Alpine Satellite Development 

Plan for the Proposed Greater 

Mooses Tooth 2 Development 

Project 

Final Supplemental Environmental Impact 

Statement

Volume 3: Appendices

Prepared by:

U.S. Department of the Interior

Bureau of Land Management

Anchorage, AK

In cooperation with:

Native Village of Nuiqsut

U.S. Army Corps of Engineers

U.S. Environmental Protection Agency

U.S. DOI Fish and Wildlife Service

U.S. DOI Bureau of Ocean Energy Management

State of Alaska

North Slope Borough

Inupiat Community of the Arctic Slope

August 2018 

Total Cost of Producing the EIS: $1.1 Million. 
Appendices  Final Supplemental Environmental Impact Statement

Alpine Satellite Development Plan for the Proposed Greater Mooses Tooth 2 Development Project

Contents of Volume 3 

Appendix A: Permit Drawings Package

Appendix B: Vehicle Trips, Aircraft Traffic and Water Use Tables

Appendix C: Passive Acoustic Monitoring Project Methodology

Appendix D: Classification and Description of Vegetation and Wildlife Habitat Types 

Appendix E: Essential Fish Habitat

Appendix F: Overview of Nuiqsut Subsistence Uses

Appendix G: Human Health Baseline Summary 

Appendix H: BOEM Greenhouse Gas Lifecycle Model Methodology

Appendix I: Request for Deviations from Lease Stipulations and Best Management Practices

Appendix J: 2013 NPR-A Integrated Activity Plan Record of Decision Best Management Practices 

and State of Alaska Regulations Protecting Environmental Quality 

Appendix K: North Slope Aviation Disturbance Information 

Appendix L: ANILCA 810 Subsistence Analysis 

Appendix M: CALPUFF Sample Files for Far-Field Air Quality Modeling

Appendix N: Methodology for Content Analysis of Nuiqsut Residents’ Comments on Oil 

Development 

Appendix O: Economic Analysis of Roadless Alternative with Seasonal Drilling

Appendix P: Alpine Oil Discharge Prevention and Contingency Plan 

Appendix Q: Potential Mitigation Measures Being Considered for Adoption in GMT2 ROD 

Appendix R: Applicant Proposed 404 Mitigation Plan 
Appendices  Final Supplemental Environmental Impact Statement

Alpine Satellite Development Plan for the Proposed Greater Mooses Tooth 2 Development Project

APPENDIX A

PERMIT DRAWINGS PACKAGE

t' 

I 

, __ 

.-----------t-~--+~-------+~7"'--+, ~~, , 

r-- _/-

~ r--,,,,;- --- --+--1 

.._ GREATER 

- MOOSES TOOTH ,-~---t=-~ ~ ~+-----,.de-..,--J__j 

" UNIT I -

GMT2 -iiili ~ ~ ---------t--------ff-~ t~ ---------=:!~ -------j 

~osed] 

1r----~i-----=-----tt--rL-r--.---+--+---L____---,---~-.1\ 

SCALE IN MILES 

3 0 3 6 --------- ---- ---- 9 

ENG I N EERS, I NC. 

PURPOSE: REFERENCE: POA XXXX-XXX 

CONSTRUCT A GRAVEL DRILLING PAD 

AND ROAD ACCESS FOR OILFIELD APPLICANT: CONOCOPHILLIPS 

DEVELOPMENT ALASKA, INC ( CPAI) 

DATUM: BPMSL, NAD83 ASP ZONE 4 LOCATION: T10N, R3E 

ADJACENT PROPERTY OWNERS: UMIAT MERIDIAN 

1. KUUKPIK VILLAGE CORP 

2. BUREAU OF LAND MANAGEMENT 

3. ARCTIC SLOPE REGIONAL CORP 

4. STATE OF ALASKA DNR 

,---------

' ' 

~ 

ConocoPhillips 

Alaska, Inc. 

PROPOSED: GMT2 ROAD, PAD & 

PIPELINE CONSTRUCTION 

IN: 

NEAR/AT: 

COUNTY: 

STATE: 

SHEET 

GREATER MOOSES TOOTH 

UNIT 

ALPINE 

NORTH SLOPE BOROUGH 

ALASKA 

1 of 33 05/11/17 

BARROW 

KAKTOVIK 

NUIQSUT 

KOTZEBUE 

NOME 

FAIRBANKS 

ANCHORAGE VALDEZ 

SKAGWAY 

HOMER SEWARD 

JUNEAU 

KODIAK 

KETCHIKAN 

UNALASKA 

ALASKA VICINITY MAP 

ALPINE SATELLITE DEVELOPMENT VICINITY MAP 
Alaska, Inc

GMT2 ADJACENT LAND OWNERS 33

.

2
STATE OF

ALASKA

DEPARTMENT OF

NATURAL

RESOURCES

CD5

[existing]

CD2

[existing]

CD1

[existing]

CD4

[existing]

ASRC MINE

NUIQSUT SITE

KUUKPIK

VILLAGE

CORPORATION

KUUKPIK

VILLAGE

CORPORATION

GMT1

[existing]

BUREAU OF

LAND

MANAGEMENT

BUREAU OF

LAND

MANAGEMENT

CD3

[existing]

GMT2

[proposed]

KUPARUK

UNIT

GMT2 ACCESS

ROAD [proposed]

STATE OF ALASKA

DEPARTMENT OF

NATURAL RESOURCES

NPRA BOUNDARY

NUIQSUT

TIE-IN

ROAD

33

Alaska, Inc.

3

GMT2 ADJACENT LAND OWNERS MAP 
CD5

[existing]

CD2

[existing]

CD4

[existing]

NUIQSUT

GMT1

GREATER [existing]

MOOSES

TOOTH

UNIT

ASRC MINE

SITE

COLVILLE

RIVER

UNIT

CD3 [existing]

GMT2 PAD

[proposed]

LAT: 70.1730

LONG: 151.6934

CD1

[existing]

GMT2

PIPELINE

[proposed]

GMT2 ACCESS

ROAD [proposed] NUIQSUT

TIE-IN

ROAD

33

Alaska, Inc.

4

ALPINE SATELLITE DEVELOPMENT LOCATION MAP 

TIFMIAQSIUBVIK 
NUIQSUT

CD2

[existing]

CD1

CD5 PAD [existing]

[existing]

GMT1 PAD

[existing]

20" CRUDE

PIPELINE

[proposed]

NUIQSUT

TIE-IN ROAD

[existing]

CD4

[existing]

SUBSISTENCE ACCESS/

VEHICLE PULLOUT PAD

3 TOTAL [proposed]

ASRC MINE SITE

GMT2 PAD

[proposed]

GMT2 PIPELINE

[proposed]

GMT2 ACCESS

ROAD [proposed]

8" MI PIPELINE

[proposed]

Alaska, Inc

TIFMIAQSIUBVIK 

GMT2 PROPOSED SATELLITE FACILITY OVERVIEW 33

.

5

GMT2 FACILITIES VEHICLE PULLOUT/SUBSISTENCE 

ACCESS PAD QUANTITIES 

ASRC MATERIAL SOURCE 
SHT 16

SHT 15

SHT 14

SHT 13

SHT 12

SHT 20

SHT 19

SHT 17

SHT 18 SHT 11

SHT 10

SHT 08

SHT 07

SHT 09

COLVILLE RIVER

NUIQSUT

HARRISON

BAY

33

Alaska, Inc.

6

GMT2 PROPOSED ACCESS ROAD AND 

PIPELINE ROUTE KEY MAP 
33

Alaska, Inc.

7

GMT2 ACCESS ROAD 

[proposed, Sheet 31] 

CROSS DRAINAGE CULVERT 

[proposed, Sheet 33] 

GMT2 PAD 

[proposed, Sheet 21] 

GMT2 TO GMT1 PIPELINE 

[proposed, Sheet 23] 

PROPOSED GMT2

 ACCESS ROAD AND PIPELINE 

ROUTE KEY MAP 1 of 14 
TIFMIAQSIUBVIK

33

Alaska, Inc.

8

SUBSISTENCE 

ACCESS/VEHICLE 

PULLOUT PAD 

[proposed, Sheet 22] 

CROSS DRAINAGE 

CULVERT 

[proposed, Sheet 33] 

GMT2 ACCESS ROAD 

[proposed, Sheet 31] 

GMT2 TO GMT1 PIPELINE 

[proposed, Sheet 23] 

LAKE R0062 

(UBLUTUOCH) 

RIVER 1/2 MILE 

BUFFER 

PROPOSED GMT2 

ACCESS ROAD AND PIPELINE 

ROUTE KEY MAP 2 of 14 
33

Alaska, Inc.

9

SUBSISTENCE 

ACCESS/VEHICLE 

PULLOUT PAD 

[proposed, Sheet 22] 

CROSS DRAINAGE 

CULVERT, TYP. 

[proposed, Sheet 33] 

LAKE Z06005 

LAKE MB0401 

GMT2 TO GMT1 PIPELINE 

GMT2 ACCESS ROAD 

[proposed, Sheet 23] 

[proposed, Sheet 31] 

LAKE R0070 

PROPOSED GMT2 

ACCESS ROAD AND PIPELINE 

ROUTE KEY MAP 3 of 14 
33

Alaska, Inc.

10

GMT2 ACCESS ROAD 

[proposed, Sheet 31] 

LAKE M9922 LAKE 

M9923 

CROSS DRAINAGE 

CULVERT, TYP. 

[proposed, Sheet 33] 

GMT2 TO GMT1 PIPELINE 

[proposed, Sheet 23] 

PROPOSED GMT2 

ACCESS ROAD AND PIPELINE 

ROUTE KEY MAP 4 of 14 
33

Alaska, Inc.

11

GMT2 ACCESS ROAD 

LAKE M9912 [proposed, Sheet 31] 

LAKE M9913 

SUBSISTENCE 

ACCESS/VEHICLE 

PULLOUT PAD 

[proposed, Sheet 22] 

CROSS DRAINAGE 

CULVERT, TYP. 

[proposed, Sheet 33] 

GMT2 TO GMT1 PIPELINE 

[proposed, Sheet 23] 

PROPOSED GMT2 

ACCESS ROAD AND PIPELINE 

ROUTE KEY MAP 5 of 14 
33

Alaska, Inc.

12

GMT1 ACCESS ROAD PIPELINE 

CROSSING [existing] 

FISH CREEK 

3 MILE BUFFER 

GMT1 ACCESS ROAD 

[existing] 

BEGIN GMT2 

ACCESS ROAD 

[proposed, Sheet 31] 

GMT1 TO CD5 PIPELINE [existing] 

[proposed GMT2 messenger and power 

cable, Sheet 24] 

GMT1 PAD 

[existing] 

GMT2 TO GMT1 PIPELINE 

[proposed, Sheet 23] 

CROSS DRAINAGE 

CULVERT, TYP. 

[proposed, Sheet 33] 

PROPOSED GMT2 

MESSENGER AND POWER CABLE 

ROUTE KEY MAP 6 of 14 
33

Alaska, Inc.

13

GMT1 TO CD5 PIPELINE [existing] 

[proposed GMT2 messenger and 

power cable, Sheet 24] 

GMT1 ACCESS ROAD LAKE 9820 FISH CREEK 

[existing] 3 MILE BUFFER 

PROPOSED GMT2 

MESSENGER AND POWER CABLE 

ROUTE KEY MAP 7 OF 14 
33

Alaska, Inc.

14

TIFMIAQSIUBVIK 

(UBLUTUOCH) RIVER 

1/2 MILE BUFFER 

GMT1 TO CD5 PIPELINE 

[existing, Sheet 24] 

GMT2 MESSENGER AND POWER CABLE 

[proposed, Sheet 24] 

GMT1 ACCESS ROAD 

[existing]

CREA CREEK BRIDGE 

[existing] 

CREA CREEK 

FISH CREEK 

3 MILE BUFFER 

PROPOSED GMT2 

MESSENGER AND POWER CABLE 

ROUTE KEY MAP 8 OF 14 
33

Alaska, Inc.

15

GMT1 TO CD5 PIPELINE [existing] 

[proposed GMT2 messenger and 

power cable, Sheet 24] 

EAST VALVE PAD 

WEST VALVE PAD [existing] 

[existing] 

FISH CREEK 

3 MILE BUFFER 

TIFMIAQSIUBVIK 

(UBLUTUOCH) 

RIVER BRIDGE 

[existing] 

GMT1 ACCESS ROAD 

[existing] 

BARELY CREEK CULVERT TIFMIAQSIUBVIK [existing] (UBLUTUOCH) RIVER 

TIFMIAQSIUBVIK 

(UBLUTUOCH) RIVER 

1/2 MILE BUFFER 

BARELY 

CREEK 

TIFMIAQSIUBVIK 

(UBLUTUOCH) RIVER 

1/2 MILE BUFFER 

PROPOSED GMT2 

MESSENGER AND POWER CABLE 

ROUTE KEY MAP 9 OF 14 
33

Alaska, Inc.

16

GMT1 TO CD5 PIPELINE [existing] 

[proposed GMT2 messenger and 

power cable, Sheet 24] 

GMT1 ACCESS ROAD 

[existing] 

CD5 PAD 

[existing] 

CD5 ACCESS ROAD 

[existing] 

CD5 TO CD4N PIPELINE [existing] 

[proposed 20" crude pipeline, 

messenger cable, and power cable, to 

be added to CD5 piperack, Sheet 25] 

CD5 TO CD4N PIPELINE AND GMT1 

ROAD CROSSING [existing] 

[proposed 20" crude pipeline to be 

added to crossing, Sheet 28] 

PROPOSED GMT2 

MESSENGER AND POWER CABLE 

ROUTE KEY MAP 10 OF 14 
33

Alaska, Inc.

17

CD5 ACCESS ROAD NIGLIAGVIK [existing] CHANNEL BRIDGE 

[existing] 

CD5 TO CD4N PIPELINE AND CD5 

ROAD CROSSING [existing] 

[proposed 20" crude pipeline, 

messenger cable, and power cable 

to be added to crossing, Sheet 29] 

VALVE PAD 

[existing] 

CD5 TO CD4N PIPELINE - [existing] 

[proposed 20" crude pipeline, 

messenger cable, and power cable to 

be added to CD5 piperack, Sheet 25] 

NUIQSUT TIE-IN ROAD 

[existing] 

KUUKPIK LAYDOWN PAD 

[existing] 

PROPOSED CRUDE PIPELINE, MESSENGER CABLE, 

AND POWER CABLE 

(CD5 TO CD4N PIPELINE) 

ROUTE KEY MAP 11 OF 14 
33

Alaska, Inc.

18

L9341 BRIDGE 

[existing] 

CD5 TO CD4N PIPELINE [existing] 

[proposed 20" crude pipeline, 

messenger cable, and power cable to 

be added to CD5 piperack, Sheet 25] 

LAKE L9341 

PROPOSED CRUDE PIPELINE, MESSENGER CABLE, 

AND POWER CABLE 

(CD5 TO CD4N PIPELINE) 

ROUTE KEY MAP 12 OF 14 
33

Alaska, Inc.

19

CD4 ROAD 

[existing] 

CD4N TO CD2 JUNCTION PIPELINES [existing] 

[with GMT2 proposed 20" crude, 8" miscible 

injection, messenger cable, and power cable, 

Sheet 26] 

CD5 TO CD4N PIPELINE AND CD4 CROSSING [existing] 

[with GMT2 proposed 20" crude pipeline, messenger 

cable, and power cable, Sheet 30] 

CD5 TO CD4N PIPELINE [existing] 

[with GMT2 proposed 20" crude pipeline, 

messenger cable, and power cable, Sheet 25] 

NIGLIQ BRIDGE L9323 BRIDGE [existing] [existing] 

CD5 ROAD 

[existing] 

CD4N 

[existing] 

PROPOSED GMT2 PIPELINE 

(CD4N TO CD2 JUNCTION) 

ROUTE KEY MAP 13 OF 14 
33

Alaska, Inc.

20

CD1 ALPINE FACILITY 

[existing] 

CD2 JUNCTION TO CD1 PIPELINES [existing] 

[with GMT2 proposed 20" crude pipeline, 8" miscible 

injection pipeline, messenger cable, and power cable, 

Sheet 26] 

CD2 ROAD 

[existing] 

CD4 ROAD 

[existing] 

CD4N TO CD2 JUNCTION PIPELINES [existing] 

[with GMT2 proposed 20" crude pipeline, 8" miscible 

injection pipeline, messenger cable, and power 

cable, Sheet 26] 

PROPOSED GMT2 PIPELINE 

(CD2 JUNCTION TO CD1)

 ROUTE KEY MAP 14 OF 14 
A'

A

C C' B'

B

33

Alaska, Inc.

21

GMT2 PAD QUANTITIES 

GMT2 PROPOSED PAD FOOTPRINT WITH 48 WELLS 
E

E'

D'

D

22 33

Alaska, Inc.

SUBSISTENCE ACCESS/VEHICLE PULLOUT PAD QUANTITIES 

PROPOSED TYPICAL SUBSISTENCE 

ACCESS/VEHICLE PULLOUT PAD FOOTPRINT 

33

Alaska, Inc.

24 GMT1 TO CD5 PROPOSED PIPELINE TYPICAL SECTION 
33

Alaska, Inc.

25 CD5 TO CD4N PROPOSED PIPELINE SECTION 
26 33

Alaska, Inc.

PERMITTED GMT1 EXISTING EXISTING ALPINE

PIPERACK / PROPOSED CD-4 PIPELINE SALES PIPELINE

GMT2 PIPELINE 

CD4N TO CD2 JUNCTION

PROPOSED PIPELINE SECTION 
27 33

Alaska, Inc.

EXISTING EXISTING EXISTING PERMITTED GMT1

CD-4 PIPERACK CD-2 PIPERACK SALES PIPE PIPERACK /

RACK PROPOSED

GMT2 PIPELINE

CD2 JUNCTION TO CD1 (ALPINE) PROPOSED PIPELINE

SECTION 
33

Alaska, Inc.

28

EXISTING PIPE CROSSING PROFILE 

EXISTING PIPE CROSSING SECTION 

EXISTING PIPE CROSSING PLAN 

GMT1 ROAD AT CD5 PIPELINE CROSSING 
33

Alaska, Inc.

29

PIPE CROSSING PROFILE 

PIPE CROSSING SECTION 

PIPE CROSSING PLAN 

CD5 ROAD AND CD5 PIPELINE CROSSING 
33

Alaska, Inc.

30

PIPE CROSSING PROFILE 

PIPE CROSSING SECTION 

PIPE CROSSING PLAN 

CD4 ROAD AND CD5 PIPELINE CROSSING 
GMT2 TYPICAL GRAVEL ACCESS ROAD SECTION

33

Alaska, Inc.

31

SECTION A-A' 

GMT2 TYPICAL WELL PAD NARROW TRANSVERSE 

SECTION B-B' 

GMT2 TYPICAL WELL PAD BROAD TRANSVERSE 

SECTION C-C' 

GMT2 TYPICAL WELL PAD LONGITUDINAL SECTION 

GMT2 PROPOSED TYPICAL ROAD & 

WELL PAD SECTIONS 
33

Alaska, Inc.

32

SECTION D-D' 

SUBSISTENCE ACCESS/VEHICLE PULLOUT PAD 

TYPICAL LONGITUDINAL 

SECTION E-E' 

SUBSISTENCE ACCESS/VEHICLE PULLOUT PAD 

TYPICAL TRANSVERSE 

GMT2 PROPOSED SUBSISTENCE 

ACCESS/VEHICLE PULLOUT PAD 

TYPICAL SECTIONS 
33

Alaska, Inc.

33

PROPOSED CULVERT ELEVATION 

PROPOSED CULVERT SECTION 

PROPOSED TYPICAL CROSS 

DRAINAGE CULVERT SECTION 

Appendices  Final Supplemental Environmental Impact Statement

Alpine Satellite Development Plan for the Proposed Greater Mooses Tooth 2 Development Project

APPENDIX B

VEHICLE TRIPS, AIRCRAFT TRAFFIC AND WATER USE 

TABLES

B-1 

Aircraft Flights for Alternative A, Proposed Action - 2 YEAR CONSTRUCTION SCHEDULE a

Project Phase

Otter / CASA 

Flights Into 

CD1/APF b 

DC-6 b

Flights Into 

CD1/APF

Otter / CASA 

Flights Into 

GMT2

DC-6 / C-130 

Flights Into 

GMT2

Helicopter c,d 

Flights Into 

GMT2/NPR-A

Total Flights 

Into 

GMT2/NPR-A Total Flights

Construction (Year 1-2) e 125 0 0 0 538 538 663

Construction (Year 2-3) f 145 0 0 0 494 494 639

Drilling (Years 4-10, 

annual no. of flights) g,h 0 0 0 0 90 90 90

Drilling (Years 4-10, total 

flights for phase) 0 0 0 0 540 540 540

Post-Drilling Operations 

(annual no. of flights) 0 0 0 0 90 90 90

Post-Drilling Operations 

(total flights for phase) i,j 0 0 0 0 2,070 2,070 2,070

Project Life Total 

Flights 270 0 0 0 3,642 3,642 3,912

a A single “flight” is defined as a landing and subsequent takeoff. Monthly flight numbers were estimated by ConocoPhillips and provided for different aircraft types, flight locations, 

project activities, and project phases. Helicopter landings in NPR-A for ice-road clean-up were estimated at five landings per mile of ice road. Total flight numbers for drilling and postdrilling phases were calculated on the basis of estimated monthly flight numbers and an assumed post-construction project lifespan of 30 years. 

b Otter/CASA flights will take off from Kuparuk or Deadhorse and land at CD1/Alpine Central Processing Facility. DC-6 flights will take off from Deadhorse and land at CD1/Alpine 

Central Processing Facility. 

c Helicopter numbers refer to landings within the NPR-A. Helicopter visits to spill response equipment pre-staged as part of the GMT2 Project are included in helicopter landing 

numbers. 

d Helicopter landings for ice road cleanup are estimated at five landings per mile of ice road. Ice road cleanup will only occur from May–September of Year 2 and Year 3. Helicopters 

will take off from Alpine CD1/Alpine Central Processing Facility and land along the ice road route. Helicopter flights during drilling and annual operations years will take off from 

CD1/Alpine Central Processing Facility and will support required monitoring and studies, survey work, and staging of spill response equipment. Landing/overflight areas within the 

NPR-A for monitoring helicopter flights will differ based on the study.

e Year 1-2 refers to November of year 1 through October of year 2.

f Year 2-3 refers to November of year 2 through December of year 3 (a 14-month period).

g Drilling (Years 4-10) represents January of year 4 through April of year 10.

h Drilling flights were calculated by multiplying the annual total by 6 years of drilling. 

i Total trips for annual operations assumes a project lifespan of 23 years post drilling.

j Annual operations represents May of year 10 through December of year 32.
B-2 

Aircraft Flights for Alternative B, 2 YEAR CONSTRUCTION SCHEDULE a

Project Phase

Otter / CASA 

Flights Into 

CD1/APF

DC-6 Flights 

Into CD1/APF

Otter / CASA 

Flights Into 

GMT2

DC-6 / C-130 

Flights Into 

GMT2

Helicopter 

Flights Into 

GMT2/NPR-A

Total Flights 

Into 

GMT2/NPR-A Total Flights

Construction (Year 1-2) 125 0 0 0 538 538 663

Construction (Year 2-3) 145 0 0 0 494 494 639

Drilling (Years 4-10, 

annual no. of flights) 0 0 0 0 90 90 90

Drilling (Years 4-10, 

total flights for phase) 0 0 0 0 540 540 540

Post-Drilling Operations 

(annual no. of flights) 0 0 0 0 90 90 90

Post-Drilling Operations 

(total flights for phase) 0 0 0 0 2,070 2,070 2,070

Project Life Total 

Flights 270 0 0 0 3,642 3,642 3,912

a A single “flight” is defined as a landing and subsequent takeoff. Monthly flight numbers were estimated by ConocoPhillips and provided for different aircraft types, flight locations, 

project activities, and project phases. Helicopter landings in NPR-A for ice-road clean-up were estimated at five landings per mile of ice road. Total flight numbers for drilling and postdrilling phases were calculated on the basis of estimated monthly flight numbers and an assumed post-construction project lifespan of 30 years. 

b Otter/CASA flights will take off from Kuparuk or Deadhorse and land at CD1/Alpine Central Processing Facility. DC-6 flights will take off from Deadhorse and land at CD1/Alpine 

Central Processing Facility. 

c Helicopter numbers refer to landings within the NPR-A. Helicopter visits to spill response equipment pre-staged as part of the GMT2 Project are included in helicopter landing 

numbers. 

d Helicopter landings for ice road cleanup are estimated at five landings per mile of ice road. Ice road cleanup will only occur from May–September of Year 2 and Year 3. Helicopters 

will take off from Alpine CD1/Alpine Central Processing Facility and land along the ice road route. Helicopter flights during drilling and annual operations years will take off from 

CD1/Alpine Central Processing Facility and will support required monitoring and studies, survey work, and staging of spill response equipment. Landing/overflight areas within the 

NPR-A for monitoring helicopter flights will differ based on the study.

e Year 1-2 refers to November of year 1 through October of year 2.

f Year 2-3 refers to November of year 2 through December of year 3 (a 14-month period).

g Drilling (Years 4-10) represents January of year 4 through April of year 10.

h Drilling flights were calculated by multiplying the annual total by 6 years of drilling. 

i Total trips for annual operations assumes a project lifespan of 23 years post drilling.

j Annual operations represents May of year 10 through December of year 32.
B-3 

Aircraft Flights for Alternative A, Proposed Action and Alternative B - 3 YEAR CONSTRUCTION SCHEDULE a

Project Phase

Otter / CASA 

Flights Into 

CD1/APF b 

DC-6 c

Flights Into 

CD1/APF

Otter / CASA 

Flights Into 

GMT2

DC-6 / C-130 

Flights Into 

GMT2

Helicopter d

Flights Into 

GMT2/NPR-A

Total Flights 

Into 

GMT2/NPR-A Total Flights

Construction (Year 0-1) e 125 0 0 0 409 409 534

Construction (Year 1-2) f 145 0 0 0 402 402 547

Construction (Year 2-3) g 145 0 0 0 310 310 445

Drilling (Years 4-10, 

annual no. of flights) h,i 0 0 0 0 90 90 50

Drilling (Years 4-10, total 

flights for phase) 0 0 0 0 540 540 540

Post-Drilling Operations 

(annual no. of flights) j,k 0 0 0 0 90 90 90

Post-Drilling Operations 

(total flights for phase) 0 0 0 0 2,070 2,070 2,070

Project Life Total 

Flights 415 0 0 0 3,731 3,731 4,146

a A single “flight” is defined as a landing and subsequent takeoff. Monthly flight numbers were estimated by ConocoPhillips and provided for different aircraft types, flight locations, 

project activities, and project phases. Helicopter landings in NPR-A for ice-road clean-up were estimated at five landings per mile of ice road. Total flight numbers for drilling and postdrilling phases were calculated on the basis of estimated monthly flight numbers and an assumed post-construction project lifespan of 30 years. 

b Otter/CASA flights will take off from Kuparuk or Deadhorse and land at CD1/Alpine Central Processing Facility. DC-6 flights will take off from Deadhorse and land at CD1/Alpine 

Central Processing Facility. 

c Helicopter numbers refer to landings within the NPR-A. Helicopter visits to spill response equipment pre-staged as part of the GMT2 Project are included in helicopter landing 

numbers. 

d Helicopter landings for ice road cleanup are estimated at five landings per mile of ice road. Ice road cleanup will only occur from May–September of Year 2 and Year 3. Helicopters 

will take off from Alpine CD1/Alpine Central Processing Facility and land along the ice road route. Helicopter flights during drilling and annual operations years will take off from 

CD1/Alpine Central Processing Facility and will support required monitoring and studies, survey work, and staging of spill response equipment. Landing/overflight areas within the 

NPR-A for monitoring helicopter flights will differ based on the study.

e Year 0-1 refers to November of year 0 through October of year 1.

f Year 1-2 refers to November of year 1 through October of year 2.

g Year 2-3 refers to November of year 2 through December of year 3 (a 14-month period).

h Drilling (Years 4-10) represents January of year 4 through April of year 10.

i Drilling flights were calculated by multiplying the annual total by 6 years of drilling. 

j Total trips for annual operations assumes a project lifespan of 23 years post drilling.

k Annual operations represents May of year 10 through December of year 32.
B-4 

Aircraft Flights for Alternative C - 2 YEAR CONSTRUCTION SCHEDULE a

Project Phase

Otter / CASA 

Flights Into 

CD1/APF b 

DC-6 b

Flights Into 

CD1/APF

Otter / CASA 

Flights Into 

GMT2

DC-6 / C-130 

Flights Into 

GMT2

Helicopter c,d

Flights Into 

GMT2/NPR-A

Total Flights 

Into 

GMT2/NPR-A Total Flights

Construction (Year 1-2) e 125 4 0 0 647 647 776

Construction (Year 2-3) f 145 0 865 193 413 1,471 1,616

Drilling (Years 4-10, 

annual no. of flights) g,h 0 0 983 227 143 1,353 1,353

Drilling (Years 4-10, total 

flights for phase) 0 0 6,126 1,399 858 8,383 8,383

Post-Drilling Operations 

(annual no. of flights) i,j 0 0 228 42 143 413 413

Post-Drilling Operations 

(total flights for phase) 0 0 5,281 974 3,289 9,544 9,544

Project Life Total 

Flights 270 4 12,272 2,566 5,207 20,045 20,319

a A single “flight” is defined as a landing and subsequent takeoff. Monthly flight numbers were estimated by ConocoPhillips and provided for different aircraft types, flight locations, 

project activities, and project phases. Helicopter landings in NPR-A for ice-road clean-up were estimated at five landings per mile of ice road. Total flight numbers for drilling and postdrilling phases were calculated on the basis of estimated monthly flight numbers and an assumed post-construction project lifespan of 30 years. 

b Otter/CASA flights will take off from Kuparuk or CD1/Alpine Central Processing Facility and land at the GMT2 airstrip after airstrip construction is completed. DC-6/C130 flights will 

take off from Deadhorse and land at the GMT2 airstrip after airstrip construction is completed. 

c Helicopter numbers refer to landings within the NPR-A. Helicopter visits to spill response equipment pre-staged as part of the GMT2 Project are included in helicopter landing 

numbers. 

d Helicopter landings for ice road cleanup are estimated at five landings per mile of ice road. Ice road cleanup will occur from May–September from Year 2 until the end of the project. 

Helicopters would take off from the CD1/Alpine Central Processing Facility airstrip and land along the ice road route. 

e Year 1-2 refers to November of year 1 through October of year 2.

f Year 2-3 refers to November of year 2 through December of year 3 (a 14-month period).

g Drilling (Years 4-10) represents January of year 4 through April of year 10.

h Drilling flights were calculated by multiplying the annual total by 6 years of drilling. 

i Total trips for annual operations assumes a project lifespan of 23 years post drilling.

j Annual operations represents May of year 10 through December of year 32.
B-5 

Aircraft Flights for Alternative C- 3 YEAR CONSTRUCTION SCHEDULE a

Project Phase

Otter / CASA 

Flights Into 

CD1/APF b 

DC-6 b

Flights Into 

CD1/APF

Otter / CASA 

Flights Into 

GMT2

DC-6 / C-130 

Flights Into 

GMT2

Helicopter c,d

Flights Into 

GMT2/NPR-A

Total Flights 

Into 

GMT2/NPR-A Total Flights

Construction (Year 0-1) e 60 0 0 0 517 517 577

Construction (Year 1-2) f 65 4 0 0 287 287 356

Construction (Year 2-3) g 145 0 865 193 413 1,471 1,616

Drilling (Years 4-10, 

annual no. of flights) h,i 0 0 983 227 143 1,353 1,353

Drilling (Years 4-10, total 

flights for phase) 0 0 6,126 1,399 858 8,383 8,383

Post-Drilling Operations 

(annual no. of flights) j,k 0 0 228 42 143 413 413

Post-Drilling Operations 

(total flights for phase) 0 0 5,281 974 3,289 9,544 9,544

Project Life Total 

Flights 270 4 12,272 2,566 5,363 20,202 20,476

a A single “flight” is defined as a landing and subsequent takeoff. Monthly flight numbers were estimated by ConocoPhillips and provided for different aircraft types, flight locations, 

project activities, and project phases. Helicopter landings in NPR-A for ice-road clean-up were estimated at five landings per mile of ice road. Total flight numbers for drilling and postdrilling phases were calculated on the basis of estimated monthly flight numbers and an assumed post-construction project lifespan of 30 years. 

b Otter/CASA flights will take off from Kuparuk or CD1/Alpine Central Processing Facility and land at the GMT2 airstrip after airstrip construction is completed. DC-6/C130 flights will 

take off from Deadhorse and land at the GMT2 airstrip after airstrip construction is completed. 

c Helicopter numbers refer to landings within the NPR-A. Helicopter visits to spill response equipment pre-staged as part of the GMT2 Project are included in helicopter landing 

numbers. 

d Helicopter landings for ice road cleanup are estimated at five landings per mile of ice road. Ice road cleanup will occur from May–September from Year 2 until the end of the project. 

Helicopters would take off from the CD1/Alpine Central Processing Facility airstrip and land along the ice road route. 

e Year 1-2 refers to November of year 1 through October of year 2.

f Year 2-3 refers to November of year 2 through December of year 3 (a 14-month period).

g Drilling (Years 4-10) represents January of year 4 through April of year 10.

h Drilling flights were calculated by multiplying the annual total by 6 years of drilling. 

i Total trips for annual operations assumes a project lifespan of 23 years post drilling.

j Annual operations represents May of year 10 through December of year 32.

k Annual operations represents May of year 10 through December of year 32.
B-6 

ConocoPhillips’ Baseline (current) Aircraft Flights Without Development of GMT2 (Alternative D) a

Project Phase

Otter / CASA 

Flights Into 

CD1/APF

DC-6 Flights 

Into CD1/APF

Otter / CASA 

Flights Into 

GMT2

DC-6 / C-130 

Flights Into 

GMT2

Helicopter 

Flights Into 

GMT2/NPR-A

Total Flights 

Into 

GMT2/NPR-A Total Flights

Construction (Year 1-2) 1,981 366 0 0 765 765 3,112

Construction (Year 2-3) 1,981 366 0 0 765 765 3,112

Drilling (Years 4-10, 

annual no. of flights) 1,981 366 0 0 765 765 3,112

Drilling (Years 4-10, 

total flights for phase) 12,429 2,318 0 0 4,590 4,590 19,337

Post-Drilling Operations 

(annual no. of flights) 1,981 366 0 0 765 765 3,112

Post-Drilling Operations 

(total flights for phase) 45,020 8,296 0 0 17,595 17,595 70,911

Project Life Total 

Flights 61,421 11,345 0 0 23,715 23,715 96,481

a Flight numbers are organized by GMT2 development phase to facilitate comparison with additional flight activity that is projected to occur with implementation of action alternatives A, 

B, and C. A single “flight” is defined as a landing and subsequent takeoff. Monthly flight numbers were estimated by ConocoPhillips and provided for different aircraft types, flight 

locations, and activities. Total flight numbers were calculated on the basis of estimated monthly flight numbers for the assumed 30-yr post-construction lifespan of the GMT2 project. 
B-7 

Vehicle Trips and Mileage Traveled for Alternative A, Proposed Action – 2 YEAR CONSTRUCTION SCHEDULE

Vehicle Type

Construction 

Season 1 

Trips

Construction 

Season 1 

Miles

Construction 

Season 2 

Trips

Construction 

Season 2 

Miles

Drilling 

Year 1 

Trips

Drilling 

Year 1 

Miles

Infill 

Drilling a

Trips

Infill 

Drilling 

Miles

Routine 

Ops 

b

Trips

Routine 

Ops 

Miles

Intercity Bus 2,900 32,900 5,700 45,700 0 0 0 0 0 0

Light 

Commercial 

Truck 11,300 114,100 22,300 178,100 800 19,600 1,200 29,100 500 9,400

Single Unit 

Short Haul 

Truck 78,900 778,100 43,800 180,500 5,300 133,500 7,800 194,700 200 3,100

Passenger 

Truck 500 6,300 700 4,000 0 0 0 0 0 0

Annual Total c 93,600 931,400 72,500 408,300 6,100 153,100 9,000 223,800 700 12,500 a Infill drilling refers to the period of time during which up to 48 development wells will be drilled on the GMT2 pad. Total trips and total miles for annual infill drilling assumes 6.33 years 

of drilling post construction.

b Routine operations will begin once infill drilling is complete. Routine operations assumes that the Alternative A wellwork crew will travel from CD1/Alpine Central Processing Facility 

as needed along the GMT1–GMT2 Access Road and an annual ice road will not be required. Total trips and total miles for routine operations assumes a project lifespan of 23 years 

post drilling. 

c Totals are rounded to the nearest hundred. Trips are one way.

Vehicle Trips and Mileage Traveled for Alternative A, Proposed Action – 3 YEAR CONSTRUCTION SCHEDULE a 

Vehicle Type

Construction 

Season 0 Trips

Construction 

Season 0 Miles

Construction 

Season 1 Trips

Construction 

Season 1 Miles

Construction 

Season 2 Trips

Construction 

Season 2 Miles

intercity bus 1,300 13,100 1,600 19,800 5,700 45,700

light commercial truck 5,400 57,200 5,900 56,900 22,300 178,100

single unit short haul truck 50,100 667,000 29,400 114,200 43,800 180,500

passenger truck - - 500 6,300 700 4,000

Annual Total b 56,800 737,300 37,400 197,200 72,500 408,300 a Under a three year construction schedule, vehicle trips and miles for drilling and routine operations will not change. 

b Totals are rounded to the nearest hundred. Trips are one way.
B-8 

Vehicle Trips and Mileage Traveled for Alternative B, Alternative Road Alignment – 2 YEAR CONSTRUCTION SCHEDULE

Vehicle 

Type

Construction 

Season 1 

Trips

Construction 

Season 1 

Miles

Construction 

Season 2 

Trips

Construction 

Season 2 

Miles

Drilling 

Year 1 

Trips

Drilling 

Year 1 

Miles

Infill 

Drilling 

Trips

Infill 

Drilling 

Miles

Routine 

Ops 

Trips

Routine 

Ops 

Miles

Intercity Bus 2,900 32,900 5,700 45,700 0 0 0 0 0 0

Light 

Commercial 

Truck 11,300 114,100 22,300 178,100 800 20,880 1,200 30,300 500 10,100

Single Unit 

Short Haul 

Truck 83,500 870,500 43,900 181,500 5,300 138,330 7,800 202,500 200 3,400

Passenger 

Truck 500 6,300 700 4,000 0 0 0 0 0 0

Annual 

Total 98,200 1,023,800 72,600 409,300 6,100 159,210 9,000 232,800 700 13,500 a Infill drilling refers to the period of time during which up to 48 development wells will be drilled on the GMT2 pad. Total trips and total miles for annual infill drilling assumes 6.33 years 

of drilling post construction.

b Routine operations will begin once infill drilling is complete. Routine operations assumes that the Alternative A wellwork crew will travel from CD1/Alpine Central Processing Facility 

as needed along the GMT1–GMT2 Access Road and an annual ice road will not be required. Total trips and total miles for routine operations assumes a project lifespan of 23 years 

post drilling. 

c Totals are rounded to the nearest hundred. Trips are one way.

Vehicle Trips and Mileage Traveled for Alternative B, Alternative Road Alignment – 3 YEAR CONSTRUCTION SCHEDULE a 

a Under a three year construction schedule, vehicle trips and miles for drilling and routine operations will not change. 

b Totals are rounded to the nearest hundred. Trips are one way.

Vehicle Type

Construction 

Season 0 Trips

Construction 

Season 0 Miles

Construction 

Season 1 Trips

Construction 

Season 1 Miles

Construction 

Season 2 Trips

Construction 

Season 2 Miles

intercity bus 1,300 13,100 1,600 19,800 5,700 45,700

light commercial truck 5,400 57,200 5,900 56,900 22,300 178,100

single unit short haul truck 54,700 759,400 29,400 114,200 43,900 181,500

passenger truck - - 500 6,300 700 4,000

Annual Total b 61,400 829,700 37,400 197,200 72,600 409,300
B-9 

Vehicle Trips and Mileage Traveled for Alternative C, Roadless Development – 2 YEAR CONSTRUCTION SCHEDULE

Vehicle 

Type

Construction 

Season 1 

Trips

Construction 

Season 1 

Miles

Construction 

Season 2 

Trips

Construction 

Season 2 

Miles

Drilling 

Year 1 

Trips

Drilling 

Year 1 

Miles

Infill 

Drilling 

Trips

Infill 

Drilling 

Miles

Routine 

Ops 

Trips

Routine 

Ops 

Miles

Intercity Bus 2,800 30,300 5,900 29,700 0 0 0 0 0 0

Light 

Commercial 

Truck 11,700 105,600 19,500 90,200 800 800 10,200 10,200 16,000 48,300

Single Unit 

Short Haul 

Truck 91,700 1,214,400 49,200 212,000 4,500 4,500 12,300 160,900 5,800 22,000

Passenger 

Truck 500 6,300 500 4,000 0 0 0 0 0 0

Annual 

Total 106,700 1,356,600 75,100 335,900 5,300 5,300 22,500 171,100 21,800 70,300 a Trips are one way. Construction trips are performed on the ice road. Drilling and routine operation trips are primarily performed on the 1-mile gravel road connecting the drill pad to 

the camp pad.

b Infill drilling refers to the period of time during which up to 48 development wells will be drilled on the GMT2 pad. Total trips and total miles assumes 6.33 years of annual infill drilling.

c Total trips and total miles for routine operations assumes a project lifespan of 23 years post drilling. 

d Totals are rounded to the nearest hundred.

Vehicle Trips and Mileage Traveled for Alternative C, Roadless Development – 3 YEAR CONSTRUCTION SCHEDULE a 

Vehicle Type

Construction 

Season 0 Trips

Construction 

Season 0 Miles

Construction 

Season 1 Trips

Construction 

Season 1 Miles

Construction 

Season 2 Trips

Construction 

Season 2 Miles

intercity bus 1,100 8,900 1,700 21,400 5,900 29,700

light commercial truck 5,500 58,200 6,200 47,400 19,500 90,200

single unit short haul truck 60,600 1,092,200 31,700 125,300 49,200 212,000

passenger truck - - 500 6,300 500 4,000

Annual Total b 67,200 1,159,300 40,100 200,400 75,100 335,900 a Under a three year construction schedule, vehicle trips and miles for drilling and routine operations will not change. 

b Totals are rounded to the nearest hundred. Trips are one way.
B-10

Water Use for Alternative A, Proposed Action – 2 YEAR CONSTRUCTION SCHEDULE a

Project Phase Project Component Water Requirement (million 

gallons [MG])

Construction Season 1 Ice Road b: 52.6 miles 74.2 MG

Construction Season 1 Ice Pad 43.8 MG

Construction Season 1 Winter Work Force 3.7 MG

Construction Season 1 Construction Miscellaneous 1.0 MG

Construction Season 2 Ice Road: 43.9 miles 76.1 MG

Construction Season 2 Ice Pad 33.8 MG

Construction Season 2 Winter Work Force 3.7 MG

Construction Season 2 Construction Miscellaneous 1.0 MG

Construction Season 2 Summer Work Force 1.7 MG

Construction Total All Components 239 MG

Drilling Ice Pad c 2.5 MG

Drilling Drilling Water 13.5 MG

Drilling Camp Water 2.7 MG

Drilling Drilling Miscellaneous 1.0 MG

Drilling Total d All Components 140.6 MG (19.8 MG annually)

Routine Operations Ice Pad 0.5 MG

Routine Operations Total e All Components 15.0 MG (0.5 MG annually)

Project Life Total All Components 395 MG a Camp water usage for all locations and alternatives is 100 gallons per person per day.

b Typical ice road water requirement is 1 MG per mile for 35-foot wide ice road. Wider ice roads are required for pipeline 

construction; water use for pipeline construction ice roads were ratioed from the 35-foot wide ice road.

c A 10-acre ice pad would be needed (2.5 MG per 10 acres) to support drilling.

d Drilling water requirement is based on 2 MG per well; drilling a well takes 54 days. Water use was estimated for the drilling phase 

assuming 48 wells will be drilled over 7.1 years.

e Water use for routine operations assumes a 30 year project lifespan post construction. Water use for routine operations is not 

included in the Drilling total for the overlapping years.

Water Use for Alternative A, Proposed Action – 3 YEAR CONSTRUCTION SCHEDULE a 

Project Phase Project Component Water Requirement (MG)

Construction Season 0 Ice Road: 25.6 miles b 36.1

Construction Season 0 Ice Pad: 25.0

Construction Season 0 Winter Work Force 3.7

Construction Season 0 Construction Miscellaneous 1.0

Construction Season 1 Ice Road: 27.0 miles 38.1

Construction Season 1 Ice Pad: 18.8

Construction Season 1 Winter Work Force 3.7

Construction Season 1 Construction Miscellaneous 1.0

Construction Season 2 Ice Road: 43.9 miles 76.1

Construction Season 2 Ice Pad: 33.8

Construction Season 2 Winter Work Force 3.7

Construction Season 2 Construction Miscellaneous 1.0

Construction Season 2 Summer Workforce 1.7

Construction Total c 243.7

a Camp water usage for all locations and alternatives is 100 gallons per person per day.

b Typical ice road water requirement is 1 MG per mile for 35-foot wide ice road. Wider ice roads are required for pipeline 

construction; water use for pipeline construction ice roads were ratioed from the 35-foot wide ice road.

c Under a three year construction schedule, water use for drilling and routine operations will not change. 
B-11

Water Use for Alternative B, Alternate Road Alignment – 2 YEAR CONSTRUCTION SCHEDULE a

Project Phase Project Component Water Requirement (million 

gallons [MG])

Construction Season 1 Ice Road b: 52 miles 75 MG

Construction Season 1 Ice Pad 43.8 MG

Construction Season 1 Winter Work Force 3.7 MG

Construction Season 1 Construction Miscellaneous 1.0 MG

Construction Season 2 Ice Road: 43.3 miles 78.3 MG

Construction Season 2 Ice Pad 33.8 MG

Construction Season 2 Winter Work Force 3.7 MG

Construction Season 2 Construction Miscellaneous 1.0 MG

Construction Season 2 Summer Work Force 1.7 MG

Construction Total All Components 242 MG

Drilling Ice Pad c 2.5 MG

Drilling Drilling Water 13.5 MG

Drilling Camp Water 2.7 MG

Drilling Drilling Miscellaneous 1.0 MG

Drilling Total d All Components 140.6 MG (19.8 MG annually)

Routine Operations Ice Pad 0.5 MG

Routine Operations Total e All Components 15.0 MG (0.5 MG annually)

Project Life Total All Components 398 MG a Camp water usage for all locations and alternatives is 100 gallons per person per day.

b Typical ice road water requirement is 1 MG per mile for 35-foot wide ice road. Wider ice roads are required for pipeline 

construction; water use for pipeline construction ice roads were ratioed from the 35-foot wide ice road.

c A 10-acre ice pad would be needed (2.5 MG per 10 acres) to support drilling.

d Drilling water requirement is based on 2 MG per well; drilling a well takes 54 days. Water use was estimated for the drilling phase 

assuming 48 wells will be drilled over 7.1 years.

e Water use for routine operations assumes a 30 year project lifespan post construction. Water use for routine operations is not 

included in the Drilling total for the overlapping years.

Water Use for Alternative B, Alternate Road Alignment – 3 YEAR CONSTRUCTION SCHEDULE a

Project Phase Project Component Water Requirement (MG)

Construction Season 0 Ice Road: 25.0 miles b 36.0

Construction Season 0 Ice Pad: 25.0

Construction Season 0 Winter Work Force 3.7

Construction Season 0 Construction Miscellaneous 1.0

Construction Season 1 Ice Road: 27.0 miles 39.0

Construction Season 1 Ice Pad: 18.8

Construction Season 1 Winter Work Force 3.7

Construction Season 1 Construction Miscellaneous 1.0

Construction Season 2 Ice Road: 43.3 miles 78.3

Construction Season 2 Ice Pad: 33.8

Construction Season 2 Winter Work Force 3.7

Construction Season 2 Construction Miscellaneous 1.0

Construction Season 2 Summer Workforce 1.7

Construction Total c 246.7

a Camp water usage for all locations and alternatives is 100 gallons per person per day.

b Typical ice road water requirement is 1 MG per mile for 35-foot wide ice road. Wider ice roads are required for pipeline

construction; water use for pipeline construction ice roads were ratioed from the 35-foot wide ice road.

c Under a three year construction schedule, water use for drilling and routine operations will not change. 
B-12

Water Use for Alternative C, Roadless Development – 2 YEAR CONSTRUCTION SCHEDULE a 

Project Phase Project Component Water Requirement (million 

gallons [MG])

Construction Season 1 Ice Road b: 51.6 miles 72.8 MG

Construction Season 1 Ice Pad 51.3 MG

Construction Season 1 Winter Work Force (Alpine) 3.7 MG

Construction Season 1 Construction Miscellaneous 1.0 MG

Construction Season 2 Ice Road: 51.2 miles 83.4 MG

Construction Season 2 Ice Pad 43.8 MG

Construction Season 2 Winter Work Force (Alpine) 3.7 MG

Construction Season 2 Winter Work Force (Remote Facilities) 1.6 MG

Construction Season 2 Construction Miscellaneous 1.0 MG

Construction Season 2 Summer Work Force 3.4 MG

Construction Total All Components 266 MG

Drilling Ice Pad c 2.5 MG

Drilling Ice Road: 7.0 miles 7.0 MG

Drilling Drilling Water 13.5 MG

Drilling Camp Water 7.3 MG

Drilling Drilling Miscellaneous 1.0 MG

Drilling Total d All Components 222 MG

Routine Operations Ice Pad 0.5 MG

Routine Operations Ice Road 7.0 MG

Routine Operations Ops Camp Support 0.91

Routine Operations Total e All Components 203

Project Life Total All Components 691 MG a Camp water usage for all locations and alternatives is 100 gallons per person per day.

b Typical ice road water requirement is 1 MG per mile for 35-foot wide ice road. Wider ice roads are required for pipeline 

construction; water use for pipeline construction ice roads were ratioed from the 35-foot wide ice road.

c A 10-acre ice pad would be needed (2.5 MG per 10 acres) to support drilling.

d Drilling water requirement is based on 2 MG per well; drilling a well takes 54 days. Water use was estimated for the drilling phase 

assuming 48 wells will be drilled over 7.1 years. 

e Water use for routine operations assumes a 30 year project lifespan post construction. Water use for routine operations is not 

included in the Drilling total for the overlapping years. The annual ice road for the 7.1 years of drilling is accounted for in the Drilling 

Total.
B-13

Water Use for Alternative C, Roadless Development – 3 YEAR CONSTRUCTION SCHEDULE a 

Project Phase Project Component Water Requirement (MG)

Construction Season 0 Ice Road: 25.6 miles b 36.1

Construction Season 0 Ice Pad: 25.0

Construction Season 0 Winter Work Force 3.7

Construction Season 0 Construction Miscellaneous 1.0

Construction Season 1 Ice Road: 26.0 miles 36.7

Construction Season 1 Ice Pad: 26.3

Construction Season 1 Winter Work Force 3.7

Construction Season 1 Construction Miscellaneous 1.0

Construction Season 2 Ice Road: 51.2 miles 83.4

Construction Season 2 Ice Pad: 43.8

Construction Season 2 Winter Work Force - Alpine 3.7

Construction Season 2 Winter Work Force - Remote 1.6

Construction Season 2 Construction Miscellaneous 1.0

Construction Season 2 Summer Workforce 3.4

Construction Total c 270.4

a Camp water usage for all locations and alternatives is 100 gallons per person per day.

b Typical ice road water requirement is 1 MG per mile for 35-foot wide ice road. Wider ice roads are required for pipeline 

construction; water use for pipeline construction ice roads were ratioed from the 35-foot wide ice road.

c Under a three year construction schedule, water use for drilling and routine operations will not change. 

Appendices  Final Supplemental Environmental Impact Statement

Alpine Satellite Development Plan for the Proposed Greater Mooses Tooth 2 Development Project

APPENDIX C

PASSIVE ACOUSTIC MONITORING PROJECT 

METHODOLOGY

APPENDIX C: 2016 PASSIVE ACOUSTIC MONITORING 

PROJECT METHODOLOGY

Project Contacts

Taylor R. Stinchcomb 

M.S. Candidate 

Department of Biology and Wildlife

University of Alaska Fairbanks 

Phone: 970-481-4544

Email: trstinchcomb@alaska.edu

Todd J. Brinkman, PhD 

Assistant Professor of Wildlife Ecology

Institute of Arctic Biology &

Department of Biology and Wildlife

University of Alaska Fairbanks 

Phone: 907-474-7139

Email: tjbrinkman@alaska.edu

Passive Acoustic Monitoring Systems 

We deployed 20 Passive Acoustic Monitoring (PAM) systems in June 2016 to quantify aircraft 

activity and noise levels over Nuiqsut’s subsistence hunting areas during peak caribou hunting 

season. Sites were spaced approximately 10 km apart along the Colville River from its delta 

south to the Anaktuvuk River confluence, as well as along Fish Creek west of Nuiqsut (Figure 

D1). We collaborated with community organizations and Tribal entities including the Kuukpik 

Subsistence Oversight Panel (KSOP, Inc.) to locate our monitoring sites near caribou hunting 

areas where aircraft have been observed

We followed methods developed by the Natural Sounds and Night Skies Division (NSNSD) of 

the National Parks Service (NPS) for system design and configuration (NPS 2013), but we 

modified equipment selection to reduce costs while maintaining the acoustic parameters 

necessary to record aircraft noise. 

A Roland R-05 Digital Audio Recorder (DAR, Roland Corporation 2010, Los Angeles, CA) 

recorded sound continuously for 30-day intervals at a sampling rate of 44.1 kHz and bit rate of 

96 kbps. Sound files were stored in mP3 format on a removable 32 GB SDHC data card. We 

hung the DAR inside a self-crafted windscreen capped with a water-sealed plastic saucer. We 

mounted the windscreen-DAR component onto a galvanized steel pole so that the recording 

device was suspended ~1.5 - 2.4 m above ground level (Figure D1). The power supply at each 

site comprised 8 D-cell alkaline batteries wired in parallel and enclosed in a waterproof box at 

the base of the pole. We replaced batteries and SDHC cards every ~24-30 days until 09 
September 2016 unless a site could not be reached due to logistical constraints. We avoided the 

use of research aircraft for transport to our field sites and opted instead to travel by boat with a 

local driver. Our reliance on river conditions forced us to abandon several upriver sites in late 

July when water levels dropped below the depth navigable by the outboard motor boats used by 

most Nuiqsut residents. This caused substantial variation in the length of sound recordings across 

sites. PAM systems recorded between 479 and 1788 hr (20-75 days) of sound per site from 03 

June to 28 August 2016. 

Identifying Aircraft events through Audiovisual Analysis

After downloading sound data from SD cards, we converted mp3 audio files into a format 

appropriate for sound visualization using the AUDIO2NVSPL software (NPS 2008, Fort Collins, 

CO). This formatting translates audio into one-second Sound Pressure Levels (SPL) and 1/3 

octave frequency spectral bands from which spectrograms can be generated. 

To identify aircraft sound events, we conducted audiovisual analysis for all hourly spectrograms 

at all study sites using the Sound Pressure Level Annotation Tool (SPLAT) from the Acoustic 

Monitoring Toolbox version 1.0.5591 (NPS 2008, Fort Collins, CO). We followed protocols for 

audiovisual analysis outlined in the NSNSD training manual (NPS 2013). Trained users 

identified aircraft sound events by the spectrographic signature and simultaneous audio playback. 

Users then annotated audible events with a unique source ID code corresponding to aircraft type: 

high-altitude jet, propeller plane, or helicopter. Spectral information of annotated events (e.g. 

event date, time, source ID, duration, frequency range, maximum SPL, Sound Exposure Level 

(SEL), username, and date of annotation) is catalogued by the SPLAT software into a single 

Source ID(SRCID) file for each site.

Aircraft Data Analysis 

Once audiovisual analysis was completed for all days of recording at all sites, we compiled 

SRCID files from every site into a single dataset using the data management packages tidyr 

(Wickham 2017) and dplyr (Wickham and Francois 2016) in R version 3.2.4 (R Core Team 

2016). Propeller planes were aggregated into one source code for ‘aircraft type’ because the 

sound signatures produced by small propeller aircraft and larger turboprop aircraft could not be 

discriminated reliably via audiovisual analysis. The sound and appearance of an aircraft 

signature can vary with wind speed, wind direction, and the distance of the plane from the 

recording device, none of which were measured at our field sites.

Metrics files were generated by the month for each site using the Hourly Metrics tool within 

AMT. These files contain informative acoustical metrics including: hourly median exceedance 

levels, natural ambient sound level (Lnat), daytime and nighttime exceedance levels , daytime 

and nighttime ambient sound levels, hourly mean and median noise free intervals, and hourly 

‘contour’ data (changes in SPL by the hour at each 1/3 octave frequency band). The metrics files 

also report detailed measures by source ID including average event count, average event 

duration, and percent time audible by the hour. 
Software Used

Acoustic Monitoring Toolbox version 1.0.5591 (NPS 2008, Fort Collins, CO). 

 Sound Pressure Level Annotation Tool (SPLAT) 

 Hourly Metrics tool 

Python 3.5.1 |Anaconda 4.0.0 (64-bit)| (default, Feb 16 2016, 09:49:46) [MSC v.1900 64 bit 

(AMD64)] on win32 

soundDB kernel environment developed by the NPS for acoustical analysis

publicly available at: https://github.com/gjoseph92/soundDB 

derivedDataFunctions.py script written by Davyd Betchkal, NPS, revised June 2017 

Metric Derivation

1. Events per day 

One aircraft “event” is defined as an aircraft sound signature measured from when it 

enters audibility to when it fades out of audibility. “Event” does not necessarily equate to 

an individual aircraft. It is possible that the same aircraft passed over a single recording 

device multiple times, or that the same aircraft was captured at two recording devices at 

different times or distances. Our system set up does not allow for the discrimination of 

individual aircraft. For our purposes, each noise event (i.e. each time an aircraft can be 

heard) is considered a single disturbance. 

Using Python 3.5.1 and the derivedDataFunctions.py script, we extracted the median 

events per day and range of events per day from site daily percent audibility files. 

Example python code: [(entry.site, quantile_eventsPerDay(dailypa, q, source = 

"air")) for entry, dailypa in soundDB.dailypa(ds, site=ds.dailypa.values("site"))]

2. Lnat

The median sound pressure level that exists in the absence of human noise. Calculated as 

the exceedance value Lx, where x = 100*((1+PA)/2) and PA = percentage of time that 

aircraft are audible. This was extracted from METRICS files using Python v. 3.5.1 and 

thederivedDataFunctions.py script. 

Example python code: MedLnat = [(entry.site, Lnat(metrics, season="Summer", 

weight = "A")) for entry, metrics in soundDB.metrics(ds, 

site=ds.metrics.values("site"))]

The range of Lnat was extracted from METRICS files manually as the lowest and highest 

median Lnat at each site.

3. Lmax 

The maximum one-second Sound Pressure Level exerted by an aircraft. 
In an SRCID file this is equivalent to MaxSPL. Using R and thedplyr package, we 

summarized the median and range MaxSPL at each site (i) across aircraft types and (ii) 

by different types of aircraft. 

R Citations

R version 3.2.4 Revised 

R Core Team. 2016. R: A language and environment for statistical computing. R Foundation for 

Statistical Computing, Vienna, Austria. URL https://www.R-project.org/. 

Hadley Wickham and Romain Francois. 2016. dplyr: A Grammar of Data Manipulation. R packa

ge version 0.5.0. https://CRAN.R-project.org/package=dplyr 

Hadley Wickham. 2017. tidyr: Easily Tidy Data with 'spread()' and 'gather()' Functions. R packa

ge version 0.6.1. https://CRAN.R-project.org/package=tidyr 

National Park Service Citations 

National Park Service (NPS). 2008. Acoustic Monitoring Toolbox v. 1.0.5591.U.S. Department 

of the Interior. Fort Collins, Colorado. 

National Park Service (NPS). 2010. AUDIO2NVSPL: Audio to NVSPL Converter v. 

1.5378.U.S. Department of the Interior. Fort Collins, Colorado. 

National Park Service (NPS). 2013. Acoustic Monitoring: Training Manual. U.S. Department of 

the Interior, National Park Service, Natural Sounds and Night Skies Division, Fort Collins, 

Colorado.
Figures

Figure D1. Map showing locations of study sites where PAM systems were deployed during 

summer 2016 in NPR-A and the vicinity of Nuiqsut. Aircraft symbols indicate locations of 

airstrips. 
Figure D2. Example of a PAM system installed along Fish Creek, Alaska in July, 2016. A 

Roland R-05 digital audio recorder is mounted inside the brown cylindrical windscreen and 

wired down to a power supply of 8 D-cell alkaline batteries enclosed in the orange waterproof 

case.
Appendices  Final Supplemental Environmental Impact Statement

Alpine Satellite Development Plan for the Proposed Greater Mooses Tooth 2 Development Project

APPENDIX D

CLASSIFICATION AND DESCRIPTION OF VEGETATION 

AND WILDLIFE HABITAT TYPES

   

           

     

               

                 

               

                 

             

             

             

      

       

         

       

     

                 

               

             

               

  

       

         

             

          

APPENDIX D 

CLASSIFICATION AND DESCRIPTION OF VEGETATION AND

WILDLIFE HABITAT TYPES

Appendix D Contains Excerpts From the Following Sources

Jorgenson, M.T., J.E. Roth, M. Emers, S.F. Schlenter, D.K,

Swanson, E.R. Pullman, J.S. Mitchell, A.A. Stickney. 2003.

An Ecological Land Survey in the Northeast Planning Area

of the National Petroleum Reserve‐ Alaska, 2002. Prepared

by ABR, Inc.‐ Environmental Research & Services (ABR,

Inc.). Prepared for ConocoPhillips Alaska, Inc. and

Anadarko Petroleum Coporation.

Table 7: Classification and

Description of Vegetation Classes in

the Northeastern Planning Area of

the NPRA, 2002

Johnson, C.B., A.M. Wildman, J.P. Parrett, J.R. Rose, T.

Obritschkewitsch, and P.E. Seiser. 2013. Avian Studies for

the Alpine Satellite Development Project, 2012. Tenth

Annual Report. Prepared by ABR, Inc. and Anadarko

Petroleum Corporation.

Appendix B: Classification and

Descriptions of Wildlife Habitat Types

Found in the Colville Delta or NE

NPRA Study Areas, Alaska, 2012.

       

        

   

Classification and Description of

Vegetation Types

 

 

 

 Results and Discussion 

Table 7. Classification and description of vegetation classes in the Northeastern Planning Area of the

NPRA, 2002. 

Class Description 

Barrens Nonvegetated flats on river bars, sand dunes, tidal flats, and recently drained lake bottoms that are recently exposed 

or too unstable to support more than a few pioneering plants (<5% cover). Typical species include Salix alaxensis, 

Festuca rubra, Deschampsia caespitosa, Juncus arcticus, Stellaria humifusa, and Equisetum arvense. Riverine 

Barrens include river flats and bars, commonly along Fish and Judy Creeks. These areas are flooded seasonally 

and underlain by sand. Toward the coast, sediments are increasingly saline and tidally affected barrens are 

colonized by salt-tolerant species. 

Partially Riverbanks, upland sand dunes, and shallow lake basins that have 530% vegetative cover. 

Vegetated Colonizers include Deschampsia caespitosa, Salix alaxensis, Juncus arcticus, Chrysanthemum 

bipinnatum, Stellaria humifusa, Elymus arenarius mollis, Equisetum arvense and Trisetum spicatum. 

Moist Sedge Lowland sites on moderately well-drained flats and gentle slopes within Thaw Basins, Alluvial 

Shrub Tundra Marine, and Inactive Eolian Sand Deposits, and Riverine Inactive Overbank Deposits, frequently 

associated with high-centered, and mixed high- and low-centered polygons. Vegetation is codominated by sedges (e.g. Carex bigelowii, C. aquatilis, Eriophorum angustifolium), and dwarf or low 

shrubs including Dryas integrifolia and Salix reticulata. Other common vascular species include Salix 

lanata richardsonii, S. planifolia pulchra, Equisetum variegatum, Arctagrostis latifolia, and Cassiope 

tetragona. Important non-vascular species include Tomentypnum nitens, Hylocomium splendens, 

Sanionia uncinata, and Dicranum sp. This class can be confused with Dryas Tundra on drier sites 

where Dryas integrifolia is dominant and Tussock Tundra where Eriophorum vaginatum is dominant. 

Soils are saturated at intermediate depths (> 15 cm) but generally are free of surface water during 

summer; some sites may be inundated briefly during break-up. 

Tussock The tussock-forming sedge Eriophorum vaginatum dominates the vegetation. On somewhat acidic 

Tundra soils associated species include Ledum decumbens, Vaccinium vitis-idaea, Salix planifolia pulchra, 

Betula nana, Salix phlebophylla, Dicranum sp., and Hylocomium splendens. On circumneutral soils 

Dryas integrifolia, Salix reticulata, Carex bigelowii, and Tomentypnum nitens are more common 

though there are many species in common among the two tussock communities and Moist Sedge 

Shrub Tundra. Found associated with high-centered, and mixed high- and low-centered polygons on 

broad slopes of AlluvialMarine, Inactive Eolian Sand, and Old Alluvial Terrace Deposits and within 

Ice-rich Thaw Basins. Water generally is absent from the active layer during midsummer. 

Common In shallow coastal ponds, pond margins, and at the edges of slow moving streams. Hippuris vulgaris 

Marestail is the dominant species, Arctophila fulva, Potamogeton sp., Carex subspathacea, and Calliergon sp. 

are common associates. This class was not mapped. 

Fresh Grass Shallow lakes within Ice-Poor Thaw Basins and river ox-bows, shallow margins of large lakes, and 

Marsh shallow water of slow-moving headwater streams dominated by Arctophila fulva. Water depths 

generally are < 1.0m. Hippuris vulgaris, Limprichtia revolvens, and Carex aquatilis may be present in 

water < 0.5m . 

Fresh Sedge Permanently flooded shallow water within Thaw Basins, shallow margins of large lakes, and shallow 

Marsh water of slow-moving headwater streams dominated by Carex aquatilis. Often found as a fringe 

between deeper water with Arctophila fulva and the lake shore, Carex aquatilis also may form a 

monoculture within shallow (< 0.5m) waterbodies. Associated species include Scorpidium scorpioides 

and Eriophorum angustifolium. Polygon development is minimal though disjunct polygon rims may 

be present. 

Wet Sedge Low-lying, poorly drained areas with vegetation dominated by Carex aquatilis, Eriophorum 

Meadow angustifolium, and mosses. Associated with nonpatterned ground, low-centered, or disjunct polygons 

Tundra in Thaw Basins, AlluvialMarine, Old Alluvial Terrace, and Inactive Overbank Deposits. This class is 

also found in water tracks and swales where willows may be co-dominant. Associated species include 

E. russeolum, C. chordorrhiza, C. saxatilis, Salix lanata richardsonii, S. planifolia pulchra, and 

Pedicularis sudetica. Frequently occurring mosses include Scorpidium scorpioides, Limprichtia 

revolvens, Drepanocladus spp., and Campylium stellatum. When polygons are present the rim 

vegetation is similar to Moist SedgeShrub Tundra. The tundra surface generally is flooded during 

early summer (depth < 0.3m) and water remains close to the surface throughout the growing season. 

Soils usually have a moderately thick organic layer over silt loam or sandy loam. 

35 NPRA Ecological Land Survey, 2002 
 

 

Results and Discussion 

Table 7. (Continued). 

Class Description 

Salt-killed Coastal areas where saltwater intrusions from storm surges have killed much of the original terrestrial 

Wet Meadow vegetation and where salt-tolerant plants are actively colonizing. Colonizing plants include 

Puccinellia andersonii, Dupontia fisheri, Braya purpurascens, B. pilosa, Cochlearia officinalis, 

Stellaria humifusa, Cerastium beeringianum, and Salix ovalifolia. This class typically occurs either 

on low-lying areas that originally supported Wet Sedge Meadow Tundra and Basin Wetland 

Complexes, or less commonly, along drier coastal bluffs that originally supported Moist SedgeShrub 

Meadow Tundra. Salt-killed Wet Meadow differs from Halophytic Sedge Wet Meadow in having 

abundant litter from dead tundra vegetation, a surface horizon of organic soil, and salt-tolerant 

colonizers. 

Halophytic Coastal areas with wet, saline soils typically dominated by the sedges Carex subspathacea and C. 

Sedge Wet ursina. Primarily found on Inactive Tidal Flat Deposits and Delta Thaw Basins on nonpatterned 

Meadow ground or low-centered polygons, associated species often include Puccinellia phryganodes, Salix 

ovalifolia, Calamagrostis deschampsioides, Cochlearia officinalis, Stellaria humifusa, and Sedum 

rosea. 

Dryas Dwarf Dry, upland, sandy slopes, crests, and well-drained river terraces dominated by Dryas integrifolia. 

Shrub Tundra Most commonly associated with Inactive Eolian Sand Deposits and small dunes, Dryas Dwarf Shrub 

Tundra also is found on nonpatterned ground and high-centered polygons on Pingos, Inactive 

Overbank, and AlluvialMarine Deposits. Inactive dune sites are strongly dominated by Dryas and 

occasionally co-dominated by lichens, associated species include Salix glauca, S. reticulata, 

Arctostaphylos alpina, Arctagrostis latifolia, Thamnolia vermicularis, and Cetraria cuculata. 

Riverine sites may have co-dominant species such as Equisetum variegatum and Salix reticulata, with 

S. lanata richardsonii, Arctostaphylos rubra, Oxytropis deflexa, Tomentypnum nitens, and Thamnolia 

vermicularis as associated species. Sedges (e.g. Carex scirpoidea) may be present on moist sites but 

are never co-dominant. Soils are sandy, well to somewhat excessively drained, and thaw depths often 

exceed 1.0m. 

Cassiope Old dunes and banks on Inactive Eolian Sand, AlluvialMarine Deposits, and Ice-rich Thaw Basins 

Dwarf Shrub dominated by Cassiope tetragona. Compared with Dryas Dwarf Shrub Tundra, with which this class 

Tundra shares some species, Cassiope Dwarf Shrub Tundra is less well drained, has shallower thaw depths, 

and can occur on sandy or loamy soils. Cassiope dominated sites typically are very species rich, 

common associated species include Dryas integrifolia, S. phlebophylla, Salix reticulata, Vaccinium 

vitis-idaea, Carex bigelowii, Hierochloe alpina, and Arctagrostis latifolia. Cryptogams present 

include crustose lichens, Hylocomium splendens, Dicranum sp., Tomentypnum nitens, and Rhytidium 

rugosum. All sites have a wide variety of forbs. 

Halophytic Coastal areas with moist to wet, saline or slightly saline soils typically dominated by Salix ovalifolia or 

Willow Dwarf co-dominated by S. ovalifolia and halophytic graminoids. Primarily found on Inactive Tidal Flats, 

Shrub Tundra Delta Overbank Deposits, and Delta Thaw Basins on nonpatterned ground or low-centered polygons. 

Associated species often include Carex subspathacea, C. aquatilis, C. glareosa, Calamagrostis 

deschampsioides, Dupontia fisheri, Drepanocladus sp., and Thamnolia vermicularis. 

Open and Riverine, lowland or upland communities dominated by low willows (0.2 1.5m) with an open (25 

Closed Low 75% cover) or closed (>75%) canopy. Riverine deposits typically are dominated by Salix lanata 

Willow Shrub richardsonii (sometimes co-dominant with S. planifolia pulchra), with Carex aquatilis, Equisetum 

arvense, E. variegatum, Arctagrostis latifolia, and Tomentypnum nitens. Lowland willow shrub is 

found primarily on high-centered polygons or nonpatterned ground on Abandoned Floodplains, within 

Thaw Basins, and on banks or water tracks of AlluvialMarine Deposits. Lowland communities are 

dominated by S. planifolia pulchra, with C. aquatilis, S. reticulata, C. bigelowii, Pyrola grandiflora, 

Dicranum sp., Aulacomnium turgidum, A. palustre, and Hylocomium splendens. Upland 

communities, dominated by Salix glauca, are found on small dunes of Eolian Inactive Sand Deposits. 

Associated species include S. alaxensis, Arctostaphylos rubra, Dryas integrifolia, and Oxytropis 

nigrescens. 

Open Low More typical of areas in the southern NPRA, this class infrequently is found on banks, or highMesic Shrub centered polygons on AlluvialMarine Deposits. Betula nana is dominant with Salix planifolia 

Birch pulchra, S. glauca, S. reticulata, Arctostaphylos rubra, Dryas integrifolia, Vaccinium vitis-idaea, 

Ericaceous Pyrola grandiflora, Hylocomium splendens, Aulacomnium palustre, Dicranum sp., and Pleurozium 

Shrub schreberi as associates. This class was not mapped. 

NPRA Ecological Land Survey, 2002 36 
 

 Results and Discussion 

Table 7. (Continued). 

Class Description 

Open and Active Eolian Sand and Riverine Deposits dominated by Salix alaxensis. Willows often are > 1.5m 

Closed Tall tall with an open (2575% cover) or closed (>75%) canopy. Soils are very well-drained, sandy, and 

Willow Shrub frequently disturbed by flooding or strong winds. Understory species on riverine deposits include 

Equisetum arvense, Chrysanthemum bipinnatum, Festuca rubra, Aster sibiricus, and Gentiana 

propinqua. Upland dune associates include S. glauca, Arctostaphylos rubra, Astragalus alpinus, 

Castilleja caudata, Festuca rubra, and Chrysanthemum bipinnatum. 

Water Permanently flooded, non-vegetated waterbodies. Included in this class are non-vegetated Thaw 

Lakes, Headwater Streams, Lower Perennial Rivers, Riverine Lakes, and Beaded Streams. Areas 

mapped as water may include some partially vegetated waterbodies where vegetation was submerged 

and therefore not discernable on the aerial photography. 

Young Basin Young Basin Wetland Complexes occur in portions of recently drained lake basins and are 

Wetland characterized by a complex mosaic of open water, Fresh Sedge and Grass Marshes, Wet Sedge 

Complex (ice- Meadow, and Moist SedgeShrub Tundra in patches too small (< 0.5 ha) to map individually. Young 

poor) basins are distinguished from older basins because they have little ground ice development and 

typically are dominated by more productive vegetation than older basins. Surface forms are 

nonpatterned ground or disjunct polygons. To be mapped as a complex an area must be at least 2 ha 

and have at least three vegetation types, with no single type dominant. 

Old Basin Similar to Young Basin Wetland Complexes but occurring in portions of less recently drained basins. 

Wetland This type is characterized by vegetation found in association with ice wedge development and 

Complex (ice- aggradation of segregated ice including Wet Sedge Meadow Tundra with low-centered polygons, 

rich) Moist SedgeShrub, and Tussock Tundra. Fresh Grass Marshes are absent and Sedge Marsh occurs 

only in flooded portions of margins. Centers of old basins are uplifted sands and loams with shallow 

to moderate organic horizons. Complexes mapped in centers typically are Tussock, Moist Sedge 

Shrub, and Wet Sedge Meadow Tundra. Margins of old basins are wetter with many small, discrete 

ponds. Soils generally have a moderately thick organic layer overlying sand or sandy loam, vegetation 

in margins typically is Moist SedgeShrub Tundra, Wet Sedge Meadow, Fresh Sedge Marsh, and 

Water. Complexes are comprised of at least three vegetation types, with no single type dominant. 

Minimum size for complexes is 2 ha. 

Riverine Permanently flooded channels and narrow bands or patches of vegetation too small to be mapped 

Complex separately. The variety of vegetation reflects the degree and regularity of flooding. Vegetation classes 

include Water, Barren or Partially Vegetated gravel bars, Fresh Sedge or Grass Marsh, Wet Sedge 

Meadow, Moist SedgeShrub Tundra, or Low Willow Shrub. Rivers generally experience peak 

flooding during spring breakup and lowest water levels during mid-summer. 

Deep Polygon Mosaic of vegetation on inactive and abandoned floodplains where low-centered polygons have 

Complex particularly deep (>0.5 m) centers formed by thaw settlement of ice-rich soils. Permanently flooded 

nonvegetated polygon centers are fringed by Fresh Grass or Sedge Marsh. Broad, low, rims of Wet 

Sedge Meadow or Moist SedgeShrub Tundra separate the centers. While water forms a substantial 

portion of this class, no single vegetation type or water is dominant. 

Dune Complex formed on inactive sand dunes on meander floodplains. A series of narrow swale and ridge 

Complex features develop in parallel with river flow that are too small to map separately. Vegetation in moist to 

wet swales typically is Low Willow Shrub, Wet Sedge Meadow Tundra, or Fresh Sedge Marsh, while 

dry to moist sandy, dune ridges commonly are Dryas Dwarf Shrub Tundra or Low Willow Shrub. 

37 NPRA Ecological Land Survey, 2002 

        

     

Classification and Description of

Wildlife Habitat Types

Habitat Class Description 

Open Nearshore Water Shallow estuaries, lagoons, and embayments along the coast of the Beaufort Sea. Winds, 

(Estuarine Subtidal) tides, river discharge, and icing create dynamic changes in physical and chemical 

characteristics. Tidal range normally is small (< 0.2 m), but storm surges produced by 

winds may raise sea level as much as 2–3 m. Bottom sediments are mostly 

unconsolidated mud. Winter freezing generally begins in late September and is 

completed by late November. An important habitat for some species of waterfowl for 

molting during spring and fall staging. 

Brackish Water (Tidal Coastal ponds and lakes that are flooded periodically with saltwater during storm surges. 

Ponds) Salinity levels often are increased by subsequent evaporation of impounded saline 

water. Sediments may contain peat, reflecting a freshwater/terrestrial origin, but this 

peat is mixed with deposited silt and clay. 

Tapped Lake with Waterbodies that have been partially drained by erosion of banks by adjacent river 

Low-water channels and are connected to rivers by distinct, permanently flooded channels. The 

Connection water typically is brackish and the lakes are subject to flooding every year. Because 

water levels have dropped, the lakes generally have broad flat shorelines with silty clay 

sediments. Salt-marsh vegetation is common along the shorelines. Deeper lakes in this 

habitat do not freeze to the bottom during winter. Sediments are fine-grained silt and 

clay with some sand. These lakes form important over-wintering habitat for fish. 

Tapped Lake with Similar to Tapped Lake with Low-water Connection except that the connecting channels 

High-water are dry during low water and the lakes are connected only during flooding events. 

Connection Water tends to be fresh. Small deltaic fans are common near the connecting channel 

due to deposition during seasonal flooding. These lakes form important fish habitat. 

Salt Marsh On the Beaufort Sea coast, arctic Salt Marshes generally occur in small, widely dispersed 

patches, most frequently on fairly stable tidal flats associated with river deltas. The 

surface is flooded irregularly by brackish or marine water during high tides, storm 

surges, and river flooding events. Salt Marshes typically include a complex assemblage 

of small brackish ponds and Halophytic Sedge or Grass Wet Meadows. Moist 

Halophytic Dwarf Shrub and small barren areas also may occur in patches too small to 

map separately. Dominant plant species usually include Carex subspathacea, C. ursina, 

C. ramenskii, Puccinellia phryganodes, Dupontia fisheri, P. andersonii, Salix ovalifolia, 

Cochlearia officinalis, Stellaria humifusa, and Sedum rosea. Salt Marsh is important 

habitat for brood-rearing and molting waterfowl. 

Moist Halophytic Tidal flats and regularly flooded riverbars of tidal rivers with vegetation dominated by 

Dwarf Shrub dwarf willow and graminoids. Tide flat communities have brackish, loamy (with 

variable organic horizons), saturated soils, with ground water depths ~ 25 cm and active 

layer depths ~50 cm. Vegetation is dominated by Salix ovalifolia, Carex subspathacea, 

and Calamagrostis deschampsioides. On sandy sites Elymus arenarius mollis is a codominant. On active tidal river depostis, soils are loamy, less brackish, and vegetation 

is dominated by Salix ovalifolia with Carex aquatilis and Dupontia fisheri. 

Appendix B. Classification and descriptions of wildlife habitat types found in the 

Colville Delta or NE NPRA study areas, Alaska, 2012. Species 

associations of some habitats vary between the Colville Delta and the 

NE NPRA study areas. 
 

 

 

 

 

Appendix B. (Continued). 

Habitat Class Description 

Dry Halophytic 

Meadow 

Somewhat poorly vegetated, well-drained meadows on regularly inundated tidal flats and 

riverbars of tidal rivers, characterized by the presence of Elymus arenarius mollis. Soils 

are brackish sands with little organic material and deep active layers. Commonly 

associated species include Salix ovalifolia, Sedum rosea, Stellaria humifusa, (on tide 

flats) and Deschampsia caespitosa (on tidal river deposits). 

Tidal Flat Barrens Areas of nearly flat, barren mud or sand that are periodically inundated by tidal waters. 

Tidal Flat Barrens occur on the seaward margins of deltaic estuaries, leeward portions of 

bays and inlets, and at mouths of rivers. Tidal Flat Barrens frequently are associated 

with lagoons and estuaries and may vary widely in actual salinity levels. Tidal Flat 

Barrens are considered separately from other barren habitats because of their importance 

to estuarine and marine invertebrates and shorebirds. 

Salt-killed Tundra Coastal areas where saltwater intrusions from storm surges have killed much of the 

original terrestrial vegetation and are being colonized by salt-tolerant plants. Colonizing 

plants include Puccinellia andersonii, Dupontia fisheri, Braya purpurascens, B. pilosa, 

Cochlearia officinalis, Stellaria humifusa, Cerastium beeringianum, and Salix 

ovalifolia. This habitat typically occurs either on low-lying areas that originally 

supported Patterned Wet Meadows and Basin Wetland Complexes or, less commonly, 

along drier coastal bluffs that originally supported Moist Sedge–Shrub Meadow and Dry 

Dwarf Shrub. Salt-killed Tundra differs from Salt Marshes in having abundant litter 

from dead tundra vegetation, a surface horizon of organic soil, and salt-tolerant 

colonizers. 

Deep Open Water 

without Islands 

Deep (≥1.5 m) waterbodies range in size from small ponds in ice-wedge polygons to large 

open lakes. Most have resulted from thawing of ice-rich sediments, although some are 

associated with old river channels. They do not freeze to the bottom during winter and 

usually are not connected to rivers. Sediments are fine-grained silt in centers with sandy 

margins. Deep Open Waters without Islands are differentiated from those with islands 

because of the lack of nest sites for waterbirds that prefer islands. 

Deep Open Water with 

Islands or 

Polygonized Margins 

Similar to above except that they have islands or complex shorelines formed by thermal 

erosion of low-center polygons. The complex shorelines and islands are important 

features of nesting habitat for many species of waterbirds. 

Shallow Open Water 

without Islands 

Ponds and small lakes <1.5 m deep with emergent vegetation covering <5% of the 

waterbody’s surface. Due to the shallow depth, water freezes to the bottom during 

winter and thaws by early to mid-June. Maximal summer temperatures are higher than 

those in deep water. Sediments are loamy to sandy. 

Shallow Open Water 

with Islands or 

Polygonized Margins 

Shallow lakes and ponds with islands or complex low-center polygon shorelines, 

otherwise similar to Shallow Open Water without Islands. Distinguished from Shallow 

Open Water without Islands because shoreline complexity appears to be an important 

feature of nesting habitat for many species of waterbirds. 

River or Stream All permanently flooded channels large enough to be mapped as separate units. Rivers 

generally experience peak flooding during spring breakup and lowest water levels 

during mid-summer. The distributaries of Fish Creek are slightly saline, whereas other 

streams are non-saline. 
 

 

 

 

 

 

 

 

Appendix B. (Continued). 

Habitat Class Description 

Sedge Marsh Permanently flooded waterbodies dominated by Carex aquatilis. Typically, emergent 

sedges occur in water ≤0.5 m deep. Water and bottom sediments of this shallow habitat 

freeze completely during winter, but the ice melts in early June. The sediments 

generally consist of a peat layer (0.2–0.5 m deep) overlying loam or sand. 

Deep Polygon Complex A habitat associated with inactive and abandoned floodplains and deltas in which 

thermokarst of ice-rich soil has produced deep (>0.5 m), permanently flooded polygon 

centers. Emergent vegetation, mostly Carex aquatilis, usually is found around the 

margins of the polygon centers. Occasionally, centers will have the emergent grass 

Arctophila fulva. Polygon rims are moderately well drained and dominated by sedges 

and dwarf shrubs, including Carex aquatilis, Eriophorum angustifolium, C. bigelowii, 

Dryas integrifolia, Salix reticulata, and S. ovalifolia. 

Grass Marsh Ponds and lake margins with the emergent grass Arctophila fulva. Due to shallow water 

depths (<1 m), the water freezes to the bottom in the winter, and thaws by early June. 

Arctophila fulva stem densities and annual productivity can vary widely among sites. 

Sediments generally lack peat. This type usually occurs as an early successional stage 

in recently drained lake basins and is more productive than Sedge Marsh. This habitat 

tends to have abundant invertebrates and is important to many waterbirds. 

Young Basin Wetland 

Complex (Ice-poor) 

Complex habitat found in recently drained lake basins and characterized by a mosaic of 

open water, Sedge and Grass Marshes, Nonpatterned Wet Meadows, and Moist Sedge– 

Shrub Meadows in patches too small (<0.5 ha) to map individually. During spring 

breakup, basins may be entirely inundated, though water levels recede by early summer. 

Basins often have distinct banks marking the location of old shorelines, but these 

boundaries may be indistinct due to the coalescence of thaw basins and the presence of 

several thaw lake stages. Soils generally are loamy to sandy, moderately to richly 

organic, and ice-poor. Because there is little segregated ground ice the surface form is 

nonpatterned ground or disjunct polygons and the margins of waterbodies are indistinct 

and often interconnected. Ecological communities within young basins appear to be 

much more productive than are those in older basins: this was the primary rationale for 

differentiating these two types. 

Old Basin Wetland 

Complex (Ice-rich) 

Similar to above but characterized by well-developed low- and high-centered polygons 

resulting from ice-wedge development and aggradation of segregated ice. Complexes in 

basin margins generally include Sedge Marsh, Patterned Wet Meadow, Moist Sedge– 

Shrub Meadows, and small ponds (<0.25 ha). The waterbodies in old basins tend to 

have smoother, more rectangular shorelines and are not as interconnected as those in 

more recently drained basins. The vegetation types in basin centers generally include 

Moist Sedge–Shrub Meadow and Moist Tussock Tundra on high-centered polygons, 

and Patterned Wet Meadows. Grass Marsh generally is absent. Soils have a moderately 

thick (0.2–0.5 m) organic layer overlying loam or sand. 
 

 

 

Appendix B. (Continued). 

Habitat Class Description 

Riverine Complex Permanently flooded streams and floodplains characterized by a complex mosaic of water, 

Barrens, Dry Dwarf Shrub, Moist Tall Shrub and Moist Low Shrub, Sedge and Grass 

Marsh, Nonpatterned and Patterned Wet Meadow, and Moist Sedge–Shrub Meadow in 

patches too small (<0.5 ha) to map individually. Surface form varies from nonpatterned 

point bars and meadows to mixed high- and low-centered polygons and small, stabilized 

dunes. Small ponds tend to have smooth, rectangular shorelines resulting from the 

coalescing of low centered polygons. During spring flooding these areas may be 

entirely inundated, following breakup water levels gradually recede. 

Dune Complex Complex formed from the action of irregular flooding on inactive sand dunes, most 

commonly on river point bars. A series of narrow swale and ridge features develop in 

parallel with river flow that are too small to map separately. Swales are moist or 

saturated while ridges are moist to dry. Habitat classes in swales typically are Moist 

Low Shrub, Nonpatterned Wet Meadow, or Sedge Marsh, while ridges commonly are 

Dry Dwarf Shrub or Moist Low Shrub. 

Nonpatterned Wet 

Meadow 

Sedge-dominated meadows that occur within recently drained lake basins, as narrow 

margins of receding waterbodies, or along edges of small stream channels in areas that 

have not yet undergone extensive ice-wedge polygonization. Disjunct polygon rims and 

strang cover <5% of the ground surface. The surface generally is flooded during early 

summer (depth <0.3 m) and drains later, but water remains close to the surface 

throughout the growing season. The uninterrupted movement of water (and dissolved 

nutrients) in nonpatterned ground results in more robust growth of sedges than occurs in 

polygonized habitats. Usually dominated by Carex aquatilis and Eriophorum 

angustifolium, although other sedges may be present. Near the coast, the grass 

Dupontia fisheri may be present. Low and dwarf willows (Salix lanata richardsonii, S. 

reticulata, S. planifolia pulchra) occasionally are present. Soils generally have a 

moderately thick (10–30 cm) organic horizon overlying loam or sand. 

Patterned Wet Meadow Lowland areas with low-centered polygons or strang within drained lake basins, level 

floodplains, and flats and water tracks on terraces. Polygon centers are flooded in 

spring and water remains close to the surface throughout the growing season. Polygon 

rims or strang interrupt surface and groundwater flow, so only interconnected polygon 

troughs receive downslope flow and dissolved nutrients; in contrast, the input of water 

to polygon centers is limited to precipitation. As a result, vegetation growth typically is 

more robust in polygon troughs than in centers. Vegetation is dominated by sedges, 

usually Carex aquatilis and Eriophorum angustifolium, although other sedges may be 

present including C. rotundata, C. saxatilis, C. membranacea, C. chordorrhiza, and E. 

russeolum. On polygon rims, willows (e.g., Salix lanata richardsonii, S. reticulata, S. 

planifolia pulchra) and the dwarf shrubs Dryas integrifolia and Cassiope tetragona may 

be abundant along with other species typical of moist tundra. 

Moist Sedge–Shrub 

Meadow 

High-centered, low-relief polygons and mixed high- and low-centered polygons on gentle 

slopes of lowland, riverine, drained basin, and solifluction deposits. Soils are saturated 

at intermediate depths (>0.15 m) but generally are free of surface water during summer. 

Vegetation is dominated by Dryas integrifolia, and Carex bigelowii. Other common 

species include C. aquatilis, Eriophorum angustifolium, Salix reticulata, S. lanata 

richardsonii, and the moss Tomentypnum nitens. The active layer is relatively shallow 

and the organic horizon is moderate (0.1–0.2 m). 
Habitat Class Description 

Moist Tussock Tundra Gentle slopes and ridges of coastal deposits and terraces, pingos, and the uplifted centers 

of older drained lake basins. Vegetation is dominated by tussock-forming plants, most 

commonly Eriophorum vaginatum. High-centered polygons of low or high relief are 

associated with this habitat. Soils are loamy to sandy, somewhat well-drained, acidic to 

circumneutral, with moderately thick (0.1–0.3 m) organic horizons and shallow (<0.4 

m) active layer depths. On acidic sites, associated species include Ledum decumbens, 

Betula nana, Salix planifolia pulchra, Cassiope tetragona and Vaccinium vitis-idaea. 

On circumneutral sites common species include Dryas integrifolia, S. reticulata, Carex 

bigelowii, and lichens. Mosses are common at most sites. 

Moist Tall Shrub Most commonly found on actively flooded banks and bars of meander and tidal rivers 

dominated by tall (> 1.5 m) shrubs. Sites are nonpatterned and subject to variable 

flooding frequency, soils are well-drained, alkaline to circumneutral, and lack organic 

material. Vegetation is defined by an open canopy of Salix alaxensis. Understory 

species include Equisetum arvense, Gentiana propinqua, Chrysanthemum bipinnatum, 

Festuca rubra and Aster sibiricus. Moist Tall Shrub occasionally occurs on protected 

lowland sites where the dominant species may be Salix spp.or Alnus crispa. 

Moist Low Shrub Any community on moist soils dominated by willows < 1.5m tall. Upland sites are welldrained sands and loams characterized by Salix glauca (or infrequently, Betula nana), 

Dryas integrifolia, and Arctostaphylos rubra. Recently drained basins are somewhat 

poorly drained loams with moderate organic horizons dominated by either S. lanata 

richardsonii or S. planifolia pulchra with Eriophorum angustifolium and Carex 

aquatilis. Riverbank deposits also are dominated by either S. lanata richardsonii or S. 

planifolia pulchra, but with Equisetum arvense, Arctagrostis latifolia, or Petasites 

frigidus. Somewhat poorly-drained lowland flats and lower slopes have the greatest 

organic horizon development and are dominated by S. planifolia pulchra. Associated 

species are similar to those in drained basin communities. Thaw depths are deepest in 

riverine and upland communities and shallowest in lowland areas. 

Moist Dwarf Shrub Well-drained upland slopes and banks, and the margins of drained lake basins dominated 

by Cassiope tetragona. Soils are well-drained, loamy to sandy and circumneutral to 

acidic. Vegetation is species rich, associated species include Dryas integrifolia, Salix 

phlebophylla, Vaccinium vitis-idaea, Carex bigelowii, Arctagrostis latifolia, Hierochloe 

alpina, Pyrola grandiflora, and Saussurea angustifolia. Lichens and mosses also are 

common. 

Dry Tall Shrub Crests of active sand dunes with vegetation dominated by the tall willow Salix alaxensis. 

Soils are sandy, excessively drained, alkaline to circumneutral, with deep active layers 

(>1 m) and no surface organic horizons. The shrub canopy usually is open with 

dominant shrubs >1m tall. Other common species include Chrysanthemum bipinnatum, 

Festuca rubra, and Equisetum arvense. 

Appendix B. (Continued). 
 

 

 

Appendix B. (Continued). 

Habitat Class Description 

Dry Dwarf Shrub Well-drained riverbank deposits and windswept, upper slopes and ridges dominated by 

the dwarf shrub Dryas integrifolia. Soils are sandy to loamy, alkaline to circumneutral, 

with deep active layers. Upland sites are lacking in organics, and in riverine sites 

organic accumulation is shallow. Riverbank communities have Salix reticulata, Carex 

bigelowii, Arctagrostis latifolia, Equisetum variegatum, Oxytropis deflexa, 

Arctostaphylos rubra, and lichens as common associates, while upland sites have S. 

reticulata, S. glauca, S. arctica, C. bigelowii, Arctostaphylos alpina, Arctagrostis 

latifolia, and lichens. 

Barrens (Riverine, 

Eolian, or Lacustrine) 

Includes barren and partially vegetated (<30% plant cover) areas related to riverine, 

eolian, or thaw basin processes. Riverine Barrens on river flats and bars are underlain 

by moist sands and are flooded seasonally. Early colonizers are Deschampsia 

caespitosa, Poa hartzii, Festuca rubra, Salix alaxensis, and Equisetum arvense. Eolian 

Barrens are active sand dunes that are too unstable to support more than a few 

pioneering plants (<5% cover). Typical species include Salix alaxensis, Festuca rubra, 

and Chrysanthemum bipinnatum. Lacustrine Barrens occur within recently drained 

lakes and ponds. These areas may be flooded seasonally or can be well drained. 

Typical colonizers are forbs, graminoids, and mosses including Carex aquatilis, 

Dupontia fisheri, Scorpidium scorpioides, and Calliergon sp. on wet sites and Poa spp., 

Festuca rubra, Deschampsia caespitosa, Stellaria humifusa, Senecio congestus, and 

Salix ovalifolia on drier sites. Barrens may receive intense use seasonally by caribou as 

mosquito-relief habitat. 

Human Modified 

(Water, Fill, Peat Road) 

A variety of small disturbed areas, including impoundments, gravel fill, and a sewage 

lagoon at Nuiqsut. Gravel fill is present at Nuiqsut, the Alpine facilities, and at the 

Helmericks’ residence near the mouth of the Colville River. 
     

       

Cross Reference for

Habitat and Vegetation Types

           

      

   

   

               

         

           

             

           

       

         

       

   

   

             

               

           

           

           

       

           

         

             

               

             

     

       

         

             

       

         

               

         

         

Cross Reference for Habitat and Vegetation Types

Vegetation Type Habitat Type

Partially Vegetated Barrens

Barren Barrens

Water Brackish Water

Water Deep Open Water with Islands or Polygonized Margins

Water Deep Open Water without Islands

Deep Polygon Complex Deep Polygon Complex

Dryas Dwarf Shrub Tundra Dry Dwarf Shrub

Open Tall Willow Dry Tall Shrub

Dune Complex Dune Complex

Fresh Grass Marsh Grass Marsh

Partially Vegetated Human Modified

Barren Human Modified

Water Human Modified

Cassiope Dwarf Shrub Tundra Moist Dwarf Shrub

Halophytic Willow–Graminoid Dwarf Shrub Tundra Moist Halophytic Dwarf Shrub

Open Low Willow Moist Low Shrub

Closed Low Willow Moist Low Shrub

Open Tall Willow Moist Low Shrub

Moist Sedge–Shrub Tundra Moist Sedge‐Shrub Meadow

Open Tall Willow Moist Tall Shrub

Tussock Tundra Moist Tussock Tundra

Wet Sedge Meadow Tundra Nonpatterned Wet Meadow

Old Basin Wetland Complex Old Basin Wetland Complex

Wet Sedge Meadow Tundra Patterned Wet Meadow

Water River or Stream

Riverine Complex Riverine Complex

Salt–killed Wet Meadow Salt‐killed Tundra

Halophytic Grass Wet Meadow, brackish Salt Marsh

Coastal Complex Salt Marsh

Fresh Sedge Marsh Sedge Marsh

Water Shallow Open Water with Islands or Polygonized Margins

Water Shallow Open Water without Islands

Water Tapped Lake with Low‐water Connection

Appendices  Final Supplemental Environmental Impact Statement

Alpine Satellite Development Plan for the Proposed Greater Mooses Tooth 2 Development Project

APPENDIX E

ESSENTIAL FISH HABITAT
1 

Essential Fish Habitat

Regulatory Background

The 1996 Sustainable Fisheries Act (Public Law 104‐297) enacted additional management 

measures to protect commercially harvested fish species from overfishing. Along with

reauthorizing the Magnuson‐ Stevens Fishery Conservation and Management Act (Public

Law 94‐265 [Magnuson‐Stevens Act), one of those added measures is to describe, identify, 

and minimize adverse effects to “essential fish habitat.” Definitions and rules involving

essential fish habitat are in 50 CFR Part 600. The National Marine Fisheries Service 

implements the requirements of the Magnuson‐Stevens Act.

Essential fish habitat definition: “...those waters and substrate necessary to fish for 

spawning, breeding, feeding, or growth to maturity. For the purpose of interpreting the

definition of essential fish habitat: ‘Waters’ include aquatic areas and their associated 

physical, chemical, and biological properties that are used by fish and may include aquatic 

areas historically used by fish where appropriate; ‘substrate’ includes sediment, hard

bottom, structures underlying the waters, and associated biological communities; ‘necessary’

means the habitat required to support a sustainable fishery and the managed species'

contribution to a healthy ecosystem; and ‘spawning, breeding, feeding, or growth to

maturity’ covers a species' full life cycle” (50 CFR Part 600.10).

Adverse effect definition: “...any impact that reduces quality and/or quantity of EFH.

Adverse effects may include direct or indirect physical, chemical, or biological alterations of 

the waters or substrate and loss of, or injury to, benthic organisms, prey species and their 

habitat, and other ecosystem components, if such modifications reduce the quality and/or

quantity of EFH. Adverse effects to EFH may result from actions occurring within EFH or 

outside of EFH and may include site‐specific or habitat‐ wide impacts, including individual,

cumulative, or synergistic consequences of actions” (50 CFR Part 600.810).

Federal action requirement: “For any Federal action that may adversely affect EFH,

Federal agencies must provide National Marine Fisheries Service with a written 

assessment of the effects of that action on EFH.... Federal agencies may incorporate an

EFH Assessment into documents prepared for other purposes such as...the National 
2 

Environmental Policy Act” (50 CFR Part 600.920).

In 1997, the National Marine Fisheries Service issued an interim final rule to implement 

the essential fish habitat provisions of the Magnuson‐Stevens Act (62 FR 66531). This 

included the clarification that Regional Fishery Management Councils would describe and 

identify essential fish habitat in fishery management plans. In Alaska, fishery

management plans are developed by the North Pacific Fishery Management Council and

approved by Secretary of Commerce. In 2002, National Marine Fisheries Service issued a 

final rule with no substantial changes to the interim rule (67 FR 2343).

Arctic Essential Fish Habitat 

Fish species with essential fish habitat designated in and near the NPR‐A include all five

species of Pacific salmon [chum (Oncorhynchus keta), pink (O. gorbuscha), Chinook (O.

tshawytscha), coho (O. kisutch), and sockeye (O. nerka)], Arctic cod (Boregogadus saida), and

saffron cod (Eleginus gracilis). Of these, only the Pacific salmon occur in and near the project 

study area. Salmon are managed under the “Fishery Management Plan for the Salmon 

Fisheries in the EEZ off the Coast of Alaska” (Salmon Fishery Management Plan; North

Pacific Fishery Management Council 1990).

All of the salmon species have anadromous life histories that are described broadly in Table 

1 according to Mecklenburg et al. (2002). For more detailed information on each species, see 

Groot and Margolis (1991).

Table 1. Pacific salmon life history characteristics

Species Spawning habitat Migration to sea from 

spawning habitat

Time at sea

Chum salmon Freshwater Immediately 3 to 5 years

Pink salmon Freshwater

zone

or intertidal Immediately 18 months

Chinook salmon Freshwater 3 months to 2 years 1 to 5 years

Coho salmon Freshwater 1 to 4 years 2 to 3 years

Sockeye salmon Freshwater (lakes) 1 to 2 years 1 to 4 years

In the northeast Chukchi Sea and western Beaufort Sea, all five species of Pacific salmon 

have been reported (Craig and Haldorson 1986). However, salmon have a very difficult 

time establishing sustainable runs in the Arctic, most likely because of marginal
3 

freshwater habitats (Craig 1989a). Pink and chum salmon occur in the greatest numbers.

Although the number of actual spawning stocks (versus probable stray runs) is unknown,

they are relatively common in the Chukchi Sea and Beaufort Sea (Moss et al. 2009).

Chinook salmon are much more uncommon in the NPR‐A and its coastal waters and

sockeye and coho salmon are rare. Due to the colder temperatures in the Beaufort Sea, 

these salmon species are more likely to be present in the northeast Chukchi Sea, although

captures anywhere north of Point Hope are most commonly limited to only one or a few 

individuals (Craig and Haldorson 1986). In 17 years of summer coastal sampling in the 

Prudhoe Bay region of the Beaufort Sea (1981−1997), only one king salmon and zero

sockeye or coho salmon were captured (BLM 2012, Appendix D, p. 66).

The most current essential fish habitat descriptions for salmon in the Arctic are included in 

amendments 7 and 8 to the Salmon Fishery Management Plan (North Pacific Fishery

Management Council 2006), which implemented the preferred alternative from the

“Environmental Impact Statement for Essential Fish Habitat Identification and

Conservation in Alaska” (National Marine Fisheries Service 2005). This describes essential 

fish habitat that encompasses all life history stages for all Pacific salmon species as marine 

waters extending to the outer limit of the U.S. Exclusive Economic Zone, estuarine waters

extending to the salinity transition zone, and freshwaters that are identified as being used by

salmon in Alaska Department of Fish and Game’s “Catalogue of Waters Important for the

Spawning, Rearing, or Migration of Anadromous Fishes” (Alaska Department of Fish and

Game 2011), also known as the “Anadromous Waters Catalog.” The outer limit of the U.S.

Exclusive Economic Zone is 200 nautical miles; for analysis purposes here, the salinity 

transition zone is considered to be 10 kilometers offshore, as this is typically the greatest

extent of the estuarine band that forms along the coast of the Beaufort Sea during the 

summer (Craig 1984a); and a more recent version of freshwaters documented as being

utilized by salmon is available in the current electronic version of the Anadromous Waters 

Catalog (ADF&G 2017). These essential fish habitat designations for salmon are shown on 

Map 3.3-5. Table 2 lists the stream and river systems with essential fish habitat in the

project study area.
4 

Table 2. Stream and river systems in the GMT2 project area with freshwater essential fish 

habitat based on the Anadromous Waters Catalog

Stream system AWC Code Salmon species utilizing

Colville River 330-00-10700 pink, chum

Fish Creek 330-00-10840 pink, chum, Chinook

Ublutuoch River 330-00-10840-2017 pink, chum, Chinook

Source: Alaska Department of Fish and Game (2017) 

Proposed Action and Alternatives

The BLM is undertaking the GMT2 Supplemental Environmental Impact Statement

(SEIS) to determine the appropriate management decisions for allowing the applicant

to construct and operate an oil production infrastructure in the project study area. The

BLM will consider the best management practices, while providing special protections 

for specific habitats and site‐specific resources and uses.

Potential Adverse Effects on Essential Fish Habitat

The potential adverse effects on essential fish habitat from the GMT2 project 

alternatives would be the same as those described for other fish habitat in Section 4.3.2.

No effects on marine or estuarine essential fish habitat would be expected. Potential 

effects on freshwater essential fish habitat from a variety of oil and gas activities 

described in detail in Section 4.6.7.2 broadly include altered water quality, physical 

habitat changes (water quantity, flow patterns, and geomorphology), increased

turbidity and sedimentation, and barriers to fish movements. The primary difference

among alternatives is the type, amount, and location of impacts that have the potential

to affect fish populations. Based on the proximity to and the potential for impacts to

waters listed for salmon in the Anadromous Waters Catalog, the greatest potential

impacts to freshwater essential fish habitat are expected to occur under Alternatives A

and B (primarily due to potential impacts during the open water season from roads),

less risk under Alternative C.

Proposed Mitigation Measures 

Lease stipulations and best management practices would mitigate potential effects on 

essential fish habitat. Proper implementation of these protective measures should
5 

ensure that impacts to essential fish habitat are avoided or minimized. The following 

list summarizes the mitigation measures. These management standards largely 

address relevant comparable Recommended Conservation Measures identified in 

“Impacts to Essential Fish Habitat from Non‐fishing Activities in Alaska” (National 

Marine Fisheries Service 2011).

• Best Management Practice A‐2: Requires comprehensive waste management plan.

• Best Management Practice A‐3: Requires a hazardous materials emergency

contingency plan.

• Best Management Practice A‐4: Requires a comprehensive spill prevention 

and response contingency plan.

• Best Management Practice A‐5: Establishes refueling setbacks from waterbodies. 

• Best Management Practice A‐6: Prohibits discharge of reserve‐pit fluids.

• Best Management Practice A‐7: Prohibits discharge of produced water in 

upland areas and marine waters.

• Best Management Practice B‐1: Prohibits water withdrawals from rivers and

streams during winter.

• Best Management Practice B‐2: Establishes lake water withdrawal limits and

practices to protect fish.

• Best Management Practice C‐2: Requires sufficient ground frost and snow cover 

prior to winter overland moves, contributing to the protection of stream banks

and frozen waterbodies. 

• Best Management Practice C‐3: Establishes winter river and stream crossing

guidelines related to protecting runoff patterns, fish passage, and natural

channel characteristics, including the requirement that crossings reinforced with

additional snow or ice ("bridges") be removed, breached, or slotted before spring

breakup.

• Best Management Practice C‐4: Establishes winter river and stream crossing

guidelines related to avoiding additional freeze‐down into fish habitat, including

restrictions on traveling up and down streambeds.

• Lease Stipulation D‐1: Prohibits exploratory drilling within the floodplain of 

rivers and streams and within fish‐bearing lakes.

• Lease Stipulation D‐2: Prohibits construction of permanent or gravel facilities 

(including pads, roads, and airstrips) for exploratory drilling.

• Best Management Practice E‐1: Requires that all roads be designed,

constructed, maintained, and operated in a manner that minimizes

environmental impacts.

• Lease Stipulation E‐2: Prohibits permanent facilities (including pads, roads,

airstrips, and pipelines) within 500 feet of fish‐bearing waterbodies, except for

essential road and pipeline crossings that will be permitted on a case‐by‐case

basis.

• Lease Stipulation E‐3: Prohibits causeways, docks, artificial gravel islands, and

bottom‐founded structures in river mouths or deltas. Requires that the design of 

any coastal structure ensures free fish passage and doesn't cause significant

changes to nearshore oceanographic circulation patterns and water quality

characteristics.

• Best Management Practice E‐4: Requires that pipelines be designed, constructed,
6 

and operated according to the best available technology for detecting and 

preventing corrosion that can lead to leaks. 

• Best Management Practice E‐5: Establishes guidelines to minimize the 

development footprint, which would minimize the total impervious surface area 

within individual drainages.

• Best Management Practice E‐6: Requires that stream and marsh crossings be

designed and constructed to ensure free fish passage, reduce erosion, 

maintain natural drainage, and minimize effects to natural stream flow.

• Best Management Practice E‐8: Establishes gravel mine guidelines for design that

will minimize negative effects on fish habitat and for reclamation that will promote

potential positive effects on fish habitat.

• Best Management Practice E‐14: Requires that stream and river road crossings 

utilize the most current design tools that will facilitate free fish passage,

including a minimal of 3 years of hydrology and fish data to guide decisions. 

• Lease Stipulation/Best Management Practice K‐1: Establishes setback distances

for permanent facilities (including pads, roads, airstrips, and pipelines) of 0.5 mile, 

0.75 mile, 1 mile, and, under Alternative B‐1 and B‐2, 2 miles from many major

streams and rivers, except for essential road and pipeline crossings that will be

permitted on a case‐by‐case basis.

• Lease Stipulation/Best Management Practice K‐3b: Establishes additional

protective measurements for "major coastal waterbodies" regarding

exploration and development.

Essential Fish Habitat Finding 

No marine or estuarine essential fish habitat impacts are probable based on the scope of 

the proposed action. The multitude of required operating procedures/best management 

practices listed above would provide substantial environmental protections that would

minimize or avoid effects on freshwater essential fish habitat. Although unavoidable

impacts will occur to some freshwater habitat in the project study area, those streams

and rivers with freshwater essential fish habitat are much less likely to experience those 

impacts. For example, all streams and rivers currently considered freshwater essential 

fish habitat (Table 2 above) are provided an additional safeguard through infrastructure 

setbacks included in Lease Stipulation/Best Management Practice K‐1. Also, since

streams and rivers comprising freshwater essential fish habitat are listed within the 

Anadromous Waters Catalog, they are granted further regulatory protection under the

Anadromous Fish Act (AS 16.05.871) which requires additional review and permitting of 

activities by Alaska Department of Fish and Game. Based on these considerations, oil 

and gas exploration and development in the NPR‐A is assigned the essential fish habitat

assessment determination: “May affect, not likely to adversely affect”. 
7 

EFH References

Alaska Department of Fish and Game (ADF&G). 2017. Anadromous waters catalog. 

Alaska Department of Fish and Game, Division of Sport Fish. Online address: 

http://extra.sf.adfg.state.ak.us/FishResourceMonitor/?mode=awc. 

Craig, P.C. and L. Haldorson. 1981. Beaufort Sea Barrier Island‐Lagoon Ecological 

Process Studies: Final Report, Simpson Lagoon. Part 4 In Environmental

Assessment of the Alaskan Continental Shelf. Final Report, Volume 7. Bureau

of Land Management and National Oceanic and Atmospheric Administration, 

Outer Continental Shelf Environmental Assessment Program.

Craig, P.C. 1984a. Fish Use of Coastal Waters of the Alaskan Beaufort Sea: A Review. 

Transactions of the American Fisheries Society 113:265‐282.

Craig, P.C. and L. Haldorson. 1986. Pacific Salmon in the North American Arctic. Arctic

39:2‐7.

Fechhelm, R.G.. 1989a. An Introduction to Anadromous Fishes in the Alaskan Arctic.

Biological Papers of the University of Alaska 24:27‐54.

Groot, C. and L. Margolis. 1991. Pacific Salmon Life Histories. University of Washington

Press.

Mecklenburg, C.W., T.A. Mecklenburg, and L.K. Thorsteinson. 2002. Fishes of Alaska.

American Fisheries Society, Bethesda, Maryland.

Moss, J.H., J.M. Murphy, E.V. Farley, L.B. Eisner, and A.G. Andrews. 2009. Juvenile 

Pink and Chum Salmon Distribution, Diet, and Growth in the Northern 

Bering and Chukchi seas. North Pacific Anadromous Fish Commission 

Bulletin 5: 191–196.

National Marine Fisheries Service (NMFS). 2005. Final Environmental Impact

Statement for Essential Fish Habitat Identification and Conservation in Alaska.

U.S. DOC, National Marine Fisheries Service, Alaska Region.

National Marine Fisheries Service (NMFS). 2011. Impacts to Essential Fish Habitat

from Non‐fishing Activities in Alaska. Public Review Draft, February 2011.

National Marine Fisheries Service, Alaska Region.

North Pacific Fishery Management Council (NPFMC). 2006. Amendments 7 and 8 to

the Fishery Management Plan for the Salmon Fisheries in the EEZ off the

Coast of Alaska. U.S. Department of Commerce, National Oceanic and

Atmospheric Administration, National Marine Fisheries Service ‐ Alaska

Region, North Pacific Fishery Management Council, Anchorage, AK.
Appendices  Final Supplemental Environmental Impact Statement

Alpine Satellite Development Plan for the Proposed Greater Mooses Tooth 2 Development Project

APPENDIX F

OVERVIEW OF NUIQSUT SUBSISTENCE USES

Greater Mooses Tooth 2 Development 

Supplemental Environmental Impact Statement

Subsistence 

APPENDIX F: 

Overview of Nuiqsut Subsistence Uses

Prepared for

U.S. Department of the Interior 

Bureau of Land Management - Alaska

222 University Ave. 

Fairbanks, Alaska 99709 

Prepared by

Stephen R. Braund & Associates 

P.O. Box 10-1480 

Anchorage, Alaska 99510-1480 

907-276-8222 

907-276-6117 (fax) 

info@srbak.com

May 16, 2017 

Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

i 

TABLE OF CONTENTS

CHAPTER 1: Introduction ........................................................................................................................... 1

CHAPTER 2: Nuiqsut Overview ................................................................................................................. 2

2.1 Subsistence Use Areas .................................................................................................................. 3

2.2 Harvest Data ................................................................................................................................ 15

2.3 Seasonal Round ........................................................................................................................... 24

2.4 References ................................................................................................................................... 26

LIST OF TABLES

Table F-1: Nuiqsut Subsistence Harvest Estimates by Resource Category, All Resources Study Years ... 16

Table F-2: Nuiqsut Subsistence Harvest Estimates by Selected Species, All Study Years ........................ 19

Table F-3: Nuiqsut Annual Cycle of Subsistence Activities ...................................................................... 25

LIST OF FIGURES

Figure F-1: Nuiqsut Subsistence Use Areas, All Resources ......................................................................... 4

Figure F-2: Nuiqsut Subsistence Use Areas, Caribou ................................................................................... 6

Figure F-3: Nuiqsut Subsistence Use Areas, Moose ..................................................................................... 7

Figure F-4: Nuiqsut Subsistence Use Areas, Other Large Land Mammals .................................................. 8

Figure F-5: Nuiqsut Subsistence Use Areas, Furbearers and Small Land Mammals ................................... 9

Figure F-6: Nuiqsut Subsistence Use Areas, Fish ....................................................................................... 11

Figure F-7: Nuiqsut Subsistence Use Areas, Birds ..................................................................................... 12

Figure F-8: Nuiqsut Subsistence Use Areas, Vegetation ............................................................................ 13

Figure F-9: Nuiqsut Subsistence Use Areas, Marine Mammals ................................................................. 14

ACRONYMS

ANCSA - Alaska Native Claims Settlement Act

ATV - All terrain vehicle 

GMT2 - Greater Mooses Tooth 2 

IAI - Impact Assessment, Inc.

ISER - Institute of Social and Economic Research

NSB - North Slope Borough 

SRB&A - Stephen R. Braund & Associates
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

ii 
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

1 

CHAPTER 1: INTRODUCTION

The proposed Greater Mooses Tooth 2 (GMT2) Development is located in the North Slope 

region, a geographical area that extends north of the Brooks Range in Alaska to the Beaufort Sea. 

The North Slope environment includes the Brooks Range, Arctic Foothills, and Arctic Coastal 

Plain eco-regions. The GMT2 Project area is located in the Arctic Coastal Plain, which consist of 

flat tundra environment with poor drainage and numerous lakes (Gallant et al. 1995). This region 

is characterized by low mean annual temperatures and precipitation. 

At the time of European contact, the North Slope was inhabited by indigenous Iñupiat 

populations, which were comprised of two primary cultural groups. The Tagiugmiut inhabited 

coastal areas of the Arctic Coastal Plain and the Nunamiut inhabited the interior including the 

Brooks Range and Arctic Foothills areas. Iñupiaq is the language spoken by both North Slope 

cultural groups as well as in other areas of Alaska (including Northwestern Alaska and the 

Seward Peninsula) and Canada (known as Inuktitut). Coastal Iñupiat (Tagiugmiut) relied 

primarily on harvests of marine mammals, terrestrial mammals, and fish, while their inland 

neighbors, the Nunamiut, relied mostly on terrestrial mammals and fish, with caribou comprising 

the majority of their subsistence harvests.

Iñupiat are still the primary occupants of the North Slope today and continue the hunting and 

harvesting traditions of their ancestors. Local residents often harvest subsistence resources from 

specific camps that are situated in locations that provide multiple resource harvest opportunities 

throughout the year. Harvest activities tend to occur near communities, along rivers and 

coastlines, or at particularly productive sites where resources are known to occur seasonally. 

Traditional knowledge concerning the distribution, migration, seasonal variation of animal 

populations, and other environmental factors (e.g., tides, currents, ice, and snow conditions), is 

often used when determining what, where, and when a subsistence resource will be harvested. 

While some harvest locations may be used infrequently, they can still be important to a 

subsistence user or a community if they are particularly productive areas or if they have cultural, 

historical, or familial significance to the user. Prior to the 1950s, when mandatory school 

attendance and economic factors such as a decline in fur prices compelled families to 

permanently settle in one of the few centralized communities, the Iñupiat were highly mobile and 

ranged over large geographic areas for trapping, fishing, gathering, and hunting activities. 

Contemporary subsistence use areas include many of these traditional use areas. The advent of 

snowmachines and all-terrain vehicles (ATVs) including four-wheelers has reduced the time 

required to travel to traditional hunting and harvesting areas, but has also increased the need for 

cash employment to purchase, maintain, and procure supplies for the new equipment 

(Ahtuangaruak 1997, Impact Assessment Inc. [IAI] 1990a, b, Stephen R. Braund & Associates 

[SRB&A] and Institute of Social and Economic Research [ISER] 1993, Worl and Smythe 1986). 

The nomadic land use patterns once typical of North Slope Iñupiat evolved to the use of base 

camps consisting of tent platforms, cabins, and/or caches located near productive resource bases. 

While the use of camps and cabins continues, the community of Nuiqsut has, in more recent 

years, become a base from which many residents conduct same-day subsistence activities (IAI

1990b, SRB&A 2010a, SRB&A 2018). The following section provides a brief introduction of 
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

2 

Nuiqsut, followed by a description of their subsistence use areas, harvest data, and seasonal 

round data as available.

CHAPTER 2: NUIQSUT OVERVIEW 

Nuiqsut is located on the Colville River, approximately 35 miles upstream from the Beaufort 

Sea, in an area that provides abundant fishing, hunting, birding, and gathering opportunities. 

Although the location is less advantageous for marine mammal harvests, residents regularly 

travel to the ocean to harvest them. The Colville River is the largest river system on the North 

Slope and supports the largest overwintering areas for whitefish, which local residents harvest in 

substantial quantities (Craig 1987; Seigle et al. 2016). 

The Nuiqsut area was formerly a place where Iñupiat and Athabascan people gathered to trade 

and fish, maintaining connections between the Nunamiut of the inland areas and the Tagiugmiut 

of the coast (Brown 1979). After the passage of the Alaska Native Claims Settlement Act 

(ANCSA), 27 Iñupiat families from Barrow resettled at Nuiqsut to live a more traditional 

lifestyle and to reconnect with familial ties to the area (IAI 1990a). Easy access to the main 

channel of the Colville River for fishing and hunting and for ease of movement between upriver 

hunting sites and downriver whaling and sealing sites was the primary reason for selection of the 

site (Brown 1979). 

Since its resettlement, Nuiqsut has grown to a population of 449 residents living in 138 

households (North Slope Borough [NSB] 2015). Primary sources of employment in the 

community include the village corporation (Kuukpik Corporation), the North Slope Borough 

(NSB), and the NSB school district (NSB 2017). Nuiqsut is one of 11 Alaska Eskimo bowhead 

whaling communities. It is the closest community to the major oil producing fields of the North 

Slope, which has impacted local subsistence activities (Fuller and George 1999, IAI 1990a, 

Pedersen et al. 2000), jobs, corporate dividends, and local revenue.
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

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2.1 Subsistence Use Areas 

Figure F-1 depicts Nuiqsut all resources subsistence use areas for multiple time periods, as 

documented by Pedersen (1979, 1986), BLM (2004), SRB&A (2010a), and Brown et al. (2016). 

Pedersen’s (1979) lifetime (pre-1979) use areas show Nuiqsut residents utilizing a large area 

centered on the community to harvest subsistence resources; reported use areas extended 

offshore approximately 15 miles, as far east as Camden Bay, south along the Itkillik River, and 

west as far as Teshekpuk Lake. Subsequent use area data shows Nuiqsut residents traveling 

across a progressively larger area to harvest subsistence resources. SRB&A’s (2010a) use areas 

(1995-2006) document Nuiqsut residents traveling beyond Atqasuk in the west, offshore more 

than 50 miles northeast of Cross Island, overland to Cape Halkett and Barrow in the north, to 

Camden Bay in the east, and beyond the Colville River in the south. The majority of Nuiqsut 

1995-2006 use areas are concentrated around the Colville River, overland areas to the southwest 

of the community, offshore areas north of the Colville River delta, and northeast of Cross Island. 

Pedersen (1986) and SRB&A (2003) use areas for Nuiqsut are all within the extent of Pedersen 

(1979) and SRB&A (2010a) use areas described above with the exception of extending as far as 

Kaktovik in the east and along the Anaktuvuk River as far as Anaktuvuk Pass to the south. 

SRB&A (2010a) notes that wolf and wolverine use areas continued farther south toward 

Anaktuvuk Pass but were not documented due to the size of the map used during interviews. Use 

areas documented by ADF&G for the 2014 study year (Brown et al. 2016) show use areas 

occurring within those documented by SRB&A (2010a) but with overland areas extending 

farther south to Anaktuvuk Pass. Nuiqsut all resources use areas from all available studies 

(Pedersen 1979, Pedersen 1986, SRB&A 2003, SRB&A 2010a, and Brown et al. 2016) overlap 

with large portions of the project study area. 
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

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Figure F-1: Nuiqsut Subsistence Use Areas, All Resources
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

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Nuiqsut subsistence use area maps organized by resource are shown on Figure F-2 through 

Figure F-9 for the lifetime (pre-1979), 1973-1986, 1994-2003, 1995-2006, 2008-2016, and 2014 

time periods. Nuiqsut subsistence use areas for large land mammals are shown on Figure F-2

through Figure F-4. Nuiqsut caribou use areas are shown on Figure F-2 and include use areas 

documented by Pedersen (1979), Pedersen (1986), BLM (2004), SRB&A (2010a), Brown et al. 

(2016), and nine years of caribou monitoring studies summarized most recently in SRB&A 2018. 

As indicated on the map, areas consistently used by Nuiqsut residents for caribou hunting occur 

in an overland area between the Ikpikpuk and Kuparuk Rivers, north to the coast, and south 

along the Colville River. The maximum extent of their use areas documented between all the 

studies extends from Atqasuk in the west towards Point Thomson in the east and south along the 

Colville and Anaktuvuk Rivers to Anaktuvuk Pass. SRB&A’s (2010a) overlapping use areas 

show the greatest number of caribou use areas are concentrated along the Colville River and 

delta, along the Itkillik River, and overland to the west and south of the community; these areas 

correspond to the caribou hunting areas reported during the 2008 through 2016 study years 

(SRB&A 2018). 

Nuiqsut moose use areas (Figure F-3) as documented by Pedersen (1979, 1986), BLM (2004) 

SRB&A (2010a), and Brown et al. (2016) show residents’ consistent use of areas adjacent to the 

Colville River for moose harvests. While lifetime (pre-1979) use areas were completely confined 

to the Colville River, more recent moose use areas for the 1973-1986, 1994-2003, and 1995-

2006 time periods have expanded to include other tributaries including the Chandler and 

Anaktuvuk Rivers and Fish Creek. The most recent 2014 moose use areas were confined to the 

Colville and Itkillik Rivers in that particular study year. The 1995-2006 moose use areas show 

the highest amount of overlap along the Colville River south of Nuiqsut as far as Umiat. 

Figure F-4 depicts Nuiqsut use areas for grizzly bear as documented by Pedersen (1979, 1986). 

Use areas for grizzly bear for the lifetime and 1973-1986 time periods include areas along the 

Colville River watershed from Fish Creek to Umiat. 

Nuiqsut small land mammal use areas are shown on Figure F-5 for the lifetime, 1973-1986, 

1994-2003, 1995-2006, and 2014 time periods. Lifetime (pre-1979) use areas documented by 

Pedersen (1979) showed residents using overland areas near the community, as well as the more 

southern Colville, Chandler, Anaktuvuk, Itkillik, and Kuparuk Rivers to harvest small land 

mammals. Pedersen’s (1986) furbearer and small land mammal use areas for the 1973-1986 time 

period expanded from previously recorded use areas to the west beyond the Ikpikpuk River and 

south to Anaktuvuk Pass. SRB&A’s (2010a) wolf and wolverine use areas for the 1995-2006 

time period indicate a farther expansion of use areas to the Meade River in the west and beyond 

the Dalton Highway in the east, including an eastward area reaching to just south of Kaktovik. 

Small land mammal use areas for 2014 from the most recent Brown et al. (2016) study indicated 

fewer use areas extending as far east and west of the community and an expansion of use areas 

into the Brooks Range. 
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

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Figure F-2: Nuiqsut Subsistence Use Areas, Caribou
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

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Figure F-3: Nuiqsut Subsistence Use Areas, Moose
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

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Figure F-4: Nuiqsut Subsistence Use Areas, Other Large Land Mammals
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

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Figure F-5: Nuiqsut Subsistence Use Areas, Furbearers and Small Land Mammals
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

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Nuiqsut lifetime (1973-1986 and pre-1979) and more contemporary (1994-2003, 1995-2006, 

2014) fishing areas are shown on Figure F-6. These use areas indicate consistent use of the 

Colville River and smaller tributaries including the Itkillik, Chandler, and Anaktuvuk Rivers as 

well as Fish and Judy creeks. Contemporary use areas extend somewhat father along the Colville 

and Itkillik Rivers as well as along Fish Creek. 

Nuiqsut use areas for birds (Figure F-7) are mostly concentrated along the Colville River and 

nearby overland areas for the lifetime (pre-1979), 1973-1986, 1994-2003, 1995-2006, and 2014 

time periods, though they also include offshore eider hunting areas extending from Cape Halkett 

to Camden Bay. Lifetime (pre-1979) wildfowl use areas include areas near the Colville River 

and near-shore locations extending east to Prudhoe Bay. More recent use areas for geese and 

eider for the 1994-2003 and 1995-2006 time period expanded previously recorded bird use areas 

to include areas offshore and east of Prudhoe Bay to Camden Bay. The 2014 bird use areas were 

primarily concentrated north of the community and offshore into Harrison Bay.

Figure F-8 displays Nuiqsut use areas for vegetation for the 1973-1986, 1994-2003, and 2014 

time periods. These studies document use of the Colville River as far as Umiat and areas near 

Fish Creek for harvests of vegetation and berries. BLM (2004) also documented berry gathering 

areas along the Itkillik, Chandler, and Anaktuvuk Rivers. 

Nuiqsut subsistence use areas for marine mammals are shown on Figure F-9. Nuiqsut marine 

mammal use areas are depicted for the lifetime (pre-1979), 1973-1986, 1994-2003 (seal only), 

1995-2006, and 2014 time periods. Lifetime Nuiqsut use areas for marine mammals included 

offshore areas from Atigaru Point to Kaktovik at distances of less than 20 miles; subsequent 

studies documented use areas extending to Cape Halkett in the west and varying distances to the 

east. SRB&A’s (2010a) use areas showed Nuiqsut residents harvesting marine mammals up to 

40 miles offshore to the north of the community and even farther offshore (approximately 60 

miles) in an area near Cross Island, a sandy barrier island used traditionally and currently as a 

base of operations for Nuiqsut whaling crews. Galginaitis (2009a, 2009b, and 2010) documented 

Cross Island bowhead whaling tracks from 2001-2009. These tracks were recorded by 

participating whaling crews using Geographic Positioning System (GPS) units for an ongoing 

MMS funded subsistence bowhead whaling study and represent actual boat hunting routes taken 

by whaling crews during each study year. Nuiqsut 2001-2009 bowhead whale hunting GPS 

tracks extend as far east as Flaxman Island and over 30 miles offshore from Cross Island. The 

2014 marine mammal use areas were concentrated in the areas of highest overlap documented by 

SRB&A (2010a). Polar bear use areas for the 1973-1986 time period were documented in the 

Colville River delta and offshore areas extending east to Cross and Tigvariak islands. 
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

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Figure F-6: Nuiqsut Subsistence Use Areas, Fish
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

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Figure F-7: Nuiqsut Subsistence Use Areas, Birds
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

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Figure F-8: Nuiqsut Subsistence Use Areas, Vegetation
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

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Figure F-9: Nuiqsut Subsistence Use Areas, Marine Mammals
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

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2.2 Harvest Data

Table F-1 and Table F-2 provide Nuiqsut harvest data for various years between 1985 and 2016. 

Comprehensive (i.e., all resources) study years are available for 1985, 1992, 1993, 1994-1995, 

1995-1996, 2000-2001, and 2014 (Table F-1, Table F-2). Twelve study years include data solely 

for caribou harvests (Braem et al. 2011, SRB&A 2012-2018) (Table F-2). 

During years with per capita harvest data, Nuiqsut households harvested between 399 in 1985 (a 

year when the community did not successfully harvest a bowhead whale) and 896 in 2014 

pounds of subsistence resources per capita (Table F-1). Land mammals, marine mammals, and 

fish are all major subsistence resources in Nuiqsut. Table F-1 shows that marine mammals 

contributed more total edible pounds during four comprehensive study years (1992, 1995-1996, 

2000-2001, and 2014) than any other resource. Non-salmon fish were the top harvested resource 

during the remaining three study years (1985, 1993, and 1994-1995) and accounted for between 

173 (in 1985) and 248 (in 1993) pounds per capita during years with per capita harvest data. 

Large land mammals were generally the second or third most harvested resource during all study 

years and provided between 169 (in 1985) and 261 (in 2014) pounds per capita. In smaller 

quantities, Nuiqsut residents harvest migratory birds (between 10 and 17 pounds per capita); 

upland game birds (between <1 and 3 pounds per capita); salmon (between 3 and 9 pounds per 

capita); and bird eggs and vegetation (no more than one pound per capita). Small land mammals 

are also harvested, but because they are harvested primarily for their fur, they contribute little in 

the way of edible pounds. 

Specifically, bowhead whales, whitefish (Arctic cisco, or qaaktaq, and broad whitefish), and 

caribou are the primary subsistence species harvested in Nuiqsut. Bowhead whale harvests 

accounted for between 28.7 percent and 60.3 percent of the total harvest during all study years 

(except for 1985 and 1994-1995, when Nuiqsut did not successfully harvest a whale). Arctic 

cisco harvests have accounted for between 1.9 and 14.9 percent of the total harvest, broad 

whitefish have accounted for between 5.3 and 45 percent of the total harvest, and caribou have 

accounted for between 21.7 and 37.5 percent of the total harvest. Other subsistence species with 

substantial contributions to Nuiqsut subsistence harvests include moose, seals, geese, Arctic 

grayling, least cisco, and burbot. 

Household participation data (in terms of percentage of households harvesting) are available for 

four comprehensive study years (1985, 1992, 1993, 2014) and 10 caribou only study years 

(2002-03, 2003-04, 2004-05, 2005-06, 2006-07, 2010-2013, 2015, and 2016). Nuiqsut relies 

heavily on subsistence resources. As shown in Table F-1, 100 percent of households reported 

using subsistence resources in 1985, 1993, and 2014, and over 90 percent of households 

participated in subsistence activities (i.e., attempted to harvest). During all available study years, 

participation in subsistence activities was highest for non-salmon fish, large land mammals, and 

migratory birds. Specifically, in 2014, over half of Nuiqsut households participated in harvests of 

caribou, broad whitefish, white-fronted geese, cloudberries, and Arctic cisco. In 2016, 76 percent 

of households participated in caribou hunting activities. Sharing of subsistence resources is also 

high; 100 percent of households received resources in 1985, 98 percent in 1993, and 97 percent 

in 2014. Sharing of subsistence foods is particularly common with marine mammals (between 95 

and 100 percent of households receiving); large land mammals (between 70 and 92 percent); and 

non-salmon fish (between 71 and 90 percent).
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

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Table F-1: Nuiqsut Subsistence Harvest Estimates by Resource Category, All Resources Study Years

Study 

Year Resource 

Percentage of Households Estimated Harvest

% of Total 

Harvest

Use Try to 

Harvest Harvest Give Receive Number* Total Pounds**

Average 

HH 

Pounds

Per Capita 

Pounds

1985

All Resources 100 98 98 95 100 - 160,035 2,106 399 100.0%

Salmon 60 43 40 23 23 441 1,366 18 3 0.9%

Non-Salmon Fish 100 93 93 83 75 67,712 69,243 911 173 43.3%

Large Land 

Mammals 98 90 90 80 70 536 67,621 890 169 42.3%

Small Land 

Mammals 65 63 58 23 13 688 245 3 1 0.2%

Marine Mammals 100 48 23 30 100 59 13,355 176 33 8.3%

Migratory Birds 90 90 85 60 55 1,733 6,626 87 17 4.1%

Upland Game 

Birds 88 88 88 58 13 1,957 1,370 18 3 0.9%

Bird Eggs 25 25 23 8 10 262 40 1 <1 <0.1%

Vegetation 38 50 18 10 20 - 169 2 <1 0.1%

1992***

All Resources - - - - - - 150,195 - - 100.0%

Salmon - - - - - 6 65 - - 0.0%

Non-Salmon Fish - 74 - - - 36,701 51,890 - - 34.5%

Large Land 

Mammals - - - - - 299 41,386 - - 27.6%

Small Land 

Mammals - - - - - 46 1 - - 0.0%

Marine Mammals - - - - - 49 52,865 - - 35.2%

Migratory Birds - - - - - 1,105 3,655 - - 2.4%

Upland Game 

Birds - - - - - 378 265 - - 0.2%

Eggs - - - - - 25 4 - - <0.1%

Vegetation - 32 - - - - 66 - - <0.1%
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

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Study 

Year Resource 

Percentage of Households Estimated Harvest

% of Total 

Harvest

Use Try to 

Harvest Harvest Give Receive Number* Total Pounds**

Average 

HH 

Pounds

Per Capita 

Pounds

1993

All Resources 100 94 90 92 98 - 267,818 2,943 742 100.0%

Salmon 71 45 36 39 47 272 1,009 11 3 0.4%

Non-Salmon Fish 97 79 79 87 90 71,626 89,481 983 248 33.4%

Large Land 

Mammals 98 76 74 82 92 691 87,306 959 242 32.6%

Small Land 

Mammals 53 45 42 27 18 599 84 1 <1 <0.1%

Marine Mammals 97 58 37 79 97 113 85,216 936 236 31.8%

Migratory Birds 87 74 73 63 65 2,238 3,540 39 10 1.3%

Upland Game 

Birds 60 45 45 42 26 973 681 7 2 0.3%

Eggs 40 21 19 15 23 346 104 1 <1 <0.1%

Vegetation 79 71 71 27 40 - 396 4 1 0.1%

1994-

95****

All Resources - - - - - - 83,228 - - 100.0%

Salmon - - - - - 10 31 - - <0.1%

Non-Salmon Fish - - - - - 15,190 46,569 - - 56.0%

Large Land 

Mammals - - - - - 263 32,686 - - 39.3%

Small Land 

Mammals - - - - - 42 0 - - 0.0%

Marine Mammals - - - - - 25 1,504 - - 1.8%

Migratory Birds - - - - - 569 2,289 - - 2.8%

Upland Game 

Birds - - - - - 58 58 - - 0.1%

Vegetation - - - - - 14 91 - - 0.1%
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

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Study 

Year Resource 

Percentage of Households Estimated Harvest

% of Total 

Harvest

Use Try to 

Harvest Harvest Give Receive Number* Total Pounds**

Average 

HH 

Pounds

Per Capita 

Pounds

1995-96

All Resources - - - - - - 183,576 - - 100.0%

Salmon - - - - - 42 131 - - 0.1%

Non-Salmon 

Fish - - - - - 10,612 16,822 - - 9.2%

Large Land 

Mammals - - - - - 364 43,554 - - 23.7%

Small Land 

Mammals - - - - - 27 0 - - 0.0%

Marine 

Mammals - - - - - 178 120,811 - - 65.8%

Migratory Birds - - - - - 683 2,166 - - 1.2%

Upland Birds - - - - - 19 13 - - <0.1%

Vegetation - - - - - 12 78 - - <0.1%

2000-01

All Resources - - - - - - 183,246 - - 100.0%

Salmon - - - - - 10 75 - - <0.1%

Non-Salmon 

Fish - - - - - 26,545 27,933 - - 15.2%

Large Land 

Mammals - - - - - 504 62,171 - - 33.9%

Small Land 

Mammals - - - - - 108 2 - - <0.1%

Marine 

Mammals - - - - - 31 87,929 - - 48.0%

Migratory Birds - - - - - 1,192 5,108 - - 2.8%

Upland Birds - - - - - 23 16 - - <0.1%

Vegetation - - - - - 2 13 - - <0.1%
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

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Study 

Year Resource

Percentage of Households Estimated Harvest

% of Total 

Harvest

Use Try to 

Harvest Harvest Give Receive Number* Total Pounds**

Average 

HH 

Pounds

Per Capita 

Pounds

2014

All Resources 100 95 90 91 97 - 371,992 3,444 896 100.0%

Salmon 64 41 40 31 35 - 3,889 36 9 1.0%

Non-Salmon 

Fish 93 78 71 72 71 - 85,106 788 205 22.9%

Large Land 

Mammals 91 66 64 67 72 - 108,359 1,003 261 29.1%

Small Land 

Mammals 17 16 10 2 7 - 0 0 0 0.0%

Marine 

Mammals 95 55 40 71 95 - 169,367 1,568 408 45.5%

Migratory Birds 79 71 66 52 38 - 4,742 44 11 1.3%

Upland Birds 16 12 12 9 5 - 78 1 <1 0.0%

Vegetation 67 55 53 21 38 - 414 4 1 0.1%

Notes: *Estimated numbers represent individuals in all cases except vegetation, where they represent gallons.

**Estimated pounds include only edible pounds and therefore do not include estimates for resources that are not typically eaten by community 

residents (e.g., furbearers).

***The estimated pounds of moose harvested in 1992 is likely too high (Fuller and George 1999).

****The 1994-95 study year underrepresents the harvest of Arctic cisco and humpback whitefish (Brower and Hepa 1998); Nuiqsut did not 

successfully harvest a bowhead whale in 1994-95. 

The estimated harvest numbers for the 1994-95, 1995-96 and 2000-01 data were derived by summing individual species in each resource 

category. Also for those study years, total pounds were derived from conversion rates found at ADF&G (2017) and total (usable) pounds for 

bowhead whales were calculated based on the method presented in SRB&A and ISER (1993). These estimates do not account for whale girth and 

should be considered approximate; more exact methods for estimating total whale weights are available in George et al. (n.d.). 

Sources: ADF&G, 2017 (1985); Bacon et al., 2009 (1995-96, 2000-01); Brower and Hepa, 1998 (1994-95); Brown et al., 2016 (2014); Fuller and 

George, 1999 (1992); and Pedersen, 1995 (1993).
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

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Table F-2: Nuiqsut Subsistence Harvest Estimates by Selected Species, All Study Years

Study 

Year Resource*

Percentage of Households Estimated Harvest

% of Total 

Use Harvest

Try to 

Harvest Harvest Give Receive Number**

Total 

Pounds***

Average 

HH 

Pounds

Per Capita 

Pounds

1985

Caribou 98 90 90 80 60 513 60,021 790 150 37.5%

Cisco 98 75 73 65 60 46,478 29,354 386 73 18.3%

Broad Whitefish 95 80 78 70 40 7,900 26,861 353 67 16.8%

Bowhead Whale 100 23 5 8 100 0 7,458 98 19 4.7%

Moose 40 40 18 20 25 13 6,650 88 17 4.2%

White-fronted 

Geese 90 90 85 55 48 1,340 6,028 79 15 3.8%

Arctic Grayling 78 65 63 48 35 4,055 3,650 48 9 2.3%

Humpback 

Whitefish 48 45 38 33 13 4,345 3,476 46 9 2.2%

Arctic Char 75 63 60 33 35 1,060 2,969 39 7 1.9%

Burbot 75 60 60 43 33 669 2,675 35 7 1.7%

Bearded Seal 48 25 15 15 35 15 2,675 35 7 1.7%

Ringed Seal 53 25 18 23 40 40 1,676 22 4 1.0%

1992

Bowhead Whale - - - - - 2 48,715 - - 32.4%

Caribou - 81 - - - 278 32,551 - - 21.7%

Arctic Cisco - - - - - 22,391 22,391 - - 14.9%

Broad Whitefish - - - - - 6,248 15,621 - - 10.4%

Moose**** - - - - - 18 8,835 - - 5.9%

Humpback 

Whitefish - - - - - 1,802 4,504 - - 3.0%

Arctic Char - - - - - 1,544 4,324 - - 2.9%

Bearded Seal - - - - - 16 2,760 - - 1.8%

Arctic Grayling - - - - - 3,114 2,491 - - 1.7%

Canada Geese - - - - - 319 1,437 - - 1.0%
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

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Study 

Year Resource*

Percentage of Households Estimated Harvest

% of Total 

Use Harvest

Try to 

Harvest Harvest Give Receive Number**

Total 

Pounds***

Average 

HH 

Pounds

Per Capita 

Pounds

1993

Caribou 98 74 74 79 79 672 82,169 903 228 30.7%

Bowhead Whale 97 37 5 76 97 3 76,906 845 213 28.7%

Broad Whitefish 90 66 66 65 66 12,193 41,455 456 115 15.5%

Arctic Cisco 89 69 68 81 60 45,237 31,666 348 88 11.8%

Ringed Seal 65 42 31 40 55 98 7,277 80 20 2.7%

Burbot 79 63 57 53 55 1,416 5,949 65 16 2.2%

Moose 69 47 10 29 63 9 4,403 48 12 1.6%

Arctic Grayling 79 69 65 44 27 4,515 4,063 45 11 1.5%

Least Cisco 63 52 47 36 27 6,553 3,277 36 9 1.2%

1994-

95*****

Broad Whitefish - - - - - 3,237 37,417 - - 45.0%

Caribou - - - - - 258 30,186 - - 36.3%

Arctic Cisco - - - - - 9,842 6,889 - - 8.3%

Moose - - - - - 5 2,500 - - 3.0%

Geese 

Unidentified - - - - - 474 2,133 - - 2.6%

Ringed Seal - - - - - 24 1,008 - - 1.2%

1995-96

Bowhead Whale - - - - - 4 110,715 - - 60.3%

Caribou - - - - - 362 42,354 - - 23.1%

Broad Whitefish - - - - - 2,863 9,735 - - 5.3%

Ringed Seal - - - - - 155 6,527 - - 3.6%

Arctic Cisco - - - - - 5,030 3,521 - - 1.9%

Bearded Seal - - - - - 17 2,974 - - 1.6%

Least Cisco - - - - - 1,804 1,804 - - 1.0%

1999-00 Caribou - - - - - 413 - - 112 -
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

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Study 

Year Resource*

Percentage of Households Estimated Harvest

% of Total 

Use Harvest

Try to 

Harvest Harvest Give Receive Number**

Total 

Pounds***

Average 

HH 

Pounds

Per Capita 

Pounds

2000-01

Bowhead Whale - - - - - 4 86,220 - - 47.1%

Caribou - - - - - 496 57,985 - - 31.6%

Arctic Cisco - - - - - 18,222 12,755 - - 7.0%

Broad Whitefish - - - - - 2,968 10,092 - - 5.5%

White-fronted 

Geese - - - - - 787 3,543 - - 1.9%

Moose - - - - - 6 3,000 - - 1.6%

2002-03 Caribou 95 47 45 49 80 397 - - 118 -

2003-04 Caribou 97 74 70 81 81 564 - - 157 -

2004-05 Caribou 99 62 61 81 96 546 - - 147 -

2005-06 Caribou 100 60 59 97 96 363 - - 102 -

2006-07 Caribou 97 77 74 66 69 475 - - 143 -

2010 Caribou 94 86 76 - - 562 65,754 707 - -

2011 Caribou 92 70 56 49 58 437 51,129 544 134 -

2012 Caribou 99 68 62 65 79 501 58,617 598 147 -

2013 Caribou 95 79 63 62 75 586 68,534 692 166 -

2014

Bowhead 93 29 21 57 91 5 148,087 1,371 357 39.8%

Caribou 90 66 64 67 59 774 105,193 974 253 28.3%

Broad Whitefish 72 60 59 52 40 11,439 36,605 339 88 9.8%

Arctic Cisco 83 52 48 59 53 46,277 32,394 300 78 8.7%

Bearded Seal 67 38 22 40 62 13,846 13,846 128 33 3.7%

Least Cisco 33 28 28 19 7 13,332 9,333 86 22 2.5%

Ringed Seal 52 40 35 38 33 108 6,156 57 15 1.7%

2015 Caribou 96 84 78 74 72 628 73,527 728 180 -

2016 Caribou 96 76 67 79 81 481 56,277 592 132 -
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

23

Notes: *This table shows individual species unless they are not available for a given study year.

**Estimated numbers represent individuals in all cases except vegetation, where they represent 

gallons.

***Estimated pounds include only edible pounds and therefore do not include estimates for 

resources that are not typically eaten by community residents (e.g., furbearers). 

 The estimated pounds of moose harvested in 1992 is likely too high (Fuller and George, 

1999).

** ***The 1994-95 study year underrepresents the harvest of Arctic cisco and humpback 

whitefish (Brower and Hepa 1998); Nuiqsut did not successfully harvest a bowhead whale in 

1994-95.

For All Resources study years (1985, 1992, 1993, 1994-95, 1995-96, 2000-01), species are 

listed in descending order by percent of total harvest and are limited to species accounting for at 

least 1.0 percent of the total harvest; for single-resource study years, species are listed in 

descending order by total estimated pounds (or total number harvested, in the case of salmon 

study years) and limited to the five top species. Years lacking "% of total harvest" data were not 

comprehensive (i.e., all resources) study years. 

The estimated harvest numbers for the 1992, 1994-95, 1995-96 and 2000-01 data were derived 

by summing individual species in each resource category. Also for those study years, total 

pounds were derived from conversion rates found at ADF&G (2017) and total (usable) pounds 

for bowhead whales were calculated based on the method presented in SRB&A and ISER 

(1993). These estimates do not account for whale girth and should be considered approximate; 

more exact methods for estimating total whale weights are available in George et al. (n.d.). For 

the 2002-2003, 2003-2004, 2004-2005, 2005-2006, 2006-2007, 2010, and 2011 study years, 

total pounds were derived from conversion rates from Braem et al. (2011).

Sources: ADF&G, 2017 (1985); Bacon et al., 2009 (1995-96, 2000-01); Braem et al., 2011 

(1999-00; 2002-2007); Brower and Hepa, 1998 (1994-95); Brown et al., 2016 (2014); Fuller and 

George, 1999 (1992), Pedersen, 1995 (1993); and SRB&A, 2012, 2013, 2014, 2015, 2016, 

2017, 2018 (2010-2013, 2015-2016).
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

24

2.3 Seasonal Round

Table F-3 provides seasonal round data based on reports from the 1970s through the 2010s. The 

spring month of April marks a transition from the late winter/early spring harvesting of 

furbearers, seals (through the ice), and upland game birds (ptarmigan) to the spring waterfowl 

hunting season which peaks in May and June. Some residents also harvest geese eggs after the 

birds begin nesting in June. Beginning as early as May (depending on the timing of breakup), 

residents travel by boat along the local river system and into the Beaufort Sea to harvest various 

resources including caribou, waterfowl, seals, and fish. 

Caribou harvests occur throughout the year, but with the most intensity during the summer 

months of July and August. During this time, residents also set nets for broad whitefish in local 

river systems or harvest fish such as Arctic grayling and Dolly Varden with rod and reel, often 

while hunting caribou along the Colville River. In addition to traveling along the Colville River 

during the summer for fishing and caribou hunting, residents continue to travel to the ocean to 

hunt for ringed seals, bearded seals, and king and common eiders throughout the summer months 

(SRB&A 2010a). Berry and plant gathering also occur during the summer, primarily in July and 

August. 

As summer turns to fall (August/September), some residents shift their focus to moose hunting 

upriver, which often takes place alongside caribou hunting. Summer rod and reel harvests of 

non-salmon fish, particularly Arctic grayling, continue into the fall as well. Bowhead whaling 

occurs in September when whaling crews are stationed at Cross Island, with preparations for the 

whaling season beginning in August. Nuiqsut hunters harvest few polar bears, but if they are 

harvested it is often during or after the fall whaling season. The fall months of October and 

November are spent fishing and harvesting caribou close to the community, often by fourwheeler or snowmachine. The Arctic cisco fishery may begin as early as September but is most 

productive between October and mid-November when the fish are running upriver and residents 

harvest them in the Colville Delta with gillnets. Other fish, including humpback whitefish, broad 

whitefish, and least cisco are caught incidentally during this time. 

During the winter and early spring months (primarily December through April), furbearer 

hunters pursue wolves and wolverines, target caribou and ptarmigan as needed and available, and 

fish for burbot through the ice. Overall, Nuiqsut harvesters target the highest numbers of 

resources during the summer/fall months of August and September. 
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

25

Table F-3: Nuiqsut Annual Cycle of Subsistence Activities

Resources Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Freshwater 

Non-Salmon Moderate Limited Moderate Moderate Limited Limited Moderate High High High High Limited

Marine 

Non-Salmon None None None None None None None None High High None None

Salmon None None None None None None High Moderate None None None None

Caribou Limited Limited Limited Limited Limited Moderate High High Moderate Moderate Limited Limited

Moose Limited None None None None None Limited High High Moderate Limited Limited

Bear Moderate Moderate Moderate Limited Limited Limited Limited Limited High Moderate Moderate Moderate

Muskox None None None None None None None High High High None None

Furbearers High High High High Moderate Limited Limited Limited Limited Limited Moderate High

Small Land 

Mammals None None None None Limited Limited High High Limited None None None

Marine 

Mammals None None Moderate High Limited Limited Moderate High High Limited Limited Limited

Upland 

Birds Moderate Moderate High High Moderate Limited None Limited Limited Moderate Moderate Moderate

Waterfowl None None None Limited High High Moderate Moderate Moderate Moderate Limited Limited

Eggs None None None None None High None None None None None None

Plants and 

Berries None None None None Limited Limited High High None None None None

Key: White = No Activity

Yellow = Limited activity and/or harvests

Orange = Moderate activity and/or harvests

Red = High activity and/or harvests

Notes: Rankings of “High,” “Moderate,” and “Limited” are based on an analysis of all sources of seasonal round data listed below. For each source, the 

study team assigned each month a ranking of “1,” “2,” or “3” based on the intensity of use identified in that source’s data set. The study team then 

summed the individual rankings for each month across all sources, and then assigned a ranking of “1 (Limited),” “2 (Moderate),” or “3 (High)” based on 

the summed values

Sources: Bacon et al. 2009; Braem et al. 2011; Brower and Hepa 1998; Brown 1979; Brown et al. 2016; EDAW Inc. 2008; Fuller and George 1999 (where 

resource category data are available); Galginaitis 2014; Hoffman et al. 1988; Libbey et al. 1979; SRB&A 2010a, 2018. 
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

26

2.4 References 

Ahtuangaruak, R. 1997. Scoping Testimony. Transcript of Public Hearing, Draft Environmental 

Impact Statement for Beaufort Sea Proposed Oil and Gas Lease Sale 170, Nuiqsut, 

Alaska. 

Alaska Department of Fish and Game (ADF&G). 2017. Community Subsistence Information 

System. Available online at: 

http://www.adfg.alaska.gov/sb/CSIS/index.cfm?ADFG=main.home (accessed May 

2017). 

Bacon, J., T. Hepa, H. Brower, Jr., M. Pederson, T. Olemaun, J. George, and B. Corrigan. 2009. 

Estimates of Subsistence Harvest for Villages on the North Slope of Alaska, 1994–2003. 

North Slope Borough Department of Wildlife Management, Barrow, Alaska. Available 

online at: http://www.north-slope.org/assets/images/uploads/MASTER%20SHDP%2094-

03%20REPORT%20FINAL%20and%20%20Errata%20info%20(Sept%202012).pdf

(accessed May 2017).

Braem, N., S. Pedersen, J. Simon, D. Koster, T. Kaleak, P. Leavitt, J. Patkotak, and P. Neakok. 

2011. Monitoring of Annual Caribou Harvests in the National Petroleum Reserve in 

Alaska: Atqasuk, Barrow, and Nuiqsut, 2003–2007. ADF&G, Division of Subsistence, 

Technical Paper No. 361, Fairbanks, Alaska. Available online at: 

http://www.adfg.alaska.gov/techpap/TP361.pdf (accessed May 2017). 

Braund, Stephen R. & Associates (SRB&A). 2010a. Subsistence Mapping of Nuiqsut, Kaktovik, 

and Barrow. MMS OCS Study 2009-003. Prepared for United States Department of the 

Interior, Minerals Management Service, Alaska OCS Region, Environmental Studies 

Program. Anchorage, Alaska. Available online at: http://www.boem.gov/BOEMNewsroom/Library/Publications/2009/2009_003.aspx (accessed May 2017).

_____. 2010b. Nuiqsut Caribou Subsistence Monitoring Project: Results of 2009 Hunter 

Interviews. Prepared for ConocoPhillips Alaska, Inc., Anchorage, Alaska. Available 

online at: http://www.arlis.org/docs/vol1/B/648170617.pdf (accessed May 2017). 

_____. 2011. Nuiqsut Caribou Subsistence Monitoring Project: Results of Year 2 Hunter 

Interviews. Prepared for ConocoPhillips Alaska, Inc., Anchorage, Alaska. 

_____. 2012. Nuiqsut Caribou Subsistence Monitoring Project: Results of Year 3 Hunter 

Interviews. Prepared for ConocoPhillips Alaska, Inc., Anchorage, Alaska. Anchorage, 

Alaska.

_____. 2013. Nuiqsut Caribou Subsistence Monitoring Project: Results of Year 4 Hunter 

Interviews. Prepared for ConocoPhillips Alaska, Inc. Anchorage, Alaska. Anchorage, 

Alaska. Available online at: 

http://epscor.alaska.edu/cms/2014/04/10/8zc5x1d23f_Nuiqsut_Caribou_Monitoring_Y4_

Report_July19.pdf (accessed May 2017). 
Appendix F- Overview of Nuiqsut Subsistence Uses Stephen R. Braund & Associates

27

_____. 2014. Nuiqsut Caribou Subsistence Monitoring Project: Results of Year 5 Hunter 

Interviews and Household Harvest Surveys. Prepared for ConocoPhillips Alaska, Inc. 

Anchorage, Alaska. 

_____. 2015. Nuiqsut Caribou Subsistence Monitoring Project: Results of Year 6 Hunter 

Interviews and Household Harvest Surveys. Prepared for ConocoPhillips Alaska, Inc. 

Anchorage, Alaska. 

_____. 2016. Nuiqsut Caribou Subsistence Monitoring Project: Results of Year 7 Hunter 

Interviews and Household Harvest Surveys. Prepared for ConocoPhillips Alaska, Inc. 

Anchorage, Alaska. 

_____. 2017. Nuiqsut Caribou Subsistence Monitoring Project: Results of Year 8 Hunter 

Interviews and Household Harvest Surveys. Abridged. Prepared for ConocoPhillips 

Alaska, Inc. Anchorage, Alaska.

_____. 2018. Nuiqsut Caribou Subsistence Monitoring Project: Results of Year 9 Hunter 

Interviews and Household Harvest Surveys. DRAFT. Prepared for ConocoPhillips 

Alaska, Inc. Anchorage, Alaska.

Braund, Stephen R. & Associates (SRB&A) and Institute of Social and Economic Research 

(ISER). 1993. North Slope Subsistence Study: Barrow, 1987, 1988, and 1989. Prepared 

for the U.S. Department of the Interior, Minerals Management Service, Alaska OCS 

Region Social and Economic Studies, Technical Report No. 149, OCS Study MMS 91-

0086. Anchorage, Alaska. Available online at: http://www.northslope.org/assets/images/uploads/Braund_North_Slope_Subsistence_Study_Barrow_1987,

_1988,_1989_MMS_91-0086.pdf (accessed May 2017). 

Brower, H.K., Jr., and R. Hepa. 1998. North Slope Borough Subsistence Documentation Project: 

Data for Nuiqsut, Alaska for the Period July 1, 1994 to June 30, 1995. North Slope 

Borough, Department of Wildlife Management, Barrow, Alaska. Available online at: 

http://www.northslope.org/assets/images/uploads/Subsistence%20Harvest%20Doc%20Report_Nuiqsut_94

-95.pdf (accessed May 2017).

Brown, C., N. Braem, M. Kostick, A. Trainor, L. Slayton, D. Runfola, E. Mikow, H. Ikuta, C. 

McDevitt, J. Park, and J. Simon. 2016. Harvests and uses of wild resources in 4 Interior 

Alaska communities and 3 Arctic Alaska communities. Alaska Department of Fish and 

Game Division of Subsistence, Technical Paper No. 426, Fairbanks. Available online at: 

http://www.adfg.alaska.gov/techpap/TP426.pdf (accessed May 2017). 

Brown, W. 1979. Nuiqsut Paisanich: Nuiqsut Heritage, a Cultural Plan. Prepared for the Village 

of Nuiqsut and the North Slope Borough Planning Commission on History and Culture. 

Arctic Environmental Information and Data Center, Anchorage, Alaska. 

Craig, P. 1987. Subsistence Fisheries at Coastal Villages in the Alaskan Arctic, 1970-1986. LGL 
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Ecological Research Associates, Inc. Anchorage, Alaska. Prepared for U.S. Department 

of the Interior, Minerals Management Service, Alaska Outer Continental Shelf Region, 

Leasing and Environment Office, MMS OCS Technical Report No. 129, Anchorage, 

Alaska. San Diego, California. Available online at https://www.boem.gov/BOEMNewsroom/Library/Publications/1987/87_0044.aspx (accessed May 2017).

Fuller, A., and J. George. 1999. Evaluation of Subsistence Harvest Data from the North Slope 

Borough 1993 Census for Eight North Slope Villages: For the Calendar Year 1992. North 

Slope Borough, Department of Wildlife Management, Barrow, Alaska. Available online 

at: http://www.north-slope.org/assets/images/uploads/Master%20Report%20(FullerGeorge%2099).pdf (accessed May 2017). 

Galginaitis, M. 2010. Annual Assessment of Subsistence Bowhead Whaling Near Cross Island, 

2009: Continuation of Monitoring Activities. Annual Report. Prepared by Applied 

Sociocultural Research for U.S. Department of the Interior, Minerals Management 

Service (USDOI, MMS), Alaska Outer Continental Shelf Region, Contract No. 

M08PC20029. Anchorage, Alaska. Available online at: https://www.boem.gov/BOEMNewsroom/Library/Publications/2009/2009_0421_AnnualRpt.aspx (accessed May 2017).

______2009a. Annual Assessment of Subsistence Bowhead Whaling Near Cross Island, 2001-

2007. Final Report. Prepared by Applied Sociocultural Research for U.S. Department of 

the Interior, Minerals Management Service (USDOI, MMS), Alaska Outer Continental 

Shelf Region, Contract Nos. 1435-01-04-CT-32149 and M04PC00032. OCS Study MMS 

2009-038. Anchorage, Alaska. Available online at: https://www.boem.gov/BOEMNewsroom/Library/Publications/2009/2009_038.aspx (accessed May 2017).

______2009b. Annual Assessment of Subsistence Bowhead Whaling Near Cross Island, 2008: 

Continuation of Monitoring Activities. Annual Report. Prepared by Applied 

Sociocultural Research for U.S. Department of the Interior, Minerals Management 

Service (USDOI, MMS), Alaska Outer Continental Shelf Region, Contract No. 

M08PC20029. Anchorage, Alaska. Available online at: 

http://www.arlis.org/docs/vol1/BOEM/CrossIsland/AnnualReport2008/AnnualReport200

8.pdf (accessed May 2017).

Gallant A., E.F. Binnian, J.M. Omernik, and M.B. Shasby. 1995. Ecoregions of Alaska. U.S. 

Geological Survey Professional Paper No. 1567. United States Government Printing 

Office, Washington D.C. Available online at: https://pubs.usgs.gov/pp/1567/report.pdf

(accessed May 2017).

George, J., M. Philo, R. Suydam, G. Carroll, and T. Albert. n.d. Chapter 3 Body Mass of 

Bowhead Whales (Balaena mysticetus) of the Bering Chukchi Beaufort Seals. Formatted 

for Journal Arctic.

Impact Assessment, Inc. (IAI). 1990a. Subsistence Resource Harvest Patterns: Nuiqsut Special 

Report No. 8. Prepared for U.S. Department of the Interior, Minerals Management 

Service, Alaska OCS Region Social and Economic Studies. Anchorage, Alaska. In BLM. 
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2012. National Petroleum Reserve−Alaska (NPR-A). Final Integrated Activity Plan 

(IAP)/Environmental Impact Statement (EIS). Available online at 

https://www.boem.gov/BOEM-Newsroom/Library/Publications/1990/90_0038.aspx

(accessed May 2017).

_____. 1990b. Subsistence Resource Harvest Patterns: Kaktovik. Prepared for U.S. Department 

of the Interior, Minerals Management Service, Alaska OCS Region Social and Economic 

Studies, Anchorage, Alaska. OCS Study MMS 90-0039, Special Report No. 9. La Jolla, 

California. Available online at: https://www.boem.gov/BOEMNewsroom/Library/Publications/1990/90_0039.aspx (accessed May 2017).

North Slope Borough (NSB). 2015. North Slope Borough 2015 Economic Profile & Census 

Report. Barrow, Alaska. Available online at: http://www.northslope.org/assets/images/uploads/NSB_Economic_Profile_and_Census_Report_2015_FIN

AL.pdf (accessed May 2017).

______2017. Nuiqsut. Available online at: http://www.north-slope.org/our-communities/nuiqsut

(accessed May 2017).

Pedersen, S. 1979. Regional Subsistence Land Use, North Slope Borough, Alaska. Occasional 

Paper No. 2. Anthropology and Historic Preservation, Cooperative Park Studies Unit, 

University of Alaska, Fairbanks, Alaska and Conservation and Environmental Protection, 

North Slope Borough, Barrow, Alaska. 

_____. 1986. Nuiqsut Subsistence Land Use Atlas, 1986 Update. ADF&G, Division of 

Subsistence, File Report 1986-01. Fairbanks, Alaska.

_____. 1995. Chapter XXII: Nuiqsut. In J. Fall and C. Utermohle (Eds) An Investigation of the 

Sociocultural Consequences of Outer Continental Shelf Development in Alaska. V. 

Alaska Peninsula and Arctic. Submitted by ADF&G, Division of Subsistence. Prepared 

for U.S. Department of the Interior, Minerals Management Service, Alaska OCS Region, 

OCS Study MMS 95-012. Available online at: https://www.boem.gov/BOEMNewsroom/Library/Publications/1995/95_014.aspx (accessed May 2017).

Pedersen, E., R. Wolfe, C. Scott, and R. Caulfield. 2000. Subsistence Economies and Oil 

Development: Case Studies from Nuiqsut and Kaktovik, Alaska. Part 1. In Subsistence 

Economies and Oil Development: Case Studies from Nuiqsut and Kaktovik, Alaska. S. 

Pederson, R. Wolfe, C. Scott, and R. Caulfield editors, and Part 2: Subsistence Harvest 

Variability in Alaska Native Communities. R. Wolfe, C. Scott, S. Pedersen, and R. 

Caulfield editors. Prepared by the ADF&G, Division of Subsistence and the University of 

Alaska, Fairbanks, Department of Alaska Native and Rural Development. Prepared for 

U.S. Department of the Interior, Minerals Management Service, Alaska OCS Region, 

Contract MMS 14-35-001-300661. Fairbanks, Alaska. 

Research Foundation of State University of New York. 1984. Ethnographic Study and 

Monitoring Methodology of Contemporary Economic Growth, Socio-Cultural Change 
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and Community Development in Nuiqsut, Alaska. In: Nuiqsut Case Study. Prepared for 

the U.S. Department of the Interior, Minerals Management Service, Alaska Outer 

Continental Shelf Region, Leasing and Environment Office, Social and Economic Studies 

Unit, Technical Report No. 96. Anchorage, Alaska. Available online at: 

https://www.boem.gov/BOEM-Newsroom/Library/Publications/1984/84_TR96.aspx

(accessed May 2017).

Seigle, J., L. Gutierrez, J. Rose, J. Welch, A. Prichard, J. Pausanna. 2016. Fall 2015 Subsistence 

Fishery Monitoring on the Colville River. Prepared for ConocoPhillips Alaska, Inc. ABR, 

Inc.—Environmental Research & Services. Anchorage, Alaska. 

Worl, R., and C. Smythe. 1986. Barrow: A Decade of Modernization. Technical Report No. 125, 

Alaska OCS Socioeconomic Studies Program, MMS, Alaska Continental Shelf Region, 

Anchorage, Alaska. Available online at: https://www.boem.gov/BOEMNewsroom/Library/Publications/1986/86_0088.aspx (accessed May 2017).
Appendices  Final Supplemental Environmental Impact Statement

Alpine Satellite Development Plan for the Proposed Greater Mooses Tooth 2 Development Project

APPENDIX G

HUMAN HEALTH BASELINE SUMMARY 

1 

BASELINE HUMAN HEALTH SUMMARY

GMT2 PROJECT 

JULY, 2017 

Prepared by: 

Alaska Department of Health and Social Services 

Environmental Public Health Program 
2 

TABLE OF CONTENTS

Introduction and Overview.......................................................................................................................... 3

HEC 1: Social Determinants of Health ......................................................................................................... 4 

HEC 2: Accidents and Injuries..................................................................................................................... 11

HEC 3: Exposure to Potentially Hazardous Materials ............................................................................... 13

HEC 4: Food, Nutrition, and Subsistence................................................................................................... 16 

HEC 5: Infectious Diseases ......................................................................................................................... 19 

HEC 6: Water and Sanitation...................................................................................................................... 21 

HEC 7: Non-communicable and Chronic Diseases..................................................................................... 22

HEC 8: Health Services Infrastructure and Capacity.................................................................................. 27 

References.................................................................................................................................................. 28

TABLES

Table 1. Population demographics in PACs ..................................................................................................4

Table 2. Economic indicators........................................................................................................................6

Table 3. Educational attainment...................................................................................................................7

Table 4. Unintentional Injury Deaths by Cause, North Slope Borough and State of Alaska, 2013-2015....12

Table 5. Percentage of food insecure households in the NSB, 2015..........................................................17

Table 6. NSB Iñupiat household head’s participation in subsistence activities..........................................18

Table 7. Subsistence resources most commonly used by Nuiqsut households, 2014 ...............................18

Table 8. Overweight and obesity among NSB households, 2012 ...............................................................23

Table 9. Cancer Deaths by Type, North Slope Borough and the State of Alaska, 2013-2016 ....................24

Table 10. Major Cardiovascular Disease Deaths, North Slope Borough and the State of Alaska, 2011 - 

2013 ............................................................................................................................................................25

Table 11. Chronic lower respiratory disease rates, NSB, 2013-2016..........................................................26

FIGURES

Figure 1. Leading causes of North Slope Borough non-fatal injury hospitalizations, 2009-2015...............13

Figure 2. Chlamydia infection rates, by Region – Alaska 2014 and 2015 ...................................................20

Figure 3. Gonorrhea infection rates, by Region – Alaska 2014 and 2015...................................................21
3 

GMT2 BASELINE HUMAN HEALTH SUMMARY 

Introduction

This baseline human health summary presents an overview of the current health status of the 

communities within the North Slope Borough (NSB). This baseline health summary included Anaktuvuk

Pass, Atqasuk, Kaktovik, Nuiqsut, Point Hope, Point Lay, Utqiaġvik [formerly known as Barrow], and

Wainwright. This baseline summary refers to these communities as potentially affected communities

(PACs) in accordance with the HIA Toolkit (ADHSS, 2015). The summary focused on Nuiqsut because it is

the closest PAC to the proposed GMT2 Project.

Baseline health conditions form a fundamental context for the overall health impact assessment (HIA)

process. The baseline health summary creates a point of reference for the health status of a community

prior to development of a proposed project and also describes an overall health profile for an area. The 

baseline health summary will inform decision-makers about health vulnerabilities and strengths of PACs.

This information, used in conjunction with their knowledge of the features of a project, will help them

better understand the potential health implications of the project and better inform deliberations.

For Alaska, baseline health information can be found in public health surveillance systems maintained by

the State of Alaska, the Alaska Native Tribal Health Consortium (ANTHC), and occasionally local borough

and tribal entities. This document focuses on a review of existing public health surveillance data. The

GMT2 Baseline Human Health Summary presents personal health information (PHI) according to the

requirements of the Health Insurance Portability and Privacy Act of 1996 (HIPPA). The State of Alaska’s

approach to PHI is detailed in the HIA Toolkit (ADHSS, 2015). 

Alaska public health agencies routinely report public health surveillance data at the statewide or

regional level. These agencies do not typically report village or community-level data to avoid privacy

violations (e.g., stigmatization) and problems with statistical analysis when case numbers are small. In

general, the State of Alaska does not release disaggregated results for small numbers (e.g., <6). As a

result, the majority of the data presented in this baseline health summary represents the entire NSB,

rather than community-level data.

Baseline community health data are organized and presented by specific Health Effect Categories (HECs). 

The report focuses on health data that, based on experience with similar types of projects, are likely to be 

most relevant to the proposed GMT2 Project. 
4 

HEC1: Social Determinants of Health

The World Health Organization (WHO) defines the social determinants of health as, “the circumstances 

in which people are born, grow up, live, work, and age, and the systems put in place to deal with illness” 

and asserts that “the social determinants of health are mostly responsible for health inequities—the 

unfair and avoidable differences in health status seen within and between countries” (WHO, 2008).

Both health outcome data and health determinant data are used to establish baseline health status 

according to the social determinants of health. An outcome is a health event that has actually occurred, 

while a determinant is a setting or context that strongly influences health status.

Life expectancy, maternal and child health, intimate partner violence and sexual violence, oral health, 

suicide rates, and substance dependence are health outcomes used as general indicators of physical and 

social wellness. Family structure, economic status, educational attainment, family stability, and cultural 

continuity are health determinants that are associated with positive and negative health outcomes. For 

the purpose of the baseline health summary, regional information about the aforementioned criteria is 

compared to information for all Alaska Native peoples (AN), Alaskans statewide, and to the U.S. 

population, where possible. 

Demographics

Population 

The PACs described in this baseline summary are communities whose residents may be affected by the 

proposed GMT2 Project. This includes the eight villages of the NSB (Anaktuvuk Pass, Atqasuk, Utqiaġvik, 

Kaktovik, Nuiqsut, Point Hope, Point Lay and Wainwright). Additional data will be provided, where 

possible, for the community of Nuiqsut, due to its proximity to the proposed project.

The population of the villages in the PACs is described in Table 1. The majority of villages are small, with 

populations fewer than 500 residents. The majority of residents in all communities (roughly 90%, except 

in Utqiaġvik) are American Indian/AN. The population is young (median age: 24-31 years old; Table 1). 

Table 1. Population demographics in PACs

Village Population 

size

American 

Indian/Alaska 

Nativea

Median age

(years)

Proportion of 

residents ≥ 65 

years of age

Proportion of 

residents < 18 

years of age

Anaktuvuk Pass 324 92% 27 4% 33%

Atqasuk 233 93% 24 6% 39%

Kaktovik 239 90% 31 8% 30%

Nuiqsut 402 90% 25 6% 28%

Point Hope 674 93% 25 6% 35%

Point Lay 189 89% 25 4% 31%

Utqiaġvik 4,212 69% 28 5% 33%

Wainwright 556 92% 28 5% 34%

Source: U.S. Census, 2014 a

Race reported alone or in combination with one or more other races 
5 

Income

The U.S. Census Bureau collects data on median household income via the American Communities 

Survey (ACS). Income includes all monetary sources of income including wages, the Permanent Fund 

Dividend, corporation dividends, and public assistance (ADCRA, 2016). Income does not include any 

dollar equivalent of subsistence resources (resources from the harvesting and processing of wild foods 

and raw materials). For 2014, the estimated median household income in the NSB was $74,609; for 

Alaska it was $71,829. Median household income in the PACs ranged from $49,375 (Anaktuvuk Pass) to 

$85,883 (Nuiqsut; Table 2). In the majority of NSB households, permanent fund dividends account for 7-

17% of the household’s total income. The three most important sources of income for Iñupiat 

households in the NSB are wage work (57%), corporation dividend income (20%) and permanent fund 

dividends from the state (NSB Census, 2015) 

According to the 2010-2014 ACS estimates, the per capita income in the NSB ($50,267) was one and a 

half times higher than in the State of Alaska ($33,129). Each PAC had a per capita income lower than the 

state average, with Utqiaġvik having the highest at $27,696 (U.S. Census ACS, 2014; Table 2). 

Employment

Employment is another key demographic factor that influences health. Unemployment includes anyone 

who has made an active attempt to find work in the four-week period up to and including the week that 

includes the 12th of the referenced month. Due to the scarcity of employment opportunities in rural 

Alaska, many individuals do not meet the official definition of unemployed because they are not 

conducting active job searches. In October of 2016 (the most recently available data), the 

unemployment rate for the entire NSB was 6.7%, which was similar to the statewide unemployment 

rate of 6.3%, but higher than the nation-wide rate of 4.7% (ADLWD, 2016). According to the 2015 NSB 

Census, the unemployment rate for the NSB was 27.7%; this rate was determined through interviews 

and census respondents, rather than from unemployment insurance claims and accounts for the lack of 

employment opportunities and seasonal unemployment in the NSB. Communities outside of Utqiaġvik 

bear the largest burden of unemployment in the NSB (NSB Census, 2015). 

Percent living below poverty level

Poverty is a powerful determinant of human health (Braveman et al., 2011). The U.S. Census Bureau 

uses a set of money income thresholds that vary by family size and composition to determine who is in 

poverty nationwide (U.S. Census, 2016). However, the U.S. Census defines poverty in a way that does 

not take into account the higher cost of living in Alaska. The U.S. Department of Health and Human 

Services adjusts poverty guidelines for entitlement programs such as Women, Infants and Children, and 

Temporary Assistance for Needy Families for local factors. For the 48-contiguous U.S. states, the 2016 

poverty level for a 1-person household was $11,880 and for a 4-person household it was $24,300. 

Comparatively, the 2016 poverty level in Alaska for a 1-person household was $14,840 and for a 4-

person household was $30,380 (ASPE, 2016). However, the poverty measure may still not accurately 

predict the well-being of a family in rural Alaska, due to the contributions from subsistence and sharing 

resources within the community (Goldsmith, 2007; Kofinas et al., 2016 ). 

In 2014, the percent of residents living below the federal poverty level in the NSB was very similar to the 

percentage for all of Alaska (10.2% for NSB, 10.1% for Alaska; Table 2). The variation between villages is 
6 

high, ranging from 3% in Nuiqsut to over 21% in Atqasuk. All villages, except Nuiqsut, had a higher 

percentage of residents living below the poverty line than the State of Alaska as a whole (U.S. Census 

ACS, 2014).

Table 2. Economic indicators 

Location Per Capita 

Income ($)

Median 

Household 

Income ($)

% of People Living Below 

the Poverty Limit

State of Alaska 33,129 71,859 10.1%

North Slope Borough 50,267 74,609 10.2%

Anaktuvuk Pass 19,122 49,375 18.9%

Atqasuk 19,968 51,500 21.5%

Kaktovik 20,782 58,125 14.8%

Nuiqsut 26,861 85,833 3.0%

Point Hope 19,497 67,500 11.9%

Point Lay 18,819 60,000 16.7%

Utqiaġvik 27,696 82,976 12.3%

Wainwright 20,551 64,861 19.3%

Source: U.S. Census ACS, 2014

Educational attainment

The highest level of household educational attainment is positively associated with improved overall 

family health status (Muennig, 2006). High school graduates have been found to live an average of 6 to 9 

years longer than high school dropouts (Wong et al., 2002). Adults with low educational attainment are 

more likely to die from cardiovascular disease, cancer, and lung disease (Muennig, 2005). Multiple 

mechanisms have been proposed to account for this trend. Education positively impacts lifestyle choices 

and health-related decisions, and better-educated people are also less likely to be employed in 

dangerous jobs (Muennig, 2006). 

Compared to the State of Alaska, the NSB has a slightly lower percentage of adults with a high school 

diploma and with a bachelor’s degree or higher (Table 3). The percentage of adults who are high school 

graduates varies considerably among the communities, from a low of 69.7% in Atqasuk to a high of 

82.7% in Utqiaġvik (U.S. Census ACS, 2014). 
7 

Table 3. Educational attainment

Location Percent high school graduate or higher

Alaska 91.8%

North Slope Borough 87.1%

Anaktuvuk Pass 75.4%

Atqasuk 69.7%

Utqiaġvik 82.7%

Kaktovik 70.4%

Nuiqsut 70.4%

Point Hope 81.5%

Point Lay 80.0%

Wainwright 75.2%

Source: U.S. Census ACS, 2014

General Health

Self-rated health is one of the most consistent predictors of illness, premature death, health care 

utilization, and hospitalization. In 2010, more than three-quarters (79%) of Nuiqsut heads of household 

reported their health to be at least good, and 21% reported fair to poor health, which is generally 

consistent with the other NSB villages. The percentage of adults reporting to have very good to excellent 

health was lower in Nuiqsut (39%) than it was statewide (56%; BLM, 2013). Comparatively, in 2015, 95% 

of Nuiqsut heads of household reported their health to be at least good. With the exception of 

Anaktuvuk Pass, the percentage of household heads reporting poor to fair health in all NSB communities 

decreased (NSB Census, 2015).

Maternal and Child Health

Infant mortality

Infant mortality is an important indicator for population health and is influenced by living conditions, 

food security, domestic conflict, socio-economic well-being, and access to health services. Infant 

mortality can be separated into neonatal deaths, which occur during the first 28 days of life, and postneonatal deaths, which occur from the 28th day to 1 year of life. Whereas neonatal deaths are 

associated with the quality of prenatal and perinatal health care, post-neonatal deaths are more closely 

associated with socio-economic conditions (AMAP, 2009). 

The infant mortality rate in the NSB (11.6 per 1,000 live births) was 2 times higher than the rate for the 

State of Alaska (5.7 per 1,000 live births) from 2011-2015. In 2014, the infant mortality rate for the U.S. 

was 5.8 deaths per 1,000 live births. These data suggest that the post-natal experience, which is affected 

by socio-economic conditions, is of concern in the NSB compared to Alaska overall and the U.S., though 

it is important to note that infant mortality rates in the NSB have been declining in recent decades (NSB,

2012). 

Low birth weight

Low birth weight is defined by the WHO as a weight at birth of less than 2,500 grams (5.5 lbs) and most 

often results from poor delivery of nutrients and oxygen to the fetus, which is directly related to the 
8 

health of the mother (WHO, 2005). Low birth weight is associated with an increased risk of lifelong 

disability and a 20-fold increased risk of premature death (NCHS, 2011). Low birth weight is therefore an 

indicator of health in maternal and infant populations. 

In 2015, the percent of low birthweight infants (all races) in the NSB was 6.4%, compared to 5.7% low 

birthweight infants statewide. The percent of low birthweight infants in the NSB has remained relatively 

stable and comparable to Alaska rates since 1995 (NSB, 2014). 

Substance use during pregnancy

Substance use during pregnancy refers to the consumption of alcohol, tobacco, and/or drugs while 

pregnant. Substance use is a risk for both the mother and the fetus and can lead to premature 

detachment of the placenta, sudden infant death syndrome, and developmental problems in childhood

(WHO, 2005). Alcohol use during pregnancy puts infants at risk for fetal alcohol spectrum disorders

(FASD), the leading preventable cause of birth defects and developmental disabilities nationwide (CDC, 

2011).

In the NSB during 2012, the percentage of infants born to all mothers who reported drinking alcohol 

(0.6%) during pregnancy was much less than that reported for Alaska mothers statewide (2.6%; ABVS, 

2015). The NSB Baseline Community Health Analysis (NSB, 2012) reported that the prevalence of FASD 

in the NSB was >3 times the state average and 16 times the rate in non-Natives statewide, but was 

similar to the rate for AN statewide. Variation in screening practices, diagnosis, and reporting may 

account for some of the regional differences (NSB, 2012). 

Smoking during pregnancy is the single most important contributor to low birth weight (CDC, 2004). In 

the NSB in 2015, 47.8% of infants were born to mothers who reported smoking during pregnancy. This 

was almost 3 times higher than the statewide rate of 18.5% (ABVS, 2016). 

Mental Health

Mental health is a “state of well-being in which an individual realizes his or her own abilities, can cope 

with the normal stresses of life, can work productively, and is able to make a contribution to his or her 

community (WHO, 2014)”. Mental health, or behavioral health, is increasingly considered a critical 

component of overall health and is linked to physical health and well-being for people at all ages. Mental 

health can be affected by factors such as employment, working conditions, income, living environment, 

housing quality, food security, physical health, and cultural support (NSB, 2014).

Assessing mental health at the population level is often challenging, in part because diagnosis can be 

low (e.g., people may not seek medical care for depression). Also, Iñupiat cultural traditions sometimes

prevent the open recognition and discussion of emotional suffering (NSB, 2012). These factors can result 

in under reporting and diagnosis of mental health issues. Often, researchers must rely on self-reported 

data to gain a clearer picture of mental health in a community. 

Mentally unhealthy days

The Behavioral Risk Factor Surveillance System (BRFSS) asked participants ‘thinking about your mental 

health, which includes stress, depression, and problems with emotions, for how many days during the 

past 30 days was your mental health not good?’. From 2011-2013, NSB residents (all races) reported 3.3 
9 

mentally unhealthy days per month, compared to 3.1 mentally unhealthy days reported statewide. NSB

residents reported fewer mentally unhealthy days than AN statewide (4.0 days) and all Alaskans (3.2 

days). The average number of mentally unhealthy days in the NSB has more than doubled from a low of 

1.5 days in 1995-1997 (BRFSS, 2016). Additionally, from 2008-2010, residents in the NSB less commonly 

reported always or usually receiving the social and emotional support they needed (53%) than AN 

statewide (66.8%) or all Alaskans (80.0%; NSB, 2012). 

Suicide

Suicide is an important health outcome that can indicate mental health illness in a population and has 

devastating effects on families and communities. Age-adjusted suicide mortality rates are consistently 

higher in the NSB compared to the State of Alaska (NSB, 2014). Suicide was the fifth leading cause of 

death in the NSB and the sixth leading cause of death in the State of Alaska from 2013-2015. The ageadjusted suicide rate in the NSB from 2013-2015 (30.1per 100,000 U.S. year 2000 standard population)

was similar to the age-adjusted rate for the State of Alaska (24.2 per 100,000 U.S. year 2000 standard 

population), though it is important to note that the NSB rate was based on fewer than 20 occurrences 

and may therefore be statistically unreliable and should be interpreted with caution. Suicide has 

remained a leading cause of death in the NSB for over 2 decades, ranked as either the fourth or fifth 

leading cause of death since 1992 (ABVS, 2015).

Substance Dependence

Substance abuse is an indication of poor mental health, can cause additional health problems, and 

strongly influences many related health outcomes, such as accidents and injuries, suicide, and mental 

health. Substance abuse includes illicit use of drugs (such as marijuana and heroin), alcohol addiction, 

and binge drinking. Current substance use is defined as having used (e.g., alcohol, marijuana, or cocaine) 

in the past 30 days. 

According to the NSB 2010 Census, 33% to 57% of household heads reported that they felt a household 

member had been hurt often by the effects of drugs or alcohol in the previous year. This illustrates the 

wide-ranging effects of alcohol and drug abuse on the individual, household, and community levels 

(NSB, 2012).

Alcohol

Alcohol abuse is linked to chronic disease, risky and violent behavior, injuries, suicide, homicide,

disintegration of family structure and well-being, and adverse home environments for children. In 

particular, interpersonal violence and injury are associated with “binge,” or episodic, heavy drinking 

(WHO, 2006; IAP, 2013). Binge drinking is defined as a pattern of drinking that brings a person’s blood 

alcohol concentration to 0.08 grams percent or above. Typically, this happens when men consume 5 or 

more drinks, and when women consume 4 or more drinks, in about 2 hours (CDC, 2015). 

In the NSB, 34% of all injury hospitalizations, and 63% of assault injuries among AN were recorded as 

alcohol-related (NSB, 2012). According to BLM 2013, “alcohol is involved in an estimated 40% of snow 

machine-related injury hospitalizations, 70% of assault injuries, 57% of suicide attempts, and 45% of 

motor vehicle-related injury hospitalizations” (BLM, 2013). 
10

According to data from the Alaska BRFSS, from 2011-2013, the self-reported prevalence of current 

alcohol use was lower in the NSB (37.4%) than among AN statewide (43.4%) and among all Alaskans 

(56.6%). For that time period, the NSB had one of the lowest self-reported prevalences of current 

alcohol use when compared to other regions in the state. Also for the same time period, the selfreported prevalence of binge drinking in the NSB (20.1%) was similar to the binge drinking prevalence

for all AN statewide (20.3%) and for all Alaskans (18.6%; BRFSS, 2016).

Marijuana

In 2015, current marijuana use among high school students was higher in the Northwest region (35.7%; 

includes NSB, Northwest Arctic Borough, and the Nome Census Area) than high school students 

statewide (26.1% AN statewide, 19.0% all Alaskans statewide; BRFSS, 2016). Marijuana use statistics for 

adults at the regional level are limited.

Tobacco 

Tobacco use and exposure to second-hand smoke have been associated with many different health 

conditions, including lung cancer and heart disease (CDC, 2016). Rates of tobacco use in NSB are very 

high compared to most other areas of Alaska, with almost half of adults engaged in regular smoking. 

From 2011-2103, the NSB had the third-highest prevalence of current tobacco users (includes current 

smokeless tobacco users). The prevalence of current tobacco users in the NSB from 2011-2012 was 53% 

(BRFSS, 2016). The 2015 NSB census also found that 53% of the Iñupiat population reported smoking as 

least some days each week (NSB Census, 2015). Comparatively, 46.5% of AN statewide and 26.1% of all 

Alaskans reported current tobacco use (BRFSS, 2016). Adolescents in the Northwest region also had a 

high prevalence of current smokers. In 2015, 24.1% of high school students in the Northwest region 

reported smoking a cigarette in the past 30 days. Comparatively, 19.7% of AN HS students statewide and 

11.1% of all high students statewide reported current cigarette-smoking status (BRFSS, 2016). 

Cultural Continuity

Cultural continuity has been linked to numerous positive health outcomes, including reduced rates of 

suicide (Chandler, 1998; Chandler, 2004). Speaking a native language and participating in subsistence 

activities have been highlighted by circumpolar communities as important signifiers of community 

health and cultural continuity (Stevenson, 2009). Subsistence participation can include use of 

subsistence resources, harvest activities, sharing, and receiving subsistence resources. 

In 2014, 34% of NSB residents spoke a language other than English at home (most commonly Iñupiaq; 

range: 36-58%). For that same year, 58% of Nuiqsut residents reported speaking a language other than 

English at home (U.S. Census ACS, 2014). 

Participation in subsistence preserves cultural continuity and ensures cultural survival. Participation in 

subsistence activities is high throughout the region; in 2015, nearly 99% of households in all NSB 

communities participated in subsistence activities and at least 95% of NSB Iñupiat households reported 

consuming subsistence foods (NSB Census, 2015).
11

Summary

Areas of Vulnerability

• The per capita income of residents in the PACs is lower than the per capita income of the state.

• All villages, except Nuiqsut, had a higher percentage of residents living below the poverty line

than the State of Alaska as a whole.

• Infant mortality rate is higher in the NSB. Even though infant mortality is steadily decreasing in

the state, prenatal care remains a critical topic in the NSB.

• A greater percentage of women in the NSB reported smoking during pregnancy than in the

state.

• Prevalence of smoking is higher in the NSB than most regions in the state.

Areas of Resilience/Success

• Self-reported prevalence of heavy drinking and binge drinking in the NSB is lower than most

regions in the state.

• All NSB communities exhibit a high level of participation in subsistence harvests and other

subsistence activities (such as sharing and receiving subsistence resources).

HEC 2: Accidents and Injuries

Accidents and Injuries are an important cause of morbidity and mortality in Alaska. The term unintentional 

injury refers to causes of injury or death other than suicide and homicide. Fatal injury information is 

drawn from death certificates and the Alaska Violent Death Reporting System (VDRS), while non-fatal 

injuries are typically obtained from the Alaska Trauma Registry (ATR).

Fatal Injuries

Fatal unintentional injuries

From 2013-2015, unintentional injuries were the third leading cause of death among all residents of the 

NSB and among Alaska residents statewide. Motor vehicle accidents were the leading cause of 

unintentional injury death in the NSB (6 deaths), followed by poisoning (5 deaths), which is typically 

caused by alcohol ingestion, though an age-adjusted rate was not reported due to the small number of 

cases. Poisoning was the leading cause of unintentional injury death statewide, followed by motor 

vehicle accidents (Table 4; ABVS, 2016). 
12

Table 4. Unintentional Injury Deaths by Cause, North Slope Borough and State of Alaska, 2013-2015

Cause of Death

North Slope Borough State of Alaska

Number 

of Deaths

Age-adjusted 

Ratea

Number 

of Deaths

Age-adjusted 

Ratea

Unintentional Injuries 15 68.2* 1117 54.7

Transport accidents

Motor vehicle accidents 6 22.4* 228 10.2

Snow machineb 2 ** 23 0.9

ATVc 1 ** 40 1.7

Nontransport accidents

Falls 0 ** 113 7.2

Poisoning 5 ** 398 18.1

Source: ABVS, 2016 

a Age-adjusted rates are per 100,000 U.S. year 2000 standard population

b Deaths to an operator or passenger related to the use of a snow machine

c Deaths to an operator or passenger related to the use of an ATV

* Rates based on fewer than 20 occurrences are statistically unreliable and should be used with caution

**Rates based on fewer than 6 occurrences are not reported

Fatal intentional injuries (suicide)

Suicide was the fifth leading cause of death in the NSB from 2013-2015 (ABVS, 2016). Suicide has 

remained a leading cause of death in the NSB for over 2 decades. More than two-thirds of suicides 

occurring in the NSB since 2000 have involved firearms (NSB, 2012).

Non-fatal injuries

According to the NSB Baseline Community Health Analysis Report, from 1999-2008, there were 736 nonfatal injury hospitalizations among NSB residents. The leading causes of injury hospitalization for this 

time period were falls, suicide attempts, assault, and snow machine-related injuries. With the exception 

of motor vehicle traffic-related injuries, injury hospitalization rates in the NSB were higher than the 

statewide rates. In particular, the NSB rate of snow machine-related injury hospitalizations was four 

times higher than the statewide rate for all Alaskans and twice as high as the rate for AN statewide (NSB, 

2012).

The Alaska Trauma Registry (ATR) records non-fatal injuries that are serious enough to require 

admission to a health care facility. According to the ATR data, from 2009-2015, the most common cause 

of non-fatal injury requiring hospitalization in the NSB was falls (35% of all non-fatal injuries), followed 

by assault (14%), and attempted suicide (8%). These three causes of injury alone accounted for 57% of 

all non-fatal injuries from 2009-2015 (Figure 1). Males accounted for 57% of all injuries in this time 

period (ATR, 2016). 
13

Figure 1. Leading causes of North Slope Borough non-fatal injury hospitalizations, 2009-2015

Source: ATR, 2016

* Starting 1/1/2013: Adults (18 years and older) were no longer included in the ATR due to intentional,

self-inflicted, suicidal overdoses

Summary

Areas of Vulnerability

• Accidents and injuries were the third leading cause of death in the NSB from 2013-2015. The most 

common causes of unintentional injury deaths among all NSB residents were motor vehicle

accidents (the majority of which are snow machine accidents) and poisoning (typically caused by

alcohol ingestion).

• Falls, assaults, and suicide attempts were the most common causes of non-fatal injury

hospitalization in the NSB from 2009-2015.

HEC 3: Exposure to Potentially Hazardous Materials

When reviewing data on exposure to potentially hazardous materials, it is important to consider health 

outcomes, such as the prevalence of illnesses that result from exposures to hazardous materials 

(including asthma and cancer), and health determinants, such as soil, water, and air quality (when data 

are available). 

Air Quality—Expanded Discussion

Air pollution has been shown to increase the risk of a number of respiratory and cardiac conditions. Air 

pollution is also associated with increased daily mortality rates (Dockery et al., 1993). The elderly, 

children, and those with underlying health problems are particularly vulnerable to the effects of air 

pollution (CDC, 2016b). 

8

8

9

9

18

31

35

38

64

157

0 20 40 60 80 100 120 140 160

Struck by Person/Object, Accidental

Motor Vehicle Non Traffic

Firearm, Accidental

Bicycle

Motor Vehicle Traffic

Snow Machine

All-Terrain Vehicle

Suicidal

Assault

Falls

Number of Injuries
14

According to the U.S. Environmental Protection Agency (USEPA), “tribes in Alaska face unique challenges 

to protecting air quality and reducing health risks in their communities: 

• Most Tribes do not have a reservation or defined lands where they can assert jurisdiction to

address air quality issues.

• Frozen ground prevents burying waste in landfills, and many communities resort to burning trash

that creates air pollution.

• Electricity primarily comes from diesel generators that produce particulate and other air

pollutants.

• The cold climate means people spend significant time indoors in homes and buildings where

indoor air pollution can accumulate.

• Many homes have older wood stoves that can be inefficient and create air pollution.

• Dust from unpaved roads may contain pollutants that can be inhaled or deposited on subsistence

food sources.” (USEPA, 2016)

Air quality concerns in rural Alaska villages include diesel emissions, indoor air quality, road dust, solid 

waste burning, and wood smoke. Residents in the NSB have also expressed concern about air pollution 

generated by nearby oil and gas extraction activities.

In response to concerns about air pollution generated from oil and gas extraction activities, the Alaska 

Native Tribal Health Consortium (ANTHC) partnered with the Native Village of Nuiqsut to conduct an 

independent assessment of the air quality in Nuiqsut. The study included a review of 2008-2010 air 

monitoring data from the ConocoPhillips Alaska, Inc. (CPAI) air monitoring station. This station is located 

on the northern edge of Nuiqsut, 6 miles east of the Alpine Central Processing Facility (which processes 

oil and natural gas from the surrounding production pads), and collects data on the following pollutants: 

carbon monoxide (CO), nitrogen oxides (NOX), ozone (O3), sulfur dioxide (SO2), particulate matter ≤10 

μm (PM10), and particulate matter ≤2.5 μm (PM2.5). Data from the air monitoring station showed 

pollutant concentrations generally well below the national ambient air quality standards (NAAQS). PM10

exceeded the 24-hour average NAAQS twice from 2008-2010 and both instances were believed to be 

caused by dust from natural sources. PM2.5 exceeded the 24-hour NAAQS once from 2008-2010 and may 

have been due to a large forest fire plume. CO, NOX, O3, and SO2 all remained below the NAAQS from 

2008-2010 (ANTHC, 2011). 

Researchers also collected air and water samples to assess for volatile organic compounds (VOCs). Of 

the 45 samples collected, 28 contained VOCs, though none of the VOC concentrations exceeded the air 

quality standards and screening levels set by multiple federal agencies (U.S. Environmental Protection 

Agency, Agency for Toxic Substances and Disease Registry, National Institute for Occupational Safety and 

Health, and Occupational Safety and Health Administration). VOCs specifically associated with crude oil 

development were either not detected or were found at very low concentrations (below all standards 

and screening levels) for all of the collected samples. None of the water samples had VOC 

concentrations that exceeded the ADEC water quality standards (ANTHC, 2011). 

The most frequently identified source of air pollution during key informant interviews in Nuiqsut was oil 

and gas development (ANTHC, 2011). The available air monitoring data do not support this observation, 

as measured air pollutant concentrations are consistently low. It will be crucial to continue to monitor 

air quality in Nuiqsut over time. 
15

In 2013, ADEC reviewed pollutant data from the CPAI Nuiqsut monitoring station. ADEC found that all 

pollutants measured by the CPAI monitor were below the Alaska Ambient Air Quality Standards 

(AAAQS), which were developed to protect public health in Alaska (ADEC, 2015). 

Additionally, ADHSS investigated air pollution and respiratory illness in Nuiqsut in response to 

community concerns in 2003 and 2012. In both investigations, health data were collected from inpatient 

and outpatient visits for respiratory illness. The 2003 ADHSS study found no significant differences for 

respiratory visits in Nuiqsut compared to a similarly sized North Slope village for the years 1998-2002, 

except for the 10-19 years old age group. Because only one age group had a statistically higher rate of 

respiratory visits than the control village, it is unlikely that an air pollution source is the cause. If air 

pollution or another type of environmental contaminant were associated with clinic visits for respiratory 

conditions, most age groups would likely be impacted similarly. The study concluded that the increase in 

respiratory visits in Nuiqsut for 10-19 year olds was likely due to a few individuals with numerous clinic 

visits to address asthma-related problems (ADHSS SOE 2003). In the 2012 ADHSS study, which was 

conducted after the Repsol blowout event, air pollution data were collected from the CPAI monitoring 

station, as well as clinic visit data. The study concluded that there was a large number of visits to the 

Nuiqsut clinic related to respiratory conditions, but air pollution was not associated with respiratory 

illness in this investigation; instead, the increase in clinic visits was likely due to increased influenza and 

respiratory syncytial virus (RSV) activity, which was reported throughout the state during the same time 

period (ADHSS SOE, 2003; ADHSS SOE, 2012).

Water Quality

Overall, available water quality data for Nuiqsut indicate that, with few exceptions, water quality 

standards for human consumption are being met (BLM, 2014). See HEC 6: Water and Sanitation for a 

related discussion on water and sanitation in the NSB.

Summary

Areas of Vulnerability

• Residents of Nuiqsut have expressed concerns that the air quality in the community is poor, and

have indicated that this is causing high rates of respiratory diseases; the available air monitoring

data do not support this observation, as measured air pollutant concentrations are consistently

low. It will be crucial to continue to monitor air quality in Nuiqsut over time.

Areas of Resilience/Success

• Available air quality monitoring data indicate that pollutants are at levels that are not expected

to cause adverse health outcomes.

• Results indicate little evidence of significant air- or water-quality problems associated with oil

and gas development.
16

HEC 4: Food, Nutrition, and Subsistence

The Alaska Federation of Natives (AFN) describes subsistence as “the hunting, fishing, and gathering 

activities, which traditionally constituted the economic base of life for Alaska's Native peoples and which 

continue to flourish in many areas of the state today” (AFN, 1993). 

Subsistence is part of a rural economic system, called a “mixed, subsistence-market” economy, wherein 

families invest money into small-scale, efficient technologies to harvest wild foods. Fishing and hunting 

for subsistence resources provides a reliable economic base for many rural regions. Subsistence is focused 

toward meeting the needs of families and small communities. Participants in this mixed economy in rural 

Alaska often augment their subsistence production by cash employment. Cash (from commercial fishing, 

trapping, or wages from public sector employment, construction, firefighting, oil and gas industry, or other 

services) provides the means to purchase the equipment, supplies, and fuel used in subsistence activities. 

The combination of traditional and commercial-wage activities provides the economic basis for the way 

of life valued in rural communities (Wolfe and Walker, 1987).

Subsistence fishing and hunting are important sources of employment and nutrition in almost all rural 

communities. Traditional fishing, hunting, and gathering are critical sources of nutrition for many 

residents in areas of Alaska where food prices are high. While some people earn income from 

employment, these and other residents rely on subsistence to supplement their diets throughout the year. 

Furthermore, traditional and cultural activities support a healthy diet, cultural continuity, and contribute 

to residents’ overall well-being (Ballew et al., 2004; Kofinas et al., 2016).

Food Security

Food security is defined by the Food and Agricultural Organization of the United Nations as “a situation 

that exists when all people at all times have physical, social, and economic access to sufficient, safe, 

nutritious food that meets their dietary needs and food preferences for an active and healthy life” (FAO, 

2002). Food security is based on the availability, access (both physical and economical; also includes 

access via sharing networks), and use of food, and is related to health through malnutrition. Food 

insecurity, the inability to access enough food at all times to meet basic needs, is tied to poor health 

status among children, including: more frequent colds, ear infections, and other health problems; 

aggression, hyperactivity, and anxiety; increased need for mental health services; impaired cognitive 

functioning, lower test scores, and poorer overall school achievement (NSB, 2012; ADHSS, 2008). Food 

insecurity is associated with malnutrition and is also associated with increased obesity and diabetes 

because those who do not always have enough food often consume high-calorie foods with low nutrient 

value (ADHSS, 2008). 

NSB households, particularly Iñupiat households, reported high levels of food insecurity in the NSB 2015

Census. In the NSB, 37% of household heads reported that there were times last year when they found it 

difficult to get the food needed to make healthy meals and 25% of household heads reported that there 

were times in the previous year when household members did not have enough to eat. Food insecurity 

varied greatly between communities and ranged 9-54% of households (NSB Census, 2015; Table 5).

Statewide and national food insecurity data are not easily comparable with NSB data because the state 

and national surveys do not ask about subsistence food security or take into account the lack of 

availability of many foods in remote communities. For reference, in 2010, 10.8% of Alaska households 

surveyed were found to have some degree of food insecurity, and 4.4% were found to have “very low 
17

food security,” with disrupted eating patterns or reduced food intake (USDA, 2010). Although the NSB 

2015 census data are not directly comparable with statewide estimates, the results suggest that food 

insecurity is a serious problem across the NSB and, like other rural areas, exists at levels higher than 

statewide estimates. 

Table 5. Percentage of food insecure households in the NSB, 2015

Community % of Food Insecure 

Households

North Slope 

Borough

24

Anaktuvuk Pass 54

Atqasuk 31

Kaktovik 10

Nuiqsut 9

Point Hope 25

Point Lay 9

Utqiaġvik 25

Wainwright 24

Source: NSB Census, 2015

The Alaska Department of Fish and Game (ADF&G) conducted a harvest study in Nuiqsut during 2015. In 

the study, which has several questions focused on food security, 12% of Nuiqsut households worried 

about having enough food at one or more times during 2014. Approximately 26% of households 

reported that they lacked the resources (i.e., time, money, and equipment) to obtain either subsistence 

or store-bought foods (ADFG, 2016). In this study, Nuiqsut had a slightly higher percentage of food 

secure households (90%) and slightly lower very food insecure households (2%), compared to 2014 

estimates for the entire state (88% food secure, 4% very food insecure; ADF&G, 2016).

Subsistence Resources

Participation in subsistence

Data from the NSB 2015 Census indicate that there is a high level of participation in subsistence 

activities in NSB households (nearly 99% in all NSB communities). In 2015, 95% or more of NSB Iñupiat 

households reported consuming subsistence foods. The 2010 NSB Census found that participation was 

high among both men and women (Table 6). Subsistence foods also make up a significant portion of 

food consumed in NSB communities. 
18

Table 6. NSB Iñupiat household head’s participation in subsistence activities

Subsistence Activity Men Women

Participation in spring whaling 44% 27%

Participate in fall whaling 31% 23%

Hunt sea mammals 55% 17%

Hunt land mammals 69% 30%

Fish 70% 49%

Hunt birds 61% 22%

Gather bird eggs 14% 7%

Pick berries and plants 44% 45%

Share, cook, and process wild foods 79% 82%

Sew skins and clothes 10% 42%

Make sleds and boats 38% 6%

Trap fur bearers 9% 1%

Source: NSB, 2012; NSB Census, 2010

The annual wild food harvest in 2014 for Nuiqsut was approximately 371,992 pounds in useable weight 

for the entire community, an average of 3,444 pounds per household and 896 pounds per person

(ADF&G, 2016). In terms of usable weight, marine mammals provided 46 percent of the harvest while 

large land animals (29 percent of harvest), non-salmon fish (23 percent of harvest), salmon (1% of 

harvest), birds and eggs (1 percent of harvest), and berries and edible plants (<1 percent of harvest) 

contributed the rest. Table 7 shows the resources most commonly used by Nuiqsut households in 2014. 

Marine mammals and non-salmon fish were particularly important resources for Nuiqsut. In terms of 

edible weight, marine mammals (bowhead whale; bearded, ringed, and spotted seals) accounted for 

46% of the total wild foods harvested. Non-salmon fish (primarily Arctic cisco, broad whitefish, least 

cisco, Arctic grayling, and burbot) accounted for nearly one quarter of the 2014 Nuiqsut subsistence 

harvest (ADF&G, 2016). 

Table 7. Subsistence resources most commonly used by Nuiqsut households, 2014

Resource Percentage of households using resource

Bowhead whale 93%

Caribou 90%

Arctic cisco 83%

White-fronted goose 74%

Broad whitefish 72%

Bearded seal 67%

Cloudberry 62%

Ringed seal 52%

Moose 43%

Blueberry 40%

Source: ADFG, 2016

NSB communities also have strong sharing networks for subsistence resources. Typically, about 30% of 

rural households in Alaska harvest about 70% of subsistence resources used in a community (Wolfe, 

2004). A 2015 study found that in two North Slope communities, Kaktovik and Wainwright, only 25% of 

subsistence resources in a household were from the households’ own harvesting efforts, which indicates 
19 

substantial sharing of subsistence resources. Strong sharing networks within and between communities 

are crucial for social, cultural, health, and economic well-being. Strong sharing networks can also 

encourage community members, such as young adults, to take pride in harvest subsistence resources 

and participate in the cooperative traditions within their community; this is important for maintaining 

cultural continuity in a community. 

Summary

Areas of Vulnerability

• NSB households, particularly Anaktuvuk Pass, reported high levels of food insecurity. More than

one in three NSB household heads reported difficulty getting the food needed to eat healthy

meals, and approximately 24% of household heads reported that at times in the previous year,

household members did not have enough to eat.

Areas of Resilience/Success

• There is a high level of participation in subsistence activities and sharing subsistence resources

among NSB households. Subsistence foods also make up a substantial portion of food consumed

in NSB communities. These determinants are crucial to an individual’s health and well-being, as

well as ensuring cultural continuity within a community.

HEC 5: Infectious Diseases

Reportable communicable (infectious) diseases include infectious and parasitic diseases, such as 

tuberculosis, viral hepatitis, sexually transmitted infectious (STIs), influenza, and pneumonia. 

With the exception of STIs, the number of cases of reportable infectious diseases in the NSB is very low. 

Because of the small number of cases of reportable infectious diseases each year, reliable prevalence 

rates for the NSB cannot be calculated for most individual reportable diseases. Trends in reportable 

infectious diseases in the NSB are generally comparable to those occurring statewide (NSB, 2012).

Reportable communicable diseases were not among the leading causes of death in the NSB. Pneumonia 

(2 deaths) and septicemia (1 death) were the only causes of death due to infectious diseases, accounting 

for less than 2% of all deaths from 2011-2013 (ABVS, 2015). No influenza deaths were reported during 

the same time period. 
20

Sexually Transmitted Infections

Chlamydia rates

Chlamydia is a common STI and is caused by the bacterium Chlamydia trachomatis (CT). CT can cause 

pelvic inflammatory disease (PID), ectopic pregnancy, infertility, and preterm labor. Infants born to 

infected women are at risk for neonatal conjunctivitis and pneumonia. Untreated CT infections in men 

can cause epididymitis, Reiter syndrome, and infertility.

Alaska ranked first for CT rates nationwide from 2010-2014; rates disproportionately affect northern 

regions and AN. In 2015, the age-adjusted CT infection rate for the Northern Region (2,151 cases per 

100,000 population; includes NSB, Northwest Arctic Borough, and Nome Census Area) was nearly three

times higher than the rate statewide (766 cases per 100,000 population) and higher than any other 

region in Alaska (Figure 2; ADHSS, 2016b).

Figure 2. Chlamydia infection rates, by Region – Alaska 2014 and 2015

Source: ADHSS, 2016c

Gonorrhea rates

Gonorrhea is an STI caused by the bacterium Neisseria gonorrhea. Alaska had the third highest 

gonococcal infection rate in the nation in 2014 (ADHSS 2016a). The rate of gonorrhea in 2015 was 518

cases per 100,000 population for all races in the Northern Region, which was nearly 3.5 times the rate 

for Alaska statewide (151 cases per 100,000 population; Figure 3, ADHSS, 2016c). 

0 500 1000 1500 2000 2500

Gulf Coast

Southeast

Interior

Anchorage/Mat-Su

Statewide

Southwest

Northern

Cases per 100,000

2014

2015
21

Figure 3. Gonorrhea infection rates, by Region – Alaska 2014 and 2015

Source: ADHSS 2016c

Summary

Areas of Vulnerability

• The Northern region, which includes NSB communities, is disproportionately affected by 

chlamydia and gonorrhea. 

Areas of Resilience/Success

• The number of cases of reportable, non-STI, infectious diseases in the NSB is very low. 

HEC 6: Water and Sanitation

A high proportion of rural Alaska households (approximately 20%) are without basic sanitation facilities 

and adequate in-home water sources. Relying primarily on community-based water points can lead to 

inadequate amounts of water collected and increases the likelihood for disease transmission. 

The lack of clean running water and proper sewage disposal is a leading cause of preventable diseases in 

rural Alaskan villages and is directly linked to infectious disease morbidity and mortality. Respiratory, 

gastrointestinal, and skin diseases are common in areas without safe or easily accessible water supplies. 

In a study conducted in 6 regions in Alaska, regions with a lower proportion of in-home water service 

had 2.5 times the hospitalization rate of pneumonia and influenza and 2 times the rate of skin or soft 

tissue infection, and over 3 times the rate of respiratory syncytial virus among those younger than 5 

years, when compared to higher-service regions (Hennessy et al., 2008). 

0 100 200 300 400 500 600 700

Southeast

Gulf Coast

Interior

Statewide

Anchorage/Mat-Su

Southwest

Northern

Cases per 100,000

2014

2015
22

Water and Sewer Service Rates

In 2015, 92% of NSB households had access to running water (NSB Census, 2015). This indicates that the 

majority of households drink treated water rather than unfiltered surface water, which typically results 

in better water quality. This compares to almost 78% of households with modern water and sewer 

service for rural communities within the State of Alaska. 

According to the U.S. Census Bureau, 2010-2014 American Community Survey 5-Year Estimates, the 

proportion of households that lacked complete plumbing facilities were as follows: 10.6% in NSB, 6.9% 

in Utqiaġvik, 5.3% in Kaktovik, and 2.0% in Nuiqsut (U.S. Census ACS, 2014). 

According to the NSB, 90% of Nuiqsut households had sewage facilities and the remaining 10% used 

holding tanks. Similarly, 94% of drinking water was piped to Nuiqsut households and 6% was trucked 

(NSB, 2015). 

Nuiqsut’s water and sewer system is run with a vacuum pump, creating constant flow and reducing 

vulnerabilities to freezing pipes. Water operators in 2014 reported few issues with frozen lines. 

Community water is acquired during an approximate 40-day water making season from July to August, 

and the water source is a tundra lake located one mile south of town (Brubaker et al., 2014). While 

water operators noted few issues with freezing pipes, some water and sanitation infrastructure has 

been impacted by changing permafrost conditions; in 2014, operators reported small-scale permafrost 

erosion near an outflow pipe from the water tanks. Annual erosion also threatens the sewage outflow 

line (Brubaker et al., 2014).

Summary

Areas of Vulnerability

• Water and sanitation infrastructure is vulnerable to changing permafrost conditions.

Areas of Resilience/Success

• More than 94% of NSB household have modern water and sewer service.

HEC 7: Non-communicable and Chronic Diseases

Diabetes

Diabetes mellitus is a metabolic disease characterized by high blood sugar levels, which result from 

defects in insulin secretion, insulin resistance, or both. There are two types of diabetes, Type 1 and Type 

2. Type 2 is the most common type of diabetes, is associated with obesity, and is considered a

preventable illness. Uncontrolled diabetes can result in serious medical consequences.

From 2011-2013, there were 3 deaths attributed to diabetes in the NSB. Due to the small numbers, an 

associated rate was not reported. For the same time period, there were 324 deaths related to diabetes 

mellitus in Alaska (age-adjusted rate of 19.4 per 100,000 U.S. year 2000 population; ABVS, 2015).
23

The self-reported prevalence of adult diabetes among NSB residents from 2011-2013 was 6.5%, which 

was similar to the prevalence for AN statewide (7.7%) and all of Alaska (7.2%). Comparatively, the 

prevalence of prediabetes in adults was higher in the NSB than any other region from 2011-2013. The 

prevalence of prediabetes in the NSB was 13.3% compared to 10.0% for AN statewide and 8.0% for all of 

Alaska (BRFSS, 2016).

Overweight and Obesity

Obesity and overweight are terms that define an accumulation of fat that is greater than what is 

considered healthy. Body mass index (BMI) is a common indicator of obesity and overweight status. 

Overweight refers to persons who have a current BMI assessment with a BMI of 25 to 29.9 and obese 

refers to persons who have a current BMI assessment of 30 or greater. Being overweight or obese 

increases the risk of diabetes, diseases of the heart (mainly stroke and heart disease), cancer, and

premature death (WHO, 2016). 

The prevalence of adult overweight or obesity among NSB residents from 2011-2013 was 75.8%, which 

was higher than the prevalence for AN statewide (67.0%) and for all of Alaska (65.0%). NSB had the fifthhighest prevalence of overweight and obesity of all boroughs and census areas in Alaska (BRFSS, 2016).

Among NSB communities, the percent of overweight residents ranged from 17%-36% and the percent of 

obese residents ranged from 23%-48% (Table 8; NSB, 2012).

Table 8. Overweight and obesity among NSB households, 2012

Location Overweight Obese

Anaktuvuk Pass 32% 23%

Atqasuk 26% 38%

Kaktovik 34% 32%

Nuiqsut 28% 33%

Point Hope 29% 48%

Point Lay 17% 46%

Utqiaġvik 34% 40%

Wainwright 36% 41%

North Slope Borough 33% 39%

Alaska 37% 28%

Source: NSB, 2012

Cancer 

The prevalence of self-reported cancer in the NSB was lower than the prevalence statewide from 2011-

2013. For this time period, the prevalence of cancer in the NSB was 3.6% compared to 6.7% for AN 

statewide and 8.0% for all of Alaska (BRFSS, 2016). The NSB had the second lowest self-reported cancer 

prevalence of Alaska boroughs and census areas. 
24

During 2013-2015, cancer was the leading cause of death among NSB residents and among Alaskans 

statewide. Table 9 presents data from the Alaska Bureau of Vital Statistics that shows the age-adjusted 

rates for cancer deaths in the NSB are higher than those in the state as a whole. Lung cancer was the 

leading cause of death due to cancer (50.8 deaths per 100,000 persons, though this rate is based on 

small numbers and should be interpreted with caution; ABVS, 2016). 

Table 9. Cancer Deaths by Type, North Slope Borough and the State of Alaska, 2013-2016

Cause of Death

North Slope Borough State of Alaska

Number of 

Deaths

Age-Adjusted 

Rate1

Number of 

Deaths

Age-Adjusted 

Rates1

Malignant Neoplasms 44 327.8 2942 159.5

 Lip, Oral Cavity, and Pharynx 0 0 41 1.9

Esophagus 1 ** 94 5.0

Stomach 7 23.7* 89 4.6

Colon, Rectum, and Anus 9 30.4* 273 15.0 

 Liver and Intrahepatic Bile Ducts 2 ** 143 6.5

Pancreas 1 ** 195 10.3

 Larynx 0 0 12 0.6*

Trachea, Bronchus, and Lung 15 50.8* 765 41.4

 Skin 0 0 49 2.8

Breast 2 2 ** 195 19.6 

Cervical2 1 ** 19 1.6

 Uterine2 0 0 36 3.6

Ovarian2 1 ** 58 5.7

 Prostate2 1 ** 126 17.8

Kidney and Renal Pelvis 0 0 79 4.5

Bladder 0 0 54 3.3

Brain 0 0 74 3.5

Lymphoid & Hematopoietic 2 ** 236 13.5

Hodgkin’s Disease 0 0 2 **

Non-Hodgkin’s Lymphoma 0 0 86 4.9

Leukemia 2 ** 91 5.3

Multiple Myeloma 0 0 56 3.0

All Other Lymphoid & 

hematopoietic

0 0 1 **

All Other and Unspecified Cancers 3 ** 404 22.5

Source: ABVS, 2016 1

Age-Adjusted rates are per 100,000 U.S. year 2000 standard population 2 Breast, cervical, uterine and ovarian cancer rates are for females only and prostate cancer rates are for 

males only

* Rates based on fewer than 20 occurrences are statistically unreliable and should be used with caution

**Rates based on fewer than 6 occurrences are not reported
25

Cardiovascular and cerebrovascular disease mortality

The prevalence of self-reported diseases of the circulatory system (heart attack, angina, or stroke) in the 

NSB has consistently been lower than the prevalence statewide. In 2011-2013, the prevalence of 

cardiovascular disease was 4.2% compared to 5.8% for all of Alaska (BRFSS, 2016). When circulatory 

diseases were further categorized as heart attack, stroke, cardiovascular disease, or coronary disease, 

the prevalence was still lower in the NSB compared to statewide (BRFSS, 2016).

The mortality rate of major cardiovascular diseases from 2011-2013 was slightly lower in the NSB than 

all of Alaska (Table 10; ABVS, 2015).

Table 10. Major Cardiovascular Disease Deaths, North Slope Borough and the State of Alaska, 2011 - 

2013

Cause of Death

North Slope Borough State of Alaska

Number 

of Deaths

Age-Adjusted 

Rate1

Number of 

Deaths

AgeAdjusted 

Rate1

Major Cardiovascular Diseases 20 165.8 2866 189.9 

 Heart disease 14 84.7* 2146 137.7

Ischemic heart disease 7 24.8* 1225 74.3

Acute myocardial infarction 0 0.0 246 15.7

Atherosclerotic cardiovascular 

disease 

5 ** 450 22.8

All other ischemic heart disease 2 ** 529 35.9

All other heart disease 7 60.0* 921 63.4

Cerebrovascular disease 5 ** 544 40.4

All other cardiovascular diseases 1 ** 176 11.8

Source: ABVS, 2015 1 Age-adjusted rates are per 100,000 U.S. year 2000 standard population

* Rates based on fewer than 20 occurrences are statistically unreliable and should be used with caution

**Rates based on fewer than 6 occurrences are not reported

Chronic respiratory disease rates

Historically, chronic respiratory diseases have been a major cause of morbidity and mortality in rural 

Alaska, and respiratory problems remain a frequently cited health concern in NSB communities. The 

NSB 2010 Census asked household heads whether they or other household members had, in the last 12 

months, experienced any breathing problems such as asthma, emphysema, or a cough that does not go 

away. Thirteen percent of household heads and 8% of all adults in the NSB reported or were reported to 

have experienced any of these problems. The estimated prevalence of these respiratory problems did 

not vary significantly by ethnic group, gender, or community of residence. Of children aged 0–17 years, 

5% were reported by the household head to have had breathing problems such as asthma, emphysema, 

or a chronic cough in the past 12 months. There was not a statistically significant difference in the

relationship between village of residence and the prevalence of breathing problems among children

(NSB, 2012). 
26

Chronic lower respiratory disease mortality

Chronic lower respiratory disease (such as asthma or emphysema) is one of the most frequently stated

concerns in the NSB. In the NSB, chronic lower respiratory disease has been the fourth or fifth leading 

cause of death for most years since at least 1992, which is comparable to the state of Alaska in recent 

years. From 2013-2015, the age-adjusted chronic lower respiratory disease mortality rate was higher in 

the NSB compared to the rate statewide (Table 11). However, the NSB mortality rates were based on 

fewer than 20 deaths, and should therefore be interpreted with caution as the rate may be statistically 

unreliable (ABVS, 2016). 

Table 11. Chronic lower respiratory disease rates, NSB, 2013-2016

Detailed Cause of 

Death

NSB 

Deaths

Crude 

Rate1

Age-Adjusted 

Rate2

Alaska 

Deaths

Alaska 

Crude Rate1

Alaska AgeAdjusted Rate2

Chronic lower 

respiratory 

disease

11 37.2* 129.0* 593 26.8 37.2

Source: ABVS, 2016 1 Crude rates are per 100,000 population

2 Age-adjusted rates are per 100,000 U.S. year 2000 standard population

* Rates based on fewer than 20 occurrences are statistically unreliable and should be used with caution

Asthma

Asthma is a disease that affects the lungs and can cause repeated episodes of wheezing, breathlessness, 

chest tightness, and nighttime or early morning coughing (CDC, 2016a). There are multiple

environmental factors known to trigger or exacerbate asthma symptoms, including tobacco smoke, 

exhaust from heating sources and vehicles, and poor air quality (both outdoor and indoor air). Indoor air 

pollution is a particular concern in rural Alaska, primarily due to tightly sealed houses with inadequate

ventilation and prolonged time spent indoors (NSB, 2012).

The prevalence of self-reported asthma (‘Have you ever been told by a doctor, nurse, or other health 

professional that you have asthma?’) has consistently been lower in the NSB than the prevalence 

statewide. In 2011-2013, the prevalence of asthma was 9.7% compared to 14.4% of for all of Alaska

(BRFSS, 2016). 

In response to community concerns about asthma and pollution from nearby oil and gas development 

activities, ADHSS investigated air pollution and respiratory illness in Nuiqsut in 2003. The 2003 ADHSS 

study found no significant differences for respiratory visits and asthma in Nuiqsut compared to a 

similarly sized North Slope village for the years 1998-2002, except for the 10-19 years old age group. 

Because only one age group had a statistically higher rate of respiratory visits than the control village, it 

is unlikely that an air pollution source is the cause. If air pollution or another type of environmental 

contaminant were associated with clinic visits for respiratory conditions, most age groups would likely 

also see increased rates of respiratory visits. The study concluded that the increase in respiratory visits 

in Nuiqsut for 10-19 year olds was likely due to a few individuals with numerous clinic visits to address

asthma-related problems. (ADHSS SOE, 2003). 
27

COPD

Chronic obstructive pulmonary disease (COPD) is a disease that includes emphysema and chronic 

bronchitis. It is the most common form of chronic lower respiratory disease in adults. Cigarette smoking 

is the most common risk factor for COPD, but environmental and genetic factors can also contribute to 

the development of COPD.

In Alaska, COPD mortality rates have historically been higher among AN than Caucasians. COPD 

mortality rates have also increased among AN and have remained stable among whites in Alaska. The 

prevalence of self-reported COPD in the NSB was lower than the prevalence statewide from 2011-2013. 

For this time period, the prevalence of COPD in the NSB was 4.0% compared to 7.8% for AN statewide 

and 5.1% for all of Alaska (BRFSS, 2016).

HEC 8: Health Services Infrastructure and Capacity

The NSB and the Arctic Slope Native Association are jointly responsible for delivering health services to 

NSB residents (NSB, 2012). With the exception of Utqiaġvik, all NSB communities maintain a clinic that is 

staffed by medical personnel via the Community Health Aide Program (CHAP). These clinics do not have 

a physician or physician’s assistant in residence. The Samuel Simmonds Memorial Hospital (SSMH) is 

located in Utqiaġvik and is a 14-bed hospital with an outpatient unit that consists of a 6-room clinic and 

a 2-bed emergency room (Arctic Slope Native Association, 2010). Utqiaġvik is the tertiary care center for 

the NSB villages; cases are referred to Fairbanks or Anchorage if they cannot be admitted by SSMH. 

Utqiaġvik also has a community mental health center, a dental clinic, and is the location of the NSB

Department of Health and Social Services (NSB, 2012). 

Access to services is limited by the remote location of the villages, cost of travel, and severity of the 

climate (NSB, 2010). Many of the communities in the NSB suffer from chronic health care workforce 

shortages and turnover (NSB, 2012). The U.S. Health Resources and Services Administration 

characterizes the NSB as a medically underserved and health professional shortage area (NSB, 2012). In 

2016, there were only 0.4 licensed physicians per 1,000 population in the NSB, compared to 2.6 licensed 

physicians per 1,000 population statewide (ADPH, 2016). 

Summary

Areas of Vulnerability

• Access to adequate health services can be limited by cost, difficulty of travel (i.e., weather, 

logistics), and the capacity of clinics.

Areas of Resilience/Success

• Comprehensive health services are available in Utqiaġvik for residents throughout the NSB 

service area. 
28

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Appendices  Final Supplemental Environmental Impact Statement

Alpine Satellite Development Plan for the Proposed Greater Mooses Tooth 2 Development Project

APPENDIX H

BOEM GREENHOUSE GAS LIFECYCLE MODEL 

METHODOLOGY

The following sections are the relevant excerpts from the Bureau of Ocean Energy 

Management’s Outer Continental Shelf (OCS) Report 2016-065, Oil and Natural Gas: Potential 

Lifecycle Greenhouse Gas Emissions and Social Cost of Carbon (Wolvovsky, et al, 2016). The 

Bureau of Land Management used BOEM’s Lifecycle Greenhouse Gas Emissions Model to 

predict the indirect emissions of greenhouse gases from the GMT2 Project. The modeling 

methodology and key assumptions are outlined below. 
Greenhouse Gas Emissions Calculations Methodology

The following analysis includes emissions from the three largest GHGs: CO2, CH4, and N2O. 

Fluorocarbons are used in very small quantities in refrigeration and in circuit breakers offshore, but are 

not deliberately released. This makes quantifying them very difficult, but their contribution relative to 

CO2, CH4, and N2O emissions is very small; moreover, calculating fluorocarbon emissions would suggest 

the results have a greater degree of accuracy than is currently possible with available data. Additionally, 

the analysis has been spatially bounded to include emissions from U.S. consumption of OCS oil and gas, 

along with the substitution of sources for that energy under the No Action Alternative scenario where 

there is no 2017-2022 Program. The reasoning behind this is the insufficient data available for the kind 

and proportion of oil products used and a lack of information on overseas energy substitutions. The 

model estimates the emissions resulting from exploration, development, production, transportation to 

shore, onshore processing, delivery, and consumption of oil and gas products from the OCS, or their 

substitutes. This includes all OCS operations, as well as onshore refining, processing, storage, 

distribution, and consumption. It excludes emissions from secondary changes regarding OCS operations, 

such as BOEM’s and oil and gas companies’ office spaces, changes in vehicle fuel efficiency in response 

to changing market conditions, and others. 

The following three subsections detail the approach for estimating GHG emissions. The first subsection 

addresses emissions released from offshore operations. The second subsection describes scaling

emissions released as part of onshore processing and distribution, based on historic emission rates. 

Lastly, emissions resulting from consumption of petroleum and gas products are calculated using 

emissions factors and historic consumption patterns.

1.1 EMISSIONS FROM OCS EXPLORATION, DEVELOPMENT, PRODUCTION,

AND TRANSPORT

BOEM uses the Offshore Environmental Cost Model (OECM) to calculate the environmental and social 

costs and GHG emissions associated with oil and gas activity occurring on the OCS (BOEM 2015a, 

2015b). OECM provides estimates for the monetized impact of typical activities associated with OCS 

production, including potential oil spills (other than catastrophic oil spills) occurring on the OCS. OECM 

uses economic inputs, resource estimates, and expected exploration and development scenarios with 

expected numbers of wells and associated production as the basis for its calculations. GHG emissions 

from OCS operations are estimated as follows, and a single total emissions number is reported for each

of the three major GHGs: 
Equation 1:

PPPPoooooooohoooooo = �PPPPooeeeeeeeeeeooeeee

PEoffshore is the total emissions from offshore production in metric tons

PEequipment are the incremental emissions from using each piece of equipment 

such as drilling wells, constructing platforms, delivering supplies, and 

transporting resources to shore.

1.2 EMISSIONS FROM ONSHORE PROCESSING, STORAGE, AND 

DISTRIBUTION

Once onshore, oil is generally refined into petroleum products for specific uses, such as jet fuel, 

kerosene, and motor gasoline. A ratio of expected OCS production, to crude oil inputs, to refineries is 

used to scale emissions from refineries. Crude oil input data from 2014 (EIA 2016d) are used in 

coordination with 2014 GHG emissions from refineries (EPA 2016a). The same approach is used for 

natural gas storage and transmission; a ratio of OCS production and national gas consumption in 2014

(EIA 2016a) is used to scale the U.S. Environmental Protection Agency’s (EPA) (2016a) inventory of 

natural gas systems emissions. It is assumed emissions from these activities are in proportion to the 

amount of oil and gas that make their way through these processes.

Equation 2. 

PPPPoo oohoo = RRoo oo

OOOOOOOOOOOO

OOOOOOTT TT

+ SSSS nn

NNNNOOOOOO

NNNNTT TT ee oooo ee

ooee oo ee ooee oo

PEonshore is total emissions from onshore processing in metric tons

Roil is total emissions from all oil refining onshore in metric tons (EPA 2016a)

SDng is total emissions from storage and distribution of natural gas in metric tons 

(EPA 2016a)

OilOCS and OilTotal are oil expected to be produced on the OCS, and total U.S. oil 

refinery inputs in 2014 (EIA 2016d), respectively in barrels (bbl)

NGOCS and NGTotal are natural gas expected to be produced on the OCS, and total 

U.S. natural gas consumption from 2014 (EIA 2016a), respectively in millions of 

standard cubic feet (mmcf)

This equation is repeated for each of the GHGs being analyzed (CO2, CH4, and N2O). Roil and SDng are 

summed from EPA’s (2016a) most recent inventory. Roil includes emissions data from the following:

• Table 3-37 (Refining)

• Table 3-39 (Crude Refining)

SDng includes emissions data (EPA 2016a) from the following: 

• Table 3-47 (Processing, Transmission and Storage, Distribution)

• Table 3-50 (Processing, Transmission and Storage, Distribution) 
After being refined, oil is primarily transported using oil products as an energy source (EPA 2008). To 

avoid double counting, motor and other oils estimated in Section 4.3, are assumed to be consumed in 

proportion to the transportation of OCS oil. For more information on this assumption, see Section 7.

1.3 EMISSIONS FROM CONSUMPTION

All oil and gas is assumed to be consumed in U.S. markets (for details on this assumption see Section 7). 

To determine the types of petroleum products Americans consume and in what proportion, EIA’s 

(2016b) national 2015 consumption reports are used. A ratio is generated by dividing the national 

consumption of each petroleum product by overall oil consumption.

Equation 3. 

CC = OOOOOO

OOOOOOTT TT

ee

ee

ooee oo

Where Ci is the consumption factor for end use of a petroleum product 

Oili is the national consumption for a petroleum product in bbls 

(EIA 2016b)

OilTotal is total oil products consumed nationally in bbls (EIA 2016b)

This calculation is repeated for each petroleum product quantified by EIA and is used to generate 

Table 4-1 below.

Table 4-1. U.S. 2015 Oil Consumption

Petroleum Product 2015 Consumption

(1000s of Gallons)

2015 Consumption

(% of Total)

Asphalt and Road Oil 5,258,190 1.95

Aviation Gasoline 175,018 0.06

Distillate Fuel Oil 60,999,348 22.62

Jet Fuel (Kerosene Type) 23,574,985 8.74

Kerosene 110,097 0.04

Propane 17,223,255 6.39

Other Liquid Petroleum Gases 19,205,935 7.12

Lubricants 2,069,550 0.77

Motor Gasoline 140,380,643 52.06

Petroleum Coke 127,811 0.05

Residual Fuel Oil #6 94,444 0.04

Other Oil 452,022 0.17

Source: EIA 2016b

Note: Forty-two gallons is equal to 1 barrel of oil

When oil is refined, the volume of product increases as a result of the addition of other ingredients used 

to make each petroleum product. This volume increase is called the production gain. Currently, EIA 

estimates production gain to be 6.7 percent across all petroleum products (EIA 2015).

By allocating expected OCS production proportionately, based on the petroleum products and 

incorporating oil production gain, BOEM can apply EPA’s recommended emissions factors for GHG 
inventories (see Table 4-2). These categories of petroleum products do not match up perfectly between

EIA and EPA. In two cases, distillate and residual fuel oils, there are multiple EPA emissions factors for a 

single EIA product category. In these instances, the amount of oil is evenly split among the possible 

emissions factors. This is a reasonable approximation since the fuel types are used enough in the 

U.S. for EPA to have researched and developed emissions factors for each. This does not have a major 

effect on the overall analysis since the emissions factors for the different distillate and residual fuel oil 

categories are very similar.

Table 4-2. Petroleum Emissions Factors for Greenhouse Gas Inventories in kg/gallons

Petroleum Product CO2 CH4 N2O

Asphalt and Road Oil 11.91 0.00047 0.00009

Aviation Gasoline 8.31 0.00036 0.00007

Distillate Fuel Oil #1 10.18 0.00042 0.00008

Distillate Fuel Oil #2 10.21 0.00041 0.00008

Distillate Fuel Oil #4 10.96 0.00044 0.00009

Jet Fuel (Kerosene Type) 9.75 0.00041 0.00008

Kerosene 10.15 0.00041 0.00008

Propane 5.72 0.00027 0.00005

Other Liquid Petroleum Gases 5.86 0.00028 0.00006

Lubricants 10.69 0.00043 0.00009

Motor Gasoline 8.78 0.00038 0.00008

Petroleum Coke 14.64 0.00043 0.00009

Residual Fuel Oil #5 10.21 0.00042 0.00008

Residual Fuel Oil #6 11.27 0.00045 0.00009

Other Oil (> 401oF) 10.59 0.00042 0.00008

Source: EPA 2015

Some oil and natural gas are used as an ingredient for non-combustible products such as fertilizer and 

petrochemicals; this portion is removed from the consumption calculations since these products are not 

combusted and their use does not result in GHG emissions. EIA reports that 1.6 percent of all natural 

gas and 1.2 percent of all oil is never combusted (EIA 2012). Thus, the estimation for emissions from 

consumption of OCS oil is a summation of the emissions from each distinct petroleum product, as shown 

in Equation 4 below: 
Equation 4. 

CC oo oo = PP ∗ CC oo oo(1 − NN oo oo) ∗�[CC ∗ EE ] ∗ 1,000

=

=1

PP ee NN PP ee CC ee ee PP ee

ee ee

ee

CEoil is total emissions from oil consumption in metric tons

PG is the percent processing gain 

CPoil is OCS oil produced in gallons

NCoil is the proportion of oil which is not combusted

Ci is the consumption factor for end use of a petroleum product (ratio, see

Equation 3)

EFi is the emission factor for each petroleum product in kilograms (kg) per 

gallon. 

i refers to each of the petroleum products listed in Table 4-2. 

1,000 converts kg to metric tons

Since natural gas is not refined into other combustible products, there is no processing gain; moreover, 

there is only a single product to assess even though natural gas is used in different markets. EPA (2015) 

provides a single set of emissions factors for natural gas (see Table 4-3), making the estimation straight 

forward, as follows: 

Equation 5. 

CCPPeenn = CCPPeenn(1 − NNCCeenn) ∗ PPEEee ∗ 1,000

CEng is total emissions from natural gas consumption in metric tons, 

CPng is natural gas produced and consumed in mmcf, 

NCng is the proportion of natural gas that is not combusted in mmcf, and 

EFi is the emission factor for natural gas in kg per mmcf

1,000 converts kg to metric tons

Table 1-3. Natural Gas Emissions Factors for Greenhouse Gas Inventories in kg/scf

Petroleum Product CO2 CH4 N2O

Natural Gas 0.05444 0.00103 0.00010

Source: EPA 2015

Finally, total emissions, in metric tons, can be summed as Etotal: 

Equation 6. 

= PPPPoooooooohoooooo + PPPPoo oohoooooo + CC oo oo + CC nn 
1.4 EMISSIONS FROM ENERGY SUBSTITUTES

To evaluate the difference between new OCS oil and gas leasing during the 2017–2022 Program and a 

No Action Alternative (i.e., no new leases in the 2017–2022 Program), BOEM uses information from EIA 

to estimate energy sources that would be used in absence of the 2017–2022 Program to meet energy 

demand. The determination of energy substitutes adopts EIA’s assumptions that account for current 

laws, not potential future policies that could reduce emissions. BOEM estimates the GHG emissions that 

would otherwise be emitted from the other sources of energy Americans could use in place of OCS oil 

and gas from new leasing. Energy substitution includes meeting energy needs from other sources of oil 

and natural gas such as production from state submerged lands, onshore domestic production, and 

international imports. Coal, biofuels, and nuclear and renewable energy sources are substituted for OCS 

oil and gas in lesser amounts. In addition, it is assumed that there would be some conservation 

measures, including reduced demand and consumption of all energy sources due to higher oil and gas 

prices in the absence of new OCS resource availability. To determine the amount of GHG emissions for 

substituted energy sources, BOEM estimates the lifecycle emissions of the oil, gas, and other sources of 

energy used to replace OCS oil and gas.
Changes in energy consumption patterns are estimated using BOEM’s energy market simulation model, 

MarketSim (Industrial Economics, Inc. 2015). MarketSim is the same model used to evaluate

substitutions in the 2017–2022 Program economic analysis. This model simulates end-use domestic 

consumption of oil, natural gas, coal, and electricity in four sectors (residential, commercial, industrial, 

and transportation); primary energy production; and the transformation of primary energy into 

electricity. MarketSim mostly represents U.S. energy markets, but also captures interaction with world 

energy markets as appropriate. The model takes current measures of energy production, consumption, 

and prices assuming no new OCS leasing as a baseline to which a given scenario of OCS production is 

added. Accounting for substitution between different sources of energy, the model calculates 

equilibrating prices for oil, natural gas, coal, and electricity based upon the expected increase in OCS 

production of oil and gas. 

For purposes of these GHG calculations, BOEM assumes nuclear, biofuels, solar, and wind sources have 

negligible GHG emissions at final consumption either because the emissions are small by unit, or 

because the amount of substituted emissions are less than one percent (BOEM 2015a, 2015b, and 

2016). These negligible emissions are not analyzed in this report with one exception. Although coal is 

expected to substitute for a very small portion of OCS oil and gas (less than one percent in the 2017–

2022 Program), its higher rate of GHG emissions per unit of energy makes it worth evaluating. Coal is 

expected to substitute for natural gas in electrical power generation. BOEM uses EPA’s (2015) emissions 

factors (see Table 4-4) combined with the substitution rate estimated by MarketSim to calculate 

emissions from coal (see Equation 7).

Table 4-4. Coal Emissions Factors for Greenhouse Gas Inventories in kilograms/million British Thermal Units

Emissions Source CO2 CH4 N2O

Mixed (Electric Power Sector) 95.52 11 1.6

Source: EPA 2015

Equation 7.

CCccooeeoo = OOccooTToo ∗ PPEEccooTToo ∗ 1000

Ccons is the emissions from the consumption of substituted coal in metric tons 

Ocoal is the amount of coal replacing OCS products in British thermal units 

EFcoal is the emissions factor for Mixed Coal (Electric Power Sector) in metric 

tons per British thermal unit (EPA 2015)

1000 converts kg to metric tons

The overall emissions as a result of substitution are totaled using emissions from exploration, 

development, production (including tankering), processing, storage and distribution, and consumption 

of the substituted resources. OECM, the model used to calculate offshore emissions (see Section 4.1), 

provides similar emissions values for non-OCS production. This includes emissions from oil, gas, coal, 

and other substituted sources of energy. If the energy, such as oil, is substituted by foreign sources, the 

GHG emissions released from bringing these products to the U.S. are included. 
The summation of production and consumption of substituted sources is reflected in the following 

equation:

Equation 8.

PPeenn = OOeeoooonn + CCPPoo ooee ∗ SSoo ooee + CCPPeenn ∗ SSeenn + CCccooeeoo

End is the total emissions from oil and gas consumption when there is no new 

drilling on the OCS in metric tons

Oprod is the total emissions of all substituting sources in metric tons as estimated 

in OECM

CEoil and CEng are total emissions from oil (see Equation 4) and natural gas (see 

Equation 5); consumption is in metric tons

Soil and Sng are the oil and gas substitution rates, estimated by MarketSim

Ccons is the emissions from the consumption of substituted coal in metric tons 

(see Equation 8)

Oprod in Equation 8 originates from OECM, which assumes oil production overseas is more GHG-intensive 

than production on the OCS. For example, CO2 emissions occurring on the OCS are approximately 

0.007759 metric tons per barrel of oil equivalent (boe) versus overseas production, which OECM 

estimates at 0.036522 metric tons per boe. This relationship between OCS and foreign oil production 

has been corroborated by other studies (Gordon 2015). To a lesser degree, these higher emissions can 

also be attributed to OECM assuming two-way trips of tankers bringing oil to the U.S.

To support calculating the SC-CO2, and to provide a direct comparison between the three different 

pollutants calculated, BOEM uses Global Warming Potential, also known as CO2e. The purpose behind 

converting into a CO2e is to provide a direct comparison between emissions with different potential to 

trap heat and different atmospheric lifespans. For example, one metric ton of CH4 has a similar impact 

as 25 metric tons of CO2e. EPA’s (2015) conversion factors are used (see Table 4-5).

Table 4-5. Global Warming Potential in Metric Tons

Greenhouse Gas Global Warming

Potential (CO2e)

CO2 1

CH4 25

N2O 298

Source: EPA 2015

Key Assumptions

This analytical model makes a number of assumptions, which could reduce its accuracy; the 

assumptions are characterized here. The principal variable in this estimation is the production 

estimates of OCS oil and gas; the underlying uncertainty in the estimates of the amount of oil and gas to 

be produced has a profound impact on overall accuracy. These production estimates are a critical input 

into MarketSim and OECM, models which in turn necessarily rely on a series of assumptions. Other 

critical assumptions that affect the GHG emissions estimates are as follows:
1. Near constant demand is assumed over the next 40–70 years for oil and gas. 

This analysis uses a projection of near constant demand over the next 40–70 years using the 2016 AEO 

Reference Case, for which EIA does not assume any future changes in laws or policies other than what is 

incorporated in existing laws and policies. As countries, including the U.S., address climate change with 

individual policy targets, this assumption could no longer hold. Additionally, as new energy sources 

become more economically feasible, they could displace existing sources and/or alter the composition 

of energy supply. The Reference Case is the best baseline currently available. This analysis could be 

adapted in the future to incorporate policy shifts that affect demand for oil and gas.

2. Engines used for production, processing, and consumption of oil and gas will not become more 

efficient, and oil and gas will remain a primary energy source. 

Historically, engines have become increasingly efficient both in the offshore and onshore environments, 

but those engines by and large have remained dependent on fossil fuels. Moreover, the President’s 

Climate Action Plan (White House 2013) calls for energy and transport efficiency improvements, 

including transitioning from more intense GHG energy sources. One of the key tenets of the President’s 

Climate Action Plan is the reduction of methane from oil and gas production facilities. Efficiency 

improves through the need for greater economy, and also through Government regulation. These 

changes could alter the fuel type or quantity of oil and gas used to generate power. Similar changes will 

impact other types of oil and gas products, such as lubricants and plastics. These changes will alter more

than just the amount of oil, but the portion of each barrel being consumed by any sector. For instance, 

in 2015, motor gasoline represented 52 percent of all oil products by volume. As battery technologies

continue to improve, plug-in electric vehicle prices could continue to drop (Nyvist and Nilsson 2015), and 

the percent of oil used for motor gasoline could drop as the share of electric vehicles increases. 

However, as the American electrical grid is increasingly dependent on natural gas, such shifts could 

increase demand for those resources.

Figure 3 shows how consumption patterns of oil have changed in the past, including the rise of jet fuel 

and motor gasoline use, and the contraction of residual fuel oil use. Despite these longer-term shifts, 

petroleum products maintain a reasonable level of continuity from year to year. For example, motor 

gasoline, the largest consumed petroleum product, has never exceeded 52 percent (2015) of total 

consumption, nor has it dropped below 39 percent (1980) since 1950. During that entire time, it 

remained the largest petroleum product consumed by Americans. 
Figure 1. Historical U.S. Average Consumption per day of Petroleum Products by Year (1950 – 2015) 

in Thousands of Barrels (EIA 2016b)

Without a definitive method of estimating oil consumption and petroleum markets for the coming 

70 years, it is impossible to predict how oil and gas consumption will change. Using 2015 data still 

provides a useful approximation of consumption because the consumption patterns have not radically 

changed over the short-term. Longer-term trends could be incorporated by keeping the model 

uptodate with consumption patterns. It is likely that efficiency will continue to improve, meaning less 

oil and gas will be required to generate the same amount of energy. This also affects upstream 

calculations, including the offshore exploration, development, and production, and onshore processing, 

storage, and distribution. This impacts both the evaluation of OCS activities, as well as energy 

substitutions, thereby still allowing a user to directly compare emissions.

These assumptions are necessary because it is uncertain how oil consumption will change in the future. 

However, this assumption is reasonable because of the historical stability in proportionality of 

petroleum product consumption.

3. All oil and gas on OCS leases is produced, processed, and consumed. 

This analysis assumes all the oil and gas expected to be discovered on the OCS is produced, processed, 

and consumed. In reality, some oil and gas is lost, either by not being brought to production, or through 

inefficiencies at various stages of processing and distribution or other incidents, such as spills. These 

results assume that all oil removed from the OCS makes its way through to a customer and is consumed 

with perfect efficiency. This assumption is currently the only way to conduct this analysis currently; 

however, it ensures emissions will not be underestimated. Petroleum products that are not combusted 

are accounted for in this analysis.

0

5000

10000

15000

20000 Asphalt/Road Oil

Aviation Gasoline

Distillate Fuel Oil

Jet Fuel

Kerosene

Liquid Petroleum Gas (including

Propane)

Lubricants

Motor Gasoline
4. ‘Other’ oils, distillate fuel oil, and residual fuel oil are approximated.

There are several places where EIA’s consumption categories do not match with EPA’s emissions factors. 

Since EIA groups pentanes, petrochemical feedstocks, naptha-type jet fuel, still gas, waxes, and crude oil 

into a single ‘Other’ category, EPA’s ‘Other Oil (> 401o

F)’ emissions factors are used. Similarly, EPA has 

two emissions factors for ‘Residual Fuel Oil’ and three for ‘Distillate Fuel Oil,’ but EIA reports distillate 

and residual fuel oils broadly. As a result, it is assumed there is equal consumption for each emissions 

factor, with half of residual fuel oil using each EPA emissions factor, and a third of oil for each distillate 

fuel oil emission factor. These assumptions reduce the model’s accuracy. See Table 4-2 for both 

residual and distillate fuel oil emissions factors. This assumption is necessary given the uncertainty of 

how these fuels are consumed, but it is reasonable given how similar EPA’s emissions factors are for 

each petroleum product with multiple emissions factors.

5. Production gain is equal across all petroleum products and steady over time.

Production gain is the increase in volume as oil is refined into petroleum products. Although all 

petroleum products have a production gain, it is not the same for each product. Currently, EIA (2015)

estimates production gain as 6.7 percent, but that will likely change in the future. This assumption is 

necessary given the lack of available information regarding the production gain of individual fuels.

6. All oil and gas is consumed domestically. 

Emissions from the export of U.S.-produced oil and gas are relatively minor compared to the amount 

produced, processed, and consumed domestically. This assumption slightly underestimates the 

emissions from transportation of these products to other countries. Since emissions factors for natural 

gas do not vary, if they are consumed overseas, their emissions factors remain the same. However, 

since oil is consumed in a variety of products, which have a wide range of emissions factors, there is 

some loss in accuracy for petroleum products consumed overseas, since other counties do not consume 

these products in identical proportions to the U.S. Even with the loss of accuracy, approximating global 

emissions from oil using the United States as the example provides a reasonable example of oil 

consumption. These assumptions are reasonable given the small amount of oil and gas products 

exported (EIA 2016e).

7. OCS oil is refined into the same petroleum products and consumed in the same proportions as oil 

and gas nationally. 

It is likely OCS oil is refined into specific petroleum products, and those products are not in the same 

proportions as oil from all sources. However neither BOEM nor EIA have information specifically 

identifying what petroleum products OCS oil is refined into, and in what proportions. Should more 

specific information about the type of products OCS oil is refined into become available; the analytical 

model would be adjusted to accommodate such information. This assumption is necessary given the 

current lack of information.
8. Oil transportation is powered with oil in proportion to the overall production. 

According to the EPA (2008), the vast majority of transporting oil to market is powered with petroleum 

products. It is therefore assumed this oil is consumed in proportion to the oil produced from the OCS. 

Since this oil is already accounted for as part of the consumption calculations, there is no additional 

attempt to incorporate these emissions separately, which would result in double counting these 

emissions. 

9. The percent of oil and gas that remains un-combusted is the same as 2011.

Since EIA (2012) has not updated their non-combusted use of fossil fuels since 2011, this is the most 

uptodate information available. Similar to other assumptions, this no-change assumption reduces the 

overall accuracy of the analysis.

10. The reduction in foreign consumption of oil and gas in a no action analysis is not taken into 

account.

Although MarketSim estimates a foreign reduction in consumption, MarketSim provides the reduction 

for oil only. MarketSim does not model natural gas fluctuations in the global market. However, for the 

global oil market, MarketSim substitutions under the No Action Alternative show a reduction in foreign 

oil consumption of approximately 1, 4, and 6 billion barrels of oil for the low-, mid-, and high-price 

scenarios, respectively, over the duration of the 2017–2022 Program. GHG impacts for this reduction in 

oil consumption, as well as possible changes for natural gas, are not captured in this analysis.

The implications for oil and gas production in other countries relating to U.S. decisions about issuing 

leases are highly uncertain. In the substitution analysis based on MarketSim, the assumption is made 

that other oil producing countries will supply oil for U.S. import without additional restraints due to 

GHG-related policies in those countries. This might change in the future if other countries establish 

policies to achieve their GHG-related targets.

Excluding the foreign oil and gas markets is reasonable. Oil consumption in each country is different, 

and BOEM does not have information related to which countries would consume less oil. This is 

important information since consumption patterns vary by country. For gas consumption, BOEM does 

not have information related to how changes in the U.S. market would affect other countries.
References 

Bureau of Ocean Energy Management (BOEM). 2016a. Final Programmatic EIS for 2017-2022 OCS Oil 

and Gas Program. Available online at http://www.boemoceaninfo.com. 

BOEM. 2015a. Forecasting Environmental and Social Externalities Associated with Outer Continental 

Shelf Oil and Gas Development – Volume 1: The 2015 Revised Offshore Environmental Cost Model. 

Prepared by: Industrial Economics, Inc.; Applied Sciences Associates, Inc.; Northern Economics; Dr. 

Nicholas Z. Muller; and SC&A, Inc. OCS Study BOEM 2015-052. 

BOEM. 2015b. Forecasting Environmental and Social Externalities Associated with Outer Continental 

Shelf Oil and Gas Development – Volume 2: Supplemental Information to the 2015 Revised OCEM. 

Prepared by: Industrial Economics, Inc.; and SC&A, Inc. OCS Study BOEM 2015-053.

Energy Information Administration (EIA). 2016a. Natural Gas Consumption by End Use. Available online 

at https://www.eia.gov/dnav/ng/ng_cons_sum_dcu_nus_a.htm. Accessed May 16, 2016.

EIA. 2016b. Petroleum Products Supplied by Type. Available online at http://www.eia.gov/totalenergy/ 

data/monthly/pdf/sec3_15.pdf. Accessed May 16, 2016.

EIA. 2016e. How much petroleum does the United States import and export? Available online at 

http://www.eia.gov/tools/faqs/faq.cfm?id=727&t=6. Accessed September 15, 2016.

EIA. 2015. Refining Crude Oil. Available online at http://www.eia.gov/energyexplained/ 

index.cfm?page=oil_refining#tab3. Accessed May 17, 2016.

EIA. 2012. Non-Combustion Use of Fossil Fuels 1980-2011. Available online at https://www.eia.gov/ 

totalenergy/data/annual/showtext.cfm?t=ptb0115. Accessed May 13, 2016.

Environmental Protection Agency (EPA). 2016a. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 

1990 – 2014. Available online at https://www3.epa.gov/climatechange/Downloads/ ghgemissions/USGHG-Inventory-2016-Main-Text.pdf. Accessed August 31, 2016.

EPA. 2016b. Understanding Global Warming Potentials. Available online at https://www.epa.gov/ 

ghgemissions/understanding-global-warming-potentials. Accessed August 31, 2016.

EPA. 2015. Emission Factors for Greenhouse Gas Inventories. Available online at https://www.epa.gov/ 

sites/production/files/2015-12/documents/emission-factors_nov_2015.pdf. Accessed May 13, 2016.

EPA. 2008. Compilation of Air Pollutant Emission Factors, Publication AP-42, Section 5.2 Transportation 

and Marketing of Petroleum Liquids. Available online at www.epa.gov/ttnchie1/ap42. Office of Air 

Quality Planning and Standards, Research Triangle Park, NC.

Industrial Economics, Inc., 2015. Consumer Surplus and Energy Substitutes for OCS Oil and Gas 

Production: The 2015 Revised Market Simulation Model (MarketSim). OCS Study BOEM 2015-054.
Gordon, D. et al. 2015. Know your Oil. Carnegie Endowment for International Peace. Available online at 

http://carnegieendowment.org/files/know_your_oil.pdf. Accessed October 31, 2016.

Nykvist B. and M. Nilsson. 2015. Rapidly falling costs of battery packs for electric vehicles. Nature 

Climate Change, vol. 5, issue 4, pp. 329-332.

Wolvovsky, E. and Anderson, W. 2016. OCS Oil and Natural Gas: Potential Lifecycle Greenhouse Gas 

Emissions and Social Cost of Carbon. BOEM OCS Report 2016-065. 44 pp. Accessed from: 

https://www.boem.gov/ocs-oil-and-natural-gas/

Appendices  Final Supplemental Environmental Impact Statement

Alpine Satellite Development Plan for the Proposed Greater Mooses Tooth 2 Development Project

APPENDIX I

REQUEST FOR DEVIATIONS FROM LEASE 

STIPULATIONS AND BEST MANAGEMENT PRACTICES

.,..,,,, Bradley C. Thomas 

Coordinator - New Developments 

ConocoPhillips Alaska, Inc. 

700 G Street, ATO-1970 

Alaska Anchorage, AK 9951 0 

ConocoPhillips 

phone 907.263.4741 

bradlct@conocophillips.com 

October 30, 2017 

Ms. Stephanie Rice 

Planning and Environmental Specialist 

Bureau of Land Management (BLM) 

222 W. 7th Avenue, #13 

Anchorage, AK 99513 

Re: Request for Deviations from Lease Stipulations and Best Management Practices 

GMT2 Development 

Dear Ms. Rice: 

ConocoPhillips Alaska, Inc. (CPAI), as Operator on behalf of the working interest owners of the Greater 

Mooses Tooth (GMT) Unit, seeks Bureau of Land Management (BLM) approval for two deviations from 

lease stipulations and Best Management Practices (BMPs) for the GMT2 project. Two of the deviations 

requested here were also requested and approved in 2015 for GMT1 project. The deviations would allow 

the GMT2 access road to be the shortest length, on the driest land with the lowest habitat value. 

Background on BMPs and Lease Stipulations 

The scheme for lease stipulations and BMPs has become complicated as National Petroleum Reserve -

Alaska (NPR-A) Integrated Activity Plans (IAP) have been revised over the years. Oil and gas leases in 

the GMT2 project are were issued in 1999, subject to stipulations identified in the detailed statement of 

sale for NPR-A Oil and Gas Lease Sale 991, which are also reflected in the Record of Decision (ROD) for 

the 1998 NPR-A Integrated Activity Plan (1998 ROD). The 1998 ROD clearly anticipated and provided for 

exceptions to lease stipulations upon a finding that implementation of a stipulation is (1) technically not 

feasible, economically prohibitive, or that an environmentally preferable alternative is available, and (2) 

the alternative means proposed fully satisfies the objective of the stipulations. See Appendix B to 1998 

ROD. Thus, the lease stipulations were not intended to be inflexible, and were not intended to preclude or 

unduly impede reasonable oil and gas development proposals. 

The suite of lease stipulations and BMPs (previously called Required Operating Procedures, or ROPs) 

were modified and supplemented in the ROD for the 2008 Integrated Activity Plan (2008 ROD). The 2008 

ROD did not purport to apply the modified lease stipulations to pre-existing leases, but in connection with 

lease extension applications, CPAI notified BLM, in a letter dated April 6, 2009, that it "will apply the 

IAP/EIS lease stipulations and Required Operating Procedures under the 2008 Record of Decision ." The 

2008 stipulations and BMPs were essentially reiterated in the 2013 ROD for the most recent NPR-A IAP 

(2013 ROD). 

In short, most Greater Mooses Tooth Unit leases are subject to the lease stipulations set forth in the 2008 

ROD, and subject to BMPs set forth in the 2013 ROD. Both documents clearly allow for deviations. As 

stated on page 43 of the 2013 ROD: "A lessee/permittee may propose a deviation from the 

requirements/standards of stipulations and best management practices as part of an authorization 

application." The two provisions from which CPAI is seeking approved deviations are set forth in 

Attachment 1. 
Deviation Request for Lease Stipulation E-2 (Facilities Within 500 Feet of Water Bodies) 

CPAI first seeks a deviation from Lease Stipulation E-2 (2008), which prohibits permanent oil and gas 

facilities, including roads and pipelines, within 500 feet of fish bearing water bodies and aquatic habitats. 

A map illustrating all rivers, streams, and lakes within 500 feet of the Alternative A facilities is included as 

Attachment 2 for reference. As shown on that map, the road route for Alternative A comes within 500 of 

one named lake (M9925). 

The objective of Lease Stipulation E-2 is to protect fish-bearing waterbodies, water quality, and aquatic 

habitats. In the 2013 IAP, Stipulation E-2 was clarified to apply only to fish-bearing waterbodies. The 

terms of Lease Stipulation E-2 in both the 2008 and 2013 versions expressly provide: "Essential pipeline 

and road crossings will be permitted on a case-by-case basis." 

The GMT2 project area, like much of the North Slope, contains abundant lakes, rivers, streams, creeks, 

and ponds. These water bodies are prevalent because the area is underlain by permafrost, which 

generally prohibits drainage. Additionally, this area is classified as wetlands, attesting to presence of 

numerous water bodies. The 2004 Alpine Satellite Development Plan EIS (Sections 3.2.1.1 and 3.2.2.1) 

states: 

• "The tundra covered Arctic Coastal Plain . . . is generally characterized by periglacial features 

associated with flat topography, poor drainage, and underlying permafrost. Thaw-lakes and 

polygonal surface patterns on inter-lake ice wedges are the dominant terrain features." 

• "Abundant thaw-lakes and marshy thaw-lake basins, generally only a few feet deep, cover 25 to 

30 percent of the landscape." 

• "Lakes and ponds are the most prevalent features of the Plan Area. " 

Because of the abundance of water bodies in the area, it is not technically possible, let alone technically 

feasible, to locate all facilities farther than 500 feet from the highest high-water mark of all active 

floodplains. CPAI selected the proposed locations for pads, roads, and pipelines by balancing 

engineering, habitat, economics, hydrology, and other environmental factors, such as avoiding bird nest 

locations, to the extent possible. Maintaining a distance of 500 feet from every water body, while also 

minimizing gravel footprint, is not practicable in this environment. 

Even where facilities need to be placed closer than 500 feet from a water body, the objective of Lease 

Stipulation E-2, protection of water quality, would still be satisfied. Standard practices such as pipeline 

inspections and other spill prevention efforts will protect water bodies from potential spills to the extent 

possible. Secondary containment for tanks, tank inspection procedures, and refueling practices minimize 

the chance of a potential tank spill leaving a pad and entering a water body. Spill response equipment will 

be staged near sensitive areas and agency approved spill plans will be in place. 

BLM granted approval an exception from this requirement in 2004, based on technical infeasibility of total 

compliance due to the hydrology and number of water bodies in the area as well as implementation of 

other measures that would protect water bodies (e.g., use of secondary containment). 1 BLM reaffirmed 

this decision, speaking terms of a "deviation" rather than an exception, for the GMT1 development at 

page 7 of the GMT1 ROD, issued in 2015. CPAI now requests confirmation that the 2004 exception 

remains in effect to allow the location of facilities closer than 500 feet from water bodies where necessary 

based on other environmental and engineering factors. 

1 In the 2004 Alpine Satellite Development Plan ROD, this Lease Stipulation is referred to on page 3 as "Stipulation 

41." 

2 
Deviation Request for BMP E-7c (500 Feet Between Pipelines and Roads) 

CPAl's second request is for a deviation from BMP E-7c., which requires a minimum distance of 500 feet 

between pipelines and roads. A map illustrating the locations where the pipeline route would put the 

within 500 feet of the proposed gravel road is included as Attachment 3 for reference. Four stretches of 

the Alternative A road and pipeline routes locate the pipeline within 500 feet of the gravel road. These are 

3,990 feet of road and pipeline near lake M9925, 3,909 feet near lake M9923, 4,803 feet near lake 

Z06005, and 1,195 feet near lake R0062. These particular distances and locations may change subject 

to potential pipeline route modifications. 

The objective of BMP E-7c is to minimize disruption of caribou movement and subsistence use. The 

standard is for pipelines and roads to be designed to allow the free movement of caribou and the safe, 

unimpeded passage of the public while participating in subsistence activities. The BMP also states: 

"Separating roads from pipelines may not be feasible within narrow land corridors between lakes and 

where pipelines and roads converge on a drill pad. Where it is not feasible to separate pipelines and 

roads, alternative pipeline routes, designs and possible burial within the road will be considered by the 

authorizing officer. " 

Separating the pipeline from the gravel road by more than 500 feet, while also staying 500 feet away from 

nearby lakes, is not feasible at locations 1-4 marked in Attachment 3. Location 2 is also narrowed by the 

need to keep the road out of the Fish Creek setback. The nearest the road comes to the pipeline at 

location 1 is approximately 359 feet, at location 2, 337 feet, at location 3, 269 feet, and at location 4, 458 

feet. 

Even where pipelines and roads would be placed closer than 500 feet, the objective of BMP E-7c, that the 

pipelines and roads would be designed to allow the free movement of caribou and the safe, unimpeded 

passage of the public while participating in subsistence activities, will still be satisfied. The pipeline height 

will be a minimum of 7 feet allowing unimpeded passage, and road pullouts have been proposed to 

support subsistence activities and provide a safe place for subsistence hunters to rendezvous while 

hunting or traveling to camp and cabin sites. 

For the reasons set forth above, CPAI requests a deviation from ROP E-7c as necessary to allow certain 

stretches of road and pipeline to be less than 500 feet apart. 

Conclusion 

CPAl 's proposed project design minimizes environmental impact, but requires minor deviations from just 

two of the approximately 70 lease stipulations and BMPs that apply to the project. Please call me if you 

have any questions or need additional information about this request. 

Respectfully, 

Brad Thomas 

~ 

cc: 

Stacie McIntosh, BLM 

Stephen Moore, USAGE 

Louise Smith, USFWS 

Jennifer Curtis, USEPA 

3 
References: 

U.S. Department of Interior, Bureau of Land management (BLM). 2015. Supplemental 

Environmental Impact Statement (EIS) for the Alpine Satellite Development Plan for the 

Proposed Greater Mooses Tooth One Development Project Record of Decision (ROD). U.S. 

Department of the Interior, Bureau of Land management, Anchorage, Alaska. U.S. Department 

of the Interior, Bureau of Land management, Anchorage, Alaska . 

. 2013. National Petroleum Reserve-Alaska (NPR-A). Final Integrated Activity Plan 

(IAP)/Environmental Impact Statement (EIS) Record of Decision (ROD) . 

. 2008. Northeast National Petroleum Reserve Alaska Integrated Activity 

Plan(IAP)/Environmental Impact Statement (EIS) Record of Decision (ROD). BLM/AK/PL05/002+3130+931 . 

. 2004. Alpine Satellite Development Plan Record of Decision (ROD). BLM/AK/PL05/002+3130+931 

.1998. Northeast National Petroleum Reserve Alaska Integrated Activity Plan/Environmental 

Impact Statement Record of Decision. U.S. DOI , Bureau of Land Management. 

4 
Attachment 1 

Lease Stipulation and Best Management Practices 

Requiring Exception for GMT1 Alternative A 

E-2 Lease Stipulation (2008) 

Objective: Protect fish-bearing water bodies, water quality, and aquatic habitats. 

Requirement/Standard: Permanent oil and gas facilities, including roads, airstrips, and pipelines, 

are prohibited upon or within 500 feet as measured from the ordinary high-water mark of fishbearing waterbodies. Essential pipeline and road crossings will be permitted on a case-by-case 

basis. 

E-7c Best Management Practice 

Objective: Minimize disruption of caribou movement and subsistence use. 

Requirement/Standard: Pipelines and roads shall be designed to allow the free movement of 

caribou and the safe, unimpeded passage of the public while participating in subsistence 

activities. Listed below are the accepted design practices: 

c. A minimum distance of 500 feet between pipelines and roads shall be maintained. Separating 

roads from pipelines may not be feasible within narrow land corridors between lakes and where 

pipelines and roads converge on a drill pad. Where it is not feasible to separate pipelines and 

roads, alternative pipeline routes, designs and possible burial within the road will be considered 

by the authorized officer. 

5 
151 °4S'0"W 151"40'0"\N 1~W35'0'W 151"30'0'W 151-:25'0"W 

GMT2 

Alternative A 

Fish Bearing Waterbodies 

within 500 ft of Infrastructure 

GMT2 Alt B (Proposed) 

,A./ Pipeline w~hin 500' of Fish 

Bearing Waterbody 

Fish Bearing Waterbody 

within 500 Feet of 

Infrastructure 

500' Buffer of Lake M9925 

GMT1 (Pennitted) 

.......• Pipellne 

1 

----===::iMiles 

Attachment 2: Fish Bearing Water Bodies within 500 Feet of Infrastructure 
GMT2 

Alternative A 

Road Toe within 

500 feet of Pipeline 

GMT2 Alt B /Proposed) 

500' Pipeline Butler 

GMT1 /Permitted) 

•#•. • Pipeline 

·....::...-_ 

----====Miles 

ConocciPhillips Alaska, Inc. 

October 10, 2017 

151.45'0"\N 151•40•0-w 151"35'0'W 151930'0"W 

1 

Fish Creek Setback 

Attachment 3: Road Toe within 500 Feet of Pipeline 

2 

Appendices  Final Supplemental Environmental Impact Statement

Alpine Satellite Development Plan for the Proposed Greater Mooses Tooth 2 Development Project

APPENDIX J

NPR-A INTEGRATED ACTIVITY PLAN 

BEST MANAGEMENT PRACTICES AND 

STATE OF ALASKA REGULATIONS PROTECTING 

ENVIRONMENTAL QUALITY

APPENDIX A: LEASE STIPULATIONS 

AND BEST MANAGEMENT PRACTICES 

Definitions 

The following definitions apply to the stipulations and best management 

practices listed in this appendix. The Glossary of the Final IAP/EIS has 

additional definitions. 

Active Floodplain: The lowland and relatively flat areas adjoining inland 

and coastal waters, including the flood-prone areas of offshore islands, 

composing, at a minimum, that area subject to a 1 percent or greater chance 

of flooding in any given year (also referred to as the 100-year or base 

floodplain). 

Authorized Officer: A position of authority for approval of various 

activities through delegation from the Secretary of the Interior. Currently, 

the designated authorized officers in Alaska for leasing, surface use, and 

permitting are 1) State Director, 2) Manager of the Arctic Field Office in 

Fairbanks, and 3) Deputy State Director, Division of Resources. 

Best Management Practice: Mitigation developed through the BLM 

planning process/NEPA process that is not attached to the oil and gas lease 

but is required, implemented, and enforced at the operational level for all 

authorized (not just oil and gas) activities in the planning area. 

Best management practices were developed with various mechanisms in 

place to ensure compliance. These mechanisms include the following: 

1. Some best management practices are pre-application requirements; 

therefore compliance will precede approval of the proposed activity. 

For example, Best Management Practice H-1(a) requires consultation 

with affected communities prior to submission of an application for 

relevant activities within the NPR-A. If consultation has not taken 

place, the application will be rejected or will be considered 

incomplete until such time that the consultation has occurred. 

2. Other best management practices are required design features, and 

will have to be incorporated into the applicant’s proposal. As an 

integral part of the proposal and the authorization, the requirement 

February 2013 Appendix A: Lease Stipulations and Best Management Practices 

NPR-A IAP Record of Decision 

39 
does not need to be stipulated to be enforceable. For example, a 

minimum pipeline height of 7 feet for above ground pipelines is a 

required design of any approved above ground pipeline (Best 

Management Practice E-7). Since the authorization (a ROW in this 

case) authorizes a pipeline with a minimum height of 7 feet, anything 

less (unless specifically approved through additional NEPA analysis 

and the permit) is not in compliance and enforcement actions may be 

taken even if the permit does not specify a minimum of 7 feet. 

3. Other best management practices will become conditions of approval 

on post lease land use authorizations. For example, Best Management 

Practice C-1 prohibits heavy equipment used for cross-country moves 

within 1⁄2 mile of occupied grizzly bear dens. 

Body of Water or Water body: A lake, river, stream, creek, or pond that 

holds water throughout the summer and supports a minimum of aquatic life. 

Buffer: A zone extending outward or inward from the periphery of a 

“protected” feature for a specified distance. Activities and development may 

be prohibited or limited by type or time within the buffer dependent on the 

goal associated with applying the buffer. 

Class I air quality area: One of 156 protected areas such as national parks 

(over 6,000 acres), wilderness areas (over 5,000 acres), national memorial 

parks (over 5,000 acres), and international parks that were in existence as of 

August 1977, where air quality should be given special protection. Federal 

Class I areas are subject to maximum limits on air quality degradation called 

air quality increments (often referred to as Prevention of Significant 

Deterioration [PSD] increments). All areas of the United States not 

designated as Class I are Class II areas. The air quality standards in Class I 

areas are more stringent than national ambient air quality standards. 

Consultation: Consultation, as it is referenced in the lease stipulations, does 

not infer formal consultation as required under other legal mandates such as 

“Section 7 Consultation” under the ESA. Rather, consultation implies that 

the BLM or the Lessee/Permittee will contact other agencies or entities to 

inform them of potential actions and to seek input on noted topics. This 

includes informal contacts, and written, electronic, and/or verbal 

communication. 

February 2013 Appendix A: Lease Stipulations and Best Management Practices 

NPR-A IAP Record of Decision 

40 
Criteria Air Pollutants: Those pollutants subject to the National Air 

Quality Standards (http://www.epa.gov/air/criteria.html). They currently 

include carbon monoxide (CO), lead (Pb), nitrogen dioxide (NO2), ozone 

(O3), particulate matter (both PM10 and PM2.5 – inhalable and respirable 

particulates), and sulfur dioxide (SO2). 

Development Activities: Any activity associated with construction and 

operation of facilities or equipment post exploration. 

Field: The term used to describe the area containing surface infrastructure 

above one or more subsurface reservoirs. In this sense, “field” is analogous 

to “a Unit participating area or collection of participating areas.” The 

infrastructure in the field includes, but is not limited to, drilling and 

production pads, service roads, perhaps an airstrip, and processing and 

support facilities. Field infrastructure may be used in the development and 

production of several oil/gas accumulations in different subsurface 

reservoirs. Fields typically have a primary reservoir that supports initial 

development in addition to satellite reservoirs that are developed later and tie 

into the main facilities. Although oil and gas reservoirs may vary greatly in 

subsurface depth and other geologic characteristics, because they are located 

in the same geographic area it is more efficient to coordinate and share the 

necessary surface infrastructure. Fields may or may not be connected by 

permanent roads to adjacent fields or transportation facilities outside the 

field area. 

Greenhouse gas (GHG): A gas that absorbs and emits thermal radiation 

within the lowest layers of the atmosphere. This process is the fundamental 

cause of the greenhouse effect. The primary greenhouse gases that are 

considered air pollutants are carbon dioxide, (CO2), methane (CH4), nitrous 

oxide (N2O), and chlorofluorocarbons (CFCs). 

Hazardous air pollutants (HAPs): (also known as toxic air pollutants) 

Those pollutants that cause or may cause cancer or other serious health 

effects, such as reproductive effects or birth defects, or adverse 

environmental and ecological effects. The Environmental Protection Agency 

(EPA) is required to control 187 hazardous air pollutants. Examples of 

HAPs include benzene (found in gasoline), perchlorethlyene (emitted from 

dry cleaning facilities), and methylene chloride (used as a solvent). 

February 2013 Appendix A: Lease Stipulations and Best Management Practices 

NPR-A IAP Record of Decision 

41 
 

Lease Stipulation: Mitigation developed through BLM planning 

process/NEPA process that is specifically attached to a lease. 

NOx: Mono-nitrogen oxides, including nitric oxide (NO) and nitrogen 

dioxide (NO2). It is formed when naturally occurring atmospheric nitrogen 

and oxygen are combusted with fuels in automobiles, power plants, 

industrial processes, and home and office heating units. 

Permanent Oil and Gas Facilities: Permanent Facilities include production 

facilities, pipelines, roads, airstrips, production pads, docks and other 

bottom-founded structures, seawater-treatment plants, and other structures 

associated with an oil and gas operation that occupy land for more than one 

winter season; also included are material sites such as sand and gravel, and 

“temporary platforms” if those platforms are used for production rather than 

exploration. Exploration wellheads and seasonal facilities such as ice roads 

and ice pads are excluded, even when the pads are designed for use in 

successive winters. This definition does not include over-summering ice 

pads for exploration purposes. 

Setback: A distance measured from a named ground feature, such as a river 

or lake, in which certain activities or structures would not be allowed. All 

setback distances are to be measured as of the time of the application for a 

permit for a development. In addition, facility development along the coast 

would be required to be designed to maintain the prescribed setback distance 

for the anticipated life of the facility. 

SOx: Sulfur oxides, including sulfur dioxide (SO2). A product of vehicle 

tailpipe emissions. 

Stipulation: A requirement or condition placed by the Bureau of Land 

Management on the leaseholder for operations the leaseholder might carry 

out within that lease. The Bureau of Land Management develops stipulations 

that apply to all future leases within the National Petroleum Reserve-Alaska. 

Temporary Platform: A facility that does not require the use of an ice or 

gravel pad to support oil and gas and related exploration activities. An 

example of a temporary platform recently used on the North Slope is 

Anadarko Petroleum's Arctic Drilling Platform used for the company's Hot 

Ice Project during the winters of 2003-2004. The facility consisted of a 

series of platform modules joined together and supported above the tundra 

February 2013 Appendix A: Lease Stipulations and Best Management Practices 

NPR-A IAP Record of Decision 

42 
surface on steel legs. Once the project was completed the platform was 

disassembled and the support legs were removed, leaving the tundra surface 

undisturbed. Note: A temporary platform that is used for production, as 

opposed to exploration, would be considered a permanent oil and gas facility 

and be subject to the restrictions on placement of such structures. 

Valid existing: in the context of exceptions for the development of “valid 

existing NPR-A oil and gas leases,” “valid existing” leases refers to oil and 

gas leases issued by the BLM prior to the signing of this record of decision 

and valid at the time of the application for approval of an action for which 

the “valid existing NPR-A oil and gas lease” exception is requested. 

Volatile Organic Compounds (VOCs): A group of chemicals that react in 

the atmosphere with nitrogen oxides in the presence of sunlight and heat to 

form ozone. VOCs contribute significantly to photochemical smog 

production and certain health problems. Examples of VOCs are gasoline 

fumes and oil-based paints. 

Applicability of Requirements/Standards 

All surface disturbing activities such as exploratory drilling, road/pipeline 

construction, seismic acquisition, and overland moves require additional 

authorization(s) issued subsequent to leasing. The stipulations and best 

management practices require that certain protections of resources and uses 

be achieved. Requirements and standards listed with the stipulations and 

best management practices represent BLM’s current understanding of how 

lessees/permittees would achieve the objectives of the stipulation or best 

management practice. 

A lessee/permittee may propose a deviation from the requirements/standards 

of stipulations and best management practices as part of an authorization 

application. Prior to approving an alternative procedure as part of the 

authorization, BLM’s staff would analyze the proposal and determine if the 

proposal incorporating the alternative procedure would achieve the 

objectives of the stipulations and best management practices. If the BLM 

determines that the alternative procedure proposed by the applicant would 

meet the stipulation’s or best management practice’s objective, BLM could 

approve the alternative procedure. If BLM determines that the alternative 

procedure proposed by the applicant is unlikely to meet the objectives of a 

February 2013 Appendix A: Lease Stipulations and Best Management Practices 

NPR-A IAP Record of Decision 

43 
stipulation or best management practice, the requirements/standards would 

still be required. However, the authorized officer may allow a deviation 

from the objectives and requirement/standard in a new decision document 

supported by additional NEPA analysis. 

The BLM could independently require different actions than those listed 

under requirements/standards. If, after experience or additional study, BLM 

concludes that a requirement/standard is not achieving or is unlikely to 

achieve the protective objective when applied to a specific future on-theground action or would not do so as well as the use of recently proven 

technology or techniques, BLM could at the permitting stage and under the 

terms of the stipulation or best management practice, impose other 

restrictions to meet the objective. 

Stipulations and Best Management Practices 

Waste Prevention, Handling, Disposal, Spills, Air Quality, and Public 

Health and Safety 

A-1 Best Management Practice 

Objective: Protect the health and safety of oil and gas field workers and the 

general public by disposing of solid waste and garbage in accordance with 

applicable federal, State, and local law and regulations. 

Requirement/Standard: Areas of operation shall be left clean of all debris. 

A-2 Best Management Practice 

Objective: Minimize impacts on the environment from non-hazardous and 

hazardous waste generation. Encourage continuous environmental 

improvement. Protect the health and safety of oil field workers and the 

general public. Avoid human-caused changes in predator populations. 

Requirement/Standard: Lessees/permittees shall prepare and implement a 

comprehensive waste management plan for all phases of exploration and 

development, including seismic activities. The plan shall be submitted to the 

authorized officer for approval, in consultation with federal, State, and North 

Slope Borough regulatory and resource agencies, as appropriate (based on 

agency legal authority and jurisdictional responsibility), as part of a plan of 

operations or other similar permit application. 

Management decisions affecting waste generation shall be addressed in the 

following order of priority: 1) prevention and reduction, 2) recycling, 3) 

February 2013 Appendix A: Lease Stipulations and Best Management Practices 

NPR-A IAP Record of Decision 

44 
treatment, and 4) disposal. The plan shall consider and take into account the 

following requirements: 

a. Methods to avoid attracting wildlife to food and garbage. The plan 

shall identify precautions that are to be taken to avoid attracting 

wildlife to food and garbage 

b. Disposal of putrescible waste. Requirements prohibit the burial of 

garbage. Lessees and permitted users shall have a written procedure to 

ensure that the handling and disposal of putrescible waste will be 

accomplished in a manner that prevents the attraction of wildlife. All 

putrescible waste shall be incinerated, backhauled, or composted in a 

manner approved by the authorized officer. All solid waste, including 

incinerator ash, shall be disposed of in an approved waste-disposal 

facility in accordance with EPA and Alaska Department of 

Environmental Conservation regulations and procedures. The burial of 

human waste is prohibited except as authorized by the authorized 

officer. 

c. Disposal of pumpable waste products. Except as specifically provided, 

the BLM requires that all pumpable solid, liquid, and sludge waste be 

disposed of by injection in accordance with EPA, Alaska Department 

of Environmental Conservation, and the Alaska Oil and Gas 

Conservation Commission regulations and procedures. On-pad 

temporary muds and cuttings storage, as approved by Alaska 

Department of Environmental Conservation, will be allowed as 

necessary to facilitate annular injection and/or backhaul operations. 

d. Disposal of wastewater and domestic wastewater. The BLM prohibits 

wastewater discharges or disposal of domestic wastewater into bodies 

of fresh, estuarine, and marine water, including wetlands, unless 

authorized by a National Pollutant Discharge Elimination System or 

State permit. 

A-3 Best Management Practice 

Objective: Minimize pollution through effective hazardous-materials 

contingency planning. 

Requirement/Standard: For oil- and gas-related activities, a hazardous 

materials emergency contingency plan shall be prepared and implemented 

before transportation, storage, or use of fuel or hazardous substances. The 

plan shall include a set of procedures to ensure prompt response, 

notification, and cleanup in the event of a hazardous substance spill or threat 

of a release. Procedures in the plan applicable to fuel and hazardous 

substances handling (associated with transportation vehicles) shall consist of 

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best management practices if approved by the authorized officer. The plan 

shall include a list of resources available for response (e.g., heavy-equipment 

operators, spill-cleanup materials or companies), and names and phone 

numbers of federal, State, and North Slope Borough contacts. Other federal 

and State regulations may apply and require additional planning 

requirements. All appropriate staff shall be instructed regarding these 

procedures. In addition contingency plans related to facilities developed for 

oil production shall include requirements to: 

a. provide refresher spill-response training to North Slope Borough and 

local community spill-response teams on a yearly basis, 

b. plan and conduct a major spill-response field-deployment drill 

annually, 

c. prior to production and as required by law, develop spill prevention 

and response contingency plans and participate in development and 

maintenance of the North Slope Subarea Contingency Plan for Oil and 

Hazardous Substances Discharges/Releases for the National 

Petroleum Reserve-Alaska operating area. Planning shall include 

development and funding of detailed (e.g., 1:26,000 scale) 

environmental sensitivity index maps for the lessee’s/permittee’s 

operating area and areas outside the lessee’s/permittee’s operating 

area that could be affected by their activities. (The specific area to be 

mapped shall be defined in the lease agreement and approved by the 

authorized officer in consultation with appropriate resource agencies.) 

Maps shall be completed in paper copy and geographic information 

system format in conformance with the latest version of the U.S. 

Department of Commerce, National Oceanic and Atmospheric 

Administration’s Environmental Sensitivity Index Guidelines. Draft 

and final products shall be peer reviewed and approved by the 

authorized officer in consultation with appropriate federal, State, and 

North Slope Borough resource and regulatory agencies. 

A-4 Best Management Practice 

Objective: Minimize the impact of contaminants on fish, wildlife, and the 

environment, including wetlands, marshes and marine waters, as a result of 

fuel, crude oil, and other liquid chemical spills. Protect subsistence resources 

and subsistence activities. Protect public health and safety. 

Requirement/Standard: Before initiating any oil and gas or related activity or 

operation, including field research/surveys and/or seismic operations, 

lessees/permittees shall develop a comprehensive spill prevention and 

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response contingency plan per 40 CFR § 112 (Oil Pollution Act). The plan 

shall consider and take into account the following requirements: 

a. On-site Clean-up Materials. Sufficient oil-spill-cleanup materials 

(absorbents, containment devices, etc.) shall be stored at all fueling 

points and vehicle-maintenance areas and shall be carried by field 

crews on all overland moves, seismic work trains, and similar 

overland moves by heavy equipment. 

b. Storage Containers. Fuel and other petroleum products and other 

liquid chemicals shall be stored in proper containers at approved 

locations. Except during overland moves and seismic operations, fuel, 

other petroleum products, and other liquid chemicals designated by 

the authorized officer that in total exceed 1,320 gallons shall be stored 

within an impermeable lined and diked area or within approved 

alternate storage containers, such as over packs, capable of containing 

110% of the stored volume. In areas within 500 feet of water bodies, 

fuel containers are to be stored within appropriate containment. 

c. Liner Materials. Liner material shall be compatible with the stored 

product and capable of remaining impermeable during typical weather 

extremes expected throughout the storage period. 

d. Permanent Fueling Stations. Permanent fueling stations shall be lined 

or have impermeable protection to prevent fuel migration to the 

environment from overfills and spills. 

e. Proper Identification of Containers. All fuel containers, including 

barrels and propane tanks, shall be marked with the responsible party's 

name, product type, and year filled or purchased. 

f. Notice of Reportable Spills. Notice of any reportable spill (as required 

by 40 CFR § 300.125 and 18 AAC § 75.300) shall be given to the 

authorized officer as soon as possible, but no later than 24 hours after 

occurrence. 

g. Identification of Oil Pans (“duck ponds”). All oil pans shall be 

marked with the responsible party’s name. 

A-5 Best Management Practice 

Objective: Minimize the impact of contaminants from refueling operations 

on fish, wildlife and the environment. 

Requirement/Standard: Refueling of equipment within 500 feet of the active 

floodplain of any water body is prohibited. Fuel storage stations shall be 

located at least 500 feet from any water body with the exception that small 

caches (up to 210 gallons) for motor boats, float planes, ski planes, and 

small equipment, e.g. portable generators and water pumps, are permitted. 

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The authorized officer may allow storage and operations at areas closer than 

the stated distances if properly designed to account for local hydrologic 

conditions. 

A-6 Best Management Practice 

Objective: Minimize the impact on fish, wildlife, and the environment from 

contaminants associated with the exploratory drilling process. 

Requirement/Standard: Surface discharge of reserve-pit fluids is prohibited. 

A-7 Best Management Practice 

Objective: Minimize the impacts to the environment of disposal of produced 

fluids recovered during the development phase on fish, wildlife, and the 

environment. 

Requirement/Standard: Discharge of produced water in upland areas and 

marine waters is prohibited. 

A-8 Best Management Practice 

Objective: Minimize conflicts resulting from interaction between humans 

and bears during oil and gas activities. 

Requirement/Standard: Oil and gas lessees and their contractors and 

subcontractors will, as a part of preparation of lease operation planning, 

prepare and implement bear-interaction plans to minimize conflicts between 

bears and humans. These plans shall include measures to: 

a. Minimize attraction of bears to the drill sites. 

b. Organize layout of buildings and work sites to minimize human/bear 

interactions. 

c. Warn personnel of bears near or on work sites and identify proper 

procedures to be followed. 

d. Establish procedures, if authorized, to discourage bears from 

approaching the work site. 

e. Provide contingencies in the event bears do not leave the site or 

cannot be discouraged by authorized personnel. 

f. Discuss proper storage and disposal of materials that may be toxic to 

bears. 

g. Provide a systematic record of bears on the work site and in the 

immediate area. 

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A-9 Best Management Practice 

Objective: Reduce air quality impacts. 

Requirement/Standard: All oil and gas operations (vehicles and equipment) 

that burn diesel fuels must use “ultra-low sulfur” diesel as defined by the 

Alaska Department of Environmental Conservation-Division of Air Quality. 

A-10 Best Management Practice 

Objective: Prevent unnecessary or undue degradation of the lands and 

protect health. 

Requirement/Standard: This measure includes the following elements: 

a. Prior to initiation of a NEPA analysis for an application to develop a 

central production facility, production pad/well, airstrip, road, gas 

compressor station, or other potential substantial air pollutant 

emission source (hereafter project), the authorizing officer (BLM) 

may require the project proponent to provide a minimum of one year 

of baseline ambient air monitoring data for any pollutant(s) of concern 

as determined by BLM if no representative air monitoring data are 

available for the project area, or existing representative ambient air 

monitoring data are insufficient, incomplete, or do not meet minimum 

air monitoring standards set by the Alaska DEC or the EPA. If BLM 

determines that baseline monitoring is required, this pre-analysis data 

must meet Alaska DEC and EPA air monitoring standards, and cover 

the year immediately prior to the submittal. Pre-project monitoring 

may not be appropriate where the life of the project is less than one 

year. 

b. The BLM may require monitoring for the life of the project depending 

on the magnitude of potential air emissions from the project, 

proximity to a federally mandated Class I area, sensitive Class II area 

(as identified on a case-by-case basis by Alaska DEC or a federal land 

management agency), or population center, location within or 

proximity to a non-attainment or maintenance area, meteorological or 

geographic conditions, existing air quality conditions, magnitude of 

existing development in the area, or issues identified during NEPA 

undertaken for the project. 

c. For an application to develop a central production facility, production 

pad/well, airstrip, road, gas compressor station, or other potential 

substantial air pollutant emission source, the project proponent shall 

prepare (and submit for BLM approval) an emissions inventory that 

includes quantified emissions of regulated air pollutants from all 

direct and indirect sources related to the proposed project, including 

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reasonably foreseeable air pollutant emissions of criteria air 

pollutants, volatile organic compounds, hazardous air pollutants, and 

greenhouse gases estimated for each year for the life of the project. 

The BLM will use this estimated emissions inventory to identify 

pollutants of concern and to determine the appropriate level of air 

analysis to be conducted for the proposed project. 

d. For an application to develop a central production facility, production 

pad/well, airstrip, road, gas compressor station, or other potential 

substantial air pollutant emission source, the BLM may require the 

proponent to provide an emissions reduction plan that includes a 

detailed description of operator committed measures to reduce project 

related air pollutant emissions including, but not limited to greenhouse 

gases and fugitive dust. 

e. For an application to develop a central production facility, production 

pad/well, airstrip, road, gas compressor station, or other potential 

substantial air pollutant emission source, the authorized officer may 

require air quality modeling for purposes of analyzing project direct, 

indirect or cumulative impacts to air quality. The BLM may require 

air quality modeling depending on the magnitude of potential air 

emissions from the project or activity, duration of the proposed action, 

proximity to a federally mandated Class I area, sensitive Class II area 

(as identified on a case-by-case basis by Alaska DEC or a federal land 

management agency), or population center, location within a nonattainment or maintenance area, meteorological or geographic 

conditions, existing air quality conditions, magnitude of existing 

development in the area, or issues identified during NEPA undertaken 

for the project. The BLM will determine the information required for 

a project specific modeling analysis through the development of a 

modeling protocol for each analysis. The authorized officer will 

consult with appropriate federal, State, and/or local agencies regarding 

modeling to inform his/her modeling decision and avoid duplication 

of effort. The modeling shall compare predicted impacts to all 

applicable local, State, and federal air quality standards and 

increments, as well as other scientifically defensible significance 

thresholds (such as impacts to air quality related values, incremental 

cancer risks, etc.). 

f. The BLM may require air quality mitigation measures and strategies 

within its authority (and in consultation with local, state, federal, and 

tribal agencies with responsibility for managing air resources) in 

addition to regulatory requirements and proponent committed 

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emission reduction measures, and for emission sources not otherwise 

regulated by Alaska DEC or EPA, if the air quality analysis shows 

potential future impacts to NAAQS or AAAQS or impacts above 

specific levels of concern for air quality related values (AQRVs). 

g. If ambient air monitoring indicates that project-related emissions are 

causing or contributing to impacts that would cause unnecessary or 

undue degradation of the lands, cause exceedances of NAAQS, or fail 

to protect health (either directly or through use of subsistence 

resources), the authorized officer may require changes in activities at 

any time to reduce these emissions to comply with the NAAQS and/or 

minimize impacts to AQRVs. Within the scope of BLM’s authority, 

the BLM may require additional emission control strategies to 

minimize or reduce impacts to air quality. 

h. Publicly available reports on air quality baseline monitoring, 

emissions inventory, and modeling results developed in conformance 

with this best management procedure shall be provided by the project 

proponent to the North Slope Borough and to local communities and 

Tribes in a timely manner. 

A-11 Best Management Practice 

Objective: Ensure that permitted activities do not create human health risks 

through contamination of subsistence foods. 

Requirement/Standard: A lessee proposing a permanent oil and gas 

development shall design and implement a monitoring study of contaminants 

in locally-used subsistence foods. The monitoring study shall examine 

subsistence foods for all contaminants that could be associated with the 

proposed development. The study shall identify the level of contaminants in 

subsistence foods prior to the proposed permanent oil and gas development 

and monitor the level of these contaminants throughout the operation and 

abandonment phases of the development. If ongoing monitoring detects a 

measurable and persistent increase in a contaminant in subsistence foods, the 

lessee shall design and implement a study to determine how much, if any, of 

the increase in the contaminant in subsistence foods originates from the 

lessee's activities. If the study determines that a portion of the increase in 

contamination in subsistence foods is caused by the lessee's activities, the 

authorized officer may require changes in the lessee’s processes to reduce or 

eliminate emissions of the contaminant. The design of the study/studies must 

meet the approval of the authorized officer. The authorized officer may 

consult with appropriate federal, State, and North Slope Borough agencies 

prior to approving the study/studies design. The authorized officer may 

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require/authorize changes in the design of the studies throughout the 

operations and abandonment period, or terminate or suspend studies if 

results warrant. 

A-12 Best Management Practice 

Objective: To minimize negative health impacts associated with oil spills. 

Requirement/Standard: If an oil spill with potential impacts to public health 

occurs, the BLM, in undertaking its oil spill responsibilities, will consider: 

a. Immediate health impacts and responses for affected communities and 

individuals. 

b. Long-term monitoring for contamination of subsistence food sources. 

c. Long-term monitoring of potential human health impacts. 

d. Perceptions of contamination and subsequent changes in consumption 

patterns. 

e. Health promotion activities and communication strategies to maintain 

the consumption of traditional food. 

Water Use for Permitted Activities 

B-1 Best Management Practice 

Objective: Maintain populations of, and adequate habitat for, fish and 

invertebrates. 

Requirement/Standard: Withdrawal of unfrozen water from rivers and 

streams during winter is prohibited. The removal of ice aggregate from 

grounded areas ≤4-feet deep may be authorized from rivers on a site-specific 

basis. 

B-2 Best Management Practice 

Objective: Maintain natural hydrologic regimes in soils surrounding lakes 

and ponds, and maintain populations of, and adequate habitat for, fish, 

invertebrates, and waterfowl. 

Requirement/Standard: Withdrawal of unfrozen water from lakes and the 

removal of ice aggregate from grounded areas ≤4-feet deep may be 

authorized on a site-specific basis depending on water volume and depth and 

the waterbody’s fish community. Current water use requirements are: 

a. Lakes with sensitive fish (i.e., any fish except ninespine stickleback or 

Alaska blackfish): unfrozen water available for withdrawal is limited 

to 15% of calculated volume deeper than 7 feet; only ice aggregate 

may be removed from lakes that are ≤7-feet deep. 

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b. Lakes with only non-sensitive fish (i.e., ninespine stickleback or 

Alaska blackfish): unfrozen water available for withdrawal is limited 

to 30% of calculated volume deeper than 5 feet; only ice aggregate 

may be removed from lakes that are ≤5. 

c. Lakes with no fish present, regardless of depth: water available for use 

is limited to 35% of total lake volume. 

d. In lakes where unfrozen water and ice aggregate are both removed, 

the total use shall not exceed the respective 15%, 30%, or 35% 

volume calculations. 

e. Additional modeling or monitoring may be required to assess water 

level and water quality conditions before, during, and after water use 

from any fish-bearing lake or lake of special concern. 

f. Any water intake structures in fish bearing or non-fish bearing waters 

shall be designed, operated, and maintained to prevent fish 

entrapment, entrainment, or injury. Note: All water withdrawal 

equipment must be equipped and must utilize fish screening devices 

approved by the Alaska Department of Fish and Game, Division of 

Habitat. 

g. Compaction of snow cover or snow removal from fish-bearing 

waterbodies shall be prohibited except at approved ice road crossings, 

water pumping stations on lakes, or areas of grounded ice. 

Winter Overland Moves and Seismic Work 

The following best management practices apply to overland moves, seismic 

work, and any similar cross-country vehicle use of heavy equipment on nonroaded surfaces during the winter season. These restrictions do not apply to 

the use of such equipment on ice roads after they are constructed. 

C-1 Best Management Practice 

Objective: Protect grizzly bear, polar bear, and marine mammal denning 

and/or birthing locations. 

Requirement/Standard: 

a. Cross-country use of heavy equipment and seismic activities is 

prohibited within 1⁄2 mile of occupied grizzly bear dens identified by 

the Alaska Department of Fish and Game unless alternative protective 

measures are approved by the authorized officer in consultation with 

the Alaska Department of Fish and Game. 

b. Cross-country use of heavy equipment and seismic activity is 

prohibited within 1 mile of known or observed polar bear dens or seal 

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birthing lairs. Operators near coastal areas shall conduct a survey for 

potential polar bear dens and seal birthing lairs and consult with the 

USFWS and/or NOAA-Fisheries, as appropriate, before initiating 

activities in coastal habitat between October 30 and April 15. 

C-2 Best Management Practice 

Objective: Protect stream banks, minimize compaction of soils, and 

minimize the breakage, abrasion, compaction, or displacement of vegetation. 

Requirement/Standard: 

a. Ground operations shall be allowed only when frost and snow cover 

are at sufficient depths to protect the tundra. Ground operations shall 

cease when the spring snowmelt begins (approximately May 5 in the 

foothills area where elevations reach or exceed 500 feet and 

approximately May 15 in the northern coastal areas). The exact dates 

will be determined by the authorized officer. 

b. Low-ground-pressure vehicles shall be used for on-the-ground 

activities off ice roads or pads. Low-ground-pressure vehicles shall be 

selected and operated in a manner that eliminates direct impacts to the 

tundra by shearing, scraping, or excessively compacting the tundra 

mat. Note: This provision does not include the use of heavy 

equipment such as front-end loaders and similar equipment required 

during ice road construction. 

c. Bulldozing of tundra mat and vegetation, trails, or seismic lines is 

prohibited; however, on existing trails, seismic lines or camps, 

clearing of drifted snow is allowed to the extent that the tundra mat is 

not disturbed. 

d. To reduce the possibility of ruts, vehicles shall avoid using the same 

trails for multiple trips unless necessitated by serious safety or 

superseding environmental concern. This provision does not apply to 

hardened snow trails for use by low-ground-pressure vehicles such as 

Rolligons. 

e. The location of ice roads shall be designed and located to minimize 

compaction of soils and the breakage, abrasion, compaction, or 

displacement of vegetation. Offsets may be required to avoid using 

the same route or track in the subsequent year. 

f. Motorized ground-vehicle use within the Colville River Special Area 

associated with overland moves, seismic work, and any similar use of 

heavy equipment shall be minimized within an area that extends 1 

mile west or northwest of the bluffs of the Colville River, and 2 miles 

on either side of the Kogosukruk and Kikiakrorak rivers and 

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tributaries of the Kogosukruk River from April 15 through August 5, 

with the exception that use will be minimized in the vicinity of 

gyrfalcon nests beginning March 15. Such use will remain 1/2 mile 

away from known raptor nesting sites, unless authorized by the 

authorized officer. 

C-3 Best Management Practice 

Objective: Maintain natural spring runoff patterns and fish passage, avoid 

flooding, prevent streambed sedimentation and scour, protect water quality, 

and protect stream banks. 

Requirement/Standard: Crossing of waterway courses shall be made using a 

low-angle approach. Crossings that are reinforced with additional snow or 

ice (“bridges”) shall be removed, breached, or slotted before spring breakup. 

Ramps and bridges shall be substantially free of soil and debris. 

C-4 Best Management Practice 

Objective: Avoid additional freeze-down of deep-water pools harboring 

over-wintering fish and invertebrates used by fish. 

Requirement/Standard: Travel up and down streambeds is prohibited unless 

it can be demonstrated that there will be no additional impacts from such 

travel to over-wintering fish or the invertebrates they rely on. Rivers, 

streams, and lakes shall be crossed at areas of grounded ice whenever 

possible. 

C-5 Best Management Practice 

Objective: Minimize the effects of high-intensity acoustic energy from 

seismic surveys on fish. 

Requirement/Standard: 

a. When conducting vibroseis-based surveys above potential fish 

overwintering areas (water 6 feet deep or greater, ice plus liquid 

depth), operators shall follow recommendations by Morris and Winters 

(2005): only a single set of vibroseis shots should be conducted if 

possible; if multiple shot locations are required, these should be 

conducted with minimal delay; multiple days of vibroseis activity 

above the same overwintering area should be avoided if possible. 

b. When conducting air gun-based surveys in freshwater, operators shall 

follow standard marine mitigation measures that are applicable to fish 

(e.g., Minerals Management Service 2006): operators will use the 

lowest sound levels feasible to accomplish their data-collection needs; 

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ramp-up techniques will be utilized (ramp-up involves the gradual 

increase in emitted sound levels beginning with firing a single air gun 

and gradually adding air guns until the desired operating level of the 

full array is obtained). 

c. When conducting explosive-based surveys, operators shall follow 

setback distances from fish-bearing waterbodies based on 

requirements outlined by Alaska Department of Fish and Game 

(1991). 

Oil and Gas Exploratory Drilling 

D-1 Lease Stipulation 

Objectives: Protect fish-bearing rivers, streams, and lakes from blowouts and 

minimize alteration of riparian habitat. 

Requirement/Standard: Exploratory drilling is prohibited in rivers and 

streams, as determined by the active floodplain, and fish-bearing lakes. 

D-2 Lease Stipulation 

Objective: Minimize surface impacts from exploratory drilling. 

Requirement/Standard: Construction of permanent or gravel oil and gas 

facilities shall be prohibited for exploratory drilling. Use of a previously 

constructed road or pad may be permitted if it is environmentally preferred. 

Facility Design and Construction 

E-1 Best Management Practice 

Objective: Protect subsistence use and access to subsistence hunting and 

fishing areas and minimize the impact of oil and gas activities on air, land, 

water, fish, and wildlife resources. 

Requirement/Standard: All roads must be designed, constructed, maintained, 

and operated to create minimal environmental impacts and to protect 

subsistence use and access to subsistence hunting and fishing areas. The 

authorized officer will consult with appropriate federal, State, and North 

Slope Borough regulatory and resources agencies prior to approving 

construction of roads. Subject to approval by the authorized officer, the 

construction, operation, and maintenance of oil and gas field roads is the 

responsibility of the lessee unless the construction, operation, and 

maintenance of roads are assumed by the appropriate governing entity. 

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E-2 Lease Stipulation 

Objective: Protect fish-bearing water bodies, water quality, and aquatic 

habitats. 

Requirement/Standard: Permanent oil and gas facilities, including roads, 

airstrips, and pipelines, are prohibited upon or within 500 feet as measured 

from the ordinary high water mark of fish-bearing waterbodies. Essential 

pipeline and road crossings will be permitted on a case-by-case basis. Note: 

Also refer to Stipulations/Best Management Practices K-1 and K-2. 

Construction camps are prohibited on frozen lakes and river ice. Siting of 

construction camps on river sand and gravel bars is allowed and encouraged. 

Where leveling of trailers or modules is required and the surface has a 

vegetative mat, leveling shall be accomplished through blocking rather than 

use of a bulldozer. 

E-3 Lease Stipulation 

Objective: Maintain free passage of marine and anadromous fish and protect 

subsistence use and access to subsistence hunting and fishing. 

Requirement/Standard: Causeways and docks are prohibited in river mouths 

or deltas. Artificial gravel islands and bottom-founded structures are 

prohibited in river mouths or active stream channels on river deltas. 

Causeways, docks, artificial islands, and bottom-founded drilling structures 

shall be designed to ensure free passage of marine and anadromous fish and 

to prevent significant changes to nearshore oceanographic circulation 

patterns and water quality characteristics. A monitoring program, developed 

in consultation with appropriate federal, State, and North Slope Borough 

regulatory and resource agencies, shall be required to address the objectives 

of water quality and free passage of fish. 

E-4 Best Management Practice 

Objective: Minimize the potential for pipeline leaks, the resulting 

environmental damage, and industrial accidents. 

Requirement/Standard: All pipelines shall be designed, constructed, and 

operated under an authorized officer-approved Quality Assurance/Quality 

Control plan that is specific to the product transported and shall be 

constructed to accommodate the best available technology for detecting and 

preventing corrosion or mechanical defects during routine structural 

integrity inspections. 

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E-5 Best Management Practice 

Objective: Minimize impacts of the development footprint. 

Requirement/Standard: Facilities shall be designed and located to minimize 

the development footprint. Issues and methods that are to be considered 

include: 

a. use of maximum extended-reach drilling for production drilling to 

minimize the number of pads and the network of roads between pads; 

b. sharing facilities with existing development; 

c. collocation of all oil and gas facilities, except airstrips, docks, and 

seawater-treatment plants, with drill pads; 

d. integration of airstrips with roads; 

e. use of gravel-reduction technologies, e.g., insulated or pile-supported 

pads, 

f. coordination of facilities with infrastructure in support of offshore 

development. 

Note: Where aircraft traffic is a concern, consideration shall be given to 

balancing gravel pad size and available supply storage capacity with 

potential reductions in the use of aircraft to support oil and gas operations. 

E-6 Best Management Practice 

Objective: Reduce the potential for ice-jam flooding, impacts to wetlands 

and floodplains, erosion, alteration of natural drainage patterns, and 

restriction of fish passage. 

Requirement/Standard: Stream and marsh crossings shall be designed and 

constructed to ensure free passage of fish, reduce erosion, maintain natural 

drainage, and minimize adverse effects to natural stream flow. Note: 

Bridges, rather than culverts, are the preferred method for crossing rivers. 

When necessary, culverts can be constructed on smaller streams, if they are 

large enough to avoid restricting fish passage or adversely affecting natural 

stream flow. 

E-7 Best Management Practice 

Objective: Minimize disruption of caribou movement and subsistence use. 

Requirement/Standard: Pipelines and roads shall be designed to allow the 

free movement of caribou and the safe, unimpeded passage of the public 

while participating in subsistence activities. Listed below are the accepted 

design practices: 

a. Above ground pipelines shall be elevated a minimum of 7 feet as 

measured from the ground to the bottom of the pipeline at vertical 

support members. 

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b. In areas where facilities or terrain may funnel caribou movement, 

ramps over pipelines, buried pipelines, or pipelines buried under roads 

may be required by the authorized officer after consultation with 

federal, State, and North Slope Borough regulatory and resource 

agencies (as appropriate, based on agency legal authority and 

jurisdictional responsibility). 

c. A minimum distance of 500 feet between pipelines and roads shall be 

maintained. Separating roads from pipelines may not be feasible 

within narrow land corridors between lakes and where pipelines and 

roads converge on a drill pad. Where it is not feasible to separate 

pipelines and roads, alternative pipeline routes, designs and possible 

burial within the road will be considered by the authorized officer. 

E-8 Best Management Practice 

Objective: Minimize the impact of mineral materials mining activities on air, 

land, water, fish, and wildlife resources. 

Requirement/Standard: Gravel mine site design and reclamation will be in 

accordance with a plan approved by the authorized officer. The plan shall be 

developed in consultation with appropriate federal, State, and North Slope 

Borough regulatory and resource agencies and consider: 

a. Locations outside the active flood plain. 

b. Design and construction of gravel mine sites within active flood plains 

to serve as water reservoirs for future use. 

c. Potential use of the site for enhancing fish and wildlife habitat. 

d. Potential storage and reuse of sod/overburden for the mine site or at 

other disturbed sites on the North Slope. 

E-9 Best Management Practice 

Objective: Avoidance of human-caused increases in populations of predators 

of ground nesting birds. 

Requirement/Standard: 

a. Lessee shall utilize best available technology to prevent facilities from 

providing nesting, denning, or shelter sites for ravens, raptors, and 

foxes. The lessee shall provide the authorized officer with an annual 

report on the use of oil and gas facilities by ravens, raptors, and foxes 

as nesting, denning, and shelter sites. 

b. Feeding of wildlife is prohibited and will be subject to noncompliance regulations. 

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E-10 Best Management Practice 

Objective: Prevention of migrating waterfowl, including species listed under 

the Endangered Species Act, from striking oil and gas and related facilities 

during low light conditions. 

Requirement/Standard: Illumination of all structures between August 1 and 

October 31 shall be designed to direct artificial exterior lighting inward and 

downward, rather than upward and outward, unless otherwise required by 

the Federal Aviation Administration. 

E-11 Best Management Practice 

Objective: Minimize the take of species, particularly those listed under the 

Endangered Species Act and BLM Special Status Species, from direct or 

indirect interaction with oil and gas facilities. 

Requirement/Standard: In accordance with the guidance below, before the 

approval of facility construction, aerial surveys of the following species shall 

be conducted within any area proposed for development. 

Special Conditions in Spectacled and/or Steller’s Eiders Habitats: 

a. Surveys shall be conducted by the lessee for at least 3 years before 

authorization of construction, if such construction is within the USFWS 

North Slope eider survey area and at least 1 year outside that area. 

Results of aerial surveys and habitat mapping may require additional 

ground nest surveys. Spectacled and/or Steller’s eider surveys shall be 

conducted following accepted BLM-protocol. Information gained from 

these surveys shall be used to make infrastructure siting decisions as 

discussed in subparagraph b, below. 

b. If spectacled and/or Steller’s eiders are determined to be present 

within the proposed development area, the applicant shall work with 

the USFWS and BLM early in the design process to site roads and 

facilities in order to minimize impacts to nesting and brood-rearing 

eiders and their preferred habitats. Such consultation shall address 

timing restrictions and other temporary mitigating measures, location 

of permanent facilities, placement of fill, alteration of eider habitat, 

aircraft operations, and management of high noise levels. 

c. To reduce the possibility of spectacled and/or Steller’s eiders or other 

birds colliding with above-ground utility lines (power and 

communication), such lines shall either be buried in access roads or 

suspended on vertical support members except in rare cases which are 

to be few in number and limited in extent. Exceptions are limited to 

the following situations, and must be reported to the USFWS when 

exceptions are authorized: 

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1. Overhead power or communication lines may be allowed when 

located entirely within the boundaries of a facility pad; 

2. Overhead power or communication lines may be allowed when 

engineering constraints at the specific and limited location make it 

infeasible to bury or connect the lines to a vertical support 

member; or 

3. Overhead power or communication lines may be allowed in 

situations when human safety would be compromised by other 

methods. 

d. To reduce the likelihood of spectacled and/or Steller’s eiders or other 

birds colliding with communication towers, towers should be located, 

to the extent practicable, on existing pads and as close as possible to 

buildings or other structures, and on the east or west side of buildings 

or other structures if possible. Support wires associated with 

communication towers, radio antennas, and other similar facilities, 

should be avoided to the extent practicable. If support wires are 

necessary, they should be clearly marked along their entire length to 

improve visibility to low flying birds. Such markings shall be 

developed through consultation with the USFWS. 

Special Conditions in Yellow-billed Loon Habitats: 

e. Aerial surveys shall be conducted by the lessee for at least 3 years 

before authorization of construction of facilities proposed for 

development which are within 1 mile of a lake 25 acres or larger in 

size. These surveys along shorelines of large lakes shall be conducted 

following accepted BLM protocol during nesting in late June and 

during brood rearing in late August. 

f. Should yellow-billed loons be present, the design and location of 

facilities must be such that disturbance is minimized. The default 

standard mitigation is a 1-mile buffer around all recorded nest sites 

and a minimum 1,625-foot (500-meter) buffer around the remainder 

of the shoreline. Development will generally be prohibited within 

buffers unless no other option exists. 

Protections for Birds 

g. To reduce the possibility of birds colliding with above-ground utility 

lines (power and communication), such lines shall either be buried in 

access roads or suspended on vertical support members except in rare 

cases, which are to be few in number and limited in extent. Exceptions 

are limited to the following situations: 

1. Overhead power or communication lines may be allowed when 

located entirely within the boundaries of a facility pad; 

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2. Overhead power or communication lines may be allowed when 

engineering constraints at the specific and limited location make it 

infeasible to bury or connect the lines to a vertical support 

member; or 

3. Overhead power or communication lines may be allowed in 

situations when human safety would be compromised by other 

methods. 

h. To reduce the likelihood of birds colliding with communication towers, 

towers should be located, to the extent practicable, on existing pads and 

as close as possible to buildings or other structures, and on the east or 

west side of buildings or other structures if possible. Support wires 

associated with communication towers, radio antennas, and other 

similar facilities, should be avoided to the extent practicable. If support 

wires are necessary, they should be clearly marked along their entire 

length to improve visibility to low-flying birds. Such markings shall be 

developed through consultation with the USFWS. 

E-12 Best Management Practice 

Objective: Use ecological mapping as a tool to assess wildlife habitat before 

development of permanent facilities to conserve important habitat types 

during development. 

Requirement/Standard: An ecological land classification map of the 

development area shall be developed before approval of facility 

construction. The map will integrate geomorphology, surface form, and 

vegetation at a scale, level of resolution, and level of positional accuracy 

adequate for detailed analysis of development alternatives. The map shall be 

prepared in time to plan one season of ground-based wildlife surveys, if 

deemed necessary by the authorized officer, before approval of the exact 

facility location and facility construction. 

E-13 Best Management Practice 

Objective: Protect cultural and paleontological resources. 

Requirement/Standard: Lessees shall conduct a cultural and paleontological 

resources survey prior to any ground-disturbing activity. Upon finding any 

potential cultural or paleontological resource, the lessee or their designated 

representative shall notify the authorized officer and suspend all operations 

in the immediate area of such discovery until written authorization to 

proceed is issued by the authorized officer. 

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E-14 Best Management Practice 

Objective: Ensure the passage of fish at stream crossings. 

Requirement/Standard: To ensure that crossings provide for fish passage, all 

proposed crossing designs shall adhere to the best management practices 

outlined in “Stream Crossing Design Procedure for Fish Streams on the 

North Slope Coastal Plain” by McDonald et al. (1994), “Fundamentals of 

Culvert Design for Passage of Weak-Swimming Fish” by Behlke et al. 

(1991), and other generally accepted best management procedures 

prescribed by the authorized officer. To adhere to these best management 

practices, at least 3 years of hydrologic and fish data shall be collected by 

the lessee for any proposed crossing of a stream whose structure is designed 

to occur, wholly or partially, below the stream’s ordinary high watermark. 

These data shall include, but are not limited to, the range of water levels 

(highest and lowest) at the location of the planned crossing, and the seasonal 

distribution and composition of fish populations using the stream. 

E-15 Best Management Practice 

Objective: Prevent or minimize the loss of nesting habitat for cliff nesting 

raptors. 

Requirement/Standard: 

a. Removal of greater than 100 cubic yards of bedrock outcrops, sand, 

and/or gravel from cliffs shall be prohibited. 

b. Any extraction of sand and/or gravel from an active river or stream 

channel shall be prohibited unless preceded by a hydrological study 

that indicates no potential impact by the action to the integrity of the 

river bluffs. 

E-16 Best Management Practice 

Objective: Prevent or minimize the loss of raptors due to electrocution by 

power lines. 

Requirement/Standard: Comply with the most up-to-date industry-accepted 

suggested practices for raptor protection on power lines. Current accepted 

standards were published in Reducing Avian Collisions with Power Lines: 

The State of the Art in 2012 by the Avian Power Line Interaction Committee 

and are updated as needed. 

E-17 Best Management Practice 

Objective: Manage permitted activities to meet Visual Resource 

Management class objectives described below. 

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Class I: Natural ecological changes and very limited management activity 

are allowed. The level of change to the characteristic landscape should 

be very low and must not attract attention. 

Class II: The level of change to the characteristic landscape should be 

low. Management activities may be seen, but should not dominate the 

view of the casual observer. Any changes should repeat the basic 

elements of form, line, color, and texture found in the predominant 

natural features of the characteristic landscape. 

Class III: The level of change to the characteristic landscape should be 

moderate. Management activities may attract attention, but should not 

dominate the view of the casual observer. Changes should repeat the 

basic elements found in the predominant natural features of the 

characteristic landscape. 

Class IV: The level of change to the characteristic landscape can be high. 

These management activities may dominate the view and be the major 

focus of viewer attention. However, every attempt should be made to 

minimize impacts through location and design by repeating form, line, 

color, and texture. 

Requirement/Standard: At the time of application for construction of 

permanent facilities, the lessee/permittee shall, after consultation with the 

authorized officer, submit a plan to best minimize visual impacts, consistent 

with the Visual Resource Management class for the lands on which facilities 

would be located. A photo simulation of the proposed facilities may be a 

necessary element of the plan. 

E-18 Best Management Practice 

Objective: Avoid and reduce temporary impacts to productivity from 

disturbance near Steller’s and/or spectacled eider nests. 

Requirement/Standard: Ground-level activity (by vehicle or on foot) within 

200 meters of occupied Steller’s and/or spectacled eider nests, from June 1 

through August 15, will be restricted to existing thoroughfares, such as pads 

and roads. Construction of permanent facilities, placement of fill, alteration 

of habitat, and introduction of high noise levels within 200 meters of 

occupied Steller’s and/or spectacled eider nests will be prohibited. In 

instances where summer (June 1 through August 15) support/construction 

activity must occur off existing thoroughfares, USFWS-approved nest 

surveys must be conducted during mid-June prior to the approval of the 

activity. Collected data will be used to evaluate whether the action could 

occur based on employment of a 200-meter buffer around nests or if the 

activity would be delayed until after mid-August once ducklings are mobile 

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and have left the nest site. Also, in cases in which oil spill response training 

is proposed to be conducted within 200 meters of shore in riverine, marine, 

or inter-tidal areas, the BLM will work with the USFWS to schedule the 

training at a time that is not a sensitive nesting/brood-rearing period or 

require that nest surveys be conducted in the training area prior to the 

rendering a decision on approving the training. The protocol and timing of 

nest surveys for Steller’s and/or spectacled eiders will be determined in 

cooperation with the USFWS, and must be approved by the USFWS. 

Surveys should be supervised by biologists who have previous experience 

with Steller’s and/or spectacled eider nest surveys. 

E-19 Best Management Practice 

Objective: Provide information to be used in monitoring and assessing 

wildlife movements during and after construction. 

Requirement/Standard: A representation, in the form of ArcGIS-compatible 

shape-files, of all new infrastructure construction shall be provided to the 

authorized officer. During the planning and permitting phase, shape-files 

representing proposed locations shall be provided. Within 6 months of 

construction completion, shape-files (within GPS accuracy) of all new 

infrastructure shall be provided. Infrastructure includes all gravel roads and 

pads, facilities built on pads, pipelines and independently constructed 

powerlines (as opposed to those incorporated in pipeline design). Gravel 

pads shall be included as polygon feature. Roads, pipelines, and powerlines 

may be represented as line features but must include ancillary data to denote 

width, number pipes, etc. Poles for power lines may be represented as point 

features. Ancillary data shall include construction beginning and ending 

dates. 

Use of Aircraft for Permitted Activities 

F-1 Best Management Practice 

Objective: Minimize the effects of low-flying aircraft on wildlife, 

subsistence activities, and local communities. 

Requirement/Standard: The lessee shall ensure that aircraft used for 

permitted activities maintain altitudes according to the following guidelines 

(Note: This best management practice is not intended to restrict flights 

necessary to survey wildlife to gain information necessary to meet the stated 

objectives of the stipulations and best management practices. However, 

flights necessary to gain this information will be restricted to the minimum 

necessary to collect such data.): 

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a. Aircraft shall maintain an altitude of at least 1,500 feet above ground 

level when within 1⁄2 mile of cliffs identified as raptor nesting sites 

from April 15 through August 15 and an altitude of at least 1,500 feet 

above ground level when within 1⁄2 mile of known gyrfalcon nest sites 

from March 15 to August 15, unless doing so would endanger human 

life or violate safe flying practices. Permittees shall obtain information 

from the BLM necessary to plan flight routes when routes may go 

near falcon nests. 

b. Aircraft shall maintain an altitude of at least 1,000 feet above ground 

level (except for takeoffs and landings) over caribou winter ranges 

from December 1 through May 1, unless doing so would endanger 

human life or violate safe flying practices. Caribou wintering areas 

will be defined annually by the authorized officer. The BLM will 

consult directly with the Alaska Department of Fish and Game in 

annually defining caribou winter ranges. 

c. Land user shall submit an aircraft use plan as part of an oil and gas 

exploration or development proposal. The plan shall address strategies 

to minimize impacts to subsistence hunting and associated activities, 

including but not limited to the number of flights, type of aircraft, and 

flight altitudes and routes, and shall also include a plan to monitor 

flights. Proposed aircraft use plans should be reviewed by appropriate 

federal, State, and borough agencies. Consultations with these same 

agencies will be required if unacceptable disturbance is identified by 

subsistence users. Adjustments, including possible suspension of all 

flights, may be required by the authorized officer if resulting 

disturbance is determined to be unacceptable. The number of takeoffs 

and landings to support oil and gas operations with necessary 

materials and supplies should be limited to the maximum extent 

possible. During the design of proposed oil and gas facilities, larger 

landing strips and storage areas should be considered to allow larger 

aircraft to be employed, resulting in fewer flights to the facility. 

d. Use of aircraft, especially rotary wing aircraft, near known 

subsistence camps and cabins or during sensitive subsistence hunting 

periods (spring goose hunting and fall caribou and moose hunting) 

should be kept to a minimum. 

e. Aircraft used for permitted activities shall maintain an altitude of at 

least 2,000 feet above ground level (except for takeoffs and landings) 

over the Teshekpuk Lake Caribou Habitat Area (Map 2) from May 20 

through August 20, unless doing so would endanger human life or 

violate safe flying practices. Aircraft use (including fixed wing and 

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helicopter) by oil and gas lessees in the Goose Molting Area (Map 2) 

should be minimized from May 20 through August 20, unless doing 

so would endanger human life or violate safe flying practices. 

f. Aircraft used for permitted activities shall maintain an altitude of at 

least 2,000 feet above ground level (except for takeoffs and landings) 

over the Utukok River Uplands Special Area (Map 2) from May 20 

through August 20, unless doing so would endanger human life or 

violate safe flying practices. 

g. Hazing of wildlife by aircraft is prohibited. Pursuit of running wildlife 

is hazing. If wildlife begins to run as an aircraft approaches, the 

aircraft is too close and must break away. 

h. Fixed wing aircraft used as part of a BLM-authorized activity along 

the coast shall maintain minimum altitude of 2,000 feet when within a 

1⁄2-mile of walrus haulouts, unless doing so would endanger human 

life or violate safe flying practices. Helicopters used as part of a 

BLM-authorized activity along the coast shall maintain minimum 

altitude of 3,000 feet and a 1-mile buffer from walrus haulouts, unless 

doing so would endanger human life or violate safe flying practices. 

i. Aircraft used as part of a BLM-authorized activity along the coast and 

shore fast ice zone shall maintain minimum altitude of 3,000 feet 

when within 1 mile from aggregations of seals, unless doing so would 

endanger human life or violate safe flying practices. 

Oil Field Abandonment 

G-1 Lease Stipulation 

Objective: Ensure long-term reclamation of land to its previous condition 

and use. 

Requirement/Standard: Prior to final abandonment, land used for oil and gas 

infrastructure—including but not limited to well pads, production facilities, 

access roads, and airstrips—shall be reclaimed to ensure eventual restoration 

of ecosystem function. The leaseholder shall develop and implement an 

abandonment and reclamation plan approved by the BLM. The plan shall 

describe short-term stability, visual, hydrological, and productivity 

objectives and steps to be taken to ensure eventual ecosystem restoration to 

the land’s previous hydrological, vegetative, and habitat condition. The 

BLM may grant exceptions to satisfy stated environmental or public 

purposes. 

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Subsistence Consultation for Permitted Activities 

H-1 Best Management Practice 

Objective: Provide opportunities for participation in planning and decision 

making to prevent unreasonable conflicts between subsistence uses and other 

activities. 

Requirement/Standard: Lessee/permittee shall consult directly with affected 

communities using the following guidelines: 

a. Before submitting an application to the BLM, the applicant shall 

consult with directly affected subsistence communities, the North Slope 

Borough, and the National Petroleum Reserve-Alaska Subsistence 

Advisory Panel to discuss the siting, timing, and methods of their 

proposed operations to help discover local traditional and scientific 

knowledge, resulting in measures that minimize impacts to subsistence 

uses. Through this consultation, the applicant shall make every 

reasonable effort, including such mechanisms as conflict avoidance 

agreements and mitigating measures, to ensure that proposed activities 

will not result in unreasonable interference with subsistence activities. 

In the event that no agreement is reached between the parties, the 

authorized officer shall consult with the directly involved parties and 

determine which activities will occur, including the timeframes. 

b. The applicant shall submit documentation of consultation efforts as 

part of its operations plan. Applicants should submit the proposed 

plan of operations to the National Petroleum Reserve-Alaska 

Subsistence Advisory Panel for review and comment. The applicant 

must allow time for the BLM to conduct formal government-togovernment consultation with Native Tribal governments if the 

proposed action requires it. 

c. A plan shall be developed that shows how the activity, in combination 

with other activities in the area, will be scheduled and located to 

prevent unreasonable conflicts with subsistence activities. The plan 

will also describe the methods used to monitor the effects of the 

activity on subsistence use. The plan shall be submitted to the BLM as 

part of the plan of operations. The plan should address the following 

items: 

1. A detailed description of the activity(ies) to take place (including 

the use of aircraft). 

2. A description of how the lessee/permittee will minimize and/or 

deal with any potential impacts identified by the authorized officer 

during the consultation process. 

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3. A detailed description of the monitoring effort to take place, 

including process, procedures, personnel involved and points of 

contact both at the work site and in the local community. 

4. Communication elements to provide information on how the 

applicant will keep potentially affected individuals and 

communities up-to-date on the progress of the activities and 

locations of possible, short-term conflicts (if any) with subsistence 

activities. Communication methods could include holding 

community meetings, open house meetings, workshops, 

newsletters, radio and television announcements, etc. 

5. Procedures necessary to facilitate access by subsistence users to 

the permitees’ area of activity or facilities during the course of 

conducting subsistence activities. 

d. During development, monitoring plans must be established for new 

permanent facilities, including pipelines, to assess an appropriate 

range of potential effects on resources and subsistence as determined 

on a case-by-case basis given the nature and location of the facilities. 

The scope, intensity, and duration of such plans will be established in 

consultation with the authorized officer and NPR-A Subsistence 

Advisory Panel. 

e. Permittees that propose barging facilities, equipment, supplies, or other 

materials to NPR-A in support of oil and gas activities in the NPR-A 

shall notify, confer, and coordinate with the Alaska Eskimo Whaling 

Commission, the appropriate local community whaling captains’ 

associations, and the North Slope Borough to minimize impacts from 

the proposed barging on subsistence whaling activities. 

f. Barge operators requiring a BLM permit are required to demonstrate 

that barging activities will not have unmitigable adverse impacts on 

the availability of marine mammals to subsistence hunters. 

g. All vessels over 50 ft. in length engaged in operations requiring a BLM 

permit must have an Automatic Identification System (AIS) 

transponder system on the vessel. 

H-2 Best Management Practice 

Objective: Prevent unreasonable conflicts between subsistence activities and 

geophysical (seismic) exploration. 

Requirement/Standard: In addition to the consultation process described in 

Best Management Practice H-1 for permitted activities, before activity to 

conduct geophysical (seismic) exploration commences, applicants shall 

notify the local search and rescue organizations of proposed seismic survey 

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locations for that operational season. For the purpose of this standard, a 

potentially affected cabin/campsite is defined as any camp or campsite used 

for subsistence purposes and located within the boundary of the area subject 

to proposed geophysical exploration and/or within 1 mile of actual or 

planned travel routes used to supply the seismic operations while it is in 

operation. 

a. Because of the large land area covered by typical geophysical 

operations and the potential to impact a large number of subsistence 

users during the exploration season, the permittee/operator will notify 

all potentially affected subsistence-use cabin and campsite users. 

b. The official recognized list of subsistence-use cabin and campsite 

users is the North Slope Borough’s most current inventory of cabins 

and campsites, which have been identified by the subsistence users’ 

names. 

c. A copy of the notification, a map of the proposed exploration area, 

and the list of potentially affected users shall also be provided to the 

office of the appropriate Native Tribal government. 

d. The authorized officer will prohibit seismic work within 1 mile of any 

known subsistence-use cabin or campsite unless an alternate 

agreement between the cabin/campsite owner/user is reached through 

the consultation process and presented to the authorized officer. 

(Regardless of the consultation outcome, the authorized officer will 

prohibit seismic work within 300 feet of a known subsistence-use 

cabin or campsite.) 

e. The permittee shall notify the appropriate local search and rescue 

(e.g., Nuiqsut Search and Rescue, Atqasuk Search and Rescue) of 

their current operational location within the NPR-A on a weekly basis. 

This notification should include a map indicating the current extent of 

surface use and occupation, as well as areas previously used/occupied 

during the course of the operation in progress. The purpose of this 

notification is to allow hunters up-to-date information regarding 

where seismic exploration is occurring, and has occurred, so that they 

can plan their hunting trips and access routes accordingly. 

Identification of the appropriate search and rescue offices to be 

contacted can be obtained from the coordinator of the NPR-A 

Subsistence Advisory Panel in the BLM’s Arctic Field Office. 

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H-3 Best Management Practice 

Objective: Minimize impacts to sport hunting and trapping species and to 

subsistence harvest of those animals. 

Requirement/Standard: Hunting and trapping by lessee's/permittee’s 

employees, agents, and contractors are prohibited when persons are on 

“work status.” Work status is defined as the period during which an 

individual is under the control and supervision of an employer. Work status 

is terminated when the individual’s shift ends and he/she returns to a public 

airport or community (e.g., Fairbanks, Barrow, Nuiqsut, or Deadhorse). Use 

of lessee/permittee facilities, equipment, or transport for personal access or 

aid in hunting and trapping is prohibited. 

Orientation Programs Associated with Permitted Activities 

I-1 Best Management Practice 

Objective: Minimize cultural and resource conflicts. 

Requirement/Standard: All personnel involved in oil and gas and related 

activities shall be provided information concerning applicable stipulations, 

best management practices, standards, and specific types of environmental, 

social, traditional, and cultural concerns that relate to the region. The 

lessee/permittee shall ensure that all personnel involved in permitted 

activities shall attend an orientation program at least once a year. The 

proposed orientation program shall be submitted to the authorized officer for 

review and approval and should: 

a. provide sufficient detail to notify personnel of applicable stipulations 

and best management practices as well as inform individuals working 

on the project of specific types of environmental, social, traditional 

and cultural concerns that relate to the region. 

b. Address the importance of not disturbing archaeological and 

biological resources and habitats, including endangered species, 

fisheries, bird colonies, and marine mammals, and provide guidance 

on how to avoid disturbance. 

c. Include guidance on the preparation, production, and distribution of 

information cards on endangered and/or threatened species. 

d. Be designed to increase sensitivity and understanding of personnel to 

community values, customs, and lifestyles in areas in which personnel 

will be operating. 

e. Include information concerning avoidance of conflicts with 

subsistence, commercial fishing activities, and pertinent mitigation. 

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f. Include information for aircraft personnel concerning subsistence 

activities and areas/seasons that are particularly sensitive to 

disturbance by low-flying aircraft. Of special concern is aircraft use 

near traditional subsistence cabins and campsites, flights during spring 

goose hunting and fall caribou and moose hunting seasons, and flights 

near North Slope communities. 

g. Provide that individual training is transferable from one facility to 

another except for elements of the training specific to a particular site. 

h. Include on-site records of all personnel who attend the program for so 

long as the site is active, though not to exceed the 5 most recent years 

of operations. This record shall include the name and dates(s) of 

attendance of each attendee. 

i. Include a module discussing bear interaction plans to minimize 

conflicts between bears and humans. 

j. Provide a copy of 43 CFR 3163 regarding Non-Compliance 

Assessment and Penalties to on-site personnel. 

k. Include training designed to ensure strict compliance with local and 

corporate drug and alcohol policies. This training should be offered to 

the North Slope Borough Health Department for review and comment. 

l. Include training developed to train employees on how to prevent 

transmission of communicable diseases, including sexually 

transmitted diseases, to the local communities. This training should 

be offered to the North Slope Borough Health Department for review 

and comment. 

Endangered Species Act—Section 7 Consultation Process 

J. The lease areas may now or hereafter contain plants, animals, or their 

habitats determined to be threatened, endangered, or to have some other 

special status. The BLM may recommend modifications to exploration and 

development proposals to further its conservation and management objective 

to avoid BLM-approved activities that will contribute to the need to list such 

a species or their habitat. The BLM may require modifications to or 

disapprove a proposed activity that is likely to adversely affect a proposed or 

listed endangered species, threatened species, or critical habitat. The BLM 

will not approve any activity that may affect any such species or critical 

habitat until it completes its obligations under applicable requirements of the 

Endangered Species Act as amended, 16 USC § 1531 et seq., including 

completion of any required procedure for conference or consultation. 

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Additional Protections that Apply in Select Biologically Sensitive Areas 

K-1 Lease Stipulation/Best Management Practice – Rivers 

Note: This measure would be applied to relevant new leases. On lands 

unavailable for leasing in the respective alternatives, K-1 would be a best 

management practice. The decision indicated below in subparagraphs (a) 

and (d) modify Protection 1 of the Colville River Special Area Management 

Plan by widening its applicability to 2 miles. 

Objective: Minimize the disruption of natural flow patterns and changes to 

water quality; the disruption of natural functions resulting from the loss or 

change to vegetative and physical characteristics of floodplain and riparian 

areas; the loss of spawning, rearing or over-wintering habitat for fish; the 

loss of cultural and paleontological resources; the loss of raptor habitat; 

impacts to subsistence cabin and campsites; the disruption of subsistence 

activities; and impacts to scenic and other resource values. 

Requirement/Standard: Permanent oil and gas facilities, including gravel 

pads, roads, airstrips, and pipelines, are prohibited in the streambed and 

adjacent to the rivers listed below at the distances identified. (Gravel mines 

may be located within the active floodplain consistent with Best 

Management Practice E-8). On a case-by case basis, and in consultation with 

federal, State, and North Slope Borough regulatory and resource agencies 

(as appropriate, based on agency legal authority and jurisdictional 

responsibility), essential pipeline and road crossings to the main channel will 

be permitted through setback areas. The below setbacks may not be practical 

within river deltas; in such deltas, permanent facilities shall be designed to 

withstand a 200-year flood event. In the below list, if no upper limit for the 

setback is indicated, the setback extends to the head of the stream as 

identified in the National Hydrography Dataset. 

a. Colville River: a 2-mile setback from the boundary of NPR-A where 

the river determines the boundary along the Colville River as 

determined by cadastral survey to be the highest high watermark on 

the left (western or northern) bank and from both banks’ ordinary high 

watermark where BLM-manages both sides of the river up through 

T5S, R30W, U.M. Above that point to its source at the juncture of 

Thunder and Storm creeks the setback will be 1⁄2 mile. Note: The 

planning area excludes conveyed Native lands along the lower reaches 

of the Colville River. Development of road crossings intended to 

support oil and gas activities shall be consolidated with other similar 

projects and uses to the maximum extent possible. Note: This 

provision does not apply to intercommunity or other permanent roads 

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constructed with public funds for general transportation purposes, 

though the BLM would encourage minimal use of the setback area. 

This preserves the opportunity to plan, design, and construct public 

transportation systems to meet the economic, transportation, and 

public health and safety needs of the State of Alaska and/or 

communities within National Petroleum Reserve-Alaska. 

b. Ikpikpuk River: a 2-mile setback from of the ordinary high 

watermark of the Ikpikpuk River extending from the mouth upstream 

through T7 N, R11W, U.M.; above that the setback would be for 1 

mile to the confluence of the Kigalik River and Maybe Creek. 

c. Miguakiak River: a 1⁄2-mile setback from the ordinary high 

watermark. 

d. Kikiakrorak and Kogosukruk Rivers: A 2-mile setback from the top 

of the bluff (or ordinary high watermark if there is no bluff) on the 

Kikiakrorak River downstream from T2N., R4W, U.M. and on the 

Kogosukruk River (including Branch of Kogosukruk River, Henry 

Creek, and two unnamed tributaries off the southern bank) 

downstream from T2N, R3W, U.M. The setback from these streams in 

the named townships and further upstream as applicable will be a 1⁄2-

mile from the top of the bluff or bank if there is no bluff. 

e. Fish Creek: a 3-mile setback from the highest high watermark of the 

creek downstream from the eastern edge of section 31, T11N, R1E., 

U.M. and a 1⁄2-mile setback from the bank’s highest high watermark 

farther upstream. 

f. Judy Creek: a 1⁄2-mile setback from the ordinary high watermark. 

g. Ublutuoch (Tiƾmiaqsiugvik) River: a 1⁄2-mile setback from the 

ordinary high water mark. 

h. Alaktak River: a 1-mile setback from the ordinary high water mark. 

i. Chipp River: a 1-mile setback from the ordinary high water mark. 

j. Oumalik River: a 1⁄2-mile setback from the Oumalik River ordinary 

high water mark from the mouth upstream to section 5, T8N, R14W, 

U.M., and a 1⁄2 mile setback in and above section 5, T8N, R14W, U.M. 

k. Titaluk River: a 2-mile setback from the ordinary high water mark 

from its confluence with the Ikpikpuk River upstream through T7N, 

R12W, U.M.; above that point the setback would be 1⁄2-mile from the 

ordinary high water mark. 

l. Kigalik River: a 1⁄2-mile setback from the ordinary high water mark. 

m. Maybe Creek: a 1⁄2-mile setback from the ordinary high water mark. 

n. Topagoruk River: a 1-mile setback from the ordinary high water 

mark. 

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o. Ishuktak Creek: a 1⁄2-mile setback from the ordinary high water mark. 

p. Meade River: a 1-mile setback from the ordinary high water mark on 

BLM-managed lands. 

q. Usuktuk River: a 1-mile setback from the ordinary high water mark 

on BLM-managed lands. 

r. Pikroka Creek: a 1⁄2-mile setback from the ordinary high water mark. 

s. Nigisaktuvik River: a 1-mile setback from the ordinary high water 

mark. 

t. Inaru River: a 1-mile setback from the ordinary high water mark. 

u. Kucheak Creek: a 1⁄2-mile setback from the ordinary high water mark. 

v. Avalik River: a 1-mile setback from the ordinary high water mark. 

w. Niklavik Creek: a 1⁄2-mile setback from the ordinary high water mark. 

x. Kugrua River: a 1⁄2-mile setback from the ordinary high water mark. 

y. Kungok River: a 1-mile setback from the ordinary high water mark on 

BLM-managed lands. 

z. Kolipsun Creek: a 1⁄2-mile setback from the ordinary high water mark 

upstream through T13N, R28W, U.M. 

aa. Maguriak Creek: a 1⁄2-mile setback from the ordinary high water 

mark upstream through T12N, R29W, U.M. 

ab. Mikigealiak River: a 1⁄2-mile setback from the ordinary high water 

mark upstream through T12N, R30W, U.M. 

ac. Kuk River: a 1-mile setback from the ordinary high water mark on 

BLM-managed lands. 

ad. Ketik River: a 1-mile setback from the ordinary high water mark. 

ae. Kaolak River: a 1-mile setback from the ordinary high water mark. 

af. Ivisaruk River: a 1-mile setback from the ordinary high water mark. 

ag. Nokotlek River: a 1⁄2-mile setback from the ordinary high water 

mark. 

ah. Ongorakvik River: a 1⁄2-mile setback from the ordinary high water 

mark. 

ai. Tunalik River: a 1⁄2-mile setback from the ordinary high water mark. 

aj. Avak River: a 1⁄2-mile setback from the ordinary high water mark 

within the NPR-A. 

ak. Nigu River: a 1⁄2-mile setback from the ordinary high water mark 

from the confluence with the Etivluk River upstream to the boundary 

of NPR-A 

al. Etivluk River: a 1⁄2-mile setback from the ordinary high water mark. 

am. Ipnavik River: a 1⁄2-mile setback from the ordinary high water mark. 

an. Kuna River: a 1⁄2-mile setback from the ordinary high water mark. 

ao. Kiligwa River: a 1⁄2-mile setback from the ordinary high water mark. 

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ap. Nuka River: a 1⁄2-mile setback from the ordinary high water mark. 

aq. Driftwood Creek: a 1⁄2-mile setback from the ordinary high water 

mark. 

ar. Utukok River: a 1-mile setback from the ordinary high water mark 

within the NPR-A. 

as. Awuna River: a 1⁄2-mile setback from the ordinary high water mark. 

at. Carbon Creek: a 1⁄2-mile setback from the ordinary high water mark. 

au. Kokolik River: a 1-mile setback from the ordinary high water mark 

within the NPR-A. 

av. Keolok Creek: a 1⁄2-mile setback from the ordinary high water mark. 

The decisions in subparagraphs K-1(a) and K-1(d) modify Colville River 

Management Plan Protection 1 by widening the setback in that measure to 2 

miles. Protection 1 thus is modified to the following: 

Colville River Special Area Management Plan-Protection 1 

Objective: Minimize the loss of arctic peregrine falcon nesting habitat in the 

Colville River Special Area. 

Requirement/Standard: To minimize the direct loss of arctic peregrine falcon 

nesting habitat and to protect nest sites in the Colville River Special Area the 

following protective measures apply: Permanent oil and gas facilities, 

including gravel pads, roads, airstrips, and pipelines, are prohibited in the 

stream bed and adjacent to the rivers listed below at the distances identified. 

On a case-by-case basis, and in consultation with federal, State, and North 

Slope Borough regulatory and resource agencies (as appropriate; based on 

agency legal authority and jurisdictional responsibility), essential pipeline 

and road crossings perpendicular to the main channel will be permitted 

through setback areas. 

a. Colville River: downstream of the Etivluk River a continuous 2-mile 

setback measured from the highest high watermark on the left bank 

(facing downstream); upstream of the Etivluk River a 2-mile setback 

measured from the ordinary high watermark of the bank on both sides 

of the river. Development of road crossings intended to support oil 

and gas activities shall be consolidated with other similar projects and 

uses to the maximum extent possible. This provision does not apply to 

intercommunity or other permanent roads constructed with public 

funds for general transportation purposes. 

b. Kikiakrorak River: downstream from T2N, R4W, U.M., a continuous 

2-mile setback as measured from the top of the bluff (or bank if there 

is no bluff) of both sides of the river. 

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c. Kogosukruk River: downstream from T2N, R3W, U.M., a continuous 

2-mile setback as measured from the top of the bluff (or bank if there 

is no bluff) of both sides of the river and several of its tributaries. 

K-2 Lease Stipulation/Best Management Practice – Deep Water Lakes 

Note: This measure would be applied to relevant new leases. On lands 

unavailable for leasing, K-2 would be a best management practice. 

Objective: Minimize the disruption of natural flow patterns and changes to 

water quality; the disruption of natural functions resulting from the loss or 

change to vegetative and physical characteristics of deep water lakes; the 

loss of spawning, rearing or over wintering habitat for fish; the loss of 

cultural and paleontological resources; impacts to subsistence cabin and 

campsites; and the disruption of subsistence activities. 

Requirement/Standard: Generally, permanent oil and gas facilities, including 

gravel pads, roads, airstrips, and pipelines, are prohibited on the lake or 

lakebed and within 1⁄4 mile of the ordinary high water mark of any deep lake 

as determined to be in lake zone III (i.e., depth greater than 13 feet [4 

meters]; Mellor 1985). On a case-by-case basis in consultation with federal, 

State and North Slope Borough regulatory and resource agencies (as 

appropriate based on agency legal authority and jurisdictional 

responsibility), essential pipeline(s), road crossings, and other permanent 

facilities may be considered through the permitting process in these areas 

where the lessee can demonstrate on a site-specific basis that impacts will be 

minimal. 

K-3 Best Management Practice – Kogru River, Dease Inlet, Admiralty 

Bay, Elson Lagoon, Peard Bay, Wainwright Inlet/Kuk River, and 

Kasegaluk Lagoon, and their associated Islands 

Note: None of the area is available for oil and gas leasing or exploratory 

drilling. Therefore, K-3 will apply as a best management practice. 

Objective: Protect fish and wildlife habitat (including, but not limited to, that 

for waterfowl and shorebirds, caribou insect-relief, and marine mammals), 

preserve air and water quality, and minimize impacts to subsistence 

activities and historic travel routes on the major coastal waterbodies. 

Requirement/Standard (Development): With the exception of linear features 

such as pipelines, no permanent oil and gas facilities are permitted on or 

under the water within 3⁄4 mile seaward of the shoreline (as measured from 

mean high tide) of the major coastal waterbodies or the natural coastal 

islands (to the extent that the seaward subsurface is within NPR-A). 

Elsewhere, permanent facilities within the major coastal waterbodies will 

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only be permitted on or under the water if they can meet all the following 

criteria: 

a. Design and construction of facilities shall minimize impacts to 

subsistence uses, travel corridors, seasonally concentrated fish and 

wildlife resources. 

b. Daily operational activities, including use of support vehicles, 

watercraft, and aircraft traffic, alone or in combination with other 

past, present, and reasonably foreseeable activities, shall be conducted 

to minimize impacts to subsistence uses, travel corridors, and 

seasonally concentrated fish and wildlife resources. 

c. The location of oil and gas facilities, including artificial islands, 

platforms, associated pipelines, ice or other roads, bridges or 

causeways, shall be sited and constructed so as to not pose a hazard to 

navigation by the public using traditional high-use subsistence-related 

travel routes into and through the major coastal waterbodies as 

identified by the North Slope Borough. 

d. Demonstrated year-round oil spill response capability, including the 

capability of adequate response during periods of broken ice or open 

water, or the availability of alternative methods to prevent well 

blowouts during periods when adequate response capability cannot be 

demonstrated. Such alternative methods may include seasonal drilling 

restrictions, improvements in blowout prevention technology, 

equipment and/or changes in operational procedures, and “top-setting” 

of hydrocarbon-bearing zones. 

e. Reasonable efforts will be made to avoid or minimize impacts related 

to oil spill response activities, including vessel, aircraft, and 

pedestrian traffic that add to impacts or further compound “direct 

spill” related impacts on area resources and subsistence uses. 

f. Before conducting open water activities, the permittee shall consult 

with the Alaska Eskimo Whaling Commission and the North Slope 

Borough to minimize impacts to the fall and spring subsistence 

whaling activities of the communities of the North Slope. 

K-4a Best Management Practice – Goose Molting Area 

Note: Except for less than 10,000 acres east of the mouth of the Ikpikpuk 

River, new non-subsistence infrastructure would be prohibited in the goose 

molting area. None of the area is available for oil and gas leasing or 

exploratory drilling. 

Objective: Minimize disturbance to molting geese and loss of goose molting 

habitat in and around lakes in the Goose Molting Area. 

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Requirement/Standard (General): Within the Goose Molting Area no 

permanent oil and gas facilities, except for pipelines, will be allowed within 

1 mile of the shoreline of goose molting lakes. No waiver, exception, or 

modification will be considered. Prior to the permitting of a pipeline in the 

Goose Molting Area, a workshop will be convened to determine the best 

corridor for pipeline construction in efforts to minimize impacts to wildlife 

and subsistence resources. The workshop participants will include but will 

not be limited to federal, state, and North Slope Borough representatives. In 

addition, only “in field” roads will be authorized as part of oil and gas field 

development. 

Requirement/Standard (Development): In the Goose Molting Area, the 

following standards will be followed for permitted activities: 

a. Within the Goose Molting Area from June 15 through August 20, all 

off-pad activities and major construction activities using heavy 

equipment (e.g., sand/gravel extraction and transport, pipeline and pad 

construction, but not drilling from existing production pads) shall be 

suspended (see also Best Management Practice K-5(d)), unless 

approved by the authorized officer in consultation with the 

appropriate federal, State, and North Slope Borough regulatory and 

resource agencies. The intent of this requirement is to restrict 

activities that will disturb molting geese during the period when geese 

are present. 

b. Water extraction from any lakes used by molting geese shall not alter 

hydrological conditions that could adversely affect identified goosefeeding habitat along lakeshore margins. Considerations will be given 

to seasonal use by operators (generally in winter) and geese (generally 

in summer), as well as recharge to lakes from the spring snowmelt. 

c. Oil and gas activities will avoid altering (i.e., damage or disturbance of 

soils, vegetation, or surface hydrology) critical goose-feeding habitat 

types along lakeshore margins (grass/sedge/moss) and salt marsh 

habitats. 

d. Permanent oil and gas facilities (including gravel roads, pads, and 

airstrips, but excluding pipelines) and material sites will be sited 

outside the identified buffers and restricted surface occupancy areas. 

Additional limits on development footprint apply 

e. Between June 15 and August, 20 within the Goose Molting Area, oil 

and gas facilities shall incorporate features (e.g., temporary fences, 

siting/orientation) that screen/shield human activity from view of any 

Goose Molting Area lake, as identified by the authorized officer in 

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consultation with appropriate federal, State, and North Slope Borough 

regulatory and resource agencies. 

f. Strategies to minimize ground traffic shall be implemented from June 

15 through August 20. These strategies may include limiting trips, use 

of convoys, different vehicle types, etc. to the extent practicable. The 

permittee shall submit with the development proposal a vehicle use 

plan that considers these and any other mitigation. The vehicle use 

plan shall also include a vehicle-use monitoring plan. Adjustments 

will be required by the authorized officer if resulting disturbance is 

determined to be unacceptable. 

g. Within the Goose Molting Area aircraft use (including fixed wing and 

helicopter) shall be restricted from June 15 through August 20 unless 

doing so endangers human life or violates safe flying practices. 

Restrictions may include: (1) limiting flights to two round-trips/week, 

and (2) limiting flights to corridors established by the BLM after 

discussions with appropriate federal, State, and North Slope Borough 

regulatory and resource agencies. The permittee shall submit with the 

development proposal an aircraft use plan that considers these and 

other mitigation. The aircraft use plan shall also include an aircraft 

monitoring plan. Adjustments, including perhaps suspension of all 

aircraft use, will be required by the authorized officer if resulting 

disturbance is determined to be unacceptable. Note: This site-specific 

best management practice is not intended to restrict flights necessary 

to survey wildlife to gain information necessary to meet the stated 

objective of the stipulations and best management practices. However, 

flights necessary to gain this information will be restricted to the 

minimum necessary to collect such data. 

h. Any permit for development issued under this IAP/EIS will include a 

requirement for the permittee to conduct monitoring studies necessary 

to adequately determine consequences of development and any need 

for change to mitigations. Monitoring studies will be site- and 

development-specific within a set of over-arching guidelines 

developed by the BLM after conferring with appropriate federal, 

State, North Slope Borough agencies. The study(ies) will include the 

construction period and will continue for a minimum of 3 years after 

construction has been completed and production has begun. The 

monitoring studies will be a continuation of evaluating the 

effectiveness of Best Management Practice K-4a’s requirements in 

meeting the objective of K-4a and determine if any changes to the best 

management practice or any project specific mitigation(s) are 

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necessary. If changes are determined to be necessary, the BLM, with 

the permittee and/or their representative, will conduct an assessment 

of the feasibility of altering development operation (e.g., reduced 

human activity, visibility barriers, noise abatement). Any changes 

determined necessary will be implemented prior to authorization of 

any new construction. 

K-4b Best Management Practice – Brant Survey Area 

Objective: Minimize the loss or alteration of habitat for, or disturbance of, 

nesting and brood rearing brant in the Brant Survey Area. None of the area 

is available for oil and gas leasing or exploratory drilling. 

Requirement/Standard: 

a. Aerial surveys for brant nesting colonies and brood-rearing areas shall 

be conducted for a minimum of 2 years before authorization of 

construction of permanent facilities. At a minimum, the survey area 

shall include the proposed development site(s) (i.e., the footprint) and 

the surrounding 1⁄2-mile area. These surveys shall be conducted 

following accepted BLM protocol. 

b. Development may be prohibited or activities curtailed within 1⁄2-mile 

of all identified brant nesting colonies and brood-rearing areas 

identified during the 2-year survey 

K-5 Best Management Practice –Teshekpuk Lake Caribou Habitat Area 

Note: None of the area is available for oil and gas leasing or exploratory 

drilling. Therefore, K-5 will apply as a best management practice. Portions 

of K-5 that apply to permanent infrastructure are only relevant to the portion 

of the Teshekpuk Lake Caribou Habitat Area available to application for 

such infrastructure, i.e., to those areas outside of the approximately 1.1 

million acres near the lake where no new non-subsistence permanent 

infrastructure will be permitted. 

Objective: Minimize disturbance and hindrance of caribou, or alteration of 

caribou movements through portions the Teshekpuk Lake Caribou Habitat 

Area that are essential for all season use, including calving and rearing, 

insect-relief, and migration. 

Requirement/Standard: In the Teshekpuk Lake Caribou Habitat Area the 

following standards will be applied to permitted activities: 

a. Before authorization of construction of permanent facilities (limited as 

they may be by surface occupancy restrictions established in this 

decision), the permittee shall design and implement and report a study 

of caribou movement unless an acceptable study(s) specific to the 

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Teshekpuk Caribou Herd has been completed within the last 10 years. 

The study shall include a minimum of four years of current data on 

the Teshekpuk Caribou Herd movements and the study design shall be 

approved by the authorized officer in consultation with the 

appropriate federal, State, and North Slope Borough wildlife and 

resource agencies. The study should provide information necessary to 

determine facility (including pipeline) design and location. Permittee 

may submit individual study proposals or they may combine with 

other permittees in the area to do a single, joint study for the entire 

Teshekpuk Lake Caribou Habitat Area. Study data may be gathered 

concurrently with other activities as approved by the authorized 

officer and in consultation with the appropriate federal, State, and 

North Slope Borough wildlife and resource agencies. A final report of 

the study results will be prepared and submitted. Prior to the 

permitting of a pipeline in the Teshekpuk Lake Caribou Habitat Area, 

a workshop will be convened to identify the best corridor for pipeline 

construction in efforts to minimize impacts to wildlife (specifically 

the Teshekpuk Caribou Herd) and subsistence resources. The 

workshop participants will include but will not be limited to federal, 

State, and North Slope Borough representatives. All of these 

modifications will increase protection for caribou and other wildlife 

that utilize the Teshekpuk Lake Caribou Habitat Area during all 

seasons. 

b. Within the Teshekpuk Lake Caribou Habitat Area, permittee shall 

orient linear corridors when laying out oil and gas field developments 

to address migration and corralling effects and to avoid loops of road 

and/or pipeline that connect facilities. 

c. Ramps over pipelines, buried pipelines, or pipelines buried under the 

road may be required by the authorized officer, after consultation with 

appropriate federal, State, and North Slope Borough regulatory and 

resource agencies, in the Teshekpuk Lake Caribou Habitat Area where 

pipelines potentially impede caribou movement. 

d. Major construction activities using heavy equipment (e.g., sand/gravel 

extraction and transport, pipeline and pad construction, but not 

drilling from existing production pads) shall be suspended within 

Teshekpuk Lake Caribou Habitat Area from May 20 through August 

20, unless approved by the authorized officer in consultation with the 

appropriate federal, State, and North Slope Borough regulatory and 

resource agencies. The intent of this requirement is to restrict 

activities that will disturb caribou during calving and insect-relief 

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periods. If caribou arrive on the calving grounds prior to May 20, 

major construction activities will be suspended. The permittee shall 

submit with the development proposal a “stop work” plan that 

considers this and any other mitigation related to caribou early arrival. 

The intent of this latter requirement is to provide flexibility to adapt to 

changing climate conditions that may occur during the life of fields in 

the region. 

e. The following ground and air traffic restrictions shall apply in the 

areas and time periods indicated. Ground traffic restrictions apply to 

permanent oil and gas-related roads: 

1. Within the Teshekpuk Lake Caribou Habitat Area, from May 20 

through August 20, traffic speed shall not exceed 15 miles per hour 

when caribou are within 1⁄2 mile of the road. Additional strategies 

may include limiting trips, using convoys, using different vehicle 

types, etc., to the extent practicable. The permittee shall submit 

with the development proposal a vehicle use plan that considers 

these and any other mitigation. The vehicle use plan shall also 

include a vehicle-use monitoring plan. Adjustments will be 

required by the authorized officer if resulting disturbance is 

determined to be unacceptable. 

2. The permittee or a contractor shall observe caribou movement 

from May 20 through August 20, or earlier if caribou are present 

prior to May 20. Based on these observations, traffic will be 

stopped: 

a. temporarily to allow a crossing by 10 or more caribou. Sections 

of road will be evacuated whenever an attempted crossing by a 

large number of caribou appears to be imminent. The permittee 

shall submit with the development proposal a vehicle use plan 

that considers these and any other mitigation. 

b. by direction of the authorized officer throughout a defined area 

for up to four weeks to prevent displacement of calving caribou. 

The vehicle use plan shall also include a vehicle-use monitoring 

plan. Adjustments will be required by the authorized officer if 

resulting disturbance is determined to be unacceptable. 

3. Major equipment, materials, and supplies to be used at oil and gas 

work sites in the Teshekpuk Lake Caribou Habitat Area shall be 

stockpiled prior to or after the period of May 20 through August 20 

to minimize road traffic during that period. 

4. Within the Teshekpuk Lake Caribou Habitat Area aircraft use 

(including fixed wing and helicopter) shall be restricted from May 

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20 through August 20 unless doing so endangers human life or 

violates safe flying practices. Authorized users of the NPR-A may 

be restricted from using aircraft larger than a Twin Otter, and 

limited to an average of one fixed-wing aircraft takeoff and landing 

per day per airstrip, except for emergency purposes. Restrictions 

may include prohibiting the use of aircraft larger than a Twin Otter 

by authorized users of the NPR-A, including oil and gas permittee, 

from May 20 through August 20 within the Teshekpuk Lake 

Caribou Habitat Area, except for emergency purposes. The 

permittee shall submit with the development proposal an aircraft 

use plan that considers these and other mitigation. The aircraft use 

plan shall also include an aircraft monitoring plan. Adjustments, 

including perhaps suspension of all aircraft use, will be required by 

the authorized officer if resulting disturbance is determined to be 

unacceptable. This best management practice is not intended to 

restrict flights necessary to survey wildlife to gain information 

necessary to meet the stated objective of the stipulations and best 

management practices. However, flights necessary to gain this 

information will be restricted to the minimum necessary to collect 

such data. 

5. Aircraft shall maintain a minimum height of 1,000 feet above 

ground level (except for takeoffs and landings) over caribou winter 

ranges from December 1 through May 1, and 2,000 feet above 

ground level over the Teshekpuk Lake Caribou Habitat Area from 

May 20 through August 20, unless doing so endangers human life 

or violates safe flying practices. Caribou wintering ranges will be 

defined annually by the authorized officer in consultation with the 

Alaska Department of Fish and Game. This best management 

practice is not intended to restrict flights necessary to survey 

wildlife to gain information necessary to meet the stated objective 

of the stipulations and best management practices. However, 

flights necessary to gain this information will be restricted to the 

minimum necessary to collect such data. 

K-6 Lease Stipulation/Best Management Practice – Coastal Area 

Note: This measure would be applied to relevant new leases. On lands 

unavailable for leasing in the respective alternatives, K-6 would be a best 

management practice. 

Objective: Protect coastal waters and their value as fish and wildlife habitat 

(including, but not limited to, that for waterfowl, shorebirds, and marine 

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mammals), minimize hindrance or alteration of caribou movement within 

caribou coastal insect-relief areas; protect the summer and winter shoreline 

habitat for polar bears, and the summer shoreline habitat for walrus and 

seals; prevent loss of important bird habitat and alteration or disturbance of 

shoreline marshes; and prevent impacts to subsistence resources and 

activities. 

Requirement/Standard: 

a. Exploratory well drill pads, production well drill pads, or a central 

processing facility for oil or gas would not be allowed in coastal 

waters or on islands between the northern boundary of the Reserve 

and the mainland, or in inland areas within one mile of the coast. 

(Note: This would include the entirety of the Kasegaluk Lagoon and 

Peard Bay Special Areas.) Other facilities necessary for oil and gas 

production within NPR-A that necessarily must be within this area 

(e.g., barge landing, seawater treatment plant, or spill response staging 

and storage areas) would not be precluded. Nor would this stipulation 

preclude infrastructure associated with offshore oil and gas 

exploration and production or construction, renovation, or 

replacement of facilities on existing gravel sites. Lessees/permittees 

shall consider the practicality of locating facilities that necessarily 

must be within this area at previously occupied sites such as various 

Husky/USGS drill sites and Distant Early Warning-Line sites. All 

lessees/permittees involved in activities in the immediate area must 

coordinate use of these new or existing sites with all other prospective 

users. Before conducting open water activities, the lessee shall consult 

with the Alaska Eskimo Whaling Commission, the North Slope 

Borough, and local whaling captains associations to minimize impacts 

to the fall and spring subsistence whaling activities of the 

communities of the North Slope. In a case in which the BLM 

authorizes a permanent oil and gas facility within the Coastal Area, 

the lessee/permittee shall develop and implement a monitoring plan to 

assess the effects of the facility and its use on coastal habitat and use. 

b. Marine vessels used as part of a BLM-authorized activity shall 

maintain a 1-mile buffer from the shore when transiting past an 

aggregation of seals (primarily spotted seals) using a terrestrial 

haulout unless doing so would endanger human life or violate safe 

boating practices. Marine vessels shall not conduct ballast transfers or 

discharge any matter into the marine environment within 3 miles of 

the coast except when necessary for the safe operation of the vessel. 

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c. Marine vessels used as part of a BLM-authorized activity shall 

maintain a 1⁄2-mile buffer from shore when transiting past an 

aggregation of walrus using a terrestrial haulout. 

K-7 Lease Stipulation/Best Management Practice - Colville River Special 

Area 

Note: This measure would be applied to relevant new leases. On lands 

unavailable for leasing, K-7 would be a best management practice. 

Objective: Prevent or minimize loss of raptor foraging habitat (also see 

Lease Stipulation K-1). 

Requirement/Standard: If necessary to construct permanent facilities within 

the Colville River Special Area, all reasonable and practicable efforts shall 

be made to locate permanent facilities as far from raptor nests as feasible. 

Additionally, within 15 miles of raptor nest sites, significant alteration of 

high quality foraging habitat shall be prohibited unless the lessee can 

demonstrate on a site-specific basis that impacts would be minimal. Of 

particular concern are ponds, lakes, wetlands, and riparian habitats. Note: On 

a case-by-case basis, and in consultation with appropriate federal and State 

regulatory and resource agencies, essential pipeline and road crossings will 

be permitted through the Colville River Special Area where no other feasible 

or prudent options are available. 

K-8 Best Management Practice - Pik Dunes 

Note: None of the area is available for oil and gas leasing or exploratory 

drilling. Therefore, K-8 will apply as a best management practice. 

Objective: Retain unique qualities of the Pik Dunes, including geologic and 

scenic uniqueness, insect-relief habitat for caribou, and habitat for several 

uncommon plant species. 

Requirement/Standard: Surface structures, except approximately 

perpendicular pipeline crossings and ice pads, are prohibited within the Pik 

Dunes. 

K-9 Best Management Practice – Teshekpuk Lake Caribou Movement 

Corridor 

Note: None of the area is available for oil and gas leasing or exploratory 

drilling. Therefore, K-9 will apply as a best management practice. All of the 

former movement corridor northwest of Teshekpuk Lake and all but the 

eastern-most part of the other corridor that lies north of the Kogru River are 

within an area prohibiting new non-subsistence infrastructure. Therefore, 

February 2013 Appendix A: Lease Stipulations and Best Management Practices 

NPR-A IAP Record of Decision 

86 
this best management practice only applies to the lands in the former 

corridor north of the Kogru River in Ts. 14-15 N., R. 2 W., U.M. 

Objective: Minimize disturbance and hindrance of caribou, or alteration of 

caribou movements (that are essential for all season use, including calving 

and rearing, insect-relief, and migration) in the area extending from the 

eastern shore of Teshekpuk Lake eastward to the Kogru River. 

Requirement/Standard: Within the Teshekpuk Lake Caribou Movement 

Corridor, no permanent oil and gas facilities, except for pipelines or other 

infrastructure associated with offshore oil and gas exploration and 

production, will be allowed. Prior to the permitting of permanent oil and gas 

infrastructure in the Caribou Movement Corridor, a workshop will be 

convened to identify the best corridor for pipeline construction in efforts to 

minimize impacts to wildlife and subsistence resources. The workshop 

participants will include but will not be limited to federal, State, and North 

Slope Borough representatives. 

K-10 Best Management Practice – Southern Caribou Calving Area 

Note: None of the area is available for oil and gas leasing or exploratory 

drilling. Therefore, K-10 will apply as a best management practice. All but 

the eastern-most part of the former Southern Caribou Calving Area lies 

within an area prohibiting new non-subsistence infrastructure. Therefore, 

this best management practice only applies to the lands in the former area 

T. 14 N., Rs. 1-2 W., U.M.; T. 14 N., R. 1 E., U.M; and T. 15 N., R. 2 W., 

U.M. 

Objective: Minimize disturbance and hindrance of caribou, or alteration of 

caribou movements (that are essential for all season use, including calving 

and post calving, and insect-relief) in the area south/southeast of Teshekpuk 

Lake. 

Requirement/Standard: Within the Southern Caribou Calving Area, no 

permanent oil and gas facilities, except pipelines or other infrastructure 

associated with offshore oil and gas exploration and production, will be 

allowed. Prior to the permitting of permanent oil and gas infrastructure in the 

Southern Caribou Calving Area, a workshop will be convened to identify the 

best corridor for pipeline construction in efforts to minimize impacts to 

wildlife and subsistence resources. The workshop participants will include 

but will not be limited to federal, State, and North Slope Borough 

representatives. 

February 2013 Appendix A: Lease Stipulations and Best Management Practices 

NPR-A IAP Record of Decision 

87 
K-11 Lease Stipulation/Best Management Practice – Western Arctic Herd 

Habitat Area 

Note: This measure would be applied to relevant new leases. On lands 

unavailable for leasing, K-11 would be a best management practice. Portions 

of K-11 that apply to permanent infrastructure are only relevant to the 

northern portion of the Utukok River Uplands Special Area available to 

application for such infrastructure. 

Objective: Minimize disturbance and hindrance of caribou, or alteration of 

caribou movements through the Utukok River Uplands Special Area that are 

essential for all season use, including calving and rearing, insect-relief, and 

migration. 

Requirement/Standard: In the Utukok River Uplands Special Area the 

following standards will be applied to permitted activities: 

a. Before authorization of construction of permanent facilities, the lessee 

shall design and implement and report a study of caribou movement 

unless an acceptable study(s) specific to the Western Arctic Herd has 

been completed within the last 10 years. The study shall include a 

minimum of four years of current data on the Western Arctic Herd’s 

movements and the study design shall be approved by the authorized 

officer in consultation with the appropriate federal, State, and North 

Slope Borough wildlife and resource agencies and the Western Arctic 

Caribou Herd Working Group. The study should provide information 

necessary to determine facility (including pipeline) design and 

location. Lessees may submit individual study proposals or they may 

combine with other lessees in the area to do a single, joint study for 

the entire Utukok River Uplands Special Area. Study data may be 

gathered concurrently with other activities as approved by the 

authorized officer and in consultation with the appropriate federal, 

State, and North Slope Borough wildlife and resource agencies. A 

final report of the study results will be prepared and submitted. Prior 

to the permitting of a pipeline in the Utukok River Uplands Special 

Area, a workshop will be convened to identify the best corridor for 

pipeline construction in efforts to minimize impacts to wildlife 

(specifically the Western Arctic Herd) and subsistence resources. The 

workshop participants will include but will not be limited to federal, 

State, and North Slope Borough representatives. All of these 

modifications will increase protection for caribou and other wildlife 

that utilize the Utukok River Uplands Special Area during all seasons. 

b. Within the Utukok River Uplands Special Area, lessees shall orient 

linear corridors when laying out oil and gas field developments to 

February 2013 Appendix A: Lease Stipulations and Best Management Practices 

NPR-A IAP Record of Decision 

88 
address migration and corralling effects and to avoid loops of road 

and/or pipeline that connect facilities. 

c. Ramps over pipelines, buried pipelines, or pipelines buried under the 

road may be required by the authorized officer, after consultation with 

appropriate federal, State, and North Slope Borough regulatory and 

resource agencies, in the Utukok River Uplands Special Area where 

pipelines potentially impede caribou movement. 

d. Major construction activities using heavy equipment (e.g., sand/gravel 

extraction and transport, pipeline and pad construction, but not 

drilling from existing production pads) shall be suspended within 

Utukok River Uplands Special Area from May 20 through August 20, 

unless approved by the authorized officer in consultation with the 

appropriate federal, State, and North Slope Borough regulatory and 

resource agencies. The intent of this requirement is to restrict 

activities that will disturb caribou during calving and insect-relief 

periods. If caribou arrive on the calving grounds prior to May 20, 

major construction activities will be suspended. The lessee shall 

submit with the development proposal a “stop work” plan that 

considers this and any other mitigation related to caribou early arrival. 

The intent of this latter requirement is to provide flexibility to adapt to 

changing climate conditions that may occur during the life of fields in 

the region. 

e. The following ground and air traffic restrictions shall apply to 

permanent oil and gas-related roads in the areas and time periods 

indicated: 

1. Within the Utukok River Uplands Special Area, from May 20 

through August 20, traffic speed shall not exceed 15 miles per hour 

when caribou are within 1⁄2 mile of the road. Additional strategies 

may include limiting trips, using convoys, using different vehicle 

types, etc., to the extent practicable. The lessee shall submit with 

the development proposal a vehicle use plan that considers these 

and any other mitigation. The vehicle use plan shall also include a 

vehicle-use monitoring plan. Adjustments will be required by the 

authorized officer if resulting disturbance is determined to be 

unacceptable. 

2. The lessee or a contractor shall observe caribou movement from 

May 20 through August 20, or earlier if caribou are present prior to 

May 20. Based on these observations, traffic will be stopped: 

a. Temporarily to allow a crossing by 10 or more caribou. 

Sections of road will be evacuated whenever an attempted 

February 2013 Appendix A: Lease Stipulations and Best Management Practices 

NPR-A IAP Record of Decision 

89 
crossing by a large number of caribou appears to be imminent. 

The lessee shall submit with the development proposal a 

vehicle use plan that considers these and any other mitigation. 

b. By direction of the authorized officer throughout a defined area 

for up to four weeks to prevent displacement of calving caribou. 

The vehicle use plan shall also include a vehicle-use monitoring 

plan. Adjustments will be required by the authorized officer if 

resulting disturbance is determined to be unacceptable. 

3. Major equipment, materials, and supplies to be used at oil and gas 

work sites in the Utukok River Uplands Special Area shall be 

stockpiled prior to or after the period of May 20 through August 20 

to minimize road traffic during that period. 

4. Within the Utukok River Uplands Special Area aircraft use 

(including fixed wing and helicopter) shall be restricted from May 

20 through August 20 unless doing so endangers human life or 

violates safe flying practices. Authorized users of the NPR-A may 

be restricted from using aircraft larger than a Twin Otter, and 

limited to an average of one fixed-wing aircraft takeoff and landing 

per day per airstrip, except for emergency purposes. Restrictions 

may include prohibiting the use of aircraft larger than a Twin Otter 

by authorized users of the NPR-A, including oil and gas lessees, 

from May 20 through August 20 within the Utukok River Uplands 

Special Area, except for emergency purposes. The lessee shall 

submit with the development proposal an aircraft use plan that 

considers these and other mitigation. The aircraft use plan shall 

also include an aircraft monitoring plan. Adjustments, including 

perhaps suspension of all aircraft use, will be required by the 

authorized officer if resulting disturbance is determined to be 

unacceptable. This lease stipulation is not intended to restrict 

flights necessary to survey wildlife to gain information necessary 

to meet the stated objective of the stipulations and best 

management practices. However, flights necessary to gain this 

information will be restricted to the minimum necessary to collect 

such data. 

5. Aircraft shall maintain a minimum height of 1,000 feet above 

ground level (except for takeoffs and landings) over caribou winter 

ranges from December 1 through May 1, and 2,000 feet above 

ground level over the Utukok River Uplands Special Area from 

May 20 through August 20, unless doing so endangers human life 

or violates safe flying practices. Caribou wintering ranges will be 

February 2013 Appendix A: Lease Stipulations and Best Management Practices 

NPR-A IAP Record of Decision 

90 
defined annually by the authorized officer in consultation with the 

Alaska Department of Fish and Game. This lease stipulation is not 

intended to restrict flights necessary to survey wildlife to gain 

information necessary to meet the stated objective of the 

stipulations and best management practices. However, flights 

necessary to gain this information will be restricted to the 

minimum necessary to collect such data. 

Summer Vehicle Tundra Access 

L-1 Best Management Practice 

Objective: Protect stream banks and water quality; minimize compaction and 

displacement of soils; minimize the breakage, abrasion, compaction, or 

displacement of vegetation; protect cultural and paleontological resources; 

maintain populations of, and adequate habitat for birds, fish, and caribou and 

other terrestrial mammals; and minimize impacts to subsistence activities. 

Requirement/Standard: On a case-by-case basis, BLM may permit lowground-pressure vehicles to travel off of gravel pads and roads during times 

other than those identified in Best Management Practice C-2a. Permission 

for such use would only be granted after an applicant has: 

a. Submitted studies satisfactory to the authorized officer of the impacts 

on soils and vegetation of the specific low-ground-pressure vehicles to 

be used. These studies should reflect use of such vehicles under 

conditions similar to those of the route proposed for use and should 

demonstrate that the proposed use would have no more than minimal 

impacts to soils and vegetation. 

b. Submitted surveys satisfactory to the authorized officer of subsistence 

uses of the area as well as of the soils, vegetation, hydrology, wildlife 

and fish (and their habitats), paleontological and archaeological 

resources, and other resources as required by the authorized officer. 

c. Designed and/or modified the use proposal to minimize impacts to the 

authorized officer’s satisfaction. Design steps to achieve the 

objectives and based upon the studies and surveys may include, but 

not be limited to, timing restrictions (generally it is considered 

inadvisable to conduct tundra travel prior to August 1 to protect 

ground-nesting birds), shifting of work to winter, rerouting, and not 

proceeding when certain wildlife are present or subsistence activities 

are occurring. At the discretion of the authorized officer, the plan for 

summer tundra vehicle access may be included as part of the spill 

February 2013 Appendix A: Lease Stipulations and Best Management Practices 

NPR-A IAP Record of Decision 

91 
prevention and response contingency plan required by 40 CFR 112 

(Oil Pollution Act) and Best Management Practice A-4. 

General Wildlife and Habitat Protection 

M-1 Best Management Practice 

Objective: Minimize disturbance and hindrance of wildlife, or alteration of 

wildlife movements through the NPR-A. 

Requirement/Standard: Chasing wildlife with ground vehicles is prohibited. 

Particular attention will be given to avoid disturbing caribou. 

M-2 Best Management Practice 

Objective: Prevent the introduction, or spread, of non-native, invasive plant 

species in the NPR-A. 

Requirement/Standard: Certify that all equipment and vehicles (intended for 

use either off or on roads) are weed-free prior to transporting them into the 

NPR-A. Monitor annually along roads for non-native invasive species, and 

initiate effective weed control measures upon evidence of their introduction. 

Prior to operations in the NPR-A, submit a plan for the BLM’s approval, 

detailing the methods for cleaning equipment and vehicles, monitoring for 

weeds and weed control. 

M-3 Best Management Practice 

Objective: Minimize loss of populations of, and habitat for, plant species 

designated as Sensitive by the BLM in Alaska. 

Requirement/Standard: If a development is proposed in an area that provides 

potential habitat for a BLM Sensitive Plant Species, the development 

proponent would conduct surveys at appropriate times of the summer season 

and in appropriate habitats for the Sensitive Plant Species that might occur 

there. The results of these surveys will be submitted to the BLM with the 

application for development. 

M-4 Best Management Practice 

Objective: Minimize loss of individuals of, and habitat for, mammalian 

species designated as Sensitive by the BLM in Alaska. 

Requirement/Standard: If a development is proposed in an area that provides 

potential habitat for the Alaska tiny shrew, the development proponent 

would conduct surveys at appropriate times of the year and in appropriate 

February 2013 Appendix A: Lease Stipulations and Best Management Practices 

NPR-A IAP Record of Decision 

92 
 

habitats in an effort to detect the presence of the shrew. The results of these 

surveys will be submitted to BLM with the application for development. 

February 2013 Appendix A: Lease Stipulations and Best Management Practices 

NPR-A IAP Record of Decision 

93 
February 2013 Appendix A: Lease Stipulations and Best Management Practices 

NPR-A IAP Record of Decision 

94 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

State of Alaska Statutes and Regulations Protecting 

Environmental Quality 

Alaska Statutes 

AS 46.03.100 Waste management and disposal authorization 

AS 46.03.740 Oil pollution 

AS 46.03.745 Hazardous substance release 

AS 46.03.800 Water nuisances 

AS 46.03.810 Air and land nuisances 

AS 46.14.010 Emission control regulation 

Alaska Department of Environmental Quality Regulations 

Air Quality Control 

18 AAC 50.030 State air quality control plan 

18 AAC 50.045 Prohibitions 

18 AAC 50.065 Open burning 

18 AAC 50.110 Air pollution prohibited 

Solid Waste Management 

18 AAC 60.200 Permit requirement 

18 AAC 60.230 Disease vector, wildlife and domestic animal control 

18 AAC 60.233 Controlling impact outside facility boundaries 

Wastewater Disposal 

18 AAC 72.050 Minimum treatment 

18 AAC 72.200 Application for department approval 

18 AAC 72.215 Permit required – domestic wastewater 

18 AAC 72.275 Disposal systems 

18 AAC 72.500 Permit required – nondomestic wastewater 

Oil and other Hazardous Substances Pollution Control 

18 AAC 75.007 General oil pollution prevention requirements 

18 AAC 75.045 Operating requirements for exploration and production facilities 

18 AAC 75.047 Requirements for flowlines at production facilities 

18 AAC 75.055 Leak detection, monitoring and operating requirements for crude oil 

transmission pipelines 

18 AAC 75.075 Secondary containment requirements for aboveground storage tanks 

18 AAC 75.080 Requirements for facility oil piping 

18 AAC 75.300-396 Discharge reporting, cleanup and disposal of oil and other hazardous 

substances 

18 AAC 75.400-496 Oil discharge prevention and contingency plans and nontank vessel 

plans 

18 AAC 75.605-670 Civil penalties for discharge of petroleum and petroleum product and 

byproducts 

18 AAC 75.700-730 Surface oiling 
 

 

18 AAC 75.800-830 Oil discharge for scientific purposes 

These statutes and regulations can be obtained from links here: 

http://dec.alaska.gov/commish/regulations/index.htm 
Appendices  Final Supplemental Environmental Impact Statement

Alpine Satellite Development Plan for the Proposed Greater Mooses Tooth 2 Development Project

APPENDIX K

NORTH SLOPE AVIATION DISTURBANCE INFORMATION

Greater Mooses Tooth 2 Development Project

Draft Supplemental Environmental Impact Statement

Appendix K: 

(Chapter 4 Section 4.5: Subsistence)

North Slope Aviation Disturbance Information 
A-1: 2016 North Slope Borough Oil and Gas Forum Final Report1: 

Summary of Breakout Session #6: Reducing Impacts from North Slope Air Traffic

Desired Outcome of Breakout Session: Provide an opportunity for North Slope residents to 

identify their concerns about air traffic and identify future cooperation among stakeholders to 

reduce impacts

Common Themes Identified by Session Participants: 

• Increase communication (37 votes) 

• Reduce frustration by using alternate transport modes and local hire (37 votes) 

• Educate researchers, identify their impacts and mitigate (33 votes) 

• Time and area closures - Conflict Avoidance Agreement (CAA) model (32 votes) 

• Consolidate agency site inspections (14 votes) 

• Social media – connecting locals (8 votes) 

• Be good neighbors (5 votes) 

• Best Practices (4 votes)

Specific Recommendations: 

• Increase communication with local residents - use social media.

• Consider time and area closures (use CAA model). 

• Reduce flights needed by deploying fuel and supplies by land during winter. 

• Use camps for research and to decrease impacts.

• Remove areas from lease sales to reduce impacts.

• Use a “good neighbor” approach. 

• Require permittees to identify where they will be landing and type of aircraft 

• Hire locals, use subsistence advisors.

• Identify who researchers should contact. 

• Coordinate agency inspections (e.g., combine flights to reduce aircraft). 

• Tracking flights -Consolidate flight information among agencies. 

• Minimize research projects and share information (BLM and EPA have done this). 

• Identify what can be done to mitigate impacts before the fact.

• Agencies should communicate with villagers in the same way that industry does. 

• Consider involving the North Slope Science Initiative to address this issue. 

• Help government agencies learn from industry to help relationships with local people. 

• Reduce “stick picking” to reduce impacts of aircraft.

 

1 The complete Final Report of the NSB 2016 Oil and Gas Forum is available online at: http://www.northslope.org/assets/images/uploads/news/FinalOGforumReport.pdf
• Consider impacts from all aircraft (industry, agency, researchers, ecotourism, recreational

• users).

• Document history and lessons learned. 

• Share information about subsistence times: 

• Many hunting seasons on the North Slope; winter, breakup, etc. 

• Share a subsistence calendar to identify what types of hunting are occurring when. 

• Increase communication between researchers and residents:

• Inform researchers regarding all parties to contact – find ways to inform researchers as

• to how to communicate and mitigate impacts.

• Continue use of call centers

• Shell would call into call centers to find out where people were going 

• Agencies should contribute to funding of call centers. 

• Identify flight patterns - build on existing Audubon map. 

Other Comments: 

• Communication should be a two-way street. Residents, industry and other agencies 

willing to communicate, just need to make it happen. 

• Frustration because of a lack of responsiveness from agencies.

• Delegation of authority is not clear – don’t know who is responsible. 

• Call centers:

o What is the status of call centers? Shell funded them in the past, but not this year. 

o Funding agencies should help contribute to these call centers to help villages with 

o cultural needs and subsistence needs.

o Conoco Phillips has a daily call number that people can call. Also have a daily 

recording to let people know what the activity is in the area (Nuiqsut only). 

• Barrow search and rescue can be called but looking out for game. 

• Planes do interfere with the subsistence lifestyle – villagers live off the food of the land 

and sea - villagers impacted by aircraft and by outside hunters coming in to their area. 

• After impact has occurred it is too late and hunter does not get any game and loses money 

on the hunt. This has gone on for several years now. Still talking but not solved yet. 

These are real situations when a hunter can’t provide food for family or community. 

People go without food as a result. 

• Long history – lots of data, must sit down and put it all together. Agency communication 

and

• cooperation is needed. Permits are given to many different people and agencies which 

• villagers don’t know about. They are told it is “every day stuff.” Tourism, sightseeing, 

sport 

• fishing, etc. use aircraft. They can disrupt the wildlife actions and patterns. Take the local 
• people’s history in mind is important. 

• Non-subsistence hunters have been a problem in Anaktuvuk Pass. 

• Wainwright worked with industry to talk about impacts and mitigation, industry hired 

people and worked with the village dates. Agencies don’t do this and are not as sensitive. 

Want industry to communicate with people but the agencies don’t follow that example. 

• Wainwright has cancelled at least one project due to the impacts of aircraft on people. 

• Communication must go both ways. 

• Alaska Eskimo Whaling Commission is a leader – Diomede was declared nutritionally a 

disaster

• area – no food, no resources for them. 

• 10 Summary Report - North Slope Borough 2016 Oil and Gas Forum: Appendix E 

• Government agencies are not sensitive to the local subsistence calendars.

• Lack of local hire increases the need for aircraft.

• Tracking:

o Subsistence Advisory Panel Meetings identify impacts.

o Permits (number of takeoffs and landings). 

o As a resident I don’t know who is out there with aircraft.

• It is very expensive to travel. 

• Air traffic over and around the walrus haul out at Point Lay creates a hazard to the walrus 

herd - stampeding occurs. 
A-2 BLM NPR-A Subsistence Advisory Panel Recommendations on Aviation 2000 – 2016 

Note: There are 178 recommendations in the most recent spreadsheet of SAP recommendations. 

Of those, the following 31 recommendations refer specifically to aviation. These 

recommendations account for over over 17 percent of the total. 

There have been numerous SAP recommendations that refer to conflicts that likely meant 

aviation disturbance; they were not included. 

1. #21 6/2000, Thomas Napageak Sr.: Concern: People have witnessed FWS (or another 

research entity) hovering over the herd, trying to turn them away from coming toward the 

village. I think it is not appropriate for Fish and Wildlife, or the oil companies, to hover over 

caribou. Fly high, or get out of there. 

2. #23 9/2000, Paul Ogroogak: Also planes have been flying low, thinks it’s the Helmericks, 

and Fish and Game should look at that. 

3. #46 8/2001, SAP Panel: Conflicts between subsistence users and aircraft, especially 

helicopters.

4. #68 8/2002: Concern that there was a lot of helicopter activity in the Nuiqsut area during 

the summer. 

5. #78 6/2003: Arnold Brower: Helicopter flights in the spring impacted goose hunter--

recommended to the AO to have helicopters fly higher or lessen the number of flights. 

6. #82 6/ 2003: Baxter Hopson: If the oil companies or contractors say they are going to have a 

set number of flights, then the BLM needs to make sure they stay within this self-imposed 

limit.

7. #109 12/2005, Dorothy Edwardsen: July and August are very important subsistence months, 

aircraft use (helicopter and fixed wing) should be kept to a minimum during this time, 

especially around communities 

8. #111 3/2005, Taqulik Hepa: Recommendation that the different companies working in 

NPR-A hold a meeting to coordinate studies and helicopter use in order to reduce the impact 

of the studies. 

9. #131 8/2007, SAP Panel: Recommendation that the BLM create two brochures to help 

alleviate impacts to subsistence from aircraft (primarily helicopter) use. The SAP 

characterized the problem as they saw it as: 1) occurrences when a helicopter directly 

interferes with a hunt (i.e., moving caribou or other game away from the hunter); 2) the 

belief that many pilots intentionally herd caribou using the helicopter, as this has been 

witnessed by residents on the Slope; 3) the concern that pilots don’t know what the 

rules/stipulations are; and 4) the belief that many pilots do know what the rules are, but 

purposefully push the limits of the rules to see what they can get away with. 
10. #135 12/2007, Nanuaq Thorpe: Recommended that the Flight Use brochures be distributed 

to all of the small aircraft companies and their pilots who fly on the North Slope. 

11. #148 4/2009, Isaac Nukapigak: Recommended to BLM employees that something needs to 

be done about the interference to subsistence waterfowl hunters of helicopters during breakup. The helicopters are there to study hydrology and break-up, which coincides with 

waterfowl hunting for the community. Isaac recommended that all parties (researchers with 

the BLM, USGS, and contractors to CPAI) get together to talk about helicopter routes, 

frequency of visits and timing. 

12. #154 12/2010, Andrew Hopson: The SAP should talk with the companies (and government 

agencies) developing the road to Umiat and try to stop the use of private aircraft (hunters) in 

that area.

13. #166 3/2012, Panel: SAP recommended that Alaska Fish and Game wildlife surveys 

coordinate their flights with Search and Rescue and the BLM encourage other permitted 

surveys to do the same. 

14. #172 3/2012, Raymond Aguvluk: Aguvluk reported that because Wainwright has had so 

many concerns with helicopters that BLM and researchers should save money and disturb 

fewer hunters by using boats and other less disruptive travel methods. 

15. #177 11/2012, Panel: Recommended that BLM arrange to have a representative of the FAA 

present at a SAP meeting to discuss whether there is any possibility of establishing special 

restrictions on flights over the NPR-A.

16. #178 11/2012, SAP Panel: Recommended that BLM establish a system that allows 

information on North Slope aviation (flight paths, tail numbers) to be shared among the 

public, cities, and tribal governments. 

17. #210 2/2014, Joe Sage: Baseline information on the impacts of aircraft traffic on wildlife is 

needed to illustrate that the traffic is depriving the animals of the time they need to rest and 

feed in certain areas and aircraft traffic needs to be reduced. 

18. #211 2/2014, Joe Sage and Sam Kunaknana: Researchers and others using aircraft should 

camp in one site, visit the sites they need to study around them by other means, and then fly 

to another site to eliminate take offs and landings.

19. #212 2/2014, Joe Sage and Bart Ahsogeak: Tribes, industry, and agencies need to work 

together to improve enforcement on aircraft restrictions. 

20. #214 9/2014, Warren Lampe: Kuparuk River near Point Lay be added to the BLM’s 

Aviation Awareness and Conflict Avoidance letter as a heavily used subsistence river that 

should be avoided by aircraft whenever possible. 
21. #217 9/2014, Bart Ahsogeak: Language should be added to the Aviation Awareness and 

Conflict Avoidance letter instructing permittees and others involved with aviation on the 

North Slope to contact the city administration or the Tribe before flying in the area and to 

provide notification of when and where aircraft activity will occur 

22. #220 9/2014, Qaiyaan Harcharek: Amendment to BMP F-1 (e): The measure currently 

requires that aircraft maintain an altitude of at least 2,000 feet over the Teshekpuk Lake 

Caribou Herd Area from May 20 through August 20. Harcharek suggested that BLM extend 

those dates from May 20 through October 20 to better protect the fall hunting season. 

23. #221 9/2014, Qaiyaan Harcharek: BLM require aircraft information at the permit 

application stage (color, description, tail number). 

24. #133 2/2015, Joe Sage: Industry and researchers share data whenever possible to save 

money and reduce aircraft traffic. Requests that everyone involved with activities on the 

North Slope listen carefully to all the concerns about aircraft disturbance and understand 

what a real and significant impacts it is on indigenous hunters. 

25. #137 9/2015, Warren Lampe and Terry Tagarook: Lampe: Although studies have declined 

around Point Lay, recommends that all permitting agencies notify the community about all 

permits, especially those for in the area that will use aircraft. Tagarook: any entity giving 

permits out improve the process of notifying potentially affected communities

26. #143 9/2015, Colleen Akpik-Lemen: BLM increase its enforcement arm so that it is not left

to the community members to argue with aircraft users and outside hunters. 

27. #159 6/1/2016, Qaiyaan Harcharek: Requested that the soundscape ecology (aircraft noise 

monitoring) project be expanded to Anaktuvuk Pass and other villages and subsistence 

areas.

28. #161 6/1/2016, Bart Ahsogeak: Recommended that all studies scheduled to occur on the 

North Slope be delayed for two years in order to reduce the amount of helicopter traffic 

during caribou hunting season. 

29. #165 6/1/2016, Sam Kunaknana: Recommended that State of Alaska freshwater fish 

inventory participants float down rivers instead of flying with helicopters.

30. #175 6/1/2016 Sam Kunaknana: Recommended that at the next meeting the BLM show total 

number of flights, including on the east (state) side, taken throughout the study season to 

better analyze cumulative impacts.

31. #176 6/1/2016, Qaiyaan Harcharek: Recommended that any studies where it is feasible 

should hire local boats for transportation rather than fly in helicopters. 
IÑUPIAT COMMUNITY of the ARCTIC SLOPE

An IRA Regional Tribal Government

P.O Box 934 • Barrow, Alaska 99723

Ph: (907)852-4227 (888)788-4227 Fax: (907)852-4246

A-3: ICAS Resolution on Aviation 

 

Resolution 2014- 12 

RESOLUTION ADDRESSING THE INALIENABLE NATURE 

OF INUPIAT SUBSISTENCE/HARVEST RIGHTS WITHIN THE ARCTIC SLOPE

WHEREAS, The Inupiat Community of the Arctic Slope (ICAS) is a federally recognized Native tribe of 

Inupiat Eskimos under the Indian Reorganization Act of 1934, a Regional Tribal Government, as 

amended, whose governing body is the ICAS Executive Board with representatives from all eight Inupiat 

tribal councils in the Arctic Slope of Alaska; and 

WHEREAS, ICAS Regional Tribal Council (a,k.a, ICAS Executive Board) is the governing body of 

ICAS and is responsible for protecting the interests of its tribal members and its rights of self -

governance; and 

WHEREAS ,A Resolution addressing the high air traffic low flying airplanes, helicopters, and aircraft 

that hinder and divert the migrating caribou herds away from our villages of Barrow , Atqasuk, 

Wainwright, Point Lay, Point Hope, Kaktovik, Nuiqsut, and Anaktuvuk Pass, during the summer months 

June through October, that usually come to our villages, for insect relief, and escapement from predators, 

and 

WHEREAS, the tribe represent the interest of over 9,000 members residing in the Arctic Communities of 

Anaktuvuk Pass, Atqasuk, Barrow, Kaktovik, Nuiqsut, Point Hope, Point Lay, and Wainwright, and, 

WHEREAS,ICAS was founded to promote the security, and social welfare of its members, to exercise its 

power of the Tribal self-government, and to advance, protect, and preserve its common interest as 

descendants of the aboriginal Inupiat people of the Arctic Slope region of Alaska, and,
WHEREAS, Inupiat subsistence hunting, fishing, trapping, whaling, and gathering rights must take 

preference over any non-subsistence use of wildlife resources in the Arctic Slope region, and no other 

nations shall not interfere with our subsistence hunting rights and

WHEREAS, to alleviate high air traffic low flying airplanes, helicopters, and aircraft that hinder and 

divert the migrating caribou herds away from our village, and 

NOW THEREFORE BE IT RESOLVED, that the Inupiat Community of the Arctic Slope is seeking 

assistance from the Office of Subsistence Management, Federal Aviation Administration, Bureau of Land 

Management Subsistence Advisory Panel, North Slope Borough Wildlife Department, North Slope 

Borough Game Management Board, BLM Subsistence Advisory Board, Federal Subsistence Advisory 

Panel, Bureau of Land Management Advisory Panel, Alaska National Meritime Wildlife Refuge , Gates 

of the Arctic National Park Service, U.S. Department of Office of Interior Fish & Wildlife Service, and 

Department of Interior to alleviate the high air traffic low flying aircraft, airplanes, and helicopter use 

from diverting the caribou migrations to our villages, and 

BE IT FURTHER RESOLVED, that the Inupiat Community of the Arctic Slope has adopted and 

passed this resolution at the Inupiat Community of the Arctic Slope Annual meeting on August 23, 2014, 

in Barrow, Alaska. 

_____________________________ ______________________________ 

George Olemaun , ICAS President Doreen Ahgeak , ICAS Secretary 

Appendices  Final Supplemental Environmental Impact Statement

Alpine Satellite Development Plan for the Proposed Greater Mooses Tooth 2 Development Project

APPENDIX L

ANILCA 810 SUBSISTENCE ANALYSIS

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APPENDIX L: ANILCA § 810 ANALYSIS OF 

SUBSISTENCE IMPACTS

This analysis of subsistence impacts is for the proposed Greater Mooses Tooth Unit 2 (GMT 2) 

Development Project Supplemental Environmental Impact Statement (SEIS). The GMT2 SEIS

supplements the 2004 Alpine Satellite Development Plan (ASDP) EIS. ConocoPhillips Alaska, Inc. 

(ConocoPhillips) submitted an application to the Bureau of Land Management (BLM) for a permit to drill 

and related authorizations in August 2015. The proposed GMT2 site is located on Alaska’s North Slope in 

the northeast corner of the National Petroleum Reserve in Alaska (NPR-A), immediately west of the 

Colville River Delta and approximately 16.5 miles west of the town of Nuiqsut. 

The proposed GMT2 drill site is located on BLM-managed lands selected by the Kuukpik Corporation, 

the Alaska Native Claims Settlement Act (ANCSA) village corporation for the community of Nuiqsut. 

Two of the four alternatives analyzed in the GMT2 SEIS include an access road to the GMT2 drill site 

from the GMT1 pad. Each action alternative includes a pipeline connecting GMT2 and GMT1. 

The GMT2 site is one of five drill sites that were included in the 2004 ASDP EIS. The BLM issued a 

Record of Decision (ROD) in 2004 that approved the Preferred Alternative for permitting. In the ASDP 

EIS, the GMT1 and GMT2 sites were referred to as CD6 and CD7 respectively. After the ROD was 

signed, it was determined that GMT1 and GMT2 were not located in the same reservoir as the other 

Alpine satellites. In 2008, the GMT Unit (GMTU) was formed within the NPR-A, and satellites CD6 and 

CD7 were officially renamed GMT1 and GMT2. 

In 2012, the BLM prepared the NPR-A Integrated Activity Plan (IAP)/EIS, a leasing and land 

management plan for over 22 million acres of BLM-managed land in the NPR-A. In 2014, the BLM 

completed a SEIS to evaluate the proposed GMT1 Development Project. The GMT2 SEIS tiers to these 

previous analyses and incorporates new data and site-specific information. The Alaska National Interest 

Lands Conservation Act (ANILCA) § 810 evaluations for these plans are summarized in GMT2 SEIS § 

1.4.3.1. 

The current proposal for development of the GMT2 drill site has been revised since the BLM authorized 

it in the 2004 ASDP ROD. Notable revisions include: 

• A large portion of the GMT1-GMT2 access road and pipelines were located within the 3-mile 

Fish Creek Setback in the 2004 design. In the 2014 design, the drill pad was located in the 

Colville River Special Area. In response to public input, the current design locates the drill pad

north of the Colville River Special Area and avoids the Fish Creek Setback. 

• The size of the proposed GMT2 drill pad, previously 9.1 acres, is now 14 acres to accommodate 

48 wells, compared to 20 wells permitted in 2004. 

• The proposed 8.2-mile GMT1-GMT2 access road is 1.8 miles longer than the CD6-CD7 road 

permitted in 2004 because of the relocation of the Nigliq Channel bridge and relocation of the 

GMT1 and GMT2 drill pads. 

• The proposed GMT2 project’s total gravel footprint is 78 acres compared to 50.6 acres permitted 

in 2004. The total gravel requirement is 671,300 cubic yards compared to 339,000 cubic yards 

permitted in 2004. 
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• The proposed GMT1-GMT2 access road design currently includes three 1.2-acre vehicle pullouts 

to accommodate use, entrance, and egress of the road corridor by subsistence users and overland 

travelers with highway vehicles, snowmachines, and four-wheelers.

• The proposed gravel source for the project was originally the Clover Site, which is located on 

BLM-managed lands. The gravel source currently proposed is the Arctic Slope Regional 

Corporation (ASRC) mine site, located 4.5 miles east of Nuiqsut. 

These modifications to the proposed project, the length of time that has passed since issuing the 2004 

ASDP ROD, the level of public interest in the project, construction of the Nuiqsut Spur Road in 2014-15, 

and updated subsistence harvest and use pattern data were among the factors the BLM considered in its 

decision to prepare a SEIS for the GMT2 Development Project. 

Chapters 3 and 4 of the GMT2 SEIS describe the current environmental status of the project area and 

potential effects of the alternatives to subsistence and subsistence resources. This appendix uses that 

information to evaluate potential impacts to subsistence pursuant to § 810(a) of ANILCA as directed in

BLM IM AK-2011-008. 

A.1 SUBSISTENCE EVALUATION FACTORS

Section 810(a) of ANILCA, 16 United States Code (USC) § 3120(a), requires that an evaluation of 

subsistence uses and needs be completed for any federal determination to “withdraw, reserve, lease, or 

otherwise permit the use, occupancy or disposition of public lands.” The GMT2 drill pad, sections of the 

GMT2 gravel access road (under Alternatives A and B) and sections of the pipeline and ice road (under 

all action alternatives) are on BLM-managed lands and require BLM authorization. Thus, evaluation of 

potential impacts to subsistence under ANILCA § 810(a) must be completed for the GMT2 project. 

Evaluations of all impacts to subsistence uses and needs apply regardless of land status. 

ANILCA requires that this evaluation includes findings on 3 specific issues: 

1) The effect of use, occupancy, or disposition on subsistence uses and needs;

2) The availability of other lands for the purposes sought to be achieved; and 

3) Other alternatives that would reduce or eliminate the use, occupancy, or disposition of public 

lands needed for subsistence purposes (16 USC § 3120(a)). 

Three factors are considered when determining if a significant restriction of subsistence uses and needs 

may result from the proposed action and alternatives or in the cumulative case:

1) Reductions in the abundance of subsistence resources caused by a decline in the population or 

amount of harvestable resources; 

2) Reductions in the availability of resources used for subsistence purposes caused by alteration of 

their normal locations, migration, or distribution patterns; and, 

3) Limitations on access to subsistence resources, including from increased competition for the 

resources (BLM IM AK-2011-008). 

A finding that the proposed action may significantly restrict subsistence uses initiates requirements to 

notify the State of Alaska and appropriate regional and local subsistence committees, hold hearings in the 

affected communities, and make the following determinations before the BLM can authorize use of the 

public lands: 
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1) Such a significant restriction of subsistence uses is necessary, consistent with sound management 

principles for the utilization of the public lands; 

2) The proposed activity will involve the minimal amount of public lands necessary to accomplish 

the purposes of the use, occupancy, or other disposition; and 

3) Reasonable steps will be taken to minimize adverse effects upon subsistence uses and resources 

resulting from such actions (§ 810(a)(3)). 

A proposed action and/or alternative would be considered to significantly restrict subsistence uses if, after 

consideration of stipulations or protection measures (i.e., lease stipulations, Best Management Practices 

(BMPs), etc.) included as a part of each alternative, it can be expected to result in a substantial reduction 

in the opportunity to continue subsistence uses of renewable resources. Substantial reductions in the 

opportunity to continue subsistence uses generally are caused by large reductions in resource abundance,

a major redistribution of resources, extensive interference with access, or major increases in the use of 

those resources by non-subsistence users (BLM IM AK-2011-008). 

In addition to ANILCA, Environmental Justice, as defined in Executive Order 12898, calls for an analysis 

of the effects of federal actions on minority populations with regard to subsistence. Specifically, 

Environmental Justice is:

The fair treatment and meaningful involvement of all people regardless of race, color, national 

origin, or income with respect to the development, implementation, and enforcement of environmental 

laws, regulations, and policies. Fair treatment means that no group of people, including a racial, 

ethnic, or socioeconomic group should bear a disproportionate share of the negative environmental 

consequences resulting from industrial, municipal, and commercial operations or the execution of 

federal, state, local, and tribal programs and policies (EPA, 2016).

Section 4-4 of the Executive Order on Environmental Justice, regarding the Subsistence Consumption of 

Fish and Wildlife, requires federal agencies to collect, maintain, and analyze information on the 

consumption patterns of populations who principally rely on fish and/or wildlife for subsistence, and to 

communicate to the public any risks associated with those consumption patterns. To this end, the 

subsistence analyses of all alternatives, located in Chapter 4 of the SEIS, have been reviewed and found 

to comply with Executive Order 12898. 

A.2 ANILCA § 810(a) Evaluations and Findings for All Alternatives 

and the Cumulative Case 

Evaluations and findings for Alternatives A, B, C, and D and the cumulative case, are presented

individually in the following sections. BMPs established by the 2013 ROD for the NPR-A IAP/EIS would 

apply to all GMT2 SEIS alternatives. ConocoPhillips’ leases in the GMTU are subject to lease 

stipulations established in the 2008 ROD for the Northeast NPR-A. The mitigating impacts of these 

BMPs and lease stipulations are accounted for in the following evaluations and findings, however 

potential new mitigation measures analyzed in the SEIS are not incorporated because, until the GMT2 

ROD is issued, it is not known whether they will be adopted. 

A.2.1 Evaluation and Findings for Alternative A

Development of oil reserves at the GMT2 site would occur under Alternative A. Infrastructure would 

include a drill site on BLM-managed land in the GMTU, an 8.2-mile access road between GMT1 and 
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GMT2, pipelines on BLM-managed and private lands in the NPR-A, and a pipeline and pipe rack on 

private and state lands outside the NPR-A. 

The BLM developed two project areas to quantify impacts to subsistence use areas during the 

construction phase and the drilling and operations phases. Both project areas were established by creating 

a 2.5-mile buffer around all project activity and infrastructure that would occur during each phase. The 

2.5-mile buffer was established based on displacement distances evaluated in studies of caribou 

behavioral responses to disturbance (see GMT2 SEIS § 4.4.5).

The GMT2 construction project area encompasses 158,480 acres (Figure 1). It includes the community of 

Nuiqsut, the gravel mine located 4.5 miles northeast of Nuiqsut, the Alpine Central Processing Facility 

(CPF), CD2, and CD4 in the Colville Delta north of Nuiqsut, bridges over the Nigliq Channel of the 

Colville River (and 3 smaller bridges between the Nigliq and CD5 and over the Ublutuoch River), the 

CD5 drill site, the CD5-GMT1 access road, the GMT1 drill site northwest of Nuiqsut, and the proposed 

GMT1-GMT2 access road and GMT2 drill site west of Nuiqsut. 

The GMT2 drilling and operations project area encompasses approximately 97,900 acres (Fig. 1) and 

includes the Alpine CPF, CD2, and CD4 in the Colville Delta north of Nuiqsut, bridges over the Nigliq 

Channel of the Colville River (and 3 smaller bridges between the Nigliq and CD5 and over the Ublutuoch 

River), the CD5 drill site, the CD5-GMT1 access road, the GMT1 drill site northwest of Nuiqsut, and the 

proposed GMT1-GMT2 access road and GMT2 drill site west of Nuiqsut.
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Figure 1. GMT2 construction and drilling and operations project areas and proposed and existing infrastructure in the vicinity of 

Nuiqsut, Alaska.
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A.2.1.1 Evaluation of the Effect of Use, Occupancy, or Disposition on Subsistence Uses 

and Needs

The GMT2 construction and drilling and operations project areas lie within areas heavily used for 

subsistence by residents of Nuiqsut (Figs. 2a, 2b). All of Nuiqsut active harvesters interviewed from 

1995-2006 reported using both the construction project area and the drilling and operations project area to 

harvest subsistence resources (SRB&A 2010b). 

While the project areas would overlap areas used by Nuiqsut residents to harvest nearly all types of 

subsistence resources, caribou are particularly important to the community (Brown et al. 2016). Thus, this 

ANILCA § 810 evaluation focuses primarily on impacts affecting the abundance, availability, and access 

to caribou. However, hunting and trapping furbearers (specifically wolf and wolverine) are also important 

activities for residents of Nuiqsut. Impacts to the abundance, availability, and access to these resources 

are described as appropriate in this evaluation.

Hunters from Nuiqsut rely primarily on the Teshekpuk Caribou Herd (TCH) (87% of annual harvest), but 

Braem et al. (2011) estimated that approximately 13% of the total annual caribou harvest by Nuiqsut 

consists of Central Arctic Herd (CAH) animals (Parrett 2015). CAH animals are harvested primarily in 

the Colville River Delta, which is northeast of the project area and unlikely to experience direct impacts 

under Alternative A. 

Subsistence Resource Abundance

TCH population trends are discussed in GMT2 SEIS § 3.3.4.1. The TCH has undergone recent changes in 

size, demography, and distribution, but these changes are not thought to be related to oil field 

development (Parrett 2015, Lenart 2015). The GMT2 project areas overlap only the lowest density TCH 

calving areas. Construction or operation activities would not affect large numbers of pregnant or lactating 

cows’ access to high-quality forage, nor would they affect calf production. Therefore, the abundance of 

caribou available for subsistence use would not be impacted under Alternative A. 

Population levels of furbearers on the coastal plain are not likely to be impacted by proposed development 

activities under Alternative A. 

Subsistence Resource Availability

Subsistence use of the GMT2 project areas is discussed in GMT2 SEIS § 4.4.5. Most caribou hunting 

occurs along the Nigliq Channel and the Colville River via boat, and in two primary areas accessed 

“overland” via snowmachine or four wheeler: 1) northwest of Nuiqsut in the vicinity of Fish Creek, and 

2) directly west of Nuiqsut. The area west of Nuiqsut is within and directly south of the project areas 

(Figs. 2a, 2b). Use of these overland areas has increased in recent years (SRB&A 2017a).

The GMT2 construction project area overlaps 25% of overland caribou subsistence use areas (Fig. 2a). 

Ninety one percent of interviewed Nuiqsut active harvesters reported hunting caribou in the GMT2 

construction project area (SRB&A 2017). The drilling and operations project area overlaps 13% of 

overland caribou subsistence use areas (Fig. 2b). Eighty four percent of interviewed active harvesters 

reported using the drilling and operations project area (SRB&A 2017). 

Availability of caribou for subsistence use could be impacted by habitat alteration and anthropogenic 

disturbance under Alternative A. Sources of disturbance include 1) road-related disturbance associated 
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with the GMT1-GMT2 access road (presence of road, vehicle traffic, and design features (e.g. height) of 

the road), and 2) aircraft traffic.

Figure 2a. GMT2 construction project area and subsistence use areas for caribou, 2008-2015 

(SRB&A 2017). Areas in red, orange, and yellow indicate high, moderate, and low use respectively. 

Figure 2b. GMT2 drilling and operations project area and subsistence use areas for caribou, 2008-

2015 (SRB&A 2017). Areas in red, orange, and yellow indicate high, moderate, and low use 

respectively. 
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Displacement of caribou due to habitat loss

Habitat-related impacts to caribou are discussed in the GMT2 SEIS § 4.3.4.1. Thirty eight percent of the 

construction project area overlaps the TCH range (60,634 of 158,480 acres), and consists of 0.2% of the 

herd’s range (60,634 of 33,673,144 acres). Fifty seven percent of the drilling and operations project area 

overlaps the TCH range (55,934 of 97,921 acres), and consists of 0.2% of the herd’s range. Impacts to 

habitat would be low (GMT2 SEIS § 4.3.4). Local displacement of caribou in areas where forage habitat

is lost due to infrastructure would occur, but caribou would not be displaced generally from the project 

areas due to direct loss of habitat associated with the proposed development. 

Displacement of caribou due to road disturbance

Impacts of roads on caribou are discussed in GMT2 SEIS § 4.3.4.1. Research suggests that, while historic 

caribou ranges persist in the presence of roads, a range of reactions to a new road (from no reaction to 

dramatic, novel movements) is possible. Mechanisms of disturbance are not completely understood, but 

traditional knowledge asserts that disturbance of adult cows initiating and leading fall migration can 

disrupt traditional migration routes. Recent research (Wilson et al. 2016 and others) emphasizes the need 

to consider the full suite of effects a road could have on migration, including avoidance, duration of delay, 

speed of migratory movements, and total distance traveled. These factors are particularly important to 

consider in subsistence use areas adjacent to rural communities. 

In late summer and at the onset of fall migration, some members of the TCH move east across the coastal 

plain and migrate south along the Colville River in the vicinity of Nuiqsut (Fig. 3, Panel G, H). The 

GMT1-GMT2 access road would bisect this migration corridor. Five percent of GPS-collared caribou 

crossed the proposed alignment during fall migration between 2005 and 2017 (Lawhead et al. 2015, L. 

Parrett pers. comm.). Annual crossing rates vary considerably, ranging from 0% to 31%. Considering 

these figures with respect to the herd’s current size (56,000 animals), anywhere from 0 (0%) to 17,360 

(31%) animals are likely to encounter the road in a given year, with approximately 2,800 (5%) 

encountering the road annually. 

Use of the migration corridor west of the Colville River is low when considered relative to the herd’s 

migratory movements as a whole, as evident by 5% of collared caribou crossing the proposed alignment 

over 12 years. However, caribou using migration routes on the eastern edge of the herd’s range are most 

easily accessible by Nuiqsut hunters. Thus, the small portion of the herd that uses this eastern migration 

route is particularly important to the community. Its importance has likely increased in recent years, as 

use of the GMT2 project areas during August and September has increased (GMT2 SEIS Figs. 3.4-17, 

3.4-18). 

The most analogous case study for road impacts to caribou is the CD5-GMT1 access road, constructed in 

2015. While it is east of the proposed GMT1-GMT2 access road, and therefore further on the periphery of 

the TCH range, it is similar in terms of location, length, orientation, and proximity to Nuiqsut’s caribou 

subsistence use area. The road has not been in place long enough for researchers to document caribou 

responses to it via multi-year collar data (L. Parrett, pers. comm.). The 2016 and 2017 caribou harvests 

were similar to harvest levels observed prior to construction. Hunting trip duration has not changed in 

recent years, but trip duration data have not been collected since the CD5-GMT1 access road was built 

(GMT2 SEIS Table 4.4.8). Some Nuiqsut hunters and Native Village of Nuiqsut (NVN) Tribal Council 

members reported reduced availability of caribou south of the road, although whether this is attributable 

to the road is unknown. 

Wilson et al. (2016) explored the effects of the Red Dog Mine road on individual caribou movements 

during fall migration. It is important to highlight the differences between the Red Dog Mine road and 
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proposed GMT1-GMT2 access road. The Red Dog Mine road is much longer (50 miles total) than the 

GMT1-GMT2 access road, and is primarily within the range of the Western Arctic Herd. Traffic consists 

of large trucks transporting ore, often in convoys. While large equipment would use the GMT1-GMT2 

access road, use would be periodic as opposed to regularly scheduled. However, the roads would share 

similarities: they are oriented somewhat perpendicular to fall migration paths and are similar both in 

terms of design features and traffic rates. Considering the results and subsequent discussion of this study 

is worthwhile in the absence of concrete conclusions regarding caribou interactions with the CD5-GMT1 

access road. 

Wilson et al. (2016) found that 8 out of 28 (29%) GPS-collared cow caribou took longer to cross the Red 

Dog Mine road than expected. They defined these animals as “slow crossers” and “normal crossers” 

respectively. They observed the following: 

• Avoidance - once they came within approximately 10 miles of the road, slow crossers took an 

average of 33 days to cross it. Normal crossers took 3 days.

• Delay - slow crossers delayed crossing the road. They crossed the road an average of 2 weeks 

later than normal crossers.

• Increased speed - slow crossers traveled 60% faster than normal crossers after crossing the road.

• Increased movements - slow crossers traveled an average of 273 miles farther over the course of 

fall migration, and wintered farther south. 

Wilson et al. were unable to offer definitive reasons for why the road elicited responses from some 

caribou and not others, but they do outline and explore multiple theories. They cite other studies 

demonstrating life history condition (e.g. pregnant cows) affects individual response to infrastructure, and 

explore the concept of social cues and their potential indirect impact on herd-wide movements (aligned 

with the long-held belief that lead cows must not be disrupted during fall migration). They consider the 

implications of environmental and context specific variables (e.g. traffic type), but ultimately conclude 

that reactions to roads are individual and context dependent, and can vary greatly from year to year. 

It is possible that none, some, or all of the TCH animals using the migration route west of Nuiqsut would 

react to the GMT1-GMT2 access road in a manner similar to those described by Wilson et al. (2016). 

Likely, at least some animals will demonstrate avoidance, delay, increased speed, or increased 

movements, whether annually or on an interannual basis. It is impossible to know definitively, and thus 

accurately predict impacts to subsistence. However, if 29% of the caribou encountering the road exhibit 

these responses, as was observed by Wilson et al., it is reasonable to expect that subsistence hunters 

would take more trips and expend more time and resources in search of caribou. It is possible that their 

seasonal round would be affected, as some caribou may move through Nuiqsut’s subsistence use area

later in the year. This would have implications for those hunting by boat along the Colville River, as icing 

would preclude continued use of the river late in the year. Caribou could also move through Nuiqsut’s 

subsistence use area faster during fall migration, limiting the time that sufficient numbers of caribou are 

available for harvest, particularly in the area directly west of Nuiqsut which is easily accessible during 

day trips. 

There is substantial compounding uncertainty associated with the impacts of the GMT1-GMT2 access 

road on subsistence. The literature does not yet offer broad scale, predictive conclusions regarding 

caribou responses to roads that bisect migration routes. Caribou responses to this specific road are 

unknown and likely would be highly variable. Hunter success is highly contingent on numerous factors. 

Also, hunters’ ability to adapt to changes in resource availability is substantial. It is likely that many 
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hunters could overcome issues associated with the road and caribou availability. However, potential 

consequences of altered caribou availability could result in increases in trip duration or frequency. If this 

occurs over the expected life of the project, Nuiqsut hunters lacking adequate time, income, or equipment 

could experience a significant resctiction due to the reduced local availability of caribou to meet their 

needs. 
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Figure 3. Teshekpuk Caribou Herd seasonal range use, 2012-2017, based on GPS-collared cow caribou (ABR unpublished data, 2018).
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Displacement of caribou due to aircraft disturbance

Fixed-wing and helicopter aircraft would be based at the Alpine CPF during construction for all 

alternatives. Fixed-wing air traffic would consist of 270 flights over the 2-3 year period. Helicopter traffic

(1032 flights over 2-3 years) would be present within the GMT2 project area from May to September and 

would include flights required for monitoring studies, ice road clean-up, and emergency response. A total 

of 1302 fixed-wing and helicopter flights would occur during the 2-3 year construction phase. 

Caribou response to aircraft is discussed in GMT2 SEIS § 4.3.4.1. Caribou response to aircraft varies 

depending on the season, degree of habituation, aircraft, altitude, flight patterns, weather conditions, 

frequency of overflights, and the sex and age composition of caribou groups. Low-level flights or 

maneuvering in the presence of un-habituated caribou can elicit escapist behavior (increased speed, abrupt 

direction change). Alternatively, caribou can become habituated to aircraft; particularly when aircraft 

maintain altitudes greater than 500 feet above ground level and do not engage in hazing or harassing 

behavior (Valkenburg and Davis 1983). In general, caribou responses to aircraft tend to be short-lived 

(Fullman et al. 2017 and others). 

Although short-lived, caribou responses to aircraft can impact subsistence hunters. Residents of Nuiqsut 

consistently highlight aircraft disturbance of caribou as a concern and state that aircraft activity makes 

animals more wary and harvest more difficult. Further discussion of community concerns regarding 

aircraft disturbance of caribou is in GMT2 SEIS § 4.4.5 and Appendix K. Caribou harvest has remained 

consistent despite increased air traffic in the vicinity of Alpine and other new infrastructure, and 

mitigation measures have been implemented to alleviate impacts. However, residents consistently say that 

the effort required to harvest resources is acutely disturbed by aircraft, particularly helicopter traffic. 

Assessing potential impacts of aircraft traffic considers Inupiaq hunters’ traditional knowledge and 

observations, the consistent North Slope Borough-wide opposition to aircraft traffic during the caribou 

hunting season, and research on aircraft noise effects on animals.

Displacement of furbearers

Furbearer subsistence use area data show high overlapping use areas throughout the GMT2 project areas 

(GMT2 SEIS Appendix F, Fig. F-5, Brown et al. 2016). One hundred percent of wolf and wolverine 

hunters reported hunting or trapping furbearers in the project areas. Studies in Canada and Scandinavia 

have shown that wolverines are more abundant in areas without development and that they are less likely 

to occur in areas with oil and gas exploration (GMT2 SEIS § 3.3.4.1). Nuiqsut residents report that 

furbearers such as wolf and wolverine are particularly sensitive to development activities and noise 

(SRB&A 2009a, 2010b). Furbearer avoidance of proposed development within the GMT2 project areas 

would likely necessitate further travel and increased effort (time, resources) in pursuit of these resources. 

Access to Subsistence Resources

Use of the industry-established safety area (1,000 feet surrounding the GMT2 drill pad) by subsistence 

users would be prohibited during both the construction and drilling and operations phases. 

Ice roads and pads would be used to support GMT2 construction activities during three winter seasons 

(GMT2 SEIS Map 2.5-3). The ice roads and pads would be open for 80 days (February 1 – April 20), 

however construction would begin in November and clean-up would extend to late spring/early summer. 

Subsistence use of or travel on ice roads and pads would be prohibited, and shooting across or towards the 

ice roads and pad within a distance of 2 miles presents a safety hazard (see GMT2 SEIS § 4.4.5.1). 

Access would be restricted in the area directly west of Nuiqsut due to these safety concerns for the first 
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construction season (November to May) while the ice road is being constructed and gravel is being hauled 

from the ASRC mine site to the GMT2 site. 

During construction, the GMT1-GMT2 access road would introduce a physical barrier to travel through 

the area by snowmachine or four-wheeler. These impacts could occur during summer, fall, or winter 

caribou hunting, winter furbearer hunting and trapping, and spring geese hunting. Impacts related to manmade structures were the second most commonly reported impact in 2014 (SRB&A 2016), before ramps 

had been constructed to cross the new CD5 road. Several hunters reported that man-made structures 

blocked access when traveling overland, and hunters were required to go around the road to access areas 

to the north and west. While the GMT1-GMT2 access road is being constructed, but before it is open to 

public use, subsistence hunters will be able to access land north and west of the community. They can do 

this by traveling overland and crossing the CD5-GMT1 road at one of three crossing locations with 

ramps, or driving to one of the ramp locations via the Kuukpik Spur Road and CD5-GMT1 road. 

The GMT1-GMT2 access road would be open to Nuiqsut subsistence users once construction is 

completed and a road access agreement is finalized. The road access agreement would likely be similar to 

the agreement for the CD5-GMT1 road, and would list the requirements for use of the road. The road 

would facilitate access to subsistence use areas west of Nuiqsut. Subsistence users would be permitted to 

use designated pullouts or parking areas along the road. They could use snowmachines, four-wheelers, 

vehicles, or a combination thereof (via trailering) along the road. Many would egress the road corridor 

and continue hunting overland. Subsistence hunters with authorized vehicles and permission from the 

Kuukpik Corporation to use the Spur Road or access Kuukpik lands would likely benefit directly from 

this facilitated access. Hunters who lack appropriate authorization would not benefit from the road.

The road would continue to act as an impediment to overland travel (snowmachines and four-wheelers) 

throughout the drilling and operations phase. Users would be able to cross the road using the ramps, but 

may have to reroute their direction of travel based on the location of the ramps.

A.2.1.2 Evaluation of the Availability of Other Lands

The Naval Petroleum Reserves Production Act of 1976 (NPRPA), as amended, instructs the Secretary of 

the Interior to conduct oil and gas leasing in the NPR-A. Congress authorized petroleum production in 

1980, and directed the Secretary of the Interior to undertake a program of competitive leasing of potential 

oil and gas tracts in the Reserve. In 2004, the ASDP ROD approved the GMT2 (then CD7) project for 

permitting, and in 2013, the NRP-A IAP/EIS analyzed impacts of future development in and around the 

Alpine Field, including reasonably foreseeable development of the GMT2 site. The purpose of the GMT2 

SEIS is to consider any new and site-specific information relevant to this previously authorized project. 

The proposed project was designed to develop oil from a delineated oil field on valid leases within the 

Petroleum Reserve. Other lands managed by the BLM are too distant to access the GMTU reservoir using 

current drilling technologies. 

A.2.1.3 Evaluation of Other Alternatives that Would Reduce or Eliminate the Use,

Occupancy, or Disposition of Public Lands Needed for Subsistence Purposes

Alternative D would reduce or eliminate the use of public lands needed for subsistence purposes. 

However, the BLM may not select Alternative D as its preferred alternative. The BLM issued leases to

ConocoPhillips, and is required to allow reasonable development of those leases. 
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GMT2 SEIS § 2.4.2 discusses other alternatives that were considered but eliminated from detailed

analysis due to economic or technological disadvantages, or because they did not meet the purpose of the 

proposed action to produce the oil discovered on ConocoPhillips’ leases. 

A.2.1.4 Findings

This evaluation concludes that Alternative A may result in a significant restriction to subsistence 

uses for the community of Nuiqsut due to impacts to caribou and furbearer availability. This

finding requires a positive determination pursuant to ANILCA § 810. 

The GMT1-GMT2 access road and aircraft traffic may alter late summer and fall movements of TCH 

caribou in the vicinity of Nuiqsut. While the magnitude of the impact with respect to the TCH as a whole 

would be small, it could be substantial given the significance of the portion of the herd that ranges close 

to Nuiqsut (Fig. 3). Caribou movements could be altered through the life of the project, as high interannual variability and overall low use makes the likelihood that a caribou would encounter the road 

multiple times during its lifetime, and thus become habituated to it, low. The extent of the impact could 

encompass important and easily accessible areas used by Nuiqsut hunters, namely along the Colville 

River and the area west of Nuiqsut and south of the proposed road. The basis for this finding relies 

heavily on the project’s proximity to this core subsistence use area. Current research and preliminary 

reports by subsistence users suggest that caribou availability could be impacted (SRB&A 2017). The 

likelihood of the impact occurring is difficult to determine, given the compounding uncertainty associated 

with caribou’s reactions to roads, hunters’ response to changing resource distribution, and natural 

variation at multiple geographic scales. BLM policy directs the BLM to err on the side of protection in 

cases of uncertainty such as this (BLM IM AK-2011-008, pgs. 6-2, 6-3). 

Wolf and wolverine avoidance of infrastructure is well documented (SRB&A 2009a, 2010b). It is likely 

that subsistence hunters targeting furbearers would need to relocate trap lines due to reduced availability

of these resources in the vicinity of the GMT2 project areas. 

A.2.2 Evaluation and Findings for Alternative B

The GMT1-GMT2 access road follows the watershed boundary between Fish Creek and the 

Tinmiaqsiugvik River under Alternative B. The road would be 1.2 miles longer and require additional 

gravel.

A.2.2.1 Evaluation of the Effect of Use, Occupancy, or Disposition on Subsistence Uses 

and Needs

The effects of Alternative B on subsistence would be similar to those described for Alternative A with

one important difference: greater impacts during construction due to increased industrial traffic and 

activity (i.e., gravel hauling and gravel mining) associated with the longer road. Under Alternative B, the 

road and pipeline would be slightly closer to Nuiqsut than under Alternative A. Some residents perceive 

an advantage in keeping industrial activities as close as possible to town, thereby leaving the more remote 

hunting areas less affected. This is advantageous for those with the means and time to travel and hunt

remote areas but disadvantageous for those who depend on hunting close to town. In the case of GMT2, 

the long-term differences in direct impacts between alternatives A and B are not considered significant

because neither route includes bridges or is located within a setback.

14 
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A.2.2.2 Evaluation of the Availability of Other Lands

The evaluation for GMT2 SEIS Alternative B is identical to that provided above in § A.2.1.2. 

A.2.2.3 Evaluation of Other Alternatives that Would Reduce or Eliminate the Use,

Occupancy, or Disposition of Public Lands Needed for Subsistence Purposes

The evaluation for GMT2 SEIS Alternative B is identical to that provided above in § A.2.1.3. 

A.2.2.4 Findings

This evaluation concludes that Alternative B may result in a significant restriction to subsistence 

uses for the community of Nuiqsut due to impacts to caribou and furbearer availability. This 

finding requires a positive determination pursuant to ANILCA § 810. 

With the exception of the difference in effects noted above, the rationale for these findings under 

Alternative B are identical to those for Alternative A. 

A.2.3 Evaluation and Findings for Alternative C

GMT2 SEIS Alternative C would not include the GMT1-GMT2 access road. Under this alternative,

transportation to the GMT2 site would be by aircraft approximately 9 months of the year (May through 

January) and primarily via ice road approximately three months of the year (February through April). An

airstrip, associated parking apron, storage building, and a gravel pad second gravel pad to accommodate a 

camp and additional facilities would be constructed, along with a 0.9 mile access road connecting the 

airstrip with the drill site and occupied pad. 

Movement of the drill rig to and from other drill sites would take place when the ice-road is open. The 

drill pad would be larger and numerous additional facilities would be required, including a mud plant and 

cement facility, a class-one disposal well, drilling and mud plant water supply, an incremental 150-man 

construction support camp, a 75-man drill rig support camp, a permanent full-service operations camp, a 

water and wastewater treatment plant, a 2-inch potable water pipeline, and other additional infrastructure 

required for a stand-alone facility. Construction of infrastructure would require 45-50% more gravel, and 

the total footprint of Alternative C would be 92 acres greater than Alternatives A or B. Water use would 

be greater due to annual ice road construction and additional man camp and industrial facilities. Air 

pollution emissions would be greater due to more facilities at the GMT2 site, annual ice road 

construction, and increased air traffic. 

A.2.3.1 Evaluation of the Effect of Use, Occupancy, or Disposition on Subsistence Uses

and Needs

Subsistence Resource Abundance

The evaluation for GMT2 SEIS Alternative C is identical to that provided above in § A.2.1.1. 
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Subsistence Resource Availability

GMT2 SEIS § 4.4.3.3 considers reduced availability of subsistence resources. Many effects on 

subsistence uses from Alternative C would be different than under Alternatives A and B, although 

reduced availability of caribou, wolves, and wolverine are anticipated. 

Alternative C could create impacts to caribou hunting due to increased air traffic. The lack of a gravel 

road would reduce physical disruption of caribou movement, specifically during fall migration. However, 

increased air traffic, may reduce localized availability of caribou. Alternative C would result in more air 

traffic in important hunting areas west of the Nuiqsut and would create a new and significant source of air 

traffic that did not exist before (GMT2 SEIS § 4.4.5.5). GMT2 SEIS Table 2.9-3 summarizes the total 

number of projected aircraft flights over the course of construction, drilling, and operations under 

Alternatives A, B, and C. Alternative C would consist of 81% more flights over the course of the project. 

Helicopter traffic would be 30% higher. 

The GMT2 SEIS describes impacts of aircraft on caribou. Numerous studies have documented general 

behavioral responses ranging from escapist behavior to no observable effect. Caribou ultimately appear to 

habituate to aircraft when aircraft consistently maintain altitudes greater than 500 feet above ground level 

and do not engage in hazing or harassing behavior (Webster 1997). Despite this, Nuiqsut caribou hunters 

cite aircraft traffic as the most common impact on caribou. They believe that increased air traffic diverts 

caribou away from hunting areas, and make caribou more wary and difficult to approach, resulting in 

reduced harvest opportunities. Given these consistent concerns and observations, it is likely that 

availability of caribou would be impacted under Alternative C.

Residents have indicated that furbearers such as wolf and wolverine are particularly sensitive to 

development activities and noise (SRB&A 2009a, 2010b). It is likely that displacement of furbearers 

from the GMT2 project area would cause hunters to travel farther looking for these resources. Alternative 

C will have the highest traffic levels during the routine operations period due to exclusively utilizing ice 

roads for all vehicle traffic, which will result in reduced availability of resources in areas where they are 

traditionally harvested.

Access to Subsistence Resources

Ice roads would be adverse for wintertime furbearer hunting and trapping activities. Routes that bisect or 

overlay trap lines force trappers to relocate from traditional trapping areas.

A.2.3.2 Evaluation of Availability of Other Lands 

The evaluation for GMT2 SEIS Alternative C is identical to that provided above in § A.2.1.2. 

A.2.3.3 Evaluation of Other Alternatives that Would Reduce or Eliminate the Use, 

Occupancy, or Disposition of Public Lands Needed for Subsistence Purposes

The evaluation for GMT2 SEIS Alternative C is identical to that provided above in § A.2.1.3. 
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A.2.3.4 Findings

This evaluation concludes that Alternative C may result in a significant restriction to subsistence 

uses for the community of Nuiqsut due to impacts to caribou and furbearer availability, and access 

to furbearers. This finding requires a positive determination pursuant to ANILCA § 810. 

Increased air traffic would likely make harvesting caribou more difficult, particularly in the vicinity of 

frequently used flight paths. Displacement would occur west of Nuiqsut in an important and easily 

accessible hunting area. The basis for this finding relies heavily on the project’s proximity to this core 

subsistence use area. Periodic displacement would persist through the life of the project. 

Ice roads and infrastructure would likely result in substantial displacement of furbearers that are sensitive 

to development. Displacement would occur within the project area, which is within Nuiqsut’s subsistence 

use area for furbearers. Displacement would persist through the life of the project. This substantial 

amount of displacement of furbearers from important harvest areas is expected to result in a major 

redistribution of furbearers, and thus may significantly restrict subsistence uses. 

A.2.4 Evaluation and Findings for Alternative D

GMT2 SEIS Alternative D (No Action) precludes the currently proposed development in the GMTU. Oil 

from the GMT2 field would not be produced. New roads, airstrips, pipelines or other oil and gas facilities 

would not be constructed pursuant to ConocoPhillips’ application. 

Other activities that are currently allowed pursuant to the 2013 NPR-A IAP/EIS ROD would continue. 

These activities include seismic exploration, exploratory drilling of test wells, and the construction of ice 

roads and pads to support these operations. 

A.2.4.1 Evaluation of the Effect of Use, Occupancy, or Disposition on Subsistence Uses

and Needs

Impacts to subsistence would not be expected under Alternative D. 

A.2.4.2 Evaluation of the Availability of Other Lands

Alternative D does not propose the disposition or use of public lands with regard to the proposed action. 

Therefore, evaluating the available of other lands is not applicable.

A.2.4.3 Evaluation of Other Alternatives that would Reduce or Eliminate the Use,

Occupancy, or Disposition of Public Lands Needed for Subsistence Purposes

Alternative D would eliminate the use of public lands needed for subsistence purposes, but does not meet 

the purpose of the proposed action, nor does the BLM have authority to select this alternative because the 

right to drill is associated with these leases.

GMT2 SEIS § 2.4.2 discusses alternatives that were considered but eliminated from detailed analysis due 

to economic or technological disadvantages, or because they did not meet the purpose of the proposed 

action. 
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A.2.4.4 Findings

This evaluation concludes that Alternative D (No Action) would not result in a significant reduction 

in subsistence uses. A positive determination pursuant to ANILCA § 810 is not required. 

A.2.5 Evaluation and Findings for the Cumulative Case

GMT2 SEIS § 4.6 contains a detailed description of the cumulative case, which evaluates the impact of 

the proposed action in conjunction with all past, present, and reasonably foreseeable future activities in 

the Colville River watershed and Nuiqsut subsistence use area. It considers, in detail, activities that are 

more certain to happen, and gives special attention to activities that have been identified as being of 

concern to subsistence users.Past, present and reasonably foreseeable future developments (RFFDs) 

within 40 miles of Nuiqsut are presented in GMT2 SEIS Table 4.6-2. Existing oil development within this 

area includes approximately 1,702 development wells, 48 miles of pipeline, 240 miles of permanent 

gravel road, and 791 acres of surface development. 

Reasonably foreseeable oil development within 40 miles of Nuiqsut will result in hundreds of additional 

development wells and several miles of pipeline and permanent gravel roads. Upcoming oil development 

projects considered in the cumulative effects analysis are: 

• Development of GMT1 (construction began winter 2016-2017)

• Nanushuk development is currently under analysis through an EIS led by the U.S. Army Corps of

Engineers. Oil Search Alaska, LLC assumed the role of Operator for the Nanushuk development

in March 2018, and the schedule for the EIS has been extended. The former Operator

(Armstrong) expected the first development in the Pikka Unit to go online no later than 2022.

• Future development of the Bear Tooth Unit

• Future development of the Willow Prospect

A.2.5.1 Evaluation of the Effect of Such Use, Occupancy, or Disposition on Subsistence

Uses and Needs

Cumulative effects on subsistence would be similar if Alternatives A or B are selected in the ROD for 

GMT2. If Alternative C is selected, cumulative effects would differ due to the lack of an access road.

Construction of GMT2 without a road would reduce the likelihood of local displacement of caribou, but 

would not include facilitated subsistence access via the road and would substantially increase aircraft 

traffic in the GMT2 area. 

GMT2 SEIS § 4.6.8.8 indicates that, irrespective of the GMT2 alternative selected, cumulative activity in 

the Nuiqsut subsistence use area will increasingly restrict subsistence access and decrease the availability 

of caribou in traditional use areas. This analysis focuses in part on the impacts that would be associated 

with an access road to GMT2 (Alternatives A and B) and assumes access roads to any future development 

west of GMT2. For the roadless scenario (Alternative C), impacts from roads as described below would 

not accumulate from development of GMT2 and impacts to subsistence hunting success from aircraft 

traffic (noise, emissions, larger footprint of sites) would accumulate to a greater degree. 

The CD5 and GMT1 development projects are present actions most closely connected to the proposed 

GMT2 project. Development of GMT1 was dependent upon the construction and operation of CD5; 
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likewise development of GMT2 is dependent on GMT1. CD5 is located directly west of the Nigliq 

Channel (approximately 8 miles north of Nuiqsut) and connects via a bridge and pipeline to the Alpine 

field in the Colville Delta (Fig. 4). 

Development of GMT2 would, with existing development in the Colville Delta and west of the Colville 

(CD5 and GMT1), as well as the reasonably foreseeable development in the Bear Tooth Unit/Willow 

Prospect, bound Nuiqsut by development to the north, northwest, west, and southwest (Fig. 4). 

Exploratory drilling (Stony Hill, Horseshoe) and seismic surveys (Bear survey) are currently occurring 

south of Nuiqsut. Recently acquired leases west and southwest of Nuiqsut, including 595,000 additional 

acres leased by the applicant in 2016, strongly indicate the likelihood of oil exploration and, depending on 

the results of that exploration, development infrastructure to the south/southwest of Nuiqsut as well. 

Figure 4. Existing and projected development near Nuiqsut

GMT2 scoping comments submitted by the Kuukpik Corporation include a recitation of the comments 

that the Nuiqsut village ANCSA corporation submitted in response to the 2012 Draft NPR-A IAP/EIS 
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regarding development that has “choked Nuiqsut’s Inupiat residents off from our traditional lands,” (J. 

Nukapigak and Kuukpik Corp., 2016). 

“We are not feeling boxed in – we are boxed in, or soon will be as CD5, GMT1, and GMT2 are 

built to the west and southwest, in addition to the existing developments to the north (Alpine), 

northeast (Oooguruk and Nikaitchuq), east (Kuparuk and Prudhoe Bay) and southeast (Tarn and 

Meltwater). With physical barriers existing or proposed on three sides of our community, being 

boxed in is not just a perception – it is a reality.” 

The Kuukpik Spur Road was constructed in 2016. The Kuukpik Corporation proposed the road in order to 

increase user access to hunting areas in the Colville Delta, CD5, and GMTU areas. The Spur Road 

supports Kuukpik Corporation and its subsidiaries’ oil-field business activities by providing year-round 

access to the Alpine field. Residents already use ice roads seasonally with motorized vehicles and 

commonly use road vehicles to transport snowmachines to more remote hunting areas via ice roads. Data

indicate that the Nuiqsut Spur Road will be used in the same ways during the winter and for vehicles and 

ORVs during the rest of the year. It is likely that the Nuiqsut Spur Road will result in increased 

subsistence hunting in the Colville Delta and GMTU areas for some residents, with the restriction that 

ATV access to the tundra from the road is prohibited. This facilitated access to traditional hunting areas 

can be considered a countervailing effect that partially mitigates the negative impact of loss of subsistence 

use areas by industrial development. The road may increase hunting pressure in the areas where access is 

facilitated, and these areas could likely experience greater disturbance to subsistence resources, 

particularly caribou, due to industrial activity and traffic on the road. 

The Colville River Access Road is a road proposed by the Native Village of Nuiqsut that would allow 

residents to drive from town to a boat launch area south of town on the main channel of the Colville 

River. This is desirable because otherwise subsistence boating requires travel up the Niqliq Channel to 

reach the Colville and that area of the Niqliq is often too shallow to allow safe passage. The Colville 

River Access Road will facilitate boat access to upriver and downriver areas of the Colville including to 

tributaries of the Colville that are traditionally valuable for subsistence, and that will likely become 

increasingly valuable due to additional development to the North and West of town. The Colville River 

Access Road is therefore mitigating action that facilitates subsistence use of the Colville. 

Annual winter oil and gas exploration activities are expected to continue in areas west of Nuiqsut in the 

coming decades. Subsistence hunters have identified seismic survey as an activity that disturbs animals 

from the area and creates difficult terrain for snowmachines. Ice road construction requires substantial 

fresh water use from local fish-bearing lakes and results in summer air traffic to plan routes and to 

retrieve marker stakes. The ice roads, where and when access is permitted and feasible, facilitate access to 

remote areas that some subsistence hunters appreciate and can be considered a countervailing effect. 

Adverse impacts include traffic, large man camps, and subsequent helicopter traffic, resulting in overall 

adverse and additive impacts of winter oil and gas activities. 

Foreseeable development in the NPR-A could also include onshore facilities to support development of 

submerged lands in Smith Bay. For this cumulative effects analysis, the onshore facility considered is a 

pipeline from Smith Bay that would tie into TAPS. Other potential activities include continued lease sales 

in the NPR-A. Onshore infrastructure west of the GMT2 project study area could influence movement of 

the TCH. The onshore support infrastructure for offshore activities could make it more economically 

viable to extract oil and gas reserves from a wide area spanning the NPR-A in which oil and gas would 

otherwise not be economically recoverable. Infrastructure built for coastal onshore oil and gas activities 

could encourage offshore development. This could cause a synergistic increase in disturbance sources. 

There is the potential for this scenario to have a significant impact on subsistence resources and access to 

those resources for the communities of Utqiagvik, Atqasuk, Anaktuvuk Pass, and Nuiqsut. 
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The cumulative effects of these current and future activities on restricting access to traditional subsistence 

use areas and to resource distribution and abundance are likely to be long-term, lasting as long as the life 

of the onshore and offshore oil fields. Any reduction in the calving and summer habitat use by caribou 

cows and calves from future onshore development would represent a functional loss of habitat that could 

result in long-term effects on the caribou herds’ productivity and abundance. 

A.2.5.2 Evaluation of the Availability of Other Lands

The cumulative case is based on adoption of GMT2 Alternative A, thus this evaluation is identical to that 

provided above in § A.2.1.2. 

A.2.5.3 Evaluation of Other Alternatives that would Reduce or Eliminate the Use,

Occupancy, or Disposition of Public Lands Needed for Subsistence Purposes

The cumulative case is based on adoption of GMT2 Alternative A, thus the evaluation of other 

alternatives is identical to that provided above in § A.2.1.3. 

A.2.5.4 Findings

This evaluation concludes that the Cumulative Case may result in a significant restriction to 

subsistence uses for the community of Nuiqsut due to impacts to caribou and furbearer availability 

and access thereof. 

This evaluation concludes that the Cumulative Case may result in a significant restriction to 

subsistence uses for the communities of Utqiagvik, Atqasuk, and Anaktuvuk Pass due to impacts to 

terrestrial and marine subsistence resources and access. This finding requires a positive 

determination pursuant to ANILCA § 810. 

The types of impacts on caribou availability related to infrastructure and associated activity would be 

similar to those described in Alternatives A-C, but such impacts would occur on a broader scale. For 

example, local displacement and increased difficulty harvesting caribou due to aircraft traffic may be 

widespread rather than localized in project-specific flight paths. The uncertainties surrounding caribou 

responses to the road network associated with development of GMT1 and GMT2 make it difficult to 

assess changes to caribou availability associated with future development such as development of the 

Willow Prospect. It is likely that impacts to subsistence associated with these roads would be highly 

localized (i.e. restricted to caribou hunting directly west of Nuiqsut and south of the GMT1-GMT2 access 

road), and thus would not be exacerbated by additional development. Observing caribou movements and 

continuing to document caribou harvest and associated hunter effort metrics in the presence of these roads 

will inform discussion of future impacts.

The types of impacts on furbearer availability related to infrastructure and associated activity would be 

identical to those described in Alternatives A-C. If reasonably foreseeable development occurs, furbearer 

trapping in traditional areas would be substantially impacted for the duration of development activities, 

and would thus constitute a substantial effect on subsistence users’ ability to harvest these resources.

Foreseeable development in the NPR-A includes onshore facilities to support development of submerged 

lands in Smith Bay and additional lease sales and development in the NPR-A. This synergistic increase in 

disturbance sources could have a significant impact on subsistence resource availability and access to 

those resources for the communities of Utqiagvik, Atqasuk, and Anaktuvuk Pass, as foreseeable 
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developments such as these would likely be located within subsistence use areas of these communities.

Similar to GMT1 and GMT2, it is likely that these impacts would be unique to the location and specific 

design features of each project. Procedures would be in place to ensure that future development affects 

access to subsistence resources as little as possible, and development would facilitate access when 

possible via use of development infrastructure (e.g. roads), but it is likely that safety considerations would 

reduce the total area available for subsistence purposes. If reasonably foreseeable development occurs, 

there could be a substantial effect on subsistence users’ ability to access subsistence use areas, or access 

new or less-frequently used areas that become more important in light of development. 

A.3 Notice and Hearings 

ANILCA § 810(a) provides that no “withdrawal, reservation, lease, permit, or other use, occupancy or 

disposition of the public lands which would significantly restrict subsistence uses shall be effected” until 

the federal agency gives the required notice and holds hearings in accordance with ANILCA § 810(a)(1) 

and (2). The BLM provided notice in the Federal Register that it made positive findings pursuant to 

ANILCA § 810 that alternatives A, B, and C and the cumulative case presented in the GMT2 SEIS, met 

the “may significantly restrict” threshold. As a result, public hearings were held in the potentially affected 

communities of Nuiqsut, Utqiagvik, Atqasuk, and Anaktuvuk Pass. Notice of these hearings were

provided in the Federal Register and by way of the local media, including the Arctic Sounder newspaper, 

and KBRW, the local Utqiagvik radio station with coverage to all villages on the North Slope. Meeting 

dates and times were posted on BLM’s website at www.blm.gov/ak/gmt. 

A.4 Subsistence Determinations under 

ANILCA § 810(a)(3)(A), (B), & (C)

ANILCA § 810(a) provides that no “withdrawal, reservation, lease, permit, or other use, occupancy or 

disposition of the public lands which would significantly restrict subsistence uses shall be effected” until 

the federal agency gives the required notice and holds hearings in accordance with ANILCA §810(a)(1) 

and (2), and makes the three determinations required by ANILCA § 810(a)(3)(A), (B), and (C). The three 

determinations that must be made are: 

1) Such a significant restriction of subsistence use is necessary, consistent with sound management 

principles for the utilization of the public lands; 

2) The proposed activity will involve the minimal amount of public lands necessary to accomplish 

the purposes of such use, occupancy, or other such disposition; and, 

3) Reasonable steps will be taken to minimize adverse impacts to subsistence uses and resources 

resulting from such actions [16 U.S.C. § 3120(a)(3)(A), (B), and (C)]. 

The BLM found that Alternatives A, B, and C and the cumulative case considered in the GMT2 SEIS

may significantly restrict subsistence uses. Therefore, the BLM undertook the notice and hearing 

procedures required by ANILCA § 810 (a)(1) and (2) in conjunction with release of the Draft GMT2 

SEIS in order to solicit public comment from the potentially affected communities and subsistence users.

The determinations below satisfy the requirements of ANILCA § 810(a)(3)(A), (B), and (C). 
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A.4.1. Significant restriction of subsistence use is necessary, consistent 

with sound management principles for the utilization of public lands

BLM drafted the GMT2 SEIS in response to ConocoPhillips’ applications to develop and produce oil 

from leases in the GMTU, and to fulfill BLM’s responsibilities to manage these lands under authority of 

the NPRPA and Federal Land Policy and Management Act (FLPMA) while providing protections for 

specific habitats and site-specific resources and uses identified and developed through a NEPA process. 

The SEIS will provide the opportunity, subject to appropriate conditions, to construct the necessary 

infrastructure to produce oil from the GMTU. 

The BLM considered multiple factors with regard to the proposed activity on public lands, including the 

comments received during the public meetings and hearings which stressed the importance of facilitating 

Nuiqsut residents’ continued use of the project area and local preferences for development scenarios that 

contribute the lowest increase in aircraft traffic.The BLM determined that Alternative A best fulfills the 

purpose and need of the proposed action, while incorporating protective measures that serve to minimize 

impacts to important subsistence resources and use areas. Alternative A considers the necessity for 

economically feasible development while providing protections to minimize impacts to subsistence 

resources and uses. Under Alternative A, the lease stipulations and BMPs that accompany the alternative 

would be the primary mitigation measures to reduce the impact of the proposed action on subsistence uses 

and resources. 

The BLM determined that the significant restriction that may occur under Alternative A, when considered 

with all possible impacts of the cumulative case, is necessary, consistent with sound management 

principles for the use of these public lands, and for BLM to fulfill the management goals of the NPR-A as 

directed by the 2013 NPR-A IAP/EIS, the NPRPA, and FLPMA.

A.4.2. The proposed activitiy will involve the minimal amount of public lands 

necessary to accomplish the purpose of such use, occupancy, or other 

disposition

The BLM analyzed four alternatives. Alternative D (No Action) would involve the minimal amount of 

public lands necessary, but it would not accomplish the purpose of the proposed action, nor would it 

fulfill the management goals of the NPR-A as directed by the 2013 NPR-A IAP/EIS, the NPRPA, or 

FLPMA. The federal lands that would be impacted are the same under Alternatives A, B, and C, although 

physical footprints of each would vary. Alternative C would involve the minimal amount of public lands 

necessary to accomplish the purpose of the proposed action, but it would not meet the requirement 

outlined in A.4.3. Alternative A would involve the minimal amount of public lands necessary to 

accomplish the purposes of the proposed action given that Alternative C does not qualify. Under 

Alternative B, the GMT1-GMT2 access road would be 1.8 miles longer than the road proposed under 

Alternative A. Therefore, alternative B would not involve the minimal amount of public lands necessary 

to accomplish the proposed action.

Other lands managed by the BLM are too distant to access the GMTU reservoir using current drilling 

technologies. Consideration of other lands, therefore, would not accomplish the purpose of the proposed 

action. 
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_____________________________________________________________________________________________

24 

A.4.3. Reasonable steps will be taken to minimize adverse impacts upon

subsistence uses and resouces resulting from such actions

The information acquired through analysis of impacts to subsistence, insight from public meetings and 

ANILCA § 810 hearings, meetings with the NPR-A Subsistence Advisory Panel, and consultation with 

tribal and local governments were used to analyze the impacts of Alternatives A, B, C, and D. Several 

existing mitigation measures would minimize adverse impacts to subsistence. In addition, ConocoPhillips 

proposes implementing various voluntary policies and measures which will further minimize impacts to 

subsistence. These stipulations, BMPs, and efforts are summarized herein, but are described, in detail, in 

GMT2 SEIS § 4.3.4.1, and 4.4.5.6, and Appendix J. 

Existing stipulations and BMPs from the 2013 NPR-A IAP/EIS ROD that address subsistence include:

Measures to ensure the continued health of wildlife, fish, and subsistence resources 

Many of the measures established in the 2013 NPR-A IAP/EIS ROD are intended to ensure the continued 

health of fish, wildlife, and subsistence resources. Measures to mitigate impacts to fish are described in 

GMT2 SEIS § 4.3.2, those addressing impacts to birds are described in § 4.3.3, and those addressing 

impacts to mammals are described in § 4.3.4. Mitigation measures addressing impacts to water resources 

and vegetation are described in § 4.2.2 and 4.3.1 respectively.

Measures to avoid conflict with subsistence users 

• E-1: All roads must be designed, constructed, maintained, and operated to create minimal

environmental impacts and to protect subsistence use and access to subsistence hunting and

fishing areas.

• E-2: Permanent oil and gas facilities, including roads, airstrips, and pipelines, are prohibited upon

or within 500 feet of fish-bearing water bodies.

• E-3: Causways and docks are prohibited in river mouths or deltas. Artificial gravel islands and

bottom-founded structures are prohibited in river mouths, active stream channels, or river deltas

• E-7: Pipelines and roads shall be designed to allow the free movement of caribou and the safe,

unimpeded passage of the public while participating in subsistence activities

• F-1: Permittee will ensure that aircraft used for permitted activities comply with the guidelines

outlined therin

• H-1: Permittee will consult directly with affected communities using the guidelines outlined

therein

• H-2: Permittee will notify the local search and rescue organizations of proposed seismic survey

locations for that operation season, and will comply with the guidelines therein
ANILCA 810 Subsistence Evaluation for GMT2 Final Supplemental EIS

_____________________________________________________________________________________________

25 

• H-3: Hunting and trapping by the permittee’s employees, agents, and contractors are prohibited

when persons are on “work status”

• I-1: All personnel involved in oil and gas and related activities shall be provided information

concerning applicable stipulations, BMPs, standards, and specific types of environmental, social,

traditional, and cultural concerns that relate to the region. The permittee shall ensure that all

personnel involved in permitted activities shall attend an orientation program at least once a year

and will consist of the guidelines therein

ConocoPhillips has implemented voluntary policies and measures to address impacts to subsistence under 

previous authorizations, and proposes similar policies during development and operation of the GMT2 

site. These include incorporating vehicle pullouts into the design of the GMT1-GMT2 access road, which 

would facilitate egress from the road and access to lands west of Nuiqsut. ConocoPhillips consistently

attempts to coordinate aircraft operations both internally and with other regional oil development 

companies, and to minimize flights when possible, specifically during peak hunting season. 

Given that these lease stipulations, BMPs, and voluntary policies directly protect or address subsistence 

resources and concerns, the BLM determines that any roaded alternative (i.e., Alternatives A or B) will 

include reasonable steps to minimize impacts upon subsistence uses and resources.

A.4.4. Concluding Declaration

The BLM has determined that, after consideration of all alternatives, subsistence evaluations, and public 

hearings, such a significant restriction of subsistence uses is necessary, consistent with sound 

management principles for the utilization of this land, and that the selected alternative will involve the 

minimal amount of public lands necessary to accomplish Alternative A. Reasonable steps have and will 

be taken to minimize the adverse impacts upon subsistence uses and resources arising from this action.

Citations

Braem, N., S. Pedersen, J. Simon, D. Koster, T. Kaleak, P. Leavitt, J. Patkotak, and P. Neakok. 2011. 

Monitoring of Annual Caribou Harvests in the National Petroleum Reserve in Alaska: Atqasuk, Barrow, 

and Nuiqsut, 2003–2007. ADF&G, Division of Subsistence, Technical Paper No. 361, Fairbanks, Alaska. 

Available online at: http://www.adfg.alaska.gov/techpap/TP361.pdf (accessed May 2017).

Brown, C. L., et al. (2016). Harvests and uses of wild resources in 4 Interior Alaska communities and 3 

Arctic Alaska communities. Alaska Department of Fish and Game Division of Subsistence, Technical 

Paper no. 426. Fairbanks, Alaska. 

Environmental Protection Agency, 2016. Environmental Justice 2020 Glossary, definitions of 

“Environmental Justice” and “Fair Treatment.” Accessed from 

https://www.epa.gov/environmentaljustice/ej-2020-glossary on March 7, 2018. 

Fullman, T. J., K. Joly, and A. Ackerman. 2017. Effects of environmental features and sport hunting on 

caribou migration in northwestern Alaska. Movement Ecology 5:4. 

Lawhead, B. E., A. K. Prichard, M. J. Macander, and J. H. Welch. 2015. Caribou monitoring study for the 

Alpine Satellite Development Project, 2014, 10th annual report. Prepared for ConocoPhillips Alaska, Inc. 

Prepared by ABR, Inc. – Environmental Research and Services, Fairbanks, Alaska.
ANILCA 810 Subsistence Evaluation for GMT2 Final Supplemental EIS

_____________________________________________________________________________________________

26 

Lenart, E. A. 2015. Units 26B and 26C caribou. Chapter 18, pages 18-1 through 18-38 in P. Harper and L. 

A. McCarthy, editors. Caribou management report of survey and inventory activities 1 July 2012 – 30

June 2014. Alaska Department of Fish and Game, Species Management Report ADF&G/DWC/SMR2015-4, Juneau, Alaska.

Nukapigak, J. (2017). Comment made as Native Village of Nuiqsut council member to the BLM during 

Oct. 2017 government-to-government consultation between the BLM and NVN. Audio recording on file 

with the BLM Arctic Office. Fairbanks, Alaska. 

Parrett, L. S. 2015. Unit 26A, Teshekpuk Caribou Herd. In: Harper, P. (Ed.), Caribou management report 

of survey and inventory activities, 1 July 2010 – 30 June 2012. Alaska Department of Fish and Game, 

Juneau, Alaska.

Parrett, L. 2017. Lincoln Parrett (ADF&G) personal communication to Debora Nigro and Erin Julianus 

(BLM). December 7, 2017. 

Parrett, L. 2018. Lincoln Parrett (ADF&G) personal communication to Erin Julianus (BLM). July 19, 

2018. 

Stephen R. Braund and Associates (SRB&A) (2009a). Nuiqsut Caribou Subsistence Monitoring Project: 

Results of 2008 Hunter Interviews. Prepared for ConocoPhillips Alaska, Inc. Anchorage, Alaska.

Stephen R. Braund and Associates (SRB&A) (2010b). Nuiqsut Caribou Subsistence Monitoring Project: 

Results of 2009 Hunter Interviews. Prepared for ConocoPhillips Alaska, Inc. Anchorage, Alaska. 

Stephen R. Braund and Associates (SRB&A) (2016). Nuiqsut Caribou Subsistence Monitoring Project: 

Results of Year Seven Hunter Interviews and Household Harvest Surveys. Prepared for ConocoPhillips 

Alaska, Inc. Anchorage, Alaska. 

Stephen R. Braund and Associates (SRB&A) (2017a). Nuiqsut Caribou Subsistence Monitoring Project: 

Results of Year Eight Hunter Interviews and Household Harvest Surveys. Abridged. Prepared for 

ConocoPhillips Alaska, Inc. Anchorage, Alaska 

Valkenburg, P., and J. L. Davis. 1983. The reaction of caribou to aircraft: a comparison of two herds. 

(Pages 7-9) In: Martell, A. M. and D. E. Russell, editors. Caribou and human activity. Proceedings 1st

North American Caribou Workshop, Whitehorse, Yukon. 28 – 29 September 1983. Canadian Wildlife 

Service Special Publication, Ottowa.

Wilson, R. R., L. S. Parrett, K. Joly, and J. R. Dau. 2016. Effects of roads on individual caribou 

movements during migration. Biological Conservation 195: 2-8. 
Appendices  Final Supplemental Environmental Impact Statement

Alpine Satellite Development Plan for the Proposed Greater Mooses Tooth 2 Development Project

APPENDIX M

CALPUFF SAMPLE FILES FOR FAR FIELD AIR QUALITY 

MODELING 

APPENDIX M

Sample Files for Far-Field Air Quality Modeling
M-1 

1. Sample CALPUFF Input File

Greater Mooses Tooth 2, Alt A CALPUFF run, 141x100x4.000km mesh, 2009 

4.000km WRF supplied by BOEM.

Using MMIF, not CALMET. Hourly ozone, 1 ppb NH3.

No gridded receptors, only sensitive Class II receptors.

---------------- Run title (3 lines) -------------------------------------

-----

 CALPUFF MODEL CONTROL FILE

--------------------------

--------------------------------------------------------------------------

-----

INPUT GROUP: 0 -- Input and Output File Names

--------------

Default Name Type File Name

------------ ---- ---------

CALMET.DAT input * METDAT = *

 or

ISCMET.DAT input * ISCDAT = *

 or

PLMMET.DAT input * PLMDAT = *

 or

PROFILE.DAT input * PRFDAT = *

SURFACE.DAT input * SFCDAT = *

RESTARTB.DAT input * RSTARTB= *

--------------------------------------------------------------------------

------

CALPUFF.LST output ! PUFLST = gmt2.2009.out !

CONC.DAT output ! CONDAT = gmt2.2009.con !

DFLX.DAT output ! DFDAT = gmt2.2009.dry !

WFLX.DAT output ! WFDAT = gmt2.2009.wet !

VISB.DAT output * VISDAT = *

TK2D.DAT output * T2DDAT = *

RHO2D.DAT output * RHODAT = *

RESTARTE.DAT output * RSTARTE= *

--------------------------------------------------------------------------

------

Emission Files

--------------

PTEMARB.DAT input * PTDAT = *

VOLEMARB.DAT input * VOLDAT = *

BAEMARB.DAT input * ARDAT = *

LNEMARB.DAT input * LNDAT = * 

--------------------------------------------------------------------------

------

Other Files
M-2 

-----------

OZONE.DAT input ! OZDAT = ozone/ozone.nuiqsut.2009-2013.dat ! 

VD.DAT input * VDDAT = *

CHEM.DAT input * CHEMDAT= *

H2O2.DAT input * H2O2DAT= *

HILL.DAT input * HILDAT= *

HILLRCT.DAT input * RCTDAT= *

COASTLN.DAT input * CSTDAT= *

FLUXBDY.DAT input * BDYDAT= * 

BCON.DAT input * BCNDAT= *

DEBUG.DAT output * DEBUG = *

MASSFLX.DAT output * FLXDAT= *

MASSBAL.DAT output ! BALDAT= gmt2.2009.bal !

FOG.DAT output * FOGDAT= *

--------------------------------------------------------------------------

------

All file names will be converted to lower case if LCFILES = T

Otherwise, if LCFILES = F, file names will be converted to UPPER CASE

 T = lower case ! LCFILES = T !

 F = UPPER CASE

NOTE: (1) file/path names can be up to 70 characters in length

Provision for multiple input files

----------------------------------

 Number of CALMET.DAT files for run (NMETDAT)

 Default: 1 ! NMETDAT = 12 !

 Number of PTEMARB.DAT files for run (NPTDAT)

 Default: 0 ! NPTDAT = 0 !

 Number of BAEMARB.DAT files for run (NARDAT)

 Default: 0 ! NARDAT = 0 !

 Number of VOLEMARB.DAT files for run (NVOLDAT)

 Default: 0 ! NVOLDAT = 0 !

!END!

-------------

Subgroup (0a)

-------------

 The following CALMET.DAT filenames are processed in sequence if 

NMETDAT>1

Default Name Type File Name

------------ ---- ---------

CALMET.DAT input ! METDAT =../mmif/gmt2.2009.01.met ! !END!

CALMET.DAT input ! METDAT =../mmif/gmt2.2009.02.met ! !END!

CALMET.DAT input ! METDAT =../mmif/gmt2.2009.03.met ! !END!

CALMET.DAT input ! METDAT =../mmif/gmt2.2009.04.met ! !END!

CALMET.DAT input ! METDAT =../mmif/gmt2.2009.05.met ! !END!
M-3 

CALMET.DAT input ! METDAT =../mmif/gmt2.2009.06.met ! !END!

CALMET.DAT input ! METDAT =../mmif/gmt2.2009.07.met ! !END!

CALMET.DAT input ! METDAT =../mmif/gmt2.2009.08.met ! !END!

CALMET.DAT input ! METDAT =../mmif/gmt2.2009.09.met ! !END!

CALMET.DAT input ! METDAT =../mmif/gmt2.2009.10.met ! !END!

CALMET.DAT input ! METDAT =../mmif/gmt2.2009.11.met ! !END!

CALMET.DAT input ! METDAT =../mmif/gmt2.2009.12.met ! !END!

--------------------------------------------------------------------------

------

INPUT GROUP: 1 -- General run control parameters

--------------

 Option to run all periods found

 in the met. file (METRUN) Default: 0 ! METRUN = 0 !

 METRUN = 0 - Run period explicitly defined below

 METRUN = 1 - Run all periods in met. file

 Starting date: Year (IBYR) -- No default ! IBYR = 2009 ! 

 (used only if Month (IBMO) -- No default ! IBMO = 01 !

 METRUN = 0) Day (IBDY) -- No default ! IBDY = 01 !

 Hour (IBHR) -- No default ! IBHR = 01 !

 Base time zone (XBTZ) -- No default ! XBTZ = 9.0 !

 PST = 8., MST = 7.

 CST = 6., EST = 5.

 Length of run (hours) (IRLG) -- No default ! IRLG = 8760 ! 

 Number of chemical species (NSPEC)

 Default: 5 ! NSPEC = 13 ! 9+4

 Number of chemical species

 to be emitted (NSE) Default: 3 ! NSE = 9 !

 Flag to stop run after

 SETUP phase (ITEST) Default: 2 ! ITEST = 2 !

 (Used to allow checking

 of the model inputs, files, etc.)

 ITEST = 1 - STOPS program after SETUP phase

 ITEST = 2 - Continues with execution of program

 after SETUP

 Restart Configuration:

 Control flag (MRESTART) Default: 0 ! MRESTART = 0 !

 0 = Do not read or write a restart file

 1 = Read a restart file at the beginning of

 the run

 2 = Write a restart file during run

 3 = Read a restart file at beginning of run
M-4 

 and write a restart file during run

 Number of periods in Restart

 output cycle (NRESPD) Default: 0 ! NRESPD = 0 !

 0 = File written only at last period

 >0 = File updated every NRESPD periods

 Meteorological Data Format (METFM)

 Default: 1 ! METFM = 1 !

 METFM = 1 - CALMET binary file (CALMET.MET)

 METFM = 2 - ISC ASCII file (ISCMET.MET)

 METFM = 3 - AUSPLUME ASCII file (PLMMET.MET)

 METFM = 4 - CTDM plus tower file (PROFILE.DAT) and

 surface parameters file (SURFACE.DAT)

 METFM = 5 - AERMET tower file (PROFILE.DAT) and

 surface parameters file (SURFACE.DAT)

 Meteorological Profile Data Format (MPRFFM)

 (used only for METFM = 1, 2, 3)

 Default: 1 ! MPRFFM = 1 !

 MPRFFM = 1 - CTDM plus tower file (PROFILE.DAT)

 MPRFFM = 2 - AERMET tower file (PROFILE.DAT)

 PG sigma-y is adjusted by the factor (AVET/PGTIME)**0.2

 Averaging Time (minutes) (AVET)

 Default: 60.0 ! AVET = 60. !

 PG Averaging Time (minutes) (PGTIME)

 Default: 60.0 ! PGTIME = 60. ! 

!END!

--------------------------------------------------------------------------

-----

INPUT GROUP: 2 -- Technical options

--------------

 Vertical distribution used in the

 near field (MGAUSS) Default: 1 ! MGAUSS = 1 

! 

 0 = uniform

 1 = Gaussian

 Terrain adjustment method

 (MCTADJ) Default: 3 ! MCTADJ = 3 

! 

 0 = no adjustment
M-5 

 1 = ISC-type of terrain adjustment

 2 = simple, CALPUFF-type of terrain

 adjustment 

 3 = partial plume path adjustment

 Subgrid-scale complex terrain

 flag (MCTSG) Default: 0 ! MCTSG = 0 !

 0 = not modeled

 1 = modeled

 Near-field puffs modeled as

 elongated 0 (MSLUG) Default: 0 ! MSLUG = 0 !

 0 = no

 1 = yes (slug model used)

 Transitional plume rise modeled ?

 (MTRANS) Default: 1 ! MTRANS = 1 

! 

 0 = no (i.e., final rise only)

 1 = yes (i.e., transitional rise computed)

 Stack tip downwash? (MTIP) Default: 1 ! MTIP = 1 !

 0 = no (i.e., no stack tip downwash)

 1 = yes (i.e., use stack tip downwash)

 Method used to simulate building

 downwash? (MBDW) Default: 1 ! MBDW = 1 !

 1 = ISC method

 2 = PRIME method

 Vertical wind shear modeled above

 stack top? (MSHEAR) Default: 0 ! MSHEAR = 0 !

 0 = no (i.e., vertical wind shear not modeled)

 1 = yes (i.e., vertical wind shear modeled)

 Puff splitting allowed? (MSPLIT) Default: 0 ! MSPLIT = 0 ! 

 0 = no (i.e., puffs not split)

 1 = yes (i.e., puffs are split)

 Chemical mechanism flag (MCHEM) Default: 1 ! MCHEM = 1 !

 0 = chemical transformation not modeled

 1 = transformation rates computed internally (MESOPUFF II scheme)

 2 = user-specified transformation rates used

 3 = transformation rates computed internally (RIVAD/ARM3 scheme)

 4 = secondary organic aerosol formation computed (MESOPUFF II 

scheme for OH)

 Aqueous phase transformation flag (MAQCHEM)

 (Used only if MCHEM = 1, or 3) Default: 0 ! MAQCHEM = 0 

! 

 0 = aqueous phase transformation not modeled

 1 = transformation rates adjusted for aqueous phase reactions

 Wet removal modeled ? (MWET) Default: 1 ! MWET = 1 !
M-6 

 0 = no

 1 = yes

 Dry deposition modeled ? (MDRY) Default: 1 ! MDRY = 1 !

 0 = no

 1 = yes

 (dry deposition method specified for each species in Input Group 

3)

 Gravitational settling (plume tilt)

 modeled ? (MTILT) Default: 0 ! MTILT = 0 !

 0 = no

 1 = yes

 (puff center falls at the gravitational

 settling velocity for 1 particle species)

 Restrictions:

 - MDRY = 1 

 - NSPEC = 1 (must be particle species as well)

 - sg = 0 GEOMETRIC STANDARD DEVIATION in Group 8 is

 set to zero for a single particle diameter

 Method used to compute dispersion

 coefficients (MDISP) Default: 3 ! MDISP = 3 !

 1 = dispersion coefficients computed from measured values

 of turbulence, sigma v, sigma w

 2 = dispersion coefficients from internally calculated 

 sigma v, sigma w using micrometeorological variables

 (u*, w*, L, etc.)

 3 = PG dispersion coefficients for RURAL areas (computed using

 the ISCST multi-segment approximation) and MP coefficients in

 urban areas

 4 = same as 3 except PG coefficients computed using

 the MESOPUFF II eqns.

 5 = CTDM sigmas used for stable and neutral conditions.

 For unstable conditions, sigmas are computed as in

 MDISP = 3, described above. MDISP = 5 assumes that

 measured values are read

 Sigma-v/sigma-theta, sigma-w measurements used? (MTURBVW)

 (Used only if MDISP = 1 or 5) Default: 3 ! MTURBVW = 3 

! 

 1 = use sigma-v or sigma-theta measurements

 from PROFILE.DAT to compute sigma-y 

 (valid for METFM = 1, 2, 3, 4, 5)

 2 = use sigma-w measurements

 from PROFILE.DAT to compute sigma-z 

 (valid for METFM = 1, 2, 3, 4, 5)

 3 = use both sigma-(v/theta) and sigma-w 

 from PROFILE.DAT to compute sigma-y and sigma-z 

 (valid for METFM = 1, 2, 3, 4, 5)

 4 = use sigma-theta measurements

 from PLMMET.DAT to compute sigma-y 
M-7 

 (valid only if METFM = 3)

 Back-up method used to compute dispersion

 when measured turbulence data are

 missing (MDISP2) Default: 3 ! MDISP2 = 3 !

 (used only if MDISP = 1 or 5)

 2 = dispersion coefficients from internally calculated 

 sigma v, sigma w using micrometeorological variables

 (u*, w*, L, etc.)

 3 = PG dispersion coefficients for RURAL areas (computed using

 the ISCST multi-segment approximation) and MP coefficients in

 urban areas

 4 = same as 3 except PG coefficients computed using

 the MESOPUFF II eqns.

 [DIAGNOSTIC FEATURE]

 Method used for Lagrangian timescale for Sigma-y 

 (used only if MDISP=1,2 or MDISP2=1,2)

 (MTAULY) Default: 0 ! MTAULY = 0 

! 

 0 = Draxler default 617.284 (s)

 1 = Computed as Lag. Length / (.75 q) -- after SCIPUFF

 10 < Direct user input (s) -- e.g., 306.9

 [DIAGNOSTIC FEATURE]

 Method used for Advective-Decay timescale for Turbulence

 (used only if MDISP=2 or MDISP2=2)

 (MTAUADV) Default: 0 ! MTAUADV = 0 

! 

 0 = No turbulence advection

 1 = Computed (OPTION NOT IMPLEMENTED)

 10 < Direct user input (s) -- e.g., 800

 Method used to compute turbulence sigma-v &

 sigma-w using micrometeorological variables

 (Used only if MDISP = 2 or MDISP2 = 2)

 (MCTURB) Default: 1 ! MCTURB = 1 

! 

 1 = Standard CALPUFF subroutines

 2 = AERMOD subroutines

 PG sigma-y,z adj. for roughness? Default: 0 ! MROUGH = 0 !

 (MROUGH)

 0 = no

 1 = yes

 Partial plume penetration of Default: 1 ! MPARTL = 1 !

 elevated inversion?

 (MPARTL)

 0 = no

 1 = yes
M-8 

 Strength of temperature inversion Default: 0 ! MTINV = 0 !

 provided in PROFILE.DAT extended records?

 (MTINV)

 0 = no (computed from measured/default gradients)

 1 = yes

 PDF used for dispersion under convective conditions?

 Default: 0 ! MPDF = 0 !

 (MPDF)

 0 = no

 1 = yes

 Sub-Grid TIBL module used for shore line?

 Default: 0 ! MSGTIBL = 0 !

 (MSGTIBL)

 0 = no

 1 = yes

 Boundary conditions (concentration) modeled?

 Default: 0 ! MBCON = 0 !

 (MBCON)

 0 = no

 1 = yes, using formatted BCON.DAT file

 2 = yes, using unformatted CONC.DAT file

 Note: MBCON > 0 requires that the last species modeled

 be 'BCON'. Mass is placed in species BCON when

 generating boundary condition puffs so that clean

 air entering the modeling domain can be simulated

 in the same way as polluted air. Specify zero

 emission of species BCON for all regular sources.

 Individual source contributions saved?

 Default: 0 ! MSOURCE = 0 !

 (MSOURCE)

 0 = no

 1 = yes

 Analyses of fogging and icing impacts due to emissions from

 arrays of mechanically-forced cooling towers can be performed

 using CALPUFF in conjunction with a cooling tower emissions

 processor (CTEMISS) and its associated postprocessors. Hourly

 emissions of water vapor and temperature from each cooling tower

 cell are computed for the current cell configuration and ambient

 conditions by CTEMISS. CALPUFF models the dispersion of these

 emissions and provides cloud information in a specialized format

 for further analysis. Output to FOG.DAT is provided in either

 'plume mode' or 'receptor mode' format.

 Configure for FOG Model output?

 Default: 0 ! MFOG = 0 !

 (MFOG)
M-9 

 0 = no

 1 = yes - report results in PLUME Mode format

 2 = yes - report results in RECEPTOR Mode format

 Test options specified to see if

 they conform to regulatory

 values? (MREG) Default: 1 ! MREG = 1 !

 0 = NO checks are made

 1 = Technical options must conform to USEPA

 Long Range Transport (LRT) guidance

 METFM 1 or 2

AVET 60. (min)

PGTIME 60. (min)

MGAUSS 1

MCTADJ 3

MTRANS 1

 MTIP 1

 MCHEM 1 or 3 (if modeling SOx, NOx)

MWET 1

MDRY 1

MDISP 2 or 3

MPDF 0 if MDISP=3

 1 if MDISP=2

 MROUGH 0

MPARTL 1

SYTDEP 550. (m)

MHFTSZ 0

SVMIN 0.5 (m/s)

!END!

--------------------------------------------------------------------------

-----

INPUT GROUP: 3a, 3b -- Species list

-------------------

------------

Subgroup (3a)

------------

 The following species are modeled:

! CSPEC = SO2 ! !END!

! CSPEC = SO4 ! !END!

! CSPEC = NOX ! !END!

! CSPEC = HNO3 ! !END!

! CSPEC = NO3 ! !END!

! CSPEC = EC ! !END!

! CSPEC = SOA ! !END!
M-10

! CSPEC = PMC ! !END!

! CSPEC = PMF ! !END!

! CSPEC = nSO2 ! !END! Non-reactive SO2

! CSPEC = nNOX ! !END! Non-reactive NOx

! CSPEC = nPM10 ! !END! Non-reactive PM10

! CSPEC = nPM25 ! !END! Non-reactive PM2.5

 Dry 

OUTPUT GROUP

 SPECIES MODELED EMITTED DEPOSITED 

NUMBER

 NAME (0=NO, 1=YES) (0=NO, 1=YES) (0=NO, 

(0=NONE,

 (Limit: 12 1=COMPUTED-GAS 

1=1st CGRUP,

 Characters 2=COMPUTED-PARTICLE 

2=2nd CGRUP,

 in length) 3=USER-SPECIFIED) 

3= etc.)

! SO2 = 1, 1, 1, 

0 !

! SO4 = 1, 1, 2, 

0 !

! NOX = 1, 1, 1, 

0 !

! HNO3 = 1, 1, 1, 

0 !

! NO3 = 1, 1, 2, 

0 !

! EC = 1, 1, 2, 

0 !

! SOA = 1, 1, 2, 

0 !

! PMC = 1, 1, 2, 

0 !

! PMF = 1, 1, 2, 

0 !

! nSO2 = 1, 1, 0, 

0 !

! nNOX = 1, 1, 0, 

0 !

! nPM10 = 1, 1, 0, 

0 !

! nPM25 = 1, 1, 0, 

0 !

!END!

 Note: The last species in (3a) must be 'BCON' when using the

 boundary condition option (MBCON > 0). Species BCON should

 typically be modeled as inert (no chem transformation or

 removal). 
M-11

-------------

Subgroup (3b)

-------------

 The following names are used for Species-Groups in which results

 for certain species are combined (added) prior to output. The

 CGRUP name will be used as the species name in output files.

 Use this feature to model specific particle-size distributions

 by treating each size-range as a separate species.

 Order must be consistent with 3(a) above.

--------------------------------------------------------------------------

-----

INPUT GROUP: 4 -- Map Projection and Grid control parameters

--------------

 Projection for all (X,Y):

 -------------------------

 Map projection

 (PMAP) Default: UTM ! PMAP = PS !

 UTM : Universal Transverse Mercator

 TTM : Tangential Transverse Mercator

 LCC : Lambert Conformal Conic

 PS : Polar Stereographic

 EM : Equatorial Mercator

 LAZA : Lambert Azimuthal Equal Area

 False Easting and Northing (km) at the projection origin

 (Used only if PMAP= TTM, LCC, or LAZA)

 (FEAST) Default=0.0 ! FEAST = 0.000 !

 (FNORTH) Default=0.0 ! FNORTH = 0.000 !

 UTM zone (1 to 60)

 (Used only if PMAP=UTM)

 (IUTMZN) No Default ! IUTMZN = 0 !

 Hemisphere for UTM projection?

 (Used only if PMAP=UTM)

 (UTMHEM) Default: N ! UTMHEM = N !

 N : Northern hemisphere projection

 S : Southern hemisphere projection

 Latitude and Longitude (decimal degrees) of projection origin

 (Used only if PMAP= TTM, LCC, PS, EM, or LAZA)

 (RLAT0) No Default ! RLAT0 = 70.000N !

 (RLON0) No Default ! RLON0 = 155.000W !

 TTM : RLON0 identifies central (true N/S) meridian of projection
M-12

 RLAT0 selected for convenience

 LCC : RLON0 identifies central (true N/S) meridian of projection

 RLAT0 selected for convenience

 PS : RLON0 identifies central (grid N/S) meridian of projection

 RLAT0 selected for convenience

 EM : RLON0 identifies central meridian of projection

 RLAT0 is REPLACED by 0.0N (Equator)

 LAZA: RLON0 identifies longitude of tangent-point of mapping 

plane

 RLAT0 identifies latitude of tangent-point of mapping 

plane

 Matching parallel(s) of latitude (decimal degrees) for projection

 (Used only if PMAP= LCC or PS)

 (XLAT1) No Default ! XLAT1 = 70.000N !

 (XLAT2) No Default ! XLAT2 = 70.000N !

 LCC : Projection cone slices through Earth's surface at XLAT1 

and XLAT2

 PS : Projection plane slices through Earth at XLAT1

 (XLAT2 is not used)

 ----------

 Note: Latitudes and longitudes should be positive, and include a

 letter N,S,E, or W indicating north or south latitude, and

 east or west longitude. For example,

 35.9 N Latitude = 35.9N

 118.7 E Longitude = 118.7E

 Datum-region

 ------------

 The Datum-Region for the coordinates is identified by a character

 string. Many mapping products currently available use the model of 

the

 Earth known as the World Geodetic System 1984 (WGS-84). Other local

 models may be in use, and their selection in CALMET will make its 

output

 consistent with local mapping products. The list of Datum-Regions 

with

 official transformation parameters is provided by the National 

Imagery and

 Mapping Agency (NIMA).

 NIMA Datum - Regions(Examples)

 ---------------------------------------------------------------------

---------

 WGS-84 WGS-84 Reference Ellipsoid and Geoid, Global coverage 

(WGS84)

 NAS-C NORTH AMERICAN 1927 Clarke 1866 Spheroid, MEAN FOR CONUS 

(NAD27)

 NAR-C NORTH AMERICAN 1983 GRS 80 Spheroid, MEAN FOR CONUS (NAD83)

 NWS-84 NWS 6370KM Radius, Sphere
M-13

 ESR-S ESRI REFERENCE 6371KM Radius, Sphere

 Datum-region for output coordinates

 (DATUM) Default: WGS-G ! DATUM = NWS-84 ! 

 *** Same as WRF ***

METEOROLOGICAL Grid:

 Rectangular grid defined for projection PMAP,

 with X the Easting and Y the Northing coordinate

 No. X grid cells (NX) No default ! NX = 141 !

 No. Y grid cells (NY) No default ! NY = 100 !

 No. vertical layers (NZ) No default ! NZ = 10 !

 Grid spacing (DGRIDKM) No default ! DGRIDKM = 4.000 !

 Units: km

 Cell face heights

 (ZFACE(nz+1)) No defaults

 Units: m

 ! ZFACE =0.,20.,40.,80.,160.,320.,640.,1200.,2000.,3000.,4000. 

! 

 Reference Coordinates

 of SOUTHWEST corner of

 grid cell(1, 1):

 X coordinate (XORIGKM) No default ! XORIGKM = -130.000 

! 

 Y coordinate (YORIGKM) No default ! YORIGKM = -238.000 

! 

 Units: km

COMPUTATIONAL Grid:

 The computational grid is identical to or a subset of the MET. grid.

 The lower left (LL) corner of the computational grid is at grid point

 (IBCOMP, JBCOMP) of the MET. grid. The upper right (UR) corner of 

the

 computational grid is at grid point (IECOMP, JECOMP) of the MET. 

grid.

 The grid spacing of the computational grid is the same as the MET. 

grid.

 X index of LL corner (IBCOMP) No default ! IBCOMP = 1 !

 (1 <= IBCOMP <= NX)

 Y index of LL corner (JBCOMP) No default ! JBCOMP = 1 !

 (1 <= JBCOMP <= NY)
M-14

 X index of UR corner (IECOMP) No default ! IECOMP = 141 !

 (1 <= IECOMP <= NX)

 Y index of UR corner (JECOMP) No default ! JECOMP = 100 !

 (1 <= JECOMP <= NY)

SAMPLING Grid (GRIDDED RECEPTORS):

 The lower left (LL) corner of the sampling grid is at grid point

 (IBSAMP, JBSAMP) of the MET. grid. The upper right (UR) corner of 

the

 sampling grid is at grid point (IESAMP, JESAMP) of the MET. grid.

 The sampling grid must be identical to or a subset of the 

computational

 grid. It may be a nested grid inside the computational grid.

 The grid spacing of the sampling grid is DGRIDKM/MESHDN.

 Logical flag indicating if gridded

 receptors are used (LSAMP) Default: T ! LSAMP = F !

 (T=yes, F=no)

 X index of LL corner (IBSAMP) No default ! IBSAMP = 1 !

 (IBCOMP <= IBSAMP <= IECOMP)

 Y index of LL corner (JBSAMP) No default ! JBSAMP = 1 !

 (JBCOMP <= JBSAMP <= JECOMP)

 X index of UR corner (IESAMP) No default ! IESAMP = 141 !

 (IBCOMP <= IESAMP <= IECOMP)

 Y index of UR corner (JESAMP) No default ! JESAMP = 100 !

 (JBCOMP <= JESAMP <= JECOMP)

 Nesting factor of the sampling

 grid (MESHDN) Default: 1 ! MESHDN = 1 !

 (MESHDN is an integer >= 1)

!END!

--------------------------------------------------------------------------

-----

INPUT GROUP: 5 -- Output Options

--------------

 * *

 FILE DEFAULT VALUE VALUE THIS RUN

 ---- ------------- --------------
M-15

 Concentrations (ICON) 1 ! ICON = 1 !

 Dry Fluxes (IDRY) 1 ! IDRY = 1 !

 Wet Fluxes (IWET) 1 ! IWET = 1 !

 2D Temperature (IT2D) 0 ! IT2D = 0 !

 2D Density (IRHO) 0 ! IRHO = 0 !

 Relative Humidity (IVIS) 1 ! IVIS = 0 !

 (RH file is required for

 VISIBILITY analyses)

 Use data compression option in output file?

 (LCOMPRS) Default: T ! LCOMPRS = T !

 * 

 0 = Do not create file, 1 = create file

 QA PLOT FILE OUTPUT OPTION:

 Create a standard series of output files (e.g.

 locations of sources, receptors, grids ...)

 suitable for plotting?

 (IQAPLOT) Default: 1 ! IQAPLOT = 1 

! 

 0 = no

 1 = yes

 DIAGNOSTIC MASS FLUX OUTPUT OPTIONS:

 Mass flux across specified boundaries

 for selected species reported hourly?

 (IMFLX) Default: 0 ! IMFLX = 0 !

 0 = no

 1 = yes (FLUXBDY.DAT and MASSFLX.DAT filenames

 are specified in Input Group 0)

 Mass balance for each species

 reported hourly?

 (IMBAL) Default: 0 ! IMBAL = 1 !

 0 = no

 1 = yes (MASSBAL.DAT filename is

 specified in Input Group 0)

 LINE PRINTER OUTPUT OPTIONS:

 Print concentrations (ICPRT) Default: 0 ! ICPRT = 0 !

 Print dry fluxes (IDPRT) Default: 0 ! IDPRT = 0 !

 Print wet fluxes (IWPRT) Default: 0 ! IWPRT = 0 !

 (0 = Do not print, 1 = Print)

 Concentration print interval

 (ICFRQ) in hours Default: 1 ! ICFRQ = 24 

! 
M-16

 Dry flux print interval

 (IDFRQ) in hours Default: 1 ! IDFRQ = 1 !

 Wet flux print interval

 (IWFRQ) in hours Default: 1 ! IWFRQ = 1 !

 Units for Line Printer Output

 (IPRTU) Default: 1 ! IPRTU = 1 !

 for for

 Concentration Deposition

 1 = g/m**3 g/m**2/s

 2 = mg/m**3 mg/m**2/s

 3 = ug/m**3 ug/m**2/s

 4 = ng/m**3 ng/m**2/s

 5 = Odour Units

 Messages tracking progress of run

 written to the screen ?

 (IMESG) Default: 2 ! IMESG = 2 !

 0 = no

 1 = yes (advection step, puff ID)

 2 = yes (2009JJJHH, # old puffs, # emitted puffs)

 SPECIES (or GROUP for combined species) LIST FOR OUTPUT OPTIONS

 ---- CONCENTRATIONS ---- ------ DRY FLUXES ------ ------ WET 

FLUXES ------ -- MASS FLUX --

 SPECIES

 /GROUP PRINTED? SAVED ON DISK? PRINTED? SAVED ON DISK? PRINTED? 

SAVED ON DISK? SAVED ON DISK?

 ------- ------------------------ ------------------------ -----------

------------- ---------------

! SO2 = 0, 1, 0, 1, 0, 

1, 0 !

! NOX = 0, 1, 0, 1, 0, 

1, 0 !

! HNO3 = 0, 1, 0, 1, 0, 

1, 0 !

! SO4 = 0, 1, 0, 1, 0, 

1, 0 !

! NO3 = 0, 1, 0, 1, 0, 

1, 0 !

! EC = 0, 1, 0, 1, 0, 

1, 0 !

! SOA = 0, 1, 0, 1, 0, 

1, 0 !

! PMC = 0, 1, 0, 1, 0, 

1, 0 !

! PMF = 0, 1, 0, 1, 0, 

1, 0 !

! nSO2 = 0, 1, 0, 0, 0, 

0, 0 !

! nNOX = 0, 1, 0, 0, 0, 

0, 0 !
M-17

! nPM10 = 0, 1, 0, 0, 0, 

0, 0 !

! nPM25 = 0, 1, 0, 0, 0, 

0, 0 !

 Note: Species BCON (for MBCON > 0) does not need to be saved on disk.

 OPTIONS FOR PRINTING "DEBUG" QUANTITIES (much output) 

 Logical for debug output

 (LDEBUG) Default: F ! LDEBUG = 

F !

 First puff to track

 (IPFDEB) Default: 1 ! IPFDEB = 

1 !

 Number of puffs to track

 (NPFDEB) Default: 1 ! NPFDEB = 

1 !

 Met. period to start output

 (NN1) Default: 1 ! NN1 = 1 

! 

 Met. period to end output

 (NN2) Default: 10 ! NN2 = 10 

! 

!END!

--------------------------------------------------------------------------

-----

INPUT GROUP: 6a, 6b, & 6c -- Subgrid scale complex terrain inputs

-------------------------

---------------

Subgroup (6a)

---------------

 Number of terrain features (NHILL) Default: 0 ! NHILL = 

0 !

 Number of special complex terrain

 receptors (NCTREC) Default: 0 ! NCTREC = 

0 !

 Terrain and CTSG Receptor data for 

 CTSG hills input in CTDM format ?
M-18

 (MHILL) No Default ! MHILL = 

2 !

 1 = Hill and Receptor data created

 by CTDM processors & read from

 HILL.DAT and HILLRCT.DAT files

 2 = Hill data created by OPTHILL &

 input below in Subgroup (6b);

 Receptor data in Subgroup (6c)

 Factor to convert horizontal dimensions Default: 1.0 ! XHILL2M = 

0. !

 to meters (MHILL=1)

 Factor to convert vertical dimensions Default: 1.0 ! ZHILL2M = 

0. !

 to meters (MHILL=1)

 X-origin of CTDM system relative to No Default ! XCTDMKM = 

0.0E00 !

 CALPUFF coordinate system, in Kilometers (MHILL=1)

 Y-origin of CTDM system relative to No Default ! YCTDMKM = 

0.0E00 !

 CALPUFF coordinate system, in Kilometers (MHILL=1)

! END !

---------------

Subgroup (6b)

---------------

 1 **

 HILL information

HILL XC YC THETAH ZGRID RELIEF EXPO 1 EXPO 

2 SCALE 1 SCALE 2 AMAX1 AMAX2

NO. (km) (km) (deg.) (m) (m) (m) (m) 

(m) (m) (m) (m)

---- ---- ---- ------ ----- ------ ------ -----

- ------- ------- ----- -----

---------------

Subgroup (6c)

---------------

 COMPLEX TERRAIN RECEPTOR INFORMATION

 XRCT YRCT ZRCT XHH

(km) (km) (m)

 ------ ----- ------ ----

-------------------
M-19

1 

 Description of Complex Terrain Variables:

 XC, YC = Coordinates of center of hill

 THETAH = Orientation of major axis of hill (clockwise from

 North)

 ZGRID = Height of the 0 of the grid above mean sea

 level

 RELIEF = Height of the crest of the hill above the grid 

elevation

 EXPO 1 = Hill-shape exponent for the major axis

 EXPO 2 = Hill-shape exponent for the major axis

 SCALE 1 = Horizontal length scale along the major axis

 SCALE 2 = Horizontal length scale along the minor axis

 AMAX = Maximum allowed axis length for the major axis

 BMAX = Maximum allowed axis length for the major axis

 XRCT, YRCT = Coordinates of the complex terrain receptors

 ZRCT = Height of the ground (MSL) at the complex terrain

 Receptor

 XHH = Hill number associated with each complex terrain 

receptor

 (NOTE: MUST BE ENTERED AS A REAL NUMBER)

 **

 NOTE: DATA for each hill and CTSG receptor are treated as a separate

 input subgroup and therefore must end with an input group 

terminator.

--------------------------------------------------------------------------

-----

INPUT GROUP: 7 -- Chemical parameters for dry deposition of gases

--------------

 SPECIES DIFFUSIVITY ALPHA STAR REACTIVITY MESOPHYLL 

RESISTANCE HENRY'S LAW COEFFICIENT

 NAME (cm**2/s) 

(s/cm) (dimensionless)

 ------- ----------- ---------- ---------- ---------

----------- -----------------------

! SO2 = 0.1509, 1000., 8., 0., 

0.04 !

! NOX = 0.1656, 1., 8., 5., 

3.5 !

! HNO3 = 0.1628, 1., 18., 0., 

0.00000008 !

!END!

--------------------------------------------------------------------------

-----
M-20

INPUT GROUP: 8 -- Size parameters for dry deposition of particles

--------------

 For SINGLE SPECIES, the mean and standard deviation are used to

 compute a deposition velocity for NINT (see group 9) size-ranges,

 and these are then averaged to obtain a mean deposition velocity.

 For GROUPED SPECIES, the size distribution should be explicitly

 specified (by the 'species' in the group), and the standard deviation

 for each should be entered as 0. The model will then use the

 deposition velocity for the stated mean diameter.

 SPECIES GEOMETRIC MASS MEAN GEOMETRIC STANDARD

 NAME DIAMETER DEVIATION

 (microns) (microns)

 ------- ------------------- ------------------

! SO4 = 0.48, 2.0 !

! NO3 = 0.48, 2.0 !

! EC = 0.48, 2.0 !

! SOA = 0.48, 2.0 !

! PMC = 5.0, 1.5 !

! PMF = 0.48, 2.0 !

!END!

--------------------------------------------------------------------------

-----

INPUT GROUP: 9 -- Miscellaneous dry deposition parameters

--------------

 Reference cuticle resistance (s/cm)

 (RCUTR) Default: 30 ! RCUTR = 30.0 !

 Reference ground resistance (s/cm)

 (RGR) Default: 10 ! RGR = 10.0 !

 Reference pollutant reactivity

 (REACTR) Default: 8 ! REACTR = 8.0 !

 Number of particle-size intervals used to 

 evaluate effective particle deposition velocity

 (NINT) Default: 9 ! NINT = 9 !

 Vegetation state in unirrigated areas

 (IVEG) Default: 1 ! IVEG = 1 !

 IVEG=1 for active and unstressed vegetation

 IVEG=2 for active and stressed vegetation

 IVEG=3 for inactive vegetation

!END!
M-21

--------------------------------------------------------------------------

-----

INPUT GROUP: 10 -- Wet Deposition Parameters

---------------

 

 Scavenging Coefficient -- Units: (sec)**(-1)

 Pollutant Liquid Precip. Frozen Precip.

 --------- -------------- --------------

! SO2 = 3.0E-05, 0.0E00 !

! SO4 = 1.0E-04, 3.0E-05 !

! NOX = 0.0E00, 0.0E00 !

! HNO3 = 6.0E-05, 0.0E00 !

! NO3 = 1.0E-04, 3.0E-05 !

! EC = 1.0E-04, 3.0E-05 !

! SOA = 1.0E-04, 3.0E-05 !

! PMC = 1.0E-04, 3.0E-05 !

! PMF = 1.0E-04, 3.0E-05 !

!END!

--------------------------------------------------------------------------

-----

INPUT GROUP: 11 -- Chemistry Parameters

---------------

 Ozone data input option (MOZ) Default: 1 ! MOZ = 1 !

 (Used only if MCHEM = 1, 3, or 4)

 0 = use a monthly background ozone value

 1 = read hourly ozone concentrations from

 the OZONE.DAT data file

 Monthly ozone concentrations

 (Used only if MCHEM = 1, 3, or 4 and 

 MOZ = 0 or MOZ = 1 and all hourly O3 data missing)

 (BCKO3) in ppb Default: 12*80. 

 ! BCKO3 = 12*59.8 ! ** Highest o3 measured during modeling period, 

59.8 ppb on Feb 19 2009 at 17:00 **

 Monthly ammonia concentrations

 (Used only if MCHEM = 1, or 3)

 (BCKNH3) in ppb Default: 12*10. ! BCKNH3 = 

12*1.0 !

 Nighttime SO2 loss rate (RNITE1)
M-22

 in percent/hour Default: 0.2 ! RNITE1 = .2 

! 

 Nighttime NOx loss rate (RNITE2)

 in percent/hour Default: 2.0 ! RNITE2 = 

2.0 !

 Nighttime HNO3 formation rate (RNITE3)

 in percent/hour Default: 2.0 ! RNITE3 = 

2.0 !

 H2O2 data input option (MH2O2) Default: 1 ! MH2O2 = 0 

! 

 (Used only if MAQCHEM = 1)

 0 = use a monthly background H2O2 value

 1 = read hourly H2O2 concentrations from

 the H2O2.DAT data file

 Monthly H2O2 concentrations

 (Used only if MQACHEM = 1 and

 MH2O2 = 0 or MH2O2 = 1 and all hourly H2O2 data missing)

 (BCKH2O2) in ppb Default: 12*1. ! BCKH2O2 = 

12*1.0 ! 

--- Data for SECONDARY ORGANIC AEROSOL (SOA) Option

 (used only if MCHEM = 4)

 The SOA module uses monthly values of:

 Fine particulate concentration in ug/m^3 (BCKPMF)

 Organic fraction of fine particulate (OFRAC)

 VOC / NOX ratio (after reaction) (VCNX)

 to characterize the air mass when computing

 the formation of SOA from VOC emissions.

 Typical values for several distinct air mass types are:

 Month 1 2 3 4 5 6 7 8 9 10 11 12

 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

 Clean Continental

 BCKPMF 1. 1. 1. 1. 1. 1. 1. 1. 1. 1. 1. 1.

 OFRAC .15 .15 .20 .20 .20 .20 .20 .20 .20 .20 .20 .15

 VCNX 50. 50. 50. 50. 50. 50. 50. 50. 50. 50. 50. 50.

 Clean Marine (surface)

 BCKPMF .5 .5 .5 .5 .5 .5 .5 .5 .5 .5 .5 .5

 OFRAC .25 .25 .30 .30 .30 .30 .30 .30 .30 .30 .30 .25

 VCNX 50. 50. 50. 50. 50. 50. 50. 50. 50. 50. 50. 50.

 Urban - low biogenic (controls present)

 BCKPMF 30. 30. 30. 30. 30. 30. 30. 30. 30. 30. 30. 30.

 OFRAC .20 .20 .25 .25 .25 .25 .25 .25 .20 .20 .20 .20

 VCNX 4. 4. 4. 4. 4. 4. 4. 4. 4. 4. 4. 4.
M-23

 Urban - high biogenic (controls present)

 BCKPMF 60. 60. 60. 60. 60. 60. 60. 60. 60. 60. 60. 60.

 OFRAC .25 .25 .30 .30 .30 .55 .55 .55 .35 .35 .35 .25

 VCNX 15. 15. 15. 15. 15. 15. 15. 15. 15. 15. 15. 15.

 Regional Plume

 BCKPMF 20. 20. 20. 20. 20. 20. 20. 20. 20. 20. 20. 20.

 OFRAC .20 .20 .25 .35 .25 .40 .40 .40 .30 .30 .30 .20

 VCNX 15. 15. 15. 15. 15. 15. 15. 15. 15. 15. 15. 15.

 Urban - no controls present

 BCKPMF 100. 100. 100. 100. 100. 100. 100. 100. 100. 100. 100. 100.

 OFRAC .30 .30 .35 .35 .35 .55 .55 .55 .35 .35 .35 .30

 VCNX 2. 2. 2. 2. 2. 2. 2. 2. 2. 2. 2. 2.

 Default: Clean Continental

 ! BCKPMF = 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 

1.00, 1.00, 1.00 !

 ! OFRAC = 0.15, 0.15, 0.20, 0.20, 0.20, 0.20, 0.20, 0.20, 0.20, 

0.20, 0.20, 0.15 !

 ! VCNX = 50.0, 50.0, 50.0, 50.0, 50.0, 50.0, 50.0, 50.0, 50.0, 

50.0, 50.0, 50.0 !

!END!

--------------------------------------------------------------------------

-----

INPUT GROUP: 12 -- Misc. Dispersion and Computational Parameters

---------------

 Horizontal size of puff (m) beyond which

 time-dependent dispersion equations (Heffter)

 are used to determine sigma-y and

 sigma-z (SYTDEP) Default: 550. ! SYTDEP = 

550.0 !

 Switch for using Heffter equation for sigma z 

 as above (0 = Not use Heffter; 1 = use Heffter

 (MHFTSZ) Default: 0 ! MHFTSZ = 

0 !

 Stability class used to determine plume

 growth rates for puffs above the boundary

 layer (JSUP) Default: 5 ! JSUP = 

5 !

 Vertical dispersion constant for stable

 conditions (k1 in Eqn. 2.7-3) (CONK1) Default: 0.01 ! CONK1 = 

.01 !
M-24

 Vertical dispersion constant for neutral/

 unstable conditions (k2 in Eqn. 2.7-4)

 (CONK2) Default: 0.1 ! CONK2 = 

.1 !

 Factor for determining Transition-point from

 Schulman-Scire to Huber-Snyder Building Downwash

 scheme (SS used for Hs < Hb + TBD * HL)

 (TBD) Default: 0.5 ! TBD = .5 

! 

 TBD < 0 ==> always use Huber-Snyder

 TBD = 1.5 ==> always use Schulman-Scire

 TBD = 0.5 ==> ISC Transition-point

 Range of land use categories for which

 urban dispersion is assumed

 (IURB1, IURB2) Default: 10 ! IURB1 = 

1 ! **wrf urban**

 19 ! IURB2 = 

1 !

 Site characterization parameters for single-point Met data files ----

-----

 (needed for METFM = 2,3,4,5)

 Land use category for modeling domain

 (ILANDUIN) Default: 20 ! ILANDUIN 

= 20 !

 Roughness length (m) for modeling domain

 (Z0IN) Default: 0.25 ! Z0IN = 

.25 !

 Leaf area index for modeling domain

 (XLAIIN) Default: 3.0 ! XLAIIN = 

3.0 !

 Elevation above sea level (m)

 (ELEVIN) Default: 0.0 ! ELEVIN = 

.0 !

 Latitude (degrees) for met location

 (XLATIN) Default: -999. ! XLATIN = 

-999.0 !

 Longitude (degrees) for met location

 (XLONIN) Default: -999. ! XLONIN = 

-999.0 !

 Specialized information for interpreting single-point Met data files 

-----

 Anemometer height (m) (Used only if METFM = 2,3)
M-25

 (ANEMHT) Default: 10. ! ANEMHT = 

10.0 !

 Form of lateral turbulance data in PROFILE.DAT file

 (Used only if METFM = 4,5 or MTURBVW = 1 or 3)

 (ISIGMAV) Default: 1 ! ISIGMAV 

= 1 !

 0 = read sigma-theta

 1 = read sigma-v 

 Choice of mixing heights (Used only if METFM = 4)

 (IMIXCTDM) Default: 0 ! IMIXCTDM 

= 0 !

 0 = read PREDICTED mixing heights

 1 = read OBSERVED mixing heights

 Maximum length of a slug (met. grid units)

 (XMXLEN) Default: 1.0 ! XMXLEN = 

1.0 !

 Maximum travel distance of a puff/slug (in

 grid units) during one sampling step

 (XSAMLEN) Default: 1.0 ! XSAMLEN 

= 1.0 !

 Maximum Number of slugs/puffs release from

 one source during one time step 

 (MXNEW) Default: 99 ! MXNEW = 

99 !

 Maximum Number of sampling steps for 

 one puff/slug during one time step 

 (MXSAM) Default: 99 ! MXSAM = 

99 !

 Number of iterations used when computing

 the transport wind for a sampling step

 that includes gradual rise (for CALMET

 and PROFILE winds)

 (NCOUNT) Default: 2 ! NCOUNT = 

2 !

 Minimum sigma y for a new puff/slug (m) 

 (SYMIN) Default: 1.0 ! SYMIN = 

1.0 !

 Minimum sigma z for a new puff/slug (m) 

 (SZMIN) Default: 1.0 ! SZMIN = 

1.0 !

 Default minimum turbulence velocities sigma-v and sigma-w 

 for each stability class over land and over water (m/s)

 (SVMIN(12) and SWMIN(12))
M-26

 ---------- LAND ---------- --------- WATER 

----------

 Stab Class : A B C D E F A B C D 

E F 

 --- --- --- --- --- --- --- --- --- --- 

--- ---

 Default SVMIN : .50, .50, .50, .50, .50, .50, .37, .37, .37, 

.37, .37, .37

 Default SWMIN : .20, .12, .08, .06, .03, .016, .20, .12, .08, 

.06, .03, .016

 * SVMIN = 0.500, 0.500, 0.500, 0.500, 0.500, 0.500, 0.370, 

0.370, 0.370, 0.370, 0.370, 0.370 *

 ! SVMIN = 12* 0.5 ! MREG = 1 requirement

 ! SWMIN = 0.200, 0.120, 0.080, 0.060, 0.030, 0.016, 0.200, 

0.120, 0.080, 0.060, 0.030, 0.016!

 Divergence criterion for dw/dz across puff

 used to initiate adjustment for horizontal

 convergence (1/s)

 Partial adjustment starts at CDIV(1), and

 full adjustment is reached at CDIV(2)

 (CDIV(2)) Default: 0.0,0.0 ! CDIV = 

0.0, 0.0 !

 Minimum wind speed (m/s) allowed for

 non-calm conditions. Also used as minimum

 speed returned when using power-law 

 extrapolation toward surface

 (WSCALM) Default: 0.5 ! WSCALM = 

.5 !

 Maximum mixing height (m) 

 (XMAXZI) Default: 3000. ! XMAXZI = 

3000.0 !

 Minimum mixing height (m) 

 (XMINZI) Default: 50. ! XMINZI = 

50.0 !

 Default wind speed classes --

 5 upper bounds (m/s) are entered;

 the 6th class has no upper limit

 (WSCAT(5)) Default : 

 ISC RURAL : 1.54, 3.09, 5.14, 8.23, 

10.8 (10.8+)

 Wind Speed Class : 1 2 3 4 

5 

 --- --- --- --- -

-- 

 ! WSCAT = 1.54, 3.09, 5.14, 8.23, 

10.80 !
M-27

 Default wind speed profile power-law

 exponents for stabilities 1-6 

 (PLX0(6)) Default : ISC RURAL values

 ISC RURAL : .07, .07, .10, .15, .35, 

.55

ISC URBAN : .15, .15, .20, .25, .30, 

.30

 Stability Class : A B C D 

E F

 --- --- --- --- -

-- ---

 ! PLX0 = 0.07, 0.07, 0.10, 0.15, 

0.35, 0.55 !

 Default potential temperature gradient

 for stable classes E, F (degK/m)

 (PTG0(2)) Default: 0.020, 0.035

 ! PTG0 = 0.020, 0.035 !

 Default plume path coefficients for

 each stability class (used when option

 for partial plume height terrain adjustment

 is selected -- MCTADJ=3)

 (PPC(6)) Stability Class : A B C D 

E F

 Default PPC : .50, .50, .50, .50, 

.35, .35

 --- --- --- --- -

-- ---

 ! PPC = 0.50, 0.50, 0.50, 0.50, 

0.35, 0.35 !

 Slug-to-puff transition criterion factor

 equal to sigma-y/length of slug

 (SL2PF) Default: 10. ! SL2PF = 

10.0!

 Puff-splitting control variables ------------------------

 VERTICAL SPLIT

 --------------

 Number of puffs that result every time a puff

 is split - nsplit=2 means that 1 puff splits

 into 2

 (NSPLIT) Default: 3 ! NSPLIT = 

3 !

 Time(s) of a day when split puffs are eligible to

 be split once again; this is typically set once

 per day, around sunset before nocturnal shear develops.

 24 values: 0 is midnight (00:00) and 23 is 11 PM (23:00)
M-28

 0=do not re-split 1=eligible for re-split

 (IRESPLIT(24)) Default: Hour 17 = 1

 ! IRESPLIT = 0,0,0,0,0,0,0,0,0,0,0,0,0,0,0,0,0,1,0,0,0,0,0,0 !

 Split is allowed only if last hour's mixing

 height (m) exceeds a minimum value

 (ZISPLIT) Default: 100. ! ZISPLIT = 

100.0 !

 Split is allowed only if ratio of last hour's

 mixing ht to the maximum mixing ht experienced

 by the puff is less than a maximum value (this

 postpones a split until a nocturnal layer develops)

 (ROLDMAX) Default: 0.25 ! ROLDMAX = 

0.25 !

 HORIZONTAL SPLIT

 ----------------

 Number of puffs that result every time a puff

 is split - nsplith=5 means that 1 puff splits

 into 5

 (NSPLITH) Default: 5 ! NSPLITH = 

5 !

 Minimum sigma-y (Grid Cells Units) of puff

 before it may be split

 (SYSPLITH) Default: 1.0 ! SYSPLITH 

= 1.0 !

 Minimum puff elongation rate (SYSPLITH/hr) due to

 wind shear, before it may be split

 (SHSPLITH) Default: 2. ! SHSPLITH 

= 2.0 !

 Minimum concentration (g/m^3) of each

 species in puff before it may be split

 Enter array of NSPEC values; if a single value is

 entered, it will be used for ALL species

 (CNSPLITH) Default: 1.0E-07 ! CNSPLITH 

= 1.0E-07 !

 Integration control variables ------------------------

 Fractional convergence criterion for numerical SLUG

 sampling integration

 (EPSSLUG) Default: 1.0e-04 ! EPSSLUG = 

1.0E-04 !

 Fractional convergence criterion for numerical AREA

 source integration

 (EPSAREA) Default: 1.0e-06 ! EPSAREA = 

1.0E-06 !
M-29

 Trajectory step-length (m) used for numerical rise

 integration

 (DSRISE) Default: 1.0 ! DSRISE = 

1.0 !

 Boundary Condition (BC) Puff control variables ----------------------

--

 Minimum height (m) to which BC puffs are mixed as they are emitted

 (MBCON=2 ONLY). Actual height is reset to the current mixing 

height

 at the release point if greater than this minimum.

 (HTMINBC) Default: 500. ! HTMINBC = 

500. !

 Search radius (km) about a receptor for sampling nearest BC puff.

 BC puffs are typically emitted with a spacing of one grid cell

 length, so the search radius should be greater than DGRIDKM.

 (RSAMPBC) Default: 10. ! RSAMPBC = 

10 !

 Near-Surface depletion adjustment to concentration profile used 

when

 sampling BC puffs?

 (MDEPBC) Default: 1 ! MDEPBC = 

1 !

 0 = Concentration is NOT adjusted for depletion

 1 = Adjust Concentration for depletion

!END!

--------------------------------------------------------------------------

-----

INPUT GROUPS: 13a, 13b, 13c, 13d -- Point source parameters

--------------------------------

---------------

Subgroup (13a)

---------------

 Number of point sources with

 parameters provided below (NPT1) No default ! NPT1 = 17 !

 Units used for point source

 emissions below (IPTU) Default: 1 ! IPTU = 1 !

 1 = g/s

 2 = kg/hr

 3 = lb/hr

 4 = tons/yr

 5 = Odour Unit * m**3/s (vol. flux of odour compound)
M-30

 6 = Odour Unit * m**3/min

 7 = metric tons/yr

 Number of source-species

 combinations with variable

 emissions scaling factors

 provided below in (13d) (NSPT1) Default: 0 ! NSPT1 = 0 !

 Number of point sources with

 variable emission parameters

 provided in external file (NPT2) No default ! NPT2 = 0 !

 (If NPT2 > 0, these point

 source emissions are read from

 the file: PTEMARB.DAT)

!END!

---------------

Subgroup (13b)

---------------

 a 

 POINT SOURCE: CONSTANT DATA

 -----------------------------

 

b c

 Source X UTM Y UTM Stack Base Stack Exit Exit 

Bldg. Emission

 No. Coordinate Coordinate Height Elevation Diameter Vel. Temp. 

Dwash Rates

 (km) (km) (m) (m) (m) (m/s) (deg. K) 

 ------ ---------- ---------- ------ ------ -------- ----- --------

----- --------

*** Max short-term emission rates ***

*** The species starting with "n" (the last four) are non-reactive 

versions ***

 X Y Ht Elev Diam Vel Temp DW SO2 SO4 NOX 

HNO3 NO3 EC SOA PMC PMF nSO2 nNOx nPM10 nPM25

! SRCNAM = GMT2HT !

! X = 125.12678, 22.83898, 12.2, 33.259, 0.94, 5.7, 529, 0, 2.49E04,9.96E-05,2.33E-02,0,3.16E-06,1.10E-04,3.05E-04,2.92E-04,1.93E-03,2.49E04,2.33E-02,2.78E-03,0.00E+00 !

! END !

! SRCNAM = CAMPGEN !

! X = 125.11929, 22.93334, 6.5, 33.259, 0.2, 47, 761, 0, 4.62E-04,8.98E06,4.94E-01,0,1.34E-05,3.01E-03,1.47E-02,0.00E+00,6.99E-03,4.62E-04,4.94E01,2.47E-02,2.47E-02 !

! END !

! SRCNAM = DRILLPE !

! X = 125.0211, 22.86409, 13.3, 33.210, 0.4, 10.5, 614, 0, 5.64E-04,2.58E03,3.65E-01,0,3.22E-05,0.00E+00,7.41E-04,0.00E+00,1.08E-02,5.64E-04,3.65E01,1.51E-02,0.00E+00 !

! END !

! SRCNAM = DRILLCP1 !
M-31

! X = 125.01318, 22.8738, 10.4, 33.206, 0.13, 43.5, 750, 0, 1.07E05,9.76E-05,1.88E-02,0,1.22E-06,0.00E+00,2.80E-05,0.00E+00,4.07E-04,1.07E05,1.88E-02,5.71E-04,0.00E+00 !

! END !

! SRCNAM = DRILLCP2 !

! X = 125.01679, 22.86911, 10.4, 33.208, 0.13, 43.5, 750, 0, 1.07E05,9.76E-05,1.88E-02,0,1.22E-06,0.00E+00,2.80E-05,0.00E+00,4.07E-04,1.07E05,1.88E-02,5.71E-04,0.00E+00 !

! END !

! SRCNAM = DRILLB1 !

! X = 125.02335, 22.8783, 11.9, 33.211, 0.279, 11.7, 450, 0, 6.49E04,4.06E-04,6.10E-02,0,1.06E-04,2.49E-03,2.24E-03,7.62E-04,1.06E-03,6.49E04,6.10E-02,7.25E-03,0.00E+00 !

! END !

! SRCNAM = DRILLB2 !

! X = 125.02627, 22.87358, 11.9, 33.213, 0.279, 11.7, 450, 0, 6.49E04,4.06E-04,6.10E-02,0,1.06E-04,2.49E-03,2.24E-03,7.62E-04,1.06E-03,6.49E04,6.10E-02,7.25E-03,0.00E+00 !

! END !

! SRCNAM = DRILLAH1 !

! X = 125.03029, 22.88165, 10.5, 33.215, 0.3, 3.2, 533, 0, 7.75E-04,3.11E04,7.28E-02,0,9.85E-06,3.42E-04,9.52E-04,9.10E-04,6.02E-03,7.75E-04,7.28E02,8.66E-03,0.00E+00 !

! END !

! SRCNAM = DRILLAH2 !

! X = 125.03231, 22.88311, 10.5, 33.216, 0.3, 3.2, 533, 0, 3.88E-04,1.55E04,3.64E-02,0,4.93E-06,1.71E-04,4.76E-04,4.55E-04,3.01E-03,3.88E-04,3.64E02,4.33E-03,0.00E+00 !

! END !

! SRCNAM = DRILLMP !

! X = 125.03045, 22.87736, 7.2, 33.215, 0.3, 10.8, 533, 0, 5.81E-04,2.33E04,5.46E-02,0,7.39E-06,2.56E-04,7.14E-04,6.82E-04,4.51E-03,5.81E-04,5.46E02,6.50E-03,0.00E+00 !

! END !

! SRCNAM = DRILLFLARE !

! X = 125.14489, 22.84136, 10.1429569, 33.267, 0.3, 6.096, 1033.15, 0, 

3.88E-03,8.18E-06,6.77E-02,0,1.02E-07,0.00E+00,2.35E-06,0.00E+00,3.41E05,3.88E-03,6.77E-02,4.79E-05,0.00E+00 !

! END !

! SRCNAM = DRILLEG !

! X = 125.25235, 23.00777, 6.1, 33.323, 0.46, 15.1, 795, 0, 6.03E05,2.35E-06,7.58E-02,0,3.50E-06,7.86E-04,3.83E-03,0.00E+00,1.83E-03,6.03E05,7.58E-02,6.45E-03,0.00E+00 !

! END !

! SRCNAM = FRACENG1 !

! X = 125.04908, 22.89436, 3.7, 33.224, 0.356, 41.6, 644, 0, 5.69E05,1.50E-04,2.18E-02,0,1.88E-06,0.00E+00,4.31E-05,1.30E-04,6.28E-04,5.69E05,2.18E-02,1.01E-03,0.00E+00 !

! END !

! SRCNAM = FRACENG2 !

! X = 125.05935, 22.88207, 3.7, 33.229, 0.356, 41.6, 644, 0, 5.69E05,1.50E-04,2.18E-02,0,1.88E-06,0.00E+00,4.31E-05,1.30E-04,6.28E-04,5.69E05,2.18E-02,1.01E-03,0.00E+00 !

! END !
M-32

! SRCNAM = OPSLH !

! X = 125.1883, 22.9999, 12.2, 33.293, 0.94, 5.7, 529, 0, 5.53E-03,1.96E03,1.51E-01,0,2.44E-05,0.00E+00,5.62E-04,0.00E+00,8.18E-03,5.53E-03,1.51E01,1.15E-02,0.00E+00 !

! END !

! SRCNAM = OPSEMGEN !

! X = 125.11929, 22.93334, 6.1, 33.259, 0.46, 15.1, 795, 0, 2.39E04,1.18E-06,1.04E-01,0,1.76E-06,3.95E-04,1.92E-03,0.00E+00,9.17E-04,2.39E04,1.04E-01,3.24E-03,0.00E+00 !

! END !

! SRCNAM = GRVLHT !

! X = 125.0553, 22.88217, 12.2, 33.227, 0.94, 5.7, 529, 0, 

0,0,0,0,0,0,0,0,0,0,0,0,0.003646717 !

! END !

--------

 a 

 Data for each source are treated as a separate input subgroup

 and therefore must end with an input group terminator.

 SRCNAM is a 12-character name for a source

 (No default)

 X is an array holding the source data listed by the column 

headings

 (No default)

 SIGYZI is an array holding the initial sigma-y and sigma-z (m)

 (Default: 0.,0.)

 FMFAC is a vertical momentum flux factor (0. or 1.0) used to 

represent

 the effect of rain-caps or other physical configurations that

 reduce momentum rise associated with the actual exit 

velocity.

 (Default: 1.0 -- full momentum used)

 ZPLTFM is the platform height (m) for sources influenced by an 

isolated

 structure that has a significant open area between the 

surface

 and the bulk of the structure, such as an offshore oil 

platform.

 The Base Elevation is that of the surface (ground or ocean), 

 and the Stack Height is the release height above the Base 

(not

 above the platform). Building heights entered in Subgroup 

13c

 must be those of the buildings on the platform, measured from

 the platform deck. ZPLTFM is used only with MBDW=1 (ISC

 downwash method) for sources with building downwash.

 (Default: 0.0)

 b 

 0. = No building downwash modeled

 1. = Downwash modeled for buildings resting on the surface

 2. = Downwash modeled for buildings raised above the surface (ZPLTFM 

> 0.)
M-33

 NOTE: must be entered as a REAL number (i.e., with decimal point)

 c 

 An emission rate must be entered for every pollutant modeled.

 Enter emission rate of zero for secondary pollutants that are

 modeled, but not emitted. Units are specified by IPTU

 (e.g. 1 for g/s).

---------------

Subgroup (13c)

---------------

 BUILDING DIMENSION DATA FOR SOURCES SUBJECT TO DOWNWASH

 -------------------------------------------------------

Source 

a 

No. Effective building height, width, length and X/Y offset (in 

meters)

 every 10 degrees. LENGTH, XBADJ, and YBADJ are only needed for

 MBDW=2 (PRIME downwash option)

------ ---------------------------------------------------------------

----

--------

 a 

 Building height, width, length, and X/Y offset from the source are 

treated

 as a separate input subgroup for each source and therefore must end 

with

 an input group terminator.

---------------

Subgroup (13d)

---------------

 a 

 POINT SOURCE: VARIABLE EMISSIONS DATA

 ---------------------------------------

 Use this subgroup to describe temporal variations in the emission

 rates given in 13b. Factors entered multiply the rates in 13b.

 Skip sources here that have constant emissions. For more elaborate

 variation in source parameters, use PTEMARB.DAT and NPT2 > 0.

 IVARY determines the type of variation, and is source-specific:

 (IVARY) Default: 0

 0 = Constant

 1 = Diurnal cycle (24 scaling factors: hours 1-24)

 2 = Monthly cycle (12 scaling factors: months 1-12)

 3 = Hour & Season (4 groups of 24 hourly scaling factors,

 where first group is DEC-JAN-FEB)

 4 = Speed & Stab. (6 groups of 6 scaling factors, where

 first group is Stability Class A,
M-34

 and the speed classes have upper

bounds (m/s) defined in Group 12

 5 = Temperature (12 scaling factors, where temperature

 classes have upper bounds (C) of:

 0, 5, 10, 15, 20, 25, 30, 35, 40,

45, 50, 50+)

--------

 a 

 Data for each species are treated as a separate input subgroup

 and therefore must end with an input group terminator.

--------------------------------------------------------------------------

-----

INPUT GROUPS: 14a, 14b, 14c, 14d -- Area source parameters

--------------------------------

---------------

Subgroup (14a)

---------------

 Number of polygon area sources with

 parameters specified below (NAR1) No default ! NAR1 = 0 !

 Units used for area source

 emissions below (IARU) Default: 1 ! IARU = 1 !

 1 = g/m**2/s

 2 = kg/m**2/hr

 3 = lb/m**2/hr

 4 = tons/m**2/yr

 5 = Odour Unit * m/s (vol. flux/m**2 of odour compound)

 6 = Odour Unit * m/min

 7 = metric tons/m**2/yr

 Number of source-species

 combinations with variable

 emissions scaling factors

 provided below in (14d) (NSAR1) Default: 0 ! NSAR1 = 0 !

 Number of buoyant polygon area sources

 with variable location and emission

 parameters (NAR2) No default ! NAR2 = 0 !

 (If NAR2 > 0, ALL parameter data for

 these sources are read from the file: BAEMARB.DAT)

!END!

---------------

Subgroup (14b)
M-35

---------------

 a 

 AREA SOURCE: CONSTANT DATA

 ----------------------------

 b 

Source Effect. Base Initial Emission

No. Height Elevation Sigma z Rates

 (m) (m) (m) 

------- ------ ------ -------- ---------

--------

 a 

 Data for each source are treated as a separate input subgroup

 and therefore must end with an input group terminator.

 b 

 An emission rate must be entered for every pollutant modeled.

 Enter emission rate of zero for secondary pollutants that are

 modeled, but not emitted. Units are specified by IARU 

 (e.g. 1 for g/m**2/s).

---------------

Subgroup (14c)

---------------

 COORDINATES (UTM-km) FOR EACH VERTEX(4) OF EACH POLYGON

 --------------------------------------------------------

Source a

No. Ordered list of X followed by list of Y, grouped by source

------ ------------------------------------------------------------

--------

 a 

 Data for each source are treated as a separate input subgroup

 and therefore must end with an input group terminator.

---------------

Subgroup (14d)

---------------

 a 

 AREA SOURCE: VARIABLE EMISSIONS DATA

 --------------------------------------

 Use this subgroup to describe temporal variations in the emission

 rates given in 14b. Factors entered multiply the rates in 14b.

 Skip sources here that have constant emissions. For more elaborate

 variation in source parameters, use BAEMARB.DAT and NAR2 > 0.

 IVARY determines the type of variation, and is source-specific:

 (IVARY) Default: 0

 0 = Constant

 1 = Diurnal cycle (24 scaling factors: hours 1-24)
M-36

 2 = Monthly cycle (12 scaling factors: months 1-12)

 3 = Hour & Season (4 groups of 24 hourly scaling factors,

 where first group is DEC-JAN-FEB)

 4 = Speed & Stab. (6 groups of 6 scaling factors, where

 first group is Stability Class A,

and the speed classes have upper

bounds (m/s) defined in Group 12

 5 = Temperature (12 scaling factors, where temperature

 classes have upper bounds (C) of:

 0, 5, 10, 15, 20, 25, 30, 35, 40,

45, 50, 50+)

--------

 a 

 Data for each species are treated as a separate input subgroup

 and therefore must end with an input group terminator.

--------------------------------------------------------------------------

-----

INPUT GROUPS: 15a, 15b, 15c -- Line source parameters

---------------------------

---------------

Subgroup (15a)

---------------

 Number of buoyant line sources

 with variable location and emission

 parameters (NLN2) No default ! NLN2 = 

0 !

 (If NLN2 > 0, ALL parameter data for

 these sources are read from the file: LNEMARB.DAT)

 Number of buoyant line sources (NLINES) No default ! NLINES 

= 0 !

 Units used for line source

 emissions below (ILNU) Default: 1 ! ILNU = 

1 !

 1 = g/s

 2 = kg/hr

 3 = lb/hr

 4 = tons/yr

 5 = Odour Unit * m**3/s (vol. flux of odour compound)

 6 = Odour Unit * m**3/min

 7 = metric tons/yr

 Number of source-species

 combinations with variable
M-37

 emissions scaling factors

 provided below in (15c) (NSLN1) Default: 0 ! NSLN1 = 0 !

 Maximum number of segments used to model

 each line (MXNSEG) Default: 7 ! MXNSEG 

= 7 !

 The following variables are required only if NLINES > 0. They are

 used in the buoyant line source plume rise calculations.

 Number of distances at which Default: 6 ! NLRISE 

= 6 !

 transitional rise is computed

 Average building length (XL) No default ! XL = .0 

! 

 (in meters)

 Average building height (HBL) No default ! HBL = 

.0 !

 (in meters)

 Average building width (WBL) No default ! WBL = 

.0 !

 (in meters)

 Average line source width (WML) No default ! WML = 

.0 !

 (in meters)

 Average separation between buildings (DXL) No default ! DXL = 

.0 !

 (in meters)

 Average buoyancy parameter (FPRIMEL) No default ! FPRIMEL 

= .0 !

 (in m**4/s**3)

!END!

---------------

Subgroup (15b)

---------------

 BUOYANT LINE SOURCE: CONSTANT DATA

 ----------------------------------

 

a 

Source Beg. X Beg. Y End. X End. Y Release Base 

Emission

No. Coordinate Coordinate Coordinate Coordinate Height 

Elevation Rates

 (km) (km) (km) (km) (m) (m) 
M-38

------ ---------- ---------- --------- ---------- ------- --------

- ---------

--------

 a 

 Data for each source are treated as a separate input subgroup

 and therefore must end with an input group terminator.

 b 

 An emission rate must be entered for every pollutant modeled.

 Enter emission rate of zero for secondary pollutants that are

 modeled, but not emitted. Units are specified by ILNTU 

 (e.g. 1 for g/s).

---------------

Subgroup (15c)

---------------

 a 

 BUOYANT LINE SOURCE: VARIABLE EMISSIONS DATA

 ----------------------------------------------

 Use this subgroup to describe temporal variations in the emission

 rates given in 15b. Factors entered multiply the rates in 15b.

 Skip sources here that have constant emissions.

 IVARY determines the type of variation, and is source-specific:

 (IVARY) Default: 0

 0 = Constant

 1 = Diurnal cycle (24 scaling factors: hours 1-24)

 2 = Monthly cycle (12 scaling factors: months 1-12)

 3 = Hour & Season (4 groups of 24 hourly scaling factors,

 where first group is DEC-JAN-FEB)

 4 = Speed & Stab. (6 groups of 6 scaling factors, where

 first group is Stability Class A,

and the speed classes have upper

bounds (m/s) defined in Group 12

 5 = Temperature (12 scaling factors, where temperature

 classes have upper bounds (C) of:

 0, 5, 10, 15, 20, 25, 30, 35, 40,

45, 50, 50+)

--------

 a 

 Data for each species are treated as a separate input subgroup

 and therefore must end with an input group terminator.

--------------------------------------------------------------------------

-----
M-39

INPUT GROUPS: 16a, 16b, 16c -- Volume source parameters

---------------------------

---------------

Subgroup (16a)

---------------

 Number of volume sources with

 parameters provided in 16b,c (NVL1) No default ! NVL1 = 222 !

 Units used for volume source

 emissions below in 16b (IVLU) Default: 1 ! IVLU = 1 !

 1 = g/s

 2 = kg/hr

 3 = lb/hr

 4 = tons/yr

 5 = Odour Unit * m**3/s (vol. flux of odour compound)

 6 = Odour Unit * m**3/min

 7 = metric tons/yr

 Number of source-species

 combinations with variable

 emissions scaling factors

 provided below in (16c) (NSVL1) Default: 0 ! NSVL1 = 0 !

 Number of volume sources with

 variable location and emission

 parameters (NVL2) No default ! NVL2 = 0 !

 (If NVL2 > 0, ALL parameter data for

 these sources are read from the VOLEMARB.DAT file(s) )

!END!

---------------

Subgroup (16b)

---------------

 a 

 VOLUME SOURCE: CONSTANT DATA

 ------------------------------

 

b 

 X UTM Y UTM Effect. Base Initial Initial 

Emission

 Coordinate Coordinate Height Elevation Sigma y Sigma z 

Rates

 (km) (km) (m) (m) (m) (m) 

 ---------- ---------- ------ ------ -------- -------- --

------

*** Max short-term emission rates ***

 X Y Ht Elev sigma-y sigma-z SO2 SO4 NOX 

HNO3 NO3 EC SOA PMC PMF nSO2 nNOx nPM10 nPM25

! SRCNAM = GMT2NR !
M-40

! X = 124.60761, 22.82642, 3.66, 33.012, 62.46108995, 3.37627907, 1.54E04,1.48E-05,1.07E-01,0,6.09E-06,5.31E-03,1.51E-03,2.13E-04,3.59E-05,1.54E04,1.07E-01,7.10E-03,6.89E-03 !

! END !

! SRCNAM = CONFE !

! X = 124.60761, 22.82642, 3.66, 33.012, 62.46108995, 3.37627907, 

0.00E+00,6.50E-04,0,0,2.41E-05,0,5.51E-03,6.39E-01,7.87E02,0.00E+00,0.00E+00,7.24E-01,8.52E-02 !

! END !

! SRCNAM = DRILLNR !

! X = 124.60761, 22.82642, 3.66, 33.012, 62.46108995, 3.37627907, 8.94E04,3.10E-05,1.41E-01,0,1.28E-05,1.11E-02,3.17E-03,1.00E-03,7.52E-05,8.94E04,1.41E-01,1.54E-02,1.44E-02 !

! END !

! SRCNAM = FRACNR !

! X = 124.60761, 22.82642, 3.66, 33.012, 62.46108995, 3.37627907, 3.41E05,1.18E-06,5.38E-03,0,4.87E-07,4.24E-04,1.21E-04,3.83E-05,2.87E-06,3.41E05,5.38E-03,5.88E-04,5.50E-04 !

! END !

! SRCNAM = PADNR !

! X = 124.60761, 22.82642, 3.66, 33.012, 62.46108995, 3.37627907, 

0.00E+00,0.00E+00,0.00E+00,0,0.00E+00,0.00E+00,0.00E+00,0.00E+00,0.00E+00,

0.00E+00,0.00E+00,0.00E+00,6.24E-03 !

! END !

! SRCNAM = PADFE !

! X = 124.60761, 22.82642, 3.66, 33.012, 62.46108995, 0.851, 

0.00E+00,0.00E+00,0.00E+00,0,0.00E+00,0.00E+00,0.00E+00,0.00E+00,0.00E+00,

0.00E+00,0.00E+00,0.00E+00,8.51E-03 !

! END !

! SRCNAM = S2CONTAIL1 !

! X = 125.17384, 23.17569, 3.66, 33.292, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !

! SRCNAM = S2CONTAIL2 !

! X = 125.60973, 23.39549, 3.66, 33.494, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !

! SRCNAM = S2CONTAIL3 !

! X = 126.08181, 23.55943, 3.66, 33.704, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !

! SRCNAM = S2CONTAIL4 !

! X = 126.55388, 23.72337, 3.66, 33.905, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !

! SRCNAM = S2CONTAIL5 !

! X = 127.02594, 23.88732, 3.66, 34.100, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !
M-41

! SRCNAM = S2CONTAIL6 !

! X = 127.498, 24.05127, 3.66, 34.289, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !

! SRCNAM = S2CONTAIL7 !

! X = 127.92559, 24.29415, 3.66, 34.474, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !

! SRCNAM = S2CONTAIL8 !

! X = 128.27261, 24.65372, 3.66, 34.453, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !

! SRCNAM = S2CONTAIL9 !

! X = 128.53706, 25.0671, 3.66, 34.399, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !

! SRCNAM = S2CONTAIL10 !

! X = 128.63575, 25.55697, 3.66, 34.384, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !

! SRCNAM = S2CONTAIL11 !

! X = 128.73444, 26.04682, 3.66, 34.369, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !

! SRCNAM = S2CONTAIL12 !

! X = 128.83312, 26.53667, 3.66, 34.353, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !

! SRCNAM = S2CONTAIL13 !

! X = 128.93181, 27.02652, 3.66, 34.335, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !

! SRCNAM = S2CONTAIL14 !

! X = 129.07723, 27.50284, 3.66, 34.303, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !

! SRCNAM = S2CONTAIL15 !

! X = 129.25515, 27.96976, 3.66, 34.260, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !

! SRCNAM = S2CONTAIL16 !

! X = 129.43307, 28.43668, 3.66, 33.208, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !
M-42

! END !

! SRCNAM = S2CONTAIL17 !

! X = 129.61098, 28.9036, 3.66, 32.115, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !

! SRCNAM = S2CONTAIL18 !

! X = 129.78888, 29.3705, 3.66, 31.054, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !

! SRCNAM = S2CONTAIL19 !

! X = 129.96679, 29.83741, 3.66, 30.022, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !

! SRCNAM = S2CONTAIL20 !

! X = 130.14468, 30.30431, 3.66, 29.022, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !

! SRCNAM = S2CONTAIL21 !

! X = 130.45329, 30.68139, 3.66, 28.271, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !

! SRCNAM = S2CONTAIL22 !

! X = 130.82869, 31.00528, 3.66, 27.690, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !

! SRCNAM = S2CONTAIL23 !

! X = 131.11633, 31.4138, 3.66, 26.956, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !

! SRCNAM = S2CONTAIL24 !

! X = 131.40396, 31.82232, 3.66, 26.266, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !

! SRCNAM = S2CONTAIL25 !

! X = 131.72987, 32.19849, 3.66, 25.308, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !

! SRCNAM = S2CONTAIL26 !

! X = 132.08466, 32.55025, 3.66, 24.036, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !

! SRCNAM = S2CONTAIL27 !
M-43

! X = 132.4931, 32.83098, 3.66, 22.759, 7.302325581, 3.37627907, 2.19E05,9.62E-07,7.80E-03,0,3.96E-07,3.46E-04,9.84E-05,4.89E-04,2.34E-06,2.19E05,7.80E-03,9.37E-04,4.48E-04 !

! END !

! SRCNAM = DRILLM1 !

! X = 125.17384, 23.17569, 3.66, 33.292, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !

! SRCNAM = DRILLM2 !

! X = 125.60973, 23.39549, 3.66, 33.494, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !

! SRCNAM = DRILLM3 !

! X = 126.08181, 23.55943, 3.66, 33.704, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !

! SRCNAM = DRILLM4 !

! X = 126.55388, 23.72337, 3.66, 33.905, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !

! SRCNAM = DRILLM5 !

! X = 127.02594, 23.88732, 3.66, 34.100, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !

! SRCNAM = DRILLM6 !

! X = 127.498, 24.05127, 3.66, 34.289, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !

! SRCNAM = DRILLM7 ! 

! X = 127.92559, 24.29415, 3.66, 34.474, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !

! SRCNAM = DRILLM8 !

! X = 128.27261, 24.65372, 3.66, 34.453, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !

! SRCNAM = DRILLM9 !

! X = 128.53706, 25.0671, 3.66, 34.399, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !

! SRCNAM = DRILLM10 !

! X = 128.63575, 25.55697, 3.66, 34.384, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !
M-44

! SRCNAM = DRILLM11 !

! X = 128.73444, 26.04682, 3.66, 34.369, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !

! SRCNAM = DRILLM12 !

! X = 128.83312, 26.53667, 3.66, 34.353, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !

! SRCNAM = DRILLM13 !

! X = 128.93181, 27.02652, 3.66, 34.335, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !

! SRCNAM = DRILLM14 !

! X = 129.07723, 27.50284, 3.66, 34.303, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !

! SRCNAM = DRILLM15 !

! X = 129.25515, 27.96976, 3.66, 34.260, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !

! SRCNAM = DRILLM16 !

! X = 129.43307, 28.43668, 3.66, 33.208, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !

! SRCNAM = DRILLM17 !

! X = 129.61098, 28.9036, 3.66, 32.115, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !

! SRCNAM = DRILLM18 !

! X = 129.78888, 29.3705, 3.66, 31.054, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !

! SRCNAM = DRILLM19 !

! X = 129.96679, 29.83741, 3.66, 30.022, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !

! SRCNAM = DRILLM20 !

! X = 130.14468, 30.30431, 3.66, 29.022, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !

! SRCNAM = DRILLM21 !

! X = 130.45329, 30.68139, 3.66, 28.271, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !
M-45

! END !

! SRCNAM = DRILLM22 !

! X = 130.82869, 31.00528, 3.66, 27.690, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !

! SRCNAM = DRILLM23 !

! X = 131.11633, 31.4138, 3.66, 26.956, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !

! SRCNAM = DRILLM24 !

! X = 131.40396, 31.82232, 3.66, 26.266, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !

! SRCNAM = DRILLM25 !

! X = 131.72987, 32.19849, 3.66, 25.308, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !

! SRCNAM = DRILLM26 !

! X = 132.08466, 32.55025, 3.66, 24.036, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !

! SRCNAM = DRILLM27 !

! X = 132.4931, 32.83098, 3.66, 22.759, 7.302325581, 3.37627907, 1.81E06,7.46E-08,4.06E-04,0,3.08E-08,2.68E-05,7.64E-06,4.16E-05,1.81E-07,1.81E06,4.06E-04,7.64E-05,3.48E-05 !

! END !

! SRCNAM = FEROAD1 !

! X = 125.17384, 23.17569, 3.66, 33.292, 7.302325581, 3.38, 

0.00E+00,3.42E-05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !

! SRCNAM = FEROAD2 !

! X = 125.60973, 23.39549, 3.66, 33.494, 7.302325581, 3.38, 

0.00E+00,3.42E-05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !

! SRCNAM = FEROAD3 !

! X = 126.08181, 23.55943, 3.66, 33.704, 7.302325581, 3.38, 

0.00E+00,3.42E-05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !

! SRCNAM = FEROAD4 !

! X = 126.55388, 23.72337, 3.66, 33.905, 7.302325581, 3.38, 

0.00E+00,3.42E-05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !

! SRCNAM = FEROAD5 !
M-46

! X = 127.02594, 23.88732, 3.66, 34.100, 7.302325581, 3.38, 

0.00E+00,3.42E-05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !

! SRCNAM = FEROAD6 !

! X = 127.498, 24.05127, 3.66, 34.289, 7.302325581, 3.38, 0.00E+00,3.42E05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !

! SRCNAM = FEROAD7 !

! X = 127.92559, 24.29415, 3.66, 34.474, 7.302325581, 3.38, 

0.00E+00,3.42E-05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !

! SRCNAM = FEROAD8 !

! X = 128.27261, 24.65372, 3.66, 34.453, 7.302325581, 3.38, 

0.00E+00,3.42E-05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !

! SRCNAM = FEROAD9 !

! X = 128.53706, 25.0671, 3.66, 34.399, 7.302325581, 3.38, 0.00E+00,3.42E05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !

! SRCNAM = FEROAD10 !

! X = 128.63575, 25.55697, 3.66, 34.384, 7.302325581, 3.38, 

0.00E+00,3.42E-05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !

! SRCNAM = FEROAD11 !

! X = 128.73444, 26.04682, 3.66, 34.369, 7.302325581, 3.38, 

0.00E+00,3.42E-05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !

! SRCNAM = FEROAD12 !

! X = 128.83312, 26.53667, 3.66, 34.353, 7.302325581, 3.38, 

0.00E+00,3.42E-05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !

! SRCNAM = FEROAD13 !

! X = 128.93181, 27.02652, 3.66, 34.335, 7.302325581, 3.38, 

0.00E+00,3.42E-05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !

! SRCNAM = FEROAD14 !

! X = 129.07723, 27.50284, 3.66, 34.303, 7.302325581, 3.38, 

0.00E+00,3.42E-05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !

! SRCNAM = FEROAD15 !

! X = 129.25515, 27.96976, 3.66, 34.260, 7.302325581, 3.38, 

0.00E+00,3.42E-05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !
M-47

! SRCNAM = FEROAD16 !

! X = 129.43307, 28.43668, 3.66, 33.208, 7.302325581, 3.38, 

0.00E+00,3.42E-05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !

! SRCNAM = FEROAD17 !

! X = 129.61098, 28.9036, 3.66, 32.115, 7.302325581, 3.38, 0.00E+00,3.42E05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !

! SRCNAM = FEROAD18 !

! X = 129.78888, 29.3705, 3.66, 31.054, 7.302325581, 3.38, 0.00E+00,3.42E05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !

! SRCNAM = FEROAD19 !

! X = 129.96679, 29.83741, 3.66, 30.022, 7.302325581, 3.38, 

0.00E+00,3.42E-05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !

! SRCNAM = FEROAD20 !

! X = 130.14468, 30.30431, 3.66, 29.022, 7.302325581, 3.38, 

0.00E+00,3.42E-05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !

! SRCNAM = FEROAD21 !

! X = 130.45329, 30.68139, 3.66, 28.271, 7.302325581, 3.38, 

0.00E+00,3.42E-05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !

! SRCNAM = FEROAD22 !

! X = 130.82869, 31.00528, 3.66, 27.690, 7.302325581, 3.38, 

0.00E+00,3.42E-05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !

! SRCNAM = FEROAD23 !

! X = 131.11633, 31.4138, 3.66, 26.956, 7.302325581, 3.38, 0.00E+00,3.42E05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !

! SRCNAM = FEROAD24 !

! X = 131.40396, 31.82232, 3.66, 26.266, 7.302325581, 3.38, 

0.00E+00,3.42E-05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !

! SRCNAM = FEROAD25 !

! X = 131.72987, 32.19849, 3.66, 25.308, 7.302325581, 3.38, 

0.00E+00,3.42E-05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !

! SRCNAM = FEROAD26 !

! X = 132.08466, 32.55025, 3.66, 24.036, 7.302325581, 3.38, 

0.00E+00,3.42E-05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !
M-48

! END !

! SRCNAM = FEROAD27 !

! X = 132.4931, 32.83098, 3.66, 22.759, 7.302325581, 3.38, 0.00E+00,3.42E05,0.00E+00,0,1.27E-06,0.00E+00,2.90E-04,4.03E-02,4.14E03,0.00E+00,0.00E+00,4.48E-02,1.69E-02 !

! END !

! SRCNAM = FRACM1 !

! X = 125.17384, 23.17569, 3.66, 33.292, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACM2 !

! X = 125.60973, 23.39549, 3.66, 33.494, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACM3 !

! X = 126.08181, 23.55943, 3.66, 33.704, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACM4 !

! X = 126.55388, 23.72337, 3.66, 33.905, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACM5 !

! X = 127.02594, 23.88732, 3.66, 34.100, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACM6 !

! X = 127.498, 24.05127, 3.66, 34.289, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACM7 !

! X = 127.92559, 24.29415, 3.66, 34.474, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACM8 !

! X = 128.27261, 24.65372, 3.66, 34.453, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACM9 !

! X = 128.53706, 25.0671, 3.66, 34.399, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACM10 !
M-49

! X = 128.63575, 25.55697, 3.66, 34.384, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACM11 !

! X = 128.73444, 26.04682, 3.66, 34.369, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACM12 !

! X = 128.83312, 26.53667, 3.66, 34.353, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACM13 !

! X = 128.93181, 27.02652, 3.66, 34.335, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACM14 !

! X = 129.07723, 27.50284, 3.66, 34.303, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACM15 !

! X = 129.25515, 27.96976, 3.66, 34.260, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACM16 !

! X = 129.43307, 28.43668, 3.66, 33.208, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACM17 !

! X = 129.61098, 28.9036, 3.66, 32.115, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACM18 !

! X = 129.78888, 29.3705, 3.66, 31.054, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACM19 !

! X = 129.96679, 29.83741, 3.66, 30.022, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACM20 !

! X = 130.14468, 30.30431, 3.66, 29.022, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !
M-50

! SRCNAM = FRACM21 !

! X = 130.45329, 30.68139, 3.66, 28.271, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACM22 !

! X = 130.82869, 31.00528, 3.66, 27.690, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACM23 !

! X = 131.11633, 31.4138, 3.66, 26.956, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACM24 !

! X = 131.40396, 31.82232, 3.66, 26.266, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACM25 !

! X = 131.72987, 32.19849, 3.66, 25.308, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACM26 ! 

! X = 132.08466, 32.55025, 3.66, 24.036, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACM27 !

! X = 132.4931, 32.83098, 3.66, 22.759, 7.302325581, 3.37627907, 4.90E08,2.96E-07,1.55E-05,0,1.22E-07,1.07E-04,3.03E-05,1.38E-04,7.20E-07,4.90E08,1.55E-05,2.76E-04,1.38E-04 !

! END !

! SRCNAM = FRACFE1 !

! X = 125.17384, 23.17569, 3.66, 33.292, 7.302325581, 3.38, 

0.00E+00,8.39E-06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !

! SRCNAM = FRACFE2 !

! X = 125.60973, 23.39549, 3.66, 33.494, 7.302325581, 3.38, 

0.00E+00,8.39E-06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !

! SRCNAM = FRACFE3 !

! X = 126.08181, 23.55943, 3.66, 33.704, 7.302325581, 3.38, 

0.00E+00,8.39E-06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !

! SRCNAM = FRACFE4 !

! X = 126.55388, 23.72337, 3.66, 33.905, 7.302325581, 3.38, 

0.00E+00,8.39E-06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !
M-51

! END !

! SRCNAM = FRACFE5 !

! X = 127.02594, 23.88732, 3.66, 34.100, 7.302325581, 3.38, 

0.00E+00,8.39E-06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !

! SRCNAM = FRACFE6 !

! X = 127.498, 24.05127, 3.66, 34.289, 7.302325581, 3.38, 0.00E+00,8.39E06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !

! SRCNAM = FRACFE7 !

! X = 127.92559, 24.29415, 3.66, 34.474, 7.302325581, 3.38, 

0.00E+00,8.39E-06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !

! SRCNAM = FRACFE8 !

! X = 128.27261, 24.65372, 3.66, 34.453, 7.302325581, 3.38, 

0.00E+00,8.39E-06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !

! SRCNAM = FRACFE9 !

! X = 128.53706, 25.0671, 3.66, 34.399, 7.302325581, 3.38, 0.00E+00,8.39E06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !

! SRCNAM = FRACFE10 !

! X = 128.63575, 25.55697, 3.66, 34.384, 7.302325581, 3.38, 

0.00E+00,8.39E-06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !

! SRCNAM = FRACFE11 !

! X = 128.73444, 26.04682, 3.66, 34.369, 7.302325581, 3.38, 

0.00E+00,8.39E-06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !

! SRCNAM = FRACFE12 !

! X = 128.83312, 26.53667, 3.66, 34.353, 7.302325581, 3.38, 

0.00E+00,8.39E-06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !

! SRCNAM = FRACFE13 !

! X = 128.93181, 27.02652, 3.66, 34.335, 7.302325581, 3.38, 

0.00E+00,8.39E-06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !

! SRCNAM = FRACFE14 !

! X = 129.07723, 27.50284, 3.66, 34.303, 7.302325581, 3.38, 

0.00E+00,8.39E-06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !

! SRCNAM = FRACFE15 !
M-52

! X = 129.25515, 27.96976, 3.66, 34.260, 7.302325581, 3.38, 

0.00E+00,8.39E-06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !

! SRCNAM = FRACFE16 !

! X = 129.43307, 28.43668, 3.66, 33.208, 7.302325581, 3.38, 

0.00E+00,8.39E-06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !

! SRCNAM = FRACFE17 !

! X = 129.61098, 28.9036, 3.66, 32.115, 7.302325581, 3.38, 0.00E+00,8.39E06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !

! SRCNAM = FRACFE18 !

! X = 129.78888, 29.3705, 3.66, 31.054, 7.302325581, 3.38, 0.00E+00,8.39E06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !

! SRCNAM = FRACFE19 !

! X = 129.96679, 29.83741, 3.66, 30.022, 7.302325581, 3.38, 

0.00E+00,8.39E-06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !

! SRCNAM = FRACFE20 !

! X = 130.14468, 30.30431, 3.66, 29.022, 7.302325581, 3.38, 

0.00E+00,8.39E-06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !

! SRCNAM = FRACFE21 !

! X = 130.45329, 30.68139, 3.66, 28.271, 7.302325581, 3.38, 

0.00E+00,8.39E-06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !

! SRCNAM = FRACFE22 !

! X = 130.82869, 31.00528, 3.66, 27.690, 7.302325581, 3.38, 

0.00E+00,8.39E-06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !

! SRCNAM = FRACFE23 !

! X = 131.11633, 31.4138, 3.66, 26.956, 7.302325581, 3.38, 0.00E+00,8.39E06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !

! SRCNAM = FRACFE24 !

! X = 131.40396, 31.82232, 3.66, 26.266, 7.302325581, 3.38, 

0.00E+00,8.39E-06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !

! SRCNAM = FRACFE25 !

! X = 131.72987, 32.19849, 3.66, 25.308, 7.302325581, 3.38, 

0.00E+00,8.39E-06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !
M-53

! SRCNAM = FRACFE26 !

! X = 132.08466, 32.55025, 3.66, 24.036, 7.302325581, 3.38, 

0.00E+00,8.39E-06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !

! SRCNAM = FRACFE27 !

! X = 132.4931, 32.83098, 3.66, 22.759, 7.302325581, 3.38, 0.00E+00,8.39E06,0.00E+00,0,3.11E-07,0.00E+00,7.11E-05,6.22E-03,1.02E03,0.00E+00,0.00E+00,7.32E-03,1.10E-03 !

! END !

! SRCNAM = OPSTAIL1 !

! X = 125.17384, 23.17569, 3.66, 33.292, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = OPSTAIL2 !

! X = 125.60973, 23.39549, 3.66, 33.494, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = OPSTAIL3 !

! X = 126.08181, 23.55943, 3.66, 33.704, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = OPSTAIL4 !

! X = 126.55388, 23.72337, 3.66, 33.905, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = OPSTAIL5 !

! X = 127.02594, 23.88732, 3.66, 34.100, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = OPSTAIL6 !

! X = 127.498, 24.05127, 3.66, 34.289, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = OPSTAIL7 !

! X = 127.92559, 24.29415, 3.66, 34.474, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = OPSTAIL8 !

! X = 128.27261, 24.65372, 3.66, 34.453, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = OPSTAIL9 !

! X = 128.53706, 25.0671, 3.66, 34.399, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !
M-54

! END !

! SRCNAM = OPSTAIL10 !

! X = 128.63575, 25.55697, 3.66, 34.384, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = OPSTAIL11 !

! X = 128.73444, 26.04682, 3.66, 34.369, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = OPSTAIL12 !

! X = 128.83312, 26.53667, 3.66, 34.353, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = OPSTAIL13 !

! X = 128.93181, 27.02652, 3.66, 34.335, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = OPSTAIL14 !

! X = 129.07723, 27.50284, 3.66, 34.303, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = OPSTAIL15 !

! X = 129.25515, 27.96976, 3.66, 34.260, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = OPSTAIL16 !

! X = 129.43307, 28.43668, 3.66, 33.208, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = OPSTAIL17 !

! X = 129.61098, 28.9036, 3.66, 32.115, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = OPSTAIL18 !

! X = 129.78888, 29.3705, 3.66, 31.054, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = OPSTAIL19 !

! X = 129.96679, 29.83741, 3.66, 30.022, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = OPSTAIL20 !
M-55

! X = 130.14468, 30.30431, 3.66, 29.022, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = OPSTAIL21 !

! X = 130.45329, 30.68139, 3.66, 28.271, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = OPSTAIL22 !

! X = 130.82869, 31.00528, 3.66, 27.690, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = OPSTAIL23 !

! X = 131.11633, 31.4138, 3.66, 26.956, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = OPSTAIL24 !

! X = 131.40396, 31.82232, 3.66, 26.266, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = OPSTAIL25 !

! X = 131.72987, 32.19849, 3.66, 25.308, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = OPSTAIL26 !

! X = 132.08466, 32.55025, 3.66, 24.036, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = OPSTAIL27 !

! X = 132.4931, 32.83098, 3.66, 22.759, 7.302325581, 3.37627907, 9.30E08,3.24E-09,2.86E-05,0,1.34E-09,1.17E-06,3.32E-07,1.68E-06,7.88E-09,9.30E08,2.86E-05,3.19E-06,1.51E-06 !

! END !

! SRCNAM = GRVLNRRD1 !

! X = 125.17384, 23.17569, 3.66, 33.292, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = GRVLNRRD2 !

! X = 125.60973, 23.39549, 3.66, 33.494, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = GRVLNRRD3 !

! X = 126.08181, 23.55943, 3.66, 33.704, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = GRVLNRRD4 !

! X = 126.55388, 23.72337, 3.66, 33.905, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !
M-56

! END !

! SRCNAM = GRVLNRRD5 !

! X = 127.02594, 23.88732, 3.66, 34.100, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = GRVLNRRD6 !

! X = 127.498, 24.05127, 3.66, 34.289, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = GRVLNRRD7 !

! X = 127.92559, 24.29415, 3.66, 34.474, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = GRVLNRRD8 !

! X = 128.27261, 24.65372, 3.66, 34.453, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = GRVLNRRD9 !

! X = 128.53706, 25.0671, 3.66, 34.399, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = GRVLNRRD10 !

! X = 128.63575, 25.55697, 3.66, 34.384, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = GRVLNRRD11 !

! X = 128.73444, 26.04682, 3.66, 34.369, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = GRVLNRRD12 !

! X = 128.83312, 26.53667, 3.66, 34.353, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = GRVLNRRD13 !

! X = 128.93181, 27.02652, 3.66, 34.335, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = GRVLNRRD14 !

! X = 129.07723, 27.50284, 3.66, 34.303, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = GRVLNRRD15 !

! X = 129.25515, 27.96976, 3.66, 34.260, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = GRVLNRRD16 !

! X = 129.43307, 28.43668, 3.66, 33.208, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = GRVLNRRD17 !

! X = 129.61098, 28.9036, 3.66, 32.115, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = GRVLNRRD18 !
M-57

! X = 129.78888, 29.3705, 3.66, 31.054, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = GRVLNRRD19 !

! X = 129.96679, 29.83741, 3.66, 30.022, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = GRVLNRRD20 !

! X = 130.14468, 30.30431, 3.66, 29.022, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = GRVLNRRD21 !

! X = 130.45329, 30.68139, 3.66, 28.271, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = GRVLNRRD22 !

! X = 130.82869, 31.00528, 3.66, 27.690, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = GRVLNRRD23 !

! X = 131.11633, 31.4138, 3.66, 26.956, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = GRVLNRRD24 !

! X = 131.40396, 31.82232, 3.66, 26.266, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = GRVLNRRD25 !

! X = 131.72987, 32.19849, 3.66, 25.308, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = GRVLNRRD26 !

! X = 132.08466, 32.55025, 3.66, 24.036, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = GRVLNRRD27 !

! X = 132.4931, 32.83098, 3.66, 22.759, 7.3, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.001057227 !

! END !

! SRCNAM = S1CONTAIL1 !

! X = 125.17384, 23.17569, 3.66, 33.292, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

! SRCNAM = S1CONTAIL2 !

! X = 125.60973, 23.39549, 3.66, 33.494, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

! SRCNAM = S1CONTAIL3 !

! X = 126.08181, 23.55943, 3.66, 33.704, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

! SRCNAM = S1CONTAIL4 !

! X = 126.55388, 23.72337, 3.66, 33.905, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !
M-58

! END !

! SRCNAM = S1CONTAIL5 !

! X = 127.02594, 23.88732, 3.66, 34.100, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

! SRCNAM = S1CONTAIL6 !

! X = 127.498, 24.05127, 3.66, 34.289, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

! SRCNAM = S1CONTAIL7 !

! X = 127.92559, 24.29415, 3.66, 34.474, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

! SRCNAM = S1CONTAIL8 !

! X = 128.27261, 24.65372, 3.66, 34.453, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

! SRCNAM = S1CONTAIL9 ! 

! X = 128.53706, 25.0671, 3.66, 34.399, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

! SRCNAM = S1CONTAIL10 !

! X = 128.63575, 25.55697, 3.66, 34.384, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

! SRCNAM = S1CONTAIL11 !

! X = 128.73444, 26.04682, 3.66, 34.369, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

! SRCNAM = S1CONTAIL12 !

! X = 128.83312, 26.53667, 3.66, 34.353, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

! SRCNAM = S1CONTAIL13 !

! X = 128.93181, 27.02652, 3.66, 34.335, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

! SRCNAM = S1CONTAIL14 !

! X = 129.07723, 27.50284, 3.66, 34.303, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

! SRCNAM = S1CONTAIL15 !

! X = 129.25515, 27.96976, 3.66, 34.260, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

! SRCNAM = S1CONTAIL16 !

! X = 129.43307, 28.43668, 3.66, 33.208, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

! SRCNAM = S1CONTAIL17 !

! X = 129.61098, 28.9036, 3.66, 32.115, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

! SRCNAM = S1CONTAIL18 !
M-59

! X = 129.78888, 29.3705, 3.66, 31.054, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

! SRCNAM = S1CONTAIL19 !

! X = 129.96679, 29.83741, 3.66, 30.022, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

! SRCNAM = S1CONTAIL20 !

! X = 130.14468, 30.30431, 3.66, 29.022, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

! SRCNAM = S1CONTAIL21 !

! X = 130.45329, 30.68139, 3.66, 28.271, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

! SRCNAM = S1CONTAIL22 !

! X = 130.82869, 31.00528, 3.66, 27.690, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

! SRCNAM = S1CONTAIL23 !

! X = 131.11633, 31.4138, 3.66, 26.956, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

! SRCNAM = S1CONTAIL24 !

! X = 131.40396, 31.82232, 3.66, 26.266, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

! SRCNAM = S1CONTAIL25 !

! X = 131.72987, 32.19849, 3.66, 25.308, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

! SRCNAM = S1CONTAIL26 !

! X = 132.08466, 32.55025, 3.66, 24.036, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

! SRCNAM = S1CONTAIL27 !

! X = 132.4931, 32.83098, 3.66, 22.759, 7.302325581, 3.37627907, 

0,0,0,0,0,0,0,0,0,0,0,0,0.000626798 !

! END !

--------

 a 

 Data for each source are treated as a separate input subgroup

 and therefore must end with an input group terminator.

 b 

 An emission rate must be entered for every pollutant modeled.

 Enter emission rate of zero for secondary pollutants that are

 modeled, but not emitted. Units are specified by IVLU 

 (e.g. 1 for g/s).

---------------

Subgroup (16c)

---------------
M-60

 a 

 VOLUME SOURCE: VARIABLE EMISSIONS DATA

 ----------------------------------------

 Use this subgroup to describe temporal variations in the emission

 rates given in 16b. Factors entered multiply the rates in 16b.

 Skip sources here that have constant emissions. For more elaborate

 variation in source parameters, use VOLEMARB.DAT and NVL2 > 0.

 IVARY determines the type of variation, and is source-specific:

 (IVARY) Default: 0

 0 = Constant

 1 = Diurnal cycle (24 scaling factors: hours 1-24)

 2 = Monthly cycle (12 scaling factors: months 1-12)

 3 = Hour & Season (4 groups of 24 hourly scaling factors,

 where first group is DEC-JAN-FEB)

 4 = Speed & Stab. (6 groups of 6 scaling factors, where

 first group is Stability Class A,

and the speed classes have upper

bounds (m/s) defined in Group 12

 5 = Temperature (12 scaling factors, where temperature

 classes have upper bounds (C) of:

 0, 5, 10, 15, 20, 25, 30, 35, 40,

45, 50, 50+)

--------

 a 

 Data for each species are treated as a separate input subgroup

 and therefore must end with an input group terminator.

--------------------------------------------------------------------------

-----

INPUT GROUPS: 17a & 17b -- Non-gridded (discrete) receptor information

-----------------------

---------------

Subgroup (17a)

---------------

 Number of non-gridded receptors (NREC) No default ! NREC = 269 !

!END!

---------------

Subgroup (17b)

---------------

 a 

 NON-GRIDDED (DISCRETE) RECEPTOR DATA

 ------------------------------------
M-61

 X UTM Y UTM Ground Height b

Receptor Coordinate Coordinate Elevation Above Ground

 No. (km) (km) (m) (m)

-------- ---------- ---------- --------- ------------

00001 ! X = 289.802, -137.751, 1039.1, 0 ! !END! anwr-0001

00002 ! X = 294.117, -127.757, 991.9, 0 ! !END! anwr-0002

00003 ! X = 296.471, -117.762, 1076.1, 0 ! !END! anwr-0003

00004 ! X = 310.194, -107.773, 1042.8, 0 ! !END! anwr-0004

00005 ! X = 315.251, -97.778, 747.2, 0 ! !END! anwr-0005

00006 ! X = 322.899, -87.785, 1140.7, 0 ! !END! anwr-0006

00007 ! X = 377.995, -67.826, 1328.8, 0 ! !END! anwr-0007

00008 ! X = 382.380, -57.830, 1298.0, 0 ! !END! anwr-0008

00009 ! X = 383.033, -47.834, 1642.3, 0 ! !END! anwr-0009

00010 ! X = 381.515, -37.835, 1079.6, 0 ! !END! anwr-0010

00011 ! X = 377.114, -27.834, 959.8, 0 ! !END! anwr-0011

00012 ! X = 368.689, -17.830, 858.4, 0 ! !END! anwr-0012

00013 ! X = 368.630, -7.831, 572.4, 0 ! !END! anwr-0013

00014 ! X = 275.946, -147.740, 1203.0, 0 ! !END! anwr-0014

00015 ! X = 277.053, -137.745, 783.4, 0 ! !END! anwr-0015

00016 ! X = 283.689, -127.752, 877.2, 0 ! !END! anwr-0016

00017 ! X = 284.617, -117.756, 884.0, 0 ! !END! anwr-0017

00018 ! X = 294.480, -107.765, 955.3, 0 ! !END! anwr-0018

00019 ! X = 304.570, -97.772, 956.1, 0 ! !END! anwr-0019

00020 ! X = 309.651, -87.778, 899.4, 0 ! !END! anwr-0020

00021 ! X = 317.624, -77.786, 764.8, 0 ! !END! anwr-0021

00022 ! X = 371.920, -57.824, 1238.2, 0 ! !END! anwr-0022

00023 ! X = 372.907, -47.827, 1406.8, 0 ! !END! anwr-0023

00024 ! X = 371.043, -37.827, 889.6, 0 ! !END! anwr-0024

00025 ! X = 363.719, -27.825, 892.9, 0 ! !END! anwr-0025

00026 ! X = 358.458, -17.823, 772.9, 0 ! !END! anwr-0026

00027 ! X = 358.358, -7.824, 447.3, 0 ! !END! anwr-0027

00028 ! X = 355.055, 2.177, 236.5, 0 ! !END! anwr-0028

00029 ! X = 263.629, -157.731, 1492.5, 0 ! !END! anwr-0029

00030 ! X = 265.853, -147.736, 1135.1, 0 ! !END! anwr-0030

00031 ! X = 264.819, -137.739, 820.5, 0 ! !END! anwr-0031

00032 ! X = 272.229, -127.746, 922.9, 0 ! !END! anwr-0032

00033 ! X = 274.516, -117.751, 679.9, 0 ! !END! anwr-0033

00034 ! X = 273.435, -107.754, 649.5, 0 ! !END! anwr-0034

00035 ! X = 291.918, -97.766, 832.1, 0 ! !END! anwr-0035

00036 ! X = 296.625, -87.771, 593.2, 0 ! !END! anwr-0036

00037 ! X = 303.394, -77.778, 851.4, 0 ! !END! anwr-0037

00038 ! X = 309.919, -67.784, 781.4, 0 ! !END! anwr-0038

00039 ! X = 360.349, -57.816, 746.5, 0 ! !END! anwr-0039

00040 ! X = 362.620, -47.820, 1054.0, 0 ! !END! anwr-0040

00041 ! X = 359.486, -37.821, 636.2, 0 ! !END! anwr-0041

00042 ! X = 349.308, -27.816, 749.2, 0 ! !END! anwr-0042

00043 ! X = 347.936, -17.816, 541.9, 0 ! !END! anwr-0043

00044 ! X = 347.930, -7.818, 348.5, 0 ! !END! anwr-0044

00045 ! X = 342.858, 2.184, 250.6, 0 ! !END! anwr-0045

00046 ! X = 339.156, 12.185, 131.1, 0 ! !END! anwr-0046

00047 ! X = 238.438, -167.715, 1462.9, 0 ! !END! anwr-0047

00048 ! X = 255.761, -147.731, 1178.4, 0 ! !END! anwr-0048

00049 ! X = 254.727, -137.735, 864.5, 0 ! !END! anwr-0049

00050 ! X = 259.013, -127.740, 578.4, 0 ! !END! anwr-0050
M-62

00051 ! X = 264.417, -117.745, 610.5, 0 ! !END! anwr-0051

00052 ! X = 263.341, -107.749, 528.0, 0 ! !END! anwr-0052

00053 ! X = 262.277, -97.751, 491.0, 0 ! !END! anwr-0053

00054 ! X = 286.107, -87.766, 443.2, 0 ! !END! anwr-0054

00055 ! X = 291.381, -77.772, 767.6, 0 ! !END! anwr-0055

00056 ! X = 299.822, -67.778, 768.0, 0 ! !END! anwr-0056

00057 ! X = 306.567, -57.784, 665.4, 0 ! !END! anwr-0057

00058 ! X = 351.042, -47.813, 571.6, 0 ! !END! anwr-0058

00059 ! X = 343.064, -37.810, 343.3, 0 ! !END! anwr-0059

00060 ! X = 339.164, -27.810, 400.0, 0 ! !END! anwr-0060

00061 ! X = 337.386, -17.810, 256.4, 0 ! !END! anwr-0061

00062 ! X = 337.620, -7.812, 253.1, 0 ! !END! anwr-0062

00063 ! X = 328.260, 2.193, 172.8, 0 ! !END! anwr-0063

00064 ! X = 328.844, 12.191, 117.5, 0 ! !END! anwr-0064

00065 ! X = 332.217, 22.188, 62.3, 0 ! !END! anwr-0065

00066 ! X = 316.267, -187.744, 1151.1, 0 ! !END! anwr-0066

00067 ! X = 313.493, -177.747, 1252.8, 0 ! !END! anwr-0067

00068 ! X = 310.454, -167.751, 1052.1, 0 ! !END! anwr-0068

00069 ! X = 302.316, -157.750, 1442.6, 0 ! !END! anwr-0069

00070 ! X = 286.039, -147.745, 1104.7, 0 ! !END! anwr-0070

00071 ! X = 289.892, -137.612, 1037.2, 0 ! !END! anwr-0071

00072 ! X = 309.900, -108.152, 1047.1, 0 ! !END! anwr-0072

00073 ! X = 309.868, -166.625, 1116.8, 0 ! !END! anwr-0073

00074 ! X = 329.908, -85.087, 1125.6, 0 ! !END! anwr-0074

00075 ! X = 339.906, -83.704, 1518.9, 0 ! !END! anwr-0075

00076 ! X = 349.904, -82.301, 1139.5, 0 ! !END! anwr-0076

00077 ! X = 359.902, -80.673, 1412.6, 0 ! !END! anwr-0077

00078 ! X = 369.902, -76.002, 1058.3, 0 ! !END! anwr-0078

00079 ! X = 307.165, -197.735, 1014.7, 0 ! !END! anwr-0079

00080 ! X = 305.718, -187.739, 1145.9, 0 ! !END! anwr-0080

00081 ! X = 303.339, -177.743, 1398.8, 0 ! !END! anwr-0081

00082 ! X = 298.362, -167.744, 1497.8, 0 ! !END! anwr-0082

00083 ! X = 275.050, -157.736, 1565.0, 0 ! !END! anwr-0083

00084 ! X = 357.638, 12.173, 170.6, 0 ! !END! anwr-0084

00085 ! X = 349.840, 12.179, 166.3, 0 ! !END! anwr-0085

00086 ! X = 289.879, -161.964, 1436.1, 0 ! !END! anwr-0086

00087 ! X = 319.915, -76.272, 726.5, 0 ! !END! anwr-0087

00088 ! X = 319.841, -206.622, 1087.2, 0 ! !END! anwr-0088

00089 ! X = 329.914, -74.967, 968.7, 0 ! !END! anwr-0089

00090 ! X = 339.912, -73.571, 1280.0, 0 ! !END! anwr-0090

00091 ! X = 349.963, 12.422, 163.2, 0 ! !END! anwr-0091

00092 ! X = 349.910, -72.140, 1172.0, 0 ! !END! anwr-0092

00093 ! X = 359.960, 10.707, 191.8, 0 ! !END! anwr-0093

00094 ! X = 359.909, -70.129, 937.7, 0 ! !END! anwr-0094

00095 ! X = 369.958, 8.238, 231.3, 0 ! !END! anwr-0095

00096 ! X = 319.153, -217.731, 1067.3, 0 ! !END! anwr-0096

00097 ! X = 297.049, -197.730, 1325.9, 0 ! !END! anwr-0097

00098 ! X = 295.392, -187.733, 1076.2, 0 ! !END! anwr-0098

00099 ! X = 292.956, -177.737, 1194.2, 0 ! !END! anwr-0099

00100 ! X = 255.830, -177.718, 1072.1, 0 ! !END! anwr-0100

00101 ! X = 247.706, -177.715, 1435.1, 0 ! !END! anwr-0101

00102 ! X = 248.518, -167.720, 1178.1, 0 ! !END! anwr-0102

00103 ! X = 361.603, 22.170, 64.8, 0 ! !END! anwr-0103

00104 ! X = 343.183, 22.182, 48.5, 0 ! !END! anwr-0104
M-63

00105 ! X = 249.896, -161.786, 1271.9, 0 ! !END! anwr-0105

00106 ! X = 259.892, -160.380, 1227.4, 0 ! !END! anwr-0106

00107 ! X = 269.884, -168.722, 1582.4, 0 ! !END! anwr-0107

00108 ! X = 279.914, -100.278, 661.6, 0 ! !END! anwr-0108

00109 ! X = 279.879, -170.482, 1754.5, 0 ! !END! anwr-0109

00110 ! X = 299.850, -208.159, 1075.1, 0 ! !END! anwr-0110

00111 ! X = 309.922, -67.865, 782.0, 0 ! !END! anwr-0111

00112 ! X = 319.921, -66.148, 1034.1, 0 ! !END! anwr-0112

00113 ! X = 319.835, -218.372, 1063.4, 0 ! !END! anwr-0113

00114 ! X = 329.919, -64.828, 903.1, 0 ! !END! anwr-0114

00115 ! X = 339.918, -63.450, 1283.3, 0 ! !END! anwr-0115

00116 ! X = 349.972, 26.638, 22.2, 0 ! !END! anwr-0116

00117 ! X = 349.916, -61.988, 1204.3, 0 ! !END! anwr-0117

00118 ! X = 359.916, -58.250, 708.2, 0 ! !END! anwr-0118

00119 ! X = 369.964, 18.275, 134.1, 0 ! !END! anwr-0119

00120 ! X = 286.119, -207.718, 1203.4, 0 ! !END! anwr-0120

00121 ! X = 285.656, -197.724, 1450.8, 0 ! !END! anwr-0121

00122 ! X = 281.299, -187.726, 1529.0, 0 ! !END! anwr-0122

00123 ! X = 261.131, -187.717, 1381.3, 0 ! !END! anwr-0123

00124 ! X = 237.626, -177.710, 1583.6, 0 ! !END! anwr-0124

00125 ! X = 337.125, 32.185, 19.6, 0 ! !END! anwr-0125

00126 ! X = 229.906, -157.662, 1015.7, 0 ! !END! anwr-0126

00127 ! X = 229.905, -160.094, 967.2, 0 ! !END! anwr-0127

00128 ! X = 239.904, -152.694, 868.1, 0 ! !END! anwr-0128

00129 ! X = 239.887, -191.765, 1590.3, 0 ! !END! anwr-0129

00130 ! X = 249.900, -151.685, 959.9, 0 ! !END! anwr-0130

00131 ! X = 249.882, -192.757, 1590.9, 0 ! !END! anwr-0131

00132 ! X = 259.880, -187.926, 1396.6, 0 ! !END! anwr-0132

00133 ! X = 269.921, -91.330, 481.7, 0 ! !END! anwr-0133

00134 ! X = 269.879, -179.654, 1693.4, 0 ! !END! anwr-0134

00135 ! X = 279.919, -90.216, 384.0, 0 ! !END! anwr-0135

00136 ! X = 279.874, -181.391, 1599.2, 0 ! !END! anwr-0136

00137 ! X = 299.845, -218.353, 893.7, 0 ! !END! anwr-0137

00138 ! X = 309.931, -52.455, 611.4, 0 ! !END! anwr-0138

00139 ! X = 319.927, -56.023, 823.2, 0 ! !END! anwr-0139

00140 ! X = 329.925, -54.710, 877.4, 0 ! !END! anwr-0140

00141 ! X = 339.981, 41.158, 2.4, 0 ! !END! anwr-0141

00142 ! X = 339.924, -53.291, 795.5, 0 ! !END! anwr-0142

00143 ! X = 349.981, 41.002, 1.4, 0 ! !END! anwr-0143

00144 ! X = 349.922, -51.865, 586.9, 0 ! !END! anwr-0144

00145 ! X = 359.977, 36.429, 0.2, 0 ! !END! anwr-0145

00146 ! X = 369.973, 31.666, 3.4, 0 ! !END! anwr-0146

00147 ! X = 19.990, -206.149, 1337.5, 0 ! !END! gaar-0001

00148 ! X = 29.986, -201.575, 1115.3, 0 ! !END! gaar-0002

00149 ! X = 39.981, -199.984, 959.9, 0 ! !END! gaar-0003

00150 ! X = -39.978, -233.576, 919.0, 0 ! !END! gaar-0004

00151 ! X = -29.983, -235.721, 1107.9, 0 ! !END! gaar-0005

00152 ! X = -19.989, -234.467, 1152.9, 0 ! !END! gaar-0006

00153 ! X = -9.995, -196.684, 1212.5, 0 ! !END! gaar-0007

00154 ! X = 0.000, -196.703, 1523.4, 0 ! !END! gaar-0008

00155 ! X = 9.995, -196.683, 1604.4, 0 ! !END! gaar-0009

00156 ! X = 19.990, -195.541, 1488.6, 0 ! !END! gaar-0010

00157 ! X = 29.986, -191.278, 1393.6, 0 ! !END! gaar-0011

00158 ! X = 39.981, -189.955, 664.3, 0 ! !END! gaar-0012
M-64

00159 ! X = 49.977, -189.778, 1440.1, 0 ! !END! gaar-0013

00160 ! X = 59.972, -188.698, 1536.5, 0 ! !END! gaar-0014

00161 ! X = -49.974, -223.489, 866.4, 0 ! !END! gaar-0015

00162 ! X = -39.979, -220.660, 936.8, 0 ! !END! gaar-0016

00163 ! X = -29.984, -225.135, 962.3, 0 ! !END! gaar-0017

00164 ! X = -19.991, -181.840, 799.2, 0 ! !END! gaar-0018

00165 ! X = -9.996, -186.657, 990.3, 0 ! !END! gaar-0019

00166 ! X = 0.000, -186.676, 1072.3, 0 ! !END! gaar-0020

00167 ! X = 9.996, -186.656, 1245.9, 0 ! !END! gaar-0021

00168 ! X = 19.991, -181.838, 1131.4, 0 ! !END! gaar-0022

00169 ! X = 29.987, -180.065, 821.2, 0 ! !END! gaar-0023

00170 ! X = 39.982, -179.927, 592.1, 0 ! !END! gaar-0024

00171 ! X = 49.978, -179.749, 973.3, 0 ! !END! gaar-0025

00172 ! X = 59.974, -173.093, 774.8, 0 ! !END! gaar-0026

00173 ! X = 69.970, -168.008, 680.2, 0 ! !END! gaar-0027

00174 ! X = 79.966, -167.710, 795.4, 0 ! !END! gaar-0028

00175 ! X = 179.919, -181.907, 1297.2, 0 ! !END! gaar-0029

00176 ! X = 4.117, -227.636, 973.3, 0 ! !END! gaar-0030

00177 ! X = 4.261, -217.641, 1064.3, 0 ! !END! gaar-0031

00178 ! X = 9.995, -216.738, 1072.1, 0 ! !END! gaar-0032

00179 ! X = 19.990, -216.353, 748.3, 0 ! !END! gaar-0033

00180 ! X = 29.985, -212.932, 780.8, 0 ! !END! gaar-0034

00181 ! X = 39.980, -210.014, 835.4, 0 ! !END! gaar-0035

00182 ! X = 49.975, -209.838, 1110.4, 0 ! !END! gaar-0036

00183 ! X = 59.970, -209.395, 1151.6, 0 ! !END! gaar-0037

00184 ! X = 69.965, -206.117, 1250.0, 0 ! !END! gaar-0038

00185 ! X = 79.960, -209.737, 1079.5, 0 ! !END! gaar-0039

00186 ! X = 89.955, -211.878, 1236.0, 0 ! !END! gaar-0040

00187 ! X = 99.949, -215.463, 1059.4, 0 ! !END! gaar-0041

00188 ! X = 109.943, -218.715, 970.2, 0 ! !END! gaar-0042

00189 ! X = 119.938, -218.795, 783.5, 0 ! !END! gaar-0043

00190 ! X = 129.932, -219.510, 1270.5, 0 ! !END! gaar-0044

00191 ! X = 139.927, -219.397, 1188.9, 0 ! !END! gaar-0045

00192 ! X = 149.922, -218.834, 1246.0, 0 ! !END! gaar-0046

00193 ! X = 159.917, -218.232, 1387.5, 0 ! !END! gaar-0047

00194 ! X = 169.913, -216.946, 1182.3, 0 ! !END! gaar-0048

00195 ! X = 179.909, -212.073, 1502.5, 0 ! !END! gaar-0049

00196 ! X = -5.939, -227.635, 1031.6, 0 ! !END! gaar-0050

00197 ! X = -5.777, -217.641, 1171.0, 0 ! !END! gaar-0051

00198 ! X = 192.384, -207.679, 1384.0, 0 ! !END! gaar-0052

00199 ! X = -5.649, -207.646, 1450.8, 0 ! !END! gaar-0053

00200 ! X = 0.000, -206.730, 1318.9, 0 ! !END! gaar-0054

00201 ! X = 9.995, -206.712, 1310.5, 0 ! !END! gaar-0055

00202 ! X = 49.976, -199.809, 1537.8, 0 ! !END! gaar-0056

00203 ! X = 59.971, -199.219, 1430.2, 0 ! !END! gaar-0057

00204 ! X = 69.967, -193.724, 1181.4, 0 ! !END! gaar-0058

00205 ! X = 79.961, -198.459, 1147.4, 0 ! !END! gaar-0059

00206 ! X = 89.956, -201.832, 1113.0, 0 ! !END! gaar-0060

00207 ! X = 99.951, -203.092, 1384.5, 0 ! !END! gaar-0061

00208 ! X = 109.945, -208.542, 1256.3, 0 ! !END! gaar-0062

00209 ! X = 119.940, -208.755, 936.5, 0 ! !END! gaar-0063

00210 ! X = 129.935, -209.393, 927.7, 0 ! !END! gaar-0064

00211 ! X = 139.930, -209.353, 1184.2, 0 ! !END! gaar-0065

00212 ! X = 149.925, -208.788, 1093.9, 0 ! !END! gaar-0066
M-65

00213 ! X = 159.920, -208.183, 1256.2, 0 ! !END! gaar-0067

00214 ! X = 169.916, -206.342, 1250.1, 0 ! !END! gaar-0068

00215 ! X = 179.912, -202.018, 1586.2, 0 ! !END! gaar-0069

00216 ! X = 189.907, -201.294, 1370.6, 0 ! !END! gaar-0070

00217 ! X = -16.007, -227.636, 1022.2, 0 ! !END! gaar-0071

00218 ! X = -15.815, -217.641, 1147.5, 0 ! !END! gaar-0072

00219 ! X = 202.945, -207.683, 1536.5, 0 ! !END! gaar-0073

00220 ! X = -15.687, -207.646, 1177.2, 0 ! !END! gaar-0074

00221 ! X = 202.698, -197.688, 1403.9, 0 ! !END! gaar-0075

00222 ! X = 109.218, -197.662, 1332.1, 0 ! !END! gaar-0076

00223 ! X = -15.560, -197.652, 1231.8, 0 ! !END! gaar-0077

00224 ! X = 207.150, -187.693, 1160.5, 0 ! !END! gaar-0078

00225 ! X = -49.973, -233.657, 828.0, 0 ! !END! gaar-0079

00226 ! X = 69.969, -178.040, 1022.6, 0 ! !END! gaar-0080

00227 ! X = 79.963, -186.130, 910.7, 0 ! !END! gaar-0081

00228 ! X = 89.958, -191.773, 1380.7, 0 ! !END! gaar-0082

00229 ! X = 99.953, -191.525, 1140.1, 0 ! !END! gaar-0083

00230 ! X = 109.947, -198.040, 1315.0, 0 ! !END! gaar-0084

00231 ! X = 119.942, -198.714, 1370.2, 0 ! !END! gaar-0085

00232 ! X = 129.937, -199.063, 1196.1, 0 ! !END! gaar-0086

00233 ! X = 139.932, -199.308, 734.7, 0 ! !END! gaar-0087

00234 ! X = 149.928, -198.740, 1182.6, 0 ! !END! gaar-0088

00235 ! X = 159.923, -198.134, 1469.7, 0 ! !END! gaar-0089

00236 ! X = 169.920, -193.979, 1492.8, 0 ! !END! gaar-0090

00237 ! X = 179.915, -191.962, 1491.0, 0 ! !END! gaar-0091

00238 ! X = 189.911, -191.236, 1450.4, 0 ! !END! gaar-0092

00239 ! X = 199.908, -185.627, 1439.5, 0 ! !END! gaar-0093

00240 ! X = 209.906, -178.674, 1193.4, 0 ! !END! gaar-0094

00241 ! X = 209.906, -180.460, 1169.8, 0 ! !END! gaar-0095

00242 ! X = -25.853, -217.641, 937.0, 0 ! !END! gaar-0096

00243 ! X = -25.724, -207.647, 1021.2, 0 ! !END! gaar-0097

00244 ! X = -25.597, -197.651, 1148.8, 0 ! !END! gaar-0098

00245 ! X = -25.468, -187.656, 972.5, 0 ! !END! gaar-0099

00246 ! X = 55.656, -177.663, 904.5, 0 ! !END! gaar-0100

00247 ! X = -59.968, -224.883, 894.3, 0 ! !END! gaar-0101

00248 ! X = 89.960, -177.032, 856.3, 0 ! !END! gaar-0102

00249 ! X = 99.955, -181.487, 973.3, 0 ! !END! gaar-0103

00250 ! X = 109.951, -176.243, 753.8, 0 ! !END! gaar-0104

00251 ! X = 119.944, -188.674, 1107.6, 0 ! !END! gaar-0105

00252 ! X = 129.940, -188.183, 985.4, 0 ! !END! gaar-0106

00253 ! X = 139.935, -189.263, 855.9, 0 ! !END! gaar-0107

00254 ! X = 149.930, -188.694, 1012.9, 0 ! !END! gaar-0108

00255 ! X = 159.926, -188.084, 1253.6, 0 ! !END! gaar-0109

00256 ! X = 169.924, -177.759, 1161.5, 0 ! !END! gaar-0110

00257 ! X = 189.916, -176.336, 1501.1, 0 ! !END! gaar-0111

00258 ! X = 189.915, -178.640, 1591.6, 0 ! !END! gaar-0112

00259 ! X = 189.914, -181.177, 1642.1, 0 ! !END! gaar-0113

00260 ! X = 199.915, -165.879, 1059.7, 0 ! !END! gaar-0114

00261 ! X = 199.914, -169.667, 1170.0, 0 ! !END! gaar-0115

00262 ! X = 199.912, -175.566, 1341.7, 0 ! !END! gaar-0116

00263 ! X = 209.911, -165.065, 809.0, 0 ! !END! gaar-0117

00264 ! X = 219.908, -164.211, 1159.3, 0 ! !END! gaar-0118

00265 ! X = 219.907, -166.298, 1202.6, 0 ! !END! gaar-0119

00266 ! X = 219.899, -185.141, 1556.5, 0 ! !END! gaar-0120
M-66

00267 ! X = 79.969, -148.394, 468.9, 0 ! !END! gaar-0121

00268 ! X = 95.662, -160.383, 650.4, 0 ! !END! gaar-0122

00269 ! X = 150.448, 29.665, 10.0, 0 ! !END! nuiq-0001

-------------

 a 

 Data for each receptor are treated as a separate input subgroup

 and therefore must end with an input group terminator.

 b 

 Receptor height above ground is optional. If no value is entered,

 the receptor is placed on the ground.
M-67

2. Sample CALPOST Input File

Class I Analysis 2009 Visibility Analysis

anwr Recs

Visibility Method 8 Mode 5 (FLAG 2008) using calpost v6.221

---------------- Run title (3 lines) -------------------------------------

-----

 CALPOST MODEL CONTROL FILE

--------------------------

--------------------------------------------------------------------------

-----

INPUT GROUP: 0 -- Input and Output File Names

--------------

Input Files

-----------

File Default File Name

---- -----------------

Conc/Dep Flux File MODEL.DAT ! MODDAT =../gmt2.2009.con !

Relative Humidity File VISB.DAT * VISDAT = *

Background Data File BACK.DAT * BACKDAT = *

Transmissometer or VSRN.DAT * VSRDAT = *

Nephelometer Data File or

DATSAV Weather Data File or

Prognostic Weather File 

Single-point Met File SURFACE.DAT * MET1DAT = *

(Used ONLY to identify CALM hours for plume model

 output averaging when MCALMPRO option is used)

Output Files

------------

File Default File Name

---- -----------------

List File CALPOST.LST ! PSTLST 

=vis.anwr.2009.mth8.lst !

Pathname for Timeseries Files (blank) * TSPATH = *

(activate with exclamation points only if

providing NON-BLANK character string)

Pathname for Plot Files (blank) * PLPATH = *

(activate with exclamation points only if

providing NON-BLANK character string)
M-68

User Character String (U) to augment default filenames

(activate with exclamation points only if

providing NON-BLANK character string)

Timeseries TSERIES_ASPEC_ttHR_CONC_TSUNAM.DAT

Peak Value PEAKVAL_ASPEC_ttHR_CONC_TSUNAM.DAT

 * TSUNAM = *

Top Nth Rank Plot RANK(ALL)_ASPEC_ttHR_CONC_TUNAM.DAT

 or RANK(ii)_ASPEC_ttHR_CONC_TUNAM.GRD 

 ! TUNAM = anwr09m8 !

Exceedance Plot EXCEED_ASPEC_ttHR_CONC_XUNAM.DAT

 or EXCEED_ASPEC_ttHR_CONC_XUNAM.GRD

 * XUNAM = *

Echo Plot

(Specific Days) 

 yyyy_Mmm_Ddd_hhmm(UTCszzzz)_L00_ASPEC_ttHR_CONC.DAT

 or yyyy_Mmm_Ddd_hhmm(UTCszzzz)_L00_ASPEC_ttHR_CONC.GRD

Visibility Plot DAILY_VISIB_VUNAM.DAT ! VUNAM = anwr09m8 !

(Daily Peak Summary) 

Auxiliary Output Files

----------------------

File Default File Name

---- -----------------

Visibility Change DELVIS.DAT ! DVISDAT 

=delv_anwr.2009.mth8.dat !

--------------------------------------------------------------------------

------

All file names will be converted to lower case if LCFILES = T

Otherwise, if LCFILES = F, file names will be converted to UPPER CASE

 T = lower case ! LCFILES = T !

 F = UPPER CASE

NOTE: (1) file/path names can be up to 132 characters in length

NOTE: (2) Filenames for ALL PLOT and TIMESERIES FILES are constructed

 using a template that includes a pathname, user-supplied 

 character(s), and context-specific strings, where

 ASPEC = Species Name

 CONC = CONC Or WFLX Or DFLX Or TFLX

 tt = Averaging Period (e.g. 03)

 ii = Rank (e.g. 02)

 hh = Hour(ending) in LST

 szzzz = LST time zone shift (EST is -0500)

 yyyy = Year(LST)
M-69

 mm = Month(LST)

 dd = day of month (LST)

 are determined internally based on selections made below.

 If a path or user-supplied character(s) are supplied, each

 must contain at least 1 non-blank character.

!END!

--------------------------------------------------------------------------

------

INPUT GROUP: 1 -- General run control parameters

--------------

 Option to run all periods found

 in the met. file(s) (METRUN) Default: 0 ! METRUN = 0 !

 METRUN = 0 - Run period explicitly defined below

 METRUN = 1 - Run all periods in CALPUFF data file(s)

 Starting date: Year (ISYR) -- No default ! ISYR = 2009 

! 

 Month (ISMO) -- No default ! ISMO = 1 !

 Day (ISDY) -- No default ! ISDY = 1 !

 Starting time: Hour (ISHR) -- No default ! ISHR = 0 !

 Minute (ISMIN) -- No default ! ISMIN = 0 !

 Second (ISSEC) -- No default ! ISSEC = 0 !

 Ending date: Year (IEYR) -- No default ! IEYR = 2009 

! 

 Month (IEMO) -- No default ! IEMO = 12 !

 Day (IEDY) -- No default ! IEDY = 31 !

 Ending time: Hour (IEHR) -- No default ! IEHR = 24 !

 Minute (IEMIN) -- No default ! IEMIN = 0 !

 Second (IESEC) -- No default ! IESEC = 0 ! 

 (These are only used if METRUN = 0)

 All times are in the base time zone of the CALPUFF simulation.

 CALPUFF Dataset Version 2.1 contains the zone, but earlier versions

 do not, and the zone must be specified here. The zone is the

 number of hours that must be ADDED to the time to obtain UTC (or 

GMT).

 Identify the Base Time Zone for the CALPUFF simulation

 (BTZONE) -- No default ! BTZONE = 9.0 !

 Process every period of data?

 (NREP) -- Default: 1 ! NREP = 1 !

 (1 = every period processed,

 2 = every 2nd period processed,

 5 = every 5th period processed, etc.)

Species & Concentration/Deposition Information

----------------------------------------------
M-70

 Species to process (ASPEC) -- No default ! ASPEC = VISIB !

 (ASPEC = VISIB for visibility processing)

 Layer/deposition code (ILAYER) -- Default: 1 ! ILAYER = 1 !

 '1' for CALPUFF concentrations,

 '-1' for dry deposition fluxes,

 '-2' for wet deposition fluxes,

 '-3' for wet+dry deposition fluxes.

 Scaling factors of the form: -- Defaults: ! A = 0.0 !

 X(new) = X(old) * A + B A = 0.0 ! B = 0.0 !

 (NOT applied if A = B = 0.0) B = 0.0

 Add Hourly Background Concentrations/Fluxes?

 (LBACK) -- Default: F ! LBACK = F !

 Source of NO2 when ASPEC=NO2 (above) or LVNO2=T (Group 2) may be 

 from CALPUFF NO2 concentrations OR from a fraction of CALPUFF NOx

 concentrations. Specify the fraction of NOx that is treated as NO2

 either as a constant or as a table of fractions that depend on the

 magnitude of the NOx concentration:

 (NO2CALC) -- Default: 1 ! NO2CALC = 1 !

 0 = Use NO2 directly (NO2 must be in file)

 1 = Specify a single NO2/NOx ratio (RNO2NOX)

 2 = Specify a table NO2/NOx ratios (TNO2NOX)

 (NOTE: Scaling Factors must NOT be used with NO2CALC=2)

 Single NO2/NOx ratio (0.0 to 1.0) for treating some

 or all NOx as NO2, where [NO2] = [NOX] * RNO2NOX

 (used only if NO2CALC = 1)

 (RNO2NOX) -- Default: 1.0 ! RNO2NOX = 1.0 !

 Table of NO2/NOx ratios that vary with NOx concentration.

 Provide 14 NOx concentrations (ug/m**3) and the corresponding

 NO2/NOx ratio, with NOx increasing in magnitude. The ratio used

 for a particular NOx concentration is interpolated from the values

 provided in the table. The ratio for the smallest tabulated NOx

 concentration (the first) is used for all NOx concentrations less

 than the smallest tabulated value, and the ratio for the largest

 tabulated NOx concentration (the last) is used for all NOx

 concentrations greater than the largest tabulated value.

 (used only if NO2CALC = 2)

 NOx concentration(ug / m3)

 (CNOX) -- No default

 ! CNOX = 1.0, 2.0, 3.0, 4.0, 5.0, 6.0, 7.0, 

 8.0, 9.0, 10.0, 11.0, 12.0, 13.0, 14.0 !

 NO2/NOx ratio for each NOx concentration:

 (TNO2NOX) -- No default

 ! TNO2NOX = 1.0, 1.0, 1.0, 1.0, 1.0, 1.0, 1.0, 

 1.0, 1.0, 1.0, 1.0, 1.0, 1.0, 1.0 !
M-71

Source information

------------------

 Option to process source contributions:

 0 = Process only total reported contributions 

 1 = Sum all individual source contributions and process

 2 = Run in TRACEBACK mode to identify source

 contributions at a SINGLE receptor

 (MSOURCE) -- Default: 0 ! MSOURCE = 0 !

Plume Model Output Processing Options

-------------------------------------

 Output from models other than CALPUFF and CALGRID can be written in

 the CONC.DAT format and processed by CALPOST. Plume models such as

 AERMOD typically do not treat CALM hours, and do not include such hours

 in multiple-hour averages, with specific rules about how many calm hours

 can be removed from an average. This treatment is known as CALM

 PROCESSING. Calm periods are identified from wind speeds in the

 meteorological data file for the application, which must be identified

 in Input Group 0 as the single-point meteorological data file MET1DAT.

 0 = Option is not used for CALPUFF/CALGRID output files

 1 = Apply CALM processing procedures to multiple-hour averages

 (MCALMPRO) -- Default: 0 ! MCALMPRO = 0 !

 Format of Single-point Met File

 1 = AERMOD/AERMET SURFACE file

 (MET1FMT) -- Default: 1 ! MET1FMT = 1 !

 

Receptor information

--------------------

 Gridded receptors processed? (LG) -- Default: F ! LG = F !

 Discrete receptors processed? (LD) -- Default: F ! LD = T !

 CTSG Complex terrain receptors processed?

 (LCT) -- Default: F ! LCT = F !

--Report results by DISCRETE receptor RING?

 (only used when LD = T) (LDRING) -- Default: F ! LDRING = F !

--Select range of DISCRETE receptors (only used when LD = T):

 Select ALL DISCRETE receptors by setting NDRECP flag to -1;

 OR

 Select SPECIFIC DISCRETE receptors by entering a flag (0,1) for each

 0 = discrete receptor not processed

 1 = discrete receptor processed

 using repeated value notation to select blocks of receptors:

 23*1, 15*0, 12*1

 Flag for all receptors after the last one assigned is set to 0

 (NDRECP) -- Default: -1 
M-72

 anwr ! NDRECP = 146*1, 122*0 

! 

--Select range of GRIDDED receptors (only used when LG = T):

 X index of LL corner (IBGRID) -- Default: -1 ! IBGRID = -1 !

 (-1 OR 1 <= IBGRID <= NX)

 Y index of LL corner (JBGRID) -- Default: -1 ! JBGRID = -1 !

 (-1 OR 1 <= JBGRID <= NY)

 X index of UR corner (IEGRID) -- Default: -1 ! IEGRID = -1 !

 (-1 OR 1 <= IEGRID <= NX)

 Y index of UR corner (JEGRID) -- Default: -1 ! JEGRID = -1 !

 (-1 OR 1 <= JEGRID <= NY)

 Note: Entire grid is processed if IBGRID=JBGRID=IEGRID=JEGRID=-1 

--Specific gridded receptors can also be excluded from CALPOST

 processing by filling a processing grid array with 0s and 1s. If the

 processing flag for receptor index (i,j) is 1 (ON), that receptor

 will be processed if it lies within the range delineated by IBGRID,

 JBGRID,IEGRID,JEGRID and if LG=T. If it is 0 (OFF), it will not be

 processed in the run. By default, all array values are set to 1 (ON).

 Number of gridded receptor rows provided in Subgroup (1a) to

 identify specific gridded receptors to process

 (NGONOFF) -- Default: 0 ! NGONOFF = 0 !

!END!

--------------

Subgroup (1a) -- Specific gridded receptors included/excluded

--------------

 Specific gridded receptors are excluded from CALPOST processing

 by filling a processing grid array with 0s and 1s. A total of

 NGONOFF lines are read here. Each line corresponds to one 'row'

 in the sampling grid, starting with the NORTHERNMOST row that

 contains receptors that you wish to exclude, and finishing with

 row 1 to the SOUTH (no intervening rows may be skipped). Within

 a row, each receptor position is assigned either a 0 or 1,

 starting with the westernmost receptor.

 0 = gridded receptor not processed

 1 = gridded receptor processed

 Repeated value notation may be used to select blocks of receptors:

 23*1, 15*0, 12*1
M-73

 Because all values are initially set to 1, any receptors north of

 the first row entered, or east of the last value provided in a row,

 remain ON.

 (NGXRECP) -- Default: 1

--------------------------------------------------------------------------

-----

INPUT GROUP: 2 -- Visibility Parameters (ASPEC = VISIB)

--------------

 Test visibility options specified to see

 if they conform to FLAG 2008 configuration?

 (MVISCHECK) -- Default: 1 ! MVISCHECK = 1 

! 

 0 = NO checks are made

 1 = Technical options must conform to FLAG 2008 visibility 

guidance

 ASPEC = VISIB

 LVNO2 = T

 NO2CALC = 1

 RNO2NOX = 1.0

 MVISBK = 8

 M8_MODE = 5

 Some of the data entered for use with the FLAG 2008 configuration

 are specific to the Class I area being evaluated. These values can

 be checked within the CALPOST user interface when the name of the

 Class I area is provided.

 Name of Class I Area (used for QA purposes only)

 (AREANAME) -- Default: User ! AREANAME = anwr 

! 

 Particle growth curve f(RH) for hygroscopic species

 (MFRH) -- Default: 4 ! MFRH = 4 !

 1 = IWAQM (1998) f(RH) curve (originally used with MVISBK=1)

 2 = FLAG (2000) f(RH) tabulation

 3 = EPA (2003) f(RH) tabulation

 4 = IMPROVE (2006) f(RH) tabulations for sea salt, and for small 

and

 large SULFATE and NITRATE particles;

 Used in Visibility Method 8 (MVISBK = 8 with M8_MODE = 1, 2, 

or 3)

 Maximum relative humidity (%) used in particle growth curve

 (RHMAX) -- Default: 98 ! RHMAX = 95.0 !

 Modeled species to be included in computing the light extinction

 Include SULFATE? (LVSO4) -- Default: T ! LVSO4 = T !

 Include NITRATE? (LVNO3) -- Default: T ! LVNO3 = T !
M-74

 Include ORGANIC CARBON? (LVOC) -- Default: T ! LVOC = T !

 Include COARSE PARTICLES? (LVPMC) -- Default: T ! LVPMC = T !

 Include FINE PARTICLES? (LVPMF) -- Default: T ! LVPMF = T !

 Include ELEMENTAL CARBON? (LVEC) -- Default: T ! LVEC = T !

 Include NO2 absorption? (LVNO2) -- Default: F ! LVNO2 = T !

 With Visibility Method 8 -- Default: T

 FLAG (2008)

 And, when ranking for TOP-N, TOP-50, and Exceedance tables,

 Include BACKGROUND? (LVBK) -- Default: T ! LVBK = F !

 Species name used for particulates in MODEL.DAT file

 COARSE (SPECPMC) -- Default: PMC ! SPECPMC = PMC !

 FINE (SPECPMF) -- Default: PMF ! SPECPMF = PMF !

Extinction Efficiency (1/Mm per ug/m**3)

----------------------------------------

 MODELED particulate species:

 PM COARSE (EEPMC) -- Default: 0.6 ! EEPMC = 0.6 !

 PM FINE (EEPMF) -- Default: 1.0 ! EEPMF = 1 !

 BACKGROUND particulate species:

 PM COARSE (EEPMCBK) -- Default: 0.6 ! EEPMCBK = 0.6 !

 Other species:

 AMMONIUM SULFATE (EESO4) -- Default: 3.0 ! EESO4 = 3 !

 AMMONIUM NITRATE (EENO3) -- Default: 3.0 ! EENO3 = 3 !

 ORGANIC CARBON (EEOC) -- Default: 4.0 ! EEOC = 4 !

 SOIL (EESOIL)-- Default: 1.0 ! EESOIL = 1 !

 ELEMENTAL CARBON (EEEC) -- Default: 10. ! EEEC = 10 !

 NO2 GAS (EENO2) -- Default: .1755 ! EENO2 = 0.1755 

! 

 Visibility Method 8:

 AMMONIUM SULFATE (EESO4S) Set Internally (small)

 AMMONIUM SULFATE (EESO4L) Set Internally (large)

 AMMONIUM NITRATE (EENO3S) Set Internally (small)

 AMMONIUM NITRATE (EENO3L) Set Internally (large)

 ORGANIC CARBON (EEOCS) Set Internally (small)

 ORGANIC CARBON (EEOCL) Set Internally (large)

 SEA SALT (EESALT) Set Internally

Background Extinction Computation

---------------------------------

 Method used for the 24h-average of percent change of light extinction:

 Hourly ratio of source light extinction / background light extinction

 is averaged? (LAVER) -- Default: F ! LAVER = F !

 Method used for background light extinction

 (MVISBK) -- Default: 8 ! MVISBK = 8 !

 FLAG (2008)

 1 = Supply single light extinction and hygroscopic fraction

 - Hourly F(RH) adjustment applied to hygroscopic background

 and modeled sulfate and nitrate
M-75

 2 = Background extinction from speciated PM concentrations (A)

 - Hourly F(RH) adjustment applied to observed and modeled 

sulfate

 and nitrate

 - F(RH) factor is capped at F(RHMAX)

 3 = Background extinction from speciated PM concentrations (B)

 - Hourly F(RH) adjustment applied to observed and modeled 

sulfate

 and nitrate

 - Receptor-hour excluded if RH>RHMAX

 - Receptor-day excluded if fewer than 6 valid receptor-hours

 4 = Read hourly transmissometer background extinction 

measurements

 - Hourly F(RH) adjustment applied to modeled sulfate and 

nitrate

 - Hour excluded if measurement invalid (missing, 

interference,

 or large RH)

 - Receptor-hour excluded if RH>RHMAX

 - Receptor-day excluded if fewer than 6 valid receptor-hours

 5 = Read hourly nephelometer background extinction measurements

 - Rayleigh extinction value (BEXTRAY) added to measurement

 - Hourly F(RH) adjustment applied to modeled sulfate and 

nitrate

 - Hour excluded if measurement invalid (missing, 

interference,

 or large RH)

 - Receptor-hour excluded if RH>RHMAX

 - Receptor-day excluded if fewer than 6 valid receptor-hours

 6 = Background extinction from speciated PM concentrations

 - FLAG (2000) monthly RH adjustment factor applied to 

observed and

 and modeled sulfate and nitrate

 7 = Use observed weather or prognostic weather information for

 background extinction during weather events; otherwise, use 

Method 2

 - Hourly F(RH) adjustment applied to modeled sulfate and 

nitrate

 - F(RH) factor is capped at F(RHMAX)

 - During observed weather events, compute Bext from visual 

range

 if using an observed weather data file, or

 - During prognostic weather events, use Bext from the 

prognostic

 weather file

 - Use Method 2 for hours without a weather event

 8 = Background extinction from speciated PM concentrations using

 the IMPROVE (2006) variable extinction efficiency 

formulation

 (MFRH must be set to 4)

 - Split between small and large particle concentrations of

 SULFATES, NITRATES, and ORGANICS is a function of 

concentration

 and different extinction efficiencies are used for each
M-76

 - Source-induced change in visibility includes the increase 

in

 extinction of the background aerosol due to the change in 

the

 extinction efficiency that now depends on total 

concentration.

 - Fsmall(RH) and Flarge(RH) adjustments for small and large

 particles are applied to observed and modeled sulfate and

 nitrate concentrations

 - Fsalt(RH) adjustment for sea salt is applied to background

 sea salt concentrations

 - F(RH) factors are capped at F(RHMAX)

 - RH for Fsmall(RH), Flarge(RH), and Fsalt(RH) may be 

obtained

 from hourly data as in Method 2 or from the FLAG monthly 

RH

 adjustment factor used for Method 6 where EPA F(RH) 

tabulation

 is used to infer RH, or monthly Fsmall, Flarge, and Fsalt 

RH

 adjustment factors can be directly entered.

 Furthermore, a monthly RH factor may be applied to either 

hourly

 concentrations or daily concentrations to obtain the 24-

hour

 extinction.

 These choices are made using the M8_MODE selection.

 Additional inputs used for MVISBK = 1:

 --------------------------------------

 Background light extinction (1/Mm)

 (BEXTBK) -- No default ! BEXTBK = 0.0 !

 Percentage of particles affected by relative humidity

 (RHFRAC) -- No default ! RHFRAC = 0.0 !

 Additional inputs used for MVISBK = 6,8:

 ----------------------------------------

 Extinction coefficients for hygroscopic species (modeled and

 background) are computed using a monthly RH adjustment factor

 in place of an hourly RH factor (VISB.DAT file is NOT needed).

 Enter the 12 monthly factors here (RHFAC). Month 1 is January.

 (RHFAC) -- No default 

 (RHFAC) -- No default ! RHFAC = 0, 0, 0, 0, 

 0, 0, 0, 0, 

0, 0, 0, 0 !

 Additional inputs used for MVISBK = 7:

 --------------------------------------

 The weather data file (DATSAV abbreviated space-delimited) that

 is identified as VSRN.DAT may contain data for more than one

 station. Identify the stations that are needed in the order in

 which they will be used to obtain valid weather and visual range.
M-77

 The first station that contains valid data for an hour will be

 used. Enter up to MXWSTA (set in PARAMS file) integer station IDs

 of up to 6 digits each as variable IDWSTA, and enter the 

corresponding

 time zone for each, as variable TZONE (= UTC-LST).

 A prognostic weather data file with Bext for weather events may be 

used

 in place of the observed weather file. Identify this as the VSRN.DAT

 file and use a station ID of IDWSTA = 999999, and TZONE = 0.

 NOTE: TZONE identifies the time zone used in the dataset. The

 DATSAV abbreviated space-delimited data usually are prepared

 with UTC time rather than local time, so TZONE is typically

 set to zero.

 (IDWSTA) -- No default

 ! IDWSTA = 999999 !

 (TZONE) -- No default

 ! TZONE = 0.0 !

 Additional inputs used for MVISBK = 2,3,6,7,8:

 ----------------------------------------------

 Background extinction coefficients are computed from monthly

 CONCENTRATIONS of ammonium sulfate (BKSO4), ammonium nitrate (BKNO3),

 coarse particulates (BKPMC), organic carbon (BKOC), soil (BKSOIL), 

and

 elemental carbon (BKEC). Month 1 is January.

 (ug/m**3)

 (BKSO4) -- No default ! BKSO4 = 12*0.12 !

 (BKNO3) -- No default ! BKNO3 = 12*0.05 !

 (BKPMC) -- No default ! BKPMC = 12*1.12 ! 

 (BKOC) -- No default ! BKOC = 12*0.6 !

 (BKSOIL) -- No default ! BKSOIL= 12*0.14!

 (BKEC) -- No default ! BKEC = 12*0.02 !

 Additional inputs used for MVISBK = 8:

 --------------------------------------

 Extinction coefficients for hygroscopic species (modeled and

 background) may be computed using hourly RH values and hourly

 modeled concentrations, or using monthly RH values inferred from

 the RHFAC adjustment factors and either hourly or daily modeled

 concentrations, or using monthly RHFSML, RHFLRG, and RHFSEA 

adjustment

 factors and either hourly or daily modeled concentrations.

 

 (M8_MODE) -- Default: 5 ! M8_MODE= 5 !

 FLAG (2008)

 

 1 = Use hourly RH values from VISB.DAT file with hourly

 modeled and monthly background concentrations. 

 2 = Use monthly RH from monthly RHFAC and EPA (2003) f(RH) 

tabulation
M-78

 with hourly modeled and monthly background concentrations.

 (VISB.DAT file is NOT needed).

 3 = Use monthly RH from monthly RHFAC with EPA (2003) f(RH) 

tabulation

 with daily modeled and monthly background concentrations.

 (VISB.DAT file is NOT needed).

 4 = Use monthly RHFSML, RHFLRG, and RHFSEA with hourly modeled

 and monthly background concentrations.

 (VISB.DAT file is NOT needed).

 5 = Use monthly RHFSML, RHFLRG, and RHFSEA with daily modeled

 and monthly background concentrations.

 (VISB.DAT file is NOT needed).

 Background extinction coefficients are computed from monthly

 CONCENTRATIONS of sea salt (BKSALT). Month 1 is January.

 (ug/m**3)

 (BKSALT) -- No default ! BKSALT= 12*0.04 !

 Extinction coefficients for hygroscopic species (modeled and

 background) can be computed using monthly RH adjustment factors

 in place of an hourly RH factor (VISB.DAT file is NOT needed).

 Enter the 12 monthly factors here (RHFSML,RHFLRG,RHFSEA).

 Month 1 is January. (Used if M8_MODE = 4 or 5)

 Small ammonium sulfate and ammonium nitrate particle sizes

 (RHFSML) -- No default 

 ! RHFSML= 3.21,3.19,2.71,2.39,2.46,2.69,3.27,4.05,4.17,3.9,3.59,3.58 !

 Large ammonium sulfate and ammonium nitrate particle sizes

 (RHFLRG) -- No default 

 ! RHFLRG= 2.48,2.44,2.15,1.96,1.98,2.13,2.47,2.9,2.95,2.84,2.69,2.68 !

 Sea salt particles

 (RHFSEA) -- No default 

 ! RHFSEA= 3.68,3.57,3.07,2.74,2.74,3.01,3.53,4.13,4.19,4.09,3.92,3.94 !

 Additional inputs used for MVISBK = 2,3,5,6,7,8:

 ------------------------------------------------

 Extinction due to Rayleigh scattering is added (1/Mm)

 (BEXTRAY) -- Default: 10.0 ! BEXTRAY = 11 !

 

!END!

--------------------------------------------------------------------------

-----

INPUT GROUP: 3 -- Output options

--------------

Documentation

-------------

 Documentation records contained in the header of the

 CALPUFF output file may be written to the list file.
M-79

 Print documentation image?

 (LDOC) -- Default: F ! LDOC = F !

Output Units

------------

 Units for All Output (IPRTU) -- Default: 1 ! IPRTU = 3 !

 for for

 Concentration Deposition

 1 = g/m**3 g/m**2/s

 2 = mg/m**3 mg/m**2/s

 3 = ug/m**3 ug/m**2/s

 4 = ng/m**3 ng/m**2/s

 5 = Odour Units

 Visibility: extinction expressed in 1/Mega-meters (IPRTU is ignored)

Averaging time(s) reported

--------------------------

 1-pd averages (L1PD) -- Default: T ! L1PD = F !

 (pd = averaging period of model output)

 1-hr averages (L1HR) -- Default: T ! L1HR = F !

 3-hr averages (L3HR) -- Default: T ! L3HR = F !

 24-hr averages (L24HR) -- Default: T ! L24HR = T !

 Run-length averages (LRUNL) -- Default: T ! LRUNL = F !

 User-specified averaging time in hours, minutes, seconds

 - results for this averaging time are reported if it is not zero

 (NAVGH) -- Default: 0 ! NAVGH = 0 !

(NAVGM) -- Default: 0 ! NAVGM = 0 !

 (NAVGS) -- Default: 0 ! NAVGS = 0 !

Types of tabulations reported

------------------------------

 1) Visibility: daily visibility tabulations are always reported

 for the selected receptors when ASPEC = VISIB.

In addition, any of the other tabulations listed

below may be chosen to characterize the light

extinction coefficients.

[List file or Plot/Analysis File]

 2) Top 50 table for each averaging time selected

 [List file only]

 (LT50) -- Default: T ! LT50 = T !
M-80

 3) Top 'N' table for each averaging time selected

 [List file or Plot file]

 (LTOPN) -- Default: F ! LTOPN = T !

 -- Number of 'Top-N' values at each receptor

 selected (NTOP must be <= 4)

 (NTOP) -- Default: 4 ! NTOP = 4 !

 -- Specific ranks of 'Top-N' values reported

 (NTOP values must be entered)

 (ITOP(4) array) -- Default: ! ITOP = 1 , 2 , 3 , 4 

! 

 1,2,3,4

 4) Threshold exceedance counts for each receptor and each averaging

 time selected

 [List file or Plot file]

 (LEXCD) -- Default: F ! LEXCD = F !

 -- Identify the threshold for each averaging time by assigning a

 non-negative value (output units).

 -- Default: -1.0

 Threshold for 1-hr averages (THRESH1) ! THRESH1 = -1.0 !

 Threshold for 3-hr averages (THRESH3) ! THRESH3 = -1.0 !

 Threshold for 24-hr averages (THRESH24) ! THRESH24 = -1.0 !

 Threshold for NAVG-hr averages (THRESHN) ! THRESHN = -1.0 !

 -- Counts for the shortest averaging period selected can be

 tallied daily, and receptors that experience more than NCOUNT

 counts over any NDAY period will be reported. This type of

 exceedance violation output is triggered only if NDAY > 0.

 Accumulation period(Days)

 (NDAY) -- Default: 0 ! NDAY = 0 !

 Number of exceedances allowed

 (NCOUNT) -- Default: 1 ! NCOUNT = 1 !

 5) Selected day table(s)

 Echo Option -- Many records are written each averaging period

 selected and output is grouped by day

 [List file or Plot file]

 (LECHO) -- Default: F ! LECHO = F !

 Timeseries Option -- Averages at all selected receptors for

 each selected averaging period are written to timeseries files.

 Each file contains one averaging period, and all receptors are

 written to a single record each averaging time.

 [TSERIES_ASPEC_ttHR_CONC_TSUNAM.DAT files]

 (LTIME) -- Default: F ! LTIME = F !
M-81

 Peak Value Option -- Averages at all selected receptors for

 each selected averaging period are screened and the peak value

 each period is written to timeseries files.

 Each file contains one averaging period.

 [PEAKVAL_ASPEC_ttHR_CONC_TSUNAM.DAT files]

 (LPEAK) -- Default: F ! LPEAK = F !

 -- Days selected for output

 (IECHO(366)) -- Default: 366*0

 ! IECHO = 366*0 !

 (366 values must be entered)

Plot output options

-------------------

 Plot files can be created for the Top-N, Exceedance, and Echo

 tables selected above. Two formats for these files are available,

 DATA and GRID. In the DATA format, results at all receptors are

 listed along with the receptor location [x,y,val1,val2,...].

 In the GRID format, results at only gridded receptors are written,

 using a compact representation. The gridded values are written in

 rows (x varies), starting with the most southern row of the grid.

 The GRID format is given the .GRD extension, and includes headers

 compatible with the SURFER(R) plotting software.

 A plotting and analysis file can also be created for the daily

 peak visibility summary output, in DATA format only.

 Generate Plot file output in addition to writing tables

 to List file?

 (LPLT) -- Default: F ! LPLT = T !

 Use GRID format rather than DATA format,

 when available?

 (LGRD) -- Default: F ! LGRD = F !

Auxiliary Output Files (for subsequent analyses)

------------------------------------------------

 Visibility

 A separate output file may be requested that contains the change

 in visibility at each selected receptor when ASPEC = VISIB. This

 file can be processed to construct visibility measures that are

 not available in CALPOST.

 Output file with the visibility change at each receptor?

 (MDVIS) -- Default: 0 ! MDVIS = 2 !

 0 = Do Not create file

 1 = Create file of DAILY (24 hour) Delta-Deciview

 2 = Create file of DAILY (24 hour) Extinction Change (%)
M-82

 3 = Create file of HOURLY Delta-Deciview

 4 = Create file of HOURLY Extinction Change (%)

Additional Debug Output

-----------------------

 Output selected information to List file

 for debugging?

 (LDEBUG) -- Default: F ! LDEBUG = F !

 Output hourly extinction information to REPORT.HRV?

 (Visibility Method 7)

 (LVEXTHR) -- Default: F ! LVEXTHR = F !

!END!
M-83

3. Sample POSTUTIL Input File

Greater Mooses Tooth 2, Alt A total deposition fluxes (wet & dry), 2009 

Simulation

N due to NOx, HNO3, NH4NO3, and (NH4)2SO4

S due to SO2, (NH4)2SO4

---------------- Run title (3 lines) -------------------------------------

-----

 POSTUTIL MODEL CONTROL FILE

 ---------------------------

--------------------------------------------------------------------------

-----

INPUT GROUP: 0 -- Input and Output File Names

--------------

-------------

Subgroup (0a)

-------------

Output Files

------------

File Default File Name

---- -----------------

List File POSTUTIL.LST ! UTLLST =tdep.2009.lst !

Data File MODEL.DAT ! UTLDAT =tdep.2009.dep !

Input Files

-----------

A time-varying file of "background" concentrations can be included

when the ammonia-limiting method (ALM) for setting the HNO3/NO3

concentration partition is accomplished in 1 step. This option

is selected by setting MNITRATE=3 in Input Group 1.

Species required in the "background" concentration file are: 

SO4, NO3, HNO3 and TNH3 (total NH3 = NH3gaseous + NH3particulate).

File Default File Name

---- -----------------

BCKG File BCKGALM.DAT * BCKGALM =BCKGALM.DAT *

A number of CALPUFF data files may be processed in this application.

The files may represent individual CALPUFF simulations that were made

for a specific set of species and/or sources. Specify the total number

of CALPUFF runs you wish to combine, and provide the filename for each
M-84

in subgroup 0b.

 Number of CALPUFF data files (NFILES)

 Default: 1 ! NFILES = 2 !

Meteorological data files are needed for the HNO3/NO3 partition option.

Three types of meteorological data files can be used:

 METFM= 0 - CALMET.DAT

 METFM= 1 - 1-D file with RH, Temp and Rhoair timeseries

 METFM= 2 - 2-D files with either Rh, Temp or Rhoair in each

 (3 2_D files are needed)

 The default is to use CALMET.DAT files.

 Default: 0 ! METFM = 0 !

 

 

Multiple meteorological data files may be used in sequence to span the

processing period. Specify the number of time-period files (NMET) that

you need to use, and provide a filename for each in subgroup 0b.

 - NMET is 0 if no meteorological files are provided

 - NMET is 1 if METFM=1 (multiple file feature is not available)

 - NMET is 1 or more if METFM=0 or 2 (multiple CALMET files or 2DMET 

files)

 Number of meteorological data file time-periods (NMET)

 Default: 0 ! NMET = 0 !

All filenames will be converted to lower case if LCFILES = T

Otherwise, if LCFILES = F, filenames will be converted to UPPER CASE

 Convert filenames to lower case? Default: T ! LCFILES = T !

 T = lower case 

 F = UPPER CASE

!END!

-----------------------------------------------------------

NOTE: file/path names can be up to 70 characters in length

-----------------------------------------------------------

-------------

Subgroup (0b)

-------------

NMET CALMET Data Files (METFM=0):

Input File Default File Name

---------- -----------------

 1 MET.DAT * UTLMET =CALMET.DAT * *END*
M-85

NMET 1-D Data Files (METFM=1):

Input File Default File Name

---------- -----------------

 1 MET_1D.DAT * MET1D = MET_1D.DAT * *END*

NMET 2-D Data Files of Each Type (METFM=2):

Input File Default File Name

---------- -----------------

 1 RHUMD.DAT * M2DRHU = RELHUM.DAT * *END*

 1 TEMP.DAT * M2DTMP = TEMP.DAT * *END*

 1 RHOAIR.DAT * M2DRHO = RHOAIR.DAT * *END*

NFILES CALPUFF Data Files:

Input File Default File Name

---------- -----------------

 1 CALPUFF.DAT ! MODDAT = gmt2.2009.wet ! !END!

 2 (none) ! MODDAT = gmt2.2009.dry ! !END!

-------------

Note: provide NMET lines of the form * UTLMET = name * *END* 

 or * MET1D = name * *END* 

or * M2DRHU = name * *END* 

 (and) * M2DTMP = name * *END* 

 (and) * M2DRHO = name * *END* 

 and NFILES lines of the form * MODDAT = name * *END*

 

 where the * should be replaced with an exclamation point,

 the special delimiter character.

--------------------------------------------------------------------------

------

INPUT GROUP: 1 -- General run control parameters

--------------

 Starting date: Year (ISYR) -- No default ! ISYR = 2009 !

 Month (ISMO) -- No default ! ISMO = 1 !

 Day (ISDY) -- No default ! ISDY = 1 !

 Hour (ISHR) -- No default ! ISHR = 1 !

 Number of periods to process

 (NPER) -- No default ! NPER = 8760 !

 Number of species to process from CALPUFF runs
M-86

 (NSPECINP) -- No default ! NSPECINP = 5 !

 Number of species to write to output file

 (NSPECOUT) -- No default ! NSPECOUT = 2 !

 Number of species to compute from those modeled

 (must be no greater than NSPECOUT)

 (NSPECCMP) -- No default ! NSPECCMP = 2 !

When multiple files are used, a species name may appear in more than

one file. Data for this species will be summed (appropriate if the

CALPUFF runs use different source groups). If this summing is not

appropriate, remove duplicate species from the file(s).

 Stop run if duplicate species names

 are found? (MDUPLCT) Default: 0 ! MDUPLCT = 0 !

 0 = no (i.e., duplicate species are summed)

 1 = yes (i.e., run is halted)

Data for each species in a CALPUFF data file may also be scaled as

they are read. This can be done to alter the emission rate of all

sources that were modeled in a particular CALPUFF application.

The scaling factor for each species is entered in Subgroup (2d), for

each file for which scaling is requested.

 Number of CALPUFF data files that will be scaled

 (must be no greater than NFILES)

 (NSCALED) Default: 0 ! NSCALED = 0 !

Ammonia-Limiting Method Option to recompute the HNO3/NO3 concentration

partition prior to performing other actions is controlled by MNITRATE.

This option will NOT alter any deposition fluxes contained in the CALPUFF

file(s). Three partition selections are provided. The first two are

typically used in sequence (POSTUTIL is run more than once). The first

selection (MNITRATE=1) computes the partition for the TOTAL (all sources)

concentration fields (SO4, NO3, HNO3; NH3), and the second (MNITRATE=2)

uses this partition (from the previous application of POSTUTIL) to

compute the partition for individual source groups. The third selection

(MNITRATE=3) can be used instead in a single POSTUTIL application if a

file of background concentrations is provided (BCKGALM in Input Group 0). 

Required information for MNITRATE=1 includes:

 species NO3, HNO3, and SO4

 NH3 concentration(s)

 met. data file for RH and T

Required information for MNITRATE=2 includes:

 species NO3 and HNO3 for a source group

 species NO3ALL and HNO3ALL for all source groups, properly

 partitioned

Required information for MNITRATE=3 includes:
M-87

 species NO3, HNO3, and SO4 for a source group

 species NO3, HNO3, SO4 and TNH3 from the background BCKGALM file

 If TNH3 is not in the background BCKGALM file, monthly TNH3

 concentrations are used (BCKTNH3)

 TNH3= total NH3 = NH3gaseous+NH3particulate

 Recompute the HNO3/NO3 partition for concentrations?

 (MNITRATE) Default: 0 ! MNITRATE = 0 !

 0 = no

 1 = yes, for all sources combined

 2 = yes, for a source group

 3 = yes, ALM application in one step

SOURCE OF AMMONIA:

Ammonia may be available as a modeled species in the CALPUFF files,

and it may or may not be appropriate to use it for repartitioning 

NO3/HNO3

(in option MNITRATE=1 or MNITRATE=3). Its use is contolled by NH3TYP.

When NH3 is listed as a processed species in Subgroup (2a), as one of 

the NSPECINP ASPECI entries, and the right option is chosen for NH3TYP,

the NH3 modeled values from the CALPUFF concentration files will be used

in the chemical equilibrium calculation. 

NH3TYP also controls when monthly background ammonia values are used. 

Both

gaseous (NH3) and total (TNH3=NH3gaseous+NH3particulate) ammonia can be 

provided

monthly as BCKNH3/BCKTNH3.

 

 What is the input source of Ammonia?

 (NH3TYP) No Default ! NH3TYP = 0 !

 0 = No background will be used.

 ONLY NH3 or TNH3 from the concentration 

 files listed in Subgroup (2a&2b) as 

 a processed species will be used.

 (Cannot be used with MNITRATE=3)

 1 = NH3 Monthly averaged background (BCKNH3)

 listed below will be added to NH3 from 

 concentration files listed in Subgroup (2a)

 2 = NH3 from background concentration file BCKGALM

 will be added to NH3 from concentration files

 listed in Subgroup (2a&2b)

 (ONLY possible for MNITRATE=3)

 3 = NH3 Monthly averaged background (BCKNH3)

 listed below will be used alone.

 4 = NH3 from background concentration file BCKGALM

 will be used alone

 (ONLY possible for MNITRATE=3)
M-88

| OPTION | NH3 or TNH3 CONC | BCKNH3 or BCKTNH3 | TNH3/BCKGALM or BCKTNH3 

| 

 |--------|------------------|-------------------|------------------------

-| 

| 0 | X | 0 | 0 

| 

 |--------|------------------|-------------------|------------------------

-| 

| 1 | X | X | 0 

| 

 |--------|------------------|-------------------|------------------------

-| 

| 2 | X | 0 | X 

| 

 |--------|------------------|-------------------|------------------------

-| 

| 3 | 0 | X | 0 

| 

 |--------|------------------|-------------------|------------------------

-| 

| 4 | 0 | 0 | X 

| 

 |--------|------------------|-------------------|------------------------

-| 

 Default monthly (12 values) background ammonia concentration (ppb)

 used for HNO3/NO3 partition (need to choose one or the other):

 

 Gaseous NH3 (BCKNH3) Default: -999

 * BCKNH3 = 1., 1., 1., 1.1, 1.4, 1.3, 1.3, 1.2, 4*1. *

 Total TNH3 (BCKTNH3) Default: -999

 * BCKTNH3 = 1., 1., 1., 1.1, 1.4, 1.3, 1.3, 1.2, 4*1. *

 

 If a single value is entered, this is used for all 12 months. 

 Month 1 is JANUARY, Month 12 is DECEMBER.

!END!

--------------------------------------------------------------------------

-----

INPUT GROUP: 2 -- Species Processing Information

--------------

-------------

Subgroup (2a)

-------------

 The following NSPECINP species will be processed:

! ASPECI = SO2 ! !END!

! ASPECI = SO4 ! !END!
M-89

! ASPECI = NOX ! !END!

! ASPECI = HNO3 ! !END!

! ASPECI = NO3 ! !END!

-------------

Subgroup (2b)

-------------

 The following NSPECOUT species will be written:

! ASPECO = TOTN ! !END!

! ASPECO = TOTS ! !END!

-------------

Subgroup (2c)

-------------

 The following NSPECCMP species will be computed by scaling and summing

 one or more of the processed input species. Identify the name(s) of

 the computed species and provide the scaling factors for each of the

 NSPECINP input species (NSPECCMP groups of NSPECINP+1 lines each):

! CSPECCMP = TOTN !

! SO2 = 0.0 !

! SO4 = 0.291667 ! 28/96

! NOX = 0.3043 ! 14/46

! HNO3 = 0.222222 ! 14/63

! NO3 = 0.451613 ! 28/62

!END!

! CSPECCMP = TOTS !

! SO2 = 0.500000 ! 32/64

! SO4 = 0.333333 ! 32/96

! NOX = 0.0 !

! HNO3 = 0.0 ! 

! NO3 = 0.0 !

!END!

-------------

Subgroup (2d)

-------------

 Each species in NSCALED CALPUFF data files may be scaled before being

 processed (e.g., to change the emission rate for all sources modeled

 in the run that produced a data file). For each file, identify the

 file name and then provide the name(s) of the scaled species and the

 corresponding scaling factors (A,B where x' = Ax+B).

 A(Default=1.0) B(Default=0.0)

 -------------- --------------

* MODDAT =NOFILES.DAT *
M-90

* SO2 = 1.1, 0.0 *

* SO4 = 1.5, 0.0 *

* HNO3 = 0.8, 0.0 *

* NO3 = 0.1, 0.0 *

*END*

Appendices  Final Supplemental Environmental Impact Statement

Alpine Satellite Development Plan for the Proposed Greater Mooses Tooth 2 Development Project

APPENDIX N

METHODOLOGY FOR CONTENT ANALYSIS OF 

NUIQSUT RESIDENTS’ COMMENTS ON OIL 

DEVELOPMENT

1 

Research Objectives

The objectives of this project are to analyze public testimony to better assess various social impacts 

of nearby oil development on the small indigenous community of Nuiqsut and to create a tool that 

will both facilitate analysis and lessen the inevitable impacts of future requirements to analyze social 

impacts in the region. Common questions at public meetings include ones such as, ‘What did you 

guys do with our comments?’ This is understood as meaning ‘Are you including and giving extra 

weight not just to my testimony today but to all the valuable indigenous and traditional ecological 

knowledge that our elders shared with you throughout decades of meetings like this one, how can we 

be assured that you are, and why should we continue spending our time and sharing it without much 

evidence that you are using it in your decision-making?'

Methodology

This project used standard social science qualitative data analysis software (Atlas.ti). The purpose of 

this software is to help researchers uncover and systematically analyze complex phenomena hidden in 

unstructured data. The program provides tools that let the user locate, code, and annotate findings in 

primary data material, to weigh and evaluate their importance, and to visualize the often complex 

relations between them. 

Through a lengthy and deliberate collaboration between the BLM sociocultural expert and an outside 

qualitative analysis specialist, a master codebook to guide the analysis of transcripts of 10 Nuiqsut 

public meetings on oil development1 was designed. Initial creation of the codebook did use categories 

and aspects of subsistence and sociocultural impacts already identified in NEPA documents as 

prospective groups and codes, but it was mainly developed through intensive and iterative ‘open 

coding’ (also known as substantive or intuitive coding). In reviewing the data (in this case, public 

testimony of Inupiat), repeated ideas, concepts, or elements became apparent and were tagged with 

codes. As more data was collected and reviewed, codes were grouped into concepts and categories. 

This methodology allowed an organization of impacts into codes and categories to aggregate through 

the analysis of data instead of simply trying to find data that informed the limited categories of what 

were already suspected to be social impacts. 

Determining the unit of analysis (amount of text) to code was challenging given the nature of the 

transcripts, but we decided to use what would generally be considered a paragraph as the unit. 

Transcriptions varied as to whether they were broken into blocks or paragraphs by subject or simply 

divided by speakers, regardless of the length of time one person spoke. In some cases we broke long 

sections of text into paragraphs. Capturing repetitions by a given speaker is important, as is capturing 

different ways the same code might come up. 

The codebook and overall project was presented to and supported by the Native Village of Nuiqsut 

tribal council in August 2016. 

 

1 Testimony is from public meetings in Nuiqsut on the Alpine Satellite Development Project, the NPR-A Integrated 

Activity Plan, the GMT1 Supplemental EIS, scoping for the Nanushuk EIS, and the GMT1 Compensatory Mitigation Funds. 

A list of meetings is included at the end of this section. 
2 

The Codebook

The codebook consists of 47 intuitive codes grouped into 7 categories: 

1. Public Health

2. Subsistence 

3. Social Impacts of the Permitting Process

4. Physical Environment and Infrastructure 

5. Miscellaneous and Important 

6. Inupiat Culture and Way of Life

7. Economy 

Two additional categories are not based on open or intuitive coding: one (Names/Affiliations) is for 

the personal names and, when known and appropriate, the affiliations of the speakers. Codes in these 

categories are not included in the analyses depicted below.

The second non-subjective category is Places. How testimony is coded into the Physical 

Environment and Infrastructure and the Subsistence groups is usually very straightforward, Economy

is rarely subjective, and Public Health is only slightly more so. 

A one-page version of the codebook serves as an overview and as a table of contents for the actual 

codebook2

, which includes descriptions of categories, rules for the use of each code, and, for each 

code, examples of testimony that were given that code. Much of the testimony refers to more than 

one subject and is co-coded appropriately, allowing the important analysis of frequencies of code cooccurrences. 

 

2 The full-length codebook is available on a case-by-case basis
3 

Nuiqsut Oil Development Testimony Analysis Codes

Topic Codes

Public Health

• Air quality 

• Noise

• Food (niqipiaq & store-bought) 

• Water Health

• Other human health issues

Subsistence • Access/Land Loss/Avoidance

• Abundance of Fish & Wildlife

• Migration changes/localized displacement 

• Air Traffic

• Roads 

• Hunting (competition, regulations, enforcement) 

• Native Allotments

NEPA Process/Social Impacts of 

Permitting 

• Meetings

• Comments 

• Pace

• Capacity

• Bureaucracy/difficulty/confusion

• Rules

• Lack of Sociocultural Analysis

• Lack of Environmental Analysis 

• Distrust

• Disenfranchisement

• Conflict 

• Compensatory Mitigation 

Physical Environment & Infrastructure • Drill Pads and wells

• Pipelines

• Water Resources

• Climate change

• Legacy Wells

• Vegetation

• Oil Spill

• Blowout 

• Bridges

• Flooding 

• Seismic

• Proximity of development 

• Offshore

• Environment
4 

Topic Codes

Places • Fish Creek

• Nigliq Channel 

• Colville River

• Judy Creek

• Tingmiaqsigvik/Ublutuoch/The Y 

• Umiat

• Teshekpuk Lake

• Oliktok

Miscellaneous & Important • Cumulative Impacts

• Environmental Justice 

• Positive Impacts

• Cultural Sites

• Notable Quotations 

Inupiaq Culture & Way of Life • Inupiaq or Native way of life

• Future generations 

• Traditional or Indigenous Knowledge

Economy/Jobs/Poverty • Economy

• Overcrowding

Names/Affiliations • 53 Inupiaq residents of Nuiqsut identified by full names3

• Native Village of Nuiqsut

• Kuukpik Corporation 

• City of Nuiqsut 

• Arctic Slope Regional Corporation

• North Slope Borough

The Social Impacts of the Permitting Process category is the main focus of this project and is the 

most difficult to code. It contains numerous codes that are more nuanced than the subjects typically 

analyzed in NEPA sociocultural systems sections. The codes are meant to provide insights into 

impacts that are often difficult to articulate and that pertain to a perpetual permitting process on a 

small minority population for nearby, large-scale development.

There are 12 codes within this group and several of the codes cover subjects that are closely related, 

thus the codebook includes extensive documentation of how to distinguish similar concepts. One 

such code in this group is Bureaucracy and it is designed to capture all comments that refer to:

• Difficulty or confusion with any aspects of the NEPA process or land management, including 

the documents themselves, any acronyms and jargon, what stage of the process the agency is 

at, and the significance of ‘alternatives’ presented in Draft NEPA documents. 

• Confusion about the various land owners or managers, including which entities own or 

manage which land, how land conveyance occurs, and what the various authorities of the 

entities are. 

• Confusion over the numerous advisory groups that exist on the North Slope 

 

3 There are also 5 unidentified speakers, many of whom are likely included in the 53 named speakers
5 

• Complaints about information overload, frustration with red tape 

A closely related code within the group is called Community Capacity. This code is used whenever 

people discuss how they are not adequately prepared to participate effectively in the process. This can 

be due to lack of trained and paid personnel, lack of time to deal with the process, lack of technology 

or equipment, or lack of ability to solicit legal advice. 

Lack of Power/Disrespect/Disenfranchisement4 is designed to capture other commonly expressed 

complaints about some aspect of the permitting process that is unfair or unjust and that occurs 

because the Inupiat have less power and agency. It is used for any complaints of racism, of 

inadequate consultation, that people’s input is always solicited but seems to be ignored, that they 

have no real power to influence the ultimate decision (limited access to actual decision makers), and 

any complaints that they are exploited by industry or government agencies. 

Distrust is the code used for a reference to distrust of the government, of industry, of the science and 

monitoring done on impacts (including the belief that there are too many and redundant studies, 

which is usually connected to aircraft traffic), when conflicts of interest are cited as reasons for 

distrust, and when people are concerned the science is being spun or edited to reduce the evidence of 

impacts. 

Any testimony that refers to social and political conflict, including intra-community conflict that is 

exacerbated by the permitting process and intercommunity conflict due to appropriation of impact 

funds and levels of impacts experienced, is coded as Conflict. 

Codes within this group that are much simpler to attribute include Pace, which is used for any 

comment that refers to the speed at which various projects are permitted and constructed. Meetings is

the code for any reference to actual meetings (length, structure, scheduling, and number of, demands 

for, needs for food and door prizes at, etc.). Any testimony that is explicitly about testimony and 

public comments (how they are used, what has been done with all of them, please use previous ones, 

etc.) is coded with Comments. Any testimony that refers to inadequacy of the physical/environmental 

data used in the analyses is coded Lack of Environmental Analysis, and any reference to an EIS or 

agencies or researchers failing to study or include information about impacts to humans (including 

failure to weigh social impacts adequately) is coded as Lack of Social/Cultural Analysis. Most

reference to funds that are directed to a community to be used to offset impacts (including the State 

of Alaska NPR-A Impact Mitigation funds, GMT1 funds, or the Northeast NPR-A Regional 

Mitigation Strategy) are coded as Compensatory Mitigation. All references to permit stipulations and 

requirements, laws and regulations, and monitoring and enforcement are coded as Regulations and 

Enforcement5 (code shorthand: Rules).

Findings

At this initial stage of the project, the codebook is finalized and preliminary analyses can be done on 

the data. There is likely too little data (too few meetings) to analyze trends, but the existing data does 

 

4 Disenfranchisement is the most accurate word for this code. However, use of the term alone disenfranchises many 

residents, who are not familiar with it. It was felt that ‘marginalize’ was an even worse term and that ‘lack of agency’ 

would be quite confusing as well. 

5 The Rules code is used for any discussion of what the BLM refers to as avoidance and minimization mitigation. 
6 

provide evidence that social impacts of the perpetual permitting process are deeper and more 

complex than previous analyses have indicated. 

The coding software allows numerous types of analyses to be extracted from the data sets of coded 

transcripts. The most simple is a spreadsheet that lists every code, depicts in columns how many 

times each code occurred in each meeting, and gives a total. This allows one to see whether an 

especially high code is high due to only one or two meetings where it may have been the subject of a 

lengthy discussion or whether it is high because it is something that reoccurs at most meetings in high 

frequency. In the transcripts coded to date, for example, Compensatory Mitigation (code shorthand: 

Mitigate) has the highest count (170) and it is clear that it is an important subject at all meetings, but 

the very high count is due to the fact that 3 of the 10 meetings included focused on the uses of GMT1 

mitigation funds. 

The second most frequent code (85 occurrences) is Regulations and Enforcement (code shorthand: 

Rules). Nearly every occurrence of this code is due to residents requesting stricter regulations and 

enforcement of them to protect subsistence resources and air and water quality. The top code with 

which Regulations and Enforcement co-occurs is Migration changes/localized displacement. 

Access/Land Loss/Avoidance (code shorthand: Access), which is used whenever people speak of their 

ability to use traditional land, the loss of land, the avoidance of land due to infrastructure and 

activities, the need to travel further to hunt or fish, and land claims and title to land is the third 

highest code (81 occurrences). 

Both the Regulations and Enforcement and Access/Land Loss/Avoidance codes are spread more 

evenly over all meetings. When more meetings are included in the analysis and outliers are accounted 

for, it is hoped that basic code counts will allow for a robust analysis of trends.
7 

Table 1 Code Counts for Nuiqsut Residents’ Testimony on Oil Development

Topic

P 1: 2004_2_10 

Draft Alpine 

Satellite 

Development 

Plan

P 2: 2004_8_9 

Northeast NPR-A 

Amendment 

Draft EIS

P 3: 2010_9_16 

NPR-A IAP 

Scoping

P 4: 2012_5_16 

NPR-A Draft 

IAP

P 5: 2014_3_12 

GMT1 EIS 

Scoping

P 6: 2015_5_30 

GMT1 

Compensatory 

Mitigation 

Funds

P 7: 2015_9_22 

GMT1 

Compensatory 

Mitigation 

Funds

P 8: 2016_3_21 

Nanushuk EIS 

scoping meeting

P 9: 2016_4_22 

Nuiqsut trilateral 

on GMT1 

Compensatory 

Mitigation Funds

P10: 2016_4_22 

GMT1 

Compensatory 

Mitigation 

Funds TOTALS:

Abundance of Fish & Wildlife 8 4 3 3 6 3 3 6 3 2 41

Access/Land Loss/ Avoidance 16 5 7 18 8 4 7 8 5 3 81

Air Quality 5 0 1 8 3 5 0 8 0 1 31

Air Traffic 6 2 3 0 10 0 0 8 0 1 30

Allotment 1 3 1 2 0 0 0 1 0 0 8

Blowout 0 0 0 2 1 2 1 8 0 2 16

Bridges 10 0 2 0 1 1 0 0 0 0 14

Bureaucracy 4 3 11 4 2 4 21 4 9 1 63

Community Capacity 6 0 0 1 1 0 2 0 7 0 17

Climate Change 1 0 1 1 2 0 0 0 0 0 5

Colville River 6 1 4 3 2 2 4 11 13 4 50

Comments 5 3 1 9 0 2 1 2 0 1 24

Conflict 0 0 3 1 4 11 36 6 7 0 68

Cultural Sites 5 2 0 1 0 0 0 0 0 0 8

Cumulative Impacts 12 4 2 6 6 3 7 6 1 2 49

Lack of Power/Disrespect/

Disenfranchisement 10 1 1 3 1 2 17 4 1 0 40

Distrust 9 1 4 9 4 2 14 11 1 2 57

Economy/jobs/

Poverty/royalties 14 6 1 9 5 14 2 7 3 1 62

Environmental Justice 1 0 0 0 0 2 1 0 0 1 5

Fish Creek 5 1 2 2 4 2 4 0 3 6 29

Flooding 5 0 0 0 0 1 0 4 0 0 10

Food (Native & Store-bought) 2 1 1 8 2 0 0 5 1 1 21

Future Generations 7 6 0 9 10 5 6 8 2 0 53

Additional Human Health

Issues 5 3 2 1 1 5 1 4 0 0 22

Hunting (competition, regs, 

Enforcement) 1 0 3 0 0 1 4 3 18 0 30
8 

Topic

P 1: 2004_2_10 

Draft Alpine 

Satellite 

Development 

Plan

P 2: 2004_8_9 

Northeast NPR-A 

Amendment 

Draft EIS

P 3: 2010_9_16 

NPR-A IAP 

Scoping

P 4: 2012_5_16 

NPR-A Draft 

IAP

P 5: 2014_3_12 

GMT1 EIS 

Scoping

P 6: 2015_5_30 

GMT1 

Compensatory 

Mitigation 

Funds

P 7: 2015_9_22 

GMT1 

Compensatory 

Mitigation 

Funds

P 8: 2016_3_21 

Nanushuk EIS 

scoping meeting

P 9: 2016_4_22 

Nuiqsut trilateral 

on GMT1 

Compensatory 

Mitigation Funds

P10: 2016_4_22 

GMT1 

Compensatory 

Mitigation 

Funds TOTALS:

Inupiaq Culture 16 6 2 18 7 2 9 4 3 4 71

Judy Creek 0 0 0 0 1 0 0 0 0 0 1

Lack of Environmental

Analysis 21 0 4 3 12 1 1 3 4 2 51

Lack of Social Analysis 7 1 1 4 3 2 8 2 3 2 33

Legacy Wells 0 0 0 1 0 1 0 3 0 0 5

Meetings 0 2 1 5 2 2 0 1 0 1 14

Migration changes 22 9 3 9 6 3 3 10 1 0 66

Compensatory Mitigation 5 7 4 6 6 28 38 6 58 12 170

Nigliq Channel 9 0 1 2 1 2 0 4 1 2 22

Noise 1 0 0 0 0 1 0 1 0 0 3

Offshore Oil Development 0 0 0 1 1 0 1 0 0 0 3

Oliktok 0 0 0 0 0 0 0 0 0 0 0

Overcrowding 0 0 0 4 0 1 0 0 1 0 6

Pace 2 2 2 3 0 1 3 4 4 2 23

Drill pads & wells 4 0 0 0 2 1 1 5 0 0 13

Pipelines 19 4 6 5 1 0 0 3 0 0 38

Positive Impacts 3 4 2 0 3 0 0 1 23 1 37

Proximity of development 11 1 1 3 4 1 2 7 0 0 30

Roads 14 0 3 2 6 1 1 3 27 1 58

Regulations and Enforcement 14 15 5 7 6 8 7 16 6 1 85

Seismic Exploration 0 0 0 1 0 0 0 0 0 0 1

Oil Spills 3 0 2 0 1 2 0 6 0 2 16

Teshekpuk Lake 1 3 1 2 1 0 3 0 0 0 11

Tingmiaqsigvuk 0 0 0 0 0 0 0 0 0 0 0

Traditional Knowledge 9 1 0 3 4 1 0 0 0 0 18

Umiat 1 0 1 1 1 0 0 1 2 0 7

Vegetation 1 0 0 0 0 0 0 0 0 0 1

Water resources 2 0 3 0 1 0 0 0 0 0 6

Water Quality 0 0 0 2 1 1 0 0 3 1 8

Totals 309 101 95 182 143 130 208 194 210 59 1631
9 

Top code counts can also be depicted with bar graphs that differentiate meetings by color: 

Figure 1 Top Code Counts by Meeting

Code counts by meeting allows for a greater understanding of which meetings may be outliers:

Figure 2 Code Counts by Meetings for Codes “A” through “J” 
10

Figure 3 Code Counts by Meetings for Codes “L” through “W” 

Depicting the code counts by code category indicates that despite the extra attention the permitting 

process was given at recent meetings on the RMS, codes in that category tend to occur at a high 

frequency at most meetings. 

Figure 4 Code Counts by Category
11

As mentioned above, one of the most useful analyses that can be run with the software is exploring 

which codes co-occur with each other. One can look at the top co-occurrences of all codes as is 

shown below, or one can analyze co-occurrences of specific codes. Looking at the frequency of cooccurrences with Distrust, for example, the data shows that its highest co-occurrences are with 

Regulations and Enforcement and Lack of Power/Disenfranchisement (14 times with each). The 

second highest co-occurrence frequency for Distrust is with Cumulative Impacts, Social Conflict, and 

Access/Land Loss: each co-occur with Distrust 9 times. 

Figure 5 Top Code Co-occurrences

0

5

10

15

20

25

30

35

40

45

Top Co-Occurrences Excluding Affiliations and Speakers
12

Figure 6 Top Code Co-occurrences Excluding the Mitigate Code

Another simple output that the software provides is a query report, which extracts all the actual 

testimony for the code or codes you select. A query can search for quotes from the testimony that are 

co-coded with a particularly high number of the top codes, such as this comment which was co-coded 

for Access/Land Loss, Bureaucracy, Community Capacity, Cumulative Impacts, Future Generations, 

and Inupiaq Culture: 

“And I didn't have a written comment, but I just want to say that I represent the elders who 

has no education on reading the EIS draft. They have taught us to live a good life, 

subsistence life, the way Inupiaqs are and that's who we are, and that's who we will continue 

to be when you leave. And I want to say that where were the agencies 30 years ago when 

Prudhoe Bay was being developed? Where were the agencies for our elders who I know have 

lost their rights, hunting rights over at Kuparuk, some on along the Sagavanirktok River? 

Where were the agencies to protect our elders who had once lived in Prudhoe Bay? Where 

were the agencies when Sarah Kunaknana who I know has a sod house in Prudhoe Bay that 

she hasn't gone to see 30 years and was told by industry that she's -- she can't go over there? 

She would for one time would love to go see her sod house, which is in Prudhoe Bay. Where 

were the agencies when my mom and other people from Oliktok were taken -- driven out of 

there because of industry?” 

0

5

10

15

20

25

30

35

Top Co-Occurrences Excluding Affiliations and Speakers and 

Mitigate Code
13

Next Steps

The core transcripts for this first stage are public meetings6 in Nuiqsut on onshore oil development. 

Subsequent stages of the project will expand the scope of meetings to allow users to compare and 

contrast data from those with the core transcripts. The other types of transcripts will include Nuiqsut 

public meetings on offshore oil development, public meetings in other North Slope Borough 

communities on oil development, NPR-A Subsistence Advisory Panel meetings, all-stakeholder 

Regional Mitigation Strategy workshops, NPR-A Working Group meetings, and other sets of 

transcripts that are available. 

Nuiqsut Public Meetings Analyzed in First Stage of Project

1. 2004_2_10 Draft Alpine Satellite Development Plan

2. 2004_8_9 Northeast NPR-A Amendment Draft EIS

3. 2010_9_16 NPR-A IAP Scoping 

4. 2012_5_16 NPR-A Draft IAP

5. 2014_3_12 GMT1 EIS Scoping 

6. 2015_5_30 GMT1 Compensatory Mitigation Funds 

7. 2015_9_22 GMT1 Compensatory Mitigation Funds 

8. 2016_3_21 Nanushuk EIS scoping meeting 

9. 2016_4_22 Nuiqsut trilateral on GMT1 Compensatory Mitigation Funds 

10. 2016_4_22 GMT1 Compensatory Mitigation Funds 

 

6 One of the meetings included in the first ten (2016_4_22 Nuiqsut trilateral on GMT1 Compensatory Mitigation Funds) 

was technically not public; it was between BLM and numerous representatives of the three entities (Tribe, City, and 

Corporation). This transcript is included for now but perhaps should be analyzed separately for comparative purposes in 

the future. The ‘Code Count by Meeting” chart shows that this meeting, as would be expected, focused heavily on 

mitigation. 

Appendices  Final Supplemental Environmental Impact Statement

Alpine Satellite Development Plan for the Proposed Greater Mooses Tooth 2 Development Project

APPENDIX O

ECONOMIC ANALYSIS OF ROADLESS ALTERNATIVE 

WITH SEASONAL DRILLING

Stacie McIntosh 

Arctic Field Office 

Bureau of Land Management 

1150 University Avenue 

Fairbanks, Alaska 99709 

Dear Ms. McIntosh: 

This letter report transmits our findings on the economic analysis related to the Greater Mooses Tooth 

2 (GMT2) project proposed by ConocoPhillips Alaska, Inc. (CPAI). This report is specifically focused on 

Alternative D2, the alternative with both a limited access restriction (no permanent road access) and a 

seasonal drilling restriction. 

This letter report contains the following sections: 

 Executive Summary 

 Introduction and Purpose 

 Approach 

 Data Sources 

 Oil Industry Rates of Return 

 Findings and Comparisons 

Executive Summary 

Based on feedback from the Bureau of Land Management, CPAI requested an independent analysis to 

evaluate the project economics of Alternative D2, one of the alternatives being considered for the 

proposed Greater Mooses Tooth 2 (GMT2) development. This economic analysis was requested to 

support CPAI’s application for environmental permits. The primary objective of the analysis was to 

determine whether Alternative D2 would be economically feasible given its restrictions-- development 

without permanent road access to the facility and seasonal drilling. 

The results of our economic analysis indicate that Alternative D2 would not be economic. The 

environmental restrictions noted above would negatively impact the economics of the proposed 

project. 

Two oil price scenarios were considered in the analysis: 1) the latest Energy Information Administration’s 

long-term price projections (Annual Energy Outlook 2016 with projections to 2040, released on 

September 15, 2016); and 2) the latest Alaska Department of Revenue’s (ADOR) price projections 

(Revenue Sources Book Spring 2016, released on April 7, 2016). 

February 21, 2017 
 

 

EIA Price Scenario 

The results show that under the EIA price scenario (which has an average long-term price of about 

$123/barrel in 2015 $), and assuming a 10 percent real discount rate, Alternative D2 would be 

uneconomic with a negative discounted after-tax cash flow of -$554 million. This is due to both the 

seasonal drilling restriction and the limited access restriction. The seasonal drilling restriction would 

cause a delay in oil production, the subsequent monetizing of the oil resource, and would lower total 

oil production. Furthermore, without year-round road access, a number of facilities and services that 

would be provided at Alpine would need to be built at the GMT2 drill site resulting in a substantial 

increase in capital and operating costs. 

ADOR Price Scenario 

As expected, the results under the ADOR price scenario are similar. Given this low oil price scenario, 

with an average price of about $62 per barrel of oil in 2015 $, the GMT2 development would not be 

economic, assuming a 10 percent real discount rate. Discounted EMV for Alternative D2 was estimated 

to be -$759 million. 

Introduction and Purpose 

CPAI, as operator of the Greater Mooses Tooth Unit (GMTU) is proposing to produce hydrocarbon 

resources from a surface location on federal oil and gas leases in the NPR-A. The proposed Greater 

Mooses Tooth 2 Development Project (GMT2) is the second project proposed to be developed in the 

GMTU, in the Northeast NPR-A on Alaska’s North Slope. The first project is GMT1, where production 

is expected to begin the fourth quarter of 2018. GMT2 was formerly known as the CD7 development 

production pad, one of the five drill sites comprising the Alpine Satellite Development Plan (ASDP), for 

which in 2004 a Final Environmental Impact Statement was prepared by the Bureau of Land 

Management (BLM). GMT2 was also analyzed in the 2012 NPR-A Integrated Activity Plan. In 2014, 

GMT2 development was considered as a reasonably foreseeable future action in the cumulative effects 

analysis of the Supplemental EIS prepared by BLM for GMT1 Development. In October of 2015, a 

modified NEPA Analysis Document (MNAD) was prepared by ConocoPhillips Alaska, Inc. (CPAI) to 

assist federal, state, and North Slope Borough agencies in evaluating CPAI’s permit applications for the 

GMT2 Project by considering relevant new information to determine whether the impacts of the 

proposed project are still within the range of impacts analyzed in the previous environmental impact 

studies noted above. CPAI requested this additional analysis following feedback given by the BLM to 

support the environmental permit process. A similar independent economic analysis was requested by 

the BLM to support the Supplemental EIS for the GMT1 development. 

The currently proposed GMT2 Project will include a drill site on Native selected land in the GMTU, 

with an access road, pipe rack, and pipelines on Native and federal lands to GMT1. The project will 

produce 3-phase hydrocarbons (oil, gas, and water) which will be carried by pipeline (across Native 

and federal lands within the NPR-A and Native and state lands outside) to the ACF at CD1 for 

processing. A new miscible injectant (MI) pipeline will be constructed on state land from the tie-in 

location north of Colville Delta 4 North. Gravel will be obtained from the Arctic Slope Regional 

Corporation (ASRC) mine site outside the NPR-A. Sales quality crude oil produced at the ACF will be 

transported from CD1 via the existing Alpine Sales Oil Pipeline and Kuparuk Pipeline to the TAPS for 

shipment to market. 

CPAI’s proposed alternative (Alternative A) includes a drill pad, a gravel access road to connect to the 

proposed GMT1 development, and pipelines. CPAI proposes to construct the GMT2 facilities on a 2-

year construction schedule in 2019 and 2020. Drilling for Alternative A is expected to begin in May of 

Year 2, with first oil expected at the end of Year 2. Drilling is anticipated to continue year-round for 7 

2 
 

 

 

 

years to complete up to 48 wells. Operations is currently estimated to be 30 years post construction. 

Table 1 provides a summary of the proposed infrastructure for the GMT2 Project. 

Table 1. Summary of Infrastructure for GMT2 Alternative A, Proposed Action 

Component Alternative A Proposed Action 

Gravel Drill Pad 14.0 acres 

Wells up to 48 wells 

GMT1-GMT2 Access Road 8.1 miles, 62.8 acres 

Subsistence Tundra Access Road 

Pullouts 3 pullouts, 1.2 acres (0.4 acre each) 

Elevated Pipelines on VSMs 

8.6 miles from GMT2 to GMT1; 0.1 acres 

9.8 miles, crude oil pipeline from CD5 to CD1/ACF (on existing VSMs) 

3.3 miles, MI pipeline from CD4/CD5 intersection to CD1/ACF (on 

existing VSMs) 

Bridges None 

Gravel Supply ASRC mine site 

Total Gravel Footprint 78.0 acres 

Total Gravel Requirement 671,300 cubic yards 

Ice Roads 52.6 miles (Year1) 

43.9 miles (Year2) 

Source: Modified NEPA Analysis Document, CPAI 2015. 

In addition to the proposed alternative, two other alternatives are being evaluated in consideration of 

anticipated environmental restrictions. Information on these alternatives is taken from the Modified 

NEPA Analysis Document prepared by CPAI. 

Alternative D1 (Roadless Access to GMT2) is similar to Alternative A, but without a gravel access road 

from GMT1 to GMT2 and the rest of the Alpine field development area. Access to the GMT2 site would 

be by aircraft and ice road during the winter. Alternative D1 includes a drill pad, an air strip and 

associated facilities, a local access road, and pipelines. The airstrip provides year-round access to GMT2 

in lieu of a gravel road. A local gravel access road would connect the drill pad, occupied pad, and air 

access facilities (airstrip and apron). During winter, ice roads would be constructed to access the site. 

Movement of the drill rig to and from other drill sites would be limited to the ice road season restricting 

the ability to mobilize and demobilize the rig for work at other drill sites when it cannot work at GMT2. 

Construction and drilling schedule is similar to Alternative A. 

With limited surface access, certain services, equipment, and supplies otherwise provided at the 

CD1/ACF would need to be duplicated at the drill site. A full-time workforce at GMT2 would also be 

required; hence onsite housing facilities will be required (an onsite occupied structure pad will be built). 

GMT2 would be re-supplied during the ice road season, requiring long-term storage of drilling and 

operating fluid and supplies. A new mud plant and bulk cement facility would be required for yearround drilling because the existing plant at CD1/ACF must remain in place to service drilling operations 

at the other satellites. Onsite wastewater and solid waste treatment or management would be required. 

The need for additional facilities at GMT2 under this alternative results in much higher capital 

expenditures compared to Alternative A. 

Alternative D2, which is the focus of this analysis, is very similar to Alternative D1 with the exception 

that a potential seasonal drilling restriction would preclude drilling activities when surface access (i.e., 

ice road) is not available. Drilling would be restricted to the time period when an ice road is available 

from GMT2 and GMT1, typically February to April (seasonal drilling). Once construction is completed, 

3 
 

 

ice roads would be constructed annually along the same route for 37 years to support vehicle access 

for drilling and operation. Operation would be year-round. The restriction to seasonal drilling would 

extend the drilling period and delay production and monetization of the oil resources. 

This restriction would result in about an 80-day drilling season, including the time to mobilize and demobilize the drilling rig from GMT2, which could result in about 1.5 wells being drilled per season. 

The MNAD prepared by CPAI contains more detailed information regarding the alternatives being 

considered for the GMT2 development. 

Approach 

To conduct the analysis, we built upon the economic model developed by the Alaska Department of 

Natural Resources that was originally designed to assist interested parties in evaluating after-tax cash 

flows of oil and/or gas developments on State leases in Cook Inlet and Alaska's North Slope (ANS). We 

used the same model in the work we conducted for the Bureau of Land Management to assess the 

economic merits of the proposed GMT1 development. The DNR North Slope model was modified and 

calibrated for both the GMT1 and GMT2 economic evaluation. 

The DNR model is based on the current fiscal regime; it has a number of input cells that are fixed due 

to statutes or regulations but there are a considerable number of inputs required for the model to 

accurately reflect a proposed project. The major inputs required for the analysis include: 

1. Capital expenditures (CAPEX) 

2. Operating expenditures (OPEX) 

3. Projected production volumes 

4. Tariffs/transportation costs 

5. Crude oil price forecasts 

The economic feasibility of the project alternatives were assessed using the following metrics— 

1. The Internal Rate of Return (IRR) is the discount rate that makes the net present value of all 

cash flows from a particular project equal to zero. The higher the discount rate the more 

attractive the project. 

2. The Expected Monetary Value is the discounted after-tax cash flow; higher numbers are 

preferred and negative after-tax cash flows would likely indicate that the operator would not 

proceed with the project. 

3. The Discounted Profitability Index is similar to a benefit-cost ratio with the discounted aftertax cash flow divided by the discounted CAPEX. A ratio less than 1 would indicate that the 

project is not profitable. 

Data Sources 

Cost Data. The cost data presented by CPAI in the Modified NEPA Analysis Document (MNAD) for 

GMT2 were reviewed and compared to other data sources available to Northern Economics. A primary 

source of data for this work were capital and operating cost estimates developed by IMV Projects, 

Calgary, Alberta and independent research conducted by Northern Economics for an economic model 

that the two firms developed for the Bureau of Ocean Energy Management (BOEM). The model, called 

MAG-PLAN Alaska, was an update of an earlier model developed in the late 1990s and early 2000s. 

While the model focuses on OCS exploration, development, and production activities, it also has capital 

4 
 

cost and operating cost data related to a number of onshore activities and facilities (e.g., onshore 

pipelines, gravel pad and road construction, ice road construction, production facilities, camps, etc.). 

These costs were developed from interviews with contractors and service providers operating on the 

North Slope in 2010, along with extensive internet research. Additional research was undertaken to fill 

in data gaps and update the cost data to reflect changes since 2010. For example, information on day 

rates and total costs per day for drilling onshore wells on the North Slope have increased and 

subsequently decreased since 2010. The IHS Upstream Capital Cost Index provides information on 

historical trends in upstream costs (the index tracks the costs of equipment, facilities, materials and 

personnel (both skilled and unskilled) used in the construction of a geographically diversified portfolio 

of 28 onshore, offshore, pipeline and LNG projects). Generally, costs vary depending on business cycles. 

If future oil prices will more closely follow the DOR forecasted prices (a lower price scenario than the 

EIA price forecast) then future upstream costs could be lower than current and 2010 costs. 

Oil Price Projections. Two oil price scenarios were considered in the analysis: 

1) Energy Information Administration’s (EIA) long-term price projections (Annual Energy Outlook 2016 

with projections to 2040, released on September 15, 2016); and 

2) Alaska Department of Revenue’s (ADOR) price projections (Revenue Sources Book Spring 2016, 

released on April 7, 2016). 

Both of these projections are publicly available and therefore are usually used in economic analyses of 

this nature. The oil price forecasts considered in the analysis are the latest available data from the two 

sources. Table 2 shows the price per barrel of oil for the years covering this analysis (2020 to 2050) 

under the two price scenarios. 

The EIA prices shown in the table are Brent prices expressed in real 2015 dollars. The EIA projections 

cover the period 2016 to 2040; prices beyond 2040 were extrapolated using the annual rate of change 

(2.9 percent year-to-year change) for the period 2020 to 2040 as reflected in the EIA price forecast. 

The ADOR price projections shown in the table are real 2015 dollars for ANS West Coast. ADOR 

projections only cover the period 2016 to 2025; prices beyond 2025 were extrapolated using the 

annual rate of change (1.5 percent year-to-year change) for the last 5 years of the projections (2020 to 

2025). 

Note that the ANS West Coast tracks closer to Brent than WTI since most imported crudes to the West 

Coast which compete with ANS are based on the Brent benchmark, thus ANS West Coast moves in a 

manner similar to Brent. 

As shown in Table 2, the EIA forecasts much higher oil prices compared to ADOR. The long-term 

average price under the EIA projection is about $123 per barrel of oil compared to about $62 under 

the ADOR projection. 

5 
 

Year ADOR Price Projection EIA Price Projection 

2020 48.62 76.57

2021 52.60 81.16

2022 52.56 84.65

2023 52.54 87.11

2024 52.51 89.15

2025 52.49 91.59

2026 53.30 94.63 

2027 54.12 97.18 

2028 54.95 99.33 

2029 55.80 102.23 

2030 56.66 104.00 

2031 57.53 107.23 

2032 58.42 110.50 

2033 59.32 113.85 

2034 60.24 117.39 

2035 61.17 119.64 

2036 62.11 123.29 

2037 63.07 125.51 

2038 64.04 129.21 

2039 65.03 132.08 

2040 66.03 136.21 

2041 67.05 140.19

2042 68.08 144.29

2043 69.13 148.51

2044 70.20 152.84

2045 71.28 157.31

2046 72.38 161.91

2047 73.50 166.64

2048 74.63 171.51

2049 75.78 176.52

2050 76.95 181.68

 

Table 2. Projected Real Price per Barrel of Oil (2015 $) based on latest ADOR and EIA Price Projections 

Sources: Energy Information Administration’s Annual Energy Outlook (EIA, 2016) and Alaska Department of 

Revenue’s Spring Revenue Sources Book (ADOR, 2016). 

Production Volumes. Annual production volumes for Alternative D2 were estimated by Northern 

Economics based on the assumption that the seasonal drilling restriction would result in an 80-day 

drilling season, with about 1.5 wells drilled per season. The production schedule under Alternative D2 

is delayed by several years compared to Alternatives A and D1. The annual production volumes for 

Alternative A and D1 are presented in the MNAD. 

6 
 

 

Pipeline and marine transportation costs forecasts. These are based on the 2016 Revenue Sources 

Book with the average ANS feeder line tariff of $1 subtracted from the ADOR estimate and replaced 

with known tariffs for Alpine and Kuparuk pipelines, plus an estimated operating cost for the GMT1 

and GMT2 multiphase flowlines. 

OPEX data. Data are not readily available to estimate the various OPEX categories in the DNR model, 

so the average ANS OPEX data for the North Slope from the Revenue Sources Book was used. 

Oil Industry Rates of Return 

The outputs from the DNR model provide several metrics to consider when evaluating whether a 

proposed alternative is viable. However, the perspective of viability may be much different for a public 

agency compared to private industry, which may require higher rates of return on their investments. 

The threshold rate of returns and the associated discount rate for most major oil companies are usually 

closely held and considered proprietary information and typically are not available in the public 

domain. To assist in a review of oil industry rates of return, we previously reached out to Mr. Scott 

Susich, a consultant with Energy Management Institute, and Mr. Barry Rodgers of Rodgers Oil and Gas 

Consulting. Mr Susich and Mr. Rogers have lengthy experience in the oil and gas industry and also teach 

Petroleum Economics and related courses. 

In general, the rates of return for evaluating projects that they have seen in the industry over the past 

few years range from 8 to 12 percent with 10 percent (real) being the most common number. If there 

is an assumption of 2 percent inflation, then the nominal rate of return would be 12.2 percent.1

 A 10 

percent real discount rate is also the number most commonly seen in oil and gas industry quarterly or 

annual reports where companies are demonstrating to investors the value of their known and probable 

reserves. As noted by the two experts, the rate of return can help in ranking projects, but when the rates 

are close, other factors such as the after-tax cash flow are used to provide further distinction with the 

largest after-tax cash flows being preferred. Thus, a project may meet the rate of return hurdle but the 

after-tax cash flow or other factors may not be sufficient to meet a company’s requirements. 

The DNR model as modified by Northern Economics uses a 10 percent real discount rate. 

Findings and Comparisons 

The findings under each of the price scenarios considered are presented below. 

Energy Information Administration’s Annual Energy Outlook Price Scenario: 

Table 3 presents the outputs from the modified DNR model for Alternative D2 under the EIA price 

scenario. 

The Expected Monetary Value is the discounted after-tax cash flow, so higher numbers are preferred. 

Alternative D2 has a negative after-tax cash flow, hence, the operator would not likely proceed with 

this project alternative unless significant CAPEX or OPEX changes were possible to generate positive 

after tax cash flows. 

1 The nominal rate of return is calculated as (1+0.1)*(1+0.02)-1 = 0.122 or 12.2% where 0.1 equals the 10 percent 

real rate of return and the 0.02 is the inflation rate of 2 percent. 

7 
 

 

Table 3. Estimated Financial Metrics and Taxes under EIA Price Scenario: Alternative D2 

Model Outputs (Discounted to 2015 $) Value 

Discounted Expected Monetary Value (EMV 2015$ MM) -$554 

Discounted Profitability Index 0.6 

Internal Rate of Return (%) 3% 

Discounted Royalties Paid (2015$ MM) $148 

Discounted State and Local Taxes (2015$ MM) -$188 

Discounted Federal Taxes (2015$ MM) $13 

Source: Northern Economics, Inc. 

The Discounted Profitability Index (DPI) is similar to a benefit-cost ratio with the ratio of the discounted 

after-tax cash flow to the discounted CAPEX. Using this indicator, Alternative D2 is not profitable given 

a DPI of less than 1. 

The Internal Rate of Return (IRR) is the discount rate that makes the net present value of all cash flows 

from a particular project equal to zero. Thus, the higher the discount rate, the more attractive the 

project. As noted above, typical oil industry threshold rate of return requirement can range from 8 to 

12 percent; with 10 percent (real) being the most common number cited in economic analyses. 

Alternative D2 has an IRR of 3 percent, well below the threshold requirement for the oil industry. 

Table 3 above also shows some metrics that are not oriented to the producer but rather provide an 

indicator of returns to other public and private parties. 

Alternative D2 is estimated to generate royalties amounting to $148 million. This amount however 

would be much lower compared to the royalties generated if there were no delays in oil production. 

State and local taxes are primarily severance, ad valorem (property), and corporate income taxes. Local 

governments only participate in the shared ad valorem taxes; the other taxes are reserved for the state. 

The state also has various tax credits that can partially offset the severance tax. The net present value of 

the state and local tax revenues is negative for Alternative D2 due to the large amount of tax credits 

issued early in the project life and the lower production volumes early in the production life due to the 

seasonal drilling restriction. 

Federal tax is primarily corporate income tax which is also affected by the net (total tax revenue less tax 

credits) taxes paid to the state. As state tax credits increase the result is lower net state tax revenue 

which results in greater reported income to the operator for federal income tax purposes. Alternative 

D2 is estimated to generate about $13 million in federal taxes. 

Alaska Department of Revenue’s Price Scenario 

Table 4 presents the results of the analysis under the ADOR price scenario. The latest oil price projection 

published by the Alaska Department of Revenue (Revenue Sources Book Spring 2016) shows lower 

expected oil prices compared to the EIA long-term forecast. ADOR projects an average price of $62 per 

barrel in real prices (2015 $) while the EIA price forecast averages to about $123 per barrel (in 2015 $) 

over the timeframe of the analysis (2020 to 2050). 

As expected, under this lower oil price scenario, the results show that Alternative D2 is uneconomic. 

As shown in Table 4, royalties under this price scenario are estimated to be about $56 million for 

Alternative D2. Because of the lower oil prices under this scenario, royalties are less than the estimated 

8 
 

 

royalties under the EIA price scenario. The discounted state and local taxes as well as federal taxes, or 

loss carry-forwards are negative under this low oil price scenario. 

Table 4. Estimated Financial Metrics and Taxes under ADOR Price Scenario: Alternative D2 

Model Outputs (Discounted to 2015 $) Value 

Discounted Expected Monetary Value (EMV 2015$ MM) -$759 

Discounted Profitability Index 0.4 

Internal Rate of Return (%) N/A 

Discounted Royalties Paid (2015$ MM) $56 

Discounted State and Local Taxes (2015$ MM) -$310 

Discounted Federal Taxes (2015$ MM) -$116 

Source: Northern Economics, Inc. 

Thank you for the opportunity to be involved in this interesting project. If you have any questions 

concerning this letter, report please contact me or Dr. Leah Cuyno at 907.274.5600. 

Sincerely, 

Patrick L. Burden 

Principal Economist 

9 
 

 

 

 

 

 

 

 

 

 

Memorandum 

Date: July 9, 2018 

To: Stephanie Rice, Alaska Bureau of Land Management 

From: Patrick Burden and Leah Cuyno 

Re: GMT-2 Updated Alternative D2 Analysis 

This memorandum transmits the results of the updated economic analysis of Alternative D2 of the 

Greater Mooses Tooth 2 (GMT2) development as described in the Draft Supplemental EIS. 

This analysis considers the following major updates: 

1. A change in the Federal corporate tax rate that went into effect in January 2018 with the passage 

of the "Tax Cuts and Jobs Act". 

2. Changes in certain provisions of the State of Alaska’s oil production tax. 

3. New oil price projections published by the Alaska Department of Revenue and the Energy 

Information Administration. 

4. Changes in capital and operating cost estimates. 

5. Revisions to the projected annual oil production estimates. 

Fiscal Terms 

The analysis was updated using a revised cash flow model developed by the Alaska Department of 

Natural Resources (ADNR) that incorporated recent changes in both State and Federal taxes. Since the 

beginning of 2018, the Federal corporate income tax rate in effect is a flat rate of 21 percent. A summary 

of the key provisions of Alaska’s oil production tax as of January 1, 2018 is presented in the table below. 

Provision Terms: Oil Production in the Alaska North Slope 

Base Tax Rate 35% (applied to production tax value) 

Minimum Tax Floor Up to 4% of the Gross Value at Point of Production. 4% rate applies when the 

Alaska North Slope price is more than $25/barrel. (applied to Gross Value at Point 

of Production) 

Gross Value Reduction For new oil, 20% or 30% of gross value excluded from the Base tax calculation; 

limited to first seven years of production; benefit ends early if the average ANS 

price exceeds $70 for any three years. 

Per-Taxable-Barrel 

Credit for Non-GVR 

Production 

Sliding scale $0/barrel to $8/barrel. $8 credit applies when wellhead price is less 

than $80/ barrel. Cannot be used to reduce tax below the minimum tax. Cannot 

be carried forward to subsequent year. 

Per-Taxable-Barrel 

Credit for GVR 

Production 

$5/barrel, no sliding scale. Cannot be carried forward to subsequent year. When 

used alongside non-GVR eligible oil credit, cannot reduce tax below the minimum 

tax. 

Lease Expenditures 

Carryforward Deduction 

Beginning Jan. 1, 2018, a company may carry forward lease expenditures not 

deducted against tax, and may apply in future year to reduce liability to minimum 

tax, contingent on the production from the area earned. Carryforwards reduce in 

value by one-tenth each year beginning in the eighth or 11th year after it is 

earned. 
 

 

Oil Price Projections. Two oil price scenarios were considered in the analysis: 

1) Energy Information Administration’s (EIA) long-term price projections (Annual Energy Outlook 2018 

with projections to 2050, released on February 6, 2018); and 

2) Alaska Department of Revenue’s (ADOR) price projections (Revenue Sources Book Spring 2018, 

released on March 16, 2018). 

The table below shows the price per barrel of oil in real dollars (2017 $) for the years covering the 

production phase of the analysis. The ADOR price projections shown in the table are ANS West Coast. 

ADOR projections only cover the period 2018 to 2027; prices beyond 2027 were extrapolated using 

the annual rate of change for the period 2018 to 2027. The long-term average oil price per barrel under 

the EIA projection is about $99.70 compared to about $60.80 under the ADOR projection. 

Projected Real Price per Barrel of Oil (2017 $) based on latest EIA and ADOR Price Projections 

Year EIA ADOR 

2022 80.55 59.95 

2023 82.95 60.38 

2024 84.51 59.90 

2025 85.70 60.26 

2026 87.47 60.57 

2027 88.66 60.04 

2028 90.31 60.11 

2029 91.80 60.19 

2030 92.82 60.27 

2031 94.87 60.34 

2032 95.84 60.42 

2033 97.17 60.50 

2034 98.74 60.58 

2035 99.87 60.65 

2036 100.32 60.73 

2037 102.77 60.81 

2038 103.92 60.88 

2039 104.87 60.96 

2040 106.08 61.04 

2041 107.21 61.12 

2042 107.77 61.19 

2043 108.46 61.27 

2044 109.41 61.35 

2045 110.04 61.43 

2046 110.39 61.51 

2047 111.14 61.58 

2048 112.10 61.66 

2049 112.99 61.74 

2050 113.56 61.82 

2 
 

 

 

 

 

 

 

 

Updated CAPEX Estimates. CAPEX estimates were updated based on data from the ADNR revised cash 

flow model, as well as information from Attanasi and Freeman (2007) that changed some of the 

allocation between CAPEX for facilities and CAPEX for development drilling. The revised cost data 

remained comparable to the CAPEX estimate used in the previous economic analysis of Alternative D2. 

The capital costs in the model were also adjusted to 2017 dollars using the IHS Upstream Capital Cost 

Index which provides information on historical trends in upstream costs (the index tracks the costs of 

equipment, facilities, materials and personnel (both skilled and unskilled) used in the construction of a 

geographically diversified portfolio of 28 onshore, offshore, pipeline and LNG projects). 

Updated OPEX Estimate. The annual operating cost estimate in the revised model reflects the prevailing 

operating costs in the Alaska North Slope- a fixed $/well/year estimate of $300,000 and a variable 

operating cost component of $10 per barrel of oil. These were the default values in the ADNR revised 

cash flow model. 

Revised Production Volumes. CPAI provided an updated oil production profile for their proposed 

project alternative (Alternative A). Given the increase in the total production volumes and the change 

in the decline rate, Northern Economics revised the annual production volumes for Alternative D2 

accordingly. The revised production profile for Alternative D2 is based on the assumption that the 

seasonal drilling restriction would result in an 80-day drilling season, with 2 wells drilled per season. 

The production schedule under Alternative D2 is delayed by several years compared to Alternative A. 

Findings 

The results show that Alternative D2 would not be economic under any of the price scenarios 

considered given the changes in fiscal terms, updated production volumes, and updated oil price 

assumptions and costs (see table below). 

The results show that under the EIA price scenario (which has an average long-term price of about 

$99.7/barrel in 2017 $), and assuming a 10 percent real discount rate, Alternative D2 would be 

uneconomic with a negative discounted after-tax cash flow (Producer’s NPV) of -$498 million, and an 

Internal Rate of Return (IRR) of 6 percent. This IRR is below the discount rate (10 percent) or the typical 

threshold for oil industry rate of return. 

The results under the ADOR price scenario are similar. Given an even lower oil price scenario, with an 

average price of about $60.8 per barrel of oil in 2017 $, the discounted Producer’s NPV for Alternative 

D2 was estimated to be -$871 million with an IRR of 1 percent. 

Estimated Financial Metrics under the ADOR and EIA Price Projections 

Model Outputs (Discounted) Expected Value 

ADOR Price Scenario EIA Price Scenario 

Producer’s Net Present Value (NPV) ($MM) -871 -498 

Internal Rate of Return (IRR) (%) 1.1% 6.0% 

State Royalty Revenue ($MM) $83 $132 

State Property Tax ($MM) $168 $168 

State Production Tax ($MM) $22 $111 

Federal Royalty Revenue ($MM) $79 $132 

Federal Corporate Income Tax $51 $468 

3 
Appendices  Final Supplemental Environmental Impact Statement

Alpine Satellite Development Plan for the Proposed Greater Mooses Tooth 2 Development Project

APPENDIX P

ALPINE OIL DISCHARGE PREVENTION AND 

CONTINGENCY PLAN

 

 

 

Oil Discharge Prevention 

and Contingency Plan 

Alpine Field and Satellites and 

Alpine Pipeline System 

Western North Slope, Alaska 

Approved February 2018 

ADEC Plan No. 17-CP-4140 

EPA FRP AKA0236 

DOT Sequence No. 1476 

 

 

 

ALPINE FIELD AND SATELLITES 

AND 

ALPINE PIPELINE SYSTEM 

WESTERN NORTH SLOPE, ALASKA 

OIL DISCHARGE PREVENTION 

AND 

CONTINGENCY PLAN 

Approved February 2018 
BLANK PAGE
THE STATE 

01ALASKA 

GOVERNOR BI LL WALKER 

Department of

Environmental Conservation 

DIVISION OF SPILL PREVENTION AND RESPONSE 

Prevention, Preparedness, and Response Program 

555 Cordova Stree t 

Anchorage, AK 99501 -2617 

Main: 907-269-7557 

Fax: 907-269-7687 

www.dec.alaska .gov 

OIL DISCHARGE PREVENTION AND 

CONTINGENCY PLAN APPROVAL 

Febrnary 16, 2018 

Jeanie Shifflett 

ConocoPhillips Alaska, Inc. 

PO Box 100360 

Anchorage, AK 99 510 

Subject: ConocoPhillips Alaska, Inc. Alpine Field and Satellites and Alpine Pipeline System 

Oil Discharge Prevention and Contingency Plan, ADEC Plan#: 17-CP-4140; 

Plan Approval 

Dear Ms. Jeanie Shifflett: 

The Alaska Department of Environmental Conservation ( department) has completed its review of the plan 

renewal application package for the ConocoPhillips Alaska, Inc. Alpine Field and Satellites and Alpine 

Pipeline System Oil Discharge Prevention and Contingency Plan (plan) that was received on July 28, 2017. 

The department coordinated the State of Alaska's public review for compliance with 18 AAC 75, using the 

review procedures outlined in 18 AAC 75.455. Based on our review, the department has determined that 

your plan is consistent with the applicable requirements of the referenced regulations and is hereby 

approved. 

This approval applies to the following plan: 

Plan Title: ConocoPhillips Alaska, Inc. Alpine Field and Satellites and Alpine Pipeline 

System Oil Discharge Prevention and Contingency Plan 

Documents: Alaska Clean Seas Technical Manual 

Plan Holder: ConocoPhillips Alaska, Inc., Anchorage, AK 

Covered Facilities: Production facilities at CD1, CO2, CD3, CD4, CDS, and GMT1; the 14-inch 

crude oil transmission pipeline and 2-inch diesel line from Alpine's CD1 to 

Kuparuk River Unit's CPF2; and associated flow lines, regulated tanks, and 

facility piping 

PLAN APPROVAL: The approval for the referenced plan is hereby granted effective February 16, 

2018. A Certificate of Approval stating that the department has approved the plan is enclosed. 

Facility#: 5138 
Jeanie Shifflett 2 Febmary 16, 2018 

ConocoPhillips Alaska, Inc. 

EXPIRATION: This approval expires February 15, 2023. Following expiration, Alaska law prohibits 

operation of the facility until an approved plan is once again in effect. 

CONDITION(S) OF APPROVAL: The approval is subject to the following condition: 

1. Blowout Contingency Plan. A copy of the Blowout Contingency Plan (BCP) must be 

maintained at Alpine and made available to the department upon request. A copy of the BCP must 

be made available for review by the Alaska Oil and Gas Conservation Commission upon request. 

This co11ditio11 is necessary to enst1re that the plan holder is prepared to co11tro! a potential JPell blowout. 

18 AAC 75.425(e)(1)(I), 18 AAC.445(d)(2), and 18 AAC 75.480. 

TERMS: The approval is subject to the following terms: 

1. PROOF OF FINANCIAL RESPONSIBILITY: The plan holder has provided the department 

with proof of financial responsibility per the requirements of AS.46.04.040 and 18 AAC 75.205 -

18 AAC 75.290. 

2. PUBLICATION OF PLAN: The plan holder shall provide copies of the approved plan to the 

parties and in the format indicated in the enclosed distribution list in accordance with 18 AAC 

75.408(c) not later than 30 days of this approval. 

3. AMENDMENT: Except for routine updates under 18 AAC 75.415(6), an application for 

approval of an amendment must be submitted by the plan holder and approved by the department 

before a change to this plan may take effect. This is to ensure that changes to the plan do not 

diminish the plan holder's ability to respond to a discharge and to evaluate any additional 

environmental considerations that may need to be taken into account (18 AAC 75.415). 

4. RENEWAL: To renew this plan, the plan holder must submit an application package to the 

department no later than 180 days prior to the expiration of this approval. This is to ensure that 

the submitted plan is approved before the current plan in effect expires (18 AAC 75.420). 

5. REVOCATION, SUSPENSION OR MODIFICATION: This approval is effective only while 

the plan holder is in compliance with the plan as defined in AS 46.04.030(r) and with all of the 

terms and conditions described above. The department may, after notice and opportunity for a 

hearing, revoke, suspend, or require modification of the approved plan if the plan holder is not in 

compliance with the plan or for any other reason stated in AS 46.04.030(£). In addition, Alaska law 

provides that a vessel or facility that is not in compliance with a plan may not operate (AS 

46.04.030). The department may terminate approval prior to the expiration date if deficiencies are 

identified that would adversely affect spill prevention, response or preparedness capabilities. 

6. DUTY TO RESPOND: Notwithstanding any other provisions or requirements of this plan, a 

person causing or permitting the discharge of oil is required by law to immediately control, contain, 

and cleanup the discharge regardless of the adequacy or inadequacy of the plan (AS 46.04.020). 

7. NOTIFICATION OF NON-READINESS: The plan holder must notify the department in 

writing, within 24 hours, after any significant response equipment as specified in the plan is 

removed from its designated storage location or becomes non-operational. This notification must 

provide a schedule for equipment substitution, repair, or return to service as described in 18 AAC 

75.475(6). 
Jeanie Shifflett 3 Febrnary 16, 2018 

ConocoPhillips Alaska, Inc. 

8. CIVIL AND CRIMINAL SANCTIONS: Failure to comply with the plan may subject the plan 

holder to civil liability for damages and to civil and criminal penalties. Civil and criminal sanctions 

may also be imposed for any violation of AS 46.04, any regulation issued thereunder or any 

violation of a lawful order of the department. 

9. INSPECTIONS, DRILLS, RIGHTS TO ACCESS, AND VERIFICATION OF 

EQUIPMENT, SUPPLIES, AND PERSONNEL: The department has the right to verify the 

ability of the plan holder to carry out the provisions of this plan and to access inventories of 

equipment, supplies, and personnel through such means as inspections and discharge exercises 

without prior notice to the plan holder. The department has the right to enter and inspect the 

facility in a safe manner at any reasonable time for these purposes and to othe1wise ensure 

compliance with the plan and the terms and conditions [AS 46.04.030(e) and AS 46.04.060]. The 

plan holder shall conduct exercises for the purpose of testing the adequacy of the plan and its 

implementation (18 AAC 75.480 and 485). 

10. FAILURE TO PERFORM: In granting approval of the plan, the department has determined 

that the plan, as represented to the department by the applicant in the application package for 

approval, satisfies the minimum planning standards and other requirements established by 

applicable statutes and regulations, taking as true all information provided by the applicant. The 

department does not warrant to the applicant, the plan holder, or any other person or entity: 

(1) the accuracy or validity of the information or assurances relied upon; (2) that the plan is or will 

be implemented; or (3) that even full compliance and implementation with the plan will result in 

complete containment, control or clean-up of any given oil spill, including a spill specifically 

described in the planning standards. The plan holder is encouraged to take any additional 

precautions and obtain any additional response capability it deems appropriate to further guard 

against the risk of oil spills and to enhance its ability to comply with its duty under AS 46.04.020(a) 

to immediately contain and clean up an oil discharge. 

11. COMPLIANCE WITH APPLICABLE LAWS: The plan holder must adhere to all applicable 

state statutes and regulations as they may be amended from time to time. This approval does not 

relieve the plan holder of the responsibility to secure other federal, state, or local approvals or 

permits or to comply with all other applicable laws. 

12. INFORMAL REVIEWS AND ADJUDICATORY HEARINGS: If aggrieved by the 

department's decision, the applicant or any person who submitted comments on the application 

not later than the close of the public comment period set out under 18 AAC 75.455 may request an 

adjudicatory hearing in accordance with 18 AAC 15.195 - 18 AAC 15.340 or an informal review by 

the Division Director in accordance with 18 AAC 15.185. 

Informal review requests must be delivered to the Director, Spill Prevention and Response, 

555 Cordova Street, Anchorage, Alaska 99501, not later than 20 days of the issuance of the plan 

approval. A request for informal review is not required prior to making a request for adjudicatory 

hearing. A copy of the request should be sent to the undersigned. 

Adjudicatory hearing requests must be delivered to the Commissioner, Department of 

Environmental Conse1vation, 410 Willoughby Avenue, Suite 303,Juneau, Alaska 99801, within 30 

days of the plan approval. If a hearing is not requested within 30 days, the right to appeal is 

waived. A copy of a hearing request must be se1ved on the undersigned and the permit applicant as 

required by 18 AAC 15.200(c). A copy of the request must also be provided to the department in 
 

Jeanie Shifflett 4 Febmary 16, 2018 

ConocoPhillips Alaska, Inc. 

an electronic format, unless the department waives this requirement because the requestor lacks a 

readily accessible means or the capability to provide the items in an electronic format. 

13. NOTICE OF CHANGED RELATIONSHIP WITH RESPONSE CONTRACTOR: 

Because the plan relies on the use of response contractor(s) for its implementation, the plan holder 

must immediately notify the department in writing of any change in the contractual relationship 

with the plan holder's response contractor(s), and of any event including but not limited to any 

breach by either party to the response contract that may excuse a response contractor from 

performing, that indicates a response contractor may fail or refuse to perform, or that may 

otherwise affect the response, prevention, or preparedness capabilities described in the approved 

plan. 

If you have any questions regarding this process, please contact Laurie Silfven at 907-269-7540 or 

laurie.silfven ~a. ov. 

Enclosures: Certificate of Approval, Number: 18CER-007 

Summary of Basis for Decision 

Approved Plan Distribution List 

cc with enclosure: 

Tom DeRuyter, ADEC 

Laurie Silfven, ADEC 

Colin Taylor, ADEC 

C-Plan Reviewer, ADNR 

DNR C-Plan, ADNR NRO 

Bob Whittier, USEP A 

Jason Walsh, ADNR 

Jack Winters, ADF&G 

Gordon Brower, NSB 

Price Leavitt, NSB 

USCG, Western Alaska Facilities 

David Lehman, USDOT 

Donna Wixon, BLM 

Elisabeth Dabney, NAEC 

Lois Epstein, The Wilderness Society 

Planning Manager, Alaska Clean Seas 
Certificate Number: 

Plan Title: 

Covered Facility(s): 

Plan Holder: 

Address: 

Telephone: 

Region(s) of Operation 

(18 AAC 75.495): 

Alaska Department of Environmental Conservation 

Oil Discharge Prevention and Contingency Plan 

Certificate of Approval 

18CER-007 Plan Number: 17-CP-4140 

ConocoPhillips Alaska, Inc. Alpine Field and Satellites and Alpine Pipeline System Oil Discharge Prevention and 

Contingency Plan 

Production facilities at CDl, CO2, CD3, CD4, CDS, and GMTl; the 14-inch crude oil transmission pipeline and 2-

inch diesel line from Alpine's CDl to Kuparuk River Unit's CPF2; and associated flow lines, regulated tanks, and 

facility piping 

ConocoPhillips Alaska, Inc. 

P.O. Box 100360, Anchorage, AK 99510 

907-265-6488 Fax: 907-265-6235 

North Slope 

Effective Date of Approval: February 16, 2018 Expiration Date: February 15, 2023 

This approval is subject to the terms and conditions of the applicable Alaska Department of Environmental Conservation contingency plan approval letter dated 

2/16/2018 and continuing compliance with the requirements of .04 and 18 AAC 75. 

Graham Wood, Approving Authority 

Prevention, Preparedness and Response Program Manager 

CONOCOPHILLIPS ALASKA 

OIL DISCHARGE PREVENTION AND CONTINGENCY PLAN 

ALPINE FIELD AND SATELLITES AND ALPINE PIPELINE SYSTEM 

WESTERN NORTH SLOPE, ALASKA 

MANAGEMENT APPROVAL AND RESOURCE COMMITMENT STATEMENT 

This Oil Discharge Prevention and Contingency Plan (ODPCP) is prepared for oil production facility and oil 

pipeline facility activities conducted by ConocoPhillips Alaska (COPA) within the Colville River Unit and 

Greater Mooses Tooth Unit on the Western North Slope of Alaska. 

This plan is approved for implementation as herein described. Manpower, equipment, and materials will be 

provided as required in accordance with this plan. 

Manager, Western North Slope Operations 

ConocoPhillips Alaska 

Alpine Field, Satellites, and Pipelines ODPCP February 2018, Rev. O 

Date 
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Alpine Field, Satellites, and Pipelines ODPCP ii February 2018, Rev. 0 
 

 

 

 

RECORD OF REVISIONS 

REVISION 

NUMBER REVISION DATE SUMMARY OF REVISION 

0 February 2018 5-Year renewal revision of entire plan. 

1 April 2018 

Section 3.1.1: update owner/operator information to “ConocoPhillips 100%”. Revise 

Appendix D: Table D-3, add back two Rain for Rent tanks (#’s 254993, 255141); 

Table D-4, add seven Schlumberger tanks available for use (2SSF48256, 

2SSF48257, 2SSF48258, 2SSF48259, 2SSF48260, 2SSF48261, 2SSF48262). 

2 May 2018 

Section 1.8: update CD5 facility diagram to include tank farm and TTLA; Section 

2.1.10 Table 2-3 to include CD5 TTLA; Appendix D: Table D-1 add tank CF-T505031 and update product type for CF-T-50090. 

Alpine Field, Satellites, and Pipelines ODPCP iii May 2018, Rev. 2 
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Alpine Field, Satellites, and Pipelines ODPCP iv February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TABLE OF CONTENTS 

MANAGEMENT APPROVAL AND RESOURCE COMMITMENT................................................................ i 

RECORD OF REVISIONS........................................................................................................................... iii 

TABLE OF CONTENTS ............................................................................................................................... v 

List of Appendices.......................................................................................................................... viii 

List of Figures...................................................................................................................................ix 

List of Tables.................................................................................................................................... x 

List of Acronyms..............................................................................................................................xii 

INTRODUCTION.........................................................................................................................................I-1 

Plan Contents.................................................................................................................................I-2 

Plan Supplemental Documention...................................................................................................I-2 

Plan Distribution .............................................................................................................................I-4 

Plan Updating and Renewal ..........................................................................................................I-4 

PART 1 RESPONSE ACTION PLAN [18 AAC 75.425(e)(1)].............................................................1-1 

1.1 EMERGENCY ACTION CHECKLIST [18 AAC 75.425(e)(1)(A)].....................................1-1 

1.2 REPORTING AND NOTIFICATION [18 AAC 75.425(e)(1)(B)] .......................................1-4 

1.2.1 Initial Reporting and Notification [18 AAC 75.425(e)(1)(B)(i)].............................1-4 

1.2.2 External Reporting and Notification [18 AAC 75.425(e)(1)(B)(ii)] .......................1-6 

1.3 SAFETY [18 AAC 75.425(e)(1)(C)]..................................................................................1-8 

1.4 COMMUNICATIONS [18 AAC 75.425(e)(1)(D)] ..............................................................1-9 

1.5 DEPLOYMENT STRATEGIES [18 AAC 75.425(e)(1)(E)] .............................................1-11 

1.5.1 Transport Procedures [18 AAC 75.425(e)(1)(E)(i)]...........................................1-11 

1.5.2 Notification and Mobilization of Response Action Contractor [18 AAC 

75.425(e)(1)(E)(ii)].............................................................................................1-12 

1.6 RESPONSE SCENARIOS AND STRATEGIES [18 AAC 75.425(e)(1)(F), 18 AAC 

75.425(e)(1)(I), AND 18 AAC 75.445(d)] .......................................................................1-13 

1.6.1 Qualifier Statement ...........................................................................................1-13 

1.6.2 Temporary Storage and Disposal [18 AAC 75.425(e)(1)(F)(x)]........................1-13 

1.6.3 Response Scenarios and Strategies [18 AAC 75.425(e)(1)(F) and (I)]............1-15 

1.7 NON-MECHANICAL RESPONSE OPTIONS [18 AAC 75.425(e)(1)(G)] ......................1-65 

1.7.1 Obtaining Permits and Approvals .....................................................................1-65 

1.7.2 Decision Criteria for Use ...................................................................................1-65 

1.7.3 Implementation Procedures ..............................................................................1-65 

1.7.4 Required Equipment and Personnel.................................................................1-65 

1.8 FACILITY DIAGRAMS [18 AAC 75.425(e)(1)(H)]..........................................................1-66 

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1.9 RESPONSE SCENARIO FOR AN EXPLORATION OR PRODUCTION FACILITY 

[18 AAC 75.425(e)(1)(I)] ................................................................................................1-81 

1.9.1 Response Strategy to Control a Well Blowout [18 AAC 425(e)(1)(I) and 18 

AAC 75.445(d)(2)].............................................................................................1-81 

1.9.2 Response Scenario Typical Environmental Conditions [18 AAC 

75.425(e)(1)(I)(iii)] .............................................................................................1-82 

PART 2 PREVENTION PLAN [18 AAC 75.425(e)(2)] ........................................................................2-1 

2.1 DISCHARGE PREVENTION PROGRAMS [18 AAC 75.425(e)(2)(A)]............................2-1 

2.1.1 Oil Discharge Prevention Training [18 AAC 75.020]...........................................2-1 

2.1.2 Substance Abuse Program [18 AAC 75.007(e)].................................................2-1 

2.1.3 Medical Monitoring [18 AAC 75.007(e)]..............................................................2-2 

2.1.4 Security and Surveillance Programs [18 AAC 75.007(f)]....................................2-2 

2.1.5 Fuel Transfer Procedures [18 AAC 75.025]........................................................2-2 

2.1.6 Operating Requirements for Exploration and Production Facilities [18 AAC 

75.045] ................................................................................................................2-3 

2.1.7 Requirements for Flowlines and Facility Oil Piping [18 AAC 75.047 and 18 

AAC 75.080]........................................................................................................2-4 

2.1.8 Leak Detection, Monitoring, and Operating Requirements for Crude Oil 

Transmission Pipelines [18 AAC 75.055] ...........................................................2-9 

2.1.9 Shop-Fabricated Aboveground Oil Storage Tanks [18 AAC 75.066] ...............2-10 

2.1.10 Secondary Containment Areas for Aboveground Oil Storage Tanks [18 

AAC 75.075]......................................................................................................2-13 

2.2 DISCHARGE HISTORY [18 AAC 75.425(e)(2)(B)] .......................................................2-17 

2.3 POTENTIAL DISCHARGE ANALYSIS [18 AAC 75.425(e)(2)(C)] ................................2-21 

2.4 CONDITIONS INCREASING RISK OF DISCHARGE [18 AAC 75.425(e)(2)(D)]..........2-25 

2.5 DISCHARGE DETECTION [18 AAC 75.425(e)(2)(E)]...................................................2-27 

2.5.1 Drill Sites and Production Facilities...................................................................2-27 

2.5.2 Alpine Oil Pipeline.............................................................................................2-27 

2.5.3 Facility Oil Piping and Flowline .........................................................................2-29 

2.5.4 Aboveground Oil Storage Tanks.......................................................................2-29 

2.6 WAIVERS [18 AAC 75.425(e)(2)(F)]..............................................................................2-30 

PART 3 SUPPLEMENTAL INFORMATION [18 AAC 75.425(e)(3)] ..................................................3-1 

3.1 FACILITY DESCRIPTION AND OPERATIONAL OVERVIEW [18 AAC 

75.425(e)(3)(A)]................................................................................................................3-1 

3.1.1 Facility Ownership and General Site Description [18 AAC 75.425(e)(3)(A)] ......3-1 

3.1.2 Facility Oil Storage Containers [18 AAC 75.425(e)(3)(A)(i) and (ii)]...................3-2 

3.1.3 Transfer Procedures [18 AAC 75.425(e)(3)(A)(vi)].............................................3-2 

3.1.4 General Description of Pipelines and Processing Facilities [18 AAC 

75.425(e)(3)(A)(vii)].............................................................................................3-3 

3.2 RECEIVING ENVIRONMENT [18 AAC 75.425(e)(3)(B)] ..............................................3-10 

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3.2.1 Potential Routes of Discharge Travel to Open Water [18 AAC 

75.425(e)(3)(B)(i)] .............................................................................................3-15 

3.2.2 Estimate of Response Planning Standard Volume to Reach Open Water 

[18 AAC 75.425(e)(3)(B)(ii)] ..............................................................................3-15 

3.3 COMMAND SYSTEM [18 AAC 75.425(e)(3)(C)]...........................................................3-17 

3.4 REALISTIC MAXIMUM RESPONSE OPERATING LIMITATIONS [18 AAC 

75.425(e)(3)(D)] .............................................................................................................3-26 

3.4.1 Introduction .......................................................................................................3-26 

3.4.2 Weather and Ice Conditions During the Shoulder Seasons .............................3-26 

3.4.3 In Situ Burning Response Measures to Reduce Environmental 

Consequences of a Spill in Ice Conditions .......................................................3-27 

3.4.4 Environmental Conditions .................................................................................3-32 

3.4.5 Colville River Delta............................................................................................3-33 

3.4.6 Fish Creek Basin...............................................................................................3-35 

3.5 LOGISTICAL SUPPORT [18 AAC 75.425(e)(3)(E)] ......................................................3-36 

3.6 RESPONSE EQUIPMENT [18 AAC 75.425(e)(3)(F)]....................................................3-37 

3.6.1 Equipment Lists.................................................................................................3-37 

3.6.2 Pre-Staged and Pre-Deployed Response Equipment ......................................3-37 

3.6.3 Maintenance and Inspection of Response Equipment .....................................3-39 

3.7 NON-MECHANICAL RESPONSE INFORMATION [18 AAC 75.425(e)(3)(G)] .............3-43 

3.7.1 Environmental Consequences and Protection of Sensitive Areas ...................3-43 

3.7.2 Operational Capability.......................................................................................3-44 

3.7.3 Effectiveness of In Situ Burning in Ice ..............................................................3-44 

3.7.4 Permits, Approvals, and Authorizations............................................................3-44 

3.8 RESPONSE CONTRACTOR INFORMATION [18 AAC 75.425(e)(3)(H)].....................3-46 

3.9 RESPONSE TRAINING PROGRAM [18 AAC 75.425(e)(3)(I)] .....................................3-50 

3.9.1 NSSRT Spill Response Training.......................................................................3-50 

3.9.2 IMT Member Training........................................................................................3-50 

3.9.3 Auxiliary Contract Response Team ..................................................................3-50 

3.9.4 Other Training ...................................................................................................3-50 

3.9.5 Recordkeeping..................................................................................................3-51 

3.9.6 Spill Response Exercises .................................................................................3-51 

3.10 PROTECTION OF ENVIRONMENTALLY SENSITIVE AREAS [18 AAC 

75.425(e)(3)(J)] ..............................................................................................................3-53 

3.10.1 Persistence and Toxicity Effects of Products in the Environment [18 AAC 

75.425(e)(3)(J)(ii)] .............................................................................................3-54 

3.10.2 Prediction of Discharge Movement...................................................................3-55 

3.10.3 Information on Probable Points of Contact .......................................................3-56 

3.11 ADDITIONAL INFORMATION [18 AAC 75.425(e)(3)(K)]..............................................3-57 

3.12 BIBLIOGRAPHY [18 AAC 75.425(e)(3)(L)] ...................................................................3-58 

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PART 4 BEST AVAILABLE TECHNOLOGY [18 AAC 75.425(e)(4)]................................................4-1 

4.1 COMMUNICATIONS [18 AAC 75.425(e)(4)(A)(i)] ...........................................................4-1 

4.2 SOURCE CONTROL [18 AAC 75.425(e)(4)(A)(i)]...........................................................4-1 

4.2.1 Well Source Control ............................................................................................4-1 

4.2.2 Pipeline Source Control ......................................................................................4-2 

4.2.3 Tank Source Control ...........................................................................................4-3 

4.3 TRAJECTORY ANALYSES AND FORECASTS [18 AAC 75.425(e)(4)(A)(i)]...............4-11 

4.4 WILDLIFE CAPTURE, TREATMENT, AND RELEASE PROGRAMS [18 AAC 

75.425(e)(4)(A)(i)] ..........................................................................................................4-11 

4.5 CATHODIC PROTECTION FOR FIELD-CONSTRUCTED OIL STORAGE TANKS 

[18 AAC 75.425(e)(4)(A)(ii)] ...........................................................................................4-11 

4.6 LEAK DETECTION SYSTEM FOR FIELD-CONSTRUCTED OIL STORAGE 

TANKS [18 AAC 75.425(e)(4)(A)(ii)]..............................................................................4-11 

4.7 LIQUID LEVEL DETERMINATION [18 AAC 75.425(e)(4)(A)(ii)]...................................4-11 

4.8 MAINTENANCE PROCEDURES FOR BURIED STEEL FACILITY OIL PIPING [18 

AAC 75.425(e)(4)(A)(ii)] .................................................................................................4-16 

4.9 PROTECTIVE COATING AND CATHODIC PROTECTION FOR FACILITY OIL 

PIPING [18 AAC 75.425(e)(4)(A)(ii)]..............................................................................4-16 

4.9.1 Pipeline Corrosion Protective (Anti-Corrosion) Wrapping or Coating...............4-16 

4.9.2 Cathodic Protection System..............................................................................4-17 

4.10 CORROSION SURVEYS [18 AAC 75.425(e)(4)(A)(ii)] .................................................4-17 

4.11 PIPELINE LEAK DETECTION, MONITORING, AND OPERATIONS [18 AAC 

75.425(e)(4)((A)(iv)] .......................................................................................................4-17 

4.11.1 Aboveground Crude Oil Transmission Pipeline ................................................4-17 

4.11.2 Belowground Crude Oil Transmission Pipeline ................................................4-18 

PART 5 RESPONSE PLANNING STANDARD [18 AAC 75.425(e)(5)] .............................................5-1 

5.1 STORAGE TANK RUPTURE ..........................................................................................5-1 

5.2 PRODUCTION WELL BLOWOUT [18 AAC 75.434] .......................................................5-1 

5.3 CRUDE OIL TRANSMISSION PIPELINE SPILL TO MILUVEACH RIVER [18 AAC 

75.436] .............................................................................................................................5-2 

5.4 CRUDE OIL TRANSMISSION PIPELINE SPILL TO KACHEMACH RIVER [18 

AAC 75.436].....................................................................................................................5-3 

5.5 CRUDE OIL TRANSMISSION PIPELINE SPILL TO COLVILLE RIVER [18 AAC 

75.436] .............................................................................................................................5-4 

APPENDICES 

A Federal Response Plans – OPA 90 Addendum 

B Alpine Project: Oil Pipeline Spill Isolation Strategy 

C Alpine Oil Spill History 

D ADEC Regulated Oil Storage Tanks 

E ADEC Letters of Approval 

Alpine Field, Satellites, and Pipelines ODPCP viii February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

LIST OF FIGURES 

1-1: Immediate Spill Notification Process ..................................................................................................1-3 

1-2: Spill Report Notification.......................................................................................................................1-5 

1-3: Well Blowout in - Summer Wind Rose Diagram ...............................................................................1-29 

1-4: Simulated Oil Plume Trajectory for Summer Blowout ......................................................................1-30 

1-5: Simulated Oil Plume Trajectory for Summer Blowout - Pad Detail ..................................................1-31 

1-6: Well Blowout in Winter - Wind Rose Diagram ..................................................................................1-43 

1-7: Simulated Oil Plume Trajectory for Winter Blowout..........................................................................1-44 

1-8: Simulated Oil Plume Trajectory for Winter Blowout Pad Detail........................................................1-45 

1-9: Miluveach River Crossing, Diagram 1 ..............................................................................................1-55 

1-10: Miluveach River Crossing, Diagram 2 ............................................................................................1-56 

1-11: Alpine CD1 Pad Detail - Tank Rupture in Summer ........................................................................1-63 

1-12: Alpine Development Area ...............................................................................................................1-67 

1-13: Alpine Pipelines Operations Rights-of-Way....................................................................................1-69 

1-14: CD1, CD2, and CD3 Vicinity Map...................................................................................................1-71 

1-15: CD1 Pad Layout..............................................................................................................................1-72 

1-16: CD2 Pad Layout..............................................................................................................................1-73 

1-17: CD3 Pad Layout..............................................................................................................................1-74 

1-18: CD4 Vicinity Map ............................................................................................................................1-75 

1-19: CD4 Pad Layout..............................................................................................................................1-76 

1-20: CD5 Vicinity Map ............................................................................................................................1-77 

1-21: CD5 Pad Layout..............................................................................................................................1-78 

1-22: GMT1 Vicinity Map..........................................................................................................................1-79 

1-23: GMT1 Pad Layout...........................................................................................................................1-80 

1-24: Summer Wind Rose Diagram .........................................................................................................1-84 

1-25: Winter Wind Rose Diagram ............................................................................................................1-85 

2-1: Percentage of Oil Spill Incidents by Source (1999 – 2016)..............................................................2-19 

2-2: Percentage of Oil Spill Volume by Source (1999 – 2016) ................................................................2-19 

2-3: Percentage of Oil Spill Volume by Cause (1999 – 2016) .................................................................2-20 

3-1: Incident Command System Structure...............................................................................................3-19 

3-2: IMT Functions and Responsibilities Checklists ................................................................................3-20 

3-3: ACS Pre-Deployed and Pre-Staged Spill Response Equipment......................................................3-41 

3-4: ACS Statement of Contractual Terms ..............................................................................................3-47 

3-5: ACS-COPA Member Response Action Contract Signature Page....................................................3-49 

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LIST OF TABLES 

1-1: Emergency Action Checklist ...............................................................................................................1-1 

1-2: Agency Reporting Requirements for Oil Spills and Hazardous Materials ..........................................1-7 

1-3: Seasonal Transportation Options .....................................................................................................1-11 

1-4: Estimated Response Time................................................................................................................1-11 

1-5: Well Blowout in Summer - Typical Environmental Conditions..........................................................1-19 

1-6: Well Blowout in Summer - Response Strategy.................................................................................1-20 

1-7: Well Blowout in Summer - Oil Recovery Capacity............................................................................1-25 

1-8: Well Blowout in Summer - Recovery and Protection Equipment......................................................1-27 

1-9: Well Blowout in Summer - Staff to Operate Oil Containment, Recovery, and Transfer 

Equipment ...................................................................................................................................1-28 

1-10: Well Blowout in Winter - Typical Environmental Conditions ...........................................................1-35 

1-11: Well Blowout in Winter - Response Strategy..................................................................................1-36 

1-12: Well Blowout in Winter – Oil Recovery and Handling Capacity......................................................1-39 

1-13: Well Blowout in Winter - Oil Recovery and Transfer Equipment ....................................................1-41 

1-14: Well Blowout in Winter - Staff to Operate Oil Containment, Recovery, and Transfer 

Equipment ...................................................................................................................................1-42 

1-15: Alpine Pipeline Release to the Miluveach River in Summer - Typical Environmental 

Conditions ...................................................................................................................................1-49 

1-16: Alpine Pipeline Release to the Miluveach River in Summer - Response Strategy ........................1-50 

1-17: Alpine Pipeline Release to the Miluveach River in Summer - Liquid Recovery Capability ............1-53 

1-18: Alpine Pipeline Release to the Miluveach River in Summer - Liquid Handling Capability .............1-54 

1-19: Alpine Tank Rupture in Summer - Typical Environmental Conditions............................................1-59 

1-20: Alpine Tank Rupture in Summer - Response Strategy...................................................................1-60 

1-21: Alpine Tank Rupture in Summer - Recovery and Handling Capability...........................................1-62 

1-22: Well Capping Equipment List..........................................................................................................1-82 

1-23: Average Wind Speed and Temperature .........................................................................................1-83 

2-1: Flowline Compliance Measures..........................................................................................................2-4 

2-2: Facility Oil Piping Compliance Measures ...........................................................................................2-5 

2-3: Tank Loading and Unloading Areas at Alpine ..................................................................................2-15 

2-4: Alpine Oil Spill Reports (1999-2016) ................................................................................................2-17 

2-5: Alpine Potential Oil Spills from Major Sources .................................................................................2-21 

2-6: Potential Discharge of Alpine Pipelines ............................................................................................2-23 

3-1: Cross-Country Pipeline Design Basis.................................................................................................3-4 

3-2: Alpine Cross-Country Pipeline Vertical Loop Placement....................................................................3-5 

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3-3: Burning Equipment ...........................................................................................................................3-28 

3-4: Minimum Ignitable Thickness on Water............................................................................................3-30 

3-5: Burn/Removal Rates for Large Fires on Water ................................................................................3-30 

3-6: Fire Extinguishing Slick Thickness ...................................................................................................3-31 

3-7: Alpine Pre-Staged and Pre-deployed Equipment Sites....................................................................3-38 

3-8: Safe Distances Between In Situ Burns and Downwind Human Populations in Flat Terrain: 

Location of Fire Zones ................................................................................................................3-44 

4-1: Best Available Technology Analysis Well Blowout Source Control....................................................4-5 

4-2: Best Available Technology Analysis Crude Oil Transmission Pipeline Source Control .....................4-7 

4-3: Best Available Technology Analysis Tank Source Control.................................................................4-9 

4-4: Best Available Technology Analysis Tank Liquid Level Determination ............................................4-13 

4-5: Best Available Technology Analysis Leak Detection in Crude Oil Transmission Pipeline ...............4-19 

Alpine Field, Satellites, and Pipelines ODPCP xi February 2018, Rev. 0 
LIST OF ACRONYMS 

°F degrees Fahrenheit 

°C degrees Celsius 

AAC Alaska Administrative Code 

ACF Alpine Central Facilities 

ACP area contingency plan 

ACS Alaska Clean Seas 

ADEC Alaska Department of Environmental Conservation 

ADF&G Alaska Department of Fish and Game 

ADNR Alaska Department of Natural Resources 

AFPM American Fuel & Petrochemical Manufacturers 

ANSI American National Standards Institute 

AOGCC Alaska Oil and Gas Conservation Commission 

API American Petroleum Institute 

ARRT Alaska Regional Response Team 

ASME American Society of Mechanical Engineers 

ATV all-terrain vehicle 

BAT best available technology 

bbl barrels 

BLM U.S. Department of the Interior, Bureau of Land Management 

BOP blowout preventer 

bopd barrels of oil per day 

boph barrels of oil per hour 

bpd barrel per day 

bph barrels per hour 

CERCLA Comprehensive Environmental Response, Compensation, and Liability Act 

CFR Code of Federal Regulation 

cfs cubic feet per second 

CO2 carbon dioxide 

CP cathodic protection 

COPA ConocoPhillips Alaska 

CPF Central Processing Facility 

CS Control Site 

Alpine Field, Satellites, and Pipelines ODPCP xii February 2018, Rev. 0 
CTF Containment Task Force 

cu yd cubic yard 

DCS distributed control system 

DOT U.S. Department of Transportation 

DRA drag reducing agent 

EOC Emergency Operations Center 

EPA U.S. Environmental Protection Agency 

ERD extended reach drilling 

ESD emergency shutdown 

FBE fusion bonded epoxy 

FLIR forward-looking infrared 

FOSC Federal On-Scene Coordinator 

GIMAT Global Incident Management Assist Team 

GOR gas-to-oil ratio 

gpm gallons per minute 

HAZMAT Hazardous Materials 

HAZWOPER hazardous waste operations and emergency response 

HDD horizontal directional drilling 

HDPE high density polyethylene 

HMRT hazardous materials response team 

HSE health, safety, and environment 

IAP Incident Action Plan 

IARC International Agency for Research on Cancer 

IC Incident Commander 

ICS Incident Command System 

IMT Incident Management Team 

LEPC Local Emergency Planning Committee 

LOSC Local On-Scene Coordinator 

MAD Mutual Aid Drill 

MB Mass Balance 

MBLPC Mass Balance Line Pack Compensation 

mph miles per hour 

NACE National Association of Corrosion Engineers 

NGL natural gas liquid 

Alpine Field, Satellites, and Pipelines ODPCP xiii February 2018, Rev. 0 
NIMS National Incident Management System 

NIST National Institute of Standards and Technology 

NPR-A National Petroleum Reserve – Alaska 

NPREP National Preparedness for Response Exercise Program 

NPWM Negative Pressure Wave Monitoring 

NRC National Response Center 

NSB North Slope Borough 

NSSRT North Slope Spill Response Team 

NTP National Toxicology Program 

ODPCP Oil Discharge Prevention and Contingency Plan 

OSC On-Scene Commander 

OSHA Occupational Safety and Health Administration 

OSRO oil spill removal organization 

PM preventive maintenance 

PPATM Pressure Point AnalysisTM 

PPE personal protective equipment 

ppm parts per million 

PRAC primary response action contractor 

PREP Preparedness for Response Exercise Program 

psi pounds per square inch 

psig pounds per square inch gauge 

PVC polyvinyl chloride 

QI Qualified Individual 

RCRA Resource Conservation and Recovery Act 

REIM remote electrical-instrument module 

RP responsible party 

RPS response planning standard 

RTTM Real Time Transient Model 

SCADA Supervisory Control and Data Acquisition 

scf/bbl standard cubic feet per barrel 

SIS safety instrument system 

SOP Standard Operating Procedure 

SPCC Spill Prevention, Control, and Countermeasure 

SPCO State Pipeline Coordinator’s Office 

Alpine Field, Satellites, and Pipelines ODPCP xiv February 2018, Rev. 0 
SRT Spill Response Team 

TF Task Force 

UC Unified Command 

UHF ultra high frequency 

ULSD ultra-low sulfur diesel 

USCG U.S. Coast Guard 

USFWS U.S. Fish and Wildlife Service 

VHF very high frequency 

VSM vertical support member 

WCD worst case discharge 

Alpine Field, Satellites, and Pipelines ODPCP xv February 2018, Rev. 0 
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INTRODUCTION 

This Oil Discharge Prevention and Contingency Plan (ODPCP) is for the Alpine Field and Satellites and 

Alpine Pipeline System facilities located within the North Slope Borough, Alaska and on state lands within 

the Colville River Unit and federal lands of the National Petroleum Reserve – Alaska (NPR-A) within the 

Greater Mooses Tooth Unit. ConocoPhillips Alaska (COPA) is the operator of the facilities covered by this 

ODPCP. COPA’s address, phone, and fax numbers are provided below: 

ConocoPhillips Alaska Street Address: 

P.O. Box 100360 700 G Street 

Anchorage, AK 99510-0360 Anchorage, AK 99510-0360 

Phone: (907) 276-1215 

The primary goal of this ODPCP is to prevent and/or limit the spread of a spill, thereby minimizing potential 

environmental impacts, and providing for the safety of personnel. Where the two may conflict, safety of 

personnel will always be given the first consideration. 

Under Alaska Statute 46.04.030 a pipeline or production facility must operate in compliance with an 

approved ODPCP. This ODPCP addresses requirements for pipeline and production facility operations 

governed by the Alaska Department of Environmental Conservation (ADEC) under Title 18, Chapter 75 of 

the Alaska Administrative Code (18 AAC 75), as amended through March 23, 2017. This ODPCP addresses 

federal regulations of the U.S. Environmental Protection Agency (EPA) at Title 40 of the Code of Federal 

Regulations Part 112 (40 CFR 112) and regulations of the U.S. Department of Transportation (DOT) at 49 

CFR 194, as mandated by the Oil Pollution Act of 1990. In addition, this ODPCP addresses environmental 

obligations required by the U.S. Department of the Interior Bureau of Land Management (BLM) under 43 

CFR 3162.5 

The major operations covered by this ODPCP include: 

• Alpine Central Processing Facility; 

• Production Drill Sites CD1, CD2, CD3, CD4 CD5, and GMT1; 

• Production flowlines; 

• Gas/water handling and injection facilities; 

• Alpine crude oil transmission pipeline; and 

• Alpine diesel pipeline. 

COPA assumes responsibility for containment and cleanup of oil spills from its facilities and operations 

within the Alpine Field and Satellites and Alpine Pipeline System. COPA requires that contract companies 

and their employees adhere strictly to COPA safety and environmental policies and procedures while 

working on COPA lease holdings. Contractors are required to report all spills to Alpine Security. 

COPA is a member of Alaska Clean Seas (ACS), which serves as the primary response action contractor 

for COPA operations on the North Slope. This ODPCP incorporates by reference, wherever applicable, the 

ACS Technical Manual, which consists of Volume 1, Tactics Descriptions, and Volume 2, Map Atlas. 

Volume 1 describes the tactics used to respond to a variety of spill situations. Volume 2 provides maps and 

a narrative description of resources at risk, as well as key response considerations by location. 

Alpine Field, Satellites, and Pipelines ODPCP I-1 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

PLAN CONTENTS 

The ODPCP format is consistent with the format required by 18 AAC 75. Facilities are located on private, 

local, state, and/or federal land, and are regulated by and subject to applicable legal provisions of North 

Slope Borough, State of Alaska, EPA, DOT, and BLM. 

The following is a summary of principal contents of this ODPCP: 

• Part 1 – Response Action Plan: provides information to guide responders during an incident. 

Information includes reporting and notification procedures, basic safety procedures, response 

communications, deployment and response strategies, and initial response procedures. 

• Part 2 – Prevention Plan: provides detailed description of policies, best management 

practices, and prevention measures employed at facilities. Information is included on training 

programs, identified risks, historical spills, and measures taken to minimize potential 

environmental impact. 

• Part 3 – Supplemental Information: provides an overview of facility operations, receiving 

environment, and supporting response information. 

• Part 4 – Best Available Technology: provides analysis of facility spill prevention and 

response equipment to ensure it meets performance standards in 18 AAC 75. 

• Part 5 – Response Planning Standard: presents a calculation of the applicable response 

planning standards and detailed basis for the calculation of reductions if applied to the response 

planning standard volume. 

• Appendices: provide additional supporting information, including EPA, DOT, and BLM 

response plan cross-reference tables, facility spill history, and a list of regulated oil storage 

tanks subject to this ODPCP. 

EPA and DOT regulations allow submission of an equivalent state response plan to meet federal response 

plan requirements [40 CFR 112.20(h) and 49 CFR 194.109, respectively]. Cross-reference tables are 

provided in the Appendices to demonstrate compliance with EPA and DOT requirements. This ODPCP is 

also in place to meet contingency and response plan requirements for development operations on federal 

lands within the NPRA; a cross-reference table is also provided in the Appendices to address BLM 

requirements. 

PLAN SUPPLEMENTAL DOCUMENTATION 

This ODPCP is supported by additional document resources that provide key prevention and response 

information. These documents provide a robust framework of procedures, processes, tactics, strategies, 

and guidance for operational personnel and response teams. Figure I-1 shows the important referenced 

documents that support the ODPCP. In addition, the following table provides a listing of the supplemental 

documents COPA references for oil discharge prevention and response information. Key internal and 

external written materials are available at COPA emergency operation center facilities. 

Alpine Field, Satellites, and Pipelines ODPCP I-2 February 2018, Rev. 0 
FIGURE I-1 

Key Prevention and Response Documents 

State/Federal Agency 

Supporting Response 

Resources 

Industry Prevention and 

Emergency Response Plans 

and Procedures 

Oil Discharge Prevention 

and Contingency Plan 

• Unified Plan, North 

Slope Subarea Plan 

• ESI Maps 

• EAP, IMH, D&W BCP, 

SOPs, AK EMT Policy 

• ACS TM, ASH, NS Env. 

Handbook, Red Book 

•State ADEC Regulations 18 

AAC 75 

•Federal Regulations: EPA 

40 CFR 112; DOT 49 CFR 

194; BLM 43 CFR 3162.5 

 
 

 

 

 

 

 

 

 

 

ODPCP SUPPLEMENTAL DOCUMENTATION 

DOCUMENT AUTHOR LOCATION/LINK 

Alaska Administrative Code, Section 75 (18 AAC 75) ADEC http://dec.alaska.gov/commish/regulations/index.htm 

Alaska Clean Seas Technical Manuals: Volume 1, 

Tactics Descriptions; and, Volume 2, Map Atlas 

Alaska Clean 

Seas http://www.alaskacleanseas.org. 

Alaska Federal/State Preparedness Plan for 

Response to Oil & Hazardous Substance 

Discharges/Releases (Unified Plan) 

Alaska Regional 

Response Team 

(ARRT) 

http://dec.alaska.gov/spar/perp/plans/uc.htm 

North Slope Subarea Contingency Plan ARRT http://dec.alaska.gov/spar/perp/plans/scp_ns.htm. 

Alaska “Prevention and Emergency Response 

Subarea Plans Maps” ADEC http://www.asgdc.state.ak.us/maps/cplans/subareas.h tml#northslope. 

State of Alaska land records – Alaska Mapper ADNR http://dnr.alaska.gov/mapper/ 

Alaska Safety Handbook (ASH) North Slope 

Operators 

COPA EOC facilities and COPA internal internet 

Alaska HSE website. 

COPA Alaska Emergency Management Teams 

Policy COPA COPA internal internet Emergency Plans homepage 

COPA Incident Management Handbook COPA 

COPA EOC facilities and COPA internal internet 

Emergency Plans website. 

COPA Emergency Action Plans COPA COPA EOC facilities and COPA internal internet 

Alaska HSE website. 

COPA Drilling and Wells Emergency Preparedness 

Blowout Contingency Plan COPA COPA EOC facilities and COPA internal internet 

Emergency Plans website. 

North Slope Environmental Field Handbook COPA COPA EOC facilities and COPA internal internet 

Alaska HSE website. 

Alaska Waste Disposal and Reuse Guide COPA COPA EOC facilities and COPA internal intranet 

Alaska HSE website. 

NOAA Environmental Sensitivity Index (ESI) Maps. NOAA http://response.restoration.noaa.gov/esi. 

PLAN DISTRIBUTION 

The ODPCP is available electronically on the ADEC Internet website, as per 18 AAC 75.460(b)(3). The 

ODPCP is distributed to COPA Management and staff as appropriate, and is maintained on the COPA 

intranet Emergency Plans website. Paper copies are located in COPA emergency operations centers. The 

Plan Administrator maintains a record of plan distribution. Federal, state and local agency personnel and 

external stakeholders are provided copies of the plan, upon request; however, COPA encourages use of 

the electronic copy posted to the ADEC Internet website to ensure use of the most recent version and to 

reduce waste. 

PLAN UPDATING AND RENEWAL 

The ODPCP is reviewed annually and periodically updated when changes occur. Changes necessary to 

keep the ODPCP current for use in an emergency are submitted to ADEC as plan amendments and typically 

Alpine Field, Satellites, and Pipelines ODPCP I-4 February 2018, Rev. 0 
 

 

 

 

 

 

are considered routine plan updates or minor amendments, in accordance with provisions of 18 AAC 

75.415(b) and (f). Plan amendments that ADEC determines to be a major amendment are reviewed per 18 

AAC 75.455. The following changes are considered a major amendment: 

• Response planning standard volume increase that exceeds current plan response capabilities. 

• Change in scenario location, receiving environment, or season of operations. 

• Expansion of current plan area of operations. 

• Change in prevention, response resources, or training above or below current plan capabilities. 

Plan renewals occur every five years and must be submitted to ADEC in accordance with 18 AAC 75.408 

at least 180 days prior to expiration of existing plan approval. An application for plan renewal is reviewed 

under the provisions of 18 AAC 75.455. 

EPA regulation 40 CFR 112.20(d)(1) requires revision and resubmittal of a response plan within 60 days of 

a change that materially may affect the response and DOT regulation 49 CFR 194.121 requires that 

modifications, which could substantially affect the implementation of the response plan, be submitted for 

review within 30 days. Both EPA and DOT require review and resubmittal of a plan every 5 years from the 

last submittal or approval date. 

Revisions to the ODPCP are documented in the Record of Revisions. Upon request, hard copies of 

changed pages or electronic copies are distributed to plan recipients, including regulatory agencies and 

emergency operations centers. Upon receipt of revisions, the plan recipient replaces pages (hardcopy) or 

the previous disc, as instructed. It is the responsibility of each plan recipient to ensure updates are promptly 

addressed. 

COPA ensures that plan renewals are submitted to the appropriate agencies according to their renewal 

timeframe. The approvals covered by this ODPCP and relevant renewal cycles are listed below: 

Regulating Agency Renewal Cycle Expiration Date 

ADEC 5 years February 15, 2023 

EPA No more than every 5 years 

for facility response plan December 12, 2022 

DOT 5 years September 11, 2022 

BLM requirements do not specify a plan review and/or renewal cycle. At a minimum, the plan is available 

to BLM as part of the ADEC 5-year renewal process. 

Alpine Field, Satellites, and Pipelines ODPCP I-5 February 2018, Rev. 0 
BLANK PAGE 

Alpine Field, Satellites, and Pipelines ODPCP I-6 February 2018, Rev. 0 
Alpine Field, Satellites, and Pipelines ODPCP I-7 February 2018, Rev. 0 

 

 

 

 

 

PART 1 RESPONSE ACTION PLAN 

[18 AAC 75.425(e)(1)] 

1.1 EMERGENCY ACTION CHECKLIST [18 AAC 75.425(e)(1)(A)] 

The person reporting an oil spill may be required to supply minimum spill assessment information to provide 

as complete an understanding of the event as possible. Table 1-1 provides some emergency actions and 

information that may be reported and Figure 1-1 provides a flow chart of steps for immediate spill 

notification. 

TABLE 1-1: EMERGENCY ACTION CHECKLIST 

INITIAL SPILL RESPONSE ACTIONS WHAT TO REPORT TO YOUR SUPERVISOR 

1. Protect people: Safety is first priority. 

• Shut off ignition sources. 

• Restrict access. 

• Evaluate as necessary, and initiate rescue and 

response actions. 

• Evacuate nonessential personnel. 

2. Notify Supervisor and Security. 

3. Stop or contain the spill at source, if safe to do so. 

4. Assess possible hazards: 

• Fire and explosion potential of vapors at or near 

the source, 

• Potential toxic effects of the discharge, 

• Damage to facility affecting safety, and 

• Recovery of the spilled product. 

5. For a blowout, implement well control and 

evacuation procedures, and activate Tier Ill Incident 

Command System. 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

11. 

12. 

Was anyone hurt? 

Where is the spill? 

What time did it happen? 

What was spilled? 

How much was spilled? 

What is the rate of release? 

What is the source? 

What are the weather conditions? 

What actions have you taken? 

What equipment do you need? 

Are there any immediate environmental impacts? 

Who did you notify? 

The emergency actions and notification sequence varies depending on the size of the spill and safety issues 

present. A minor spill defines a situation where on-site employees do not require assistance from the Alpine 

Spill Response Team (SRT), or the situation does not represent an emergency. Emergency situations exist 

where any of these conditions are present: 

• The safety of personnel is threatened. 

• The spilled material is of an unknown nature and is potentially hazardous or toxic. 

• The release of product cannot be quickly stopped or contained. 

The levels described below apply only to the emergency phases of containment and initial recovery of a 

spill. 

Minor. Defines a situation where the on-site personnel can control the incident and SRT response is not 

required. 

Alpine Field, Satellites, and Pipelines ODPCP 1-1 February 2018, Rev. 0 
 

 

 

 

Tier I. Defines a situation where on-site employees require immediate assistance of the on-site ACS Spill 

Technician(s) and, if necessary, SRT to control, contain, and cleanup a spill. 

Tier II. Defines a situation that requires call-out of the Alpine SRT and/or Hazardous Materials (HAZMAT) 

Team (a Tier I response), and other resources available on the North Slope, including ACS Base resources 

(Deadhorse) and/or Mutual Aid. 

Tier III. Defines a situation that requires activation of North Slope resources (a Tier II response) and those 

available from sources other than North Slope suppliers. A Tier III response is activated in the event of a 

catastrophic spill and involves use of various trained response contractors. 

Alpine Field, Satellites, and Pipelines ODPCP 1-2 February 2018, Rev. 0 
 

FIGURE 1-1: IMMEDIATE SPILL NOTIFICATION PROCESS 

SPILL OBSERVER 

Supervisor Team Lead 

SECURITY 911 

670-4900* 

Emergency 

Response Chief 

ACS / SRT Operations 

Incident 

Management Team 

Field Environmental 

Coordinator 

Regulatory Agencies 

(spill reporting) 

Alpine Pipeline 

Controller 

Drilling / Wells 

Superintendent 

Drilling / Wells 

Manager 

Boots & Coots 

1-800-BLOWOUT 

COPA Source Control 

Team 

Anchorage AOGCC / 

BLM 

AOGCC Emergency 

Notification 

Drillsite or Board 

Operator 

670-4222, 4220, or 4221 

Drilling / Well Event 

Tier II / III 

Initiate Emergency Preparedness 

& Blowout Contingency Plan 

notification procedures 

DOT Pipeline Event 

Initiate emergency procedures per 

Pipeline Emergency Operations SOP 

* Dial 911 from a facility phone only. 

Do not call 911 from a cell phone; 

call 1-907-670-4900. 

Radio: ALPNET 

Initiate emergency 

action plan emergency 

reporting procedures 

 
 

 

 

 

 

 

 

1.2 REPORTING AND NOTIFICATION [18 AAC 75.425(e)(1)(B)] 

1.2.1 Initial Reporting and Notification [18 AAC 75.425(e)(1)(B)(i)] 

Any person who causes or observes a spill is required to immediately report the spill to their supervisor. 

The supervisor makes notification to Security. If their supervisor is not available, notify Security. 

Security documents initial spill information and is responsible for initiating notification and reporting 

procedures. Once Security is alerted, they will notify appropriate response personnel, depending on the 

spill size and safety issues involved (Figure 1-2). Security will activate a singular, all-call paging number to 

emergency responders. Internal reporting requirements follow COPA Spill Reporting Procedure. 

Alpine Security 24-hour emergency contact: 911 or (907) 670-4900 

Note: do not call 911 from a cell phone. If using a cell phone, call 1-907-670-4900. 

Security maintains contact phone numbers for personnel including the Qualified Individual (QI) who is the 

Operations Manager, Alternate QI who is the Operations & Maintenance Superintendent. Contact 

information for the QI and the Alternate QI is described in Section 3.3. 

Alpine Field, Satellites, and Pipelines ODPCP 1-4 February 2018, Rev. 0 
FIGURE 1-2: SPILL REPORT NOTIFICATION 

Alpine Field, Satellites, and Pipelines ODPCP 1-5 February 2018, Rev. 0 
 

 

 

 

 

 

 

1.2.2 External Reporting and Notification [18 AAC 75.425(e)(1)(B)(ii)] 

The Field Environmental Coordinator is responsible for notifying the appropriate regulatory agencies and 

landowners, in accordance with COPA Spill Reporting Procedure. 

Federal law requires that at least one of its representative agencies be notified of qualifying spills of oil or 

hazardous substances. Federal law also requires that the National Response Center (NRC) be notified of 

all hazardous substance spills that exceed the Comprehensive Environmental Response, Compensation, 

and Liability Act (CERCLA) reportable quantity limit. This notification should be made within two hours of 

the incident. 

For incidents on federal lands, BLM requires verbal notification of major undesirable events, including spills, 

as soon as possible; but no later than 24 hours after the event. 

At the earliest practicable moment following discovery, but no later than one hour after confirmed discovery, 

DOT requires notification of spills from the Alpine crude oil and diesel pipelines that involve one or more of 

the following conditions: 

• Explosions or fires, 

• Death or personal injury requiring hospitalization, 

• Estimated damage to property of $50,000 or more, or 

• Pollution of any body of water. 

DOT requires information on weather conditions for any reported spill. During severe flooding conditions, 

COPA provides open communications with local and state officials to address concerns regarding observed 

environmental conditions that may affect the integrity of pipeline crossings. A telephone report made more 

than two hours after confirmation of a reportable condition is considered late. 

Primary agency reporting requirements are provided in Table 1-2. As appropriate per regulatory 

requirements and/or operating agreements, verbal notifications and/or written reports are provided to: 

• National Response Center (EPA, DOT, and U.S. Coast Guard); 

• U.S. Department of the Interior, Bureau of Land Management; 

• Alaska Department of Environmental Conservation 

• Alaska Department of Fish & Game 

• Alaska Department of Natural Resources 

• Alaska Oil and Gas Conservation Commission 

• North Slope Borough 

• Kuukpik Corporation 

Alpine Field, Satellites, and Pipelines ODPCP 1-6 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

TABLE 1-2: AGENCY REPORTING REQUIREMENTS FOR OIL SPILLS AND HAZARDOUS MATERIALS 

AGENCY LOCATION / RECEIVING 

ENVIRONMENT SPILL SIZE VERBAL 

REPORT PHONE NUMBER WRITTEN REPORT 

National Response Center 

EPA, DOT, and USCG 

Into or upon navigable waters 

of the U.S. or to land that 

may threaten navigable 

waters of the U.S. 

Any Immediately (800) 424-8802 (24 hour) 

Note: DOT requires notification at the earliest 

practicable moment following discovery, but no 

later than one hour after confirmed discovery. 

Follow up is required within 48 hours. 

Form completed during phone 

notification. 

For SPCC facilities, if spill is 

≥1,000 gallons or if it is a 

second spill >42 gallons in 12 

months to water or tundra, 

submit written report to EPA. 

ADEC 

ADNR (same requirements as 

ADEC) 

ADF&G (any release to fishbearing waters) 

Kuukpik Corporation (within 

Kuukpik withdrawal area or if 

IMT activated) 

Off pad to water or tundra Any Immediately (within 

30 minutes) 

ADEC ADNR 

(907) 451-2121 (907) 451-2719 

(907) 451-2362 (fax) dnr.nro.spill@alaska.gov 

or ADF&G - Fairbanks 

AK State Troopers (907) 459-7289 

(after hours and (907) 459-7303 

weekends) Kuukpik 

(800) 478-9300 (907) 480-6220 

(907) 480-6126 (fax) 

Submit within 15 days after 

containment and cleanup are 

completed or, if no cleanup 

occurs, within 15 days after 

the discharge or release. 

On gravel pad, gravel road, 

ice pad, ice road, or snowcovered tundra 

1 to 10 gallons (<1 

gallon no report) 

Monthly written 

report 

>10 to 55 gallons Within 48 hours 

>55 gallons Immediately 

Into impermeable secondary 

containment area or structure 

>55 gallons Within 48 hours 

Alaska Oil and Gas 

Conservation Commission 

(AOGCC) 

Well release (crude or gas) Any Immediately Anchorage North Slope (Field) 

(907) 279-1433 (907) 659-2714 

(907) 276-7542 (fax) (907) 659-3607 (pager) 

(907) 659-2717 (fax) 

Submit within 5 days of loss; 

final report required within 30 

days. 

North Slope Borough (NSB) Off pad to water or tundra Any Immediately Permitting & Zoning LEPC - Risk 

(907) 301-1461 Management 

(907) 852-0321 (fax) (907) 852-0248 

(907) 852-0356 (fax) 

Submit within 7 days. 

On gravel pad, gravel road, 

ice pad, ice road, or snowcovered tundra 

>55 gallons Immediately 

Into impermeable secondary 

containment area or structure 

>55 gallons Within 48 hours 

State Pipeline Coordinator’s 

Section (SPCS) 

U.S. Department of 

Transportation (DOT) 

From pipeline administered 

by the SPCS or to pipeline 

ROW 

Any Immediately SPCS 

(907) 269-6403 

(907) 269-6880 (fax) 

NRC 

(800) 424-8802 (24 hour) 

DOT - Anchorage 

(907) 271-6519 or 271-6517 

Submit DOT Form 7000-I 

within 30 days (see form for 

details). 

From DOT-regulated pipeline ≥5 gallons

Bureau of Land Management 

(BLM) 

Major Undesirable Events – 

all spills or releases of 

petroleum fluids or chemicals 

used in the petroleum 

industry 

Any As soon as 

practicable, but no 

later than 24 hours 

Anchorage Fairbanks 

(907) 267-1446 (907) 474-2301 

(907) 276-1304 (fax) (907) 474-2307 (Hazmat) 

(907) 474-2386 (fax) 

Submit in duplicate within 15 

days after the incident 

Alpine Field, Satellites, and Pipelines ODPCP 1-7 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

1.3 SAFETY [18 AAC 75.425(e)(1)(C)] 

At COPA, our work is never so urgent or important that we cannot take the time to do it safely and in an 

environmentally prudent manner. The COPA Alaska Workforce HSE Roles & Responsibilities handbook 

defines specific Health, Safety, and Environment (HSE) roles, responsibilities, and performance criteria 

designed to achieve the goal of zero incidents, injuries and illnesses, and promote COPA Incident-Free 

Culture. In addition, the Alaska Safety Handbook presents “best” safety procedures and standards to guide 

employees and contractors working at COPA facilities on the North Slope. Workers are expected to 

understand and use the safety rules presented in the handbook as a requirement of employment. The 

handbook is made available to COPA employees and contractors. 

The steps necessary to develop an incident-specific safety plan for conducting a response are outlined in 

the ACS Technical Manual, Tactics S-1 to S-6. The ACS tactics, incorporated here by reference, include 

site entry procedures, site safety plan development (Incident Command System [ICS] Form 201-5), and 

personnel protection procedures. 

Safety procedures and emergency action plans are made available to employees and contractors on the 

COPA intranet. At the time of an incident, an incident-specific safety plan is developed by the Incident 

Management Team (IMT), which documents initial assessment and response plan recommendations. 

As outlined in the North Slope Sub-Area Plan, the Local On-Scene Coordinator (LOSC) will be involved in 

any spill that poses an immediate threat to public safety. The North Slope Borough LOSC, or designee, will 

typically integrate into the incident command system through a liaison representing all affected 

communities. 

Alpine Field, Satellites, and Pipelines ODPCP 1-8 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

1.4 COMMUNICATIONS [18 AAC 75.425(e)(1)(D)] 

The spill communication system supports the organizational structure of spill response efforts and is 

scalable in both size and scope to serve both small- and large-scale response events. An event that is 

limited to a local response by the SRT is adequately served by the local SRT communications system. An 

event that invokes a response by ACS or involves a significant Mutual Aid effort with other North Slope 

operators is able to use ACS communications equipment and upgrade smoothly from the local 

communication system to the ACS wide-area communications system. 

The Alpine communication resources available for spill response may be loosely classified into the following 

four categories: 

1. COPA SRT Telecom Resource: Communication resources designed to support spill response 

and developed for the SRT and the COPA Incident Command Post. 

2. ACS Telecom Resource: Communication resources that are part of the ACS 

Telecommunications Plan. These resources are available for COPA and members of ACS. 

3. North Slope Telecom Resource: Communication resources t not designed exclusively for 

spill response but may directly or indirectly play an important supportive role toward a 

successful response effort. 

4. Locally available public resources (cellular service). 

During an incident, the Communications Unit Leader in the IMT will provide the most effective 

communications system necessary to support the response actions of the SRT, and will develop a 

communications plan to suit the response. 

A detailed explanation of oil spill response communications on the North Slope is provided in the ACS 

Technical Manual, Volume 1, Tactic L-5. 

Communications in the Alpine area are currently provided by a digital Microwave system that extends the 

COP Network to these locations. This Network provides IP Phones and the Computing capabilities. This 

Microwave system also extends the Digital two-way radio system that connects Alpine and Kuparuk. This 

Microwave extension has also provided the ability to provide a remote portable Cellular site that extends 

ASTAC & AT&T services into the NPR-A. COPA also has available, a ground-based satellite system as 

backup. 

COPA installs a VHF repeater at each remote site with the correct ACS frequencies to provide extended 

local coverage for spill response personnel using hand held and mobile radios during a response. The 

extension of the COPA Microwave Network into remote areas is provided through a series of statically 

installed temporary towers varying in size, depending on project needs. 

North Slope personnel may have on-site, the following additional equipment: 

• Cell phones 

• Portable satellite phones 

• Hand held and mobile radios for on-site use and area-wide communications 

Alpine Field, Satellites, and Pipelines ODPCP 1-9 February 2018, Rev. 0 
 

 

 

Oil Spill Response repeaters installed across the North Slope provide response radio coverage from 

eastern NPR-A to Badami. The range of each fixed repeater is approximately 30 to 50 miles, depending on 

topography. 

Of the areas covered by this ODPCP, the NPR-A area is the most remote, and therefore poses the greatest 

communications challenges. Oil spill response communications in NPR-A will initially use VHF radios. The 

Alpine operating area has a 115-ft. radio tower, and a VHF repeater at the Alpine Base will provide 

communications throughout the Alpine operating area. This repeater is tied into the ACS wide-area VHF 

radio network as Channel OS-33. 

The oil spill response communications frequencies assigned to Alpine are as follows: 

VHF Oil Spill (OS-33) 

• Repeater Transmit: 159.585 MHz 

• Repeater Receive: 161.235 MHz 

• Private Line Code 103.5 Hz 

Communications within the boundaries of the Kuparuk River Unit have access to the Kuparuk area VHF 

radio system. The frequencies assigned to Kuparuk are as follows: 

VHF Oil Spill (OS-35) 

• Repeater Transmit: 154.585 MHz 

• Repeater Receive: 150.980 MHz 

• Private Line Code 107.2 Hz 

Alpine Field, Satellites, and Pipelines ODPCP 1-10 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1.5 DEPLOYMENT STRATEGIES [18 AAC 75.425(e)(1)(E)] 

1.5.1 Transport Procedures [18 AAC 75.425(e)(1)(E)(i)] 

COPA daily operations provide an infrastructure for a spill response. The extensive transportation 

infrastructure for personnel and equipment can support a small response and can be enhanced for a major 

spill. Existing access to channels in the Colville River delta is currently provided by the CD1 boat launch in 

the Sakoonang Channel. Infrastructure and pre-staged equipment is described in ACS Technical Manual, 

Volume 2, Map Atlas Sheets 8, 9, 12, 16, 17, 18, 20, 21, 22, 23, 23A, 24, 25, 26, 27, 121, 125, and 126. 

Transportation options, depending on the location, season, availability, and weather, include vessels, road 

vehicles, tundra travel vehicles, helicopters, fixed-wing planes, and air-cushion vehicles. Ice roads may also 

be constructed to provide site access during the winter. Table 1-3 summarizes Alpine’s seasonal 

transportation options. 

TABLE 1-3: SEASONAL TRANSPORTATION OPTIONS 

MODES OF TRANSPORTATION SUMMER WINTER BREAK-UP / 

FREEZE-UP 

Vessel X 

Helicopter X X X 

Fixed-wing aircraft X X X 

Road vehicle X1 X X1 

Tundra travel vehicle X X X 

Air-cushion vehicle X X X 

1Travel between CD1 and satellite drill sites, excluding CD3 

The estimated response time from discovery of a spill to the deployment of equipment varies depending on 

the location, pre-planning, logistical support, and available information. For planning purposes, 5 knots is 

used for vessels; 100 miles per hour (mph) for helicopters; 150 mph for light, fixed-wing aircraft; 300 mph 

for heavy, fixed-wing aircraft; 5 mph for tundra travel vehicle transport across tundra; and 35 mph for road 

vehicles. Table 1-4 describes the estimated response times for Alpine. 

TABLE 1-4: ESTIMATED RESPONSE TIME 

RESPONSE TIME 

Immediate response Immediate response will occur with the pre-staged response equipment. 

Aircraft 

(Mobilization is 1 hour from notice to fly.) 

Aircraft from Deadhorse within 2 hours. 

Light fixed-wing aircraft from Deadhorse is 30 minutes. 

Light fixed-wing aircraft from Kuparuk is 15 minutes (good weather). 

Vehicle CD1 to CD3 (winter ice road) – 10 to 15 minutes. 

CD1 to road-based satellite drill sites – varies; up to 1 hour (see maps in 

Section 1.8 for distances). 

Initial SRT response along pipeline route Alpine Pipeline route - within 2 hours. 

Vessel 

(Oliktok Dock to Colville River Delta) 

2.2 hours after the vessel is underway. 

(vessels response time from CD1 varies) 

Tundra travel vehicle From Kuparuk or Deadhorse – varies 

CD1 to CD3 – 1.2 hours. 

During the summer, travel to CD3 is possible by aircraft or boat; travel times will vary based on aircraft or 

vessel origin. Estimated times for transportation of containment, exclusion, and recovery equipment from 

Alpine Field, Satellites, and Pipelines ODPCP 1-11 February 2018, Rev. 0 
 

 

 

 

 

 

 

the Prudhoe Bay and Deadhorse areas to Nuiqsut and/or Alpine are summarized in Tactics L-3 and L-4 in 

the ACS Technical Manual. Response times will vary depending on the location and the time of year that a 

spill occurs. These variables are discussed for each site-specific scenario provided in Section 1.6.3. 

Rolligons have the capability to float on water and may cross channels in shallow water (≤2 feet) or may 

float until reaching a shallow area, if conditions are safe. Use of Rolligons or other vehicles for tundra travel 

during all seasons requires authorization by ADNR and may be subject to other approval requirements from 

local or federal jurisdictional agencies. 

SRT airboat operators are trained to navigate the channels of the Colville River delta. In addition, channels 

are surveyed and navigation markers are deployed each summer to assist spill responders traveling 

through the delta channels. 

1.5.2 Notification and Mobilization of Response Action Contractor [18 AAC 75.425(e)(1)(E)(ii)] 

Section 1.1 describes immediate response and notification actions, which may include notification of ACS. 

While ACS is mobilizing personnel and equipment to the spill site, COPA personnel determine safety 

procedures, notify government agencies and COPA personnel, and proceed with source control measures. 

In addition, if safe to do so, COPA response personnel will deploy on-site spill containment equipment. 

ACS is the primary response action contractor for COPA. The 24-hour phone number for ACS is listed in 

Section 3.8. The on-site personnel are the initial responders to spills at Alpine. SRT members promptly 

respond upon notification. Equipment will be deployed in the manner appropriate to the type of spill, based 

on tactics established in the ACS Technical Manual. Pre-staged and pre-deployed oil spill response 

equipment is discussed in Section 3.6. 

Alpine Field, Satellites, and Pipelines ODPCP 1-12 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1.6 RESPONSE SCENARIOS AND STRATEGIES [18 AAC 75.425(e)(1)(F), 18 

AAC 75.425(e)(1)(I), AND 18 AAC 75.445(d)] 

1.6.1 Qualifier Statement 

The scenarios and response strategies described in this plan were developed according to 18 AAC 

75.425(e)(1)(F) and (I). They describe general procedures, equipment, personnel, tactics, and operational 

capabilities that could be used to respond to an oil spill using applicable response strategies required by 

18 AAC 75.425(e)(1)(F)(i) through (xii) and 18 AAC 75.445(d). 

These scenarios are for illustration only and are not performance standards or guarantees of performance. 

The scenarios assume potential conditions of the spills and responses to demonstrate COPA’s capability 

to respond to a discharge of each applicable response planning standard (RPS) volume within the required 

timeframes using the resources described in this ODPCP and as required by 18 AAC 75.425(e)(1)(F) and 

(I). The RPS volume calculations are presented in Part 5. 

The scenarios identify the location, time of year, time of day, source and cause of spill, quantity and type 

of oil spilled, relevant environmental conditions (including weather, sea state, and visibility), spill trajectory, 

expected timeline for response actions, and a description of response actions to be taken. The response 

scenarios and strategies are usable as a general guide for a discharge of any size, and describe the 

discharge containment, control, and cleanup actions to be taken, which demonstrate the strategies and 

procedures adopted to conduct and maintain an effective response. Well blowout scenarios include a 

summary of planned methods, equipment, logistics, and timeframes proposed to be employed to control a 

well blowout within 15 days. The response strategies illustrate specific response measures that can reduce 

the risk, magnitude, or environmental impact of an oil spill, considering the variation of receiving 

environments and seasonal conditions. The response strategies address each of the relevant required 

elements of 18 AAC 75.425(e)(1)(F)(i) through (xii). 

Some details in the scenarios and response strategies are for illustration purposes; and although some 

equipment is named, it may be replaced by functionally similar equipment. These details do not limit the 

discretion of the persons in charge of the spill response to select any sequence or take whatever time they 

deem necessary to respond to a spill without jeopardizing personnel safety. 

In situ burning could be used in a spill response to reduce the quantity of oil, regardless of whether a 

scenario hypothesizes in situ burning to help meet the RPS. 

Actual responses in an oil spill emergency depend on personnel safety considerations, weather, other 

environmental conditions, agency permits and priorities, and other factors. In any incident, considerations 

to ensure the safety of personnel will be given highest priority. If severe weather or other conditions limit 

the safety of personnel, COPA may take precautions up to and including suspending response efforts until 

it is deemed safe to proceed. Likewise, if operating limitations are reached because of weather conditions, 

COPA will reassess the response effort and take necessary precautions to protect personnel and 

equipment. The scenarios assume the agency on-scene coordinators and other agency officials will 

immediately grant any required permits. 

1.6.2 Temporary Storage and Disposal [18 AAC 75.425(e)(1)(F)(x)] 

Temporary storage of oil, oily waste, and debris recovered during a spill cleanup may be provided by tanks, 

pits, or basins located at facilities near the site. The spill location or other logistical concerns may require 

Alpine Field, Satellites, and Pipelines ODPCP 1-13 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

storage of oil, oily waste, and debris in smaller, more portable containers that can be brought to the scene 

via truck, boat, or aircraft. 

Other temporary storage options during a spill response include lined natural depressions, construction of 

lined earthen dikes, and portable storage (bladder tanks, inflatable tanks, open-top drums, vacuum trucks, 

dump trucks, etc.). 

There are six permitted temporary solid waste cells at Pad 3 in the Prudhoe Bay Eastern Operating Area. 

Although it is not a permanent disposal site, long-term storage of solid hydrocarbons is possible. 

Requirements for use of the Pad 3 oily solid waste pits are set by ADEC solid waste disposal permit. 

There are also two permitted temporary storage pits at Pad 3 – the East Pit for contaminated snow and the 

West Pit for contaminated gravel. Contaminated snow from the East Pit is melted each spring and injected 

into one of the Pad 3 Class I wells. Gravel from the West Pit is thermally remediated each summer or every 

other summer, depending on the volume requirements. Kuparuk DS-1H may also be used for contaminated 

gravel and/or snow storage, and contains 12,230 cubic yards of storage capacity. Gravel from DS-1H is 

thermally remediated each summer or every other summer, depending on volume requirements. 

During the summer months at Alpine, when it may not be feasible to transport contaminated gravel to the 

Eastern Operating Area or Kuparuk, temporary storage cells would be constructed on site using appropriate 

liner and construction materials. 

The method of disposal for oil and contaminated materials from spill recovery operations (or for oily waste 

from normal operations) must be approved and permitted by the appropriate state and federal agencies. At 

the time of the spill, the Operations Chief, in consultation with the Environmental Unit Leader, determines 

the reuse, recycle, or disposal method best suited to the state of the oil, the degree of contamination of 

recovered debris, and the logistics involved in these operations. See Tactics D-1 through D-5 in the ACS 

Technical Manual. An initial determination must be made regarding the classification of the waste as 

exempt, hazardous, or non-hazardous. This classification can be made on a case-by-case basis. The 

Environmental Unit Leader provides assistance in determining the classification if the status of the waste 

material is in question. In general, the following guidelines apply: 

• Spills from DOT pipelines are non-exempt and may need to be tested to determine whether 

the material to be disposed of is hazardous. 

• Spills from production lines are exempt. 

• Spilled material that comes out of a well, either during drilling or work-over operations, is 

exempt. Spilled material that did not come out of a well is non-exempt and may need to be 

tested to determine if the material to be disposed of is hazardous. 

• Spills that occur from filling a tank (i.e., vehicle, storage, etc.) are non-exempt, even though 

they may occur on a well pad; product knowledge or testing may be needed to determine 

if the material to be disposed of is hazardous. 

The preferred management option for recovered oil is to recycle it back into the production stream via 

existing oil production facilities at Alpine CD1. Should materials need to be transported off the North Slope 

for handling and disposal by a third-party hazardous waste management contractor, truck, barge, and/or 

air transportation would be arranged. Guidelines for handling and managing oil and contaminated materials 

or oily waste are found in the Alaska Waste Disposal and Reuse Guide also known as the “Red Book”. 

Alpine Field, Satellites, and Pipelines ODPCP 1-14 February 2018, Rev. 0 
1.6.3 Response Scenarios and Strategies [18 AAC 75.425(e)(1)(F) and (I)] 

The following response scenarios and response strategies are included in this section: 

• Scenario 1: Well Blowout in Summer 

• Scenario 2: Well Blowout in Winter 

• Scenario 3: Alpine Pipeline Release to the Miluveach River in Summer 

• Scenario 4: Alpine Tank Rupture in Summer 

Alpine Field, Satellites, and Pipelines ODPCP 1-15 February 2018, Rev. 0 
BLANK PAGE 

Alpine Field, Satellites, and Pipelines ODPCP 1-16 February 2018, Rev. 0 
 

SCENARIO 1 

WELL BLOWOUT IN SUMMER 

Alpine Field, Satellites, and Pipelines ODPCP 1-17 February 2018, Rev. 0 
BLANK PAGE 

Alpine Field, Satellites, and Pipelines ODPCP 1-18 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TABLE 1-5: WELL BLOWOUT IN SUMMER - TYPICAL ENVIRONMENTAL CONDITIONS 

Spill Location Production well CD5-313 on Alpine CD5 Pad 

Date / Time August 1 / 0800 

Duration 15 days 

Source of Spill Although production wells are secured with a wellhead or blowout preventer while drilling, and are enclosed, 

this scenario assumes an uncontrolled well blowout occurs through an unobstructed open orifice. 

Cause of Spill Underbalanced well and failure of pressure control systems. 

Quantity of Oil Spilled RPS Volume: 150,000 barrels 

Based on a maximum production rate of 10,000 bopd and a blowout duration of 15 days. 

Emulsification Factor 1.67 (Applicable to oil that reaches open water, for storage purposes.) 

Oil Type North Slope Alpine Crude 

Wind Speed Average August wind speed is 22 mph 

Wind Direction The predominant wind directions are ENE, NE, E, and W (see Figure 1-3). The winds blow from the ENE 

40% of the time (6 days) and from the other directions, 20% of the time (3 days each): 

• Days 1 through 6: wind from ENE 

• Days 7 through 9: wind from NE 

• Days 10 through 12: wind from W 

• Days 13 through 15: wind from E 

Current Low. Oil falls to nearby lakes and may impact ephemeral or low flow streams. 

Air Temperature 51 degrees Fahrenheit (°F) 

Surface Well is on a gravel pad located approximately 4 miles west of the Nigliq Channel, and approximately 8 

miles west of CD1. Surrounding surface is tundra and tundra lakes and interconnecting streams. 

Trajectory The simulated blowout discharges at a rate of 10,000 bopd with a GOR of 650 scf/bbl. 

The SL Ross oil deposition model provided in ACS Technical Manual Tactic T-6 projects that the oil takes 

the form of an aerial plume extending from the well in the direction of the predominant wind directions. 

The blowout discharges 150,000 barrels of oil to the WSW, SW, W, and E of well CD5-313 (Figure 1-4). 

The model predicts the following plume dimensions: 

• 70% of the discharged oil falls within 430 feet downwind of the well. At that distance, the plume is about 

90 feet wide. 

• 80% of the discharged oil falls within 1,275 feet downwind of the well. At that distance, the plume is 

about 235 feet wide. 

• 90% of the discharged oil falls within 8,885 feet (1.7 mile) downwind of the well. At that distance, the 

plume is about 1,355 feet wide. 

• According to the SL Ross model, 10% of discharged oil is in the form of droplets so small (50 

micrometers or less) that they do not fall to the ground. 

Under the SL Ross model, approximately 70% (105,000 barrels) of the discharged oil falls on the CD5 pad. 

Not all oil falling on the pad is retained by gravel. If not recovered, discharged oil accumulates in low-lying 

areas and eventually flows off the pad. Approximately 30,000 barrels of oil falls beyond the pad. An 

estimated 4,300 barrels enters open water. The average thickness of the oil deposited on water surfaces 

is 0.10 inch. 

Alpine Field, Satellites, and Pipelines ODPCP 1-19 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TABLE 1-6: WELL BLOWOUT IN SUMMER - RESPONSE STRATEGY 

ADEC 

REQUIREMENT RESPONSE STRATEGY ACS TECHNICAL MANUAL TACTIC 

(i) Stopping Efforts are made to bring the well under control. Emergency shutdown 

Discharge at procedures are initiated. 

Source Once it has been determined that control of the well cannot be immediately 

regained, or the safety of personnel is at risk, personnel are evacuated to 

the pre-designated safe area. At all times, the safety of personnel is 

COPA’s first concern. No unauthorized personnel are allowed near the spill 

area. 

The Drilling/Wells Supervisor notifies the Drilling/Wells Superintendent. All 

appropriate notifications are made according to the COPA Drilling & Wells 

Emergency Preparedness & Blowout Contingency Plan. 

Boots & Coots is activated and dispatched from Houston, Texas within 12 

hours. 

The COPA IMT is activated; the Source Control team develops a well 

control strategy and coordinates logistics for mobilizing well capping 

resources. 

Boots & Coots initiates plans to cap the well. 

The blowout is controlled on Day 15. 

(ii) Preventing or Throughout the first few hours of the spill, the Site Safety Officer verifies S-1 

Controlling Fire that all sources of ignition are shutdown or removed from the area. The Site through Hazards Safety Officer provides access zone information and determines personal 

protective equipment (PPE) requirements. Access to the spill site is 

carefully controlled and the scene is secured by Security. Monitoring 

protocol is established by the Site Safety Officer for all work areas to ensure 

personnel protection. No personnel are allowed in the hot zones unless 

proper PPE is worn and it is permitted by the Site Safety Officer. 

Containment and recovery operations are allowed without respiratory 

protection in areas where safety criteria are met. Recovery operations and 

traffic are not allowed downwind of the blowout well in areas where workers 

may become exposed to flash fire hazard or to oil particulate matter at 

concentrations in excess of permissible exposure limits. Firewater coverage 

is set up. 

S-6 

(iv) Surveillance 

and Tracking of 

Oil on Open 

Water; 

Forecasting 

Shoreline 

Contact Points 

Blowout plume model is run. Aerial surveillance of oiled tundra and water is 

visually conducted by helicopter and by FLIR mounted on small fixed-wing 

aircraft. Initial estimates are made as to volume of spilled oil. 

T-6 

T-2, T-4, T-5, T-7 

(v) Protection of No ACS priority protection sites occur within the projected oil plumes impact W-6 

Environmentally area or vicinity. C-14 

Sensitive Areas The nearest priority protection sites are located at the mouth of Fish Creek, 

approximately 3.5 miles north of the blowout well. A Sensitive Area 

Protection Task Force is deployed to the following priority protection sites: 

Priority Site # Map Atlas Boom Required (ft) Tactic 

34 7 600 C-14 

35 7 500 C-14 

36 7 1,000 C-14 

37 7 300 C-14 

38 6 300 C-14 

39 6 300 C-14 

Response activities are conducted away from cultural sites, based on a 

cleanup plan approved by the Unified Command, in consultation with the 

ADNR Office of History and Archaeology (OHA). 

ACS Map Atlas, 

Sheets 6 and 7 

Alpine Field, Satellites, and Pipelines ODPCP 1-20 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

TABLE 1-6 (CONTINUED): WELL BLOWOUT IN SUMMER - RESPONSE STRATEGY 

ADEC 

REQUIREMENT RESPONSE STRATEGY ACS TECHNICAL MANUAL TACTIC 

(v) Protection of Pre-staged equipment and pre-deployed boom are located at numerous Pre-staged 

Environmentally locations in the Alpine area (see Figure 3-3). Resources are redistributed as Equipment: ACS 

Sensitive Areas needed for priority protection sites and exclusion booming areas. The Map Atlas, Sheets 

(continued) resources include: 

• ALP-9 is located on the Nigliq Channel. It contains 4,350 feet of river 

boom, a 3-inch trash pump, a drum or brush skimmer, two anchor 

systems and four 2,500-gallon (59-barrel) open-top storage units. 

• Approximately 200 feet of river boom are seasonally pre-deployed at NK3, Nanuq Lake and 1,500 feet of river boom is storage at NK-4.. 

• Seasonal pre-deployed boom in the Sakoonang Channel consists of 

approximately 500 to 750 feet of river boom deployed at both SK-13 and 

SK-15 control sites, upstream and downstream of CD1. 

• Three locations along the Sakoonang Channel contain response 

equipment. Locations ALP-5, ALP-10, and ALP-14 each contain over 

1,000 feet of river boom, a 3-inch trash pump, a drum or brush skimmer, 

at least two anchor systems and at least four 2,500-gallon (59-barrel) 

open-top storage units. No oil is projected to fall in the Sakoonang 

Channel; consequently, all equipment is available to be re-allocated to 

priority protection sites and exclusion booming areas. 

8, 9, 12, 16, 17, 20, 

21, and 22 

(vi) Spill Upon initial reports and assessment of the blowout, ACS begins 

Containment transportation of additional containment and recovery equipment from L-3 

and Control Deadhorse and other North Slope facilities to Alpine. Equipment is 

Actions transported via air to a staging area at CD1. On Day 1, additional vessels 

are deployed from Oliktok Point or West Dock. The Alpine airstrip remains 

in operation to support response efforts. 

COPA, in conjunction with ACS, begins obtaining the proper permits 

needed for spill response operations. 

A-3 

Crews work cross-wind or upwind of the aerial oil plume. All containment 

and control activities are conducted in accordance with ACS and COPA site 

entry protocols. 

Pad and Tundra Containment and Control: 

Resources are mobilized by Day 2 to provide containment and control of oil 

that enters pad and tundra environments. Efforts continue throughout the 

blowout and after the blowout ends until oil is cleaned up. Mobilized 

resources are appropriate to provide sufficient containment and control to 

clean up the RPS volume spilled to pad and tundra surfaces. 

S-1 to S-6 

Task Force 1 (TF-1) builds trenches and berms at strategic locations on 

and off the pad to contain oil and control its movement away from water 

bodies and site access points. Work conducted near the blowout is carefully 

C-3 

C-4 

monitored for safety; no ignition sources are allowed in hot zones and 

proper PPE is required. 

The pad retains oil up to 0.125 barrel per cubic yard (cu yd) of gravel. The 

pad retains an estimated 1,370 barrels of oil over an approximate area of 

98,579 square feet, assuming a depth of 3 feet. The remaining oil spreads 

on the surface of the pad. 

Lake Containment and Control: 

Resources are mobilized by Day 2 to provide containment and control of oil 

that enters open water environments. Efforts continue throughout the 

blowout and after the blowout ends until oil is cleaned up from water 

surfaces within 72-hours of the end of the blowout. 

R-26 

Task Force 2 (TF-2) deploys and maintains deflection and exclusion boom 

on lakes for collection and recovery of oil spilled on-water. 

C-5 

Alpine Field, Satellites, and Pipelines ODPCP 1-21 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TABLE 1-6 (CONTINUED): WELL BLOWOUT IN SUMMER - RESPONSE STRATEGY 

ADEC 

REQUIREMENT RESPONSE STRATEGY ACS TECHNICAL MANUAL TACTIC 

(vii) Spill Recovery Resources are mobilized by Day 2 to provide effective recovery of oil that 

Procedures pools on pad and tundra surfaces and that enters open water environments. 

Spill recovery efforts continue throughout the blowout and after the blowout 

ends until oil is cleaned up. Mobilized resources are sufficient to provide 

enough recovery capacity to cleanup an estimated 4,300 bbl spilled to open 

water by Day 18 (i.e., 72-hours after the blowout ends), as well as the 

additional RPS volume spilled to pad and tundra surfaces. Estimated 

recovery capacity and handling capacity indicate the RPS volume could be 

cleaned up in approximately 15 days under normal, continuous operations 

(see Table 1-7 for recovery capacity rates). 

Recovery operations begin after safety protocols are established. Recovery 

continues for the duration of the blowout as long as conditions allow for safe 

operations. 

Pad and Tundra Liquid Recovery: 

In areas on and nearby the gravel pad, where up to 80% of the oil is 

deposited, recovery task forces target pooled oil in berms and trenches 

created by TF-1 and natural depressions. 

Task Force 3 (TF-3): TF-3 mobilizes five vacuum trucks, and associated 

pumps and hoses from locations within Alpine. TF-3 begins recovery of oil 

S-1 to S-6 

by direct suction from the drainage basins and the bermed and trenched 

areas containing oil that falls on and off the pad. If oil is encountered on 

water, it is recovered with a Manta Ray skimmer head. Vacuum trucks can 

recover liquid oil up to 200 feet from the truck. 

Task Force 4 (TF-4): by Day 2 TF-4 mobilizes three Rolligons with 10,000-

gallon tanks and trash pumps for recovery of oil by direct suction in areas 

R-6, R-7 

on the tundra that are inaccessible by vacuum truck. The Rolligons transfer 

recovered oil to temporary storage tanks or vacuum truck staged along the 

CD5 access road. An all-terrain vacuum unit is used as needed to reach 

pools of oil. 

Tundra and Lake Liquid Recovery: 

R-6, R-7, R-23 

Task Force 5 (TF-5): TF-5 uses portable skimmers and pumps to recover oil 

from depressions in tundra that the vacuum trucks and Rolligons cannot 

access. Rope mop skimmers are used to skim oil on tundra. Drum/brush 

skimmers are used to skim oil on lakes at collection points established and 

R-8, R-24 

maintained by TF-2. Portable tanks or bladders are deployed with TF-5 to 

provide sufficient on-site storage. TF-4 provides transfer of recovered fluids 

from temporary storage at TF-5 sites. TF-5 targets areas outside of active oil 

deposition, moving equipment and adjusting number of recovery systems, as 

the oil plume shifts with the prevailing wind direction. 

R-23 

An offshore Task Force is deployed to Harrison Bay to recover any oil that 

may escape. No oil is encountered and no mini barge is deployed. 

Once well control is achieved, recovery teams have full access to oiled 

tundra, water, and gravel. Task forces maximize the number of personnel 

and equipment to recover oil from water surface. Once the oil is recovered 

from the water surface, cleanup of the tundra and pad surfaces begins: 

R-17 

Task Force 6 (TF-6): TF-6 begins the process of flushing the tundra 

surface. Oil is recovered by hand using sorbent materials. Plywood 

walkways are used to minimize traffic damage to the tundra. 

R-4, R-9 

Upon approval through the Unified Command, a Thermal Remediation Task 

Force uses weed burners to remove heavily oiled vegetation. Burning is 

conducted so that smoke and embers do not interfere with activities 

occurring at downwind locations. 

B-2 

Alpine Field, Satellites, and Pipelines ODPCP 1-22 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TABLE 1-6 (CONTINUED): WELL BLOWOUT IN SUMMER - RESPONSE STRATEGY 

ADEC 

REQUIREMENT RESPONSE STRATEGY ACS TECHNICAL MANUAL TACTIC 

(vii) Spill Recovery Pad Decontamination and Oiled Gravel Removal: 

Procedures 

(continued) Task Force 7 (TF-7): TF-7 works on a non-emergency basis to pressure 

wash oil from structures on the pad. Once the structures are cleaned, oily 

gravel is recovered and stored in temporary, lined stockpiles at drill sites 

and/or Kuukpik pad. Estimated handling capacity rates indicates the volume 

of impacted gravel could be excavated and transported to lined storage in 

10 days. 

R-21, R-26 

D-2 

(viii) Lightering, Not applicable. 

Transfer, & 

Storage from

Tanks at Risk 

Procedures 

(ix) Transfer and A temporary storage area and tank farm are established on the CD5 access D-1 

Storage of road. Portable tanks available from on-site equipment inventory temporarily 

Recovered store recovered oil and water until it is recycled into the production stream 

Oil/Water; by in-place production facilities at Alpine. Alpine has at least ten 400-barrel 

Volume upright and five 500-bbl horizontal oil storage tanks, and up to 22, 59-barrel 

Estimating open-top tanks, seven 14- barrel Fold-a-Tanks, and five 119-barrel bladder 

Procedure tanks are for temporary storage. Additional storage capacity is available 

from ACS. 

Portable tanks containing fluids recovered by Task Forces 4, and 5 provide 

sufficient storage for oil recovered from tundra and water bodies to the east, 

west, and southwest of the pad. Rolligons with tanks transfer recovered oil 

and water from these portable tanks to temporary storage at CD5 access 

road, then vacuum trucks transport fluids directly to the Alpine production 

facility at CD1 for recycling. 

The amount of oil is gauged using a Coliwasa tube or by other appropriate 

means. 

L-6 

R-23 

(x) Plans, A waste management plan is prepared and approved by Unified Command. D-1 to D-4 

Procedures, The appropriate permits for waste storage and disposal are obtained. 

and Locations 

for Temporary Temporary storage areas are established within secondary containment on 

Storage and the CD1 airstrip apron, Kuukpik pad, and/or drill sites for interim oil storage, 

Disposal contaminated soils, contaminated gravel, and oily wastes, as needed. 

Wastes are characterized and disposed of accordingly. 

Storage tanks and stockpiles are monitored until all contents have been 

processed. 

Recovered oil is recycled into the production stream via the processing 

facility. 

In winter, the contaminated gravel and soil is transported by truck to 

Kuparuk DS-1H for processing. 

Non-liquid oily wastes and non-oily wastes are classified and disposed of 

accordingly. 

(xi) Wildlife Resources at risk primarily are birds. Exclusionary methods are W-1 through W-6 

Protection Plan implemented to keep oil away from bird habitat. Additionally, hazing 

operations are initiated and captive/treatment and stabilization is conducted 

as needed, under authorization from the appropriate resource agencies. 

Under Unified Command, the FOSC determines the need for, and makes 

the request for, resource agency review and authorization. Refer to the 

Unified Plan, Annex G: Wildlife Protection Guidelines. 

International Bird Rescue is mobilized to make the wildlife stabilization 

facility operational on Day 2. 

L-9 

Alpine Field, Satellites, and Pipelines ODPCP 1-23 February 2018, Rev. 0 
 

 

 

 

TABLE 1-6 (CONTINUED): WELL BLOWOUT IN SUMMER - RESPONSE STRATEGY 

ADEC 

REQUIREMENT RESPONSE STRATEGY ACS TECHNICAL MANUAL TACTIC 

(xi)Wildlife Foxes and grizzly bears that may be either in the area or otherwise W2-A 

Protection Plan attracted to the site are hazed from the oiled areas. 

(continued) Trained personnel collect dead, oiled wildlife to reduce the risk of other 

wildlife preying on oiled carcasses. 

W-4 

(xii)Shoreline 

Cleanup Plan 

Shoreline cleanup operations are initiated based on a plan approved by 

Unified Command. A shoreline assessment is conducted to understand the 

nature and extent of oiling and to establish cleanup priorities. Cleanup 

techniques utilized are based on shoreline type and degree of oiling. 

Primary shoreline cleanup techniques considered include: 

• Natural recovery for areas of residual oiling where other cleanup 

techniques would cause harm or damage. 

• Flooding of minor to moderately oiled shoreline. 

• Manual or mechanical removal or tilling and aeration of oiled 

sediments or debris. 

• Burning of oily vegetation. 

SH-1 through SH-6 

B-1 

Alpine Field, Satellites, and Pipelines ODPCP 1-24 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

TABLE 1-7: WELL BLOWOUT IN SUMMER - OIL RECOVERY CAPACITY 

A B C D E F G 

SPILL 

RECOVERY 

TACTIC 

NUMBER 

OF 

SYSTEMS 

RECOVERY OR 

TRANSFER 

SYSTEM 

OIL 

RECOVERY 

RATE PER 

SYSTEM 

(bph) or 

(yd3/hr) 

MOBILIZATION, 

DEPLOYMENT 

AND TRANSIT 

TIME TO SITE 

OPERATING 

TIME 

(hours per 

24-hour 

shift) 

RECOVERY 

CAPACITY 

B x D x F 

TF-3. On/near 

pad recovery: 

R-6, R-7 

5 Vacuum truck 83 bph 1 4 hours 20 8,300 bpd 

TF-3 Handling Capacity: 8,300 bpd 1 

TF-4. On tundra 

recovery: 

R-6, R-7 3 

Rolligons with 

tanks transferring 

to tanks or vacuum 

truck on CD5 road 

52 bph 2 Day 2 20 3,120 bpd 

1 

Vacuum unit, allterrain with 110-

gallon tank 

700 yd3

/hr 

vacuum; 0.5 

yd3

/hr /tank 

Day 2 3 20 > 50 bpd 

> 10 yd3

/d 

10 400-barrel Upright 

Oil Storage Tanks 

(temporary 

storage) Day 2 3 -- 4,000 bbl 

TF-5. On 

tundra/lake 

recovery 

R-8, R-24 

8 

Action AP24MD 

Drum/Brush 

skimmer 

20 bph Day 2 3 20 3,200 bpd 

5 Rope Mop MW-41 

skimmer 5 bph Day 2 3 20 500 bpd 

1 Lamor MM30 5-Belt 

Brush skimmer 50 bph Day 2 3 20 100 bpd 

8 Manta Ray Slickbar 

Rigid skimmer 11 bph Day 2 3 20 1,760 bpd 

37 59-barrel Open Top 

Tank 

(temporary 

storage) Day 2 3 -- 2,183 bbl 

26 3,000-gallon 

Folding Tank 

(temporary 

storage) Day 2 3 -- 1,857 bbl 

12 600-gallon Folding 

Tank 

(temporary 

storage) Day 2 3 -- 171 bbl 

4 1000-gallon Folding 

Tank 

(temporary 

storage) Day 2 3 -- 95 bbl 

TF-4 and TF-5 Handling Capacity: 3,320 bpd 2 

TF-7. Oiled 

gravel removal 

R-26 

2 

Dozer/Front-end 

Loader/Bobcat with 

Dump Truck 

28 yd3

/hr 4 Day 15, Nonemergency 

response 

20 1,120 yd3/d 

2 Supersucker 14 yd3

/hr 20 168 yd3/d 5 

TF-7 Handling Capacity: 1,288 yd3/d 

1. TF-3 vacuum truck recovery rate is calculated as Oil Recovery Rate (ORR) = Vacuum Truck Capacity / Time, where Time = 

(miles to disposal * 2 trips / 35 mph) + 2(Tc / Sr), and where: 

miles to disposal is 9.75 from CD5 to CD1 

Tc = Vacuum Truck Capacity = 300 bbl 

Sr = Suction Rate = 200 bph 

Time = (9.75 mi * 2 / 35 mph) + 2(300 bbl / 200 bph) = 3.6 hours 

ORR = 300 bbl / 3.6 hrs = 83 bph 

TF-3 vacuum trucks transfer recovered liquids directly to recycle facilities for disposal; therefore the handling capacity is 8,300 

bpd. 

Alpine Field, Satellites, and Pipelines ODPCP 1-25 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

2. TF-4 Rolligon tank truck recovery rate: is calculated as ORR = Vacuum Truck Capacity / Time, where: 

Time = (miles to transfer point * 2 trips / 5 mph) + 2(Tc / Sr), and where: 

Tc = Rolligon tank truck capacity = 238 bbl 

Sr = Suction Rate = 114 bph 

Time = (1 mile to CD5 road * 2 trips / 5 mph) + 2(238 bbl / 114 bph) = 4.6 

ORR = 238 bbl / 4.6 hrs = 51.7 bph 

TF-4 Rolligons also support TF-5 to transfer recovered liquids to nearby temporary storage tanks at the CD5 access road. If 

the Rolligons have a recovery capacity of 3,120 bpd, they can fill the ten (10) 400-bbl storage tanks in one day. Vacuum trucks 

offload the tanks and transfer recovered liquids directly to recycle facilities for disposal. Two (2) vacuum trucks can offload the 

temporary storage tanks at a rate of 3,320 bpd (e.g., 2 trucks * 83 bph * 20 h). Therefore, the handling capacity for TF-4 and 

TF-5 is 3,320 bpd. 

3. Equipment utilized is available from existing inventory at Alpine; therefore, it is mobilized and deployed as soon as response 

strategies and objectives are established. Additional equipment could be mobilized from ACS base and mutual aid operators, if 

necessary. Derated recovery rate values obtained from ACS Technical Manual Tactic L-6. 

4. TF-7 dump truck recovery rate is calculated as Tc/(Lt+Tt+Ut), where: 

Tc = Truck Capacity = 25 cu yd 

Lt = Load Time = 0.25 hr 

Tt = Travel Time = miles to lined storage * 2 trips / 35 mph = 9.75 mi * 2 trips / 35 mph = 0.56 

Ut = Unload Time = 0.08 hr 

Dump Recovery = 25 cu yd /(0.25 hour + (9.75 miles * 2 trips / 35 mph) + 0.08 hour) = 28.2 cu yd/hr 

5. Recovery rate is based on Tactic R-5. The Supersucker recovery rate is approximately 14 cu yd per hour. Transit time to lined 

storage and back is approximately 0.5 hour; therefore, 6 full loads are made per shift. 

Alpine Field, Satellites, and Pipelines ODPCP 1-26 February 2018, Rev. 0 
 

 

 

 

 

 

TABLE 1-8: WELL BLOWOUT IN SUMMER - RECOVERY AND PROTECTION EQUIPMENT 

RESPONSE 

FUNCTION TASK FORCE TACTIC EQUIPMENT TOTAL QUANTITY 

SHORELINE AND SENSITIVE AREA PROTECTION UNIT 

Sensitive Area 

Protection 

Priority Protection Sites C-14 Work boat 

Boom 

2 

variable 

Cultural Resource Protection W-6 Helicopter 1 

Shoreline Protection Discharge Tracking T-4 Fixed wing aircraft with FLIR 1 

SPILL RESPONSE UNIT 

Containment and 

Control Group 

TF-1. Pad and tundra C-4 Backhoe 

Front-end loader 

Bobcat with trencher 

1 

2 

1 

TF-2. Lake C-5 Work boat 

Boom 

Anchor system 

2 

>50 ft 

variable 

Liquid Recovery 

Group TF-3. On/near pad 

R-6 / R-7 Vacuum Truck 

4-inch pumps 

Suction and discharge hose 

5 

5 

variable 

TF-4. Tundra recovery R-6 / R-7 

R-23 

Rolligon 

4-inch pumps 

Suction and discharge hose 

Vacuum Truck 

3 

3 

Variable 

2 

TF-5. Tundra and lake R-8 

R-24 

Skimmers 

Storage 

All-terrain vehicle 

3- to 4-inch pumps 

Suction and discharge hose 

Up to 22 

Up to 79 

2 

≥ 44 

variable 

Oiled Surface 

Cleanup Group 

TF-6. Tundra flush and burn R-4 

R-9 

B-2 

Water Truck or Upright Tank 

Pump 

Suction and discharge hose 

Sorbent boom 

Weed burner, propane tank 

1 

1 

variable 

variable 

1 

TF-7. Oiled gravel removal R-21 

R-26 

Water wash van 

Front-end loader 

Bobcat 

Dump truck 

Supersucker 

1 

1 

1 

2 

2 

WILDLIFE PROTECTION UNIT 

Wildlife Hazing 

Group 

Mammal and Bird Hazing W-2A 

W-2B 

Wildlife hazing kit 

Propane exploder cannon 

1 

1 

Oiled Wildlife 

Recovery Group 

Capture W-3 Helicopter 1 

Salvage W-4 Various transportation variable 

Stabilization W-5 ACS Mobile Wildlife 

Stabilization Center 

1 

Alpine Field, Satellites, and Pipelines ODPCP 1-27 February 2018, Rev. 0 
 

 

 

 

 

 

TABLE 1-9: WELL BLOWOUT IN SUMMER - STAFF TO OPERATE OIL CONTAINMENT, 

RECOVERY, AND TRANSFER EQUIPMENT 

TASK 

FORCE TACTIC NO. 

UNIT 

NO. STAFF PER SHIFT 

NOTE TEAM 

LEADER 

SKILLED 

TECH. 

GENERAL 

LABORER 

VESSEL 

OPERATOR 

EQUIPMENT 

OPERATOR 

Protection C-14 1 4 2 -

TF-1 C-4 1 

1 

- - - 4 Team Leader 

supports both 

TF TF-1 and TF-2 -2 C-5 2 - 4 2 -

TF-3 R-6, R-7 5 

1 

5 - - 5 Team Leader 

supports both 

TF TF-3 and TF-4 -4 R-6, R-7, 

R-23 3 3 - - 5 

TF-5 R-8, R-24 22 1 22 44 - -

TF-6 R-4, R-9, B-2 1 1 2 2 - 1 

Deployed after 

Day 15 TF-7 R-21, R-26 1 1 - 2 - 7 

TOTAL 5 32 56 4 22 

Alpine Field, Satellites, and Pipelines ODPCP 1-28 February 2018, Rev. 0 
 

 

 

FIGURE 1-3: WELL BLOWOUT IN - SUMMER WIND ROSE DIAGRAM 

Per convention, the wind rose illustrates direction of wind origin (i.e., where the wind is coming from). Wind data are 

derived from the NOAA Global Historic Climatology Network Nuiqsut Station. Data reflects wind direction during August, 

as recorded 2012-2016. 

Alpine Field, Satellites, and Pipelines ODPCP 1-29 February 2018, Rev. 0 
FIGURE 1-4: SIMULATED OIL PLUME TRAJECTORY FOR SUMMER BLOWOUT 

Alpine Field, Satellites, and Pipelines ODPCP 1-30 February 2018, Rev. 0 
FIGURE 1-5: SIMULATED OIL PLUME TRAJECTORY FOR SUMMER BLOWOUT - PAD 

DETAIL 

Alpine Field, Satellites, and Pipelines ODPCP 1-31 February 2018, Rev. 0 
BLANK PAGE 

Alpine Field, Satellites, and Pipelines ODPCP 1-32 February 2018, Rev. 0 
SCENARIO 2 

WELL BLOWOUT IN WINTER 

Alpine Field, Satellites, and Pipelines ODPCP 1-33 February 2018, Rev. 0 
BLANK PAGE 

Alpine Field, Satellites, and Pipelines ODPCP 1-34 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TABLE 1-10: WELL BLOWOUT IN WINTER - TYPICAL ENVIRONMENTAL CONDITIONS 

Spill Location Production well CD5-313 on Alpine CD5 Pad 

Date / Time February 15 / 0800 

Duration 15 days 

Source of Spill Although production wells are secured with a wellhead or blowout preventer while drilling, and 

are enclosed, this scenario assumes an uncontrolled well blowout occurs through an 

unobstructed open orifice. 

Cause of Spill Underbalanced well and failure of pressure control systems. 

Quantity of Oil Spilled RPS Volume: 150,000 barrels 

Based on a maximum production rate of 10,000 bopd and a blowout duration of 15 days. 

Emulsification Factor Not applicable. Oil falls to snow and ice; no oil reaches open water. 

Type of Spilled Oil North Slope Alpine Crude 

Wind Speed Average wind speed in February is 27 mph 

Wind Direction The predominant wind directions are NE, ENE, and E. The winds blow from the NE 50% of 

the time (8 days), from the ENE 30% of the time (4 days) and from the E 20% of the time (3 

days). 

• Day 1 through 8: wind from NE 

• Day 9 through 12: wind from ENE 

• Day 13 through 15: wind from E 

Current Not applicable. Oil falls to frozen water surfaces; no oil reaches flowing water. 

Air Temperature -20 °F 

Surface Well is on a gravel pad located approximately 4 miles west of the Nigliq Channel, and 

approximately 8 miles west of CD1. Surrounding surface is frozen, snow-covered tundra, and 

frozen tundra lakes and streams. 

Trajectory The simulated blowout is discharging at a rate of10,000 bopd with a GOR of 650scf/bbl. 

The SL Ross plume dispersion model published in ACS Technical Manual Tactic T-6 projects 

that the oil takes the form of an aerial plume extending from the well in the direction of the 

predominant wind directions. The blowout discharges 150,000 barrels to the SW, WSW, and 

W of well CD5-313 (Figure 1-6). The model predicts the following plume dimensions: 

• 70% of the discharged oil falls within 430 feet downwind of the well. At that distance, the 

plume is about 90 feet wide. 

• 80% of the discharged oil falls within 1,275 feet downwind of the well. At that distance, the 

plume is about 235 feet wide. 

• 90% of the discharged oil falls within 8,885 feet (1.7 mile) downwind of the well. At that 

distance, the plume is about 1,355 feet wide. 

• According to the SL Ross model, 10% of discharged oil is in the form of droplets so small 

(50 micrometers or less) that they do not fall to the ground. 

Under the SL Ross model, approximately 70% (105,000 barrels) of the discharged oil falls on 

the CD5 pad. Not all oil falling on the pad is retained by the gravel. If not recovered, discharged 

oil accumulates in low-lying areas and eventually flows off the pad. Approximately 30,000 

barrels of oil falls beyond the pad. 

Alpine Field, Satellites, and Pipelines ODPCP 1-35 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TABLE 1-11: WELL BLOWOUT IN WINTER - RESPONSE STRATEGY 

ADEC 

REQUIREMENT RESPONSE STRATEGY ACS TECHNICAL MANUAL TACTIC 

(i) Stopping Efforts are made to bring the well under control. Emergency shutdown 

Discharge at procedures are initiated. 

Source When it is determined that control of the well cannot be immediately 

regained, and safety of personnel is at risk, personnel are evacuated to the 

pre-designated safe area. At all times, the safety of personnel is COPA’s 

first concern. No unauthorized personnel are allowed near the spill area. 

The Drilling/Wells Supervisor notifies the Drilling/Wells Superintendent. 

Security is notified, and the proper notifications and reports are made 

according to the COPA Drilling & Wells Emergency Preparedness & 

Blowout Contingency Plan. 

Boots & Coots is activated and dispatched from Houston, Texas within 12 

hours. 

The COPA IMT is activated; the Source Control team develops a well 

control strategy and coordinates logistics for mobilizing well capping 

resources. 

Boots & Coots initiates plans to cap the well. 

The blowout is controlled on Day 15. 

(ii) Preventing or Throughout the first few hours of the spill, the Site Safety Officer verifies S-1 to 

Controlling Fire that all sources of ignition are shut down or removed from the area. The S-6 

Hazards Site Safety Officer provides access zone information and determines PPE 

requirements. Access to the spill site is carefully controlled and the scene is 

secured by Security. Monitoring protocol is established by the Site Safety 

Officer for all work areas to ensure personnel protection. The monitoring 

protocol establishes safety zones according to applicable Occupational 

Safety and Health Administration (OSHA) and fire hazard standards. No 

personnel are allowed in the hot zones unless proper PPE is worn, and it is 

permitted by the Site Safety Officer. 

Containment and recovery operations are allowed without respiratory 

protection in areas where safety criteria are met. Recovery operations, oil 

field operations, and traffic are not allowed downwind of the blowout well in 

areas where personnel may become exposed to flash fire hazard or to oil 

particulate matter at concentrations in excess of permissible exposure 

limits. Firewater coverage is set up. 

(iv) Surveillance 

and Tracking of

Oil on Open 

Water; 

Forecasting

Shoreline 

Contact Points 

Blowout plume model is run. The extent of oil on the snow is delineated so 

that it can be found if subsequent snowfall or blowing snow covers the spill. 

Initial estimates are made as to volume of spilled oil. 

T-6 

T-1, T-7 

(v) Protection of All oil falls to the ground and is absorbed by either the pad or snow. No ACS Map Atlas, 

Environmentally ACS priority protection sites are impacted. In consultation with ADNR OHA Sheets 6 and 7 

Sensitive Areas. Unified Command identifies cultural sites in the vicinity of the response area 

so as to avoid disturbance. 

(vi) Spill Task Force 1 (TF-1): Pad Containment and Control C-1 

Containment When it is determined safe to do so, berms are constructed on and off the S-1 to S-6 

and Control pad to provide initial containment. Containment berms and trenches are Actions built to divert oil to low-lying areas and/or contain it on the pad. Berms and 

trenches are raised/shored-up on a continuous basis, as needed. Work 

conducted near the blowout is carefully monitored for safety; no ignition 

sources are allowed in hot zones and proper PPE is required. 

Alpine Field, Satellites, and Pipelines ODPCP 1-36 February 2018, Rev. 0 
TABLE 1-11 (CONTINUED): WELL BLOWOUT IN WINTER - RESPONSE STRATEGY 

ADEC 

REQUIREMENT RESPONSE STRATEGY ACS TECHNICAL MANUAL TACTIC 

(vi) Spill Task Force 2 (TF-2): Frozen Tundra Containment and Control C-4, C-18, C-19 

Containment TF-2 constructs containment berms on frozen tundra using large diameter and Control hoses or sorbent. Areas of lightly oiled snow are contained using water spray Actions 

(continued) and snow fencing. 

Temporary containment areas are built: Two 150 feet x 200 feet x 2 feet 

lined storage pits are constructed at Kuukpik Pad. The pits are bermed to a 

height of 3 feet. The pits contain snow piled to a height of 15 feet. These 

storage areas are for staging contaminated snow and storing any that 

cannot be transported off site. 

D-2 

(vii) Spill Recovery On Day 1, the equipment for the recovery, transfer, and interim storage of 

Procedures oiled snow and recovered oil is mobilized. Recovery crews work cross-wind 

or upwind of the aerial plume. All recovery activities are conducted in 

accordance with ACS and COPA site entry protocols. 

S-1 to S-6 

Task Force 3 (TF-3): Liquid Recovery 

TF-3 uses seven vacuum trucks to recover oil from low-lying area and 

bermed and trenched areas containing oil. Vacuum trucks can recover 

liquid oil up to 200 feet from the truck. 

Three Rolligons with 10,000 gallon tanks and trash pumps are used for 

recovery of oil in areas that area inaccessible by vacuum truck. Pumps and 

hoses in series are also used to recover liquids that are difficult to access. 

Rolligons transfer fluids to 400-barrel upright storage tanks staged on the 

CD5 access road to provide temporary on-site storage. Vacuum trucks 

transfer recovered liquids from the CD5 access road site. 

R-6, R-7, R-23, R-24 

Task Force 4 (TF-4): Mechanical Snow Recovery 

TF-4 uses dozers, front-end loaders, trimmers, and Bobcats, to collect oiled 

snow and load into dump trucks (48 cu yd) to recover oiled snow. Dump 

trucks transfer oiled snow to interim storage 2.5 miles from the blowout site. 

R-1, R-3 

Task Force 5 (TF-5): Manual Snow Recovery 

In areas safe for personnel to operate, and after well control is achieved, 

TF-5 uses of shovels, brooms, snow blowers, snow machines and all-terrain 

vehicles to collect lightly oiled snow. Dump trucks transfer oiled snow to 

interim storage 2.5 miles from the blowout site. 

Once surface control is achieved, allowing full access to the oiled snow. TF3. TF-4, and TF-5 increase to maximum number of systems. TF-1 and TF-2 

demobilize, as containment and control is no longer needed. 

Task Force 6 (TF-6): Pad Decontamination 

R-2 

Cleanup and recovery operations are conducted on a non-emergency 

basis. TF-6 pressure washes oil from the structures on the pad. Once the 

structures are cleaned, oily gravel is recovered and stored for proper 

disposal. 

Task Force 7 (TF-7): Embedded Oil / Oiled Gravel Removal 

R-21 

Oiled gravel is excavated on a non-emergency basis. Trimmers and frontend loaders excavate oiled gravel. Dump trucks haul the oiled gravel to 

R-5, R-26 

stockpiles at Kuparuk. D-4 

(viii) Lightering 

Procedures 

Not applicable. 

(ix) Transfer and Recovered liquids are transported to Alpine production facilities ACF for D-1, D-5 

Storage of recycling into the Alpine oil processing stream. Volume of oil is gauged 

Recovered using a Coliwasa tube or by other appropriate means and loads are 

Oil/Water; manifested accordingly. 

Volume Oiled snow recovered by TF-4 and TF-5 is loaded into dump trucks for Estimating transport via the Alpine re-supply ice road to Kuparuk CPF1 for Procedure disposal/recycling, according to an approved waste management plan. 

Alpine Field, Satellites, and Pipelines ODPCP 1-37 February 2018, Rev. 0 
TABLE 1-11 (CONTINUED): WELL BLOWOUT IN WINTER - RESPONSE STRATEGY 

ADEC 

REQUIREMENT RESPONSE STRATEGY ACS TECHNICAL MANUAL TACTIC 

(x) Plans, Heavily oiled snow recovered by TF-4 and is taken to the temporary staging D-1, D-2, D-5 

Procedures, areas at Kuukpik pad to await transfer via the Alpine re-supply ice road to 

and Locations Kuparuk CPF1 for interim storage and proper disposal. 

for Temporary 

Storage and 

Disposal 

The temporary storage pits are continuously monitored until all contents 

have been processed. 

D-2 

Oil recovered by vacuum trucks is recycled back into the production stream 

via the Alpine oil processing system. 

D-1 

Non-liquid oily wastes are classified and disposed of accordingly. 

Non-oily wastes are classified and disposed of accordingly. 

D-3 

Oiled gravel is transported to a disposal site in Kuparuk, and disposed of 

accordingly. 

D-4 

(xi) Wildlife 

Protection Plan 

Polar bear monitors are assigned to protect bears and workers. Facilities 

are made available to agency biologists and veterinarians standing by for 

potential reports of oiled bears. No wildlife becomes oiled. 

W-1, W-2, 

W-2A, W-2B 

(xii) Shoreline 

Cleanup Plan 

Not applicable. Not applicable 

Alpine Field, Satellites, and Pipelines ODPCP 1-38 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

TABLE 1-12: WELL BLOWOUT IN WINTER – OIL RECOVERY AND HANDLING CAPACITY 

SPILL RECOVERY TACTIC NUMBER OF 

SYSTEMS RECOVERY SYSTEM 

OILED SNOW 

RECOVERY 

RATE 

[yd3

/hr or bph] 

MOBILIZATION 

AND TRANSIT 

TIME TO SITE 

[TIME] 

OPERATING 

TIME 

(hr/day) 

HANDLING 

CAPACITY 

[yd3

/day or bpd] 

(B X D X F) 

TF-3. Liquid Recovery 

R-6, R-7 7 Vacuum truck 65 bph 1 4 hours 20 9,100 bpd 

TF-3. Liquid Recovery 

R-6, R-7 / R-23 3 Rolligon with 10,000-gallon tank 52 bph 2 Day 2 20 3,120 bpd 

TF-3. Liquid Recovery 

R-24 variable 3- to 4-inch pump, hoses, 

portable tanks 52 to 65 bph 3 Day 2 4 20 > 1,040 bpd 

TF-4. Mechanical Recovery 

R-1, R-3 

6 dump 

trucks 

Dozer/Front-end loader/ Bobcat, 

2 Dump trucks 53 yd3

/hr 5 Day 2 4 20 6,336 yd3/d 

TF-5. Manual Recovery 

R-2 20 

Shovels, brooms, all-terrain 

vehicle/snow machine, frontend loader, dump truck 

3 yd3

/hr Day 15 20 600 yd3/d 

TF-4 & TF-5 

Transfer 

20 dump 

trucks 

Front-end loader, 2 Dump 

trucks 10.5 yd3

/hr 6 Day 2 4 20 4,200 yd3/d 

TF-7. Embedded Oil / Oiled 

Gravel Removal and 

Transfer 

R-5 

10 (dump 

trucks) 

Trimmer/Front-end loader, 

Dump truck 10.5 yd3

/hr 6 

Day 15 

non-emergency 

response 

20 2,100 yd3

/d 

1. TF-3 vacuum truck recovery rate is calculated as Oil Recovery Rate (ORR) = Vacuum Truck Capacity / Time, where Time = (miles to disposal * 2 trips / 35 mph) + 2(Tc / Sr), and 

where: 

miles to disposal is 9.75 from CD5 to CD1 

Tc = Vacuum Truck Capacity = 300 bbl 

Sr = Suction Rate = 150 bph 

Time = (9.75 mi * 2 / 35 mph) + 2(300 bbl / 150 bph) = 4.6 hours 

ORR = 300 bbl / 4.6 hrs = 65.2 bph 

2. TF-4 rolligon tank truck recovery rate: is calculated as ORR = Vacuum Truck Capacity / Time, where: 

Time = (miles to transfer point * 2 trips / 5 mph) + 2(Tc / Sr), and where: 

Tc = Rolligon tank truck capacity = 238 bbl 

Sr = Suction Rate = 114 bph 

Time = (1 mile to CD5 road * 2 trips / 5 mph) + 2(238 bbl / 114 bph) = 4.6 

ORR = 238 bbl / 4.6 hrs = 51.7 bph 

3. Off pad liquid recovery using hoses and pumps in series can recover at rates exceeding 52 to 65 bph; however, vacuum trucks or Rolligons with tanks offload temporary portable 

tanks and transport liquids to disposal, so the effective recovery rate is 52 to 65 bph. 

4. Equipment utilized is available from existing inventory at Alpine; therefore, it is mobilized and deployed as soon as response strategies and objectives area established. 

Additional equipment could be mobilized from ACS base and mutual aid operators, if necessary. 

Alpine Field, Satellites, and Pipelines ODPCP 1-39 February 2018, Rev. 0 
5. TF-4 dump truck recovery rate is calculated as Tc/(Lt+Tt+Ut), where: 

Tc = Truck Capacity = 25 cu yd 

Lt = Load Time = 0.25 hr 

Tt = Travel Time = miles to interim storage * 2 trips / 35 mph = 2.5 mi * 2 trips / 35 mph = 0.14 hr 

Ut = Unload Time = 0.08 hr 

Dump Recovery = 25 cu yd /(0.25 hour + (2.5 miles * 2 trips / 35 mph) + 0.08 hour) = 53 cu yd/hr 

6. For TF-7, a trimmer set at a six-inch depth can chip approximately 160 yd3 of ice per hour; however, due to the long travel distance to disposal (e.g., Kuparuk DS1H) the recovery 

rate is based on dump truck handling capacity, as follows: 

TF-4, TF-5, and TF-7 maxi-haul or Euclid B-70 recovery rate is calculated as Tc/(Lt+Tt+Ut), where: 

Tc = Truck Capacity = 32.5 cu yd 

Lt = Load Time = 0.34 hr 

Tt = Travel Time = miles to storage and disposal at CPF1 * 2 trips / 35 mph = 45 mi * 2 trips / 35 mph = 2.6 hr 

Ut = Unload Time = 0.16 hr 

Dump Recovery = 32.5 cu yd /(0.34 hour + (45 miles * 2 trips / 35 mph) + 0.16 hour) = 10.5 cu yd/hr 

Alpine Field, Satellites, and Pipelines ODPCP 1-40 February 2018, Rev. 0 
 

 

 

 

 

 

 

TABLE 1-13: WELL BLOWOUT IN WINTER - OIL RECOVERY AND TRANSFER 

EQUIPMENT 

RESPONSE FUNCTION TASK FORCE TACTIC EQUIPMENT TOTAL 

QUANTITY 

SPILL RESPONSE UNIT 

Containment and Control 

Group 

TF-1. Pad C-1 Dozer 

Front-end loader 

Bobcat 

1 

3 

2 

TF-2. Tundra C-4 

C-18 / C-19 

Backhoe 

Bobcat 

Front-end loader 

Water truck / tank 

Snow fence 

Shore seal boom 

Sandbags 

2 

2 

1 

1 

variable 

variable 

variable 

Liquid Recovery Group TF-3. Pad and tundra R-6 / R-7 

R-23 

R-24 

Vacuum Truck 

Rolligon with tank 

4-inch pumps 

Suction and discharge hose 

Storage 

7 

3 

10 

Variable 

Up to 79 

Mechanical Recovery 

Group 

TF-4. R-1 / R-3 Dozer 

Front-end loader 

Bobcat 

Dump truck 

1 

3 

2 

6 

Manual Recovery Group TF-5. R-2 Shovel / broom 

Snow machine/all-terrain vehicle 

Front-end loader 

Dump truck (shared with TF-4) 

120 

20 

1 

2 

DISPOSAL UNIT 

Oiled Snow Transfer Group TF-4 and TF-5. R-3 Front-end loader 

Maxi-haul or Euclid B-70 

10 

20 

PAD DECONTAMINATION UNIT 

Structure Cleanup Group TF-6. R-21 Water wash van/steam unit 1 

Embedded Oil / Oiled 

Gravel Removal and 

Transfer Group 

TF-7. R-5 Trimmer 

Front-end loader 

Maxi-haul or Euclid B-70 

5 

5 

10 

Alpine Field, Satellites, and Pipelines ODPCP 1-41 February 2018, Rev. 0 
 

 

 

 

 

 

 

TABLE 1-14: WELL BLOWOUT IN WINTER - STAFF TO OPERATE OIL CONTAINMENT, 

RECOVERY, AND TRANSFER EQUIPMENT 

TASK 

FORCE TACTIC NO. 

UNIT 

NO. STAFF PER SHIFT NOTE 

TEAM 

LEADER 

SKILLED 

TECH. 

GENERAL 

LABORER 

EQUIPMENT 

OPERATOR 

TF-1 C-1 1 

1 

- - 6 

Team Leader supports 

both TF-1 and TF-2 

TF-2 C-4, C-18, C-19 2 2 4 5 

TF-3 R-6, R-7, R-23, 

R-24 10 2 10 20 10 

TF-4 R-1, R-3 3 1 - - 12 

TF-4/5 R-3 Transfer 10 - - - 30 

TF-5 R-2 20 2 - 120 3 Deployed after Day 15 

TF-6 R-21 1 2 - 2 1 Team Leader supports 

both TF-6 and TF-7. 

TF Deployed after Day 15 -7 R-5 1 - - 20 

TOTAL 8 12 144 87 

Alpine Field, Satellites, and Pipelines ODPCP 1-42 February 2018, Rev. 0 
 

 

 

FIGURE 1-6: WELL BLOWOUT IN WINTER - WIND ROSE DIAGRAM 

Per convention, the wind rose illustrates direction of wind origin (i.e., where the wind is coming from). Wind data are 

derived from the NOAA Global Historic Climatology Network Nuiqsut Station. Data reflects wind direction during 

February, as recorded 2012-2016. 

Alpine Field, Satellites, and Pipelines ODPCP 1-43 February 2018, Rev. 0 
FIGURE 1-7: SIMULATED OIL PLUME TRAJECTORY FOR WINTER BLOWOUT 

Alpine Field, Satellites, and Pipelines ODPCP 1-44 February 2018, Rev. 0 
FIGURE 1-8: SIMULATED OIL PLUME TRAJECTORY FOR WINTER BLOWOUT PAD 

DETAIL 

Alpine Field, Satellites, and Pipelines ODPCP 1-45 February 2018, Rev. 0 
BLANK PAGE 

Alpine Field, Satellites, and Pipelines ODPCP 1-46 February 2018, Rev. 0 
 

SCENARIO 3 

ALPINE PIPELINE RELEASE TO THE MILUVEACH RIVER IN SUMMER 

Alpine Field, Satellites, and Pipelines ODPCP 1-47 February 2018, Rev. 0 
BLANK PAGE 

Alpine Field, Satellites, and Pipelines ODPCP 1-48 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

TABLE 1-15: ALPINE PIPELINE RELEASE TO THE MILUVEACH RIVER IN SUMMER -

TYPICAL ENVIRONMENTAL CONDITIONS 

Spill Location Miluveach River crossing (between Vertical Loops 4 and 5) 

Date / Time July 10 / 0600 

Duration Instantaneous 

Source of Spill 14-inch crude oil transmission pipeline between Alpine processing facility (ACF at CD1) 

and Kuparuk CPF2 

Cause of Spill Pipeline rupture 

Quantity of Oil Spilled Adjusted RPS volume = 2,830 barrels, all to open water (See Part 5) 

Emulsification Factor 

(for Storage Purposes) 

1.67 

Oil Type Alaska North Slope Crude 

Wind Direction and Speed Wind data are derived from the NOAA Global Historic Climatology Network Nuiqsut 

Station. The data used were collected during summer months (May through October) from 

May 2012 to October 2016 (see Figure 1-24). The average wind speed during summer 

months is 23 mph. The predominant wind directions are NE, ENE, E, WSW, and W. 

Current 1.5 knot average (0.71-2.4 knot) 

Air Temperature 44 °F 

Trajectory Rupture occurs directly above the water and 2,830 barrels of oil drains from pipeline into 

the Miluveach River. Oil moves downstream in the current. Wind-influenced trajectory is 

not considered unless oil leaves the Miluveach/Colville River system into Harrison Bay. 

The estimated time for oil to reach the first control point (CS-A) is 5 minutes; oil reaches 

the second control point (CS-B) within 15-25 minutes (see Figure 1-9). Oil entraining past 

CS-B continues downstream towards the Miluveach confluence with the Colville River. The 

remaining oil strands on the riverbank before reaching the Colville River, becoming 

unavailable for open-water recovery. 

Alpine Field, Satellites, and Pipelines ODPCP 1-49 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TABLE 1-16: ALPINE PIPELINE RELEASE TO THE MILUVEACH RIVER IN SUMMER -

RESPONSE STRATEGY 

ADEC 

REQUIREMENT RESPONSE STRATEGY ACS TECHNICAL 

MANUAL TACTIC 

(i) Stopping Upon notification by Security, the Alpine Pipeline Coordinator verifies that 

Discharge at the pipelines have been shut in. However, oil and water continue to drain 

Source from the higher elevations of the damaged pipe segments for approximately 

1 hour. 

(ii) Preventing or Throughout the first few hours of the spill, the Site Safety Officer verifies S-1 to S-6 

Controlling Fire that all sources of ignition are shutdown or removed from the area. The Site 

Hazards Safety Officer provides access zone information and determines PPE 

requirements. Access to the spill site is carefully controlled and the scene is 

secured by Security. Monitoring protocol is established by the Site Safety 

Officer for all work areas to ensure personnel protection. Decontamination 

areas are set up. 

(iv) Surveillance Aerial observation using fixed wing aircraft or helicopter is used to provide T-4 

and Tracking of real time tracking of the leading edge of the oil. T-5 

Oil on Open Oil trajectory is calculated initially using 100% of the downgradient current. Water; A trajectory using vector addition will be calculated if oil enters Harrison Forecasting Bay. Shoreline 

Contact Points Tracking buoys are staged at the mouth of the river in the event they are 

needed to track oil entering Harrison Bay. 

(v) Protection of Exclusion planning takes into account the protection priorities based on the C-13 (1) 

Environmentally North Slope Subarea Contingency Plan for Oil and Hazardous Substance 

Sensitive Areas Discharges/Releases list of resources of concern and cultural sites 

described in the ACS Technical Manual, Volume 2, Map Atlas. 

There are no priority sites on the Miluveach River downriver of the rupture 

point. 

The nearest ACS priority protection sites are approximately 4 miles 

downriver of the at the confluence of the Miluveach and Colville rivers: 

Priority Site # Map Atlas Boom Length (ft) Tactic TF 

31 14 8,000 C-13 SPTF#1 

43 14 500 C-14 SPTF#2 

Response activities are conducted away from cultural sites, based on a 

shoreline cleanup plan approved by the Unified Command in consultation 

with the ADNR Office of History and Archaeology (OHA). 

C-14 (1) 

ACS Map Atlas 

Sheets 14 and 15 

Pre-staged 

Equipment: ACS 

Map Atlas Sheets 18 

and 27 

(vi) Spill Containment and recovery teams are deployed to pre-designated control 

Containment sites and are instructed to take steps necessary in order to keep the oil from 

and Control entering the Colville River. 

Actions Approximately 350 feet of diversionary boom has been pre-deployed to 

Control Site A (CS-A), approximately 500 feet downstream of the pipeline 

crossing. This boom is deployed at the beginning of the summer as a 

contingency measure for such a scenario. The boom placement is designed 

to divert the oil into the small oxbow channel at CS-A where it can be 

recovered or burned. Approximately 60% of the oil is contained at CS-A. 

See Figure 1-9. 

Approximately 350 feet of diversionary boom deployed to Control Site B 

(CS-B), approximately 2,400 feet downstream of the pipeline crossing.. The 

boom placement is designed to divert the oil into a collection point along the 

east bank of the river. Approximately 30% of the oil is contained at CS-B. 

See Figure 1-9. 

Containment at boom sites is accomplished immediately. ACS location 

ALP-1 contains the following equipment to support the CS-A and CS-B 

sites: 1,500 feet of river boom, one 3-inch trash pump, two drum or brush 

skimmers, two 500-gallon bladders, and eight 2,500-gallon (59-barrel) open 

top storage units. The total storage capacity pre-staged at ALP-1 is 479 

barrels. 

C-8, C-9 

ACS Map Atlas 

Sheet 27 

C-8, C-9 

ACS Map Atlas 

Sheet 27 

Alpine Field, Satellites, and Pipelines ODPCP 1-50 February 2018, Rev. 0 
TABLE 1-16 (CONTINUED): ALPINE PIPELINE RELEASE TO THE MILUVEACH RIVER IN 

SUMMER - RESPONSE STRATEGY 

ADEC 

REQUIREMENT RESPONSE STRATEGY ACS TECHNICAL MANUAL TACTIC 

(vii) Spill Recovery Task Force 1 (TF-1) recovers oil at CS-A utilizing a portable skimmer. R-8, R-9 

Procedures Floating hoses are used to transfer oil directly from the skimmer to Fastanks 

on the east bank of the river. Three additional Fastanks and two drum/brush 

skimmers are mobilized to ensure adequate storage and recovery. The total 

storage capacity for TF-1 is 418 barrels. Sorbents are utilized in conjunction 

with skimming operations. 

Task Force 2 (TF-2) recovers oil at CS-B utilizing a portable skimmer. 

Three additional Fastanks and two drum/brush skimmers are mobilized to 

ensure adequate storage and recovery. The total storage capacity for TF-2 

is 418 barrels. Sorbents are utilized in conjunction with skimming 

operations. 

R-8, R-9 

Task Force 3 is assigned to transfer recovered fluids from CS-A and CS-B 

to vacuum trucks waiting on the Tarn Road. 

R-23 

Task Force 4 (TF-4) is deployed to CS-C at the confluence of the 

Miluveach and Colville rivers. The following equipment is pre-staged at site 

CS-C (also known as ALP-13): 750 feet of river boom and two anchor 

systems. Containment boom is deployed to collect any remaining oil before 

it reaches the Colville River. 

R-16, R-9 

Task Force 5 is a contingency open-water recovery system deployed to the 

waters at the mouth of the Colville River to encounter any oil that may 

escape up-stream containment and recovery sites. No oil reaches this task 

force. 

R-17 

Task Force 6 is a shoreline cleanup task force (see xii below). SH-1 

A staging area is set up at the West Sak 15 Pad on the Tarn Road. L-2 

(viii) Lightering, Not applicable. 

Transfer, & 

Storage from 

Tanks at Risk 

Procedures 

(ix) Transfer and Recovered oil at CS-A and CS-B is temporarily stored in Fastanks on site. A R-23 

Storage of Rolligon with a trailer tank transfers the fluids to vacuum trucks waiting on D-1 

Recovered the Tarn Road. The vacuum trucks deliver recovered liquids to Kuparuk 

Oil/Water; CPF-1 for processing. 

Volume The amount of oil is gauged using a Coliwasa tube or by other appropriate Estimating means. Procedure 

(x) Plans, Oily liquids are taken to Kuparuk CPF-1 for handling in the oil processing D-1 

Procedures, facility. 

and Locations 

for Temporary 

Storage and 

Disposal 

Non-liquid oily wastes are classified and disposed of according to 

classification. Sorbent material, Visqueen, and other materials are 

contained in poly bags and hauled to the NSB incineration facility at 

Deadhorse. 

D-2 

Non-oily wastes are classified and disposed of accordingly. D-3 

(xi) Wildlife Immediate response activities include the preparation of wildlife deterrent W-1 to W-6 

Protection Plan systems. 

A wildlife task force prevents birds and mammals from entering oiled areas 

onshore and on water. A wildlife stabilization and treatment center is made 

operational and staffed by Bird Rescue staff by Hour 24. 

Alpine Field, Satellites, and Pipelines ODPCP 1-51 February 2018, Rev. 0 
TABLE 1-16 (CONTINUED): ALPINE PIPELINE RELEASE TO THE MILUVEACH RIVER IN 

SUMMER - RESPONSE STRATEGY 

(xii) Shoreline 

Cleanup Plan 

Shoreline cleanup operations are initiated once the source of the oil has 

been stopped and all on-water recovery actions are complete. 

A shoreline assessment is conducted to understand the nature and extent 

of oiling and to establish cleanup priorities. 

Four Shoreline Cleanup Task Forces (TF-6) are deployed along the 

Miluveach River banks. Shoreline cleanup techniques consist primarily of 

manual removal, removal by use of sorbents, and cutting of oiled 

vegetation. 

SH-1 

SH-2, SH-5, SH-7 

Alpine Field, Satellites, and Pipelines ODPCP 1-52 February 2018, Rev. 0 
 

 

 

 

 

 

 

TABLE 1-17: ALPINE PIPELINE RELEASE TO THE MILUVEACH RIVER IN SUMMER -

LIQUID RECOVERY CAPABILITY 

A B C D E F G 

SPILL 

RECOVERY 

TACTIC 

NUMBER 

OF 

SYSTEMS 

RECOVERY 

SYSTEM / 

SKIMMER 

NAME AND 

MODEL 

DERATED 

OIL 

RECOVERY 

RATE PER 

SYSTEM 

(bph) 

MOBILIZATION, 

DEPLOYMENT 

AND TRANSIT 

TIME TO SITE 

(hours) 

OPERATING 

TIME 

(hours per 24-

hour shift) 

LIQUID 

RECOVERY 

CAPACITY 

(bbl per day) 

(B X D X F) 

Day 1 

TF-1: R-8 1 Action 

AP24MD 20 On site 16 320 

TF-2: R-8 1 Action 

AP24MD 20 On site 16 320 

TF-4: R-16 1 Action 

AP24MD 20 14 6 320 

TF-5: R-17 1 Vikoma weir 

skimmer 97 14 6 582 

Days 2-3 

TF-1: R-8 3 Action 

AP24MD 20 Mobilized by Day 2 20 1,200 

TF-2: R-8 3 Action 

AP24MD 20 Mobilized by Day 2 20 1,200 

TF-4: R-16 1 Action 

AP24MD 20 On site 20 400 

TF-5: R-17 1 Vikoma weir 

skimmer 97 On site 20 1,940 

Alpine Field, Satellites, and Pipelines ODPCP 1-53 February 2018, Rev. 0 
 

 

 1 

TABLE 1-18: ALPINE PIPELINE RELEASE TO THE MILUVEACH RIVER IN SUMMER - LIQUID HANDLING CAPABILITY 

A B H I J K L M N O P 

SPILL 

RECOVERY 

TACTIC 

NUMBER 

OF 

SYSTEMS 

STORAGE 

CAPACITY 

DESCRIPTION 

STORAGE 

CAPACITY 

VOLUME 

(bbl) 

OIL / 

EMULSION 

AVAILABLE 

(bph)

1 

TIME ON 

LOCATION 

PRIOR TO 

NEEDING 

TO 

OFFLOAD 

(hrs) 

I/J 

OFFLOADING 

MECHANISM 

OFFLOADING 

RATE 

(bph) 

TRANSIT 

TIME -

BOTH 

WAYS 

(hrs) 

OFFLOADING 

TIME 

(hrs) 

I/M 

OFFLOAD 

AND 

TRANSIT 

TIME 

(hrs) 

N+O 

TF-1: R-8 1 Fastanks (7), 

Open top (1) 418 33.4 12.5 3-inch Trash Pump 485 NA 0.5 NA 

TF-2: R-8 1 Fastanks (7), 

Open top (1) 418 33.4 12.5 3-inch Trash Pump 485 NA 0.5 NA 

TF-3: R-23 to R-6 1 Rolligon w/ Trailer 

Tank 238 66.8 4 Vac Truck 200 4 1.2 5.2 

TF-3: R-6 1 Vac Truck 300 66.8 4 Vac Truck 200 0.6 1.5 2.1 

The total volume of oil/emulsion available for recovery is the volume of oil that discharges to water x 1.67 (emulsion factor). 

For example, a drum/brush skimmer with a derated recovery rate of 20 bph will require 33.4 bph emulsion storage (20 bph x 1.67 = 33.4 bph). 

Alpine Field, Satellites, and Pipelines ODPCP 1-54 February 2018, Rev. 0 
FIGURE 1-9: MILUVEACH RIVER CROSSING, DIAGRAM 1 

Alpine Field, Satellites, and Pipelines ODPCP 1-55 February 2018, Rev. 0 
FIGURE 1-10: MILUVEACH RIVER CROSSING, DIAGRAM 2 

Alpine Field, Satellites, and Pipelines ODPCP 1-56 February 2018, Rev. 0 
 

 

SCENARIO 4 

ALPINE TANK RUPTURE IN SUMMER 

Alpine Field, Satellites, and Pipelines ODPCP 1-57 February 2018, Rev. 0 
BLANK PAGE 

Alpine Field, Satellites, and Pipelines ODPCP 1-58 February 2018, Rev. 0 
 

 

 

 

 

 

 

TABLE 1-19: ALPINE TANK RUPTURE IN SUMMER - TYPICAL ENVIRONMENTAL 

CONDITIONS 

Spill Location CF-T-61001, a 3,300-barrel Diesel (ultra-low sulfur diesel) Tank 

Date August 1 

Duration Instantaneous release 

Cause of Spill Unknown 

Quantity of Oil Spilled RPS Volume: 1,320 barrels 

Based on a maximum tank capacity of 3,300 barrels with a deduction of 1,980 barrels for 

secondary containment. 

Emulsification Factor Not applicable. All diesel is contained on the pad; no diesel reaches open water. 

Oil Type Diesel (ultra-low sulfur diesel) 

Wind Direction and Speed Wind data are derived from NOAA Global Historic Climatology Network Nuiqsut Station. The 

data used were collected during summer months (May through October) from May 2012 to 

October 2016 (see Figure 1-24). The average wind speed during summer months is 23 mph. 

The predominant wind directions are NE, ENE, E, WSW and W. 

Current Not applicable. 

Air Temperature 44 °F 

Surface The tank is located on the eastern portion of CD1 pad, approximately 100 feet from the 

perimeter of the pad and 400 feet from the Sakoonang Channel. The surface between CD1 

and the channel is tundra. 

Trajectory Sixty percent of the diesel is contained in secondary containment. The remaining 40% (1,320 

barrels) spreads laterally from the source (tank). Most of the 1,320 barrels migrates downhill 

(north) to the Tank Farm Basin. 

Alpine Field, Satellites, and Pipelines ODPCP 1-59 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TABLE 1-20: ALPINE TANK RUPTURE IN SUMMER - RESPONSE STRATEGY 

ADEC 

REQUIREMENT RESPONSE STRATEGY ACS TECHNICAL 

MANUAL 

(i) Stopping 

Discharge at 

Source 

Security notifies the SRT. The secondary containment is assessed for repair to 

prevent further leakage. At all times, the safety of personnel is COPA’s first 

concern. No unauthorized personnel are allowed near the spill area. 

(ii) Preventing or 

Controlling Fire 

Hazards 

Throughout the first few hours of the spill, the Site Safety Officer verifies that all 

sources of ignition are shut down or removed from the area. The Site Safety 

Officer provides access zone information and determines PPE requirements. 

Access to the spill site is carefully controlled and the scene is secured by 

Security. Monitoring protocol is established by the Site Safety Officer for all work 

areas to ensure personnel protection. 

No personnel are allowed in the hot zones unless proper PPE is worn, and it is 

permitted by the Site Safety Officer. 

Firewater coverage is set up. 

S-1 through S-6 

(iv) Surveillance 

and Tracking of 

Oil on Open 

Water; 

Forecasting 

Shoreline 

Contact Points 

The extent of the spill is marked with stakes and hand-held global positioning 

systems. 

T-1 

(v) Protection of 

Environmentally 

Sensitive Areas 

No ACS priority protection sites occur within the projected spill footprint or 

downstream of CD1 along the Nigliq and Sakoonang channels. 

The nearest priority protection sites are located in Harrison Bay, approximately 7 

miles WNW of the pad. 

Response activities are conducted away from cultural sites, based on a shoreline 

cleanup plan approved by the Unified Command in consultation with the ADNR 

Office of History and Archaeology (OHA). 

A Shoreline Protection Task Force is deployed to Sakoonang Channel to observe 

conditions. Pre-staged equipment and pre-deployed boom are located at 

numerous locations along Sakoonang Channel. The resources include: 

• Seasonal pre-deployed boom in the Sakoonang Channel is maintained; 

however, no oil is projected to fall in the Sakoonang Channel. Approximately 

500 to 750 feet of river boom are deployed at both SK-13 and SK-15 control 

sites, upstream and downstream of CD1 on the Sakoonang Channel. 

• Three locations along the Sakoonang Channel contain response equipment. 

Locations ALP-5, ALP-10, and ALP-14 each contain over 1,000 feet of river 

boom, a 3-inch trash pump, a drum or brush skimmer, at least two anchor 

systems and at least four 2,500-gallon (59-barrel) open-top storage units. ALP5 is located upriver of the release; consequently, all of the equipment is reallocated to downstream locations. 

Recovery resources can be redistributed as needed; however, no diesel is 

expected to reach the water. 

Pre-staged 

Equipment: 

ACS Map Atlas, 

Sheets 16, 17, and 

20 

(vi) Spill 

Containment 

and Control 

Actions 

Containment and recovery operations begin after safety protocols are 

established. Work conducted near the release is carefully monitored for safety 

(see part ii above). The equipment needed to respond to the rupture is located on 

site (at CD1). 

S-1 to S-6 

Containment Task Force 1 (CTF-1) constructs berms and trenches in order to: 

• Separate pooled diesel from vehicle access routes. 

• Direct diesel into low-lying areas where recovery is more efficient. 

• Keep diesel from migrating off pad. 

C-4 

Containment Task Force 2 (CTF-2), with four SRT staff and a vessel deploys 

from its staging location at Alpine. CTF-2 checks the pre-deployed boom in 

Sakoonang Channel. 

C-8 

Alpine Field, Satellites, and Pipelines ODPCP 1-60 February 2018, Rev. 0 
TABLE 1-20 (CONTINUED): ALPINE TANK RUPTURE IN SUMMER - RESPONSE STRATEGY 

ADEC 

REQUIREMENT RESPONSE STRATEGY ACS TECHNICAL MANUAL 

(vii) Spill Recovery Task Force 1 (TF-1): Using an on-site vacuum truck, TF-1 begins recovery of R-6/R-7 

Procedures diesel from the Tank Farm Basin, trenches, and secondary containment. The 

recovered diesel is temporarily stored in tanks and bladders. The on-site 

response equipment inventory includes four 400-barrel upright tanks. The total 

storage capacity at CD1 exceeds the unadjusted RPS volume for the tank 

rupture. The recovery rate for TF-1 is detailed in Table 1-21. 

Task Force 2 (TF-2): TF-2 consists of a Bobcat or backhoe, loader, dump truck, 

and Supersucker. TF-2 excavates diesel-contaminated gravel and transports it to 

temporary lined storage at CD1. The recovery capacity for TF-2 is detailed in 

Table 1-21. 

The recovery rate capacity of the task forces is greater than the RPS volume of 

1,320 barrels. 

R-5/R-26 

(viii) Lightering Not applicable. 

Procedures, 

Transfer, & 

Storage from 

Tanks at Risk 

(ix) Transfer and A Fluid Storage and Transfer Task Force establishes a temporary storage area. D-1 

Storage of Portable tanks and bladders available from on-site equipment inventory 

Recovered temporarily store recovered oil and water until it is recycled into the Alpine 

Oil/Water; production stream using in-place production facilities at Alpine. Over 600 barrels 

Volume of bladder tanks and 3,286 barrels of tank capacity are available for temporary 

Estimating storage of liquids. 

Procedure 

(x) Plans, Recovered liquids are transferred from temporary storage and recycled into the D-1 

Procedures, and Alpine production stream. 

Locations for 

Temporary Non-liquid oily wastes are classified and disposed of according to classification. D-2 

Storage and Non-oily wastes are classified and disposed of accordingly. D-3 

Disposal Temporary containment cells are constructed on site for storage of contaminated 

gravel. Liner material (20-30 mil pit liner material) is mobilized for construction of 

lined storage cells. Seams are welded together as constructed. Oiled gravel is 

later excavated, tested, and hauled to a disposal facility. 

D-4 

(xi) Wildlife 

Protection Plan 

The spill is contained on the pad area. No risk to wildlife is anticipated. Not applicable 

(vii) Shoreline 

Cleanup Plan 

Contaminated materials are recovered as described in vii above. No additional 

cleanup measures are required. 

Not applicable 

Alpine Field, Satellites, and Pipelines ODPCP 1-61 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

TABLE 1-21: ALPINE TANK RUPTURE IN SUMMER - RECOVERY AND HANDLING 

CAPABILITY 

A B C D E F G 

TASK FORCE / 

ACS RECOVERY 

TACTIC 

NUMBER 

OF 

SYSTEMS 

RECOVERY 

SYSTEM 

OIL 

RECOVERY 

RATE 

(BPH OR CU 

YD/HR) 

MOBILIZATION, 

DEPLOYMENT, 

AND TRANSIT 

TIME TO SITE 

(HOURS) 

OPERATING 

TIME 

(HOURS IN A

24-HOUR 

SHIFT) 

DAILY 

DERATED 

OIL 

RECOVERY 

CAPACITY 

(BPD OR CU 

YD PER DAY) 

(B X D X F) 

RECOVERY OF LIQUIDS 

TF-1A: R-6/R-7 1 

Vacuum truck 

recovery by 

direct suction 

96 2 HoursB 20 1,920 

Total (bbl): 1,920 

RECOVERY OF OILED GRAVEL 

TF-2C: R-26 1 

Bobcat or 

backhoe, 

front-end 

loader, and 

dump truck 

45 2 HoursB 20 900 

TF-2D: R-5 1 Supersucker 14 2 HoursB 20 280 

Total (cu yd): 1,180 

NOTES: 

A. TF-1 liquid recovery rates are based on a distance of 2 road miles from the recovery area to the temporary storage site. The 

time in transit, including load/unload time is 3 hours. The load time is calculated using an average pumping rate of 200 bph (rate 

for diesel). The assumed travel speed is 35 mph. Alpine has an on-site inventory of three vacuum trucks. 

B. All response equipment is located on site. The time required to mobilize the equipment and transport it to the release site also 

includes the time required to establish safety protocols. 

C. TF-2 recovery rate is based on Tactic R-26. The recovery rate for gravel is dependent on the following: 

Tc/(Lt+Tt+Ut) = 20 cu yd/(0.25 hour + (2 miles * 2 trips / 35 mph) + 0.08 hour) = 45.0 cu yd/hr, where 

Tc = Truck Capacity, Lt = Load Time, Tt = Travel Time, Ut = Unload Time 

D. TF-2 recovery rate is based on Tactic R-5. The Supersucker recovery rate is approximately 14 cu yd per hour. 

Alpine Field, Satellites, and Pipelines ODPCP 1-62 February 2018, Rev. 0 
FIGURE 1-11: ALPINE CD1 PAD DETAIL - TANK RUPTURE IN SUMMER 

Alpine Field, Satellites, and Pipelines ODPCP 1-63 February 2018, Rev. 0 
BLANK PAGE 

Alpine Field, Satellites, and Pipelines ODPCP 1-64 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

1.7 NON -MECHANICAL RESPONSE OPTIONS [18 AAC 75.425(e)(1)(G)] 

COPA will request approval for in situ burning from the Federal On-Scene Coordinator (FOSC) and State 

On-Scene Coordinator (SOSC) when mechanical response methods prove ineffective or when in situ 

burning will be used as a tool to minimize environmental damage. Due to the close proximity of the local 

resident population of Nuiqsut, additional considerations are discussed before approval of in situ burning 

by the Unified Command. 

Use of dispersants is not considered in this ODPCP. Information about use of dispersants in Alaska, 

including procedures for obtaining use authorization are presented in the Alaska Regional Response Team 

Unified Plan, Annex F, Appendix 1: Alaska Regional Response Team Dispersant Use Plan for Alaska. 

1.7.1 Obtaining Permits and Approvals 

Burning will not occur without approval by local, state, and federal agencies. The COPA Incident 

Commander will discuss the option of in situ burning with the federal and state on-scene coordinators. 

COPA will complete an “Application and Burn Plan” as provided in the ARRT Unified Plan In Situ Burning 

Guidelines for Alaska. 

1.7.2 Decision Criteria for Use 

In situ burning of spilled oil is considered under conditions such as the following: 

• Mechanical recovery is impractical or ineffective. 

• Shorelines are threatened. 

• Burning would augment the oil elimination capacity of mechanical recovery. 

• Present and forecast wind conditions will carry the smoke plume away from populated areas. 

• A successful test burn has been conducted. 

1.7.3 Implementation Procedures 

If the COPA Incident Commander decides to use in situ burning and obtains the necessary authorization, 

ACS carries out the response as described in the ACS Technical Manual Tactics B-1 through B-6 and L-6. 

1.7.4 Required Equipment and Personnel 

ACS maintains the equipment and personnel for in situ burning. The equipment and personnel are 

described in the ACS Technical Manual, Volume 1 Tactics B-1 to B-6 and SH-10, incorporated here by 

reference. 

Alpine Field, Satellites, and Pipelines ODPCP 1-65 February 2018, Rev. 0 
1.8 FACILITY DIAGRAMS [18 AAC 75.425(e)(1)(H)] 

The ACS Technical Manual, Volume 2, Map Atlas contains maps covering the North Slope oil fields showing 

facilities, roads, pipelines, culvert locations, pre-staged response equipment, ACS priority protection sites, 

topography, hydrology (including drainage divides and flow directions), and shoreline types. 

The following vicinity maps and facility diagrams are provided: 

 Alpine Development Area (Figure 1-12) 

 Alpine Pipelines Operations Rights-of-Way (Figure 1-13) 

 CD1, CD2, and CD3 Vicinity Map (Figure 1-14) 

 CD1 Pad Layout (Figure 1-15) 

 CD2 Pad Layout (Figure 1-16) 

 CD3 Pad Layout (Figure 1-17) 

 CD4 Vicinity Map (Figure 1-18) 

 CD4 Pad Layout (Figure 1-19) 

 CD5 Vicinity Map (Figure 1-20) 

 CD5 Pad Layout (Figure 1-21) 

 GMT1 Vicinity Map (Figure 1-22) 

 GMT1 Pad Layout (Figure 1-23) 

Alpine Field, Satellites, and Pipelines ODPCP 1-66 February 2018, Rev. 0 
FIGURE 1-12: ALPINE DEVELOPMENT AREA

Alpine Field, Satellites, and Pipelines ODPCP 1-67 February 2018, Rev. 0 
BLANK PAGE 

Alpine Field, Satellites, and Pipelines ODPCP 1-68 February 2018, Rev. 0 
FIGURE 1-13: ALPINE PIPELINES OPERATIONS RIGHTS-OF-WAY 

Alpine Field, Satellites, and Pipelines ODPCP 1-69 February 2018, Rev. 0 
BLANK PAGE 

Alpine Field, Satellites, and Pipelines ODPCP 1-70 February 2018, Rev. 0 
FIGURE 1-14: CD1, CD2, AND CD3 VICINITY MAP 

Alpine Field, Satellites, and Pipelines ODPCP 1-71 February 2018, Rev. 0 
FIGURE 1-15: CD1 PAD LAYOUT 

TANK FARM BASIN 

Alpine Field, Satellites, and Pipelines ODPCP 1-72 February 2018, Rev. 0 
FIGURE 1-16: CD2 PAD LAYOUT 

Alpine Field, Satellites, and Pipelines ODPCP 1-73 February 2018, Rev. 0 
FIGURE 1-17: CD3 PAD LAYOUT 

Alpine Field, Satellites, and Pipelines ODPCP 1-74 February 2018, Rev. 0 
FIGURE 1-18: CD4 VICINITY MAP 

Alpine Field, Satellites, and Pipelines ODPCP 1-75 February 2018, Rev. 0 
FIGURE 1-19: CD4 PAD LAYOUT 

Alpine Field, Satellites, and Pipelines ODPCP 1-76 February 2018, Rev. 0 
FIGURE 1-20: CD5 VICINITY MAP 

Alpine Field, Satellites, and Pipelines ODPCP 1-77 February 2018, Rev. 0 
FIGURE 1-21: CD5 PAD LAYOUT 

Alpine Field, Satellites, and Pipelines ODPCP 1-78 May 2018, Rev. 2 
FIGURE 1-22: GMT1 VICINITY MAP 

Alpine Field, Satellites, and Pipelines ODPCP 1-79 February 2018, Rev. 0 
FIGURE 1-23: GMT1 PAD LAYOUT 

Alpine Field, Satellites, and Pipelines ODPCP 1-80 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1.9 RESPONSE SCENARIO FOR AN EXPLORATION OR PRODUCTION 

FACILITY [18 AAC 75.425(e)(1)(I)] 

1.9.1 Response Strategy to Control a Well Blowout [18 AAC 425(e)(1)(I) and 18 AAC 

75.445(d)(2)] 

Well blowout scenarios include a summary of planned methods, equipment, logistics, and timeframes 

proposed to be employed to control a well blowout within 15 days. Well blowout scenarios are presented in 

Section 1.6.3. 

COPA has precautions in place that minimize the potential for a loss of well control. If an uncontrolled flow 

occurs at the surface, safety procedures would be employed to protect personnel, stop the spill, protect the 

environment, and protect the equipment. The COPA Drilling and Wells Emergency Preparedness and 

Blowout Contingency Plan describes initial response procedures and incident management roles and 

responsibilities to guide well control specialists in the event of uncontrolled flow at the surface. COPA 

certifies the Plan is a separate well blowout contingency plan that is not part of this ODPCP. It provides 

step-by-step process to develop detailed incident-specific plans and actions to regain control. An electronic 

copy of the COPA Drilling and Wells Emergency Preparedness and Blowout Contingency Plan is available 

to COPA drilling operations personnel. 

Well control specialists are promptly notified in the event of a well control situation with the potential to 

escalate. COPA Drilling and Wells Source Control Team provides company and external technical 

expertise, assistance, and resources to support IMT actions. In addition, COPA maintains an operating 

agreement with Boots & Coots, a well control specialist contractor that can assist in the intervention and 

resolution of any well control emergency. Boots & Coots services include, but are not limited to, firefighting 

equipment and services, specialty blowout control equipment and services, directional drilling services, 

high-pressure pumping services, and experience with specialty fluids, chemicals, and additives. The 24-

hour phone number for Boots & Coots is provided in Figure 1-1. 

Well capping operations would commence with COPA activation of Boots & Coots and mobilization of key 

personnel and equipment. Attempts at dynamic and surface well control methods would continue, if safe 

conditions exist. If the well capping option is selected, safe reentry to the wellhead area must be established 

and rig equipment must be moved. If the rig moving system is unavailable or inactive, then heavy bulldozers, 

block and tackle, and/or cranes would be used to remove the rig from the wellhead area. Once safe access 

is regained, capping operations can commence. COPA, North Slope operators, and oil field service vendors 

have available, most major equipment items that would be required to initiate well capping or other surface 

control options. Specialized equipment required for well capping is summarized in Table 1-22. 

An estimated time frame to control a well blowout by means of a well capping program is 15 days, excluding 

weather days and other contingencies. Mobilization of well control specialist teams and initial equipment, 

and initiation of well intervention planning is generally expected to take 2 to 3 days. On-site actions to 

prepare the damaged well and surrounding area would take another 3 to 4 days. Concurrently, site access 

and safety, well-capping engineering, and well re-entry planning would occur, and decontamination and offsite operations facilities would be mobilized and deployed. Uncontrolled fluids may be diverted for collection 

and handling to create a safe working environment and minimize pollution. The blowout prevention 

equipment would be removed from the well if necessary. The capping stack would be installed within 

several days to provide containment and the uncontrolled release of hydrocarbons is terminated by Day 

15. 

Alpine Field, Satellites, and Pipelines ODPCP 1-81 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TABLE 1-22: WELL CAPPING EQUIPMENT LIST 

COMPONENT WELL CAPPING USAGE LOCATION MOBILIZATION 

6,000-gallon per 

minute Fire Pumps Fire and heat suppression North Slope <24 hours 

Athey Wagons Tractorized booms for manipulation of tools in and 

around blowout well North Slope <24 hours 

Bulldozers 

Power for Athey wagons and backup for heavy 

equipment moving; can also be used for constructing 

berms to aid in spill containment 

North Slope <24 hours 

Backhoes Drainage ditch, berm construction North Slope <24 hours 

100-200 ton Cranes Heavy equipment lifting capability; if well blowout is 

ignited, may be needed to facilitate rig move North Slope <24 hours 

50-75 ton Cranes Smaller, mobile units for spotting support equipment North Slope <24 hours 

250-500 ton Drilling 

Blocks 

Block and tackle system for moving or dragging heavy 

equipment North Slope <24 hours 

Drilling Line Component of block and tackle system if rig moving 

system is inoperable North Slope <24 hours 

20-inch and 30-inch 

Casing 

Used to construct Venturi tubes to divert blowing well 

bore fluids (ignited and un-ignited) North Slope <24 hours 

Miscellaneous 

Equipment 

High pressure chicksan, flexible hoses, valves, 

containment boom, absorbent, hand tools North Slope <24 hours 

Junk Shot Manifold Manifold system constructed to pump small leak 

sealing materials into well North Slope <24 hours 

Hot Tap Tool Manifold used to gain safe access to pressurized 

tubulars at surface North Slope <24 hours 

Crimping Tool Sized device used to pinch tubulars closed to seal off 

internal flow Houston, Texas <48 hours 

Abrasive Cutter High-pressure cutting tool used to sever leaking 

BOPs, rig structures Duncan, Oklahoma <48 hours 

Kill Pumps Back up to rig pumps North Slope <48hours 

Capping Stack Various high pressure BOP stacks (to replace leaking, 

damaged or severed primary BOPs) Houston, Texas <10 days 

Heavy Lift Helicopter Helicopter capable of lifting U.S. Pacific 

Northwest < 10 days 

1.9.2 Response Scenario Typical Environmental Conditions [18 AAC 75.425(e)(1)(I)(iii)] 

The response scenarios in this ODPCP were developed under typical summer environmental conditions 

during May through October and typical winter environmental conditions during November through April. 

The average wind speeds, temperatures, and predominant wind directions are derived from publicly 

available meteorological measurements recorded by National Oceanic and Atmospheric Administration 

Global Historical Climatology Network Station data from Nuiqsut, Alaska. Table 1-23 shows average wind 

speed and temperature, and Figures 1-24 and 1-25 are a wind rose diagrams depicting predominant wind 

directions during summer and winter, respectively. The data were collected for years 2012 to 2016. 

Alpine Field, Satellites, and Pipelines ODPCP 1-82 February 2018, Rev. 0 
TABLE 1-23: AVERAGE WIND SPEED AND TEMPERATURE 

MONTH 

AVERAGE 

WIND SPEED 

(MPH) 

AVERAGE 

MAXIMUM 

TEMPERATURE 

(DEGREES F) 

AVERAGE 

MINIMUM 

TEMPERATURE 

(DEGREES F) 

JANUARY 28 -8 -21 

FEBRUARY 27 -6 -20 

MARCH 24 -9 -22 

APRIL 25 10 -4 

MAY 22 32 21 

JUNE 23 52 36 

JULY 22 58 42 

AUGUST 22 52 39 

SEPTEMBER 23 39 30 

OCTOBER 24 28 17 

NOVEMBER 24 10 -4 

DECEMBER 23 -4 -18 

Alpine Field, Satellites, and Pipelines ODPCP 1-83 February 2018, Rev. 0 
FIGURE 1-24: SUMMER WIND ROSE DIAGRAM 

Alpine Field, Satellites, and Pipelines ODPCP 1-84 February 2018, Rev. 0 
FIGURE 1-25: WINTER WIND ROSE DIAGRAM 

Alpine Field, Satellites, and Pipelines ODPCP 1-85 February 2018, Rev. 0 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

PART 2 PREVENTION PLAN 

[18 AAC 75.425(e)(2)] 

2.1 DISCHARGE PREVENTION PROGRAMS [18 AAC 75.425(e)(2)(A)] 

COPA considers prevention the core of its spill response at Alpine. Pollution prevention begins with the 

drilling of wells and extends through all phases of oil production. Spill prevention methods used by COPA 

include: design, inspection, testing, repair and replacement, preventive maintenance, detection and 

shutdown procedures, training, and policies. 

2.1.1 Oil Discharge Prevention Training [18 AAC 75.020] 

COPA personnel with job duties directly involving inspection, maintenance, or operation of oil storage and 

transfer equipment regulated under 18 AAC 75.005 through 18 AAC 75.080 are required to complete 

training on the ODPCP and Spill Prevention, Control, and Countermeasures (SPCC) Plan for North Slope 

Exploration and Production Operations Training Module (CPA-REQ-229). This module contains information 

on state and federal oil pollution prevention requirements that are applicable to facility and field operations. 

A listing of each position required to take this training is maintained by the COPA HSE Training Coordinator 

and documented in the COPA Training Course Catalog. Required licenses, certifications, or other 

prerequisites are in the Alpine Equipment Integrity Program Manual. COPA personnel and contractors who 

perform inspections and maintenance are required to maintain the necessary certifications consistent with 

the applicable industry standard (i.e., American Petroleum Institute [API], National Association of Corrosion 

Engineers [NACE], and American Society of Mechanical Engineers [ASME]). 

Spill responders will possess training and qualifications required for the position, as established by COPA 

and ACS. ODPCP Section 3.9 provides additional information on spill responder training. 

COPA requires contractors to comply with applicable local, state, and federal regulations. Contractors 

maintain their own training programs and records. COPA periodically audits contractor training programs 

and records as part of the COPA HSE Contactor Audit program. 

2.1.2 Substance Abuse Program [18 AAC 75.007(e)] 

COPA employees are held accountable to the ConocoPhillips Global Substance Abuse Policy, which is 

established to provide for safety of employees, contractors, and non-employees, and to ensure a safe 

working environment at all operations. The Global Policy includes: 

• Zero tolerance for violations of the Global Policy. 

• Pre-employment drug testing. 

• Random drug and alcohol screening and screening for reasonable suspicion/cause. 

• Routine training and communication of the Global Policy. 

• Opportunities for rehabilitation for voluntary disclosure of substance abuse problems. 

Upon entering Company premises, all COPA employees and contractors are expected to comply with 

COPA's substance abuse program. As provided in the Alaska Safety Handbook General Safety Rules, 

illegal substance and alcohol use or possession is prohibited while on Company property. All personnel 

Alpine Field, Satellites, and Pipelines ODPCP 2-1 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

must notify their Supervisor if taking prescription medication that may inhibit their job performance. 

Prescription drugs should be kept in the original container. 

In addition, operation of the Alpine Pipeline is under the jurisdiction of DOT regulations, which require drug 

testing for pre-employment, random, post-accident, reasonable cause, and return-to-duty situations for 

employees who operate in designated DOT positions that may include tasks on a pipeline in an operating, 

maintenance, or emergency response function regulated by 49 CFR Parts 192, 193, or 195 . 

2.1.3 Medical Monitoring [18 AAC 75.007(e)] 

COPA employees engaged in work that requires medical monitoring under federal Occupational Safety and 

Health Administration (OSHA) and state Alaska Department of Occupational Safety and Health 

requirements must meet minimum medical and physical requirements for their job classification. Employees 

and contractors who may be required to use respiratory protection while performing specified job task(s) 

must follow the COPA Respiratory Protection Procedure. Employee enrollment in the COPA Hearing 

Conservation Program is based on job classification; affected employees must follow the COPA Hearing 

Conservation Procedure. 

All members of COPA’s HAZMAT Team and Fire Department are given a physical examination that 

complies with National Fire Protection Association standards. SRT members are given a physical 

examination every two years. Upon medical clearance, HAZMAT, Fire Department, and SRT members 

perform respirator fit testing in accordance with the COPA Respiratory Protection Procedure. 

A medical evaluation may be required if personnel are exposed to, or may be exposed to, hazardous 

substances at or above the permissible exposure level. If a permissible exposure level does not exist, 

published exposure levels may be used instead. The exposure will be the ambient air concentration 

(regardless of respirator use). Medical surveillance also will be provided at the employee's request. 

If overexposure is known or suspected as a result of an accidental release, the exposed employee(s) is 

examined and treated as necessary. Physician’s Assistants who work under the direction of a medical 

doctor can render medical attention. If a Physician’s Assistant is not available at Alpine, one can be flown 

from Kuparuk within one hour, if necessary. Persons requiring additional medical attention are taken to 

Anchorage by air ambulance or by commercial or Company charter. 

2.1.4 Security and Surveillance Programs [18 AAC 75.007(f)] 

Access to Alpine is available year-round through a privately owned on-site airstrip. Limited ice road access 

may be available via established checkpoints during winter months. All visitors are required to sign-in upon 

arrival. Security staff monitor personnel arriving and departing the site by routine patrol and security check 

points. 

2.1.5 Fuel Transfer Procedures [18 AAC 75.025] 

Employees and contractors must follow established safety procedures for conducting fuel transfers in order 

to prevent spills or overfilling during a transfer of oil. Under 18 AAC 75.025, “transfer” means any movement 

of oil within an oil terminal facility or between an oil terminal facility and a tank truck. As a production facility, 

fuel transfers at Alpine are primarily conducted as: 

• Transfer operations from a tank truck to a stationary tank at permanent unloading areas; 

Alpine Field, Satellites, and Pipelines ODPCP 2-2 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

• Transfer operations from a stationary or portable tank to a tank truck or other equipment; and 

• Transfer between a tank and other drilling or production equipment through hose or piping. 

Fuel transfer operations follow North Slope Environmental Field Handbook North Slope Fluid Transfer 

Guidelines, which prescribe: 

• Use of established procedures and/or checklist. 

• Use two people, if necessary; ensure communication among workers is clear. 

• Maintain constant line-of-sight throughout entire operation; be prepared to stop the transfer 

immediately. 

• Inspect hoses, connections, valves, etc. before and after transfer operations. 

• Check tank level and overfill protection on regulated tanks prior to start. 

• Use surface liners and sorbents. 

• Never leave the operation unattended. 

• Upon completion, check for spills; report all spills immediately. 

The COPA Fluid Transfer Procedure gives general procedures for conducting fluid transfer at COPA North 

Slope facilities. The Procedure provides pre- and post-job actions, as well as a Fluid Transfer Procedure 

Checklist that may be used, if an established standard form is not already in use. 

2.1.6 Operating Requirements for Exploration and Production Facilities [18 AAC 75.045] 

Under 18 AAC 75.045(a), oil produced during a formation flow test or other drilling operations is collected 

and stored in a manner that prevents the oil from entering the land or waters of the state. If flow tests are 

conducted at Alpine, oil produced from these tests will be stored in mobile tanks or flowed directly to the 

processing facility. 

The requirements for platform integrity inspections and isolation valves for pipelines leaving platforms under 

18 AAC 75.045(b) and (c) do not apply.. 

A typical well house includes a cellar box (sump) constructed with steel metal pipe set into the gravel pad 

to a depth of 5 feet below grade, with a layer of concrete or, for installations after December 30, 2008, a 

steel bottom seal-welded to the conductor. The design helps contain fluid leaks at the wellhead and 

facilitates cleanup [18 AAC 75.045(d)]. 

Catch tank requirements do not apply [18 AAC 75.045(e)]. 

Onshore oil storage tanks meet requirements of 18 AAC 75.066 and 18 AAC 75.075. See Sections 2.1.10 

and 2.1.11. 

Onshore piping meets requirements of 18 AAC 75.080. See Section 2.1.7 

Drilling operations meet AOGCC requirements for primary and secondary well control to mitigate risks 

associated with drilling wells on the North Slope. 

Alpine Field, Satellites, and Pipelines ODPCP 2-3 February 2018, Rev. 0 
 

 

 

 

 

 

2.1.7 Requirements for Flowlines and Facility Oil Piping [18 AAC 75.047 and 18 AAC 75.080] 

Flowlines 

Alpine has a network of flowlines (three-phase oil/water/gas, miscible injection, water, and gas injection) 

between the processing facility at CD1 and the satellite drill sites. Flowlines are aboveground, with the 

exception of below-road-grade sections at road crossings. Table 2-1 summarizes flowline compliance 

measures in place to meet requirements of 18 AAC 75.047. 

TABLE 2-1: FLOWLINE COMPLIANCE MEASURES 

18 AAC 

75.047 FLOWLINE REQUIREMENT INDUSTRY STANDARD COPA MEASURE 

(b) Design and construction for liquid 

hydrocarbon, other liquids, and gas. 

ASME B31.4-2002 

ASME B31.8-2003 

Company engineering standards for 

flowlines are in accordance with industry 

standards. 

(c)(1) Corrosion control and monitoring program 

for liquid hydrocarbon and other liquids. 

ASME B31.4-2002 Company engineering and asset integrity 

management procedures. 

(c)(2) External corrosion control of buried or 

submerged metallic piping. 

NACE RP0169-2002 Company engineering and asset integrity 

management procedures. 

(c)(3) External corrosion control of aboveground 

flowlines with coatings or corrosionresistant alloy, or another method. 

None Aboveground flowlines are protected from 

atmospheric corrosion by fusion bonded 

epoxy (FBE) and/or construction of 

corrosion resistant alloy. 

(c)(4) Program designed to minimize internal 

corrosion. 

None Company engineering and asset integrity 

management procedures. 

(d)(1) Completely contain the entire flowline and 

provide interstitial leak detection. 

None Not applicable. Flowlines are managed 

under a preventative maintenance 

program instead. 

(d)(2)(A) Preventative maintenance program for 

submerged flowlines. 

ASME B31.4-2002 

chapters VII-IX 

Not applicable. The facility has no 

submerged flowlines. 

(d)(2)(B) Preventative maintenance program for 

buried flowlines. 

ASME B31.4-2002 

chapters VII-VIII 

Company engineering and asset integrity 

management procedures. 

(d)(2)(C) Preventative maintenance program for 

aboveground flowlines. 

API 570* 

ASME B31.4-2002 

chapters VII-VIII 

Company engineering and asset integrity 

management procedures. 

(d)(2)(D) Procedures to review operational changes 

that may impact pipeline integrity. 

None Management of change procedures 

address operational changes and 

potential impact to flowlines. 

(e) Line markers installed at road crossings 

and at one-mile intervals. 

None One-mile interval markers waived per 

September 13, 2007 ADEC letter; see 

Section 2.6 for waiver letter. 

(f) “Removed from service” ** for more than 

one year must be free of oil and notify 

ADEC. For piggable pipeline, a cleaning 

pig used and for other pipelines use 

gravity drainage; or evacuate by air or 

other method. 

None Company engineering and asset integrity 

management procedures. Out-of-service 

notices are sent to ADEC on regular 

intervals. 

(g) Aboveground flowlines must be supported 

consistent with Paragraph 421 of ASME 

B31.4-2002. 

ASME B31.4-2002 

paragraphy 421 

Flowline support design is consistent with 

the standard. 

(h)(1) 

and (2) 

Verify compliance with requirement to 

have programs for corrosion control and 

preventative maintenance through 

documentation of inspections, tests, 

evaluation, analysis, repairs, procedures, 

and audtis. 

None Company engineering and asset integrity 

management procedures. Records, tests, 

and information are maintained in an 

electronic database and files. 

* API 570, Second Edition, October 1998, Addendum 1, February 2000, Addendum 2, December 2001, and Addendum 3, August 

2003, excluding Section 8; adopted by reference (effective 12/30/2006, Register 180) 

Alpine Field, Satellites, and Pipelines ODPCP 2-4 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

** For purposes of this section, “removed from service” means not in regular use for the service intended and not included in a 

regular maintenance and inspection program. 

Facility Piping 

Facility oil piping at Alpine includes piping and associated fittings connected to an aboveground storage 

tank regulated under 18 AAC 75.066 and piping from a production well (sometimes referred to as “well 

line”) up to the connection to a flowline. Table 2-2 summarizes facility oil piping compliance measures in 

place to meet requirements of 18 AAC 75.080. 

TABLE 2-2: FACILITY OIL PIPING COMPLIANCE MEASURES 

18 AAC 

75.080 

FACILITY OIL PIPING 

REQUIREMENT 

INDUSTRY 

STANDARD COPA MEASURE 

(b) Corrosion control program for metallic 

piping containing oil. 

None Company engineering and asset integrity 

management procedures. 

(c) Design and construction for process 

piping, liquid hydrocarbon, other liquids, 

and gas. 

ASME B31.3-2004 

ASME B31.4-2002 

ASME B31.8-2003 

Company engineering standards for 

piping are in accordance with industry 

standards. 

(d) Protect buried metallic piping in service 

between May 14, 1992 and December 30, 

2008 with protective coating * and 

cathodic protection. 

None The facility has no buried facility oil piping 

meeting this criteria. 

(e) Buried piping in service after December 

30, 2008 is of welded construction for line 

larger than one-inch and constructed of 

corrosion-resistant material or coated * 

and cathodically protected. 

NACE RP0169-2002 Company engineering standards for 

piping and asset integrity management 

procedures are in accordance with 

industry standards. 

(f) Cathodic protection systems installed after 

December 30, 2008 are per industry 

standard and designed and installed by a 

corrosion expert **. 

NACE RP0169-2002 Cathodic protection on piping is not 

currently used. Company engineering 

standards for cathodic protection systems 

are consistent with industry standards. 

(g) Examination of exposed buried piping, 

and corrosion control and repair or 

replacement per (c) and (e) 

API 570 *** 

ASME B31.3-2004 

ASME B31.4-2002 

ASME B31.8-2003 

NACE RP0169-2002 

Buried piping inspection and repair or 

replacement follows company engineering 

standards and asset integrity 

management procedures. 

(h) Buried metallic piping without cathodic 

protection is electrically inspected every 

three years, not exceeding 39 months and 

cathodic protection applied to areas of 

active corrosion per (d) or (f) 

NACE RP0169-2002 Buried piping without cathodic protection 

is inspected per company asset integrity 

management procedures. 

(i) Aboveground piping supported consistent 

with Paragraph 321 of ASME B31.3-2004. 

ASME B31.3-2004 

paragraph 321 

Piping support designs are consistent with 

ASME codes. 

(j) All piping maintained and inspected per 

API 570 ***. 

API 570 *** Inspection, maintenance, and repair 

procedures are in accordance with API 

570. 

(k) Operation and maintenance of a cathodic 

protection system per NACE RP0169-

2002 and must include survey by 

corrosion expert * or qualified cathodic 

protection tester *** and maintenance of 

test lead wires to determine system 

effectiveness. 

NACE RP0169-2002 Cathodic protection on piping is not 

currently used. Company engineering 

standards for cathodic protection systems 

are consistent with industry standards. 

Alpine Field, Satellites, and Pipelines ODPCP 2-5 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

18 AAC 

75.080 

FACILITY OIL PIPING 

REQUIREMENT 

INDUSTRY 

STANDARD COPA MEASURE 

(l) Protection of aboveground piping from 

atmospheric corrosion using coatings * or 

consruction with corrosion-resistant 

material unless test, investigation, or 

experience determines corrosion will only 

be light surface ozide or not affect safe 

operation before program inspection. 

(inspection program 

per API 570 ***) 

Piping is subject to an inspection program 

in accordance with API 570. Experience 

shows that the ConocoPhillips inspection 

program is adequate to ensure safe 

operation. 

(m) Corrosion protection using protective 

coating * or construction with corrosionresistant material for aboveground piping 

located at a soil-to-air interface. 

None Piping at soil-to-air interface has 

protective coating or is constructed of 

corrosion-resistant materials. 

(n) Routine visual inspection for leaks or 

damage, and damage protection for 

aboveground piping and valves 

None Company asset management practices 

include routine visual inspection of piping 

for leaks or damage, during normal 

operations. Vehicle barriers are in place, 

where appropriate. 

(o) “Removed from service” *** for more than 

one year must be free of oil, origin 

identified, and marked “Out of Service” 

with the date taken out of service and 

secured to prevent use. Notify ADEC. 

None Piping removed from service for more 

than one year is made free of oil and 

secured to prevent unauthorized use. 

Piping is marked "Out of Service" or 

"Removed from Service". Out-of-service 

notices are sent to ADEC on regular 

intervals. 

* Protective coating is defined in 18 AAC 75.080(p). 

** Corrosion expert is defined in 18 AAC 75.990(169) and includes NACE certification or registered professional engineer. 

*** API 570, Second Edition, October 1998, Addendum 1, February 2000, Addendum 2, December 2001, and Addendum 3, August 

2003, excluding Section 8; adopted by reference (effective 12/30/2006, Register 180) 

**** For purposes of this section, “removed from service” means not in regular use for the service intended and not included in a 

regular maintenance and inspection program. 

Below-Grade Facility Oil Piping 

Although composed of non-corrosive stainless steel and encased in high density polyethylene pipe casing, 

the below-grade piping for the drag reducing agent tank is maintained under COPA’s asset integrity 

program. The piping is operated under an ADEC compliance waiver of cathodic protection (CP) and 

protective wrapping/coating (see Section 2.6). 

There are two buried lines at Alpine. These operate under an ADEC compliance waiver (see Section 2.6). 

The two buried lines are water lines to the WD-02 injection well and regulated pursuant to 18 AAC 75 due 

to the limited “oil” content in the fluids. The continued integrity of these lines are managed via an accelerated 

inspection program, as specified in the compliance waiver. 

Alpine Diesel Pipeline 

The Alpine Diesel Pipeline is non-insulated and non-coated except at the Colville River crossing where it is 

cased . The diesel is not heated and the line operates at ambient temperature. Because the ambient 

temperature is below freezing during the majority of the year, external corrosion is anticipated to be limited. 

The pipe supports are in direct contact with the piping. A representative sampling of the pipe supports is 

inspected to determine external pipeline damage during each of the first five years the line is in operation 

and to verify that corrosion or mechanical damage in these areas is not a concern. Any damage found is 

recorded on a re-inspection schedule, and operations are modified, as practicable, to limit additional 

damage. 

Alpine Field, Satellites, and Pipelines ODPCP 2-6 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The diesel pipeline has dye added to diesel, and other products, when practical and as determined by 

Operations, in order to enhance visual monitoring for leak detection. Diesel pipelines are also monitored for 

any pressure loss during each transfer procedure. 

Flowlines and Facility Oil Piping Inspection 

Flowlines and facility oil piping are routinely inspected to detect and prevent corrosion and leakage. The 

inspection programs are based on industry standards and best practices, and focus inspection efforts on 

areas of greatest potential for failure. Inspection and monitoring of flowlines and facility oil piping indicate if 

additional corrosion control is required, and provide feedback to success of the overall corrosion control 

program. 

At a minimum, the intervals between flowline inspections meet the requirements of ASME B31.4-2002 for 

bare flowlines and API 570 for insulated flowlines. 

Many factors determine the interval between successive inspections. Safety, history of the piping and 

similar-service piping, and state and federal regulations influence the frequency of inspections. Inspection 

and monitoring programs for internal and external corrosion use different methods, including the following: 

• Ultrasonic Inspection. Ultrasonic techniques use acoustic waves to measure metal thickness 

and uniformity. Corrosion can be detected by changes in ultrasonic measurements. In addition 

to determining a baseline wall thickness, ultrasonic inspection can be used to determine 

changes in wall thickness with time. Specific locations are inspected and monitored for change 

with ultrasonic inspection accordingly. 

• Radiographic Inspection. Radiographic inspection uses either gamma ray or X-ray sources 

to provide images of the metal, corrosion product, or insulation to aid in the assessment of 

asset condition. These techniques are useful in detecting metal loss to pipelines, both internal 

and external, and to assess the condition of the pipeline insulation and extent of corrosion 

product as a result of metal loss. In addition to providing a measure of the extent and depth of 

damage, radiographic inspection can be used to determine changes in damage with time. 

Specific locations are inspected with radiographic inspection periodically to monitor change. 

• Visual Inspections. There are several forms of visual inspection. A detailed visual inspection 

is used when the surface to be inspected is accessed and cleaned for inspection. This 

technique may use pit depth gauges or ultrasonic techniques to aid in the evaluation of the 

asset’s condition. The second type of visual inspection is the API 570 visual inspection for 

pipelines, which focuses on chafing, insulation damage, and pipeline support/structural integrity 

assessments. Visual inspections often entail ultrasonic inspection measurements along with 

visual observation of the piping. 

• Coupon Monitoring. Metal coupons are strategically placed at designated locations to help 

assess the corrosiveness of the process fluid. The coupons are periodically removed, cleaned, 

and inspected to help evaluate corrosion potential of the system and to monitor corrosion 

inhibitor effectiveness. New coupons are then installed. 

• In-Line Inspection using “Smart pigs.” In-line inspections measure specific properties of the 

pipe as a function of length using pipeline pigs. The two most common instrumented pigs are 

“metal loss detection pigs” and “geometry pigs.” Metal loss detection pigs are capable of 

evaluating locations with corrosion or gouges. Geometry pigs are used to identify dents and 

out-of-round conditions, as well as pipeline deflection, depending on the type of geometry pig 

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used. Flowlines capable of handling smart pigs are inspected with those pigs periodically, as 

determined by risk assessment. 

• Forward Looking Infrared (FLIR) System. A FLIR system is an optical technology that uses 

the infrared spectrum to detect variations in temperature. COPA employs a hand-held device 

for localized investigation, or an aircraft-based system that allows surveillance of large areas. 

It is an effective tool for leak detection on the North Slope, since typically, the temperature of 

the process systems is different than the ambient (surrounding) temperature. 

In addition, equipment and facilities at Alpine are maintained through the use of a computer-based 

Preventive Maintenance (PM) program that ensures the continued operational reliability of any flowline 

system component affecting quality, safety, and pollution prevention as required by 18 AAC 75.047(d)(2). 

The PM program was implemented to schedule maintenance at appropriate intervals to ensure equipment 

is fit for service. The program undergoes continual refinement by incorporating feedback from the field 

based on inspection results. In general, however, most corrosion inspections are driven by COPA’s 

corrosion database, which may generate more frequent inspections than those scheduled by the PM 

program. Corrosion inspection records are kept and maintained in the database in accordance with API 

570. 

The PM program is comprehensive. Inclusion in this ODPCP of all inspections performed in conjunction 

with PM cycles for vessels, pipelines, containment areas and tanks is impractical because of the volume of 

written records. At scheduled intervals, these forms are generated by an automated PM information system 

located and accessed on site at Alpine. At the completion of the PM inspection cycle, the forms are reviewed 

for completion, and results and data entered for the particular equipment. This provides an historical record 

for each component. A review of proposed changes in pipeline operation to evaluate potential impacts on 

pipeline integrity is included as a task in the COPA Management of Change (MOC) procedure. 

Corrosion Control for Flowlines and Facility Oil Piping 

Applied corrosion control measures reflect the active or potential corrosion mechanisms in the relevant 

system. The corrosion mechanisms can be divided into internal mechanisms that vary with the service, and 

external mechanisms that are constant for all services. 

COPA tracks spill events for corrosion-related leaks and spills and conducts one or more of the following: 

• Root Cause Analysis, 

• Physical Cause Analysis, or 

• Latent Cause Analysis, as required by the situation. 

If a spill occurs from piping due to corrosion, a survey of the area is conducted, including wall thicknesses, 

to determine the full extent of the affected area. Additionally, historical corrosion survey information for the 

area is reviewed in order to better understand and analyze the corrosion mechanisms and subsequent 

causes of the leak. Based on the results of these studies, a decision is made to either replace or repair the 

equipment. As applicable, other areas in the field operating with similar environments or histories are 

reviewed and surveyed to prevent similar spills or leaks from occurring. Inspection priorities are adjusted 

based on the outcome of such an analysis. In areas of concern, such as highly corrosive environments, 

corrosion inhibitors may be used, and surveys may be conducted more frequently to help identify and 

mitigate future occurrences. 

Alpine Field, Satellites, and Pipelines ODPCP 2-8 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pipelines in corrosive service may be protected from corrosion by the following techniques when inspection 

or monitoring data indicate that adequate protection does not exist: 

• Internal Corrosion Control Techniques: 

− Corrosion Inhibitors. Chemical corrosion inhibitors are used to continuously coat the 

inside of pipelines or to inhibit chemical corrosivity of the produced fluids. 

− Biocide. Biocide is used to prevent growth of bacteria within the oil production and water 

system. 

− Pigging. Seawater pipelines, produced water pipelines, and some production pipelines are 

routinely pigged to remove scale and deposits that can allow corrosion to occur. Pigging 

can allow corrosion inhibitors to work more effectively by providing a clean surface. 

• External Corrosion Control Techniques: 

− Coating. Coating with polymeric materials is used to protect the steel from corrosive fluid. 

These polymeric materials provide a barrier between the metal and fluid. 

− Maintenance Procedures for Pipe Casings. Pipe casings under road crossings are 

inspected annually for the presence of soil and debris that may be in contact with piping. 

When encountered, the soil and debris are removed to reduce the potential for external 

corrosion. 

Weight-loss corrosion coupons from the various process streams are examined periodically, based on the 

historical corrosivity of a system. The frequency is typically between three months and one year. The 

frequency of coupon examination in specific locations is determined by a qualified corrosion engineer and 

adjusted over the life of the field to provide adequate process monitoring. 

Monitoring locations are selected where water is present or may be present during process upsets, and 

where corrosion has been seen in other operating fields. Corrosion coupon fittings are strategically placed 

throughout the production, miscible injection, and seawater in-field pipeline system at Alpine. 

When necessary, corrosion inhibitor is injected at well site manifolds and at the inlet separator. Injection 

rates vary with results from the corrosion inspection program. 

Leak Detection 

The flowlines at Alpine use pipeline pressure/flow monitoring and visual inspection as the primary methods 

for leak detection. Three-phase production fluid pipelines contain low-pressure switches that automatically 

shut in the pipeline upon detection of a significant leak or line rupture. Monitoring for small leaks is 

accomplished primarily by visual inspection during routine visits to production pads. Routine overflights, 

FLIR, or ground-based visual examinations of the piping also may be used for early leak and spill detection. 

In addition, flowlines to CD3 are visually inspected by routine aerial surveillance during periods when an 

ice road is not in place. 

2.1.8 Leak Detection, Monitoring, and Operating Requirements for Crude Oil Transmission 

Pipelines [18 AAC 75.055] 

For the Alpine Oil Pipeline, metered volume balancing is performed at least once every 24 hours using 

measurements by flow meters at CD1 and at the Alpine Oil Pipeline terminus at Kuparuk CPF2, as required 

Alpine Field, Satellites, and Pipelines ODPCP 2-9 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

-

by 18 AAC 75.055(a)(2). Flow measurements are continuously monitored via the Supervisory Control and 

Data Acquisition (SCADA) system and managed by control room board operators. 

Computational pipeline monitoring is the primary means of providing continuous leak detection capability, 

as required by 18 AAC 75.055(a)(1). The Alpine Pipeline System is equipped with a software system 

capable of detecting a leak having a daily rate equal to one percent of daily throughput. The flow of incoming 

oil can be stopped within one hour after detection of a spill, as required by 18 AAC 75.055(b). In the event 

of an alarm, the control board operator proceeds through a series of steps to determine its cause. Aerial or 

ground-based surveillance may be requested. The leak detection system details are presented in Section 

2.5.2 and Section 4.11. 

If a spill is detected, the pipeline will be shut down. The shut down will prevent or mitigate a substantial 

threat of a worst case discharge. If the ESD system fails, the pipeline would be manually shut down by onsite personnel. Manual shutdown valves are located inside at the Alpine processing facility and at Kuparuk 

CPF2. These facilities are staffed 24 hours a day. 

The Alpine Oil Pipeline is considered a remote pipeline because it is not always directly accessible by 

ground transportation. For a remote pipeline, 18 AAC 75.055(a)(3) requires weekly visual inspections to be 

made by aerial surveillance. The goal of these aerial surveys is visual detection of oil slicks that may develop 

as a result of an oil leak below monitoring thresholds. COPA conducts weekly visual aerial surveillance to 

meet requirements of 18 AAC 75.055(a)(3). 

Natural events such as flooding, ice damage, or frost jacking could impact facilities and pipelines. Should 

any of these events pose a threat, visual evaluations will be performed to determine if a line or facility should 

remain in operation. Each DOT-regulated Alpine pipeline has an operations manual that addresses all 

operations and procedures related to the pipeline, including abnormal and emergency operations. 

COPA notifies ADEC in writing within 24 hours if a significant change is made to, or occurs in, the leak 

detection system and if, as a result of the change, the system no longer meets the ADEC performance 

requirements in 18 AAC 75.055, as required by 18 AAC 75.475. 

Horizontal Directional Drilling Belowground Pipeline Section 

The leak detection systems that apply to the aboveground pipeline also apply to the belowground section. 

In addition, the annular space in the casing at the Colville River horizontal directional drilling crossing is 

equipped with a conduit for leak detection sensors. The sensors are able to detect fluids entering the 

annular space. 

The technology uses a small sensor that measures the refraction of light through liquids. Each liquid has a 

different index of refraction, allowing the sensor to distinguish between oil and water, and the sensor is 

sensitive enough to distinguish between different types of hydrocarbons. Fiber optic cable connects the 

sensor to the control panel and carries light between the two. The system is inherently safe because no 

electrical power is used in the annulus. The sensor automatically resets and does not require removal after 

wetting. 

2.1.9 Shop Fabricated Aboveground Oil Storage Tanks [18 AAC 75.066] 

Section 3.1.2 contains additional information on the ADEC-regulated oil storage tanks at Alpine. There are 

currently no field-constructed oil storage tanks at Alpine placed into service after December 30, 2008; as 

such, requirements at 18 AAC 75.065 for field-constructed aboveground oil storage tanks do not apply. The 

Alpine Field, Satellites, and Pipelines ODPCP 2-10 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

following addresses requirements of 18 AAC 75.066 for ADEC-regulated shop-fabricated aboveground oil 

storage tanks at Alpine. 

Tank Design and Construction 

In accordance with 18 AAC 75.066(a)(1), ADEC-regulated shop-fabricated aboveground oil storage tanks 

initially placed into service on or before December 30, 2008, are not subject to requirements for design and 

construction standards and, if of vaulted, self-diked, or double-walled design, are not subject to additional 

design and equipment requirements of 18 AAC 75.066(c), (d), and (e), respectively. 

ADEC-regulated shop-fabricated aboveground oil storage tanks placed into service after December 30, 

2008, will be consistent with 18 AAC 75.066(a)(2). Tanks placed into service after December 30, 2008, will 

be designed and constructed according to an ADEC-approved design, including: Underwriters Laboratory 

(UL) 142, API 650, API 12F, STI F921-03, UL 2085, or an engineer-certified design approved by ADEC. 

ADEC-regulated vaulted, self-diked, or double-walled shop-fabricated aboveground oil storage tanks 

placed into service after December 30, 2008, will meet requirements of 18 AAC 75.066(c), (d), and (e), 

respectively. 

Maintenance and Inspection 

Regulated oil storage containers owned and operated by COPA are maintained and inspected in accordance 

with state and federal regulatory requirements. Required inspections, repairs, and alterations are discussed 

in the following sections. Inspection schedule information for ADEC-regulated tanks is provided in Appendix 

D, Table D-1 for tanks owned by COPA and operated at Alpine, in Table D-2 for tanks owned by COPA that 

may be operated at Alpine, in Table D-3 for tanks that may be directly rented by COPA, and in Table D-4 for 

third-party tanks not owned or leased by COPA. Descriptions and locations of oil storage containers with 

capacity less than 10,000 gallons and that are regulated by EPA, are listed in COPA’s Alpine SPCC Plan. 

EPA SPCC-regulated oil containers, with capacity of 55 gallons or more, are inspected in accordance with 

COPA tank management and/or PM programs, which include periodic visual inspection conducted 

according to written procedures. Additional description, locations, and inspection information is provided in 

COPA’s Alpine SPCC Plan available at the facility. 

COPA requires regulated tanks rented or leased directly by COPA meet all applicable regulatory 

requirements. 

ADEC-regulated oil storage tanks at Alpine are elevated. Internal and external inspections on regulated 

tanks are performed by a tank inspector certified under API 653 at the frequencies required by API 653 and 

18 AAC 75.066(f), or as determined by the certified inspector under best management practices. 

COPA inspects and maintains tanks in accordance with tank management and PM programs. Tanks not 

owned, leased, or operated by COPA (otherwise referred to as third-party tanks) are inspected and maintained 

by the tank owner. COPA may audit third-party service companies to ensure their practices are in accordance 

with their respective tank management programs. Tanks provided by non pre-qualified companies are 

reviewed by COPA prior to being put into service. 

Integrity inspection of aboveground oil storage tanks is conducted by staff or contract-certified tank 

inspectors in accordance with API 653 and ADEC requirements for regulated tanks. 

Internal tank corrosion is often mitigated by use of coatings, anodes (cathodic protection), and/or the use 

of corrosion-resistant alloys. 

Alpine Field, Satellites, and Pipelines ODPCP 2-11 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

At a minimum, monthly routine operational examinations (external) are conducted for ADEC-regulated oil 

storage tanks. EPA SPCC-regulated oil storage containers are visually inspected at least annually. Written 

records of repairs or operational alerts are retained for the life of the tanks. Records of API 653 inspections 

are prepared according to API document guidelines and retained for the service life of the tanks. Records 

of visual inspections are maintained in accordance with Company policies. 

Discharge Prevention 

For tanks with automated liquid level devices, various types of liquid level devices are used for overfill 

protection and tank level indication. For some tanks at CD1, devices feed into the distributed control system 

(DCS) for localized control of shutdown and/or alarms, with reporting back to the control room. If a highlevel situation is detected, the transmitters send a signal to the DCS, which initiates both remote and local 

alarms and closes automated ESD valves on those tanks that are so equipped. The ESD valves are 

automated valves. 

The three types of liquid level devices are: 

• Hydrostatic Head or Differential Pressure Devices: These transmitters are located in the 

bottom of the tank and measure the liquid level by comparing atmospheric pressure and the 

pressure inside of the tank. 

• Ultrasonic Non-Contact Transmitter: This transmitter utilizes microprocessor-based 

electronics and non-contact ultrasonic transducers to provide a level measurement unaffected 

by changes in specific gravity, viscosity, or conductivity. The sensor is mounted at the top of 

the tank. Ultrasonic pulses are directed to the measuring surface. The returning echo is 

detected by the sensor, and the electronics amplify and convert the signal into a digital 

representation of the level. 

• Microwave Radar Non-Contact Transmitter: This transmitter utilizes microwave signals, 

typically emitted from an antenna, that travel at light velocity to the liquid surface and then are 

reflected back to a sensor that detects the time taken for the microwave reflection (or echo). 

Unlike sound waves, microwaves require no transmission medium and can be applied in 

vacuum and positive-pressure conditions. 

At a minimum, monthly manual tank strapping measurements are conducted on non-fuel gas-blanketed 

tanks or tanks without two independent level measurement devices to check tank levels and verify 

automated devices indicate proper level limits. 

Tanks with more than one independent transmitter have additional (redundant) protection. The independent 

systems are measured for deviations between each other. Audible systems connected to the DCS will 

sound an alarm in the control room if deviations are detected. This type of backup system creates a 

continuous internal testing system for the liquid-level devices. 

Overfill protection devices are tested before each transfer operation, or monthly, whichever is less frequent. 

If monthly testing would necessitate interrupting the operation of a system subject to continuous flow, 

monthly inspection and annual testing may be substituted for the monthly testing as required in 18 AAC 

75.066(h). For tanks without automated overfill protection devices, overfill protection relies on visual 

surveillance. Tank fuel levels are monitored and controlled manually during filling activities. 

Fueling operations will follow COPA’s fuel transfer procedures to prevent discharge from transfer hoses, as 

discussed in Section 2.1.5. 

Alpine Field, Satellites, and Pipelines ODPCP 2-12 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2.1.10 Secondary Containment Areas for Aboveground Oil Storage Tanks [18 AAC 75.075] 

For purposes of 18 AAC 75.075, 18 AAC 75.990(165) defines “aboveground oil storage tank” as having 

capacity of greater than 10,000 gallons. Secondary containment is provided at permanent tank installations 

and for regulated oil storage containers, according to applicable requirements. Secondary containment 

areas for aboveground oil storage tanks are sufficiently impermeable, typically lined with a product resistant 

synthetic liner and sized for 100 percent capacity of the largest single tank, plus an additional volume for 

precipitation. Secondary containment information including type and volume descriptions for EPA SPCCregulated oil storage containers with capacity 55 gallons or greater as required by 40 CFR 112.7(c), and 

112.8(c), or 112.9(c), is provided in the Alpine SPCC Plan. 

Secondary containment systems are resistant to operational damage and weather, and are sufficiently 

impermeable as required by 18 AAC 75.075(a)(2). In addition, personnel follow a field procedure, which 

describes the containment dimensions based on the size and number of tanks when constructing secondary 

containments for portable tanks. Secondary containment systems are maintained free of major debris, 

vegetation, and excessive accumulated water that may interfere with the effectiveness of the system. 

Secondary containment areas are routinely visually checked for presence of leaks or spills and documented 

weekly inspections are performed, in accordance with 18 AAC 75.075(c). Drainage, when required to 

recover containment capacity due to snowmelt or rain, is typically performed by vacuum truck. Where 

applicable, COPA’s Liner and Drip Pan Use Policy will be followed.. 

Shop-fabricated aboveground oil storage tanks of a vaulted, self-diked, or double-walled design are not 

required by state or federal regulation to be placed within bermed, lined, secondary containment areas if 

they are equipped with catchments that positively hold overflow due to tank overfill, or divert it into an 

integral secondary containment area [18 AAC 75.075(h)]. Local agency requirements for containment of 

double-walled tanks are either met or waived by approval of the local agency. 

Portable oil storage tanks that are temporarily not in use are emptied and placed within designated storage 

areas on gravel pads without secondary containment. The stored tanks are maintained under the tank 

management program. 

COPA notifies ADEC in writing within 24 hours if a significant change occurs in or is made to an ADECregulated secondary containment system and if, as a result of the change, the system no longer meets the 

ADEC performance requirement [18 AAC 75.475(d)]. 

Tank Truck Loading Areas and Permanent Unloading Areas 

For purposes of compliance with 18 AAC 75.075(g), tank truck loading areas and permanent unloading 

areas are identified in Table 2-3 and are recognized as those involving frequent transfers of oil to and from 

ADEC-regulated aboveground oil storage tanks, which is defined in 18 AAC 75.990(165). 

In accordance with 18 AAC 75.075(g), tank truck loading areas and permanent unloading areas are: 

• Designed with secondary containment to contain 100 percent of the maximum capacity of any 

single compartment of a tank truck; 

• Paved, surfaced, or lined with sufficiently impermeable materials; 

• Maintained free of debris, vegetation, excess accumulated water, or other materials; 

Alpine Field, Satellites, and Pipelines ODPCP 2-13 February 2018, Rev. 0 
 

 

• Have warning lights, warning signs, or contain physical barriers to prevent premature vehicular 

movement; and 

• Visually inspected before any transfer operation, or at least monthly. 

Alpine Field, Satellites, and Pipelines ODPCP 2-14 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

TABLE 2-3:TANK LOADING AND UNLOADING AREAS AT ALPINE 

FACILITY MODULE TAG # SERVICE 

NOMINAL 

DESIGN 

CAPACITY (BBL) 

MAXIMUM BULK 

TRUCK 

COMPARTMENT SIZE 

(BBL) 

BULK TRUCK 

AREA LINED? 

(Y/N) 

LINER TYPE 

SIZE/CAPACITY OF

LINED AREA FOR BULK 

TRUCKS 

BERMS, TRENCHES, OR 

DRAINS FOR LOADING 

AREA CONTAINMENT 

PHYSICAL 

BARRIERS, 

LIGHTS, OR SIGNS 

WAIVERS IN EFFECT 

CD1 

G1 CF-T-50061A Completions Fluid Storage Tank 

(Diesel at present) 400 

325 Y 

Pre-cast concrete slabs 

with underlying 

geomembrane liner (80-

mil Polyshield SS-100 or 

equivalent) 

95 ft X 36.3 ft 

620 bbl 

4% grade toward a sump 

with vertical sidewalls, 

slopes up again at 

opposite end; pre-cast 

curbs along the sides; 

sump at bottom 

Yes None 

G1 CF-T-50061B Completions Fluid Storage Tank 

(Diesel at present) 400 

G1 CF-T-50063A 

Upright Fiberglass Tank (“Brine Tank”) 

(Diesel at present; may also contain 

mineral oil or brine) 

400 

G1 CF-T-50063B 

Upright Fiberglass Tank (“Brine Tank”) 

(Diesel at present; may also contain 

mineral oil or brine) 

400 

G1 CF-T-61001 ULSD Storage Tank 3,300 

G2 CF-T-50031 Production Chemical Tank (Biocide) 250 

G2 CF-T-50011 Production Chemical Tank (Scale 

Inhibitor) 400 

G2 CF-T-50001 Production Chemical Tank 

(Emulsion breaker) 750 

G2 CF-T-60001 Lube Oil Storage Tank 250 

G2 CF-T-31010 Slop Oil Tank 1,500 

G2 CF-T-52001 Production Chemical Tank 

(Triethylene glycol) 250 

G2 CF-T-51001 Production Chemical Tank (dry crude 

or diesel) 1,500 

G5 CF-T-50090 Glycol or Diesel 803 

G6 CF-T-50120 Corrosion Inhibitor 750 

Alpine Injection 

Skid 

(MI SWACO) 

MI-A6061610 Varies – water and drilling mud 1,000 

325 Y Sufficiently impermeable 

welded steel structure 

86 ft X 25 ft 

approx. 473 bbl 

Below grade, drive 

through area with 

containment sump tanks 

Yes 

MI-A6061611 Varies – water and drilling mud 1,000 

MI-A6061612 Varies – water and drilling mud 1,000 

MI-A6061613 Varies – water and drilling mud 1,000 

CD2 

CD2 Tank Farm CD2-T-51001 Weathered crude Storage Tank 500 

325 Y 

Pre-cast concrete panels 

with underlying 

geomembrane liner 

85.6 ft X 23.6 ft 

635 bbl 

3% grade toward sump, 

slopes up at opposite end; 

pre-cast curbs along the 

sides 

Yes None 

CD2 Tank Farm CD2-T-50011 MeOH 250 

CD3 

CD3 J CD3-T-383003 Hydrocarbon recycle 443 

325 Y 

Pre-cast concrete panels 

and curbing with 

underlying geomembrane 

liner 

81.5 ft X 16.5 ft 

350 bbl 

2% grade toward sump, 

slopes up at opposite end; 

pre-cast curbs along the 

sides 

Yes None 

CD3 J CD3-T-553003 Water recycle 443 

CD3 J CD3-T-613012 ULSD Storage Tank 252 

CD3 J CD3-T-513006 Methanol 443 

CD3 J CD3-T-503009 Corrosion Inhibitor 443 

CD3 J CD3-T-503010 Scale Inhibitor 136 

CD3 J CD3-T-503037 Biocide 25 

CD3 J CD3-T-503038 Oxygen Scavenger 25 

CD3 J CD3-T-503011 Anti-foam 136 

CD3 J CD3-T-503012 Emulsion Breaker 136 

CD3 J CD3-T-503013 Vehicle fuel day tank 12 

CD5 Chemical Tank 

Farm CD5Q 

CD5-T-505031 Weathered crude 847 

325 Y 

Pre-cast concrete panels 

and curbing with 

underlying geomembrane 

liner and lined secondary 

containment sump 

(containment sump) 

67 ft X 16.6 ft X 2.42 ft 

338 bbl 

1% slope from tank truck 

area toward containment 

sump 

CD5-T-505002 Corrosion Inhibitor (non-oil) 847 Yes None 

CD5-T-505044 Corrosion Inhibitor (non-oil) 847 

Alpine Field, Satellites, and Pipelines ODPCP 2-15 May 2018, Rev. 2 
BLANK PAGE 

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2.2 DISCHARGE HISTORY [18 AAC 75.425(e)(2)(B)] 

Alpine participates proactively in spill prevention programs including campaigns, investigations, and training 

to increase employee awareness levels. 

The major causes for oil spills greater than 55 gallons were equipment difficulties associated with tanks, 

which accounts for most spills since 1999. Causes for spills can be grouped in the following 

categories:collision, corrosion, equipment failure, human error, leak, overfill, and unknown (Table 2-4). 

TABLE 2-4: ALPINE OIL SPILL REPORTS (1999-2016) 

CAUSE CATEGORY CAUSE SOURCE 

NUMBER 

OF 

SPILLS 

ESTIMATED 

CUMULATIVE 

VOLUME 

(GAL) 

Human Factors Human Error Fittings/seals/connections 1 440 

Heavy Equipment/ Mobile 

Equipment/ Vehicles 

2 664 

Tanks 4 913 

Overfill Heavy Equipment/ Mobile 

Equipment/ Vehicles 

2 151 

Tanks 3 3,551 

Structural/Mechanical Collision Heavy Equipment/ Mobile 

Equipment/ Vehicles 

1 600 

Corrosion Pipe/flowlines/ hardlines 1 170 

Equipment Failure Flanges 1 1,560 

Tanks 4 485 

Transfer hoses 1 420 

Leak Coiled tubing unit/wireline 

equip/well service 

1 62 

Fittings/seals/connections 1 252 

Sumps 1 500 

Tanks 1 210 

Overfill Fittings/seals/connections 1 840 

Operational Unknown Flares 1 210 

Pipe/flowlines/ hardlines 1 137 

The history of known discharges of volumes greater than 55 gallons is maintained in the COPA spill 

database for the life of the facility. The database includes the source, cause, amount of the discharge, and 

corrective actions taken. Most spills that occur at Alpine are small events that are contained on gravel pads 

and rarely reach the tundra or water environment. The history of known discharges greater than 55 gallons 

for COPA in the Alpine field since 1999 is included in Appendix C. 

A spill analysis was completed for oil spills over 55 gallons at Alpine since facility startup in 1999 through 

2016. The analysis showed that sources with the highest percentage of spill incidents were tanks (44%) 

and heavy equipment/ mobile equipment/ vehicles (18%) (Figure 2-1). The largest percentage of spill 

volume was from tanks (46%), and from flange failure (14%) and heavy equipment/ mobile equipment/ 

vehicles (13%) (Figure 2-2). Figure 2-3 illustrates percentage of oil spill volume by cause. 

Alpine Field, Satellites, and Pipelines ODPCP 2-17 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

The history of known discharges for reportable spills to tundra and/or water since 1999 is included in 

Appendix A. Appendix A includes the information outlined in 40 CFR Part 112, Appendix F, Section 1.4.4, 

for spills that are identified by 40 CFR Part 110. 

COPA North Slope operations employ several measures to minimize and mitigate the occurrence of spills. 

A “Root Cause Failure Analysis” investigation process occurs for significant spills and corrective actions 

are taken based on the analysis by the review team. Lessons learned are shared with supervisors and 

affected workgroups to promote spill prevention. Depending on the incident, the review team may include: 

personnel responsible for the operation causing the spill, their foreman or supervisor, a safety 

representative, field environmental compliance personnel, a facility supervisor, and/or a corrosion engineer. 

The investigation process is aimed at increasing safety and reducing personnel exposure to spilled 

materials, preventing reoccurrence of spills, and identifying spill causes and early detection. Spill 

investigation results are communicated to field personnel to promote spill prevention. Periodically, teams 

may be developed to conduct an analysis of spill causes, volumes, and frequencies. Slope-wide trends of 

frequency, cause, and size of spills are noted. 

COPA promotes spill prevention by encouraging proactive involvement and knowledge sharing through 

spill prevention programs and awareness training or communications. Personnel receive recognition for 

outstanding spill prevention and information or new tools/procedures are shared with other Alpine 

personnel. 

Alpine Field, Satellites, and Pipelines ODPCP 2-18 February 2018, Rev. 0 
 

 

FIGURE 2-1: PERCENTAGE OF OIL SPILL INCIDENTS BY SOURCE (1999 – 2016) 

FIGURE 2-2: PERCENTAGE OF OIL SPILL VOLUME BY SOURCE (1999 – 2016) 

Alpine Field, Satellites, and Pipelines ODPCP 2-19 February 2018, Rev. 0 
FIGURE 2-3:PERCENTAGE OF OIL SP ILL VOLUME BYCAUSE (1999 – 2016)

Alpine Field, Satellites, and Pipelines ODPCP 2-20 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2.3 POTENTIAL DISCHARGE ANALYSIS [18 AAC 75.425(e)(2)(C)] 

This section is an analysis of potential oil discharges at Alpine. Response scenarios, including response 

planning standard volumes, are presented in Section 1.6.3, Response Strategies, and are not duplicated 

here. 

Table 2-5 shows potential spill sources, the types of failures that may occur, estimates of spill sizes, and 

appropriate prevention measures for Alpine operations. The historical data presented in Section 2.2 assist 

in identifying the areas of operation prone to spills. Table 2-6 indicates the approximate calculated volumes 

of individual pipeline sections. 

TABLE 2-5: ALPINE POTENTIAL OIL SPILLS FROM MAJOR SOURCES 

SOURCE CAUSE SIZE PREVENTION MEASURES 

ULSD Storage Tank Rupture, overflow, valve leak 3,300 bbl Impound basin, overfill alarms, daily 

visual checks 

Portable Tank Rupture, overflow, valve leak 400 bbl 

(varies) 

Secondary containment, transfer 

procedures, overfill alarms 

Fuel Transfer Rupture, overfill, valve leak, 

improper procedures 5 bbl Liners/drip pans, visual integrity inspection, transfer procedures 

Production Well Sheared off 2,000 –10,000 

bbl/day 

surface safety valves, blowout 

preventers, ESD system 

The following discussions are related to potential spills, prediction, and control. The major source of failures 

are tanks, vessels, piping, and process equipment. The major types of failures are leaks or ruptures. 

Alpine Central Processing Facility 

Major process and utility equipment at Alpine including pressure vessels, pumps, gas compressors, 

heaters, and major piping components such as pig launchers and receivers, are housed in enclosed 

modules. The modules in the processing facility are provided with a 4-inch raised sill and a module sump 

equipped with a 30-gallon per minute pneumatic sump pump. Contents of the sumps (resulting from minor 

hydrocarbon and water spills) are transferred by sump pump through a six-inch low-pressure drain header 

to the 1,500-barrel slop tank. 

In case of a major loss of containment, the overflow from each module sump is directed to the 660-gallon 

open-drain overflow sump through a six-inch overflow header. The contents of this sump are transferred by 

a 30-gallon per minute pneumatic sump pump through the 6-inch low-pressure drain header to the slop 

tank. Overflow from the open-drain overflow sump is directed via a six-inch line to the secondary 

containment basin in the tank farm. The largest possible hydrocarbon spill from the process area (the inlet 

separator in the A3 module) will not exceed 1,000 barrels. The ULSD storage tank and other storage tanks 

are contained by a 5,220-barrel lined pit and a dike. The volume of the secondary containment is greater 

than 100 percent of the ULSD tank, which is the largest facility tank. Small to moderate leaks from failures 

of bulk chemical tanks or vessels (i.e., crude, corrosion inhibitor, lube oil, methanol) within the facility would 

be controlled by the floor drain sump system and by the modular “cell” design of the facility itself. 

Drill Sites 

Small discharges from wells are contained in the well cellars. 

In the event of an on-pad rupture or failure, a discharge is typically retained by the gravel pad. Personnel 

are summoned for spill response and containment as described in Section 1. In the event of a flowline 

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rupture or failure, subsurface and/or surface safety valves in the well are activated to a closed position from 

a low-pressure sensor, preventing continued discharge. Low-pressure alarms alert Operations personnel 

who would initiate spill response and containment, as necessary. 

Production and gas injection wells at Alpine are subject to routine integrity testing by AOGCC statutes. On 

a rotating basis, each well is subject to testing on a frequency determined by well type. The safety systems 

of the well being tested are tripped out by an artificially-created low-pressure signal which causes the safety 

valves to shut in the well. A manual valve downstream is then closed and the tubing pressure is observed 

for increases in pressure. The State of Alaska inspectors witness the successful testing of the wellhead 

safety systems at prescribed intervals for wells capable of flowing hydrocarbons.Annulus integrity of 

injection wells is tested by a COPA procedure. The State of Alaska inspectors also witness this testing. 

Pipelines 

In the event of pipeline failure, Operations personnel isolate the damaged section by closing the necessary 

valves to prevent further discharge from production or backflow potential. The backflow potential is further 

reduced by the vertical loops along the crude oil transmission pipeline and diesel pipeline. 

Reaction time to isolate pipeline sections varies and is a factor in predicting spill volume potential. It is 

difficult to predict the rate or spill potential for any given pipeline beyond the immediate volume of the 

affected pipeline. Continuous production from drill sites is stopped when low pressure is sensed as a result 

of the failure. Both the visual observation of a pipeline leak by field personnel, and the low-pressure alarms 

from the primary separator vessel sensors, initiate a response and shut-in. It is unlikely that the entire 

volume would be drained, due to the frequent elevation changes associated with routing of pipelines and/or 

vertical loops. 

In the event of a pipeline spill, natural depressions adjacent to the subject pipeline and nearby dry lakebed 

depressions will provide temporary containment. Spill response will be provided by the Alpine SRT and/or 

COPA’s primary response action contractor, according to the procedures described in Section 1. 

Seawater pipelines have been included in the response planning effort even though seawater is not 

hydrocarbon by nature. It is unlikely that seawater pipelines, should they require displacement for freeze 

protection in the event of upset, will be displaced with any substance other than warm fuel gas. However, 

a portion of the displacement process requires a glycol/water “slug” to chase the water from the pipeline, 

leaving a glycol residue that coats the pipeline wall. Should a failure occur during this process, glycol may 

be present in the seawater. 

Should a spill occur from a produced water pipeline, hydrocarbons may be present and should be 

considered in the spill response. 

Drainage maps of the Alpine area are located in the ACS Technical Manual Map Atlas and Section 1.8. 

Alpine Field, Satellites, and Pipelines ODPCP 2-22 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TABLE 2-6: POTENTIAL DISCHARGE OF ALPINE PIPELINES 

FROM TO DIAMETER* 

(IN) 

LENGTH 

(FT) 

PIPELINE 

CAPACITY 

(FT3) 

POTENTIAL 

DISCHARGE 

(BBL) 

NOTE 

SALES CRUDE OIL 

CD1/ACF HDD West Loop 14 47,886 51,191 9,112 

HDD West Loop HDD East Loop 14 5,304 5,670 1,009 Colville River crossing (below grade) 

HDD East Loop Vertical Loop #1 14 8,951 9,569 1,703 

Vertical Loop #1 Vertical Loop #2 14 42,413 45,340 8,071 

Vertical Loop #2 Vertical Loop #3 14 1,255 1,342 239 Kachemach River crossing 

Vertical Loop #3 Vertical Loop #4 14 18,809 20,107 3,579 

Vertical Loop #4 Vertical Loop #5 14 3,317 3,546 631 Miluveach River crossing 

Vertical Loop #5 CPF2 Valve 14 54,741 58,519 10,416 

PRODUCED OIL (THREE PHASE LIQUID) 

CD1 CD1/ACF 18 790 1,396 248 

CD2 CD1/ACF 20 17,600 38,397 6,835 

CD3 CD1/ACF 16 35,800 49,986 8,898 

CD4 CD1/ACF 14 23,600 25,229 4,491 

CD5 CD5 Nigliq Valve 20 16,646 36,316 6,464 

CD5 Nigliq Valve CD5@ CD4 road 20 19,453 42,440 7,554 

CD5@ CD4 road CD1/ACF 20 15,285 33,347 5,936 

GMT1 West Tin Valve 19.25 30,414 61,470 10,942 

West Tin Valve East Tin Valve 19.25 3,285 6,639 1,182 Tinmiaqsiugvik River crossing 

East Tin Valve CD1/ACF 19.25 11,090 22,414 3,990 

ENHANCED OIL RECOVERY (MISCIBLE INJECTANT) 

CD1/ACF CD1 6 790 155 28 

CD1/ACF CD2 8 17,600 6,144 1,094 

CD1/ACF CD3 6 35,800 7,029 1,251 

CD1/ACF CD4 6 23,600 4,634 825 

CD1/ACF CD5 6 51,384 10,089 1,796 

CD5 GMT1 7.5 44,600 13,683 2,436 

Alpine Field, Satellites, and Pipelines ODPCP 2-23 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

FROM TO DIAMETER* 

(IN) 

LENGTH 

(FT) 

PIPELINE 

CAPACITY 

(FT3) 

POTENTIAL 

DISCHARGE 

(BBL) 

NOTE 

SEAWATER 

CPF2 Valve Vertical Loop #5 12 54,741 42,993 7,653 

Vertical Loop #5 Vertical Loop #4 12 3,317 2,605 464 Miluveach River crossing 

Vertical Loop #4 Vertical Loop #3 12 18,809 14,773 2,630 

Vertical Loop #3 Vertical Loop #2 12 1,255 986 175 Kachemach River crossing 

Vertical Loop #2 Vertical Loop #1 12 42,413 33,311 5,929 

Vertical Loop #1 HDD East Loop 12 8,951 7,030 1,251 

HDD East Loop HDD West Loop 12 5,304 4,166 742 Colville River crossing (below grade) 

HDD West Loop CD1/ACF 12 47,886 37,610 6,695 

CD1/ACF CD1 8 790 276 49 

CD1/ACF CD2 10 17,600 9,599 1,709 

CD1/ACF CD3 8 35,800 12,497 2,224 

CD1/ACF CD4 8 23,600 8,238 1,466 

CD1/ACF CD5 8 51,384 17,936 3,193 

CD1/ACF CD5 12.75 51,600 45,751 8,144 

CD5 GMT1 12.75 44,600 39,544 7,039 

DIESEL 

CPF2 Valve Vertical Loop #5 2 54,741 1,194 213 

Vertical Loop #5 Vertical Loop #4 2 3,317 72 13 Miluveach River crossing 

Vertical Loop #4 Vertical Loop #3 2 18,809 410 73 

Vertical Loop #3 Vertical Loop #2 2 1,255 27 5 Kachemach River crossing 

Vertical Loop #2 Vertical Loop #1 2 42,413 925 165 

Vertical Loop #1 HDD East Loop 2 8,951 195 35 

HDD East Loop HDD West Loop 2 5,304 116 21 Colville River crossing (below grade) 

HDD West Loop CD1/ACF 2 47,886 1,045 186 

CD1/ACF CD3 2 35,800 781 139 

*GMT1 pipelines potential discharge estimated using inner diameter size; other pipeline’s diameter sizes may reflect outer shell measurement and thus provide more conservative 

potential discharge volume estimates. 

Alpine Field, Satellites, and Pipelines ODPCP 2-24 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2.4 CONDITIONS INCREASING RISK OF DISCHARGE 

[18 AAC 75.425(e)(2)(D)] 

Conditions specific to COPA's North Slope operations that potentially increase the risk of discharge, and 

actions taken to eliminate or minimize identified risks, are summarized below: 

• Temperature: Heat may cause gases to expand, increasing the likelihood of discharge. North 

Slope facilities are engineered to accommodate temperature fluctuations. 

• Weather Conditions: Icy roads, white-out conditions, and cold snaps present obvious threats 

to field operations. COPA Security's strict adherence to vehicle safety, speed limits, and the 

posting of warning signs assist in minimizing the potential for vehicular accidents that may 

result in a spill. In addition, North Slope facilities are engineered to withstand Arctic conditions. 

• Traffic Patterns: Changes in traffic patterns may increase the risk of vehicles colliding into 

well lines. COPA Security's strict adherence to vehicle safety, speed limits, and the posting of 

warning signs or traffic cones will help to minimize the potential for vehicular accidents that 

may result in a spill. 

• Unplanned Shutdown Trans-Alaska Pipeline System: If Alyeska Pipeline Service Company 

unexpectedly shuts down the Trans-Alaska Pipeline System, the risk to COPA operations 

increases. COPA's advanced communication system enables immediate communication 

between Alyeska Pipeline Service Company and the North Slope operators, which allows for 

the coordination of impacts and minimizes the risks due to a shutdown of the pipeline. 

Conditions specific to Alpine operations that potentially increase the risk of discharge, and actions taken to 

eliminate or minimize identified risks, are summarized below: 

• Upheaval Buckling: Buried pipelines in the Arctic are installed at temperatures that are below 

their operating temperatures. Because buried pipelines are restrained during thermal 

expansion, significant compressive force develops in pipelines that increase from their installed 

temperature to their operating temperature. This compressive force may cause upheaval 

buckling (vertical buckling displacement of a pipeline due to low lateral stability provided by the 

pipeline’s overlying soil). The cross-country pipelines buried at the Colville River crossing are 

located at sufficient depth to avoid upheaval buckling. 

• High Water/Ice: High water and/or ice during spring break-up could increase the risk of 

discharge from pipeline crossings over rivers. To decrease risk of a discharge, pipeline 

crossings over rivers are built above flood levels and are engineered to withstand ice impact 

and jamming. The cross-country pipeline crossing at the Colville River is a below-river crossing; 

thus, it is not affected by high water or ice. High water could also increase the risk of discharge 

in locations where a large flood (200-year event) could threaten access to drill sites or in-field 

oil piping. In the event a large flood causes an emergency situation, to decrease risk of a 

discharge, Alpine Operations may initiate an emergency de-inventory of the affected pipelines. 

The emergency de-inventory would stop production and injection operations, and the affected 

pipelines would be emptied and depressurized. 

• Permafrost Thaw Subsidence: The weight and heat from a buried operating pipeline causes 

some differential thaw subsidence at locations where permafrost soils exist. Permafrost soils 

are not found in the underground crossing area of the cross-country pipeline route. 

Alpine Field, Satellites, and Pipelines ODPCP 2-25 February 2018, Rev. 0 
 

 

 

 

• Roadless Areas: To decrease risk of discharge, automated process control equipment can be 

installed at wells and pipelines to allow continuous monitoring of production factors, such as 

wellhead temperature and pressure, annuli pressures, choke and valve positions, gas, and/or 

liquid level in the well cellar. 

Alpine Field, Satellites, and Pipelines ODPCP 2-26 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2.5 DISCHARGE DETECTION [18 AAC 75.425(e)(2)(E)] 

2.5.1 Drill Sites and Production Facilities 

Routine tours of drill sites and production facilities by Operations personnel can detect leaks or spills from 

the drill sites. 

Production wells capable of unassisted flow are equipped with surface safety valves that are monitored and 

controlled by an automated system; wells may also be equipped with subsurface safety valves. The system 

is designed to shut in well production automatically when the pressure transmitter senses pressure below 

a specified set point. At CD3, because it is remote, the wellheads are fully instrumented to allow continuous, 

remote monitoring of wellhead pressure and temperature, well annulus pressure (inner and outer annuli), 

and choke and valve positions. In addition, each well house at CD3 is equipped with a gas detector and 

liquid level detector in the well cellar that ties in to the automated system. 

2.5.2 Alpine Oil Pipeline 

The Alpine crude oil transmission pipeline (Alpine Oil Pipeline) is monitored for leaks using three different 

methods: 1) metered balancing, 2) computational pipeline monitoring, and 3) visual surveillance. 

Metered Volume Balancing 

Volumetric balancing is one method used to monitor for leaks along the Alpine Oil Pipeline. This method 

compares the volume leaving the pipeline against the total volume entering the pipeline over various time 

periods. Calculations are made using meter readings corrected for temperature and pressure to standard 

barrel conditions (0 pounds per square inch gauge [psig] and 60 degrees Fahrenheit [°F]). Volume balances 

of the Alpine Oil Pipeline are performed at 1-minute, 1-hour, and 24-hour intervals. 

A custody transfer metering system is installed at Alpine and meters are installed at CPF-2, where the 

Alpine Oil Pipeline terminates. Custody transfer metering at Alpine consists of a meter skid with a meter 

prover. This combination provides the most accurate volume measurement currently accepted by industry. 

The custody metering skid uses turbine meters as the primary flow measuring element. Oil volumes are 

computer-corrected to industry standard reference conditions of 0 psig and 60 °F. 

Meter provers are used to develop correction factors to account for changes in temperature, pressure, 

meter wear, etc. Meter “proofs” are obtained on a regular basis and as required by changes in operating 

conditions. Additional proving can be done if discrepancies in the volume balance become evident or if 

meter correction curves show a shift. 

While the Alpine Oil Pipeline operates full (line packed), variations in the meter readings, changes in the 

average pressure and temperature of the crude, and different pipe diameters cause “noise” that make exact 

volume balancing impossible. This noise is reduced as the balance is taken over more throughput (i.e., 

longer time periods), but it is never entirely eliminated. Thus, in volume balancing leak detection, a 

maximum variation, or imbalance, is set for various lengths of time. Note that in volume balancing, the 

balance over several days should lose and gain, with a net variation of about zero. 

A consistent loss or gain trend indicates a bias in the measurement system or possibly a small leak 

(consistent loss). 

Alpine Field, Satellites, and Pipelines ODPCP 2-27 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Computational Pipeline Monitoring 

Computational pipeline monitoring involves using algorithmic tools to perform statistical analysis to 

determine hydraulic anomalies that may indicate a leak or spill. Real-time probability analysis is performed 

on the Alpine Oil Pipeline by a dedicated system using a proprietary third-party software package. Statistical 

analysis is performed on the pipeline flow rates and pressures to identify fluctuations such as a drop in 

pressure or a change in flow. This statistical approach is limited to detecting leaks that affect pipeline flow 

and detecting pressure that is noticeable within the normal flow and pressure fluctuations. 

Advanced process automation controls monitor the compensated volumes, pressures, and temperatures 

entering and leaving the pipeline. This information is distributed through the SCADA system and handed 

off to a dedicated computer system running the software package LINEGUARDTM. LINEGUARDTM performs 

dynamic pipeline monitoring using a material balance calculation on the system at 5-minute, 1-hour, and 

24-hour intervals to detect volume imbalance and thus possible leak. LINEGUARDTM also analyzes inlet 

and outlet flow rate, calculated segment flow rate and measured pressures to determine leak location. 

The material balance calculation determines system imbalance by subtracting the sum of the volume into 

and out of the pipeline from the calculated volume of fluid contained in the pipeline (known as “linepack”). 

LINEGUARDTM calculates pipeline linepack using measured pressure, temperature, and density data 

gathered by process automation controls and sent to the SCADA system, taking into account temperature 

fluctuations and known physical or hydraulic characteristics of the pipeline system. The calculated volume 

imbalance is then compared to the set leak thresholds and alarms are generated if the thresholds are 

reached. LINEGUARDTM also calculates flow rate in each segment of the pipeline system, and uses those 

values along with pressure and flow changes measured at inlets and outlets of the pipeline system to 

estimate the location of a leak. The system accounts for the starting/stopping of shipping pumps and can 

accommodate shutdown periods. 

Visual Surveillance 

The Alpine Oil Pipeline and Diesel Pipeline are aboveground pipelines supported by vertical support 

members, with the exception of the crossing at the Colville River. Weekly visual inspections (weather and 

equipment permitting) are made by aerial surveillance in accordance with 18 AAC 75.055(a)(3); a log is 

completed by surveillance personnel. For the sections of the pipelines located on the facility, daily 

inspections are performed as part of routine operations. 

As an added measure of leak detection, aerial surveillance can be conducted using a FLIR-equipped 

aircraft, weather and safety conditions permitting, to survey piping for temperature anomalies that could be 

indicative of a leak or certain other conditions. During winter snow conditions, FLIR equipped flights are 

conducted as part of the weekly aerial surveillance. FLIR surveillance may be delayed due to emergency 

use of the FLIR in other locations, or mechanical failure or routine maintenance of the aircraft or FLIR 

system. Therefore, COPA relies upon weekly visual aerial surveillance to meet requirements of 18 AAC 

75.055(a)(3). 

If a minor leak is suspected, it is the responsibility of the Pipeline Controller or his designee to dispatch 

qualified personnel to visually check the line. Communications with the Pipeline Controller and facility 

operators is maintained so that appropriate action can be taken to mitigate a leak if discovered. 

Alpine Field, Satellites, and Pipelines ODPCP 2-28 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2.5.3 Facility Oil Piping and Flowline 

Facility oil piping is visually inspected for leaks during routine operations. Well lines with emergency 

shutdown valves are monitored with pressure sensors located at the drill site manifold. Flowlines are 

monitored by pressure sensors at the drill sites and production facilities that trigger alarms and emergency 

shutdown when abnormally low pressures occur. 

Daily operation of flowlines is monitored continuously by the SCADA system, using flow meters and 

pressure and temperature sensors to provide real-time information on pipeline status to control room 

operating personnel. In order to verify correct operation of the system, regular checks are conducted on the 

equipment employed, including the hardware and associated software. 

Routine visual observation of the pipelines to detect leaks occurs during road travel by field and/or security 

personnel, or during overflights of the pipeline route when no road access is available. Additionally, 

employee and contract personnel drive the road system adjacent to pipeline routing to the satellite drill 

sites. Elevated pipelines adjacent to the road system allow for visual detection of leaks from pipeline failure, 

valves, or tie-in connections. Should a pipeline failure manifest itself as a small leak and spill site, 

undetected by leak detection systems, it would likely be observed by personnel traveling by road or aircraft. 

2.5.4 Aboveground Oil Storage Tanks 

Alpine aboveground oil storage tanks with capacity greater than 10,000 gallons are elevated and located 

within secondary containment areas or have double-walled construction. At a minimum, visual checks to 

detect leaks or spills below the tank in the containment area and/or sump occur daily at manned facilities, 

such as CD1, or each time an unmanned facility, such as a satellite drill site, is visited as part of scheduled 

operational rounds. In accordance with 18 AAC 75.075(c), inspection of secondary containment areas for 

ADEC-regulated aboveground oil storage tanks occurs at least once per week. Tanks equipped with level 

indicators and/or alarms are monitored by the control room operating personnel through the SCADA 

system. An alarm or other system indication of abnormal low-level is investigated. 

Alpine Field, Satellites, and Pipelines ODPCP 2-29 February 2018, Rev. 0 
 

 

 

2.6 WAIVERS [18 AAC 75.425(e)(2)(F)] 

Waivers follow this page, as described below: 

• September 13, 2007. Waiver for Flow Line Marker Requirements. 

• October 7, 2004. Waiver of Cathodic Protection and Protective Wrapping/Coating 

Requirements for Underground Line (Tank CF-T-50090 to Module A2). 

Alpine Field, Satellites, and Pipelines ODPCP 2-30 February 2018, Rev. 0 
DEPT. OF ENVIRONMENTAL CONSERVATION

DIVISION OF SPILL PREVENTION AND RESPONSE

INDUSTRY PREPAREDNESS PROGRAM

SARAH PAUN, GOVERNOR

555 Cordova Street 

Anchorage, AK 99501

PHONE: (907) 269-30

FAX: (907) '269-7687

http://www.dec.state.ak.us

Exploration Production & Refineries

September 13, 2007

File No.: 305.30

(CPAI-Alpine & Kuparuk)

Ms. Leigh McDaniel

ConocoPhillips Alaska, Inc.

P.O. Box 100360

Anchorage, AK 99510-0360

Subject: ConocoPhillips Alaska, Inc. (CPAI) Oil Discharge Prevention and

Contingency Plans for the Kuparuk River Unit and Alpine Development

Participating Area. Waiver for Flow Line Marker Requirements

Dear Ms. McDaniel:

The Alaska Department of Environmental Conservation (ADEC) has reviewed your August 20,

2007 request (revised) for a waiver from the flow line marker requirements in 18 AAC

75.047(e) for CPAI Kuparuk and Alpine facilities. The letter reflects CPAI’s revised request as 

agreed upon in our.August 9, 2007 meeting.

Under 18 AAC 75.047(e), line markers must be installed and maintained over each onshore flow

line at road crossings and at one-mile intervals along the remainder of the pipe by December 30,

2007. The intent ofthe regulation is to facilitate rapid shutdown of a leaking line by quickly

identifying the line. CPAI is planning to install line markers at all road crossings by December

30, 2007, but is seeking,a waiver from the requirement forline markers at one-mile intervals

along the cross-country portions of flow lines.

In accordance with 18 AAC 75.015, ADEC may waive a requirement if the owner or operator

demonstrates that an equivalent level of protection will be achieved by using a technology or

procedure other than that required by 18 AAC 75.005-18AAC 75.085.

ADEC approves the .waiver request, based on.the following conditions that provide an equivalent

level of protection:

1. CPAI will, install additional line markers where flow lines approach drill pads for long

spans, of remote flow .lines by the end of 2007

2- CPAI pipeline,mapping information currently allows rapid identification of flow lines by

security, surveillance, and otherpersonnel during routine and emergency operations.

CPAIhas provided us with a copy ofthe pipelinemapping data file.

Printed on Recycled Paper
Ms. Leigh McDaniel

ConocoPhillips Alaska, Inc.

2 September 13, 2007

If you have any question, please contact me at (907) 269-7640.

Sincerely,

Laurie Silfven

Acting Section Manager

cc: Betty Schorr, ADEC

Tanya Verbyla, ADEC

Ed Meggert, ADEC, NART, Fairbanks .

Todd Nichols, ADFG, Fairbanks

Jack Winters/Mac McLean, ADNR Habitat, Fairbanks

Carol Fries, ADNR, Anchorage

Carl Lautenberger, USEPA

Capt. Mark DeVries, USCG Sector-Anchorage

Johnny Aiken, North Slope Borough

Melanie Barber, USDOT

Leonard Lampe, Nuiqsut

The Honorable Carl Brower, Mayor of Nuiqsut
DEPT. OF ENVIRONMENTAL CONSERVATION

DIVISION OF SPILL PREVENTION AND RESPONSE

INDUSTRY PREPAREDNESS PROGRAM

Exploration Production & Refineries

FRANK H. MURKOWSKI, GOVERNOR

555 Cordova Street

Anchorage, AK 99501

PHONE: (907) 269-3094

FAX: (907)269-7687

http://www.state.ak.us/dec

October 7, 2004

File No: 305.35 (CPAl-Alpine)

Mr. Jason Charton/Ms. Shellie Colegrove

Alpine Development Project

ConocoPhillips Alaska, Inc.

P.O. Box 100360

Anchorage, AK 99510-0360

Dear Mr. Jason Charton/Ms. Shellie Colegrove:

SUBJECT: ConocoPhillips Alaska, Inc. (CPAI) Alpine Development Participating Area, Oil

Discharge Prevention and Contingency Plan (plan), Plan Number 014-CP-4140.

Waiver of Cathodic Protection and Protective Wrapping/Coating Requirements

for Underground Line (Tank CF-T-50090 to Module A2).

The Alaska Department of Environmental Conservation (ADEC) has reviewed your request to

waive the requirements of 18 AAC 75.080(b)(1)(A) for the underground line being installed

between tank CF-T-50090 and module A2. In accordance with 18 AAC 75.015, ADEC may

waive a requirement if the owner or operator demonstrates that an equivalent level of protection

will be achieved by using a technology or procedure other than that required by 18 AAC

75.005- 18AAC 75.090.

According to your letter dated September 12, 2004, the underground line consists of a

continuous run of Vi-inch diameter, 316L stainless steel tubing encased in PVC-coated

insulation; the PVC will be supported by centralizers within fusion-joined, 8-inch HDPE

casing. The line will be added to CPAl’s below grade pipe monitoring program and will be

monitored with a gas detection device annually via a leak detection standpipe. While the line

will primarily be used to transfer DRA, it may also be used to transfer miscellaneous

hydrocarbons.

18 AAC 75.080(b)(1)(A) requires protective wrapping or coating and cathodic protection

appropriate for local soil conditions. Our review indicates that the proposed design, coupled

with annual monitoring, is sufficient to satisfy the intent of this regulation. The ADEC is

granting a waiver of the protective wrapping or coating and cathodic protection requirements of

18 AAC 75.080(b)(1)(A) for the underground line being installed between tank CF-T-50090

and module A2.

The waiver is subject to the following conditions:

1) CPAI must use the design construction described in your September 12, 2004

letter.

Primed on ric
Mr. Jason Charton/Ms. Shellie Colegrove

ConocoPhillips Alaska, Inc.

2 October 7, 2004

2) The line must be monitored with a gas detection device on an annual basis

(or greater frequency), and be part of CPAI’s below grade pipe monitoring

program as described in your September 12, 2004 letter.

3) The Alpine plan must be revised at the next routine update to include this

waiver approval letter.

Please be advised that the approval of this waiver does not relieve you of the responsibility for

securing other state, federal or local approvals or permits, and that you are still required to

comply with all other applicable laws.

If you have any questions, please contact Laune Silfven at 269-7540 or me at 269-7680.

Section Manager

cc: Bill Hutmacher, ADEC

Laurie Silfven, ADEC

Sam Saengsudham, ADEC

Stephen Geddes/Jeanie Shifflett, CPAI, Anchorage

Ed Meggert, ADEC, NART, Fairbanks

Mark Fink, ADFG, Anchorage

A1 Ott/Mac Maclean, ADFG, Fairbanks

Sam Means, ADNR, Anchorage

Carl Lautenberger, USEPA

Capt. Ron Morris, USCG MSO-Anchorage

Rex Okakok, North Slope Borough

Jim Taylor, USDOT

Leonard Lampe, Native Village of Nuiqsut
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

PART 3 SUPPLEMENTAL INFORMATION 

[18 AAC 75.425(e)(3)] 

3.1 FACILITY DESCRIPTION AND OPERATIONAL OVERVIEW [18 AAC 

75.425(e)(3)(A)] 

3.1.1 Facility Ownership and General Site Description [18 AAC 75.425(e)(3)(A)] 

The Alpine field, satellites, and pipelines are located within the North Slope Borough on federal, state, and 

private lands in the central Arctic Coastal Plain of Alaska’s North Slope. ConocoPhillips operates the drill 

sites, oil processing facility, and pipelines. The ownership of Alpine is as follows: 

Operator: ConocoPhillips 100% 

Alpine is located in the area of the Colville River delta approximately 35 miles west of Kuparuk Central 

Processing Facility #2 (CPF2). Alpine facilities are located in the vicinity of major channels of the Colville 

River, including the Nigliq Channel, the Sakoonang Channel, and the Tammaiyagiaq Channel and within 

the area of the Tinmiaqsiugvik River and Fish Creek. The Alpine Pipeline system runs from Alpine’s central 

processing facility at CD1 pad to Kuparuk CPF2. The village of Nuiqsut lies approximately 8 miles south of 

the main pad, CD1.. 

Alpine’s footprint consists of one main gravel pad (CD1) with base camp, wells, production modules, oil 

piping, materials and chemical storage, and processing facility (ACF), with five satellite drill sites on gravel 

pads (CD2, CD3, CD4, CD5, and GMT1), and gravel roads to drill sites CD2, CD4, CD5 and GMT1. Alpine 

drill sites CD1, CD2, CD3, CD4, and CD5 are located within the Colville River Unit, while drill site GMT1 is 

located within the Greater Mooses Tooth Unit. Approximately 100 to 300 employees are housed at the 

Alpine CD1 base camp facility during normal operations. The Alpine processing facility processes salesquality crude oil, separating oil from water and gas. The processing facility is capable of processing up to 

approximately 150,000 barrels of oil per day. 

A crude oil transmission pipeline, a diesel pipeline, a fiber optic cable, and a utility (seawater) pipeline 

extend 34.2 miles cross-country and aboveground on vertical support members (VSMs) from CD1 to 

Kuparuk CPF2. The crude oil transmission pipeline, diesel pipeline, fiber optic cable, and seawater pipeline 

cross beneath the main channel of the Colville River through bored and cased holes. Other minor river and 

stream crossings are aboveground, on VSMs. 

Drill site CD2, is located west of CD1 and consists of wells, production modules, oil piping, and materials 

storage. CD2 is connected to CD by a 3-mile-long gravel road. A 5,000-foot airstrip lies adjacent to this 

gravel road near CD1. 

Drill site CD3 lies to the north of CD1 and consists of a gravel pad, wells, production modules, oil piping, 

chemical storage, and a 3,040-foot-long airstrip that provides year-round access by aircraft. During winter, 

access to CD3 may also be via ice road. 

Drill site CD4 lies to the south of CD2 and consists of a gravel pad, wells, production modules, and oil 

piping. A 3.6-mile-long gravel road connects CD4 to the CD2 access road. 

Alpine Field, Satellites, and Pipelines ODPCP 3-1 April 2018, Rev. 1 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

Drill site CD5 lies to the west of CD4 and consists of a gravel pad, wells, production modules, oil piping, 

chemical storage, and approximately 6-mile long gravel road connected to the CD4 access road. 

Drill site GMT1 lies within the National Petroleum Reserve – Alaska, and consists of a gravel pad, wells, 

production modules, oil piping, and approximately 8-mile long gravel road connected to CD5. 

Each drill site is linked to an in-field pipeline system that connects to the Alpine processing facility at CD1. 

The in-field pipeline system consists of three-phase flowlines (oil, water, gas), gas lines (reinjection gas 

and/or miscible injection), and water lines. The CD3 in-field pipeline system also includes a diesel pipeline. 

The flowlines are supported on VSMs and extend approximately 3 miles from CD2, 6.5 miles from CD3, 

4.5 miles from CD4, approximately 6 miles from CD5 to the CD4 flowline tie-in, and approximately 8.5 miles 

from GMT1 to the CD5 flowline tie-in. The Nigliq Channel bridge carries the CD5 flowline over the channel. 

Alpine location maps and facility diagrams are provided in Section 1.8. 

Gravel Pads 

The Alpine gravel pads are, at a minimum, 5 feet above the surrounding tundra elevations. The shoulder 

elevations of the pads are at least 1 foot above the 200-year flood-event elevations. As a way to mitigate 

excessive storm water drainage, drainage basins are built into the CD1 pad using slight gravel grading 

change to collect excess water. The drainage basins collect snow/ice melt and precipitation during breakup and summer, so it does not run off the pad. During this time, the drainage basins are visually checked 

as part of routine operations and are drained as necessary. 

Waste Disposal and Water Use 

Solid waste, oily waste, and sewage solids are incinerated at the site or transported to Kuparuk or Prudhoe 

Bay for disposal. Gray water is injected into a permitted Class 1 disposal well at CD1. Drilling wastes are 

managed either by annular disposal into permitted wells at the drill site, or by transportation and injection 

into an approved Class 2 disposal well at CD1. Non-combustible solid waste is transported to approved, 

off-site facilities for disposal. 

During operations, fresh water is used at the facilities for maintenance drilling, potable water, firefighting, 

and dust suppression. A pump house is located at nearby lakes and is permitted to provide untreated water 

to CD1, where it is processed before use. The water in the lakes is accessed by pipeline from CD1. 

Additional lake water sources may be permitted and used during drilling operations. 

3.1.2 Facility Oil Storage Containers [18 AAC 75.425(e)(3)(A)(i) and (ii)] 

Appendix D contains the number, type, and oil storage capacity of each container regulated by ADEC 

covered under this plan and its installation date, design, construction, and general condition. The type and 

amount of oil stored in each container is also listed. Information about containers regulated under spill 

prevention, control, and countermeasures criteria is provided in the Alpine SPCC Plan. 

3.1.3 Transfer Procedures [18 AAC 75.425(e)(3)(A)(vi)] 

Transfer procedures are described in Section 2.1.5. 

During drilling activities and production operations, a tanker truck or mobile refueling tank is used to refuel 

equipment. These transfer operations are conducted with the fueling truck driver in constant attendance. 

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All fueling-hose transfer connections have a drip pan. The fueling truck also carries absorbents, waste 

containers, and tools to contain and clean up minor drips and spills. If necessary, the fueling truck is 

chocked to prevent vehicle movement during the transfer. 

3.1.4 General Description of Pipelines and Processing Facilities [18 AAC 75.425(e)(3)(A)(vii)] 

Pipelines 

Flowlines 

Flowlines connect the drill sites to the Alpine central processing facility. The separate three-phase oil 

production, gas and seawater pipelines (in-field pipelines) required for CD1 to CD2 operations cross 

underneath the gravel road near the west end of the airstrip at CD1, then run on the north side of the road 

to CD2. The road provides visual surveillance capability and flood protection for the pipelines. The in-field 

pipelines for CD1 and CD2 include two 8-inch diameter lines (gas and seawater) and one 20-inch diameter, 

three-phase line. With the exception of the small road crossing, the CD1 and CD2 in-field pipelines are 

supported on VSMs at least 5 feet above the tundra, with 50- to 65-foot spacing for approximately 3 miles. 

The pipelines connecting other drill sites consist of three-phase oil production, gas lift and/or miscible 

injection, water lines, and a diesel pipeline between CD1 and CD3. The pipeline corridor extends 

approximately 6.5 miles to CD3, 4.5 miles to CD4, approximately 6 miles to CD5, and approximately 8.5 

miles to GMT-1. Flowlines sizes and distances are presented in Table 2-6 and are illustrated in the Alaska 

Clean Seas (ACS) Technical Manual Map Atlas Sheets 12, 16, 17, 20, 22, 121, 125, and 126 and facility 

diagrams in Section 1.8. 

Pipeline elevation breaks created by raised sections of the pipeline at channel crossings aid in reducing 

spill volume, because the elevation breaks would trap liquids in the damaged pipeline away from the 

rupture. 

Facility Oil Piping 

Facility oil piping connects the wellhead to the flowline, and also includes oil piping associated with ADECregulated oil storage tanks. Produced fluids flow from the wellheads through well lines to drill site manifold 

buildings, which connect to flowlines. Manifold buildings are considered to be an interconnection and not 

ADEC-regulated facility oil piping under 18 AAC 75.080 if the buildings provide weather protection, include 

monitors and alarms for detecting abnormal conditions, and have floors, sills or other components that 

would contain most oil spills originating from piping within the building. Oil piping connecting an ADECregulated oil storage tanks to a fuel dispensing system, fill cap or valve, or transfer pump is considered 

facility oil piping. 

Crude Oil Transmission Pipeline 

The 34.2-mile crude oil transmission pipeline is constructed of steel, covered with insulation, and has a 

nominal diameter of 14 inches. The pipeline is designed to U.S. DOT standards for crude oil pipelines. The 

pipeline is cased within a carrier pipe where it crosses underneath the Colville River. Both the carrier pipe 

and the casing are fusion bonded epoxy coated and the annulus is equipped with leak detection. 

The insulated pipeline transports hot crude oil with a maximum design temperature of 180 degrees 

Fahrenheit (°F). The pipeline is elevated on VSMs. A minimum height of 5 feet is maintained for the entire 

length of the crude oil transmission pipeline. To further enhance caribou and human crossings, selected 

portions of the elevated pipeline exceed the 5-foot minimum (7 to 8 feet average) near streams and lake 

complexes where caribou and human use is high. 

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The crude oil transmission pipeline crosses three rivers, two of which are aboveground crossings, and the 

Colville River crossing, which is the only underground portion of the pipeline. River bank setbacks of 

approximately 300 feet were established for bored-hole entry and exit locations at the Colville River 

crossing. Horizontal directional drilling (HDD) was used to bore the crossing underneath the Colville River. 

These setbacks enhance caribou and human use crossings and achieve channel-migration setback 

allowances. The pipeline at this location is externally coated, while the aboveground portion is uncoated 

steel pipe, insulated with polyurethane and protected with a metal jacket. 

The pipeline support system has several components including VSMs, cross members, connectors, and 

pipe saddles. VSMs spaced approximately 55 to 70 feet apart, safely support the pipeline. Approximately 

2,760 VSMs were placed in the transportation corridor. The VSMs are embedded at depths between 20 to 

25 feet. 

Table 3-1 contains the design basis for the crude oil transmission pipeline. The table also includes the 

seawater and diesel pipelines that parallel the crude oil transmission pipeline. 

TABLE 3-1: CROSS-COUNTRY PIPELINE DESIGN BASIS 

LINE OUTSIDE DIAMETER 

(IN) 

DESIGN TEMP 

(°F) 

CORROSION 

ALLOW 

MAXIMUM ALLOWABLE 

OPERATING PRESSURE 

(PSI) 

Crude Oil Line 14 -50/180 0 2,064 

Seawater Line 12.75 -50/150 0 2,160 

Products Line 2.375 -50/100 0 1,366 

Vertical loops were placed in the pipeline in lieu of valve hardware, except at the pipeline inlet and outlet 

where automatic ball valves are located. This alternative was developed in recognition of the relatively low 

terrain relief of the North Slope and the spill risks associated with valves. These loops were installed to form 

a terrace structure that significantly limits the amount of oil that could be spilled due to drain-down effects. 

The potential pipeline spill volumes with this design are less than those associated with the valved pipeline 

alternative. Vertical loops perform the same function as valves without the hydraulic inefficiencies and 

maintenance concerns associated with check valves. The loops meet the requirements of Title 49 of the 

Code of Federal Regulations (CFR), Part 195. Besides reducing the risk and size of spills, the loops do not 

require maintenance and testing, as do valves, therefore reducing the need for gravel heliports on the 

tundra and for tundra access. The pipeline contains seven vertical loops, one on each side of the Colville, 

Miluveach, and Kachemach rivers, and one approximately 1.5 miles east of the Colville River. 

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TABLE 3-2: ALPINE CROSS-COUNTRY PIPELINE VERTICAL LOOP PLACEMENT 

LOCATION DESCRIPTION 

PIPELINE DISTANCE FROM 

ALPINE PROCESSING FACILITY 

(FT) 

PIPELINE ELEVATION 

(FT) 

Alpine Processing Facility Pig Launcher 0 32 

Vertical Loop HDD West 47,886 34 

Vertical Loop HDD East 53,190 35 

Vertical Loop #1 62,141 68.25 

Vertical Loop #2 104,554 71.66 

Vertical Loop #3 105,809 99.61 

Vertical Loop #4 124,618 101.1 

Vertical Loop #5 127,935 114.26 

CPF-2 Pig Receiver 182,676 88.58 

Processing Facilities 

The oil processing facility is designed as a feed-forward operation. The production components are 

progressively separated by flowing through the inlet separator, the low pressure separator, and the 

dehydrator prior to the sales quality oil entering the Alpine crude oil transmission pipeline via the crude-oil 

shipping pumps. 

Most of the natural gas liquid knocked out of the gas in the compressor aerial coolers is re-injected. Some 

natural gas liquids are passed back into the inlet separator. Produced gas, along with formation fluids and 

solids, are removed from the liquid stream in this vessel. 

Control Strategy 

The oil separation operation receives crude oil from the CD1 and satellite drill sites. Through heating and 

gravity segregation, the gas is separated from the liquids. Gas is sent to the gas compression unit for 

compression to re-injection pressures. Oil is separated from water by settling and electrical coalescing. Gas 

condensate, which drops out of the gas in the compression stages, is blended with sales crude or with the 

gas for use in the MI system. 

The primary objective of this process operation is to reduce the maximum water content of the oil to less 

than 0.35 percent by volume to meet final product specifications. 

Water content of the oil prior to metering is measured, and alarms note when the results are outside 

specified ranges. There is no automatic control of water content. Water content is affected by the Alpine 

processing facility oil throughput, the fluids temperature in the production vessels, the effectiveness of the 

low pressure separator, and the effectiveness of the dehydrator. Recycling of off-specification oil to the 

off-spec/slop tank and/or the inlet separator is an operator-initiated action. Due to the off-spec tank’s small 

size, production diversion to the slop oil tank for special treatment is limited. 

Inlet Crude Oil 

Produced fluids from satellite drill sites are transferred via pipeline to the Alpine processing facility and 

mixed with the fluids from CD1. CD1 production wells are located adjacent to the Alpine processing facility, 

and the CD1 well-test separator is located in the Alpine processing facility. The test/start-up separator is 

also used as the source of start-up fuel gas for the plant and for diversion of injection water/auxiliary fuel 

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gas from Kuparuk. Except during the diversion of start-up fuel gas and injection water/auxiliary fuel gas, the 

test/start-up separator fluids are added back into the CD1 and satellite drill site production fluid stream. The 

combined drill site fluid streams enter the Alpine processing facility at 90°F to 110°F. Flow into the Alpine 

processing facility is controlled by the choke valves for each producing well. 

Outlet Oil 

The crude cooler pre-heats the incoming production by cross-exchanging heat and subsequently cooling 

the sales crude oil to a range of 145°F to 150°F before going through a series of trim coolers for additional 

sales crude oil cooling to 115°F to 125°F depending on the time of year. In order to avoid permafrost 

damage at the river crossings, the maximum Alpine processing facility outlet temperature is 180°F. The 

crude contains 2.8 percent wax by weight (116°F wax melt-point and +5°F crude pour-point). 

There are also minimum flow and temperature requirements for the crude oil transmission pipeline to avoid 

coagulation of the oil at low ambient temperatures. Falling oil temperature in the winter could result in highly 

viscous oil, increasing the flowing pressure drop in the pipeline and restricting throughput. Winter crude oil 

temperatures must exceed 116°F in order to minimize pigging, while summer temperatures are limited to 

the maximum specified temperature of 142°F. 

A pressure control valve maintains the crude oil transmission pipeline inlet pressure at or below 2,065 

pounds per square inch gauge (psig). The oil deliveries to Kuparuk CPF-2 normally encounter a delivery 

pressure minimum of 1,400 psig. The pipeline system is limited by the 2,100-psig pressure limit of the 

pipeline between Alpine and Kuparuk. Normal plant outlet oil pressure is 1,870 psig. The maximum 

sulfur/hydrogen sulfide content of the export oil is 50 parts per million by weight. 

The minimum allowable flow rate conditions during -50°F weather for the line to Kuparuk are as follows: 

• Flow rate, 25,300 barrels per day 

• Pipeline Inlet Pressure, 1,480 psig 

• Pipeline Outlet Pressure, 1,435 psig 

• Pipeline Inlet Temperature, 180°F 

• Pipeline Outlet Temperature, 100°F 

Water/Gas Re-injection and Produced Water 

Imported seawater and formation produced water is alternately injected with gas into the formation to 

enhance oil recovery. This process is referred to as miscible water-alternating-gas injection. Seawater 

comes from CPF-2 through the cross-country seawater (utility) pipeline. The maximum design-water 

injection rate is 150,000 barrels of water per day. The maximum wellhead injection pressure is 2,700 psig. 

The processing facilities have been designed to handle and dispose of up to 10,000 barrels of water per 

day of formation produced water via the CD1 Class 1 disposal well. The design disposal well temperature 

and pressure are 214°F and 2,700 psig, respectively. 

Produced gas is dehydrated using a triethylene glycol system to prevent hydrate formation in the surface 

piping and downhole. The design-plant outlet-gas injection pressure is 5,500 psig, with a maximum 

wellhead injection pressure of 4,200 psig. The design-plant outlet-gas injection temperature is 205°F, with 

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maximum wellhead injection temperature of 180°F. The facility is designed with an injection/lift gas design 

rate of 180 million standard cubic feet per day. 

Electrical Power 

During drilling operations, the drilling rig may provide its own power using generators fired on diesel. The 

drilling rig may also receive power directly from the Alpine processing facility. The Alpine processing facility 

generates electricity from fuel gas, using a primary generator with approximately 25 megawatts. This 

primary generator provides the base-load power requirements. Should anything happen to the primary 

generator, a 10-megawatt back-up gas fueled generator is available at the facility. 

Two twin 5.5 megawatt gas and diesel fired turbine generators provide emergency power at CD1. These 

twin solar turbine power plants can also provide primary power and are often run in combination with the 

larger primary units. Uninterruptible power supply systems provide power to the control systems and 

switchgear. 

Electrical power for satellite drill sites is supplied by CD1 via insulated power cables or is generated on-site 

by generator. Power cables to satellite drill sites are either suspended under or along VSM-supported 

pipelines or buried in gravel roads. Emergency power generators also may be maintained at satellite drill 

sites. 

Lighting of Facilities 

The lighting for Alpine facilities is designed to direct light to the local area. Lighting is required for safe 

operations and security while minimizing misdirected lighting glare to the surrounding landscape. 

Instrumentation and Controls 

The facilities in the Alpine Development Area require a control system for: 

• Process monitoring and control, 

• ESD functions, 

• Pipeline leak detection, 

• Compressor surge control, 

• Fire and gas detection, and 

• Vibration monitoring. 

The control system is: 

• A reliable, standard industrially-proven system; 

• Capable of future expansion; and 

• Reduces Operation’s manpower requirements. 

Control loops in the facility are electronic. The basic process control and safety is an integrated system 

used to perform process analog control and monitoring, alarming, and discreet logic function, such as 

normal operational equipment shutdowns/starts and stops. It is composed of easily expandable hardware 

and software to meet future COPA needs. It exhibits industry-proven reliability. 

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Remote Electrical-Instrument Module 

To facilitate the modularized/skid-mounted process equipment approach, input/output modules, 

terminations, and electrical equipment are mounted on each skid in a modular building called a remote 

electrical-instrument module (REIM). Devices on the skid associated with the electrical and control systems 

are wired in the fabricator’s shop to the REIM electrical/module input/output. A data communication highway 

cable runs between the REIMs and the control room. Control system interconnects and site checkout 

requirements are reduced. The REIM modules require controlled environmental conditions 

(heating/cooling), depending on their location in the plant. Processors for control of the input/output modules 

are redundant and are located in the control room/auxiliary room or remotely with the input/output, 

depending on security of control and economic considerations. 

REIM modules are associated with the larger skids and vendor packages. Where smaller modules are 

involved, the wiring for these is field-run on site to the closest applicable REIM unit. 

Emergency Shutdowns 

A stand-alone plant ESD safeguard system, hereafter termed the safety instrument system (SIS), is used 

for gas ESD functions affecting personnel or plant safety. This system uses redundant “hot standby” 

processors and remote input/output modules in the REIMs. Shutdown signals to the SIS are from analog 

transmitters wherever possible, with the exception that packaged equipment uses the vendor’s standard 

(switches or transmitters) when necessary. 

The SIS is integrated with the plant control system, not just interfaced to it. This means that the SIS 

controller is a node or drop on the system highway and able to communicate directly with other nodes 

performing basic process control functions and with the operator interface terminals. Advantages of this 

system are that communication between devices is not dependent on an intermediate device, less 

programming is required, and the system is therefore more secure and reliable. 

Dedicated shutdown buttons are provided in the control room console and hardwired directly to the SIS 

controllers for each of the levels of shutdown, except the CD1 and CD2 SIS. CD1 and CD2 control room 

ESD buttons are wired to the oil SIS. Communication to the CD1 and CD2 control processors occurs via 

the redundant M-NET communication highway and redundant communication processor racks at CD1 and 

CD2. A watchdog logic circuit monitors the communication module health and causes a CD1 or CD2 ESD 

to occur if both modules fail. 

Dedicated shutdown buttons are also provided inside and outside doorways for each of the applicable 

process modules and REIM buildings. Remote/local ESDs, blowdown emergency shutdowns, and facility 

shutdowns are all considered part of the SIS. 

Operation Requirements 

The main central facility is staffed by operating personnel on a 24-hour basis, with the minimum staff 

complement as follows: 

• 1 control room operator (day and night), 

• 1 to 4 central facility/drill pad operators (day and night), 

• 1 shift supervisor (days), 

• 1 electrical/instrument technician (days), 

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• 1 millwright (days), and 

• 1 mechanic (days). 

Satellite drill sites may not be staffed by operating personnel on a 24-hour basis; however, these sites are 

visited regularly, during routine operational rounds. Unmanned sites are visually inspected at least once 

per month. Satellite drill sites are equipped with automated remote well monitoring systems that are 

managed in the Operator Control Room (see Section 2.5.1). 

Control System Architecture 

The control system architecture is: 

• Distributed: Operator interfaces in one building, and process controllers/input-output modules are 

distributed throughout the plant. This reduces field wiring by permitting shorter runs from module 

devices to input/output devices located on the ends of skids. Only data highway runs are required 

to control the building, enabling more work to be completed at module shops, including partial 

testing of system components. 

• Multi-drop Signals: Operator interface/process controllers are in the same or adjacent rooms, and 

input/output modules are either centralized or distributed, but quantities are significantly reduced 

due to use of serially-connected field devices. Multi-drop signals are used for monitoring functions 

only, as a break in the wire of any device in the loop will make the information from all devices 

unavailable. The advantage of this system approach is the significant reduction of field wiring. Use 

is limited to drill site manifold buildings and selected central facility loops. 

Facility Human Machine Interface 

The facility utilizes a Supervisory Control and Data Acquisition (SCADA) software system as the basis for 

the human machine interface. The process control system, ESD safety system, fire system, and various 

equipment packages and their control systems interface with the SCADA servers. The operator interface 

terminals also derive their data from the SCADA servers. 

The SCADA system communicates with most devices using an Ethernet highway with TCP/IP protocol and 

provides operator information to the REIM displays and to Kuparuk over the fiber-optic highway. Production 

reports, alarming, and business administration data are derived from the SCADA system. 

Operator Station Interfaces 

Operator station interfaces, also called operator interface terminals, are provided in the Alpine processing 

facility control room, in Modules C3, A3 REIMS, E3, and at CD1 and CD2. Operator-initiated control 

changes for the entire facility are performed in the Alpine processing facility control room. The operator 

interface terminal displays at the REIMs and drill sites are provided for the convenience of maintenance 

and operations staff for monitoring functions only, due to the geographical distances from the Alpine 

processing facility. The operator interface terminal systems are workstation computer architecture with color 

graphics, rather than console-style, and are equipped with printers for alarm logs, reports, etc. in the Alpine 

processing facility. 

Pipeline Leak Detection 

Pipeline leak detection is discussed in Sections 2.1.7, 2.1.8, 2.5.2 and 2.5.3. 

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3.2 RECEIVING ENVIRONMENT [18 AAC 75.425(e)(3)(B)] 

The receiving environment for Alpine consists of the area surrounding the man-made gravel pads and roads 

and pipelines situated in the Colville River delta and Tinmiaqsiugvik River and Fish Creek drainage area. 

Large spills occurring at Alpine, particularly well blowouts and pipeline ruptures, are unlikely but have the 

potential of reaching tundra, open water, and/or ice. 

Nuiqsut 

The Native village of Nuiqsut is located near the main channel of the Colville River, approximately 8 miles 

south of the Alpine Development Area. The population measured in the 2009 consensus was 379 residents. 

Nuiqsut provides modern amenities such as governance, infrastructure, schools, and an airport. The 

proximity of Nuiqsut would require close monitoring of meteorological conditions and communication and 

consultation with Nuiqsut representatives concerning how best to mitigate potential health effects on the 

community. In addition, subsistence hunting and gathering is viewed as an essential part of the culture and 

community and requires protection of the natural environment and its subsistence resources. 

Vegetation 

The vegetation of the Alpine area reflects the severe climatic conditions of the Arctic Coastal Plain and the 

dynamic stream channel configurations of the Alpine area. On the delta, abandoned and active stream 

channels have exposed extensive mud flats. Along the coast, mud flats, sand beaches, and slumping peat 

bluffs add to the diversity of landforms. Inland, a more usual contingent of landforms is found, including 

flooded tundra, high- and low-centered polygons, and deep and shallow open lakes. Although the dominant 

species of vegetation in the area are associated with water-saturated soils, plants characteristic of dry areas 

are also present. 

Wetlands 

The main portion of the Colville River Unit includes the Colville River delta, Harrison Bay, and its 

surrounding brackish and freshwater wetlands. The area within the Greater Mooses Tooth Unit includes 

drainage areas of the Tinmiaqsiugvik River and Fish Creek, and thaw lakes, marshes, and polygonpatterned ground. These wetlands are composed of a variety of habitat types that support a diverse bird 

community during the summer. Shore birds and waterfowl typically are most abundant. Several mammals 

also inhabit the area, with caribou and arctic fox most prevalent. 

Soils and Landforms 

The soils of the coastal lowlands are generally marine, glacial, or alluvial. A layer of unconsolidated silt, 

sand, and gravel, as much as 200 feet thick, covers the Arctic Coastal Plain, the largest coastal lowland 

deposit in Alaska. Permafrost is continuous throughout the plain and usually extends through the layer of 

unconsolidated sediments into bedrock. Unfrozen areas exist at perennial springs and beneath major 

streams. The Colville River has a thawed area beneath its bed several hundred feet thick that may perforate 

the permafrost in places. This does not occur at shallower, braided streams. Poor drainage due to shallow 

permafrost and fine, low-permeability soils contribute to numerous thaw lakes typical of this area. 

The Alpine area is characterized by low relief with mud flats, sand dunes, and ice-rich tundra bluffs along 

the coastline. From sea level, the land slopes upward to a maximum elevation of 30 feet near the runway 

at CD1. Microrelief in the area is provided by polygon rims, pingos, frost boils, and sand dunes. 

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Hydrology 

The hydrologic environment is characterized by large flows of water during the snowmelt runoff period, 

reduced flows during the summer, and little or no flow in the winter. Groundwater resources are limited by 

the existence of permafrost. Annual precipitation is light, averaging less than 7 inches per year, much of 

this falling during the summer and fall. Despite the prevalence of streams, lakes, and wetlands, the area is 

characterized as semi-arid due to its low annual precipitation. 

Ponds and lakes are the most prevalent water bodies on the Colville River delta. Most of the ponds are 

located within low-centered ice-wedge polygons. Many of the ponds and lakes are shallow and freeze to 

the bottom in the winter. They are formed from thawing of ice-rich sediments during a “thaw-lake cycle” that 

includes thawing, expansion, drainage, ice aggradations, and eventual thawing again. Lakes of over 10 

acres are numerous, covering 16 percent of the delta surface. These lakes are generally 11 to 15 feet deep 

but can be as deep as 28 feet. Because they have greater masses of ice and water to warm and melt at 

break-up, these lakes remain ice-covered into early July, much later than the smaller lakes. 

The Colville River is the largest freshwater surface resource in the development area, with a length of 370 

miles and a drainage area of 20,920 square miles. Peak runoff and corresponding peak sediment load 

occur from late May through early July and are attributed to snowmelt and rainfall. A second peak, due 

primarily to rainfall, normally occurs in July or August. Summer flows are sustained by gradual snowmelt in 

the mountains. Winter flows decrease to very low values (0-1,000 cubic feet per second [cfs]). 

The Colville River enters the delta north of the mouth of the Itkillik River, approximately 4 miles southeast 

of Nuiqsut. The delta is more than 25 miles long and covers about 250 square miles. Most of the water 

reaching the delta is carried to the ocean through two main channels: the East Channel and the Nigliq 

Channel. Approximately 80 percent of the discharge at the head of the delta flows in the East Channel and 

its distributaries, while the remaining 20 percent flows in the Nigliq Channel. Several distributaries branch 

from the East Channel, including the Sakoonang and Tamayayak channels. In general, the channels of the 

Colville River and its distributaries are broad and relatively shallow. 

Spring break-up on the Colville River generally occurs before the break-up of coastal plain streams, such 

as the Kachemach and Miluveach rivers. The median date of peak break-up discharge is June 2 and the 

peak break-up discharge at the head of the delta averages 264,000 cfs (Ray and Aldrich, 1996). Typical 

summer flows at the head of the Colville River delta range between 20,000 and 80,000 cfs. 

The Kachemach and Miluveach rivers, which drain the Arctic Coastal Plain east of the lower Colville River, 

are completely underlain by permafrost. The Kachemach River is approximately 35 miles long with a 

drainage area of 213 square miles. The Miluveach River is approximately 40 miles long and has a drainage 

area of 184 square miles. Both rivers flow into the East Channel of the Colville River. 

The Fish Creek drainage area consists of lakes and three significant tributary basins: Inigok Creek, Judy 

Creek, and Tinmiaqsiugvik (Ublutuoch) River. During flood stage in the lower Fish Creek area, one main 

(east) channel and a minor (west) channel are main pathways to Harrison Bay. Streams in the Fish Creek 

area have relatively low gradients and highly sinuous channels, though portions of the Tinmiaqsiugvik River 

are entrenched, which creates a narrower floodplain and steeper banks (BLM, 2004). Spring break-up 

occurs in the Tinmiaqsiugvik River earlier than Fish or Judy Creeks. Measurements taken near the bridge 

and pipeline crossing show break-up occurs during the first week in June, with peak stages noted between 

June 5 and 8 (BLM, 2004). Flooding and high-water conveyance along the Tinmiaqsiugvik River at breakAlpine Field, Satellites, and Pipelines ODPCP 3-11 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

up occurs within the lower west floodplain during periods of high flow and/or when ice occurs in the main 

channel; the east and upper west floodplains are also inundated but convey little flow (BLM, 2004). 

Nigliq Channel 

The topography of the land immediately west of the Nigliq Channel, just outside the Colville River delta, 

slopes toward the channel. The gravel access road to CD-5 could be used for spill response access and 

staging, and containment and control points could be established at road-stream crossings. ACS Technical 

Manual, Volume 1, Tactics C-2 and C-3 describe culvert blocking techniques that could be employed to 

prevent oil from reaching the other side of the gravel road if a spill occurs from in-field piping. Additionally, 

boom is seasonally pre-staged at the Nigliq Channel as a preventative measure. 

Oceanography 

The general surface circulation of the Beaufort Sea is dominated by a clockwise gyre that produces offshore 

currents from the west. The average set is 1 to 2 nautical miles per day. In early 1960, Ice Island T-3 drifted 

at an average rate of 3 nautical miles per day in the southern Beaufort Sea. These prevailing currents move 

both water and ice shoreward throughout most of the year. In contrast, nearshore surface currents are 

variable and influenced by local winds. They might set in either an easterly or westerly direction, and are 

generally weak and unpredictable. 

Seasonal freezing and melting and the freshwater input from large rivers are the major influences on the 

surface water characteristics of the Beaufort Sea. Salinity varies both geographically and seasonally, 

ranging from 29 to 36 parts per thousand. Temperature of seawater ranges from -1 degrees Celsius (°C) 

to -2.8°C under ice in winter, to just above freezing in summer. 

Tides are small, about 1 foot in extreme. Associated tidal currents also are weak. All tidal phenomena are 

altered by ice coverage, especially shore-fast ice, with the time of the tide reduced and the range decreased. 

Nevertheless, Beaufort Sea tides have been known to form cracks in the shore-fast ice in mid- to late winter 

and to free seasonal shoreline ice. 

Surface waves on the Beaufort Sea are restricted to summer periods when open water exists. During these 

periods, swells of 6 to 7 feet have been observed along the coast when the ice pack was far out to sea. 

Large waves are uncommon, probably because of the restricted area of fetch when open water exists. 

Ice is present in the Beaufort Sea at least 9 or 10 months of the year and is an important factor in 

determining the dynamic events associated with the shoreline and coastal waters. Embayments, lagoons, 

and shore fringes are normally covered with fast ice during the long winter, as is the shoreline. As freezing 

begins in the fall, new ice forms along the coast and slowly builds seaward, often freezing to the bottom. 

This land-fast seasonal ice typically extends to the 5- to 10-fathom depth contour and can reach a thickness 

of 6 feet. 

Farther out to sea lays the pack ice, consisting predominantly of multiyear flows from 6 to 12 feet thick. In 

summer, the pack ice is surrounded by open water and in winter, by first-year ice. Pack ice is constantly in 

motion, moving generally under the influence of the Arctic gyre. Ice islands such as T-3 are infrequently 

found within the pack ice. These islands originate from the Ellesmere Ice Shelf and can be quite large. 

During freeze-up, a shear zone of ice often produces open-water leads that freeze and form new seasonal 

ice, which in turn can be deformed under pressure. Pressure ridges and ice hummocks are often created 

in this shear zone. 

Alpine Field, Satellites, and Pipelines ODPCP 3-12 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

In summer, the land-fast ice melts and the pack ice retreats northward, leaving open water along the coast. 

However, during periods of northerly winds, the polar pack can be blown against the shoreline east of Point 

Barrow. The extent of ice cover varies greatly from year to year, with its distribution a function of 

meteorological conditions, currents, tides, and the topography of the sea floor. 

The coastal zone of the operating area includes Harrison Bay and the growing delta of the Colville River. 

Offshore lies Thetis Island and numerous islands associated with the river delta. The shallow depth of 

Harrison Bay protects it from the dynamic ice activity that occasionally occurs along the coastline. 

Coastal erosion is insignificant during the winter when the seas are frozen. However, during the summer, 

mechanical erosion of thawed beaches and thermal erosion of coastal banks causes the shoreline to recede 

inland at rates of as much as 30 feet per year. Also, severe storms with significant waves can bring about 

changes in local topography through erosion and deposition. Sediments enter the coastal waters of the 

Beaufort Sea, as a result of river flow during the summer and from the coastal erosion processes discussed 

earlier. This results in coastal-shelf bottom materials high in silts and sands and with lesser amounts of 

gravel. 

Ecology 

The Alpine area contains a diverse array of habitats used by wildlife for feeding, breeding, and shelter. The 

habitats also provide other important ecological functions. Wetlands are particularly important because of 

their influence on surface and ground water hydrology, water quality, bird nesting and feeding, and fish 

production. Estuarine wetlands produce nutrients that are exported to marine and river systems where they 

provide for a wide variety of plants and animals. River channels serve as transportation corridors for 

hunting, fishing, and recreation. The habitat types in the project area constitute a complex mosaic of 

biological communities that support a rich diversity of plant and animal resources. 

The vegetation at the Alpine area reflects the climatic and topographic features of the area. Many shallow 

ponds have formed in the low-lying areas, while peat ridges and polygonal features related to frost action 

and ice wedges provide slightly higher, better-drained soils. Few woody plants are present, but those that 

do are found on drier sites where the microrelief raises them above the standing-water table. The most 

abundant and widespread habitat classes in the project area are wet and moist tundra. The most prominent 

habitat types in these classes are Wet Sedge-Willow Meadow on the delta and Moist Sedge-Shrub Meadow 

and Moist Tussock Tundra in the transportation corridor. Other prominent habitat classes on the delta 

include estuarine, river/stream, barrens, and lake/pond. 

The Colville River delta is regionally important to birds and mammals. The Colville River delta is the largest 

and most complex river delta on the Arctic Coastal Plain of Alaska. It provides high-quality breeding habitats 

for water birds such as the spectacled eider, brant, tundra swan, and yellow-billed loon, as well as other 

water birds, shorebirds, songbirds, and predatory birds. The delta supports 29 species of water birds 

including 16 species that breed there. The Colville River delta provides some of the earliest open-water and 

snow-free areas for migrating birds during spring. The extensive salt marshes and mudflats on the delta 

are used by geese and shorebirds as staging areas during fall migration and by many other birds during 

spring and summer. Few species inhabit the area year-round. 

The U.S. Fish and Wildlife Service (USFWS) has listed the spectacled eider as a threatened species 

throughout its range since 1993. Biologists have reported nests and broods in several areas on the Colville 

River delta. Most nests lie outside of areas that might be affected by spills. Guidelines for activities within 

the breeding range of spectacled eiders are as follows: 

Alpine Field, Satellites, and Pipelines ODPCP 3-13 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

• Assess whether spectacled eiders are likely to use the project area for nesting or brood-rearing. 

Contact the USFWS for assistance. For projects conducted during the breeding season, a USFWSapproved survey for spectacled eiders should be conducted in the year of construction, prior to 

initiation of activities. 

• If spectacled eider nests are in the project area, the following activities may require special permits 

within 200 meters of nest sites: 

− Vehicle and foot traffic, except on existing roads. 

− Construction of permanent facilities, placement of fill, or alteration of habitat. 

− Introduction of high noise levels, including but not limited to noise from airports, blasting, and 

compressor stations. 

• Eiders are present on breeding grounds from mid-May through mid-September, but activities at any 

time of year may affect them through habitat modification. 

The delta is also used seasonally by caribou for foraging and insect relief habitat and by foxes and polar 

bears for denning habitat. Many of these wildlife resources are hunted by local residents as an essential 

element of their subsistence lifestyle. 

The marine waters of the Beaufort Sea, off the Colville River delta, provide habitat for bowhead and beluga 

whales; ringed, spotted, hooded, and bearded seals; and walruses. The beluga whale is the most abundant 

in northern Alaska and is an important subsistence resource for coastal residents. The ringed seal is a yearround resident and is the most abundant seal species in the Beaufort Sea. 

The fish resource is composed of three major groups of fish; marine, anadromous, and freshwater. 

Freshwater species such as arctic grayling, burbot, and nine-spine stickleback typically reside within the 

confines of fresh or slightly brackish water and are generally restricted to the rivers and small streams that 

flow into the Beaufort Sea. 

Anadromous species (arctic char, chum salmon, least cisco, arctic cisco, broad whitefish, and humpback 

whitefish) over-winter and spawn in the fresh water of larger rivers such as the Sagavanirktok and Colville 

rivers (Morrow, 1980), but tend to spend the summer in nearshore marine waters, often undergoing 

extensive coastal migrations. Pink salmon that spawn in the Colville River are also present in the nearshore 

coastal waters during the juvenile out-migration and adult return migration. Spawning of pink and chum 

salmon occurs in very low numbers in the Colville River and associated tributaries. The National Marine 

Fisheries Act recognizes waters cataloged under AS 16.05.870 (Waters Important for the Spawning, 

Rearing, or Migration of Anadromous Fishes) as Essential Fish Habitat. Fish Creek, Judy Creek, the 

Tinmiaqsiugvik River, and the Colville River are considered Essential Fish Habitat for chum and pink salmon 

(BLM, 2004). 

Marine species such as arctic cod, four-horn sculpin, and snailfish complete their entire life cycle within the 

marine and coastal waters of the Beaufort Sea. Occasionally, a euryhaline species (tolerant of wide salinity 

ranges), such as four-horn sculpin, might intrude a few miles up into a stream or river discharging into the 

Beaufort Sea, but all key stages within the life cycle (such as spawning, nursery, and over-wintering 

functions) occur within the marine and nearshore brackish water environments. 

Alpine Field, Satellites, and Pipelines ODPCP 3-14 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

3.2.1 Potential Routes of Discharge Travel to Open Water [18 AAC 75.425(e)(3)(B)(i)] 

The ACS Technical Manual Map Atlas Sheets 1 through 29, 53, and 112 through 137 contain potential 

containment sites and features including sensitive receiving environments and information on potential 

routes of discharge. 

The Alpine area encompasses portions of the Colville River delta, Fish Creek basin (including 

Tinmiaqsiugvik River), and surrounding terrestrial environments. The marine environment adjacent to the 

delta could also be affected by spills from the development. The Colville is the largest river in the United 

States’ portion of the North Slope. This river has a major influence on local marine and terrestrial 

environments. At the mouth, the river forms a delta containing two major channels and several minor 

distributaries. 

A spill on an Alpine facility pad will remain on the pad, unless the spill is near the pad edge or exceeds the 

retention capacity of the pad. Fuel transfers are not allowed near pad edges in order to mitigate this risk. 

A spill from the cross-country transportation pipelines or the in-field flowlines will reach the tundra 

environment and has the potential to reach fresh-water environments. A spill from the cross-country 

transportation pipelines will not reach the Colville River, because of the vertical loops and the HDD-buried 

crossing. A spill from the cross-country transportation pipelines could reach other bodies of freshwater 

including the Kachemach River and the Miluveach River. A spill from in-field flowlines has the potential to 

reach open waters of nearby freshwater lakes, river channels, and the open marine waters of Harrison Bay. 

A spill from in-field flowlines over the Nigliq Channel would reach the channel and has the potential to reach 

Harrison Bay if not swiftly contained. However, a spill from the in-field flowlines is not likely to reach the 

main channel of the Colville River. A spill from in-field flowlines over the Tinmiaqsiugvik River may reach 

channels of Fish Creek, particularly during periods of flooding. The relatively low flow and highly sinuous 

nature of streams in the Fish Creek basin may preclude a spill into the Tinmiaqsiugvik River from reaching 

Harrison Bay. 

In the unlikely event of an oil well blowout at Alpine, there is the potential for oil to reach open waters of 

nearby freshwater lakes, channels, and the marine waters of Harrison Bay. An oil well blowout is not likely 

to directly reach the Colville River; however, there is the potential for oil from the Sakoonang and 

Tamayayak channels to flow into the main channel of the Colville River. An oil well blowout from drill sites 

located outside the Colville River delta would impact nearby lakes and streams; however, it is unlikely the 

oil would fallout directly onto Fish Creek, the Tinmiaqsiugvik River, or Crea Creek due to the distance from 

existing drill sites. 

Estimated volumes of oil that could reach open water are discussed below and are based on ACS Technical 

Manual Tactics T-6 and T-7. 

3.2.2 Estimate of Response Planning Standard Volume to Reach Open Water [18 AAC 

75.425(e)(3)(B)(ii)] 

The following are descriptions of the worst-case discharge events that have the potential to occur at Alpine. 

These estimated percentages are based on the applicable response planning standard (RPS) volume 

calculations in Part 5. 

Alpine Field, Satellites, and Pipelines ODPCP 3-15 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

Storage Tank Rupture 

The receiving environment for a storage tank rupture is a gravel pad, lined secondary containment basin, 

tundra, and possibly the shoreline of the Sakoonang Channel. The adjusted RPS volume for the oil storage 

tank at CD1 is 1,320 barrels. No oil reaches open water initially; however, a conservative estimate of 5 

percent (66 barrels) of the volume spilled may spread to the shoreline of the Sakoonang Channel and enter 

its waters. 

Well Blowout in Summer 

The receiving environment for a well blowout in summer is open water, gravel pad, and tundra. The RPS 

volume for a blowout over 15 days is 150,000 barrels, of which, approximately 4,300 barrels reaches open 

water of nearby lakes and small streams. 

Well Blowout in Winter 

The receiving environment for a well blowout in winter is frozen lake and stream surfaces and snowcovered, frozen tundra. The adjusted RPS volume for a blowout over 15 days is 150,000 barrels. No oil 

enters open water. 

Crude Oil Transmission Pipeline Spill to Miluveach River in Summer 

The receiving environment for a crude oil transmission pipeline spill in summer is the Miluveach River. The 

adjusted RPS volume for a spill from the Alpine crude oil transmission line is 2,830 barrels, all of which 

enters open water. 

Alpine Field, Satellites, and Pipelines ODPCP 3-16 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

3.3 COMMAND SYSTEM [18 AAC 75.425(e)(3)(C)] 

Oil spill response will use an ICS that is compatible with the ARRT Alaska Federal/State Preparedness 

Plan for Response to Oil and Hazardous Substance Discharges / Releases (Unified Plan). The ICS 

organizational structure is based on the National Incident Management System and provides clear definition 

of roles and lines of command, together with the flexibility for expansion or contraction of the organization. 

The basic ICS organizational structure is shown in Figure 3-1. This structure is designed to expand 

according to the needs of the incident. For Tier I incidents, the SRT will fill the basic ICS positions. For Tier 

II/III incidents, an expanded ICS structure would be staffed by the COPA Incident Management Team (IMT). 

The COPA IMT is comprised of North Slope and Anchorage staff employees and contractors. COPA IMT 

staffing changes periodically, as the workforce changes; the COPA Alaska Response Teams Carry-All 

maintains the most up-to-date listing of IMT (including QI) member name, location, telephone number, and 

functional role within the ICS. A comprehensive description of the COPA IMT structure and roles and 

responsibilities associated with various positions is provided in the ConocoPhillips Incident Management 

Handbook (IMH). Copies of the Carry-All and IMH are made available to COPA IMT members in electronic 

form on the COPA intranet and in paper form at all COPA Emergency Operations Center locations. 

In most Tier I incidents, the SRT can effectively control the incident. The Drilling Supervisor fulfills the role 

of initial On-Scene Commander. Additional resources are activated under the ICS, as needed, to fill support 

roles. 

Tier II/III spill response is initiated by the On-Scene Commander and the. Alpine IMT is activated. The 

Alpine IMT will take initial Command, working from the Alpine Emergency Operations Center located at 

Alpine CD1 Pad. If the response exceeds capabilities of the Alpine IMT, Command of the response may 

transition to the Kuparuk IMT who will operate from the Kuparuk Emergency Operations Center located at 

Kuparuk Operations Center. Once the response level is ascertained, the appropriate IMT begins to provide 

support to the field responders and to coordinate the collection and distribution of information. Additional 

support, such as in technical areas regarding source control and environmental, may be provided by the 

Anchorage IMT who will operate from the Anchorage Emergency Operations Center located in COPA 

Anchorage Office Complex. 

ACS will be activated to stand by for spills until an assessment is performed. Once the assessment is 

complete, ACS is either released or mobilized. ACS provides additional manpower and equipment 

resources from Deadhorse to assist in spill containment and recovery. North Slope operators coordinate 

with ACS to ensure that a reserve of trained manpower is available for an extended spill response. 

The Qualified individual (QI) is the Incident Commander who is notified during call out of the IMT. During 

Tier II events, ACS North Slope resources and, if needed, Mutual Aid resources, are mobilized and 

deployed, as needed. During Tier III events, the QI acts as the company representative for commitment of 

out of region resources. 

Not every incident will require formation of the Unified Command. For significant oil spills, there may be OnScene Coordinators from the federal, state, and local governments, and COPA, as well as the responsible 

party, if other than COPA. These individuals will become part of the Unified Command, representing their 

organization as the Federal On-Scene Coordinator (FOSC), State On-Scene Coordinator (SOSC), 

Responsible Party (RP), and Local On-Scene Coordinator (LOSC). The North Slope Borough is the LOSC. 

Under provisions of the National Contingency Plan, EPA designates the FOSC for inland zone oil 

discharges and hazardous substance releases. For incidents involving multiple jurisdictional federal 

Alpine Field, Satellites, and Pipelines ODPCP 3-17 February 2018, Rev. 0 
 

 

agencies, it is the responsibility of those federal agencies to determine appropriate ICS roles and 

responsibilities under the Unified Command. 

Primary responsibilities of the Unified Command are as follows: 

• Determine and establish overall incident objective and response priorities, 

• Review and approve tactical plans and strategies developed to address objectives and priorities, 

• Ensure full integration of response resources, and 

• Resolve conflicts. 

The responsible party will be the Incident Commander in the Unified Command structure unless the State 

or Federal On-Scene Coordinator determines the response is inadequate. At that time, either the State or 

Federal On-Scene Coordinator will assume the Incident Commander's duties. 

The QI / Incident Commander determines if needs for additional IMT personnel or resources requires 

activation of the ConocoPhillips Global Incident Management Assist Team (GIMAT). The GIMAT is 

comprised of personnel and resources from ConocoPhillips’ worldwide operating business units, 

departments, or subsidiaries. The GIMAT may be called upon to augment or fill positions on the IMT. 

Activation of the Global IMAT is initiated by calling the ConocoPhillips Crisis Hotline at 1-800-342-5119. 

Alpine Field, Satellites, and Pipelines ODPCP 3-18 February 2018, Rev. 0 
FIGURE 3-1: INCIDENT COMMAND SYSTEM STRUCTURE 

Qualified Individual 

/ Incident 

Commander Public Information 

Officer 

Liaison Officer 

Safety Officer 

Deputy Incident 

Commander 

Information / 

Security Officer 

Legal Officer 

Operations Section 

Chief 

Planning Section 

Chief 

Logistics Section 

Chief 

Finance Section 

Chief 

Tactical Response 

Organization 

(SRT) 

Situation 

Unit 

Resource 

Unit 

Documentation 

Unit 

Environmental 

Unit 

Technical 

Specialists 

Supply Unit 

Facilities Unit 

Ground Support 

Unit 

Communications 

Unit 

Security 

Medical 

Specialist 

Claims / 

Insurance Unit 

Cost Unit 

Procurement 

Unit Staging Area 

Air Operations 

Source Control 

Business 

Resumption 

 
 

 

 

 

FIGURE 3-2: IMT FUNCTIONS AND RESPONSIBILITIES CHECKLISTS 

QUALIFIED INDIVIDUAL / INCIDENT COMMANDER 

The Incident Commander (IC) is the responsible party’s (RP’s) representative in Unified Command (UC), 

as applicable, and leads the RP’s response effort. Based on the size and complexity of the incident, the IC 

will work with the United States Coast Guard and state agencies to establish a UC. The IC/UC works with 

the federal and state On-Scene Coordinators to make decisions including those involving the response 

objectives/priorities, safety stand downs, expansion/contraction of the response team and the approval of 

the Incident Action Plan (IAP). 

 Serve as point of contact for RP personnel in initial response. 

 Review general ICS procedures and common responsibilities. 

 Ensure adequate safety measures are in place. 

 Obtain a briefing from the prior IC (201 Briefing), if applicable. 

 Determine incident objectives and general direction for managing the incident. 

 Ensure regulatory notifications have been completed. 

 Establish an ICP. 

 Establish appropriate communications with FOSC, SOSC, and other federal and state officials, 

as appropriate. 

 Notify and activate oil spill removal organizations, as appropriate. 

 Brief Command and general staff. 

 Establish an appropriate organization. 

 Ensure planning meetings are scheduled as required. 

 Approve and authorize the implementation of an IAP. 

 Coordinate activity for all Command and general staff. 

 Coordinate with key people and officials. 

 Approve requests for additional resources or for the release of resources. 

 Keep agency administrator informed of incident status. 

 Authorize release of information to the news media. 

 Ensure ICS 209 is completed and forwarded to appropriate higher authority. 

 Order the demobilization of the incident when appropriate. 

For further information regarding ICS position roles and responsibilities, consult ConocoPhillips’ Incident 

Management Handbook. 

Alpine Field, Satellites, and Pipelines ODPCP 3-20 February 2018, Rev. 0 
 

 

 

 

 

SAFETY OFFICER 

During a response, the Safety Officer and safety team(s) ensure the safety of both responders and the 

general public. The Safety Officer and safety team(s) are tasked with completing safety ICS forms and 

plans for the response, which are approved by the Safety Officer before submitting them to IC/UC. 

 Become familiar with all applicable national, state, and local health and safety regulations. 

 Participate in tactics and planning meetings, and other meetings and briefings as required. 

 Develop the Site Safety Plan and publish Site Safety Plan summary (ICS Forms 201-5/208) as 

required. 

 Identify hazardous situations associated with the incident. 

 Review the IAP for safety implications. 

 Provide safety advice in the IAP for assigned responders via the safety message on each ICS 

204. 

 Exercise emergency authority to stop and prevent unsafe acts. 

 Investigate accidents that have occurred within the incident area. 

 Review and approve the Medical Plan (ICS Form 206). 

 Develop the Safety Analysis Worksheet (ICS 215A) as required. 

 Ensure all required agency forms, reports, and documents are completion prior to demobilization. 

 Brief Command on safety issues and concerns. 

 Maintain individual log (ICS 214a). 

For further information regarding ICS position roles and responsibilities, consult ConocoPhillips’ Incident 

Management Handbook. 

Alpine Field, Satellites, and Pipelines ODPCP 3-21 February 2018, Rev. 0 
 

 

 

 

 

 

OPERATIONS SECTION CHIEF 

The Operations Section Chief, a member of the General staff, is responsible for the management of all 

operations directly applicable to the primary objectives of the response. The Operations Section Chief is 

the leader of the Operations Section, which is directed by IC/UC. 

 Obtain briefing from IC. 

 Request sufficient section supervisory staffing for both operations and planning activities. 

 Identify kind and number of resources required to support selected strategies. 

 Subdivide work areas into manageable units. 

 Develop work assignments and allocate tactical resources based on strategy requirements. 

 Prepare ICS 234 work analysis matrix with Planning Section Chief to ensure strategies and 

tactics and task are in line with ICS 202 response objectives to develop ICS 215. 

 Participate in the planning process and the development of the tactical portions (ICS 204 and 

ICS 220) of the IAP. 

 Assist with development of long-range strategic, contingency, and demobilization plans. 

 Supervise Operations Section personnel. 

 Monitor need for and request additional resources to support operations as necessary. 

 Evaluate and monitor current situation for use in next operational period planning. 

 Interact and coordinate with Command on achievements, issues, problems, significant changes, 

special activities, evens, and occurrences. 

 Troubleshoot operational problems with other IMT members. 

 Supervise and adjust operations organization and tactics as necessary. 

 Participate in operational briefings to IMT members as well as briefings to media and visiting 

dignitaries. 

 Develop recommended list of section resources to be demobilized, and initiate recommendation 

for release when appropriate. 

 Receive and implement applicable portions of the incident Demobilization Plan. 

For further information regarding ICS position roles and responsibilities, consult ConocoPhillips’ Incident 

Management Handbook. 

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PLANNING SECTION CHIEF 

The Planning Section collects, evaluates, disseminates, and uses incident information for planning 

operations for the next operating period and for strategic planning (long range). It maintains assigned 

resource status, and plans for future response activities, prepares the IAP, documents the incident 

response, tracks incident resources, coordinates Environmental Unit activities, oversees the display of the 

Situation Status Board produced by the Situation Unit, and demobilizes resources through the 

Demobilization Unit as necessary. 

 Collect, process, and display incident information. 

 Supervise preparation of the IAP. 

 Facilitate planning meetings and briefings. 

 Assign personnel already on site to ICS organizational positions as appropriate. 

 Establish information requirements and reporting schedules for Planning Section units (e.g., 

Resources, Situation). 

 Determine the need for any specialized resources in support of the incident. 

 Establish special information collection activities as necessary (e.g., weather, environmental, 

toxics, etc.). 

 Assemble information on alternative strategies. 

 Keep IMT apprised of any significant changes in incident status. 

 Compile and display incident status information. 

 Oversee preparation and implementation of the incident Demobilization Plan. 

 Incorporate plans (e.g., traffic, medical, communications, site safety) in the IAP. 

 Develop other incident-supporting plans (e.g., salvage, transition, security). 

 Assist Operations with development of the ICS 234 work analysis matrix. 

 Maintain Unit Log (ICS 214). 

For further information regarding ICS position roles and responsibilities, consult ConocoPhillips’ Incident 

Management Handbook. 

Alpine Field, Satellites, and Pipelines ODPCP 3-23 February 2018, Rev. 0 
 

 

 

 

 

LOGISTICS SECTION CHIEF 

The Logistics Section provides necessary facilities, services, equipment, and supplies to support the 

incident response. The Logistics Section Chief activates and supervises the Service Branch and the 

Support Branch within the Logistics Section and reports directly to IC/UC as a member of the General Staff. 

The Logistics Section Chief coordinates with the other sections of the IMT to plan for the current and future 

operational periods in order to support the response objectives set by IC/UC. 

 Plan the organization of the Logistics Section. 

 Assign work locations and preliminary work tasks to section personnel. 

 Notify the Resources Unit of the Logistics Section units activated, including names and locations 

of assigned personnel. 

 Assemble and brief Logistics Branch Directors and Unit Leaders. 

 Determine and supply immediate incident resource and facility needs. 

 In conjunction with Command, develop and advise all sections of the IMT resource approval and 

requesting process. 

 Review proposed tactics for upcoming operational period for ability to provide resources and 

logistical support. 

 Identify long-term service and support requirements for planned and expected operations. 

 Advise Command and other Section Chiefs on resource availability to support incident needs. 

 Provide input and review the Communications Plan, Medical Plan, and Traffic Plan. 

 Identify resource needs for incident contingencies. 

 Coordinate and process requests for additional resources. 

 Develop recommended list of section resources to be demobilized and initiate recommendation 

for release when appropriate. 

 Receive and implement applicable portions of the incident Demobilization Plan. 

 Ensure the general welfare and safety of Logistics Section personnel. 

 Maintain Unit Log (ICS 214). 

For further information regarding ICS position roles and responsibilities, consult ConocoPhillips’ Incident 

Management Handbook. 

Alpine Field, Satellites, and Pipelines ODPCP 3-24 February 2018, Rev. 0 
 

 

 

 

 

 

FINANCE SECTION CHIEF 

The Finance Section manages financial aspects of the incident response, including tracking the incident 

cost, processing invoices and payments, paying claims, and negotiating vendor contracts and pricing. The 

Finance Section Chief, a member of the General Staff, leads the Finance Section and is directed by IC/UC. 

The Finance Section Chief activates and supervises the Time/Cost Unit, the Procurement Unit, and the 

Compensation/Claims Unit, when necessary. 

 Participate in incident planning meetings and briefings as required. 

 Review operational plans and provide alternatives where financially appropriate. 

 Manage all financial aspects of an incident. 

 Provide financial and cost analysis information as requested. 

 Gather pertinent information from briefings with responsible agencies. 

 Develop an Operating Plan for the Finance/Admin Section; fill supply and support needs. 

 Determine the need to set up and operate an incident commissary. 

 Meet with assisting and cooperating agency representatives, as needed. 

 Maintain daily contact with agency(ies) administrative headquarters on finance/admin matters. 

 Ensure all personnel time records are accurately completed and transmitted to home agencies, 

according to policy. 

 Provide financial input to demobilization planning. 

 Ensure all obligation documents initiated at the incident are properly prepared and completed. 

 Brief agency administrative personnel on all incident-related financial issues that require attention 

or follow-up prior to leaving the incident. 

 Develop recommended list of section resources to be demobilized and initial recommendation 

for release when appropriate. 

 Receive and implement applicable portions of the incident Demobilization Plan. 

 Maintain Unit Log (ICS 214). 

For further information regarding ICS position roles and responsibilities, consult ConocoPhillips’ Incident 

Management Handbook. 

Alpine Field, Satellites, and Pipelines ODPCP 3-25 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

3.4 REALISTIC MAXIMUM RESPONSE OPERATING LIMITATIONS 

[18 AAC 75.425(e)(3)(D)] 

3.4.1 Introduction 

Realistic maximum response operating limitations that might be encountered at the facility are described in 

the ACS Technical Manual, Volume 1, Tactics Description L-7, which is incorporated into the plan by 

reference. Tactic L-7 analyzes the frequency and duration, expressed as a percentage of time, of limitations 

that would render mechanical response methods ineffective, as required by 18 AAC 75.425(e)(3)(D). The 

analysis considers weather, sea conditions, ice, daylight hours, and other environmental conditions that 

might influence the efficiency of the oil spill response. 

Broken ice conditions limit mechanical oil containment boom and recovery skimmers. As ice coverage 

increases, it becomes more and more difficult to maintain containment boom configurations and skirts to 

concentrate oil for recovery. Field tests in July 2000 demonstrated the effects of broken ice on a 

containment boom system (Bronson, 2002). However, broken ice conditions can promote oil removal by in 

situ burning. Alternative response measures may reduce environmental consequences of a spill when 

environmental conditions exceed operating limits. In high wind-chill conditions staff may be added to allow 

longer warm-up break times. When ground visibility or road transportation is limited by weather, conditions 

may allow flights for transportation and surveillance. Tracked vehicles and airboats or low-draft vessels can 

transit meltwater, snow and ice surfaces that preclude wheeled traffic. In sea states that preclude oil 

containment and recovery, vessels are still able to transit. When night hours otherwise restrict visibility, light 

plants can be used. 

3.4.2 Weather and Ice Conditions During the Shoulder Seasons 

The following general description of break-up and freeze-up applies to the marine environment in the 

Prudhoe Bay region. Descriptions are of typical conditions. They cover the chronology of break-up and 

freeze-up. See Vaudrey and Dickins et al. (2000) and tables in Atwater (1991) for further site-specific 

details. 

May 

The Sagavanirktok River and Kuparuk River overfloods (Condition 5) commence on average May 20 and 

27, respectively, based on 16 years of analysis. See DF Dickins Associates et al. (2001) for descriptions of 

seasonal ice conditions. 

June 

June 1-10: Landfast ice is intact (Condition 4) beyond the Kuparuk River and Sagavanirktok River overflood 

boundaries. Within the overflood zones immediately off the river deltas, fast ice lifts off the bottom of the 

Beaufort Sea and rapidly melts in place from the relatively warm water discharge (Conditions 6 and 7). The 

peak of major flooding occurs during the period June 4-7 (±6 days), at which point the Kuparuk River 

overflood may reach within 1 mile of the Northstar Island (Condition 5). Routine ice road operations might 

cease at this time. First open water appears offshore of the Sagavanirktok River and Kuparuk River by June 

6 to 13, respectively, on average. Fast ice beyond the overflood zones and outside the barrier islands is 

still intact and more than 5 feet thick in early June. 

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June 15-20: Nearshore lagoon areas affected by the Kuparuk overflood and shallow waters off the 

Sagavanirktok delta become mostly free of ice (Condition 9). Fast ice offshore remains intact (e.g., Stump 

Island to Northstar) and continues to melt (Condition 7). Solid ice 4 to 5 feet thick still surrounds Northstar 

Island. The soft surface is 25 percent covered by melt water pools (Condition 6). 

Air temperatures average 35oF and range from 20oF to 40oF. The wind is variable, but blows 60 percent of 

the time from the east and northeast, averaging 10 knots. 

The ice can support response vehicles up to several weeks before break-up. The effect of deteriorating sea 

ice on access with specific equipment is illustrated in ACS Technical Manual, Tactic L-7, based on field 

trials by Coastal Frontiers (2001). 

July, August, and September 

July 1: A completely intact, deteriorated ice cover 3 to 4 feet thick, with many cracks and approximately 40 

percent to 50 percent of its surface covered by melt pools and holes still exists in deeper water in the vicinity 

of Northstar (Condition 6). 

July 4 (Typical): Break-up begins with fracturing and movement in the floating landfast ice (Condition 7). 

July 8-12: Remaining fast ice outside the barrier islands, off the Sagavanirktok River delta and in Prudhoe 

Bay, decreases to less than seven-tenths coverage (Condition 8). 

July 15-26: Open, ice-free water out to Northstar and surrounding West Dock and Endicott causeway 

(Condition 9). 

Air temperatures average 40oF in July. 

The median number of days with flooded and/or broken ice at break-up at production facilities range from 

12 days at Point McIntyre, to 22 days at Northstar. 

October 

October 4, ±8 days: Freeze-up begins along shore in shallow water. Ice becomes shorefast for the season 

within one week following freeze-up in the nearshore lagoons (e.g., Point McIntyre 2 and Niakuk) and by 

October 25 offshore. 

Additional time is required for the young ice sheet to gain sufficient thickness and stability to be judged safe 

for over-ice operations. Time from initial freeze-up to being able to commence on-ice operations with 

response equipment ranges on average from 40 to 43 days at coastal or nearshore locations such as Point 

McIntyre 1, Niakuk, and Endicott, to 55 days at Northstar. 

Air temperatures at freeze-up range from 5oF to 15oF. Daylight is 9 to 10 hours per day. 

3.4.3 In Situ Burning Response Measures to Reduce Environmental Consequences of a Spill 

in Ice Conditions 

Section 1.7 provides information about permits and approval required for in situ burning. Oil spill removal 

during the shoulder seasons can be greatly enhanced by in situ burning. Cold water slows weathering 

processes, which increases the timeframe window of opportunity for burning, and ice provides containment 

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to concentrate oil for burning and recovery. In situ burning in shoulder-season ice conditions generally 

involves selective burning of oil on melt pools and in leads between floes, followed by manual recovery of 

residue. 

Operational Capability for In Situ Burning in Ice 

ACS maintains an inventory of specialized equipment for in situ burning operations during shoulder-season 

ice conditions. 

ACS Technical Manual, Tactics B-1 through B-7 describe planning, response strategies, procedures, and 

equipment to implement a successful burn in a mix of solid ice, broken ice, and open water situations. The 

tactics descriptions are listed below and are incorporated by reference into the plan. 

• B-1 In Situ Burning Plan, 

• B-2 Burning Oily Vegetation 

• B-3 In Situ Burning with Helitorch and Other Igniters, 

• B-4 Deployment and Use of Fire Containment Boom, 

• B-5 Burning Oil Pools on any Solid Surface, 

• B-6 Residue Recovery, and 

• B-7 Burn Extinguishment on Water (applicable to fire booms in light ice cover). 

ACS conducts spill response training courses involving classroom and field exercises at North Slope 

locations to practice the burn tactics in the ACS Technical Manual . The training involves a classroom 

course and a field demonstration with burn plans. The helitorch is discussed in the classroom and shown 

in the warehouse. Demonstrations can also involve creating and igniting gelled fuel. Alyeska Pipeline 

Service Company has pilots familiar with the helitorch operations and its helicopter is set up for the helitorch 

attachment. 

The ACS inventory of specialized response equipment on hand to support a large-scale burning operation 

is summarized in Table 3-3. 

TABLE 3-3: BURNING EQUIPMENT 

EQUIPMENT QUANTITY 

Helitorch (55 gallons) 6 

Air deployable igniters 1,436 

Helitorch batch gel mixers 2 

Adapted from ACS inventory – Response Equipment Specifications, ACS Technical Manual, 

Tactic L-6. 

In addition, ACS maintains fire-resistant boom in a mix of sizes (20-, 30- and 42-inch skirts), together with 

specialized logistics vehicles to access spill sites over a rotting and/or flooded ice surface in May and June 

(e.g., shallow draft boats). See Tactic L-6 tables describing boom and vessels. 

Steps in the decision to use in situ burning are summarized in the ACS Technical Manual Tactic B-1. Before 

using in situ burning, regulatory approval is obtained by first completing the ARRT Application for In Situ 

Burning and submitting it to the Unified Command according to ARRT’s Unified Plan, Annex F, Appendix 

II, “In Situ Burning Guidelines for Alaska,”. The application contains the incident-specific burn plan. 

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Once state and federal approval is granted, the following steps are taken to implement the response: 

• Collect and concentrate the oil using fire-resistant booms in light ice cover or utilize naturally 

occurring pools of thicker oil in high-ice concentrations and on surface melt pools on solid ice breakup, and in slush and new ice at freeze-up. 

• Ignite the oil using the helitorch or hand-held igniters, following established safety procedures to 

avoid flashback or ignition of any ongoing spill source. 

• Monitor the burn, maintaining constant watch on the fire and smoke plume, condition of 

containment booms (if used), and other safety hazards and issues. 

• Recover and dispose of the burn residue. 

Safety procedures and planning in accordance with established guidelines are emphasized throughout the 

training, preparation, and conduct of in situ burning operations. In situ burns are monitored to ensure that 

fire does not spread to adjacent combustible material. Care is taken to control the fire and to prevent 

secondary fires. Personnel and equipment managing the process are protected. The safe working distances 

from an in situ fire on water depend on the size of the fire and the exposure time. Aerial ignition with gel by 

helitorch or other ignition methods is coordinated, taking into account prevailing weather conditions, oil pool 

size, and distribution and the need for strict adherence to established safety distances. Effectiveness of In 

Situ Burning in Ice 

The consensus of research on spill response in broken ice conditions is that in situ burning is an effective 

response technique with removal rates exceeding 85 percent in many situations (Shell et al., 1983; SL 

Ross, 1983; SL Ross and DF Dickins, 1987; Singsaas et al., 1994). A considerable amount of research has 

demonstrated in situ burning in broken ice. The research includes several smaller-scale field and tank tests 

(SL Ross et al., 2003; Shell et al., 1983; Brown and Goodman, 1986; Buist and Dickins, 1987; Smith and 

Diaz, 1987; Bech et al., 1993; Guénette and Wighus, 1996) and one large field test (Singsaas et al., 1994). 

Most of the tests involved large volumes of oil placed in a static test field of broken ice resulting in substantial 

slick thicknesses for ignition. The few tests in unrestricted ice fields or in dynamic ice have indicated that 

the efficacy of in situ burning is sensitive to ice concentration and dynamics and thus the tendency for the 

ice floes to naturally contain the oil, the thickness (or coverage) of oil in leads between floes, and the 

presence or absence of brash or frazil ice which can absorb the oil. 

Brash ice is the debris created when larger ice features interact and degrade. Frazil ice is the “soupy” 

mixture of very small ice particles that forms as seawater freezes. 

Oil spilled on solid ice or among broken ice in concentrations equal to or greater than six-tenths has a high 

probability of becoming naturally contained in thicknesses sufficient for combustion. In lower ice 

concentrations, oil spill response methods can be used to create and maintain sufficient film thickness to 

facilitate burning. Fire-resistant booms are examples. Field experience has shown that it is the small ice 

pieces (e.g., the brash and frazil, or slush, ice) that accumulate with the oil against the edges of larger ice 

features (floes) and control the concentration (e.g., thickness) of oil in an area, and control the rate at which 

the oil subsequently thins and spreads. Other factors affecting burn effectiveness include oil weathering 

processes (e.g., evaporation and emulsification) and mixing energy from waves. 

The following discussion summarizes the current state of understanding the scientific principles and 

physical processes involved in situ burning of oil on melt pools during the ice-melt phase in June or on 

water between floes during the break-up period in July, based on SL Ross et al. (2003). Further discussion 

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also covers in situ burning of thinner slicks in mobile broken ice comprised of brash or frazil ice during the 

freeze-up shoulder season in October. 

The success of an in situ burning operation is dependent on the thickness of the oil to be burned. Ignition 

and burn efficiency are highly dependent on slick thickness. 

For an oil slick on water or ice to become ignited, the oil must be thick enough to insulate itself from the 

water beneath it. The igniter can heat the surface of thickened oil to the flash point temperature at which 

the oil produces sufficient vapors to ignite. The rules of thumb for minimum ignition thickness are listed in 

Table 3-4. 

TABLE 3-4: MINIMUM IGNITABLE THICKNESS ON WATER 

OIL TYPE MINIMUM THICKNESS 

Light crude and gasoline 1 millimeter (0.04 inch) 

Weathered crude and middle-distillate fuel oils (diesel and kerosene) 2 to 3 millimeter (0.08 to 0.12 inch) 

Residual fuel oils and emulsified crude oils 10 millimeter (0.4 inch) 

The oil removal rate for in situ oil fires is a function of fire size (or diameter), slick thickness, oil type, and 

ambient environmental conditions. For most large (greater than 3 meters in diameter) fires of unemulsified 

crude oil on water, the “rule-of-thumb” is that the burning consumption rate is 3.5 millimeters per minute. 

Lighter fuels burn faster, and heavier oils and emulsions burn slower, as shown in Table 3-5. 

Burn rate is also a function of the size of the fire. Crude oil burn rates increase from 1 millimeter per minute 

with 3-foot diameter fires, to 3.5 millimeters per minute for 15-foot fires and greater. In situ burns on melt 

pools typically consume oil at 1 millimeter per minute. For very large fires, on the order of 50 feet in diameter 

and larger, burn rates may decrease slightly because there is insufficient air in the middle of the fire to 

support combustion at 3.5 millimeters per minute. As fire size grows to the 50-foot range, oil type ceases 

to affect burn rate for the same reason. 

TABLE 3-5: BURN/REMOVAL RATES FOR LARGE FIRES ON WATER 

OIL TYPE / CONDITION BURN / REMOVAL RATE 

Gasoline >10 millimeters (0.4 inch) thick 4.5 millimeters per minute 

(0.18 inch per minute) 

Distillate fuels (diesel and kerosene) >10 millimeters (0.4 inch) thick 4.0 millimeters per minute 

(0.16 inch per minute) 

Crude oil >10 millimeters (0.4 inch) thick 3.5 millimeters per minute 

(0.14 inch per minute) 

Heavy residual fuels >10 millimeters (0.4 inch) thick 2.0 millimeters per minute 

(0.08 inch per minute) 

Slick 5 millimeters thick* 90 percent of rate stated above 

Slick 2 millimeters thick* 50 percent of rate stated above 

Emulsified oil (percent of water content)** Slower than above rates by a factor equal to the water 

content percent 

Estimates of burn/removal rate based on experimental burns and should be accurate to within ±20 percent. 

* Thin slicks will naturally extinguish, so this reduction in burn rate only applies at the end of a burn. 

** If ignited, emulsions will burn at a slower rate almost proportional to their water content (a 25 percent water-in-crude-oil emulsion 

burns about 25 percent slower than the unemulsified crude). 

An in situ oil fire is extinguished naturally when the slick burns down to a thickness that allows enough heat 

to pass through the slick to the water to cool the surface of the oil below the temperature required to sustain 

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combustion. The thickness at which an oil fire on water extinguishes is related to the type of oil and initial 

slick thickness. The rules of thumb are presented in Table 3-6. Other, secondary factors include 

environmental effects such as wind (winds greater than 20 knots preclude in situ burning in most cases), 

current herding of slicks against barriers, and oil weathering. 

TABLE 3-6: FIRE EXTINGUISHING SLICK THICKNESS 

OIL TYPE/INITIAL SLICK THICKNESS EXTINGUISHING THICKNESS 

Crude oil up to 20 millimeters (0.8 inch) thick 1 millimeter (0.04 inch) 

Crude oil 50 millimeters (2 inches) thick 2 to 3 millimeters (0.08 to 0.12 inch) 

Distillate fuels any thickness 1 millimeter (0.04 inch) 

With an estimate of the initial thickness of a fully contained slick, or a measure of the burn time, it is relatively 

easy to estimate oil removal efficiency by burning. If not all the slick area is on fire; the calculations need to 

account for this. 

Oil removal efficiency by in situ burning may be summarized as a function of the following key factors: 

• Initial thickness of the slick, 

• Thickness of the residue remaining, and 

• Amount of the slick's surface that was on fire. 

The water current maintains the oil thickness in the apex of a fire-resistant boom under tow, or against an 

ice edge in wind or current. When burning in a current, the fire slowly decreases in area until it reaches a 

size that can no longer support combustion. This herding effect can increase overall burn efficiencies, but 

it extends the time required to complete each burn. 

The residue from a typical, efficient (greater than 85 percent removal) in situ burn of crude oil 10 to 20 

millimeters thick is a semi-solid, tar-like layer that has an appearance similar to the skin on an old, poorlysealed can of latex paint that has gelled. For thicker slicks, typical of what might be expected in a towed 

fire boom (about 150 to 300 millimeters), the residue can be a solid. Burn residue is usually denser than 

the original pre-burn oil, and usually it does not spread due to its increased viscosity or solid nature. 

Tests indicate that the burn residues from efficient burns of heavier crude oils less than 32 degrees API 

gravity may sink once the residue cools, but their acute aquatic toxicity is very low or nonexistent. The “In 

Situ Burning Guidelines for Alaska,” state: 

“In general, however, the effects [of burn residue in that floats or sinks] are less severe 

than those from a large, uncontained oil spill, and no specific biological concerns have 

been identified to date.” 

Compared with unemulsified slicks, emulsions are much more difficult to ignite and, once ignited, display 

reduced flame spreading and more sensitivity to wind and wave action. Stable emulsion water contents are 

typically in the 60 percent to 80 percent range with some up to 90 percent. The oil in the emulsion cannot 

reach a temperature higher than 100°C until the water is either boiled off or removed. The heat from the 

igniter or from the adjacent burning oil is used first mostly to boil the water rather than heat the oil. 

The following points summarize the effect of water content on the removal efficiency of weathered crude 

emulsions: 

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• Little effect on oil removal efficiency (i.e., residue thickness) for water contents up to about 12.5 

percent by volume; 

• A noticeable decrease in burn efficiency with water contents above 12.5 percent, the decrease 

being more pronounced with weathered oils; 

• Zero burn efficiency for emulsion slicks having water contents of 25 percent or more; and 

• Some crudes form meso-stable emulsions that can burn efficiently at much higher water contents. 

Paraffinic crudes appear to fall into this category. 

Fortunately, emulsion formation is slowed dramatically by high ice concentrations and may not be a 

significant operational factor in planning in situ burns on solid ice or naturally contained in higher 

concentrations of broken ice. 

SL Ross et al. (2003) provides guidelines for burning thin slicks in broken ice with brash and slush, 

particularly relevant during the break-up and freeze-up shoulder seasons. General rules for minimum 

ignitable thickness and oil removal rates for burning thin slicks of crude oils on brash and/or slush with 

broken ice are as follows: 

• The minimum ignitable thickness for fresh crude on frazil ice or small brash ice pieces is up to 

double that on open water, or about 1 to 2 millimeters. 

• The minimum ignitable thickness for evaporated crude oil on frazil ice or small brash ice pieces can 

be higher than on open water, but is still within the range quoted for weathered crude on water, 

about 3 millimeters with gelled gasoline igniters. 

• For a given spill diameter, the burn rate in calm conditions is about halved on relatively smooth 

frazil/slush ice and halved again on rougher, brash ice. Wave action slightly reduces the burn rate 

on open water, but the halving rule seems to apply in waves as well. 

• The residue remaining on broken ice in calm conditions is about 50 percent greater than that on 

open water, or 1.5 millimeters. The residue remaining on brash or frazil ice in waves is slightly 

greater than in calm conditions, at about 2 millimeters. 

In summary, in situ burning of oil is efficient and rapid in broken ice conditions under the following conditions: 

• The spilled oil is thicker than the minimum ignitable (a thickness of 2 to 3 millimeters results in 50 

to 66 percent removal efficiency: 10-millimeter thickness, a typical thickness for wind-herded slicks 

on melt ponds on ice, gives 90 percent removal efficiency); 

• Larger areas can be ignited (a 100-square-foot slick on a melt pool will burn at 3.5 barrels of oil per 

hour, a 50-foot diameter, 10-millimeters thick slick will burn at 300 barrels of oil per hour, and a 

100-foot diameter slick will burn at 1,200 barrels of oil per hour); and 

• The oil is not more than 25 percent emulsified. 

3.4.4 Environmental Conditions 

The realistic maximum response operating limitations are described in the ACS Technical Manual (Tactic 

L-7). Environmental conditions can sometimes limit response work. Some limitations are based on safety, 

and others concern equipment effectiveness. The ACS Technical Manual lists the percentage of time some 

variables reduce effectiveness of response for planning purposes. 

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Low visibility due to fog or heavy snow is an environmental condition that can limit the effectiveness of a 

response. Low visibility can affect transportation as well as visual pipeline leak detection and spill tracking. 

The most limiting factors of mechanical containment and response effectiveness at Alpine are the remote 

location and the lack of road access in the event of a blowout (except when an ice road is in place). An 

open-orifice blowout to a remote, roadless area presents a difficult response because of the volume of oil 

to be contained without a road-supported response. Major factors affecting the response to a blowout in a 

roadless area are as follows: 

• Storage Removal: Without vehicles and vacuum trucks accessing the site at collection points, a 

major advantage of mass storage removal is removed from the response. The collection sites must 

be accessed with smaller collection units, i.e., tundra travel vehicles or airboats. Other removal 

options include large quantities of transfer pumps and hoses or burning at the collection points. 

• Vessel Access: The Colville River delta presents a unique response environment with its many 

channels, dead arms, sloughs and isolated lakes. Passage in many of the channels is variable. 

Airboats are the best vessel for use in the river channels of the delta. 

• Break-up Flooding: A spring break-up flooding event usually occurs every year in the delta. High 

river discharge along with ice would complicate a response activity. The high water may make 

navigation in the channel easier, but it would disperse the oil rapidly and in an erratic manner, and 

ice conditions may limit the effectiveness of boom containment and skimmer operation. Break-up 

flows last for approximately three weeks. 

COPA and North Slope spill responders plan to respond to all reported spills, including all those in spring 

break-up conditions. Responders evaluate the spill and do everything humanly possible to contain, control, 

and clean up the spill without jeopardizing personal safety. Break-up conditions do not preclude any oil spill 

responses at Alpine, although they may limit the effectiveness of responses. 

3.4.5 Colville River Delta 

Realistic maximum response operating limitations descriptions, called for in 18 AAC 75.425(c)(3)(D), are 

incorporated into this plan by reference to the ACS Technical Manual Tactic L-7. The Tactic L-7 descriptions 

of water and ice conditions of the Colville River in the spring are based on the U.S. Army Corps of Engineers 

report for the Endicott Environmental Monitoring Project. Tactic L-7 outlines the amount of time and typical 

dates that break-up conditions could reduce the effectiveness of mechanical response in the Colville River 

and its vicinity, as follows: 

• In the lagoon, broken ice concentrations limiting the effectiveness of oil recovery by vessels may 

last a week. 

• Ice in the Colville River may limit response effectiveness for 13 days typically. 

• Over-ice flow of Colville River water may limit responses for 12 days typically. 

• High water flows in the rivers may limit response effectiveness for two to three weeks typically. 

Responses are not precluded during these dates. 

The Colville River’s median date of peak break-up discharge is June 2. For about three weeks centered on 

the peak flow date, some overflow, ice movement, and ice pile-up are expected to reduce the effectiveness 

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of mechanical oil spill response. In situ burning is an important non-mechanical response that can be 

effective and can be conducted safely by response personnel. 

Examples of break-up conditions that may reduce the effectiveness of mechanical response are as follows: 

Sheetflow Periods 

Oil spill containment and removal in sheetflow conditions may involve in situ burning of oil, as well as 

booming and barriers. See ACS Technical Manual Tactics B-1 through B-5 and C-1 through C-5. 

Ice Pile-up in the Colville River Delta 

The Nigliq Channel Bridge and in-field piping crossings over channels of the delta are designed to withstand 

and break through ice jamming and loading events. However, broken ice, ice jams, and floodwaters in the 

Colville River and other channels of the delta threaten response worker safety and limit response 

effectiveness during break-up. Workers do not deploy response equipment on water at times and locations 

that are unsafe for them, including some aggressive break-up conditions. In situ burning is an important 

response options under these conditions. 

Broken Ice in Rivers and Channels 

During aggressive break-up in rivers and channels of the Colville River delta, when freshwater ice breaks 

loose and begins floating downstream, tactical spill response options are limited. Strong currents and large 

pieces of ice make conditions unsafe for airboat or other vessel deployment. Due to elevated safety risks 

to personnel, containment and/or recovery equipment may not be able to be deployed in river channels. 

During this time, alternative mechanical recovery or burning strategies are used in quiet-water areas 

downstream of the spill. See ACS Technical Manual Tactic R-12. 

Broken Ice in the Lagoon 

Conventional on-water containment and recovery is affected by ice concentrations greater than 30 percent 

coverage. At ice concentrations greater than 70 percent, on-water recovery effectiveness becomes limited 

(see the Deployment Considerations and Limitations statement in the ACS Technical Manual Tactics R19A and L-7). 

River Water Overflows onto the Shore-fast Lagoon Ice 

Over-flooding limits mechanical response effectiveness. In situ burning is an important response option for 

over-flood conditions. See ACS Technical Manual Tactics L-7, B-1, B-3, and B-5. 

Ice Pile-up at the Pipeline Transitions at the Colville River 

The pipeline’s exit points from its transition under the Colville River lie approximately 6 inches below the 

200-year flood stage elevation and are not expected to experience river ice pile-up. This means that only 

6 inches of water would be expected, at worst case, during a 200-year event to cover the pad and surround 

the point where the pipeline exits the ground. Six inches of water is not capable of carrying significant 

quantities of ice. As such, a pile-up condition cannot be created. 

Examples of freeze-up conditions that may reduce the effectiveness of mechanical response are as follows: 

Freezing Rivers, Ponds, and Lakes 

Low water flow is characteristic of Alpine-area hydrology during freeze-up and into the winter when rivers, 

ponds, and lakes freeze over and shallow ponds and lakes freeze to the bottom (Section 3.2). Aggressive 

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ice pile-ups or ice jams are not expected; however, resources would be expended on ice management in 

water bodies to reduce the risk of boom failure and limit safety concerns. As ice coverage increases, it 

becomes more difficult to operate containment boom to concentrate oil for recovery from open water. 

Operation of some skimmers may be reduced. Aufeis formations may be present downstream of local 

freshwater springs or along shorelines. Safety or operational restraints on response activities on thin or 

new-forming ice and aufeis would limit response effectiveness. Additional response limitations during 

freeze-up are discussed in the ACS Technical Manual. 

3.4.6 Fish Creek Basin 

The Fish Creek Basin is a relatively large drainage basin consisting of lakes and three significant tributary 

basins: Inigok Creek, Judy Creek, and Tinmiaqsiugvik (Ublutuoch) River. The Tinmiaqsiugvik River enters 

Fish Creek approximately 10 miles upstream from its mouth; portions of the river are entrenched, which 

creates narrower floodplains and steeper river banks. Fish Creek Basin streams have relatively low 

gradients and highly sinuous channels (BLM, 2004). Channel surveys of the Tinmiaqsiugvik River show 

general water depths of 5 feet, which allows access and navigation by shallow draft vessel (ConocoPhillips, 

2005). 

Floodplain Inundation 

Spring break-up occurs in the Tinmiaqsiugvik River during the first week in June, with peak stages noted 

between June 5 and 8 (BLM, 2004). Flooding and high water conveyance along the Tinmiaqsiugvik River 

at break-up occurs within the lower west floodplain during periods of high flow and/or when ice occurs in 

the main channel; the east and upper west floodplains are also inundated but convey little flow (BLM, 2004). 

Oil spill containment and removal in flood conditions may involve in situ burning of oil, as well as booming 

and barriers. See ACS Technical Manual Tactics B-1 through B-5 and C-1 through C-5. Workers do not 

deploy response equipment on water at times and locations that are unsafe for them, including some 

aggressive break-up conditions. In situ burning is an important response options under these conditions. 

Snow and Ice in Channels 

In Fish and Judy Creeks, observations made during the 2001 spring break-up indicate that snow and ice 

influence the shape and size of the channel cross-section, cause ice jams, and affect hydraulic roughness 

(BLM, 2004). For the Tinmiaqsiugvik River, the main channel may be entirely blocked by snow and ice and 

from the start of break-up flow until late June, when the water gradually cuts through the snow and ice until 

it reaches the permanent channel bed. During this time, the snow and ice dramatically impact the channel 

shape, size, and elevation, the hydraulic roughness, and the energy slope. Peak water surface elevation 

and discharge occurs in early June, during which time, flow is conveyed on snow, well above the permanent 

riverbed (BLM, 2004). River overflow on ice conditions, broken ice, and ice jams, threaten response worker 

safety and may limit response effectiveness; containment and/or recovery equipment may not be able to 

be deployed in river channels. Strong currents and large pieces of ice make conditions unsafe for vessel 

deployment and may interfere with boom systems. Alternative mechanical recovery or burning strategies 

are used in quiet-water areas. 

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3.5 LOGISTICAL SUPPORT [18 AAC 75.425(e)(3)(E)] 

COPA has an existing logistical support infrastructure for its operations on the North Slope. Transportation 

equipment, operational coordination procedures, and maintenance procedures are in place under normal 

operating conditions. COPA has contracts for operational logistics to support a spill response. Additionally, 

ACS maintains contracts with various vendors, which, as a member of ACS, COPA may utilize during a 

spill response. 

ACS Technical Manual, Volume 1, Tactics L-3, L-4, L-6, and L-8 through L-10 are incorporated here by 

reference. 

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- -

3.6 RESPONSE EQUIPMENT [18 AAC 75.425(e)(3)(F)] 

3.6.1 Equipment Lists 

Contracted or other oil discharge containment, control, cleanup, storage, transfer, lightering, and related 

response equipment to meet the applicable RPS presented in Part 1, and to protect environmentally 

sensitive areas and areas of public concern described in Part 3, and that may be reasonably expected to 

suffer an impact from a spill of the RPS volume as described in the response Scenarios in Section 1.6 is 

listed in the ACS Technical Manual, Volume 1 under relevant tactics. The location, inventory, and ownership 

of the equipment is listed in ACS Technical Manual under relevant tactics and/or Tactic L-6. The timeframe 

for delivery (mobilization) and startup (deployment) of response equipment and trained personnel is outlined 

in the response scenarios in Section 1.6. Manufacturer’s rated capacities, limitations, and operational 

characteristics for oil recovery equipment listed in the response scenarios are described in ACS Technical 

Manual under relevant tactics and/or Tactic L-6. Each vessel and the equipment for transferring oil from 

tanks mentioned in the scenarios in Part 1 is listed in Tactic L-6 as well. 

Alpine has dedicated oil spill response equipment positioned throughout the field in conexes and storage 

areas. The general equipment locations are shown in Figure 3-3. Pre-staged equipment and support 

infrastructure are also illustrated in ACS Technical Manual, Volume 2, Map Atlas Sheets 8, 9, 12, 16, 17, 

18, 20, 21, 22, 23, 23A, 24, 27, and 121. With each year’s experience in operating in the Alpine area, the 

staging of equipment and sites will vary. Alpine spill response equipment is maintained by ACS who can 

provide the most current and up-to-date equipment inventory and their locations, including remote and prestaged locations. The Alpine response equipment list is available upon request. 

In addition to the dedicated spill response equipment at Alpine, there is other equipment located on site 

that would be available in the event of a spill. Heavy equipment maintained at Alpine drilling and production 

operations typically includes a forklift with snow bucket attachment, front-end loaders, Supersucker, 14G 

grader, backhoe, vacuum trucks, Maxi Haul, lube truck, mechanics truck, water truck, fuel truck, bobcat 

with trimmer, semi and trailer, avgas trailer, and portable storage tanks. Sandbags are also available on 

site. Additionally, tundra travel vehicle support may be on site during drilling and production operations. 

Equipment can be used for berm construction, trenching, direct suction and storage, and other spill 

response operations, if needed. 

3.6.2 Pre Staged and Pre Deployed Response Equipment 

Spill prevention and response measures for the Alpine area includes several sites with pre-staged 

equipment and pre-deployed boom. Equipment is pre-staged at strategic locations either year-round or 

seasonally, during summer months. Boom is seasonally pre-deployed in diversionary and exclusion boom 

configurations immediately downstream of major pipeline crossings and at other pre-designated strategic 

locations along river channels and streams (see ACS Technical Manual Tactics C-8 and C-9 for typical 

boom configurations). With each year’s experience in operating in the Alpine area, the staging sites and 

deployment of equipment may vary. The goal is to strategically locate staged equipment in close proximity 

to potential leak sources, at likely containment sites, and in areas that are easily accessible so additional 

equipment can be quickly deployed, if needed. Additional boom deployment sites may be evaluated during 

an actual event. In addition to pre-deployed boom and response equipment, channel markers are annually 

deployed in major channels to assist responders in vessel navigation. 

Due to seasonal changes of the river channels and weather conditions causing fluctuating river currents, 

specific boom configurations and exact lengths of boom pre-deployed may vary. At each pre-deployment 

Alpine Field, Satellites, and Pipelines ODPCP 3-37 February 2018, Rev. 0 
site, sufficient boom sections and anchors are utilized to traverse the water body in a manner that optimizes 

its intended use for containment, diversion, exclusion, and/or recovery. Pre-staged equipment and predeployed boom locations are described in Table 3-7. 

The open-water time frame for seasonal boom deployment activities follows spring break-up each year, 

typically occurring around early to mid-June on the Colville River and mid-to-late June on surrounding rivers, 

and ends prior to the fall freeze-up (typically in mid-September). Some pre-staged equipment locations are 

also seasonally deployed each year. If possible, seasonally pre-staged equipment deployment is conducted 

in late May to early June. Initial boom pre-deployment at all sites is estimated to take approximately two 

weeks. Prior to fall freeze-up, all pre-deployed response equipment is removed , cleaned, repaired, and 

returned to the appropriate storage location. 

TABLE 3-7: ALPINE PRE-STAGED AND PRE-DEPLOYED EQUIPMENT SITES 

NAME LOCATION EQUIPMENT RESPONSE STRATEGY 

ALP-1 North of Alpine Pipeline crossing 

of the Miluveach River 

Pre-staged equipment and 

seasonally pre-deployed boom 

Deflect oil toward bank for 

recovery; Tactic C-8. 

ALP-2 North of Alpine Pipeline crossing 

of the Kachemach River 

Pre-staged equipment and 

seasonally pre-deployed boom 

Deflect oil toward bank for 

recovery; Tactic C-8. 

ALP-3 

East bank of Colville River north of 

Alpine Pipeline below grade 

crossing 

Pre-staged equipment Deflect oil toward bank for 

recovery; Tactic C-8. 

ALP-5 West bank of Sakoonang Channel 

southeast of CD4 pad Pre-staged equipment 

Deflect oil toward bank for 

recovery; Tactic C-8. Exclusion 

booming; Tactic C-9. 

ALP-9 East bank of Nigliq Channel north 

of CD2 pad Pre-staged equipment Deflect oil toward bank for recovery; Tactic C-8. 

ALP-10 

South bank at hairpin turn of 

Sakoonang Channel north of CD1 

pad 

Pre-staged equipment Deflect oil toward bank for 

recovery; Tactic C-8. 

ALP-12 West bank of Kachemach River 

south of three finger fork Seasonally pre-staged equipment Deflect oil toward bank for recovery; Tactic C-8. 

ALP-13 

West bank of Miluveach River 

south of confluence with Colville 

River 

Seasonally pre-staged equipment Deflect oil toward bank for 

recovery; Tactic C-8. 

ALP-14 

North bank of Sakoonang Channel 

downstream of CD3 pipeline 

crossing 

Pre-staged equipment Deflect oil toward bank for 

recovery; Tactic C-8. 

ALP-15 

West bank of Tamayagiak 

Channel upstream of Ulamnigiaq 

fork 

Seasonally pre-staged equipment 

and seasonally pre-deployed 

boom 

Deflect oil toward bank for 

recovery; Tactic C-8. 

ALP-16 

North bank of Tamayagiak 

Channel downstream of southern 

CD3 pipeline crossing 

Pre-staged equipment and 

seasonally pre-deployed boom 

Deflect oil toward bank for 

recovery; Tactic C-8. 

ALP-17 

North bank of Ulamnigiaq Channel 

downstream of northern CD3 

pipeline crossing 

Pre-staged equipment and 

seasonally pre-deployed boom 

Deflect oil toward bank for 

recovery; Tactic C-8. 

ALP-18 CD3 pad Pre-staged equipment Deflect oil toward bank for 

recovery; Tactic C-8. 

ALP-19 West bank of West Ulamnigiaq 

Channel north of CD3 pad 

Pre-staged equipment and 

seasonally pre-deployed boom 

Deflect oil toward bank for 

recovery; Tactic C-8. 

ALP-20 East bank of East Ulamnigiaq 

Channel northeast of CD3 pad Seasonally pre-staged equipment Deflect oil toward bank for 

recovery; Tactic C-8. 

ALP-21 East bank of east fork at the mouth 

of Sakoonang Channel. Pre-staged equipment Exclude oil from Harrison Bay; 

Tactic C-9. 

NK-3 Southwest area of Nanuk Lake Seasonally pre-deployed boom Exclude oil from Nanuk Lake; 

Tactic C-9. 

Alpine Field, Satellites, and Pipelines ODPCP 3-38 February 2018, Rev. 0 
NAME LOCATION EQUIPMENT RESPONSE STRATEGY 

NK-4 East bank of Nigliq Channel north 

of Nigliq bridge pipeline crossing Pre-staged equipment Deflect oil toward bank for recovery; Tactic C-8. 

CC-1 

East bank of Nigliagvik Channel 

north of Nigliagvik bridge pipeline 

crossing 

Seasonally pre-deployed boom Deflect oil toward bank for 

recovery; Tactic C-8. 

CC-2 West bank of Nigliq Channel north 

of Nigliq bridge pipeline crossing Seasonally pre-staged equipment 

Deflect oil toward bank for 

recovery; Tactic C-8. Exclusion 

booming; Tactic C-9. 

CC-3 

East bank of abandoned channel 

L9341 north of L9341 Bridge 

pipeline crossing 

Seasonally pre-staged equipment 

Deflect oil toward bank for 

recovery; Tactic C-8. Exclusion 

booming; Tactic C-9. 

SK-13 Sakoonang Channel southeast of 

CD1 pad Seasonally pre-deployed boom Deflect oil toward bank for recovery; Tactic C-8. 

SK-14 Sakoonang Channel south of CD1 

pad Seasonally pre-deployed boom Deflect oil toward bank for recovery; Tactic C-8. 

SK-15 Sakoonang Channel northeast of 

CD1 pad Seasonally pre-deployed boom Deflect oil toward bank for recovery; Tactic C-8. 

CD5 CD5 pad Pre-staged equipment Varies; deflect oil toward bank for 

recovery; Tactic C-8. 

TIN-1* North of Tinmiaqsiugvik River 

bridge and pipeline crossing Seasonally pre-deployed boom Deflect oil toward bank for recovery; Tactic C-8. 

FC-1 

Approximately 3.5 miles 

downstream of Tinmiaqsiugvik 

River bridge; north of large lake 

Pre-staged equipment 

Varies; deflect oil toward bank for 

recovery; Tactic C-8. Exclusion 

booming; Tactic C-9. 

CRC-1* GMT1 road near Crea Creek 

bridge and pipeline crossing Seasonally pre-staged equipment 

Deflect oil toward bank for 

recovery; Tactic C-8. Exclusion 

booming; Tactic C-9. 

GMT1 GMT1 Pad Pre-staged equipment Varies; deflect oil toward bank for 

recovery; Tactic C-8. 

* locations and equipment are proposed to support GMT1 development starting summer 2019 and are 

subject to change. 

3.6.3 Maintenance and Inspection of Response Equipment 

Response equipment is maintained in a condition for immediate use and rapid deployment. ACS performs 

routine inspection and maintenance of its response equipment. ACS inspections, tests, and maintenance 

follow ACS written standard operating procedures. 

ACS is a registered State of Alaska Oil Spill Primary Response Action Contractor (PRAC), and maintains 

certification as a U.S. Coast Guard Oil Spill Removal Organization (OSRO). ACS PRAC and OSRO 

certification information is provided in ACS Technical Manual, Volume 1 Tactic A-5. 

ACS has fulfilled the equipment maintenance and testing criteria required by these certifications. 

Alpine Field, Satellites, and Pipelines ODPCP 3-39 February 2018, Rev. 0 
BLANK PAGE 

Alpine Field, Satellites, and Pipelines ODPCP 3-40 February 2018, Rev. 0 
 

Alpine Field, Satellites, and Pipelines ODPCP 3-41 February 2018, Rev. 0 
BLANK PAGE 

Alpine Field, Satellites, and Pipelines ODPCP 3-42 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

3.7 NON -MECHANICAL RESPONSE INFORMATION [18 AAC 75.425(e)(3)(G)] 

Non-mechanical response is attempted only in situations where mechanical recovery cannot be 

accomplished without unacceptable environmental damage or unacceptable risk to personnel, or when 

mechanical recovery cannot be completed before the threat of further migration of contained oil is imminent. 

In situ burning will not be used as a substitute for mechanical recovery. 

In situ burning equipment inventory and deployment is described in the ACS Technical Manual Tactics 

L-6 and B-2 through B-7, incorporated here by reference. 

3.7.1 Environmental Consequences and Protection of Sensitive Areas 

The environmental consequences of in situ burning will be assessed by monitoring the downwind trajectory 

of the smoke. A trial burn will indicate the path of the smoke. Monitoring the downwind position of the smoke 

plume will be accomplished by a ground- or air-based member of the IMT. 

Appropriate measures, as required by the Unified Command, natural resource agencies, and public safety 

agencies, will be carried out to protect nearby human populations and environmentally sensitive areas. In 

situ burns will be limited to sites that are a minimum safe distance, generally several miles upwind of human 

populations. The safe distance will be plotted as outlined in the “In Situ Burning Guidelines for Alaska”. The 

determination takes into account a trial burn, wind conditions, and size of the expected burn area. In 

addition, public notifications and warnings will be issued in cooperation with agency emergency staff. 

In situ burns conducted according to the Unified Plan are not expected to harm environmentally sensitive 

areas and areas of public concern. Heat from in situ burning affects only the upper few centimeters of the 

water column in contact with the oil. Smoke has not been found harmful to wildlife populations. In situ 

burning smoke is reduced to concentrations that are safe to people by means of burning only at safe 

distances (see Table 3-8). 

In situ burn operations receive constant visual monitoring of the smoke plume’s behavior. The Burn 

Operations Team visually monitors the smoke plume. The federal and state On-Scene Coordinators may 

authorize a trial burn to confirm anticipated plume drift direction and dispersion distances downwind before 

authorizing the proposed burn. Burn operations may be stopped if the plume contacts or threatens to 

contact the ground in a populated area. 

A step-by-step process in establishing safe distances for burning is fully presented in the “In Situ Burning 

Guidelines for Alaska; Section 1.7 provides information about permits and approval required for in situ 

burning.”. The state and federal On-Scene Coordinators determine whether the burn lies at a safe distance 

from human populations. In situ burning is not authorized if it does not meet public health regulatory 

standards. The safe distance separating human populations from in situ oil burns is the downwind radius 

from the fire at which smoke particulate matter concentrations at the ground diminish to limits established 

by National Ambient Air Quality Standards. The safe distance guidelines are based on the predictions of a 

National Institute of Standards and Technology ALOFT-Flat Terrain computer model. 

The safe distance meets the National Ambient Air Quality Standards for particulate matter over a one-hour 

time period and is also used as the indicator that human populations will not be exposed to unsafe levels 

of all other smoke components. Table 3-8 lists the general safe distances separating an in situ burn and 

downwind populated areas in flat terrain. 

Alpine Field, Satellites, and Pipelines ODPCP 3-43 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

TABLE 3-8: SAFE DISTANCES BETWEEN IN SITU BURNS AND DOWNWIND HUMAN 

POPULATIONS IN FLAT TERRAIN: LOCATION OF FIRE ZONES 

LOCATION OF FIRE GREEN ZONE YELLOW ZONE RED ZONE 

Flat terrain on land 

>3 miles 1 to 3 miles <1 mile 

Water <3 miles from shore 

Water >3 miles from shore >1 mile Not applicable <1 mile 

Burning at a green zone safe distance from the public is acceptable following public notification. 

The “In Situ Burning Guidelines for Alaska” allow results of National Institute of Standards and Technology 

modeling to be used to authorize burning on the North Slope. The results show that for fires up to 10,000 

square feet in area (about 100 feet in diameter, in all wind speeds modeled over land or water in typical 

winter and summer atmospheric conditions), the surface concentrations of particulate matter decline below 

the target concentration in less than 0.6 mile of the burn. Fifty-six scenarios in Cook Inlet and the North 

Slope were modeled using the ALOFT-Flat Terrain computer model, and the worst case predictions were 

used to develop the safe distances for those specific locations. 

The Unified Plan aims to protect wildlife and habitat threatened by an oil spill by using in situ burning where 

mechanical methods become inadequate to contain and remove spilled oil. The ARRT’s Science and 

Technology Committee further decided that in situ burning can reduce the threat to wildlife posed by 

untreated oil, and that this benefit outweighs the potential harm posed by in situ burning smoke and residue. 

The Committee also decided not to require the incident-specific identification of wildlife threatened by in 

situ burning based party on a report by Campbell et al. (1994) regarding the environmental trade-offs of in 

situ burning. It concluded that in offshore, nearshore, and estuarine environments, burning a crude oil spill 

poses less risk to wildlife than not burning. Burning greatly reduces the volume of oil and therefore, the 

probability that oil comes in contact with wildlife. Burning also eliminates the volatile/soluble fraction of the 

spill. 

3.7.2 Operational Capability 

ACS maintains specialized equipment to conduct in situ burning operations during all seasons and all ice 

conditions as described in Section 3.4.3. The extensive inventory of response equipment is specifically 

designed to support a large-scale burning operation. Section 3.4.3 describes the effectiveness of in situ 

burning in ice. 

3.7.3 Effectiveness of In Situ Burning in Ice 

The consensus of research on spill response in broken ice conditions is that in situ burning is an effective 

response technique with removal rates exceeding 85 percent in many situations (Shell et al. 1983, SL Ross 

1983, SL Ross and DF Dickins 1987, Singsaas et al. 1994, SL Ross et al. 1998, DF Dickins et al. 2000, 

Sørstrøm et al. 2010). 

3.7.4 Permits, Approvals, and Authorizations 

Permits, approvals, and authorizations required to implement in situ burning are described in ACS Tactic 

B-1. Each response is different and as such, a specific time-line for obtaining permit approvals and 

authorizations is not defined. The tactic cannot be executed until all permits, approvals, and authorizations 

are in place. Tactic B-1 refers to Annex F of the Unified Plan which provides further detail on the use of the 

Alpine Field, Satellites, and Pipelines ODPCP 3-44 February 2018, Rev. 0 
 

in situ burning response options. ACS maintains emergency use permits that can be activated during a 

response (ACS Tactic A-3). 

Alpine Field, Satellites, and Pipelines ODPCP 3-45 February 2018, Rev. 0 
 

 

 

3.8 RESPONSE CONTRACTOR INFORMATION [18 AAC 75.425(e)(3)(H)] 

Contact information for ACS: 

Phone (907) 659-2405 (24-hour emergency number) 

Fax (907) 659-2616 

Mailing Address: Pouch 340022 

Prudhoe Bay, Alaska 99734-0022 

COPA will activate ACS to provide the initial manpower and resources required to respond to a large or 

lengthy spill response. If additional resources are required, they will be accessed through contracts 

maintained by ACS. COPA’s Statement of Contractual Terms and Response Action Contract signature 

page with ACS is presented as Figure 3-4 and Figure 3-5, respectively. 

Alpine Field, Satellites, and Pipelines ODPCP 3-46 February 2018, Rev. 0 
FIGURE 3-4: ACS STATEMENT OF CONTRACTUAL TERMS

STATEMENT OF CONTRACTUAL TERMS

AS REQUIRED UNDER AS46.04.30, AS 46.04.035, and 18 AAC 75.445(1) (1) in fulfillment of

requirement for registration of primary response action contractors and for approval of an Oil

Discharge Prevention and Contingency Plan

PLAN TITLE: Alpine ODPCP, Kuparuk ODPCP, and North Slope Exploration ODPCP

PLANHOLDER: ConocoPhillips, Alaska Inc. ________________________________ _____

This statement is a certification to the Alaska Department of Environmental Conservation

summarizing the contract between ConocoPhillios. Alaska. Inc, the oil discharge prevention and

contingency plan holder (hereinafter “PLAN HOLDER"), and Alaska Clean Seas, the oil spill

primary response action contractor or a holder of an approved oil discharge prevention and

contingency plan under contract (hereinafter “CONTRACTOR"), executed on

July 1, 2014, and the original of which is located at 3300 C Street, Suite 200, Anchorage, AK

99503, as evidence of the PLAN HOLDER’S access to the containment, control and/or cleanup

resources required under standards at AS 46.04.030 and 18 AAC 75.400 -- 18 AAC 75.495.

The PLAN HOLDER and the CONTRACTOR attest to the Department that the provisions of this

written contract clearly obligate the CONTRACTOR TO:

(A) provide the response and equipment listed for the CONTRACTOR in the contingency

plan;

(B) respond if a discharge occurs;

(C) notify the PLAN HOLDER immediately if the CONTRACTOR cannot carry out the

response actions specified in this contract or the contingency plan;

(D) give written notice at least 30 days before terminating this contract with the PLAN

HOLDER;

(E) respond to a Department-conducted discharge exercise required of the PLAN

HOLDER: and

(F) continuously maintain in a state of readiness, in accordance with industry standards,

the equipment and other spill response resources to be provided by the

CONTRACTOR under the contingency plan.

Statement of Contractual Terms

Page 1 of 2

Alpine Field, Satellites, and Pipelines ODPCP 3-47 February 2018, Rev. 0
STATEMENT OF CONTRACTUAL TERMS

I hereby certify that, as representative of the PLAN HOLDER, I have the authority to legally bind

the PLAN HOLDER in this matter. I am aware that false statements, representation, or

certifications may be punishable as as civil or criminal violations of law.

 

Lisa Bruner

Title: VP, NS Operations and Development

For: ConocoPhillips Alaska, Inc.

PLAN HOLDER

hereby certify that, as representative of the CONTRACTOR, I have authority to legally bind the

CONTRACTOR in this matter. I am aware that false statements, representation, or certifications

may be punishable as civil or criminal violations of law

 

Title: C. Barkley Lloyd

President & General Manager

For: Alaska Clean Seas

CONTRACTOR

Statement of Contractual Terms

Page 2 of 2

Alpine Field, Satellites, and Pipelines ODPCP 3-48 February 2018, Rev. 0
FIGURE 3-5: ACS-COPA MEMBER RESPONSE ACTION CONTRACT SIGNATURE PAGE

(G) Survival. Notwithstanding the termination of this RAC. the provisions of this RAC that, by their

nature, shall survive any expiration or termmatron.

(H) Amendment. [ h:s RAC may be amended only in writing signed by all Parties

(I) Entire Understanding. The terms set forth in this RAC supersede all previous discussions,

understandings and agreements between the Parties hereto with respect to the subject matter

hereof, and are intended by tha Parties as a final, complete and exclusive expression of the

terms nt their agreement and may net he contradicted, explained or supplemented by evidence

of any prior agreement or any contemporaneous oral agreement.

(J) Conflicts, This RAC is to be interpreted in harmony with the ACS Bylaws. In the event of a

conflict between tire provisions of this RAC and the ACS Bylaws, the terms of the ACS Bylaws

shall Control.

IN WITNESS WHEREOF, the Parties have signed this RAC.

ACS

Alaska Clean Seas

MEMBER

ConocoPhi I lips, Alaska Inc.

Signature'

Name:

Title:

Date.

t. snfelty LUy?: 2dl4.C6.26

09:06:03 da'OO' 

C. Barkley Lloya

President and General Manager

June 26, 2014

 

 

 

 

'Member Response Action Contract Page 9 of 11

Revised; March 2014

Alpine Field, Satellites, and Pipelines ODPCP 3-49 February 2018, Rev. 0
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

3.9 RESPONSE TRAINING PROGRAM [18 AAC 75.425(e)(3)(I)] 

COPA, in conjunction with ACS, provides an extensive training program for employees and contractors who 

volunteer for the North Slope Spill Response Team (NSSRT). COPA also provides relevant ICS training 

for employees and contractors who volunteer for the IMT. 

3.9.1 NSSRT Spill Response Training 

The NSSRT consists of workers who volunteer as emergency spill response personnel. Each team member 

is required to have initial emergency response training and annual refresher training, which meets or 

exceeds the requirements HAZWOPER regulations, 29 CFR 1910.120(q). Qualified responders must have 

a minimum of 24-Hour HAZWOPER training and annual requirements for HAZWOPER refreshers, medical 

clearance (physical), and a valid respiratory fit test, in addition to required training within each individual 

labor category (see ACS Tactic A-4). The ACS Training Department tracks these requirements and 

distributes a monthly “Readiness Report” of responder status, which is generated from the ACS database. 

Alpine SRT members are trained as NSSRT members or are ACS employees. Alpine SRT members are 

trained according to the NSSRT training requirements described in ACS Technical Manual Tactic A-4; ACS 

employees may have additional training. 

The NSSRT training program offers weekly classes at each field. These classes emphasize hands-on 

experience, field exercises, and team building drills. The courses are selected by the facility Lead ACS 

Technician in conjunction with field management, and use COPA, ACS, and external training consultants. 

Due to operational time constraints, many of the courses are divided by subject area and are taught in the 

two- or three-hour time frame of an NSSRT meeting. Training and attendance is documented and 

maintained by ACS. The yearly training schedule is also available at the facility and at ACS. Current NSSRT 

training schedules are posted on the ACS web site. 

3.9.2 IMT Member Training 

IMT member training includes an introduction to the ICS, ICS position specific training, tabletop exercises, 

and deployment drills. As new training needs are identified, they are developed and incorporated into the 

IMT training program. The COPA Alaska Emergency Management Teams Procedure delineates roles, 

responsibilities, and training requirements for COPA IMT members. IMT members are expected to complete 

initial training and annual training and drill events to maintain proficiency in their positions. The IMT receives 

training on the ODPCP through computer-based training module. Periodic announced and unannounced 

drills ensure IMT members understand their roles and responsibilities within the ICS and under the ODPCP. 

3.9.3 Auxiliary Contract Response Team 

ACS maintains third-party contracts to ensure North Slope Operators have the ability to provide personnel 

required to support a long-term response. The program consists of contracts and agreements with various 

spill response contractors and provides assurance that a host of trained and qualified responders are 

available to respond to oil spills on the North Slope. 

3.9.4 Other Training 

COPA employees and contract personnel involved in spill response are required to attend hydrogen sulfide 

training and may receive firefighting training. In addition, there may be specific departmental training 

requirements for Alpine facility operations.. Operators and facility personnel receive annual training on the 

Alpine Field, Satellites, and Pipelines ODPCP 3-50 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Emergency Action Plan, which covers procedures for reporting, notification, alarms, evacuation, and duties 

to perform during an emergency at Alpine facilities. 

The Alpine fire team may be involved in a spill response due to threat of fire. The team is trained to National 

Fire Protection Agency standards that permit personnel to be certified as State of Alaska Firefighters at the 

I and II levels, certified as Driver/Operators of Fire Apparatus and as Certified Fire Officers. Training is 

conducted in order to ground people in the skills needed as well as providing practical opportunities to 

become proficient in the tasks needed to operate as a firefighter. Training records are held in an electronic 

data base for as long as the individual is an active member of the team. 

Basic spill response and/or ICS training is provided to representatives of the local community that may be 

involved in a spill response, contingent upon availability and willingness of participants, along with COPA 

operational needs. North Slope Borough officials are typically involved in COPA-led response exercises 

and/or the annual Mutual Aid Drill, which are opportunities for spill response training. 

3.9.5 Recordkeeping 

Training records for COPA employees with duties under this response plan are maintained by the COPA 

HSE Department and/or human resources. Recordkeeping practices are conducted in accordance with 

Company policy and applicable retention periods. COPA employee records are maintained for the period 

of employment plus a minimum of five years. Records of COPA employees with assigned duties directly 

related to operation of DOT-regulated pipelines are maintained until the employee is no longer assigned 

those duties, plus five years. ACS maintains training records for NSSRT personnel, including COPA 

employees and contractors. The ACS Training Department maintains a database as a record of the courses 

taken by each employee and contractor. Records are kept for a minimum of five years or for the entire time 

the employee or contractor is assigned responsibilities under ACS programs. The database provides a 

description of the course and the date completed. Current training status of employees and contractors is 

available by contacting the ACS Training Department. 

3.9.6 Spill Response Exercises 

COPA conducts or participates in several types of spill response exercises every year, including QI and/or 

IMT notification, IMT tabletop, equipment deployment, and unannounced. Most exercises are conducted 

by COPA, some are conducted by regulatory agencies, while others are conducted by ACS or its member 

companies (e.g., Mutual Aid Drill [MAD]). In addition, actions taken during actual spill response incidents 

may fulfill exercise requirements. 

COPA has adopted the National Preparedness for Response Exercise Program (PREP) Guidelines for 

preparation and implementation of COPA-led spill response exercises. The Guidelines specify 15 core 

components to implement in a response exercise program. The 15 components are: 

Organizational Design: 

• Notifications; 

• Staff mobilization; and 

• Ability to operate within the response management system described in the plan. 

Alpine Field, Satellites, and Pipelines ODPCP 3-51 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

Operational Response: 

• Source control; 

• Assessment of discharge; 

• Containment of discharge; 

• Mitigation of discharge; 

• Protection of economically and environmentally sensitive areas; and 

• Disposal of recovered product. 

Response Support: 

• Communications; 

• Transportation; 

• Personnel support; 

• Equipment maintenance and support; 

• Procurement; and 

• Documentation. 

The COPA Crisis Management and Emergency Response Coordinator is responsible for scheduling, 

coordinating, and implementing COPA-led spill response exercises to ensure they meet NPREP 

requirements on an annual basis and within a triennial cycle. COPA -led exercises are self-evaluated and 

self-certified as meeting PREP guidelines. Supporting documentation from an exercise or drill, and in some 

cases an actual event, if actions taken will be used for PREP credit, is maintained for a minimum of five 

years. ACS leads equipment deployment exercises to meet PREP requirements. 

The COPA response exercise program includes the following: 

• Quarterly QI Notification Drills – ensure the QI is available on a 24-hour basis and can carry out 

assigned duties. 

• Annual IMT Tabletop Exercises – ensure personnel are knowledgeable of ICS roles and 

responsibilities, and familiar with notification telephone numbers and procedures. 

• Equipment Deployment Exercises – ensure response equipment is fully functional and ready to 

deploy, and provide hands-on training opportunity for NSSRT members. These exercises are 

managed by ACS. 

• Triennial Exercise of the Response Plan – ensures all components of National PREP are exercised 

every three years; and 

• Government-initiated unannounced exercises. 

COPA may participate in the North Slope operator’s annual MAD exercise. In addition to actively 

participating in the MAD, federal, state, and local agencies are involved in the development and evaluation 

of the drill. Equipment may be deployed at the MAD per PREP guidelines, and the MAD exercise may 

satisfy PREP requirements to exercise all aspects of the response plan at least every three years. 

Alpine Field, Satellites, and Pipelines ODPCP 3-52 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

3.10 PROTECTION OF ENVIRONMENTALLY SENSITIVE AREAS [18 AAC 

75.425(e)(3)(J)] 

Priority protection sites, environmentally sensitive areas, and areas of public concern that may be impacted 

during a worst case discharge are described within the scenarios in Section 1.6.3, Response Scenarios 

and Strategies. Additional resources used to identify environmentally sensitive areas and areas of public 

concern include the ACS Technical Manual, Volume 2, Map Atlas; the North Slope Subarea Contingency 

Plan; and NOAA Environmental Sensitivity Index (ESI) Maps. Environmentally sensitive areas and areas 

of public concern include bird nesting areas, fish-bearing lakes and streams, marine and terrestrial mammal 

areas, cultural resource and historic sites, and Native allotments. 

The ACS Technical Manual, Volume 2, Map Sheets 1 through 30 and 53 include specific information about 

priority protection sites and local environmental and cultural sensitivities for areas around Alpine facilities 

and pipelines. In addition, wildlife protection strategies are described in the ACS Technical Manual, Volume 

1, Tactics W-1 through W-6. The ACS Technical Manual is available online at: 

http://www.alaskacleanseas.org 

The North Slope Subarea Contingency Plan is a sub-plan of the Unified Plan, Alaska’s Area Contingency 

Plan. It includes specific information on biological and cultural resources on the North Slope for use during 

initial phases of a spill response. The Subarea Plan includes data on resource sensitivity, habitat types, 

threatened and endangered species, and has numerous wildlife maps and references to online resources 

to aid in protection of the environment during a spill response. The Subarea Plan is available online at: 

http://dec.alaska.gov/spar/perp/plans/scp_ns.htm 

NOAA ESI maps are another important resource for identifying environmentally sensitive areas within the 

Alpine facilities and pipelines operating area. ESI maps help identify locations vulnerable to oil spills, and 

can help establish protection priorities and identify cleanup strategies. North Slope ESI maps numbers ESI7 and ESI-8 cover the Alpine area and are available online at: 

http://response.restoration.noaa.gov/esi 

The state of Alaska has established a “Prevention and Emergency Response Subarea Plans Maps” section 

to their online Alaska State Geo-Spatial Data Clearinghouse. It contains links to subarea plans and their 

related maps, ESI maps, and other mapping resources such as: nautical and oceanographic charts, land 

use and management maps, biologically sensitive areas maps, most environmentally sensitive areas maps, 

and geographic response strategies (GRS) maps. The online Alaska maps clearinghouse is available via 

the following link: 

http://www.asgdc.state.ak.us/maps/cplans/subareas.html#northslope 

Alpine is located in a remote, rural onshore area where the economic base is the oil and gas exploration 

and production industry, and the government sector. An oil spill from Alpine facilities or pipelines would not 

significantly impact an economically sensitive area; however there is potential to impact local subsistence 

areas and practices. Nuiqsut is located near the main channel of the Colville River, approximately 8 miles 

south of Alpine CD1 pad. The population measured in the 2015 consensus was 415 residents. Nuiqsut 

provides modern amenities such as governance, infrastructure, schools, and an airport. Residents maintain 

recreational and subsistence hunting and gathering resources within the Alpine area; these are an essential 

part of the culture and community and require protection. The proximity of Nuiqsut would require close 

monitoring of meteorological conditions and communication and consultation with Nuiqsut representatives 

(through Unified Command) concerning how best to mitigate potential health effects on the community 

resulting from a major spill response. If historic, prehistoric, or archaeological sites or materials are 

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uncovered during spill recovery operations, the site is protected to prevent oiling and limit access, and 

ADNR Office of History and Archaeology is notified. 

3.10.1 Persistence and Toxicity Effects of Products in the Environment [18 AAC 

75.425(e)(3)(J)(ii)] 

Crude Oil 

Sweet crude oil is amber to black colored liquid. It typically has a sulfurous odor similar to rotten eggs. 

Crude oil is stable under normal ambient and anticipated conditions of storage and handling. It is extremely 

flammable as a liquid and vapor. The vapor can cause flash fire. Crude oil exhibited an increase incidence 

of skin tumors with a chronic application to mouse skin. There is limited evidence of carcinogenicity in 

animals, and crude oil is not classifiable as to its carcinogenicity in humans. It has not been listed as a 

carcinogen by the National Toxicology Program (NTP) or by OSHA. Dermal exposure to crude oil during 

pregnancy resulted in limited evidence of developmental toxicity in laboratory animals. Decreased fetal 

weight and increased resorptions were noted at maternally toxic doses in laboratory animals. No significant 

effects on offspring growth or other developmental landmarks were observed postnatally. 

Ultra Low Sulfur Diesel Oil 

Ultra low sulfur diesel oil is a liquid that is amber to various colors. It may be dyed red. It is combustible as 

a liquid and vapor. It is harmful if swallowed. It is harmful or fatal if the liquid is aspirated into the lungs. It 

causes skin irritation. It may cause respiratory tract irritation. Inhalation causes headache, dizziness, 

drowsiness, and nausea, and may lead to unconsciousness. It is stable under recommended storage and 

handling conditions. 

No component of this product at levels greater than 0.1% is identified as a carcinogen by the American 

Conference of Governmental Industrial Hygienists or the International Agency for Research on Cancer 

(IARC.) No component of this product present at levels greater than 0.1% is identified as a carcinogen by 

the NTP or OSHA. Diesel is toxic to aquatic organisms. It may cause long-term adverse effects in the 

aquatic environment. Spillages may penetrate the soil causing groundwater contamination. It is not 

expected to bioaccumulate through food chains in the environment. Spills may form a film on water surfaces 

causing physical damage to organisms. Oxygen transfer could also be impaired. 

No. 1 Diesel 

No. 1 Diesel is a crystal-clear liquid with a kerosene-like odor. It is an extremely flammable liquid and vapor. 

The vapor may cause flash fire or explosion. It may be harmful or fatal if swallowed and may cause lung 

damage. It contains chemicals that are both human and animal carcinogens. It is toxic to aquatic organisms. 

Regarding persistence and degradability, it is not readily biodegradable. It may bioaccumulate in aquatic 

organisms. Regarding mobility in environmental media, it may partition into air, soil, and water. 

Lube Oil 

Lube oil ranges from a clear and bright to amber liquid in color with a petroleum odor. It is stable under 

anticipated normal handling and storage conditions. Acute aspirations of large amounts of material may 

produce serious aspiration pneumonia and can cause irritation and redness to eyes and skin. All of the oils 

meet the IP-346 criteria of less than 3 percent polyaromatic hydrocarbons and are not considered 

carcinogens by IARC, NTP, or OSHA. 

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Extended exposure to high temperature may cause it to decompose. Volatilization is not significant after 

release of lubricating oil basestocks to the environment due to the very low vapor pressure of the 

hydrocarbon constituents. In water, lubricating oil basestocks will float and spread at a rate that is viscosity 

dependent. Water solubility is very low and dispersion occurs mainly from water movement with adsorption 

by sediment. In soil, lubricating oil basestocks show little mobility and adsorption is the predominant 

physical process. 

Emulsion Breaker 

Emulsion Breaker is a clear, yellow to amber color liquid with a hydrocarbon odor. It is flammable and 

should not be exposed to heat, sparks, and flames. It is harmful if inhaled, swallowed, or absorption through 

skin and could cause irreversible effects. It may cause eye irritation. Emulsion Breaker containing 

methanol could cause blindness. Emulsion Breaker containing naphthalene is listed as reasonably 

anticipated to be carcinogenic by NTP, and listed as IARC Group 2B, possibly carcinogenic to humans. It 

is toxic to aquatic organisms and may cause long-term adverse effects in the aquatic environment. 

Anti-Foam 

Anti-foam is a colorless to pink liquid with a hydrocarbon odor. The liquid and vapor is flammable and 

should not be exposed to heat, sparks, flames, or other ignition sources. It is harmful if swallowed. It is 

harmful or fatal if the liquid is aspirated into the lungs. It causes skin irritation. It may cause respiratory tract 

irritation. Inhalation causes headache, dizziness, drowsiness, and nausea, and may lead to 

unconsciousness. It is suspected of causing cancer and is not listed as a carcinogen by IARC, NTP or 

OSHA. 

Hydrocarbons in Anti-foam are not readily biodegradable but are regarded as inherently biodegradable 

since their hydrocarbon components can be degraded by microorganisms. On release to water, 

hydrocarbons will float on the surface and since they are sparingly soluble, the only significant loss is 

volatilization to air. It is possible that some of the hydrocarbons will be adsorbed on sediment. It is toxic to 

aquatic organisms and may cause long-term adverse effects in the aquatic environment. Biodegradation 

in water is a minor loss process and are photodegraded in air. 

Corrosion Inhibitor 

Corrosion Inhibitor is a brown liquid that is corrosive and highly flammable. Harmful by inhalation and 

ingestion with possible risk of irreversible effects. It may give off gas, vapor or dust that is very irritating or 

corrosive to the respiratory system and may cause burns to mouth, throat and stomach if ingested. It is 

corrosive and can cause burns to the skin and eyes. The naphthalene component is listed as reasonably 

anticipated to be carcinogenic by NTP, and listed as IARC Group 2B, possibly carcinogenic to humans. It 

is toxic to aquatic organisms and may cause long-term adverse effects in the aquatic environment. 

3.10.2 Prediction of Discharge Movement 

Flow from a release is from either a pipeline or a gravel pad to nearby tundra and ponds in summer and to 

frozen, snow-covered tundra and ponds in winter. See ACS Technical Manual, Volume 1 Tactics T-6 and 

T-7 for discussion of oil-retention rates of snow and for blowout aerial oil plume distribution, as well as 

Volume 2 Map Sheets 1 through 30 and 53 for information on likely surface drainage direction of flow. 

Alpine Field, Satellites, and Pipelines ODPCP 3-55 February 2018, Rev. 0 
 

3.10.3 Information on Probable Points of Contact 

Spilled oil will reach tundra and ponds in summer and frozen, snow- and ice-covered surfaces in winter. Oil 

trajectories are not expected to affect open water of Harrison Bay; but may impact environmentally sensitive 

areas or areas of public concern including migratory bird nesting locations and local subsistence areas. 

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3.11 ADDITIONAL INFORMATION [18 AAC 75.425(e)(3)(K)] 

Under 18 AAC 75.066(b)(2), a shop-fabricated oil storage tank built after December 31, 2008 to a design 

equivalent to industry standards specified by 18 AAC 75.066(b)(1) must be approved by ADEC. Letters of 

approval are provided in Appendix E; content is as follows: 

• January 21, 2016. Tank Design Approval #2016-01. 

• October 27, 2014. Tank Design Approval #2014-01. 

• February 28, 2013. Approval of Oil Storage Tank Construction Standards 

• February 9, 2005. Waiver of Oil Storage Tank Construction Standards. 

• February 26, 2003. Waiver [approval] of Oil Storage Tank Construction Standards. 

• February 14, 2003. Waiver [approval] of Oil Storage Tank Construction Standards. 

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3.12 BIBLIOGRAPHY [18 AAC 75.425(e)(3)(L)] 

Alaska Clean Seas (ACS). (latest version). ACS Technical Manual, Volume 1, Tactics Descriptions; Volume 

2, Map Atlas, www.alaskacleanseas.org . 

Alaska Regional Response Team (ARRT). (latest version). The Alaska Federal/State Preparedness Plan 

for Response to Oil & Hazardous Substance Discharges/Releases (Unified Plan). 

http://dec.alaska.gov/spar/perp/plans/uc.htm 

Alaska Regional Response Team (ARRT), (latest version). Alaska Federal/State Preparedness Plan for 

Response to Oil & Hazardous Substance Discharges/Releases (Unified Plan), Volume II, Change 2, 

North Slope Subarea Contingency Plan. 

Alaska State Geo-Spatial Data Clearinghouse. Prevention and Emergency Response Subarea Plan Maps, 

North Slope. Environmental Sensitivity Index Maps. 

http://www.asgdc.state.ak.us/maps/cplans/subareas.html#northslope . 

Atwater, S.G. 1991. 1990 Endicott Environmental Monitoring Program Final Report: Ice Break-up and 

Freeze-up. Prepared by SAIC for the U.S. Army Corps of Engineers, Anchorage, Alaska. 

Bech, C., P. Sveum, and I. Buist. 1993. The Effect of Wind, Ice and Waves on the In Situ Burning of 

Emulsions and Aged Oils. Proceedings of the Sixteenth Arctic and Marine Oilspill Program Technical 

Seminar, Calgary, AB. pp. 735-748. 

Bronson, M., Thompson, E., McAdams F., and J. McHale. 2002. Ice Effects on Barge-based Oil Spill 

Response Systems in the Alaskan Beaufort Sea. Proceedings 25th Arctic and Marine Oilspill Program 

Technical Seminar (AMOP), Calgary, pp. 1253-1268. 

Brown, H.M. and R.H. Goodman. 1986. In Situ Burning of Oil in Experimental Ice Leads. Environmental 

Studies Revolving Funds Report 064. National Energy Board, Calgary. 

Buist, I.A. and D. F. Dickins. 1987. Experimental Spills of Crude Oil in Pack Ice. Proceedings of the 1987 

Oil Spill Conference, April 6-9, Baltimore, Maryland. American Petroleum Institute, Washington, D.C., 

pp.373-382. 

Bureau of Land Management (BLM). 2004. Alpine Satellite Development Plan Final Environmental Impact 

Statement. U.S. Department of Interior, BLM Alaska State Office, Anchorage, Alaska. 

Campbell, T.E., Taylor, E. and D. Aurand. 1994. Ecological Risks Associated with Burning as a Spill 

Countermeasure in a Marine Environment. Proceedings of the 17th AMOP Technical Seminar, June 

8-10, Vancouver, British Columbia, pp. 707-716. 

Coastal Frontiers. 2001. Spring Breakup Equipment Access Test Program (Draft and Final), prepared for 

BP Exploration (Alaska), Inc., Anchorage, Alaska. 

ConocoPhillips. 2005. NPR-A Oil Spill Response Strategy Study. Prepared by Polaris Applied Sciences, 

Inc. Unpublished study. Anchorage, Alaska. 121 pages. 

Department of Transportation, U.S. Coast Guard, Research and Special Programs Administration, 

Environmental Protection Agency, Department of the Interior Minerals Management Service. (latest 

version). National Preparedness for Response Exercise Program (PREP) Guidelines. 

DF Dickins Associates Ltd., Vaudrey & Associates, Inc., and SL Ross Environmental Research Limited. 

2000. Oil Spills in Ice Discussion Paper. Prepared for Alaska Clean Seas, Prudhoe Bay, Alaska. 

Alpine Field, Satellites, and Pipelines ODPCP 3-58 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Dickins, D.F. and K. Vaudrey. 2000. Typical Environmental Conditions During Freeze-Up in Nearshore 

Alaskan Beaufort Sea. Prepared for Alaska Clean Seas. 

Guénette, C.C. and R. Wighus, 1996. In Situ Burning of Crude Oil and Emulsions in Broken Ice. 

Proceedings of the 19th MOP Technical Seminar. Calgary, AB. pp. 895-906. 

Gavin, A. 1976. Wildlife of the North Slope. The Islands of Offshore Prudhoe Bay: The Snow Geese of 

Howe Island; The Seventh Year of Study. Atlantic Richfield Company. pp. 71. 

Morrow, J.E. 1980. The Freshwater Fishes of Alaska. Alaska Northwest Publishing Co., Anchorage. 

Norton, D.W., I.W. Ailes, and J.A. Curatolo. 1975. Ecological relationships of the island tundra avifauna 

near Prudhoe Bay, Alaska. J. Brown (ed.). Ecological Investigations of the Tundra Biome in the 

Prudhoe Bay Region, Alaska. Biological Papers, University of Alaska. Special Report No. 2. pp. 125-

133. 

Parametrix, Inc. 1997. Alpine Development Project. Environmental Evaluation Document. September. 

Polaris Applied Sciences, Inc. September 2003 (update). Oil Spill Strategy and Response Studies for the 

Channels of the Colville River Delta Region, Alaska. Prepared for Phillips Alaska, Inc. 

Ray, S. and J.W. Aldrich. 1996. Part 4: Flood Magnitude and Frequency. pp. 35-40. In: M.T. Jorgenson, 

J.W. Aldrich, S.R. Ray, E.R. Pullman, Y. Shur, M.D. Smith, A. A. Stickney, and H.J. Walker. 1996. 

Geomorphology and Hydrology of the Colville River Delta, Alaska, 1995. Volume 1. Unpublished fourth 

annual report by ABR, Inc., Shannon and Wilson, Inc., and Louisiana State University to PAI Alaska, 

Inc., and Kuukpik Unit Owners, Anchorage, Alaska. 

Scandpower A/S, Report No. 27.83.01/R1. 2001. “Blowout Frequency Assessment of Northstar.” July. 

Shell Oil Company, Sohio Alaska Petroleum Company, Exxon Company, U.S.A., Amoco Production 

Company. 1983. Oil Spill Response in the Arctic – Part 2: Field Demonstrations in Broken Ice., Shell 

Oil Company, Sohio Alaska Petroleum Company, Exxon Company, U.S.A., Amoco Production 

Company. Anchorage, Alaska. 

Singsaas, I., P. Brandvik, P. Daling, M. Reed and A. Lewis. 1994. Fate and Behavior of Oils Spilled in the 

Presence of Ice – a Comparison of the Results from Recent Laboratory, Mesoscale Flume and Field 

Tests. Proceedings of the 17th AMOP Technical Seminar, June 8-10, Vancouver, British Columbia, 

pp. 355-370. 

SL Ross Environmental Research Ltd., DF Dickins Associates Ltd., and Alaska Clean Seas. 2003. Tests 

to Determine the Limits of In Situ Burning of Thin Oil Slicks in Broken Ice. Report prepared for the U.S. 

Minerals Management Service and ExxonMobil Upstream Research. 

SL Ross Environmental Research Ltd., D.F. Dickins and Associates Ltd. and Vaudrey and Associates, Inc. 

1998. Evaluation of Cleanup Capabilities for Large Blowout Spills in the Alaskan Beaufort Sea During 

Periods of Broken Ice. April 23. 

SL Ross Environmental Research Ltd. and DF Dickins Associates Ltd. 1987. Field Research Spills to 

Investigate the Physical and Chemical Fate of Oil in Pack Ice. Environmental Studies Revolving Funds 

Report No. 062. 95 pages. 

SL Ross Environmental Research Ltd. 1983. Evaluation of Industry’s Oil Spill Countermeasures Capability 

in Broken Ice Conditions in the Alaskan Beaufort Sea. Prepared for the Alaska Department of 

Environmental Conservation, Anchorage, Alaska. 

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Smith, N.K. and A. Diaz. 1987. In-Place Burning of Crude Oils in Broken Ice. Proceedings of the 1987 Oil 

Spill Conference, April 6-9, Baltimore, Maryland. American Petroleum Institute, Washington, D.C., pp. 

383-387. 

Sørstrøm, S.E., P.J. Brandvik, I. Buist, P. Daling, D. Dickins, L. Faksness, S. Potter, J.F. Rasmussen and 

I. Singsaas. 2010. Oil in Ice – Joint Industry Program on Oil Spill Contingency for Arctic and Ice 

Covered Waters, Summary Report. 

Steinhauer, M.S., and P.D. Boehm. 1992. The composition and distribution of saturated and aromatic 

hydrocarbons in nearshore sediments, river sediments, and coastal peat of the Alaskan Beaufort Sea: 

Implications for detecting anthropogenic hydrocarbon inputs. Marine Environmental Research. 

33:223-253. 

U.S. Geological Survey. 1977. Water Resources Data for Alaska, Water Year 1976. Water-Data Report 

AK-76-1. pp. 401. 

Vaudrey & Associates, Inc. 1998 Memorandum. Broken ice periods for selected production sites along the 

Alaskan Beaufort Coast. June 27. 

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PART 4 BEST AVAILABLE TECHNOLOGY 

[18 AAC 75.425(e)(4)] 

Part 4 discusses the best available technology (BAT) requirements contained in 18 AAC 75.425(e)(4)(A), 

(B), and (C) and addresses technologies not subject to response planning or performance standards in 18 

AAC 75.445(k)(1) and (2). The discussion of each technology complies with the requirement to analyze 

applicable technologies and to provide justification that the technology is the best available. 

4.1 COMMUNICATIONS [18 AAC 75.425(e)(4)(A)(i)] 

The communications system for use in a spill response at Alpine is described in the ACS Technical Manual, 

Volume 1, Tactic L-11A, and is incorporated here by reference. 

4.2 SOURCE CONTROL [18 AAC 75.425(e)(4)(A)(i)] 

BAT analysis of source control for a well blowout, pipeline leak, and tank overflow is provided. COPA will 

use the services of professional well control specialists if well control is not regained by conventional 

mechanical means or natural occurrences. 

4.2.1 Well Source Control 

This BAT analysis reviews the techniques and methods to control a “deep” well blowout that has the 

potential to release liquid hydrocarbons at the surface. Inherent to this analysis are the assumptions that 

all primary and secondary levels of well control have failed and that all dynamic and mechanical attempts 

to regain primary or secondary well control have been ineffective. 

Once an incident has escalated to a blowout incident of the magnitude described in Section 1.6, the two 

methods of well control are well capping and relief well drilling. COPA concludes well capping constitutes 

BAT for source control of a well blowout. Table 4-1 summarizes well capping as BAT for a well blowout. 

The rationale for acceptance of well capping as BAT is provided in the following discussion. 

Well Capping 

Well capping techniques have been developed and have proven to be efficient and effective in regaining 

control of damaged wells and in reducing associated environmental impacts. Well capping techniques and 

procedures have been developed and implemented by professional well control specialist companies 

throughout the world. COPA has the ability to mobilize specialized well control personnel and equipment to 

a North Slope location within 24 to 48 hours of notification. 

Well capping is both compatible and feasible with all drilling operations because the technology is applied 

at the surface. There are no sensitivities to well types (extended reach drilling [ERD], horizontal, etc.) or 

location (remote, island, etc.). Well capping techniques have been applied both to land-based and offshore 

locations, and historically have been proven successful in regaining well control in shorter durations. Well 

capping techniques are preferred over the more time-intensive alternative of drilling a relief well. Blowouts 

are typically controlled with more conventional surface control or dynamic kill methods (blowout preventer 

[BOP] equipment, weighted drilling muds, or cement placement in the well) before well capping is attempted 

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or required; drilling relief wells is often a last resort when surface control or kill methods fail and well capping 

is not feasible. 

The U.S. Bureau of Ocean Energy Management and SINTEF Civil and Environmental Engineering 

(Norway) data indicate well capping technologies provide the shortest duration and most effective option 

for regaining well control and minimizing environmental impacts. This is shown by the consistent application 

of well capping in response to well control events and also by the associated shorter duration to successfully 

regain well control using well capping, as compared to relief well drilling. 

Other than the initial cost of the well control equipment currently stationed on the North Slope, maintaining 

an open contract with Boots & Coots is a minimal annual cost. Any additional services required during an 

actual response would be provided at previously agreed-to rates. 

Well control events where well capping would not be the preferred response involve events in which the 

potential to release liquid hydrocarbons to the surface is highly unlikely (e.g., shallow gas, compromised 

surface casing or surface casing cement jobs, broaching or reasonable concern of broaching, inaccessible 

wellhead and/or casing). 

Relief Well Drilling 

The lead time involved in relocating a rig to a surface location and drilling a relief well necessitates early 

planning, which may be initiated concurrently with the implementation of surface control methods. If surface 

control methods fail, COPA relief well plans are fully implemented. COPA’s decisions are made by 

management in accordance with procedures contained in the incident-specific relief well plan. It should be 

recognized that a relief well is generally considered as a last resort to regain control of a blowout. It is far 

more common to kill the well with surface kill techniques or for the well to cease flowing due to depletion or 

the formation of a natural bridge in the wellbore. 

Relief well drilling technology is compatible with North Slope drilling operations, although it may be sensitive 

to both the well location and well type. Multiple drilling rigs that are capable of drilling a relief well are under 

contract on the North Slope. Downhole and surface equipment (e.g., tubulars, wellheads, etc.) to support 

relief well drilling operations are also available. 

Relief well drilling has been attempted only once as a mitigation measure to control a blowout on the North 

Slope. This was the ARCO Cirque gas well blowout in 1992, where well control was regained by a 

combination of surface control techniques and an assist from natural bridging before the relief well reached 

total depth. 

Relief well drilling is similar to current methods used to drill and complete North Slope wells today, and 

advances in directional drilling technology that allow for more precise wellbore placement increase 

likelihood of success of a relief well. However, relief well attempts are thus more sensitive to blowout well 

location and/or blowout well type. For extended reach wells, or remote locations with limited access, relief 

well drilling is both logistically challenging and time consuming, thereby adding an undesired increase to 

the overall environmental impact (volume spilled) from the blowout. 

4.2.2 Pipeline Source Control 

The pipeline source control procedures required by 18 AAC 75.425(e)(1)(F)(i) involve the placement of 

automatic shutdown valves (i.e., emergency shutdown [ESD] valves) at each terminus of the pipelines to 

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stop the flow of oil or product through the pipelines. Pipeline source control is also discussed in Section 1.6 

scenarios. 

Crude Oil Transmission Pipeline 

The Alpine sales crude oil transmission pipeline is equipped with automated leak detection systems that 

alarm if a leak is detected, which would activate ESD action from the control room. In addition, the crude 

oil transmission pipeline includes vertical loops in seven locations – one on each side of the Colville River, 

two on opposite sides of the Kachemach River, two on opposite sides of the Miluveach River, and one 

between the Colville and Kachemach rivers. The vertical loops isolate oil within the pipeline to prevent total 

down-drain of the pipeline and decrease the potential amount spilled. 

Valve isolation is an option compared to the pipeline profile changes, or vertical loops, shown in Table 4-2. 

Due to the remoteness of the Alpine crude oil transmission pipeline, use of vertical loops is considerably 

more effective in minimizing spill volumes during spill events. Moreover, the additional possibility of oil 

leakage at the mechanical connections of the valves, traditionally an area of concern and maintenance, is 

eliminated. Valves are needed on each terminus of the pipeline to keep any oil from entering or exiting in 

the event the pipeline needs to be isolated. The Alpine crude oil transmission pipeline Spill Isolation 

Strategy is presented as Appendix B. 

Vertical loops are also analyzed, along with two technology options for the valves: automatic ball valves 

and automatic gate valves (Table 4-2). Both valve options, when installed in new condition, are similar in 

terms of availability, transferability, cost, compatibility, and feasibility. In terms of effectiveness, ball valves 

typically have slightly faster closure times than gate valves. For the Alpine crude oil transmission pipeline, 

automatic ball valves (block and bleed type) are used in combination with vertical loops. As required by 18 

AAC 75.055(b), the flow of oil or product/gas can be completely stopped by these loops and valves within 

one hour after a discharge has been detected. The valve closure time for these types of valves is on the 

order of 30 seconds. 

4.2.3 Tank Source Control 

Source control procedures for purposes of this BAT analysis relate to the fill procedures and inlet valves 

controlling flow to regulated oil storage tanks identified in Appendix D, Table D-1. BAT analysis for tank 

source control is discussed in Table 4-3. 

The tanks listed below are fitted with truck fill connections only. The tanks are: 

• Lube oil tank, 

• Completions fluid storage tanks, and 

• Brine storage tanks. 

Tank fill connections are grouped together on the east side of the Alpine Central Processing Facility tank 

farm. An impound basin will be provided under the truck loading/unloading area to ensure any minor 

discharges that might take place during filling operations are contained. Filling operations are closely 

supervised to ensure fill procedures are followed. Inlet valves on these truck fill connections are onequarter-turn ball valves that must be operated manually. 

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Manual intervention is effective in source control because operators are required to remain at or near the 

tanks during loading and unloading operations, and because secondary containment and high-level audible 

and visual alarms are provided for these tanks. 

The primary source of supply for the diesel fuel tank is the 2-inch-diameter diesel pipeline from Kuparuk. 

Filling of the tank from the pipeline will be an unmanned operation. The 2-inch-diameter diesel pipeline is 

fitted with an automated fail safe one-quarter-turn ball valve mounted close to the tank inlet that closes on 

detection of a high-level condition in the tank. The diesel tank is also fitted with a local truck fill connection 

so the tank can be used at times when the pipeline supply may be unavailable. Truck filling operations are 

closely supervised in the same manner as the three tanks discussed above. The truck fill connection on the 

diesel tank is fitted with a one-quarter-turn ball valve that must be operated manually. The truck fill 

connection is also fitted with a check valve to prevent back flow from the tank. The combination of valves 

is considered BAT for the service type. 

The slop tank is an integral component of the oil treating process at Alpine and is the collection point for a 

number of oil-containing streams that may be released from the Alpine processing facilities. The contents 

of the slop tank are automatically pumped back into the inlet separator. Potential major sources of discharge 

to the slop tank are fitted with automated ball or flow control valves that close automatically by the distributed 

control system in the event of a first-stage, high-level condition in the slop tank. If the liquid level in the tank 

continues to increase despite the closure of these valves, it eventually reaches the set point for the second 

high-level transmitter. Should this second-stage, high-level condition be detected, the process control 

system initiates ESD of the entire process plant. Remedial action then must be initiated by operations staff 

before the plant can be restarted. The combination of valves and tie-in with the process plant ESD is 

considered BAT for the tank service type. 

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TABLE 4-1: BEST AVAILABLE TECHNOLOGY ANALYSIS WELL BLOWOUT SOURCE CONTROL 

BAT EVALUATION 

CRITERIA 

CURRENT METHOD: 

WELL CAPPING 

ALTERNATE METHOD: 

RELIEF WELL DRILLING 

AVAILABILITY: 

Whether technology is best in use in other 

similar situations or is available for use by 

applicant 

Well capping is in use globally. Fit-for-purpose well capping and well control 

equipment is located on the North Slope. Additional equipment can be on 

location within 24-48 hours. 

Relief well drilling equipment (e.g., rigs, downhole tools, etc.) is 

available. 

TRANSFERABILITY: 

Whether each technology is transferable to 

applicant’s operations 

Equipment is currently available on the North Slope or on retainer via well 

control services contract. 

Multiple drilling rigs are currently under contract on the North 

Slope. 

EFFECTIVENESS: Numerous global companies provide successful applications of well capping. Rare, successful application of relief well drilling has been 

Whether there is a reasonable expectation 

each technology will provide increased spill 

prevention or other environmental benefits 

After natural bridging and conventional methods (e.g., BOP, mud, 

cementing, equipment repairs), well capping is the most frequent blowout 

control measure. Application of well capping provides the best opportunity 

for minimizing pollution impacts. 

documented by industry. Industry data suggest a very small 

percentage of blowouts are successfully controlled with this 

technique. Relief well drilling, as compared to well control from 

dynamic and mechanical methods, is the longest pollution 

mitigation measure possible. 

Relief wells may be the preferred response method in some well 

control events (e.g., shallow gas, compromised surface casing or 

surface casing cementing, broaching, etc.), but these events are 

unlikely to result in the release of liquid hydrocarbons. 

COST: Fit-for-purpose equipment is already owned or under long-term contract. Time and cost of permitting, location construction, well planning, 

The cost to the applicant of achieving BAT, 

including consideration of that cost relative to 

Well capping requires the maintenance of open-end contracts with trained 

specialists to implement well control and capping operations. 

and executing relief wells is estimated at 2-3 times the cost of well 

capping, excluding any lost production. 

the remaining years of service of the 

technology in use by the applicant 

AGE AND CONDITION: 

The age and condition of technology in use by 

the applicant 

Well capping technology has improved since its application during the IraqKuwait conflict in the early 1990s. Firefighting equipment is in place on the 

North Slope. 

Relief well drilling technology is similar to current methods used to 

drill/complete North Slope wells. This technology is potentially 

sensitive to blowout well types (e.g., ERD). 

COMPATIBILITY: 

Whether each technology is compatible with 

existing operations and technologies in use by 

the applicant 

Technology is compatible and applied at surface (no sensitivity to well type). Technology is compatible, though potentially sensitive to blowout 

well types (e.g., ERD, remote locations, etc.). Survey uncertainty 

on high departure wells may result in problems intersecting target 

wellbore. 

FEASIBILITY: Method is feasible with all drilling operations. Applied at surface – no Method feasibility is contingent on geographical access near area 

The practical feasibility of each technology in 

terms of engineering and other operational 

aspects 

sensitivities to well type (e.g., ERD, remote locations, etc.). Prior proven 

success in offshore environments. Demonstrated success in historical well 

control efforts. 

of blowout. Lack of year-round access to some locations (e.g., 

offshore) limits application. There is little evidence of successful 

application of relief well drilling as the primary mitigation measure 

of control. 

Relief wells may be the preferred response method in some well 

control events (e.g., shallow gas, compromised surf casing or surf 

casing cementing, broaching, etc.), but these events are unlikely 

to result in the release of liquid hydrocarbons. 

Alpine Field, Satellites, and Pipelines ODPCP 4-5 February 2018, Rev. 0 
 

 

 

TABLE 4-1 (CONTINUED): BEST AVAILABLE TECHNOLOGY ANALYSIS WELL BLOWOUT SOURCE CONTROL 

BAT EVALUATION 

CRITERIA 

CURRENT METHOD: 

WELL CAPPING 

ALTERNATE METHOD: 

RELIEF WELL DRILLING 

ENVIRONMENTAL IMPACTS: 

Whether other environmental impacts of each 

technology, such as air, land, water pollution, 

and energy requirements, offset any 

anticipated environmental benefits 

Technology provides the best-proven opportunity to quickly reduce 

environmental impacts. Estimated duration of 18-30 days is significantly less 

than conventional alternative technologies. 

Technology provides additional exposure and environmental risks 

during application (e.g., additional well control problems). 

Technology application may be seasonally limited, leading to 

durations of 60-180 days. Relief wells may require additional 

gravel placement and mobilization or demobilization pressures on 

the local environment. Drilling a relief well is accompanied by the 

additional risk of a second well control event. 

Alpine Field, Satellites, and Pipelines ODPCP 4-6 February 2018, Rev. 0 
TABLE 4-2: BEST AVAILABLE TECHNOLOGY ANALYSIS CRUDE OIL TRANSMISSION PIPELINE SOURC

BAT EVALUATION 

CRITERIA 

CURRENT METHOD: 

AUTOMATIC ISOLATION BALL 

VALVES AND VERTICAL LOOPS 

TO ELIMINATE DRAIN BACK 

ALTERNATE METHOD: 

ADDITIONAL AUTOMATIC 

SHUTDOWN BALL VALVES 

ALTERNATE METHOD: 

MANUAL BLOCK VALVES 

AVAILABILITY: Whether technology is best in use in other similar situations or is available for use by applicant 

The Alpine crude oil transmission pipeline has two automatic isolation valves at each terminus and seven vertical loops along its length. 

Existing shutdown valves could be added to the system, and/or could replace the vertical loops. 

Proposed valves and vertical loops could be replaced with manual block valves. 

TRANSFERABILITY: Whether each technology is transferable to applicant’s operations 

Currently installed. Method is transferable. Method is transferable. 

EFFECTIVENESS: Automatic ball valves at each Automatic shutdown valves in Increased shutdown time Whether there is a reasonable expectation each technology will provide increased spill prevention or other environmental benefits 

pipeline terminus, with vertical loops along its length, are effective in minimizing spill volumes during spill events. Vertical loops form a terrace structure that significantly 

place of vertical loops would provide similar containment results. However, the additional possibility of oil leakage at the mechanical connections of the valves, 

associated with manual block valves in a roadless area would be significant. Compared to manual isolation block valves, vertical loops decrease the projected spill 

limits the amount of oil spilled due traditionally an area of concern and volume by 63% at the Colville to drain-down effects. Moreover, maintenance, would be added to River, 98% at the Kachemach the additional possibility of oil the project in a roadless area. The River, and 92% at the Miluveach leakage at the mechanical potential for spills is increased River by effectively blocking oil in connections of the valves, because a valve/actuator could fail “pools” in the pipeline on the traditionally an area of concern and to close, potentially causing a fluid opposite sides of the loops. maintenance, is eliminated. hammer condition that could 

Because the area between valves overpressure the line. Additionally, is roadless, the risk of undetected failure to close, while not adding to valve leakage is reduced. the risk of a spill, could allow more 

oil to spill. 

COST: The cost to the applicant of achieving BAT, including consideration of that cost relative to the remaining years of service of the technology in use by the applicant 

The system described is proposed and is a base case for comparison. 

Additional automation would cost in excess of $100,000. 

Additional cost in excess of $50,000. 

AGE AND CONDITION: The age and condition of technology in use by the applicant 

Proposed equipment would be new. 

Alternative equipment would be new. 

Alternative equipment would be new. 

COMPATIBILITY: Whether each technology is compatible with existing operations and technologies in use by the applicant 

Compatible with the proposed project. 

Compatible with the proposed project. 

Compatible with the proposed project. 

Alpine Field, Satellites, and Pipelines ODPCP 4-7 
 

 

 

 

 

TABLE 4-2 (CONTINUED): BEST AVAILABLE TECHNOLOGY ANALYSISCRUDE OIL TRANSMISSION PIPELINE SOURCE CONTROL 

BAT EVALUATION 

CRITERIA 

CURRENT METHOD: 

AUTOMATIC ISOLATION BALL 

VALVES AND VERTICAL LOOPS 

TO ELIMINATE DRAIN BACK 

ALTERNATE METHOD: 

ADDITIONAL AUTOMATIC 

SHUTDOWN BALL VALVES 

ALTERNATE METHOD: 

MANUAL BLOCK VALVES 

ALTERNATE METHOD: 

REPLACEMENT OF AUTOMATIC 

SHUTDOWN BALL VALVES WITH 

GATE VALVES 

FEASIBILITY: 

The practical feasibility of each 

technology in terms of engineering and 

other operational aspects 

Feasible to implement. Feasible to implement. Feasible to implement. Feasible to implement. 

ENVIRONMENTAL IMPACTS: 

Whether other environmental impacts 

of each technology, such as air, land, 

water pollution, and energy 

requirements, offset any anticipated 

environmental benefits 

There are no offsetting 

environmental impacts. 

In the event of a spill, there is an 

increased possibility of discharge 

to tundra and water from the pipe. 

In the event of a spill, there is an 

increased possibility of discharge 

to tundra and water from the pipe. 

In the event of a spill, there is an 

increased possibility of discharge to 

tundra and water from the pipe. 

Alpine Field, Satellites, and Pipelines ODPCP 4-8 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TABLE 4-3: BEST AVAILABLE TECHNOLOGY ANALYSIS TANK SOURCE CONTROL 

ALTERNATIVE METHOD: ALTERNATIVE 

CURRENT METHOD: LUBE OIL, COMPLETIONS METHOD: ALTERNATIVE METHOD: 

LUBE OIL, COMPLETIONS FLUIDS AND BRINE CURRENT METHOD: DIESEL TANK AND DIESEL TANK AND OFFBAT EVALUATION 

FLUIDS AND BRINE STORAGE 

TANKS 

STORAGE TANKS 

AUTOMATED VALVE 

DIESEL TANK AND OFF-SPEC 

TANK 

OFF-SPEC TANK 

AUTOMATED GATE 

SPEC TANK 

MANUALLY-OPERATED 

CRITERIA MANUAL VALVE CLOSURE CLOSURE AUTOMATED BALL VALVES VALVES VALVES 

AVAILABILITY: The product transfer lines for filling Technology is available. Valve closures are automatically Technology is Hardware is available and 

Whether technology 

is best in use in other 

similar situations or is 

available for use by 

applicant 

tanks are manually operated. Most 

fill lines are fitted with a check 

valve to prevent reverse flow. 

initiated when a high-level condition 

in the tank occurs. A 

microprocessor-based distributed 

control system transmitter detects 

high-level conditions. 

available. proven, but manual operation 

is not a viable option. 

TRANSFERABILITY: Currently installed. Technology is transferable. Currently installed. Technology is Technology is transferable. 

Whether each transferable. 

technology is 

transferable to 

applicant’s 

operations 

EFFECTIVENESS: Because operators are required to Additional automation would This technology is an effective, Larger gate valves Manual valve operation is not 

Whether there is a 

reasonable 

expectation each 

technology will 

provide increased 

spill prevention or 

other environmental 

remain at or near the tank during 

filling operations, and because an 

audible and visual alarm is 

provided should the tank reach a 

high level, manual intervention is 

effective in source control. 

afford little benefit given the 

existing filling procedures 

and requirement for 

continuous operator 

presence during the filling 

operation. 

proven means of preventing liquid 

carryover in tanks fed by pipelines 

or process streams. Automated 

valves are ball valves that require 

only one-quarter turn to close and 

their performance has been proven 

in dirty service conditions. 

would have a longer 

closure time than onequarter turn ball valves 

and may not close 

completely after long 

service in a dirty 

environment. 

a viable option. Diesel and offspec tanks are in continuous 

service and around-the-clock 

staffing with operators is 

impractical during periods of 

high fuel demand. 

benefits 

COST: Equipment is installed. Automation of these valves Equipment is installed. Similar cost to the Manual valves would cost less 

The cost to the 

applicant of achieving 

BAT, including 

consideration of that 

cost relative to the 

remaining years of 

service of the 

technology in use by 

the applicant 

would cost significantly 

more than the current 

technology. Also, the 

operator would still be 

required to remain at the fill 

site to oversee the filling 

operation so there would be 

no offsetting reduction in 

operating cost. 

current technology. than the current technology. 

AGE AND The system is simple, well proven, Method is more complex, Automated valves are current. New Proven and current Manual valves would be new, 

CONDITION: and current. New when installed. well proven, and current. when installed. technology. New when proven equipment, but 

The age and 

condition of 

technology in use by 

the applicant 

New when installed. installed. automated valves are typically 

used universally on process 

tanks supplied by pipelines. 

New when installed. 

Alpine Field, Satellites, and Pipelines ODPCP 4-9 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

TABLE 4-3 (CONTINUED): BEST AVAILABLE TECHNOLOGY ANALYSIS TANK SOURCE CONTROL 

BAT EVALUATION 

CRITERIA 

CURRENT METHOD: 

LUBE OIL, COMPLETIONS 

FLUIDS AND BRINE STORAGE 

TANKS 

MANUAL VALVE CLOSURE 

ALTERNATIVE METHOD: 

LUBE OIL, COMPLETIONS 

FLUIDS AND BRINE 

STORAGE TANKS 

AUTOMATED VALVE 

CLOSURE 

CURRENT METHOD: 

DIESEL TANK AND OFF-SPEC 

TANK 

AUTOMATED BALL VALVES 

ALTERNATIVE 

METHOD: 

DIESEL TANK AND 

OFF-SPEC TANK 

AUTOMATED GATE 

VALVES 

ALTERNATIVE METHOD: 

DIESEL TANK AND OFFSPEC TANK 

MANUALLY-OPERATED 

VALVES 

COMPATIBILITY: Method is compatible. Method is compatible. Method is compatible. Method is compatible. Method is compatible. 

Whether each 

technology is 

compatible with 

Gate valves are larger 

and would require more 

room to install. 

existing operations 

and technologies in 

use by the applicant 

FEASIBILITY: 

The practical 

feasibility of each 

technology in terms 

of engineering and 

other operational 

aspects 

Method is feasible. Method is feasible. Method is feasible. Method is feasible. Method is not feasible. 

Operating personnel are not 

available in sufficient numbers 

and would not provide the 

reliability of an automated 

system. 

ENVIRONMENTAL There are no offsetting There are no offsetting There are no offsetting There are no offsetting There are offsetting 

IMPACTS: environmental impacts. environmental impacts. environmental impacts. environmental impacts. environmental impacts. The 

Whether other 

environmental 

impacts of each 

technology, such as 

risk of tank overflow or a 

significant process upset 

would be far higher with a 

manually operated system. 

air, land, water 

pollution, and energy 

requirements, offset 

any anticipated 

environmental 

benefits 

Alpine Field, Satellites, and Pipelines ODPCP 4-10 February 2018, Rev. 0 
 

 

 

 

 

 

 

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4.3 TRAJECTORY ANALYSES AND FORECASTS [18 AAC 75.425(e)(4)(A)(i)] 

Trajectory analyses and forecasts are described in the ACS Technical Manual Tactics T-1 to T-6, and L-11, 

which are incorporated here by reference. 

4.4 WILDLIFE CAPTURE, TREATMENT, AND RELEASE PROGRAMS 

[18 AAC 75.425(e)(4)(A)(i)] 

Wildlife capture, treatment, and release programs are described in the ACS Technical Manual Tactic L-11 

and W-1 through W-5, which are incorporated here by reference. Wildlife protection strategies are in 

accordance with the Wildlife Protection Guidelines for Alaska (Annex G of the Unified Plan). 

4.5 CATHODIC PROTECTION FOR FIELD CONSTRUCTED OIL STORAGE 

TANKS [18 AAC 75.425(e)(4)(A)(ii)] 

Alpine tanks are shop-fabricated; the regulations requiring cathodic protection on field-constructed tanks 

do not apply. As such, BAT analysis for cathodic protection is not applicable. 

4.6 LEAK DETECTION SYSTEM FOR FIELD CONSTRUCTED OIL STORAGE 

TANKS [18 AAC 75.425(e)(4)(A)(ii)] 

Alpine tanks are shop-fabricated; the regulations requiring leak detection on field-constructed tanks do not 

apply. BAT analysis for leak detection systems is not applicable. 

4.7 LIQUID LEVEL DETERMINATION [18 AAC 75.425(e)(4)(A)(ii)] 

Alpine tanks with automated liquid level determination devices, and regulated by ADEC, are fitted with 

either an ultrasonic non-contact transmitter or microwave radar non-contact transmitter mounted at the top 

of the tank, or with a differential pressure transmitter installed at the bottom of the tank. Detection of a highlevel condition in the tank triggers local audible and visual alarms, plus remote annunciation in the staffed 

control room. Most tanks equipped with automated devices are filled with truck fill connections only. 

Because operators are required to remain at or near the tank during filling operations, and because audible 

and visual alarms are provided should the tank reach a high level, manual shutdown intervention is effective 

in source control. The diesel storage tank (No. CF-T-61001) is fitted with dual differential pressure 

transmitters mounted externally near the bottom of the tank. Detection of a high-level condition in the tank 

initiates local audible and visual alarms, plus remote annunciation in the control room. The normal source 

of supply to the tank is the 2-inch-diameter diesel pipeline from Kuparuk. Detection of a high-level condition 

by either transmitter initiates the closure of the automated tank inlet valve on the incoming products pipeline 

from Kuparuk. The slop oil tank (No. CF-T-31010) is fitted with a differential pressure transmitter, a radar 

transmitter, and an ultrasonic transmitter. The differential pressure transmitter is set to alarm at a lower 

liquid level than the radar and ultrasonic transmitters. Detection of a high level by the differential pressure 

transmitter annunciates an alarm remotely in the control room and close automated valves on several 

potential sources of supply to the slop tank. Detection of a higher high level by the microwave radar and 

ultrasonic transmitter initiates an ESD of the process train. The use of multiple liquid-level determination 

Alpine Field, Satellites, and Pipelines ODPCP 4-11 February 2018, Rev. 0 
devices in these tanks provides redundant (backup) overfill protection, and a means to test the system’s 

functionality. BAT analysis for tank liquid level determination is discussed in Table 4-4. 

Alpine Field, Satellites, and Pipelines ODPCP 4-12 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

TABLE 4-4: BEST AVAILABLE TECHNOLOGY ANALYSIS TANK LIQUID LEVEL DETERMINATION 

BAT EVALUATION 

CRITERIA 

CURRENT METHOD: 

ULTRASONIC LEVEL 

TRANSMITTERS 

CURRENT METHOD: 

DIFFERENTIAL 

PRESSURE LEVEL 

TRANSMITTERS 

ALTERNATE 

CURRENT METHOD: 

MICROWAVE RADAR 

LEVEL 

TRANSMITTERS 

CURRENT 

METHOD: 

VISUAL 

OBSERVATION 

ALTERNATE 

METHOD: 

CAPACITANCE 

PROBES 

ALTERNATE 

METHOD: 

DISPLACER LEVEL 

SWITCH AND 

TRANSMITTERS 

ALTERNATE 

METHOD: 

FLOAT GAUGE 

AVAILABILITY: Ultrasonic level Differential pressure Equipment is Visual observation Equipment is Equipment is Equipment is 

Whether technology is 

best in use in other 

similar situations or is 

available for use by 

applicant 

transmitters on tanks 

provide local visual 

and audible 

annunciation of a highlevel alarm and reports 

the high-level alarm to 

the Central Control 

Room. Operators are 

required to remain at 

the fill station during 

filling operation. 

level transmitters on 

tanks provide local 

visual and audible 

annunciation of a 

high-level alarm, plus 

remote annunciation 

at the Central Control 

Room. 

available and reliable 

in most level 

determination 

applications. 

is the current 

method. 

available and 

widely used in 

oilfield 

applications. 

available and widely 

used in oilfield 

applications. 

available. 

TRANSFERABILITY: 

Whether each 

technology is 

transferable to 

applicant’s operations 

Currently installed in 

some tanks. 

Currently installed in 

some tanks. 

Currently installed in 

some tanks. 

Technology is 

transferable. 

Technology is 

transferable. 

Technology is 

transferable. 

Technology is 

transferable and 

is currently in 

use on some 

tanks in Alaska. 

EFFECTIVENESS: Because operators are Continuous Equipment has Equipment is Method will work Method will work Method has 

Whether there is a 

reasonable 

expectation each 

technology will provide 

increased spill 

prevention or other 

environmental benefits 

required to remain at 

or near the tanks 

during the fill 

operation, and 

because a high-level 

condition will trigger 

both local audible and 

visual alarms and a 

monitoring of tank 

level provides inputs 

required for 

microprocessorbased process control 

system to initiate 

automated valve 

closure(s) when highacceptable 

measurement 

accuracy. Microwaves 

require no 

transmission medium 

and can operate in 

vacuum and positivepressure conditions. 

effective with strict 

adherence to Best 

Management 

Practices and local 

procedure. Tank 

liquid levels are 

determined from 

direct observation 

effectively in 

Alpine service 

conditions. 

effectively in Alpine 

service conditions 

but may require 

more maintenance 

for cleaning of 

displacer. Units 

would probably 

require heat tracing 

acceptable 

measurement 

accuracy. 

remote alarm in the 

Central Control Room, 

ultrasonic level 

transmitters provide 

adequate level 

determination for 

prompt closure of the 

manual valves. 

level conditions occur. Measurement results 

may be affected by 

vapor, foaming, or 

turbulent conditions; 

but low-frequency or 

modulated-frequency 

radar pulse devices 

work well in these 

conditions. 

through the hatch 

using a flashlight or 

other manual device 

(e.g., tank strap, 

etc.). 

As good or better 

than other “low 

tech” devices. 

for effective 

operation. 

Alpine Field, Satellites, and Pipelines ODPCP 4-13 February 2018, Rev. 0 
 

 

 

 

 

 

TABLE (CONTINUED): BEST AVAILABLE TECHNOLOGY ANALYSIS TANK LIQUID LEVEL DETERMINATION 

BAT EVALUATION 

CRITERIA 

CURRENT METHOD: 

ULTRASONIC LEVEL 

TRANSMITTERS 

CURRENT METHOD: 

DIFFERENTIAL 

PRESSURE LEVEL 

TRANSMITTERS 

ALTERNATE 

CURRENT METHOD: 

MICROWAVE RADAR 

LEVEL 

TRANSMITTERS 

CURRENT 

METHOD: 

VISUAL 

OBSERVATION 

ALTERNATE 

METHOD: 

CAPACITANCE 

PROBES 

ALTERNATE 

METHOD: 

DISPLACER LEVEL 

SWITCH AND 

TRANSMITTERS 

ALTERNATE 

METHOD: 

FLOAT GAUGE 

COST: Already in service Already in service Already in service Not applicable. Costs would be Costs would be Not investigated 

The cost to the 

applicant of achieving 

BAT, including 

where appropriate. where appropriate. where appropriate. comparable to 

selected methods. 

equal to or modestly 

higher than the 

selected methods. 

– see feasibility 

comments. 

consideration of that 

cost relative to the 

remaining years of 

service of the 

technology in use by 

the applicant 

AGE AND The system is simple, The technology is The technology is Procedures have The technology is The technology is The technology 

CONDITION: well proven, and current and well current and proven. been in place since current and current and proven. is current and 

The age and condition 

of technology in use 

current. New when 

installed. 

proven. New when 

installed. 

New when installed. 1993 for fuel 

transfer operations. 

proven. New when 

installed. 

New when installed. proven. 

by the applicant 

COMPATIBILITY: Currently installed. Currently installed. Currently installed. Compatible and The technology is The technology is The technology 

Whether each 

technology is 

compatible with 

widely used. 

Requires no 

change. 

compatible. compatible. is compatible. 

existing operations 

and technologies in 

use by the applicant 

FEASIBILITY: Currently installed. Currently installed. Currently installed. Feasible and Method is feasible. Installation is ADEC has 

The practical feasibility 

of each technology in 

terms of engineering 

and other operational 

aspects. 

preferred due to 

potential for 

electronic or 

pneumatic systems 

to experience 

damage from rough 

handling. 

feasible - would 

likely require 

modifications to the 

tanks that have 

already been 

fabricated without 

any increase in 

availability or 

reliability. 

expressed 

concern over the 

use of float 

devices due to 

several failures 

of float devices 

within the state. 

Alpine Field, Satellites, and Pipelines ODPCP 4-14 February 2018, Rev. 0 
TABLE (CONTINUED): BEST AVAILABLE TECHNOLOGY ANALYSIS TANK LIQUID LEVEL DETERMINATION 

BAT EVALUATION 

CRITERIA 

CURRENT METHOD: 

ULTRASONIC LEVEL 

TRANSMITTERS 

CURRENT METHOD: 

DIFFERENTIAL 

PRESSURE LEVEL 

TRANSMITTERS 

ALTERNATE 

CURRENT METHOD: 

MICROWAVE RADAR 

LEVEL 

TRANSMITTERS 

CURRENT 

METHOD: 

VISUAL 

OBSERVATION 

ALTERNATE 

METHOD: 

CAPACITANCE 

PROBES 

ALTERNATE 

METHOD: 

DISPLACER LEVEL 

SWITCH AND 

TRANSMITTERS 

ALTERNATE 

METHOD: 

FLOAT GAUGE 

ENVIRONMENTAL 

IMPACTS: 

Whether other 

environmental impacts 

of each technology, 

such as air, land, 

water pollution, and 

energy requirements, 

offset any anticipated 

environmental benefits 

None. None. None. None. None. None. None. 

Alpine Field, Satellites, and Pipelines ODPCP 4-15 February 2018, Rev. 0 
 

 

 

 

 

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4.8 MAINTENANCE PROCEDURES FOR BURIED STEEL FACILITY OIL 

PIPING [18 AAC 75.425(e)(4)(A)(ii)] 

The buried piping for tank CF-T-50090 at CD-1 is abandoned in-place. However, it is composed of a noncorrosive stainless steel material, wrapped in insulation coated with polyvinyl chloride (PVC), and is 

centered within a fusion-joined high-density prolyethylene (HDPE) pipe casing. The HDPE pipe casing 

prevents the piping from contacting soil or water conditions. Corrosion is not anticipated because the pipe 

is stainless steel and encased in HDPE pipe casing. 

4.9 PROTECTIVE COATING AND CATHODIC PROTECTION FOR FACILITY 

OIL PIPING [18 AAC 75.425(e)(4)(A)(ii)] 

4.9.1 Pipeline Corrosion Protective (Anti Corrosion) Wrapping or Coating 

As required by 18 AAC 75.080(d) and 18 AAC 75.080(e)(2)(A), the buried pipelines in the horizontal 

directional drilling (HDD) segment under the Colville River are protected from external corrosion by an 

external coating. Available technologies for pipeline wrapping or coating are: 

• Dual-layer fusion bonded epoxy (FBE) for corrosion and mechanical protection, 

• Conventional single-layer FBE for corrosion protection, 

• Paint, 

• Ceramic, 

• Cold tar enamel, and 

• Neoprene or foam. 

Of these six technologies, dual-layer FBE is considered BAT based on the physical properties of each 

technology in relation to the physical environment of the Alpine pipelines and the cost of FBE relative to a 

neoprene or foam coating system. 

Paint and ceramic coatings are not effective for the pipelines because these materials are brittle. The 

pipelines require a coating material that is ductile, because the pipelines may be subjected to high-bending 

strains potentially caused by permafrost thaw settlement. Neoprene or foam-type coatings are ductile and 

durable; however, they are more costly than FBE coatings. Also, neoprene and foam coatings reduce the 

weight of the pipelines, and more cost would be incurred to provide additional weight to the pipelines for 

stability during pipe-laying operations. 

Both dual-layer and single-layer FBE coatings are ductile; however, dual-layer FBE, composed of an inner 

layer of conventional FBE for corrosion protection and an outer layer of impact-resistant FBE for mechanical 

protection, is more durable (hence more transferable) than a single-layer FBE coating. Dual-layer FBE has 

been used on other pipelines and is readily available for the Alpine pipelines. The dual-layer FBE coating’s 

inner layer is the conventional FBE material that has been effective as a corrosion protection coating on 

marine pipelines. Both layers, which are feasible to apply, have a low coating breakdown factor that causes 

less impact to the environment while making the dual-layer FBE coating compatible with sacrificial anodes. 

High coating breakdown factors adversely affect sacrificial anode systems. The cost to apply the dual-layer 

FBE coating (in a new condition) is considered reasonable by COPA. Therefore, a dual-layer FBE coating 

Alpine Field, Satellites, and Pipelines ODPCP 4-16 February 2018, Rev. 0 
 

 

 

 

 

 

 

is considered BAT suited for the Alpine pipelines. If it is determined that the durability of the impact-resistant 

layer of FBE is not required, a single layer of corrosion-protective FBE may be used. 

The buried piping for tank CF-T-50090 at CD-1, which is abandoned in-place, is not wrapped or coated for 

corrosion protection. The piping is composed of a non-corrosive stainless steel material, wrapped in 

insulation coated with PVC, and is centered within a fusion-joined HDPE pipe casing. The HDPE pipe 

casing prevents the piping from contacting soil or water conditions. The piping is subject to an ADEC 

compliance waiver of cathodic protection and protective wrapping/coating (see Section 2.6). 

4.9.2 Cathodic Protection System 

The buried piping for tank CF-T-50090 at CD-1, which is abandoned in-place, does not have cathodic 

protection. The piping is composed of a non-corrosive stainless steel material, wrapped in insulation coated 

with PVC, and is centered within a fusion-joined HDPE pipe casing. The HDPE pipe casing prevents the 

piping from contacting soil or water conditions. The piping is subject to an ADEC compliance waiver of 

cathodic protection and protective wrapping/coating (see Section 2.6). 

4.10 CORROSION SURVEYS [18 AAC 75.425(e)(4)(A)(ii)] 

Not applicable; cathodic protection is not installed on facility oil piping. 

4.11 PIPELINE LEAK DETECTION, MONITORING, AND OPERATIONS 

[18 AAC 75.425(e)(4)((A)(iv)] 

4.11.1 Aboveground Crude Oil Transmission Pipeline 

As required by 18 AAC 75.425(e)(4)(A)(iv), a BAT review is provided for leak detection technologies 

applicable to the Alpine crude oil transmission pipeline and is discussed in Table 4-5. These technologies 

are: 

• Mass Balance Line Pack Compensation (MBLPC) – included for Alpine crude oil transmission 

pipeline, 

• Flow and Pressure Analysis – included for Alpine crude oil transmission pipeline, 

• Visual Surveillance – included for Alpine crude oil transmission pipeline, 

• Negative Pressure Wave Monitoring (NPWM) (acoustic monitoring system) 

• Mass Balance (MB), 

• Acoustic Emissions – monitoring based on measured sound data, and 

• Real Time Transient Model (RTTM). 

The rationale in determining the most appropriate leak detection system for North Slope transmission lines 

is based on operation philosophy, and criteria stipulated in the BAT analysis. First, there must be 

redundancy (i.e., reliance will not be placed on a single leak detection system). The technology must be 

state-of-the-art and capable of immediate detection of a sudden, large volume loss of product and detection 

of a low-threshold, chronic (pinhole) leak. The system also must be commercially available, in use on similar 

Alpine Field, Satellites, and Pipelines ODPCP 4-17 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

pipeline systems, comprised of two leak detection systems that are readily integrated with each other, and 

available from a vendor with a proven track record. 

A combination MBLPC and flow and pressure analysis automated leak detection systems, and visual 

surveillance is the most appropriate system for the Alpine crude oil transmission pipeline. The combination 

of these leak detection systems provides the ability to rapidly detect large and small volume leaks. The 

LINEGUARDTM system provides the monitoring capability of a combination MBLPC and flow and pressure 

analysis system needed for a long, high-pressure, high-flow rate production crude oil transmission pipeline 

such as the Alpine crude oil transmission pipeline. Further discussion of the leak detection methods is 

provided in Section 2.5. 

The combination of these technologies achieves a minimum leak detection threshold limit of 1% when used 

in conjunction with: 

• A proving loop for assuring meter accuracy. 

• The crude oil transmission pipeline’s selected meters, which will provide the best available 

meter accuracy (1% accuracy with repeatability of 0.02%). Currently, custody transfer meters 

measure flow upstream of the oil pipeline pumps, and flow meters measure flow immediately 

downstream of the pipeline at Central Processing Facility 2. 

• Relatively stable pump performance. 

This 1% limit, which can be provided by the selected overall leak detection system listed above for the 

Alpine crude oil transmission pipeline, meets the minimum required leak detection threshold limit of 1% of 

the oil pipeline’s daily throughput as specified by 18 AAC 75.055(a)(1). 

4.11.2 Belowground Crude Oil Transmission Pipeline 

The leak detection systems that apply to the aboveground pipeline also apply to the belowground piping. 

In addition, the annular space in the casing at the Colville River crossing is provided with conduit for leak 

detection sensors. The sensors detect fluids entering the annular space. The system is intended to detect 

oil from the carrier pipes, but the MBLPC and flow and pressure analysis automated leak detection systems 

are the primary leak detection system. The secondary system is not subject to BAT. 

The technology uses a small sensor that measures the refraction of light through the liquids. Each liquid 

has a different index of refraction, allowing the sensor to distinguish between oil and water. The sensor is 

sensitive enough to distinguish between different types of hydrocarbons. A fiber optic cable connects the 

sensor to the control panel and carries the light between the two. The system is inherently safe because 

no electrical power is used in the annulus. The sensor automatically resets and does not require removal 

after wetting. 

Alpine Field, Satellites, and Pipelines ODPCP 4-18 February 2018, Rev. 0 
TABLE 4-5: BEST AVAILABLE TECHNOLOGY ANALYSIS LEAK DETECTION IN CRUDE OIL TRANSMISSI

BAT EVALUATION 

CRITERIA 

EXISTING METHOD: 

MBLPC 

EXISTING 

METHOD 

FLOW AND 

PRESSURE 

ANALYSIS 

EXISTING 

METHOD 

VISUAL 

SURVEILLANCE 

ALTERNATE 

METHOD 

NPWM 

ALTERNATE 

METHOD 

MASS BALANCE 

(MB) 

ALTERN

METH

ACOUS

EMISSIO

MONITO

BASED 

MEASURED 

DAT

AVAILABILITY: Whether technology is best in use in other similar situations or is available for use by applicant 

MBLPC is widely used on crude oil pipelines and is commercially available. 

Technology is simple and inexpensive and is commercially available. 

Technology is very simple and available. 

NPWM is commercially available and performs best under steady-state flow conditions. It has been used on existing production oil pipelines at leak detection thresholds of 3% to 4% of daily oil throughput. 

MB has been widely used on oil pipelines. It performs best under steady-state flow conditions. However, vendors are now recommending MBLPC over MB because MBLPC offers better performance than MB. 

Acoustic emicommercially and reportedapplicable to However, the technology hbeen installecrude oil tranpipeline. 

Alpine Field, Satellites, and Pipelines ODPCP 4-19 
TABLE 4-5 (CONTINUED): BEST AVAILABLE TECHNOLOGY ANALYSIS LEAK DETECTION IN CRUDE OIL TRAN

BAT EVALUATION 

CRITERIA 

EXISTING METHOD: 

MBLPC 

EXISTING 

METHOD 

FLOW AND 

PRESSURE 

ANALYSIS 

EXISTING 

METHOD 

VISUAL 

SURVEILLANCE 

ALTERNATE 

METHOD 

NPWM 

ALTERNATE 

METHOD 

MASS BALANCE 

(MB) 

ALTERN

METH

ACOUS

EMISSIO

MONITO

BASED 

MEASURED 

DAT

TRANSFERABILITY: MBLPC is widely Technology is used Currently used. NPWM technology can MB technology is Acoustic emiWhether each used on oil on oil pipelines. be used on oil pipelines widely used on oil reportedly tra

technology is pipelines. Software Typically used as a if: pipelines. It performs to crude oil 

transferable to applicant’s operations 

is compatible with existing Supervisory Control and Data Acquisition (SCADA) systems, it requires basic pipeline 

adjunct to a line or mass balance system. Can use existing pressure or flow 

1. The oil pipeline operates in a 

steady-state mode. 

2. There is no 

batching. 

best if: 1. The oil pipeline 

operates in a steady-state mode. 

2. There is no 

transmission It performs b1. There is n

phase flow

2. There is n

parameter and configuration set-up, and it requires no maintenance. It performs best if: 

1. Transient flow 

conditions do not occur frequently. 

2. There is no multiphase flow. 3. There is no 

meters. It performs best when: 

1. Transient flow 

conditions do not occur frequently. 

2. There is no 

multi-phase flow. 

3. There is no 

3. There is no multiphase flow. 

4. There is no slackline 

flow. 

5. NPWM systems 

work best with a maximum pressure wave transducer spacing between 2 to 10 miles apart. 

6. Optimal data 

batching. 

3. There is no multiphase flow. 4. There is no 

slackline flow. 

5. Temperature 

remains constant. 

6. Pipeline is relatively 

short (on the order of 20 miles long). 

slackline f

3. Transduce

spaced alopipeline at less than 3

4. The signa

of the prodthe pipe is 

5. Backgroun

minimized filtered. 

slackline flow. slackline flow. sampling frequency 6. Large pres

of once every 6 transients seconds or less. occur freqLeak locating requires data sampling frequency of once every 0.25 seconds. Effective leak detection is dependent on the amount of pressure flow deviations in the pipeline. 

Alpine Field, Satellites, and Pipelines ODPCP 4-20 
TABLE 4-5 (CONTINUED): BEST AVAILABLE TECHNOLOGY ANALYSIS LEAK DETECTION IN CRUDE OIL TRAN

BAT EVALUATION 

CRITERIA 

EXISTING METHOD: 

MBLPC 

EXISTING 

METHOD 

FLOW AND 

PRESSURE 

ANALYSIS 

EXISTING 

METHOD 

VISUAL 

SURVEILLANCE 

ALTERNATE 

METHOD 

NPWM 

ALTERNATE 

METHOD 

MASS BALANCE 

(MB) 

ALTERN

METH

ACOUS

EMISSIO

MONITO

BASED 

MEASURED 

DAT

EFFECTIVENESS: MBLPC can detect Not a mass An effective means This method does not This method is less This method Whether there is a leaks that are 1% of balance method, of identifying a leak provide improved leak effective than MBLPC. leaks that are reasonable daily oil throughput. so there is no that can be detection over other 1% of daily thexpectation each MBLPC system calculation of leak detected either methods. Detection Identification technology will provide performance is rate. Uses visually or by threshold is elimination oincreased spill dependent on the statistical methods infrared sensors. approximately 3% to ambient and prevention or other accuracy of oil and digital signal to Sometimes leaks 4% of daily throughput operating noenvironmental benefits pipeline flow meters. identify patterns of occur that are for liquid lines and 10% essential for 

With flow meter change in pressure below the threshold to 15% of daily accurate aco

calibration, detection or flow that may limit of the leak throughput for gas assessment 

of leaks smaller than indicate presence detection system lines. detection). 

the 1% threshold can of a leak. and are spotted by 

be achieved. MBLPC can detect a 250-barrel leak over a 5-minute interval, a 600-barrel leak over a 1-hour interval, and a 1,500-barrel leak over a 24-hour interval. 

Rapid detection of significant leaks is possible. Sensitivity depends on the system’s flow stability and the location of the leak relative to the sensing devices. 

visual detection. Best when utilized in conjunction with an automated leak detection system. 

Algorithms can utilize calculated flow rates with measured flow and pressures to estimate position or location of a leak. 

COST: Approximate cost is Technology is The cost would be Minimum cost of Approximate cost is Minimum cos

The cost to the $120,000 for typically packaged based on trips to $130,000. $50,000. $90,000. applicant of achieving software and with other systems. cover the pipeline 

BAT, including support; assumes right-of-way. No 

consideration of that equipment is already up-front 

cost relative to the in place for SCADA investment. 

remaining years of and metering. service of the technology is use by the applicant. 

Alpine Field, Satellites, and Pipelines ODPCP 4-21 
TABLE 4-5 (CONTINUED): BEST AVAILABLE TECHNOLOGY ANALYSIS LEAK DETECTION IN CRUDE OIL TRAN

BAT EVALUATION 

CRITERIA 

EXISTING METHOD: 

MBLPC 

EXISTING 

METHOD 

FLOW AND 

PRESSURE 

ANALYSIS 

EXISTING 

METHOD 

VISUAL 

SURVEILLANCE 

ALTERNATE 

METHOD 

NPWM 

ALTERNATE 

METHOD 

MASS BALANCE 

(MB) 

ALTERN

METH

ACOUS

EMISSIO

MONITO

BASED 

MEASURED 

DAT

AGE AND Method is current. Method is current. Method is current. The required software The required software The required CONDITION: and hardware would be and hardware would be and hardwarThe age and condition new when installed. new when installed. new when inof technology in use by the applicant COMPATIBILITY: MBLPC is compatible Technology is Compatible NPWM is compatible MB is compatible with Acoustic emiWhether each with SCADA systems compatible with because of ready with SCADA systems. SCADA systems. compatible wtechnology is and can be combined SCADA systems access by road SCADA systcompatible with with flow and and is typically system and by 

existing operations pressure analysis. combined with aerial overflight by 

and technologies in MBLPC. aircraft. 

use by the applicant FEASIBILITY: MBLPC is routinely Technology is Method is feasible NPWM is feasible for MB is simple to Acoustic em

The practical feasibility used on relatively feasible and and routinely used. oil pipelines. It does implement on relatively reportedly tra

of each technology in short pipelines. It is appropriate to the not offer the same short pipelines to crude oil terms of engineering used on long application of effectiveness in (approximately 20 transmission and other operational pipelines when the pipeline leak detecting leaks less miles). and would thaspects pipeline is split into 

segments, each bound by flow and/or pressure meters. 

detection and leak location. Is not feasible as a method to calculate leak rate. 

than 1% of daily oil throughput. It is the least expensive system to 

install on the oil pipeline. 

feasible. 

Alpine Field, Satellites, and Pipelines ODPCP 4-22 
TABLE 4-5 (CONTINUED): BEST AVAILABLE TECHNOLOGY ANALYSIS LEAK DETECTION IN CRUDE OIL TRAN

BAT EVALUATION 

CRITERIA 

EXISTING METHOD: 

MBLPC 

EXISTING 

METHOD 

FLOW AND 

PRESSURE 

ANALYSIS 

EXISTING 

METHOD 

VISUAL 

SURVEILLANCE 

ALTERNATE 

METHOD 

NPWM 

ALTERNATE 

METHOD 

MASS BALANCE 

(MB) 

ALTERN

METH

ACOUS

EMISSIO

MONITO

BASED 

MEASURED 

DAT

ENVIRONMENTAL IMPACTS: Whether other environmental impacts of each technology, such as air, land, water pollution, and energy requirements, offset any anticipated environmental benefits 

None. Implementation of this system will significantly reduce oil loss to the environment if a leak were to occur. MBLPC is best suited to detect small, chronic leaks that fall below a threshold set under flow and pressure analysis systems. 

None. In conjunction with MBLPC, implementation of this system will significantly reduce oil loss to the environment if a leak were ever to occur. 

Visual identification adds the ability to detect small leaks. Therefore, when used as a complement to other automated leak detection systems, it provides an environmental benefit. 

With NPWM, there is only a single opportunity to detect a leak, when the leak initiates. Therefore, once the expansion wave passes the system’s monitoring locations, the opportunity for detection is gone. If this detection opportunity is missed, the environmental impact could be large. 

MB is an effective leak detection system. Implementation will significantly reduce oil loss to the environment if a leak were ever to occur. However, MBLPC offers improved performance over MB. The system requires data collection in 30 or 60 second intervals for oil lines. 

None. With trequired elimexternal ambpipeline opernoise, acousemissions is effective leak system. 

Alpine Field, Satellites, and Pipelines ODPCP 4-23 

 

 

 

 

PART 5 RESPONSE PLANNING STANDARD 

[18 AAC 75.425(e)(5)] 

5.1 STORAGE TANK RUPTURE 

The adjusted RPS volume for the oil storage tanks at Alpine is 1,320 barrels of diesel as calculated below. 

Initial RPS volume (volume capacity of the tank) 3,300 bbl 

60% adjust for secondary containment -1,980 bbl 

Adjusted RPS volume 1,320 bbl 

5.2 PRODUCTION WELL BLOWOUT [18 AAC 75.434] 

The production facility RPS volume was calculated using publicly available data from the Alaska Oil and 

Gas Conservation Commission. 

Alpine oil production data from November 1, 2015 to January 31, 2017 was reviewed to determine the 

maximum producing well. Well CD5-313 had the highest oil production rate, with an average of 9,775 bopd. 

Oil production wells at Alpine are equipped for assisted lift; however new wells (such as CD5-313) tapping 

new reservoir development areas tend to flow at high rates during the first years of production, followed by 

continuous decline as formation gas is depleted and reservoir pressure changes. The RPS volume was 

determined for a well without assisted lift, at an average rate of 10,000 bopd: 

Daily discharge rate 10,000 bopd 

Number of days x 15 days 

RPS volume 150,000 bbl 

The receiving environment is a gravel production well pad surrounded by tundra and lakes in the summer 

season, and snow and ice on frozen tundra and frozen lake surfaces in the winter season. Oil travels from 

the well in an aerial plume. 

Alpine Field, Satellites, and Pipelines ODPCP 5-1 July 2017, Rev. 0 
 

 

5.3 CRUDE OIL TRANSMISSION PIPELINE SPILL TO MILUVEACH RIVER 

[18 AAC 75.436] 

The adjusted RPS volume for a spill from the Alpine crude oil transmission pipeline at the Miluveach River 

crossing is 2,830 barrels, all of which reaches open water via a pipeline rupture directly over the river. This 

value was calculated using the following equation from 18 AAC 75.436: 

RPS volume = (L - H) * C+ FR * (TD + TSD) 

Where: 

L = pipeline length between pumping or receiving station valves; 

H = pipeline hydraulic characteristics due to terrain profile; 

C = pipeline capacity in bbl per linear measure; 

FR = pipeline flow rate in bbl per time period; 

TD = estimated time to detect a spill event; 

TSD = time needed to shut down the pipeline pump or system; 

L = 182,676 feet between valves (vertical loops meet requirement of 49 CFR 195); 

H = 179,359 feet of the pipeline that will not drain*; 

*Hydraulic gradients are determined by the linear distance between vertical loops along the pipeline. See Section 1.8 

and Table 3-2 for locations and distances between vertical loops. 

C = 0.17 bbl per linear foot of pipeline; 

FR = 69.44 bbl per minute based on a flow rate of 100,000 bbl per day; 

TD = 30 minutes; and 

TSD = 15 minutes. 

Alpine Field, Satellites, and Pipelines ODPCP 5-2 July 2017, Rev. 0 
 

 

 

 

 

Therefore: 

RPS = [(182,676 ft - 179,359 ft) x (0.17 bbl/ft)] + [(69.44 bbl/min) x (30 min + 15 min)] 

= 3,689 bbl 

RPS volume entering open water 3,689 bbl 

Less 5% prevention credit, drug and alcohol testing 

[18 AAC 75.436(c)(1)] 

(184 bbl) 

Less 5% prevention credit, on-line leak detection 

[18 AAC 75.436(c)(3)] 

(175 bbl) 

Less 15% prevention credit, smart pig system 

[18 AAC 75.436(c)(4)(B)] 

(500bbl) 

Adjusted RPS volume entering open water 2,830 bbl 

In the event of a catastrophic pipeline rupture, the Pipeline Controller would immediately detect a change 

in pipeline operating pressure while simultaneously sensing a total loss of flow at the CPF2 metering skid. 

The Alpine Pipeline would be shut in immediately. Subsequent signal verification, shutdown support, and 

field verification would follow. For planning purposes, 45 minutes is assumed for detection and shutdown 

combined, although the period may be a few minutes. 

5.4 CRUDE OIL TRANSMISSION PIPELINE SPILL TO KACHEMACH RIVER 

[18 AAC 75.436] 

The adjusted RPS volume for a spill from the Alpine crude oil transmission pipeline at the Kachemach River 

crossing is 244 barrels, all of which reach open water via a pipeline rupture directly over the river. This 

value was calculated using the following equation from 18 AAC 75.436: 

RPS volume = (L - H) * C+ FR * (TD + TSD) 

Where: 

L = pipeline length between pumping or receiving station valves; 

H = pipeline hydraulic characteristics due to terrain profile; 

C = pipeline capacity in bbl per linear measure; 

FR = pipeline flow rate in bbl per time period; 

TD = estimated time to detect a spill event; 

TSD = time needed to shut down the pipeline pump or system; 

L = 182,676 feet between valves (vertical loops meet requirement of 49 CFR 195); 

H = 181,421 feet of the pipeline that will not drain*; 

* Hydraulic gradients are determined by the linear distance between vertical loops along the pipeline. See Section 1.8 

and Table 3-2 for locations and distances between vertical loops. 

Alpine Field, Satellites, and Pipelines ODPCP 5-3 July 2017, Rev. 0 
 

 

 

 

 

 

 

 

C = 0.17 bbl per linear foot of pipeline; 

FR = 69.44 bbl per minute based on a flow rate of 100,000 bbl per day; 

TD = 1 minute; and 

TSD = 30 seconds (0.5 minute). 

Therefore: 

RPS = [(182,676 ft – 181,421 ft) x (0.17 bbl/ft)] + [(69.44 bbl/min) x (1 min + 0.5 min)] 

= 318 bbl 

RPS volume entering open water 318 bbl 

Less 5% prevention credit, drug, and alcohol testing 

[18 AAC 75.436(c)(1)] 

(16 bbl) 

Less 5% prevention credit, online leak detection 

[18 AAC 75.436(c)(3)] 

(15 bbl) 

Less 15% prevention credit, smart pig system 

[18 AAC 75.436(c)(4)(B)] 

(43 bbl) 

Adjusted RPS volume entering open water 244 bbl 

In the event of a catastrophic pipeline rupture, the Pipeline Controller would immediately detect a change 

in pipeline operating pressure while simultaneously sensing a total loss of flow at the CPF2 metering skid. 

The Alpine Pipeline would be shut in immediately. Subsequent signal verification, shutdown support, and 

field verification would follow. For planning purposes, 45 minutes is assumed for detection and shutdown 

combined, although the period may be a few minutes. 

5.5 CRUDE OIL TRANSMISSION PIPELINE SPILL TO COLVILLE RIVER 

[18 AAC 75.436] 

The adjusted RPS volume for a spill from the Alpine crude oil transmission pipeline at the Colville River 

crossing is 772 barrels, none of which reaches open water. The distance between vertical loop horizontal 

directional drilling West and the river bank is such that an aboveground pipeline rupture of this volume likely 

would not result in oil reaching the Colville River. The oil would saturate the tundra surface surrounding the 

rupture site. This value was calculated using the following equation from 18 AAC 75.436: 

RPS volume = (L - H) * C+ FR * (TD + TSD) 

Where: 

L = pipeline length between pumping or receiving station valves; 

H = pipeline hydraulic characteristics due to terrain profile; 

C = pipeline capacity in bbl per linear measure; 

Alpine Field, Satellites, and Pipelines ODPCP 5-4 July 2017, Rev. 0 
 

 

 

FR = pipeline flow rate in bbl per time period; 

TD = estimated time to detect a spill event; 

TSD = time needed to shut down the pipeline pump or system; 

L = 182,676 feet between valves (vertical loops meet requirement of 49 CFR 195); 

H = 177,372 feet of the pipeline that will not drain*; 

* Hydraulic gradients are determined by the linear distance between vertical loops along the pipeline. Value is 

calculated by subtracting the distance between Vertical loops horizontal directional drilling west and east from the total 

length between valves. See Section 1.8 and Table 3-2 for locations and distances between vertical loops. 

C = 0.17 bbl per linear foot of pipeline; 

FR = 69.44 bbl per minute based on a flow rate of 100,000 bbl per day; 

TD = 1 minute; and 

TSD = 30 seconds (0.5 minute). 

Therefore: 

RPS = [(182,676 ft – 177,372 ft) x (0.17 bbl/ft)] + [(69.44 bbl/min) x (1 min + 0.5 min)] 

= 1,006 bbl 

RPS volume entering land 1,006 bbl 

Less 5% prevention credit, drug, and alcohol testing (50 bbl) 

[18 AAC 75.436(c)(1)] 

Less 5% prevention credit, online leak detection (48 bbl) 

[18 AAC 75.436(c)(3)] 

Less 15% prevention credit, smart pig system (136 bbl) 

[18 AAC 75.436(c)(4)(B)] 

Adjusted RPS volume entering land 772 bbl 

RPS volume entering open water 0 bbl 

In the event of a catastrophic pipeline rupture, the Pipeline Controller would immediately detect a change 

in pipeline operating pressure while simultaneously sensing a total loss of flow at the CPF2 metering skid. 

The Alpine Pipeline would be shut in immediately. Subsequent signal verification, shutdown support, and 

field verification would follow. For planning purposes, 45 minutes is assumed for detection and shutdown 

combined, although the period may be a few minutes. 

Alpine Field, Satellites, and Pipelines ODPCP 5-5 July 2017, Rev. 0 

APPENDIX A 

FEDERAL RESPONSE PLANS 

OIL POLLUTION ACT OF 1990 ADDENDUM 

U.S. DEPARTMENT OF TRANSPORTATION 

U.S. ENVIRONMENTAL PROTECTION AGENCY 

AND 

U.S. DEPARTMENT OF THE INTERIOR BUREAU OF LAND MANAGEMENT 
BLANK PAGE 
U.S. Department

of Transportation

1200 New Jersey Avenue, S.E.

Washington, D C. 20590

Pipeline and Hazardous

Materials Safety Administration

September 11, 2017

Jeanie Shifflet

ConocoPhillips Alaska, Inc.

700 G Street

Anchorage, AK 94510-0360

RE: LETTER OF APPROVAL: Alpine Development Participating Area North Slope, Alaska

Oil Discharge Prevention and Contingency Plan, Sequence Number: 1476, June 2017

Dear Ms. Shifflet:

The Pipeline and Hazardous Materials Safety Administration (PHMSA) has received and reviewed

ConocoPhillips Alaska, Inc.’s amended Alpine Development Participating Area North Slope, Alaska Oil

Discharge Prevention and Contingency Plan dated June 2017. We conclude that the plan complies with

PHMSA’s regulations concerning onshore oil pipelines found at 49 Code ofFederal Regulations (CFR)

Part 194. Your Response Plan is approved.

This approval is valid for Five years from the date ofthis letter. If discrepancies are found during PHMSA

inspections, or ifnew or different operating conditions or information would substantially affect the

implementation ofthis plan, you will be required to resubmit a revised plan. See 49 CFR § 194.121(b).

Should you have any questions or concerns, please contact me at (202) 366-4595 or by email at

PHMSA.QPA90@dot.gov. Please include the sequence number and your PHMSA Operator

Identification Number on any future correspondence.

Sincerely,

David K. Lehman, Director

Oil Spill Preparedness and Emergency Support Division

Office of Pipeline Safety

PHMSA Western Region

Alpine Field, Satellites, and Pipelines ODPCP A-1 February 2018, Rev. 0
BLANK PAGE 

Alpine Field, Satellites, and Pipelines ODPCP A-1 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

U.S. DEPARTMENT OF TRANSPORTATION 

ALPINE PIPELINE SYSTEM 

RESPONSE PLAN 

CROSS REFERENCE TO 

[49 CFR 194, Subpart B] 

REGULATION 

SECTION 

(49 CFR) 

SECTION TITLE ODPCP PLAN SECTION 

194.103 Significant and substantial harm; operator’s statement 

(a) Identification of line sections that might cause significant and substantial harm 

to the environment in the event of a discharge 

p. A-6, Section 2.3, Table 

2-6, Section 3.1.4 

(b) Response zone(s) considered to cause significant and substantial harm to the 

environment in the event of a discharge. 

p. A-6 

(c) Significant and substantial harm criteria. p. A-6 

194.105 Worst case discharge 

(a) The worst case discharge (WCD) and the methodology, including 

calculations, used to arrive at the volume 

p. A-7 

(b)(1) Pipeline release WCD p. A-7, Sections 1.6, 5.3, 

5.4, and 5.5 

(b)(2) Historical discharge WCD p. A-7 

(b)(3) Largest breakout tank WCD p. A-7; Alpine does not 

operate a breakout tank 

(b)(4) Secondary containment prevention credits for breakout tank WCD. Not applicable 

194.107 General response plan requirements 

(a) Resources for responding, to the maximum extent practicable, to a worstcase discharge and to the substantial threat of such a discharge p. A-4, A-8, Sections 1.5, 

1.6, and 3.6 

(b)(1) Certification that the response plan is consistent with the NCP p. A-5 

(b)(1)(i) Demonstrate an operator’s clear understanding of the function of the Federal 

response structure, including procedures to notify the National Response 

Center reflecting the relationship between the operator’s response 

organization’s role and the Federal On Scene Coordinator’s role in pollution 

response; 

Sections 1.1, 1.2, and 3.3 

(b)(1)(ii) Establish provisions to ensure the protection of safety at the response site; 

and 

Section 1.3 

(b)(1)(iii) Identify the procedures to obtain any required Federal and State permissions 

for using alternative response strategies such as in-situ burning and 

dispersants as provided for in the applicable ACPs; and 

COPA does not consider 

the use of dispersants in 

this FRP. Information for insitu burning is provided in: 

Sections 1.7 and 3.7 

(b)(2) As a minimum, to be consistent with the applicable ACP the plan must --

(b)(2)(i) Address the removal of a worst case discharge and the mitigation or 

prevention of a substantial threat of a worst case discharge; 

Sections 1.6 and 3.6 

(b)(2)(ii) Identify environmentally and economically sensitive areas; Sections 1.6 and 3.10 

(b)(2)(iii) Describe the responsibilities of the operator and of Federal, State and local 

agencies in removing a discharge and in mitigating or preventing a 

substantial threat of a discharge; and 

Sections 1.1, 1.2, 1.6, 2.1, 

2.3, 2.4, 2.5, 3.3, 3.6, 3.7, 

3.9, and 3.10 

(b)(2)(iv) Establish the procedures for obtaining an expedited decision on use of 

dispersants or other chemicals. 

Not applicable. COPA does 

not consider use of 

dispersants in this FRP 

(c)(1)(i) Information Summary as required by 194.113 p. A-6 

(c)(1)(ii) Immediate notification procedures Sections 1.1, 1.2, and 3.3 

(c)(1)(iii) Spill detection and mitigation procedures Sections 2.1.8 and 2.5 

Alpine Field, Satellites, and Pipelines ODPCP A-1 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CROSS REFERENCE TO 

[49 CFR 194, Subpart B] 

REGULATION 

SECTION 

(49 CFR) 

SECTION TITLE ODPCP PLAN SECTION 

(c)(1)(iv) Name, address, telephone number of oil spill response organization Section 3.8 

(c)(1)(v) Response activities and response resources p. A-4, A-8, Sections 1.1, 

1.2, 1.5, 3.3, and 3.6 

(c)(1)(vi) Names and telephone numbers of federal, state, and local agencies with 

pollution control responsibilities or support 

Section 1.2; Table 1-2 

(c)(1)(vii) Training procedures Sections 2.1.1 and 3.9 

(c)(1)(viii) Equipment testing Section 3.6.3 

(c)(1)(ix) Drill types, schedules, and procedures Section 3.9.6 

(c)(1)(x) Plan review and update procedures Introduction 

(c)(2) Response zone appendices Not applicable, entire 

pipeline is a single 

response zone 

(c)(3) Description of response management organization, span of control, clear 

chain of command, and trained response personnel. 

Sections 3.3 and 3.9 

194.109 Submission of state response plans. 

(b)(1) A plan submitted under this section must have an information summary 

required by §194.113; 

p. A-6 

(b)(2) List the names or titles and 24-hour telephone numbers of the qualified 

individual(s) and at least one alternate qualified individual(s); and 

p. A-6 

(b)(3) Ensure through contract or other approved means the necessary private 

personnel and equipment to respond to a worst case discharge or a 

substantial threat of such a discharge. 

Section 3.8 

194.113 Information Summary 

(a)(1) Name and address of operator p. A-6 

(a)(2) Listing and description of response zones p. A-6 

(b) The information summary for the response zone appendix.... Not applicable. 

Refer to 194.107(c)(1)(i) 

through 194.107(c)(1)(x) in 

this cross-reference. 

194.115 Response Resources 

(a) Identify and ensure, by contract or other approved means the recourses 

necessary to remove, to the maximum extent practicable, a WCD and to 

mitigate or prevent a substantial threat of a WCD. 

Sections 1.5, 1.6, 3.6, 3.8, 

and 3.9 

(b) Identify the response resources which are available to respond within the time 

specified, after discovery of a worst case discharge, or to mitigate the 

substantial threat of such a discharge as follows: Tier 1 – 12 hrs; Tier 2 – 36 

hrs; and Tier 3 – 60 hrs. 

Sections 1.5, 1.6, 3.6, and 

3.9 

194.117 Training 

(a)(1) All personnel know: 

(a)(1)(i) Their responsibilities under the response plan, Sections 2.1.1 and 3.9 

(a)(1)(ii) and 

(iii) 

Name and address of, and the procedure for contacting, the operator...(and) 

the qualified individual on a 24-hour basis. 

p. A-6, Sections 1.1 and 

3.3 

(a)(2) Reporting personnel know: 

(a)(2)(i) Content of the information summary of the response plan, Sections 2.1.1 and 3.9 

(a)(2)(ii) The toll-free number for the National Response Center, Section 1.2 

(a)(2)(iii) The notification process; and Section 1.2 

Alpine Field, Satellites, and Pipelines ODPCP A-2 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

CROSS REFERENCE TO 

[49 CFR 194, Subpart B] 

REGULATION 

SECTION 

(49 CFR) 

SECTION TITLE ODPCP PLAN SECTION 

(a)(3) Personnel engaged in response activities know: 

(a)(3)(i) Characteristics and hazards of the oil discharged, Section 3.10.1 

(a)(3)(ii) Conditions that are likely to worsen emergencies, including the consequences 

of facility malfunctions or failures, and the appropriate corrective action. 

Section 3.4, Section 3.9 

(a)(3)(iii) Steps necessary to control any accidental discharge of oil and to minimize the 

potential for fire, explosion, toxicity, or environmental damage, and 

Sections 1.1, 1.3, and 1.6 

(a)(3)(iv) Proper firefighting procedures and use of equipment, fire suits, and breathing 

apparatus. 

Sections 1.6 and 3.9.4 

(b) Maintain a training record for each individual that has been trained as 

required by this section and maintain the records in the following manner as 

long as the individual has responsibility under the response plan: 

Sections 2.1.1 and 3.9.5 

(b)(1) Records for operator personnel must be maintained at the operator’s 

headquarters; and 

Sections 2.1.1 and 3.9.5 

(b)(2) Records for personnel engaged in response, other than operator personnel, 

shall be maintained as determined by the operator. 

Sections 2.1.1 and 3.9.5 

(c) Nothing in this section relieves the operator from the responsibility to ensure 

that all response personnel are trained to meet the OSHA standards for 

emergency response operations. 

Section 3.9 

195.440 Public Awareness p. A-8 

Alpine Field, Satellites, and Pipelines ODPCP A-3 February 2018, Rev. 0 
U.S. DOT CERTIFICATION OF RESPONSE PREPAREDNESS

CONOCOPHILLIPS ALASKA

ALPINE PIPELINE SYSTEM

U.S. Department of Transportation

Pipeline and Hazardous Materials Safety Administration

Office of Pipeline Safety

1200 New Jersey Ave, SE

Washington, DC 20590

ConocoPhillips Alaska hereby certifies to the Pipeline and Hazardous Materials Safety Administration of

the U.S. Department of Transportation that it has identified, and ensured by contract, or other means to be

approved by the Pipeline and Hazardous Materials Safety Administration, the availability of private

personnel and equipment to respond, to the maximum extent practicable, to a worst case discharge or a

substantial threat of such a discharge.

 

Scott Collins or Philip Susen

Superintendent, DOT Pipelines

ConocoPhillips Alaska

Date

Alpine Field, Satellites, and Pipelines ODPCP A-4 February 2018, Rev. 0
U.S. DOT NCP / ACP CONSISTENCY CERTIFICATION

ALPINE PIPELINE SYSTEM

ConocoPhillips Alaska hereby certifies to the Pipelines and Hazardous Materials Safety Administration of

the U.S. Department of Transportation that it has reviewed the National Contingency Plan (NCP) and 

applicable area contingency plan (ACP) and found the Oil Discharge Prevention and Contingency Plan for

the Alpine Field and Satellites and Alpine Pipeline System to be consistent with them. The NCP/ACP

reviewed includes the NCP developed under 40 CFR Part 300 known as The Alaska Federal and State

Preparedness Plan forResponse to Oil and Hazardous Substance Discharges and Releases (Unified Plan), 

and the North Slope Subarea Contingency Plan.

 

Scott Collins or Philip Susen

Superintendent, DOT Pipelines

ConocoPhillips Alaska

-2/28/2018

Date

Alpine Field, Satellites, and Pipelines ODPCP A-5 February 2018, Rev. 0
 

 

 

 

 

 

 

 

 

U.S. DEPARTMENT OF TRANSPORTATION INFORMATION SUMMARY 

NAME AND ADDRESS OF OPERATOR 

ConocoPhillips Alaska Street Address: 

P.O. Box 100360 700 G Street 

Anchorage, AK 99510-0360 Anchorage, AK 99510-0360 

Phone: (907) 265-6150 (Security emergency line) 

RESPONSE ZONE DESCRIPTION 

The Alpine Pipeline System, located in the North Slope Borough, Alaska, consists of a single response 

zone containing a product transportation system, consisting of an onshore pipeline. For purposes of this 

plan, all the pipelines within the Alpine Pipeline System under the jurisdiction of 49 CFR 149 are considered 

to be one line section and, therefore, in one response zone. 

The Alpine pipelines have individual numbered vertical support members (VSMs) that can be used to 

identify specific line segments, if necessary. 

NAME AND TELEPHONE NUMBER OF QUALIFIED INDIVIDUAL 

Qualified Individual: Alternate: 

Manager, Western North Slope Operations Superintendent, Operations & Maintenance 

Misty Alexa Mike Lyden/Glynn Jones 

(907) 670-4024 (907) 670-4021 

COPA Security maintains 24-hour contact numbers for the Qualified Individual and alternates. Security can 

be reached in Anchorage at (907) 265-6150 or at Alpine at (907) 670-4900. 

BASIS OF DETERMINATION OF SIGNIFICANT AND SUBSTANTIAL HARM 

As stated in 49 CFR 194.103(c), a line section can be expected to cause significant and substantial harm 

to the environment in the event of a discharge of oil into or on the navigable waters or adjoining shorelines 

if; the pipeline is greater than 6 5⁄8 inches in outside nominal diameter, greater than 10 miles in length, and

the line section is located within a 1 mile radius of potentially affected environmentally sensitive areas, and 

could reasonably be expected to reach these areas. 

The crude oil transmission pipeline has a nominal diameter of 14 inches and is 34.2 miles in length. In 

addition, the pipeline traverses tundra and crosses three rivers, two of which are aboveground and the 

Colville River crossing, which is the only underground portion of the pipeline. 

Line segments are described in ODPCP Table 2-5 and Section 3.1.4. 

Alpine Field, Satellites, and Pipelines ODPCP A-6 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

TYPE OF OIL AND VOLUME OF WORST CASE DISCHARGE 

The type of oil transported in the DOT-regulated pipeline at Alpine is sales quality crude oil. The worst-case 

discharge (WCD) for Alpine would occur from a rupture of the pipeline between the pig receiver at Kuparuk 

Central Processing Facility #2 (CPF2) and the vertical loop1 (#5) nearest CPF2 on the east side of the 

Miluveach River. The WCD volume includes the entire volume of the pipeline segment between CPF2 and 

vertical loop #5 in addition to the throughput volume lost during 45 minutes before shutdown. 

Weather conditions do not affect the pipeline shutdown time (see calculation below). If the emergency 

shutdown system fails, manual shutdown valves are located inside at the Alpine Central Facility (CD1) and 

at CPF2. These facilities are staffed 24 hours a day. 

In accordance with 49 CFR 194.105(b)(1), the WCD for the pipeline is equal to the pipeline's maximum 

release time (RTmax) in hours, plus the maximum shutdown response time (STmax) in hours, multiplied by 

the maximum flow rate (Fmax) expressed in barrels per hour (bph) (based on maximum daily capacity of the 

pipeline), plus the largest pipeline drainage volume (PVmax) after shutdown of the line section(s) in the 

response zone expressed in barrels (bbl) or: 

WCD = [(RTmax + STmax) * Fmax] + PVmax 

Where: 

RTmax = 0.5 hours (30) 

STmax = 0.25 hours (15 minutes) 

Fmax = 4,167 bph2 

PVmax = 9,306 bbl3 

Therefore, the DOT WCD is: 

[(0.5 hrs + 0.25 hrs) x 4,167 bph] + 9,306 bbl = 12,431 bbl of oil 

There is no breakout tank in the Alpine operational area / response zone and therefore no WCD for a 

breakout tank is provided. 

Consideration of the maximum historical discharge for WCD calculations is not applicable. 

RESOURCES TO RESPOND TO A WORST CASE DISCHARGE 

Sufficient resources are available to respond to a potential WCD or a threat of such a discharge. The WCD 

calculations are based on the longest portion of the DOT-regulated pipeline at Alpine, which is located 

between the pig receiver at CPF2 and the vertical loop #5 on the east side of the Miluveach River (Figure 

1-10). This portion of pipeline is within 2 miles of the Kuparuk road system. 

Information regarding specific tactics and equipment that would be utilized during a WCD is provided in the 

Alaska Clean Seas (ACS) Technical Manual, Volume 1, Tactics Descriptions. Off-pad spill response tactics 

1 Vertical loops perform the same function as check valves without the hydraulic inefficiencies and 

maintenance concerns associated with check valves. The loops meet the requirements of 49 CFR 195. 

2 Calculated at 100,000 bbls per day throughput 

3 ID of pipe = 13.376 inches (r = 0.56 foot) 

Distance between valve and vertical loop = 54,741 feet 

Design Pipe Capacity = 0.17 bbl/linear foot: PVmax = (0.17 bbl/lin. ft.)(54,741 ft.) = 9,306 bbls 

Alpine Field, Satellites, and Pipelines ODPCP A-7 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

are also detailed in Scenarios 1 through 3 in Section 1.6.3 of this plan. The scenarios include a pipeline 

discharge to the Miluveach River. 

Section 1.1 of the ODPCP describes immediate response and notification actions, which include notification 

of ACS. The on-site personnel are the initial responders to spills at Alpine. SRT members will respond 

promptly upon notification. The estimated response time from discovery of a spill to the deployment of 

equipment varies depending on the location, pre-planning, logistical support, and available information. 

This section also contains additional information including seasonal transportation options. 

Spill response equipment and supplies are available throughout the North Slope for immediate deployment. 

Equipment is pre-deployed at the CPFs, along the Kuparuk and Miluveach Rivers, and along the coastline. 

Spill response and/or pre-staged equipment at CPF1 pad can be rapidly deployed via the Kuparuk road 

system. Off-road oil spill recovery operations can be conducted by Rolligons, Centaurs®, 6-wheelers, and 

4-wheelers available to COPA and ACS, the primary oil spill removal organization (OSRO). Infrastructure 

and pre-staged equipment along the portion of pipeline subject to a potential WCD is illustrated in the ACS 

Technical Manual, Volume 2, Map Atlas Sheets 26, 29, 53, and 54. Boom is seasonally pre-deployed at 

both the Miluveach River and Kalubik Creek, which intersect the portion of pipeline subject to a potential 

WCD. 

Spill-tracking equipment includes fixed wing aircraft equipped with a Forward-Looking Infrared (FLIR) 

System for aerial surveillance of released oil or temperature anomalies that could be indicative of a pipeline 

leak. Hand-held sensors are also available. 

Waste disposal information is contained in the Alaska Waste Disposal and Reuse Guide (aka the Red 

Book). Released fluids can be recovered and transferred via vacuum truck, or Rolligon with tanks, to the 

CPF1 hydrocarbon recycle facility or water recycle facility. Oiled gravel storage is located within the Kuparuk 

road system at drill site 1H. Temporary lined containment cells can be constructed at other locations. 

CERTIFICATION OF RESPONSE PERSONNEL AND EQUIPMENT 

Sufficient response personnel and equipment are available to respond to a WCD or threat of such a 

discharge. The information is provided in Sections 1.6.3, Spill Response Scenarios; 3.5, Logistical Support; 

3.6, Response Equipment; and 3.8, Response Contractor Information. 

PUBLIC AWARENESS 

COPA is committed to public safety and environmental protection and maintains a public awareness 

program for COPA-operated DOT-regulated pipelines, in accordance with DOT regulations. COPA 

periodically provides information to the public via the Hazardous Liquids Pipeline Guide for Emergency and 

Public Officials and related summary bulletins; a copy of the summary bulletin is provided on pages A-9 

and A-10. 

Alpine Field, Satellites, and Pipelines ODPCP A-8 February 2018, Rev. 0 
SAFETY IS OUR TOP PRIORITY

Important Information

about

Pipeline

Safety

At ConocoPhillips Alaska Inc., we are committed to

operating our North Slope pipelines safely. We are

dedicated to the protection ofour employees, the public

and the environment within the Alpine, Kuparuk and

Oliktok pipelme areas.

We want to enhance the continued safe operations of

these pipelines, so we invited you to read this brochure

to increase pipeline safety awareness. Ifyou have any

questions or concerns please contact us:

NORTH SLOPE TRANSPORTATION PIPELINES

Pipelines remain the safest and most reliable method of

transporting energy products from the production

location to market and the consumer.

We operate, along with our partners, more than 16S

miles of transportation pipelines on the North Slope. The

U.S. Department of Transportation, Office ofPipeline

Safety, regulates appioximately BO miles ofthese

pipelines They extend from the Alpine Facilities to the

Trans Alaska Pipeline System (see Figure 1).

The Alpine Oil Pipeline transports sales-quality crude oil

from the Colville River Unit to the Kuparuk Pipeline at

CPF2. The Kuparuk Pipeline transports Colville River Unit.

Kuparuk River Unit, Milne Point Unit and ENI sales quality

crude tothe Trans Alaska Pipeline System, connecting at

PumpStation 1. A breakout tankis located at CPF2 to

provide relief or storage during periods of pipeline upset,

proration or maintenance. The Alpine Arctic Heating Fuel

Pipeline transports refined petroleum products and the

Alpine Utility Pipeline transports treated seawater from

CPF2 to the Alpine Facilities. The Oliktok Pipeline

transports natural gas from the Prudhoe Bay Unit to

CPFl The Kupaiukand Oliktok Pipelines parallel die

Spine Road for much of its route.

POTENTIAL HAZARDS

While rare, a leak from a transportation pipeline,

depending on what the line is carrying at the lime, could

create breathing hazards for nearby habitants, starta fire

or explosion, damage the environment, or injure piarits

and animals A leak resulting in an explosion or a fire,

inadvertently triggered by vehicles, equipment, or

people, increases the risk of potential damage.

PREVENTIVE MEASURES

At ConocoPhillips, we are accountable for the safe and

efficient operations ofour pipelines. We monitor and

operate the pipeline systems using state-of-the-art

operations control centers, 24 hours a day, 365 days a year.

In case ofan emergency, our control centers can shut

down the pipelines, greatly reducing potential hazards.

Additionally, to ensure prpeline integrity, we implement a

variety ofprograms, procedures, and systems, including

• Ensuring pipeline design, construction, operation and

maintenance adhere to federal, state and local codes,

regulations and statutes.

• Enforcing aggressive arid proactive maintenance

programs, such as pipe inspection programs that

utilize state-of-the-art tools.

• Using automated, computer-based, around-the-clock

pipeline monitoring.

• Conducting routine air and/or ground surveillance.

• Setting up checkpoints along the pipelme route to

enhance security when required.

PIPELINE SIGNAGE

We've attached signage to the North Slope transmission

pipelines toenhance identification ofthe transportation

pipelines and to provide emergency contact information

(see Figure 21

Pipeline signage provides important safety information

and it is a fede/al crime for any person to willfully deface,

damage, remove, or destroy any pipeline sign or

right-of-way marker required by federal law. The penalty

tor each offense is a fine of up to $5,000, imprisonment

for not more than one year, or both.

Figure 2 - Example of Pipeline Signage

 

 

Alpine DOT Compliance Specialist______(907) 670 -4224

Kuparuk DOT Compliance Specialist(907) #59-7574 November 2014

Alpine Field, Satellites, and Pipelines ODPCP A-9 February 2018, Rev. 0
TO ENSURE YOUR SAFETY

To help ensure your safety and prevent pipeline damage,

please do not:

• Operate equipment near pipelines without permission.

■ Dig near pipelines without permission.

• Shoot in the direction ofthe pipelines.

• Climb, walk on, or tie anything to the pipelines.

If you observe any unusual activities taking place near

the pipelines, please contact us immediately by the

appropriate emergency phone number on the back of

this brochure.

HOWTO RECOGNIZE A LEAK

BySight: A pipeline product on the ground near a

pipeline, a dense white cloud or fog over a pipeline, or

discolored vegetation surrounding the pipeline may be

signs of a leak.

BySound: An unusual noise coming from the pipeline,

such as hissing or roaring, may be a sign of a leak.

By Smet/: An unusual odor may accompanya pipeline leak

(e.g,, pungent hydrocarbon, kerosene, gasoline-like,etc).

IF YOU SUSPECT OR DISCOVER A LEAK

• Do not touch, breathe, or make contactwith

leaking liquids.

■ Do not light a match, start an engine, use a telephone

or cell phone, switch on/offlight switches, or do

anything that may create a spark.

■ Do not drive into a leak or vapor cloud area.

• Turn off running motors or other ignition sources.

• Immediately leave the area in an upwind direction.

• Warn others!,

• From a safe location, call us as soon as possible by the

appropriate emergency phone number listed on the

back ofthis brochure. Please provide your name,

phone number, a description ofthe leak or spill and

its location.

- Contact the Nuiqsut Public Safety Department and Fire

Department by the emergency phone numbers listed

on the back ofthis brochure.

WHAT HAPPENS WHEN YOU REPORT A LEAK OR

UNUSUAL ACTIVITY

AtConocoPhillips, we take immediate action to stop the

leak, contain, and dean up the spill by following

approved Discharge Response and Contingency Plans.

Our response to reported leaks also indudes notifying

the appropriate federal, state and local authorities.

We immediately investigate all reported unusual activity

near pipelines and take action as appropriate,

FOR MORE INFORMATION

• ConocoPhillips Alaska, Inc.

P.O. Box 196105

Anchorage, AK 99519-61105

(907) 276-H215

• Pipeline Safety Information

http://primis.phmsa.dat.gov/cornm/lndex.htm

Website provides stakeholder communications to

facilitate pipeline safety.

• Nationa I PipeI ine Mapping System

http://www.npms.phmsa.dot.gov/

Website provides maps within a specific:zip code and

information regarding the product transported and

identification ofthe pipeline operator.

 

 

 

 

 

 

INCASE IF EMERGENCY,CALL

ConocoPhiHips Alaska, Inc.

- Alpine...............................................(907) 670-4900 or911

• Kuparuk...........................................(907) 659-7300 or 911

COLLECTCALLS WILL BE ACCEPTED.

Village of Nuiqsut

• PublicSafety............................................... (907)430-6911

• Fire Department...............................................................911

Iftravelling through the Kuparuk field, you may chose to

report leaks or other safety concerns at the Seawater

Treatment Plant (STP), CPF2, CPF3, or the Kuparuk Office

Complex (KOCX

 

Alpine Field, Satellites, and Pipelines ODPCP A-10 February 2018, Rev. 0
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY

REGION 10

222 West 7th Avenue, Room 537, Box 19

Anchorage, Alaska 99513-7588

December 12, 2017

Jeanie Shifflett, Emergency Planning Coordinator

ConocoPhillips Alaska, Inc.

Health, Safety & Environmental

P.O. Box 100360

Anchorage, Alaska 99510-0360

RE: Review ofFRPAKA0236, Alpine Field and Satellites and Alpine Pipeline System, Western

North Slope, Alaska

Dear Ms. Shifflett:

Pursuant to the Clean Water Act, 33 U.S.C. Section 1321 (j)(5), as amended by the Oil Pollution

Act of 1990, the United States Environmental Protection Agency (U.S. EPA) has reviewed your

Facility Response Plan (FRP) and finds that it meets the requirements of Section 311 (j)(5) ofthe

Clean Water Act and 40 CFR 112.20(c)(4). Your FRP is approved for 5 years until December

12,2022.

Note that, pursuant to 40 CFR 112.20(d)(1), the owner or operator of a facility for which a

response plan is required shall revise and resubmit revised portions ofthe response plan to U.S.

EPA within 60 days of each facility change that may materially affect the response to a worst

case discharge. Changes which may require revisions to a response plan include:

• a change in the facility’s configuration;

• a change in the type ofoil handled, stored or transferred;

• a change in the capabilities ofthe oil spill response organization;

• a change in the facility’s spill prevention and response equipment or emergency response

procedures; and

• any other change that materially affects the implementation ofthe response plan.

In addition, 40 CFR Section 112.20(d)(2) provides that changes in personnel and telephone

number lists included in an FRP do not require U.S. EPA approval, but should be supplied to

U.S. EPA as the revisions occur.

If you have questions regarding this correspondence, please contact me at 907-271-3247 or

Vivian Melde at 907-257-5000, ext. 3305.

Sincerely,

Robert S. Whittier, Jr.

On Scene Coordinator (OSC)

Emergency Preparedness and Prevention Unit

Alpine Field, Satellites, and Pipelines ODPCP A-11 February 2018, Rev. 0
BLANK PAGE 

Alpine Field, Satellites, and Pipelines ODPCP A-12 February 2018, Rev. 0 
 

 

 

 

 

 

U.S. ENVIRONMENTAL PROTECTION AGENCY 

ALPINE FIELD AND SATELLITES 

FACILITY RESPONSE PLAN FRPAKA0236 

CROSS REFERENCE 

[40 CFR 112, APPENDIX F] 

REGULATION 

SECTION 

(APPENDIX F) 

SECTION TITLE PLAN SECTION 

1.1 Emergency Response Action Plan [112.20(h)(1)] 

1.1.1 Qualified Individual Information p. A-18 

1.1.2 Emergency Notification Phone List Table 1-2 

1.1.3 Spill Response Notification Form Figure 1-2 

1.1.4 Response Equipment List and Location Section 3.6 

1.1.5 Response Equipment Testing and Deployment Sections 1.5 and 3.6.3 

1.1.6 Facility Response Team Sections 1.2, 3.3, 3.9 

1.1.7 Evacuation Plan Section 1.1 and Introduction 

Supplemental Documentation 

1.1.8 Immediate Actions Section 1.1 

1.1.9 Facility Diagram Section 1.8 

1.2 Facility Information [112.20(h)(2)] 

1.2.1 Facility Name and Location p. A-15 and A-18 

1.2.2 Latitude and Longitude p. A-15 and A-18 

1.2.3 Wellhead Protection Area Not applicable 

1.2.4 Owner/Operator p. A-18 

1.2.5 Qualified Individual p. A-18 

1.2.6 Date of Oil Storage Start-up p. A-18 

1.2.7 Current Operation p. A-15, Section 3.1.1 

1.2.8 Dates and Type of Substantial Expansion p. A-18 

1.3 Emergency Response Information [112.20(h)(3)] 

1.3.1 Notification Sections 1.2 and 3.3 

1.3.2 Response Equipment List Section 3.6.1 

1.3.3 Response Equipment Testing/Deployment Sections 1.5 and 3.6.3 

1.3.4 Personnel Sections 1.5, 3.3, and 3.8 

1.3.5 Evacuation Plans Section 1.1 and Introduction 

Supplemental Documentation 

1.3.6 Qualified Individual's Duties Section 1.2 and 3.3 

1.4 Hazard Evaluation [112.20(h)(4)] 

1.4.1 Hazard Identification Sections 2.1.4, 2.1.6, 2.1.7, 2.1.8, 

2.2, 2.3, 2.4, and 2.5; Alpine Spill 

Prevention, Control, and 

Countermeasure Plan 

1.4.2 Vulnerability Analysis Section 3.10 and p. A-19 

1.4.3 Analysis of the Potential for an Oil Spill Sections 2.3 and 2.4 

1.4.4 Facility Reportable Oil Spill History Section 2.2 and pp. A-25 to A-39 

1.5 Discharge Scenarios [112.20(h)(5)] 

1.5.1 Small and Medium Discharges Section 1.6.3 

1.5.2 Worst Case Discharge p. A-20, Section 1.6.3 

Alpine Field, Satellites, and Pipelines ODPCP A-13 February 2018, Rev. 0 
 

 

CROSS REFERENCE 

[40 CFR 112, APPENDIX F] 

REGULATION 

SECTION 

(APPENDIX F) 

SECTION TITLE PLAN SECTION 

1.6 Discharge Detection Systems [112.20(h)(6)] 

1.6.1 Discharge Detection by Personnel Sections 1.1, 2.1.7, 2.1.8, and 2.5 

1.6.2 Automated Discharge Detection Section 2.5 

1.7 Plan Implementation [112.20(h)(7)] 

1.7.1 Response Resources for Small, Medium and Worst-Case Spills Sections 1.5, 1.6.3, 3.5, 3.6, 3.7, 

3.8, and 3.9 

1.7.2 Disposal Plans Sections 1.6.2 and 1.6.3 

1.7.3 Containment and Drainage Planning Sections 1.6, 1.8, 2.1.10, and 3.1 

1.8 Self Inspection, Drills/Exercises, and Response Training 

[112.20(h)(8)] 

1.8.1 Facility Self-Inspection Sections 2.1.4, 2.1.7, 2.1.8, 2.1.9, 

3.1, 3.6.3, and 3.9.6 

1.8.1.1 Tank Inspection Sections 2.1.9 

1.8.1.2 Response Equipment Inspection Section 3.6.3 

1.8.1.3 Secondary Containment Inspection Section 2.1.10 

1.8.2 Facility Drills/Exercises Section 3.9.6 

1.8.2.1 Qualified Individual Notification Drill Logs Section 3.9.6 

1.8.2.2 Spill Management Team Tabletop Exercise Logs Section 3.9.6 

1.8.3 Response Training Section 3.9 

1.9 Diagrams [112.20(h)(9)] Section 1.8 

1.10 Security [112.20(h)(10)] Section 2.1.4 

2.0 Response Plan Cover Sheet [112.20(h)(11)] 

2.1 General Information p. A-15 

2.2 Applicability of Substantial Harm Criteria p. A-16 

2.3 Certification p. A-17 

3.0 Acronyms p. xii 

Alpine Field, Satellites, and Pipelines ODPCP A-14 February 2018, Rev. 0 
 

U.S. ENVIRONMENTAL PROTECTION AGENCY 

RESPONSE PLAN COVER SHEET 

PAGE 1 OF 3 

GENERAL INFORMATION 

Owner/Operator of Facility: ConocoPhillips Alaska 

Facility Name: Alpine Field and Satellites and Alpine Pipeline System 

Facility Address: The Alpine Field and Satellites area is within the Western North Slope of Alaska 

(Mailing address) 700 G St., P.O. Box 100360 Anchorage, AK 99510-0360 

Facility Phone No.: (907) 276-1215 

Latitude (Degrees: North): N 70 degrees, 20 minutes, 40 seconds 

Longitude (Degrees: West): W 150 degrees, 55 minutes, 30 seconds 

Dun & Bradstreet Number: 118819478 

Standard Industrial Classification (SIC) Code: 1330 

Largest Above-ground Oil Storage Tank Capacity (Gallons): 138,600 

Maximum Oil Storage Capacity (Gallons): 1,346,908 

Number of Above-ground Oil Storage Tanks: 732 (stationary bulk storage containers [includes flowthrough process vessels], portable bulk storage 

containers, and oil-filled operational equipment) 

Worst Case Oil Discharge Amount (Gallons): 

Facility Distance to Navigable 

Water: 

7,566,762 

0-1/4 mile 1/4-1/2 mile 1/2-1 mile >1 mile 

(mark the appropriate distance) 

Alpine Field, Satellites, and Pipelines ODPCP A-15 February 2018, Rev. 0 
 

 

 

 

 

U.S. ENVIRONMENTAL PROTECTION AGENCY 

RESPONSE PLAN COVER SHEET 

PAGE 2 OF 3 

APPLICABILITY OF SUBSTANTIAL HARM CRITERIA 

Facility Name: Alpine Field and Satellites and Pipeline System. 

Does the facility transfer oil over water to or from vessels and does the facility have a total oil storage 

capacity greater than or equal to 42,000 gallons? 

Yes 

No X 

Does the facility have a total oil storage capacity greater than or equal to 1 million gallons and does the 

facility lack secondary containment that is sufficiently large to contain the capacity of the largest aboveground oil storage tank plus sufficient freeboard to allow for precipitation within any above-ground oil 

storage tank area? 

Yes 

No X 

Does the facility have a total oil storage capacity greater than or equal to 1 million gallons and is the facility 

located at a distance (as calculated using the appropriate formula in Appendix C or a comparable formula) 

such that a discharge from the facility could cause injury to fish and wildlife and sensitive environments? 

Yes X 

No 

Does the facility have a total oil storage capacity greater than or equal to 1 million gallons and is the facility 

located at a distance (as calculated using the appropriate formula in Appendix C or a comparable formula) 

such that a discharge from the facility would shut down a public drinking water intake? 

Yes X 

No 

Does the facility have a total oil storage capacity greater than or equal to 1 million gallons and has the 

facility experienced a reportable oil spill in an amount greater than or equal to 10,000 gallons within the last 

5 years? 

Yes 

No X 

Alpine Field, Satellites, and Pipelines ODPCP A-16 February 2018, Rev. 0 

 

 

 

 

U.S. ENVIRONMENTAL PROTECTION AGENCY INFORMATION SUMMARY 

FACILITY INFORMATION 

Facility Name: Alpine Field and Satellites and Pipeline System 

Location: The Alpine Development Area is located on the Western North Slope of Alaska 

City: North Slope Borough 

State: Alaska 

County: N/A 

Phone Number: (907) 670-4900 (Alpine Security) 

Latitude: N 70 Degrees, 20 Minutes, 40 Seconds 

Longitude: W 150 Degrees, 55 Minutes, 30 Seconds 

Wellhead Protection Area: Not applicable 

Owner: ConocoPhillips Alaska 

Owner Location: 700 G Street, P.O. Box 100360 Anchorage, Alaska 99510-0360 (mailing address) 

City: Anchorage 

State: Alaska 

County: N/A 

Phone Number: (907) 276-1215 

Operator (if not Owner): ConocoPhillips Alaska 

Qualified Individual(s): Misty Alexa 

Position Title: Manager, Western North Slope Operations 

Work Address: 700 G Street, P.O. Box 100360, Anchorage, AK 99510-0360 OR Alpine CD1 

Home Address: Anchorage, Alaska 

Emergency Phone Number: (907) 265-1000 (Anchorage Security); (907) 670-4900 (Alpine Security) 

Date of Oil Storage Start-up: 1999 

Current Operations: Drilling, Production, Processing, and Oil Transfer (pipeline) 

Standard Industrial Classification: 1330 

Date(s) and Types(s) of Substantial Expansion(s): 

Summer 2004 production and seawater facility expansion. Expansion occurred during spring and winter 

2005 and 2006, respectively, with the construction and development of drill sites CD3 and CD4. 

Construction and development of drill site CD5 and in-field flow lines, and construction of a bridge over 

the Nigliq Channel occurred during winter 2013 and 2014; on-pad facilities were installed in 2015. 

Construction and development of drill site GMT1 and in-field flow lines, and construction of a gravel pad 

and road occurred during winter 2017 and 2018; on-pad facilities were installed in 2018. 

Alpine Field, Satellites, and Pipelines ODPCP A-18 February 2018, Rev. 0 
 

 

VULNERABILITY ANALYSIS 

The vulnerability analysis table below identifies the potential effects of an oil discharge as prescribed by 40 

CFR 112, Appendix F section 1.4.2. 

VULNERABILITY ANALYSIS 

Water intakes There is a freshwater intake for the Alpine camp and operations at nearby 

permitted lakes (ACS Technical Manual, Volume 2, Map Atlas, Sheet 20). A 

freshwater drinking water intake for Nuiqsut is located over 8 miles away from 

the facility. 

Schools Schools are present in the city of Nuiqsut, located approximately 8 miles from 

the facility. Impact to schools is not anticipated. 

Medical facilities COPA medical facilities are located at the main camp facilities at CD1. 

Medical facilities are present in the city of Nuiqsut, located approximately 8 

miles from the facility. 

Residential areas Nuiqsut is a residential area located approximately 8 miles from the facility. 

Native allotments and homesteads are in the vicinity of the Alpine area. 

Businesses Alpine is neighbored by other oil and gas exploration and production 

businesses that may or may not be active. 

Wetlands or other sensitive 

environments 

There are wetlands in the area. Environmentally sensitive areas are 

discussed in Section 3.10 of the FRP. 

Fish and Wildlife The area surrounding the facility provides important habitat for migratory 

birds, land and marine mammals, anadromous fish, and resident fish. Fish 

species documented in the area include arctic cisco, chum salmon, dolly 

varden, least cisco, pink salmon, rainbow smelt, and whitefish. 

Lakes and streams The primary rivers in the area include the Colville River, Sakoonang Channel, 

Nigliq Channel, Nigliagvik Channel, Tinmiaqsiugvik River, and Fish Creek 

Basin. There are also numerous small lakes, ponds, and streams in the area. 

Endangered Flora and Fauna Polar bears, spectacled eiders, and Steller’s eiders are listed as threatened 

and managed by US Fish and Wildlife Service (USFWS). Ringed seals are 

listed as threatened and managed by the National Marine Fisheries Service 

(NMFS). Bowhead, fin, and humpback whales are listed as endangered and 

managed by NMFS; however, fin and humpback whales are rarely in the 

project area. 

Recreational areas The expansive area surrounding Alpine facilities may be utilized by local 

residents of Nuiqsut for boating, subsistence hunting, and camping. Cabins 

and fishing camps are present along the channels of Fish Creek. 

Transportation routes The Alpine facilities are interconnected by gravel roads or are accessed by 

airstrip. There is no permanent gravel road connection to Deadhorse. 

Temporary ice roads may be constructed during winter season to allow 

transportation from Deadhorse to Alpine and Nuiqsut. 

A gravel airstrip is maintained at Alpine CD1 and CD3, and in Nuiqsut; the 

airstrips provide year-round transportation support. 

Utilities A natural gas transmission pipeline is present from Alpine CD1 to Nuiqsut. 

Other Areas of Economic 

Importance 

The expansive area surrounding Alpine facilities is utilized by local residents 

for subsistence hunting, trapping, and gathering. 

Alpine Field, Satellites, and Pipelines ODPCP A-19 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

WORST CASE DISCHARGE 

Type of Oil and Volume of Worst Case Discharge 

Using the calculation described in 40 CFR 112, Appendix D, Part B.2, the WCD is equal to the capacity of 

the largest single aboveground oil storage tank within an adequate secondary containment area, plus the 

volume of all aboveground tanks without adequate secondary containment, plus the production volume of 

the well with the highest output. 

Worst -Case Discharge Calculations 

• The largest tank has a 3,300-barrel capacity (138,600 gallons). The tank stores diesel for use at 

the facilities. Produced fluids are not stored in bulk oil storage tanks or tank batteries, they are 

transferred by flowline directly to a sales oil processing facility. 

• The volume of containers without adequate secondary containment is: zero (0) barrels. 

• The well with highest output at Alpine is at 10,000 barrels of oil per day (bopd) and is less than 

10,000 feet deep, with total vertical depth at 7,380 feet. 

• Alpine production facilities are attended (monitored) 24-hours a day, and initial response personnel 

and equipment are immediately available to respond to a discharge. 

• Recovery rate is based on combined liquid recovery capacity, as presented in plan Section 1.6.3, 

Scenario 1, Table 1-7. 

• Production volume of well = discharge volume 1 (DV1) + discharge volume 2 (DV2) (see 40 CFR 

112 Appendix D, Attachment D-1, section 2.2 Method B). 

Where: 

DV1 = (days unattended + days to respond) * (rate of well) 

= (0 days + 0.17 days) *10,000 bopd = 1,700 bbl (71,400 gallons) 

DV2 = [30 days – (days unattended + days to respond)] * (rate of well) * (rate of well/rate of recovery) 

= [30 days – (0 days + 0.17 days)] * (10,000 bopd) * (10,000 bopd / 17,030 bopd) = 175,161 bbl 

(7,356,762 gallons) 

Production volume of well = 1,700 bbl + 175,161 bbl = 176,861 bbl (7,428,162 gallons) 

Therefore: 

WCD = 3,300 bbl + 0 bbl + 176,861 bbl = 180,161 bbl (7,566,762 gallons) 

BASIS FOR DETERMINATION OF SIGNIFICANT AND SUBSTANTIAL HARM 

Operations at Alpine have potential to spill hydrocarbon material on tundra (wetlands) and into navigable 

waters of the United States. As such, it is determined to pose significant and substantial harm should a spill 

occur. 

Alpine Field, Satellites, and Pipelines ODPCP A-20 February 2018, Rev. 0 
 

ATTACHMENT E-1 

WORKSHEET TO PLAN VOLUME OF RESPONSE RESOURCES 

FOR WORST CASE DISCHARGE – PETROLEUM OILS 

CRUDE OIL WCD 

Part I Background Information 

176,861 Step (A) Calculate Worst Case Discharge in barrels (Appendix D) . . . . . . 

(A) 

2 Step (B) Oil Group1(Table 3 and section 1.2 of this appendix) . . . . . . . . 

Step (C) Operating Area (choose one) . . . . Nearshore/Inland or Rivers and 

Great Lakes Canals 

Step (D) Percentages of Oil (Table 2 of this appendix) 

Percent Lost to Natural Percent Recovered 

Dissipation Floating Oil Percent Oil Onshore 

40 15 45 

(D1) (D2) (D3) 

Step (E1) On-Water Oil Recovery Step (D2) x Step (A) 26,529 

100 (E1) 

Step (E2) Shoreline Recovery Step (D3) x Step (A) 79,587 

100 (E2) 

Step (F) Emulsification Factor 

(Table 3 of this appendix) . . . . . . . . . . . . . . . . . . . . . . . . 1.8 

(F) 

Step (G) On-Water Oil Recovery Resource Mobilization Factor 

(Table 4 of this appendix) 

Tier 1 Tier 2 Tier 3 

0.30 0.40 0.60 

(G1) (G2) (G3) 

1 A facility that handles, stores, or transports multiple groups of oil must do separate calculations for each 

oil group on site except for those oil groups that constitute 10 percent of less by volume of the total oil 

storage capacity at the facility. For purposes of this calculation, the volumes of all products in an oil groups 

must be summed to determine the percentage of the facility’s total oil storage capacity. 

Alpine Field, Satellites, and Pipelines ODPCP A-21 February 2018, Rev. 0 
 

 

ATTACHMENT E-1 (CONTINUED) 

WORKSHEET TO PLAN VOLUME OF RESPONSE RESOURCES 

FOR WORST CASE DISCHARGE – PETROLEUM OILS 

CRUDE OIL WCD 

Part II On-Water Oil Recovery Capacity (barrels/day) 

Tier 1 Tier 2 Tier 3 

14,326 19,101 28,651 

Step (E1) x Step (F) x 

Step (G1) 

Step (E1) x Step (F) x 

Step (G2) 

Step (E1) x Step (F) x 

Step (G3) 

143,257 Part III Shoreline Cleanup Volume (barrels) . . . . . . . . . . . . . . . . . . 

Step (E2) x Step (F) 

Part IV On-Water Response Capacity by Operating Area 

(Table 5 of this appendix) 

(Amount needed to be contracted for in barrels/day) 

Tier 1 Tier 2 Tier 3 

1,875 3,750 7,500 

(J1) (J2) (J3) 

Part V On-Water Amount Needed to be Identified, but not Contracted for in Advance (barrels/day) 

Tier 1 Tier 2 Tier 3 

12,451 15,351 21,151 

Part II Tier 1 - Step (J1) Part II Tier 2 - Step (J2) Part II Tier 3 - Step (J3) 

NOTE: To convert from barrels/day to gallons/day, multiply the quantities in Parts II through V by 42 

gallons/barrel. 

Alpine Field, Satellites, and Pipelines ODPCP A-22 February 2018, Rev. 0 
 

 

ATTACHMENT E-1 

WORKSHEET TO PLAN VOLUME OF RESPONSE RESOURCES 

FOR WORST CASE DISCHARGE – PETROLEUM OILS 

ULTRA-LOW SULFUR DIESEL, TANK CF-T-61001 

Part I Background Information 

3,300 Step (A) Calculate Worst Case Discharge in barrels (Appendix D) . . . . . . 

(A) 

1 Step (B) Oil Group1 (Table 3 and section 1.2 of this appendix) . . . . . . . . 

Step (C) Operating Area (choose one) . . . . Nearshore/Inland or Rivers and 

Great Lakes Canals 

Step (D) Percentages of Oil (Table 2 of this appendix) 

Percent Lost to Natural 

Dissipation 

80 

(D1) 

Step (E1) On-Water Oil Recovery 

Step (E2) Shoreline Recovery 

Step (F) Emulsification Factor 

(Table 3 of this appendix) 

Percent Recovered 

Floating Oil Percent Oil Onshore 

10 10 

(D2) (D3) 

330 Step (D2) x Step (A) 

100 (E1) 

330 Step (D3) x Step (A) 

100 (E2) 

. . . . . . . . . . . . . . . . . . . . . . . . 1.0 

(F) 

Step (G) On-Water Oil Recovery Resource Mobilization Factor 

(Table 4 of this appendix) 

Tier 1 Tier 2 Tier 3 

0.30 0.40 0.60 

(G1) (G2) (G3) 

1 A facility that handles, stores, or transports multiple groups of oil must do separate calculations for each 

oil group on site except for those oil groups that constitute 10 percent of less by volume of the total oil 

storage capacity at the facility. For purposes of this calculation, the volumes of all products in an oil groups 

must be summed to determine the percentage of the facility’s total oil storage capacity. 

Alpine Field, Satellites, and Pipelines ODPCP A-23 February 2018, Rev. 0 
 

 

ATTACHMENT E-1 (CONTINUED) 

WORKSHEET TO PLAN VOLUME OF RESPONSE RESOURCES 

FOR WORST CASE DISCHARGE – PETROLEUM OILS 

ULTRA-LOW SULFUR DIESEL, TANK CF-T-61001 

Part II On-Water Oil Recovery Capacity (barrels/day) 

Tier 1 Tier 2 Tier 3 

99 132 198 

Step (E1) x Step (F) x 

Step (G1) 

Step (E1) x Step (F) x 

Step (G2) 

Step (E1) x Step (F) x 

Step (G3) 

330 Part III Shoreline Cleanup Volume (barrels) . . . . . . . . . . . . . . . . . 

Step (E2) x Step (F) 

Part IV On-Water Response Capacity by Operating Area 

(Table 5 of this appendix) 

(Amount needed to be contracted for in barrels/day) 

Tier 1 Tier 2 Tier 3 

1,875 3,750 7,500 

(J1) (J2) (J3) 

Part V On-Water Amount Needed to be Identified, but not Contracted for in Advance (barrels/day) 

Tier 1 Tier 2 Tier 3 

-1,776 (0) -3,618 (0) -7,302 (0) 

Part II Tier 1 - Step (J1) Part II Tier 2 - Step (J2) Part II Tier 3 - Step (J3) 

NOTE: To convert from barrels/day to gallons/day, multiply the quantities in Parts II through V by 42 

gallons/barrel. 

Alpine Field, Satellites, and Pipelines ODPCP A-24 February 2018, Rev. 0 
 

 

 

 

 

 

 

ALPINE OIL SPILLS TO NAVIGABLE WATERS (TUNDRA AND WATER) 

Date of 

Discharge 

Discharge Cause; 

Spill Source 

Material 

Discharged 

Volume 

Discharged 

(gal) 

Volume to 

Tundra 

(gal) 

Volume to 

Water 

(gal) 

Volume to 

Containment 

(gal) 

Cleanup Actions Corrective Action 

Cause Explanation/

Description of 

Detection 

1/10/1999 Cause: Flange 

Leak/ Failure; 

Source: Not 

Specified 

Hydraulic Fluid100% 2.00 1.00 0.00 0.00 100% Recovered; 

Disposal Location: 

Snowmelter at B70 Pad 

Equipment repaired. Blown O-ring on joy 

compressor 

1/15/1999 Cause: Rolling 

Stock Leak; 

Source: Not 

Specified 

Hydraulic Fluid100% 1.00 0.00 1.00 0.00 100% Recovered; 

Disposal Location: 

Snowmelter at B70 Pad 

Equipment repaired. Failed O-ring on end 

dump. 

1/25/1999 Cause: Rolling 

Stock Leak; 

Source: Not 

Specified 

Hydraulic Fluid100% 0.30 0.00 0.30 0.00 100% Recovered; 

Disposal Location: 

Snowmelter at B70 Pad 

Equipment repaired. Hydraulic line broke due 

to extreme temperatures 

(-40F) 

1/27/1999 Cause: Rolling 

Stock Leak; 

Source: Not 

Specified 

Hydraulic Fluid100% 4.00 0.00 3.00 1.00 100% Recovered; 

Disposal Location: 

Snowmelter at B70 Pad 

Operations were ceased 

and equipment repaired. 

Hydraulic line on 65-ton 

hydro-crane snagged on 

rotor and was stretched. 

Line did not break but 

caused leak around seal. 

2/22/1999 Cause: Human 

Error; Source: 

Heavy 

Equip/Mobile 

Equip/Vehicles 

Diesel-100% 5.00 5.00 0.00 0.00 100% Recovered; 

Disposal Location: 

Snowmelter at B70 Pad 

Heavy equipment (B70) 

lost control and veered 

off road causing fuel tank 

to rupture. 

2/26/1999 Cause: Rolling 

Stock Leak; 

Source: Not 

Specified 

Hydraulic Fluid100% 0.10 0.00 0.10 0.00 100% Recovered; 

Disposal Location: 

Snowmelter at B70 Pad 

Patrol area for 

confirmation of source. 

Advise personnel to use 

containment under 

vehicles and equipment. 

Multiple users of lake; 

positive identification of 

origin unknown. 

2/27/1999 Cause: Rolling 

Stock Leak; 

Source: Heavy 

Equip/Mobile 

Equip/Vehicles 

Hydraulic Fluid100% 20.00 20.00 0.00 0.00 100% Recovered; Snow 

bagged for disposal at 

snowmelter - gravel 

taken to DS-1H. 

Operator training; 

monitor equipment 

movement so valve is 

protected. 

Containment (drip pan), 

lodged against valve 

when moving equipment, 

causing valve to open. 

3/3/1999 Cause: Rolling 

Stock Leak; 

Source: Not 

Specified 

Motor Oil-100% 0.50 0.00 0.50 0.00 100% Recovered; Snow 

bagged for disposal at 

snowmelter - gravel 

taken to DS-1H. 

Closer inspection of all 

vehicles visiting the 

Alpine field. 

Unknown, not able to 

determine cause or 

equipment user/operator. 

3/7/1999 Cause: Rolling 

Stock Leak; 

Source: Heavy 

Equip/Mobile 

Equip/Vehicles 

Hydraulic Fluid100% 35.00 35.00 0.00 0.00 98% Recovered Equipment repaired. D10N equipment 

hydraulic line failed 

Alpine Field, Satellites, and Pipelines ODPCP A-25 February 2018, Rev. 0 
 

 

 

 

 

 

 

ALPINE OIL SPILLS TO NAVIGABLE WATERS (TUNDRA AND WATER), CONTINUED 

Date of 

Discharge 

Discharge Cause; 

Spill Source 

Material 

Discharged 

Volume 

Discharged 

(gal) 

Volume to 

Tundra 

(gal) 

Volume to 

Water 

(gal) 

Volume to 

Containment 

(gal) 

Cleanup Actions Corrective Action 

Cause Explanation/

Description of 

Detection 

3/7/1999 Cause: Rolling 

Stock Leak; 

Source: Not 

Specified 

Hydraulic Fluid100% 0.80 0.00 0.80 0.00 100% Recovered; 

Disposal Location: 

Snowmelter at B70 Pad 

Equipment repaired. Failed hydraulic line on 

ballderson hitch. 

3/8/1999 Cause: Rolling 

Stock Leak; 

Source: Heavy 

Equip/Mobile 

Equip/Vehicles 

Hydraulic Fluid100% 3.00 2.80 0.00 0.00 100% Recovered; 

Disposal Location: 

Snowmelter at B70 Pad 

Tighten connection, 

check occasionally by 

maintenance crew. 

Hose connection loose, 

parted from connection. 

3/14/1999 Cause: Rolling 

Stock Leak; 

Source: Heavy 

Equip/Mobile 

Equip/Vehicles 

Diesel-100% 2.00 2.00 0.00 0.00 100% Recovered; 

Disposal Location: 

Snowmelter at B70 Pad 

Replaced damaged line. Euclid B-70 went off road 

and compromised the 

fuel line. 

3/29/1999 Cause: Equipment 

Difficulty; Source: 

Heavy 

Equip/Mobile 

Equip/Vehicles 

Hydraulic Fluid100% 0.10 0.00 0.10 0.00 100% Recovered; 

Disposal Location: 

Snowmelter at B70 Pad 

Loader taken out of 

service for repair. 

Hose leak on loader. 

4/5/1999 Cause: Human 

Engineering; 

Source: Heavy 

Equip/Mobile 

Equip/Vehicles 

Glycol-67%, 

Motor Oil-33% 

2.00 0.00 2.00 0.00 100% Recovered; 

Disposal Location: 

Snowmelter at B70 Pad 

Discussed accident 

cause and events in craft 

safety meetings. 

Cement Truck #76003 

lost control on ice road 

and left the roadway. 

5/4/1999 Procedures; 

Source: Heavy 

Equip/Mobile 

Equip/Vehicles 

Diesel-98%, 

Glycoll-1%, 

Motor Oil-1% 

252.00 252.00 0.00 0.00 100% Recovered; 

contaminated snow 

taken to snow melter. 

Reduce speed during 

warm weather. 

Traveling too fast for 

road condition. 

6/10/1999 Training; Source: 

Drums/Containers/ 

Dumpsters 

Diesel-100% 10.00 10.00 0.00 0.00 100% Recovered; 

Disposal Location: DS1H Pit; Liquids recycled. 

Immediate action to 

contain sheen using 

boom and absorb 

(dumpster storage 

procedures). 

Sheen was found off 

pad, probable cause was 

dumpster storage during 

winter on pad. 

6/16/1999 Cause: Human 

Engineering; 

Source: Transfer 

Hoses 

Diesel-100% 2.00 1.00 1.00 0.00 100% Recovered; 

Sorbant taken to 

incinerator 

- Diesel spill in snow 

sometime during winter 

construction. 

1/7/2000 Cause: Equipment 

Difficulty; Source: 

Heavy 

Equip/Mobile 

Equip/Vehicles 

Hydraulic Fluid100% 0.10 0.00 0.10 0.00 100% Recovered; 

Staged in containment 

cell for disposal at 1H. 

Replaced seal. Balerson hitch pin 

actuator seal failure. 

Equip. # 42-025 

Alpine Field, Satellites, and Pipelines ODPCP A-26 February 2018, Rev. 0 
 

 

 

 

 

 

ALPINE OIL SPILLS TO NAVIGABLE WATERS (TUNDRA AND WATER), CONTINUED 

Date of 

Discharge 

Discharge Cause; 

Spill Source 

Material 

Discharged 

Volume 

Discharged 

(gal) 

Volume to 

Tundra 

(gal) 

Volume to 

Water 

(gal) 

Volume to 

Containment 

(gal) 

Cleanup Actions Corrective Action 

Cause Explanation/

Description of 

Detection 

1/24/2000 Cause: Equipment 

Difficulty; Source: 

Fittings/Seals/Conn 

ections 

Hydraulic Fluid100% 0.30 0.00 0.30 0.00 100% Recovered; 

Contaminated ice 

chipped and placed in 

bags. Transported to 

ACS holding area 

pending snow melting. 

- Hydraulic brake line 

failure on DJB. 

2/27/2000 Cause: Unknown; 

Source: Heavy 

Equip/Mobile 

Equip/Vehicles 

Motor Oil-100% 0.30 0.00 0.30 0.00 100% Recovered; 

Disposal Location: 

Snowmelter 

Continue to review 

policies and procedures 

in tool box and weekly 

safety meetings about 

spill prevention and 

reporting. Also the need 

for better maintenance of 

equipment. 

Unknown 

3/4/2000 Cause: Equipment 

Difficulty; Source: 

Heavy 

Equip/Mobile 

Equip/Vehicles 

Hydraulic Fluid100% 4.50 0.00 4.50 0.00 100% Recovered; ACS 

storage cell - waiting for 

snowmelter 

Replaced new hose. Failed hydraulic hose on 

Challenger equipment 

#AH8023. 

3/15/2000 Cause: Equipment 

Difficulty; Source: 

Heavy 

Equip/Mobile 

Equip/Vehicles 

Hydraulic Fluid100% 5.00 5.00 0.00 0.00 100% Recovered; 

Disposal Location: 

Snowmelter 

Replaced with new Oring. An O-ring on 

transmission filter failed. 

3/23/2000 Cause: Equipment 

Difficulty; Source: 

Flares 

Diesel-100% 9.00 9.00 0.00 0.00 100% Recovered; 

Disposal Location: DS1H Pit 

Replaced fuel filter. O-ring failed on fuel filter. 

4/20/2000 Cause: Equipment 

Difficulty; Source: 

Heavy 

Equip/Mobile 

Equip/Vehicles 

Diesel-100% 0.50 0.50 0.00 0.00 100% Recovered; 

Disposal Location: 

Snowmelter 

Isolated reserve tank. Reserve fuel tank 

pressurized spilling 

diesel out of filler cap. 

5/9/2000 Cause: Equipment 

Difficulty; Source: 

Fittings/Seals/Conn 

ections 

Hydraulic Fluid100% 0.30 0.00 0.30 0.00 100% Recovered; 

Disposal Location: 

Snowmelter 

Equipment moved to 

shop and repaired. 

Hydraulic line failure. 

9/4/2000 Cause: Equipment 

Difficulty; Source: 

Tanks 

Hydraulic Fluid100% 0.10 0.10 0.00 0.00 100% Recovered; 

Disposal Location: Oily 

Waste 

Tighten hydraulic fluid 

cap. 

Hydraulic fluid cap 

leaked while equipment 

was on an incline. 

Alpine Field, Satellites, and Pipelines ODPCP A-27 February 2018, Rev. 0 
 

 

 

 

 

 

ALPINE OIL SPILLS TO NAVIGABLE WATERS (TUNDRA AND WATER), CONTINUED 

Date of 

Discharge 

Discharge Cause; 

Spill Source 

Material 

Discharged 

Volume 

Discharged 

(gal) 

Volume to 

Tundra 

(gal) 

Volume to 

Water 

(gal) 

Volume to 

Containment 

(gal) 

Cleanup Actions Corrective Action 

Cause Explanation/

Description of 

Detection 

9/18/2000 Cause: Equipment 

Difficulty; Source: 

Heavy 

Equip/Mobile 

Equip/Vehicles 

Hydraulic Fluid100% 0.10 0.10 0.00 0.00 100% Recovered; 

Absorb was incinerated 

at Alpine. 

Hose was replaced. Hose Failure 

11/4/2000 Cause: Equipment 

Difficulty; Source: 

Fittings/Seals/Conn 

ections 

Diesel-100% 0.20 0.20 0.00 0.00 100% Recovered; ACS 

Drum Dock awaiting 

Snow Melter. 

Teflon tape was added 

to the plug's threads. 

Fuel tank plug leaked. 

12/8/2000 Cause: Human 

Engineering; 

Source: Heavy 

Equip/Mobile 

Equip/Vehicles 

Diesel-1%, 

Hydraulic Fluid99% 

0.30 0.00 0.30 0.00 95% Recovered; Taken 

to Prudhoe Bay to Catco 

Base Camp. 

Residual impacted area 

(sheen) will be allowed 

to freeze and frozen 

impacted area removed 

at a later date using a 

chain saw. 

Front right side of 

Rolligon broke through 

the ice. 

3/11/2002 Cause: Equipment 

Difficulty; Source: 

Fittings/Seals/Conn 

ections 

Crude-1%, 

Diesel-30%, 

Freshwater64%, Produced 

water-5%) 

15.00 0.00 0.00 10.00 90% Recovered; CD1-

19a Class II disposal 

well for melted snow, 

CD1 Class II solids pit 

for contaminated gravel 

Chicksan swivel joint 

failed leaking fluid onto 

the gravel pad. 

6/6/2002 Cause: Equipment 

Difficulty; Source: 

Heavy 

Equip/Mobile 

Equip/Vehicles 

Hydraulic Fluid100% 1.00 0.70 0.00 0.30 100% Recovered; The 

contaminated snow was 

taken to the ACS 

Hopper. After the snow 

is melted it will be 

injected down the Class 

1 well WD-2. Based on 

MSDS/user knowledge, 

the hydraulic oil is nonhazardous. 

The Challenger is on a 

regular preventative 

maintenance schedule. 

The information of this 

spill event will be 

provided to the 

mechanics, to determine 

if the preventative 

maintenance for the 

Challenger needs to be 

modified. 

Hydraulic hose leaked 

on the Challenger while 

working on the snow 

next to the gravel pad. 

Alpine Field, Satellites, and Pipelines ODPCP A-28 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

ALPINE OIL SPILLS TO NAVIGABLE WATERS (TUNDRA AND WATER), CONTINUED 

Date of 

Discharge 

Discharge Cause; 

Spill Source 

Material 

Discharged 

Volume 

Discharged 

(gal) 

Volume to 

Tundra 

(gal) 

Volume to 

Water 

(gal) 

Volume to 

Containment 

(gal) 

Cleanup Actions Corrective Action 

Cause Explanation/

Description of 

Detection 

3/14/2003 Cause: Equipment 

Difficulty; Source: 

Heavy 

Equip/Mobile 

Equip/ Vehicles 

Diesel-100% 0.20 0.20 0.00 0.00 100% Recovered; 

Disposal Location: WD-2 

Alpine Class I Disposal 

1. Review availability of 

different tank designs. 

Contact manufacturer to 

obtain appropriate 

tankage for our use. 2. 

Revise training to include 

discussion of increased 

spill potential when 

parking/traveling on 

uneven terrain and 

additional gravity-feed 

spill potential from 

saddle tanks. 

Material dripped from the 

fuel cap of a Sno-cat 

tucker when the unit was 

parked on an uneven 

tundra location due to an 

inadequate fuel tank 

system design. 

2/19/2004 Contractor - Nanuq 

Inc.; Transmission 

line failure on 

pickup truck #115 

100% 

Transimission 

Fluid 

0.30 0.00 0.30 0.00 Chipped and bagged 

material; brought to AIC 

snowmelter in 

Deadhorse. 

Check transmission, 

repair line and perform 

any necessary 

maintenance on vehicle 

prior to placing back in 

service. 

Equipment difficulty. Spill 

to frozen surface of lake 

M0025. Ambient air 

temperature near -50F 

@ nuiqsut. 

3/14/2005 Contractor - AES 

PP&C; Equipment 

Difficulty 

100% Hydraulic 

Fluid 

1.50 0.00 1.50 0.00 ACS was contacted. 

Contaminated snow was 

collected and trucked to 

KRU snow melter for 

further remediation and 

hydrocarbon recycle. Ice 

surface was scratched 

and swept clean. Sent to 

KRU snow melter -

hydrocarbon recycle. 

Tap root investigation 

conducted. 

Hydraulic line connection 

from a loader's snow 

blower attachment 

became loose, allowing 

hydraulic oil to leak onto 

frozen lake surface. 

4/13/2005 Contractor - AES 

PP&C; Equipment 

Difficulty 

10% Motor Oil; 

90% Glycol 

6.00 0.00 0.50 5.50 ACS and environmental 

responded to the spill. 

Spill was cleaned up with 

liners, absorbents, 

shovels, and ice 

chippers. Sent to alpine 

disposal well WD-02. 

Preventative 

maintenance needs 

improvement as per 

taproot investigation. 

A broken heater hose on 

a panel truck caused a 6 

gallon spill of glycol and 

motor oil. CD3 pipeline 

crossing. 

4/18/2005 Contractor - AES 

PP&C; Equipment 

Difficulty 

100% Diesel 0.50 0.00 0.50 0.00 Impacted river ice was 

chipped up. Melted in 

acs snow hopper. 

Hydrocarbons will be 

skimmed off and the 

water sent to WD-02. 

None Spill occurred on the 

river ice at the CD3 

pipeline crossing of the 

Ulamnigiaq River and 

appears to have been 

caused by a leak in the 

thaw unit's fuel line. 

Alpine Field, Satellites, and Pipelines ODPCP A-29 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

ALPINE OIL SPILLS TO NAVIGABLE WATERS (TUNDRA AND WATER), CONTINUED 

Date of 

Discharge 

Discharge Cause; 

Spill Source 

Material 

Discharged 

Volume 

Discharged 

(gal) 

Volume to 

Tundra 

(gal) 

Volume to 

Water 

(gal) 

Volume to 

Containment 

(gal) 

Cleanup Actions Corrective Action 

Cause Explanation/

Description of 

Detection 

4/23/2005 Contractor - AES 

PP&C; Equipment 

Difficulty 

100% Motor Oil 0.10 0.00 0.10 Some Impacted ice was 

chipped up and 

collected. Impacted ice 

will be melted, then the 

hydrocarbons will be 

skimmed off and the 

water sent to WD-2. 

Welding unit was taken 

out of service and sent 

and sent in for repairs. 

Leaking gasket on 

welding-unit engine. 

Approximately 1 pint 

leaked from the welding 

unit with about 75% 

caught in the secondary 

containment under the 

unit. Approximately 4 

ounces of motor oil 

leaked onto the river ice 

surface. 

5/30/2005 Cause: Flange 

Leak/ Failure; 

Source: 

Fittings/Seals/Conn 

ections 

Diesel-100% 3.00 0.00 0.20 1.00 100% Recovered; 

Contaminated gravel 

was taken to the Class I 

gravel cell for further 

remediation. Liquid and 

sheen was collected with 

sorbents and boom and 

sent to incineration. 

Replace fuel line hoses 

on pump with diesel 

rated hoses. Verify that 

hoses on other pumps 

are diesel rated and 

discuss with mechanics 

regarding future PMs on 

this equipment. 

A water pump was being 

used to dewater an 

impoundment filled with 

melting snow directly 

adjacent to the Alpine 

CD1 apron area. An 

improper fuel line was 

used on the ACS water 

pump causing diesel fuel 

to leak into secondary 

containment, onto the 

gravel pad and into the 

water filled impoundment 

area. 

7/27/2005 Cause: 

Management 

System; Source: 

Heavy 

Equip/Mobile 

Equip/Vehicles 

Hydraulic Fluid90%, Motor Oil10% 

10.50 0.30 0.00 0.00 100% Recovered; 

Disposal Location: WD-2 

Alpine Class I Disposal; 

Small amount of 

snow/gravel placed into 

Class I temporary pit. 

Fluids will be manifested 

to WD-02 Class I Well. 

As of 8/6/05, 25 barrels 

of fluid recovered. 

AES will modify periodic 

skills re-assessment 

criteria for heavy 

equipment operators. 

Backhoe tipped over due 

to a slick working area 

on a slope. 

1/28/2006 Contractor - AES 

PP&C; Equipment 

Difficulty 

100% Hydraulic 

Fluid 

0.50 0.00 0.50 0.00 ACS responded and 

chipped up contaminated 

snow and ice. 

Contaminated snow and 

ice sent to snow melter 

for hydrocarbon recycle. 

Taproot investigation. Hydraulic hose on all 

terrain dump truck failed 

while traveling on 

Sakoonang River ice 

road crossing. On ice 

road crossing 

Sakoonang River. 

Alpine Field, Satellites, and Pipelines ODPCP A-30 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

ALPINE OIL SPILLS TO NAVIGABLE WATERS (TUNDRA AND WATER), CONTINUED 

Date of 

Discharge 

Discharge Cause; 

Spill Source 

Material 

Discharged 

Volume 

Discharged 

(gal) 

Volume to 

Tundra 

(gal) 

Volume to 

Water 

(gal) 

Volume to 

Containment 

(gal) 

Cleanup Actions Corrective Action 

Cause Explanation/

Description of 

Detection 

2/26/2006 Contractor - AES 

PP&C; Equipment 

Difficulty 

100% Motor Oil 0.50 0.00 0.20 0.00 ACS and contractor 

responded. Used loader 

and shovels to clean up 

contaminated snow/ice. 

Snow was melted in 

ACS hoppers and sent to 

WD-02 for Class I 

disposal. 

Investigation and 

corrective actions. 

Spill occurred along the 

CD3 pipeline ice road 

and within the Tamayak 

River crossing (crossing 

#4). A swalling CCI 

Kenworth tractor had a 

belly containment filled 

with snow/ice during a 

storm. As the engine 

was warmed, some of 

the snow/ice in the 

containment melted 

along with motor oil 

which had leaked into 

the containment. The 

tractor was moved from 

the south side of the 

Tamayak River crossing 

(#4) to the north side 

tracking a 3" to 6" track 

of motor oil along the ice 

road and within the 

Tamayak River crossing. 

3/15/2006 Cause: Unknown; 

Source: Heavy 

Equip/Mobile 

Equip/Vehicles 

Hydraulic Fluid100% 1.00 0.00 0.10 0.00 100% Recovered; 

Disposal Locations: WD2 Alpine Class I 

Disposal; The 

contaminated snow/ice 

was bagged and sent to 

ACS snow melter. Liquid 

sent to Class I disposal 

well. 

None. Leaking mobile vehicle. 

6/22/2007 Cause: Unknown; 

Source: Heavy 

Equip/Mobile 

Equip/ Vehicles 

Motor Oil-100% 0.10 0.00 0.10 0.00 100% Recovered; 

Disposal Locations: CD1 

Class I pit, WD02 Class I 

well 

Spill cause was unknown Source and cause is 

unknown but sheen is 

located near equipment 

line. 

1/19/2008 Contractor – 

Nanuq Inc.; 

Unknown – likely 

heavy equipment 

100% Motor Oil 0.10 0.00 0.10 0.00 Hand tools were used to 

remove the 

contaminated snow and 

ice. 

Attempt to identify the 

leaking vehicle and have 

it repaired. Contractor 

was in the process of 

inspecting their 

equipment to see if the 

source could be 

determined. 

1/2 cup was spilled on 

the ice covered lake. The 

source or cause of the 

spill is unknown. 

Alpine Field, Satellites, and Pipelines ODPCP A-31 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ALPINE OIL SPILLS TO NAVIGABLE WATERS (TUNDRA AND WATER), CONTINUED 

Date of 

Discharge 

Discharge Cause; 

Spill Source 

Material 

Discharged 

Volume 

Discharged 

(gal) 

Volume to 

Tundra 

(gal) 

Volume to 

Water 

(gal) 

Volume to 

Containment 

(gal) 

Cleanup Actions Corrective Action 

Cause Explanation/

Description of 

Detection 

1/20/2008 Unknown – likely 

heavy equipment. 

100% Hydraulic 

Fluid 

0.20 0.00 0.20 0.00 Hand tools were used to 

clean up the 

contaminated ice and 

snow. 

Contractors who used 

the site were contacted 

and asked to check their 

equipment for hydraulic 

leaks. 

Unable to determine 

cause of spill or the 

responsible party as the 

site was used by multiple 

contractors for water 

withdraws and no 

vehicles were at the site 

at the time of the 

discovery. 

4/4/2008 Operator error -

Heavy Equipment 

100% Diesel 5.00 1.00 0.00 4.00 ACS responded and 

used sorbents and hand 

tools to clean up the 

spill. Approval given by 

ADEC to weed burn and 

cover area with snow. 

Weed burned and area 

covered on 4/5. 

Reinspect area in 

summer. Re-inspected 

on 7/23/08 and no 

damage or hydrocarbon 

staining was evident. 1. 

Conduct training on 

recognizing changing 

conditions that 

exacerbate ice road 

driving hazards. 

Emphasize the need to 

drive per the conditions 

being ever mindful of 

changes. In addition 

always comply with 

general safe driving 

practices. 2. Review, 

evaluate and 

recommend safe 

operational speeds for 

the hagglunds and 

document the decisions 

in the qualification 

training. 3. Purchase 

lifesaver hammer to 

assist in self extrication 

in the hagglunds. 4. 

Review the seat belt 

policy with all employees 

for use in all vehicles 

and any deviation from 

safety policies requires a 

signed safety variance. 

Hagglund vehicle 

traveling on ice road hit a 

slick spot and went off of 

the road, turning onto its 

side in the process. 4 

gallons caught in 

secondary containment 

and 1 gallon spilled to 

snow covered tundra. 

Alpine Field, Satellites, and Pipelines ODPCP A-32 February 2018, Rev. 0 
 

 

 

 

ALPINE OIL SPILLS TO NAVIGABLE WATERS (TUNDRA AND WATER), CONTINUED 

Date of 

Discharge 

Discharge Cause; 

Spill Source 

Material 

Discharged 

Volume 

Discharged 

(gal) 

Volume to 

Tundra 

(gal) 

Volume to 

Water 

(gal) 

Volume to 

Containment 

(gal) 

Cleanup Actions Corrective Action 

Cause Explanation/

Description of 

Detection 

9/12/2008 Human/Operator 

error 

100% Motor Oil 0.70 0.70 0.00 0.00 Absorbent pads were 

use to remove as much 

ponded oil as possible, a 

vacuum truck was used 

to remove any oil and 

water that had ponded 

under the imprint of the 

truck, and any residual 

oil left on the vegetation 

was burned with 

permission from ADF&G. 

A safe driving bulletin will 

be put out and 

addressed with the 

crews 

Employee was driving a 

pickup truck when the 

employee lost control 

and drove on the 

shoulder of the road 

which is angled and 

composed of soft gravel. 

The employee was trying 

to avoid a parka squirrel 

which was in the road. 

The employee hit a steel 

culvert and rolled the 

truck over onto its side. 

While on its side motor 

oil leaked out of the 

engine. 

Alpine Field, Satellites, and Pipelines ODPCP A-33 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

ALPINE OIL SPILLS TO NAVIGABLE WATERS (TUNDRA AND WATER), CONTINUED 

Date of 

Discharge 

Discharge Cause; 

Spill Source 

Material 

Discharged 

Volume 

Discharged 

(gal) 

Volume to 

Tundra 

(gal) 

Volume to 

Water 

(gal) 

Volume to 

Containment 

(gal) 

Cleanup Actions Corrective Action 

Cause Explanation/

Description of 

Detection 

12/20/2009 Equipment failure; 

CD2 

30% Diesel, 

70% Crude Oil 

0.78 0.50 0.00 0.00 Hand tools are being 

used to brush the top 

layer of snow off the 

tundra where the wind 

carried a fine misting of 

the product. A loader 

scooped up the 

contaminated snow from 

the pad. 

Remedial plans include a 

site inspection of the 

area in the spring to 

ensure no sheens or 

residue is observed in 

the area. Tap root 

investigation done on 

incident. E-Line crew to 

produce written 

procedures or to address 

the application of hot 

diesel. The procedures 

should include a way to 

keep the lubricator 

wipers engaged or 

having the lubricator 

packed off when the hot 

oil is being added. ELine crew will modify 

their site conditions 

check list to include a 

final site inspection 

downwind of the work 

taking place. E-Line crew 

will evaluate the need to 

use hot oil during a high 

wind event. E-Line crew 

will carry heat detecting 

guns as standard 

equipment. E-Line crew 

will carry heat detecting 

guns as standard 

equipment. A 

modification of the 

wipers will be looked at 

in which the opening at 

the top of the wipers be 

sized down. 

The tap root 

investigation was not 

able to determine the 

exact cause but it is 

believed that the release 

could have taken place 

during the application of 

hot diesel to the well 

while the lubricator was 

attached to the well and 

the lubricator wipers 

were not engaged. 

Additionally high winds 

would have carried the 

spray off of the pad. 

Alpine Field, Satellites, and Pipelines ODPCP A-34 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

ALPINE OIL SPILLS TO NAVIGABLE WATERS (TUNDRA AND WATER), CONTINUED 

Date of 

Discharge 

Discharge Cause; 

Spill Source 

Material 

Discharged 

Volume 

Discharged 

(gal) 

Volume to 

Tundra 

(gal) 

Volume to 

Water 

(gal) 

Volume to 

Containment 

(gal) 

Cleanup Actions Corrective Action 

Cause Explanation/

Description of 

Detection 

2/3/2011 Flange leak/ 

failure; On lake 

L9323 next to the 

Alpine ice road 

100% Diesel 6.00 0.00 6.00 Used a loader and 

bucket, a grader, hand 

shovels, brooms and 

absorbents to remove 

contaminated snow and 

ice. All the absorbents 

and some contaminated 

snow/ice were placed 

into oily waste bags. 

The remainder of the 

contaminated snow and 

ice was hauled off using 

a maxi haul. 

The lake will be 

inspected during the 

summer 2011 helicopter 

inspections of the alpine 

ice road. The water truck 

was driven back to the 

shop to repair the 

cracked fuel line. 

Nanuq's water truck 

#135 was on the lake 

and filling up with a load 

of water for ice road 

maintenance. The fuel 

line on Nanuq water 

truck #135 cracked due 

to ice buildup around the 

fitting. 

7/4/2011 Contractor - Alaska 

Clean Seas; 

Moored vessel at 

Alpine Boat Dock 

100% Motor Oil 0.12 0.00 0.12 0.00 The area had a slight 

sheen inside the boomed 

area only. The area was 

boomed prior to the 

incident as per CPAI 

policy. The area was 

skimmed and water was 

pumped from the boat. 

No sheen has escaped 

boomed area. 

The boat was removed 

from the water and 

inspected to find any 

holes in the hull. Small 

holes were found on the 

deck. The holes that 

were found were filled to 

prevent recurrence of 

sinking. After this 

incident it has been 

determined that CPAI 

will remove from service 

both this boat and the 

only other boat on site 

like it, which cannot be 

removed from the water 

for inspection. 

Human error. Boat sank 

while moored. The boat 

had holes in the hull from 

modification of a console 

in the engine 

compartment. The bilge 

pump evacuated the 

water from the 

compartment until the 

battery powering the 

pump died, at which 

point the boat filled with 

water and sank, and oil 

from the engine 

compartment escaped, 

creating a sheen. Engine 

compartment flooded, 

resulting in sheen. 

Sheen mostly confined 

within the boast hull (the 

hull was above the water 

line). Small amount 

escaped hull but 

remained in boomed 

area. 

Alpine Field, Satellites, and Pipelines ODPCP A-35 February 2018, Rev. 0 
 

 

 

ALPINE OIL SPILLS TO NAVIGABLE WATERS (TUNDRA AND WATER), CONTINUED 

Date of 

Discharge 

Discharge Cause; 

Spill Source 

Material 

Discharged 

Volume 

Discharged 

(gal) 

Volume to 

Tundra 

(gal) 

Volume to 

Water 

(gal) 

Volume to 

Containment 

(gal) 

Cleanup Actions Corrective Action 

Cause Explanation/

Description of 

Detection 

1/10/2012 Hose failure; 

Nanuq Lake, 

Approximately 2 

miles SSE of CD2 

100% Diesel 0.50 0.00 0.25 0.25 ACS techs. Were 

dispatched and cleaned 

the material from the ice 

surface with hand tools. 

Both ACS techs. And the 

KSOP subsistence 

representative were on 

site during spill cleanup 

activities, and both 

parties verified that all of 

the product was 

removed. 

Rock truck was fixed on 

site and then transported 

back to Nuiqsut for 

further inspection and 

cleaning. 

Hose clamp on return 

fuel line came loose on 

Nanuq Inc. John Deere 

rock truck. 

Alpine Field, Satellites, and Pipelines ODPCP A-36 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

ALPINE OIL SPILLS TO NAVIGABLE WATERS (TUNDRA AND WATER), CONTINUED 

Date of 

Discharge 

Discharge Cause; 

Spill Source 

Material 

Discharged 

Volume 

Discharged 

(gal) 

Volume to 

Tundra 

(gal) 

Volume to 

Water 

(gal) 

Volume to 

Containment 

(gal) 

Cleanup Actions Corrective Action 

Cause Explanation/

Description of 

Detection 

4/16/2014 Human Factor; 

pumphouse relief 

hose placed in 

wrong position over 

open hole on 

frozen lake at 

ASRC Minesite. 

100% MOTOR 

OIL 

0.10 0.00 0.10 0.00 SHEEN WAS 

REMOVED BY 

SKIMMING THE 

WATER SURFACE 

WITH ABSORBANTS. 

ABSORBANTS WERE 

PLACED IN OILY 

WASTE BAGS AND 

PUT INTO AN OILY 

WASTE DUMPSTER AT 

ALPINE. 

THE AIR 

COMPRESSOR RELIEF 

HOSE WAS ROUTED 

AWAY FROM THE 

WATER HOLE INTO A 

CONTAINMENT SO 

THAT NO MORE OIL 

CAN DRIP INTO 

WATER HOLE. IN THE 

FUTURE, ALL 

BREATHER HOSES 

WILL BE ROUTED AND 

SECURED TO 

CATCHMENT BOTTLES 

WITHIN SECONDARY 

CONTAINMENT IN THE 

PUMPHOUSE, AND 

WILL BE SECURED IN 

A WAY THAT 

PREVENTS THEM 

FROM HANGING 

OUTSIDE THE 

SECONDARY 

CONTAINMENT OR 

OVER THE OPEN 

WATER HOLE. PEAK 

PERFORMS 

INSPECTIONS ON THE 

PUMPHOUSES 

BEFORE, DURING AND 

AFTER EACH ICE 

ROAD SEASON TO 

IDENTIFY MAJOR 

MAINTENANCE OR 

UPGRADES/REPLACE 

MENTS NEEDED AT 

PUMP HOUSES. CPAI 

ENVIRONMENTAL 

WILL PERFORM PRESEASON 

INSPECTIONS ON ALL 

PEAK PUMP HOUSES 

PRIOR TO 

DEPLOYMENT. 

AN AIR COMPRESSOR 

RELIEF HOSE ON A 

WATER PUMPHOUSE 

MOTOR DRIPPED A 

DROP OF MOTOR OIL 

INTO AN OPEN WATER 

HOLE OF A FROZEN 

LAKE BEING USED 

FOR ICE ROAD 

CONSTRUCTION 

WATER WITHDRAWAL. 

THE RELIEF HOSE 

WAS INADVERTANTLY 

PLACED OVER THE 

OPEN WATER HOLE. 

THE OIL WAS MOST 

LIKELY COMING FROM 

A LEAK IN THE PISTON 

RINGS AND IS A SIGN 

OF ENGINE WEAR. 

SPILL WAS CONFINED 

TO A SMALL OPENWATER AREA AT THE 

PUMPHOUSE AND 

WAS CLEANED 

IMMEDIATELY. NO 

SHEEN WAS VISIBLE 

ON THE WATER OR 

ICE AFTER CLEAN-UP. 

Alpine Field, Satellites, and Pipelines ODPCP A-37 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

ALPINE OIL SPILLS TO NAVIGABLE WATERS (TUNDRA AND WATER), CONTINUED 

Date of 

Discharge 

Discharge Cause; 

Spill Source 

Material 

Discharged 

Volume 

Discharged 

(gal) 

Volume to 

Tundra 

(gal) 

Volume to 

Water 

(gal) 

Volume to 

Containment 

(gal) 

Cleanup Actions Corrective Action 

Cause Explanation/

Description of 

Detection 

3/28/2015 Human Factor; 

overfill fuel tank on 

ice pad for CD5 

100% Diesel 25.00 1.00 0.00 0.00 ALL MATERIAL WAS 

CLEANED BY ACS. 

HAND TOOLS AND 

JACKHAMMERS WERE 

USED TO REMOVE ALL 

ICE AND SNOW FROM 

THE AREA. WRITTEN 

APPROVAL TO BURN 

FREE DIESEL FROM 

THE TUNDRA 

SURFACE WAS 

GRANTED BY ALASKA 

DEPT. OF 

ENVIRONMENTAL 

CONSERVATION -

PREVENTION AND 

EMERGENCY 

RESPONSE 

PROGRAM. 

THIS SPILL WAS 

IDENTIFIED BY ACS 

TECHNICIANS WHILE 

CONDUCTING 

INSPECTIONS AT 0625. 

THE SPILL WAS 

ORIGINALLY 

ESTIMATED AT 4 

GALLONS, AND 

ESTIMATIONS 

INCREASED 

ACCORDINGLY AS 

RECOVERY 

PROGRESSED. AT 

APPROXIMATELY 1400 

THE RECOVERY 

EFFORTS HAT 

REACHED THE 

TUNDRA SURFACE, 

AND IMMEDIATE 

NOTIFICATION WAS 

MADE TO ALL 

APPROPRIATE. THE 

LOCATION INSPECTED 

DURING THE 2015 

SUMMER SEASON VIA 

HELICOPTER; NO 

FURTHER 

INFORMATION OR 

CLEANUP ACTIONS 

REQUIRED. 

SPILL CAUSED BY 

INATTENTION OF 

FUELER WHILE 

CONDUCTING 

FUELING 

OPERATIONS. FUELER 

NEGLIGENCE LEAD TO 

EXCESSIVE 

OVERFILLING OF 

EQUIPMENT. 

NEGLIGENT 

OPERATOR REMOVED 

FROM PROJECT. 

Alpine Field, Satellites, and Pipelines ODPCP A-38 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

ALPINE OIL SPILLS TO NAVIGABLE WATERS (TUNDRA AND WATER), CONTINUED 

Date of 

Discharge 

Discharge Cause; 

Spill Source 

Material 

Discharged 

Volume 

Discharged 

(gal) 

Volume to 

Tundra 

(gal) 

Volume to 

Water 

(gal) 

Volume to 

Containment 

(gal) 

Cleanup Actions Corrective Action 

Cause Explanation/

Description of 

Detection 

12/13/2016 Contractor - heavy 

equipment; building 

GMT ice road, 

water truck tipped 

off road causing oil 

to leak from 

engine. 

100% Motor Oil 0.80 0.75 0.00 0.05 TRUCK WAS RIGHTED 

AND EXTRACTED 

FROM THE TUNDRA, 

AFTER WATER TANK 

WAS PUMPED EMPTY. 

HAND TOOLS WERE 

USED TO COLLECT 

ANY AFFECTED SNOW 

AND ABSORBENT 

PADS TO REMOVE 

FLUID FROM 

SECONDARY 

CONTAINMENT. OIL 

DID NOT PENATRATE 

THE SURFACE OF THE 

TUNDRA. SECONDARY 

CONTAINMENT WAS 

DEPLOYED UNDER 

ENGINE 

COMPARTMENT 

IMMEDIATELY AFTER 

INCIDENT OCCURED. 

CPAI IS 

IMPLEMENTING A 

BETTER SPOTTER 

SYSTEM FOR THE 

WATER TRUCKS 

BACKING DOWN THE 

ROADS DURING OUR 

CONDITIONAL 

CONSTRUCTION OF 

ICE ROADS AND PADS. 

THE GRADER 

OPERATOR WILL 

SERVE AS THE 

SPOTTER AND HAS 

THE BEST VANTAGE 

POINT DURING THE 

INITIAL 

CONSTRUCTION AND 

WILL BE IN CONSTANT 

RADIO CONTACT WITH 

THE TRUCK DRIVERS 

AS THEY PREPARE TO 

SPREAD WATER AND 

WHILE SPREADING 

WATER. 

WHILE BUILDING ICE 

ROAD, A WATER 

TRUCK SLIPPED 

SIDEWAYS OFF THE 

ROAD DUE TO A 

SLOPE ON THE 

PARTIALLY 

CONSTRUCTED ICE 

ROAD. THE TRUCK 

TIPPED ONTO ITS 

SIDE ALLOWING SOME 

MOTOR OIL TO LEAK 

OUT OF THE ENGINE. 

Alpine Field, Satellites, and Pipelines ODPCP A-39 February 2018, Rev. 0 
BLANK PAGE 

Alpine Field, Satellites, and Pipelines ODPCP A-40 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S. DEPARTMENT OF THE INTERIOR 

BUREAU OF LAND MANAGEMENT 

ALPINE FIELD AND SATELLITES 

CROSS REFERENCE 

BLM 

GOVERNANCE 

DOCUMENT 

MEASURE OBJECTIVE SUMMARY REQUIREMENT RELEVANT PLAN 

SECTION 

43 CFR Ch. II 

Subpart 3162 

§3162.5 

Environment 

and safety. 

§3162.5-1(a) Environmental 

obligations 

The operator shall conduct 

operations in a manner which 

protects the mineral resources, 

other natural resources, and 

environmental quality. 

Entire plan, 

demonstrated by 

this table, in its 

intended capacity 

to comply with 

applicable terms 

and conditions of 

approval. 

§3162.5-1(c) Spill reporting per NTL2007-01-Alaska 

Report of major undesirable 

events. 1.2.2 

§3162.5-1(d) Contingency plan 

When reasonably required by the 

authorized officer, a contingency 

plan shall be submitted describing 

procedures to be implemented to 

protect life, property, and the 

environment. 

Introduction – Plan 

Distribution. 

Entire plan. 

February 2013 

NPR-A IAP 

ROD 

BMP A-3 a. Minimize Pollution 

through effective 

hazardous-materials 

contingency planning. 

Spill response training for local 

community. 

3.9.4 

BPM A-3 b. Annual spill response drill. 3.9.6 

BPM A-3 c. Develop facility contingency plans 

and participate in North Slope 

Subarea Contingency Plan for Oil 

and Hazardous Substances 

Discharges/Releases development 

of environmental sensitivity index 

maps. 

entire plan; 3.10 

February 2013 SBMP 2 (new Oil spill response equipment must 3.4; 3.8 

NPR-A IAP subparagraph be effective in Arctic conditions and 

ROD to BMP A-3) must have mechanisms to prevent 

February 2015 freezing and/or de-ice. 

SEIS ROD 

February 2013 SBMP 3 (new Minimize pollution by Equipment used to develop 2.1.5; 2.1.6; 2.1.7; 

NPR-A IAP subparagraph ensuring adequate hydrocarbons must be designed in 2.1.8; 2.1.9 

ROD to BMP A-3) facility design criteria and accordance with standard Arctic Part 4 Best 

February 2015 system integrity engineering practices. Available 

SEIS ROD Technology 

February 2013 

NPR-A IAP 

ROD 

BMP A-4 a. Minimize the impact of 

contaminants on fish, 

wildlife, and the 

environment, including 

wetlands, marshes and 

marine waters, as a 

result of fuel, crude oil, 

and other liquid chemical 

spills. Protect 

subsistence resources 

and subsistence 

activities. Protect public 

health and safety. 

Sufficient oil spill cleanup materials 

shall be stored at all fueling points 

and vehicle maintenance areas, 

and shall be carried by field crews. 

1.3.4; 1.5; 1.6.3; 

1.7; 2.1.3; 2.1.5; 

2.1.9; 2.3; 3.3; 4.3 

BMP A-4 b. Fuel and other petroleum products 

and other liquid chemicals shall be 

stored in proper containers...and 

shall be stored within an 

impermeable lined and diked area 

or within approved alternate 

storage containers...capable of 

containing 110% of the stored 

volume. 

2.1.6; 2.1.8 

Alpine Field, Satellites, and Pipelines ODPCP A-41 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

BUREAU OF LAND MANAGEMENT 

CROSS REFERENCE 

BLM 

GOVERNANCE 

DOCUMENT 

MEASURE OBJECTIVE SUMMARY REQUIREMENT RELEVANT PLAN 

SECTION 

BMP A-4 c. Liner material shall be compatible 

with the stored product and 

capable of remaining impermeable 

during typical weather extremes 

expected throughout the storage 

period. 

2.1.10 

BMP A-4 d. Permanent fueling stations shall be 

lined or have impermeable 

protection to prevent fuel migration 

to the environment from overfills 

and spills. 

2.1.10 

BMP A-4 e. All fuel containers, including barrels 

and propane tanks, shall be 

marked with the responsible party's 

name, product type, and year filled 

or purchased. 

2.1.9; 3.1.2; 

Appendix D 

Propane tanks are 

not addressed in 

the ODPCP. 

BMP A-4 f. Notice of any reportable spill shall 

be given to the authorized officer 

as soon as possible, but no later 

than 24 hours after occurrence. 

1.2 

BMP A-4 g. All oil pans ("duck ponds") shall be 

marked with the responsible party's 

name. 

Markings on duck 

ponds do not 

provide spill 

prevention or 

preparedness; 

therefore, it is not 

addressed in the 

ODPCP. Existing 

policies and 

procedures on 

proper handling of 

duck ponds, spill 

reporting, and 

handling oiled 

materials should 

provide protection 

against misuse or 

mishandling of 

duck ponds. 

February 2013 SBMP 1 (new Fuel and hazardous material 2.1.9; 2.1.10; 

NPR-A IAP subparagraph storage containers with a capacity Appendix D 

ROD to BMP A-4) greater than 660 gallons must use 

February 2015 impermeable lining and diking 

SEIS ROD capable of containing 110 percent 

of the containers’ capacity. Vinyl 

liners, with foam dikes and a 

capacity of 25 gallons, must be 

placed under all valves or 

connections to fuel tanks when 

located outside of secondary 

containment. 

Alpine Field, Satellites, and Pipelines ODPCP A-42 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

BUREAU OF LAND MANAGEMENT 

CROSS REFERENCE 

BLM 

GOVERNANCE 

DOCUMENT 

MEASURE OBJECTIVE SUMMARY REQUIREMENT RELEVANT PLAN 

SECTION 

February 2013 

NPR-A IAP 

ROD 

February 2015 

SEIS ROD 

SBMP 4 a. Under the requirements 

of 43 CFR 3162.5-1(c) 

and (d), develop a 

contingency plan for 

blowouts, spills, and 

other undesirable events 

that addresses 

equipment and 

communication with 

affected residents. 

Minimize pollution by 

ensuring effective 

hazardous materials 

contingency planning. 

Establish BLM’s role in 

an actual response 

scenario on unitized 

lands and in the ROW 

corridor. 

The appropriate BLM office must 

be notified of any spills or releases 

that occur on unitized lands. 

Thresholds are established under 

BLM’s NTL-2007-01-Alaska for 

incidents that require immediate 

notification (e.g., any blowout that 

occurs; any spill, regardless of 

volume, to water, tundra, or 

undisturbed lands; and spills to 

land greater than 1 barrel for oil). 

1.2 

SBMP 4 b. As part of BLM’s approval of the 

initial Plan, COPA will provide a 

detailed, probabilistic risk 

assessment for spills, a most likely 

trajectory for various environmental 

conditions related to a catastrophic 

spill, and an assessment which 

includes pre-staging equipment 

across the Nigliq Channel. 

1.6; 2.2; 2.3; 2.4; 

3.6.2; Part 5 

SBMP 4 c. The BLM will be provided with upto-date copies of the Alpine C-Plan 

and all amendments to the plan, 

which BLM will review (with respect 

to GMT1) on a five-year basis or as 

otherwise required by the BLM 

Authorized Officer. The BLM 

Authorized Officer reserves the 

right to require changes to the 

contingency plan to ensure 

compliance with Federal 

requirements. 

Introduction, "Plan 

Updating and 

Renewal" 

SBMP 4 d. The BLM will require submission of 

ACS Technical Manual and any 

updates. (This describes all the 

tactics used to control, contain, and 

clean up a spill.) 

Introduction, "Plan 

Supplemental 

Documentation" 

SBMP 4 e. If the Unified Plan is enacted, the 

Federal On-Scene Coordinator 

(FOSC) is responsible for directing 

the emergency spill response. On 

unitized and Federal lands, 

necessary measures to control and 

remove pollutants and to extinguish 

fires are subject to the approval of 

the BLM Authorized Officer. 

3.3 

SBMP 4 f. If there is a spill due to system 

failure which necessitates an 

emergency shut-down of 

equipment or other in-Unit 

undesirable event as defined by 

NTL-2007-01-Alaska, BLM will be 

notified prior to system restart. 

This will ensure that repair was 

appropriately and correctly done, 

and that appropriate investigations 

into the root cause of the spill will 

occur. 

1.2 

Alpine Field, Satellites, and Pipelines ODPCP A-43 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

BUREAU OF LAND MANAGEMENT 

CROSS REFERENCE 

BLM 

GOVERNANCE 

DOCUMENT 

MEASURE OBJECTIVE SUMMARY REQUIREMENT RELEVANT PLAN 

SECTION 

SBMP 4 g. The BLM will require that specific 

tactics (e.g., boom locations, 

access locations, staging areas, 

etc.) be described for drainages 

(Crea Creek, Barkley Creek and 

Tinmiaqsiugvik (Ublutuoch) River) 

in the GMT1 area, while 

recognizing that actual spill 

response would be based on 

conditions of the time of the spill. 

3.6.2 

SBMP 4 h. The BLM will require that the Alpine 

C-Plan be amended with specific 

facility descriptions for GMT1, 

including (Section 3.10) specific 

environmental features and 

sensitive areas. 

1.8; 3.1; 3.2; 3.4; 

3.10 

SBMP 4 i. An emergency countermeasure 

plan must include well capping if 

technically feasible. 

1.6.3; 1.9; 4.2 

Preparedness 

Plan 

Requirement a. 

The BLM will observe and evaluate 

responder training and response 

exercises to ascertain response 

readiness. The permittee will 

accommodate BLM’s observation 

of training efforts. 

3.9.6 

Preparedness 

Plan 

Requirement b. 

If satellite fields developed in the 

NPR-A become a significant 

portion of the Alpine Development 

Area, BLM be will periodically 

check the availability of immediate 

incident responders and to monitor 

training records. 

3.9.6 

Preparedness 

Plan 

Requirement c. 

If any pre-deployed boom is 

identified for the GMT1 area, BLM 

requires amendment of Alpine CPlan to show its location. 

3.6.2 

SBMP 5 Implement leak detection 

systems for GMT1 

facilities. 

To the extent practicable, the 

permittee will provide a specific 

description of the leak detections 

systems installed on all lines 

described in the development plan. 

The descriptions could be an 

addendum to the Alpine C-Plan or 

a stand-alone document. 

Monitoring would be via remote 

continual monitoring (e.g., camera 

or FLIR) of water crossings, or daily 

on-site visual inspections. The spill 

prevention section of the Alpine CPlan must contain criteria to 

prevent and detect slow leaks. 

2.1.7 

Alpine Field, Satellites, and Pipelines ODPCP A-44 February 2018, Rev. 0 
APPENDIX B 

ALPINE PROJECT: OIL PIPELINE SPILL ISOLATION STRATEGY 
BLANK PAGE 
Al pine Development 

Mpine Project: Oil Pipeline Spill Isolation Strategy 

Prepuedfor 

ARCOALASKA, INC. 

ALPINE DEVE LCPMENT PROJE CI 

by 

- aker 

Michael Baker Jr., In::. 

4aJ 1 Business Park Blvd., Suite 42 

An::horage, AK 9":J 113 

23100-MBJ-RP-005 

December 8, 1998 
Contents 

Executive Summary ....................................................... 1 

1.0 Introduction ........................................................ 2 

1.1 Regulatory Requirements ............................................ 2 

1.2 Valve Installation Option ................. . .......... . ... . ........... 3 

1.3 Pipeline Profile Change Option ....................................... 3 

2.0 Pipeline Description ........................... . .... . ................. 4 

3.0 Vertical Loop Operation and Design Description .......................... 5 

4.0 Pipeline Leak Scenarios ............................ . ................. 6 

5.0 Spill Volume Determination .................... . ...................... 7 

5 .1 Oil Spill Volume Prior to Leak Detection .. . ............................ 7 

5 .2 Oil Spill Volume During Operator Reaction ........................ . .... 8 

5.3 Oil Spill Volume During Valve Closure and Pipeline Depressuring ........... 9 

5.4 Oil Spill Volume Due to Pipeline Draindown ........................... 10 

5.5 Oil Spill Volume Summary ......................................... 11 

6.0 Summary and Conclusions ........................................... 12 

7.0 Figures 

Figure 1. 

Figure 2. 

Figure 3. 

Figure 4. 

Figure 5. 

·aker 

........................................................... 13 

Vertical Pipeline Loop Schematic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 

Isolation Block Valve Location Plan. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 

Vertical Loop Location Plan. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 

Pipeline with Vertical Loops Schematic . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 

Pipeline Elevation Profile and Vertical Loop Location. . . . . . . . . . . . . . . . 22 

23100-MBJ-RP-005, Alpine Project: Oil Pipeline Spill Isolation Strategy 

Edition I, Rev. 0, December 7, 1998 

ii 
Executive Summary 

Alternative options for isolating and minimizing the volume of oil during a contingency spill event 

are evaluated and compared using the methodology outline by the California State Fire Marshall 

Report: "Hazardous Liquid Pipeline Risk Assessment." The first option is a conventional valving 

strategy, and the second utilizes passive pipeline profile changes constructed with vertical loops. Two 

types ofleaks are evaluated: a pinhole leak and a guillotine failure. 

The four contributing components to pipeline spillage considered in the evaluation are: 

1. Oil spilled during length of time to detection. 

2. Oil spilled operator reaction time. 

3. Oil spilled during valve closure time and pipeline/fluid decompression. 

4. Oil spilled during pipeline draindown. 

The pinhole leak case is considered the more likely spill scenario. Two classes of pinhole leaks are 

analyzed, those with release rates under the leak detection system detection limit and those with 

release rates over the detection limit. For very small leaks, those under the detection limit, the volume 

of oil spilled during the length of time to detection, is by far the major contributor to the total 

potential oil spill volume for both the conventional valve and the vertical loop cases. The second 

biggest component of spill volume for the pinhole case is oil spilled during valve closure and 

pipeline/fluid decompression. Compared to remote operated valves (ROVs), the option utilizing 

vertical pipeline loops is found to be considerably more effective at minimizing the oil spill volume 

by not trapping line pressure between adjacent valves. It is concluded that the option utilizing vertical 

loops is more effective overall at minimizing spill volume for the pinhole leak scenario. 

The guillotine failure is considered an extremely unlikely scenario. For this case, the last spill 

component, oil spilled during draindown, is the largest component contributing to total projected spill 

volume by an order of magnitude over any other component. Compared to manual isolation block 

valves, vertical loops decrease the projected spill volume by 63% at the Colville River, 98% at the 

Kachemach River, and 92% at the Miluveach River by effectively blocking oil in "pools" in the 

pipeline on the opposite side of the loops. 

It is concluded that the alternative utilizing vertical loops is considerably more effective in 

minimizing spill volumes during contingency spill events. Moreover, the additional possibility of oil 

leakage at the mechanical connections of the valves, traditionally an area of concern and 

maintenance, is eliminated. 

It is recommended that the vertical pipeline loops alternative be utilized for the Alpine Pipeline. 

Summary of December 1998 Revision 

This report was updated in December 1998 to add a new section that further describes the design 

criteria for the vertical loops and illustrates how the loops function. This latest version has also been 

revised to reflect the most recent design refinements. It is now certain that the oil pipeline will be 

cased under the Colville River and the number and location of the vertical loops has been optimized. 

Revised diagrams and text have been included. The decision to use vertical loops (and reasoning) did 

not change. 

 
1.0 Introduction 

The purpose of this study is to investigate and determine the best strategy to minimize the volume of 

an oil spill for the contingency condition of a pipeline leak. There are two alternative strategies to be 

evaluated and compared for their effectiveness in minimizing the oil spill volume during such an 

event for the pipelines connecting the Alpine Development to the Kuparuk system: 

1. Valve Installation, i.e. the case where isolation block valves are installed for the Alpine Project 

oil sales line. This case assumes remotely actuated valves are installed at the inlet and outlet of 

the pipeline with remotely operated valves (ROVs) on the east and west banks of the Colville 

River and manual block valves on the east and west banks of the Kachemach and Miluveach 

Rivers. 

2. Pipeline Profile Changes, i.e. the case where vertical pipeline loops are installed at strategic 

locations to naturally limit oil flow. These loops take advantage of the relatively low terrain relief 

of the North Slope to provide artificial terrain breaks that greatly reduce the size of potential oil 

spills. (See Figure 1 for representative vertical loop schematic.) 

1.1 Regulatory Requirements 

The isolation strategy is based on the following: 

• Code of Federal Regulations Title 49, Part 195 - Transportation of Hazardous Liquids by 

Pipeline (CFR 195) specifies the following requirement for water crossing locations. 

Paragraph 195.260 reads: "Valves: Location. A valve must be installed at each of the following 

locations: ... ( e) On each side of a water crossing that is more than 100 feet wide from high-water 

mark to high-water mark unless the administrator finds in a particular case that valves are not 

justified." 

• ASME B31.4, Liquid Transportation Systems for Hydrocarbons, Liquid Petroleum Gas, 

Anhydrous Ammonia, and Alcohols, repeats the design requirements of CFR 195 for valve 

locations at rivers and streams. 

Paragraph 434.15.2 reads: "Mainline Valves (a) Mainline block valves shall be installed on the 

upstream side of major river crossings and public water supply reservoirs. Either a block or check 

valve shall be installed on the downstream side of major river crossings and public water supply 

reservoirs." 

There is no other specific mention of design requirements for water crossings in either document. The 

issue of valve automation or remote actuation is left to the discretion of the operator, as there is no 

requirement for remotely actuating valves in either CFR 195 or ASME B31.4. In addition, CFR 195 

allows consideration of alternative approaches to isolation strategy if it can be found by the 

administrator that" ... valves are not justified." Thus, if it can be shown that valves are not justified 

and the administrator agrees with these findings, either of the two alternative approaches being 

considered in this study are in compliance with regulatory requirements. 

Additional project criteria to guide isolation block valve strategy include: 

• Install valves (automatic, remotely actuated, or manual) where practical to minimize spill 

volumes. 

• Optimize the number of automatic or remotely actuated valves to maximize environmental 

safeguards. 

• Site block valves at the nominal pipeline elevation, 5 feet above grade, outside the flood zone 

bounded by the high-water marks to allow access ifrequired during floods. 

• Utilize pipe elevation changes where practical to provide drainage breaks. 

 
Based on the regulations, there are three river/stream crossings along the pipeline right-of-way 

(ROW) that require consideration of an isolation strategy based on the aforementioned regulations: 

the Colville River, Kachemach River, and :Miluveach River. The Colville River crossing requires 

careful consideration due to the length of the crossing and the sensitive environmental issues 

involved in this area. The Kachemach River and Miluveach River crossings require consideration 

because they can extend over 100 feet in width during high-water events, although this width extent 

is forecasted to occur an average of only two days per year for each river. 

1.2 Valve Installation Option 

Remotely actuated valves have been initially proposed at the Colville River crossing for evaluation 

since they reduce valve closure time. Manually operated block valves have been proposed for 

installation at the Kachemach and :Miluveach River crossings, because the pipeline is aboveground, 

allowing access for regular pipeline preventative maintenance, early repair, and emergency access. 

(See Figure 2 for Isolation Block Valve Location Plan). 

Small leaks on pipelines are often associated with valves, flanges, and related fittings. Small leaks 

often cause the largest spills. Valves are a frequent source ofleaks since valves usually have several 

fittings that could potentially leak. In the case ofremotely actuated valves, the potential for spills is 

increased since a valve/actuator could fail closed, potentially causing a fluid hammer condition that 

could overpressure the line. Another failure scenario, failure to close, while not adding to the risk of a 

spill, could allow more oil to spill and perhaps jeopardize the integrity of the spill response plan. A 

substantial portion of the leaks that have occurred in the Kuparuk River field, from both common 

carrier and unregulated lines, have been at valves and fittings. 

1.3 Pipeline Profile Change Option 

The alternative of placing vertical loops at all required locations in the pipeline in lieu of valve 

hardware (except those at the pipeline inlet and outlet) was developed in recognition of the relatively 

low terrain relief of the North Slope and the spill risks associated with valves. These loops would be 

installed in the pipeline to form a terrace structure that would significantly limit the amount of oil 

spilled due to draindown effects. (See Figure 3 for Vertical Loop Location Plan). The potential 

pipeline spill volumes with this design is less than the potential spill volumes associated with the 

valved pipeline alternative. 

Vertical loops perform the same function as check valves without the hydraulic inefficiencies and 

maintenance concerns associated with check valves. The long radius bends used to construct vertical 

loops are the same as those used in standard expansion loops and are considered equivalent to straight 

pipe. The loops meet the requirements of CFR 195. (See Figure 4 for Vertical Loop Location Profile) 

Inclusion of vertical pipeline loops for isolation in the pipeline design provides several advantages 

besides reducing the risk of spills and limiting the size of spills. The loops do not require maintenance 

and testing as do block valves. This results in elimination of gravel heliports on the tundra and 

reduces tundra access requirements. In addition, vertical loops provide crossing points for the northsouth movement of caribou near the streams and other points along the pipeline ROW. The upper run 

of the vertical loops will range between 15 and 45 feet off the ground, providing substantial 

clearance. The pipeline crossing points provided by the loops can also be used by individuals from 

lht: m;arby villagt: ofNuiqsul for subsislt:nct: aclivily acct:ss. 

 
2.0 Pipeline Description 

The sales oil pipeline is routed primarily aboveground on vertical support members (VSMs). It is 

underground at only one location, the Colville River crossing. The pipeline is fabricated using 

14-inch diameter high strength line pipe. The pipe in the aboveground portion is uncoated steel pipe, 

insulated with polyurethane protected by a metal jacket. 

The belowground portion at the Colville River crossing is installed by horizontal directional drilling 

(HDD) inside a high strength casing pipe. Both the casing and carrier pipe at this location are 

externally coated. Protection against corrosion of the belowground oil pipeline is provided by the 

external coating and the casing pipe. The casing pipe is protected against corrosion by the external 

coating and a cathodic protection system Addition of a casing pipe in the HDD design complements 

the vertical loop effectiveness in reducing the amount of oil spilled. The casing addresses the 

concerns ofleak detection and leak containment under the river. 

Actuated pipeline inlet and outlet block valves are incorporated in both the base case and the vertical 

loop case. These valves would be closed in the event of an emergency such as a spill. Emergency 

pressure relief valves at each end of the pipeline would be opened to drop the pressure in the pipeline 

in the event of a spill. These valves play a significant role in reducing the volume of oil leaked during 

a spill. These valves will be located at facilities where routine inspections and maintenance can detect 

and minimize leaks. Ifleaks should occur at these valves, they will be contained on gravel pads or 

within buildings. 

The 39° API gravity crnde oil transported by the pipeline is fairly light compared to most other North 

Slope crnde oils. However, it has a paraffin content that starts to precipitate (wax point) at 

approximately 89°F. The 3-inch pipeline insulation layer along with the 100°F minimum operating 

temperature of the pipeline accommodates the crnde oil wax point plus a safety factor. The additional 

pipeline height in the vertical loops does not add to the potential cooling, waxing or freezing of the 

pipeline. 

Vertical loops are viewed the same as the standard expansion loops and straight pipe with respect to 

thermal effects. There is no measurable increase in heat loss due to the increased elevation of the 

vertical loops. Heat loss along the entire pipeline and its effects on pipeline startup, operation and 

shutdown, are being addressed as part of the detailed engineering design. This will determine the 

allowable pipeline shutdown duration limits. 

 
3.0 Vertical Loop Operation and Design Description 

The alternative of placing vertical loops in the pipeline in lieu of valves, except those at the pipeline 

inlet and outlet, was developed in recognition of the relatively low relief terrain of the North Slope 

and the spill risks associated with valves. The proposed loops form a terrace structure to limit the 

amount of oil spilled due to draindown effects. Vertical loops are essentially hat configuration 

expansion loops with the outboard run elevated to a pre-determined elevation to limit pipeline 

draindown caused by an elevation difference. 

The vertical loops work by creating hydraulic break points in the pipeline where the fluid in the 

pipeline will be contained between the loops and other high points along the route, performing a 

function similar to valves but without the hydraulic inefficiencies and maintenance concerns. The 

operating effectiveness of the loops is primarily dependent on inlet and outlet block valves that are 

closed when a leak is detected. The pipeline inlet and outlet block valves create a closed system with 

no way for a siphon to develop. 

A vertical overlap from one loop to another encourages vapor space formation primarily in the 

vertical and horizontal runs of the loops and not in the long runs of the pipeline between the loops. 

Some vapor spaces (small discrete bubbles) will form in the horizontal runs but they have little effect 

on the system. Both bench scale testing and computer simulation indicates that formation of vapor 

spaces within the vertical loops will stop flow and trap the volume ofliquid in the horizontal runs 

between the loops. 

The height of the vertical loops in a pipeline system is a function of the pipeline right-of-way terrain 

profile. An optimal solution would incorporate loops of varying heights based on the location of the 

rivers, hills, and other geographic features. In addition, vertical loop siting does not have to take into 

account access for maintenance activities since they do not require maintenance. They can be 

optimally sited to minimize spill volumes. 

In the field, it is anticipated that during a leak event, the pipeline will be shut down and the inlet and 

outlet block valves at the ends of the pipeline will be closed. At the same time, the divert valves will 

open long enough to depressurize the pipeline and drain the line pack into tanks at the inlet and outlet 

facilities. When the pipeline is depressurized, the divert valves will close. During a depressurization 

event, the single-phase fluids become multi-phase and vapor spaces will begin forming at the high 

points. 

At this time, the net flow is toward the leak. However, the oil at the highest point in the pipeline will 

quickly reach its bubble point or vapor pressure and flash, forming a vapor space. The free liquid 

surface in the downhill side of the vertical loop drops as the line drains. When the liquid level in the 

highest loop drops to the elevation of the next highest loop the oil in that loop will flash, again 

forming a vapor space. The oil between the two vapor spaces is effectively isolated from the rest of 

the pipeline and from the leak. This mechanism will continue the length of the pipeline from vertical 

loop to vertical loop all the way to the leak site. The estimated volume of oil that could spill is the 

amount contained between the loops on each side of the leak plus a small amount of the oil in the 

vertical loops. 

Figure 4a-fillustrates the operation of vertical loops. See Figure 5 for the Vertical Loop Location 

Profile proposed for the Alpine Pipeline. The loops in final design are expected to range from 15' to 

45' aboveground, and at a minimum, will be placed on each side of major river crossings (that are 

greater than 100 feet wide) to comply with US DOT requirements. Figure 5a-c illustrates where 

liquid would be retained in the system in case of a leak at the Colville, Kachemach, and Miluveach 

Rivers, respectively. 

 
4.0 Pipeline Leak Scenarios 

This report conservatively assumes that any pipeline failure mechanisms would result in either: 

• A pinhole leak below the detection limit, or 

• A pinhole leak above the detection limit, or 

• A guillotine failure. 

The pinhole leak represents the maximum risk from a difficulty of detection. The guillotine failure 

represents the maximum spill volume per unit time. The evaluation and comparison of both options 

spans the range of risk for the pipeline. Both cases are investigated and compared for the alternative 

spill isolation strategies in this study. 

Pinhole leaks can range in size from a true pinhole, perhaps caused by weld porosity or corrosion 

pitting, to a cracked weld or leaking valve fitting. As the name implies, this type ofleak is often very 

small and usually very difficult to detect. Consequently, they can exist until the threshold of the leak 

detection system is crossed or they are visually discovered. This can result in oil releases significantly 

greater than for any other type ofleak. 

Guillotine cuts, visualized as the complete severing of a pipeline, can result in fairly large volumes of 

oil spilled. This type ofleak can be caused by human activity such as construction accidents, pipe 

rupture due to overpressure, pipe failure due to defects in the material, or earth movement due to 

seismic events. 

The potential for failure due to human activity is extremely low since the pipeline is routed crosscountry and not adjacent to any roads or worksites. The risk of failure due to overpressure is also very 

low due to redundancy of the overpressure protection systems, as well as the design safety factors 

incorporated into the material and structural design. Pressure surges are the likely source of 

overpressure and they have been accounted for in the design of the line and the various support 

systems. Pipe failure due to defects in the material requires that a manufacturing or construction 

defect occur simultaneously with high pipe stress. Hydrotesting identifies these flaws since 

maximum operating stresses are less than the hydrotest stresses. 

The final possible cause of a guillotine failure, seismic effects on the pipeline, are considered 

inconsequential since this is a UBC Seismic Zone 0, coincident with the lowest seismic zone for 

TAPS. As such, the expected seismic acceleration is 0.05g, resulting in less loading on the pipeline 

than that caused by the wind. 

While the probability of catastrophic failure is remote, the nature of catastrophic pipeline failures 

causes them to be quickly detected by the leak detection system. 

 
5.0 Spill Volume Determination 

In the event of a pipeline failure, the amount of oil spilled is the sum of several components. This 

report uses component descriptions similar to those given in the California State Fire Marshall Report 

"Hazardous Liquid Pipeline Risk Assessment." They are as follows: 

• Length of time to detection, 

• Operator reaction time, 

• Valve close time and pipeline/fluid decompression, and 

• Pipeline drainage. 

The major contributor to the volume of oil spilled due to a catastrophic pipeline failure is the pipeline 

depressuring and pipeline drainage. Due to the nature of the failure, the volume spilled during the 

time to detection would be relatively small. On the other hand, the major contributor to the volume of 

oil spilled due to a pinhole leak is the length of time to detection, since the very low leak rates can be 

lower than the detection threshold of the leak detection system. 

The potential leak scenarios have been modeled with the commercial software package, NATASHA 

(Network Algorithm for Transient And Steady Hydraulic Analysis). The complete pipeline system, 

including reaction times and the potential leak scenarios, were determined as separate analytical 

scenarios using the software program. 

5.1 Oil Spill Volume Prior to Leak Detection 

The length of time to detection is dependent on the sensitivity and detection threshold of the detection 

system and the spill flow rate. As a result, dependence on the leak detection system alone could allow 

pinhole leaks to go undetected for days. Aerial inspections play a major role in detection of very 

small leaks. 

The regularly scheduled Twin Otter flights to and from the Alpine production facility, as well as 

flights to the village of Nuiqsut and beyond, would be routed over the pipeline. The aircraft is 

equipped with a forward-looking infrared (FUR) system, which can detect very small temperature 

differences. This equipment is also capable ofidentifying areas where the pipeline insulation is 

damaged or saturated with water, both indicators of possible external corrosion and/or pipe damage. 

Preventative maintenance can then be scheduled. 

The volume of oil spilled before the leak is detected is a function of the leak rate and the leak 

detection system sensitivity. A small, low rate leak can spill substantially more oil before it is 

detected than a larger, high rate leak. Assuming a 0.3 5% of flow leak detection limit, the system's 

leak detection threshold for a pinhole leak is approximately 7 gallons per minute or 244 bbls per day. 

If the pipeline leak detection system cannot "see" this leak and the visual inspection interval 

conforms to CFR 195.412, Paragraph A ("Each Operator shall, at intervals not exceeding 3 weeks, 

but at least 26 time each calendar year, inspect the surface conditions on the right-of-way."), then as 

much as 5124 barrels could be spilled before it is visually detected. However, a spill volume this 

large is unlikely even if the leak rate is below the leak detection threshold. In practice, the "overs" and 

"unders" trending would indicate that a problem existed and a visual inspection would be performed. 

In comparison, any leak above the detection threshold should be quickly identified resulting in a 

much lower volume of oil spilled before detection. 

In the event of a catastrophic failure, it is assumed that the entire line pack depressurizes through the 

leak during the time to detection phase. 

Table 5-1 shows that the amount of oil spilled for each of the comparable cases is the same. 

 
Table 5-1. Volume of Oil Spilled Before Detection (bbls) 

Colville R. Kachemach R. Miluveach R. 

Isolation Valves 

Pinhole under Threshold 5124 5124 5124 

Pinhole over Threshold 0.09 0.09 0.09 

Catastrophic Failure 279.2 279.2 279.2 

Vertical Loops 

Pinhole under Threshold 5124 5124 5124 

Pinhole over Threshold 0.09 0.09 0.09 

Catastrophic Failure 279.2 279.2 279.2 

5.2 Oil Spill Volume During Operator Reaction 

The pump runtime after detection of a pinhole leak depends on whether the shutdown system is 

automated, or it must depend on operator response. An automated system could be shutdown in 

minutes while an operator directed shutdown could take hours depending on the operators 

interpretation of the data supplied by the system. In either case the closure signal for remote actuated 

block valves is usually sent at the same time the pump shutdown signal is sent. The valve time to 

close, which is based on fluid hammer calculations, is then measured in seconds to minutes. In 

contrast, the time to closure for manually operated valves can be measured in hours to days, 

depending on the time of year, weather conditions and available vehicles for access to the valves. 

As noted above, the pump runtime after leak detection is dependent on whether the shutdown system 

is automated or it must depend on operator response. An automated system could send a pump stop 

signal within 30 seconds. However, an automated system takes away operator discretion, potentially 

initiating unjustified or nuisance valve closures. An automated system, tuned and adjusted to avoid 

nuisance valve closures, would not be significantly faster than an operator controlled system. In the 

case of a catastrophic failure, the operator response time to shut down the pumps would be nearly as 

fast as an automated system. Intermediate sized leaks, those in the range between the detection 

threshold and the catastrophic failure, would require more time to verify. Obviously, the time to 

verify is dependent on the size of the leak with large leaks taking the least time. However, the time to 

verify is not proportional to the size of the leak. Visual verification of leaks just above the detection 

threshold could take as long as 12 hours. This uncertainty in time to verify results in assuming, for the 

purposes of this report only, that the operating philosophy of the Alpine pipeline will be to treat all 

leak alarms as leaks where the line would be shutdown immediately on detection. It is assumed for 

this report that the operator reaction time for all leaks is 60 seconds. In reality, low-level leaks will be 

visually verified before the pipeline is shutdown. 

Table 5-2 shows there is no difference in spill volumes between the isolation block valve case and the 

vertical loop case for all scenarios. 

 
Table 5-2. Volume of Oil Spilled During Operator Reaction (bbls) 

Colville R. Kachemach R. Miluveach R. 

Isolation Valves 

Pinhole under Threshold 0.17 0.17 0.17 

Pinhole over Threshold 0.17 0.17 0.17 

Catastrophic Failure 48.6 48.6 48.6 

Vertical Loops 

Pinhole under Threshold 0.17 0.17 0.17 

Pinhole over Threshold 0.17 0.17 0.17 

Catastrophic Failure 48.6 48.6 48.6 

5.3 Oil Spill Volume During Valve Closure and Pipeline Depressuring 

The major contributor to the volume of oil spilled due to a pinhole leak is the amount spilled before 

detection. At that point, the pipeline can be quickly shutdown and depressured thus eliminating the 

motive force for the spill. As noted above, the pump runtime is a function of the system or operator 

response time. 

The signal to close the block valves would be sent at the same time as the pump shutdown signal. The 

pipeline block valves are designed to close as fast as possible without generating severe hydraulic 

transients that may overpressure the pipeline. The approximate volume of oil spilled during valve 

closure is manually calculated by multiplying the flow rate by the valve close time divided by two. 

The accuracy is significantly impacted by opening the emergency pressure relief valves located at the 

pipeline inlet and outlet. The NATASHA program was used to model the effects of simultaneous 

relief valve opening and block valve closing and accurately calculates the volume spilled. 

The vertical loop equipped pipeline is not dependent on isolation block valve closure to stop 

depressurization through a leak. The instant the pumps are stopped, the line depressurizes through the 

pressure relief valves. Inertia maintains flow for only a few moments and has no significant effect on 

total volume. 

There are two components to the volume of oil spilled due to a pipeline depressuring to atmospheric 

pressure. They are the elasticity of the pipeline and the compressibility of the oil in the pipeline. The 

pipeline elasticity portion is comprised of hoop stress expansion and longitudinal expansion, both due 

to internal pressure. The NATASHA computer program accounts for the pipeline elasticity and the oil 

compressibility in its calculation of the potential spills volumes for the various scenarios. 

In pipelines equipped with ROVs, the isolated pipeline segment containing the leak will depressurize 

through the leak after the valves have closed. Slowing the operation ofROVs would reduce the 

amount of oil released in the depressurizing phase of a leak but this configuration runs counter to the 

requirement to close as fast as possible to limit a release in the event of a catastrophic failure. An 

ROV that fails to close could allow release of the entire line pack. This also applies to manual block 

valves since they will have long close times. Emergency pressure relief valves have been 

incorporated in the pipeline design for both the valved case and the vertical loop case to quickly drop 

the pipeline pressure and reduce the potential oil spill volume. Emergency pressure relief valves do 

not provide any spill volume reduction benefit to ROV equipped pipelines with pinhole leaks since 

 
the ROVs isolate the pressurized segments as noted above. Emergency relief valves are very effective 

with manual block valves for pipeline depressuring due to the long block valve close time but have 

very little effect ifROVs are installed. 

Table 5-3. Volume of Oil Spilled During Valve Closure and Pipeline Depressuring (bbls) 

Isolation Valves 

Pinhole under Threshold 

Pinhole over Threshold 

Catastrophic Failure 

Vertical Loops 

Pinhole under Threshold 

Pinhole over Threshold 

Catastrophic Failure 

Colville R. 

16.77 

16.79 

24.31 

0.29 

0.29 

24.31 

Kachemach R. 

0.27 

0.32 

24.31 

0.26 

0.30 

24.31 

Miluveach R. 

0.25 

0.32 

24.31 

0.26 

0.26 

24.31 

As noted above, it is assumed that the entire line pack depressurizes through the leak during the time 

to detection phase in the event of a catastrophic failure. 

5.4 Oil Spill Volume Due to Pipeline Draindown 

Pipeline drainage can be the largest contributor to total pipeline spill volumes. The purpose of 

isolation block valves is to limit the volume of oil spilled due to drainage. However, their 

effectiveness depends on the valve close time. Remote actuated block valves can be very effective in 

reducing the volume due to drainage. Manual block valves are less effective. However, pipeline 

drainage contributes little to the total spill volume associated with pinhole leaks so automating or 

remotely actuating the block valves has little to no effect on reducing the volume of oil released. It is 

assumed that the manual block valve close time is on the order of twelve hours. This length of time 

accounts for equipment and crew mobilization and travel time to the block valves during severe 

weather. This extended close time would allow a substantial portion of the oil uphill from the leak to 

spill out through the leak in the event of a catastrophic failure. 

Table 5-4 above shows that manual isolation block valves are not as effective as ROVs for reducing 

the amount of oil spilled in the pipeline drainage case. However, any benefit gained by installing 

actuated valves at the Kachemach and Miluveach Rivers is offset by the increased volume of oil 

spilled in the pipeline depressuring case with the result being no net improvement. Vertical loops are 

slightly more effective than manual block valves at limiting drainage spill volumes due to pinhole 

leaks. Vertical loops offer a substantial advantage over manual block valves for the drainage 

component due catastrophic failure. 

 
Table 5-4. Volume of Oil Spilled Due to Pipeline Drainage (bbls) 

Isolation Valves 

Pinhole under Threshold 

Pinhole over Threshold 

Catastrophic Failure 

Vertical Loops 

Pinhole under Threshold 

Pinhole over Threshold 

Catastrophic Failure 

5.5 Oil Spill Volume Summary 

Colville R. 

1.00 

1.00 

2375.5 

11.78 

11.83 

871.6 

Kachemach R. 

13.94 

14.02 

6158.1 

11.90 

11.95 

126.4 

Miluveach R. 

10.26 

10.33 

4615.8 

8.82 

8.88 

375.6 

The total volume of oil spilled in all the scenarios is the sum of the components identified and is 

shown in Table 5-5. The table shows that vertical loops installed in lieu of isolation block valves 

results in less oil released in all scenarios evaluated. 

Table 5-5. Total Volume of Oil Spilled (bbls) 

Isolation Valves 

Pinhole under Threshold 

Pinhole over Threshold 

Catastrophic Failure 

Vertical Loops 

Pinhole under Threshold 

Pinhole over Threshold 

Catastrophic Failure 

 

Colville R. Kachemach R. Miluveach R. 

5141.9 5138.4 5134.7 

18.0 14.6 10.9 

2727.6 6510.2 4967.9 

5136.2 5136.4 5133.2 

12.4 12.5 9.4 

1223.8 478.6 727.7 

 
6.0 Summary and Conclusions 

The four major components that contribute to spill volume (time to detection, operator response, 

pipeline depressurization, and pipeline drainage) have been evaluated for both the isolation block 

valve and vertical loop alternatives. They were evaluated by consideration of pinhole leaks and a 

complete guillotine failure for each alternative. 

It can be concluded that manual isolation valves, in combination with emergency relief valves, are 

superior to ROVs for the pipeline depressuring case and that remote operated valves are marginally 

superior to manual isolation valves and vertical pipeline loops only for the pipeline drainage case in 

the event of a pinhole leak. However, vertical pipeline loops, in combination with emergency relief 

valves, are superior to both remote operated valves and manual operated valves for the following 

reasons: 

• The total volume of spilled oil due to both pinhole and catastrophic pipeline failures is greater 

with both ROVs and manual isolation block valves than with vertical loops and emergency relief 

valves. 

• Valves increase the risk of spills by introducing potential leak sources. 

• Vertical loops do not require tundra access for inspection or maintenance. Vertical loops can be 

optimally sited to minimize spill volumes since their siting does not have to take into account 

access for maintenance activities since they do not require maintenance. 

• Manual isolation block valves require access to use. Vertical loops are passive and do not require 

operator action to be used. 

• Valves can fail. Vertical loops have no fittings or moving parts to fail. 

It is concluded that vertical pipeline loops are considerably more effective in minimizing spill 

volumes during spill events. In addition, the increased possibility of oil leakage at the mechanical 

connections of the valves, traditionally an area of concern and maintenance, is eliminated. 

 
7.0 Figures 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Figure 1. Vertical Pipeline Loop Schematic 

 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Figure 2. Isolation Block Valve Location Plan 

 
Figure 3. Vertical Loop Location Plan 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Figure 4. Pipeline with Vertical Loops Schematic 

 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Figure 4. (cont'd) 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Figure 4. (cont'd) 

 

 

 

 

 

 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Figure 4. (cont'd) 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
 

Figure 5: Pipeline Elevation Profile and Vertical Loop Location 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Figure 5A: Liquid Entrapment for Colville River Leak 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Figure 5B: Liquid Entrapment for Kachemach River Leak 

 

 

 

 

 

 

 

 

 

 

 
 

Figure SC: Liquid Entrapment for Miluveach River Leak 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

APPENDIX C 

ALPINE OIL SPILL HISTORY 
BLANK PAGE
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TABLE C-1: ALPINE HISTORY OF OIL SPILLS GREATER THAN 55 GALLONS 

Date Location Volume 

(Gal) Product Cause Explanation Source General Cause General Cause Category Corrective Action 

5/4/1999 Alpine 252 Diesel-98%, 

Glycol-1%, 

Motor Oil-1% 

Traveling too fast for road 

condition. 

Heavy Equipment/ 

Mobile Equipment/ 

Vehicles 

Human Error Human Factors Reduce speed during warm weather. 

4/24/2000 Mud Plant 500 Hydraulic Fluid100% Cargo not secured. Tanks Human Error Human Factors Ensure cargo is properly secured for working 

environment. 

1/5/2001 M1 

WWTP 

210 Diesel-95%, 

Grey water-5% 

High/Low level control on tank 

failed. 

Tanks Leak Structural/ 

Mechanical 

Repair Controls 

2/14/2001 CD-1 75 Hydraulic Fluid100% Sight glass hose failure on a 

hydraulic tank inside a lube 

truck. Tubing failure on sight 

glass was caused by excessive 

heat from a 28kW generator 

inside the box unit of the Lube 

truck. 

Tanks Gauge/ Site 

Glass Failure 

Structural/ 

Mechanical 

Install a thermostatically controlled vent in the 

box unit of the lube truck. 

3/29/2001 CD-1 126 Diesel-100% Tank fill valve not closed. (Spill 

was all to secondary 

containment) 

Tanks Valve Failure Structural/ 

Mechanical 

Review/revise tank filling procedures 

7/15/2001 CD2-33 252 100% Other Flow line plugged while 

cementing surface casing and 

spilled drilling mud. 

Fittings/ seals/ 

connections 

Leak Structural/ 

Mechanical 

9/25/2001 Airstrip 600 100% Aviation 

Fuel 

Aviation accident; unavoidable 

collision caused damage to fuel 

tank. 

Heavy Equipment/ 

Mobile Equipment/ 

Vehicles 

Collision/ 

Allison 

Structural/ 

Mechanical 

Review aviation procedures for take off/landing. 

5/11/2002 CD1-25 64 Diesel-100% The tank return valve was not 

closed between completing one 

process and starting another 

operation. As a result the diesel 

tank was overfilled. 

Tanks Human Error Human Factors 1. This hot oil unit has high level alarms (audible 

with small red lights) they are going to install a 

flashing beacon to this system also, this should 

increase alarm awareness. 2. Little Red will also 

put together a new spill prevention awareness 

presentation that covers recent spills as well as 

ways to prevent further spills, they did this last 

year, and it was very effective. It includes a open 

forum with all employees, looking for ways to 

improve spill performance. 

12/17/2002 Mud Plant 275 Mineral Oil100% While transferring mineral oil 

into tank, tank was overfilled. 

Spill was contained in a lined 

secondary area. 

Tanks Overfill Human Factors A Tap Root investigation was conducted on this 

spill to determine the root cause of the spill and 

the recommended remedial actions. The 

remedial actions include updating procedures 

and auditing of those procedures. 

Alpine Field, Satellites, and Pipelines ODPCP C-1 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

TABLE C-1 (CONTINUED): ALPINE HISTORY OF OIL SPILLS GREATER THAN 55 GALLONS 

Date Location Volume 

(Gal) Product Cause Explanation Source General Cause General Cause Category Corrective Action 

3/18/2004 CD2 420 Diesel-100% Hose failure on frac tank. Transfer hoses Equipment 

Failure 

Structural/ 

Mechanical 

1. Place Frac Tank Equipment in Schlumberger’s 

STEM tracking database for PM. Perform PM of 

Frac Tank Equipment annually. 2. Assure a Frac 

Crew representative is present when setting up 

Frac tanks and manifold. Add this step to Frac 

Tank Rig-Up procedure. 3. Have spare hoses 

available on site prior to filling tanks and 

throughout the frac job 4. Add steps 2&3 to SOPs 

for all fracs on CPA sites. 

3/26/2004 Mud Plant 67 Diesel-100% Overfilled fuel truck. Heavy equipment/ 

mobile equipment/ 

vehicles 

Overfill Human Factors 1. Develop a written fueling procedure for the fuel 

truck. 2. Ensure that adequate operator training 

and handover occurs for rental equipment. 3. 

Contact Airport Rentals or manufacturer and 

make them aware of the secondary containment 

drain. 4. Conduct safety/environment process 

review of new equipment or rented equipment 

coming into the field for the first time. 5. Review 

emergency procedures for fluid transfer stations, 

diesel loading, gas tank, and aviation fuel. 

8/11/2005 CD4 136.8 Diesel-100% 136-gallons of diesel fuel was 

discovered in the Nanuq #3 well 

cellar from a presumed leak in 

the well annulus. 

Pipe/flowlines/ 

hardlines 

Unknown Unknown Well diagnostics were performed; however, the 

source of the leak could not be determined. 

10/2/2005 CD2 500 Produced Water100% The Class II storage cell liner 

developed a tear. 

Sumps Leak Structural/ 

Mechanical 

Cell liner is being inspected and repaired. 

4/6/2006 CD3 210 Crude-5%, 

Brine-95% 

Approximately 2 to 5 bbls of 

brine (95%) and crude (5%) was 

blown out a flare stack during a 

well flow back operation on 

Alpine CD3 pad (well CD3-109). 

Flares Unknown Unknown 1. Generate a specific procedure for the test 

package that explains how to FCO all systems 

with a checklist that includes all safety systems. 

Require use of the checklist and procedure at all 

times. 2. Require use of the heater in the 

scrubber building. Include the heater FCO in the 

procedure and checklist 3. Require the use of 

flagging/tagging and a log for defeated safety 

devices. 4. Initiate a hazards analysis for the 

ESD system to identify situations in which safety 

systems do not fail safe and mitigate hazards. 5. 

Audit/evaluate the safety systems on the well test 

package to ensure effectiveness for prevention of 

injury and environmental damage. Include an 

evaluation of hazards posed by personnel 

working in proximity to the well test operation. 

Alpine Field, Satellites, and Pipelines ODPCP C-2 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

TABLE C-1 (CONTINUED): ALPINE HISTORY OF OIL SPILLS GREATER THAN 55 GALLONS 

Date Location Volume 

(Gal) Product Cause Explanation Source General Cause General Cause Category Corrective Action 

4/19/2006 Mud Plant 412 Diesel-100% Open valve on Triplex pump 

during fueling resulted in spill. 

Heavy equipment/ 

mobile equipment/ 

vehicles 

Human Error Human Factors 1. Fleet Maintenance to develop SOP for 

identification and tag out of any new or existing 

equipment that is out of service for repair or 

inspection. The SOP will include major systems 

such as Fuel, Hydraulics, Coolant and Electrical. 

2. Implement minimum criteria for final inspection 

by CPAI representative of new equipment prior to 

shipping to Alpine. 

12/27/2006 Mud Plant 84 100% Other While unloading vac truck into 

tank, operator allowed tank to 

overfill. Released into 

secondary containment. 

Heavy Equipment/ 

Mobile Equipment/ 

Vehicles 

Overfill Human Factors Review transfer procedures. 

1/5/2007 CD1A 440 Crude-10%, 

Produced water90% 

A purge valve on a line from the 

Slop oil tank was mistakenly left 

open after a hydro test. When 

the line was placed back in 

service, produced water and oil 

spilled onto the module floor. 

Fittings/seals/ 

connections 

Human Error Human Factors 1. Modify gas detection system such that when 

the gas heads are bypassed, the alarm that 

sounds on the DCS when 1 gas head detects 

>10% LEL is not suppressed. The system 

response to this alarm (module HVAC 

automatically switches to maximum air changes) 

should not be suppressed either. 2. Modify the 

“Return to Service” section of the energy isolation 

procedure to include a step to notify the Board 

Operator and Lead Operator prior to returning to 

service. 3. Modify the “Return to Service” section 

of the energy isolation procedure to include a 

step to “leak test the system with nitrogen” prior 

to placing in service. 4. Modify the “Return to 

Service” section of the energy isolation form to 

include a step to “ensure that all safety systems 

are back to normal” prior to placing in service. 5. 

Review the Facility Restart Checklist to 

determine whether any on the checklist items on 

it would be appropriate to include in the “Return 

To Service” section of the energy isolation 

procedure. 6. AES Interior hydro test SOP 

revised to address identification of all valves, 

bleeds points, etc...exercised during procedure. 

SOP changes to be communicated to the work 

force. 7. EIP development process to be 

reviewed in toolbox meetings with Operations 

personnel. 

2/21/2008 CD1 840 100% Diesel During frac job, master valve not 

fully closed and tank 

overflowed. 1⁄2 gal spilled 

outside of secondary 

containment. 

Fittings/seals/conn 

ections 

Overfill Structural/ 

Mechanical 

Replaced fittings and reviewed potential reasons 

for camlock failure. Management is replacing the 

wire closures to prevent reoccurrence. 

Alpine Field, Satellites, and Pipelines ODPCP C-3 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TABLE C-1 (CONTINUED): ALPINE HISTORY OF OIL SPILLS GREATER THAN 55 GALLONS 

Date Location Volume 

(Gal) Product Cause Explanation Source General Cause General Cause Category Corrective Action 

3/5/2008 CD3 84 70% Produced 

Water, 30% 

Hydrocarbon 

Mixture 

Camlok hose fitting failure Tanks Equipment 

Failure 

Structural/ 

Mechanical 

An incident investigation will be conducted. 

5/17/2008 CD1 170 99% Crude oil, 

1% Produced 

Water 

Pin hole leak in process piping 

between slop oil tank and inlet 

separator. 

Pipe/flowlines/hardl 

ines 

Corrosion Structural/ 

Mechanical 

1) Repair the known damaged areas with 

temporary clamps. 2) Design and install long 

term repair for this segment of pipe. 3) Assess 

the integrity of the remainder of the slop oil 

system. 4) Assess if similar systems at alpine 

exist and address as appropriate. 5) Review and 

update bases of design for new projects and 

associated engineering specifications to address 

the routing or disposal of off-specification fluids, 

in order to isolate the fluids from process piping 

and equipment. Review and update engineering 

specifications to address piping systems in off 

specification fluid handling service. 6) Write a 

corrosion mitigation procedure to address off 

specification fluid handling in the Kuparuk and 

alpine facilities. 

7/2/2008 CD2 84 100% Crude oil Employee was rigging up to 

pump crude returns from a 500-

gallon tiger tank to production. 

Employee was connecting a 

hose to the flowback tank and 

pulled a 2" fitting from a suction 

line. As he pulled one of the 

ears back on the camlock, it 

began to leak, and it was 

determined that an upstream 

block valve was in the open 

position. The tank valve did not 

have a handle on it, and the 

employee did not verify the 

position of the valve before 

pulling the cam-lock cap. Initially 

all of the spilled material was in 

secondary containment. When 

the tank was demobed and the 

secondary containment 

removed, employees discovered 

that the containment had holes, 

and 8 gallons had leaked 

through to the gravel pad below. 

Tanks Human Error Human Factors All tiger tanks will be inspected prior to being 

used to make sure they are fully functional and 

have handles. All tiger tank valves will need to 

have handles prior to opening them. Supervisor 

shall review the fluid transfer procedures and 

check list with employees. Employees will use 

fluid transfer procedures check list. 

Alpine Field, Satellites, and Pipelines ODPCP C-4 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TABLE C-1 (CONTINUED): ALPINE HISTORY OF OIL SPILLS GREATER THAN 55 GALLONS 

Date Location Volume 

(Gal) Product Cause Explanation Source General Cause General Cause Category Corrective Action 

5/22/2010 CD1 62 100% Hydraulic 

fluid 

It is believed that ice and snow 

pushed up on the quick connect 

fitting rereleasing the oil. 

Coiled tubing 

unit/wireline 

equip/well service 

Leak Structural/ 

Mechanical 

The unit will be on a set inspection schedule 

once / 3 weeks with a developed check list, the 

unit will be kept in full containment. All 4 source 

valves will be left in the closed position, a start 

up/ shutdown checklist will be developed for the 

spooling unit, a bulk head will be installed to dry 

connect the hoses for storage. This will block off 

the ends from activation and ensure they stay 

clean. An updated diagram of the unit will be 

developed and the crews made aware of it. 

3/16/2013 CD1 A7 

Produced 

water 

handling 

1559.8 100% Produced 

water 

A RUPTURED GASKET ON 

THE DISCHARGE OF THE 

SAND-JET SLURRY PUMP IN 

THE ALPINE CFA7 SAND-JET 

MODULE RESULTED IN A 

SPILL OF PRODUCED 

WATER. FAILURE OF 

MULTIPLE SUMP LEVEL 

SWITCHES CAUSE THIS 

WATER TO OVERWHELM THE 

CFA7 MODULE SUMP, THE 

CFG4 "LAST CHANCE" SUMP 

AND ALLOWED A FRACTION 

OF THE FLUID TO FLOW INTO 

THE ACF TANK FARM 

SECONDARY CONTAINMENT. 

WHEN THE CFG4 SUMP WAS 

OVERWHELMED, 

APPROXIMATELY 4 GALLONS 

OF RESIDUAL OIL WAS 

DISPLACED AND WAS ALSO 

SPILLED INTO THE ACF TANK 

FARM SECONDARY 

CONTAINMENT. AS ALL OF 

THE AUTOMATIC SAFETY 

SYSTEMS TO PREVENT 

SUCH AN OVERFLOW EVENT 

HAD FAILED, OPERATOR 

INTERVENTION WAS 

REQUIRED TO PREVENT 

FURTHER ESCALATION OF 

THE SPILL. 

Flanges Equipment 

Failure 

Structural/ 

Mechanical 

THE FOLLOWING ACTION ITEMS CAME OUT 

OF HT EINVESTIGATION: 1.MODIFY A7 

SANDJET PUMP PIPING TO REMOVE 

OVERSTRESS SCENARIO 2.EXTEND G5 

DISCHARGE PIPING INSULATION AND HEAT 

TRACE 3.FLUSH THE 6¿ DIAMETER PIPE 

FROM A7 TO G4 WITH DIESEL TO MITIGATE 

POTENTIAL CORROSION ISSUES 

ASSOCIATED WITH PRODUCED WATER 

CONTAMINATION 4.INVESTIGATE THE BOLTUP FAILURE ON THE A7 SANDJET SLURRY 

PUMP 5.REDESIGN THE LEVEL 

INSTRUMENTATION OF THE A7 MODULE 

SUMP TO PROVIDE MORE RELIABLE 

INDICATION 6.INVESTIGATE THE FAILURE 

OF THE LEAK DETECTION STRIPS 7.EXTEND 

SUMP LEVEL INDICATION MODIFICATIONS 

TO A1, A2, A3, A4, AND E2 MODULES 

RESULTS AS OF 2 APRIL 2013, ACTION 

ITEMS 1-6 ARE COMPLETE AND ACTION 

ITEM 7 IS UNDERWAY. LEAK DETECT STRIP 

CONFIGURATION WAS MODIFIED FROM 

ALARMING ONLY WHEN "WET" TO ALARM 

WHEN THE STRIP DETECTS LIQUID OR 

REGISTERS AS "DIRTY." THIS CHANGE WAS 

CASCADED TO ALL INSTALLATIONS OF THIS 

MODEL OF LEAK DETECTION. BOLT-UP 

PROCEDURES FOR PUMP INSTALLATION 

WERE REVIEWED WITH MECHANICS TO 

ENSURE THAT THEY WILL BE FOLLOWED. 

DESIGN WORK IS ONGOING FOR ACTION 

ITEM 7 TO INSTALL GUIDED WAVE RADAR 

STYLE LEVEL INDICATION IN A1, A2, A3, A4, 

AND E2 MODULES TO MATCH THE NEW 

INSTALLATION IN THE A7 MODULE. 

Alpine Field, Satellites, and Pipelines ODPCP C-5 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TABLE C-1 (CONTINUED): ALPINE HISTORY OF OIL SPILLS GREATER THAN 55 GALLONS 

Date Location Volume 

(Gal) Product Cause Explanation Source General Cause General Cause Category Corrective Action 

5/19/2013 CD1 ACF 265 100% Motor Oil THE LUBE OIL PUMP 

BREAKER WAS NOT 

PROPERLY ISOLATED WHILE 

THE E2 TURBINE WAS DOWN 

FOR MAINTENANCE WHICH 

ALLOWED AN INADVERTENT 

START TO THE SYSTEM. 

WHEN THE PUMP KICKED ON 

THE LUBE OIL RESERVOIR 

WAS PUMPED TO MINIMUM 

LEVELS AND SPILLED INTO 

AND OVERFLOWED THE 

MODULE SUMPS ONTO THE 

MODULE FLOOR. 

Tanks Human Error Human Factors MANAGEMENT WILL BE CLEARLY 

OUTLINING EXPECTATIONS RELATED TO 

ENERGY ISOLATIONS, COMMUNICATE THE 

LESSON'S LEARNED FROM THE EVENT AND 

EXPAND AUDITS TO INCREASE FOCUS ON 

ENERGY ISOLATION AND PROPER 

VERIFICATIONS OF ENERGY ISOLATIONS. 

12/20/2013 CD1 Tank 

Farm 

3150 50% Diesel, 50% 

Water/Tank 

Bottoms/Crude 

OPERATOR PUMPED WATER 

INTO DIESEL TANK INSTEAD 

OF WATER TANK CAUSING 

THE DIESEL TANK TO 

OVERFLOW. 

Tanks Overfill Human Factors MI CHANGED OUT THE PIPING ON THE 

TANKS SO THAT THERE IS A DIRECT FEED 

INTO THE WATER TANK AND A SEPARATE 

DIRECT FEED INTO THE DIESEL TANK. MI 

CHANGED THE DIESEL TANK FILL NOZZLE 

SO THAT ONLY A DIESEL TRUCK CAN 

ATTACHED TO THE FILL LINE, A VACUUM 

TRUCK OR WATER TRUCK CAN NO LONGER 

ATTACHED TO THE DIESEL LINE. MI PLACED 

SIGNS ON THE TANKS AND FILL LINES TO 

DIFFERENTIATE BETWEEN THE WATER AND 

DIESEL. MI CHANGE THEIR FLUID TRANSFER 

PROCEDURES TO INCLUDE WATER 

TRANSFERS. MI WILL USE A SUPERVISOR 

OR THIRD PERSON WHEN TRAINING 

EMPLOYEES ON NEW TASKS THAT INVOLVE 

FLUID TRANSFERS. IT IS DIFFICULT TO 

TRAIN ON FLUID TRANSFERS WHEN BOTH 

EMPLOYEES ( THERE IS USUALLY ONLY 

TWO ON SITE AT A TIME) NEED TO BE 

WATCHING THE LINES AND ENGAGED 

WHILE THE FLUID IS BEING TRANSFERRED. 

THIS LENDS TO BETTER TRAINING. MI HAS 

COMMITED TO KEEP INDIVIDUALS ON SITE, 

WHO ARE TRAINED TO THE TASK OF FLUID 

TRANSFERS, AND NOT HAVE THEM 

TRANSFERRED TO A NEW POSITION AS 

OFTEN, RESULTING IN LESS TURN OVER 

AROUND FOR THIS IMPORTANT TASK. 

Alpine Field, Satellites, and Pipelines ODPCP C-6 February 2018, Rev. 0 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TABLE C-1 (CONTINUED): ALPINE HISTORY OF OIL SPILLS GREATER THAN 55 GALLONS 

Date Location Volume 

(Gal) Product Cause Explanation Source General Cause General Cause Category Corrective Action 

4/6/2014 CD3 200 100% Hydraulic 

fluid 

DURING BLOW OUT 

PREVENTER MAINTENANCE, 

PRESSURE WAS BEING BLED 

OFF ACCUMULATOR BOTTLE 

TO A TANK. THE TANK DID 

NOT VENT PROPERLY 

RESULTING IN RUPTURING 

THE TANK AND RELEASING 

HYDRAULIC OIL. 

Tanks Equipment 

Failure 

Structural/ 

Mechanical 

THE TANK WAS REPAIRED AND THE VENT 

ENLARGED SO PRESSURE WOULD NOT 

BUILD UP. CONTAINMENT WAS WELDED 

AROUND THE TANK THAT WOULD CONTAIN 

ALL OF THE OIL IN THE TANK. ALL OF THE 

TANKS ON THE RIG HAVE BEEN SLOTTED 

TO BE INSPECTED FOR CONTAINMENT AND 

VENT SIZE. THE LESSONS LEARNED WENT 

OUT TO THE WHOLE DOYON COMPANY. 

ACCUMULATOR EQUIPMENT ON OTHER 

DOYON RIGS ARE BEING INSPECTED FOR 

PROPER VENTS AND CONTAINMENT. 

2/18/2015 CD3 126 100% Diesel THE OPEN TOP TANK WAS 

RATED AT 400BBL AND WAS 

FILLED BASED ON THAT 

CAPACITY, HOWEVER THE 

TANK HAD A HOLE IN IT, 

MAKING THE MAXIMUM 

CAPACITY 375BBL. THE TANK 

WAS NOT RERATED AT THE 

NEW VOLUME OR 

REMARKED TO SHOW A 

REDUCED CAPACITY. 

Tanks Overfill Human Factors FORMAL INVESTIGATION COMPLETED. 

CORRECTIVE ACTIONS ARE: 1)INSPECT ALL 

OPEN TOP TANKS IN ALP FLEET TO ENSURE 

THEY ARE EFFECTIVELY LABELED. 

2)EVALUATE AND MAKE 

RECOMMENDATIONS REGARDING THE USE 

OF PORTABLE LEVEL DETECTION DEVICES. 

3)PERFORM AN MOC TO CLOSE ANY HOLES 

IN SIDE WALL OF OPEN TOP TANKS THAT 

REDUCE TANK CAPACITY. 4)VERIFY TANK 

STRAP ACCURACY AND REMOVE INTERNAL 

STRAPPING MARKINGS THAT ARE 

CURRENTLY LOCATED ABOVE MAXIMUM 

ALLOWABLE LEVEL TO REDUCE TANK 

CAPACITY CONFUSION. 5)EVALUATE THE 

FEASIBILTY OF INSTALLING A MICROMOTION BARREL COUNTER SYSTEM ON 

CHOKE TO ASSIST IN TRACKING RETURN 

VOLUMES. 6)EVALUATE REPLACING 

CURRENT TANKS. 7)DISCUSS THE 

IMPORTANCE OF DEFINING SPECIFIC 

EMPLOYEE ROLES AND RESPONSIBILITIES 

DURING PRE JOB MEETINGS. 8)EVALUATE 

FEASIBILITY TO CROSS-TRAIN SUPPORTING 

WORK GROUPS ON CTU OPERATIONS. 

9)SLB TO DEVELOP AND INCORPORATE A 

STANDARDIZED FLUID TRACKING SYSTEM 

FOR CTU OPERATORS. 10)COMMUNICATE 

CPAI 90% MAXIMUM TANK LEVEL POLICY TO 

ALL CPAI WELLS GROUP SUPERVISORS AND 

TO ALL WELLS SERVICE CONTRACTORS. 

Alpine Field, Satellites, and Pipelines ODPCP C-7 February 2018, Rev. 0 

APPENDIX D 

ADEC REGULATED OIL STORAGE TANKS 
BLANK PAGE
TABLE D-1 

ALPINE OIL STORAGE TANKS 10,000 GALLONS OR GREATER 

TAG NO. LOCATION MODULE DESCRIPTION 

FABRICATION / 

INSTALLATION 

DATE 

CONSTRUCTION 

STANDARD 

NOMINAL 

DESIGN 

CAPACITY 

(BBL) 

PRODUCT TYPE 

SECONDARY 

CONTAINMENT 

DESCRIPTION 

SECONDARY 

CONTAINMENT 

VOLUME 

(BBL) 

LIQUID LEVEL 

MECHANISM 

LAST; NEXT 

EXTERNAL 

INSPECTION 

LAST; NEXT 

INTERNAL 

INSPECTION 

CD2-T-51001 CD2 CD2 tank 

farm 

500 bbl 

production 

chemical tank 

1999 API 12F 

(11th Edition) 500 Crude Oil Liner supported by concrete 1,000 DP 2016; 2021 2011; 2021 

CD3-T-383003 CD3 CD3J Hydrocarbon 

recycle 2005/2006 API-650 443 Oil and water Liner in gravel berm 860 DP, Radar 2016; 2021 2016; 2026 

CD3-T-513006 CD3 CD3J 443 bbl Vertical 2005 API 650 Appendix 

E & J 443 Corrosion Inhibitor Liner in gravel berm 860 Radar, DP 2015; 2020 2010; 2020 

CD3-T-553003 CD3 CD3J Water recycle 2005/2006 API 650 443 Contaminated 

water Liner in gravel berm 860 DP, Radar 2016; 2021 2016; 2026 

CD3-T-613012 CD3 CD3J AHF tank 2005/2006 API 650 252 AHF Liner in gravel berm 860 DP, Radar 2016; 2021 2016; 2026 

CD5-T-505031 CD5 CD5Q Weathered 

Crude tank 2017/2018 API 650 Appendix J 847 Weathered Crude Oil 

Liner supported by 

concrete wall 1,170 Radar new 2018; 2023 

new 2018; 

2028 

CF-T-31010 ACF G2 1,500 bbl Slop 

Oil Tank 1998/2000 API 12D (9th Edition) 1,500 Crude/Water 

Basin lined with 

impermeable 

membrane and 

coated geotextile 

layer with sump. 

17,000 DP, Radar, UT 2013; 2018 2008; 2018 

CF-T-50001 ACF G2 

750 bbl 

production 

chemical tank 

1998/1999 API 12D 

(9th Edition) 750 Diesel 

Basin lined with 

impermeable 

membrane and 

coated geotextile 

layer with sump. 

17,000 Radar 2015; 2020 2010; 2020 

CF-T-50061A ACF G1 

400 bbl 

Completions 

Fluid Storage 

Tank 

1998/1999 API 12F 

(11th Edition) 400 

Drilling or 

Production 

fluids 

Basin lined with 

impermeable 

membrane and 

coated geotextile 

layer with sump. 

17,000 Radar 2014; 2019 2014; 2024 

CF-T-50061B ACF G1 

400 bbl 

Completions 

Fluid Storage 

Tank 

1998/1999 API 12F 

(11th Edition) 400 

Drilling or 

Production 

fluids 

Basin lined with 

impermeable 

membrane and 

coated geotextile 

layer with sump. 

17,000 Radar 2014; 2019 2014; 2024 

CF-T-50090 ACF G5 803 bbl Vertical 2003 API 650 Appendix 

A & F 803 Varies (Diesel or Chemical) 

Basin lined with 

impermeable 

membrane and 

coated geotextile 

layer with sump 

17,000 DP 2015; 2020 2010; 2020 

Alpine Field, Satellites, and Pipelines ODPCP D-1 May 2018, Rev. 2 
 

 

 

 

TABLE D-1 

ALPINE OIL STORAGE TANKS 10,000 GALLONS OR GREATER 

TAG NO. LOCATION MODULE DESCRIPTION 

FABRICATION / 

INSTALLATION 

DATE 

CONSTRUCTION 

STANDARD 

NOMINAL 

DESIGN 

CAPACITY 

(BBL) 

PRODUCT TYPE 

SECONDARY 

CONTAINMENT 

DESCRIPTION 

SECONDARY 

CONTAINMENT 

VOLUME 

(BBL) 

LIQUID LEVEL 

MECHANISM 

LAST; NEXT 

EXTERNAL 

INSPECTION 

LAST; NEXT 

INTERNAL 

INSPECTION 

Basin lined with 

CF-T-51001 ACF G2 

1500 bbl 

production 

chemical tank 

1998/2001 

API 650 

(modified per 

12D) 

1,500 Dry Crude Oil 

impermeable 

membrane and 

coated geotextile 

layer with sump. 

17,000 Radar, DP 2015; 2020 2010; 2020 

CF-T-60001 ACF G2 250 bbl Lube Oil 

Storage Tank 1998/2000 API 12F (11th Edition) 250 Lube Oil 

Basin lined with 

impermeable 

membrane and 

coated geotextile 

layer with sump. 

17,000 Radar 2015; 2020 2010; 2020 

CF-T-61001 ACF G1 3,300 bbl AHF 

Storage Tank 1984/1999 API 650 Appendix E & F 3,300 

Misc. 

hydrocarbon 

service 

Basin lined with 

impermeable 

membrane and 

coated geotextile 

layer with sump. 

17,000 DP (note 4) 2014; 2019 2014; 2024 

1. ACF = Alpine Central Facility 

2. DP = Differential pressure 

3. UT = Ultrasonic non-contact transmitter 

4. Liquid level displayed, and flashing lights with audible alarm are triggered if high levels situation occurs. 

Alpine Field, Satellites, and Pipelines ODPCP D-2 February 2018, Rev. 0 
TABLE D-2 

COPA-OWNED PORTABLE OIL STORAGE TANKS 10,000 GALLONS OR GREATER AVAILABLE FOR USE 

TAG 

NUMBER 

TANK 

DESCRIPTION 

VOLUME 

(BBL) 

VOLUME 

(GAL) CONTENTS FABRICATION DATE 

CONSTRUCTION 

STANDARD 

LAST; NEXT 

EXTERNAL 

INSPECTION 

LAST; NEXT 

INTERNAL 

INSPECTION 

SERVICE 

HISTORY COMMENTS 

AK-2408 Vertical 400 16,800 Diesel 1980 Closed top/skid 2017; 2019 2017; 2027 

AP-T-61043 White hydrocarbon 

tank (Hector Tank) 357 15,000 Aviation Jet A fuel 1998 ADEC Waiver 2015; 2020 2015; 2025 

Former Tag CF-T-76004 

Double-wall, placed in containment 

ADEC approval, Section 3.11 

AP-T-76101 Upright 400 16,800 Varies 2005 API 650 2015; 2020 2015; 2023 

AP-T-76135 Tiger Tank 500 21,000 Varies 2005 ADEC Approval 2016; 2021 2016; 2026 ADEC approval, Section 3.11 

AP-T-76137 Open top Tiger Tank 400 16,800 Varies 2005 ADEC Approval 2017; 2022 2012; 2022 ADEC approval, Section 3.11 

AP-T-76197 Open Top 500 21,000 Varies 2006 ADEC Approval 2013; 2018 2013; 2023 Start 2008 ADEC approval, Section 3.11 

AP-T-76198 Open Top 500 21,000 Varies 2006 ADEC Approval 2016; 2021 2016; 2026 ADEC approval, Section 3.11 

AP-T-76223 Upright 400 16,800 Varies 2007 API 650 App J 2017; 2022 2017; 2027 

AP-T-76224 Upright 400 16,800 Varies 2007 API 650 App J 2017; 2022 2012; 2022 

AP-T-76225 Upright 400 16,800 Varies 2007 API 650 App J 2017; 2022 2017; 2027 

AP-T-76350 Upright 400 16,800 Varies 2009 API 650 2017; 2022 2017; 2027 New 2009 

AP-T-76351 Upright 400 16,800 Varies 2009 API 650 2014; 2019 2014; 2024 New 2009 

AP-T-76352 Tiger Tank 500 21,000 Varies 2009 ADEC Approval 2014; 2019 2014; 2024 New 2009 ADEC approval, Section 3.11 

AP-T-76362 Double-wall upright 400 16,800 Varies 2008 API 12F 2014; 2019 2014; 2024 New 2009 

AP-T-76363 Double-wall upright 400 16,800 Varies 2008 API 12F 2014; 2019 2014; 2024 New 2009 

Alpine Field, Satellites, and PIpelines ODPCP D-3 February 2018, Rev. 0 
TABLE D-2 

COPA-OWNED PORTABLE OIL STORAGE TANKS 10,000 GALLONS OR GREATER AVAILABLE FOR USE 

TAG 

NUMBER 

TANK 

DESCRIPTION 

VOLUME 

(BBL) 

VOLUME 

(GAL) CONTENTS FABRICATION DATE 

CONSTRUCTION 

STANDARD 

LAST; NEXT 

EXTERNAL 

INSPECTION 

LAST; NEXT 

INTERNAL 

INSPECTION 

SERVICE 

HISTORY COMMENTS 

AP-T-76364 Double-wall upright 400 16,800 Varies 2008 API 12F 2014; 2019 2014; 2024 New 2009 

AP-T-76393 Double-wall upright 400 16,800 Varies 2009 API 12F 2014; 2019 2014; 2024 

AP-T-76394 Double-wall upright 400 16,800 Varies 2009 API 12F 2014; 2019 2014; 2024 

AP-T-76395 Double-wall upright 400 16,800 Varies 2009 API 12F 2014; 2019 2014; 2024 

AP-T-76396 Double-wall upright 400 16,800 Varies 2009 API 12F 2014; 2019 2014; 2024 

AP-T-76397 Double-wall upright 400 16,800 Varies 2009 API 12F 2014; 2019 2014; 2024 

AP-T-76446 Tiger Tank 500 21,000 Varies 2014 ADEC Approval 2015; 2020 2015; 2025 Start of service 

2015 ADEC approval, Section 3.11 

AP-T-76447 Tiger Tank 500 21,000 Varies 2014 ADEC Approval 2015; 2020 2015; 2025 Start of service 

2015 ADEC approval, Section 3.11 

CF-T-76004 Horizontal open top 400 16,800 

Misc. 

hydrocarbon 

service 

ND ADEC Approval 2014; 2019 2014; 2024 ADEC approval, Section 3.11 

CF-T-76005 Horizontal open top 400 16,800 

Misc. 

hydrocarbon 

service 

ND ADEC Approval 2017; 2022 2017; 2027 ADEC approval, Section 3.11 

CF-T-76006 Black Tiger Tank 450 18,900 Well bore fluids 2000 ADEC Approval 2014; 2019 2014; 2024 ADEC approval, Section 3.11 

CF-T-76007 Black Tiger Tank 450 18,900 Well bore fluids 2000 ADEC Approval 2013; 2018 2013; 2023 ADEC approval, Section 3.11 

CF-T-76017 Gray Upright 500 21,000 

Multi-use, 

potential 

hydrocarbons 

1998 API 12 F (11th 

Edition) 2017; 2022 2017; 2027 

CF-T-76033 Gray Upright 400 16,800 

Misc. 

hydrocarbon 

service 

2003 API 650 2017; 2022 2012; 2022 

CF-T-76070 Brown Open Top 500 21,000 

Misc. 

hydrocarbon 

service 

2003 API 650 2014; 2019 2014; 2019 

CF-T-76071 Brown Tiger Tank 500 21,000 

Misc. 

hydrocarbon 

service 

2003 API 650 2013; 2018 2013; 2023 

Alpine Field, Satellites, and PIpelines ODPCP D-4 February 2018, Rev. 0 
TABLE D-2 

COPA-OWNED PORTABLE OIL STORAGE TANKS 10,000 GALLONS OR GREATER AVAILABLE FOR USE 

TAG 

NUMBER 

TANK 

DESCRIPTION 

VOLUME 

(BBL) 

VOLUME 

(GAL) CONTENTS FABRICATION DATE 

CONSTRUCTION 

STANDARD 

LAST; NEXT 

EXTERNAL 

INSPECTION 

LAST; NEXT 

INTERNAL 

INSPECTION 

SERVICE 

HISTORY COMMENTS 

CF-T-76210 Upright 400 16,800 Brine, potential 

hydrocarbons 2004 API 650 App J 2014; 2019 2014; 2024 

CF-T-76819 Upright 400 16,800 

Misc. 

hydrocarbon 

service 

2002 API 650 (10th 

Edition) 2017; 2022 2017; 2027 

CF-T-76820 Upright 400 16,800 

Misc. 

hydrocarbon 

service 

2002 API 650 (10th 

Edition) 2017; 2018 2017; 2018 

DEG-8691 Vertical 400 16,800 Diesel 1984 Closed top/skid 2015; 2020 2015; 2030 

DEG-8692 Vertical 400 16,800 Diesel 1984 Closed top/skid 2013; 2018 2013; 2018 

DEG-8693 Vertical 400 16,800 Varies 1983 Closed top/skid 2017; 2022 2017; 2022 

KP-4132 Horizontal 242 10,164 Varies ND Open top/skid 2014; 2019 2009; 2019 

KSP-0511 Tiger Tank 500 21,000 Varies 1992 Closed top/wheels 2014; 2019 2009; 2019 

PGE-86AD Vertical cylinder 400 16,800 Varies 1981 Closed top/skid 2013; 2018 2013; 2018 

PGE-86AH Vertical 400 16,800 Varies 1984 Closed top/skid 2014; 2018 2014; 2018 

PGE-86AI Vertical 400 16,800 Varies 1984 Closed top/skid 2013; 2018 2013; 2023 

PGE-86AN Vertical 400 16,800 Varies 1984 Closed top/skid 2016; 2018 2013; 2023 

PGE-86AR Vertical 400 16,800 Varies 1984 Closed top/skid 2013; 2018 2008; 2028 

PGE-86AW Vertical 400 16,800 Varies 1984 Closed top/skid 2014; 2019 2004; 2024 

PGE-86AZ Vertical 400 16,800 Varies 1984 Closed top/skid 2014; 2019 2004; 2024 

PGE-86BC Horizontal cylinder 400 16,800 Varies 1985 Open top/skid 2016; 2021 2016; 2026 

Alpine Field, Satellites, and PIpelines ODPCP D-5 February 2018, Rev. 0 
TABLE D-2 

COPA-OWNED PORTABLE OIL STORAGE TANKS 10,000 GALLONS OR GREATER AVAILABLE FOR USE 

TAG 

NUMBER 

TANK 

DESCRIPTION 

VOLUME 

(BBL) 

VOLUME 

(GAL) CONTENTS FABRICATION DATE 

CONSTRUCTION 

STANDARD 

LAST; NEXT 

EXTERNAL 

INSPECTION 

LAST; NEXT 

INTERNAL 

INSPECTION 

SERVICE 

HISTORY COMMENTS 

PGE-86BD Horizontal cylinder 400 16,800 Varies 1985 Open top/skid 2015; 2020 2010; 2020 

PGE-86BE Vertical 400 16,800 Varies 1985 Closed top/skid 2014; 2019 2004; 2024 

PGE-86BG Vertical 400 16,800 Varies 1985 Closed top/skid 2013; 2018 2013; 2023 

PGE-86CE Vertical cylinder 400 16,800 Varies 1985 Closed top/skid 2013; 2018 2008; 2028 

PGE-86CF Vertical cylinder 400 16,800 Varies 1985 Closed top/skid 2013; 2018 2008; 2028 

PGE-87 Horizontal cylinder 400 16,800 Varies 1984 Open top/skid 2013; 2018 2013; 2018 

PGE-87AC Horizontal cylinder 400 16,800 Varies ND Open top/skid 2015; 2020 2015; 2025 

PGE-87AD Horizontal 400 16,800 Varies ND Open top/skid 2016; 2021 2016; 2021 

SST-001 Vertical 400 16,800 Varies 2000 API 650 2016; 2021 2011; 2021 

SST-002 Vertical 400 16,800 Varies 2000 API 650 2016; 2021 2011; 2021 non-hydrocarbon service 

SST-003 Vertical 400 16,800 Varies 2001 API 650 2016; 2021 2011; 2021 

SST-004 Vertical 400 16,800 Varies 2001 API 650 2016; 2021 2011; 2021 

SST-005 Vertical 400 16,800 Varies 2001 API 650 2016; 2021 2011; 2021 

SST-006 Vertical 400 16,800 Varies 2001 API 650 2016; 2021 2011; 2021 

SST-007 Vertical 400 16,800 Varies 2001 API 650 2016; 2021 2011; 2021 

SST-008 Vertical 400 16,800 Varies 2001 API 650 2016; 2021 2011; 2021 

SST-009 Vertical 400 16,800 Varies 2001 API 650 2016; 2019 2011; 2021 

Alpine Field, Satellites, and PIpelines ODPCP D-6 February 2018, Rev. 0 
TABLE D-2 

COPA-OWNED PORTABLE OIL STORAGE TANKS 10,000 GALLONS OR GREATER AVAILABLE FOR USE 

TAG 

NUMBER 

TANK 

DESCRIPTION 

VOLUME 

(BBL) 

VOLUME 

(GAL) CONTENTS FABRICATION DATE 

CONSTRUCTION 

STANDARD 

LAST; NEXT 

EXTERNAL 

INSPECTION 

LAST; NEXT 

INTERNAL 

INSPECTION 

SERVICE 

HISTORY COMMENTS 

SST-010 Vertical 400 16,800 Varies 2001 API 650 2016; 2021 2011; 2021 

SST-015 Horizontal Steelfab 

Flowback 400 16,800 Varies 2006 

ADEC BBFM205126-09/05 

UL 142 

2016; 2021 2016; 2021 Double-wall, tank-within-tank design 

SST-016 Horizontal Steelfab 

Flowback 400 16,800 Varies 2006 

ADEC BBFM205126-09/05 

UL 142 

2016; 2021 2016; 2021 Double-wall, tank-within-tank design 

SST-017 Horizontal Steelfab 

Flowback 400 16,800 Varies 2006 

ADEC BBFM205126-09/05 

UL 142 

2016; 2021 2016; 2021 Double-wall, tank-within-tank design 

SST-018 Horizontal Steelfab 

Flowback 400 16,800 Varies 2006 

ADEC BBFM205126-09/05 

UL 142 

2016; 2021 2016; 2021 Double-wall, tank-within-tank design 

SST-019 Horizontal Steelfab 

Flowback 400 16,800 Varies 2006 

ADEC BBFM205126-09/05 

UL 142 

2016; 2021 2016; 2021 Double-wall, tank-within-tank design 

SST-020 Horizontal Steelfab 

Flowback 400 16,800 Varies 2006 

ADEC BBFM205126-09/05 

UL 142 

2016; 2021 2016; 2021 Double-wall, tank-within-tank design 

SST-027 Horizontal Steelfab 

Flowback 400 16,800 Varies 2007 

ADEC BBFM205126-09/05 

UL 142 

2013; 2018 2013; 2018 Double-wall, tank-within-tank design 

SST-028 Horizontal Steelfab 

Flowback 400 16,800 Varies 2007 

ADEC BBFM205126-09/05 

UL 142 

2013; 2018 2013; 2018 Double-wall, tank-within-tank design 

SST-029 Horizontal Steelfab 

Flowback 400 16,800 Varies 2007 

ADEC BBFM205126-09/05 

UL 142 

2017; 2022 2012; 2022 Double-wall, tank-within-tank design 

SST-065 Horizontal Steelfab 

Flowback 400 16,800 Varies 2009 

ADEC BBFM205126-09/05 

UL 142 

2014; 2019 2014; 2019 New 2009 Double-wall, tank-within-tank design 

SST-066 Horizontal Steelfab 

Flowback 400 16,800 Varies 2009 

ADEC BBFM205126-09/05 

UL 142 

2014; 2019 2014; 2019 New 2009 Double-wall, tank-within-tank design 

SST-067 Horizontal Steelfab 

Flowback 400 16,800 Varies 2009 ADEC BBFM205126-09/05 2015; 2020 2015; 2020 New 2009 Double-wall, tank-within-tank design 

Alpine Field, Satellites, and PIpelines ODPCP D-7 February 2018, Rev. 0 
TABLE D-2 

COPA-OWNED PORTABLE OIL STORAGE TANKS 10,000 GALLONS OR GREATER AVAILABLE FOR USE 

TAG 

NUMBER 

TANK 

DESCRIPTION 

VOLUME 

(BBL) 

VOLUME 

(GAL) CONTENTS FABRICATION DATE 

CONSTRUCTION 

STANDARD 

LAST; NEXT 

EXTERNAL 

INSPECTION 

LAST; NEXT 

INTERNAL 

INSPECTION 

SERVICE 

HISTORY COMMENTS 

SST-071 Horizontal Steelfab 

Flowback 400 16,800 Varies 2010 

ADEC BBFM205126-09/05 

UL 142 

2015; 2020 2015; 2020 New 2010 Double-wall, tank-within-tank design 

SUR-001 Double-wall upright 400 16,800 Varies 2007 API 12F 2017; 2022 2017; 2027 Former ID Atigun 250 

SUR-002 Double-wall upright 400 16,800 Varies 2007 API 12F 2017; 2022 2017; 2027 Former ID Atigun 251 

SUR-003 Double-wall upright 400 16,800 Varies 2008 API 12F 2013; 2018 2013; 2018 Former ID Atigun 286 

SUR-004 Double-wall upright 400 16,800 Varies 2008 API 12F 2013; 2018 2013; 2018 Former ID Atigun 287 

SUR-005 Double-wall upright 400 16,800 Varies 2008 API 12F 2013; 2018 2013; 2018 Former ID Atigun 306 

SUR-006 Double-wall upright 400 16,800 Varies 2008 API 12F 2013; 2018 2013; 2018 Former ID Atigun 303 

SUR-007 Double-wall upright 400 16,800 Varies 2014 API 12F 2015; 2020 2015; 2025 Start of service 

2015 

SUR-008 Double-wall upright 400 16,800 Varies 2014 API 12F 2015; 2020 2015; 2025 Start of service 

2015 

SUR-009 Double-wall upright 400 16,800 Varies 2014 API 12F 2015; 2020 2015; 2025 Start of service 

2015 

SUR-010 Double-wall upright 400 16,800 Varies 2014 API 12F 2015; 2020 2015; 2025 Start of service 

2015 

SUR-011 Double-wall upright 400 16,800 Varies 2014 API 12F 2015; 2020 2015; 2025 Start of service 

2015 

SUR-012 Double-wall upright 400 16,800 Varies 2014 API 12F 2015; 2020 2015; 2025 Start of service 

2015 

SUR-013 Double-wall upright 400 16,800 Varies 2014 API 12F 2015; 2020 2015; 2025 Start of service 

2015 

SUR-014 Double-wall upright 400 16,800 Varies 2014 API 12F 2015; 2020 2015; 2025 Start of service 

2015 

SUR-015 Double-wall upright 400 16,800 Varies 2014 API 12F 2015; 2020 2015; 2025 Start of service 

2015 

SUR-016 Double-wall upright 400 16,800 Varies 2016 API 12F 2016; 2021 2016; 2026 Start of service 

2016 

Alpine Field, Satellites, and PIpelines ODPCP D-8 February 2018, Rev. 0 
TABLE D-2 

COPA-OWNED PORTABLE OIL STORAGE TANKS 10,000 GALLONS OR GREATER AVAILABLE FOR USE 

TAG 

NUMBER 

TANK 

DESCRIPTION 

VOLUME 

(BBL) 

VOLUME 

(GAL) CONTENTS FABRICATION DATE 

CONSTRUCTION 

STANDARD 

LAST; NEXT 

EXTERNAL 

INSPECTION 

LAST; NEXT 

INTERNAL 

INSPECTION 

SERVICE 

HISTORY COMMENTS 

SUR-017 Double-wall upright 400 16,800 Varies 2016 API 12F 2016; 2021 2016; 2026 Start of service 

2016 

SUR-018 Double-wall upright 400 16,800 Varies 2016 API 12F 2016; 2021 2016; 2026 Start of service 

2016 

SUR-019 Double-wall upright 400 16,800 Varies 2016 API 12F 2016; 2021 2016; 2026 Start of service 

2016 

SUR-020 Double-wall upright 400 16,800 Varies 2016 API 12F 2016; 2021 2016; 2026 Start of service 

2016 

SUR-021 Double-wall upright 400 16,800 Varies 2016 API 12F 2016; 2021 2016; 2026 Start of service 

2016 

T-M101 

(SST-011) Vertical 400 16,800 Varies 2005 API 650 2015; 2020 2015; 2020 

T-M102 

(SST-012) Vertical 400 16,800 Varies 2005 API 650 2015; 2020 2015; 2020 

T-M103 

(SST-013) Vertical 400 16,800 Varies 2005 API 650 2015; 2020 2015; 2020 

T-M104 

(SST-014) Vertical 400 16,800 Varies 2005 API 650 2015; 2020 2015; 2020 

Notes: 

1. All listed tanks are welded construction. Tanks are owned and operated by COPA. Tanks named "AP-T" or "CF-T" typically located in Alpine, remaining listed tanks are typically located in Kuparuk, but 

may be used at other locations, if needed. 

2. Skid-mounted tanks rest approximately 1 to 1.5 feet above the ground. 

3. ND = No data available. 

Alpine Field, Satellites, and PIpelines ODPCP D-9 February 2018, Rev. 0 
TABLE D-3 

RENTED OR LEASED PORTABLE OIL STORAGE TANKS 10,000 GALLONS OR GREATER AVAILABLE FOR USE 

OWNER TAG 

NUMBER 

TANK 

DESCRIPTION 

VOLUME 

(BBL) 

VOLUME 

(GAL) CONTENTS FABRICATION 

DATE 

CONSTRUCTION 

STANDARD 

EXTERNAL 

INSPECTION 

LAST; NEXT 

INTERNAL 

INSPECTION 

LAST; NEXT 

SERVICE 

HISTORY COMMENTS 

Atigun 123 Double-wall, 

welded steel 400 16,800 Oil; drilling 

fluids 2006 API 12F 2016; 2021 2016; 2026 New 2006 

Atigun 124 Double-wall, 

welded steel 400 16,800 Oil; drilling fluids 2006 API 12F 2013; 2018 2013; 2023 New 2006 

Atigun 125 Double-wall, 

welded steel 400 16,800 Oil; drilling fluids 2006 API 12F 2016; 2021 2016; 2026 New 2006 

Atigun 126 Double-wall, 

welded steel 400 16,800 Oil; drilling fluids 2006 API 12F 2016; 2021 2016; 2026 New 2006 

Atigun 127 Double-wall, 

welded steel 400 16,800 Oil; drilling fluids 2006 API 12F 2016; 2021 2016; 2026 New 2006 

Atigun 128 Double-wall, 

welded steel 400 16,800 Oil; drilling 

fluids 2006 API 12F 2015; 2021 2015; 2021 New 2006 

Atigun 1128 Horizontal opentop 253 10,660 Drilling fluids 2002 None 2014; 2019 2014; 2024 three compartment tank 

MagTec 027291-05 Single wall 

upright 400 16,800 Varies; drilling fluids 2013 API 12F New 2013; 2018 

New 2013; 

2023 

MagTec 027291-09 Single wall 

upright 400 16,800 Varies; 

drilling fluids 2013 API 12F New 2013; 

2018 

New 2013; 

2023 

MagTec 027503-02 Single wall 

upright 400 16,800 Varies; 

drilling fluids 2013 API 12F New 2013; 

2018 

New 2013; 

2023 

MagTec 027503-10 Single wall 

upright 400 16,800 Varies; 

drilling fluids 2013 API 12F New 2013; 

2018 

New 2013; 

2023 

MagTec 603-105 Single wall 

upright 400 16,800 Varies; 

drilling fluids 2012 API 12F 2017; 2022 2012; 2022 New 2012 SN 024841-04 

MagTec 603-107 Single wall 

upright 400 16,800 Varies; drilling fluids 2012 API 12F 2017; 2022 2012; 2022 New 2012 SN 024841-07 

Alpine FIeld, Satellites, and Pipelines ODPCP D-10 February 2018, Rev. 0 
TABLE D-3 

RENTED OR LEASED PORTABLE OIL STORAGE TANKS 10,000 GALLONS OR GREATER AVAILABLE FOR USE 

OWNER TAG 

NUMBER 

TANK 

DESCRIPTION 

VOLUME 

(BBL) 

VOLUME 

(GAL) CONTENTS FABRICATION 

DATE 

CONSTRUCTION 

STANDARD 

EXTERNAL 

INSPECTION 

LAST; NEXT 

INTERNAL 

INSPECTION 

LAST; NEXT 

SERVICE 

HISTORY COMMENTS 

MagTec 603-127 Single wall 

upright 400 16,800 Varies; drilling fluids 2013 API 12F 2015; 2020 2015; 2025 New 2013 SN 024333-10 

MagTec 603-128 Single wall 

upright 400 16,800 Varies; drilling fluids 2013 API 12F 2015; 2020 2015; 2025 New 2013 SN 026106-06 

MagTec 603-129 Single wall 

upright 400 16,800 Varies; drilling fluids 2013 API 12F 2015; 2020 2015; 2025 New 2013 SN 026106-07 

MagTec 603-131 Single wall 

upright 400 16,800 Varies; drilling fluids 2013 API 12F New 2013; 2018 

New 2013; 

2023 New 2013 SN 027291-10 

MagTec 603-133 Single wall 

upright 400 16,800 Varies; drilling fluids 2013 API 12F 2015; 2020 2015; 2025 New 2013 SN 024333-07 

MagTec 603-135 Single wall 

upright 400 16,800 Varies; drilling fluids 2013 API 12F New 2013; 

2018 

New 2013; 

2023 New 2013 SN 027291-06 

MagTec 603-136 Single wall 

upright 400 16,800 Varies; 

drilling fluids 2013 API 12F New 2013; 

2018 

New 2013; 

2023 New 2013 SN 027503-04 

MagTec 603-139 Single wall 

upright 400 16,800 Varies; drilling fluids 2013 API 12F 2015; 2020 2015; 2025 New 2013 SN 024841-14 

MagTec 603-142 Single wall 

upright 400 16,800 Varies; 

drilling fluids 2013 API 12F 2015; 2020 2015; 2025 New 2013 SN 024841-11 

MagTec 603-146 Single wall 

upright 400 16,800 Varies; 

drilling fluids 2013 API 12F 2013; 2018 2013; 2023 New 2013 SN 027291-05 

MagTec 603-148 Single wall 

upright 400 16,800 Varies; 

drilling fluids 2013 API 12F 2015; 2020 2015; 2025 New 2013 SN 026106-03 

MagTec 603-149 Single wall 

upright 400 16,800 Varies; drilling fluids 2013 API 12F 2015; 2020 2015; 2025 New 2013 SN 026106-04 

MagTec 603-163 Single wall 

upright 400 16,800 Varies; drilling fluids 2013 API 12F 2013; 2018 2013; 2023 New 2013 SN 030978-01 

Alpine FIeld, Satellites, and Pipelines ODPCP D-11 February 2018, Rev. 0 
TABLE D-3 

RENTED OR LEASED PORTABLE OIL STORAGE TANKS 10,000 GALLONS OR GREATER AVAILABLE FOR USE 

OWNER TAG 

NUMBER 

TANK 

DESCRIPTION 

VOLUME 

(BBL) 

VOLUME 

(GAL) CONTENTS FABRICATION 

DATE 

CONSTRUCTION 

STANDARD 

EXTERNAL 

INSPECTION 

LAST; NEXT 

INTERNAL 

INSPECTION 

LAST; NEXT 

SERVICE 

HISTORY COMMENTS 

MagTec 603-164 Single wall 

upright 400 16,800 Varies; drilling fluids 2013 API 12F 2013; 2018 2013; 2023 New 2013 SN 030978-02 

MagTec 603-166 Single wall 

upright 400 16,800 Varies; drilling fluids 2013 API 12F 2013; 2018 2013; 2023 New 2013 SN 030978-04 

MagTec 603-170 Single wall 

upright 400 16,800 Varies; drilling fluids 2014 API 12F 2014; 2019 2014; 2024 New 2014 SN 031472-02 

MagTec 603-172 Single wall 

upright 400 16,800 Varies; drilling fluids 2014 API 12F 2014; 2019 2014; 2024 New 2014 SN 031472-04 

MagTec 603-173 Single wall 

upright 400 16,800 Varies; drilling fluids 2014 API 12F 2014; 2019 2014; 2024 New 2014 SN 031472-05 

MagTec 603-174 Single wall 

upright 400 16,800 Varies; drilling fluids 2014 API 12F 2014; 2019 2014; 2024 New 2014 SN 031472-06 

MagTec 603-176 Single wall 

upright 400 16,800 Varies; drilling fluids 2014 API 12F 2014; 2019 2014; 2024 New 2014 SN 030978-06 

MagTec 603-177 Single wall 

upright 400 16,800 Varies; drilling fluids 2014 API 12F 2014; 2019 2014; 2024 New 2014 SN 031472-08 

MagTec 603-178 Single wall 

upright 400 16,800 Varies; 

drilling fluids 2014 API 12F 2014; 2019 2014; 2024 New 2014 SN 030978-10 

Rain for 

Rent 239578 Bi-Level Tiger 

Tank 500 21,000 Oil; drilling 

fluids 1995 RFR Spec. 99044 2017; 2022 2012; 2022 Continuous 

since 1998 COPA Ref# SST-024 

Rain for 

Rent 252826 Double-wall 

upright 400 16,800 Varies 2014 API 12F New 2014; 

2019 

New 2014; 

2024 New 2014 

Rain for 

Rent 252827 Double-wall 

upright 400 16,800 Varies 2014 API 12F New 2014; 2019 

New 2014; 

2024 New 2014 

Rain for 

Rent 252828 Double-wall upright 400 16,800 Varies 2014 API 12F New 2014; 2019 

New 2014; 

2024 New 2014 

Alpine FIeld, Satellites, and Pipelines ODPCP D-12 February 2018, Rev. 0 
 

TABLE D-3 

RENTED OR LEASED PORTABLE OIL STORAGE TANKS 10,000 GALLONS OR GREATER AVAILABLE FOR USE 

OWNER TAG 

NUMBER 

TANK 

DESCRIPTION 

VOLUME 

(BBL) 

VOLUME 

(GAL) CONTENTS FABRICATION DATE 

CONSTRUCTION 

STANDARD 

EXTERNAL 

INSPECTION 

LAST; NEXT 

INTERNAL 

INSPECTION 

LAST; NEXT 

SERVICE 

HISTORY COMMENTS 

Rain for 

Rent 252829 Double-wall upright 400 16,800 Varies 2014 API 12F New 2014; 2019 

New 2014; 

2024 New 2014 

Rain for 

Rent 252830 Double-wall upright 400 16,800 Varies 2014 API 12F New 2014; 2019 

New 2014; 

2024 New 2014 

Rain for 

Rent 252832 Double-wall upright 400 16,800 Varies 2014 API 12F New 2014; 2019 

New 2014; 

2024 New 2014 

Rain for 

Rent 254254 Bi-Level Tiger Tank 500 21,000 Varies 1999 RFR Spec. 99044 2017; 2022 2012; 2022 Continuous since 1999 

Rain for 

Rent 254881 Bi-Level Tiger Tank 500 21,000 Varies 2000 RFR Spec. 99044 2014; 2019 2012; 2022 Continuous since 2000 

Rain for 

Rent 254993 Bi-Level Tiger Tank 500 21,000 Varies 2000 RFR Spec. 99044 2017; 2022 2012; 2022 Continuous since 2000 

Rain for 

Rent 255141 Bi-Level Tiger Tank 500 21,000 Varies 2001 RFR Spec. 99044 2017; 2022 2012; 2022 Continuous since 2001 

Rain for 

Rent 255317 Bi-Level Tiger Tank 500 21,000 Oil; drilling fluids 2001 RFR Spec. 99044 2017; 2022 2012; 2022 Continuous since 2001 COPA Ref# SST-023 

Rain for 

Rent 255497 Bi-Level Tiger Tank 500 21,000 Oil; drilling fluids 2001 RFR Spec. 99044 2014; 2019 2014; 2024 Continuous since 2001 COPA Ref# SST-022 

Rain for 

Rent 255902 Bi-Level Tiger Tank 500 21,000 Varies 2006 RFR Spec. 107789 2015; 2020 2010; 2020 Continuous since 2006 

Rain for 

Rent 258119 Tiger Tank 500 21,000 Varies 2000 RFR Spec. 99044 2013; 2018 2008; 2018 Continuous 

since 2000 

Rain for 

Rent 258670 Bi-Level Tiger Tank 500 21,000 Varies 2002 RFR Spec. 107789 2015; 2020 2010; 2020 Continuous since 2002 

Rain for 

Rent 259172 Bi-Level Tiger Tank 500 21,000 Varies 2004 RFR Spec. 107789 2015; 2020 2010; 2020 Continuous since 2004 

Rain for 

Rent 259408 Bi-Level Tiger Tank 500 21,000 Varies 2004 RFR Spec. 107789 2015; 2020 2010; 2020 Continuous since 2004 

Rain for 

Rent 259412 Bi-Level Tiger Tank 500 21,000 Varies 2004 RFR Spec. 107789 2015; 2020 2010; 2020 Continuous since 2004 

Alpine FIeld, Satellites, and Pipelines ODPCP D-13 April 2018, Rev. 1 
 

 

 

TABLE D-3 

RENTED OR LEASED PORTABLE OIL STORAGE TANKS 10,000 GALLONS OR GREATER AVAILABLE FOR USE 

OWNER TAG 

NUMBER 

TANK 

DESCRIPTION 

VOLUME 

(BBL) 

VOLUME 

(GAL) CONTENTS FABRICATION 

DATE 

CONSTRUCTION 

STANDARD 

EXTERNAL 

INSPECTION 

LAST; NEXT 

INTERNAL 

INSPECTION 

LAST; NEXT 

SERVICE 

HISTORY COMMENTS 

Rain for 

Rent 265402 Bi-Level Tiger Tank 500 21,000 Varies 2006 RFR Spec. 107789 2015; 2020 2010; 2020 Continuous since 2006 

Rain for 

Rent 266010 Tiger Tank 500 21,000 Varies 2008 RFR Spec. 99044 2013; 2018 New 2008; 2018 New 2008 

TANKO 

Alaska 108 Double-wall, welded steel 570 23,940 Oil; drilling fluids 1983 None 2014; 2019 2014; 2019 Continuous since 1983 

TANKO 

Alaska 111 Double-wall, welded steel 570 23,940 Varies 1983 None 2014; 2019 2014; 2019 Continuous since 1983 COPA Ref# SST-068 

TANKO 

Alaska 114 Double-wall, welded steel 570 23,940 Oil; drilling fluids 1983 None 2014; 2019 2014; 2019 Continuous 

since 1983 

TANKO 

Alaska 115 Double-wall, welded steel 570 23,940 Oil; drilling 

fluids 1983 None 2014; 2019 2014; 2019 Continuous 

since 1983 

TANKO 

Alaska 116 Double-wall, 

welded steel 570 23,940 Oil; drilling fluids 1983 None 2014; 2019 2014; 2019 Continuous since 1992 COPA Ref# SST-030 

TANKO 

Alaska 117 Double-wall, welded steel 570 23,940 Oil; drilling fluids 1983 None 2014; 2019 2014; 2019 Continuous since 1992 COPA Ref# SST-031 

TANKO 

Alaska 118 Double-wall, 

welded steel 570 23,940 Oil; drilling 

fluids 1983 None 2014; 2019 2014; 2019 Continuous 

since 1992 COPA Ref# SST-032 

TANKO 

Alaska 119 Double-wall, 

welded steel 570 23,940 Oil; drilling 

fluids 1983 None 2014; 2019 2014; 2019 Continuous 

since 1992 COPA Ref# SST-033 

TANKO 

Alaska 121 Double-wall, 

welded steel 570 23,940 Oil; drilling 

fluids 1983 None 2014; 2019 2014; 2019 Continuous 

since 1992 COPA Ref# SST-034 

TANKO 

Alaska 122 Double-wall, welded steel 570 23,940 Oil; drilling fluids 1983 None 2014; 2019 2014; 2019 Continuous since 1992 

TANKO 

Alaska 123 Double-wall, welded steel 570 23,940 Oil; drilling fluids 1983 None 2014; 2019 2014; 2019 Continuous since 1983 

Alpine FIeld, Satellites, and Pipelines ODPCP D-14 February 2018, Rev. 0 
 

 

 

 

 

TABLE D-3 

RENTED OR LEASED PORTABLE OIL STORAGE TANKS 10,000 GALLONS OR GREATER AVAILABLE FOR USE 

OWNER TAG 

NUMBER 

TANK 

DESCRIPTION 

VOLUME 

(BBL) 

VOLUME 

(GAL) CONTENTS FABRICATION 

DATE 

CONSTRUCTION 

STANDARD 

EXTERNAL 

INSPECTION 

LAST; NEXT 

INTERNAL 

INSPECTION 

LAST; NEXT 

SERVICE 

HISTORY COMMENTS 

TANKO 

Alaska 124 Double-wall, welded steel 570 23,940 Oil; drilling fluids 1983 None 2014; 2019 2014; 2019 Continuous since 1983 COPA Ref# SST-051 

TANKO 

Alaska 125 Double-wall, welded steel 570 23,940 Oil; drilling fluids 1983 None 2014; 2019 2014; 2019 Continuous since 1983 COPA Ref# SST-052 

TANKO 

Alaska 127 Double-wall, welded steel 570 23,940 Oil; drilling fluids 1983 None 2014; 2019 2014; 2019 Continuous since 1992 

TANKO 

Alaska 128 Double-wall, welded steel 570 23,940 Oil; drilling fluids 1983 None 2014; 2019 2014; 2019 Continuous since 1983 COPA Ref# SST-053 

TANKO 

Alaska 130 Double-wall, welded steel 570 23,940 Oil; drilling fluids 1983 None 2015; 2020 2015; 2020 Continuous 

since 1983 

TANKO 

Alaska 131 Double-wall, welded steel 570 23,940 Varies 1983 None 2015; 2020 2015; 2020 Continuous 

since 1983 COPA Ref# SST-069 

TANKO 

Alaska 132 Double-wall, welded steel 570 23,940 Oil; drilling 

fluids 1983 None 2014; 2019 2014; 2019 Continuous 

since 1983 

TANKO 

Alaska H-01 Single-wall upright 400 16,800 Varies 1992 None 2016; 2021 2016; 2021 Continuous since 1992 COPA Ref# SST-036 

TANKO 

Alaska H-07 Single-wall 

upright 400 16,800 Varies 1992 None 2016; 2021 2016; 2021 Continuous 

since 1992 COPA Ref# SST-042 

TANKO 

Alaska 

O-3 

(CTU-03) 

Double-wall; 

Horizontal opentop 616 25,872 Varies 1990 None 2015; 2020 2015; 2020 Continuous 

since 1990 

TANKO 

Alaska 

O-5 

(CTU-05) 

Double-wall; 

Horizontal opentop 461 19,362 Varies 1990 None 2013; 2018 2013; 2018 Continuous 

since 1990 

TANKO 

Alaska 

O-8 

(CTU-08) 

Double-wall; 

Horizontal opentop 460 19,320 Varies 1992 None 2014; 2019 2014; 2019 Continuous 

since 1992 COPA Ref# SST-055 

TANKO 

Alaska 

O-9 

(CTU-09) 

Double-wall; 

Horizontal opentop 505 21,210 Varies 1992 None 2016; 2021 2016; 2021 Continuous 

since 1992 COPA Ref# SST-056 

Alpine FIeld, Satellites, and Pipelines ODPCP D-15 February 2018, Rev. 0 
TABLE D-3 

RENTED OR LEASED PORTABLE OIL STORAGE TANKS 10,000 GALLONS OR GREATER AVAILABLE FOR USE 

OWNER TAG 

NUMBER 

TANK 

DESCRIPTION 

VOLUME 

(BBL) 

VOLUME 

(GAL) CONTENTS FABRICATION 

DATE 

CONSTRUCTION 

STANDARD 

EXTERNAL 

INSPECTION 

LAST; NEXT 

INTERNAL 

INSPECTION 

LAST; NEXT 

SERVICE 

HISTORY COMMENTS 

TANKO 

Alaska O-10 Single-wall Open Top Skid 415 17,430 Varies Unknown None 2015; 2020 2015; 2020 Continuous 

TANKO 

Alaska O-11 Single-wall Open Top Skid 415 17,430 Varies Unknown None 2015; 2020 2015; 2020 Continuous 

TANKO 

Alaska O-15 Tiger Tank 320 13,440 Varies 1986 None 2014; 2019 2014; 2019 Continuous since 1990 COPA Ref# SST-057 

TANKO 

Alaska O-16 Tiger Tank 320 13,440 Varies 1986 None 2014; 2019 2014; 2019 Continuous since 1990 COPA Ref# SST-058 

TANKO 

Alaska O-17 Tiger Tank 320 13,440 Varies Pre-1990 None 2015; 2020 2015; 2020 Continuous since 1990 COPA Ref# SST-044 

TANKO 

Alaska O-21 Tiger Tank 460 19,320 Varies 1986 None 2014; 2019 2014; 2019 Continuous since 1990 COPA Ref# SST-045 

TANKO 

Alaska O-22 Tiger Tank 500 21,000 Varies 1986 None 2014; 2019 2014; 2019 Continuous 

since 1990 

TANKO 

Alaska O-23 Tiger Tank 500 21,000 Varies 1986 None 2014; 2019 2014; 2019 Continuous since 1990 

TANKO 

Alaska T-12 Horizontal opentop 425 17,850 Varies Pre-1992 None 2013; 2018 2013; 2018 Continuous 

since 1992 

TANKO 

Alaska T-22 

Double-wall 

Horizontal Opentop 400 16,800 Drilling fluids 2013 ADEC Approval 

#2014-01 New; 2018 New; 2018 

Start of 

service 

2014 

See letter dated 10/27/2014 in 

Section 3.11 

TANKO 

Alaska T-23 

Double-wall 

Horizontal Opentop 400 16,800 Drilling fluids 2013 ADEC Approval 

#2014-01 New; 2018 New; 2018 

Start of 

service 

2014 

See letter dated 10/27/2014 in 

Section 3.11 

TANKO 

Alaska T-24 

Double-wall 

Horizontal Opentop 400 16,800 Drilling fluids 2014 ADEC Approval 

#2014-01 New; 2019 New; 2019 New 2014 See letter dated 10/27/2014 in Section 3.11 

TANKO 

Alaska T-25 

Double-wall 

Horizontal Opentop 400 16,800 Drilling fluids 2014 ADEC Approval 

#2014-01 New; 2019 New; 2019 New 2014 See letter dated 10/27/2014 in Section 3.11 

Alpine FIeld, Satellites, and Pipelines ODPCP D-16 February 2018, Rev. 0 
 

 

TABLE D-3 

RENTED OR LEASED PORTABLE OIL STORAGE TANKS 10,000 GALLONS OR GREATER AVAILABLE FOR USE 

OWNER TAG 

NUMBER 

TANK 

DESCRIPTION 

VOLUME 

(BBL) 

VOLUME 

(GAL) CONTENTS FABRICATION 

DATE 

CONSTRUCTION 

STANDARD 

EXTERNAL 

INSPECTION 

LAST; NEXT 

INTERNAL 

INSPECTION 

LAST; NEXT 

SERVICE 

HISTORY COMMENTS 

TANKO 

Alaska T-26 

Double-wall 

Horizontal Opentop 400 16,800 Drilling fluids 2014 ADEC Approval 

#2014-01 New; 2019 New; 2019 New 2014 See letter dated 10/27/2014 in Section 3.11 

TANKO 

Alaska T-27 

Double-wall 

Horizontal Opentop 400 16,800 Drilling fluids 2014 ADEC Approval 

#2014-01 New; 2019 New; 2019 New 2014 See letter dated 10/27/2014 in Section 3.11 

TANKO 

Alaska T-28 

Double-wall 

Horizontal Opentop 400 16,800 Drilling fluids 2014 ADEC Approval 

#2014-01 New; 2019 New; 2019 New 2014 See letter dated 10/27/2014 in Section 3.11 

TANKO 

Alaska T-29 

Double-wall 

Horizontal Opentop 

400 16,800 Drilling fluids 2014 ADEC Approval 

#2014-01 New; 2019 New; 2019 New 2014 See letter dated 10/27/2014 in Section 3.11 

TANKO 

Alaska T-30 

Double-wall 

Horizontal Opentop 400 16,800 Drilling fluids 2014 ADEC Approval 

#2014-01 New; 2019 New; 2019 New 2014 See letter dated 10/27/2014 in 

Section 3.11 

TANKO 

Alaska T-31 

Double-wall 

Horizontal Opentop 400 16,800 Drilling fluids 2014 ADEC Approval 

#2014-01 New; 2019 New; 2019 New 2014 See letter dated 10/27/2014 in 

Section 3.11 

TANKO 

Alaska T-32 

Double-wall 

Horizontal Opentop 400 16,800 Drilling fluids 2014 ADEC Approval 

#2014-01 New; 2019 New; 2019 New 2014 See letter dated 10/27/2014 in 

Section 3.11 

TANKO 

Alaska T-33 

Double-wall 

Horizontal Opentop 400 16,800 Drilling fluids 2014 ADEC Approval 

#2014-01 New; 2019 New; 2019 New 2014 See letter dated 10/27/2014 in Section 3.11 

Notes: 

1. Listed tanks are not owned by COPA, but may be directly rented or leased by COPA. Owners are responsible for conducting appropriate inspections and for maintaining records according to the 

provisions of 18 AAC 75.066. Tanks leased (rented) directly by COPA are managed under COPA's Tank Management Program while under lease; tank records are subject to review by COPA. 

Prior to return to COPA facilities for use, tanks require current inspection, record review under COPA's Tank Management Program, and update of information in this table. 

2. Tanks are required to be placed in secondary containment sized to 100% of the volume of the largest tank, plus additional volume for local precipitation, per 18 AAC 75.075(a). A compliance 

waiver must be in place for tanks that do not meet this requirement. 

3. COPA is responsible for ensuring tanks meet regulatory requirements for leak detection systems, overfill protection, and testing of overfill protection per 18 AAC 75.066 as described in this 

ODPCP. 

4. Tanks placed into service after December 30, 2008 must be constructed and installed in compliance with 18 AAC 75.066. 

5. Tanks placed into service before December 30, 2008 do not require ADEC approval of construction standard. Prior to use, tank records are reviewed by COPA to determine the service history. 

Alpine FIeld, Satellites, and Pipelines ODPCP D-17 February 2018, Rev. 0 
TABLE D-4 

THIRD-PARTY OIL STORAGE TANKS 10,000 GALLONS OR GREATER NOT OWNED OR OPERATED BY COPA 

OWNER / 

OPERATOR TAG NUMBER TANK 

DESCRIPTION 

VOLUME 

(BBL) 

VOLUME 

(GAL) CONTENTS FABRICATION 

DATE 

CONSTRUCTION 

STANDARD 

EXTERNAL 

INSPECTION 

LAST; NEXT 

INTERNAL 

INSPECTION 

LAST; NEXT 

COMMENTS 

Halliburton 850 

(S/N 100863) 

Horizontal 

rectangular 476 20,000 Frac fluids 2012 ADEC Approval #2016-01 2017; 2022 2012; 2022 

rented from Lynden 

Oilfield Services, 

Section 3.11 

Halliburton 851 

(S/N 100864) 

Horizontal 

rectangular 476 20,000 Frac fluids 2012 ADEC Approval #2016-01 2017; 2022 2012; 2022 

rented from Lynden 

Oilfield Services, 

Section 3.11 

Halliburton 852 

(S/N 100865) 

Horizontal 

rectangular 476 20,000 Frac fluids 2012 ADEC Approval #2016-01 2017; 2022 2012; 2022 

rented from Lynden 

Oilfield Services, 

Section 3.11 

Halliburton 853 

(S/N 100866) 

Horizontal 

rectangular 476 20,000 Frac fluids 2012 ADEC Approval #2016-01 2017; 2022 2012; 2022 

rented from Lynden 

Oilfield Services, 

Section 3.11 

Halliburton 854 

(S/N 100868) 

Horizontal 

rectangular 476 20,000 Frac fluids 2012 ADEC Approval #2016-01 2017; 2022 2012; 2022 

rented from Lynden 

Oilfield Services, 

Section 3.11 

Halliburton 855 

(S/N 100869) 

Horizontal 

rectangular 476 20,000 Frac fluids 2012 ADEC Approval #2016-01 2017; 2022 2012; 2022 

rented from Lynden 

Oilfield Services, 

Section 3.11 

Halliburton 856 

(S/N 100870) 

Horizontal 

rectangular 476 20,000 Frac fluids 2012 ADEC Approval #2016-01 2017; 2022 2012; 2022 

rented from Lynden 

Oilfield Services, 

Section 3.11 

Halliburton 857 

(S/N 100872) 

Horizontal 

rectangular 476 20,000 Frac fluids 2012 ADEC Approval #2016-01 2017; 2022 2012; 2022 

rented from Lynden 

Oilfield Services, 

Section 3.11 

Halliburton 858 

(S/N 100873) 

Horizontal 

rectangular 476 20,000 Frac fluids 2012 ADEC Approval #2016-01 2017; 2022 2012; 2022 

rented from Lynden 

Oilfield Services, 

Section 3.11 

Halliburton 859 

(S/N 100874) 

Horizontal 

rectangular 476 20,000 Frac fluids 2012 ADEC Approval #2016-01 2017; 2022 2012; 2022 

rented from Lynden 

Oilfield Services, 

Section 3.11 

Halliburton 860 

(S/N 100881) 

Horizontal 

rectangular 476 20,000 Frac fluids 2012 ADEC Approval #2016-01 2017; 2022 2012; 2022 

rented from Lynden 

Oilfield Services, 

Section 3.11 

Halliburton 861 

(S/N 100894) 

Horizontal 

rectangular 476 20,000 Frac fluids 2012 ADEC Approval #2016-01 2017; 2022 2012; 2022 

rented from Lynden 

Oilfield Services, 

Section 3.11 

Halliburton 862 

(S/N 100895) 

Horizontal 

rectangular 476 20,000 Frac fluids 2012 ADEC Approval 

#2016-01 2017; 2022 2012; 2022 

rented from Lynden 

Oilfield Services, 

Section 3.11 

Alpine Field, Satellites, and Pipelines ODPCP D-18 February 2018, Rev. 0 
TABLE D-4 

THIRD-PARTY OIL STORAGE TANKS 10,000 GALLONS OR GREATER NOT OWNED OR OPERATED BY COPA 

OWNER / 

OPERATOR TAG NUMBER TANK 

DESCRIPTION 

VOLUME 

(BBL) 

VOLUME 

(GAL) CONTENTS FABRICATION 

DATE 

CONSTRUCTION 

STANDARD 

EXTERNAL 

INSPECTION 

LAST; NEXT 

INTERNAL 

INSPECTION 

LAST; NEXT 

COMMENTS 

Halliburton 863 

(S/N 100896) 

Horizontal 

rectangular 476 20,000 Frac fluids 2012 ADEC Approval #2016-01 2017; 2022 2012; 2022 

rented from Lynden 

Oilfield Services, 

Section 3.11 

Halliburton 864 

(S/N 100897) 

Horizontal 

rectangular 476 20,000 Frac fluids 2012 ADEC Approval #2016-01 2017; 2022 2012; 2022 

rented from Lynden 

Oilfield Services, 

Section 3.11 

Halliburton 865 

(S/N 100898) 

Horizontal 

rectangular 476 20,000 Frac fluids 2012 ADEC Approval #2016-01 2017; 2022 2012; 2022 

rented from Lynden 

Oilfield Services, 

Section 3.11 

Halliburton 866 

(S/N 100899) 

Horizontal 

rectangular 476 20,000 Frac fluids 2012 ADEC Approval #2016-01 2017; 2022 2012; 2022 

rented from Lynden 

Oilfield Services, 

Section 3.11 

Halliburton 867 

(S/N 100802) 

Horizontal 

rectangular 476 20,000 Frac fluids 2012 ADEC Approval #2016-01 2017; 2022 2012; 2022 

rented from Lynden 

Oilfield Services, 

Section 3.11 

Halliburton 868 

(S/N 100804) 

Horizontal 

rectangular 476 20,000 Frac fluids 2012 ADEC Approval #2016-01 2017; 2022 2012; 2022 

rented from Lynden 

Oilfield Services, 

Section 3.11 

Halliburton 869 

(S/N 100805) 

Horizontal 

rectangular 476 20,000 Frac fluids 2012 ADEC Approval #2016-01 2017; 2022 2012; 2022 

rented from Lynden 

Oilfield Services, 

Section 3.11 

Halliburton T-14 Tiger Tank 500 21,000 Oil; drilling 

fluids 

In service 

pre-1992 non-standard 2014; 2019 2014; 2019 rented from Lynden 

Oilfield Services 

Halliburton T-18 Tiger Tank 500 21,000 Varies 1990 non-standard 2014; 2019 2014; 2019 rented from Lynden 

Oilfield Services 

Halliburton T-19 Tiger Tank 500 21,000 Varies 1990 non-standard 2015; 2020 2015; 2020 rented from Lynden 

Oilfield Services 

Halliburton T-20 Tiger Tank 500 21,000 Varies 1990 non-standard 2014; 2019 2014; 2019 rented from Lynden 

Oilfield Services 

Halliburton T-21 Tiger Tank 500 21,000 Varies 1990 non-standard 2014; 2019 2014; 2019 rented from Lynden 

Oilfield Services 

Ice Services 128 Camp Tank Dike Tank on Skid 285 12,000 Diesel 2013 UL-142 New 2013; 2018 New 2013; 2023 Located at Kuukpik 

Pad 

Alpine Field, Satellites, and Pipelines ODPCP D-19 February 2018, Rev. 0 
TABLE D-4 

THIRD-PARTY OIL STORAGE TANKS 10,000 GALLONS OR GREATER NOT OWNED OR OPERATED BY COPA 

OWNER / 

OPERATOR TAG NUMBER TANK 

DESCRIPTION 

VOLUME 

(BBL) 

VOLUME 

(GAL) CONTENTS FABRICATION 

DATE 

CONSTRUCTION 

STANDARD 

EXTERNAL 

INSPECTION 

LAST; NEXT 

INTERNAL 

INSPECTION 

LAST; NEXT 

COMMENTS 

MI Swaco E-02-034-S1 Upright Tank (MI 32) 600 25,200 Drilling Fluids 2002 API 12 F 2012; 2017 2012; 2022 Located at Alpine CD1 

Mud Plant 

MI Swaco E-02-034-S2 Upright Tank (MI 34) 600 25,200 Drilling Fluids 2002 API 650 2016; 2021 2016; 2026 Located at Alpine CD1 

Mud Plant 

MI Swaco E-02-034-S3 Upright Tank (MI 33) 600 25,200 Drilling Fluids 2002 API 650 2016; 2021 2016; 2026 Located at Alpine CD1 

Mud Plant 

MI Swaco E-98-272-2 Upright Tank (MI 27) 600 25,200 Drilling Fluids 1998 API 12 F 2013; 2018 2008; 2018 Located at Alpine CD1 

Mud Plant 

MI Swaco E-98-272-3 Upright Tank (MI 28) 600 25,200 Drilling Fluids 1998 API 12 F 2013; 2018 2008; 2018 Located at Alpine CD1 

Mud Plant 

MI Swaco E-98-272-4 Upright Tank (MI 26) 600 25,200 Drilling Fluids 1998 API 12 F 2015; 2018 2015; 2025 Located at Alpine CD1 

Mud Plant 

MI Swaco E-98-272-5 Upright Tank (MI 30) 600 25,200 Drilling Fluids 1998 API 12 F 2013; 2018 2008; 2018 Located at Alpine CD1 

Mud Plant 

MI Swaco E-98-272-6 Upright Tank (MI 31) 600 25,200 Drilling Fluids 1998 API 12 F 2013; 2018 2008; 2018 Located at Alpine CD1 

Mud Plant 

MI Swaco MI-A6061610 ALP INJ SKID 

T-0001 1,000 42,000 Drilling Fluids 

2013 

(first service in 

2014) 

API 650 

Appendix J 2014; 2019 2014; 2024 Located at Alpine 

Injection skid at CD1 

MI Swaco MI-A6061611 ALP INJ SKID 

T-0002 1,000 42,000 Drilling Fluids 

2013 

(first service in 

2014) 

API 650 

Appendix J 2014; 2019 2014; 2024 Located at Alpine 

Injection skid at CD1 

MI Swaco MI-A6061612 ALP INJ SKID 

T-0003 1,000 42,000 Drilling Fluids 

2013 

(first service in 

2014) 

API 650 

Appendix J 2014; 2019 2014; 2024 Located at Alpine 

Injection skid at CD1 

MI Swaco MI-A6061613 ALP INJ SKID 

T-0004 1,000 42,000 Drilling Fluids 

2013 

(first service in 

2014) 

API 650 

Appendix J 2014; 2019 2014; 2024 Located at Alpine 

Injection skid at CD1 

Schlumberger 2SUS15818 Tiger Tank 500 21,000 Varies 2000 ADEC Waiver 2013; 2018 2013; 2023 ADEC approval 

Section 3.11 

Alpine Field, Satellites, and Pipelines ODPCP D-20 February 2018, Rev. 0 
TABLE D-4 

THIRD-PARTY OIL STORAGE TANKS 10,000 GALLONS OR GREATER NOT OWNED OR OPERATED BY COPA 

OWNER / 

OPERATOR TAG NUMBER TANK 

DESCRIPTION 

VOLUME 

(BBL) 

VOLUME 

(GAL) CONTENTS FABRICATION 

DATE 

CONSTRUCTION 

STANDARD 

EXTERNAL 

INSPECTION 

LAST; NEXT 

INTERNAL 

INSPECTION 

LAST; NEXT 

COMMENTS 

Schlumberger 2SUS16104 Tiger Tank 500 21,000 Varies 2000 ADEC Waiver 2013; 2018 2013; 2023 ADEC approval 

Section 3.11 

Schlumberger 2SUS18473 Horizontal 

rectangular 500 21,000 Varies 2001 ADEC Waiver 2013; 2018 2013; 2023 ADEC approval 

Section 3.11 

Schlumberger 2SUS18603 Tiger Tank 500 21,000 Varies 2001 ADEC Waiver 2013; 2018 2013; 2018 ADEC approval 

Section 3.11 

Schlumberger 2SUS18606 Tiger Tank 500 21,000 Varies 2001 ADEC Waiver 2013; 2018 2013; 2023 ADEC approval 

Section 3.11 

Schlumberger 2SUS18607 Tiger Tank 500 21,000 Varies 2001 ADEC Waiver 2013; 2018 2013; 2023 ADEC approval 

Section 3.11 

Schlumberger 2SFF41961 

Horizontal 

rectangular Frac 

Tank 

500 21,000 Varies 2013 ADEC Approval 

#2013-01 New 2013; 2018 New 2013; 2023 

See letter dated 

2/28/2013 in Section 

3.11 

Schlumberger 2SFF41962 

Horizontal 

rectangular Frac 

Tank 

500 21,000 Varies 2013 ADEC Approval 

#2013-01 New 2013; 2018 New 2013; 2023 

See letter dated 

2/28/2013 in Section 

3.11 

Schlumberger 2SFF41963 

Horizontal 

rectangular Frac 

Tank 

500 21,000 Varies 2013 ADEC Approval 

#2013-01 New 2013; 2018 New 2013; 2023 

See letter dated 

2/28/2013 in Section 

3.11 

Schlumberger 2SFF41964 

Horizontal 

rectangular Frac 

Tank 

500 21,000 Varies 2013 ADEC Approval 

#2013-01 New 2013; 2018 New 2013; 2023 

See letter dated 

2/28/2013 in Section 

3.11 

Schlumberger 2SSF48256 Horizontal 

rectangular 500 21,000 Varies 2014 ADEC Approval #2013-01 New 2014; 2019 New 2014; 2024 

See letter dated 

2/28/2013 in Section 

3.11 

Schlumberger 2SSF48257 Horizontal 

rectangular 500 21,000 Varies 2014 ADEC Approval #2013-01 New 2014; 2019 New 2014; 2024 

See letter dated 

2/28/2013 in Section 

3.11 

Schlumberger 2SSF48258 Horizontal 

rectangular 500 21,000 Varies 2014 ADEC Approval #2013-01 New 2014; 2019 New 2014; 2024 

See letter dated 

2/28/2013 in Section 

3.11 

Schlumberger 2SSF48259 Horizontal 

rectangular 500 21,000 Varies 2014 ADEC Approval 

#2013-01 New 2014; 2019 New 2014; 2024 

See letter dated 

2/28/2013 in Section 

3.11 

Alpine Field, Satellites, and Pipelines ODPCP D-21 April 2018, Rev. 1 
TABLE D-4 

THIRD-PARTY OIL STORAGE TANKS 10,000 GALLONS OR GREATER NOT OWNED OR OPERATED BY COPA 

OWNER / 

OPERATOR TAG NUMBER TANK 

DESCRIPTION 

VOLUME 

(BBL) 

VOLUME 

(GAL) CONTENTS FABRICATION 

DATE 

CONSTRUCTION 

STANDARD 

EXTERNAL 

INSPECTION 

LAST; NEXT 

INTERNAL 

INSPECTION 

LAST; NEXT 

COMMENTS 

Schlumberger 2SSF48260 Horizontal 

rectangular 500 21,000 Varies 2014 ADEC Approval #2013-01 New 2014; 2019 New 2014; 2024 

See letter dated 

2/28/2013 in Section 

3.11 

Schlumberger 2SSF48261 Horizontal 

rectangular 500 21,000 Varies 2014 ADEC Approval 

#2013-01 New 2014; 2019 New 2014; 2024 

See letter dated 

2/28/2013 in Section 

3.11 

Schlumberger 2SSF48262 Horizontal 

rectangular 500 21,000 Varies 2014 ADEC Approval #2013-01 New 2014; 2019 New 2014; 2024 

See letter dated 

2/28/2013 in Section 

3.11 

Note: Prior to return to use at COPA facilities, tank requires current inspection, record review under COPA's tank management program, and update of information in this table. Listed tanks are not owned 

by COPA. Owners are responsible for conducting appropriate inspections and for maintaining records according to the provisions of 18 AAC 75.066. 

Alpine Field, Satellites, and Pipelines ODPCP D-22 April 2018, Rev. 1 
APPENDIX E 

ADEC APPROVAL LETTERS 
BLANK PAGE
 

Department of Environmental 

Conservation 

DIVISION OF SPILL PREVENTION AND RESPONSE 

Prevention, Preparedness and Response Program 

 555 Cordova St 

Anchorage. AK 99501 

Office: 907•269·3094 

Fax: 907-269-7687 

www.dec.aloska.gov 

File No.: 305.35 

January 21, 2016 

Jeanie Shifflett 

Emergency Planning Coordinator 

ConocoPhillips Alaska, Inc. 

P.O. Box 100360 

Anchorage, AK 99510-0360 

Subject: ConocoPhillips Alaska, Inc. Oil Discharge Prevention and Contingency 

Plans for the Kuparuk River Unit (Plan No. 12-CP-4102), Alpine Development (Plan 

No.12-CP-4140), and North Slope Exploration (Plan No. 12-CP-5096). Tank Design 

Awroval #2016-01 

Dear Ms. Shifflett: 

The Alaska Department of Environmental Conservation (department) has reviewed 

ConocoPhillips Alaska, Inc.'s (CPAI) December 8, 2015 request foe tank design approval. 

CPA! requested that the department approve an alternate tank design for portable 500-barrel 

"Frac" tank to be used by CPA! at its North Slope facilities. 

(CIE) 

18 AAC 75.066(b)(1) requires that shop-fabricated oil storage tanks be built to specified standards; 

however, 18 AAC 75.066(b)(2) allows alternate tank design if the design is certified by a registered 

engineer and is approved by the department as equivalent to a design for a standard listed in 18 

AAC 75.066(b)(1). Detailed information about the tank design was submitted in emails and in hard 

copy form. The tank design was reviewed by the department's engineering staff. The following 

documents were included in CIE's submittal and were reviewed and considered for design approval. 

1. Tank drawings, certified by Professional Engineer 

2. Modified API 653 Inspection Report - initial, for new tank 

3. Manufacturing specifications quality control inspection documentation 

4. Hydro Test Report 

5. Welding Procedure and Specification 

6. Welding Procedure Qualification Record 

7. Example photo of tank with this design 

When operated at CPA! facilities, tanks of this design will be managed in accordance with 

applicable regulations of 18 AAC 75 and as described in the facility's Oil Discharge Prevention 
Jeanie Shifflett 

ConocoPhillips Alaska, Inc. 

2 January 21, 2016 

and Contingency Plan. CPAI tank management personnel review tank records to verify 

compliance and document company approval of tanks for service prior to first operation in the 

field. In addition, a structural engineer registered in Alaska verified the integrity of the tanks through 

stress analysis modeling and certified the results. 

The department's review indicates that tanks built per the submitted design criteria should 

be fit for service for atmospheric, hydrocarbon service. Based on the tank drawings, the 

tank meets the construction and appurtenance requirements of 18 AAC 75.066. The 

department approves this design as equivalent to a design for a standard listed in 18 AAC 

75.066(b)(l). This alternate construction standard approval, "Tank Design Approval #2016-

01," remains valid for tanks built to the design specifications. In the future, as long as there 

is verification that a tank is being built per this design package, no further evaluation by the 

department is necessary. 

Please be advised that this approval docs not relieve you of the responsibility for securing 

other state, federal, or local approvals or permits, and that you are still required to comply 

with applicable requirements of 18 AAC 75, Article 1 and all other applicable laws. 

If you have any questions, please contact Gary Evans at (907) 269-7536 or via email at 

g;icy.evans@alaska.gov. 

Sincerely, 

Tom DeRuyter 

Northern Alaska Region Manager 

Electronic cc: 

Laurie Silfven, ADEC 

Gary Evans, ADEC 

Jessica Starsman, ADEC 

Sam Saengsudham, ADEC 

Roger Burleigh, ADEC 
 

 

October 27, 2014 

Jeanie Shifflett 

Emergency Planning Coordinator 

ConocoPhillips Alaska, Inc. 

P.O. Box 100360 

Anchorage, AK 99510-0360 

Department of Environmental 

Conservation 

DIVISION OF SPILL PREVENTION & RESPONSE 

INDUSTRY PREPAREDNESS PROGRAM 

Exploration, Production and Refineries 

555 Cordova Street 

Anchorage. Alaska 99501 

Main: 907.269.3094 

Fox: 907.269.7687 

File No.: 305.35 

(CPAI-Alpine. KRU, NSX) 

Subject ConocoPhillips Alaska, Inc. Oil Discharge Prevention and Contingency Plans 

for the Kupanak River Unit (Plan No. 12-CP-4102), Alpine Development (Plan No. 

12-CP-4140), and North Slope Explomtion (Plan No. 12-CP-5096). Tank De,igp, 

Appoya1#1,014-01 

Dear Ms. Shifflett 

The Alaska Department of Envhonmental Conservation (department) has ieviewed ConocoPhillips 

Alaska, Inc.'s (CPAI) September 25, 2014 request for tank design npp.rovaL CPAI requested that the 

department approve an altemate tnnk design for portable 400 baael, .recmngular storage tanks 

owned by Taok-0 Alas~ LLC for use by CP. I at its Noffh Slope fuc:ilities. 

18 AAC 75.066(b)(1) requires that shop-fub.ticated oil stofflge tulks be built to specified standards; 

however, 18 AAC 75.066(b)(2) allows altemate tnnk design if the design is cei:tified by a registered 

engineer and is approvea by the depamnent as equivalent to a design for a stnndard listed in 18 

AAC 75.066(b)(t). Detailed informadon about the tank design was submitted on a CD, along with 

inspections aod repod:s 6 t two example tanks. The tnnk design wns engineeied by PCI 

Manufacturing, I.LC. A conceptual review wns conducted by the lndustty Preparedness Program's 

Pipeline and Tank lntegnty Section on the following design infonnation: 

• Tank drawings 

• Wdding ProcedUle Speci.6.cndons and Wd der Qualifications 

• Wdding Inspection Repo.rts and Hydrotest nnd Air Test Reports 

• Materials Summary and Test Repom 

• Structural Calculations 

• Coating Inspection Repom 

• Coating Data Sheets 

• Inspector Qualifications 
Jeanie Shifflett 

ConocoPhillips Alaska, Inc. 

2 October 27, 2014 

Review of the design submittal substantiates that department approval of the tank design as 

equivalent to a standard listed in 18 AAC 75.066(b)(2) is warranted. A summary of findings is 

outlined below: 

• The 400-battel steel, horizontal, recmngular, double-w~ open-top tank is reported to have 

been designed and constructed to American Petroleum Institute (API) 650, Weld4d Sm/ 

Tanks for Oil Storage, including modifications in Appendix J for shop-assembled stotage tanks, 

which meets the requirements of 18 AAC 75.066(b). 

• The tank meets 18 AAC 75.066(e) by having an interstitial monitoring system, a fixed overfill 

spill containment system at the fill and dispensing ports, and a system for freeing any 

contents from the interstitial space. 

• Structwal calculations were perfonned and smmped by a licensed Alaska Professional 

Engineer. 

• The construction drawings were approved and stamped by a licensed Alaska Professional 

Engineer. 

The department's review indicates that tanks built per the submitted design criteria should be fit for 

service for atmospheric, hydrocarbon service. Based on the tank drawings, the tank meets the 

construction and appurtenance requirements of 18 AAC 75.066. The department approves this 

design as equivalent to a design for a standard listed in 18 AAC 75.066(b)(1). This alternate 

construction standard approval, ''Tank Design Approval #2014-01," remains valid for tanks built to 

the design specifications. In the future, as long as there is verification that a tank is being built per 

this design package, no further evaluation by the department is necessary. 

Please be advised that this approval does not relieve you of the responsibility for securing other 

state, federal, or local approvals or permits, and that you are still required to comply with applicable 

requirements of 18 AAC 75, Article 1 and all other applicable laws. 

If you have any questions, please contact Laurie Silfven at (907) 269-7540 or via email at 

· · or myself at (907) 269-7680 or grabarn,wood@alaska,~y. 

Section Manager 

Electronic cc: 

Laurie Silfven, ADEC 

Ashley Adamczak, ADEC 

Sam Saengsudham, ADEC 

Roger Burleigh, ADEC 

Beth Heim, ADEC 

Gary Evans, ADEC 

Mike Evans, ADEC 
 

 

February 28, 2013 

Jeanie Shifflett 

Emergency Planning Coordinator 

ConocoPhillips Alaska, Inc. 

P.O. Box 100360 

Anchorage, AK 99510-0360 

Department of Environmental 

Conservation 

DIVISION OF SPILL PREVENTION & RESPONSE 

INDUSTRY PREPAREDNESS PROGRAM 

Exploration, Production and Refineries 

555 Cordova Street 

Anchorage, Alosk.o 99501 

Main: 907.269.3094 

fox; 907.269.7687 

File No.: 305.3S (Rev. I) 

(CPAI·Alpinc, KRU, NSX) 

Subject: ConocoPhillips Alaska, Inc. Oil Discharge Prevention and Contingency Plans. 

Tank Design Approval #2013-01 - Schlumberger Portable Tank& for the Kuparuk 

River Unit (Plan N o. 07-CP-4102), Alpine Development (Plan No. 12-CP-4140), and 

North Slope Exploration (Plan No. 12-CP-5096). Reyisionl 

Dear Ms. Shifflett: 

The Alaska Department of Environmental Conservation (department) bas ieviewed ConocoPhillips 

Alaska, Inc.'s (CPA.I) request for tank design approval dated November 21, 2012. CPAI requested 

that the department approve an altemate tnnk design for portable 500-barrel, rectangular storage 

tanks for use by CPAI at its North Slope facilities. 

18 AAC 75.066(b)(1) requires that shop-fabricated oil stornge tanks be built to specified standards; 

however, 18 AAC 75.066(b)(2) allows altemative tnnk design if the design is certified by a registered 

engineer and is approved by the department as equivalent to a design for a standard listed in 18 

AAC 75.066(b)(t). CPAI submitted a design/consttuction package for five portable storage tanks 

owned by Schlumberger Technology Coq,omtion and consttucted in 2012. The tank design was 

engineered and built by Greer Tank and Welding, Inc. A conceptual review was conducted by the 

Industry Preparedness Progmm's Pipeline and Tank Integrity Section on the submitted 

design/ construction package wbicb included the following documentntion: 

• Hydrotest Certificates 

• Certificate of Acceptnnce - Certificate of Compliance 

• Welding Procedure Speci.6cntions 

• Welding Qualification Test Record 

• Professional Engineer Stnmped Dmwings 

• Professional Engineer Stamped Structural Calculations 

• Tank As-Built Dmwings 
Jeanie Shifflett 

ConocoPhillips Alaska, Inc. 

2 February 28, 2013 

Review of the design/ construction package substantiates that department approval of the tank 

design as equivalent to a standard listed in 18 AAC 75.066(b)(2) is warnnted. A summary of 

findings is outlined below: 

• Structural calculations were perfonned and stamped by a licensed Alaska Professional 

Engineer. 

• The construction drawings were approved and stamped by a licensed Alaska Professional 

Engineer. 

• As-built drawings confinn design intent. 

• The design criteria notes state that tanks were constructed to follow the basic design 

provisions of American Petroleum Institute (API) 650, Welmd Sue/ Tanks far Oil Slmlge, 11th 

Edition, including Addendums 1, 2, and 3, and specifically Appendix J, Slx,p-Assemb'4d Storage 

Tanks, unless deviations were specified. The design criteria notes indicate that API 650 

provided the most appropriate guidance, even though this rectangular tank design does not 

fit the large volume, vertical cylindrical tank configuration typical of API 650. 

• Welding documentation appears adequate. 

o Wdding procedure specifications are based on American Society of Mechanical 

Engineers (ASME) IX and American Wdding Society (AWS) D1.1 and were signed and 

stamped by an A WS-certified company representative. 

o Wdder and Wdding Operator Qualification Test records are signed and stamped by an 

A WS-certified company representative. 

o 100 percent of wdds were specified for visual inspection. 

o 100 percent of butt wdds at the wall plate, floor plate, and roof plate were specified for 

Liquid Penetrant examination. 

• Tank inspections in accordance with API 653 were conducted by an API-certified inspector. 

• Records indicate the tanks passed hydrostatic testing per Underwriters' Laboratories (UL) 

142. 

The department's review indicates that tanks built per the submitted procedures should be fit for 

service for atmospheric, hydrocarbon service. The department approves this design as equivalent to 

a design for a standard listed in 18 AAC 75.066(b)(1). This alternate construction standard approval, 

''Tank Design Approval #2013-01," remains valid for tanks built to the design/construction 

package specifications as long as the tank design and construction specifications are not modified 

and the tanks are operated within the established design parameters. In the future, as long as there is 

verification that a tank is being built per this design package, no further evaluation by the 

department is necessary. We request that CPAI give us advance notice of intended use of tanks 

built to this design standard. 

Please be advised that this approval does not rdieve you of the responsibility for securing other 

state, federal, or local approvals or permits, and that you are still required to comply with applicable 

requirements of 18 AAC 75, Article 1 and all other applicable laws. 

If you have any questions, please contact Laurie Silfven at (907) 269-7540 or via email at 

Jaurie.silfven@aJaska.gov, or contact me at (907) 269-7680 ot gJ1,baro,wood@alff!.ka.gov. 
J euiie Shifflett 

ConocoP · · s Alaska, Inc. 

Electronic cc: 

Laurie Silfven, ADEC 

Ashley Adamczak, ADEC 

Sam Saengsudham, ADEC 

Roger Burleigh, ADEC 

Keith Sanfacon, ADEC 

3 February 28, 2013 

 

 

 

 

DEPT. OF ENVIRONMENTAL CONSERVATION 

DIVISION OF SPILL PREVENTION AND RESPONSE 

INDUSTRY PREPAREDNESS PROGRAM 

Exploration Production & Refineries 

Mr. Jason Charton/Ms. Shellie Colegrove 

Alpine Operations 

ConocoPhillips Alaska, Inc. HSE-ALP 14 

P.O. Box 196860 

Anchorage, AK 99519-6105 

February 9, 2005 

FRANK H. MURKOWSKI, GOVERNOR 

555 Cordova Street 

Anchorage, AK 99501 

PHONE: (907) 269-3094 

FAX: (907) 269-7687 

http://www,.,<;tate.ak.us/dec 

Fil~ No. 305.35 (CPNAlpine) 

Subject: ConocoPhillips Alaska, Inc. (CPAI) Alpine Development Oil Discharge Prevention 

and Contingency Plan (plan). ADEC Plan Number 014-CP-4140. 

Waiver of Oil Storage Tank Construction Standards 

Dear Mr. Jason Charron/Ms. Shellie Colegrove: 

The Department of Environmental Conservation (Department) has reviewed your request dated 

December 23, 2004 and follow-on information provided for approval of an alternate construction 

standard for portable, 500-harrel, steel rectangular tanks (also referred to as "Tiger Tanks") to be 

used in the Alpine Development. Your submittal consists of drawings and supporting 

documentation for ten tanks owned by Schlumberger and constructed by Greer Tank and Welding. 

Under 18 AAC 75.065 (h)(l), tanks constructed, installed, or placed into service after May 14, 1992 

must he built to .A.Pl 650, API 12, or another standard approved by the Department. 

The tank records do not contain sufficient information for the Department to approve the current or 

future construction standard of these tanks; however, in accordance with 18 AAC 75.015, ADEC 

may waive a regulatory requirement if the owner or operator demonstrates that an equivalent level of 

protection will be achieved by using a technology or procedure other than that required by 18 AAC 

75.005 - 18AAC 75.090. 

These tanks have undergone hydrostatic testing with the average holding time of 2.5 hrs for 7 tanks 

and over 8 hrs for 3 tanks. The testing fill heights were 8'11" and 8' 1 0". The average water 

temperature (during the test) was 78 F. 

The tanks have been in service on the North Slope for five years, and have therefore endured the 

"test of time." It is our understanding that the tanks have typically been used for frac jobs performed 

with water; however, the tanks will contain diesel for frac jobs at Alpine. lt is our opinion that 

diesel service will not compromise tank integrity, since diesel has a lower specific gravity than water 

(between 0.82 and 0.95, depending on the grade). 

Based on our review of your submittal, the Department approves continued use of these tanks for the 

same service conditions based on the conditions described below. 

• The ten tanks with the following numbers are covered under this waiver: 2SUS18471, 

2SUS18472, 2SUS18473, 2SUS18474, 2SUS18475, 2SUS18476, 2SUS18477, 2SlJS18478, 

2SUS18479, and 2SUS18480. 

• Fill height of the tanks must be limited to the hydrostatic test fill height. 
Mr. Jason Charton/Ms. Shellie Colegrove 

ConocoPhillips Alaska, Inc. 

2 February 9, 2005 

• The fluid stored in the tanks must have a specific gravity equal to or less than 1.0. 

• Hydrostatic testing records must be kept as part of the permanent record of the tanks. 

• Since the hydrostatic tests were conducted in a controlled environment, other operational and 

physical factors must be considered when specifying the operational fill height. The fill 

height and other operational constraints need to be part of the operating procedures for the 

tanks. 

Assumptions and calculation worksheets are attached. Future designs or construction of similar 

tanks are not part of this waiver and will need to be evaluated on an individual basis to ensure that 

operational conditions are identical to the subject tanks. 

The Alpine plan must be revised at the next routine update or minor amendment to include this 

waiver approval letter. 

Future Alternate Tank Construction Standard Approvals: 

For a typical storage tank construction standard, it is customary to see the following information. 

Please note that the list might not be all inclusive, but it follows the framework of API Standard 650. 

• Intended service that defines the operating and environmental parameters for the tanks 

• Materials (selection) 

• Design, such as plate thickness and stiffeners spacing 

• FabricationJErection 

• Inspection Goints) 

• Welding procedure(s) and welder(s) qualification 

• Testing 

• Procedures to ensure that the specifications are being followed 

Additionally, we strongly emphasize the importance of designs having an Alaska Professional 

Engineer's (PE) seal as it will ensure solid evidence of sound practices and, if applicable, 

compliance with Alaska Statute (AS) 08.48. Alternatively, we recommend that designs lacking a PE 

stamp receive certification by CPAI's engineer. 

If you have any questions regarding the review process, please contact Laurie Silfven at (907) 

269-7540, or me at (907) 269-7680. 

cc: Bill Hutmacher, ADEC 

Laurie Silfvcn, ADEC 

Sam Saengsudham, ADEC 

Ed Meggert, ADEC, NART, Fairbanks 

Sincerely, 

Lydia Miner 

Section Manager 

Stephen Geddes/Jeanie Shifflett, CPAI, Anchorage 
The evaluation is based on the following assumptions. 

Assumptions Suooorting Documents 

Design pressure: 3.85 psi. Undated and unsigned engineering calculations. 

However, use 3.75 psi (fill height of 

8.6 ft) for calculation because of the 

soecified maximum wall hei!Zht. 

Design specific gravity: 1.02 Engineering calculation submitted on scratch paper 

(undated and unsigned) listing 64 lb~ water has typical 

ft 

specific weight of 62.3 lb~ at 60 F. 

ft 

The-material used: ASTM 36 -97 A Oregon Steel Mills Reoort. 

Thick:μess for wall and bottom Oregon Steel Mills Report. 

plates: 0.25" 

Structural configuration: Undated, unstamped, not detailed (not all dimensions 

Wall and bottom - flat plate with included) tank drawings. 

stiffeners. 

Maximum as-built wall stiffeners Engineering calculation submitted on scratch paper. 

spacing: 17" Date and author unknown due to the auality of the copy. 

No initial hydrostatic testing Only Greer Tank Air Test Certificate submitted. 

performed after construction. 

Maximum fill height: 104 inches Rectangular Tank Wall Design spreadsheet with the 

(8.66 ft) value of wall heimt of 104 inches. 

Design allowable (membrane) Submitted documentations -Rectangular Tank Wall 

stress: 27000 psi Desien spreadsheet. 

Allowable (membrane) stress using Typical published property of ASTM A36. Refer to 

in evaluation calculation: 36000 psi Table 4-1 of API Std 653, latest edition. 

Floor (beam) stiffeners spacing: 34" Drawinl?S submitted on 1/13/05 

Evaluation methodologies: 

1) Appendices I.7.3.1, I.7.3.2, and I.7.3.3 of API Std 650, 2003 Edition. 

2) AISI Steel Plate Engineering Data- Vol 2-1992. 

Welding procedures not reviewed because this is an in-service review. 

CPA - Schlumberger Frac Tank Review 

Saengsudham - Feb 05 

Page 1 of3 
API 6501 App I method: 

1bf F ·= 27000·-

y· .2 

m 

( 

2]0.5 

b := l.S·Fy• t: 

b = 25.981 ir 

tg := 0.25-ir p := 3.75• lbf 

.2 

m 

Appendix I, API Std 650 equation is generally more conservative 

than the steel plate engineering equations. Fy is 75% of the listed 

SMYS of A36 (36 ksi). 

Steel Plate Engineering Method: 

1bf 

Fy := 36000·~ 

m 

( 

2]0.5 , ·= Fy".75•t_g 

bmax· B·P 

B :=0.5 

bmax = 30ir 

Steel plate engineering equation, with B the most conservative 

assumption of B=0.5. Fy used is 100% of A36's listed SMYS. 

Where B is the longer side of a rectangular plate, and b is the shorter side. 

Pressure used for both cal's is the max hydrostatic at the bottom and applied equally for the 

entire wall. The pressure actually decreases going up the liquid column. Note that no 

corrosion allowance {CA) is factored in for the calculation. If use double SF's - 75% SMYS 

AND 70% SMYS for joint efficiency, bmax is = 25.1 inches. 

CPA- Schlumberger Frac Tank Review 

Saengsudham - Feb 05 

Page 2 of 3 

( 

( 
Floor: 

API 6501 App I method: 

lbf 

Fy := 27000·- . 2 

m 

( 

2')°'5 

b := l.S·F/:) 

b =- 25.742ir 

tg := 0.25-ir P := 3.82· ~b~ 

m 

Pressure (P) is from SG=1.0 (pressure of 3.75 ~b~ and 

zn 

weight of steel (pressure of 0.0707 ~b~ . zn 

Appendix I, API Std 650 is generally more conservative 

· (because ·it's a construction -code) .than the steel plate 

engineering equations. Fy of 27000 psi is 75% of the listed 

SMYS of A36 (36 ksi). If use 36 ksi, maximum spacing is 

29.72". 

Steel Plate Engineering Method (SPED): 

lbf 

Fy := 36000·- . 2 

m 

( 

2)0.5 ·= Fy·.75·tg 

brnax· B·P 

brnax = 29.754ir 

B := 0.499 

CPA- Schlumberger Frac Tanlc Review 

Saengsudham-Feb 05 

The coefficient B1=0.499 is from Table 1-1B at ratio of 

Bib= (26*12)/34 = 9.18. 

Page 3 of3 

DEPT. OF ENVIRONMENTAL CONSERVATION 

DIVISION OF SPILL PREVENTION AND RFSPONSE 

INDUSTRY PREPAREDNESS PROGRAM 

Exploration Production & Refineries 

Mr. John Whitehea4 

Alpine Development Project 

ConocoPhillips Alaska, Inc. 

P. 0. Box 196105 

Anchorage,AK 99519-6105 

Dear Mr. Whitehead: 

February 26, 2003 

FIIANK H. lfURKOWSKI, GOVERNOR 

SSS Cordova Street · 

Anchorage,AK 99501 

PHONB: (907) 269-3094 

FAX: (907) 269-7687 

hap:/lwww.atate.at.uldec 

HleNo: 305.30.4140 

SUBJECT:. Approval (waiver) of Oil Storage Tank Construction Standards; Oil 

Discharge Preventi.on~d Contingency Plan (''plan") for ConocoPhillips 

Alaska, Inc. (CPA) Alpine Development Participating Area; · 

ADEC Plan number: 994-CP-4140 

The Department of Environmental Conservation (Department) has reviewe4 your J.ariuary 27, 

2003, request for approval for the coμstmction of two types of tanks used for well-work, "Open 

Top" and "Tiger Tanks" as "another standard approved by the department''. in accordance with 

18 AAC J5.065(h)(l). The ·Department may waive a storage tank-requirement of 18 AAC 

75.065 if the owner or operator demonstrates that an equivalent level of protection will be -

achieved by using a technology or~ other than that required (18 AAC 75.0lS(c )]. 

CPA has indicated, and the Department has confirmed, that there are no nationally recognized 

construction standards for the "Open Top" and "Tiger Tanks." ~ecognizing that thereis no 

construction standard for these tanks to meet the "new installati_pn" ·tank requirements of 18 

AAC 75.065(h)(l), CPA developed a 'standard' for the construction of these tanks. CPA's 

. -standard includes welding procedure specifications, structural integrity cal~ulations, material 

specifications, and other engineering design considerations to standardize the design, 

construction and fitness for service of these tanks, based· on the intended uses and capacities of 

the subject tanks. 

The specifications have been reviewed by the Department's engineer, Sam Saengsudham, and 

API 653 Certified Tanlc Inspector, Kirsten-Ballard. Based upon this review, the Department has 

no objections to or additional comment on the use or design of the tanks as depicted in the 

BBFM Engineers Inc. design drawings and calculations, submitted on January 31, 2003, with 

the revised calculations and drawings for the Tiger Tank submitted-on February 11, 2003. 

Based on the information supplied by CPA and discussions with CPA personnel, the 

Department is granting the waiver. CPA must include a copy of this waiver in the section of the 

plan designated as "Compliance Schedule and Waivers," cunently Section 2. 7, for the duration 

of the service life of the subject tanks. Facility diagrams and other information required by 18 

AAC 75.425(e)(l-3) must also be included. · 

0 Prillll'd on Re,• 
Mr: John Whitehead 

ConocoPhillips Alaska, In~. 

2 Fe~ruary 26, 2003 

This waiver, including any necessary changes to the plan, must be incorporated into the plan 

renewal application currently in process prior to final distribution of the plan, when approved. 

CPA must notify the Department when any of the tanks are taken out of service or when major 

· repairs are made [Ref: 18 AAC 75.065(e) and 18 AAC 75.415(a)]. This waiver is subject to · 

the following conditions: 

l) CPA must use the "Open Top" and "Tiger Tanlc" designs for any new tanks of these 

types at CPA's North Slope facilities. Any CPA facility that uses these tanks must include a 

copy of this waiver in the appropriate section of the applicable plan for the service life of the 

tanks included by this waiver. This waiver is transferable to CPA, its subsidiaries and 

purchasing agents, but not to other plan holders without prior approval. 

This condition is reasonably necessary to affinn that these tanks, and any other tanks of this 

type that are brought into service after May 14, 1992, meet the intent of 18 AAC 75.065(hXl). 

The waiver is not transferable without prior approval, as required by 18 AAC 75.400 and 18 

AAC 75.415(a). 

2) CPA will include the procurement procedures describe~ below whenever new tanks of 

this type are ordered to ensure new oil storage tanks regulated under i8 AAC 75 are built to the 

appropriate code. This includes the modification of the "CPA Engineering Standards" for tanlc 

design, construction and placement into service to clearly define and identify the new oil 

storage tank construction requirements of 18 AAC 75.065 for CPA procurement processes. _The 

changes to the CPA Engineering Standards and acceptance protocols will be communicated to 

CPA Operations/Drilling/Wells management and will be followed when CPA procures new oil 

. __ .storage tanks ... _ . 

a) The proposed tank design will be developed in compliance with CPA' s Tank Design 

Criteria and Welded Tanlc Procurement Specification Qr Fiberglass Reinforced Tanlc 

Specification, depending on whether the tanlc is of welded or fiberglass construction; 

b) If a tanlc design code is desired that is not explicitly allowed by 18 AAC 75.065, a 

request for a waiver will be submitted to the Department for approval prior to the 

commencement of any construction work; 

c) The new tank cannot be released for service until the Corrosion Department has 

completed a "Pre-Operational Tank Inspection Checklist" and all outstanding items have 

been resolved. This will ensure that the new tanlc has all the appropriate documentation 

and complies with 18 AAC 75.065 before it is put into service; 

d) A record for the tank will be created in the Corrosion Department's "Tanlc Database," 

where future external and internal inspection dates will be assigned and entered. In 

addition, all records of inspection results and corrective actions will be kept for the 

service life of a tank, as required by 18 AAC 75.065(d); 

e) The new tank information will be added to the applicable plan, currently Table 2-6; 

.. '.'l., 
'' 

I 

Mr. John Whitehead 

ConocoPhillips Alaska, Inc. 

3 February 26, 2003 

f) The requirements of 18 AAC 75, as well as the above CPA procedural requirements, 

have been communicated to, and will continue to be followed by, the Wells, Drilling, 

Operations, Projects, Engineering and Procurement Organizations, or their equivalents 

should CPA reorganize, sell or otherwise re-name the organizations that make up CPA. 

g) This waiver shall be binding to CPA, its agents, successors, and assigns and upon all 

persons, contractors and consultants acting on behalf of CPA. 

This condition is reasonably necessary considering that CPA is a large company with numerous 

employees, contractors, subcontractors, agents and potential successors, who may purchase oil 

storage tanks for use in the State of Alaska at the Kuparuk or Alpine facilities. Incorporating 

_the requirements for new oil storage tanks into CPA' s internal procurement process, including 

provisions for the sale of the company or its assets, is the best way to ensure that a new Tiger or 

Open Top tank that is ordered or placed into service after May 14, 1992, will meet the 

requirements of 18 AAC 75.065(h andj), that the information regarding a tank is maintained to 

meet the requirements of 18 AAC 75.065( d), and the information. is maintained in the plan as 

required by 18AAC 75.425(e)(2)(A). 

3) These tanks are subject to all other-applicable requirements of 18 AAC 75.065 and 18 

AAC 75.075 for tank inspection, maintenance, and secondary containment requirements. 

As required by 18 AAC 75.065(h)(l), this condition is reasonably necessary to insure that any 

new oil storage tanks needed for operations at CPA facilities on the North Slope will be 

submittedfor approval prior to purchase, including "Open Top Tanks" and "Tiger Tanks" 

without the need for additional approvals for these two tank designs. 

Please be advised thatthe approval of this waiver does not relieve you of the responsibility for 

securing other state, federal or local approvals or pennits, and that you are still required to 

comply with all other applicable laws. 

If you have any questions, please contact Kirsten Ballard at 269-7541. 

cc: Kirsten Ballard, ADEC 

Sam Saengsudham, ADEC 

Sam Means, ADNR 

Al Ott, ADFG 

S. Adams, North Slope Borough 

Brad Frates, CPA 

Randy Kanady/Shellie Colegrove, CPA 

Bob Hale/Steve Geddes, CPA 

Sincerely, 

Section Manager 

Michael Erwin, Supervisor, WNS Operations, CPA 

Joseph A. Leone, CPA 

Richard P. Mott, CPA 

Tom Wellman, CPA 

DEPT. OF ENVIRONMENTAL CONSERVATION 

DIVISION OF SPILL PREVENTION AND RESPON~E 

INDUSTRY PREPAREDNESS PROGRAM 

Exploration Production & Refineries 

FRANK H. MURKOWSKI, GOVERNOR 

SSS Cordova Street 

Anchorage, AK 99S01 

PHONE: (?07) 269-3094 

FAX: (907) 269-7687 

. hq;p;//www.state.ak.us/dec 

February 14, 2003 

Mr. John Whitehead 

Alpine DeveJopment Project 

· Phillips Alaska, Inc. 

P. 0. Box 196105 

Anchorage,AK 99519-6105 

Dtpr Mr. Whitehe~: ,·, 

I 

File No.: 30S.40 

,, ,·, 

I I 

SUBIBCT: Waiver of Oil Storage Tank Comtructio~ Standards; Oil Discharge 

Prevention and Contingency Plan (''plan") for ConocoPhillips Alaska, Inc. 

(CPA) Alpine Development Pa,ticipatfug Area._ 

ADEC Plan number: 994-C4140. 

The Department of&vironmental Conservation (Department) has reviewed your September 

· 13, 2002, request for it waiver to operate severalportable oil storage tanks and two fiberglass 

tanks (listed in Table 1) that do not meet the requirements of 18 AAC_75.065(h) for a ''new 

installation." CPA recognized that these tanks did not meet the "new facility'' tank 

requirements of 18 AAC 75.065(h){l) and took immediate action to remove the tanks from_ 

service. While the initial request included approval of these tanks' construction as "another 

standard approved by the department" (Ref: 18 AAC 75.065(h)(l)), the tank records provided · 

with the initial application ·did not contain sufficient information for the Department to approve 

the current or future construction 'standard' of these tanks as meeii]J.g the intent of 18 AAC 

75.065(h)(l). . 

The Department has determined that the continued use of these tanks is permissible under the 

''test of time." These types of tanks have been in use for many years on the North Slope with 

no major problems noted due to their cpnstruction. No spills have been reported from these 

tanks since their use at-Alpine, according to Ci> A's information. In addition, recognizing that a 

standard for these types of tanks needed to be developed, .CPA agreed to develop such a 

standard as a condition of this waiver approval. The approval of those tank construction 

standards is addressed under separate correspondence. 

0 Ptinted 1m Re,:. rk..,;. 
Mr. John Whitehead 

ConocoPhillips Alaska 

2 February 14, 2003 

Based on the information supplied by CPA and discussions with CPA personnel, the 

Department is granting the waiver. CPA must include a copy of this waiver in the section of 

the plan designated as "Compliance Schedule and Waivers,,, currently Section 2.7 of the plan, 

for the duration of the service life of the subject tanks. F~cility diagrams and other information 

required by 18 AAC 75.425(e)(l-3), must also be included. · 

This waiver, including any necessary changes to the plan, must be incorporated into the plan 

renewal application currently in process prior to final distribution of the plan, when approved. 

CPA must notify the Department when any of the tanks are taken out of service or when major 

repairs are made. This waiver is ~ubject to the following conditions: 

' 1) CPA has developed an accelerated API 653 inspection schedule for the subject tanks, as 

outlined in Table 1 below to comply with 18 AAC 75.065(a). All API 653 inspections will be 

. completed l;>y May 2003. After the API 653 inspections are complete, CPA will have a 

qualified mechanical engineer, familiar with the design and construction of oil storage tanks, 

evaluate the tanks for continued service. The engineer evaluation will be completed by July 

2003 and CPA will submit to the Department the results of this evaluation by Augus~ 2003, as 

. well as the API 653 tank inspection results/reports for the subject tanks. 

Tablel 

API 653 Alpine ADEC Tank Inspections for Waived Tanks 

Existing API 653 Accelerawd API 653 

Inspection Schedule T nffl41!1'tion Schedule 

Equipment Op. . Last .Last N~ Next 

Tae: Unit Tank Name Internal External Internal External. 

CF-T-76004 ALP OPENTOP#4 5/12/2000 5/12/2000 5/2003 5/2003 

CF-T-76005 ALP OPENTOP#2 5/12/2000 5/12/2000 5/2003 · 5/2003 

450 BBL TIGER 

CF-T-76006 ALP TANK#6 N~w2000 New2000 5/2003 5/2003 

450 BBL TIGER 

CF-T-76007 ALP TANK#5 New2000 New2000 5/2003 5/2003 

300 BBL GREEN 

CF-T-76018 ALP OPENTOP ~ew 1998 New 1998 5/2003 5/2003 

HEATING FUEL I 

CF-T-76042 ALP TANK · 4/19/2001 4/19/2001 5/2003 5/2003 

CF-T-76043 ALP FUEL TANK 5/3/2001 5/3/2001 5/2003 5/2003 

CF-T-76044 ALP JET FUEL TANK 4/14/2001 4/14/2001 5/2003 5/2003 

CF-T- FIBERGLASS 

50063A ALP UPRIGHf· New 1998 New 1998 5/2003 5/2003 

CF-T- FIBERGLASS 

50063B ALP UPRIGHf New 1998 New 1998 5/2003 5/2003 
Mr. John Whitehead 

ConocoPhillips Alaska 

3 February 14, 2003 

This condition is reasonably necessary to affinn that these tanks, brought into service after 

May 14, 1992, are suitable for continued service. This inspection requirement will also ensure 

that the tanks meet all applicable requirements of an oil storage tank at an "existing 

installation," as required by 18 AAC 75.065(a, i, andj) and lBAAC 75.990(39), since they 

cannot meet the requirements of 18 AAC 75.065(h), and it would cause undue hardship to . . 

require these tanks to be pennanently taken out-ofservice. 

2) CPA will review internal tank criteria and specifications to include revisions that ensure 

new oil storage tanks regulated under 18 AAC 75 are built to the appropriate code. This 

includes the modification of the ''CPA Engineering Standards" for tank design, construction 

and placement into service to clearly define and identify the new oil storage tank construction 

requirements of 18 AAC 75.065 for CPA procurement processes. The changes to the CPA 

Engineering Standards and acceptance protocols will be communicated to CPA 

Operations/Drilling/Wells management to be included when CPA procures new oil storage 

tanks. 

., 

This condition is reasonably necessary corlsidering that CPA is a large company with 

numerous employees who may purchase oil storage tanks for use in the State of Alaska. 

Incorporating the requirements for new oil storage tanks into CPA' s internal procurement 

process is the best way to ensure that any new oil storage tanks that CPA orders or places into 

service after May 14, 1992, will meet the requirements of 18 AAC 75.065(h and j). · 

3) Future oil storage tanks that cannotbe built to the 18 AAC 75 standards will be 

submitted to the Department for approval prior to design, purchase or placement into service. 

To facilitate this effort, CPA Engineering has worked with ADEC to develop standardized 

portable tank designs for "Open Top" and "Tiger Tank" styles for use in Alaska by CPA 

facilities on the North Slope. Regulatory approvals will be obtained prior to the start of 

construction of any other types of tanks for which there are no construction standards. Included 

in this effort is a new "Tank Acceptance Protocol," included in the project file, whereby the 

"CPA Corrosion Group" will verify that new oil storage tanks are in compliance with 18 AAC 

75 prior to being placed in service. The parties have agreed that this will take the form of a 

tank pre-commissioning checklist, which will be included in the Department's approval of the 

alternative tank standards for the Open Top and Tiger tanks. In addition, the protocols, 

· engineering standards and tank pre-commissioning checklist will be included in the Greater 

Kuparuk Area (GKA) Startup Status Checklist for the use of new storage tanks. 

As required by 18 AAC 75.065(h)( 1 ), this condition is reasonably necessary to insure that any 

new oil storage tanks needed for operations at CPAfacilities on the North Slope will be 

submitted for approval prior to purchase, and, to include approved tank designs for two types 

of oil storage tanks, known as the "Open Top Tank" and Tiger Tank for use without additional 

approval of these particular tank designs. 

Please be advised. that the approval of this waiver does not relieve you of the responsibility for 

securing other state, federal or local approvals or permits, and that you are still required to 

comply with all other applicable laws. 
Mr. Whitehead 

ConocoPhillips Alaska 

4 

If you have any questions, please contact Kirsten Ballard at (907) 269-7541. 

cc: Kirsten Ballard, ADEC 

Sam Means, ADNR 

AIOtt,ADFG . I 

S. Adams, North Slope Borough 

Brad Frates, CPA 

Randy Kanady/Shellie Colegrove, CPA 

Bob Hale/Steve Geddes, CPA 

Sincerely, 

Lydia Miner 

Section Manager 

Michael Erwin, Supervisor, WNS Operations, CPA 

February 14, 2003 
Appendices  Final Supplemental Environmental Impact Statement

Alpine Satellite Development Plan for the Proposed Greater Mooses Tooth 2 Development Project

APPENDIX Q

POTENTIAL MITIGATION MEASURES BEING 

CONSIDERED FOR ADOPTION IN GMT2 ROD
APPENDIX Q: GMT2 PROPOSED MITIGATION 

MEASURES

The BLM held a 55 day public comment period after publication of the GMT2 Draft Supplemental EIS. 

BLM solicited comments from interested members of the public on potential new mitigation measures 

that could further avoid, minimize or compensate for the expected impacts of the GMT2 Project. BLM 

held 6 public meetings in Anaktuvuk Pass, Anchorage, Atqasuk, Fairbanks, Nuiqsut and Utqiagvik, and 

all potential new mitigation measures that met the guidelines for reasonableness outlined in the BLM’s 

NEPA Handbook were included in the Final Supplemental EIS for possible inclusion in the Record of 

Decision (ROD). Mitigation measures proposed by BLM subject matter experts during production of the 

Draft or Final Supplemental EIS, as well as mitigation measures proposed by cooperating agencies and 

tribal entities during consultation were also included for consideration. 

Current BLM Mitigation Guidance

The mitigation measures adopted in the GMT2 ROD must meet the current guidance for mitigation 

outlined in the BLM NEPA Handbook, Instruction Memorandums and the NPR-A Regional Mitigation 

Strategy. Relevant text from the BLM NEPA Handbook is below: 

Mitigation includes specific means, measures or practices that would reduce or eliminate 

effects of the proposed action or alternatives. Mitigation measures can be applied to 

reduce or eliminate adverse effects to biological, physical, or socioeconomic resources... 

and may be used to reduce or avoid adverse impacts, whether or not they are significant 

in nature. Measures or practices should only be termed mitigation measures if they have 

not been incorporated into the proposed action or alternatives. If mitigation measures 

are incorporated into the proposed action or alternatives, they are called design features, 

not mitigation measures. Monitoring is required to ensure the implementation of these 

measures (40 CFR 1505.2(c)) (see section 10.1, Purposes of and Requirements for 

Monitoring). 

In an EIS, all “relevant, reasonable mitigation measures that could improve the project 

are to be identified,” even if they are outside the jurisdiction of the agency (see Question 

19b, CEQ, Forty Most Asked Questions Concerning CEQ's NEPA Regulations, March 

23, 1981). 

In addition to the BLM NEPA Handbook, the BLM has recently issued guidance on compensatory 

mitigation in BLM Instruction Memorandum 2018-093, Compensatory Mitigation, published July 24, 

2018. Several mitigation measures were proposed by members of the public that meet the definition of 

compensatory mitigation. Instruction Memorandum 2018-093 precludes the adoption of these mitigation 

measures in the GMT2 ROD; however, BLM has included them in the Final Supplemental EIS to 

acknowledge stakeholder comments and to encourage consideration of these mitigation measures through 

other programs such as the State of Alaska’s NPR-A Impact Mitigation Fund. 
Northeast NPR-A Regional Mitigation Strategy

The ROD for the GMT1 Project directed the BLM to prepare a Regional Mitigation Strategy (RMS) that 

would “serve as a roadmap for mitigating impacts from GMT1 and future projects enabled or assisted by 

the existence of GMT1.” The RMS will help the BLM manage the NPR-A in a manner consistent with 

public law, and to fulfill the requirements of the National Environmental Policy Act (NEPA). The overall 

goal of the NPR-A RMS is to facilitate the expeditious development of oil and gas resources, while 

mitigating reasonably foreseeable and significantly adverse effects on the surface resources of the NPRA. The RMS describes current and potential future mitigation actions or opportunities that should be 

considered when approving an application for development. The GMT2 ROD will identify mitigation 

measures that incorporate recommendations made in the RMS. 

Potential Mitigation Measures Being Considered for Adoption 

in the GMT2 Record of Decision 

Below is a list of all the potential new mitigation measures that were identified in the GMT2 Final 

Supplemental EIS. 

Proposed New Mitigation Measures for Soils and Permafrost

Potential Mitigation Measure 1: Alaska Natural Resources Conservation Service Level II 

Soil Survey 

Objective: Establish baseline conditions of soils within 1,000-meter radius of all planned gravel 

infrastructure. This may be accomplished within the first year after the start of construction.

Requirement/Standard: The permittee shall conduct a soil survey that meets the requirements of the 

Alaska Natural Resources Conservation Service Level II soil survey (including ecological site 

description). The soil survey will extend for a 1,000-meter radius from all planned gravel infrastructure 

and will be accomplished prior to construction activities. 

Potential Benefits and Residual/Unavoidable Impacts: Establishing baseline conditions will allow the 

BLM to monitor changes to the soil profile and vegetation as a result of airborne soil movement resulting 

from industrial activity. Addition of loess material will affect albedo resulting in increased active layer 

depth. It may also affect the vegetative community composition over time. This data will help delineate 

changes based on development activities from general change from warming temperatures. The data will 

help improve future engineering, design and permitting decisions thus mitigating future impacts. 

Proposed Mitigation for Air Quality 

Best management practices and best available control technology will be implemented by ConocoPhillips 

for GMT2 construction, drilling, and routine operations in order to reduce project-related emissions and 

therefore impacts on the GMT2 Project area. Below are a list of potential mitigation measures that are 

proven emission reduction strategies and technologies that will be evaluated by BLM for adoption in its 

Record of Decision. 

Potential Mitigation Measure 1 — Warm Building for vehicle storage 

Objective: Reduce air quality impacts from idling vehicles
Requirement/Standard: Construct building with sufficient size and capacity to heat vehicles to reduce 

the amount of idling vehicles. 

Potential Benefits and Residual/Unavoidable Impacts: Actions taken to minimize impacts to air 

quality will assist with minimizing impacts to overall human health by reducing the potential sources of 

exposure that local residents may experience. Could reduce emissions by reducing numbers of idling 

vehicles. Would add to the footprint of the development, potentially increasing construction emissions. 

May concentrate emissions from numerous vehicles in a single area that would otherwise be distributed 

by moving vehicles throughout the project area.

Potential Mitigation Measure 2—Minimize methane waste 

Objective: Reduce air emissions of methane and protect human health and the environment.

Requirement/Standard: Measurement and reporting of all natural gas waste from venting, flaring and 

leaks. A methane waste capture plan would be developed and submitted with the APD. Also, 

ConocoPhillips would implement a leak detection and repair (LDAR) program in order to conduct 

preventative maintenance. Using either a Method 21 instrument such as a photo ionization detector or 

flame ionization detector or an optical gas imaging instrument such as a FLIR camera, inspections shall 

be conducted on a regular schedule to identify leaks and the need for repairs. As an additional measure of 

preventative maintenance, there should also be regular auditory, visual, and olfactory inspections. 

Potential Benefits and Residual/Unavoidable Impacts: These preventative maintenance procedures 

will reduce the potential for hydrocarbon emissions such as VOC, hazardous air pollutants, and CH4. 

These measures might also prevent or lessen the impacts of a potentially significant major unintentional 

release of material. This measure would also improve worker safety through reduction of accidental 

releases. The proponent would incur financial and man-power costs due to purchase of capital assets and 

necessary on-going labor to conduct this program. 

As of this writing, it is not known how BLM’s 2016 Methane Waste Prevention Rule might impact this 

mitigation measure due to on-going litigation.

Potential Mitigation Measure 3—Use of Alternative Fuels (new subparagraph to BMP A10)

Objective: Prevent unnecessary or undue degradation of the lands and protect health and ensure 

effectiveness of previously required mitigation measures. 

Requirement/Standard: To the extent practicable, all oil and gas operations (vehicles and equipment) 

must be powered by natural gas or electric power rather than diesel fuel. To the extent natural gas and 

electric power are not practicable, the permittee will use gasoline rather than diesel to the extent 

practicable. Any vehicles and equipment that require diesel fuel must use ULSD as defined by the Alaska 

Department of Conservation, Division of Air Quality. ConocoPhillips will provide an annual report 

beginning one year after the ROD date to BLM Arctic District Office and BLM Alaska State Office Air 

Program lead reporting their use of and feasibility of natural gas, electric and gasoline powered 

equipment. 

Potential Benefits and Residual/Unavoidable Impacts: Natural gas has fewer impurities, is less 

chemically complex, and generally results in less pollution when combusted than diesel fuel. In most 

applications, using natural gas produces less CO2, SO2, and particulate matter, than diesel fuel, resulting 

in reduced health risks from fuel combustion in equipment associated with oil and gas operations. 
Natural gas is an available fuel for stationary combustion sources on the North Slope; however, vehicle 

fueling with natural gas may not be currently feasible due to a lack of infrastructure and availability of 

appropriate vehicles. Where use of natural gas is not practicable, use of gasoline generally results in less 

pollution when combusted than diesel fuel. Use of natural gas-generated electric power to operate GMT1 

sources, rather than diesel-fired electric power generation, is environmentally beneficial. Reporting 

requirements will allow BLM to evaluate the effectiveness of this mitigation measure. 

Potential Mitigation Measure 4—Implementation of Air Quality Monitoring Data Review

(new subparagraph to BMP A-10)

Objective: Provide BLM oversight and technical review of air quality monitoring near the GMT2 

project; address concerns in the local community regarding oversight of air quality.

Requirement/Standard: As part of the GMT1 ROD, permittee is required to provide funding for 

monitoring to identify and address concerns related to air quality in the Nuiqsut area. Reports from the 

monitoring station in Nuiqsut are required to be provided to BLM, the State, NSB, and the local 

community and tribal government pursuant to BMP A-10(h). The permittee is required to provide funding 

for BLM technical review of these documents, via an ongoing cost reimbursement agreement. BLM may 

elect to have a contractor or another agency perform the technical review. Permittee will begin providing 

quarterly monitoring reports beginning at the end of the first quarter of calendar year 2019. The format 

and exact content of the reports as well as the cost reimbursement agreement will be negotiated with 

permittee by January 30, 2019. 

Potential Benefits and Residual/Unavoidable Impacts: Members of the public have expressed concern 

over air quality in the project vicinity. Providing for a technical BLM review of the monitoring results 

provides certainty for BLM and the community that air quality is being carefully considered and will help 

identify any potential project-related impacts that would cause exceedances of NAAQS, or fail to protect 

public health. 

Potential Mitigation Measure 5— Electrification 

Objective: To the extent possible, power on-site combustion sources with electricity rather than fossil 

fuels.

Requirement/Standard: Under all GMT2 Alternatives, it is expected that grid power will be available 

for electric support at the GMT2 drill pad. The onsite pad generator is expected to be used for emergency 

purposes only when grid power is not available. Power lines will be installed between GMT2 and nearby 

power generation facilities and should be relied upon in place of fossil-fuel combustion equipment. 

Potential Benefits and Residual/Unavoidable Impacts: Will reduce on-site emissions from combustion 

sources. There will be some combustion sources that cannot be electrified, so there will be some residual 

combustion source emissions. May increase emissions from the source generating electricity for the site.

Potential Mitigation Measure 6—Require Near Real Time Monitoring to Prevent Excess 

Emissions of Regulated Air Pollutants 

Objective: Protect human health and the environment. 

Requirement/Standard: To get real-time and site-specific data, ConocoPhillips should implement a 

telemetry monitoring system to provide effective management of production exceptions, while reducing 

the number of vehicle trips and miles traveled. In addition to the current ConocoPhillips-operated Nuiqsut 
Monitoring Station, other monitoring systems should include supervisory control and data acquisition to 

monitor for malfunctioning equipment and production exceptions. 

Potential Benefits and Residual/Unavoidable Impacts: These types of continuous monitoring systems 

would reduce the need for regular site inspections, reducing onsite truck traffic, and would alert field 

personnel of emission exception events in real-time therefore reducing emissions to the atmosphere that 

otherwise would have gone unnoticed. 

Potential Mitigation Measure 7—Air Quality Monitoring 

Objective: Increase air quality monitoring to better determine actual impacts from development 

Requirement/Standard: Due to the concern over ambient air in the GMT2 Project area and near 

Nuiqsut, and in line with the NPR-A Final Record of Decision BMP A-10 (BLM 2013a) to reduce 

unnecessary and undue degradation of the land and protect health, additional air quality monitoring will 

be required at the GMT2 pad. Permittee will begin air quality monitoring beginning after pad and road 

construction but before additional development (assumed to begin in January 2020). Permittee will set up 

the monitoring station as a telemetry monitoring system and will provide annual reports to BLM on air 

quality monitoring results. Data and reports will be provided through the end of the drilling phase of the 

GMT2 Project. Permittee should consider using a mobile air quality monitoring system similar to the 

BLM Wyoming Air Resource Monitoring System. 

Potential Benefits and Residual/Unavoidable Impacts: There is very little ambient air quality 

monitoring data currently on the North Slope and in the vicinity of recent development. A telemetry 

monitoring system will allow permittee to take actions to reduce emissions in the event of an emissions 

exception, as well as provide BLM land managers useful air quality data to evaluate air strategy 

effectiveness. A mobile station will allow the permittee to move the air quality monitoring system to new 

developments as they are permitted. 

Potential Mitigation Measure 8—Use of Tier 4 Engines 

Objective: Reduce air quality impacts from diesel engines

Requirement/Standard: When possible, the use of Tier 4 diesel engines instead of Tier 2 or Tier 3 

engines should be operated in the field for drill rigs, completion rigs, generators, and other diesel-fired 

engines. For the emission inventories for Alternative A, B, and C, Tier 2 standards were assumed for all 

diesel-fired engines except for the routine operations emergency generator which was noted by 

ConocoPhillips to be a Tier 4 unit. 

Potential Benefits and Residual/Unavoidable Impacts: Tier 4 engines have lower emission 

standards for NOx and PM, therefore resulting in less impacts from those pollutants. Impacts to air 

quality related values (AQRVs; visibility and atmospheric deposition) at Federal Class II areas could also 

be reduced. 

Potential Mitigation Measure 9—Selective and non-selective catalytic reduction devices: 

Objective: Reduce emissions from combustion sources

Requirement/Standard: For engines, heaters, and other combustion devices, selective and nonselective catalytic reduction devices should be used to reduce criteria and hazardous air pollutant 

emissions such as NOx, CO, VOC, and formaldehyde, when feasible. Some selective catalytic reduction 
devices inject ammonia into the exhaust to reduce NOx emissions; however, these types of devices should 

be avoided to prevent ammonia emissions.

Potential Benefits and Residual/Unavoidable Impacts: A reduction in combustion source emissions 

would result, commensurate with the number of devices that can be used. Impacts to local air quality 

would decrease as well as impacts to air quality and AQRVs at Federal Class II areas.

Potential Mitigation Measure 10—Flaring or closed-loop systems 

Objective: Reduce greenhouse gas emissions 

Requirement/Standard: CH4, a greenhouse gas, is the primary constituent of natural gas. Instead of 

venting natural gas during hydraulic fracturing or pigging operations, flaring will reduce VOC, hazardous 

air pollutant, and CH4 emissions. 

Potential Benefits and Residual/Unavoidable Impacts: Combustion emissions from flaring, in 

result, increase pollutant levels of NOx, CO, and CO2. Overall greenhouse gas impacts would go down 

since the global warming potential of CH4 is 25 times greater than CO2. The hydrocarbon destruction 

efficiency of most flares is upwards of 95 percent. Also, a closed-loop system with 100 percent capture by 

re-routing gas from hydraulic fracturing or pigging operations to a sales line or onsite process results in 

no additional emissions to the atmosphere.

Potential Mitigation Measure 11—Use of no-bleed or low-bleed pneumatic devices 

Objective: Reduce hydrocarbon emissions

Requirement/Standard: In place of high-bleed or intermittent-bleed pneumatic devices for pressure, 

temperature, or liquid level control, no-bleed and low-bleed pneumatic devices should be installed, if 

feasible.

Potential Benefits and Residual/Unavoidable Impacts: No-bleed and low-bleed pneumatic devices will 

reduce hydrocarbon emissions, such as those of VOC, hazardous air pollutant, and CH4 pollutants. Lowbleed pneumatic devices are classified as those with a bleed rate less than 6 standard cubic feet per hour 

(scfh). No-bleed pneumatic devices are those that are mechanically driven or solar-powered instead of 

powered by natural gas.

Proposed New Mitigation for Vegetation and Wetlands

Potential Mitigation Measure 1-- Reclamation of Wetlands, Natural Soils and Vegetation

Objective: Ensure project infrastructure is dismantled when no longer in use to promote reclamation of 

wetlands, soils and vegetation.

Requirement/Standard: When wells and facilities have met their useful life and are to be abandoned, 

recommendations found in the reclamation plan will be applied whenever feasible. Any planned 

reclamation goals will be in consultation with the local community, tribal government, and interested 

stakeholders.

Potential Benefits and Residual/Unavoidable Impacts: Reclamation can begin after the following two 

conditions are met: 1) the operator determines that a portion of a developed site will no longer be used for 

oil and gas operations and 2) BLM determines that environmental conditions are favorable for the 
replacement and reestablishment of natural soils and vegetation. Returning vegetation and wetlands to a 

more natural state after removing gravel roads and pads will contribute to the long-term rehabilitation of 

the region. The permittee will report to the BLM on the latest research and methods related to reclamation 

of oil and gas infrastructure and roads in the arctic every 2 years. Abandonment and reclamation activities 

within the NPR-A are governed by 43 CFR Part 3160, subpart 3162, which requires lessees to reclaim the 

land in accordance with plans approved by the BLM (43 CFR 3162.3-4 and 3162.5-1). 

Proposed New Mitigation Measure for Fish

Potential Mitigation Measure 1—Ensure Compliance with BMP E-6 

Objective: Ensure that water flowing out of Lake M9925 and moving toward Blackfish Creek is not 

impeded by the road and that upstream fish passage by ninespine stickleback is possible, in accordance 

with requirements laid out in BMP E-6. 

Requirement/Standard: Two weeks before placing culverts, submit to BLM the technical drawings for 

this area that show the planned placement of culverts as well as the road line and culvert points overlain 

on high-resolution imagery in GIS. 

Potential Benefits and Residual/Unavoidable Impacts: This additional measure will enable the BLM to 

further evaluate pre-construction plans in an effort to increase the likelihood that the objective of BMP E6 is met. 

Proposed New Mitigation Measures for Birds

Potential Mitigation Measure 1: Roadkill Monitoring System for Birds and Wildlife 

Objective: Implement a reporting system to monitor roadkill of birds and other wildlife on transportation 

routes.

Requirement/Standard: The permittee shall provide an annual report to the Authorized Officer reporting 

roadkill of birds and mammals to help the BLM determine whether additional preventative measures on 

vehicle collisions should be made.

Potential Benefits and Residual/Unavoidable Impacts: Knowledge about bird and mammal mortality 

due to vehicle traffic will help managers to develop methods to reduce collision rates with vehicles.

Potential Mitigation Measure 2: Directional Facility Lighting 

Objective: To prevent episodic bird collisions with infrastructure, especially during migration and 

inclement weather.

Requirement/Standard: . 

All facility external lighting, during all months of the year, shall be designed to direct artificial exterior 

lighting inward and downward or be fitted with shields to reduce reflectivity in clouds and fog conditions, 

unless otherwise required by the Federal Aviation Administration. 

Potential Benefits and Residual/Unavoidable Impacts: (see public comment)
Best Management Practice E-10 contained in the 2013 NPR-A IAP ROD contains very similar language 

to this proposed mitigation measure with that exception that E-10 is in effect between August 1 and 

October 31 only. In their comments the USFWS pointed out that “Lighted facilities (drill rigs and 

buildings) can cause episodic bird collisions with infrastructure, especially during migration and 

inclement weather” which is why this new mitigation measure removes the timing limitations and extends 

the BMP to being applicable year round. The benefit for including this new mitigation measure is to 

mitigate the collision risk to birds year round.

Potential Mitigation Measure 3: Gravel Pit Rehabilitation

Objective: To prevent subsidence within gravel excavation pits and improve site rehabilitation for the 

benefit of nesting waterfowl. 

Requirement/Standard: A 3:1 side slope and perimeter berm during excavation on the ASRC pit. Once 

the pit fills with water, the perimeter berm shall be pushed into the pit. 

Potential Benefits and Residual/Unavoidable Impacts: (see public comment) 

The DSEIS indicates the new cells mined for the GMT2 development will be rehabilitated as a matrix of 

undisturbed tundra, deep water, shallow, and very shallow littoral, and waterfowl nesting islands. The 

previous rehabilitation efforts of Phase 1, mined in the late 1990s and early 2000s, to create similar 

habitats as described above have failed. The latest photo (2017) shows an approximately 95% reduction in 

the overburden islands and continued subsidence of the channel cut islands and complete subsidence of 

the littoral shelf to the north. In order to avoid repeating previous failures Phase 3 of the ASRC pit be 

mined without the intention of creating shallow habitats. Best Management Practices (BMPs) should be 

used during excavation (3:1 side slopes and a perimeter berm to prevent thermokarsting and for safety.) 

Once the pit fills with water the perimeter berm can be pushed into the pit creating the desired matrix of 

habitats. 

Proposed New Mitigation Measures for Mammals

Potential Mitigation Measure 1: Roadkill Monitoring System for Birds and Wildlife 

Objective: Implement a reporting system to monitor roadkill of birds and other wildlife on transportation 

routes.

Requirement/Standard: The permittee shall provide an annual report to the Authorized Officer reporting 

roadkill of birds and mammals to help the BLM determine whether additional preventative measures on 

vehicle collisions should be made.

Potential Benefits and Residual/Unavoidable Impacts: Knowledge about bird and mammal mortality 

due to vehicle traffic will help managers to develop methods to reduce collision rates with vehicles.

Potential Mitigation Measure 2: (Adapted from BMP K-5.e.1 and 2): Minimize Potential 

Ground Vehicle Traffic Disturbance of Caribou

Objective: Minimize disturbance and hindrance of caribou, or alteration of caribou movements, by 

vehicle traffic on the GMT1-GMT2 gravel road during the oestrid fly-relief and fall-migration seasons.

Requirement/Standard: The following ground vehicle traffic restrictions shall apply to permitted 

activities using the GMT1-GMT2 road in the time periods indicated: 
1. Along the GMT1-GMT2 road, from July 16 through November 30, traffic speed shall not exceed 

15 miles per hour when caribou are within 0.5 mile of the road. If caribou are observed regularly 

within 0.5 miles of the road (i.e. observed daily for 3 or more consecutive days) then additional 

strategies would be implemented including restricting vehicle traffic or requiring vehicles to 

travel in convoys. 

2. The permittee or a contractor shall observe caribou movement from July 16 through November 

30 to assess whether or not caribou may be trying to cross the road. Based on the assessment, 

traffic will be stopped temporarily if it is determined that caribou are trying to cross the road. Any 

individual or group of caribou moving steadily toward the road within a distance of 0.25 miles 

(approximately 400 meters) should be considered attempting to cross the road. Sections of road 

will be closed to vehicle traffic whenever an attempted crossing by 100 caribou or more appears 

to be imminent.

3. The permittee shall submit, prior to road construction, a vehicle use plan that considers these and 

any other appropriate mitigation measures. Adjustments will be required by the Authorized 

Officer if resulting disturbance is determined to be unacceptable.

4. The permittee will consult with the Authorized Officer annually to determine if the seasonal 

restrictions, and restrictions described in paragraphs 1 and 2 above are still appropriate given 

possible changes in migration patterns. In light of ongoing caribou monitoring, the Authorized 

Officer may modify the restrictions as appropriate to achieve the objectives of this measure.

Potential Benefits and Residual/Unavoidable Impacts: Limiting vehicle traffic during caribou 

migration will help reduce impacts and disturbance to caribou. Unavoidable impacts would continue due 

to the presence of the road and continued traffic. 

Proposed New Mitigation Measures for Sociocultural Systems

Through the consultation process, local entities and residents have already suggested numerous potential 

benefits to the community that they believe could begin to offset the negative impacts to their way of life. 

Although the BLM lacks the authority to require implementation of these measures, many of which could 

be considered social services, they are presented here. 

Locally Requested Mitigation Measures

Through the consultation process, local entities and residents have suggested numerous potential benefits 

to the community that they believe could begin to offset the negative impacts to their way of life. 

Although the BLM lacks the authority to require implementation of these measures, many of which could 

be considered social services, they are presented here. 

Heritage Center in Nuiqsut

When asked what could offset the sociocultural impacts Nuiqsut would experience with development of 

GMT1, several residents articulated the need for a local heritage center and a place for youth sports and 

activities. This mitigation measure would address the fact that the community of Nuiqsut’s community 

center is no longer an ideal location for social events due to the regular development-related meetings that 

are held there, and would be a place where the community could meet, pass on traditional knowledge, and 

actively participate in cultural activities.
Support Cultural and Educational Projects

Support projects that document, teach, and protect culture, history, and language, such as: establishing a 

library with a focus on Iñupiat culture that is open year-round; establishing a community-based 

photojournalism/media institute, build recreation centers, teen centers, playgrounds, and/or picnic areas. 

Provide Administrative and Technical Support

Assist communities in communicating with levels of government to get issues of concern addressed, such 

as hiring permanent grant writers to submit proposals for impacts mitigation and other grants and to 

produce grant requests, and assist local entities with obtaining technical and legal expertise to advise them 

on the permitting process. 

Nuiqsut Drug Rehabilitation Program

The 2005 Nuiqsut Village Profile, based on data compiled during a comprehensive survey of every North 

Slope Borough household, noted this issue as a community priority: “Social services – A rehabilitation 

program, with certified counselors, is needed in the community” (URS Corporation 2005). The lack of 

local counseling and drug rehabilitation programs is understood by some locals as preventing local 

employment in the oil field. 

Provide Educational Support

 Assist with the implementation/expansion of Science Technology Engineering Math programs within 

local schools, such as the Alaska Native Science and Engineering Program in impacted communities. 

Support the development and implementation of job training programs in North Slope communities, 

including local oversight/monitoring of development activities (e.g., staff, training, funding to contract for 

technical and scientific expertise).

The NSB suggests that industry could fund a local science center that could be associated with one of the 

suggested buildings. The Borough reports great success despite minimal local resources conducting 

science within NSB communities, typically with the assistance and support of local hunters and the 

participation of local residents. With a dedicated facility containing basic equipment, industry could 

support occasional important scientific research in Nuiqsut with the support and participation of local 

residents. 

Provide Economic and Community Development Opportunities

Develop and implement programs that support local entrepreneurial and economic development in 

impacted communities. Fund the development of long-term community development plans for impacted 

communities. Build new housing to meet growing demand in impacted communities. 

Residents have noted that many past workforce development efforts have been geared exclusively 

towards oil industry jobs, while the majority of the jobs available on the North Slope are no longer for 

industry (or that industry jobs are not feasible for parents or caregivers who must stay in town). The 

concern is that everyone who is qualified for a job in industry is quickly hired and relocated to 

Anchorage. The suggestion is that workforce development efforts should refocus to support preparation 

for those jobs that are available in the communities, primarily teachers and nurses. 

Establish a BLM Field Office in Nuiqsut

Local residents have not only requested that an office be established by the BLM in the community of 

Nuiqsut, but that it be staffed by a local who is charged with inspection and enforcement authority on 

behalf of the federal government. By having an office in Nuiqsut, local residents would be able to more 
easily receive timely information and answers to questions, and report issues, local concerns and 

violations to stipulations or best management practices. 

Postpone Approval of Development Projects until Impacts are Understood 

Several local residents and entities expressed frustration regarding the hypothetical nature of how 

potential impacts are described within the Draft EIS. They have requested the USDOI and BLM 

postpone approving the GMT2 application, and future development applications, for a period of 5 years. 

The purpose of the postponement is to allow for local residents to experience the presence of GMT1, and 

for BLM and other entities to collect concrete data regarding resource displacement and other potential 

impacts, access enhancers and barriers, and other potential changes that will result from new the new 

development. This data could then contribute to a NEPA analysis that is based on data regarding the 

impacts and benefits that have occurred from a similarly designed and constructed development.

Search and Rescue Assistance

Local residents of Nuiqsut have expressed concern regarding the ability of current Search and Rescue 

capabilities within the community given that local hunters are traveling farther away to harvest resources, 

leading to safety concerns both in terms of increased potential for local residents to need assistance, and 

increased capacity for Search and Rescue response. Specific Requests include:

• Upgrades for Search and Rescue Equipment 

• Upgrades for Search and Rescue communications, radio and satellite 

• Additional training for Search and Rescue Responders 

Potential Mitigation Measure #1: Nuiqsut Area Environmental Information Dissemination

Objective: Make data and summary reports derived from local studies available locally. 

Requirements/Standard: The permittee will create a simple, user-friendly website where data, studies, 

reports, and research summaries associated with required monitoring studies are maintained and made 

accessible. These documents will be made accessible via the website within 2 months of finalization. 

The website should not require the creation of accounts or passwords or restrictions on access of any kind. 

When new documents are added to the website, the permittee will notify residents and the BLM by email 

and by posts to any industry-maintained social media accounts (i.e., the Nuisagmiut Facebook group). 

The permittee will also print copies of summary reports and distribute them to Nuiqsut entities (including, 

but not restricted to, Trapper School, KSOP, Kuukpik, NVN, and City of Nuiqsut). 

At a minimum, the website and notification system will include all data and reports related to required 

monitoring studies that pertain to the environment within 50 miles of Nuiqsut on BLM-managed land. 

The permittee is encouraged to make other (non-industry contracted) research on the same area accessible 

in the same manner. 

Potential Benefits and Residual/Unavoidable Impacts: Much of the data that is used by federal 

agencies conducting NEPA analyses is either information derived from studies and research paid for by 

the applicant, or conducted by agencies (i.e., federal, state and local government entities). There is no 

systematic way that residents can review these studies. In addition, residents have stated that many of the 

reports that present the data or study results are too complicated, and not effective at communicating 

important information that they need to be able to assist with the NEPA process. This contributes to a 

pervasive belief among local residents that much of this data is compromised, in that the entities who paid 
for or collected the information have a vested interest in manipulating the data in some way (i.e., 

downplaying, minimizing, or increasing results; sabotaging accurate data collection; or summarizing 

information in non-meaningful ways). These conflict of interest concerns could be mitigated, in part, by 

the new methodology and peer review requirements established by Potential Subsistence Mitigation 

Measure 8 (section 4.4.5.6) and this Nuiqsut Area Environmental Information Dissemination measure 

would mitigate confusion over which studies are being conducted and what the findings are. 

Although not a part of the BLM requirement/standard, local entities have requested support to engage 

their own contractor who would be responsible for working with local entities and the school to 

disseminate information on the studies and to prepare research summaries that effectively communicate 

research and data in a manner that is understood by residents. 

Proposed New Mitigation Measures for Subsistence

In addition to the lease stipulations and best management practices that apply to all oil and gas activities 

in the NPR-A established by the NPR-A Integrated Activity Plan/EIS (BLM 2013), an extensive set of 

subsistence mitigation measures for the GMT1 project was established with the 2015 GMT1 Record of 

Decision. Similar mitigation measures are proposed for GMT2 and additional potential mitigation 

measures have been developed through consultation with stakeholders or proposed via input on the Draft 

SEIS for GMT2. 

Potential Mitigation Measure 1: GMT2 Road Right of Access Agreement 

Objective: Ensure that residents will have the right to use the GMT2 Access Road throughout the life of 

the project and ensure that residents are aware of the policies regarding use of project-associated roads for 

subsistence activities to reduce misunderstandings and ensure the safety of project workers and local 

residents using the roads. 

Requirement/Standard: The permittee will produce a clear and legally binding right of access 

agreement that will provide the community of Nuiqsut with concise policies regarding use of the roads 

associated with the project and hunting prohibitions, if any, along the roads and near project components. 

Permittee will insure that this agreement is disseminated throughout the community. The permittee will 

also include a presentation on the agreement in its employee orientation, will ensure that sub-contractors 

have the agreement for their employee orientation, and will post the agreement on the road itself. The 

agreement should also be provided to BLM for their records. 

Potential Benefits and Residual/Unavoidable Impacts: Clear policies regarding use of project roads 

for subsistence activities will likely reduce misunderstandings about whether and to what extent local 

harvesters can use and/or hunt from the road. Residents will be more likely to use project roads if they are 

well informed about company policies and security restrictions. 

Potential Mitigation Measure 2: Suspend Non-essential Helicopter Traffic during Peak 

Caribou Hunting Season

Objective: To reduce the impacts of helicopter traffic on Nuiqsut caribou hunters.

Requirement/Standard: Via ongoing consultation with the City of Nuiqsut, the North Slope Borough 

Department of Planning, Native Village of Nuiqsut, Kuukpik Corporation, and the Kuukpik Subsistence 

Oversight Panel, Inc., the BLM will establish an approximately 1-month-long period during peak caribou 

hunting when non-essential helicopter flights will be suspended within a predetermined distance of rivers 

that have been documented as caribou subsistence use areas, or limit helicopter traffic during this time to 
established flyways. The consultation results should be documented, distributed to BLM and other 

stakeholders, and clearly identify actions to be implemented based on the consultation. 

• Ongoing (multi-year, already planned) scientific/environmental studies that depend on access to 

study sites that are already planned could continue if there is no alternative access to sites.

• Suspension dates can be revised every 3 years upon review of peak caribou season.

Potential Benefits and Residual/Unavoidable Impacts: Reducing helicopter traffic or limiting the 

geographic area affected by helicopter traffic would reduce the incidence of conflicts between GMT2-

related helicopter traffic and Nuiqsut subsistence activities. However, other operators on the North Slope 

may continue to fly during the suspension period. 

Potential Mitigation Measure 3: Consultation Regarding Aircraft Communication 

Protocols

Objective: Ensure that current communication protocols related to helicopter and fixed-wing air traffic 

by the permittee are adequate in addressing Nuiqsut concerns about the impacts of air traffic on their 

hunting activities. 

Requirement/Standard: In consultation with local hunters and local organizations, the permittee will 

continue to facilitate, improve, and expand communication protocols to inform subsistence users of daily 

flight patterns and identify potential conflict areas during peak hunting times. This consultation should 

include efforts to advertise these communication protocols within the community so that Nuiqsut 

subsistence harvesters are aware of them and confirmation that existing minimum altitude requirements 

are adequate. The consultation results should be documented, distributed to BLM and other stakeholders, 

and clearly identify actions to be implemented based on the consultation. 

Potential Benefits and Residual/Unavoidable Impacts: Strong communication protocols with the 

community of Nuiqsut regarding the timing, altitude, and location of air traffic should reduce the 

frequency of these impacts on subsistence users. However, such protocols will not remove impacts of air 

traffic altogether.

Potential Mitigation Measure 4: Aircraft Monitoring Data Requirements

Objective: Monitor aircraft patterns and the impacts of aircraft associated with the GMT2 Project on 

subsistence hunting activities in the project area.

Requirement/Standard: Permittee will be responsible for funding and providing data to BLM for a 

monitoring study of aircraft flight patterns and impacts related to aircraft traffic on subsistence activities. 

The permittee will provide the BLM with data from the monitoring study in a manner that facilitates 

meaningful analysis of activities and impacts.

The permittee will provide BLM with clear and detailed quarterly flight reports that include the timing, 

flight path, and purpose of each flight in the project area. 

The reports will highlight all flights that represent deviations from BLM’s best management practices and 

include explanations for any deviations. 

The permittee will provide data related to altitude of flights patterns. Noise data associated with altitudes 

will be cross-referenced to determine minimum altitudes for flights in the project area, to reduce impacts 

on wildlife and subsistence activities.
The aircraft monitoring plan will differentiate to the greatest degree practicable between the various 

purposes of flights (i.e., flights that are conducted for exploratory drilling operations, offshore pipeline 

baseline studies, and other scientific research broken down by species and researcher).

Reports will include statistical analyses on flight patterns, including how often actual flights and patterns 

deviate from the flight plan currently submitted to BLM under existing BMP F-1. 

Monitoring undertaken to provide baseline data or to monitor effectiveness of mitigation measures must 

meet the approval of the authorized officer. As the authorized officer deems it appropriate, the data 

collection process and product shall be consistent with standards established by BLM’s Assessment, 

Inventory, and Monitoring Program. 

Background, Potential Benefits, and Residual/Unavoidable Impacts: Improved monitoring and 

analysis of flights, flight purposes, and other flight patterns will assist BLM to estimate the impacts of 

proposed actions or to formulate appropriate plans to reduce impacts. A monitoring study would provide a 

better understanding of how many aircraft are being used for different purposes, whether and how 

industry could reduce flights, and how aircraft and flight altitude affect subsistence activities and wildlife 

and in the project area. It is anticipated that such a monitoring plan will be significantly useful for the 

permittee and could direct the permittee to greater cost savings and efficiencies. It is anticipated that if 

aircraft traffic is not the reason for failed hunts, such a plan may be able to substantiate that. Data 

collected from this study will help BLM to adapt management decisions to changing conditions and 

circumstances and make better decisions for future research studies and development projects in the NPRA.

Potential Mitigation Measure 5: Reduce Flights by Utilizing Unmanned Aerial Vehicles

Objective: To reduce the impacts of aircraft traffic on Nuiqsut subsistence activities.

Requirement/Standard: The permittee will begin to employ unmanned aerial vehicles to conduct 

monitoring activities that otherwise require helicopters (i.e., pipeline inspections, studies, and other 

appropriate activities). The permittee will consult with the authorized agency every 3 years to determine 

feasibility of this technology and appropriate monitoring activities for its use. 

Background, Potential Benefits and Residual/Unavoidable Impacts: Much of the ecological 

monitoring required of lessees and permittees is supported by/requested by local residents, but there is 

less understanding and little support for the number of helicopter flights that are required to conduct those 

activities. The potential for using unmanned aerial vehicles for baseline monitoring was discussed at the 

September 2013 NPR-A Subsistence Advisory Panel meeting when a representative of Shell Oil 

announced that that company was experimenting with using them. The Subsistence Advisory Panel was 

supportive of their use to decrease impacts from helicopters. Unmanned aerial vehicles have been utilized 

for oil field studies at Prudhoe Bay, and have the potential for use in the NPR-A. Residents of Nuiqsut 

have requested that the latest technology be used for such studies as soon as and to the greatest extent 

possible in order to alleviate the high number of aircraft flights. BLM would not have the authority to 

implement this best management practice on lands that are not managed by the BLM in the Nuiqsut area, 

where much of the disturbance from aircraft occurs.

Potential Mitigation Measure 6: Subsistence Monitoring Studies

Objective: Monitor the impacts of GMT2 development on subsistence patterns, harvests, and associated 

subsistence activities for the community of Nuiqsut.

Requirement/Standard: 
1). Initially (one time), the permittee will provide for an all-resources subsistence mapping study to 

document contemporary subsistence use patterns for Nuiqsut.

Potential Benefits and Residual/Unavoidable Impacts: The 2010 BOEM mapping study for all subsistence 

resources (SRB&A 2010a) has been valuable for this SEIS and several other North Slope analyses. The 

2010 mapping study is based on data collected 1995-2006, thus the data is 12 years old and might not 

reflect changes that have occurred since 2006 or reliably confirm continuity. The one time initial 

mapping study will include all resources. The decadal interim will provide a comprehensive overview of 

any changes in subsistence use patterns during a period of development expansion near the community. 

2) The permittee will monitor, through the life of the project, changes in subsistence activities in the 

community of Nuiqsut. The permittee will provide for annual research and monitoring to document 

changes to subsistence patterns and harvest levels resulting from the proposed project. 

Studies commissioned as part of the GMT2 development will be designed with input from the 

community and will identify changes resulting from the proposed project including cumulative effects, 

and, at a minimum, monitor impacts to caribou, fish, and bird harvests. Monitoring reports, aggregated 

harvest data, and overall use areas by resource will be made available to local residents and the public 

via the standards established by the Data Review and Information Dissemination mitigation measure 

(Section 4.4.2.5). 

Researchers will employ adaptive research and monitoring techniques, including flexibility to refine 

monitoring questions based on study findings on a year-to-year basis. Adaptive monitoring will include 

researcher discretion to establish or reformulate local resource expert panels. 

The methodology for the monitoring studies will be approved by the North Slope Borough Department 

of Wildlife Management (NSB DWM) and the NSB DWM will conduct annual initial peer review of the 

monitoring reports. The reports will be edited according to the NSB DWM peer review and the 

subsequent draft report will be provided simultaneously to the permittee and, when appropriate, to a 

local resource panel (e.g., the Nuiqsut Caribou Panel). The contractor will incorporate comments from 

both entities before releasing a final report. 

Potential Benefits and Residual/Unavoidable Impacts: A subsistence monitoring study would help 

identify the impacts of GMT2-related activities on Nuiqsut subsistence activities. The nine years of data 

from the Nuiqsut subsistence caribou monitoring project (SRB&A 2010a-2018) is a valuable resource for 

evaluating impacts. The permittee may expand upon the Nuiqsut Caribou Subsistence Monitoring 

Project (initiated in 2008 and proposed for a total length of 10 years) to include additional resources 

(e.g., birds, fish) and to document both impacts related to GMT2 and cumulative impacts. The 

monitoring program would continue on an annual basis until 2024 and on a biennial basis after that. The 

Subsistence Fishery Monitoring on the Colville River project may be expanded to include Fish Creek and 

extended on a biennial basis. After 2033, the Authorized Officer and the permittee may agree to adjust 

the focus and duration of these subsistence monitoring studies. The results of an expanded subsistence 

monitoring project could be used to develop future mitigation measures aimed at lessening the impacts 

of GMT2 on Nuiqsut harvesters. Subsistence monitoring studies will continue throughout the life of the 

project, or until the Authorized Officer determines such studies are no longer necessary or prudent.

Potential Mitigation Measure 7: Road Pullouts and Access Ramps along the GMT2 

Road

Objective: To ensure the GMT2 road pullouts are constructed in advantageous locations and that ramps 

constructed to provide ATV access to and from ground surface are designed to allow maximum benefit to 

local users and to protect tundra damage. 
Requirement/Standard: Prior to construction of the GMT2 Access Road, the permittee will hold a 

public workshop in Nuiqsut to gather input regarding the location and design of the three road pullouts 

and associated access ramps. Information from the workshop will be used by the permittee to ensure that 

the pullouts are properly located along the road to maximize access for subsistence users. The access 

ramps should be long and wide enough to allow safe ingress and egress to and from the road and/or 

pullout. In addition, the design of the ramps should account for multi-season subsistence-use while 

minimizing impacts to the adjacent ground surface. This may involve “hardening” of the tundra around 

the bottom of the ramps with geo-block or other acceptable methods.

Once the road pullouts and access ramps have been designed, the permittee will post the design for public 

comment for 30 days. Input derived from the public workshop and comment period will be provided to 

the BLM and the Kuukpik Subsistence Oversight Panel (KSOP). Concurrence from KSOP on final 

location and design of the pullouts and ramps shall be obtained by the permittee. 

At least once a year after construction, the permittee will hold a public meeting in Nuiqsut to discuss use 

of the access road, pullouts, and ramps to solicit information on their use and any improvements that 

could be made to address health, safety, and access concerns. Information gathered at these meetings will 

be provided to BLM and KSOP, along with any planned improvements. 

Potential Benefits and Residual/Unavoidable Impacts: Allowing potential users of the pullouts and 

access ramps a role in ramp location and design will ensure that the ramps provide a locally accepted 

mechanism for leaving the road surface and accessing tundra that is safe, feasible, and can minimize

impacts to subsistence access and aid in search and rescue missions. Regular meetings with local resident 

who use the road will facilitate improved design features or other suggestions that can be incorporated to 

make use of the road, pullouts, and ramps safer and more effective for users and prevent tundra damage.

Potential Mitigation Measure 8: Subsistence User Monitoring and Adaptive 

Management

Objective: Prevent or minimize unreasonable conflicts between subsistence users and permitted 

activities associated with construction, operation, and production at the GMT2 development. 

Requirement/Standard: Permittee will work with the Native Village of Nuiqsut, the Kuukpik 

Subsistence Oversight Panel, and local hunters to create a Subsistence User Monitoring Plan. The plan 

will include documentation of current issues facing subsistence users regarding resource abundance, 

limitations on access, and resource availability resulting from GMT2 and associated activities, and 

including other permitted activities being carried out by the permittee in the NPR-A (i.e., exploration 

drilling, data collection, etc.). The plan will specify a set of key indicators to be monitored through the 

life of the GMT2 development, as well mechanisms identified by subsistence hunters that can be used to 

prevent, reduce, alleviate, or correct adverse effects. The monitoring plan will provide a framework for 

Nuiqsut entities, the permittee, and BLM to adaptively manage impacts to subsistence users resulting 

from the development. The process for developing the monitoring plan must be approved by the Kuukpik 

Subsistence Oversight Panel, and the final plan must be approved by the Nuiqsut trilateral entities (NVN, 

Kuukpik Corporation, and City of Nuiqsut). 

Potential Benefits and Residual/Unavoidable Impacts: Current subsistence monitoring in Nuiqsut 

focuses on the subsistence harvest, namely the scope and amount of resources being harvested through 

time, and only peripherally documents issues being experienced by the users themselves. Local residents 

have expressed frustration at the pace of development, the lack of in-depth data regarding impacts, and 

the inadequacy of back-to-back NEPA analyses in effectively describing and minimizing risk. 

Establishing a monitoring plan and program now at the beginning of development activities in NPR-A 
will help inform future analyses and development decisions. Combining the monitoring plan with 

adaptive management actions will afford local residents a measure of control over subsistence use. 

Potential Mitigation Measure 9: Prohibit Airboats in Key Subsistence Use Areas*

Objective: To reduce noise and disturbance impacts from airboats on subsistence resources, users, and 

activities.

Requirement/Standard: Except in the case of emergencies, oil spill response training, mobilization and 

deployment of pre-staged spill response equipment, and mobilization and response during a spill event, 

the permittee and its contractors will be prohibited from using airboats on rivers on BLM managed lands 

in the Nuiqsut subsistence use area (for this measure, defined as a 50-mile-wide buffer around the 

community). Through consultation with local residents, BLM may identify other key boating areas that 

should be avoided. The Authorized Officer and the permittee will coordinate to identify specific 

areas/rivers where oil spill response training and preparation activities would be permitted by BLM. 

Potential Benefits and Residual/Unavoidable Impacts: Prohibiting the use of airboats in places where 

residents are actively traveling by boat to harvest subsistence resources will reduce potential disruptions 

to subsistence users and resources. The sudden and loud noise of airboats causes acute stress situations 

for subsistence users, particularly the elderly. Residual issues could arise if local subsistence use of 

airboats increased (there is currently one airboat, not in use, in Nuiqsut). The BLM would not have the 

authority to implement this measure on non-BLM managed land and it is therefore unlikely that hunters 

and other subsistence users will experience complete respite from airboat disturbance if the measure is not 

adopted by the permittee for other lands. 

Potential Mitigation Measure 10: Annual Community Ice Road Information

Objective: Provide the community of Nuiqsut with information on area ice roads on an annual basis 

Requirement/Standard: Before ice road construction begins, the permittee and contractors associated 

with ice road construction will hold a community meeting to describe the routes and relevant information 

on all ice roads that will be constructed within the GMT2 project area. At the meeting, the permittee will 

distribute copies of maps of that winter’s ice roads. The permittee will also make the map available on the 

website developed to comply with Sociocultural potential mitigation measure #1 (if that measure is 

adopted as a BMP in the ROD for GMT2) and provide notice of availability of the map and a link to the 

online map on local social media (i.e., the Nuisagmiut facebook group). 

Potential Benefits and Residual/Unavoidable Impacts: Community members have no official system 

for learning about where ice roads are being constructed each winter and whether there are any relevant 

restrictions on those roads. Many winter hunters use the roads to facilitate access to hunting areas, and 

some may need to plan the locations for trap lines and other subsistence activities that could be affected 

by ice roads. This measure, if adopted, would only apply to ice roads within the GMT2 project area, 

which does not adequately address the needs of the community. The permittee is therefore encouraged to 

include information on all ice roads within 40 miles of Nuiqsut. 

Proposed New Mitigation Measures for Public Health

Potential Mitigation Measure 1—Minimize Undue Idling of all Vehicles

Objective: Reduce air emissions and protect human health. 
Requirement/Standard: To the extent practicable, engines of rolling stock (such as pick-up trucks, vans, 

buses, other trucks and trailers, and heavy machinery) used for oil and gas operations will be powered off 

when not in active use. 

Potential Benefits and Residual/Unavoidable Impacts: Prohibiting unnecessary vehicle idling will 

reduce emissions associated with vehicle use, such as carbon monoxide, fine particulate matter, and 

volatile organic compounds. Additionally, this measure will decrease noise impacts associated with the 

GMT2 Project. Projected emissions associated with GMT2, including vehicle exhaust emissions, are 

subject to the regulatory oversight ofthe Environmental Protection Agency through emission standards for 

engines and vehicles.

Potential Mitigation Measure 2—Public Health Monitoring

Objective: To understand the effects of oil and gas development-related changes to population health and 

increase community understanding of public health impacts. 

Requirement/Standard: The Human Health Baseline Summary (Appendix G) provides an overview of 

and helps establish the current health status of the communities within the North Slope Borough. Future 

human health baseline summaries can be created to make comparisons to baseline summaries over-time 

and as oil and gas development may advance within NPR-A. Future human health baseline studies may 

include health indicators and and should focus on health outcomes and/or health determinants that can be 

tied to GMT2 oil and gas activity. Where possible, indicators should include threshold levels and specific 

actions should be developed for when thresholds are surpassed. The State of Alaska Department of Health

and Social Services, the North Slope Borough, and the Alaska Native Tribal Health Consortium should be 

consulted in the identification of appropriate indicators, thresholds, and responsive actions. 

Potential Benefits and Residual/Unavoidable Impacts: Future comparisons to the Human Health 

Baseline Summary (Appendix G) may expedite the detection of changes in population health caused by 

GMT2 development and associated oil and gas activity. Future human health baseline information may 

inform on-going health monitoring activities to help further understand public health changes that may 

result from oil and gas development.

Potential Mitigation Measure 3—Water Quality Monitoring

Objective: Ensure that permitted activities do not create a human health risk through contamination of 

local drinking water sources.

Requirement/Standard: Permittee will work with the City of Nuiqsut to design and implement a water 

quality monitoring program at the fresh water drinking lake, and other lakes in the vicinity that could be 

used as a source of drinking water should the currently utilized lake fail or become contaminated. The 

monitoring program will consist of a monitoring plan, training for local residents so that they can carry 

out the monitoring themselves, and a water sampling program. 

Potential Benefits and Residual/Unavoidable Impacts: Monitoring the fresh water sources used for 

drinking water in Nuiqsut will provide information on contaminant levels, if present, which may have the 

potential to affect drinking water quality and human health. 

Potential Mitigation Measure 4—Accident Prevention: Additional Requirement to BMP 

C-3 

Objective: Prevent accidents due to snowmachine operators trying to cross ice road bridges after they 

have been removed, breached or slotted in accordance with BMP C-3 
Requirement/Standard: Crossing of waterway courses shall be made using a low-angle approach. 

Crossings that are reinforced with additional snow or ice (“bridges”) shall be removed, breached or 

slotted before spring break-up. Trails leading to the snow or ice bridge shall be clearly marked on either 

side of the crossing once it has been removed, breached or slotted. Applicant will coordinate with local 

entities (Kuukpik, NVN, City of Nuiqsut) to establish the best way to mark and communicate to Nuiqsut 

residents when the ice bridges are no longer passable. 

Potential Benefits and Residual/Unavoidable Impacts: Clearly marking trails on either side of a 

crossing that has been removed, breached or slotted will ensure that local users as well as contractors are 

aware that the trail has been compromised and that the crossing should not be used, thereby minimizing 

the likelihood of an accident.

Proposed New Mitigation Measures for Solid Waste and Hazardous 

Materials

Potential Mitigation Measure 1 —Trash Removal and Anti-Littering Campaign 

Objective: Prevent unnecessary or undue degradation of the land. 

Requirement/Standard: All solid waste and industry-derived trash originating from permitted activities 

is required to be properly containerized while on site, or removed from the area of operation/activity. 

Objects that have the potential to be left or forgotten (such as duck ponds, containments, or sorbent 

material caches) shall be clearly marked with the name of the company using the object.

The permittee will solicit ideas from the community of Nuiqsut to assist with addressing regular trash 

removal and inadvertent littering (including such things as ice-roads delineation markers, construction 

detritus, etc.) in order to ensure or adopt cost-effective methods that also minimize other identified 

impacts, such as those associated with helicopter use.

Potential Benefits and Residual/Unavoidable Impacts: Clearly marking movable objects associated 

with industrial development with the name of the company who utilized them will instill a greater sense 

of responsibility in employees in being good neighbors and ensuring the objects are not left or forgotten. 

In addition, it will also allow the permittee, the BLM, and local residents to track and assess the 

effectiveness of workers or contractors in following authorization requirements. By working with the 

community to identify new ideas or suggestions for the removal and handling of trash, the permittee may 

be able to save money while building effective partnerships. 

Potential Mitigation Measure 2 —Leak Detection and Leak Shut Down Requirements 

Objective: Reduce pipeline leaks and protect human health and safety.

Requirement/Standard: Meet the requirements of 18 AAC 75.055 for the pipeline carrying crude oil 

from GMT2 to GMT 1, including using external leak detection for prompt identification of leaks, daily 

flow verification, weekly visual surveillance, and demonstrated ability to stop flow within one hour of 

detection. 

Potential Benefits and Residual/Unavoidable Impacts: The pipeline carrying crude oil from GMT2 to 

GMT1 is a flow line regulated under 18 AAC 75.047. Although it does not meet the definition of a crude 

oil transmission pipeline because it also carries gas and produced water, complying with the 18 AAC 
75.005 requirements for crude oil transmission pipelines will ensure early detection and response to any 

leaks. This will minimize impacts to human health and the environment from pipeline leaks. 

Potential Mitigation Measure 3—Fuel Storage (new subparagraph to BMP A-4)

Objective: Minimize the impact of contaminants on fish, wildlife, and the environment, including 

wetlands, marshes, and marine waters, as a result of fuel, crude oil, and other liquid chemical spills. 

Protect subsistence resources and subsistence activities. Protect public health and safety.

Requirement/Standard: Fuel and hazardous material storage containers with a capacity greater than 660

gallons must use impermeable lining and diking capable of containing 110 percent of the containers’ 

capacity. Vinyl liners, with foam dikes and a capacity of 25 gallons, must be placed under all valves or 

connections to fuel tanks when located outside of secondary containment. 

Potential Benefits and Residual/Unavoidable Impacts: Potential benefits of these added measures 

above current protections include additional protection for vegetation, wetlands, and other surface 

resources by l providing secondary containment for storage containers greater than 660 gallons and using 

liners for protection outside of secondary containment. 

Potential Mitigation Measure 4— Oil Spill Response Equipment (new subparagraph to 

BMP A-3)

Objective: Minimize pollution through effective hazardous-materials contingency planning.

Requirement/Standard: Oil spill response equipment for use in winter conditions must meet the 

following standards: 

a. Equipment must be designed to be effective in Arctic conditions. 

b. Mechanisms must be available to prevent the freezing of response equipment (including the 

equipment used for storing, transferring, and treating recovered fluids) and/or to de-ice it.

Potential Benefits and Residual/Unavoidable Impacts: Potential benefits of these added measures 

above current protections include additional protection for vegetation, wetlands, and other surface 

resources by ensuring response equipment is operational under extreme weather conditions and other 

limiting factors such as ice and snow conditions.

Potential Mitigation Measure 5—Facility Equipment and Design Criteria (new 

subparagraph to BMP A-3)

Objective: Minimize pollution by ensuring adequate facility design criteria and system integrity.

Requirement/Standard: Equipment used to develop hydrocarbons must meet the following standards: 

a. Equipment must be designed in accordance with standard Arctic engineering practices for use in 

Arctic conditions; 

b. Design criteria must be based on conservative estimates (as determined by the authorizing 

officer). 

Potential Benefits and Residual/Unavoidable Impacts: System integrity is essential for spill 

prevention, but not all integrity requirements are within the scope of Oil Spill Contingency Planning. 
Potential benefits of these added measures above current protections include additional protection for 

vegetation, wetlands, and other surface resources by ensuring facility design and system integrity are 

suitable to harsh Arctic environmental conditions. 

Potential Mitigation Measure 6— Leak Detection Criteria (new subparagraph to BMP E4) 

Objective: Implement leak detection systems for GMT1 facilities. 

Requirement/Standard: To the extent practicable, the permittee will provide a specific description of the 

leak detections systems installed on all lines described in the development plan. The descriptions could be 

an addendum to the Alpine C-Plan or a stand-alone document. Monitoring would be via remote continual 

monitoring (e.g., camera or FLIR) of water crossings, or daily on-site visual inspections. The spill 

prevention section of the Alpine C-Plan must contain criteria to prevent and detect slow leaks.

Potential Benefits and Residual/Unavoidable Impacts: Automated and visual on-site leak inspections 

would reduce the extent of spills.
Appendices  Final Supplemental Environmental Impact Statement

Alpine Satellite Development Plan for the Proposed Greater Mooses Tooth 2 Development Project

APPENDIX R

APPLICANT PROPOSED 404 MITIGATION PLAN

GREATER MOOSES TOOTH TWO (GMT2) 

DEVELOPMENT PROJECT PERMITTEE 

RESPONSIBLE WETLANDS MITIGATION PLAN 

NATIONAL PETROLEUM RESERVE-ALASKA 

Prepared for: 

ConocoPhillips Alaska, Inc. 

Anchorage, AK 

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TABLE OF CONTENTS 

Section Page

1.0 INTRODUCTION..............................................................................................................1

2.0 OBJECTIVES ....................................................................................................................1

3.0 SITE SELECTION ............................................................................................................2

3.1 Watershed Needs .....................................................................................................2

3.2 Onsite Alternatives...................................................................................................3

3.3 Other Restoration Alternatives or Land Preservation Opportunities .......................3

3.4 Practicability of Results Being Ecologically Self-Sustaining ..................................3

4.0 SITE PROTECTION INSTRUMENT ............................................................................3

5.0 BASELINE INFORMATION...........................................................................................3

5.1 GMT2 Baseline Information ....................................................................................3

5.2 Fresh Water Road Restoration Site Baseline Information .......................................5

6.0 MITIGATION CREDIT .................................................................................................10

7.0 MITIGATION WORK PLAN........................................................................................10

7.1 Fresh Water Road Restoration Work Plan .............................................................10

8.0 MAINTENANCE PLAN.................................................................................................11

9.0 PERFORMANCE STANDARDS...................................................................................11

10.0 MONITORING PLAN ....................................................................................................11

11.0 LONG-TERM MANAGEMENT ...................................................................................11

12.0 ADAPTIVE MANAGEMENT .......................................................................................11

13.0 FINANCIAL ASSURANCE ...........................................................................................11

14.0 REFERENCES.................................................................................................................12

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APPENDICES 

Appendix 

Appendix A – Figures 

Appendix B – HDL 2016 Project Analysis Report 

Appendix C – Letter Agreement Between CPAI and NSB 

Appendix D – ABR GMT2 Wetlands Delineation 

Appendix E – ANSRAM Data Sheets and Debit-Credit Calculation 

TABLES 

Table 1.- GMT2 Baseline FCI Scores 4

Table 2.- Post GMT2 FCI Scores 5

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ACRONYM LIST 

ABR ABR, Inc.- Environmental Research & Services

ANSRAM Alaska North Slope Rapid Assessment Method 

ASA Aquatic Site Assessment 

ASRC Arctic Slope Regional Corporation 

CPAI ConocoPhillips Alaska, Inc. 

DA Department of the Army 

FCI Functional Capacity Index 

GMT 2 Greater Mooses Tooth 2 

HDL Hattenburg Dilley & Linnell 

HUC Hydrologic Unit Code 

NSB North Slope Borough 

NWI National Wetland Inventory 

PRM Permittee Responsible Mitigation

USACE U.S. Army Corps of Engineers 

USFWS United States Fish and Wildlife Service

WOUS Waters of the U.S. 

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1.0 INTRODUCTION 

ConocoPhillips Alaska, Inc. (CPAI) is seeking a Department of the Army (DA) permit 

authorization from the U.S. Army Corps of Engineers (USACE) to construct the Greater 

Mooses Tooth Two (GMT2) development project, consisting of a drill site, access road, 

pipelines, and ancillary facilities to support development of petroleum reserves within the 

Greater Mooses Tooth Unit. The proposed work involves the placement of clean fill 

material on 78.1 acres, 77.9 acres of which are Waters of the U.S. (WOUS). A Vicinity 

map showing the location of the GMT2 Project is included in Appendix A, Figure 1. 

2.0 OBJECTIVES 

The overall objective of this Permittee Responsible Mitigation (PRM) plan is to

demonstrate how CPAI proposes to mitigate for unavoidable wetlands impacts at GMT2

through permittee responsible wetlands restoration. In addition to the avoidance and 

minimization measures incorporated into the design of GMT2, the proposed restoration

project presented in this PRM plan provides wetlands uplift near the GMT2 project site.

The mitigation project will restore important key functions to a riverine wetland system

associated with a fresh water access road (Fresh Water Road) in Nuiqsut, Alaska. In 

addition, the project will provide safe and continuous access to Nuiqsut’s fresh water

supply reservoir. Safe and continual access to the reservoir is currently jeopardized by 

recurring flooding and road damage that occurs during breakup. 

The current culvert battery crossing associated with the Fresh Water Road is undersized, 

resulting in ice damming and road over-topping during spring breakup flood events. The

gravel road prism over the culverts has been significantly damaged from the over-topping 

and is contributing to gravel deposition and excess sediment load to the riverine system.

The undersized culverts and altered flows contribute to degraded aquatic function and alter 

the system’s hydrologic and sediment transport functions. 

The Fresh Water Road restoration project will restore important key riverine wetland 

function to 35.8 acres (0.30 acres more than currently exists) of lower perennial stream and 

abutting palustrine wetlands, as well as alleviate ice damming associated with annual

breakup discharges. This functional uplift will be achieved through restoring natural flows 

by: 1) upgrading the crossing to reflect normal flow conditions to restore flood flow 

alteration function and improve general habitat suitability; 2) removing gravel that has 

washed downstream to improve sediment removal function and afford vegetation growth;

and 3) elevating the road crossing above anticipated spring breakup flood elevations to 

protect from road washouts during breakup. This restoration project would provide direct 

benefit to a resident fish bearing stream and abutting wetlands that discharge directly to the 

Nigliq Channel of the Colville River. These improvements would protect a crucial Nuiqsut 

transportation corridor providing access to Nuiqsut’s fresh water supply. A Restoration 

Site Overview Map is included in Appendix A, Figure 2. 

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3.0 SITE SELECTION 

The proposed Fresh Water Road restoration site is in the village of Nuiqsut, Alaska, and is 

identified on the Vicinity Map (Figure 1) and Overview Map (Figure 2) in Appendix A. 

The North Slope Borough (NSB) contracted Hattenburg, Dilley, and Linnell (HDL) to

complete a Project Analysis Report (PAR) (Appendix B) for the crossing in 2016 (HDL 

2016). HDL reported that the crossing appears within the floodplain of the Colville River 

and that it has undersized culverts which result in the roadway getting over-topped during 

high spring breakup flows. 

The factors considered during the mitigation site selection process include the following: 

 Watershed and community needs; 

 Onsite alternatives; 

 Other restoration alternatives or land preservation opportunities near the 

watershed; and 

 Practicability of accomplishing an ecologically self-sustaining mitigation 

project. 

3.1 Watershed Needs 

The GMT2 impacts occur along the drainage divide between the following 10-digit 

Hydrologic Unit Code (HUC) watersheds: 

 1906020507 - Outlet Fish Creek 

 1906020506 - Ublutuoch River 

The Outlet Fish Creek watershed occupies 137,576.89 acres, and the Ublutuoch River 

watershed occupies 150,954.37 acres. The GMT2 project will impact 52.3 acres of 

wetlands in the Outlet Fish Creek, and 25.6 acres of wetlands in the Ublutuoch River 

watersheds, for a total of 77.9 acres of wetlands impacts. These two watersheds contain

very little current development and are made up almost entirely of jurisdictional WOUS, 

including wetlands. The total current development and proposed GMT2 development in 

these watersheds will be 88.9 acres and 90.1 acres, respectively (Figure 3, Appendix A). 

This is equivalent to 0.06 percent total anthropogenic impacts in each of the 10-digit HUCs; 

therefore, these watersheds are not considered impaired. 

The proposed restoration project is in the adjacent Colville River Delta-Frontal Harrison 

Bay watershed (HUC-1906030413). This watershed occupies 303,614.25 acres and 

contains the village of Nuiqsut and the gravel infrastructure development associated with

the village, transportation corridors, and gravel mining. The immediate area around 

Nuiqsut and the mitigation project site drain to the Nigliq Channel of the Colville River, 

an important subsistence resource for the area. CPAI has consulted the NSB to discuss the

needs of Nuiqsut and the importance of completing this project. The proximity of the

mitigation site to Nuiqsut creates an opportunity to provide wetlands and water-related 

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benefits to the community that is nearest to the GMT2 project and to wetland and water 

resources used by the community. A copy of the letter agreement documenting CPAI’s 

discussions with the NSB is provided as Appendix C to this Mitigation Plan. 

3.2 Onsite Alternatives 

Mitigation opportunities at the GMT2 project site were considered, but the lack of 

development in the abutting and adjacent wetlands affords no opportunities for wetlands 

restoration, or creation onsite or in the same watershed. As shown on Figure 3 (Appendix 

A), these two watersheds would only have 0.06 percent anthropogenic impacts from 

development after GMT2 is constructed. 

3.3 Other Restoration Alternatives or Land Preservation Opportunities 

Other options were explored but nothing was identified that had a similar combination of 

proximity to the GMT2 project area, actual wetlands functional uplift, positive community

impact and community support, and economic practicability. Land preservation 

opportunities were explored but are very limited, provide no wetlands uplift, are

commercially complex, and lack the broad support of a restoration program. 

3.4 Practicability of Results Being Ecologically Self-Sustaining 

The proposed improvements to the Fresh Water Road will follow acceptable practices of 

arctic engineering and design. Regular monitoring, coupled with routine maintenance 

activities and returning the riverine system to normal flows, will result in an ecologically

self-sustaining restoration project. 

4.0 SITE PROTECTION INSTRUMENT 

CPAI has discussed this mitigation project with the NSB. CPAI does not own the land 

proposed for restoration activities and does not have the ability to establish a perpetual 

protection instrument. The site is managed by the local government (NSB). The mitigation

project does not face threats that are deemed to require site protection beyond the 

stewardship provided by the NSB. 

5.0 BASELINE INFORMATION 

5.1 GMT2 Baseline Information 

ABR, Inc. - Environmental Research & Services (ABR) performed wetlands habitat 

mapping for the GMT2 project and submitted that information to CPAI in a July 2017 

wetland delineation and desktop mapping verification report (ABR, 2017). The ABR report 

(Appendix D) contains detailed wetlands mapping and habitat descriptions for the proposed 

GMT2 impact area, which is included in a larger immediate study area investigated by 

ABR. 

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ABR reported that the GMT2 study area contains typical tundra habitats composed of

dwarf shrub and emergent vascular plants within saturated and seasonally flooded 

palustrine wetlands. The study area also comprises two shallow open-water pond systems 

with poor littoral zones. ABR stated that the pond systems are likely remnants of drained 

lake basins, which are prevalent on the North Slope. 

The ABR report concludes that the GMT2 project will impact 77.8 acres (rounded to the

nearest 0.1 acre) of palustrine wetlands and a 0.1-acre pond habitat for a total of 77.9 acres 

of jurisdictional WOUS impacted. ABR reports that the GMT2 project will also impact 0.2 

acres of non-jurisdictional uplands. 

CPAI performed an Aquatic Site Assessment (ASA) based on the Arctic Slope Regional 

Corporation (ASRC) Alaska North Slope Rapid Assessment Method (ANSRAM) for each 

wetlands class impacted by the GMT2 project to determine the baseline level of functional

capacity and the post-project impacts to those watershed functions after GMT2 is 

constructed. ANSRAM determined that the key functions being provided by the wetlands 

prior to constructing GMT2 are: 

 Flood flow alteration; 

 Nutrient and toxicant removal; 

 Production of organic matter and its export; 

 General habitat suitability; and

 Native plant richness. 

The overall baseline Functional Capacity Index (FCI) score for each wetland class is shown 

below in Table 1. 

Table 1. GMT2 Baseline FCI Scores 

Wetlands Class FCI Score Acres 

PEM1F 0.781 4.3 

PEM1SS1B 0.682 49.8 

PEM1SS1E 0.799 23.7 

PUBH 0.814 0.1 

0.0 = Low Functional Capacity/ 1.0 = High Functional Capacity 

The overall FCI scores determined by ANSRAM for each wetlands type after GMT2 

construction are shown below in Table 2. The FCI scores indicate that while permanent 

gravel will be placed for the construction of GMT2 and result in reduced wetland function, 

the loss of function in the watershed will be partial rather than total because of the 

minimization measures incorporated into the GMT2 project, such as culverts to preserve

water flow and sufficient gravel to minimize thermokarsting. 

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Table 2. Post GMT2 FCI Scores 

Wetlands Class FCI Score Acres 

PEM1F 0.618 4.3 

PEM1SS1B 0.542 49.8 

PEM1SS1E 0.677 23.7 

PUBH 0.710 0.1 

0.0 = Low Functional Capacity/ 1.0 = High Functional Capacity 

Copies of the ANSRAM data sheets showing the individual evaluation metrics and the 

individual FCI for each function are included in Appendix E. 

5.2 Fresh Water Road Restoration Site Baseline Information 

A formal wetland delineation has not been completed for the Fresh Water Road restoration

site. The wetlands proposed for restoration were delineated from the desktop using United 

States Fish and Wildlife Service (USFWS) National Wetland Inventory (NWI) mapping

(USFWS, 2017). NWI mapping was further adapted using current aerial photography and 

information contained within the 2016 PAR. The extent of the desktop mapping is depicted 

in Appendix A, Figure 2. 

The desktop delineation indicates the Fresh Water Road restoration site currently consists 

of 35.5 acres of lower perennial riverine habitat (mapped to 20 foot above mean sea level), 

with palustrine emergent littoral zones and inclusions (R2EM2/UBH). The upstream

portion of the system is delineated to the approximate extent of estimated maximum annual

breakup flooding elevation presented in the 2016 PAR. The downstream portion of the 

restoration site terminates at another culvert crossing. 

The 2016 PAR identified the restoration site as a culverted crossing over a series of kettle 

ponds that provides access to the community’s water supply located 1.2 miles south of 

Nuiqsut. HDL reported that a 16-foot wide gravel roadway crosses the unnamed drainage. 

HDL also reported that the culverts were installed after an existing bridge failed. The 

crossing consists of three 48-inch diameter by 40-foot long galvanized corrugated steel

culverts, armored at the inlets and outlets with sandbags. The crossing primarily drains 9.5 

square miles and conveys snowmelt and permafrost thaw. The stream has a mild hydraulic 

gradient of 0.4% and connects with the main channel of an unnamed stream that is 

approximately 500 feet downstream of the road crossing. The unnamed stream drains to

the Nigliq Channel of the Colville River. HDL reported that the road crossing at the 

proposed restoration site experiences regular over-topping caused by high spring breakup 

flows, ice damming, and currently undersized culverts. 

This flooding has contributed to road damage which results in excess gravel and sediment

deposition downstream of the crossing. This deposition has resulted in channel constriction 

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Wetlands Mitigation Plan 

downstream of the culverts and removal of shoreline vegetation and wetlands habitat. 

Additional impacts resulting from repeated inundation may be experienced upstream to the 

limit of reported flood elevations. The upstream portion also discharges from Nuiqsut 

airport; therefore, flooding could jeopardize the runway during spring breakup. 

CPAI performed a baseline desktop ASA for the site using the ASRC ANSRAM to be 

consistent with the ASA performed for the GMT2 impact site. The ANSRAM determined 

that the key functions currently being provided by the riverine systems are: 

 Nutrient and toxicant removal; 

 General fish habitat; 

 Native plant richness; and 

 Production of organic matter and its export. 

ANSRAM determined that several functions were underperforming due to the condition of 

the culverts and the gravel deposition downstream from annual flood events. The functions 

that are underperforming and in need of uplift are: 

 Sediment removal; 

 Erosion and shoreline stabilization; 

 General habitat suitability; 

 Educational value; and 

 Uniqueness and heritage. 

ANSRAM determined that the overall baseline FCI score for the system is 0.651. 

ANSRAM determined that addressing the issues at the crossing would provide significant 

uplift to the degraded functions listed above, and that the post-restoration project would 

result in an overall FCI score of 0.947, which is a ~45 percent increase in function across

the system. Additionally, the restoration project would add 0.30 acres to the system by 

returning the crossing to normal flow patterns and removing gravel deposited downstream.

The ANSRAM data sheets showing the pre- and post-restoration site functional capacity 

for each measured function are included in Appendix E. 

Photographs of the restoration site taken during the summer of 2017 are below: 

6 August 2018 
GMT2 Development Project 

Wetlands Mitigation Plan 

Photo 1. View along roadway and crossing, looking south. 

Photo 2. View along roadway and crossing, looking north. 

7 August 2018 
GMT2 Development Project 

Wetlands Mitigation Plan 

Photo 3. View looking south at upstream side of culverts. 

Photo 4. Looking north at downstream side of culverts. The gravel in the 

stream is from road washouts. 

8 August 2018 
GMT2 Development Project 

Wetlands Mitigation Plan 

Photo 5. View of upstream side of culverts and sand bag armoring in 

creek and road embankment. 

Photo 6. View downstream from road surface with gravel in stream. 

9 August 2018 
 

 

GMT2 Development Project 

Wetlands Mitigation Plan 

6.0 MITIGATION CREDIT 

The Fresh Water Road restoration project would benefit 35.8 acres of lower perennial 

stream channel and abutting wetlands. Mitigation would be provided by removing the 

gravel that has been washed downstream and restoring the crossing to natural flow 

conditions. The crossing restoration will involve widening the stream to its pre-disturbance 

ordinary high-water width. The restoration project will provide an approximate 0.30-acre 

increase in wetland surface area over the existing 35.5-acre habitat. The gravel removal

will allow shoreline palustrine wetlands to form. 

Road integrity will be restored by strengthening the embankments and raising the road 

grade above anticipated flood elevations, which will reduce the existing effects that the 

road has on the channel. Upstream channel deformation will likely subside given that

excessive ponding from ice damming would be mitigated. Sediment transport function 

downstream will also be realized once natural flows and channel dimensions are restored

at the crossing. 

CPAI used the FCI score from ANSRAM to determine a debit from GMT2, using the 

USACE Credit-Debit Procedure. The debit-credit calculation determined that GMT2 

would result in 10.5 debits and that the restoration site would result in 10.7 credits, thus 

returning slightly more than a 1:1 mitigation ratio. A copy of the calculation is included in

Appendix E. 

7.0 MITIGATION WORK PLAN 

7.1 Fresh Water Road Restoration Work Plan 

CPAI proposes to enter into a contractual agreement with the NSB and plans to complete 

the Fresh Water Road restoration project within the time frame that GMT2 is constructed, 

which is estimated to be complete by October 2021. The work will include removal of the

existing culvert battery and restoring the stream to normal flow patterns. The actual design 

of the crossing is estimated to be complete by December 31, 2018 and will be submitted to 

the Corps as an addendum to this PRM plan by March 31, 2019. 

The nature of the work and soils in the area lend themselves to construction during multiple 

seasons. CPAI will mobilize and demobilize materials and equipment for all construction

activities. Ice roads will be used during winter activities. CPAI will work closely with the 

NSB and Nuiqsut for specific construction activity timing. 

The excess gravel deposited downstream due to recent flood events will be removed as part 

of this effort. The gravel, depending on the quality, could be reused in road grade 

improvements. Gravel that cannot be used will be deposited in an upland location. 

Vegetation along the shoreline will be allowed to develop naturally where gravel is

removed. 

10 August 2018 
 

GMT2 Development Project 

Wetlands Mitigation Plan 

8.0 MAINTENANCE PLAN 

Land at the Fresh Water Road restoration site is owned and managed by the NSB. The NSB 

will be responsible for all maintenance at the site after the repair is completed. 

9.0 PERFORMANCE STANDARDS 

The design will restore normal flows and remove the excess sedimentation downstream of 

the crossing. Upstream portions of the stream will experience a reduction in flood 

elevations and ice damming during breakup. This will alleviate the potential for shoreline

erosion and ice gouging. Scour below the crossing will be mitigated by restoring normal 

flow patterns. 

Importantly, an improved crossing would also provide year-round community access to the 

fresh water supply south of the crossing. The threat of flooding to the airport runway will 

be reduced. Any other use of the road crossing, such as for access to subsistence or 

recreational activities, will also be improved. 

Other design and performance standards will be established by agreement with the NSB. 

10.0 MONITORING PLAN 

CPAI will confirm the efficacy of the repairs during the first breakup season following 

completion of those repairs. This confirmation will include documentation that the integrity

of the road prism and new crossing are maintained and that normal flows are being

experienced. The findings from this monitoring effort will be retained by CPAI and used 

in the determination of whether adaptive management is necessary. 

11.0 LONG-TERM MANAGEMENT 

The NSB will be responsible for all long-term management of the crossing. 

12.0 ADAPTIVE MANAGEMENT 

The NSB will be responsible for any adaptive management at the crossing. 

13.0 FINANCIAL ASSURANCE 

CPAI will ensure that the project, as explained in this document, is executed. The NSB will 

be responsible for financial assurance related to future maintenance and monitoring. 

11 August 2018 
 

GMT2 Development Project 

Wetlands Mitigation Plan 

14.0 REFERENCES 

ABR, Inc.- Environmental Research & Services (ABR). 2017. Wetland Delineation and 

Desktop Mapping Verification for the Greater Mooses Tooth 2 Development 

Project, Alternative A-2015. 2017. 

Hattenburg Dilley & Linnell (HDL). 2016. Project Analysis Report, Nuiqsut Repair 

Bridge Crossings. 2016.

United States Fish & Wildlife Service (USFWS). 2017 Nation.al Wetland Inventory 

Mapping website. 2017. https://www.fws.gov/wetlands/data/Mapper.html. 

12 August 2018 
GMT2 Development Project 

Wetlands Mitigation Plan 

APPENDICES 
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APPENDIX A 

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August 3, 2018 

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APPENDIX B 

HDL 2016 PROJECT ANALYSIS REPORT 
 

 

 

 

 

PROJECT ANALYSIS REPORT 

Nuiqsut Repair 

Bridge Crossings 

 North Slope Borough 

Department of Public Works 

Capital Improvement 

Program Management 

Prepared by: 

3335 Arctic Boulevard, Suite 100 

 Anchorage, Alaska 99503 

February 10, 2016 

 

 

NUIQSUT REPAIR BRIDGE CROSSINGS 

PROJECT ANALYSIS REPORT 

CIP No. 68-041 

Borough Contract No. 2015-205 

Prepared for: 

North Slope Borough 

Department of Capital Improvement Program Management 

Bernadette Fischer, Program Manager 

Prepared by: 

Scott Hattenburg, PE/Principal 

Adam Bruscher, Project Engineer 

Hattenburg Dilley and Linnell, LLC 

Engineering Consultants 

3335 Arctic Boulevard, Suite 100 

Anchorage, Alaska 99503 

(907) 564-2120 

HDL Project: 15-031-02 

February 10, 2016 

 

 

 

 

 

 

 

 

 

North Slope Borough 

Nuiqsut Repair Bridge Crossings Project Analysis Report 

TABLE OF CONTENTS 

1.0 INTRODUCTION ............................................................................................................................ 1 

1.1 Project Purpose and Objective ...................................................................................................... 1 

1.2 Scope ........................................................................................................................................... 1 

1.3 Project Location............................................................................................................................ 1 

1.4 Background .................................................................................................................................. 3 

1.5 Crossing Evaluation....................................................................................................................... 3 

1.5.1 Lower Stream Crossing (Site 1) ....................................................................................... 3 

1.5.2 Upper Stream Crossing (Site 2) ....................................................................................... 5 

1.5.3 Tributary Stream Crossing (Site 3)................................................................................... 6 

1.6 Flood and Stage Frequency............................................................................................................ 8 

1.7 Drainage and Hydraulics................................................................................................................ 8 

1.8 Soil Conditions.............................................................................................................................. 9 

1.9 Material Source .......................................................................................................................... 10 

1.9.1 Gravel.......................................................................................................................... 10 

1.9.2 Riprap.......................................................................................................................... 10 

1.10 Roadway Design Criteria ............................................................................................................. 10 

1.11 Design Standards and Guidelines................................................................................................. 11 

2.0 ALTERNATIVES............................................................................................................................ 12 

2.1 Alternative 1A – Remove Crossing and Salvage Useable Materials ................................................ 12 

2.2 Alternative 1B - Do Nothing......................................................................................................... 12 

2.3 Alternative 2A – New Bridge Crossing, Elevate Above Ordinary High Water.................................. 13 

2.4 Alternative 2B – New Culverts, Minor Elevation Change ............................................................... 14 

2.5 Alternative 2C – Do Nothing ........................................................................................................ 15 

2.6 Alternative 3A – Armor Existing Structure, No Elevation Change .................................................. 15 

2.7 Alternative 3B – Install New Circular Culverts, Elevate Roadway 3 Feet ........................................ 16 

2.8 Alternative 3C – Install New Arched Culvert, Elevate Road 4.5 Feet .............................................. 16 

2.9 Alternative 3D – Do Nothing ........................................................................................................ 17 

2.10 Other Alternatives Considered .................................................................................................... 18 

2.10.1 Elevate Bridge at Site 2 Above Extreme High Water ...................................................... 18 

2.10.2 Precast Concrete Girders .............................................................................................. 18 

2.10.3 Elevate the Entire Road to the Boat Ramp Above Extreme High Water .......................... 18 

3.0 CONSTRUCTION METHODS .......................................................................................................... 18 

3.1 Construction Methods for Culverts .............................................................................................. 19 

3.1.1 Site 2 ........................................................................................................................... 19 

3.1.2 Site 3 ........................................................................................................................... 19 

3.2 Construction Methods for the Bridge........................................................................................... 20 

4.0 MAINTENANCE AND OPERATION................................................................................................. 20 

5.0 ENVIRONMENTAL CONSIDERATIONS AND PERMITTING REQUIREMENTS ...................................... 20 

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North Slope Borough 

Nuiqsut Repair Bridge Crossings Project Analysis Report 

6.0 ESTIMATE OF PROBABLE COSTS ................................................................................................... 23 

6.1 Capital Cost ................................................................................................................................ 23 

6.2 Operation and Maintenance Costs............................................................................................... 24 

7.0 FINDINGS.................................................................................................................................... 25 

8.0 RECOMMENDATIONS.................................................................................................................. 25 

9.0 REFERENCES ............................................................................................................................... 26 

LIST OF FIGURES 

Figure 1: Project Location Map .............................................................................................................. 1 

Figure 2: Site Location Map ................................................................................................................... 2 

Figure 3: Site 1 Culverts ......................................................................................................................... 4 

Figure 4: Failed Bridge at Site 2 .............................................................................................................. 5 

Figure 5: Bridge Abutments at Site 2 ...................................................................................................... 6 

Figure 6: Site 3 Crossing Looking South .................................................................................................. 7 

Figure 7: Site 3 Culverts - Downstream Face........................................................................................... 7 

Figure 8: Upper Stream Crossing (Site 2), High Water Debris Line............................................................ 8 

LIST OF TABLES 

Table 1: Nigliq Channel Historical Summary of Peak WSE CD5 Road........................................................ 3 

Table 2: Roadway Design Criteria......................................................................................................... 10 

Table 3: Upper Stream Crossing Model Results .................................................................................... 14 

Table 4: Tributary Culvert Model Results ............................................................................................. 16 

Table 5: Tributary Culvert Model Results ............................................................................................. 17 

Table 6: Recommended Regulatory and Permitting Tasks ..................................................................... 22 

Table 7: Capital Cost Summary ............................................................................................................ 24 

APPENDICES 

Appendix A: Capital Cost Estimates 

Appendix B: Concept Drawings for Upper Stream Crossing (Site 2) 

Appendix C: Concept Drawings for Tributary Stream Crossing (Site 3) 

Appendix D: HDL Site Inspection Report 

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North Slope Borough 

Nuiqsut Repair Bridge Crossings Project Analysis Report 

EXECUTIVE SUMMARY 

The purpose of this study is to provide the North Slope Borough (Borough) with feasible 

alternatives and costs for the repair and/or replacement of three bridge and culvert crossings in 

Nuiqsut, Alaska. The three crossings at Sites 1, 2, and 3 have failed or require yearly 

reconstruction and maintenance. 

The Lower Stream Crossing (Site 1) is a temporary culvert crossing approximately 300 feet from 

the Nigliq Channel. Currently, it provides the only access to the City’s boat ramp and material 

source stockpile. This crossing requires complete reconstruction after the high water and ice 

jamming events every spring. 

The Upper Stream Crossing (Site 2) consists of a 42-foot steel bridge constructed in 1974. This 

crossing originally provided access to the old airport, and now the village boat ramp and 

material source stockpile. Reports indicate it failed a couple of years ago. The lower stream 

crossing at Site 1 was built when the bridge failed. 

The Tributary Stream Crossing (Site 3) is a culvert crossing approximately 6,200 feet upstream 

from the Nigliq Channel that provides the only access to the community’s water source. This 

crossing was installed after a previous bridge failure and has required minimal maintenance 

with sandbags after seasonal flooding. 

Alternatives for each of the crossings were analyzed. Our findings, recommendations and the 

costs of PAR alternatives are shown Table EX-1 below. 

FINDINGS 

1. All three sites are in the flood plain of the Colville River and are subject to overtopping and 

ice jamming. 

2. Little flood information exists for Nuiqsut and the Corps of Engineers has not established a 

flood datum for Nuiqsut. 

3. A flood study and stream monitoring is needed to determine flood recurrence intervals and 

flood elevations. 

4. Debris lines near Site 2 suggest seasonal floodwaters and ice floes overtop the bridge by 

approximately 2 feet annually and by approximately 8.5 feet during extreme flood events. 

5. The Site 3 culverts are undersized and overtop annually but requires only minor sandbag 

repair after the high water recedes. 

6. Debris lines near Site 3, suggests that the roadway overtops by approximately 4.5 feet 

during extreme high water events. 

EX-1 
 

 

North Slope Borough 

Nuiqsut Repair Bridge Crossings Project Analysis Report 

RECOMMENDATIONS 

1. Conduct a flood study and stream monitoring study to determine flood recurrence intervals 

and flood elevations. 

2. Conduct a geotechnical investigation to determine engineering and thermal properties of 

soils at the sites to allow for proper design. 

3. At the Lower Stream Crossing (Site 1), remove the crossing after the Site 2 crossing is 

restored: Alternative 1A – Remove Crossing and Salvage Useable Materials. 

4. At the Upper Stream Crossing (Site 2), remove the existing bridge and install three 120-inch 

culverts: Alternative 2B – New Culverts, Minor Elevation Change. 

5. At the Tributary Stream Crossing (Site 3), install three new 72-inch culverts to provide allseason access to the water source lake: Alternative 3B – Install New Circular Culverts, 

Elevate Roadway 3 Feet. 

Table EX-1 – Capital Cost Summary 

Alternative Capital Cost Useful Life 

1A. Remove Crossing and Salvage Useable Materials 

1B. Do Nothing 

2A. New Bridge Crossing, Elevate Above Ordinary High 

Water 

2B. New Culverts, Minor Elevation Change 

2C. Do Nothing 

3A. Armor Existing Culverts, No Elevation Change 

3B. Install New Circular Culverts, Elevate Roadway 3 Feet 

3C. Install New Arched Culvert, Elevate Roadway 4.5 Feet 

3D. Do Nothing 

EX-2 
 

 

 

 

 

 

 

North Slope Borough 

Nuiqsut Repair Bridge Crossings Project Analysis Report 

1.0 INTRODUCTION 

Hattenburg Dilley and Linnell, LLC (HDL) was retained by the North Slope Borough (Borough) 

Department of Capital Improvement Program Management (CIPM) to provide a Project Analysis 

Report (PAR) for the reconstruction of three drainage channel crossings at Nuiqsut, Alaska. The 

crossings include two culverts and one bridge crossing on the same unnamed drainage. 

Breakup flood events damage the structures, causing annual repairs and prevent access to the 

village water source, boat ramp, and material source stockpile. 

1.1 Project Purpose and Objective 

The purpose of this project is to provide the Borough with feasible solutions and costs for the 

reconstruction of the three drainage channel crossings at Nuiqsut. 

1.2 Scope 

The scope of this PAR includes analyzing the existing site conditions at each of the three sites, 

developing feasible bridge and culvert crossing alternatives, developing recommendations for 

repair and/or replacement, and developing a budgetary cost estimate for each alternative. The 

analysis of the alternatives considers cost, scheduling, phasing of work, material delivery, lead 

time, impacts on access, and other pertinent criteria determined during the study. HDL worked 

closely with the Borough and village public works staff to determine the history of failures and 

operational and maintenance issues. 

1.3 Project Location 

The project sites are located on the 

village road system at Nuiqsut, Alaska. 

Nuiqsut is located 35 miles from the 

Beaufort Sea coast on the west bank of 

the Nigliq Channel near the Colville River 

Delta (CRD). The village is located at 

70°13’00” North and 151°00’00” West. 

The climate is arctic and dominated by 

extreme temperatures, wind, long 

daylight hours in the summer and 

extended periods of darkness during the 

winter. Temperatures range from -56 to 

78°F with the daily minimum 

temperature below freezing 297 days per 

year. Annual precipitation is minimal and 

Figure 1: Project Location Map 

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North Slope Borough 

Nuiqsut Repair Bridge Crossings Project Analysis Report 

averages around 5 inches with an annual snowfall of 20 inches. 

This study evaluates three crossings - two culvert crossings and one failed bridge crossing 

located on an unnamed drainage channel. See Figure 2. 

Figure 2: Site Location Map 

The Lower Stream Crossing (Site 1) is a temporary culvert crossing approximately 300 feet from 

the Nigliq Channel. Currently, it provides the only access to the City’s boat ramp and material 

source stockpile. This crossing requires complete reconstruction after the high water and ice 

jamming events every spring. The Upper Stream Crossing (Site 2) is a bridge constructed in 1974 

approximately 1,550 feet upstream from Nigliq Channel. 

This crossing originally provided access to the village boat ramp and material source stockpile, 

but has not been operational for the past couple of years. The lower stream crossing was 

established upon failure of this structure. 

The Tributary Stream Crossing (Site 3) is a culvert crossing approximately 6,200 feet upstream 

from the Nigliq Channel that provides the only access to the community’s water source. 

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North Slope Borough 

Nuiqsut Repair Bridge Crossings Project Analysis Report 

1.4 Background 

The Colville River is the largest river basin north of the Brooks Range draining nearly 23,500 

square miles. (Baker, 2013 Colville River Delta Spring Breakup Monitoring & Hydrologic 

Assessment). Spring breakup on the Colville River is dominated by ice jams, glaciering, large ice 

floes, and high flow rates for an approximate 3 week period each spring. The three crossings 

are located on an unnamed stream channel adjacent to the Nigliq Channel. See Figure 2. The 

crossings are located in the flood plain of the Colville River. 

ConocoPhillips has studied the timing and breakup of the CRD flooding since 2002, including the 

Nigliq Channel. ConocoPhillips has four stream monitoring stations (MON20, MON22, MON23 

and MON28), on the Nigliq Channel downstream of Nuiqsut. Approximately 1.5 miles 

downstream from Nuiqsut the Nigliq Channel branches into another minor side channel, the 

Nigliagvik Channel. Peak discharge and water surface elevation in the Nigliq Channel has been 

monitored at the ice road crossing to CD5 between MON20 and MON23 since 2009. Peak 

annual discharges and water surface elevations (WSE) are shown in Table 1. The WSE is based 

on the British Petroleum Mean Sea Level (BPMSL) vertical datum. The scope of this study 

excluded any surveying, ties, or extrapolation to the BPMSL vertical datum. 

Table 1: Nigliq Channel Historical Summary of Peak WSE CD5 Road 

Year Peak Indirect 

Discharge (cfs) 

Peak WSE (ft 

BPMSL) 

2014 66,000 9.38 

2013 110000 12.42 

2012 94,000 8.82 

2011 141,000 9.89 

2010 134,000 9.65 

2009 57,000 7.91 

Source Baker, 2013 CRD Spring Breakup Monitoring and Hydrologic 

Assessment 

1.5 Crossing Evaluation 

1.5.1 Lower Stream Crossing (Site 1) 

The Lower Stream Crossing at Site 1 is a culvert crossing constructed after the upstream bridge 

failed. See Figure 3. The road was rerouted and culverts were installed approximately 1,250 

feet downstream from the bridge to provide access to the boat ramp and village material 

source stockpile. The temporary culvert crossing is two 48-inch corrugated metal pipes (CMP) 

42-feet in length. These pipes sit atop another series of five to seven buried steel pipes that are 

estimated to range in sizes from 18-inch to 24-inch. A 16-foot wide gravel roadway crosses the 

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North Slope Borough 

Nuiqsut Repair Bridge Crossings Project Analysis Report 

existing 48-inch diameter culverts. Due to the proximity of the lower stream crossing to the 

Nigliq Channel (approximately 300-feet) it is subjected to major damage during the spring 

breakup events and often times has to be reconstructed when the water levels recede. 

Currently, it provides the only access to the community boat ramp and material source 

stockpile. This low profile road is approximately three feet above the surrounding terrain. This 

crossing is reported to fail almost every spring from overtopping, high flows and ice floes which 

erode the gravel embankment and scours around the culverts. 

Figure 3: Site 1 Culverts 

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North Slope Borough 

Nuiqsut Repair Bridge Crossings Project Analysis Report 

1.5.2 Upper Stream Crossing (Site 2) 

The Upper Stream Crossing at Site 2 is a steel bridge constructed in 1974. This crossing 

originally provided the access to the old airport in the 1970s and then the village boat ramp and 

material source stockpile until its failure a few years ago. The bridge is a steel girder bridge 

supported by steel H-piles with abutments retained by timber lagging between piles. The bridge 

span length is 42 feet, measured from end of girder to end of girder. The bridge has a 14-foot 

wide overall deck width and decking consists of 2 x 8-inch treated timbers bolted together and 

attached to the steel girders. Railing consists of 12 x 12-inch timber posts and galvanized 

guardrail. 

Figure 4: Failed Bridge at Site 2 

The decking, girders and guardrail have failed. See Figure 4. Physical evidence from debris 

lines indicate that the Colville River spring flood waters overtop the bridge and the bridge 

elements have failed from the hydraulic pressures and/or impacts from ice floes. The steel pile 

and timber abutments have survived 40 years with only minor damage and displacement. See 

Figure 5. Steel elements show heavy surficial rust. 

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North Slope Borough 

Nuiqsut Repair Bridge Crossings Project Analysis Report 

Figure 5: Bridge Abutments at Site 2 

1.5.3 Tributary Stream Crossing (Site 3) 

The Tributary Stream Crossing at Site 3 is a culvert crossing that provides access to the 

community’s water supply - a fresh water lake located 1.2 miles south of the village. The 16-

foot wide gravel roadway crosses the unnamed drainage that is estimated to be approximately 

250 feet wide and 15 feet deep. The road profile sags approximately 11 feet at the culverts. 

Culverts were reportedly installed after a previous bridge failed. 

The crossing consists of three 48-inch diameter by 40-foot long galvanized corrugated steel 

culverts. See Figures 6 and 7. Physical evidence of a debris line and anecdotal information 

indicate the roadway overtops yearly at spring breakup. To help protect the structure, the 

Borough has armored the inlets and outlets with sandbags. According to the Public Works 

Supervisor for Nuiqsut, the addition of sandbags has greatly extended the life of the structure. 

The condition of the sandbags is fair. The sandbags are easily accessible to vandalism. This 

crossing requires minimal maintenance and reconstruction after spring breakup, according to 

local public works staff. 

The crossing appears to be in the floodplain of the Colville River, but primarily drains snowmelt 

in a basin defined later in this report south and west of Nuiqsut. The overtopping is likely 

caused by high spring breakup flows and undersized culverts. 

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North Slope Borough 

Nuiqsut Repair Bridge Crossings Project Analysis Report 

Figure 6: Site 3 Crossing Looking South 

Figure 7: Site 3 Culverts - Downstream Face 

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North Slope Borough 

Nuiqsut Repair Bridge Crossings Project Analysis Report 

1.6 Flood and Stage Frequency 

Since all of the crossings are located within the Colville River floodplain, flood and stage 

frequency depend heavily on Colville River hydrology. From 1992 to 2014, the measured peak 

flow ranged from 159,000 – 590,000 cfs, with an 

average peak discharge of 294,000 cfs. The peak 

stage varied between 12.20 – 20.69 feet (BPMSL), 

with an average historical peak of 16.79 feet 

(BPMSL). The earliest seasonal occurrence of peak 

flow was May 16, and the latest was June 11. 

Colville River data collected for ConocoPhillips has 

limited applicability to Nuiqsut. Water surface 

elevations refer to a proprietary vertical datum, 

BPMSL, which prevented calibration of elevation 

data collected by HDL and others. Additionally the 

ConocoPhillips studies did not include a monitoring 

station immediately in the vicinity of Nuiqsut. 

Thus, there is no record of peak flow stage and 

discharge that accounts for isolated seasonal flow 

events caused by ice jams in the Nigliq Channel at 

Nuiqsut. 

For the crossings in this report, peak flood stage 

was determined by examining surrounding terrain 

for evidence of past high water events, such as woody Figure 8: Upper Stream Crossing (Site 2), High Water 

debris deposited at a consistent elevation. See Figure Debris Line 

8. We found two locations with evidence of debris 

from high water events. We estimated that the lower of the two debris lines represented a 

normal high water event due to the large amount of debris in the area. The relative elevation 

of this debris line was approximately 2-feet higher than the centerline of the bridge deck. We 

estimated the higher of the debris lines represented an extreme high water event. This debris 

line was measured to be approximately 8.5-feet higher than the bridge deck. 

For the comparison of alternatives, peak discharges, calculated by USGS regression equations, 

were used to estimate the preliminary bridge and culvert sizes. Determination of actual peak 

stage and discharge for design should include installation of stream gages at each of the 

crossings in question and the conduction of a flood study. 

1.7 Drainage and Hydraulics 

Sites 1 and 2 are located on an unnamed stream that meanders north from the drinking water 

supply to its outfall at the Nigliq channel. The drainage area upstream of the crossings is 

approximately 24.5 square miles. The hydraulic gradient of the channel is extremely mild at 

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North Slope Borough 

Nuiqsut Repair Bridge Crossings Project Analysis Report 

approximately 0.07%. The upstream watershed consists of flat, sparsely vegetated tundra with 

many permafrost lakes and ponds. 

Site 3 drains an area of 9.5 square miles, and conveys snowmelt and permafrost thaw that 

collects in a series of kettle ponds south of the Nuiqsut airport runway. The tributary has a mild 

hydraulic gradient of 0.4%, and connects with the main channel of the unnamed stream 

approximately 500 feet downstream of the road crossing. 

The hydraulics at each crossing are heavily influenced by the Colville River. As the Colville rises 

during spring breakup, a backwater effect can be created as culvert outlets become submerged 

or blocked by ice. The compromise in culvert capacity causes a rise in the headwater elevation, 

and in some cases, total inundation of the roadway. 

Culvert design criteria should comply with the Alaska Highway Drainage Manual, Alaska 

DOT&PF, June 13, 2006. 

Bridge hydraulic design criteria are provided in Sections 10.2 and 10.3 of the Alaska Highway 

Drainage Manual. The primary design constraint is maintaining a minimum of 3 feet of vertical 

clearance for passage of ice and debris at the design flow. 

1.8 Soil Conditions 

The project area is located in the Arctic Coastal Plain. The coastal plain is typically poorly 

drained and consequently marshy in the summer. Permafrost is known to exist from 800 -

1,000 feet below the ground surface. Soil conditions are unknown at these sites, but are 

generally assumed to be ice-rich, fine-grained soils with a thawed active layer of 1 to 3 feet in 

virgin undisturbed tundra, 6 to 10 feet in gravelly material, and deeper in the vicinity of stream 

channels where thaw bulbs are known to exist. 

A geotechnical evaluation has not been performed as part of this contract, but should be 

performed prior to design and construction. A full geotechnical investigation should be 

conducted including a subsurface boring program to the depth of expected foundations with 

subsurface temperature measurements and laboratory testing. At a minimum, one boring 

should be performed per substructure and one boring per 50 linear feet of wingwall. Borings 

should include Standard Penetration Testing (SPT) in unfrozen soils and macro-coring, or 

equivalent sampling in frozen soils to retrieve samples of the frozen soil and ice. The subsurface 

temperature should be measured using thermistors to a depth of 10 feet below expected 

foundations. Laboratory testing should include grain size distribution analyses, moisture 

content, Atterberg limits (if applicable), and salinities. A grain size distribution analysis and 

proctor test should be performed on the anticipated fill material. In addition, samples of the 

stream bed materials should be collected to support evaluation of the scour potential. 

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1.9 Material Source 

Gravel and riprap are the two main aggregate materials needed for the project. 

1.9.1 Gravel 

The Borough’s material source stockpile is located approximately 0.5 miles east of the project 

areas on the south bank of the Nigliq Channel. See Figure 2. The stockpile contains 

approximately 150,000 cubic yards (CY) of sandy gravelly material and is suitable for 

constructing roadway embankments. The material was extracted 4.5 miles east of the project 

area on the east bank of the main channel of the Colville River. The Borough indicates the 

material was delivered to the stockpile in the winter of 2014/2015 for $40 per CY; 70,000 CY of 

this material is dedicated to the Colville River Access Road project. We understand the 

remaining 80,000 CY is available for Borough public works needs. 

1.9.2 Riprap 

There are no known local sources of rock for riprap. Most armor stone on the North Slope 

comes from Cape Nome or Dutch Harbor via ocean barge. The nearest upland source is Atigun 

Pass. Atigun Pass riprap would be mined and transported to Prudhoe Bay via the Dalton 

Highway and then to Nuiqsut via ice roads. The cost is estimated to be about $375 per CY in 

place - which is less than barged riprap. 

1.10 Roadway Design Criteria 

Roadway design Criteria are set forth in Table 2. 

Table 2: Roadway Design Criteria 

ELEMENT VALUE SOURCE 

Construction Classification 

Design Functional Classification 

Improvement of Existing Road 

Very Low-Volume Local Road / Rural Minor 

Access Road AASHTO GDVLVLR 2001 

Design Year 2036 

AADT Construction Year (2016) 

Mid-Design Year (2025) 

Design Year (2035) 

<400 

<400 

<400 

Design Hourly Volume (DHV) 

Directional Split (%D)

(%T)

Equiv. Single Axle Load (ESAL)

Pavement Design Year

<400 

50/50 

50% 

 N/A 

 N/A 

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Nuiqsut Repair Bridge Crossings Project Analysis Report 

Design Vehicle

Design Speed (Terrain) 

Stopping Sight Distance 

Maximum Allowable Grade 

Minimum Allowable Grade 

Minimum Radius of Curvature 

Minimum K-Value for 

Vertical Curves 

Number of Roadways

Width of Traveled Way

Width of Shoulder

Surface Treatment

Side Slope Ratios 

Degree of Access Control

Median Treatment

Illumination:

Curb Usage and Type

Bicycle/ Pedestrian Provisions

 N/A 

25 mph (Level) 

250 (Assumed “Higher Risk” & 

doubled per p.52 

7% 

0.5% 

210 ft with Tc=0.4 (wet earth) 

Crest = 29 

Sag = 26 

 1 lane 

 16 ft 

 N/A 

 N/A 

Fore: 2H:1V 

Back: 2H:1V 

 N/A 

 N/A 

 N/A 

 N/A 

 N/A 

AASHTO GDVLVLR 2001, p. 52 & Ex. 8, 

p.34 

AASHTO PGDHS 2011, Tbl. 5.2, pg. 5-3 

AASHTO GDVLVLR 2001, p. 51 

AASHTO GDVLVLR 2001, Ex. 12, pg. 39 

AASHTO PGDHS 2011, Tbl. 5.3, pg. 5-4 

1.11 Design Standards and Guidelines 

Design standards should comply with the following publications: 

 Guidelines for Geometric Design of Very Low-Volume Local Roads (ADT ≤ 400), American 

Association of State Highway and Transportation Officials (AASHTO), 2001. 

 A Policy on Geometric Design of Highways and Streets (PGDHS or “Green Book”), AASHTO, 2001. 

 Bridge LRFD Design Specifications, AASHTO, 2014. 

 Alaska Highway Drainage Manual, Alaska Department of Transportation and Public Facilities 

(ADOT&PF). 

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2.0 ALTERNATIVES 

The following feasible alternatives are considered. 

Site 1 

 Alternative 1A - Remove Crossing and Salvage Useable Materials 

 Alternative 1B - Do Nothing 

Site 2 

 Alternative 2A - New Bridge Crossing, Elevate Above Ordinary High Water 

 Alternative 2B - New Culverts, Minor Elevation Change 

 Alternative 2C - Do Nothing 

Site 3 

 Alternative 3A - Armor Existing Culverts, No Elevation Change 

 Alternative 3B - Install New Circular Culverts, Elevate Roadway 3 Feet 

 Alternative 3C - Install New Arched Culvert, Elevate Roadway 4.5 Feet 

 Alternative 3D - Do Nothing 

2.1 Alternative 1A – Remove Crossing and Salvage Useable Materials 

Alternative 1A consists of removing the lower stream crossing at Site 1 and salvaging the 

aggregate and two 48-inch culverts. The crossing is within 300 feet of the Nigliq Channel and is 

mostly affected by high flows in the Nigliq Channel. The crossing is reconstructed every spring. 

The banks of the stream and streambed would be reshaped and blended to match the existing 

contours to help facilitate the flow. Removing this crossing would eliminate a 

maintenance/reconstruction project every spring. Removing the crossing at Site 1 cannot occur 

until the crossing at Site 2 is reconstructed. 

2.2 Alternative 1B - Do Nothing 

Alternative 1B is to leave the lower stream crossing at Site 1 in place. If Alternative 1B is 

selected, the crossing will likely blow out within one year making the road to the boat ramp and 

material source stockpile impassible. 

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2.3 Alternative 2A – New Bridge Crossing, Elevate Above Ordinary High Water 

This alternative consists of a one lane modular bridge on a steel pile foundation. The proposed 

superstructure would be a prefabricated modular bridge with an estimated deadload of 34-kips. 

The bridge would be designed to withstand loading conditions consistent with AASHTO’s HL-93 

loading condition, which is defined as lane load plus design truck load. In accordance with the 

Guidelines for Geometric Design of Very Low-Volume Local Roads (ADT ≤ 400) the 

recommended bridge width is 15 feet. This bridge would be constructed at the previous 

location and the span would remain unchanged at 42 feet. Prior to any new construction, the 

existing bridge would be removed and all salvageable materials delivered to the city landfill. 

The existing piles would be pulled using a vibratory hammer, and new piles driven at the same 

approximate location. 

To allow passage of debris, the bottom chord of the new modular bridge would be elevated to a 

height of 3-feet above the ordinary high water mark per the recommendation of the Alaska 

Highway Drainage Manual. The deck height of the new bridge is estimated to be about 8 feet 

above that of the previous bridge. Based on the debris lines observed in the field, the 

additional height of this bridge would keep the structure from being impacted during ordinary 

high water events and spring ice jams, but not extreme flooding. Elevating the new structure 

would require reconstruction of the approaches. 

According to the Alaska Highway Preconstruction Manual, bridge railings must comply with 

NCHRP 350 test level 2 or 3. To increase bridge rail performance the test level 3 railing should 

be considered. 

Per the AASHTO Guidelines for Geometric Design of Very Low-Volume Local Roads (ADT ≤ 400) 

the use of guardrails or other traffic barriers are not recommended and deemed impractical for 

use on roads with very low traffic volumes. 

For the purposes of developing a cost estimate, we assumed an active layer of 8 to 10 feet and 

HP 14 x 117, grade 50, steel H-piles spaced at approximate 6 feet and driven to a depth of 50 

feet below the ground surface. It is anticipated that the piles would be driven in the same 

general location as the existing piling. In permafrost, piles will likely require predrilling. 

With an anticipated embankment height of 18 feet, abutments would consist of the H-piles, 8-

inch x 8-inch treated timber lagging and horizontal steel rod tiebacks and deadmen to restrain 

lateral earth pressures. A steel pile cap would support the modular bridge and should be 

designed to resist the force of ice jams should the ordinary high water mark be exceeded. 

Riprap armoring would be installed on approach slopes and along the abutment toe to resist 

erosion and scour. See the concept drawings in Appendix B. 

This alternative would elevate the bridge above the estimated ordinary high water mark, but 

could be expected to overtop occasionally and be damaged by extreme flood events on the 

Colville River. Approach slope armor may be displaced by large ice floes and would require 

maintenance. Stream gaging and flood study would be needed to estimate the recurrence 

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interval and flood stages for a proper bridge design at Site 2. The roadway from the boat ramp 

to the village would intentionally not be elevated to allow flood waters and ice floes to pass 

around the bridge and approaches and avoid having the roadway act as a dam. 

2.4 Alternative 2B – New Culverts, Minor Elevation Change 

Alternative 2B consists of installing three 120-inch diameter galvanized steel culverts. Sheet 

piling should be considered under culverts at both ends to prevent piping around the bottom of 

culverts. Rigid insulation would be installed under culverts to avoid thaw settlements. Prior to 

any new construction, the existing bridge would be removed and all materials disposed of at 

the landfill. Existing piles would be pulled or cut off below grade. 

A preliminary hydraulic analysis was performed to compare the existing condition to three 10-

foot diameter culverts with headwalls. HEC-RAS modeling software was used to develop 

hydraulic models based on elevations recorded during the site visit. The complexity of the 

hydraulic processes associated with the ice jams in the Colville River Drainage limits the ability 

to validate the modeling, but it allows for a general comparison between the existing structure 

and a proposed structure. 

Based on the Alaska Department of Transportation’s listed design value for bridges in flood 

hazard areas, the 100-year peak flow was selected as the design flow. This flow was calculated 

using USGS regression equations. The model assumed that the bridges or culverts would have a 

2-foot blockage due to icing. The results are depicted in Table 3. 

Table 3: Upper Stream Crossing Model Results 

 

 

 

 

 

The results suggest that installing three 120-inch culverts would increase freeboard by 2.4 feet 

and nearly double the flow capacity. 

This Alternative assumes there is no benefit to elevating the crossing because the roadways 

have flooded. Finished grade over the culverts would approximately match that of the existing 

bridge approaches with 2 feet of minimum cover over new culverts. 

To prevent piping under the culverts, a sheet pile wall would be installed at the inlet and outlet 

ends to prevent piping under the culvert bottoms. The culverts would be bolted to a steel 

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angle which is in turn secured to the sheet piling. The sheet piling wall shall be cut to 

accommodate the bottom of the culvert and driven to refusal at the permafrost interface. 

The crossing would be armored with 32-inches of Class II riprap from the toe of the slope to the 

shoulder of the road. This armor toes should be keyed in at the bottoms and ends to prevent 

edge scour. A riprap apron should extend 15-feet in front of the inlet and outlet ends of the 

culverts. 

Approach slope armor may be displaced by large ice floes and would require some 

maintenance but less than an elevated bridge. Stream gaging and flood study would be needed 

to estimate the flood recurrence intervals and stages for design. The roadways and crossings 

would flood more frequently than the Alternative 2A, the elevated bridge. 

2.5 Alternative 2C – Do Nothing 

Currently, half of the bridge decking is missing and a wooden barricade with a single warning 

sign is the only safety measure implemented. Leaving the site as-is is a potential hazard and 

liability for the Borough and therefore this alternative is not recommended. The bridge and 

abutments should be removed and the slopes graded to match the existing contours. 

2.6 Alternative 3A – Armor Existing Structure, No Elevation Change 

During HDL’s site visit in August 2015, it was observed that very little flow was active through 

the culverts at Site 3. However, a high water debris line was discovered upstream of the 

crossing. This upstream debris line was measured at approximately 4.5 feet above the crest of 

the road at the culverts. Downstream of the crossing, a high water debris line was observed 

approximately 2 feet below the top of the road. Based on the debris lines, there appears to be a 

significant backwater buildup during peak flows resulting in roadway overtopping and erosion 

damage. This effect can be mitigated through hydraulic improvements at the crossing. This 

alternative, however, makes no improvement to the crossing’s hydraulic issues but includes 

armoring the existing culverts and installing a minimum of 32 inches of Class II riprap. The 

embankment slopes would be armored and culvert ends armored 15 feet in front of the culvert 

ends to a width 4 feet on either side of the outside of the culvert. This alternative does not 

mitigate the backwater buildup during peak flows, but addresses erosion and damage sustained 

during these periods. Once the waters have receded there may still be a need for minor 

maintenance. 

This alternative would be prone to flooding during breakup and would not provide all season 

access to the water source lake. This alternative is not recommended if all season access to the 

water source lake is required. 

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2.7 Alternative 3B – Install New Circular Culverts, Elevate Roadway 3 Feet 

Alternative 3B consists of installing three 72-inch circular culverts at Site 3, raising road grade 

approximately 3 feet, and armoring slopes and aprons similar to Alternative 2B. Rigid insulation 

would be installed under culverts to reduce thaw settlements. To prevent piping under the 

culvert bottoms, a sheet pile wall would be installed at the inlet and outlet ends of the culverts. 

The culverts shall be bolted to an angle and secured to the sheet piling. The sheet piling would 

be trimmed to accommodate the shape of the culvert. Slopes and inlet and outlet aprons 

would be armored with 32-inches of Class II riprap. The aprons would extend 15 feet in front of 

the culverts. 

A hydraulic analysis was performed to compare the existing conditions to the recommendation 

using HY-8 modeling software. It should be noted that the complexity of the hydraulic process 

associated with ice jams in the Colville River Drainage limits the ability to validate modeling 

results; however, a performance comparison between the existing and proposed condition is 

useful. 

Based on the Alaska Department of Transportation’s design value for low usage secondary 

highways, the 10-year peak flow was used as the design flow to analyze the tributary stream 

crossing. The results are depicted in Table 4 below. USGS regression equations were used to 

calculate the flow and it was assumed that the culverts would have a 2-foot blockage due to 

icing. 

Table 4: Tributary Culvert Model Results

 

 

 

The results suggest that upgrading to three 72-inch diameter circular culverts would reduce the 

backwater elevation by several feet and may significantly reduce the probability of overtopping. 

The alternative would provide all season access to the water source lake. This alternative is 

recommended. 

2.8 Alternative 3C – Install New Arched Culvert, Elevate Road 4.5 Feet 

Alternative 3C consists of installing a single 100-inch by 154-inch arched culvert, rigid insulation, 

a sheet pile cutoff wall and slope and apron armoring. Similar to Alternatives 3A and 3B, the 

slopes and aprons would be armored with 32-inches of Class II riprap. The apron would 

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Nuiqsut Repair Bridge Crossings Project Analysis Report 

measure approximately 15-feet by 27-feet in front of culvert inlets and outlets. To achieve the 

recommended minimum culvert cover of 2 feet, the existing roadway grade would have to be 

raised by 1.2 feet. In order to mitigate overtopping, similar to Alternative 3B (using the Q10 

backwater information) the roadway should be raised 4.3 feet. Elevating the roadway would 

enable the road to be useable during spring breakup. 

A preliminary hydraulic analysis was performed similar to Alternatives 3A and 3B. Based on the 

Alaska DOT’s design value for low usage secondary highways, the 10-year peak flow was used 

as the design flow to analyze the tributary stream crossing. The results are depicted in Table 5 

below. USGS regression equations were used to calculate the flow and it was assumed that the 

culverts would have a 2-foot blockage due to icing. 

Table 5: Tributary Culvert Model Results 

 

 

 

The results suggest upgrading to a single 100-inch by 154-inch arched culvert would reduce the 

backwater elevation by a couple of feet and would reduce the occurrence of overtopping. 

This alternative may be feasible, but its design should take special precautions to insulate the 

foundation under the arched culvert to prevent frost jacking. Arched culverts are susceptible to 

failure from frost jacking because of their flat bottom. Recently, a similar multiplate arched 

culvert in Buckland failed when the bottom jacked, while a circular multiplate structure 

alongside it performed satisfactorily. It is reported that an ice lense formed underneath, 

causing the bottom to buckle. For this reason, additional insulation should be added to prevent 

ice lenses from forming under the arch. 

2.9 Alternative 3D – Do Nothing 

Alternative 3D leaves the existing crossing as is. With minor spring time repairs this crossing 

may be useable for years, but will eventually fail due to damage sustained during high water 

events and ice jamming activities. If the Borough desires all season access to the water source 

lake, this option is not recommended. 

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2.10 Other Alternatives Considered 

Other alternatives were considered, but deemed not feasible for technical or economic 

reasons. 

2.10.1 Elevate Bridge at Site 2 Above Extreme High Water 

Elevating the bridge at Site 2 above the extreme high water event was considered, but deemed 

not practical or feasible. This alternative would require extremely high, roughly 24.5–foot, 

abutment walls and extended approaches. Building abutments and approaches of this 

magnitude would require massive amounts of fill material and gravel, which would be 

expensive and complicated. Elevating the bridge to this extreme would pose no benefit to the 

community as the surrounding access roads would be inundated and the bridge would not be 

of any benefit to the general public. For cost estimate breakdown see Page 10 of Appendix A. 

2.10.2 Precast Concrete Girders 

A bulb-T prestressed concrete bridge was considered for Site 2, but deemed not economically 

feasible due to the short span. According to a local prestressed concrete manufacturer, a short 

50-foot span with a 14 to 16 foot deck width, three 42-inch bulb-T prestressed concrete 

girders would not be competitive with modular steel bridges of an equivalent size. The 

concrete would also be more susceptible to ice damage because of the girder depth, and the 

bulbs lesser lateral strength when compared to a steel bridge. 

2.10.3 Elevate the Entire Road to the Boat Ramp Above Extreme High Water 

Elevating and armoring the 3200 feet of road to the boat ramp and bridge at Site 2 above 

extreme high water was considered, but the high cost, estimated to be $20M to $30M for the 

28,800 CY of riprap and 92,800 CY of gravel fill was deemed not economically feasible. 

Elevating the entire road and bridge would hydraulically act as a dam for Colville River flood 

waters and would be prone to flood damage. The high cost compared to the benefit of 

providing access to the boat ramp and material source during flood events makes this concept 

not feasible. 

3.0 CONSTRUCTION METHODS 

The nature of the work and soils in the area lend itself to construction during multiple seasons. 

The mobilization/demobilization of materials and equipment on the ice road coupled with 

winter and summer construction activities will extend construction over the course of one year. 

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Construction access at Site 3 is governed by the need for access to the village’s water source. 

The 3rd or 4th week of June the city begins pumping water from the lake and pumps 

continuously until the tanks are full, which is typically around the 1st week of September. The 

shutdown date varies according to weather. Freezing of the waterline ends the pumping 

season. During the pumping season, the water system operators require unrestricted access to 

service pumps and monitor the operation. 

3.1 Construction Methods for Culverts 

3.1.1 Site 2 

The existing bridge should be removed and all salvageable materials shall be delivered to the 

Borough. The existing piles may be able to be pulled, salvaged, and returned to the City; 

otherwise, the piling should be cut two feet below grade. In late fall, the sheet pile walls should 

be installed when the active layer is at its maximum depth. These walls are to be driven 

through the active layer and to refusal in the permafrost layer below. The sheet pile walls 

should be left high, about to the spring line of the culverts. Under frozen ground conditions, 

the Contractor would excavate and install a layer of rigid insulation and install approximately 4-

feet of sacrificial fill material to protect the crossing during spring runoff and breakup. After 

breakup, culverts would be installed and remaining thawed fill placed and compacted under 

low flow conditions. The sheet piles would be trimmed and attached to culverts using a double 

rolled angle. Fill slopes should be armored with Class II riprap 32-inches deep over a geotextile 

fabric with keyed edges. The culvert inlets would be armored with a riprap apron. 

3.1.2 Site 3 

Due to the average historical high water date of the Colville River on May 31st, and the need for 

access to the water source lake by the 3rd week in June, winter construction methods will need 

to be employed. In late fall, the existing culverts and fill would be removed and sheet pile walls 

installed similar to Site 2. Sheet piles would be cut to an elevation about 6 inches above the 

invert of the inlet and outlet of the culverts. Then under frozen ground conditions, excavation 

would occur to the bottom of insulation, insulation installed, then fill brought back up to the 

bedding depth of the culvert inverts. The culverts, fill, geotextile, and riprap could be placed 

under frozen ground conditions, if dry granular material could be properly placed and 

compacted; or the contractor could place temporary riprap to protect during breakup and 

complete the project under thawed conditions. The sheet piles would be trimmed and attached 

to culverts using a double rolled angle. Fill slopes should be armored with Class II riprap 32-

inches deep over a geotextile fabric with keyed edges. The culvert inlets would be armored 

with a riprap apron. 

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3.2 Construction Methods for the Bridge 

The removal of the existing bridge structure is needed to construct the bridge. The existing 

bridge should be removed and all salvageable materials shall be delivered to the Borough. The 

existing piles should be pulled, salvaged, and returned to the City, or the bridge offset to miss 

existing piles. 

Gravel approaches would be removed to the extent required to drive piles and construct 

deadmen anchors. New H-piles would be predrilled with an undersized pilot hole and driven to 

depth. Near-water work should be avoided until spring breakup high flows have receded. 

The abutments and wing walls, consisting of piles, treated-timber lagging and deadman 

anchors, would be constructed during thawing conditions to help ensure proper placement and 

compaction of fills. The pile caps, elastomeric bearing pads, backwall, bridge structure, and 

appurtenances would be installed when environmental conditions allow for proper welding and 

connection installation. 

4.0 MAINTENANCE AND OPERATION 

Yearly maintenance may be required at Sites 2 and 3 to ensure the longevity of the crossings. 

Erosion control and bank stabilization will need to be maintained and repaired in a timely 

manner to protect the structures in place. These structures will be subject to flooding and 

overtopping during extreme events and will need to be repaired and rearmored, if needed. If 

normal maintenance is not conducted in a timely fashion the structures may prematurely fail. 

It is recommended to inspect culverts on an annual basis and after extreme events. The 

National Bridge Inspection Standards (NBIS) recommends that bridges should be inspected 

every two years and that the maximum interval between inspections should not exceed four 

years. 

5.0 ENVIRONMENTAL CONSIDERATIONS AND PERMITTING REQUIREMENTS 

HDL conducted preliminary environmental research using the most current available data from 

state and federal agencies to identify environmental resources in the vicinity of the proposed 

project. The purpose of the preliminary research was to assist in identifying permitting and 

regulatory requirements to ensure environmental considerations are adequately addressed in 

developing any of the "action" alternatives for the proposed project. Environmental categories 

with resources potentially present in the project area are discussed below. 

National Environmental Policy Act (NEPA) Review 

The funding source for the proposed project will dictate the type of environmental 

documentation necessary to satisfy state and federal requirements and/or authorizations. 

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Nuiqsut Repair Bridge Crossings Project Analysis Report 

Should federal funds be used, the federal agency appropriating the funds would likely assume 

the role of lead federal agency and would be responsible for development of appropriate NEPA 

documentation. NEPA documentation would outline potential impacts to the natural and manmade environment. 

Should the project be entirely state funded, the NSB’s primary environmental documentation 

will be the environmental review conducted for this PAR, which identifies potential 

environmental impacts and outlines permits and authorizations needed for the project. A NSB 

or state-funded project triggers the NEPA process when a federal permit is required, such as a 

U.S. Army Corps of Engineers (USACE) Section 404 permit for impacts to wetlands. This 

environmental review may be used by the USACE to streamline their NEPA documentation 

efforts and potentially decrease the amount of time necessary in receiving authorization. 

Wetlands & Waters of the U.S. 

A review of the U.S. Fish & Wildlife Service (USFWS) National Wetlands Inventory and recent 

satellite imagery indicates the project area contains wetlands under USACE jurisdiction. It is 

anticipated that the project will impact wetlands, and will require authorization under a 

Nationwide Permit and submittal of a Pre-Construction Notification to USACE. Should the 

project disturb more than 0.50 acre of wetlands, an Individual Permit application would be 

required. 

Construction of the proposed project will involve the discharge of construction storm water 

into waters of the U.S. Should the project involve more than one acre of disturbed ground, 

coverage under the Alaska Department of Environmental Conservation’s Alaska Pollutant 

Discharge Elimination Systems (APDES) Construction General Permit for stormwater discharges 

would be required. 

Cultural, Historic, Pre-Historic, & Archaeological Resources 

The likelihood of disturbing previously unknown cultural, historic, pre-historic, or archaeological 

resources within the project areas is low since the areas have been previously disturbed by 

construction of existing infrastructure. The project will require a Certificate of Traditional Land 

Use Inventory (TLUI) Clearance from the NSB Department of Inupiat History, Language, and 

Culture (IHLC). 

Should the project receive state or federal funding, consultation with the Alaska Office of 

History and Archaeology under the Alaska Historic Preservation Act, or State Historic 

Preservation Officer (SHPO) under Section 106 of the National Historic Preservation Act, would 

be required. 

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Fish & Wildlife: 

Threatened & Endangered Species 

Initial project scoping conducted using USFWS’s Information, Planning, and Conservation 

System tool indicates there is one species, the polar bear (Ursus maritimus), listed as 

threatened under the Endangered Species Act (ESA) that is known to inhabit the project area. 

There are no endangered or candidate species or designated critical habitats located in the 

project area. Consultation with the USFWS under Section 7 of the ESA would be required if 

federal funding is received for construction. 

Migratory Birds 

The project is located in areas that have been heavily disturbed; however, shrub and grassvegetated areas are present. To avoid disturbance to migratory birds, USFWS recommends 

avoiding clearing from June 1st through August 10th. 

Anadromous Fish Streams 

A review of the Alaska Department of Fish and Game’s (ADF&G) Anadromous Waters Catalog 

(AWC) indicates the project is located on the Nigliq Channel, a tributary of the Colville River, 

which is listed as supporting several species of anadromous fishes. Consultation with ADF&G 

during the design phase of the project is recommended to determine whether fish may be 

present in the project area and if a Fish Habitat Permit will be required. 

Land Ownership 

According the Alaska Division of Community and Regional Affairs’ Community Map for Nuiqsut, 

the project would be located on a combination of lands owned by the Borough, City of Nuiqsut, 

and Kuukpik Corporation. The project will require easements or rights-of-way prior to 

construction. 

Environmental Permitting Summary & Recommendations 

Table 6 below summarizes environmental data and permit requirements for development. 

Table 6: Recommended Regulatory and Permitting Tasks 

NSB Land Management 

Regulations (LMR) 

Development Permit. (fee waived for NSB projects). 

Wetlands, Waters of the 

U.S, & Navigable Waters 

Jurisdictional wetlands located within project areas. Section 404 

Nationwide Permit/Pre-Construction Notification required. 

APDES Construction General required if disturbed area is 1 or 

more acre ($490 fee). 

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Cultural, Historic, PreHistoric, & Archaeological 

Resources 

Low potential to encounter historic sites; IHLC's Certificate of 

TLUI Clearance required (fee waived for NSB projects). 

Consultation with OHA/SHPO required depending on funding 

source. 

Threatened & Endangered 

Species 

Polar bear listed as Threatened under ESA. Consultation with 

USFWS required if federally funded. 

Migratory Birds No vegetation clearing between June 1st and August 10th 

recommended. 

Anadromous Fish Streams No AWC-listed anadromous fish habitat in project area; Nigliq 

Channel of Colville River is approximately 500 feet downstream 

of Site 1. Consultation with ADF&G recommended during design. 

Land Ownership Confirm existing or provide easements or rights-of-way for work 

on NSB, City of Nuiqsut, and Kuukpik Corporation lands. 

6.0 ESTIMATE OF PROBABLE COSTS 

6.1 Capital Cost 

Capital costs for the three sites have been prepared based on the analysis provided herein for 

each of the sites, details of which are provided in Appendix A and summarized in Table 7. 

Capital cost estimates are based on the following general assumptions: 

1. Work will be competitively bid. 

2. Seasonal ice road between Prudhoe Bay and Nuiqsut will be available and constructed 

by industry. 

3. Materials and equipment will mobilize and demobilize via ice road. 

4. A site for material staging and equipment storage will be provided at no cost to the 

contractor. 

5. The Borough stockpiled gravel will be available at no cost. 

6. Piling will be predrilled in permafrost. 

7. Sheet piling will be driven through the thawed active layer to refusal in the permafrost. 

23 
 

 

 

North Slope Borough 

Nuiqsut Repair Bridge Crossings Project Analysis Report 

8. Construction shall occur during times of low to no flow. 

9. Dewatering will be necessary when working at or below the water levels in the 

surrounding area. 

10. Labor assumed to be at Title 36 wage rates. 

11. No crushed aggregate surfacing is required for road surfacing. 

12. Alternative 1A work will be performed upon completion of Site 2 work by the same 

Contractor. 

Table 7: Capital Cost Summary 

Alternative Capital Cost Useful Life 

1A. Remove Crossing and Salvage Useable Materials 

1B. Do Nothing 

2A. New Bridge Crossing, Elevate Above Ordinary High 

Water 

2B. New Culverts, Minor Elevation Change 

2C. Do Nothing 

3A. Armor Existing Culverts, No Elevation Change 

3B. Install New Circular Culverts, Elevate Roadway 3 Feet 

3C. Install New Arched Culvert, Elevate Roadway 4.5 Feet 

3D. Do Nothing 

6.2 Operation and Maintenance Costs 

Operation and maintenance (O&M) costs are expected to include minor riprap restoration 

annually from ice floes; except after extreme flood events which may cause significant damage. 

O&M costs can be minimized by keeping embankments sloped and low profile to minimize 

hydraulic impacts and restoration costs. 

24 
 

 

 

North Slope Borough 

Nuiqsut Repair Bridge Crossings Project Analysis Report 

7.0 FINDINGS 

1. All three sites are in the flood plain of the Colville River and are subject to overtopping 

and ice jamming. 

2. Little flood information exists for Nuiqsut and the Corps of Engineers has not established 

a flood datum for Nuiqsut. 

3. A flood study and stream monitoring is needed to determine flood recurrence intervals 

and flood elevations. 

4. Debris lines near Site 2 suggest seasonal floodwaters and ice floes overtop the bridge by 

approximately 2 feet annually and by approximately 8.5 feet during extreme flood 

events. 

5. The Site 3 overtops annually but requires only minor sandbag repair after the high water 

recedes. 

6. Debris lines near Site 3 suggest that the roadway overtops by approximately 4.5 feet 

during extreme high water events. 

8.0 RECOMMENDATIONS 

1. Conduct a flood study and stream monitoring study to determine flood recurrence 

intervals and flood elevations. 

2. Conduct a geotechnical investigation to determine engineering and thermal properties 

of soils at the sites to allow for proper design. 

3. At the Lower Stream Crossing (Site 1), remove the crossing after the Site 2 crossing is 

restored: Alternative 1A – Remove Crossing and Salvage Useable Materials. 

4. At the Upper Stream Crossing (Site 2), remove the existing bridge and install three 120-

inch culverts: Alternative 2B – New Culverts, Minor Elevation Change. 

5. At the Tributary Stream Crossing (Site 3), install three new 72-inch culverts to provide 

all-season access to the water source lake: Alternative 3B – Install New Circular 

Culverts, Elevate Roadway 3 Feet. 

25 
 

 

North Slope Borough 

Nuiqsut Repair Bridge Crossings Project Analysis Report 

9.0 REFERENCES 

1. A Policy on Geometric Design of Highways and Streets, (PGDHS or “Green Book”) 

AASHTO, 2011. 

2. Alaska Highway Drainage Manual, Alaska DOT&PF. June 13, 2006. 

3. Baker. 2013 Colville River Delta Spring Breakup Monitoring & Hydrologic Assessment. 

4. Big R Bridge. Standard 4 1⁄4” Steel Deck 30’ to 80’ x 14’ or 16’ Single Lane Bridge – Bridge 

Detail, December 7, 2015. 

5. "Bridges & Structures." Revisions to the National Bridge Inspection Standards (NBIS). 

N.p., n.d. Web. 07 Dec. 2015. 

6. Guidelines for Geometric Design of Very Low-Volume Local Roads (ADT ≤ 400). 

American Association of State Highway and Transportation Officials (AASHTO), 2001. 

7. Green, Ken. NSB CIPM Project Administrator, Personal communication regarding 

material source stockpile, December 2015.Nukapigak, Thomas. Nuiqsut Public Works 

Superintendent, Personal Communication, August and November 2015. 

8. Roadside Design Guide. AASHTO, 2011. 

9. "Village of Nuiqsut | ICAS." ICAS. Web. 16 Sept. 2015. 

26 
 

 

North Slope Borough 

Nuiqsut Repair Bridge Crossings Project Analysis Report 

APPENDIX A 

COST ESTIMATE 

Nuiqsut Repair Bridge Crossing PAR 

2/10/2016 

Alternative 1A - Remove Crossing and Salvage Useable Materials 

ITEM QUANTITY DESCRIPTION UNIT PRICE TOTAL PRICE 

1 1 L.S. Temp Erosion and Pollution Control 20,000.00 20,000 

2 1 L.S. Remove 2-48" CMPs 25,000.00 25,000 

3 1 L.S. Remove 5-7 18"-24" Burried Steel Pipes 25,000.00 25,000 

4 1 L.S. Reshaping and Bank Stabilization 45,000.00 45,000 

5 1 L.S. Salvagable Material 15,000.00 15,000 

Subtotal Construction $130,000 

Land Acquisition 

City Administration 

Design 

Construction Management 

Project Contingency 

3 Years Inflation 

@ 5% 

@ 12% 

@ 15% 

@ 15% 

@ 3% 

0 

6,500 

15,600 

19,500 

19,500 

12,100 

Subtotal $203,200 

Alt 1A Page 1 of 10 Prepared by HDL Engineering 
Nuiqsut Repair Bridge Crossing PAR 

2/10/2016 

Alternative 1B - Do Nothing 

ITEM QUANTITY DESCRIPTION UNIT PRICE TOTAL PRICE 

Subtotal Construction $0 

Land Acquisition 

City Administration 

Design 

Construction Management 

Project Contingency 

1 Years Inflation 

@ 5% 

@ 12% 

@ 15% 

@ 15% 

@ 3% 

0 

0 

0 

0 

0 

0 

Subtotal $0 

Alt 1B Page 2 of 10 Prepared by HDL Engineering 
Nuiqsut Repair Bridge Crossing PAR 

2/10/2016 

Alternative 2A - New Bridge Crossing, Elevate Above Ordinary High Water 

ITEM QUANTITY DESCRIPTION UNIT PRICE TOTAL PRICE 

1 1 L.S. Mobilization/Demobilization 286,000.00 286,000 

2 1 L.S. Temp Erosion and Pollution Control 75,000.00 75,000 

3 1 L.S. Construction Surveying 90,000.00 90,000 

4 1 L.S. Remove Piling, Abutments, and Superstrucure 75,000.00 75,000 

5 1 L.S. Modular Bridge (FOB Seattle) 54,600.00 54,600 

6 1 L.S. Modular Bridge Assembly 20,000.00 20,000 

7 17 Tons Barging of Bridge Structure (SEA to PUD) 1,000.00 17,000 

8 332,000 Lbs. HP14x117 Piling, Grade 50 (2840l.f.) 1.00 332,000 

9 20 Days Install H Piles 18,000.00 360,000 

10 9,000 Lbs. Pile Caps, Backwall, and Bearing Plates 1.00 9,000 

11 2,700 B.F. 8x8 PT Timber 2.00 5,400 

12 432 L.F. Tie Back Anchors 50.00 21,600 

13 12 Each Deadmen 10,000.00 120,000 

14 290 C.Y. Excavation 50.00 14,500 

15 3,960 C.Y. Gravel Fill 50.00 198,000 

16 1,500 S.Y. Geotextile Fabric 5.00 7,500 

17 1,000 C.Y. Rip Rap 375.00 375,000 

18 13 Loads Trucking (Anc. to Nui.) 10,000.00 130,000 

Subtotal Construction $2,190,600 

Land Acquisition 

City Administration 

Design 

Construction Management 

Project Contingency 

3 Years Inflation 

@ 5% 

@ 12% 

@ 15% 

@ 15% 

@ 3% 

0 

109,500 

262,900 

328,600 

328,600 

203,100 

Subtotal $3,423,300 

Alt 2A Page 3 of 10 Prepared by HDL Engineering 
Nuiqsut Repair Bridge Crossing PAR 

2/10/2016 

Alternative 2B - New Culverts, Minor Elevation Change 

ITEM QUANTITY DESCRIPTION UNIT PRICE TOTAL PRICE 

1 1 L.S. Mobilization/Demobilization 268,000.00 268,000 

2 1 L.S. Temp Erosion and Pollution Control 50,000.00 50,000 

3 1 L.S. Construction Surveying 90,000.00 90,000 

4 1 L.S. Remove Piling, Abutments, and Superstrucure 75,000.00 75,000 

5 195 L.F. 3 - 120" Φ CMP 1,800.00 351,000 

6 6 Each End Section 4,000.00 24,000 

7 55,000 Lbs. Sheet Piling (1550 S.f.) 1.00 55,000 

8 15 Days Install Sheet Piling 18,000.00 270,000 

9 500 Lbs. 8"x4"x9/16" Rolled Angle H.D.G. 6.00 3,000 

10 72 L.F. Tieback Anchors 50.00 3,600 

11 4 Each Deadmen 7,500.00 30,000 

12 19,500 B.F. 4" Rigid Insulation 12.00 234,000 

13 610 C.Y. Excavation 50.00 30,500 

14 1,600 C.Y. Gravel Fill 50.00 80,000 

15 1,030 C.Y. Riprap 375.00 386,250 

16 1,500 S.Y. Geotextile Fabric 5.00 7,500 

17 10 Loads Trucking (Anc. to Nui.) 10,000.00 100,000 

Subtotal Construction $2,057,850 

Land Acquisition 

City Administration 

Design 

Construction Management 

Project Contingency 

3 Years Inflation 

@ 5% 

@ 12% 

@ 15% 

@ 15% 

@ 3% 

0 

102,900 

246,900 

308,700 

308,700 

190,800 

Subtotal $3,215,850 

Alt 2B Page 4 of 10 Prepared by HDL Engineering 
Nuiqsut Repair Bridge Crossing PAR 

2/10/2016 

Alternative 2C - Do Nothing (Remove Bridge) 

ITEM QUANTITY DESCRIPTION UNIT PRICE TOTAL PRICE 

1 1 L.S. Mobilization/Demobilization 40,000.00 40,000 

2 1 L.S. Temp Erosion and Pollution Control 75,000.00 75,000 

3 1 L.S. Remove Piling, Abutments, and Superstrucure 75,000.00 75,000 

4 1 L.S. Reshaping and Bank Stabilization 50,000.00 50,000 

Subtotal Construction $240,000 

Land Acquisition 

City Administration 

Design 

Construction Management 

Project Contingency 

3 Years Inflation 

@ 5% 

@ 15% 

@ 20% 

@ 20% 

@ 3% 

0 

12,000 

36,000 

48,000 

48,000 

22,300 

Subtotal $406,300 

Alt 2C Page 5 of 10 Prepared by HDL Engineering 
Nuiqsut Repair Bridge Crossing PAR 

2/10/2016 

Alternative 3A - Armor Existing Culverts, No Elevation Change 

ITEM QUANTITY DESCRIPTION UNIT PRICE TOTAL PRICE 

1 1 L.S. Mobilization/Demobilization 250,000.00 250,000 

2 1 L.S. Temp Erosion and Pollution Control 50,000.00 50,000 

3 1 L.S. Slope Grading 85,000.00 85,000 

4 1,425 C.Y. Riprap 375.00 534,400 

5 2,420 S.Y. Geotextile Fabric 5.00 12,100 

Subtotal Construction $931,500 

Land Acquisition 

City Administration 

Design 

Construction Management 

Project Contingency 

3 Years Inflation 

@ 5% 

@ 12% 

@ 15% 

@ 20% 

@ 3% 

0 

46,600 

111,800 

139,700 

186,300 

86,400 

Subtotal $1,502,300 

Alt 3A Page 6 of 10 Prepared by HDL Engineering 
Nuiqsut Repair Bridge Crossing PAR 

2/10/2016 

Alternative 3B - Install New Circular Culverts, Elevate Roadway 3 Feet 

ITEM QUANTITY DESCRIPTION UNIT PRICE TOTAL PRICE 

1 1 L.S. Mobilization/Demobilization 280,000.00 280,000 

2 1 L.S. Temp Erosion and Pollution Control 50,000.00 50,000 

3 1 L.S. Construction Surveying 90,000.00 90,000 

4 1 L.S. Remove Old Culverts 25,000.00 25,000 

5 195 L.F. 72" CMP 1,200.00 234,000 

6 6 Each End Sections 3,000.00 18,000 

7 34,000 Lbs. Sheet Piling (1000 S.f) 1.00 34,000 

8 15 Days Install Sheet Piling 18,000.00 270,000 

9 500 Lbs. 8"x4"x9/16" Rolled Angle H.D.G. 6.00 3,000 

10 72 L.F. Tieback Anchors 50.00 3,600 

11 4 Each Deadmen 7,500.00 30,000 

12 12,400 B.F. 4" Rigid Insulation 12.00 148,800 

13 1,280 C.Y. Excavation 50.00 64,000 

14 2,740 C.Y. Gravel Fill 50.00 137,000 

15 1,735 C.Y. Riprap 375.00 650,625 

16 1,390 S.Y. Geotextile Fabric 5.00 6,950 

17 10 Loads Trucking (Anc. to Nui.) 10,000.00 100,000 

Subtotal Construction $2,144,975 

Land Acquisition 

City Administration 

Design 

Construction Management 

Project Contingency 

3 Years Inflation 

@ 5% 

@ 12% 

@ 15% 

@ 15% 

@ 3% 

0 

107,200 

257,400 

321,700 

321,700 

198,900 

Subtotal $3,351,875 

Alt 3B Page 7 of 10 Prepared by HDL Engineering 
Nuiqsut Repair Bridge Crossing PAR 

2/10/2016 

Alternative 3C - Install New Arched Culvert, Elevate Roadway 4.5 Feet 

ITEM QUANTITY DESCRIPTION UNIT PRICE TOTAL PRICE 

1 1 L.S. Mobilization/Demobilization 328,000.00 328,000 

2 1 L.S. Temp Erosion and Pollution Control 50,000.00 50,000 

3 1 L.S. Construction Surveying 90,000.00 90,000 

4 1 L.S. Remove Old Culverts 25,000.00 25,000 

5 72 L.F. 100-inch x 154-inch Pipe Arch Culvert 1,800.00 129,600 

6 2 Each End Sections 4,000.00 8,000 

7 40,000 Lbs. Sheet Piling (1130 S.F.) 1.00 40,000 

8 15 Days Install Sheet Piling 18,000.00 270,000 

9 1,000 Lbs. 8"x4"x9/16" Rolled Angle H.D.G. 3.00 3,000 

10 72 L.F. Tieback Anchors 50.00 3,600 

11 4 Each Deadmen 7,500.00 30,000 

12 30,800 B.F. 4" Rigid Insulation 12.00 369,600 

13 1,500 C.Y. Excavation 50.00 75,000 

14 3,300 C.Y. Gravel Fill 50.00 165,000 

15 2,190 C.Y. Riprap 375.00 821,250 

16 1,660 S.Y. Geotextile Fabric 5.00 8,300 

17 10 Loads Trucking (Anc. to Nui.) 10,000.00 100,000 

Subtotal Construction $2,516,350 

Land Acquisition 

City Administration 

Design 

Construction Management 

Project Contingency 

3 Years Inflation 

@ 5% 

@ 12% 

@ 15% 

@ 15% 

@ 3% 

0 

125,800 

302,000 

377,500 

377,500 

233,300 

Subtotal $3,932,450 

Alt 3C Page 8 of 10 Prepared by HDL Engineering 
Nuiqsut Repair Bridge Crossing PAR 

2/10/2016 

Alternative 3D - Do Nothing 

ITEM QUANTITY DESCRIPTION UNIT PRICE TOTAL PRICE 

Subtotal Construction $0 

Land Acquisition 

City Administration 

Design 

Construction Management 

Project Contingency 

1 Years Inflation 

@ 5% 

@ 12% 

@ 15% 

@ 15% 

@ 3% 

0 

0 

0 

0 

0 

0 

Subtotal $0 

Alt 3D Page 9 of 10 Prepared by HDL Engineering 
Nuiqsut Repair Bridge Crossing PAR 

2/10/2016 

Elevate Bridge at Site 2 Above Extreme High Water - See Section 2.10.1 pg 18 

ITEM QUANTITY DESCRIPTION UNIT PRICE TOTAL PRICE 

1 1 L.S. Mobilization/Demobilization 2,300,000.00 2,300,000 

2 92,800 C.Y. Gravel Fill 50.00 4,640,000 

3 28,824 C.Y. Riprap 375.00 10,809,000 

4 42,000 S.Y. Geotextile Fabric 5.00 210,000 

Subtotal Construction $17,959,000 

Land Acquisition 

City Administration 

Design 

Construction Management 

Project Contingency 

1 Years Inflation 

@ 5% 

@ 12% 

@ 15% 

@ 15% 

@ 3% 

0 

898,000 

2,155,100 

2,693,900 

2,693,900 

538,800 

Subtotal $26,938,700 

E.H.W.M Page 10 of 10 Prepared by HDL Engineering 
 

 

North Slope Borough 

Nuiqsut Repair Bridge Crossing Project Analysis Report 

APPENDIX B 

CONCEPT DRAWINGS FOR UPPER STREAM CROSSING (SITE 2) 

 

 

 

 
 

 

 

 
 

 

 

 

 

 

 

 

North Slope Borough 

Nuiqsut Repair Bridge Crossing Project Analysis Report 

APPENDIX C 

CONCEPT DRAWINGS FOR TRIBUTARY STREAM CROSSING (SITE 3) 

 

 

 

 
 

 

 

 

 

 
 

 

 

 
 

 

 

 

 

 
 

 

North Slope Borough 

Nuiqsut Repair Bridge Crossing Project Analysis Report 

APPENDIX D 

HDL SITE INSPECTION REPORT 

 

 

 

 

 

 

MEMORANDUM 

CIVIL 

ENGINEERING 

GEOTECHNICAL 

ENGINEERING 

TRANSPORTATION 

ENGINEERING 

ENVIRONMENTAL 

SERVICES 

PLANNING 

SURVEYING 

CONSTRUCTION 

ADMINSTRATION 

MATERIAL 

TESTING 

RIGHT-OF-WAY 

SERVICES 

DATE: September 8, 2015 

TO: Jack Frantz, North Slope Borough Project Administrator 

FROM: Adam Bruscher, Project Engineer 

RE: August 20-21, NSB PAR Bridge Crossing Repair - Nuiqsut Site Inspection 

On Thursday August 20, 2015, I departed Anchorage with Scott Hattenburg and Kyle Albert 

of Hattenburg Dilley & Linnell via Alaska Airlines at 7:35 AM and arrived in Prudhoe Bay at 

9:17 AM. We departed Prudhoe Bay at 1:30 PM via Ravn Alaska and arrived in Nuiqsut at 

1:50 PM. Upon arriving in Nuiqsut we were greeted by Kuukpik Hotel staff and transported 

to Kuukpikmiut Subsistence Oversight Panel Inc. for our vehicle rental. Upon obtaining the 

vehicle rental we checked into our rooms at the Kuukpik Hotel. 

Temperatures were in the low-40°Fs during the day and mid-30°Fs at night. Conditions 

were overcast during the site visit. 

The purpose for the trip was to investigate and gather the field information necessary to 

prepare a Project Analysis Report (PAR) for the North Slope Borough (Borough) to repair 

two temporary culvert crossings and one failed bridge crossing (Figure 1). During our visit 

to Nuiqsut we also completed an as-built survey of the PAPI pads for the Nuiqsut Airport. 

Figure 1: project location map 

Upon departing the hotel we spoke with Thomas, the Public Works Supervisor for Nuiqsut. 

He mentioned that extreme high water events occur during the spring ice breakup and the 

only visible landmark is the gravel pile located 0.7 miles east of the village and a knoll 0.1 

miles east of the village (Figure 1). He also informed us that the backwater from the Colville 

River causes the water level to rise well above the access road, thus annually washing out 

the lower stream crossing by the boat launch. The tributary stream crossing south of the 

airport is armored with sandbags and though it overtops annually, it has not washed out. 

3335 Arctic Boulevard Suite 100 • Anchorage Alaska 99503 • Phone: 907.564.2120 • Fax: 907.564.2122 

202 W. Elmwood Avenue • Palmer Alaska 99645 • Phone: 907.746.5230 • Fax: 907.746.5231 
 

 

 

 

 

 

RE: August 20-21, 2015 Nuiqsut Inspection Report 

September 2, 2015 

Page 2 of 3 

For the remainder of the day on August 20th we performed a preliminary investigation of 

the three stream crossings and as a separate project as-built the newly constructed PAPI 

pads at the airport. 

On August 21st we started our field work at the temporary culvert crossing on the boat ramp 

access road. We gathered measurements on the existing pipes, roadway dimensions. We 

setup a level and took field measurements on the top of the roadway, top of pipes and water 

level at the culverts. We collected a cross section of the stream 100 feet upstream of the 

bridge, recording relative elevations at 10’ intervals. 

Figure 2: Temporary culvert crossing, Road to the Boat Launch, two 48-inch CMPs 

Next we visited the failed bridge location. We noted the condition of the bridge, what failed, 

and the sizes and dimension of the structural components of the bridge. We setup a level 

and took relative elevation measurements on the centerline of the bridge deck, the water 

surface, channel bottom, and centerline of the road 75 feet East and West of the structure. 

To better understand the channel hydraulics we recorded a reference cross section roughly 

250 feet downstream of the bridge. 

Figure 3: Failed 42-foot span Bridge, Road to Boat Launch 

The last structure we visited was the tributary stream crossing south of the airport on the 

road to the water source. We gathered data in a similar fashion to the first culvert crossing 

and noted the dimensions of the existing pipes and roadway widths. A level was used to 

determine relative heights for the top of the roadway, culverts, and water surface. A 

reference cross section was collected 100 feet upstream of the crossing. High water debris 
 

 

 

 

 

 

RE: August 20-21, 2015 Nuiqsut Inspection Report 

September 2, 2015 

Page 3 of 3 

lines were located at the edges of the cross-section. The road embankment at this crossing 

was armored with sandbags that appeared to help protect the structure from erosion. 

Figure 4: Temporary culvert crossing – Road to Water Source, 

three 48-inch diameter CMPs 

Upon completing visits to all three structures, we revisited the failed bridge location and 

investigated surrounding areas to locate the high water debris lines. We found two locations 

with evidence of debris from high water events. We estimated that the lower of the two 

debris lines represented a normal high water event due to the large amount of debris in the 

area. The relative elevation of this debris line was approximately 2 feet higher than the 

centerline of the bridge deck. We estimated the higher of the debris lines represented an 

extreme high water event. This debris line was measured to be approximately 8.5 feet 

higher than the bridge deck. 

Figure 5: High water debris line 

After documenting the location and relative elevations of the high water lines we gathered 

our equipment, departed from Nuiqsut at 3:50 PM and arrived in Anchorage at 8:39 PM. 

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