Technology key to ANS production increases

Alaska’s North Slope has been proving ground for coiled tubing drilling, other technology; new information technology next

Kristen Nelson

Petroleum News Editor-in-Chief

How many barrels was the Kuparuk River field on Alaska’s North Slope projected to produce when it started up in the early 1980s? And how many barrels had it produced as of Jan. 17?

The answer, says Joe Leone, president of upstream technologies at ConocoPhillips, is the same: 2 billion barrels.

But obviously ConocoPhillips Alaska is continuing to produce from the Kuparuk River field—in fact it is Alaska’s second largest producing field, second only to Prudhoe Bay. And the latest report from the Alaska Division of Oil and Gas lists more than 1 billion barrels remaining to be produced from the Kuparuk main reservoir — 1.5 billion barrels when satellite fields are included.

At Prudhoe Bay, where field development in the 1970s originally called for 500 wells: “We’ve already drilled 1,300 penetrations, and plan another 200,” said Tony Meggs, BP group vice president for technology.

“Ten years from now I predict we’ll have another 200 to drill, regardless of all the drilling we’ll do in the meantime,” he said.

Did industry misjudge the fields’ reservoirs when development first got under way?

No, the technology available to develop the reservoirs has changed — and continues to change, both Leone and Meggs said in Anchorage Jan. 23 at the Alaska Support Industry Alliance’s “Meet Alaska” conference, the theme of which was technology.

Leone said a study by Shell found that 80 percent of improvements in upstream production are due to development and application of technology, compared to 20 percent for all other factors. You could argue the specifics, he said, but whatever the actual number is, “technology is actually the biggest driver of performance improvement in our industry.”

Prize is billions of barrels of oil

“For BP,” Meggs said, “the potential prize is 5 billion barrels of oil equivalent.” About 2 billion of that is proven, he said, and about half of it is light oil.

“To transform the potential into production,” he said, BP must continue “to research ways to produce viscous (heavy) oil competitively. And we must move North Slope natural gas to market.”

Promising technology in the viscous area is the “introduction of long, horizontal completions, multilateral wells” and developments which are reducing operating costs and increasing production rates, Meggs said. Viscous production on the North Slope has “nearly doubled” in recent years, he said, and with continued investment, “we believe we can more than triple viscous production by 2010.”

Meggs said areas where technology is improving include: subsurface visualization, drilling efficiency, low-salinity oil recovery and use of polymers in enhanced oil recovery.

Billions to develop new technology

BP will spend “close to a billion dollars a year” over the next five years to develop and test new technology worldwide, Meggs said.

Those technology dollars translate into dollars spent on the ground in Alaska. Meggs said BP completed a $180 million viscous oil project at Milne Point, and the Prudhoe owners will spend $500 million on the Orion project over the next four to five years.

And out in the future? BP is looking at biotechnology, nanotechnology and information technology. On the biotech side, BP is taking a “fresh look” at producing “the elusive bug that gobbles up all residual oil and returns it to the surface.” Nanotechnology could lead to new materials.

The information technology area is more immediate: “advances in computing power, automation, remote sensing and miniaturization are leading to a potential transformation in the way we run oil and gas fields.”

In the future, Meggs said, digital technology could “collect reservoir, drilling, well and facility performance data on a continuous basis.” The result: increased production and reduced costs.

What would it look like? Permanent seismic arrays and other sensors would “provide real-time measurements from the subsurface and surface.”

What is needed? Control over flow down in the well and “the ability to adjust flow to optimize oil production and minimize production of associated water and gas,” and “real-time data on the performance and operational integrity of surface equipment.”

With increased automation, companies would be able to operate facilities remotely.

Meggs said “bits and pieces” of this technology are already in use.

“But we’ll be incorporating the entire package in new developments next year in Trinidad, the deepwater Gulf of Mexico and the North Sea.” He said BP will use the North Slope as a testing ground for components of the new technology.

Faster seismic

Even with clusters of processors, Leone said, it takes five weeks to run a single cycle of processing because the data sets are so large. Technology which should be online the first quarter of this year will cut cycle time to a few hours.

On the North Slope, ConocoPhillips set an extended reach drilling record at West Sak this fall: 11,812 feet drilled in the reservoir.

This translates directly to production he said, with an initial production of more than 5,000 barrels a day, compared to 150 barrels a day for a West Sak well drilled in the 1980s.

“What’s the difference between those two wells? Technology,” Leone said.

More long lateral wells are planned on the North Slope, he said, as well as tri-lateral wells.

And coiled tubing drilling, which was pioneered on the North Slope, now accounts for 60 percent of Prudhoe Bay drilling.

Then there is gas handling.

Natural gas is produced with crude oil and needs to be separated and re-injected.

But there is only so much gas-handling capacity on the North Slope, and gas-handling is a limiting factor in the amount of crude oil that can be produced. The gas-handling facilities are so huge that economics don’t justify additional expansion, he said.

A technology now under development could change all that, by separating gas from crude oil at the bottom of wells.

What is being developed, Leone said is “gas separation and re-injection technology so small it would go down 3 1/2-inch tubing.” There is no guarantee the technology will become commercial, he said, but if development success continues for this sub-surface processing and re-injection, the technology could be employed by 2006.

BP has resource in Alaska, wants continued good business climate

But there is something BP can’t provide, he told the Alaska Support Industry Alliance’s Meet Alaska conference in Anchorage, and that is a good business climate.

BP’s investment in its Alaska business will be more than $650 million in 2004, including more than $200 million in double-hulled tankers.

“And that means we continue to be the state’s number one investor.”

BP’s investment in the four tankers is about a billion dollars, Marshall said, with the first of the new tankers scheduled to enter service this year.

The company will “drill more than 100 new penetrations in fields we operate” on the North Slope, he said, including 19 viscous wells. And while the company hasn’t had any high-profile projects since Northstar, “our focus on drilling generates new production and new state revenues today — not five, 10 or 15 years from today,” he said.

Ongoing investments have resulted in a 13 percent increase in BP’s production over the last two years, a production level the company expects to sustain for several years to come. Over that same two-year period, the company has reduced its “total cash cost by more than 10 percent,” Marshall said.

But while BP sees a “tremendous potential for an extended and stable business in Alaska,” that will require “the right business environment,” Marshall said.

There is “relentless” competition for investment within BP, he said. “Alaska’s remoteness, high cost and complex regulatory environment has very real competitive challenges.”

What does BP see as the right business environment?

Marshall listed having “confidence in the long-term stability and fairness of the fiscal and regulatory climate in Alaska,” changes in the Alaska Pipeline Act “to eliminate ambiguity over the jurisdictional issue and ensure that rules regarding tariffs and other pipeline matters are clear, precise and consistent over time.”

He also said that, before BP can move forward with commercializing North Slope natural gas, “we must have confidence in a strong, sustainable oil business throughout the life of the project. The two are inseparable.”

The reform legislation passed by last year’s Legislature must be transformed “into real streamlined regulations.”

And the company must have confidence in the tax structure that has already “helped to enable the oil industry to invest hundreds of millions of dollars, billions of dollars, in new viscous oil projects with very marginal economics.”

Alpine capacity could be expanded to 135,000 barrels of oil per day, says Meyers

He told the Alaska Support Industry Alliance “Meet Alaska” conference that Alpine facilities, originally planned for 70,000 bpd, were upped in the planning stage to 80,000 bpd, and now the facility handles an average 100,000 bpd, and“hit 118,000 barrels per day” in early January. (See production story page 12 this issue.)

Alpine capacity expansion No. 1, ACX1, begins later this year, adding 5,000 bpd of oil capacity and increasing the facility’s produced water handling.

“In the next few months we expect to sanction our second Alpine facility expansion, that’s called ACX2, and that should start in the 2005 time frame and it will increase the oil production at Alpine to over 135,000 barrels a day,” he said.

That capacity will handle satellite discoveries. “They’re relatively small fields,” he said, but together they add up.

This expansion is the subject of the Bureau of Land Management’s current draft environmental impact statement, and Myers said that it is “not 100 percent guaranteed, but if the economics hold together” it will be the first oil production out of the National Petroleum Reserve-Alaska.

Also investing in heavy oil

“If you look at what technology has the potential to do, we at ConocoPhillips believe by the end of the decade we could increase that heavy oil production … could shift the number up to closer to 100,000 barrels per day, which would be about 10 percent of our North Slope production, so this is an important part of our future on the North Slope.”

The West Sak 1-J drill site, on the west side of the Kuparuk River field, by itself would produce more than 30,000 bpd, Meyers said.

“ConocoPhillips sanctioned 1-J this last December and we’re hoping to see our partners approve it later this year so we can move this project along to development in 2004 and 2005,” he said.