Geology topics
David W. Houseknecht
Publications and source records attributed to David W. Houseknecht.
Sedimentology and sequence stratigraphy of the Cretaceous Nanushuk, Seabee, and Tuluvak formations exposed on Umiat Mountain, north-central Alaska
Upper Cretaceous strata of the upper part of the Nanushuk Formation, the Seabee Formation, and the lower part of the Tuluvak Formation are exposed along the Colville River on the east flank of Umiat Mountain in north-central Alaska. The Ninuluk sandstone, which is the uppermost unit of the Nanushuk Formation, displays a vertical succession of facies indicative of deposition in an upward-deepening estuarine through shoreface setting. A marine-flooding surface lies between the Ninuluk sandstone and organic-rich shale of the basal part of the Seabee Formation. The Ninuluk sandstone and the lower part of the Seabee Formation are interpreted as components of a transgressive-systems tract. The lowest, well-exposed strata in the Seabee Formation are a succession of shoreface sandstone beds in the middle of the formation. Integration of outcrop information and the Umiat No. 11 well log suggests that this sandstone succession rests on a sequence boundary and is capped by a marine-flooding surface. The sandstone succession is interpreted as a lowstand-systems tract. The upper part of the Seabee Formation includes a thick interval of organic-rich shale deposited in a dysaerobic offshore environment, and the gradational Seabee-Tuluvak contact is a coarsening-upward shale-to-sandstone succession deposited in a prodelta/delta-front environment. The observation that the upper part of the Seabee Formation correlates with seismic clinoforms suggests that dysaerobic conditions extended well up onto the prodelta slope during intervals of transgression and highstand. Correlation of the Umiat Mountain outcrop section with well logs and seismic data suggests that sequence boundaries and lowstand shoreface deposits may be common in the Seabee Formation and that wave action may have been important in transporting sand to the paleoshelf margin. These conclusions may contribute to an enhanced understanding of sand distribution in prospective lowstand turbidite deposits in the subsurface of the central North Slope of Alaska.
Geologic map of the Ikpikpuk River quadrangle, Alaska
This map is a product of the USGS Digital Geologic Maps of Northern Alaska project, which captures in digital format quadrangles across the entire width of northern Alaska. Sources include geologic maps previously published in hardcopy format and recent updates and revisions based on field mapping by the Alaska Department of Natural Resources, Division of Geological and Geophysical Surveys and Division of Oil and Gas, and the U.S. Geological Survey. Individual quadrangles are digitized at either 1:125,000 or 1:250,000 depending on the resolution of source maps. The project objective is to produce a set of digital geologic maps with uniform stratigraphic nomenclature and structural annotation, and publish those maps electronically. The paper version of this map is available for purchase from the USGS Store.
Conventional natural gas resource potential, Alaska North Slope
An estimate of total natural gas resource potential of northern Alaska can be obtained by summing known gas reserves in oil and gas fields (35 TCF), mean estimates of undiscovered nonassociated (61 TCF) and associated (12 TCF) gas resources in NPRA, and mean estimates of undiscovered nonassociated (4 TCF) and associated (5 TCF) gas resources in the 1002 area of ANWR; this yields a total of 117 TCF. When estimates of undiscovered gas resources for non-Federal lands are released in 2005, that total will increase by a non-trivial amount. Thus, the conventional natural gas resource potential of onshore and State offshore areas totals well over 100 TCF. The inclusion of the MMS mean estimate (96 TCF) for undiscovered gas resources in the Beaufort and Chukchi planning areas of the Federal offshore extends that total above 200 TCF.
Geologic map of the Umiat quadrangle, Alaska
This geologic map of the Umiat quadrangle is a compilation of previously published USGS geologic maps and unpublished mapping done for the Richfield Oil Corporation. Geologic mapping from these three primary sources was augmented with additional unpublished map data from British Petroleum Company. This report incorporates recent revisions in stratigraphic nomenclature. Stratigraphic and structural interpretations were revised with the aid of modern high-resolution color infrared aerial photographs. The revised geologic map was checked in the field during the summers of 2001 and 2002. The geologic unit descriptions on this map give detailed information on thicknesses, regional distributions, age determinations, and depositional environments. The paper version of this map is available for purchase from the USGS Store.
Brookian stratigraphic plays in the National Petroleum Reserve - Alaska (NPRA)
The Brookian megasequence in the National Petroleum Reserve in Alaska (NPRA) includes bottomset and clinoform seismic facies of the Torok Formation (mostly Albian age) and generally coeval, topset seismic facies of the uppermost Torok Formation and the Nanushuk Group. These strata are part of a composite total petroleum system involving hydrocarbons expelled from three stratigraphic intervals of source rocks, the Lower Cretaceous gamma-ray zone (GRZ), the Lower Jurassic Kingak Shale, and the Triassic Shublik Formation. The potential for undiscovered oil and gas resources in the Brookian megasequence in NPRA was assessed by defining five plays (assessment units), one in the topset seismic facies and four in the bottomset-clinoform seismic facies. The Brookian Topset Play is estimated to contain between 60 (95-percent probability) and 465 (5-percent probability) million barrels of technically recoverable oil, with a mean (expected value) of 239 million barrels. The Brookian Topset Play is estimated to contain between 0 (95-percent probability) and 679 (5-percent probability) billion cubic feet of technically recoverable, nonassociated natural gas, with a mean (expected value) of 192 billion cubic feet. The Brookian Clinoform North Play, which extends across northern NPRA, is estimated to contain between 538 (95-percent probability) and 2,257 (5-percent probability) million barrels of technically recoverable oil, with a mean (expected value) of 1,306 million barrels. The Brookian Clinoform North Play is estimated to contain between 0 (95-percent probability) and 1,969 (5-percent probability) billion cubic feet of technically recoverable, nonassociated natural gas, with a mean (expected value) of 674 billion cubic feet. The Brookian Clinoform Central Play, which extends across central NPRA, is estimated to contain between 299 (95-percent probability) and 1,849 (5-percent probability) million barrels of technically recoverable oil, with a mean (expected value) of 973 million barrels. The Brookian Clinoform Central Play is estimated to contain between 1,806 (95-percent probability) and 10,076 (5-percent probability) billion cubic feet of technically recoverable, nonassociated natural gas, with a mean (expected value) of 5,405 billion cubic feet. The Brookian Clinoform South-Shallow Play is estimated to contain between 0 (95-percent probability) and 1,254 (5-percent probability) million barrels of technically recoverable oil, with a mean (expected value) of 508 million barrels. The Brookian Clinoform South-Shallow Play is estimated to contain between 0 (95-percent probability) and 5,809 (5-percent probability) billion cubic feet of technically recoverable, nonassociated natural gas, with a mean (expected value) of 2,405 billion cubic feet. The Brookian Clinoform South-Deep Play is estimated to contain between 0 (95-percent probability) and 8,796 (5-percent probability) billion cubic feet of technically recoverable, nonassociated natural gas, with a mean (expected value) of 3,788 billion cubic feet. No technically recoverable oil is assessed in the Brookian Clinoform South-Deep Play, as it lies at depths that are entirely in the gas window. Among the Brookian stratigraphic plays in NPRA, the Brookian Clinoform North Play and the Brookian Clinoform Central Play are most likely to be objectives of exploration activity in the near-term future because they are estimated to contain multiple oil accumulations larger than 128 million barrels technically recoverable oil, and because some of those accumulations may occur near existing infrastructure in the eastern parts of the plays. The other Brookian stratigraphic plays are not likely to be the focus of exploration activity because they are estimated to contain maximum accumulation sizes that are smaller, but they may be an objective of satellite exploration if infrastructure is extended into the play areas. The total volumes of natural gas estimated to occur in B
Beaufortian stratigraphic plays in the National Petroleum Reserve - Alaska (NPRA)
The Beaufortian megasequence in the National Petroleum Reserve in Alaska (NPRA) includes Jurassic through lower Cretaceous (Neocomian) strata of the Kingak Shale and the overlying pebble shale unit. These strata are part of a composite total petroleum system involving hydrocarbons expelled from source rocks in three stratigraphic intervals, the Lower Jurassic part of the Kingak Shale, the Triassic Shublik Formation, and the Lower Cretaceous gamma-ray zone (GRZ) and associated strata. The potential for undiscovered oil and gas resources in the Beaufortian megasequence in NPRA was assessed by defining eight plays (assessment units), two in lower Cretaceous (Neocomian) topset seismic facies, four in Upper Jurassic topset seismic facies, one in Lower Jurassic topset seismic facies, and one in Jurassic through lower Cretaceous (Neocomian) clinoform seismic facies. The Beaufortian Cretaceous Topset North Play is estimated to contain between 0 (95-percent probability) and 239 (5-percent probability) million barrels of technically recoverable oil, with a mean (expected value) of 103 million barrels. The Beaufortian Cretaceous Topset North Play is estimated to contain between 0 (95-percent probability) and 1,162 (5-percent probability) billion cubic feet of technically recoverable, nonassociated natural gas, with a mean (expected value) of 405 billion cubic feet. The Beaufortian Cretaceous Topset South Play is estimated to contain between 635 (95-percent probability) and 4,004 (5-percent probability) billion cubic feet of technically recoverable, nonassociated natural gas, with a mean (expected value) of 2,130 billion cubic feet. No technically recoverable oil is assessed in the Beaufortian Cretaceous Topset South Play, as it lies at depths that are entirely in the gas window. The Beaufortian Upper Jurassic Topset Northeast Play is estimated to contain between 2,744 (95-percent probability) and 8,086 (5-percent probability) million barrels of technically recoverable oil, with a mean (expected value) of 5,176 million barrels. No technically recoverable gas is assessed in the Beaufortian Upper Jurassic Topset Northeast Play. The Beaufortian Upper Jurassic Topset Northwest Play is estimated to contain between 733 (95-percent probability) and 3,312 (5-percent probability) million barrels of technically recoverable oil, with a mean (expected value) of 1,859 million barrels. No technically recoverable gas is assessed in the Beaufortian Upper Jurassic Topset Northwest Play. The Beaufortian Upper Jurassic Topset Southeast Play is estimated to contain between 2,053 (95-percent probability) and 9,030 (5-percent probability) billion cubic feet of technically recoverable, nonassociated natural gas, with a mean (expected value) of 5,137 billion cubic feet. No technically recoverable oil is assessed in the Beaufortian Upper Jurassic Topset Southeast Play, as it lies at depths that are entirely in the gas window. The Beaufortian Upper Jurassic Topset Southwest Play is estimated to contain between 2,008 (95-percent probability) and 9,265 (5-percent probability) billion cubic feet of technically recoverable, nonassociated natural gas, with a mean (expected value) of 5,220 billion cubic feet. No technically recoverable oil is assessed in the Beaufortian Upper Jurassic Topset Southwest Play, as it lies at depths that are entirely in the gas window. The Beaufortian Lower Jurassic Topset Play is estimated to contain between 0 (95-percent probability) and 210 (5-percent probability) million barrels of technically recoverable oil, with a mean (expected value) of 83 million barrels. The Beaufortian Lower Jurassic Topset Play is estimated to contain between 0 (95-percent probability) and 1,915 (5-percent probability) billion cubic feet of technically recoverable, nonassociated natural gas, with a mean (expected value) of 793 billion cubic feet. The Beaufortian Clinoform Play is estimated to contain between 0 (95-percent probability)
Sandstone and shale compaction curves derived from sonic and gamma ray logs in offshore wells, North Slope, Alaska– Parameters for basin modeling
Representative compaction curves for the principle lithologies are essential input for reliable models of basin history. Compaction curves influence estimates of maximum burial and erosion. Different compaction curves may produce significantly different thermal histories. Default compaction curves provided by basin modeling packages may or may not be a good proxy for the compaction properties in a given area. Compaction curves in the published literature span a wide range, even within one lithology, e.g., sandstone (see Panel 3). An abundance of geophysical well data for the North Slope, from both government and private sources, provides us with an unusually good opportunity to develop compaction curves for the Cretaceous-Tertiary Brookian sandstones, siltstones, and shales. We examined the sonic and gamma ray logs from 19 offshore wells (see map), where significant erosion is least likely to have occurred. Our data are primarily from the Cretaceous-Tertiary Brookian sequence and are less complete for older sequences. For each well, the fraction of shale (Vsh) at a given depth was estimated from the gamma ray log, and porosity was computed from sonic travel time. By compositing porosities for the near-pure sand (Vsh<1%) and shale (Vsh>99%)from many individual wells we obtained data over sufficient depth intervals to define sandstone and shale 'master' compaction curves. A siltstone curve was defined using the sonic-derived porosities for Vsh values of 50%. These compaction curves generally match most of the sonic porosities with an error of 5% or less. Onshore, the curves are used to estimate the depth of maximum burial at the end of Brookian sedimentation. The depth of sonic-derived porosity profiles is adjusted to give the best match with the 'master' compaction curves. The amount of the depth adjustment is the erosion estimate. Using our compaction curves, erosion estimates on the North Slope range from zero in much of the offshore, to as much as 1500 ft along the coast, and to more than 10,000 ft in the foothills (Panel 3). Compaction curves provide an alternative to vitrinite reflectance for estimating erosion. Vitrinite reflectance data are often very sparse in contrast to well log data and are subject to inconsistencies when measurements are made by different labs. The phenomenon of 'recycling' can also make the reflectance values of dispersed vitrinite problematic for quantifying erosion. Recycling is suspected in dispersed vitrinite in North Slope rocks, particularly in the younger, Cretaceous-Tertiary section. The compaction curves defined here are being integrated into our burial history and thermal models to determine the timing of source rock maturation. An example on Panel 3 shows the results of calculating the maturity of the Shublik Fm. at the Tulaga well using two different sets of shale and siltstone compaction curves. Finally, accurate compaction curves improve a model's ability to realistically simulate the pressure regime during burial, including overpressures.
Revised Cretaceous and Tertiary stratigraphic nomenclature in the Colville Basin, Northern Alaska
A revised stratigraphic nomenclature is proposed for Cretaceous and Tertiary geologic units of the central and western North Slope of Alaska. This revised nomenclature is a simplified and broadly applicable scheme suitable for a suite of digital geologic quadrangle maps being prepared jointly by the U.S. Geological Survey and the Alaska Department of Natural Resources, Division of Geological and Geophysical Surveys and Division of Oil and Gas. This revised nomenclature scheme is a simplification of a complex stratigraphic terminology that developed piecemeal during five decades of geologic investigations of the North Slope. It is based on helicopter-supported geologic field investigations incorporating information from high-resolution aerial photography, satellite imagery, paleontology, reflection seismic records, and sequence stratigraphic concepts. This revised nomenclature proposes the abandonment of the Colville Group; demotion of the Nanushuk Group to formation status; abandonment of six formations (Kukpowruk, Tuktu, Grandstand, Corwin, Chandler, and Ninuluk); revision of four formations (Sagavanirktok, Prince Creek, Schrader Bluff, and Seabee); elevation of the Tuluvak Tongue of the Prince Creek Formation to formation status; revision of two members (Franklin Bluffs Member and Sagwon Member of the Sagavanirktok Formation); abandonment of eight members or tongues (Kogosukruk, Rogers Creek, Barrow Trail, Sentinel Hill, Ayiyak, Shale Wall, Niakogon, and Killik); and definition of one new member (White Hills Member of the Sagavanirktok Formation).
U.S. Geological Survey 2002 petroleum resource assessment of the National Petroleum Reserve in Alaska (NPRA): play maps and technically recoverable resource estimates
This report provides a summary of the estimated volume of technically recoverable undiscovered oil and nonassociated gas resources for each of the 24 plays evaluated in the U.S. Geological Survey 2002 petroleum resource assessment of the NPRA (Bird and Houseknecht, 2002). It also provides a set of illustrations showing the stratigraphic and geographic location of each play. Additional details of this assessment will follow in later publications.
U.S. Geological Survey 2002 petroleum resource assessment of the National Petroleum Reserve in Alaska (NPRA): GIS play maps
This report provides digital GIS files of maps for each of the 24 plays evaluated in the U.S. Geological Survey (USGS) 2002 petroleum resource assessment of the NPRA (Bird and Houseknecht, 2002a). These are the same maps released in pdf format by Bird and Houseknecht (2002b). The USGS released in 2002 a summary of the estimated volume of technically recoverable, undiscovered oil and nonassociated gas resources for 24 plays in NPRA (Bird and Houseknecht, 2002b). The NPRA assessment study area includes Federal and Native onshore land and adjacent State offshore areas. A map showing the areal extent of each play was prepared by USGS geologists as a preliminary step in the assessment process. Boundaries were drawn on the basis of a variety of information, including seismic reflection data, results of previous exploration drilling, and regional patterns of rock properties. Play boundary polygons were captured by digitizing the play maps prepared by USGS geologists. Federal, Native, and State areas were later clipped from the play boundary polygons, allowing for acreages to be calculated for entire plays and for various subareas within plays.
Depositional sequences and facies in the Torok Formation, National Petroleum Reserve, Alaska (NPRA)
Brookian turbidites (Cretaceous through Tertiary) have become oil exploration objectives on the North Slope of Alaska during the past decade, and it is likely this focus will extend into the National Petroleum Reserve - Alaska ( NPRA ). A regional grid of 2- D seismic data, sparse well control, and field work in the Brooks Range foothills provide constraints for an ongoing effort to establish a sequence stratigraphic framework for Brookian turbidites in the Torok Formation across NPRA . The Torok Formation and overlying Nanushuk Formation (both mostly Albian) display the overall seismic geometry of bottomset-clinoform-topset strata indicating northeastward migration of a shelf margin. Within bottomset and clinoform strata of the Torok , depositional sequences have been identified that represent four distinct phases of shelf-margin sedimentation. (1) Regression, representing low relative sea level, is characterized by the development of an erosional surface on the shelf and upper slope , and the deposition of turbidite channel deposits on the middle to lower slope and submarine fan deposits at the base of slope. These deposits constitute a lowstand systems tract (LST). (2) Transgression, representing rising relative sea level, is characterized by the deposition of a mudstone drape on the basin floor, slope, and outer shelf. This drape comprises relatively condensed facies that constitute a transgressive systems tract (TST). (3) Aggradation, representing high relative sea level, is characterized by the deposition of relatively thick strata on the outer shelf and moderately thick mudstones on the slope. (4) Progradation, also representing high relative sea level, is characterized by the deposition of relatively thin strata on the outer shelf and very thick mudstones on the slope. Together, deposits of the aggradation and progradation phases constitute a highstand systems tract (HST). Large scale geometries of Torok strata vary across the Colville basin. In southern NPRA, high rates of subsidence accommodated the deposition of a "foredeep clinoform wedge" that contains a high proportion of sand-rich LST deposits. In northern NPRA, lower rates of subsidence favored the accumulation of mud-rich HST deposits. The most favorable stratigraphic trapping geometries in the Torok Formation occur where amalgamated sandstones deposited in turbidite channels incised on the mid- to lower-slope and on the proximal parts of submarine fans during regression (LSTs) are capped by relatively condensed mudstone facies deposited during transgression (TSTs). Common successions observed in Torok cores include a spectrum of slope and turbidite facies. Upper slope facies comprise laminated mudstones and siltstones that locally display evidence of slumping, sliding, and chaotic failure. Lower slope facies comprise heterolithic turbidites at some locations and interlaminated mudstones and thin, very fine-grained sandstones at others. Torok turbidites include amalgamated sandstones deposited in channel systems as well as thin-bedded, widespread sandstones deposited by unconfined flows on lobes or in channel overbank settings. These turbidite facies likely occur in both channel-lobe systems and slope apron systems within the Torok.
Rotational reflectance properties of Arkoma Basin dispersed vitrinite: Insights for understanding reflectance populations in high thermal maturity regions
Analysis and interpretation of dispersed vitrinite reflectance data in regions of high thermal maturity (> 2% vitrinite reflectance) have been equivocal partly because of an increase in width and complexity of reflectance histograms with increasing mean reflectance. Such complexity is illustrated by random reflectance ( R ran ) data from the Arkoma Basin that display a linear increase in standard deviation of R ran with an increase in mean R ran from 1 to 5%. Evaluating how much of the dispersion in these data is the result of vitrinite anisotropy and how much is the result of mixing of kerogen populations by sedimentary processes and/or sampling procedures has been problematic. Automated collection of reflectance data during polarizer rotation provides preliminary data for solution of this problem. Rotational reflectance data collected from a subset of Arkoma Basin samples reveal positive, linear relationships among maximum ( R ′ max ), random ( R ran ), rotational ( R rot ), and minimum ( R ′ min ) reflectance, as well as a systematic increase in bireflectance ( R ′ max – R ′ min ) with increasing reflectance. R ′ max and R rot display lower standard deviations and narrower, more nearly unimodal histograms than R ran and R ′ min , suggesting that R ′ max and R rot are superior (less ambiguous) indices of thermal maturity. These data patterns are inferred to be mostly an indication of increasing vitrinite anisotropy with increasing thermal maturity, suggesting that the linear covariance observed between mean R ran and standard deviation in dispersed organic data sets from regions of high thermal maturity may be explained mostly as the result of increasing vitrinite anisotropy with increasing thermal maturity.