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ConocoPhillips applies for pilot EOR at Kuparuk River’s Coyote
Kristen Nelson Petroleum News
ConocoPhillips Alaska has applied to the Alaska Oil and Gas Conservation Commission for approval of a pilot enhanced oil recovery project for the Coyote interval in the Kuparuk River unit.
ConocoPhillips drilled the Coyote prospect as a sidetrack from an existing 3S drill site well at Kuparuk at the end of 2021 after it was identified from a review of 2015 3D seismic.
A ConocoPhillips Alaska spokesperson told Petroleum News in May that test results from Coyote were “very successful,” exceeding the company’s expectations and “providing key data to help us better understand the Coyote reservoir interval.”
The company plans to drill a follow-up pair of wells (one producer, one injector) in the same area in the fourth quarter that “will enable us to gather other critical data to help us better plan for a future development of this reservoir from the 3S pad.”
AOGCC application In its Aug. 11 application to AOGCC the company said since the feasibility of injection into the reservoir has not been established this is considered a pilot project which “will aid in determining the commercial viability of developing Coyote as an enhanced oil recovery project.”
The area is in the vicinity of the 3S drill site at Kuparuk, and includes an adjacent lease, ADL 392374, which is held by the Kuparuk working interest owners but is not currently in the unit.
“The 3S-24B exploration well was drilled to understand the ability to produce from the Coyote interval,” the company told the commission. A horizontal producer-injector well pair is planned for the fourth quarter of this year with injection beginning about the first quarter of 2023.
The development design for Coyote is expected to be a line-drive water alternating gas flood with horizontal producers and injectors, the company said, with results from the pilot indicating whether that is the optimal development concept.
“If a commercially viable discovery is established and the development is sanctioned, then CPAI would apply at that time to the AOGCC to establish pool rules and an area injection order,” the company said.
Second injector possible ConocoPhillips told the commission the first injector will be 3S-701 and be 1,000 to 3,000 feet southwest of the planned production well, the 3S-704, with optimum spacing for development of the reservoir still under analysis.
“Completion of the 3S-701 injection well will allow interference and injection testing of the Coyote reservoir to help establish the optimal pattern spacing and potentially support commerciality of the reservoir,” the company said.
A second injection well may be drilled, depending on the outcome of the first injector and its testing, to continue “this long-term injection and production test with a fully supported producer centered pattern centered around the 3S-704.”
The company is requesting a 3-year duration for the pilot to allow time for drilling, testing injector performance, analyzing results of the first injector and potentially drilling, testing and observing and analyzing results of a second injector.
Logs from the Palm 1 well - with a bottomhole immediately west of drill site 3S - were used to define the “gross Coyote reservoir interval” at a measured depth range of 4,270 to 5,115 feet, the company said.
“The Late Cretaceous Coyote reservoir is a thinly bedded, shallow marine, west to east progradational system within the Nanushuk formation,” ConocoPhillips said, with a thickness of approximately 650 feet in the 3S drill site area.
“The interval has been penetrated by numerous wells targeting deeper stratigraphic intervals, both from drill site 3S, and vertical off-ice exploration wells in and surrounding the Kuparuk River Unit.”
Injection The 3S drill site is currently on produced water service, but that could change, and part of the purpose of the pilot is to confirm compatibility, the company said, listing primary injection fluids as:
*Produced water and gas from oil pools within the Kuparuk River unit;
*Beaufort seawater from the Kuparuk seawater treatment plant; and
*Enriched hydrocarbon gas - a blend of KRU lean gas with indigenous and/or imported natural gas liquids.
ConocoPhillips said the proposed Coyote enhanced recovery injection order area is within the scope of an existing aquifer exemption, as the lease not currently in the KRU was part of the unit in 1984 when the Environmental Protection Agency adopted the aquifer exemption and in 1986 when AOGCC incorporated the EPA aquifer exemption.
“Initial reservoir modeling and simulation estimate a primary depletion recovery factor of 5-10%, a cumulative recovery factor from waterflood operations between 20-30%, and an incremental 1-5% recovery for enriched gas injection (EWAG),” ConocoPhillips said.
- KRISTEN NELSON
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