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This month in history: Technology key to ANS production increases 20 years ago this month: North Slope proving ground for coiled tubing drilling, other technology; new information technology next
Kristen Nelson Petroleum News
Editor's note: This story first appeared in the Feb. 8, 2004, issue of Petroleum News.
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, 2004?
The answer, said 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 underway?
No, the technology available to develop the reservoirs has changed -- and continues to change, both Leone and Meggs said in Anchorage Jan. 23, 2004, 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% of improvements in upstream production are due to development and application of technology, compared to 20% 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 What does the future hold? And why should the companies keep investing in technology development for the North Slope.
"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 That technology doesn't come cheap.
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 ConocoPhillips is working with technology which will dramatically reduce the processing time for changes in the models geophysicists make as they interpret results of seismic programs.
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% 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.
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