Goal: Stem N. Slope output decline

ALASKA'S E&P OUTLOOK-2

• Selective 40 Acre Infill Drilling [59386 bytes]

Alaska North Slope production peaked at 2 million b/d in 1988 and since then has declined to a present 1.4 million b/d.

"ARCO Alaska's net production has remained flat at more than 400,000 b/d," said Ken Thompson, company president. "Our net production was actually 13,000 b/d higher in 1995 than it was in 1985."

For the next few years, however, Thompson ac- knowledged ARCO's net production will decline as North Slope oil production continues to fall.

"There's no changing that for a few years. We can slow it down. We can find new sources of oil. We can mitigate the impact of decline on our company and the state. We now believe that with innovative ideas and by pursuing new opportunities we could potentially level off ARCO's share of North Slope production by the year 2000," Thompson said.

With a five-year Alaska budget of $1.15 billion, the company has ambitious plans to continue the large role it has played in Alaskan oil development. "We've been here 40 years," Thompson said, "and we plan to be here another 40."

Infilling Prudhoe Bay

Further infill drilling is on the agenda for Prudhoe Bay field. "We'll be doing site selective 40 acre drilling," Thompson said. Development of the field started at 160 acre spacing, but most has been with the present 80 acre spacing. (Fig. 1).

"We will complete nearly 500 reservoir penetrations the next four years," Thompson said. Some will be operated by ARCO, some by BP, the field's two operators. In 1997, we will drill more new reservoir penetrations per year than in any year since Prudhoe Bay was discovered.

"We're able to go for undrained oil because of technology like coiled tubing drilling, horizontal drilling, sidetracking, and slim holes. Now we've cut the cost of an average Prudhoe Bay reservoir penetration from $7 million to $2 million. This cost reduction has allowed us to turn marginal drilling targets into attractive ones," Thompson said.

"You'll notice that I said reservoir penetrations and not wells," the ARCO executive added. "That's because ARCO has developed a whole new way of accessing reserves by drilling coiled tubing sidetracks.

"ARCO was the first company in the world to use coiled tubing to drill sidetracks this way. With our alliance contractor, Dowell-Schlumberger, we developed and patented many of the necessary tools. ARCO has done more of these jobs than anyone else.

"Eighty percent of the new penetrations at Prudhoe Bay Unit will also be horizontal wells. ARCO originally patented many of the tools for horizontal drilling."

Horizontal wells drilled for ARCO and BP under Shared Services Corp. have tapped wedge oil in the Permian Sadlerochit sand, Prudhoe Bay field's prime pay, with good results.

"The 2,000 ft horizontal wedge zone wells produce an average of 5,000 b/d," Thompson said.

The stakes are large for low cost, high performance drilling technology, Thompson added. "Low cost development drilling and even lower cost coiled tubing drilling have greatly in- creased the number of reservoir penetrations planned at Prudhoe Bay. Had drilling costs remained at the 1977 levels, it is safe to say there would be few if any drilling rigs working at Prudhoe Bay today."

Another factor in the Prudhoe Bay picture is the ARCO-proposed MIX project. The initials stand for Miscible Injectant eXpansion.

"This is a project that has been submitted to co-owners for further engineering study and hopefully for final approval later this year," Thompson said.

"The goal is to increase natural gas liquid and field gas production while also expanding the manufacturing of miscible injectant for additional enhanced oil recovery. If approved, this would be a sealift by fall 1998.

"MIX would increase black oil rate by boosting field gas offtake to over 8 bcfd," Thompson added. "It would boost natural gas liquids production by increasing CGF throughput, raising miscible injectant production, and accelerating recovery of enhanced oil recovery oil. MIX will cost approximately $200 million and add significant new reserves."

Satellite production will also play a role. "In the ARCO operated Lisburne Production Center/Greater Point McIntyre field area, we have continued to improve production from small satellite accumulations," Thompson said. "In 1993, production through the processing center was 40,000 b/d from one single reservoir-the Lisburne part of Prudhoe Bay Unit. Today the Lisburne Production Center is processing over 200,000 b/d from five different reservoirs-all within 10 miles of the plant. In addition to Lisburne, the satellites are Point McIntyre, West Beach, North Prudhoe Bay, and BP/ARCO/Exxon's Niakuk."

Exploring satellites

The future looks promising for more satellites. "We've identified across the slope 40 more satellite accumulation prospects for ARCO," Thompson said. "For the smaller satellites, we think there are numerous left."

The team that identified satellite opportunities in the Prudhoe area (Fig. 2 [30973 bytes]) was a joint team of geoscientists and engineers from ARCO, Exxon, BP, Mobil, and Phillips.

"These known and likely accumulations probably range in size from a few million to a few hundred million barrels," Thompson said. "In total, we believe just these accumulations around Prudhoe Bay may contain as much as 1.3 billion bbl of oil, with 300 million bbl recoverable.

"Over the next three years, our exploration program will be focused on testing a large number of these prospects as well as prospects surrounding other fields. We expect to drill six to eight exploratory wells a year.

"This effort should mean additional production for existing facilities across the slope. Recently we announced acquisition of Amerada Hess acreage holdings on the slope, moving ARCO into the No. 1 position as Alaska's largest leaseholder. The upside potential is substantial."

"The work in the last couple of years has lessened decline for ARCO to only 6% per year," Thompson said. "That contrasts to 12% for the whole Prudhoe Bay field.

"The ideas for the next few years-additional drill- ing and enhanced oil recovery in Kuparuk, Prudhoe Bay additional satellite accumulation development, a potential phase development of West Sak-could level ARCO's production by year 2000. We now have a saying among all our employees, 'That's a stretch goal.' That goal is 'No decline after '99.' We think the opportunities are there and we're optimistic with the investment climate."

West Sak may make a significant contribution. The resource overlies deeper producing horizons in Kuparuk River field. An estimated 16 billion bbl of oil are in place at West Sak, or some 6 billion bbl less than the original oil in place in Prudhoe Bay field. The crude checks out at less than 15 up to 22 gravity, but closeness to permafrost gives it a high viscosity.

"Our past approach was looking for a technology miracle to improve well rates of this viscous oil," Thompson said. "Our new investment team has concluded that no new technology miracle is needed.

"Rather, existing technologies by reducing costs by over 30% could make parts of West Sak viable. We're spending $10 million this year to test ideas on well completions and new ways to lower operating costs. If successful, we could begin a phased development of West Sak in 1997 using a pay-as-you-go approach.

"We'll do an area, learn from it, next year do some more, and just keep going if the economics are there. It could be significant because we see ARCO's share of recoverable barrels at 300-500 million bbl."

Colville delta decision

Another contribution to North Slope production may be in the making in the Colville River delta area, where ARCO has been active since 1992.

"About 30 miles west of Kuparuk we've been hard at work completing another season of delineation drilling on the Western Colville high," Thompson said (Fig. 3 [30855 bytes]).

"We'll decide Colville development by September. First, we have to process and interpret the large 3D seismic study we did and also assess well test results. We won't be sharing the results of our 1996 exploration effort until after a state lease sale in late August. At that time we will announce whether ARCO and our partners-Union Texas Petroleum and Anadarko-plan to proceed with commercial development."

Thompson added that ARCO already has shared the partners' conceptual development plan with state and federal permitting agencies. "It's a plan in which cost and environmental impact are reduced by eliminating road access, the use of extended reach drilling, and the construction of fewer and smaller surface locations. If the field is commercial, it is our plan that the necessary production facilities be built here in Alaska, by Alaskans."

ARCO's Colville drilling program this year included the testing of a well drilled in 1995 and the drilling of five new wells. The new wells were within a 4 mile radius of the 1 Alpine, in 1-11n-4e, which was drilled in winter 1995. ARCO took the wildcat to 7,500 ft in the original hole and drilled two sidetracks.

The new wells included 2 Bergschrund, in 9-11n-5e, which reportedly had two sidetracks, including one that bottomed about 4,100 ft southeast of the surface location and another that bottomed approximately 2,100 ft northwest of the surface location; 3 Alpine, in 25-12n-4e, which reportedly was a straight hole; 1 Neve, in 14-11n-4e, which reportedly had two sidetracks, including one that bottomed approximately 4,300 ft southwest of the surface location and another that bottomed about 1,300 ft northeast of the surface location; 1 Nanuk, in 19-11n-5e, which reportedly had one sidetrack that bottomed approximately 520 ft southwest of the surface location; and 1 Temptation, in 16-12n-4e, which reportedly had only one sidetrack that bottomed approximately 4,000 ft northeast of the surface location.

The state's proposed sale of Colville River acreage is Sale 86A, Colville River Exempt, which includes 15 tracts with an area of approximately 18,288 acres entirely within the North Slope borough. The proposed sale area is generally located in the Colville River delta along the Nechelik River channel and within the National Petroleum Reserve-Alaska, consisting of uplands and tide and submerged lands in the Colville River delta and the Beaufort Sea. If a decision is made to hold the sale, it is tentatively scheduled for Aug. 20, 1996, in Anchorage.

BP maps strategy

Despite declining production and reserves on the North Slope, Alaska will continue to be a core area of activity for BP, according to Richard J. Olver, Deputy Chief Executive Officer of BP Exploration.

"BP has played a pivotal role in Alaska's past and present, and we will play a prominent role in its future as well," Olver said in a speech earlier this year before the Alaska Support Industry Alliance's "Meet Alaska Conference" in Anchorage.

"And we believe it's possible-if Alaska can successfully compete for investment funds and we can build a bridge of near- and medium-term production from new and existing sources-that BP can hold our North Slope production nearly steady for the next 10 years.

"BP continues to generate jobs and revenues for Alaskans by investing more than half a billion dollars a year in capital projects, reinforcing our position as Alaska's No. 1 investor. Our capital spending plan calls for more than $500 million in Alaskan investments in 1996 and more than $1.5 billion over the next 3 years," Olver said.

One BP focus is on Milne Point field. The company in January 1994 acquired a 91.9% interest and became operator for the field with acquisition of Conoco's and Chevron's interests. Occidental Petroleum Corp. owns an 8.1% interest.

At the time, production from Milne Point averaged 19,400 b/d. The field, a 1969 discovery by Conoco, had produced 37.0 million bbl of oil. Thanks to a $140 million capacity enhancement and expansion project, production in February of this year averaged 27,700 b/d. After the project is completed this year, production is expected to double to more than 60,000 b/d. Cumulative production to the end of February was 54 million bbl. Estimated remaining reserves at the beginning of this year were 348 million bbl, according to figures from the Department of Natural Resources' Division of Oil & Gas.

Of February's production, 9.5% or approximately 2,600 b/d came from the Schrader Bluff pool at a depth of about 4,000 ft. The shallow oil sands are highly unconsolidated, and the estimated 2 billion bbl of oil in place are heavy, ranging from 14-20 gravity, and viscous, making it technically and commercially difficult to produce.

BP has drilled six wells and recompleted three others as part of a $21 million pilot project to further advance commercial development of the Schrader Bluff heavy crude. A decision on further development is expected toward the end of this year.

Meanwhile, BP is continuing to work with contractors and regulators to make development of Badami field 35 miles east of Prudhoe Bay commercially viable and competitive by further reducing costs.

BP drilled two appraisal wells last year that indicated recoverable reserves of 100 million bbl. This fell short of the 150 million bbl that had been targeted, making development extremely challenging despite significant reductions in drilling and construction costs that had preceded the two-well program.

Initially, capital expenditures had been estimated at $780 million. BP's goal had been to reduce costs to $320 million for the entire project, based on 150 million bbl of reserves.

Badami field was a 1990 discovery by Conoco and Petrofina Delaware Inc. BP entered the picture in January 1994 with acquisition of Conoco's 70% interest. Petrofina retained the other 30%.

On the exploratory side, BP's drilling plans this year include the 3 Sourdough, in 29-9n-24e, in the Staines River area approximately one mile west of the ANWR coastal plain and 50 miles east of Prudhoe Bay. The permitted drill site is about one mile north and slightly east of BP's 2 Sourdough, in 31-9n-24e, drilled to TD 12,600 ft in 1994. The state classified the No. 2 well as "capable of producing in paying quantities."

Meanwhile, though production declined last year on the North Slope, dropping from an average of 1,629,824 b/d in 1994 to an average of 1,565,213 b/d in 1995, a decline of 4.0%, a pair of fields reached milestones in September 1995.

Prudhoe Bay produced its 9 billionth bbl of oil. When production began in 1977, the field's estimated reserves were approximately 9 billion bbl. BP said the field is expected to yield at least another 4 billion bbl.

BP-operated Endicott field produced its 300th million bbl of oil, which was the projection of total recoverable reserves when the field began production in 1987. BP said the field is expected to produce an additional 300 million bbl. n

Cutting export costs

Still to be decided in the North Slope picture is the fate of 21 tcf of natural gas in the Prudhoe Bay reservoir that's available for export (see table).

"Together with Exxon and BP we're stressing that 'learning how to compete' is the key to making this resource commercial," said ARCO's Thompson. ARCO's share in the resource is 7 tcf.

"First, everyone must be on the same team. This is a two-way street. The producers and the state and federal governments all have roles.

"The producers must dramatically reduce project cost. Competing projects have gas at tidewater. North Slope gas is 800 miles and a $5 billion pipeline from the nearest port."

Thompson said the primary finding of a state report is that gas exports can be viable but are not yet economic and major cost reductions are necessary.

"An Alaska gas project would also be helped by innovative marketing terms that would allow us to quickly place a large volume of gas and shorten time required to get to full production," Thompson said. "Finally, the producers must develop an innovative project structure that will allow participation by lots of investors.

"The state and federal governments have a role, too. First, they must assess international LNG projects and-based on that assessment-offer competitive fiscal and regulatory terms. The state may also wish to consider direct investment in the project."

Thompson said energy demand is growing at a phenomenal rate in nations of the Pacific Rim and while a source of U.S. supply is viewed as desirable by potential buyers the cost must be competitive with other sources.

"During our trips to the Far East, the buyers have been glad to see North Slope producers. All were comfortable with a project aimed at the 2005-10 time frame. Some buyers may want to invest.

"We want to sell our gas and we will continue to explore innovations, both technical and financial, to make it happen. In the meantime, we will continue to put the gas to work to recover more oil. Over a third of our current liquid production is due to reinjection of the gas reserves. This includes natural gas liquids, condensate and EOR black oil," Thompson said.

Copyright 1996 Oil & Gas Journal. All Rights Reserved.