ALASKA'S COOK INLET BASIN SLATED FOR REBOUND IN DRILLING

Almost 36 years after the Cook Inlet basin gave Alaska its first significant oil discovery, the basin is bounding back with a burst of exploration and development. Players in the renaissance are Arco Alaska Inc., Phillips Petroleum Co., Unocal Corp., Shell Western E&P Inc., and Anchorage independent Stewart Petroleum Co. Arco, as operator for itself and Phillips, is preparing to kick off a two or three well drilling program to delineate a deeper pay discovery that holds the potential of being

May 24, 1993

14 min read

Almost 36 years after the Cook Inlet basin gave Alaska its first significant oil discovery, the basin is bounding back with a burst of exploration and development.

Players in the renaissance are Arco Alaska Inc., Phillips Petroleum Co., Unocal Corp., Shell Western E&P Inc., and Anchorage independent Stewart Petroleum Co.

Arco, as operator for itself and Phillips, is preparing to kick off a two or three well drilling program to delineate a deeper pay discovery that holds the potential of being the largest oil find in the prolific Cook Inlet basin.

The company estimates its Sunfish discovery it made in deeper pay in North Cook Inlet gas field in 1991 and confirmed in 1992 may hold gross reserves of as much as 750 million bbl of oil (OGJ, Apr. 19, p. 20).

If the estimate proves correct, the find will top McArthur River, another Cook Inlet field 24 miles southwest. The latter field, a 1965 discovery by Unocal, leads the inlet's six oil fields with a cumulative production of 557 million bbl.

The fields, four offshore and two onshore, have produced 1.16 billion bbl since Arco found Swanson River field on the Kenai Peninsula in July 1957. That started Alaska on the road to becoming a neck-and-neck competitor with Texas for the distinction of being the nation's No. 1 oil producing state.

SUNFISH DISCOVERY

Arco drilled its 1 Sunfish discovery with Global Marine's Glomar Adriatic VIII jack up in state waters on projected section 12-11n-10w, 30 miles southwest of Anchorage. Sand at 12,160 ft yielded 1,100 b/d of 42 gravity oil and 1 MMcfd of gas through a 24/64 in. choke.

The strike lies 1-1/2 miles southwest of Platform Tyonek from which Phillips, as operator, developed North Cook Inlet gas field. The field, a 1962 discovery by Amoco Production Co. forerunner Pan American Petroleum Co., has produced 1.05 tcf from Sterling and Beluga sands at average depths of 4,200 and 5,100 ft.

Last year, Arco moved 1-1/4 miles south and slightly west of the discovery well to drill 1 North Foreland State on projected section 13-11n-10w. The 17,770 ft confirmation well flowed 3,610 b/d of high quality oil and 3 MMcfd of gas.

In addition to confirming the earlier find, the North Foreland well found two more, related hydrocarbon bearing zones. Arco confirmed that the Sunfish and North Foreland pays are Tyonek equivalent of Tertiary age.

Phillips also joined the play as an operator last year, spudding 2 Sunfish in November as a delineation well from Platform Tyonek on projected section 6-11n-9w. The directional hole was planned to bottom 1-3/4 miles northwest of the surface location, or 2 miles northwest of 1 Sunfish, but mechanical problems intervened.

This month the well was at undisclosed depth in the fourth sidetrack, still short of target depth.

SUNFISH PLANS

This year's work by Arco-Phillips will test acreage acquired by the combine at Alaska's Sale 76 last Jan. 26. The two companies won all 15 tracts they bid on, paying bonuses totaling $64.4 million, or 98.6% of the sale's total high bonus bids of $65.3 million.

Arco, as operator, will use Rowan Drilling Co.'s Rowan Gilbert Rowe, a jack up newly arrived off Alaska from Singapore, to drill 3 South Cook Inlet in about 100 ft of water on projected section 33-10n-11w. The drillsite has about 13 miles southwest of the 1 North Foreland confirmation.

The projected 16,000 ft vertical well will test Tract 14, which Arco-Phillips acquired for a bonus of $12.8 million, or $2,502.67/acre. The bonus was the second highest of the sale.

Arco plans to use the Glomar Adriatic VIII for a pair of delineation wells. The first is expected to be either a replacement for the troubled 2 Sunfish or another delineation, 2 South Cook Inlet on projected section 18-10n-10w, 10 miles southwest of the North Foreland confirmation. The well will test Tract 10, the top dollar tract in Sale 76 with a bonus of $17.1 million, or $3,001.26/acre.

If the assignment is for 2 South Cook Inlet, the jack up on completion of that job-and depending on what the well finds-will move to 2 North Foreland or 1 South Cook Inlet, both of them between the North Foreland confirmation well and the 2 South Cook Inlet on a northeast-southwest trend.

Phillips, also plans to drill 3 Sunfish from Platform Tyonek. Like 2 Sunfish, it is programmed to further delineate the Sunfish and North Foreland sands.

Along with delineation wells, Arco plans a 3D seismic survey this summer over a 150 sq mile area in North Cook Inlet, beginning in late May or early June and continuing until freezeup. In preparation for the survey during the approximately 22 ft tidal drop of Cook Inlet waters, Arco last year made a test run, successfully laying and retrieving cables from the boulder-strewn, glacial-scoured bed of the Inlet.

Results of wells drilled this summer will determine whether a 3D survey will be run next year south of the two wells that have been successfully tested.

SUNFISH PROSPECT

The Sunfish discovery in Cook Inlet, which had largely been developed in the 1960s and early 1970s, had its inception with a new stratigraphic model developed by Arco for the inlet.

"It was good old-fashioned geological work with biostratigraphy, samples, and logs," said Pamela Parks, Arco Alaska's manager of South Alaska exploration. "And then we added to it technology that wasn't available 3 or 4 years ago."

Another factor, Parks said was Arco's long association with the inlet. "We've had a continuous presence in the inlet since the 1950s, and we've continued working it."

The first trial of the stratigraphic model took place in 1990 with drilling of 1 Sturgeon on projected section 25-5n-17w, near Kalgin Island about 60 miles southwest of North Cook Inlet gas field.

"The stratigraphy worked, but the oil wasn't there," Parks said of the 7,206 ft hole. Although 1 Sturgeon was dry, the support given the stratigraphic model encouraged Arco to move north to test the Sunfish prospect.

With delineation still under way, the earliest Sunfish could come on line would be late 1996, Parks said. Full development of the field could require as many as five more platforms to bolster the 15 presently in Cook Inlet. The discovery in North Cook Inlet does not seem to have implications for the lower Cook Inlet. "The lower Cook Inlet has a thin Tertiary section," Parks said. "Therefore it is not impacted by the Sunfish discovery."

SELLING THE OIL

Still to be determined is how Sunfish oil will be marketed.

High gravity of the crude could make it attractive on Lower 48 West Coast or international markets.

Because Sunfish is in state waters, some who have studied the situation, including staff researchers of the California Independent Petroleum Association, have concluded the oil will not face the export restrictions confronting North Slope crude which, CIPA says causes North Slope crude to glut the California market.

There is some precedent for exporting production from Cook Inlet. Phillips and Marathon jointly have supplied gas from the North Cook Inlet field to a pair of Tokyo utilities since 1969. The gas is liquefied in a plant near Kenai and shipped about 3,300 miles to Japan, where it's regasified for use.

Sale of gas to Japanese utilities was the enabling factor that allowed the gas field to go on production.

UNOCAL PERSPECTIVE

In a pair of fields of more than 100 million bbl southwest of the Sunfish play, Unocal is another player in revitalization of Cook Inlet.

The company is an old hand in the inlet. Before Prudhoe Bay went on stream, Unocal was Alaska's largest producer, due mainly to flush production from McArthur River field.

"All of the development in the late 1960s was with 1960s technology," said Wylie R. Barrow Jr., Unocal's general manager for Alaska. "Generally it was with wide spacing and peripheral waterfloods. After 20 years of production, it was obvious well spacing was inefficient, and with modern seismic the geological structure is different from the original conception and requires more wells to develop it properly."

Another factor, Barrow said, is new technology's ability to drill extended reach and horizontal wells that enable the operator to do things that were not possible before.

"Underdevelopment, new geology, and new drilling technology," Barrow said. "The combination makes opportunity. That's really the basic premise toward redevelopment."

GRANITE POINT

Unocal trained its sights on Granite Point, a 1965 discovery by Mobil that has produced 118.6 million bbl, and Middle Ground Shoal, a 1962 discovery by Pan American that has yielded 167.3 million bbl. Unocal had a foothold with a 25% interest in a state tract held jointly with Mobil, 75%, on the south end of Granite Point field. The tract had been developed from Granite Point Platform operated by Mobil.

Two other platforms in Granite Point field-Bruce and Anna-and two in Middle Ground Shoal field-Baker on the north end and Dillon on the south end-were owned by Amoco 62.5%, Texaco 25%, and Chevron 12.5%.

Unocal bought Amoco's interest for an undisclosed price effective Sept. 1, 1990, and followed up with acquisition by trade of Texaco's interest and Chevron's, giving the company a 100% interest in Platforms Bruce, Anna, Baker, and Dillon. The company later tried to acquire Shell's interest in the midportion of Middle Ground Shoal developed by Platforms A and C, but the companies were not able to come to terms.

Unocal chose Granite Point as the proving ground, drilling four wells last year that boosted production from Granite Point platform to 5,200 b/d from 2,300 b/d. Two of the extended reach wells tapped the Tyonek formation for rates four to five times greater than conventional wells in the formation. Two other wells proved up production in the Hemlock, a deeper pay discovery.

In the wake of that successful program, Unocal disclosed a $60 million campaign to drill 12 more wells from Granite Point platform in a period of about 4 years. The wells are expected to add production of 7,000 b/d of oil and 4.9 MMcfd of gas. Plans call for adding a gas compressor on the platform to set the stage for development drilling to resume in 1994.

CHAKACHATNA

A second, larger project on Unocal's revitalization list is Chakachatna, which envisions development of significant reserves from Platforms Bruce and Anna north of Granite Point platform in Granite Point field and Platforms Baker and Dillon in Middle Ground Shoal field.

The project name dates back to the early 1960s. It was chosen by partners who originally developed the leases purchased by Unocal from Amoco, Texaco, and Chevron.

Unocal plans to start Chakachatna rolling with an investment of $119 million.

"The $119 million is basically to drill a set of concept wells in the first phase and pay for a drilling rig and associated production facilities," Barrow said.

The first phase calls for drilling 20 development wells-four this year, 11 in 1994, and five in 1995. The wells are expected to increase production from the four platforms to about 11,000 b/d from the current 4,000 b/d.

Unocal is rigging up on Platform Bruce. Pool Arctic will handle the labor contract.

Pool is assembling a rig in a yard near Salt Lake City for service on the other platforms.

"It's designed specifically to fit on the platforms," Barrow said. "The modules are small so the rig can be moved with platform cranes and workboats." The rig, a top drive unit rated to 16,000 feet, will work at first on Platform Baker, with scheduled start about Sept. 1.

The Chakachatna project, encompassing the four 100% Unocal owned platforms, could point the way to more such projects.

"There is more opportunity," Barrow said, citing Platforms Dolly Varden, Grayling, and Steelhead in McArthur River field and the Monopod platform in nearby Trading Bay field. "They all have possibilities. The future depends on drilling success, commodity price, and our ability to operate cost effectively. Those questions will be answered before the end of 1995.

"In a couple of years, it will be very interesting to see where the inlet stands. With the development Unocal is talking about and Arco's projects, it's going to be exciting times."

In other activity, Shell plans a four well development drilling program on Platform C in its share of Middle Ground Shoal field. Drilling is scheduled to start late this summer and take about 9 months to complete. It is's part of a plan to maintain production.

STEWART'S PROGRAM

West of McArthur River field, Stewart is preparing to join Alaska's producing ranks as the first independent to develop production in the modern era of the state's oil industry.

The company in 1991 proved up a new offshore field, directionally drilling the discovery well from an onshore site in the West Foreland area about 65 miles southwest of Anchorage.

The drill pad was an abandoned air strip included in a 700 acre surface use contract negotiated with Salamatof Native Association Inc. The contract also allowed use of an existing road from the pad to Marathon Oil Co.'s Trading Bay production facility, 2-1/2 miles to the north.

A subsurface agreement with Cook Inlet Region Inc. (CIRI) covered a 55 acre area within the Salamatof agreement area, allowing drilling through CIRI's subsurface estate en route to Stewart's offshore acreage and granting a subsurface easement through a pipeline corridor area along the west side of the road to Marathon's facility as established by the Salamatof agreement.

Stewart's 1 West McArthur River Unit, section 16-8n-14w, 13,742 ft measured depth, bottoming about 9,500 ft northwest of the surface location. The well found oil in the Hemlock, topped just below 9,200 ft.

The well was first tested in December 1991 and fully tested in June 1992, indicating a conservatively estimated initial production rate of about 3,400 b/d using a jet pump to assist the flow of 32-34 gravity, sulfur free oil.

Stewart is preparing to place the well on production, aiming for start up about June 1. The oil will be trucked at first to Marathon's Trading Bay site, where Stewart is completing an offloading facility.

Production will be limited by trucking capacity to about 3,000 b/d.

Stewart Pres. W.R. Bill Stewart, said, "We won't know the field's full potential until we run a pipeline."

Plans call for starting construction of an 8 in. 2-1/2 mile pipeline in August, with completion expected to take about 3 weeks.

Unocal will buy the crude and ship it through the Cook Inlet pipeline to the Drift River terminal for shipment by tanker to southern California refiners.

Along with the oil line, Stewart plans to lay a 4 in. gas pipeline in the same corridor.

Stewart's 6,300 acre West McArthur River Unit includes proved gas reserves in West Foreland gas field, discovered in 1962 by Pan American on the southern end of the structure tapped by Stewart's discovery well.

Pan American's 1 West foreland, section 21-9n-14w, had a calculated absolute open flow of 16.45 MMcfd. It was shut in because of lack of market and has been retested several times since then. The onshore wellsite is presently held by Phillips.

Stewart spudded the first confirmation well Apr. 3 with Grace Drilling Co.'s Rig No. 160. Its 2 West McArthur River Unit has a proposed 13,500 ft measured depth and 9,500 ft true vertical depth. Bottomhole location will be about 2/3 of a mile south of the discovery well.

Development of the 6,330 acres included in Stewart's block will require about five production wells and two injection wells.

Estimated reserves are 50 million bbl. Gas reserves are estimated at a total 21.7 bcf underlying Stewart's 263 acre portion of the 640 acre participating area of West Foreland gas field. The field holds estimated reserves of 20 bcf and 13.5 bcf in undeveloped reserves within the Stewart block north of the gas field.

West McArthur River investment to date in operations by Stewart on behalf of itself, private Alaskan and nonAlaskan participants, and a Korean refining company totals about $20 million, Stewart said. Estimated future investment totals $50 million for the Stewart acreage.

"It costs about $10 million for each completed well if you don't have major drilling problems," Stewart said.

The West McArthur River prospect was based on shows turned up by wildcats drilled in the 1960s and seismic that was reshot using today's more sophisticated stacking technique for processing and better data than that of earlier surveys in the first wave of exploration in the 1960s.

In the state's Sale 76 in January, Stewart, bidding unopposed, paid $20,767.77 or $6.57/acre for Tract 16, 6 miles north of the West McArthur River discovery well. The lease is on another prospect, Stewart said.