Alaskan North Slope operators shift focus from stemming decline to hiking production

A delineation well is drilling ahead in the Alaskan North Slope's newest giant oil field, Alpine, which is expected to make a major contribution to North Slope operators' efforts to reverse the slope's oil production decline. Photo courtesy of ARCO Alaska Inc.

After fretting for years that Alaskan North Slope oil production would enter into a steep decline at the turn of the century, North Slope operators now are focusing instead on increasing output.

Giant fields are buoying the production curve on the North Slope. That ranges from improved and enhanced recovery efforts in stalwarts Prudhoe Bay and Kuparuk River to start-up of commercial production in the long-intractable West Sak field to development of new-play giant Alpine field.

Reversing the decline

At Prudhoe Bay, the initial estimates of original oil in place were 22 billion bbl, with ultimate reserves recovery pegged at 9.6 billion bbl. After 21 years of production, 9.7 billion bbl have been recovered. Ultimate recovery is now expected to total more than 13.2 billion bbl.

Prudhoe is believed to still have 3.5 billion bbl or more of recoverable oil. Although production has declined from an average of 777,000 b/d a year ago to about 707,000 b/d, the key producers are optimistic about the future.

"Not only will Prudhoe Bay still be producing years from now," said Ken Thompson, chairman and CEO of ARCO Alaska Inc., "but new opportunities in the Kuparuk field-America's second largest oil field-and elsewhere on the North Slope are very encouraging."

ARCO Alaska on Mar. 17 disclosed that it expects to spend $2.5 billion on oil field development and exploration projects in Alaska over the next 5 years, an increase of $800 million, or 47%, from the company's 1997 5-year plan. Current plans call for about 1,100 reservoir penetrations in the 5-year period.

The l998 5-year capital plan allocates $1 billion to existing assets, such as Prudhoe Bay, greater Point McIntyre area, and Kuparuk; $800 million to new developments, such as West Sak, Tarn, and Alpine; $275 million to exploration; and $425 million to development of exploration successes.

In a May 12 speech before financial analysts in New York, ARCO Chairman and CEO Mike R. Bowlin underscored the improved outlook for ARCO in Alaska under the new 5-year plan.

"You can quit talking about the decline in production in Alaska," said Bowlin. "We have solved that problem with additions from the new Alpine field, development of the West Sak formation, enhanced oil recovery projects, and numerous satellite field developments. The production goal of 'No Decline After '99' is being achieved."

Of what else might be expected, Bowlin and other senior ARCO executives had this to say:

"ARCO's net Alaskan oil production is expected to level off at more than 360,000 b/d after 1999, up from an expected level of about 350,000 b/d just a year ago. This latest forecast is 80,000 b/d higher than the production outlook for 2001 predicted just 4 years ago. ARCO Alaska is also setting a new target called 'Incline After '99' for increasing Alaskan production."

A pair of rich reserves are on track to brighten the production picture on the North Slope. One is Alpine field, a new giant field in the western Colville River delta area, 34 miles west of Kuparuk River field.

The other is West Sak, a large, relatively shallow viscous oil accumulation that overlies much of Kuparuk River field and has estimated oil in place of more than 15 billion bbl.

Alpine

The 10-mile long, 40,000-acre Alpine field has proved and potential reserves of 365 million bbl of oil with almost 1 billion bbl in place. ARCO Alaska Inc. is the operator. Before its parent merged with Union Texas Petroleum Holdings (see Industry Briefs, p. 35), ARCO Alaska had a 56% working interest and Union Texas and Anadarko Petroleum Corp. each had a 22% working interest. The merger boosts ARCO Alaska's interest to 78%.

ARCO Alaska drilled the discovery well at Alpine in l994, but until October l996, the discovery had not been declared commercial pending completion of field work. The delineation program included seven wells, four sidetracks, and a state-of-the-art 3D seismic survey. Four delineation wells on separate tests flowed 40° gravity oil at rates exceeding 2,300 b/d. The field is the first commercial Jurassic reservoir discovered on the North Slope.

Total field development is expected to cost $650-750 million. Plans call for drilling 100 wells. Extended-reach drilling will allow ARCO to reach and produce Alpine reserves from only two drillsites, minimizing the footprint and the environmental effects of development.

Alpine will be operated as a remote location, much like an offshore platform. There will not be a road connecting the field to Kuparuk and other North Slope infrastructure. ARCO has begun construction of a 34-mile, elevated pipeline that will pass under the Colville River by way of a 100-ft deep, 36-in. diameter bored crossing rather than by a costly bridge over the river. Start-up is scheduled to begin early in 2000, with production climbing to 70,000 b/d in 2001.

ARCO this winter drilled three Alpine appraisal wells. These tight holes included: Alpine CD1-22, in 5S-11N-5E, a horizontal well drilled by Pool Arctic's Rig No. 6; Alpine CD2-35, in 2S-11N-4E, a horizontal well drilled by Doyon Drilling's Rig No. 141; and Nuiqsut No. 1A, in 5S-11N-4E, a straight hole drilled by Pool Arctic's Rig No. 6.

West Sak

In West Sak field, ARCO as operator began commercial production from the first producing well on Dec. 26, 1997. Early in the first quarter of this year, the well was producing 200 b/d, with production being slowly increased and expected to reach the project's target of 300 b/d.

Fifty West Sak wells-including production and injection wells-are scheduled for completion by early l999. Work on the field began in October l997, and by June of this year, 15 wells had been drilled and 8 completed that are now producing about 2,000 b/d.

"Our Phase I West Sak development program is on budget, on time, and will contribute to achieving ARCO's North Slope production goal of 'No Decline After '99,' Thompson said. "This effort will develop 51 million bbl of new reserves-26 million ARCO net-and add near-term production of 4,000 b/d gross in l998, increasing to 7,000 b/d gross in early 1999," Thompson said.

A successful Phase I project would mean additional West Sak drilling. Phase II development of the West Sak core area, if approved in 1999, would require 500 additional wells, yield additional reserves of 400 million bbl, and push production to 37,000 b/d in 2001, increasing to 70,000 b/d by 2005.

Because of low-cost drilling and completion technologies, and because West Sak will make extensive use of existing Kuparuk drillsites, as well as common pipelines and processing centers, total estimated Phase I development costs are only $98 million.

SURE training

West Sak production has benefited from a novel training program called SURE, which takes its name from the program's four major components: Safety, health and environmental awareness; Unscheduled event and downtime prevention; Regional and cultural focus; and Evaluation, follow-up, and communication.

Three SURE training classes were held that brought together roughnecks, service company hands, and ARCO rig supervisors to help them keep costs down, increase rig productivity, and prevent downtime so that crews can drill more safely and efficiently.

During the first month of production from West Sak, SURE was implemented with a 2-day supervisory leadership workshop and a pair of 2-day rig team completion workshops.

According to West Sak Coordinator Keith Lynch, "SURE not only helped us meet our targets by explaining the entire project to the participants, but the training was targeted specifically at West Sak's completions."

This enabled the team to establish firm links to the project's three principal targets set by Lynch and West Sak Superintendent Steve Kruse: a capital cost target (an average of $1.7 million/well), an operating cost target ($2.35/bbl), and a production rate target (300 b/d/well).

All three Phase I development targets have been met or exceeded. One example: per-well producing rates are exceeding 300 b/d. Over 50 million bbl of gross oil reserves will be added under this phase.

Much of the field's success has depended on SURE training, instilling a team atmosphere that's been so crucial for success. Senior Drilling Engineer Tom McKay pointed to one more advantage of SURE training: "It provided a vehicle to transmit the goals and objectives of the project directly to the personnel working on the rig and in the field, people who play a key role in successfully completing the work to be done."

"We were able to clearly communicate our goals as operator and align the efforts of various contractors to achieve those goals," Lynch said. "Of course, the big difference was making the contractors a part of the planning process."

One of the keys was getting all participants to understand not only what needed to be done, but, most importantly, why it was being done, Lynch added: "Once they understood why, they had a much easier time understanding and accepting what had to be done."

Lynch also believes the training helped participants "gain the feeling that they are a key to the project's success, that their actions influence the future, and that we value their opinions and input."

In addition to the three key objectives, West Sak management attributes some other successes to the SURE training: No lost-time accidents were involved in planning and executing Phase 1 drilling; drill and case costs have been 15% below expectations; and effort has the recorded drilling "problem time" of only 7%.

The reasons why the West Sak effort is succeeding where others have not, according to McKay, "are new technology, a focus on low costs, the implementation of a true team effort, and better field crew training."

West Sak owners are ARCO Alaska Inc. 55%, BP Exploration Alaska 39%, Unocal Corp. 5%, and Mobil Corp. and Chevron Corp. combined 1%.

Miscible injection expansion

Another major project is unfolding to reach a goal of increased production at Prudhoe Bay. Owners of the Prudhoe Bay Unit (PBU) on the North Slope are moving ahead to build the largest oil field production module ever assembled in Alaska, at the Port of Anchorage.

ARCO will manage construction of the project for PBU partners and will operate the facilities once they are installed on the slope. The 2,700-ton compressor module is part of a previously announced Prudhoe Bay Miscible Injectant Expansion (MIX) project, which will yield 20,000 b/d of incremental production at Prudhoe Bay by late l999 and increase ultimate Prudhoe Bay liquids recovery by 50 million bbl.

VECO Construction Inc. began assembly of the compressor module before the end of May using a site developed by BP Exploration (Alaska) and its contractors for fabrication of modules for BP's Northstar development. The construction project will take 14 months, and the compressor module will be delivered to the North Slope by barge in summer l999.

VECO was previously selected to handle the North Slope portion of the $160 million project, which entails major modification of the Prudhoe Bay Central Gas Facility and installation of the compressor module in summer 1999.

Flowline Alaska will fabricate a pipe rack that will tie the new MIX module into the Central Gas Facility. The 135-ft pipe rack will be constructed in Fairbanks this summer.

The completed pipe rack, weighing 70 tons, will be transported in two sections by truck to the North Slope late in August.

Terms of the VECO agreement are confidential.

The MIX project will increase the amount of miscible hydrocarbon injectant made at Prudhoe Bay by 20%. Miscible injectant is used for the Prudhoe Bay gas enhanced oil recovery project, which already is the world's largest miscible injection EOR project.

The MIX project will also increase the amount of natural gas that can be produced, processed, and reinjected into the Prudhoe Bay reservoir to 8 bcfd from 7 bcfd. This increased gas handling capacity will boost oil production by 18,000 b/d by allowing the field operators to produce from a larger number of wells at any given time.

It will also increase natural gas liquids production by 2,000 b/d.

The MIX project team includes ARCO and BP personnel. Costs of the project will be divided according to Prudhoe Bay oil ownership interests, with BP paying about 50%, ARCO and Exxon each paying about 20%, and Mobil, Phillips, Chevron, and other minor owners paying the remainder.