North Slope producers see Alaska renaissance as TAPS reaches 20

Shown is Pump Station 6 of the Trans-Alaska Pipeline System (TAPS) operated by Alyeska Pipeline Service Co. TAPS' future is looking brighter with an exploration and development renaissance under way on Alaska's North Slope. Photo courtesy of Alyeska.

• Prudhoe bay drilling [10661 bytes]
• Arco Alaska's production goal [27346 bytes]
• West Sak development plan [35653 bytes]
• Well 15-45 Wellbore schematic [36670 bytes]

With that milestone attained, the principal Alaskan North Slope producers are turning their sights toward keeping the world's most famous pipeline operating for perhaps another generation.

North Slope operators see a "renaissance" under way in the prolific region that, despite a recent production decline, still accounts for about 20% of U.S. oil production.

Developing many recently discovered small-to-medium sized oil accumulations, pushing the technology envelope on improved and enhanced oil recovery methods in the existing giant fields, and gaining a better understanding of North Slope geology to find still more reserves are key to sustaining TAPS throughput well into the next century.

Milestones and renaissance

With cumulative production of 9.4 billion bbl as of Jan. 1, Prudhoe Bay by yearend is expected to reach another milestone with production of its 9.6 billionth bbl of oil.

The figure is significant, because that is the total ultimate recovery of oil that many predicted when the field went on line.

Prudhoe is believed to still have 3.5 billion bbl or more of recoverable oil remaining. Production has declined from an average of 957,927 b/d a year ago to 890,794 b/d at the beginning of this year-but far from being despondent, major producers are optimistic about the future.

''There is an oil field renaissance occurring in Alaska," said Ken Thompson, president of ARCO Alaska Inc.

"It's a renaissance sparked by the industry's new, lower-cost structure; technology advancements; and a state government that has changed its tax, royalty, and leasing policies to encourage more enhanced oil recovery and more exploration and satellite field development."

ARCO stabilizes production

Thompson said ARCO expects to stabilize its net Alaska production during the next 5 years. While ARCO's production will vary year-to-year, it is expected to average 350,000 b/d during the 5-year period.

''This is a significant improvement over our 1996 forecast, in which (our) production fell below 300,000 b/d in 1999,'' Thompson said. '"We had to do better, so we put in motion a plan to achieve 'No Decline After 99.'"

Of the 50,000 b/d improvement, 90% will come from known oil accumulations such as Alpine, Tarn, and West Sak, Thompson added, and much will be developed and produced at low cost through additional drilling and enhanced oil recovery in currently producing North Slope fields.

"Over the next 5 years, we expect to invest $1.7 billion in Alaska, and we expect this capital program to add net reserves of 965 million bbl," Thompson said.

Cutting costs

"Our strategies are based on our new cost structure. Since 1991, we've made dramatic reductions we can sustain into the future. Net lease operating costs have been reduced 38% by eliminating duplication at Prudhoe Bay and consolidating field support services, by forging strategic alliances with key contractors and suppliers, and by developing better, more cost-effective ways to maintain our facilities."

Examples include cutting the cost of corrosion prevention with the use of new high-performance chemicals and reducing the frequency of maintenance shutdowns with the use of advanced-technology internal inspection techniques, Thompson said.

'"We've cut net overhead costs 53% by eliminating low-value support services and by streamlining and automating the way we purchase materials," Thompson said. "Today the company is appropriately sized to meet the challenges and pursue the opportunities we see ahead.

"Net operating and overhead costs were $2.29/bbl in 1991 and $1.54/bbl in 1996. That's a savings of 75¢/bbl, or $150 million in absolute annual cost savings that go directly to our bottom line. Considering inflation and that production declined slightly over this period, these absolute and per-barrel cost savings are even more dramatic."

On the development side, Thompson said the company has cut the cost of an average development well by one third: "We obtained these cost savings by reducing the time required to drill conventional wells and by drilling smaller-diameter slim holes with lower casing, mud, and cement costs.

"Coiled tubing technology developed at Prudhoe Bay has enabled us to cut the cost of sidetrack completions by almost half. We estimate that the use of coiled tubing for well workovers and for drilling sidetracks has already saved $300 million net vs. conventional technologies. Future savings will be even greater.

'"Finally, we cut the cost of hooking up new wells 60% by making greater use of various technologies. Our new cost structure gives us staying power when oil prices are low and earning power when prices are high. Just as important, it allows us to pursue growth opportunities we couldn't consider 3 or 4 years ago," Thompson said.

Alpine project

The North Slope outlook is brightened by the Alpine field, a giant new oil field in the western Colville area 30 miles west of Kuparuk River field.

The 10-mile-long, 40,000-acre field has combined proven and potential reserves of 365 million bbl with almost 1 billion bbl of original oil in place, making Alpine one of the largest fields found in the U.S. this decade.

ARCO's net reserves at Alpine are estimated at 170 million bbl. Last year, the company booked 65 million bbl with a remaining 105 million bbl to be booked in the future.

ARCO with 56% working interest is the Alpine operator; Anadarko Petroleum Corp. and Union Texas Petroleum Alaska Corp. each have 22% working interest.

ARCO Alaska drilled the discovery well in 1994, but until October 1996 the discovery had not been declared commercial pending completion of field work. The delineation program included seven wells, four sidetracks, and a 3D seismic survey. Four Alpine delineation wells were tested and on separate tests flowed 40° gravity oil at rates exceeding 2,300 b/d.

''This high-gravity crude surprised us and is a significant plus in terms of flow properties and market value," Thompson said. '"We expect this high quality crude to command a premium of as much as $1/bbl as compared with other North Slope oils. Importantly, Alpine is the first commercial Jurassic reservoir discovered on the North Slope. Total field development is expected to cost $650-750 million."

Extended-reach drilling will allow ARCO to reach and produce Alpine reserves from only two drillsites, minimizing the footprint and the environmental impact of the development.

"Alpine will be operated as a remote location, much like an offshore production platform," Thompson said. ''There will not be a road connecting the field to Kuparuk and other North Slope infrastructure.

"To further save costs, we plan to construct a 34-mile, elevated pipeline that will pass under the Colville River by way of a 100-ft deep, 360-in. diameter, bored crossing rather than building a costly bridge over the river.

"Start-up will occur early in 2000, with production climbing to 70,000 b/d in 2001. Our rate forecast and reserve estimates do not include recovery factor improvements we are striving to make, nor do they include satellite oil accumulations in the Alpine area that could someday prove commercial. Additional 3D seismic is planned to further assess the potential of this area," Thompson said.

Tarn

Another North Slope discovery was disclosed in March by ARCO Alaska Inc. and BP Exploration (Alaska) Inc. on the Tarn prospect off the western boundary of the Kuparuk River field.

''At Tarn we discovered 38° gravity oil in three delineation wells and a sidetrack," Thompson said. ''This higher-quality, higher-wellhead value oil is a big positive for Tarn. We stimulated and tested the first well, and it flowed at a steady rate of more than 2,000 b/d.

"This accumulation contains proven and potential gross reserves of 55 million bbl, 28 million bbl ARCO net. ARCO will book 10 million bbl in 1997."

Start-up of Tarn is planned late in 1998 or early in 1999 with initial production of 10,000-15,000 b/d. ARCO holds a 58.5% interest in the Tarn prospect; BP holds a 41.5 % interest.

Kuparuk area E&D

At the same time the Tarn discovery was unveiled, ARCO and BP disclosed the signing of an alignment agreement that will quicken the pace of oil exploration in and around Kuparuk River, the second largest oil field in North America.

The agreement provides for joint exploration and appraisal of a 580-sq mile area that includes the ARCO-operated Kuparuk River Unit and adjacent acreage. The agreement also allows production of satellite oil accumulations through existing Kuparuk facilities and clears the way for West Sak development.

"These agreements make it clear up front who owns what and how the costs and benefits of exploration and development will be shared among the partners," Thompson said.

"This eliminates the need to negotiate the terms for every exploration well as well as the need for time-consuming equity negotiations when a discovery is made. These agreements encourage exploitation of all the producing horizons in and around known fields. They also allow access and establish terms for producing satellite accumulations through existing facilities."

The agreement aligns all ARCO and BP ownership for tracts within the Greater Kuparuk Area at 58.5 % for operator ARCO and 41.5 % for BP.

''The Kuparuk agreement is important, because previously we had determined ownership of only the oil produced from the Kuparuk River formation. As a result, that is the only formation now produced at Kuparuk,'' Thompson said.

"This agreement clears the way to pursue production from shallow formations like the West Sak and Tabasco that can be developed near term. It also clears the way for evaluation of deeper formations like the Sag River, Ivishak, Lisburne, and Endicott, from which production is occurring in other North Slope fields.

"Because so much production and transportation infrastructure is already in place, new discoveries in the Greater Kuparuk Area can be in the pipeline very quickly-sometimes in a matter of months."

ARCO has 2D seismic covering the entire Greater Kuparuk area and much of the Alpine area. The company is acquiring additional 3D seismic in these areas to better define prospects already recognized and to identify new ones, Thompson said.

''This is important because advanced AVO 3D seismic surveys have enhanced our ability to identify the stratigraphic traps that exist in this area. This technology led to the Tarn exploration effort that is now under way and was the key seismic technology leading to discovery of the Alpine field in 1994."

In the wake of Alpine and Tarn discoveries, Frank M. Brown, ARCO's senior vice-president, Kuparuk Business Unit, said of Kuparuk and the surrounding area: "This could be one of the most exciting oil exploration areas in the U.S. coming up."

West Sak

ARCO's game plan also calls for pursuing to fruition new growth opportunities like West Sak.

The Kuparuk Alignment Agreement clears the way for production from the large viscous oil resource by allowing ARCO to make extensive use of existing Kuparuk facilities and other infrastructure.

'"Facility-sharing and low-cost drilling and completion technologies make West Sak development possible," said Thompson. "By making use of existing drillsites, existing processing plants, and existing pipelines, we expect to develop this resource at a cost of $2/bbl.

'"Phase 1 work on the West Sak sweet spot will begin at drill sites 1C and 1D in October. First production is expected by yearend, with peak production of 7,000 b/d by mid-1998.

'"Phase 1 calls for 50 wells and will add 50 million bbl of new reserves. Success in Phase 1 will clear the way for additional West Sak development. This will be a well-planned, pay-as-we-go effort. If things work out the way we expect, we will drill an additional 500 West Sak wells, allowing recovery of an additional 400 million bbl of oil.

''This will boost West Sak production to 11,000 b/d by 2001 and eventually to a peak production of almost 70,000 b/d," Thompson said.

Enhanced recovery

Miscible-gas enhanced oil recovery will play a significant role in stabilizing North Slope production.

"Alaska is where we earned our reputation as EOR leaders, because it's in Alaska that we operate the largest miscible-gas enhanced oil recovery projects in the world," Thompson said. "The largest is at Prudhoe Bay, where miscible gas EOR will increase ultimate recovery by 400 million bbl and now contributes 60,000 b/d of incremental production.

''At Kuparuk, this same technology will increase ultimate recovery from America's second largest oil field by 290 million bbl. The largest portion of this additional recovery at Kuparuk-200 million bbl-is the result of the Kuparuk Large Scale EOR (Lseor) project, The rest comes from the small-scale pilot project that preceded Lseor and a number of smaller projects, like the EOR test now under way in the northern half of the field," Thompson said.

Brown credited the alignment agreement that ARCO and BP disclosed in March with being the key that is opening Kuparuk and surrounding areas to an important chapter in the Alaska renaissance.

The agreement expands the area where we have facilities and additional space available to us," Brown said. "We can expand 3D seismic and test these concepts. We're at the very early stages conceptually."

Other Kuparuk owners in addition to ARCO 55.17% and BP Exploration 39.19% are Unocal Corp. 4.95%, Mobil Corp. 0.36%, Exxon Corp. 0.22%, and Chevron Corp. 0.11%.

Brown said the Lseor project, which ARCO as operator started up in September 1996, will slow decline in the Kuparuk reservoir. Production had peaked in 1992 at an average of 322,000 b/d and declined to an average of 267,000 b/d in January 1997: "Reserves of 2.2 billion bbl are a little over 50% produced," Brown said.

ARCO since last September has expanded Lseor from four drillsites to 20 drillsites in the southern half of Kuparuk River field. The project is performing well and is expected to yield incremental new production of 12,000 b/d this year, increasing to peak production of 40,000 b/d by late in 1998.

''If Lseor performs as well as expected, this process will be expanded to the rest of the field,'' said Thompson. "So there is opportunity for additional growth that is not yet in our base plan."

Meanwhile, ARCO and partners, Exxon and BP, are pursuing expansion of Prudhoe Bay's miscible injection project (MIX). The new project would increase Prudhoe Bay liquids production by 20,000 b/d, Thompson said. "We anticipate project approval during the spring of this year and start-up of this $165 million project in late 1999."

The Point McIntyre field, 2 miles north of the Prudhoe Bay producing area, is being studied for another enhanced recovery project. Waterflooding would be continued with addition of an enriched miscible-gas injection project, according to Kevin O. Meyers, ARCO vice-president, Prudhoe Bay Unit. The field's owners are ARCO 30.1%, Exxon 37.7%, and BP 32.2%, with Point McIntyre production averaging 167,000 b/d and the field pretty well defined.

ARCO and partners are turning attention back to Lisburne, where production has dropped from a peak of 45,000 b/d in 1990 to about 15,000 b/d and natural gas liquids in January.

''There are a lot of challenges, but a lot of opportunities," Meyers said. "We have a joint team working on a program. We'll test some area. If it holds up, we'll drill additional wells. Combining 3D seismic with advanced technology with a cost of less than $1 million will enable us to do 40-acre drilling from existing 80-acre slots."

Prudhoe drilling

On the drilling scene, ARCO's plans for Prudhoe Bay call for 540 reservoir penetrations during 1995-2000, which will be more penetrations than in any previous 5-year period since 1980.

Coiled tubing (CT) will play an important role. "We're using it for sidetracks," Meyers said. "We can reach out as much as 2,500 ft." About 200 sidetracks have been made with coiled tubing, among them two laterals in several wells.

"Prudhoe Bay is the world leader of CT," Meyers said. "The 'Tiny Tools' technology has been used with 2-in. coiled tubing pushing the drilling assembly through 31/2-in. production tubing. We have two coiled tubing rigs running. We also use them for workovers. We're looking to put a third on before the end of this year."

An example of advanced technology at work in the Prudhoe Bay field came on Drill Site 15 at Well No. 45.

"The field encompasses more than 150,000 acres," Thompson said. "Geologically, it's a complex area that is crisscrossed by hundreds of small faults. These faults can create small undrained pockets of oil like one pinpointed near Drill Site 15 by 3D seismic and intense reservoir management assessments."

To tap the 100-acre undrained trap, ARCO drilled a sidetrack hole from an existing well. The hole made a left-hand turn and curved back with a "fishhook" completion that would not have been possible 2 or 3 years ago (see schematic, p. 24).

''The fishhook completion almost tripled the amount of pipe in direct contact with the oil-bearing sand vs. a conventional horizontal well path," Thompson said.

"Average initial production from such designer wells at Drill Site 15 was more than 5,000 b/d per well, twice that of wells drilled as part of earlier Drill Site 15 infill drilling programs.

"By more effectively draining the reservoir over a broader area, the program created 1.4 million bbl of new reserves per well-about a third more than the wells in the earlier programs.

"Seven years ago, Drill Site 15 was producing only 20,000 b/d and was one of our poorest performers. Today it averages 45,000 b/d.

"Our success at Drill Site 15 was a key contributor to the Prudhoe Bay field performing better than anticipated in 1996. It's another example of technology contributing to the bottom line.

''The undrained fault block is only one of dozens that we have identified at Prudhoe Bay," Thompson said. "We plan to drill others."

BP spending plans

BP Exploration (Alaska) Inc. also is optimistic about the future in Alaska.

The company plans to increase capital spending by $1 billion to $3.5 billion during the next 5 years for an average of $700 million/year.

Richard Campbell, president, BP Exploration (Alaska) Inc., said: "Thanks to the friendlier investment climate created by cooperation between the industry and the state and our own technological advances that have enhanced our ability to produce oil once considered inaccessible-for example, horizontal drilling and coiled tubing technology-we see a number of significant investment opportunities in Alaska that can bring substantial benefits to Alaskans and to BP.

"They include new developments, advancing technologies, and squeezing new oil out of older developments. All, however, are premised on maintaining the financial performance of our base production."

Milne Point

One example cited by Campbell is the Milne Point field about 25 miles west of Prudhoe Bay.

Partners in the field are operator BP 91.19% and Oxy USA Inc. 8.81%.

"Since acquiring Milne Point 3 years ago," Campbell said, "we have tripled production and reserves and see potential for even more growth over the next several years."

Production from the field in the first quarter averaged 53,826 b/d. The key to future growth and investment, says BP, is development of the Schrader Bluff heavy oil accumulation overlying the Kuparuk formation.

A team of BP staff and contractors is working to assess the feasibility of large-scale, long-term development of the Schrader Bluff heavy oil accumulation.

'"We're confident of our ability to overcome the cost and productivity challenges posed by this heavy oil reservoir, where the prize could be 400 million bbl of oil," Campbell said. "This could help to boost Milne Point production to 100,000 b/d by the turn of the century.'

Another example is Niakuk: "Major strides forward in extended-reach drilling technology are enabling us to substantially increase the scope of the Niakuk project, adding new production and reserves to a field once considered almost too small to develop," Campbell said.

"BP is a world leader in horizontal drilling, with world-record extensions of more than 5 miles on wells in our Wytch Farm development in southern England. We're importing and adapting this technology to the unique conditions on the North Slope and applying it with great success at Niakuk and Milne."

Production is forecast to peak at 23,000-30,000 b/d. Additional infill drilling and drilling extension into Segment 3 are planned for this year.

Badami

BP is continuing development to bring on line Badami field, about 35 miles east of Prudhoe Bay.

BP, operator, has a 70 % interest; Belgium's Petrofina SA owns the remaining 30%, which is managed by Fina Inc., its U.S. affiliate.

Gravel placement for production facilities and wells is under way, and first oil production is planned for late 1998. Badami contains an estimated 120 million bbl of recoverable oil, making it the ninth largest among 13 North Slope fields currently producing oil or planned for development. Production is expected to peak at about 35,000 b/d in 1999.

The project is expected to cost about $300 million.

Badami construction will rely extensively on Alaskan contractors, including Alaska Interstate Construction Co. for gravel work, Houston Contracting Corp. for pipeline installation, and Veco Construction Co. for facilities fabrication and installation.

Truckable modules, accounting for about one third of the fabrication budget, will be built in Anchorage. Larger production modules, requiring shallow-draft barge transport to the Badami site, will be built in Canada and barged up the MacKenzie River.

"Badami is a critical part of BP's plans to invest an additional $1 billion in Alaska over the next 5 years, and it plays an important role in extending infrastructure further east on the North Slope," said Eric Luttrell, BP's vice president of exploration and new developments.

Oil will be processed onsite and transported by pipeline to the Endicott oil pipeline, which will carry it to TAPS Pump Station 1. The 26-mile, 12-in. pipeline will be buried at three river crossings and elevated elsewhere.

While about two thirds of the recoverable reserves are offshore, Badami will be developed from a single onshore location with directional wells. Drilling is to begin in the third quarter.

The entire Badami development will cover about 100 acres, or 0.2% of the field area. There will be no gravel road linking the development to existing oil field infrastructure to the west, and a shallow-draft dock will reduce offshore effects.

Badami will be supplied by ice road in the winter and by barge in the summer. A gravel airstrip will provide year-round access. Badami was discovered in 1990 by Conoco Inc. and Fina. BP joined the project in 1992.

Northstar

Another project, bringing Northstar field on production, ran into a roadblock in February.

A lawsuit filed by two industry critics against Alaska in Anchorage Superior Court caused BP to stop all Anchorage module fabrication work on the Northstar project.

The suit challenges revisions in Northstar's lease terms that were ratified by the Alaska legislature and signed by the governor last year.

"Unfortunately, the lawsuit is having a real and immediate impact on Alaska jobs and the growth of new support industries in Alaska," said Richard Campbell.

Until the suit is resolved, BP will focus its work on permitting, the environmental impact statement, and support engineering.

The full pace of Northstar development work will be resumed as quickly as practical once the legislation modifying BP's Northstar lease terms is affirmed.

"This is a painful but necessary step that will help us to minimize our financial exposure until the suit is resolved," Campbell said. "We're confident the court will affirm the legislation, and we remain committed to the project."

Northstar reserves are estimated at 130 million bbl of 40° gravity oil, with recovery possibly reaching 145-150 million bbl of an estimated 260 million bbl in place. Peak production has been predicted at 50,000 b/d.

Copyright 1997 Oil & Gas Journal. All Rights Reserved.