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Alaska Oil and Gas Conservation Commission report
ERIC LIDJI For Petroleum News
Beaver Creek unit comingling On July 18, the Alaska Oil and Gas Conservation Commission allowed (Conservation Order No. 726) Hilcorp Alaska LLC to co-mingle natural gas production between the Beluga and Tyonek formations in the BCU No. 23 well at the Beaver Creek unit.
Hilcorp completed the well into the Beluga formation in December 2014 but reported a disappointing initial production rate of less than 350,000 thousand cubic feet per day. An attempt in May 2015 to improve production by adding Beluga formation perforations “did not appreciably add to production from the well,” according to the AOGCC.
In a second attempt to improve performance, Hilcorp now wants to perforate zones in the deeper Tyonek formation while also producing from the existing Beluga perforations.
The current pressure of the Beluga formation at the well is greater than the expected pressure of the targeted Tyonek formation, according to Hilcorp. According to the commission decision, “Any potential for crossflow between the Beluga and Tyonek would be minimized by the low permeability and low productivity of the Beluga.”
Under the terms of the decision, any increase in production from the well during the first year would be attributed to the Tyonek formation. After that, Hilcorp would run a production log at least once a year to accurately allocation production from the well.
Prudhoe Bay monitoring
On July 18, the commission granted (Conservation Order No. 341F.001) a request from BP Exploration Alaska Inc. to amend two monitoring rules at the Prudhoe Bay unit.
The change will allow BP to extrapolate bottom-hole pressure surveys using surface data from water injection wells and to extrapolate gas oil contact monitoring on cased hole logs on active producers using open hole neutron logs required for new wells. The argument is that the maturity of the field challenges the accuracy of the cased hole logs.
“After nearly 40 years of production, the movement of the gas oil contact is well understood and the requirement to conduct repeat cased hole neutron logs on 40 wells in addition to requiring a neutron log on all new wellbores prior to first production does not appreciably add to the understanding of the performance of the reservoir, especially given the suspect results of these,” the commission concluded in its recent decision.
On July 20, the commission corrected the order to reflect the proper numbering sequence of orders for the Prudhoe Bay Oil Pool: Conservation Order No. 341F.002.
Administrative matters On July 20, the commission proposed 14 changes as part of a periodic review of its regulations (Alaska Administrative Code Title 20, Chapter 25). “In general,” according to the commission, “the proposed modifications aim to update and clarify the requirements, improve understanding, and streamline the implementation of the regulations.”
The commission will accept written comments on the changes through the afternoon of Sept. 27 and will accept written and oral comments that morning at a public meeting.
On July 20, Gov. Bill Walker appointed Hollis French to fill a vacant seat on the commission. As reported in the July 24 issue of Petroleum News, the former state senator and oil industry veteran will fill the public seat on the three-member commission. Kuparuk-Torok pool On July 22, the commission granted (Conservation Order No. 725 and Area Injection Order No. 39) a pair of requests from ConocoPhillips Alaska Inc. to define the Kuparuk River-Torok Oil Pool and to allow for injection at the pool for enhanced oil recovery.
As reported in the July 31 issue of Petroleum News, ConocoPhillips is proposing to initially develop the pool from the existing Drill Site 3S using approximately 10 horizontal wells completed with fracture stimulation. But the company indicated it could also develop between one and two additional pads to access other sections of the pool.
According to estimates provided by the AOGCC, a development from DS-3S could access between 100 million and 500 million barrels of oil in place from the Torok formation the unit, and an additional pad could access another 100 million to 300 million barrels of oil in place. The commission estimated a 5 percent primary recovery rate and a recovery rate between 13 and 55 percent using certain enhanced recovery techniques.
CIE challenges fine Cook Inlet Energy LLC has asked the commission to reconsider imposing a $446,000 civil penalty against the company for violations pertaining to the Sword No. 1 well.
As reported in the July 31 issue of Petroleum News, the commission imposed the penalty (Order No. 102) for “numerous regulatory violations pertaining to Sword #1 safety valve system (SVS) and CIE’s failure to provide requested information regarding its SVS compliance policies.” The commission scheduled a hearing for Sept. 13.
An earlier hearing was delayed until a third member was appointed to the commission.
Kenai gas field injections Through a July 27 letter, Hilcorp Alaska LLC asked the commission for permission to dispose of third party Class II eligible wastes in the existing KU 12-17 Class II disposal well at the Kenai gas field. The disposal well is currently operating under rules (Disposal Injection Order 34A) issued to previous operator Marathon Oil Co. in 2009.
The AOGCC tentatively scheduled a public hearing on the matter for Sept. 15.
BlueCrest Alaska Operating LLC and Glacier Oil and Gas Corp. both submitted letters to the commission supporting the proposal. According to BlueCrest, the region around its Cosmopolitan unit includes one solid disposal site and no liquid disposal sites. “The potential cost savings and efficiencies of local disposal may help us to justify additional investments in exploration/development drilling activities in the future as well as helping us maintain good, sound environmental compliance,” Drilling Manager Randy Frazier wrote in a July 15 letter. Glacier Oil and Gas made similar points in its letter of support.
According to a review by Petrotechnical Resources Alaska, previous operator Marathon Oil Co. took preliminary steps to open the well to third part injection back in 2010.
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