U.S. Geological Survey Open-File Report 03-039
Version 1.0

Brookian Stratigraphic Plays in the National Petroleum Reserve – Alaska (NPRA)

David W. Houseknecht
U.S. Geological Survey
Reston, Virginia 20192
dhouse@usgs.gov

Abstract
Introduction
Geology of Brookian Strata in NPRA
      Stratigraphy and Depositional Facies
      Structure and Thermal Maturity
Petroleum Source Rocks Pertinent to Brookian Stratigraphic Plays
      GRZ and associated source rocks
      Kingak Shale
      Shublik Formation
Brookian Stratigraphic Plays
      Brookian Topset Play
            Hydrocarbon Charge
            Reservoir Properties
            Trap Types
            Timing
            Play Attributes – Brookian Topset Play
            Results – Brookian Topset Play
      Brookian Clinoform Plays
            Hydrocarbon Charge
            Reservoir Properties
            Trap Types
            Timing
            Play Attributes – Brookian Clinoform North Play
            Results – Brookian Clinoform North Play
            Play Attributes – Brookian Clinoform Central Play
            Results – Brookian Clinoform Central Play
            Play Attributes – Brookian Clinoform South-Shallow Play
            Results – Brookian Clinoform South-Shallow Play
            Play Attributes – Brookian Clinoform South-Deep Play
            Results – Brookian Clinoform South-Deep Play
Summary and Conclusions
Acknowledgments
References
Tables 1-20 (one separate file, or Tables 1-2 | 3-4 | 5-6 | 7-8 | 9-10 | 11-12 | 13-14 | 15-16 | 17-18 | 19-20)
Figures (separate files, or all figures with captions in a 1-MB PDF file)

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Abstract

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 Brookian stratigraphic plays, together with the relatively modest sizes of accumulations estimated to occur, suggest these plays will not be major objectives of natural gas exploration in the near-term future.

Introduction

Alaska North Slope oil exploration in recent years has focused increasingly on stratigraphic traps, including objectives in the Cretaceous to Tertiary Brookian megasequence. The main focus of exploration in Brookian strata has been deep marine (turbidite) facies, resulting in the discovery and development of several accumulations (e.g., Badami, Tarn, Meltwater, and Nanuq). Exploitation activity also has focused on shallow marine through non-marine Brookian facies, with the development of the Tabasco pool illustrating the significant potential that exists in these strata.

The objectives of this chapter are to provide an overview of Brookian strata within the National Petroleum Reserve – Alaska (NPRA), to summarize the rationale for assessing undiscovered oil and gas resources in stratigraphic traps in those strata, and to present the results of evaluating the resource potential of five assessment units (plays) in Brookian strata. The potential for undiscovered oil and gas resources in structural traps in these same strata is evaluated in a companion chapter.

Geology of Brookian Strata in NPRA

Stratigraphy and Depositional Facies

The Brookian “megasequence” of northern Alaska (Fig. 1) includes Early Cretaceous through Tertiary strata comprising sediment derived from the ancestral Brooks Range and deposited in the Colville foreland basin (see regional summaries by Hubbard and others, 1987; and Bird and Molenaar, 1992). Filling of the Colville basin generally progressed from west to east through time as reflected by the eastward younging of Brookian strata across the North Slope.

The oldest Brookian strata in NPRA (Neocomian Okpikruak Formation and Aptian-Albian Fortress Mountain Formation) are limited to the highly deformed outcrop belt of the southern Foothills (e.g., Moore and others, 1994), although parts of the Torok Formation are likely equivalent to the Fortress Mountain (e.g., Molenaar, 1988; Mull and others, in press). The youngest Brookian strata in NPRA include the Upper Cretaceous Colville Group (Fig. 1) and the Tertiary Sagavanirktok Formation. The Colville Group occurs in northeastern NPRA, where it thickens eastward from a zero-truncation edge to a maximum thickness of 4,000 to 5,000 feet along the Colville River (Brosgé and others, 1966; Bird, 1988). The Sagavanirktok Formation (Mull and others, in press), which occurs offshore and across much of the Alaska North Slope east of the Colville River, is present in NPRA only along the northeastern coast (Witmer and others, 1981).

The bulk of Brookian strata in NPRA is represented by the mostly Albian aged Torok Formation and the Albian-Cenomanian aged Nanushuk Group (Fig. 1). The Torok Formation ranges in thickness from less than 3,000 ft. in eastern and northern NPRA to more than 15,000 ft. in southern NPRA (Fig. 2). From a depositional zero edge just east of NPRA, the Nanushuk Group thickens to more than 8,000 ft. in western NPRA (Fig. 2). These two formations have the potential to contain stratigraphically trapped petroleum and they are the focus of the remainder of this chapter.

The regional stratigraphy and depositional facies of the Torok Formation and Nanushuk Group are well known (e.g., Molenaar, 1988; Bird and Molenaar, 1992). Previous work has demonstrated that the Torok Formation and Nanushuk Group together display the overall seismic geometry of bottomset-clinoform-topset strata indicating eastward to northeastward migration of a depositional system that included deep marine through non-marine depositional environments. The Torok generally includes deep marine basin, marine slope, and outer shelf deposits (Molenaar, 1985, 1988; Houseknecht and Schenk, 2001) whereas the Nanushuk includes marine shelf and shoreface, deltaic, and non-marine deposits (Ahlbrandt and others, 1979; Huffman and others, 1985; Huffman and others, 1988; Houseknecht and others, 1999; LePain and Kirkham, 2001). Although it generally is inferred that the Torok and Nanushuk represent coeval deposits within a single depositional system and that time lines cut across their shared formational contact (e.g., Molenaar, 1988), specific stratigraphic surfaces or beds can rarely be correlated across the two formations. Reasons for this include insufficient resolution of paleontologic, seismic, and other subsurface data, and poor continuity of outcrops in the Brooks Range foothills.

Structure and Thermal Maturity

Figure 3 schematically illustrates the regional geometry of Brookian strata in eastern NPRA. Little deformation of Brookian strata is evident beneath the coastal plain, although regional patterns of bedrock subcrops beneath surficial deposits, structural attitudes, thermal maturity patterns, and apatite fission track evidence indicate this area was subjected to broad, regional uplift and erosion during Tertiary time (Mayfield and others, 1988; O’Sullivan and others, 1997; Bird, 2001). The foothills are the surficial expression of a fold-and-thrust belt that developed about 60 Ma and was further deformed by subsequent compressional tectonic events later in the Tertiary (O'Sullivan and others, 1997). Brookian strata beneath the foothills are characterized by detachment folds and tectonic thickening in the Torok, and these characteristics become more pronounced southward. The southern foothills are characterized by a tectonic wedge that displays greater structural complexity and exposes deeper stratigraphic horizons. The structural geology of NPRA is discussed in greater detail in companion chapters (Potter and Moore, this volume; Moore and Potter, this volume).

Subsurface patterns of thermal maturity, based on data compiled by Johnsson and others (1999) and new data from USGS fieldwork in the foothills, also are shown schematically in Figure 3. This illustration indicates that most of the Torok and all of the Nanushuk in the subsurface of eastern NPRA are characterized by vitrinite reflectance values generally associated with the oil window (<1.35%; Law, 1999). At greater depths beneath the foothills, vitrinite reflectance values are projected to be 1.5 to 2.5 percent in the lower Torok, and these levels of thermal maturity are commonly associated with producible natural gas resources in other foreland basins (Houseknecht and Spötl, 1993). Figure 3 also shows the locations of the Tarn and Nanuq oil pools and heavily oil-stained, turbidite sandstones in Torok outcrops in the foothills.

Petroleum Source Rocks Pertinent to Brookian Stratigraphic Plays

Hydrocarbons expelled from three petroleum source rocks present in the NPRA region (Lillis and Magoon, this volume) have the greatest potential to charge Brookian stratigraphic plays: GRZ, Kingak, and Shublik (Fig. 1). Geochemical evidence from oil tests, oil shows, and oil-stained outcrop samples indicate that hydrocarbons expelled from all three source rock intervals have migrated into Brookian strata at various locations (Magoon and Bird, 1987, 1988; Magoon and others, 1988; Lillis and Magoon, this volume), and specific examples are cited in subsequent sections of this report. This evidence suggests that Brookian strata within NPRA are part of a composite total petroleum system (Magoon and Schmoker, 2000).

GRZ and Associated Source Rocks

The “GRZ” is herein used to refer collectively to an interval of source rocks that occur over a relatively thin stratigraphic section in the uppermost part of the Beaufortian megasequence and the basal part of the Brookian megasequence (Fig. 1). These include, in ascending order, the pebble shale unit, gamma-ray zone (GRZ) and its distal equivalent the Hue Shale (mostly east of NPRA), and lower parts of the Torok Formation. The GRZ is an oil-prone source rock that represents a condensed section marking the boundary between the Beaufortian and Brookian megasequences. The underlying pebble shale unit and overlying Torok Formation, both of which display gradational or intertonguing relationships with the GRZ, range from mixed oil- and gas-prone to predominately gas-prone. Oil generated from source rocks in the GRZ interval is characterized by high API gravity (average 37°) and low sulfur content (0.1%).

In easternmost NPRA and points east, the lower part of the Upper Cretaceous Seabee Formation also may be included in the GRZ source rock interval. The Seabee Formation is a mixed oil- and gas-prone source rock, and is buried deeply enough to have generated hydrocarbons east of NPRA.

Throughout NPRA the Nanushuk Group (Fig. 1) locally contains strata that may be of source-rock quality. These include coals, carbonaceous shales, and mudstones that locally contain abundant type III (coaly) kerogen. Although most of these potential source rocks are gas-prone, the local presence of boghead or cannel coals (Stadnichenko, 1929; Webber, 1947) and the occurrence of amber (Langenheim and others, 1960) in the Nanushuk Group suggest that oil-prone source rocks may be present locally.

Kingak Shale

The “Kingak” is herein used to refer collectively to hydrocarbon source rocks that occur within the Jurassic – Lower Cretaceous Kingak Shale (Fig. 1), and within the Blankenship Member of the Otuk Formation (Mull and others, 1982), which is the southern, distal stratigraphic equivalent of the Kingak Shale. A reconstruction of depositional sequences within the Kingak Shale has been completed based on interpretation of a regional grid of 2-D seismic data (Houseknecht, 2001, this volume). In northern NPRA, the Kingak Shale comprises a complex assemblage of shale, siltstone, and sandstone deposited in numerous depositional sequences on a shallow marine shelf. Those shallow marine depositional sequences thin and grade southward across an abrupt shelf margin into deeper marine shales that represent a distal condensed section. The Blankenship Member of the Otuk Formation, which crops out in the southern foothills just north of the Brooks Range, is the distal stratigraphic equivalent of the entire Kingak Shale (Mull and others, 1982).

North of the abrupt shelf margin in the Kingak Shale, condensed mudstones with elevated organic carbon content occur within transgressive systems tracts, and these mudstones may represent local source rocks. Their geochemical characteristics indicate that they are either gas-prone or mixed oil- and gas-prone. South of the abrupt shelf margin in the Kingak Shale, the basinal condensed section is rich in organic carbon and is oil-prone. This condensed section includes basinal facies of the Kingak Shale beneath much of NPRA as well as the distal Blankenship Member of the Otuk Formation, which crops out locally in the southern foothills and is inferred to be present in the subsurface beneath the foothills. Collectively, the distal Kingak and Blankenship condensed section represents an important, oil-prone source rock that would yield a high gravity (average 39° API) and low sulfur (0.3%) oil (Lillis and Magoon, this volume).

Shublik Formation

The “Shublik” is herein used to refer collectively to source rocks that occur within the Triassic Shublik Formation (Fig. 1) and within the lower two members of the Otuk Formation, which are considered to be the southern, distal stratigraphic equivalent of the Shublik Formation (Mull and others, 1982). The Shublik Formation was deposited in a marine system with high organic productivity, and is thought to represent an ancient upwelling zone (Parrish and others, 2001). Together, the Shublik and Otuk formations comprise a blanket of oil-prone source rocks that are present throughout NPRA (except for a small area around Point Barrow where the Shublik is absent due to onlap pinchout) and the foothills to the south of NPRA.

The Shublik Formation has long been acknowledged as a significant oil source rock beneath the Alaska North Slope, having generated the bulk of the oil produced at Prudhoe Bay oil field. Oil generated from the Shublik is characterized by relatively low gravity (average 23 ° API) and high sulfur content (1.6%).

Brookian Stratigraphic Plays

Assessment of oil and gas resource potential in Brookian stratigraphic plays was conducted within the framework of (1) a single topset play and (2) a set of four clinoform plays. This decision is based on the fact that stratal geometries and depositional facies are fundamentally different in shallow marine through non-marine deposits as opposed to marine slope and deep-water deposits. Therefore, populations of stratigraphic traps are likely to be significantly different between topset and clinoform strata. In the context of recent and ongoing assessments conducted by the U.S. Geological Survey in other parts of the United States and the World (Pollastro and others, 2001; Magoon and Schmoker, 2000; Schmoker and Klett, 2000), these five plays represent five assessment units within the composite total petroleum system discussed in a previous section. The following sections provide a brief overview of the main attributes of each play, as well as an explanation of assessment input values.

All Brookian stratigraphic plays discussed in this chapter extend beyond the boundaries of the NPRA. However, this assessment of undiscovered petroleum resources is limited to the NPRA and adjacent State waters. Play boundaries, therefore, are based on geologic criteria in some areas and on land-ownership criteria in other areas, and are defined as such in each section.

Brookian Topset Play

This play primarily involves stratigraphic traps within topset seismic facies in the Nanushuk Group and uppermost Torok Formation in NPRA, although subtle structural traps also are included in the generally undeformed part of NPRA (north of the Brookian Topset Structural Play). This play extends into the Beaufort Sea, so the northern assessment limit is set at the boundary between State and Federal waters (Fig. 4). The southern play boundary is defined in the foothills along a trend of the northernmost anticlines across which the Nanushuk Group is completely eroded (Awuna and Carbon anticlines; Kirschner and Rycerski, 1988, plate 9.1). The southern play boundary is drawn on the north side of those anticlines, approximately 2 miles north of the outcrop of the contact between the Nanushuk Group and Torok Formation. The play boundaries on the west and east are defined by the boundary of the National Petroleum Reserve – Alaska. The area of this play overlaps broadly with that of the Brookian Topset Structural Play, which involves structural traps within topset seismic facies. The assumption made here is that viable stratigraphic traps may occur off structure (i.e., in synclines and broad limbs of structures) and that potential is included in this play.

Brookian topset strata include marine shelf, deltaic, and non-marine facies based on analysis of 2-D seismic data, wire-line well logs, well cores, and outcrops. This work benefited from the regional studies of previous workers, especially Ahlbrandt and others (1979), Huffman and others (1985), Molenaar (1985), and Huffman and others (1988). Certain interpretations stemming from the current analysis are summarized by Houseknecht and others (1999) and LePain and Kirkham (2001), although many details of the work leading to this assessment have not yet been published.

Two small oil accumulations are known within NPRA in this play. The Simpson accumulation (Fig. 4) is estimated to contain 12 million barrels of 24° API gravity oil in a stratigraphic trap involving up-dip truncation of sandstones in the Nanushuk Group against a shale-filled Canyon formed during the Late Cretaceous (Kornbrath and others, 1997; Kumar and others, 2002). The second is the Fish Creek accumulation (Fig. 4), where 14° API gravity oil was tested from sandstones in the Nanushuk Group, and for which no estimate of reserves has been made (Kornbrath and others, 1997: Kumar and others, 2002). The Fish Creek accumulation is located on a subtle structural nose (Kumar and others, 2002, although the exact trapping mechanism is unclear.

Stratigraphic traps in the Brookian topset play have not been a primary objective of exploration drilling in NPRA. The Simpson accumulation was discovered by core drilling to evaluate the origin of surface oil seeps, and the Fish Creek discovery was a stratigraphic test of a prominent gravity anomaly with a surface oil seep nearby (Robinson and Collins, 1959).

Hydrocarbon Charge

The GRZ interval is considered to be the primary source rock for oil and gas that may have charged this play. Oils from seeps on the Simpson peninsula and Fish Creek, oils extracted from Nanushuk sandstones from numerous locations in NPRA, and oils extracted from outcrop samples from the foothills south of NPRA have geochemical characteristics indicating they were generated exclusively or partly from the GRZ (Lillis and Magoon, this volume). Topset seismic facies in the Nanushuk Group and uppermost Torok Formation are stratigraphically separated by at least several thousand feet from the oil-prone source rock interval. Clinoforms within the Torok Formation may have served as migration pathways from GRZ source rocks to stratigraphic traps in the topset play (Fig. 5).

Hydrocarbons expelled from either Kingak or Shublik source rocks are considered secondary candidates to have charged the Brookian topset play. In either case, rather long and circuitous migration pathways would have been required unless high angle fractures provided a direct, vertical route. Low displacement normal faults and strike-slip faults are known to exist, especially in northern NPRA (e.g., Homza, in press), and these may have served as pathways for significant vertical migration. Oil recovered from the Fish Creek well has geochemical affinities with Shublik source rocks, thereby providing evidence that oil expelled from the Shublik migrated into the Brookian topsets at that locality. Oil extracted from some stained outcrop samples from the foothills south of NPRA have geochemical characteristics indicating they were generated exclusively or partly from the Shublik (Lillis and Magoon, this volume).

Reservoir Properties

Sandstones within the Nanushuk Group are the most likely reservoirs in this play, although it is possible that sandstones in the uppermost Torok Formation also may be reservoirs. Reservoir properties in Nanushuk sandstones are highly dependent upon depositional facies and maximum depth to which they have been buried. The highest porosity and permeability occur in relatively coarse-grained, cross-bedded sandstones deposited in incised fluvial or deltaic channels or in wave-modified delta front or estuarine systems. The lowest porosity and permeability occur in relatively fine-grained, ripple-bedded or hummocky cross-stratified sandstones deposited in open marine shelf and shoreface systems.

Average porosity and permeability of Nanushuk sandstones generally decrease from north to south in NPRA, a trend that reflects increasing thermal maturity and maximum depth of burial to the south. In northern NPRA, shallow cores of Nanushuk sandstones (e.g., Simpson 1 and East Simpson 2) have maximum porosities of 20 to 30 percent (locally more than 30%) and maximum permeabilities of 100 to > 1,000 millidarcies (Nelson and Kibler, 2002). In contrast, shallow cores of Nanushuk sandstones in central NPRA (e.g., Inigok 1, Umiat 9 and 11, Gubik 1 and 2) have maximum porosities of 10 to 20 percent and maximum permeabilities of 10 to 500 millidarcies. Sandstone samples from Nanushuk outcrops in the foothills south of NPRA rarely have porosities and permeabilities greater than 10 percent and 10 millidarcies, respectively, although local occurrences of sandstone bodies with porosities of 10 to 20 percent and permeabilities of >100 millidarcies have been documented by recent field work conducted by USGS and Alaska Geological Survey field parties.

Trap Types

The Nanushuk Group is exposed at the surface across a broad area of the foothills and its top is a truncation surface capped by Pliocene-Pleistocene strata across the western two-thirds of NPRA (Fig. 4). Nevertheless, there is significant trap potential within the formation. Although certain stratigraphic trap geometries are apparent in NPRA seismic data, many traps within this play are either too small or too subtle to be resolved with public domain, 2-D seismic data. Inferences regarding the style, size, and frequency of traps are based on seismic observations (where possible), analogues from more clearly developed examples elsewhere on the North Slope, analogues from discoveries elsewhere on the North Slope, mapping of integrated subsurface datasets in areas where hydrocarbons have been tested from exploration wells, and outcrop studies.

Seismic data reveal a number of potential trap geometries at Nanushuk shelf margins. Basinward-thickening wedges with shingled internal reflections are perhaps the largest trap geometry observed. These wedges may represent shelf-margin deltas deposited during lowstands of relative sea level, or they may represent prisms of shoreface to offshore (shelf) facies deposited in accommodation space generated by compaction of underlying marine slope muds (clinoforms). Each shelf-margin wedge displays shingled internal reflections that downlap onto the base of the wedge and either toplap or truncate against the top of the wedge. If the internal reflections represent strata that include porous sandstone beds, the shelf-margin wedges have significant stratigraphic trapping potential. Growth faults also occur at Nanushuk shelf margins. Many are of small displacement and therefore are not resolvable with available seismic data. Those that are resolvable display high dips and evidence of syndepositional movement within topset facies, and typically become listric within underlying clinoform (marine slope) facies. In a few cases, there is sufficient displacement along growth faults to form rollover anticlines on the hanging wall; however, most display wedge-shaped geometries.

The largest number of stratigraphic traps in the Brookian topset play is likely to occur in various types of stratigraphic lenses, where lenses of porous and permeable sandstone are sealed by mudstones. This trapping potential occurs in several specific depositional facies documented in outcrops of the Nanushuk Group, including fluvial, deltaic, and estuarine channels (including lowstand incisions); shoreface bars at the distal ends of incised valleys; barriers, bars, and tidal deltas associated with shorezone depositional systems; and transgressive sheet sandstones. These features are rarely resolvable in seismic data available in the public domain, although incised channels may be inferred at a few locations based on truncation of seismic reflections. An analogue for incised channel traps in the Nanushuk Group may be the Tabasco pool (Kumar and others, 2002) within Upper Cretaceous topset strata in the Kuparuk River field, interpreted as an incised fluvial channel deposit by Konkler and others (2000). Incised channel systems in the Nanushuk Group have been documented during fieldwork in support of this assessment, and it is likely that similar deposits hold the potential for stratigraphically trapped hydrocarbons throughout NPRA.

The Simpson oil accumulation in northern NPRA (Fig. 4) represents an unusual stratigraphic trap in which reservoir sandstones are truncated up dip against the mudstone filling of a submarine canyon, which was cut during the Late Cretaceous. Deep incisions of this nature are not uncommon along the Arctic coast and offshore, but are rare to absent onshore in NPRA. For this reason, it is not likely that similar features will form stratigraphic traps elsewhere in NPRA.

Despite the considerable potential that exists in NPRA for stratigraphic traps in Brookian topset strata, most of the trap geometries are inferred to be rather small in size and subtle in nature. Exploration for these traps would require the use of 3-D seismic data. Hydrocarbon accumulations in this play are inferred to be modest in size and not likely to be a primary focus of exploration activity. However, these stratigraphic traps could contribute to ultimate productivity in NPRA as satellite pools if larger discoveries in other plays stimulate the development of infrastructure.

Timing

The timing of trap development relative to oil generation is excellent in the Brookian topset play. Deposition of Lower Cretaceous topset strata across NPRA occurred between ~115 Ma and ~94 Ma. Peak oil generation in the GRZ is estimated to have occurred between ~100 Ma in western NPRA and ~90 Ma in eastern NPRA (Burns and others, 2002), and generation occurred over a similar interval of time in the Kingak and Shublik source rock intervals. Thus, all stratigraphic traps in this play were formed before any oil was generated from source rocks likely to charge this play. Inasmuch as gas generation and expulsion from source rocks is inferred to have followed oil generation and expulsion, timing of stratigraphic trap development also is excellent for a gas charge.

Play Attributes – Brookian Topset Play

Tables 1 through 3 summarize the play attributes used as assessment input for this play. All input values are conditional for accumulations of the minimum size considered in this assessment (50 million barrels of in-place oil or 250 billion cubic feet of technically recoverable gas). A brief explanation of key attributes follows each table.

Reservoir thickness. Most analogue data are from small accumulations of oil and/or gas in structural traps, where multiple sand bodies contribute to total reservoir thickness (e.g., Umiat, Fish Creek, Gubik; see Kumar and others, 2002). Net reservoir thickness in known stratigraphic traps ranges from less than 50 ft. (Simpson) to more than 150 ft. (Tabasco – although this is in younger, Upper Cretaceous strata and may not be an appropriate constraint for this play). Values used for the assessment are based on the thickness of individual sand bodies that are likely to be involved in stratigraphic traps and inferred ratios of net/gross, and these observations include data from both wireline logs and outcrop studies.

Area of closure. Little analogue data exist for stratigraphic traps in Brookian topset strata. The only developed and producing pool in a similar play (Tabasco) covers about 2000 acres (Kumar and others, 2002), and the reservoir is a blocky, thick, and porous sandstone. Input values for the assessment are based on inferred sand body geometries likely to form stratigraphic traps in the Nanushuk Group, based on subsurface and outcrop studies.

Porosity and hydrocarbon pore volume. Porosity values are based on available data (Nelson and Kibler, 2002), the likely influence of burial depth across the play area, and the inference that reservoired hydrocarbons may help preserve reservoir quality. Water saturation is based on petrophysical analysis and analogues from similar lithic arenite reservoirs (Nelson, this volume).

Trap fill. The generally moderate values are based on the inference that charge reaching the play may be modest in volume and that seal integrity may not be of high quality.

Trap depth. The depth range of potential traps in the play was derived from seismic and wireline log data.

Number of prospects. The values reflect knowledge of the depositional system, perceived density of sand bodies within the Nanushuk Group, small size of inferred sand bodies (area of closure), very large size of the play area (18.3 million acres), and very shallow depth of much of the play.

Play probability attributes. Each input value represents the probability that the attribute is sufficient for the existence within the play of at least one hydrocarbon accumulation of the minimum size considered in this assessment (50 million barrels of in-place oil or 250 billion cubic feet of technically recoverable gas). Charge, trap, and timing probabilities are all estimated to be 1 (100%). The resultant play probability of 100 percent indicates an interpretation that at least one hydrocarbon accumulation of the minimum size is certain to occur in this play.

Prospect probability attributes. Each value represents the probability that the attribute is favorable to form a hydrocarbon accumulation of the minimum size considered in this assessment (50 million barrels of in-place oil or 250 billion cubic feet of technically recoverable gas) in a randomly selected prospect within the play. The charge probability is estimated to be 0.6. Although the potential for charge is generally favorable in this play, both the inferred migration pathways and the stratigraphic traps are relatively small and localized. Therefore, sufficient charge may not have reached all stratigraphic traps. The trap probability is estimated to be 0.2, primarily because: (1) Many sand bodies are inferred to have insufficient porosity, especially in the deeper parts of the play; and (2) The play may be characterized as “leaky” owing to the lack of high quality seals and the abundance of fractures. The timing probability is 1 because all the traps in this play formed well in advance of any hydrocarbon generation and migration in the region. The resultant prospect probability (charge probability X trap probability X timing probability) indicates a 12 percent chance that a randomly chosen prospect within the play will have a favorable combination of charge, trap, and timing.

The combination of play and prospect probabilities indicates a 12 percent chance that prospects in the play will contain at least 50 million barrels of in-place oil or 250 billion cubic feet of technically recoverable gas. Ninety (90) percent of the undiscovered hydrocarbon accumulations within the play are expected to be oil and ten (10) percent are expected to be gas. This estimate is based on the observations that the play is entirely within the oil window and there are viable scenarios for an oil charge (see previous discussion). However, the presence of gas-prone kerogen in the underlying Torok Formation and the possibility of a thermogenic gas charge from the deep Colville basin provide the possibility that a non-associated gas charge may be present in a small percentage of traps.

Hydrocarbon parameters. Recovery factors are based on analogues from accumulations in structural traps (e.g., Umiat) and from analogues from other basins with similar reservoir properties (Verma, this volume). Oil gravity and sulfur content are based on the assumption that the most likely scenario for an oil charge involves hydrocarbons expelled from the GRZ (Lillis and Magoon, this volume).

Results – Brookian Topset Play

The assessment input values summarized in Tables 1, 2, and 3 were used to estimate the petroleum resource potential using methods described by Schuenemeyer (this volume). Basic results are summarized in Table 4 for technically recoverable crude oil and non-associated gas. Additional results are provided by Schuenemeyer (this volume).

The volume of undiscovered, technically recoverable oil in the Brookian Topset Play in NPRA is estimated to range between 60 (95-percent probability) and 465 (5-percent probability) million barrels, with a mean (expected value) of 239 million barrels (Table 4). The volume of undiscovered, technically recoverable, non-associated gas in the Brookian Topset Play in NPRA is estimated to range between 0 (95-percent probability) and 679 (5-percent probability) billion cubic feet, with a mean (expected value) of 192 billion cubic feet (Table 4).

The oil and gas resources are estimated to occur in accumulations of various sizes, as illustrated in Figure 6. One oil accumulation between 64 and 128 mmbo may occur within the play, and no larger accumulations are expected. Approximately three accumulations between 32 and 64 mmbo may occur in the play, and all other accumulations are expected to be smaller (Fig. 6a). Most of the volume of oil is expected to occur in accumulations that fall in the 32 to 64 mmbo and in the 64 to 128 mmbo size classes, as shown in Fig. 6b.

One non-associated, gas accumulation between 192 and 384 bcf may occur within the play, and no larger accumulations are expected. Most of the gas is expected to occur in that one accumulation, as shown in Fig. 6d.

In addition to crude oil and non-associated gas, small volumes of associated natural gas and natural gas liquids are estimated to occur in this play. Those estimates are reported by Schuenemeyer (this volume).

Brookian Clinoform Plays

This set of plays involves stratigraphic traps within clinoform seismic facies in the Torok Formation in NPRA. Brookian clinoform strata include deposits of the marine slope, toe-of-slope, and basin plain. Facies mostly reflect deposition of mud and silt from suspension or deposition of sand and coarser particles from sediment gravity flows (turbidites and debris flows).

Successions of depositional facies have been identified in the Torok Formation that represent four distinct phases of sedimentation (Fig. 7; Houseknecht and Schenk, 2001); this inference is based on integrated observations from seismic data, well logs and cores, and outcrops. (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). The systems tracts delineated in this work are similar to those defined by McMillen (1991) in east-central NPRA.

Four Brookian clinoform plays are defined in NPRA based on inferred hydrocarbon charge and thermal maturity. The main geologic parameters used to define these plays are illustrated in a cross-section (Fig. 8) that illustrates the foreland basin geometry of the Colville basin. In the foredeep portion (south) of the basin, the lower Torok contains a wedge of strata that thins northward and appears to onlap the south-dipping GRZ. This wedge of strata is characterized by large-scale (generally >4000 ft.), east-dipping clinoforms and a high proportion of sandstone. It has been interpreted as comprising mostly lowstand systems tracts by Houseknecht and Schenk (2001), and is labeled “lowstand clinoform wedge” in Figure 8. This wedge is restricted to the foredeep of the Colville Basin, and pinches out along a “foredeep hinge” that extends from west to east across northern NPRA (Fig. 8). North of the foredeep hinge, that same stratigraphic position is occupied only by the GRZ. In other words, the GRZ condensed section in northern NPRA is chronostratigraphically equivalent to more than 10,000 ft. of sandstone-rich strata in the foredeep of southern NPRA (Fig. 8). The foredeep hinge forms the boundary between two of the Brookian clinoform plays, as explained below.

Structural deformation increases southward within the lowstand clinoform wedge (Fig. 8). The northern part of the wedge displays a coherent stratigraphic succession that southward is increasingly dismembered by thrust faults and detachment anticlines (Fig. 8). The amplitude of the detachment anticlines generally increases southward to a point where lower and upper parts of the foredeep wedge are structurally segregated. Southward from this “detachment tip,” the lower part of the foredeep wedge is generally attached to and lies parallel to underlying Beaufortian and Ellesmerian strata whereas the upper part of the foredeep wedge generally is attached to and lies parallel to a carapace of overlying upper Torok and Nanushuk strata. This structural detachment tip, which can be mapped across NPRA, also forms a boundary between Brookian clinoform plays, as explained below.

The four Brookian clinoform plays are defined as follows. (1) The Brookian Clinoform North Play lies north of the foredeep hinge (Fig. 9), and is associated with the most condensed part of the GRZ, which is inferred to be predominately oil-prone. This northern play area is therefore inferred to have a high probability to be charged with high gravity, low sulfur oil generated from the GRZ. This play extends into the Beaufort Sea, so the northern assessment limit is defined as the boundary between State and Federal waters.

(2) The Brookian Clinoform Central Play lies south of the foredeep hinge and north of the structural detachment tip (Figs. 8 and 9). Although this play is closely associated with the GRZ source rock interval, the GRZ is less condensed and probably contains a greater proportion of terrigenous (type III) kerogen. The GRZ source rock interval in this play area is more likely to yield a mixture of oil and gas. For this reason, the Brookian Clinoform Central Play is inferred to have a high probability to be charged with a mixture of high gravity, low sulfur oil plus natural gas.

The Brookian Clinoform South-Shallow Play and the Brookian Clinoform South-Deep Play share identical boundaries. The northern play boundary is the structural detachment tip described previously (Fig. 8). The southern play boundary is defined in the foothills along a trend of the southernmost synclines that have the Nanushuk Group exposed along their axes. The southern play boundary is drawn approximately along the exposed contact between the Nanushuk Group and Torok Formation on the southern flanks of these un-named synclines (Kirschner and Rycerski, 1988). Within this play area, (3) the Brookian Clinoform South-Shallow Play includes stratigraphic traps in the Torok Formation on the relatively shallow carapace above the zone of major structural detachment within the Torok (Fig. 8). This play has the potential to be charged by hydrocarbons expelled from the GRZ, Kingak, and Shublik source rock intervals beneath the foothills belt. The play is relatively shallow and lies at levels of thermal maturity mostly within the oil window. For these reasons, the Brookian Clinoform South-Shallow Play may contain a mixture of oil with characteristics reflecting multiple source rocks and natural gas. (4) The Brookian Clinoform South-Deep Play includes stratigraphic traps in the Torok Formation on the relatively deep plate beneath the zone of major structural detachment within the Torok. Although this play has the potential to be charged by hydrocarbons expelled from the GRZ, Kingak, and Shublik source rock intervals, it lies at levels of thermal maturity entirely in the gas window. Therefore, this play is considered to have potential for undiscovered gas resources only.

The western and eastern boundaries for all Brookian clinoform plays are defined by the boundary of the National Petroleum Reserve – Alaska. The Brookian clinoform plays overlap broadly with that of the Torok structural play (Potter and Moore, this volume), which involves structural traps within the Torok Formation. The assessment of broadly overlapping plays within the same formation emphasizes the potential that hydrocarbons may occur both in structural traps and in stratigraphic traps off structure (i.e., in synclines and broad limbs of structures), and that play attributes are likely to be significantly different in these two play types (e.g., area of closure, reservoir thickness, etc.).

Stratigraphic traps in Brookian clinoform plays have not been a primary objective of exploration drilling in NPRA, and no significant oil or gas tests have been recorded from Torok sandstones in purely stratigraphic traps in NPRA. The recently announced Nanuq discovery (> 40 mmbo recoverable; Phillips press release, 2001), a satellite of the giant Alpine field on the Colville River delta (Fig. 9), appears to be the initial economic discovery in this play, although Nanuq lies outside the assessment area as defined by the eastern boundary of NPRA. An oil-stained turbidite channel system discovered in outcrop south of NPRA (Fig. 9) during field work in support of this assessment appears to represent an exhumed analogue that may have contained more than 100 mmbo recoverable prior to exhumation (Houseknecht and Schenk, 2000, 2001). Significant oil reserves have been discovered in stratigraphic traps in a closely related play just east of NPRA (Fig. 9), where the Tarn accumulation may yield more than 75 mmbo (Alaska Department of Natural Resources, 2000) and the Meltwater accumulation may yield more than 50 mmbo (Phillips press release, 2000), both from turbidites in the Upper Cretaceous Seabee Formation. Tarn and Meltwater are similar to stratigraphic traps in the Torok Formation in that they represent oil accumulations in lowstand turbidite channel and lobe deposits (Morris and others, 2000). They may differ, however, because the shelf margin along which Tarn and Meltwater occur represents global lowstand and subsequent flooding events of major proportions, and because the sandstone reservoir quality in Tarn (and presumably Meltwater) has been enhanced by dissolution of volcanic components (Helmold and others, 2001), which are not present in Torok sandstones.

Hydrocarbon Charge

Turbidite successions in the Torok Formation commonly downlap onto and interfinger with the GRZ interval (Fig. 7), which is considered the primary source for oil and gas charging these plays, particularly in the north and central play areas. In addition to many stratigraphic traps that are in direct contact with the GRZ, clinoforms within the Torok Formation may act as migration pathways from source rocks to stratigraphic traps that may occur higher in the Torok section (Fig. 10). Oils extracted from Torok sandstones from numerous locations in NPRA have geochemical characteristics indicating they were generated exclusively or partly from the GRZ (Lillis and Magoon, this volume). The discovery well for the Nanuq accumulation tested 40° API gravity oil plus gas (Phillips press release, 2001), suggesting the hydrocarbons may have been sourced from the GRZ. Oils produced from the Tarn and Meltwater fields, east of NPRA, similarly are high gravity, low sulfur oils likely generated from the GRZ.

Hydrocarbons expelled from either Kingak or Shublik source rocks are considered secondary candidates to charge the Brookian clinoform plays (Fig. 10). In the north and central plays, the Brookian clinoform plays are separated from Kingak and Shublik source rocks by a number of stratigraphic horizons that may act as migration pathways, including the Sag River Sandstone and sandstones and sequence bounding unconformities in the Kingak Shale (Fig. 10). In that part of NPRA, hydrocarbons expelled from the Kingak and Shublik source rocks are more likely to migrate laterally up dip northward (towards the crest of the Barrow arch) rather than to migrate vertically through the Kingak Shale and into the Torok Formation (Fig. 10). However, the presence in northern NPRA (Fish Creek) of oil with Shublik geochemical affinities provides evidence that oil expelled from source rocks stratigraphically beneath the GRZ did migrated vertically through both the Torok Formation and Nanushuk Group, so Kingak and/or Shublik charge in the northern and central play areas cannot be ruled out. In the southern clinoform play areas, the Kingak Shale is thin and lacking permeable horizons and the Sag River Sandstone is absent. In that southern part of NPRA, therefore, hydrocarbons expelled from the Kingak and Shublik source rocks are more likely to migrate vertically into the Torok Formation (Fig. 10). Oils extracted from outcrops of Torok sandstones in the foothills yield geochemical characteristics suggesting Shublik, GRZ, mixed Shublik-GRZ, or mixed Shublik-GRZ-Kingak affinities (Lillis and Magoon, this volume). This evidence supports the interpretation that the Brookian clinoform plays in southern NPRA are likely to have been charged by hydrocarbons expelled from multiple sources.

Reservoir Properties

Sediment texture (grain size) and the pattern of sediment supply to the shelf margin largely determine the facies architecture of constructional slope and base of slope systems (Galloway, 1998). Point sources of sediment along the shelf margin result in channel-lobe complexes, whereas line sources of sediment along the shelf margin result in apron complexes. A continuum exists between the singular slope channel-lobe complex and the more extensive slope-apron complex. Moreover, the geometry and internal characteristics of turbidite channels may be identical in channel-lobe and slope-apron systems, especially in proximal locations where feeder channels may be incised into slope muds.

The Torok Formation in core and outcrop in NPRA and vicinity contains facies that have been interpreted as parts of slope-channel, fan lobe, and slope-apron systems (Houseknecht and Schenk, 2001). Torok turbidites in relatively proximal parts of the depositional system characterized by high rates of accommodation (southern and western NPRA) may be characterized by multiple, closely spaced feeder channels at lowstand shelf margins and therefore more nearly resemble the slope-apron complex. In contrast, Torok turbidites in relatively distal parts of the depositional system characterized by lower rates of accommodation (northern and eastern NPRA) may be characterized by fewer, more widely spaced feeder channels at lowstand shelf margins and therefore more nearly resemble the slope channel-lobe complex.

Although the Torok Formation is known to contain a huge volume of sandstone, much of which may occur in lowstand systems tracts, only a small proportion of that sandstone is likely to have reservoir-quality properties. Observations from subsurface and outcrop examples indicate that the best reservoir quality is preserved in relatively coarse grained (typically medium-grained and coarser), amalgamated sandstones deposited in turbidite channels incised into mudstones of the middle to lower slope or into sandy, proximal lobe deposits at the base of slope. These channelized deposits are inferred to pinch out up dip via onlap onto muddy slope deposits, and to grade down dip into finer grained, more widespread sandstones of submarine fan lobe deposits, which constitute the volumetrically largest proportion of sandstone in the Torok Formation.

Relatively little porosity and permeability data are available in the public domain for Torok Formation sandstones in NPRA. Data from cores in the East Simpson 2 and Oumalik 1 wells fall in the range of 10 to 16 percent porosity and permeability is generally less than 10 millidarcies (Nelson and Kibler, 2002). Hand-specimen examination of all Torok Formation core samples available in the USGS archive suggests that porosity and permeability generally decrease from north to south in NPRA, a trend that reflects increasing thermal maturity and maximum depth of burial to the south. However, well penetrations and cores of Torok sandstones in NPRA have not targeted channelized turbidite deposits that are most likely to have retained better reservoir properties. Meager evidence from field observations suggests that better porosity and permeability may be preserved in channelized turbidite deposits. In outcrop, Torok Formation sandstones deposited by unconfined (non-channelized) turbidity currents on submarine fan lobes and aprons are typically very fine to fine-grained and display low porosity (<10%) and permeability (<5 md). In contrast, Torok sandstones deposited by channelized turbidity currents within channels incised into slope muds or proximal submarine fan facies locally display higher porosity (10-20%) and permeability (up to 100 md). Moreover, oil stained outcrop samples display higher porosity and permeability than non-stained samples, suggesting that early accumulation of hydrocarbons resulted in the preservation of better reservoir properties.

Trap Types

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). Shelf margins associated with LSTs, mapped across NPRA using a grid of public domain, 2-D seismic data, form the basis for assessing the petroleum potential of the Brookian clinoform plays because it is likely that stratigraphic traps are concentrated along those lowstand shelf-margin trends. The resolution of available seismic data, however, is insufficient to identify specific turbidite channel systems. Exploration for these traps would require the use of 3-D seismic data. Hydrocarbon accumulations in these plays may be in the 50 to 100 million barrel (recoverable) range. These clinoform plays are likely to be a focus of exploration in NPRA, especially as potential satellites to larger accumulations that may occur in the Jurassic part of the section (see chapter on Beaufortian Stratigraphic Plays; Houseknecht, this volume).

Timing

The timing of trap development relative to oil generation is excellent in the Brookian clinoform plays. Deposition of Lower Cretaceous clinoform strata across NPRA occurred between ~117 Ma and ~94 Ma. Peak oil generation in the GRZ is estimated to have occurred between ~100 Ma in western NPRA and ~90 Ma in eastern NPRA (Burns and others, 2002), and generation occurred over a similar interval of time in the Kingak and Shublik source rock intervals. Thus, all stratigraphic traps in the Brookian clinoform plays were formed before significant volumes of oil were generated from source rocks likely to charge these plays. Inasmuch as gas generation and expulsion from source rocks is inferred to have followed oil generation and expulsion, timing of stratigraphic trap development also is excellent for a gas charge.

Play Attributes – Brookian Clinoform North Play

Tables 5 through 7 summarize the play attributes used as assessment input for this play. All input values are conditional for accumulations of the minimum size considered in this assessment (50 million barrels of in-place oil or 250 billion cubic feet of technically recoverable gas). A brief explanation of key attributes follows each table.

Reservoir thickness. Limited analogue data are available from the new discovery at Nanuq and from the Tarn and Meltwater fields (although they are both in the younger, Upper Cretaceous part of the section and may not be appropriate constraints for this play). Additional constraints are provided from outcrop studies of Torok turbidite systems (Houseknecht and Schenk, 2000, 2001). The median value is based on the assumption of a single channelized turbidite channel deposit of moderate size. The lower probability values are based on larger turbidite channel deposits or the assumption of stacked turbidite deposits in a single location.

Area of closure. Little analogue data exist for stratigraphic traps in Brookian clinoform strata. The Tarn accumulation covers about 15,000 acres (Kumar and others, 2002). The median value is estimated as a single channelized turbidite deposit and the lower probability values are inferred to represent an aggregate of submarine fan lobe and channelized turbidite deposits.

Trap fill. The high values are based on the close and interfingering association of stratigraphic traps and GRZ source rocks, and the relatively small size of stratigraphic traps.

Trap depth. The depth range of potential traps in the play was derived from seismic and wireline log data.

Number of prospects. The values reflect knowledge of the depositional system, maps of lowstand shelf margins constructed from seismic interpretations, and the inference that an incised turbidite channel – submarine fan systems may be spaced approximately 10 miles apart along lowstand shelf-margins.

Prospect probability attributes. Each value represents the probability that the attribute is favorable to form a hydrocarbon accumulation of the minimum size considered in this assessment (50 million barrels of in-place oil or 250 billion cubic feet of technically recoverable gas) in a randomly selected prospect within the play. The charge probability is estimated to be 0.9, a favorable value that is based on the close association of the play with GRZ source rocks. The trap probability is estimated to be 0.3. The primary geologic parameters that contribute to this low value include the potential for porosity and trap sizes that may be insufficient because of small and/or heterogeneous sand bodies. The timing probability is 1 because all the traps in this play formed in advance of any hydrocarbon generation and migration in the region. The resultant prospect probability (charge probability X trap probability X timing probability) indicates a 27 percent chance that a randomly chosen prospect within the play will have a favorable combination of charge, trap, and timing.

The combination of play and prospect probabilities indicates a 27 percent chance that prospects in the play will contain at least 50 million barrels of in-place oil or 250 billion cubic feet of technically recoverable gas. Ninety (90) percent of the undiscovered hydrocarbon accumulations within the play are estimated to be oil and ten (10) percent are estimated to be gas. This estimate is based on the observations that the play is entirely within the oil window and there are viable scenarios for an oil charge (see previous discussion). However, the presence of gas-prone kerogen in the Torok Formation and the possibility of a thermogenic gas charge from the deep Colville basin provide the possibility that a non-associated gas charge may be present in some traps.

Hydrocarbon parameters. Recovery factors are based on analogues from closely related plays (e.g., Tarn) and from analogues from other basins with similar reservoir properties (Verma, this volume). Oil gravity and sulfur content are based on the assumption that the most likely scenario for an oil charge involves hydrocarbons expelled from the GRZ (Lillis and Magoon, this volume).

Results – Brookian Clinoform North Play

The assessment input values summarized in Tables 5, 6, and 7 were used to estimate petroleum resource potential using methods described by Schuenemeyer (this volume). Basic results are summarized in Table 8 for technically recoverable crude oil and non-associated gas. Additional results are provided by Schuenemeyer (this volume).

The volume of undiscovered, technically recoverable oil in the Brookian Clinoform North Play in NPRA is estimated to range between 538 (95-percent probability) and 2,257 (5-percent probability) million barrels, with a mean (expected value) of 1,306 million barrels (Table 8). The volume of undiscovered, technically recoverable, non-associated gas in the Brookian Clinoform North Play in NPRA is estimated to range between 0 (95-percent probability) and 1,969 (5-percent probability) billion cubic feet, with a mean (expected value) of 674 billion cubic feet (Table 8).

The oil and gas resources are estimated to occur in accumulations of various sizes, as illustrated in Figure 11. One oil accumulation between 256 and 512 mmbo may occur within the Brookian Clinoform North Play, but smaller accumulations are more likely. Three accumulations between 128 and 256 mmbo, five accumulations between 64 and 128 mmbo, and three accumulations between 32 and 64 mmbo are estimated to occur within the play (Fig. 11a). Most of the volume of oil within this play is expected to occur in accumulations that fall in the 128 to 256 mmbo and in the 64 to 128 mmbo size classes, as shown in Fig. 11b.

One non-associated, natural gas accumulation in the 384 to 768 bcf size class and one accumulation in the 192 to 384 bcf size class are estimated to occur in the Brookian Clinoform North Play, as shown in Fig. 11c. Most of the gas in this play is expected to occur in an accumulation that falls in the 384 to 768 bcf size class, as shown in Fig. 11d.

In addition to volumes of crude oil and non-associated gas, associated natural gas and natural gas liquids are estimated to occur in the Brookian Clinoform North Play. Those estimates are reported by Schuenemeyer (this volume).

Play Attributes – Brookian Clinoform Central Play

Tables 9 through 11 summarize the play attributes used as assessment input for this play. All input values are conditional for accumulations of the minimum size considered in this assessment (50 million barrels of in-place oil or 250 billion cubic feet of technically recoverable gas). A brief explanation of key attributes follows each table.

Reservoir thickness. Interpretation of depositional systems suggests that sand bodies may be thicker in the Brookian Clinoform Central Play than in the Brookian Clinoform North Play (see previous discussion regarding accommodation space). For this reason, all values of thickness are higher than in the North Play.

Area of closure. Interpretation of depositional systems suggests that sand bodies may be larger in the Brookian Clinoform Central Play than in the Brookian Clinoform North Play (see previous discussion regarding accommodation space). For this reason, all values of closure area are higher than in the North Play.

Porosity and hydrocarbon pore volume. Porosity is estimated to be systematically lower in the Brookian Clinoform Central Play than in the Brookian Clinoform North Play because maximum burial depth was greater in the Central Play. The value for water saturation is the same as the Northern Play.

Trap fill. The high values are based on the close and interfingering association of stratigraphic traps and GRZ source rocks, and the relatively small size of stratigraphic traps.

Trap depth. The depth range of potential traps in the Brookian Clinoform Central Play was derived from seismic and wireline log data. The potential for oil and gas is inferred to be depth related, with oil limited to shallower depths and gas to deeper depths. The depth ranges for oil and gas are inferred to overlap.

Number of prospects. Values are systematically higher than in the northern play area because of (1) closer spacing of turbidite systems along lowstand shelf margins (see previous discussion) and (2) a greater number of lowstand shelf margins is present in Central Play.

The combination of play and prospect probabilities indicates a 27 percent chance that prospects in the play will contain at least 50 million barrels of in-place oil or 250 billion cubic feet of technically recoverable gas. Fifty (50) percent of the undiscovered hydrocarbon accumulations within the play are estimated to be oil and fifty (50) percent are estimated to be gas. These estimates are based on the inference that the GRZ source rock interval contains a greater proportion of gas-prone kerogen in the Brookian Clinoform Central Play than in the Brookian Clinoform North Play (see previous discussion).

Results – Brookian Clinoform Central Play

The assessment input values summarized in Tables 9, 10, and 11 were used to estimate petroleum resource potential using methods described by Schuenemeyer (this volume). Basic results are summarized in Table 12 for technically recoverable crude oil and non-associated gas. Additional results are provided by Schuenemeyer (this volume).

The volume of undiscovered, technically recoverable oil in the Brookian Clinoform Central Play in NPRA is estimated to range between 299 (95-percent probability) and 1,849 (5-percent probability) million barrels, with a mean (expected value) of 973 million barrels (Table 12). The volume of undiscovered, technically recoverable, non-associated gas in the Brookian Clinoform Central Play in NPRA is estimated to range between 1,806 (95-percent probability) and 10,076 (5-percent probability) billion cubic feet, with a mean (expected value) of 5,405 billion cubic feet (Table 12).

The oil and gas resources are estimated to occur in accumulations of various sizes, as illustrated in Figure 12. One oil accumulation between 256 and 512 mmbo may occur within the Brookian Clinoform Central Play. Two accumulations between 128 and 256 mmbo, three accumulations between 64 and 128 mmbo, and two accumulations between 32 and 64 mmbo are estimated to occur within the play (Fig. 12a). Most of the volume of oil within this play is expected to occur in accumulations that fall in the 128 to 256 mmbo, the 64 to 128 mmbo, and the 32 to 64 mmbo size classes, as shown in Fig. 12b.

Two natural gas accumulations in the 768 to 1,536 bcf size class, three accumulations in the 384 to 768 bcf size class, and two accumulations in the 192 to 384 bcf size class are estimated to occur in the Brookian Clinoform Central Play, as shown in Fig. 12c. Most of the gas in this play is expected to occur in accumulations that fall in the 768 to 1,536 bcf and 384 to 768 bcf size classes, as shown in Fig. 12d.

In addition to volumes of crude oil and non-associated gas, associated natural gas and natural gas liquids are estimated to occur in the Brookian Clinoform Central Play. Those estimates are reported by Schuenemeyer (this volume).

Play Attributes – Brookian Clinoform South-Shallow Play

Tables 13 through 15 summarize the play attributes used as assessment input for this play. All input values are conditional for accumulations of the minimum size considered in this assessment (50 million barrels of in-place oil or 250 billion cubic feet of technically recoverable gas). A brief explanation of key attributes follows each table.

Reservoir thickness. Interpretation of depositional systems suggests that sand bodies may be thicker in the Brookian Clinoform South-Shallow Play than in the Central Play (see previous discussion regarding accommodation space). For this reason, all values of thickness are higher than in the Central Play.

Area of closure. Interpretation of depositional systems suggests that sand bodies may be larger in the South-Shallow Play than in the Central Play (see previous discussion regarding accommodation space). For this reason, all values of closure area are higher than in the Central Play.

Porosity and hydrocarbon pore volume. Porosity is estimated to be slightly lower in the Brookian Clinoform South-Shallow Play than in the Central Play because maximum burial depth was greater. Therefore, the median value is lower than in the Central Play and all other values are the same. The value for water saturation is the same as the Central Play.

Trap fill. The high values are based on the potential for charging the Brookian Clinoform South-Shallow Play with hydrocarbons expelled from at least three source rocks (GRZ, Kingak, and Shublik) and the relatively small size of stratigraphic traps.

Trap depth. The depth range of potential traps in the Brookian Clinoform South-Shallow Play was derived from seismic and wireline log data. The potential for oil and gas is inferred to be depth related, with oil limited to shallower depths and gas to deeper depths. The depth ranges for oil and gas are inferred to overlap.

Number of prospects. Values are systematically lower in the Brookian Clinoform South-Shallow Play than in the Central Play because the potential for stratigraphic traps in part of the southern play area is disrupted by structural deformation. The potential represented by the prospects in this play is restricted to purely stratigraphic traps that occur away from structural closures.

Play probability attributes. Each value represents the probability that the attribute is sufficient for the existence within the play of at least one hydrocarbon accumulation of the minimum size considered in this assessment (50 million barrels of in-place oil or 250 billion cubic feet of technically recoverable gas). Charge, trap, and timing probabilities are all estimated to be 1 (100%). The resultant play probability of 100 percent indicates an interpretation that at least one hydrocarbon accumulation of the minimum size is certain to occur in this play. Although no fields have been discovered in this play, an exhumed oil accumulation discovered in outcrop (Houseknecht and Schenk, 2000, 2001) is inferred to support these favorable play probabilities.

Prospect probability attributes. Each value represents the probability that the attribute is favorable to form a hydrocarbon accumulation of the minimum size considered in this assessment (50 million barrels of in-place oil or 250 billion cubic feet of technically recoverable gas) in a randomly selected prospect within the play. The charge probability is estimated to be 0.7, trap probability is estimated to be 0.2, and timing probability is 1. Charge probability is lower in the Brookian Clinoform South-Shallow Play than in the Central Play because the volumetric ratio of total sediment to source rock increases substantially in the southern (foredeep) part of NPRA, and because the quality of the GRZ source rocks is inferred to deteriorate southward. Trap probability is lower here than in the Brookian Clinoform Central Play because reservoir quality is expected to be lower as the result of deeper maximum burial depths. The resultant prospect probability (charge probability X trap probability X timing probability) indicates a 14 percent chance that a randomly chosen prospect within the play will have a favorable combination of charge, trap, and timing.

The combination of play and prospect probabilities indicates a 14 percent chance that prospects in the play will contain at least 50 million barrels of in-place oil or 250 billion cubic feet of technically recoverable gas. Fifty (50) percent of the undiscovered hydrocarbon accumulations within the play are estimated to be oil and fifty (50) percent are estimated to be gas. These estimates are based on the inference that the GRZ source rock interval contains a greater proportion of gas-prone kerogen in the Brookian Clinoform South-Shallow Play than in the Central Play (see previous discussion), and on the likelihood that thermogenic gas from the underlying, Colville foredeep may charge the play.

Hydrocarbon parameters. The oil recovery factor is lower in the Brookian Clinoform South-Shallow Play than in the Brookian Clinoform Central Play because it is inferred that reservoir quality may be lower and that a lower gravity oil (reflecting mixed oil provenance) may be present. Oil gravity and sulfur content reflect the inference that a mixture of oil from the GRZ, Kingak, and Shublik may be present (Lillis and Magoon, this volume)

Results – Brookian Clinoform South-Shallow Play

The assessment input values summarized in Tables 13, 14, and 15 were used to estimate petroleum resource potential using methods described by Schuenemeyer (this volume). Basic results are summarized in Table 16 for technically recoverable crude oil and non-associated gas. Additional results are provided by Schuenemeyer (this volume).

The volume of undiscovered, technically recoverable oil in the Brookian Clinoform South-Shallow Play in NPRA is estimated to range between 0 (95-percent probability) and 1,254 (5-percent probability) million barrels, with a mean (expected value) of 508 million barrels (Table 16). The volume of undiscovered, technically recoverable, non-associated gas in the Brookian Clinoform South-Shallow Play in NPRA is estimated to range between 0 (95-percent probability) and 5,809 (5-percent probability) billion cubic feet, with a mean (expected value) of 2,405 billion cubic feet (Table 16).

The oil and gas resources are estimated to occur in accumulations of various sizes, as illustrated in Figure 13. One accumulation in the 128 to 256 mmbo size class and one accumulation in the 64 to 128 mmbo size class are estimated to occur within the Brookian Clinoform South-Shallow Play (Fig. 13a). The likelihood that larger accumulations may occur is small. Most of the volume of oil within this play is expected to occur in accumulations that fall in the 128 to 256 mmbo, as shown in Fig. 13b.

One natural gas accumulation in the 768 to 1,536 bcf size class, one accumulation in the 384 to 768 bcf size class, and perhaps one accumulation in the 192 to 384 bcf size class are estimated to occur in the Brookian Clinoform South-Shallow Play, as shown in Fig. 13c. Most of the gas in this play is expected to occur in accumulations that fall in the 768 to 1,536 bcf and 384 to 768 bcf size classes, as shown in Fig. 13d.

In addition to volumes of crude oil and non-associated gas, associated natural gas and natural gas liquids are estimated to occur in the Brookian Clinoform South-Shallow Play. Those estimates are reported by Schuenemeyer (this volume).

Play Attributes – Brookian Clinoform South-Deep Play

Tables 17 through 19 summarize the play attributes used as assessment input for this play. All input values are conditional for accumulations of the minimum size considered in this assessment (50 million barrels of in-place oil or 250 billion cubic feet of technically recoverable gas). A brief explanation of key attributes follows each table.

Reservoir thickness. Values for the Brookian Clinoform South-Deep Play are identical to those used for the Brookian Clinoform South-Shallow Play based on the same interpretations.

Area of closure. Values for the Brookian Clinoform South-Deep Play are identical to those used for the Brookian Clinoform South-Shallow Play based on the same interpretations.

Porosity and hydrocarbon pore volume. Porosity is estimated to be systematically lower in the Brookian Clinoform South-Deep Play than in the South-Shallow Play because maximum burial depth was greater.

Trap fill. The high values are based on the potential for charging the Brookian Clinoform South-Deep Play with hydrocarbons expelled from at least three source rocks (GRZ, Kingak, and Shublik) and the relatively small size of stratigraphic traps.

Trap depth. The depth range of potential traps in the play was derived from seismic and wireline log data.

Number of prospects. Values are systematically lower in the Brookian Clinoform South-Deep Play than in the South-Shallow Play because of the potential for stratigraphic traps to have been destroyed by structural deformation within and beneath the lower Torok structural wedge.

Play probability attributes. Each value represents the probability that the attribute is sufficient for the existence within the play of at least one hydrocarbon accumulation of the minimum size considered in this assessment (50 million barrels of in-place oil or 250 billion cubic feet of technically recoverable gas). Charge and timing probabilities are estimated to be 1 (100%) based on the same rationale used in the other Brookian clinoform plays. Trap probability for the Brookian Clinoform South-Deep Play is estimated to be 0.8, reflecting the greater risk in survival of viable reservoir quality and seal integrity with deep burial and exposure to deformation. The resultant play probability suggests an 80 percent chance that at least one hydrocarbon accumulation of the minimum size exists in this play.

The combination of play and prospect probabilities indicates an 11 percent chance that prospects in the play will contain at least 50 million barrels of in-place oil or 250 billion cubic feet of technically recoverable gas. All accumulations in this play are expected to be gas because of high levels of thermal maturity.

Hydrocarbon parameters. The gas recovery factor is based on analogue fields elsewhere in the U.S. (Verma, this volume).

Results – Brookian Clinoform South-Deep Play

The assessment input values summarized in Tables 17, 18, and 19 were used to estimate petroleum resource potential using methods described by Schuenemeyer (this volume). Basic results are summarized in Table 16 for technically recoverable crude oil and non-associated gas. Additional results are provided by Schuenemeyer (this volume).

The volume of undiscovered, technically recoverable, non-associated gas in the Brookian Clinoform South-Deep Play in NPRA is estimated to range between 0 (95-percent probability) and 8,796 (5-percent probability) billion cubic feet, with a mean (expected value) of 3,788 billion cubic feet (Table 20). No technically recoverable oil is assessed in this play.

The gas resources are estimated to occur in accumulations of various sizes, as illustrated in Figure 14. One natural gas accumulation in the 768 to 1,536 bcf size class, three accumulations in the 384 to 768 bcf size class, and two accumulations in the 192 to 384 bcf size class are estimated to occur within the Brookian Clinoform South-Deep Play, as shown in Fig. 14a. Most of the gas in this play is expected to occur in accumulations that fall in the 768 to 1,536 bcf and 384 to 768 bcf size classes, as shown in Fig. 13b.

In addition to volumes of non-associated gas, natural gas liquids are estimated to occur in the Brookian Clinoform South-Deep Play. Those estimates are reported by Schuenemeyer (this volume).

Summary and Conclusions

The Brookian megasequence in the National Petroleum Reserve – 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. The Torok thickens markedly southward into the foredeep of the Colville basin, where much of the formation forms a “foredeep clinoform wedge” whose geometry indicates eastward migration of a sand-rich slope apron system deposited during low-stands punctuated by drapes of condensed, pelagic mud-stones deposited during transgressions. Smaller scale, mud-rich clinoforms that dip north to northeast and that extend northward across the entire NPRA are superimposed on the east-dipping clinoforms of the foredeep wedge. These mud-rich clinoforms represent aggradation and progradation of the marine slope during highstands. The Nanushuk thickens westward across NPRA and includes marine-shelf, wave-influenced shorezone, deltaic, and non-marine facies.

Brookian strata within NPRA are part of a composite total petroleum system involving hydrocarbons expelled from three stratigraphic intervals of source rocks. The primary charge potential involves hydrocarbons expelled from a Lower Cretaceous interval of source rocks collectively called the “GRZ”, which includes the pebble shale unit, gamma-ray zone (GRZ), and shales in the lower parts of the Torok Formation. Hydrocarbons expelled from the GRZ are inferred to be predominately high-gravity oil in northern NPRA and a mixture of high-gravity oil and gas in southern NPRA. Additional charge potential involves hydrocarbons expelled from source rocks in the lower part of the Jurassic Kingak Shale, and these hydrocarbons are inferred to be predominately high-gravity oil except where thermal maturity exceeds the oil window. Additional charge potential also involves hydrocarbons expelled from source rocks in the Triassic Shublik Formation, and these hydrocarbons are inferred to be predominately lower-gravity oil except where thermal maturity exceeds the oil window.

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 involves stratigraphic traps in the Nanushuk Group and uppermost Torok Formation. 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, and between 0 (95-percent probability) and 679 (5-percent probability) billion cubic feet of technically recoverable natural gas, with a mean (expected value) of 192 billion cubic feet. Hydrocarbon accumulations in this play are inferred to be modest in size and not likely to be a primary focus of exploration activity.

Four Brookian clinoform plays were defined within the Torok Formation in NPRA based on inferred hydrocarbon charge and thermal maturity. The most favorable stratigraphic trapping geometries in all four of these clinoform plays occur where amalgamated sandstones deposited in turbidite channels incised on the mid- to lower-slope and on the proximal parts of submarine fans during lowstands of relative sea level are capped by relatively condensed mudstone facies deposited during rising relative sea level. 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, and between 0 (95-percent probability) and 1,969 (5-percent probability) billion cubic feet of technically recoverable natural gas, with a mean (expected value) of 674 billion cubic feet. This play is estimated to contain multiple oil accumulations larger than 128 mmbo technically recoverable, and these may be a focus of exploration activity in the near-term future, particularly near existing infrastructure in the eastern part of the play.

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, and between 1,806 (95-percent probability) and 10,076 (5-percent probability) billion cubic feet of technically recoverable natural gas, with a mean (expected value) of 5,405 billion cubic feet. This play is estimated to contain multiple oil accumulations larger than 128 mmbo technically recoverable, and these may be a focus of exploration activity in the near-term future, particularly near existing infrastructure in the eastern part of the play.

Two Brookian clinoform plays extend across southern NPRA. The Brookian Clinoform South-Shallow Play involves stratigraphic traps at relatively shallow depths above a zone of major structural detachment within the Torok Formation. 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, and between 0 (95-percent probability) and 5,809 (5-percent probability) billion cubic feet of technically recoverable natural gas, with a mean (expected value) of 2,405 billion cubic feet. This play is estimated to contain a small number of accumulations larger than 64 million barrels of technically recoverable oil and most of the play area is distant from existing infrastructure, a combination that suggests it is not likely to be a primary focus of exploration activity in the near-term future.

The Brookian Clinoform South-Deep Play involves relatively deep stratigraphic traps beneath a zone of major structural detachment within the Torok Formation, and lies entirely within the gas window. The Brookian Clinoform South-Shallow Play is estimated to contain no technically recoverable oil and between 0 (95-percent probability) and 8,796 (5-percent probability) billion cubic feet of technically recoverable natural gas, with a mean (expected value) of 3,788 billion cubic feet. The modest size and great depth of gas accumulations estimated to occur in this play suggest it is not likely to be a primary focus of exploration activity in the near-term future, especially in the absence of a gas pipeline.

Acknowledgments

Peer reviews by Chris Schenk and Matt Burns, as well as additional suggestions by Ken Bird, improved the technical content and clarity of this report. Other members of the USGS NPRA assessment team have provided valuable feedback, advice, and technical support as this research was conducted. Ken Bird, Chris Potter, Tom Moore, Phil Nelson, and Paul Lillis have been particularly helpful. This work also has benefited greatly from the technical support of Chris Garrity, Joe East, Rob Crangle, and Max Borella of the USGS.

Colleagues at the Alaska Department of Natural Resources also have provided valuable insights and feedback during the course of this work. Gil Mull of the Division of Oil and Gas and Dave LePain of the Division of Geological and Geophysical Surveys have played especially important roles in this regard.

Various aspects of the geologic framework on which this report is based have been presented at several technical conferences sponsored by the American Association of Petroleum Geologists, the Geological Society of America, and the Alaska Geological Society; at core workshops sponsored by the U.S. Geological Survey, the Rocky Mountain Region Petroleum Technology Transfer Council, and the Society for Sedimentary Geology (SEPM); at university seminars; and at in-house seminars hosted by the U.S. Bureau of Land Management and U.S. Minerals Management Service, the Alaska Department of Natural Resources Division of Oil and Gas, and several oil companies. Technical discussions with dozens of geologists participating in those venues have improved the logic and interpretations presented in this report. All those interactions focused on the framework geology of the Brookian megasequence, and none included presentation or discussion of assessment input or results.

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Brookian Stratigraphic Plays in the National Petroleum Reserve – Alaska (NPRA)

CONTENTS

Abstract

Introduction

Geology of Brookian Strata in NPRA

Stratigraphy and Depositional Facies

Structure and Thermal Maturity

Petroleum Source Rocks Pertinent to Brookian Stratigraphic Plays

GRZ and Associated Source Rocks

Kingak Shale

Shublik Formation

Brookian Stratigraphic Plays

Brookian Topset Play

Brookian Clinoform Plays

Summary and Conclusions

Acknowledgments

References