U.S. Geological Survey Open-File Report 03-040
Version 1.0
David W. Houseknecht
U.S. Geological Survey
Reston, Virginia 20192
dhouse@usgs.gov
Abstract
Introduction
Geology of Beaufortian Strata in NPRA
Stratigraphy
Sequence Stratigraphy and Depositional Facies
Petroleum Source Rocks Pertinent to Beaufortian Stratigraphic
Plays
GRZ and associated source rocks
Kingak Shale
Shublik Formation
Beaufortian Stratigraphic Plays
Beaufortian Cretaceous Topset Plays
Hydrocarbon Charge
Reservoir Properties
Trap Types
Timing
Play Attributes – Beaufortian Cretaceous Topset North Play
Results – Beaufortian Cretaceous Topset North Play
Play Attributes – Beaufortian Cretaceous Topset South Play
Results – Beaufortian Cretaceous Topset South Play
Beaufortian Upper Jurassic Topset Plays
Hydrocarbon Charge
Reservoir Properties
Trap Types
Timing
Play Attributes – Beaufortian Upper Jurassic Topset Northeast
Play
Results – Beaufortian Upper Jurassic Topset Northeast Play
Play Attributes – Beaufortian Upper Jurassic Topset Southeast
Play
Results – Beaufortian Upper Jurassic Topset Southeast Play
Play Attributes – Beaufortian Upper Jurassic Topset Northwest
Play
Results – Beaufortian Upper Jurassic Topset Northwest Play
Play Attributes – Beaufortian Upper Jurassic Topset Southwest
Play
Results – Beaufortian Upper Jurassic Topset Southwest Play
Beaufortian Lower Jurassic Topset Play
Hydrocarbon Charge
Reservoir Properties
Trap Types
Timing
Play Attributes – Beaufortian Lower Jurassic Topset Play
Results – Beaufortian Lower Jurassic Topset Play
Beaufortian Clinoform Play
Hydrocarbon Charge
Reservoir Properties
Trap Types
Timing
Play Attributes – Beaufortian Clinoform Play
Results – Beaufortian Clinoform Play
Summary and Conclusions
Acknowledgments
References
Tables 1-32 (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
| 21-22 | 23-24
| 25-26 | 27-28
| 29-30 | 31-32)
Figure Captions (separate files,
or all figures with captions in a 2.4-MB PDF file)
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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) and 71 (5-percent probability) million barrels of technically recoverable oil, with a mean (expected value) of 12 million barrels. The Beaufortian Clinoform Play is estimated to contain between 0 (95-percent probability) and 2,180 (5-percent probability) billion cubic feet of technically recoverable, nonassociated natural gas, with a mean (expected value) of 822 billion cubic feet.
The Beaufortian Upper Jurassic Topset Northeast Play will be the main focus of exploration in NPRA because it is estimated to contain numerous oil accumulations large enough to be developed as stand-alone or satellite fields, and because it is near existing infrastructure. The total volume of oil assessed in the Beaufortian Upper Jurassic Topset Northeast Play (mean estimate 5.2 billion barrels) suggests it has the potential to contribute significantly to Alaska North Slope oil production.
The Beaufortian Upper Jurassic Topset Northwest Play may become a focus of exploration in NPRA if infrastructure is extended closer to the play area, as it is estimated to contain several oil accumulations that may be large enough to be developed depending on infrastructure proximity. All other Beaufortian plays are estimated to contain accumulations of modest size that may be developed as satellites if larger accumulations in the Beaufortian Upper Jurassic Topset Northeast Play or the Beaufortian Upper Jurassic Topset Northwest Play are developed as fields.
The primary focus of recent exploration on the Colville River delta and in the National Petroleum Reserve in Alaska (NPRA) is stratigraphic traps within Jurassic through Early Cretaceous (Neocomian) strata (Fig. 1). Renewed exploration in this area was stimulated by the 1994 discovery (announced in 1996) of the Alpine field, located on the Colville River delta immediately adjacent to the northeastern boundary of NPRA (Fig. 2). Brought on line in November 2000, the Alpine field contains more than 400 million barrels of recoverable, high gravity oil reservoired in Beaufortian strata (Hannon and others, 2000; Morris and others, 2000; Gingrich and others, 2001). Additional, smaller discoveries in Beaufortian strata on the Colville River delta also document the oil potential of this stratigraphic interval (e.g., Fiord pool and oil tests in the Colville Delta No.1 and Kalubik No. 1 wells; Kornbraith and others, 1997).
The objectives of this chapter are to provide an overview of Beaufortian strata within the National Petroleum Reserve in 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 eight assessment units (plays) in Beaufortian strata. The potential for undiscovered oil and gas resources in subtle structural traps in these same strata also is evaluated in this chapter.
The Beaufortian “megasequence” of northern Alaska (Fig. 1) includes a Jurassic through Early Cretaceous (Neocomian) stratigraphic interval genetically linked to tectonic events that led to the opening of the Arctic Ocean (e.g., Hubbard and others, 1987). Previous regional studies have documented that Beaufortian strata are distinguished by a northern provenance and seismically defined clinoforms that indicate south to southeast offlap (e.g., Bird, 1985, 1987, 2001a,b; Bird and Molenaar, 1992). Most workers agree that these strata record depositional and erosional effects of pre-rift (quiescent) and rift events associated with opening of the Arctic Ocean basin (Hubbard and others, 1987). The Beaufortian sequence in NPRA includes the Kingak Shale (formation) and overlying pebble shale unit (informal stratigraphic term; Fig. 1). The Kingak Shale is a wedge of strata that thickens southward from a zero truncation edge on the Barrow arch in northernmost NPRA and just offshore to as much as 4,000 ft. in central NPRA, and then thins southward to less than 2,500 ft. in southern NPRA (Fig. 2). The top of the Kingak Shale in northern NPRA is defined by the regionally extensive Lower Cretaceous Unconformity (LCU), considered to represent maximum uplift on the Barrow arch (rift shoulder). Northward beveling of the Kingak beneath the LCU is evidenced by the generally increasing age of the uppermost strata within the formation (Fig. 2). In southern NPRA, the top of the Kingak appears to be a correlative conformity and the formation thins in a clinoform geometry suggesting an “ultimate” (farthest basinward) shelf margin. The distal stratigraphic equivalent of the Kingak Shale is the Blankenship Member of the Otuk Formation (Mull and others, 1982), an organic-rich condensed shale that crops out locally in thrust slivers within the foothills of southernmost NPRA and along a trend to the east and west of NPRA.
Resting on the LCU throughout NPRA, the pebble shale unit is a thin (generally less than 300 ft.), organic-rich shale that commonly contains randomly scattered chert pebbles and frosted quartz grains. Locally, the pebble shale unit contains lenticular sandstones, including the Kemik sandstone that, where present, rests directly on the LCU. Stratigraphically equivalent sandstones outside NPRA are oil reservoirs, including the main reservoir in the Kuparuk River field (Fig. 2; Masterson and Eggert, 1992; Carman and Hardwick, 1993).
Based on seismic, wireline log, and core interpretations, the Kingak Shale in NPRA has been divided into four composite depositional sequences (sequence sets) that define a generally southward offlapping succession of Beaufortian strata (Fig. 3; Houseknecht, 2001, 2002). Sequence set K1 (Lower-Middle Jurassic) accumulated in a depocenter in northcentral NPRA. Constituent depositional sequences of K1 include lowstand (LST), transgressive (TST), and highstand (HST) systems tracts that comprise mostly offshore marine through lower shoreface deposits (Fig. 4b). Significantly, progradation and aggradation of K1 depositional sequences resulted in the construction in northcentral NPRA of a lobate shelf (Fig. 4a), which influenced the geometry of younger Beaufortian strata. Sequence set K2 (Oxfordian-Kimmeridgian) is a composite of higher-order depositional sequences each of which reflects a forced regression, which caused widespread erosion across northcentral NPRA (i.e., upon the shelf comprising K1 strata) and accumulation of sediment at the shelf margin in lowstand systems tracts (Fig. 5). Subsequent flooding of the shelf resulted in deposition of transgressive systems tracts that commonly include well-winnowed, upper shoreface sandstones capped by a condensed section of fissile shale, forming good stratigraphic trapping potential (Fig. 5b; Alpine-type traps). Sequence set K3 (Valanginian) displays relatively distal facies character, suggesting high relative sea level during most of the depositional history. An important exception is the presence of a transgressive systems tract at the base of K3 that contains winnowed, shoreface sandstones (Fig. 6). Sequence K4 (Hauterivian) is a shelf-margin wedge that developed as the result of tectonic uplift along the Barrow Arch. It comprises lowstand and transgressive systems tracts that display stratal geometries suggesting dynamic incision and synsedimentary collapse of the shelf margin (Fig. 7).
Hydrocarbons expelled from three petroleum source rocks present in the NPRA region (Lillis and Magoon, this volume) have the greatest potential to charge Beaufortian 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 Beaufortian 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 Beaufortian strata within NPRA are part of a composite total petroleum system (Magoon and Schmoker, 2000).
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, also known as HRZ or highly radioactive zone) 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.
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, 2002). 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).
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 yielded 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%).
As illustrated schematically in Figure 8, assessment of stratigraphic plays in Beaufortian strata was conducted within the framework of (1) a set of two Cretaceous topset plays, (2) a set of four Upper Jurassic topset plays, (3) a single Lower Jurassic topset play, and (4) a single clinoform play. The play definitions are based on significant contrasts in potential reservoir properties and trap types, as well as differences in charge potential among the constituent strata. The following sections provide an overview of the main attributes of each play, as well as an explanation of assessment input values.
This set of two plays involves stratigraphic traps within topset seismic facies in the Lower Cretaceous (Neocomian) part of the Kingak Shale and in the pebble shale unit (Fig. 8). The stratigraphic interval involved in these plays includes sequence sets K3 (mostly Valanginian-aged strata) and K4 (mostly Hauterivian-aged strata) of Houseknecht (2001, 2002), plus the pebble shale unit (Figs. 3 and 8). Sequence set K3 is a wedge of strata (Fig. 6a) composed mostly of mudstone that has the potential for sand-prone facies at its base (Fig. 6b), where a transgressive shoreface sand is locally present, and in northern NPRA, where seismic and wire-line log data indicate the presence of more proximal facies that may locally contain reservoir-quality sandstone (Fig. 6b; Houseknecht, 2001, 2002). Sequence set K4 is a wedge of strata (Fig. 7a) containing abundant sandstone, particularly in its upper half (Fig. 7b). It thickens abruptly southward from a zero depositional edge in north-central NPRA (Fig. 7a) and displays seismic geometries that suggest deposition on a dynamic, high-energy shelf margin, perhaps in wave-modified deltaic systems (Houseknecht, 2001). The pebble shale unit is a thin veneer at the top of the Beaufortian megasequence that contains lenses of shoreface sandstone whose presence and size are difficult to delineate with available data. The K3-K4-pebble shale stratigraphic interval was aggregated for assessment purposes because public domain data lack sufficient resolution to evaluate the petroleum potential at a finer scale.
Two Beaufortian Cretaceous topset plays are defined based primarily on inferred reservoir thickness, inferred trap size, and thermal maturity. (1) The Beaufortian Cretaceous Topset North Play lies north of the approximate K4 zero depositional edge and extends to the State-Federal boundary in the Chukchi and Beaufort seas (Fig. 9). This play therefore involves the northern part of the K3 stratal wedge (Fig. 6) and the northern part of the pebble shale unit (Fig. 8). The southern boundary of the Beaufortian Cretaceous Topset North Play also corresponds to the approximate location of the 1.3 percent vitrinite reflectance contour on the LCU (lower values to the north and higher values to the south), indicating that most of this play lies at levels of thermal maturity that are within the oil window. Inasmuch as the LCU lies between K3 strata beneath and the pebble shale unit above (Fig. 8), the LCU may have acted as a significant migration pathway to charge this play, perhaps from areas of higher thermal maturity in southern NPRA. This play thus has the potential to contain both oil, which may have been generated locally or may have migrated early into the play area, and gas, which may have migrated later into the play area.
(2) The Beaufortian Cretaceous Topset South Play lies south of the approximate K4 zero depositional edge and the 1.3 percent vitrinite reflectance contour on the LCU (Figs. 8 and 9). The southern boundary of the Beaufortian Cretaceous Topset South Play is defined as the most distal occurrence of topset seismic reflections in the K4 sequence set as inferred from the regional grid of public domain, 2-D seismic data used for this study. Most of this play area lies at levels of thermal maturity higher than typically associated with oil preservation, and it is therefore considered a gas play.
Although numerous wells penetrated the Beaufortian Cretaceous Topset North Play (Fig. 6), stratigraphic traps in Cretaceous-aged Beaufortian strata have not been a primary objective of exploration drilling in NPRA. Two wells drilled by the Federal Government considered stratigraphic and/or combination structural-stratigraphic traps involving the Kemik sandstone or its equivalents (basal pebble shale unit) to be objectives. The North Kalikpik well (Fig. 9) was designed to test seismic geometries inferred to include blocks of Kemik-type sandstone isolated by erosional channels cut during deposition of the younger Torok Formation. These seismic geometries subsequently have been interpreted to be blocks of the Torok Formation within the Fish Creek slide (Weimer, 1987; Homza, in press). No Kemik-type sandstone was present in the North Kalikpik well, as demonstrated by a continuous core extending from the gamma-ray zone into the Kingak Shale (Fig. 1; Houseknecht and Schenk, 2001, 2002). The J.W. Dalton well (Fig. 9) included as a secondary objective Kemik-type sandstone on an LCU closure above truncated Ivishak and Lisburne strata (i.e., a Prudhoe Bay type trap). No reservoir-quality sandstone was encountered and only minor oil shows were observed in this play interval (Hayba and others, 2002).
The Walakpa 1 well, drilled to test an inferred truncation of the Simpson sand (Fig. 3) within the lower part of the Kingak Shale, discovered natural gas in the Walakpa sand (Fig. 3). Previously interpreted to be a lens of Kemik-type sandstone resting on the LCU (e.g., Bird, 1987), the Walakpa sand recently has been reinterpreted on the basis of preliminary new paleontology data to represent a transgressive shoreface sand in the basal K3 (Valanginian) sequence set (Houseknecht, 2001, 2002). The Walakpa sand occurs within the Beaufortian Cretaceous Topset North Play. Seismic data and additional drilling to develop gas resources (~30 BCF) in the Walakpa sand for local consumption at Barrow indicates the trap includes both depositional lenticularity and up-dip pinchout either by onlap onto an older sequence-bounding unconformity or erosional truncation by a younger sequence-bounding unconformity. A subsequent wildcat well (Tulageak; Fig. 9) drilled to test the presence of the Walakpa sand on the east flank of the Barrow high failed to encounter significant reservoir-quality sandstones, although minor oil shows were found in the Kemik-type sandstone interval.
Only three wells have penetrated the Beaufortian Cretaceous Topset South Play (Fig. 7). No wire-line logs were recovered from the play interval in the Oumalik and Seabee wells, and no show of oil or gas was reported. The Tunalik well, the westernmost well drilled in NPRA, encountered a substantial gas kick near the stratigraphic boundary between this play and the Beaufortian clinoform play (see later section). Wire-line logs from the Tunalik indicate a thick, sandstone-prone section throughout the play interval (~700 ft.) and cores recovered from both the Tunalik and Seabee suggest the potential for relatively high energy depositional facies across the entire width of NPRA.
There are multiple and varied scenarios by which the Beaufortian Cretaceous topset plays could be charged with hydrocarbons (Fig. 10). In northern NPRA, hydrocarbons expelled from the Shublik and/or Kingak source rock intervals could have migrated into the Beaufortian Cretaceous Topset North Play along one or more of the following pathways: (1) the top of Franklinian basement, onto which Shublik through Kingak strata onlap around the Barrow high, (2) fractures and normal faults that commonly are present along the south flank of the Barrow arch, (3) southward downlapping clinoforms in the Kingak Shale, and (4) sequence bounding unconformities (including the LCU) within Beaufortian strata. The GRZ source rock interval forms the upper stratigraphic boundary of the Beaufortian Cretaceous Topset North Play across all of northern NPRA, so expelled hydrocarbons could have migrated short distances into underlying stratigraphic traps. The regionally extensive LCU, which lies within this play, extends downdip southward to areas of high thermal maturity, thereby providing the potential for a regional migration pathway for thermogenic gas from the deep basin to charge this play, even at shallow depths along the crest of the Barrow arch (Burruss and others, this volume). The varied nature of hydrocarbons documented to be present in this play (low gravity oil, high gravity oil, thermogenic gas) likely reflects this spectrum of charge scenarios.
The Beaufortian Cretaceous Topset South Play also has the potential to be charged by multiple source rocks. Clinoforms within the K3 and K4 sequence sets downlap onto the Kingak source rock interval, which rests almost directly on the Shublik source rock interval in southern NPRA (Fig. 10). In addition, the GRZ source rock interval, including condensed mudstones within the pebble shale unit, the GRZ, and the lower Torok, rest directly on or downlap onto the upper stratigraphic units within the Beaufortian Cretaceous Topset South Play. Although these source rocks originally may have expelled either oil (Shublik, Kingak, GRZ) or gas (GRZ), the play currently lies at levels of thermal maturity mostly in the gas window.
Sandstones in the Kingak Shale and pebble shale unit are typically quartz arenites with variable amounts of glauconite and clay matrix. Most porosity and permeability data from the Beaufortian Cretaceous Topset North Play are from wells high on the Barrow arch where this play is at its shallowest depths. In the Walakpa gas field and in wells at the South Barrow gas field (Fig. 9), sandstones in this play display porosities that typically range from 10 to 25 percent and permeabilities that range from 0.1 to 200 millidarcies (Nelson and Kibler, 2002). Wells in the area of the Colville River delta, east of NPRA, have encountered oil-saturated Kuparuk sands (stratigraphically equivalent to Kemik) with porosities that range from 10 to 30 percent and permeabilities that range from 1 to 800 millidarcies (e.g., Kalubik; Kumar and others, 2002).
Reservoir quality data in the Beaufortian Cretaceous Topset South Play are limited to a few samples from cores in the Tunalik well (Fig. 9), which have porosities that range from 7 to 10 percent and permeabilities consistently below 1 millidarcy (Nelson and Kibler, 2002).
Stratigraphic traps in the Beaufortian Cretaceous Topset North Play all are inferred to involve lenticular bodies of shallow marine sandstone. Limited well data suggest that most of the sandstones in the Kingak K3 sequence set and pebble shale unit are thin (a few feet to a few 10’s of feet thick) and probably aerially restricted in size. They may have been deposited as transgressive shoreface sands (e.g., Walakpa) or as shallow marine storm sands (e.g., oil-stained sands in South Barrow cores). These lenticular sandstone bodies may pinch out in an up-dip (generally northward) direction owing to either onlap onto a sequence-bounding unconformity or ravinement surface, or truncation beneath a sequence-bounding unconformity or ravinement surface.
Stratigraphic traps in the Beaufortian Cretaceous Topset South Play may include a variety of sandstone bodies deposited in shelf-margin deltas, wave-modified shoreface systems, and perhaps fluvial or estuarine incisions. Limited well control and seismic expression suggest the Kingak K4 sequence set was deposited in a dynamic setting characterized by rapid sediment influx, rotational growth faulting, shelf-margin collapse, and fairly high energy wave reworking of sand. Specific trap types may include sand-body pinchouts against growth faults, antiformal dip reversals related to growth fault movement, lenticular delta-mouth bars, offlapping and shingled delta-front sand lenses, and transgressive shoreface sandstones. The clear evidence of a sequence-bounding unconformity in northern NPRA and rapid sediment influx to the shelf margin in central NPRA also suggests the potential that there may be incised channel systems that could contain fluvial or estuarine sandstone bodies. Although no clear seismic evidence of major incisions has been documented, the tectonic and sedimentary setting favors the existence of incisions and they could provide the potential for the preservation of relatively coarse-grained sandstone with adequate reservoir properties in favorable stratigraphic trapping geometries.
The timing of trap development relative to oil generation is excellent in the Beaufortian Cretaceous topset plays. Deposition of Cretaceous-aged Beaufortian strata across NPRA occurred between ~130 Ma and ~115 Ma (Fig. 3). Peak oil generation in the Shublik, Kingak, and GRZ source rock intervals occurred between ~100 Ma in western NPRA and ~90 Ma in eastern NPRA (Burns and others, 2002). Thus, all stratigraphic traps in the Beaufortian Cretaceous topset plays were formed before any oil was 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.
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. Two fields provide analogue data. Average reservoir thickness (net pay) in the Walakpa gas field is 24 ft. (AOGCC, 1999) and in the Kuparuk oil field is 35 ft. (Kuparuk “A” = 20 ft. and Kuparuk “C” = 15 ft.) (Masterson and Eggert, 1992). Thicknesses of sandstone measured from wireline logs and cores in NPRA suggest that most sandstone bodies are less than 30 ft. thick. The compilation of Kornbrath and others (1997) for wells in the area of the Colville River delta is consistent with this inference for Cretaceous-aged Beaufortian sandstones. The maximum input value of 100 ft. is based on a scenario of multiple stacked sandstone bodies. For comparison, the maximum net reservoir thickness for Cretaceous-aged Beaufortian sandstones in Kuparuk field in 105 ft. (Masterson and Eggert, 1992).
Area of closure. Little analogue data exist. The area of closure of the trap at Walakpa gas field is estimated to be about 6,000 acres (Kumar and others, 2002). The area of closure of the Kuparuk field is 135,000 acres, but that is not considered a valid analogue as the trap is primarily a structural closure (Masterson and Eggert, 1992). Limited information regarding the size of oil accumulations in Cretaceous-aged Beaufortian sands on the Colville River delta suggests they are likely less than 10,000 acres in size. The maximum input value of 50,000 acres represents the largest possible closure that may exist based on current understanding of sand-body geometries and trapping mechanisms.
Porosity and hydrocarbon pore volume. Most of the play area lies at greater depths than analogue data sets from within the play (Walakpa and South Barrow) and from outside the play area (Colville River delta – Kornbrath and others, 1997; Kuparuk field – Masterson and Eggert, 1992). Therefore, input values reflect the expectation that porosity is likely to be slightly lower than these analogues. The value for water saturation is based on petrophysical properties of analogues (especially Walakpa field) and hydrocarbon pore volumes are calculated by subtraction.
Trap fill. The generally high input values reflect a combination of good charge potential and small trap size.
Trap depth. The depth range of potential traps in the play was derived by posting a structure map of the Lower Cretaceous Unconformity over the play map.
Number of prospects. The values reflect knowledge of the depositional system, perceived density of sand bodies within Cretaceous-aged Beaufortian strata, small size of inferred sand bodies (area of closure), and large size of the play area (7.9 million acres).
Play probability attributes – Table 2. 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). The probabilities that sufficient charge was available and that timing was appropriate are both inferred to be 1 (i.e., 100%). The probability that at least one trap (includes reservoir, seal, and geometry) exists is estimated to be 0.9 (90%). The primary reservation regarding trap is whether a sand body of sufficient porosity and size exists within the play area. The resultant play probability (charge probability X trap probability X timing probability) indicates a 90 percent chance that at least one hydrocarbon accumulation of the minimum size occurs in this play.
Prospect probability attributes – Table 2. 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 0.8. Although the potential for charge is favorable in this play, some migration pathways are restricted in space (e.g., fractures and unconformities), as are the stratigraphic traps. Sufficient charge may not reach all lenticular sandstone bodies. The trap probability is estimated to be 0.2, primarily because (1) relatively few sand bodies are inferred to have sufficient volume to hold 50 million barrels of in-place oil or 250 billion cubic feet of technically recoverable gas, (2) relatively few sand bodies are inferred to have adequate porosity, and (3) the play may be characterized as “leaky” because of multiple unconformities (especially the LCU) and fractures. The timing probability is 1 because all the traps in this play formed before any hydrocarbon generation and migration in the region. The resultant prospect probability (charge probability X trap probability X timing probability) indicates a 16 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 a prospect in the play will contain at least 50 million barrels of in-place oil or 250 billion cubic feet of technically recoverable gas. Seventy (70) percent of the hydrocarbon accumulations within the play are inferred to be oil and 30 percent are inferred 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, but that thermogenic gas from the Colville basin may have entered the play along regional migration pathways (e.g., the LCU). The presence of at least one dry gas accumulation (Walakpa) in the play supports this conclusion.
Hydrocarbon parameters – Table 3. An oil recovery factor of 35 percent is based on the similarity of reservoirs anticipated in this play with analogues elsewhere on the North Slope (e.g., Kuparuk River field; Masterson and Eggert, 1992; Verma, this volume). Non-associated gas recovery factor is based on analogue fields elsewhere in the U.S. (Verma, this volume). An oil gravity of 30° API and a sulfur content of 1 percent reflect the inference that oil migrating into the play likely was a mixture of low-gravity/high sulfur oil expelled from the Shublik and high-gravity/low sulfur oil expelled from the lower Kingak and/or GRZ (Lillis and Magoon, this volume).
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 Beaufortian Cretaceous Topset North Play in NPRA is estimated to range between 0 (95-percent probability) and 239 (5-percent probability) million barrels, with a mean (expected value) of 103 million barrels (Table 4). The volume of undiscovered, technically recoverable, non-associated gas in the Beaufortian Cretaceous Topset North Play in NPRA is estimated to range between 0 (95-percent probability) and 1,162 (5-percent probability) billion cubic feet, with a mean (expected value) of 405 billion cubic feet (Table 4).
The oil and gas resources are estimated to occur in accumulations of various sizes, as illustrated in Figure 11. One oil accumulation between 32 and 64 mmbo, and two accumulations between 16 and 32 mmbo may occur within the Beaufortian Cretaceous Topset North Play (Fig. 11a). No larger accumulations are expected. Most of the volume of oil within this play is expected to occur in accumulations that fall in the 32 to 64 mmbo and the 16 to 32 mmbo size classes (Fig. 11b).
One non-associated, natural gas accumulation in the 192 to 384 bcf size class is estimated to occur in the Beaufortian Cretaceous Topset North Play (Fig. 11c). Most of the gas in this play is expected to occur in that accumulation (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 Beaufortian Cretaceous Topset North Play. Those estimates are reported by Schuenemeyer (this volume).
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. This play involves a sand-prone, shelf-margin section that may be as much as 1,000 feet thick, and the input values (Table 5) reflect reasonable estimates if only a small percentage of that section has sufficient porosity.
Area of closure. Input values are based on assumptions regarding the potential size range of a variety of possible shelf-margin trap geometries, including growth fault traps, delta-mouth bars, and offlapping and shingled delta-front sand bodies.
Porosity and hydrocarbon pore volume. In the absence of much data, the median porosity value is estimated to be about 50% higher than measured porosities from the Tunalik core. The 5-percent probability and maximum values (Table 5) reflect the possibility of an early hydrocarbon charge that may have preserved porosity by inhibiting diagenesis. Water saturation is the same used in the Beaufortian Cretaceous Topset North Play, and is primarily based on petrophysical properties of Walakpa field.
Trap fill. The generally high input values reflect a combination of good charge potential and small to moderate trap size.
Trap depth. The depth range of potential traps in the play was derived by posting a structure map of the Lower Cretaceous Unconformity over the play map.
Number of prospects. The values (Table 5) reflect the inferred character of the shelf-margin depositional system and seismic data that suggest good potential for stratigraphic trap geometries. The large play area (6.8 million acres) provides ample opportunity for trap distribution across NPRA.
Play probability attributes – Table 6. 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 gas accumulation of the minimum size is certain to occur in this play.
Prospect probability attributes – Table 6. 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 based on the close and favorable association of multiple source rocks and migration pathways throughout the play area. Trap probability is estimated to be 0.2, primarily because the likelihood of sufficient reservoir quality is uncertain. Timing probability is 1 because all the traps in this play formed before any hydrocarbon generation and migration in the region. The resultant prospect probability (charge probability X trap probability X timing probability) indicates an 18 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 an 18 percent chance that a prospect in the play will contain at least 250 billion cubic feet of technically recoverable gas. All hydrocarbon accumulations within the play are inferred to be gas based on thermal maturity, both of the play itself and of the deep basin downdip from the play from which thermogenic gas may have been expelled.
Hydrocarbon parameters. The gas recovery factor of 70 percent is based on analogue fields elsewhere in the U.S. (Verma, this volume).
Results – Beaufortian Cretaceous Topset South 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, non-associated gas in the Beaufortian Cretaceous Topset South Play in NPRA is estimated to range between 635 (95-percent probability) and 4,004 (5-percent probability) billion cubic feet, with a mean (expected value) of 2,130 billion cubic feet (Table 20). No technically recoverable oil is estimated to occur in this play.
The gas resources are estimated to occur in accumulations of various sizes, as illustrated in Figure 12. Two natural gas accumulations in the 384 to 768 bcf size class and three accumulations in the 192 to 384 bcf size class are estimated to occur within the Beaufortian Cretaceous Topset South Play (Fig. 12c). Most of the gas in this play is expected to occur in accumulations that fall in the 384 to 768 bcf and 192 to 384 bcf size classes (Fig. 12d).
In addition to volumes of non-associated gas, natural gas liquids are estimated to occur in the Beaufortian Cretaceous Topset South Play. Those estimates are reported by Schuenemeyer (this volume).
This set of four plays involves stratigraphic traps within topset seismic facies in the Upper Jurassic (Oxfordian - Kimmeridgian) part of the Kingak Shale. The stratigraphic interval involved in these plays includes sequence set K2 of Houseknecht (2001, 2002; Figs. 3 and 8). Sequence set K2 is present across a broad area in north-central NPRA where its thickness is generally less than 500 feet, in a major depocenter in eastern NPRA where its maximum thickness exceeds 1,750 feet, and in a subsidiary depocenter in western NPRA where its maximum thickness exceeds 750 feet (Fig. 5A). This thickness pattern reflects the geometry of the underlying K1 sequence set. That is, K2 is thin across the broad K1 “shelf” in north-central NPRA and K2 thickens abruptly basinward across the K1 shelf margin (Houseknecht, 2001, 2002).
Within the K2 depocenter in eastern NPRA, at least three generally offlapping depositional sequences are recognized in seismic and well-log data. Each comprises south-southeast dipping clinoforms that downlap onto an inferred Lower Jurassic condensed section (Fig. 5B). These clinoforms are inferred to be part of a lowstand systems tract (LST) deposited at the shelf margin during pulses of uplift on the Barrow arch during failed rift events. Northward (updip), the clinoforms either (1) toplap relatively proximal, sand-prone facies within the lowstand systems tract or (2) are truncated by a ravinement surface (transgressive surface of erosion) at the base of a transgressive systems tract (TST) that locally includes winnowed shoreface sands. In the Alpine oil field (Fig. 13), where closely spaced wells reveal abundant local complexity of facies, coarsening-upward successions inferred to represent prograding offshore to lower shoreface deposits of a LST likely represent the toplap seismic relationship (although the public domain seismic grid used for this study does not extend into the Alpine field area). In addition, the sharp-based and blocky sandstones that form the main Alpine reservoir are inferred to represent winnowed shoreface deposits of a TST resting directly on a ravinement or sequence boundary (Fig.13); these likely represent the updip truncation of clinoforms observed in seismic data.
North of the major depocenter in eastern NPRA, clinoforms are absent and the K2 sequence set comprises a thin (generally less than 500 ft.) interval that includes parts of multiple transgressive systems tracts and remnants of highstand systems tracts. The Kingak Shale in general and the K2 sequence set in particular in this part of NPRA are characterized by numerous ravinements and/or sequence-bounding unconformities that converge northward towards the Barrow arch, and the sequences display variable amounts of erosional truncation along strike. The resulting complexity of erosional surfaces generally exceeds the resolution and density of public domain data with which the surfaces can be identified and mapped. The potential for winnowed shoreface sandstones of reservoir quality within this broad northern area is demonstrated by the presence of more than 80 feet of Alpine-type sandstone cored in the Kuyanak well in northern NPRA (Figs. 5A, 5B).
The depocenter in western NPRA is not as clearly defined seismically, perhaps because the underlying K1 shelf margin appears to be less abrupt than in eastern NPRA. As a result, the K2 sequence set is significantly thinner and does not display large-scale clinoforms that downlap onto a well-defined Lower Jurassic condensed section.
Four Beaufortian Upper Jurassic topset plays are defined based on seismic definition of potential source-charge-reservoir geometries and thermal maturity. The potential for a favorable source-charge-reservoir setting is inferred to be different in eastern vs. western NPRA based on seismic evidence that suggests the following: (A) The distal Lower Jurassic condensed section, which is inferred to represent the primary source rock interval for high gravity oil that may charge these plays, is well defined as a thin, high amplitude seismic unit that extends northward beneath the play areas in the east. In contrast, the distal Lower Jurassic section is thicker and composed of multiple seismic units that do not extend as far northward beneath the play areas in the west. (B) In eastern NPRA, the Upper Jurassic (K2) sequence set includes a thick interval of clinoforms, most of which downlap directly onto the Lower Jurassic condensed section. In western NPRA, the Upper Jurassic (K2) sequence set includes a thinner interval of clinoforms, most of which downlap onto internal sequence boundaries within the K2 section, and not directly onto the Lower Jurassic section. For these reasons, the seismically defined extent of Beaufortian Upper Jurassic topset horizons was divided into eastern and western areas along a north-south line that approximates a “migration divide” based on a structure map of the Lower Cretaceous Unconformity (LCU).
A second play boundary was imposed from west to east across the region based on projecting the 1.3 percent vitrinite reflectance contour onto the stratigraphic top of the play interval. The area north of this line is inferred to be mostly oil prone whereas the area south of this line is inferred to be mostly gas prone. A gradational oil to gas (north to south) transition related to increasing thermal maturity is expected to exist between the northern and southern play areas. However, insufficient data exist to determine the nature and location of this transition. For purposes of this assessment, the assumption is made that all undiscovered hydrocarbon accumulations will be oil north of the play boundary and will be gas south of the play boundary.
The four play areas delineated based on these criteria are shown in Figure 14 and defined as follows: (1) The Beaufortian Upper Jurassic Topset Northeast Play lies east of the LCU structural divide and north of the 1.3 vitrinite reflectance contour projected onto the stratigraphic top of the play. The northern boundary of the play is defined by complete truncation of Upper Jurassic strata beneath the LCU. The eastern boundary of the play is defined by the State-Federal water boundary in the Beaufort Sea and by the NPRA boundary onshore. (2) The Beaufortian Upper Jurassic Topset Southeast Play lays east of the LCU structural divide and south of the 1.3 vitrinite reflectance contour projected onto the stratigraphic top of the play. The southern boundary of the play is defined by the southernmost extent of topset seismic reflections within Upper Jurassic strata. The eastern boundary of the play is defined by the NPRA boundary along the Colville River. (3) The Beaufortian Upper Jurassic Topset Northwest Play lays west of the LCU structural divide and north of the 1.3 vitrinite reflectance contour projected onto the stratigraphic top of the play. The northern boundary of the play is defined by complete truncation of Upper Jurassic strata beneath the LCU. The western boundary of the play is defined by the State-Federal water boundary in the Chukchi Sea. (4) The Beaufortian Upper Jurassic Topset Southwest Play is west of the LCU structural divide and south of the 1.3 vitrinite reflectance contour projected onto the stratigraphic top of the play. The southern boundary of the play is defined by the southernmost extent of topset seismic reflections within Upper Jurassic strata. The western boundary of the play is defined by the State-Federal water boundary in the Chukchi Sea.
The Alpine oil field occurs within the extension of the Beaufortian Upper Jurassic Topset Northeast Play, just outside the NPRA assessment area, and public information from the Alpine field has been used in this study to help constrain certain attributes of the play. Most of the recent exploration wells drilled in eastern NPRA since the 1999 Federal lease sale, including the discoveries announced in 2001 (Phillips press release) have apparently targeted this play as the primary objective. However, data from these new wells were not available for this study and the information released to the public is insufficient at this time to estimate either the number or the sizes of the new discoveries. Therefore, these new discoveries in NPRA have been used as indications that favorable charge, reservoir, and trap conditions exist within the assessment area, but otherwise they have not been used to constrain play attributes.
Among previous exploration wells drilled in NPRA, only one is known to have specifically targeted any of the Beaufortian Upper Jurassic topset plays. The North Inigok well was drilled to test seismic geometries inferred to represent bar-type sandstones within the upper Kingak Shale, at a stratigraphic horizon that approximately correlates to the Alpine horizon. The seismic geometries interpreted as expressions of offshore bars are now thought to represent strata in interfluves between clearly visible (on seismic data) erosional incisions on the “Alpine” sequence boundary. Current models suggest that Alpine-type sands accumulated in erosional lows on ravinements or sequence-bounding unconformities (Houseknecht, 2001, 2002). The North Inigok well penetrated non-reservoir facies (mostly siltstone and muddy sandstone) and recovered gas and evidence of condensate in a drill stem test at the Alpine horizon (Burruss and others, this volume).
Although numerous other wells penetrated the Beaufortian Upper Jurassic topset plays (Fig. 5a), stratigraphic traps within these plays were not primary objectives. A few wells initially drilled to test pinchouts or other stratigraphic aspects of Lower Jurassic strata have provided significant information regarding facies in the Upper Jurassic plays. In particular, cores from the Walakpa 1 and 2 wells provide important constraints on non-reservoir facies, and cores from the Kuyanak 1 well provide the best public domain example of Alpine-type reservoir facies.
The potential for charging Beaufortian Upper Jurassic topset plays is summarized in Figure 15. In the Beaufortian Upper Jurassic Topset Northeast Play and the Beaufortian Upper Jurassic Topset Southeast Play, the primary potential is inferred to involve expulsion of hydrocarbons from the lower Kingak (Lower Jurassic) source interval and migration of those hydrocarbons updip along Upper Jurassic clinoforms to stratigraphic traps. In this scenario there is a higher potential for charge within the Upper Jurassic depocenter in eastern NPRA, where the presence of clinoforms provide a direct migration pathway from source rock to reservoir. North of that depocenter, where Upper Jurassic clinoforms are absent, there is a lower charge potential as hydrocarbons would have to migrate long distances updip along sequence bounding unconformities to charge stratigraphic traps. In the Beaufortian Upper Jurassic Topset Northwest Play and the Beaufortian Upper Jurassic Topset Southwest Play, a charge scenario similar to that in the eastern depocenter is considered to provide the primary potential. However, charge risk is considered higher in the two western plays relative to the two eastern plays because seismic evidence suggests that both the Lower Jurassic condensed section (source) and the Upper Jurassic clinoforms (migration pathway) are not as favorably developed (see previous discussion).
The Shublik Formation source rock interval is inferred to provide secondary charge potential in all four play areas. The Shublik directly underlies the Kingak source rock interval in the southern half of NPRA, and any hydrocarbons expelled from the distal Shublik Formation could follow the same migration pathways discussed above. Hydrocarbons expelled from Shublik Formation source rocks in northern NPRA, where the Shublik is overlain by the Sag River Sandstone and the Lower Jurassic part of the Kingak Shale, would have to follow more circuitous migration pathways to charge stratigraphic traps in Upper Jurassic strata. These pathways may include (1) the top of Franklinian basement, onto which Shublik through Kingak strata onlap around the Barrow high, (2) fractures and normal faults that commonly are present along the south flank of the Barrow arch, (3) southward downlapping clinoforms in the Kingak Shale, and (4) sequence bounding unconformities (including the LCU) within Beaufortian strata.
The GRZ source rock interval also may provide charge potential in all four play areas. However, the GRZ is separated from Upper Jurassic strata by Cretaceous-aged strata within the Kingak Shale (i.e., strata involved in the Beaufortian Cretaceous topset plays), except along a narrow zone in northern NPRA where Upper Jurassic strata are beveled northward beneath the LCU. For this reason, the potential for charging these Upper Jurassic plays with hydrocarbons expelled from the GRZ is considered poor except in the northernmost extent of the two northern plays.
The fact that Upper Jurassic strata are beveled beneath the LCU in northern NPRA introduces the possibility that hydrocarbons expelled from the deep Colville basin could migrate updip northward along the LCU and charge traps in Upper Jurassic strata. For this reason, the areas where Upper Jurassic strata subcrop beneath the LCU within the Beaufortian Upper Jurassic Topset Northeast Play and the Beaufortian Upper Jurassic Topset Northwest Play are considered to have a lower probability for high gravity oil charge and a higher probability for gas charge than the remainder of those play areas.
The Beaufortian Upper Jurassic topset plays are likely to contain sandstones that display two distinctly different types of reservoir quality. The best reservoir quality will occur in sharp-based, winnowed shoreface sandstones within transgressive systems tracts. Examples include the main reservoir in the Alpine oil field (Alpine “C”) and the “Kuyanak sandstone” cored in the Kuyanak 1 well (Houseknecht, 2001, 2002). Porosity in the Kuyanak sandstone ranges from 15 to 25 percent (average ~20%) and permeability ranges from 1 to 300 millidarcies (average ~100 md) (Nelson and Kibler, 2002), and values reported from the Alpine “C” are similar (Hannon and others, 2000; Morris and others, 2000; Gingrich and others, 2001). These better reservoirs are required for economically viable oil accumulations in these plays.
Poorer reservoir quality will occur in offshore to lower shoreface sandstones that occur in coarsening-upwards successions, mostly in lowstand systems tracts. Examples include lower shoreface sands in cores of K2 strata from the Walakpa 1 well (Houseknecht, 2001, 2002) and subsidiary reservoirs in the Alpine oil field (Alpine “A”). Porosity in these sands commonly ranges from 10 to 20 percent but permeability rarely exceeds 1 millidarcy because of abundant clay matrix. Sandstones such as these may contribute to hydrocarbon volumes in Upper Jurassic stratigraphic traps, but are unlikely to represent economically viable reservoirs in the absence of winnowed shoreface sands.
Stratigraphic traps in all four Beaufortian Upper Jurassic topset plays are inferred to involve lenticular bodies of winnowed, shoreface sandstone. Integration of seismic, wireline log, and core data has resulted in two end-member depositional models for stratigraphic traps in Upper Jurassic strata in NPRA (Figs. 16, 17; Houseknecht, 2002). These models involve the deposition of lenticular bodies of winnowed, shoreface sand in incised lows on ravinement surfaces or sequence-bounding unconformities. Subsurface data suggest that some lows are narrow features that appear to be incised channels whereas others are wider features that appear to be embayments. In both cases, the sand bodies pinch out by onlap onto the margins of incisions and therefore are prone to abrupt variability in thickness. The perception of two depositional models may reflect limitations of public domain, 2-D seismic data when, in fact, these two end-member models may occur within a single depositional system. In that case, the incision model may represent a relatively proximal setting and the embayment model may represent a more distal setting. In effect, this describes an overall depositional model that may be characterized as an estuary in which narrowly confined proximal sands grade into more unconfined distal sands. In some cases an insufficient volume of winnowed shoreface sand may have been available to completely fill incised lows. This may result in an incised valley or embayment that contains a sedimentary fill comprising both discontinuous, bar-like sand bodies and transgressive mudstone or siltstone facies.
The depositional models presented above suggest that the northern play areas may be more prone to stratigraphic trap geometries that are narrow and elongate (i.e., incised channels) and that the southern play areas may be more prone to stratigraphic trap geometries that are wider and more equant (i.e., embayments). However, insufficient data exists to validate this interpretation. For the purposes of this assessment, therefore, the assumption is made that similar depositional conditions existed across the study area during the Late Jurassic and that similar stratigraphic trap geometries are present throughout all four play areas.
The timing of trap development relative to oil generation is excellent in the Beaufortian Upper Jurassic topset plays. Deposition of Upper Jurassic strata across NPRA occurred between ~155 Ma and ~135 Ma. Peak oil generation in the Shublik, Kingak, and GRZ source rock intervals occurred between ~100 Ma in western NPRA and ~90 Ma in eastern NPRA (Burns and others, 2002). Thus, all stratigraphic traps in the Beaufortian Upper Jurassic topset plays were formed before any oil was 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.
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. The Alpine field is the only analogue data at field scale. The Alpine “C” (blocky shoreface sand that is the main reservoir) ranges between 5 and 110 ft. net thickness (Gingrich and others, 2001) and averages about 50 ft. net thickness. The average net/gross ratio is 95 percent (Gingrich and others, 2001). The only Alpine-type sandstone in public domain wells in NPRA is in the Kuyanak well, which penetrated about 85 ft. net thickness. Based on these limited constraints, a median thickness of 50 ft. and a maximum thickness of 150 ft. were used as assessment inputs (Table 9).
Area of closure. The Alpine field, which occupies approximately 25,000 acres, is the only analogue. Features believed to represent incised channel and shoreface systems have been mapped in NPRA using public domain, 2-D seismic data (Figs. 16c, 17c, 25; Houseknecht, 2002) and those generally appear to be smaller than Alpine. The values assigned for area of closure were estimated using those interpretations, and the input distribution is defined by a median of 8,000 acres, a 5-percent fractile of 25,000 acres, and a maximum value of 40,000 acres (Table 9). This input suggests that the median trap size in the play is about one-third the size of Alpine, that only the largest 5 percent of traps in the play will be equal in size or larger than Alpine, and that the largest trap in the play may be 40 or 50 percent larger than Alpine.
Porosity and hydrocarbon pore volume. Average porosity in the main reservoir at Alpine field is 20 percent (Gingrich and others, 2001) and the Kuyanak sand is nearly the same (Nelson and Kibler, 2002). Porosity in this play is inferred to be slightly lower (Table 9) than these analogues because the most prospective part of the play lies at greater depths than Alpine. The value for water saturation is based on Alpine data (AOGCC, 1999).
Trap fill. Values are very high based on (1) no water leg has yet been reported at Alpine field, (2) the play has excellent charge potential, and (3) the trap size is relatively small.
Trap depth. The depth range of potential traps in the play was derived by posting a structure map of the Lower Cretaceous Unconformity over the play map, and then adding an increment of depth for the interval between the LCU and the top of the play.
Number of prospects. Estimates are based on interpretation of incised channel and shoreface systems using public domain, 2-D seismic data (Fig. 16c, 17c, 25; Houseknecht, 2002) and on estimation of potential prospects between seismic lines.
Play probability attributes – Table 10. 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. This certainty is supported by the presence of the Alpine field just outside the assessment area and the positive results announced for exploration wells drilled within the play area during 2000 and 2001 (Phillips press release, 2001).
Prospect probability attributes – Table 10. 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. Although the potential for charge is considered highly favorable in that part of the play underlain by Upper Jurassic clinoforms that downlap onto inferred source rocks in the Lower Jurassic, less favorable conditions may exist in the northwestern part of the play where Upper Jurassic clinoforms and the Lower Jurassic condensed section are absent. Sufficient migration pathways may not exist to charge all stratigraphic traps in that part of the play. The trap probability is estimated to be 0.7. This favorable estimate is based on the discrete geometry of stratigraphic traps formed within incision features, the excellent reservoir quality of the winnowed shoreface sands, and the favorable seal integrity provided by condensed mudstones draped directly on the reservoir sands (Figs. 16b and 17b). The timing probability is 1 because all the traps in this play formed before any hydrocarbon generation and migration in the region. The resultant prospect probability (charge probability X trap probability X timing probability) indicates a 49 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 49 percent chance that a prospect in the Beaufortian Upper Jurassic Topset Northeast Play will contain at least 50 mmbo in-place. All hydrocarbon accumulations within the play are assumed be oil (see previous discussion regarding oil to gas transition). This estimate is based on the inference that the play is charged by hydrocarbons expelled from the oil-prone Lower Jurassic source rocks, and perhaps from the oil-prone Shublik Formation, and that the play is characterized by thermal maturities within the oil window. Although there is clear evidence that the play is oil-prone, there is some uncertainty involving the amount of gas that may occur in association with liquid hydrocarbons. The Alpine field has a low gas-oil ratio (GOR) of approximately 500, whereas the new discoveries in NPRA apparently have significantly higher GOR values of approximately 10,000 (based on volumes of oil and gas tested as reported in Phillips press release, 2001). If additional increases in GOR occur to the west, the volume of gas in the play may be higher at the expense of oil.
Hydrocarbon parameters. An oil recovery factor of 50 percent (Table 11) is based on reported estimates of original oil in-place and recoverable reserves at the Alpine field. Oil gravity and sulfur content are based on reports from Alpine and the assumption that the play is charged by oil expelled from lower Kingak source rocks (Lillis and Magoon, this volume).
The assessment input values summarized in Tables 9, 10, and 11 were used to estimate the 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 Beaufortian Upper Jurassic Topset Northeast Play in NPRA is estimated to range between 2,744 (95-percent probability) and 8,086 (5-percent probability) million barrels, with a mean (expected value) of 5,176 million barrels (Table 12). No non-associated natural gas is assessed in this play.
The oil resources are estimated to occur in accumulations of various sizes, as illustrated in Figure 18. There is a chance that one accumulation between 512 and 1,024 mmbo may occur, but larger accumulations are not likely. Six accumulations between 256 and 512 mmbo, ten accumulations between 128 and 256 mmbo, eight accumulations between 64 and 128 mmbo, and five accumulations between 32 and 64 mmbo may occur within the Beaufortian Upper Jurassic Topset Northeast Play (Fig. 18a). Most of the volume of oil within this play is expected to occur in accumulations that fall in the 256 to 512 mmbo and in the 128 to 256 mmbo size classes (Fig. 18b).
In addition to volumes of crude oil, associated natural gas and natural gas liquids are estimated to occur in the Beaufortian Upper Jurassic Topset Northeast Play. Those estimates are reported by Schuenemeyer (this volume).
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 sandstone bodies will be less confined to erosional incisions as compared to the Beaufortian Upper Jurassic Topset Northeast Play. For this reason, LTP and median values are lower than the northeast play area, and low probability values are the same (Table 13).
Area of closure. Interpretation of depositional systems suggests that sandstone bodies will be less confined to erosional incisions as compared to the Beaufortian Upper Jurassic Topset Northeast Play. For this reason, LTP and median values are higher than the northeast play area, and low probability values are the same (Table 13).
Porosity and hydrocarbon pore volume. Porosity is estimated to be systematically lower (Table 13) than in the Beaufortian Upper Jurassic Topset Northeast Play because burial depth is greater. The value for water saturation is the same as the northeast play area.
Trap fill. Values are the same used for the Beaufortian Upper Jurassic Topset Northeast Play because charge potential is even more favorable (closer to higher quality source rocks in the lower Kingak) and trap size remains relatively small.
Trap depth. The depth range of potential traps in the play was derived by posting a structure map of the Lower Cretaceous Unconformity over the play map, and then adding an increment of depth for the interval between the LCU and the top of the play.
Number of prospects. Estimates are based on interpretation of incised channel and shoreface systems using public domain, 2-D seismic data (Houseknecht, 2002) and on estimation of potential prospects between seismic lines.
Play probability attributes – Table 14. 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.
Prospect probability attributes – Table 14. 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. This value is higher than the corresponding attribute in the northeast play area because of closer proximity to the inferred primary source rocks (lower Kingak) and the presence of Upper Jurassic clinoforms that downlap onto that source rock interval throughout the play area. The trap probability is estimated to be 0.5. This estimate is lower than the corresponding attribute in the northeast play area because depositional facies are inferred to be more distal in character and because porosity is inferred to be lower as a consequence of greater burial depth and higher thermal maturity. The timing probability is 1 because all the traps in this play formed before any hydrocarbon generation and migration in the region. The resultant prospect probability (charge probability X trap probability X timing probability) indicates a 45 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 45 percent chance that a prospect in the Beaufortian Upper Jurassic Topset Southeast Play will contain at least 250 billion cubic feet of technically recoverable gas. All hydrocarbon accumulations within the play are assumed to be gas (see previous discussion regarding oil to gas transition). This estimate is based on the inference that the play is characterized by thermal maturities within the gas window.
Hydrocarbon parameters. The gas recovery factor of 70 percent is based on analogue fields elsewhere in the U.S. (Verma, this volume).
The assessment input values summarized in Tables 13, 14, and 15 were used to estimate the 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 Beaufortian Upper Jurassic Topset Southeast Play in NPRA is estimated to range between 2,053 (95-percent probability) and 9,030 (5-percent probability) billion cubic feet, with a mean (expected value) of 5,137 billion cubic feet (Table 16). No crude oil is assessed in this play.
The gas resources are estimated to occur in accumulations of various sizes, as illustrated in Figure 19. Two accumulations between 768 and 1,536 bcf, four accumulations between 384 and 768 bcf, and two accumulations between 192 and 384 bcf may occur within the Beaufortian Upper Jurassic Topset Southeast Play (Fig. 19c). 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 (Fig. 19d).
In addition to volumes of non-associated natural gas, natural gas liquids are estimated to occur in the Beaufortian Upper Jurassic Topset Southeast Play. Those estimates are reported by Schuenemeyer (this volume).
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 (Table 17) are identical to those used for the Beaufortian Upper Jurassic Topset Northeast Play, based on the assumption that depositional systems were similar across the broad shelf area in northern NPRA. Although no well in the play area has penetrated reservoir-quality shoreface sandstone, the proximity to the play of sandstone displaying good reservoir properties in the Kuyanak well (Fig. 14) suggests good potential for the presence of winnowed shoreface sandstones within the play area.
Area of closure. Values are identical to those used for the Beaufortian Upper Jurassic Topset Northeast Play, based on the assumption that depositional systems, and therefore sand body size and geometry, were similar across northern NPRA.
Porosity and hydrocarbon pore volume. Values are identical to those used for the Beaufortian Upper Jurassic Topset Northeast Play, based on similar depths of burial and the assumption of similar sandstone composition and diagenetic history.
Trap fill. Values are identical to those used for the Beaufortian Upper Jurassic Topset Northeast Play.
Trap depth. The depth range of potential traps in the play was derived by posting a structure map of the Lower Cretaceous Unconformity over the play map, and adding an increment of depth for the interval between the LCU and the top of the play.
Number of prospects. Estimates are based on interpretation of incised channel and shoreface systems using public domain, 2-D seismic data (Houseknecht, 2002) and on estimation of potential prospects between seismic lines. The smaller number of prospects as compared to the Beaufortian Upper Jurassic Topset Northeast Play reflects the smaller play area.
Play probability attributes – Table 18. 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.
Prospect probability attributes – Table 18. 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 0.5. This value reflects the interpretation that source rock potential in the lower Kingak is less favorable and that migration pathways are more complex as compared to the Beaufortian Upper Jurassic Topset Northeast Play. The trap probability is estimated to be 0.7, a value identical to that for the Beaufortian Upper Jurassic Topset Northeast Play. This favorable estimate is based on the discrete geometry of stratigraphic traps formed within incision features, the excellent reservoir quality of the winnowed shoreface sands, and the favorable seal integrity provided by condensed mudstones draped directly on the reservoir sands (Figs. 16b and 17b). The timing probability is 1 because all the traps in this play formed before any hydrocarbon generation and migration in the region. The resultant prospect probability (charge probability X trap probability X timing probability) indicates a 35 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 35 percent chance that a prospect in the play will contain at least 50 mmbo in-place. All hydrocarbon accumulations within the play are assumed be oil (see previous discussion regarding oil to gas transition), based on the same line of reasoning used for the northeast play area.
Hydrocarbon parameters. An oil recovery factor of 50 percent (Table 19) is based on reported estimates of original oil in-place and recoverable reserves at the Alpine field. Oil gravity and sulfur content are based on reports from Alpine and the assumption that the play is charged by oil expelled from the lower Kingak (Lillis and Magoon, this volume).
The assessment input values summarized in Tables 17, 18, and 19 were used to estimate the petroleum resource potential using methods described by Schuenemeyer (this volume). Basic results are summarized in Table 20 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 Beaufortian Upper Jurassic Topset Northwest Play in NPRA is estimated to range between 733 (95-percent probability) and 3,312 (5-percent probability) million barrels, with a mean (expected value) of 1,859 million barrels (Table 12). No non-associated natural gas is assessed in this play.
The oil resources are estimated to occur in accumulations of various sizes, as illustrated in Figure 18. Two accumulations between 256 and 512 mmbo, three accumulations between 128 and 256 mmbo, three accumulations between 64 and 128 mmbo, and two accumulations between 32 and 64 mmbo may occur within the Beaufortian Upper Jurassic Topset Northwest Play (Fig. 20a). Most of the volume of oil within this play is expected to occur in accumulations that fall in the 256 to 512 mmbo and in the 128 to 256 mmbo size classes (Fig. 20b).
In addition to volumes of crude oil, associated natural gas and natural gas liquids are estimated to occur in the Beaufortian Upper Jurassic Topset Northwest Play. Those estimates are reported by Schuenemeyer (this volume).
Tables 21 through 23 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 (Table 21) are identical to those used for the Beaufortian Upper Jurassic Topset Southeast Play based on the same interpretations.
Area of closure. Values are identical to those used for the Beaufortian Upper Jurassic Topset Southeast Play based on the same interpretations.
Trap fill. Values are identical to those used for the Beaufortian Upper Jurassic Topset Southeast Play based on the same interpretations.
Trap depth. The depth range of potential traps in the play was derived by posting a structure map of the Lower Cretaceous Unconformity over the play map, and then adding an increment of depth for the interval between the LCU and the top of the play.
Number of prospects. Estimates are based on interpretation of incised channel and shoreface systems using public domain, 2-D seismic data (Houseknecht, 2002) and on estimation of potential prospects between seismic lines. The larger number of prospects compared to the Beaufortian Upper Jurassic Topset Southeast Play reflects the larger play area.
Play probability attributes – Table 22. 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.
Prospect probability attributes – Table 22. 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 0.5. This value reflects the interpretation that source rock potential in the lower Kingak is less favorable as compared to the Beaufortian Upper Jurassic Topset Southeast Play. The trap probability is estimated to be 0.5. This estimate is lower than the corresponding attribute in the Beaufortian Upper Jurassic Topset Northeast Play and the Beaufortian Upper Jurassic Topset Northwest Play because depositional facies are inferred to be more distal in character and because porosity is inferred to be lower as a consequence of greater burial depth and higher thermal maturity. The timing probability is 1 because all the traps in this play formed before any hydrocarbon generation and migration in the region. The resultant prospect probability (charge probability X trap probability X timing probability) indicates a 25 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 25 percent chance that a prospect in the play will contain at least 250 billion cubic feet of technically recoverable gas. All hydrocarbon accumulations within the play are assumed to be gas (see previous discussion regarding oil to gas transition). This estimate is based on the inference that the play is characterized by thermal maturities within the gas window.
Hydrocarbon parameters. The gas recovery factor of 70 percent is based on analogue fields elsewhere in the U.S. (Verma, this volume).
The assessment input values summarized in Tables 21, 22, and 23 were used to estimate the petroleum resource potential using methods described by Schuenemeyer (this volume). Basic results are summarized in Table 24 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 Beaufortian Upper Jurassic Topset Southwest Play in NPRA is estimated to range between 2,008 (95-percent probability) and 9,265 (5-percent probability) billion cubic feet, with a mean (expected value) of 5,220 billion cubic feet (Table 24). No crude oil is assessed in this play.
The gas resources are estimated to occur in accumulations of various sizes, as illustrated in Figure 21. Two accumulations between 768 and 1,536 bcf, four accumulations between 384 and 768 bcf, and three accumulations between 192 and 384 bcf may occur within the Beaufortian Upper Jurassic Topset Southwest Play (Fig. 21c). 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 (Fig. 21d).
In addition to volumes of non-associated natural gas, natural gas liquids are estimated to occur in the Beaufortian Upper Jurassic Topset Southwest Play. Those estimates are reported by Schuenemeyer (this volume).
This play involves stratigraphic traps within topset seismic facies in the Lower Jurassic part of the Kingak Shale. The stratigraphic interval involved in this play includes sequence set “K1” of Houseknecht (2001, 2002; see Figs. 3 and 8). Sequence set K1 lies directly on Triassic strata, including the Sag River Sandstone in northern NPRA and the Shublik Formation in southern NPRA, where the Sag River Sandstone is absent. K1 is generally more than 1000 feet thick in northcentral NPRA, where it accumulated on a lobate shelf, except in a narrow zone along the Arctic coast where it is beveled northward beneath the LCU to a zero truncation edge (Fig. 4A). Along the distal margin of the lobate shelf, seismic reflections within K1 roll over rather abruptly into clinoforms that downlap and coalesce into a condensed section inferred to contain the source rocks from which high gravity, Alpine-type oil was expelled.
Sequence set K1 is interpreted as a composite of numerous higher-order depositional sequences whose individual internal stratal geometries are too small to be resolved with public domain seismic data. In northern NPRA, wireline logs through K1 display at least six and perhaps as many as eight motifs that can be interpreted as individual depositional sequences, as illustrated in Figure 4B. Two of these depositional sequences include sandstones (informally named Barrow sandstone and Simpson sandstone) that locally display reservoir-quality characteristics.
The Beaufortian Lower Jurassic Topset Play extends over much of northern NPRA (Fig. 22). The northeastern boundary is defined by the erosional truncation (zero edge) of Lower Jurassic strata beneath the LCU, the northwestern boundary is defined by the State-Federal water boundary (the play extends into Federal waters in the Chukchi Sea), and the southern boundary is defined by the most distal occurrence of topset seismic reflections.
The Barrow and Simpson sandstones were objectives for numerous wells drilled in north-central NPRA. The Barrow sandstone, which occurs near the base of the Kingak Shale, was found to contain natural gas with the discovery of the South Barrow pool (~25 bcf) in 1949. Subsequent drilling resulted in the discovery of two additional gas accumulations in the Barrow sandstone, the East Barrow pool (~12 bcf; discovered in 1974) and the Sikulik pool (~16 bcf; discovered in 1988). These three natural gas accumulations occur where the Barrow sandstone is truncated updip against fine-grained rocks within the Avak impact structure (Kirschner and others, 1992). Thus, although these natural gas accumulations demonstrate the viability of reservoir quality in the Barrow sandstone, they do not serve as analogues for stratigraphic traps assessed in this play.
The Simpson sandstone, which occurs in the upper part of the K1 sequence set, has been penetrated in several wells in north-central NPRA, including the Topagoruk, South Simpson, Kugrua, Peard, and South Meade (Fig. 22). At least three wells drilled in NPRA targeted potential updip pinchouts of the Simpson sandstone, but the sandstone was absent in the Walakpa 1 and Kuyanak wells and yielded only minor gas shows in the South Meade well (Fig. 22; Hayba and others, 2002).
There are several scenarios by which the Beaufortian Lower Jurassic Topset Play could be charged (Fig. 23). The Shublik Formation source rock interval lies beneath the entire play area and the Kingak Shale source rock interval is the distal stratigraphic equivalent of the K1 topsets. Throughout the play area, hydrocarbons expelled from the Shublik and/or Kingak could have migrated into the play along one or more of the following pathways: (1) the top of Franklinian basement, onto which Shublik through Kingak strata onlap around the Barrow high, (2) fractures and normal faults that commonly are present along the south flank of the Barrow arch, (3) southward downlapping clinoforms at the K1 shelf margin, and (4) sequence bounding unconformities (including the LCU) within Beaufortian strata. The GRZ source rock interval is separated from the play by younger Kingak strata, and migration of hydrocarbons expelled from the GRZ into the Lower Jurassic topset play seems possible only along the northeastern margin of the play where Lower Jurassic strata are beveled by the LCU.
In addition to the main source rock intervals of the Shublik, distal Kingak, and GRZ, source rocks may occur locally within the Lower Jurassic Topset Play. The widespread high amplitude reflections that are a distinctive seismic attribute of this succession represent relatively condensed mudstone facies deposited during transgression and maximum flooding of the shelf (Houseknecht, 2001, 2002). In some wells, these condensed mudstones display total organic carbon values in excess of 2 percent and may represent source rocks on a limited scale. In most cases, these mudstones appear to contain a predominance of type III kerogen and are likely gas prone.
Sandstones in the Beaufortian Lower Jurassic Topset Play are variably glauconitic quartz arenites that typically contain abundant clay. They are pervasively burrowed and contain locally abundant carbonate cement. Reservoir quality, therefore, is variable both locally and regionally. However a common characteristic is relatively high porosity and low permeability, a reflection of the pervasively abundant glauconite and clay.
A large number of porosity and permeability determinations are available from the Barrow sandstone (Nelson and Kibler, 2002). In the Barrow area gas pools, average porosity for individual wells ranges from 15 to 21 percent and average permeability ranges from 15 to 250 millidarcies. In other wells, porosity and permeability are lower, with average respective values of 9% and <1 md in Kuyanak, 16% and 17 md in Walakpa 1, and 14% and 8 md in West Dease. Reservoir quality data are not available for the Simpson sandstone, but wireline log and core observations suggest that porosity and permeability are similar to the Barrow sandstone.
Considering the number of depositional sequences that may be present within K1, reservoir-quality sandstones may occur at horizons other than those already known. However, the depositional setting inferred for the entire K1 sequence set suggests that predominately offshore through lower shoreface deposits occur throughout the play area. These depositional systems appear to have been characterized by relatively low depositional relief, and it is unlikely that higher energy sandstone facies will be found in this play. Therefore, reservoir quality generally will be no better than that observed in the Barrow sandstone.
Traps in the Beaufortian Lower Jurassic Topset Play are inferred to involve lenticular bodies of shallow marine sandstone or perhaps subtle structural closures associated with block faulting or drape across deeper, ancestral positive features (e.g., Endicott basin margins or horsts). Based on well penetrations of the Barrow and Simpson sandstones, reservoir sandstones are likely to range from a few feet to a few 10’s of feet thick. Shoreface sandstones deposited as part of a prograding lowstand systems tract (Fig. 4B) may be widespread and trapping would likely require structural closure associated with faults, drape, or differential compaction. Considering the paucity of well control in northern NPRA, it also is possible that more proximal, lenticular sandstone facies associated with forced regression may be present, and these may have favorable trap potential.
The timing of trap development relative to oil generation is excellent in the Beaufortian Lower Jurassic Topset Play. Deposition of Beaufortian Lower Cretaceous strata across NPRA occurred between ~205 Ma and ~170 Ma. Peak oil generation in the Shublik, Kingak, and GRZ source rock intervals occurred between ~100 Ma in western NPRA and ~90 Ma in eastern NPRA (Burns and others, 2002). Thus, all traps in the Beaufortian Lower Jurassic Topset Play were formed before any oil was generated from source rocks likely to charge the 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.
Tables 25 through 27 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. The median value (Table 25) is based on typical net sandstone thickness in the Barrow gas pools and on other penetrations of Barrow and Simpson sandstone bodies. Lower probability values are based on the possibility of encountering multiple stacked sandstone bodies.
Area of closure. Little analogue data exist as the only delineation drilling focused on this stratigraphic interval has been done in the Barrow gas pools, where the trap is associated with an impact structure. Nevertheless, the Barrow gas pools provide evidence of minimum lateral extent of porous sandstone bodies that occur in the lower Kingak Shale. The median value (Table 25) approximates the size of the East Barrow pool and the lower probability values are based on sandstone-body geometries inferred from current understanding of depositional systems in which lower Kingak strata were deposited (Houseknecht, 2001, 2002).
Porosity and hydrocarbon pore volume. Porosity and water saturation values are based on empirical data from the Barrow sandstone (see previous discussion; Nelson and Kibler, 2002).
Trap fill. The generally high input values reflect a combination of good charge potential and small trap size.
Trap depth. The depth range of potential traps in the play was derived by posting a structure map of the Lower Cretaceous Unconformity over the play map, and then adding an increment for the stratigraphic interval between the LCU and the top of the play. Different values were assigned to oil and gas based on the inference that oil is most likely to occur in the shallower part of the play and that gas may occur at any depth within the play.
Number of prospects. The values reflect knowledge of the depositional system, perceived density of sandstone bodies within Lower Jurassic-aged Beaufortian strata, small size of inferred sandstone bodies (area of closure), and large size of the play area (9.3 million acres).
Play probability attributes – Table 26. 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). The probabilities that sufficient charge was available and that timing was appropriate are both inferred to be 1 (i.e., 100%). Abundant evidence exists that both oil and gas have migrated into the play, and the stratigraphic traps clearly formed prior to the generation and migration of hydrocarbons. The probability that at least one trap (includes reservoir, seal, and geometry) exists is estimated to be 0.9 (90%). The primary reservation regarding trap is whether a sand body of sufficient porosity and size exists within the play area. The resultant play probability (charge probability X trap probability X timing probability) indicates a 90 percent chance that at least one hydrocarbon accumulation of the minimum size occurs in this play.
Prospect probability attributes – Table 26. 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. Although the potential for charge is favorable in this play, some migration pathways are restricted in space (e.g., fractures and unconformities), as are the stratigraphic traps. Sufficient charge may not reach all lenticular sandstone bodies. The trap probability is estimated to be 0.2, primarily because (1) relatively few sandstone bodies are inferred to have sufficient volume to hold 50 million barrels of in-place oil or 250 billion cubic feet of technically recoverable gas, (2) relatively few sandstone bodies are inferred to have adequate porosity, and (3) the play may be characterized as “leaky” because of multiple unconformities (especially the LCU) and fractures. The timing probability is 1 because all the traps in this play formed before of any hydrocarbon generation and migration in the region. 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 12.6 percent chance that a prospect in the play will contain at least 50 million barrels of in-place oil or 250 billion cubic feet of technically recoverable gas. Half the hydrocarbon accumulations within the play are estimated to be oil and half 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, but that thermogenic gas from the Colville basin likely entered the play along regional migration pathways (e.g., the LCU). The presence of at least three dry gas accumulations (the Barrow pools) in the play supports this conclusion (Burruss and others, this volume).
Hydrocarbon parameters. An oil recovery factor of 30 percent is based on the generally low permeability and high clay content of sandstones in the play, and the similarity of reservoirs anticipated in this play with analogues elsewhere on the North Slope (e.g., Kuparuk River field; Masterson and Eggert, 1992). Non-associated gas recovery factor is based on analogue fields elsewhere in the U.S. (Verma, this volume). An oil gravity of 30° API and a sulfur content of 1 percent reflect the inference that oil migrating into the play likely was a mixture of low-gravity/high sulfur oil expelled from the Shublik Formation and high-gravity/low sulfur oil expelled from the lower Kingak Shale and/or GRZ.
The assessment input values summarized in Tables 25, 26, and 27 were used to estimate the petroleum resource potential using methods described by Schuenemeyer (this volume). Basic results are summarized in Table 28 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 Beaufortian Lower Jurassic Topset Play in NPRA is estimated to range between 0 (95-percent probability) and 210 (5-percent probability) million barrels, with a mean (expected value) of 83 million barrels (Table 28). The volume of undiscovered, technically recoverable, non-associated gas in the Beaufortian Lower Jurassic Topset Play in NPRA is estimated to range between 0 (95-percent probability) and 1,915 (5-percent probability) billion cubic feet, with a mean (expected value) of 793 billion cubic feet (Table 28).
The oil and gas resources are estimated to occur in accumulations of various sizes, as illustrated in Figure 24. One oil accumulation between 32 and 64 mmbo, and one accumulation between 16 and 32 mmbo may occur within the Beaufortian Lower Jurassic Topset Play (Fig. 24a). No larger accumulations are expected. Most of the volume of oil within this play is expected to occur in accumulations that fall in the 32 to 64 mmbo and the 16 to 32 mmbo size classes (Fig. 24b).
Two non-associated, natural gas accumulations in the 192 to 384 bcf size class are estimated to occur in the Beaufortian Lower Jurassic Topset Play (Fig. 24c). Most of the gas in this play is expected to occur in those accumulations (Fig. 24d).
In addition to volumes of crude oil and non-associated gas, associated natural gas and natural gas liquids are estimated to occur in the Beaufortian Lower Jurassic Topset Play. Those estimates are reported by Schuenemeyer (this volume).
This play involves stratigraphic traps within clinoform seismic facies in the Kingak Shale, including strata that are distal equivalents to all Beaufortian topset plays described previously (Fig. 8). This play concept is based on the recognition of significant sequence-bounding unconformities within Beaufortian topsets and the consequent potential for the presence of sand-prone, deep-water facies in lowstand systems tracts within Kingak clinoforms. This inference is substantiated by the seismic observation locally within Kingak clinoforms of apparent lowstand wedges that pinch out and onlap northward onto sequence-bounding unconformities (Fig. 25). The potential for sandstone-prone facies in lowstand systems tracts is considered to be higher in clinoforms of the K2 (Upper Jurassic) and K4 (Hauterivian) sequence sets and lower in clinoforms of the K1 (Lower Jurassic) and K3 (Valanginian) sequence sets. This inference is based on interpretations of greater relief within the K2 and K4 depositional systems, an effect related to pulses of uplift of the Barrow arch rift shoulder (Houseknecht, 2001, 2002; Hubbard and others, 1987). Nevertheless, all Beaufortian clinoforms are included in this play because (1) the play is highly speculative and (2) there is little data to constrain assessment parameters.
The Beaufortian Clinoform Play extends in a relatively narrow band across the entire width of NPRA (Fig. 26). The northern and southern play boundaries are defined by the most proximal and most distal occurrences of thick clinoforms in Beaufortian strata. The play is wider in eastern NPRA, where significant depocenters occur in both the Upper Jurassic (K2) and Hauterivian (K4) parts of the section (Figs. 3 and 26). The eastern play boundary is defined by the State-Federal water boundary in the Beaufort Sea north of the Colville River delta and by the NPRA boundary onshore. The western play boundary is defined by the State-Federal water boundary in the Chukchi Sea and by the NPRA boundary onshore (Fig. 26).
Stratigraphic traps in the Beaufortian Clinoform Play have not been objectives in exploration wells drilled in NPRA. Several wells in eastern NPRA have penetrated the play, including the Inigok, North Inigok, West Fish Creek, South Harrison Bay, and Atigaru Point. Most of these wells contain little sandstone within Beaufortian clinoform strata, and most yielded minor shows of gas and/or oil within the play interval (Hayba and others, 2002). Just one well in western NPRA has penetrated the Beaufortian clinoform play. The Tunalik penetrated clinoforms in K4 (Hauterivian) and K3 (Valanginian) strata with common gas shows throughout. Most notably, the Tunalik encountered a substantial gas kick near the stratigraphic boundary between the Beaufortian Clinoform Play (this play) and the Beaufortian Cretaceous Topset Play.
The potential for charging the Beaufortian Clinoform Play is summarized in Figure 27. Throughout the play area, the Beaufortian clinoform section downlaps onto and coalesces with condensed mudstones in the lower Kingak Shale. Hydrocarbons expelled from the lower Kingak source rock interval would have a direct and short distance migration pathway into this play, and this is considered the most likely charge scenario. In the southern parts of the play, the Shublik Formation source rock interval may lie directly beneath the Kingak Shale source rock interval, and in the northern parts of the play the Shublik and Kingak source rock intervals are separated by a thin Sag River Sandstone. Therefore Shublik-sourced hydrocarbons also had good potential for charging this play throughout the area.
Across much of the play area, the GRZ source rock interval lies hundreds of feet above Beaufortian clinoform strata, and potential migration pathways would be long and circuitous. However, along the southern margin of the play the GRZ source rock interval (including the pebble shale unit) is draped upon and/or downlaps onto the most distal Beaufortian clinoform (Fig. 27). Farther basinward, the GRZ lies a short distance above the lower Kingak Shale condensed section. Hydrocarbons expelled from the GRZ source rock interval in this distal area would have short and relatively direct migration pathways into the southern parts of this play. Thus, the GRZ source rock interval had good potential for charging this play, especially along its southern margin.
Most of the Beaufortian Clinoform Play lies at levels of thermal maturity higher than the oil window, and therefore the play is mostly gas-prone. However, the northeast portion of the play lies at lower levels of thermal maturity and there is potential for oil preservation in that area.
Little is known about reservoir quality of sandstones in the Beaufortian Clinoform Play, or even if substantial bodies of sandstone occur. Wells that have penetrated the play have encountered sections comprising mostly mudstone and siltstone. The greatest potential for the occurrence of sandstone likely exists in the K4 (Hauterivian) part of the section, where there is abundant evidence of sand-prone depositional systems at the shelf margin, and of shelf-margin collapse features that would have supplied sand to slope and base-of-slope systems. Potential also exists in the K2 (Upper Jurassic) part of the section, where sediment eroded from sequence-bounding unconformities on the shelf during lowstands likely was recycled over the shelf margin to deeper water depositional systems.
Stratigraphic traps in the Beaufortian Clinoform Play are inferred to involve turbidite channel facies incised into marine slope facies and/or a spectrum of sand-prone submarine fan facies. Trap geometries may include updip pinchout of either channel sands or proximal lobe sands deposited during lowstand and sealed by drapes of condensed mudstones deposited during transgression.
The timing of trap development relative to oil generation is excellent in the Beaufortian Clinoform Play. Deposition of Beaufortian clinoform strata across NPRA occurred between ~205 Ma and ~115 Ma. Peak oil generation in the Shublik, Kingak, and GRZ source rock intervals occurred between ~100 Ma in western NPRA and ~90 Ma in eastern NPRA (Burns and others, 2002). Thus, all stratigraphic traps in the Beaufortian Clinoform Play were formed before any oil was 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.
Tables 29 through 31 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. All values are based on interpretations of depositional systems and dimensions of sand bodies that may have been deposited during lowstands.
Area of closure. Values are based on the seismically observed size (in two dimensions only) of lowstand wedges in a few locations in NPRA and on the inferred presence of submarine fan lobes.
Porosity and hydrocarbon pore volume. Values are estimated from knowledge of sandstone characteristics in equivalent topset strata combined with general understanding of the influence of burial depth on sandstone reservoir quality.
Trap fill. The generally high input values reflect a combination of good charge potential and small trap size.
Trap depth. The depth range of potential traps in the play was derived by posting a structure map of the Lower Cretaceous Unconformity over the play map, and then adding an increment for the stratigraphic interval between the LCU and the top of the play. Different values were assigned to oil and gas based on the inference that oil is most likely to occur in the shallowest part of the play and that gas may occur at any depth within the play.
Number of prospects. The values reflect knowledge of the depositional system, small size of inferred sand bodies (area of closure), and large size of the play area (7.9 million acres).
Play probability attributes – Table 30. 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). The probabilities that sufficient charge was available and that timing was appropriate are both inferred to be 1 (i.e., 100%). The potential for charge is excellent as the play downlaps directly onto source rocks in the lower Kingak Shale, and the stratigraphic traps clearly formed prior to the generation and migration of hydrocarbons. The probability that at least one trap (includes reservoir, seal, and geometry) exists is estimated to be 0.9 (90%). The primary reservation regarding trap is whether a sand body of sufficient porosity and size exists within the play area. The resultant play probability (charge probability X trap probability X timing probability) indicates a 90 percent chance that at least one hydrocarbon accumulation of the minimum size occurs in this play.
Prospect probability attributes – Table 30. 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 1 (100%) because of the close relationship between this play and source rocks in the lower Kingak Shale. The trap probability is estimated to be 0.1, primarily because relatively few sandstone bodies are inferred to have sufficient volume to hold 50 million barrels of in-place oil or 250 billion cubic feet of technically recoverable gas, and few sand bodies are inferred to have adequate porosity. The timing probability is 1 because all the traps in this play formed before any hydrocarbon generation and migration in the region. The resultant prospect probability (charge probability X trap probability X timing probability) indicates a 10 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 9 percent chance that a prospect in the play will contain at least 50 million barrels of in-place oil or 250 billion cubic feet of technically recoverable gas. Ten (10) percent of the hydrocarbon accumulations within the play are estimated to be oil and 90 percent to be gas. This estimate is based on the observation that only the northeastern-most part of the play lies at levels of thermal maturity that may be within the oil window. Most of the play is characterized by thermal maturities in the gas window.
Hydrocarbon parameters — Table 31. Recovery factors are based on the inferred similarity of sandstone reservoirs with those in other plays (Verma, this volume). Oil gravity and sulfur content reflects that the lower Kingak Shale is the most probably source rock (Lillis and Magoon, this volume).
The assessment input values summarized in Tables 29, 30, and 31 were used to estimate the petroleum resource potential using methods described by Schuenemeyer (this volume). Basic results are summarized in Table 32 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 Beaufortian Clinoform Play in NPRA is estimated to range between 0 (95-percent probability) and 71 (5-percent probability) million barrels, with a mean (expected value) of 12 million barrels (Table 32). The volume of undiscovered, technically recoverable, non-associated gas in the Beaufortian Clinoform Play in NPRA is estimated to range between 0 (95-percent probability) and 2,180 (5-percent probability) billion cubic feet, with a mean (expected value) of 822 billion cubic feet (Table 32).
The oil and gas resources are estimated to occur in accumulations of various sizes, as illustrated in Figure 28. There is only a small chance that any oil accumulations of the minimum size assessed (50 mmbo in-place) occur in the play (Fig. 28a). One non-associated, natural gas accumulation between 384 and 768 bcf and one accumulation between 192 and 384 bcf are estimated to occur in the Beaufortian Clinoform Play (Fig. 28c). Most of the gas in this play is expected to occur in those accumulations (Fig. 28d).
In addition to volumes of crude oil and non-associated gas, associated natural gas and natural gas liquids are estimated to occur in the Beaufortian Clinoform Play. Those estimates are reported by Schuenemeyer (this volume).
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. The Kingak Shale is divided into four major depositional sequence sets that each display unique stratal geometries and thickness trends. Sequence set K1 (Lower-Middle Jurassic) is a composite of numerous higher-order depositional sequences whose progradation and aggradation through time constructed a clastic shelf in north-central NPRA. Sequence set K2 (Oxfordian-Kimmeridgian) is a composite of at least three higher-order depositional sequences that developed as the result of episodic tectonic uplift along the Barrow Arch during failed rift events. Each higher-order sequence reflects a forced regression, which caused widespread erosion across north-central NPRA and accumulation of the derived sediment at the shelf margin in lowstand systems tracts, followed by flooding of the shelf as the result of a rise in relative sea level, which resulted in deposition of a transgressive systems tract. Sequence set K3 (Valanginian) is a composite of at least two higher-order depositional sequences that display relatively distal facies character, suggesting high relative sea level during most of the depositional history. Sequence set K4 (Hauterivian) is a shelf-margin wedge that developed as the result of tectonic uplift along the Barrow Arch during the rift opening of the Arctic Ocean basin. It comprises lowstand and transgressive systems tracts that display stratal geometries suggesting dynamic incision and synsedimentary collapse of the shelf margin.
Beaufortian 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 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 is in the gas window. Additional charge potential 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 is in the gas window. Additional charge potential also 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.
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 involves mostly stratigraphic traps in sequence set K3 of the Kingak Shale and in the pebble shale unit, in northern NPRA where the play lies entirely within the oil window. The volume of undiscovered, technically recoverable oil in the Beaufortian Cretaceous Topset North is estimated to range between 0 (95-percent probability) and 239 (5-percent probability) million barrels, with a mean (expected value) of 103 million barrels. The volume of undiscovered, technically recoverable, non-associated gas in the Beaufortian Cretaceous Topset North Play in NPRA is estimated to range between 0 (95-percent probability) and 1,162 (5-percent probability) billion cubic feet, with a mean (expected value) of 405 billion cubic feet. Hydrocarbon accumulations in this play are inferred to be small in size and not likely to be a primary focus of exploration activity.
The Beaufortian Cretaceous Topset South Play involves mostly stratigraphic traps in sequence sets K3 and K4 of the Kingak Shale and in the pebble shale unit. The play lies entirely within the gas window in central NPRA. The volume of undiscovered, technically recoverable, non-associated gas in the Beaufortian Cretaceous Topset South Play is estimated to range between 635 (95-percent probability) and 4,004 (5-percent probability) billion cubic feet, with a mean (expected value) of 2,130 billion cubic feet. Gas accumulations in this play are inferred to be moderate in size. No technically recoverable oil is estimated to occur in this play.
Four Beaufortian Upper Jurassic topset plays involve stratigraphic traps within topset seismic facies in the Oxfordian - Kimmeridgian part of the Kingak Shale. The most favorable stratigraphic trapping geometries in all four of these Beaufortian Upper Jurassic topset plays involve lenticular bodies of winnowed, shoreface sandstone deposited during transgression in incised lows on ravinement surfaces or sequence-bounding unconformities and sealed by condensed mudstone deposited during highstand. The four plays were defined in NPRA based on inferred hydrocarbon charge and thermal maturity.
The Beaufortian Upper Jurassic Topset Northeast Play, which occurs in northeastern NPRA, has favorable charge potential and lies entirely within the oil window. This play is the western continuation of the geologic trend that hosts the Alpine oil field just east of NPRA, with announced ultimate oil recovery of 429 million barrels. The volume of undiscovered, technically recoverable oil in the Beaufortian Upper Jurassic Topset Northeast Play is estimated to range between 2,744 (95-percent probability) and 8,086 (5-percent probability) million barrels, with a mean (expected value) of 5,176 million barrels. This play is estimated to include numerous oil accumulations large enough to be developed as stand-alone or satellite fields, and these are likely to be the primary focus of exploration activity in northeastern NPRA. No non-associated natural gas is assessed in this play.
The Beaufortian Upper Jurassic Topset Southeast Play, which occurs in east-central NPRA, has favorable charge potential and lies entirely within the gas window. The volume of undiscovered, technically recoverable, non-associated gas in the Beaufortian Upper Jurassic Topset Southeast Play is estimated to range between 2,053 (95-percent probability) and 9,030 (5-percent probability) billion cubic feet, with a mean (expected value) of 5,137 billion cubic feet. This play is estimated to include numerous gas accumulations of moderate size that may become exploration objectives if natural gas resources become marketable. No crude oil is assessed in this play.
The Beaufortian Upper Jurassic Topset Northwest Play, which occurs in northwestern NPRA, has less favorable charge potential than the Beaufortian Upper Jurassic Topset Northeast Play and lies entirely within the oil window. The volume of undiscovered, technically recoverable oil in the Beaufortian Upper Jurassic Topset Northwest Play is estimated to range between 733 (95-percent probability) and 3,312 (5-percent probability) million barrels, with a mean (expected value) of 1,859 million barrels. This play is estimated to include several oil accumulations that would be considered large enough to be developed as stand-alone or satellite fields if they were located closer to infrastructure, and they may become exploration objectives in the future if infrastructure is extended closer to the play. No non-associated natural gas is assessed in this play.
The Beaufortian Upper Jurassic Topset Southwest Play, which occurs in west-central NPRA, has less favorable charge potential than the Beaufortian Upper Jurassic Topset Southeast Play and lies entirely within the gas window. The volume of undiscovered, technically recoverable, non-associated gas in the Beaufortian Upper Jurassic Topset Southwest Play is estimated to range between 2,008 (95-percent probability) and 9,265 (5-percent probability) billion cubic feet, with a mean (expected value) of 5,220 billion cubic feet. This play is estimated to include several moderate-sized gas accumulations but it is unlikely to become a focus of exploration in the near-term future owing to its remote location and lack of a natural gas pipeline. No crude oil is assessed in this play.
The Beaufortian Lower Jurassic Topset Play involves mostly stratigraphic traps in sequence set K1 of the Kingak Shale, and it extends across much of northern NPRA. The volume of undiscovered, technically recoverable oil in the Beaufortian Lower Jurassic Topset Play is estimated to range between 0 (95-percent probability) and 210 (5-percent probability) million barrels, with a mean (expected value) of 83 million barrels. The volume of undiscovered, technically recoverable, non-associated gas in the Beaufortian Lower Jurassic Topset Play in NPRA is estimated to range between 0 (95-percent probability) and 1,915 (5-percent probability) billion cubic feet, with a mean (expected value) of 793 billion cubic feet. Hydrocarbon accumulations in this play are inferred to be small in size and not likely to be a primary focus of exploration activity.
The Beaufortian Clinoform Play involves stratigraphic traps within clinoform seismic facies in the Kingak Shale, including strata that are distal equivalents to all Beaufortian topset plays described previously. The play extends in a relatively narrow band across the entire width of central NPRA. The volume of undiscovered, technically recoverable oil in the Beaufortian Clinoform Play is estimated to range between 0 (95-percent probability) and 71 (5-percent probability) million barrels, with a mean (expected value) of 12 million barrels. The volume of undiscovered, technically recoverable, non-associated gas in the Beaufortian Clinoform Play is estimated to range between 0 (95-percent probability) and 2,180 (5-percent probability) billion cubic feet, with a mean (expected value) of 822 billion cubic feet. Hydrocarbon accumulations in this play are inferred to be small in size and not likely to be a focus of exploration activity.
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 has played an especially important role 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, the Society for Sedimentary Geology (SEPM), and the Pacific Section 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 Beaufortian megasequence, and none included presentation or discussion of assessment input or results.
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