Alaskan exploration, development robust in `98, but low oil prices threatened future drilling levels
WHILE SCARCELY IMMUNE TO the effects of low oil prices, Alaskan operators were initially undeterred in their plans to conduct an impressive campaign of exploratory drilling on the North Slope in the 1998-99 winter drilling season.
Principal slope operators ARCO Alaska Inc. and BP Exploration Alaska Inc. at the onset of the drilling season had applied for as many as 10 exploratory wells in the theater that, apart from the deepwater Gulf of Mexico, was the costliest exploration and production (E&P) province in the U.S.
While a scarcity of rigs suggested it was unlikely that all 10 wells would get spudded during the 1998-99 season, the ambitious drilling plans flew in the face of oil prices that skidded to as low as $10/bbl as the season got under way. That pointed to the critical importance Alaska`s North Slope held for these two companies in replacing their oil production. It also pointed to the long lead times for development on the slope and the perception that oil prices would have improved by the times any new discoveries were ready to be developed.
Operators had made great progress in reducing North Slope operating costs while managing to make 14 significant oil discoveries with combined reserves totaling 1.6 billion bbl in the 1990s.
On the other hand, with Alaska North Slope crude selling for less than $10/bbl at the start of 1999, development drilling in the prolific region was slowing dramatically. And both principal operators said early in 1999 that they were reviewing capital spending and drilling plans.
High priority
It is the prolific nature of the region that kept Alaska`s North Slope high on ARCO and BP`s priority list. While such supergiants as Prudhoe Bay and Kuparuk River fields were not likely to be found again there-absent any opportunity for industry to gain access to the Arctic National Wildlife Refuge (ANWR) Coastal Plain east of the Prudhoe Bay area-a clutch of satellite discoveries of respectable size had turned up within the shadow of existing infrastructure.
These satellite strikes led ARCO and BP to become optimistic about the North Slope`s future. Only a few years earlier, the conventional wisdom held that North Slope oil production would continue to decline to the point where, not long after the turn of the century, it would not sustain the economically viable throughput threshold of the Trans-Alaska Pipeline System. ARCO Alaska`s slogan, "No decline after `99," showed how expectations had changed. And BP suggested that not only could the North Slope production curve flatten, it might well rise again in the near term.
As for ANWR, the likelihood of gaining access to this prospective, vast oil and gas resource was no brighter early in 1999 than it was a year prior. But far to the west of the refuge and within striking distance of the westernmost extremity of near-future slope infrastructure (Alpine field development), the Bureau of Land Management was implementing plans to again lease acreage in the National Petroleum Reserve-Alaska.
And operators continued to nibble at the edges of the forbidden ANWR Coastal Plain with small discoveries, potential new developments, and new wildcat drilling plans.
In the Cook Inlet region of southern Alaska, a new breed of independents was making its presence felt, taking over operations from majors and finding more hydrocarbons.
BP exploration
As of January 1999, BP was grappling with ways to rein in costs while still hewing to a robust exploratory drilling progam on the North Slope.
Near Alpine field, BP was proceeding with plans to dril the Snowcap wildcat on the east bank of the Colville River. The well, located on a lease acquired in the federal North Slope areawide lease sale in August 1998, was to target the same producing formation found in Alpine field. BP planned to take advantage of Alpine field development by sharing an ice road to the drillsite with Alpine operator ARCO.
Another satellite prospect within the boundaries of the Prudhoe Bay Unit was targeted by the V-200 exploratory and appraisal well, in 28s-12n-12e, which BP had slated to spud by Jan. 15, 1999. BP might use the drillsite as a future gravel pad from which to drill a number of sidetrack wells.
Less certain in the 1998-99 winter drilling season was the 1 Genese, which BP planned to drill from a grounded ice island in Foggy Island Bay northeast of Prudhoe Bay. BP shot 3D seismic over the prospect and began permitting efforts in fall 1998 for the well, programmed to about 12,000 ft and scheduled to spud Jan. 21, 1999, if weather allowed time for construction of ice roads to the site from the Endicott field causeway.
Partnership issues left a question mark over plans by BP and Petrofina to drill a low-risk wildcat, 98 PTAC (Point Thomson Area Cluster), in the Bullen Point area between the Point Thomson and Badami units. While BP was developing Badami, the state continued to urge Exxon Co. USA and partners to develop the Point Thomson area, which holds as much as 200 million bbl of condensate along with 3-8 tcf of natural gas. The Alaska Department of Natural Resources (DNR) in 1998 rejected Exxon`s bid to add a lease to the unit. At least three locations were considered for 98 PTAC, and BP had hoped to get leaseholders in the area to agree on a site-a goal complicated by the mix of partner interests in Point Thomson and adjacent leases. Exxon considered Point Thomson uneconomic because of lack of infrastructure but, together with other unit owners, was to develop a common database on development studies for Point Thomson and hand that over to DNR by Sept. 30, 1999.
Meanwhile, BP in 1998 held off on plans to drill an appraisal well at its Sourdough discovery, on the southeastern fringe of the Point Thomson Unit. The company cited a need to further review seismic data before proceeding with the appraisal of the find, thought to hold as much as 100 million bbl of oil, but industry observers speculated the Point Thomson impasse was the underlying reason for the delay.
ARCO`s winter program
ARCO had a fairly ambitious 1998-99 exploratory drilling program at 8-10 wells, but earlier it cited a longer-term goalofdrillingasmanyas12-15 exploratory and appraisal wells/year on Alaska`s North Slope during 5 years.
ARCO planned to drill the 2 Meltwater North exploratory well, in 17s-8n-7e, to target a prospect in the southwestern corner of the Kuparuk River Unit, just southwest of the Tarn discovery. Just a few miles to the south of that well, ARCO planned to drill the 1 Meltwater South, in 32s-7n-7e. Also on tap in the Tarn vicinity was the ARCO Cairn 1, on the southwest fringe of Tarn field.
North of Kuparuk River field, ARCO planned to drill the 3 Meltwater. Also in the 1998-99 winter drilling program was the 1 Kian, just west of Kuparuk River field.
Near Alpine field, ARCO scheduled a pair of exploratory wells, Fiord 4 and 5. Its operations plan incorporated a pair of sidetracks from those wells. ARCO apparently was trying to appraise the Fiord strike on the coast of the Colville River delta, about 8 miles north of Alpine field. If delineation proved Fiord worth developing, it could be tied into Alpine. The Fiord program also gave ARCO another chance to take a look at the Colville River delta area geology, a possible point of interest in the NPR-A lease sale. Another Colville area prospect was to get probed in the 1998-99 season with the spudding of the 1 Palm, just east of the river mouth.
Chevron`s return
Chevron U.S.A. Inc. marked its return to the Alaskan E&D scene in 1998 with a couple of deals with North Slope operators.
Chevron and ARCO Alaska in August 1998 signed two agreements designed to quicken oil exploration on more than 2.8 million acres on the Alaskan North Slope, between the Colville and Canning rivers. The agreements provided for 50-50 ownership of leases the two companies acquired in Alaska state lease Sale 87, as well as other North Slope leases.
The first agreement called for joint exploration and appraisal of a 4,000 sq mile area containing 35 tracts covering about 200,000 gross acres southwest of Kuparuk and Alpine. The tracts comprise 13 leases the two companies acquired jointly, 18 ARCO acquired solely, and 4 Chevron acquired solely in Sale 87. ARCO was designated exploration and development operator in the area.
A second alignment agreement encompassed the McCovey/Salmon area, which includes 196,000 acres in the Beaufort Sea north of Prudhoe Bay field. Under this agreement, ARCO and Chevron each held a 50% interest in 16 tracts. Here, too, ARCO was designated exploration and development operator.
The agreements followed accords struck early in 1998, in which Chevron agreed to take over operatorship of the Hammerhead and Kuvlum discoveries in the eastern Beaufort Sea.
ARCO had discovered Kuvlum and Shell Oil Co. Hammerhead, both of which were deemed subeconomic in the remote corner of the Beaufort. Union Texas Petroleum Holdings bought ARCO`s interests in Kuvlum and sought to implement a low-cost development plan that failed to materialize.ARCO,whichin1998 acquired Union Texas, had said Kuvlum needed reserves of 1 billion bbl to be economic. Chevron agreed to assume operatorship of both units, with an eye to "ultimately establish economic oil and gas operations in the (eastern) Beaufort Sea."
Alaskan officials speculated that Chevron`s long-term goal was to establish a string of discoveries around the Point Thomson area, where it held significant interests, and perhaps tie the eastern Beaufort and Point Thomson into the emerging Badami-Sourdough infrastructure.
Development delays
While exploration remained robust on the North Slope, ANS crude selling for less than $10/bbl at the end of 1998 was forcing some delays in development drilling for mature fields and for new satellite developments on the slope.
BP at year-end 1998 said low oil prices could cut development drilling in half from the 100 or so development wells that were expected to be drilled in 1998 by the North Slope operating alliance of BP and ARCO Alaska. The alliance was handling development drilling in Prudhoe Bay, Milne Point, Endicott, Lisburne, Point McIntyre, Niakuk, and Badami oil fields.
While the scope of such delays was still unforeseen when budgets were still being worked up in mid-January 1999, BP confirmed that low oil prices had forced a delay in its Liberty development project, 20 miles east of Prudhoe Bay. Plans had called for BP to start construction work on the satellite project in the 1999-2000 winter season, with first oil slated for year-end 2000. Development costs were pegged at $350-400 million for the project, expected to reach a plateau rate of 60,000 b/d. BP was considering a late 2001 or early 2002 start-up for Liberty.
BP`s plans for heavy oil development in the Milne Point Unit, targeting the Schrader Bluff formation, also were set back because of low oil prices. Schrader Bluff wells produce at rates of 500-600 b/d, well below rates of as much as 2,000-5,000 b/d typical at Prudhoe Bay and Kuparuk River. Initial development of Schrader Bluff would entail about 100 wells at a cost of about $100 million, but BP planned to drill another 10-12 pilot wells before committing to development.
Almost certain to get squeezed by the slump in oil prices was the phased development of West Sak, the vast, shallow heavy oil reservoir-with oil in place of more than 15 billion bbl-overlying Kuparuk River field, which ARCO had described as a "pay as we go" project. West Sak Phase I started up at the end of 1997 and was expected to reach 7,000 b/d by early 1999. If successful, it would be followed by Phase II development of the West Sak core area, calling for another 500 wells and production reaching 70,000 b/d by 2005.
ARCO said that, despite the downturn, it remained committed to its goal of "No decline after `99," or sustaining its production well into the next century.
BP made similar pronouncements, stating in June 1998 that it thought the 12% production decline rate at Prudhoe Bay field could be cut in half within a few years. At an analysts` meeting in Anchorage, the company disclosed plans to increase its share of North Slope production by 100,000 b/d to more than 500,000 b/d.
Even with the aggressive efforts by BP and ARCO to stem the decline on the North Slope, state officials contended that, after a slight rebound to about 1.25 million b/d in 2001, North Slope output would begin to fall off dramatically beginning in 2003.
Satellites status
Alpinedevelopment,however, remained on track for start-up in mid-2000 at a rate of 40,000 b/d, rising to 70,000 b/d in 2001.
Operator ARCO undertook a fast-track development and found ways to cut costs by deferring some well completions and the delivery of production modules to the drilling and production site. ARCO had planned to move in a rig to start development drilling in winter 1998-99 at the 365 million bbl field.
Alpine development represented a threshold in the industry`s efforts to reduce its "footprint" on the environmentally sensitive North Slope. Advances in technology enabled ARCO to reduce the size of well pads and, consequently, well spacing. Prudhoe Bay development in 1970 called for 65-acre pads with development wells spaced 120 ft apart. At Kuparuk, in 1980, well pads took up about 24 acres with well spacing of 60 ft. At Alpine, the pad covers only 10 acres, and wells are spaced 10 ft apart. In addition, Alpine development excluded reserve pits, and muds and cuttings were injected into nonproducing wells.
Badami field started up in August 1998 and originally was slated to reach a production peak of 35,000 b/d in 1999. However, late in 1998, operator BP found that the Badami reservoir was more complex than originally thought. At the start of the 1998-99 winter season, Badami was producing only about 5,000 b/d from seven wells, compared with what had been projected at that point at more than 10,000 b/d. Two thirds of the field lies offshore, where it was being developed with extended-reach wells from an onshore drilling pad. The Brookian reservoir was described as comprising compartmentalized channels in a turbidite depositional environment.
The big Northstar development began moving forward in 1998 after a delay of more than a year because of litigation. The project, considered to be the first true offshore development in arctic Alaska, entailed development of about 145 million bbl of oil from a 5-acre drilling-production island in the Beaufort Sea that would be expanded from an existing island. Plans called for drilling 23 wells to develop the field and transporting the oil through what would be the first buried subsea pipeline in the North Slope area. Gravel island construction was slated to get under way early in 1999, with first oil scheduled for early 2001 and production expected to peak at 50,000 b/d. Northstar was a 1982 Shell discovery combined with a later extension drilled by Amerada Hess Corp. BP acquired both companies` interests in 1995 and set about securing better net-profits lease terms in order to justify development
BP`s other noteworthy North Slope satellitedevelopment,Liberty,was expected to undergo first development drilling in 1999, with start-up likely in 2000. The field, about 6 miles east of offshore Endicott field, would be developed from a single offshore gravel island, with oil moving to shore via buried subsea pipeline. Reserves were pegged at 120 million bbl of oil.
Still in the consideration stage was the Sourdough development in the southern Point Thomson area. While the discovery and confirmation wells indicated the field holds about 100 million bbl of potentially recoverable oil, its distance from infrastructure made development problematic.
NPR-A, ANWR
The two massive areas on opposite sides of the North Slope`s active area had long been poles apart in perceived potential and accessibility.
But major steps taken in 1998 changed some of those perceptions.
For years, oil companies had sought to gain access to the ANWR Coastal Plain, aware that it holds North America`s largest undrilled onshore structures and possibly the only chance the U.S. had for finding another Prudhoe Bay. Vehement environmental lobbying has aborted even the most tenuous of attempts at access beyond a single wildcat Chevron drilled on native lands within the refuge-a notoriously tight hole.
Alaska`s Republican Sen. Frank Murkowski in 1998 said he was considering a bill to require the federal government to conduct 3D seismic surveys on the ANWR Coastal Plain. That came up at a Senate energy committee hearing prompted by the U.S. Geological Survey`s boosting its estimate of potential reserves within the ANWR Coastal Plain. With the USGS`s estimate raised to a mean resource of 7.7 billion bbl of producible oil, Alaskan officials argued that such estimates were based on data that included only 2D seismic and that the more advanced seismic method was needed to better ascertain the Coastal Plain`s potential. About 85% of the Coastal Plain`s potential was believed to lie within the western, "undeformed" area.
At the other end of the potential-accessibility spectrum was NPR-A, which saw limited interest and drilling in the early 1980s after an initial leasing effort by the federal government. The Department of Interior decided to allow renewed leasing in the reserve in 1998, with the first sale expected to be held in summer 1999. While industry interest in the earlier leasing effort was muted, discoveries in the Colville River delta area (Alpine, Fiord, Tarn) resuscitated interest.
The earlier leasing effort was met with minimal opposition by environmentalists as well as with minimal interest by industry. But the 1998 NPR-A leasing plan was hit with a lawsuit by environmental lobby groups challenging the Bureau of Land Management`s environmental impact statement for the lease sale (which itself was also criticized by industry as having overly stringent environmental restrictions). By year-end 1998, the state and the native-ownedArcticSlopeRegional Corp. announced plans to intervene in the suit on behalf of leasing.
Cook Inlet
Independents made waves in Cook Inlet exploration and development in 1998, beneficiaries of moves by several majors to exit or seek partners in the province and the lure of a substantial gas-prone play.
Anadarko Petroleum Corp. planned to develop the Lone Creek gas discovery north of Tyonek in the Upper Cook Inlet. The 1 Lone Creek wildcat flowed 10.6 MMcfd of gas from 53 ft of pay at about 2,400 ft. About 180 ft of potential gas pay was not tested. The discovery is only 5 miles from an existing 16-in gas pipeline. The well, on the Moquawkie prospect, was covered by a strategic alliance Anadarko agreed to with ARCO Alaska in 1996. Each company held a 50% interest in the strike.
Miami independent Forcenergy Inc. planned to drill an exploratory well to test a prospect in Redoubt Shoal oil field, a discovery that flowed 1,400 b/d but had been shut in since 1968. Forcenergy in 1998 ordered a portable drilling platform built in South Korea that it planned to install in April 1999, with a goal to spud the well by Oct. 1, 1999. If the well proved up commercial production, the platform would be left in place as a production platform; if unsuccessful, the portable platform would be moved to drill other prospects that Forcenergy had identified with 3D seismic in Cook Inlet.
Forecenergy in 1998 also completed two wells in West McArthur River field, on the west side of Cook Inlet, where it boosted production almost threefold to more than 4,000 b/d of oil.
Another Forcenergy wildcat, 1 Coffee Creek, 40 miles west of Anchorage on the west side of the inlet, was tested in fall 1998, with no final report by year-end.
Frontier Petroleum Corp., Syracuse, N.Y., in late 1998 started permitting efforts for a Cook Inlet wildcat to spud in 1999. The well would target Jurassic Talkeetna at 5,000 ft near Cook Inlet`s Drift River terminal.
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An ocean-bottom cable, shallow-water 3D seismic survey is shown being conducted by 3-D Geophysical Inc., Englewood, Colo., in the Beaufort Sea just off Prudhoe Bay field on Alaska`s North Slope. The Beaufort-North Slope region generated renewed industry interest because of a string of satellite discoveries near existing infrastructure. Photo courtesy of 3-D Geophysical Inc.
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The Trans-Alaska Pipeline System`s future viability in 1998 remained a question mark for the first decade of the 21st century, as Alaskan North Slope operators struggled to maintain slope production to ensure a minimum throughput threshold. Photo courtesy of Alyeska Pipeline Service Co.
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