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Alaska Oil and Gas Conservation Commission

Alaska Department of Administration, Alaska Oil and Gas Conservation Commission
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AOGCC Pool Statistics
Prudhoe Bay Unit, Pt.McIntyre Oil Pool
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Operator: BP Exploration (Alaska) Inc. Index Map
Discovery Well: Arco / Exxon
  Point McIntyre No. 3
  Permit #189-003
  API No. 50-029-21779-90-00
  Sec. 15, T12N, R14E, UM

Depth: 11,035' MD / 10,483' TVD

March 22, 1988

Status: Producing
Location: Central Arctic Slope Area Location Map Pool Location Map DNR Unit Map
References: List of Orders Summary - Annotated Reference List  
Discovered in 1988 by the Pt. McIntyre No. 3 exploratory well, the Pt. McIntyre Oil Pool lies in the northernmost portion of the Prudhoe Bay Unit. This pool encompasses the Cretaceous-aged Kuparuk River and Kalubik Formations, and it is defined as the accumulation of oil and gas that is common to and correlates with the interval from 9,908' to 10,665' measured depth in the Pt. McIntyre No. 11 exploratory well (later renamed Pt. McIntyre P1-12). An oil-water contact is present and is estimated to lie about 9,070 true vertical feet below sea level, although an oil-water transition zone of varying thickness is present throughout the pool. A gas cap is also present. The gas-oil contact is considered to be planar and to lie at a depth of about 8,580 true vertical feet below sea level. The primary drive mechanisms for production are gas cap expansion and solution gas drive.

Regular oil production began in October 1993, peaked at an average rate of 172,995 barrels of oil per day (“BOPD”) in December 1996, and then began to decline rapidly. Production dropped from 152,000 BOPD in December 1997 to 45,000 BOPD in December 2001. Since then, the production decline has slowed. For the first quarter of 2011, production from the pool averaged about 22,350 BOPD.


In the Pt. McIntyre area, the Kuparuk River Formation is stratigraphically complex. It consists predominantly of sandstone, pebbly sandstone, siltstone and sandy mudstone, and is characterized by rapid changes in thickness, lithology, and local diagenetic cementation. Two informal subdivisions, the lower and upper units, are recognized. The basal portion of the lower unit is tight, non-productive, silty sandstone, siltstone and sandy mudstone that are overlain by about 200 feet of porous, very fine- to fine-grained, well sorted sandstone. The thickness of the lower unit is relatively constant, suggesting it was deposited prior to faulting. The upper unit consists of interbedded, glauconitic, well to poorly sorted sandstone and pebbly to muddy sandstone. Local areas of siderite cementation and compaction reduce porosity and permeability, especially on the western side of the field where cementation forms a permeability barrier that contributes to hydrocarbon trapping. The upper unit is variable in thickness and is thought to have been influenced by syndepositional faulting.

The overlying Kalubik Formation consists mainly of shale and shaly mudstone that also exhibits abrupt changes in lithology and thickness. The oil-bearing portions of the Kalubik Formation are restricted to the western portion of the Pt. McIntyre area.

The Pt. McIntyre reservoir is a faulted, gently north-plunging anticline that is bound to the south by the east-trending, large-displacement, down-to-the-north Pt. McIntyre fault. This fault was the primary control for Kuparuk deposition and preservation. North of the fault, Kuparuk sediments are thick and preserved; south of the fault, equivalent Kuparuk sediments are very thin to absent. Other controls on Kuparuk distribution were paleogeography and erosion truncation. Numerous moderate displacement normal faults cut the reservoirs. Fluid contact and pressure data indicate these faults are non-sealing.

The Pt. McIntyre Oil Pool is trapped by a combination of structural and stratigraphic elements. To the south, the Pt. McIntyre fault juxtaposes reservoir rock against impermeable shale. The northern limit of the pool is established by structural dip. To the west, cementation of the reservoir sediments creates a permeability barrier in the upper portion of the Kuparuk, and to the east, structural dip and diminishing reservoir quality limit the extent of the accumulation.

Average porosity for the Kuparuk River reservoir ranges from 19% to 25%. Average horizontal permeability ranges from 50 to 300 millidarcies in the Upper Kuparuk and 100 to 600 millidarcies in the Lower Kuparuk. Initial water saturation values for the oil column range from 16% to 65% and average 33%. Gas-cap initial water saturation is about 15%. Reservoir oil gravity is 27 degrees API, and the oil viscosity is 0.9 centipoise at the bubble-point pressure of 4,308 psia. The solution gas-oil ratio is 806 scf/stb, and the formation volume factor is 1.39 rvb/stb. Initial reservoir temperature ranges from 176 to 184 deg F at 8800' true vertical depth below sea level.

Structure Map Strat Column Type Log
Production: Prod Chart    

  Oil (bbls) NGL (bbls) Gas (mcf) Water (bbls)
Cumulative 436,327,626 11,159,448 1,066,489,482 641,861,940
2005 Total
11,789,081 843,979 76,821,500 54,820,569
2006 Total
7,735,422 364,374 42,234,112 33,098,499
2007 Total
8,825,993 272,017 52,978,900 41,680,150
2008 Total
9,467,760 425,178 69,036,653 44,943,682
2009 Total
8,443,247 388,265 67,181,806 45,657,559
2010 Total
7,132,607 420,217 60,374,848 43,899,539
2011 Total
6,861,532 414,273 59,097,025 43,584,918
2007 Rate (b/d)
24,181 745 145,148 114,193
2008 Rate (b/d)
25,939 1,165 189,142 123,133
2009 Rate (b/d)
23,132 1,064 184,060 125,089
2010 Rate (b/d)
19,541 1,151 165,411 120,273
2011 Rate (b/d) 18,799 1,135 161,910 119,411
2008 Change (%)
7 56 30 8
2009 Change(%)
-11 -9 -3 2
2010 Change(%)
-16 8 -10 -4
2011 Change (%)
-4 -1 -2 -1

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