North Aleutian Basin OCS Planning Area 

Assessment of Undiscovered Technically-Recoverable Oil and Gas 

As of 2006 

U.S. Department of the Interior 

Minerals Management Service 

Alaska OCS Region 

Anchorage, Alaska 

Kirk W. Sherwood 

John Larson 

C. Drew Comer 

James D. Craig 

Cameron Reitmeier 

February 2006 

This report is available online at http://www.mms.gov/alaska/re/reports/rereport.htm. A 

Compact Disk version of the report (in PDF format) may be obtained by contacting 

Rance Wall, Regional Supervisor for Resource Evaluation, Minerals Management 

Service, Centerpoint Financial Center, 3801 Centerpoint Drive, Suite 500, MS 8100, 

Anchorage, AK 99503-5823, or at Ph. 907-334-5320, or at e-mail rance.wall@mms.gov
Table of Contents 

List of Text Topics

Summary, page 1

Location and General Geology of North 

Aleutian Basin OCS Planning Area, 

page 5

Exploration History of North Aleutian 

Basin, page 6

Past Exploration Onshore, page 6

Leasing Onshore, page 6

Offshore/OCS Exploration, page 7

Past OCS Leasing, page 7

Productive Analog Basin—Cook Inlet 

Basin, page 8

Petroleum Geology of the North Aleutian 

Basin, page 9

Regional Geology, page 9

Alaska Peninsula, page 9

Formation of North Aleutian Basin, 

page 10

Structures of Amak Basin, Black Hills 

Uplift, and North Aleutian Basin, 

page 11

Nature of Basement Beneath North 

Aleutian Basin, page 13

Mesozoic Stratigraphy and Reservoir 

Formations, page 15

Cenozoic Stratigraphy, Reservoir 

Formations, and Play Sequences, page 

16

Petroleum Systems in North Aleutian 

Basin Plays, page 19

Thermal Maturity of North Aleutian 

Basin Fill, page 19

Source Rock Potential, page 21

Mesozoic Source Rocks, page 21

Tertiary Source Rocks, page 22 

Source Potential of Coal-Bearing 

Rocks, page 23 

Source Potential of “Amorphous” 

Interval, 15,620-17,155 ft bkb, 

page 24

Source Potential of Tertiary Basin 

Fill and Assessment Model, page 

26

Oil and Gas Occurrences and 

Biomarker Correlations, page 26

Petroleum System—Critical Events, 

page 31

Petroleum System Elements and Oil and 

Gas Plays in North Aleutian Basin OCS 

Planning Area, page 37

Key Elements of Petroleum System, 

page 37

Play Definition, page 37

Play Descriptions, North Aleutian Basin, 

Alaska, page 38

Play 1: Bear Lake-Stepovak 

(Oligocene-Miocene), page 38

Play 2: Tolstoi (Eocene-Oligocene), 

page 39

Play 3: Black Hills Uplift-Amak 

Basin (Eocene-Miocene), page 41

Play 4: Milky River Biogenic Gas 

(Plio-Pleistocene), page 43

Play 5: Mesozoic Deformed 

Sedimentary Rocks (TriassicCretaceous), page 45

Play 6: Mesozoic Buried Granitic 

Hills (Jurassic-Cretaceous 

Magmatic Rocks), page 47

Geologic Assessment Model, page 50

Prospect Areas and Volumes, page 50

Prospect Numbers, page 51

i
Pay Thickness Model, page 52

Construction of Probability Distributions 

with Limited Data, page 53

Computation of Oil and Gas Recovery 

Factors, page 54

Oil Recovery Factor, page 54

Gas Recovery Factor, page 54

Risk Assessment, page 56

Assessment Results for North Aleutian 

Basin, page 57

Play 1: Bear Lake-Stepovak (OligoceneMiocene), page 57

Play 2: Tolstoi (Eocene-Oligocene), 

page 58

Play 3: Black Hills Uplift-Amak Basin 

(Eocene-Miocene), page 59

Play 4: Milky River Biogenic Gas (PlioPleistocene), page 59

Play 5: Mesozoic Deformed 

Sedimentary Rocks (TriassicCretaceous), page 59

Play 6: Mesozoic Buried Granitic Hills 

(Jurassic-Cretaceous Magmatic 

Rocks), page 60

Overall Results for Oil and Gas 

Endowments of North Aleutian Basin, 

page 61

Large Individual Gas Fields Are 

Possible, page 61 

Economic Potential of North Aleutian 

Basin, page 62

References Cited, page 64

List of Tables

1. North Aleutian Basin and Alaska 

Peninsula Exploration Wells, 1903-

1985, page 71

2. Selected Extract Data, Oil and Gas Show 

Interval, North Aleutian Shelf COST 1 

well, page 72

3. Input Data for Play 1, Bear LakeStepovak (Oligocene- Miocene), page 

73

4. Input Data for Play 2, Tolstoi (EoceneOligocene), page 74

5. Input Data for Play 3, Black Hills UpliftAmak Basin (Eocene-Miocene), page 75

6. Input Data for Play 4, Milky River 

Biogenic Gas (Plio-Pleistocene), page 

76

7. Input Data for Play 5, Mesozoic 

Deformed Sedimentary Rocks (TriassicCretaceous), page 77

8. Input Data for Play 6, Mesozoic Buried 

Granitic Hills (Jurassic-Cretaceous 

Magmatic Rocks), page 78

9. Input Data for Oil and Gas Recovery 

Factor Calculation, Play 1, Bear LakeStepovak (Oligocene- Miocene), page 

79

10. Input Data for Oil and Gas Recovery 

Factor Calculation, Play 2, Tolstoi 

(Eocene-Oligocene), page 80

11. Input Data for Oil and Gas Recovery 

Factor Calculation, Play 3, Black Hills 

Uplift-Amak Basin (Eocene-Miocene), 

page 81

ii
12. Input Data for Oil and Gas Recovery 

Factor Calculation, Play 5, Mesozoic 

Deformed Sedimentary Rocks (TriassicCretaceous), page 82

13. Input Data for Oil and Gas Recovery 

Factor Calculation, Play 6, Mesozoic 

Buried Granitic Hills (JurassicCretaceous Magmatic Rocks), page 83

14. 2006 Assessment Results for North 

Aleutian Basin OCS Planning Area, page 84

15. Conditional (Un-risked) Recoverable 

Pool Size Simulation Statistics for Play 1 

– Bear Lake-Stepovak (OligoceneMiocene), page 85

16. Conditional (Un-risked) Recoverable 

Sizes of Ranked Pools for Play 1 – Bear 

Lake-Stepovak (Oligocene-Miocene), 

page 85

17. Conditional (Un-risked) Recoverable 

Pool Size Simulation Statistics for Play 2 

– Tolstoi (Eocene-Oligocene), page 86

18. Conditional (Un-risked) Recoverable 

Sizes of Ranked Pools for Play 2 - 

Tolstoi (Eocene-Oligocene), page 86

19. Conditional (Un-risked) Recoverable 

Pool Size Simulation Statistics for Play 3 

– Black Hills Uplift-Amak Basin 

(Eocene-Miocene), page 87 

20. Conditional (Un-risked) Recoverable 

Sizes of Ranked Pools for Play 3 – Black 

Hills Uplift-Amak Basin (EoceneMiocene), page 87

21. Conditional (Un-risked) Recoverable 

Pool Size Simulation Statistics for Play 5 

– Mesozoic Deformed Sedimentary 

Rocks (Triassic-Cretaceous), page 88

22. Conditional (Un-risked) Recoverable 

Sizes of Ranked Pools for Play 5 – 

Mesozoic Deformed Sedimentary Rocks 

(Triassic-Cretaceous), page 88

23. Conditional (Un-risked) Recoverable 

Pool Size Simulation Statistics for Play 6 

– Mesozoic Granitic Buried Hills 

(Jurassic-Cretaceous), page 89

24. Conditional (Un-risked) Recoverable 

Sizes of Ranked Pools for Play 6 – 

Mesozoic Granitic Buried Hills 

(Jurassic-Cretaceous), page 89 

25. 2006 Economic Assessment Results for 

North Aleutian Basin OCS Planning 

Area, page 90

List of Figures

1. Location map for North Aleutian basin 

and other Tertiary-age basins of the 

Bering shelf, Pacific margin, and 

southern Chukchi Sea, page 91

2. Regional map for North Aleutian basin, 

with well control, Sale 92 (1988) leases, 

and regional distribution of Tertiary-age 

sedimentary rocks, page 92 

3. Seismic data coverage (CDP, TwoDimensional) for North Aleutian Basin 

iii
OCS Planning Area, page 93

4. Regional distribution of Mesozoic 

sedimentary basin containing strata 

correlative to Middle Jurassic oil source 

rocks that generated 1.4 billion barrels of 

oil reserves in the oil fields of northern 

Cook Inlet basin, page 94

5. Principal geologic structures of the 

North Aleutian basin and contiguous 

areas, including: 1) transtensional faults 

and basement uplifts in western parts of 

the basin; 2) wrench-fault structures 

along the Black Hills uplift; and 3) 

fold/thrust belts along the southeast 

margin of the basin, page 95

6. Seismic profile through basement uplifts 

in western North Aleutian basin, 

showing Tertiary sedimentary sequences 

and basin structures, page 96. An 

undistorted Adobe Acrobat version of 

figure 6 is available as plate 1

7. Magnetic intensity map with offshore 

speculative extrapolation of the Bruin 

Bay fault, page 97

8. Mesozoic stratigraphy, Alaska Peninsula 

and substrate beneath southwest part of 

North Aleutian basin, page 98

9. Wellbore stratigraphy, North Aleutian 

Shelf COST 1 stratigraphic test well, 

page 99. An undistorted Adobe Acrobat 

version of figure 9 is available as plate 

2. 

10. Regional stratigraphic correlation, 

Tertiary sequence in North Aleutian 

Shelf COST 1, Sandy River 1, Port 

Heiden 1, Ugashik 1, and Becharof Lake 

1 wells, North Aleutian basin and Alaska 

Peninsula, page 100. An undistorted 

Adobe Acrobat version of figure 10 is 

available as plate 3

11. Statistical summaries for sandstone bed 

thicknesses for North Aleutian basin 

play sequences, page 101

12. Core porosity versus depth in the North 

Aleutian Shelf COST 1 well, with linear 

regression function for porosity decline 

with depth, page 102

13. Core porosity versus permeability for 

sandstones, North Aleutian Shelf COST 

1 well, with correlation, page 103

14. Core permeability versus depth for 

sandstones, North Aleutian Shelf COST 

1 well, with function for permeability 

decline with depth, page 104

15. Porosity histograms for Bear LakeStepovak, Upper Tolstoi, and Lower 

Tolstoi play sequences, page 105

16. Permeability histograms for Bear LakeStepovak, Upper Tolstoi, and Lower 

Tolstoi play sequences, page 106

17. Vitrinite reflectance data for 94 samples 

of cuttings, conventional cores, and 

percussion sidewall cores in the North 

Aleutian Shelf COST 1 well, with 

statistical fits and forecasts for depths of 

important isograds, page 107

18. Depth to top of oil generation zone 

(0.6% vitrinite reflectance) with 

probable areas of thermal maturity of 

Tertiary rocks sufficient for oil 

generation in and beneath the North 

Aleutian basin, page 108

19. Isopach map for thickness of Tertiaryage rocks within oil generation zone 

(0.6% to 1.35% vitrinite reflectance) 

with probable areas of thermal maturity 

iv
sufficient for oil generation within and 

beneath North Aleutian basin, page 109

20. Generation potential (total organic 

carbon) and hydrocarbon type (hydrogen 

index) indicators for Mesozoic rocks in 

the Cathedral River 1 well, page 110

21. Generation potential (total organic 

carbon) and hydrocarbon type (hydrogen 

index) indicators for Tertiary rocks in 

the North Aleutian Shelf COST 1 well, 

page 111

22. (A) Modified Van Krevelen plot 

comparing Exlog (1983) pyrolysis data 

for cuttings with coal partly removed (by 

flotation in water) and cuttings with coal 

content retained; (B) Sidewall and 

conventional core samples, with coalbearing and coal-free samples plotted 

separately; (C) Van Krevelen-type plot 

showing elemental data for sidewall and 

conventional core samples, with coalbearing and coal-free samples plotted 

separately; (D) Van Krevelen-type plot 

with elemental analyses for all coalbearing samples with HI>150, page 112

23. Analyses of gas compositions from 

Alaska Peninsula seeps and oil and gas 

fields in northern Cook Inlet basin, page 

113

24. (A) Methane carbon isotope data for 

Amoco Becharof Lake 1 well. B) Gas 

wetness versus methane isotopes, page 

114

25. Cross plot for Pristane/n-C17 versus 

Phytane/n-C18 ratios for rock extracts 

from the oil show interval in nonmarine 

Eocene Tolstoi Formation from 15,300 

to 16,800 feet bkb in the North Aleutian 

Shelf COST 1 well, page 115

26. Histograms for Pristane/Phytane ratios 

of North Aleutian Shelf COST 1 well 

extracts, Tertiary (nonmarine) extracts 

and oils, and Mesozoic (marine) extracts 

and oils, page 116

27. Sofer cross plot for carbon isotopes for 

aromatics and saturates, comparing 

North Aleutian Shelf COST 1 well 

extracts, Tertiary (nonmarine) extracts 

and oils, and Mesozoic (marine) extracts 

and oils, page 117

28. A) Triangular plot for saturates versus 

aromatics versus non-hydrocarbons, 

North Aleutian Shelf COST 1 well 

extracts, Tertiary (nonmarine) extracts 

and oils, and Mesozoic (marine) extracts 

and oils; B) Triangular plot for C27-

C28-C29 sterane ratios, page 118

29. M/Z 191 chromatograms for terpanes by 

Baseline DGSI (2003) for extracts from 

composited samples from: (A) cores 18 

and 19, 16,006-16,720 ft, North Aleutian 

Shelf COST 1 well; and (B) cuttings, 

15,700 to 16,800 ft. Both 

chromatograms show abundant presence 

of C19 to C30 tricyclic terpanes, page 

119

30. Burial history plot for North Aleutian 

Shelf COST 1 well, with timelines for 

critical petroleum system events, page 

120

31. Schematic cross sections illustrating (A) 

petroleum system elements and (B) play 

concepts for North Aleutian Basin OCS 

Planning Area, page 121

32. Map area of play 1, Bear Lake-Stepovak 

play, North Aleutian Basin OCS 

Planning Area, Alaska, page 122

33. Map area of play 2, Tolstoi play, North 

v
Aleutian Basin OCS Planning Area, 

Alaska, page 123

34. Map area of play 3, Black Hills UpliftAmak Basin, North Aleutian Basin OCS 

Planning Area, Alaska, page 124

35. Map area of play 4, Milky River 

Biogenic Gas play, North Aleutian Basin 

OCS Planning Area, Alaska, page 125

36. Map area of play 5, Mesozoic Deformed 

Sedimentary Rocks play, North Aleutian 

Basin OCS Planning Area, Alaska, page 

126

37. Map area of play 6, Mesozoic Buried 

Granitic Hills play, North Aleutian Basin 

OCS Planning Area, Alaska, page 127

38. Histogram for pay thickness in Tertiary 

reservoirs in oil and gas fields of Cook 

Inlet, page 128

39. Example of “force-fit” probability 

distributions constructed graphically 

between estimates for extreme values. 

Geothermal models for plays 1, 2 and 3, 

in oRankine (oF + 460 = oR), page 129

40. Assessment results for North Aleutian 

Basin OCS Planning Area play 1 (Bear 

Lake-Stepovak play). (A), cumulative 

probability plot for total risked 

recoverable BOE resources (barrels of 

oil-equivalent); (B), pool class size 

histogram, conditional recoverable BOE 

volumes; (C), pool rank plot, conditional 

recoverable BOE volumes: page 130

41. Assessment results for North Aleutian 

Basin OCS Planning Area play 2 

(Tolstoi play). (A), cumulative 

probability plot for total risked 

recoverable BOE resources (barrels of 

oil-equivalent); (B), pool class size 

histogram, conditional recoverable BOE 

volumes; (C), pool rank plot, conditional 

recoverable BOE volumes: page 131

42. Assessment results for North Aleutian 

Basin OCS Planning Area play 3 (Black 

Hills Uplift-Amak Basin play). (A), 

cumulative probability plot for total 

risked recoverable BOE resources 

(barrels of oil-equivalent); (B), pool 

class size histogram, conditional 

recoverable BOE volumes; (C), pool 

rank plot, conditional recoverable BOE 

volumes: page 132

43. Assessment results for North Aleutian 

Basin OCS Planning Area play 4 (Milky 

River Biogenic Gas play)—Play 4 was 

not quantified, page 133

44. Assessment results for North Aleutian 

Basin OCS Planning Area play 5 

(Mesozoic Deformed Sedimentary 

Rocks play). (A), cumulative 

probability plot for total risked 

recoverable BOE resources (barrels of 

oil-equivalent); (B), pool class size 

histogram, conditional recoverable BOE 

volumes; (C), pool rank plot, conditional 

recoverable BOE volumes: page 134

45. Assessment results for North Aleutian 

Basin OCS Planning Area play 6 

(Mesozoic Buried Granitic Hills play). 

(A), cumulative probability plot for total 

risked recoverable BOE resources 

(barrels of oil-equivalent); (B), pool 

class size histogram, conditional 

recoverable BOE volumes; (C), pool 

rank plot, conditional recoverable BOE 

volumes: page 135

46. Assessment results for North Aleutian 

Basin OCS Planning Area. (A), 

cumulative probability plot for total 

risked recoverable BOE resources (oil 

vi
and gas in barrels of oil-equivalent); (B), 

cumulative probability plot for total 

risked recoverable liquid (oil + 

condensate from gas) resources; (C), 

cumulative probability plot for total 

risked recoverable gas (free gas and 

solution gas) resources; (D), 

comparative cumulative probability plot 

for oil & condensate, BOE, and gas (free 

gas and solution gas) resources: page 

136 

47. Pool rank plot for hypothetical gas pools 

in gas-prone plays (1, 2, and 6) of North 

Aleutian basin compared to the gas 

fields of Cook Inlet basin, page 137

48. Hypothetical development model for 

North Aleutian basin gas resources. 

Platforms and subsea completions at 

offshore gas fields direct the gas into 

gathering pipelines that carry the gas to 

an offshore hub. A 75-mile pipeline (25 

miles subsea, 50 miles overland) then 

carries the gas to a hypothetical liquefied 

natural gas (LNG) plant at Balboa Bay 

(site in southwest arm identified in 1980 

study by Dames & Moore). At the LNG 

plant the gas is refrigerated to a liquid 

state (-260oF) preparatory to shipping 

via LNG tankers to hypothetical 

receiving and re-gasification facilities in 

Cook Inlet or along the U.S. (or Canada 

or Mexico) West Coast. page 138

 

vii
List of Plates

(Recommended to be printed tabloid size or larger) 

Plate 1. Seismic profile through basement uplifts in western North Aleutian basin, 

showing Tertiary sedimentary sequences and basin structures. A page-sized 

version of plate 1 is also available as figure 6 (page 96). 

Plate 2. Wellbore stratigraphy, North Aleutian Shelf COST 1 stratigraphic test well. A 

page-sized version of plate 2 is also available as figure 9 (page 99). 

Plate 3. Regional stratigraphic correlation, Tertiary sequence in North Aleutian Shelf 

COST 1, Sandy River 1, Port Heiden 1, Ugashik 1, and Becharof Lake 1 wells, 

North Aleutian basin and Alaska Peninsula. A page-sized version of plate 3 is 

available as figure 10 (page 100). 

Plate 4. Summary panel of data plots for source rock quality, source type (oil vs. gas), 

thermal maturity, and hydrocarbon occurrences in the North Aleutian Shelf COST 

1 well (recommended plot size, 34 X 44 inch [ANSI E] or larger). 

Appendices-Data Files

Appendix 1. Excel file (xls), porosity and permeability data, sidewall and conventional cores, 

Core Laboratories (1983), North Aleutian Shelf COST 1 well. 

Appendix 2. Excel file (xls), organic geochemical data, cuttings, sidewall cores, and 

conventional cores, Exlog (1983) and Robertson Research (1983), North Aleutian 

Shelf COST 1 well. 

Appendix 3. Biomarker study, extracts from show interval from 15,700 to 16,800 ft md, North 

Aleutian Shelf COST 1 well, composites of core and cuttings material, by 

Baseline DGSI for Minerals Management Service (Baseline DGSI, 2003). 

Appendix 4. Acrobat file (pdf), Exlog (1983) Pyrolysis Data and Report, North Aleutian Shelf 

COST 1 well. 

Appendix 5. Acrobat file (pdf), Robertson Research (1983) Geochemical Data and Report, 

North Aleutian Shelf COST 1 well. 

 viii
North Aleutian Basin Outer Continental Shelf Planning Area 

Assessment of Undiscovered Technically-Recoverable Oil and Gas 

 As of 2006

Kirk W. Sherwood 

John Larson 

C. Drew Comer 

James D. Craig 

Cameron Reitmeier 

February 2006 

U.S. Department of the Interior 

Minerals Management Service 

Alaska OCS Region 

Anchorage, Alaska 

Summary

The North Aleutian Basin Outer Continental 

Shelf (OCS) Planning Area encompasses an 

area of 52,234 square miles and includes 

most of the southeastern part of the Bering 

Sea continental shelf (fig. 1). The North 

Aleutian basin proper is about 17,500 square 

miles in area and underlies the northern 

coastal plain of the Alaska Peninsula and the 

waters of Bristol Bay. North Aleutian basin 

is sometimes also referred to as the “Bristol 

Bay” basin. Water depths range from 15 to 

700 feet and in the area of the most 

important prospects the water depths are 

approximately 300 feet. 

The North Aleutian basin is filled with 

approximately 20,000 feet of Tertiary-age 

strata. In the southwest corner of the 

Planning Area, the Amak basin is separated 

by an arch (Black Hills uplift) from the 

North Aleutian basin (figs. 2, 3). The Amak 

basin is filled with up to 12,500 feet of 

Tertiary-age strata. The North Aleutian and 

Amak basins, the intervening Black Hills 

uplift, and the Mesozoic rocks beneath these 

features all contribute resources to the 2006

oil and gas assessment of the North Aleutian 

basin. 

Most mapped prospects in the North 

Aleutian basin proper are simple domes 

draped over the crests of fault-bounded 

basement uplifts. These domes range up to 

133,000 acres in closure area. In the central 

part of the North Aleutian basin 65 miles 

northwest of Port Moller, these domes are 

surrounded by deep parts of the basin where 

the lowermost strata are heated to 

temperatures sufficient for conversion of 

organic matter to oil and gas. Oil and gas 

generated in these basin deeps should have 

migrated upward into the domes. 

The prospects in the central part of the North 

Aleutian basin have long been the focus of 

exploration interest in North Aleutian basin 

 1
and several were leased for total high bids of 

$95.4 million (23 blocks) in OCS lease sale 

92 in 1988. All of the 1988 leases have 

been returned to the U.S. Government and 

are no longer active. In this assessment, as 

well as in past assessments, most of the 

hypothetical, undiscovered oil and gas 

resources of the North Aleutian Basin OCS 

Planning Area are associated with the simple 

domes draped over basement uplifts in the 

central part of the North Aleutian basin. 

Onshore, nine exploration wells have tested 

fold and thrust-fault structures along the 

southern edge of the North Aleutian basin. 

Several offshore wells tested age-equivalent 

strata in the St. George basin to the west. 

The principal point of geological control for 

the Tertiary-age fill in the North Aleutian 

basin is the North Aleutian Shelf COST 1 

well, drilled in 1983 by an industry 

consortium led by ARCO Exploration 

Company. None of these wells encountered 

any sizeable accumulations of oil or gas, 

although several wells detected oil and gas 

shows and two onshore wells tested minor 

gas pools at rates up to 90 thousands of 

cubic feet per day. No wells have tested the 

Amak basin. North Aleutian and Amak 

basins are covered by gridded (1 to 5 mile 

spacing in prospective areas) twodimensional seismic data mostly acquired in 

the period from 1975 to 1988. 

Well and seismic data indicate that thick, 

highly porous, and highly permeable 

sandstones of Oligocene-Miocene age (Bear 

Lake-Stepovak Formations) are present 

within the key prospects in the North 

Aleutian basin. Geochemical analyses of 

well samples indicate that Tertiary strata are 

primarily sources for natural gas, possibly 

with some condensates. Minor oil shows 

were detected within Tertiary rocks in the 

lowermost part of the North Aleutian Shelf 

COST 1 well. Geochemical studies of 

extracts of these oil shows indicate 

origination within coaly, Tertiary-age rocks 

like those sampled by the well. The 

southwest part of the North Aleutian Basin 

OCS Planning Area is underlain by 

Mesozoic rocks that might form a source for 

oil. However, the North Aleutian Basin 

OCS Planning Area is primarily a gas 

province. 

The 2006 assessment was completed in 

November 2005 and incorporates data and 

information available as of 01 January 2003. 

The risked, technically-recoverable, 

undiscovered hydrocarbon energy 

endowment of the North Aleutian Basin 

OCS Planning Area ranges up to 6,647 

millions of barrels (oil-energy-equivalent, at 

F05, the 5% fractile, or 5% probability), 

with a mean value or expectation of 2,287 

millions of barrels (oil-energy-equivalent). 

The Planning Area is gas-prone, with sixtyseven percent of the undiscovered 

hydrocarbon energy endowment consisting 

of natural gas. Mean risked, undiscovered 

total gas (sum of “non-associated” [free] gas 

and solution gas in oil) resources total 8.622 

trillions of cubic feet but could range up to a 

maximum (F05) potential of 23.278 trillions 

of cubic feet. Mean risked, undiscovered 

liquid petroleum (sum of free oil and 

condensate from gas) resources are 

estimated at 753 millions of barrels but 

could range up to a maximum (F05) 

potential of 2,505 millions of barrels. 

 2
 3

F95 Mean F05

BOE (Mmboe) 91 2,287 6,647

Total Gas (Tcfg) 0.404 8.622 23.278

Total Liquids 

(Mmbo) 19 753 2,505

Free Gas (Tcfg) 0.401 8.393 22.487

Solution Gas 

(Tcfg) 0.003 0.229 0.791

Oil (Mmbo) 9 545 1,948

Condensate 

(Mmbc) 10 208 556

* Risked, Technically-Recoverable

Mmb = millions of barrels

Tcf = trillions of cubic feet

BOE = total hydrocarbon energy, expressed in barrels-of-oilequivalent, where 1 barrel of oil = 5,620 cubic feet of batural 

gas

F95 = 95% chance that resources will equal or exceed the 

given quantity

F05 = 5% chance that resources will equal or exceed the given 

quantity

Resources * Resource 

Commodity 

(Units)

North Aleutian Basin OCS Planning Area, 

Undiscovered Technically-Recoverable Oil & Gas

Assessment Results as of 2006

The 2006 assessment of the North Aleutian 

Basin OCS Planning Area identified six 

exploration plays. Most (61%) of the 

hypothetical, undiscovered oil and gas 

resources are associated with play 1—

termed the Bear Lake-Stepovak play. Play 1 

captures most of the key prospects in the 

central part of the North Aleutian basin. 

The mean conditional (un-risked) size of the 

largest pool in play 1 (and the North 

Aleutian basin overall) is 4.65 trillions of 

cubic feet of natural gas (or 827 millions of 

barrels [oil-energy-equivalent]), nearly twice 

the size of the largest gas field in Cook Inlet 

(Kenai gas field, 2.427 Tcfg EUR). At 

maximum (F05) size, the largest pool in play 

1 could contain 14.02 trillions of cubic feet 

of natural gas (or 2.495 billions of barrels 

[oil-energy-equivalent]). 

The 2006 MMS economic assessment of the 

North Aleutian basin models production 

infrastructure that originates at offshore 

platforms where gas, condensate, and crude 

oil are gathered by subsea pipelines from 

several surrounding fields. Subsea pipelines 

carry natural gas and petroleum liquids from 

an offshore hub to onshore facilities and a 

liquefied natural gas (LNG) plant 

constructed in Balboa Bay on the south side 

of the Alaska Peninsula (fig. 10). In our 

model, natural gas is converted to LNG and 

then transported by marine LNG carriers to 

new receiving terminals either in the 

northern Cook Inlet (550 mi.) or on the U.S. 

West Coast (2,600 mi.; fig. 48). Minimum 

transportation tariffs in the economic model 

represent a Cook Inlet destination while the 

maximum tariffs reflect a U.S. West Coast 

landing. The Cook Inlet market (total 

approximately 200 Bcfg/yr; Sherwood and 

Craig, 2001, tbl. 5) is probably too small to 

accept the entire North Aleutian production 

stream (approximately 150 Bcfg/yr) but 

nonetheless offers an alternative market. 

The lowest (or “threshold”) prices that yield 

positive economic volumes in the North 

Aleutian basin are $14/barrel of oil and 

$3.63/Mcf of non-associated gas. (Solution 

gas is linked to oil development and first 

becomes “economic” at $2.12/Mcf or the 

threshold price for oil [$14/barrel].) 

However, higher prices are required to 

economically recover meaningful fractions 

of the oil and gas endowment. Significant 

quantities (>300 Mmbo) of oil become 

economic to recover at prices approaching 

$30/bbl. This could represent a standalone 

offshore oil field. Significant quantities (>1 

Tcfg) of gas become economic at prices 

exceeding $4.54/Mcf. However, a 

minimum total gas reserve of 5 Tcfg would 

probably be required to justify a grassroots 

LNG export operation. This economic 

volume is recoverable at an approximate gas 
 4

price of $6.50/Mcfg and represents 58 

percent of the total recoverable gas 

endowment (8.622 Tcfg). 

F95 Mean F05

$18/bbl Oil & Condensate 

(Mmbo) 0 45 200

$2.72/Mcf Solution Gas (Tcfg) 0.000 0.017 0.053

$30/bbl Oil & Condensate 

(Mmbo) 2 378 1,371

$4.54/Mcf Free Gas & Solution 

Gas (Tcfg) 0.001 0.909 2.780

$46/bbl Oil & Condensate 

(Mmbo) 11 631 2,180

$6.96/Mcf Free Gas & Solution 

Gas (Tcfg) 0.132 5.852 16.548

$80/bbl Oil & Condensate 

(Mmbo) 19 738 2,468

$12.10/Mcf Free Gas & Solution 

Gas (Tcfg) 0.392 8.396 22.767

Threshold Prices ($2005, Mean Resource Case) for Positive 

Economic Results = $14/Barrel of Oil and $3.63/Mcf of NonAssociated Gas

ECONOMIC ASSUMPTIONS: 2005 base year; oil price is indexed 

to Alaska North Slope crude landed on the U.S. West Coast; gas 

price is LNG landed on the U.S. West Coast; 0.8488 BOE-basis 

gas value discount relative to oil; flat real prices and costs; 3% 

inflation; 12% discount rate; 35% Federal tax. 

Resources * Price 

($2005) Per 

Unit

Resource 

Commodity (Units)

North Aleutian Basin OCS Planning Area, Undiscovered 

Economically-Recoverable Oil & Gas

Assessment Results as of 2006

Tcf = trillions of cubic feet

F95 = 95% chance that resources will equal or exceed the given 

quantity

F05 = 5% chance that resources will equal or exceed the given 

quantity

* Risked, Economically-Recoverable

Mmb = millions of barrels

Current prices exceed $6.50/Mcf by a wide 

margin (recent gas prices at the Los Angeles 

city gate have exceeded $13.00/Mcf; Natural 

Gas Week, 19 December 2005). If the 

current high prices are sustained, a 

significant fraction of North Aleutian basin 

gas resources are economically attractive. 

Locally, the proposed “Pebble” gold mine 

(estimated gas demand of 66 Mmcfg/day to 

feed a 200 Mw power plant) north of 

Iliamna Lake may form a potential future 

market for North Aleutian basin gas 

resources. However, the Pebble project site 

is located approximately 400 miles 

northwest of the key prospects in the central 

part of the North Aleutian basin and the 

estimated gas demand may be too small to 

support a pipeline of this length. 

In October 1989, the North Aleutian basin 

was placed under a Congressional 

moratorium which banned U.S. Department 

of Interior expenditures in support of any 

petroleum leasing or development activities 

in North Aleutian Basin as well as the 

Atlantic, Pacific, and eastern Gulf of Mexico 

OCS Planning Areas. Bristol Bay is the 

center of a very important commercial 

salmon fishery. The North Aleutian 

moratorium reacted to widespread demands 

for fisheries protection in Bristol Bay by 

Native organizations, Native villages, local 

fishing interests, and the State of Alaska 

following the March 1989 Exxon Valdez

grounding and oil spill in Prince William 

Sound, Alaska. This moratorium was 

extended by Congress several times during 

the 1990’s. Offshore leases that had been 

issued in the 1988 OCS Sale 92 in the North 

Aleutian basin were returned to the Federal 

government in a 1995 buy-back agreement. 

On 12 June 1998, President William Clinton 

issued an Executive Order reinforcing the 

moratorium, as a Presidential Withdrawal, 

on North Aleutian Basin as well as the 

Atlantic, Pacific, and eastern Gulf of Mexico 

continental shelves until 30 June 2012. The 

Presidential Withdrawal still stands but can 

be revoked by the President. In the FY2004 Congressional bill appropriating the 

budget for the U.S. Department of Interior, 

the language forbidding funding of oil and 

gas activities (i.e., the “Congressional 

moratorium”) in the North Aleutian Basin 

OCS Planning Area was dropped. The 

moratoria language in the bill was retained 
for the other moratoria areas listed above. 

This action effectively ended the 

Congressional moratorium on oil and gas 

activities in the North Aleutian Basin OCS 

Planning Area. 

Location and General Geology of North Aleutian Basin OCS Planning Area 

The North Aleutian basin, located in figure 

1, is one of several basins of primarily 

Tertiary age that dot the Bering Sea shelf. 

The Bering Sea shelf is relatively flat and 

featureless except near the modern shoreline 

where Pleistocene glacial and relict 

shoreline features occur. The outer shelf 

and slope are incised by large submarine 

canyons near the shelf edge west of the St. 

George and Navarin basins. These 

submarine canyons empty westward into the 

deep abyssal plains of the western Bering 

Sea. 

 The North Aleutian basin underlies the 

waters of Bristol Bay north of the Alaska 

Peninsula (located in fig. 1) and is 

sometimes also termed the “Bristol Bay” 

basin. The basin underlies the southern part 

of the North Aleutian Basin Outer 

Continental Shelf (OCS) Planning Area. 

The basin is roughly 100 miles wide and 400 

miles in length and reaches depths of 20,000 

feet in its deepest parts. The North Aleutian 

basin extends onshore beneath the lowlands 

along the north shore of the Alaska 

Peninsula, where it has been penetrated by 

several wells. At its west end, a series of 

arches isolate the basin from the similar St. 

George and Amak basins, where Tertiary 

sediment thicknesses reach 40,000 feet and 

12,500 feet, respectively (Comer et al., 

1987). Along the southern margin of the 

North Aleutian basin, the Tertiary basin fill 

is deformed in fold and thrust-fault 

structures like those widely exposed on the 

Alaska Peninsula. The interior of the North 

Aleutian basin is dominated by uplifted fault 

blocks that have domed the overlying strata. 

Prospects associated with these dome 

structures are the primary exploration 

objectives in the North Aleutian basin. 

Although minor quantities of gas were 

recovered by flow tests at an onshore well, 

no significant accumulations of 

hydrocarbons have been located by 

exploration in the North Aleutian Basin 

OCS Planning Area or on the Alaska 

Peninsula.

 5
Exploration History of North Aleutian Basin 

Past Exploration Onshore 

Beginning with the first wells drilled in 

1903, a total of 27 wells were drilled 

onshore on the Alaska Peninsula to the 

southeast of the North Aleutian Basin OCS 

Planning Area (table 1; fig. 2). All the 10 

earliest wells (1903-1940) were drilled in 

the vicinity of local oil seeps. The last 17 

wells, completed since 1959, were located 

based primarily on considerations of 

geologic structure and stratigraphy. The 

wells are spread over a distance of 

approximately 260 miles along the Alaska 

Peninsula, extending from the Pacific, 

Costello, and Great Basins wells in the 

northeast to the Cathedral River 1 well to the 

southwest (fig. 2). Although these wells are 

mostly located at moderate distances from 

the North Aleutian Basin OCS Planning 

Area, they are important for making 

correlations and inferences about the 

hydrocarbon potential of the stratigraphic 

section offshore. 

None of the onshore wells encountered 

producible oil and gas; however, at least 6 of 

the wells completed since 1959 have 

encountered minor shows of oil and/or gas. 

A seventh, the Amoco Becharof Lake 1, 

tested gas in measurable but noncommercial amounts. 

Leasing Onshore 

On 26 October 2005, the State of Alaska 

received 37 bids on 37 tracts in the Port 

Moller area (fig. 2). High bids totaled $1.27 

million and all bids were submitted by either 

Shell Offshore Inc. (33 tracts, $0.95 million) 

or Hewitt Mineral Corp. (4 tracts, $0.31 

million). The tracts cover areas where thrust 

faulted and folded Mesozoic and Cenozoic 

rocks are exposed at the surface (Wilson et 

al., 1995). The new State of Alaska leases 

presumably offer exploration objectives in 

fold structures that are unlike the simple 

domes that form the key prospects in the 

Federal offshore. 

In 2003, the State of Alaska proposed a 

sealed-bid licensing program focusing on 

shallow gas resources north of their 

proposed lease area, as outlined (2003 area) 

in figure 2. Based upon industry interest, 

the licensing program area was later 

contracted to the 2004 area of 329,000 acres 

also shown in figure 2. A license was to be 

awarded (supplemental notice of 22 

December 2004, AKDO&G, 2004) to 

Bristol Shores LLC. However, financing 

efforts to bond the exploration commitment 

failed (P. Galvin, pers. comm., 2005) and 

the license lapsed. Bristol Shores LLC has 

submitted a new license application for a 

reduced area of 20,154 acres (Bailey, 2005). 

The proposed Northern Dynasty “Pebble” 

gold mine north of Iliamna Lake (located in 

fig. 2) forms a potential new market for 

North Aleutian basin gas resources and may 

drive interest in future lease sales on State of 

Alaska lands in the region. In the Federal 

offshore, the best prospects lie 

approximately 400 pipeline miles southwest 

of the proposed Pebble mine. Northern 

Dynasty representatives have indicated that 

the Pebble project will require a 200 

megawatt (Mw) power supply (Ede, 2005). 

This translates to a potential gas demand of 

 6
about 66 Mmcf/day1

 and may be too small 

to support a 400 mile pipeline. 

Offshore/OCS Exploration

Only one well has been drilled offshore in 

the North Aleutian Basin OCS Planning 

Area. This was a “Continental Offshore 

Stratigraphic Test” (COST) well, the North 

Aleutian Shelf COST 1 well (tbl.1; fig. 2). 

Eighteen companies participated in 

financing the well, with ARCO Exploration 

Company as the operator. It was drilled 

from the SEDCO 708, a self-propelled semisubmersible drilling rig, and was spudded 

(began drilling) on September 8, 1982, in 

285 feet of water. The well was plugged 

and abandoned on January 14, 1983, after 

bottoming at 17,155 feet in sedimentary 

rock of Eocene age. Below 15,300 feet, 

minor gas peaks appeared on the mud log 

and drill cuttings showed some oil stain and 

fluorescence (Turner et al., 1988), but no 

pools of oil or gas were encountered. 

Seismic data coverage for the North 

Aleutian Basin OCS Planning Area is shown 

in figure 3. Seismic data gathered to date 

within the North Aleutian Basin OCS 

Planning Area consists of 64,672 combined 

line miles of conventional, two-dimensional, 

common-depth-point (CDP) and shallowpenetrating, high-resolution (HRD) data. Of 

the seismic data held by MMS, 95% is CDP 

and 5% is HRD. Airborne magnetic data in 

 

1 Estimated as follows: One Mw capacity matches 

one Mw·h (megawatt-hour) demand. Assume 3,412 

btu/kwh energy equivalence (AEO, 2001, tbl. H1, p. 

248) and 1,000 btu/cf gas; substitutions obtain 3,412 

cf/Mw·h. At 25% efficiency* and 200Mw·h demand, 

we obtain 2.73 Mmcfg/h or 65.51 Mmcfg/day in gas 

demand. 

* AEO (2001, tbls. 19 & 20, p. 103) reports a 1984-

1999 range in efficiencies of delivered electricity of 

15% to 38% for various sectors. 

the area covers 9,596 line miles. 

Approximately 6,400 miles of airborne 

gravity data have also been gathered in the 

Planning Area. 

Past OCS Leasing

The only OCS lease sale in the area, the 

North Aleutian Shelf Sale 92, was held in 

October of 1988, with a total offering of 990 

lease blocks (area of offering shown in fig. 

2). The bidding resulted in the awarding of 

23 leases (blocks shown in fig. 2) covering 

121,757 acres. Proceeds from the sale 

totaled $95,439,500. 

Following the March 1989 grounding of the 

Exxon Valdez tanker and subsequent oil 

spill, a drilling ban was instituted in the 

North Aleutian basin Federal offshore in 

1989. The drilling ban and moratorium on 

all exploration recognized widespread 

opposition from Native organizations and 

villages and concerns about impacts on the 

lucrative salmon fishery. As a result, none 

of the 23 leases in the area were ever drilled. 

In 1992, 11 oil companies filed a joint 

lawsuit (Conoco Inc. vs. USA) in an attempt 

to end the ban or receive compensation. An 

out of court settlement and a Federal 

buyback of the leases was reached in 1995. 

On 12 June 1998, President William Clinton 

issued an Executive Order extending the 

moratorium (as a Presidential Withdrawal) 

on North Aleutian basin (and the Atlantic, 

Pacific, and eastern Gulf of Mexico 

continental shelves) until 30 June 2012 

(Alaska Report, 1998). The Presidential 

Withdrawal still stands but can be revoked 

by the President. However, the 

Congressional moratorium on petroleumrelated activities in North Aleutian basin has 

been lifted. In the FY-2004 Congressional 

bill appropriating budget funding for the 

U.S. Department of Interior, the language 

 7
forbidding funding of oil and gas activities 

(i.e., the “moratorium”) in the North 

Aleutian Basin OCS Planning Area was 

dropped (but retained for other moratoria 

areas).

Productive Analog Basin—Cook Inlet Basin

In southern Alaska, the most successful 

basin from the standpoint of oil and gas is 

the northern part of Cook Inlet basin, located 

in figure 4. The first field was discovered in 

1957, and exploration programs continuing 

into the early 1970’s located original 

recoverable reserves of 1.4 billions of 

barrels of oil and 11.6 trillions of cubic feet 

of gas (AKDO&G, 2004). Most of these 

reserves have been depleted, with remaining 

reserves as of late 2003 estimated at 0.0751 

billions of barrels of oil (5% of original 

reserves) and 2.039 trillions of cubic feet of 

gas (18% of original reserves) (AKDO&G, 

2004, tbls. 3.2, IV.2, IV.6). 

Like the North Aleutian basin, the principal 

fill of the Cook Inlet basin is of Tertiary age 

and reaches maximum thicknesses of 

roughly 26,000 feet (Hite, 1976; Fisher and 

Magoon, 1982, fig. 4). The most prolific 

Cook Inlet basin petroleum reservoirs are of 

Oligocene, Miocene, and Pliocene ages. 

Age-equivalent strata in the North Aleutian 

basin are also the best candidates for 

petroleum reservoirs. 

The structural style of prospects differs 

between the North Aleutian and Cook Inlet 

basins. Oil and gas fields in Cook Inlet 

occupy transpressional anticlines of 

Oligocene to Pliocene age that formed near 

strike-slip faults that pass from northeast to 

southwest through the basin (Haeussler et 

al., 2000). In contrast, North Aleutian basin 

prospects are drape anticlines developed in 

Eocene through Pliocene time over 

basement uplifts that were elevated while 

sediments in flanking deeps compacted, 

thereby doming shallow strata over the 

basement uplifts. 

One of the more compelling points of 

analogy between the Cook Inlet and North 

Aleutian basins is the potential role of 

underlying Mesozoic rocks in the generation 

of oil and charging of prospects in overlying 

Tertiary strata. Both basins overlie an older 

Mesozoic basin that contains the oil source 

rocks that generated the oil fields of 

northern Cook Inlet basin. The petroleum 

system in northern Cook Inlet succeeded 

because a deep Tertiary basin was 

superposed on a thermally immature 

Mesozoic assemblage that was buried and 

heated to temperatures appropriate for oil 

generation at the same time that fold traps 

grew in the overlying Tertiary basin fill 

(Magoon, 1994). The Middle Jurassic 

Tuxedni Group was the source for the oil 

that migrated upward into the Tertiary basin 

fill, generally charging fold structures in the 

Oligocene Hemlock Conglomerate 

(Magoon, 1994). The “Tuxedni-Hemlock” 

petroleum system that created the prolific oil 

fields of northern Cook Inlet basin is 

featured as a case study by Magoon (1994). 

Critical to the success of the “TuxedniHemlock” petroleum system are the facts 

 8
that the Mesozoic assemblage beneath 

northern Cook Inlet basin was both: 1) 

compositionally appropriate (endowed with 

rocks rich in organic matter and able to 

generate oil); and 2) thermally immature 

(retained ability to generate oil through 100 

million years following deposition and not 

deeply buried until about 65 Ma [Magoon, 

1994, fig. 22.7]). Correlative potential oil 

source rocks with a similar burial history 

may be found in the Mesozoic basin in areas 

beyond northern Cook Inlet. 

The Mesozoic rocks beneath Cook Inlet 

basin were deposited in a Mesozoic (Jurassic 

to Cretaceous) basin that was coupled to a 

Jurassic to Cretaceous volcanic arc to the 

north (Bally and Snelson, 1980). This 

Mesozoic basin extends at least 600 miles 

from interior Alaska to the southwest 

through the Alaska Peninsula (Imlay and 

Detterman, 1973, p. 8-9). From the Alaska 

Peninsula the Mesozoic basin probably 

extends an additional 300 miles 

northwesterly beneath St. George basin 

(Worrall, 1991, fig. 15). The approximate 

area of this Mesozoic basin is highlighted in 

figure 4 as the “Mesozoic basin with 

Jurassic oil source rocks?” The Cook Inlet 

basin, the North Aleutian basin, and the St. 

George basin are all superposed on the 

Mesozoic basin. Magoon (1994) has shown 

that this superposition was critical to the 

creation of the oil accumulations of the 

northern Cook Inlet basin. On the other 

hand, St. George basin was tested by 12 

wells, none of which encountered any oil or 

gas accumulations. It seems that the 

Mesozoic strata beneath St. George basin 

were somehow incapable of generating oil 

into the overlying St. George basin fill. 

Perhaps early deep burial caused generation 

and expulsion of petroleum from the 

Mesozoic rocks prior to formation of the 

Tertiary-age St. George basin. Perhaps the 

Mesozoic rocks beneath St. George basin 

simply lack the appropriate organic matter 

for oil generation. 

To the northeast of the North Aleutian basin 

we have a successful analog (northern Cook 

Inlet basin) and to the southwest of North 

Aleutian basin we have a failure analog (St 

George basin). The existence of substantive 

oil sources in the part of the Mesozoic basin 

that lies beneath North Aleutian basin 

remains unproven. However, this 

assessment assumes some capability 

(appropriately risked, given the uncertainty) 

of Mesozoic oil source rocks for providing 

oil to traps within both Mesozoic and 

contiguous Cenozoic rocks. 

Petroleum Geology of the North Aleutian Basin 

Regional Geology

Alaska Peninsula 

The Alaska Peninsula is the site of tectonicplate convergence between the Pacific 

oceanic plate and the North American 

continental margin. The resulting magmatic 

arc is a continuation of the Aleutian islands 

volcanic arc to the west, where convergence 

involves two oceanic plates. Plate 

convergence has been occurring at this 

margin episodically since the Early Jurassic. 

As a result, the peninsula is geologically 

 9
complex and includes both Mesozoic and 

Cenozoic igneous and sedimentary rocks. 

The modern Alaska Peninsula volcanic arc 

is built upon earlier volcano-plutonic arcs. 

Intrusive plutons from both Jurassic and 

Tertiary magmatic events occur in many 

places on the Alaska Peninsula. The oldest 

sedimentary rocks on the Alaska Peninsula 

are Late Triassic carbonates at Puale Bay to 

the east (located in fig. 2) along Shelikof 

Strait, but most of the Mesozoic strata 

consist of arc-derived clastic rocks of 

Jurassic and Cretaceous age. Those rocks 

are mostly of marine origin and are 

extensively folded and thrust faulted. The 

Tertiary section includes interbedded 

volcanic and volcaniclastic sedimentary 

rocks of continental origin. The Tertiary 

strata are less deformed than the Mesozoic 

strata. Both the Mesozoic and Cenozoic 

rock units of the Alaska Peninsula extend 

under the North Aleutian Basin OCS 

Planning Area. 

Formation of North Aleutian Basin

The North Aleutian Basin OCS Planning 

Area contains two main depocenters: the 

North Aleutian basin and the Amak basin. 

Those two sedimentary depressions are 

separated by the Black Hills uplift, which 

extends westward under the Bering Sea shelf 

from the Alaska Peninsula. The North 

Aleutian basin is primarily a Tertiary-age 

basin that was filled with sediments derived 

from uplifted areas in the Alaska Peninsula 

to the south and the western Alaska Range 

(located in fig. 1) to the northeast. The 

North Aleutian basin contains as much as 

20,000 feet of Cenozoic strata. The basin is 

less than 3,000 ft thick on the northwest and 

thickens southeastward to about 20,000 

near the Alaska Peninsula. This asymmetric 

profile has the appearance of a foredeep, 

possibly caused by tectonically thickened 

crust under the volcanic arc of the Alaska 

Peninsula (Bond et al., 1988). 

The North Aleutian Shelf COST 1 well did 

not penetrate “basement” but reached total 

depth in Lower Eocene rocks of the lower 

part of the Tolstoi Formation (Detterman, 

1990; Turner et al., 1988). The oldest 

known strata within the basin fill are Late 

Paleocene rocks of the Tolstoi Formation 

exposed on the Alaska Peninsula (Detterman 

et al., 1996). Detterman et al. (1996, p. 42) 

note that in most parts of the Alaska 

Peninsula, the base of the Tolstoi Formation 

is a prominent Paleocene unconformity that 

places the Tolstoi on a variety of older 

Mesozoic formations. Wilson et al. (1995) 

and Detterman et al. (1996) indicate that in 

the vicinity of the Black Hills uplift and east 

to Port Moller, the Tolstoi Formation and 

underlying Cretaceous Hoodoo Formation 

(or equivalent Chignik Fm.) are concordant 

across a disconformity. Offshore on the 

Black Hill uplift, we observe structural 

discordance between Tolstoi strata and 

underlying Mesozoic rocks in seismic data. 

From regional geological data and seismic 

interpretation, Worrall (1991) infers a late 

Eocene age for the unconformity (his “red” 

seismic horizon; approximately our seismic 

horizon “D” at 10,380 ft bkb [below Kelly 

bushing, or measured depth] in the COST 

well) flooring North Aleutian basin proper. 

The angular unconformity separating the 

two sequences was formed when plate 

reorganization in the north Pacific resulted 

in a change from convergent to strike-slip 

movement along the continental margin 

(Marlow and Cooper, 1980; Lonsdale, 1988; 

Worrall, 1991). Worrall (1991, fig. 38) 

assigns all of the Eocene rocks below 10,660 

ft bkb in the North Aleutian Shelf COST 1 

well to an older (his “carapace” sequence) 

group of Campanian to Eocene rocks that 

was deposited and folded prior to the late 

 10
Eocene or “red” unconformity. However, it 

is our view that Worrall’s “carapace 

sequence” in the North Aleutian basin 

instead represents the earliest basin fill 

deposited in faulted grabens during the 

initial rift phase of basin subsidence. Rather 

than the roots of fold synclines (Worrall 

model), we view these bodies of rock as fill 

within grabens established at the onset of 

transtensional rifting, most likely in 

Paleocene time. The Upper Eocene 

unconformity (“red” horizon of Worrall; our 

seismic horizon “D”) marks the transition 

from a rift phase (accompanied by faulting) 

to a foredeep phase with southward tilting 

governed by thrust loading on the south 

(Bond et al., 1988). 

The North Aleutian Shelf COST 1 well 

reached total depth at 17,155 ft bkb in 

Lower Eocene rocks of the Tolstoi 

Formation, but seismic data suggest an 

additional 2,000 to 3,000 feet of stratified 

rocks below the base of the well. Because 

of the widespread Paleocene unconformity 

at the base of the Tolstoi Formation on the 

Alaska Peninsula, we infer that the oldest 

deposits in the North Aleutian basin, dating 

the onset of rift faulting and basin 

subsidence, are Paleocene in age. 

Structures of Amak Basin, Black Hills 

Uplift, and North Aleutian Basin

The principal structures of the North 

Aleutian Basin OCS Planning Area and 

contiguous areas are mapped in figure 5. 

The context for these structures is 

compressive deformation on the south and a 

diffuse zone of strike-slip deformation and 

extension that passes through the Alaska 

Peninsula, the western part of the North 

Aleutian basin, and along the flanks of the 

Black Hills uplift. All structures are 

ultimately rooted in the interactions between 

the Alaska Peninsula volcanic arc and the 

Aleutian trench and subduction zone. 

The Amak basin is a relatively small 

structural depression south of the Black 

Hills uplift on the outer Bering Sea shelf. 

This basin contains as much as 12,500 feet 

of Cenozoic strata overlying folded and 

faulted Mesozoic sedimentary rocks. The 

Cenozoic strata within the Amak basin are 

less deformed than in the North Aleutian 

basin. Wrench faults and normal faults 

commonly cut the basement and lower 

Tertiary horizons, but the horst and graben 

structural style characteristic of the North 

Aleutian basin is absent in the Amak basin. 

The Black Hills uplift is the dominant 

positive structural feature of the southwest 

part of the North Aleutian Basin OCS 

Planning Area. This uplift plunges 

westward from the Alaska Peninsula 

through the southern Bering Sea shelf and 

continues into the St. George Basin Planning 

Area. The Black Hills uplift is probably a 

transpressional feature formed by strike-slip 

motion along the Bering Sea margin. The 

Naknek Formation (Late Jurassic) is 

exposed at the crest of the Black Hills uplift 

onshore. The Naknek Formation and older 

(as old as Late Triassic) formations probably 

form the core of the Black Hills uplift. The 

crest of the uplift is draped by Upper Eocene 

through Miocene strata. The uplift is faultbounded on both the North Aleutian basin 

side (to the north) and the Amak basin side 

(to the south). Wrench fault zones pass 

along the north and south flanks of the Black 

Hills uplift, as illustrated in a seismic profile 

published by Worrall (1991, pl. 2G). The 

wrench fault zones are 10 to 15 miles wide, 

extend through Plio-Pleistocene strata to the 

seafloor, and are associated with both 

transpressional (or “positive”) and 

transtensional (or “negative”) flower 

structures. Normal (probably transtensional) 

 11
faults are observed between the wrench 

zones across the crest of the Black Hills 

uplift. The sense of displacement on the 

wrench faults is believed to be right-lateral 

on the basis of context and regional 

structural patterns (Worrall, 1991). 

We recognize two general structural 

domains in the North Aleutian basin: 1) 

transtensional grabens and horsts in the 

basin interior; and 2) fold and thrust-fault 

structures along the south margin. From a 

petroleum exploration standpoint the 

transtensional horsts in the basin interior and 

overlying drape structures form the most 

attractive prospects in the basin. 

In the southwest half of the North Aleutian 

basin, transtensional faults bound horsts 

with several thousands of feet of structural 

relief at the basement level. Tertiary strata 

younger than Late Eocene are domed 

upward over these horsts, partly because of 

fault movements and partly because of 

compaction subsidence within sedimentfilled grabens flanking the horsts. Some 

examples of these drape anticlines are 

illustrated in the seismic line of figure 6 (full 

scale image available as plate 1). Drape 

anticlines over basement uplifts extend from 

the Upper Eocene unconformity (seismic 

horizon “D”--truncates the crests of 

basement uplifts) at about 10,000 ft ssd 

(subsea depth) upward to a Lower Pliocene 

unconformity (seismic horizon “A”) at about 

2,500 ft ssd. Displacements on upliftbounding faults abruptly diminish above the 

Upper Eocene unconformity, but very small 

(possibly compaction-driven) offsets are 

observed up to about 5,000 feet in figure 6 

(and pl. 1). These drape anticlines are the 

primary exploration targets in the North 

Aleutian basin. Because of their large 

closure areas and involvement of the thick, 

porous Bear Lake-Stepovak reservoir 

sandstones, these drape anticlines host most 

of the undiscovered, hypothetical oil and gas 

potential of the North Aleutian basin. 

The overall structure of North Aleutian 

basin is illustrated by structural contours on 

an Upper Oligocene datum in figure 5. The 

basin is basically a southward-thickening 

wedge that is abruptly terminated in a series 

of fold and thrust-fault structures that are the 

northern limit of the compressional 

deformations that dominate the Alaska 

Peninsula. The Alaska Peninsula is a fold 

and thrust belt that grades from simple, open 

structures on the northeast to highly 

shortened and complex structures in the 

southwest (Burk, 1965, figs. 21, 22). In its 

overall shape, the North Aleutian basin 

resembles a foredeep, in which the south 

flank has been depressed by thrust loading 

and in which shallow thrust structures 

abruptly terminate in a system of duplexes 

and triangle zones. This view is supported 

by modeling studies of the deep structure of 

the North Aleutian basin and the Alaska 

Peninsula volcanic arc by Bond et al. (1988) 

and Walker et al. (2003). The Bond study 

concluded that basin subsidence was driven 

by downward flexure of the back-arc 

lithosphere beneath a load imposed by 

subduction-driven crustal thickening of the 

arc and forearc of the Alaska Peninsula. 

The Walker study concluded that early 

extension and fault-controlled subsidence 

was succeeded by flexural subsidence due to 

loading on the south by stacking of volcanic 

materials on the Alaska Peninsula. 

The southeast margin of the North Aleutian 

basin is deformed by folds, thrust faults, and 

antiformal duplexes that represent the 

northern front of the Alaska Peninsula fold 

and thrust belt. Proprietary seismic data 

indicate that the fold and thrust-fault 

structures along the southwest margin of the 

basin terminate northward in triangle zones 

that have tilted rocks as young as Pliocene 

 12
over duplex roofs. The David River 1/1A, 

Hoodoo Lake 1, Hoodoo Lake 2, and Sandy 

River 1 wells were all drilled into antiformal 

duplexes that back triangle zones that taper 

northward beneath north-dipping Miocene to 

Pliocene basin fill. We speculate (as shown 

in fig. 5) that similar structures extend along 

strike to the northeast and form the targets 

drilled at the Port Heiden 1, Ugashik 1, 

Great Basins 1, Great Basins 2, and 

Becharof Lake 1 wells. However, we do not 

have access to any seismic data through 

these latter wells. Southwest of the Sandy 

River 1 well, proprietary seismic data 

indicate that the fold, thrust-fault, and 

duplex structures do not extend offshore into 

Federal waters. Therefore, these fold and 

thrust-fault structures do not form an oil and 

gas play in our assessment of the North 

Aleutian basin. 

Nature of Basement Beneath North 

Aleutian Basin

In the western Alaska Range, the Bruin Bay 

fault forms a regional contact between 

Mesozoic volcano-plutonic rocks on the 

north and Mesozoic sedimentary rocks on 

the south (Magoon et al., 1976). The 

volcano-plutonic rocks on the north are the 

roots of a Mesozoic volcanic arc and range 

in K-Ar ages from 179 to 107 Ma (Magoon 

et al., 1976, sh. 3), or Middle Jurassic to 

mid-Cretaceous, respectively, in equivalent 

stratigraphic ages. The Mesozoic 

sedimentary rocks south of the Bruin Bay 

fault represent a Mesozoic basin that flanked 

the contemporary volcanic arc to the north 

(Bally and Snelson, 1980). 

The Bruin Bay fault system is a series of 

high-angle reverse faults with the upthrown 

side on the northwest (Detterman and Reed, 

1980). The Bruin Bay fault is truncated 

north of Cook Inlet by the presently-active 

Castle Mountain fault. To the southwest, 

the fault system is mapped at the surface 

through the Alaska Peninsula to Becharof 

Lake, where the fault trace passes southwest 

beneath Quaternary volcanic and glacial 

deposits (Detterman et al., 1987). Fault 

movement was primarily in Middle and Late 

Jurassic time, when the Alaska-Aleutian 

Range batholith was being unroofed, 

providing clastic detritus to the Late Jurassic 

Naknek and younger formations. The Bruin 

Bay fault is intruded by a plutonic stock on 

the Alaska Peninsula that was age-dated at 

25.0-26.7 Ma, indicating no movement since 

the Oligocene in that area (Reed and 

Lanphere, 1972; Magoon et al., 1976, sheets 

2, 3, sites 66 & 67; Detterman and Reed, 

1980). To the north, the subsurface trace 

extends very close to the complexly-folded 

and reverse-faulted structures of the Middle 

Ground Shoal, McArthur River, Beluga 

River and other oil and gas fields of upper 

Cook Inlet (Boss et al., 1976). According to 

Haeussler et al. (2000), those fault-cored 

folds are Miocene and younger, with most of 

the deformation occurring in the 

Quaternary. 

Penetrations of Mesozoic granitic rocks 

beneath the North Aleutian basin fill north 

of the Bruin Bay fault occurred at the Great 

Basins 1, Great Basins 2, Becharof Lake 1, 

and Port Heiden 1 wells. Penetrations of 

Mesozoic sedimentary rocks south of the 

Bruin Bay fault occurred at the Cathedral 

River 1, David River 1/1A, and Hoodoo 

Lake 2 wells. Five wells in the St. George 

basin to the west encountered Mesozoic 

sedimentary rocks beneath Tertiary basin 

fill. The North Aleutian Shelf COST 1 well 

did not reach any pre-Tertiary rocks. These 

well penetrations of the Mesozoic substrate 

are sparse and only provide fragmentary 

information about the subsurface 

distribution of the component terranes. 

 13
Southwest of Becharof Lake, as noted 

above, the Bruin Bay fault passes beneath 

volcanic rocks and glacial sediments of 

Quaternary age of the Bristol Bay lowlands. 

The lowlands are dotted with numerous 

semi-circular magnetic anomalies that Case 

et al. (1988) interpret to locate buried 

granitoid to gabbroic plutons of Jurassic to 

Tertiary ages. None of these buried igneous 

bodies have been sampled or dated and 

speculations about their ages are based on 

regional context. A narrow, north-northeasttrending belt of high magnetic intensity 

(anomaly 8C of Case et al.) south of 

Becharof Lake is interpreted to locate a 

buried anticlinal limb of Naknek Formation 

(Jurassic) (Case et al., 1988, fig. 4, p. 4). 

This “Naknek” anomaly is truncated on the 

north at a projected buried strand of the 

Bruin Bay fault 15 miles southwest of 

Becharof Lake (Case et al., 1988, sheet 2).2

 

Farther southwest, the location of any 

extension of the Bruin Bay fault is unknown 

and a matter for speculation. 

A regional magnetic intensity map for the 

southern Bering Sea shelf published by 

Childs et al. (1981) is reproduced with 

annotations in figure 7. The map shows two 

principal magnetic domains with very 

different field characters. In the north, the 

map shows high-frequency, high-intensity 

magnetic anomalies. In the south, the map 

shows low-frequency, low-intensity 

magnetic anomalies. The two magnetic 

domains are clearly separated by a sharp, 

 

2 Similar relationships are shown on geologic maps 

(Magoon et al., 1976, sheet 2) to the east near 

Kamishak Bay. In the latter area, the exposed 

Naknek Formation is confined to the block southeast 

of the Bruin Bay fault, which also truncates the axes 

of large folds within the Naknek (Magoon et al., 

1976, sheet 2). Naknek folds and the Bruin Bay fault 

are both truncated by a 25.0-26.7 Ma (Oligocene) 

granodiorite/quartz diorite stock (Magoon et al., 

1976, sheets 2, 3, sites 66 & 67), which sets the 

minimum age for the deformation. 

west-trending line that may represent the 

extension of the Bruin Bay fault into the 

southern Bering Sea. 

We speculate that the northern magnetic 

domain in figure 7 is the southwestward, 

offshore extension of the Mesozoic 

magmatic arc terrane exposed north of the 

Bruin Bay fault in the western Alaska 

Range. In support of this notion we observe 

that magnetic data over the exposed 

magmatic arc terrane north of the Bruin Bay 

fault (in a regional compilation published by 

Godson, 1994) show a high-frequency, highintensity field character much like that of the 

northern magnetic domain illustrated in 

figure 7. Along the Alaska Peninsula 

proper, there are numerous magnetic 

anomalies related to Tertiary-age intrusives 

and modern volcanoes. West of 162o WL, 

the projected extension of the Bruin Bay 

fault diverges northwest away from the 

Tertiary arc and the contrast in magnetic 

domains north and south of the Bruin Bay 

fault is more clear (fig. 7). 

In marine seismic data over the Black Hills 

uplift, we observe coherent, folded 

reflections that extend up to 2 sec below a 

prominent angular unconformity at the base 

of Tertiary rocks. These coherent, folded 

reflections are interpreted to correspond to 

Mesozoic strata that are exposed onshore to 

the east along the crest of the Black Hills 

uplift (fig. 5; Wilson et al., 1995). Some 

examples of these coherent, folded 

reflections are observed within the 

“Peninsular terrane” in a seismic panel 

published by Worrall (1991, pl. 2, line “G”) 

and in the southwest end of a seismic panel 

published by Turner et al. (1988, fig. 65). 

The “Peninsular terrane” corresponds to the 

Mesozoic sedimentary rocks southeast of the 

Bruin Bay fault. 

North of the Black Hills uplift, Worrall 

 14
(1991, pl. 2) shows deeply buried synclines 

in a folded “carapace” sequence of Late 

Cretaceous to Eocene age that underlies his 

“Red” Upper Eocene unconformity. 

Worrall’s synclines are associated with 

coherent seismic reflections that are lost 

through the intervening anticlines. We 

interpret these features somewhat 

differently. We view Worrall’s “synclines” 

as grabens that record the earliest rift 

subsidence of the North Aleutian basin and 

that are filled with Paleocene to Eocene age 

strata. We interpret Worrall’s “anticlines” 

as horsts that are decapitated by an Upper 

Eocene unconformity corresponding to our 

seismic horizon “D” (fig. 6). Our horizon 

“D” correlates to Worrall’s “Red” 

unconformity. The horizon “D” 

unconformity separates the rift phase from 

the subsequent sag phase of basin 

subsidence. The horsts are acoustically 

transparent (lack coherent reflections) in 

their central areas (fig. 6 and lines “F” and 

“G” of Worrall, 1991, pl. 2). We interpret 

the horsts to be cored by primarily Mesozoic 

magmatic rocks with sparse surviving 

bodies of unabsorbed Mesozoic sedimentary 

rocks. The acoustic transparency of the 

substrate below the “Red” unconformity 

north of the graben field in North Aleutian 

basin is illustrated at the north ends of lines 

“F” and “G” of Worrall (1991, pl. 2). 

We have not attempted to map the 

southwestward extension of the Bruin Bay 

fault in seismic data, instead relying on 

magnetic character to separate the northern 

magmatic terrane from the southern 

sedimentary terrane. But, it is our general 

experience that the acoustic appearance of 

the Mesozoic substrate on the north 

(transparent) is fundamentally different from 

the Mesozoic substrate on the south 

(stratified/folded). Offshore seismic data 

therefore support our partitioning of the 

Mesozoic substrate into magmatic and 

sedimentary terranes juxtaposed along a 

southwestern extension of the Bruin Bay 

fault. 

Figures 5 and 7 show that the most 

important gas and oil prospects in the North 

Aleutian basin (partly located by Sale 92 

leases) occupy the part of the basin that 

overlies the Mesozoic magmatic terrane 

north of the Bruin Bay fault. This 

observation is very significant to conceptual 

models for petroleum charge for these 

important prospects. Any analogy to the 

petroleum system of northern Cook Inlet, 

where oil generated in an underlying 

Mesozoic basin has charged shallower traps 

in Cenozoic rocks, cannot be extended to 

this part of the North Aleutian basin. It is 

very unlikely that hydrocarbons in any 

quantity can be sourced out of the Mesozoic 

magmatic terrane beneath the part of the 

North Aleutian basin north of the Bruin Bay 

fault. These important prospects must 

instead depend entirely upon potential 

sources within the Tertiary-aged North 

Aleutian basin fill, mostly gas-prone, for 

petroleum charge. 

Mesozoic Stratigraphy and Reservoir 

Formations

A stratigraphic chart for the Mesozoic rocks 

of the Alaska Peninsula is presented in 

figure 8. Sandstones and conglomerates that 

might form reservoirs for petroleum include 

the Talkeetna, Naknek, Staniukovich, 

Herendeen, and Hoodoo (or equivalent 

Chignik) Formations. Because the 

Mesozoic basins in which these strata were 

deposited flanked a volcanic arc, most 

clastic sediments contain great quantities of 

volcanic and plutonic rock fragments. Upon 

burial, the volcanic material readily 

degraded into laumontite and other zeolitegroup minerals that fully occluded 

 15
intergranular porosity. Dutrow (1982, p. 1) 

describes typical Jurassic-age sandstones in 

the Cathedral River 1 well as follows: 

“Petrographic examination of 43 

samples from Amoco Cathedral 

River No. 1 sand, showed the 

lithology to be predominately 

volcanic-rich litharenites or 

feldspathic litharenites with only 

minor amounts of arkose, lithic 

arkose, and quartzite (the 

classification scheme used is Folk, 

1968). Typically the sands were 

compacted with no remaining 

porosity. Often volcanic rock 

fragments became incoherent with 

compaction, molding around grains 

to form an interstitial matrix. 

Where compaction did not reduce 

all intergranular voids, authigenic 

cements formed. The cements are 

chlorite/smectite, laumontite, and 

carbonate. Veins of 

laumontite/heulandite cut the 

volcaniclastic sands. These phases 

also replace pre-existing minerals. 

The most common accessory 

minerals were a green hornblendic 

amphibole, epidote and opaques 

(clasts and pyrite framboids.”(sic)

Generally, younger sandstone formations 

contain less volcanic debris because of recycling of older clastic formations and 

winnowing of volcanic particles made 

susceptible to disintegration by chemical 

and physical weathering (Burk, 1965, fig. 

10). Younger formations have also been 

less deeply buried because of their position 

at the top of the sedimentary stack and have 

presumably suffered less from compaction 

and thermally-driven pore-filling diagenesis. 

For both of these reasons, the Staniukovich 

and Naknek Formations and younger 

Cretaceous units form the best candidates 

for viable petroleum reservoirs among the 

Mesozoic assemblage (fig. 8). 

The prolific oil fields of northern Cook Inlet 

are underlain by the Upper Jurassic Naknek 

Formation sandstones, which are underlain 

by the Middle Jurassic Tuxedni Group oil 

source beds, which are in turn underlain by 

the Lower Jurassic Talkeetna Formation 

sandstones (Magoon, 1994). Despite this 

close association with the Tuxedni Group oil 

source beds (proven to have generated 1.6 

billion barrels of oil reserves now residing in 

overlying Tertiary reservoirs), there is 

virtually no oil production in northern Cook 

Inlet from the associated Mesozoic 

sandstone formations. The Naknek and 

Talkeetna Formations are completely 

cemented and barren of hydrocarbons. We 

note a single exception at the McArthur 

River oil field where a small amount 

(<300,000 bbls) of oil was produced over a 

9-year period from fractured Lower Jurassic 

rocks (Talkeetna Formation) below the main 

Tertiary-age oil reservoir (AOGCC, 2001, p. 

183). The generation of oil out of the 

Middle Jurassic oil source beds occurred 

mostly in Tertiary time (Magoon, 1994, fig. 

22.7), after 100 million years of burial stasis 

during which diagenesis and compaction 

completely destroyed the pore systems in 

Mesozoic sandstone formations. An 

intriguing concept for petroleum exploration 

of Mesozoic sandstones postulates that in 

some areas an early (presumably 

Cretaceous) cycle of burial sufficient to 

generate hydrocarbons might have charged 

the still-porous Mesozoic sandstones with 

petroleum and protected the pore systems 

from destruction. However, this was not the 

case in the Cook Inlet area. 

Cenozoic Stratigraphy, Reservoir 

Formations, and Play Sequences

The most complete point of stratigraphic 

control for the North Aleutian basin fill is 

the North Aleutian Shelf COST 1 

stratigraphic test well that was drilled in 

1983 by an industry consortium. Detailed 

 16
descriptions of the results of that well are 

given by Turner et al. (1988). The 

stratigraphy of the COST well is presented 

in figure 9 (full-scale version available as 

plate 2). 

Three play sequences based on COST well 

stratigraphy are defined for purposes of this 

assessment. Each play sequence embraces 

groups of rocks that share some 

commonality in reservoir formation 

characteristics and relationships to 

prominent unconformities and seismic 

markers. The play sequences considerably 

overlap biostratigraphic boundaries but 

correspond sufficiently to established 

stratigraphic units to permit co-opting the 

formal nomenclature into our play sequence 

terminology (shown in fig. 9, right column). 

Detterman (1990) extended Alaska 

Peninsula stratigraphic nomenclature to the 

North Aleutian Shelf COST 1 well and we 

adopt his correlations for this assessment 

(shown in fig. 9, left column). A 

stratigraphic correlation chart in figure 10

(full-scale version available as plate 3) 

shows the relationship of the North Aleutian 

Shelf COST 1 well to several onshore 

penetrations of Tertiary rocks. 

The Milky River Biogenic Gas (play 4) play 

sequence ranges in age from Early Pliocene 

to Holocene and includes the upper part of 

the Milky River Formation and overlying 

unnamed Quaternary-age rocks. The play 

sequence is 2,148 feet thick at the North 

Aleutian Shelf COST 1 well. The play 

sequence overlies seismic horizon “A”, 

which generally is not domed over basement 

uplifts. The play sequence consists of 

middle to outer neritic unconsolidated lithic 

pebbly sands, mud, ooze, and clay (Turner et 

al., 1988, p. 14). 

The Bear Lake-Stepovak (plays 1, 3) play 

sequence ranges in age from Late Oligocene 

to Early Pliocene in the North Aleutian 

Shelf COST 1 well and includes the upper 

part of the Stepovak Formation, the entire 

Bear Lake Formation, and the lower part of 

the Milky River Formation. The play 

sequence is 5,390 feet thick at the COST 

well and thickens to approximately 7,300 

feet in seismic data along the north coast of 

the Alaska Peninsula (Turner et al., 1988, 

figs. 66, 67). The Bear Lake-Stepovak play 

sequence overlies seismic horizon “C” 

which is a regional mid-Tertiary 

unconformity. On parts of the Black Hills 

uplift, seismic horizon “C” places Oligocene 

rocks directly upon Mesozoic rocks. 

Seismic horizon “C” does not contact 

basement over the basement horsts in the 

southwest half of the North Aleutian basin, 

but overlies a sandy sequence and a regional 

shale sequence in the lower part of the 

Stepovak Formation (fig. 10). Seismic 

horizon “D” incises basement on the horsts 

in the southwest half of the North Aleutian 

basin. The seismic profile in figure 6 (and 

pl. 1) shows that most of the strata in the 

Bear Lake-Stepovak play sequence are 

domed over the basement horsts in the 

southwest half of the North Aleutian basin. 

The Bear Lake-Stepovak play sequence at 

the North Aleutian Shelf COST 1 well is 

rich (61% of play sequence) in thick (up to 

277 feet), porous (up to 40+% porosity), and 

permeable (up to 7,722 md) sandstones. 

Some statistics for sandstone beds in the 

Bear Lake-Stepovak play sequence are 

summarized in figure 11. The play sequence 

contains a total of 3,120 net feet of 

sandstones in beds greater than 10 feet thick 

(an assumed practical minimum thickness 

for productive reservoir) and 1,443 net feet 

in beds over 100 feet thick. Figure 12

shows core porosity versus depth for 

sandstones in the North Aleutian Shelf 

COST 1 well. Core porosity is also posted 

with density log sandstone porosity in figure 

 17
9 and plate 2. For the Bear Lake-Stepovak 

play sequence, core porosity ranges between 

20% and 40%. Figure 13 summarizes core 

porosity and permeability data and we note 

that the 20% to 40% porosity range is 

associated with multi-Darcy permeability 

values. Figure 14 summarizes core 

permeability data versus depth and we 

observe that the statistical fit forecasts 

preservation of permeability at tens of 

millidarcies (at the mean) down to the base 

of the Bear Lake-Stepovak play sequence. 

A core porosity histogram for the Bear 

Lake-Stepovak play sequence is shown in 

the upper panel of figure 15. A core 

permeability histogram for the Bear LakeStepovak play sequence is likewise 

presented in the upper panel of figure 16. 

Because of the ample, thick sandstones and 

the excellent preservation of porosity and 

permeability, the Bear Lake-Stepovak play 

sequence is the most attractive reservoir 

target in the North Aleutian basin. 

The Tolstoi (play 2) play sequence ranges in 

age from Early Eocene to Early Oligocene 

in the North Aleutian Shelf COST 1 well 

and includes the Tolstoi Formation and the 

lower, shaly part of the Stepovak Formation 

(9,555-10,380 ft bkb) that forms a regional 

seal (fig. 10 and pl. 3). The minimum 

thickness (base not penetrated) of the Tolstoi 

play sequence is 9,255 feet at the North 

Aleutian Shelf COST 1 well. The Tolstoi 

play sequence probably extends through 

Paleocene strata down to Mesozoic volcanoplutonic “basement” beneath the COST 

well. Seismic horizon “D” occurs within the 

upper part of the Tolstoi play sequence and 

corresponds to a regional Upper Eocene 

unconformity that truncates the crests of 

basement uplifts in the southwest half of the 

North Aleutian basin (fig. 6 and pl. 1). As 

shown in the sandstone thickness histograms 

of figure 11, the Tolstoi play sequence is 

characterized by sparse (10% to 30% of 

interval), thin (maximum = 57 ft) 

sandstones. In the upper part of the Tolstoi 

play sequence, from 7,900 to 10,380 feet in 

the COST well, the sandstones are porous 

and permeable (figs. 12, 14, 15, and 16). 

This part of the sequence, like the overlying 

Bear Lake-Stepovak play sequence, is 

draped over the basement uplifts. Below 

10,380 feet, the sandstones are largely 

impermeable (fig. 16, lower panel) because 

diagenesis (to clay and zeolites) has softened 

volcanic clasts and the sandstone grain 

framework has collapsed, as described in 

petrographic studies by AGAT (1983, p. 2) 

and Turner et al. (1988, p. 23-24). This 

collapse post-dates some early pore-filling 

cement, around which formerly rigid 

volcanic framework grains (softened by 

diagenesis) have flowed (AGAT, 1983). 

The abrupt loss of permeability in 

sandstones approximately coincides with the 

onset of overpressure at 11,200 feet bkb (fig. 

9 and pl. 2) in the North Aleutian Shelf 

COST 1 well. The diagenetically-induced 

implosion of the intergranular pore system 

and expulsion of fluids may be a prime 

driver for the overpressure (Turner et al., 

1988, p. 217). Core porosity data for the 

Tolstoi play sequence are summarized in the 

histograms of figure 15. Most of the 

measured core porosity in the Tolstoi play 

sequence below 10,380 feet bkb in the 

COST well is microporosity in altered 

volcanic rock fragments. 

The lower part of the Tolstoi play sequence 

(below 10,380 ft/seismic horizon “D”) is 

truncated by faults at the flanks of basement 

uplifts and would form the primary reservoir 

targets for prospects ringing uplift flanks. 

The probable absence of porous sandstones 

in the lower part of the Tolstoi play 

sequence forms an area of great risk for the 

flank prospects. 

 18
Petroleum Systems in North Aleutian 

Basin Plays

Thermal Maturity of North Aleutian 

Basin Fill

The first important concern about the 

viability of any potential petroleum systems 

in North Aleutian basin is whether or not 

any rocks have been buried to depths and 

temperatures sufficient to convert organic 

matter to oil or gas. Figure 17 summarizes 

vitrinite reflectance data for the North 

Aleutian Shelf COST 1 well and offers 

statistical fits to data sets above and below a 

discontinuity at 15,620 feet bkb. The 

vitrinite reflectance discontinuity has been 

cited as evidence for an unconformity at 

15,620 ft bkb (Turner et al., 1988, p. 192; 

Robertson Research, 1983). If so, the 

statistical fits indicate “erosion” of 647 feet 

of section at the “unconformity.” As an 

alternative interpretation, we suggest that the 

discontinuity at 15,620 ft bkb is a 647-foot 

sequence gap at the point where the well 

penetrated an unrecognized normal fault. 

We note that no vitrinite reflectance 

discontinuities are associated with known 

regional unconformities corresponding to 

either seismic horizon “B” (5,675 ft; Upper 

Oligocene), seismic horizon “C” (7,900 feet, 

Upper Oligocene), or seismic horizon “D” 

(10,380 ft; Upper Eocene). A 20-degree 

structural dip first noted in core 19 (Turner 

et al., 1988, p. 26) probably indicates the 

presence of an angular unconformity 

between flat-lying strata at the base of core 

18 (16,028.5 ft bkb) and dipping strata at the 

top of core 19 (16,701 ft bkb). This is the 

“Lower Eocene unconformity” posted in the 

seismic profile of figure 6 (pl. 1) and in the 

stratigraphic column of figure 9 (pl. 2). As 

with the shallower regional unconformities, 

no discontinuity in vitrinite reflectance is 

associated with this angular unconformity 

(fig. 17). 

The statistical fits to the data sets above and 

below the fault gap at 15,620 ft bkb in figure 

17 were used to forecast depths to various 

isograds3

 that correspond to critical stages in 

source maturation, as tabulated (inset) in 

figure 17. These isograds are posted on the 

seismic profile in figure 6 (and pl. 1) and 

show that the principal reservoir section 

(between seismic horizons “A” and “C”) in 

the sequence domed over the basement 

uplifts is thermally immature (pre-oil 

generation). Only the much deeper rocks in 

the grabens flanking basement uplifts are 

thermally mature and capable of having 

generated oil or gas. Rocks within the 

Mesozoic substrate may be sufficiently 

thermally mature to have generated oil or 

gas, but in this area these rocks are 

interpreted to consist of mostly volcanoplutonic arc rocks. Successful charging of 

prospects in the strata domed over basement 

uplifts will require generation of petroleum 

in flanking deeps, lateral migration to the 

flanks of basement uplifts, and vertical 

migration up faults through the regional 

shale sequence (approx. the interval between 

seismic horizons “C” and “D” in fig. 6 and 

pl. 1) in order to reach sandstone reservoirs 

in the Bear Lake-Stepovak play sequence 

(between seismic horizons “A” and “C”). 

The basement uplift to the southeast of the 

North Aleutian Shelf COST 1 well in figure 

6 (and pl. 1) won 73% of the sum of all high 

bids in OCS Lease Sale 92 in 1988. All of 

the remaining bids in Sale 92 were placed on 

tracts over nearby basement uplifts that 

similarly dome the overlying Bear LakeStepovak play sequence and that are also 

adjoined by areas of deep subsidence where 

 

3 “Isograd” is used here to denote a surface of fixed 

thermal maturity. Any single thermal maturity index 

value (TTI, Ro%, etc.) can be used to represent an 

isograd. 

 19
the basin fill lies within the oil and gas4

generation zone. It appears that the energy 

companies that placed bids on tracts in Sale 

92 embraced the basic framework of the 

hypothetical petroleum system described 

above as that most likely to create 

significant petroleum accumulations within 

North Aleutian basin.5 The model requires 

generation of large quantities of petroleum 

in flanking grabens and migration of the 

petroleum several thousands of feet upward 

into porous strata domed over basement 

uplifts. The minor (small displacement) 

faults extending upward from the major 

(large displacement), older faults along 

uplift flanks are the only faults that penetrate 

the regional lower Stepovak shale seal 

(overlying seismic horizon “D”; fig. 10 and 

pl. 3). These faults may provide the critical 

pathways from deep areas of petroleum 

generation to shallow traps domed over 

uplifts. 

Figure 18 presents regional well data for 

thermal maturity compiled into a structure 

map for the 0.6% vitrinite reflectance 

isograd, which generally coincides with the 

onset of oil generation (depending on 

organic matter composition, oil or gas 

generation can begin as low as 0.5% vitrinite 

reflectance [liptinitic or Type 1 kerogens]; 

Dow, 1977, fig. 3). Areas highlighted in 

gray represent Tertiary basin fill that 

exceeds 0.6% vitrinite reflectance. If rocks 

with appropriate organic matter for creation 

 

4 Boreham and Powell (1993, p.149-50) point out 

that “humic coals and terrigenous kerogens can form 

appreciable quantities of gas over the maturity range 

of oil generation....” and “...significant yields of gas 

generation before the onset of intense liquid 

generation have been experimentally observed for 

both hydrogen-poor and hydrogen-rich organic 

matter.” 

5 Some may have relied upon oil generated in the 

Mesozoic substrate. For reasons explained in 

previous sections, we believe that the Mesozoic 

substrate beneath the key prospects shown in figure 6

is composed of volcano-plutonic rocks. 

of oil and gas lie within the gray areas, the 

latter then become the “oil (and gas) 

kitchens” for the basin. Figure 19 maps the 

thicknesses of Tertiary-age strata within the 

oil generation zone and we note that the 

maximum penetrated thickness (minimum, 

4,758 ft) is at the North Aleutian Shelf 

COST 1 well. 

The North Aleutian basin hypothetical “oil 

kitchen” is segmented by the presence of a 

massive volcanic center at the Port Heiden 1 

and Ugashik 1 wells. This volcanic center 

produced a thick pile of volcanic flows and 

volcaniclastic sediments 33 to 39 millions of 

years ago. The volcanic pile is represented 

by the Meshik Formation. The Meshik 

Formation is age-equivalent to the Stepovak 

Formation (Brockway et al., 1975) or 

Tolstoi Formation (Detterman, 1990), with 

which the volcanic rocks interfinger at the 

margins of the volcanic center (fig. 10 and 

pl. 3). The segmentation by this volcanic 

center of the thermally-mature rocks 

flooring North Aleutian basin leaves the 

southwest part of the basin with the largest 

continuous volume of potentially oilgenerative rocks. This part of the basin has 

accordingly formed the primary area of 

exploration interest in the past. 

The Amak basin fill reaches a maximum 

thickness of about 12,500 feet, scarcely 200 

feet deeper than the depth to the 0.6% 

vitrinite reflectance isograd (12,312 ft 

subsea) in the North Aleutian Shelf COST 1 

well. It appears that only a very small 

volume of rock at the floor of the Amak 

basin lies within the oil generation zone. It 

is therefore unlikely that significant 

quantities of hydrocarbons have been 

generated in the Amak basin. 

 20
Source Rock Potential

The second important concern about 

potential petroleum systems in the North 

Aleutian basin is whether or not any rocks 

have the type of organic matter appropriate 

for conversion to oil or gas upon heating. 

We recognize two groups of potential source 

rocks: 1) Mesozoic sedimentary rocks that 

underlie the southwest part of North 

Aleutian basin and the Black Hills uplift; 

and 2) Cenozoic rocks that comprise the 

North Aleutian basin fill. 

Mesozoic Source Rocks

The principal point of control for the source 

rock potential of Mesozoic rocks in the 

North Aleutian Basin OCS Planning Area is 

the Cathedral River 1 well. Some indicators 

for source rock potential of the Mesozoic 

rocks in this well are plotted in figure 20. 

Mesozoic rocks extend across southern 

Alaska (fig. 4) but are known to have 

generated significant quantities of oil only in 

the northern Cook Inlet area. The Kialagvik 

Formation in the Cathedral River 1 well (fig. 

20) is age-equivalent to the Middle Jurassic 

Tuxedni Group that generated the oil in 

northern Cook Inlet producing fields 

(Magoon, 1994). The Kamishak Formation 

in the Cathedral River 1 well is ageequivalent to unnamed Upper Triassic rocks 

at Puale Bay that are suspected of 

contributing oil to some minor 

accumulations and seeps in southern Cook 

Inlet and the Alaska Peninsula (Magoon and 

Anders, 1992; Magoon, 1994). The Upper 

Triassic rocks at Puale Bay form excellent 

oil-prone source rocks (Wang et al., 1988, 

fig. 4), but are only known from that outcrop 

locality and the penetration at the Cathedral 

River 1 well. 

For most of the Mesozoic sequence 

penetrated by the Cathedral River 1 well6

, 

the rocks are rated as poor to fair sources 

(TOC) for gas (Hydrogen Index). Two 

significant anomalies are observed in figure 

20. Shales and tuffaceous limestones in the 

interval from 8,700 to 9,300 feet in the 

Kialagvik Formation appear to rate as 

“good” potential sources for oil and wet gas. 

Cherty shales and marlstones in the interval 

from 12,000 to 12,700 feet in the Talkeetna 

Formation also appear to form “good” 

sources for oil and wet gas7. These 

anomalies are somewhat suspect because the 

elevated thermal maturity (>3.0 T.A.I., or 

greater than approximately 1.0% vitrinite 

reflectance below 7,300 ft bkb) of much of 

 

6 The logged shows and geochemical data in the 

Cathedral River 1 well are somewhat problematic in 

that oil-base additives were introduced into the 

drilling mud at about 7,500 feet. However, no 

geochemical anomalies are observed at the first 

reported (Borst & Giddens mud log) point of 

introduction of “Soltex” at 7,500 feet (fig. 20). The 

deeper anomalies rise from an established 

“background” and could be reflecting rock 

compositions rather than drilling mud contamination, 

unless other additives were introduced. An 

annotation on the Borst & Giddens mud log at 8,770 

feet reports that “abundance of tar noticed in 

samples are determined to be contamination as 

results (sic) of mud additive reactions of ‘HME’ and 

‘SuperLubFlow’”. The anomalies in the TOC and 

HI profiles may reflect authentic rock properties, but 

the potential contamination clouds the issue (Peters, 

1986, p. 324-5) and in this case blocks any 

straightforward conclusions. Geochem Laboratories 

(Geochem, 1976) reported that samples deeper than 

8,600 feet were contaminated, possibly with 

“Gilsonite”. We note that Peters (1986, fig. 12) 

specifically discusses the Cathedral River 1 case and 

concludes that the anomalies are entirely artifacts of 

contamination by drilling mud additives. 

7 Oil staining is reported (Detterman, 1990) in rocks 

immediately above these anomalies. Modest “S1” 

(resident hydrocarbons thermally distilled out of 

rocks during pyrolysis experiments) anomalies (rise 

from 0.2 to 0.7 mg/g [upper zone] or 0.2 to 1.07 mg/g 

[lower zone]) suggest a possible association of the 

TOC and Hydrogen Index anomalies with migrated 

oil. 

 21
the Cathedral River 1 sequence indicates 

that most of the original oil generation 

potential of the Mesozoic rocks has been 

depleted. A single vitrinite reflectance 

analysis (6 measurements) at 10,650 feet 

yielded a mean value of 1.47%, well past the 

1.35% vitrinite reflectance isograd marking 

exhaustion of all oil generation potential. 

The top of the prominent geochemical 

anomaly within the Talkeetna Formation lies 

at 12,000 ft bkb, 1,350 feet below the lone 

vitrinite reflectance measurement. 

The pyrolysis data are inconclusive because 

of doubts about analytical results (possibly 

distorted by mud additive contaminants, as 

footnoted) and the high thermal maturity of 

the Mesozoic sequence (original generative 

potential largely depleted). However, the 

Cathedral River 1 data are at least 

permissive of the potential existence of oil 

sources within the Mesozoic sedimentary 

rocks beneath the Black Hills uplift. That 

some oil source rocks once existed within 

the Mesozoic sequence beneath the Black 

Hills uplift is supported by the observation 

of oil shows throughout the Cathedral River 

1 well. Oil shows were first noted as 

shallow as 390 feet bkb, far above the first 

reported introduction of the troublesome 

drilling mud contaminants at 7,500 feet. 

The time of generation of this oil is 

unknown. Near the surface, the Cathedral 

River 1 well entered Mesozoic rocks with 

T.A.I. values of 2.5 (fig. 20), approximately 

equivalent to 0.65% vitrinite reflectance. A 

vitrinite reflectance of 0.65% corresponds to 

a depth of 13,287 feet bkb in the North 

Aleutian Shelf COST 1 well. Clearly, the 

rocks in the Cathedral River 1 well were 

previously much more deeply buried. 

Because the well is located on the Black 

Hills uplift where Mesozoic strata are 

unconformably overlain by Eocene-age 

rocks (north flank), it appears that the 

thermal maturation occurred during a 

Mesozoic cycle of deep burial. Thus, there 

is substantial risk that Mesozoic oil sources 

in this area generated and expelled their oil 

long before the deposition of Tertiary-age 

reservoir sandstones or the formation of 

drape anticlines in Oligocene strata atop the 

Black Hills uplift. 

Tertiary Source Rocks

The principal point of control for the source 

rock potential of the Tertiary-age fill for 

North Aleutian basin is the North Aleutian 

Shelf COST 1 well. A graphical summary 

of source rock geochemical information is 

attached as plate 4. An Excel spreadsheet 

containing most available geochemical data 

for the COST well is included as Appendix 

2. The data in Appendix 2 were extracted 

from the original reports by Exlog (1983) 

and Robertson Research (1983), which are 

attached as Adobe Acrobat (pdf) files to this 

report as Appendix 4 and Appendix 5, 

respectively. 

Some indicators for source potential (TOC) 

and hydrocarbon type (hydrogen index or 

“HI”) in the COST well are plotted in figure 

21. Total organic carbon (TOC) data 

suggest that source potential ranges from 

“poor” to “very good.” Hydrogen index 

(HI) values suggest mostly gas sources with 

some intervals where HI>300 that might be 

capable of generating oil. Sample 

descriptions reveal that most samples with 

TOC values exceeding 1.0% include coal, as 

either discrete fragments in cuttings or coaly 

laminations in core samples. In the several 

depth intervals below 8,000 feet in figure 21

where HI>300, we note that nearly all of the 

elevated HI values are associated with rock 

sequences described as containing coal. 

The key question then is whether or not 

these high-HI coals, or possibly non-coal 

lithologies mixed with coal material in 

 22
samples, are legitimately capable of 

generating oil. 

Source Potential of Coal-Bearing Rocks 

Exlog (1983, p. 8) attempted to remove the 

coal (by water flotation) from a suite of 

cuttings samples and then conducted 

separate pyrolysis8

 experiments on the 

“coal-removed” and “coal-retained” sample 

suites. Both data sets are shown in the well 

profiles for pyrolysis data in figure 21 and 

plate 4. Figure 22a compares these two 

Exlog data sets in a modified Van Krevelen 

diagram. The plot fields for “coalremoved” and “coal-retained” sample suites 

in figure 22a essentially overlap with several 

samples from both suites yielding HI>300. 

One possible conclusion from the Exlog

experiment is that both coal-bearing and 

non-coal-bearing lithologies in the COST 

well are capable of generating liquid 

hydrocarbons. A second possible 

conclusion is that the Exlog9

 method for 

removing coal from cuttings was 

unsuccessful and that the high HI values in 

both sample suites are associated with coal 

material. Clearly, a more explicit means of 

evaluating the source potential of the well 

samples is needed. We first need to 

establish the role of coal-bearing samples in 

generating the high HI values noted in parts 

of the COST well. We secondly need to 

establish the liquid-generating potential of 

the coals themselves. 

 

 

8 Samples are heated, driving off existing petroleum 

(bitumen) and then cracking the organic matter and 

releasing petroleum-like materials. This method is 

fast and inexpensive compared to elemental analysis 

and can yield results that can be used in a similar 

way. 

9 Use of trade names or references to specific 

corporate entities or products in this report is for 

descriptive purposes only and does not constitute 

endorsement of these products or companies by the 

U.S. Minerals Management Service 

Cuttings samples are problematic because 

unstable formations like coal may 

spontaneously collapse (“cave”) into the 

uncased part of a wellbore at any time and 

mix with the actual cuttings carried away 

from the drill face to the surface. A cuttings 

sample may contain materials from any 

depth in the uncased or “open” part of a well 

and may not represent the collected drill 

interval. Unless “cave” materials are 

selectively removed, bulk analyses of 

cuttings samples will not truly represent the 

drill interval. 

Sidewall and conventional core data clarify 

the link between the presence of coal and 

elevated HI values in the North Aleutian 

Shelf COST 1 well. Figure 22b shows a 

modified Van Krevelen diagram with 

pyrolysis data for core samples from the 

COST well (Robertson Research, 1983, 

App. III). Samples described as coalbearing are plotted separately from samples 

for which descriptions did not note the 

presence of coal. All core samples with HI 

values exceeding 151 are described as 

containing coal by Robertson Research 

(1983, App. II). Among sidewall cores, the 

highest HI value observed for coal-free 

samples is 123. Among conventional core 

samples, the highest HI value observed for 

coal-free samples is 151. Coal-free core 

samples therefore appear to be primarily 

sources for gas (characterized by HI<150). 

But, what about the coal-bearing core 

samples with HI>150? Could these coalbearing rocks form potential sources for oil? 

Figure 22c shows a Van Krevelen-type10

10 The Robertson Research (1983, App. VII) data set 

reports O (oxygen) and S (sulfur) as combined into a 

single value. The classification fields in figures 22c

and 22d were extracted from a published diagram 

plotting H/C versus O/C (Tissot and Welte, 1984, fig. 

II.4.14). The presence of significant quantities of 

sulfur may shift the data to the right and distort 

 23
diagram with elemental data11 for sidewall 

and conventional core samples, with coalbearing and coal-free samples plotted 

separately. All samples fall within (or to the 

right of) the classification area for Type III 

(gas-prone) organic matter. Samples in 

figure 22c with [O+S]/C elemental ratios 

greater than 0.6 are atypical and may contain 

sulfur or oxygen-rich matter like lignite or 

woody material12 (Tissot and Welte, 1984, 

fig. II.8.6, p. 240). 

Nine core samples containing coal that have 

HI>150 (HI range, 200-373; mean HI=289) 

and for which elemental data are available 

are plotted in figure 22d. The oil-generating 

potential suggested by the high HI values for 

these 9 coal-bearing core samples is not 

supported by elemental data. Figure 22d

shows that none of the nine COST well core 

samples plot within the Type I or Type II 

classification fields where algal coals are 

usually found. All 9 core samples with 

HI>150 are shown by elemental data to 

contain primarily Type III organic matter 

and to therefore be gas-prone. 

In pyrolysis experiments coals can yield 

specious results that improperly “type” 

organic matter. Coals sometimes yield high 

pyrolysis HI values that over-estimate the 

capacity to generate liquid petroleum 

(Peters, 1986, p. 322). Another problem is 

that thermally-mature coals may yield low 

oxygen index (OI) values during pyrolysis 

because more oxygen is released as carbon 

monoxide (not detected by device) rather 

than carbon dioxide (detected by device) 

(Peters, 1986, p. 322). Both of these 

pyrolysis responses of coals would lead to 

 

 

relationships to traditional kerogen classification 

fields. 

11 H, hydrogen; C, carbon; O, oxygen; and S, sulfur. 

Obtained by chemical analysis of isolated kerogens. 

12 “Woody fibers” were described in cuttings from 

2,580 to 4,320 ft md (Robertson Research, 1983, App. 

II). 

an incorrect interpretation of the type of 

organic matter. Robertson Research (1983, 

p. 9) raised another problem wherein the 

coal-bearing samples in the COST well may 

have yielded high HI values and low OI 

values because of the presence of solid 

bitumen. This has the effect of shifting data 

points toward the y-axis (fig. 22b) and 

perhaps out of the classification field for 

Type III kerogen and into the classification 

field for Type II kerogen. 

Given the ambiguities of interpreting coal 

pyrolysis data, it seems clear that elemental 

data provide a more reliable way to evaluate 

the oil-generating potential of the coalbearing Tertiary rocks in the North Aleutian 

Shelf COST 1 well. The elemental data at 

hand indicate dominance of gas-prone Type 

III kerogens in coal and non-coal lithologies 

alike. Oil-prone algal coals, if present, were 

not sampled by the North Aleutian Shelf 

COST 1 well. 

Source Potential of “Amorphous” Interval, 

15,620-17,155 ft bkb 

The part of the COST well below the fault 

cut at 15,620 ft (fig. 17) is associated with 

abundant “amorphous” (oil-prone) kerogens, 

high H/C values, high gas “wetness,” 13 and 

oil shows. These outwardly signal the 

possible presence of potential oil sources in 

what is otherwise a nonmarine, coal-bearing 

clastic sequence (fig. 9). A review of the 

characteristics of what we here informally 

term the “amorphous” interval follows. 

The part of the COST well below the fault 

cut at 15,620 feet drew attention soon after 

the well was drilled because it is associated 

with high fractions (30% to 55%) of 

“amorphous” (i.e., unstructured) kerogens as 

13 Gas present in the tops of sealed cans containing 

cuttings samples. 

 24
observed in microscope studies (upper 

panel, pl. 4). “Amorphous” kerogens 

usually signal algal origins (Type I kerogen) 

and in dominant proportions may form a 

source for liquid hydrocarbons. 

The “amorphous” interval probably does not 

form a source for oil. The amorphous 

kerogen content in the COST well samples 

is probably insufficient to form effective oil 

sources. Robertson Research (1983, p. 6-7) 

claims that amorphous kerogens must 

exceed 65% by volume14 relative to the 3 

other kerogen classes to form an effective 

oil source. Microscopy studies indicate 

abundances ranging between 30% and 50% 

in the “amorphous” interval in the COST 

well (upper panel, pl. 4). 

Other data indicate poor potential for 

generation of liquid hydrocarbons by the 

“amorphous” interval. The interval in the 

COST well is associated with low values for 

HI, low genetic potential (S1+S2), mostly 

low elemental H/C ratios (4 exceptions 

noted below), and high pristane/phytane 

ratios (upper panel, pl. 4). The latter all 

argue for predominantly Type III organic 

matter in the “amorphous” interval. To 

explain the curiously gas-prone character, 

Robertson Research (1983, p. 8) speculated 

that the “amorphous” kerogens between 

16,009.3 and 17,143 ft are actually either 

oxidized relicts of original amorphous 

material or perhaps finely divided vitrinite 

that was incorrectly classified by 

microscopy. Tissot and Welte (1984, p. 

158, fig. II.4.16) illustrate examples of poor 

correlation between “amorphous” kerogens 

and source type from elemental analysis. In 

either case, based on these data, the 

“amorphous” interval in the COST well is 

 14 A large proportional volume relative to other 

classes of kerogens (exinite, vitrinite, and inertinite) 

is required because of the low density of amorphous 

kerogen. 

viewed as primarily a source for gas. 

A depth profile for elemental H/C data for 

the COST well is shown in the upper panel 

of plate 4. Elemental data classify most of 

the strata penetrated by the well as potential 

sources for dry gas or wet gas. However, 

within the “amorphous” interval below 

15,620 feet, four conventional core samples 

yielded elemental H/C ratios greater than 

1.0,15 suggesting some liquid-generating 

potential. These samples are coal-free and 

are described as gray or brown massive 

shales (Robertson Research, 1983, App. II). 

Vitrinite reflectance values for these four 

samples range from 0.98% to 1.01% 

(Robertson Research, 1983, App. III). At 

this level of thermal maturity, these H/C 

values would normally be associated with an 

oil-prone source (as classified by the profile 

in pl. 4). However, HI values for these four 

samples range from 88 to 120, indicating 

instead a gas-prone source.16 Also, these 

four samples yielded high [O+S]/C ratios 

that associate them with Type III organic 

matter in a Van Krevelen-type diagram (the 

four samples are highlighted in fig. 22c). 

Robertson Research noted that reflectedlight microscopy revealed “medium” to 

“high” presence of solid bitumen in these 

four samples and concluded that this 

material, rather than kerogens, may be the 

source of the elevated H/C ratios (Robertson 

Research, 1983, p. 8, 190-192; Appendix 5, 

this report). 

Headspace gas wetness ranges up to 95% in 

the “amorphous” interval, but most values 

range between 75% and 85% and heavier 

gases (C5+) form less than 20% of 

headspace gases (lower panel, pl. 4). 

Robertson Research (1983, p. 10) indicate 

that these data suggest a wet gas source and 

15 Ranging from 1.06 to 1.12; samples at 16,029.0 ft, 

16,703.7 ft, 16,714.6 ft, and 16,719.6 ft. 16 Oil-prone kerogens at this thermal maturity should 

yield HI>200 (see Baskin, 1997). 

 25
a low probability for generation of 

significant quantities of oil. 

Finally, the oil shows logged in and just 

above (15,450-15,500 ft bkb) the 

“amorphous” interval are actually quite 

sparse and are described as “slight” or 

“trace” in the sample (“mud”) logs (lower 

panel, pl. 4). Detailed analyses of extracts 

of these oil shows and correlations to 

possible source rocks are described below. 

Source Potential of Tertiary Basin Fill and 

Assessment Model 

From these data, we conclude that most of 

the depth intervals in the COST well that 

appear from pyrolysis results to form 

potential oil sources are actually coalbearing intervals that are dominated by Type 

III (gas-prone) organic matter. Although 

some exceptions are known,17 coal is not 

commonly a source for oil because the 

typically modest quantities of petroleum 

liquids that are generated are often 

sequestered (“sorbed” into extensive internal 

pores) within the coal (Levine, 1993, p. 40, 

71). Other intervals of interest for oil source 

potential, such as the “amorphous” interval, 

appear on the basis of other data to form 

potential sources for gas or wet gas, with 

possible minor quantities of liquids. 

We conclude, as did Robertson Research 

(1983, p. 1-9) and Turner et al. (1988, p. 

190-191) from consideration of all 

geochemical data, that the Tertiary sequence 

penetrated by the North Aleutian Shelf 

COST 1 well contains primarily Type III 

organic matter. This gas-prone organic 

 

17 In the best-known example, Upper Cretaceous and 

Tertiary coals in the Gippsland basin of Australia are 

credited as the source for liquid petroleum reserves 

of 3.762 billions of barrels and gas reserves of 7.8 

trillions of cubic feet (Clayton, 1993, p. 187, tbl. 1). 

matter occurs in coal beds or is dispersed as 

finely divided material in clastic rocks and 

forms poor to very good sources for gas, 

with minor potential for condensates and 

light oil. Our conclusions about the source 

potential for the Tertiary fill in the North 

Aleutian basin are reflected in our 

assessment models for plays 1, 2, and 6 

(tbls. 3, 4, and 8), which are primarily 

sourced by Tertiary rocks. For these three 

plays, we estimate that there is a 10% 

chance that any pool will be filled 

completely with oil and an 80% chance that 

any pool will be filled completely with gas. 

For the 10% fraction of the overall pools in 

which free oil is overlain by a gas cap 

(“mixed” case), we estimate that 90% of the 

pool volume is occupied by gas. Although 

these model input values are speculative, 

they reflect our sentiment that the Tertiary 

fill of the North Aleutian basin is most likely 

a source for gas with some potential for 

minor quantities of petroleum liquids. 

Oil and Gas Occurrences and Biomarker 

Correlations

Gas was recovered by three flow tests at 

rates summing to 90 Mcfg/d from 3 zones in 

the Tolstoi Formation in the Becharof Lake 

1 well. Gas was also recovered in flow tests 

from two intervals in the Tolstoi Formation 

at rates of 5 to10 Mcfg/d (with 300-400 

barrels of water per day) in the David River 

1/1A well. Oil and gas shows were noted 

elsewhere in wells offshore and in wells on 

the Alaska Peninsula (annotated in fig. 2). 

Gas seeps are observed as gas “chimneys” in 

some proprietary seismic profiles on the 

Black Hills uplift. Onshore, oil and gas 

seeps are known primarily from the area 

near the east end of Becharof Lake, where 

they are observed along the axes of exposed 

anticlines in Mesozoic rocks or along 

 26
important faults. Gas seep samples are 

composed mostly of carbon dioxide and 

other non-combustible gases, with minor 

hydrocarbons, as shown in the plot and inset 

data table of figure 23. These gas seeps are 

probably the result of magmatic intrusions 

that are decarbonating limestones in the 

subsurface. Reifenstuhl (2005) however 

reports a gas seep from Oil Creek18 that 

consists of 91% methane, 7% nitrogen, and 

2% carbon dioxide. Natural gas recovered19

from the Becharof Lake 1 well consists of 

87.5% methane, 4.7% ethane, 2.3% propane, 

0.8% butane, 1.0% hydrogen, and 3.7% 

“other” gases (AOGCC, 1985, DST data). 

This gas is very different from most of the 

nearby seeps which are mostly carbon 

dioxide (fig. 23). Methane carbon isotope 

(C13 and C12 isotope ratios) data for cuttings 

headspace gases in the Becharof Lake 1 well 

are shown in figure 24a. Above 3,000 feet, 

the gas is primarily biogenic in origin; 

below 5,500 feet, it is primarily thermogenic 

in origin. Gases are of mixed origins in the 

intermediate interval (3,000 to 5,500 ft) of 

Bear Lake and Stepovak Formations. 

Thermally-mature Tertiary strata reach 

thicknesses of 1,127 ft in the area of the 

Becharof Lake 1 well (fig. 19). The 

relatively dry thermogenic gas (wetness = 

8.2%) recovered in the DST in the Becharof 

Lake 1 well (fig. 24b) is probably Tertiarysourced. 

Oil seeps emanating from Jurassic rocks 

along the axes of exposed anticlines 

attracted the earliest exploration drilling to 

the Alaska Peninsula in the early 1900’s. 

Geochemical studies of these seep oils 

suggest that they were sourced from Upper 

Triassic rocks (unnamed) like those exposed 

at Puale Bay (locale posted in fig. 2), with 

 

18 Four miles west of Puale Bay (fig. 2). 19 Recovered in a DST (drill stem test) (30 mcfg/d) 

from the interval 7,470 to 7,550 feet (Tolstoi Fm., 

near top of oil window).

possible contribution from Middle Jurassic 

rocks (Kialagvik Fm.) like those exposed in 

the same area (Magoon and Anders, 1992). 

The Upper Triassic rocks exposed at Puale 

Bay are minimally thermally mature 

(TMAX= ~438oC, or about 0.7% vitrinite 

reflectance) and form excellent oil-prone 

source rocks (Wang et al., 1988, figs. 4, 16). 

Where age-equivalent Mesozoic 

sedimentary rocks underlie North Aleutian 

basin and the Black Hills uplift, they might 

form sources for oil migrating into overlying 

Tertiary-age rocks. The Mesozoic rocks 

exposed along the Black Hills uplift, like at 

Puale Bay, are minimally thermally mature 

at the surface (TAI=2.5, or about 0.65% 

vitrinite reflectance, Cathedral River 1 well) 

and any oil moving out of them into Tertiary 

reservoirs would probably be re-migrated 

from disrupted pools that formed prior to 

Tertiary time. Most exposures of Mesozoic 

rocks along the Alaska Peninsula south of 

the Bruin Bay fault are mapped at a level of 

thermal maturity exceeding 0.6% vitrinite 

reflectance (approximate onset of oil 

generation) or greater (Johnsson and 

Howell, 1996). 

Modest oil and gas shows and gas “wetness” 

values of 30% to 95% (lower panel, pl. 4) 

were noted below 15,450 feet bkb (most 

prominent from 15,700 to 16,740 ft bkb) in 

the North Aleutian Shelf COST 1 well. 

These shows and the high gas wetness 

values may signal the presence of migrated 

liquid petroleum. It is therefore important to 

determine the source of these liquid 

hydrocarbons. Were they generated by 

Type III organic matter like that dominating 

the Tertiary rocks penetrated by the COST 

well? Or, are these minor petroleum liquids 

evidence for unseen oil sources within 

Mesozoic rocks beneath the North Aleutian 

basin? 

To try to identify the source of the liquid 

 27
hydrocarbons below 15,450 ft in the COST 

well, we conducted extraction and 

biomarker studies on “show interval” 

samples borrowed from the State of Alaska 

archive in Eagle River, Alaska. 

Hydrocarbons were extracted from two 

composites of show interval samples20 by 

Baseline DGSI and analyzed for carbon 

isotopes, metals, and biomarkers (Baseline 

DGSI, 2003; attached as Appendix 3 of this 

report) for comparison to data for regional 

oils and source rocks published by Magoon 

and Anders (1992). The two extractions 

obtained in this study supplement a less 

robust data suite on 7 extractions in the 

show interval in the North Aleutian Shelf 

COST 1 well previously obtained by 

Robertson Research (1983, App. IX; 

attached as Appendix 2 and Appendix 5 of 

this report). Selected extract data are listed 

in table 2. Extract data are shown in figures 

25, 26, 27, 28, and 29, and are selectively 

profiled on depth in plate 4. 

We conclude from the extract data that the 

oil shows in the interval from 15,450 to 

16,800 feet bkb in the North Aleutian Shelf 

COST 1 well originated from nonmarine 

Tertiary rocks rather than marine Mesozoic 

rocks. This interpretation extends from the 

following observations: 

1. Low Sulfur Content Suggests 

Tertiary Sources. The sulfur 

contents of Mesozoic-sourced oils in 

the Cook Inlet range from 0.04% to 

0.23% (average 0.11%) while those 

from the Alaska Peninsula oil seeps 

(from Middle Jurassic rocks) range 

 

20 One sample composite was collected from 

conventional core chips every foot: cores 18 and 19, 

16006-16720 ft bkb overall. A second sample 

composite was collected from cuttings, 10-ft 

intervals, 15,700-16,800 ft bkb. At the time the 

interval from 15,700 to 16,800 feet was drilled, the 

well was open below 9-5/8 inch casing set at 13,287 

ft bkb (Turner et al., 1988, p. 7).

from 0.20% to 0.21%. Sulfur 

contents for Tertiary-sourced 

condensates in Cook Inlet range 

from 0.03% to 0.05%, much lower 

than the Mesozoic oils (all data from 

Magoon and Anders, 1992, tbl. 

13.1). In two extracts of the show 

interval in the North Aleutian Shelf 

COST 1 well, sulfur levels were 

below the detection limit of 0.01% 

(Baseline DGSI, 2003). The low 

sulfur contents of the COST well 

extracts are consistent with a source 

in nonmarine Tertiary rocks. 

2. Isoprenoid Ratios Are Terrestrial. 

Cross-plots for ratios of pristane/nC17 versus phytane/n-C18, as shown 

in figure 25, indicate a terrigenous, 

oxidizing source environment (i.e., 

Tertiary rocks) for the COST well 

extracts, rather than a marine source 

(i.e., Mesozoic rocks). 

3. Pristane/Phytane Ratios are 

Terrestrial. Pristane/phytane ratios 

range from 2.14 to 9.30 for the 9 

extracts in the show interval in the 

North Aleutian Shelf COST 1 well, 

as summarized in the histograms in 

figure 26. For Tertiary extracts and 

oils in Cook Inlet basin, 

pristane/phytane ratios similarly 

range from 2.5 to 10.0 (Magoon and 

Anders, 1992, tbl. 13.1). For 

Mesozoic (marine) oils and extracts, 

pristane/phytane ratios range 

narrowly from 2.7 to 4.0; for Alaska 

Peninsula oil seeps the range is from 

1.5 to 1.7 (Magoon and Anders, 

1992, tbl. 13.1). The 

pristane/phytane ratios of the North 

Aleutian Shelf COST 1 well extracts 

are ranged in a manner most similar 

to the range for Tertiary rocks and 

oils of Cook Inlet basin. 

 28
4. Carbon Isotopes Correlate to 

Nonmarine Tertiary. Carbon isotope 

data for saturate and aromatic 

fractions of extracts from the oil 

show interval in the COST well 

group decisively with similar data 

for nonmarine Tertiary rocks and 

Tertiary-sourced condensates of 

northern Cook Inlet (fig. 27). The 

North Aleutian extracts are distinctly 

“heavier” (enriched in C13) than all 

of the Mesozoic (marine) rocks and 

oils, including the oil seeps on the 

Alaska Peninsula. 

5. Deficit of Saturates Correlates to 

Tertiary Extracts. Ratios among 

saturates, aromatics, and nonhydrocarbons for 9 extracts from the 

show interval in the North Aleutian 

Shelf COST 1 well, shown in figure 

28a, are highly deficient in saturates 

relative to Mesozoic rocks and oils. 

Although highly variable as a group, 

the North Aleutian extracts are 

mostly saturate-deficient like the 

extracts of Tertiary rocks from Cook 

Inlet. The North Aleutian cuttings 

sample extract (MMSAK2003-2) 

forms an exception. It is relatively 

saturate-rich and plots very close to a 

Tertiary-sourced condensate from 

Cook Inlet in figure 28a. 

In addition, C30 steranes are absent, C29 

steroids slightly predominate (C29:C28:C27 

= 43.6:22.5:33.0 [MMSAK2003-1] and 

47.7:23.4:29.9 [MMSAK2003-2]), oleanane 

is present (oleonane/hopane= 0.22-0.29), 

and the carbon preference index (Bray and 

Evans, CPI24-34)

21 is greater than 1.0 (CPI = 

 

 

21 Baseline DGSI (2003) calculate an “OEP” (oddeven preference) which ranges from 1.10 to 1.22. 

Another index reported by Baseline DGSI, CPIMarzi, 

ranges from 1.03 to 1.07 (see Marzi et al., 1993). 

1.078-1.160). The absence of C30 steranes 

is consistent with terrestrial source (Peters 

and Moldowan, 1993, tbl. 3.1.5). Sterane 

ratios, plotted in the ternary diagram of 

figure 28b, suggest mixing of marine and 

nonmarine depositional environments in the 

source sequence. Oleananes are generally 

associated with Late Cretaceous or Tertiary 

angiosperms (flowering plants) (Waples and 

Machihara, 1991, p. 54) and are not found in 

older rocks. Unless swept up in the course 

of migration through Tertiary rocks, their 

presence in these extracts seems to preclude 

origination from Jurassic- or Triassic-aged 

sources. 

Magoon and Anders (1992) and Magoon 

(1994) have noted that extracts from Upper 

Triassic potential oil source rocks exposed at 

Puale Bay (fig. 2) are enriched in C19 to 

C29 tricyclic terpanes relative to extracts 

from Middle Jurassic or Tertiary rocks. 

Some oils collected from wells and seeps in 

southern Cook Inlet (Magoon and Anders, 

1992, spls. 37-43) are also enriched in 

tricyclics relative to oils in northern Cook 

Inlet, and Magoon (1994) suggests that the 

high tricyclics indicate some contribution 

from Upper Triassic oil sources (mixed with 

the more typical Middle Jurassic Tuxedni 

Gp. oils). In the more general case, Clayton 

(1993, tbls. 1, 2) notes that tricyclic terpanes 

are rarely abundant in oils derived from coal 

or coaly organic matter. If tricyclic 

terpanes are present in the COST well 

extracts, it may imply origination from 

Upper Triassic rocks beneath North Aleutian 

basin. 

Figure 29a is an excerpt from an M/Z 19122

22 M/Z, or M/e, is the mass/charge ratio of ions 

fragmented by an electron beam in the GCMS device. 

M/Z controls how ions are separated, displaced, and 

sequentially detected through manipulation by the 

magnetic field of the mass spectrometer (Waples and 

Machihara, 1991, p. 11-12). M/Z 191 is most 

appropriate for obtaining the quantities of tricyclic 

 29
chromatogram for terpanes from an extract 

from core samples from 16,006 to 16,720 

feet in the North Aleutian Shelf COST 1 

well. Figure 29b shows the entire M/Z 191 

chromatogram for the extract from cuttings

over the interval 15,700 to 16,800 ft bkb. 

Both chromatograms show that tricyclic 

terpanes are abundant in the show interval 

extracts, although subordinate to hopanes 

(tricyclic terpanes/hopanes = 0.56 to 0.80). 

The presence of these tricyclic terpanes in 

the COST well extracts could suggest a link 

to Upper Triassic source rocks beneath the 

North Aleutian basin. But, a wide spectrum 

of depositional environments is associated 

with suites of tricyclic terpanes. Crude oils 

derived from paralic/deltaic (nearshore 

marine), deep water marine, lacustrine, and 

“phosphatic” environments all feature robust 

suites of tricyclics (Zumberge, 1987, tbl. 5). 

Tricyclics have been specifically linked to 

Mesozoic lacustrine sources (Waples and 

Machihara, 1991, p. 58). A condensate from 

the North Cook Inlet gas field, sourced from 

Tertiary nonmarine rocks, resembles the 

COST well extracts in that it is rich in C19 

and C20 tricyclic terpanes (Magoon and 

Anders, 1992, fig. 13.9, spl. 18), the latter 

linked to vascular land plants (Zumberge, 

1987, p. 1630). Figure 29b shows a strong 

unidentified peak between the C19 and C20 

tricyclic terpanes; a similar unidentified 

peak is also present in the North Cook Inlet 

field condensate (and reportedly other 

northern Cook Inlet condensates) sourced 

from Tertiary nonmarine rocks (Magoon and 

Anders, 1992, fig. 13.9, spl. 18; p. 264, 

268). 

These tricyclic terpanes might point to the 

existence of effective source rocks within 

the Mesozoic substrate beneath the part of 

 

and pentacyclic terpanes because it is the most 

abundant ion obtained by fragmentation of these 

compounds in an electron beam. 

the North Aleutian basin north of the 

projected trace of the Bruin Bay fault (fig. 

32). However, several lines of logic indicate 

that the probability of effective Mesozoic 

sources, particularly Triassic sources, in this 

area is low. 

Both published tectonic models for the 

“Peninsular terrane” (Mesozoic strata 

southeast of the Bruin Bay fault) tie it to the 

Jurassic-Cretaceous magmatic arc 

(magmatic arc terrane north of Bruin Bay 

fault), but in two different ways. Moore and 

Connelly (1979) locate the Mesozoic 

sedimentary rocks in a fore-arc basin

between the magmatic arc on the northwest 

and a subduction zone on the southeast. In 

an alternative model, Reed et al. (1983) 

locate the Mesozoic sedimentary rocks in a 

back-arc basin southeast of both the 

magmatic arc and subduction zone to the 

northwest. In either case, the Mesozoic 

sedimentary rocks would not be expected to 

extend in quantity northwest of the 

magmatic arc and beneath the North 

Aleutian basin. Both models presumably 

include the Triassic rocks, which contain 

abundant volcanic material of arc origins 

(Wang et al., 1988). 

These tectonic models are disputed by 

geologic mapping that locates some Triassic 

sedimentary rocks in the magmatic arc 

terrane north of the Bruin Bay fault and 

“Peninsular terrane.” Carbonates of the 

Upper Triassic Kamishak Formation are 

exposed at a few localities among the vast 

Jurassic-Cretaceous plutons north of the 

Bruin Bay fault in the Cook Inlet area 

(Magoon et al., 1976, sh. 2) and near 

Becharof Lake (Riehle et al., 1993). 

However, even if the Upper Triassic rocks 

extend northwest of the Bruin Bay fault into 

the magmatic arc terrane, there is some 

question about their survival as effective 

 30
potential source rocks. Independent 

evidence points to a dominantly magmatic 

character for the Mesozoic substrate north of 

the Bruin Bay fault beneath the Bristol Bay 

lowlands and North Aleutian basin. We 

consider it unlikely that significant 

quantities of effective Triassic oil source 

rocks survive among the numerous 

magmatic intrusions inferred from regional 

context and magnetic data in the Mesozoic 

substrate north of the projected Bruin Bay 

fault (Case et al., 1988). Geologic mapping 

northwest of Cook Inlet indicates that bodies 

of Upper Triassic rocks are small, scattered, 

and isolated amid very large intrusives of 

Jurassic, Cretaceous, and Tertiary ages 

(Magoon et al., 1976, sh. 2; Riehle et al., 

1993). The Upper Triassic and Jurassic 

sedimentary rocks among the intrusives are 

thermally overmature at the surface, ranging 

from 1.3% vitrinite reflectance (end of oil 

generation) to >5.0% (metamorphic) at all 

mapped data sites (Johnsson and Howell, 

1996). Presumably, this thermal maturation 

was achieved in Mesozoic time in concert 

with pluton emplacement, before the 

formation of the North Aleutian basin. 

Lastly, a host of other geochemical data, 

reviewed above, seems to link the extracts to 

Type III organic matter of Late Cretaceous 

or Tertiary age. Regional geology and 

geochemical data, taken as a whole, most 

persuasively argue for a source within 

Tertiary nonmarine rocks for the sparse 

petroleum liquids encountered in the deep 

part of the COST well. 

Petroleum System—Critical Events 

A “Lopatin”-style (Lopatin, 1971) burial 

history model for the North Aleutian Shelf 

COST 1 well23 is shown in figure 30 along 

with some timelines for critical events in the 

hypothetical petroleum system for the 

offshore part of the North Aleutian basin. 

Vitrinite reflectance data from the COST 

well indicate that the lower part of the rock 

column has experienced sufficient thermal 

exposure24 to have generated oil and gas. 

But, these data give no information about 

when petroleum generation might have 

occurred. The Lopatin burial model 

combines burial history with thermal 

environment to measure thermal exposure 

using established thermo-chemical 

principles. The purpose of creating a 

Lopatin model for the COST well was to 

obtain estimates for the times of onset and 

duration of key phases of petroleum 

generation. The time of petroleum 

generation can then be compared to the time 

of trap formation to ascertain whether traps 

were available to capture petroleum 

migrating upward from generation centers. 

For example, if petroleum generation 

occurred prior to trap formation, the 

petroleum may have simply escaped to the 

surface and been lost. 

The Lopatin burial model in figure 30

highlights the thermal evolution of the 

sequence penetrated by the well and an 

additional 3,000 feet of unknown strata 

interpreted (from seismic data) to lie beneath 

the bottom of the COST well. These latter 

rocks comprise the most deeply buried strata 

in the basin and presumably offer the 

earliest opportunity for generation of 

petroleum. 

Tolstoi Formation strata that are probably 

correlative to the unknown sequence 

 

23 Used software “Lopatin-From Here to Maturity”, 

version 1.0, copyright 1985, by Platte River 

Associates, Inc. and Douglas W. Waples. 

24 Temperatures experienced and residence time at 

maximum temperatures. 

 31
beneath the COST well are described in 

surface geologic mapping onshore. There, 

the lower Tolstoi Formation consists of 

nonmarine and shallow marine sandstones 

and conglomerates with subordinate 

siltstone, shale, and coal (Detterman et al., 

1996, p. 38-42). These rocks are much the 

same as the part of the Tolstoi Formation 

that was penetrated by the COST well (fig. 

9). The latter rocks are dominated by coaly, 

Type III organic matter and are most 

probably sources for gas and wet gas. 

Geological mapping (Wilson et al., 1995; 

Detterman et al., 1996) documents a 

widespread unconformity at the base of the 

Tolstoi Formation where it rests upon 

Cretaceous rocks in the Port Moller area. 

The Tolstoi Formation rocks that overlie this 

regional unconformity range in possible age 

from middle Eocene to late Paleocene 

(Detterman et al., 1996, p. 39-42). The 

offshore COST well reached total depth 

within lower to middle Eocene rocks (fig. 

9). From stratigraphic relations onshore, we 

infer that the untested strata beneath the 

bottom of the COST well overlie Mesozoic 

rocks on a Late Paleocene unconformity. 

This unconformity probably marks the onset 

of subsidence of the North Aleutian basin 

and forms the starting point for the Lopatin 

burial model. We model the untested strata 

beneath the COST well as Tolstoiequivalent rocks that range up to 61 Ma in 

age (base of Late Paleocene). 

Initial basin subsidence was rift-driven and 

was accompanied by large-scale faulting and 

the elevation of horsts in the southwest half 

of the North Aleutian basin. The rift-driven 

phase of basin subsidence was concluded by 

the time of seismic horizon “D” (35.4 Ma), 

which corresponds to the regional 

unconformity that decapitates the basement 

horsts in the southwest half of the North 

Aleutian basin (fig. 6). 

The later phase of basin subsidence was 

mostly unaccompanied by faulting, with 

some reactivation of horst-bounding faults. 

This phase of subsidence was more 

regionally extensive than the rift phase and 

may have been both thermally-driven 

(cooling following the rift phase) and loaddriven (as a foredeep bending downward to 

the south beneath tectonically-thickened 

crust on the south margin of the basin [Bond 

et al., 1988]). 

In figure 30, the rocks at the bottom of the 

North Aleutian Shelf COST 1 well are 

shown to enter the early oil generation zone 

(TTI>3) at about 31.7 Ma. The base of the 

well entered the peak oil generation zone 

(TTI>10) at 27.0 Ma. 

The thermal maturation of the basin floor 

strata beneath the bottom of the COST well 

represents the earliest opportunity for 

generation of petroleum in the North 

Aleutian basin. This deeper package of 

strata would have entered the early oil 

generation window (TTI>3) as early as 38.5 

Ma and the peak oil generation zone 

(TTI>10) at 34.4 Ma. Oil and gas 

generation from shallower strata with 

appropriate organic compositions has 

presumably taken place with progressive 

burial since 38.5 Ma, continuing to the 

present time. 

The erosionally–truncated crests of the 

basement horsts were buried beneath the 

thick shaly sequence of the lower part of the 

Stepovak Formation (lower contact, seismic 

horizon “D”) at approximately 35.4 Ma, 

thereby sealing the deeper traps on horst 

flanks. The underlying strata that onlap the 

faulted flanks of the horsts were deposited 

between 61 Ma and 35.4 Ma, mostly before 

the earliest onset of hypothetical oil 

generation from basin floor strata at 38.5 

 32
Ma. Traps associated with faults and 

stratigraphic onlap on the flanks of these 

basement horsts were mostly available to 

capture petroleum generated in flanking 

basin deeps after 38.5 Ma. 

Deposition of the principal reservoir—the 

Bear Lake-Stepovak play sequence—began 

about 28.5 Ma and continued up to about 4.5 

Ma. The compaction-driven doming of 

drape anticlines over basement horsts 

continued through the time interval of Bear 

Lake-Stepovak deposition, as indicated by 

the thickening of strata into the grabens 

flanking horsts (illustrated in fig. 6 and pl. 

1). 

Oil and gas generated between 28.5 and 38.5 

Ma preceded the formation of the drape 

anticlines in the Bear Lake-Stepovak 

sequence over basement horsts. Some earlyformed generation products may have 

preceded drape anticline formation and 

escaped to the surface unless sequestered in 

older traps along horst flanks. But, the early 

fraction of the total generated product may 

have been relatively small. Sometime 

between 21.2 Ma (vitrinite reflectance 

data25) and 27.0 Ma (Lopatin model), basinfloor strata reached peak oil generation 

(Ro=1.00%; TTI=75), corresponding to the 

stage when petroleum is most abundantly 

created (Dow, 1977a, fig. 3; Baskin, 1997, 

tbl. 1). At this time, the lower part of the 

Bear Lake-Stepovak sequence and 

 

 

25 In figure 30 a dashed black line for the Ro=1.00% 

isograd has been added and is shown intersecting the 

basin floor at 21.2 Ma. This isograd is not a product 

of the model but was constructed parallel to modelbased TTI isograds and hand-sketched back through 

time from the actual well penetration of the 1.00% Ro 

isograd based on vitrinite reflectance data. This was 

done to obtain an alternative estimate for the time 

when basin floor strata achieved peak oil generation 

(Ro=1.00%). The Lopatin model forecasts for 

thermal maturity below 15,000 ft bkb in the COST 

well do not conform with vitrinite reflectance data 

and are not considered reliable. 

associated traps were certainly in place to 

capture migrating petroleum. Given 

appropriate organic compositions within the 

lower part of the North Aleutian basin fill, 

the timing of hypothetical petroleum 

generation is mostly appropriate for 

charging of the Bear Lake-Stepovak 

reservoirs in the 28.5-4.5 Ma drape 

anticlines over horsts. 

The “amorphous” interval in the COST well 

(discussed above26), of past interest because 

of the presence of putative amorphous (i.e., 

oil prone) kerogens, oil shows, and elevated 

gas wetness (pl. 4), corresponds 

approximately to the interval from 15,620 ft 

bkb (top of fault gap in fig. 30) to total 

depth. The top of the “amorphous” interval 

entered the early oil generation window 

(TTI>3) at 26.4 Ma and entered the peak oil 

generation zone (TTI>10) at 20.4 Ma. Any 

hydrocarbons generated out of the 

“amorphous” interval therefore could have 

charged some of the shallow drape anticlines 

involving the Bear Lake-Stepovak play 

sequence reservoirs over basement horsts. 

The timing of hypothetical petroleum 

generation is favorable for preservation of 

porosity in the principal reservoir, the Bear 

Lake-Stepovak play sequence. As noted, 

hydrocarbon generation could have begun at 

the basin floor sometime between 38.5 Ma 

and 34.4 Ma, and ostensibly reached peak 

oil generation (Ro=1.00%; TTI=75) between 

21.2 and 27.0 Ma (fig. 30). The 

hypothetical oil and gas forming near the 

basin floor therefore could have invaded the 

Bear Lake-Stepovak sandstones shortly after 

deposition. Early entry of hydrocarbons into 

the pore systems of the Bear Lake-Stepovak 

26 The review of source rock geochemical data in this 

report discounts the “amorphous” interval as a 

potential oil source. It is viewed as a potential 

source for gas or wet gas, but is no more promising 

than other sequences penetrated by the COST well. 

 33
sandstones within traps could have arrested 

the diagenetic processes that act to destroy 

porosity. We note that the Bear LakeStepovak sandstones in the COST well were 

not associated with any oil or gas shows, but 

nonetheless preserve excellent porosity and 

permeability (figs. 15 and 16). 

In contrast, the older Tolstoi play sequence 

resided at significant burial depths for up to 

22.5 m.y. (61 Ma minus 38.5 Ma=22.5) 

before any petroleum could have been 

generated out of basin-floor strata. This 

protracted opportunity for diagenetic 

destruction of pore space27 may partly 

explain the overall poor reservoir quality of 

the Tolstoi sandstones below 10,380 ft bkb 

in the COST well. 

The TTI isograd depths forecast by the 

Lopatin model conform reasonably well to 

vitrinite reflectance-based isograd depths in 

the part of the COST well above 13,000 ft 

bkb. Specifically, vitrinite reflectance data 

indicate that isograd Ro=0.5% (threshold for 

early oil generation) is reached at 10,372 ft 

bkb. The Lopatin model forecasts the 

equivalent TTI=3 isograd to lie 223 ft 

shallower, at 10,213 ft bkb. Vitrinite 

reflectance data indicate that isograd 

Ro=0.6% (threshold for peak oil generation) 

is reached at 12,397 ft bkb. The Lopatin 

model forecasts the equivalent TTI=10 

isograd to lie 337 ft shallower, at 12,060 ft 

bkb. The depths of these isograds are 

compared in the right-hand columns of 

figure 30. 

The isograd depths forecast by the Lopatin 

model do not conform to vitrinite 

reflectance-based isograd depths in the part 

of the COST well below 15,000 ft bkb. 

 27Mostly by pore-filling chemical cements, and, 

replacement of volcanic clasts by clays leading to 

collapse of clasts, as observed in petrographic 

microscopy (AGAT, 1983, p.2).

Generally, the Lopatin maturity values at a 

given depth are higher than the observed 

vitrinite-reflectance-based maturity values. 

For example, the observed vitrinite 

reflectance at modeled well total depth 

(17,802 ft bkb, 647 ft added for fault gap28) 

is 1.097% (fig. 17) and the appropriate 

corresponding TTI value is 98 (Waples, 

1980, tbl. 4). At the same depth, the Lopatin 

model for the COST well overestimates a 

TTI value of 576 (equivalent to 1.80% Ro; 

Waples, 1980, tbl. 4). 

Generally, the model-to-data discrepancies 

(between the Lopatin model forecasts for 

thermal maturities and vitrinite-reflectancebased thermal maturities) in the COST well 

increase with depth. The Lopatin isograd 

TTI=75 is forecast to lie at 15,141 feet bkb. 

The isograd TTI=75 normally corresponds 

to a vitrinite reflectance of 1.00% or peakoil generation (Waples, 1980, tbl. 4), but the 

observed vitrinite reflectance at 15,141 ft in 

the COST well is only 0.768%. A vitrinite 

reflectance of 1.00% is not achieved until a 

depth of 17,160 ft, or 2,019 ft deeper than 

the Lopatin model forecast (for TTI=75). 

Likewise, the oil-generation-floor isograd 

TTI=180, forecast at 16,479 ft bkb by the 

Lopatin model, is 2,772 ft shallower than the 

equivalent vitrinite reflectance isograd 

(Ro=1.35%) forecast (below the data set) at 

19,251 ft bkb. The large discrepancies 

between the depths of Lopatin isograds and 

vitrinite reflectance isograds are illustrated 

in the right-hand columns of figure 30. 

The model-to-data discrepancies below 

15,000 ft bkb are too large and result in 

erroneously high (early) Lopatin-model 

estimates for the onset ages of peak oil 

generation (TTI=75), the oil generation floor 

28 The base of the well for modeling purposes is 

“corrected” or extended down to 17,802 ft bkb to 

account for the 647 ft gap at the normal fault 

penetrated at 15,620 ft bkb. 

 34
(TTI=180), peak wet gas generation 

(TTI=92), and the floor for survival of 

liquids (TTI=900). The onset ages forecast 

by this high-TTI part of the Lopatin model 

are only useful as maximum ages.29 

In an effort to construct a Lopatin model that 

better conforms to observational data, we 

experimented with two variations on the 

basic model shown and tabulated in figure 

30. For the first variation, we retained the 

geothermal model (modern gradients) but 

added time gaps at regional unconformities. 

For the second variation, we retained the 

stratigraphic model (without time gaps) but 

reduced the geothermal gradient. 

As the first variation to our Lopatin model, 

we inserted arbitrary time gaps at the 

regional unconformities marked by seismic 

horizons A, B, C, and D (3 m.y., 3 m.y., 3 

m.y., and 5 m.y., respectively). These time 

gaps are arbitrary because the paleontologic 

data do not resolve any quantifiable time 

gaps at these surfaces in the COST well (fig. 

9), nor do we observe erosional truncation 

effects at these surfaces in the graben area 

near the well. The addition of these time 

gaps (hiatuses) to the basic stratigraphic 

model produced the general effect of 

moving TTI isograds to even shallower 

depths. Therefore, adding time gaps to the 

stratigraphic model increased the 

discrepancies between Lopatin model 

forecasts and vitrinite reflectance data from 

the well. This first variation on the Lopatin 

model degraded model-to-data conformance 

and was discarded. 

 

 

29 The principal product generated in the high-TTI 

part of the Lopatin burial model is gas. Actual gasgeneration thresholds were probably achieved much 

more recently than the times indicated by the Lopatin 

burial model in figure 30. Because gas is more likely 

to breach trap seals with time, a late (i.e., very 

recent) gas-charge charge history is probably helpful 

to overall trap success.

As the second variation on our Lopatin 

model, we used the basic stratigraphic 

model of figure 30 but reduced the 

geothermal gradient for the entire well to 

14.0oF/1,000 ft, held constant through time. 

As shown in plate 4 and figure 30, the 

COST well temperature data describe a 

three-leg set of gradients ranging from 

16.7oF to 18.3oF per 1,000 ft. The 

substitution of a lower geothermal gradient 

of 14.0oF/1,000 ft produced better model-todata conformance for TTI values of 75 and 

higher, but substantially decreased the 

model-to-data conformance for the critical 

oil-generation-onset TTI isograds less than 

75. This second variation on the Lopatin 

model was also discarded. 

The results of the second variation on our 

Lopatin model suggest that a better fit might 

be achieved by assuming a low geothermal 

gradient for the deeper (and older) part of 

the well and a high geothermal gradient (like 

that observed) in the shallow part of the 

well. This would retain the good model-todata conformance in the shallow part of the 

well and move TTI isograds to greater 

depths (and better conformance to data) in 

the deep parts of the well. In fact, some 

experimentation revealed that an early (preseismic horizon “D”) geothermal gradient of 

10oF/1,000 ft could produce reasonably 

good model-to-data conformance in the deep 

part of the well. However, this (10oF/1,000 

ft) is an extremely low geothermal 

gradient.30 Even more troubling, this twopart geothermal model implies that the early 

history of the North Aleutian basin was 

characterized by a relatively low geothermal 

gradient that was later replaced by the 

higher gradients observed today. This is the 

opposite of what we might expect 

30 Cook Inlet basin, a relatively “cold” forearc basin, 

has geothermal gradients ranging from 12oF to 16oF 

per 1,000 ft depending on proximity to the modern 

volcanic arc (Magoon, 1986, fig. 20, p.45). 

 35
considering the early rift history of the 

North Aleutian basin. Rifting is usually 

accompanied by elevated geothermal 

gradients (Dewey and Bird, 1970; Falvey, 

1974; McKenzie, 1978; White and 

McKenzie, 1988; Bond and Kominz, 1988), 

above the “world average” of 13.7oF/1,000 

ft (25oC/km) and ranging up to 42oF/1,000 

ft (77oC/km or higher) (Lee and Uyeda, 

1965; Tissot and Welte, 1984, p. 296). At 

the conclusion of rifting, the crust cools and 

subsides, producing a shift to a lower 

geothermal gradient. To invoke an 

uncommonly low geothermal gradient 

during a rift event, followed by warming and 

a higher geothermal gradient, contradicts 

generally-accepted tectonic-thermal models 

for rift basins. 

In the end, we were unable to devise a 

Lopatin model for the COST well that uses 

available geothermal and stratigraphic data, 

that produces a good fit at all depths to the 

observational data, and that is rational in the 

tectonic context of the well. 

Despite the flaws in the high-TTI Lopatin 

model forecasts, the model did produce lowTTI forecasts that are vindicated by vitrinite 

reflectance data in the shallower parts of the 

COST well. Therefore, we believe that the 

Lopatin model of figure 30 provides useful 

insights into the timing of the earliest phases 

of thermal maturation and potential 

hydrocarbon generation in the area of the 

COST well. And here, amid the most 

important prospects in the North Aleutian 

basin, the Lopatin model indicates that, 

given appropriate organic compositions, 

hydrocarbon generation deep in the basin 

could have preceded and accompanied the 

formation of key reservoirs and traps,. 

Vitrinite reflectance data and Lopatin 

modeling both indicate that about 10,500 ft 

of strata in the lower part of the North 

Aleutian basin are within or have passed 

through the oil generation window 

(Ro=0.5% to 1.35%). Significant quantities 

of gas may also have been generated out of 

the coaly, Type III organic matter as the host 

strata passed through the thermal maturity 

window for oil generation (Boreham and 

Powell, 1993, p. 149-150). Vitrinite 

reflectance data indicate that over 5,100 ft of 

strata have passed into the wet gas 

generation window for mixed kerogens 

(Ro>0.8%). Vitrinite reflectance data 

indicate that over 3,300 ft of strata in the 

lower part of the basin have passed into the 

thermal maturity window for generation of 

dry gas from coaly/Type III organic matter 

(Ro>1.07%). Clearly, a large volume of 

rocks have experienced thermal exposures 

sufficient for significant petroleum 

generation in the lower part of the basin. 

The Lopatin model shows that the most 

attractive reservoirs and traps existed and 

were available to capture oil and gas at the 

time of most prolific oil and gas generation.

 36
Petroleum System Elements and Oil and Gas Plays in North Aleutian Basin 

OCS Planning Area 

Key Elements of Petroleum System

The major elements of the petroleum 

systems hypothesized for the North Aleutian 

Basin OCS Planning Area are illustrated in a 

schematic cross section in figure 31a. For 

the main part of the North Aleutian basin, 

traps are hypothesized to be charged by gas, 

condensate, and oil originating from deeply 

buried, gas-prone source rocks of Tertiary 

age. For the southwest part of the Planning 

Area, which is underlain by possibly oilprone Mesozoic rocks, traps in Mesozoic 

sandstones are hypothesized to be charged 

by original oil migration from Mesozoic oil 

source rocks. Traps in Tertiary sandstones 

overlying oil-prone Mesozoic rocks are 

hypothesized to be charged by re-migration 

of oil out of disrupted Mesozoic reservoirs. 

The hypothetical petroleum system 

responsible for the majority of potential 

undiscovered oil and gas resources in the 

Planning Area is illustrated on the right side 

of figure 31a. Sandstone reservoirs (Bear 

Lake-Stepovak play sequence) within the 

domes draped over basement uplifts are 

charged by petroleum generated in Tertiary 

rocks (Tolstoi play sequence) deeply buried 

in grabens flanking the uplifts. A regional 

shale seal (lower part of Stepovak Fm.; fig. 

10 and pl. 3) floors the Bear Lake-Stepovak 

reservoir sequence and is pierced by horstbounding faults that extend upward into the 

shallow level of the basin fill above seismic 

horizon “D”. These faults may provide the 

critical pathways for petroleum migration 

between the deep oil and gas generation 

centers (“GAS/COND KITCHEN” in fig. 

31a) flanking basement uplifts and the 

shallow traps that overlie the uplifts. Gas 

and oil migrating out of Tertiary rocks in the 

deep grabens may also fill Tolstoi reservoir 

sandstones in traps ringing the faulted flanks 

of basement uplifts. 

The hypothetical petroleum system 

responsible for a minority fraction of 

undiscovered oil resources in the Planning 

Area is illustrated on the left side of figure 

31a. Mesozoic rocks beneath the Black 

Hills uplift reached thermal maturity 

sufficient for oil generation prior to Eocene 

time and may contain oil pools that formed 

in Mesozoic (probably Cretaceous?) time. 

Cenozoic-age faulting may have disrupted 

some of these oil pools and provided 

avenues for re-migration into traps in 

overlying Oligocene-Miocene reservoir 

sandstones of the Bear Lake-Stepovak play 

sequence. Traps in Tertiary reservoirs on 

the Black Hills uplift may also be charged 

by gas and condensate migrating out of 

deeply buried Tertiary strata in North 

Aleutian basin. However, this would 

requires 50+ miles of lateral migration 

through the highly faulted southwest part of 

the North Aleutian basin, with great risk of 

diversion of migrating petroleum up faults 

and loss to surface seeps. 

Play Definition

Plays were separated first on the basis of 

reservoir characteristics, for which the 

stratigraphic sequence serves as proxy. 

Further separations were made on the basis 

of structural setting and hydrocarbon charge 

models (source type [oil vs. gas] and access 

[length and integrity of migration path]). 

The Bear Lake-Stepovak sequence was 

defined so as to capture the main reservoir 

 37
package between seismic horizons “A” and 

“C” (fig. 9 and pl. 2), which is characterized 

by abundant, thick, porous, and permeable 

sandstones. The Bear Lake-Stepovak 

sequence is draped over basement uplifts in 

the southwest part of the North Aleutian 

basin and forms the key exploration play in 

the basin. The Bear Lake-Stepovak play 

sequence can be traced to the Black Hills 

uplift, where it is also draped over basement 

uplifts. But the Black Hills uplift is treated 

as a separate play because it has access to 

hypothetical oil-prone sources in the 

underlying Mesozoic assemblage. The 

Black Hills uplift has limited access (large 

distances across highly faulted areas) to the 

deeply buried gas-prone Tertiary age 

sources that are hypothesized to charge the 

main Bear Lake-Stepovak play. The Tolstoi 

play sequence hosts poor-quality reservoir 

sandstones (thin and impermeable) and is 

involved in flank traps against basement 

uplifts. The Tolstoi sequence is thus set 

apart into a third play. 

A fourth play identifies low-pressure 

biogenic gas resources in shallow PlioPleistocene strata of glacial and marine 

origins. 

The substrate of Mesozoic rocks beneath the 

North Aleutian basin in divided into a 

southern province of deformed sedimentary 

rocks (play 5) and a northern province of 

volcano-plutonic rocks (play 6). The 

Mesozoic deformed sedimentary rocks on 

the south include rocks correlative to 

regional oil sources and are primarily an oil 

play. The volcano-plutonic Mesozoic 

assemblage on the north forms the cores of 

basement uplifts and if properly fractured, 

might form a reservoir for hydrocarbons. 

The schematic structural cross section in 

figure 31b illustrates the organization of the 

six plays and associated trap types. The 6 

plays are described in detail below. 

Play Descriptions, North Aleutian Basin, 

Alaska

Play 1: Bear Lake-Stepovak (OligoceneMiocene)

Play Area: 14,820 square miles 

Play Water Depth Range: 15-300 feet 

Play Depth Range: 2,000-10,000 feet 

Reservoir Thermal Maturity: 0.25%-0.48% vitrinite 

reflectance 

Risked, Mean, Undiscovered, Technically 

Recoverable Resources: 

271 Mmb (oil) + 136 Mmb (gas-condensate) = 406 

Mmb liquids (rounding sums to 406) 

5.473 Tcf (gas) + 0.113 Tcf (solution gas) = 5.586 

Tcf gas 

Pool Rank 1 Mean Conditional Resource: 827 

Mmboe (4.65 Tcfge) 

Play Exploration Chance: 0.1872

Play 1, the “Bear Lake-Stepovak” play, is 

the dominant play in the North Aleutian 

Basin OCS Planning Area, with 61% (1,400 

Mmboe) of the Planning Area energy 

endowment (2,287 Mmboe). Oil and gascondensate liquids form 29% of the 

hydrocarbon energy endowment of play 1. 

The Bear Lake-Stepovak play sequence 

corresponds in the North Aleutian Shelf 

COST 1 well to the lower part of the Milky 

River Formation, all of the Bear Lake 

Formation, and the upper (sandy) part of the 

Stepovak Formation. The play sequence 

ranges in age from late Oligocene through 

early Pliocene (fig. 9 and pl. 2). In onshore 

areas, rocks correlative to play 1 were 

penetrated by 9 wells (David River 1/1A, 

Hoodoo Lake 1, Hoodoo Lake 2, Sandy 

River 1, Port Heiden 1, Ugashik 1, Becharof 

Lake 1, Great Basins 1, and Great Basins 2 

wells). Offshore, in eastern St. George 

basin, correlative rocks were penetrated by 

the St. George Basin COST 2, Monkshood 

1, and Bertha 1 wells. The principal point of 

offshore control is the North Aleutian Shelf 

COST 1 stratigraphic information test well 

 38
that was drilled by an industry consortium in 

1983. The area of play 1 is shown in figure 

32. 

No pools of oil or gas were encountered in 

any wells penetrating the Bear LakeStepovak sequence in the North Aleutian 

basin. Minor gas shows are associated with 

coals in the Bear Lake-Stepovak sequence in 

the North Aleutian Shelf COST 1 well and 

in most wells onshore. In the Becharof Lake 

1 well, cuttings headspace gas carbon 

isotopes (AOGCC, 1985) for the Bear Lake 

and Stepovak Formations range from -19.5 

to -65.4 (δ13C [PDB]), indicating mixed 

thermogenic and biogenic gas (fig. 24). No 

shows of oil were noted within the Bear 

Lake-Stepovak play sequence in the North 

Aleutian Shelf COST 1 well. Oil shows 

were noted in the play sequence in the 

Becharof Lake 1, Sandy River 1, and David 

River 1/1A wells. Flow tests in the Bear 

Lake-Stepovak sequence in the Sandy River 

1 well recovered gas-cut drilling mud and 

formation waters. 

Most of the oil and gas resources of play 1 

are associated with Oligocene- to Mioceneage sandstones in simple domes draped over 

basement uplifts, as illustrated schematically 

in figure 31b (and in the seismic panel in fig. 

6 and pl. 1). Mapped domes range up to 

93,000 acres in closure areas. Thick 

(maximum = 277 ft), highly porous reservoir 

sandstones sum to 3,305 feet in the North 

Aleutian Shelf COST 1 well—comprising 

61 percent of the 5,390 ft-thick Bear LakeStepovak play sequence (figs. 11-16). No 

oil source formation has been identified in 

the North Aleutian basin but coals and 

shales with Type III (coal-like) organic 

matter are abundant and could form sources 

for both biogenic and thermogenic gas, 

condensate, and perhaps minor oil (fig. 21). 

For this reason, play 1 is modeled as gasprone. Oil shows were encountered in the 

interval from 15,300 to 16,800 feet 

(corresponds to 0.78% to 1.04% Ro) in the 

North Aleutian Shelf COST 1 well. Carbon 

isotopes on extracts from the show interval 

correlate to extracts and oils from Tertiaryage rocks in northern Cook Inlet as opposed 

to extracts and oils from known Mesozoicage oil source rocks on the Alaska Peninsula 

and beneath Cook Inlet (fig. 27). These data 

suggest that Mesozoic oil source beds do not 

underlie North Aleutian basin in the area of 

play 1. This interpretation is supported by 

magnetic intensity data (fig. 7) that suggest 

that play 1 is underlain by a substrate of 

Mesozoic volcano-plutonic rocks. The 

hypothesized petroleum system for play 1 

assumes that gas and minor liquids migrate 

out of Tertiary rocks in the deep parts of 

North Aleutian basin and rise along faults 

bounding basement uplifts to charge shallow 

reservoir beds draped over uplifts. 

Three major risk factors for play 1 relate to: 

1) seal (reservoir sequence is very sand-rich 

and is not capped by a regional seal); 2) 

source adequacy (no attractive source 

formation in known Tertiary-age rocks; 

Mesozoic rocks beneath play 1 are 

pervasively invaded by plutons and cannot 

form a source for petroleum); and 3) 

petroleum migration to reservoirs (a 

major seal sequence—bentonitic shales of 

the lower Stepovak Formation—floors the 

reservoir sequence and is only sparsely 

pierced by faults). 

Play 2: Tolstoi (Eocene-Oligocene)

Play Area: 10,890 square miles 

Play Water Depth Range: 15-300 feet 

Play Depth Range: 4,000-20,000 feet 

Reservoir Thermal Maturity: 0.3%-1.65% vitrinite 

reflectance 

Risked, Mean, Undiscovered, Technically 

Recoverable Resources: 

62 Mmb (oil) + 61 Mmb (gas-condensate) = 

 39
123 Mmb liquids

2.476 Tcf (gas) + 0.025 Tcf (solution gas) = 

2.501 Tcf gas 

Pool Rank 1 Mean Conditional Resource: 208 

Mmboe (1.17 Tcfge) 

Play Exploration Chance: 0.1404

Play 2, the “Tolstoi” play, is the second 

most important play in the North Aleutian 

Basin OCS Planning Area, with 25% (568 

Mmboe) of the Planning Area energy 

endowment (2,287 Mmboe). Oil and gascondensate liquids form 22 percent of the 

hydrocarbon energy endowment of play 2. 

The Tolstoi play sequence corresponds in 

the North Aleutian Shelf COST 1 well to the 

lower part of the Stepovak Formation and 

the entire Tolstoi Formation. The play 

sequence ranges in age from early Eocene to 

early Oligocene (fig. 9 and pl. 2). In 

onshore areas, rocks correlative to play 2 

were penetrated by 5 wells (Becharof Lake 

1, Great Basins 1, Great Basins 2, Hoodoo 

Lake 2, and David River 1/1A wells). 

Offshore, in eastern St. George Basin, 

correlative rocks were penetrated by the St. 

George Basin COST 2 well. The North 

Aleutian Shelf COST 1 well is the most 

important point of control for the Tolstoi 

play sequence in the North Aleutian basin. 

The area of play 2 is shown in figure 33. 

Gas is pooled in several Tolstoi Formation 

intervals in the Becharof Lake 1 well, where 

flow tests of separate intervals recovered gas 

at rates ranging from 10 to 50 mcfg/d, or a 

total of 90 mcfg/d for all three zones. In the 

Becharof Lake 1 well, cuttings headspace 

gas carbon isotopes (AOGCC, 1985) for the 

Tolstoi Formation range from -32.8 to -43.9 

(δ13C [PDB]), indicating thermogenic gas 

(fig. 24). Gas was recovered in flow tests 

from two intervals in the Tolstoi Formation 

at rates of 5 to 10 Mcfgpd (with 300-400 

bwpd) in the David River 1/1A well. Gas 

shows were associated with Tolstoi 

Formation coals in the North Aleutian Shelf 

COST 1 well as well as in the 5 Tolstoi 

penetrations onshore. Oil shows were noted 

in the Tolstoi Formation in the North 

Aleutian Shelf COST 1, Becharof Lake 1, 

Hoodoo Lake 2, and David River 1/1A 

wells). 

Most of the oil and gas resources of play 2 

are associated with simple anticlines draped 

over basement uplifts, or, in truncation traps 

(against faults and unconformities) on the 

flanks of basement uplifts, as illustrated in 

figure 31. Mapped traps range up to 53,000 

acres in closure area. The upper part of the 

Tolstoi play sequence (lower part of 

Stepovak Formation) passes over the crests 

of basement uplifts. In the North Aleutian 

Shelf COST 1 well, the upper part of the 

Tolstoi play sequence contains porous and 

permeable sandstones that are sparse (236 

feet net, or 10% of interval) and thin 

(maximum = 43 feet) (figs. 11-16). A 

regional shale seal in the lower part of the 

Stepovak Formation is prominent within the 

upper part of the Tolstoi play sequence (fig. 

9 and pl. 2). The lower part of the Tolstoi 

play sequence is involved in fault- and 

stratigraphic-truncation traps on the flanks 

of basement uplifts. Sandstones are 

abundant in the lower Tolstoi play sequence 

(1,910 feet net, 30% of sequence) in the 

North Aleutian Shelf COST 1 well, but are 

thin-bedded (maximum = 57 feet) and 

impermeable (diagenesis of volcanic 

particles has resulted in collapse of 

framework grains; 84% of core samples 

have <10 md permeability) (figs. 11-16). 

No oil source rock formation has been 

identified in the North Aleutian basin but 

coals and shales with Type III (coal-like) 

organic matter are abundant and could form 

sources for both biogenic and thermogenic 

gas, condensate, and minor oil (fig. 21). For 

this reason, play 2 is modeled as gas-prone. 

Oil shows were encountered in the interval 

 40
from 15,300 to 16,800 feet (corresponds to 

0.78% to 1.04% Ro) in the North Aleutian 

Shelf COST 1 well. Carbon isotopes on 

extracts from the show interval correlate to 

extracts and oils from Tertiary-age rocks in 

northern Cook Inlet as opposed to extracts 

and oils from Mesozoic-age source rocks on 

the Alaska Peninsula and beneath Cook Inlet 

(fig. 27). These data suggest that Mesozoic 

oil source beds do not underlie North 

Aleutian basin in the area of play 2. The 

hypothetical petroleum system for play 2 

assumes that gas and minor liquids 

migrating out of Tertiary rocks in the deep 

parts of North Aleutian basin rise along 

faults bounding basement uplifts to charge 

shallow reservoir beds draped over uplifts or 

truncated on uplift flanks. 

The major risk factors for play 2 relate to: 1) 

reservoir (thin sandstones are porous in the 

upper Tolstoi play sequence but are 

impermeable in the lower Tolstoi play 

sequence); and 2) source adequacy (no 

attractive source formation in known 

Tertiary-age rocks; Mesozoic rocks beneath 

play 2 are pervasively invaded by plutons 

and cannot form a source for petroleum). 

Play 3: Black Hills Uplift-Amak Basin 

(Eocene-Miocene)

Play Area: 6,990 square miles 

Play Water Depth Range: 15-700 feet 

Play Depth Range: 2,000-20,000 feet (mostly 2,000-

5,000 feet) 

Reservoir Thermal Maturity: 0.23%-2.00% (mostly 

0.23%-0.31%) vitrinite reflectance 

Risked, Mean, Undiscovered, Technically 

Recoverable Resources: 

149 Mmb (oil) + 6 Mmb (gas-condensate) = 155 

Mmb liquids 

0.249 Tcf (gas) + 0.063 Tcf (solution gas) = 

0.312 Tcf gas 

Pool Rank 1 Mean Conditional Resource: 378 

Mmboe (2.12 Tcfge) 

Play Exploration Chance: 0.105

Play 3, the “Black Hills Uplift-Amak Basin” 

play, is a subordinate play in the North 

Aleutian Basin OCS Planning Area, with 

9% (210 Mmboe) of the Planning Area 

energy endowment (2,287 Mmboe). Oil and 

gas-condensate liquids form 74% of the 

energy endowment of play 3. 

The Black Hills uplift is a regional arch that 

extends west from the Alaska Peninsula to 

join the shelf-edge uplift that forms the west 

boundary of St. George basin. The Black 

Hills uplift is onlapped by the Tertiary-age 

sedimentary fill of both the North Aleutian 

and Amak basins, but only rocks correlative 

to the Bear Lake-Stepovak sequence of play 

1 crest the top of the uplift. Over the crest, 

the Bear Lake-Stepovak-equivalent 

sequence (fig. 9 and pl. 1) ranges up to 

5,000 feet thick and directly overlies 

moderately deformed Mesozoic sedimentary 

rocks. Rocks of the lower part of the 

Stepovak Formation and the Tolstoi 

Formation are truncated at faults and 

unconformities on the north and south flanks 

of the uplift. No wells have penetrated the 

Tolstoi-equivalent strata in the Amak basin 

south of the Black Hills uplift. In onshore 

areas, rocks correlative to the Bear LakeStepovak play sequence were penetrated by 

9 wells (David River 1/1A, Hoodoo Lake 1, 

Hoodoo Lake 2, Sandy River 1, Port Heiden 

1, Ugashik 1, Becharof Lake 1, Great Basins 

1, and Great Basins 2 wells). Offshore, 

correlative rocks were penetrated at the 

North Aleutian Shelf COST 1 well (North 

Aleutian basin) and at the St. George Basin 

COST 2, Monkshood 1, and Bertha 1 wells 

(St. George basin). The closest point of 

offshore control is the Bertha 1 well, located 

on the crest of the Black Hills uplift. The 

Bear Lake-Stepovak-equivalent sequence at 

the Bertha 1 well is mostly marine and noncoal-bearing, and is a more distal facies than 

the correlative coal-bearing (nonmarine to 

 41
inner neritic; fig. 9 and pl. 2) sequences 

penetrated onshore and at the North Aleutian 

Shelf COST 1 well. The area of play 3 is 

shown in figure 34. 

No pools of oil or gas have been discovered 

in the Bear Lake-Stepovak play sequence or 

correlative rocks of plays 1 and 3. Gas 

shows are widely associated with coals in 

the Bear Lake and Stepovak Formations and 

oil shows have been noted in these 

formations in 3 wells onshore (Becharof 

Lake 1, Sandy River 1, and David River 

1/1A wells). Flow tests recovered gas from 

the Tolstoi Formation in the Becharof Lake 

1 well and oil shows were noted in 4 Tolstoi 

penetrations (North Aleutian Shelf COST 1, 

Becharof Lake 1, Hoodoo Lake 2, and 

David River 1/1A wells). No oil or gas 

shows are associated with the Bear LakeStepovak sequence in the Bertha 1 well, 

located on the Black Hills uplift near the 

west boundary of play 3. 

Most of the oil and gas resources of play 3 

are associated with broad, low-amplitude 

anticlines draped over culminations on the 

Black Hills uplift, as illustrated in figure 31. 

Mapped traps have closure areas ranging up 

to 133,000 acres. Thick (maximum = 220 

feet), highly porous, and plentiful (sum to 

1,706 feet net, or 59% of sequence) 

reservoir sandstones are present in the Bear 

Lake-Stepovak-equivalent sequence in the 

Bertha 1 well. No regional seal caps the 

abundant sandstones in the Bear LakeStepovak-equivalent sequence at the Bertha 

1 well. 

No oil source rocks have been identified in 

the Tertiary sedimentary fill of either the 

North Aleutian or Amak basins. In the 

North Aleutian basin (and presumably the 

Amak basin), coals and shales with Type III 

(coal-like) organic matter are abundant and 

could form sources for both biogenic and 

thermogenic gas, condensate, and minor oil. 

In the southwest part of the North Aleutian 

basin, thousands of feet of Tertiary rocks are 

thermally mature and could generate oil and 

gas, given appropriate organic compositions 

(fig. 19). However, the Amak basin fill 

reaches a maximum thickness of only 

12,500 feet. The depth to the 0.6% vitrinite 

reflectance isograd at the North Aleutian 

Shelf COST 1 well is 12,312 feet subsea 

(figs. 9 and 17). If the depth for this isograd 

at the COST well is extrapolated to Amak 

basin, only about 200 feet of rocks at the 

floor of the Amak basin are forecast to be 

thermally mature and capable of generating 

petroleum (figs. 18 and 19). It is therefore 

unlikely that Amak basin forms a source for 

significant quantities of petroleum. In any 

case, gas and condensate generated in the 

deep parts of either Amak or North Aleutian 

basins must migrate laterally tens of miles 

through areas highly dissected by very 

young strike-slip faults (that follow the 

margins of the Black Hills uplift). Because 

of the risks of losses through long-distance 

lateral migration and diversion at faults, it is 

unlikely that significant quantities of gas and 

condensate generated in the Amak or North 

Aleutian basins would reach traps on the 

Black Hills uplift. 

The Black Hills uplift is underlain by an 

assemblage of folded Mesozoic sedimentary 

rocks that include strata age-equivalent to 

known regional oil source beds of Middle 

Jurassic (Kialagvik Fm. or Tuxedni Gp.) and 

Late Triassic (Kamishak Fm.) ages. The 

Middle Jurassic Tuxedni Group is the source 

for 1.6 billion barrels of original oil reserves 

in northern Cook Inlet (AKDO&G, 2002), 

most of which is pooled in Tertiary-age 

rocks that overlie the Tuxedni Group. The 

Tuxedni-correlative sequence—the 

Kialagvik Formation—is present in the 

Cathedral River 1 well onshore and 

equivocal geochemical anomalies may 

 42
suggest a past role as an oil source (fig. 20). 

In the Cathedral River 1 well, oil shows 

were widely observed in the rocks overlying 

the Kialagvik Formation. The Kialagvik 

Formation is thermally overmature (TAI = 

3.0 to 3.8) and post oil-generative in the 

Cathedral River 1 well (fig. 20). It is 

probable that Mesozoic oil sources in this 

area generated and expelled the oil in a past 

(pre-Tertiary) cycle of deep burial, long 

before the deposition of the Tertiary-age 

rocks flanking or overlapping the Black 

Hills arch. Oil-charging of the Tertiary-age 

rocks in play 3 must therefore rely upon 

capturing oil remobilized out of Mesozoic 

reservoirs where it was sequestered perhaps 

30 million years earlier during Mesozoic 

(Late Cretaceous?) burial and oil generation. 

The hypothetical Mesozoic oil pools within 

the Black Hills uplift must first survive 

uplift, deep erosion, and re-burial beneath 

Oligocene and younger strata. The 

Mesozoic oil pools must remain intact 

during creation of the drape anticlines in 

Tertiary rocks over culminations on the 

Black Hills uplift. Once the drape anticlines 

had formed, fault disruption of the Mesozoic 

pools must then trigger the release of the oil 

sequestered in Mesozoic reservoirs. The 

released oil then migrates upward in some 

(necessarily) focused or non-dispersive 

pattern en route to Tertiary-age reservoir 

sandstones in the drape anticlines. The 

charge model for play 3 prospects is 

dependent upon a long chain of critical 

events and therefore seems likely to fail. 

Two major risk factors for play 3 relate to: 

1) migration (must re-migrate oil from 

underlying disrupted Mesozoic pools or gas 

from distant generation centers in North 

Aleutian or Amak basins, crossing numerous 

young faults); and 2) seal (the reservoir 

sequence over the crest of the Black Hills 

uplift is very sand-rich and is not capped by 

a regional seal). 

Play 4: Milky River Biogenic Gas (PlioPleistocene)

Play Area: 50,710 square miles 

Play Water Depth Range: 15-700 feet 

Play Depth Range: 500-3,000 feet 

Reservoir Thermal Maturity: 0.20%-0.26% vitrinite 

reflectance 

Risked, Mean, Undiscovered, Technically 

Recoverable Resources: 

Biogenic gas in negligible recoverable quantities 

Play Exploration Chance: 0.000

Play 4, the “Milky River Biogenic Gas” 

play, is the most extensive yet least 

prospective play in the North Aleutian Basin 

OCS Planning Area. Play 4 probably 

contains sizable in-place quantities of 

biogenic gas simply because of the vast area 

embraced by the play. However, very little 

of this gas is likely to be recoverable by 

conventional means, and the technically 

recoverable resource endowment is assessed 

as negligible. 

The Milky River play sequence corresponds 

in the North Aleutian Shelf COST 1 well to 

the upper part of the Milky River Formation 

and overlying, unnamed Quaternary 

deposits. The play sequence ranges in age 

from early Pliocene to Holocene (fig. 9 and 

pl. 2). In onshore areas, rocks correlative to 

play 4 were penetrated by 9 wells (David 

River 1/1A, Hoodoo Lake 1, Hoodoo Lake 

2, Sandy River 1, Port Heiden 1, Ugashik 1, 

Becharof Lake 1, Great Basins 1, and Great 

Basins 2 wells). Offshore, in eastern St. 

George basin, correlative rocks were 

penetrated by the St. George Basin COST 2, 

Monkshood 1, and Bertha 1 wells. The 

principal point of offshore control is the 

North Aleutian Shelf COST 1 well that was 

drilled by an industry consortium in 1983. 

The area of play 4 is shown in figure 35. 

No pools of oil or gas were encountered in 

any wells penetrating the Milky River play 

sequence in the North Aleutian basin. 

 43
Minor biogenic gas shows are associated 

with the Milky River sequence in the North 

Aleutian Shelf COST 1 well (Robertson 

Research, 1983, p. 1), several wells onshore, 

and in the Bertha 1 well in the St. George 

basin. In the Becharof Lake 1 well, cuttings 

headspace gas carbon isotopes (AOGCC, 

1985) for the Milky River Formation range 

from -67.9 to -80.2 (δ13C [PDB]), clearly 

indicating gas of largely biogenic origin (fig. 

24). Biogenic gas is primarily a product of 

bacterial fermentation of the organic matter 

buried within sediments (Hunt, 1979, p. 

154). 

In offshore areas, biogenic gas may be 

pooled in features emplaced by large alpine 

glaciers that invaded Bristol Bay from the 

south (Alaska Peninsula) and northeast 

(Alaska Range) during the Pleistocene 

epoch and then retreated during the last 

10,000 years. The legacy of glaciation may 

include drumlins, eskers, and recessional 

moraines. These elevated landforms are 

gravelly, porous features that were later 

drowned in rising sea waters and are now 

draped and perhaps sealed by 

unconsolidated pelagic mud. Such features 

might pool biogenic gas, at least in southern 

parts of North Aleutian basin. Thick shelfal 

sandstone sequences of Pliocene age, 

presumably representing large-scale currentmolded bedforms, also form candidates for 

stratigraphic traps for biogenic gas, as 

illustrated in figure 31. Pools of biogenic 

gas in play 4 would be characterized by very 

low pressure (no more than 1,300 psi) and 

would not yield significant fractions of the 

in-place gas to conventional development 

wells. The biogenic gas may occur in low 

saturations or be dissolved in formation 

waters. In either case, gas production might 

be accompanied by abundant formation 

water, a typical experience in biogenic gas 

production (Hunt, 1979, p. 155; Shurr and 

Ridgley, 2002). 

We note that most Cook Inlet gas fields are 

largely of biogenic origin with basin-wide 

original recoverable gas reserves of 8.6 Tcf 

(AKDO&G, 2002). Cook Inlet clearly 

offers a successful example of a commercial 

biogenic gas province. However, the Cook 

Inlet gas fields occur in fold structures 

(often overlying oil fields) that gathered the 

gas from surrounding extensive areas of gas 

biogenesis. Cook Inlet gas field reference 

depths range from 1,935 feet to 10,000 feet 

(average, 5,790 feet) and are normallypressured to over-pressured (AOGCC, 

2001). The Cook Inlet gas field sandstone 

reservoirs (Miocene and Pliocene) are 

overlain by compacted shales that form 

competent seals. The Cook Inlet gas fields, 

though filled with biogenic gas, do not 

provide a useful analog for play 4. Because 

of similarities in trap type, burial depths, and 

reservoir and seal lithologies, the Cook Inlet 

biogenic gas fields are most analogous to the 

drape-anticline prospects of North Aleutian 

basin plays 1 and 2, which range in depth 

from 2,500 to 10,000 ft. However, the 

latter are expected to be charged with mostly 

thermogenic gas and condensate. 

Areas of significant risk to play 4 include: 1) 

gas recoverability (low reservoir pressure 

and high formation water production); 2) 

poor seal (poor integrity of the 

unconsolidated pelagic mud that may seal 

glacial features); 3) reservoir (poor 

reservoir continuity); and 4) charge (lack of 

aquifer structure that would concentrate and 

convey biogenic gas to stratigraphic traps). 

Play 4 is assessed to have an exploration 

chance of zero and negligible undiscovered 

technically recoverable oil and gas 

resources. 

 44
Play 5: Mesozoic Deformed Sedimentary 

Rocks (Triassic-Cretaceous)

Play Area: 5,040 square miles 

Play Water Depth Range: 15-700 feet 

Play Depth Range: 2,000-15,000 feet 

Reservoir Thermal Maturity: 0.60%-1.30% vitrinite 

reflectance 

Risked, Mean, Undiscovered, Technically 

Recoverable Resources: 

38 Mmb (oil) + 0 Mmb (gas-condensate) = 38 

Mmb liquids 

0.000 Tcf (gas) + 0.017 Tcf (solution gas) = 

0.017 Tcf gas 

Pool Rank 1 Mean Conditional Resource: 63 Mmboe 

Play Exploration Chance: 0.09216

Play 5, the “Mesozoic Deformed 

Sedimentary Rocks” play, contributes a 

mere 1.8% (41 Mmboe) of the energy 

endowment (2,287 Mmboe) of the North 

Aleutian Basin OCS Planning Area. Oil 

forms 93% of the energy endowment of play 

5. 

Folded and thrust-faulted Mesozoic 

sedimentary rocks are widely exposed on the 

south side of the Alaska Peninsula (figs. 5, 

8). Exploration drilling on the Alaska 

Peninsula began in 1903 with drilling on oil 

seeps along the axes of anticlines near the 

east end of Becharof Lake (fig. 5). Oil seep 

drilling continued through 1940 and 

ultimately 10 wells were drilled (tbl. 1). 

Five modern (1961-1981) wells (Canoe Bay 

1, Big River 1, Koniag 1, Painter Creek 1, 

and Wide Bay 1) also tested exposed fold 

structures along the south flank of the 

Alaska Peninsula (Molenaar, 1996b, tbl. 1). 

On the north flank of the Alaska Peninsula 

and along the southern edge of North 

Aleutian basin, Mesozoic sedimentary rocks 

were penetrated by 3 wells (Cathedral River 

1, David River 1/1A, and Hoodoo Lake 2 

wells). To the west, five wells in St. George 

basin (St. George COST 2, Rat 1, Segula 1, 

Tustamena 1 [Y-0530], and Tustamena 2 

[Y-0527] wells) reached total depth in 

Jurassic rocks. The North Aleutian Shelf 

COST 1 well did not penetrate Mesozoic 

rocks (fig. 9 and pl. 2). The principal point 

of well information for the Mesozoic rocks 

of play 5 is the Cathedral River 1 well atop 

the onshore extension of the Black Hills 

uplift. The Cathedral River 1 well 

penetrated a relatively complete Mesozoic 

sequence 13,911 feet thick and ranging in 

age from Late Triassic (Kamishak Fm.) to 

Late Jurassic (Naknek Fm.) (fig. 20). The 

area of play 5 is shown in figure 36. 

No significant pools of oil or gas were 

encountered in any of the wells testing 

Mesozoic rocks on the Alaska Peninsula or 

in St. George basin. The Humble Bear 

Creek 1 well near Becharof Lake (fig. 2) 

recovered 450 Mcf/d of gas and large 

amounts (5,800 feet in drill pipe) of salt 

water (AOGCC, 1959) from a 120-foot 

interval of the uppermost part of the 

Talkeetna Formation (Detterman, 1990). 

Elsewhere, several wells encountered sparse 

oil and gas shows in Mesozoic rocks 

correlative to the play 5 sequence. Oil 

shows generally consist of white to yellow 

sample fluorescence and weak to streaming 

white, blue, or yellow cut fluorescence from 

isolated pores or fractures in impermeable 

sandstones and siltstones. In the Cathedral 

River 1 well, oil shows were encountered as 

shallow as 390 feet and were commonly 

observed down to 7,500 feet. At 7,500 feet, 

a petroleum-based mud additive (Soltex©) 

was introduced to the drilling mud, casting 

suspicion on the authenticity of the 

widespread hydrocarbon shows observed at 

greater depths. Flow tests in the Shelikof 

and Kialagvik Formations (Middle Jurassic) 

and the Talkeetna Formation (Lower 

Jurassic) in the Cathedral River 1 well 

recovered gassy drilling mud with traces of 

oil. In northern Cook Inlet, some oil 

production (<300,000 barrels) has occurred 

from fractured Talkeetna Formation beneath 

the principal accumulation (in Tertiary 

 45
rocks) in the McArthur River field 

(AOGCC, 2001, p. 171). 

Across the eastern Alaska Peninsula and 

western Alaska Range, the Bruin Bay fault 

forms the contact between a Mesozoic 

volcano-plutonic arc terrane on the north 

and a Mesozoic sedimentary basin on the 

south. The Bruin Bay fault is extrapolated 

offshore beneath the North Aleutian basin as 

the boundary between a northern area of 

high-frequency, high-amplitude magnetic 

anomalies and a southern area of lowfrequency, low-amplitude magnetic 

anomalies (fig. 7). We speculate that the 

magnetic anomaly field north of the 

projected Bruin Bay fault corresponds to the 

volcano-plutonic arc terrane exposed north 

of the Bruin Bay fault onshore. These rocks 

were penetrated beneath Tertiary strata in 

three wells (Great Basins 1, Great Basins 2, 

and Becharof Lake 1 wells) in the northeast 

part of North Aleutian basin. The magnetic 

anomaly field south of the projected Bruin 

Bay fault represents an offshore extension of 

the deformed Mesozoic sedimentary rocks 

of the Alaska Peninsula, as demonstrated by 

penetrations of Mesozoic rocks at several 

wells to the west in St. George basin and at 

the Cathedral River 1, David River 1/1A, 

and Hoodoo Lake 2 wells on the Alaska 

Peninsula. The area of play 5 corresponds 

to the area of the low-frequency, lowamplitude magnetic field south of the 

offshore extension of the Bruin Bay fault, 

and underlies the Amak basin and the Black 

Hills uplift (fig. 7). 

Most of the oil and gas resources of play 5 

are associated with hypothetical pools of oil 

captured in anticlines or fault traps like 

those exposed on the Alaska Peninsula, as 

illustrated in figure 31. We have not 

mapped such structures within the Mesozoic 

complex offshore, but fold, thrust-fault, and 

wrench-fault structures are observed in 

available seismic data. The surface 

anticlines outlined by geologic mapping 

near Becharof Lake range from 7,000 to 

147,000 acres in gross map area and the 

ranges of sizes of these anticlines were used 

to model hypothetical prospect areas in play 

5. Potential reservoir formations in play 5 

include the Lower Jurassic Talkeetna 

Formation, the Upper Jurassic Naknek 

Formation, the Lower Cretaceous 

Staniukovich and Herendeen Formations, 

and the Upper Cretaceous Chignik and/or 

Hoodoo Formations (stratigraphic column in 

fig. 8). In outcrop and well penetrations, 

most of these sandstones and conglomerates 

are highly zeolitized and preserve negligible 

porosity (Franks and Hite, 1980). The 

Staniukovich and Naknek Formations 

generally have the smallest fractions of 

volcaniclastic detritus (Burk, 1965, fig. 10), 

and, as the younger (or shallower) reservoir 

formations in the Mesozoic assemblage, 

have a burial history that is less severe than 

that of Middle Jurassic and older units. 

The principal resource in play 5 is predicted 

to be oil with no accumulations of free gas. 

Play 5 was modeled as an oil play because it 

is assumed to be charged by Middle Jurassic 

oil sources like those that charged the 

undersaturated (relative to gas) oil fields of 

northern Cook Inlet. Play 5 includes strata 

that are age-equivalent to known regional oil 

source beds of Middle Jurassic (Kialagvik 

Fm. or Tuxedni Gp.) and Late Triassic 

(Kamishak Fm.) ages. The Middle Jurassic 

Tuxedni Group is the source for 1.6 billion 

barrels of original oil reserves in northern 

Cook Inlet (AKDO&G, 2002), most of 

which are pooled in Tertiary-age rocks that 

overlie the Tuxedni Group. The Tuxednicorrelative sequence on the Alaska 

Peninsula—the Kialagvik Formation—is 

present in the Cathedral River 1 well 

onshore. Geochemical anomalies associated 

with the Kialagvik Formation in the 

 46
Cathedral River 1 well may suggest a past 

role as an oil source (fig. 20). In the 

Cathedral River 1 well, oil shows were 

widely observed in the rocks overlying the 

Kialagvik Formation, which is thermally 

overmature (TAI = 3.0 to 3.8) and post oilgenerative (fig. 20). It is probable that 

Mesozoic oil sources in this area generated 

and expelled the oil in a past (pre-Tertiary) 

cycle of deep burial and thermal 

transformation of organic matter. The 

existence of viable oil accumulations in play 

5 requires that the generation of oil out of 

these source rocks predate zeolitization of 

pore systems in Mesozoic sandstone 

reservoirs. Unfortunately, the general case 

appears to be that oil generation and 

migration followed reservoir zeolitization. 

Oil, though commonly observed in 

Mesozoic rocks in wells and outcrops, is 

only observed in trace quantities in fractures 

or in isolated pores that survived 

zeolitization. 

Four major risk factors for play 5 relate to: 

1) reservoir (early zeolitization and porosity 

destruction in chemically reactive 

volcaniclastic sandstones); 2) timing (oil 

generation and migration must occur early 

[Late Jurassic or Early Cretaceous] to 

protect reservoir pore systems, but traps 

probably did not form until Late Cretaceous 

or early Cenozoic time); 3) trap integrity

(breaching of traps at Miocene and older 

Cenozoic unconformities or trap disruption 

by faults may have destroyed Mesozoic 

petroleum accumulations); and 4) 

preservation (exhumation to shallow burial 

depths and invasion of meteoric waters may 

have promoted biological degradation of oil 

in Mesozoic-age accumulations to asphaltic 

materials). 

Play 6: Mesozoic Buried Granitic Hills 

(Jurassic-Cretaceous Magmatic Rocks)

Play Area: 46,810 square miles 

Play Water Depth Range: 15-400 feet 

Play Depth Range: 6,000-12,000 feet 

Reservoir Thermal Maturity: 0.34%-0.60% vitrinite 

reflectance (projected from burial depth but 

irrelevant because reservoirs are fractured 

plutonic and volcanic rocks) 

Risked, Mean, Undiscovered, Technically 

Recoverable Resources: 

26 Mmb (oil) + 5 Mmb (gas-condensate) = 30 

Mmb liquids (rounding sums to 31) 

0.195 Tcf (gas) + 0.010 Tcf (solution gas) = 

0.206 Tcf gas (rounding sums to 0.205) 

Pool Rank 1 Mean Conditional Resource: 148 

Mmboe (0.83 Tcfge) 

Play Exploration Chance: 0.04095

Play 6, the “Mesozoic Buried Granitic Hill” 

play, is a subordinate play in the North 

Aleutian Basin OCS Planning Area, with 

3% (67 Mmboe) of the Planning Area 

energy endowment (2,287 Mmboe). Oil and 

gas-condensate liquids form 45% of the 

hydrocarbon energy endowment of play 6. 

The rocks comprising the Mesozoic Buried 

Granitic Hill play correspond to the 

Mesozoic plutonic complex exposed in the 

Alaska Range to the northeast of the North 

Aleutian basin. The latter rocks are the 

roots of a volcanic arc system of Jurassic 

and Cretaceous age. The volcanic arc 

system is long-lived and remains active 

today as the chain of large, active volcanoes 

along the backbone of the Alaska Peninsula. 

The area of play 6 is shown in figure 37. 

Jurassic and Cretaceous plutonic rocks are 

overlain unconformably by Tertiary strata in 

wells in the northeastern parts of the North 

Aleutian basin. This plutonic complex was 

penetrated by 3 wells (Great Basins 1, Great 

Basins 2, and Becharof Lake 1 wells) at 

depths ranging from 8,780 to 10,860 feet. 

Plutonic rocks (quartz diorite) in the 

lowermost 15 ft of the Port Heiden 1 well 

 47
have been assigned to the Middle Jurassic 

by Detterman (1990), although Brockway et 

al. (1975) included these rocks with the 

overlying Eocene-Oligocene Meshik 

volcanics. Radiometric dating of some of 

these plutonic rocks by the K-Ar method 

(Geochron, 1969; original reported dates--

not recalculated using modern constants; 

Brockway et al., 1975) has yielded ages of 

96.3 Ma (Great Basins 2 well), 120 Ma, and 

177 Ma (Great Basins 1 well), or, ranging 

from mid-Cretaceous to Middle Jurassic in 

equivalent stratigraphic age. 

No pools of oil or gas were encountered in 

any of the well penetrations of the Mesozoic 

magmatic arc complex. A gas seep at “Gas 

Rocks” along the southwest shore of 

Becharof Lake (located in fig. 23 [spl. 149]) 

is located along the projected trace of the 

Bruin Bay fault. This gas seep consists 

mostly of carbon dioxide and nitrogen. 

On the eastern Alaska Peninsula and western 

Alaska Range, the Bruin Bay fault forms the 

contact between a Mesozoic volcanoplutonic arc terrane on the north and a 

Mesozoic sedimentary basin on the south. 

The Bruin Bay fault is extrapolated offshore 

as the boundary between a northern area of 

high-frequency, high-amplitude magnetic 

anomalies and a southern area of lowfrequency, low-amplitude magnetic 

anomalies (fig. 7). We speculate that the 

magnetic anomaly field north of the 

projected Bruin Bay fault corresponds to the 

volcano-plutonic arc terrane exposed north 

of the Bruin Bay fault onshore. These rocks 

were penetrated beneath Tertiary strata in 

three wells (Great Basins 1, Great Basins 2, 

and Becharof Lake 1 wells) in the northeast 

part of North Aleutian basin. The magnetic 

anomaly field south of the projected Bruin 

Bay fault represents an offshore extension of 

the deformed Mesozoic sedimentary rocks 

of the Alaska Peninsula, as demonstrated by 

well penetrations of Mesozoic rocks at 

several wells to the west in St. George basin 

and at the Cathedral River 1, David River 

1/1A, and Hoodoo Lake 2 wells on the 

Alaska Peninsula. The area of play 6 

corresponds to the area of the highfrequency, high-amplitude magnetic 

anomaly field north of the offshore 

extension of the Bruin Bay fault. This 

magnetic anomaly field is interpreted to 

mark a substrate of Mesozoic volcanoplutonic rocks that underlies the northern 

ninety-two percent of the North Aleutian 

Basin OCS Planning Area. 

The Mesozoic basement rocks penetrated at 

the Great Basins 1 well are described from 

cores as polymictic conglomerates31 passing 

 

31 The stratigraphic assignment of these 

conglomerates in the Great Basins 1 well has been 

used to make a case for association with the very 

different terranes that lie north and south of the 

Bruin Bay fault. Hite (2004, p. 17) has argued that 

the assignment of these conglomerates to the Naknek 

Formation (after Detterman, 1990) indicates that the 

well penetrated the Mesozoic sedimentary (Chignik) 

terrane south of the Bruin Bay fault. (Regional 

mapping published by Magoon et al [1976] confines 

the Upper Jurassic Naknek Formation to the terrane 

south of the Bruin Bay fault.) However, the Hite 

interpretation also requires that the Bruin Bay fault 

curve abruptly westward from the southwest shore of 

Becharof Lake so as to pass north of the Great 

Basins 1 well. We note that views differ on the 

correct assignment for the conglomerates in the 

depth interval 10,516-10,850 ft md in the Great 

Basins 1 well. Brockway et al. (1975) assigned these 

conglomerates to the Oligocene Stepovak Formation 

and as such they would have no bearing on the 

interpretation of position relative to the terranes 

separated by the Bruin Bay fault. The conglomerates 

at the Great Basins 1 well pass downward into 

granitic gneiss and lamprophyre that, in our view, 

are most sensibly associated with the volcanoplutonic arc (Iliamna) terrane north of the Bruin Bay 

fault. Shales interbedded with the conglomerates are 

described as “baked” (AOGCC, 1959b, p. 11) and 

the deeper granitic rocks have been K-Ar dated at 

120 and 177 Ma (Early Cretaceous and earliest 

Middle Jurassic, respectively; Geochron, 1969; 

Brockway et al., 1975). Contact metamorphism of 

 48
downward into granitic gneiss (with large 

orthoclase porphyroblasts) and lamprophyre 

(rich in dark minerals and transitional to 

gabbros). The Great Basins 2 well 

penetrated diorite and granite, brecciated 

and seamed with calcite veins. The 

Mesozoic rocks penetrated at the Becharof 

Lake 1 well are described as metamorphic 

green schist, meta-gabbro, and meta-diorite, 

highly fractured and veined by feldspar and 

quartz. 

All of the undiscovered potential oil and gas 

resources of play 6 are associated with 

hypothetical pools lodged in fractured 

“granitic”32 rocks that core basement uplifts 

of Tertiary age, as illustrated in figure 31. 

These granite-cored uplifts were repeatedly 

exposed to weathering and erosion through 

early Tertiary (perhaps also Late 

Cretaceous) time. We hypothesize that 

fractures in the granites provided avenues 

for deep invasion by meteoric waters during 

times of surface exposure. The meteoric 

waters may have enlarged fractures through 

dissolution and created a bulk porosity that 

was later occupied by petroleum (following 

deep reburial). In addition to an abundance 

of fractures, fractures must be lengthy and 

sufficiently diverse in orientations and depth 

of penetration in the granitic body to 

establish effective connectivity across pool 

areas of thousands of acres. The granitecored basement uplifts were eventually (in 

Late Eocene time, approx. 40 Ma) sealed 

 

shales interbedded with the conglomerates by Middle 

Jurassic intrusives suggests to us that the 

conglomerates might more logically be assigned to 

the Lower Jurassic Talkeetna Formation, which is 

widely mapped and commonly intruded by plutons in 

the volcano-plutonic arc (Iliamna) terrane north of 

the Bruin Bay fault (Magoon et al., 1976). We 

conclude that the conglomerates and magmatic rocks 

penetrated below 10,516 ft md in the Great Basins 1 

well probably represent the volcano-plutonic terrane 

north of the Bruin Bay fault. 

32 Here referring to any felsic pluton or massive felsic 

volcanic flow.

beneath a regional shale within the lower 

part of the Stepovak Formation. We 

hypothesize that gas and oil arising from 

Type III and coaly source rocks of Tertiary 

age in deep areas of the North Aleutian 

basin that surround the basement uplifts 

migrated up the bounding faults and invaded 

the fractured and weathered granites at the 

crest of the basement uplifts. 

Features similar to the North Aleutian basin 

buried hills form important exploration 

targets in the Bohai (North China) basin 

(Guangming and Quanheng, 1982) and 

offshore Vietnam (Areshev et al., 1992). 

Buried hills form an important play concept 

for exploration of the Mesozoic assemblage 

in ultra-deep waters of the U.S. Gulf of 

Mexico (Post et al., 2001). In the productive 

analog from Vietnam, the granitic rocks 

range in age from 97 to 178 Ma (midCretaceous to Middle Jurassic) and feature 

bulk porosity values ranging from up to 

25.0%. Effective porosity averages between 

2.5% and 3.8% and is roughly distributed in 

halves as “fracture porosity” and as 

“caverns” or “microcaverns”, the latter the 

legacy of dissolution of fracture surfaces by 

both hydrothermal and meteoric fluids. 

Vietnam’s largest field (Bach Ho) is lodged 

in a fractured granitic reservoir and produces 

approximately 280,000 bbl/day (Brown, 

2005, p. 8). Paul Post (pers. comm., August 

2003) of the Minerals Management Service 

has compiled data on the buried hill oil and 

gas fields of China and Vietnam. Pool 

volumes can exceed 1 billion barrels of oil 

and 2 trillions of cubic feet of gas. 

Productive columns can range up to 3,300 

feet (P’An, 1982, tbl. 1; O&GJ, 2003). 

Initial production rates can exceed 18,000 

barrels of oil per day. Oil recovery factors 

can range up to 900 bbl/acre-foot (F50 = 

158 bbl/acre-foot). The variability in these 

fractured reservoirs is such that the upper 

parts of the reservoir can be sparsely 

 49
fractured while better fracture systems exist 

deeper in the buried hill. Many hydrocarbon 

accumulations in Vietnam and China (and 

elsewhere) may have been missed because 

exploration wells stopped drilling as soon as 

granitic rocks were encountered in the belief 

that it was economic basement and no 

hydrocarbons could be housed there (Sladen, 

1997). The data compiled and analyzed by 

Paul Post for analog features in China and 

Vietnam formed the basis for the pay 

thickness and oil and gas yields used in the 

play 6 resource model (prospect areas are 

based on MMS seismic mapping). 

Three major risk factors for play 6 relate to: 

1) reservoir (requires extensive fractures, 

enhanced by weathering, and of sufficient 

vertical and horizontal lengths and diversity 

of orientation to achieve connectivity across 

an area of tens of thousands of acres); 2) 

adequate source (no attractive source 

formation in known Tertiary-age rocks); and 

3) migration (hydrocarbons generated in 

deep basin areas surrounding basement 

uplifts must first migrate vertically up 

bounding faults to reach the horsts, but then 

must encounter sealing levels on the same 

faults that act to divert hydrocarbons into the 

crests of uplifts; there is some risk that these 

faults will instead allow the hydrocarbons to 

escape upwards into overlying Tertiary 

sedimentary rocks). 

GEOLOGIC ASSESSMENT MODEL

The creation of the geologic model used in 

the computer simulation for the 

undiscovered oil and gas resources of the 

North Aleutian Basin OCS Planning Area 

drew data from MMS seismic mapping, 

exploratory wells, producing fields in 

analogous reservoirs in the northern Cook 

Inlet basin, and published literature. 

Tabulations of the geologic input data used 

to assess the 6 plays identified in the North 

Aleutian Basin OCS Planning Area are 

given in tables 3, 4, 5, 6, 7, and 8. 

Prospect Areas and Volumes

This oil and gas assessment relies upon the 

seismic mapping conducted prior to 1988 by 

the Alaska (Region) office of the Minerals 

Management Service. This mapping 

identified 74 prospects in the North Aleutian 

Basin OCS Planning Area. This mapping 

was the basis for construction of probability 

distributions for the aerial sizes of prospects 

and probability distributions for the numbers 

of prospects. These are the most influential 

variables within the geologic model used to 

compute the undiscovered oil and gas 

potential and it is important that they are 

grounded in direct information. 

Mapped prospects were grouped by play and 

the prospect areas (maximum closure within 

spill point) were tabulated and entered into 

the BESTFIT module within @RISK for 

approximation by a log-normal probability 

distribution. The closure areas of mapped 

prospects in the North Aleutian Basin OCS 

Planning Area range from 2,600 to 133,000 

acres. Independent probability distributions 

for prospect areas were created for each 

play. These are the distributions reported as 

“Prospect Area (acres)-Model Input” in 

tables 3 through 8. 

 50
The prospect area distribution was then 

aggregated (in @RISK) with a probability 

distribution for fill fraction (described 

below) to obtain the probability distribution 

for pool area. The @RISK aggregation 

reports back an “as-sampled” prospect area 

distribution, which is reported as the 

“Prospect Area (acres)-Model Output” in 

tables 3 through 8. 

The pool area distribution reported from the 

@RISK aggregation was then aggregated 

with a probability distribution for pay 

thickness (described below) in order to 

calculate a probability distribution for pool 

volume (in acre-feet) in the POOLS module 

within GRASP. The pool volume 

distribution and the pool numbers 

distribution (described below) were then 

aggregated to calculate the volumes (acrefeet) of discrete hypothetical pools in the 

PSRK module. The PSUM module 

completed the analysis by charging the 

discrete hypothetical pools with a specified 

mix of petroleum fluids and then calculating 

resources for the individual pools and the 

play as a whole. 

The construction of probability distributions 

for trap fill fractions relied upon subjective 

analysis of each of the key elements 

controlling trap fill. We first considered the 

charge potential for the play, that is, the 

extent to which hydrocarbons were made 

available to fill traps within the play. In 

plays understood to have easy access to 

abundant hydrocarbons migrating from areas 

of prolific oil and gas generation, trap fill 

fractions were permitted to rise to a 

maximum of 1.0 (100%). Generally, these 

are plays with prospects amidst a 

hydrocarbon generation center. In plays 

perceived to have limited access to 

migrating hydrocarbons were modeled with 

prospects incompletely filled. For plays 

requiring migration from distant generation 

areas, trap fill fractions were reduced in 

recognition of the risks of high losses and 

diversions (up faults to surface seeps) 

incurred by long-distance migration. 

Given access to some significant source of 

hydrocarbons for the play, attention was 

then turned to trap size, trap amplitude, trap 

type, and seal integrity. Trap size is an issue 

where limited hydrocarbons are available to 

fill high-volume traps. Trap amplitude 

becomes a factor when the vertical relief is 

very large, so large that differential 

pressures across seals33 at the crests could 

rupture the seals and allow the hydrocarbons 

to escape. Trap integrity is also a function 

of trap type. A trap sealed by one or more 

faults is probably at more risk for leakage 

than a simple anticline sealed by a single, 

continuous shale formation. Seal integrity is 

generally controlled by lithology and 

thickness. Even high-amplitude prospects 

could reasonably be allowed to be 

completely filled if sealed by thick, wellconsolidated, clay-rich shales. Shales that 

can be shown to be geopressured also offer 

greater seal integrity and more complete 

filling of traps might be anticipated where 

such geopressured shales form the seals. 

Prospect Numbers 

As noted above, MMS seismic mapping 

identified a total of 74 prospects34 in the 

 33created by contrasts between hydrostatic 

pressures in rocks saturated by relatively highdensity water and excess pressures (“buoyant 

pressures”) developed in columns of relatively lowdensity hydrocarbons

34 In plays 1, 2, 3, and 6. No prospects are mapped 

in play 5. There, the minimum (F99) number of 

prospects (and areas) were estimated from the 

density and sizes of surface anticlines exposed on the 

Alaska Peninsula from Becharof Lake to Chignik 

Bay. 

 51
North Aleutian Basin OCS Planning Area. 

Some prospects represent closures at 

different depth levels (separate play 

sequences) on a single structure, so the total 

number of identified discrete prospective 

structures in the Planning Area is somewhat 

less than 74. 

In assessment work, we generally concede 

that large numbers of prospects could 

remain unidentified, some even in the most 

thoroughly mapped areas. “Unidentified” 

prospects exist for a variety of reasons. 

Some prospects remain unidentified because 

some areas lack seismic data. Some smaller 

prospects may have been missed because 

they fall within spaces in the seismic grid. 

Other prospects may be missed because of 

lack of detail in stratigraphic analysis. 

Lastly, many prospects may remain 

unidentified because they are subtle or 

impossible to detect in seismic data. It is 

generally acknowledged that unidentified 

prospects exist in all basins and plays, that 

some fraction of the unidentified prospects 

probably contain petroleum, and that some 

of the unidentified prospects will ultimately 

be tested and discovered to contain pooled 

oil or gas, perhaps in commercial quantities. 

Therefore, unidentified prospects must be 

given account in the assessment of 

undiscovered oil and gas potential. 

For the exploration plays identified in the 

North Aleutian Basin OCS Planning Area 

we supplemented the numbers of known 

prospects with some estimate of the numbers 

of prospects that might remain unidentified. 

The estimation process focused on the 

completeness of seismic information and the 

level of geological complexity. In 

thoroughly-mapped plays with simple 

geology and large structures, like play 1, 

relatively few prospects are expected to 

remain unidentified. Conversely, in plays 

with complex geology, deficient analysis 

(sparse seismic data, or rudimentary 

seismic-stratigraphic analysis), or 

predominantly small prospects, like play 2, 

very large numbers of prospects might 

reasonably be expected to remain 

unidentified. 

We constructed prospect numbers 

probability distributions for each play using 

a graphical approach. Our practice was to 

first post the number of mapped prospects at 

F99 (99% probability of equaling or 

exceeding the associated value) on logprobability graph paper. To the number of 

mapped prospects we add our estimate for 

the number of unidentified prospects; this 

sum is then posted at the extreme right (at 

~F00) on the same log-probability plot. A 

line connecting these two data points then 

defines the probability distribution for 

prospect numbers for a particular play. 

We estimated that as many as 285 

hypothetical prospects might remain 

unidentified in the 5 assessed exploration 

plays (play 4 was not quantitatively 

assessed). When added to the 74 mapped 

prospects (and the 11 prospects at minimum 

inferred for play 5), we have a maximum 

estimated endowment of 370 prospects. 

When aggregated with the play risk models 

in the MPRO module of GRASP, we 

obtained a maximum endowment of 119 

hypothetical pools35 that contributed to the 

overall undiscovered oil and gas potential of 

the North Aleutian Basin OCS Planning 

Area. 

Pay Thickness Model

Cook Inlet oil fields (data reported by 

AOGCC, 2001) were used as an analog for 

 35sum of maximum numbers of pools found for 5 

plays, as reported in tables 3, 4, 5, 6, 7, and 8

 52
developing probability distributions for pay 

thickness for the prospects in North Aleutian 

basin. The North Aleutian Shelf COST 1 

well encountered abundant thick sandstones 

(aggregate exceeding 3,000 feet) in the Bear 

Lake-Stepovak play (1) sequence. Given 

the thin and discontinuous shale seals within 

and above the Bear Lake-Stepovak 

sequence, and, the unknown charge capacity 

for basin petroleum sources, it seems 

unlikely that all sandstones in this sequence 

would form “pay” across any given 

prospect. The nonmarine to inner neritic 

sandstones of the Bear Lake-Stepovak 

sequence are broadly analogous to the 

nonmarine to inner neritic (estuarine) 

Tertiary basin fill of Cook Inlet basin (Kenai 

Gp., Beluga Fm., and Sterling Fm.) as 

described by Hite (1976) and Hayes et al. 

(1976). Pay thickness data for the oil and 

gas fields of northern Cook Inlet are 

presented in figure 38. The statistical fit to 

these data was used to model pay thickness 

for analogous plays (1 and 3) in the North 

Aleutian Basin OCS Planning Area. Figure 

11 shows that there is clearly adequate 

sandstone in this sequence to accommodate 

the most generous pay thickness model—

certainly the modest pay thickness model 

developed from Cook Inlet oil and gas fields 

in figure 38. (We note that the amplitudes 

of mapped prospects in the North Aleutian 

basin range from 46 to 584 feet [mean = 227 

feet], adequate at maximum amplitudes to 

accommodate the full pay column [456 feet] 

modeled in figure 38.) Pay thicknesses for 

play 2 were reduced to reflect the observed 

(in core data) poor reservoir qualities in the 

sandstones of the Tolstoi play sequence. 

Construction of Probability Distributions 

With Limited Data

The input parameters required by the 

computer models for plays are listed in the 

data forms shown in table 3 through table 

13. There has been little or no exploratory 

drilling and very little data are directly 

available for most of these input parameters. 

However, in many cases, one can forecast 

the extreme ranges for any particular input 

parameter using regional well data or data 

from analogous basins. For example, in the 

calculation of gas recovery factors, the 

reservoir temperature is an important 

variable that is controlled by burial depth 

and geothermal gradient. The latter 

information is available from seismic 

mapping (depths) and well data (geothermal 

gradient), or thermal models from analogous 

basins. Our approach to constructing a 

probability distribution for reservoir 

temperature is to estimate the temperature 

extremes – the temperatures of the 

shallowest (coolest) and deepest (hottest) 

prospects in the play. Then, we post the 

minimum temperature at the 99.99 

(effectively 100.0) percent probability and 

the maximum temperature at the 

0.01 (effectively 0) percent probability in a 

“normal” (Gaussian) probability plot. (One 

might also use a log-normal probability plot 

to conduct this exercise. We assumed a 

normal distribution for play reservoir 

temperature.) A straight line drawn 

connecting the two points (invoking a 

normal distribution) then defines a 

probability distribution for reservoir 

temperature for the play. An example plot is 

shown in figure 39. Newendorp (1975, 

p. 383) termed such constructions “force-fit” 

distributions. Many input probability 

distributions in the geologic computer 

models for plays in this assessment were 

created using this method. 

 53
Computation of Oil and Gas Recovery 

Factors

The GRASP computer model requires 

entries for recoverable petroleum per unit 

volume of petroleum-saturated reservoir. 

The data forms in table 3 through table 13

list these entries as “Oil Recovery Factor” 

(barrels of oil recoverable per acre-foot of 

reservoir pool) and “Gas Recovery Factor” 

(thousands of cubic feet of gas recoverable 

per acre-foot of reservoir pool). In the 

absence of local production experience, 

predicting these values for undiscovered 

pools is difficult because they are the 

product of complex interactions of several 

variables. Analogous reservoirs in 

comparable plays or geologic settings can 

form a source for such data. However, 

establishing credible analogs and finding 

published data for them are both difficult 

tasks. In the North Aleutian Basin OCS 

Planning Area, we chose to use a computer 

model to calculate the oil and gas recovery 

factors using basic information that is often 

available from regional studies or local well 

data. 

The data required to compute oil and gas 

recovery factors are essentially the variables 

in the yield equations for oil and gas. These 

are listed in the data forms of tables 9, 10, 

11, and 12 and are noted in the yield 

equations below: 

Oil Recovery Factor: 

a. Porosity (decimal fraction) 

b. Water Saturation (decimal fraction) 

c. Oil Recovery Efficiency (decimal 

fraction) 

d. Oil Volume Factor (as 1/FVF [where 

FVF = Formation Volume Factor = 

Reservoir Barrels Per Stock Tank 

Barrels]) 

Barrels Oil Recoverable per Acre-Foot of 

Pool Reservoir (BO) 

= 7758.38 Bbl/acre-ft (a·(1-b)·c·d)

Gas Recovery Factor: 

a. Porosity (decimal fraction) 

b. Water Saturation (decimal fraction) 

c. Reservoir Pressure (pounds per in2) 

d. Gas FVF (as 1/Z [Z = Gas 

Deviation36 Factor]) 

e. Gas Recovery Efficiency (decimal 

fraction) 

f. Gas Shrinkage Factor (decimal 

fraction) 

g. Reservoir Temperature (in °Rankine= 

°F+460) 

Thousands of Cubic Feet of Gas 

Recoverable per Acre-Foot of Pool 

Reservoir (MCFG)* 

= [43,560 ft3

/acre-ft] [a·(1-b)] 

[(60°+460°)·d·e] [c/14.73] [(1-f)/g [1/1,000]

* (at standard surface conditions of 60 

°F (520°R) and 14.73 pounds per in2 [1 

atmosphere])37

or, rearranging for simplification: 

Thousands of Cubic Feet of Gas 

Recoverable per Acre-Foot of Pool 

Reservoir (MCFG)* 

 

36 Also known as the compressibility factor, a 

measure of deviation from ideal gas behavior. The 

“Z” factor can be defined as the ratio between the 

volume actually occupied by a gas at a certain 

pressure and temperature and the volume that the 

gas would occupy, if it behaved like an ideal gas, at 

the same pressure and temperature (McCain, 1973, 

p. 95-109). For ideal gases, the “Z” value is 1.0. 

“Z” factors can range from 0.2 to 2.0, but in most 

North Aleutian prospects, estimated “Z” values 

range from 0.65 to 1.04 (tbls. 9 to 11). 37 The value of 14.73 psi/atm was inherited from 

earlier MMS assessment work. The conventional 

value is 14.70 psi/atm, although the legal base in 

many States is 14.65 psi/atm, and in New Mexico and 

Louisiana it is 15.025 psi/atm (Craft and Hawkins, 

1959, p. 11). 

 54
= 1537.8 (a·(1-b)·c·d·e) (1-f)/g 

Many of these variables, such as 

temperature, pressure, and porosity, are 

depth-dependent and can be predicted over 

the depth ranges of plays if geothermal, 

geopressure, and porosity-decline gradients, 

respectively, are known. These latter data 

are available from exploratory wells and can 

often be extrapolated with some confidence 

over large areas. In this case, geothermal 

and geopressure data were obtained from the 

North Aleutian Shelf COST 1 well. 

Likewise, porosity data were extracted from 

the abundant core porosity data obtained by 

the COST well and incorporated directly 

into oil and gas yields after statistical 

approximation by normal and log-normal 

distributions (figs. 12, 13, 14, and 15). 

If reservoir texture can be estimated, 

irreducible water saturations can be 

predicted from porosity determinations by 

reference to a series of general tables and 

charts. We began by estimating the 

lithology and grain size of potential 

reservoirs and using these data to estimate 

bulk volume water using a published table 

(Asquith and Gibson, 1982, p. 98, tbl. 8). 

The value for bulk volume water was taken 

as equivalent to the “φSwi” (porosity ⋅

irreducible water saturation) curves in a 

porosity-saturation cross plot published by 

Schlumberger (1991, p. 158, chart K-3). By 

pairing minimum and maximum porosity 

values with extreme “φSwi ” values (from 

textural considerations and the Asquith 

table)38, estimates for irreducible water 

saturations can be read from the 

Schlumberger chart. In this way, minimum 

and maximum values for water saturations 

 

38minimum porosity (10%) paired with a poorlysorted, very- fine-grained sandstone; maximum 

observed porosity paired with a well-sorted example 

of the coarsest-grained clastic rock expected to occur 

within the play sequence 

were determined for the play and used to 

construct “force-fit” log-normal probability 

distributions for entry to the computer 

model. Averaged “initial water saturation” 

data for Cook Inlet oil and gas fields 

(AOGCC, 2001) were used to calibrate the 

medians of the probability distributions for 

water saturation in the North Aleutian plays. 

When oil is produced, it shrinks in volume 

because gases dissolved in the oil at 

reservoir pressures are released at surface 

pressures. This volume change is 

represented by the “Oil Formation Volume 

Factor” or “FVF” (reservoir barrels per 

stock tank barrels) and it is dictated by the 

quantity of dissolved solution gas (gas-oil 

ratio, or GOR), which is in turn controlled 

by reservoir pressure, temperature and 

petroleum composition(s). A single 

distribution was used for all North Aleutian 

plays. The probability distribution for 

Formation Volume Factor was estimated 

from a statistical fit to 14 FVF values 

reported for Cook Inlet producing oil fields 

(AOGCC, 2001). These data were inverted 

and entered as the “Oil Volume Factor 

(1/FVF)” for purposes of oil yield 

calculations (tbls. 9, 10, 11, and 12). 

Ranges in oil and gas recovery efficiencies 

were estimated from recovery data for 

various combinations of reservoirs and drive 

mechanisms as published by White (1989, p. 

3-29 to 3-31) and Arps (1967). 

The gas “Z” factor, or “deviation” factor, 

was determined using charts published by 

Standings and Katz (1942; republished by 

Anderson [1975, p. 155-156] and McCain 

[1973, p. 95-109]) and using estimates for 

gas gravities, reservoir temperatures, and 

reservoir pressures. Gas gravities were 

obtained from data for producing fields in 

Cook Inlet (AOGCC, 2001). 

 55
Probability distributions for all of the 

variables in the yield equations, and 

appropriate unit conversion constants, were 

entered into the @RISK computer program 

and aggregated with dependencies to 

calculate probability distributions for oil and 

gas recovery factors. The input variables 

and the dependency models are shown in 

tables 9, 10, 11, and 12. Probability 

distributions for oil and gas recovery factors 

for play 6 (listed in tbl. 8) were taken from 

MMS data compilations by Paul Post (pers. 

Comm.., August, 2003). 

Risk Assessment

Analyses of play risk were carried out along 

the lines suggested by White (1993). First, 

risk was assessed at the play level, where the 

absence of a critical element could hazard 

the success of the entire play. Second, risk 

was assessed at the prospect level, where a 

critical element might be absent at some 

sites and cause some fraction of the 

prospects in a successful play to be barren of 

hydrocarbons. 

Chances for success at the prospect level are 

analogous to drilling success rates in 

commercially successful plays in productive 

basins (some specific examples provided by 

Clifford, 1986, p. 370). Our subjective 

estimates for prospect level chances of 

success are conditioned upon success (i.e., 

success is assumed) at the play level. The 

play chance for an unproven play is 

typically less than 1.0. The prospect chance 

is ultimately multiplied against the play 

chance to obtain an “exploration” chance. 

The exploration chance is in turn used with 

the (probability distribution for) numbers of 

prospects to determine the (probability 

distribution for) numbers of pools39. 

Success of a play or prospect can be defined 

in different ways. Commercial success in 

oil prospecting is contingent upon finding 

sufficient reserves to permit the 

accumulation to be developed at a profit. 

However, some (or most) oil or gas pools, 

particularly in the Arctic, are too small to 

warrant commercial development. 

Nevertheless, these small pools represent 

“geologic” successes, proving that 

petroleum must have been generated 

somewhere and was able to migrate to traps 

bearing porous media. The small pools, by 

their existence, prove that all components of 

the play petroleum system are working 

properly. 

In this assessment of the North Aleutian 

Basin OCS Planning Area, the condition for 

“geologic” success for a play was a single 

occurrence of conventionally pooled 

hydrocarbons capable of flowing to a wellbore. Any play known to host such an 

occurrence was assigned a play level chance 

of success of 1.0. For example, based on 

small gas flows in tests from the Tolstoi 

Formation at the Becharof Lake 1 and the 

David River 1/1A wells, play 2 (Tolstoi) 

was assigned a play chance of 1.0. The play 

chances for all other plays are less than 1.0 

because no pooled hydrocarbons have been 

identified in these plays. No attempt was 

made to formalize a specific minimum field 

size as part of the condition of “geologic” 

success. Although similar definitions for 

play success, in which no minimum pool 

sizes are specified, are advocated by some 

experts, (Capen, 1992; Rose, 1992), the 

practice has been criticized by prominent 

experts such as White (1993, p. 2050). 

 39 performed in a mathematically complex 

process by the MPRO module of the GRASP 

computer program, as described by Bennett (1994) 

 56
The construction of risk models required a 

subjective appraisal of the factors 

underlying play and prospect success. Our 

subjective risk analysis focused upon each 

of the main elements required for successful 

creation and preservation of oil or gas 

accumulations, including: 1) trap definition 

and integrity; 2), reservoir presence and 

quality; 3) charge or source success; and 4) 

preservation success. Exploration chances 

for the 6 plays identified in the North 

Aleutian Basin OCS Planning Area range 

from 0.0 (play 4) to 0.1872 (play 1). The 

key risk factors for each of the 6 plays 

identified in the North Aleutian Basin OCS 

Planning Area are listed in tables 3, 4, 5, 6, 

7, and 8.

Assessment Results for North Aleutian Basin 

Table 14 shows the results of the 2006 oil 

and gas assessment of the North Aleutian 

Basin OCS Planning Area, including results 

for total technically recoverable 

hydrocarbon energy (in barrels of oilequivalent) and four individual commodities 

(oil, condensate from gas, free gas (“nonassociated”40 and solution gas) for 

individual plays. Planning Area totals by 

individual commodity are also listed. 

Play 1: Bear Lake-Stepovak (OligoceneMiocene)

Play 1 is the dominant play in the North 

Aleutian Basin OCS Planning Area, with 

61% (1,400 Mmboe) of the Planning Area 

hydrocarbon energy endowment (2,287 

Mmboe) at mean risked values. The play 

hydrocarbon energy endowment (risked, 

recoverable) ranges from 0 Mmboe (F95) to 

3,749 Mmboe (F05), as shown in figure 

 

40 The term “non-associated gas” as used in GRASP 

output reports refers to both free gas occurring as 

pools of gas unaccompanied by oil and free gas 

occurring in gas caps directly overlying oil 

accumulations. The industry convention is to 

describe the free gas in caps overlying oil 

accumulations as “associated” gas. 

40A. Gas (“non-associated” [free] gas and 

solution gas) forms 71% of the hydrocarbon 

energy endowment of play 1. 

In the computer simulation for play 1, each 

of the 7,198 successful trials is comprised of 

one or more “pools” (or “hits”, in 

assessment vernacular), for a total of 73,007 

pools sampled for size (tbl. 15). These pools 

can be grouped and displayed as size 

classes, as shown in the histogram of figure 

40B. Pool size class 12 contains the largest 

share (15,882, or 22%) of pools 

“discovered” among the 10,000 trials41

conducted by the computer simulation for 

play 1. Pool size class 12 ranges from 64 to 

128 Mmboe. Pool count statistics for the 

play 1 simulation are shown in table 15. The 

largest pool among the 73,007 pools or 

“hits” in the computer simulation for play 1 

falls within pool size class 19, which ranges 

in size from 8,192 to 16,384 Mmboe (or 46 

41 The model simulates the drilling of all pools in the 

play by comparing computer-generated random 

numbers (ranging from 0.0 to 1.0) to the user-input 

play risk factors (play risk = 1.0 – play chance). 

When the random number exceeds the risk, then the 

trial is declared “successful,” indicating a discovery 

(i.e., hydrocarbons exist in the pool), or pool. Most 

successful trials contain several pools.

 57
to 92 Tcfge; tbl. 15 and fig. 40B). The 

computer simulation therefore indicates 

some potential for very large hydrocarbon 

pools in play 1. 

A maximum of 34 hypothetical pools is 

forecast by the aggregation of the risk model 

and the prospect numbers model (tbl. 3) for 

play 1, as shown in figure 40C. These 34 

pools range in mean conditional (un-risked) 

recoverable volumes from 6 Mmboe (pool 

rank 34) to 827 Mmboe (pool rank 1). Pool 

rank 1 (fig. 40C) ranges in possible 

conditional recoverable volumes from 187 

Mmboe (F95) to 2,495 Mmboe (F05), or in a 

gas case from 1.05 Tcfge (F95) to 14.02 

Tcfge (F05). Data for the size ranges of 

play 1 pools are given in table 16. As noted 

above, at low probabilities we observe some 

potential for very large hydrocarbon pools in 

play 1. The high-side potential recognizes 

the combination of large, simple traps and 

thick, high-quality reservoir formations that 

form the best exploration opportunities in 

both play 1 and the entire North Aleutian 

Basin OCS Planning Area. Overall, play 1 

and most of the North Aleutian basin are 

hypothesized to be charged by sources 

within the Tertiary basin fill and are 

modeled as gas prone. Therefore, the largest 

pool in play 1 (and in the Planning Area) is 

most likely to be charged by gas. 

Play 2: Tolstoi (Eocene-Oligocene)

Play 2 is the second most important play in 

the North Aleutian Basin OCS Planning 

Area, with 25% (568 Mmboe) of the 

Planning Area hydrocarbon energy 

endowment (2,287 Mmboe) at mean risked 

values. The play 2 hydrocarbon energy 

endowment (risked, recoverable) ranges 

from 91 Mmboe (F95) to 1,293 Mmboe 

(F05), as shown in figure 41A. Gas (“nonassociated” [free] gas and solution gas) 

forms 78% of the hydrocarbon energy 

endowment of play 2. 

In the computer simulation for play 2, each 

of the 9,905 successful trials is comprised of 

one or more pools (or “hits”), for a total of 

61,326 pools sampled for size (tbl. 17). 

These pools can be grouped and displayed 

as size classes, as shown in the histogram of 

figure 41B. Pool size class 12 contains the 

largest share (18,963, or 31%) of pools 

“discovered” among the 10,000 trials 

conducted by the computer simulation for 

play 2. Pool size class 12 ranges from 64 to 

128 Mmboe. Pool count statistics for the 

play 2 simulation are shown in table 17. 

The 5 largest pools among the 61,326 pools 

or “hits” in the computer simulation for play 

2 fall within pool size class 16, which ranges 

in size from 1,024 to 2,048 Mmboe (or 5.8 

to 11.5 Tcfge; fig. 41B). The computer 

simulation therefore indicates some lowprobability potential for large hydrocarbon 

pools in play 2. 

A maximum of 44 hypothetical pools is 

forecast by the integration of the risk model 

and the prospect numbers model (tbl. 4) for 

play 2, as shown in figure 41C. These 44 

pools range in mean conditional (un-risked) 

recoverable volumes from 7 Mmboe (pool 

rank 44) to 208 Mmboe (pool rank 1). Pool 

rank 1 (fig. 41C) ranges in possible 

conditional recoverable volumes from 61 

Mmboe (F95) to 467 Mmboe (F05), or, in 

the gas case, from 0.34 Tcfge (F95) to 2.62 

Tcfge (F05). Data for the size ranges of the 

play 2 pools are given in table 18. The 

modest high-side potential recognizes the 

thin, typically impermeable reservoir 

formations that characterize play 2. Overall, 

play 2 is Tertiary-sourced and is modeled as 

gas-prone, so the largest pool is most likely 

to be charged by gas. 

 58
Play 3: Black Hills Uplift-Amak Basin 

(Eocene-Miocene)

Play 3 is a subordinate play in the North 

Aleutian Basin OCS Planning Area, with 

9% (210 Mmboe) of the Planning Area 

hydrocarbon energy endowment (2,287 

Mmboe). The play 3 hydrocarbon energy 

endowment (risked, recoverable) ranges 

from 0 Mmboe (F95) to 1,077 Mmboe 

(F05), as shown in figure 42A. Gas (“nonassociated” [free] gas and solution gas) 

forms 26% of the hydrocarbon energy 

endowment of play 3. 

In the computer simulation for play 3, each 

of the 4,127 successful trials is comprised of 

one or more pools (or “hits”), for a total of 

15,323 pools sampled for size (tbl. 19). 

These pools can be grouped and displayed 

as size classes, as shown in the histogram of 

figure 42B. Pool size class 11 contains the 

largest share (2,521, or 16%) of pools 

“discovered” among the 10,000 trials 

conducted by the computer simulation for 

play 3. Pool size class 11 ranges from 32 to 

64 Mmboe. Pool count statistics for the play 

3 simulation are shown in table 19. The 

largest pool among the 15,323 pools or 

“hits” in the computer simulation for play 3 

falls within pool size class 19, which ranges 

in size from 8,192 to 16,384 Mmboe (fig. 

42B). The computer simulation therefore 

indicates a low-probability potential for very 

large hydrocarbon pools in play 3. 

A maximum of 13 hypothetical pools is 

forecast by the aggregation of the risk model 

and the prospect numbers model (tbl. 5) for 

play 3, as shown in figure 42C. These pools 

range in mean conditional (un-risked) 

recoverable volumes from 4 Mmboe (pool 

rank 13) to 378 Mmboe (pool rank 1). Pool 

rank 1 (fig. 42C) ranges in possible 

conditional recoverable volumes from 20 

Mmboe (F95) to 1,302 Mmboe (F05), or, in 

the gas case, from 0.11 Tcfge (F95) to 7.32 

Tcfge (F05). Data for the size ranges of the 

play 3 pools are given in table 20. As noted 

above, at very low probabilities, we observe 

some potential for large pools of 

hydrocarbons in play 3. This high-side 

potential recognizes the small number of 

very large closures in play 3 that have been 

identified by seismic mapping. Because of 

the potential for oil sourced from underlying 

Mesozoic sedimentary rocks and the great 

distance to Tertiary gas sources, play 3 is 

predominately an oil play. The largest pool 

in play 3 is most likely to contain oil. 

Play 4: Milky River Biogenic Gas (PlioPleistocene)

Play 4 is the most regionally extensive yet 

least prospective play in the North Aleutian 

Basin OCS Planning Area. Play 4 probably 

contains sizeable in-place quantities of 

biogenic gas. However, all hypothetical 

prospects (none are identified) are related to 

stratigraphic isolation of sandstone or 

glacial-moraine bodies within 

unconsolidated marine mud. Any gas 

production might be accompanied by high 

water production because of low gas 

saturations, a common experience in 

biogenic gas production. Formation 

pressures are low owing to shallow burial 

depths and recovery efficiencies will 

accordingly be quite low. The recoverable 

biogenic gas endowment of play 4 is 

therefore assessed as negligible, as shown in 

table 6 and figure 43. 

Play 5: Mesozoic Deformed Sedimentary 

Rocks (Triassic-Cretaceous)

Play 5 contributes 1.8% (41 Mmboe) to the 

hydrocarbon energy endowment (2,287 

Mmboe) of the North Aleutian Basin OCS 

 59
Planning Area. The play hydrocarbon 

energy endowment (risked, recoverable) 

ranges from 0 Mmboe (F95) to 197 Mmboe 

(F05), as shown in figure 44A. Gas 

(solution gas only) forms 7% of the 

hydrocarbon energy endowment of play 5. 

In the computer simulation for play 5, each 

of the 3,923 successful trials is comprised of 

one or more pools (or “hits”), for a total of 

14,327 pools sampled for size (tbl. 21). 

These pools can be grouped and displayed 

as size classes, as shown in the histogram of 

figure 44B. Pool size class 10 contains the 

largest share (3,088, or 22%) of pools 

“discovered” among the 10,000 trials 

conducted by the computer simulation for 

play 5. Pool size class 10 ranges from 16 to 

32 Mmboe. Pool count statistics for the play 

5 simulation are shown in table 21. The 

largest pool among the 14,327 pools or 

“hits” in the computer simulation for play 5 

falls within pool size class 16, which ranges 

in size from 1,024 to 2,048 Mmboe (tbl. 21

and fig. 44B). The computer simulation 

therefore indicates an extremely lowprobability potential for modest to large 

(sub-multi-billion barrel) hydrocarbon pools 

in play 5. 

A maximum of 13 hypothetical pools is 

forecast by the aggregation of the risk model 

and the prospect numbers model (tbl. 7) for 

play 5, as shown in figure 44C. These pools 

range in mean conditional (un-risked) 

recoverable volumes from 2 Mmboe (pool 

rank 13) to 63 Mmboe (pool rank 1). Pool 

rank 1 (fig. 44C) ranges in possible 

conditional recoverable volumes from 8 

Mmboe (F95) to 176 Mmboe (F05), or, in 

the case of gas, from 0.04 Tcfge (F95) to 

0.99 Tcfge (F05). Data for the size ranges 

of the play 5 pools are given in table 22. 

Overall, it seems unlikely that any sizeable 

pools of hydrocarbons will be found in play 

5—mostly because of the poor reservoir 

capacities forecast by the observed regional 

zeolitization and wholesale pore occlusion 

in Mesozoic sandstones. The Mesozoic 

assemblage of play 5 includes rocks that are 

age-equivalent to established regional oil 

sources. Although the age-equivalent rocks 

in play 5 have not been securely 

demonstrated to be significant sources for 

oil in the area of the North Aleutian basin, it 

is most likely that if any pools exist in play 

5, they will consist of oil. 

Play 6: Mesozoic Buried Granitic Hills 

(Jurassic-Cretaceous Magmatic Rocks)

Play 6 is a subordinate play in the North 

Aleutian Basin OCS Planning Area with 3% 

(67 Mmboe) of the Planning Area 

hydrocarbon energy endowment (2,287 

Mmboe). The play hydrocarbon energy 

endowment (risked, recoverable) ranges 

from 0 Mmboe (F95) to 330 Mmboe (F05), 

as shown in figure 45A. Gas (“nonassociated” [free] gas and solution gas) 

forms 55% of the hydrocarbon energy 

endowment of play 6. 

In the computer simulation for play 6, each 

of the 3,427 successful trials is comprised of 

one or more pools (or “hits”), for a total of 

13,089 pools sampled for size (tbl. 23). 

These pools can be grouped and displayed 

as size classes, as shown in the histogram of 

figure 45B. Pool size class 10 contains the 

largest share (2,483, or 19%) of pools 

“discovered” among the 10,000 trials 

conducted by the computer simulation for 

play 6. Pool size class 10 ranges from 16 to 

32 Mmboe. Pool count statistics for the play 

6 simulation are shown in table 23. The 4 

largest pools among the 13,089 pools or 

“hits” in the computer simulation for play 6 

falls within pool size class 18, which ranges 

in size from 4,096 to 8,192 Mmboe. The 

computer simulation therefore indicates a 

 60
low probability (effectively zero) for very 

large hydrocarbon pools in play 6. 

A maximum of 15 hypothetical pools is 

forecast by the aggregation of the risk model 

and the prospect numbers model (tbl. 8) for 

play 6, as shown in figure 45C. These pools 

range in mean conditional (un-risked) 

recoverable volumes from 2 Mmboe (pool 

rank 15) to 148 Mmboe (pool rank 1). Pool 

rank 1 (fig. 45C) ranges in possible 

conditional recoverable volumes from 9 

Mmboe (F95) to 469 Mmboe (F05), or, in 

the gas case, from 0.05 Tcfge (F95) to 2.64 

Tcfge (F05). Data for the size ranges of the 

play 6 pools are given in table 24. At low 

probabilities, we observe some potential for 

modest-size pools of hydrocarbons in play 

6—their modest sizes owing mostly to the 

doubtful capacity of the fractured granites 

that are conjectured to form the reservoirs 

for play 6 pools. Play 6 is Tertiary-sourced 

and is modeled as gas prone, so the largest 

pool is most likely to be charged by gas. 

Overall Results for Oil and Gas 

Endowments of North Aleutian Basin

Graphical summaries for overall basin 

hydrocarbon endowments (risked, 

recoverable) are shown in figure 46. Total 

Planning Area technically recoverable 

hydrocarbon resources range from 91 

Mmboe (F95) to 6,647 Mmboe (F05), with a 

mean outcome of 2,287 Mmboe (fig. 46A). 

At mean values, 67% of the hydrocarbon 

energy endowment is gas (“non-associated” 

[free] gas and solution gas from oil) and 

33% is liquid petroleum (free oil and 

condensate from gas). The North Aleutian 

Basin OCS Planning Area is overall a gasprone province, although some subordinate 

plays are primarily oil plays. 

Technically recoverable gas resources for 

the North Aleutian Basin OCS Planning 

Area range from 0.404 Tcfg (F95) to 23.278 

Tcfg (F05), with a mean outcome of 8.622 

Tcfg (fig. 46B). Table 14 separates gas 

commodities and shows that at mean values, 

97% (8.393 Tcfg) of the gas endowment 

exists as “non-associated” [free] gas, with 

the remaining 3% (0.229 Tcfg) dissolved as 

solution gas in free oil. 

Technically recoverable liquid petroleum 

resources for the North Aleutian Basin OCS 

Planning Area range from 19 Mmbo (F95) 

to 2,505 Mmbo (F05), with a mean outcome 

of 751 Mmbo (fig. 46C). Table 14 separates 

liquid petroleum commodities and shows 

that at mean values, 72% (545 Mmbo) of the 

liquid petroleum exists as free oil, with the 

remaining 28% (208 Mmbo) dissolved as 

condensate in free gas. 

A comparative plot for cumulative 

probability distributions for liquid petroleum 

(oil and condensate), total petroleum energy 

(BOE, all gas and liquids), and total gas 

(free gas and solution gas) is shown in figure 

46D. 

Large Individual Gas Fields Are Possible

Play 1, the Bear Lake-Stepovak play, 

captures most of the large prospects in the 

central part of the North Aleutian basin. 

The mean conditional (un-risked) size of the 

largest hypothetical pool in play 1 (and the 

North Aleutian basin overall) is 4.65 

trillions of cubic feet of natural gas (or 827 

millions of barrels [oil-energy-equivalent]). 

As shown in the pool rank plot in figure 47, 

the largest hypothetical pool is nearly twice 

the size of the largest gas field in Cook Inlet 

(Kenai gas field, 2.427 Tcfg EUR). At 

maximum (F05) size, the largest pool in play 

1 could contain 14.02 trillions of cubic feet 

of natural gas (or 2.495 billions of barrels 

 61
[oil-energy-equivalent]). 

Economic Potential of North Aleutian 

Basin

The hypothetical infrastructure model for 

the 2006 MMS economic assessment is 

illustrated in the map of figure 48. Our 

infrastructure model, although a likely 

scenario, was constructed only for the 

purpose of conducting economic tests and is 

not necessarily a predictor of actual future 

installations. The model assumes that 

several prospects that were leased in 1988 

(since relinquished untested back to the U.S. 

Government) are found to contain 

commercial gas reserves. Development 

platforms (with some subsea completions 

over field margins) send production to an 

offshore hub that is centrally located over 

the prospect that garnered the highest bids in 

the 1988 lease sale. Trunk pipelines (gas 

and oil) link the offshore hub to gas 

conditioning facilities and a liquefiednatural-gas (LNG) plant at a port in Balboa 

Bay on the Pacific (south) coast of the 

Alaska Peninsula (fig. 48). At the LNG 

plant, the natural gas is chilled to a liquid 

state (-260°F) preparatory to loading into 

tankers. The LNG tankers then convey the 

gas to receiving and re-gasification 

terminals either at Nikiski in Cook Inlet 

(550 mi. tanker sailing) or on the U.S. West 

Coast (assumed 2,600 mi. tanker sailing). 

Minimum transportation tariffs in the 

economic model represent a Cook Inlet 

destination while the maximum tariffs 

represent a U.S. West Coast destination. 

The Cook Inlet market is isolated and small, 

typically consuming a little over 200 Bcfg/yr 

(Sherwood and Craig, 2001, tbl. 5). It is 

unlikely that the entire North Aleutian basin 

production stream (estimated at 150 

Bcfg/yr) could be absorbed by the Cook 

Inlet market. Most North Aleutian basin gas 

would likely be marketed to the U.S. West 

Coast, Hawaii, or perhaps even the Asian 

Pacific Rim. However, the Cook Inlet 

would form a logical and accessible 

alternative destination for some fraction of 

the production from North Aleutian basin. 

Condensate and oil are assumed to be loaded 

at Balboa Bay and tankered to Cook Inlet or 

perhaps to the oil loading terminal for the 

Trans-Alaska oil pipeline system (TAPS) at 

Valdez, Alaska (located in figs. 1, 4). 

A summary of the results of the economic 

modeling for the North Aleutian basin are 

shown in table 25. Economic modeling 

yields first positive economic results at 

prices of $14/barrel of oil and $2.12/Mcf of 

associated solution gas. Non-associated gas 

pools yield first positive economic results at 

a gas price of $3.63/Mcf (tbl. 25). In any 

case, these “threshold” prices correspond to 

very small risked volumes of gas, 

condensate, and oil. Meaningful volumes of 

gas (>1 Tcfg) are not economically 

recoverable until prices exceed $4.54/Mcfg 

(tbl. 25). 

A minimum developable gas reserve of 5 

Tcf will probably be required to justify a 

grassroots LNG export system in the remote 

frontier area of the North Aleutian basin. 

The 5 Tcf of gas will presumably be 

supplied by several fields. Our economic 

analysis indicates that economic recovery of 

5 Tcf of gas will require prices of $6.50/Mcf 

and $43/barrel (2005$) landed at the U.S. 

West Coast. Current gas prices do exceed 

$6.50/Mcf by a wide margin (recent gas 

prices at the Los Angeles city gate exceed 

$13.00/Mcf; Natural Gas Week, 19 

December 2005). If market prices can be 

sustained at the current level or higher, a 

large fraction of the North Aleutian basin 

 62
gas endowment could ultimately be 

economically recoverable.

 63
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 70
Table 1: North Aleutian Basin and Alaska Peninsula Exploration Wells, 1903-1983

Operator and Well Name Year Completed Location Kelly Bushing Elevation; Age and Name, Surface Formation Total D

For

Pacific Oil and Commercial Pacific Oil No. 1 1903 NW/4 Sec. 3, T29S, R40W Ground level(?); M. Jurassic, Shelikof Fm. 1421 feet; MJ.H. Costello Costello No. 1 1903 NW/4 Sec. 10,T29S, R40W Ground level(?); M. Jurassic, Shelikof Fm. 728 feet;M. JPacific Oil and Commercial Pacific Oil No. 2 1904 SE/4 Sec. 3, T29S, R40W Ground level(?);M. Jurassic, Shelikof Fm. 1542 feet;M. J.H. Costello Costello No. 2 1904 SE/4 Sec. 10, T29S, R40W Ground level(?);M. Jurassic, Shelikof Fm. TD Unknown

Standard Lathrop No. 1 1923 SE/4 Sec. 17, T29S, R43W Ground level(?); U. Jurassic, Naknek Fm. 500 feet; U. J

Tidewater Associated Finnegan No. 1 1923 NE/4 Sec. 30, T29S, R43W Ground level(?); U. Jurassic, Naknek Fm. 560 feet; U. JStandard Oil McNally No. 1 1925 NW/4 Sec. 29, T29S, R43W Ground level(?); U. Jurassic Naknek Fm. 510 feet; U. JTidewater Associated Alaska No.1 1925 SW/4 Sec.20, T29S, R43W Ground level, 694 ft; U. Jurassic, Naknek Fm. 3033 feet; MStandard Lee No. 1 1926 SW/4 Sec.20, T29S, R43W Ground level, 764 ft; U. Jurassic, Naknek Fm. 5053 feet; MStandard, et. al. Grammer No. 1 1940 Sec. 10, T30S, R41W 375 feet; M. Jurassic, Shelikof Fm. 7596 feet; Lo

Humble-Shell Bear Creek Unit No. 1 1959 Sec 36, T29S, R41W 927 feet; M. Jurassic, Shelikof Fm. 14,374 feet; T

General Petroleum Great Basins No. 1 1959 Sec. 2, T27S, R48W 231 feet; Quaternary, Un-named Alluvium 11,080 feet; M

General Petroleum Great Basins No. 2 1959 Sec. 35, T25S, R50W 105 feet; Quaternary, Un-named Alluvium 8865 feet; Me

Pure Canoe Bay No. 1 1961 Sec. 8, T54S, R78W 1221 feet; U. Cretaceous, Hoodoo Fm. 6642 feet; U. 

Richfield Wide Bay Unit No. 1 1963 Sec. 5, T33S, R44W 54 feet; M. Jurassic, Kialagvik Fm. 12,568 feet; TGulf Sandy River Federal No. 1 1963 Sec. 10, T46S, R70W 235 feet; Quaternary, Un-named Alluvium 13,068 feet; O

Great Basins Ugashik No. 1 1966 Sec. 8, T32S, R52W 142 feet; Quaternary, Un-named Alluvium 9476 feet; OlCities Service Painter Creek No. 1 1967 Sec. 14, T35S, R51W 394 feet; Pliocene, Milky River Fm. 7912 feet; U. 

Pan American David River No. 1 & No. 1-A 1969 Sec. 12, T50S, R80W 70 feet; Pliocene, Milky River Fm. 13,769 feet; (

Pan American Hoodo Lake No. 1 1970 Sec. 21, T50S, R76W 141 feet; Pliocene, Milky River Fm. 8048 feet; OlPan American Hoodoo Lake No. 2 1970 Sec. 35, T50S, R76W 345 feet; Pliocene, Milky River Fm. 11,234 feet; U

Gulf Port Heiden Unit No. 1 1972 Sec. 20, T37S, R59W 36 feet; Quaternary, Un-named Alluvium 15,015 feet; O

Amoco Cathedral River No. 1 1974 Sec. 29, T51S, R83W 178 feet; U. Jurassic, Naknek Fm. 14,301 feet; TPhillips Big River No. A-1 1977 Sec 15, T49S, R68W 281 feet; Oligocene, Stepovak Fm. 11,371 feet; U

Chevron Koniag No. 1 1981 Sec. 2, T38S, R49W 62 feet; U. Jurassic, Naknek Fm. 10,905 feet; T

Amoco Becharof No. 1 1985 Sec. 15, T28S, R48W 220 feet; Quaternary, Un-named Alluvium 9022 feet; Me

Arco North Aleutian Basin COST No. 1 1983 56.724o N. Lat., 171.976o W. Long. 74 feet; Quaternary-Pleistocene, Marine Mud 17,155 feet; E

Table adapted from Molenaar (1996b, tbl. 1)

Offshore Wells

71
Table 2: Summary of Selected Extract Data, North Aleutian Shelf COST 

Del13C Del13

C

SAT

ARO

MMSAK2003-1 Core 16006-16029 & 16701.2-16720 6.82 1.16 92.02 -28.5 -27.3 2.65 MMSAK2003-2 Cuttings 15700-16800 56.21 9.26 34.53 -28.0 -26.9 3.75 RR-1 Core 15354.6 2.6 43.9 53.5 NA NA 9.30 RR-2 Core 15368.5 9.9 37.3 52.8 NA NA 6.54 RR-3 Core 16009.3 19.1 33.7 47.2 NA NA 5.00 RR-4 Core 16029 31.3 32 36.7 NA NA 3.85 RR-5 Core 16703.7 21.4 57.4 21.2 NA NA 2.78 RR-6 Core 16714.6 14.8 25 60.2 NA NA 2.14 RR-7 Core 16719.6 37.4 21.6 41 NA NA 2.27 

MMSAK: Baseline-DGSI for Minerals Management Service, 2003RR: Roberston Research for ARCO and COST Well Consortium, 1983Thermal maturity of show interval = 0.78% to 1.04% vitrinite reflectance

ARO %

North Aleutian Shelf COST 1 Extract Data: Oil Show Interval 15,300-16,800 ft bkb

Spl. No. Depth/ Interval Spl. Type SAT % Pristane/ Phytane P

NSO + ASPH %

72
Table 3: Play 1, GRASP Play Data Form (Minerals Management Service-Alaska Regional Office)

Basin: North Aleutian Basin Assessor(s): K.W. Sherwood, D. Comer, J. Larson Date: December 2004

Play Number: 1 Play Name: Bear Lake-Stepovak (Oligocene-Miocene)

Play UAI Number: AAAAA HAB

Play Area: 14,820mi2 (9.5 million acres) Play Depth Range: 2,000-10,000 feet (mean = 6,000 ft)

Reservoir Thermal Maturity: 0.25%-0.48% Ro Expected Oil Gravity: 35O API

Play Water Depth Range: 15-300 feet (mean = 250 ft)

POOLS Module (Volumes of Pools, Acre-Feet)

Fractile F100 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 Prospect Area (acres)-Model Input* 3227 4249 10661 13794/11325 26750 

Prospect Area (acres)-Model Output** 989 3408 4394 6710 10825 13560/10075 17299 22441 26058 33526 Fill Fraction (Fraction of Area Filled) 0.17 0.28 0.3 0.34 0.4 0.41/0.10 0.48 0.51 0.53 0.6 Productive Area of Pool (acres) 247 1310 1706 2638 4299 5742/4972 7173 9421 11081 14063 Pay Thickness (feet) 3 21 29 52 98 151/180*** 184 258 324 340 * model fit to prospect area data in BESTFIT *** original fit to Cook Inlet data** output from @RISK after aggregation with fill fraction

MPRO Module (Numbers of Pools)

Input Play Level Chance 0.72 0.26 Output Play Level Chance 0.72

Risk Model

Fractile F99 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 Numbers of Prospects in Play 24 28 30 32 38 39/7.95 43 46 49 52 

Numbers of Pools in Play 8 7.30/5.40 11 13 14 15 

Zero Pools at F72.00

Minimum Number of Pools 4 (F70) 7.3 

POOLS/PSRK/PSUM Modules (Play Resources)

Fractile F100 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 Oil Recovery Factor (bbl/acre-foot) 89 212 247 319 424 465/209 564 657 728 848 Gas Recovery Factor (Mcfg/acre-foot) 279 578 657 812 1029 1093/399 1304 1480 1613 1832 Gas Oil Ratio (Sol'n Gas)(cf/bbl) 56 162 195 267 376 426/220 531 638 723 871 Condensate Yield ((bbl/Mmcfg) 1 14 17 21 25 25/7 29 32 34 35 BOE Conversion Factor (cf/bbl) 5620 0.1

Probability Any Pool is 100% Oil 0.1 0.9Probability Any Pool is 100% Gas 0.8

0.8 Seal (no regional seal over reservoir sequence) 0.

Play Chance Prospect 

0.9 Source (mainly Tertiary coals and Type III shales) 0.6

Prospect Level Chance Exploration Chance

Petroleum System Factors

Fraction of Pool Volume Gas-Bearing in Oil Pools with Gas CapProbability Any Pool Contains Both Oil and Free Gas (Gas Cap)

Migration (regional shale seal between source & reservoir)

Mean Number of Pools Maximum Number of Pools

0.

Pool Size Distribution Statistics from POOLS (1,000 BOE): μ (mu)= 11.439 σ2 (sigma squared)= 1.628 Random Number Gen

73
Table 4: Play 2, GRASP Play Data Form (Minerals Management Service-Alaska Regional Office)

Basin: North Aleutian Basin Assessor(s): K.W . Sherwood, D. Comer, J. Larson Date: Decem

Play Number: 2 Play Name: Tolstoi (Eocene-Oligocene)

Play UAI Number: AAAAA HAC

Play Area: 10,890 mi2 (7 million acres) Play Depth Range: 4,000 to 20,000 feet (mean = 12,000 ft)

Reservoir Thermal M aturity: 0.30%-1.65% Ro Expected Oil Gravity: 35 O API

Play Water Depth Range: 15-300 feet (mean = 250 ft)

POOLS Module (Volumes of Pools, Acre-Feet)

Fractile F100 F95 F90 F75 F50 M ean/Std. Dev. F25 F15 F10 Prospect Area (acres)- M odel Input* 6787 (act) 6567 (fit) 11169 15925/9790 28028

Prospect Area (acres)- M odel Output** 1518 5490 6647 9321 13549 15555/8547 19702 23776 27111 Fill Fraction (Fraction of Area Filled) 0.16 0.28 0.3 0.34 0.4 0.41/0.10 0.48 0.51 0.53 Productive Area of Pool (acres) 455 2031 2509 3631 5447 6442/3960 8173 10082 11572 Pay Thickness (feet) 31 49 53 60 69 71/17 80 86 91 

* m odel fit to prospect area data in BESTFIT** output from @ RISK after aggregation with fill fraction

MPRO Module (Numbers of Pools)

Input Play Level Chance 1 0.1404 

Output Play Level Chance 0.9906

Risk M odel

Fractile F99 F95 F90 F75 F50 M ean/Std. Dev. F25 F15 F10 

Numbers of Prospects in Play 16 20 23 30 40 43.65/19.72 51 60 65 

Numbers of Pools in Play 1 2 2 4 6 6.13/3.60 8 9 11 

Zero Pools at F99.06

M inim um Number of Pools 1 (F99.00) 6.13 

POOLS/PSRK/PSUM Modules (Play Resources)

Fractile F100 F95 F90 F75 F50 M ean/Std. Dev. F25 F15 F10 Oil Recovery Factor (bbl/acre-foot) 25 57 75 113 178 203/118 266 322 364 

Gas Recovery Factor (Mcfg/acre-foot) 18 351 433 630 921 997/497 1285 1509 1657 

Gas Oil Ratio (Sol'n Gas)(cf/bbl) 56 162 195 267 376 426/220 531 638 723 

Condensate Yield ((bbl/Mmcfg) 1 14 17 21 25 25/17 29 32 34 

BOE Conversion Factor (cf/bbl) 5620 

Probability Any Pool is 100% Oil 0.1 

Probability Any Pool is 100% Gas 0.8Pool Size Distribution Statistics from POOLS (1,000 BOE): μ (mu)= 11.079 σ2 (sigma squared)= 0.828 Random Nu

Prospect Level Chance Exploration 

Petroleum System Factors

Fraction of Pool Volum e Gas-Bearing in Oil Pools with Gas CapProbability Any Pool Contains Both Oil and Free Gas (Gas Cap)

Source (mainly Tertiary coals and Type III shales)

Mean Number of Pools M aximum Number o

Reservoir (impermeable through most of sequence) 

M inor gas pools tested (90 M cfg/d) in Becharof Lake 1 well

Play Chance 

74
Table 5: Play 3, GRASP Play Data Form (Minerals Management Service-Alaska Regional Office)

Basin: North Aleutian Basin Assessor(s): K.W. Sherwood, D. Comer, J. Larson Date: December 2004

Play Number: 3 Play Name: Black Hills Uplift - Amak Basin (Eocene-Miocene)

Play UAI Number: AAAAA HAD

Play Area: 6,990 mi2 (4.5 million acres) Play Depth Range: 2,000-12,500 feet (mostly 2,000-5,000 feet)

Reservoir Thermal Maturity: 0.23%-2.00% Ro (mostly 0.23%-0.31% Ro) Expected Oil Gravity: 35O API

Play Water Depth Range: 15-700 feet (mean = 350 ft)

POOLS Module (Volumes of Pools, Acre-Feet)

Fractile F100 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 Prospect Area (acres)-Model Input* 2667 (act) 2350 (fit) 5916 25230/48696 57316 Prospect Area (acres)-Model Output** 509 1643 2471 4869 11201 19995/23424 25426 38733 49245 70155 Fill Fraction (Fraction of Area Filled) 0.02 0.07 0.08 0.12 0.15 0.17/0.08 0.2 0.26 0.28 0.33 Productive Area of Pool (acres) 42 226 343 706 1734 3554/5194 4054 6211 8543 12700 Pay Thickness (feet) 3 21 29 52 98 151/180* 184 258 324 340 

* model fit to prospect area data in BESTFIT *** original fit to Cook Inlet data** output from @RISK after aggregation with fill fraction

MPRO Module (Numbers of Pools)

Input Play Level Chance 0.42 0.25 

Output Play Level Chance 0.4128

Risk Model

Fractile F99 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 Numbers of Prospects in Play 10 11 12 13 14 14.61/1.83 15 16 17 17.5 Numbers of Pools in Play 1.53/2.12 3 4 5 6 

Zero Pools at F41.28

Minimum Number of Pools 1 (F40.00) 1.53 

POOLS/PSRK/PSUM Modules (Play Resources)

Fractile F100 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 Oil Recovery Factor (bbl/acre-foot) 42 129 158 221 311 343/177 427 500 558 644 Gas Recovery Factor (Mcfg/acre-foot) 8 441 531 686 873 888/302 1074 1194 1271 1389 Gas Oil Ratio (Sol'n Gas)(cf/bbl) 56 162 195 267 376 426/220 531 638 723 871 Condensate Yield ((bbl/Mmcfg) 1 14 17 21 25 25/7 29 32 34 35 BOE Conversion Factor (cf/bbl) 5620 0.4

Probability Any Pool is 100% Oil 0.4 0.5Probability Any Pool is 100% Gas 0.2Pool Size Distribution Statistics from POOLS (1,000 BOE): μ (mu)= 10.662 σ2 (sigma squared)= 2.666 Random Number Gen

Prospect Level Chance Exploration Chance

Petroleum System Factors

Fraction of Pool Volume Gas-Bearing in Oil Pools with Gas CapProbability Any Pool Contains Both Oil and Free Gas (Gas Cap)

Mean Number of Pools Maximum Number of Pools

0.7 Seal (no regional seal over reservoir) 00.6 Migration (lengthy, highly-faulted path from Tertiary source) 0

Play Chance Prospec

75
Table 6: Play 4, GRASP Play Data Form (Minerals Management Service-Alaska Regional Office)

Basin: North Aleutian Basin Assessor(s): K.W. Sherwood, D. Comer, J. Larson Date: December 2004

Play Number: 4 Play Name: Milky River Biogenic Gas (Plio-Pleistocene)

Play UAI Number: AAAAA HAE

Play Area: 50,706 mi2 (32.45 million acres) Play Depth Range: 500-3,000 feet

Reservoir Thermal Maturity: 0.20%-0.26% Ro Expected Oil Gravity: 35O API

Play Water Depth Range: 15-700 feet

POOLS Module (Volumes of Pools, Acre-Feet)

Fractile F100 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 Prospect Area (acres)Fill Fraction (Fraction of Area Filled)Productive Area of Pool (acres)Pay Thickness (feet)

MPRO Module (Numbers of Pools)

Input Play Level Chance 0 0 Output Play Level Chance

Risk Model

Fractile F99 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 Numbers of Prospects in PlayNumbers of Pools in Play

Minimum Number of Pools 0 0

POOLS/PSRK/PSUM Modules (Play Resources)

Fractile F100 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 Oil Recovery Factor (bbl/acre-foot)Gas Recovery Factor (Mcfg/acre-foot)Gas Oil Ratio (Sol'n Gas)(cf/bbl)Condensate Yield ((bbl/Mmcfg)BOE Conversion Factor (cf/bbl) 5620 0

Probability Any Pool is 100% Oil 0 NA

Probability Any Pool is 100% Gas 1

Charge (No Structured Fetch to Potential Traps)

Prospect 

0

Petroleum System Factors

Seal (unconsolidated mud) 0

0 Gas recoverability (low pressure; water production)

Mean Number of Pools Maximum Number of Pools

00

Play 4 Not Quantified; Assessed to Have Negligible Undiscovered Technically Recoverable Biogenic Ga

No Identified Prospects

Play 4 Not Quantified; Assessed to Have Negligible Undiscovered Technically Recoverable Biogenic Ga

Fraction of Pool Volume Gas-Bearing in Oil Pools with Gas CapProbability Any Pool Contains Both Oil and Free Gas (Gas Cap)

0 Reservoir (poor continuity)

Play Chance

Prospect Level Chance Exploration Chance

Pool Size Distribution Statistics from POOLS (1,000 BOE): μ (mu)= NA σ2 (sigma squared)= NA Random Number Gen

76
Table 7: Play 5, GRASP Play Data Form (Minerals Management Service-Alaska Regional Office)

Basin: North Aleutian Basin Assessor(s): K.W. Sherwood, D. Comer, J. Larson Date: December 2004

Play Number: 5 Play Name: Mesozoic Deformed Sedimentary Rocks (Triassic-Cretaceous)

Play UAI Number: AAAAA HAF

Play Area: 5,040 mi2 (3.2 million acres) Play Depth Range: 2,000 to 15,000 feet (mean = 8,000 ft)

Reservoir Thermal Maturity: 0.6% to 2.0% Ro Expected Oil Gravity: 35O API

Play Water Depth Range: 15-700 feet (mean = 350 ft)

POOLS Module (Volumes of Pools, Acre-Feet)

Fractile F100 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 Prospect Area (acres)-Model Input* 7000 10415 39621 68223/95634 150718 

Prospect Area (acres)-Model Output** 1024 6793 9768 18402 35028 44767/33824 63167 82991 97444 116497 

Fill Fraction (Fraction of Area Filled) 0.03 0.05 0.06 0.08 0.1 0.11/0.05 0.13 0.16 0.17 0.2 Productive Area of Pool (acres) 93 595 902 1736 3478 5004/4766 6596 9087 10687 13683 Pay Thickness (feet) 18 47 55 73 100 113/60 137 162 182 215 

* model fit to prospect area data in BESTFIT** output from @RISK after aggregation with fill fraction

MPRO Module (Numbers of Pools)

Input Play Level Chance 0.4 0.2304 

Output Play Level Chance 0.3925

Risk Model

Fractile F99 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 Numbers of Prospects in Play 11 12 13 14 15 15.56/1.76 16 17 17.5 18 Numbers of Pools in Play 1.43/2.06 3 4 5 6 

Zero Pools at F39.25

Minimum Number of Pools 2 (F35) 1.43 

POOLS/PSRK/PSUM Modules (Play Resources)

Fractile F100 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 Oil Recovery Factor (bbl/acre-foot) 1 17 21 30 43 47/25 59 69 77 89 

Gas Recovery Factor (Mcfg/acre-foot)Gas Oil Ratio (Sol'n Gas)(cf/bbl) 56 162 195 267 376 426/220 531 638 723 871 Condensate Yield ((bbl/Mmcfg)BOE Conversion Factor (cf/bbl) 5620 0Probability Any Pool is 100% Oil 1 0Probability Any Pool is 100% Gas 0

Preservation (denudation to shallow depths/biodegradation of petroleum 

accumulations in Mesozoic rocks) 0.

Mean Number of Pools Maximum Number of Pools

Trap integrity (erosional breaching and fault disruption) 0.

Prospect Level Chance Exploration Chance

Prospect 

Reservoir (widespread early zeolitization) 0.

0.8

Petroleum System Factors

Timing of migration (if early, no traps; if late, no porosity) 0.

0.5

Play Chance

No Free GasNo Free Gas

Fraction of Pool Volume Gas-Bearing in Oil Pools with Gas CapProbability Any Pool Contains Both Oil and Free Gas (Gas Cap)

Pool Size Distribution Statistics from POOLS (1,000 BOE): μ (mu)= 9.564 σ2 (sigma squared)= 1.609 Random Number Gen

77
Table 8: Play 6, GRASP Play Data Form (Minerals Management Service-Alaska Regional Office)

Basin: North Aleutian Basin Assessor(s): K.W. Sherwood, D. Comer, J. Larson Date: December 2004

Play Number: 6 Play Name: Mesozoic Buried Granitic Hills (Jurassic-Cretaceous Magmatic Rocks)

Play UAI Number: AAAAA HAG

Play Area: 46,810 mi2 (30 million acres) Play Depth Range: 6,000-12,000 feet (mean = 9,000 ft)

Reservoir Thermal Maturity: Fractured Granite Reservoir Expected Oil Gravity: 35O API

(0.34%-0.60% Ro projected from depth range) Play Water Depth Range: 15-400 feet (mean = 300 ft)

POOLS Module (Volumes of Pools, Acre-Feet)

Fractile F100 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 Prospect Area (acres)-Model Input* 4000 5537 13119 16454/12456 31082 

Prospect Area (acres)-Model Output** 1281 4235 5538 8339 13240 16493/11905 21097 27029 31445 39296 Fill Fraction (Fraction of Area Filled) 0.02 0.07 0.08 0.12 0.15 0.17/0.08 0.2 0.25 0.28 0.33 Productive Area of Pool (acres) 108 523 696 1157 2008 2838/2846 3473 4615 5690 7550 Pay Thickness (feet) 88 115 142 184 254 276/116 351 405 435 505 * model fit to prospect area data in BESTFIT** output from @RISK after aggregation with fill fraction

MPRO Module (Numbers of Pools)

Input Play Level Chance 0.35 0.117 

Output Play Level Chance 0.3428

Risk Model

Fractile F99 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 Numbers of Prospects in Play 24 26 27 29 32 31.99/3.62 33 34 36 38 

Numbers of Pools in Play 1.31/2.10 3 4 5 6 

Zero Pools at F34.28

Minimum Number of Pools 2 (F30) 1.31 

POOLS/PSRK/PSUM Modules (Play Resources)

Fractile F100 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 Oil Recovery Factor (bbl/acre-foot) 5 31 43 81 158 228/191 310 444 580 610 Gas Recovery Factor (Mcfg/acre-foot) 3 27 38 73 146 218/193 290 420 541 620 Gas Oil Ratio (Sol'n Gas)(cf/bbl) 56 162 195 267 376 426/220 531 638 723 871 Condensate Yield ((bbl/Mmcfg) 1 14 17 21 25 25/7 29 32 34 35 BOE Conversion Factor (cf/bbl) 5620 0.1Probability Any Pool is 100% Oil 0.1 0.9

Probability Any Pool is 100% Gas 0.8

Petroleum System Factors

Source (mainly Tertiary coals and Type III shales) 0.6

0.35 Reservoir (granites fractured with weathering enhancement) 0

Play Chance

Fraction of Pool Volume Gas-Bearing in Oil Pools with Gas CapProbability Any Pool Contains Both Oil and Free Gas (Gas Cap)

Migration (fault migration paths must both transmit [deep] and seal [shallow])

Pool Size Distribution Statistics from POOLS (1,000 BOE): μ (mu)= 9.814 σ2 (sigma squared)= 2.170 Random Number Gen

Prospect Level Chance Exploration Chance

Mean Number of Pools Maximum Number of Pools

0

Prospect 

78
Table 9: DATA SHEET FOR @RISK MODELS FOR OIL AND GAS RECOVERY FACTORS FOR PLAY 1

Assessment Area: North Aleutian Basin Date: December 2003

Play: 1 - Bear Lake-Stepovak (Oligocene-Miocene)

Assessors: K.W. Sherwood, D. Comer, J. Larson

Oil Recovery Factor (barrels recoverable per acre-foot)

Input Constant and @RISK Equation: "=7758.38*a2*(1-b2)*c2*d2"

Mean Standard 

Deviation Minimum Maximum f(x) Type

a Porosity 0.314705 0.053704 0.010 0.414 T-Normal

b Water Saturation 0.343750 0.059615 0.030 0.700 T-L-Normal

c Oil Recovery Efficiency 0.346810 0.057227 0.050 0.650 T-L-Normal

d Oil Volume Factor [1/FVF] 0.793075 0.094369 0.500 1.000 T-Normal

Dependency or Correlation Matrix for Oil Recovery Factor Calculation

Porosity Water 

Saturation

Oil Recovery 

Efficiency

Oil Volume 

Factor [1/FVF]

a Porosity 1 -0.9 0.9 0

b Water Saturation -0.9 1 -0.8 0

c Oil Recovery Efficiency 0.9 -0.8 1 0

d Oil Volume Factor [1/FVF] 00 0 1

Gas Recovery Factor (mcfg recoverable per acre-foot)

Input Constant and @RISK Equation: "=1537.8*a2*(1-b2)*c2*d2*e2*(1-f2)/g2"

Mean Standard 

Deviation Minimum Maximum f(x) Type

a Porosity 0.314705 0.053704 0.100 0.414 T-Normal

b Water Saturation 0.343750 0.059615 0.030 0.700 T-L-Normal

c Pressure (psi) 2609.400000 438.190000 878.000 4390.000 T-Normal

d Gas FVF (1/Z) 1.079112 0.028545 0.960 1.200 T-Normal

e Gas Recovery Efficiency 0.797408 0.038362 0.650 0.950 T-Normal

f Gas Shrinkage Factor* 0.126230 0.161910 0.000 1.000 T-L-Normal

g Temperature (oRankine) 594.101000 18.089000 525.000 664.000 T-Normal

Dependency or Correlation Matrix for Gas Recovery Factor Calculation

Porosity Water 

Saturation Pressure (psi) Gas FVF (1/Z) Gas Recovery Efficiency

Gas 

Shrinkage 

Factor*

Temperature 

(oRankine)

a Porosity 1 -0.9 0 0 0.80 0

b Water Saturation -0.9 1 0 0 -0.6 0 0

c Pressure (psi) 0 0 1 0 0 00.95

d Gas FVF (1/Z) 0 0 0 1 00 0

e Gas Recovery Efficiency 0.8 -0.6 0 0 1 0 0

f Gas Shrinkage Factor* 0 0 0 0 01 0

g Temperature (oRankine) 0 0 0.95 0 0 0 1

* Includes gas volume lost to condensate drop-out and content of inert gases (Nitrogen, Oxygen, Argon, Hydrogen Sulfide, Carbon Dioxide, and Helium)

79
Table 10: DATA SHEET FOR @RISK MODELS FOR OIL AND GAS RECOVERY FACTORS FOR PLAY 2

Assessment Area: North Aleutian Basin Date: December 2003

Play: 2 - Tolstoi (Eocene-Oligocene)

Assessors: K.W. Sherwood, D. Comer, J. Larson

Oil Recovery Factor (barrels recoverable per acre-foot)

Input Constant and @RISK Equation: "=7758.38*a2*(1-b2)*c2*d2"

Mean Standard 

Deviation Minimum Maximum f(x) Type

a Porosity 0.213296 0.080897 0.100 0.335 T-Normal

b Water Saturation 0.452190 0.051720 0.060 0.700 T-L-Normal

c Oil Recovery Efficiency 0.254150 0.060354 0.050 0.650 T-L-Normal

d Oil Volume Factor [1/FVF] 0.793075 0.094369 0.500 1.000 T-Normal

Dependency or Correlation Matrix for Oil Recovery Factor Calculation

Porosity Water 

Saturation

Oil Recovery 

Efficiency

Oil Volume 

Factor [1/FVF]

a Porosity 1 -0.9 0.9 0

b Water Saturation -0.9 1 -0.8 0

c Oil Recovery Efficiency 0.9 -0.8 1 0

d Oil Volume Factor [1/FVF] 00 0 1

Gas Recovery Factor (mcfg recoverable per acre-foot)

Input Constant and @RISK Equation: "=1537.8*a2*(1-b2)*c2*d2*e2*(1-f2)/g2"

Mean Standard 

Deviation Minimum Maximum f(x) Type

a Porosity 0.213296 0.080897 0.100 0.335 T-Normal

b Water Saturation 0.452190 0.051720 0.060 0.700 T-L-Normal

c Pressure (psi) 7432.000000 1388.500000 1756.000 13000.000 T-Normal

d Gas FVF (1/Z) 0.935260 0.107430 0.500 1.360 T-Normal

e Gas Recovery Efficiency 0.603219 0.051470 0.400 0.800 T-Normal

f Gas Shrinkage Factor* 0.126230 0.161910 0.000 1.000 T-L-Normal

g Temperature (oRankine) 700.150000 32.112000 563.000 834.000 T-Normal

Dependency or Correlation Matrix for Gas Recovery Factor Calculation

Porosity Water 

Saturation Pressure (psi) Gas FVF (1/Z) Gas Recovery Efficiency

Gas 

Shrinkage 

Factor*

Temperature 

(oRankine)

a Porosity 1 -0.9 0 0 0.80 0

b Water Saturation -0.9 1 0 0 -0.6 0 0

c Pressure (psi) 0 0 1 0 0 00.95

d Gas FVF (1/Z) 0 0 0 1 00 0

e Gas Recovery Efficiency 0.8 -0.6 0 0 1 0 0

f Gas Shrinkage Factor* 0 0 0 0 01 0

g Temperature (oRankine) 0 0 0.95 0 0 0 1

* Includes gas volume lost to condensate drop-out and content of inert gases (Nitrogen, Oxygen, Argon, Hydrogen Sulfide, Carbon Dioxide, and Helium)

80
Table 11: DATA SHEET FOR @RISK MODELS FOR OIL AND GAS RECOVERY FACTORS FOR PLAY 3

Assessment Area: North Aleutian Basin Date: December 2003

Play: 3 - Black Hills Uplift - Amak Basin (Eocene-Miocene)

Assessors: K.W. Sherwood, D. Comer, J. Larson

Oil Recovery Factor (barrels recoverable per acre-foot)

Input Constant and @RISK Equation: "=7758.38*a2*(1-b2)*c2*d2"

Mean Standard 

Deviation Minimum Maximum f(x) Type

a Porosity 0.314705 0.053704 0.100 0.414 T-Normal

b Water Saturation 0.343750 0.059615 0.030 0.700 T-L-Normal

c Oil Recovery Efficiency 0.254150 0.060354 0.050 0.650 T-L-Normal

d Oil Volume Factor [1/FVF] 0.793075 0.094369 0.500 1.000 T-Normal

Dependency or Correlation Matrix for Oil Recovery Factor Calculation

Porosity Water 

Saturation

Oil Recovery 

Efficiency

Oil Volume 

Factor [1/FVF]

a Porosity 1 -0.9 0.9 0

b Water Saturation -0.9 1 -0.8 0

c Oil Recovery Efficiency 0.9 -0.8 1 0

d Oil Volume Factor [1/FVF] 00 0 1

Gas Recovery Factor (mcfg recoverable per acre-foot)

Input Constant and @RISK Equation: "=1537.8*a2*(1-b2)*c2*d2*e2*(1-f2)/g2"

Mean Standard 

Deviation Minimum Maximum f(x) Type

a Porosity 0.314709 0.053704 0.100 0.414 T-Normal

b Water Saturation 0.343750 0.059615 0.030 0.700 T-L-Normal

c Pressure (psi) 1502.800000 155.320000 878.000 2195.000 T-Normal

d Gas FVF (1/Z) 1.450000 0.015716 1.370 1.520 T-Normal

e Gas Recovery Efficiency 0.797408 0.038362 0.650 0.950 T-Normal

f Gas Shrinkage Factor* 0.126230 0.161910 0.000 1.000 T-L-Normal

g Temperature (oRankine) 552.479700 6.622400 525.000 581.000 T-Normal

Dependency or Correlation Matrix for Gas Recovery Factor Calculation

Porosity Water 

Saturation Pressure (psi) Gas FVF (1/Z) Gas Recovery 

Efficiency

Gas 

Shrinkage 

Factor*

Temperature 

(oRankine)

a Porosity 1 -0.9 0 0 0.80 0

b Water Saturation -0.9 1 0 0 -0.6 0 0

c Pressure (psi) 0 0 1 0 0 00.95

d Gas FVF (1/Z) 0 0 0 1 00 0

e Gas Recovery Efficiency 0.8 -0.6 0 0 1 0 0

f Gas Shrinkage Factor* 0 0 0 0 01 0

g Temperature (oRankine) 0 0 0.95 0 0 0 1

* Includes gas volume lost to condensate drop-out and content of inert gases (Nitrogen, Oxygen, Argon, Hydrogen Sulfide, Carbon Dioxide, and Helium)

81
Table 12: DATA SHEET FOR @RISK MODELS FOR OIL AND GAS RECOVERY FACTORS FOR PLAY 5

Assessment Area: North Aleutian Basin Date: December 2003

Play: 5 - Mesozoic Deformed Sedimentary Rocks (Triassic-Cretaceous)

Assessors: K.W. Sherwood, D. Comer, J. Larson

Oil Recovery Factor (barrels recoverable per acre-foot)

Input Constant and @RISK Equation: "=7758.38*a2*(1-b2)*c2*d2"

Mean Standard 

Deviation Minimum Maximum f(x) Type

a Porosity 0.075664 0.019040 0.000 0.150 T-Normal

b Water Saturation 0.531180 0.042925 0.400 0.700 T-L-Normal

c Oil Recovery Efficiency 0.206220 0.033169 0.100 0.400 T-L-Normal

d Oil Volume Factor [1/FVF] 0.793075 0.094367 0.556 0.901 T-Normal

Dependency or Correlation Matrix for Oil Recovery Factor Calculation

Porosity Water 

Saturation

Oil Recovery 

Efficiency

Oil Volume 

Factor [1/FVF]

a Porosity 1 -0.9 0.9 0

b Water Saturation -0.9 1 -0.8 0

c Oil Recovery Efficiency 0.9 -0.8 1 0

d Oil Volume Factor [1/FVF] 00 0 1

Gas Recovery Factor (mcfg recoverable per acre-foot)

Input Constant and @RISK Equation: "=1537.8*a2*(1-b2)*c2*d2*e2*(1-f2)/g2"

Mean Standard 

Deviation Minimum Maximum f(x) Type

a Porosity T-Normal

b Water Saturation T-L-Normal

c Pressure (psi) T-Normal

d Gas FVF (1/Z) T-Normal

e Gas Recovery Efficiency T-Normal

f Gas Shrinkage Factor* T-L-Normal

g Temperature (oRankine) T-Normal

Dependency or Correlation Matrix for Gas Recovery Factor Calculation

Porosity Water 

Saturation Pressure (psi) Gas FVF (1/Z) Gas Recovery 

Efficiency

Gas 

Shrinkage 

Factor*

Temperature 

(oRankine)

a Porosity 1 -0.9 0 0 0.80 0

b Water Saturation -0.9 1 0 0 -0.6 0 0

c Pressure (psi) 0 0 1 0 0 00.95

d Gas FVF (1/Z) 0 0 0 1 00 0

e Gas Recovery Efficiency 0.8 -0.6 0 0 1 0 0

f Gas Shrinkage Factor* 0 0 0 0 01 0

g Temperature (oRankine) 0 0 0.95 0 0 0 1

* Includes gas volume lost to condensate drop-out and content of inert gases (Nitrogen, Oxygen, Argon, Hydrogen Sulfide, Carbon Dioxide, and Helium)

No Free Gas

82
83

a Porosity 1 -0.9 0.9 0

b Water Saturation -0.9 1 -0.8 0

c Oil Recovery Efficiency 0.9 -0.8 1 0

d Oil Volume Factor [1/FVF] 00 0 1

Gas Recovery Factor (mcfg recoverable per acre-foot)

Input Constant and @RISK Equation: "=1537.8*a2*(1-b2)*c2*d2*e2*(1-f2)/g2"

Mean Standard 

Deviation Minimum Maximum f(x) Type

a Porosity T-Normal

b Water Saturation T-L-Normal

c Pressure (psi) T-Normal

d Gas FVF (1/Z) T-Normal

e Gas Recovery Efficiency T-Normal

f Gas Shrinkage Factor* T-L-Normal

g Temperature (oRankine) T-Normal

Dependency or Correlation Matrix for Gas Recovery Factor Calculation

Porosity Water 

Saturation Pressure (psi) Gas FVF (1/Z) Gas Recovery 

Efficiency

Gas 

Shrinkage 

Factor*

Temperature 

(oRankine)

a Porosity 1 -0.9 0 0 0.80 0

b Water Saturation -0.9 1 0 0 -0.6 0 0

c Pressure (psi) 0 0 1 0 0 00.95

d Gas FVF (1/Z) 0 0 0 1 00 0

e Gas Recovery Efficiency 0.8 -0.6 0 0 1 0 0

f Gas Shrinkage Factor* 0 0 0 0 01 0

g Temperature (oRankine) 0 0 0.95 0 0 0 1

* Includes gas volume lost to condensate drop-out and content of inert gases (Nitrogen, Oxygen, Argon, Hydrogen Sulfide, Carbon Dioxide, and Helium)

Oil and Gas Yields From Literature Compilation and Analysis by 

Paul Post and Jesse Hunt of U.S. Minerals Management Service, 

Gulf of Mexico OCS Region

Table 13: DATA SHEET FOR @RISK MODELS FOR OIL AND GAS RECOVERY FACTORS FOR PLAY 6

Assessment Area: North Aleutian Basin Date: December 2003

Play: 6 - Mesozoic Buried Granitic Hills (Jurassic-Cretaceous Magmatic Rocks)

Assessors: K.W. Sherwood, D. Comer, J. Larson

Oil Recovery Factor (barrels recoverable per acre-foot)

Input Constant and @RISK Equation: "=7758.38*a2*(1-b2)*c2*d2"

Mean Standard 

Deviation Minimum Maximum f(x) Type

a Porosity T-Normal

b Water Saturation T-L-Normal

c Oil Recovery Efficiency T-L-Normal

d Oil Volume Factor [1/FVF] T-Normal

Dependency or Correlation Matrix for Oil Recovery Factor Calculation

Porosity Water 

Saturation

Oil Recovery 

Efficiency

Oil Volume 

Factor [1/FVF]

Oil and Gas Yields From Literature Compilation and Analysis by 

Paul Post and Jesse Hunt of U.S. Minerals Management Service, 

Gulf of Mexico OCS Region
84

Table 14: 2006 Assessment Results for North Aleutian Basin OCS Planning Area

Risked, Undiscovered, Technically Recoverable Oil and Gas Resources

Play 

Number Play Name F95 Mean F05 F95 Mean F05 F95 Mean F05 F95 Mean F05 F95 Mean F05 F95 Mean F05 F

1 Bear Lake-Stepovak (Oligocene-Miocene) 0 1400 3749 0 271 828 0 136 349 0.000 5.473 14.131 0.000 0.113 0.330 0 406 1176 0.0

2 Tolstoi (Eocene- Oligocene) 91 568 1293 9 62 139 10 61 141 0.401 2.476 5.640 0.003 0.025 0.053 19 123 280 0.4

3

Black Hills UpliftAmak Basin (EoceneMiocene) 0 210 1077 0 149 706 0 6 38 0.000 0.249 1.588 0.000 0.063 0.289 0 155 743 0.0

4 Milky River Biogenic Gas (Plio-Pleistocene)

5

Mesozoic Deformed Sedimentary Rocks (Triassic-Cretaceous)

0 41 197 0 38 183 0 0 0 0.000 0.000 0.000 0.000 0.017 0.079 0 38 183 0.0

6

Mesozoic Buried Granitic Hills (JurassicCretaceous Magmatic 

Rocks)

0 67 330 0 26 93 0 5 29 0.000 0.195 1.128 0.000 0.010 0.041 0 30 122 0.0

91 2287 6647 9 545 1948 10 208 556 0.401 8.393 22.487 0.003 0.229 0.791 19 753 2505 0.4

* Free gas, occurring as gas caps associated with oil and as oil-free gas pools.BOE, total energy, in millions of barrels (5,620 cubic feet of gas per barrel of oil, energy-equivalent); Mmbo, millions of barrels of oil or liquids; Tcfg, trillions of cubic feet of 

Total Liquid 

Resources (Mmbo)

To

** Values as reported out of Basin Level Analysis-Geologic Scenario aggregation module in GRASP , "Volume Ordered" aggregation option. Total liquids and total gas vaobtained by summing resource values for means and fractiles of component commodities. Play resource values are rounded and may not sum to totals reported from basaggregation.

Solution Gas 

Resources (Tcfg)

BOE Resources 

(Mmboe)

Sum of All Plays**

Oil Resources 

(Mmbo) 

*** Calculated as the ratio of total gas to total liquids at mean values (1 barrel of liquids = 5,620 cubic feet of gas at standard conditions). Given as ratio between fractions 100.

Play 4 Assessed with Negligible Resources

Gas-Condensate 

Liquid Resources 

(Mmbo)

Nonassociated* Gas 

Resources (Tcfg)
Class

Minimum 

Size 

(Mmboe)

Maximum 

Size 

(Mmboe)

Pool 

Count Percentage Trial Average

Trials with 

Pool 

Average

Mixed 

Pool 

Count

Oil Pool 

Count

Gas 

Pool 

Count

1 0.0312 0.0625 0 0 0 0 0 0 0

2 0.0625 0.125 0 0 0 0 0 0

3 0.125 0.25 4 0.005479 0.0004 0.000556 0 0 4

4 0.25 0.5 8 0.010958 0.0008 0.001111 0 0 8

5 0.5 1 53 0.072596 0.0053 0.007363 4 5 44

6 1 2 207 0.283534 0.0207 0.028758 11 5 191

7 2 4 604 0.827318 0.0604 0.083912 49 24 531

8 4 8 1630 2.232663 0.163 0.226452 146 73 1411

9 8 16 3893 5.332366 0.3893 0.540845 378 173 3342

10 16 32 7896 10.815401 0.7896 1.096971 741 442 6713

11 32 64 12596 17.253139 1.2596 1.749931 1231 754 10611

12 64 128 15882 21.754078 1.5882 2.206446 1584 1249 13049

13 128 256 14566 19.951511 1.4566 2.023618 1497 1508 11561

14 256 512 9798 13.42063 0.9798 1.361211 1094 1476 7228

15 512 1024 4321 5.918611 0.4321 0.600306 434 902 2985

16 1024 2048 1282 1.755996 0.1282 0.178105 101 448 733

17 2048 4096 238 0.325996 0.0238 0.033065 23 98 117

18 4096 8192 28 0.038352 0.0028 0.00389 1 20 7

19 8192 16384 1 0.00137 0.0001 0.000139 0 1 0

20 16384 32768 0 0 0 0 0 0 0

21 32768 65536 0 0 0 0 0 0 0

22 65536 131072 0 0 0 0 0 0 0

23 131072 262144 0 0 0 0 0 0 0

24 262144 524288 0 0 0 0 0 0 0

25 524288 1048576 0 0 0 0 0 0 0

0 0 0 00 0

Totals = 73007 100.000000 7.3007 10.142679 7294 7178 58535

Number of Pools Not Classified = 0 Number of Pools Below Class 1 = 0

Number of Trials with Pools = 7198 Number of Pools Above Class 25 = 0

Pool Rank F95 F75 F50 Mean F25 F05 F01

1 187 370 591 827 899 2495 3464

2 106 211 321 378 475 816 1255

3 65 139 214 245 317 542 738

4 41 97 153 174 227 382 543

5 26 69 113 130 172 290 404

6 17 50 86 99 133 227 319

7 12 38 67 78 106 184 260

8 9 29 53 63 86 153 215

9 7 23 44 53 72 129 182

10 6 19 36 44 61 110 157

11 5 16 31 38 53 96 138

12 4 14 27 34 46 85 123

13 4 13 24 30 41 76 111

14 4 12 22 27 37 69 101

15 3 11 20 25 34 64 93

16 3 10 18 23 31 59 125

17 3 9 17 22 29 56 81

18 3 9 16 21 28 53 77

19 2 8 16 20 27 50 72

20 2 8 15 19 25 48 69

21 2 8 15 18 25 46 65

22 2 8 14 17 24 43 61

23 2 7 14 17 23 41 58

24 2 7 13 16 21 39 55

25 2 7 12 15 20 37 51

26 2 6 12 14 19 34 48

27 2 6 11 13 18 32 45

28 1 6 10 12 17 30 42

29 1 5 10 12 16 28 39

30 1 5 9 11 15 26 36

31 1 5 9 10 14 24 33

32 1 4 8 9 13 22 29

33 1 4 7 8 11 19 26

34 1 3 5 6 9 15 22

Maximum Number of Pools = 34

Pool Size in Millions of Barrels of Oil, Energy-Equivalent

Table 15: Conditional (Unrisked) Recoverable Pool Size Results for Play 1 - Bear 

Lake-Stepovak (Oligocene-Miocene)

Table 16: Conditional (Unrisked) Recoverable Sizes of Ranked Pools for Play 1 - 

Bear Lake-Stepovak (Oligocene-Miocene)

Classification and Size Pool Count Statistics Pool Type Counts

Not Classified

0

0

85
Class

Minimum 

Size 

(Mmboe)

Maximum 

Size 

(Mmboe)

Pool 

Count Percentage Trial 

Average

Trials with 

Pool 

Average

Mixed 

Pool 

Count

Oil Pool 

Count

Gas 

Pool 

Count

1 0.0312 0.0625 0 0 0 0 0 0 0

2 0.0625 0.125 0 0 0 0 0 0 0

3 0.125 0.25 2 0.003261 0.0002 0.000202 0 0 2

4 0.25 0.5 3 0.004892 0.0003 0.000303 0 0 3

5 0.5 1 34 0.055441 0.0034 0.003433 1 0 33

6 1 2 105 0.171216 0.0105 0.010601 2 3 100

7 2 4 310 0.505495 0.031 0.031297 12 13 285

8 4 8 944 1.539315 0.0944 0.095305 68 80 796

9 8 16 2646 4.314646 0.2646 0.267138 225 333 2088

10 16 32 8004 13.05156 0.8004 0.808077 780 819 6405

11 32 64 16546 26.9804 1.6546 1.670469 1662 1633 13251

12 64 128 18963 30.921633 1.8963 1.914488 1920 1780 15263

13 128 256 10866 17.718422 1.0866 1.097022 1033 1123 8710

14 256 512 2633 4.293448 0.2633 0.265825 252 352 2029

15 512 1024 265 0.432117 0.0265 0.026754 23 39 203

16 1024 2048 5 0.008153 0.0005 0.000505 0 1 4

17 2048 4096 0 0 0 0 0 0 0

18 4096 8192 0 0 0 0 0 0 0

19 8192 16384 0 0 0 0 0 0 0

20 16384 32768 0 0 0 0 0 0 0

21 32768 65536 0 0 0 0 0 0 0

22 65536 131072 0 0 0 0 0 0 0

23 131072 262144 0 0 0 0 0 0 0

24 262144 524288 0 0 0 0 0 0 0

25 524288 1048576 0 0 0 0 0 0 0

0 0 0 00 0

Totals = 61326 100 6.1326 6.191419 5978 6176 49172

Number of Pools Not Classified = 0 Number of Pools Below Class 1 = 0

Number of Trials with Pools = 9905 Number of Pools Above Class 25 = 0

Pool Rank F95 F75 F50 Mean F25 F05 F01

1 61 122 181 208 258 467 686

2 34 75 113 124 159 248 330

3 22 54 83 90 117 182 241

4 16 41 65 71 94 146 191

5 13 34 54 59 78 122 161

6 11 29 46 51 68 107 142

7 9 25 41 45 60 96 129

8 8 22 37 41 54 88 119

9 7 21 34 38 50 82 112

10 6 19 31 35 47 79 107

11 6 18 30 34 45 76 104

12 6 17 29 33 44 75 100

13 5 16 28 32 43 74 97

14 5 16 28 32 44 74 94

15 5 16 28 32 45 73 92

16 5 17 29 33 46 71 89

17 6 17 30 33 46 69 85

18 6 18 31 33 46 67 82

19 6 18 31 32 45 64 78

20 6 19 30 32 43 62 75

21 6 18 29 30 41 59 72

22 6 17 28 29 39 56 68

23 6 16 26 27 37 53 65

24 5 15 25 26 35 51 62

25 5 14 24 25 33 48 59

26 5 14 22 23 31 46 56

27 4 13 21 22 30 44 54

28 4 12 20 21 28 42 52

29 3 11 19 20 27 40 49

30 3 11 18 19 26 38 47

31 3 10 17 18 25 37 45

32 3 9 16 17 23 35 53

33 2 9 15 16 22 34 42

34 2 8 14 16 22 32 40

35 2 8 14 15 21 31 39

36 2 8 13 14 20 30 37

37 2 7 13 14 19 28 35

38 2 7 12 13 18 27 34

39 2 7 12 12 17 26 32

40 1 6 11 12 16 24 30

41 1 6 10 11 15 23 28

42 1 5 9 10 14 21 26

43 1 5 8 9 12 19 24

44 1 3 6 7 10 16 21

* ranked as reported in PSRK module of GRASP

Maximum Number of Pools = 44

Table 17: Conditional (Unrisked) Recoverable Pool Size Results for Play 2 - 

Tolstoi (Eocene-Oligocene)

Table 18: Conditional (Unrisked) Recoverable Sizes of Ranked Pools for Play 2 

0

-

Tolstoi (Eocene-Oligocene)

Pool Size in Millions of Barrels of Oil, Energy-Equivalent *

Classification and Size Pool Count Statistics Pool Type Counts

Not Classified

86
Class

Minimum 

Size 

(Mmboe)

Maximum 

Size 

(Mmboe)

Pool 

Count Percentage Trial 

Average

Trials with 

Pool 

Average

Mixed 

Pool 

Count

Oil Pool 

Count

Gas 

Pool 

Count

1 0.0312 0.0625 3 0.019578 0.0003 0.000727 2 1 0

2 0.0625 0.125 4 0.026105 0.0004 0.000969 1 2 1

3 0.125 0.25 18 0.11747 0.0018 0.004362 5 4 9

4 0.25 0.5 60 0.391568 0.006 0.014538 25 16 19

5 0.5 1 140 0.913659 0.014 0.033923 51 49 40

6 1 2 320 2.088364 0.032 0.077538 126 104 90

7 2 4 624 4.072309 0.0624 0.151199 226 194 204

8 4 8 1139 7.43327 0.1139 0.275987 464 373 302

9 8 16 1744 11.381583 0.1744 0.422583 695 647 402

10 16 32 2362 15.414736 0.2362 0.572329 937 906 519

11 32 64 2521 16.452393 0.2521 0.610855 1026 999 496

12 64 128 2440 15.923775 0.244 0.591228 973 1017 450

13 128 256 1889 12.327873 0.1889 0.457717 787 811 291

14 256 512 1182 7.713894 0.1182 0.286407 464 571 147

15 512 1024 569 3.713372 0.0569 0.137873 226 305 38

16 1024 2048 242 1.579325 0.0242 0.058638 82 141 19

17 2048 4096 58 0.378516 0.0058 0.014054 16 40 2

18 4096 8192 6 0.039157 0.0006 0.001454 1 5 0

19 8192 16384 1 0.006526 0.0001 0.000242 0 1 0

20 16384 32768 0 0 0 0 0 0 0

21 32768 65536 0 0 0 0 0 0 0

22 65536 131072 0 0 0 0 0 0 0

23 131072 262144 0 0 0 0 0 0 0

24 262144 524288 0 0 0 0 0 0 0

25 524288 1048576 0 0 0 0 0 0 0

1 0.006526 0.0001 0.000242 0 0 1

Totals = 15323 99.999992 1.5323 3.712866 6107 6186 3029

Number of Pools Not Classified = 1 Number of Pools Below Class 1 =1

Number of Trials with Pools = 4127 Number of Pools Above Class 25 = 0

Pool Rank F95 F75 F50 Mean F25 F05 F01

1 19.7 83 195 378 444 1302 3328

2 5.8 27 64 110 136 365 667

3 2.7 13 31 52 65 169 312

4 1.7 7 18 30 38 98 176

5 1.2 5 12 20 25 64 114

6 1.0 4 9 14 18 45 80

7 0.8 3 7 11 14 34 60

8 0.73 6 9 11 27 47

9 0.6 2 5 7 9 22 38

10 0.5 2 4 6 8 19 32

11 0.4 2 4 5 7 16 27

12 0.4 2 3 5 6 14 23

13 0.3 1 3 4 5 11 19

Maximum Number of Pools = 13

Table 19: Conditional (Unrisked) Recoverable Pool Size Results for Play 3 - 

Black Hills Uplift-Amak Basin (Eocene-Miocene)

Table 20: Conditional (Unrisked) Recoverable Sizes of Ranked Pools for Play 3 - 

Black Hills Uplift-Amak Basin (Eocene-Miocene)

Pool Size in Millions of Barrels of Oil, Energy-Equivalent

Classification and Size Pool Count Statistics Pool Type Counts

Not Classified

87
Class

Minimum 

Size 

(Mmboe)

Maximum 

Size 

(Mmboe)

Pool 

Count Percentage Trial Average

Trials with 

Pool 

Average

Mixed 

Pool 

Count

Oil Pool 

Count

Gas 

Pool 

Count

1 0.0312 0.0625 5 0.034899 0.0005 0.001275 0 5 0

2 0.0625 0.125 7 0.048859 0.0007 0.001784 0 7 0

3 0.125 0.25 32 0.223355 0.0032 0.008157 0 32 0

4 0.25 0.5 101 0.704963 0.0101 0.025746 0 101 0

5 0.5 1 278 1.940392 0.0278 0.070864 0 278 0

6 1 2 570 3.978502 0.057 0.145297 0 570 0

7 2 4 1201 8.382773 0.1201 0.306143 0 1201 0

8 4 8 2164 15.104348 0.2164 0.551619 0 2164 0

9 8 16 2948 20.576534 0.2948 0.751466 0 2948 0

10 16 32 3088 21.553709 0.3088 0.787153 0 3088 0

11 32 64 2387 16.660851 0.2387 0.608463 0 2387 0

12 64 128 1166 8.13848 0.1166 0.297222 0 1166 0

13 128 256 304 2.121868 0.0304 0.077492 0 304 0

14 256 512 66 0.460669 0.0066 0.016824 0 66 0

15 512 1024 8 0.055839 0.0008 0.002039 0 8 0

16 1024 2048 1 0.00698 0.0001 0.000255 0 1 0

17 2048 4096 0 0 0 0 0 0 0

18 4096 8192 0 0 0 0 0 0 0

19 8192 16384 0 0 0 0 0 0 0

20 16384 32768 0 0 0 0 0 0 0

21 32768 65536 0 0 0 0 0 0 0

22 65536 131072 0 0 0 0 0 0 0

23 131072 262144 0 0 0 0 0 0 0

24 262144 524288 0 0 0 0 0 0 0

25 524288 1048576 0 0 0 0 0 0 0

1 0.00698 0.0001 0.000255 0 1 0

Totals = 14327 100 1.4327 3.652052 0 14327 0

Number of Pools Not Classified = 1 Number of Pools Below Class 1 = 1

Number of Trials with Pools = 3923 Number of Pools Above Class 25 = 0

Pool Rank F95 F75 F50 Mean F25 F05 F01

1 8 24 45 63 80 176 387

2 3 10 20 26 35 70 107

3 26 11 15 20 41 63

4 1 4 8 10 14 27 42

5 13 5 7 10 20 31

6 1 2 4 6 8 15 24

7 1 2 4 5 6 13 19

8 0.4 1 3 4 5 11 16

9 0.41 3 3 5 9 14

10 0.3 1 2 3 4 8 12

11 0.3 1 2 3 4 7 11

12 0.2 1 2 2 3 6 9

13 0.2 1 2 2 3 5 8

Maximum Number of Pools = 13

Table 21: Conditional (Unrisked) Recoverable Pool Size Results for Play 5 - 

Mesozoic Deformed Sedimentary Rocks (Triassic-Cretaceous)

Pool Size in Millions of Barrels of Oil, Energy-Equivalent

Classification and Size Pool Count Statistics Pool Type Counts

Table 22: Conditional (Unrisked) Recoverable Sizes of Ranked Pools for Play 5 - 

Mesozoic Deformed Sedimentary Rocks (Triassic-Cretaceous)

Not Classified

88
89

Class

Minimum 

Size 

(Mmboe)

Maximum 

Size 

(Mmboe)

Pool 

Count Percentage Trial Average

Trials with 

Pool 

Average

Mixed 

Pool 

Count

Oil Pool 

Count

Gas 

Pool 

Count

1 0.0312 0.0625 2 0.01528 0.0002 0.000584 0 0

2 0.0625 0.125 10 0.0764 0.001 0.002918 0 0 10

3 0.125 0.25 35 0.2674 0.0035 0.010213 0 0 35

4 0.25 0.5 102 0.77928 0.0102 0.029764 0 0 102

5 0.5 1 250 1.910001 0.025 0.07295 11 1 238

6 1 2 498 3.804722 0.0498 0.145317 12 3 483

7 2 4 1030 7.869203 0.103 0.300554 61 16 953

8 4 8 1709 13.056766 0.1709 0.498687 146 44 1519

9 8 16 2302 17.587288 0.2302 0.671725 233 88 1981

10 16 32 2483 18.970127 0.2483 0.72454 271 149 2063

11 32 64 2173 16.601727 0.2173 0.634082 297 238 1638

12 64 128 1397 10.673084 0.1397 0.407645 167 260 970

5

3

0

0

0

0

0

0

0

0

0

1

Table 23: Conditional (Unrisked) Recoverable Pool Size Results for Play 6 - 

Mesozoic Granitic Buried Hills (Jurassic-Cretaceous)

Classification and Size Pool Count Statistics Pool Type Counts

13 128 256 733 5.600122 0.0733 0.21389 74 249 410

14 256 512 247 1.887081 0.0247 0.072075 13 144 90

15 512 1024 86 0.65704 0.0086 0.025095 5 66 1

16 1024 2048 22 0.16808 0.0022 0.00642 0 19

17 2048 4096 5 0.0382 0.0005 0.001459 0 5

18 4096 8192 4 0.03056 0.0004 0.001167 0 4

19 8192 16384 0 0 0 0 0 0

20 16384 32768 0 0 0 0 0 0

21 32768 65536 0 0 0 0 0 0

22 65536 131072 0 0 0 0 0 0

23 131072 262144 0 0 0 0 0 0

24 262144 524288 0 0 0 0 0 0

25 524288 1048576 0 0 0 0 0 0

1 0.00764 0.0001 0.000292 0 0

Totals = 13089 100.000008 1.3089 3.819376 1290 1286 10513

Number of Pools Not Classified = 1 Number of Pools Below Class 1 = 1

Number of Trials with Pools = 3427 Number of Pools Above Class 25 = 0

Pool Rank F95 F75 F50 Mean F25 F05 F01

1 9 33 71 148 154 469 1416

2 3 13 27 42 52 131 234

3 2 7 14 21 28 64 112

4 1 4 9 13 18 40 68

5 13 6 9 12 28 46

6 1 2 5 7 9 21 34

7 1 2 4 6 8 16 27

8 0.5 2 3 5 6 13 22

9 0.4 1 3 4 5 11 18

10 0.3 1 3 4 5 10 16

11 0.3 1 2 3 4 9 14

12 0.3 1 2 3 4 8 12

13 0.2 1 2 3 3 7 11

14 0.2 1 2 2 3 6 9

15 0.2 1 1 2 2 5 8

Maxiumum Number of Pools = 15

Pool Size in Millions of Barrels of Oil, Energy-Equivalent

Table 24: Conditional (Unrisked) Recoverable Sizes of Ranked Pools for Play 6 

2

-

Mesozoic Granitic Buried Hills (Jurassic-Cretaceous)

Not Classified
90

Risked, Undiscovered, Technically and Economically Recoverable Oil and Gas Resources

F95 Mean F05 F95 Mean F05 F95 Mean 

Technically Recoverable (Petroleum 

Endowment) 19 753 2505 0.404 8.622 23.278 91 2287 

Economically Recoverable at $18/Bbl 

(Oil) and $2.72/Mcf (Gas) 0 45 200 0.000 0.017 0.053 0 48 

Economically Recoverable at $30/Bbl 

(Oil) and $4.54/Mcf (Gas) 2 378 1371 0.001 0.909 2.780 3 539 

Economically Recoverable at $46/Bbl 

(Oil) and $6.96/Mcf (Gas) 11 631 2180 0.132 5.852 16.548 34 1672 

Economically Recoverable at $80/Bbl 

(Oil) and $12.10/Mcf (Gas) 19 738 2468 0.392 8.396 22.767 89 2232 

risked (product of multiplying the conditional resources and MPhc). ECONOMIC ASSUMPTIONS : 2005 base year; oil price is Alaska North Slope crude landed at U.S. West Coast; gas price is LNG deCoast; 0.8488 is gas value discountrelative to oil on a BOE basis; flat real prices and costs; 3% inflation; 12% discount rate; 35% FedeTERMINOLOGY : Mmbo , millions of barrels of oil and condensate; Tcfg , trillions of cubic feet, gas; Mmboe , total oil and gas in mil

barrels; Mean , resource quantities at the mean in cumulative probability distributions; F95 , the resource quantity having a 95-percen

or exceeded; F05 , the resource quantity having a 5-percent probability of being met or exceeded; The MPhc for technically recovera

probability that the assessment area contains at least one accumulation. The MPhc for the economic cases is the probability that the 

one economic accumulation under the given economic conditions. For example, if the $30 case shows a MPhc of 0.22, then 2,200 ouleast one prospect with economically recoverable resources (oil or gas) at the given starting prices and other economic conditions. R

SCENARIO 

Threshold or "Marginal" Prices ($2005, Mean Resource Case) Required for First Positive Economic Results = $14/barrel o

Solution Gas. The Threshold Price for Economic Non-Associated Gas = $3.63/Mcf.

Table 25: 2006 Economic Assessment Results for North Aleutian Basin OCS Planning A

OIL AND CONDENSATE 

(Mmbo)

 FREE GAS AND SOLUTION 

GAS (Tcfg) BOE (Mm
174° 174° 154°

52°

178° 178°

54°

56°

58°

170° 166° 162° 158°

60°

156° 160° 164° 168° 172° 176° 180° 176° 172° 168° 164°160°

150° 146° 142° 

156° 152° 148° 140°144° 136° 132° 128° 

144° 148° 152° 

50°

48°

46°

44° 

BARROW

A

LAS

KA

BETHEL

DUTCH

HARBOR

NOME

RUSSIA

ANCHORAGE

KODIAK

ISLAND

VALDEZ

FAIRBANKS

NPR-A

ANWR

50 150 0 

50 0 150 

50 0 150 

C

ANADA

BASINS OF BERING SHELF

AND PACIFIC MARGIN OFFSHORE

Sherwood\...\Fig01-LocationMap-NorthAleutianBasin.cdr

Bering Sea

Pacific Ocean

Chukchi Sea

Pacific Ocean

Bristol Bay

Gulf of Alask

Beaufort Sea

Arctic Ocean 

ALASKA PENINSULA

Aleutian Islands

OCS Planning Area Boundaries

North Aleutian Basin

OCS Planning Area

WESTERN ALASKA RANGE

NORTON

BASIN

ST. MATTHEWHALL BASIN

HOPEBASIN

KOTZEBUE

BASIN

NAVARIN

BASIN

ST. GEORGE

BASIN

AMAK

BASIN

NORTH

ALEUTIAN

BASIN

COOK

INLET

BASIN BERING

 SHELF

 BASINS

DEEP ABYSSAL

PLAINS OF THE

BERING SEA

PACIFIC MARGIN

BASINS

CENTRAL

ALASKA

Figure 1: Location map for North Aleutian basin and other Tertiary-age basins of the Bering shelf, Pacific margin, and southern C

91
Becha

Ugashik Lakes

BearLake

164°

162°

160°

158°

58°

56°

OCS Sale 92 Area

Sale 92

High Bid Tract

$24.36 MM

Top Prospect 

Collected $69.4 MM in 

Sale 92 (73% of Sale)

Bristol Bay

Bering Sea

Pacific Ocean

ALASKA

NORTHALEUTIANBASINOCSPLANNINGAREA

Sherwood\....\Fig02-Wells&Leases-NAB.cdr

Balboa

Bay

Pavlof

Bay

ST.

GEORGE

BASIN

ALASKA PENINSULA

0 50

MILES

Leased MM, 23 Inactive

Leased $1.3 MM

Well, PWells Ooffsho

Well, Pwith Ga

Well, Pwith O

Gas Se

Oil See(see be

Uplift o

Tertiary>3,000 

EXPL

* Becharof Lake oil seunknown” by Magoon markers in sediments 

Oil Shows

Gas Shows

Outlines of proposed licensing programs at http://www/dog.dnr.stas.htm

State of Alaska

Oct 2005Lease

 Sale Area

State of Alas2003 ProposLicensing Ar

State of Alaska

2004 Contracted

Licensing Area

GreatBasins 2

GreatBasins 1

Becharof

Lake 1

Finnegan 

Lee 1

Koniag 1

PainterCreek 1

Ugashik 1

PortHeiden 1

Sandy River 1

North AleutianShelf COST 1

Big River 1

DavidRiver 1/1A

HoodooLake 1

HoodooLake 2

CanoeBay 1

CathedralRiver 1

Bertha 1

Monkshood 1

St. GeorgeCOST 2

Tested Gas90 Mcfd

Oil Shows

Oil Shows

Oil Shows

Oil Staining

Gas Shows

Tested Gas(5-9 Mcfd)

Oil Shows

Gas Shows

ShallowGas Shows

Oil Show

Jur-Cret OilSource Rocks?

Oil Stain

Oil Shows

PortMoller

PortHeiden

Chignik

Nak

KinSal

FalsePass

ColdBay

SandPoint

Proposed “Gold-CoppMolybdenu

Figure 2: Regional map for North Aleutian basin, with well control, Sale 92 (1988) leases (now relinquished and inactive), and regTertiary-age sedimentary rocks.

92
CDP SEISMIC DATA GRID (TWO-DIMENSIONAL)

Sherwood\....\Fig03-NorthAleutianSeismicGrid.cdr

Bristol Bay

Alaska Peninsula

NORTH ALEUTIAN SHELF

COST 1 WELL

0 25 50 75 100 miles

Sale 92 (1988)

Figure 3: CDP (common-depth-point) seismic data (two-dimensional) for the North Aleutian Basin OCS Planning 

Area. Most data was acquired prior to 1988. Seismic data gathered to date within the North Aleutian Basin OCS 

Planning Area consists of 64,672 combined line miles of conventional, two-dimensional, common-depth-point 

(CDP) and shallow-penetrating, high-resolution (HRD) data. Of the seismic data held by MMS, 95% is CDP and 

5% is HRD. Airborne magnetic data in the area covers 9,596 line miles. Approximately 6,400 miles of airborne 

gravity data have also been gathered in the Planning Area. 

93
??

??

174° 174° 154°

52°

178° 178°

54°

56°

58°

170° 166° 162° 158°

60°

156° 160° 164° 168° 172° 176° 180° 176° 172° 168° 164°160°

150° 146° 142° 

156° 152° 148° 140°144° 136° 132° 12

144° 148° 152° 

50°

48°

46°

44° 

BARROW

ALASKA

BETHEL

DUTCH

HARBOR

NOME

RUSSIA

ANCHORAGE

KODIAK

ISLAND

VALDEZ

FAIRBANKS

NPR-A

ANWR

50 

0 

50 0 

50 0 

Tertiary-Age Basins

Mesozoic Basin with Jurassic Oil Source Rocks?

CANADA

BASINS OF BERING SHELF

AND PACIFIC MARGIN OFFSHORE

Sherwood\...\Fig04-RegionalDistributionJurassic.cdr

Bering Sea

Chukchi Sea

Pacific Ocean

Gulf of Alaska

Beaufort Sea

Arctic Ocean 

Distribution of Jurassic rocks after Imlay & Detterman, 1973, USGS PP 801

NORTON

BASIN

ST. MATTHEWHALL BASIN

HOPEBASIN

KOTZEBUE

BASIN

NAVARIN

BASIN

DEEP BERING 

SEA BASINS

ST. GEORGE

BASIN

NORTH

ALEUTIAN

BASIN

COOK

INLET

BASIN

BERING

 SHELF

 BASINS

PACIFIC MARGIN

BASINS

CENTRAL

ALASKA

GUL

L

F OF A AS L KA SHE F

SHUMAGIN-KODIAK SHELF

Northern Cook

Inlet Oil & Gas

Province

Figure 4: Regional distribution of Mesozoic sedimentary basin containing strata correlative to Middle Jurassic oil source rocks that gen

of oil reserves in the oil fields of northern Cook Inlet basin. Distribution of Jurassic rocks after Imlay and Detterman (1973) and Worra

94
Ugashik Lak

BearLake

U

164°

162°

160°

158°

58°

56°

OCS Sale 92

Figure6

2000

3000

4000 5000

6000

7000

7000

4000

5000

6000

ALASKA PENINSULA

ST.

GEORGE

BASIN

NORTH

ALEUTIAN-- BRISTOL

BAY

BASIN

A

MA

K

BASIN

Acoustic Basement <3,000 Feet

BLACK

HIL

LS

UPLIFT ??

Bristol Bay

Bering Sea

Pacific Ocean

ALA

NORTHALEUTIANBASINOCSPLANNINGAREA

Sherwood\....\Fig05-NorthAleutianStructures.cdr

Balboa

Bay

Pavlof

Bay

0 50

MILES

Well, Plugged and Abandoned (18 Wells Onshore, 1903-1983; 1 well offshore, 1983)

Gas Seep

Oil Seep. *Becharof Lake seep (see below)

Uplift or Structural Arch

Surface Anticline or Antiformal Duplex in Mesozoic Rocks

Tertiary-Age (<65 Ma) Strata >3,000 Feet Thick

Strike-Slip Fault, with Sense of Displacement

Bruin Bay Fault and Subsurface Projection Based on Aeromagnetic Data

4000

EXPLANATION

* Becharof Lake oil seep reported as “location unknown” by Magoon and Anders (1992, Biologic markStructures in Mesozoic rocks from Detterman et al. (1987), Detterman et al (1981), Wilson et al. (1995), 

GreatBasins 2

Becharof Lake 1

Fin

Koniag 

PainterCreek 1

Ugashik 1

PortHeiden 1

SandyRiver 1

North AleutianShelf COST 1

Big River 1

DavidRiver 1/1A

HoodooLake 1

HoodooLake 2

CanoeBay 1

CathedralRiver 1

Bertha 1

Monkshood 1

St. GeorgeCOST 2

PortMoller

PortHeiden

Chignik

FalsePass

ColdBay

SandPoint

??

??

Figure 5: Principal geologic structures of the North Aleutian basin and contiguous areas, including: 1) transtensional faults and baseme

of the basin; 2) wrench-fault structures along the Black Hills uplift; and 3) fold/thrust belts along the southeast margin of the basin. Th

not appear to extend into the Federal offshore (>3 miles).

95
TD 17,155 ft

Early EoceneTolstoi Fm.

North Aleutian

Shelf COST 1

Adapted from Figure 64, North Aleutian COST 1 well report, OCS Report MMS 88-0089

Pre-TeJurassvolcan

NORTHWEST 

SEISMIC LINE--NORTH ALEUTIAN BASIN BASEMENT UPLIFTS

Sherwood\...\Fig06-SeismicLineFig64-SS6.cdr

Two-Way Time (s)

0

1.02.0

3.0

4.0

5.0

Depth (1,000 feet, subsea)

51015 

R egional Shale Seal

Sale 92

High Bid Tract 755

$24.36 MM

? ?

? ?

?

Paleocene-Top Basement?

Paleocene-Top Basement?

Bear Lake-Stepovak (OligoceneMiocene) Play Sequence

Typical Top of Oil Generation Zone (0.6% Ro) at 12,312 feet

Liquid Floor (2.0% Ro) at 21,907 feet ssd

Re gional de pths for thermal maturity zones are b ased on vitrinite re flectance isograds penetrated at the North Aleutia n Shelf COST 1 well. The 1.35% and 2.00% isograds w ere not penetrated but are forecast from the da ta set below the fa ult at 15 ,620 ft, with 647 ft added to forecast d epths to correct for the fau lt gap.

Upper Eocene Unconformity-Hz D

Top Prospect--$69.4 MM in High Bids (73% of Sale 92)

Oil Shows (Trace)

Gas Shows (Minor)

Figure 6: Seismic profile through basement uplifts in western North Aleutian basin, showing Tertiary sedimentary sequences and basi

adapted from Turner et al. (1988, fig. 64). The location of the profile is shown in figure 5. A full-scale version of figure 6 is also avail

96
OCS Sale 92 Sale 92

Leases

ST. GEORGE

BASIN

AMAK BASIN

BLACK HILLS UPLIFT

0 50

MILES

North Aleutian

Shelf COST 1

Cathedral

River 1

Bertha 1

Monkshood 1

St. George

COST 2 St. George

COST 1

Sherwood\....\Fig07-NorthAleutianMagneticMap.cdr

Adapted from Childs, Cooper and Wright, 1981, USGS Geoph. Inv. Map GP-939

MAGNETIC ANOMALIES AND MESOZOIC BASEMENT TERRANES

NORTH ALEUTIAN AND ST. GEORGE BASINS

Southern Bering Sea Shelf

162O

166O

167O 164O

58O

56O

54O

-800

0

>1,000

Residual Magnetic Intensity

(gammas)

Figure 7: Magnetic intensity map with offshore speculative extrapolation of the Bruin Bay fault. Adapted from 

Childs et al. (1981).

97
Figure 8: Mesozoic stratigraphy, Alaska Peninsula and substrate beneath southwest part of North Aleutian basin.

98
SEISMIC HORIZON

“A” (2510 ft)

SEISMIC HORIZON

“B” (5675 ft)

SEISMIC HORIZON

“D” (10380 ft)

[Truncates 

Basement Uplifts]

SEISMIC HORIZON

“C” (7900 ft)

SEISMIC

SEQUENCE I

SEISMIC

SEQUENCE II

SEISMIC

SEQUENCE III

SEISMIC

SEQUENCE IV

SEISMIC

SEQUENCE V

REGIONAL

UNCONFORMITIES,

SEISMIC HORIZONS,

SEISMIC SEQUENCES

TD

[17,155 ft in

Eocene]

NORTH ALEUTIAN SHELF COST 1 WELL LITHOLOGY

Sherwood\.....\Fig09-NorthAleutianStratColumn.cdr Adapted from Plate 1, Minerals Managment Service OCS Report MMS 88-0089

EXPLANATION

Volcanics

Coal

Shale

Siltstone

Sandstone

Gas Show

Oil Show

Oil & Gas

Show

Conglomerate,

Pebbly Sandstone

ERA

PERIOD

EPOCH

AGE

QUATERNARY NEOGENE PALEOGENE

CENOZOIC

PLEISTOCENE PLIOCENE MIOCENE OLIGOCENE EOCENE

EARLY

LATE

EARLY

LATE EAR LY TO LATE?

? LATE

? PROBABLE ? PROBA BLE EARLY EARLY LATE LATE MIDDLE TO LATE EARLY TO MIDDLE ?

GEOLOGICAL

AGE

?

?

33.7

Ma

23.8

Ma

5.3

Ma

1.8

Ma

PLAY

SEQUENCES Milky River Biogenic Gas (Play 4) Bear Lake - Stepovak (Plays 1, 3) Tolstoi (Play 2)

FORMATIONS

MILKY RIVER

FORMATION

UNNAMED

QUATERNARY

BEAR LAKE

FORMATION

STEPOVAK

FORMATION

TOLSTOI

FORMATION

0 100

GR (API Units)

SPONTANEOUS

GAMMA

RAY

POTENTIAL

SP

-80 (Millivolts) 20

SP

GR

Log TD 16,686 ft bkb

RESISTIVITY

0.3 (Ohms m /m) 300 2

DEEP

RESISTIVITY

LOG

Log TD 16,686 ft bkb

Range of Sandstone 

Porosity in Conventional 

Core

Density Porosity 

(Sandstone)

FORMATION DENSITY

POROSITY AND CORE POROSITY

(Den = 2.65 g/cc) MA

SANDSTONE POROSITY

40 2030 10 0

100 (%) -21

Log TD 16,686 ft bkb

1000

0

2000

3000

4000

5000

6000

7000

8000

9000

10000

11000

12000

13000

14000

15000

16000

17000

DEPTH

(FEET BKB)

KB 85 ft asl

WD 274 ft

Seafloor=

359 ft bkb

Floor/Effective Porosity at 10,380 ft 

(Only Microporosity >10,380 ft)

Top Overpressure

at 11,200 ft

Top Peak Oil Generation Zone

(0.6 Ro%) at 12,397 ft

SHOWS

K-Ar

40.5 Ma

K-Ar

47.1 Ma

K-Ar

31.6 Ma

K-Ar Radiometric Dates by Teldyne Isotopes (1983)

Spl 136: 16,660-16,670 ft bkb; 40.5 +/- 10.3 m.y.

 (Volcanic Fragments in Cuttings)

Spl 137: 16,690-16,700 ft bkb; 47.1 +/- 18.3 m.y.

 (Intrusive? Diabase Fragments, Cuttings)

Spl 138: 16,016.2-16,016.6 feet bkb; 31.6 +/-2.0 m.y.

 (Volcanic Pebble in Conglomerate, Core 18) NONMARI NE TRANSITIONAL INNER NERITIC MIDDLE NE RITIC OUTER NERITIC

PALEOBATHYMETRY

2700 ft

1590 ft

4870 ft

10380 ft

Formation correlations from Detterman, 1990, U.S. Geological Survey Open 

File 90-279, pl. 1. Time scale values from Palmer (1998).

Top Oil Generation Zone at 10,372 ft

Lower Eocene

Unconformity

16,028.5 ft

16,701 ft

Fault Cut at

15,620 ft md

(Gap = 647 ft)

Figure 9: Wellbore stratigraphy, North Aleutian Shelf COST 1 stratigraphic test well, drilled by an industry 

consortium in 1983. A full-scale version of figure 9 is available as plate 2.

99
Seismic Horizon “A”

(Pliocene Unconformity)

16028.5-16701 ft

(Between Cores 18 & 19)

U

E

n

a

c

rly Eocene

onformity

0 100

GR

(API Units)

SPONTANEOUS

GAMMA

RAY

POTENTIAL

SP

-80 20 (Millivolts)

SP

GR

0.3 300

(Ohms m /m) 2

DEEP

RESISTIVITY

NORTH ALEUTIAN

SHELF COST 1 WELL

KB 85 ft ASL, WD 277 ft

Completed 1983

[TD 17,155 ft bkb

in Lower Eocene]

(Turner et al., 1988)

Formation correlations for North 

Aleutian Shelf COST 1 well from 

Detterman, 1990, U.S. Geological 

Survey Open File 90-279, pl. 1.

Radiometric (K-Ar) dates by Teledyne Isotopes (1983)

Radiometric (?) dates from Brockway (1975)

Water Depth 277 ft

Dip 20

In Core

O 

Milky River 

Biogenic Gas (Play 4)

SANDY RIVER

1 WELL

KB 255 ft ASL

Completed 1963

[TD 13,068 ft bkb

in Upper Eocene?]

(Anderson et al., 1977b)

Dip 30 -50 NW

O

O

31.6 2 m.y. +40.5 10.3 m.y. +47.1 18.3 m.y. +

SP

-80 20

(Ohms m /m) 2

DEEP

RESISTIVITY

0.2 200

PORT HEIDEN

1 WELL

KB 36 ft ASL

Completed 1972

[TD 15,015 ft bkb

in Eocene Diorite]

42 4 m.y. +

42 4 m.y. +43 4 m.y. +

36 8 m.y. +

37.7 2 m.y. +

Radiometric (K-Ar) dates from Geochron (1969)

SP

-80 20

(Ohms m /m) 2

DEEP

RESISTIVITY

0.2 200

UGASHIK 1 WELL

KB 145 ft ASL

Completed 1966

39 7 m.y. +

33 1.7 m.y. +

[TD 9,476 ft bkb

in Eocene Volcanics]

SP

-80 20

(Ohms m /m) 2

DEEP

RESISTIVITY

0.2 200

2510

5675

7900

10380

9555

2850

63809840

12280

11330

2970

58459120

2600

3975

72 Miles

Sea Level Datum

77 Miles

Sea Level Datum

48 Miles

Sea Level Datum

34 M

S.

Dat

Meshik

Volcanics

Milky River

Play Sequence

Milky River

Play Sequence

Bear Lake-Stepovak

Play Sequence

Bear Lake-Stepovak

Play Sequence

Tolstoi

Play

Sequence

Tolstoi

Play

Sequence

Regional Shale

Seal

Seismic Horizon “B”

(Late Oligocene Unconformity)

Seismic Horizon “C”

(Early Oligocene Unconformity)

Seismic Horizon “D”

(Late Eocene Unconformity)

A

(Southwest)

Sherwood\.....\Fig10-StratCorrelation-NASwell-OnshoreWells.cdr

Adapted from an unpublished stratigraphic correlation panel prepared by G.C. Martin (fmr. MMS, ca. 1990)

Regional Stratigraphic Correlation Panel

North Aleutian Shelf COST 1 Well to Alaska Peninsula

164°

58°

56°

7000

4000

5000

6000

ST. GEORGE BASIN AMAK BASIN

BLACK HILLS UPLIFT

Bering Sea

NORTH ALEUTIAN BASIN OCS PLANNING AREA

Sherwood\....\StratCrossSectionLocationMap.cdr

0 50

MILES

North A

Shelf C

Bertha 1

Monkshood 1

St. GeorgeCOST 2

FalsePass

ColdBay

A

EXPLANATION Milky River

Play Sequence

Bear Lake-StepovakPlay Sequence

Tolstoi PlaySequence

RegionalUnconformity

Regional ShaleSeal

Meshik Formation(Eocene Volcanics)

Jurassic-CretaceousGranites, Metamorphics

Interfingering atFacies Boundary

Figure 10: Regional stratigraphic correlation panel for Tertiary sequence in North Aleutian Shelf COST 1, Sandy River 1, Port Heiden Becharof Lake 1 wells, North Aleutian basin and Alaska Peninsula. A full-scale version of figure 10 is available as plate 3.

100
UPPER TOLSTOI

(7900-10380 ft)

LOWER TOLSTOI

(10380-16700 ft, log TD)

BEAR LAKE-STEPOVAK

(2510-7900 ft)

Bear Lake-Stepovak (Plays 1, 3)

Gross Interval = 5390 ft

Number of SS Beds = 91

Net Sand = 3305 ft (61% of Interval)

Net Sand > 10 ft Beds = 3120 ft (94% of Sand)

Net Sand > 100 ft Beds = 1443 ft

Maximum Thickness Single Sand = 277 ft

Upper Tolstoi (Play 2)

Gross Interval = 2480 ft

Number of SS Beds = 22

Net Sand = 236 ft (10% of Interval)

Net Sand > 10 ft Beds = 186 ft (80% of Sand)

Net Sand >100 ft Beds = 0 ft (0% of Sand)

Maximum Thickness Single Sand = 43 ft

Lower Tolstoi (Play 2)

Gross Interval = 6320 ft

Number of SS Beds = 186

Net Sand = 1910 ft (30% of Interval)

Net Sand > 10 ft = 1431 ft (75% of Sand)

Net Sand > 100 ft = 0 (0% of Sand)

Maximum Thickness Single Sand = 57 ft

NORTH ALEUTIAN SHELF COST 1 WELL

Statistical Summaries of Sandstone Bed Thickness Data

Percent of Sandstone Beds

Sandstone Bed Thickness (feet)

Percent of Sandstone Beds Percent of Sandstone Beds

Sherwood\.....\Fig11-HistogramsNAB-COST1-SandThicknesses.cdr

Figure 11: Statistical summaries for sandstone bed thicknesses for North Aleutian basin play sequences. The 

Tolstoi sequence is treated in two parts because virtually all sandstones below 10,380 feet bkb are impermeable 

owing to diagenesis of volcanic framework grains and implosion of the pore system.

101
North Aleutian Shelf COST 1 Well

Core Porosity vs Depth

Conventional Core Plugs and Percussion Sidewall Cores

Porosity % = -0.0022[Depth] + 44.29

R2 = 0.6734 (n=312)

05

1015202530354045

0 2000 4000 6000 8000 10000 12000 14000 

Depth (feet bkb)

Core Porosity % (Helium)

Sherwood\....\Fig12-NorthAleutianCOST1CoreData.xls

Floor Effective Porosity at 10,380 ft bkb (21.45% porosi

Milky River Biogenic Gas Play Sequence

Bear Lake-Stepovak Play Sequence

Tolstoi Play Sequence

Figure 12: Core porosity versus depth in the North Aleutian Shelf COST 1 well, with linear regression function for porosity decline w

Core Laboratories (1983).

102
North Aleutian Shelf COST 1 Well

Porosity vs Permeability

Conventional Core Plugs and Percussion Sidewall Cores

Permeability = 0.0046e0.3423[Por

R2 = 0.7466 (n = 288)

0.001

0.01

0.1

1

10

100

1000

10000

0 5 10 15 20 25 30 35 

Core Porosity % (Helium)

Core Permeability, millidarcys (Air)

Sherwood\....\Fig13-NorthAleut

Figure 13: Core porosity versus permeability for sandstones, North Aleutian Shelf COST 1 well, with correlation. All data from Core 

103
North Aleutian Shelf COST 1 Well

Permeability vs Depth

Conventional Core Plugs and Percussion Sidewall Cores

Permeability (md) = 14766e-0.0007317[Depth]

R2 = 0.4693 (n = 288)

0.01

0.1

1

10

100

1000

10000

0 2000 4000 6000 8000 10000 12000 14000 

Depth, feet bkb

Permeability (Air), millidarcys

Seismic Horizon "A"at 2,510 ft bkb

Seismic Horizon "C"at 7,900 ft bkb Bear Lake-Stepovak Play (1)

Tolstoi (L

Tertiary) P

Sherwood \....\Fig14-NorthAleutianCOST1CoreData.xls

Seismic Horizon "D" at 10,380 ft bkb

Floor for Effective Porosity (Only Microporosity > 10,380 ft)

Figure 14: Core permeability versus depth for sandstones, North Aleutian Shelf COST 1 well, with function for permeability decline w

Core Laboratories (1983).

104
Lower Tolstoi Play Sequence

10,380-17,155 ft bkb

n = 84

Mean = 14.7679%

Standard Deviation = 6.4896%

21% of Samples < 10% Porosity

Normal Fit

North Aleutian Shelf COST 1 Well

Core Porosity Histograms, Bear Lake-Stepovak and Tolstoi Play Sequences

Sherwood\...\Fig15-NABPorosityHistograms.cdr Probability Probability (%) Probability (%)

0 5 10 15 20 25 30 35 40 45

Core Porosity (%)

Conventional and Percussion Sidewall Cores

Upper Tolstoi Play Sequence

7,900-10,380 ft bkb

n = 139

Mean = 25.2950%

Standard Deviation = 6.1564%

3% of Samples < 10% Porosity

Normal Fit

Bear Lake-Stepovak Play Sequence

2,510-7,900 ft bkb

n = 88

Mean = 31.4705%

Standard Deviation = 5.3704%

1% of Samples < 10% Porosity

Normal Fit

Figure 15: Porosity histograms for Bear Lake-Stepovak, Upper Tolstoi, and Lower Tolstoi play sequences from 

311 conventional and sidewall core samples. Tolstoi sandstones below 10,380 feet bkb are essentially impermeable 

because of diagenesis of volcanic framework grains and collapse of the pore system. All data from Core 

Laboratories (1983).

105
Log Permeability (md) 10

Probability

Lower Tolstoi Play Sequence 

10,380-17,155 ft bkb

n = 75

Geometric Average = 0.34 md (Log = -0.46913)

Standard Deviation = 19 md (Log = 1.2877)

Arithmetic Average = 26 md

68% of Samples < 1 md

84% of Samples < 10 md

10

10

Normal Fit

Log Permeability (md) 10

Probability

Upper Tolstoi Play Sequence 

7,900-10,380 ft bkb

n = 132

Geometric Average = 39 md (Log = 1.5924)

Standard Deviation = 14 md (Log = 1.1525)

Arithmetic Average = 295 md

11% of Samples < 1 md

32% of Samples < 10 md

10

10

Normal Fit

Log Permeability (md) 10

Probability

Bear Lake-Stepovak Play Sequence 

2,510-7,900 ft bkb

n = 80

Geometric Average = 168 md (Log = 2.22452)

Standard Deviation = 7 md (Log = 0.86774)

Arithmetic Average = 713 md

1% of Samples < 1md

4% of Samples < 10 md

10

10

Normal Fit

Sherwood\....\Fig16-NABPermeabilityHistograms.cdr

North Aleutian Shelf COST 1 Well

Core Permeability Histograms for Bear Lake-Stepovak and Tolstoi Play Sequences

0.01 0.10 1.0 10.0 100 1,000 10,000 105

Permeability (Air, millidarcys)

Figure 16: Permeability histograms for Bear Lake-Stepovak, Upper Tolstoi, and Lower Tolstoi play sequences 

from 287 conventional and percussion sidewall core samples. Tolstoi sandstones below 10,380 feet bkb are 

essentially impermeable because of cementation, diagenesis of volcanic framework grains, and collapse of the pore 

system. All data from Core Laboratories (1983).

106
North Aleutian Shelf COST 1 Well

Vitrinite Reflectance (Ro%)

Ro% [Above Ft Gap] = 0.1966e0.00009(Depth BKB)

R2 = 0.9439 (n = 84)

Ro% (Below Ft Gap) = 0.0936e0.00014345(Depth 

R2 = 0.7361 (n = 10)

0.1

1

10

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 

Depth (feet, bkb)

Vitrinite Reflectance (%) Cuttings Cuttings SidewallCoreData Conventional Core Data Conventional Core Data Fit to All Data Fit to All Data

Expon. (Cuttings)

Fault Gap (647 ft) at 15620 ft

Isograd Depths As Penetrated/Forecast By Well(No Fault Gap Correction)0.50 Ro% Top Early Oil Generation Zone at 10,372 ft bkb (Penetrated)0.60 Ro% Top Peak Oil Generation Zone at 12,397 ft bkb (Penetrated)0.80 Ro% Top Wet Gas Generation Zone; Hanging Wall of Fault at 15,620 ft bkb (Penetrated)0.88 Ro% Foot Wall of Fault at 15,620 ft bkb (Penetrated)1.00 Ro% Peak Oil Generation at 16,513 ft bkb (Penetrated)1.07 Ro% Peak Wet Gas, Top Dry Gas/Coaly Matter Generation at 16,984 ft bkb (Penetrated)1.35 Ro% Base Oil Generation Zone at 18,604 ft bkb (Forecast Below Data)2.00 Ro% Liquid Floor at 21,345 ft bkb (Forecast Below Data; Basement at ~20,800 ft bkb)Regional Depth Forecasts Should Add 647 ft to Isograds Below Fault at 15,620 ft bkb

Sherwood \...\Fig17-NorAleutCOST1VitRefData.xls

Projection of lower Ro% trend to Ro% at base of uppsequence suggests a 647 ft gap at a normal fault penetrated by the well at 15,620 ft bkb

Angular Unconformity 

16,028.5-16,701 ft bkb

Seismic Hz "B"

Seismic Hz "C"

Seismic Hz "D" 1.097% Ro 

@ TD (17,155 ft bkb

Figure 17: Vitrinite reflectance data for 94 samples of cuttings, conventional cores, and percussion sidewall cores in the North Aleutia

with statistical fits and forecasts for depths of important isograds. All analyses prepared by Robertson Research (1983). Critical isogra

(1977a, fig. 3) and Waples (1980).

107
Areas of Possible Gas, Condensate, and 

Oil Generation (Sufficient Thermal 

Maturity) within Tertiary-age strata of 

North Aleutian and Amak Basins

Ugashik La

BearLake

164°

162°

160°

158°

58°

56°

Sale 92High Bid Tract$24.36 MM

Figure6

Bristol Bay

Pacific Ocean

ALASKA

NORTHALEUTIANBASINOCSPLANNINGAREA

Sherwood\....\Fig18-NorthAleutianBasinThermalMaturity.cdr

0 50

MILES

Leased Blocks (1988, Sale 92, $9Well, Plugged and Abandoned, Wto Top of Oil Generation Zone (0.

Area of Possible Oil Generation Maturity) from Tertiary-Age [<65 Aleutian Basin). Uplifts in southAleutian basin are highly genera

Lower Tertiary (33-39 Ma) Rocks Dominantly Volcanic or Plutonic 

Depths (feet, subsea) to peak oil (corresponding to 0.6% vitrinite 

EXPLANATION

-1,007 ft

Koniag 1

Interpretation of North Aleutian COST 1 and Sandy River 1 Winterpretation of onshore wells from Johnsson and Howell (1Bulletin 2142, plate 1) and Molenaar (1996a, same pub., figs. compiled from merging 0.6% Ro isograd structure (this map) datums B, C, and D (Turner et al., 1988, MMS OCS Report MM

-8,000

Tertiary-Age (<65 Ma) Strata >3,0

-12,000

-11,000

-12,312 (est)

-4,000

-11,0

0

0

-10,000

-8,000

-9,000

-1,000

-7,00

-8,000 ft

-10,050 ft

-3,428 ft

-12,312 ft

-12,323 ft

-7,000 ft

-12,474 ft

-7,714 ft

-8,426 ft -9,6

-1,007 

+354 ft

GreatBasins 2

Becharof Lake 1 

Fin

Koniag 

PainterCreek 1

Ugashik 1

PortHeiden 1

SandyRiver 1

North Aleutian

Shelf COST 1

Big River 1

DavidRiver 1, 1A

HoodooLake 1

HoodooLake 2

CanoeBay 1

CathedralRiver 1

Bertha 1

Monkshood 1

St. GeorgeCOST 2

Figure 18: Depth to top of oil generation zone (0.6% vitrinite reflectance) with probable areas of thermal maturity of Tertiary rocks su

in and beneath the North Aleutian basin. The North Aleutian basin is segmented by a 33-39 Ma volcanic center that invaded the basin Heiden 1 and Ugashik 1 wells, producing the volcanic flows and volcaniclastics of the Meshik Formation (age-equivalent to the Stepov

108
Ugashik Lak

BearLake

164°

162°

160°

158°

58°

56°

Figure 6

Bristol Bay

Pacific Ocean

ALASKA

NORTHALEUTIANBASINOCSPLANNINGAREA

Sherwood\....\Fig19-NorthAleutianBasinThicknessOilWindow.cdr

0 50

MILES

Leased Blocks (1988, Sale 92, $

Leased Blocks (2005, AK State, 

Well, Plugged and Abandoned, Tertiary Rocks Within Oil Gener

Vitrinite Reflectance). “+” Indic

Because of Incomplete PenetratArea of Possible Oil Generation Maturity) from Tertiary-Age [<65 Aleutian Basin). Uplifts in southAleutian basin are highly gener

Lower Tertiary (33-39 Ma) Rocks Dominantly Volcanic or Plutonic 

EXPLANATIO

4,578+

Koniag 1

Interpretation of North Aleutian COST 1 and Sandy River 1 Winterpretation of onshore wells from Johnsson and Howell (Bulletin 2142, plate 1) and Molenaar (1996a, same pub., figscompiled from merging 0.6% Ro isograd structure (this mapdatums B, C, and D (Turner et al., 1988, MMS OCS Report M

GreatBasins 2

Becharof Lake 1 

Fin

Koniag 

PainterCreek 1

Ugashik 1

PortHeiden 1

SandyRiver 1

North Aleutian

Shelf COST 1

Big River 1

DavidRiver 1, 1A

HoodooLake 1

HoodooLake 2

CanoeBay 1

CathedralRiver 1

Bertha 1

Monkshood 1

St. GeorgeCOST 2

4,758 +

140

est. ~200 ft

728

1,713

49+

3,927

2763 +

0 ft Sediments

(All Volcanics)

All Volcanics

474

1127

204

577

0

Areas of Possible Gas, Condensate, and Oil 

Generation (Sufficient Thermal Maturity) within 

Tertiary-age strata of North Aleutian and Amak Basins

Figure 19: Isopach map for thickness of Tertiary-age rocks within oil generation zone (0.6% to 1.35% vitrinite reflectance) with probamaturity sufficient for oil generation within and beneath North Aleutian basin.

109
0

2000

4000

6000

8000

10000

12000

14000

16000

0123

Total Organic Carbon (TOC, Wt.%)

Depth (feet, bkb)

Exlog-Cuttings

0

2000

4000

6000

8000

10000

12000

14000

16000

0 100 200 300 400 500

Hydrogen Index (mg S2/gTOC)

Exlog-Cuttings

NAKNEK FM.

(UPPER JURASSIC)

SHELIKOF FM.

(MIDDLE JURASSIC)

KIALAGVIK FM.

(MIDDLE JURASSIC)

TALKEETNA FM.

(LOWER JURASSIC)

KAMISHAK FM.

(UPPER TRIASSIC)

(re-assigned to Jurassic

by Mickey et al., 2005)

THERMAL

MATURITY

T.A.I.

2.5

3.0

3.5

3.8

3.8

OIL GENERATION DRY GAS GENERATION OIL DESTRUCTION AND GAS GENERATION

1.47%

Ro

Cathedral River 1 Well

Generation Potential (TOC) and Hydrocarbon Type (Hydrogen Index)

Source Rock Potential Classes from Peters (1986, AAPG 70/3, 320, tbl. 1). Stratigraphy from Detterman (1990, USGS OF 90-279). TOC and pyrolysis data from Exlog (1982; 

available as AK Geol. Matl’s Center Report 2). T.A.I. data from Anderson et al. (1977a; available as AK Geol. Matl’s Center Report 47). Potential Hydrocarbon Type Classes from 

Peters (1986, AAPG 70/3, 320, tbl. 2). T.A.I. (Thermal Alteration Index) Values and Thermal Maturity Zones from Boreham and Powell (1993, AAPG Stud. Geol. 38, fig. 5)

An oil-base additive (Soltex) was 

added to the drilling mud below 

7,500 ft and may have 

contaminated cuttings samples

Sherwood\...\Fig20-CathedralRiver1TOC&HIPlot.cdr POOR

FAIR

GOOD

VERY

GOOD

GAS

SOURCE

GAS & OIL

SOURCE

OIL

SOURCE

Figure 20: Generation potential (total organic carbon) and hydrocarbon type (hydrogen index) indicators for 

Mesozoic rocks in the Cathedral River 1 well. Analyses conducted and reported by Exlog (1982). T.A.I. (thermal 

alteration index) data from Anderson et al. (1977a). Vitrinite reflectance data point at 10,650 feet bkb from 

Robertson Research (1982).

110
Total organic carbon data from Exlog (1983) and Robertson 

Research (1983, Apps. III, IV). Source Rock Potential 

Classes from Peters (1986, AAPG 70/3, 320, tbl. 1).

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

0.1 1 10 100

Depth (feet, bkb)

Exlog-Cuttings (Coal Retained); n = 60

Exlog-Conventional Cores; n = 62

Exlog-Sidewall Cores; n = 12

Robertson Research-Cuttings; n = 262

Robertson Research-Sidewall Cores; n = 121

Robertson Research-Conventional Cores; n = 139

Exlog-Cuttings/Coal Removed (n=268) VERY GOOD

POOR

FAIR

GOOD

Total Organic Carbon (% Wt.)

Hydrogen Index data from Exlog (1983) and Roberston 

Research (1983, App. IV). Potential Hydrocarbon Type 

Classes from Peters (1986, AAPG 70/3, 320, tbl. 2, 

assume Ro=0.6%) 150 300

Coal

Sequence Coal Sequence Coal Sequence

Coal

Sequence

Coal

Sequence

North Aleutian Shelf COST 1 Well

Sherwood\....\Fig21-NoAleutianCOST1-TOC&HI.cdr

Thermal

Maturity

Figure 21: Generation potential (total organic carbon) and hydrocarbon type (hydrogen index) indicators for 

Tertiary rocks in the North Aleutian Shelf COST 1 well. Analyses from Exlog (1983) and Robertson Research 

(1983). Posted vitrinite reflectance values are from data fits in figure 17.

111
Algal Coals

Source Type Classificatio(1984, Pet. Fm. & Occ., 2This diagram plots H/C vs classifications may be disalgal (e.g., boghead, can(1984, p. 241, fig. II.8.8).

High-S, Lignite, or Wood?

Source Type Classifications adapted from Tissot and Welte (1984, Pet. Fm. & Occ., 2nd Ed., Fig. II.4.14) for H/C vs O/C. This diagram plots H/C vs [O+S]/C and relationship to classifications may be distorted by sulfur content.

Type I (Oil)

Type II (Oil & Gas)

Type III (Gas)

Range of CoalCompositions Sour

of Co(198

Separation of coal fragments from cuttings attempted by water flotation by Exlog (1983, p. 8)

Sherwood\....\Fig22New-CoalySWCVanKrevelenDiagram.cdr

Coal-Bearing vs Coal-Free Cuttings & Core Samples

Pyrolysis and Elemental Analysis

A B

C D

Figure 22: (A) Modified Van Krevelen plot comparing Exlog (1983) pyrolysis data for cuttings with coal partly removed (by flotation with coal content retained. The fields of the two data sets essentially overlap; (B) Sidewall and conventional core samples, with coal-b

samples plotted separately-all samples with HI>151 are described as coal-bearing; (C) Van Krevelen-type plot showing elemental data 

conventional core samples, with coal-bearing and coal-free samples plotted separately; (D) Van Krevelen-type plot with elemental ana

samples with HI>150 (shows that these samples are dominated by Type III kerogens). Tertiary rocks penetrated by the North Aleutian gas-prone and offer little potential for generation of oil. All core data from Robertson Research (1983, Apps. IV, VII).

112
Becharof Lake

Ugashik Lakes

Iliamna Lake

Kuka L.

Lake

Brooks

Naknek Lake

Bear

Lake

BRUIN BAY FAULT

Magmatic Mesozoic

Basement

Sedimentary Mesozoic

Basement

Ugashik Anticline

164°

162°

160°

158°

156°

58°

56°

OCS Sale 92

Sale 92

High Bid Tract

$24.36 MM

Prospect 11 collected 

$69.4 MM in Sale 92 

(73% of Sale)

Figure 6

2000

3000

4000 5000

6000

7000 7000

4000

5000

6000

ALEUTIAN RANGE VOLCANIC ARC

ST.

GEORGE

BASIN

NORTH ALEUTIAN--

BRISTOL BAY BASIN AMAK BASIN

Acoustic Basement <3,000 Feet

BLACK HILLS UPLIFT

Bristol Bay

Bering Sea

Pacific Ocean

ALASKA

NORTH ALEUTIAN BASIN PLANNING AREA

Sherwood\....\AkPenGasSeepLocationMap.cdr, revised 24 July 03

Balboa

Bay

Sherwood\....\Fig23-GasSeeps&DataAkPen.cdr

GAS SEEPS, ALASKA PENINSULA

0 50

MILES

Great

Basins 2

Great

Basins 1

Becharof Lake 1

Bear

Creek 1

Wide Bay 1

Pacific 1

Costello 1

Pacific 2

Costello 2

Grammer 1

Finnegan 1

Lathrop 1

McNally 1

Alaska 1

Lee 1

Koniag 1

Painter

Creek 1

Ugashik 1

Port

Heiden 1

Sandy

River 1

North

Aleutian

COST 1

Big River 1

David

River 1, 1A

Hoodoo

Lake 1

Hoodoo

Lake 2

Canoe

Bay 1

Cathedral

River 1

Bertha 1

Monkshood 1

St. George

COST 2

Tested Gas

90 Mcfd

Oil Shows

Oil Shows

Oil Shows

Oil Staining

Gas Shows

Tested Gas

(5-9 Mcfd)

Oil Shows

Gas Shows

Shallow

Gas Shows

Oil Show

Jur-Cret Oil

Source Rocks?

Triassic Oil

Source Rocks

Jurassic Oil

Source Rocks

Oil Stain

75 149

76

Port

Moller

Port

Heiden

Chignik

Naknek

King

Salmon

False

Pass

Cold

Bay

Sand

Point

Carbon Dioxide

Hydrocarbons

+ Hydrogen

Nitrogen + Oxygen+ Argon 

+ Hydrogen Sulfide + Helium

50 50

50

76

75

149

Cook Inlet

Oil & Gas

Fields (n=23)

Alaska

Peninsula

Gas Seeps

Figure 23: Analyses of gas compositions from Alaska Peninsula seeps and oil and gas fields in northern Cook Inlet 

basin. Alaska Peninsula gas seeps are mostly carbon dioxide and probably reflect magmatic intrusion and 

decarbonation of limestones in the subsurface. All data are from Moore and Sigler (1987, p. 15-21).

113
0

100020003000400050006000700080009000

10000

-90 -70 -50 -30 -10 10

Methane Del 13 C (PDB)

Dep

ht (feet,bkb)

THER

GA

B

BIOGENIC GAS

THERMOGENIC GAS

MilkyRiver

Fm.

Bear

Lake

Fm.

Stepovak

Fm.

Tolstoi

Fm.

Jurassic-Cretaceous

Plutonic Rocks

Sherwood\....\Fig24-BecharofLakeCarbonIsotopes.cdr

Separation of biogenic and thermogenic methane at -55.0 Del C (PDB) from Hunt (1979, p. 176) 13

Carbon isotope data from public well data file, Becharof Lake 1 well, Alaska Oil and Gas Conservation Commission. Stratigraphy from correlations by authors. Thermal maturity isograds for Becharof Lake 1 well from Johnsson and Howell (1996, pl. 1) and Molenaar (1996a).

DST 5

7,470-7,550 ft

Plot classification fand Claypool and K

Becharof Lake 1 Well

Depth Profile for Methane Carbon Isotopes on Headspace Gas, Molecular Composition (and Inferred Isotope) for DS

A B

ThermalMaturity

(Vitrinite

Reflectance)

0.6%

1.3%

2.0%

7929 ft8420 ft

9251 ft (proj.

Liquid floor)

1.77% Ro at TD at 9017 ft

Submature

Oil

Gas

Figure 24: A) Methane carbon isotope data for Amoco Becharof Lake 1 well. Gas is biogenic above 3,000 feet, and thermogenic belo

of gas are mixed in the intermediate interval from 3,000 to 5,500 feet. Data from AOGCC (1985, Carbon Isotope Ratios). B) Gas recothe interval 7,470 to 7,550 feet consists of 87.5% methane, 4.7% ethane, 2.3% propane, 0.8% butane, 1.0% hydrogen, and 3.7% “other” data) and classifies as thermogenic in cross-plot of Schoell (1984) and Claypool and Kvenvolden (1983).

114
North Aleutian COST 1 Well

Interpretation of Depositional Environment and Thermal Maturity

Extracts From Show Interval 15,300 to 16,800 ft bkb

0.1

1

10

0.1 1 

Phytane/n-C18

Pristane/n-C17

2003 Baseline-DGSI Data1983 Robertson Research Data

Maturation

Biodegradation

Oxidizing Reducing

Terrigenous Organic Matter

Peat-Coal Environments

Mixed Organic Sources

Marine Organic Matter (Algal/Bacterial)

Plot fields from Shanmugam AAPG Bull., 69/8, 1241, fig. 4

Sherwood\....\Fig25-NABCOST1-ExtractDepositionalEnvironment.cdr

Thermal maturity of show interval = 0.78% to 1.04% vitrinite reflectance

Figure 25: Cross plot for Pristane/n-C17 versus Phytane/n-C18 ratios for rock extracts from the oil show interval in nonmarine Eocene 15,300 to 16,800 feet bkb in the North Aleutian Shelf COST 1 well. A terrigenous, coal-bearing depositional environment is indicated, 

within Tertiary nonmarine rocks. All data from Baseline DGSI (2003) and Robertson Research (1983).

115
0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

0 2 4 6 8 10 12

Pristane/Phytane

Fraction of Samples

Fraction of Samples

Fraction of Samples

Tertiary (Nonmarine) Extracts & Oils

Cook Inlet Basin

Mesozoic (Marine) Extracts & Oils

Alaska Peninsula & Cook Inlet Basin

North Aleutian Basin COST 1

Eocene Nonmarine-Tolstoi Formation

Show Interval (15300-16800 ft bkb) Extracts

Mean = 4.25

(n = 9)

Mean = 5.76

(n = 7)

Mean = 2.91

(n = 32)

Data for North Aleutian Basin COST 1 well by 

Robertson Research for ARCO (1983) and by 

Baseline-DGSI for Minerals Management Service 

(2003). All other pristane/phytane data from Magoon 

and Anders (1992)

Sherwood\...\Fig26-NAB-Extracts-Pristane-PhytaneRatios.cdr

PRISTANE/PHYTANE RATIOS FOR 

EXTRACTS FROM NORTH ALEUTIAN 

SHELF COST 1 WELL AND COOK INLET 

OILS AND EXTRACTS

Figure 26: Histograms for Pristane/Phytane ratios of North Aleutian Shelf COST 1 well extracts, Tertiary 

(nonmarine) extracts and oils, and Mesozoic (marine) extracts and oils. The thermal maturity of the oil show 

interval in the North Aleutian Shelf COST 1 well ranges from 0.78% to 1.04% vitrinite reflectance. These data 

suggest that oil shows in the North Aleutian Shelf COST 1 well originated from Tertiary nonmarine sources. All 

data from Baseline DGSI (2003), Robertson Research (1983), and Magoon and Anders (1992).

116
Carbon Isotopes of Rock Extracts and Oil from Fields and Seeps

North Aleutian COST 1 Well, Alaska Peninsula, and Cook Inlet

-31.0-30.0-29.0-28.0-27.0-26.0-25.0

-32.0 -31.0 -30.0 -29.0 -28.0 -27.0 -26.0 

Saturate Fraction Carbon Isotope Composition

Aromatic Fraction Carbon Isotope Composition North Aleutian COST 1 Well Extracts 15700-16

Alaska Peninsula Oil Seeps [Mesozoic Rocks] Tertiary (Nonmarine) Rock Extracts Jurassic (Marine) Rock ExtractsTertiary (Nonmarine) Oil and CondensateMesozoic-Sourced (Marine) OilsTriassic (Marine) Rock Extracts

Data for North Aleutian Basin COST 1 well by Baseline-DGSI for Minerals Management Service (2003). All other isotope data from Magoon and Anders (1992)

Jurassic and Triassic 

Marine Oils and Rock 

Extracts

Tertiary Nonmarine Oils 

and Rock Extracts

SoferLines

Marine Oils

Nonmarine Oils

North Aleutian Shelf 

COST 1 Well Extracts

Sherwood\.....\Fig27-NAB-Extract-CarbonIsotopes-SoferPlot.cdr

Figure 27: Sofer cross plot for carbon isotopes for aromatics and saturates, comparing North Aleutian Shelf COST 1 well extracts, Terand oils, and Mesozoic (marine) extracts and oils. The thermal maturity of the oil show interval in the North Aleutian Shelf COST 1 w1.04% vitrinite reflectance. These data suggest that oil shows in the North Aleutian Shelf COST 1 well originated from Tertiary nonmfrom Baseline DGSI (2003), Robertson Research (1983), and Magoon and Anders (1992).

117
A

B

Sherwood\....\Fig28-TrianglePlots-Sats-Aroms & Steranes.cdr

MMSAK2003-1 Baseline-DGSI rock extracts from core

and cuttings composite samples, North 

Aleutian Shelf COST 1 well (n = 2)

RR-3 Robertson Research rock extracts from core

chips, North Aleutian Shelf COST 1 well (n = 7)

Tertiary (Nonmarine) Rock Extracts

from Cook Inlet (n = 5)

Triassic (Marine) Rock Extracts from

Alaska Peninsula (n = 3)

Jurassic (Marine) Rock Extracts from Alaska

Peninsula and Cook Inlet (n = 9)

Tertiary (Nonmarine) Condensates

from northern Cook Inlet (n = 2)

Oil Seeps, Alaska Peninsula near Becharof

Lake (n = 2)

Mesozoic (Marine) Oils and Condensates from

northern Cook Inlet (n = 18)

EXPLANATION

Mesozoic

(Marine)

Oils

Tertiary

(Cook Inlet)

Extracts

Upper

Triassic

(Puale Bay)

Extracts

Middle Jurassic

(Cook Inlet & Puale Bay)

Extracts

MMSAK2003-2

(Cuttings)

MMSAK2003-1

(Core)

RR-5

RR-4

RR-3

RR-2

RR-6

RR-1

RR-7

SATURATES, AROMATICS, AND NON-HYDROCARBONS

North Aleutian Shelf COST 1 Well, Alaska Peninsula, and Cook Inlet Extracts and Oils

100% SATURATES

100% AROMATICS

NON-HYDROCARBONS: NSO’s + Asphaltenes (North Aleutian Basin COST 1 Extracts)

 Resins + Asphaltenes (All Other Data for Extracts & Oils)

100% NON-HYDROCARBONS*

Data for North Aleutian Shelf COST 1 well by 

Robertson Research for ARCO (1983) and by 

Baseline DGSI for Minerals Management Service 

(2003). All other liquid chromatograph data from 

Magoon and Anders (1992)

Sherwood\...\Fig28a-TrianglePlot-Sat-Aro-NSO.cdr

50

50

50

STERANE RATIOS

North Aleutian Shelf COST 1 Well Extracts

C27 STERANES

C28 STERANES C29 STERANES

Sherwood\...\Fig28b-TrianglePlot-Steranes.cdr

50

50

50

PLANKTON

LACUSTRINE

OPEN MARINE

ESTUARINE

TERRESTRIAL HIGHER

PLANTS

Facies classifications after Huang and 

Meinschein (1979, Geochim. Cos. Acta, 

v.43, 739)

A

B

B A

A

B

B

A

Sample MMSAK2003-1 (Core Chips, 16,006-16,720 ft)

Sample MMSAK2003-2 (Cuttings, 15,700-16,800 ft)

C S (218), C27-C28-C29 Steranes ABB

C S (218), C27-C28-C29 Steranes ABB

C R (217), C27-C28-C29 Steranes AAA

C R (217), C27-C28-C29 Steranes AAA

Figure 28: A) Triangular plot for saturates versus aromatics versus non-hydrocarbons, North Aleutian Shelf COST 

1 well extracts, Tertiary (nonmarine) extracts and oils, and Mesozoic (marine) extracts and oils. The thermal 

maturity of the oil show interval in the North Aleutian Shelf COST 1 well ranges from 0.78% to 1.04% vitrinite 

reflectance. These data suggest that oil shows in the North Aleutian Shelf COST 1 well originated from Tertiary 

nonmarine sources. All data from Baseline DGSI (2003), Robertson Research (1983), and Magoon and Anders 

(1992). B) Triangular plot for C27-C28-C29 steranes for 2 extracts from interval 15,700 to 16,800 ft bkb in the 

North Aleutian Shelf COST 1 well. Data from Baseline DGSI (2003 and Appendix 3 of this report). C29 steranes 

are dominant but ratios suggest mixing of marine and nonmarine environments. Facies classifications after Huang 

and Meinschein (1979) and Shanmugam (1985, fig. 5)

118
Thermal Maturity of Show Interval: 0.78% to 1.04% Vitrinite Reflectance

Thermal Maturity of Show Interval: 0.78% to 1.04% Vitrinite Reflectance

Unidentified

Peak

North Aleutian Shelf COST 1 Well, M/Z 191 Chromatograms for Terpanes

A. Show Interval Extract: (Sample MMSAK2003-1: Cores 18 & 19, 16006-16029 and 16701.2-16720 ft bkb, Composited)

B. Show Interval Extract: (Sample MMSAK2003-2: Cuttings, 15,700 to 16,800 ft bkb, Composited)

Sherwood\....\Fig29-2003-1MZ191Fragmentogram18-65.cdr

Figure 29: (A) Excerpt from M/Z 191 chromatogram by Baseline DGSI (2003) for an extract from sample 

MMSAK2003-1, composited from cores 18 and 19, 16,006-16,720 ft bkb, North Aleutian Shelf COST 1 well. (B) 

Entire M/Z 191 chromatogram by Baseline DGSI (2003) for an extract from sample MMSAK2003-2 composited 

from cuttings, 15,700-16,800 ft bkb. (When the interval from 15,700-16,800 ft was drilled, the well was uncased 

below 9-5/8 inch casing at 13,287 ft bkb (Turner et al., 1988, p. 7) and subject to contamination by cave.) Both 

chromatograms show abundant C19 to C30 tricyclic terpanes, with C23 + C24 peak areas dominant in both samples 

(C19-tri/C23-tri = 0.43 to 0.75). In the lower chromatogram (for the cuttings extract), a prominent unidentified 

terpane between peak A (C19-tri) and peak B (C20-tri) is not present in the core extract. This unidentified peak is 

prominent among condensates of nonmarine (Tertiary) origin in the northern Cook Inlet (Magoon and Anders, 1992, 

fig. 13.9, spl. 18, and p. 264) but absent from other Cook Inlet samples. Magoon and Anders (1992) and Magoon 

(1994) have noted that abundant tricyclic terpanes characterize extracts from Upper Triassic rocks at Puale Bay 

(located in fig. 2) and some oils in southern Cook Inlet basin. However, several other parameters (figs. 25, 26, 27, 

and 28) suggest that the extracts from the “oil show interval” in the North Aleutian Shelf COST 1 well probably 

originated from Tertiary nonmarine rocks. 

119
65.0 61.0 54.8 49.0 37.0 33.7 28.5 23.8 16.4 11.2 5.3 3.6 1.8

60 50 40 30 20 10 0

3.0

Ma?

Early Oil Generation (TTI>3)

Peak Oil Generation (TTI>10)

End of Oil Generation; Main Gas Generation (TTI>180)

Liquid Floor (TTI>900)

Deposition Bear Lake/Stepovak

TIMELINES--CRITICAL PETROLEUM SYSTEM EVENTS FROM BURIAL MODEL

Today

Today

61+ Ma

28.5 Ma 4.5 Ma Hz “D”

17.3 Ma

(Base of Well)

TTI=75

31.7 Ma

(Base of Well, Corrected for Fault Gap)

38.5 Ma?

(Basin Floor [Est])

35.4 Ma

27.0 Ma

(Base of Well, Corrected)

7.7 Ma

(Base of Well, Corrected for

Fault Gap)

34.4 Ma ?

(Basin Floor [Est])

24.2 Ma ?

(Basin Floor [Est])

10.0 Ma ?

(Basin Floor [Est])

Traps Form on Flanks of Basement Horsts

(Rifting, Horst Elevation)

Traps Form in Drape Anticlines Over Basement Horsts

(Compaction, Drape Folds, Minor Faulting)

Deeper Results from Lopatin Model Not Supported by Well Thermal Maturity Data

DEPTH

(ft bkb)

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

11000

12000

13000

14000

15000

16000

17000

19000

20000

21000

22000

18000

19000

20000

21000

22000

18000

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

11000

12000

13000

14000

15000

16000

17000

PRESENT-DAY

SUBSURFACE

TEMPERATURE ( F) O

60

80

100

120

140

160

180

200

220

240

260

280

300

320

324

at TD

(17,155 ft bkb)

MODELED TTI & 

EQUIVALENT Ro%

900 (2.00% Ro)

567

at TD

(1.80% Ro)

92 (1.07% Ro)

10 (0.60% Ro)

3 (0.50% Ro)

180 (1.35% Ro)

75 (1.00% Ro)

OBSERVED 

VITRINITE 

REFLECTANCE

(Ro%)

0.25

0.35

0.40

0.45

0.50

0.55

0.60

0.70

0.75

0.80

0.88

1.00

0.92

1.07

1.097

at TD

(Corrected,

17,802 ft bkb)

1.35

(Proj.)

2.00

(Proj.)

Ft Gap

(647 ft)

PLAY

SEQUENCE

MILKY RIVER

SEQUENCE

(PLAY 4)

BEAR LAKE-STEPOVAK

SEQUENCE (PLAYS 1, 3)

TOLSTOI SEQUENCE

(PLAY 2)

TTI=3 (~ 0.5% Ro)

TTI=10 (~ 0.6% Ro)

TTI=75 (~ 1.0% Ro)

TTI=92 (~ 1.07% Ro)

TTI=180 (~ 1.35% Ro)

Actual Vit. Ref. = 1.00% Ro (Isograd Path Hand-Sketched)

1.00% Ro From Well Data

TTI=900 (~ 2.00% Ro)

?????

TTI Ro% Maturity 

 3 0.50 Shallowest Top Oil Generation

 10 0.60 Top Peak Oil Generation Zone

 75 1.00 Peak Oil Generation

 92 1.07 Peak Wet Gas, Top Dry Gas Gen.

180 1.35 Base Oil Generation Zone

900 2.00 Liquid Floor

TTI-Ro Correlations

North Aleutian Shelf COST 1 Well

Lopatin Burial History Model and Critical Events Timelines

Sherwood\....\Fig30-BurialHistory-NAB-COST1.cdr

Software: , ver. 1.0, 1985, by Platte River Associates, Inc., and D. 

Waples.

Lopatin-From Here to Maturity

Geologic time scale from Palmer (1998). TTI thresholds from Waples (1980, AAPG, 

64/6, p. 916). TTI calculations and Ro data do not correlate below 15,000 feet md.

Early Late

Cret.

PALEOCENE

Early Middle Late

EOCENE OLIGOCENE

Early Late

MIOCENE

E L

PLIO.

DEPTH

(ft bkb)

CENOZOIC

Early Middle Late

Q.

GAS

GEN.

PEAK OIL

GENERATION

EARLY OIL

GENERATION

Thickness of 

sedimentary 

column beneath 

base of well is 

unknown, but 

may range up to 

3,000 feet

??

??

??

??

??

??

??

Late Paleocene Below Well?

Estimated Base of Sedimentary Fill

Drilled TD at

17,155 ft bkb Fault Gap-Corrected TD at 17,802 ft bkb

Fault Gap (647 ft) at 15,620 ft

Base of Well (Fault Gap-Corrected)

SEISMIC HZ D

(Late Eocene)

Fault Gap

SEISMIC HZ C

(Early Oligocene)

SEISMIC HZ B

(Late Oligocene)

SEISMIC HZ A

(Early Pliocene)

Unknown Mesozoic (Granitic?) Rocks

(Basement Not Penetrated by COST Well)

MR Q

Base Bear Lake Fm.

Top Stepovak Fm.

Tolstoi

Fm.

Base Stepovak Fm.

Top Tolstoi Fm.

Basin Floor

at 20,800 ft (Est)

MODEL INPUT DATA

21.2

Ma?

Figure 30: Burial history plot for North Aleutian Shelf COST 1 well, with timelines for critical petroleum system 

events.

120
121

+ + + + + + + + + + + + + + +

+ +

+

+

+

+

+ +

+

+

+

+ +

+

+ + + + + + + +

+

+

+ + + +

+

+

+ + + +

+

+

+ + + +

Fractures

BRUIN BAY FAULT??

Petroleum System Elements for North Aleutian Basin

Sherwood\...\PetroleumSystemElements.cdr Adapted from unpublished drawing by G.C. Martin (ca. 1990)

ENT UNCONFORMITY

Bsmt

Amak Basin Black Hills Uplift North Aleutian Basin

SEISMIC HORIZON “A”

SEISMIC HORIZON “B”

SEISMIC HORIZON “C”

SEISMIC HORIZON “D”

BASEM

Hz “D”

NON-SEALING OVERBURDEN

PRINCIPAL RESERVOIR SEQUENCE

REGIONAL SEAL

GAS/COND

KITCHEN GAS/COND

KITCHEN

THERMALLY-MATURE

(POST-GENERATIVE)

MESOZOIC ROCKS

DISRUPTED

OIL POOLS

GRANITIC

ROCKS

MIGRATION

MIGRATION

Top Oil & Gas Generation Zone

+ + + + + + + + + + + + + + +

+

+

+

+

+

+ +

+

+ + + + + + + +

+

+

+

+

+ + + +

+

+

+

+

+ + + +

+

+

+

+

+ + + +

Fractures

BRUIN BAY FAULT??

Milky River Play [4] (Biogenic Gas) Milky River Play [4] (Biogenic Gas)

Bear Lake-Stepovak Play 

[1] (Oil and Gas)

Black Hills UpliftAmak Basin Play [3] 

(Oil and Gas)

Play Concepts for North Aleutian Basin

Sherwood\...\PlayConcepts-CrossSection.cdr Adapted from unpublished drawing by G.C. Martin (ca. 1990)

Tolstoi Play [2] 

(Oil and Gas)

Tolstoi Play [2] 

(Oil and Gas)

Mesozoic Buried 

Granitic Hills Play [6] 

(Oil and Gas)

Mesozoic Deformed 

Sedimentary Rocks 

Play [5] (Oil)

Amak Basin Black Hills Uplift North Aleutian Basin

SEISMIC HORIZON “A”

SEISMIC HORIZON “B”

S

S

E

EISMIC HORIZON “C”

ISMIC HORIZON “D”

BASEMENT UNCONFORMITY

Hz “D”

Bsmt

A.

B.

Sherwood\...\Fig31-PetSystemElements&Plays-NAleutBsn.cdr

Figure 31: Schematic cross sections illustrating petroleum system elements and play concepts for North Aleutian 

Basin OCS Planning Area. 

A) Petroleum system elements, including regional reservoir sequence floored by a regional seal and underlain by 

deep gas/condensate “kitchens” in grabens flanking uplifts. Petroleum generated in “kitchens” migrates to traps in 

shallow reservoir formations draped over basement uplifts via faults that pierce the regional seal. The Black Hills 

uplift may be reached by long-distance lateral migration of petroleum across highly faulted areas. Fault disruption 

of Mesozoic oil pools beneath the Black Hills uplift may release oil into overlying strata. Arrows show hypothetical 

migration paths for gas (red) and oil (green). 

B) Six oil and gas plays defined for North Aleutian Basin OCS Planning Area, separated on the basis of reservoir 

character, structural style, and access to petroleum sources.
Tertiary Rocks

Mesozoic Rocks

PLAY 1: BEAR LAKE-STEPOVAK FMS.

(Oligocene-Miocene)

Ugashik Lak

BearLake

Magmatic Mesozoic Basement

Sedimentary Mesozoic Basement

164°

162°

160°

158°

58°

56°

Sale 92High Bid Tract$24.36 MM

Top Prospect collected $69.4 MM in Sale 92 (73% of Sale)

Figure 6

ALASKAPENINSULA ST. GEORGE BASIN NORTH ALEUTIAN BASIN

AMAK BASIN

BLACK HILLS UPLIFT

Bristol Bay

Pacific Ocean

ALASKA

NORTH

ALEUTIAN

BASIN

OCS

PLANNINGAREA

Sherwood\....\Fig32-Play1BearLakeMap.cdr

0 50

MILES

Leased Bl$95.4 MM, 

Leased Blo$1.3 MM, 3

Well, Plug

Gas Seep

Seismic Pr

Uplift or S

EXPLAN

Figure 6

Oil Seep. seep (see 

* Becharof Lake oil seep reported as “loBiologic markers in sediments and petro

GreatBasins 2

Becharof Lake 1

Fin

Koniag 

PainterCreek 1

Ugashik 1

PortHeiden 1

SandyRiver 1

North AleutianShelf COST 1

Big River 1

DavidRiver 1, 1A

HoodooLake 1

HoodooLake 2

CanoeBay 1

CathedralRiver 1

Bertha 1

Monkshood 1

St. GeorgeCOST 2

Tested Gas90 Mcfd

Oil Shows

Oil Shows

Oil Shows

Oil Staining

Gas Shows

Tested Gas(5-9 Mcfd)

Oil Shows

Gas Shows

ShallowGas Shows

Oil Show

Jur-Cret OilSource Rocks?

JurassSource 

Oil Shows

2000

3000 4000

5000 6000 7000

7000

4000

5000

6000

Figure 32: Area of play 1, Bear Lake-Stepovak play, North Aleutian Basin OCS Planning Area, Alaska.

122
PLAY 2: TOLSTOI FM.

(Eocene-Oligocene)

Ugashik Lak

BearLake

Magmatic Mesozoic Basement

Sedimentary Mesozoic Basement

164°

162°

160°

158°

58°

56°

Sale 92High Bid Tract$24.36 MM

Top Prospect collected $69.4 MM in Sale 92 (73% of Sale)

Figure 6

ALASKAPENINSULA ST. GEORGE BASIN NORTH ALEUTIAN BASIN

AMAK BASIN

BLACK HILLS UPLIFT

Bristol Bay

Pacific Ocean

ALASKA

Sherwood\....\Fig33-Play2TolstoiFmMap.cdr

NORTH

ALEUTIAN

BASIN

OCS

PLANNINGAREA

0 50

MILES

Leased Blo$95.4 MM, 2

Leased Blo$1.3 MM, 37 

Well, Plugg

Gas Seep

Seismic Pr

Uplift or St

EXPLAN

Figure 6

Oil Seep. *seep (see b

* Becharof Lake oil seep reported as “locaBiologic markers in sediments and petrol

GreatBasins 2

Becharof Lake 1

Fin

Koniag 

PainterCreek 1

Ugashik 1

PortHeiden 1

SandyRiver 1

North Aleutian

Shelf COST 1

Big River 1

DavidRiver 1, 1A

HoodooLake 1

HoodooLake 2

CanoeBay 1

CathedralRiver 1

Bertha 1

Monkshood 1

St. GeorgeCOST 2

Tested Gas90 Mcfd

Oil Shows

Oil Shows

Oil Shows

Oil Staining

Gas Shows

Tested Gas(5-9 Mcfd)

Oil Shows

Gas Shows

ShallowGas Shows

Oil Show

Jur-Cret OilSource Rocks?

JurassSource 

Oil Shows

Figure 33: Area of play 2, Tolstoi play, North Aleutian Basin OCS Planning Area, Alaska.

123
Tertiary Rocks

Mesozoic Rocks

PLAY 3: BLACK HILLSUPLIFT-AMAK BASIN

Ugashik Lak

BearLake

Magmatic Mesozoic Basement

Sedimentary Mesozoic Basement

164°

162°

160°

158°

58°

56°

Sale 92High Bid Tract$24.36 MM

Top Prospect collected $69.4 MM in Sale 92 (73% of Sale)

Figure 6

ALASKAPENINSULA ST. GEORGE BASIN NORTH ALEUTIAN BASIN

AMAK BASIN

Acoustic Basement <3,000 Feet

BLACK HILLS UPLIFT

Bristol Bay

Pacific Ocean

ALASK

Sherwood\....\Fig34-Play3BlackHillsMap.cdr

NORTH

ALEUTIAN

BASIN

OCS

PLANNINGAREA

0 50

MILES

Leased Blo$95.4 MM, 2

Leased Blo$1.3 MM, 37 

Well, Plugg

Gas Seep

Seismic Pr

Uplift or St

EXPLAN

Figure 6

Oil Seep. *seep (see b

* Becharof Lake oil seep reported as “locaBiologic markers in sediments and petrol

GreatBasins 2

Becharof Lake 1

Fin

Koniag 

PainterCreek 1

Ugashik 1

PortHeiden 1

SandyRiver 1

North Aleutian

Shelf COST 1

Big River 1

DavidRiver 1, 1A

HoodooLake 1

HoodooLake 2

CanoeBay 1

CathedralRiver 1

Bertha 1

Monkshood 1

St. GeorgeCOST 2

Tested Gas90 Mcfd

Oil Shows

Oil Shows

Oil Shows

Oil Staining

Gas Shows

Tested Gas(5-9 Mcfd)

Oil Shows

Gas Shows

ShallowGas Shows

Oil Show

Jur-Cret OilSource Rocks?

JurassSource 

Oil Shows

Figure 34: Area of play 3, Black Hills Uplift-Amak Basin, North Aleutian Basin OCS Planning Area, Alaska.

124
PLAY 4: MILKY RIVER BIOGENIC

GAS (Plio-Pleistocene)

Ugashik Lak

BearLake

Magmatic Mesozoic Basement

Sedimentary Mesozoic Basement

164°

162°

160°

158°

58°

56°

Sale 92High Bid Tract$24.36 MM

Top Prospect collected $69.4 MM in Sale 92 (73% of Sale)

Figure 6

ALASKAPENINSULA ST. GEORGE BASIN NORTH ALEUTIAN BASIN

AMAK BASIN

BLACK HILLS UPLIFT

Bristol Bay

Pacific Ocean

ALASKA

Sherwood\....\Fig35-Play4BeringPlatform.cdr

NORTH

ALEUTIAN

BASIN

OCS

PLANNINGAREA

0 50

MILES

Leased Blo$95.4 MM, 2

Leased Blo$1.3 MM, 37 

Well, Plugg

Gas Seep

Seismic Pro

Uplift or St

EXPLAN

Figure 6

Oil Seep. *seep (see b

* Becharof Lake oil seep reported as “locaBiologic markers in sediments and petrole

GreatBasins 2

Becharof Lake 1

Finn

Koniag 

PainterCreek 1

Ugashik 1

PortHeiden 1

SandyRiver 1

North Aleutian

Shelf COST 1

Big River 1

DavidRiver 1, 1A

HoodooLake 1

HoodooLake 2

CanoeBay 1

CathedralRiver 1

Bertha 1

Monkshood 1

St. GeorgeCOST 2

Tested Gas90 Mcfd

Oil Shows

Oil Shows

Oil Shows

Oil Staining

Gas Shows

Tested Gas(5-9 Mcfd)

Oil Shows

Gas Shows

ShallowGas Shows

Oil Show

Jur-Cret OilSource Rocks?

JurassiSource 

Oil Shows

Figure 35: Area of play 4, Milky River Biogenic Gas play, North Aleutian Basin OCS Planning Area, Alaska.

125
PLAY 5: MESOZOIC DEFORMED

SEDIMENTARY ROCKS

(Triassic-Cretaceous)

Ugashik Lak

BearLake

Magmatic Mesozoic Basement

Sedimentary Mesozoic Basement

164°

162°

160°

158°

58°

56°

Sale 92High Bid Tract$24.36 MM

Top Prospect collected $69.4 MM in Sale 92 (73% of Sale)

Figure 6

ALASKAPENINSULA ST. GEORGE BASIN NORTH ALEUTIAN BASIN

AMAK BASIN

BLACK HILLS UPLIFT

Bristol Bay

Pacific Ocean

ALASKA

Sherwood\....\Fig36-Play5MesoSedTerraneMap.cdr

NORTH

ALEUTIAN

BASIN

OCS

PLANNINGAREA

0 50

MILES

Leased Blo$95.4 MM, 2

Leased Blo$1.3 MM, 37 

Well, Plugg

Gas Seep

Seismic Pr

Uplift or St

EXPLAN

Figure 6

Oil Seep. *seep (see b

* Becharof Lake oil seep reported as “locaBiologic markers in sediments and petrol

GreatBasins 2

Becharof Lake 1

Fin

Koniag 

PainterCreek 1

Ugashik 1

PortHeiden 1

SandyRiver 1

North Aleutian

Shelf COST 1

Big River 1

DavidRiver 1, 1A

HoodooLake 1

HoodooLake 2

CanoeBay 1

CathedralRiver 1

Bertha 1

Monkshood 1

St. GeorgeCOST 2

Tested Gas90 Mcfd

Oil Shows

Oil Shows

Oil Shows

Oil Staining

Gas Shows

Tested Gas(5-9 Mcfd)

Oil Shows

Gas Shows

ShallowGas Shows

Oil Show

Jur-Cret OilSource Rocks?

JurassSource 

Oil Shows

Figure 36: Area of play 5, Mesozoic Deformed Sedimentary Rocks play, North Aleutian Basin OCS Planning Area, Alaska.

126
PLAY 6: MESOZOIC BURIED GRANITIC HILLS

(Jurassic-Cretaceous Magmatic Rocks)

Area of 

Basement 

Highs

Ugashik Lak

BearLake

Magmatic Mesozoic Basement

Sedimentary

Mesozoic Basement

164°

162°

160°

158°

58°

56°

Sale 92High Bid Tract$24.36 MM

Top Prospect collected $69.4 MM in Sale 92 (73% of Sale)

Figure 6

ALASKAPENINSULA ST. GEORGE BASIN

NORTH

ALEUTIAN

BASIN

A

MA

K

BASIN

BLACK

HIL

LS

UPLIFT

Bristol Bay

Pacific Ocean

ALASKA

Sherwood\....\Fig37-PlayMesoMagTerraneMap.cdr

NORTHALEUTIANBASINOCSPLANNINGAREA

0 50

MILES

Leased Blo$95.4 MM, 2

Leased Blo$1.3 MM, 37 

Well, Plugg

Gas Seep

Seismic Pr

Uplift or St

EXPLAN

Figure 6

Oil Seep. *seep (see b

* Becharof Lake oil seep reported as “locaBiologic markers in sediments and petrol

GreatBasins 2

Becharof Lake 1

Fin

Koniag 

PainterCreek 1

Ugashik 1

PortHeiden 1

SandyRiver 1

North Aleutian

Shelf COST 1

Big River 1

DavidRiver 1, 1A

HoodooLake 1

HoodooLake 2

CanoeBay 1

CathedralRiver 1

Bertha 1

Monkshood 1

St. GeorgeCOST 2

Tested Gas90 Mcfd

Oil Shows

Oil Shows

Oil Shows

Oil Staining

Gas Shows

Tested Gas(5-9 Mcfd)

Oil Shows

Gas Shows

ShallowGas Shows

Oil Show

Jur-Cret OilSource Rocks?

JurassSource 

Oil Shows

Figure 37: Area of play 6, Mesozoic Buried Granitic Hills play, North Aleutian Basin OCS Planning Area, Alaska.

127
0

2

4

6

8

10

0

100200300400500600

Number of Pools (Total = 56)

Net Feet Pay

56 Oil and Gas Pools in 28 Fields

Minimum Reported = 15 ft

Maximum Reported = 550 ft (midpoint of 100-1000 ft,

 Tyonek D Pool, Trading Bay Field)

:

Mean = 151.39 ft

Standard Deviation = 179.72 ft

Mode=40.484 ft; mu=4.5802; sigma=0.9377

Statistical Range Lognormal Fit = 20-456 ft (F95-F05)

Log-Normal Fit

Mapped prospects in North Aleutian basin range 

in amplitude from 46 to 584 feet, sufficient to 

capture the full pay column (20-456 ft; mean=227 

ft) modeled from Cook Inlet oil and gas fields.

NET PAY IN COOK INLET OIL AND GAS POOLS

Sherwood\.....\Fig38-PayHistogramCookInletFields.cdr

Figure 38: Histogram for pay thickness in Tertiary reservoirs in oil and gas fields of Cook Inlet. The log-normal fit 

to these data was the basis for the pay thickness model for plays 1 and 3 in the North Aleutian basin. A modified 

(reduced to reflect lower permeability) version of this distribution formed the pay thickness model for play 2. Data 

from AOGCC (2001).

128
Sherwood\....\Fig39-GeothermalModelsForPlays.cdr

Geothermal Models for Plays 1-3

North Aleutian Basin OCS Planning Area

PLAY 2

PLAY 1

PLAY 3

F100=563

F100=525

F00=834

F00=664

F00=581

900

800

700

600

500

PROBABILITY FOR EXCEEDANCE (FRACTILES)

O O RANKINE ( F + 460)

Normal (Gaussian) Probability Distributions

“Force-Fit” Between Estimates for Extremes

at Limits of Depth Range for Play

~100 99.9 99 95 75 50 25 05 1 0.1 ~0

Figure 39: Examples of “force-fit” probability distributions constructed between estimates for extreme values. 

These geothermal models for North Aleutian plays 1, 2, and 3 are based on depth ranges of plays and a geothermal 

gradient of 17oF/1,000 ft at the North Aleutian Shelf COST 1 well (Turner et al., 1988, fig. 92, p. 182). 

129
A

BOE Resources (Risked)

F95 = 0 Mmboe

Mean = 1400 Mmboe

F05 = 3749 Mmboe

Sherwood\...\Fig40A-NAB-Play1-CumulativeGraphBOE.cdr

C

Largest Pool (Recoverable, Conditional)

F95 = 187 Mmboe (or 1.05 Tcfge)

F75 = 370 Mmboe (or 2.08 Tcfge)

Mean = 827 Mmboe (or 4.65 Tcfge)

F25 = 899 Mmboe (or 5.05 Tcfge)

F05 = 2,495 Mmboe (or 14.02 Tcfge)

Sherwood\....\Fig40C-NAB-Play1-RankedPoolPlot.cdr

NORTH ALEUTIAN BASIN PLAY 1 RESOURCE SUMMARY

Sherwood\....\Fig40-NAB-Play1-GraphicCompilation.cdr

Figure 40: Assessment results for North Aleutian Basin OCS Planning Area play 1 (Bear Lake-Stepovak play). 

(A), cumulative probability plot for total risked recoverable BOE resources (barrels of oil-equivalent); (B), pool 

class size histogram, conditional recoverable BOE volumes; (C), pool rank plot, conditional recoverable BOE 

volumes.

130
A

BOE Resources (Risked)

F95 = 91 Mmboe

Mean = 568 Mmboe

F05 = 1,293 Mmboe

Sherwood\....\Fig41A-NAB-Play2-CumulativeGraphBOE.cdr

North Aleutian Basin Play 02 - Tolstoi Pool Rank (Conditional Technically Recoverable): Re-Ranked on Means from PSRK Listing

1

10

100

1000

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43

Pool Rank [n = 44] (25th to 75th Percentile, With Mean)

ConditionalRecoverableBOEResources

(Mmboe)

Largest Pool (Conditional, Recoverable)

F95 = 61 Mmboe (or 0.34 Tcfge)

F75 = 122 Mmboe (or 0.69 Tcfge)

Mean = 208 Mmboe (or 1.17 Tcfge)

F25 = 258 Mmboe (or 1.45 Tcfge)

F05 = 467 Mmboe (or 2.62 Tcfge)

C

Sherwood\....\Fig41C-NAB-Play2-PoolRankPlot.cdr

NORTH ALEUTIAN BASIN PLAY 2 RESOURCE SUMMARY

Sherwood\....\Fig41-NAB-Play2-GraphicCompilation.cdr

Figure 41: Assessment results for North Aleutian Basin OCS Planning Area play 2 (Tolstoi play). (A), cumulative 

probability plot for total risked recoverable BOE resources (barrels of oil-equivalent); (B), pool class size histogram, 

conditional recoverable BOE volumes; (C), pool rank plot, conditional recoverable BOE volumes.

131
A

BOE Resources (Risked)

F95 = 0 Mmboe

Mean = 210 Mmboe

F05 = 1077 Mmboe

Sherwood\....\Fig42A-NAB-Play3-CumulativeGraphBOE.cdr

Sherwood\...\Fig42C-NAB-Play3-PoolRankPlot.cdr

Largest Pool (Conditional, Recoverable)

F95 = 20 Mmboe (or 0.11 Tcfge)

F75 = 83 Mmboe (or 0.47 Tcfge)

Mean = 378 Mmboe (or 2.12 Tcfge)

F25 = 444 Mmboe (or 2.50 Tcfge)

F05 = 1302 Mmboe (or 7.32 Tcfge)

C

NORTH ALEUTIAN BASIN PLAY 3 RESOURCE SUMMARY

Sherwood\....\Fig42-NAB-Play3-GraphicCompilation.cdr

Figure 42: Assessment results for North Aleutian Basin OCS Planning Area play 3 (Black Hills Uplift-Amak Basin 

play). (A), cumulative probability plot for total risked recoverable BOE resources (barrels of oil-equivalent); (B), 

pool class size histogram, conditional recoverable BOE volumes; (C), pool rank plot, conditional recoverable BOE 

volumes.

132
NORTH ALEUTIAN BASIN PLAY 4 RESOURCE SUMMARY

Sherwood\....\Fig43-NAB-Play4-GraphicCompilation.cdr

The Milky River Biogenic Gas play 

(play 4) is assessed with negligible 

recoverable gas resources.

Figure 43: Assessment results for North Aleutian Basin OCS Planning Area play 4 (Milky River Biogenic Gas 

play).

133
Sherwood\....\Fig-44A-NAB-Play5-CumulativeGraph.cdr

A

BOE Resources (Risked)

F95 = 0 Mmboe

Mean = 41 Mmboe

F05 = 197 Mmboe

Sherwood\....\Fig44C-NAB-Play5-PoolRankPlot.cdr

C

Largest Pool (Conditional, Recoverable)

F95 = 8 Mmboe (or 0.04 Tcfge)

F75 = 24 Mmboe (or 0.13 Tcfge)

Mean = 63 Mmboe (or 0.35 Tcfge)

F25 = 80 Mmboe (or 0.45 Tcfge)

F05 = 176 Mmboe (or 0.99 Tcfge)

NORTH ALEUTIAN BASIN PLAY 5 RESOURCE SUMMARY

Sherwood\....\Fig44-NAB-Play5-GraphicCompilation.cdr

Figure 44: Assessment results for North Aleutian Basin OCS Planning Area play 5 (Mesozoic Deformed 

Sedimentary Rocks play). (A), cumulative probability plot for total risked recoverable BOE resources (barrels of 

oil-equivalent); (B), pool class size histogram, conditional recoverable BOE volumes; (C), pool rank plot, 

conditional recoverable BOE volumes.

134
135

Sherwood\....\Fig45A-NAB-Play6-CumulativeGraphBOE.cdr

A

BOE Resources (Risked)

F95 = 0 Mmboe

Mean = 67 Mmboe

F05 = 330 Mmboe

Sherwood\...\NAB-Play6-USGSClassPlot.cdr

B

Sherwood\....\Fig45C-NAB-Play6-PoolRankPlot.cdr

C

Largest Pool (Conditional, Recoverable)

F95 = 9 Mmboe (or 0.05 Tcfge)

F75 = 33 Mmboe (or 0.19 Tcfge)

Mean = 148 Mmboe (or 0.83 Tcfge)

F25 = 154 Mmboe (or 0.87 Tcfge)

F05 = 469 Mmboe (or 2.64 Tcfge)

NORTH ALEUTIAN BASIN PLAY 6 RESOURCE SUMMARY

Sherwood\....\Fig45-NAB-Play6-GraphicCompilation.cdr

Figure 45: Assessment results for North Aleutian Basin OCS Planning Area play 6 (Mesozoic Buried Granitic Hills 

play). (A), cumulative probability plot for total risked recoverable BOE resources (barrels of oil-equivalent); (B), 

pool class size histogram, conditional recoverable BOE volumes; (C), pool rank plot, conditional recoverable BOE 

volumes.
Gas 

and S

Oil & 

Condensate

NORTH ALEUTIAN BASIN RESOURCE SUMMARY

Sherwood\...\Fig46-NAB-CumGraphResourceCompilation.cdr

Figure 46: Assessment results for North Aleutian Basin OCS Planning Area. (A), cumulative probability plot for total risked recoveraand gas in barrels of oil-equivalent); (B), cumulative probability plot for total risked recoverable liquid (oil + condensate from gas) resoprobability plot for total risked recoverable gas (free gas and solution gas) resources; (D), comparative cumulative probability plot for o

and gas (free gas and solution gas).

136
Rank Plot, North Aleutian Basin Hypothetical Gas Pools (Conditio

and Cook Inlet Gas Fields (Bcf EUR)

North Aleutian Basin Pools (9

Gas-Prone Plays 1, 2, & 6

BOE Pools Presented As 100% 

Cook Inlet Gas Fields (16)

Largest NAB Pool: 4645 Bcfg (Mean)

Largest CI Field (Kenai): 2427 Bcfg

F25 (Bcfg)

F75 (Bcfg)

Mean

Sherwood\....\Fig47-Rank Plot-NAB Gas Pools Plays 1, 2, & 6 and CI Gas Fields.cdr

Cook Inlet field reserve & Gas (2005), 2004 Ann

Figure 47: Hypothetical gas pools in gas-prone plays (1, 2, and 6) of North Aleutian basin are comparable in size to the gas fields of C

largest hypothetical pool in North Aleutian basin could be almost twice the size of the Kenai gas field in Cook Inlet. Total Cook Inlet ENorth Aleutian Basin OCS Planning Area is estimated to contain 8.6 Tcf gas (mean, risked, technically-recoverable).

137
Three-Mile Limit

Ugashik Lak

BearLake

2005 Alaska

State Leases (37)

1988 Federal

Offshore Leases (23)

(Relinquished)

164°

162°

160°

158°

58°

56°

Bristol Bay

Bering Sea

Pacific Ocean

ALA

NORTHALEUTIAN

BASINOCS

PLANNINGAREA

Sherwood\....\Fig48-North Aleutian-Development Model.cdr

Balboa

Bay

0 50

MILES

PortMoller

PortHeiden

Chignik

FalsePass

ColdBay

SandPoint

Offshore

Hub

Balboa Bay

LNG Plant/Port

LNG Tankers 2,600 Mi. to U.S. West 

LNG

550 Mi. to

Gathering Pipelines Trunk Pipeline

Figure 48: Hypothetical development model for North Aleutian basin gas resources. Platforms and subsea completions at offshore ga

gathering pipelines that carry the gas to an offshore hub. A 75-mile pipeline (25 miles subsea, 50 miles overland) then carries the gas tnatural gas (LNG) plant at Balboa Bay (site in southwest arm identified in 1980 study by Dames & Moore). At the LNG plant the gas istate (-260oF) preparatory to shipping via LNG tankers to hypothetical receiving and re-gasification facilities in Cook Inlet or along the Mexico) West Coast. 

138