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AOGCC issues pool rules for Rendezvous Second pool, after Lookout, to come online in National Petroleum Reserve-Alaska; will produce from Greater Mooses Tooth 2 pad Kristen Nelson Petroleum News
The Alaska Oil and Gas Conservation Commission has issued pool rules and an area injection order for ConocoPhillips Alaska’s Rendezvous pool, which the company is developing from Greater Moose’s Tooth Pad 2 in the National Petroleum Reserve-Alaska. The GMT2 pad is in the Greater Mooses Tooth unit; the Rendezvous pool also extends into the Bear Tooth unit to the west. The company has been producing from the Lookout pool at GMT1 since 2018. AOGCC said Rendezvous is west and south of Lookout.
The Rendezvous A exploration well penetrated the accumulation in 2000 with five additional exploratory wells drilled over the next few years by ConocoPhillips (Rendezvous 2, Spark 1A, Moose’s Tooth C, Spark 4 and Carbon 1) and Altamura 1 drilled by Anadarko Petroleum.
AOGCC said Rendezvous 2 and Altamura encountered black oil; Rendezvous A, Spark 1A, Spark 4 and Carbon 1 encountered gas columns with condensate in the gas.
The commission said ConocoPhillips proposed defining the accumulation as hydrocarbons common to and correlating with the Rendezvous 2 interval from measured depths of 8,229 feet to 8,393 feet (equivalent to minus 8,104 to minus 8,268 feet true vertical depth subsea), late Jurassic-aged sediments subdivided to Alpha C and D intervals.
Volumes The gas-oil contact is estimated at minus 8,108 feet TVD based on testing in the Rendezvous A and Rendezvous 3 wells. Oil was established down to minus 8,450 feet TVD in the Altamura 1, the commission said, with no exploratory or development wells drilled in the Colville River unit to the east or within the Greater Mooses Tooth unit encountering an oil-water contact in Jurassic-aged reservoirs.
The API gravity of the oil is 37.2 degrees, with original oil in place estimated at 300 million to 460 million stock tank barrels, primary recovery estimated at 20% of OOIP, 60 million to 92 million barrels, and primary plus waterflood plus enriched gas estimated at 35-60% of OOIP, or 105 million to 276 million barrels.
Gas cap resources are estimated at 1.7 trillion cubic feet to 2.8 tcf with condensate yield at 30-60 barrels per million standard cubic feet and condensate in place estimated at 51-168 million stock tank barrels.
“Project screening data and costs estimates indicate that a standalone processing facility for the ROP is not feasible and that the only viable option for development at this time is to send unprocessed production from the ROP to the Alpine Central Facility (ACF) in the CRU for processing and sales conditioning. The ACF has no free-gas handling capacity so it is not feasible to attempt to produce the gas cap to recover the condensate reserves,” the commission said.
Development Development from GMT2 will be with 36 horizontal wells split evenly between producers and injectors, the commission said. Pilot holes may be drilled before drilling horizontal wellbores. An additional 12 extended reach wells may be drilled, again split roughly between producers and injectors. “Potential ERD wells will depend, in part, on drilling results and performance of the initial wells,” the commission said, and the ERD wells would extend development to the east and west.
The commission said all wells would trend northwest, with two rows of wells in the western part of the development area, a northern bank of 14 wells drilled from southeast to northwest and a southern bank of 13 wells drilled northwest to southwest, with producers alternating with injectors “to form a line-drive enhanced oil recovery (EOR) project.”
A single row of nine wells is currently planned in the eastern development area.
“Northern wells beneath the ROP gas cap will be drilled near the base of the reservoir to minimize the risk of gas coning,” the commission said, with hydraulic fracturing programs in those wells designed to avoid fracking into the gas cap.
Development drilling has begun Drilling at GMT2 began in the second quarter of the year with primary drilling expected to continue through the end of 2024; ERD drilling might occur later, the commission said.
GMT2 construction took place over two construction seasons, with final installation of facilities and pipelines this year and first production and injection expected in the fourth quarter, ConocoPhillips told the commission at a May pool rules hearing.
The reservoir will be developed as a water- and water-alternating-enriched-gas-injection enhanced oil recovery project, with production and injection balanced to maintain reservoir pressure at or near the original measured pressure, preserving reservoir energy and increasing ultimate recovery, the commission said.
Fluids authorized for injection include:
*Source water from the Kuparuk seawater treatment plant;
*Produced water from the Alpine Central Facility;
*Enriched hydrocarbon gas from the ACF;
*Lean gas from the ACF:
*Tracer survey fluids to monitor reservoir performance;
*Fluids used to improve near wellbore injectivity;
*Fluids used to seal wellbore intervals which negatively impact recovery efficiency;
*Fluids associated with freeze protection;
*Standard oilfield chemicals; and
*Small amounts of Class II fluids, mixed with source or produced water including sump fluid, hydrotest fluid, rinsate generated from washing trucks, excess well work fluids and meltwater collected from well cellars.
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