The years immediately following Kuparuk startup in 1981 saw major facilities work completed at the field, with the addition of the second and third processing facilities and the seawater treatment plant, construction of drill sites and an expanded Kuparuk sales line.
By the end of 1986, big development projects were complete, and focus had begun to shift to reservoir management.
The 1982 sealift included modules for Kuparuk including additional compression capacity for CPF-1 so the facility could handle more natural gas and maintain production levels.
The sealift also contained the first increment of the Kuparuk waterflood project for installation at CPF-1, the first large-scale water injection project on the North Slope, which began operation in early 1983, more than a year ahead of the Prudhoe Bay waterflood.
Production from Kuparuk, which had begun the previous December, was averaging more than 90,000 bpd.
Kuparuk produced more oil than expected in its first year, 31.8 million barrels, an average of 87,000 barrels per day. The field had been forecast to produce 80,000 bpd.
Ninety wells were drilled by the end of 1982, with 75 producing oil.
ARCO had 163 employees working at Kuparuk, with about half of them on the slope at any given time.
First waterflood in 1983
The first waterflood on the North Slope was initiated in January 1983 at Kuparuk, beginning with 3,200 bpd of water at drill site 1A; the rate was to be gradually increased to 5,000 bpd, and then expanded to other wells at drill sites 1A and 1E.
ARCO estimated that 1.25 billion to 1.5 billion barrels of oil would be recovered with waterflood, compared to a fraction of that volume without waterflood.
Because of arctic conditions, the water must be heated before injection to avoid having it freeze in the pipelines. And the pipelines must be insulated and freeze-protection systems installed.
“The key is to keep the water moving and keep it warm,” said Landon Kelly, Kuparuk operations manager. “And we have to pump enough volume to overcome heat loss as the water travels down through the permafrost.”
Water came initially from wells; water for full-field waterflood would come from the Beaufort Sea.
By March, 22,000 bpd of water were being injected into wells on drill sites 1A and 1E, Kelly said. In Phase I the rate was gradually increased to 50,000 bpd; when full waterflood was under way in the late 1980s, an estimated 400,000 to 450,000 bpd of water would be injected.
ARCO said it expected to recover an additional 800 million to 900 million barrels of oil with waterflood.
1983: new pipeline; dock at Oliktok Point
A joint venture agreement was reached in 1983 for a 24-inch pipeline, expected to handle as much as 250,000 barrels per day by the late 1980s.
The field’s 16-inch line, which handled more than 100,000 bpd, was converted to other service once the 24-inch line was completed.
In 1983 sealift modules for Kuparuk were offloaded at a new dock at Oliktok Point, west of Prudhoe Bay, and then transported 10 miles south to the Kuparuk field; previously Kuparuk modules came into Prudhoe Bay and were transported 40 miles overland.
The 1983 sealift carried the utilities portion of CPF-2; the oil handling portion of the new facility is scheduled for the 1984 sealift.
Different than Prudhoe, but with ex-Prudhoe leaders
A 1983 article in the ARCO Spark, the company newsletter, gave some insight into work at the new field, now producing 100,000 bpd.
“There’s an attitude up here that everybody’s looking for oil,” said Bob Appling, Kuparuk operations manager. “It’s a personal pride that everyone shares, and everyone sees to it the job’s done right.”
Appling said there are a number of differences between Kuparuk and Prudhoe Bay.
“Because Prudhoe can still produce more oil than it is allowed to sell, in some cases, repairs can be made in a less than critical manner.
“Over here, we get to sell every barrel we can get our hands on. If something goes down, man, you get it fixed right then and back into production. Every minute lost is less money to the company. We take all down-time very seriously.”
Appling also said that Kuparuk people are constantly looking for ways to boost production levels. “Not a week goes by that somebody isn’t in here with an idea. Some we can use, some we can’t. But it sure helps to have that kind of input,” he said.
Appling listed a number of people as responsible for the field’s first-year success, above all Landon Kelly, the field’s overall operations chief. “I think everyone would agree that Landon is the single most important player at Kuparuk. He’s the guy who pushed this field as a high priority long before it became one. And he’s the one largely responsible for bringing it on earlier than anyone expected.”
Major expansion in 1984
Installation of the second processing facility, CPF-2, was planned following its arrival on the 1984 sealift, which also carried a tripling of bed capacity for the Kuparuk Operations Center.
The sealift also included a crude oil topping plant which would be producing 3,000 bpd of diesel fuel by the end of the year.
The sealift arrived a week ahead of schedule and that contributed to getting CPF-2 online at the end of October, more than a month early, increasing production by 75,000 bpd and raising the field’s total production to 190,000 bpd.
Kuparuk was now one of the five largest U.S. producing fields.
Harold Heinze, president of ARCO Alaska, attributed the early startup to exceptional teamwork, as well as “excellent productivity” by field construction workers and supervisors. “This is the fastest major facility ever put into service on the North Slope,” Heinze said.
The new 24-inch Kuparuk pipeline went into operation Oct. 6, replacing the 16-inch pipeline in operation since field startup.
Drilling records set; more waterflood
The Alaska Spark reported in December 1984 that drilling records were being set nearly every month at Kuparuk. During development drilling in 1980, it took an average of 22 days at a cost of $2.5 million to drill and complete a well.
The average time had dropped to 11 days and the average cost to $1.5 million, with the current drilling record held by Parker rig 141. It drilled and cased a 6,704-foot well in four days, 23 and three-fourths hours, a drilling average of 1,348 feet per day.
Four rigs have been working at Kuparuk since the spring of 1984 and if they complete their 1984 schedule, 117 wells will have been drilled; 155 wells are planned for 1985.
Major construction by ARCO in 1985 included waterflood at Kuparuk, with construction for the seawater treatment and injection plants under way, the Alaska Spark said in May 1985.
The seawater treatment plant, two modular buildings connected by a 100-foot arctic walkway, was scheduled to go in at Oliktok Point some 20 miles from the Kuparuk main camp and will process 585,000 barrels of seawater a day through four intake bays. A jet pump will separate marine life from the arctic water and safely return them to their environment.
1985; 200-million barrel mark passed
Kuparuk set a one-day production record in October 1985 of 264,490 barrels.
“We had expected that Kuparuk production would not reach 250,000 barrels a day until late 1986, after the installation of a third central production facility,” said Ben Odom, ARCO’s senior vice president for operations. “However, our aggressive and innovative engineering and operations people have been able to achieve higher rates than expected from only two production facilities.”
The water injection program went into operation Oct. 28, 1985, and is expected to triple recoverable oil, from 500 million barrels without waterflood to 1.5 billion barrels with waterflood.
“It’s a major shift from primary production to secondary waterflooding,” senior reservoir engineer Paul White told the Alaska Spark. “The recent history of Kuparuk focuses on expanding the field by drilling new wells. We’ll still be expanding the field, but the focus will be coming around to managing a developed field.
“This will include developing the less productive areas of the field,” White said, “where the costs will be about the same but the benefits are much less.”
Kuparuk passed the 200 million barrel production mark Jan. 8, 1986, two months ahead of schedule, with production at 240,000 bpd.
It had taken 32 months for the field to produce its first 100 million barrels on Aug. 16, 1984.
After CPF-2 was added in late 1984, and with continued development drilling, the 200 million-barrel mark took just 17 months.
1986 sealift last planned
The 1986 sealift was ARCO’s last committed shipment of facilities to the North Slope. For the first time since the discovery of oil on the North Slope, no future major projects were in the design or construction stages, and no new facilities were planned for the 1987 sealift or beyond, ARCO said in January 1986.
The 1986 sealift included Kuparuk’s third central production facility which would allow development of the northern portion of the field and help keep field production in excess of 200,000 bpd for the next several years. Kuparuk also had modules for five new drill sites on the 1986 sealift.
ARCO Alaska advertised in Alaska for skilled instrument technicians and other oilfield operating personnel to operate the new facilities, and did receive Alaska applicants.
“The problem is that there simply are not enough experienced and technically qualified Alaskans to fill the large number of positions which are being created by the new facilities,” said ARCO Alaska President Harold Heinze. “We have created so many new jobs in the past several years, in bringing on line new facilities that we have already drawn heavily from the pool of qualified Alaskan workers.”
As a result, he said, ARCO is placing ads in Lower 48 papers.
The 1986 downturn
But by early March 1986, ARCO said the declining price of crude oil had forced it to reduce its North Slope development drilling activity by nearly 50 percent. Of the nine drilling rigs operating on the North Slope earlier in the winter, five were to be idled by the end of April or early May, leaving four rigs drilling new production wells for ARCO, only one at Kuparuk, with an estimated 400 North Slope jobs affected, about 100 jobs per drill rig.
The cut in development drilling was part of ARCO’s 30 percent capital spending reduction, announced in February.
The number of wells to be drilled at Kuparuk was reduced from 150 to 90.
In mid-April ARCO Alaska said the drastic drop in crude oil prices had prompted it to streamline its operations on the North Slope. The company said staff levels would be reduced and a number of employees would be reassigned to operate new facilities scheduled to arrive on the 1986 sealift.
Ben Odom, ARCO Alaska’s senior vice president of operations, said the reassignment of present ARCO personnel meant no significant new hiring would take pace from outside the company. It had been estimated that 200 new employees would be needed, but a majority of those jobs, ARCO said, would now be filled by employees already working on the North Slope, whose current jobs will be eliminated by the realignment.
CPF-3 installation
Work to install Kuparuk’s third central production facility, CPF-3, was to begin in June and finish in mid-October, with startup of CPF-3 scheduled for late October.
In December 1986 ARCO Alaska said that startup of the third central processing facility at Kuparuk had boosted oil production to nearly 300,000 bpd.
Kuparuk production reached a new record high of more than 298,000 bpd on Dec. 2; production had been averaging between 250,000 and 260,000 bpd prior to startup of CPF-3. Cold weather also helped.
CPF-3 has a capacity of 80,000 bpd; CPF-1 and CPF-2 each have a capacity of 120,000 bpd.
“The addition of CPF-3 was part of the planned total development of the Kuparuk field,” Odom said. “It’s the last major facility for a while, following the installation of a seawater treatment plant and introduction of field-wide waterflooding last year.”
Dana Dayton, manager of Kuparuk reservoir engineering, told the Alaska Spark in 1986 that “CPF-3 is the culmination of a development era. This year is unique because of a feeling of transition which many of us have.
“While we may have a big sense of satisfaction and accomplishment, we may also have some apprehension about the change from development to reservoir management,” she said.
