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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