Abstract Basin evolution of the U.S. Chukchi shelf involved multiple phases, including Late Devonian–Permian rifting, Permian–Early Jurassic sagging, Late Jurassic–Neocomian inversion, and Cretaceous–Cenozoic foreland-basin development. The focus of ongoing exploration is a petroleum system that includes sag-phase source rocks; inversion-phase reservoir rocks; structure spanning the rift, sag, and inversion phases; and hydrocarbon generation during the foreland-basin phase. Interpretation of 2-D seismic and sparse well data documents the presence, in the south-central part of the shelf, of a series of en-echelon, north-south trending monoclonal fold limbs that display up to 1+ km (3,300 ft) of structural relief. These folds, which are located above the tips of rift-phase normal faults, are interpreted as inversion structures formed by maximum compressive stress oriented obliquely to the strike of rift-phase normal faults. Erosional relief on a Jurassic unconformity, growth strata in the overlying Upper Jurassic to Neocomian strata, and east-dipping clino-forms in a high accommodation depocenter east of the inversion structures indicate profound structural influence on sedimentation. Oil-prone source rocks, reservoir-quality sandstone, migration pathways, and structural closure are linked intimately across the Jurassic unconformity, which reflects inversion. Thus, all these key petroleum systems elements were in place when Triassic source rocks entered the oil generation window during Cretaceous–Cenozoic stratigraphic burial.

Abstract The Dinkum graben system beneath the central to eastern Beaufort shelf of Arctic Alaska comprises a complex of grabens and horsts that records multiple phases of extension and contraction spanning the Mississippian through Early Cretaceous (Neocomian). The graben system extends from about 150°W eastward for more than 200 km, approximately parallel to the Alaska Beaufort Sea coast. The eastern extent of the graben system (east of about 145.5°W) is masked by deep burial beneath Cenozoic strata and by complex Cenozoic structures. The graben system developed above regional basement that includes the pre-Mississippian Franklinian sequence, interpreted as Late Proterozoic-Devonian strata deformed and metamorphosed during the Ellesmerian orogeny. Franklinian rocks display in seismic data a range of variably dipping structural and metamorphic fabrics described in a companion abstract (Connors and Houseknecht). Previously published interpretations of the Din-kum graben suggest two phases of extension related to rift opening of the Amerasia basin, a Jurassic phase characterized by generally south-dipping normal faults and an Early Cretaceous phase characterized by generally north-dipping normal faults. However, our interpretation of 2D seismic data, tied to well control near the coast and potential fields data across the Beaufort shelf, documents a geologic history commencing with Mississippian extension accommodated by both north- and south-dipping normal faults detached along the variably dipping basement fabrics. Growth strata indicate that pulses of extension in the graben system occurred during the Mississippian, Late Triassic–Early Jurassic, and Neocomian. Further, certain faults accommodate Mid-Late Jurassic growth strata that grade from positive to negative growth along strike, suggesting inversion of older structures, perhaps by stresses oblique to older fault planes. This polyphase deformational history is reflected in a complex graben system that accommodates Mississippian-Neocomian strata at least 5 km thick in places. The newly recognized presence of pre-Jurassic strata in the Dinkum graben system has significant implications regarding petroleum systems. Upper Triassic growth strata likely include oil-prone source rocks in the Shublik Formation, corroborated along the southern margin of the graben by oil accumulations ( e.g. , Northstar) with implausible migration pathways from sources to the south, and by chemistry that suggests a Triassic source rock containing more detrital components and less carbonate than typical Shublik of the North Slope. Considering the timing of extensional pulses discussed above, the presence of Lower Jurassic and Neocomian source rocks also is likely. Although all these source rocks likely are thermally overmature in deeper parts of the graben, shallower parts of the graben, horsts within the graben, and southern and northern margins of the graben may be in the oil window, and may have been charged from the graben.

Abstract The emerging global focus on the oil and gas potential of the Arctic underscores the importance of understanding petroleum systems with limited data. Geohistory modeling of Arctic Alaska (including the Chukchi shelf) and the southern Canada basin indicates that regional patterns of thermal maturity and timing of petroleum generation reflect geologic processes associated with rift-opening of the Canada basin and collision orogenesis along the Brooks Range–Herald arch from Jurassic through Tertiary time. The base of the Cretaceous–Tertiary Brookian sequence provides a regional reference horizon because most oil generation occurred as the result of Brookian burial. In Arctic Alaska, basal Brookian strata on the Beaufort rift shoulder grade from immature in the west to overmature in the east. From the crest of the rift shoulder, thermal maturity of basal Brookian strata increases southward into the oil window on the north flank of the Colville foreland basin and into the gas window in the foredeep. A <200-mile-wide area of immature to mature strata in the Chukchi Sea narrows eastward as the Brooks Range converges with the rift shoulder in the eastern North Slope. These patterns reflect generally low Jurassic to Tertiary sediment accommodation on the rift shoulder, large Cretaceous sediment accommodation in the Colville foredeep, and northward impingement of the Brooks Range onto the eastern part of the rift shoulder during the Tertiary. Fewer geologic data in the Canada basin increases the uncertainty of modeling. Projection of stratigraphy from the rift shoulder, reconstruction of regional sediment dispersal patterns, and consideration of source rocks in Arctic Alaska and Canada indicate the potential for four source rocks in the Cretaceous and Paleogene. Model results indicate that all four source rocks are mature or overmature across much of the southern Canada basin. The highest thermal maturity occurs in depocenters immediately north of the rift shoulder and on the eastern margin of the study area, which is the distal Mackenzie delta. The lowest thermal maturity occurs at the northern limit of modeling, more than 200 miles north of the rift shoulder and on the western margin of the study area, adjacent to the Chukchi borderland. A potential source rock in the Lower Cretaceous likely matured during the Early Cretaceous in a western depocenter related to sediment by-pass of the Chukchi shelf, but maturation of all source rocks elsewhere occurred during the Paleogene when large volumes of sediment were shed from the Brooks Range and through the Mackenzie delta.

Abstract The US Geological Survey recently assessed the potential for undiscovered conventional petroleum in the Arctic. Using a new map compilation of sedimentary elements, the area north of the Arctic Circle was subdivided into 70 assessment units, 48 of which were quantitatively assessed. The Circum-Arctic Resource Appraisal (CARA) was a geologically based, probabilistic study that relied mainly on burial history analysis and analogue modelling to estimate sizes and numbers of undiscovered oil and gas accumulations. The results of the CARA suggest the Arctic is gas-prone with an estimated 770–2990 trillion cubic feet of undiscovered conventional natural gas, most of which is in Russian territory. On an energy-equivalent basis, the quantity of natural gas is more than three times the quantity of oil and the largest undiscovered gas field is expected to be about 10 times the size of the largest undiscovered oil field. In addition to gas, the gas accumulations may contain an estimated 39 billion barrels of liquids. The South Kara Sea is the most prospective gas assessment unit, but giant gas fields containing more than 6 trillion cubic feet of recoverable gas are possible at a 50% chance in 10 assessment units. Sixty per cent of the estimated undiscovered oil resource is in just six assessment units, of which the Alaska Platform, with 31% of the resource, is the most prospective. Overall, the Arctic is estimated to contain between 44 and 157 billion barrels of recoverable oil. Billion barrel oil fields are possible at a 50% chance in seven assessment units. Undiscovered oil resources could be significant to the Arctic nations, but are probably not sufficient to shift the world oil balance away from the Middle East.

Abstract The Arctic Alaska petroleum province encompasses all lands and adjacent continental shelf areas north of the Brooks Range–Herald Arch orogenic belt and south of the northern (outboard) margin of the Beaufort Rift shoulder. Even though only a small part is thoroughly explored, it is one of the most prolific petroleum provinces in North America with total known resources (cumulative production plus proved reserves) of c . 28 BBOE. The province constitutes a significant part of a displaced continental fragment, the Arctic Alaska microplate, that was probably rifted from the Canadian Arctic margin during formation of the Canada Basin. Petroleum prospective rocks in the province, mostly Mississippian and younger, record a sequential geological evolution through passive margin, rift and foreland basin tectonic stages. Significant petroleum source and reservoir rocks were formed during each tectonic stage but it was the foreland basin stage that provided the necessary burial heating to generate petroleum from the source rocks. The lion's share of known petroleum resources in the province occur in combination structural–stratigraphic traps formed as a consequence of rifting and located along the rift shoulder. Since the discovery of the super-giant Prudhoe Bay accumulation in one of these traps in the late 1960s, exploration activity preferentially focused on these types of traps. More recent activity, however, has emphasized the potential for stratigraphic traps and the prospect of a natural gas pipeline in this region has spurred renewed interest in structural traps. For assessment purposes, the province is divided into a Platform assessment unit (AU), comprising the Beaufort Rift shoulder and its relatively undeformed flanks, and a Fold-and-Thrust Belt AU, comprising the deformed area north of the Brooks Range and Herald Arch tectonic belt. Mean estimates of undiscovered, technically recoverable resources include nearly 28 billion barrels of oil (BBO) and 122 trillion cubic feet (TCF) of nonassociated gas in the Platform AU and 2 BBO and 59 TCF of nonassociated gas in the Fold-and-Thrust Belt AU.

Abstract Three sides of the Canada Basin are bordered by high-standing, conjugate rift shoulders of the Chukchi Borderland, Alaska and Canada. The Alaska and Canada margins are mantled with thick, growth-faulted sediment prisms, and the Chukchi Borderland contains only a thin veneer of sediment. The rift-margin strata of Alaska and Canada reflect the tectonics and sediment dispersal systems of adjacent continental regions whereas the Chukchi Borderland was tectonically isolated from these sediment dispersal systems. Along the eastern Alaska–southern Canada margin, termed herein the ‘Canning–Mackenzie deformed margin’, the rifted margin is deformed by ongoing Brooks Range tectonism. Additional contractional structures occur in a gravity fold belt that may be present along the entire Alaska and Canada margins of the Canada Basin. Source-rock data inboard of the rift shoulders and regional palaeogeographic reconstructions suggest three potential source-rock intervals: Lower Cretaceous (Hauterivian–Albian), Upper Cretaceous (mostly Turonian) and Lower Palaeogene. Burial history modelling indicates favourable timing for generation from all three intervals beneath the Alaska and Canada passive margins, and an active petroleum system has been documented in the Canning–Mackenzie deformed margin. Assessment of undiscovered petroleum resources indicates the greatest potential in the Canning–Mackenzie deformed margin and significant potential in the Canada and Alaska passive margins.

Abstract Geological features of NE Greenland suggest large petroleum potential, as well as high uncertainty and risk. The area was the prototype for development of methodology used in the US Geological Survey (USGS) Circum-Arctic Resource Appraisal (CARA), and was the first area evaluated. In collaboration with the Geological Survey of Denmark and Greenland (GEUS), eight ‘assessment units’ (AU) were defined, six of which were probabilistically assessed. The most prospective areas are offshore in the Danmarkshavn Basin. This study supersedes a previous USGS assessment, from which it differs in several important respects: oil estimates are reduced and natural gas estimates are increased to reflect revised understanding of offshore geology. Despite the reduced estimates, the CARA indicates that NE Greenland may be an important future petroleum province.

Abstract Shale gas is produced from the Woodford, Caney, and Fayetteville shales (Devonian and/or Mississippian), and coal-bed gas is produced from the Hartshorne and McAlester coal beds in the Arkoma basin of Oklahoma and Arkansas. The U.S. Geological Survey is currently assessing the technically recoverable hydrocarbon resources of the Arkoma basin and for assessment purposes has divided the continuous shale gas (unconventional) resources into three total petroleum systems together with their associated assessment units (AUs). Each of the gas shale AUs contains 2.5 % or more total organic carbon, is thermally mature with respect to gas generation over much of its area within the basin, and may be accessed by the drill at depths less than 14,000 feet. In addition, the Woodford, Caney, and Fayetteville Shale Gas AUs underlie relatively large areas that have not been tested adequately by the drill. Coal-bed gas is currently being produced from the Hartshorne and McAlester coal beds in the Arkoma basin, and for assessment purposes they have been grouped together into one total petroleum system and one AU. Much of the area where the coal beds are relatively shallow in the northern part of the AU has been drilled. However, the area underlain by coal in the southern part of the basin, which is deeper and more structurally deformed, remains largely unexplored for coalbed methane.

Abstract Outcrops of the Lower Cretaceous (Albian) Torok Formation in the Brooks Range foothills of north-central Alaska expose an exhumed, oil-charged stratigraphic trap in a turbidite-channel system ( Figure 1 ). Although scattered along strike for 21 km (13 mi), these outcrops collectively provide a unique and significant analog for an emerging oil play beneath the Alaska North Slope. Recent discoveries 140 to 180 km (90 to 110 mi) north of these outcrops in channelized turbidites of the Torok Formation (Nanuq Field, approximately 40 million barrels of oil recoverable [MMBO]) and Upper Cretaceous Seabee Formation (Tarn Field, approximately 100 MMBO, and Meltwater Field, approximately 50 MMBO) emphasize the magnitude of potential undiscovered resources in this play and suggest the potential for a prospective fairway that extends between the two areas. The Torok Formation and overlying Nanushuk Formation (Cretaceous, Albian-Cenomanian) comprise sediment derived from the Brooks Range and deposited in a system that prograded eastward and northeastward across the foreland basin ( Figure 3 ). Torok strata include basin-plain and marine-slope facies, whereas Nanushuk strata include marine-shelf, deltaic, and fluvial facies. The study area is located in the foredeep, where Torok submarine-fan and marine-slope facies were deposited basinward of a north-south-oriented shelf margin characterized by significant mass wasting (slumping and sliding of blocks of strata derived from the outer shelf and upper slope) as indicated by seismic data to the north ( Houseknecht and Schenk, 2001 ). Three generalized architectural elements are defined in the Torok outcrops. C1 is a basal element, comprising poorly sorted,

Abstract Integrated field and subsurface studies of the Albian Torok and Nanushuk formations (coeval clinoform and topset couplet) have produced a sequence stratigraphic framework for identifying fairways most likely to contain stratigraphic traps in Brookian turbidites in NPRA (Fig. 1) . Stratigraphic traps in the Torok involve lowstand, sand-rich turbidite facies sealed by condensed mudstones deposited during transgression. The lowstand deposits commonly downlap onto, and interfinger basinward with, oil-prone source rocks of the gamma-ray zone (GRZ), an Aptian-Albian condensed section ( Fig. 2 ).

Abstract The 1994 discovery of the Alpine oil field (>400 MMBO recoverable), a subsequent Federal lease sale in northeast NPRA, and the 2001 announcement of discoveries of commercial quantities of hydrocarbons in Alpine-type traps within NPRA ( Fig. 1 ) have reinvigorated exploration interest in a formerly moribund part of the Alaska North Slope. Limited data available in the public domain suggest that key ingredients of Alpine-type accumulations include a high gravity oil charge apparently sourced from a condensed section in the Lower Jurassic and stratigraphic traps in the Upper Jurassic comprising a transgressive assemblage of lenticular, fine-grained, well winnowed shoreface sands deposited in erosional incisions and sealed by condensed mudstone ( Figs. 2 and 3 ).