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Providing coverage of Alaska and northern Canada's oil and gas industry
July 2009

Vol. 14, No. 28 Week of July 12, 2009

BP in Alaska: 50 more years in Alaska…

Frank Baker

For Petroleum News

BP Alaska is planning a 50-year future and is continuing on an ambitious course of renewal that could rival everything it has achieved to date.

“Looking forward, our priorities are safe, reliable and efficient operations, managing the light oil decline, renewal of North Slope infrastructure and facilities and unlocking heavy oil and gas, which are immense resources,” says John Mingé, who on Jan. 1, 2009, became BP Alaska’s president, succeeding Doug Suttles. “We have built our workforce and are making the large investments necessary to create a sustainable, long-term future.”

From 2006-08, BP Alaska’s workforce grew by more than 40 percent, to almost 2,000 employees, and its contractor workforce increased by about 2,500, to more than 6,000 jobs. The last time the workforce reached this level was in the 1970s and 1980s, during development of the Prudhoe Bay field.

“BP Alaska has invested about $30 billion over the past decade to manage the light oil decline,” says Mingé.

“That has included drilling 800 additional wells in the Prudhoe Bay field, and developing satellite fields. This year, we’ll invest about $800 million to sustain our Alaska operations — about half of that will be on facility and infrastructure projects that increase safety and reliability.”

Mingé adds that BP Alaska’s Liberty project, currently under way, will push the limits of extended-reach drilling technology to tap an offshore field that contains an estimated 100 million barrels of recoverable oil. Production is expected to begin in 2011.

BP Alaska currently operates 13 oil fields on Alaska’s North Slope (including Prudhoe Bay, Northstar and Milne Point), and owns an interest in six other producing fields, as well as four North Slope pipelines. The company’s 26.4 percent interest in Prudhoe Bay also includes a large undeveloped natural gas resource.

Overall during 2008, BP Alaska produced an average of around 204,000 barrels of oil per day from North Slope fields. Production came from nearly 2,000 wells.

One of BP Alaska’s big resources — heavy oil — presents technical and economic challenges. Around 20 billion barrels of it lie in the Ugnu deposit, a reservoir overlying the Milne Point, Prudhoe Bay, and Kuparuk River oil fields. But it is as thick as molasses and doesn’t flow freely into wells like the lighter oils of Prudhoe Bay, Endicott and Northstar.

BP’s reservoir scientists and engineers estimate that roughly 10 percent of that resource, or 2 billion barrels, could be recovered. A heavy oil production test, part of a five-year testing program, was conducted on the North Slope in August and September 2008.

Gas pipeline progresses

This past April, the formation of Denali — the Alaska Gas Pipeline LLC — by BP Alaska and its partner, ConocoPhillips, got a long-awaited pipeline project under way.

In June 2008, BP Alaska’s Bud Fackrell was named president of Denali, and in the summer other project executives were selected.

Denali is headquartered in Anchorage and a small field office was opened in Tok, near the proposed pipeline route. In the summer of 2008, fieldwork began to support permit applications. The work, done by around 60 people, included cultural resource identification and research, hydrology studies, soil and air monitoring and aerial photography and mapping.

“The fieldwork is a critical step toward meeting the target of a 2010 open season, when buyers and sellers of pipeline space reach agreement,” says Fackrell. “Our prefiling and ongoing communication with the U.S. Federal Energy Regulatory Commission will ensure we progress the project on a timely basis.”

The largest private sector project in North America, if Denali is built it will extend 2,000 miles from Alaska’s North Slope to Alberta, Canada, with a possible 1,500-mile leg to U.S. markets.

The buried, large-diameter, high-pressure pipeline will carry about 4 billion cubic feet of natural gas a day from the North Slope for delivery to Alaska, Canadian and lower 48 markets. At that rate, it will supply around 6 percent-8 percent of U.S. consumption.

At peak construction, the pipeline will require 10,000 workers on the Alaska portions of the route.

Modernizing field infrastructure

BP Alaska is also working on several fronts to modernize its oil field infrastructure. One of these was a two-year project to replace 16 miles of oil transit pipelines in the Prudhoe Bay oil field. Completed at the end of 2008, it includes pig launchers and receivers, anti-corrosion chemical injection facilities and leak-detection systems.

Another major effort, an in-line inspection program using state-of-the-art corrosion detection technology, is also under way. About 140 miles of North Slope pipelines were inspected last year.

Some of the planned Alaska North Slope Renewal (ANSR) projects under the projects directorate organization include consolidating oil and gas separation facilities (called gathering centers) and flow stations, building new power stations, installing more gas handling and water injection capacity, building new worker housing facilities, and constructing flowlines and transit lines. In addition, facilities will be updated with more sensitive safety equipment that automatically detects and responds to gas leaks or fires.

“With ANSR, we’re talking about the potential for investing $5–$10 billion over the next 10 years,” says Gary Boubel, who heads up the projects directorate organization. “These renewal projects easily rival anything done on the North Slope to date.”





Prudhoe surpasses expectations

Further advancements and improvements in drilling technology, reservoir management — aided by advanced imaging techniques — enhanced recovery methods, production operations, communications and control systems, have helped mitigate the effects of the field’s natural decline, which began in 1989.

Prudhoe’s recovery factor today is expected to be more than 60 percent, compared with less than 40 percent when production began in the late 1970s. “At the start of the 1980s, the field was expected to last about 30 years,” says Howard Mayson, BP’s vice president of technology. “There could easily be another 50 years to go,” he adds. “It’s very long-legged, and a lot of that is down to technology.”

Prudhoe’s total recoverable reserves are now estimated at about 13 billion barrels — several billion barrels more than what was envisaged when production started in 1977.

Development of Prudhoe Bay and the transportation system necessary to move its crude oil to market cost more than $40 billion, which includes the recent addition of four modern, Alaska-class double-hulled tankers. To date, more than 1,500 wells have been drilled in the field. Ownership in the field includes ConocoPhillips and ExxonMobil Alaska Production Inc., with about 36 percent each; BP at 26 percent, and others 2 percent. BP operates the field under an agreement reached with partners in 2000 after it acquired ARCO.

—Frank Baker

Alaska gas pipeline gains momentum with Denali

In April 2008 BP and ConocoPhillips formed Denali — The Alaska Gas Pipeline LLC, and got the long-awaited Alaska natural gas pipeline project under way.

In June 2008, BP Alaska’s Bud Fackrell was named President of Denali, and throughout the summer other top Denali executives were selected.

Denali headquarters is in Anchorage and a small field office was opened in Tok, Alaska, near the proposed pipeline route. By the end of the year, a third Denali office was opened in Calgary, Alberta, Canada.

The largest private sector project in North American history, Denali is estimated to cost more than $30 billion. It will extend about 2,000 miles from Alaska’s North Slope to Alberta, British Colombia, Canada, with a possible 1,500-mile leg to U.S. markets.

The large-diameter (48-to 52-inch), high-pressure pipeline will carry about 4 billion cubic feet of natural gas a day from the North Slope for delivery to Alaska, Canada and lower 48 markets. At that rate it will supply about 6 percent to 8 percent of U.S. consumption. Studies of long-term in-state gas needs will begin in 2009 and at least five gas take off points are planned.

Design features: A major component of the project will be construction of a gas treatment plant on the North Slope that will remove carbon dioxide and other impurities. The plant will dehydrate, compress and chill the gas for its shipment through the pipeline. The new facility will dwarf the existing gas facilities, the Central Compression Plant and Central Gas Facility, which are already the largest of their kind in the world.

Most of the chilled pipeline would be buried, while segments through earthquake-prone areas and major river crossings would be built above ground. Above ground portions would be placed on supports similar to those used for the trans-Alaska oil pipeline.

Upgrades of key infrastructure in Alaska will be required, mainly on bridges, highways and ports needed to support heavy loads during construction. The one-inch-thick-walled pipe will be very heavy and loads on highways and bridges will be substantial.

At peak construction, the pipeline project will require 10,000 construction workers.

—Frank Baker

Advancing technology maximizes light oil production

Extracting as much oil as possible from Prudhoe Bay and other mature North Slope fields remains a top priority for BP, ConocoPhillips and others. Using advanced imaging technology, BP remapped much of Prudhoe Bay in 2003, and in 2009 completed more 3-D and 4-D seismic surveys.

New data acquired through these surveys has helped the company reach small pockets of oil through sidetrack wells, which are wells drilled directionally with great precision through existing wellbores. BP drills more than 100 new well penetrations each year and the program has significantly reduced production declines at Prudhoe Bay. As summer comes to the North Slope in 2008, a total of 13 drilling rigs were operating in and around Prudhoe Bay.

A key element of sustaining oil production is developing satellite accumulations around the Slope’s major fields. These relatively small oil pools can be produced from existing facilities and could yield millions of barrels of recoverable oil. New drilling technologies, sophisticated enhanced oil recovery programs and new, innovative well maintenance techniques are coaxing more oil from existing fields.

A collaborative effort among the North Slope producers to drive down costs and add hundreds of millions of barrels of recoverable oil is making significant progress.

—Frank Baker

Alaska heavy oil test yields positive results

A heavy oil production test program on the North Slope in August-September 2008 was an important step toward extracting vast deposits of heavy oil that lie above established fields such as Milne Point and Kuparuk.

Using the cold heavy oil production with sand (CHOPS) technology for the first time in Alaska, the test brought oil and sand to the surface reliably and sustainably.

Production at the Milne Point site to the west of Prudhoe Bay peaked at about 120 barrels a day of a sand/oil mixture before the test period ended Sept. 15. During the course of the test, about 700 barrels of heavy oil — API gravity 10 — was processed at Milne Point and shipped down the 800-mile-long trans-Alaska pipeline.

“Part of the test was to determine if the progressive cavity pump, driven from the surface, could pull sand and oil from the reservoir.” notes Eric West, BP Alaska’s manager of heavy oil. “This clearly worked, and the reservoir formation had characteristics that may sustain higher production rates as testing is resumed next summer.”

The Ugnu reservoir contains roughly 20 billion barrels of oil in place. BP’s reservoir scientists and engineers conservatively estimate that roughly 10 percent of that resource, or 2 billion barrels, could be recoverable — a world-class prize. But it’s as thick as molasses and doesn’t flow freely into wells like the lighter oils of the Prudhoe Bay, Endicott or Northstar fields.

“In the light oil business we try to keep the sand out of the wellbores,” says West. “The CHOPS method has the opposite intent. We intentionally produce sand into the wellbore, and with the sand comes the oil. As sand production continues, channels in the reservoir called ‘wormholes’ will form representing a multi fold increase in the surface area of the reservoir being contacted. At the surface, oil will be separated from the sand in heated tanks and will ultimately be processed by existing facilities and shipped down the trans-Alaska oil pipeline.

“Timing is everything on advancing and deploying this technology,” West adds. “After it’s separated from the sand, the oil is still too thick to flow down pipelines to the refineries. It must be mixed with lighter crudes which serve as a diluent. The use of light oil as a diluent creates a hard link between the existing light-oil business and the potential heavy-oil business. If we didn’t have an established light-oil business all around us it is unlikely that we could make heavy oil work on the North Slope.”

To draw cold, heavy oil, sand and water from 4,000 feet below the ground to the surface, a key piece of equipment called a progressive cavity pump is needed. The pump includes a long metal rod with cavities along its length. As the cavities are progressed up through the pump, sand and oil are pulled from the formation into the wellbore.

Grant Encelewski, heavy oil operations team lead, says the first phase of the CHOPS testing program requires an investment of about $70 million. It includes expanding S-Pad, designing and constructing a purpose-built, long-term test kit, and four new wells. The second phase, in 2009-10, will require an investment comparable to the first phase, and will include further expansion of S-pad, drilling, testing four more wells, and possibly adding more well test facilities.

The 20-person heavy oil team, or HOT, will grow with project success.

Viscous oil is currently under production on the North Slope at about 50,000 barrels per day, primarily from the Schrader Bluff Formation. About 100 million barrels of viscous oil have been produced to date. However, the large, heavy oil resource is colder and much thicker than viscous oil.

Commercial production of heavy oil in Alberta, Canada, comprises both cold and thermal recovery processes. Likewise, North Slope heavy oil development will likely involve both cold and thermal development techniques. BP Alaska is currently testing CHOPS in the field, but thermal field tests are on the drawing board. Thermal recov


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