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Vol. 15, No. 48 Week of November 28, 2010
Providing coverage of Alaska and northern Canada's oil and gas industry

Nikaitchuq heavy, shallow, cold; multiple challenges at new field

Eni Petroleum plans to bring its Nikaitchuq field on Alaska’s North Slope online in December or January. This development includes the first North Slope processing facilities built by a company other than BP or ConocoPhillips.

Eni will send sales-ready crude oil into the Kuparuk Pipeline and from there to the trans-Alaska oil pipeline.

Eni holds 100 percent of the working interest at Nikaitchuq, the company’s Alaska representative and development manager, David Moles, said Nov. 17, which means the company can’t share risk with partners.

“But it also offers an opportunity,” Moles told the Resource Development Council for Alaska’s annual conference, for the company to use “innovative technologies that we’re trying to apply in the viscous oil arena … to make Nikaitchuq a success for Eni.”

The challenge at Nikaitchuq is that it is a marginally economic field based on viscous oil development, Moles said.

Work at Nikaitchuq was begun by Kerr-McGee. Eni acquired a 30 percent interest from Armstrong in 2005, “and we were sitting in the back of the bus, anxious to learn how to do projects in Alaska,” he said.

Then in 2007, Eni acquired Kerr-McGee’s 70 percent interest (Kerr-McGee had been acquired by Anadarko Petroleum in 2006).

Eni plans 52 wells at Nikaitchuq, 26 producers, 21 water injectors, three water source wells and two disposal wells, with 22 wells planned onshore and 30 offshore.

Nikaitchuq has facilities onshore at Oliktok Point and offshore at a drilling island, with the processing facilities at Oliktok Point.

“The facilities that we built are for 40,000 barrels a day notionally of viscous crude and they employ a lot of technology tha t you don’t find in the normal production and processing facility,” Moles said.

Production drilling has begun onshore and the civil work is complete at the offshore drilling pad, including foundations for the modules that will be installed later.

Drilling challenge

Moles said drilling at Nikaitchuq is a challenge because the reservoir is about 4,000 feet true vertical depth with targets at some distance from the drilling pads.

Referring to an illustration comparing vertical depth to step out — the distance from the drilling pad to the target — Moles said “our drillers are going to be doing some world-class wells in a marginal field at very shallow depths to produce cold viscous crude.”

There are about 45 people in Eni’s local office, Moles said, “and for a $2 billion project, that’s not a lot of people; and these guys work selflessly and have done a great job getting us to where we are.”

Eni also has 42 people on the North Slope managing construction.

“And then of course we’re supported by the other 560 contract staff that are up there every day living in our camp, putting the thing in.”

Nikaitchuq will be produced with waterflood, using water from the Ivishak formation and produced water. That Ivishak water is 185 to 200 degrees, Moles said, and will be used for waterflood, but will also be mixed with the crude oil coming back from offshore “because the crude’s about 87 degrees” and for it to move through the subsea pipeline to the processing facility “it needs some energy and some temperature to ensure the flow.”

Heaviest flowline bundle

The flowline bundle between the offshore drilling pad and shore includes an outgoing pipe to take water to the drilling pad, a line for diesel for the rig and cables for power and fiber optic, he said.

When development was being discussed there were some who favored using the natural Spy Island so Eni wouldn’t be putting another island in the Beaufort; others argued that Spy Island should be left in its natural state.

“We chose to keep it off the island and keep it far enough away that we wouldn’t induce any currents that would erode the island,” Moles said.

The offshore flowline bundle was installed in 2008 and the onshore flowline in 2009.

Liquids move to and from the island in a “pipe in a pipe: That helps us with some heat retention and some capability for leak detection,” he said. While the pipe in a pipe “was quite a challenge … it gives us a second barrier to the sea.”

Hot water goes out to the drilling pad in a concrete-coated pipe.

Moles said the pipe bundle to the offshore drilling pad is only 3.8 miles long, not the longest ever installed, “but it’s by far and away the heaviest bundle that’s been installed in the Arctic.”

Well containment shelters

Like Oooguruk, where Eni is a partner to field operator Pioneer Natural Resources, Nikaitchuq has well containment modules, so that any spills during drilling are “captured by the shelters and that liquid can be put back into the system.”

Because Nikaitchuq will use waterflood, Moles said it’s “going to be a large water cycling project.”

The processing facilities are designed to handle 40,000 bpd of crude oil, but will circulate 100,000 to 120,000 bpd of water at peak, water used to “sweep what oil we can out of the reservoirs after the early flow.”

The project includes two grind and inject facilities, a permanent one onshore and a temporary one on the offshore drilling island.

Moles said that initially the facilities will grind and inject cuttings from the drilling rig, “but in the long term, we’re not managing sand downhole; we’re bringing the sand to the surface.”

“Sand’s maybe a misnomer — it’s more like a heavy flour. And that will be accumulated in the process facilities, managed,” and sent to the grind and inject facility to be further pulverized and re-injected, he said.

Offshore next

A rig has been contracted for the offshore drilling pad and that will go offshore next summer, Moles said. Drilling of the offshore wells will continue into 2014.

The offshore drilling pad will have quarters for 120 and power distribution for the wells.

All the wells require electric submersible pumps, he said: “These wells won’t flow without some help. So we have a large power and management distribution component in this development.”

Onshore modules are in place — two large modules built in Louisiana, one the processing facilities and the other the utilities. In addition, Moles said, “we had a very large number of pipe rack and other process modules built here in Alaska.”

All of the offshore modules are being built in Alaska, and those are now being built at local fabrication shops.



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Eni gets Schrader Bluff pool rules

The Alaska Oil and Gas Conservation Commission has issued pool rules for the Schrader Bluff oil pool at Nikaitchuq.

While initial wells are being drilled from a drilling pad at Oliktok Point, the entire Nikaitchuq unit is offshore in East Harrison Bay, approximately centered around Spy Island.

The commission said the Nikaitchuq Schrader Bluff oil pool is the accumulation of hydrocarbons correlating to the interval between the measured depths of 3,530 and 3,867 feet in the Kigun No. 1 well southwest of Spy Island.

The Nikaitchuq Schrader Bluff includes two sands, OA (3,780 to 3,822 feet in the Kigun well) and N (3,627 to 3,663 feet); only the deeper OA sand will be developed initially.

“Four distinct lobe deposits are currently interpreted by the operator, and these lobes are separated by layers of siltstone, calcite-cemented siltstone, or mudstone. The OA and N sands appear to persist through the Nikaitchuq Unit,” the commission said in its Nov. 19 order.

Gross thickness for the OA sand ranges from 30 to 40 true vertical feet.

OA sand

API gravity for the OA sand varied from 16 degrees API to 19 degrees in samples from four wells.

Original oil in place for the OA sand is estimated at 800 million to 930 million barrels, with 4-5 percent (30-45 million barrels) estimated recoverable through primary recovery, and 120 million to 200 million barrels estimated recoverable through primary and waterflood, a total of 15 to 22 percent of original oil in place.

The commission said production over a projected life of 30 years is expected to average some 7,000 barrels per day, with a peak production rate of about 28,000 bpd and 2.2 million cubic feet of gas per day early in the project life.

The N sand reservoir is estimated to contain between 300 million and 600 million barrels and “may be developed later depending upon drilling results,” the commission said.

Twenty-six production wells are planned, with the horizontal sections of the wells ranging from 4,000 to 8,500 feet within the reservoir. Producers will alternate with injectors “in a line-drive flood pattern flanked by outboard production wells.”

—Kristen Nelson