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Cook Inlet's wrinkles.

Cook Inlet's Wrinkles

COOK INLET IS WHERE IT all began for Alaska's petroleum industry 33 years ago, but somehow it became a forgotten child after big oil was discovered on the North Slope in the late 1960s. Oil and gas production in Cook Inlet fell into decline long ago and many fields could be shut down in a few years.

That is not to say industry is preparing to abandon the Southcentral fields. On the contrary, at least four oil companies are planning to explore for new reserves in Cook Inlet this summer and winter. Many others are eagerly awaiting a state oil and gas lease sale tentatively scheduled for fall. And new technology and strong oil prices could keep the old fields operating for years.

The bulk of Alaska's crude oil is produced in the Arctic. But the area's remoteness and vast distance from markets on the West and Gulf coasts translates into enormous exploration, development and transportation costs for industry.

It's less expensive to do business in Cook Inlet. And a new breed of geologist equipped with the latest technology has been searching for pockets of oil and gas that may have been overlooked in earlier years when the focus was on finding the motherlode.

Says Al Hastings, director of external affairs for Conoco Inc., "Alaska is just a big oil province and one of the more attractive places to explore. In the Cook Inlet, the discovery can be a lot smaller because the cost of getting oil to market is a lot less. You don't have the pipeline tariffs."

Conoco, Arco Alaska Inc., Chevron USA and Stewart Petroleum Co., an independent oil company based in Anchorage, are planning to drill exploratory wells on the west side of Cook Inlet. C.V. "Chat" Chatterton, chairman of the Alaska Oil and Gas Conservation Commission, says it took the previous five years for industry to drill four wells.

"These young bucks (geologists) start reinterpreting the geology and utilizing it more responsively," Chatterton says. "They are interested in making plays and they are selling them to management. And one of the most rewarding places to look for oil is around an oil field."

West Cook Inlet is an area of particular interest. The region supports 10 of the 15 offshore platforms operating in the entire inlet and accounting for most of the production, when they are pumping crude. But a cantankerous Redoubt Volcano has been causing havoc with tanker loading schedules at the Drift River terminals since mid-December.

The offshore oil fields that feed crude to the Drift River tank farm via a pipeline have been shut down periodically as the terminal operator and government agencies figured out ways to protect the facility from volcano-induced flooding and mudslides.

In early April, the owners of Cook Inlet Pipe Line Co., the terminal operator, decided to spend about $14 million to construct a diking system to protect the facility on three sides. It was to consist of earth dikes reinforced with interlocking steel plates.

"The whole idea is to defend against the worst-case scenario. We feel we can operate with only minor disruptions," says Ron Greene, terminal supervisor.

Arco Alaska, which operates the King Salmon platform in the Trading Bay unit, says it has taken "a significant hit" in revenues because of the disruptions. But the company's manager of Cook Inlet operations, Bret Allard, views the problem at Drift River as a temporary setback.

"We see an end to it (with) the successful upgrading of the Drift River terminal ... and the quieting of the volcano," Allard says. "From the long-term standpoint, we have a lot to learn about Cook Inlet. We're not the only ones who have seismic interest in the inlet. There's still perceived to be reasonable oil potential in the lower part of the state. And there's the lower cost to get it to market."

Tom Cook, Chevron's exploration representative in Alaska, says volvanic eruptions are a concern to the company's exploration plans. "But if we find something, we'll design around it. I don't think it is an insurmountable thing. Hopefully the volcano will go back into a 20-year dormancy period."

Public outcry over last year's Exxon Valdez oil spill in Price William Sound has raised similar concerns about potential spills in Cook Inlet, the site of two spills earlier in the 1980s. That concern coupled with problems at Drift River has cast a cloud over future oil and gas development on the west side of the inlet. In addition to the continuing eruptions from Redoubt, heavy winter ice conditions in the area pose a threat to oil tankers.

Some observers have suggested either moving the Drift River tank farm to a safer location or running a subsea pipeline from offshore platforms at Trading Bay and Granite Point to refineries on the east side of the inlet. In either case, the question arises whether declining production or any new discoveries in the Cook Inlet region could support the capital investment necessary to develop new fields.

Bob Anderson, regional land manager for the inlet's major producer, Unocal, says although a new terminal north of Drift River likely would be too costly, Unocal is considering the option. He adds a subsea pipeline may be more workable.

"I think we are going to look for alternatives. We don't like to take this kind of hit," Anderson says of Uncocal revenue losses associated with the closure of Drift River.

He adds that Unocal likely would continue using the Drift River facility after the new diking system is in place, providing the government allows its tanker to take on a full load of about 400,000 barrels of crude oil. Unocal stopped lifting oil at Drift River in March because of environmental risks associated with the 10-12 day loading time required to fill the ship's tanks. Under the regulation, a tanker could only load 50,000 barrels at a time.

"Every time you connect and disconnect, you run the risk of a pollution problem," Anderson explains. He says that changing the emergency regulations and allowing the terminal to fill the tanks likely would satisfy Unocal's concerns.

Government regulations associated with a Cook Inlet oil-spill contingency plan, which is yet to be formulated, also could serve to increase operating costs dramatically. For example, tankers may be required to have double hulls to prevent oil leaks and spills.

"If Cook Inlet is held to the same standard as Alyeska Pipeline Service Co. in Prince William Sound, they just couldn't afford it," says Bill Ashton of the state Department of Environmental Conservation. "It just doesn't have the oil. It's simple economics. When you have two million barrels a day it's a lot easier to pay for a $40 million a year (oil-spill response) operation."

Ashton notes oil companies are becoming more environmentally conscious. "Industry really did learn from the Exxon Valdez," he explains. "They're really concerned about oil spills. That has really helped agencies in negotiations."

Past Its Peak. The earliest oil and gas development in the Cook Inlet Basin occurred on the Kenai Peninsula. Richfield Oil Corp.'s onshore oil discovery at Swanson River in 1957 ushered in Alaska's oil age. But nearly all of today's major producing oil and gas field in the region - Swanson River, Granite Point, Trading Bay, McArthur River, Middle Ground Shoal, North Cook Inlet, Beluga River - were discovered and brought into production by the late 1960s.

Cook Inlet oil production peaked by 1970, falling from about 83 million barrels a year to about 16 million barrels a year in 1989. Gas production hit its high between 1982 and 1983 and fell to about 193 billion cubic feet by the end of last year.

Regarding the Drift River problem, Arco's Allard says, "We've spent a lot of money trying to stem the decline, and when it (offshore) production comes back we're going to spend a lot of money. In the meantime, we have people on the platform doing maintenance work."

Although many Cook Inlet oil fields are near depletion, they continue to play a critical role in the region's economy, particularly on the Kenai Peninsula, where several refineries operate. Gross value of the oil and gas produced in the Cook Inlet Basin is estimated to be about $400 million annually.

Unocal, which operates an ammonia-urea plant at Nikiski, will begin producing gas from fields that were once uneconomical to bring on line. "We're always looking for gas to feed the insatiable appetite of that petrochemical plant down there," Anderson says.

While much natural gas produced in the Cook Inlet Basin in consumed in Alaska, some of it also is exported. Phillips-Marathon each year ships about 1 million tons of liquefied natual gas to Japan. Chinese Petroleum Co. also buys about 1.3 million barrels a year of state royalty oil for shipment to Taiwan. Unocal ships its crude to California.

The state says permanent closure of West Cook Inlet oil fields would pose a serious threat for the entire region. Some 554 petroleum industry jobs with an annual payroll of $30.46 million would be lost. Another 831 related jobs with an annual payroll of $23.36 million also would be eliminated. The state would lose $21.05 million a year in royalty oil, and state and local governments would lose $3.36 million annually in taxes.

Chatterton of the Oil and Gas Conservation Commission says if crude oil prices waver, "some of these (Cook Inlet) fields will have to start phasing out - McArthur River would have about another five years."

Amoco Production Co. put its 62.5 percent interest in four Cook Inlet platforms on the auction block in November because of declining production from Anna and Bruce in the Granite Middle Ground Shoal field. The company declines to comment on its future role in the inlet, but does say it expected to find a buyer for its properties sometime this summer.

Chatterton points out new oil recovery technology coupled with the expense of removing offshore platforms in the inlet might encourage industry to continue operating in declining fields. "But the cost of doing business is going to go up because is no question about that. And this could bring a field to its economic limit sooner," he adds.

Treasure Hunts. Even with the added costs, however, industry appears willing to spend money on exploration to replace dwindling oil and gas reserves in Cook Inlet. During the past two years there has been extensive seismic testing conducted in the region as oil companies prepare to offer bids on 550,000 acres of state oil and gas leases in Upper Cook Inlet. Delayed after the Exxon Valdez oil spill and again when the entire state leasing program was suspended last June, Cook Inlet Sale 67-A is now tentatively scheduled to be held in the fall. Others are scheduled for 1993 and 1994.

"We'll do whatever it takes to have a sale," says Bill Van Dyke, petroleum manager for the state Division on Oil and Gas. "During the delay, companies continued to collect geophysical data. We can't guarantee all of it was related to the sale ... but we saw a fair amount of industry interest prior to the (sale) cancellation. We presume the interest is still there."

Industry's future in the Cook Inlet Basin depends on the level of exploration activity and how successful the effort is over the next three to four years, Unocal's Anderson says.

"The anomaly on the east side is that there is only one oil field and two gas fields," he says. "Why isn't there another Swanson field? I think you're going to see a lot more exploration in Cook Inlet. We've been successful there, and we don't treat the inlet as a step-child."
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Title Annotation:Cook Inlet oil and gas producers
Author:Tyson, Ray
Publication:Alaska Business Monthly
Date:Jun 1, 1990
Previous Article:Carrying on in Prince William Sound.
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