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Vol. 29, No.7 Week of February 18, 2024
Providing coverage of Alaska and northern Canada's oil and gas industry

Leases expired Sept; DOG approval saves them, well winter 2025-26

Kay Cashman

Petroleum News

Retroactive to Oct. 12, 2022, on Jan. 31, 2024, the Alaska Department of Natural Resources' Division of Oil and Gas approved the formation of the Smith Bay unit, encompassing approximately 117,093 acres of state of Alaska oil and gas leases in the shallow waters of Smith Bay north of the National Petroleum Reserve-Alaska.

(See map in the online issue PDF)

Operator Caelus Energy Alaska Smith Bay LLC and other working interest owners commit to drilling an exploration well including a horizontal section and production test during the winter ice exploration season of 2025-26.

The individuals that signed the Smith Bay unit agreement attached to the unit application for the three working interest owner companies were as follows:

*David Pfeiffer, manager, Caelus Energy Alaska Smith Bay LLC (75%)

*David Pfeiffer, president, The Smith Bay Company Alaska Inc. (17.5%)

*David Cruz, managing member, L 71 Resources LLC (7.5%)

Caelus filed the original Smith Bay unit application on Oct. 10, 2022, but the application was not deemed complete by the Division of Oil and Gas until Oct. 26, 2023, following more than a year of negotiations.

All 26 leases (or parts of leases) in the unit expired in September, but unitization staves off the expiration and holds the leases.

In its approval, the division said the potential hydrocarbon accumulation in the Smith Bay unit lies in Brookian turbidite sandstones in the lower Torok formation.

Five wells have been drilled in or near the Smith Bay unit, or SBU.

Early exploration wells

The following three exploration wells were drilled in 1978, 1979 and 1980.

--Drew Point No. 1 (DP-1) API # 50279200020000, was drilled in January-March 1978 by Husky Oil NPR Operations for the United States Geological Society to a total depth of 7,946 feet measured depth, or MD. The well was targeting the Ivishak formation but also confirmed the presence of a low permeability reservoir with hydrocarbon shows in the lower Torok formation. Gas shows were encountered in the Torok sandstones and a drill stem test was taken from 5,848 feet to 5,906 feet MD. No formation fluids were recovered from the test. Core taken over this interval had porosity ranging from 1.4 to 7.3% and permeability from 0.1 to 0.2 millidarcies.

--East Simpson Test Well No. 1 (ES-1), API # 50279200050000, was drilled in February-April 1979 by Husky for the USGS to a total depth of 7,739 feet MD. The primary objective was to test the Ivishak formation, with secondary targets of the Nanushuk formation, Torok formation, and Sag River sandstone. Sidewall core and conventional core were cut for several zones, but only 10 feet were in the Torok formation from 5,120 feet to 5,130 feet MD. No shows or fluorescence were noted in the core. The two core plugs taken from this section had porosity/permeability values of 10.4%/0.2 millidarcies and 11.6%/0.1 millidarcies. Sample recovery during drilling of ES-1 from the lower Torok formation was poor, but no porosity, staining, or fluorescence was observed. Slight gas peaks were encountered while drilling the lower Torok.

--East Simpson Test Well No. 2 (ES-2), API # 50279200070000, was drilled in January-March 1980 by Husky for the USGS to a total depth of 7,506 feet MD. The primary objective was to test the Ivishak sandstone with secondary targets of the Nanushuk and Torok formations and Sag River sandstone. Sidewall cores and conventional cores were cut, including 27.5 feet of conventional core from 6,056 feet to 6,086 feet MD over the Torok formation. Minor shows were detected in the Torok including a small gas kick from 5,710 feet to 5,730 feet MD with no associated stain, cut or fluorescence and a fair gas kick from 6,190 feet to 6,210 feet MD with associated spotty fluorescence and a slight cut in the cuttings. Core porosity ranged from 8.1% to 14.6% and permeabilities were less than 1 millidarcy.

Recent exploration wells

Neither of the following two Caelus Energy Alaska Smith Bay, or CEASB, wells were flow tested.

--Caelus Tulimaniq 1 (CT-1), API # 50879200210000, was drilled in January-February 2016 to a total depth of 7,070 feet MD/6,943 feet total vertical depth (TVD) by CEASB. The primary target was to prove reserves within the Torok formation in the Tulimaniq Fans. No oil or gas shows were found at the wellsite over the zone of interest during drilling. Mass spectrometry and gas chromatography showed indications of hydrocarbon gas associated with liquid hydrocarbons in some zones. In a separate petrography report on the thin sections, analysts saw dark staining in thin sections. When core plugs were placed in solvent, the extract fluoresced milky white-blue, suggesting light, high gravity oil. The Modular Formation Dynamics Tester, or MDT, acquisition program collected two fluid samples from one sampling station, and the fluid collected was primarily water. Core plugs for this well had porosities ranging from 12.4% to 15.3% with an average of 13.3% and permeabilities ranging from 0.051 to 1.26 millidarcies with an average of 0.2736 millidarcies. Pore volume saturation from rotary sidewall routine core analysis were 0% oil and 31 to 72.9% water.

--Caelus Tulimaniq (CT-2), API # 50879200220000, was drilled in February-April 2016 by CEASB to a total depth of 9,390 feet MD/9,029 feet TVD. The primary target was to prove reserves within the Torok formation in the Tulimaniq Fans. Oil shows were seen in the Torok during drilling and were rated as very questionable to fair on the geologists' end of well report. The MDT program collected samples from two sampling stations, and the fluid collected was primarily water. Mud Gas Analysis divided the Torok section into four zones and results showed mostly methane in the uppermost zone, uncertain evidence of liquid hydrocarbons in the middle two zones, and strong evidence of liquid hydrocarbons in the lowest zone. Core plugs for this well had porosities ranging from 8.2% to 15.9% with an average of 13.0% and permeabilities ranging from 0.043 to 2.83 millidarcies with an average of 0.632 millidarcies. Fluid saturations from rotary core analysis were 2.2% to 9.4% Oil and 44.9% to 97.3% water.

Brookian reservoir potential

The Torok formation is part of the early to mid-Cretaceous (Aptian to Cenomanian) Brookian sequence on Alaska's North Slope.

During this time, the Colville basin was filled by major east- and northeast-flowing river systems and their associated coastal plain, shoreline, shelf-edge, slope, and basin floor deposits. These are readily imaged on seismic as large scale clinoform packages with the sand-prone shelf edge deposits imaged as the topset units and the deepwater slope to basin floor fan deposits (Torok formation) imaged as the foresets and bottomsets.

The upper Torok formation is mostly mudstone and siltstone, deposited beyond the shelf edge on the relatively steep upper to mid slope. The lower Torok formation was deposited on the lower slope, toe-of slope, and proximal basin floor and contains turbidite and sediment-gravity flow sandstones.

These sandstones are generally very fine- to fine-grained and well-sorted to very well-sorted. They consist mainly of quartz, chert, sedimentary and metamorphic lithic grains with varying amounts of clay matrix and accessory minerals.

Reservoir sandstones within the Torok formation can be found in lobate geometries produced by submarine fans or in thin, elongate bodies produced by lower slope to proximal basin floor systems.

CEASB has mapped slope basin fan deposits within the SBU using 3D seismic and used information from exploration wells, including mud logs, that recorded hydrocarbon shows in the Brookian interval.

Five-year exploration plan

The water depth in Smith Bay is very shallow with the main area of interest averaging less than 8 feet. The SBU is immediately offshore in state waters and the upland adjacent areas are federal lands located within the NPR-A.

The plan of exploration is a 5-year forecast of planned unit exploration activities. The primary exploration target is Cretaceous (Albian) Lower Torok turbidite sandstones. Other reservoir intervals of potential interest include the Cretaceous Albian "topset" sandstones, the lower Cretaceous Kuparuk "C" sandstones, the Middle Jurassic "Simpson/Kugrua" sandstones, the Triassic Ivishak sandstones, and the Carboniferous Lisburne carbonates and Endicott sandstones.

The initial plan of exploration, or POE, for the SBU represents the working interest owners' current thoughts regarding exploration activities and is based upon the analysis of existing geologic, geophysical and engineering data. As additional information is collected and exploration activities are completed, the POE may be modified to optimize exploitation of identified resources within the unit area. Annual updates and progress reports will be filed with the division.

The Smith Bay unit owners intend to drill and test an appraisal well where commercial flow rates of light oil can be achieved. Because of logistical and time limitations, a location close to shore, in shallow water and in the vicinity of CT-1 where oil saturated lower Torok reservoirs are known to exist, is considered as the best option. The following provisional CT-3 evaluation and well testing plan, is as follows:

Surface location of CT-3: Tl7N-R09W-Umiat Meridian-Alaska, Section 16: 2,459' FNL, 3,750' FEL.

--Drill a pilot hole to approximately 7,500 feet to TD in the HRZ.

--The base plan would be to then drill and complete a 2,200-foot lateral in the Torok reservoir of choice.

--ST-1 to be drilled to a TD of 7,124 feet MD (5,363 feet TVD.

--The well would be fracture stimulated with four mechanical diversion stages.

--Each stage would consist of 200 Klbs., of 20/40 CarboLite at 8 PPA max concentration.

--Kick off with nitrogen lift and coiled tubing assist.

--Estimated flow rates of 2,000 to 3,000 barrels per day.

--Fluid storage estimates on site requires 10,000 barrels.

--A flow period of five days (zero water cut after 48 hours) plus five days of PBU.

--Fluid injection down annulus.

--Well to be plugged and abandoned and all equipment de-mobbed off the ice.

In addition to the test data, the collection of additional reservoir information is a prime objective:

--Collect RSWC samples through the key reservoir intervals.

--Obtain quality log data to be able to calculate a log derived Kh.

--Gather PVT quality fluid data and formation evaluation via production test.

--Calculate PTA derived Kh.

--Compare fluids recovered to previous fluid extract results.

--Determine formation GOR.

The SBU working interest owners have acquired from third parties 3D seismic and 2D seismic over the unit area. Following the drilling of the CT-3 appraisal well in the 2025-26 winter drilling season, the working interest owners will evaluate and consider the reprocessing of certain seismic data to improve their understanding of the prospective reservoir characteristics and parameters.

Best solution

The SBU approval, which was signed by division Director Derek Nottingham, said that "the remote location of the SBU, combined with the difficulty mobilizing equipment to the area, supports unitization. If the application was denied, the leases in the SBU area would likely expire, and it is possible no party would be interested in leasing the area in the future."

--Kay Cashman

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