Stinson, East Point Thomson

Off-shore, Eastern North Slope

  • Key Features
    • Stinson #1 Well is within the project area: 3,500’ section of oil & gas shows; Base Eocene Unconf. Sand assigned 150 MMBO probable reserves; Base Tert. Unconf./Pre-Miss. test yielded 430 BOPD (37-51 API), 7-18 MMCFGPD, 520 BWPD under poor hole conditions (700-800 BOPD cleanhole estimate).
    • Point Thomson Unit lies ½ mile to the west.
    • ANWR: USGS study that assigned 10.3 BBO reserves to ANWR identified 6 distinct plays over the project area.
    • Water Depths ± 50’
  • Leases
    • ADL 391374, 391375   (8/31/2016)
    • ADL 391629, 391630, 391631   (5/31/2021)
    • ADL 391374, 391375   (?/?/2022)

Geologic Summary by: D. T. Gross / D. Brizzolara (4/9/2012)

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The Stinson, East Point Thomson Project is comprised of five leases totaling 17,746 acres with an additional three tracts of 10,935 acres acquired in the BS 2011W Sale, giving a project total of approximately 28,681 acres. This acreage is located in Alaska State Waters at depths of +/- 50’ and lies immediately north of the ANWR 1002 Area. The leasehold is centered over the southeasterly plunging nose of the Barrow Arch and is 1⁄2 mile east of the Point Thomson Unit where Exxon made discoveries of both oil (Tertiary Flaxman Turbidites; 75 MMBO; 1975) and gas/condensate (Cretaceous Thomson sand; 300 MMBO, 9 TCFG; 1977). Two additional oil discoveries are located near the Stinson project acreage in the OCS Federal Waters of the Beaufort Sea; Kuvlum (265 MMBO) lies 9 miles to the northeast and Sivulliq (previously Hammerhead; 150 MMBO) lies 12 miles to the northwest. One well has been drilled within the Donkel/Cade leases and was the basis of assigning 150 MMBO of recoverable reserves to the project. The ARCO Stinson #1 well encountered a 3,500’ section of oil and gas shows that were confirmed by conventional and RSW cores, as well as an openhole drillstem test.

In 1990 the Stinson #1 well successfully proved up the potential of two play concepts unique to the North Slope. One is localized upon and within the structural nose of the fractured Franklinian basement (Devonian(?) to Precambrian) where the sandstone and carbonate strata were tested in the open hole from 14,863’ to 15,194’ MD. The DST #1 flowed oil and gas at rates of 430 BOPD (37 to 51 API gravity), 7.1 -18.0 MMCFPD, and 520 BWPD. It was predicted that flow rates would have reached 700 to 800 BOPD under clean-hole conditions had not the test been impeded by shale sloughed from uphole. A younger play occurs in the Lower Eocene sands that were deposited in shallow water shelf to deep-marine environments. A single 100’ sand that is situated directly above the Basal Eocene Unconformity (BEU) and utilizes a combined structural-stratigraphic trap was assigned 150 MMBO of probable reserves in an independent engineering study by PetroTechnical Resources Alaska, LLC (P90: 80 MMBO; P10: 420 MMBO).

Another Tertiary discovery similar to the Stinson BEU Sand had been made by Unocal in 1985- 86 when they drilled two wells in OCS Block 849, 16 miles northwest of the future Stinson #1 well. With Shell as a partner, Unocal announced the Hammerhead prospect reserves to be between 100 and 200 MMBO in Brookian-aged sands despite the oil pool not being fully delineated.

ARCO extended the Hammerhead play concept in 1992 by drilling three wells along trend to the east in OCS Blocks 865 and 866, 11 miles northeast of their Stinson #1 discovery of two years before. The Kuvlum discovery was established when its #1 well flowed 3,400 barrels per day of 34 degree API oil from highly-faulted Oligocene sands. With information from the subsequent
#2 and #3 wells, ARCO placed the recoverable reserves at 160 – 300 MMBO. In 1993, ARCO split the distance between their 1990 Stinson #1 Eocene discovery and their Kuvlum Oligocene discovery by drilling the Wild Weasel #1 midway between the two. The well reached total depth in the Oligocene at 9,324’ MD(TVD) but encountered no commercial hydrocarbons.

ARCO’s final attempt at establishing a Tertiary oil field in the area came when, after forming the Camden Bay Unit, they gave Fairweather E&P a farmout to drill the Warthog #1 well in 1997. The surface location was on the three-mile-limit line of Alaska State Waters, 21 miles ESE from the Stinson #1 well, and the well was drilled directionally one mile to the southwest to reach a total depth at 10,286’ MD (8,602’ TVD). The primary target was Early Oligocene topset beds overlying delta front “shingles” and though sands were encountered, no tests were taken over the few oil shows. The mudlog described these target sands as being medium to very fine grained, friable, and “often deeply invaded by drilling mud”. The well was abandoned and the unit was terminated in 1999 when the leases were relinquished.

The Hammerhead and Kuvlum leases were also relinquished in 1999 when neither Unocal nor ARCO felt that their reserves were sizeable enough to warrant development as stand-alone projects due to the remote location and harsh environment of the discoveries. However, in 2005 Shell acquired the leases encompassing the Hammerhead discovery and had their bids for the Kuvlum leases rejected as being too low ($80,650 per tract). Shell was successful in acquiring five leases on the north and east sides of the tracts containing the Kuvlum discovery wells, as well as 12 leases even further to the east which are located in a group only 10 miles northwest of Kaktovik. In 2007 Shell added to their acreage position by winning 27 leases immediately north of both their Hammerhead and Kuvlum positions. In the same sale, Total acquired 32 leases on the western side of this new Shell acreage position. Shell recently renamed Hammerhead as Sivulliq and proposed two new well locations in the block north of the original discovery well. Additionally, 6 miles further to the northeast, Shell has proposed two more wells, the Torpedo H and Torpedo J.

Approximately 16 miles of pipeline would be required to connect the Stinson Project production to the planned 22 mile-long pipeline between the Point Thomson and Badami fields. An Initial Production System (IPS) timetable was laid out in the recent settlement agreement between the State of Alaska and ExxonMobil which will preserve the Point Thomson Unit. The pipeline connection to Badami will be a common carrier with a 70,000 barrel per day capacity and is slated to begin carrying production by the winter of 2015-16 from two well completions in the Thomson sand, an Early Cretaceous Kemik Sandstone equivalent. The PTU-15 and PTU-16 wells were drilled early in 2009 as part of ExxonMobil’s $1.3 billion development project for the field. The liquid production potential from the two wells is expected to be only 10,000 barrels per day of gas condensate, leaving an excess capacity in the pipeline of 60,000 barrels per day.

The reserves at Stinson will most likely increase with further exploration and delineation drilling. New productive horizons are probable because recent seismic mapping has shown that it is possible to move more than 800’ structurally updip from the ARCO Stinson #1 well location and still be within the Donkel/Cade leasehold. This seismic data clearly shows reflectors indicating a prograding shelf edge of Eocene to Oligocene age with associated foreset and bottomset units which were not encountered by the Stinson #1 well. The oil pay zones in the Flaxman Island (2,507 BOPD; 23 API oil) and Sourdough (100 MMBO) discoveries of the Point Thomson Unit are trapped in similar strata, as are the Hammerhead and Kuvlum discoveries in the OCS waters.

Additionally, the distribution of units similar to the Point Thomson sand that were deposited upon Lower Cretaceous Unconformity surface are not well delineated, especially near the Stinson acreage, and will be better understood as the flanks of the Barrow Arch are further explored. The range in API gravities from the Stinson #1 DST (37 - 51 API) may be the result of the blending of condensate from a “Thomson-Kemik sand” above the LCU (51 API) and of an oil from below the LCU (37 API). At Point Thomson where the API gravities range from 18 to 45 degrees, the Alaska State #F-1 well proved the basement reservoir play to be valid when it tested strata immediately below the LCU at 152 BOPD (35 API) with 3.0 MMCFGPD and the Alaska State #A-1 well displayed great basement permeability with a test that flowed 4,220 BWPD.

A 1998 USGS report on the petroleum potential of the ANWR 1002 Area calculated that 10.3 BBO of reserves were contained in ten plays in this area and the adjacent State of Alaska Waters. The Stinson, East Point Thomson Project overlies six of these plays: 1) The Topset Play, Paleocene to Miocene shelf, deltaic, and nonmarine sands; 2) The Turbidite Play, Paleocene to Oligocene marine slope and bottomset fan sands; 3) The Wedge Play, Eocene shoreface bars, incised channels, and shingled turbidites which onlap and pinchout upon the Base Eocene Unconformity surface; 4) The Thomson Play, Early Cretaceous detrital carbonate clasts derived from Franklinian-age basement rocks and deposited upon the LCU surface as graben to shoreline sands on the Mikkelsen High; 5) The Kemik Play, Early Cretaceous detrital lithic (chert) clasts derived from Ellesmerian-age rocks and deposited upon the LCU as nearshore or estuarial/fluvial sands; and 6) The Undeformed Franklinian Play, pre-Mississippian metasedimentary basement rocks that contain dolostones that have fracture and karst porosity.

Thus, the Stinson, East Point Thomson Project has 150 MMBO probable reserves assigned to its Base Eocene Sand with potential Brookian oil accumulations both above and below it. It also has DST results that strongly suggest the presence of a “Thomson-Kemik sand” condensate accumulation lying upon the LCU with a pre-Mississippian oil accumulation below it.