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Vol. 12, No. 3 Week of January 21, 2007
Providing coverage of Alaska and northern Canada's oil and gas industry

KUPARUK ANNIVERSARY: Meltwater discovered, in production

Palm does better than expected; new 3-D seismic planned for Kuparuk, coiled tubing in-fill wells

Kristen Nelson

Petroleum News

Phillips Petroleum bought ARCO’s Alaska assets in March 2000 and named Kevin Meyers president and CEO of Phillips Alaska, which included all of ARCO’s Alaska businesses, plus all of Phillips’ Alaska operations, including the Kenai LNG plant.

The new company soon had something to celebrate, announcing the discovery of Meltwater on May 2, 2000.

Meltwater was estimated to contain about 50 million barrels of proven and potential reserves.

Meltwater North 1, about 10 miles south of the Tarn oil field in the Greater Kuparuk Area, tested at 4,000 barrels per day of 37-degree API gravity oil. A second exploration well and sidetrack, Meltwater North 2 and 2A, confirmed a northern portion of the reservoir.

The discovery was made on acreage purchased in June 1998 in the first areawide lease sale ever conducted by the State of Alaska. Phillips holds a 58.46 percent interest; BP holds a 41.54 percent interest.

Meltwater has the potential to be the fourth Kuparuk satellite field to begin production. The West Sak field began production in 1997, and Tarn and Tabasco began production in 1998.

“State areawide leasing and the application of advanced 3-D seismic technology made this discovery possible in less than one year,” said Michael Richter, Phillips Alaska vice president of exploration and land. “This discovery marks a new era in the Alaska oil industry. This is Phillips Alaska’s first discovery as a new company and the first discovery this century for the State of Alaska.”

“This discovery signals a bright start to exploration in the new millennium and will also serve to move production infrastructure further south than ever before. Our goal is to bring this new field on production as quickly as possible. We will soon be working with Phillips on a field development plan,” said F.X. O’Keefe, exploration business unit leader for BP Exploration (Alaska).

Production began from Meltwater in late 2001

Initial production began from Meltwater at 3,000 barrels per day Nov. 29, 2001. Meltwater was discovered in March 2000 and road, pad, power line and pipeline construction were done over the 2000-2001 winter season. The 50 million barrel field is in the southwestern portion of the Kuparuk River unit, some 27 miles from central processing facility 2.

Ryan Stramp, Phillips Alaska’s Meltwater development coordinator, said Meltwater is the most distant of the Kuparuk satellites — only 10 miles from Tarn, but some 25 miles from production facilities at Kuparuk.

The company’s process engineers had to determine if crude oil from the Meltwater pad “would make it on its own energy, or were we going to have to put some pumps or some sort of processing” at the pad.

They decided that with a large diameter pipe at the Meltwater pad the natural energy from the reservoir would move the crude oil approximately 25 miles to the processing facility.

Stramp said 17 or 18 wells would be drilled initially, results assessed, and then the final eight or 10 wells drilled. The reservoir at Meltwater is a little shallower than Kuparuk, about 5,200 feet, and conventional directionally drilled wells are planned.

“We’ve got one central pad and we’re going to develop several square miles of reservoir by directionally drilling out in all directions around the pad,” Stramp said.

The 2000 exploration well produced at 4,000 bpd during a short-term test.

Palm exceeds expectations

Meanwhile, there was another name change for the company: Phillips Petroleum combined with Conoco in August 2002, creating ConocoPhillips and, in Alaska, ConocoPhillips Alaska.

The Palm discovery, developed as Kuparuk drill site 3S, had production of 29,000 bpd in July 2003, exceeding pre-development expectations of a peak of 16,000 bpd by 2004. There are 17 wells at the drill site, nine producers and eight MWAG injectors.

The project came in under budget and ahead of schedule.

Development drilling began in November 2002 and the field came online Nov. 14, 2002, initially producing 2,350 bpd of 26-degree API gravity oil from a single well.

The accumulation is estimated to contain 35 million barrels.

Time from spud of discovery well to first production was 20 months.

New 3-D at Kuparuk

ConocoPhillips and BP announced expansion of West Sak on Aug. 10, 2004 (see West Sak story in this publication).

Work continued on the main Kuparuk reservoir.

Matt Fox, then the company’s greater Kuparuk area development manager, said in December 2004 that a new 3-D seismic survey would be shot across the Kuparuk field.

Kuparuk, he said, “is one of the most complex fields in the world from a geological perspective, from a faulting perspective — it’s just incredibly complex. You combine that with the fact that we’re doing a miscible gas injection enhanced oil recovery. You can’t go many places in the world and find anything more challenging than this.”

Because Kuparuk is so complex, there are still opportunities there, Fox said.

The 3-D seismic shot in the winter of 2004-05 uses “new technology that’s designed to allow us to image in the reservoir where the oil and gas are” allowing the company to target sidetracks, he said.

More coiled tubing work

ConocoPhillips is also experimenting with coiled tubing drilling techniques.

Coiled tubing drilling has been used successfully at Prudhoe Bay, Fox said, “but the geology at Kuparuk makes coiled tubing drilling more of a challenge. …”

In addition to 3-D and coiled tubing, ConocoPhillips is “building a new full-field reservoir simulation model at Kuparuk,” which, Fox said, is challenging “because of the complexity of the field.” He said the combination of new 3-D seismic, coiled tubing drilling and the new reservoir simulation model “are going to allow us to get the most from Kuparuk, whether it’s through base management or through new development.

“We can’t stop Kuparuk declining,” he said, “but we can slow the decline down” and fill in with West Sak developments.

The combination of the new 3-D seismic and the reservoir simulation model and well performance will let ConocoPhillips identify areas where it doesn’t seem to be getting all the oil it could “if there were no geological problems.” The seismic will identify opportunities, he said, such as an oil trap “up against the fault, and then we can tale a coiled-tubing sidetrack up against that fault so that we pull the oil in.”

Coiled tubing wells will also increase rates because they are drilled as horizontal sidetracks.

Fox said that while coiled tubing can’t achieve the lateral lengths a rotary rig can, “we don’t need those lengths because it’s quite a tight well spacing in Kuparuk anyway. What we need is the accuracy, the ability to see it and then get after it with the coiled tubing.”



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Dobson, O'Dell, Hannon comment on changes

• Engineer Stephanie Dobson, who now works in Anchorage with ConocoPhillips, worked at Kuparuk in 1992 and from 1998-2004.

“The biggest change that I’ve seen over the years about Kuparuk is the attitude people both internally and externally associate with the field. Kuparuk was always the ‘little brother’ to Prudhoe Bay.

“Kuparuk is more vulnerable to lower oil prices than Prudhoe,” she said.

The technological breakthroughs that got the field to 2 billion barrels of oil, “and that’s despite oil prices — this has really gotten people excited about it again,” demonstrated by the level of investment at the field over the last five years.

“It’s like the reservoir that could.”

Dobson also said that in the early 1990s she wouldn’t necessarily have predicted the enhanced oil recovery and coiled tubing drilling work that have contributed to the field’s success.

• Brian O’Dell, now wells coordination supervisor for ConocoPhillips’ North Slope operations, has worked in the Kuparuk group since 1982, with three years off for a Cook Inlet assignment in the early ‘90s.

“Some of the biggest and most significant changes I’ve seen since I first started working here involve the evolution of Kuparuk from a pseudo-satellite field of Prudhoe Bay (the ‘other’ field on the North Slope) to a hub for the surrounding satellites of Kuparuk (Alpine etc.) Kuparuk has grown to become a production and operations center for the Western North Slope development.”

“There are really too many team accomplishments over the years to single one out. Things such as producing over 130,000 bpd through a facility originally designed for 80,000, all of the facility expansions and installations, and the new wells drilled and added to the field are all significant achievements.

“These types of efforts, along with engineering developments and innovations, like WAG flooding and MI EOR, and many of the innovative and creative drilling and well intervention developments, like coiled tubing drilling, multilateral wells and improved artificial lift systems, are all accomplishments that have helped keep Kuparuk a great place to work for the 25 years we’ve been here on the slope.”

• Engineer Renee Hannon started working Kuparuk from the Plano ARCO lab in 1982, she said in the 2001 20th anniversary video. “We were working with the reservoir engineers up here on formation damage studies, trying to determine the best stimulation treatment of Kuparuk.

“Kuparuk was just an infant back then and it does turn out that fracturing is probably one of the best stimulations.

“Ten years ago, in 1992, I was working Kuparuk here in Anchorage and I was the lead of the geoscience group and Kuparuk back then was this energetic, bubbling teenager, producing over 300,000 barrels of oil per day. … We were still peripheral drilling and in-fill drilling back then.

“And more recently, I’m working Kuparuk now, another decade later, 2001, and Kuparuk right now is very different. It’s like this laid-back, mature adult, getting ready for retirement. However, it’s given birth to four or five satellites … (with) very nice character (that) help production rates.”