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20 Years Ago This Month: Coming on strong
Northstar reservoir performance excellent; BP brought field on slowly to allow pipeline to warm up; production intermittently reduced by facility startup issues Kristen Nelson Petroleum News
The wells at Northstar are coming on at high rates of production, which is just what BP expected, says Fritz Gunkel, BP Exploration (Alaska) Inc.’s Northstar delivery manager.
“We’ve had wells come on at 24,000 barrels a day,” he said, and Northstar has had wells among BP’s top 10 producers worldwide.
Northstar produces from the Ivishak reservoir, the same reservoir produced at Prudhoe Bay, “and so these wells produce very strongly. They’ve really done just what we expected them to do,” Gunkel said.
Production began Nov. 1 with two wells and BP will continue to drill with 15 producers, six injectors and a solid waste disposal well planned by the time drilling ends in 2004.
BP drilled a few wells in 2001, Gunkel said, and then took a break while the production facilities were put in place. During that break BP evaluated the drilling on the initial wells.
And found a way to make the wells easier - and faster - and cheaper - to drill.
One more casing string “What we’ve basically done is we’ve run one more string of casing than we used to,” Gunkel said: “Just drilled the hole in a little bit smaller sections at a time.”
The initial wells had surface casing set and then were drilled in a single hole all the way down to the top of the producing Ivishak formation; once the Ivishak was drilled a liner was run.
The additional casing, called a drilling liner, “is something that we don’t run anywhere else on the slope,” Gunkel said. The drive in Alaska has been for “fewer casing strings and smaller casing strings,” he said. Steel is costly, and “when you add a casing string you run more steel and it takes a while to install each casing strong.”
Either well design provides absolute control at the surface, Gunkel said, and once the drilling liner is in place the producing interval can be drilled without the risk of shales falling apart in the upper part of the hole and the drill getting stuck.
It takes about four additional days to get the drilling liner into place but BP recovers “way more than that with the pace” of drilling the drilling liner allows, he said.
Faster drilling with liner The common measure for drilling speed is days per 10,000 feet.
“And we’re drilling wells at 16 days per 10,000 feet right now. When we were starting out we were drilling wells at more like 24 days per 10,000 feet,” he said.
“So it really pays for itself.”
Gunkel said the change in drilling took “some really good engineering and some courage on the part of people like Floyd Hernandez, who stepped forward and said, hey, we’ve got a problem: I’ve got a solution. It’s a counter-intuitive solution, but it’s the right solution. And then made it stick.”
And the end result of that faster drilling is reduced drilling costs: a savings of about a million dollars per well.
Fiber optics, extra tubing
The Northstar wells are also being completed with new technology: a fiber optic cable down the side “that monitors the bottom hole pressure and temperature while we produce,” Gunkel said. While fiber optics are used in all kinds of applications, this is one of the first five applications of this particular technology in the world, and “appears to be working very well.”
“So not only do you see surface performance, but you also see what the reservoir is doing. It’s actually a reservoir engineer’s dream, to be able to monitor this all the time,” he said.
Warming the pipe slowly Production was planned to begin slowly, Gunkel said, to allow the temperature of the subsea pipeline, the first in the Beaufort Sea, to rise gradually from 40 degrees Fahrenheit at the beginning to a planned operating temperature in the low 90s.
“It was very carefully laid and buried and very carefully surveyed at its initial installation,” Gunkel said. “And then we’ve gone back and resurveyed it using what’s called a geo-pig, a navigational pig, to verify its movement as we heated up the line.”
The key thing that impacted Northstar production was the need “to very gradually heat up our pipeline operating temperature… to gradually thaw the subsea sediments around that line and also gradually heat that line so it lays nice and straight in the trench while it’s heating up,” he said.
The crude oil comes out of the ground at more than 100 degrees F and was initially cooled to 40 degrees F in the plant before going into the pipeline.
Gunkel said “the primary cooling process is just an overgrown version of a car radiator with a set of piping that has cold air blown past it to cool the line.” This is similar to cooling systems in many plants, he said, “the thing that’s unusual about our requirements is we had to cool it off so much and we have to be so rigorous about the temperature that we move the oil through the line.”
The warm up period took some six months, Gunkel said, from November to June.
Up and down production The biggest challenges at Northstar have been at the production facility, “but it’s really a combination of the plant’s startup behavior and how we’ve chosen to manage the air emissions from the island,” Gunkel said.
“We were permitted to do a tremendous amount of production flaring,” he said, something which is standard at startups not just in Alaska but all over the United States.
“But what we’ve chosen to do is limit our production flaring to just the amount required to keep that subsea pipeline warm. So when we experience an interruption in our gas compression system that doesn’t allow us to re-inject gas, what we’ve done is curtailed production dramatically.”
With normal production and injection, the only flare that’s burning at Northstar is just the pilot, Gunkel s aid.
“If we went to flare with full production at Northstar, we’d be flaring 150 million standard cubic feet a day.
“What we’ve chosen to do, rather than continue producing, when we’d be liberating all this gas, is curtain our production down to about 10,000 barrels a day or less - that keeps our subsea pipeline warm…”
Compression problems temporarily slow production The general production trend at Northstar has increased as wells have been drilled and added to production. But there have been downward dips in production, and the big dips “are associated with gas handling problems, mostly compression problems.”
Northstar has had problems with both high-pressure and low-pressure compressors.
Production reached 76,000 barrels a day for the first half of July and then was curtailed July 16 due to a gas compression problem, Gunkel said.
The original design at Northstar was for 65,000 bpd, “BP invested a few million more dollars to debottleneck it to 72,000 a day before we started up,” Gunkel said. The 76,000 bpd average for the first half of July he credits “to the cumulative effect of all the problems we’ve solved in the past plus some terrific operations by our people in the field.”
Production is generally on the incline, he said. “We’ve been learning and we’re getting longer and longer runs of uninterrupted production.
“We are solving our compression problems and it’s taken some really fundamental problem solving, but we are solving them.”
Production for this year is expected to average some 60,000 barrels a day.
Base development 22 wells There is room on the pad for more than 30 wells, but Gunkel said the plan is to drill 22: 15 producers, six injectors and a solid-waste injection well.
“Our base plan is that we will be done drilling in 2004,” Gunkel said. “Now if we accumulate this better performance (from the addition of the drilling liner), we may beat that, we may get done before that.”
Northstar continues to add wells to its production capacity until June, “when we stop drilling into the reservoir… And then starting in November we’ll go back in, finish the production hole section in these wells and put them on production.”
Drilling between June and November is the top three-quarters of the wells, “and the last quarter we’re saving until we get out of the seasonal drilling restrictions.”
What’s next? Production is generally on the incline as more wells are drilled and compression problems are solved.
There are seven wells in production and BP plans to complete the rest in 2004. Things will change at Northstar once drilling is finished.
“Northstar is at its very busiest time right now,” Gunkel said. “We’re doing troubleshooting in the plant. We’re drilling wells. We’re still doing some construction activities out there.”
The key issues have been identified in the production facility, Gunkel said, and because the project team planned for backup equipment for the isolated location, those problems have been easier to resolve.
“We had a failure in a major piece of equipment that most operations wouldn’t have had a spare - we had it. We did something in a few weeks that would have taken months without the spare.
“And that all comes down to Pete Flones and his team that came ahead of us having the shares in place.”
The other think that has helped, he said, is that many of the operators at the field worked on the plant on the Kenai during the assembly phase, “so they know this plant from the perspective somebody that helped build it.
“And that’s been a huge help to us.”
Gunkel said BP is looking very carefully at what else could be done from the island.
BP went into the project “with a pretty clear picture of what we were going to be developing, because there were eight delineation wells drilled around this area before we built the island.”
One thing that is of interest, he said, is the Kuparuk zone above the producing Ivishak reservoir. The Kuparuk is gas-filled at Northstar, Gunkel said.
Right now Northstar is importing gas from Prudhoe Bay “to make up for the voidage we create with our production.”
The Kuparuk formation “could be developed,” Gunkel said, “and also you could blow down the reservoir, remove the gas that we’re using for pressure support right now.”
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