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AOGCC rejects BP plan for Aurora Commission says it will require pressure maintenance Kristen Nelson PN Editor-in-Chief
The Alaska Oil and Gas Conservation Commission has rejected an application from BP Exploration (Alaska) to begin miscible injection at Aurora, a western Prudhoe Bay satellite on Alaska's North Slope, and has scheduled a hearing on rules requiring the company to submit a reservoir depletion plan for Aurora and to maintain a minimum reservoir pressure.
BP applied for a modification of the Aurora area injection order in December, asking to use miscible injectant to enhance recovery. BP also asked for an increase in maximum allowable surface injection pressure from 2,600 pounds per square inch to 2,800 psi during water injection.
The commission held a hearing on the application March 4 and denied the application April 3.
BP Exploration (Alaska) spokesman Daren Beaudo told Petroleum News April 9 that BP, as operator and acting on behalf of itself and its partners, filed an application for modification of the Aurora injection order in December.
“It is our intent to apply miscible injectant on the Aurora satellite field in order to increase production and maximize recovery,” Beaudo said.
The commission filed an amendment to a conservation order he said, “that addresses the issue of development of the field. In doing so they denied our application, leaving the opportunity to reapply, requesting more information in support of Aurora plan of development.”
Beaudo said that BP “will work cooperatively with the AOGCC over the coming weeks to provide data that we expect will eventually result in our ability to proceed with our MI application.
“Our goal is to provide a mutually beneficial conclusion,” he said. Aurora operations Tract operations at the Aurora oil pool began in November 2000 and the commission approved water injection in September 2001. The commission described BP's proposal as “the cyclical injection of water alternating with enriched hydrocarbon gas into the oil column of the Kuparuk River formation” at Aurora. The injectant proposed is hydrocarbon gas enriched with intermediate hydrocarbons and is “designed to be miscible with the reservoir oil,” the commission said.
BP asked to begin miscible injection in the second quarter of 2003 with the conversion of one well; five additional wells would be converted for miscible injectant later.
The commission said the Aurora waterflood uses produced water from Prudhoe Bay Gathering Center 2. With increased surface pressures maximum water injection capacity at Aurora is estimated at 40,000 barrels per day.
The miscible injectant for the proposed project would come from enriched gas from the Prudhoe Bay central gas facility.
Reservoir pressure concerns The commission said BP has estimated original oil in place at Aurora at 110-146 million barrels and 15-75 billion standard cubic feet of free gas. Primary and waterflood recovery was estimated at 30-40 million barrels, roughly 27 percent. Primary recovery only was estimated at 12 percent.
“Additional reserves of 3-5 percent were projected with miscible gas injection, suggesting about 4 million barrels recovery” if miscible injectant was used over the entire Aurora oil pool area, the commission said.
BP testified that the reservoir pressure at which the enriched gas is miscible with the oil in the reservoir is about 2,700 pounds per square inch.
BP said reservoir pressures are about 2,000-2,500 psi in the west block at Aurora, 3,000 psi in the north-of-crest block and 3,100 psi in the southeast-of-crest block.
The commission said its records of well reservoir pressure measurements for 2002 show that some wells in the north-of-crest and southeast-of-crest blocks are below 2,700 psi. It acknowledged that those “pressures may not be representative due to factors such as insufficient shut-in time or inaccurate method of gathering.” Voidage concerns In addition to reservoir pressure concerns, the commission said it also has voidage concerns.
Through Jan. 31, cumulative production at Aurora was 4.6 million barrels of oil, 1.1 million barrels of water and 26.7 billion cubic feet of gas. Water injection from gathering center 2 was 3.9 million barrels.
“Cumulative net voidage is approximately 22 million reservoir barrels, excluding gas cap expansion and aquifer influx,” the commission said. Net voidage rates are 25,000 bpd from the west block, 6,000 bpd from the north-of-crest block and 5,000 bpd from the southeast-of-crest block.
The commission said BP plans to begin water injection of some 10,000-15,000 bpd at the west block soon and has said facilities projects are being “considered” to increase the water source volume for water injection and to increase water injection pressure. Those projects would increase Aurora water injection rates from the current 10,000 bpd to 40,000 bpd.
Wells recommended for testing The commission further said that while BP “testified that reservoir simulation shows reservoir pressure within the west block will be restored to above minimum miscibility by the end of 2003, it is not apparent how this will be accomplished without curtailment of production.”
The commission concluded that Aurora “production and waterflood operations are not being conducted in a manner consistent with the testimony provided in support of” the 2001 conservation order which established pool rules for Aurora and said that if reservoir pressure is not restored, recovery of reserves through miscible injection and waterflood “may be jeopardized.”
The commission is recommending specific wells be shut in for bottom hole pressure measurements to ensure the reservoir is not over depleted. If shut-in reservoir pressure in those wells is below minimum miscibility pressure, the commission said, “further production curtailment should be considered.”
Below miscibility pressure The commission concluded that BP's proposed “project has been represented as a miscible injection project and, as such, it is implied that the reservoir pressure is above minimum miscibility pressure. Measurements suggest reservoir pressures are below minimum miscibility in the west block and possibly within portions of the southeast-of-crest block and north-of-crest block.”
The commission said BP's “current reservoir management strategy is unclear. A comprehensive reservoir management plan is required which addresses water injection and re-pressurization of the reservoir in preparation for miscible gas injection to ensure greater ultimate recovery of the oil” in the Aurora oil pool.
The commission specified the wells where it wants reservoir pressure measurements taken.
In denying BP's application for changes to the Aurora area injection order, the commission said the denial is “without prejudice” to the company's right to renew its application at a later date.
Commission's hearing On April 4 the commission scheduled a hearing “on its own motion” to amend the pool rules order for Aurora, the 2001 conservation order which established how the pool would be operated.
The commission said April 4 that it would consider adding a definition of the Aurora oil pool; revising the metering plan, test frequency and reporting requirements; requiring five wells “to be temporarily shut in for reservoir pressure measurements;” requiring those wells to remain shut in “if the pressure is below 2,700 psi” and requiring BP to submit to the commission for approval “a plan for water injection, re-pressurization, and enriched gas injection.”
The commission is proposing requiring approval of a waterflood program and requiring reservoir pressure to be maintained above 2,700 psi, and requiring submission for commission approval “of a reservoir depletion plan that provides for reservoir re-pressurization to a level that will allow for future miscible gas injection and will ensure a grater ultimate recovery under waterflood.”
The commission hearing will be May 8.
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