The $5.6 billion sale of BP’s Alaska business to Hilcorp demonstrates a growing trend and the differing strategies of the majors and private oil and gas players, industry observers say.
“BP was a pioneer in Alaskan drilling and one of the key players in building the Alaskan oil industry, including drilling … for the massive Prudhoe Bay field in the 1960s and participating in the Trans Alaska Pipeline in the 1970s,” Enverus’ senior M&A analyst Andrew Dittmar was quoted as saying in press reports. “Their exit and replacement by Hilcorp marks a changing of the guard for the Alaskan petroleum industry.”
“In departing Alaska, BP is choosing to focus on higher growth opportunities elsewhere, including in U.S. unconventionals,” Dittmar said. “The company made a major commitment to growth in U.S. shale by acquiring Permian, Eagle Ford and Haynesville assets from BHP for $10.5 billion in 2018. That value is being offset by this sale and a U.S. Lower 48 divestment program that targets the bulk of BP’s assets outside of its three key growth shale plays.”
Wood MacKenzie analyst Rowena Gowen said BP is not the only major divesting mature assets.
“The majors are making progress with their divestment campaigns. This will mean long-held assets and territories will be let go. BP made such a deal today with its sale of all U.S. Alaska assets to privately-owned Hilcorp,” Gowen said.
BP CEO Bob Dudley said Aug. 27, “We are steadily reshaping BP and today we have other opportunities, both in the U.S. and around the world, that are more closely aligned with our long-term strategy and more competitive for our investment.”
Hilcorp CEO Greg Lalicker said that the Alaska acquisition fits into the privately owned independent’s strategy: “Hilcorp has a proven track record of bringing new life to mature basins, including Alaska’s Cook Inlet and the North Slope.”
Myers’ thoughts on dealWeighing in on Hilcorp’s agreement to purchase BP Exploration (Alaska) and its assets, Mark Myers, a former commissioner of the Alaska Department of Natural Resources and former director of the U.S. Geological Survey, told Petroleum News Sept. 11, “it’s not unusual to see a transition to smaller companies as assets mature. It’s part of the evolution of the core infrastructure on the North Slope.”
An “advantage” with Hilcorp, Myers said, is that “through its operation of the adjacent Milne Point field, it has shown it can introduce new technological approaches and investment that economically increase production.”
“Hopefully, Hilcorp will have the opportunity to operate as they did at Milne Point and increase production, especially with the expansion of viscous oil and extension exploration and development,” he said.
On the downside, he noted, “an operation the size of Prudhoe will stretch a company the size of Hilcorp and likely will mean fewer jobs on the North Slope and less corporate income tax for the state.”
One other issue Myers raised is “what the state will need in bonding, and what guarantees Hilcorp can give the state. The state will have to carefully review Hilcorp’s balance sheet and not fully release BP from its obligations for long term field asset abandonment, removal and restoration.” (The deal between Hilcorp and BP is subject to state and federal regulatory approval, so the state will have an opportunity to address these and other possible issues.)
“One other question that should be looked at is,” Myers said, “how is facility sharing going to work on the North Slope with BP gone? Will facility infrastructure sharing agreements change?”
Billions of barrels left at PrudhoeHow much oil is left in the Prudhoe Bay field for a new operator to pursue?
According to a recent Wood Mackenzie report, the remaining Prudhoe reserves include more than 13 billion barrels of oil and condensate, 1 billion barrels of natural gas liquids, and an expected 23 trillion cubic feet of natural gas.
When Prudhoe Bay went into production in 1977, the initial estimated ultimate recovery was 9.6 billion barrels of oil. To date, however, it has generated more than 13 billion barrels of oil. According to BP, a bit more than 1 billion barrels of producible oil remain in the field, excluding most of the Put River formation liquids.
At first, field reservoir pressure was high and there was a 600-foot oil column but production over the years has lowered the pressure, Fabian Wirnkar, BP vice president for reservoir development, said in an October 2018 presentation.
Waterflood and gas injection have been used to sustain reservoir pressure to levels where oil production can continue.
BP recycles and reinjects about 8 billion cubic feet of gas per day through the Prudhoe reservoir, without which the field would no longer produce any oil, Wirnkar said.
Put River formation recoveryIn addition to infield exploration for untapped pockets of oil using 3D seismic, BP has been looking to capitalize on known but difficult to produce reserves in Prudhoe’s initial participating area, or IPA, by developing creative production techniques based on data analysis and advanced technology.
The company obtained Alaska Oil and Gas Conservation Commission approval in late 2018 to allow for commingled downhole production for wells completed in both the Prudhoe oil pool and the Put River oil pool which overlies the main reservoir. The ruling allowed production of some 6.9 million barrels of oil in place in the IPA’s Put River formation, which would otherwise be stranded.
Put River consists of three lobes - Central, Southern and Western - with a fourth lobe, the Northern, in hydraulic communication with the Prudhoe oil pool. The Southern lobe of Put River has had production since 1999 with an active waterflood.
The Central lobe contains an estimated 1.1 million to 2.7 million barrels of oil in place and the Western lobe about 69.6 billion to 104.4 billion cubic feet in place with a condensate yield of approximately 40 barrels per million cubic feet, and a condensate in place value of between 2.8 million and 4.2 million barrels of oil.
AOGCC said several wells penetrating the Prudhoe and Put River oil pools would be candidates for downhole commingling, which “should allow for increased flowrates and flow velocity in the tubing and reduce the potential for the hydrate deposition that is problematic in production from wells completed solely in the (Put River pool). Since standalone production of the Central and Western lobes is not viable due to hydrate deposition those reserves are essentially trapped. Commingling … will allow these resources to be recovered.”
Myers: North Slope not matureMyers, a geologist, has been saying for years that a lot of oil was missed or ignored on the North Slope in the first waves of exploration. The oil province, he said Sept. 11, should no longer be viewed a mature basin.
“The size of the Nanushuk discoveries is another demonstration that the North Slope shouldn’t be classified as a mature basin. The new oil resources that are under development will lead to a significant increase in North Slope production,” he said, referring to new Nanushuk developments by Oil Search and ConocoPhillips.
There are other parts of the Slope that have potential for similar large-scale stratigraphic traps to that of the giant Nanushuk discoveries west of the central North Slope, Myers said, noting that USGS and other assessments indicate “a very significant remaining undiscovered oil and gas endowment.”