2006 Oil and Gas Assessment of North Aleutian Basin Planning Area

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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 [email protected] Table of Contents

List of Text Topics

Summary, page 1 Source Potential of Coal-Bearing Rocks, page 23 Location and General Geology of North Source Potential of “Amorphous” Aleutian Basin OCS Planning Area, Interval, 15,620-17,155 ft bkb, page 5 page 24 Source Potential of Tertiary Basin Exploration History of North Aleutian Fill and Assessment Model, page Basin, page 6 26 Past Exploration Onshore, page 6 Oil and Gas Occurrences and Leasing Onshore, page 6 Biomarker Correlations, page 26 Offshore/OCS Exploration, page 7 Petroleum System—Critical Events, Past OCS Leasing, page 7 page 31

Productive Analog Basin—Cook Inlet Petroleum System Elements and Oil and Basin, page 8 Gas Plays in North Aleutian Basin OCS Planning Area, page 37 Petroleum Geology of the North Aleutian Key Elements of Petroleum System, Basin, page 9 page 37 Regional Geology, page 9 Play Definition, page 37 Alaska Peninsula, page 9 Play Descriptions, North Aleutian Basin, Formation of North Aleutian Basin, Alaska, page 38 page 10 Play 1: Bear Lake-Stepovak Structures of Amak Basin, Black Hills (Oligocene-Miocene), page 38 Uplift, and North Aleutian Basin, Play 2: Tolstoi (Eocene-Oligocene), page 11 page 39 Nature of Basement Beneath North Play 3: Black Hills Uplift-Amak Aleutian Basin, page 13 Basin (Eocene-Miocene), page 41 Mesozoic Stratigraphy and Reservoir Play 4: Milky River Biogenic Gas Formations, page 15 (Plio-Pleistocene), page 43 Cenozoic Stratigraphy, Reservoir Play 5: Mesozoic Deformed Formations, and Play Sequences, page Sedimentary Rocks (Triassic- 16 Cretaceous), page 45 Petroleum Systems in North Aleutian Play 6: Mesozoic Buried Granitic Basin Plays, page 19 Hills (Jurassic-Cretaceous Thermal Maturity of North Aleutian Magmatic Rocks), page 47 Basin Fill, page 19 Source Rock Potential, page 21 Geologic Assessment Model, page 50 Mesozoic Source Rocks, page 21 Prospect Areas and Volumes, page 50 Tertiary Source Rocks, page 22 Prospect Numbers, page 51

i Pay Thickness Model, page 52 Play 4: Milky River Biogenic Gas (Plio- Construction of Probability Distributions Pleistocene), page 59 with Limited Data, page 53 Play 5: Mesozoic Deformed Computation of Oil and Gas Recovery Sedimentary Rocks (Triassic- Factors, page 54 Cretaceous), page 59 Oil Recovery Factor, page 54 Play 6: Mesozoic Buried Granitic Hills Gas Recovery Factor, page 54 (Jurassic-Cretaceous Magmatic Risk Assessment, page 56 Rocks), page 60 Overall Results for Oil and Gas Assessment Results for North Aleutian Endowments of North Aleutian Basin, Basin, page 57 page 61 Play 1: Bear Lake-Stepovak (Oligocene- Large Individual Gas Fields Are Miocene), page 57 Possible, page 61 Play 2: Tolstoi (Eocene-Oligocene), Economic Potential of North Aleutian page 58 Basin, page 62 Play 3: Black Hills Uplift-Amak Basin (Eocene-Miocene), page 59 References Cited, page 64

List of Tables

1. North Aleutian Basin and Alaska 7. Input Data for Play 5, Mesozoic Peninsula Exploration Wells, 1903- Deformed Sedimentary Rocks (Triassic- 1985, page 71 Cretaceous), page 77

2. Selected Extract Data, Oil and Gas Show 8. Input Data for Play 6, Mesozoic Buried Interval, North Aleutian Shelf COST 1 Granitic Hills (Jurassic-Cretaceous well, page 72 Magmatic Rocks), page 78

3. Input Data for Play 1, Bear Lake- 9. Input Data for Oil and Gas Recovery Stepovak (Oligocene- Miocene), page Factor Calculation, Play 1, Bear Lake- 73 Stepovak (Oligocene- Miocene), page 79 4. Input Data for Play 2, Tolstoi (Eocene- Oligocene), page 74 10. Input Data for Oil and Gas Recovery Factor Calculation, Play 2, Tolstoi 5. Input Data for Play 3, Black Hills Uplift- (Eocene-Oligocene), page 80 Amak Basin (Eocene-Miocene), page 75 11. Input Data for Oil and Gas Recovery 6. Input Data for Play 4, Milky River Factor Calculation, Play 3, Black Hills Biogenic Gas (Plio-Pleistocene), page Uplift-Amak Basin (Eocene-Miocene), 76 page 81

ii 12. Input Data for Oil and Gas Recovery Pool Size Simulation Statistics for Play 3 Factor Calculation, Play 5, Mesozoic – Black Hills Uplift-Amak Basin Deformed Sedimentary Rocks (Triassic- (Eocene-Miocene), page 87 Cretaceous), page 82 20. Conditional (Un-risked) Recoverable 13. Input Data for Oil and Gas Recovery Sizes of Ranked Pools for Play 3 – Black Factor Calculation, Play 6, Mesozoic Hills Uplift-Amak Basin (Eocene- Buried Granitic Hills (Jurassic- Miocene), page 87 Cretaceous Magmatic Rocks), page 83 21. Conditional (Un-risked) Recoverable 14. 2006 Assessment Results for North Pool Size Simulation Statistics for Play 5 Aleutian Basin OCS Planning Area, page 84 – Mesozoic Deformed Sedimentary Rocks (Triassic-Cretaceous), page 88 15. Conditional (Un-risked) Recoverable Pool Size Simulation Statistics for Play 1 22. Conditional (Un-risked) Recoverable – Bear Lake-Stepovak (Oligocene- Sizes of Ranked Pools for Play 5 – Miocene), page 85 Mesozoic Deformed Sedimentary Rocks (Triassic-Cretaceous), page 88 16. Conditional (Un-risked) Recoverable Sizes of Ranked Pools for Play 1 – Bear 23. Conditional (Un-risked) Recoverable Lake-Stepovak (Oligocene-Miocene), Pool Size Simulation Statistics for Play 6 page 85 – Mesozoic Granitic Buried Hills (Jurassic-Cretaceous), page 89 17. Conditional (Un-risked) Recoverable Pool Size Simulation Statistics for Play 2 24. Conditional (Un-risked) Recoverable – Tolstoi (Eocene-Oligocene), page 86 Sizes of Ranked Pools for Play 6 – Mesozoic Granitic Buried Hills 18. Conditional (Un-risked) Recoverable (Jurassic-Cretaceous), page 89 Sizes of Ranked Pools for Play 2 - Tolstoi (Eocene-Oligocene), page 86 25. 2006 Economic Assessment Results for North Aleutian Basin OCS Planning 19. Conditional (Un-risked) Recoverable Area, page 90

List of Figures

1. Location map for North Aleutian basin with well control, Sale 92 (1988) leases, and other Tertiary-age basins of the and regional distribution of Tertiary-age Bering shelf, Pacific margin, and sedimentary rocks, page 92 southern Chukchi Sea, page 91 3. Seismic data coverage (CDP, Two- 2. Regional map for North Aleutian basin, Dimensional) for North Aleutian Basin

iii OCS Planning Area, page 93 available as plate 3

4. Regional distribution of Mesozoic 11. Statistical summaries for sandstone bed sedimentary basin containing strata thicknesses for North Aleutian basin correlative to Middle Jurassic oil source play sequences, page 101 rocks that generated 1.4 billion barrels of oil reserves in the oil fields of northern 12. Core porosity versus depth in the North Cook Inlet basin, page 94 Aleutian Shelf COST 1 well, with linear regression function for porosity decline 5. Principal geologic structures of the with depth, page 102 North Aleutian basin and contiguous areas, including: 1) transtensional faults 13. Core porosity versus permeability for and basement uplifts in western parts of sandstones, North Aleutian Shelf COST the basin; 2) wrench-fault structures 1 well, with correlation, page 103 along the Black Hills uplift; and 3) fold/thrust belts along the southeast 14. Core permeability versus depth for margin of the basin, page 95 sandstones, North Aleutian Shelf COST 1 well, with function for permeability 6. Seismic profile through basement uplifts decline with depth, page 104 in western North Aleutian basin, showing Tertiary sedimentary sequences 15. Porosity histograms for Bear Lake- and basin structures, page 96. An Stepovak, Upper Tolstoi, and Lower undistorted Adobe Acrobat version of Tolstoi play sequences, page 105 figure 6 is available as plate 1 16. Permeability histograms for Bear Lake- 7. Magnetic intensity map with offshore Stepovak, Upper Tolstoi, and Lower speculative extrapolation of the Bruin Tolstoi play sequences, page 106 Bay fault, page 97 17. Vitrinite reflectance data for 94 samples 8. Mesozoic stratigraphy, Alaska Peninsula of cuttings, conventional cores, and and substrate beneath southwest part of percussion sidewall cores in the North North Aleutian basin, page 98 Aleutian Shelf COST 1 well, with statistical fits and forecasts for depths of 9. Wellbore stratigraphy, North Aleutian important isograds, page 107 Shelf COST 1 stratigraphic test well, page 99. An undistorted Adobe Acrobat 18. Depth to top of oil generation zone version of figure 9 is available as plate (0.6% vitrinite reflectance) with 2. probable areas of thermal maturity of Tertiary rocks sufficient for oil 10. Regional stratigraphic correlation, generation in and beneath the North Tertiary sequence in North Aleutian Aleutian basin, page 108 Shelf COST 1, Sandy River 1, Port Heiden 1, Ugashik 1, and Becharof Lake 19. Isopach map for thickness of Tertiary- 1 wells, North Aleutian basin and Alaska age rocks within oil generation zone Peninsula, page 100. An undistorted (0.6% to 1.35% vitrinite reflectance) Adobe Acrobat version of figure 10 is with probable areas of thermal maturity

iv sufficient for oil generation within and 26. Histograms for Pristane/Phytane ratios beneath North Aleutian basin, page 109 of North Aleutian Shelf COST 1 well extracts, Tertiary (nonmarine) extracts 20. Generation potential (total organic and oils, and Mesozoic (marine) extracts carbon) and hydrocarbon type (hydrogen and oils, page 116 index) indicators for Mesozoic rocks in the Cathedral River 1 well, page 110 27. Sofer cross plot for carbon isotopes for aromatics and saturates, comparing 21. Generation potential (total organic North Aleutian Shelf COST 1 well carbon) and hydrocarbon type (hydrogen extracts, Tertiary (nonmarine) extracts index) indicators for Tertiary rocks in and oils, and Mesozoic (marine) extracts the North Aleutian Shelf COST 1 well, and oils, page 117 page 111 28. A) Triangular plot for saturates versus 22. (A) Modified Van Krevelen plot aromatics versus non-hydrocarbons, comparing Exlog (1983) pyrolysis data North Aleutian Shelf COST 1 well for cuttings with coal partly removed (by extracts, Tertiary (nonmarine) extracts flotation in water) and cuttings with coal and oils, and Mesozoic (marine) extracts content retained; (B) Sidewall and and oils; B) Triangular plot for C27- conventional core samples, with coal- C28-C29 sterane ratios, page 118 bearing and coal-free samples plotted separately; (C) Van Krevelen-type plot 29. M/Z 191 chromatograms for terpanes by showing elemental data for sidewall and Baseline DGSI (2003) for extracts from conventional core samples, with coal- composited samples from: (A) cores 18 bearing and coal-free samples plotted and 19, 16,006-16,720 ft, North Aleutian separately; (D) Van Krevelen-type plot Shelf COST 1 well; and (B) cuttings, with elemental analyses for all coal- 15,700 to 16,800 ft. Both bearing samples with HI>150, page 112 chromatograms show abundant presence of C19 to C30 tricyclic terpanes, page 23. Analyses of gas compositions from 119 Alaska Peninsula seeps and oil and gas fields in northern Cook Inlet basin, page 30. Burial history plot for North Aleutian 113 Shelf COST 1 well, with timelines for critical petroleum system events, page 24. (A) Methane carbon isotope data for 120 Amoco Becharof Lake 1 well. B) Gas wetness versus methane isotopes, page 31. Schematic cross sections illustrating (A) 114 petroleum system elements and (B) play concepts for North Aleutian Basin OCS 25. Cross plot for Pristane/n-C17 versus Planning Area, page 121 Phytane/n-C18 ratios for rock extracts from the oil show interval in nonmarine 32. Map area of play 1, Bear Lake-Stepovak Eocene Tolstoi Formation from 15,300 play, North Aleutian Basin OCS to 16,800 feet bkb in the North Aleutian Planning Area, Alaska, page 122 Shelf COST 1 well, page 115 33. Map area of play 2, Tolstoi play, North

v Aleutian Basin OCS Planning Area, histogram, conditional recoverable BOE Alaska, page 123 volumes; (C), pool rank plot, conditional recoverable BOE volumes: page 131 34. Map area of play 3, Black Hills Uplift- Amak Basin, North Aleutian Basin OCS 42. Assessment results for North Aleutian Planning Area, Alaska, page 124 Basin OCS Planning Area play 3 (Black Hills Uplift-Amak Basin play). (A), 35. Map area of play 4, Milky River cumulative probability plot for total Biogenic Gas play, North Aleutian Basin risked recoverable BOE resources OCS Planning Area, Alaska, page 125 (barrels of oil-equivalent); (B), pool class size histogram, conditional 36. Map area of play 5, Mesozoic Deformed recoverable BOE volumes; (C), pool Sedimentary Rocks play, North Aleutian rank plot, conditional recoverable BOE Basin OCS Planning Area, Alaska, page volumes: page 132 126 43. Assessment results for North Aleutian 37. Map area of play 6, Mesozoic Buried Basin OCS Planning Area play 4 (Milky Granitic Hills play, North Aleutian Basin River Biogenic Gas play)—Play 4 was OCS Planning Area, Alaska, page 127 not quantified, page 133

38. Histogram for pay thickness in Tertiary 44. Assessment results for North Aleutian reservoirs in oil and gas fields of Cook Basin OCS Planning Area play 5 Inlet, page 128 (Mesozoic Deformed Sedimentary Rocks play). (A), cumulative 39. Example of “force-fit” probability probability plot for total risked distributions constructed graphically recoverable BOE resources (barrels of between estimates for extreme values. oil-equivalent); (B), pool class size Geothermal models for plays 1, 2 and 3, histogram, conditional recoverable BOE in ºRankine (ºF + 460 = ºR), page 129 volumes; (C), pool rank plot, conditional recoverable BOE volumes: page 134 40. Assessment results for North Aleutian Basin OCS Planning Area play 1 (Bear 45. Assessment results for North Aleutian Lake-Stepovak play). (A), cumulative Basin OCS Planning Area play 6 probability plot for total risked (Mesozoic Buried Granitic Hills play). recoverable BOE resources (barrels of (A), cumulative probability plot for total oil-equivalent); (B), pool class size risked recoverable BOE resources histogram, conditional recoverable BOE (barrels of oil-equivalent); (B), pool volumes; (C), pool rank plot, conditional class size histogram, conditional recoverable BOE volumes: page 130 recoverable BOE volumes; (C), pool rank plot, conditional recoverable BOE 41. Assessment results for North Aleutian volumes: page 135 Basin OCS Planning Area play 2 (Tolstoi play). (A), cumulative 46. Assessment results for North Aleutian probability plot for total risked Basin OCS Planning Area. (A), recoverable BOE resources (barrels of cumulative probability plot for total oil-equivalent); (B), pool class size risked recoverable BOE resources (oil

vi and gas in barrels of oil-equivalent); (B), 48. Hypothetical development model for cumulative probability plot for total North Aleutian basin gas resources. risked recoverable liquid (oil + Platforms and subsea completions at condensate from gas) resources; (C), offshore gas fields direct the gas into cumulative probability plot for total gathering pipelines that carry the gas to risked recoverable gas (free gas and an offshore hub. A 75-mile pipeline (25 solution gas) resources; (D), miles subsea, 50 miles overland) then comparative cumulative probability plot carries the gas to a hypothetical liquefied for oil & condensate, BOE, and gas (free natural gas (LNG) plant at Balboa Bay gas and solution gas) resources: page (site in southwest arm identified in 1980 136 study by Dames & Moore). At the LNG plant the gas is refrigerated to a liquid 47. Pool rank plot for hypothetical gas pools state (-260ºF) preparatory to shipping in gas-prone plays (1, 2, and 6) of North via LNG tankers to hypothetical Aleutian basin compared to the gas receiving and re-gasification facilities in fields of Cook Inlet basin, page 137 Cook Inlet or along the U.S. (or Canada or Mexico) West Coast. page 138

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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.

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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 Amak basins, the intervening Black Hills Shelf (OCS) Planning Area encompasses an uplift, and the Mesozoic rocks beneath these area of 52,234 square miles and includes features all contribute resources to the 2006 most of the southeastern part of the Bering oil and gas assessment of the North Aleutian Sea continental shelf (fig. 1). The North basin. Aleutian basin proper is about 17,500 square miles in area and underlies the northern Most mapped prospects in the North coastal plain of the Alaska Peninsula and the Aleutian basin proper are simple domes waters of Bristol Bay. North Aleutian basin draped over the crests of fault-bounded is sometimes also referred to as the “Bristol basement uplifts. These domes range up to Bay” basin. Water depths range from 15 to 133,000 acres in closure area. In the central 700 feet and in the area of the most part of the North Aleutian basin 65 miles important prospects the water depths are northwest of Port Moller, these domes are approximately 300 feet. surrounded by deep parts of the basin where the lowermost strata are heated to The North Aleutian basin is filled with temperatures sufficient for conversion of approximately 20,000 feet of Tertiary-age organic matter to oil and gas. Oil and gas strata. In the southwest corner of the generated in these basin deeps should have Planning Area, the Amak basin is separated migrated upward into the domes. by an arch (Black Hills uplift) from the North Aleutian basin (figs. 2, 3). The Amak The prospects in the central part of the North basin is filled with up to 12,500 feet of Aleutian basin have long been the focus of Tertiary-age strata. The North Aleutian and exploration interest in North Aleutian basin

and several were leased for total high bids of extracts of these oil shows indicate $95.4 million (23 blocks) in OCS lease sale origination within coaly, Tertiary-age rocks 92 in 1988. All of the 1988 leases have like those sampled by the well. The been returned to the U.S. Government and southwest part of the North Aleutian Basin are no longer active. In this assessment, as OCS Planning Area is underlain by well as in past assessments, most of the Mesozoic rocks that might form a source for hypothetical, undiscovered oil and gas oil. However, the North Aleutian Basin resources of the North Aleutian Basin OCS OCS Planning Area is primarily a gas Planning Area are associated with the simple province. domes draped over basement uplifts in the central part of the North Aleutian basin. The 2006 assessment was completed in November 2005 and incorporates data and Onshore, nine exploration wells have tested information available as of 01 January 2003. fold and thrust-fault structures along the The risked, technically-recoverable, southern edge of the North Aleutian basin. undiscovered hydrocarbon energy Several offshore wells tested age-equivalent endowment of the North Aleutian Basin strata in the St. George basin to the west. OCS Planning Area ranges up to 6,647 The principal point of geological control for millions of barrels (oil-energy-equivalent, at the Tertiary-age fill in the North Aleutian F05, the 5% fractile, or 5% probability), basin is the North Aleutian Shelf COST 1 with a mean value or expectation of 2,287 well, drilled in 1983 by an industry millions of barrels (oil-energy-equivalent). consortium led by ARCO Exploration The Planning Area is gas-prone, with sixty- Company. None of these wells encountered seven percent of the undiscovered any sizeable accumulations of oil or gas, hydrocarbon energy endowment consisting although several wells detected oil and gas of natural gas. Mean risked, undiscovered shows and two onshore wells tested minor total gas (sum of “non-associated” [free] gas gas pools at rates up to 90 thousands of and solution gas in oil) resources total 8.622 cubic feet per day. No wells have tested the trillions of cubic feet but could range up to a Amak basin. North Aleutian and Amak maximum (F05) potential of 23.278 trillions basins are covered by gridded (1 to 5 mile of cubic feet. Mean risked, undiscovered spacing in prospective areas) two- liquid petroleum (sum of free oil and dimensional seismic data mostly acquired in condensate from gas) resources are the period from 1975 to 1988. estimated at 753 millions of barrels but could range up to a maximum (F05) Well and seismic data indicate that thick, potential of 2,505 millions of barrels. 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

North Aleutian Basin OCS Planning Area, The 2006 MMS economic assessment of the Undiscovered Technically-Recoverable Oil & Gas North Aleutian basin models production Assessment Results as of 2006 infrastructure that originates at offshore Resource Resources * Commodity platforms where gas, condensate, and crude (Units) F95 Mean F05 oil are gathered by subsea pipelines from BOE (Mmboe) 91 2,287 6,647 several surrounding fields. Subsea pipelines Total Gas (Tcfg) 0.404 8.622 23.278 carry natural gas and petroleum liquids from an offshore hub to onshore facilities and a Total Liquids 19 753 2,505 (Mmbo) liquefied natural gas (LNG) plant constructed in Balboa Bay on the south side Free Gas (Tcfg) 0.401 8.393 22.487 of the Alaska Peninsula (fig. 10). In our Solution Gas 0.003 0.229 0.791 model, natural gas is converted to LNG and (Tcfg) then transported by marine LNG carriers to Oil (Mmbo) 9 545 1,948 new receiving terminals either in the Condensate 10 208 556 (Mmbc) northern Cook Inlet (550 mi.) or on the U.S. * Risked, Technically-Recoverable West Coast (2,600 mi.; fig. 48). Minimum F95 = 95% chance that resources will equal or exceed the transportation tariffs in the economic model given quantity represent a Cook Inlet destination while the F05 = 5% chance that resources will equal or exceed the given quantity maximum tariffs reflect a U.S. West Coast BOE = total hydrocarbon energy, expressed in barrels-of-oil- landing. The Cook Inlet market (total equivalent, where 1 barrel of oil = 5,620 cubic feet of batural approximately 200 Bcfg/yr; Sherwood and gas Craig, 2001, tbl. 5) is probably too small to Mmb = millions of barrels accept the entire North Aleutian production Tcf = trillions of cubic feet stream (approximately 150 Bcfg/yr) but

nonetheless offers an alternative market.

The lowest (or “threshold”) prices that yield The 2006 assessment of the North Aleutian positive economic volumes in the North Basin OCS Planning Area identified six Aleutian basin are $14/barrel of oil and exploration plays. Most (61%) of the $3.63/Mcf of non-associated gas. (Solution hypothetical, undiscovered oil and gas gas is linked to oil development and first resources are associated with play 1— becomes “economic” at $2.12/Mcf or the termed the Bear Lake-Stepovak play. Play 1 threshold price for oil [$14/barrel].) captures most of the key prospects in the However, higher prices are required to central part of the North Aleutian basin. economically recover meaningful fractions The mean conditional (un-risked) size of the of the oil and gas endowment. Significant largest pool in play 1 (and the North quantities (>300 Mmbo) of oil become Aleutian basin overall) is 4.65 trillions of economic to recover at prices approaching cubic feet of natural gas (or 827 millions of $30/bbl. This could represent a standalone barrels [oil-energy-equivalent]), nearly twice offshore oil field. Significant quantities (>1 the size of the largest gas field in Cook Inlet Tcfg) of gas become economic at prices (Kenai gas field, 2.427 Tcfg EUR). At exceeding $4.54/Mcf. However, a maximum (F05) size, the largest pool in play minimum total gas reserve of 5 Tcfg would 1 could contain 14.02 trillions of cubic feet probably be required to justify a grassroots of natural gas (or 2.495 billions of barrels LNG export operation. This economic [oil-energy-equivalent]). volume is recoverable at an approximate gas

3 price of $6.50/Mcfg and represents 58 Iliamna Lake may form a potential future percent of the total recoverable gas market for North Aleutian basin gas endowment (8.622 Tcfg). resources. However, the Pebble project site is located approximately 400 miles North Aleutian Basin OCS Planning Area, Undiscovered northwest of the key prospects in the central Economically-Recoverable Oil & Gas part of the North Aleutian basin and the Assessment Results as of 2006 Price estimated gas demand may be too small to Resource Resources * ($2005) Per Commodity (Units) support a pipeline of this length. Unit F95 Mean F05 Threshold Prices ($2005, Mean Resource Case) for Positive Economic Results = $14/Barrel of Oil and $3.63/Mcf of Non- In October 1989, the North Aleutian basin Associated Gas was placed under a Congressional Oil & Condensate $18/bbl 045200 moratorium which banned U.S. Department (Mmbo) of Interior expenditures in support of any Solution Gas (Tcfg) $2.72/Mcf 0.000 0.017 0.053 petroleum leasing or development activities Oil & Condensate $30/bbl 2 378 1,371 (Mmbo) in North Aleutian Basin as well as the Free Gas & Solution Atlantic, Pacific, and eastern Gulf of Mexico $4.54/Mcf 0.001 0.909 2.780 Gas (Tcfg) OCS Planning Areas. Bristol Bay is the Oil & Condensate center of a very important commercial $46/bbl 11 631 2,180 (Mmbo) salmon fishery. The North Aleutian Free Gas & Solution moratorium reacted to widespread demands $6.96/Mcf 0.132 5.852 16.548 Gas (Tcfg) for fisheries protection in Bristol Bay by Oil & Condensate $80/bbl 19 738 2,468 Native organizations, Native villages, local (Mmbo) fishing interests, and the State of Alaska Free Gas & Solution $12.10/Mcf 0.392 8.396 22.767 Gas (Tcfg) following the March 1989 Exxon Valdez grounding and oil spill in Prince William ECONOMIC ASSUMPTIONS: 2005 base year; oil price is indexed to Alaska North Slope crude landed on the U.S. West Coast; gas Sound, Alaska. This moratorium was price is LNG landed on the U.S. West Coast; 0.8488 BOE-basis extended by Congress several times during gas value discount relative to oil; flat real prices and costs; 3% inflation; 12% discount rate; 35% Federal tax. the 1990’s. Offshore leases that had been issued in the 1988 OCS Sale 92 in the North * Risked, Economically-Recoverable F95 = 95% chance that resources will equal or exceed the given Aleutian basin were returned to the Federal quantity government in a 1995 buy-back agreement. F05 = 5% chance that resources will equal or exceed the given On 12 June 1998, President William Clinton quantity Mmb = millions of barrels issued an Executive Order reinforcing the Tcf = trillions of cubic feet moratorium, as a Presidential Withdrawal, on North Aleutian Basin as well as the Current prices exceed $6.50/Mcf by a wide Atlantic, Pacific, and eastern Gulf of Mexico margin (recent gas prices at the Los Angeles continental shelves until 30 June 2012. The city gate have exceeded $13.00/Mcf; Natural Presidential Withdrawal still stands but can Gas Week, 19 December 2005). If the be revoked by the President. In the FY- current high prices are sustained, a 2004 Congressional bill appropriating the significant fraction of North Aleutian basin budget for the U.S. Department of Interior, gas resources are economically attractive. the language forbidding funding of oil and gas activities (i.e., the “Congressional Locally, the proposed “Pebble” gold mine moratorium”) in the North Aleutian Basin (estimated gas demand of 66 Mmcfg/day to OCS Planning Area was dropped. The feed a 200 Mw power plant) north of moratoria language in the bill was retained

4 for the other moratoria areas listed above. activities in the North Aleutian Basin OCS This action effectively ended the Planning Area. Congressional moratorium on oil and gas

Location and General Geology of North Aleutian Basin OCS Planning Area

The North Aleutian basin, located in figure along the north shore of the Alaska 1, is one of several basins of primarily Peninsula, where it has been penetrated by Tertiary age that dot the Bering Sea shelf. several wells. At its west end, a series of The Bering Sea shelf is relatively flat and arches isolate the basin from the similar St. featureless except near the modern shoreline George and Amak basins, where Tertiary where Pleistocene glacial and relict sediment thicknesses reach 40,000 feet and shoreline features occur. The outer shelf 12,500 feet, respectively (Comer et al., and slope are incised by large submarine 1987). Along the southern margin of the canyons near the shelf edge west of the St. North Aleutian basin, the Tertiary basin fill George and Navarin basins. These is deformed in fold and thrust-fault submarine canyons empty westward into the structures like those widely exposed on the deep abyssal plains of the western Bering Alaska Peninsula. The interior of the North Sea. Aleutian basin is dominated by uplifted fault blocks that have domed the overlying strata. The North Aleutian basin underlies the Prospects associated with these dome waters of Bristol Bay north of the Alaska structures are the primary exploration Peninsula (located in fig. 1) and is objectives in the North Aleutian basin. sometimes also termed the “Bristol Bay” Although minor quantities of gas were basin. The basin underlies the southern part recovered by flow tests at an onshore well, of the North Aleutian Basin Outer no significant accumulations of Continental Shelf (OCS) Planning Area. hydrocarbons have been located by The basin is roughly 100 miles wide and 400 exploration in the North Aleutian Basin miles in length and reaches depths of 20,000 OCS Planning Area or on the Alaska feet in its deepest parts. The North Aleutian Peninsula. basin extends onshore beneath the lowlands

Exploration History of North Aleutian Basin

Past Exploration Onshore million). The tracts cover areas where thrust faulted and folded Mesozoic and Cenozoic Beginning with the first wells drilled in rocks are exposed at the surface (Wilson et 1903, a total of 27 wells were drilled al., 1995). The new State of Alaska leases onshore on the Alaska Peninsula to the presumably offer exploration objectives in southeast of the North Aleutian Basin OCS fold structures that are unlike the simple Planning Area (table 1; fig. 2). All the 10 domes that form the key prospects in the earliest wells (1903-1940) were drilled in Federal offshore. the vicinity of local oil seeps. The last 17 wells, completed since 1959, were located In 2003, the State of Alaska proposed a based primarily on considerations of sealed-bid licensing program focusing on geologic structure and stratigraphy. The shallow gas resources north of their wells are spread over a distance of proposed lease area, as outlined (2003 area) approximately 260 miles along the Alaska in figure 2. Based upon industry interest, Peninsula, extending from the Pacific, the licensing program area was later Costello, and Great Basins wells in the contracted to the 2004 area of 329,000 acres northeast to the Cathedral River 1 well to the also shown in figure 2. A license was to be southwest (fig. 2). Although these wells are awarded (supplemental notice of 22 mostly located at moderate distances from December 2004, AKDO&G, 2004) to the North Aleutian Basin OCS Planning Bristol Shores LLC. However, financing Area, they are important for making efforts to bond the exploration commitment correlations and inferences about the failed (P. Galvin, pers. comm., 2005) and hydrocarbon potential of the stratigraphic the license lapsed. Bristol Shores LLC has section offshore. submitted a new license application for a reduced area of 20,154 acres (Bailey, 2005). None of the onshore wells encountered producible oil and gas; however, at least 6 of The proposed Northern Dynasty “Pebble” the wells completed since 1959 have gold mine north of Iliamna Lake (located in encountered minor shows of oil and/or gas. fig. 2) forms a potential new market for A seventh, the Amoco Becharof Lake 1, North Aleutian basin gas resources and may tested gas in measurable but non- drive interest in future lease sales on State of commercial amounts. Alaska lands in the region. In the Federal offshore, the best prospects lie approximately 400 pipeline miles southwest Leasing Onshore of the proposed Pebble mine. Northern Dynasty representatives have indicated that On 26 October 2005, the State of Alaska the Pebble project will require a 200 received 37 bids on 37 tracts in the Port megawatt (Mw) power supply (Ede, 2005). Moller area (fig. 2). High bids totaled $1.27 This translates to a potential gas demand of million and all bids were submitted by either Shell Offshore Inc. (33 tracts, $0.95 million) or Hewitt Mineral Corp. (4 tracts, $0.31

about 66 Mmcf/day1 and may be too small the area covers 9,596 line miles. to support a 400 mile pipeline. Approximately 6,400 miles of airborne gravity data have also been gathered in the Planning Area. Offshore/OCS Exploration

Only one well has been drilled offshore in Past OCS Leasing the North Aleutian Basin OCS Planning Area. This was a “Continental Offshore The only OCS lease sale in the area, the Stratigraphic Test” (COST) well, the North North Aleutian Shelf Sale 92, was held in Aleutian Shelf COST 1 well (tbl.1; fig. 2). October of 1988, with a total offering of 990 Eighteen companies participated in lease blocks (area of offering shown in fig. financing the well, with ARCO Exploration 2). The bidding resulted in the awarding of Company as the operator. It was drilled 23 leases (blocks shown in fig. 2) covering from the SEDCO 708, a self-propelled semi- 121,757 acres. Proceeds from the sale submersible drilling rig, and was spudded totaled $95,439,500. (began drilling) on September 8, 1982, in 285 feet of water. The well was plugged Following the March 1989 grounding of the and abandoned on January 14, 1983, after Exxon Valdez tanker and subsequent oil bottoming at 17,155 feet in sedimentary spill, a drilling ban was instituted in the rock of Eocene age. Below 15,300 feet, North Aleutian basin Federal offshore in minor gas peaks appeared on the mud log 1989. The drilling ban and moratorium on and drill cuttings showed some oil stain and all exploration recognized widespread fluorescence (Turner et al., 1988), but no opposition from Native organizations and pools of oil or gas were encountered. villages and concerns about impacts on the lucrative salmon fishery. As a result, none Seismic data coverage for the North of the 23 leases in the area were ever drilled. Aleutian Basin OCS Planning Area is shown In 1992, 11 oil companies filed a joint in figure 3. Seismic data gathered to date lawsuit (Conoco Inc. vs. USA) in an attempt within the North Aleutian Basin OCS to end the ban or receive compensation. An Planning Area consists of 64,672 combined out of court settlement and a Federal line miles of conventional, two-dimensional, buyback of the leases was reached in 1995. common-depth-point (CDP) and shallow- On 12 June 1998, President William Clinton penetrating, high-resolution (HRD) data. Of issued an Executive Order extending the the seismic data held by MMS, 95% is CDP moratorium (as a Presidential Withdrawal) and 5% is HRD. Airborne magnetic data in on North Aleutian basin (and the Atlantic, Pacific, and eastern Gulf of Mexico continental shelves) until 30 June 2012 1 Estimated as follows: One Mw capacity matches (Alaska Report, 1998). The Presidential one Mw·h (megawatt-hour) demand. Assume 3,412 btu/kwh energy equivalence (AEO, 2001, tbl. H1, p. Withdrawal still stands but can be revoked 248) and 1,000 btu/cf gas; substitutions obtain 3,412 by the President. However, the cf/Mw·h. At 25% efficiency* and 200Mw·h demand, Congressional moratorium on petroleum- we obtain 2.73 Mmcfg/h or 65.51 Mmcfg/day in gas related activities in North Aleutian basin has demand. been lifted. In the FY-2004 Congressional

* AEO (2001, tbls. 19 & 20, p. 103) reports a 1984- bill appropriating budget funding for the 1999 range in efficiencies of delivered electricity of U.S. Department of Interior, the language 15% to 38% for various sectors.

forbidding funding of oil and gas activities dropped (but retained for other moratoria (i.e., the “moratorium”) in the North areas). Aleutian Basin OCS Planning Area was

Productive Analog Basin—Cook Inlet Basin

In southern Alaska, the most successful prospects are drape anticlines developed in basin from the standpoint of oil and gas is Eocene through Pliocene time over the northern part of Cook Inlet basin, located basement uplifts that were elevated while in figure 4. The first field was discovered in sediments in flanking deeps compacted, 1957, and exploration programs continuing thereby doming shallow strata over the into the early 1970’s located original basement uplifts. recoverable reserves of 1.4 billions of barrels of oil and 11.6 trillions of cubic feet One of the more compelling points of of gas (AKDO&G, 2004). Most of these analogy between the Cook Inlet and North reserves have been depleted, with remaining Aleutian basins is the potential role of reserves as of late 2003 estimated at 0.0751 underlying Mesozoic rocks in the generation billions of barrels of oil (5% of original of oil and charging of prospects in overlying reserves) and 2.039 trillions of cubic feet of Tertiary strata. Both basins overlie an older gas (18% of original reserves) (AKDO&G, Mesozoic basin that contains the oil source 2004, tbls. 3.2, IV.2, IV.6). rocks that generated the oil fields of northern Cook Inlet basin. The petroleum Like the North Aleutian basin, the principal system in northern Cook Inlet succeeded fill of the Cook Inlet basin is of Tertiary age because a deep Tertiary basin was and reaches maximum thicknesses of superposed on a thermally immature roughly 26,000 feet (Hite, 1976; Fisher and Mesozoic assemblage that was buried and Magoon, 1982, fig. 4). The most prolific heated to temperatures appropriate for oil Cook Inlet basin petroleum reservoirs are of generation at the same time that fold traps Oligocene, Miocene, and Pliocene ages. grew in the overlying Tertiary basin fill Age-equivalent strata in the North Aleutian (Magoon, 1994). The Middle Jurassic basin are also the best candidates for Tuxedni Group was the source for the oil petroleum reservoirs. that migrated upward into the Tertiary basin fill, generally charging fold structures in the The structural style of prospects differs Oligocene Hemlock Conglomerate between the North Aleutian and Cook Inlet (Magoon, 1994). The “Tuxedni-Hemlock” basins. Oil and gas fields in Cook Inlet petroleum system that created the prolific oil occupy transpressional anticlines of fields of northern Cook Inlet basin is Oligocene to Pliocene age that formed near featured as a case study by Magoon (1994). strike-slip faults that pass from northeast to southwest through the basin (Haeussler et Critical to the success of the “Tuxedni- al., 2000). In contrast, North Aleutian basin Hemlock” petroleum system are the facts

8 that the Mesozoic assemblage beneath Mesozoic basin. Magoon (1994) has shown northern Cook Inlet basin was both: 1) that this superposition was critical to the compositionally appropriate (endowed with creation of the oil accumulations of the rocks rich in organic matter and able to northern Cook Inlet basin. On the other generate oil); and 2) thermally immature hand, St. George basin was tested by 12 (retained ability to generate oil through 100 wells, none of which encountered any oil or million years following deposition and not gas accumulations. It seems that the deeply buried until about 65 Ma [Magoon, Mesozoic strata beneath St. George basin 1994, fig. 22.7]). Correlative potential oil were somehow incapable of generating oil source rocks with a similar burial history into the overlying St. George basin fill. may be found in the Mesozoic basin in areas Perhaps early deep burial caused generation beyond northern Cook Inlet. and expulsion of petroleum from the Mesozoic rocks prior to formation of the The Mesozoic rocks beneath Cook Inlet Tertiary-age St. George basin. Perhaps the basin were deposited in a Mesozoic (Jurassic Mesozoic rocks beneath St. George basin to Cretaceous) basin that was coupled to a simply lack the appropriate organic matter Jurassic to Cretaceous volcanic arc to the for oil generation. north (Bally and Snelson, 1980). This Mesozoic basin extends at least 600 miles To the northeast of the North Aleutian basin from interior Alaska to the southwest we have a successful analog (northern Cook through the Alaska Peninsula (Imlay and Inlet basin) and to the southwest of North Detterman, 1973, p. 8-9). From the Alaska Aleutian basin we have a failure analog (St Peninsula the Mesozoic basin probably George basin). The existence of substantive extends an additional 300 miles oil sources in the part of the Mesozoic basin northwesterly beneath St. George basin that lies beneath North Aleutian basin (Worrall, 1991, fig. 15). The approximate remains unproven. However, this area of this Mesozoic basin is highlighted in assessment assumes some capability figure 4 as the “Mesozoic basin with (appropriately risked, given the uncertainty) Jurassic oil source rocks?” The Cook Inlet of Mesozoic oil source rocks for providing basin, the North Aleutian basin, and the St. oil to traps within both Mesozoic and George basin are all superposed on the contiguous Cenozoic rocks.

Petroleum Geology of the North Aleutian Basin

Regional Geology continental margin. The resulting magmatic arc is a continuation of the Aleutian islands Alaska Peninsula volcanic arc to the west, where convergence involves two oceanic plates. Plate The Alaska Peninsula is the site of tectonic- convergence has been occurring at this plate convergence between the Pacific margin episodically since the Early Jurassic. oceanic plate and the North American As a result, the peninsula is geologically

9 complex and includes both Mesozoic and crust under the volcanic arc of the Alaska Cenozoic igneous and sedimentary rocks. Peninsula (Bond et al., 1988). The modern Alaska Peninsula volcanic arc is built upon earlier volcano-plutonic arcs. The North Aleutian Shelf COST 1 well did Intrusive plutons from both Jurassic and not penetrate “basement” but reached total Tertiary magmatic events occur in many depth in Lower Eocene rocks of the lower places on the Alaska Peninsula. The oldest part of the Tolstoi Formation (Detterman, sedimentary rocks on the Alaska Peninsula 1990; Turner et al., 1988). The oldest are Late Triassic carbonates at Puale Bay to known strata within the basin fill are Late the east (located in fig. 2) along Shelikof Paleocene rocks of the Tolstoi Formation Strait, but most of the Mesozoic strata exposed on the Alaska Peninsula (Detterman consist of arc-derived clastic rocks of et al., 1996). Detterman et al. (1996, p. 42) Jurassic and Cretaceous age. Those rocks note that in most parts of the Alaska are mostly of marine origin and are Peninsula, the base of the Tolstoi Formation extensively folded and thrust faulted. The is a prominent Paleocene unconformity that Tertiary section includes interbedded places the Tolstoi on a variety of older volcanic and volcaniclastic sedimentary Mesozoic formations. Wilson et al. (1995) rocks of continental origin. The Tertiary and Detterman et al. (1996) indicate that in strata are less deformed than the Mesozoic the vicinity of the Black Hills uplift and east strata. Both the Mesozoic and Cenozoic to Port Moller, the Tolstoi Formation and rock units of the Alaska Peninsula extend underlying Cretaceous Hoodoo Formation under the North Aleutian Basin OCS (or equivalent Chignik Fm.) are concordant Planning Area. across a disconformity. Offshore on the Black Hill uplift, we observe structural discordance between Tolstoi strata and Formation of North Aleutian Basin underlying Mesozoic rocks in seismic data.

The North Aleutian Basin OCS Planning From regional geological data and seismic Area contains two main depocenters: the interpretation, Worrall (1991) infers a late North Aleutian basin and the Amak basin. Eocene age for the unconformity (his “red” Those two sedimentary depressions are seismic horizon; approximately our seismic separated by the Black Hills uplift, which horizon “D” at 10,380 ft bkb [below Kelly extends westward under the Bering Sea shelf bushing, or measured depth] in the COST from the Alaska Peninsula. The North well) flooring North Aleutian basin proper. Aleutian basin is primarily a Tertiary-age The angular unconformity separating the basin that was filled with sediments derived two sequences was formed when plate from uplifted areas in the Alaska Peninsula reorganization in the north Pacific resulted to the south and the western Alaska Range in a change from convergent to strike-slip (located in fig. 1) to the northeast. The movement along the continental margin North Aleutian basin contains as much as (Marlow and Cooper, 1980; Lonsdale, 1988; 20,000 feet of Cenozoic strata. The basin is Worrall, 1991). Worrall (1991, fig. 38) less than 3,000 ft thick on the northwest and assigns all of the Eocene rocks below 10,660 thickens southeastward to about 20,000 ft bkb in the North Aleutian Shelf COST 1 near the Alaska Peninsula. This asymmetric well to an older (his “carapace” sequence) profile has the appearance of a foredeep, group of Campanian to Eocene rocks that possibly caused by tectonically thickened was deposited and folded prior to the late

Eocene or “red” unconformity. However, it the Alaska Peninsula volcanic arc and the is our view that Worrall’s “carapace Aleutian trench and subduction zone. sequence” in the North Aleutian basin instead represents the earliest basin fill The Amak basin is a relatively small deposited in faulted grabens during the structural depression south of the Black initial rift phase of basin subsidence. Rather Hills uplift on the outer Bering Sea shelf. than the roots of fold synclines (Worrall This basin contains as much as 12,500 feet model), we view these bodies of rock as fill of Cenozoic strata overlying folded and within grabens established at the onset of faulted Mesozoic sedimentary rocks. The transtensional rifting, most likely in Cenozoic strata within the Amak basin are Paleocene time. The Upper Eocene less deformed than in the North Aleutian unconformity (“red” horizon of Worrall; our basin. Wrench faults and normal faults seismic horizon “D”) marks the transition commonly cut the basement and lower from a rift phase (accompanied by faulting) Tertiary horizons, but the horst and graben to a foredeep phase with southward tilting structural style characteristic of the North governed by thrust loading on the south Aleutian basin is absent in the Amak basin. (Bond et al., 1988). The Black Hills uplift is the dominant The North Aleutian Shelf COST 1 well positive structural feature of the southwest reached total depth at 17,155 ft bkb in part of the North Aleutian Basin OCS Lower Eocene rocks of the Tolstoi Planning Area. This uplift plunges Formation, but seismic data suggest an westward from the Alaska Peninsula additional 2,000 to 3,000 feet of stratified through the southern Bering Sea shelf and rocks below the base of the well. Because continues into the St. George Basin Planning of the widespread Paleocene unconformity Area. The Black Hills uplift is probably a at the base of the Tolstoi Formation on the transpressional feature formed by strike-slip Alaska Peninsula, we infer that the oldest motion along the Bering Sea margin. The deposits in the North Aleutian basin, dating Naknek Formation (Late Jurassic) is the onset of rift faulting and basin exposed at the crest of the Black Hills uplift subsidence, are Paleocene in age. onshore. The Naknek Formation and older (as old as Late Triassic) formations probably form the core of the Black Hills uplift. The Structures of Amak Basin, Black Hills crest of the uplift is draped by Upper Eocene Uplift, and North Aleutian Basin through Miocene strata. The uplift is fault- bounded on both the North Aleutian basin The principal structures of the North side (to the north) and the Amak basin side Aleutian Basin OCS Planning Area and (to the south). Wrench fault zones pass contiguous areas are mapped in figure 5. along the north and south flanks of the Black The context for these structures is Hills uplift, as illustrated in a seismic profile compressive deformation on the south and a published by Worrall (1991, pl. 2G). The diffuse zone of strike-slip deformation and wrench fault zones are 10 to 15 miles wide, extension that passes through the Alaska extend through Plio-Pleistocene strata to the Peninsula, the western part of the North seafloor, and are associated with both Aleutian basin, and along the flanks of the transpressional (or “positive”) and Black Hills uplift. All structures are transtensional (or “negative”) flower ultimately rooted in the interactions between structures. Normal (probably transtensional)

11 faults are observed between the wrench of the undiscovered, hypothetical oil and gas zones across the crest of the Black Hills potential of the North Aleutian basin. uplift. The sense of displacement on the wrench faults is believed to be right-lateral The overall structure of North Aleutian on the basis of context and regional basin is illustrated by structural contours on structural patterns (Worrall, 1991). an Upper Oligocene datum in figure 5. The basin is basically a southward-thickening We recognize two general structural wedge that is abruptly terminated in a series domains in the North Aleutian basin: 1) of fold and thrust-fault structures that are the transtensional grabens and horsts in the northern limit of the compressional basin interior; and 2) fold and thrust-fault deformations that dominate the Alaska structures along the south margin. From a Peninsula. The Alaska Peninsula is a fold petroleum exploration standpoint the and thrust belt that grades from simple, open transtensional horsts in the basin interior and structures on the northeast to highly overlying drape structures form the most shortened and complex structures in the attractive prospects in the basin. southwest (Burk, 1965, figs. 21, 22). In its overall shape, the North Aleutian basin In the southwest half of the North Aleutian resembles a foredeep, in which the south basin, transtensional faults bound horsts flank has been depressed by thrust loading with several thousands of feet of structural and in which shallow thrust structures relief at the basement level. Tertiary strata abruptly terminate in a system of duplexes younger than Late Eocene are domed and triangle zones. This view is supported upward over these horsts, partly because of by modeling studies of the deep structure of fault movements and partly because of the North Aleutian basin and the Alaska compaction subsidence within sediment- Peninsula volcanic arc by Bond et al. (1988) filled grabens flanking the horsts. Some and Walker et al. (2003). The Bond study examples of these drape anticlines are concluded that basin subsidence was driven illustrated in the seismic line of figure 6 (full by downward flexure of the back-arc scale image available as plate 1). Drape lithosphere beneath a load imposed by anticlines over basement uplifts extend from subduction-driven crustal thickening of the the Upper Eocene unconformity (seismic arc and forearc of the Alaska Peninsula. horizon “D”--truncates the crests of The Walker study concluded that early basement uplifts) at about 10,000 ft ssd extension and fault-controlled subsidence (subsea depth) upward to a Lower Pliocene was succeeded by flexural subsidence due to unconformity (seismic horizon “A”) at about loading on the south by stacking of volcanic 2,500 ft ssd. Displacements on uplift- materials on the Alaska Peninsula. bounding faults abruptly diminish above the Upper Eocene unconformity, but very small The southeast margin of the North Aleutian (possibly compaction-driven) offsets are basin is deformed by folds, thrust faults, and observed up to about 5,000 feet in figure 6 antiformal duplexes that represent the (and pl. 1). These drape anticlines are the northern front of the Alaska Peninsula fold primary exploration targets in the North and thrust belt. Proprietary seismic data Aleutian basin. Because of their large indicate that the fold and thrust-fault closure areas and involvement of the thick, structures along the southwest margin of the porous Bear Lake-Stepovak reservoir basin terminate northward in triangle zones sandstones, these drape anticlines host most that have tilted rocks as young as Pliocene

over duplex roofs. The David River 1/1A, Castle Mountain fault. To the southwest, Hoodoo Lake 1, Hoodoo Lake 2, and Sandy the fault system is mapped at the surface River 1 wells were all drilled into antiformal through the Alaska Peninsula to Becharof duplexes that back triangle zones that taper Lake, where the fault trace passes southwest northward beneath north-dipping Miocene to beneath Quaternary volcanic and glacial Pliocene basin fill. We speculate (as shown deposits (Detterman et al., 1987). Fault in fig. 5) that similar structures extend along movement was primarily in Middle and Late strike to the northeast and form the targets Jurassic time, when the Alaska-Aleutian drilled at the Port Heiden 1, Ugashik 1, Range batholith was being unroofed, Great Basins 1, Great Basins 2, and providing clastic detritus to the Late Jurassic Becharof Lake 1 wells. However, we do not Naknek and younger formations. The Bruin have access to any seismic data through Bay fault is intruded by a plutonic stock on these latter wells. Southwest of the Sandy the Alaska Peninsula that was age-dated at River 1 well, proprietary seismic data 25.0-26.7 Ma, indicating no movement since indicate that the fold, thrust-fault, and the Oligocene in that area (Reed and duplex structures do not extend offshore into Lanphere, 1972; Magoon et al., 1976, sheets Federal waters. Therefore, these fold and 2, 3, sites 66 & 67; Detterman and Reed, thrust-fault structures do not form an oil and 1980). To the north, the subsurface trace gas play in our assessment of the North extends very close to the complexly-folded Aleutian basin. and reverse-faulted structures of the Middle Ground Shoal, McArthur River, Beluga River and other oil and gas fields of upper Nature of Basement Beneath North Cook Inlet (Boss et al., 1976). According to Aleutian Basin Haeussler et al. (2000), those fault-cored folds are Miocene and younger, with most of In the western Alaska Range, the Bruin Bay the deformation occurring in the fault forms a regional contact between Quaternary. Mesozoic volcano-plutonic rocks on the north and Mesozoic sedimentary rocks on Penetrations of Mesozoic granitic rocks the south (Magoon et al., 1976). The beneath the North Aleutian basin fill north volcano-plutonic rocks on the north are the of the Bruin Bay fault occurred at the Great roots of a Mesozoic volcanic arc and range Basins 1, Great Basins 2, Becharof Lake 1, in K-Ar ages from 179 to 107 Ma (Magoon and Port Heiden 1 wells. Penetrations of et al., 1976, sh. 3), or Middle Jurassic to Mesozoic sedimentary rocks south of the mid-Cretaceous, respectively, in equivalent Bruin Bay fault occurred at the Cathedral stratigraphic ages. The Mesozoic River 1, David River 1/1A, and Hoodoo sedimentary rocks south of the Bruin Bay Lake 2 wells. Five wells in the St. George fault represent a Mesozoic basin that flanked basin to the west encountered Mesozoic the contemporary volcanic arc to the north sedimentary rocks beneath Tertiary basin (Bally and Snelson, 1980). fill. The North Aleutian Shelf COST 1 well did not reach any pre-Tertiary rocks. These The Bruin Bay fault system is a series of well penetrations of the Mesozoic substrate high-angle reverse faults with the upthrown are sparse and only provide fragmentary side on the northwest (Detterman and Reed, information about the subsurface 1980). The Bruin Bay fault is truncated distribution of the component terranes. north of Cook Inlet by the presently-active

Southwest of Becharof Lake, as noted west-trending line that may represent the above, the Bruin Bay fault passes beneath extension of the Bruin Bay fault into the volcanic rocks and glacial sediments of southern Bering Sea. Quaternary age of the Bristol Bay lowlands. The lowlands are dotted with numerous We speculate that the northern magnetic semi-circular magnetic anomalies that Case domain in figure 7 is the southwestward, et al. (1988) interpret to locate buried offshore extension of the Mesozoic granitoid to gabbroic plutons of Jurassic to magmatic arc terrane exposed north of the Tertiary ages. None of these buried igneous Bruin Bay fault in the western Alaska bodies have been sampled or dated and Range. In support of this notion we observe speculations about their ages are based on that magnetic data over the exposed regional context. A narrow, north-northeast- magmatic arc terrane north of the Bruin Bay trending belt of high magnetic intensity fault (in a regional compilation published by (anomaly 8C of Case et al.) south of Godson, 1994) show a high-frequency, high- Becharof Lake is interpreted to locate a intensity field character much like that of the buried anticlinal limb of Naknek Formation northern magnetic domain illustrated in (Jurassic) (Case et al., 1988, fig. 4, p. 4). figure 7. Along the Alaska Peninsula This “Naknek” anomaly is truncated on the proper, there are numerous magnetic north at a projected buried strand of the anomalies related to Tertiary-age intrusives Bruin Bay fault 15 miles southwest of and modern volcanoes. West of 162º WL, Becharof Lake (Case et al., 1988, sheet 2).2 the projected extension of the Bruin Bay Farther southwest, the location of any fault diverges northwest away from the extension of the Bruin Bay fault is unknown Tertiary arc and the contrast in magnetic and a matter for speculation. domains north and south of the Bruin Bay fault is more clear (fig. 7). A regional magnetic intensity map for the southern Bering Sea shelf published by In marine seismic data over the Black Hills Childs et al. (1981) is reproduced with uplift, we observe coherent, folded annotations in figure 7. The map shows two reflections that extend up to 2 sec below a principal magnetic domains with very prominent angular unconformity at the base different field characters. In the north, the of Tertiary rocks. These coherent, folded map shows high-frequency, high-intensity reflections are interpreted to correspond to magnetic anomalies. In the south, the map Mesozoic strata that are exposed onshore to shows low-frequency, low-intensity the east along the crest of the Black Hills magnetic anomalies. The two magnetic uplift (fig. 5; Wilson et al., 1995). Some domains are clearly separated by a sharp, examples of these coherent, folded reflections are observed within the “Peninsular terrane” in a seismic panel 2 Similar relationships are shown on geologic maps published by Worrall (1991, pl. 2, line “G”) (Magoon et al., 1976, sheet 2) to the east near Kamishak Bay. In the latter area, the exposed and in the southwest end of a seismic panel Naknek Formation is confined to the block southeast published by Turner et al. (1988, fig. 65). of the Bruin Bay fault, which also truncates the axes The “Peninsular terrane” corresponds to the of large folds within the Naknek (Magoon et al., Mesozoic sedimentary rocks southeast of the 1976, sheet 2). Naknek folds and the Bruin Bay fault 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 North of the Black Hills uplift, Worrall minimum age for the deformation.

(1991, pl. 2) shows deeply buried synclines sedimentary terranes juxtaposed along a in a folded “carapace” sequence of Late southwestern extension of the Bruin Bay Cretaceous to Eocene age that underlies his fault. “Red” Upper Eocene unconformity. Worrall’s synclines are associated with Figures 5 and 7 show that the most coherent seismic reflections that are lost important gas and oil prospects in the North through the intervening anticlines. We Aleutian basin (partly located by Sale 92 interpret these features somewhat leases) occupy the part of the basin that differently. We view Worrall’s “synclines” overlies the Mesozoic magmatic terrane as grabens that record the earliest rift north of the Bruin Bay fault. This subsidence of the North Aleutian basin and observation is very significant to conceptual that are filled with Paleocene to Eocene age models for petroleum charge for these strata. We interpret Worrall’s “anticlines” important prospects. Any analogy to the as horsts that are decapitated by an Upper petroleum system of northern Cook Inlet, Eocene unconformity corresponding to our where oil generated in an underlying seismic horizon “D” (fig. 6). Our horizon Mesozoic basin has charged shallower traps “D” correlates to Worrall’s “Red” in Cenozoic rocks, cannot be extended to unconformity. The horizon “D” this part of the North Aleutian basin. It is unconformity separates the rift phase from very unlikely that hydrocarbons in any the subsequent sag phase of basin quantity can be sourced out of the Mesozoic subsidence. The horsts are acoustically magmatic terrane beneath the part of the transparent (lack coherent reflections) in North Aleutian basin north of the Bruin Bay their central areas (fig. 6 and lines “F” and fault. These important prospects must “G” of Worrall, 1991, pl. 2). We interpret instead depend entirely upon potential the horsts to be cored by primarily Mesozoic sources within the Tertiary-aged North magmatic rocks with sparse surviving Aleutian basin fill, mostly gas-prone, for bodies of unabsorbed Mesozoic sedimentary petroleum charge. rocks. The acoustic transparency of the substrate below the “Red” unconformity north of the graben field in North Aleutian Mesozoic Stratigraphy and Reservoir basin is illustrated at the north ends of lines Formations “F” and “G” of Worrall (1991, pl. 2). A stratigraphic chart for the Mesozoic rocks We have not attempted to map the of the Alaska Peninsula is presented in southwestward extension of the Bruin Bay figure 8. Sandstones and conglomerates that fault in seismic data, instead relying on might form reservoirs for petroleum include magnetic character to separate the northern the Talkeetna, Naknek, Staniukovich, magmatic terrane from the southern Herendeen, and Hoodoo (or equivalent sedimentary terrane. But, it is our general Chignik) Formations. Because the experience that the acoustic appearance of Mesozoic basins in which these strata were the Mesozoic substrate on the north deposited flanked a volcanic arc, most (transparent) is fundamentally different from clastic sediments contain great quantities of the Mesozoic substrate on the south volcanic and plutonic rock fragments. Upon (stratified/folded). Offshore seismic data burial, the volcanic material readily therefore support our partitioning of the degraded into laumontite and other zeolite- Mesozoic substrate into magmatic and group minerals that fully occluded

15 intergranular porosity. Dutrow (1982, p. 1) Formation sandstones, which are underlain describes typical Jurassic-age sandstones in by the Middle Jurassic Tuxedni Group oil the Cathedral River 1 well as follows: source beds, which are in turn underlain by the Lower Jurassic Talkeetna Formation “Petrographic examination of 43 sandstones (Magoon, 1994). Despite this samples from Amoco Cathedral close association with the Tuxedni Group oil River No. 1 sand, showed the lithology to be predominately source beds (proven to have generated 1.6 volcanic-rich litharenites or billion barrels of oil reserves now residing in feldspathic litharenites with only overlying Tertiary reservoirs), there is minor amounts of arkose, lithic virtually no oil production in northern Cook arkose, and quartzite (the Inlet from the associated Mesozoic classification scheme used is Folk, 1968). Typically the sands were sandstone formations. The Naknek and compacted with no remaining Talkeetna Formations are completely porosity. Often volcanic rock cemented and barren of hydrocarbons. We fragments became incoherent with note a single exception at the McArthur compaction, molding around grains River oil field where a small amount to form an interstitial matrix. Where compaction did not reduce (<300,000 bbls) of oil was produced over a all intergranular voids, authigenic 9-year period from fractured Lower Jurassic cements formed. The cements are rocks (Talkeetna Formation) below the main chlorite/smectite, laumontite, and Tertiary-age oil reservoir (AOGCC, 2001, p. carbonate. Veins of 183). The generation of oil out of the laumontite/heulandite cut the volcaniclastic sands. These phases Middle Jurassic oil source beds occurred also replace pre-existing minerals. mostly in Tertiary time (Magoon, 1994, fig. The most common accessory 22.7), after 100 million years of burial stasis minerals were a green hornblendic during which diagenesis and compaction amphibole, epidote and opaques completely destroyed the pore systems in (clasts and pyrite framboids.”(sic) Mesozoic sandstone formations. An

intriguing concept for petroleum exploration Generally, younger sandstone formations of Mesozoic sandstones postulates that in contain less volcanic debris because of re- some areas an early (presumably cycling of older clastic formations and Cretaceous) cycle of burial sufficient to winnowing of volcanic particles made generate hydrocarbons might have charged susceptible to disintegration by chemical the still-porous Mesozoic sandstones with and physical weathering (Burk, 1965, fig. petroleum and protected the pore systems 10). Younger formations have also been from destruction. However, this was not the less deeply buried because of their position case in the Cook Inlet area. at the top of the sedimentary stack and have presumably suffered less from compaction and thermally-driven pore-filling diagenesis. Cenozoic Stratigraphy, Reservoir For both of these reasons, the Staniukovich Formations, and Play Sequences and Naknek Formations and younger

Cretaceous units form the best candidates The most complete point of stratigraphic for viable petroleum reservoirs among the control for the North Aleutian basin fill is Mesozoic assemblage (fig. 8). the North Aleutian Shelf COST 1

stratigraphic test well that was drilled in The prolific oil fields of northern Cook Inlet 1983 by an industry consortium. Detailed are underlain by the Upper Jurassic Naknek

16 descriptions of the results of that well are to Early Pliocene in the North Aleutian given by Turner et al. (1988). The Shelf COST 1 well and includes the upper stratigraphy of the COST well is presented part of the Stepovak Formation, the entire in figure 9 (full-scale version available as Bear Lake Formation, and the lower part of plate 2). the Milky River Formation. The play sequence is 5,390 feet thick at the COST Three play sequences based on COST well well and thickens to approximately 7,300 stratigraphy are defined for purposes of this feet in seismic data along the north coast of assessment. Each play sequence embraces the Alaska Peninsula (Turner et al., 1988, groups of rocks that share some figs. 66, 67). The Bear Lake-Stepovak play commonality in reservoir formation sequence overlies seismic horizon “C” characteristics and relationships to which is a regional mid-Tertiary prominent unconformities and seismic unconformity. On parts of the Black Hills markers. The play sequences considerably uplift, seismic horizon “C” places Oligocene overlap biostratigraphic boundaries but rocks directly upon Mesozoic rocks. correspond sufficiently to established Seismic horizon “C” does not contact stratigraphic units to permit co-opting the basement over the basement horsts in the formal nomenclature into our play sequence southwest half of the North Aleutian basin, terminology (shown in fig. 9, right column). but overlies a sandy sequence and a regional Detterman (1990) extended Alaska shale sequence in the lower part of the Peninsula stratigraphic nomenclature to the Stepovak Formation (fig. 10). Seismic North Aleutian Shelf COST 1 well and we horizon “D” incises basement on the horsts adopt his correlations for this assessment in the southwest half of the North Aleutian (shown in fig. 9, left column). A basin. The seismic profile in figure 6 (and stratigraphic correlation chart in figure 10 pl. 1) shows that most of the strata in the (full-scale version available as plate 3) Bear Lake-Stepovak play sequence are shows the relationship of the North Aleutian domed over the basement horsts in the Shelf COST 1 well to several onshore southwest half of the North Aleutian basin. penetrations of Tertiary rocks. The Bear Lake-Stepovak play sequence at The Milky River Biogenic Gas (play 4) play the North Aleutian Shelf COST 1 well is sequence ranges in age from Early Pliocene rich (61% of play sequence) in thick (up to to Holocene and includes the upper part of 277 feet), porous (up to 40+% porosity), and the Milky River Formation and overlying permeable (up to 7,722 md) sandstones. unnamed Quaternary-age rocks. The play Some statistics for sandstone beds in the sequence is 2,148 feet thick at the North Bear Lake-Stepovak play sequence are Aleutian Shelf COST 1 well. The play summarized in figure 11. The play sequence sequence overlies seismic horizon “A”, contains a total of 3,120 net feet of which generally is not domed over basement sandstones in beds greater than 10 feet thick uplifts. The play sequence consists of (an assumed practical minimum thickness middle to outer neritic unconsolidated lithic for productive reservoir) and 1,443 net feet pebbly sands, mud, ooze, and clay (Turner et in beds over 100 feet thick. Figure 12 al., 1988, p. 14). shows core porosity versus depth for sandstones in the North Aleutian Shelf The Bear Lake-Stepovak (plays 1, 3) play COST 1 well. Core porosity is also posted sequence ranges in age from Late Oligocene with density log sandstone porosity in figure

9 and plate 2. For the Bear Lake-Stepovak interval), thin (maximum = 57 ft) play sequence, core porosity ranges between sandstones. In the upper part of the Tolstoi 20% and 40%. Figure 13 summarizes core play sequence, from 7,900 to 10,380 feet in porosity and permeability data and we note the COST well, the sandstones are porous that the 20% to 40% porosity range is and permeable (figs. 12, 14, 15, and 16). associated with multi-Darcy permeability This part of the sequence, like the overlying values. Figure 14 summarizes core Bear Lake-Stepovak play sequence, is permeability data versus depth and we draped over the basement uplifts. Below observe that the statistical fit forecasts 10,380 feet, the sandstones are largely preservation of permeability at tens of impermeable (fig. 16, lower panel) because millidarcies (at the mean) down to the base diagenesis (to clay and zeolites) has softened of the Bear Lake-Stepovak play sequence. volcanic clasts and the sandstone grain A core porosity histogram for the Bear framework has collapsed, as described in Lake-Stepovak play sequence is shown in petrographic studies by AGAT (1983, p. 2) the upper panel of figure 15. A core and Turner et al. (1988, p. 23-24). This permeability histogram for the Bear Lake- collapse post-dates some early pore-filling Stepovak play sequence is likewise cement, around which formerly rigid presented in the upper panel of figure 16. volcanic framework grains (softened by Because of the ample, thick sandstones and diagenesis) have flowed (AGAT, 1983). the excellent preservation of porosity and The abrupt loss of permeability in permeability, the Bear Lake-Stepovak play sandstones approximately coincides with the sequence is the most attractive reservoir onset of overpressure at 11,200 feet bkb (fig. target in the North Aleutian basin. 9 and pl. 2) in the North Aleutian Shelf COST 1 well. The diagenetically-induced The Tolstoi (play 2) play sequence ranges in implosion of the intergranular pore system age from Early Eocene to Early Oligocene and expulsion of fluids may be a prime in the North Aleutian Shelf COST 1 well driver for the overpressure (Turner et al., and includes the Tolstoi Formation and the 1988, p. 217). Core porosity data for the lower, shaly part of the Stepovak Formation Tolstoi play sequence are summarized in the (9,555-10,380 ft bkb) that forms a regional histograms of figure 15. Most of the seal (fig. 10 and pl. 3). The minimum measured core porosity in the Tolstoi play thickness (base not penetrated) of the Tolstoi sequence below 10,380 feet bkb in the play sequence is 9,255 feet at the North COST well is microporosity in altered Aleutian Shelf COST 1 well. The Tolstoi volcanic rock fragments. play sequence probably extends through Paleocene strata down to Mesozoic volcano- The lower part of the Tolstoi play sequence plutonic “basement” beneath the COST (below 10,380 ft/seismic horizon “D”) is well. Seismic horizon “D” occurs within the truncated by faults at the flanks of basement upper part of the Tolstoi play sequence and uplifts and would form the primary reservoir corresponds to a regional Upper Eocene targets for prospects ringing uplift flanks. unconformity that truncates the crests of The probable absence of porous sandstones basement uplifts in the southwest half of the in the lower part of the Tolstoi play North Aleutian basin (fig. 6 and pl. 1). As sequence forms an area of great risk for the shown in the sandstone thickness histograms flank prospects. of figure 11, the Tolstoi play sequence is characterized by sparse (10% to 30% of

Petroleum Systems in North Aleutian (fig. 17). Basin Plays The statistical fits to the data sets above and below the fault gap at 15,620 ft bkb in figure Thermal Maturity of North Aleutian 17 were used to forecast depths to various Basin Fill isograds3 that correspond to critical stages in source maturation, as tabulated (inset) in The first important concern about the figure 17. These isograds are posted on the viability of any potential petroleum systems seismic profile in figure 6 (and pl. 1) and in North Aleutian basin is whether or not show that the principal reservoir section any rocks have been buried to depths and (between seismic horizons “A” and “C”) in temperatures sufficient to convert organic the sequence domed over the basement matter to oil or gas. Figure 17 summarizes uplifts is thermally immature (pre-oil vitrinite reflectance data for the North generation). Only the much deeper rocks in Aleutian Shelf COST 1 well and offers the grabens flanking basement uplifts are statistical fits to data sets above and below a thermally mature and capable of having discontinuity at 15,620 feet bkb. The generated oil or gas. Rocks within the vitrinite reflectance discontinuity has been Mesozoic substrate may be sufficiently cited as evidence for an unconformity at thermally mature to have generated oil or 15,620 ft bkb (Turner et al., 1988, p. 192; gas, but in this area these rocks are Robertson Research, 1983). If so, the interpreted to consist of mostly volcano- statistical fits indicate “erosion” of 647 feet plutonic arc rocks. Successful charging of of section at the “unconformity.” As an prospects in the strata domed over basement alternative interpretation, we suggest that the uplifts will require generation of petroleum discontinuity at 15,620 ft bkb is a 647-foot in flanking deeps, lateral migration to the sequence gap at the point where the well flanks of basement uplifts, and vertical penetrated an unrecognized normal fault. migration up faults through the regional We note that no vitrinite reflectance shale sequence (approx. the interval between discontinuities are associated with known seismic horizons “C” and “D” in fig. 6 and regional unconformities corresponding to pl. 1) in order to reach sandstone reservoirs either seismic horizon “B” (5,675 ft; Upper in the Bear Lake-Stepovak play sequence Oligocene), seismic horizon “C” (7,900 feet, (between seismic horizons “A” and “C”). Upper Oligocene), or seismic horizon “D” (10,380 ft; Upper Eocene). A 20-degree The basement uplift to the southeast of the structural dip first noted in core 19 (Turner North Aleutian Shelf COST 1 well in figure et al., 1988, p. 26) probably indicates the 6 (and pl. 1) won 73% of the sum of all high presence of an angular unconformity bids in OCS Lease Sale 92 in 1988. All of between flat-lying strata at the base of core the remaining bids in Sale 92 were placed on 18 (16,028.5 ft bkb) and dipping strata at the tracts over nearby basement uplifts that top of core 19 (16,701 ft bkb). This is the similarly dome the overlying Bear Lake- “Lower Eocene unconformity” posted in the Stepovak play sequence and that are also seismic profile of figure 6 (pl. 1) and in the adjoined by areas of deep subsidence where stratigraphic column of figure 9 (pl. 2). As with the shallower regional unconformities, 3 “Isograd” is used here to denote a surface of fixed no discontinuity in vitrinite reflectance is thermal maturity. Any single thermal maturity index associated with this angular unconformity value (TTI, Ro%, etc.) can be used to represent an isograd.

19 the basin fill lies within the oil and gas4 of oil and gas lie within the gray areas, the generation zone. It appears that the energy latter then become the “oil (and gas) companies that placed bids on tracts in Sale kitchens” for the basin. Figure 19 maps the 92 embraced the basic framework of the thicknesses of Tertiary-age strata within the hypothetical petroleum system described oil generation zone and we note that the above as that most likely to create maximum penetrated thickness (minimum, significant petroleum accumulations within 4,758 ft) is at the North Aleutian Shelf North Aleutian basin.5 The model requires COST 1 well. generation of large quantities of petroleum in flanking grabens and migration of the The North Aleutian basin hypothetical “oil petroleum several thousands of feet upward kitchen” is segmented by the presence of a into porous strata domed over basement massive volcanic center at the Port Heiden 1 uplifts. The minor (small displacement) and Ugashik 1 wells. This volcanic center faults extending upward from the major produced a thick pile of volcanic flows and (large displacement), older faults along volcaniclastic sediments 33 to 39 millions of uplift flanks are the only faults that penetrate years ago. The volcanic pile is represented the regional lower Stepovak shale seal by the Meshik Formation. The Meshik (overlying seismic horizon “D”; fig. 10 and Formation is age-equivalent to the Stepovak pl. 3). These faults may provide the critical Formation (Brockway et al., 1975) or pathways from deep areas of petroleum Tolstoi Formation (Detterman, 1990), with generation to shallow traps domed over which the volcanic rocks interfinger at the uplifts. margins of the volcanic center (fig. 10 and pl. 3). The segmentation by this volcanic Figure 18 presents regional well data for center of the thermally-mature rocks thermal maturity compiled into a structure flooring North Aleutian basin leaves the map for the 0.6% vitrinite reflectance southwest part of the basin with the largest isograd, which generally coincides with the continuous volume of potentially oil- onset of oil generation (depending on generative rocks. This part of the basin has organic matter composition, oil or gas accordingly formed the primary area of generation can begin as low as 0.5% vitrinite exploration interest in the past. reflectance [liptinitic or Type 1 kerogens]; Dow, 1977, fig. 3). Areas highlighted in The Amak basin fill reaches a maximum gray represent Tertiary basin fill that thickness of about 12,500 feet, scarcely 200 exceeds 0.6% vitrinite reflectance. If rocks feet deeper than the depth to the 0.6% with appropriate organic matter for creation vitrinite reflectance isograd (12,312 ft subsea) in the North Aleutian Shelf COST 1 4 Boreham and Powell (1993, p.149-50) point out well. It appears that only a very small that “humic coals and terrigenous kerogens can form volume of rock at the floor of the Amak appreciable quantities of gas over the maturity range basin lies within the oil generation zone. It of oil generation….” and “…significant yields of gas generation before the onset of intense liquid is therefore unlikely that significant generation have been experimentally observed for quantities of hydrocarbons have been both hydrogen-poor and hydrogen-rich organic generated in the Amak basin. 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.

Source Rock Potential For most of the Mesozoic sequence penetrated by the Cathedral River 1 well6, The second important concern about the rocks are rated as poor to fair sources potential petroleum systems in the North (TOC) for gas (Hydrogen Index). Two Aleutian basin is whether or not any rocks significant anomalies are observed in figure have the type of organic matter appropriate 20. Shales and tuffaceous limestones in the for conversion to oil or gas upon heating. interval from 8,700 to 9,300 feet in the We recognize two groups of potential source Kialagvik Formation appear to rate as rocks: 1) Mesozoic sedimentary rocks that “good” potential sources for oil and wet gas. underlie the southwest part of North Cherty shales and marlstones in the interval Aleutian basin and the Black Hills uplift; from 12,000 to 12,700 feet in the Talkeetna and 2) Cenozoic rocks that comprise the Formation also appear to form “good” North Aleutian basin fill. sources for oil and wet gas7. These anomalies are somewhat suspect because the elevated thermal maturity (>3.0 T.A.I., or Mesozoic Source Rocks greater than approximately 1.0% vitrinite reflectance below 7,300 ft bkb) of much of The principal point of control for the source rock potential of Mesozoic rocks in the 6 The logged shows and geochemical data in the North Aleutian Basin OCS Planning Area is Cathedral River 1 well are somewhat problematic in the Cathedral River 1 well. Some indicators that oil-base additives were introduced into the for source rock potential of the Mesozoic drilling mud at about 7,500 feet. However, no rocks in this well are plotted in figure 20. geochemical anomalies are observed at the first reported (Borst & Giddens mud log) point of introduction of “Soltex” at 7,500 feet (fig. 20). The Mesozoic rocks extend across southern deeper anomalies rise from an established Alaska (fig. 4) but are known to have “background” and could be reflecting rock generated significant quantities of oil only in compositions rather than drilling mud contamination, the northern Cook Inlet area. The Kialagvik unless other additives were introduced. An Formation in the Cathedral River 1 well (fig. annotation on the Borst & Giddens mud log at 8,770 feet reports that “abundance of tar noticed in 20) is age-equivalent to the Middle Jurassic samples are determined to be contamination as Tuxedni Group that generated the oil in results (sic) of mud additive reactions of ‘HME’ and northern Cook Inlet producing fields ‘SuperLubFlow’”. The anomalies in the TOC and (Magoon, 1994). The Kamishak Formation HI profiles may reflect authentic rock properties, but in the Cathedral River 1 well is age- the potential contamination clouds the issue (Peters, 1986, p. 324-5) and in this case blocks any equivalent to unnamed Upper Triassic rocks straightforward conclusions. Geochem Laboratories at Puale Bay that are suspected of (Geochem, 1976) reported that samples deeper than contributing oil to some minor 8,600 feet were contaminated, possibly with accumulations and seeps in southern Cook “Gilsonite”. We note that Peters (1986, fig. 12) Inlet and the Alaska Peninsula (Magoon and specifically discusses the Cathedral River 1 case and concludes that the anomalies are entirely artifacts of Anders, 1992; Magoon, 1994). The Upper contamination by drilling mud additives. Triassic rocks at Puale Bay form excellent 7 Oil staining is reported (Detterman, 1990) in rocks oil-prone source rocks (Wang et al., 1988, immediately above these anomalies. Modest “S1” fig. 4), but are only known from that outcrop (resident hydrocarbons thermally distilled out of locality and the penetration at the Cathedral rocks during pyrolysis experiments) anomalies (rise from 0.2 to 0.7 mg/g [upper zone] or 0.2 to 1.07 mg/g River 1 well. [lower zone]) suggest a possible association of the TOC and Hydrogen Index anomalies with migrated oil.

21 the Cathedral River 1 sequence indicates Mesozoic cycle of deep burial. Thus, there that most of the original oil generation is substantial risk that Mesozoic oil sources potential of the Mesozoic rocks has been in this area generated and expelled their oil depleted. A single vitrinite reflectance long before the deposition of Tertiary-age analysis (6 measurements) at 10,650 feet reservoir sandstones or the formation of yielded a mean value of 1.47%, well past the drape anticlines in Oligocene strata atop the 1.35% vitrinite reflectance isograd marking Black Hills uplift. exhaustion of all oil generation potential. The top of the prominent geochemical anomaly within the Talkeetna Formation lies Tertiary Source Rocks at 12,000 ft bkb, 1,350 feet below the lone vitrinite reflectance measurement. The principal point of control for the source rock potential of the Tertiary-age fill for The pyrolysis data are inconclusive because North Aleutian basin is the North Aleutian of doubts about analytical results (possibly Shelf COST 1 well. A graphical summary distorted by mud additive contaminants, as of source rock geochemical information is footnoted) and the high thermal maturity of attached as plate 4. An Excel spreadsheet the Mesozoic sequence (original generative containing most available geochemical data potential largely depleted). However, the for the COST well is included as Appendix Cathedral River 1 data are at least 2. The data in Appendix 2 were extracted permissive of the potential existence of oil from the original reports by Exlog (1983) sources within the Mesozoic sedimentary and Robertson Research (1983), which are rocks beneath the Black Hills uplift. That attached as Adobe Acrobat (pdf) files to this some oil source rocks once existed within report as Appendix 4 and Appendix 5, the Mesozoic sequence beneath the Black respectively. Hills uplift is supported by the observation of oil shows throughout the Cathedral River Some indicators for source potential (TOC) 1 well. Oil shows were first noted as and hydrocarbon type (hydrogen index or shallow as 390 feet bkb, far above the first “HI”) in the COST well are plotted in figure reported introduction of the troublesome 21. Total organic carbon (TOC) data drilling mud contaminants at 7,500 feet. suggest that source potential ranges from The time of generation of this oil is “poor” to “very good.” Hydrogen index unknown. Near the surface, the Cathedral (HI) values suggest mostly gas sources with River 1 well entered Mesozoic rocks with some intervals where HI>300 that might be T.A.I. values of 2.5 (fig. 20), approximately capable of generating oil. Sample equivalent to 0.65% vitrinite reflectance. A descriptions reveal that most samples with vitrinite reflectance of 0.65% corresponds to TOC values exceeding 1.0% include coal, as a depth of 13,287 feet bkb in the North either discrete fragments in cuttings or coaly Aleutian Shelf COST 1 well. Clearly, the laminations in core samples. In the several rocks in the Cathedral River 1 well were depth intervals below 8,000 feet in figure 21 previously much more deeply buried. where HI>300, we note that nearly all of the Because the well is located on the Black elevated HI values are associated with rock Hills uplift where Mesozoic strata are sequences described as containing coal. unconformably overlain by Eocene-age The key question then is whether or not rocks (north flank), it appears that the these high-HI coals, or possibly non-coal thermal maturation occurred during a lithologies mixed with coal material in

22 samples, are legitimately capable of generating oil. Cuttings samples are problematic because unstable formations like coal may spontaneously collapse (“cave”) into the Source Potential of Coal-Bearing Rocks uncased part of a wellbore at any time and mix with the actual cuttings carried away Exlog (1983, p. 8) attempted to remove the from the drill face to the surface. A cuttings coal (by water flotation) from a suite of sample may contain materials from any cuttings samples and then conducted depth in the uncased or “open” part of a well separate pyrolysis8 experiments on the and may not represent the collected drill “coal-removed” and “coal-retained” sample interval. Unless “cave” materials are suites. Both data sets are shown in the well selectively removed, bulk analyses of profiles for pyrolysis data in figure 21 and cuttings samples will not truly represent the plate 4. Figure 22a compares these two drill interval. Exlog data sets in a modified Van Krevelen diagram. The plot fields for “coal- Sidewall and conventional core data clarify removed” and “coal-retained” sample suites the link between the presence of coal and in figure 22a essentially overlap with several elevated HI values in the North Aleutian samples from both suites yielding HI>300. Shelf COST 1 well. Figure 22b shows a One possible conclusion from the Exlog modified Van Krevelen diagram with experiment is that both coal-bearing and pyrolysis data for core samples from the non-coal-bearing lithologies in the COST COST well (Robertson Research, 1983, well are capable of generating liquid App. III). Samples described as coal- hydrocarbons. A second possible bearing are plotted separately from samples conclusion is that the Exlog9 method for for which descriptions did not note the removing coal from cuttings was presence of coal. All core samples with HI unsuccessful and that the high HI values in values exceeding 151 are described as both sample suites are associated with coal containing coal by Robertson Research material. Clearly, a more explicit means of (1983, App. II). Among sidewall cores, the evaluating the source potential of the well highest HI value observed for coal-free samples is needed. We first need to samples is 123. Among conventional core establish the role of coal-bearing samples in samples, the highest HI value observed for generating the high HI values noted in parts coal-free samples is 151. Coal-free core of the COST well. We secondly need to samples therefore appear to be primarily establish the liquid-generating potential of sources for gas (characterized by HI<150). the coals themselves. But, what about the coal-bearing core samples with HI>150? Could these coal- bearing rocks form potential sources for oil? 8 Samples are heated, driving off existing petroleum (bitumen) and then cracking the organic matter and 10 releasing petroleum-like materials. This method is Figure 22c shows a Van Krevelen-type fast and inexpensive compared to elemental analysis and can yield results that can be used in a similar 10 The Robertson Research (1983, App. VII) data set way. reports O (oxygen) and S (sulfur) as combined into a 9 Use of trade names or references to specific single value. The classification fields in figures 22c corporate entities or products in this report is for and 22d were extracted from a published diagram descriptive purposes only and does not constitute plotting H/C versus O/C (Tissot and Welte, 1984, fig. endorsement of these products or companies by the II.4.14). The presence of significant quantities of U.S. Minerals Management Service sulfur may shift the data to the right and distort

23 diagram with elemental data11 for sidewall an incorrect interpretation of the type of and conventional core samples, with coal- organic matter. Robertson Research (1983, bearing and coal-free samples plotted p. 9) raised another problem wherein the separately. All samples fall within (or to the coal-bearing samples in the COST well may right of) the classification area for Type III have yielded high HI values and low OI (gas-prone) organic matter. Samples in values because of the presence of solid figure 22c with [O+S]/C elemental ratios bitumen. This has the effect of shifting data greater than 0.6 are atypical and may contain points toward the y-axis (fig. 22b) and sulfur or oxygen-rich matter like lignite or perhaps out of the classification field for woody material12 (Tissot and Welte, 1984, Type III kerogen and into the classification fig. II.8.6, p. 240). field for Type II kerogen.

Nine core samples containing coal that have Given the ambiguities of interpreting coal HI>150 (HI range, 200-373; mean HI=289) pyrolysis data, it seems clear that elemental and for which elemental data are available data provide a more reliable way to evaluate are plotted in figure 22d. The oil-generating the oil-generating potential of the coal- potential suggested by the high HI values for bearing Tertiary rocks in the North Aleutian these 9 coal-bearing core samples is not Shelf COST 1 well. The elemental data at supported by elemental data. Figure 22d hand indicate dominance of gas-prone Type shows that none of the nine COST well core III kerogens in coal and non-coal lithologies samples plot within the Type I or Type II alike. Oil-prone algal coals, if present, were classification fields where algal coals are not sampled by the North Aleutian Shelf usually found. All 9 core samples with COST 1 well. HI>150 are shown by elemental data to contain primarily Type III organic matter and to therefore be gas-prone. Source Potential of “Amorphous” Interval, 15,620-17,155 ft bkb In pyrolysis experiments coals can yield specious results that improperly “type” The part of the COST well below the fault organic matter. Coals sometimes yield high cut at 15,620 ft (fig. 17) is associated with pyrolysis HI values that over-estimate the abundant “amorphous” (oil-prone) kerogens, capacity to generate liquid petroleum high H/C values, high gas “wetness,” 13 and (Peters, 1986, p. 322). Another problem is oil shows. These outwardly signal the that thermally-mature coals may yield low possible presence of potential oil sources in oxygen index (OI) values during pyrolysis what is otherwise a nonmarine, coal-bearing because more oxygen is released as carbon clastic sequence (fig. 9). A review of the monoxide (not detected by device) rather characteristics of what we here informally than carbon dioxide (detected by device) term the “amorphous” interval follows. (Peters, 1986, p. 322). Both of these pyrolysis responses of coals would lead to The part of the COST well below the fault cut at 15,620 feet drew attention soon after relationships to traditional kerogen classification the well was drilled because it is associated fields. with high fractions (30% to 55%) of 11 H, hydrogen; C, carbon; O, oxygen; and S, sulfur. “amorphous” (i.e., unstructured) kerogens as 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. 13 Gas present in the tops of sealed cans containing II). cuttings samples.

observed in microscope studies (upper viewed as primarily a source for gas. panel, pl. 4). “Amorphous” kerogens usually signal algal origins (Type I kerogen) A depth profile for elemental H/C data for and in dominant proportions may form a the COST well is shown in the upper panel source for liquid hydrocarbons. of plate 4. Elemental data classify most of the strata penetrated by the well as potential The “amorphous” interval probably does not sources for dry gas or wet gas. However, form a source for oil. The amorphous within the “amorphous” interval below kerogen content in the COST well samples 15,620 feet, four conventional core samples is probably insufficient to form effective oil yielded elemental H/C ratios greater than sources. Robertson Research (1983, p. 6-7) 1.0,15 suggesting some liquid-generating claims that amorphous kerogens must potential. These samples are coal-free and exceed 65% by volume14 relative to the 3 are described as gray or brown massive other kerogen classes to form an effective shales (Robertson Research, 1983, App. II). oil source. Microscopy studies indicate Vitrinite reflectance values for these four abundances ranging between 30% and 50% samples range from 0.98% to 1.01% in the “amorphous” interval in the COST (Robertson Research, 1983, App. III). At well (upper panel, pl. 4). this level of thermal maturity, these H/C values would normally be associated with an Other data indicate poor potential for oil-prone source (as classified by the profile generation of liquid hydrocarbons by the in pl. 4). However, HI values for these four “amorphous” interval. The interval in the samples range from 88 to 120, indicating COST well is associated with low values for instead a gas-prone source.16 Also, these HI, low genetic potential (S1+S2), mostly four samples yielded high [O+S]/C ratios low elemental H/C ratios (4 exceptions that associate them with Type III organic noted below), and high pristane/phytane matter in a Van Krevelen-type diagram (the ratios (upper panel, pl. 4). The latter all four samples are highlighted in fig. 22c). argue for predominantly Type III organic Robertson Research noted that reflected- matter in the “amorphous” interval. To light microscopy revealed “medium” to explain the curiously gas-prone character, “high” presence of solid bitumen in these Robertson Research (1983, p. 8) speculated four samples and concluded that this that the “amorphous” kerogens between material, rather than kerogens, may be the 16,009.3 and 17,143 ft are actually either source of the elevated H/C ratios (Robertson oxidized relicts of original amorphous Research, 1983, p. 8, 190-192; Appendix 5, material or perhaps finely divided vitrinite this report). that was incorrectly classified by Headspace gas wetness ranges up to 95% in microscopy. Tissot and Welte (1984, p. the “amorphous” interval, but most values 158, fig. II.4.16) illustrate examples of poor range between 75% and 85% and heavier correlation between “amorphous” kerogens gases (C5+) form less than 20% of and source type from elemental analysis. In headspace gases (lower panel, pl. 4). either case, based on these data, the Robertson Research (1983, p. 10) indicate “amorphous” interval in the COST well is that these data suggest a wet gas source and

14 A large proportional volume relative to other 15 Ranging from 1.06 to 1.12; samples at 16,029.0 ft, classes of kerogens (exinite, vitrinite, and inertinite) 16,703.7 ft, 16,714.6 ft, and 16,719.6 ft. is required because of the low density of amorphous 16 Oil-prone kerogens at this thermal maturity should kerogen. yield HI>200 (see Baskin, 1997).

a low probability for generation of matter occurs in coal beds or is dispersed as significant quantities of oil. finely divided material in clastic rocks and forms poor to very good sources for gas, Finally, the oil shows logged in and just with minor potential for condensates and above (15,450-15,500 ft bkb) the light oil. Our conclusions about the source “amorphous” interval are actually quite potential for the Tertiary fill in the North sparse and are described as “slight” or Aleutian basin are reflected in our “trace” in the sample (“mud”) logs (lower assessment models for plays 1, 2, and 6 panel, pl. 4). Detailed analyses of extracts (tbls. 3, 4, and 8), which are primarily of these oil shows and correlations to sourced by Tertiary rocks. For these three possible source rocks are described below. plays, we estimate that there is a 10% chance that any pool will be filled completely with oil and an 80% chance that Source Potential of Tertiary Basin Fill and any pool will be filled completely with gas. Assessment Model For the 10% fraction of the overall pools in which free oil is overlain by a gas cap From these data, we conclude that most of (“mixed” case), we estimate that 90% of the the depth intervals in the COST well that pool volume is occupied by gas. Although appear from pyrolysis results to form these model input values are speculative, potential oil sources are actually coal- they reflect our sentiment that the Tertiary bearing intervals that are dominated by Type fill of the North Aleutian basin is most likely III (gas-prone) organic matter. Although a source for gas with some potential for some exceptions are known,17 coal is not minor quantities of petroleum liquids. commonly a source for oil because the typically modest quantities of petroleum liquids that are generated are often Oil and Gas Occurrences and Biomarker sequestered (“sorbed” into extensive internal Correlations pores) within the coal (Levine, 1993, p. 40, 71). Other intervals of interest for oil source Gas was recovered by three flow tests at potential, such as the “amorphous” interval, rates summing to 90 Mcfg/d from 3 zones in appear on the basis of other data to form the Tolstoi Formation in the Becharof Lake potential sources for gas or wet gas, with 1 well. Gas was also recovered in flow tests possible minor quantities of liquids. from two intervals in the Tolstoi Formation at rates of 5 to10 Mcfg/d (with 300-400 We conclude, as did Robertson Research barrels of water per day) in the David River (1983, p. 1-9) and Turner et al. (1988, p. 1/1A well. Oil and gas shows were noted 190-191) from consideration of all elsewhere in wells offshore and in wells on geochemical data, that the Tertiary sequence the Alaska Peninsula (annotated in fig. 2). penetrated by the North Aleutian Shelf COST 1 well contains primarily Type III Gas seeps are observed as gas “chimneys” in organic matter. This gas-prone organic some proprietary seismic profiles on the Black Hills uplift. Onshore, oil and gas seeps are known primarily from the area 17 In the best-known example, Upper Cretaceous and near the east end of Becharof Lake, where Tertiary coals in the Gippsland basin of Australia are credited as the source for liquid petroleum reserves they are observed along the axes of exposed of 3.762 billions of barrels and gas reserves of 7.8 anticlines in Mesozoic rocks or along trillions of cubic feet (Clayton, 1993, p. 187, tbl. 1).

important faults. Gas seep samples are possible contribution from Middle Jurassic composed mostly of carbon dioxide and rocks (Kialagvik Fm.) like those exposed in other non-combustible gases, with minor the same area (Magoon and Anders, 1992). hydrocarbons, as shown in the plot and inset The Upper Triassic rocks exposed at Puale data table of figure 23. These gas seeps are Bay are minimally thermally mature probably the result of magmatic intrusions (TMAX= ~438ºC, or about 0.7% vitrinite that are decarbonating limestones in the reflectance) and form excellent oil-prone subsurface. Reifenstuhl (2005) however source rocks (Wang et al., 1988, figs. 4, 16). reports a gas seep from Oil Creek18 that Where age-equivalent Mesozoic consists of 91% methane, 7% nitrogen, and sedimentary rocks underlie North Aleutian 2% carbon dioxide. Natural gas recovered19 basin and the Black Hills uplift, they might from the Becharof Lake 1 well consists of form sources for oil migrating into overlying 87.5% methane, 4.7% ethane, 2.3% propane, Tertiary-age rocks. The Mesozoic rocks 0.8% butane, 1.0% hydrogen, and 3.7% exposed along the Black Hills uplift, like at “other” gases (AOGCC, 1985, DST data). Puale Bay, are minimally thermally mature This gas is very different from most of the at the surface (TAI=2.5, or about 0.65% nearby seeps which are mostly carbon vitrinite reflectance, Cathedral River 1 well) dioxide (fig. 23). Methane carbon isotope and any oil moving out of them into Tertiary (C13 and C12 isotope ratios) data for cuttings reservoirs would probably be re-migrated headspace gases in the Becharof Lake 1 well from disrupted pools that formed prior to are shown in figure 24a. Above 3,000 feet, Tertiary time. Most exposures of Mesozoic the gas is primarily biogenic in origin; rocks along the Alaska Peninsula south of below 5,500 feet, it is primarily thermogenic the Bruin Bay fault are mapped at a level of in origin. Gases are of mixed origins in the thermal maturity exceeding 0.6% vitrinite intermediate interval (3,000 to 5,500 ft) of reflectance (approximate onset of oil Bear Lake and Stepovak Formations. generation) or greater (Johnsson and Thermally-mature Tertiary strata reach Howell, 1996). thicknesses of 1,127 ft in the area of the Becharof Lake 1 well (fig. 19). The Modest oil and gas shows and gas “wetness” relatively dry thermogenic gas (wetness = values of 30% to 95% (lower panel, pl. 4) 8.2%) recovered in the DST in the Becharof were noted below 15,450 feet bkb (most Lake 1 well (fig. 24b) is probably Tertiary- prominent from 15,700 to 16,740 ft bkb) in sourced. the North Aleutian Shelf COST 1 well. These shows and the high gas wetness Oil seeps emanating from Jurassic rocks values may signal the presence of migrated along the axes of exposed anticlines liquid petroleum. It is therefore important to attracted the earliest exploration drilling to determine the source of these liquid the Alaska Peninsula in the early 1900’s. hydrocarbons. Were they generated by Geochemical studies of these seep oils Type III organic matter like that dominating suggest that they were sourced from Upper the Tertiary rocks penetrated by the COST Triassic rocks (unnamed) like those exposed well? Or, are these minor petroleum liquids at Puale Bay (locale posted in fig. 2), with evidence for unseen oil sources within Mesozoic rocks beneath the North Aleutian basin? 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., To try to identify the source of the liquid near top of oil window).

hydrocarbons below 15,450 ft in the COST from 0.20% to 0.21%. Sulfur well, we conducted extraction and contents for Tertiary-sourced biomarker studies on “show interval” condensates in Cook Inlet range samples borrowed from the State of Alaska from 0.03% to 0.05%, much lower archive in Eagle River, Alaska. than the Mesozoic oils (all data from Hydrocarbons were extracted from two Magoon and Anders, 1992, tbl. composites of show interval samples20 by 13.1). In two extracts of the show Baseline DGSI and analyzed for carbon interval in the North Aleutian Shelf isotopes, metals, and biomarkers (Baseline COST 1 well, sulfur levels were DGSI, 2003; attached as Appendix 3 of this below the detection limit of 0.01% report) for comparison to data for regional (Baseline DGSI, 2003). The low oils and source rocks published by Magoon sulfur contents of the COST well and Anders (1992). The two extractions extracts are consistent with a source obtained in this study supplement a less in nonmarine Tertiary rocks. robust data suite on 7 extractions in the show interval in the North Aleutian Shelf 2. Isoprenoid Ratios Are Terrestrial. COST 1 well previously obtained by Cross-plots for ratios of pristane/n- Robertson Research (1983, App. IX; C17 versus phytane/n-C18, as shown attached as Appendix 2 and Appendix 5 of in figure 25, indicate a terrigenous, this report). Selected extract data are listed oxidizing source environment (i.e., in table 2. Extract data are shown in figures Tertiary rocks) for the COST well 25, 26, 27, 28, and 29, and are selectively extracts, rather than a marine source profiled on depth in plate 4. (i.e., Mesozoic rocks).

We conclude from the extract data that the 3. Pristane/Phytane Ratios are oil shows in the interval from 15,450 to Terrestrial. Pristane/phytane ratios 16,800 feet bkb in the North Aleutian Shelf range from 2.14 to 9.30 for the 9 COST 1 well originated from nonmarine extracts in the show interval in the Tertiary rocks rather than marine Mesozoic North Aleutian Shelf COST 1 well, rocks. This interpretation extends from the as summarized in the histograms in following observations: figure 26. For Tertiary extracts and oils in Cook Inlet basin, 1. Low Sulfur Content Suggests pristane/phytane ratios similarly Tertiary Sources. The sulfur range from 2.5 to 10.0 (Magoon and contents of Mesozoic-sourced oils in Anders, 1992, tbl. 13.1). For the Cook Inlet range from 0.04% to Mesozoic (marine) oils and extracts, 0.23% (average 0.11%) while those pristane/phytane ratios range from the Alaska Peninsula oil seeps narrowly from 2.7 to 4.0; for Alaska (from Middle Jurassic rocks) range Peninsula oil seeps the range is from 1.5 to 1.7 (Magoon and Anders, 20 One sample composite was collected from 1992, tbl. 13.1). The conventional core chips every foot: cores 18 and 19, pristane/phytane ratios of the North 16006-16720 ft bkb overall. A second sample Aleutian Shelf COST 1 well extracts composite was collected from cuttings, 10-ft are ranged in a manner most similar intervals, 15,700-16,800 ft bkb. At the time the interval from 15,700 to 16,800 feet was drilled, the to the range for Tertiary rocks and well was open below 9-5/8 inch casing set at 13,287 oils of Cook Inlet basin. ft bkb (Turner et al., 1988, p. 7).

1.078-1.160). The absence of C30 steranes 4. Carbon Isotopes Correlate to is consistent with terrestrial source (Peters Nonmarine Tertiary. Carbon isotope and Moldowan, 1993, tbl. 3.1.5). Sterane data for saturate and aromatic ratios, plotted in the ternary diagram of fractions of extracts from the oil figure 28b, suggest mixing of marine and show interval in the COST well nonmarine depositional environments in the group decisively with similar data source sequence. Oleananes are generally for nonmarine Tertiary rocks and associated with Late Cretaceous or Tertiary Tertiary-sourced condensates of angiosperms (flowering plants) (Waples and northern Cook Inlet (fig. 27). The Machihara, 1991, p. 54) and are not found in North Aleutian extracts are distinctly older rocks. Unless swept up in the course “heavier” (enriched in C13) than all of migration through Tertiary rocks, their of the Mesozoic (marine) rocks and presence in these extracts seems to preclude oils, including the oil seeps on the origination from Jurassic- or Triassic-aged Alaska Peninsula. sources.

5. Deficit of Saturates Correlates to Magoon and Anders (1992) and Magoon Tertiary Extracts. Ratios among (1994) have noted that extracts from Upper saturates, aromatics, and non- Triassic potential oil source rocks exposed at hydrocarbons for 9 extracts from the Puale Bay (fig. 2) are enriched in C19 to show interval in the North Aleutian C29 tricyclic terpanes relative to extracts Shelf COST 1 well, shown in figure from Middle Jurassic or Tertiary rocks. 28a, are highly deficient in saturates Some oils collected from wells and seeps in relative to Mesozoic rocks and oils. southern Cook Inlet (Magoon and Anders, Although highly variable as a group, 1992, spls. 37-43) are also enriched in the North Aleutian extracts are tricyclics relative to oils in northern Cook mostly saturate-deficient like the Inlet, and Magoon (1994) suggests that the extracts of Tertiary rocks from Cook high tricyclics indicate some contribution Inlet. The North Aleutian cuttings from Upper Triassic oil sources (mixed with sample extract (MMSAK2003-2) the more typical Middle Jurassic Tuxedni forms an exception. It is relatively Gp. oils). In the more general case, Clayton saturate-rich and plots very close to a (1993, tbls. 1, 2) notes that tricyclic terpanes Tertiary-sourced condensate from are rarely abundant in oils derived from coal Cook Inlet in figure 28a. or coaly organic matter. If tricyclic terpanes are present in the COST well In addition, C30 steranes are absent, C29 extracts, it may imply origination from steroids slightly predominate (C29:C28:C27 Upper Triassic rocks beneath North Aleutian = 43.6:22.5:33.0 [MMSAK2003-1] and basin. 47.7:23.4:29.9 [MMSAK2003-2]), oleanane is present (oleonane/hopane= 0.22-0.29), Figure 29a is an excerpt from an M/Z 19122 and the carbon preference index (Bray and 21 22 Evans, CPI24-34) is greater than 1.0 (CPI = 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 21 Baseline DGSI (2003) calculate an “OEP” (odd- sequentially detected through manipulation by the even preference) which ranges from 1.10 to 1.22. magnetic field of the mass spectrometer (Waples and Another index reported by Baseline DGSI, CPIMarzi, Machihara, 1991, p. 11-12). M/Z 191 is most ranges from 1.03 to 1.07 (see Marzi et al., 1993). appropriate for obtaining the quantities of tricyclic

chromatogram for terpanes from an extract the North Aleutian basin north of the from core samples from 16,006 to 16,720 projected trace of the Bruin Bay fault (fig. feet in the North Aleutian Shelf COST 1 32). However, several lines of logic indicate well. Figure 29b shows the entire M/Z 191 that the probability of effective Mesozoic chromatogram for the extract from cuttings sources, particularly Triassic sources, in this over the interval 15,700 to 16,800 ft bkb. area is low. Both chromatograms show that tricyclic terpanes are abundant in the show interval Both published tectonic models for the extracts, although subordinate to hopanes “Peninsular terrane” (Mesozoic strata (tricyclic terpanes/hopanes = 0.56 to 0.80). southeast of the Bruin Bay fault) tie it to the Jurassic-Cretaceous magmatic arc The presence of these tricyclic terpanes in (magmatic arc terrane north of Bruin Bay the COST well extracts could suggest a link fault), but in two different ways. Moore and to Upper Triassic source rocks beneath the Connelly (1979) locate the Mesozoic North Aleutian basin. But, a wide spectrum sedimentary rocks in a fore-arc basin of depositional environments is associated between the magmatic arc on the northwest with suites of tricyclic terpanes. Crude oils and a subduction zone on the southeast. In derived from paralic/deltaic (nearshore an alternative model, Reed et al. (1983) marine), deep water marine, lacustrine, and locate the Mesozoic sedimentary rocks in a “phosphatic” environments all feature robust back-arc basin southeast of both the suites of tricyclics (Zumberge, 1987, tbl. 5). magmatic arc and subduction zone to the Tricyclics have been specifically linked to northwest. In either case, the Mesozoic Mesozoic lacustrine sources (Waples and sedimentary rocks would not be expected to Machihara, 1991, p. 58). A condensate from extend in quantity northwest of the the North Cook Inlet gas field, sourced from magmatic arc and beneath the North Tertiary nonmarine rocks, resembles the Aleutian basin. Both models presumably COST well extracts in that it is rich in C19 include the Triassic rocks, which contain and C20 tricyclic terpanes (Magoon and abundant volcanic material of arc origins Anders, 1992, fig. 13.9, spl. 18), the latter (Wang et al., 1988). linked to vascular land plants (Zumberge, 1987, p. 1630). Figure 29b shows a strong These tectonic models are disputed by unidentified peak between the C19 and C20 geologic mapping that locates some Triassic tricyclic terpanes; a similar unidentified sedimentary rocks in the magmatic arc peak is also present in the North Cook Inlet terrane north of the Bruin Bay fault and field condensate (and reportedly other “Peninsular terrane.” Carbonates of the northern Cook Inlet condensates) sourced Upper Triassic Kamishak Formation are from Tertiary nonmarine rocks (Magoon and exposed at a few localities among the vast Anders, 1992, fig. 13.9, spl. 18; p. 264, Jurassic-Cretaceous plutons north of the 268). Bruin Bay fault in the Cook Inlet area (Magoon et al., 1976, sh. 2) and near These tricyclic terpanes might point to the Becharof Lake (Riehle et al., 1993). existence of effective source rocks within the Mesozoic substrate beneath the part of However, even if the Upper Triassic rocks extend northwest of the Bruin Bay fault into

and pentacyclic terpanes because it is the most the magmatic arc terrane, there is some abundant ion obtained by fragmentation of these question about their survival as effective compounds in an electron beam.

potential source rocks. Independent COST 1 well23 is shown in figure 30 along evidence points to a dominantly magmatic with some timelines for critical events in the character for the Mesozoic substrate north of hypothetical petroleum system for the the Bruin Bay fault beneath the Bristol Bay offshore part of the North Aleutian basin. lowlands and North Aleutian basin. We Vitrinite reflectance data from the COST consider it unlikely that significant well indicate that the lower part of the rock quantities of effective Triassic oil source column has experienced sufficient thermal rocks survive among the numerous exposure24 to have generated oil and gas. magmatic intrusions inferred from regional But, these data give no information about context and magnetic data in the Mesozoic when petroleum generation might have substrate north of the projected Bruin Bay occurred. The Lopatin burial model fault (Case et al., 1988). Geologic mapping combines burial history with thermal northwest of Cook Inlet indicates that bodies environment to measure thermal exposure of Upper Triassic rocks are small, scattered, using established thermo-chemical and isolated amid very large intrusives of principles. The purpose of creating a Jurassic, Cretaceous, and Tertiary ages Lopatin model for the COST well was to (Magoon et al., 1976, sh. 2; Riehle et al., obtain estimates for the times of onset and 1993). The Upper Triassic and Jurassic duration of key phases of petroleum sedimentary rocks among the intrusives are generation. The time of petroleum thermally overmature at the surface, ranging generation can then be compared to the time from 1.3% vitrinite reflectance (end of oil of trap formation to ascertain whether traps generation) to >5.0% (metamorphic) at all were available to capture petroleum mapped data sites (Johnsson and Howell, migrating upward from generation centers. 1996). Presumably, this thermal maturation For example, if petroleum generation was achieved in Mesozoic time in concert occurred prior to trap formation, the with pluton emplacement, before the petroleum may have simply escaped to the formation of the North Aleutian basin. surface and been lost.

Lastly, a host of other geochemical data, The Lopatin burial model in figure 30 reviewed above, seems to link the extracts to highlights the thermal evolution of the Type III organic matter of Late Cretaceous sequence penetrated by the well and an or Tertiary age. Regional geology and additional 3,000 feet of unknown strata geochemical data, taken as a whole, most interpreted (from seismic data) to lie beneath persuasively argue for a source within the bottom of the COST well. These latter Tertiary nonmarine rocks for the sparse rocks comprise the most deeply buried strata petroleum liquids encountered in the deep in the basin and presumably offer the part of the COST well. earliest opportunity for generation of petroleum.

Petroleum System—Critical Events Tolstoi Formation strata that are probably correlative to the unknown sequence A “Lopatin”-style (Lopatin, 1971) burial history model for the North Aleutian Shelf 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 later phase of basin subsidence was the lower Tolstoi Formation consists of mostly unaccompanied by faulting, with nonmarine and shallow marine sandstones some reactivation of horst-bounding faults. and conglomerates with subordinate This phase of subsidence was more siltstone, shale, and coal (Detterman et al., regionally extensive than the rift phase and 1996, p. 38-42). These rocks are much the may have been both thermally-driven same as the part of the Tolstoi Formation (cooling following the rift phase) and load- that was penetrated by the COST well (fig. driven (as a foredeep bending downward to 9). The latter rocks are dominated by coaly, the south beneath tectonically-thickened Type III organic matter and are most crust on the south margin of the basin [Bond probably sources for gas and wet gas. et al., 1988]).

Geological mapping (Wilson et al., 1995; In figure 30, the rocks at the bottom of the Detterman et al., 1996) documents a North Aleutian Shelf COST 1 well are widespread unconformity at the base of the shown to enter the early oil generation zone Tolstoi Formation where it rests upon (TTI>3) at about 31.7 Ma. The base of the Cretaceous rocks in the Port Moller area. well entered the peak oil generation zone The Tolstoi Formation rocks that overlie this (TTI>10) at 27.0 Ma. regional unconformity range in possible age from middle Eocene to late Paleocene The thermal maturation of the basin floor (Detterman et al., 1996, p. 39-42). The strata beneath the bottom of the COST well offshore COST well reached total depth represents the earliest opportunity for within lower to middle Eocene rocks (fig. generation of petroleum in the North 9). From stratigraphic relations onshore, we Aleutian basin. This deeper package of infer that the untested strata beneath the strata would have entered the early oil bottom of the COST well overlie Mesozoic generation window (TTI>3) as early as 38.5 rocks on a Late Paleocene unconformity. Ma and the peak oil generation zone This unconformity probably marks the onset (TTI>10) at 34.4 Ma. Oil and gas of subsidence of the North Aleutian basin generation from shallower strata with and forms the starting point for the Lopatin appropriate organic compositions has burial model. We model the untested strata presumably taken place with progressive beneath the COST well as Tolstoi- burial since 38.5 Ma, continuing to the equivalent rocks that range up to 61 Ma in present time. age (base of Late Paleocene). The erosionally–truncated crests of the Initial basin subsidence was rift-driven and basement horsts were buried beneath the was accompanied by large-scale faulting and thick shaly sequence of the lower part of the the elevation of horsts in the southwest half Stepovak Formation (lower contact, seismic of the North Aleutian basin. The rift-driven horizon “D”) at approximately 35.4 Ma, phase of basin subsidence was concluded by thereby sealing the deeper traps on horst the time of seismic horizon “D” (35.4 Ma), flanks. The underlying strata that onlap the which corresponds to the regional faulted flanks of the horsts were deposited unconformity that decapitates the basement between 61 Ma and 35.4 Ma, mostly before horsts in the southwest half of the North the earliest onset of hypothetical oil Aleutian basin (fig. 6). generation from basin floor strata at 38.5

Ma. Traps associated with faults and associated traps were certainly in place to stratigraphic onlap on the flanks of these capture migrating petroleum. Given basement horsts were mostly available to appropriate organic compositions within the capture petroleum generated in flanking lower part of the North Aleutian basin fill, basin deeps after 38.5 Ma. the timing of hypothetical petroleum generation is mostly appropriate for Deposition of the principal reservoir—the charging of the Bear Lake-Stepovak Bear Lake-Stepovak play sequence—began reservoirs in the 28.5-4.5 Ma drape about 28.5 Ma and continued up to about 4.5 anticlines over horsts. Ma. The compaction-driven doming of drape anticlines over basement horsts The “amorphous” interval in the COST well continued through the time interval of Bear (discussed above26), of past interest because Lake-Stepovak deposition, as indicated by of the presence of putative amorphous (i.e., the thickening of strata into the grabens oil prone) kerogens, oil shows, and elevated flanking horsts (illustrated in fig. 6 and pl. gas wetness (pl. 4), corresponds 1). approximately to the interval from 15,620 ft bkb (top of fault gap in fig. 30) to total Oil and gas generated between 28.5 and 38.5 depth. The top of the “amorphous” interval Ma preceded the formation of the drape entered the early oil generation window anticlines in the Bear Lake-Stepovak (TTI>3) at 26.4 Ma and entered the peak oil sequence over basement horsts. Some early- generation zone (TTI>10) at 20.4 Ma. Any formed generation products may have hydrocarbons generated out of the preceded drape anticline formation and “amorphous” interval therefore could have escaped to the surface unless sequestered in charged some of the shallow drape anticlines older traps along horst flanks. But, the early involving the Bear Lake-Stepovak play fraction of the total generated product may sequence reservoirs over basement horsts. have been relatively small. Sometime between 21.2 Ma (vitrinite reflectance The timing of hypothetical petroleum data25) and 27.0 Ma (Lopatin model), basin- generation is favorable for preservation of floor strata reached peak oil generation porosity in the principal reservoir, the Bear (Ro=1.00%; TTI=75), corresponding to the Lake-Stepovak play sequence. As noted, stage when petroleum is most abundantly hydrocarbon generation could have begun at created (Dow, 1977a, fig. 3; Baskin, 1997, the basin floor sometime between 38.5 Ma tbl. 1). At this time, the lower part of the and 34.4 Ma, and ostensibly reached peak Bear Lake-Stepovak sequence and oil generation (Ro=1.00%; TTI=75) between 21.2 and 27.0 Ma (fig. 30). The 25 In figure 30 a dashed black line for the Ro=1.00% hypothetical oil and gas forming near the isograd has been added and is shown intersecting the basin floor therefore could have invaded the basin floor at 21.2 Ma. This isograd is not a product Bear Lake-Stepovak sandstones shortly after of the model but was constructed parallel to model- based TTI isograds and hand-sketched back through deposition. Early entry of hydrocarbons into time from the actual well penetration of the 1.00% Ro the pore systems of the Bear Lake-Stepovak 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 26 The review of source rock geochemical data in this (Ro=1.00%). The Lopatin model forecasts for report discounts the “amorphous” interval as a thermal maturity below 15,000 ft bkb in the COST potential oil source. It is viewed as a potential well do not conform with vitrinite reflectance data source for gas or wet gas, but is no more promising and are not considered reliable. than other sequences penetrated by the COST well.

sandstones within traps could have arrested Generally, the Lopatin maturity values at a the diagenetic processes that act to destroy given depth are higher than the observed porosity. We note that the Bear Lake- vitrinite-reflectance-based maturity values. Stepovak sandstones in the COST well were For example, the observed vitrinite not associated with any oil or gas shows, but reflectance at modeled well total depth nonetheless preserve excellent porosity and (17,802 ft bkb, 647 ft added for fault gap28) permeability (figs. 15 and 16). is 1.097% (fig. 17) and the appropriate corresponding TTI value is 98 (Waples, In contrast, the older Tolstoi play sequence 1980, tbl. 4). At the same depth, the Lopatin resided at significant burial depths for up to model for the COST well overestimates a 22.5 m.y. (61 Ma minus 38.5 Ma=22.5) TTI value of 576 (equivalent to 1.80% Ro; before any petroleum could have been Waples, 1980, tbl. 4). generated out of basin-floor strata. This protracted opportunity for diagenetic Generally, the model-to-data discrepancies destruction of pore space27 may partly (between the Lopatin model forecasts for explain the overall poor reservoir quality of thermal maturities and vitrinite-reflectance- the Tolstoi sandstones below 10,380 ft bkb based thermal maturities) in the COST well in the COST well. increase with depth. The Lopatin isograd TTI=75 is forecast to lie at 15,141 feet bkb. The TTI isograd depths forecast by the The isograd TTI=75 normally corresponds Lopatin model conform reasonably well to to a vitrinite reflectance of 1.00% or peak- vitrinite reflectance-based isograd depths in oil generation (Waples, 1980, tbl. 4), but the the part of the COST well above 13,000 ft observed vitrinite reflectance at 15,141 ft in bkb. Specifically, vitrinite reflectance data the COST well is only 0.768%. A vitrinite indicate that isograd Ro=0.5% (threshold for reflectance of 1.00% is not achieved until a early oil generation) is reached at 10,372 ft depth of 17,160 ft, or 2,019 ft deeper than bkb. The Lopatin model forecasts the the Lopatin model forecast (for TTI=75). equivalent TTI=3 isograd to lie 223 ft Likewise, the oil-generation-floor isograd shallower, at 10,213 ft bkb. Vitrinite TTI=180, forecast at 16,479 ft bkb by the reflectance data indicate that isograd Lopatin model, is 2,772 ft shallower than the Ro=0.6% (threshold for peak oil generation) equivalent vitrinite reflectance isograd is reached at 12,397 ft bkb. The Lopatin (Ro=1.35%) forecast (below the data set) at model forecasts the equivalent TTI=10 19,251 ft bkb. The large discrepancies isograd to lie 337 ft shallower, at 12,060 ft between the depths of Lopatin isograds and bkb. The depths of these isograds are vitrinite reflectance isograds are illustrated compared in the right-hand columns of in the right-hand columns of figure 30. figure 30. The model-to-data discrepancies below The isograd depths forecast by the Lopatin 15,000 ft bkb are too large and result in model do not conform to vitrinite erroneously high (early) Lopatin-model reflectance-based isograd depths in the part estimates for the onset ages of peak oil of the COST well below 15,000 ft bkb. generation (TTI=75), the oil generation floor

27Mostly by pore-filling chemical cements, and, 28 The base of the well for modeling purposes is replacement of volcanic clasts by clays leading to “corrected” or extended down to 17,802 ft bkb to collapse of clasts, as observed in petrographic account for the 647 ft gap at the normal fault microscopy (AGAT, 1983, p.2). penetrated at 15,620 ft bkb.

(TTI=180), peak wet gas generation As the second variation on our Lopatin (TTI=92), and the floor for survival of model, we used the basic stratigraphic liquids (TTI=900). The onset ages forecast model of figure 30 but reduced the by this high-TTI part of the Lopatin model geothermal gradient for the entire well to are only useful as maximum ages.29 14.0ºF/1,000 ft, held constant through time. As shown in plate 4 and figure 30, the In an effort to construct a Lopatin model that COST well temperature data describe a better conforms to observational data, we three-leg set of gradients ranging from experimented with two variations on the 16.7ºF to 18.3ºF per 1,000 ft. The basic model shown and tabulated in figure substitution of a lower geothermal gradient 30. For the first variation, we retained the of 14.0ºF/1,000 ft produced better model-to- geothermal model (modern gradients) but data conformance for TTI values of 75 and added time gaps at regional unconformities. higher, but substantially decreased the For the second variation, we retained the model-to-data conformance for the critical stratigraphic model (without time gaps) but oil-generation-onset TTI isograds less than reduced the geothermal gradient. 75. This second variation on the Lopatin model was also discarded. As the first variation to our Lopatin model, we inserted arbitrary time gaps at the The results of the second variation on our regional unconformities marked by seismic Lopatin model suggest that a better fit might horizons A, B, C, and D (3 m.y., 3 m.y., 3 be achieved by assuming a low geothermal m.y., and 5 m.y., respectively). These time gradient for the deeper (and older) part of gaps are arbitrary because the paleontologic the well and a high geothermal gradient (like data do not resolve any quantifiable time that observed) in the shallow part of the gaps at these surfaces in the COST well (fig. well. This would retain the good model-to- 9), nor do we observe erosional truncation data conformance in the shallow part of the effects at these surfaces in the graben area well and move TTI isograds to greater near the well. The addition of these time depths (and better conformance to data) in gaps (hiatuses) to the basic stratigraphic the deep parts of the well. In fact, some model produced the general effect of experimentation revealed that an early (pre- moving TTI isograds to even shallower seismic horizon “D”) geothermal gradient of depths. Therefore, adding time gaps to the 10ºF/1,000 ft could produce reasonably stratigraphic model increased the good model-to-data conformance in the deep discrepancies between Lopatin model part of the well. However, this (10ºF/1,000 forecasts and vitrinite reflectance data from ft) is an extremely low geothermal the well. This first variation on the Lopatin gradient.30 Even more troubling, this two- model degraded model-to-data conformance part geothermal model implies that the early and was discarded. history of the North Aleutian basin was characterized by a relatively low geothermal gradient that was later replaced by the 29 The principal product generated in the high-TTI higher gradients observed today. This is the part of the Lopatin burial model is gas. Actual gas- opposite of what we might expect generation thresholds were probably achieved much more recently than the times indicated by the Lopatin burial model in figure 30. Because gas is more likely 30 Cook Inlet basin, a relatively “cold” forearc basin, to breach trap seals with time, a late (i.e., very has geothermal gradients ranging from 12ºF to 16ºF recent) gas-charge charge history is probably helpful per 1,000 ft depending on proximity to the modern to overall trap success. volcanic arc (Magoon, 1986, fig. 20, p.45).

35 considering the early rift history of the COST well. And here, amid the most North Aleutian basin. Rifting is usually important prospects in the North Aleutian accompanied by elevated geothermal basin, the Lopatin model indicates that, gradients (Dewey and Bird, 1970; Falvey, given appropriate organic compositions, 1974; McKenzie, 1978; White and hydrocarbon generation deep in the basin McKenzie, 1988; Bond and Kominz, 1988), could have preceded and accompanied the above the “world average” of 13.7ºF/1,000 formation of key reservoirs and traps,. ft (25ºC/km) and ranging up to 42ºF/1,000 Vitrinite reflectance data and Lopatin ft (77ºC/km or higher) (Lee and Uyeda, modeling both indicate that about 10,500 ft 1965; Tissot and Welte, 1984, p. 296). At of strata in the lower part of the North the conclusion of rifting, the crust cools and Aleutian basin are within or have passed subsides, producing a shift to a lower through the oil generation window geothermal gradient. To invoke an (Ro=0.5% to 1.35%). Significant quantities uncommonly low geothermal gradient of gas may also have been generated out of during a rift event, followed by warming and the coaly, Type III organic matter as the host a higher geothermal gradient, contradicts strata passed through the thermal maturity generally-accepted tectonic-thermal models window for oil generation (Boreham and for rift basins. Powell, 1993, p. 149-150). Vitrinite reflectance data indicate that over 5,100 ft of In the end, we were unable to devise a strata have passed into the wet gas Lopatin model for the COST well that uses generation window for mixed kerogens available geothermal and stratigraphic data, (Ro>0.8%). Vitrinite reflectance data that produces a good fit at all depths to the indicate that over 3,300 ft of strata in the observational data, and that is rational in the lower part of the basin have passed into the tectonic context of the well. thermal maturity window for generation of dry gas from coaly/Type III organic matter Despite the flaws in the high-TTI Lopatin (Ro>1.07%). Clearly, a large volume of model forecasts, the model did produce low- rocks have experienced thermal exposures TTI forecasts that are vindicated by vitrinite sufficient for significant petroleum reflectance data in the shallower parts of the generation in the lower part of the basin. COST well. Therefore, we believe that the The Lopatin model shows that the most Lopatin model of figure 30 provides useful attractive reservoirs and traps existed and insights into the timing of the earliest phases were available to capture oil and gas at the of thermal maturation and potential time of most prolific oil and gas generation. hydrocarbon generation in the area of the

Petroleum System Elements and Oil and Gas Plays in North Aleutian Basin OCS Planning Area

Key Elements of Petroleum System deep grabens may also fill Tolstoi reservoir sandstones in traps ringing the faulted flanks The major elements of the petroleum of basement uplifts. systems hypothesized for the North Aleutian Basin OCS Planning Area are illustrated in a The hypothetical petroleum system schematic cross section in figure 31a. For responsible for a minority fraction of the main part of the North Aleutian basin, undiscovered oil resources in the Planning traps are hypothesized to be charged by gas, Area is illustrated on the left side of figure condensate, and oil originating from deeply 31a. Mesozoic rocks beneath the Black buried, gas-prone source rocks of Tertiary Hills uplift reached thermal maturity age. For the southwest part of the Planning sufficient for oil generation prior to Eocene Area, which is underlain by possibly oil- time and may contain oil pools that formed prone Mesozoic rocks, traps in Mesozoic in Mesozoic (probably Cretaceous?) time. sandstones are hypothesized to be charged Cenozoic-age faulting may have disrupted by original oil migration from Mesozoic oil some of these oil pools and provided source rocks. Traps in Tertiary sandstones avenues for re-migration into traps in overlying oil-prone Mesozoic rocks are overlying Oligocene-Miocene reservoir hypothesized to be charged by re-migration sandstones of the Bear Lake-Stepovak play of oil out of disrupted Mesozoic reservoirs. sequence. Traps in Tertiary reservoirs on the Black Hills uplift may also be charged The hypothetical petroleum system by gas and condensate migrating out of responsible for the majority of potential deeply buried Tertiary strata in North undiscovered oil and gas resources in the Aleutian basin. However, this would Planning Area is illustrated on the right side requires 50+ miles of lateral migration of figure 31a. Sandstone reservoirs (Bear through the highly faulted southwest part of Lake-Stepovak play sequence) within the the North Aleutian basin, with great risk of domes draped over basement uplifts are diversion of migrating petroleum up faults charged by petroleum generated in Tertiary and loss to surface seeps. rocks (Tolstoi play sequence) deeply buried in grabens flanking the uplifts. A regional shale seal (lower part of Stepovak Fm.; fig. Play Definition 10 and pl. 3) floors the Bear Lake-Stepovak reservoir sequence and is pierced by horst- Plays were separated first on the basis of bounding faults that extend upward into the reservoir characteristics, for which the shallow level of the basin fill above seismic stratigraphic sequence serves as proxy. horizon “D”. These faults may provide the Further separations were made on the basis critical pathways for petroleum migration of structural setting and hydrocarbon charge between the deep oil and gas generation models (source type [oil vs. gas] and access centers (“GAS/COND KITCHEN” in fig. [length and integrity of migration path]). 31a) flanking basement uplifts and the shallow traps that overlie the uplifts. Gas The Bear Lake-Stepovak sequence was and oil migrating out of Tertiary rocks in the defined so as to capture the main reservoir

37 package between seismic horizons “A” and Play Descriptions, North Aleutian Basin, “C” (fig. 9 and pl. 2), which is characterized Alaska by abundant, thick, porous, and permeable sandstones. The Bear Lake-Stepovak sequence is draped over basement uplifts in Play 1: Bear Lake-Stepovak (Oligocene- the southwest part of the North Aleutian Miocene) basin and forms the key exploration play in the basin. The Bear Lake-Stepovak play Play Area: 14,820 square miles Play Water Depth Range: 15-300 feet sequence can be traced to the Black Hills Play Depth Range: 2,000-10,000 feet uplift, where it is also draped over basement Reservoir Thermal Maturity: 0.25%-0.48% vitrinite uplifts. But the Black Hills uplift is treated reflectance as a separate play because it has access to Risked, Mean, Undiscovered, Technically hypothetical oil-prone sources in the Recoverable Resources: 271 Mmb (oil) + 136 Mmb (gas-condensate) = 406 underlying Mesozoic assemblage. The Mmb liquids (rounding sums to 406) Black Hills uplift has limited access (large 5.473 Tcf (gas) + 0.113 Tcf (solution gas) = 5.586 distances across highly faulted areas) to the Tcf gas deeply buried gas-prone Tertiary age Pool Rank 1 Mean Conditional Resource: 827 sources that are hypothesized to charge the Mmboe (4.65 Tcfge) main Bear Lake-Stepovak play. The Tolstoi Play Exploration Chance: 0.1872 play sequence hosts poor-quality reservoir Play 1, the “Bear Lake-Stepovak” play, is sandstones (thin and impermeable) and is the dominant play in the North Aleutian involved in flank traps against basement Basin OCS Planning Area, with 61% (1,400 uplifts. The Tolstoi sequence is thus set Mmboe) of the Planning Area energy apart into a third play. endowment (2,287 Mmboe). Oil and gas-

condensate liquids form 29% of the A fourth play identifies low-pressure hydrocarbon energy endowment of play 1. biogenic gas resources in shallow Plio-

Pleistocene strata of glacial and marine The Bear Lake-Stepovak play sequence origins. corresponds in the North Aleutian Shelf

COST 1 well to the lower part of the Milky The substrate of Mesozoic rocks beneath the River Formation, all of the Bear Lake North Aleutian basin in divided into a Formation, and the upper (sandy) part of the southern province of deformed sedimentary Stepovak Formation. The play sequence rocks (play 5) and a northern province of ranges in age from late Oligocene through volcano-plutonic rocks (play 6). The early Pliocene (fig. 9 and pl. 2). In onshore Mesozoic deformed sedimentary rocks on areas, rocks correlative to play 1 were the south include rocks correlative to penetrated by 9 wells (David River 1/1A, regional oil sources and are primarily an oil Hoodoo Lake 1, Hoodoo Lake 2, Sandy play. The volcano-plutonic Mesozoic River 1, Port Heiden 1, Ugashik 1, Becharof assemblage on the north forms the cores of Lake 1, Great Basins 1, and Great Basins 2 basement uplifts and if properly fractured, wells). Offshore, in eastern St. George might form a reservoir for hydrocarbons. basin, correlative rocks were penetrated by The schematic structural cross section in the St. George Basin COST 2, Monkshood figure 31b illustrates the organization of the 1, and Bertha 1 wells. The principal point of six plays and associated trap types. The 6 offshore control is the North Aleutian Shelf plays are described in detail below. COST 1 stratigraphic information test well

that was drilled by an industry consortium in interval from 15,300 to 16,800 feet 1983. The area of play 1 is shown in figure (corresponds to 0.78% to 1.04% Ro) in the 32. North Aleutian Shelf COST 1 well. Carbon isotopes on extracts from the show interval No pools of oil or gas were encountered in correlate to extracts and oils from Tertiary- any wells penetrating the Bear Lake- age rocks in northern Cook Inlet as opposed Stepovak sequence in the North Aleutian to extracts and oils from known Mesozoic- basin. Minor gas shows are associated with age oil source rocks on the Alaska Peninsula coals in the Bear Lake-Stepovak sequence in and beneath Cook Inlet (fig. 27). These data the North Aleutian Shelf COST 1 well and suggest that Mesozoic oil source beds do not in most wells onshore. In the Becharof Lake underlie North Aleutian basin in the area of 1 well, cuttings headspace gas carbon play 1. This interpretation is supported by isotopes (AOGCC, 1985) for the Bear Lake magnetic intensity data (fig. 7) that suggest and Stepovak Formations range from -19.5 that play 1 is underlain by a substrate of to -65.4 (δ13C [PDB]), indicating mixed Mesozoic volcano-plutonic rocks. The thermogenic and biogenic gas (fig. 24). No hypothesized petroleum system for play 1 shows of oil were noted within the Bear assumes that gas and minor liquids migrate Lake-Stepovak play sequence in the North out of Tertiary rocks in the deep parts of Aleutian Shelf COST 1 well. Oil shows North Aleutian basin and rise along faults were noted in the play sequence in the bounding basement uplifts to charge shallow Becharof Lake 1, Sandy River 1, and David reservoir beds draped over uplifts. River 1/1A wells. Flow tests in the Bear Lake-Stepovak sequence in the Sandy River Three major risk factors for play 1 relate to: 1 well recovered gas-cut drilling mud and 1) seal (reservoir sequence is very sand-rich formation waters. and is not capped by a regional seal); 2) source adequacy (no attractive source Most of the oil and gas resources of play 1 formation in known Tertiary-age rocks; are associated with Oligocene- to Miocene- Mesozoic rocks beneath play 1 are age sandstones in simple domes draped over pervasively invaded by plutons and cannot basement uplifts, as illustrated schematically form a source for petroleum); and 3) in figure 31b (and in the seismic panel in fig. petroleum migration to reservoirs (a 6 and pl. 1). Mapped domes range up to major seal sequence—bentonitic shales of 93,000 acres in closure areas. Thick the lower Stepovak Formation—floors the (maximum = 277 ft), highly porous reservoir reservoir sequence and is only sparsely sandstones sum to 3,305 feet in the North pierced by faults). Aleutian Shelf COST 1 well—comprising 61 percent of the 5,390 ft-thick Bear Lake- Stepovak play sequence (figs. 11-16). No oil source formation has been identified in Play 2: Tolstoi (Eocene-Oligocene) the North Aleutian basin but coals and shales with Type III (coal-like) organic Play Area: 10,890 square miles matter are abundant and could form sources Play Water Depth Range: 15-300 feet Play Depth Range: 4,000-20,000 feet for both biogenic and thermogenic gas, Reservoir Thermal Maturity: 0.3%-1.65% vitrinite condensate, and perhaps minor oil (fig. 21). reflectance For this reason, play 1 is modeled as gas- Risked, Mean, Undiscovered, Technically prone. Oil shows were encountered in the Recoverable Resources: 62 Mmb (oil) + 61 Mmb (gas-condensate) =

123 Mmb liquids Formation coals in the North Aleutian Shelf 2.476 Tcf (gas) + 0.025 Tcf (solution gas) = COST 1 well as well as in the 5 Tolstoi 2.501 Tcf gas Pool Rank 1 Mean Conditional Resource: 208 penetrations onshore. Oil shows were noted Mmboe (1.17 Tcfge) in the Tolstoi Formation in the North Play Exploration Chance: 0.1404 Aleutian Shelf COST 1, Becharof Lake 1, Hoodoo Lake 2, and David River 1/1A Play 2, the “Tolstoi” play, is the second wells). most important play in the North Aleutian Basin OCS Planning Area, with 25% (568 Most of the oil and gas resources of play 2 Mmboe) of the Planning Area energy are associated with simple anticlines draped endowment (2,287 Mmboe). Oil and gas- over basement uplifts, or, in truncation traps condensate liquids form 22 percent of the (against faults and unconformities) on the hydrocarbon energy endowment of play 2. flanks of basement uplifts, as illustrated in figure 31. Mapped traps range up to 53,000 The Tolstoi play sequence corresponds in acres in closure area. The upper part of the the North Aleutian Shelf COST 1 well to the Tolstoi play sequence (lower part of lower part of the Stepovak Formation and Stepovak Formation) passes over the crests the entire Tolstoi Formation. The play of basement uplifts. In the North Aleutian sequence ranges in age from early Eocene to Shelf COST 1 well, the upper part of the early Oligocene (fig. 9 and pl. 2). In Tolstoi play sequence contains porous and onshore areas, rocks correlative to play 2 permeable sandstones that are sparse (236 were penetrated by 5 wells (Becharof Lake feet net, or 10% of interval) and thin 1, Great Basins 1, Great Basins 2, Hoodoo (maximum = 43 feet) (figs. 11-16). A Lake 2, and David River 1/1A wells). regional shale seal in the lower part of the Offshore, in eastern St. George Basin, Stepovak Formation is prominent within the correlative rocks were penetrated by the St. upper part of the Tolstoi play sequence (fig. George Basin COST 2 well. The North 9 and pl. 2). The lower part of the Tolstoi Aleutian Shelf COST 1 well is the most play sequence is involved in fault- and important point of control for the Tolstoi stratigraphic-truncation traps on the flanks play sequence in the North Aleutian basin. of basement uplifts. Sandstones are The area of play 2 is shown in figure 33. abundant in the lower Tolstoi play sequence (1,910 feet net, 30% of sequence) in the Gas is pooled in several Tolstoi Formation North Aleutian Shelf COST 1 well, but are intervals in the Becharof Lake 1 well, where thin-bedded (maximum = 57 feet) and flow tests of separate intervals recovered gas impermeable (diagenesis of volcanic at rates ranging from 10 to 50 mcfg/d, or a particles has resulted in collapse of total of 90 mcfg/d for all three zones. In the framework grains; 84% of core samples Becharof Lake 1 well, cuttings headspace have <10 md permeability) (figs. 11-16). gas carbon isotopes (AOGCC, 1985) for the No oil source rock formation has been Tolstoi Formation range from -32.8 to -43.9 identified in the North Aleutian basin but (δ13C [PDB]), indicating thermogenic gas coals and shales with Type III (coal-like) (fig. 24). Gas was recovered in flow tests organic matter are abundant and could form from two intervals in the Tolstoi Formation sources for both biogenic and thermogenic at rates of 5 to 10 Mcfgpd (with 300-400 gas, condensate, and minor oil (fig. 21). For bwpd) in the David River 1/1A well. Gas this reason, play 2 is modeled as gas-prone. shows were associated with Tolstoi 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 Play 3, the “Black Hills Uplift-Amak Basin” Shelf COST 1 well. Carbon isotopes on play, is a subordinate play in the North extracts from the show interval correlate to Aleutian Basin OCS Planning Area, with extracts and oils from Tertiary-age rocks in 9% (210 Mmboe) of the Planning Area northern Cook Inlet as opposed to extracts energy endowment (2,287 Mmboe). Oil and and oils from Mesozoic-age source rocks on gas-condensate liquids form 74% of the the Alaska Peninsula and beneath Cook Inlet energy endowment of play 3. (fig. 27). These data suggest that Mesozoic oil source beds do not underlie North The Black Hills uplift is a regional arch that Aleutian basin in the area of play 2. The extends west from the Alaska Peninsula to hypothetical petroleum system for play 2 join the shelf-edge uplift that forms the west assumes that gas and minor liquids boundary of St. George basin. The Black migrating out of Tertiary rocks in the deep Hills uplift is onlapped by the Tertiary-age parts of North Aleutian basin rise along sedimentary fill of both the North Aleutian faults bounding basement uplifts to charge and Amak basins, but only rocks correlative shallow reservoir beds draped over uplifts or to the Bear Lake-Stepovak sequence of play truncated on uplift flanks. 1 crest the top of the uplift. Over the crest, the Bear Lake-Stepovak-equivalent The major risk factors for play 2 relate to: 1) sequence (fig. 9 and pl. 1) ranges up to reservoir (thin sandstones are porous in the 5,000 feet thick and directly overlies upper Tolstoi play sequence but are moderately deformed Mesozoic sedimentary impermeable in the lower Tolstoi play rocks. Rocks of the lower part of the sequence); and 2) source adequacy (no Stepovak Formation and the Tolstoi attractive source formation in known Formation are truncated at faults and Tertiary-age rocks; Mesozoic rocks beneath unconformities on the north and south flanks play 2 are pervasively invaded by plutons of the uplift. No wells have penetrated the and cannot form a source for petroleum). Tolstoi-equivalent strata in the Amak basin south of the Black Hills uplift. In onshore areas, rocks correlative to the Bear Lake- Stepovak play sequence were penetrated by Play 3: Black Hills Uplift-Amak Basin 9 wells (David River 1/1A, Hoodoo Lake 1, (Eocene-Miocene) Hoodoo Lake 2, Sandy River 1, Port Heiden 1, Ugashik 1, Becharof Lake 1, Great Basins Play Area: 6,990 square miles 1, and Great Basins 2 wells). Offshore, Play Water Depth Range: 15-700 feet correlative rocks were penetrated at the Play Depth Range: 2,000-20,000 feet (mostly 2,000- 5,000 feet) North Aleutian Shelf COST 1 well (North Reservoir Thermal Maturity: 0.23%-2.00% (mostly Aleutian basin) and at the St. George Basin 0.23%-0.31%) vitrinite reflectance COST 2, Monkshood 1, and Bertha 1 wells Risked, Mean, Undiscovered, Technically (St. George basin). The closest point of Recoverable Resources: offshore control is the Bertha 1 well, located 149 Mmb (oil) + 6 Mmb (gas-condensate) = 155 Mmb liquids on the crest of the Black Hills uplift. The 0.249 Tcf (gas) + 0.063 Tcf (solution gas) = Bear Lake-Stepovak-equivalent sequence at 0.312 Tcf gas the Bertha 1 well is mostly marine and non- Pool Rank 1 Mean Conditional Resource: 378 coal-bearing, and is a more distal facies than Mmboe (2.12 Tcfge) the correlative coal-bearing (nonmarine to Play Exploration Chance: 0.105

inner neritic; fig. 9 and pl. 2) sequences thermogenic gas, condensate, and minor oil. penetrated onshore and at the North Aleutian In the southwest part of the North Aleutian Shelf COST 1 well. The area of play 3 is basin, thousands of feet of Tertiary rocks are shown in figure 34. thermally mature and could generate oil and gas, given appropriate organic compositions No pools of oil or gas have been discovered (fig. 19). However, the Amak basin fill in the Bear Lake-Stepovak play sequence or reaches a maximum thickness of only correlative rocks of plays 1 and 3. Gas 12,500 feet. The depth to the 0.6% vitrinite shows are widely associated with coals in reflectance isograd at the North Aleutian the Bear Lake and Stepovak Formations and Shelf COST 1 well is 12,312 feet subsea oil shows have been noted in these (figs. 9 and 17). If the depth for this isograd formations in 3 wells onshore (Becharof at the COST well is extrapolated to Amak Lake 1, Sandy River 1, and David River basin, only about 200 feet of rocks at the 1/1A wells). Flow tests recovered gas from floor of the Amak basin are forecast to be the Tolstoi Formation in the Becharof Lake thermally mature and capable of generating 1 well and oil shows were noted in 4 Tolstoi petroleum (figs. 18 and 19). It is therefore penetrations (North Aleutian Shelf COST 1, unlikely that Amak basin forms a source for Becharof Lake 1, Hoodoo Lake 2, and significant quantities of petroleum. In any David River 1/1A wells). No oil or gas case, gas and condensate generated in the shows are associated with the Bear Lake- deep parts of either Amak or North Aleutian Stepovak sequence in the Bertha 1 well, basins must migrate laterally tens of miles located on the Black Hills uplift near the through areas highly dissected by very west boundary of play 3. young strike-slip faults (that follow the margins of the Black Hills uplift). Because Most of the oil and gas resources of play 3 of the risks of losses through long-distance are associated with broad, low-amplitude lateral migration and diversion at faults, it is anticlines draped over culminations on the unlikely that significant quantities of gas and Black Hills uplift, as illustrated in figure 31. condensate generated in the Amak or North Mapped traps have closure areas ranging up Aleutian basins would reach traps on the to 133,000 acres. Thick (maximum = 220 Black Hills uplift. feet), highly porous, and plentiful (sum to 1,706 feet net, or 59% of sequence) The Black Hills uplift is underlain by an reservoir sandstones are present in the Bear assemblage of folded Mesozoic sedimentary Lake-Stepovak-equivalent sequence in the rocks that include strata age-equivalent to Bertha 1 well. No regional seal caps the known regional oil source beds of Middle abundant sandstones in the Bear Lake- Jurassic (Kialagvik Fm. or Tuxedni Gp.) and Stepovak-equivalent sequence at the Bertha Late Triassic (Kamishak Fm.) ages. The 1 well. Middle Jurassic Tuxedni Group is the source for 1.6 billion barrels of original oil reserves No oil source rocks have been identified in in northern Cook Inlet (AKDO&G, 2002), the Tertiary sedimentary fill of either the most of which is pooled in Tertiary-age North Aleutian or Amak basins. In the rocks that overlie the Tuxedni Group. The North Aleutian basin (and presumably the Tuxedni-correlative sequence—the Amak basin), coals and shales with Type III Kialagvik Formation—is present in the (coal-like) organic matter are abundant and Cathedral River 1 well onshore and could form sources for both biogenic and equivocal geochemical anomalies may

42 suggest a past role as an oil source (fig. 20). Play 4: Milky River Biogenic Gas (Plio- In the Cathedral River 1 well, oil shows Pleistocene) were widely observed in the rocks overlying the Kialagvik Formation. The Kialagvik Play Area: 50,710 square miles Formation is thermally overmature (TAI = Play Water Depth Range: 15-700 feet Play Depth Range: 500-3,000 feet 3.0 to 3.8) and post oil-generative in the Reservoir Thermal Maturity: 0.20%-0.26% vitrinite Cathedral River 1 well (fig. 20). It is reflectance probable that Mesozoic oil sources in this Risked, Mean, Undiscovered, Technically area generated and expelled the oil in a past Recoverable Resources: (pre-Tertiary) cycle of deep burial, long Biogenic gas in negligible recoverable quantities before the deposition of the Tertiary-age Play Exploration Chance: 0.000 rocks flanking or overlapping the Black Play 4, the “Milky River Biogenic Gas” Hills arch. Oil-charging of the Tertiary-age play, is the most extensive yet least rocks in play 3 must therefore rely upon prospective play in the North Aleutian Basin capturing oil remobilized out of Mesozoic OCS Planning Area. Play 4 probably reservoirs where it was sequestered perhaps contains sizable in-place quantities of 30 million years earlier during Mesozoic biogenic gas simply because of the vast area (Late Cretaceous?) burial and oil generation. embraced by the play. However, very little The hypothetical Mesozoic oil pools within of this gas is likely to be recoverable by the Black Hills uplift must first survive conventional means, and the technically uplift, deep erosion, and re-burial beneath recoverable resource endowment is assessed Oligocene and younger strata. The as negligible. Mesozoic oil pools must remain intact during creation of the drape anticlines in The Milky River play sequence corresponds Tertiary rocks over culminations on the in the North Aleutian Shelf COST 1 well to Black Hills uplift. Once the drape anticlines the upper part of the Milky River Formation had formed, fault disruption of the Mesozoic and overlying, unnamed Quaternary pools must then trigger the release of the oil deposits. The play sequence ranges in age sequestered in Mesozoic reservoirs. The from early Pliocene to Holocene (fig. 9 and released oil then migrates upward in some pl. 2). In onshore areas, rocks correlative to (necessarily) focused or non-dispersive play 4 were penetrated by 9 wells (David pattern en route to Tertiary-age reservoir River 1/1A, Hoodoo Lake 1, Hoodoo Lake sandstones in the drape anticlines. The 2, Sandy River 1, Port Heiden 1, Ugashik 1, charge model for play 3 prospects is Becharof Lake 1, Great Basins 1, and Great dependent upon a long chain of critical Basins 2 wells). Offshore, in eastern St. events and therefore seems likely to fail. George basin, correlative rocks were

penetrated by the St. George Basin COST 2, Two major risk factors for play 3 relate to: Monkshood 1, and Bertha 1 wells. The 1) migration (must re-migrate oil from principal point of offshore control is the underlying disrupted Mesozoic pools or gas North Aleutian Shelf COST 1 well that was from distant generation centers in North drilled by an industry consortium in 1983. Aleutian or Amak basins, crossing numerous The area of play 4 is shown in figure 35. young faults); and 2) seal (the reservoir sequence over the crest of the Black Hills No pools of oil or gas were encountered in uplift is very sand-rich and is not capped by any wells penetrating the Milky River play a regional seal). sequence in the North Aleutian basin.

Minor biogenic gas shows are associated We note that most Cook Inlet gas fields are with the Milky River sequence in the North largely of biogenic origin with basin-wide Aleutian Shelf COST 1 well (Robertson original recoverable gas reserves of 8.6 Tcf Research, 1983, p. 1), several wells onshore, (AKDO&G, 2002). Cook Inlet clearly and in the Bertha 1 well in the St. George offers a successful example of a commercial basin. In the Becharof Lake 1 well, cuttings biogenic gas province. However, the Cook headspace gas carbon isotopes (AOGCC, Inlet gas fields occur in fold structures 1985) for the Milky River Formation range (often overlying oil fields) that gathered the from -67.9 to -80.2 (δ13C [PDB]), clearly gas from surrounding extensive areas of gas indicating gas of largely biogenic origin (fig. biogenesis. Cook Inlet gas field reference 24). Biogenic gas is primarily a product of depths range from 1,935 feet to 10,000 feet bacterial fermentation of the organic matter (average, 5,790 feet) and are normally- buried within sediments (Hunt, 1979, p. pressured to over-pressured (AOGCC, 154). 2001). The Cook Inlet gas field sandstone reservoirs (Miocene and Pliocene) are In offshore areas, biogenic gas may be overlain by compacted shales that form pooled in features emplaced by large alpine competent seals. The Cook Inlet gas fields, glaciers that invaded Bristol Bay from the though filled with biogenic gas, do not south (Alaska Peninsula) and northeast provide a useful analog for play 4. Because (Alaska Range) during the Pleistocene of similarities in trap type, burial depths, and epoch and then retreated during the last reservoir and seal lithologies, the Cook Inlet 10,000 years. The legacy of glaciation may biogenic gas fields are most analogous to the include drumlins, eskers, and recessional drape-anticline prospects of North Aleutian moraines. These elevated landforms are basin plays 1 and 2, which range in depth gravelly, porous features that were later from 2,500 to 10,000 ft. However, the drowned in rising sea waters and are now latter are expected to be charged with mostly draped and perhaps sealed by thermogenic gas and condensate. unconsolidated pelagic mud. Such features might pool biogenic gas, at least in southern Areas of significant risk to play 4 include: 1) parts of North Aleutian basin. Thick shelfal gas recoverability (low reservoir pressure sandstone sequences of Pliocene age, and high formation water production); 2) presumably representing large-scale current- poor seal (poor integrity of the molded bedforms, also form candidates for unconsolidated pelagic mud that may seal stratigraphic traps for biogenic gas, as glacial features); 3) reservoir (poor illustrated in figure 31. Pools of biogenic reservoir continuity); and 4) charge (lack of gas in play 4 would be characterized by very aquifer structure that would concentrate and low pressure (no more than 1,300 psi) and convey biogenic gas to stratigraphic traps). would not yield significant fractions of the Play 4 is assessed to have an exploration in-place gas to conventional development chance of zero and negligible undiscovered wells. The biogenic gas may occur in low technically recoverable oil and gas saturations or be dissolved in formation resources. 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).

Play 5: Mesozoic Deformed Sedimentary COST 1 well did not penetrate Mesozoic Rocks (Triassic-Cretaceous) rocks (fig. 9 and pl. 2). The principal point of well information for the Mesozoic rocks Play Area: 5,040 square miles of play 5 is the Cathedral River 1 well atop Play Water Depth Range: 15-700 feet the onshore extension of the Black Hills Play Depth Range: 2,000-15,000 feet Reservoir Thermal Maturity: 0.60%-1.30% vitrinite uplift. The Cathedral River 1 well reflectance penetrated a relatively complete Mesozoic Risked, Mean, Undiscovered, Technically sequence 13,911 feet thick and ranging in Recoverable Resources: age from Late Triassic (Kamishak Fm.) to 38 Mmb (oil) + 0 Mmb (gas-condensate) = 38 Late Jurassic (Naknek Fm.) (fig. 20). The Mmb liquids 0.000 Tcf (gas) + 0.017 Tcf (solution gas) = area of play 5 is shown in figure 36. 0.017 Tcf gas Pool Rank 1 Mean Conditional Resource: 63 Mmboe No significant pools of oil or gas were Play Exploration Chance: 0.09216 encountered in any of the wells testing Mesozoic rocks on the Alaska Peninsula or Play 5, the “Mesozoic Deformed in St. George basin. The Humble Bear Sedimentary Rocks” play, contributes a Creek 1 well near Becharof Lake (fig. 2) mere 1.8% (41 Mmboe) of the energy recovered 450 Mcf/d of gas and large endowment (2,287 Mmboe) of the North amounts (5,800 feet in drill pipe) of salt Aleutian Basin OCS Planning Area. Oil water (AOGCC, 1959) from a 120-foot forms 93% of the energy endowment of play interval of the uppermost part of the 5. Talkeetna Formation (Detterman, 1990). Elsewhere, several wells encountered sparse Folded and thrust-faulted Mesozoic oil and gas shows in Mesozoic rocks sedimentary rocks are widely exposed on the correlative to the play 5 sequence. Oil south side of the Alaska Peninsula (figs. 5, shows generally consist of white to yellow 8). Exploration drilling on the Alaska sample fluorescence and weak to streaming Peninsula began in 1903 with drilling on oil white, blue, or yellow cut fluorescence from seeps along the axes of anticlines near the isolated pores or fractures in impermeable east end of Becharof Lake (fig. 5). Oil seep sandstones and siltstones. In the Cathedral drilling continued through 1940 and River 1 well, oil shows were encountered as ultimately 10 wells were drilled (tbl. 1). shallow as 390 feet and were commonly Five modern (1961-1981) wells (Canoe Bay observed down to 7,500 feet. At 7,500 feet, 1, Big River 1, Koniag 1, Painter Creek 1, a petroleum-based mud additive (Soltex©) and Wide Bay 1) also tested exposed fold was introduced to the drilling mud, casting structures along the south flank of the suspicion on the authenticity of the Alaska Peninsula (Molenaar, 1996b, tbl. 1). widespread hydrocarbon shows observed at On the north flank of the Alaska Peninsula greater depths. Flow tests in the Shelikof and along the southern edge of North and Kialagvik Formations (Middle Jurassic) Aleutian basin, Mesozoic sedimentary rocks and the Talkeetna Formation (Lower were penetrated by 3 wells (Cathedral River Jurassic) in the Cathedral River 1 well 1, David River 1/1A, and Hoodoo Lake 2 recovered gassy drilling mud with traces of wells). To the west, five wells in St. George oil. In northern Cook Inlet, some oil basin (St. George COST 2, Rat 1, Segula 1, production (<300,000 barrels) has occurred Tustamena 1 [Y-0530], and Tustamena 2 from fractured Talkeetna Formation beneath [Y-0527] wells) reached total depth in the principal accumulation (in Tertiary Jurassic rocks. The North Aleutian Shelf

45 rocks) in the McArthur River field available seismic data. The surface (AOGCC, 2001, p. 171). anticlines outlined by geologic mapping near Becharof Lake range from 7,000 to Across the eastern Alaska Peninsula and 147,000 acres in gross map area and the western Alaska Range, the Bruin Bay fault ranges of sizes of these anticlines were used forms the contact between a Mesozoic to model hypothetical prospect areas in play volcano-plutonic arc terrane on the north 5. Potential reservoir formations in play 5 and a Mesozoic sedimentary basin on the include the Lower Jurassic Talkeetna south. The Bruin Bay fault is extrapolated Formation, the Upper Jurassic Naknek offshore beneath the North Aleutian basin as Formation, the Lower Cretaceous the boundary between a northern area of Staniukovich and Herendeen Formations, high-frequency, high-amplitude magnetic and the Upper Cretaceous Chignik and/or anomalies and a southern area of low- Hoodoo Formations (stratigraphic column in frequency, low-amplitude magnetic fig. 8). In outcrop and well penetrations, anomalies (fig. 7). We speculate that the most of these sandstones and conglomerates magnetic anomaly field north of the are highly zeolitized and preserve negligible projected Bruin Bay fault corresponds to the porosity (Franks and Hite, 1980). The volcano-plutonic arc terrane exposed north Staniukovich and Naknek Formations of the Bruin Bay fault onshore. These rocks generally have the smallest fractions of were penetrated beneath Tertiary strata in volcaniclastic detritus (Burk, 1965, fig. 10), three wells (Great Basins 1, Great Basins 2, and, as the younger (or shallower) reservoir and Becharof Lake 1 wells) in the northeast formations in the Mesozoic assemblage, part of North Aleutian basin. The magnetic have a burial history that is less severe than anomaly field south of the projected Bruin that of Middle Jurassic and older units. Bay fault represents an offshore extension of the deformed Mesozoic sedimentary rocks The principal resource in play 5 is predicted of the Alaska Peninsula, as demonstrated by to be oil with no accumulations of free gas. penetrations of Mesozoic rocks at several Play 5 was modeled as an oil play because it wells to the west in St. George basin and at is assumed to be charged by Middle Jurassic the Cathedral River 1, David River 1/1A, oil sources like those that charged the and Hoodoo Lake 2 wells on the Alaska undersaturated (relative to gas) oil fields of Peninsula. The area of play 5 corresponds northern Cook Inlet. Play 5 includes strata to the area of the low-frequency, low- that are age-equivalent to known regional oil amplitude magnetic field south of the source beds of Middle Jurassic (Kialagvik offshore extension of the Bruin Bay fault, Fm. or Tuxedni Gp.) and Late Triassic and underlies the Amak basin and the Black (Kamishak Fm.) ages. The Middle Jurassic Hills uplift (fig. 7). Tuxedni Group is the source for 1.6 billion barrels of original oil reserves in northern Most of the oil and gas resources of play 5 Cook Inlet (AKDO&G, 2002), most of are associated with hypothetical pools of oil which are pooled in Tertiary-age rocks that captured in anticlines or fault traps like overlie the Tuxedni Group. The Tuxedni- those exposed on the Alaska Peninsula, as correlative sequence on the Alaska illustrated in figure 31. We have not Peninsula—the Kialagvik Formation—is mapped such structures within the Mesozoic present in the Cathedral River 1 well complex offshore, but fold, thrust-fault, and onshore. Geochemical anomalies associated wrench-fault structures are observed in with the Kialagvik Formation in the

Cathedral River 1 well may suggest a past Play 6: Mesozoic Buried Granitic Hills role as an oil source (fig. 20). In the (Jurassic-Cretaceous Magmatic Rocks) Cathedral River 1 well, oil shows were widely observed in the rocks overlying the Play Area: 46,810 square miles Kialagvik Formation, which is thermally Play Water Depth Range: 15-400 feet Play Depth Range: 6,000-12,000 feet overmature (TAI = 3.0 to 3.8) and post oil- Reservoir Thermal Maturity: 0.34%-0.60% vitrinite generative (fig. 20). It is probable that reflectance (projected from burial depth but Mesozoic oil sources in this area generated irrelevant because reservoirs are fractured and expelled the oil in a past (pre-Tertiary) plutonic and volcanic rocks) cycle of deep burial and thermal Risked, Mean, Undiscovered, Technically Recoverable Resources: transformation of organic matter. The 26 Mmb (oil) + 5 Mmb (gas-condensate) = 30 existence of viable oil accumulations in play Mmb liquids (rounding sums to 31) 5 requires that the generation of oil out of 0.195 Tcf (gas) + 0.010 Tcf (solution gas) = these source rocks predate zeolitization of 0.206 Tcf gas (rounding sums to 0.205) pore systems in Mesozoic sandstone Pool Rank 1 Mean Conditional Resource: 148 Mmboe (0.83 Tcfge) reservoirs. Unfortunately, the general case Play Exploration Chance: 0.04095 appears to be that oil generation and migration followed reservoir zeolitization. Play 6, the “Mesozoic Buried Granitic Hill” Oil, though commonly observed in play, is a subordinate play in the North Mesozoic rocks in wells and outcrops, is Aleutian Basin OCS Planning Area, with only observed in trace quantities in fractures 3% (67 Mmboe) of the Planning Area or in isolated pores that survived energy endowment (2,287 Mmboe). Oil and zeolitization. gas-condensate liquids form 45% of the hydrocarbon energy endowment of play 6. Four major risk factors for play 5 relate to: 1) reservoir (early zeolitization and porosity The rocks comprising the Mesozoic Buried destruction in chemically reactive Granitic Hill play correspond to the volcaniclastic sandstones); 2) timing (oil Mesozoic plutonic complex exposed in the generation and migration must occur early Alaska Range to the northeast of the North [Late Jurassic or Early Cretaceous] to Aleutian basin. The latter rocks are the protect reservoir pore systems, but traps roots of a volcanic arc system of Jurassic probably did not form until Late Cretaceous and Cretaceous age. The volcanic arc or early Cenozoic time); 3) trap integrity system is long-lived and remains active (breaching of traps at Miocene and older today as the chain of large, active volcanoes Cenozoic unconformities or trap disruption along the backbone of the Alaska Peninsula. by faults may have destroyed Mesozoic The area of play 6 is shown in figure 37. petroleum accumulations); and 4) preservation (exhumation to shallow burial Jurassic and Cretaceous plutonic rocks are depths and invasion of meteoric waters may overlain unconformably by Tertiary strata in have promoted biological degradation of oil wells in the northeastern parts of the North in Mesozoic-age accumulations to asphaltic Aleutian basin. This plutonic complex was materials). 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 well penetrations of Mesozoic rocks at by Detterman (1990), although Brockway et several wells to the west in St. George basin al. (1975) included these rocks with the and at the Cathedral River 1, David River overlying Eocene-Oligocene Meshik 1/1A, and Hoodoo Lake 2 wells on the volcanics. Radiometric dating of some of Alaska Peninsula. The area of play 6 these plutonic rocks by the K-Ar method corresponds to the area of the high- (Geochron, 1969; original reported dates-- frequency, high-amplitude magnetic not recalculated using modern constants; anomaly field north of the offshore Brockway et al., 1975) has yielded ages of extension of the Bruin Bay fault. This 96.3 Ma (Great Basins 2 well), 120 Ma, and magnetic anomaly field is interpreted to 177 Ma (Great Basins 1 well), or, ranging mark a substrate of Mesozoic volcano- from mid-Cretaceous to Middle Jurassic in plutonic rocks that underlies the northern equivalent stratigraphic age. ninety-two percent of the North Aleutian Basin OCS Planning Area. No pools of oil or gas were encountered in any of the well penetrations of the Mesozoic The Mesozoic basement rocks penetrated at magmatic arc complex. A gas seep at “Gas the Great Basins 1 well are described from Rocks” along the southwest shore of cores as polymictic conglomerates31 passing Becharof Lake (located in fig. 23 [spl. 149]) is located along the projected trace of the 31 The stratigraphic assignment of these Bruin Bay fault. This gas seep consists conglomerates in the Great Basins 1 well has been mostly of carbon dioxide and nitrogen. used to make a case for association with the very different terranes that lie north and south of the On the eastern Alaska Peninsula and western Bruin Bay fault. Hite (2004, p. 17) has argued that the assignment of these conglomerates to the Naknek Alaska Range, the Bruin Bay fault forms the Formation (after Detterman, 1990) indicates that the contact between a Mesozoic volcano- well penetrated the Mesozoic sedimentary (Chignik) plutonic arc terrane on the north and a terrane south of the Bruin Bay fault. (Regional Mesozoic sedimentary basin on the south. mapping published by Magoon et al [1976] confines The Bruin Bay fault is extrapolated offshore the Upper Jurassic Naknek Formation to the terrane south of the Bruin Bay fault.) However, the Hite as the boundary between a northern area of interpretation also requires that the Bruin Bay fault high-frequency, high-amplitude magnetic curve abruptly westward from the southwest shore of anomalies and a southern area of low- Becharof Lake so as to pass north of the Great frequency, low-amplitude magnetic Basins 1 well. We note that views differ on the anomalies (fig. 7). We speculate that the correct assignment for the conglomerates in the depth interval 10,516-10,850 ft md in the Great magnetic anomaly field north of the Basins 1 well. Brockway et al. (1975) assigned these projected Bruin Bay fault corresponds to the conglomerates to the Oligocene Stepovak Formation volcano-plutonic arc terrane exposed north and as such they would have no bearing on the of the Bruin Bay fault onshore. These rocks interpretation of position relative to the terranes were penetrated beneath Tertiary strata in separated by the Bruin Bay fault. The conglomerates at the Great Basins 1 well pass downward into three wells (Great Basins 1, Great Basins 2, granitic gneiss and lamprophyre that, in our view, and Becharof Lake 1 wells) in the northeast are most sensibly associated with the volcano- part of North Aleutian basin. The magnetic plutonic arc (Iliamna) terrane north of the Bruin Bay anomaly field south of the projected Bruin fault. Shales interbedded with the conglomerates are Bay fault represents an offshore extension of described as “baked” (AOGCC, 1959b, p. 11) and the deeper granitic rocks have been K-Ar dated at the deformed Mesozoic sedimentary rocks 120 and 177 Ma (Early Cretaceous and earliest of the Alaska Peninsula, as demonstrated by Middle Jurassic, respectively; Geochron, 1969; Brockway et al., 1975). Contact metamorphism of 48 downward into granitic gneiss (with large beneath a regional shale within the lower orthoclase porphyroblasts) and lamprophyre part of the Stepovak Formation. We (rich in dark minerals and transitional to hypothesize that gas and oil arising from gabbros). The Great Basins 2 well Type III and coaly source rocks of Tertiary penetrated diorite and granite, brecciated age in deep areas of the North Aleutian and seamed with calcite veins. The basin that surround the basement uplifts Mesozoic rocks penetrated at the Becharof migrated up the bounding faults and invaded Lake 1 well are described as metamorphic the fractured and weathered granites at the green schist, meta-gabbro, and meta-diorite, crest of the basement uplifts. highly fractured and veined by feldspar and quartz. Features similar to the North Aleutian basin buried hills form important exploration All of the undiscovered potential oil and gas targets in the Bohai (North China) basin resources of play 6 are associated with (Guangming and Quanheng, 1982) and hypothetical pools lodged in fractured offshore Vietnam (Areshev et al., 1992). “granitic”32 rocks that core basement uplifts Buried hills form an important play concept of Tertiary age, as illustrated in figure 31. for exploration of the Mesozoic assemblage These granite-cored uplifts were repeatedly in ultra-deep waters of the U.S. Gulf of exposed to weathering and erosion through Mexico (Post et al., 2001). In the productive early Tertiary (perhaps also Late analog from Vietnam, the granitic rocks Cretaceous) time. We hypothesize that range in age from 97 to 178 Ma (mid- fractures in the granites provided avenues Cretaceous to Middle Jurassic) and feature for deep invasion by meteoric waters during bulk porosity values ranging from up to times of surface exposure. The meteoric 25.0%. Effective porosity averages between waters may have enlarged fractures through 2.5% and 3.8% and is roughly distributed in dissolution and created a bulk porosity that halves as “fracture porosity” and as was later occupied by petroleum (following “caverns” or “microcaverns”, the latter the deep reburial). In addition to an abundance legacy of dissolution of fracture surfaces by of fractures, fractures must be lengthy and both hydrothermal and meteoric fluids. sufficiently diverse in orientations and depth Vietnam’s largest field (Bach Ho) is lodged of penetration in the granitic body to in a fractured granitic reservoir and produces establish effective connectivity across pool approximately 280,000 bbl/day (Brown, areas of thousands of acres. The granite- 2005, p. 8). Paul Post (pers. comm., August cored basement uplifts were eventually (in 2003) of the Minerals Management Service Late Eocene time, approx. 40 Ma) sealed has compiled data on the buried hill oil and gas fields of China and Vietnam. Pool shales interbedded with the conglomerates by Middle volumes can exceed 1 billion barrels of oil Jurassic intrusives suggests to us that the and 2 trillions of cubic feet of gas. conglomerates might more logically be assigned to Productive columns can range up to 3,300 the Lower Jurassic Talkeetna Formation, which is widely mapped and commonly intruded by plutons in feet (P’An, 1982, tbl. 1; O&GJ, 2003). the volcano-plutonic arc (Iliamna) terrane north of Initial production rates can exceed 18,000 the Bruin Bay fault (Magoon et al., 1976). We barrels of oil per day. Oil recovery factors conclude that the conglomerates and magmatic rocks can range up to 900 bbl/acre-foot (F50 = penetrated below 10,516 ft md in the Great Basins 1 158 bbl/acre-foot). The variability in these well probably represent the volcano-plutonic terrane north of the Bruin Bay fault. fractured reservoirs is such that the upper 32 Here referring to any felsic pluton or massive felsic parts of the reservoir can be sparsely volcanic flow.

49 fractured while better fracture systems exist enhanced by weathering, and of sufficient deeper in the buried hill. Many hydrocarbon vertical and horizontal lengths and diversity accumulations in Vietnam and China (and of orientation to achieve connectivity across elsewhere) may have been missed because an area of tens of thousands of acres); 2) exploration wells stopped drilling as soon as adequate source (no attractive source granitic rocks were encountered in the belief formation in known Tertiary-age rocks); and that it was economic basement and no 3) migration (hydrocarbons generated in hydrocarbons could be housed there (Sladen, deep basin areas surrounding basement 1997). The data compiled and analyzed by uplifts must first migrate vertically up Paul Post for analog features in China and bounding faults to reach the horsts, but then Vietnam formed the basis for the pay must encounter sealing levels on the same thickness and oil and gas yields used in the faults that act to divert hydrocarbons into the play 6 resource model (prospect areas are crests of uplifts; there is some risk that these based on MMS seismic mapping). faults will instead allow the hydrocarbons to escape upwards into overlying Tertiary Three major risk factors for play 6 relate to: sedimentary rocks). 1) reservoir (requires extensive fractures,

GEOLOGIC ASSESSMENT MODEL

The creation of the geologic model used in was the basis for construction of probability the computer simulation for the distributions for the aerial sizes of prospects undiscovered oil and gas resources of the and probability distributions for the numbers North Aleutian Basin OCS Planning Area of prospects. These are the most influential drew data from MMS seismic mapping, variables within the geologic model used to exploratory wells, producing fields in compute the undiscovered oil and gas analogous reservoirs in the northern Cook potential and it is important that they are Inlet basin, and published literature. grounded in direct information. Tabulations of the geologic input data used to assess the 6 plays identified in the North Mapped prospects were grouped by play and Aleutian Basin OCS Planning Area are the prospect areas (maximum closure within given in tables 3, 4, 5, 6, 7, and 8. spill point) were tabulated and entered into the BESTFIT module within @RISK for approximation by a log-normal probability Prospect Areas and Volumes distribution. The closure areas of mapped prospects in the North Aleutian Basin OCS This oil and gas assessment relies upon the Planning Area range from 2,600 to 133,000 seismic mapping conducted prior to 1988 by acres. Independent probability distributions the Alaska (Region) office of the Minerals for prospect areas were created for each Management Service. This mapping play. These are the distributions reported as identified 74 prospects in the North Aleutian “Prospect Area (acres)-Model Input” in Basin OCS Planning Area. This mapping tables 3 through 8.

requiring migration from distant generation The prospect area distribution was then areas, trap fill fractions were reduced in aggregated (in @RISK) with a probability recognition of the risks of high losses and distribution for fill fraction (described diversions (up faults to surface seeps) below) to obtain the probability distribution incurred by long-distance migration. for pool area. The @RISK aggregation reports back an “as-sampled” prospect area Given access to some significant source of distribution, which is reported as the hydrocarbons for the play, attention was “Prospect Area (acres)-Model Output” in then turned to trap size, trap amplitude, trap tables 3 through 8. type, and seal integrity. Trap size is an issue where limited hydrocarbons are available to The pool area distribution reported from the fill high-volume traps. Trap amplitude @RISK aggregation was then aggregated becomes a factor when the vertical relief is with a probability distribution for pay very large, so large that differential thickness (described below) in order to pressures across seals33 at the crests could calculate a probability distribution for pool rupture the seals and allow the hydrocarbons volume (in acre-feet) in the POOLS module to escape. Trap integrity is also a function within GRASP. The pool volume of trap type. A trap sealed by one or more distribution and the pool numbers faults is probably at more risk for leakage distribution (described below) were then than a simple anticline sealed by a single, aggregated to calculate the volumes (acre- continuous shale formation. Seal integrity is feet) of discrete hypothetical pools in the generally controlled by lithology and PSRK module. The PSUM module thickness. Even high-amplitude prospects completed the analysis by charging the could reasonably be allowed to be discrete hypothetical pools with a specified completely filled if sealed by thick, well- mix of petroleum fluids and then calculating consolidated, clay-rich shales. Shales that resources for the individual pools and the can be shown to be geopressured also offer play as a whole. greater seal integrity and more complete filling of traps might be anticipated where The construction of probability distributions such geopressured shales form the seals. for trap fill fractions relied upon subjective analysis of each of the key elements controlling trap fill. We first considered the Prospect Numbers charge potential for the play, that is, the extent to which hydrocarbons were made As noted above, MMS seismic mapping available to fill traps within the play. In identified a total of 74 prospects34 in the plays understood to have easy access to abundant hydrocarbons migrating from areas 33created by contrasts between hydrostatic of prolific oil and gas generation, trap fill pressures in rocks saturated by relatively high- fractions were permitted to rise to a density water and excess pressures (“buoyant maximum of 1.0 (100%). Generally, these pressures”) developed in columns of relatively low- density hydrocarbons are plays with prospects amidst a hydrocarbon generation center. In plays 34 In plays 1, 2, 3, and 6. No prospects are mapped perceived to have limited access to in play 5. There, the minimum (F99) number of prospects (and areas) were estimated from the migrating hydrocarbons were modeled with density and sizes of surface anticlines exposed on the prospects incompletely filled. For plays Alaska Peninsula from Becharof Lake to Chignik Bay.

North Aleutian Basin OCS Planning Area. (sparse seismic data, or rudimentary Some prospects represent closures at seismic-stratigraphic analysis), or different depth levels (separate play predominantly small prospects, like play 2, sequences) on a single structure, so the total very large numbers of prospects might number of identified discrete prospective reasonably be expected to remain structures in the Planning Area is somewhat unidentified. less than 74. We constructed prospect numbers In assessment work, we generally concede probability distributions for each play using that large numbers of prospects could a graphical approach. Our practice was to remain unidentified, some even in the most first post the number of mapped prospects at thoroughly mapped areas. “Unidentified” F99 (99% probability of equaling or prospects exist for a variety of reasons. exceeding the associated value) on log- Some prospects remain unidentified because probability graph paper. To the number of some areas lack seismic data. Some smaller mapped prospects we add our estimate for prospects may have been missed because the number of unidentified prospects; this they fall within spaces in the seismic grid. sum is then posted at the extreme right (at Other prospects may be missed because of ~F00) on the same log-probability plot. A lack of detail in stratigraphic analysis. line connecting these two data points then Lastly, many prospects may remain defines the probability distribution for unidentified because they are subtle or prospect numbers for a particular play. impossible to detect in seismic data. It is generally acknowledged that unidentified We estimated that as many as 285 prospects exist in all basins and plays, that hypothetical prospects might remain some fraction of the unidentified prospects unidentified in the 5 assessed exploration probably contain petroleum, and that some plays (play 4 was not quantitatively of the unidentified prospects will ultimately assessed). When added to the 74 mapped be tested and discovered to contain pooled prospects (and the 11 prospects at minimum oil or gas, perhaps in commercial quantities. inferred for play 5), we have a maximum Therefore, unidentified prospects must be estimated endowment of 370 prospects. given account in the assessment of When aggregated with the play risk models undiscovered oil and gas potential. in the MPRO module of GRASP, we obtained a maximum endowment of 119 For the exploration plays identified in the hypothetical pools35 that contributed to the North Aleutian Basin OCS Planning Area overall undiscovered oil and gas potential of we supplemented the numbers of known the North Aleutian Basin OCS Planning prospects with some estimate of the numbers Area. of prospects that might remain unidentified. The estimation process focused on the completeness of seismic information and the Pay Thickness Model level of geological complexity. In thoroughly-mapped plays with simple Cook Inlet oil fields (data reported by geology and large structures, like play 1, AOGCC, 2001) were used as an analog for relatively few prospects are expected to remain unidentified. Conversely, in plays 35 with complex geology, deficient analysis sum 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 data forms shown in table 3 through table thickness for the prospects in North Aleutian 13. There has been little or no exploratory basin. The North Aleutian Shelf COST 1 drilling and very little data are directly well encountered abundant thick sandstones available for most of these input parameters. (aggregate exceeding 3,000 feet) in the Bear However, in many cases, one can forecast Lake-Stepovak play (1) sequence. Given the extreme ranges for any particular input the thin and discontinuous shale seals within parameter using regional well data or data and above the Bear Lake-Stepovak from analogous basins. For example, in the sequence, and, the unknown charge capacity calculation of gas recovery factors, the for basin petroleum sources, it seems reservoir temperature is an important unlikely that all sandstones in this sequence variable that is controlled by burial depth would form “pay” across any given and geothermal gradient. The latter prospect. The nonmarine to inner neritic information is available from seismic sandstones of the Bear Lake-Stepovak mapping (depths) and well data (geothermal sequence are broadly analogous to the gradient), or thermal models from analogous nonmarine to inner neritic (estuarine) basins. Our approach to constructing a Tertiary basin fill of Cook Inlet basin (Kenai probability distribution for reservoir Gp., Beluga Fm., and Sterling Fm.) as temperature is to estimate the temperature described by Hite (1976) and Hayes et al. extremes – the temperatures of the (1976). Pay thickness data for the oil and shallowest (coolest) and deepest (hottest) gas fields of northern Cook Inlet are prospects in the play. Then, we post the presented in figure 38. The statistical fit to minimum temperature at the 99.99 these data was used to model pay thickness (effectively 100.0) percent probability and for analogous plays (1 and 3) in the North the maximum temperature at the Aleutian Basin OCS Planning Area. Figure 0.01 (effectively 0) percent probability in a 11 shows that there is clearly adequate “normal” (Gaussian) probability plot. (One sandstone in this sequence to accommodate might also use a log-normal probability plot the most generous pay thickness model— to conduct this exercise. We assumed a certainly the modest pay thickness model normal distribution for play reservoir developed from Cook Inlet oil and gas fields temperature.) A straight line drawn in figure 38. (We note that the amplitudes connecting the two points (invoking a of mapped prospects in the North Aleutian normal distribution) then defines a basin range from 46 to 584 feet [mean = 227 probability distribution for reservoir feet], adequate at maximum amplitudes to temperature for the play. An example plot is accommodate the full pay column [456 feet] shown in figure 39. Newendorp (1975, modeled in figure 38.) Pay thicknesses for p. 383) termed such constructions “force-fit” play 2 were reduced to reflect the observed distributions. Many input probability (in core data) poor reservoir qualities in the distributions in the geologic computer sandstones of the Tolstoi play sequence. models for plays in this assessment were created using this method.

Construction of Probability Distributions With Limited Data

The input parameters required by the computer models for plays are listed in the

Computation of Oil and Gas Recovery Pool Reservoir (BO) Factors = 7758.38 Bbl/acre-ft (a·(1-b)·c·d)

The GRASP computer model requires Gas Recovery Factor: entries for recoverable petroleum per unit a. Porosity (decimal fraction) volume of petroleum-saturated reservoir. b. Water Saturation (decimal fraction) The data forms in table 3 through table 13 c. Reservoir Pressure (pounds per in2) list these entries as “Oil Recovery Factor” d. Gas FVF (as 1/Z [Z = Gas (barrels of oil recoverable per acre-foot of Deviation36 Factor]) reservoir pool) and “Gas Recovery Factor” e. Gas Recovery Efficiency (decimal (thousands of cubic feet of gas recoverable fraction) per acre-foot of reservoir pool). In the f. Gas Shrinkage Factor (decimal absence of local production experience, fraction) predicting these values for undiscovered g. Reservoir Temperature (in °Rankine= pools is difficult because they are the °F+460) product of complex interactions of several variables. Analogous reservoirs in Thousands of Cubic Feet of Gas comparable plays or geologic settings can Recoverable per Acre-Foot of Pool form a source for such data. However, Reservoir (MCFG)* establishing credible analogs and finding = [43,560 ft3/acre-ft] [a·(1-b)] published data for them are both difficult [(60°+460°)·d·e] [c/14.73] [(1-f)/g [1/1,000] tasks. In the North Aleutian Basin OCS Planning Area, we chose to use a computer * (at standard surface conditions of 60 model to calculate the oil and gas recovery °F (520°R) and 14.73 pounds per in2 [1 factors using basic information that is often atmosphere])37 available from regional studies or local well data. or, rearranging for simplification:

The data required to compute oil and gas Thousands of Cubic Feet of Gas recovery factors are essentially the variables Recoverable per Acre-Foot of Pool in the yield equations for oil and gas. These Reservoir (MCFG)* are listed in the data forms of tables 9, 10, 11, and 12 and are noted in the yield 36 equations below: 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 Oil Recovery Factor: volume actually occupied by a gas at a certain a. Porosity (decimal fraction) pressure and temperature and the volume that the b. Water Saturation (decimal fraction) gas would occupy, if it behaved like an ideal gas, at c. Oil Recovery Efficiency (decimal the same pressure and temperature (McCain, 1973, p. 95-109). For ideal gases, the “Z” value is 1.0. fraction) “Z” factors can range from 0.2 to 2.0, but in most d. Oil Volume Factor (as 1/FVF [where North Aleutian prospects, estimated “Z” values FVF = Formation Volume Factor = range from 0.65 to 1.04 (tbls. 9 to 11). Reservoir Barrels Per Stock Tank 37 The value of 14.73 psi/atm was inherited from Barrels]) 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 Barrels Oil Recoverable per Acre-Foot of Louisiana it is 15.025 psi/atm (Craft and Hawkins, 1959, p. 11).

= 1537.8 (a·(1-b)·c·d·e) (1-f)/g were determined for the play and used to construct “force-fit” log-normal probability Many of these variables, such as distributions for entry to the computer temperature, pressure, and porosity, are model. Averaged “initial water saturation” depth-dependent and can be predicted over data for Cook Inlet oil and gas fields the depth ranges of plays if geothermal, (AOGCC, 2001) were used to calibrate the geopressure, and porosity-decline gradients, medians of the probability distributions for respectively, are known. These latter data water saturation in the North Aleutian plays. are available from exploratory wells and can often be extrapolated with some confidence When oil is produced, it shrinks in volume over large areas. In this case, geothermal because gases dissolved in the oil at and geopressure data were obtained from the reservoir pressures are released at surface North Aleutian Shelf COST 1 well. pressures. This volume change is Likewise, porosity data were extracted from represented by the “Oil Formation Volume the abundant core porosity data obtained by Factor” or “FVF” (reservoir barrels per the COST well and incorporated directly stock tank barrels) and it is dictated by the into oil and gas yields after statistical quantity of dissolved solution gas (gas-oil approximation by normal and log-normal ratio, or GOR), which is in turn controlled distributions (figs. 12, 13, 14, and 15). by reservoir pressure, temperature and petroleum composition(s). A single If reservoir texture can be estimated, distribution was used for all North Aleutian irreducible water saturations can be plays. The probability distribution for predicted from porosity determinations by Formation Volume Factor was estimated reference to a series of general tables and from a statistical fit to 14 FVF values charts. We began by estimating the reported for Cook Inlet producing oil fields lithology and grain size of potential (AOGCC, 2001). These data were inverted reservoirs and using these data to estimate and entered as the “Oil Volume Factor bulk volume water using a published table (1/FVF)” for purposes of oil yield (Asquith and Gibson, 1982, p. 98, tbl. 8). calculations (tbls. 9, 10, 11, and 12). The value for bulk volume water was taken as equivalent to the “φSwi” (porosity ⋅ Ranges in oil and gas recovery efficiencies irreducible water saturation) curves in a were estimated from recovery data for porosity-saturation cross plot published by various combinations of reservoirs and drive Schlumberger (1991, p. 158, chart K-3). By mechanisms as published by White (1989, p. pairing minimum and maximum porosity 3-29 to 3-31) and Arps (1967). values with extreme “φSwi ” values (from textural considerations and the Asquith The gas “Z” factor, or “deviation” factor, table)38, estimates for irreducible water was determined using charts published by saturations can be read from the Standings and Katz (1942; republished by Schlumberger chart. In this way, minimum Anderson [1975, p. 155-156] and McCain and maximum values for water saturations [1973, p. 95-109]) and using estimates for gas gravities, reservoir temperatures, and reservoir pressures. Gas gravities were 38 minimum porosity (10%) paired with a poorly- obtained from data for producing fields in sorted, very- fine-grained sandstone; maximum observed porosity paired with a well-sorted example Cook Inlet (AOGCC, 2001). of the coarsest-grained clastic rock expected to occur within the play sequence

Probability distributions for all of the distribution for) numbers of pools39. variables in the yield equations, and appropriate unit conversion constants, were Success of a play or prospect can be defined entered into the @RISK computer program in different ways. Commercial success in and aggregated with dependencies to oil prospecting is contingent upon finding calculate probability distributions for oil and sufficient reserves to permit the gas recovery factors. The input variables accumulation to be developed at a profit. and the dependency models are shown in However, some (or most) oil or gas pools, tables 9, 10, 11, and 12. Probability particularly in the Arctic, are too small to distributions for oil and gas recovery factors warrant commercial development. for play 6 (listed in tbl. 8) were taken from Nevertheless, these small pools represent MMS data compilations by Paul Post (pers. “geologic” successes, proving that Comm.., August, 2003). petroleum must have been generated somewhere and was able to migrate to traps bearing porous media. The small pools, by Risk Assessment their existence, prove that all components of the play petroleum system are working Analyses of play risk were carried out along properly. the lines suggested by White (1993). First, risk was assessed at the play level, where the In this assessment of the North Aleutian absence of a critical element could hazard Basin OCS Planning Area, the condition for the success of the entire play. Second, risk “geologic” success for a play was a single was assessed at the prospect level, where a occurrence of conventionally pooled critical element might be absent at some hydrocarbons capable of flowing to a well- sites and cause some fraction of the bore. Any play known to host such an prospects in a successful play to be barren of occurrence was assigned a play level chance hydrocarbons. of success of 1.0. For example, based on small gas flows in tests from the Tolstoi Chances for success at the prospect level are Formation at the Becharof Lake 1 and the analogous to drilling success rates in David River 1/1A wells, play 2 (Tolstoi) commercially successful plays in productive was assigned a play chance of 1.0. The play basins (some specific examples provided by chances for all other plays are less than 1.0 Clifford, 1986, p. 370). Our subjective because no pooled hydrocarbons have been estimates for prospect level chances of identified in these plays. No attempt was success are conditioned upon success (i.e., made to formalize a specific minimum field success is assumed) at the play level. The size as part of the condition of “geologic” play chance for an unproven play is success. Although similar definitions for typically less than 1.0. The prospect chance play success, in which no minimum pool is ultimately multiplied against the play sizes are specified, are advocated by some chance to obtain an “exploration” chance. experts, (Capen, 1992; Rose, 1992), the The exploration chance is in turn used with practice has been criticized by prominent the (probability distribution for) numbers of experts such as White (1993, p. 2050). prospects to determine the (probability

39 performed in a mathematically complex process by the MPRO module of the GRASP computer program, as described by Bennett (1994)

The construction of risk models required a preservation success. Exploration chances subjective appraisal of the factors for the 6 plays identified in the North underlying play and prospect success. Our Aleutian Basin OCS Planning Area range subjective risk analysis focused upon each from 0.0 (play 4) to 0.1872 (play 1). The of the main elements required for successful key risk factors for each of the 6 plays creation and preservation of oil or gas identified in the North Aleutian Basin OCS accumulations, including: 1) trap definition Planning Area are listed in tables 3, 4, 5, 6, and integrity; 2), reservoir presence and 7, and 8. quality; 3) charge or source success; and 4)

Assessment Results for North Aleutian Basin

Table 14 shows the results of the 2006 oil 40A. Gas (“non-associated” [free] gas and and gas assessment of the North Aleutian solution gas) forms 71% of the hydrocarbon Basin OCS Planning Area, including results energy endowment of play 1. for total technically recoverable hydrocarbon energy (in barrels of oil- In the computer simulation for play 1, each equivalent) and four individual commodities of the 7,198 successful trials is comprised of (oil, condensate from gas, free gas (“non- one or more “pools” (or “hits”, in associated”40 and solution gas) for assessment vernacular), for a total of 73,007 individual plays. Planning Area totals by pools sampled for size (tbl. 15). These pools individual commodity are also listed. can be grouped and displayed as size classes, as shown in the histogram of figure 40B. Pool size class 12 contains the largest Play 1: Bear Lake-Stepovak (Oligocene- share (15,882, or 22%) of pools Miocene) “discovered” among the 10,000 trials41 conducted by the computer simulation for Play 1 is the dominant play in the North play 1. Pool size class 12 ranges from 64 to Aleutian Basin OCS Planning Area, with 128 Mmboe. Pool count statistics for the 61% (1,400 Mmboe) of the Planning Area play 1 simulation are shown in table 15. The hydrocarbon energy endowment (2,287 largest pool among the 73,007 pools or Mmboe) at mean risked values. The play “hits” in the computer simulation for play 1 hydrocarbon energy endowment (risked, falls within pool size class 19, which ranges recoverable) ranges from 0 Mmboe (F95) to in size from 8,192 to 16,384 Mmboe (or 46 3,749 Mmboe (F05), as shown in figure 41 The model simulates the drilling of all pools in the 40 The term “non-associated gas” as used in GRASP play by comparing computer-generated random output reports refers to both free gas occurring as numbers (ranging from 0.0 to 1.0) to the user-input pools of gas unaccompanied by oil and free gas play risk factors (play risk = 1.0 – play chance). occurring in gas caps directly overlying oil When the random number exceeds the risk, then the accumulations. The industry convention is to trial is declared “successful,” indicating a discovery describe the free gas in caps overlying oil (i.e., hydrocarbons exist in the pool), or pool. Most accumulations as “associated” gas. successful trials contain several pools.

57 to 92 Tcfge; tbl. 15 and fig. 40B). The forms 78% of the hydrocarbon energy computer simulation therefore indicates endowment of play 2. some potential for very large hydrocarbon pools in play 1. In the computer simulation for play 2, each of the 9,905 successful trials is comprised of A maximum of 34 hypothetical pools is one or more pools (or “hits”), for a total of forecast by the aggregation of the risk model 61,326 pools sampled for size (tbl. 17). and the prospect numbers model (tbl. 3) for These pools can be grouped and displayed play 1, as shown in figure 40C. These 34 as size classes, as shown in the histogram of pools range in mean conditional (un-risked) figure 41B. Pool size class 12 contains the recoverable volumes from 6 Mmboe (pool largest share (18,963, or 31%) of pools rank 34) to 827 Mmboe (pool rank 1). Pool “discovered” among the 10,000 trials rank 1 (fig. 40C) ranges in possible conducted by the computer simulation for conditional recoverable volumes from 187 play 2. Pool size class 12 ranges from 64 to Mmboe (F95) to 2,495 Mmboe (F05), or in a 128 Mmboe. Pool count statistics for the gas case from 1.05 Tcfge (F95) to 14.02 play 2 simulation are shown in table 17. Tcfge (F05). Data for the size ranges of The 5 largest pools among the 61,326 pools play 1 pools are given in table 16. As noted or “hits” in the computer simulation for play above, at low probabilities we observe some 2 fall within pool size class 16, which ranges potential for very large hydrocarbon pools in in size from 1,024 to 2,048 Mmboe (or 5.8 play 1. The high-side potential recognizes to 11.5 Tcfge; fig. 41B). The computer the combination of large, simple traps and simulation therefore indicates some low- thick, high-quality reservoir formations that probability potential for large hydrocarbon form the best exploration opportunities in pools in play 2. both play 1 and the entire North Aleutian Basin OCS Planning Area. Overall, play 1 A maximum of 44 hypothetical pools is and most of the North Aleutian basin are forecast by the integration of the risk model hypothesized to be charged by sources and the prospect numbers model (tbl. 4) for within the Tertiary basin fill and are play 2, as shown in figure 41C. These 44 modeled as gas prone. Therefore, the largest pools range in mean conditional (un-risked) pool in play 1 (and in the Planning Area) is recoverable volumes from 7 Mmboe (pool most likely to be charged by gas. rank 44) to 208 Mmboe (pool rank 1). Pool rank 1 (fig. 41C) ranges in possible conditional recoverable volumes from 61 Play 2: Tolstoi (Eocene-Oligocene) Mmboe (F95) to 467 Mmboe (F05), or, in the gas case, from 0.34 Tcfge (F95) to 2.62 Play 2 is the second most important play in Tcfge (F05). Data for the size ranges of the the North Aleutian Basin OCS Planning play 2 pools are given in table 18. The Area, with 25% (568 Mmboe) of the modest high-side potential recognizes the Planning Area hydrocarbon energy thin, typically impermeable reservoir endowment (2,287 Mmboe) at mean risked formations that characterize play 2. Overall, values. The play 2 hydrocarbon energy play 2 is Tertiary-sourced and is modeled as endowment (risked, recoverable) ranges gas-prone, so the largest pool is most likely from 91 Mmboe (F95) to 1,293 Mmboe to be charged by gas. (F05), as shown in figure 41A. Gas (“non- associated” [free] gas and solution gas)

Play 3: Black Hills Uplift-Amak Basin the gas case, from 0.11 Tcfge (F95) to 7.32 (Eocene-Miocene) Tcfge (F05). Data for the size ranges of the play 3 pools are given in table 20. As noted Play 3 is a subordinate play in the North above, at very low probabilities, we observe Aleutian Basin OCS Planning Area, with some potential for large pools of 9% (210 Mmboe) of the Planning Area hydrocarbons in play 3. This high-side hydrocarbon energy endowment (2,287 potential recognizes the small number of Mmboe). The play 3 hydrocarbon energy very large closures in play 3 that have been endowment (risked, recoverable) ranges identified by seismic mapping. Because of from 0 Mmboe (F95) to 1,077 Mmboe the potential for oil sourced from underlying (F05), as shown in figure 42A. Gas (“non- Mesozoic sedimentary rocks and the great associated” [free] gas and solution gas) distance to Tertiary gas sources, play 3 is forms 26% of the hydrocarbon energy predominately an oil play. The largest pool endowment of play 3. in play 3 is most likely to contain oil.

In the computer simulation for play 3, each of the 4,127 successful trials is comprised of Play 4: Milky River Biogenic Gas (Plio- one or more pools (or “hits”), for a total of Pleistocene) 15,323 pools sampled for size (tbl. 19). These pools can be grouped and displayed Play 4 is the most regionally extensive yet as size classes, as shown in the histogram of least prospective play in the North Aleutian figure 42B. Pool size class 11 contains the Basin OCS Planning Area. Play 4 probably largest share (2,521, or 16%) of pools contains sizeable in-place quantities of “discovered” among the 10,000 trials biogenic gas. However, all hypothetical conducted by the computer simulation for prospects (none are identified) are related to play 3. Pool size class 11 ranges from 32 to stratigraphic isolation of sandstone or 64 Mmboe. Pool count statistics for the play glacial-moraine bodies within 3 simulation are shown in table 19. The unconsolidated marine mud. Any gas largest pool among the 15,323 pools or production might be accompanied by high “hits” in the computer simulation for play 3 water production because of low gas falls within pool size class 19, which ranges saturations, a common experience in in size from 8,192 to 16,384 Mmboe (fig. biogenic gas production. Formation 42B). The computer simulation therefore pressures are low owing to shallow burial indicates a low-probability potential for very depths and recovery efficiencies will large hydrocarbon pools in play 3. accordingly be quite low. The recoverable biogenic gas endowment of play 4 is A maximum of 13 hypothetical pools is therefore assessed as negligible, as shown in forecast by the aggregation of the risk model table 6 and figure 43. and the prospect numbers model (tbl. 5) for play 3, as shown in figure 42C. These pools range in mean conditional (un-risked) Play 5: Mesozoic Deformed Sedimentary recoverable volumes from 4 Mmboe (pool Rocks (Triassic-Cretaceous) rank 13) to 378 Mmboe (pool rank 1). Pool rank 1 (fig. 42C) ranges in possible Play 5 contributes 1.8% (41 Mmboe) to the conditional recoverable volumes from 20 hydrocarbon energy endowment (2,287 Mmboe (F95) to 1,302 Mmboe (F05), or, in Mmboe) of the North Aleutian Basin OCS

Planning Area. The play hydrocarbon capacities forecast by the observed regional energy endowment (risked, recoverable) zeolitization and wholesale pore occlusion ranges from 0 Mmboe (F95) to 197 Mmboe in Mesozoic sandstones. The Mesozoic (F05), as shown in figure 44A. Gas assemblage of play 5 includes rocks that are (solution gas only) forms 7% of the age-equivalent to established regional oil hydrocarbon energy endowment of play 5. sources. Although the age-equivalent rocks in play 5 have not been securely In the computer simulation for play 5, each demonstrated to be significant sources for of the 3,923 successful trials is comprised of oil in the area of the North Aleutian basin, it one or more pools (or “hits”), for a total of is most likely that if any pools exist in play 14,327 pools sampled for size (tbl. 21). 5, they will consist of oil. These pools can be grouped and displayed as size classes, as shown in the histogram of figure 44B. Pool size class 10 contains the Play 6: Mesozoic Buried Granitic Hills largest share (3,088, or 22%) of pools (Jurassic-Cretaceous Magmatic Rocks) “discovered” among the 10,000 trials conducted by the computer simulation for Play 6 is a subordinate play in the North play 5. Pool size class 10 ranges from 16 to Aleutian Basin OCS Planning Area with 3% 32 Mmboe. Pool count statistics for the play (67 Mmboe) of the Planning Area 5 simulation are shown in table 21. The hydrocarbon energy endowment (2,287 largest pool among the 14,327 pools or Mmboe). The play hydrocarbon energy “hits” in the computer simulation for play 5 endowment (risked, recoverable) ranges falls within pool size class 16, which ranges from 0 Mmboe (F95) to 330 Mmboe (F05), in size from 1,024 to 2,048 Mmboe (tbl. 21 as shown in figure 45A. Gas (“non- and fig. 44B). The computer simulation associated” [free] gas and solution gas) therefore indicates an extremely low- forms 55% of the hydrocarbon energy probability potential for modest to large endowment of play 6. (sub-multi-billion barrel) hydrocarbon pools in play 5. In the computer simulation for play 6, each of the 3,427 successful trials is comprised of A maximum of 13 hypothetical pools is one or more pools (or “hits”), for a total of forecast by the aggregation of the risk model 13,089 pools sampled for size (tbl. 23). and the prospect numbers model (tbl. 7) for These pools can be grouped and displayed play 5, as shown in figure 44C. These pools as size classes, as shown in the histogram of range in mean conditional (un-risked) figure 45B. Pool size class 10 contains the recoverable volumes from 2 Mmboe (pool largest share (2,483, or 19%) of pools rank 13) to 63 Mmboe (pool rank 1). Pool “discovered” among the 10,000 trials rank 1 (fig. 44C) ranges in possible conducted by the computer simulation for conditional recoverable volumes from 8 play 6. Pool size class 10 ranges from 16 to Mmboe (F95) to 176 Mmboe (F05), or, in 32 Mmboe. Pool count statistics for the play the case of gas, from 0.04 Tcfge (F95) to 6 simulation are shown in table 23. The 4 0.99 Tcfge (F05). Data for the size ranges largest pools among the 13,089 pools or of the play 5 pools are given in table 22. “hits” in the computer simulation for play 6 Overall, it seems unlikely that any sizeable falls within pool size class 18, which ranges pools of hydrocarbons will be found in play in size from 4,096 to 8,192 Mmboe. The 5—mostly because of the poor reservoir computer simulation therefore indicates a

60 low probability (effectively zero) for very the North Aleutian Basin OCS Planning large hydrocarbon pools in play 6. Area range from 0.404 Tcfg (F95) to 23.278 Tcfg (F05), with a mean outcome of 8.622 A maximum of 15 hypothetical pools is Tcfg (fig. 46B). Table 14 separates gas forecast by the aggregation of the risk model commodities and shows that at mean values, and the prospect numbers model (tbl. 8) for 97% (8.393 Tcfg) of the gas endowment play 6, as shown in figure 45C. These pools exists as “non-associated” [free] gas, with range in mean conditional (un-risked) the remaining 3% (0.229 Tcfg) dissolved as recoverable volumes from 2 Mmboe (pool solution gas in free oil. rank 15) to 148 Mmboe (pool rank 1). Pool rank 1 (fig. 45C) ranges in possible Technically recoverable liquid petroleum conditional recoverable volumes from 9 resources for the North Aleutian Basin OCS Mmboe (F95) to 469 Mmboe (F05), or, in Planning Area range from 19 Mmbo (F95) the gas case, from 0.05 Tcfge (F95) to 2.64 to 2,505 Mmbo (F05), with a mean outcome Tcfge (F05). Data for the size ranges of the of 751 Mmbo (fig. 46C). Table 14 separates play 6 pools are given in table 24. At low liquid petroleum commodities and shows probabilities, we observe some potential for that at mean values, 72% (545 Mmbo) of the modest-size pools of hydrocarbons in play liquid petroleum exists as free oil, with the 6—their modest sizes owing mostly to the remaining 28% (208 Mmbo) dissolved as doubtful capacity of the fractured granites condensate in free gas. that are conjectured to form the reservoirs for play 6 pools. Play 6 is Tertiary-sourced A comparative plot for cumulative and is modeled as gas prone, so the largest probability distributions for liquid petroleum pool is most likely to be charged by gas. (oil and condensate), total petroleum energy (BOE, all gas and liquids), and total gas (free gas and solution gas) is shown in figure Overall Results for Oil and Gas 46D. Endowments of North Aleutian Basin

Graphical summaries for overall basin Large Individual Gas Fields Are Possible hydrocarbon endowments (risked, recoverable) are shown in figure 46. Total Play 1, the Bear Lake-Stepovak play, Planning Area technically recoverable captures most of the large prospects in the hydrocarbon resources range from 91 central part of the North Aleutian basin. Mmboe (F95) to 6,647 Mmboe (F05), with a The mean conditional (un-risked) size of the mean outcome of 2,287 Mmboe (fig. 46A). largest hypothetical pool in play 1 (and the At mean values, 67% of the hydrocarbon North Aleutian basin overall) is 4.65 energy endowment is gas (“non-associated” trillions of cubic feet of natural gas (or 827 [free] gas and solution gas from oil) and millions of barrels [oil-energy-equivalent]). 33% is liquid petroleum (free oil and As shown in the pool rank plot in figure 47, condensate from gas). The North Aleutian the largest hypothetical pool is nearly twice Basin OCS Planning Area is overall a gas- the size of the largest gas field in Cook Inlet prone province, although some subordinate (Kenai gas field, 2.427 Tcfg EUR). At plays are primarily oil plays. maximum (F05) size, the largest pool in play 1 could contain 14.02 trillions of cubic feet Technically recoverable gas resources for of natural gas (or 2.495 billions of barrels

[oil-energy-equivalent]). Bcfg/yr) could be absorbed by the Cook Inlet market. Most North Aleutian basin gas would likely be marketed to the U.S. West Economic Potential of North Aleutian Coast, Hawaii, or perhaps even the Asian Basin Pacific Rim. However, the Cook Inlet would form a logical and accessible alternative destination for some fraction of The hypothetical infrastructure model for the production from North Aleutian basin. the 2006 MMS economic assessment is illustrated in the map of figure 48. Our Condensate and oil are assumed to be loaded infrastructure model, although a likely at Balboa Bay and tankered to Cook Inlet or scenario, was constructed only for the perhaps to the oil loading terminal for the purpose of conducting economic tests and is Trans-Alaska oil pipeline system (TAPS) at not necessarily a predictor of actual future Valdez, Alaska (located in figs. 1, 4). installations. The model assumes that several prospects that were leased in 1988 A summary of the results of the economic (since relinquished untested back to the U.S. modeling for the North Aleutian basin are Government) are found to contain shown in table 25. Economic modeling commercial gas reserves. Development yields first positive economic results at platforms (with some subsea completions prices of $14/barrel of oil and $2.12/Mcf of over field margins) send production to an associated solution gas. Non-associated gas offshore hub that is centrally located over pools yield first positive economic results at the prospect that garnered the highest bids in a gas price of $3.63/Mcf (tbl. 25). In any the 1988 lease sale. Trunk pipelines (gas case, these “threshold” prices correspond to and oil) link the offshore hub to gas very small risked volumes of gas, conditioning facilities and a liquefied- condensate, and oil. Meaningful volumes of natural-gas (LNG) plant at a port in Balboa gas (>1 Tcfg) are not economically Bay on the Pacific (south) coast of the recoverable until prices exceed $4.54/Mcfg Alaska Peninsula (fig. 48). At the LNG (tbl. 25). plant, the natural gas is chilled to a liquid state (-260°F) preparatory to loading into A minimum developable gas reserve of 5 tankers. The LNG tankers then convey the Tcf will probably be required to justify a gas to receiving and re-gasification grassroots LNG export system in the remote terminals either at Nikiski in Cook Inlet frontier area of the North Aleutian basin. (550 mi. tanker sailing) or on the U.S. West The 5 Tcf of gas will presumably be Coast (assumed 2,600 mi. tanker sailing). supplied by several fields. Our economic Minimum transportation tariffs in the analysis indicates that economic recovery of economic model represent a Cook Inlet 5 Tcf of gas will require prices of $6.50/Mcf destination while the maximum tariffs and $43/barrel (2005$) landed at the U.S. represent a U.S. West Coast destination. West Coast. Current gas prices do exceed $6.50/Mcf by a wide margin (recent gas The Cook Inlet market is isolated and small, prices at the Los Angeles city gate exceed typically consuming a little over 200 Bcfg/yr $13.00/Mcf; Natural Gas Week, 19 (Sherwood and Craig, 2001, tbl. 5). It is December 2005). If market prices can be unlikely that the entire North Aleutian basin sustained at the current level or higher, a production stream (estimated at 150 large fraction of the North Aleutian basin

62 gas endowment could ultimately be economically recoverable.

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Hydrocarbon Resource Report for Proposed OCS Godson, R.H., 1994, Composite magnetic anomaly Sale Lease Sale 88-Southeastern Alaska, Northern map of Alaska and adjacent offshore areas, 1 Gulf of Alaska, Cook Inlet, and Shelikof Strait, sheet, scale 1:2,500,000, in: The Geology of Alaska Alaska, Bruns, T.R. (ed.), U.S. Geological survey (The Geology of North America, Volume G-1), Open file Report OF 82-928, p. 53-67. Plate 10.

Falvey, D.A., 1974, The development of continental Guangming, Z., and Quanheng, Z., 1982, Buried-Hill margins in plate tectonic theory: Australian oil and gas pools in the North China Basin, in: The Petroleum Exploration Association Journal, v. 14, Deliberate Search for the Subtle Trap, Halbouty, p. 95-106. M.T. (ed.), American Association of Petroleum Geologists Memoir 32, p. 317-335. Finzel, E.S., Reifenstuhl, R., Decker, P.L., and Ridgway, K.D., 2005, Sedimentology, stratigraphy, Haeussler, P.J., Bruhns, R.L., and Pratt, T.L., 2000, and hydrocarbon reservoir-source rock potential, Potential seismic hazards and tectonics of the upper using surface and subsurface data, of Tertiary and Cook Inlet basin, Alaska, based on analysis of Mesozoic strata, Bristol Bay basin and Alaska Pliocene and younger deformation: Geological Peninsula: State of Alaska, Division of Geological Society of America Bulletin, v. 112, no. 9, p. 1414- and Geophysical Surveys, Preliminary Interpretive 1429. Report PRI 2005-4, July 2005, 67 p. Hayes, J.B., Harms, J.C., and Wilson, T. Jr., 1976, Franks, S.G., and Hite, D.M., 1980, Controls of Contrasts between braided and meandering stream zeolites cementation in Upper Jurassic sandstones, deposits, Beluga and Sterling Formations lower Cook Inlet, Alaska [abs.]: American (Tertiary), Cook Inlet, Alaska, in: Recent and Association of Petroleum Geologists Bulletin, v. Ancient Sedimentary Environments in Alaska, 64, no. 5, p. 708-709. Miller, T.P. (ed.), Proceedings of the Alaska Geological Society Symposium held April 2-4, Folk, R.L., 1968, Petrology of Sedimentary Rocks: 1975, at Anchorage, Alaska, p. J1-J27. Austin, TX, Hemphill’s Book Store, 170 p. Hite, D.M., 1976, Some sedimentary aspects of the Galvin, Patrick, 2005, (personal communication), Kenai Group, Cook Inlet, Alaska, in: Recent and State of Alaska, Dept. of Natural Resources, e-mail Ancient Sedimentary Environments in Alaska, dated 17 March 2005. Miller, T.P. (ed.), Proceedings of the Alaska Geological Society Symposium held April 2-4, Geochem (Laboratories, Inc.), 1976, Hydrocarbon 1975, at Anchorage, Alaska, p. I1-I23. source rock evaluation study, organic geochemical analyses of dry well cuttings, Amoco Production Hite, D.M., 2004, BBNC – Hydrocarbon Potential of company Cathedral River Unit No. 1 well, sec. 29- Native Lands in the Bristol Bay Area, Southern 51S-83W, Cold Bay County, Alaska: Report by Alaska: Consultant Report to Bristol Bay Native Geochem Laboratories, Inc., 1143-C Brittmore Corporation, on compact disc (contact Road, Houston, Texas 77043, December 1976. [email protected]), 80 p. Available to public as Alaska Geologic Materials Center (AGMC) Report No. 56, State of Alaska Huang, W-Y., and Meinschein, W.G., 1979, Sterols Geological Materials Center, P.O. Box 772805, as ecological indicators: Geochimica et 18205 Fish Hatchery Road, Eagle River, AK, Cosmochimica Acta, v. 43, p. 739-745. 99577-2805, 17 p. Hunt, J. M., 1979, Petroleum Geochemistry and Geochron (Laboratories, Inc.), 1969, Potassium- Geology: W.H. Freeman and Company, San argon determinations, General Petroleum Corp. Francisco, 617 p. Great Basins 1 and 2 wells and Gulf Port Heiden 1 well. Available as Alaska Geological Materials Imlay, R.W., and Detterman, R.L., 1973, Jurassic Center (AGMC) Report No. 38 from Alaska paleobiogeography of Alaska: U.S. Geological Geologic Materials Center (AGMC), State of Survey Professional Paper 801, 34 p. Alaska Geological Materials Center, P.O. Box 772805, 18205 Fish Hatchery Road, Eagle River, Johnsson, M.J., and Howell, D.G., 1996, Thermal AK, 99577-2805, 3 p. maturity of sedimentary basins in Alaska—an overview, in: Thermal Evolution of Sedimentary

Basins in Alaska, Johnsson, M.J., and Howell, D.G. Bering Sea shelf: American Association of (eds.), U.S. Geological Survey Bulletin 2142, p. 1- Petroleum Geologists Bulletin, v. 64, p. 2139-2155. 10, Plate 1. Marzi, R., B. E. Torkelson and R. K. Olson, 1993, A Lee, W.H.K., and Uyeda, S., 1965, Review of heat revised carbon preference index. Org. Geochem., v. flow data: in: Terrestrial Heat, American 20, pp. 1301-1306. Geophysical Union Geophysical Monograph 8, p. 87-190. McCain, W.D., Jr., 1973, The Properties of Petroleum Fluids: The Petroleum Publishing Levine, J.R., 1993, Coalification: The Evolution of Company, Tulsa, OK, USA, 325 p. coal as source rock and reservoir rock for oil and gas, in: Hydrocarbons from Coal, Rice, D.D., and McKenzie, D.P., 1978, Some remarks on the Law, B.E. (eds.), American Association of development of sedimentary basins: Earth and Petroleum Geologists Studies in Geology 38, p. 39- Planetary Science Letters, v. 40, p. 25-32. 78. Mickey, M.B., Haga, H., Boettcher, R.S., and Kling, Lonsdale, Peter, 1988, Paleogene history of the Kula S.A., 2005, Northwestern Alaska Peninsula— plate: Offshore evidence and onshore implications: Bristol Bay Biostratigraphy Study: M.C. Job No. Geological Society of America Bulletin, v. 100, p. 25-104, June 2005 (Published by Alaska State Div. 733-754. of Oil and Gas at their website, http://www.dog.dnr.state.ak.us/oil/products/publica Lopatin, N.V., 1971, Temperature and geologic time tions/akpeninsula/biostrat.htm, August 2005), 286 as factors in Coalification (in Russian): Akad. p. Nauk. SSSR Isv. Ser. Geol. No. 3, p. 95-106. Molenaar, C.M., 1996a, Thermal maturity patterns Magoon, L.B., 1986, Present Day Geothermal and geothermal gradients on the Alaska Peninsula, Gradient: in: Geologic Studies of the Lower Cook in: Thermal Evolution of Sedimentary Basins in Inlet COST No. 1 Well, Alaska Outer Continental Alaska, Johnsson, M.J., and Howell, D.G. (eds.), Shelf, U.S. Geological Survey Bulletin 1596, p. 41- U.S. Geological Survey Bulletin 2142, p. 11-20. 46. Molenaar, C.M., 1996b, Alaska Peninsula: in: Digital Magoon, L.B., 1994, Tuxedni-Hemlock petroleum Map Data, Text, and Graphical Images in Support system in Cook Inlet, Alaska, U.S.A., in: The of the 1995 National Assessment of United States Petroleum System—From Source to Trap, Magoon, Oil and Gas Resources, U.S. Geological Survey L.B., and Dow, W.G. (eds.), American Association Digital Data Series DDS-35, file “PROV03.RTF”, of Petroleum Geologists Memoir 60, p. 359-370. p. 2-5, tbl. 1).

Magoon, L.B., and Anders, D.E., 1992, Oil-to- Moore, B.J., and Sigler, S., 1987, Analyses of natural source-rock correlation using carbon-isotopic data gases, 1917-85: U.S. Dept. of the Interior, Bureau and biological marker compounds, Cook Inlet- of Mines, Information Circular 9129. Alaska Peninsula, Alaska, in: Biological Markers in Sediments and Petroleum, Moldowan, J.M., Moore, J.C., and Connelly, W., 1979, Tectonic Albrecht, P., and Philp, R.P. (eds.), Prentice Hall, history of the continental margin of southwestern New Jersey, p. 241-274. Alaska: Late Triassic to earliest Tertiary: in: The Relationship of Plate Tectonics to Alaskan Geology Magoon, L.B., Adkison, W.L., and Egbert, R.M., and Resources, Alaska Geological Society 1976, Map showing geology, wildcat wells, Symposium Proceedings, p. H1-H29. Tertiary plant fossil localities, K-Ar age dates, and petroleum operations, Cook Inlet area, Alaska: Newendorp, P.D., 1975, Decision analysis for U.S. Geological Survey Miscellaneous petroleum exploration: The Petroleum Publishing Investigations Series, Map I-1019, 3 sheets incl. Company, Tulsa, OK, 688 p. map, 1:250,000. O&GJ (Oil and Gas Journal), 2003, Vietnam: in Marlow, M. S., and Cooper, A. K., 1980, Mesozoic Exploration and Development, Oil and Gas and Cenozoic structural trends under southern Journal, August 18, 2003, p. 42.

Palmer, A.R., 1998, Geological Society of America Geological Survey Miscellaneous Investigations geologic time scale: Boulder, Colorado, Map I-2204, 1:250,000. Geological Society of America, 1 p. Robertson Research (Inc.), 1982, Total organic P’An, C.H., 1982, Petroleum in basement rocks: carbon and Rock-Eval pyrolysis of seventeen American Association of Petroleum Geologists samples from the Cathedral River well: Robertson Bulletin, v. 66, p. 1597-1643. Research (U.S.) Inc., Report 823-7B, prepared for Cities Service Co., by Robertson Research, 16730 Parker, J., and Newman, R., 1998, North Aleutian Hedgecroft, Suite 206, Houston, Texas 77050- Basin Assessment Province: in Sherwood, K.W., 3697, April 1982. Available to public as Alaska ed., Undiscovered Oil and Gas Resources, Alaska Geologic Materials Center (AGMC) Reports Nos. Federal Offshore (As of January 1995), U.S. 12 and 64, “Total Organic Carbon, Rock-Eval Minerals Management Service, OCS Monograph Pyrolysis and Visual Kerogen/Vitrinite MMS 98-0054, p. 251-256. Reflectance, Amoco Cathedral River Unit 1”, State of Alaska Geological Materials Center, P.O. Box Peters, K.E., 1986, Guidelines for evaluating 772805, 18205 Fish Hatchery Road, Eagle River, petroleum source rock using programmed AK, 99577-2805, 13 p. pyrolysis: American Association of Petroleum Geologists Bulletin, v. 70, no. 3, p. 318-329. Robertson Research (Inc.), 1983, Geochemical analysis of the North Aleutian Shelf, COST No. 1 Peters, K.E., and Moldowan, J.M., 1993, The well, Alaska: Report to ARCO Exploration Biomarker Guide—Interpreting Molecular Fossils Company and Industry Consortium by W.G. Dow, in Petroleum and Ancient Sediments: Prentice Robertson Research (U.S.) Inc., 16730 Hedgecroft, Hall, Englewood Cliffs, New Jersey, 363 p. Suite 306, Houston, TX 77060-3697. Available as Appendix 5 of this report and in public well file, Post, P.J., Harrison, P.F., Whittle, G.L., and Hunt, Minerals Management Service, 949 E. 36th Ave., J.D., 2001, Mesozoic ultra-deep water potential of Suite 300, Anchorage, AK 99503, 316 p. Excel the U.S. Gulf of Mexico—conceptual play spreadsheet of data provided as Appendix 2 of this development and analysis, in: Gulf Coast Section report. of the Society of Economic Paleontologists and Mineralogists (SEPM) Foundation, 21st Annual Rose, P.R., 1992, Chance of success and its use in Bob F. Perkins Research Conference, p. 35-69. petroleum exploration: in: The Business of Petroleum Exploration, Steinmetz, R. (ed.), Reed, B.L., and Lanphere, M.A., 1972, The Alaska- American Association of Petroleum Geologists Aleutian Range batholith showing potassium-argon Treatise of Petroleum Geology, Handbook of ages of the plutonic rocks: U.S. Geological Survey Petroleum Geology, p. 71-86. Miscellaneous Field Studies Map MF-372, 2 sheets, 1: 1,000,000. Schlumberger (Ltd.), 1991, Log Interpretation Charts: Schlumberger Educational Services, Reed, B.L., Miesch, A.T., and Lanphere, M.A., 1983, Schlumberger Limited, 277 Park Ave., New York, Plutonic rocks of Jurassic age in the Alaska- NY, 10017, 171 p. Aleutian Range batholith: geochemical variations and polarity: Geological Society of America Shanmugam, G., 1985, Significance of coniferous Bulletin, v. 94, p. 1232-1240. rain forests and related organic matter in generating commercial quantities of oil, Gippsland basin, Reifenstuhl, R., 2005, Bristol Bay, Frontier Basin, Australia: American Association of Petroleum Alaska Peninsula—Hydrocarbon Resources, Geologists Bulletin, v. 69, no. 8, p. 1241-1254. Petroleum Reservoir Characterization, and Source Potential: Alaska Geological Society Newsletter, Sherwood, K.W., and Craig, J.D., 2001, Prospects for v. 35, no. 9, May 2005, p. 1-3. development of Alaska natural gas: a review: MMS Report issued as Compact Disc (Ph: 907- Riehle, J.R., Detterman, R.L., Yount, M.E., and 271-6060 to order free copy) and posted on website Miller, J.W., 1993, Geologic map of the Mount at http://www.mms.gov/alaska/re/reports/rereport.htm; Katmai quadrangle and adjacent parts of the January 2001, 135 p. Naknek and Afognak quadrangles, Alaska: U.S.

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Walker, K.T., McGeary, S.E., and Klemperer, S.L., Worrall, D.M., 1991, Tectonic history of the Bering 2003, Tectonic Evolution of the Bristol Bay basin, Sea and the evolution of Tertiary strike-slip basins southeast Bering Sea: Constraints from seismic of the Bering Sea: Geological Society of America reflection and potential field data: Tectonics, v. 22, Special Paper 257, 120 p. no. 5, p.4-1 to 4-19. Zumberge, J., 1987, Prediction of source rock Wang, J., Newton, C.R., and Dunne, L., 1988, Late characteristics based on terpane biomarkers in Triassic transition from biogenic to arc crude oils: A multivariate statistical approach. sedimentation on the Peninsular terrane, Puale Bay, Geochim. et Cosmochim. Acta, v. 51, p.1625-1637.

Table 1: North Aleutian Basin and Alaska Peninsula Exploration Wells, 1903-1983 Year Kelly Bushing Elevation; Age and Name, Total Depth; Fm., Age and Name, Operator and Well Name Location Completed Surface Formation Formation at Total Depth Pacific Oil and Commercial Pacific Oil No. 1 1903 NW/4 Sec. 3, T29S, R40W Ground level(?); M. Jurassic, Shelikof Fm. 1421 feet; M. Jurassic, Shelikof Fm. J.H. Costello Costello No. 1 1903 NW/4 Sec. 10,T29S, R40W Ground level(?); M. Jurassic, Shelikof Fm. 728 feet;M. Jurassic, Shelikof Fm. Pacific Oil and Commercial Pacific Oil No. 2 1904 SE/4 Sec. 3, T29S, R40W Ground level(?);M. Jurassic, Shelikof Fm. 1542 feet;M. Jurassic, Shelikof Fm. J.H. Costello Costello No. 2 1904 SE/4 Sec. 10, T29S, R40W Ground level(?);M. Jurassic, Shelikof Fm. TD Unknown;M. Jurassic, Shelikof? Fm. Standard Lathrop No. 1 1923 SE/4 Sec. 17, T29S, R43W Ground level(?); U. Jurassic, Naknek Fm. 500 feet; U. Jurassic, Naknek Fm. Tidewater Associated Finnegan No. 1 1923 NE/4 Sec. 30, T29S, R43W Ground level(?); U. Jurassic, Naknek Fm. 560 feet; U. Jurassic, Naknek Fm. Standard Oil McNally No. 1 1925 NW/4 Sec. 29, T29S, R43W Ground level(?); U. Jurassic Naknek Fm. 510 feet; U. Jurassic, Naknek Fm. Tidewater Associated Alaska No.1 1925 SW/4 Sec.20, T29S, R43W Ground level, 694 ft; U. Jurassic, Naknek Fm. 3033 feet; M. Jurassic, Shelikof Fm. Standard Lee No. 1 1926 SW/4 Sec.20, T29S, R43W Ground level, 764 ft; U. Jurassic, Naknek Fm. 5053 feet; M. Jurassic, Shelikof Fm. Standard, et. al. Grammer No. 1 1940 Sec. 10, T30S, R41W 375 feet; M. Jurassic, Shelikof Fm. 7596 feet; Lower Jurassic, Talkeetna Fm.? Humble-Shell Bear Creek Unit No. 1 1959 Sec 36, T29S, R41W 927 feet; M. Jurassic, Shelikof Fm. 14,374 feet; Triassic, Kamishak Fm. General Petroleum Great Basins No. 1 1959 Sec. 2, T27S, R48W 231 feet; Quaternary, Un-named Alluvium 11,080 feet; Mesozoic Granitic Basement General Petroleum Great Basins No. 2 1959 Sec. 35, T25S, R50W 105 feet; Quaternary, Un-named Alluvium 8865 feet; Mesozoic Granitic Basement Pure Canoe Bay No. 1 1961 Sec. 8, T54S, R78W 1221 feet; U. Cretaceous, Hoodoo Fm. 6642 feet; U. Jurassic, Naknek Fm. Richfield Wide Bay Unit No. 1 1963 Sec. 5, T33S, R44W 54 feet; M. Jurassic, Kialagvik Fm. 12,568 feet; Triassic, Kamishak Fm. Gulf Sandy River Federal No. 1 1963 Sec. 10, T46S, R70W 235 feet; Quaternary, Un-named Alluvium 13,068 feet; Oligocene, Stepovak Fm. Great Basins Ugashik No. 1 1966 Sec. 8, T32S, R52W 142 feet; Quaternary, Un-named Alluvium 9476 feet; Oligocene, Meshik Fm. Cities Service Painter Creek No. 1 1967 Sec. 14, T35S, R51W 394 feet; Pliocene, Milky River Fm. 7912 feet; U. Jurassic, Naknek Fm. Pan American David River No. 1 & No. 1-A 1969 Sec. 12, T50S, R80W 70 feet; Pliocene, Milky River Fm. 13,769 feet; (U. Cretaceous, Chignik Fm.?) Pan American Hoodo Lake No. 1 1970 Sec. 21, T50S, R76W 141 feet; Pliocene, Milky River Fm. 8048 feet; Oligocene, Stepovak Fm. Pan American Hoodoo Lake No. 2 1970 Sec. 35, T50S, R76W 345 feet; Pliocene, Milky River Fm. 11,234 feet; U.Jurassic, Naknek Fm. Gulf Port Heiden Unit No. 1 1972 Sec. 20, T37S, R59W 36 feet; Quaternary, Un-named Alluvium 15,015 feet; Oligocene, Meshik Fm. Amoco Cathedral River No. 1 1974 Sec. 29, T51S, R83W 178 feet; U. Jurassic, Naknek Fm. 14,301 feet; Triassic, Kamishak Fm. Phillips Big River No. A-1 1977 Sec 15, T49S, R68W 281 feet; Oligocene, Stepovak Fm. 11,371 feet; U. Jurassic, Naknek Fm. Chevron Koniag No. 1 1981 Sec. 2, T38S, R49W 62 feet; U. Jurassic, Naknek Fm. 10,905 feet; Triassic, Kamishak Fm. Amoco Becharof No. 1 1985 Sec. 15, T28S, R48W 220 feet; Quaternary, Un-named Alluvium 9022 feet; Mesozoic Granitic Basement Offshore Wells 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; Eocene - Tolstoi Table adapted from Molenaar (1996b, tbl. 1)

71 Table 2: Summary of Selected Extract Data, North Aleutian Shelf COST 1 Well North Aleutian Shelf COST 1 Extract Data: Oil Show Interval 15,300-16,800 ft bkb Spl. NSO + 13 13 Pristane/ Pristane/ Phytane/ Spl. No. Depth/ Interval SAT % ARO % Del CDelC Type ASPH % SAT ARO Phytane n-C17 n-C18 16006-16029 & MMSAK2003-1 Core 6.82 1.16 92.02 -28.5 -27.3 2.65 0.45 0.19 16701.2-16720 MMSAK2003-2 Cuttings 15700-16800 56.21 9.26 34.53 -28.0 -26.9 3.75 0.83 0.23 RR-1 Core 15354.6 2.6 43.9 53.5 NA NA 9.30 1.31 0.15 RR-2 Core 15368.5 9.9 37.3 52.8 NA NA 6.54 1.26 0.19 RR-3 Core 16009.3 19.1 33.7 47.2 NA NA 5.00 0.71 0.15 RR-4 Core 16029 31.3 32 36.7 NA NA 3.85 0.73 0.20 RR-5 Core 16703.7 21.4 57.4 21.2 NA NA 2.78 0.47 0.17 RR-6 Core 16714.6 14.8 25 60.2 NA NA 2.14 0.48 0.22 RR-7 Core 16719.6 37.4 21.6 41 NA NA 2.27 0.36 0.16 MMSAK: Baseline-DGSI for Minerals Management Service, 2003 RR: Roberston Research for ARCO and COST Well Consortium, 1983 Thermal maturity of show interval = 0.78% to 1.04% vitrinite reflectance

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 F02 F01 F00 Prospect Area (acres)-Model Input* 3227 4249 10661 13794/11325 26750 92660 Prospect Area (acres)-Model Output** 989 3408 4394 6710 10825 13560/10075 17299 22441 26058 33526 40000 44000 88280 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 0.65 0.69 1 Productive Area of Pool (acres) 247 1310 1706 2638 4299 5742/4972 7173 9421 11081 14063 17500 21000 51718 Pay Thickness (feet) 3 21 29 52 98 151/180*** 184 258 324 340 375 400 550 * 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 Prospect Level Chance 0.26 Exploration Chance 0.1872 Output Play Level Chance 0.72

Risk Model Play Chance Petroleum System Factors Prospect Chance 0.8 Seal (no regional seal over reservoir sequence) 0.5 0.9 Source (mainly Tertiary coals and Type III shales) 0.65 Migration (regional shale seal between source & reservoir) 0.8

Fractile F99 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 F02 F01 F00 Numbers of Prospects in Play 24 28 30 32 38 39/7.95 43 46 49 52 56 60 80 Numbers of Pools in Play 8 7.30/5.40 11 13 14 15 17 19 34 Zero Pools at F72.00 Minimum Number of Pools 4 (F70) Mean Number of Pools 7.3 Maximum Number of Pools 34

POOLS/PSRK/PSUM Modules (Play Resources) Fractile F100 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 F02 F01 F00 Oil Recovery Factor (bbl/acre-foot) 89 212 247 319 424 465/209 564 657 728 848 1008 1130 1516 Gas Recovery Factor (Mcfg/acre-foot) 279 578 657 812 1029 1093/399 1304 1480 1613 1832 2114 2327 2584 Gas Oil Ratio (Sol'n Gas)(cf/bbl) 56 162 195 267 376 426/220 531 638 723 871 1073 1100 1110 Condensate Yield ((bbl/Mmcfg) 11417212525/729323435373950 Pool Size Distribution Statistics from POOLS (1,000 BOE): μ (mu)= 11.439 σ 2 (sigma squared)= 1.628 Random Number Generator Seed= 297,150

BOE Conversion Factor (cf/bbl) 5620 Probability Any Pool Contains Both Oil and Free Gas (Gas Cap) 0.1 Probability Any Pool is 100% Oil 0.1 Fraction of Pool Volume Gas-Bearing in Oil Pools with Gas Cap 0.9 Probability Any Pool is 100% Gas 0.8

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: December 2004 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 Maturity: 0.30%-1.65% 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 F02 F01 Prospect Area (acres)- Model Input* 6787 (act) 6567 (fit) 11169 15925/9790 28028 Prospect Area (acres)- Model Output** 1518 5490 6647 9321 13549 15555/8547 19702 23776 27111 33179 36000 38000 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 0.6 0.65 0.69 Productive Area of Pool (acres) 455 2031 2509 3631 5447 6442/3960 8173 10082 11572 14470 16000 17000 Pay Thickness (feet) 31 49 53 60 69 71/17 80 86 91 98 107 113 * 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 1 Prospect Level Chance 0.1404 Exploration Chance 0.1404 Output Play Level Chance 0.9906

Risk Model Play Chance Petroleum System Factors Prospect Chance Minor gas pools tested (90 Mcfg/d) in Becharof Lake 1 well Reservoir (impermeable through most of sequence) 0.216 Source (mainly Tertiary coals and Type III shales) 0.65

Fractile F99 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 F02 F01 Numbers of Prospects in Play 16 20 23 30 40 43.65/19.72 51 60 65 75 90 100

Numbers of Pools in Play 1 2 2 4 6 6.13/3.60 8 9 11 12 15 18

Zero Pools at F99.06 Minimum Number of Pools 1 (F99.00) Mean Number of Pools 6.13 Maximum Number of Pools 44

POOLS/PSRK/PSUM Modules (Play Resources) Fractile F100 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 F02 F01 Oil Recovery Factor (bbl/acre-foot) 25 57 75 113 178 203/118 266 322 364 430 480 510 Gas Recovery Factor (Mcfg/acre-foot) 18 351 433 630 921 997/497 1285 1509 1657 1933 2100 2300 Gas Oil Ratio (Sol'n Gas)(cf/bbl) 56 162 195 267 376 426/220 531 638 723 871 1073 1100 Condensate Yield ((bbl/Mmcfg) 1 14 17 21 25 25/17 29 32 34 35 37 39

Pool Size Distribution Statistics from POOLS (1,000 BOE): μ (mu)= 11.079 σ 2 (sigma squared)= 0.828 Random Number Generator Seed= 668,076

BOE Conversion Factor (cf/bbl) 5620 Probability Any Pool Contains Both Oil and Free Gas (Gas Cap) 0.1 Probability Any Pool is 100% Oil 0.1 Fraction of Pool Volum e Gas-Bearing in Oil Pools with Gas Cap 0.9 Probability Any Pool is 100% Gas 0.8

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 F02 F01 F00 Prospect Area (acres)-Model Input* 2667 (act) 2350 (fit) 5916 25230/48696 57316 133385 Prospect Area (acres)-Model Output** 509 1643 2471 4869 11201 19995/23424 25426 38733 49245 70155 78000 82000 133124 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 0.4 0.45 1 Productive Area of Pool (acres) 42 226 343 706 1734 3554/5194 4054 6211 8543 12700 17000 20000 56488 Pay Thickness (feet) 3 21 29 52 98 151/180* 184 258 324 340 375 400 550 * 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 Prospect Level Chance 0.25 Exploration Chance 0.105 Output Play Level Chance 0.4128

Risk Model Play Chance Petroleum System Factors Prospect Chance 0.6 Migration (lengthy, highly-faulted path from Tertiary source) 0.5 0.7 Seal (no regional seal over reservoir) 0.5

Fractile F99 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 F02 F01 F00 Numbers of Prospects in Play 10 11 12 13 14 14.61/1.83 15 16 17 17.5 17.7 18 20 Numbers of Pools in Play 1.53/2.1234567713 Zero Pools at F41.28 Minimum Number of Pools 1 (F40.00) Mean Number of Pools 1.53 Maximum Number of Pools 13

POOLS/PSRK/PSUM Modules (Play Resources) Fractile F100 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 F02 F01 F00 Oil Recovery Factor (bbl/acre-foot) 42 129 158 221 311 343/177 427 500 558 644 800 960 1300 Gas Recovery Factor (Mcfg/acre-foot) 8 441 531 686 873 888/302 1074 1194 1271 1389 1450 1550 1963 Gas Oil Ratio (Sol'n Gas)(cf/bbl) 56 162 195 267 376 426/220 531 638 723 871 1073 1100 1110 Condensate Yield ((bbl/Mmcfg) 1 1417212525/729323435373950

Pool Size Distribution Statistics from POOLS (1,000 BOE): μ (mu)= 10.662 σ2 (sigma squared)= 2.666 Random Number Generator Seed= 354,412

BOE Conversion Factor (cf/bbl) 5620 Probability Any Pool Contains Both Oil and Free Gas (Gas Cap) 0.4 Probability Any Pool is 100% Oil 0.4 Fraction of Pool Volume Gas-Bearing in Oil Pools with Gas Cap 0.5 Probability Any Pool is 100% Gas 0.2

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 F02 F01 F00 Prospect Area (acres) Fill Fraction (Fraction of Area Filled) Play 4 Not Quantified; Assessed to Have Negligible Undiscovered Technically Recoverable Biogenic Gas Resources Productive Area of Pool (acres) Pay Thickness (feet)

MPRO Module (Numbers of Pools) Input Play Level Chance 00Prospect Level Chance Exploration Chance 0 Output Play Level Chance

Risk Model Play Chance Petroleum System Factors Prospect Chance 0 Gas recoverability (low pressure; water production) 0 0 Seal (unconsolidated mud) 0 0 Reservoir (poor continuity) 0 Charge (No Structured Fetch to Potential Traps)

Fractile F99 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 F02 F01 F00 Numbers of Prospects in Play No Identified Prospects Numbers of Pools in Play

Minimum Number of Pools 000Mean Number of Pools Maximum Number of Pools

POOLS/PSRK/PSUM Modules (Play Resources) Fractile F100 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 F02 F01 F00 Oil Recovery Factor (bbl/acre-foot) Gas Recovery Factor (Mcfg/acre-foot) Play 4 Not Quantified; Assessed to Have Negligible Undiscovered Technically Recoverable Biogenic Gas Resources Gas Oil Ratio (Sol'n Gas)(cf/bbl) Condensate Yield ((bbl/Mmcfg)

Pool Size Distribution Statistics from POOLS (1,000 BOE): μ (mu)= NA σ2 (sigma squared)= NA Random Number Generator Seed= 255,476

BOE Conversion Factor (cf/bbl) 5620 Probability Any Pool Contains Both Oil and Free Gas (Gas Cap) 0 Probability Any Pool is 100% Oil 0 Fraction of Pool Volume Gas-Bearing in Oil Pools with Gas Cap NA Probability Any Pool is 100% Gas 1

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 F02 F01 F00 Prospect Area (acres)-Model Input* 7000 10415 39621 68223/95634 150718 147000 Prospect Area (acres)-Model Output** 1024 6793 9768 18402 35028 44767/33824 63167 82991 97444 116497 120000 125000 146550 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 0.23 0.25 0.5 Productive Area of Pool (acres) 93 595 902 1736 3478 5004/4766 6596 9087 10687 13683 17000 19000 43443 Pay Thickness (feet) 18 47 55 73 100 113/60 137 162 182 215 260 295 564 * 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 Prospect Level Chance 0.2304 Exploration Chance 0.09216 Output Play Level Chance 0.3925

Risk Model Play Chance Petroleum System Factors Prospect Chance 0.5 Reservoir (widespread early zeolitization) 0.6 0.8 Timing of migration (if early, no traps; if late, no porosity) 0.6 Trap integrity (erosional breaching and fault disruption) 0.8 Preservation (denudation to shallow depths/biodegradation of petroleum 0.8 accumulations in Mesozoic rocks)

Fractile F99 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 F02 F01 F00 Numbers of Prospects in Play 11 12 13 14 15 15.56/1.76 16 17 17.5 18 18.5 19 22 Numbers of Pools in Play 1.43/2.06 3 4 5 6 7 7 13 Zero Pools at F39.25 Minimum Number of Pools 2 (F35) Mean Number of Pools 1.43 Maximum Number of Pools 13

POOLS/PSRK/PSUM Modules (Play Resources) Fractile F100 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 F02 F01 F00 Oil Recovery Factor (bbl/acre-foot) 1 17 21 30 43 47/25 59 69 77 89 105 120 218 Gas Recovery Factor (Mcfg/acre-foot) No Free Gas Gas Oil Ratio (Sol'n Gas)(cf/bbl) 56 162 195 267 376 426/220 531 638 723 871 1073 1100 1110 Condensate Yield ((bbl/Mmcfg) No Free Gas

Pool Size Distribution Statistics from POOLS (1,000 BOE): μ (mu)= 9.564 σ 2 (sigma squared)= 1.609 Random Number Generator Seed= 458,844

BOE Conversion Factor (cf/bbl) 5620 Probability Any Pool Contains Both Oil and Free Gas (Gas Cap) 0 Probability Any Pool is 100% Oil 1 Fraction of Pool Volume Gas-Bearing in Oil Pools with Gas Cap 0 Probability Any Pool is 100% Gas 0

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 F02 F01 F00 Prospect Area (acres)-Model Input* 4000 5537 13119 16454/12456 31082 92660 Prospect Area (acres)-Model Output** 1281 4235 5538 8339 13240 16493/11905 21097 27029 31445 39296 46000 50000 90285 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 0.4 0.45 1 Productive Area of Pool (acres) 108 523 696 1157 2008 2838/2846 3473 4615 5690 7550 9600 12000 30768 Pay Thickness (feet) 88 115 142 184 254 276/116 351 405 435 505 547 561 575 * 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 Prospect Level Chance 0.117 Exploration Chance 0.04095 Output Play Level Chance 0.3428

Risk Model Play Chance Petroleum System Factors Prospect Chance 0.35 Reservoir (granites fractured with weathering enhancement) 0.3 Source (mainly Tertiary coals and Type III shales) 0.65

Migration (fault migration paths must both transmit [deep] and seal [shallow]) 0.6

Fractile F99 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 F02 F01 F00 Numbers of Prospects in Play 24 26 27 29 32 31.99/3.62 33 34 36 38 40 42 48 Numbers of Pools in Play 1.31/2.10 3 4 5 6 7 8 15 Zero Pools at F34.28 Minimum Number of Pools 2 (F30) Mean Number of Pools 1.31 Maximum Number of Pools 15

POOLS/PSRK/PSUM Modules (Play Resources) Fractile F100 F95 F90 F75 F50 Mean/Std. Dev. F25 F15 F10 F05 F02 F01 F00 Oil Recovery Factor (bbl/acre-foot) 5 31 43 81 158 228/191 310 444 580 610 680 710 1000 Gas Recovery Factor (Mcfg/acre-foot) 3 27 38 73 146 218/193 290 420 541 620 695 730 1200 Gas Oil Ratio (Sol'n Gas)(cf/bbl) 56 162 195 267 376 426/220 531 638 723 871 1073 1100 1110 Condensate Yield ((bbl/Mmcfg) 1 1417212525/729323435373950

Pool Size Distribution Statistics from POOLS (1,000 BOE): μ (mu)= 9.814 σ 2 (sigma squared)= 2.170 Random Number Generator Seed= 599,626

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" Standard Mean Minimum Maximum f(x) Type Deviation 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 Water Oil Recovery Oil Volume Porosity Saturation Efficiency Factor [1/FVF] a Porosity 1-0.90.9 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" Standard Mean Minimum Maximum f(x) Type Deviation 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 Gas Water Gas Recovery Temperature Porosity Pressure (psi) Gas FVF (1/Z) Shrinkage Saturation Efficiency (ºRankine) Factor* a Porosity 1-0.9 0 0 0.800 b Water Saturation -0.9 1 0 0 -0.6 0 0 c Pressure (psi) 00 1 0 000.95 d Gas FVF (1/Z) 00 0 1 000 e Gas Recovery Efficiency 0.8 -0.6 0 0 1 0 0 f Gas Shrinkage Factor* 00 0 0 010 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" Standard Mean Minimum Maximum f(x) Type Deviation 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

Gas Recovery Factor (mcfg recoverable per acre-foot) Input Constant and @RISK Equation: "=1537.8*a2*(1-b2)*c2*d2*e2*(1-f2)/g2" Standard Mean Minimum Maximum f(x) Type Deviation 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

* 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" Standard Mean Minimum Maximum f(x) Type Deviation 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

Gas Recovery Factor (mcfg recoverable per acre-foot) Input Constant and @RISK Equation: "=1537.8*a2*(1-b2)*c2*d2*e2*(1-f2)/g2" Standard Mean Minimum Maximum f(x) Type Deviation 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

* 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" Standard Mean Minimum Maximum f(x) Type Deviation 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

Gas Recovery Factor (mcfg recoverable per acre-foot) Input Constant and @RISK Equation: "=1537.8*a2*(1-b2)*c2*d2*e2*(1-f2)/g2" Standard Mean Minimum Maximum f(x) Type Deviation a Porosity T-Normal b Water Saturation T-L-Normal c Pressure (psi) T-Normal d Gas FVF (1/Z) No Free Gas T-Normal e Gas Recovery Efficiency T-Normal f Gas Shrinkage Factor* T-L-Normal g Temperature (ºRankine) T-Normal

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

82 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" Standard Mean Minimum Maximum f(x) Type Deviation a Porosity T-Normal b Water Saturation Oil and Gas Yields From Literature Compilation and Analysis by T-L-Normal Paul Post and Jesse Hunt of U.S. Minerals Management Service, c Oil Recovery Efficiency T-L-Normal Gulf of Mexico OCS Region d Oil Volume Factor [1/FVF] T-Normal

Gas Recovery Factor (mcfg recoverable per acre-foot) Input Constant and @RISK Equation: "=1537.8*a2*(1-b2)*c2*d2*e2*(1-f2)/g2" Standard Mean Minimum Maximum f(x) Type Deviation a Porosity T-Normal b Water Saturation T-L-Normal c Pressure (psi) Oil and Gas Yields From Literature Compilation and Analysis by T-Normal d Gas FVF (1/Z) Paul Post and Jesse Hunt of U.S. Minerals Management Service, T-Normal e Gas Recovery Efficiency Gulf of Mexico OCS Region T-Normal f Gas Shrinkage Factor* T-L-Normal g Temperature (ºRankine) T-Normal

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

Table 14: 2006 Assessment Results for North Aleutian Basin OCS Planning Area Risked, Undiscovered, Technically Recoverable Oil and Gas Resources

Gas-Condensate BOE Resources Oil Resources Nonassociated* Gas Solution Gas Total Liquid Total Gas Resources Liquid Resources Ratio of (Mmboe) (Mmbo) Resources (Tcfg) Resources (Tcfg) Resources (Mmbo) (Tcfg) (Mmbo) Gas to Oil *** Play Play Name F95 Mean F05 F95 Mean F05 F95 Mean F05 F95 Mean F05 F95 Mean F05 F95 Mean F05 F95 Mean F05 Number Bear Lake-Stepovak 1 0 1400 3749 0 271 828 0 136 349 0.000 5.473 14.131 0.000 0.113 0.330 0 406 1176 0.000 5.586 14.461 71/29 (Oligocene-Miocene) Tolstoi (Eocene- 2 91 568 1293 9 62 139 10 61 141 0.401 2.476 5.640 0.003 0.025 0.053 19 123 280 0.404 2.501 5.693 78/22 Oligocene) Black Hills Uplift- 3 Amak Basin (Eocene- 0 210 1077 0 149 706 0 6 38 0.000 0.249 1.588 0.000 0.063 0.289 0 155 743 0.000 0.312 1.877 26/74 Miocene) Milky River Biogenic 4 Play 4 Assessed with Negligible Resources Gas (Plio-Pleistocene)

Mesozoic Deformed 5 Sedimentary Rocks 0 41 197 0 38 183 0 0 0 0.000 0.000 0.000 0.000 0.017 0.079 0 38 183 0.000 0.017 0.079 07/93 (Triassic-Cretaceous)

Mesozoic Buried Granitic Hills (Jurassic- 6 0 67 330 0 26 93 0 5 29 0.000 0.195 1.128 0.000 0.010 0.041 0 30 122 0.000 0.206 1.169 55/45 Cretaceous Magmatic Rocks) Sum of All Plays** 91 2287 6647 9 545 1948 10 208 556 0.401 8.393 22.487 0.003 0.229 0.791 19 753 2505 0.404 8.622 23.278 67/33

* Free gas, occurring as gas caps associated with oil and as oil-free gas pools.

** Values as reported out of Basin Level Analysis-Geologic Scenario aggregation module in GRASP , "Volume Ordered" aggregation option. Total liquids and total gas values were obtained by summing resource values for means and fractiles of component commodities. Play resource values are rounded and may not sum to totals reported from basin aggregation.

*** 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 summing to 100.

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 natural gas

84 Table 15: Conditional (Unrisked) Recoverable Pool Size Results for Play 1 - Bear Lake-Stepovak (Oligocene-Miocene) Classification and Size Pool Count Statistics Pool Type Counts Minimum Maximum Trials with Mixed Gas Pool Trial Oil Pool Class Size Size Percentage Pool Pool Pool Count Average Count (Mmboe) (Mmboe) Average Count Count 1 0.0312 0.0625 0 0 0 0 0 0 0 20.06250.1250 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 Not Classified 0000000 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

Table 16: Conditional (Unrisked) Recoverable Sizes of Ranked Pools for Play 1 - Bear Lake-Stepovak (Oligocene-Miocene) Pool Size in Millions of Barrels of Oil, Energy-Equivalent 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 3112025346493 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

85 Table 17: Conditional (Unrisked) Recoverable Pool Size Results for Play 2 - Tolstoi (Eocene-Oligocene) Classification and Size Pool Count Statistics Pool Type Counts Minimum Maximum Trials with Mixed Gas Pool Trial Oil Pool Class Size Size Percentage Pool Pool Pool Count Average Count (Mmboe) (Mmboe) Average Count 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 Not Classified 0000000 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

Table 18: Conditional (Unrisked) Recoverable Sizes of Ranked Pools for Play 2 - Tolstoi (Eocene-Oligocene) Pool Size in Millions of Barrels of Oil, Energy-Equivalent * 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 41641657194146191 51334545978122161 61129465168107142 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 Maximum Number of Pools = 44 * ranked as reported in PSRK module of GRASP

86 Table 19: Conditional (Unrisked) Recoverable Pool Size Results for Play 3 - Black Hills Uplift-Amak Basin (Eocene-Miocene) Classification and Size Pool Count Statistics Pool Type Counts Minimum Maximum Trials with Mixed Gas Pool Trial Oil Pool Class Size Size Percentage Pool Pool Pool Count Average Count (Mmboe) (Mmboe) Average Count 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 Not Classified 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

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 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 80.736 9112747 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

87 Table 21: Conditional (Unrisked) Recoverable Pool Size Results for Play 5 - Mesozoic Deformed Sedimentary Rocks (Triassic-Cretaceous) Classification and Size Pool Count Statistics Pool Type Counts Minimum Maximum Trials with Mixed Gas Pool Trial Oil Pool Class Size Size Percentage Pool Pool Pool Count Average Count (Mmboe) (Mmboe) Average Count 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 Not Classified 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

Table 22: Conditional (Unrisked) Recoverable Sizes of Ranked Pools for Play 5 - Mesozoic Deformed Sedimentary Rocks (Triassic-Cretaceous) Pool Size in Millions of Barrels of Oil, Energy-Equivalent 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 3261115204163 4 1 4 8 10 14 27 42 51357102031 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 90.413 3 5 914 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

88 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 Minimum Maximum Trials with Mixed Gas Pool Trial Oil Pool Class Size Size Percentage Pool Pool Pool Count Average Count (Mmboe) (Mmboe) Average Count Count 1 0.0312 0.0625 2 0.01528 0.0002 0.000584 0 0 2 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 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 15 16 1024 2048 22 0.16808 0.0022 0.00642 0 19 3 17 2048 4096 5 0.0382 0.0005 0.001459 0 5 0 18 4096 8192 4 0.03056 0.0004 0.001167 0 4 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 Not Classified 1 0.00764 0.0001 0.000292 0 0 1 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

Table 24: Conditional (Unrisked) Recoverable Sizes of Ranked Pools for Play 6 - Mesozoic Granitic Buried Hills (Jurassic-Cretaceous) Pool Size in Millions of Barrels of Oil, Energy-Equivalent 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 51369122846 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

89 Table 25: 2006 Economic Assessment Results for North Aleutian Basin OCS Planning Area Risked, Undiscovered, Technically and Economically Recoverable Oil and Gas Resources

OIL AND CONDENSATE FREE GAS AND SOLUTION BOE (Mmboe) SCENARIO (Mmbo) GAS (Tcfg) MPhc F95 Mean F05 F95 Mean F05 F95 Mean F05 Technically Recoverable (Petroleum 19 753 2505 0.404 8.622 23.278 91 2287 6647 1.00 Endowment)

Threshold or "Marginal" Prices ($2005, Mean Resource Case) Required for First Positive Economic Results = $14/barrel of oil and $2.12/Mcf of Solution Gas. The Threshold Price for Economic Non-Associated Gas = $3.63/Mcf.

Economically Recoverable at $18/Bbl 0 45 200 0.000 0.017 0.053 0 48 209 0.05 (Oil) and $2.72/Mcf (Gas)

Economically Recoverable at $30/Bbl 2 378 1371 0.001 0.909 2.780 3 539 1865 0.54 (Oil) and $4.54/Mcf (Gas)

Economically Recoverable at $46/Bbl 11 631 2180 0.132 5.852 16.548 34 1672 5125 0.90 (Oil) and $6.96/Mcf (Gas)

Economically Recoverable at $80/Bbl 19 738 2468 0.392 8.396 22.767 89 2232 6519 0.99 (Oil) and $12.10/Mcf (Gas)

ECONOMIC ASSUMPTIONS : 2005 base year; oil price is Alaska North Slope crude landed at U.S. West Coast; gas price is LNG delivered to U.S. West Coast; 0.8488 is gas value discountrelative to oil on a BOE basis; flat real prices and costs; 3% inflation; 12% discount rate; 35% Federal tax. TERMINOLOGY : Mmbo , millions of barrels of oil and condensate; Tcfg , trillions of cubic feet, gas; Mmboe , total oil and gas in millions of energy-equivalent barrels; Mean , resource quantities at the mean in cumulative probability distributions; F95 , the resource quantity having a 95-percent probability of being met or exceeded; F05 , the resource quantity having a 5-percent probability of being met or exceeded; The MPhc for technically recoverable resources is the probability that the assessment area contains at least one accumulation. The MPhc for the economic cases is the probability that the area contains at least one economic accumulation under the given economic conditions. For example, if the $30 case shows a MPhc of 0.22, then 2,200 out of 10,000 trials have at least one prospect with economically recoverable resources (oil or gas) at the given starting prices and other economic conditions. Resource quantities are risked (product of multiplying the conditional resources and MPhc).

90 156° 160° 164° 168° 172° 176° 180° 176° 172° 168° 164°160° 156° 152° 148° 140°144° 136° 132° 128° 124° 120° 116° 144° 148° 152° 112° Arctic Ocean 72° BASINS OF BERING SHELF 60° Beaufort Sea AND PACIFIC MARGIN OFFSHORE 70° Chukchi Sea BARRO W

68° 58° OCS Planning Area Boundaries RUSSIA NPR-A HOPE BASIN ANWR 66° KOTZEBUE BASIN 56°

64° ST. MATTHEW- NOME HALL BASIN CENTRAL C FAIRBANKS A

A NORTON ALASKA L N A

54° BASIN A S

D 62° K

NAVARIN North Aleutian Basin

BASIN OCS Planning Area COOK 60° Bering Sea ANCHORAGE 52° BETHEL INLET BASIN VALDEZ BERING N R SHELF E A T K E S S G 58° E A JUNEAU BASINS L N W A A R

50° ST. GEORGE A BASIN ay L DEEP ABYSSAL B U PACIFIC MARGIN ol S 56° st IN PLAINS OF THE ri N B E BASINS P BERING SEA KA AS AL KO D IAK AMAK 48° A ISLAND Gulf of Alaska le BASIN 54° ut ian Isla nds DUTCH HARBO R 46° NORTH 52° 50 0 150 ALEUTIAN NAUTICAL MILES Pacific Ocean 50 0 150 MILES Pacific Ocean 500 150 44° BASIN KILOMETERS 50° Sherwood\...\Fig01-LocationMap-NorthAleutianBasin.cdr 174° 178° 178° 174° 170° 166° 162° 158° 154° 150° 146° 142° 138° 134° Figure 1: Location map for North Aleutian basin and other Tertiary-age basins of the Bering shelf, Pacific margin, and southern Chukchi Sea.

Kuka L.

e Iliamna Lake Iliamna

L Pacific 1 Costello 1 Pacific 2 Costello 2

k Grammer 1 (Puale Bay) (Puale a Gas Shows Gas Oil Shows Oil

N Bear Creek 1 Oil Source Rocks Oil Triassic & Jurassic & Triassic * distribution of of distribution 156° Lake Brooks Lathrop 1 McNally 1 Alaska 1 Wide Bay 1 e k Jurassic Oil Source Rocks a L

f o r a h c e

King Salmon B

Naknek

e Lee 1

k a

Well, Plugged and Abandoned (18 1 well Onshore, 1903-1983; Wells offshore, 1983) Well, Plugged and Abandoned, Shows Oil with

L Abandoned,and PluggedWell, with Gas Shows Oil Seep. *Becharof Lake Seep. seep Oil *Becharof (see below) 92, $95.4 Sale (1988, Blocks Leased Leases);MM, Relinquished 23 & Inactive. Tertiary-Age (<65 Ma) Strata FeetThick >3,000

Gas Seep AK State, (2005, Leased Blocks Active. 37 Leases); $1.3 MM, Uplift or StructuralArch

k i

s Finnegan 1 a

g U EXPLANATION State of Alaska of State 2003 Proposed Licensing Area Koniag 1 Proposed “Pebble” Gold-Copper- Molybdenum Mine Great 2 Basins Oil Stain Oil Painter Creek 1 Great Basins 1 Oil Shows Gas ShowsGas

Lake 1 Outlines of proposed State of Alaska leasing and Alaska and leasing of State Outlines of proposed programs at licensing http://www/dog.dnr.state.ak.us/oil/products/product s.htm * Becharof Lake oil seep reported as “location seep reported oil Lake * as Becharof (1992, Biologic Anders Magoon andby unknown” tbl.sediments 13.1) andinmarkers petroleum,

Oil Shows Tested Gas 90 Mcfd Becharof

A 158° L

Ugashik 1 Ugashik

N I

Port 1 Heiden

N Chignik

Port Heiden A

State of Alaska of State S Licensing Area 2004 Contracted

L A 160° Big River 1 Sale Area Sale Oil Shows Oct 2005Lease Oct State of Alaska of State Sandy RiverSandy 1 Bear Lake Pacific Ocean Bay Balboa 92 Sand Point 92 (1988)92 leases (nowrelinquished and inactive), and regional ALASKA Top ProspectTop Port Moller Sale 92 Sale) (73%Sale of Collected $69.4 MM in MMCollected in $69.4 Bristol Bay Canoe Bay 1 Hoodoo 2 Lake Oil Shows 162° Bay Hoodoo 1 Lake Pavlof North Aleutian 1 COST Shelf Gas Shows Oil Shows Oil Tested Gas Tested Mcfd) (5-9 David River 1/1A Oil Shows Oil Staining Oil Cathedral River 1 Gas ShowsGas Sale 92 Sale $24.36 MM High BidTract

Cold Bay 164°

N I

N False Pass A I

R O N OCS Sale 92 Area 92 OCS Sale 58° 50 56° Jur-Cret OilJur-Cret Source Rocks? MILES Regional map for North Aleutian basin, with well control, Sale Sale control, well with basin, Aleutian North for map Regional St. George 2 COST E 1 Bertha .

T G \....\Fig02-Wells&Leases-NAB.cdr Shallow ShowsGas Bering Sea

S R 0 IN O S E A Monkshood 1 Monkshood G B Oil Show Sherwood Figure 2: Figure rocks. sedimentary Tertiary-age CDP SEISMIC DATA GRID (TWO-DIMENSIONAL)

NORTH ALEUTIAN SHELF COST 1 WELL

0 25 50 75 100 miles

ay B ol ist Br

Sale 92 (1988) la su in en P ka as Al

Sherwood\....\Fig03-NorthAleutianSeismicGrid.cdr 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.

93 144° 148° 152° 112° 156° 160° 164° 168° 172° 176° 180° 176° 172° 168° 164° 160° 156° 152° 148° 140°144° 136° 132° 128° 124° 120° 116° 72° BASINS OF BERING SHELF Arctic Ocean 60° 70° AND PACIFIC MARGIN OFFSHORE Beaufort Sea BARRO W Chukchi Sea 68°

58° RUSSIA NPR-A HOPE BASIN ANWR 66°

KOTZEBUE BASIN 56° 64°

ST. MATTHEW- NOME HALL BASIN CENTRAL C FAIRBANKS A

A NORTON ALASKA L N A 62°

54° BASIN A S

D Northern Cook K A A

Inlet Oil & Gas

?? NAVARIN

BASIN Province 60° Bering Sea 52° BETHEL COOK ANCHORAGE BERING INLET VALDEZ SHELF BASIN DEEP BERING SEA BASINS BASINS 58° JUNEAU 50° NORTH ?? KO DIAK ASK AL A S ALEUTIAN ISLAND F HE F O LF UL 56° BASIN G

F L PACIFIC MARGIN 48° ST. GEORGE E H BASIN S BASINS K DUTCH IA 54° D HARBOR O -K GIN Gulf of Alaska SHUMA 46° 52° Tertiary-Age Basins 50 0 150 NAUTICAL MILES Pacific Ocean 50 0 150 44° Distribution of Jurassic rocks after Mesozoic Basin with MILES 50° Imlay & Detterman, 1973, USGS PP 801 500 150 KILOMETERS

Sherwood\...\Fig04-RegionalDistributionJurassic.cdr Jurassic Oil Source Rocks? 174° 178° 178° 174° 170° 166° 162° 158° 154° 150° 146° 142° 138° 134° Figure 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. Distribution of Jurassic rocks after Imlay and Detterman (1973) and Worrall (1991).

Y T

L A

Kuka L. U B

N F I

e Iliamna Lake Iliamna k U

Pacific 1 Pacific 1 Costello 2 Pacific 2 Costello

L R

k e B

n Grammer 1 k

N , tbl., 13.1) Bear 1 Creek * 156° Lake Brooks rust structures do rust structures 3) Lathrop 1 1 McNally 1 Alaska Wide Bay 1 e k a L

r e

a i

King Salmon l

h i

c t n

e A Oligocene) (Upper “B” Horizon Bear of Base Approximate or Lake Fm.,(Subsea Depth in Feet) bounding faults Transtensional basement uplifts inNorth flanks along and basin Aleutian of Black Hills Uplift Leased Blocks (1988, Sale 92, Sale (1988, Blocks Leased Leases) 23 MM, $95.4 State, AK (2005, Blocks Leased 37 Leases) $1.3 MM, Thrust Faults, Folds and Duplex (Schematic Structures Locations) Affecting Tertiary StrataAlong South Flankof Basin Aleutian North

B i

Naknek h s

s parts western in uplifts nt

e 1 Lee

Great 1 Basins U k

k i

s 1 Finnegan

g U Koniag 1 ALASKA Great 2 Basins 4000 Painter Creek 1 Becharof Lake 1 Lake Becharof he basin. fold/th he basin. The

Ugashik 1 Ugashik 158°

L EXPLANATION

N Chignik

Port 1 Heiden I

N E

Port Heiden

Uplift or Structural Arch Structural or Uplift

Oil Seep. *Becharof Lake seep seep Lake *Becharof Seep. Oil below) (see Surface Anticline or Antiformal Antiformal or Anticline Surface Rocks in Mesozoic Duplex of Sense with Fault, Strike-Slip Displacement

Gas Seep Gas Tertiary-Age (<65 Ma)Strata Thick Feet >3,000 A Well, Plugged and Abandoned (18 well 1 1903-1983; Onshore, Wells 1983) offshore, Bruin BayFault andSubsurface on Based Projection Data Aeromagnetic

I -

K -

N S

A 0

B A I

* Becharof Lake oil seep reported as “location unknown” by Magoon and Anders (1992, Biologic markers in sediments and petroleuminBiologic(1992, sediments Anders and markers Magoonreported and by “location unknown” as seep Becharof Lakeoil * Structures Mesozoicin rocks from Dettermanal.et(1987), Detterman al et (1981), Wilson al. et (1995), and Riehle al. et (199 T

?? L

160° Y 0

0 U

L t

Sandy 1 River

O e

Big River1

H F

Bear Lake 0 T

0 I

5 R

0 R Bay

3 0 O

Balboa

t 95

Sand Point

0 e 3

Port Moller m

Bristol Bay a

t s Canoe 1 Bay Hoodoo 2 Lake

162° u

Pacific Ocean Pacific Bay o Hoodoo 1 Lake

Pavlof

c A North Aleutian North 1 COST Shelf uplift;fold/thrust3) and belts along the southeastof t margin David 1/1A River

6 Cathedral 1 River re gu Fi ?? Cold Bay 164°

N I

R A

F A

G I N

N B

A 0

L L

C K 0

O P

I 7

B A

N False Pass

E M L

H S

R A O 0 N L 2 0

9 0

L 6 e I l

a H 58°

0 K

0 O C

A L

0 B

5 56° MILES St. George 2 COST Principal geologic structures of the North Aleutian basin and contiguous areas, including: 1) transtensional faults and baseme and faults transtensional 1) including: areas, contiguous and basin Aleutian North the of structures geologic Principal Bertha 1 E . ....\Fig05-NorthAleutianStructures.cdr T G \ Bering Sea

S R 0 IN O S E A Monkshood 1 G B Sherwood Figure 5: Figure ofbasin; the2) wrench-fault structures the along Black Hills not appear to offshore extendFederal (>3 miles). into the SEISMIC LINE--NORTH ALEUTIAN BASIN BASEMENT UPLIFTS

Top Prospect--$69.4 MM in High Bids (73% of Sale 92) North Aleutian NORTHWEST SOUTHEAST Shelf COST 1 Sale 92 0 High Bid Tract 755 $24.36 MM 0

1.0

1.0 2.0

2.0

3.0

4.0

4.0 Time(s) Two-Way Two-Way Time (s) Time Two-Way

5.0

5 5

Regional

Shale Seal

Upper Eo cene Uncon formity-Hz D 10 10

Typical Top of Oil Generation Zone (0.6% Ro) at 12,312 feet

15 15 Paleocene-Top Basement? ? formity ene Uncon ? Lower Eoc

Pre-Tertiary Rocks (Cretaceous and

Depth (1,000Depth feet, subsea) Paleocene-Top Basement? ? Jurassic) representing accreted ? volcanic-plutonic arc terranes. Depth (1,000Depth feet, subsea)

? Liquid Floor (2.0% Ro) at 21,907 feet ssd

TD 17,15 5 ft Adapted from Figure 64, North Aleutian COST 1 well report, OCS Report MMS 88-0089Bear Lake-Stepovak (Oligocene-Oil Shows (Trace) Regional depths for thermal maturity zones are based on vitrinite reflectance Miocene) Play SequenceEarly Eo cene isograds pe netrated at the North Aleutia n Shelf C OST 1 well. The 1 .35% and 2.00% iso grads w ere no t pe net rated but are fo recast fro m the da ta set b el ow th e fa ult at Tols to i F m. 15,620 ft, with 647 ft added to forecast depths to correct for the fault gap. Gas Shows (Minor) Sh e rwo\...\Fig06-SeismicLineFig64-SS6.cdr o d Figure 6: Seismic profile through basement uplifts in western North Aleutian basin, showing Tertiary sedimentary sequences and basin structures. Profiles 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 available as plate 1.

96 MAGNETIC ANOMALIES AND MESOZOIC BASEMENT TERRANES NORTH ALEUTIAN AND ST. GEORGE BASINS Southern Bering Sea Shelf Adapted from Childs, Cooper and Wright, 1981, USGS Geoph. Inv. Map GP-939

162O O O Residual Magnetic Intensity O 164 167O 166 58 (gammas) >1,000

-800

OCS Sale 92 Sale 92 Leases North Aleutian Shelf COST 1

56O S T. G EO BA RG SIN E St. George dral Cathe COST 2 1 St. George River COST 1 LS HIL UPLIFT Monkshood 1 CK Bertha 1 A BL K B AMA ASIN

54O

0 50 MILES

Sherwood\....\Fig07-NorthAleutianMagneticMap.cdr Figure 7: Magnetic intensity map with offshore speculative extrapolation of the Bruin Bay fault. Adapted from Childs et al. (1981).

Figure 8: Mesozoic stratigraphy, Alaska Peninsula and substrate beneath southwest part of North Aleutian basin.

98 NORTH ALEUTIAN SHELF COST 1 WELL

FORMATIONS GEOLOGICAL PA LE O- SPONTANEOUS DEPTH DEEP FORMATION DENSITY SHOWS REGIONAL PLAY AGE BATHYMETRY PO TENTIAL (FEET BKB) RESISTIVITY POROSITY AND CORE POROSITY UNCONFORMITIES, SEQUENCES

GAMMA LOG (DenMA = 2.65 g/cc) SEISMIC HORIZONS, SEISMIC SEQUENCES RAY KB 85 ft as l SP WD 274 ft LITHOLOGY -80 ( Millivolts) 20 Seafloor= RES ISTIV ITY SANDSTONE POROSITY 2 ERA AGE GR 359 ft bkb 0.3 (Ohms m /m) 300 100 (%) -21 NONMARINE TRAN SITIONA L EPOCH INNER NERITIC INNER

PERIOD 100 OUTER NERITIC 0 ( API Units) 2030 MID DLE NE RI TIC 0 40 10 0

UNNAMED ? QUATERNARY 1000 SEISMIC SEQUENC E I PLEISTOCENE QUATERNARY 1590 ft 1.8 EARLY Ma

2000 4) (Play Gas MILKY RIVER LATE FORMATION SEISMIC HOR IZON EARLY Milky River Biogenic PLIOCENE ? 2700 ft 5.3 “A” (2510 ft) Ma 3000 LATE NEOG ENE

BEAR LAKE SEISMIC FORMATION 4000 SEQUENCE II MIOCENE Den sity Poro sity (Sandstone) EAR LY TOEARLATE? LY 4870 ft 23.8 Ma 5000 Ra ng e of Sa nd s ton e Porosity in Conventional Core SEISMIC HORIZON ? “B” (5675 ft) 6000 LATE

? SEISMIC SEQUENCE III 7000 Bear Lake - Stepovak (Plays 1, 3) 3) 1, (Plays Stepovak - Lake Bear PR OBA BLE

STEPOVAK FOR MATION SEISMIC HORIZON ? OLIGOCENE 8000 “C” (7900 ft)

9000 SEISMIC SEQUENCE IV PROBAEARLY BLE

33 .7 EAR LY Ma 10000 Top Oil Generation Zone at 10,372 ft 10380 ft LATE SP Floor/Effective Porosity at 10,380 ft SEISMIC HORIZON CENOZOIC GR (Only Microporosity >10,380 ft) “D” (10380 ft) LATE [Truncates Basement Uplifts] 11000 Top Ove r pr es sure

at 11,200 ft

12000 PALEOGENE Top Peak Oil Generatio n Zon e

(0.6 Ro%) at 12,397 ft

13000 SEISMIC MIDDLE TO LATE

SEQUENC E V (PlayTolstoi 2)

TOLSTOI FORMATION 14000 EOCENE

15000 Fa ult Cut at 15,620 ft md (Gap = 647 ft) ?

K-A r 16,028.5 ft 31.6 Ma 16000 Lower Eo cen e K-Ar Unc onformity 40.5 Ma EARLY TO MIDDLE TO EARLY K-A r Log TD 16,686 ft bkb Log TD 16,686 ft bkb L og TD 1 6,686 ft bkb 16,701 ft 47.1 Ma 17000 TD [17,155 ft in Eocene]

Formation correlations from Detterman, 1990, U.S. Geological Survey Open File 90-279, pl. 1. Time scale values from Palmer (1998). EXPLANATION K-Ar Radiometric Dates by Teldyne Isotopes (1983) Spl 136: 16,660-16,670 ft bkb; 40.5 +/- 10.3 m.y. Conglomerate, (Volcanic Fragments in Cuttings) Gas Show Shale Spl 137: 16,690-16,700 ft bkb; 47.1 +/- 18.3 m.y. Pebbly Sandstone (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) Oil Show Sandstone Coal Oil & Gas Siltstone Volcanics Show Sherwood\.....\Fig09-NorthAleutianStratColumn.cdr Adapted from Plate 1, Minerals Managment Service OCS Report MMS 88-0089 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.

Kuka L.

e Iliamna Lake

L 1 Pacific 1 Costello 2 Pacific 2 Costello

k 1 Grammer

N Bear Creek 1 156° Lake Brooks Lathrop 1 1 McNally Alaska 1 Wide Bay 1 e k ’ a L f o r a King Salmon h c e

Naknek

e Lee 1

Great Basins 1 k

A i

s Finnegan 1

g U Koniag 1 Horizon “B” (Upper Oligocene) or Approximate Base of Bear in Depth (Subsea Fm., Lake Feet) Strata (<65 Ma) Tertiary-Age >3,000 Feet Thick ALASKA Great Basins 2 AbandonedWell,Plugged (18 and Wells Onshore,well 1903-1983; 1 offshore, 1983)

Painter 1 Creek C

EXPLANATION A’

4000

Ugashik 1 C

158° I

Lake 1 C

Becharof O

(Northeast)

Chignik

N Port Heiden I

N S

6510 8870

5410 5460

2420 A

B A

N 0

0 L

A 7

200 A Port 2

160° 0

DEEP

Heiden 1 T Big River1 (Ohms m(Ohms /m)

RESISTIVITY

0.2 y U

Bear Lake

0 E

0 Bay 0 L

Balboa

0 Sandy River 1

Sand Point 0

3 KB 202 ft ASL ft 202 KB 20 Port Moller [TD 9,023 ft bkb ft [TD 9,023

Completed 1985 0

ic Ocean

0 f

Bristol Ba Bristol H 4 SP Ugashik 1, 1, and Ugashik

BECHAROF in Jurassic-Cretaceous in T aci Canoe Bay 1 Hoodoo Lake 2 162° LAKE 1 1 LAKE WELL -80

Hoodoo Lake 1 R Schist, Meta-Diorite, Meta-Gabbro) Meta-Diorite, Schist, O

David 1A 1, River N Cathedral River 1 S.L. A Datum 34 Miles Cold Bay 164°

Shelf 1 COST

North Aleutian N

A I

T S G

N I

N F A

+ N

A I

L B P

L 0

+ S

P K

39 7 m.y. 7 39 N

I 700 S

A U A

2600 3975 B False Pass

33 1.7 m.y. 1.7 33

I M

U S

200 E A

L 0 2 A L

H 0

T 0

R L O 6 I

DEEP N

58°

(Ohms m(Ohms /m) K 0

RESISTIVITY 0 0.2 C 0

A L 0

0 B 0

5 56° KB 145 ft ASL ft KB 145 Completed 1966 MILES [TD 9,476 ft bkb ft 9,476 [TD St. GeorgeSt. COST 2 Bertha 1 . E ....\StratCrossSectionLocationMap.cdr SP \ in Eocene Volcanics] Eocene in T G Bering Sea Bering S R IN 0 O S

-80 20 E A G B Monkshood 1 Sherwood UGASHIK 1 WELL 1 UGASHIK Radiometric (?) dates fromBrockway (1975) plate 3 . plate 48 Miles 48 Meshik Sea Level Datum Volcanics + + + 42 4 m.y. 4 42 43 4 m.y. 4 43 m.y. 4 42 5845 9120 2970 200 2 + DEEP + (Ohms m(Ohms /m) RESISTIVITY 36 36 8 m.y. 37.7 2 m.y. 2 37.7 0.2 KB 36 ft ASL ft 36 KB 1 WELL Completed 1972 20 [TD 15,015 ft bkb ft [TD 15,015 in Eocene Diorite] Eocene in SP PORT HEIDEN PORT -80

Radiometricdates (K-Ar) from Geochron(1969)

)

y t

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” m

i y

A ”

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“ n

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n c ” y Meshik Formation (Eocene Volcanics) Regional Shale Seal

Jurassic-Cretaceous Granites, Metamorphics

Interfingering at Boundary Facies

o t H

o e n i

D U

H n “

U m

e n r

n e

c o o

m 77 Miles o f

e o z s

H i n m

i c

en r

g o

Play s

e i

Sea LevelDatum c c

o c

i o l c

i i

S l

o Tolstoi H n

Milky River Milky P g

S c U i (

Play Sequence Play i

Sequence

l i e

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e n Play Sequence

O a

is e

L y

Bear Lake-Stepovak Bear e c ( l S o 100 E

ar e E t ( a (L EXPLANATION 6380 9840 2850 11330 12280 200 2 DEEP (Ohms m(Ohms /m) RESISTIVITY 0.2 Milky River Milky Sequence Play Play Tolstoi Sequence Bear Lake-Stepovak Sequence Play Regional Unconformity 20 KB ASL KB ft 255 1 WELL Completed 1963 SP [TD 13,068 ft bkb [TD 13,068 ft (Anderson et al., 1977b) al., et (Anderson in UpperEocene?] -80 SANDY RIVER SANDY O l available as 10 is of figure A full-scale version ula. a

O e y e t n i S 30Dip - 50 NW e c m r o e o l E f

n a y l o r h c a n S E U l 72 Miles a

Sea Level Datum Level Sea n

Milky River Milky o

1 Well to Alaska Peninsula Alaska to 1 Well COST Aleutian Shelf North i Play Play Sequence O

g Tolstoi Play Sequence Play e Sequence Bear Lake-Stepovak Bear 16028.5-16701 ft R Dip 20 Dip In Core (Between Cores 18 & 19) 18 Cores (Between Regional Stratigraphic Correlation Panel Regional Stratigraphic + + + 2510 9555 5675 300 7900 10380 31.6 31.6 2 m.y. 40.5 m.y. 10.3 47.1 m.y. 18.3 2 DEEP (Ohms m(Ohms /m) RESISTIVITY Water Depth 277 ft 0.3 100 Completed 1983 20 (Turner et al.,1988)(Turner KB 85 ft ASL,277 ft WD ft 85 KB [TD 17,155 ft bkb [TD 17,155 ft in Lower Eocene] Lower in GR (API Units) RAY SP GAMMA NORTH ALEUTIAN NORTH 0 (Millivolts) POTENTIAL SP GR SPONTANEOUS SHELF COST 1 WELL Radiometric (K-Ar) dates by Isotopes Teledyne (1983) -80

SurveyOpen File 90-279, pl. 1. Aleutian Shelf COST 1 well from from 1 well COST Shelf Aleutian Formation correlationsNorth for

Detterman, 1990, U.S. Geological Geological U.S. 1990, Detterman, (Play 4) (Play

Biogenic Gas Gas Biogenic Milky River River Milky Regional stratigraphic correlation panel for Tertiary sequence in North Aleutian Shelf COST 1, Sandy River 1, Port Heiden 1, Heiden 1, Port River Sandy 1, COST Shelf Aleutian North in sequence Tertiary for panel correlation stratigraphic Regional \.....\Fig10-StratCorrelation-NASwell-OnshoreWells.cdr A (Southwest) Adapted from an unpublished stratigraphic correlation 1990) ca. MMS, (fmr. Martin by G.C. prepared panel Sherwood Figure 10: Penins Alaska and basin Aleutian North wells, 1 Lake Becharof NORTH ALEUTIAN SHELF COST 1 WELL Statistical Summaries of Sandstone Bed Thickness Data

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 Percent of Sandstone Beds

UPPER TOLSTOI (7900-10380 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 PercentSandstoneBeds of

LOWER TOLSTOI (10380-16700 ft, log TD)

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 Percent ofSandstone Beds

Sandstone Bed Thickness (feet) 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

45 Porosity % = -0.0022[Depth] + 44.29 40 R2 = 0.6734 (n=312)

35 Floor Effective Porosity at 10,380 ft bkb (21.45% porosity)

15 Core Porosity % (Helium) Porosity Core 10 Milky River BiogenicSequenceMilky River Gas Play

5 Bear Lake-Stepovak Sequence Play TolstoiSequence Play Sherwood\....\Fig12-NorthAleutianCOST1CoreData.xls 0 0 2000 4000 6000 8000 10000 12000 14000 16000 18000 Depth (feet bkb)

Figure 12: Core porosity versus depth in the North Aleutian Shelf COST 1 well, with linear regression function for porosity decline with depth. All data from Core Laboratories (1983).

102 North Aleutian Shelf COST 1 Well Porosity vs Permeability Conventional Core Plugs and Percussion Sidewall Cores

10000

1000

100

1 Permeability = 0.0046e0.3423[Porosity %] R2 = 0.7466 (n = 288)

0.1 Core Permeability, millidarcys (Air) millidarcys Permeability, Core 0.01

Sherwood\....\Fig13-NorthAleutianCOST1CoreData.xls 0.001 0 5 10 15 20 25 30 35 40 45 Core Porosity % (Helium)

Figure 13: Core porosity versus permeability for sandstones, North Aleutian Shelf COST 1 well, with correlation. All data from Core Laboratories (1983).

103 North Aleutian Shelf COST 1 Well Permeability vs Depth Conventional Core Plugs and Percussion Sidewall Cores

10000 Tolstoi (Lower Tertiary) Play (2) 1000

100 Seismic Horizon "A"at 2,510 bkb ft 10 Bear Lake-Stepovak Play (1) 1 Floor for Effective Porosity (Only Microporosity > 10,380 ft) Permeability (Air), millidarcys (Air), Permeability

Permeability (md) = 14766e-0.0007317[Depth] SeismicHorizon "D" 10,380 at ft bkb 0.1 SeismicHorizon "C"at 7,900 bkb ft R2 = 0.4693 (n = 288)

Sherwood \....\Fig14-NorthAleutianCOST1CoreData.xls 0.01 0 2000 4000 6000 8000 10000 12000 14000 16000 18000 Depth, feet bkb

Figure 14: Core permeability versus depth for sandstones, North Aleutian Shelf COST 1 well, with function for permeability decline with depth. All data from Core Laboratories (1983).

104 North Aleutian Shelf COST 1 Well Core Porosity Histograms, Bear Lake-Stepovak and Tolstoi Play Sequences

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 Probability (%) Probability

Upper Tolstoi Play Sequence 7,900-10,380 ft bkb n = 139 Mean = 25.2950% Standard Deviation = 6.1564% 3% of Samples < 10% Porosity Probability

Normal Fit

Lower Tolstoi Play Sequence 10,380-17,155 ft bkb n = 84 Mean = 14.7679% Standard Deviation = 6.4896% 21% of Samples < 10% Porosity Probability (%) Probability Normal Fit

0 5 10 15 20 25 30 35 40 45 Core Porosity (%) Conventional and Percussion Sidewall Cores Sherwood\...\Fig15-NABPorosityHistograms.cdr 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 North Aleutian Shelf COST 1 Well Core Permeability Histograms for Bear Lake-Stepovak and Tolstoi Play Sequences

Bear Lake-Stepovak Play Sequence 2,510-7,900 ft bkb n = 80

Geometric Average = 168 md (Log10 = 2.22452)

Standard Deviation = 7 md (Log10 = 0.86774) Arithmetic Average = 713 md 1% of Samples < 1md 4% of Samples < 10 md Probability

Normal Fit

Log10 Permeability (md)

Upper Tolstoi Play Sequence 7,900-10,380 ft bkb n = 132

Geometric Average = 39 md (Log10 = 1.5924)

Standard Deviation = 14 md (Log10 = 1.1525) Arithmetic Average = 295 md 11% of Samples < 1 md 32% of Samples < 10 md Probability

Normal Fit

Log10 Permeability (md)

Lower Tolstoi Play Sequence 10,380-17,155 ft bkb n = 75

Geometric Average = 0.34 md (Log10 = -0.46913)

Standard Deviation = 19 md (Log10 = 1.2877) Arithmetic Average = 26 md 68% of Samples < 1 md 84% of Samples < 10 md

Normal Fit Probability

Log10 Permeability (md)

0.01 0.10 1.0 10.0 100 1,000 10,000 105 Permeability (Air, millidarcys) Sherwood\....\Fig16-NABPermeabilityHistograms.cdr 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%)

10 Isograd Depths As Penetrated/Forecast By Well (No Fault Gap Correction) Projection of lower Ro% trend to Ro% at base of upper 0.50 Ro% Top Early Oil Generation Zone at 10,372 ft bkb (Penetrated) sequence suggests a 647 ft gap at a normal fault 0.60 Ro% Top Peak Oil Generation Zone at 12,397 ft bkb (Penetrated) penetrated by the well at 15,620 ft bkb 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 Ma tter 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 Ro% (Below Ft Gap) = 0.0936e 0.00014345(Depth BKB) " " " R2 = 0.7361 (n = 10)

1 Cuttings 1.097% Ro Seismic "B Hz Seismic Hz "C Hz Seismic "D Hz Seismic Cuttings @ TD (17,155 ft bkb) SidewallCoreData b Conventional Core Data Conventional Core Data Fit to All Data

Vitrinite (%) Reflectance Fit to All Data Expon. (Cuttings)

Ro% [Above Ft Gap] = 0.1966e 0.00009(Depth BKB) ngular Unconformity ngular Unconformity A R2 = 0.9439 (n = 84) 16,028.5-16,701 ft bk Fault Gap (647 ft) at 15620 ft

Sherwood \...\Fig17-NorAleutCOST1VitRefData.xls 0.1 0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 Depth (feet, bkb)

Figure 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. All analyses prepared by Robertson Research (1983). Critical isograd values from Dow (1977a, fig. 3) and Waples (1980).

107 A E ALASKA R Iliamna Lake

N I Kuka L. N

A L

58° S 164° C N a kn e k L a k O e

N 162° Lake I Brooks S -7 ,0 A 160° -8 ,0 0 0 - B 0 0 6 , Bristol Bay 158° Great 0 0 N 0 A -8,426 ft Basins 2 B I e ch 156° - -9,612 ft a ro 9 ,0 0 f L a T Areas of Possible Gas, Condensate, and 0 Great k e U Basins 1 E Oil Generation (Sufficient Thermal -1 0 , 0 0 s L 0 e a k Becharof Lake 1 L A Maturity) within Tertiary-age strata of ik Alaska 1 Bear h -7,714 ft s g a Lee 1 U Creek 1 H North Aleutian and Amak Basins T Finnegan 1 -6,519 ft R -11 ,0 0 0 Grammar 1 O Ugashik 1 N +354 ft -1,267Wide Bay ft 1

F ig Painter u 0 r e Port Creek 1 0 6 ,0 North Aleutian -12,474Heiden 1 ft 1 Shelf COST 1 - 0 56° ,0 0 -1,007Koniag ft 1 -12,312 ft -1 2

-11 Sale 92 St. George ,0 0 0 High Bid Tract $24.36 MM Sandy EXPLANATION -12,323 ft Bear Well, Plugged and Abandoned, With Subsea Depth (feet) COST 2 River-10,050 1 ft Koniag 1 Lake to Top of Oil Generation Zone (0.6% vitrinite reflectance) -8,000 ft 0 0 -1,007 ft Hoodoo 4 ,0 Monkshood 1 -7,000 ft - - Lake 1 Big River 1 Leased Blocks (1988, Sale 92, $95.4 MM, 23 Leases) Bertha 1 1 2 ,3 1 2 (e s -3,428 ft Area of Possible Oil Generation (Sufficient Thermal t) Cathedral Hoodoo River 1 Lake 2 Maturity) from Tertiary-Age [<65 Ma] Strata within North Aleutian Basin). Uplifts in southwest part of North Canoe Aleutian basin are highly generalized. Bay 1 Lower Tertiary (33-39 Ma) Rocks Thermally Mature But Dominantly Volcanic or Plutonic (Meshik Fm.) David Tertiary-Age (<65 Ma) Strata >3,000 Feet Thick River 1, 1A -8,000 Depths (feet, subsea) to peak oil generation zone (corresponding to 0.6% vitrinite reflectance) Interpretation of North Aleutian COST 1 and Sandy River 1 Wells by K.W. Sherwood [2003]; 0 50 interpretation of onshore wells from Johnsson and Howell (1996, U.S. Geological Survey Bulletin 2142, plate 1) and Molenaar (1996a, same pub., figs. 3, 4, & 5). Area of oil generation MILES Pacific Ocean compiled from merging 0.6% Ro isograd structure (this map) with structure maps on seismic datums B, C, and D (Turner et al., 1988, MMS OCS Report MMS 88-0089, figs. 66, 67, and 68). Sherwood \....\Fig18-NorthAleutianBasinThermalMaturity.cdr Figure 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. The North Aleutian basin is segmented by a 33-39 Ma volcanic center that invaded the basin in the area of the Port Heiden 1 and Ugashik 1 wells, producing the volcanic flows and volcaniclastics of the Meshik Formation (age-equivalent to the Stepovak Formation).

108

Kuka L.

e Iliamna Lake Iliamna

k 0 a

N Grammar 1 Bear 1 Creek 156° Lake Brooks 0 Wide Bay 1 e k a L

f o 1 Alaska r a h

c of thermal e areas e

e 1 Lee

Great 1 Basins k

k i

s 1 Finnegan

g U Koniag 1 0 Great 2 Basins 474 1127 Painter Creek 1 204 Becharof Lake 1 Lake Becharof 577 Ugashik 1 Ugashik 158° All Volcanics EXPLANATION itrinite Reflectance). “+” Indicates Minimum Thickness Port 1 Heiden Leased Blocks (1988, Sale 92, $95.4 MM, 23 Leases) 23 MM, $95.4 92, Sale (1988, Blocks Leased V Because of Incomplete Penetration. Areaof Possible Oil Generation (SufficientThermal North within Strata Ma] [<65 Tertiary-Age Maturity)from Aleutian Basin). Uplifts in southwest part of North Aleutian basin are highly generalized. Well, Plugged andAbandoned, With Thickness (Feet) of RocksTertiary Within Oil Generation Zone (0.6% to 1.35% Lower Tertiary (33-39 Ma) Rocks Thermally Mature But But Mature Thermally Ma) Rocks (33-39 Tertiary Lower Dominantly Volcanic or Plutonic (Meshik Fm.) Leased Blocks (2005,AK State, $1.3 MM, 37 Leases) 0 ft Sediments 0 ft (All Volcanics) ALASKA 4,578+ Koniag 1 Interpretation of North Aleutian COST 1 and Sandy River 1 Wells by K.W. Sherwood [2003]; [2003]; Sherwood K.W. by Wells River 1 Sandy 1 COST and Aleutian of North Interpretation Survey Geological U.S. (1996, and Howell Johnsson from wells of onshore interpretation generation ofoil Area 5). & 4, 3, figs. pub., same (1996a, Molenaar and 1) plate 2142, Bulletin on seismic maps structure with map) (this structure isograd Ro 0.6% merging from compiled 68). and 67, 66, figs. MMS88-0089, Report MMSOCS 1988, al., et (Turner D and C, B, datums 160° Big River River 1 Big Sandy 1 River 2763 + Bear Lake 109 neration zone (0.6% 1.35%to vitrinite reflectance) with probabl Bristol Bay Hoodoo 2 Lake Canoe 1 Bay Hoodoo 1 Lake 162° 49+ Pacific Ocean Pacific 3,927 4,758 + Shelf COST 1 COST Shelf North Aleutian David 1A 1, River 1,713

6 re gu Cathedral 1 River Fi

164°

A Oil Condensate, and Gas, Areas Possible of

N Generation (Sufficient Thermal Maturity) within

B of strata AleutianAmak North Basins Tertiary-age and

R est. ~200 ft O 58° N 50 56° 728 MILES 140 Isopach map for thickness of Tertiary-age rocks within oil ge within rocks Tertiary-age of thickness for map Isopach St. George 2 COST Bertha 1 \....\Fig19-NorthAleutianBasinThicknessOilWindow.cdr 0 Monkshood 1 Sherwood Figure 19: maturity sufficientgenerationoil forand Aleutian beneathbasin. within North Cathedral River 1 Well Generation Potential (TOC) and Hydrocarbon Type (Hydrogen Index)

Total Organic Carbon (TOC, Wt.%) Hydrogen Index (mg S2/gTOC) 0123 0 100 200 300 400 500 THERMAL MATURITY 0 0 T.A.I. 2.5 Exlog-Cuttings Exlog-Cuttings NAKNEK FM. (UPPER JURASSIC) 2000 2000 FAIR VERY POOR GOOD GOOD

4000 4000 OIL GENERATION

SHELIKOF FM. (MIDDLE JURASSIC) 6000 6000 An oil-base additive (Soltex) was added to the drilling mud below 7,500 ft and may have contaminated cuttings samples

3.0

8000 8000 3.5 KIALAGVIK FM. (MIDDLE JURASSIC) DRY GAS DRY Depth (feet, bkb) GENERATION 10000 10000 3.8 1.47% Ro

TALKEETNA FM. 12000 (LOWER JURASSIC) 12000

14000 14000

KAMISHAK FM. GENERATION GAS

(UPPER TRIASSIC) OIL DESTRUCTIONAND (re-assigned to Jurassic OIL

by Mickey et al., 2005) GAS SOURCE SOURCE SOURCE GAS & & GAS OIL 16000 16000 3.8 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) Sherwood\...\Fig20-CathedralRiver1TOC&HIPlot.cdr 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 North Aleutian Shelf COST 1 Well Total Organic Carbon (% Wt.) Thermal Maturity 0.1 1 10 100 0 Exlog-Cuttings (Coal Retained); n = 60 Exlog-Conventional Cores; n = 62 Exlog-Sidewall Cores; n = 12 300 150 Robertson Research-Cuttings; n = 262 Robertson Research-Sidewall Cores; n = 121 Robertson Research-Conventional Cores; n = 139 2000 Exlog-Cuttings/Coal Removed (n=268)

Coal Sequence 4000

6000 VERY GOOD VERY 8000 Coal Sequence Coal

10000 Sequence Depth (feet, bkb)

12000

Coal Sequence 14000 Coal Sequence FAIR GOOD POOR 16000

18000 Total organic carbon data from Exlog (1983) and Robertson Hydrogen Index data from Exlog (1983) and Roberston Research (1983, Apps. III, IV). Source Rock Potential Research (1983, App. IV). Potential Hydrocarbon Type Classes from Peters (1986, AAPG 70/3, 320, tbl. 1). Classes from Peters (1986, AAPG 70/3, 320, tbl. 2, assume Ro=0.6%) Sherwood\....\Fig21-NoAleutianCOST1-TOC&HI.cdr 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 Coal-Bearing vs Coal-Free Cuttings & Core Samples Pyrolysis and Elemental Analysis

AB Type I (Oil)

Type II (Oil & Gas)

Range of Coal Compositions Source Type Classifications and Range of Coal Compositions from Peters (1986, AAPG Bull. 70/3, p. 318)

Separation of coal fragments from Type III (Gas) cuttings attempted by water flotation by Exlog (1983, p. 8)

C D

Algal Coals

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. Source Type Classifications adapted from Tissot and Welte This diagram plots H/C vs [O+S]/C and relationship to (1984, Pet. Fm. & Occ., 2nd Ed., Fig. II.4.14) for H/C vs O/C. classifications may be distorted by sulfur content. Area of This diagram plots H/C vs [O+S]/C and relationship to algal (e.g., boghead, cannel) coals from Tissot and Welte classifications may be distorted by sulfur content. (1984, p. 241, fig. II.8.8).

Sherwood \....\Fig22New-CoalySWCVanKrevelenDiagram.cdr Figure 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. The fields of the two data sets essentially overlap; (B) Sidewall and conventional core samples, with coal-bearing and coal-free samples plotted separately-all samples with HI>151 are described as coal-bearing; (C) Van Krevelen-type plot showing elemental data for sidewall and conventional core samples, with coal-bearing and coal-free samples plotted separately; (D) Van Krevelen-type plot with elemental analyses for all coal-bearing samples with HI>150 (shows that these samples are dominated by Type III kerogens). Tertiary rocks penetrated by the North Aleutian Shelf COST 1 well are all gas-prone and offer little potential for generation of oil. All core data from Robertson Research (1983, Apps. IV, VII).

112

GAS SEEPS, ALASKA PENINSULA

Carbon Dioxide

Iliamna Lake

Bering Sea A ALASKA

A Kuka L. 149 G

N I

N N Naknek 76 58° A L 164°

P King Nak nek La Salmon ke N I 162° Lake Brooks S T 149 L U A A 160° F B Y Bristol Bay 75 A B IN N 158° U Great R A Basins 2 B I B ec 156° ha Alaska T rof La 75 ke Triassic Oil U Great Lathrop 1 Basins 1 Source Rocks E McNally 1 Bear L Alaska 1 Peninsula Becharof Lake 1 es Creek 1 A ak L Tested Gas ik Lee 1 sh ga H 90 Mcfd U 2000 T Finnegan 1 Pacific 1 Gas Seeps e - in R - l Costello 1 t ic Fee N t 000 n 3, A A Pacific 2 O t < I Ugashik 1 en N k sem T I i Ba h Costello 2 stic U S s N cou a F A E A g Grammer 1 00 L B U Wide Bay 1 i 30 A 50 50 O g Y Port CS S H A ale 92 u T B Heiden r OR L Port Painter e North N TO Heiden 1 Creek 1 6 Aleutian Oil Shows S I C Oil Stain Jurassic Oil COST 1 Gas Shows R 0 R B 00 00 0 6 70 A Source Rocks 4000 00 IC 5 zoic N eso A Koniag 1 76 ic M LC 56° mat ent ic O Mag sem ozo V S Ba Mes E G T ary G E . ent ent N O St. George dim em A B R Prospect 11 collected Se Bas R A G COST 2 $69.4 MM in Sale 92 N S E Jur-Cret Oil (73% of Sale) A IN Sale 92 Sandy TI Source Rocks? High Bid Tract U Chignik $24.36 MM River 1 LE Bear Oil Shows A Lake Monkshood 1 HILLS Port Oil Show CK U Moller Bertha 1 LA PL Hoodoo Shallow B IFT Lake 1 Big River 1 Gas Shows 4000 Cathedral Hoodoo River 1 5000 Lake 2 AMAK B Oil Staining Oil Shows Cook Inlet ASIN Gas Shows 70 00 Canoe Balboa Bay 1 6000 Bay Oil & Gas Sand Cold Point Bay False Fields (n=23) Pass David River 1, 1A Oil Shows Tested Gas (5-9 Mcfd) 50

0 50 MILES Pacific Ocean Sherwood\....\AkPenGasSeepLocationMap.cdr, revised 24 July 03 Hydrocarbons Nitrogen + Oxygen+ Argon + Hydrogen + Hydrogen Sulfide + Helium

Sherwood\....\Fig23-GasSeeps&DataAkPen.cdr 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 Becharof Lake 1 Well Depth Profile for Methane Carbon Isotopes on Headspace Gas, Molecular Composition (and Inferred Isotope) for DST 5 Gas Sample

Methane Del C 13 (PDB) Thermal Maturity(Vitrinite Reflectance) 0 -90-70-50-30-1010 Separation of biogenic and thermogenic methane at 13 A -55.0 Del C (PDB) from Hunt (1979, p. 176) B 1000 Milky River Fm. 2000 BIOGENIC GAS FIELD 3000 Bear

) Lake b k Fm. Submature b , t ee (f 4000 h t p e D Stepovak Fm. 5000 DST 5

6000 7,470-7,550 ft 0.6% 7929 ft

BI OGENI C GAS Oil THERMOGENIC Tolstoi 1.3%

THERMOGENI CGAS Fm. 8420 ft GAS FIELD Gas 1.77% Ro at TD at 9017 ft 2.0% 9251 ft (proj. 7000 Jurassic-Cretaceous Liquid floor) Plot classification fields from Schoell (1984) Plutonic Rocks and Claypool and Kvenvolden (1983) 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). Sherwood\....\ Fig24-BecharofLakeCarbonIsotopes.cdr Figure8000 24: A) Methane carbon isotope data for Amoco Becharof Lake 1 well. Gas is biogenic above 3,000 feet, and thermogenic below 5,500 feet. Both types of gas are mixed in the intermediate interval from 3,000 to 5,500 feet. Data from AOGCC (1985, Carbon Isotope Ratios). B) Gas recovered from a flow test of the 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” (AOGCC, 1985, DST data) and classifies as thermogenic in cross-plot of Schoell (1984) and Claypool and Kvenvolden (1983). 9000

10000 114 NorthAleutianCOST1Well Interpretation of Depositional Environment and Thermal Maturity Extracts From Show Interval 15,300 to 16,800 ft bkb 10 2003 Baseline-DGSI Data 1983 Robertson Research Data ter O n at R x tio M e id ra ic d iz u an u i at rg s c n M O nt in g s e g ou nm en iro rig v es er En rc T al ou o S l) -C ic ria at an te 1 Pe rg ac O l/B ion ed ga at ix Al d M r ( ra

Pristane/n-C17 e g att de M io Thermal maturity of show nic B ga interval = 0.78% to 1.04% r vitrinite reflectance e O rin Ma Plot fields from Shanmugam (1985, AAPG Bull., 69/8, 1241, fig. 4) 0.1 0.1 1 10 Phytane/n-C18 Sherwood\....\ Fig25-NABCOST1-ExtractDepositionalEnvironment.cdr Figure 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. A terrigenous, coal-bearing depositional environment is indicated, consistent with a source within Tertiary nonmarine rocks. All data from Baseline DGSI (2003) and Robertson Research (1983).

115 PRISTANE/PHYTANE RATIOS FOR EXTRACTS FROM NORTH ALEUTIAN SHELF COST 1 WELL AND COOK INLET OILS AND EXTRACTS

North Aleutian Basin COST 1 Eocene Nonmarine-Tolstoi Formation Show Interval (15300-16800 ft bkb) Extracts s le amp Mean = 4.25

f S (n = 9) o n tio c ra F

Tertiary (Nonmarine) Extracts & Oils Cook Inlet Basin s le Mean = 5.76 (n = 7) amp f S o n tio c ra F

Mesozoic (Marine) Extracts & Oils Alaska Peninsula & Cook Inlet Basin 1.4 Mean = 2.91 s 1.2 (n = 32) le

1.0

Data for North Aleutian Basin COST 1 well by amp Robertson Research for ARCO (1983) and by 0.8 Baseline-DGSI for Minerals Management Service (2003). All other pristane/phytane data from Magoon

f S and Anders (1992)

o 0.6 n

0.4 tio c

0.2 ra F

0.0 0 2 4 681012 Pristane/Phytane Sherwood\...\Fig26-NAB-Extracts-Pristane-PhytaneRatios.cdr 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 -25.0 North Aleutian COST 1 Well, Alaska Peninsula, and Cook Inlet

Data for North Aleutian Basin COST 1 well by Baseline-DGSI for Minerals Management Service -26.0 (2003). All other isotope data from Magoon and Anders (1992) ils O e in ar m on N -27.0 ils O Tertiary Nonmarine Oils e in and Rock Extracts ar M

-28.0

North Aleutian Shelf COST 1 Well Extracts -29.0

North Aleutian COST 1 Well Extracts 15700-16800 ft Alaska Peninsula Oil Seeps [Mesozoic Rocks] -30.0 Tertiary (Nonmarine) Rock Extracts

Aromatic Fraction Carbon Isotope Composition Jurassic (Marine) Rock Extracts Jurassic and Triassic Tertiary (Nonmarine) Oil and Condensate Sofer Marine Oils and Rock Lines Mesozoic-Sourced (Marine) Oils Extracts Triassic (Marine) Rock Extracts -32.0 -31.0 -30.0 -29.0 -28.0 -27.0 -26.0 -25.0 -31.0

Saturate Fraction Carbon Isotope Composition Sherwood \.....\Fig27-NAB-Extract-Carb onIsotopes-SoferPlot.cdr Figure 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. 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).

117 SATURATES, AROMATICS, AND NON-HYDROCARBONS A North Aleutian Shelf COST 1 Well, Alaska Peninsula, and Cook Inlet Extracts and Oils EXPLANATION MMSAK2003-1 Baseline-DGSI rock extracts from core and cuttings composite samples, North 100% SATURATES 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 Data for North Aleutian Shelf COST 1 well by Peninsula and Cook Inlet (n = 9) Robertson Research for ARCO (1983) and by Baseline DGSI for Minerals Management Service Tertiary (Nonmarine) Condensates (2003). All other liquid chromatograph data from from northern Cook Inlet (n = 2) Magoon and Anders (1992) Oil Seeps, Alaska Peninsula near Becharof Lake (n = 2) Mesozoic Mesozoic (Marine) Oils and Condensates from (Marine) northern Cook Inlet (n = 18) Oils Upper MMSAK2003-2 5 (Cuttings) 0 Triassic 50 (Puale Bay) Extracts

RR-7 Middle Jurassic RR-4 (Cook Inlet & Puale Bay) Extracts

RR-5 RR-3 RR-6

Tertiary (Cook Inlet) RR-2 Extracts MMSAK2003-1 (Core)

RR-1 50 100% AROMATICS 100% NON-HYDROCARBONS*

NON-HYDROCARBONS: NSO’s + Asphaltenes (North Aleutian Basin COST 1 Extracts) Resins + Asphaltenes (All Other Data for Extracts & Oils) Sherwood\...\Fig28a-TrianglePlot-Sat-Aro-NSO.cdr

STERANE RATIOS B North Aleutian Shelf COST 1 Well Extracts

C27 STERANES Sample MMSAK2003-1 (Core Chips, 16,006-16,720 ft)

B CABB S (218), C27-C28-C29 Steranes A CAAA R (217), C27-C28-C29 Steranes

Sample MMSAK2003-2 (Cuttings, 15,700-16,800 ft)

B CABB S (218), C27-C28-C29 Steranes

A CAAA R (217), C27-C28-C29 Steranes PLANKTON

Facies classifications after Huang and Meinschein (1979, Geochim. Cos. Acta, 5 v.43, 739) 0 50 OPEN MARINE

A B B A ESTUARINE

TERRESTRIAL HIGHER LACUSTRINE PLANTS

50 C28 STERANES C29 STERANES

Sherwood\...\Fig28b-TrianglePlot-Steranes.cdr Sherwood\....\Fig28-TrianglePlots-Sats-Aroms & Steranes.cdr 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 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)

Thermal Maturity of Show Interval: 0.78% to 1.04% Vitrinite Reflectance

B. Show Interval Extract: (Sample MMSAK2003-2: Cuttings, 15,700 to 16,800 ft bkb, Composited)

Unidentified Peak

Thermal Maturity of Show Interval: 0.78% to 1.04% Vitrinite Reflectance

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 North Aleutian Shelf COST 1 Well Lopatin Burial History Model and Critical Events Timelines

CENOZOIC O DEPTH DEPTH (ft bkb) PALEOCENE EOCENE OLIGOCENE MIOCENE PLIO. Q. (ft bkb) Cret. PLAY Early Late Early Middle Late Early Late Early Middle Late E L (Ro%)

65.0 28.5 11.2 VITRINITE 61.0 54.8 49.0 37.0 33.7 23.8 16.4 5.3 3.6 1.8 OBSERVED SEQUENCE SUBSURFACE PRESENT-DAY REFLECTANCE 60 50 40 30 20 10 0 MODELED TTI & EQUIVALENT Ro% 0 ( TEMPERATURE F) 0 SEISMIC HZ A MR Q

F a (Early Pliocene) u lt B 1000 G as 60 1000 a e B ?? p To e p ar ( S L 6 te ak B 4 p e 7 S ov F a E a m 4) (PLAY f k . s t ( IS F ) L m SEQUENCE 2000 e a M . 2000 Thickness of a t IC MILKY RIVER t e o 1 O H f li Z sedimentary 5 go B W ,6 c 2 en 0.25 column beneath e 0 e B ) 80 l f l t Tolstoi a 3000 3000 base of well is ( s F T e unknown, but a Fm. o u p S l may range up to ?? t t T G e 3,000 feet o p S 100 4000 a l E 4000 p s o (E IS - t v a M o r I C a ly C E i k O H o l Z ( s r F ig C U F o B t r m c i e m e a n m n 5000 c . e) 120 5000 s k a t . t e e n e L d m o d a ) t w B e e n n a P 6000 s 6000 t a M e l 140 N e S e o o E 0.35 o f IS s c M S e (L I

t C BEAR LAKE-STEPOVAK o at SEQUENCE (PLAYS 1, 3) P e n e E HZ 7000 z d e oc D 7000 e o i B e n m n i e e) c e e l 160 n o t ( r G t w a a r 0.40 8000 t r y W 8000 e a F e d n l i l ) i l ? Ro b t l % i 0.5 180 y c =3 (~ ? TI C T 9000 ) 9000 O IL R LY O 0.45 S o EAR ON T c ATI ER W k EN 200 10000 s G 10000 e ?? ) 3 l Ro l .6% 0.50 ) 0 (~ 0 (0.50% Ro) TTI=1 11000 220 11000 0.55 TTI-Ro Correlations 12000 ?? Fa 10 12000 ul t G (0.60% Ro) 240 2) (PLAY TTI Ro% Maturity PEAK OIL ap 0.60 3 0.50 Shallowest Top Oil Generation GENERATION 13000 13000 10 0.60 Top Peak Oil Generation Zone Ro) TOLSTOI SEQUENCE 75 1.00 Peak Oil Generation ?? 1.0% 260 75 (~ 92 1.07 Peak Wet Gas, Top Dry Gas Gen. TTI= 14000 180 1.35 Base Oil Generation Zone 0.70 14000 900 2.00 Liquid Floor 280 ) 75 Ro 0.75 (1.00% Ro) 15000 .07% 15000 1 ta (~ ell Da 92 om W 0.80 92 I= Ro Fr TT 1.00% ? (1.07% Ro) 300 o) ???? Ft Gap 16000 5% R GAS (647 ft) 16000 1.3 o 0 (~ % R 0.88 180 18 1.00 d) GEN. TI= f. = tche 0.92 (1.35% Ro) T . Re -Ske 320 17000 l Vit and 21.2 17000 ctua th H 1.00 324 A d Pa Ma? Drilled TD at ogra ?? 1.07 at TD 17,155 ft bkb (Is ) (17,155 ft bkb) Ro 1.097 567 18000 0% 18000 2.0 at TD at TD (~ (Corrected, (1.80% Ro) 900 17,802 ft bkb) TI= 19000 T 900 19000 1.35 (2.00% Ro) ?? (Proj.) 20000 20000

Software: Lopatin-From Here to Maturity, ver. 1.0, 1985, by Platte River Associates, Inc., and D. Gap-Corrected Fault ft bkb 17,802 at TD 21000 21000 Waples.Geologic time scale from Palmer (1998). TTI thresholds from Waples (1980, AAPG, Basin Floor 64/6, p. 916). TTI calculations and Ro data do not correlate below 15,000 feet md. at 20,800 ft (Est) 22000 2.00 22000 (Proj.)

TIMELINES--CRITICAL PETROLEUM SYSTEM EVENTS FROM BURIAL MODEL MODEL INPUT DATA Today

Hz “D” 28.5 Ma Deposition Bear Lake/Stepovak 4.5 Ma

3.0 61+ Ma Traps Form on Flanks of Basement Horsts Traps Form in Drape Anticlines Over Basement Horsts (Rifting, Horst Elevation) (Compaction, Drape Folds, Minor Faulting) Ma? 35.4 Ma 38.5 Ma? Early Oil Generation (TTI>3) (Basin Floor [Est]) 31.7 Ma (Base of Well, Corrected for Fault Gap)

34.4 Ma ? Peak Oil Generation (TTI>10) TTI=75 (Basin Floor [Est]) 27.0 Ma 17.3 Ma (Base of Well, Corrected) (Base of Well) Deeper Results from Lopatin Model Not Supported by Well Thermal Maturity Data

24.2 Ma ? End of Oil Generation; Main Gas Generation (TTI>180) (Basin Floor [Est]) 7.7 Ma (Base of Well, Corrected for Fault Gap) 10.0 Ma ? Liquid Floor (TTI>900) (Basin Floor [Est]) Today Sherwood\....\Fig30-BurialHistory-NAB-COST1.cdr Figure 30: Burial history plot for North Aleutian Shelf COST 1 well, with timelines for critical petroleum system events.

120 A. Petroleum System Elements for North Aleutian Basin Amak Basin Black Hills Uplift North Aleutian Basin

NON-SEALING OVERBURDEN SEISMIC HORIZON “A”

PRINCIPAL RESERVOIR SEQUENCE

SEIS MIC HO RIZON “B” N O I S T M E A IG ISM IC R DISRUPTED R HO A R G T S IZO I IO EIS N “ OIL POOLS N M C” M REGION IC H AL OR IZON SEA “D L ” + + + + + + + THERMALLY-MATURE H Top Oil & Gas Generation Zone + + + + + + + + z “D (POST-GENERATIVE) B ” AS + Fractures + + + MESOZOIC ROCKS EM + + + EN GAS/COND + T U + + + + NC KITCHEN GAS/COND+ + ON + + FO KITCHEN+ + + RM + + +B ITY + sm + + + + +t + + + + + + + + + + GRANITIC + + ROCKS BRUIN BAY FAULT?? Adapted from unpublished drawing by G.C. Martin (ca. 1990) Sherwood\...\PetroleumSystemElements.cdr

B. Play Concepts for North Aleutian Basin Amak Basin Black Hills Uplift North Aleutian Basin

Milky River Play [4] (Biogenic Gas) Milky River Play [4] (Biogenic Gas)

SEISMIC HORIZON “A” Black Hills Uplift- Amak Basin Play [3] Bear Lake-Stepovak Play (Oil and Gas) [1] (Oil and Gas)

S EISMIC HORIZ ON “B” SE ISMIC HOR IZON SE “C” ISM IC H OR IZO Tolstoi Play [2] N “D” + + +++ + + (Oil and Gas) Mesozoic Deformed + + + + + + + + BA Fractures + + + H Sedimentary Rocks SE Tolstoi Play [2] + z “D” ME + + + + Play [5] (Oil) NT (Oil and Gas) + + + UN + CO + + + NF + B O + + + sm RM + t ITY + + + + + Mesozoic Buried + + + + + + Granitic Hills Play [6] + + + + + + + + + (Oil and Gas) BRUIN BAY FAULT?? Adapted from unpublished drawing by G.C. Martin (ca. 1990) Sherwood\...\PlayConcepts-CrossSection.cdr 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.

121

Kuka L. A F

e Iliamna Lake Iliamna

k N

a I

L U

k R

e n B

k (Puale Bay) (Puale a Gas Shows Gas Bear Creek 1 N Oil Shows Grammar 1 Oil Source Rocks Source Oil Triassic & Jurassic & Triassic * 156° Lake Brooks Wide Bay 1 e k a L

f o 1 Alaska r a h c e

e 1 Lee

Great 1 Basins k

k i

s 1 Finnegan

g U Jurassic OilJurassic Rocks Source Koniag 1 Painter 1 Creek Great 2 Basins Uplift or StructuralUpliftArch or Well, Plugged andAbandoned Oil Seep. *Becharof Lake below) (see seep LeasedBlocks (1988, Sale 92, Leases) 23 MM, $95.4 Leased Blocks (2005,AK State, $1.3 MM, 37 Leases) Seismic Profile Gas SeepGas EXPLANATION Tested Gas Tested 90 Mcfd Oil Shows Becharof Lake 1 Lake Becharof 6

e r

A g

Ugashik 1 Ugashik i 158° L

ALASKA

Biologic markers in sediments and petroleum, tbl. 13.1) tbl. Becharof* petroleum, Lakeand oil seepreported sediments as“location in unknown” markers by Magoon Anders and (1992,Biologic U

Port 1 Heiden

s N

I a

c t

s B 0

o k

0 e c

z s

7 c o

c o

o e

e o

r s

160° t T 0 a

0 e

i Big River1 a

L t 0

n z

A 0

o 4

Oil ShowsOil Sandy 1 River

i e

Bear Lake

R 0 e

S 5

i O

a N

0 g

122

3 M Bristol Bay Oil Shows Hoodoo 2 Lake Canoe 1 Bay Hoodoo 1 Lake 162° Top ProspectTop collected $69.4MM in Sale) of (73% 92 Sale Pacific Ocean Pacific Gas Shows Gas Oil ShowsOil North Aleutian COSTShelf 1 Tested Gas Tested Mcfd) (5-9 David 1A 1, River Oil Shows Sale 92 Sale Tract High Bid $24.36 MM

6 re Oil Staining Cathedral 1 River gu Shows Gas Fi (Oligocene-Miocene) 164°

N I

S T

A F I B

L 0

R P K 0 A

G 7 N

N U A

S FMS. BEAR 1: LAKE-STEPOVAK PLAY

C M O

I S

A B 0

N L

I 0

U 0 E

L L

H I

R O

N H

58°

0 K

C 50

A L

0 B

5 56° Jur-Cret Oil Rocks? Source E MILES

G Alaska. Area, Planning OCS Basin Aleutian North play, Lake-Stepovak Bear 1, play of Area

St. George 2 COST R Bertha 1 O N I E \....\Fig32-Play1BearLakeMap.cdr S Shallow Gas Shows G 0 A . B T Monkshood 1 S Oil Show Sherwood Figure 32: ALASKA Iliamna Lake

Kuka L.

E 58° R 164° A

N ak G nek Lake N I N 162° Lake N Brooks A LT L U A P 160° F Y S Bristol Bay A B C IN 158° U O Great R B N Basins 2 I B ech 156° S a ro f La A Great k e B Bear Basins 1 N CreekOil Shows 1 A * Gas Shows I es T PLAY 2: TOLSTOI FM. k Becharof Lake 1 La ik Alaska 1 U Tested Gas h a s Lee 1 E 90 Mcfd U g L (Eocene-Oligocene) Oil Shows A Finnegan 1 H Jurassic Oil T Source Rocks Grammar 1 R IN Ugashik 1 O A S N N B Wide Bay 1 T IA Triassic & Jurassic F U Oil Source Rocks ig LE Painter u A (Puale Bay) r North Aleutian Port Creek 1 e T H 6 ShelfOil Shows COST 1 R Gas Shows N O en t Heiden 1 A a s em L Top Prospect ic B S U collected $69.4 MM in oz o t N Sale 92 (73% of Sale) M e s e n I Koniag 1 56° atic a se m E N a g m o ic B P M e so z K A S ry M S T e n ta LA . G e d im A E Jur-Cret Oil Sale 92 S B O St. George A R Source Rocks? High Bid Tract Sandy S COSTG 2 $24.36 MM Oil Shows IN E Bear River 1 Lake K H ILL S Oil Show L A C U P L MonkshoodShallow 1 B IF T Hoodoo Gas ShowsBertha 1 Lake 1 Big River 1 EXPLANATION A M A K B CathedralOil Staining AS I Gas Shows HoodooOil Shows N River 1 Lake 2 Well, Plugged and Abandoned Gas Seep Canoe Oil Seep. *Becharof Lake Bay 1 seep (see below)

Uplift or Structural Arch Leased Blocks (1988, Sale 92, OilDavid Shows RiverTested 1, Gas 1A $95.4 MM, 23 Leases) (5-9 Mcfd) Leased Blocks (2005, AK State, $1.3 MM, 37 Leases) F ig u re 6 0 50 Seismic Profile * Becharof Lake oil seep reported as “location unknown” by Magoon and Anders (1992, MILES Pacific Ocean Biologic markers in sediments and petroleum, tbl. 13.1) Sherwood \....\Fig33-Play2TolstoiFmMap.cdr Figure 33: Area of play 2, Tolstoi play, North Aleutian Basin OCS Planning Area, Alaska.

123

Kuka L. A F

e Iliamna Lake Iliamna

k N

a I

L U

k R

e n B

k (Puale Bay) (Puale a Gas Shows Gas Oil Shows N Bear Creek 1 Grammar 1 Oil Source Rocks Source Oil Triassic & Jurassic & Triassic * 156° Lake Brooks Wide Bay 1 e k a L

f o 1 Alaska r a h c e

e 1 Lee

Great 1 Basins k

k i

s 1 Finnegan

g U Jurassic OilJurassic Rocks Source Koniag 1 Painter 1 Creek Great 2 Basins UpliftStructural or Arch Well, Plugged andAbandoned Lake *Becharof Seep. Oil below) (see seep 92, Sale (1988, Blocks Leased Leases) 23 MM, $95.4 Leased Blocks (2005, AK State, State, AK (2005, Blocks Leased 37 Leases) MM, $1.3 Seismic Profile Gas Seep Gas EXPLANATION Tested Gas Tested 90 Mcfd Oil ShowsOil Becharof Lake 1 Lake Becharof

ALASKA

r A u

Ugashik 1 Ugashik g 158° L i

U 13.1) tbl. (1992,Anders Magoonand reported by “location unknown” as seep Becharof Lake oil petroleum, * and sediments in markers Biologic

Port 1 Heiden A

A n

L e

I a

c A

s B

m z

s o

e R

N o

c o

i s

I e

o r

e B

160° t

M r

y i

o E

a Big River1

o n

t ShowsOil Sandy 1 River e

H m e

Bear Lake

F c

R i

0 S

O a

N m

g 3

a <

124

m e

Bristol Bay

B Oil Shows Hoodoo 2 Lake

c i

Canoe 1 Bay t

Hoodoo 1 Lake 162° s Top ProspectTop collected $69.4MM in Sale) of (73% 92 Sale Pacific Ocean Pacific

Gas Shows Gas u Oil Shows

Shelf COST 1 COST Shelf

o Aleutian North

c A Tested Gas Tested Mcfd) (5-9 David 1A 1, River Oil Shows Sale 92 Sale Tract High Bid $24.36 MM North Aleutian Basin OCS Planning Area, Alaska.North AleutianOCS Planning Basin

6 e

r Oil Staining Cathedral 1 River gu Shows Gas Fi 164°

N I

S T

A F I

R P K A

N U A

C BLACK 3: HILLS PLAY BASIN UPLIFT-AMAK M O

I S

A B

N L A

L L

H I

R O

N H

58°

C 50

L B 56° Jur-Cret Oil Rocks? Source E MILES

G Basin,playHills Uplift-Amak 3, Black Area of

St. George 2 COST R Bertha 1 O IN E \....\Fig34-Play3BlackHillsMap.cdr

S Shallow Gas Shows G A 0 . T B Monkshood 1 S Oil Show Sherwood Figure 34: ALASKA Iliamna Lake

Kuka L.

E 58° R 164° A

N ak G nek L ake N I N 162° Lake N Brooks T A L L U A P 160° F Y S Bristol Bay A B C IN 158° U O Great R B N Basins 2 I B ech 156° S a ro f La A Great k e Bear B Basins 1 Creek 1 N Oil Shows A I PLAY 4: MILKY RIVER BIOGENIC * Gas Shows s ke T Becharof Lake 1 L a ik Alaska 1 U Tested Gas h as Lee 1 E GAS (Plio-Pleistocene) 90 Mcfd U g L Oil Shows A Finnegan 1 H Jurassic Oil T Source Rocks Grammar 1 R IN Ugashik 1 O A S N N B Wide Bay 1 T IA Triassic & Jurassic F U ig E Painter Oil Source Rocks u L r North Aleutian A (Puale Bay) e H Port Creek 1 Oil Shows T 6 Shelf COST 1 R Heiden 1 Gas Shows N O en t A s em L Top Prospect c B a S U collected $69.4 MM in z o i t N Sale 92 (73% of Sale) s o en I Koniag 1 56° c M e s em N m a ti c B a P E M a g o zo i A M e s K S T tary A S . G im e n A L E Jur-Cret Oil S e d B O St. George Sale 92 A R Source Rocks? High Bid Tract Sandy S COSTG 2 $24.36 MM Oil Shows IN E Bear River 1 Lake K H IL L S Oil Show L A C U P L MonkshoodShallow 1 B IF T Hoodoo Gas ShowsBertha 1 Lake 1 Big River 1 EXPLANATION A M A K B CathedralOil Staining AS IN Gas Shows HoodooOil Shows River 1 Lake 2 Well, Plugged and Abandoned Gas Seep Canoe Oil Seep. *Becharof Lake Bay 1 seep (see below)

Uplift or Structural Arch Leased Blocks (1988, Sale 92, OilDavid Shows RiverTested 1, Gas 1A $95.4 MM, 23 Leases) (5-9 Mcfd) Leased Blocks (2005, AK State, $1.3 MM, 37 Leases) F ig u re 6 0 50 Seismic Profile * Becharof Lake oil seep reported as “location unknown” by Magoon and Anders (1992, MILES Pacific Ocean Biologic markers in sediments and petroleum, tbl. 13.1) Sherwood \....\Fig35-Play4BeringPlatform.cdr Figure 35: Area of play 4, Milky River Biogenic Gas play, North Aleutian Basin OCS Planning Area, Alaska.

125 ALASKA Iliamna Lake

Kuka L.

E 58° R 164° A

N ak G nek Lake N I N 162° Lake N Brooks A LT L U A P 160° F Y S Bristol Bay A B C IN 158° U O Great R B N Basins 2 I B ech 156° S a ro f La A Great k e Bear B PLAY 5: MESOZOIC DEFORMED Basins 1 Creek 1 N Oil Shows A I s * Gas Shows ke T Becharof Lake 1 La k Alaska 1 U SEDIMENTARY ROCKS Tested Gas i h a s Lee 1 E 90 Mcfd U g L Oil Shows A (Triassic-Cretaceous) Finnegan 1 H Jurassic Oil T Source Rocks Grammar 1 R IN Ugashik 1 O A S N N B Wide Bay 1 IA Triassic & Jurassic F T i U Oil Source Rocks g LE Painter u A (Puale Bay) re North Aleutian H Port Creek 1 T 6 ShelfOil ShowsCOST 1 R Gas Shows N O e n t Heiden 1 A se m U L Top Prospect ic B a S collected $69.4 MM in o zo n t IN Sale 92 (73% of Sale) e s e N Koniag 1 56° tic M as e m E g m a ic B P M a s oz o A y M e S K S T n ta r A . G d im e A L E Jur-Cret Oil S e B O Sale 92 A RSt. GeorgeSource Rocks? High Bid Tract S G $24.36 MM Sandy I COST 2 Oil Shows N E Bear River 1 Lake K H ILL S Oil Show L A C U P L MonkshoodShallow 1 B IF T Hoodoo Gas ShowsBertha 1 Lake 1 Big River 1 EXPLANATION A M A K B CathedralOil Staining AS I Gas Shows HoodooOil Shows N River 1 Lake 2 Well, Plugged and Abandoned Gas Seep Canoe Oil Seep. *Becharof Lake Bay 1 seep (see below)

Uplift or Structural Arch Leased Blocks (1988, Sale 92, OilDavid Shows RiverTested 1, Gas 1A $95.4 MM, 23 Leases) (5-9 Mcfd) Leased Blocks (2005, AK State, $1.3 MM, 37 Leases) F ig u re 6 0 50 Seismic Profile * Becharof Lake oil seep reported as “location unknown” by Magoon and Anders (1992, MILES Pacific Ocean Biologic markers in sediments and petroleum, tbl. 13.1) Sherwood \....\Fig36-Play5MesoSedTerraneMap.cdr Figure 36: Area of play 5, Mesozoic Deformed Sedimentary Rocks play, North Aleutian Basin OCS Planning Area, Alaska.

126 ALASKA Iliamna Lake

Kuka L.

E 58° R 164° A

N ak G nek Lake N I N 162° Lake N Brooks A LT L U A P 160° F Y S Bristol Bay A B C IN 158° U O Great R B N Basins 2 I B ech 156° S PLAY 6: MESOZOIC BURIED GRANITIC HILLS a ro f La A Great k e B Bear Basins 1 N (Jurassic-Cretaceous Magmatic Rocks) OilCreek Shows 1 A I s * Gas Shows ke T Becharof Lake 1 La ik Alaska 1 U Tested Gas h a s Lee 1 E 90 Mcfd U g L Oil Shows A Finnegan 1 H Jurassic Oil T Source Rocks Grammar 1 R IN Ugashik 1 O A S N Area of N B Wide Bay 1 North Aleutian IA Triassic & Jurassic F T i Oil Shows U Oil Source Rocks Basement g Shelf COST 1 LE Painter u Gas Shows A (Puale Bay) re H Port Creek 1 6 T A Highs R nt Heiden 1 L N O em e U B a s N S Top Prospect z o ic I ST. GEORGE collected $69.4 MM in e s o t E N Sale 92 (73% of Sale) M en P Koniag 1 56° a tic s em A BASIN a g m c B a K M oz oi S M e s L A tary A im en Jur-Cret Oil S ed St. George Sale 92 Source Rocks? High Bid Tract Sandy COST 2 $24.36 MM Oil Shows Bear River 1 Lake K H ILL S Oil Show L A C U P L MonkshoodShallow 1 B IF T Hoodoo Gas ShowsBertha 1 Lake 1 Big River 1 EXPLANATION A M A K B CathedralOil Staining AS I Gas Shows HoodooOil Shows N River 1 Lake 2 Well, Plugged and Abandoned Gas Seep Canoe Oil Seep. *Becharof Lake Bay 1 seep (see below)

Uplift or Structural Arch Leased Blocks (1988, Sale 92, OilDavid Shows RiverTested 1, Gas 1A $95.4 MM, 23 Leases) (5-9 Mcfd) Leased Blocks (2005, AK State, $1.3 MM, 37 Leases) F ig u re 6 0 50 Seismic Profile * Becharof Lake oil seep reported as “location unknown” by Magoon and Anders (1992, MILES Pacific Ocean Biologic markers in sediments and petroleum, tbl. 13.1) Sherwood \....\Fig37-PlayMesoMagTerraneMap.cdr Figure 37: Area of play 6, Mesozoic Buried Granitic Hills play, North Aleutian Basin OCS Planning Area, Alaska.

127 NET PAY IN COOK INLET OIL AND GAS POOLS

10 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)

Log-Normal Fit: 8 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) Mapped prospects in North Aleutian basin range 6 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.

4 Number ofNumber Pools = 56) (Total 2

0 0 100 200 300 400 500 600

Net Feet Pay 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 Geothermal Models for Plays 1-3 North Aleutian Basin OCS Planning Area Normal (Gaussian) Probability Distributions 900 “Force-Fit” Between Estimates for Extremes at Limits of Depth Range for Play

F00=834

800

700 2 AY F00=664 PL RANKINE ( F + 460) OO Y 1 PLA 600 F00=581 PLAY 3 F100=563

F100=525 500 ~100 99.9 99 95 75 50 25 05 1 0.1 ~0 PROBABILITY FOR EXCEEDANCE (FRACTILES) Sherwood\....\Fig39-GeothermalModelsForPlays.cdr 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 NORTH ALEUTIAN BASIN PLAY 1 RESOURCE SUMMARY A

BOE Resources (Risked) F95 = 0 Mmboe Mean = 1400 Mmboe F05 = 3749 Mmboe

Sherwood\...\Fig40A-NAB-Play1-CumulativeGraphBOE.cdr

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 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 NORTH ALEUTIAN BASIN PLAY 2 RESOURCE SUMMARY A

BOE Resources (Risked) F95 = 91 Mmboe Mean = 568 Mmboe F05 = 1,293 Mmboe

Sherwood\....\Fig41A-NAB-Play2-CumulativeGraphBOE.cdr

C North Aleutian Basin Play 02 - Tolstoi Pool Rank (Conditional Technically Recoverable): Re-Ranked on Means from PSRK Listing 1000 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)

esources F25 = 258 Mmboe (or 1.45 Tcfge) F05 = 467 Mmboe (or 2.62 Tcfge) ER 100 O boe) m (M ecoverable B 10 onditional R C

1 1 3 5 7 9 1113151719212325272931333537394143 Pool Rank [n = 44] (25th to 75th Percentile, With Mean)

Sherwood\....\Fig41C-NAB-Play2-PoolRankPlot.cdr 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 NORTH ALEUTIAN BASIN PLAY 3 RESOURCE SUMMARY A

BOE Resources (Risked) F95 = 0 Mmboe Mean = 210 Mmboe F05 = 1077 Mmboe

Sherwood\....\Fig42A-NAB-Play3-CumulativeGraphBOE.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)

Sherwood\...\Fig42C-NAB-Play3-PoolRankPlot.cdr 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

The Milky River Biogenic Gas play (play 4) is assessed with negligible recoverable gas resources.

Sherwood\....\Fig43-NAB-Play4-GraphicCompilation.cdr Figure 43: Assessment results for North Aleutian Basin OCS Planning Area play 4 (Milky River Biogenic Gas play).

133 NORTH ALEUTIAN BASIN PLAY 5 RESOURCE SUMMARY A

BOE Resources (Risked) F95 = 0 Mmboe Mean = 41 Mmboe F05 = 197 Mmboe

Sherwood\....\Fig-44A-NAB-Play5-CumulativeGraph.cdr

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)

Sherwood\....\Fig44C-NAB-Play5-PoolRankPlot.cdr 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 NORTH ALEUTIAN BASIN PLAY 6 RESOURCE SUMMARY A

BOE Resources (Risked) F95 = 0 Mmboe Mean = 67 Mmboe F05 = 330 Mmboe

Sherwood\....\Fig45A-NAB-Play6-CumulativeGraphBOE.cdr

Sherwood\...\NAB-Play6-USGSClassPlot.cdr

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)

Sherwood\....\Fig45C-NAB-Play6-PoolRankPlot.cdr

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.

135 NORTH ALEUTIAN BASI N RESOURCE SUMMARY

Gas (Free and Sol’n)

Oil & Condensate

Sherwood \...\Fig46-NAB-CumGraphResourceCompilation.cdr Figure 46: Assessment results for North Aleutian Basin OCS Planning Area. (A), cumulative probability plot for total risked recoverable BOE resources (oil 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).

136 Rank Plot, North Aleutian Basin Hypothetical Gas Pools (Conditional Bcf), and Cook Inlet Gas Fields (Bcf EUR)

Largest NAB Pool: 4645 Bcfg (Mean)

Largest CI Field (Kenai): 2427 Bcfg North Aleutian Basin Pools (93) Gas-Prone Plays 1, 2, & 6 BOE Pools Presented As 100% Gas

F25 (Bcfg)

Mean

F 75 (Bcfg) Cook Inlet Gas Fields (16)

Cook Inlet field reserve data from AK Division of Oil & Gas (2005), 2004 Annual Report, tbls. 3.2, IV.6 Sherwood\ ....\Fig47-Rank Plot-NAB Gas Pools Plays 1, 2, & 6 and CI Gas Fields.cdr 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 Cook Inlet basin. The largest hypothetical pool in North Aleutian basin could be almost twice the size of the Kenai gas field in Cook Inlet. Total Cook Inlet EUR = 11.6 Tcf gas. The North Aleutian Basin OCS Planning Area is estimated to contain 8.6 Tcf gas (mean, risked, technically-recoverable).

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