While Alaska`s exploration and production activity remained robust despite another oil price collapse that lingered well into 1999, it was overshadowed by a controversial proposed megamerger-the marriage of the Alaskan North Slope`s two biggest (by far) explorer-producers.
When BP Amoco PLC (itself the product of another merger of majors) proposed to acquire Alaskan E&P pioneer ARCO for $27 billion, it sent shock waves through the state. Alarms were sounded over the prospect of a single company controlling more than 70% of the state`s production and the combination of the two biggest bidders at North Slope lease sales.
The proposed BP Amoco-ARCO merger also shone a spotlight on the emergence of commercial gas-to-liquids technology that could mean achieving two Holy Grails for Alaska: keeping the Trans-Alaska Pipeline System (TAPS) humming for years beyond its previously predicted lifespan; and finally developing the vast natural gas resource on the slope.
While both companies sought to offer assurances that the merger would prove beneficial to Alaskan exploration and development-a view met with agreement by a number of analysts-there remained enough doubts that Alaska insisted on-and won-concessions from the companies in order to secure its approval of the deal.
But even with Alaska`s nod, some US government officials early in 2000 indicated their continuing opposition to the merger, citing the potential for its dominance of North Slope E&P and how that might affect prices and supply of Alaskan North Slope crude to the US West Coast.
Meanwhile, ARCO hewed to its goal of "No Decline After `99" for sustaining its North Slope production. Together with its co-operator BP and other slope partners, it pressed a wide range of new drilling and production initiatives to stem the slope`s production decline. In late 1999, BP Amoco predicted that, if it acquired ARCO and maintained its $5 billion capital investment program for Alaska, North Slope production would increase by as much as 150,000 b/d in 5 years.
At the same time, ARCO and Anadarko Petroleum Corp. pushed development of Alpine field-the first major field development west of the greater Prudhoe Bay area infrastructure. Alpine sparked new exploratory interest in the western slope, evinced by the strong industry showing at the first sale in decades of acreage in the National Petroleum Reserve-Alaska, immediately to the west of Alpine.
Elsewhere on the slope, operators sought to notch up more of the satellite discoveries that had rekindled interest in the region as more than a repository of aging giants.
And successes near the Arctic National Wildlife Refuge Coastal Plain boosted the industry`s hopes for perhaps a limited effort at developing some of the oil and gas thought to underlie one of the most prospective untapped provinces in the Western Hemisphere.
Meantime, Alaska`s elder province, Cook Inlet, held its own as a healthy E&P theater, providing a niche for aggressive independents stepping in as some majors left the scene.
Merger questions
While US Federal Trade Commission staff cited California gasoline price concerns related to a single company`s dominance of ANS production for their recommendation that the agency file suit to block the merger as anticompetitive, Alaskan officials worried about the upstream concentration`s effects.
ANS contractors generally supported the merger, contending that the deal, while initially stressful, ultimately would lead to a more stable operating climate with a single operator. (BP Amoco and ARCO each operated roughly half of the Prudhoe Bay Unit.) The companies had expected to achieve cost savings of $200 million/year in Alaskan E&P from streamlining their combined operations before the state accord. In fact, ARCO Alaska Inc. Pres. Kevin Meyers, in testimony before the Alaskan legislature in June 1999, claimed that, with North Slope production half what it was a decade earlier, continued consolidation of operations on the North Slope would have been inevitable-perhaps even imminent-even without the merger. Prior to the merger talks, BP Amoco and ARCO had already been discussing the possibility of establishing a single operator at Prudhoe Bay.
On the other hand, Alaska`s attorney general expressed concern about a possible "chilling effect" that the resulting dominance by one slope operator might have on efforts by other companies to acquire leases, explore for, and develop hydrocarbons on the slope.
But BP Amoco pointed out that the reduced operating costs from consolidating North Slope operations would contribute to efforts by the merged company to increase capital spending in Alaska. The company said the combine would invest $5 billion in Alaska during 1999-2004, an increase from what the two firms spent during the preceding 5 years and up from what would have been the sum of their individual outlays for the period. The firm also agreed to what essentially would be a barrel-for-barrel divestment of slope production that ARCO represented, plus a divestment of a sizeable slope leasehold.
With those offers on the table, the state hammered out an agreement with BP Amoco and ARCO in December 1999 under which the merged company would sell 175,000 b/d of production, 620,000 acres of state and federal exploration leases, and matching stakes in TAPS, as well as divest operatorship of Kuparuk River and Alpine oil fields (while also selling 50.01% and 40% interests, respectively, in the two fields), among other commitments.
Even after the divestments, BP Amoco-ARCO could still achieve over $140 million of the $200 million in Alaskan cost savings it originally identified in the merger, primarily through the consolidation of the Prudhoe Bay operatorship.
No decline after `99
While awaiting the outcome of the proposed merger, ARCO undertook a wide range of projects to ensure that its North Slope production curve leveled out after 1999 rather than continued to decline (Fig. 1).
A wide range of advanced-technology initiatives in drilling, improved recovery, and enhanced oil recovery enabled North Slope operators to continually postpone the day of subcommercial production levels at Prudhoe. Such efforts enabled ARCO and BP Amoco to boost reserves estimates at Prudhoe to more than 13 billion bbl and counting from an original recovery estimate of 9.6 billion bbl. ARCO`s miscible gas EOR project had added about 400 million bbl of incremental reserves and about 60,000 b/d of production at Prudhoe.
ARCO said its Prudhoe Bay production enhancements made it an industry leader in terms of applications of designer drilling, including improved drilling technologies, coiled tubing, and horizontal drilling. At Prudhoe Bay alone, ARCO estimated it had saved $300 million in the 1990s with the use of coiled tubing technology.
Miscible gas EOR projects started at Prudhoe in 1983 and at Kuparuk River in late 1996 (Fig. 2). In addition to its large scale miscible gas EOR project at the 2 billion-bbl Kuparuk, ARCO started pioneering work on immiscible water-alternating-gas in the field.
ARCO`s extended-reach drilling efforts on the North Slope included North America records, including an 18,000-ft displacement from a drillsite at Heald Point under the Beaufort Sea to tap the Niakuk satellite, and plans for a follow-up that would feature a 21,000-ft displacement and a dual completion (Fig. 3).
Development of the massive-and for a long time seemingly intractable-West Sak reservoir overlying the Kuparuk River sands made slow progress in 1999. ARCO started producing the heavy crude from the West Sak layer in 1997 under a pilot that could lead to drilling as many as 550 wells and recovery of more than 500 million bbl from the thin but areally vast reservoir that holds 16-20 billion bbl of original oil in place. The first phase was completed in 1999; the 50 wells at West Sak added incremental production of 7,000 b/d.
The West Sak project also claimed to be the first implementation of the fieldbus protocol from the Fieldbus Foundation at an oil production site. Fieldbus-based systems were expected to help reduce by as much as 50% the incremental automation cost at West Sak, as the phased development expanded.
ARCO continued its pioneering efforts in coiled-tubing (CT) drilling at Prudhoe; it claimed the industry`s first logging with CT, first measurement while drilling with CT, and first cut of a window in casing to facilitate CT-drilled sidetracks.
Extended-reach drilling also was playing a crucial role in Alpine field development,whereARCOandpartner Anadarko raised estimates of reserves to 429 million bbl from an earlier estimate of 365 million bbl. The field was to be initially developed at a cost of $650-750 million with extended-reach wells from two drillsites. Alpine production was to flow via a 34-in. pipeline to the Kuparuk River pipeline, with first oil of 40,000 b/d slated for mid-2000 and production reaching 80,000 b/d in 2001. At yearend 1999, 12 Alpine development wells of a planned 16-18 had been drilled, and plans were under way for construction of a sea-ice road to move production modules into place. ARCO might claim another first at Alpine: the first field to be developed exclusively with horizontal wells. In addition, ARCO planned a miscible gas EOR project at Alpine upon start-up. With plans for a future 20-25 wells and the EOR project, total Alpine development costs were expected to approach $1.1 billion.
Satellites
Adding to the excitement at Alpine was the discovery of a satellite to this new, western "pole" of North Slope E&P: the 50 million-bbl Fiord find.
More such western slope discoveries were in the offing in the wake of an impressive NPR-A lease sale in mid-1999 that garnered more than $104 million in apparent high bids. Not surprisingly, Alpine partners ARCO and Anadarko dominated the sale by picking up 92 of the blocks, with heaviest bidding focused on blocks near Alpine.
ARCO in 1998 started up production from Tarn, a Kuparuk River field satellite with 30 million bbl of oil reserves, only 18 months after discovery. Other recent satellite discoveries in the Prudhoe Bay area were Midnight Sun and Sambuca, which together were estimated to hold over 30 million bbl of oil reserves.
ARCO in 1999 had plans to drill 10-12 satellite prospects/year through 2001 and estimated the satellite program could prove up as much as 1 billion bbl of oil.
Another Prudhoe area satellite, Badami, fared less well under operator BP Amoco. At yearend 1999, the firm had planned to shut down the Endicott field satellite for the winter because Badami was producing less than expected and drilling there was slowed; consequently, BP Amoco shut down the field to avoid pipeline freezing-a tack it also took in February 1999. Production was expected to resume in May 2000. The original development plan called for 20 producing wells, 15 injectors, two source water wells, and one Classs I waste disposal well. Only 10 wells had been drilled as of the start of 2000.
Meantime, BP in late 1999 submitted plans to develop, on ARCO`s behalf, the latter`s 1998-99 season Aurora discovery. The Aurora discovery well, V-200, flowed 1,900 b/d of 30° gravity oil and 1.3 MMcfd of natural gas from a 58-ft section of Kuparuk River sand. The find holds 20-35 million bbl of oil and lies in the Prudhoe Bay Unit. Aurora was to be developed with 14 wells and was expected to come on line in January 2000. It was the ninth satellite discovery in the Prudhoe Bay area during 1998-99; others included Northwest Eileen Kuparuk and the S and W-Pad Schrader Bluff satellites, in addition to Midnight Sun and Sambuca.
A string of discoveries on the eastern fringe of industry operations on the North Slope suggested they may be satellites to much-larger fields waiting to be discovered on the ANWR Coastal Plain. In fact, an analysis by consultant Arlon Tussing and University of Alaska Anchorage economics Prof. Sharmon Haley, emanating from a multidisciplinary study of community sustainability in the Arctic funded by the National Science Foundation in 1999, suggested that development from state leases adjoining the federal ANWR acreage could drain reservoirs that extend under ANWR. Anticipation of such drainage might, in turn, trigger congressional authorization for limited surface development of trans-boundary fields. That would certainly escalate the strong opposition by the environmental lobby to any industry activities anywhere in ANWR.
Other developments
Other major field developments on the North Slope marked progress in 1999-2000.
The US Minerals Management Service in September 1999 approved BP Amoco`s development and production plan for Northstar field in the Beaufort Sea off Alaska, about 12 miles northwest of Prudhoe Bay field. It would be the first oil development from an island off the North Slope without a causeway connecting it to shore and the first to include buried subsea pipelines in the region.
Plans called for drilling as many as seven wells from Seal Island into two federal leases; Seal would be expanded and used as the Northstar production island. Pipeline construction was slated to begin during first-half 2000. Project costs for developing the 145 million-bbl Northstar were estimated at $60 million for the pipeline, $90 million for drilling, and $300 million for the island, production facilities, and related onshore facilities. The facilities would be designed to handle 65,000 b/d of oil, 600 MMcfd of gas, and 30,000 b/d of water. Development drilling was expected to get under way in late 2000, with first oil expected in November 2001.
BP Amoco also submitted plans to develop Liberty oil field, in Foggy Island Bay about 5 miles offshore and east of Prudhoe Bay. Plans called for installing a conventional gravel island and subsea pipeline to shore during 2001 and 2002, respectively, with start-up anticipated in 2002. The field was estimated to hold 120 million bbl of oil.
North Slope exploration
ARCO had plans to drill exploratory wells in the 1999-2000 winter drilling season south of Tarn, near where it had drilled the 1 Meltwater South. All were in the southwestern corner of the Kuparuk River Unit.
As many as three ice drill pads were planned in each of two areas: Cairn, about 3 miles south of Tarn; and Meltwater North, 3 miles south of Cairn. Plans called for a possible three wells and three sidetracks. The first well was to spud Feb. 2, 2000, at Meltwater North, followed by wells Mar. 16 and Mar. 31.
BP Amoco in late 1999 submitted plans to drill a wildcat in the western Gwydyr Bay area north of the Prudhoe Bay Unit. The well, in 3-12n-12-e, would probe a prospect on leases held by BP Amoco, ARCO, and Exxon Corp. It lies 3 miles offshore about 6 miles north of Prudhoe Bay S pad and 4 miles east of Milne Point Unit K pad.
Seismic activity remained brisk on the slope. ARCO at the outset of the 1999-2000 winter drilling season had plans to keep two crews busy shooting five seismic surveys during the season. At least three of the surveys were to target prospects in the NPR-A acreage ARCO acquired in 1999.
Meantime, MMS in 1999 issued a call for information and nominations for its proposed area-wide Beaufort Sea oil and gas lease Sale 176, which it scheduled for early 2002.
Cook Inlet
In addition to its growing presence on the North Slope, Anadarko maintained a strong presence in Cook Inlet, Alaska`s other producing province.
Plans called for Anadarko and 50-50 partnerARCOtodevelopthe Moquawkie prospect discovery the partners drilled in 1998. The 1 Lone Creek discovery well flowed 10.6 MMcfd of gas, one of the best shallow-gas tests in the vicinity.
Anotherambitiousindependent workinginAlaska,Houston-based Forcenergy Inc., stumbled in its plans to install a refurbished platform to develop the Redoubt Shoal field and prospect in the inlet. Partner Unocal Corp., which had acquired a 30% interest in the Redoubt Shoal Unit, exercised its option to pull out of the project in early 1999-after the two had signed an operating agreement and after construction had begun on the platform. The pullout was expected to leave Forcenergy short of cash to complete the platform, resulting in a likely delay of the project. The original agreement called for drilling an exploratory well from a jack up by Jan. 1, 2000, or contracting for a platform by that time. The well would probe a prospect identifiednearthesubcommercial Redoubt Shoal oil discovery made by former unit operator Marathon Oil Co. It estimated the Redoubt Shoal project could recover more than 40 million bbl of oil. In early 2000, no further progress on the project was noted.
Another Houston independent joined the Cook Inlet E&D fray in 1999. Tiny Escopeta Production Alaska Inc. won 12 tracts in the April 1999 Cook Inlet area-wide lease sale, all near existing production or discoveries. The sale garnered more than $2.4 million.
Drawing the most attention on the Cook Inlet area`s E&D scene in early 2000 was not a conventional oil or gas play but a coalbed methane exploration and development project undertaken by Unocal north of Anchorage. Unocal in 1999 submitted a plan to explore 72,000 acres comprising the Pioneer coalbed methane unit, which lies between the Anchorage suburbs of Wasilla and Houston, with three exploratory wells, and developing the resource with a series of pod-style cluster wells.
The prospects of healthy oil and gas prices in 2000 coupled with a likely resolution-one way or the other-of the BP Amoco-ARCO merger proposal augured well for a continuation of the revival on Alaska`s E&D scene.
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Prospects for the Trans-Alaska Pipeline System`s future brightened at the turn of the century, with a strong exploration and development campaign yielding a string of satellite discoveries and new field developments and possible plans for a gas-to-liquids project utilizing North Slope gas. Photo courtesy of Alyeska Pipeline Service Corp.
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