BP Celebrates 40 Years of Production in Alaska's Prudhoe Bay

At its discovery, Alaska’s prolific Prudhoe Bay was expected to have a 30-year lifespan.

Today – 40 years later – the huge oil field has exceeded all expectations and operators are planning for its next 40 years.

Scott Digert, area development manager of Greater Prudhoe Bay for BP’s resource development team in Alaska, said the continuing success of Prudhoe Bay has come through new technology and increases in efficiency.

Digert and other experts discussed the field’s history and future at a recent topical luncheon at the Arctic Technology Conference.

“(Prudhoe Bay) was originally expected to produce 9.6 billion barrels and was expected to be done in 30 years,” Digert said.

“It’s made 12.6 billion barrels as of this year. The field’s not larger. We’ve been using technology and exploiting our resources better. It’s still producing,” Digert said.

Digert said one point of pride for the company is that, after years of declining production since its peak in the 1980s, operators have “arrested” the decline and held at 280,000 barrels daily for the last three years.

Much of that hinged on using 40-year-old facilities and increasing their efficiency from 75 percent to 80 percent, he said.

“We hope to increase that to 88 percent,” Digert said.

Image Caption

The first commercial use of a C130 Hercules on Alaska’s North Slope. Photos by Gil Mull.

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At its discovery, Alaska’s prolific Prudhoe Bay was expected to have a 30-year lifespan.

Today – 40 years later – the huge oil field has exceeded all expectations and operators are planning for its next 40 years.

Scott Digert, area development manager of Greater Prudhoe Bay for BP’s resource development team in Alaska, said the continuing success of Prudhoe Bay has come through new technology and increases in efficiency.

Digert and other experts discussed the field’s history and future at a recent topical luncheon at the Arctic Technology Conference.

“(Prudhoe Bay) was originally expected to produce 9.6 billion barrels and was expected to be done in 30 years,” Digert said.

“It’s made 12.6 billion barrels as of this year. The field’s not larger. We’ve been using technology and exploiting our resources better. It’s still producing,” Digert said.

Digert said one point of pride for the company is that, after years of declining production since its peak in the 1980s, operators have “arrested” the decline and held at 280,000 barrels daily for the last three years.

Much of that hinged on using 40-year-old facilities and increasing their efficiency from 75 percent to 80 percent, he said.

“We hope to increase that to 88 percent,” Digert said.

“It’s attention to details – planned maintenance,” he said.

Enhanced Recovery

A major factor in operators’ success has been use of the gas in the reservoir, he said.

“Originally, about half the reservoir was gas. Initially, the plan was to take the gas and re-inject it to re-pressure the reservoir,” he said.

Over time, they have developed ways to use the gas not just to maintain the reservoir, but as an enhanced recovery technique, he said.

The gas is used to vaporize residual oil, then a cryogenic gas facility chills and drops out the liquids to be blended back into the oil, he said.

In other areas, one of the largest water-flood recovery project uses 2 million barrels of water day, he said.

“We can alternate between water and gas,” he said. A miscible injectant is used and acts as a very efficient EOR solvent, he explained.

Producers also are “cautiously hopeful” about a possible state-led plan to help develop the gas as a marketable resource, he said.

BP also pioneered development of coiled tubing drilling at the field, greatly reducing costs of access, and the technique is now being employed worldwide.

Improved Seismic

Seismic acquisition techniques also have improved dramatically through the years, from 2-D to 3-D and lately to “independent source and sweep.”

First employed in 2015, BP plans to use the technique this year to shoot the rest of the bay, Digert said.

“What would have taken two to three seasons, we can now shoot i one season,” he said.

The technique provides “a tremendous increase in the amount of data per geophone,” he said.

The data is combined with logging and other information being acquired during various operations.

“We feed all that into a sophisticated model and use it to re-examine targets,” he said.

“We can use it to better tune our forecasts and where we’re drilling.”

40-year Future

While the field once had 400-500 wells, there are now 2,200 – “1,300 active at any given point, 800 of them producers,” Digert said.

Operators decide how to set completion intervals, which wells to stimulate and when to maintain production.

“There’s less drilling, but more well work,” he said.

According to information provided by BP, while production has fallen from historic peaks due to natural decline, Prudhoe Bay remains the third-largest oil field in the United States by proved reserves, behind the Eagle Ford Shale and Spraberry fields in Texas, and a major source of domestic oil production, with current output at approximately 281,800 barrels of oil equivalent per day. In addition, Prudhoe Bay continues to support more than 16,000 Alaska jobs and supplies 55 percent of all Alaska oil production. And over the last four decades, the State of Alaska has earned $141 billion in revenues from North Slope production and development.

Prudhoe Bay is operated by BP in Alaska. The working interest owners include: BP, 26 percent; ConocoPhillips, 36 percent; ExxonMobil, 36 percent; Chevron, 1 percent.

Prudhoe Bay was discovered in 1968 by Richfield and Humble Oil (now ARCO and ExxonMobil, respectively), and confirmed by BP in 1969.

“We are continuing to be efficient and competitive,” Digert said.

“We want to continue to operate efficiently and attract capital,” he said.

“We see a 40-year future ahead of us.”

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