Assessment of Undiscovered Petroleum Resources of the 

Amerasia Basin Petroleum Province

Circum-Arctic Resource Appraisal Project

Scientific Investigations Report 2012–5146

U.S. Department of the Interior

U.S. Geological Survey
Cover. Eocene strata along the north side of Van Keulenfjorden, Svalbard, 

include basin-floor fan, marine slope, and deltaic to fluvial depositional facies. The age and facies of these strata are similar to Tertiary strata beneath 

the continental shelves of the Amerasia Basin, thus providing an analog for 

evaluating elements of the petroleum system. Relief from sea level to top of 

upper bluff is approximately 1,500 feet.
Assessment of Undiscovered Petroleum 

Resources of the Amerasia Basin 

Petroleum Province

By David W. Houseknecht, Kenneth J. Bird, and Christopher P. Garrity

Circum-Arctic Resource Appraisal Project

Scientific Investigations Report 2012–5146

U.S. Department of the Interior

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

KEN SALAZAR, Secretary

U.S. Geological Survey

Marcia K. McNutt, Director

U.S. Geological Survey, Reston, Virginia: 2012

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Suggested citation:

Houseknecht, D.W., Bird, K.J., and Garrity, C.P., 2012, Assessment of undiscovered petroleum resources of the 

Amerasia Basin Petroleum Province: U.S. Geological Survey Scientific Investigations Report 2012–5146, 36 p.
iii

Contents

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

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

Geologic Setting and Stratigraphy..............................................................................................................3

Source-Rock Systems...................................................................................................................................6

Lower Cretaceous Source Rocks ......................................................................................................7

Upper Cretaceous Source Rocks.......................................................................................................7

Paleogene Source Rocks ....................................................................................................................7

Canning-Mackenzie Deformed Margin....................................................................................................14

Assessment Unit Description ...........................................................................................................14

Geological Analysis of Assessment Unit Probability....................................................................14

Charge..........................................................................................................................................14

Rocks............................................................................................................................................16

Timing and Preservation...........................................................................................................17

Analogs Used for Assessment .........................................................................................................17

Assessment Inputs .............................................................................................................................17

Number of Accumulations .......................................................................................................17

Oil-to-Gas Mix.............................................................................................................................17

Accumulation Size Distribution ...............................................................................................17

Province Geologist’s Estimated Maximum Accumulation Size..........................................17

Ancillary Properties and Co-Product Ratios .........................................................................17

Results ..................................................................................................................................................17

Alaska Passive Margin ...............................................................................................................................20

Assessment Unit Description ...........................................................................................................20

Geological Analysis of Assessment Unit Probability....................................................................20

Charge..........................................................................................................................................20

Rocks............................................................................................................................................20

Timing and Preservation...........................................................................................................22

Analogs Used for Assessment .........................................................................................................22

Assessment Inputs .............................................................................................................................23

Number of Accumulations .......................................................................................................23

Oil-to-Gas Mix.............................................................................................................................23

Accumulation Size Distribution ...............................................................................................23

Province Geologist’s Estimated Maximum Accumulation Size..........................................23

Ancillary Properties and Co-Product Ratios .........................................................................24

Results ..................................................................................................................................................24

Canada Basin................................................................................................................................................24

Assessment Unit Description ...........................................................................................................24

Geological Analysis of Assessment Unit Probability....................................................................24

Charge..........................................................................................................................................24

Rocks............................................................................................................................................26

Timing and Preservation...........................................................................................................26
iv

Canada Passive Margin..............................................................................................................................26

Assessment Unit Description ...........................................................................................................26

Geological Analysis of Assessment Unit Probability....................................................................26

Charge..........................................................................................................................................26

Rocks............................................................................................................................................28

Timing and Preservation...........................................................................................................29

Analogs Used for Assessment .........................................................................................................29

Assessment Inputs .............................................................................................................................29

Number of Accumulations .......................................................................................................29

Oil-to-Gas Mix.............................................................................................................................29

Accumulation Size Distribution ...............................................................................................29

Province Geologist’s Estimated Maximum Accumulation Size..........................................29

Ancillary Properties and Co-Product Ratios .........................................................................30

Results ..................................................................................................................................................30

Summary and Conclusions.........................................................................................................................30

Acknowledgments.......................................................................................................................................30

References Cited..........................................................................................................................................30

Figures

1. Map of Amerasia Basin Petroleum Province...........................................................................2

2. Generalized representative cross sections across the Alaska rift shoulder

and southern Canada Basin........................................................................................................4

3. Generalized cross section across the Canada rifted passive margin and

extending into the Canada Basin ...............................................................................................5

4. Plots of depth versus vitrinite reflectance for representative wells from the

Canning-Mackenzie deformed margin assessment unit .......................................................8

5. Petroleum systems plots for five pseudowells and one well in the

Amerasia Basin Province............................................................................................................. 10

6. Maps of modeled thermal maturity..........................................................................................13

7. Map of the Canning-Mackenzie deformed margin assessment unit.................................15

8. Map of the Alaska passive margin assessment unit ...........................................................21

9. Map of the Canada Basin assessment unit............................................................................25

10. Map of the Canada passive margin assessment unit ..........................................................27

Tables

1. Summary of assessment unit probabilities and key input parameters for

numbers and sizes of undiscovered, conventional accumulations for the

Canning-Mackenzie deformed margin assessment unit .....................................................16

2. Analog assessment units used to constrain input parameters for the

Canning-Mackenzie deformed margin assessment unit .....................................................18

3. Summary of results for risked, undiscovered, technically recoverable

petroleum resources for the Amerasia Basin Province, including results

for the Canning-Mackenzie deformed margin, Alaska passive margin,

Canada Basin, and Canada passive margin assessment units ..........................................19
v

 4. Summary of assessment unit probabilities and key input parameters for 

Multiply By To obtain

Length

meter (m) 3.281 foot (ft) 

meter (m) 1.094 yard (yd) 

kilometer (km) 0.6214 mile (mi)

kilometer (km) 0.5400 mile, nautical (nmi) 

Area

square kilometer (km2

) 247.1 acre

square kilometer (km2

) 0.3861 square mile (mi2)

Volume

barrel (bbl), (petroleum, 

1 barrel=42 gal)

0.1590 cubic meter (m3

) 

cubic foot (ft3

) 28.32 cubic decimeter (dm3) 

cubic foot (ft3

) 0.02832 cubic meter (m3) 

Conversion Factors

Assessment of Undiscovered Petroleum Resources of the 

Amerasia Basin Petroleum Province

By David W. Houseknecht, Kenneth J. Bird, and Christopher P. Garrity

Abstract

The Amerasia Basin Petroleum Province encompasses 

the Canada Basin and the sediment prisms along the Alaska 

and Canada margins, outboard from basinward margins 

(hingelines) of the rift shoulders that formed during extensional opening of the Canada Basin. The province includes 

the Mackenzie delta and slope, the outer shelves and marine 

slopes along the Arctic margins of Alaska and Canada, and the 

deep Canada Basin.

The province is divided into four assessment units (AUs): 

(1) The Canning-Mackenzie deformed margin AU is that part 

of the rifted margin where the Brooks Range orogenic belt has 

overridden the rift shoulder and is deforming the rifted-margin 

prism of sediment outboard of the hingeline. This is the only 

part of the Amerasia Basin Province that has been explored 

and—even though more than 3 billion barrels of oil equivalent 

(BBOE) of oil, gas, and condensate have been discovered—

none has been commercially produced. (2) The Alaska passive margin AU is the rifted-margin prism of sediment lying 

beneath the Beaufort outer shelf and slope that has not been 

deformed by tectonism. (3) The Canada passive margin AU is 

the rifted-margin prism of sediment lying beneath the Arctic 

outer shelf and slope (also known as the polar margin) of 

Canada that has not been deformed by tectonism. (4) The Canada Basin AU includes the sediment wedge that lies beneath 

the deep Canada Basin, north of the marine slope developed 

along the Alaska and Canada margins. Mean estimates of 

risked, undiscovered, technically recoverable resources 

include more than 6 billion barrels of oil (BBO), more than 

19 trillion cubic feet (TCF) of associated gas, and more than 

16 TCF of nonassociated gas in the Canning-Mackenzie 

deformed margin AU; about 1 BBO, about 3 TCF of associated gas, and about 3 TCF of nonassociated gas in the Alaska 

passive margin AU; and more than 2 BBO, about 7 TCF of 

associated gas, and about 8 TCF of nonassociated gas in the 

Canada passive margin AU. Quantities of natural gas liquids 

also are assessed in each AU. The Canada Basin AU was not 

quantitatively assessed because it is judged to hold less than 

10 percent probability of containing at least one accumulation 

of 50 million barrels of oil equivalent.

Introduction

The U.S. Geological Survey (USGS) in 2008 completed 

an appraisal of undiscovered, technically recoverable, conventional oil and gas resources north of the Arctic Circle. Results 

of that Circum-Arctic Resource Appraisal include aggregate 

resource estimates for the entire Arctic region (Bird and 

others, 2008; Gautier and others, 2009, 2011a) and documentation of the geological framework and resource estimates 

for specific Arctic provinces (Bird and Houseknecht, 2011; 

Gautier and others, 2011b; Houseknecht and Bird, 2011; Klett 

and Pitman, 2011; Klett and others, 2011; Moore and Pitman, 

2011; Moore and others, 2011; Schenk, 2011a, b; Sørensen 

and others, 2011). In addition, the procedures and methods 

used in conducting the Circum-Arctic Resource Appraisal 

have been documented by Charpentier and Gautier (2011). 

The purpose of this report is to provide a synthesis of the geology of the Amerasia Basin Petroleum Province and to present 

input parameters and results of the resource assessment.

The Amerasia Basin includes that part of the Arctic 

Ocean that lies between the Lomonosov Ridge, the Arctic 

continental shelves of Canada and Alaska, the Chukchi shelf 

of Alaska and Russia, and the East Siberian shelf of Russia 

(Grantz and others, 2009, 2011b). For assessment purposes, 

we define the Amerasia Basin Petroleum Province to include 

the deep Canada Basin1

 and the depocenters along the continental margins of Alaska and Canada (fig. 1). Elements of the 

Amerasia Basin that are excluded from consideration in this 

report include the “Alpha-Mendeleev large igneous province,” 

which was deemed nonprospective for oil and gas by Grantz 

and others (2009, 2011b), and the Chukchi Borderland and 

Makarov basins, which are considered in other reports summarizing the USGS Circum-Arctic Resource Appraisal.

As defined, the Amerasia Basin Petroleum Province 

extends about 1,200 km west-east along the 73°N. parallel and 

ranges from about 1,100 km north-south in the west (adjacent 

to the Chukchi borderland) to about 2,250 km northeast-southwest in the east (along the Canada continental margin) (fig. 1). 

The western, southern, and eastern boundaries of the province 

are defined by the outboard (basinward) margins of rift shoulders that formed during the opening of the Amerasia Basin 

1

The term “Canada Basin” is used in this report as the deepwater (generally 

more than 3,000 m water depth) part of the Amerasia Basin that includes a 

sedimentary succession inferred to be thicker than about 2,000 m.
2 Assessment of Undiscovered Petroleum Resources of the Amerasia Basin Petroleum Province

Map

Area

0 100 200 MILES

0 100 200 KILOMETERS

Figure 1.

EXPLANATION

Amerasia Basin Petroleum Province

Locations of generalized cross sections

Locations of wells and pseudowells

ACEX cores

CANADA BASIN

ARCTIC ALASKA

PROVINCE HOPE BASIN

PROVINCE

NORTH CHUKCHIWRANGEL FORELAND

BASIN PROVINCE

CHUKCHI

BORDERLAND

PROVINCE

NORTHWEST CANADA

INTERIOR BASIN

PROVINCE

FRANKLINIAN

SHELF PROVINCE

SVERDRUP

BASIN

PROVINCE

ALPHA-MENDELEEV IGNEOUS PROVINCE

Arctic Alaska

Chukchi

shelf

Chukchi

Borderland

CANADA

PASSIVE

MARGIN 

CANNING-MACKENZIE

DEFORMED MARGIN

ALASKA

PASSIVE

MARGIN

Alpha ridge

CANADA

U.S.A.

RUSSIA

U.S.A.

Arctic Circle

Arctic Circle

Fig. 2A

Fig. 2

B

Fig. 2C

Fig. 3

5A

5B

5C 5D

5E

5F

150°E 90°W

80°N

75°N

70°N

170°E 170°W 150°W 130°W 110°W

Figure 1. Map of Amerasia Basin Petroleum Province (heavy 

red outline) showing component assessment units (AUs), labeled 

by name (all caps, italics) and USGS AU code, and adjacent 

provinces assessed as part of the USGS 2008 Circum-Arctic 

Resource Appraisal. Dotted lines labeled Fig. 2A, 2B, 2C and 3 

are locations of generalized cross sections shown in figs. 2 and 

3. Salmon-colored circles (labeled 5A–5F) are locations of wells 

and pseudowells for which petroleum-system plots are shown in 

fig. 5. Inset map shows location of study area, Lomonosov Ridge 

(polygon with black outline and yellow fill), and location of ACEX 

cores (red dot with black rim).
Geologic Setting and Stratigraphy 3

during Jurassic–Early Cretaceous time (Embry, 1990; Grantz 

and others, 1990b, 1998, 2011a; Lane, 1997; Lawver and Scotese, 1990). The north-central boundary is defined by abrupt 

thinning of Canada Basin strata onto extrusive rocks of the 

Alpha-Mendeleev igneous province. The northeastern boundary is defined by abrupt thinning of strata from the Canada 

continental margin onto extrusive rocks of the Alpha ridge. 

Additional details regarding these boundaries are included in 

the assessment unit descriptions that follow. The province is 

divided into four units for assessment purposes: the CanningMackenzie deformed margin, the Alaska passive margin, the 

Canada Basin, and the Canada passive margin (fig. 1).

Geologic Setting and Stratigraphy

The Canada Basin formed by Jurassic–Early Cretaceous 

rifting between Alaska and Arctic Canada. The Arctic Alaska 

microplate (including Arctic Alaska, the Chukchi shelf, and 

the Chukchi Borderland; fig. 1) rifted from Arctic Canada, 

perhaps by counterclockwise rotational opening of the Canada 

Basin or alternative motions (Grantz and May, 1982; Lawver 

and Scotese, 1990; Grantz and others, 1990b, 2011a; Embry, 

1990, 2000; Lane, 1997; Lawver and others, 2002, 2011). 

The Chukchi Borderland, composed of attenuated continental 

crust, is inferred to have rotated clockwise away from Arctic 

Alaska (Grantz and others, 2009b, 2011a), either during or 

after opening of the Canada Basin.

The Arctic margins of Alaska and Canada, as well as the 

eastern margin of the Chukchi Borderland (Northwind Ridge; 

Grantz and others, 1998), are defined by high-standing acoustic basement that represents the rift shoulders formed during 

extensional opening of the Canada Basin (Houseknecht and 

Bird, 2011). The outboard margins of those rift shoulders are 

defined by large-magnitude, down-to-the-basin normal faults 

in acoustic basement (figs. 2, 3); these abrupt margins commonly are called hinges or hingelines (fig. 2). These hinges 

separate thick continental crust beneath the Chukchi Borderland, Arctic Alaska, and Arctic Canada from highly attenuated 

continental to transitional crust beneath the Canada Basin. 

The hinges are used herein to define the western, southern, 

and eastern limits of the Amerasia Basin Petroleum Province 

because of the inferred contrasts in petroleum systems across 

those abrupt boundaries, as explained below (Houseknecht 

and others, 2012b).

Acoustic basement inboard from the hinges (west of the 

hinge in the Chukchi Borderland, south of the hinge in Arctic 

Alaska, and southeast of the hinge in Arctic Canada) mostly 

consists of pre-Mississippian, low-rank metamorphic rocks 

known as the Franklinian sequence (figs. 2, 3), which was 

broadly deformed during the Ellesmerian orogeny (Late Devonian–Early Mississippian; Balkwill and others, 1983; Moore 

and others, 1994; Dumoulin, 2001). Immediately outboard 

(basinward) of the hinges, acoustic basement presumably 

consists of similar rocks that are highly attenuated. Farther 

basinward, basement may grade into transitional crust by 

attenuation and intrusion by oceanic igneous rocks, but this 

inference is poorly constrained. Basement in the center of the 

Canada Basin may be fully oceanic crust, as suggested by the 

presence of magnetic stripes (Grantz and others, 2011a).

Pre-Cenozoic stratigraphy of the Amerasia Basin is 

poorly known because the southern and eastern margins of the 

province are mantled by such a thick succession of Cenozoic 

sediment that neither exploration wells nor seismic data provide much information regarding older strata. Therefore, the 

presence and nature of sub-Cenozoic strata must be inferred 

from the geology of adjacent regions and other indirect evidence. Jurassic–Lower Cretaceous synrift deposits are evident 

in seismic data and have been penetrated by drilling along 

parts of the rift shoulder (Grantz and May, 1982; Hubbard and 

others, 1987; Masterson and Paris, 1987; Masterson and Eggert, 1992). However, any synrift deposits outboard of the hinge 

are deeply buried beneath an expanding wedge of postrift 

strata, which thicken dramatically by growth-faulting north of 

the rift shoulder (figs. 2, 3).

The postrift succession in the Amerasia Basin probably 

includes Lower Cretaceous through Cenozoic strata. These 

strata include (1) the Brookian sequence in Arctic Alaska and 

the Canadian Beaufort-Mackenzie region (Lerand, 1973; Hubbard and others, 1987), whose sediment was derived mostly 

from the Chukotka magmatic belt and Brooks Range orogenic 

belt, and (2) coeval strata of the Canadian Arctic islands and 

adjacent shelf, whose sediment probably was derived from a 

mixed provenance that included the Canadian shield, Franklinian shelf, Sverdrup basin, Sverdrup rim (rift shoulder), and 

Eurekan tectonic uplifts (Miall, 1984, 1986, 1991; McWhae, 

1986; Haimila and others, 1990; Embry, 1991, 1993; Harrison 

and others, 1999; Houseknecht and Bird, 2011). Coeval strata 

in the deep Canada Basin may represent a distal mixture of 

sediment derived from all these provenance areas, plus contributions from the Chukchi Borderland and perhaps the AlphaMendeleev igneous province (fig. 1).

Data from exploration wells and seismic surveys indicate 

that significant volumes of sediment initially overstepped the 

rift shoulder during the Albian along the northeast Chukchi 

and western Alaska North Slope margin and during the Paleogene along the central and eastern Alaska North Slope margin 

(Houseknecht and others, 2009, 2012b; Houseknecht and Bird, 

2011). Inferences from the Mackenzie delta and Arctic Islands 

of Canada suggest that modest volumes of sediment may have 

overstepped the rift shoulder (Sverdrup rim) during the Cretaceous and that the most voluminous influx occurred during the 

Tertiary, largely a consequence of uplift associated with the 

Brooks Range orogeny (sediment fed through the Mackenzie 

delta) and the Eurekan orogeny (Miall, 1984, 1986; Hubbard 

and others, 1987; Dixon and Dietrich, 1990; Dixon and others, 

1992; Dixon, 1996; Forsyth and others, 1990, 1998; Harrison 

and others, 1999; Houseknecht and Bird, 2011). Considering 

that the Amerasia Basin likely was fully open by the Barremian (Grantz and others, 2011a), the succession deposited 

after the Barremian and before the flood of Brookian (Alaska-
4 Assessment of Undiscovered Petroleum Resources of the Amerasia Basin Petroleum Province

S4

S3

S4

S3

S3

S4

S2

S1

S2

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

A

Pseudowell 1-16

BRF

Camden anticline

A

Pseudowell 7-10

T Pl G N S N Pi A-L

Pseudowell 4-18

Dinkum graben

Dinkum plateau

1 - Lower Cretaceous

2 - Upper Cretaceous

3 - Paleogene

4 - Neogene

5 - Quaternary

1 - Lower Cretaceous

2 - Upper Cretaceous

3 - Paleogene

4 - Neogene

5 - Quaternary

1 2

3

4

1 - Lower Cretaceous

2 - Upper Cretaceous

3 - Paleogene

4 - Neogene

5 - Quaternary

1

1

1

1

2

1 0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

ARCTIC ALASKA PLATFORM ALASKA PASSIVE MARGIN CANADA BASIN

ARCTIC ALASKA PLATFORM ALASKA PASSIVE MARGIN CANADA BASIN

CANNING-MACKENZIE

DEFORMED MARGIN CANADA BASIN ARCTIC ALASKA FOLD-AND-THRUST BELT

S

S

S

FEET METERS

SOUTHWEST

B

C

FEET

SOUTH

FEET

SOUTH

NORTH

NORTHEAST

3

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

0

2,000

4,000

6,000

8,000

10,000

12,000

METERS

NORTH

METERS

0

2,000

4,000

6,000

8,000

10,000

12,000

S2

S1

B

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000 S2 S1

Figure 2.

0 25 50 MILES

0 25 50 KILOMETERS

Postrift strata

Prerift and synrift strata

Franklinian basement

Unknown basement

0.5% VR—Approximate

0.7% VR—Approximate

1.0% VR—Approximate

1.3% VR—Approximate

EXPLANATION

0 25 50 MILES

0 25 50 KILOMETERS

0 25 50 MILES

0 25 50 KILOMETERS
Geologic Setting and Stratigraphy 5

Figure 2 (at left). Generalized representative cross sections 

across the Alaska rift shoulder and southern Canada Basin 

showing simplified stratigraphy, potential source-rock 

intervals, and vitrinite reflectance contours resulting from 

burial-history modeling of exploration wells and pseudowells 

and use of vitrinite kinetics of Burnham and Sweeney (1989). 

Boundaries of assessment units are shown by thin vertical 

lines above each cross section; the Arctic Alaska assessment 

units are described in another report. Locations of pseudowells 

are shown by black ticks; labeled pseudowells are shown 

in figs. 5, 7, 8, and 10. The following exploration wells are 

indicated by black-and-yellow lines; A-L, Aufeis and Lupine; 

N, Nora; B, Bush; Pi, Pipeline; T, Toolik 2; Pl, Placid; G, Gwydyr 

Bay State 1; N, Northstar 1; S, Sandpiper 1; A, Aurora. Potential 

source-rock intervals shown are S1, Lower Cretaceous; 

S2, Upper Cretaceous; and S3 and S4, lower and upper 

limits, respectively, of inferred lower Paleogene interval; S4 

represents approximate stratigraphic position of the Azolla 

horizon documented in ACEX cores on the Lomonosov Ridge. 

Double-headed arrows labeled “S” show extent of seismic 

control along each cross section. BRF, Brooks Range front; 

pink polygon in C is deeply rooted uplift at front of Brooks 

Range. Locations of cross sections shown in figs. 1, 7, and 8. 

Cross sections modified from Houseknecht and others (2012b), 

which describes the constraining data and procedures used in 

their construction.

Figure 3.

Postrift strata

Prerift and synrift strata

Franklinian basement

Unknown basement

0.5% VR—Approximate

0.7% VR—Approximate

1.0% VR—Approximate

1.3% VR—Approximate

EXPLANATION

0 25 50 MILES

0 25 50 KILOMETERS

CANADA BASIN CANADA PASSIVE MARGIN

2,000

4,000

6,000

8,000

10,000

12,000

14,000

0

METERS

1 - Lower Cretaceous or older strata? 2 - Upper Cretaceous

3 - Paleogene

4 - Neogene

5 - Quaternary

S1

S2

S3

S4

CPM-07 CPM-06 CPM-05 CPM-04 CPM-03 CPM-02

WEST EAST

Figure 3 (above). Generalized cross section across the Canada 

rifted passive margin and extending into the Canada Basin. 

Boundaries of assessment units are shown by vertical lines 

above the cross section. Location of cross section shown in 

figs. 1 and 10. Cross section was constructed by using digital 

bathymetric data, the isopach map of Jackson and Oakey (1990), 

and known stratigraphy from adjacent regions; however, the 

lack of direct geologic or seismic data introduces significant 

uncertainty. Potential source rock intervals shown are S1, Lower 

Cretaceous; S2, Upper Cretaceous; and S3 and S4, lower and 

upper limits, respectively, of inferred lower Paleogene interval; 

S4 represents approximate stratigraphic position of the Azolla 

horizon documented in ACEX cores on the Lomonosov Ridge. 

Cross-section construction and thermal-maturity estimation based 

on procedures described by Houseknecht and others (2012b) for 

the Alaska margin.
6 Assessment of Undiscovered Petroleum Resources of the Amerasia Basin Petroleum Province

Above figure: Cross-bedded pebbly sandstone in Paleogene strata exposed along the Sagavanirktok River, Alaska North Slope. 

This sandstone was deposited in a fluvial system that delivered sediment to the Alaska continental margin of the Amerasia Basin, 

thus providing insights regarding potential reservoir facies in the Alaska Passive Margin and Canning-Mackenzie Deformed 

Margin assessment units.

Mackenzie margin) and Eurekan (Canadian Arctic islands 

margin) sediment holds the potential to include condensed 

facies (see below).

Source-Rock Systems

Much of the historical oil exploration in Arctic North 

America, inboard of the hinges, has focused on petroleum 

systems with Triassic and Jurassic source rocks (Bird, 1985, 

2001; Claypool and Magoon, 1985; Magoon and Claypool, 

1985; Magoon and others, 1987, 1999, 2003; Magoon, 1994; 

Bird and Houseknecht, 2011), which are considered to be generally absent outboard of the rift shoulder because the Canada 

Basin was not yet open when those strata were deposited. 

Although Triassic and Jurassic strata may be locally present 

outboard of the rift shoulder in synrift graben basins (Hubbard and others, 1987; Paul and others, 1994), they are buried 

to depths (more than 10 km) that would render any source 

rocks supramature. Moreover, the preservation potential of 

any hydrocarbons generated from those strata is considered 

small. Therefore, analysis of petroleum systems outboard of 

the hinges is focused on potential source rocks in Cretaceous 

and younger, postrift strata and is based on indirect evidence 

from areas adjacent to the Canada Basin. Three stratigraphic 

intervals appear to have source-rock potential: the succession 

that includes the lower Cretaceous pebble shale unit (PSU) 

and gamma-ray zone of the Hue Shale, the lower part of Upper 

Cretaceous strata, and lower Paleogene strata (Houseknecht 

and Bird, 2011; Houseknecht and others, 2012b). Each is 

discussed in a following section.
Source-Rock Systems 7

Lower Cretaceous Source Rocks

The lower Cretaceous pebble shale unit (PSU) and 

gamma-ray zone (GRZ, also known as highly radioactive zone 

or HRZ) of the Hue Shale (Mull and others, 2003) together 

represent a condensed section at the base of the Brookian 

sequence throughout Arctic Alaska (S1 in figs. 2 and 3). These 

units generally are leaner (lower total organic carbon, TOC) 

and more gas-prone (lower hydrogen index, HI) in the west 

(Chukchi shelf and western Alaska North Slope) and south 

(near Brooks Range) and richer (higher TOC) and more oilprone (higher HI) towards the east and north (rift shoulder) 

(Peters and others, 2006). Across Arctic Alaska, the PSU and 

GRZ range from about 1 percent to more than 5 percent TOC, 

contain a mixture of type II and III kerogen (for definitions of 

kerogen type, see Tissot and Welte, 1984), and are considered 

oil-prone over wide areas (Masterson 2001; Peters and others 

2006; Houseknecht and Bird, 2011). Approximately coeval 

strata in Arctic Canada tend to be either lean or gas-prone 

(Leith and others, 1993; Dixon, 1996; Houseknecht and Bird, 

2011). Petroleum accumulations in Arctic Alaska that have 

been documented to contain oil sourced either exclusively or 

partly from these basal Brookian source rocks include Endicott, Prudhoe Bay, Lisburne, Point Thomson, and Tarn (Wicks 

and others 1991; Masterson 2001; Magoon and others, 2003; 

Peters and others 2008; Houseknecht and others, 2012b).

The age of the PSU and GRZ (Hauterivian–Albian) 

includes the time interval of Canada Basin extension, which 

is inferred to have ended no later than Barremian, and of 

volcanism along the Alpha-Mendeleev igneous province 

(Grantz and others 2011a). So, even though the Canada Basin 

was the most distal and deepest marine part of the depositional 

system in which these strata were deposited, source-rock 

properties may have been influenced by sea-floor extension in 

the Canada Basin, by volcanism along the Alpha-Mendeleev 

volcanic system, and by thermal contraction and subsidence of 

the rift shoulders along the southern and eastern margins of the 

basin (Houseknecht and Bird, 2011; Houseknecht and others, 

2012b). These processes would most likely have affected the 

older part of this succession and, therefore, the younger (postBarremian) strata may have the best source-rock potential. 

On the basis of this line of reasoning, we infer that there is 

potential for a Lower Cretaceous source rock containing type 

II kerogen at the base of the postrift section in the Amerasia 

Basin Province.

Upper Cretaceous Source Rocks

The lower part of the Upper Cretaceous section (mostly 

Turonian-aged strata) includes a condensed section that 

displays source-rock quality in Arctic Alaska (Seabee Formation) and Arctic Canada (Boundary Creek, Smoking Hills, and 

Kanguk Formations) (S2 in figs. 2 and 3). These formations 

commonly range from 2 percent to more than 10 percent TOC, 

contain mostly type II kerogen, and are oil-prone across wide 

areas (Creaney, 1980; Snowdon 1980; Dixon and others 1992; 

Dixon 1996; Threlkeld and others 2000; Houseknecht and 

Bird, 2011). The Seabee and Kanguk Formations are immature beneath the Alaska North Slope and the Arctic Islands, 

respectively, and have not been inferred as the source of any 

known oil accumulations. The Boundary Creek-Smoking Hills 

Formation is inferred to have sourced the Imnak, Mayogiak, 

Kugpik, and Atkinson oil accumulations in the Mackenzie 

delta (Snowdon 1980; Dixon 1996).

The widespread occurrence of Turonian source rocks in 

Arctic Alaska and Canada inboard of the rift shoulders suggests a high probability that coeval source rocks also are present outboard of the rift shoulders. The potential for a source 

rock containing type II kerogen in the lower part of the Upper 

Cretaceous section outboard of the rift shoulder is therefore 

considered likely throughout the Amerasia Basin Province.

Paleogene Source Rocks

The lower Paleogene is a condensed section on Lomonosov Ridge, where it was cored in 2004 during the International 

Ocean Drilling Program Arctic Coring Expedition (ACEX 

cores, fig. 1). Analyses of ACEX cores suggest the Arctic 

Ocean was a warm, ice-free, brackish, and bioproductive basin 

during the early Paleogene (Sluijs and others 2006; Stein and 

others 2006), a time of globally high temperature and generally high sea level. The ACEX cores include a Paleocene–

early middle Eocene succession that is organic rich (TOC 

mostly 1–5 percent, up to 14 percent) and that locally contains 

oil-prone (type II) kerogen (Stein, 2007). Although most of 

the Paleogene kerogen in the ACEX cores is gas-prone (type 

III) kerogen, it was deposited before, and during, rifting of 

the Lomonosov Ridge away from Asia, so it is possible that 

the kerogen composition reflects dilution by terrigenous 

organic matter derived from the Asian continent. It is possible 

that coeval strata in the more distal reaches of the Amerasia 

Basin, which had fully opened by the Barremian (Grantz and 

others 1990b, 2011a), may be richer in organic matter and 

may include oil-prone kerogen. At the top of the organic-rich 

succession in the ACEX cores, a lower–middle Eocene Azolla

fern horizon occurs, indicating cooler temperatures and probably fresh surface water in the Arctic Ocean (Brinkhuis and 

others 2006). This Azolla facies is both organic-rich (mostly 

2–5 percent TOC) and oil-prone (Stein, 2007). Thus, evidence 

from the ACEX cores suggests the potential for organic-rich—

and at least partly oil-prone (type II)—kerogen in lower Paleogene strata in the Canada Basin (S3 to S4 in figs. 2 and 3).

Numerous oil occurrences along the Beaufort Shelf of 

eastern Alaska and in the Mackenzie delta of Canada have 

been typed to Tertiary-aged kerogen by means of biomarker 

geochemistry (Magoon and others 1999; Snowdon and others 

2004; Houseknecht and others, 2012b), and yet viable source 

rocks of this age rarely have been penetrated by drilling along 

the Alaska-Canada margins. It is possible that the widely 

occurring Tertiary oils were generated from early Paleogene 

source rocks—likely coeval with those cored on Lomonosov 
8 Assessment of Undiscovered Petroleum Resources of the Amerasia Basin Petroleum Province

Figure 4. ABCD 

D True vertical depth, in meters

4,000

5,000

3,000

2,000

1,000

0.1 0.2 0.3 0.4 0.6 0.8 1

EXPLANATION

Normal vitrinite

Low %Ro vitrinite

High %Ro vitrinite

Fm.Taglu

Imp. Sarpik B-35

Log %Ro = 1.7518*10-4 Z-0.7091

R2 = 0.8135

Iperk 0 CASING POINT

Vitrinite reflectance, in percent

A 

Vitrinite reflectance, in percent

Measured well depth, in feet

18,000

10,000

12,000

14,000

16,000

8,000

2,000

4,000

6,000

0.1 0.6 1 1.3 2.0 5

Shell Corona No. 1

Ro = 2.24E-1*10(3.40E-5*depth)

R2 = 8.167667E-1

0

Canning

Formation

Zone of

oil generation

Zone of

gas generation

Zone of

dry gas

Sagavanirktok

Formation

Vitrinite reflectance, in percent

C True vertical depth, in meters

2,500

3,000

2,000

1,500

500

1,000

0.1 0.2 0.3 0.4 0.6 0.8 1

EXPLANATION

Normal vitrinite

Low %Ro vitrinite

High %Ro vitrinite

Fm.Quat. Aklak Rich. Kugmallit

Dome and others Adlartok P-09

Log %Ro = 1.6671*10-4 Z-0.707

R2 = 0.8867

CASING POINT

0

Vitrinite reflectance, in percent

B Measured well depth, in feet

18,000

10,000

12,000

14,000

16,000

8,000

2,000

4,000

6,000

0.1 0.6 1 1.3 2.0 5

Amoco Belcher No. 1

Ro = 3.59E-1*10(2.48E-5*depth)

R2 = 9.509159E-1

0

Canning

Formation

Zone of

oil generation

Zone of oil and

 wet gas generation

Zone of

dry gas

Figure 4. Plots of depth versus vitrinite reflectance for representative wells from the Canning-Mackenzie deformed margin 

assessment unit. Locations of wells are shown in fig. 7. A and B are from Bird and others (1999) and C–H are from Stasiuk and others 

(2005). All vitrinite reflectance data were measured in immersion oil.

Ridge—that are deeply buried beneath younger Cenozoic 

strata in the depocenters outboard of the rift shoulders around 

the southern and eastern margins of the Amerasia Basin 

Province. Although direct evidence to support this inference is 

lacking, this potential is considered likely for the purpose of 

assessing petroleum resources.

Exploration wells have been drilled only in the CanningMackenzie deformed margin assessment unit (AU) (fig. 1), 

so there are limited data available regarding the burial history 

and thermal maturity of strata in the Amerasia Basin Province. Thermal-maturity data from representative wells in the 

Canning-Mackenzie deformed margin AU display generally 

low gradients of depth versus vitrinite reflectance (fig. 4), a 

condition that is common on passive continental margins characterized by thick accumulations of overpressured Cenozoic 

strata. Modeling of the burial and thermal maturation history 

of that part of the province north of Alaska using cross sections constructed with sparse data (figs. 2 and 3) indicates that 

most hydrocarbon generation from the three potential sourcerock intervals described above (S1, S2, and interval S3–S4 

in figs. 2 and 3) occurred during the Paleogene and early 

Neogene (fig. 5). Earlier generation may have occurred from 
Source-Rock Systems 9

E True vertical depth, in meters

1,500

2,000

1,000

500

0.1 0.2 0.3 0.4 0.6 0.8 1

EXPLANATION

Normal vitrinite

Low %Ro vitrinite

High %Ro vitrinite

Fm.Arctic Red Aklak

Gulf and others Ikhil K-35

Log %Ro = 2.1501*10-4 Z-0.5743

R2 = 0.7415

0

CASING POINT

Vitrinite reflectance, in percent

F True vertical depth, in meters

4,000

5,000

3,000

2,000

1,000

0.1 0.2 0.3 0.4 0.6 0.8 1

EXPLANATION

Normal vitrinite

Low %Ro vitrinite

High %Ro vitrinite

Fm.Quat. Richards Kugmallit

Esso PCI Home and others Hansen G-07

Log %Ro = 1.3373*10-4 Z-0.6853

R2 = 0.769

0

CASING POINT

Mac. Bay

Vitrinite reflectance, in percent

G True vertical depth, in meters

4,000

5,000

3,000

2,000

1,000

0

0.1 0.2 0.3 0.4 0.6 0.8 1

EXPLANATION

Normal vitrinite

Low %Ro vitrinite

High %Ro vitrinite

Fm.Iperk Richards Kugmallit

Esso and others Amerk O-09

Log %Ro = 1.1539*10-4 Z-0.7808

R2 = 0.899

CASING POINT

Mac. Bay

Vitrinite reflectance, in percent

H True vertical depth, in meters

4,000

5,000

3,000

2,000

1,000

0.1 0.2 0.3 0.4 0.6 0.8 1

EXPLANATION

Normal vitrinite

Low %Ro vitrinite

High %Ro vitrinite

Fm.Iperk Undef. Richards Kug.

Dome and others Havik B-41

Log %Ro = 1.2208*10-4 Z-0.8542

R2 = 0.7881

CASING POINT

Mac.

Bay

0

Vitrinite reflectance, in percent

Figure 4. EFGH

Figure 4. Plots of depth versus vitrinite reflectance for representative wells from the Canning-Mackenzie deformed margin 

assessment unit. Locations of wells are shown in fig. 7. A and B are from Bird and others (1999) and C–H are from Stasiuk and others 

(2005). All vitrinite reflectance data were measured in immersion oil. —Continued

Lower Cretaceous source rocks in the southwestern part of 

the Canada Basin (Nuwuk basin of Grantz and others, 1990a), 

where Early Cretaceous depositional systems overstepped the 

Alaska rift shoulder (Houseknecht and others, 2009; Houseknecht and Bird, 2011) and deposited a wedge of sediment 

outboard of the rift shoulder (figs. 2A, 5A).

Modeling results suggest that the base of the postrift 

succession grades from supramature (more than 2.6 percent 

vitrinite reflectance, VR) in the depocenter immediately outboard of the hinge to late mature (1.0–1.3 percent VR) in the 

northern part of the Canada Basin (fig. 6A). Across the same 

area, the top of the youngest potential source-rock interval (S4 

in figs. 2 and 3) grades in a radial pattern from overmature for 

oil (1.3–2.6 percent VR) in the distal part of the Mackenzie 

delta depocenter to immature (less than 0.5 percent VR) to 

early mature (0.5–0.7 percent VR) in the western and northern 

Canada Basin (fig. 6B). 

Finally, the Amerasia Basin Province undoubtedly 

contains biogenic gas and gas hydrates in shallow parts of the 

stratigraphic succession. These resources are not considered in 

this assessment.
10 Assessment of Undiscovered Petroleum Resources of the Amerasia Basin Petroleum Province

Early mature (0.5–0.7% VR)

Mid mature (0.7–1.0% VR)

Late mature (1.0–1.3% VR)

Main gas (1.3–2.6% VR) 40,000

45,000

30,000

10,000

20,000

0

0

Depth subsurface, in feet

150 100 50

A 

Pseudowell 1-16 

EXPLANATION

0

Age, in millions of years

150 100 50

0

1.0

TransformationRatio (fraction)

Reservoir

Seal

Overburden

Trap Formation

Source

Sources 1 2 3 4

Quaternary

Neogene

Paleogene 3

Paleogene 2

Paleogene 1

U. Cretaceous

L. Cretaceous

Source 1

Source 2

Source 3

Source 4

Pre-Brookian

Src. Res. Seal

Early mature (0.5–0.7% VR)

Mid mature (0.7–1.0% VR)

Late mature (1.0–1.3% VR)

Main gas (1.3–2.6% VR) 40,000

45,000

30,000

10,000

20,000

0

0

Depth subsurface, in feet

150 100 50

B 

Pseudowell 4-18 

EXPLANATION

0

Age, in millions of years

150 100 50

0

1.0

TransformationRatio (fraction)

Reservoir

Seal

Overburden

Trap Formation

Source

Sources 1 2 3 4

Quaternary

Neogene

Paleogene 3

Paleogene 2

Source 1

Source 2

Source 3

Source 4

Pre-Brookian

Src. Res. Seal

Paleogene 1

Upper Cretaceous

Lower Cretaceous

Figure 5. Petroleum systems plots for five pseudowells and one well in the Amerasia Basin Province. Locations of pseudowells and 

wells on maps are shown in figs. 1, 7, 8, 9, and 10; locations on cross sections are shown in figs. 2 and 3. A, Pseudowell 1-16 in the western 

part of the Alaska passive margin assessment unit. B, Pseudowell 4-18 in the eastern part of the Alaska passive margin assessment unit.
Source-Rock Systems 11

Early mature (0.5–0.7% VR)

Mid mature (0.7–1.0% VR)

Late mature (1.0–1.3% VR)

Main gas (1.3–2.6% VR) 40,000

45,000

30,000

10,000

20,000

0

0

Depth subsurface, in feet

150 100 50

D 

Havik B-41 

EXPLANATION

0

Age, in millions of years

150 100 50

0

1.0

TransformationRatio (fraction)

Reservoir

Seal

Overburden

Trap formation

Source

Sources 1 2 3 4

Src. Res. Seal

Iperk

Mackenzie Bay

Kugmallit

Richards

Eocene

Paleogene

(~Taglu)

? Albian ?

Source 3

Source 4

Pre-Albian

Source 2

Source 1

penetrated inferred

Upper Cretaceous

Paleogene (~Aklak)

Early mature (0.5–0.7% VR)

Mid mature (0.7–1.0% VR)

Late mature (1.0–1.3% VR)

Main gas (1.3–2.6% VR) 40,000

45,000

30,000

10,000

20,000

0

0

Depth subsurface, in feet

150 100 50

C 

Pseudowell 7-10 

EXPLANATION

0

Age, in millions of years

150 100 50

0

1.0

TransformationRatio (fraction)

Reservoir

Seal

Overburden

Trap formation

Source

Sources 1 2 3 4

Quaternary

Neogene

Paleogene 3

Paleogene 2

Paleogene 1

Source 1

Source 2

Source 3

Source 4

Pre-Brookian

Src. Res. Seal

Upper Cretaceous

Lower Cretaceous

Figure 5.—Continued. C, Pseudowell 7-10 in the western part of the Canning-Mackenzie deformed margin assessment unit. D, The Havik 

B-41 well in the eastern part of the Canning-Mackenzie deformed margin assessment unit. The upper part of the stratigraphy is based 

on strata penetrated, and the lower part is based on regional stratigraphic relations. Model constrained by vitrinite-reflectance data 

from Stasiuk and others (2005).
12 Assessment of Undiscovered Petroleum Resources of the Amerasia Basin Petroleum Province

Early mature (0.5–0.7% VR)

Mid mature (0.7–1.0% VR)

Late mature (1.0–1.3% VR)

Main gas (1.3–2.6% VR) 40,000

45,000

30,000

10,000

20,000

0

0

Depth subsurface, in feet

150 100 50

 E 

Pseudowell CPM-03 

EXPLANATION

0

Age, in millions of years

150 100 50

0

1.0

TransformationRatio (fraction)

Reservoir

Seal

Overburden

Trap formation

Source

Sources 1 2 3 4

Src. Res. Seal

Neogene

 (~Kugmallit & 

Mac. Bay)

Paleogene 3

 (~Taglu &

 Richards)

Source 3

Source 4

Pre-Aptian

? Albian ?

Source 2

Source 1

Quaternary

Paleogene 2 (~Taglu)

Paleogene 1 (~Aklak)

Upper Cretaceous

? Aptian ?

Early mature (0.5–0.7% VR)

Mid mature (0.7–1.0% VR)

Late mature (1.0–1.3% VR)

Main gas (1.3–2.6% VR) 40,000

45,000

30,000

10,000

20,000

0

0

Depth subsurface, in feet

150 100 50

 F 

Pseudowell 7-23

EXPLANATION

0

Age, in millions of years

150 100 50

0

1.0

TransformationRatio (fraction)

Reservoir

Seal

Overburden

Trap formation

Source

2 3

4

Sources 1

Src. Res. Seal

Quaternary

Neogene

Paleogene 3

Source 3

Source 4

Basement

Source 2

Source 1

Upper Cretaceous

Lower Cretaceous

Paleogene 2

Paleogene 1

Figure 5. Continued. E, Pseudowell CPM-03 in the southern part of the Canada passive margin assessment unit. F, Pseudowell 7-23 in 

the deep Canada Basin. A, B, C, and F are derived from a regional grid of pseudowells generated for regional modeling (Houseknecht 

and others, 2012b); D and E are derived from a set of wells and pseudowells modeled by the authors specifically for this assessment 

using the procedures of Houseknecht and others (2012b).
Source-Rock Systems 13

Figure 6. 

170°W 166°W 162°W 158°W 154°W 150°W 146°W 142°W 138°W

74°N

73°N

72°N

71°N

70°N

69°N

162°W 158°W 154°W 150°W 146°W 142°W 138°W

74°N

73°N

72°N

71°N

CANADA

U.S.A.

 A 

 B 

0 50 MILES

0 50 KILOMETERS

0 50 MILES

0 50 KILOMETERS

0.5% VR

0.7% VR

1.0% VR

1.3% VR

2.6% VR

EXPLANATION

0.5% VR

0.7% VR

1.0% VR

1.3% VR

2.6% VR

5.0% VR

EXPLANATION

Figure 6. Maps of modeled thermal maturity as indicated by 

ranges of vitrinite reflectance (VR). A, Regional map of modeled 

thermal maturity at the base of the postrift (Brookian) sequence. 

This map includes most of the Arctic Alaska Petroleum Province 

(Houseknecht and others, 2012a) and the following parts of the 

Amerasia Basin Petroleum Province; all of the Alaska passive 

margin AU, the western third of the Canning-Mackenzie deformed 

margin AU, and most of the western and southern parts of the 

Canada Basin AU. The northwestern margin of the map includes 

the southeastern part of the Chukchi Borderland (Northwind 

Ridge). B, Map of modeled thermal maturity at the approximate 

stratigraphic position of the youngest potential source rock in 

the Amerasia Basin (approximately lower–middle Eocene Azolla 

fern facies). Model results in both maps are clipped (dotted and 

dashed perimeter line) to eliminate contouring edge effects. Both 

maps are from Houseknecht and others (2012b).
14 Assessment of Undiscovered Petroleum Resources of the Amerasia Basin Petroleum Province

Canning-Mackenzie Deformed Margin

The Canning-Mackenzie deformed margin AU (USGS 

assessment code 50790101) is the only AU in the Amerasia Basin Province with exploration wells and discovered 

accumulations, although none of those discovered accumulations has been produced. This level of exploration places the 

Canning-Mackenzie deformed margin into uncertainty category 2 on the scale used by the USGS for the Circum-Arctic 

Resource Appraisal. That scale of uncertainty places each AU 

into one of five categories based on data density and degree 

of exploration, as follows: 1, producing fields; 2, discovered 

accumulations; 3, exploration wells; 4, seismic data; and 5, no 

seismic data (Charpentier and Gautier, 2011).

Assessment Unit Description

The Canning-Mackenzie deformed margin AU extends 

from the northern margin of the Alaska rift shoulder (hinge) 

on the south to the limit of contractional folding and faulting within the Cenozoic sediment prism on the north (fig. 7). 

The western and eastern boundaries of the AU are defined by 

the lateral limits of contractional deformation associated with 

ongoing Brooks Range tectonism—the “Canning displacement 

zone”—on the west (Grantz and others, 1990a) and the “Arctic 

platform hingeline” on the east (Dixon and Dietrich, 1990). 

The AU encompasses an area of 97,000 km2

.

The Canning-Mackenzie deformed margin AU lies 

mostly on highly extended continental crust that was attenuated during Jurassic to early Cretaceous rift opening of 

the Canada Basin; the top of basement lies at great depths 

(generally more than 10 km) and cannot be resolved with 

most available seismic data; an exception is recently collected, deep-resolution seismic data that images the top of 

acoustic basement (Helwig and others, 2011). The AU is 

characterized by a thick, growth-faulted, and widely overpressured succession of mostly Cenozoic strata deposited 

on the rifted margin (Scherr and Johnson, 1998; Hayba and 

others, 1999). These strata have been deformed by contraction associated with the Brooks Range tectonic front, which 

has overridden the rift shoulder and propagated northward 

into the prism of rifted-margin strata (Grantz and others, 

1987; Lane, 1998; Lane and Dietrich, 1995; Houseknecht, 

2007). Contractional deformation of the Cenozoic sediment 

prism north of the hinge likely began in the Paleocene and is 

ongoing, as indicated by active seismicity (Dietrich and Lane, 

1992; McMillen and O’Sullivan, 1992; Houseknecht, 2007). 

Locally, mud diapirism has generated uplift and withdrawal 

structures and also has modified many contractional structures 

of tectonic origin. A well-developed gravity fold-and-thrust 

belt extends from the shelf edge to the toe of the marine 

slope and includes “fill-and-spill” slope basins (Houseknecht, 

2007). Jurassic–Lower Cretaceous synrift and Lower–Upper 

Cretaceous postrift strata likely are present but are too deeply 

buried to be exploration objectives except in proximal (southern) parts of the Mackenzie delta.

Geological Analysis of Assessment Unit 

Probability

Although lightly explored, the Canning-Mackenzie 

deformed margin AU contains 14 discovered accumulations 

larger than 50 MMBOE (million barrels of recoverable oil 

equivalent), including 2 oil discoveries on the U.S. Beaufort 

Shelf (Minerals Management Service, 2006; Houseknecht and 

Bird, 2006) and 8 oil and 4 gas discoveries in the Mackenzie 

delta (onshore and offshore; Meneley, 1986; National Energy 

Board, 1998; Osadetz and others, 2005; Johnston, 2007). 

Moreover, the discovery of numerous oil and gas accumulations smaller than 50 MMBOE in the Mackenzie delta, oil 

and gas shows in exploration wells throughout the AU, and 

seeps along the U.S. and Canada coast indicate the presence of an active petroleum system within the AU (Lillis and 

others, 1999). These indications of a viable petroleum charge, 

together with the seismically confirmed presence of numerous 

favorable trap geometries of significant size that have not 

been tested by drilling (Dixon, 1996; Dixon and others, 1994; 

Scherr and Johnson, 1998; Osadetz and others, 2005; Helwig 

and others, 2011), suggest that the probability of at least 

one undiscovered accumulation of at least 50 MMBOE is 

100 percent (table 1).

Charge

Geochemical analysis of oil recovered from wells and 

seeps confirms the presence of Tertiary source rocks in the 

AU, and well samples from the Mackenzie delta confirm 

the local presence of oil- and gas-prone kerogen in carbonaceous shale of Paleogene age (Brooks, 1986a, b; Snowdon, 

1987; Magoon and others, 1999; Snowdon and others, 2004). 

Although no strata of source-rock quality have been reported 

from U.S. exploration wells, the recovery from exploration 

wells and seeps along the U.S. coast of oil geochemically 

typed to Tertiary source rocks indicates the presence of 

Tertiary source rocks—probably at depths that have not been 

penetrated by drilling (Magoon and others, 1999). Paleogene 

oil- and gas-prone source rocks recovered by scientific drilling 

on Lomonosov Ridge, together with regional paleogeographic 

reconstructions (Houseknecht and Bird, 2011; Houseknecht 

and others, 2012b), suggest that Paleogene source rocks 

may be present across the entire deepwater parts of the 

Amerasia Basin.

Geochemistry of produced oil around the southern rim of 

the Mackenzie delta, together with regional paleogeographic 

reconstructions, indicates a high probability for the presence 

of Upper Cretaceous (most likely Turonian) oil-prone source 

rocks throughout the AU (Snowdon 1980; Dixon and others 

1992; Dixon 1996; Threlkeld and others, 2000; unpublished 

data). Regional tectonic and paleogeographic reconstructions 

suggest that it also is possible that Jurassic–Lower Cretaceous 

synrift or early postrift source rocks may be present, at least 

locally. Although these strata would certainly be overmature 

today, hydrocarbons generated as those source rocks passed 
Canning-Mackenzie Deformed Margin 15

Figure 7.

0 20 40 MILES

200 40 KILOMETERS

Map

area

Assessment unit

Median extent of permanent ice—Month of 

September (1976–2006)

Exploration well

Location of pseudowells and wells

Bathymetric contour—Interval, in meters, is 

variable. Datum is sea level

Approximate oil/gas (green/red)—Proportion 

based on limited information

Accumulation of known size (scale below) showing 

oil/gas (green/red)—Proportion based on 

production and reserves data

EXPLANATION

16,384–32,768 MMBOE

8,192–16,384 MMBOE

4,096–8,192 MMBOE

2,048–4,096 MMBOE

1,024–2,048 MMBOE

512–1,024 MMBOE

256–512 MMBOE

128–256 MMBOE

64–128 MMBOE

<64 MMBOE

-500

-2000

-2500

-1500

-3000

-1000

-3500

-200

-100

CANNING-MACKENZIE DEFORMED MARGIN

CANADA

UNITED STATES

Fig. 2C

4C-Adlartok

4D-Sarpik

4F-Hansen

4G-Amerk

4H-Havik

4E-Ikhil

4A-Corona

4B-Belcher

5C-pseudowell 7-10

5D-Havik B-41

Hammerhead

Kuvlum

ALASKA

145°W 140°W 135°W 130°W

68°N

70°N

72°N

Figure 7. Map of the Canning-Mackenzie deformed margin assessment unit showing exploration wells, known petroleum 

accumulations, line of cross section shown in fig. 2C, locations of wells for which depth versus vitrinite reflectance data are shown in 

fig. 4, and locations of pseudowells and wells for which petroleum systems plots are shown in fig. 5.
16 Assessment of Undiscovered Petroleum Resources of the Amerasia Basin Petroleum Province

Table 1. Summary of assessment unit probabilities and key input parameters for numbers and sizes of 

undiscovered, conventional accumulations for the Canning-Mackenzie deformed margin assessment unit.

Assessment Unit Probabilities: (Adequacy for at least one undiscovered field of minimum size)

 Attribute Probability of occurrence (0–1.0)

1. CHARGE: Adequate petroleum charge: 1.0

2. ROCKS: Adequate reservoirs, traps, and seals: 1.0

3. TIMING OF GEOLOGIC EVENTS: Favorable timing: 1.0

Assessment Unit GEOLOGIC Probability (Product of 1, 2, and 3): 1.0

UNDISCOVERED ACCUMULATIONS

Number of Undiscovered Accumulations: How many undiscovered accumulations exist

that are at least the minimum size? (uncertainty of fixed but unknown values)

Total Accumulations: minimum (>0) 15 median 40 maximum 125

Oil/Gas Mix: minimum (>0 0.4 mode 0.7 maximum 0.8

X # of oil accumulations / # of total accumulations

# of oil accumulations / # of gas accumulations

# of gas accumulations / # of oil accumulations

Oil Accumulations: minimum (>0) 6 median 25 maximum 100

Gas Accumulations: minimum (>0) 3 median 15 maximum 75

Sizes of Undiscovered Accumulations: What are the sizes (grown) of the above accumulations?

 (variations in the sizes of undiscovered accumulations)

Oil in Oil Accumulations (mmbo): minimum 50 median 125 maximum 5,000

Gas in Gas Accumulations (bcfg): minimum 300 median 600 maximum 15,000

through the oil window may be preserved. Modeling suggests that oil generation likely began during the Paleogene in 

the Mackenzie delta depocenter, Canadian Beaufort Sea, and 

easternmost U.S. Beaufort Sea and progressively migrated 

westward and northward through the Neogene (Houseknecht 

and others, 2012b).

Rocks

Proven reservoirs include Paleocene through Oligocene 

sandstone (Aklak, Taglu, Richards, and Kugmallit Formations in Canada; Canning and Sagavanirktok Formations in 

the United States). Proven and potential reservoir rocks range 

from deepwater sediment-gravity-flow and turbidite facies 

through shallow-marine, deltaic, and perhaps fluvial facies; all 

these reservoir facies commonly are characterized by lenticular geometry (Molenaar, 1983; Dixon and others, 1992; Dixon, 

1996; Scherr and Johnson, 1998). Significant stratigraphic 

thickening across growth faults is common. Seals include shale 

and mudstone in the Paleocene through Oligocene succession, 

and seal integrity and capacity are demonstrated by a large 

number of discovered oil and gas accumulations. Discovered 

accumulations have been found in structural, combination, and 

stratigraphic traps (Meneley, 1986; Enachescu, 1990; Dixon, 

1996; Scherr and Johnson, 1998). The largest discovered accumulations and the potential for undiscovered accumulations 

larger than 50 MMBOE mostly are associated with contractional anticlines in which reservoir volume and geometry are 

influenced by growth faults and facies lenticularity. However, a 

spectrum of trap types is present and includes closures associated with tectonic, gravity, and diapiric anticlines; tectonic and 

gravity thrust faults; growth faults; localized withdrawal and 
Canning-Mackenzie Deformed Margin 17

slope basins; and a variety of lenticular sandstone facies (see, 

for example, Bergquist and others, 2003).

Timing and Preservation

Modeling suggests that oil generation began in the 

Mackenzie delta depocenter during the Paleocene and radiated 

outward to the west and north during the Eocene through 

Holocene as thick, progressively offlapping sequences were 

deposited. Much contractional structuring was syndepositional 

or early postdepositional. Thus, timing was excellent for 

early charging of relatively young reservoirs in both structural and stratigraphic traps. The potential for preservation 

of reservoired hydrocarbons also is considered excellent, as 

indicated by the large number of discovered accumulations. 

Ongoing contractional deformation, indicated by active seismicity, may indicate the local potential for trap disruption and 

leakage of hydrocarbons.

Analogs Used for Assessment

Assessment input was influenced by the geology, size, 

and number of discovered accumulations in the AU and by 

the assessments of undiscovered resources conducted by the 

Minerals Management Service (MMS) (Scherr and Johnson, 

1998; Minerals Management Service, 2006) and the Geological Survey of Canada (GSC) (Dixon and others, 1994; Chen 

and others, 2007), which were largely based on the mapping 

of favorable trap geometries from seismic data. Analogs were 

selected from the USGS World Analog Database (Charpentier 

and others, 2008) in two stages: (1) a two-tier search of rifted 

passive margin architecture plus compressional structural 

setting and (2) a combined search of trap systems comprising compressional anticlines, folds, and thrusts developed 

on transitional to oceanic basement plus delta trap systems. 

The resulting analog set was culled to eliminate salt structures, basement-involved block structures, and other geologic 

parameters judged to be inappropriate for this AU. The final 

analog set consists of 34 AUs (table 2).

Assessment Inputs

Number of Accumulations

Considering the lightly explored nature of this AU, a 

minimum number of 15 accumulations of at least 50 MMBOE 

was selected because that approximately equals the 14 discovered accumulations of at least 50 MMBOE. The analog set 

displays a fairly uniform distribution of accumulation density 

up to about 1.5 accumulations larger than 50 MMBOE/1,000 

km2, with a single outlier at 2.4. Considering that 14 accumulations greater than the minimum size have been discovered, 

input values of 15 (0.15 density) at the minimum, 40 (0.40 

density) at the median, and 125 (1.26 density) at the maximum 

were selected (table 1).

Oil-to-Gas Mix

The minimum, median, and maximum values of the oilto-gas ratio were set at 0.4, 0.7, and 0.8 (table 1) on the basis 

of the ratio of oil/gas accumulations in the discovered population (larger than 50 MMBOE) and geologic reasoning regarding the spatial distribution of oil- versus gas-prone source 

rocks across the AU.

Accumulation Size Distribution

The median oil accumulation size was set at 125 MMBO 

(table 1) on the basis of sizes of discovered accumulations in 

the AU; this value also closely matches the median and mean 

values of the median accumulation size in the analog set. The 

maximum oil accumulation size was set at 5 BBO (billion 

barrels of recoverable oil; table 1) on the basis of size of the 

largest untested structures and the size of the largest known 

accumulations in the analog population, which is between 5 

and 6 BBO. Median and maximum input values of 600 BCF 

(billion cubic feet of recoverable gas) and 15 TCF (trillion 

cubic feet of recoverable gas) were set for gas accumulation 

sizes by the same line of reasoning (table 1).

Province Geologist’s Estimated Maximum 

Accumulation Size

Maximum accumulation sizes of about 1 BBO and 2 to 3 

TCFG were selected on the basis of size distribution of discovered accumulations, the largest accumulation sizes assessed 

by MMS and GSC using a large seismic database to constrain 

trap sizes, and analysis of seismic and well data available to 

the USGS. These maximum sizes, which did not enter directly 

into the volumetric calculations, were used to judge the reasonableness of the results of statistical analysis.

Ancillary Properties and Co-Product Ratios

Data from discovered pools in this AU and from geochemistry of source rocks were used to establish input values 

for these parameters.

Results

Probabilistic estimates of volumes of undiscovered, technically recoverable hydrocarbons for the Canning-Mackenzie 

AU are summarized in table 3. These results include mean 

estimates of more than 6 BBO, nearly 20 TCF associated gas, 

and 16 TCF nonassociated gas.
18 Assessment of Undiscovered Petroleum Resources of the Amerasia Basin Petroleum Province

Table 2. Analog assessment units used to constrain input parameters for the Canning-Mackenzie deformed margin assessment unit. 

Analog data from Charpentier and others (2008). 

[AU, assessment unit; TPS, total petroleum system]

AU Code AU name TPS name Province name

11120101 Apsheron-Pribalkhan Zone Oligocene-Miocene Maykop/Diatom South Caspian Basin

11120102 Lower Kura Depression and Adjacent Shelf Oligocene-Miocene Maykop/Diatom South Caspian Basin

11120103 Gograndag-Okarem Zone and Adjacent Shelf Oligocene-Miocene Maykop/Diatom South Caspian Basin

11120104 Central Offshore Oligocene-Miocene Maykop/Diatom South Caspian Basin

11120105 Iran Onshore/Nearshore Oligocene-Miocene Maykop/Diatom South Caspian Basin

20160201 Natih-Fiqa Structural/Stratigraphic Middle Cretaceous Natih Fahud Salt Basin

20230202 Basinal Oil and Gas Jurassic Gotnia/Barsarin/Sargelu/Najmah Widyan Basin-Interior 

Platform

20480101 Bou Dabbous-Tertiary Structural/Stratigraphic Bou Dabbous-Tertiary Pelagian Basin

20480201 Jurassic-Cretaceous Structural/Stratigraphic Jurassic-Cretaceous Composite Pelagian Basin

37010101 Brunei-Sabah Deltaics Brunei-Sabah Baram Delta/Brunei-Sabah 

Basin

37010102 Brunei-Sabah Turbidites Brunei-Sabah Baram Delta/Brunei-Sabah 

Basin

38170101 Kutei Basin Deltaics Kutei Basin Kutei Basin

38170102 Kutei Basin Turbidites Kutei Basin Kutei Basin

38170103 Kutei Basin Fold and Thrust Belt Kutei Basin Kutei Basin

39100201 Petrel Keyling/Hyland Bay-Permian Bonaparte Gulf Basin

39100301 Malita Jurassic/Early Cretaceous-Mesozoic Bonaparte Gulf Basin

60210101 Late Cretaceous-Tertiary Turbidites Cenomanian-Turonian Guyana-Suriname Basin

60220101 Amazon Delta and Submarine Fan Neogene Foz do Amazonas Basin

60340103 Abrolhos Sub-Volcanic Structures Cretaceous Composite Espirito Santo Basin

60370101 Pelotas Platform and Basin Cenomanian-Turonian-Tertiary Composite Pelotas Basin

60410101 Hollin-Napo Mesozoic-Cenozoic Putumayo-OrienteMaranon Basin

60980201 Trinidad Basins Upper Cretaceous/Tertiary East Venezuela Basin

61030101 Carupano Basin Gas Lower Cruse Tobago Trough

61070101 Inner Forearc Deformation Belt Tobago Trough Paleogene Lesser Antilles Deformed 

Belt

71920101 Agbada Reservoirs Tertiary Niger Delta (Agbada/Akata) Niger Delta

71920102 Akata Reservoirs Tertiary Niger Delta (Agbada/Akata) Niger Delta

72030301 Central Congo Delta and Carbonate Platform Congo Delta Composite West-Central Coastal

72030302 Central Congo Turbidites Congo Delta Composite West-Central Coastal

72030401 Cuanza-Namibe Cuanza Composite West-Central Coastal

73030101 Offshore Cretaceous Composite Orange River Coastal

80420102 Indus Fan Sembar-Goru/Ghazij Indus

80470302 Eastern Fold Belt Jenam/Bhuban-Bokabil Ganges-Brahmaputra Delta

80480101 Central Burma Basin Eocene to Miocene Composite Irrawaddy

80480102 Irrawaddy-Andaman Eocene to Miocene Composite Irrawaddy
Canning-Mackenzie Deformed Margin 19

Table 3. Summary of results for risked, undiscovered, technically recoverable petroleum resources for the Amerasia Basin Province, 

including results for the Canning-Mackenzie deformed margin, Alaska passive margin, Canada Basin, and Canada passive margin 

assessment units.

[F95 represents a 95-percent chance of at least the amount tabulated; other fractiles are defined similarly. Std. dev., standard deviation; DM, deformed margin. 

Because the assessment unit probability for the Canada Basin was less than 0.1, the unit was not quantitatively assessed, and no statistical results are listed 

below.]

Assessment unit name Assessment unit probability

Canning-Mackenzie DM 1.000

Alaska passive margin 0.540

Canada Basin 0.050

Canada passive margin 0.540

Assessment unit name F95 F50 F5 Mean Std. dev.

Oil, in millions of barrels (MMBO)

Canning-Mackenzie DM 2,518.34 5,697.36 12,566.69 6,380.64 3,230.00

Alaska passive margin 0.00 886.94 2,900.42 972.23 1,062.11

Canada passive margin 0.00 1,760.64 7,718.95 2,370.71 2,840.77

Associated/dissolved gas, in billions of cubic feet (BCFG)

Canning-Mackenzie DM 7,146.42 17,229.69 41,198.11 19,799.52 11,026.40

Alaska passive margin 0.00 2,463.67 9,391.56 3,021.03 3,423.24

Canada passive margin 0.00 5,127.64 24,410.54 7,348.82 8,922.70

Natural gas liquids, in millions of barrels (MMBNGL)

Canning-Mackenzie DM 48.85 126.32 325.67 148.99 93.86

Alaska passive margin 0.00 16.42 73.71 22.71 27.10

Canada passive margin 0.00 35.50 187.39 55.27 68.55

Nonassociated gas, in billions of cubic feet (BCFG)

Canning-Mackenzie DM 5,661.40 13,867.14 34,298.55 16,102.74 9,339.49

Alaska passive margin 0.00 1,850.38 9,676.02 2,866.13 3,509.58

Canada passive margin 0.00 3,995.34 28,482.78 7,752.97 10,659.14

Liquids, in millions of barrels (MMBL)

Canning-Mackenzie DM 60.70 160.86 417.14 189.54 117.40

Alaska passive margin 0.00 18.99 118.84 33.68 43.12

Canada passive margin 0.00 42.90 341.53 91.52 127.61

Largest oil, in millions of barrels (MMBO)

Canning-Mackenzie DM 401.66 1,074.64 3,233.84 1,332.88 886.38

Alaska passive margin 150.76 286.43 647.56 325.87 155.39

Canada passive margin 219.78 369.63 645.30 391.65 128.36

Largest nonassociated gas, in billions of cubic feet (BCFG)

Canning-Mackenzie DM 1,126.45 2,852.91 8,836.43 3,596.21 2,470.22

Alaska passive margin 617.40 1,284.61 3,230.03 1,510.15 848.47

Canada passive margin 976.97 1,828.61 3,497.19 1,972.11 766.82
20 Assessment of Undiscovered Petroleum Resources of the Amerasia Basin Petroleum Province

Alaska Passive Margin

The Alaska passive margin AU (USGS assessment code 

50790102) contains no exploration wells and only sparse seismic data. This level of exploration places the Alaska passive 

margin into uncertainty category 4 on the scale used by the 

USGS for the Circum-Arctic Resource Appraisal (Charpentier 

and Gautier, 2011).

Assessment Unit Description

The Alaska passive margin AU extends from the northern 

margin (hinge) of the Alaska rift shoulder on the south to the 

approximate base of the Beaufort Sea marine slope (about 

3,500 m water depth), which is inferred to be the northward 

limit of gravity folding and slumping (fig. 8). The western 

boundary of the AU is defined by the eastern margin of the 

Chukchi Borderland. The eastern boundary of the AU is 

defined by the Canning displacement zone (Grantz and others, 

1990b), an active left-lateral zone of displacement that defines 

the western limit of the Canning-Mackenzie deformed margin 

AU. The AU encompasses an area of 93,000 km2.

The Alaska passive margin AU lies mostly on extended 

continental crust that was attenuated during Jurassic–Early 

Cretaceous rift opening of the Canada Basin. The top of 

basement lies at great depths (generally more than 10 km) 

and cannot be resolved with available seismic data. The AU 

is characterized by a thick, growth-faulted, and probably 

overpressured succession of mostly Cenozoic strata deposited 

on the rifted margin. Cretaceous (and perhaps Jurassic) strata 

likely are present but are buried beneath such a great thickness 

of Cenozoic strata that they cannot be identified in seismic 

data and are unlikely to be oil or gas prospective. In particular, a thick succession of Lower Cretaceous strata is assumed 

to be present just north of the hinge (fig. 2A) on the basis of 

seismic evidence that Early Cretaceous depositional systems 

overstepped the rift shoulder along the northeast margin of the 

Chukchi shelf (Houseknecht and others, 2009). The presence 

of a gravity fold belt beneath the marine slope is suggested 

by seismic imaging of large-displacement listric growth faults 

beneath the outer shelf, normal faults that offset the seafloor at 

the shelf margin, and detachment folds in the upper part of the 

Cenozoic sediment prism beneath the upper slope. However, 

the presence of a gravity fold system beneath most of the 

marine slope cannot be confirmed because no seismic data are 

available beyond the uppermost slope.

Geological Analysis of Assessment Unit 

Probability

Even though no exploration wells have been drilled in 

the Alaska passive margin AU, available evidence suggests 

a generally favorable probability for the presence of at least 

one accumulation of at least 50 MMBOE (table 4). Charge is 

viewed as the greatest risk factor.

Charge

There is no direct evidence of an active petroleum system 

in the Alaska passive margin AU. To the east, an active petroleum system is present in the Canning-Mackenzie deformed 

margin AU, with confirmed Tertiary oil in two discoveries of at 

least 50 MMBO (Hammerhead and Kuvlum, fig. 8) (Scherr and 

Johnson, 1998; Minerals Management Service, 2006; Houseknecht and Bird, 2006) a short distance east of the AU and in 

numerous shows in exploration wells and seeps along the coast 

(Houseknecht and others, 2012b). Paleogene oil- and gasprone source rocks recovered by scientific drilling on Lomonosov Ridge suggest that source rocks may be present across the 

entire Amerasia Basin. This inference is supported by palynological data indicating the presence of the Azolla fern facies in 

two wells (Popcorn and Crackerjack) (Jonathan P. Bujak, Bujak 

Research International, written commun., 2007) in the northern 

part of the Chukchi shelf, although the mudstone in which the 

Azolla facies occurs is not of source-rock quality in those two 

wells. Regional tectonic and paleogeographic reconstructions 

suggest that it also is likely that Jurassic–Lower Cretaceous 

synrift and Lower–Upper Cretaceous postrift source rocks may 

be present in the AU. Although these strata would certainly 

be overmature today, hydrocarbons generated as those source 

rocks were buried through the oil window may be preserved. 

Modeling suggests that oil generation likely began during the 

Early Cretaceous and progressively migrated eastward and 

northward through the Late Cretaceous and Tertiary (Houseknecht and others, 2012b). On the basis of this mostly circumstantial evidence, yet regionally favorable prognosis, a charge 

probability of 0.6 is assigned to this AU (table 4).

Rocks

Even though seismic data demonstrate the presence of 

more than 10 km of growth-faulted strata along the southern 

margin of this AU, the exact age of those strata is unknown 

(because no wells exist to provide age constraints), and 

seismic correlation across large-displacement growth faults 

is not possible. Regional relations suggest that most of this 

succession is Paleocene and younger and that it is composed 

of mostly mudstone and sandstone. On the basis of seismic 

similarities and apparent continuity of depositional sequences 

from the Chukchi shelf to the south and from the Beaufort 

Shelf to the east, these strata probably include good reservoirquality sandstone and seal-quality mudstone. The largest 

potential traps observed in seismic data are large-displacement 

(hundreds of meters) growth-fault systems. Smaller potential 

traps may include low-stand, shelf-margin truncations and 

channelized facies in both deepwater and shallow-water facies. 

A rock probability of 0.9 (table 4) is assigned on the basis of 

these generally favorable parameters.
Alaska Passive Margin 21

Figure 8.

Assessment unit

Median extent of permanent ice—Month of 

September (1976–2006)

Exploration well

Location of pseudowells and wells

Bathymetric contour—Interval, in meters, is 

variable. Datum is sea level

Approximate oil/gas (green/red)—Proportion 

based on limited information

Accumulation of known size (scale below) showing 

oil/gas (green/red)—Proportion based on 

production and reserves data

0 20 40 MILES

0 20 40 KILOMETERS

EXPLANATION

16,384–32,768 MMBOE

8,192–16,384 MMBOE

4,096–8,192 MMBOE

2,048–4,096 MMBOE

1,024–2,048 MMBOE

512–1,024 MMBOE

256–512 MMBOE

128–256 MMBOE

64–28 MMBOE

<64 MMBOE

Map

area

-200

-500

-3800

-3500

-100

-1500

-500

Fig. 2A

Fig. 2

B

5A-pseudowell 1-16

5B-pseudowell 4-18

Hammerhead

Kuvlum

ALASKA

ALASKA PASSIVE MARGIN

165°W 160°W 145°W

74°N

70°N

72°N

155°W 150°W

Figure 8. Map of the Alaska passive margin assessment unit showing exploration wells and known petroleum accumulations in 

adjacent areas (there are no wells in this AU), line of cross sections shown in fig. 2A and 2B, and locations of pseudowells and wells for 

which petroleum systems plots are shown in fig. 5.
22 Assessment of Undiscovered Petroleum Resources of the Amerasia Basin Petroleum Province

Table 4. Summary of assessment unit probabilities and key input parameters for numbers and sizes of 

undiscovered, conventional accumulations for the Alaska passive margin assessment unit.

Assessment Unit Probabilities: (Adequacy for at least one undiscovered field of minimum size)

 Attribute Probability of occurrence (0–1.0)

1. CHARGE: Adequate petroleum charge: 0.6

2. ROCKS: Adequate reservoirs, traps, and seals: 0.9

3. TIMING OF GEOLOGIC EVENTS: Favorable timing: 1.0

Assessment Unit GEOLOGIC Probability (Product of 1, 2, and 3): 0.54

UNDISCOVERED ACCUMULATIONS

Number of Undiscovered Accumulations: How many undiscovered accumulations exist

that are at least the minimum size? (uncertainty of fixed but unknown values)

Total Accumulations: minimum (>0) 1 median 20 maximum 50

Oil/Gas Mix: minimum (>0 0.4 mode 0.7 maximum 0.9

X # of oil accumulations / # of total accumulations

# of oil accumulations / # of gas accumulations

# of gas accumulations / # of oil accumulations

Oil Accumulations: minimum (>0) 1 median 13 maximum 45

Gas Accumulations: minimum (>0) 0 median 6 maximum 30

Sizes of Undiscovered Accumulations: What are the sizes (grown) of the above accumulations?

 (variations in the sizes of undiscovered accumulations)

Oil in Oil Accumulations (mmbo): minimum 50 median 100 maximum 1,000

Gas in Gas Accumulations (bcfg): minimum 300 median 600 maximum 6,000

Timing and Preservation

Oil generation may have begun in the Early Cretaceous 

and radiated outward to the east and north during the Tertiary 

as thick, progressively offlapping sequences were deposited. 

All potential traps are syndepositional, and so timing was 

excellent for early charging of relatively young reservoirs. The 

potential for preservation of reservoired hydrocarbons also is 

considered excellent, as suggested by hydrocarbon accumulations that have been discovered in similar sequences in adjacent AUs (Canning-Mackenzie deformed margin and Arctic 

Alaska platform; Houseknecht and others, 2012a). Thus, a 

timing and preservation probability of 1.0 is assigned (table 4).

Analogs Used for Assessment

Assessment input was influenced by the geology, sizes, 

and numbers of discovered accumulations in adjacent AUs 

(Houseknecht and others, 2012a) and by the assessment of 

undiscovered resources conducted by the MMS (Scherr and 

Johnson, 1998; Minerals Management Service, 2006), which 

was largely based on the mapping of favorable trap geometries 

from 2-D seismic data. Although seismic data are available 

within the Alaska passive margin AU, they are limited to the 

southernmost portion of the AU. Analogs were selected from 

the USGS World Analog Database (Charpentier and others, 

2008) in two stages: (1) results returned from a search of 

rifted passive margin architecture were culled by eliminating 

salt structures, basement-related normal faulting, carbonate 

reservoirs, and other inappropriate geological parameters, and 

(2) a search of gravity-induced growth-fault trap systems. The 

resulting analog set was edited to remove geological characteristics deemed inappropriate for this AU. The final analog set 

consists of 20 AUs (table 5).
Alaska Passive Margin 23

Assessment Inputs

Number of Accumulations

The analog set displays an approximately log-normal 

distribution of accumulation density with many values 

between 0 and 0.2 and several values up to about 0.5 accumulations of at least 50 MMBOE/1,000 km2

, and with two outliers at 0.8 and 1.2. Accordingly, input values of 1 (0.06 density) 

at the minimum, 20 (0.29 density) at the median, and 50 (0.58 

density) at the maximum were selected (table 4).

Oil-to-Gas Mix

The minimum, median, and maximum values of the oilto-gas ratio were set at 0.4, 0.7, and 0.9 (table 4) on the basis 

of the expected similarity with the active petroleum system 

of the Canning-Mackenzie deformed margin AU. The higher 

value of 0.9 at the maximum reflects our interpretation that 

source rocks may be more oil-prone farther from the Mackenzie delta influx of terrigenous clastic sediment.

Accumulation Size Distribution

The median oil accumulation size was set at 100 MMBO 

(table 4) on the basis of the sizes of discovered accumulations 

in Tertiary sandstone reservoirs in adjacent AUs (Houseknecht 

and others, 2012a); this value also closely matches the median 

and mean values of the median accumulation size in the analog set. The maximum oil accumulation size was set at 1 BBO 

(table 4) on the basis of the distribution of the largest known 

accumulations in the analog population, which is between 

1 and 2 BBO. Median and maximum input values of 600 BCF 

and 6 TCF (table 4) were set for gas accumulation sizes by the 

same line of reasoning.

Province Geologist’s Estimated Maximum 

Accumulation Size

Maximum accumulation sizes of 250–300 MMBO and 

1–2 TCFG were selected on the basis of the size distribution 

of discovered accumulations in Tertiary reservoirs in adjacent 

AUs (Houseknecht and others, 2012a), the largest accumulation sizes assessed by MMS (Sherwood and others, 1998; 

Table 5. Assessment units used to constrain input parameters for the Alaska passive margin and Canada passive margin assessment 

units. Analog data from Charpentier and others (2008). 

[AU, assessment unit; TPS, total petroleum system]

AU Code AU name TPS name Province name

40170102 Mid-Norway Continental Margin Upper Jurassic Spekk Vestford-Helgeland

40480101 Greater Hungarian Plain Basins Greater Hungarian Plain Neogene Pannonian Basin

40480201 Zala-Drava-Sava Basins Zala-Drava-Sava Mesozoic/Neogene Pannonian Basin

40480301 Danube Basin Danube Neogene Pannonian Basin

40480401 Transcarpathian Basin Transcarpathian Neogene Pannonian Basin

60210101 Late Cretaceous-Tertiary Turbidites Cenomanian-Turonian Guyana-Suriname Basin

60210103 Late Cretaceous-Tertiary Nearshore 

Sandstones

Cenomanian-Turonian Guyana-Suriname Basin

60220101 Amazon Delta and Submarine Fan Neogene Foz do Amazonas Basin

60290102 Late Cretaceous-Tertiary Deep-Water 

Sandstones

Neocomian to Turonian Composite Sergipe-Alagoas Basin

60360101 Santos Shelf Guaratiba-Guaruja (Cretaceous) Composite Santos Basin

60370101 Pelotas Platform and Basin Cenomanian-Turonian-Tertiary Composite Pelotas Basin

60980202 Orinoco Delta and Offshore Upper Cretaceous/Tertiary East Venezuela Basin

70130101 Coastal Plain and Offshore Cretaceous-Tertiary Composite Senegal

71920101 Agbada Reservoirs Tertiary Niger Delta (Agbada/Akata) Niger Delta

73030101 Offshore Cretaceous Composite Orange River Coastal

80420102 Indus Fan Sembar-Goru/Ghazij Indus

80470201 Western Shelf and Slope Jalangi-Sylhet/Burdwan Composite Ganges-Brahmaputra Delta

80470301 Central Basin Jenam/Bhuban-Bokabil Ganges-Brahmaputra Delta

80470302 Eastern Fold Belt Jenam/Bhuban-Bokabil Ganges-Brahmaputra Delta

80480102 Irrawaddy-Andaman Eocene to Miocene Composite Irrawaddy
24 Assessment of Undiscovered Petroleum Resources of the Amerasia Basin Petroleum Province

Minerals Management Service, 2006) using a large seismic 

database to constrain trap sizes, and analysis of seismic data 

available to the USGS. These maximum sizes, which did not 

enter directly into the volumetric calculations, were used to 

judge the reasonableness of the results of statistical analysis.

Ancillary Properties and Co-Product Ratios

Data from discovered pools in Tertiary sandstone reservoirs in adjacent AUs (Houseknecht and others, 2012a) and 

expected geochemistry of potential source rocks were used to 

establish input values for these parameters.

Results

Probabilistic estimates of volumes of undiscovered, 

technically recoverable hydrocarbons for the Alaska passive 

margin AU are summarized in table 3. These results include 

mean estimates of nearly 1 BBO, 3 TCF associated gas, and 

nearly 3 TCF nonassociated gas.

Canada Basin

The Canada Basin AU (USGS assessment code 

50790103) contains no exploration wells and only sparse seismic data. This level of exploration places the Canada Basin 

into uncertainty category 4 on the scale used by the USGS 

for the Circum-Arctic Resource Appraisal (Charpentier and 

Gautier, 2011).

Assessment Unit Description

The southern and eastern boundaries of the Canada 

Basin AU are defined by the basinward limits of the Alaska 

passive margin, Canning-Mackenzie deformed margin, and 

Canada passive margin AUs. These boundaries are defined 

by a variety of geological, geophysical, and bathymetrical 

observations described in the descriptions of those adjacent 

AUs. The western boundary of the AU is the base of the 

Northwind escarpment along the eastern margin of the 

Chukchi Borderland, and the northern boundary is defined by 

onlap thinning (to less than 2 km) of Canada Basin strata onto 

the southern margin of the Alpha-Mendeleev large igneous 

province (fig. 9). The Canada Basin AU encompasses an area 

of 673,000 km2.

This AU is characterized by a poorly known basement 

that may include highly attenuated continental and transitional 

crust, as well as oceanic crust inferred to be no younger than 

Barremian (Grantz and others, 1990b, 2009, 2011a, b), all 

overlain by a succession of Cretaceous and Cenozoic strata 

that mostly represents sediments dispersed from the Mackenzie delta and from other continental margins around the 

western (Chukchi Borderland), southern (Arctic Alaska), and 

eastern (Arctic Canada) margins of the AU. The thickness of 

this sedimentary succession ranges from about 2 km in the 

northwest to more than 12 km in the southeast, adjacent to the 

Mackenzie delta (May and Grantz, 1990; Jackson and Oakey, 

1990). The thickness of this sedimentary succession directly 

controls the bathymetry of the Canada Basin, with the thinnest succession underlying the deepest-water part of the basin 

and the thickest succession underlying the distal ramp of the 

Mackenzie delta (fig. 9).

No active petroleum systems are known in the Canada 

Basin AU; however, regional considerations suggest that shale 

representing organic-rich condensed sections likely are present in the Cretaceous and Paleogene parts of the succession. 

Modeling suggests that burial of these inferred source rocks 

beneath Cretaceous through Cenozoic strata has been sufficient to generate hydrocarbons in some—but not all—parts of 

the AU (figs. 5, 6; Houseknecht and others, 2012b).

Geological Analysis of Assessment Unit 

Probability

Available evidence suggests a generally unfavorable probability (less than 10 percent) for the presence of at least one 

accumulation of at least 50 MMBOE. Both charge and rocks are 

viewed as significant risk factors, as explained below.

Charge

There is no direct evidence of an active petroleum system 

in the Canada Basin AU. To the southeast, an active petroleum system is present in the Canning-Mackenzie deformed 

margin AU, with confirmed Tertiary oil in multiple discoveries larger than 50 MMBO in the offshore Mackenzie delta 

region and in the Alaska Beaufort Sea immediately adjacent 

to the AU. Paleogene oil- and gas-prone mudstone and shale 

recovered by scientific drilling on Lomonosov Ridge suggest 

that source rocks may be present across the entire Amerasia 

Basin, an inference deemed probable based on tectonic and 

paleogeographic reconstructions. Upper Cretaceous shale, the 

distal equivalents of the Seabee Formation of Arctic Alaska, 

the Smoking Hills Formation of the Mackenzie delta region, 

and the lower part of the Kanguk Formation in the Canadian 

Arctic Islands, are likely present and may include oil-prone 

source rocks throughout the AU (Houseknecht and Bird, 

2011). Regional tectonic and paleogeographic reconstructions 

suggest that it also is possible that Jurassic–Lower Cretaceous 

synrift and postrift source rocks may be present in the AU. 

Modeling (fig. 5F) suggests that oil generation likely began 

along the southern and eastern margins of the AU during the 

Miocene and migrated basinward to the present (Houseknecht 

and others, 2012b) and that hydrocarbon generation sufficient 

to generate at least one accumulation of the minimum size 

probably has occurred across 20 to 40 percent of the area of 

the AU. On the basis of this mostly circumstantial evidence, a 

charge probability of 0.5 is assigned to this AU.
Canada Basin 25

Figure 9.

0 40 80 MILES

400 80 KILOMETERS

Map

area

Assessment unit

Median extent of permanent ice—Month of 

September (1976–2006)

Exploration well

Location of pseudowells and wells

Bathymetric contour—Interval, in meters, is 

variable. Datum is sea level

Approximate oil/gas (green/red)—Proportion 

based on limited information

Accumulation of known size (scale below) showing 

oil/gas (green/red)—Proportion based on 

production and reserves data

EXPLANATION

16,384–32,768 MMBOE

8,192–16,384 MMBOE

4,096–8,192 MMBOE

2,048–4,096 MMBOE

1,024–2,048 MMBOE

512–1,024 MMBOE

256–512 MMBOE

128–256 MMBOE

64–128 MMBOE

<64 MMBOE

-3000

-3000

-200

-100

-500

-1500

-2000

-200

-2500

-100

-1000

-3500

-500

-200

-500

-1000

-2000

-3800

-1000

-3500

-2500

-2000

-1000

-3000

-2000

-1500

CANADA BASIN

Fig. 3

Fig. 2C

Fig. 2

B

Fig. 2A

5F-pseudowell 7-23

5E-pseudowell CPM-03

5A-pseudowell 1-16

5B-pseudowell 4-18

5D-Havik B-41

Northwind Escarpment

170°W 160°W 150°W 140°W 130°W 120°W

75°N

80°N

Figure 9. Map of the Canada Basin assessment unit showing exploration wells and known petroleum accumulations in adjacent areas 

(there are no wells in this AU), lines of cross section shown in figs. 2 and 3, and locations of pseudowells and wells for which petroleum 

systems plots are shown in fig. 5.
26 Assessment of Undiscovered Petroleum Resources of the Amerasia Basin Petroleum Province

Rocks

The potential exists in the Canada Basin for prospective 

strata ranging in age from Jurassic through Neogene. Jurassic 

to Lower Cretaceous strata may occur in rift basins around 

the western (Chukchi Borderland), southern (Arctic Alaska), 

and eastern (Arctic Canada) margins of the AU. If present, 

these strata are likely buried beneath 3 to 10 km of Upper 

Cretaceous through Cenozoic strata, and the probability that 

reservoir quality and trap geometry are preserved beneath 

this overburden is considered low. Lower Cretaceous through 

Cenozoic strata probably are mostly distal facies associated with sediment dispersal systems emanating from the 

Mackenzie delta and the Alaska and Canada passive margins. 

Although sand-prone turbidite facies may be present in these 

strata, it is likely they are fine grained, and the probability that 

their volume and reservoir quality are sufficient to trap at least 

50 MMBOE in an individual accumulation is considered low. 

The AU probably contains mostly stratigraphic trap geometries related to deepwater sediment-gravity-flow and turbidite 

depositional systems, and the presence of structural traps is 

unlikely. A rock probability of 0.1 is assigned on the basis of 

this generally unfavorable analysis.

Timing and Preservation

Hydrocarbon generation probably began in the southern and eastern margins of the AU during the Miocene and 

migrated towards the central part of the AU to the present; 

hydrocarbon generation probably has not occurred in the 

western and northern parts of the AU (Houseknecht and others, 2012b). Because potential traps in the Canada Basin are 

mostly stratigraphic, the timing for entrapment and preservation of charge is favorable. Thus, a timing and preservation 

probability of 1.0 is assigned.

The probabilities discussed above yield an AU probability of only 0.05; therefore, no quantitative assessment of 

petroleum potential was conducted.

Canada Passive Margin

The Canada passive margin AU (USGS assessment code 

50790104) contains no exploration wells, and no seismic data 

had been collected within it at the time of the assessment. 

This level of exploration places the Canada passive margin 

into uncertainty category 5 on the scale used by the USGS 

for the Circum-Arctic Resource Appraisal (Charpentier and 

Gautier, 2011).

Assessment Unit Description

The Canada passive margin is an elongate AU (fig. 10) 

whose major southeastern and northwestern boundaries are 

mapped on the basis of a horizontal gradient magnitude map 

of free air gravity anomalies (generated by R. Saltus of the 

USGS from data compiled by Forsberg, 2006; also see an 

updated gravity map in Gaina and others, 2011). This map 

was used to infer the inboard and outboard margins of a 

thick prism of sediment deposited following the rift opening 

of the Amerasia Basin. The AU is roughly equivalent to the 

“Canadian polar margin” of some publications ( for example, 

Jackson, 1990). The inboard margin of the AU corresponds to 

the northern margin (hinge) of the Canada rift shoulder (Sverdrup rim). The outboard margin corresponds roughly with 

the base of the marine slope (approximately 3,000 m water 

depth) and with basinward thinning of the sediment prism as 

inferred by Jackson and Oakey (1990). The short southwestern 

boundary of the AU is defined by the approximate basinward 

limit of contractional folding in the Canning-Mackenzie 

deformed margin AU. The short northeastern boundary of the 

AU is defined by abrupt thinning of the sediment prism onto 

volcanic rocks of the Alpha ridge. The AU encompasses an 

area of 278,000 km2

.

The Canada passive margin AU lies mostly on highly 

extended continental or transitional crust that was attenuated during Jurassic to early Cretaceous rift opening of the 

Canada Basin; the top of basement is inferred to lie at great 

depth (generally more than 10 km). The AU is characterized 

by a thick succession of mostly Cenozoic strata that is likely 

growth faulted and overpressured, an inference based on analog margins in Arctic Alaska and elsewhere around the world. 

Cretaceous (and perhaps Jurassic) strata likely are present but 

are buried beneath such a great thickness of Cenozoic strata 

that they are not likely to be oil or gas prospective, although 

they may be considered as potential source rocks. Although no 

reflection seismic data were available in this AU at the time 

of assessment, it was inferred to contain large-displacement 

growth faults and gravity folds on the basis of the Alaska passive margin analog. This inference was confirmed, at least in 

the southwestern part of the AU, by recently collected seismic 

data (Helwig and others, 2011).

Geological Analysis of Assessment Unit 

Probability

Even though no exploration wells have been drilled in 

the Canada passive margin AU, available evidence suggests 

a generally favorable probability for the presence of at least 

one accumulation of at least 50 MMBOE (table 6). Charge is 

viewed as the greatest risk factor, as explained below.

Charge

There is no direct evidence of an active petroleum system in the Canada passive margin AU. To the southwest, an 

active petroleum system is present in the Canning-Mackenzie 

deformed margin AU, with confirmed Tertiary oil in multiple 

discoveries larger than 50 MMBO in the offshore Mackenzie 

delta. Paleogene oil- and gas-prone source rocks recovered by 
Canada Passive Margin 27

Figure 10.

Assessment unit

Median extent of permanent ice—Month of 

September (1976–2006)

Exploration well

Location of pseudowells and wells

Bathymetric contour—Interval, in meters, is 

variable. Datum is sea level

Approximate oil/gas (green/red)—Proportion 

based on limited information

Accumulation of known size (scale below) showing 

oil/gas (green/red)—Proportion based on 

production and reserves data

0 40 80 MILES

400 80 KILOMETERS

EXPLANATION

16,384–32,768 MMBOE

8,192–16,384 MMBOE

4,096–8,192 MMBOE

2,048–4,096 MMBOE

1,024–2,048 MMBOE

512–1,024 MMBOE

256–512 MMBOE

128–256 MMBOE

64–128 MMBOE

<64 MMBOE

Map

area

-2000

-200

-2000

-100

-500

-200

-200

-500

-2500

-500

-3500

-200

-3800

-200

-200

-3000

-500

-3000

-2000

-1000

-500

-2000

-2000

-3000

4H-Havik

Fig. 3

5E-pseudowell CPM-03

CANADA PASSIVE

MARGIN 

5D-Havik B-41

160°W 150°W 140°W 130°W 120°W 110°W 100°W 90°W 80°W

82°N

78°N

74°N

70°N

Figure 10. Map of the Canada passive margin assessment unit showing exploration wells and known petroleum accumulations in 

adjacent areas (there are no wells in this AU), line of cross section shown in fig. 3, and locations of pseudowells and wells for which 

petroleum systems plots are shown in fig. 5.
28 Assessment of Undiscovered Petroleum Resources of the Amerasia Basin Petroleum Province

scientific drilling on Lomonosov Ridge suggest that source 

rocks may be present across the entire Amerasia Basin, an 

inference deemed probable based on tectonic and paleogeographic reconstructions (Houseknecht and Bird, 2011). Upper 

Cretaceous shale, the distal equivalents of the Smoking Hills 

Formation of the Mackenzie delta region and the lower part of 

the Kanguk Formation in the Canadian Arctic islands, is likely 

present and may include oil-prone source rocks throughout the 

AU. Regional tectonic and paleogeographic reconstructions 

suggest that Jurassic–Lower Cretaceous synrift and postrift 

source rocks also are likely present in the AU. Although these 

strata would certainly be overmature today, hydrocarbons 

generated as the source rocks were buried through the oil 

window may be preserved. Modeling (fig. 5E) suggests that oil 

generation likely began inboard during the Late Paleogene and 

progressively migrated basinward through the Neogene. On 

the basis of this mostly circumstantial evidence, yet regionally 

favorable prognosis, a charge probability of 0.6 is assigned to 

this AU (table 6).

Rocks

The potential exists in the Canada passive margin for 

prospective strata ranging in age from mid-Jurassic through 

Neogene. Mid-Jurassic to Lower Cretaceous strata were likely 

derived from the uplifted Canada rift shoulder (Embry and 

Dixon, 1990; Haimila and others, 1990) and may include 

sands derived from older sedimentary successions as well as 

from basement uplifts. Mid-Upper Cretaceous strata are likely 

mostly fine grained and may include volcanics and/or volcaniclastics related to Alpha ridge magmatism; this is especially true in the northeastern part of the AU, near the focus 

Table 6. Summary of assessment unit probabilities and key input parameters for numbers and sizes of 

undiscovered, conventional accumulations for the Canada passive margin assessment unit.

Assessment-Unit Probabilities: (Adequacy for at least one undiscovered field of minimum size)

 Attribute Probability of occurrence (0–1.0)

1. CHARGE: Adequate petroleum charge: 0.6

2. ROCKS: Adequate reservoirs, traps, and seals: 0.9

3. TIMING OF GEOLOGIC EVENTS: Favorable timing: 1.0

Assessment-Unit GEOLOGIC Probability (Product of 1, 2, and 3): 0.54

UNDISCOVERED ACCUMULATIONS

Number of Undiscovered Accumulations: How many undiscovered accumulations exist

that are at least the minimum size? (uncertainty of fixed but unknown values)

Total Accumulations: minimum (>0) 1 median 40 maximum 150

Oil/Gas Mix: minimum (>0 0.4 mode 0.7 maximum 0.9

X # of oil accumulations / # of total accumulations

# of oil accumulations / # of gas accumulations

# of gas accumulations / # of oil accumulations

Oil Accumulations: minimum (>0) 1 median 26 maximum 135

Gas Accumulations: minimum (>0) 0 median 13 maximum 105

Sizes of Undiscovered Accumulations: What are the sizes (grown) of the above accumulations?

 (variations in the sizes of undiscovered accumulations)

Oil in Oil Accumulations (mmbo): minimum 50 median 125 maximum 2,000

Gas in Gas Accumulations (bcfg): minimum 300 median 750 maximum 12,000
Canada Passive Margin 29

of volcanic activity (Embry and Osadetz, 1988). Paleogene 

strata likely include relatively coarse-grained sands derived 

from nearby uplifts associated with the Eurekan orogeny, 

especially in the northeastern half of the AU (Miall, 1984, 

1986, 1991; Harrison and others, 1999), and may include 

finer grained lithic sands derived from the Brooks Range via 

the Mackenzie delta sediment dispersal system in the southwestern part of the AU (Dixon, 1996). Neogene and younger 

strata also are likely to include relatively coarse-grained sands 

derived from the Canadian Arctic Islands region and perhaps 

from the broader Canadian shield farther south (Miall, 1984, 

1986, 1991). It is expected that sandstone-mudstone reservoirseal couplets are present in abundance and that a variety of 

growth-fault, gravity-fold, and stratigraphic trap geometries 

are present. The range of trap types is likely similar to that of 

the Alaska passive margin, where the largest potential traps 

observed in seismic data are large-displacement (hundreds 

of meters) growth-fault systems; smaller potential traps may 

include lowstand, shelf-margin truncations and channelized 

facies in both deepwater and shallow-water facies. Relative to 

the Alaska passive margin, reservoir quality may be better in 

the Canada passive margin because the provenance of sands 

is more favorable for coarser grained and less lithic compositions. A rock probability of 0.9 is assigned on the basis of this 

generally favorable analysis (table 6).

Timing and Preservation

Oil generation probably began inboard during the 

Paleogene and migrated outward to the northwest through the 

Neogene as thick, progressively offlapping sequences were 

deposited (fig. 3). All potential traps are syndepositional, so 

timing was excellent for charging relatively young reservoirs. 

The potential for preservation of reservoired hydrocarbons 

also is considered excellent, as suggested by hydrocarbon accumulations that have been discovered in similar sequences in 

the adjacent Canning-Mackenzie deformed margin AU. Thus, a 

timing and preservation probability of 1.0 is assigned (table 6).

Analogs Used for Assessment

Assessment input was influenced by the geology, sizes, 

and numbers of discovered accumulations in the adjacent 

Canning-Mackenzie deformed margin AU. Analogs were 

selected from the USGS World Analog Database (Charpentier 

and others, 2008) in two stages: (1) results of a search for 

rifted passive margin architecture was culled by eliminating 

salt structures, basement-related normal faulting, carbonate 

reservoirs, and other inappropriate geological parameters, and 

(2) a search of gravity-induced growth fault trap systems. The 

final analog set is the same as that used for the Alaska passive 

margin AU and consists of 20 AUs (table 5).

Assessment Inputs

Number of Accumulations

The analog set displays an approximate log-normal distribution of accumulation density with many values between 0 

and 0.2 and several values up to about 0.5 accumulations of at 

least 50 MMBOE/1,000 km2

, and with two outliers at 0.8 and 

1.2. Accordingly, input values of 1 (0.00 density) at the minimum, 40 (0.14 density) at the median, and 150 (0.54 density) 

at the maximum were selected (table 6). This input reflects a 

large range of uncertainty appropriate for this frontier basin.

Oil-to-Gas Mix

The minimum, median, and maximum values of the oilto-gas ratio were set at 0.4, 0.7, and 0.9 (table 6) on the basis 

of the expected similarity with the active petroleum system 

of the Canning-Mackenzie deformed margin AU. The higher 

value of 0.9 at the maximum reflects the interpretation that 

source rocks would likely be more oil-prone farther from the 

Mackenzie delta influx of terrigenous clastic sediment.

Accumulation Size Distribution

The median oil accumulation size was set at 125 MMBO 

(table 6) on the basis of the sizes of discovered accumulations in Tertiary sandstone reservoirs in adjacent AUs and 

the expectation that reservoir quality will be somewhat better 

than in the Alaska passive margin AU; this value also closely 

matches the median and mean values of the median accumulation size in the analog set. The maximum oil accumulation 

size was set at 2 BBO (table 6) on the basis of the largest 

accumulations discovered in analog areas (1 to 2 BBO). For 

maximum accumulation size, a value larger than used for 

the Alaska passive margin AU was specified, because of an 

indication that the Canada passive margin AU may contain a 

thicker sediment prism (possibly larger displacement growthfault traps) and coarser grained sandstone (possibly larger 

reservoir volume). Median and maximum input values of 750 

BCF and 12 TCF (table 6) were set for gas accumulation sizes 

by the same line of reasoning.

Province Geologist’s Estimated Maximum 

Accumulation Size

Maximum accumulation sizes of 300 to 400 MMBO and 

2 to 3 TCFG were selected on the basis of the size distribution 

of discovered accumulations in Tertiary reservoirs in adjacent 

AUs, the largest accumulation sizes assessed by MMS in the 

analog Alaska passive margin using a large seismic database 

to constrain trap sizes, and the inferences that traps may be 

larger and reservoir quality may be better in this AU. These 

maximum sizes, which did not enter directly into the volumetric calculations, were used to judge the reasonableness of the 

results of statistical analysis.
30 Assessment of Undiscovered Petroleum Resources of the Amerasia Basin Petroleum Province

Ancillary Properties and Co-Product Ratios

Data from discovered pools in Tertiary sandstone reservoirs in adjacent AUs (Houseknecht and others, 2012a) and 

expected geochemistry of potential source rocks were used to 

establish input values for these parameters.

Results

Probabilistic estimates of volumes of undiscovered, 

technically recoverable hydrocarbons for the Canada passive 

margin AU are summarized in table 3. These results include 

mean estimates of more than 2 BBO, more than 7 TCF associated gas, and nearly 8 TCF nonassociated gas.

Summary and Conclusions

The Amerasia Basin was divided into four assessment 

units (AUs) for appraisal of undiscovered petroleum resources 

in conventional accumulations. Three of the AUs—the Alaska 

passive margin, the Canning-Mackenzie deformed margin, and 

the Canada passive margin—comprise sediment prisms deposited basinward of rift shoulders after tectonic opening of the 

Canada Basin. All three of the rifted margin sediment prisms 

are characterized by thick (more than 10 km), growth-faulted, 

sandstone and mudstone successions that locally include gravity fold-and-thrust systems. The Canning-Mackenzie deformed 

margin is further characterized by ongoing contractional deformation related to northward advancement of the Brooks Range 

tectonic front. The deepwater Canada Basin is characterized 

by a succession of Cretaceous and Cenozoic strata that mostly 

represents sediments dispersed from the Mackenzie delta and 

from other continental margins around the western (Chukchi 

Borderland), southern (Arctic Alaska), and eastern (Arctic 

Canada) margins of the basin.

Except for the Canning-Mackenzie deformed margin, 

where an active petroleum charge has been documented by 

exploration and discoveries, the potential for oil-prone source 

rocks across the region is inferred from indirect evidence. 

Stratigraphic and geochemical data in Alaska and Canada, 

inboard from the rift shoulders, and regional paleogeographic 

reconstructions suggest source-rock potential in Lower 

Cretaceous (Hauterivian–Albian), Upper Cretaceous (mainly 

Turonian), and lower Paleogene strata. Burial history modeling indicates favorable timing of oil generation (relative to 

trap formation) beneath the Canning-Mackenzie deformed 

margin, the Alaska and Canada passive margins, and a large 

part of the deep Canada Basin.

The Canning-Mackenzie deformed margin hosts numerous oil and gas discoveries in traps that include detachment 

anticlines and thrust-fault closures (both of tectonic and gravity origin), growth-fault blocks, stratigraphic pinch-outs, and 

perhaps closures formed by mud diapirs. Trap potential in the 

Alaska and Canada passive margin AUs primarily involves 

growth-fault blocks, stratigraphic pinch-outs, and perhaps 

gravity fold-and-thrust closures. Trap potential in the deep 

Canada Basin is limited to stratigraphic geometries in distal 

turbidite facies.

Assessment of undiscovered, technically recoverable petroleum resources in conventional accumulations of 

at least 50 MMBOE yields the following mean estimates: 

Canning-Mackenzie deformed margin, more than 6 BBO, 

nearly 20 TCF of associated gas, and 16 TCF of nonassociated gas; Canada passive margin, more than 2 BBO, more 

than 7 TCF of associated gas, and nearly 8 TCF of nonassociated gas; and Alaska passive margin, nearly 1 BBO, 3 TCF 

of associated gas, and nearly 3 TCF of nonassociated gas. No 

quantitative assessment was completed for the deep Canada 

Basin because the overall probability for the occurrence of at 

least one accumulation of at least 50 MMBOE was estimated 

to be less than 10 percent.

Acknowledgments

This report was improved as the result of constructive 

reviews by Kirk Sherwood (Bureau of Ocean Energy Management), David Hite (Consulting Petroleum Geologist, Anchorage), and Jim Coleman.

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