Alaskan activity surges amid brightenting outlook for ANWR, ANS gas work

Alaska's upstream oil and gas industry entered 2001 confronted with the prospect that its two most cherished goals might be within reach.

The first, monetizing Alaskan North Slope natural gas reserves, started the year with the kind of momentum that lent credibility to proponents' claims of marketing the gas by 2006.

The second, opening the Arctic National Wildlife Refuge Coastal Plain to exploration and development, had a chance—if a slim one—at becoming reality, which seemed impossible before mid-2000.

The divergent prospects owed directly to political and energy market events of 2000. A string of energy market woes breathed life into both possibilities, especially the push to bring ANS gas to market. A series of shortages and price spikes including gasoline, heating oil, electric power, and especially natural gas gave energy issues urgency during a presidential election year. One of the key campaign planks of the eventual victor, George W. Bush, was to bolster US energy resource development.

But it was the changing of the guard at the White House that allowed ANWR Coastal Plain exploration and development (E&D) to become part of the discussion. Bush unequivocally stated his support for ANWR Coastal Plain E&D and even after his inauguration continued to make the opening of the refuge's coastal strip the centerpiece of his energy program.

Outgoing President Bill Clinton could have made the effort much more difficult had he opted to name ANWR a national monument, as many in the environmentalist lobby had persuaded. Clinton demurred, contending that existing law effectively inhibited drilling there. But had US Vice-President Al Gore won the US presidency, he certainly would have killed any bid to explore the ANWR Coastal Plain—probably through an executive order, such as granting national monument status.

While Alaska's oil and gas industry remained largely healthy despite the deepening decline at North Slope giant oil fields Prudhoe Bay and Kuparuk River, the realization of either prospect—ANWR leasing or gas monetization—would mean a massive boost to upstream spending on the North Slope.

Successful development of ANWR Coastal Plain oil fields—if exploration results matched postulated potential—would keep the Trans-Alaska Pipeline System (TAPS) flowing for another generation.

Developing North Slope gas on the scale expected would create another giant northern Alaska industry that could rival—and perhaps surpass—the oil industry there.

Much of the support for these two proposals hinged on the direction of oil and gas prices in the early phase of the Bush administration. Most forecasts in early 2001 were for natural gas prices high enough to sustain a gas project.

Monetizing ANS gas, such as with a pipeline to the Lower 48 (by no means the only option) had much greater support than ANWR exploration did in 2000; a pipeline had been permitted nearly 20 years earlier.

Opening the coastal strip of ANWR to E&D promised to be much dicier. Not only was there powerful opposition arrayed against it, any public support for the effort was likely to hinge on expectations that oil prices would remain at uncomfortably high levels. That was what gave TAPS and Prudhoe Bay development the political impetus those megaprojects needed in the 1970s. But most oil price forecasters in 2000 were less sanguine about the prospect of sustained high oil prices than they were about North American gas prices.

Still, to even have had ANWR on the table for discussion at the same time that North Slope gas development prospects were their brightest in 2 decades made 2001 potentially a watershed year for Alaska's upstream industry.

Another watershed emerged late in 2000, as BP took over solo operation of the Prudhoe Bay Unit, ending decades of competing operatorships of North America's biggest oil field. The change came with BP's acquisition of ARCO and the subsequent sale of ARCO North Slope interests to Phillips Petroleum Co.

In the meantime, North Slope E&D action continued to percolate in 2000-01. Alpine oil field came on stream, pushing the western frontier of North Slope oil development farther west.

And North Slope operators pressed other field developments in the shadow of Prudhoe Bay area infrastructure.

North Slope exploration pushed westward as well, as operators began drilling the first wildcats on newly leased acreage in the National Petroleum Reserve-Alaska. NPR-A exploratory interest and subsequent leasing were revived with a string of discoveries (including Alpine) to the east along the bordering Colville River delta.

Cook Inlet E&D activity continued apace. The prospect of a tightening gas supply-demand balance in south-central Alaska renewed interest in gas E&D in the region.

Elsewhere in Alaska, the state pressed initiatives to spur exploration outside the traditional regions of the North Slope-Beaufort Sea and Cook Inlet. It also unveiled its 5-year leasing program for 2001-05.

Colville River delta

The start-up of Alpine field in the Colville River delta not only bolstered Alaskan oil production, it also established a new western outpost for North Slope development that could have—like Prudhoe Bay and Kuparuk River fields—its own satellite developments.

Alpine was producing about 80,000 b/d at the outset of 2001. Operator Phillips Alaska Inc. (78%) and Anadarko Petroleum Corp. (22%) cited the 429 million bbl field as the largest onshore oil field discovered in the US in more than a decade.

As of yearend 2000, 30 wells—16 producers and 14 injectors—had been completed at the first Alpine drillsite. Full Alpine development called for two drillsites and more than 112 horizontal wells.

Included in first-phase development was a miscible enhanced oil recovery project—implemented at start-up—using a miscible injectant generated from field gas. Total field development costs were pegged at more than $1 billion.

Elsewhere in the Colville River delta area, Phillips applied to the Alaska Department of Natural Resources Division of Oil and Gas (DOG) to form the Southeast Delta Unit in an area between the Kuparuk River and Colville River units.

Phillips sought to include seven oil and gas leases in the unit, covering two oil-prospective structures in the Torok formation, Atlas and Cronus. The Atlas wildcat, programmed to 6,200 ft TVD in the north-northeast portion of the unit, was slated to spud in the 2000-01 winter drilling season and wrap up by June 1, 2001. The Cronus wildcat, probing a structure in the south-southeast part of the unit, would spud in the 2001-02 winter season and be concluded by June 1, 2002.

Prudhoe-Kuparuk area

A highlight of the Prudhoe Bay-Kuparuk River area in 2000 was confirmation of a sizeable field, Meltwater North.

Phillips and BP Exploration (Alaska) Inc. estimated the find's proved and potential reserves at 50 million bbl of oil. The Meltwater North discovery well, about 10 miles south of Tarn, another Kuparuk area satellite, flowed on test at a rate of 4,000 b/d of 37° gravity oil. A second exploratory well and a sidetrack confirmed the northern portion of the reservoir. The field lies immediately south of the Kuparuk River Unit.

The acreage covering Meltwater North was acquired in June 1998 during the state's first areawide oil and gas lease sale. The partners covered the prospect with 3D seismic, allowing the discovery to be made in less than a year. Development plans were still taking shape in early 2001.

BP expected to have five more Prudhoe Bay satellite fields on stream by the end of 2001.

By that time, the operator said late in 2000, Aurora, Borealis, Midnight Sun, Northwest Eileen-Schrader Bluff, and Polaris would be adding 40,000 b/d to North Slope oil output. All five were under development as 2001 started.

The five fields' production was expected to peak at 70,000 b/d in 2004-05.

Also helping steady the North Slope production level was Phillips's resumption of drilling in the giant West Sak heavy oil reservoir overlying Kuparuk River oil field in June 2000. Drilling had been suspended amid lagging oil prices in 1998-99, followed by the transition of former operator ARCO's being absorbed into BP.

Phillips had budgeted three horizontal wells for the field in the 2000-01 drilling season, and the first one—with two 3,000-ft laterals—came in at more than 1,000 b/d, about double the company's expectations.

Phillips, Chevron USA Inc., and Calgary independent Alberta Energy Co. in August 2000 formed a joint venture for E&D covering almost 150,000 acres in the North Slope-Beaufort area.

Under the JV, AEC's Alberta Energy Co. Oil & Gas (USA) Inc. unit would earn a one-third interest in the 28,504-acre McCovey Unit in the Beaufort Sea near Prudhoe Bay through a farm-out of the initial exploratory well there. Plans called for drilling the wildcat from an ice island during the 2000-01 winter drilling season. Phillips and Chevron each would hold a one-third interest as well.

The JV also would cover 114,262 acres comprising the Grizzly Gomo prospect south of Kuparuk River field. Interests would be Phillips and Chevron 40% each, with AEC earning via farm-out a 20% stake in the prospect. Drilling would get under way during the 2001-02 winter season. Both prospects are covered by 3D seismic.

Disappointing production results led BP to obtain a partial relinquishment of some of the acreage in its Badami sands participating area east of Prudhoe Bay field.

The state, which had approved the Badami development plan in 1997, approved the relinquishment to 3,680 acres from the original 12,737 acres. Original plans called for drilling 38 development wells and 15 water-miscible fluid injectors.

Beaufort Sea projects

In the Beaufort Sea, development of Northstar and Liberty Island fields also marked progress as 2001 unfolded.

BP's Northstar development in 2000 saw the reshaping of Seal Island, a gravel exploration island 6 miles from Prudhoe Bay, into a permanent production island for Northstar.

Construction also continued on what BP claimed to be the largest oil and gas processing modules ever built in Alaska. They were to be installed on the production island in summer 2001.

Northstar was discovered and appraised by Shell Oil Co. and partner Amerada Hess Corp. in the early 1980s but never developed because of the high development costs. Subsequent improvements in the royalty regime followed BP's acquisition of Shell and Amerada interests, and the project was approved in 1996—only to run afoul of legal and permitting delays. The project got back on track in 1999.

Northstar, with 176 million bbl of oil reserves, was to be developed with 13 producers and nine injectors (six water, three gas). It was slated to begin production in late 2001.

Meanwhile, the US Minerals Management Service in January 2001 issued a draft environmental impact statement (DEIS) for BP's Liberty project in the Beaufort Sea (Fig. 1). BP wanted to develop Liberty from a gravel island in the Beaufort 20 miles east of Prudhoe Bay and about 8 miles east of Endicott field—the first Beaufort Sea development. The company estimated Liberty reserves at 120 million bbl of oil.

If the project were approved, work would occur during two winter seasons, with island construction getting under way in 2003 and laying of a pipeline to shore to occur in 2004. The field would start up in 2004.

NPR-A exploration

A surge in exploration on the western third of the North Slope was getting under way in earnest in 2000.

Although the NPR-A had seen exploration activity during the early 1980s, it met with little success. The Colville River delta discoveries renewed industry interest enough to trigger another federal lease sale in the NPR-A, with most of the attention focused on the eastern corner of the reserve bordering the Colville River.

Phillips had applied for permits to drill five exploratory wells in addition to its plans to test the Rendezvous A and 1 Spark wildcats, drilled and suspended in winter 1999-2000. There were no plans to reenter Clover A, an NPR-A well also drilled in winter 1999-2000.

The permitted exploratory wells included Clover B, Lookout A, Moose's Tooth A, Moose's Tooth C, and Rendezvous B. Phillips also planned exploratory wells at two of the prospects targeted for testing in the 2000-01 drilling seasons: four at Spark and Rendezvous. The company also added three prospects to its NPR-A portfolio: Hunter, Outlook, and Oxbow. Hunter is just northwest of the village of Nuiqsut in the eastern corner of NPR-A, and Outlook and Oxbow are near the Spark and Rendezvous prospects, respectively, just west of the Colville River.

BP also was to be active in NPR-A exploration. Overall, the company had planned to drill 8-10 exploratory wells in 2001 in Alaska, vs. 2 in 2000 and 1 in 1999. NPR-A was to see a big chunk of that action, with eight locations permitted in the reserve as of late 2000.

Of special interest was a giant structure that BP thought had about the same areal extent as Kuparuk River field. To test that structure's potential, it planned to drill as many as three directional wells for each of two ice pads 8-12 miles apart on the structure. Partners with BP on the prospect were Chevron and Phillips. Their combined estimated spending on the program was $30 million.

State leasing efforts

Alaska's DOG in 2000-01 rose to the challenge of revived interest in state exploration by accelerating its lease sale schedule and devising innovations to attract interest to largely overlooked areas.

An area-wide lease sale held in November 2000 drew high bids totaling more than $10 million, as 158 bids were received on 149 tracts. The Phillips-Chevron-AEC group dominated the sale, offering almost $5.8 million for 32 tracts. The runner-up bidding group was Anadarko and AEC, which focused on acreage south and southwest of the undeveloped Point Thomson giant gas-condensate field near the western border of ANWR.

Because prospects there were thought to be gas-prone, the Anadarko-AEC bidding apparently represented a change in North Slope leasing and exploration strategy: an on-purpose hunt for natural gas.

In all during 1999-2000, 268 lease tracts were sold in five sales for bonus bids totaling $16 million.

DOG also unveiled its 5-year lease sale schedule in late 2000 (Fig. 2). The agency slated 16 lease sales during 2001-05: 6 on the North Slope, 5 in the Beaufort Sea, and 5 in Cook Inlet.

The state moved to area-wide leasing beginning in June 1998, with a North Slope sale, followed by the first area-wide leases sales in Cook Inlet in April 1999 and in the Beaufort Sea in November 2000.

In addition, Alaska had undertaken what it referred to as an exploration licensing program to supplement the leasing program and to encourage exploration within remote areas outside the traditional provinces of the North Slope, Beaufort Sea, and Cook Inlet. Under this program, the holder of an exploration license received the exclusive right to explore an area of 10,000-500,000 acres for up to 10 years. Instead of an up-front bonus, as in leasing, the licensee had to commit direct expenditures for exploration.

The state issued one such exploration license, to Anschutz Exploration Corp., Denver, in October 2000, covering almost 319,000 acres around Glenallen bordering the western edge of the Wrangell-St. Elias National Park in south-central Alaska.

In April 2000, Forcenergy Inc. (later acquired by Forest Oil Corp., Denver) submitted separate license proposals for two 474,240-acre areas in the Susitna River Valley just south of Talkeetna. If approved, the licenses would probably be issued by yearend 2001.

In addition, Alaska implemented a shallow gas leasing program to encourage development of low-cost energy for remote villages. Shallow gas leases were available on a noncompetitive, first-come, first-served basis, granting a licensee an exclusive right to explore for, develop, and produce natural gas above a depth of 3,000 ft.

The program, which kicked off in February 2000, had netted 270 applications by yearend 2000.

Cook Inlet update

Natural gas supply concerns remain-ed uppermost in the minds of Cook Inlet operators chasing prospects in the province.

Questions over the viability of Cook Inlet as a natural gas producing area arose with decline in the province's reserves-to-production (R/P) ratio. Official estimates pegged Cook Inlet reserves at 1.05 tcf, or about 5 years' worth of consumption. However, estimates of possible and postulated resources were put at 2.1 tcf and 3.4 tcf, respectively.

The supply concerns were strong enough that proposals had been floated to require—should a North Slope gas pipeline be built—that planning consideration also be given to a spur to the same south-central Alaska area that Cook Inlet supplied, to ensure the region had adequate gas supply.

Meanwhile, Cook Inlet operators pressed E&D plans in the region.

In early 2001, Forest Oil was drilling a 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. Predecessor company Forcenergy in 1998 ordered a portable drilling platform—dubbed Osprey and built in South Korea after extensive delays—that was installed in summer 2000. If the well promised commercial production, the platform was to be left in place as a production platform; if unsuccessful, the portable platform would be moved to drill other prospects that Forcenergy has identified with 3D seismic in Cook Inlet. Production facilities would be built onshore, and offshore pipeline construction was possible in fall 2001. Field start-up could come in early 2002.

Also in late 2000, Forest was firming up plans to spud its 1 Kustatan wildcat in the West Forelands area of Cook Inlet. Elsewhere in the West Forelands area, Forest was seeking permits to work over an old gas well to supply natural gas for fuel gas for its West McArthur field operations.

Forest also operated an infill redevelopment program in West McArthur, where in late 2000 it completed a producer that came in at 2,000 b/d of oil.

Another revival was on tap at Nikolai Creek in western Cook Inlet. Anchorage independent Aurora Gas LLC envisioned spending as much as $12 million to redevelop a shut-in gas field in the Nikolai Creek Unit. Aurora acquired 50% of the unit from Marathon Oil Co. in early 2000 and the remaining 50% from Unocal Corp. the following summer. Plans called for laying a 2-mile pipeline from the field to Unocal processing facilities at Granite Point. From there, gas was to be compressed for injection into the Cook Inlet pipeline system for sale in the Anchorage area. Aurora started reentering the suspended Nicolai Creek No. 3 at yearend 2000.

The roster of independents working in Cook Inlet grew in 2000. Northstar Energy Group Inc., Tulsa, acquired Alaskan firm Gas-Pro Alaska LLC in early 2000 and began permitting efforts for an exploratory well at the North Fork prospect, the first of a series planned in the Cook Inlet area.

Unocal's Alaska unit earmarked $40 million for Cook Inlet exploration and development in 2001, with an eye to responding to a gas shortage it expected in the region during 2004-07. Unocal contended a gas pipeline to south-central Alaska wouldn't be economic before 2010, and it saw a need to find more gas to bridge that gap.

One key customer for that gas would be the Nikiski fertilizer plant, which Unocal sold to Agrium Corp. Unocal had a 9-year supply contract with the plant.