North Slope's exploration revival targeting satellites near giants

Aug. 31, 1998
A Decade of North Slope Discoveries [210,766 bytes] ARCO's 1997-98 North Slope Satellite Drilling Programs [164,878 bytes] A revival of exploration interest and activity on Alaska's North Slope centers around a string of satellite discoveries. As in the North Sea, low-cost development of satellite finds near existing giant fields points to the maturing of the North Slope as a petroleum province.
Exploration interest in the Alaskan North Slope's untapped hydrocarbon potential has gotten a big boost with the discovery of a giant field, Alpine, west of the Prudhoe Bay infrastructure, and a string of satellite finds near Prudhoe infrastructure. Here, seismic crews gather data in the Alpine area. Photo courtesy of ARCO Alaska Inc.
A revival of exploration interest and activity on Alaska's North Slope centers around a string of satellite discoveries. As in the North Sea, low-cost development of satellite finds near existing giant fields points to the maturing of the North Slope as a petroleum province.

Those satellite developments, together with efforts to improve recovery in the existing giants and to develop a few new giants, are bolstering an industry drive to stem and even reverse a production decline in northern Alaska (OGJ, Aug. 24, 1998, p. 20).

The era of the satellite that began in earnest last year already is on its way toward increasing production on the North Slope.

In an interview last year, Ken Thompson, then-president of ARCO Alaska Inc. and now Chairman and CEO of the company, said, "We define satellites as fields that can be developed at low cost and produced through existing North Slope facilities. To date, we have identified 50-60 small-to-medium prospects that fall into this category."

Tarn: 'satellite launch'

ARCO, in a joint venture with BP, kicked off the 1997 satellite drilling program on Jan. 30, spudding in with Doyon Drilling's Rig No. 141 to drill Tarn No. 2, in 23s-10n-7e, off the southwestern flank of the Kuparuk River field.

The discovery well proved up a new field. Testing yielded a steady stimulated flow rate in excess of 2,000 b/d of 38° gravity oil from a sandstone reservoir discovered at a depth of 5,200 ft.

ARCO-BP followed up with Tarn No. 3, in 34s-10n-7e, which included a sidetrack, and Tarn No. 4, in 1s-9n-7e. The two follow-up wells and the sidetrack found oil. Possible reserves have been estimated at 55 million bbl of oil. ARCO owns 58.5% interest in the Tarn prospect. BP holds 41.5% interest.

The accent on Tarn this year is to bring the field on production by the third quarter at rates of 2,000-3,000 b/d, building to 10,000-15,000 b/d by yearend. Plans call for drilling 20 wells before yearend, including 15 producing wells and 5 gas injection wells. The latter will set the stage for miscible gas injection from the beginning of Tarn production, which is expected to peak at about 24,000 b/d.

Double discovery

ARCO Alaska Inc., Exxon Co. USA, and BP Exploration (Alaska) early this year made a "double discovery" next to Prudhoe Bay field.

The discovery of two new oil accumulations was made during the drill- ing of a Prudhoe Bay satellite project. The finds are not part of the main reservoir.

The Sambuca well (Sam No. 1), in 6s-11n-14e, encountered a 100-ft vertical section of oil and gas-bearing rock in Kuparuk sands at a measured depth of 11,662 ft. Oil and gas also were found in a 160-ft vertical section of rock in the Sag/Ivishak formation at a measured depth of 12,965 ft. Doyon Drilling's Rig No. 9 handled the drilling assignment.

The Kuparuk interval, which will become the Midnight Sun field, tested about 4,000 b/d of 29° gravity oil and 1.5 MMcfd of gas.

The Sag/Ivishak formation, which will become Sambuca field, tested 1,400 b/d of 24° gravity oil and 490 Mcfd of gas.

The discovery well is on a lease in which ARCO and Exxon each own a 50% interest. Working in concert with the state, ARCO and Exxon plan to begin long-term test production from the discovery well in the first half of 1998.

BP, as Prudhoe Bay western area operator, served as drilling operator on the well on behalf of ARCO and Exxon. BP will pay part of the cost of the well in exchange for well data. The three companies also hold leases adjacent to the Sambuca and Midnight Sun discoveries.

The Sam No. 1 well is part of the continuing satellite drilling program within the confines of Prudhoe Bay field. As many as four additional Prudhoe Bay satellite wells are planned this year.

Tabasco, EOR

Another exploratory well is planned for ARCO's drilling program this year in the greater Kuparuk River field area as part of the continuing satellite campaign.

The target is the Tabasco prospect. A well drilled and tested in l995 indicated the shallow Tabasco prospect could be commercial. The planned well will test a separate Tabasco accumulation identified with data from a 3D seismic survey.

For Tabasco, as for other North Slope fields, enhanced oil recovery would play an important part in production, which would be initially bolstered by waterflooding.

Both waterflooding and gas injection are continuing to play major roles in the EOR picture in each of the North Slope's three most productive fields. The Prudhoe Bay field is the site of the largest active gas lift project in the U.S.; Kuparuk River is the site of the second largest active gas lift project.

In March this year, Prudhoe Bay's 206 injection wells were the recipients of 1,095,983 b/d of water and 7.3 bcfd of gas. Kuparuk River's 375 injection wells were recipients of 784,363 b/d of water and 28.9 MMcfd of gas. Point McIntyre's 15 injection wells received 277,508 b/d of water and 132.5 MMcfd of gas.

BP's strategy

BP Exploration (Alaska) Inc. shares ARCO's optimism over the future of oil in Alaska. "We are growing in Alaska," said John Browne, British Petroleum Group chairman, at an Alaska Support Industry Alliance earlier this year in Anchorage.

"We intend to grow our production (in Alaska) by 100,000 b/d by the turn of the century. And we intend to sustain production above 500,000 b/d for the foreseeable future."

Browne credited a number of new projects with contributions to this outlook, among them Badami field, the Liberty prospect, perhaps the Sourdough prospect, and heavy oil reserves in the Schrader Bluff pool in Milne Point field.

Pointing out that BP has invested about $500 million/year in Alaska for the past decade, Browne said that the company a year ago announced plans to step up investment to around $700 million/year, or $3.5 billion over 5 years.

BP on Sept. 17, 1997, spudded in to drill the first well in a program to develop Badami field, about 35 miles east of Prudhoe Bay. The field, in Mikkelsen Bay, is being developed from an onshore site, where Nabors Drilling's Rig No. 28E is handling the drilling program.

Badami started production last week (see Newsletter). The field contains an estimated 120 million bbl of recoverable oil. Production is expected to peak at about 35,000 b/d in 1999.

Badami shapes up as the sixth field to go on production on the North Slope. Other fields on production and their estimated output in March are: Prudhoe Bay, 667,825 b/d from 892 wells; Kuparuk River, 265,041 b/d from 446 wells; Point McIntyre, 141,029 b/d from 48 wells; Endicott, 58,258 b/d from 51 wells; and Milne Point, 56,916 b/d from 120 wells.

Badami campaign

Badami was a 1990 discovery by Conoco Inc. and Belgium's Petrofina SA. The discovery well tested at a rate of 4,250 b/d.

A confirmation well was drilled in 1992. BP acquired Conoco's interest in the field with the acquisition in January 1994 of the company's North Slope interests, including not only Badami but also Milne Point, in return for assignment of a 33% stake in BP's wholly owned Amberjack field in the Gulf of Mexico. Badami is owned jointly by BP, the operator; and Petrofina, which is managed by Fina Inc., its U.S. affiliate. BP has a 70% interest, Petrofina the remaining 30%. The unit comprises 12 leases encompassing 48,492 acres.

In preparation for development to begin, the drilling rig and major infrastructure were barged from Prudhoe Bay to the onshore drillsite. Along with the rig and related equipment, a drilling solids grinding unit, gravel-washing plant, and power module were moved to the site from Prudhoe Bay.

Fuel storage facilities were completed in preparation for a sealift shipment from Canada, by way of the Mackenzie River, that consisted of a fuel barge with 9,000 bbl of diesel and two other barges carrying supplies.

Access to the onshore drillsite in the winter will be by ice road and in the summer by barge and helicopter. There will not be any other road access to other North Slope installations. Development includes, in addition to the pad supporting a Central Processing Unit and wells, an airstrip and a satellite well pad. Badami crude will be transported by a 26-mile, 12-in. pipeline to connect with the Endicott field pipeline.

Extensive use of extended-reach drilling is being employed to tap Badami pay. Current plans call for drilling about 30 wells, which will reach about 40 bottomhole locations through multilateral drilling.

Badami, with start-up expected this fall, shapes up as the first of the satellite era's new fields to go on production.

Northstar update

A satellite field that was once expected to be first to go on line received a go-ahead in May to end a period of more than 1 year on hold. The field is Northstar in the Beaufort Sea, 6 miles off the Kuparuk River delta and Prudhoe Bay field.

In February 1997, BP ran into a roadblock in its efforts to bring Northstar on production. A lawsuit filed by two industry critics against Alaska in Anchorage Superior Court challenged revisions in Northstar lease terms that had been ratified by the Alaska legislature and signed by the governor in 1996.

BP stopped all Anchorage module fabrication work on the Northstar project until the suit was resolved. In the meantime, BP focused its work on permitting, the environmental impact statement, and support engineering. On May 15, 1998, Alaska's Supreme Court unanimously upheld the ruling that the state's decision to modify its lease terms with BP for the Northstar field was legal.

BP plans to resume fabrication in Anchorage in November-December and hopes to get all permits in hand by yearend to start gravel island construction early in 1999. BP is targeting first production early in 2001. Peak production has been predicted at 50,000 b/d.

Northstar field was a 1982 discovery by Shell Oil Co. from manmade Seal Island. Amerada Hess followed Shell's discovery with an extension find drill- ed from Northstar Island. Both companies weighed plans to develop the field but backed off in the face of the high cost of laying a buried pipeline to transport oil to existing onshore facilities and the high net profits percentage to be paid on state leases.

BP entered the picture in January 1995 by acquiring Amerada Hess's 81% interest in the Northstar Unit and followed up with acquisition of Shell's 17% interest, bringing BP's ownership to 98%. Murphy Oil Corp. retains the remaining 2%.

Northstar project

BP's plans for development of the 30,788-acre Northstar Unit call for expanding the size of Northstar Island, from which Amerada Hess drilled in the 1980s, for use as a base from which to drill new wells.

The drilling program calls for 23 wells, including 13 producing wells, 6 water injection wells, 3 gas injection wells, and 1 waste disposal well. Oil will be transported from the drilling island through a pipeline buried 10 ft below the seafloor. The buried subsea pipeline will be the first such project in the North Slope region.

The field's reserves have been estimated at 130 million bbl of oil, with recovery possibly reaching 145-150 million bbl of an estimated 260 million bbl in place. Gravity of the oil is 40°, which is considerably higher than the mid-20°s gravity of production from other North Slope fields. Capital expenditures, mostly for more drilling, could reach $415 million.


Another satellite that could draw attention in the wake of Northstar development is Sandpiper, 11 miles northwest of Seal Island-also in Northstar field. Soon after Amerada Hess in 1986 announced extension of the Northstar/Seal Beach development with the first Northstar well, Shell enhanced the possibility of commercial development in the area with acknowledgment of a discovery on manmade Sandpiper Island.

The discovery well flowed at stabilized rates of 500-2,500 b/d of 40-52° gravity oil through chokes ranging from 30/64 in. to 2 in. Flows in the 12,575-ft well came from two zones in the Sadlerochit below 11,910 ft measured depth. Along with oil, the well produced gas at a rate of 18.5 MMcfd.

BP recently set the stage for development of Sandpiper as operator by acquiring 50% ownership of the Sandpiper Unit from Murphy Exploration Co. and Petrofina Delaware Inc. Murphy retained 28% interest, Petrofina 22%. Agreement terms were not disclosed.


In other action, BP has begun moving its proposed Liberty offshore project through the permitting process by putting its plans out for review by the U.S. Minerals Management Service, the lead agency on the environmental impact statement.

The project lies in federal waters 6 miles east of offshore Endicott field. Plans call for development from a single offshore gravel production island connected to the shore by a buried pipeline. Development of the project will be in 1999, with first oil in 2000.

BP set the stage for the Liberty prospect with a 3D seismic survey before OCS Sale 144 on Sept. 17, l996. The sale was the first federal offshore sale held in Alaska since 1991. BP was the largest bidder, spending more than $12 million at the sale, where it acquired acreage on the Liberty prospect.

The company in February l997 spudded an appraisal well to test the prospect. The directional hole, OCS Y-1650 No. 1, was drilled by Pool Arctic Alaska's Rig No. 4 from an artificial island. The rig was released early in April 1997. The appraisal well proved up an estimated 120 million bbl of recoverable oil.


Another satellite that has caught BP's attention is Sourdough, in the southern Point Thomson area about 15 miles inland from the Beaufort Sea and 50 miles east of Prudhoe Bay.

BP and Chevron USA Inc. discovered the field in 1994 and drilled another well in 1996.

The discovery was made by Sourdough No. 2 in 31s-9n-24e. The exploratory well was drilled in 1994 and went to 12,600 ft before the rig was released about 75 days after spud-in. Details were not released, but interest was heightened when the state certified Sourdough as "capable of producing in paying quantities."

In April l996, BP completed a confirmation well. The Sourdough No. 3, 29s-9n-24e, proved up production about 1 mile north and slightly east of the Sourdough No. 2. The drill site was about 1 mile west of the Arctic National Wild- life Refuge (ANWR) Coastal Plain. In March, BP reported that enough information had been obtained to indicate Sourdough could hold about 100 million bbl of recoverable oil.

BP/Chevron had planned to drill another delineation well this winter, but delayed drilling the well to study more seismic and other data compiled for the field.

Transporting Sourdough's oil to market would require at least 35 miles of new pipeline to link it to the line that transports oil from Badami field. "That far from infrastructure, 100 million bbl is not a bonanza," BP's Paul Laird said. "If it were 500 million or a billion (bbl), then that would be different."


EOR is another important player in BP's North Slope campaign for some of the smaller but still significant fields on the North Slope.

One target is Endicott field, a March 1978 discovery BP operates. Cumulative production is 362.7 million bbl of oil, but the peak output days of about 115,000 b/d from 1987 through 1993 are gone, and production now is about 58,000 b/d.

BP this year launched a $37 million EOR project that is expected to add 22 million bbl to Endicott field reserves and an incremental boost in production of 12,000 b/d beginning in October.

In the EOR project, hydrocarbons previously burned for fuel will be used to make miscible injectant fluid that will be piped into producing zones via water injection wells. The miscible substance will be injected into the reservoir at 4,500 psi through existing water injection wells in a water-alternating-with-gas operation.

Facilities for the EOR project are being built by Alaska Petroleum Contractors in Anchorage. The facilities are expected to be operational in the fourth quarter.

ANWR potential

In early June, an announcement was made that might prove a significant step toward opening wildcat ground for exploration and development about 100 miles east of the Prudhoe Bay field, within the hotly disputed Coastal Plain of ANWR.

Chevron, BP Exploration, and Arctic Slope Regional Corp. (ASRC) disclosed that they had finalized a long-term lease agreement for the exploration and development of ASRC's oil and gas interests in the Kaktovik area of the North Slope. Terms of the agreement were not disclosed.

"We are pleased to continue our long-standing relationship with Chev- ron and BPX," said Jacob Adams, president and CEO of ASRC. "We have worked together for nearly 15 years to evaluate ASRC's interests in the Kaktovik area.

"Although we cannot specifically comment on details of the U.S. Geological Survey's recent report, we are pleased that they have confirmed that the Arctic National Wildlife Refuge is indeed an area with important energy resource potential, and have endorsed the widely held view that it is one of the few remaining areas in the...United States for significant hydrocarbon reserves. We continue to stress the need for the federal government to allow full access to our property."

The USGS study concluded that ANWR could hold 4.3-11.8 billion bbl of technically recoverable oil (see related story, p. 22).

Dave Birsa, Chevron exploration manager for Alaska, said, "The ANWR Coastal Plain is very special. It is on trend with the prolific oil fields of the central North Slope and has significant geological potential. It is also an area where the arctic environment must be protected. Because of our relationship with ASRC and the native villages on the North Slope, we feel we have the unique ability to explore, and ultimately develop, the resources of the area in an environmentally responsible manner that takes into consideration the needs of everyone involved."

"ANWR offers the greatest potential for a world-class oil discovery on the North Slope," added Neil Ritson, exploration vice-president for BP in Alaska. "We continue to strongly support environmentally sound access to ANWR. ANWR is undoubtedly the most important area of new potential in Alaska."

ASRC owns subsurface oil and gas mineral rights to 92,000 acres on the Coastal Plain of ANWR on the eastern North Slope. Chevron (the operator) and BP have had the land under lease since 1984. The only well ever drilled onshore on the ANWR Coastal Plain was Chevron and BP's KIC No. 1, 1s-8n-36e, which was spudded in February 1985 and abandoned in April 1986. Total depth reportedly was 15,000 ft.

Although well results remain confidential, there was at least one published report that there were oil shows.

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