U.S. Department of the Interior

U.S. Geological Survey

Digital Data Series DDS–69–CC

National Assessment of Oil and Gas Project: 

Geologic Assessment of Undiscovered Gas Hydrate 

Resources on the North Slope, Alaska

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National Assessment of Oil and Gas 

Project: Geologic Assessment of 

Undiscovered Gas Hydrate Resources 

on the North Slope, Alaska

By U.S. Geological Survey Alaska Gas Hydrate Assessment Team

Digital Data Series DDS–69–CC

U.S. Department of the Interior

U.S. Geological Survey
U.S. Department of the Interior

SALLY JEWELL, Secretary

U.S. Geological Survey

Suzette M. Kimball, Acting Director

U.S. Geological Survey, Reston, Virginia: 2013

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Suggested citation:

U.S. Geological Survey Alaska Gas Hydrate Assessment Team, 2013, National Assessment of Oil and Gas Project—

Geologic assessment of undiscovered gas hydrate resources on the North Slope, Alaska: U.S. Geological Survey 

Digital Data Series 69–CC, 100 p., http://dx.doi.org/10.3133/ds69cc.

ISSN 2327-0271 (print)

ISSN 2327-132x (online)
iii

Contents

Abstract...........................................................................................................................................................1

1. Introduction...........................................................................................................................................1

2. USGS Oil and Gas Assessment Methodology.................................................................................4

3. Gas Hydrate Technical Review..........................................................................................................5

4. Alaska North Slope Gas Hydrate Petroleum System.....................................................................5

4.a. Gas Hydrate Stability Conditions ............................................................................................5

4.b. Reservoir Rocks.......................................................................................................................13

4.c. Gas Source and Migration.....................................................................................................20

5. Gas Hydrate Production Analysis ...................................................................................................23

5.a. Gas Hydrate Production Testing Results.............................................................................23

5.b. Gas Hydrate Production Modeling.......................................................................................25

6. Gas Hydrate Assessment Methodology.........................................................................................28

6.a. Northern Alaska Gas Hydrate Total Petroleum System and Assessment Units...........28

6.a.1. Nanushuk Formation Gas Hydrate Assessment Unit ..........................................39

6.a.2. Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate 

Assessment Unit........................................................................................................40

6.a.3. Sagavanirktok Formation Gas Hydrate Assessment Unit...................................41

6.b. Assessment Unit Probabilities ..............................................................................................41

6.c. Undiscovered Gas Hydrate Accumulations—Sizes of Accumulations.........................42

6.d. Undiscovered Gas Hydrate Accumulations—Number of Accumulations....................45

7. Assessment-Data Form.....................................................................................................................49

7.a. Identification Information ......................................................................................................51

7.b. Characteristics of Assessment Unit.....................................................................................51

7.c. Undiscovered Accumulations...............................................................................................51

7.d. Assessment of Coproducts....................................................................................................58

7.e. Selected Ancillary Data for Undiscovered Accumulations .............................................58

7.f. Allocations of Assessed Undiscovered Resources ..........................................................58

8. Resource Assessment Results ........................................................................................................58

9. References Cited................................................................................................................................59

10. Appendixes..........................................................................................................................................65

1. Basic input data (Seventh data form) used in estimates of the numbers and 

sizes of undiscovered gas hydrate accumulations in the Sagavanirktok Formation 

Gas Hydrate Assessment Unit (50010201) in the Northern Alaska Gas Hydrate 

Total Petroleum System................................................................................................................65

2. Basic input data (Seventh data form) used in estimates of the numbers and 

sizes of undiscovered gas hydrate accumulations in the Tuluvak-Schrader 

Bluff-Prince Creek Formations Gas Hydrate Assessment Unit (50010202) in 

the Northern Alaska Gas Hydrate Total Petroleum System ...................................................77

3. Basic input data (Seventh data form) used in estimates of the numbers and 

sizes of undiscovered gas hydrate accumulations in the Nanushuk Formation 

Gas Hydrate Assessment Unit (50010203) in the Northern Alaska Gas Hydrate 

Total Petroleum System................................................................................................................89
iv

Figures

1. A, generalized geographic map of the Alaska North Slope showing the 

location of coastline, rivers, lakes, major political boundaries, villages, 

pipelines, and other features. B, map of the physiographic provinces 

and major tectonic features of the Alaska North Slope.........................................................2

2. Flow diagram showing key steps in the USGS assessment model for 

undiscovered conventional oil and gas accumulations.........................................................4

3. Gas hydrate phase diagram showing the depth and temperature conditions 

suitable for the formation of gas hydrate under various conditions of 

permafrost depth, geothermal gradient, gas chemistry, and a pore-pressure 

gradient of 0.433 psi/ft (9.795 kPa/m).........................................................................................6

4. Map showing the depth to base of permafrost on the Alaska North Slope 

as determined from equilibrated well-bore temperature surveys in 46 wells....................8

5. Maps of the Alaska North Slope gas hydrate stability zone: A, depth to the 

top of the hydrate stability zone; B, depth to base of the hydrate stability zone; 

C, thickness of the hydrate stability zone .................................................................................9

6. Lithostratigraphic chart illustrating the relations between former and revised 

nomenclature of Mull and others (2003) for the Alaska North Slope.................................14

7. A, downhole logs from the Northwest Eileen State-2 well depicting the 

depth of units B, C, D, and E; data shown include the natural gamma ray log, 

bulk-density, neutron porosity, acoustic velocity, and electrical resistivity 

data. B, insert of well logs from the cored gas hydrate interval (unit C) in the 

Northwest Eileen State-2 well..................................................................................................15

8. Well log cross section showing the lateral and vertical extent of the Eileen 

and Tarn gas hydrate accumulations and the associated underlying freegas zones in the Prudhoe Bay and Kuparuk River oil fields ................................................16

9. Map of the Eileen and Tarn gas hydrate accumulations overlying portions 

of the Prudhoe Bay, Kuparuk River, and Milne Point oil fields............................................18

10. Milne Point area gas hydrate prospects identified with 3-D seismic 

interpretation...............................................................................................................................19

11. Milne Point Mount Elbert gas hydrate prospect ...................................................................20

12. Open-hole well logs from the cored section of the Mount Elbert gas 

hydrate stratigraphic test well .................................................................................................21

13. Well-log-derived gas hydrate saturations, density porosities, and sediment 

permeabilities for the two gas-hydrate-bearing intervals (units C and D) 

cored in the Mount Elbert gas hydrate stratigraphic test well ...........................................22

14. Schematic west to east cross section through the Prudhoe Bay and 

Kuparuk River fields illustrating possible gas-migration paths and spatial 

relations between the Eileen and Tarn gas hydrate accumulations, 

free-gas and oil accumulations, Eileen and other fault zones, and base 

of gas hydrate stability...............................................................................................................22

15. Montage of log data from wells drilled in Prudhoe Bay Unit (PBU), 

Kuparuk River Unit (KRU), and Milne Point Unit (MPU) areas ............................................26

16. Comparison of typical production simulation results for Alaska North 

Slope gas hydrate reservoirs....................................................................................................27
v

17. Hydrate saturation in the Prudhoe Bay Unit (PBU) L-106 well as calculated 

by the Archie (1942) relation for n = 1.5, 2.0 (model SH), and 2.5 .........................................29

18. Predicted gas and water production from the Prudhoe Bay Unit (PBU) 

L-106 C-unit methane hydrate deposit for a constant bottom-hole pressure 

of 2.7 megapascals.....................................................................................................................30

19. A, map of the Northern Alaska Gas Hydrate Total Petroleum System (TPS) 

(500102), B, map of the Northern Alaska Gas Hydrate TPS and the gas 

hydrate stability zone thickness contours from figure 5C....................................................31

20. Map of the Nanushuk Formation Gas Hydrate Assessment Unit (AU)..............................33

21. Map of the Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate 

Assessment Unit (AU)................................................................................................................34

22. Map of the Sagavanirktok Formation Gas Hydrate Assessment Unit (AU).......................35

23. Map showing locations of well-log correlation sections within the greater 

Prudhoe Bay area as compiled by Lewis and others (2013)................................................37

24. Map of 2D and 3D seismic profiles, the interpretation of which were used 

as the base data for this assessment of undiscovered gas hydrate resources 

on the Alaska North Slope ........................................................................................................38

25. Maps showing pre-drill estimates of A, gas hydrate saturation, and 

B, reservoir thickness for hydrate unit C in the Mount Elbert prospect............................44

26. Gas hydrate recovery ratio (percent of in-place gas within gas hydrates 

that would be recovered) as a product of the producing well abandonment 

pressure (pressure is shown as a percent of hydrostatic pore pressure) .......................45

27. Bar-graph showing sizes of 3D-imaged gas hydrate accumulations in 

A, the Milne Point Unit (MPU) and B, the National Petroleum Reserve in 

Alaska (NPRA).............................................................................................................................46

28. Bar-graph showing sizes of the 3D-imaged gas hydrate accumulations in 

A, the Milne Point Unit (MPU), and B, the National Petroleum Reserve in 

Alaska (NPRA), that have been modified to account for larger and smaller 

inferred gas hydrate accumulations in the MPU and NPRA, respectively.......................47

29. Map showing locations of the wells of opportunity (table 5) from which 

the analysis of gas samples were used to ascertain the composition and 

source of the gas within each of the gas hydrate assessment units in 

northern Alaska...........................................................................................................................50

30. A, map of the Nanushuk Formation Gas Hydrate Assessment Unit showing 

areas outlined with high, middle or low “gas hydrate discovery ratio—

distributions” B, same as A, but also includes locations of wells of opportunity 

and discovered oil and gas fields from figure 29...................................................................52

31. A, map of the Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate 

Assessment Unit showing areas outlined with high, middle or low “gas 

hydrate discovery ratio—distributions”. B, same as A, but also includes locations 

of wells of opportunity and discovered oil and gas fields from figure 29..........................54

32. A, Map of the Sagavanirktok Formation Gas Hydrate Assessment Unit with 

the areas outlined with high, middle or low “gas hydrate discovery ratio—

distributions”; B, with location of wells of opportunity and discovered 

oil and gas fields .........................................................................................................................56
vi

Tables

1. List of Alaska North Slope wells with equilibrated borehole temperature 

surveys along with the estimated depth of the base of permafrost (0°C) and 

the depth to the top (THSZ) and base (BHSZ) of the gas hydrate stability zone..............12

2. Cross-reference of the gas hydrate assessment units with USGS conventional 

assessment units in northern Alaska............................................................................................40

3. List of 3D seismic imaged gas hydrate accumulations in the Milne Point 

Unit and the National Petroleum Reserve in Alaska, listed by the name 

of the accumulation and associated gas hydrate assessment unit...................................43

4. Determinations of “gas hydrate discovery ratio—distributions” resulting 

from the Milne Point Unit and the National Petroleum Reserve in Alaska 3D 

seismic gas hydrate prospecting effort..................................................................................48

5. List of wells of opportunity in which analyses of gas samples have been 

used to ascertain the composition and source of the gas within each of 

the gas hydrate assessment units in northern Alaska.........................................................49

6. List of conventional oil and gas fields used in part to assign “gas hydrate 

discovery ratio—distributions” to various portions of the gas hydrate 

assessment units ........................................................................................................................51

7. Estimates of the number of undiscovered gas hydrate accumulations 

in the Nanushuk Formation Gas Hydrate Assessment Unit.58

8. Estimates of the number of undiscovered gas hydrate accumulations 

in the Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate 

Assessment Unit.........................................................................................................................58

9. Estimates of the number of undiscovered gas hydrate accumulations

in the Sagavanirktok Formation Gas Hydrate Assessment Unit.58

10. Alaska North Slope—Gas hydrate assessment results.......................................................59

Conversion Factors

Inch/Pound to SI

Multiply By To obtain

Length

inch (in.) 2.54 centimeter (cm)

inch (in.) 25.4 millimeter (mm)

foot (ft) 0.3048 meter (m)

mile (mi) 1.609 kilometer (km)

Area

square inch (in2

) 6.452 square centimeter (cm2)

square mile (mi2

) 259.0 hectare (ha)

square mile (mi2

) 2.590 square kilometer (km2)

Volume

cubic foot (ft3

) 28.32 cubic decimeter (dm3)

cubic foot (ft3

) 0.02832 cubic meter (m3)

Pressure

pound per square foot (lb/ft2

) 0.04788 kilopascal (kPa)

pound per square inch (lb/in2

) 6.895 kilopascal (kPa)

Density

pound per cubic foot (lb/ft3

) 16.02 kilogram per cubic meter (kg/m3)

pound per cubic foot (lb/ft3

) 0.01602 gram per cubic centimeter (g/cm3)

Temperature in degrees Fahrenheit (°F) may be converted to degrees Celsius (°C) as follows:

°C=(°F–32)/1.8
vii

Acronyms Used in Report

USGS U.S. Geological Survey

TCF trillion cubic feet

BLM U.S. Bureau of Land Management 

NPRA National Petroleum Reserve in Alaska

ANWR Arctic National Wildlife Reserve

TPS Total Petroleum System

AU assessment unit

sI Structure I Hydrate 

sII Structure II Hydrate

sH Structure H Hydrate

MDT Schlumberger Modular Dynamic Testing

DOE U.S. Department of Energy

JOGMEC Japan Oil, Gas and Metals National Corporation

MPU Milne Point Unit,

NRCan Natural Resources Canada

KRU Kuparak River Unit 

PBU Prudhoe Bay Unit

National Assessment of Oil and Gas Project: 

Geologic Assessment of Undiscovered Gas Hydrate 

Resources on the North Slope, Alaska

By U.S. Geological Survey Alaska Gas Hydrate Assessment Team

that gas hydrates are a global phenomenon containing 

potentially huge volumes of gas in terrestrial polar regions 

and the deep-water portions of most continental margins. 

Gas hydrates are naturally occurring, ice-like solids in which 

water molecules trap gas molecules in a cage-like structure 

known as a clathrate. Although many gases form hydrates in 

nature, methane hydrate is by far the most common. In 1995, 

the USGS conducted the first systematic assessment of the 

in-place natural gas hydrate resources of the United States 

(Collett, 1995). That study suggests that the amount of gas 

in the Nation’s hydrate accumulations greatly exceeds the 

volume of known conventional domestic gas resources. The 

1995 USGS assessment also estimated that the permafrostassociated gas hydrates on the Alaska North Slope may 

contain as much as 590 trillion cubic feet (TCF) of in-place 

gas. Two large gas hydrate accumulations have been identified 

in the Prudhoe Bay area. The in-place volume of gas estimated 

within the known gas hydrates in the greater Prudhoe Bay area 

infrastructure area alone may exceed 100 TCF (Collett, 2002). 

However, it is important to note that none of the previously 

published gas hydrate assessments have predicted how 

much gas could actually be produced from the gas hydrate 

accumulations in northern Alaska.

In recognition of the importance of gas hydrates as a 

potential energy resource, the USGS and the U.S. Bureau 

of Land Management (BLM) entered into an Assistance 

Agreement in 2002 to assess the volume of gas that could be 

produced from gas hydrates in northern Alaska. The primary 

objective of this assessment was to conduct a geology-based 

analysis of the occurrence of gas hydrates within northern 

Alaska to determine the role gas hydrate may play as a 

future domestic-energy resource. This project included three 

concurrent phases. Phase I focused on the Eileen gas hydrate 

occurrences in the greater Prudhoe Bay area (fig. 1A–B). 

Phase II dealt with identifying and characterizing potential 

gas hydrate accumulations on federally-managed lands in 

National Petroleum Reserve in Alaska (NPRA) and Arctic 

National Wildlife Refuge (ANWR), and on lands managed 

by the State of Alaska between the Colville and Canning 

Rivers (fig. 1A–B). Phase III entailed a systematic, geologybased appraisal of the volume of gas that can be technically 

produced from gas hydrates on the North Slope.

Abstract

Scientists with the U.S. Geological Survey have completed 

the first assessment of the undiscovered, technically recoverable 

gas hydrate resources beneath the North Slope of Alaska. This 

assessment indicates the existence of technically recoverable 

gas hydrate resources―that is, resources that can be discovered, 

developed, and produced using current technology.

The approach used in this assessment followed standard 

geology-based USGS methodologies developed to assess 

conventional oil and gas resources. In order to use the USGS 

conventional assessment approach on gas hydrate resources, 

three-dimensional industry-acquired seismic data were 

analyzed. The analyses indicated that the gas hydrates on the 

North Slope occupy limited, discrete volumes of rock bounded 

by faults and downdip water contacts. This assessment approach 

also assumes that the resource can be produced by existing 

conventional technology, on the basis of limited field testing and 

numerical production models of gas hydrate-bearing reservoirs.

The area assessed in northern Alaska extends from the 

National Petroleum Reserve in Alaska on the west through 

the Arctic National Wildlife Refuge on the east and from 

the Brooks Range northward to the State-Federal offshore 

boundary (located 3 miles north of the coastline). This area 

consists mostly of Federal, State, and Native lands covering 

55,894 square miles. Using the standard geology-based 

assessment methodology, the USGS estimated that the total 

undiscovered technically recoverable natural-gas resources 

in gas hydrates in northern Alaska range between 25.2 and 

157.8 trillion cubic feet, representing 95 percent and 5 percent 

probabilities of greater than these amounts, respectively, with 

a mean estimate of 85.4 trillion cubic feet.

1. Introduction

Approximately 35 years (yr) ago, Russian scientists 

made what was then a bold assertion that gas hydrates, long a 

curiosity of physical chemists, should occur in nature. Since 

then, the U.S. Geological Survey (USGS) and others have 

built a strong scientific foundation supporting the conclusion 
Figure 1. A, generalized geographic map of the Alaska North Slope showing the location of coastline, rivers, lakes, major political boundaries, villag

features. B, map of the physiographic provinces and major tectonic features of the Alaska North Slope (modified from Collett, 1993, 2002). (NPRA, Na

in Alaska; ANWR, Arctic National Wildlife refuge; TAPS, Trans Alaska Pipeline System)

Sagavanirktok River Colville River Utukok River Kokolik River Canning River

Teshekpuk

Lake

ARCTIC OCEAN

Prudhoe Harrison Bay Bay

Smith

Bay

Camden

Bay

BEAUFOR

CHUKCHI SEA

Meade River

1002 

Northwest Arctic Borough North Slope Borough

Arctic National 

National Petroleum Reserve-Alaska

Umiat

Barrow

Atqasuk

Nuiqsut Deadhorse

Wainwright

Point

Hope

Cape 

Lisburne

Point

Lay

Icy 

Cape

Point 

Barrow

Prudhoe

Bay

Point

Hope

Trans-Alaska

Pipeline System

168° 164° 160° 156° 152° 148° 144° 

71°

72°

70°69°68°

Brooks Range orogenic belt (Brooks Range province)

EXPLANATION

Area of map

0 25 50 75 100 MILES0 25 50 75 100 KILOMETERS

Base from U.S. Geological Survey digital dataAlbers Conical Equal area projectionStandard parallels 55°N and 65°NCentral meridian 154°W, latitude of origin 50°NNorth American Datum of 1983 (NAD 83)

Outer limit of Alaska State waters

A
Figure 1. A, generalized geographic map of the Alaska North Slope showing the location of coastline, rivers, lakes, major political boundaries, villag

features. B, map of the physiographic provinces and major tectonic features of the Alaska North Slope (modified from Collett, 1993, 2002). (NPRA, Nat

in Alaska; ANWR, Arctic National Wildlife refuge; TAPS, Trans Alaska Pipeline System)—Continued

ARCTIC OCEAN

Camden

Bay

BEAUFORT S

CHUKCHI SEA

1002 A

Northwest Arctic Borough North Slope Borough

Arctic National 

Umiat

Barrow

Atqasuk

Nuiqsut Deadhorse

Wainwright

Point

Lay

Icy 

Cape

Point 

Barrow

Prudhoe Bay

Point

Hope

Point

Hope

Trans-Alaska

Pipeline System

BROOKS

RANGE PROVINCE

168° 164° 160° 156° 152° 148° 144° 

71°

72°

70°69°68°

Area of map

0 25 50 75 100 MILES0 25 50 75 100 KILOMETERS

Outer limit of Alaska State waters

Chukchi Shelf

Extension of Brooks Herald arch Range Province

HopeBasin

Barrow arch

COLVILLE BASIN

Basin axis

FOOTHILLS

COASTAL

PLAIN

PROVINCE

PROVINCE

Hanna

trough

National Petroleum Reserve-Alaska

Structural trough—Large arrow  indicates direction of plunge

Brooks Range orogenic belt  (Brooks Range province)

Structural arch—Large arrow  indicates direction of plunge

Physiographic province boundary

EXPLANATION

Northern Alaska Gas Hydrate  Total Petroleum System

Base from U.S. Geological Survey digital dataAlbers Conical Equal area projectionStandard parallels 55°N and 65°NCentral meridian 154°W, latitude of origin 50°NNorth American Datum of 1983 (NAD 83)

B
4 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

This report provides a comprehensive review of the 

USGS assessment of the undiscovered, technically recoverable 

gas hydrate resources on the Alaska North Slope. This report 

begins with a review of the USGS assessment methodology 

used in this study, which is followed by a discussion of what 

gas hydrates are and a description of some of their more 

important physical properties. The concept of the gas hydrate 

petroleum system is introduced, followed by a review of the 

geologic controls that affect the formation and presence of 

gas hydrates in northern Alaska. This report also includes a 

detailed review of the results of gas hydrate-production testing 

and modeling in Alaska and other comparable settings. The 

main body of this report deals with the actual Alaska North 

Slope assessment input requirements and results.

2. USGS Oil and Gas

Assessment Methodology

For the first time, the USGS has assessed gas hydrates, 

a traditionally unconventional resource with no confirmed 

production history, as a producible resource occurring in 

discrete hydrocarbon traps and structures. The approach used 

in this assessment of gas hydrate resources in northern Alaska 

followed standard geology-based USGS methodologies 

developed to assess conventional oil and gas resources (fig. 2) 

(Schmoker and Charpentier, 2005; Schmoker and Klett, 

2005). Conventional accumulations, as recognized by the 

USGS for the purpose of resource assessment, are defined 

by two geologic characteristics: (1) they occupy limited, 

discrete volumes of rock bounded by traps, seals, and downdip 

water contacts, and (2) they depend upon the buoyancy of 

oil or gas in water for their existence. In applying the USGS 

conventional assessment approach on gas hydrate resources, 

downhole log data from wells and three-dimensional, 

industry-acquired seismic data were analyzed, with the results 

showing that gas hydrates on the North Slope occupy discrete 

hydrocarbon reservoirs, most of which are bounded by faults 

and downdip water contacts (as discussed in the “Alaska 

North Slope Gas Hydrate Petroleum System” section).

The USGS conventional assessment methodology is built 

on the geologic elements used to define a Total Petroleum 

System (TPS), including hydrocarbon source rocks (sourcerock type and maturation and hydrocarbon generation 

and migration), reservoir rocks (sequence stratigraphy, 

petrophysical properties, and seismic attribute development), 

and hydrocarbon traps (trap formation and timing). In this 

approach, the subdivisions of a TPS, termed “assessment 

units” (AU), are the basic level of the assessment. In most 

cases, a TPS consists of all genetically related hydrocarbons 

generated from the same source rock. In the case of this 

assessment, each AU was defined mostly on the similarities 

of the gas hydrate-bearing rocks. Detailed framework studies 

in stratigraphy and structural geology and the analysis of 

petroleum geochemistry, combined with historical exploration 

results, were used to define three gas hydrate AUs in northern 

Alaska, as described later in the section “Northern Alaska Gas 

Hydrate Total Petroleum System and Assessment Units.”

The USGS assessment methodology (fig. 2) also 

requires estimates of the number and sizes of undiscovered 

accumulations, for which the technically recoverable 

resources are then calculated by statistically combining 

the probability distributions of the estimated number 

and sizes of the undiscovered accumulations, along with 

associated risks. The techniques used to estimate the number 

and sizes of undiscovered gas hydrate accumulations in 

northern Alaska are discussed in the following sections of 

Figure 2. Flow diagram showing key steps in the USGS assessment 

model for undiscovered conventional oil and gas accumulations. 

Modified from Schmoker and Klett (2005).

Geologic definition of total petroleum 

system and assessment units

Select minimum accumulation size

Allocation of resources by

land entity and by offshore

Probability distribution for

undiscovered gas hydrate resources

Geologic-based probability

distribution for sizes of

undiscovered gas hydrate

accumulations

Geologic-based probability

distribution for number of

undiscovered gas hydrate

accumulations

Assign assessment-unit probabilities

–Geologic Risk–
4. Alaska North Slope Gas Hydrate Petroleum System 5

this report: “Undiscovered Gas Hydrate Accumulations—

Sizes of Accumulations” and “Undiscovered Gas Hydrate 

Accumulations—Number of Accumulations.” Within the 

USGS assessment methodology, probabilistic estimates are 

given for the amount of technically recoverable resources in 

the hydrocarbon accumulations. In most cases the production 

histories from existing wells in the assessment unit or from 

analog settings are used to estimate the relative percent of 

hydrocarbon that will be recovered from an accumulation. 

For gas hydrates, however, there are no established production 

histories to draw upon. In this assessment, data from limited 

field testing and numerical production modeling were used 

to establish the expected production characteristics of gas 

hydrate-bearing reservoirs, as discussed in the section “Gas 

Hydrate Production Analysis.”

For the purpose of the USGS assessment model, 

undiscovered petroleum is that which is postulated from 

geologic knowledge and theory to exist outside of known 

accumulations. For this gas assessment, it was decided to 

consider all of the gas hydrate accumulations on the Alaska 

North Slope as undiscovered because none of the welllog- and seismic-inferred gas hydrate accumulations have 

established production histories.

3. Gas Hydrate Technical Review

Gas hydrates are naturally occurring “ice-like” 

combinations of natural gas and water that have the potential 

to provide an immense resource of natural gas from the 

world’s oceans and polar regions. Gas hydrates are known 

to be widespread in permafrost regions and beneath the sea 

in sediments of outer continental margins. It is generally 

accepted that the volume of natural gas contained in the 

world’s gas hydrate accumulations greatly exceeds that of 

known gas reserves (Collett, 2002). There is also growing 

evidence that natural gas can be produced from gas hydrates 

with existing conventional oil and gas production technology 

(Anderson and others, 2008, Dallimore and others, 2008a, 

2008b; Yamamoto and Dallimore, 2008; Moridis and 

others, 2009).

Gas hydrates are crystalline compounds that result from 

the three-dimensional stacking of “cages” of hydrogen-bonded 

water molecules. Generally, each cage can hold a single gas 

molecule. The empty cagework is unstable, and requires 

the presence of encapsulated gas molecules to stabilize the 

clathrate crystal. The compact nature of the hydrate structure 

makes for highly effective packing of gas. A volume of gas 

hydrate expands between 150- and 180-fold when released 

in gaseous form at standard pressure and temperature 

(14.696 pounds per square inch (psi), 68°F).

Clathrate hydrates can form in the presence of gas 

molecules over the size range of 4.8–9.0 angstroms. Three 

distinct structural types can form depending on the size of the 

largest guest molecules that can be included in the clathrate 

cage of water molecules. There are considerable complexities 

in the structure-size relation; however, methane and ethane 

individually form Structure I (sI) hydrate, but in certain 

combinations also form Structure II (sII) hydrate. Propane 

and isobutane form sII hydrate, either individually or in 

combination with ethane and methane. Normal-butane and 

neopentane form sII hydrate only when methane is present 

as well, and larger hydrocarbon molecules (C5–C9) form 

Structure H (sH) hydrate, again where methane is present.

On a macroscopic level, many of the mechanical 

properties of gas hydrates resemble those of ice because 

hydrates contain about 85 percent water on a molar basis. For 

a complete description of the structure and physical properties 

of gas hydrates, see the summary by Sloan and Koh (2008).

4. Alaska North Slope Gas Hydrate

Petroleum System

In recent years, the concept of a gas hydrate petroleum 

system, similar to the concept that guides conventional oil 

and gas exploration, has gained acceptance (Collett and others, 

2009). In a gas hydrate petroleum system, the individual 

factors that contribute to the formation of gas hydrate can 

be identified and assessed; the most important include 

(1) gas hydrate pressure-temperature stability conditions, 

(2) suitable host sediment or “reservoir,” (3) gas source, and 

(4) gas migration. In the following discussion, these geologic 

controls on the stability and formation of gas hydrate deposits 

in northern Alaska are reviewed and evaluated.

4.a. Gas Hydrate Stability Conditions

Gas hydrates exist under a limited range of temperature 

and pressure conditions, such that the depth and thickness of 

the zone of potential gas hydrate stability can be calculated 

given information on formation temperatures, pore-pressure 

gradients, and gas and formation water chemistry. Depicted 

in the temperature/depth plot in figure 3 are a series of 

subsurface temperature profiles from an onshore permafrost 

area and two laboratory-derived gas hydrate stability curves 

for different natural gases (modified from Holder and others, 

1987). This gas hydrate phase diagram (fig. 3) illustrates 

how variations in formation temperature, pore-pressure, and 

gas composition can affect the thickness of the gas hydrate 

stability zone. In this example, the mean annual surface 

temperature is assumed to be 14°F (–10°C); and the depth 

to the base of permafrost (32°F; 0°C isotherm) is varied for 

three example temperature profiles, at permafrost depths 

of 1,000 feet (ft) (305 meters (m)), 2,000 ft (610 m), and 

3,000 ft (914 m). Below permafrost, three different example 

geothermal gradients of 2.19°F/100 ft (4.0°C/100 m), 

1.76°F/100 ft (3.2°C/100 m), and 1.10°F/100 ft (2.0°C/100 m) 

are used to project the sub-permafrost temperature profiles. 
6 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

The two gas hydrate stability curves represent gas hydrates 

with different gas chemistries: one with 100 percent methane 

hydrate, and the other with 98 percent methane, 1.5 percent 

ethane, and 0.5 percent propane. The phase diagram 

(fig. 3) is constructed assuming a hydrostatic pore-pressure 

gradient of 0.433 pounds per square inch per foot (psi/ft) 

(9.795 kilopascals per meter (kPa/m)).

The zone of potential gas hydrate stability in the phase 

diagram (fig. 3) lies within the depths between the two 

intersections of the geothermal gradient and the gas hydrate 

stability curve. For example, in figure 3, the temperature profile 

projected to an assumed permafrost base of 2,000 ft (610 m) 

intersects the 100-percent methane-hydrate stability curve 

at about 656 ft (200 m), thus marking the upper boundary of 

the methane-hydrate stability zone. A geothermal gradient 

of 2.19°F/100 ft (4.0°C/100 m) projected from the base of 

permafrost at 2,000 ft (610 m) intersects the 100-percent 

methane-hydrate stability curve at about 3,609 ft (1,100 m); 

thus, the zone of potential methane-hydrate stability is 

approximately 2,953 ft (900 m) thick. However, if permafrost 

is extended to a depth of 3,000 ft (914 m) and if the geothermal 

gradient below permafrost is 1.10°F/100 ft (2.0°C/100 m), 

the zone of potential methane-hydrate stability would be 

approximately 6,890 ft (2,100 m) thick.

Most gas hydrate stability studies assume a hydrostatic 

pore-pressure gradient (see Collett, 2002). Pore-pressure 

gradients greater than hydrostatic conditions correspond to 

higher pore-pressures with depth and a thicker gas hydrate 

stability zone, whereas a pore-pressure gradient less than 

hydrostatic corresponds to a thinner gas hydrate stability zone. 

Figure 3. Gas hydrate phase diagram showing the depth and temperature 

conditions suitable for the formation of gas hydrate under various conditions 

of permafrost depth, geothermal gradient, gas chemistry, and a porepressure gradient of 0.433 psi/ft (9.795 kPa/m). Modified from Holder and 

others (1987). (psi/ft, pounds per square inch per feet; kPa/m, kilopascals 

per meter)

30 45

–10 0 10 20 30

0

500

1,000

1,500

3,000

4,500

6,000

7,500

9,000

1,500

2,000

2,500

3,000

Depth in meters

Depth in feet

Hydrate stability curve

Hydrate stability curve

Temperature (°F)

Temperature (°C)

EXPLANATION

Permafrost depth

305 meters

610 meters

914 meters

Geothermal gradient

4.0 °C/100 meters

3.2 °C/100 meters

2.0 °C/100 meters

Gas chemistry

100% methane

15 60 75

98% methane

1.5% ethane

0.5% propane
4. Alaska North Slope Gas Hydrate Petroleum System 7

The gas hydrate stability curves in figure 3 were obtained 

from laboratory data published by Holder and others (1987). 

The addition of 1.5 percent ethane and 0.5 percent propane 

to the pure methane gas system shifts the stability curve to 

the right, thus deepening the zone of potential gas hydrate 

stability. It is well known that dissolved salt can depress 

the freezing-point of water. Where present in a gas hydrate 

system, salt (such as NaCl) also lowers the temperature at 

which gas hydrates form.

Collett and others (1988) and Collett (1993) included 

extensive analyses of gas hydrate stability conditions in 

northern Alaska. In support of the present assessment, Lee and 

others (2008) also used log data from wells drilled since these 

earlier studies for updating the permafrost (fig. 4) and methane 

hydrate stability maps (fig. 5A–C; table 1) in northern Alaska 

as reviewed below.

On the North Slope, the subsurface temperature data 

needed to assess the distribution of the gas hydrate stability 

zone are provided by high-resolution, equilibrated wellbore surveys in 46 wells and from well-log estimates of the 

base of ice-bearing permafrost in 102 other wells (Collett, 

1993). Beginning in 1958, a series of 46 North Slope wells, 

considered to be in or near thermal equilibrium, have 

been surveyed with high-resolution temperature devices 

(Lachenbruch and others, 1987; Lee and others, 2008). 

Geothermal gradients, which are needed to predict the 

depth and thickness of the gas hydrate stability zone, can 

be interpreted directly from these equilibrated temperature 

profiles. However, specific evaluation of subsurface 

temperatures at any one particular site on the North Slope is 

subject to error because of the vastness of the region and the 

limited number of equilibrated well-bore temperature surveys. 

To augment the limited North Slope temperature database, 

Collett and others (1988) developed a new method to evaluate 

local geothermal gradients.

In this method, well-log picks for the base of the icebearing permafrost from 102 wells (fig. 4) were combined 

with regional temperature constants derived from the highresolution surveys to extrapolate temperature data. The 

comparison of geothermal gradients calculated from the highresolution temperature surveys and projected from known 

ice-bearing permafrost depths are similar over most of the 

North Slope, with gradient values in the ice-bearing sequence 

ranging from about 0.82°F/100 ft (1.5°C/100 m) in the 

Prudhoe Bay area to about 2.47°F/100 ft (4.5°C/100 m) in the 

National Petroleum Reserve in Alaska (NPRA). The calculated 

and projected geothermal gradients from below the ice-bearing 

sequence range from about 0.88°F/100 ft (1.6°C/100 m) to 

about 2.85°F/100 ft (5.2°C/100 m).

Subsurface pore-pressure gradients calculated from 

shut-in pressures recorded during drill-stem testing in wells 

from the North Slope range from 0.41 to 0.50 psi/ft (9.3 

to 11.2 kPa/m), with an average gradient of 0.43 psi/ft 

(9.7 kPa/m), near hydrostatic (Collett and others, 1988). 

To further evaluate pore-pressure conditions, Collett (1993) 

used gamma ray and density well logs to study overburden 

compaction profiles. Within the near-surface (0–5,000 ft; 

0–1,524 m) sediments of the North Slope, no significant porepressure discontinuities were observed. Thus, a hydrostatic 

pore-pressure gradient (0.433 psi/ft; 9.795 kPa/m) is generally 

assumed when considering gas hydrate stability conditions 

in northern Alaska.

Most of the previous studies of gas hydrate stability 

conditions in northern Alaska have assumed a pure methane 

chemistry for the gas being included in the gas hydrate 

structure (Collett, 1995). The analysis of mud-log gaschromatographic data from industry exploratory wells 

generally indicates that methane is the dominant hydrocarbon 

gas in the near-surface (0–5,000 ft) sedimentary rocks of 

the North Slope (Collett and others, 1988). Analysis of 

gas evolved from recovered cored gas hydrate-bearing 

sedimentary sections in the Prudhoe Bay and Milne Point 

fields confirm that the in-situ gas hydrates are composed 

mostly of methane in this portion of the North Slope (Collett, 

1993; Lorenson and others, 2011).

Pore-water salinity data within the near-surface sediments 

of the North Slope are available from petroleum production 

tests, water samples from cores within and below permafrost, 

and spontaneous potential well-log calculations. These data 

indicate that the pore-water salinities within the sands both 

above and below the ice-bearing permafrost section are low, 

ranging from <1.0 parts per thousand (ppt) to as high as 

19 ppt (Collett and others, 1988). Analysis of core-derived 

pore waters from the Mount Elbert well (discussed later in this 

report) also confirm the presence of low-salinity pore water, 

with an average background concentration around 5.0 ppt. The 

updated gas hydrate stability calculations in Lee and others 

(2008) for northern Alaska were made assuming a pore-water 

salinity of 5.0 ppt.

The methane-hydrate stability zone in northern Alaska, 

as mapped in figures 5A–C (modified from Collett, 1993), 

covers most of the North Slope. The offshore extent of the gas 

hydrate stability zone is not well established. Geologic studies 

(for example Molochushkin, 1978) and thermal modeling of 

subsea conditions (Osterkamp and Fei, 1993) indicate that 

permafrost and gas hydrate may exist within the continental 

shelf of the Arctic Ocean. Subaerial emergence of portions 

of the Arctic continental shelf to current water depths of 

roughly 400 ft (roughly 122 m) (Bard and Fairbanks, 1990) 

during repeated Pleistocene glaciations subjected the exposed 

shelf to temperature conditions favorable to the formation of 

permafrost and gas hydrate. Thus, it is speculated that “relict” 

permafrost and gas hydrate may exist on the continental shelf 

of the Arctic Ocean to present water depths of 400 ft (roughly 

122 m). For this assessment, we assumed the model-derived 

predictions of permafrost and gas hydrate stability conditions 

to be accurate and that the offshore limit of the nearshore 

permafrost-associated gas hydrate stability conditions as 

depicted in figures 5A–C for the most part corresponds to 

the 400-ft (roughly 122 m) bathymetric contour.
Figure 4. Map showing the depth to base of permafrost on the Alaska North Slope as determined from equilibrated well-bore temperature surveys others, 2008). Well-log estimates for the base of ice-bearing permafrost in 102 other wells (Collett, 1993) were also used to draw the map contours. CNatural Petroleum Reserve in Alaska; ANWR, Alaska National Wildlife Refuge)

ARCTIC OCEAN

Prudhoe

Bay

BEAUFO

CHUKCHI SEA

Point 

Barrow

Point

Hope

1002 A

Northwest Arctic Borough North Slope Borough

Arctic National 

National Petroleum Reserve-Alaska

1,000 1,200 1,400 1,600 1,800

1,000 1,200 1,000 1,600 1,400

800

800

1,800

168° 164° 160° 156° 152° 148° 144° 

71°

72°

70°69°68°

Brooks Range orogenic belt (Brooks Range province)

EXPLANATION

Area of map

0 25 50 75 100 MILES0 25 50 75 100 KILOMETERS

Outer limit of Alaska State watersWell with Hi-res temperature dataDepth to the base of ice-bearing permafrost—Dashed  where depth is uncertain. Contour in feet

800

Base from U.S. Geological Survey digital dataAlbers Conical Equal area projectionStandard parallels 55°N and 65°NCentral meridian 154°W, latitude of origin 50°NNorth American Datum of 1983 (NAD 83)
Figure 5. Maps of the Alaska North Slope gas hydrate stability zone (modified from Collett and others, 1988): A, depth to the top of the hydrate stabi

of the hydrate stability zone; C, thickness of the hydrate stability zone. Contours in feet (ft). (NPRA, Natural Petroleum Reserve in Alaska; ANWR, Alas

ARCTIC OCEAN

Prudhoe

Bay

BEAU

CHUKCHI SEA

Point 

Barrow

Point

Hope

Northwest Arctic Borough North Slope Borough

Arctic National 

800

800

800 700

700

168° 164° 160° 156° 152° 148° 144° 

71°

72°

70°69°68°

Brooks Range orogenic belt (Brooks Range province)

EXPLANATION

Area of map

0 25 50 75 100 MILES0 25 50 75 100 KILOMETERS

Outer limit of Alaska State watersWell with Hi-res temperature dataDepth to the top of the gas hydrate stability zone— Contour in feet

800

Limit of the gas hydrate stability zone

National Petroleum Reserve-Alaska

Base from U.S. Geological Survey digital dataAlbers Conical Equal area projectionStandard parallels 55°N and 65°NCentral meridian 154°W, latitude of origin 50°NNorth American Datum of 1983 (NAD 83)A
Figure 5. Maps of the Alaska North Slope gas hydrate stability zone (modified from Collett and others, 1988): A, depth to the top of the hydrate stability zone; 

hydrate stability zone; C, thickness of the hydrate stability zone. Contours in feet (ft). (NPRA, Natural Petroleum Reserve in Alaska; ANWR, Alaska National W

ARCTIC OCEAN

Prudhoe

Bay

BEAUF

CHUKCHI SEA

Point 

Barrow

Point

Hope

Northwest Arctic Borough North Slope Borough

Arctic National 

2,800

2,200

3,400

4,000 1,600

1,600

168° 164° 160° 156° 152° 148° 144° 

71°

72°

70°69°68°

Brooks Range orogenic belt (Brooks Range province)

EXPLANATION

Area of map

0 25 50 75 100 MILES0 25 50 75 100 KILOMETERS

Outer limit of Alaska State waters

Well with Hi-res temperature data

Depth to the base of the gas hydrate stability zone— Contour in feet

1,600

Limit of the gas hydrate stability zone

National Petroleum Reserve-Alaska

Base from U.S. Geological Survey digital dataAlbers Conical Equal area projectionStandard parallels 55°N and 65°NCentral meridian 154°W, latitude of origin 50°NNorth American Datum of 1983 (NAD 83)B
Figure 5. Maps of the Alaska North Slope gas hydrate stability zone (modified from Collett and others, 1988): A, depth to the top of the hydrate stability zone

hydrate stability zone; C, thickness of the hydrate stability zone. Contours in feet (ft). (NPRA, Natural Petroleum Reserve in Alaska; ANWR, Alaska National W

ARCTIC OCEAN

Prudhoe

Bay

BEAUF

CHUKCHI SEA

Point 

Barrow

Point

Hope

Northwest Arctic Borough North Slope Borough

Arctic Nationa

600

1,800 2,400

1,200

600

1,800

0

0

0

1,200

3,00

0

3,000

168° 164° 160° 156° 152° 148° 144° 

71°

72°

70°69°68°

Brooks Range orogenic belt (Brooks Range province)

EXPLANATION

Area of map

0 25 50 75 100 MILES0 25 50 75 100 KILOMETERS

Outer limit of Alaska State waters

Well with Hi-res temperature data

1,600 Gas hydrate stability zone thickness—Contour in feet

C

Base from U.S. Geological Survey digital dataAlbers Conical Equal area projectionStandard parallels 55°N and 65°NCentral meridian 154°W, latitude of origin 50°NNorth American Datum of 1983 (NAD 83)

National Petroleum Reserve-Alaska

3,600
Table 1. List of Alaska North Slope wells with equilibrated borehole temperature surveys along with the estimated depth of the base of permafrost (top (THSZ) and base (BHSZ) of the gas hydrate stability zone. Also listed is the estimated thickness (isopach) of the gas hydrate stability zone (HSZ) (mothers, 2008). [API, American Petroleum Institute; m, meters; ft, feet] API Common well name Latitude Longitude Depth (m) to 0°C Depth (ft) to 0°C Depth (m) to THSZ Depth (ft) to THSZ Depth (m) to BHSZ Depth (ft) to BHSZ 

50301200010000 US TUNALIK #1 70.2062 161.0687 270 886 258 845 320 1,050 

50301200020000 US PEARD #1 70.7156 158.9999 300 984 248 814 557 1,827 

50163200020000 HU KUGRUA #1 70.5866 158.6617 270 886 259 849 390 1,278 

50163200010000 US SO MEADE #1 70.6147 156.8834 200 656 - - - - 

50023100110000 US SO BARROW #3 71.1652 156.5811 380 1,247 232 761 578 1,896 

50163200030000 US KUYANAK #1 70.9314 156.0368 320 1,050 233 763 500 1,640 

50023200180000 US TULAGEAK 1 71.1885 155.7329 290 951 250 819 388 1,272 

50023200140000 US WEST DEASE #1 71.1594 155.6296 270 886 257 842 352 1,155 

50279200050000 US E SIMPSON 1 70.9178 154.6180 360 1,181 228 748 556 1,824 

50279200040000 HU IKPIKPUK 1 70.4555 154.3322 330 1,083 243 796 652 2,139 

50279200020000 HU DREW POINT 1 70.8794 153.8997 320 1,050 232 761 460 1,509 

50279200060000 US J W DALTON 1 70.9209 153.1380 400 1,312 213 700 604 1,982 

50103200060000 HU E TESHEKPUK 1 70.5700 152.9447 250 820 - - - - 

50103200170000 US NORTH INIGOK 1 70.2576 152.7660 275 902 258 845 380 1,247 

50103200110000 US NORTH KALIKPIK 1 70.5092 152.3668 210 689 - - - - 

50103200090000 HU WEST FISH CREEK 1 70.3267 152.0597 260 853 - - - - 

50103200070000 HU S HARRISON BAY 1 70.4245 151.7310 380 1,247 225 737 530 1,739 

50103200080000 HU ATIGARU PT 1 70.5561 151.7160 400 1,312 217 711 541 1,775 

50029202750000 WEST SAK 11 70.3569 149.9908 465 1,526 216 709 747 2,449 

50029204190000 SO WEST SAK 14 70.2935 149.9515 465 1,526 215 705 741 2,431 

50029205410000 WEST SAK 16 70.4433 149.9483 535 1,755 212 694 845 2,772 

50029205420000 SO WEST SAK 17 70.4463 149.7237 550 1,804 210 689 850 2,789 

50029200900000 AR WEST SAK RIVER ST 1 70.3397 149.5372 550 1,804 212 694 800 2,625 

50029215040000 MPU C-19 70.4915 149.5245 525 1,722 215 705 850 2,789 

50029209000000 MPU D-2 70.4905 149.4526 560 1,837 216 709 874 2,867 

50029205730000 MO KUPARUK 1 70.3020 149.4169 570 1,870 215 705 857 2,812 

50029200130000 AT NW EILEEN ST 1 70.3659 149.3559 530 1,739 207 679 860 2,822 

50029201990000 AT HIGHLAND ST 1 70.2869 149.2181 575 1,886 210 689 908 2,979 

50029200790000 PUT RIVER N-1: 08-11-13 70.3186 148.9097 615 2,018 209 687 1,019 3,343 

50029200250000 PUT RIVER J-3:04-11-13 70.3300 148.8467 635 2,083 209 684 1,063 3,488 

50029200470000 PUT RIVER 33-12-13 70.3561 148.8350 650 2,133 206 674 1,180 3,871 

50029200840000 PUT RIVER F-2-11-11-13 70.3347 148.7669 630 2,067 216 709 1,048 3,438 

50029200850000 PUT RIVER F-3-12-11-13 70.3353 148.7644 630 2,067 229 752 1,105 3,625 

50029200540000 PUT RIVER 23-11-13 70.2944 148.7525 540 1,772 210 688 1,065 3,494 

50029200590000 PUT RIVER 31-11-14 70.2683 148.6733 640 2,100 210 687 1,085 3,560 

50029200060000 PUT RIVER 27-11-14 70.2783 148.5656 615 2,018 211 693 1,050 3,445 

50029200490000 NORTH PRUDHOE BAY STATE 1 70.3764 148.5250 596 1,955 206 676 1,057 3,468 

50029200350000 PUT RIVER 19-10-15 70.2117 148.4125 585 1,919 218 715 1,048 3,438 

50029201330000 EAST BAY STATE #1 70.3106 148.3161 620 2,034 211 691 1,130 3,707 

50029200300000 SAG DELTA 31-10-16 70.1822 148.1581 590 1,936 224 734 1,010 3,314 

50155200010000 US AWUNA #1 69.1532 158.0214 236 774 264 865 468 1,535 

50137200030000 US LISBURNE #1 68.4863 155.6935 264 866 264 866 783 2,569 

50119200010000 US KOLUKTAK 1 69.7524 154.6111 280 919 257 843 540 1,772 

50287200070000 US SEABEE 1 69.3801 152.1753 300 984 258 845 1,070 3,510 

50287100180000 BP KUPARUK 1 69.3044 150.8093 265 869 262 860 595 1,952 

50223200110000 FO LUPINE 1 69.1009 148.6193 220 722 337 1,106 660 2,165 

50223200080000 MO ECHOOKA 1 69.4002 148.2680 265 869 263 864 787 2,582 
4. Alaska North Slope Gas Hydrate Petroleum System 13

4.b. Reservoir Rocks

The study of gas hydrate samples indicates that the 

physical nature of in-situ gas hydrates is highly variable 

(reviewed by Sloan and Koh, 2008). Gas hydrates are 

observed as (1) occupying pores of coarse-grained sediment; 

(2) nodules disseminated within fine-grained sediment; 

(3) a solid substance, filling fractures; or (4) a massive unit 

composed mainly of solid gas hydrate with minor amounts 

of sediment. However, most gas hydrate field expeditions 

have shown that the occurrence of concentrated gas hydrate 

is mostly controlled by the presence of fractures and (or) 

coarse-grained sediments in which gas hydrate fills fractures 

or is disseminated in the pores of sand-rich reservoirs 

(Collett, 1993; Dallimore and Collett, 2005; Riedel and 

others, 2006; Collett and others, 2008a, 2008b; Park and 

others, 2008; Yang and others, 2008). Torres and others, 

(2008) concluded that hydrate accumulates preferentially in 

coarse-grained sediments because lower capillary pressures 

in these sediments permit the migration of gas and nucleation 

of hydrate. The growth of gas hydrate in clay-rich sediments, 

however, is less understood. Because high concentrations 

of gas hydrates in arctic permafrost regions are in sanddominated reservoirs, such lithologic units have been the focus 

of gas hydrate exploration and production studies in northern 

Alaska. Production testing and modeling have also shown that 

concentrated gas hydrate in sand reservoirs is conducive to 

existing well-based production technologies (Anderson and 

others, 2008; Dallimore and others, 2008a, 2008b; Moridis 

and others, 2009; Yamamoto and Dallimore, 2008).

The northern Alaska oil and gas province extends 

600 miles (mi) from the Chukchi Sea on the west to the 

Canadian border on the east (figs. 1A–B); maximum width 

is about 200 mi and total area is about 54,000 square miles 

(mi2

). The geology and petroleum geochemistry of rocks 

on the North Slope of Alaska are described in considerable 

detail in a number of publications (Lerand, 1973; Grantz and 

others, 1975; Carman and Hardwick, 1983; Bird and Magoon, 

1987; Gryc, 1988; Bird, 1998; Mull and others, 2003). The 

sedimentary rocks of the North Slope can be conveniently 

grouped into four sequences representing major episodes 

in the tectonic development of the region and, to a degree, 

reflecting its lithologic character. Defined on the basis of 

source area, these sequences (proposed by Lerand (1973) and 

applied to northern Alaska by Grantz and others (1975) and 

modified by Hubbard and others (1987)) are, in ascending 

order, the Franklinian (Cambrian through Devonian), the 

Ellesmerian (Mississippian to Jurassic), Beaufortian (Jurassic 

through Lower Cretaceous), and the Brookian (Cretaceous 

to Holocene). All of the known and inferred gas hydrate 

occurrences on the North Slope are in Cretaceous and Tertiary 

reservoirs of the Brookian sequence (fig. 6), which are the 

focus of the following discussions on the geologic history of 

northern Alaska.

Before the recent completion of coring and downholelogging operations in the BPXA-DOE-USGS Mount Elbert 

Gas Hydrate Stratigraphic Test Well in the Milne Point field 

(Hunter and others, 2011), the only direct confirmation of 

gas hydrate on the North Slope was obtained in 1972 with 

data from the ARCO-Exxon Northwest Eileen State-2 well, 

located in the northwest part of the Prudhoe Bay field. Studies 

of pressurized core samples, downhole logs, and the results of 

formation-production testing confirmed the presence of three 

gas hydrate-bearing stratigraphic units in the Northwest Eileen 

State-2 well (fig. 7) (Collett, 1993). The gas hydrate-bearing 

core in the Northwest Eileen State-2 well was recovered from 

a depth of 2,156 ft (657 m). The well was drilled with chilled 

drilling muds in an attempt to reduce thawing of permafrost 

and decomposition of the in-situ gas hydrate that might exist. 

A pressure-core system was also used to recover core samples 

at near in-situ conditions in order to reduce core disturbance 

attributed to gas hydrate dissociation. The presence of gas 

hydrate in the recovered core was confirmed by a pressure test 

as described by Hunt (1979, p. 167).

The confirmed gas hydrate occurrence in the Northwest 

Eileen State-2 well provided an ideal starting point for the 

development of gas hydrate well-log evaluation techniques 

(fig. 7). Numerous studies since this early work, including 

Collett (1993), have shown that in most cases only two welllogging devices are used to identify potential gas hydrates: 

they are the electrical resistivity and acoustic transit-time 

logs. For the most part, a gas hydrate-bearing sand reservoir 

is characterized by relatively high electrical resistivities and 

rapid acoustic transit times in comparison to water-saturated 

sands. However, resistivity and acoustic logs behave similarly 

within a sedimentary section that is saturated with either gas 

hydrate or ice. Hence, gas shows on the mud log produced 

from decomposing hydrate generally provide the only means 

of conclusively differentiating a gas hydrate from ice in Arctic 

permafrost regions.

Collett (1993) examined well-log data from 445 wells 

for evidence of gas hydrate based on the well-log responses 

observed in the Northwest Eileen State-2 well. Most of the 

wells were located in the greater Prudhoe Bay area; however, 

all wells in NPRA and most of the exploratory wells to the 

south and east of Prudhoe Bay were reviewed. Since this 

earlier work, Lee and others (2008) and Inks and others 

(2009) examined the well-log data from about 200 additional 

exploratory and development wells for the presence of gas 

hydrate. These well-log-based studies revealed the occurrence 

of two large gas hydrate accumulations, which have been 

named the Eileen and Tarn gas hydrate accumulations.

The Eileen gas hydrate accumulation was first described 

by Collett (1993) as six laterally continuous gas hydratebearing sandstone units, each of which has been assigned 

a reference letter (A–F, in ascending order; fig. 8). Many 

of the wells that penetrated the Eileen accumulation have 

multiple gas hydrate-bearing units, with individual units 

ranging from 10 to 100 ft (3 to 30 m) thick. All of the wells 

are geographically restricted to the area overlying the eastern 
Figure 6. Lithostratigraphic chart illustrating the relations between former and revised nomenclature of Mull and others (2003) for the Alaska North Slopsummarize the lateral variations in previous stratigraphic nomenclature for Tertiary and Cretaceous strata from west to east across the western and centRange, as presented by Chapman and others (1964) and modified from Mull and others (2003).

West 

Upper Jurassic to Permian

Lower Cretaceous

Nanushuk Group

Upper Cretaceous

Colville Group

Prince Creek

Formation

Kukpowruk

Formation Corwin Formation Corwin

Bluff Torok

Fm.

Quaternary

WEST

Utukok-Corwin area

(modified from Sable, 1956)

Quaternary deposits

(nonmarine)(nonmarine)

Corwin Formation Kukpowruk

Formation Torok Formation 

Upper Jurassic to Mississippian

Tuktu Formation

Fortress Mountain

and Torok Formations

Fortress Mountain

and Torok Formations

Tuktu Formation Tuktu Formation

Utukok

River

Etivluk

River

ARCTIC FOOTHILLS PROVINCE

Killik-Etivluk Rivers region

Quaternary deposits

Not present

Tuktu

Fm.

Niakogon Tongue

(nonmarine)

Tuluvak

Tongue

(nonmarine)

Tuluvak Tongue

(nonmarine)

Chandler

Formation

Killik

River Chandler River region and south

Quaternary deposits

Shale Wall

Member

Ayiyak Member

Niakogon Tongue (nonmarine)

Upper Jurassic to Triassic

Ninuluk Formation

Tuktu

Formation

Seabee

Fm.

Grandstand

Formation Ninuluk

Fm.

Prince

Creek

Fm.

Rogers Creek

Schrader

Bluff Fm. 

 Mbr.

Barrow Trail

Member

Nanushuk Group Colville Group

EAST

Quate

Kogosukruk Tongue (nonmarine)

Sentinel Hill Mbr.

Killik Tongue

Killik Tongue (nonmarine)

(nonmarine)

Tuktu

Formation

Prince

Creek Formation

Chandler

Formation

Tuktu

Formation

Anaktuvu

Nanushuk 

Okpikruak Formation

Fortress Mountain Formation

Okpikruak Formation Okpikruak Formation

Fortress Mountain

and Torok Formations 

Fortress Mountain

and Torok Formations 

Fortress Mountain

and Torok Formations 

and Torok Formations

Chapman, Detterman, and Mangus, 1964

Previous nomenclature

? ?

Chandler Formation

Seabee

Formation

Seabee Formation 

Nanushuk Formation Torok

Formation

Upper Cretaceous Tertiary Lower Cretaceous

Formation assessed for gas hydrates

EXPLANATION

Revised

nomenclature

Mull and others

(2003)

No Tertiary

or Upper

Cretaceous

rocks present

in western

part of

study area

?

? ? ? ? ?

? ?
4. Alaska North Slope Gas Hydrate Petroleum System 15

Figure 7. A, downhole logs from the Northwest Eileen State-2 well depicting the depth of units B, C, D, and E; data shown include the 

natural gamma ray log, bulk-density, neutron porosity, acoustic velocity, and electrical resistivity data. B, insert of well logs from the 

cored gas hydrate interval (unit C) in the Northwest Eileen State-2 well. Data shown include well logs and methane (CH4

) mud-log curve. 

See figure 9 for well location.

2 2000 130 50 100 0 300

612–2,000

METERS-FEET

670–2,200

730–2,400

Cored and

tested hydrate 

0

Depth, below ground surface

B

EXPLANATION

Gas hydrate bearing

Well log

500

METERS Depth, below ground surface

Gamma ray

(American Petroleum

Institute units)

Gamma ray

(American

Petroleum

Insititue units)

Mud log

methane gas CH4

(parts per

thousand)

Bulk-density

(gram per cubic

centimeter) 

0 100 1.9 2.4 1.5 4.5 1 10,000

Gas

hydrate

unit

Neutron-porosity

(percentage)

Velocity

(kilometer

per second)

Resistivity

(ohm-meter) 

Resistivity

(ohm-meter) 

Acoustic

transit-time

(millisecond

per foot)

15 45

800

550

600

650

700

750

C

B

E

D

A
Figure 8. Well log cross section showing the lateral and vertical extent of the Eileen and Tarn gas hydrate accumulations and the associated uthe Prudhoe Bay and Kuparuk River oil fields. See figure 9 for the location of the cross section. The gas hydrate-bearing units in the Eileen accumthe reference letters A through F. The numbered solid lines are log correlation markers used to construct a regional stratigraphic framework (moThe gas hydrate-bearing portions of units A and B in the Eileen accumulation are shown as ending above the base of the gas hydrate stability zothe path of this southwest- to northeast-trending cross section. However, to the east and south from the Kuparuk River field into the Prudhoe Bahydrates extend to the base of the gas hydrate stability zone and trap free-gas in a downdip position.

5

5

6

6

13

201918

22

21

14151617 0

1,0002,0003,0004,0005,0006,000

1011

97

Cirque-2 West Sak 15 West Sak 3 KRU 1D-8

Northwest

Eileen

State 2

West

Kuparuk

3-11-11

Gwydyr

Bay State 

Tarn 2N349 

Campanian

sand West Sak sand Ugnu sand

Cirque-2

 KRU 1C-8

1

1 1

1

12

unit A

unit B

unit F

A 

EXPLANATION

Gas hydrateFree-gasSand

Base of methane hydrate  stability fieldLog correlation marker

Natural gamma ray log— 0–150 API unitsResistivity well log— 0.2–2,000 ohm-m units

Well and identifier

METERS 
4. Alaska North Slope Gas Hydrate Petroleum System 17

part of the Kuparuk River field, the southern part of the 

Milne Point field, and the western part of the Prudhoe Bay 

field (figs. 8, 9). The lateral boundaries of the gas hydratebearing units as mapped by Collett (1993) are based in many 

places on widely-spaced well control and therefore are open 

to interpretation and further refinement. Also, the lateral 

continuity of gas hydrate occurrences between well sites is still 

poorly defined, but recent 3D seismic prospecting in the Milne 

Point area by Inks and others (2009) has provided additional 

insight to the lateral nature and extent of the well-loginferred gas hydrate-bearing units in the Eileen accumulation 

(discussed in a later section). It is also important to emphasize 

that seismic surveys (reviewed by Lee and others, 2009; Inks 

and others, 2009) and downhole logs (Collett, 1993) from 

wells in the western part of the Prudhoe Bay field indicate 

the presence of several large free-gas accumulations trapped 

stratigraphically downdip below five (units A–E) of the loginferred gas hydrates. The total mapped area of all six gas 

hydrate-units in the Eileen accumulation is about 635 mi2

; 

the areal extent of individual units ranges from 1 to 155 mi2

(fig. 9). Collett (1993) estimated the total volume of gas within 

these accumulations at about 35.3 to 42.4 TCF.

Collett (1993) concluded that the Eileen gas hydrate 

accumulation is in rocks of the Mikkelsen Tongue of the 

Canning Formation, which were deposited during a basinwide 

marine transgression in the Eocene. This sequence (which 

is mostly marine) thins southwesterly and coarsens laterally 

into a sand-rich sequence in the western part of the Prudhoe 

Bay field. Analysis of drilling cuttings (Collett, 1993) and 

core from the Mount Elbert well (Rose and others, 2011) 

indicates that the gas hydrate-bearing reservoirs in the 

Eileen accumulation consist mostly of fine-grained to very 

fine-grained sands and coarse silts with minor amounts of 

interbedded coarse sands, conglomerates, and shales deposited 

in a range of nearshore marine and nonmarine environments. 

Considering the sand-rich nature of the section at the site of 

the Mount Elbert well, the interval containing the Eileen gas 

hydrate-bearing sands are now assigned to the Sagavanirktok 

Formation (fig. 6; Molenaar and others, 1987b; Bird, 1998: 

Rose and others, 2011) and are considered the age equivalent 

of the more distal early Eocene marine shales and minor sands 

of the Mikkelsen Tongue of the Canning Formation further 

to the east.

In February of 1992, while drilling the Cirque-1 well 

near the western edge of the Kuparuk River field, a shallow 

gas zone (depth of about 2,330 ft; 710 m) was encountered 

that subsequently blew out the well (Alaska Oil and Gas 

Conservation Commission, 1992). It was later determined 

that the well also encountered a thick gas hydrate-bearing 

interval that contributed to the gas flow problem (Collett and 

Dallimore, 2002). Subsequent drilling of the Cirque-2 well 

confirmed the occurrence of gas hydrates near the base of 

permafrost within the depth interval of about 820 ft to 1,150 ft 

(250–350 m) (Collett and Dallimore, 2002).

Downhole log data from industry exploratory and 

development wells located along the western margin of the 

Kuparuk River field, tied to the well-log responses in the 

Cirque-2 well, reveal a large gas hydrate accumulation that 

has been named the Tarn gas hydrate accumulation (Collett, 

1993; figs. 8, 9). As shown in figure 9, the Tarn gas hydrate 

accumulation lies in a fairway extending from the Till-1 

well in the north, through the Cirque-Tarn area, to near the 

North Meltwater field to the south. The gas hydrate-bearing 

stratigraphic interval in the Tarn area appears to be the 

updip equivalent of the informally named West Sak sands, 

which are estimated to contain more than 20 billion barrels 

of in-place viscous oil and are the focus of development 

activity in a downdip position to the east of the Tarn gas 

hydrate accumulation (Werner, 1987). Preliminary analyses 

of other recently completed wells along the western margin 

of the Kuparuk River field indicate that the Tarn gas hydrate 

accumulation may be larger than the Eileen accumulation; 

however, the Tarn accumulation lies mostly within permafrost 

unlike the Eileen accumulation, which straddles the base 

of permafrost.

In 2003, the USGS initiated a study to develop seismic 

interpretive methods to identify and characterize gas hydrate 

accumulations and to further characterize the nature of hydratebearing reservoirs on the Alaska North Slope. This study dealt 

primarily with the analysis of a 3D seismic data set from the 

area of the Milne Point field as provided to the USGS by 

BP Exploration Alaska, Inc. (figs. 9, 10). Detailed analysis and

interpretation of available 3D and 2D seismic data sets, along 

with seismic modeling and correlation with specially processed 

downhole well-log data, have led to the development of a viable 

method for identifying sub-permafrost gas hydrate prospects 

within the gas hydrate stability zone in the Milne Point area 

(Lee and others, 2009, 2011; Inks and others, 2009).

Initial seismic interpretation indicated a range of potential 

gas hydrate prospects, including accumulations at the base 

of the gas hydrate stability zone (in contact with underlying 

free gas) and additional hydrate prospects higher in the 

stratigraphic section. However, well-log data showed that the 

gas hydrate and free gas saturations in these deeper reservoirs 

were low due to leaky seals or inadequate charge (Inks and 

others, 2009). In 2005, the USGS project team completed their 

delineation, description, and ranking (including probabilistic 

volumetrics) of 14 gas hydrate prospects (fig. 10) within 

the Milne Point area. The seismic characterization of the 

gas hydrate prospects was based on rock physics relations 

calibrated with downhole log data from nearby offset wells; 

this enabled the prediction of gas hydrate “pay” thickness and 

gas hydrate saturation from analyses of seismic amplitudes 

and peak-trough travel-times (Lee and others, 2009).

The highest ranked Milne Point gas hydrate prospect, 

named Mount Elbert, is depicted in figures 10 and 11. The 

pre-drill site evaluation predicted that Mount Elbert would 

contain roughly 145 BCF (billion cubic feet) of in-place gas 
18 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

in two reservoir sands (units C and D after Collett, 1993) 

(Inks and others, 2009). The Mount Elbert prospect, like all 

of the most promising Milne Point prospects, had not been 

penetrated by existing wells. Therefore, it was decided to drill 

a stratigraphic test well to confirm the existence of reservoirs, 

test the prospecting and assessment methodologies, and enable 

the collection of additional reservoir data to support reservoirsimulation modeling and production test design (Hunter and 

others, 2011). The Mount Elbert Gas Hydrate Stratigraphic 

Test Well was completed in February 2007 and yielded one 

of the most comprehensive datasets yet compiled on naturally 

occurring gas hydrates. The test well was designed as a 22-day 

program with the planned acquisition of cores, well-logs, 

and downhole production test data. It was first drilled and 

cased to a depth of 1,952 ft (595 m), then was continuously 

cored to a depth of 2,494 ft (760 m). After coring, the well 

was surveyed with a research-level wireline-logging program 

including nuclear magnetic resonance and dipole acoustic 

logging, resistivity scanning, borehole electrical imaging, 

and advanced geochemistry logging (figs. 12, 13). Following 

logging, Schlumberger Modular Dynamic Testing (MDT) 

was conducted at four open-hole stations in two hydratebearing sandstone reservoirs (fig. 13). Each test consisted of 

flow and shut-in periods of varying lengths, with one lasting 

more than 13 hours (hr). Gas was produced from the gas 

hydrates in each of the tests. Gas hydrates were expected and 

encountered in two stratigraphic zones (figs. 12, 13): (1) an 

upper zone (unit D) that contained roughly 46 ft (roughly 

Figure 9. Map of the Eileen and Tarn gas hydrate accumulations overlying portions of the Prudhoe Bay, Kuparuk River, and Milne 

Point oil fields (modified from Collett, 1993). Also shown are the locations of the Northwest Eileen State-2 (NWEIL), Mount Elbert and 

Hot Ice gas hydrate research wells and the well log cross-section A–B in figure 8, along with the outline of the Milne Point 3D seismic 

volume used to identify and map gas hydrate prospects.

151°00' 150°00' 149°00' 148°00'

40

0 8 124 16 KILOMETERS

Base from U.S. Geological Survey digital data 8 12 16 MILES

Universal Transverse Mercator projection

Central meridian −154°, latitude of origin 54°

North American Datum of 1927 (NAD 27)

70°30'

70°15'

70°00'

Location

of map

ALASKA

A A'

Hot Ice

Known gas hydrate accumulation boundary

Federal/State water boundary

EXPLANATION

Oil field

Free gas accumulation boundary

National Petroleum Reserve Alaska boundary

Bureau of Land Management township grid line

Milne Point 3-D seismic survey boundary

Well

Study well and identifier

Line of section

Trans-Alaska

Pipeline System

Prudhoe Bay

oil field

Endicott 

oil field

Kuparuk River

oil field

Tarn

oil field

Eileen hydrate

accumulation

(composite of 

A-F hydrates)

A′

Cirque 1

Cirque 2

Hot Ice

West Sak 3

North Meltwater-1

Gwydyr Bay

State 1

Reindeer

Island-1

A

Milne Point

oil field

Northwest Eileen

State 2

West Kuparuk

3-11-11

Mount Elbert

KRU 1D-8

Tarn hydrate

accumulation

Till-1

BEAUFORT SEA

West

Sak 15

West

KRU 1C-8

Tarn 2N349
4. Alaska North Slope Gas Hydrate Petroleum System 19

14 m) of gas hydrate-bearing reservoir-quality sandstone, 

and (2) a lower zone (unit C), that contained roughly 52 ft 

(roughly 16 m) of gas hydrate-bearing reservoir. Both zones 

displayed gas hydrate saturations that varied with reservoir 

quality as expected, with typical values between 60 percent 

and 75 percent. This result conclusively demonstrated the 

soundness of the gas hydrate prospecting methods developed 

primarily by the USGS (Lee and others, 2011).

The Milne Point 3D seismic gas hydrate prospecting 

effort also provided a greater appreciation of the lateral nature 

of the well-log-inferred gas hydrate-bearing sedimentary units 

in the Eileen accumulation. As reported by Collett (1993), 

the thickness of the well-log-inferred gas hydrate intervals in 

the Milne Point area range from roughly 10 to roughly 100 ft 

(roughly 3 to roughly 30 m). However, the nature of the gas 

hydrate occurrences between wells is poorly constrained. 

Collett (1993) assumed that the deposits were laterally 

continuous and were representative of hydrate occurrences 

throughout the Eileen accumulation. The Milne Point 3-D 

seismic analysis, however, revealed a much more “patchy” 

nature, as depicted in the gas hydrate prospect map in 

figure 10, with individual gas hydrate prospects ranging in 

Figure 10. Milne Point area gas hydrate prospects identified with 3-D seismic interpretation. Modified from Inks and others (2009). 

As a condition of the seismic data use agreement, the latitude and longitude of the seismic data and the interpreted features cannot 

be shown on this map.

As a condition of the seismic data use agreement the latitude

and longitude of the seismic data volume or the interpreted

features cannot be shown on this map

0.50

0 1 1.5 0.5 2 KILOMETERS

1 1.5 2 MILES

Location

of map

ALASKA

EXPLANATION

E Hydrate prospect

D Hydrate prospect

C Hydrate prospect

B Hydrate prospect

Upper staines hydrate prospect

Middle staines hydrate prospect

Maroon

Peak “A”

Longs Peak

Mid-Staines

Longs Peak

Upper Staines

Mount

Antero “C”

Mount

Bierstadt “D”

Mount

Elbert “D”

Mount

Elbert “C”

Mount

Sneffels “D”

Mount

Bierstade “E”

Pikes

Peak “B”

Maroon Peak

Mid-Staines 

Blanca

Peak “C”

Mount

Princeton “D”

Crestone

Peak “C”

Uncompahgre 

Peak “D”

BEAUFORT SEA

Little Bear Peak

Upper Staines

Grays

Peak “B”

Redcloud

Peak “B”
20 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

size from about 0.1 to 2.7 mi2. The thickness of the seismically 

imaged gas hydrate occurrences in the Milne Point effort were 

also determined to range from roughly 30 ft (roughly 9 m) to a 

maximum thickness of roughly 65 ft (roughly 20m). However, 

Lee and others (2009, 2011) demonstrated that within the 

Milne Point 3D seismic data volume there is no significant 

seismic response to gas hydrate reservoirs less than a cut-off 

thickness of about 25–30 ft (about 8–9 m). This indicates the 

probability that the relatively thinner log-inferred gas hydrate 

occurrences in the Milne Point area are not being seismically 

imaged. It is therefore likely that gas hydrates between well 

sites within a given stratigraphic unit are more regionally 

extensive than those imaged by Inks and others (2009), but 

thicknesses can only be inferred from available data. The local 

variability in the nature of the Eileen gas hydrate accumulation 

is likely controlled by the components of the petroleum system 

(that is, reservoir, gas source, and gas migration).

The Eileen and Tarn gas hydrate accumulations clearly 

demonstrate the role of the reservoir in a gas hydrate 

petroleum system. In both cases, gas hydrate is in pores of 

coarse-grained sedimentary rocks. It is also clear that the 

accumulation of gas hydrates is limited to the zone of 

methane hydrate stability in northern Alaska. Of most 

importance for this assessment, however, is that the seismicinferred hydrate accumulations on the Alaska North Slope 

occupy limited, discrete volumes of rock bounded by 

faults and downdip water contacts much like conventional 

hydrocarbon accumulations.

4.c. Gas Source and Migration

It has been shown that the availability of large 

quantities of hydrocarbon gas from both microbial and 

thermogenic sources is an important factor controlling the 

Figure 11. Milne Point Mount Elbert gas hydrate prospect. Shown are a three-dimensional image of a 

fault-bounded, high-amplitude feature (in a pallet of colors ranging from yellow to magenta, the yellowimaged portion contains the thickest and most concentrated gas hydrate); bounding faults (in green); 

and gas hydrate zones (in yellow) in nearby well penetrations as identified from geophysical log data. 

Modified from Inks and others (2009).

CO MPU 2

BP MPU E-26

CO MPU B-2

CO MPU D-1

C16 Seismic Marker

C16 Seismic Marker C16 Seismic Marker

D Hydrate

C Hydrate
4. Alaska North Slope Gas Hydrate Petroleum System 21

formation and distribution of natural gas hydrates (Collett, 

1993; Kvenvolden, 1993; Collett, 2002; Lorenson and others, 

2011). Carbon isotope analyses indicate that the methane in 

many oceanic hydrates is derived from microbial sources; 

however, thermal sources have been observed within several 

hydrate deposits in the Gulf of Mexico, the Caspian Sea, the 

Black Sea, and onshore in the Mackenzie Delta of Canada 

and in northern Alaska (reviewed by Collett, 2002). Recent 

studies in northern Alaska (Lorenson and others, 2011) and 

Canada (Dallimore and Collett, 2005) have also documented 

the importance of thermogenic gas sources to the formation of 

highly concentrated gas hydrate accumulations.

Typically, not enough microbial methane is generated 

internally within the gas hydrate stability zone alone 

to account for the gas content of most gas hydrate 

accumulations (Kvenvolden, 1993). In addition, most gas 

hydrate accumulations are in sediments that have not been 

deeply buried or subjected to temperatures high enough to 

form thermogenic gas. Thus, in most cases, the gas is likely 

concentrated in the hydrate stability zone by a potential 

combination of processes, one of which, gas migration, would 

appear to be the critical component within most gas hydrate 

petroleum systems.

In the greater Prudhoe Bay area, the Sagavanirktok 

Formation (fig. 6) is cut by a series of northwest-trending 

high-angle normal faults, generally downthrown to the east 

(Werner, 1987). Similar faults cut the underlying rocks in 

this area, suggesting a genetic linkage between the two fault 

systems that could provide conduits for oil and gas migration 

from the underlying Prudhoe Bay and Kuparuk River fields. 

Geochemical similarities suggest that oil and presumably 

the associated gas within the Sagavanirktok Formation were 

“spilled” from the underlying Prudhoe Bay Sadlerochit 

Group reservoir as a consequence of regional tilting during 

the middle to late Tertiary (Carman and Hardwick, 1983; 

Masterson and others, 2001).

Figure 12. Open-hole well logs from the cored section of the Mount Elbert gas hydrate stratigraphic test well. Modified from Hunter 

and others (2011).

1,800

2,000

2,200

2,400

2,600

2,800

3,000

100 0 2.5 1.6 1.0 1,000 1,500 3,500 500 1,700

Depth below Kelly Bushing

Base of permafrost

Base of gas hydrate stability

FEET

Gamma ray

(American Petroleum

Institute units)

Bulk-density

(gram per cubic

centimeter)

Resistivity

(ohm-meter) 

Compressional

velocity

(meter per second) 

Shear velocity

(meter per second) 

Core

Gas

hydrate

unit

D

C

EXPLANATION

Gas hydrate bearing

Well log
22 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Geochemical analyses of drill cuttings and core 

samples from wells in both the Eileen and Tarn gas hydrate 

accumulations indicate that methane is the principal gas in 

these accumulations (Collett, 1993; Lorenson and others, 2011). 

Stable methane-carbon isotopic analyses show that the methane 

within the gas hydrate is likely from mixed microbial and 

thermogenic sources, with the apparent thermogenic methane 

migrating from deeper sources, including the Prudhoe Bay field. 

Masterson and others (2001) and Lorenson and others (2011) 

have shown that evaporative fractionation and biodegradation 

of the Sadlerochit-sourced oil in the Sagavanirktok Formation 

is also an important source of gas within the gas hydrates of 

both the Eileen and Tarn gas hydrate accumulations.

Collett (1993) adapted a generalized cross section 

(fig. 14) from Carman and Hardwick (1983) to describe the 

history of the Eileen and Tarn gas hydrate accumulations. Collett 

postulated that as thermogenic gas and associated oil moved up 

the Eileen and other fault zones and encountered the relatively 

porous and permeable northeast-dipping Sagavanirktok 

sandstone reservoir units, some of the gas may have been 

rechanneled updip along these beds. The updip-migrating gas 

Figure 13. Well-log-derived gas hydrate saturations, density porosities, and sediment permeabilities for the two gas hydratebearing intervals (units C and D) cored in the Mount Elbert gas hydrate stratigraphic test well (modified from Hunter and others, 

2011). The intervals tested (Schlumberger Modular Dynamic Testing (MDT) Tests C1, C2, D1, and D2) are also shown. (NMR, nuclear 

magnetic resonance)

Figure 14. Schematic west to east cross section through the 

Prudhoe Bay and Kuparuk River fields illustrating possible gasmigration paths and spatial relations between the Eileen and Tarn 

gas hydrate accumulations, free-gas and oil accumulations, Eileen 

and other fault zones, and base of gas hydrate stability (modified 

from Carman and Hardwick, 1983).

Gas

hydrate

unit

D

C

EXPLANATION

Well log

2,000

2,050

2,100

2,150

2,200

0 100 15 60 0.01 10,000

Depth below Kelly Bushing

FEET

MDT D2-2025

MDT D1-2047

MDT C2-2151

MDT C1-2161

Gas hydrate saturation

(percent)

Density porosity

(percent)

NMR (Timur) permeability

(millidarcy)

BROOKIAN

SEQUENCE

ELLESMERIAN

SEQUENCE

KUPARUK RIVER

OIL FIELD

PRUDHOE BAY

OIL FIELD

WEST EAST

Eileen

fault

zone Faultzone

Eileen 

Sagavanirktok Formation

Canning Formation

Tarn

Base of gas

hydrate stability

EXPLANATION

Gas hydrate

Free gas

Oil

Gas migration
5. Gas Hydrate Production Analysis 23

may have mixed with in-situ microbial methane and collected 

in structural and stratigraphic traps where falling temperatures 

at the end of the Pliocene deepened the permafrost section and 

converted the trapped gas into gas hydrate.

As discussed above, gas hydrate in onshore Arctic 

environments is typically closely associated with permafrost. 

It is generally believed that thermal conditions conducive to 

the formation of permafrost and gas hydrate persisted in the 

Arctic since the end of the Pliocene (about 2.59 million years 

ago) (Collett, 1993, 2002; Lee and others, 2008). From Milne 

Point seismic and other studies, it also appears that most 

permafrost-associated gas hydrate accumulations probably 

developed from preexisting free-gas fields that originally 

formed in conventional hydrocarbon traps and were later 

converted to gas hydrate upon the onset of glaciation and cold 

Arctic conditions (Collett, 1993, 2002; Lee and others, 2009, 

2011; Inks and others, 2009; Boswell and others, 2011).

5. Gas Hydrate Production Analysis

Although gas hydrates are known to occur in numerous 

marine and Arctic settings, until recently little was known 

about the technology necessary to produce gas from them. 

Proposed methods of gas recovery from hydrates (reviewed 

by Collett, 2002) generally deal with dissociating or “melting” 

in-situ gas hydrates by: (1) heating the reservoir beyond 

hydrate-forming temperatures, (2) injecting an inhibitor such 

as methanol or glycol into the reservoir to decrease hydrate 

stability, and (or) (3) decreasing the reservoir pressure below 

hydrate equilibrium. Recently, several studies have shown 

that it may be possible to produce methane from hydrates 

by displacing the methane molecule in the hydrate structure 

with carbon dioxide; thus releasing methane and sequestering 

the carbon dioxide (Graue and others, 2006). Among the 

possible techniques for production of natural gas from in-situ

gas hydrates, depressurization is considered to be the most 

economically promising (reviewed by Collett, 2002) and 

is the only method of gas hydrate production considered in 

this assessment.

The USGS conventional assessment approach also 

assumes that the hydrocarbon resource being assessed can be 

produced by existing conventional technology. The production 

potential of the known and seismically-inferred gas hydrate 

accumulations in northern Alaska has not been adequately 

field tested, but has been the focus of a U.S. Department of 

Energy (DOE) gas hydrate production research modeling 

effort as reviewed by Anderson and others (2008). Although 

verified by only limited field testing (Dallimore and others, 

2008a, 2008b; Yamamoto and Dallimore, 2008), numerical 

production models (for example Anderson and others, 

2008) of gas hydrate-bearing reservoirs suggest that gas can 

be produced from gas hydrate with existing conventional 

technology. This conclusion is supported by a growing 

body of evidence indicating that concentrated gas hydrate 

accumulations in conventional hydrocarbon reservoirs, 

such as those in northern Alaska, can be produced with 

existing technology.

Field studies and associated production modeling studies, 

such as the Mallik 2002 (Dallimore and Collett, 2005), the 

Mallik 2006–2008 (Dallimore and others, 2008a, 2008b; 

Yamamoto and Dallimore, 2008), and the Mount Elbert 

projects (Hunter and others, 2011) have contributed greatly 

to our understanding of the technologies required to produce 

gas hydrates. The results of the gas hydrate-testing programs 

in northern Canada and Alaska are discussed below, together 

with a review of the rapidly evolving field of gas hydrateproduction simulation.

5.a. Gas Hydrate Production Testing Results

The Messoyakha field, a gas field located in the northern 

part of the West Siberian Basin, is commonly used as an 

example of a hydrocarbon accumulation from which gas has 

been produced from hydrates by reservoir depressurization 

(Makogon, 1981). Production data and other geologic 

information have been used to document the presence of 

gas hydrates within the upper part of the Messoyakha field 

(reviewed by Collett and Ginsburg, 1998). Long-term 

production from the gas hydrate part of the Messoyakha field 

is presumed to have been achieved by simple depressurization. 

As production began from the lower free-gas portion of the 

Messoyakha field in 1969, the measured reservoir pressures 

followed predicted decline relations; however, by 1971, the 

reservoir pressures began to deviate from expected values. 

This deviation has been attributed to the liberation of gas from 

dissociating gas hydrates. Throughout the production history 

of the Messoyakha field, it is estimated that about 36 percent 

(about 177 BCF) of the gas withdrawn from the field was 

from gas hydrate (Makogon and others, 1972). Glenn and 

Allen (1991) presented evidence that a similar phenomenon 

may be occurring within gas fields in the vicinity of the city 

of Barrow in northern Alaska. It should be noted that several 

later studies do not support the interpretation that gas hydrate 

contributes significantly to gas production in the Messoyakha 

field (reviewed by Collett and Ginsburg, 1998).

One of the major goals of the Mallik 2002 Gas Hydrate 

Production Research Well Program (Dallimore and Collett, 

2005) was to advance research pertaining to gas hydrate 

production by undertaking a suite of well-constrained, 

short-term production experiments. The scientific goals of 

this production testing effort were to confirm the feasibility 

of natural gas production by depressurization and by 

thermal-stimulation techniques. With these goals in mind, 

the tests produced gas from gas hydrate with a series of 

well-constrained and controlled production experiments, 

each designed to investigate the response of in-situ gas 

hydrate deposits to changes in pressure or temperature. 
24 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

The Mallik 2002 production test results, combined with 

other project data, were also used to calibrate gas hydrateproduction simulators, which were then used to predict the 

expected long-term response of the gas hydrate beyond the 

duration and conditions of the actual tests.

During the Mallik 2002 testing program, the response 

of gas hydrates to heating and depressurization was evaluated 

with careful attention to accurately measuring both input 

conditions and reservoir responses. Pressure draw-down 

experiments, designed to study the response of gas hydrate 

to a reduction in formation-pressure conditions, used 

Schlumberger’s Modular Formation Dynamics Tester (MDT) 

wireline tool to conduct small-scale pressure-drawdown tests 

within five perforated intervals in the Mallik 5L-38 well. The 

rationale for most of the MDT tests was to reduce reservoir 

pressure below gas hydrate stability conditions and then 

“shut-in” the tool to observe the pressure build-up attributed 

to flowing formation fluids and gas hydrate dissociation.

The results of three short duration tests demonstrate 

that gas can be produced from gas hydrates with different 

concentrations and characteristics, exclusively through 

pressure stimulation. It was shown (Hancock and others, 

2005) that the response of the hydrate-bearing sand reservoirs 

was similar to a conventional porous-media response. Thus, 

conventional pressure-transient analytical techniques were 

used to evaluate the Mallik 2002 MDT test data. Horizontal 

permeabilities were observed to range from less than 

0.001 millidarcy (mD) to as much as 0.1 mD within hydratebearing porous media. In contrast, the expected intrinsic 

permeability (that is, without gas hydrate) of the same sands 

with only water filling the pores would be on the order of 

100 to 1,000 mD. The existence of measurable permeability 

in a reservoir with high gas hydrate saturations (up to 

85 percent) was unexpected. Downhole-measured NMR-log 

data from the Mallik 5L-38 well also indicated the presence 

of a movable free-water phase within the hydrate-bearing 

sandstone reservoirs, which likely represents the compressive 

porous-media fluid phase along which flow was established 

and measured during the MDT gas hydrate tests. Downhole 

acoustic log data from Mallik also shows that gas hydrate is 

a matrix-supporting, pore-filling material rather than a graincoating substance. The presence of an interconnected fluid 

phase at measurable permeabilities indicates that gas hydrate 

reservoir-depressurization production techniques may be more 

effective than previously thought.

Thermal stimulation experiments were designed to 

destabilize gas hydrates by using circulated hot water to increase 

the in-situ temperature. A five-day experiment was undertaken 

within a 13-m-thick section of highly concentrated gas hydratebearing strata. The test was conducted by circulating hot fluids 

(122°F; 50°C) down the hole at a constant pressure slightly 

above hydrostatic conditions. Gas from dissociated hydrate 

flowed to the surface, and was separated from the circulating 

fluid, measured, sampled, and flared. Gas was continuously 

produced throughout the test at varying rates with maximum 

flow rate reaching 12,700 standard cubic feet of gas per day 

(scf/day) (Dallimore and Collett, 2005). The total volume of gas 

was small, reflecting that the test was a controlled production 

experiment rather than a long-duration conventional well test. 

It also demonstrated the difficulty of heating a relatively large 

rock mass by conductive heat flow alone.

The Mallik 2002 production research well program 

proved for the first time that gas production from gas hydrates 

is technically feasible. The resulting data allowed (1) the 

calibration of several reservoir models used to simulate 

the thermal and depressurization tests, and (2) the rational 

assessment of the production response of a gas hydrate 

accumulation if the various tests were extended far into the 

future. These studies also show that among the possible 

techniques for production of natural gas from in-situ gas 

hydrates, depressurization would produce more gas than just 

heating the formation. However, the combination of heating 

and depressurizing the gas hydrate at the same time would 

produce the greatest amount of gas.

It is recognized that the Mallik 2002 project contributed 

a great deal to an understanding of gas hydrates; however, it 

fell short of delivering all of the data needed to fully calibrate 

existing reservoir simulators. It was also determined that 

longer-duration production tests would be required to assess 

the technical viability of long-term production from gas 

hydrates; the 2006–2008 Japan Oil, Gas and Metals National 

Corporation/Natural Resources Canada (JOGMEC/NRCan) 

Mallik Gas Hydrate Production Research Program was 

conducted to address these needs.

As described by Dallimore and others, (2008a, 2008b) 

and Yamamoto and Dallimore (2008), the 2006–2008 

JOGMEC/NRCan Mallik Gas Hydrate Production Research 

Program was conducted by JOGMEC, NRCan, and the Aurora 

College/Aurora Research Institute to build on the results of 

the Mallik 2002 project, with the main goal of monitoring 

long-term production behavior of gas hydrates. The primary 

objective of the winter 2006–2007 field activities was to 

install equipment and instruments to allow for long-term gas 

hydrate production testing during the winter of 2007–2008. 

The Mallik 2L-38 and Mallik 3L-38 wells were reentered and 

each well was logged to establish formation properties prior 

to testing. After completing drilling operations during the 

2006–2007 phase of the project, a short pressure drawdown 

test was conducted to evaluate equipment performance and 

assess the short term “producibility” of the gas hydratebearing reservoir. A 40-ft-thick gas hydrate interval 

(3,586–3,626 ft; 1,093–1,105 m) near the base of the gas 

hydrate stability zone was tested for 60 hr by reducing the 

bottom-hole pressure down to roughly 1,060 psi (equal to a 

drawdown pressure of roughly 535 psi). Irregular pumping 

operations, related to excessive sand production, resulted in 

unstable fluid flow, which greatly complicated the analysis of 

the test. However, during the most successful 12.5 hr of the 
5. Gas Hydrate Production Analysis 25

test, at least roughly 29,300 scf of gas were produced. The 

test results verified the effectiveness of the depressurization 

method even for such a short duration.

The following winter (2007/2008), the team returned to 

the site to undertake a longer term production test with the 

implementation of countermeasures to overcome the problems 

encountered in the previous year’s program. The 2007/2008 

field operations consisted of a six-day pressure drawdown 

test, during which “stable” gas flow was measured at the 

surface. The 2007/2008 testing program at Mallik established 

a continuous gas flow ranging from roughly 70,000 to roughly 

140,000 scf/day, which was maintained throughout the course 

of the six-day (139-hr) test (Yamamoto and Dallimore, 2008; 

Dallimore and others, 2008b). Cumulative gas production 

volume was approximately roughly 460,000 scf. Total water 

production during the test was less than roughly 850 barrels 

(Dallimore and others, 2008b). The 2006–2008 Mallik 

production tests have shown that “sustained” gas production 

from hydrates can be achieved by depressurization alone.

As concluded by Yamamoto and Dallimore (2008), 

all of the Mallik gas hydrate research programs have 

contributed greatly to an understanding of the energy 

resource potential of gas hydrates. However, more work is 

needed to understand the longer-term production response of 

gas hydrates, and additional production data sets are required 

to develop a practical understanding of the energy-resource 

potential of gas hydrates.

As previously discussed in this report, the Alaska 

Mount Elbert gas hydrate stratigraphic test well project 

included the acquisition of pressure transient data from four 

short-duration open-hole dual-packer pressure-drawdown tests 

using Schlumberger’s wireline MDT (Anderson and others, 

2008). These tests were conducted in open-hole and were 

designed to build upon the knowledge gained from cased-hole 

MDT tests conducted during the Mallik 2002 testing program.

Four 1-m thick zones were tested in the Mount Elbert 

well (fig. 13): two in unit C (tests C1 and C2) and two in unit 

D (tests D1 and D2). Each test consisted of multiple stages 

of varying duration, with each stage consisting of a period 

of fluid withdrawal (thereby reducing formation pressure) 

followed by a period where the pump was shutoff and the 

subsequent pressure build-up was monitored. Gas and water 

samples were collected during selected flow periods, and a 

fluid analyzer on the MDT tool enabled the identification (but 

not volumetric measurement) of gas and water as it entered 

the tool.

The Mount Elbert MDT program included two types 

of tests. To investigate the petrophysical properties of the 

hydrate-bearing reservoirs, each MDT tests began with a 

“pre-flow test,” in which pressure was reduced enough to 

mobilize unbound formation water but not enough to induce 

gas hydrate dissociation. To provide insight into gas hydrate 

response to small scale pressure transients, the pre-flow tests 

were followed by numerous test stages in which the pressure 

reduction was great enough to induce gas hydrate dissociation. 

Much like the MDT results and the downhole-measured 

NMR logs from the Mallik 5L-38 well (as discussed above), 

the MDT and NMR log data from the Mount Elbert well 

also confirmed the presence of a mobile pore-water phase 

even in the most highly gas hydrate-saturated intervals. In 

the Mount Elbert unit D sand, the mobile water phase was 

determined to be about 8 to 10 percent of total pore volume. 

In the unit C sand, it appears to range upward to roughly 

15 percent (Anderson and others, 2008).

The presence of a mobile water phase appears to be a 

required prerequisite for the initiation of depressurization for 

a gas hydrate reservoir that is not in contact with underlying 

free-gas or water reservoirs. The MDT test data from the 

early pre-flow stage that targeted fluid withdrawal without 

gas hydrate dissociation produced pressure responses that 

are typical of low-permeability porous media, much like the 

Mallik 2002 MDT tests. Analysis of these pre-flow tests in a 

variety of advanced reservoir simulators (Anderson and others, 

2008) has yielded reservoir permeabilities, in the presence 

of a gas hydrate phase, of 0.12 to 0.17 mD. Gas hydrate 

dissociation and production was confirmed in the later stages 

of each test in which the pressure was drawn down below gas 

hydrate equilibrium conditions.

In the next section of the report, we review how the 

Mallik and Mount Elbert production test results are being 

used to calibrate existing gas hydrate-production simulators 

and how these models were used in this assessment to predict 

expected gas production rates from various gas hydrate 

accumulations in northern Alaska.

5.b. Gas Hydrate Production Modeling

Over the past 10 years, there have been significant 

advancements in gas hydrate production computer simulators, 

with studies by Moridis and others (2009, 2011a, 2011b) 

showing promise for simulating gas production from hydrates 

in northern Alaska. To better understand the potential reservoir 

response for the locations considered in this assessment, the 

USGS collaborated with the participants of the International 

Code Comparison Group (Anderson and others, 2011a, 2011b) 

to conduct numerical gas hydrate-production simulations 

for the idealized Milne Point Unit (MPU), Kuparuk River 

Unit (KRU), Prudhoe Bay Unit (PBU), and Down-DipPBU settings (fig. 15). For ease in making comparisons, the 

geologic representations input to the models were simplified 

and homogenized. These analyses relied heavily on the 

reservoir data acquired from Mount Elbert test well in order to 

compare production between different geologic settings and 

between the various participating modeling approaches. Given 

the similarity of the KRU and MPU settings, only three sets of 

modeling runs were undertaken (figs. 16A–C).
Figure 15. Montage of log data from wells drilled in Prudhoe Bay Unit (PBU), Kuparuk River Unit (KRU), and Milne Point Unit (MPU) areas. The data are sbase of ice-bearing permafrost. The indicated zones of reservoir temperature are approximate. Note that the PBU logs (5, 6, 7) show inferred gas hydrate deepest (warmest) identified locations of gas hydrate in areas with established surface facilities. The next data point downdip from these wells (Well #8) and the anomalous responses that may reflect drilling effects.

1

2 3

5

6

7

8

8

4

Milne Point Unit (MPU)

Prudhoe Bay

Unit (PBU)

Kuparuk River

Unit (KRU)

T11N R11E T11N R12E

T11N R10E

T12N R10E

T13N R10E

T13N R11E T13N R12E

T12N R11E

T12N R12E

Location

of map

ALASKA

EXPLANATION

Pipeline System

Study well and identifierGravel well pad

Acoustic travel time log

Unreliable log dataInformal unit designation— After Collett, 1993

EXPLANATION

Gas hydratePotential free gasResistivity log

1,200

FEET

1,300

1,400

1,5001,600

1,700

1,800

1,900

2,000

2,100

2,200

2,300

2,400

2,500

FEET 1 1,000

1 1,000

1,300

1,400

1,5001,600

Depth below ground surface 1,800 1,900

2 ,000

2 ,100

2 ,200

2 ,300

190 50

D

D

D

D

D D D

C C1

C2

E E E

E

?

C C

C

C

C

B B B

B

?

?

A

KRU

1H-6

Resistivity

(ohm-meter)

Transit-Time

(millisecond per foot)

190 50

Transit-Time

(millisecond per foot) 190 50 Transit-Time

(millisecond per foot)

190 50

Transit-Time

(millisecond per foot)

190 50

Transit-Time

(millisecond per foot)

190 50

Transit-Time

(millisecond per foot)

190 50

Transit-Time

(millisecond per foot)

KRU

1C-1

Resistivity

(ohm-meter)

1,300

1,400

1,5001,600

1,700

1,800

1,900

2,000

2,100

2,200

2,300

2,400

2,500

FEET 1 1,000

KRU

West Sak 24

Resistivity

(ohm-meter)

1,700

1

2

3

1,600

2,000

2,100

2,200

2,300

2,500

1,900

1,800

1,700

FEET 1 1,000

MPU

Mount Elbert

Resistivity

(ohm-meter)

4

1,500

2,000

2,200

2,300

1,900

1,800

1,700

1,600

FEET 1 1,000

PBU

Northwest Eileen 

Site 2

Resistivity

(ohm-meter)

5

1,500

2,000

2,100

2,200

2,300

2,400

1,900

1,800

1,700

1,600

FEET 1 1,000

PBU

L-106

Resistivity

(ohm-meter)

(ohm-meter)

6

1,5001,600

2,000

2,100

2,200

2,300

2,400

1,900

1,800

1,700

FEET 1 1,000

PBU

West Kuparuk Site 1

Resistivity

(ohmmeter)

7

1,9

2,0

2,1

2,2

2,3

2,4

2,52,6

2,8

2,9

FE

2,400

2,100

2,400

2,7

Approximate base of gas hydrate stability
5. Gas Hydrate Production Analysis 27

Figure 16. Comparison of typical production simulation results for Alaska North Slope gas hydrate reservoirs. A, setting typical for known 

Kuparuk River Unit (KRU) and Milne Point Unit (MPU) reservoirs (3–4°C); B, Westend Prudhoe Bay Unit (PBU) setting (5–6°C); C, downdip 

PBU setting (10–12°C). From Anderson and others (2011b). Gas rate, in cubic feet (x10 Gas rate, in cubic meters per day

Water rate, in cubic meters per day

6) per day

Water rate, in barrels per day

200,000

150,000

100,000

50,000

0

6.0

4.5

3.0

1.5

0

200

150

100

50

0

1,200

900

600

300

0

Time, in years

Gas rate, in cubic feet (x10

Gas rate, in cubic meters per day

Water rate, in cubic meters per day

6) per day

Water rate, in barrels per day

30,000

20,000

10,000

0

800

600

400

200

0

1.05

0.70

0.35

0

5,000

3,000

4,000

2,000

1,000

0

0 10 20 30 40 50

A

B 

C

5,000

4,000

3,000

2,000

1,000

0

20

15

10

5

0

Gas rate, in cubic meters per day

Water rate, in cubic meters per day

Gas rate, in cubic feet (x106) per day

Water rate, in barrels per day

0.175

0.140

0.105

0.070

0.035

0

120

90

60

30

0

EXPLANATION

Gas rate

Water rate
28 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Although these cases differed somewhat in reservoir 

thickness and pressure, sensitivity runs clearly demonstrated 

that initial reservoir temperature is the primary control on 

the modeled production rates, with reservoir petrophysics, 

including intrinsic reservoir permeability, in-situ “relative” 

permeability, and mobile water saturation also being important 

(Anderson and others, 2011b). The initial MPU modeling 

results (fig. 16A) showed consistent predictions between the 

various participating codes, with modest production rates 

(maximum predicted production rate of 350,000 scf/day) 

and long “lead” times (time before first gas production 

occurs and all production is water). Analysis of the PBU 

case (production from the composite unit C sands) resulted 

in production rates (maximum predicted production rate of 

825,000 scf/day) roughly three times those of MPU and with 

no lead time (fig. 16B). The Down-Dip-PBU case revealed the 

clear benefits of higher temperatures, with rates (maximum 

predicted production rate of 4,300,000 scf/day) increasing 

another five-fold (fig. 16C; Anderson and others, 2011b). 

Subsequent incorporation of more detailed geologic input 

data sets for these locations (that is, detailed vertical reservoir 

heterogeneity) resulted in increased production rates and the 

elimination of the production lead time as seen in the MPU 

model (Anderson and others, 2011b).

As discussed above, the earlier reservoir models (KRU, 

PBU, and the Down-Dip-PBU models, figs. 16A–C) were 

based on homogeneous reservoir descriptions, neglecting actual 

complex reservoir conditions. As shown by Anderson and others 

(2011b), significant differences between homogeneous and 

heterogeneous reservoir descriptions can yield much different 

model results. Therefore, to better constrain the possible extent 

of disturbance caused by long-term depressurization of a gas 

hydrate reservoir and to more accurately model the possible 

gas- and water- production rates, a heterogeneous reservoir 

model was constructed. Figure 17 shows the hydrate saturations 

for the upper and lower C sand units as determined by the 

Archie (1942) relation in the PBU L-106 well. Similar to 

the homogeneous PBU L-Pad area simulations (as discussed 

above), the radial extent of the reservoir modeled is roughly 

1,475 ft (450 m) and the two hydrate layers are each roughly 

59 ft (18 m) thick, with roughly 30 ft (9 m) of shale between. 

The top and bottom confining layers are each 328 ft (100 m) 

thick and the porosity of the hydrate-bearing zones is taken 

from the porosity log in the PBU L-106 well. The upper and 

lower boundary temperatures were kept constant at 34.9°F 

(1.6°C) and 39.4°F (4.1°C), respectively.

Depressurization simulations were performed assuming a 

constant bottom-hole pressure of 392 psi (2.7 MPa), just above 

the quadruple point for the methane hydrate system in order to 

prevent the formation of ice in the reservoir. Figure 18 shows 

the predicted gas and water rates from the heterogeneous 

simulations on the PBU L-Pad area hydrate deposit. As 

shown in figure 18, the water rate is predicted to start at its 

maximum and decrease throughout production, whereas the 

modeled gas rate increases rapidly throughout the early stages 

of production. As shown in Anderson and others (2011b), 

homogeneous L-Pad area hydrate reservoir models predict 

maximum gas-production rates as high as 1,000,000 scf/day 

after a couple of decades of production. However, as shown 

in figure 18, a heterogeneous reservoir simulation results in 

predicted gas rates on the order of 3,500,000 scf/day with 

produced water rates ranging from 1,000–3,000 barrels/day 

throughout the first six months of depressurization.

With predicted gas production rates from known 

gas hydrate accumulations in northern Alaska as high as 

3,500,000 scf/day, based on existing production technology, 

there do not appear to be any technical barriers to resource 

extraction from hydrates; the remaining resource issues deal 

mostly with the economics of hydrate extraction.

6. Gas Hydrate Assessment 

Methodology

As introduced in the “USGS Oil and Gas Assessment 

Methodology” section of this report, an assessment begins 

(fig. 2) with the volume of rock to be assessed in the total 

petroleum system (TPS) being apportioned into homogeneous 

subunits termed assessment units (AUs). The assessment 

procedure generally estimates the number and size of 

undiscovered hydrocarbon accumulations and assesses the 

geologic risk associated with each AU. The next section of 

the report focuses on defining the limits and nature of the 

Northern Alaska Gas Hydrate TPS and three associated AUs, 

the geologic risk associated with each AU, and the methods 

used to estimate the size and number of undiscovered gas 

hydrate accumulations in each AU.

6.a. Northern Alaska Gas Hydrate Total

Petroleum System and Assessment Units

The Northern Alaska Gas Hydrate TPS (figs. 19A–B) 

includes Cretaceous and Tertiary reservoir rocks divided into 

three AUs: from oldest to youngest, the Nanushuk Formation 

Gas Hydrate AU (fig. 20), the Tuluvak-Schrader BluffPrince Creek Formations Gas Hydrate AU (fig. 21), and the 

Sagavanirktok Formation Gas Hydrate AU (fig. 22).

The geologic model used to define the AUs and to set 

the limits of the TPS involved defining and characterizing 

the components of the gas hydrate petroleum system (this is, 

gas hydrate stability conditions, gas hydrate reservoirs, and 

gas source and migration) that controlled the presence of gas 

hydrate accumulations in each AU. As a first step, the factors 

controlling gas hydrate phase equilibria (which are mostly a 

function of formation temperature and pressure as described 

in the “Gas Hydrate Stability Conditions” section of this 

report) were assessed to map the spatial distribution of the gas 

hydrate stability zone in northern Alaska (fig. 5A–C). The gas 

hydrate stability maps in figures 5A and 5B depict the top and 

base of the gas hydrate stability zone; gas hydrates cannot be 

present either above or below the zone of gas hydrate stability. 

Figure 5C shows the thickness and spatial limits of the 
6. Gas Hydrate Assessment Methodology 29

Figure 17. Hydrate saturation in the Prudhoe Bay Unit (PBU) L-106 well as calculated 

by the Archie (1942) relation for n = 1.5, 2.0 (model SH), and 2.5. The gas hydrate 

saturation in the reservoir model for the layers between 697.7 m (2,289 ft) and 706.2 m 

(2,317 ft) was assumed to be zero.

Gas hydrate saturation, in percent

0 20 40 60 80 100

700

695

690

685

680

725

720

715

710

705

675

Depth, in meters below ground surface

2,290

2,275

2,260

2,245

2,230

2,365

2,350

2,335

2,320

2,305

2,215

Depth, in feet below ground surface

EXPLANATION

SH (n=2.5)

SH (n=1.5)

Model SH
30 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Figure 18. Predicted gas and water production from the Prudhoe Bay Unit (PBU) L-106 C-unit methane hydrate 

deposit for a constant bottom-hole pressure of 2.7 megapascals (MPa). The solid black and dotted grey curves 

represent the rate of gas produced at the wellhead and gas released in the reservoir respectively, and correspond 

to the left y-axis. The rate of water production is on the right (y-axis) and is indicated by the dashed black line.

inferred gas hydrate stability zone. As depicted in figure 5C

gas hydrates cannot exists outside of the zero contour line on 

the gas hydrate stability zone thickness map.

The next component of the gas hydrate petroleum 

system to be considered is the presence of suitable reservoir 

rocks within the limits of the gas hydrate stability zone, the 

characterization of which yielded the three AUs defined in 

this study. It is important to highlight that only gas hydrates 

lying below the permafrost section were assessed, thereby 

limiting the AUs to the stratigraphic interval below the base 

of the permafrost (fig. 4) and above the base of the gas hydrate 

stability zone (fig. 5B). This decision was based on the results 

of production modeling, as reviewed in the “Gas Hydrate 

Production Modeling” section of this report. The results show 

that gas hydrate depressurization production rates are severely 

retarded by low reservoir temperatures and the presence of 

ice within the permafrost section that restricts the propagation 

of a pressure front into the formation and the flow of gas to 

the borehole. It is also emphasized that free-gas potentially 

trapped below the gas hydrate stability zone was not assessed 

in this study.

As described in the “Reservoir Rocks” section of this 

report, the known gas hydrate accumulations within the 

Eileen trend along the western border of the PBU (figs. 7, 

8) are limited to sandstone reservoirs in the Sagavanirktok 

Formation (fig. 6). In this study, however, a total of five 

Cretaceous and Tertiary sand-rich formations were assessed 

for gas hydrates. Stratigraphic nomenclature used here is 

the revised nomenclature of Mull and others (2003) for 

Cretaceous and Tertiary rocks on the North Slope, as follows: 

(1) reservoir quality rocks previously included within the 

Nanushuk Group (Corwin and Chandler Formations) are now 

assigned to the Nanushuk Formation; (2) Upper Cretaceous 

reservoir strata previously assigned to the Tuluvak Tongue 

of the Prince Creek Formation in the Colville Group are 

now included in the Tuluvak Formation; and (3) reservoir 

strata previously included in the Kogosukruk Tongue of the 

Prince Creek Formation (Colville Group), as well as strata 

previously assigned to the lower part of the Sagwon Member 

of the Sagavanirktok Formation, are now included in the 

Prince Creek Formation (fig. 6). The newly revised Tuluvak 

Formation and the Prince Creek Formation are separated by 

Gas rate, in cubic meters per day

Gas rate, in cubic feet per day (x106

)

Water rate, in barrels per day

Water rate, in cubic meters per day

Time, in months

0.0

1.0

2.0

3.0

4.0

5.0

0

25,000

50,000

75,000

100,000

125,000

150,000

0 2 4 6 8 10 120

100

200

300

400

500

600

0

500

1,000

1,500

2,000

2,500

3,000

3,500

EXPLANATION

Released in the reservoir

Produced at the well

Water produced
Figure 19. A, map of the Northern Alaska Gas Hydrate Total Petroleum System (TPS) (500102) (shaded in tan). B, map of the Northern Alaska Gas H

tan) and the gas hydrate stability zone thickness contours (in red) from figure 5C. Contours in feet (ft). (NPRA, Natural Petroleum Reserve in Alaska; Wildlife Refuge)

ARCTIC OCEAN

Prudhoe

Bay

BEAUFO

CHUKCHI SEA

Northwest Arctic Borough North Slope Borough

Arctic Nationa

National Petroleum Reserve-Alaska

Point 

Barrow

Point

Hope

168° 164° 160° 156° 152° 148° 144° 

71°

72°

70°69°68°

Brooks Range orogenic belt (Brooks Range province)

EXPLANATION

Northern Alaska Gas Hydrate Total Petroleum System

0 25 50 75 100 MILES0 25 50 75 100 KILOMETERS

Outer limit of Alaska State waterProject well

Area of map

Base from U.S. Geological Survey digital dataAlbers Conical Equal area projectionStandard parallels 55°N and 65°NCentral meridian 154°W, latitude of origin 50°NNorth American Datum of 1983 (NAD 83)

A
Figure 19. A, map of the Northern Alaska Gas Hydrate Total Petroleum System (TPS) (500102) (shaded in tan). B, map of the Northern Alaska Gas Hy

tan) and the gas hydrate stability zone thickness contours (in red) from figure 5C. Contours in feet (ft). (NPRA, Natural Petroleum Reserve in Alaska; AWildlife Refuge)—Continued

ARCTIC OCEAN

BEAUFO

Prudhoe

Bay

CHUKCHI SEA

Northwest Arctic Borough North Slope Borough

Arctic Nationa

Point 

Barrow

Point

Hope

600

2,400

3,600

1,200

3000

600

1,800

0

0

0

1,200 3,000

0

1,800

168° 164° 160° 156° 152° 148° 144° 

71°

72°

70°69°68°

Brooks Range orogenic belt (Brooks Range province)

EXPLANATION

Northern Alaska Gas Hydrate Total Petroleum System

0 25 50 75 100 MILES0 25 50 75 100 KILOMETERS

Outer limit of Alaska State waterGas hydrate stability zone thickness—Contour interval 600 footProject well

National Petroleum Reserve-Alaska

0

Area of map

Base from U.S. Geological Survey digital dataAlbers Conical Equal area projectionStandard parallels 55°N and 65°NCentral meridian 154°W, latitude of origin 50°NNorth American Datum of 1983 (NAD 83)

B
Figure 20. Map of the Nanushuk Formation Gas Hydrate Assessment Unit (AU) (50010203) (shaded in green). (NPRA, Natural Petroleum Reserve in National Wildlife Refuge)

ARCTIC OCEAN

Prudhoe

Bay

BEAUFOR

CHUKCHI SEA

Northwest Arctic Borough North Slope Borough

Arctic Nationa

National Petroleum Reserve-Alaska

Point 

Barrow

Point

Hope

168° 164° 160° 156° 152° 148° 144° 

71°

72°

70°69°68°

Brooks Range orogenic belt (Brooks Range province)

EXPLANATION

Nanushuk Formation Gas Hydrate Assessment Unit

0 25 50 75 100 MILES0 25 50 75 100 KILOMETERS

Outer limit of Alaska State waterProject well

Area of map

Base from U.S. Geological Survey digital dataAlbers Conical Equal area projectionStandard parallels 55°N and 65°NCentral meridian 154°W, latitude of origin 50°NNorth American Datum of 1983 (NAD 83)
Figure 21. Map of the Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate Assessment Unit (AU) (50010202) (shaded in blue). (NPRA, Natin Alaska; ANWR, Alaska National Wildlife Refuge)

ARCTIC OCEAN

Prudhoe

Bay

BEAUFO

CHUKCHI SEA

Northwest Arctic Borough North Slope Borough

Arctic Nationa

National Petroleum Reserve-Alaska

Point 

Barrow

Point

Hope

168° 164° 160° 156° 152° 148° 144° 

71°

72°

70°69°68°

Brooks Range orogenic belt (Brooks Range province)

EXPLANATION

Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate Assessment Unit

0 25 50 75 100 MILES0 25 50 75 100 KILOMETERS

Outer limit of Alaska State waterProject well

Area of map

Base from U.S. Geological Survey digital dataAlbers Conical Equal area projectionStandard parallels 55°N and 65°NCentral meridian 154°W, latitude of origin 50°NNorth American Datum of 1983 (NAD 83)
Figure 22. Map of the Sagavanirktok Formation Gas Hydrate Assessment Unit (AU) (50010201) (shaded in pale green). (NPRA, Natural Petroleum RAlaska National Wildlife Refuge)

ARCTIC OCEAN

Prudhoe

Bay

BEAUFOR

CHUKCHI SEA

Northwest Arctic Borough North Slope Borough

Arctic Nationa

National Petroleum Reserve-Alaska

Point 

Barrow

Point

Hope

168° 164° 160° 156° 152° 148° 144° 

71°

72°

70°69°68°

Brooks Range orogenic belt (Brooks Range province)

EXPLANATION

Sagavanirktok Formation Gas Hydrate Assessment Unit

0 25 50 75 100 MILES0 25 50 75 100 KILOMETERS

Outer limit of Alaska State waterProject well

Area of map

Base from U.S. Geological Survey digital dataAlbers Conical Equal area projectionStandard parallels 55°N and 65°NCentral meridian 154°W, latitude of origin 50°NNorth American Datum of 1983 (NAD 83)
36 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

the Schrader Bluff Formation, a mostly marine unit composed 

of reservoir quality sandstone units and shale that can be as 

thick as 2,500 ft (762 m). Regional relations suggest a general 

northeasterly progradation of the Tuluvak Formation and 

overlying Schrader Bluff and Prince Creek Formations, which 

collectively appear to be genetically related, constitute a largescale sediment package of shallow-marine to marginal-marine 

facies and coastal-plain facies.

Stratigraphic nomenclature of Mull and others (2003) 

for Tertiary strata in the Sagavanirktok Formation also 

includes revisions to previous definitions and terminology 

of Gryc and others (1951) and Detterman and others 

(1975) for this formation. In Mull and others (2003), the 

Sagavanirktok Formation includes three members (ascending 

order): the Sagwon Member (revised definition), White Hills 

Member (newly defined), and the Franklin Bluffs Member 

(revised definition).

Gas source and gas migration are two of the more critical 

components of both the TPS and AUs. As part of the gas 

hydrate petroleum system assessment, geochemical analysis 

of samples recovered from wells that have penetrated known 

gas hydrate occurrences revealed a link between gas hydrate 

accumulations on the North Slope and more deeply buried 

conventional oil and gas accumulations, in which methane 

migration from depth has charged the reservoir rocks in 

the gas hydrate stability zone (Collett, 1993; Lorenson and 

others, 2011). Considering the apparent prolific nature of 

the hydrocarbon source rocks on the Alaska North Slope 

(Bird, 1998; Bird and Magoon, 1987; Houseknecht, 2003), 

it was assumed in this assessment that the gas within the 

undiscovered gas hydrate accumulations in each of the AUs 

is solely from more deeply buried thermogenic sources. The 

geochemical analysis of gas samples from wells and the 

distribution of known more deeply buried conventional oil and 

gas accumulations have also been used in this study to further 

characterize and constrain the occurrence and distribution of 

the potential gas hydrate accumulations on the North Slope as 

described in the “Undiscovered Gas Hydrate Accumulations—

Number of Accumulations” section of this report.

Because there is no production of gas from gas hydrates 

on the North Slope and only limited testing of hydrates in the 

Mount Elbert well (Hunter and others, 2011), the three AUs in 

the Northern Alaska Gas Hydrate TPS (fig. 19) (the Nanushuk 

Formation Gas Hydrate AU (fig. 20), the Tuluvak-Schrader 

Bluff-Prince Creek Formations Gas Hydrate AU (fig. 21), and 

the Sagavanirktok Formation Gas Hydrate AU (fig. 22)) are all 

considered to be hypothetical. The potential reservoir facies 

in the Tuluvak, Schrader Bluff, and Prince Creek Formations 

share a similar geographic distribution, so these formations are 

grouped together into a single AU.

The remainder of this section provides a summary of the 

geologic criteria and data used to define the physical distribution 

of the three AUs. The key geologic consideration that is 

discussed for each AU relates to the occurrence of potential gas 

hydrate reservoir sedimentary facies within the interval below 

the base of the overlying permafrost section and above the base 

of the gas hydrate stability zone.

Because of the long history of industry-led exploration 

activities and USGS resource assessments in northern Alaska, 

this study had access to a large number of pertinent published 

reports and databases. One of the more important sources 

of information was the various data sets published with the 

previously completed USGS assessments of unconventional 

and conventional resources in northern Alaska, including 

the following: (1) 1995 USGS Gas Hydrate Assessment 

(Collett, 1995); (2) 1999 Oil and Gas Resource Potential 

of the Arctic National Wildlife Refuge 1002 Area, Alaska 

(ANWR Assessment Team, U.S. Geological Survey, 1999); 

(3) 2002 Petroleum Resource Assessment of the National 

Petroleum Reserve in Alaska (Bird and Houseknecht, 2002); 

(4) 2005 Oil and Gas Assessment of Central North Slope, 

Alaska (Garrity and others, 2005); and (5) 2007 Geologic 

Assessment of Undiscovered Coalbed Gas Resources in 

Cretaceous and Tertiary Rocks, North Slope and Adjacent 

State Waters, Alaska (Roberts, 2008).

The USGS also maintains several specialized data sets that 

were used in this assessment. One of the most important data 

sets is a copy of the State of Alaska well-log database (Alaska 

Oil and Gas Conservation Commission, 2008)—this database 

contains the publicly available downhole log data from more 

than 3,000 North Slope exploratory and development wells. For 

the most part, log data from wells in Alaska are released by the 

State two years after the completion of a well. This well-log 

database was also used to develop an unpublished USGS Alaska 

formation “tops file” as maintained by Ken Bird (USGS, Menlo 

Park, California), Dave Houseknecht (USGS, Reston, Virginia), 

and Phil Nelson (USGS, Denver, Colorado). The USGS 

Alaska formation “tops file” contains listings of penetration 

depths of all the major geologic “markers” and formations tops 

encountered in about 400 wells as of December 1, 1998. This 

file was developed mostly as a product of the various USGS 

Alaska North Slope assessment studies.

A number of well-log correlation sections were 

developed as part of this study and other USGS assessments 

in northern Alaska (as listed above). Lewis and Collett 

(2013), for example, compiled a series of nine correlation 

sections, containing well-log data from more than 122 wells, 

extending from just west of the Colville River in NPRA and 

extending to the east near the Sagavanirktok River (fig. 23). 

These sections include (1) “well-log picks” for the tops of 

all the major formations and well-log markers, (2) depths of 

the well-log-inferred gas hydrate accumulations (including 

those within the Eileen and Tarn gas hydrate accumulation), 

(3) depths of the top and base of the gas hydrate stability zone, 

and (4) depths to the base of permafrost and (or) ice-bearing 

permafrost. Other important published well-log correlation 

sections were available from Molenaar and others (1987a) 

and Decker (2007).
6. Gas Hydrate Assessment Methodology 37

Figure 23. Map showing locations of well-log correlation sections within the greater Prudhoe Bay area as compiled by Lewis and 

Collett (2013).

BEAUFORT SEA

Base from U.S. Geological Survey digital data

State Plane Alaska Zone 5

Transverse Mercator projection

Central meridian 154°, latitude of origin 54°

North American Datum of 1927 (NAD 27)

Eileen hydrate

accumulation

Tarn oil

field

Niakuk oil field

Prudhoe Bay

oil field

Milne Point

oil field

Alpine

oil field

Meltwater

oil field

Kuparuk River

oil field

EXPLANATION

Producing oil field

National Petroleum Reserve Alaska boundary

Free gas accumulation boundary

Known gas hydrate accumulation boundary

Tarn hydrate

accumulation

Eileen Free

gas accumulation

Kuparuk

River

151°00' 150°00' 149°00' 148°00' 147°00'

70°00'

70°30'

CANADA

UNITED STATES

Area of

interest

Endicott

oil field

Liberty

oil field

Sagavanirktok

River

50

0 10 15 5 20 KILOMETERS

10 15 20 MILES

Line of well log correlation section

Study well

ALASKA

Outer limit of Alaska State water

Colville River

This project also made use of several extensive grids 

of 2D seismic lines and 3D seismic volumes (fig. 24). As 

part of the U.S. Government-managed NPRA exploration 

program in the 1970s and 1980s, the USGS supervised the 

acquisition of more than 15,000 mi of 2D seismic data. Miller 

and others (2000, 2001) included reprocessed digital seismic 

data for a series of regional reference seismic lines (roughly 

4,200 line-miles), which formed a 20×20-mi grid covering 

the entire NPRA (fig. 24). The USGS NPRA seismic data 

grid was used in this assessment to help set the western and 

southern limits of the three AUs. This assessment also had 

access to an additional set of multichannel, seismic-reflection 

lines from ANWR (fig. 24), which were recorded as part of a 

resource assessment study conducted by the USGS and others 

in the 1980s (Bird and Magoon, 1987). This seismic data set 

helped to define the southeastern limits of the Sagavanirktok 

Formation Gas Hydrate AU (discussed later in this report).

As described in the “Undiscovered Gas Hydrate 

Accumulations—Sizes of Accumulations” and “Undiscovered 

Gas Hydrate Accumulations—Number of Accumulations” 

sections of this report, this study also relied on numerous 

3D seismic volumes to help define the limits of the AUs 
Figure 24. Map of 2D and 3D seismic profiles, the interpretation of which were used as the base data for this assessment of undiscovered gas hydraAlaska North Slope. Most of the 2D seismic lines depicted in or near NPRA are from Miller and others (2000, 2001) and the 2D seismic lines shown in AMagoon (1987). Also shown is the outline of the Milne Point unit 3D seismic volume used to identify and map gas hydrate prospects. The NPRA 3D seisassessment have not been shown in this figure for confidentiality reasons. (NPRA, National Petroleum Reserve in Alaska; ANWR, Arctic National Wild

ARCTIC OCEAN

Prudhoe

Bay

BEAUFORT 

CHUKCHI SEA

Northwest Arctic Borough North Slope Borough

Arctic National 

National Petroleum

Reserve-Alaska

Point 

Barrow

Milne

Point

Point

Hope

168° 164° 160° 156° 152° 148° 144° 

71°

72°

70°69°68°

Brooks Range orogenic belt (Brooks  Range province)

EXPLANATION

Sagavanirktok Formation Gas Hydrate  Assessment Unit boundary

Area of map

0 25 50 75 100 MILES0 25 50 75 100 KILOMETERS

Base from U.S. Geological Survey digital dataAlbers Conical Equal area projectionStandard parallels 55°N and 65°NCentral meridian 154°W, latitude of origin 50°NNorth American Datum of 1983 (NAD 83)

Tuluvak-Schrader Bluff-Prince Creek  Formations Gas Hydrate Assessment  Unit boundary

Sagavanirktok Formation Gas Hydrate  Assessment Unit boundary

3D seismic volume boundarySeismic line

Outer limit of Alaska State water
6. Gas Hydrate Assessment Methodology 39

and to determine the size and number of undiscovered gas 

hydrate accumulations. As discussed earlier, the 3D seismic 

data volume from the MPU covering an area of 155 mi2

(figs. 10, 24) (as released to the USGS by BP Exploration 

Alaska, Inc.) was used to develop and document seismic 

methods for identifying a series of nine gas hydrate prospects 

(accumulations) in the MPU (Lee and others, 2009, 2011; 

Inks and others, 2009). The USGS was also given access by 

BLM to four additional 3D seismic volumes from NPRA. 

These additional seismic data volumes from NPRA covered 

an area of 729 mi2

, were used under strict data-confidentiality 

rules, and cannot be released for public disclosure (subject 

to 43 CFR 3152.6 (a) (b), 43 CFR 3152.7 (a) (2), and 

43 CFR 3100.4). To maintain data confidentiality, no portion 

of the data sets, location information, or names of the 

NPRA seismic data volumes were used in this report. For 

descriptive purposes, the four 3D seismic-data volumes were 

named NPRA 3D Seismic No. 1 through NPRA 3D Seismic 

No. 4. These four seismic-data volumes provided critical 

insight to the size and number of undiscovered gas hydrate 

accumulations in the Nanushuk Formation Gas Hydrate AU 

and the Tuluvak-Schrader Bluff-Prince Creek Formations Gas 

Hydrate AU.

The Northern Alaska Gas Hydrate TPS is defined here 

(figs. 19A–B) to include the area of the Alaska North Slope 

and adjacent State waters underlain by Cretaceous and 

Tertiary strata that (1) are in the interval between the base of 

the permafrost (fig. 4) and above the base of the gas hydrate 

stability zone (fig. 5B), and (2) are interpreted to contain 

reservoir quality sandstone deposits with the potential for 

containing gas hydrate. The TPS thus includes a significant 

part of the National Petroleum Reserve in Alaska (NPRA), and 

limited lands in the Arctic National Wildlife Refuge (ANWR). 

The southern onshore boundary of the TPS is defined by the 

mapped intersection of Cretaceous continental deposits and 

the base of permafrost within the mapped zone of gas hydrate 

stability. The eastern and western limits of the TPS extend 

to the limits of the Topset Play in the 1001 Area of ANWR 

(ANWR Assessment Team, U.S. Geological Survey, 1999) and 

the Brookian Topset Play in NPRA (Bird and Houseknecht, 

2002). The offshore limits of the TPS extended to the 

boundary of the Alaskan State waters.

Recent work summarized by Walsh and others (2007) 

led to the conclusion that the East Barrow and Walakpa gas 

fields, located near the village of Barrow, may extend up into 

the overlying methane hydrate stability zone, thus opening the 

possibility that gas hydrate may exist in the crest of these two 

conventional gas fields, neither of which fall within the AUs 

as defined in this assessment. However, due to the lack of well 

penetrations in the updip portion of the Walakpa field, it has 

not been possible to more thoroughly evaluate the occurrence 

of gas hydrate in this field. There is also no direct geologic 

evidence for the presence of gas hydrate in the East Barrow 

gas field. It was therefore decided not to include the Barrow or 

Walakpa reservoirs in this assessment.

6.a.1. Nanushuk Formation Gas Hydrate

Assessment Unit

The Nanushuk Formation Gas Hydrate AU encompasses 

just over 19,816,320 acres (roughly 30,963 mi2

) in the western 

and central parts of the North Slope (fig. 20). The western and 

southern limits of the Nanushuk Formation Gas Hydrate AU 

are defined by the intersection with the base of the permafrost 

section, within the limits of gas hydrate stability zone, and 

the mapped limit of the Nanushuk Formation reservoirs. The 

eastern limit of the AU is defined by the intersection with 

the base of the gas hydrate stability zone and mapped limit 

of Nanushuk Formation reservoirs and other older reservoir 

sections. The northern boundary of the AU is defined mostly 

by the limit of the Alaska State Waters (from the mean high 

water line out to 3 nautical miles).

In general, the Nanushuk Formation Gas Hydrate AU is 

limited to mostly the topset seismic facies as identified from 

the USGS regional 2D seismic lines and available 3D seismic 

volumes in NPRA and to the south along the Brooks Range 

Foothills. Well-log picks for the Nanushuk Formation from 

124 wells in the USGS Alaska formation “tops file,” along 

with several project generated well-log correlation sections, 

have been used to further refine the limits of this AU. Most 

of the AU is coincident with (1) the Nanushuk Formation 

Coalbed Gas AU (Roberts, 2008); (2) the conventional 

Brookian Topset, Brookian Topset Structural, Brookian 

Clinoform Central, Brookian Clinoform South Shallow, 

and Brookian Clinoform South Deep AUs from the 2002 

Petroleum Resource Assessment of the National Petroleum 

Reserve in Alaska (Bird and Houseknecht, 2002); and 

(3) portions of the conventional Brookian Topset, Brookian 

Clinoform, Brookian Topset Structural North, Brookian Topset 

Structural South, Brookian Clinoform Structural North, and 

Brookian Clinoform Structural South AUs from the 2005 Oil 

and Gas Assessment of Central North Slope, Alaska (Garrity 

and others, 2005) (see table 2).

The Nanushuk Formation (fig. 6), which is Albian to 

Cenomanian in age, is exposed along an outcrop belt about 

20 mi wide that extends for nearly 400 mi from west to east in 

the Foothills Province north of the Brooks Range (figs. 1A–B). 

The Nanushuk Formation overlies the predominantly marine 

Torok Formation. In the subsurface, the Nanushuk extends 

across the coastal plain, covering much of the western and 

central parts of the North Slope; the thickest observed section 

is 6,150 ft (1,874 m) in the Tunalik 1 well (as documented in 

the USGS Alaska formation “tops file”). The structural setting 

of the Nanushuk Formation within the AU coincides roughly 

with the Alaska North Slope physiographic provinces that are 

characterized by east-west-trending detachment folds in the 

foothills and broad, low-amplitude anticlines in the coastal 

plain (fig. 1B) to the north (Potter and Moore, 2003). Structure 

contour maps on the top of the Nanushuk in the coastal plain 

areas indicate that the rocks dip gently southward in the westcentral and western parts of the AU, and shift to east and 

southeasterly dips in the eastern part of the AU (Potter and 

Moore, 2003).
40 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Table 2. Cross-reference of the gas hydrate assessment units 

with USGS conventional assessment units in northern Alaska 

(ANWR Assessment Team, U.S. Geological Survey, 1999; Bird and 

Houseknecht, 2002; Garrity and others, 2005).

ANWR Assessment1 Gas Hydrate

Assessment Unit

Topset play SAG

Thin skinned trust-belt play SAG

Turbidite play SAG

Wedge play SAG

Central North Slope Assessment2 Gas Hydrate

Assessment Unit

Brookian Topset NAN/TSBPC/SAG

Brookian Clinoform NAN/TSBPC/SAG

Brookian Topset Structural North NAN/TSBPC/SAG

Brookian Topset Structural South NAN/TSBPC/SAG

Brookian Cinoform Structural North NAN/TSBPC/SAG

Brookian Cinoform Structural South NAN/TSBPC/SAG

NPRA Assessment3 Gas Hydrate

Assessment Unit

Brookian Topset NAN/TSBPC/SAG

Brookian Topset Structural NAN/TSBPC

Brookian Cinoform North NAN/TSBPC/SAG

Brookian Cinoform Central NAN/TSBPC

Brookian Cinoform South Shallow NAN/TSBPC

Brookian Cinoform South Deep NAN/TSBPC

Key:

NAN = Nanushuk Formation Gas Hydrate Assessment Unit

TSBPC = Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate

Assessment Unit

SAG = Sagavanirktok Formation Gas Hydrate Assessment Unit

1

The oil and gas resource potential of the Arctic National Wildlife Refuge 

1002 area, Alaska, 1999 (ANWR Assessment Team, U.S. Geological 

Survey, 1999).

2

Oil and gas assessment of central North Slope, Alaska, 2005 (Garrity 

and others, 2005).

3

Petroleum resource assessment of the National Petroleum Reserve in 

Alaska (NPRA), 2002 (Bird and Houseknecht, 2002).

6.a.2. Tuluvak-Schrader Bluff-Prince Creek

Formations Gas Hydrate Assessment Unit

The Tuluvak-Schrader Bluff-Prince Creek Formations 

Gas Hydrate AU encompasses more than 9,179,520 acres 

(roughly 14,343 mi2

) in the central and east-central parts of 

the North Slope (fig. 21). Because of their genetic similarities 

(as previously discussed) the Tuluvak, Schrader Bluff, and 

Prince Creek Formations (fig. 6) were assessed jointly as one 

AU. The western and southern limits of the AU are marked by 

the intersections (subcrop) of the Tuluvak, Schrader Bluff, and 

Prince Creek reservoir facies with the base of the permafrost 

section within the limits of the gas hydrate stability zone. The 

eastern limit of the AU is defined by the intersection with the 

base of the gas hydrate stability zone and the mapped limit of 

Prince Creek Formation reservoirs. The western permafrostsubcrop and eastern limit of the Tuluvak, Schrader Bluff, 

and Prince Creek reservoir facies were also mapped with the 

available NPRA 2D and 3D seismic data sets as described 

above. Although strata also interpreted to be equivalent to the 

Prince Creek and Tuluvak Formations have been reported in 

outcrops as far west as the Utukok River near Corwin Bluff 

(fig. 1A) (Mull and others, 2006), the AU boundary was not 

extended to that area because neither formation has been 

identified in wells that far west. The northern boundary of the 

AU is almost entirely defined by the limit of the Alaska State 

Waters (from the mean high water line out to three nautical 

miles; fig. 24).

Much like the Nanushuk Formation Gas Hydrate AU, 

the Tuluvak-Schrader Bluff-Prince Creek Formations Gas 

Hydrate AU is mostly limited to the topset seismic facies, 

as identified from the USGS regional 2D seismic lines and 

available 3D seismic volumes in NPRA and to the area east 

of the Colville River (fig. 24). Well-log picks for the Tuluvak, 

Schrader Bluff, and Prince Creek Formations from 94 wells 

in the USGS Alaska formation “tops file” were used to further 

define the limits of this AU. Project-developed, well-log 

correlation sections (Lewis and Collett, 2013) and the Umiat 

field to Milne Point field Brookian sequence stratigraphic 

correlation section from Decker (2007) provided valuable 

insight into the distribution of the reservoir facies within the 

AU. It is important to emphasize that the well-log-inferred 

gas hydrates of the “Tarn accumulation” along the western 

border of the KRU (fig. 23; Collett, 2002) are within reservoir 

rocks of the Tuluvak-Schrader Bluff-Prince Creek Formations 

Gas Hydrate AU (see the “Reservoir Rocks” section of 

this report).

The Prince Creek and Tuluvak Formations Coalbed Gas 

AU of Roberts (2008) falls almost entirely within the limits 

of the Tuluvak-Schrader Bluff-Prince Creek Formations 

Gas Hydrate AU. The Tuluvak-Schrader Bluff-Prince Creek 

Formations Gas Hydrate AU also includes portions of the 

conventional Brookian Topset, Brookian Topset Structural, 

Brookian Clinoform North, Brookian Clinoform Central, 

Brookian Clinoform South Shallow, and Brookian Clinoform 

South Shallow AUs from the 2002 Petroleum Resource 

Assessment of the National Petroleum Reserve in Alaska 

(Bird and Houseknecht, 2002), along with portions of the 

conventional Brookian Topset, Brookian Clinoform, Brookian 

Topset Structural North, Brookian Topset Structural South, 

Brookian Clinoform Structural North and, Brookian Clinoform 

Structural South AUs from the 2005 Oil and Gas Assessment 

of Central North Slope, Alaska (Garrity and others, 2005) as 

summarized in table 2.

As previously discussed, the Tuluvak, Schrader Bluff, 

and Prince Creek Formations have been jointly assessed in this 

report. The Tuluvak Formation (fig. 6) is Turonian-Coniacian 

in age and outcrops generally consist of conglomerate, 

sandstone, shale, carbonaceous shale, and coal. The Tuluvak 

Formation for the most part is poorly exposed in outcrop, 

but subsurface well-log data indicate thicknesses range 

from 140 ft (43 m) thick in the Colville Delta 1 well to as 

much as 1,450 ft (442 m) thick in the Aufeis Unit 1 well 

(as documented in the USGS Alaska formation “tops file”). 

The age of the Schrader Bluff Formation is Santonian to 
6. Gas Hydrate Assessment Methodology 41

Maastrichtian. The unit consists dominantly of marine 

sandstones and shale, with the upper part mostly of shallowmarine sandstones that grade upward into sandstones of the 

overlying Prince Creek Formation (fig. 6). The thickness of 

the Schrader Bluff Formation is as much as roughly 2,500 ft 

(roughly 762 m) in the Chandler River region and decreases 

northward to about 1,800 ft (549 m) in the Umiat area 

(fig. 1A). The Prince Creek Formation (fig. 6) is Campanian 

through Paleocene in age, and is characterized in outcrop by 

interbedded conglomerate, sandstone, mudstone, carbonaceous 

shale, and coal; no complete section, however, is exposed. 

Because of its lithologic similarity with the underlying 

Schrader Bluff Formation, the two formations are difficult 

to separate in the subsurface. The aggregate thickness of the 

undifferentiated Prince Creek and Schrader Bluff Formations 

ranges from about 100 ft (30 m) to almost 5,000 ft (1,524 m). 

The structural characteristics of this AU are similar to those 

described above in the Nanushuk Formation Gas Hydrate 

AU, with east-west-trending detachment folds in the foothills 

regions and only slightly deformed and gently east-dipping 

strata in the coastal plain.

6.a.3. Sagavanirktok Formation Gas Hydrate

Assessment Unit

The Sagavanirktok Formation Gas Hydrate AU (fig. 22) 

encompasses just over 6,776,320 acres (roughly 10,588 mi2) 

in the east-central part of the North Slope (fig. 1A–B). The 

western and southern boundaries of the AU represent the 

subcrop of the Sagavanirktok Formation reservoir facies with 

the base of the permafrost section within the limits of the gas 

hydrate stability zone based on drill-hole data and a limited 

number of 2D seismic lines (fig. 24). Well-log picks for the 

Sagavanirktok Formation from 253 wells in the USGS Alaska 

formation “tops file” extended the eastern boundary of the AU 

to the Canning River (fig. 1A). Because of the lack of drilling 

in ANWR, 2D seismic data were used to estimate the downdip 

intersection of the Sagavanirktok reservoir facies with the gas 

hydrate stability zone. The northern boundary of the AU is 

defined mostly by the limit of the Alaska State Waters (from 

the mean high water line out to 3 nautical miles).

Much like the case for the other two assessed gas hydrate 

AUs, the Sagavanirktok Formation Gas Hydrate AU is mostly 

limited to the topset seismic facies as identified from the 

USGS regional 2D seismic lines. Project-developed well-log 

correlation sections (Lewis and Collett, 2013), along with the 

published well-log correlation sections from Decker (2007), 

provided basic data for outlining the distribution of the 

reservoir facies in this AU. It is important to note the well-log 

inferred and cored gas hydrates in the “Eileen accumulation” 

along the western border of the PBU (fig. 23) (Collett, 

1993, 2002) are within reservoir rocks of the Sagavanirktok 

Formation Gas Hydrate AU (see “Reservoir Rocks” section of 

this report).

Most of the Sagavanirktok Formation Gas Hydrate AU 

is coincident with (1) the Sagavanirktok Formation Coalbed 

Gas AU (Roberts, 2008); (2) the conventional Brookian 

Topset and Brookian Clinoform North AUs that were defined 

for the 2002 Petroleum Resource Assessment of the National 

Petroleum Reserve in Alaska (Bird and Houseknecht, 

2002); (3) portions of the conventional Brookian Topset, 

Brookian Clinoform, Brookian Topset Structural North, 

Brookian Topset Structural South, Brookian Clinoform 

Structural North and, Brookian Clinoform Structural South 

AUs that were defined for 2005 Oil and Gas Assessment of 

Central North Slope, Alaska (Garrity and others, 2005); and 

(4) portions of the Topset Play, Thin Skinned Thrust-Belt 

Play, Turbidite Play, and Wedge Play that were defined for the 

1999 Arctic National Wildlife Refuge 1002 area assessment 

(ANWR Assessment Team, U.S. Geological Survey, 1999) 

(see table 2).

The Sagavanirktok Formation (fig. 6) is PaleoceneMiocene in age and generally consists of conglomerate, 

sandstone, mudstone, carbonaceous shale, and coal. It was 

deposited in a northeast-prograding deltaic system (Molenaar, 

1983), and becomes younger from southwest to northeast 

across the AU. The formation also thickens from the southwest 

to the northeast, with a maximum thickness of about 9,000 ft 

(2,743 m) along the northeastern boundary of the AU. 

Structurally, most of the AU lies north of the detachment folds 

that characterize the Foothills province (fig. 1B), although the 

Sagavanirktok Formation is exposed on the limbs of gently 

folded anticlines along the southeastern boundary of the AU. 

In the greater PBU area, the Sagavanirktok Formation is 

also cut by faults that are generally downthrown to the east 

(displacements from 50 to 200 ft; 15 to 61 m) that are also 

believed to provide pathways for gas migration from deeply 

buried hydrocarbon sources into the overlying hydrate-bearing 

reservoirs as reviewed in “Section 4.c. Gas Source and 

Migration” of this report.

6.b. Assessment Unit Probabilities

After defining the limits of the three gas hydrate 

AUs, the assessment unit probabilities for each AU was 

determined. The assessment-unit probabilities as determined 

for each of the AUs in this study (as further reviewed in the 

Assessment-Data Form section of this report) relate a series 

of geologic risks associated with the existence of gas hydrate 

in each the AUs. In this assessment, three risking elements 

(attributes) of charge, rocks, and timing address the question 

of the probability of occurrence of at least one gas hydrate 

accumulation of minimum size, somewhere in the AU, that 

has the potential to be added to reserves (Schmoker and Klett, 

2005). Each element in this risking structure applies to the AU 

as a whole, and each geologic element in an AU is reasonably 

homogeneous in terms of charge, rocks, and timing. In this 

assessment, the combination of geologic probabilities and the 

number and size of undiscovered accumulations (as reviewed 
42 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

in the next two sections and detailed in the accompanying 

appendices) yield the probability distribution for the amount 

of technically producible gas stored within the gas hydrate 

accumulations in each AU.

6.c. Undiscovered Gas Hydrate 

Accumulations—Sizes of Accumulations

Two of the critical components of the USGS assessment 

methodology are the accurate prediction of (1) the expected 

size and (2) the number of undiscovered hydrocarbon 

accumulations. This assessment of the gas hydrate resources 

on the North Slope relied heavily on the analysis of industryacquired three-dimensional seismic data, which used to 

characterize the size, number, and distribution of gas hydrate 

accumulations in each of the three AUs.

The results of the MPU gas hydrate 3D seismic 

prospecting study of Inks and others (2009), as reviewed in 

the “Reservoir Rocks” section of this report, provided the 

starting point for predicting the size of undiscovered gas 

hydrate accumulations on the North Slope. Inks and others 

(2009) presented a seismic-evaluation workflow designed to 

identify gas hydrate prospects (accumulations) and to estimate 

the volume of gas within the seismic-inferred gas hydrate 

accumulations. They identified a total of 14 seismic-inferred 

gas hydrate accumulations within the MPU (fig. 10) and 

estimated the in-place volume of gas within each accumulation 

(table 3). The identification of gas hydrate in the sandstone 

parts of the Sagavanirktok Formation by Inks and others 

(2009) was based primarily on seismic character analysis and 

correlation with well-log responses.

Rock-physics modeling and seismic trace modeling by 

Lee and others (2009) were used to establish seismic attributes 

for various types of gas hydrate accumulations. Modeled 

seismic amplitudes are small at relatively low gas hydrate 

saturations near 40 percent, and become larger with increasing 

gas hydrate saturations. In this study, a large positive seismic 

amplitude response signified highly saturated gas hydratebearing sediments. The modeling of Lee and others (2009) 

documented that the quality (that is, mostly frequency content) 

of the MPU 3D seismic volume limited the identification of 

gas hydrate occurrences to a minimum thickness of roughly 

25 ft (roughly 8 m) and a minimum saturation of roughly 

40 percent gas hydrate; gas hydrate occurrences below these 

values could not be identified with the 3D volume used in 

this study.

To calculate gas hydrate saturations and thicknesses of 

the gas hydrate accumulations in the MPU, the “thin-bed” 

modeling approach as described by Lee and others (2009) 

and Inks and others (2009) was used. For each inferred gas 

hydrate occurrence in this modeling approach, a time isochron 

of the wavelet from peak to trough was calculated, and the 

amplitudes of both the peak and trough were extracted. 

In each case, the seismic amplitude of the peak event and 

the travel-time between the peak and trough were used to 

calculate the thickness of the hydrate-bearing unit and the gas 

hydrate saturation within each accumulation (fig. 25A–B). 

This information was then used to compute the in-place 

volume of gas within each of the seismic inferred gas hydrate 

accumulations in the MPU (fig. 10, table 3). For this study, 

statistical distributions for bulk rock volume, sediment 

porosity, gas hydrate saturation, and net-to-gross reservoir 

thickness were used and applied based on specific ranges 

of values for each of the individual gas hydrate intervals 

examined in this study. Volumetric calculations using a 

standard Monte Carlo simulation method were performed 

for each seismic-inferred gas hydrate accumulation. The 

Monte-Carlo-derived median in-place gas volumes calculated 

for each of the gas hydrate accumulations in the MPU 

(table 3) were taken forward in the assessment process as the 

primary information on the expected size of the gas hydrate 

accumulations. These calculated volumes thus represent 

one set of potential analogs for undiscovered gas hydrate 

accumulations within areas with no 3D seismic data coverage.

To expand the database of analog gas hydrate 

accumulations, four additional 3D seismic volumes from 

NPRA were subjected to the same gas hydrate prospecting 

protocol and volumetric analysis as applied to the MPU 3D 

seismic volume. As described in the “Northern Alaska Gas 

Hydrate Total Petroleum System and Assessment Units” 

section, the 3D seismic volumes from NPRA were used under 

strict confidentiality rules, and only the number of gas hydrate 

accumulations, size of each accumulation, and volume of gas 

within each accumulation are included in this report (table 3).

In most cases, the conventional USGS assessment 

methodology only considers the size of the oil and (or) gas 

accumulation being assessed in terms of technical recoverable 

resources; the size of the accumulation is normally obtained 

from historical production data in the AU or an appropriate 

analog. As discussed in the “Gas Hydrate Production 

Analysis” section of this report, there has been no confirmed, 

sustained production of gas from gas hydrate anywhere in 

the world. Thus, the next step in the Alaska gas hydrate 

assessment was to ascertain how much of the in-place gas 

within the 3D seismic-inferred gas hydrate accumulations 

could be technically produced (table 3). The first approach 

used in this assessment to calculate percent of gas that can 

be recovered from a gas hydrate accumulation was relatively 

straightforward and based mostly on simple reservoir 

engineering concepts. As a starting point, it was assumed 

that gas hydrate dissociation in the annular space around the 

producing well is complete and that the dissociation front 

moves away from the borehole as production continues 

through time (that is, no gas hydrate remaining as isolated 

pockets or lenses in the annular space).

The borehole annular volume, which was previously 

filled with gas hydrate, is now filled with a likely mixture 

of water and gas that has evolved from the dissociated 

gas hydrate. But if it is assumed that the annular volume 

is completely filled with gas from dissociated hydrate (no 

water) at abandonment, all of the water and other gas released 
6. Gas Hydrate Assessment Methodology 43

Table 3. List of 3D seismic imaged gas hydrate accumulations in the Milne Point Unit and the National Petroleum Reserve in Alaska, 

listed by the name of the accumulation and associated gas hydrate assessment unit. Also listed is the areal size of each accumulation 

along with the estimated median in-place and technical recoverable volume of gas within each accumulation (see figs. 27, 28).

[mi2, square miles; km2, square kilometers; bcf, billion cubic feet]

Milne Point Unit—

Gas hydrate accumulation Formation Area(mi2

)

Area

(km2)

Area

(acres)

Gas hydrate

assessmnet unit

Median in-place

volume of gas

(bcf)

Median technical

recoverable volume 

of gas

(bcf)

Grays Peak Sagavanirktok 0.1 0.3 85 SAG 6 5

Uncompahgre Peak Sagavanirktok 0.3 0.8 167 SAG 11 9

Pikes Peak Sagavanirktok 0.5 1.3 298 SAG 13 11

Redcloud Peak Sagavanirktok 0.3 0.8 194 SAG 18 15

Blanca Peak Sagavanirktok 0.5 1.3 328 SAG 22 19

Mt. Bierstadt Sagavanirktok 0.4 1.0 268 SAG 32 27

Maroon Peak Sagavanirktok 0.6 1.6 375 SAG 33 28

Mt. Princeton Sagavanirktok 0.7 1.8 449 SAG 38 32

Mt. Bierstadt Sagavanirktok 0.5 1.3 332 SAG 42 36

Mt. Sneffels Sagavanirktok 0.8 2.1 516 SAG 46 39

Mt. Elbert “D” Sagavanirktok 0.4 1.0 267 SAG 52 44

Mt. Antero Sagavanirktok 1.5 3.9 955 SAG 75 64

Mt. Elbert “C” Sagavanirktok 1.7 4.4 1,106 SAG 93 79

Crestone Peak Sagavanirktok 2.7 7.0 1,728 SAG 186 158

National Petroleum 

Reserve in Alaska—

Gas hydrate accumulation

Formation Area

(mi2

)

Area

(km2)

 Area

(acres) 

Gas hydrate

assessment unit

Median in-place

volume of gas

(bcf)

Median technical 

recoverable

volume of gas

(bcf)

Long's Peak Schrader Bluff 1.7 4.42 1,085 TSBPC 33 28

Windom Peak Prince Creek 1.6 4.1 1,007 TSBPC 39 33

Mt. Columbia Tuluvak 4.3 11.2 2,757 TSBPC 132 112

Humboldt Peak Prince Creek 5.9 15.2 3,760 TSBPC 141 120

Mt. Massive Tuluvak 6.9 17.7 4,384 TSBPC 190 162

Sunlight Peak Prince Creek 8.9 23.2 5,725 TSBPC 201 171

Mt. Harvard Tuluvak 7.9 20.6 5,080 TSBPC 210 179

Mt. Bross Tuluvak 11.6 29.9 7,397 TSBPC 293 249

Kit Carson Peak Tuluvak 12.8 33.2 8,206 TSBPC 382 325

Mt. Evans Tuluvak 22.9 59.3 14,651 TSBPC 611 519

NAN = Nanushuk Formation Gas Hydrate Assessment Unit

TSBPC = Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate Assessment Unit

SAG = Sagavanirktok Formation Gas Hydrate Assessment Unit

from the hydrate must have been produced up the wellbore. 

As shown in figure 26, at a well-abandonment pressure of 

25 percent of the initial assumed formation pressure, roughly 

85 percent of the original in-place gas hydrate must have 

been produced, and the borehole annular space could hold 

no more than roughly 15 percent of the gas evolved from the 

dissociated gas hydrate. It is acknowledged that the borehole 

annular space would likely contain a significant volume of 

water, but for calculation purposes, the presence of water in 

the borehole annular space would result in even higher gas 

recovery ratios. In this assessment, a gas hydrate recovery 

ratio of 85 percent (assuming a well-abandonment pressure 

25 percent of hydrostatic) was used to convert the in-place 

gas volume estimates within each of the 3D seismic-inferred 

hydrate accumulations to a technically recoverable gas volume 

(table 3). It is important to emphasize that numerical gas 

hydrate production simulations (as reviewed by Anderson 

and others, 2011a, 2011b) also indicate relatively high gasrecovery ratios for producing gas hydrate accumulations.

Upon closer examination of the relative size (volume 

of technically recoverable gas) of the 3D seismic-inferred 

gas hydrate accumulations (table 3), it was determined that 

the accumulations as imaged in NPRA were generally larger 

than those in the MPU. Also, the seismic-imaged gas hydrate 

accumulations in NPRA were in reservoirs associated with the 

Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate 

AU, whereas the MPU gas hydrate accumulations are limited 

to reservoirs within the Sagavanirktok Formation Gas Hydrate 

AU. Because of the apparent size difference between the gas 

hydrate accumulations in the Tuluvak-Schrader Bluff-Prince 

Creek and Sagavanirktok AUs, it was decided not to merge 

the accumulation sizes from the NPRA and MPU 3D seismic 

mapping effort and to use each set of accumulation sizes as 

independent analogs for inferred gas hydrate accumulations 

in various geologic settings throughout the Northern Alaska 

Gas Hydrate TPS. In figures 27A–B, the size (volume of 

technically recoverable gas) of the 3D-imaged gas hydrate 

accumulations in the MPU and NPRA have been depicted 
44 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Figure 25. Maps showing pre-drill estimates of A, gas hydrate saturation, and B, reservoir thickness for hydrate unit C in the Mount Elbert 

prospect. Modified from Inks and others (2009). As a condition of the seismic data use agreement, the latitude and longitude of the seismic 

data volume or the interpreted features cannot be shown on these maps.

Faults

Mount Elbert C Hydrate 

 Prospect interpolated 

 saturation boundary

Interpolated hydrate saturation—

 In percent 

86

82

78

74

70

66

62

58

54

50

46

90

N

EXPLANATION

0 2,000 FEET

0 500 METERS

73

77

69

65

61

57

53

49

45

41

37

Fault line

Mount Elbert C Hydrate 

 Prospect interpolated 

 saturation boundary

Net thickness—In feet

N EXPLANATION

0 2,000 FEET

0 500 METERS

A

B
6. Gas Hydrate Assessment Methodology 45

in two bar graphs. For the most part, the accumulation sizes 

shown in figures 27A–B are characterized by log-normal 

distributions with increasing accumulation sizes to the 

right on the x-axes. However, analyses of well log and 2D 

seismic-inferred gas hydrate accumulations from outside the 

3D seismic-imaged regions suggest that the accumulation 

sizes depicted in figures 27A–B may not fully represent the 

complete range of potential gas hydrate accumulation sizes 

within the Northern Alaska Gas Hydrate TPS.

Detailed 2D seismic mapping and well-log studies south 

of the MPU in the Eileen trend of the PBU (fig. 23) indicate 

the occurrence of fault-bounded gas hydrate accumulations 

considerably larger than those mapped in the MPU, with one 

accumulation covering an area of roughly 11 mi2

. It appears 

the Sagavanirktok section in the MPU, which overlies the 

Barrow arch, is more highly faulted than the same reservoirs 

to the south into the PBU, thus leading to the variable 

accumulation sizes from north-to-south along the Eileen gas 

hydrate trend. To more accurately represent the full range of 

the potential gas hydrate-accumulation sizes in the Eileen 

trend, two hypothetical accumulations were added to the MPU 

3D seismic-inferred distribution (fig. 28A), with the size of 

these two larger accumulations imported from the NPRA 3D 

seismic-inferred size distribution (table 3, fig. 27B).

It was also determined that the NPRA 3D seismicinferred accumulation size distribution (as depicted in 

figure 27B) did not accurately represent the full range of 

gas hydrate accumulation sizes likely to occur in NPRA. 

As discussed above, the ability of a given 3D seismic volume 

to image a potential gas hydrate accumulation is dependent 

on the frequency content of the available seismic data and 

the thickness and relative concentration of gas hydrate 

occurrences in the area being assessed. The frequency 

content of most of the NPRA 3D seismic volumes was 

considerably less than that of the MPU 3D volume used 

in this study; thus, it was assumed that some of the smaller 

Figure 26. Gas hydrate recovery ratio (percent of in-place gas 

within gas hydrates that would be recovered) as a product of the 

producing well abandonment pressure (pressure is shown as a 

percent of hydrostatic pore pressure).

gas hydrate accumulations in NPRA were not imaged. It 

was decided to augment the NPRA 3D seismic-inferred gas 

hydrate accumulation distribution with three relatively small 

hypothetical accumulations (fig. 28B) as imported from the 

MPU seismic inferred size distribution (table 3, fig. 27A).

The last critical step in the analysis of the “modified” 

MPU and NPRA 3D seismic-inferred gas hydrate 

accumulation size distributions (table 3, figs. 28A–B) was the 

selection of the minimum accumulation size to be considered 

in this assessment. Based mostly on the statistical nature 

of the two gas hydrate-size distributions, the minimum 

accumulation size was assumed to be 20 billion cubic feet 

(BCF) (3.33 Million Barrels of Oil Equivalent (MMBOE)) 

of technically recoverable gas. This minimum accumulation 

size is smaller than those used in other USGS assessments 

in northern Alaska, in recognition of the fact that most of the 

seismically inferred gas hydrate accumulations are in stacked 

reservoir sections and would likely be produced together from 

the same wells and production facilities.

The selection of the minimum, median, and maximum 

undiscovered accumulation sizes for each of the three gas 

hydrate AUs (as required within the USGS assessment 

methodology) is further discussed in the “Assessment-Data 

Form” section of this report.

6.d. Undiscovered Gas Hydrate Accumulations—

Number of Accumulations

The next most critical component in the USGS 

assessment methodology is the accurate prediction of the 

number of undiscovered gas hydrate accumulations that 

may exist in the Northern Alaska Gas Hydrate TPS. It was 

again decided to rely on the MPU and NPRA 3D seismic 

analysis results to predict the possible number of gas hydrate 

accumulations in each of the AUs. As discussed earlier, the 

3D seismic data volume from the MPU (figs. 9, 10, 24) covers 

an area of 155 mi2

, whereas the four 3D seismic volumes in 

NPRA cover an area of 729 mi2

. A total of nine gas hydrate 

accumulations (exceeding the minimum accumulation size 

for this assessment of 20 BCF) were identified within the 

coverage area of the MPU 3D seismic volume. Similarly, there 

were 10 gas hydrate accumulations (exceeding the minimum 

accumulation size for this assessment of 20 BCF) within 

the area covered by the four 3D seismic volumes in NPRA. 

In each case, the number of seismic-inferred gas hydrate 

accumulations relative to the area each survey covers was 

used to develop a “gas hydrate discovery ratio,” which for 

the MPU 3D volume is 0.0581 gas hydrate accumulations for 

every square mile and for the NPRA 3D volumes is 0.0137 

gas hydrate accumulations for every square mile. These 

“gas hydrate discovery ratios” were then used to estimate 

the number of gas hydrate accumulations (exceeding the 

minimum accumulation size) that may be within the areas 

of the North Slope without available 3D seismic coverage.

0

10

20

30

40

50

60

70

80

90

100

0 10 20 30 40 50 60 70 80 90 100

Percent of hydrostatic pressure, in percent

Percent gas recovery, in percent
46 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Figure 27. Bar-graph showing sizes of 3D-imaged gas hydrate accumulations in A, the Milne Point Unit (MPU, see fig. 10 

for location) and B, the National Petroleum Reserve in Alaska (NPRA). Detailed data are given in table 3.

Grays

Peak

Pikes

Peak

Redcloud

Peak

Blanca

Peak

Mount

Bierstadt

Maroon

Peak

Mount

Princeton

Mount

Bierstadt

Mount

Sneffels

Mount

Elbert "D"

Mount

Antero

Mount

Elbert “C”

Crestone

Peak

Uncompahgre

Peak

Gas hydrate accumulation 

Volume of gas, in billion cubic feet

180

160

140

120

100

80

40

0

20

60

A

0

40

120

200

Gas hydrate accumulation 

Volume of gas, in billion cubic feet

80

160

240

280

320

360

400

440

480

520

560

Long’s

Peak

Windom

Peak

Mount

Columbia

Humboldt

Peak

Mount

Massive

Sunlight

Peak

Mount

Harvard

Mount

Bross

Kit Carson

Peak

Mount

Evans

B
6. Gas Hydrate Assessment Methodology 47

Figure 28. Bar-graph showing sizes of the 3D-imaged gas hydrate accumulations in A, the Milne Point Unit (MPU; see fig. 

10 for location), and B, the National Petroleum Reserve in Alaska (NPRA), that have been modified to account for larger and 

smaller inferred gas hydrate accumulations in the MPU and NPRA, respectively. Also accumulations with sizes below the 

minimum accumulation size (20 BCF) have been deleted from these plots.

Median 44 billion cubic feet

0

80

120

360

Mount

Bierstadt

Maroon

Peak

Mount

Princeton

Mount

Bierstadt

Mount

Sneffels

Mount

Elbert "D"

Mount

Antero

Mount

Elbert "C"

Crestone

Peak

Eileen

Westend 1

Eileen

Westend 2

Gas hydrate accumulation 

Volume of gas, in billion cubic feet

40

60

100

140

160

180

200

220

240

260

280

300

320

340

20

A

0

40

120

200

Long’s

Peak

Windom

Peak

TSBPC 1

TSBPC 1

TSBPC 2 TSBPC 3 Mount

Columbia

Humboldt

Peak

Mount

Massive

Sunlight

Peak

Mount

Harvard

Mount

Bross

Kit Carson

Peak

Mount

Evans

Gas hydrate accumulation 

Volume of gas, in billion cubic feet

80

160

240

280

320

360

400

440

480

520

560

Median 120 billion cubic feet

EXPLANATION

Tuluvak-Schrader Bluff-Prince Creek 

 Formations Gas Hydrate Assessment 

 Unit and accumulation identifier

B
48 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Before attempting to use the MPU or NPRA 3D seismicderived “gas hydrate discovery ratios,” it was recognized that 

these ratios are subject to uncertainty and are best represented 

as a probability distribution. For this assessment, the actual 

“gas hydrate discovery ratio” calculated from the MPU 

(0.0581 accumulations per square mile) and NPRA (0.0137 

accumulations per square mile) prospecting efforts were set 

at the statistical mode; for the distribution around the mode, 

the maximum number of accumulations in each case was 

set at three times the value of the mode, and the minimum 

number of accumulations was set at the actual number of 

seismic identified gas hydrate accumulations in each of the 

AUs or was set at one in AUs with no 3D seismic inferred gas 

hydrate accumulations.

The next and final step in the assessment was to assign 

the appropriate “gas hydrate discovery ratio – distribution” 

(table 4) to each AU. However, the regional analysis 

of available 2D seismic and well-log data, along with 

geochemical analyses of well drill cuttings, core samples, 

and mud logs, indicates that the geologic controls on the 

occurrence of gas hydrate are not uniform throughout the 

defined AUs (Lorenson and others, 2011). As discussed in 

the “Gas Source and Migration” section of this report, most 

of the gas within the near-surface Eileen and Tarn gas hydrate 

accumulations had migrated from deeply buried thermogenic 

sources and is closely linked to the presence of conventional 

oil and gas fields. Thus, by considering the role of gas source 

and migration within the gas hydrate petroleum system, it is 

reasonable to assume that in areas with known conventional 

oil and gas accumulations and (or) in areas with evidence of 

an active petroleum system delivering thermogenic gas to the 

gas hydrate stability zone, there is an increased likelihood 

that these anomalous areas will contain significantly more 

gas hydrate accumulations.

To assess the potential contribution of thermogenic gas 

migration to the formation of gas hydrate accumulations on 

the North Slope, gas geochemistry data from 35 “wells-ofopportunity” (table 5, fig. 29; Lorenson and others, 2011; 

Lorenson and Collett, 2011) were examined. The “wells-ofopportunity,” as described by Lorenson and Collett (2011), are 

mostly industry exploratory and development wells from which 

the USGS received drill cuttings and flowed gas samples in 

order to ascertain the composition and source of the gas within 

the inferred gas hydrate accumulations. For the wells listed in 

table 5 and highlighted on the map in figure 29 as wells with 

either significant or limited evidence of thermogenic gas in the 

gas hydrate stability zone, the area around these wells is more 

likely to contain a higher number of gas hydrate accumulations. 

The same is also true for the area around known conventional 

oil and gas fields (table 6). As discussed above, gas hydrate 

accumulations are commonly closely associated with more 

deeply buried conventional oil and gas fields that have leaked 

or possibly spilled gas that has migrated into the overlying gas 

hydrate stability zone, thus leading to a greater likelihood for 

the occurrence of gas hydrate.

In order to assess the relative impact of thermogenic 

gas sources on the number of gas hydrate accumulations 

in each of the AUs, the “gas hydrate discovery ratio—

distributions,” as described above and listed in table 4, were 

expanded to include three options: (1) high probability, 

(2) middle probability, and (3) low probability. Within an 

area determined to have a high probability for the presence 

of thermogenic gas in the gas hydrate stability zone, the 

actual seismic-derived “gas hydrate discovery ratio—

distribution” calculated from the available 3D surveys (table 

4: mode of 0.0581 gas hydrate accumulations per square 

mile for the MPU and 0.0137 gas hydrate accumulations 

per square mile for NPRA) was assigned to this area. 

For an area with a middle probability for the presence of 

thermogenic gas in the gas hydrate stability zone, the actual 

seismic derived “gas hydrate discovery ratio—distribution” 

was reduced by 50 percent, which yielded a new middle 

probability mode of 0.0278 gas hydrate accumulations per 

square mile for the MPU distribution and 0.0083 gas hydrate 

accumulations per square mile for the NPRA distribution 

(table 4). For an area with a low probability for the presence 

of thermogenic gas in the gas hydrate stability zone, the 

actual seismic-derived “gas hydrate discovery ratio—

distribution” was again reduced by another 50 percent, which 

yielded a new low probability mode of 0.0139 gas hydrate 

Table 4. Determinations of “gas hydrate discovery ratio—

distributions” resulting from the Milne Point Unit and the 

National Petroleum Reserve in Alaska 3D seismic gas hydrate 

prospecting effort.

Milne Point Unit Number of accumulations

per square mile

High probability

Minimum 0.0111

Mode 0.0581

Maximum 0.1750

Middle probability

Minimum 0.0056

Mode 0.0278

Maximum 0.0833

Low probability

Minimum 0.0028

Mode 0.0139

Maximum 0.0417

National Petroleum Reserve

in Alaska

Number of accumulations

per square mile

High probability

Minimum 0.0056

Mode 0.0137

Maximum 0.0417

Middle probability

Minimum 0.0028

Mode 0.0083

Maximum 0.0250

Low probability

Minimum 0.0028

Mode 0.0056

Maximum 0.0167
6. Gas Hydrate Assessment Methodology 49

Table 5. List of wells of opportunity (see fig. 29) in which analyses of gas samples have been used to ascertain the composition and 

source of the gas within each of the gas hydrate assessment units in northern Alaska. Wells highlighted in blue are characterized by 

“significant” evidence for thermogenic gas in the mapped limits of the gas hydrate stability zone, whereas wells highlighted in green 

are assessed to have “limited” evidence of thermogenic gas in the gas hydrate stability zone. (API, American Petroleum Institute)

Well API number Operator current name Well name Surface

latitude

Surface

longitude

Wells with significant evidence of thermogenic gas

50029233020000 BP EXPL ALASKA INC MT. ELBERT 1 70.4556 149.4132

50029232950000 CONOCOPHILLIPS AK KUPARUK RIVER UNIT WEST SAK 1R-EAST 70.3954 149.5591

50029232960000 CONOCOPHILLIPS AK KUPARUK RIVER UNIT WEST SAK 1H-SOUTH 70.3949 149.5579

50029210840000 ARCO ALASKA INC KUPARUK RIVER UNIT 2B-10 70.2894 149.9375

50029211840000 ARCO ALASKA INC KUPARUK RIVER UNIT 2D-15 70.2840 149.7617

50029206990000 ARCO OIL & GAS CORP WEST SAK 23 70.4037 149.9383

50103200860000 ARCO ALASKA INC KUPARUK RIVER UNIT 3H-9 70.4118 150.0117

50029216560000 ARCO ALASKA INC KUPARUK RIVER UNIT 3K-9 70.4332 149.7608

50029219970000 CONOCO INCORPORATED MILNE POINT UNIT E-4 70.4554 149.4367

50029203530000 SOHIO PETROLEUM CO PRUDHOE BAY UNIT R-1 70.3455 148.9108

50029220470000 BP EXPL ALASKA INC PRUDHOE BAY UNIT S-26 70.3536 149.0302

50029220460000 BP EXPL ALASKA INC PRUDHOE BAY UNIT Z-7 70.2977 149.1955

50029217870000 BP EXPL ALASKA INC PRUDHOE BAY UNIT Z-8 70.2978 149.1996

50103203490000 PHILLIPS ALASKA INC KUPARUK RIVER UNIT TARN 2N-305 70.1713 150.3143

50103203600000 PHILLIPS ALASKA INC ATLAS 1 70.1518 150.5505

50029230610000 BP EXPL ALASKA INC MILNE PT UNIT SCHRADER BLUFF S-15 70.4097 149.4663

50103204770000 CONOCOPHILLIPS AK CARBON 1 70.2479 151.8888

50103204800000 CONOCOPHILLIPS AK SPARK 4 70.2884 151.7924

50103204790000 CONOCOPHILLIPS AK SCOUT 1 70.2867 151.9571

50103205060000 CONOCOPHILLIPS AK IAPETUS 2 70.4079 151.1831

50279200170000 FEX LP AMAGUQ 2 70.3932 155.8066

50029232990000 CONOCOPHILLIPS AK ANTIGUA 1 70.1809 149.5267

50279200110000 CONOCOPHILLIPS AK KOKODA 1 70.2850 153.1375

50279200120000 CONOCOPHILLIPS AK KOKODA 5 70.3344 153.2046

50103204810000 CONOCOPHILLIPS AK PLACER 1 70.3467 150.3983

Wells with limited evidence of thermogenic gas

50279200180000 FEX LP AKLAQYAAQ 1 70.5573 155.4204

50279200130000 CONOCOPHILLIPS AK NOATAK 1 70.3802 153.1335

50301200030000 U S DEPT OF INTER AK WAINWRIGHT 1 70.6441 160.0237

50103201900000 EXXON CO USA THETIS ISLAND 1 70.5539 150.1522

50279200090000 TOTAL E&P USA INC CARIBOU 26-11 1 70.1898 153.0876

Wells with no evidence of thermogenic gas

50279200190000 FEX LP AKLAQ 6 70.7123 154.6077

accumulations per square mile for the MPU distribution and 

0.0056 gas hydrate accumulations per square mile for the 

NPRA distribution (table 4).

The AU maps in figures 30, 31, and 32 depict the areas in 

each AU that exhibit low, middle, or high probability for the 

presence of thermogenic-derived gas hydrate accumulations. 

The Nanushuk Formation Gas Hydrate AU (fig. 30, table 7) 

was divided into four regions with two low probability and 

two middle probability map units; each area was assigned the 

appropriate NPRA “gas hydrate discovery ratio—distribution” 

as listed in table 4. The Tuluvak-Schrader Bluff-Prince Creek 

Formations Gas Hydrate AU (fig. 31, table 8) was divided 

into six regions with one low probability, three middle 

probability, and two high probability map units; each area 

was assigned the appropriate NPRA “gas hydrate discovery 

ratio—distribution” as listed in table 4. The Sagavanirktok 

Formation Gas Hydrate AU (fig. 32, table 9) was divided into 

five regions with one low probability, three middle probability, 

and one high probability map units; each area was assigned the 

appropriate MPU “gas hydrate discovery ratio—distribution” 

as listed in table 4.

The selection of the final minimum, mode, and maximum 

number of undiscovered gas hydrate accumulations, as 

required within the USGS assessment methodology, for each 

of the three gas hydrate AUs are further discussed in the 

“Assessment-Data Form” section of this report.

7. Assessment-Data Form

Information required for the assessment of the 

undiscovered gas hydrate resources on the Alaska North Slope, 

was entered on a form termed the Seventh Approximation Data 

Form for Conventional Assessment Units (Klett and others, 

2005). The completed forms for each AU are reproduced in 

Appendixes A–1, A–2, and A–3. The assessment-data form 

contains six sections as described below.
Figure 29. Map showing locations of the wells of opportunity (table 5) from which the analysis of gas samples were used to ascertain the compositigas within each of the gas hydrate assessment units in northern Alaska. Also shown are the locations of discovered conventional oil and gas fields (tPetroleum Reserve in Alaska; ANWR, Alaska National Wildlife Refuge)

ARCTIC OCEAN

Prudhoe

Bay

BEAUFOR

CHUKCHI SEA

Point 

Barrow

Point

Hope 

Northwest Arctic Borough North Slope Borough

Arctic National W

National Petroleum Reserve-Alaska

168° 164° 160° 156° 152° 148° 144° 

71°

72°

70°69°68°

Brooks Range orogenic belt (Brooks  Range province)

EXPLANATION

Oil discovery and fieldGas discovery and fieldNanushuk Formation Gas Hydrate  Assessment Unit boundary

Area of map

0 25 50 75 100 MILES0 25 50 75 100 KILOMETERS

Base from U.S. Geological Survey digital dataAlbers Conical Equal area projectionStandard parallels 55°N and 65°NCentral meridian 154°W, latitude of origin 50°NNorth American Datum of 1983 (NAD 83)

Tuluvak-Schrader Bluff-Prince Creek  Formations Gas Hydrate Assessment  Unit boundary

Sagavanirktok Formation Gas Hydrate  Assessment Unit boundaryOuter limit of Alaska State waterOil and gas discovery and field boundary

Well with thermogenic gasWell with limited thermogenic gasWell with no thermogenic gas
7. Assessment-Data Form 51

7.a. Identification Information

Identification information includes the assessors’ names, 

the date of the assessment meeting at which input data were 

discussed and reviewed, and the names and numerical codes 

for each AU. Following a numbering system established by 

the USGS to facilitate petroleum resource assessments, the 

following unique numbers have been assigned to the Alaska 

North Slope gas hydrate TPS and AUs:

Northern Alaska Gas Hydrate TPS: 500102

Sagavanirktok Formation Gas Hydrate AU: 50010201

Tuluvak-Schrader Bluff-Prince Creek Formations Gas

Hydrate AU: 50010202

Nanushuk Formation Gas Hydrate AU: 50010203

In this system “5” denotes the region (North America), 

“001” denotes the province (North Slope Alaska), and “02” 

denotes the TPS. The AUs are numbered as shown above with 

the last two digits denoting the specific AU.

7.b. Characteristics of Assessment Unit

This section of the form contains basic input data and 

information about the nature of the AU. In the first entry, 

the AU is classified as being either oil-prone or gas-prone. 

Because the assessment was for gas hydrates, it was assumed 

that all three AUs as defined contain only gas. The minimum 

accumulation size for all three AUs was set at 20 billion 

cubic feet (BCF) (3.33 MMBOE) of technically recoverable 

gas. Because none of the well-log- and (or) seismic-inferred 

gas hydrate accumulations on the North Slope have been 

produced, all of the AUs are considered hypothetical with no 

discovered accumulations exceeding the minimum gas hydrate 

accumulation size.

The assessment unit probability attributes for all three AUs 

were rated high, with a probability of 1.0 (or 100 percent) that 

there was at least one undiscovered gas hydrate accumulation 

greater than the minimum size existing in each AU. Ample 

evidence of gas hydrate occurrences in the Eileen and Tarn 

trends justifies the high ranking of the assessment unit 

probability for the Sagavanirktok Formation Gas Hydrate 

AU and the Tuluvak-Schrader Bluff-Prince Creek Formations 

Gas Hydrate AU. It can also be assumed that the Nanushuk 

Formation Gas Hydrate AU, being part of a prolific petroleum 

system, should have a high assessment unit probability ranking.

7.c. Undiscovered Accumulations

The third section of the data form is for recording the 

number and sizes of undiscovered oil and gas accumulations 

used to calculate the undiscovered resources that have potential 

for additions to reserves within the forecast span of 30 years. 

Minimum, median, and maximum values (F100, F50, and 

F0

 fractals) are estimated for the sizes of the undiscovered 

accumulations. The number of undiscovered accumulations, 

however, is reported as minimum, mode, and maximum values.

As discussed in the “Undiscovered Gas Hydrate 

Accumulations—Number of Accumulations” section and 

shown in tables 7, 8, and 9, the number of undiscovered 

gas hydrate accumulations has been derived from (1) the 

analysis of the petroleum system controlling the presence 

of gas hydrate in each AU and (2) the application of “gas 

hydrate discovery ratio—distributions” resulting from the 

analysis of the 3D seismic volumes in the MPU and NPRA. 

The actual values entered into the assessment-data form were 

slightly altered from the mathematically derived number of 

undiscovered gas hydrate accumulations as listed in tables 7, 

8, and 9. This was done for the purpose of more accurately 

predicting the minimum number of undiscovered gas hydrate 

accumulations and of rounding the estimated number of 

accumulations to the nearest significant value.

As discussed in the “Undiscovered Gas Hydrate 

Accumulations—Sizes of Accumulations” section and shown 

in figures 28A–B, the sizes of the undiscovered gas hydrate 

accumulations in each of the AUs were determined by 

applying the two accumulation-size distributions developed 

in this study from the analysis of the 3D seismic volumes 

in the MPU and NPRA. In all three AUs, the minimum 

accumulation size was set at 20 BCF (3.33 MMBOE). For 

the Sagavanirktok Formation Gas Hydrate AU, the MPU 3D 

seismic-derived accumulation size distribution as shown in 

figure 28A was used to derive a median accumulation size of 

45 BCF (rounded up from the mathematically derived value 

of 44 BCF). The maximum size of the accumulations in the 

Sagavanirktok Formation Gas Hydrate AU was projected from 

Table 6. List of conventional oil and gas fields (see fig. 29) used 

in part to assign “gas hydrate discovery ratio—distributions” to 

various portions of the gas hydrate assessment units.

Field Field

type Field Fieldtype

UMIAT Oil NORTHSTAR SADLEROCHIT Oil

SOUTH BARROW Gas NORTHSTAR SAG RIVER Oil

FISH CREEK Oil HEMI SPRINGS Oil

MEADE Gas NIAKUK Oil

SIMPSON Oil COLVILLE DELTA Oil

WOLF CREEK Gas SANDPIPER Oil

GUBIK Gas HAMMERHEAD Oil

SQUARE LAKE Gas STUMP ISLAND Oil

EAST UMIAT Gas POINT MCINTYRE Oil

PRUDHOE BAY Oil SIKULIK Gas

LISBURNE Oil BURGER Oil

KUPARUK Oil BADAMI Oil

SCHRADER BLUFF Oil STINSON Oil

WEST SAK Oil TARN Oil

UGNU Oil TABASCO Oil

KUPARUK Oil FIORD Oil

SAG RIVER Oil KALUBIK Oil

AURORA Oil KUVLUM Oil

KAVIK Gas CASCADE Oil

GWYDYR BAY Oil THETIS ISLAND
Figure 30. A, map of the Nanushuk Formation Gas Hydrate Assessment Unit showing areas outlined with high, middle or low “gas hydrate discovery 

table 7). B, same as A, but also includes locations of wells of opportunity and discovered oil and gas fields from figure 29. (NPRA, National Petroleum Alaska National Wildlife Refuge)

ARCTIC OCEAN

Prudhoe

Bay

BEAUFO

CHUKCHI SEA

Northwest Arctic Borough North Slope Borough

Arctic National 

National Petroleum

Reserve-Alaska

Point 

Barrow

Point

Hope

Low 2

Low 2

Middle 1

Low 1

Middle 2

168° 164° 160° 156° 152° 148° 144° 

71°

72°

70°69°68°

Brooks Range orogenic belt (Brooks Range province)

EXPLANATION

Nanushuk Formation Gas Hydrate Assessment Unit

Area of map

0 25 50 75 100 MILES0 25 50 75 100 KILOMETERS

Base from U.S. Geological Survey digital dataAlbers Conical Equal area projectionStandard parallels 55°N and 65°NCentral meridian 154°W, latitude of origin 50°NNorth American Datum of 1983 (NAD 83)

Nanushuk Formation Gas Hydrate Assessment Unit probability field unit boundary—Terms Low, Middle, and High represent the probability of accumulations in assessment unit. Number is an identifier

Outer limit of Alaska State water

A
Figure 30. A, map of the Nanushuk Formation Gas Hydrate Assessment Unit showing areas outlined with high, middle or low “gas hydrate discovery 

table 7). B, same as A, but also includes locations of wells of opportunity and discovered oil and gas fields from figure 29. (NPRA, National Petroleum Alaska National Wildlife Refuge)—Continued

ARCTIC OCEAN

Prudhoe

Bay

BEAUFO

CHUKCHI SEA

Point 

Barrow

Point

Hope

Northwest Arctic Borough North Slope Borough

Arctic Nationa

Low 2

Middle 1

Middle 2 Low 1

Nanushuk Formation Gas Hydrate Assessment  Unit probability field unit boundary—Terms  Low, Middle, and High represent the probability  of accumulations in assessment unit. Number  is an identifier 

168° 164° 160° 156° 152° 148° 144° 

71°

72°

70°69°68°

Brooks Range orogenic belt (Brooks  Range province)

EXPLANATION

Oil discovery and fieldGas discovery and fieldNanushuk Formation Gas Hydrate  AssessmentUnit boundary

Area of map

0 25 50 75 100 MILES0 25 50 75 100 KILOMETERS

Base from U.S. Geological Survey digital dataAlbers Conical Equal area projectionStandard parallels 55°N and 65°NCentral meridian 154°W, latitude of origin 50°NNorth American Datum of 1983 (NAD 83)

Outer limit of Alaska State waterOil and gas discovery and field boundaryWell with thermogenic gasWell with limited thermogenic gasWell with no thermogenic gas

National Petroleum Reserve-Alaska

B

Low 2
Figure 31. A, map of the Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate Assessment Unit showing areas outlined with high, middle or 

ratio—distributions” (see table 8). B, same as A, but also includes locations of wells of opportunity and discovered oil and gas fields from figure 29. (NReserve in Alaska; ANWR, Alaska National Wildlife Refuge)

ARCTIC OCEAN

Prudhoe

Bay

BEAUFOR

CHUKCHI SEA

Northwest Arctic Borough North Slope Borough

Arctic National 

National Petroleum Reserve-Alaska

Point 

Barrow

Point

Hope

High 2

High 2

High 1

Middle 1

Low 1

Middle 2

Middle 3

168° 164° 160° 156° 152° 148° 144° 

71°

72°

70°69°68°

Brooks Range orogenic belt (Brooks Range province)

EXPLANATION

Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate Assessment Unit

Area of map

0 25 50 75 100 MILES0 25 50 75 100 KILOMETERS

Base from U.S. Geological Survey digital dataAlbers Conical Equal area projectionStandard parallels 55°N and 65°NCentral meridian 154°W, latitude of origin 50°NNorth American Datum of 1983 (NAD 83)

Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate Assessment Unit probability field unit boundary—Terms Low, Middle, and High represent the probability of accumulations  in assessment unit. Number is an identifier

Outer limit of Alaska State water

A
Figure 31. A, map of the Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate Assessment Unit showing areas outlined with high, middle or 

ratio—distributions” (see table 8). B, same as A, but also includes locations of wells of opportunity and discovered oil and gas fields from figure 29. (NReserve in Alaska; ANWR, Alaska National Wildlife Refuge)—Continued

ARCTIC OCEAN

Prudhoe

Bay

BEAUFOR

CHUKCHI SEA

Point 

Barrow

Point

Hope

Northwest Arctic Borough North Slope Borough

Arctic National 

National Petroleum Reserve-Alaska High 2

High 2

High 1

Middle 1

Low 1

Middle 2

Middle 3

168° 164° 160° 156° 152° 148° 144° 

71°

72°

70°69°68°

Brooks Range orogenic belt (Brooks Range province)

EXPLANATION

Oil discovery and fieldGas discovery and field

Area of map

0 25 50 75 100 MILES0 25 50 75 100 KILOMETERS

Base from U.S. Geological Survey digital dataAlbers Conical Equal area projectionStandard parallels 55°N and 65°NCentral meridian 154°W, latitude of origin 50°NNorth American Datum of 1983 (NAD 83)

Tuluvak-Schrader Bluff-Prince Creek Formations  Gas Hydrate Assessment Unit probability field unit  boundary—Terms Low, Middle, and High represent  the probability of accumulations in assessment unit.  Number is an identifier

Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate Assessment Unit boundary

Outer limit of Alaska State waterOil and gas discovery and  field boundary

Well with thermogenic gasWell with limited thermogenic gasWell with no thermogenic gas

B
Figure 32. A, Map of the Sagavanirktok Formation Gas Hydrate Assessment Unit with the areas outlined with high, middle or low “gas hydrate discov

(table 9); B, with location of wells of opportunity and discovered oil and gas fields (fig. 29). (NPRA, National Petroleum Reserve in Alaska; ANWR, Alas

ARCTIC OCEAN

Prudhoe

Bay

BEAUFOR

CHUKCHI SEA

Northwest Arctic Borough North Slope Borough

Arctic National 

National Petroleum Reserve-Alaska

Point 

Barrow

Point

Hope

Middle 1

Middle 1

Low 1

High 1

Middle 3

Middle 2

168° 164° 160° 156° 152° 148° 144° 

71°

72°

70°69°68°

Brooks Range orogenic belt (Brooks Range province)

EXPLANATION

Sagavanirktok Formation Gas Hydrate Assessment Unit

Area of map

0 25 50 75 100 MILES0 25 50 75 100 KILOMETERS

Base from U.S. Geological Survey digital dataAlbers Conical Equal area projectionStandard parallels 55°N and 65°NCentral meridian 154°W, latitude of origin 50°NNorth American Datum of 1983 (NAD 83)

Sagavanirktok Formation Gas Hydrate Assessment Unit probability field unit boundary—Terms Low, Middle,  and High represent the probability of accumulations  in assessment unit. Number is an identifier

Outer limit of Alaska State water

A
Figure 32. A, Map of the Sagavanirktok Formation Gas Hydrate Assessment Unit with the areas outlined with high, middle or low “gas hydrate disco

(table 9); B, with location of wells of opportunity and discovered oil and gas fields (fig. 29). (NPRA, National Petroleum Reserve in Alaska; ANWR, AlasRefuge)—Continued

ARCTIC OCEAN

Prudhoe

Bay

BEAUFO

CHUKCHI SEA

Point 

Barrow

Point

Hope

Northwest Arctic Borough North Slope Borough

Arctic National 

National Petroleum Reserve-Alaska

Middle 1

Middle 1

Low 1

High 1

Middle 3

Middle 2

168° 164° 160° 156° 152° 148° 144° 

71°

72°

70°69°68°

Brooks Range orogenic belt (Brooks  Range province)

EXPLANATION

Oil discovery and fieldGas discovery and field

Area of map

0 25 50 75 100 MILES0 25 50 75 100 KILOMETERS

Base from U.S. Geological Survey digital dataAlbers Conical Equal area projectionStandard parallels 55°N and 65°NCentral meridian 154°W, latitude of origin 50°NNorth American Datum of 1983 (NAD 83)

Sagavanirktok Formation Gas Hydrate  Assessment Unit boundarySagavanirktok Formation Gas Hydrate Assessment  Unit probability field unit boundary—Terms Low,  Middle, and High represent the probability of  accumulations in assessment unit. Number is  an identifier

Outer limit of Alaska State water

Oil and gas discovery and field boundary

Well with thermogenic gasWell with limited thermogenic gasWell with no thermogenic gas

B
58 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Table 9. Estimates of the number of undiscovered gas hydrate 

accumulations in the Sagavanirktok Formation Gas Hydrate 

Assessment Unit (see fig. 32).

[mi2, square mile]

Map unit Area

(mi2

)

Number of gas hydrate accumulations

Minimum Mode Maximum

Low 1 3,510 10 49 146

Middle 1 5,361 30 149 447

Middle 2 910 5 25 76

Middle 3 253 1 7 21

High 1 554 6 32 97

Total - 10,588 52 262 787

Used - 9 260 800

Table 7. Estimates of the number of undiscovered gas 

hydrate accumulations in the Nanushuk Formation Gas Hydrate 

Assessment Unit (see fig. 30).

[mi2, square mile]

Map unit Area

(mi2

)

Number of gas hydrate accumulations

Minimum Mode Maximum

Low 1 3,030 8 17 51

Low 2 19,675 55 109 328

Middle 1 7,617 21 63 190

Middle 2 641 2 5 16

Total - 30,963 86 195 585

Used - 1 195 600

Table 8. Estimates of the number of undiscovered gas hydrate 

accumulations in the Tuluvak-Schrader Bluff-Prince Creek 

Formations Gas Hydrate Assessment Unit (see fig. 31).

[mi2, square mile]

Map unit Area

(mi2

)

Number of gas hydrate accumulations

Minimum Mode Maximum

Low 1 2,002 6 11 33

Middle 1 3,011 8 25 75

Middle 2 2,640 7 22 66

Middle 3 1,210 3 10 30

High 1 2,738 15 38 114

High 2 2,742 15 38 114

Total - 14,343 55 143 433

Used - 1 145 450

the MPU accumulation size distribution at a value of 450 BCF. 

For the Tuluvak-Schrader Bluff-Prince Creek Formations Gas 

Hydrate AU and the Nanushuk Formation Gas Hydrate AU, 

the NPRA 3D seismic-derived accumulation size distribution 

as shown in figure 28B was used to derive a median 

accumulation size of 120 BCF for both AUs. The maximum 

size of the accumulations in the Tuluvak-Schrader BluffPrince Creek Formations Gas Hydrate AU and the Nanushuk 

Formation Gas Hydrate AU was also projected from the 

NPRA accumulation size distribution at a value of 675 BCF, 

but it was decided to increase the maximum accumulation size 

in the Tuluvak-Schrader Bluff-Prince Creek Formations Gas 

Hydrate AU to 700 BCF to account for some of the apparent 

larger structures mapped in this AU.

7.d. Assessment of Coproducts

As described in the “Gas Hydrate Technical Review” 

section, in almost all cases, gas hydrates in nature contain 

mostly methane with only one reported case of a Structure H 

hydrate (recovered in a shallow core from an oil seep in 

the Gulf of Mexico) that was stabilized with a liquid range 

hydrocarbon. Thus, it was assumed that the undiscovered gas 

hydrate accumulations predicted in this assessment would not 

contain any natural gas liquids (that is, no coproducts).

7.e. Selected Ancillary Data for

Undiscovered Accumulations

The data entered into this section of the form are useful 

for economic and environmental analyses of the assessment 

results, but do not contribute directly to the assessment 

calculations. Ancillary data as shown for each of the AUs 

include estimates of the inert-gas content (mostly nitrogen in 

this assessment), carbon dioxide content, hydrogen sulfide 

content, and estimated drilling and water depths.

7.f. Allocations of Assessed 

Undiscovered Resources

The resource allocation portion of the form includes input 

percentages necessary to allocate assessed undiscovered gas 

hydrate resources to various land entities of interest within each 

AU, as well as to the offshore portion of each entity. For this 

assessment, entities of interest include the State Lands (State 

of Alaska), the Federal Lands (Bureau of Land Management; 

U.S. Fish and Wildlife Service), Private Lands, Tribal Lands, a 

small category of Other Lands, and Alaska Offshore (State of 

Alaska). The estimated additions to reserves are also classified 

by the ecosystem in which they are likely to be found.

8. Resource Assessment Results

The USGS assessment strategy provides estimates 

of the volumes of undiscovered petroleum resources that 

are technically recoverable (table 10). For the Northern 

Alaska Gas Hydrate TPS, the USGS estimates that the total 

undiscovered natural gas resources in gas hydrate range 

between 25.2 and 157.8 trillion cubic feet (TCF; 95-percent 

and 5-percent probabilities of greater than these amounts, 

respectively), with a mean estimate of 85.4 TCF. Of this 

mean estimate, (1) about 24 percent (20.6 TCF) is in the 

Sagavanirktok Formation Gas Hydrate AU, (2) 33 percent 

(28.0 TCF) is within the Tuluvak-Schrader Bluff-Prince Creek 

Formations Gas Hydrate AU, and (3) 43 percent (36.9 TCF) is 

in the Nanushuk Formation Gas Hydrate AU (table 10). Given 

that relatively few wells have penetrated the expected gas 

hydrate accumulations in these three AUs, there is significant 
9. References Cited 59

Table 10. Alaska North Slope—Gas hydrate assessment results. Results shown are fully risked estimates. F95 represents a 95-percent 

chance of at least the amount tabulated; other fractiles are defined similarly. Fractiles are additive, assuming perfect positive correlations.

[BCFG, billion cubic feet of gas. MMBNGL, million barrels of natural gas liquids; NGL, natural gas liquids; TPS, total petroleum system; AU, assessment unit]

Total Petroleum System 

and Assessment Unit

Field 

type

Total undiscovered resources

Gas (BCFG) NGL (MMBNGL)

F95 F50 F5 Mean F95 F50 F5 Mean

Northern Alaska Gas Hydrate TPS

Sagavanirktok Formation Gas Hydrate AU Gas 6,285 19,490 37,791 20,567 0 0 0 0

Tuluvak-Schrader Bluff-Prince Creek 

Formations Gas Hydrate AU

Gas 8,173 26,532 51,814 28,003 0 0 0 0

Nanushuk Formation Gas Hydrate AU Gas 10,775 35,008 68,226 36,857 0 0 0 0

Total Undiscovered Resources 25,233 81,030 157,831 85,427 0 0 0 0

geologic uncertainty in these estimates that is reflected in the 

range of estimates in table 10. Of the estimated 85.4 TCF 

of gas within hydrates on the North Slope, 56 percent is on 

federally managed lands, 39 percent on lands and offshore 

waters managed by the State of Alaska, and 4 percent on 

Native lands.

The mean estimate of 85.4 TCF of gas within the gas 

hydrates of northern Alaska is considerably less than the 

590 TCF reported in the 1995 USGS assessment (Collett, 

1995). It is critical to note that the 1995 assessment only 

dealt with estimating the in-place volume of gas with 

hydrates, whereas this more recent assessment dealt only 

with technically recoverable gas. Also, the 1995 assessment 

included the offshore Federal waters (fig. 1A–B), which were 

not included in this assessment. In addition, the assessment 

results reported here are based on geologic data that were 

not previously available, which afforded a greatly improved 

appreciation of the North Slope gas hydrate petroleum system.

9. References Cited

Alaska Oil and Gas Conservation Commission, 1992, Summary 

of the Cirque-1 blowout of February 12, 1992: Anchorage, 

Alaska, public record letter from D.J. Ruckel, Atlantic 

Richfield Company (ARCO) Alaska, to D. Johnston, State of 

Alaska Oil and Gas Conservation Commissioner, 32 p.

Alaska Oil and Gas Conservation Commission, 2008, 

Digital well log files: Anchorage, Alaska, Alaska Oil 

and Gas Conservation Commission, Alaska Department 

of Administration, accessed April 12, 2008, at 

http://doa.alaska.gov/ogc/DigLog/diglogindex.html.

Anderson, B.J., Hancock, S.H., Wilson, S.J., Enger, C.S., 

Collett, T.S., Boswell, R.M., and Hunter, R.B., 2011a, 

Formation pressure testing at the Mount Elbert Gas Hydrate 

Stratigraphic Test Well, Alaska North Slope—Operational 

summary, history matching, and interpretations: Journal of 

Marine and Petroleum Geology, v. 28, no. 2, p. 478–492.

Anderson, B.J., Kurihara, M., White, M.D., Moridis, G.J., 

Wilson, S.J., Pooladi-Darvish, M., Gaddipati, M., Masuda, 

Y., Collett, T.S., Hunter, R.B., Narita, H., Rose, K., and 

Boswell, R., 2011b, Regional long-term production 

modeling from a single well test, Mount Elbert Gas Hydrate 

Stratigraphic Test Well, Alaska North Slope: Journal of 

Marine and Petroleum Geology, v. 28, no. 2, p. 493–501.

Anderson, B.J., Wilder, J.W., Kurihara, M., White, M.D., 

Moridis, G.J., Wilson, S.J., Pooladi-Darvish, M., Masuda, 

Y., Collett, T.S., Hunter, R.B., Narita, H., Rose, K., and 

Boswell, R., 2008, Analysis of modular dynamic formation 

test results from the Mount Elbert 01 stratigraphic test well, 

Milne Point Unit, North Slope, Alaska, in International 

Conference on Gas Hydrates (ICGH 2008), 6th, Vancouver, 

British Columbia, Canada, 6–10 July 2008, Proceedings: 

International Conference on Gas Hydrates, 10 p.

ANWR Assessment Team, U.S. Geological Survey, 1999, The 

oil and gas resource potential of the Arctic National Wildlife 

Refuge 1002 Area, Alaska: U.S. Geological Survey OpenFile Report 98–34.

Archie, G.E., 1942, The electrical resistivity log as an aid 

in determining some reservoir characteristic: Journal of 

Petroleum Technology, v. 5, p. 1–8.

Bard, H.B., and Fairbanks, R.G., 1990, U-Th ages obtained by 

mass spectrometry in corals from Barbados, sea level during 

the past 130,000 years: Nature, v. 346, p. 456–458.

Bird, K.J., 1998, Geographic and geologic setting, chap GG 

of The oil and gas resource potential of the Arctic National 

Wildlife Refuge 1002 Area, Alaska, by ANWR Assessment 

Team: U.S. Geological Survey Open-File Report 98–34, 

Version 1.0, p. GG1–GG51, CD-ROM. (Also available at 

http://pubs.usgs.gov/of/1998/ofr-98-0034/GG.pdf.)

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10. Appendix 65

10. Appendixes

Appendix 1. Basic input data (Seventh data form) used in estimates of the numbers and sizes of undiscovered gas hydrate accumulations 

in the Sagavanirktok Formation Gas Hydrate Assessment Unit (50010201) in the Northern Alaska Gas Hydrate Total Petroleum System.

SEVENTH APPROXIMATION

DATA FORM FOR CONVENTIONAL ASSESSMENT UNITS (Version 6, 9 April 2003)

Assessment Geologist: T.S. Collett, W.F. Agena, M.W. Lee, M.V. Zyrianova Date: 4-Jun-08

Region: North America Number: 5

Province: Northern Alaska Number: 5001

Total Petroleum System: Northern Alaska Gas Hydrate Number: 500102

Assessment Unit: Sagavanirktok Formation Gas Hydrate Number: 50010201

Based on Data as of:

Notes from Assessor:

CHARACTERISTICS OF ASSESSMENT UNIT

Oil (<20,000 cfg/bo overall) or Gas (>20,000 cfg/bo overall): Gas

What is the minimum accumulation size? 3.33 mmboe grown

(the smallest accumulation that has potential to be added to reserves)

No. of discovered accumulations exceeding minimum size: Oil: 0 Gas: 0

Established (>13 accums.) Frontier (1-13 accums.) Hypothetical (no accums X

Median size (grown) of discovered oil accumulations (mmbo):

1st 3rd 2nd 3rd 3rd 3rd

Median size (grown) of discovered gas accumulations (bcfg):

1st 3rd 2nd 3rd 3rd 3rd

Assessment-Unit Probabilities:

 Attribute Probability of occurrence (0-1.0)

1. CHARGE: Adequate petroleum charge for an undiscovered accum. > minimum size: 1.0

2. ROCKS: Adequate reservoirs, traps, and seals for an undiscovered accum. > minimum size: 1.0

3. TIMING OF GEOLOGIC EVENTS: Favorable timing for an undiscovered accum. > minimum siz 1.0

Assessment-Unit GEOLOGIC Probability (Product of 1, 2, and 3): 1.0

UNDISCOVERED ACCUMULATIONS

No. of Undiscovered Accumulations: How many undiscovered accums. exist that are > min. size?: 

 (uncertainty of fixed but unknown values)

Oil Accumulations: minimum (>0) 0 mode 0 maximum 0

Gas Accumulations: minimum (>0) 9 mode 260 maximum 800

Sizes of Undiscovered Accumulations: What are the sizes (grown) of the above accums?: 

 (variations in the sizes of undiscovered accumulations)

Oil in Oil Accumulations (mmbo): minimum median maximum

Gas in Gas Accumulations (bcfg): minimum 20 median 45 maximum 450

IDENTIFICATION INFORMATION
66 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Assessment Unit (name, no.)

Sagavanirktok Formation Gas Hydrate, 50010201

AVERAGE RATIOS FOR UNDISCOVERED ACCUMS., TO ASSESS COPRODUCTS

(uncertainty of fixed but unknown values)

Oil Accumulations: minimum mode maximum

Gas/oil ratio (cfg/bo)

NGL/gas ratio (bngl/mmcfg)

Gas Accumulations: minimum mode maximum

Liquids/gas ratio (bliq/mmcfg) 0 0 0

Oil/gas ratio (bo/mmcfg)

SELECTED ANCILLARY DATA FOR UNDISCOVERED ACCUMULATIONS

(variations in the properties of undiscovered accumulations)

Oil Accumulations: minimum mode maximum

API gravity (degrees)

Sulfur content of oil (%)

Depth (m) of water (if applicable)

minimum F75 mode F25 maximum

Drilling Depth (m)

Gas Accumulations: minimum mode maximum

Inert gas content (%) 1 2 4

CO2 content (%) 1 2 5

Hydrogen-sulfide content (%) 0 0 0

Depth (m) of water (if applicable) 0 10 20

minimum F75 mode F25 maximum

Drilling Depth (m) 300 1200 1400
10. Appendix 67

Assessment Unit (name, no.)

Sagavanirktok Formation Gas Hydrate, 50010201

Surface Allocations (uncertainty of a fixed value)

1. Alaska represents 100 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 100

2. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

3. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

4. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

5. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

6. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

ALLOCATIONS OF POTENTIAL ADDITIONS TO RESERVES TO STATES
68 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Assessment Unit (name, no.)

Sagavanirktok Formation Gas Hydrate, 50010201

7. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

8. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

9. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

10. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

11. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

12. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity
10. Appendix 69

Assessment Unit (name, no.)

Sagavanirktok Formation Gas Hydrate, 50010201

Surface Allocations (uncertainty of a fixed value)

1. Federal Lands represents 18.03 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 10.00

2. Private Lands represents 0.16 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 0.00

3. Tribal Lands represents 3.04 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 3.00

4. Other Lands represents 1.44 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 2.00

5. AK State Lands represents 59.14 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 67.00

6. AK Offshore represents 18.19 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 18.00

ALLOCATIONS OF POTENTIAL ADDITIONS TO RESERVES TO LAND ENTITIES
70 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Assessment Unit (name, no.)

Sagavanirktok Formation Gas Hydrate, 50010201

7. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

8. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

9. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

10. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

11. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

12. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity
10. Appendix 71

Assessment Unit (name, no.)

Sagavanirktok Formation Gas Hydrate, 50010201

Surface Allocations (uncertainty of a fixed value)

1. Bureau of Land Management (BLM) represents 0.97 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 0.00

2. BLM Wilderness Areas (BLMW) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

3. BLM Roadless Areas (BLMR) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

4. National Park Service (NPS) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

5. NPS Wilderness Areas (NPSW) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

6. NPS Protected Withdrawals (NPSP) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

ALLOCATIONS OF POTENTIAL ADDITIONS TO RESERVES TO FEDERAL LAND SUBDIVISIONS
72 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Assessment Unit (name, no.)

Sagavanirktok Formation Gas Hydrate, 50010201

7. US Forest Service (FS) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

8. USFS Wilderness Areas (FSW) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

9. USFS Roadless Areas (FSR) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

10. USFS Protected Withdrawals (FSP) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

11. US Fish and Wildlife Service (FWS) represents 17.06 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 10.00

12. USFWS Wilderness Areas (FWSW) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity
10. Appendix 73

Assessment Unit (name, no.)

Sagavanirktok Formation Gas Hydrate, 50010201

13. USFWS Protected Withdrawals (FWSP) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

14. Wilderness Study Areas (WS) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

15. Department of Energy (DOE) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

16. Department of Defense (DOD) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

17. Bureau of Reclamation (BOR) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

18. Tennessee Valley Authority (TVA) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity
74 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Assessment Unit (name, no.)

Sagavanirktok Formation Gas Hydrate, 50010201

19. Other Federal represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

20. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity
10. Appendix 75

Assessment Unit (name, no.)

Sagavanirktok Formation Gas Hydrate, 50010201

Surface Allocations (uncertainty of a fixed value)

1. Coastal Plain (CSTP) represents 30.12 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 30

2. Foothills (FTHL) represents 51.68 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 52

3. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

4. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

5. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

6. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

ALLOCATIONS OF POTENTIAL ADDITIONS TO RESERVES TO ECOSYSTEMS
76 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Assessment Unit (name, no.)

Sagavanirktok Formation Gas Hydrate, 50010201

7. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

8. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

9. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

10. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

11. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

12. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity
10. Appendix 77

Appendix 2. Basic input data (Seventh data form) used in estimates of the numbers and sizes of undiscovered gas hydrate accumulations 

in the Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate Assessment Unit (50010202) in the Northern Alaska Gas Hydrate Total 

Petroleum System.

SEVENTH APPROXIMATION

DATA FORM FOR CONVENTIONAL ASSESSMENT UNITS (Version 6, 9 April 2003)

Assessment Geologist: T.S. Collett, W.F. Agena, M.W. Lee, M.V. Zyrianova Date: 4-Jun-08

Region: North America Number: 5

Province: Northern Alaska Number: 5001

Total Petroleum System: Nortern Alaska Gas Hydrate Number: 500102

Assessment Unit: Tuluvak-Schrader Bluff-Prince Creek Form Gas Hydrate Number: 50010202

Based on Data as of:

Notes from Assessor:

CHARACTERISTICS OF ASSESSMENT UNIT

Oil (<20,000 cfg/bo overall) or Gas (>20,000 cfg/bo overall): Gas

What is the minimum accumulation size? 3.33 mmboe grown

(the smallest accumulation that has potential to be added to reserves)

No. of discovered accumulations exceeding minimum size: Oil: 0 Gas: 0

Established (>13 accums.) Frontier (1-13 accums.) Hypothetical (no accums X

Median size (grown) of discovered oil accumulations (mmbo):

1st 3rd 2nd 3rd 3rd 3rd

Median size (grown) of discovered gas accumulations (bcfg):

1st 3rd 2nd 3rd 3rd 3rd

Assessment-Unit Probabilities:

 Attribute Probability of occurrence (0-1.0)

1. CHARGE: Adequate petroleum charge for an undiscovered accum. > minimum size: 1.0

2. ROCKS: Adequate reservoirs, traps, and seals for an undiscovered accum. > minimum size: 1.0

3. TIMING OF GEOLOGIC EVENTS: Favorable timing for an undiscovered accum. > minimum siz 1.0

Assessment-Unit GEOLOGIC Probability (Product of 1, 2, and 3): 1.0

UNDISCOVERED ACCUMULATIONS

No. of Undiscovered Accumulations: How many undiscovered accums. exist that are > min. size?: 

 (uncertainty of fixed but unknown values)

Oil Accumulations: minimum (>0) 0 mode 0 maximum 0

Gas Accumulations: minimum (>0) 1 mode 145 maximum 450

Sizes of Undiscovered Accumulations: What are the sizes (grown) of the above accums?: 

 (variations in the sizes of undiscovered accumulations)

Oil in Oil Accumulations (mmbo): minimum median maximum

Gas in Gas Accumulations (bcfg): minimum 20 median 120 maximum 700

IDENTIFICATION INFORMATION
78 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Assessment Unit (name, no.)

Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate, 50010202

AVERAGE RATIOS FOR UNDISCOVERED ACCUMS., TO ASSESS COPRODUCTS

(uncertainty of fixed but unknown values)

Oil Accumulations: minimum mode maximum

Gas/oil ratio (cfg/bo)

NGL/gas ratio (bngl/mmcfg)

Gas Accumulations: minimum mode maximum

Liquids/gas ratio (bliq/mmcfg) 0 0 0

Oil/gas ratio (bo/mmcfg)

SELECTED ANCILLARY DATA FOR UNDISCOVERED ACCUMULATIONS

(variations in the properties of undiscovered accumulations)

Oil Accumulations: minimum mode maximum

API gravity (degrees)

Sulfur content of oil (%)

Depth (m) of water (if applicable)

minimum F75 mode F25 maximum

Drilling Depth (m)

Gas Accumulations: minimum mode maximum

Inert gas content (%) 1 2 4

CO2 content (%) 1 2 5

Hydrogen-sulfide content (%) 0 0 0

Depth (m) of water (if applicable) 0 5 15

minimum F75 mode F25 maximum

Drilling Depth (m) 300 900 1200
10. Appendix 79

Assessment Unit (name, no.)

Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate, 50010202

Surface Allocations (uncertainty of a fixed value)

1. Alaska represents 100 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 100

2. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

3. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

4. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

5. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

6. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

ALLOCATIONS OF POTENTIAL ADDITIONS TO RESERVES TO STATES
80 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Assessment Unit (name, no.)

Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate, 50010202

7. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

8. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

9. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

10. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

11. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

12. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity
10. Appendix 81

Assessment Unit (name, no.)

Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate, 50010202

Surface Allocations (uncertainty of a fixed value)

1. Federal Lands represents 43.47 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 50.00

2. Private Lands represents 0.03 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 0.00

3. Tribal Lands represents 3.48 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 4.00

4. Other Lands represents 1.07 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 1.00

5. AK State Lands represents 45.35 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 38.00

6. AK Offshore represents 6.59 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 7

ALLOCATIONS OF POTENTIAL ADDITIONS TO RESERVES TO LAND ENTITIES
82 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Assessment Unit (name, no.)

Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate, 50010202

7. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

8. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

9. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

10. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

11. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

12. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity
10. Appendix 83

Assessment Unit (name, no.)

Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate, 50010202

Surface Allocations (uncertainty of a fixed value)

1. Bureau of Land Management (BLM) represents 43.47 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 50

2. BLM Wilderness Areas (BLMW) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

3. BLM Roadless Areas (BLMR) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

4. National Park Service (NPS) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

5. NPS Wilderness Areas (NPSW) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

6. NPS Protected Withdrawals (NPSP) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

ALLOCATIONS OF POTENTIAL ADDITIONS TO RESERVES TO FEDERAL LAND SUBDIVISIONS
84 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Assessment Unit (name, no.)

Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate, 50010202

7. US Forest Service (FS) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

8. USFS Wilderness Areas (FSW) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

9. USFS Roadless Areas (FSR) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

10. USFS Protected Withdrawals (FSP) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

11. US Fish and Wildlife Service (FWS) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

12. USFWS Wilderness Areas (FWSW) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity
10. Appendix 85

Assessment Unit (name, no.)

Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate, 50010202

13. USFWS Protected Withdrawals (FWSP) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

14. Wilderness Study Areas (WS) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

15. Department of Energy (DOE) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

16. Department of Defense (DOD) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

17. Bureau of Reclamation (BOR) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

18. Tennessee Valley Authority (TVA) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity
86 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Assessment Unit (name, no.)

Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate, 50010202

19. Other Federal represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

20. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity
10. Appendix 87

Assessment Unit (name, no.)

Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate, 50010202

Surface Allocations (uncertainty of a fixed value)

1. Coastal Plain (CSTP) represents 31.29 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 31

2. Foothills (FTHL) represents 62.12 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 62

3. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

4. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

5. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

6. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

ALLOCATIONS OF POTENTIAL ADDITIONS TO RESERVES TO ECOSYSTEMS
88 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Assessment Unit (name, no.)

Tuluvak-Schrader Bluff-Prince Creek Formations Gas Hydrate, 50010202

7. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

8. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

9. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

10. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

11. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

12. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity
10. Appendix 89

SEVENTH APPROXIMATION

DATA FORM FOR CONVENTIONAL ASSESSMENT UNITS (Version 6, 9 April 2003)

Assessment Geologist: T.S. Collett, W.F. Agena, M.W. Lee, M.V. Zyrianova Date: 4-Jun-08

Region: North America Number: 5

Province: Northern Alaska Number: 5001

Total Petroleum System: Nortern Alaska Gas Hydrate Number: 500102

Assessment Unit: Nanushuk Formation Gas Hydrate Number: 50010203

Based on Data as of:

Notes from Assessor:

CHARACTERISTICS OF ASSESSMENT UNIT

Oil (<20,000 cfg/bo overall) or Gas (>20,000 cfg/bo overall): Gas

What is the minimum accumulation size? 3.33 mmboe grown

(the smallest accumulation that has potential to be added to reserves)

No. of discovered accumulations exceeding minimum size: Oil: 0 Gas: 0

Established (>13 accums.) Frontier (1-13 accums.) Hypothetical (no accums X

Median size (grown) of discovered oil accumulations (mmbo):

1st 3rd 2nd 3rd 3rd 3rd

Median size (grown) of discovered gas accumulations (bcfg):

1st 3rd 2nd 3rd 3rd 3rd

Assessment-Unit Probabilities:

 Attribute Probability of occurrence (0-1.0)

1. CHARGE: Adequate petroleum charge for an undiscovered accum. > minimum size: 1.0

2. ROCKS: Adequate reservoirs, traps, and seals for an undiscovered accum. > minimum size: 1.0

3. TIMING OF GEOLOGIC EVENTS: Favorable timing for an undiscovered accum. > minimum siz 1.0

Assessment-Unit GEOLOGIC Probability (Product of 1, 2, and 3): 1.0

UNDISCOVERED ACCUMULATIONS

No. of Undiscovered Accumulations: How many undiscovered accums. exist that are > min. size?: 

 (uncertainty of fixed but unknown values)

Oil Accumulations: minimum (>0) 0 mode 0 maximum 0

Gas Accumulations: minimum (>0) 1 mode 195 maximum 600

Sizes of Undiscovered Accumulations: What are the sizes (grown) of the above accums?: 

 (variations in the sizes of undiscovered accumulations)

Oil in Oil Accumulations (mmbo): minimum median maximum

Gas in Gas Accumulations (bcfg): minimum 20 median 120 maximum 675

IDENTIFICATION INFORMATION

Appendix 3. Basic input data (Seventh data form) used in estimates of the numbers and sizes of undiscovered gas hydrate accumulations 

in the Nanushuk Formation Gas Hydrate Assessment Unit (50010203) in the Northern Alaska Gas Hydrate Total Petroleum System.
90 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Assessment Unit (name, no.)

Nanushuk Formation Gas Hydrate, 50010203

AVERAGE RATIOS FOR UNDISCOVERED ACCUMS., TO ASSESS COPRODUCTS

(uncertainty of fixed but unknown values)

Oil Accumulations: minimum mode maximum

Gas/oil ratio (cfg/bo)

NGL/gas ratio (bngl/mmcfg)

Gas Accumulations: minimum mode maximum

Liquids/gas ratio (bliq/mmcfg) 0 0 0

Oil/gas ratio (bo/mmcfg)

SELECTED ANCILLARY DATA FOR UNDISCOVERED ACCUMULATIONS

(variations in the properties of undiscovered accumulations)

Oil Accumulations: minimum mode maximum

API gravity (degrees)

Sulfur content of oil (%)

Depth (m) of water (if applicable)

minimum F75 mode F25 maximum

Drilling Depth (m)

Gas Accumulations: minimum mode maximum

Inert gas content (%) 1 2 4

CO2 content (%) 1 2 5

Hydrogen-sulfide content (%) 0 0 0

Depth (m) of water (if applicable) 0 5 15

minimum F75 mode F25 maximum

Drilling Depth (m) 300 600 750
10. Appendix 91

Assessment Unit (name, no.)

Nanushuk Formation Gas Hydrate, 50010203

Surface Allocations (uncertainty of a fixed value)

1. Alaska represents 100 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 100

2. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

3. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

4. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

5. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

6. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

ALLOCATIONS OF POTENTIAL ADDITIONS TO RESERVES TO STATES
92 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Assessment Unit (name, no.)

Nanushuk Formation Gas Hydrate, 50010203

7. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

8. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

9. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

10. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

11. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

12. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity
10. Appendix 93

Assessment Unit (name, no.)

Nanushuk Formation Gas Hydrate, 50010203

Surface Allocations (uncertainty of a fixed value)

1. Federal Lands represents 81.50 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 81.00

2. Private Lands represents 0.01 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 0.00

3. Tribal Lands represents 5.00 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 5.00

4. Other Lands represents 0.50 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 1.00

5. AK State Lands represents 8.56 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 9.00

6. AK Offshore represents 4.43 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 4

ALLOCATIONS OF POTENTIAL ADDITIONS TO RESERVES TO LAND ENTITIES
94 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Assessment Unit (name, no.)

Nanushuk Formation Gas Hydrate, 50010203

7. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

8. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

9. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

10. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

11. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

12. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity
10. Appendix 95

Assessment Unit (name, no.)

Nanushuk Formation Gas Hydrate, 50010203

Surface Allocations (uncertainty of a fixed value)

1. Bureau of Land Management (BLM) represents 81.49 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 81

2. BLM Wilderness Areas (BLMW) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

3. BLM Roadless Areas (BLMR) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

4. National Park Service (NPS) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

5. NPS Wilderness Areas (NPSW) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

6. NPS Protected Withdrawals (NPSP) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

ALLOCATIONS OF POTENTIAL ADDITIONS TO RESERVES TO FEDERAL LAND SUBDIVISIONS
96 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Assessment Unit (name, no.)

Nanushuk Formation Gas Hydrate, 50010203

7. US Forest Service (FS) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

8. USFS Wilderness Areas (FSW) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

9. USFS Roadless Areas (FSR) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

10. USFS Protected Withdrawals (FSP) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

11. US Fish and Wildlife Service (FWS) represents 0.01 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 0

12. USFWS Wilderness Areas (FWSW) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity
10. Appendix 97

Assessment Unit (name, no.)

Nanushuk Formation Gas Hydrate, 50010203

13. USFWS Protected Withdrawals (FWSP) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

14. Wilderness Study Areas (WS) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

15. Department of Energy (DOE) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

16. Department of Defense (DOD) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

17. Bureau of Reclamation (BOR) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

18. Tennessee Valley Authority (TVA) represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity
98 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Assessment Unit (name, no.)

Nanushuk Formation Gas Hydrate, 50010203

19. Other Federal represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

20. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity
10. Appendix 99

Assessment Unit (name, no.)

Nanushuk Formation Gas Hydrate, 50010203

Surface Allocations (uncertainty of a fixed value)

1. Coastal Plain (CSTP) represents 40.47 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 41

2. Foothills (FTHL) represents 55.10 area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity 55

3. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

4. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

5. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

6. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

ALLOCATIONS OF POTENTIAL ADDITIONS TO RESERVES TO ECOSYSTEMS
100 Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska

Assessment Unit (name, no.)

Nanushuk Formation Gas Hydrate, 50010203

7. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

8. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

9. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

10. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

11. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity

12. represents area % of the AU

Oil in Oil Accumulations: minimum mode maximum

Volume % in entity

Gas in Gas Accumulations:

Volume % in entity
10. Appendix 101

Publishing support provided by:

Denver Publishing Service Center, Denver, Colorado

For more information concerning this publication, contact:

Center Director, USGS Central Energy Resources Science Center

Box 25046, Mail Stop 939

Denver, CO 80225

(303) 236-1647

Or visit the Central Energy Resources Science Center Web site at:

http://energy.usgs.gov/

This report is available at: http://dx.doi.org/10.3133/dds69cc.

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USGS Alaska Gas Hydrate Assessment Team —Geologic Assessment of Undiscovered Gas Hydrate Resources on the North Slope, Alaska—Digital Data Series DDS–69–CC

ISSN 2327-132X (online)

ISSN 2327-0271 (print)

http://dx.doi.org/10.3133/dss69cc

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Main Contents