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ExxonMobil in Alaska: Kuparuk goes online Dec. 13, 1981 Getting there is half the fun — or challenge — could have been field’s motto Petroleum News
The Kuparuk oil field was discovered in 1969 when Sinclair Oil and Gas, which would soon become part of ARCO, and BP drilled the Ugnu No. 1 well, which tested 1,056 barrels per day of oil from the Kuparuk formation.
The well was named after the nearby Ugnuravik River. That name is carried today by the shallowest and most viscous of North Slope oil formations.
Compounding the confusion, Kuparuk delineation wells were called “West Sak,” another shallow formation, although they were Kuparuk formation wells.
The discovery was a surprise and led to a reevaluation of the area’s geology.
1979 development begins Although Kuparuk was discovered in 1969, shortly after Prudhoe Bay to the east, it wasn’t until early 1979 that ARCO announced it was proceeding with field development.
The initial drilling and development program, for the first processing facility, associated drill sites and pipeline, was tagged at about $350 million (some sources say $450 million). Average daily production of some 60,000 barrels per day was expected by 1982 and, with additional investment, and production of 100,000 bpd by 1984.
ARCO said this was the first phase of what could eventually become a $1 billion investment among several companies holding leases in the Kuparuk field; the initial effort, however, was exclusively by ARCO on its leases.
ARCO Chairman Robert O. Anderson said the company was moving ahead because it felt Alaska’s negative investment climate, created chiefly through adverse tax policies, showed some sign of improvement. Oil prices were also on the rise.
Anderson also said that further development beyond the initial phase would depend on the economics of the project and the future investment climate in Alaska.
Exxon and Mobil, among others, wanted to see the entire field developed.
The first phase, exclusively ARCO, targeted 20 square miles. At the same time, ARCO put together a long-range plan for Kuparuk and was working with owners of adjacent acreage, such as Mobil and Exxon, to agree on a development plan for the Kuparuk River unit. It amounted to a tenfold expansion, costing billions of dollars, and covered some 200 square miles.
Delay had one benefit
Because Kuparuk was developed later than Prudhoe Bay it benefited from newer technology.
Most obvious was the reach of drilling rigs — which dramatically reduced the size of drill sites.
In 1970, a Prudhoe Bay drill site was 65 acres and from that 65 acres drill rigs could access a subsurface area two miles across.
A 1980 Kuparuk drill site was 24 acres and rigs could access an area three miles across.
By 1985, Kuparuk drill sites had dropped to 11 acres, but the subsurface reach was five miles across.
The reservoir was also different: Kuparuk is at about 6,300 feet, compared to 8,000 to 9,000 feet at Prudhoe Bay. Although the sizes of the reservoirs are about the same, the “pay” at Kuparuk was about 50 feet compared to nearly 600 feet at Prudhoe.
Based on remaining recoverable reserves, ARCO estimated in 1981 that Kuparuk was the second largest field in the United States, behind Prudhoe. Ultimate recovery, with successful waterflood, was expected to range between 1.2 billion and 1.5 billion barrels of oil.
Project, challenges continue to grow Getting there is half the fun — or challenge — could have been the motto for initial construction at Kuparuk.
First there were the sealifts and the struggle to get facilities modules to the North Slope in the short window each summer when there was an opening in the ice.
Initial Kuparuk facilities came in on three sealifts: The 1979 sealift brought in the warehouse, shop, vehicle storage and hanger. Workers were still installing those in the spring of 1980, along with doing piling work for modules and laying more gravel in advance of the 1980 sealift, which would bring in the permanent base camp, sewage and power facilities. Final facilities for initial production only arrived in the summer of 1981.
In the winter of 1979-80 six development wells were drilled along with two exploratory wells to confirm more high-potential Kuparuk areas.
As part of the expansion, three additional facilities (central processing facilities 2 and 3, and the seawater treatment plant) were installed to meet Kuparuk pipeline capacity of 200,000 bpd in 1986 — a big change from an original projection of 60,000 bpd.
One of the challenges of developing Kuparuk was getting there from Prudhoe, Prudhoe being the connection to the Dalton Highway, known as the Haul Road, and initially the necessary connection to West Dock for module delivery, although Kuparuk later had its own dock facilities at Oliktok Point.
At spring breakup in 1980, culverts at ARCO’s $5 million Kuparuk River crossing washed out, temporarily closing the Kuparuk Spine Road — a road needed to move sealift modules to the field.
A temporary river crossing had to be in place by August to move 1,000-ton equipment-bearing modules. If the river crossing wasn’t ready ARCO planned to move the equipment overland in the winter.
Jim Weeks, who headed the Denver-based Kuparuk project group which designed, constructed and installed Kuparuk facilities, told the ARCO Spark that three of the 12 culvert sections gave way June 9 and over the next four days the rest of the culvert sections collapsed into the Kuparuk River.
Kuparuk River a stumbling block In a 2001 interview with Petroleum News, Weeks talked about the bridge problem — and about the challenges of getting Kuparuk developed.
“From the start, Kuparuk had … the reputation of being the down-to-earth, low-cost, sort of get-it-done-cost-effectively oil field,” said Weeks, the first project manager for Kuparuk. “That was our mandate.
“We developed a lot of new technology at Kuparuk, and we broke the paradigm that you couldn’t start something up in the same year you shipped it,” Weeks said.
The sealift was due in August 1980 and materials for Kuparuk, including the power plant, would have to go across the Kuparuk River. A bridge was needed. Weeks said plans were under way the previous fall, but permits didn’t come through until after freeze-up — and the gravel that would be used for fill already had ice crystals in it.
When the Kuparuk River floods at breakup, it becomes three miles wide. “We couldn’t justify building a three-mile bridge, so what we did is build a bridge on the main channel” with two low-water crossings on either side. Even the central bridge would be expensive, so they chose the type of “massive, corrugated culverts used for train tunnels.” The culverts were backfilled with compacted gravel.
“The actual strength that held the load up on the top of the bridge was not the culvert but the gravel,” Weeks said. The gravel was key — it pushed against the sides of the culverts, giving them the strength they needed.
“But when we built the bridge the backfill was frozen. You can pound on ice all day long and it’s not going to compact,” Weeks said.
At breakup, the gravel started to thaw out, the ice crystals melted “and the gravel lost its ability to push against the side shells of the pear-shaped culverts, and they collapsed.”
Weeks and Kuparuk operations manager Landon Kelly purchased all the surplus 48-inch Alyeska Pipeline Service Co. pipe they could find in the state and used it to install a temporary bridge to meet the August sealift.
Permanent bridge needed After getting the temporary bridge in place to meet the sealift, a permanent bridge was required before oil production could begin.
Because of the strength of the Kuparuk River breakup, pilings for a permanent bridge were massive: 42 inches in diameter, so big they could not be made in the United States, they had to come from Japan, lashed to the deck of a ship because of their diameter and 80-foot length.
At Kuparuk, 54-inch holes, 100 feet deep, were drilled for the pilings, but the ship encountered a storm in the Gulf of Alaska and some of the pilings went overboard.
Without the pilings in place water would fill the holes at breakup and thaw them out and the holes would collapse.
The Japanese could get them more piling, but not until September or October, and the holes needed to be saved: they held a contest.
John Larson, an ARCO engineer, suggested using some of the surplus 48-inch pipe ARCO had bought for the temporary bridge, cutting the pipe into 15-foot lengths and putting a cap on each section.
Weeks said they hung a section of pipe into each hole, insulated the area between the 48-inch pipe and the 54-inch hole and backfilled. “We essentially put a plug in the top of the hole and froze it back in place,” Weeks said. Forty holes were saved. The replacement pilings came in and were put in during the fall of 1981, allowing startup to take place at the field.
With employees working around the clock the field started up three months ahead of schedule, on Dec. 13, 1981.
Kuparuk ownership ExxonMobil officials say their company has been an active partner in the development and production of the Kuparuk unit from the start.
Today, core area working interest owners at Kuparuk are ConocoPhillips, 52.12468 percent; BP, 37.02472 percent; ExxonMobil 5.8 percent; and Unocal, part of Chevron, 4.9506 percent.
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