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Explorers 2011: BP: North Slope a ‘technology play’ Argues lowering Alaska’s taxes necessary to make projects in the state competitive with other opportunities Kristen Nelson Petroleum News
BP Exploration (Alaska) hasn’t explored for new fields in Alaska in some 10 years, but the company continues to look for ways to produce more oil from existing North Slope fields.
Appropriate technology is a challenge for developing significant viscous and heavy oil resources, but BP officials have been telling the State of Alaska that the state’s tax structure is also a challenge, putting Alaska projects in an unfavorable position against other opportunities available to the company worldwide.
BP, which opened an Alaska office in 1959 and was an early participant in North Slope exploration drilling in the late 1960s, is the unit operator at Prudhoe Bay, North America’s largest oil and gas field, and at smaller adjacent fields, including some that are part of greater Prudhoe Bay: Lisburne, Niakuk and Point McIntyre. Among adjacent fields, BP operates Endicott and Northstar, both offshore, the former connected to shore by a causeway, the latter an island. To the northwest of Prudhoe Bay, BP operates Milne Point, an onshore-offshore field. The company is also a partner at the giant Kuparuk River field, operated by ConocoPhillips Alaska.
Technology play BP describes its North Slope work on its website as a “technology play.”
The company says the foundation of its North Slope operation “is the development of resources already discovered,” including “world-class recovery of light oil at Prudhoe Bay,” where the recovery rate of oil in place is being raised to some 60 percent (compared to about 35 percent worldwide), using “new technologies such as horizontal drilling, miscible gas injection and gas cap water injection.”
In addition to conventional oil recovery, “BP is now producing relatively heavier, viscous oils, and has begun a pilot project to find ways to tap the vast deposits of very heavy oil” lying just under many of the North Slope’s oil fields, the company said.
BP also has an undeveloped discovery, Liberty, offshore the North Slope in federal waters, where the company plans to drill some of the world’s longest extended-reach wells, some two miles deep and up to eight miles out from a drill site at Endicott. Startup on Liberty has been moved out to at least 2013 as the company works through engineering issues on the rig which was designed and constructed for the project.
Heavy oil test An area where BP has been working technology to produce new resources is in Ugnu formation heavy oil.
Eric West, manager of BP’s Alaska renewal team, told Petroleum News in August that the company’s heavy oil test had a maximum production rate of 550 net barrels of oil per day. Over 117 days of continuous operation since testing started in April, the well produced a total of 45,000 barrels of heavy oil, he said.
With 12-18 billion barrels of heavy oil in the Ugnu formation, it’s a major resource, even if only a small percentage can be recovered.
But BP has yet to determine whether production can be sustained at commercial levels, and has yet to test production from well configurations other than the single well that has been in operation.
The company has drilled four wells for its heavy oil testing, each in a different reservoir zone. Two wells, including the one that has been tested, are horizontal; the other two wells are vertical and designed to test a technique called cold heavy oil production with sand, or CHOPS.
The technique uses an augur-like downhole pump driven by a solid rod passing down the well bore to turn the pump rotor, a spinning rod which over time wears on the steel tubing lining the wells. BP told Petroleum News it had to stop production because the rod had worn a hole in the tubing. The company has been profiling tubing thickness to determine which sections it needs to replace with specially hardened pipe.
Wear on the tubing had been anticipated and one of the test objectives was to determine the rate of wear.
“Actually we got a little more life out of it than we thought,” West said.
New facility BP’s heavy oil test facility, at S pad at the Milne Point field, cost $100 million and was completed in March 2010, but commissioning took nearly a year. West told legislators in March that the facility was “essentially ready to go.”
BP had successfully tested the CHOPS technique in 2008 at a single well on S pad with standard oilfield equipment. The new facility represents a scaling up of the initial test with installation of custom-built heavy-oil production equipment.
West said in March that BP was focused on “proving technical viability.”
On the commercial side, he said that heavy oil needs to be diluted with light oil to move down the pipeline. It could be possible to flow the heavy oil by upgrading it in a North Slope refinery or by heating the pipeline, but West said BP does not view those options as commercially feasible.
“Because of that linkage (with light oil), the time to look at heavy oil is now. And in fact the longer we wait to look at it, the more the light oil declines, and at some point we’re going to curtail the amount of heavy oil we can get off the Slope,” he said.
Tax structure issues Whatever BP does on the North Slope, there are issues of getting funding for projects, which the company says means competing with opportunities available worldwide.
BP Exploration (Alaska) President John Minge told the Anchorage Chamber of Commerce in April that he believes that “oil taxes in Alaska will change because the tax structure that we have today is not competitive and it’s not driving enough investment to our industry here.”
Minge told the chamber BP’s focus in Alaska is not on finding new oil, but on “finding ways to develop the huge volumes that we have already found,” more than 5 billion barrels of resources.
Under a different tax regime a gas partial processing project could be built, he said, removing a production bottleneck at Prudhoe, where liquids production is being constrained by the volume of gas being produced.
Partial process and I Pad work would present some $2 billion in investment, Minge said, adding that he actually sees more than $5 billion in opportunities.
“I see significantly more.”
He said he couldn’t be more specific because not enough engineering had been done on other projects.
“When the higher oil taxes passed, we quit working on those projects,” Minge said.
Talking to the Resource Development Council’s annual conference in November 2010, Minge said that with technology improvements, there are some excellent oil prospects remaining on the North Slope.
He said BP had looked at its track record on viscous oil developments — the resource between conventional light oil and heavy oil.
Referring to the findings of “a fascinating study” within BP, Minge said: “The result of the scoping work is we believe it is possible to develop 2 billion barrels of gross viscous oil with technology advancements that we believe are achievable. A project like this would require on the order of 2,000 more wells on 50 pads with a new gathering center and a hundred miles of new pipelines.”
This viscous development would require surface facilities to handle lower-grade, solids-laden crudes, Minge said, adding that the cost of drilling and well completions would have to be lower.
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