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Right rocks needed in right places for designer wells Alpine is all horizontal wells: already 38 miles of reservoir have been drilled with 66 development wells; field total will be 95; enhanced oil recovery could produce as much as 60 percent of original oil in place Kristen Nelson PNA Editor-in-Chief
What will future North Slope development look like? Not like Prudhoe Bay, says Mike Erwin of ConocoPhillips Alaska Inc. Not even like Kuparuk.
Future development, Erwin told a U.S. Department of Energy-Alaska Oil and Gas Association conference in Anchorage Feb. 27, will look like Alpine.
Erwin, operations supervisor at Alpine, said “applications of advanced upstream technologies in the areas of drilling and production are impacting not only Alpine's development but with it the future of Alaska's North Slope.”
Compare the surface footprint, he said: Prudhoe Bay, built in the early 1970s, had more than two acres of gravel pad per well for an average pad size of 65 acres. The Kuparuk River field, constructed in the early 1980s, reduced the distance between wells from 160 feet to 60 feet and average pad size (for 25 to 30 wells) to 24 acres.
But pad two at Alpine, constructed at the turn of the century, has wells on 10-foot spacing with one-quarter of an acre of gravel per well: 54 wells on 13 acres. Advanced technologies The advanced upstream technologies that have made this possible start with three-dimensional seismic, Erwin said. It allows more effective placement of wells, reducing the number of wells drilled. The “enhanced reservoir resolution pushes engineers to reach ever more difficult targets, improving our recovery of fluids.”
There have also been tremendous advances in directional drilling, he said. Vertical wells through the reservoir were the standard for early development on the North Slope: “if you were drilling through a 50-foot sand, you'd see 50 foot of sand.” Directional drilling technology has changed that, he said, allowing drillers to kick off shallower than the 3,000 feet formerly required and begin to drill laterally.
“We can control tighter and more complex bends and turns. … And we apply directional drilling to horizontal applications to complete wells horizontally out in for formation.”
Such drilling has limitations, he said, including cost and geology.
Vertical wells remain the lowest cost way to drill and are favored for exploration wells.
“Geology is another key. Exotic turns and high-angle builds … can't be accomplished in shales and other fragile formations. So we need the right rocks in the right places” for designer wells. 38 miles of reservoir Today's drillers can also go farther from the drill pad: the current record on the North Slope, a 19,800-foot step-out with a vertical depth of 8,700 feet, was drilled at Niakuk.
At Alpine, he said, one well has a lateral reach of 19,300 feet and a vertical depth of 7,000 feet.
And all of the wells at Alpine are horizontal producers. An early North Slope well would be in the formation for only the vertical height of the formation, but at Alpine, wells run for 3,000 feet through the formation. Sixty-six development wells have been drilled at Alpine, Erwin said, and each averages more than 3,000 feet of horizontal reservoir section.
“That represents 200,000 feet of reservoir drilled or approximately 38 miles,” he said.
Enhanced oil recovery is also a factor in production success at Alpine.
In early oil field development primary or natural recovery would allow production of only about 10 percent of the oil, leading to the drilling of more and more wells, closer and closer together, to increase production.
But at Alpine, Erwin said, producing wells alternate with injection wells which put a combination of natural gas liquids from the crude oil and reservoir gases back into the reservoir, for an expected 60 percent production of original oil in place. The result, he said, is “more production from fewer highly efficient wells.”
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