ConocoPhillips requests pilot EOR from Kuparuk River’s Coyote – September 11, 2022
ConocoPhillips drilled the Coyote prospect as a diversion from an existing 3S drill site well at Kuparuk in late 2021 after it was identified from a 2015 3D seismic review.
A spokesperson for ConocoPhillips Alaska told Petroleum News in May that Coyote’s test results were “very successful,” exceeding company expectations and “providing key data to help us better understand the range of Coyote tank”.
The company plans to drill a pair of follow-up wells (one producer, one injector) in the same area in the fourth quarter which “will allow us to collect other critical data to help us better plan future development of this reservoir from of the 3S tablet.
In its Aug. 11 application to the AOGCC, the company said that since the feasibility of in-reservoir injection has not been established, it is a pilot project that “will help determine the commercial viability of the development of Coyote as an enhanced oil recovery project”.
The area is adjacent to the 3S drill site at Kuparuk and includes an adjacent lease, ADL 392374, which is owned by Kuparuk’s working interest owners, but 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 scheduled for the fourth quarter of this year, with injection commencing around the first quarter of 2023.
Coyote’s development design is expected to be an alternating gas flood with horizontal producers and injectors, the company said, with pilot results indicating whether this is the optimal development concept.
“If a commercially viable discovery is established and the development is sanctioned, CPAI will at that time request the AOGCC to establish pool rules and a zone injection order,” the company said.
Second injector possible
ConocoPhillips told the panel that the first injector will be 3S-701 and will be 1,000 to 3,000 feet southwest of the planned production well, 3S-704, with optimal spacing for reservoir development still underway. analysis.
“The completion of the 3S-701 injection well will allow interference and injection testing of the Coyote Reservoir to help establish optimal pattern spacing and potentially support commercialization 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-centric model centered around of 3S-704”.
The company is asking for a 3-year term for the pilot to allow time to drill, test injector performance, analyze first injector results, and possibly drill, test, observe, and test. analyze the results of a second injector.
Logs from the Palm 1 well – with a bottom hole immediately west of the 3S drill site – were used to define the “Coyote Reservoir Gross Interval” at a measured depth of 4,270 to 5,115 feet, a said the company.
“The Late Cretaceous Coyote Reservoir is a shallow, thin-bedded, west-to-east marine progradation system within the Nanushuk Formation,” ConocoPhillips said, with a thickness of about 650 feet in the 3S drill site area.
“The interval has been penetrated by numerous wells targeting deeper stratigraphic intervals, both from the 3S drill site and vertical off-ice exploration wells in and around the Kuparuk River Unit.”
The 3S drill site is currently on produced water service, but that could change, and part of the pilot’s goal is to confirm compatibility, the company said, listing the primary injection fluids as follows :
*Production of water and gas from oil fields in the Kuparuk River unit;
*Beaufort Seawater from Kuparuk Seawater Treatment Plant; and
*Enriched Hydrocarbon Gas – a blend of KRU lean gas with local and/or imported natural gas liquids.
ConocoPhillips said the proposed Coyote Enhanced Recovery Injection Ordinance Area falls within 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 the AOGCC was incorporated. the EPA aquifer exemption.
“Initial reservoir modeling and simulation estimates a recovery factor from primary depletion of 5-10%, a cumulative recovery factor from water injection operations between 20-30%, and an additional recovery factor of 1-10%. 5% for enriched gas injection (EWAG),” ConocoPhillips said. .
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