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BP to invest $14 billion in Alaska over next 10 years Marshall: ’05 turning point with pipeline refurbishing, Prudhoe wells, tanker fleet Kristen Nelson Petroleum News
BP plans to spend some $14 billion in Alaska over the next 10 years, almost half of that on the company’s oil business, BP Exploration (Alaska) President Steve Marshall told the Alaska Support Industry Alliance’s annual “Meet Alaska” conference in Anchorage Jan. 20.
He said 2005 was “something of a turning point for BP here,” citing the addition of the second and third new tankers to the company’s Alaska fleet, refurbishing of the trans-Alaska pipeline and a commitment “to the biggest refurbishment program for Prudhoe Bay wells in its history, laying the groundwork for the future.”
Marshall said, as BP officials have said before, that the company envisions being in Alaska for another 50 years or more. While the company is no longer exploring for oil in Alaska, it has 5 billion to 6 billion barrels of oil and gas resources in the state yet to be developed, much of that “critically challenged.”
He said he has been asked how the company can have a 50-year future in Alaska without exploration. In addition to working on developing what’s already been discovered, BP is also looking at ways to improve recovery factors from known reserves: A 1 percent improvement in recovery is about 600 million barrels, he said, the equivalent of four fields the size of Northstar.
What would it take to do that? Marshall listed several technologies: moving beyond 3-D seismic to 4-D seismic; looking at carbon dioxide injection; cheaper ways of drilling wells; thermal technologies to unlock heavy oil; ultra-extended reach drilling; and low-salinity waterflood.
BP is “not chasing new barrels through wildcatting” in Alaska, but it is chasing more barrels. Over the past 10 years, he said, “we had five times more success doing that” — making known barrels commercial — than in exploration drilling.
The future: gas, Liberty, LoSal™ — heavy oil Natural gas development will extend North Slope field life, Marshall said. “The life of oil fields will go on way beyond what they might have otherwise done. It causes us to think very differently about our oil business. We have to think in a 50 or 50-year plus kind of vision.”
As for the future of BP’s oil business in Alaska, Marshall discussed three projects.
Liberty is a 150 million barrel field offshore. “It’s arguably one of the best undeveloped reservoirs on the North Slope,” he said.
BP made a decision last year to develop Liberty from shore using extended reach drilling and estimates the project at about a billion dollars, Marshall said.
BP developed Northstar, another offshore North Slope field, as an island and he said regulatory issues around that development were a contributing factor to “a three-times cost overrun” on the project. Drilling Liberty from shore eliminates island, causeway and some environmental and regulatory issues, he said.
The Alaska ERD record is about 19,000 feet or some three miles, set at Niakuk. Liberty is four to eight miles offshore, so wells will be the equivalent of a rig in downtown Anchorage drilling out to Rabbit Creek Road, and hitting a target about the size of a single-car garage, Marshall said.
He said the Liberty project will entail a single pad and require a new rig because there isn’t a rig in Alaska capable of pulling tubing and casing for eight miles. Production will be tied back to either Badami or Endicott. LoSal™ for Endicott BP will be doing a low-salinity waterflood at Endicott (see story in this issue), a first for this BP technology.
BP produces 10 barrels of water for every barrel of oil at Endicott, which is the downside of water in oil fields, Marshall said, while on the plus side, waterflood, along with enhanced oil recovery, can double recovery from a field.
BP is injecting 2 million barrels of water daily at Endicott to help maximize oil recovery.
Marshall said a BP team investigated what would happen if salts were taken out of the water being injected and found “when we inject cleaner, low-salinity water we get up to about a 15 percent” increase in the recovery, an expected addition of some 30 million barrels from Endicott.
The project requires a plant at Endicott and will cost some $100 million.
This is BP’s worldwide test of its LoSal™ technology, Marshall said. “We decided Alaska is the right place to do it and the Endicott reservoir is the best reservoir we could try that on.” He said BP wants to make sure the technology is scalable to other fields, and estimates that when applied to other fields in Alaska it has the potential to add “hundreds of millions of barrels to the producing reserve base.”
The team is in place, he said, and BP hopes to have the project operational in 2008. Heavy vs. viscous oil The main production on the North Slope has been conventional oil. More recently viscous oil has been produced and Marshall noted that it took the industry an investment of three-quarters of a billion dollars before viscous oil, the consistency of molasses compared to an olive oil like consistency for conventional oil, became commercial.
It took new technologies — multi-lateral drilling and jet pumps — to make viscous commercial, and he said the operators are “still encountering significant operational headaches with sand and sand management and the need to add heat to the facilities that weren’t designed for this viscous oil.”
But beyond — and above — viscous oil, there is heavy oil.
Some 20 billion barrels, Marshall said, “about the same size Prudhoe was before we started producing.” This heavy oil, which has the consistency of liquid asphalt, overlies Kuparuk and Milne. It’s just below permafrost, so it’s cold. “And it’s got tremendous, tremendous challenges,” he said.
In Canada heavy oil exists at even shallower depths and without permafrost and there are plans to drill 20,000 wells to access the heavy oil. “We just can’t see that working here,” he said: not 20,000 wells.
Viscous oil is being accessed with multi-laterals, wells with three or more branches off the main well bore.
What if, Marshall asked, in 10 or 15 years drilling technology had developed to the point where 20 branches could be drilled from a single main bore? That would reduce 20,000 wells to a thousand. And those wells produce for 75 years: “They don’t produce a lot; they go on for a long, long time.”
Steam-assisted gravity drainage is used elsewhere in the world to produce heavy oil: Two horizontal wells are drilled parallel to each other and steam is injected into one and oil is produced out of the other. Another method involves injecting steam for six months, allowing it to soak and heat up the reservoir, producing oil for a few months and then flipping back to steam injection. That goes on for 20 to 70 years. “It’s quite a different business from what we do today.”
Today BP is looking at the possibility of an 8 percent recovery rate from the 20 billion barrels of heavy oil on the North Slope, Marshall said, while in Canada they are looking at 50 percent recovery rates.
Three or four years out we could see an Alaska heavy oil pilot project, he said.
But all of these projects are based not on just an oil industry, but on an oil and gas industry. “Some people say we’re not interested in gas: I would say just the opposite — we need gas,” Marshall said.
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