Kenneth J. Bird

Assessment of undiscovered oil and gas in the Arctic.

Arctic Energy Reserves The Arctic consists of approximately equal fractions of terrain above sea level, continental shelves with depths less than 500 meters, and deep ocean basins that have been mostly covered in ice. While the deep ocean regions probably have limited petroleum reserves, the shelf areas are likely to contain abundant ones. Based on the limited amount of exploration data available, Gautier et al. (p. 1175) have constructed a probabilistic, geology-based estimate of how much oil and gas may be found. Approximately 30% of the worlds undiscovered gas, and 13% of its undiscovered oil, may be found north of the Arctic Circle. Advances in the technology of hydrocarbon recovery, as well as vanishing ice cover around the North Pole, make the Arctic an increasingly attractive region for energy source development, although the existing reserves are probably not large enough to shift current production patterns significantly. About 30 percent of the world’s undiscovered gas and 13 percent of the world’s undiscovered oil probably exist north of the Arctic Circle. Among the greatest uncertainties in future energy supply and a subject of considerable environmental concern is the amount of oil and gas yet to be found in the Arctic. By using a probabilistic geology-based methodology, the United States Geological Survey has assessed the area north of the Arctic Circle and concluded that about 30% of the world’s undiscovered gas and 13% of the world’s undiscovered oil may be found there, mostly offshore under less than 500 meters of water. Undiscovered natural gas is three times more abundant than oil in the Arctic and is largely concentrated in Russia. Oil resources, although important to the interests of Arctic countries, are probably not sufficient to substantially shift the current geographic pattern of world oil production.

Deep seismic structure and tectonics of northern Alaska: Crustal-scale duplexing with deformation extending into the upper mantle

Seismic reflection and refraction and laboratory velocity data collected along a transect of northern Alaska (including the east edge of the Koyukuk basin, the Brooks Range, and the North Slope) yield a composite picture of the crustal and upper mantle structure of this Mesozoic and Cenozoic compressional orogen. The following observations are made: (1) Northern Alaska is underlain by nested tectonic wedges, most with northward vergence (i.e., with their tips pointed north). (2) High reflectivity throughout the crust above a basal decollement, which deepens southward from about 10 km depth beneath the northern front of the Brooks Range to about 30 km depth beneath the southern Brooks Range, is interpreted as structural complexity due to the presence of these tectonic wedges, or duplexes. (3) Low reflectivity throughout the crust below the decollement is interpreted as minimal deformation, which appears to involve chiefly bending of a relatively rigid plate consisting of the parautochthonous North Slope crust and a 10- to 15-km-thick section of mantle material. (4) This plate is interpreted as a southward verging tectonic wedge, with its tip in the lower crust or at the Moho beneath the southern Brooks Range. In this interpretation the middle and upper crust, or all of the crust, is detached in the southern Brooks Range by the tectonic wedge, or indentor: as a result, crust is uplifted and deformed above the wedge, and mantle is depressed and underthrust beneath this wedge. (5) Underthrusting has juxtaposed mantle of two different origins (and seismic velocities), giving rise to a prominent sub-Moho reflector.

Sequence stratigraphy of the Kingak Shale (Jurassic–Lower Cretaceous), National Petroleum Reserve in Alaska

Beaufortian strata (Jurassic–Lower Cretaceous) in the National Petroleum Reserve in Alaska (NPRA) are a focus of exploration since the 1994 discovery of the nearby Alpine oil field (400 MMBO). These strata include the Kingak Shale, a succession of depositional sequences influenced by rift opening of the Arctic Ocean Basin. Interpretation of sequence stratigraphy and depositional facies from a regional two-dimensional seismic grid and well data allows the definition of four sequence sets that each displays unique stratal geometries and thickness trends across NPRA.A Lower to Middle Jurassic sequence set includes numerous transgressive-regressive sequences that collectively built a clastic shelf in north-central NPRA. Along the south-facing, lobate shelf margin, condensed shales in transgressive systems tracts downlap and coalesce into a basinal condensed section that is likely an important hydrocarbon source rock. An Oxfordian–Kimmeridgian sequence set, deposited during pulses of uplift on the Barrow arch, includes multiple transgressive-regressive sequences that locally contain well-winnowed, shoreface sandstones at the base of transgressive systems tracts. These shoreface sandstones and overlying shales, deposited during maximum flooding, form stratigraphic traps that are the main objective of exploration in the Alpine play in NPRA. A Valanginian sequence set includes at least two transgressive-regressive sequences that display relatively distal characteristics, suggesting high relative sea level. An important exception is the presence of a basal transgressive systems tract that locally contains shoreface sandstones of reservoir quality. A Hauterivian sequence set includes two transgressive-regressive sequences that constitute a shelf-margin wedge developed as the result of tectonic uplift along the Barrow arch during rift opening of the Arctic Ocean Basin. This sequence set displays stratal geometries suggesting incision and synsedimentary collapse of the shelf margin.

Thermal Maturity Patterns in Alaska: Implications for Tectonic Evolution and Hydrocarbon Potential

Nearly 10,000 vitrinite reflectance and conodont color alteration index determinations from sedimentary rocks in Alaska were used to produce a thermal maturity map of rocks exposed at the surface and to evaluate subsurface thermal maturity relations in the Colville and Cook Inlet basins. Rocks exposed at the surface of the Tertiary interior basins and in the Aleutian forearc and backarc basins uniformly are of very low thermal maturity, indicating that these basins are at or near maximum burial, have seen little uplift and exhumation, and are probably thermally immature with respect to hydrocarbon generation. In contrast, many sedimentary basins show elevated levels of thermal maturity at the surface, with the highest values at basin margins. This geometry suggests a patt rn of greater uplift along basin margins, possibly reflecting isostatic readjustments as crustal loads are removed by erosion. We investigated thermal maturity relations in three sedimentary basins (Colville, Cook Inlet, and Kandik) in more detail. Thermal maturity patterns in the Colville basin are broadly asymmetric, indicating systematic differential uplift ranging from a minimum of no uplift in the north (Point Thomson area) to 9-13 km of uplift and exhumation in the central Brooks Range; even greater uplift further to the south is indicated by the presence of greenschist facies and higher grade metamorphic rocks. This pattern may reflect the deflexing of the lithosphere subsequent to the principal episode(s) of crustal convergence and thickening. These patterns further suggest a similar thermal history for the proximal Colville basin and the northern foothills belt, suggesting the possibility of hydrocar on accumulations in the foothills. Thermal maturity isograds within the Brooks Range cut major thrust faults, indicating that maximum burial postdated the principal phases of thrusting. In contrast, isograds in the foothills belt to the north are warped broadly by local structure, indicating continued north-south shortening subsequent to maximum burial. Such deformation could have remobilized hydrocarbons in early traps. A broad southward extension of thermally immature rocks in the central portions of the foothills belt suggests relatively young east-west shortening (parallel to the strike of the orogene), a feature that to date has not been included in regional tectonic syntheses. Alternatively, the thermal maturity pattern could be explained by tectonically unrelated episodes of uplif in the eastern and western parts of the Brooks Range. In the Cook Inlet basin, vitrinite reflectance isograds also are indicative of relatively greater uplift at the basin margins than at the basin center, which appears to be presently at its maximum burial depth. Uplift in the Cook Inlet basin may reflect compression along the faults bounding the basin. Relatively high thermal maturity along the western margin of the basin also may reflect magmatic heat sources from the Alaska Peninsula-Aleutian volcanic arc. The Seldovia arch, a major structural feature of the End_Page 1874------------------------------ basin, does not appear to deform vitrinite reflectance isograds, implying that deformation on that structure ceased prior to maximum burial. In the Kandik basin, a thermal maturity anomaly (thermally mature younger rocks in fault contact with thermally immature older rocks) provides clues to the nature and timing of east-west thrusting. Mesozoic foreland basin deposits associated with thrusting buried Paleozoic rocks of the easternmost part of this fold-and-thrust belt to relatively shallow depths, driving potential hydrocarbon source rocks into the oil-generation window. The western foreland basin deposits were overridden by advancing thrusts, and tectonically buried to as deep as 10 km. These disparate thermal domains are juxtaposed along the Glenn Creek fault, which may represent a terrane boundary in east-central Alaska.

Lisburne Group (Mississippian and Pennsylvanian), Potential Major Hydrocarbon Objective of Arctic Slope, Alaska

The Lisburne Group, a thick carbonate-rock unit of Mississippian and Pennsylvanian age, is one of the most widespread potential reservoir-rock units in northern Alaska. A comprehensive review of the Lisburne in the subsurface of the eastern Arctic Slope indicates attractive reservoir characteristics in a favorable source and migration setting where numerous trapping mechanisms appear to be available. Evaluation of this group as a potential exploration objective is particularly timely because of impending offshore sales in the Beaufort Sea and current exploration programs under way in the Prudhoe Bay area and the Naval Petroleum Reserve. Dolomite and sandstone have been identified as reservoir rocks. Oolitic grainstone is a common rock type, but observations indicate little reservoir potential owing to complete void filling by calcite cement. The most important reservoir rock as judged by thickness, areal extent, and predictability is microsucrosic (10 to 30µ) dolomite of intertidal to supratidal origin. It is present throughout the Lisburne and is most abundant near the middle of the sequence. Northward it decreases in thickness from 1,000 ft (300 m) to less than 100 ft (30 m). Porosity of the dolomite as determined in selected wells averages between 10 and 15% and attains a maximum of slightly more than 25%. Net thickness of reservoir rocks (i.e., rocks with greater than 5% porosity) ranges in these wells from 40 to 390 ft (40 to 120 m). Oil shows are common, and drill-stem tests have yielded as much as 1,600 bbl/day of oil and 22 MMcf/day of gas in the Lisburne pool of the Prudhoe Bay field and as much as 2,057 bbl/day of salt water outside the field area. The occurrence of dolomite over such a large area makes its presence in the offshore Beaufort Sea and adjacent Naval Petroleum Reserve 4 fairly certain. The presence of sandstone as thick as 140 ft (40 m) in the middle and upper part of the Lisburne in two coastal wells suggests that larger areas of sandstone may be found on the north in offshore areas. Shows of oil and gas and a saltwater flow of 1,470 bbl/day have been recorded from this sandstone facies. Shales of Permian and Cretaceous ages unconformably overlie the Lisburne, providing adequate sealing beds above potential reservoirs. Impermeable limestone (completely cemented grainstone) and thin beds of shale may serve as seals within the Lisburne, but the possibility of fractures in these units may negate their sealing capability. The most favorable source rock for Lisburne hydrocarbons appears to be Cretaceous shale that unconformably overlies the Lisburne east of Prudhoe Bay. This shale is reported to be a rich source rock and is the most likely source for the entire Prudhoe Bay field. A source within the Lisburne or within the underlying Kayak Shale is postulated for oil shows in the southernmost Lisburne wells. This postulated source may be in a more basinal facies of the Lisburne and may be similar to dark shale in the upper Lisburne in thrust slices to dark shale in the upper Lisburne in thrust slices in the Brooks Range. Coal in the underlying Endicott Group is a possible source for dry gas. At present, much of this coal probably is in a gas-generating regime downdip from the Prudhoe Bay field. Stratigraphic traps involving the Lisburne Group may have resulted from widespread Permian and Cretaceous unconformities. Structural traps related to normal faulting may be present along the trend of the Barrow arch, and faulted anticlines are numerous in the foothills of the Brooks Range. Combination traps are possible along the trend of the Barrow arch.

Chapter 34: Geology and petroleum potential of the rifted margins of the Canada Basin

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.

Petroleum System Modeling of Northern Alaska

Northern Alaska is a prolific oil and gas province estimated to contain a significant proportion of the undiscovered oil and gas of the circum-Arctic. A three-dimensional petroleum system model was constructed with the aim of significantly improving the understanding of the generation, migration, accumulation, and loss of hydrocarbons in the region. This study provides a unique geologic perspective that will reduce exploration risk and assess the remaining potential hydrocarbon resources in this remote province. The present-day geometry is based on newly interpreted seismic data and a database of more than 400 wells. A key aspect of this model is an improved reconstruction of the progradation of the time-transgressive Cretaceous–Tertiary Brookian sequence and multiple erosion events in the Tertiary. The deposition of these overburden rocks controlled the timing of hydrocarbon generation in underlying source rocks and their principal migration from the Colville Basin northward to the Barrow Arch. The model provides a reconstruction of the complex and dynamic interplay of diachronous deposition and erosion and allows assessment of variations in migration behavior and prediction of the present-day petroleum distribution.

Chapter 32 Geology and petroleum potential of the Arctic Alaska petroleum province

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 lions 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.

Role of reservoir engineering in the assessment of undiscovered oil and gas resources in the National Petroleum Reserve, Alaska

The geology and reservoir-engineering data were integrated in the 2002 U.S. Geological Survey assessment of the National Petroleum Reserve in Alaska (NPRA). Whereas geology defined the analog pools and fields and provided the basic information on sizes and numbers of hypothesized petroleum accumulations, reservoir engineering helped develop necessary equations and correlations, which allowed the determination of reservoir parameters for better quantification of in-place petroleum volumes and recoverable reserves. Seismic- and sequence-stratigraphic study of the NPRA resulted in identification of 24 plays. Depth ranges in these 24 plays, however, were typically greater than depth ranges of analog plays for which there were available data, necessitating the need for establishing correlations. The basic parameters required were pressure, temperature, oil and gas formation volume factors, liquid/gas ratios for the associated and nonassociated gas, and recovery factors. Finally, the results of U.S. Geological Survey deposit simulation were used in carrying out an economic evaluation, which has been separately published.

Chapter 43 Assessment of NE Greenland: prototype for development of Circum-Arctic Resource Appraisal methodology

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.