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Vol. 14, No. 21 Week of May 24, 2009
Providing coverage of Alaska and northern Canada's oil and gas industry

Where to from here?

Will the western Cook Inlet oil fields recover from Redoubt eruption?

Alan Bailey

Petroleum News

While Redoubt Volcano on the west side of Alaska’s Cook Inlet continues to rumble, threatening another massive explosion that would hurl ash into the sky and floodwaters down the Drift River on the volcano’s northern flank, the neighboring Drift River oil terminal and 10 Chevron-operated offshore oil platforms that depend on the terminal for exporting their products remain silent, shut-in since early April when eruption-induced floodwaters flung mud against the terminal’s protective dike and across the facility’s airstrip.

No oil has been spilled.

But to guard against the possibility of an environmental disaster, the oil in the Drift River terminal’s storage tanks has largely been replaced by ballast in the form of water. And Cook Inlet Pipe Line, owner of both the terminal and the pipeline connecting the terminal to the western Cook Inlet oil facilities, plans to clean out the terminal tanks, an operation that could last for several months once the current eruption ends. So, with the possibility of the eruption continuing for months, restart of the impacted oil fields on the west side of Cook Inlet seems a long way off.

Cook Inlet Pipe Line is owned 50 percent by Chevron and 50 percent by Pacific Energy Resources, with Chevron as operator.

Pacific Energy, which in March filed for chapter 11 bankruptcy protection, operates the Redoubt Shoal and West McArthur River fields, fields which feed oil into the Cook Inlet pipeline and Drift River terminal via Pacific Energy’s own production facilities. On April 24 the company reported that its facilities had enough storage capacity for about another 60 days of production from its two fields. And on May 19 the company confirmed to Petroleum News that its fields were still producing oil into storage.

Determining options

Allison Iverson, coordinator for Alaska’s Petroleum Systems Integrity Office, told Petroleum News May 12 that Chevron has put together a team to determine options for the future export of oil from the west side of Cook Inlet and will present those options to state officials in due course.

“They have told us that they are putting together an internal team to look at different potential configurations and different means of getting the oil across the Cook Inlet,” Iverson said. “… When they’re at the point of being able to move options forward, they will come to the state, and the state has committed to putting together a team to work with them.”

In addition, there are regulatory requirements, including integrity tests, for restarting the terminal and the Cook Inlet pipeline — the U.S. Department of Transportation regulates both the pipeline and the tanks at the Drift River terminal, while the U.S. Coast Guard regulates the Drift River tanker loading dock, Iverson said.

But given the relatively low rates of remaining oil production from Cook Inlet oil fields, most which originally went into operation well over 30 years ago; given the environmental concerns associated with an oil terminal at the base of an active volcano; and given possible reservoir degradation resulting from a prolonged production hiatus, what are the long-term implications of the Drift River terminal shutdown?

Concern about reopening

“My concern is that we may very well see that Drift River does not reopen at all,” David Carey, mayor of the Kenai Peninsula Borough told Petroleum News May 12. Carey characterized the oil and gas industry as “a major economic partner” with the borough in achieving a high quality of life for borough residents — the borough, with jurisdiction over the upper Cook Inlet, and over the Kenai Peninsula where many Cook Inlet oilfield workers live, has been anxiously participating in the response to Redoubt Volcano’s threat to the Drift River terminal.

“People have been laid off in the past few weeks and almost every day we hear of another layoff,” Carey said.

In addition to the direct impacts of layoffs on oil industry employees and contractors, the layoffs will have secondary impacts in terms of overall economic activity. Oil industry people buy or rent houses, buy food and contribute to the community in many ways, Carey said.

Reduced spending will also lead to a reduction in government revenues from sales taxes, he said.

Oil and gas industry property taxes, assessed by the state but paid to the borough, are also a major concern. This year the state increased its Kenai Peninsula Borough oil and gas property assessment from $603 million to $700 million, primarily because of some drilling rigs that are expected to come into the region, Carey said. A permanent shutdown of some oil facilities would knock a significant dent in that assessment, although the reduced tax take would not come into effect until after next year’s state property tax assessment.

But the question of whether a permanent shutdown of oil production is likely revolves presumably around the economics of low production rates from aging fields, and around the extent to which these fields can recover from the current shut-in.

Low production rates

In March, according to AOGCC data, the Granite Point field and the Trading Bay field, two of the fields that were shut-in at the beginning of April, were producing oil at the rates of 2,554 barrels per day and 4,577 bpd. West McArthur River produced 8,310 barrels of oil during the whole of March, while during that same period Redoubt Shoal, a field that has in the past suffered from production problems resulting from a compartmented reservoir, produced 3,124 barrels.

By comparison, Division of Oil and Gas figures shown that in 1968 Granite Point production peaked at an average rate of 35,975 barrels per day, while in 1971 Trading Bay peaked at 18,395 bpd.

Chevron spokeswoman Roxanne Sinz told Petroleum News May 5 that several Cook Inlet oil fields had to be shut-in when Redoubt Volcano last erupted in 1989-90. At that time, the Granite Point field experienced a 10 percent production drop for about six months after a two-month shut-in; Trading Bay experienced a 5 percent drop for about four months after a four-month shut-in; and McArthur River, another Chevron-operated west Cook Inlet field, returned to pre-shut-in rates some three months after a two-month shut-in. However, the oil wells in the aging fields are not as robust today as they were nearly two decades ago, Sinz said.

“It is unclear how today’s wells will respond to a return to production after a prolonged shut-in,” Sinz said.

AOGCC Commissioner Cathy Foerster told Petroleum News that although declining pressure in the reservoir and increased water production can make production from older wells more difficult than that from newer wells to restore to full production after an extended shut-in, the specifics of how successfully each well can return to production depends on the individual characteristics of that well, characteristics that include water production rates, the local reservoir pressure, the dimensions of the well tubing and what, if any, artificial lift is being used to boost oil production.

Dudley Platt, a petroleum engineering consultant with many years of Cook Inlet experience, told Petroleum News that the Hemlock formation, the main oil-bearing reservoir rock for the oil fields on the west side of Cook Inlet, tends to contain clay which is susceptible to swelling, a phenomenon that might tend to clog the reservoir when fluid stops flowing into the producing wells.

“When you shut-in anything, much like a salad dressing with vinegar and olive oil in it, once it settles out you’ve got the water over the (well) perfs and the oil floating on top, and the water may contribute to the swelling of the clays,” Platt said.

To recapture production it may be necessary to flush out the wells, re-perforate the wells or treat the area of the perforations with acid, he said. In an extreme case, it might be necessary to re-drill wells.

Platform removal

If the worst were to happen, and some platforms were to permanently shut down, the field owners would at some point be faced with the expensive operation of dismantling and removing the offshore structures. However, although the terms of the state oil and gas leases require oilfield acreage to be returned to its original condition, to the satisfaction of the state, dismantlement of the Cook Inlet platforms is still a long way off, Nan Thompson, units manager in Alaska’s Division of Oil and Gas, told Petroleum News May 12.

“They have to determine that there’s nothing else producible (before dismantlement),” Thompson said.

Thompson said that the state does not currently have regulations for platform removal, but that the division is currently working on this issue.

And maybe further use could be made of platforms, even after the original fields have stopped producing: Dan Seamount, a commissioner with the Alaska Oil and Gas Conservation Commission, has in the past suggested that the aging Cook Inlet platforms might find a use in exploratory drilling for new oil and gas resources.

One factor that might also play into all of this would be the economies of scale achievable by waiting to remove several platforms in one large project, rather than bringing a barge and other expensive equipment to the state to just remove a single structure — it is likely to be cheaper to mothball, or “lighthouse,” a single platform that is no longer in use, than to dismantle it, Platt said.

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