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Cracking the nut Armstrong Oil’s Stu Gustafson has designed a production system that lowers the cost and environmental risk for North Slope development Kristen Nelson & Kay Cashman Petroleum News editors
Some refer to it as a paradigm shift; others say it is a game changer. Everyone agrees it has the potential of cracking the nut for Alaska’s North Slope in the same way new technology made the North Sea’s oil fields economic to produce in 1971.
‘It’ is a production system for onshore and near-shore that cuts the cost of the drill site almost in half and drops the chance of an oil spill to close to zero, says the architect of the new system, Stu Gustafson, operations vice president for Armstrong Oil and Gas, the Denver independent that attracted Pioneer Natural Resources and Kerr-McGee to Alaska as partners in 2002 and 2003, respectively. Both Pioneer and Kerr-McGee have since drilled exploration wells and announced oil discoveries on North Slope prospects identified by Armstrong.
Lowering exploration and production drill site costs would allow explorers to go after “smaller” fields — i.e. 50 million barrel fields instead of 100 to 300 million barrel fields, a mechanical engineer who has worked closely with Gustafson to fine-tune the production system design told Petroleum News in mid-May.
“With this design you no longer need to find a 100-300 million barrel field on the North Slope. You can look at the 50 million barrel field, which is something the independents can … develop more economically than the majors,” Darcee Adam said. The bonus? When you’re looking for smaller fields, you stand a chance of finding a 300 million barrel field.
Adam, who works for Calgary-based Tri-Ocean Natchiq Engineering, the engineering and technology unit of Anchorage-based ASRC Energy Services, has spent most of his 15-year career designing and supporting drilling facilities around the world, including Europe (North Sea) Russia, Canada and Alaska.
“This (production system) is a game changer …. It changes the whole equation on the North Slope. … We call it cracking the nut, in the same way they cracked the nut at Ekofisk, the first field to be developed in the North Sea, 30-some years ago,” he said. SPIT: Stu’s production in a tank “What got us started on this,” Gustafson said, “was you have to be able to assure people that oil can be safely developed both onshore and offshore with a zero tolerance for environmental incidents.”
He asked himself, what if you just contained the entire drill site? What if you built your development drill site inside tanks? Tanks which would not only prevent a drop of oil from reaching the environment but would contain a larger spill. With pumps so that, in the event of spilled oil, you’d pump it right into the line carrying oil to processing facilities.
When you’re developing resources offshore, you would bring your drill rig and temporary camp — everything you need to drill your production wells — out to the drill site on a shallow-draft barge, slide back the tank lids, drill your wells and tow the barge away and after their productive life, you plug and abandon the wells and remove the tanks.
Gustafson started with hand-drawn sketches, taking his ideas to regulatory agencies for input and direction, including the U.S. Corps of Engineers, the North Slope Borough, the Alaska Department of Natural Resources and the Alaska Department of Environmental Conservation.
He has been showing illustrations of the proposed drill site design to regulators and other North Slope operators for about two and a half months, he told Petroleum News in a mid-May interview.
KISS, the well-known acronym for “keep it simple stupid,” was suggested as a name when Gustafson and Armstrong prepared to apply for a patent, but Linda Gustafson, Stu’s wife, had a better idea. It’s as simple as spitting, she said, so the working name is SPIT, “Stu’s production in a tank.” Smoother, faster, better — and cheaper Initially, Gustafson wasn’t focusing on saving money.
“When you find a way to do something smoother, faster and better, it becomes cheaper,” he said. “In this case, it is an order of magnitude cheaper, not just an incremental, small percentage change.”
But the savings doesn’t affect drilling, which is usually two-thirds of a development project’s costs: “We’re not cutting the cost of the program in half, we’re not cutting the cost of pipelines in half — we’re cutting the cost of the drill site in half,” Gustafson pointed out.
One state official, who preferred not to be identified, said the current North Slope “paradigm” for a near-shore drill site would be “about $29 million. The numbers we’ve been shown suggest Stu’s system will drop that cost to about $12 million. These are rough numbers, but they’re not rocket science. His design is the definition of simple. It’s amazing no one has put this together before.” Truckable modules Another challenge that contributed to the design of SPIT “was that offshore, we didn’t want to have any emissions; we didn’t even want to have any fuel,” Gustafson said.
His new system: “Power for the drill site comes from onshore, with just a back-up generator at the drill site for emergencies.”
He was also looking at the issue of how to provide DEC with “the three C’s: command, control and containment.”
SPIT has “control from an onshore operator — the tanks are remotely monitored from shore, as in the Gulf of Mexico, and the operator can shut in a wellhead from shore. He doesn’t have to go to the tank in the middle of a North Slope blizzard.”
So that’s command and control. “That left containment,” he said. “How do we get immediate response for containment?” Gustafson had initially suggested a barge, but was told it would cost too much. That’s when he started to think of putting the wells in a module, with a lid to control any plume or spray. Modular truckable system The result was a modular system (see illustration): A series of tanks, 51 feet long, 14 feet wide and 14 feet deep, a size that could be trucked to the North Slope.
“Piping will be installed in the tanks before they go north. The lids slide open,” Gustafson said.
Installation? “Five-foot deep holes are dug in the gravel and the tanks are lifted into place.”
What anchors the tanks? “The first thing pipe you put in for a well is conductor pipe, which normally goes to about 200 feet,” he said. “You drive the surface conductor and then fasten it to the floor of the tank. That 200 feet of pipe is the pylon holding the tank in place. They’re our foundation — a stronger foundation than you would ever design.
“You bolt additional tanks on, and flange the piping together from tank to tank with the same flexible high-pressure fittings used on platforms in the Gulf of Mexico,” Gustafson said.
“The drilling rig cantilevers for drilling, and temporary I-beams will be put in place during drilling so the tank walls won’t have to be built extra heavy for the drilling phase of the operation.”
The tanks and lids would be insulated and because the oil would be produced at about 110 degrees, “we do not have to heat trace any lines or insulate the pipelines at the drill site, because they are all inside the tanks,” he said.
There would be heaters, but only for emergency backup.
And because the drilling portion of the operation — drill rig, camp, sewer plant, mud plant and all the pipe — would be on a barge that would leave at the end of drilling, the footprint size would drop “from six acres to three acres,” Gustafson said. What happens if there is a leak? What happens if there is a leak?
Command, control and containment, he said.
“Say well No. 11 develops a leak. We already have command: the operator is sitting onshore, he has visual and heat-sensing cameras so he has a picture — he doesn’t care if it’s a blizzard outside, he can see it. He doesn’t have to get to it. And he shuts it off.
“This is the same technology in terms of command and control” that is used in the offshore platforms in the Gulf of Mexico and the North Sea, Gustafson said.
“And it’s leaking? Where’s the oil going? Down in the tank; and what happens to oil in the bottom of the tank?
“We have drain lines in these tanks, sump lines, and we have a motor over here and it sucks like a bilge pump in a boat, except instead of pumping it overboard, we’re going to put it right back in the pipeline,” Gustafson said.
There is a tank blowout requirement for major spills, but with “three tanks in a row, we already have that tankage on tap, on site — we have that capacity.” Should a spill fill one tank, there are openings at the top of the sidewalls between the tanks, and the oil would flow into the next tank.
And the whole design uses existing technologies, he said. “It’s just combining existing technologies into a single system.” Without spilling a drop Armstrong is involved in “multiple projects” on the North Slope, Gustafson said. “We are trying to capitalize on additional cost savings in terms of repeatability for multiple projects.”
SPIT, he said, works for different gravities of oil, different depths of wells.
“It’s just meant to take a three-phase flow, test it or evaluate and meet the regs and get it to a processing facility,” he said.
“Without spilling a drop.”
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