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December 2008

Vol. 13, No. 49 Week of December 07, 2008

Chevron pursues Cook Inlet development

Dealing with declining oil and gas production from Alaska’s Cook Inlet basin presents both challenges and opportunities for Chevron

Alan Bailey

Petroleum News

When it comes to extracting oil and gas from Alaska’s Cook Inlet basin, many of the easy pickings were found years ago. But there are still rewards to be had from working this technically and commercially demanding region, Steve Wright, Chevron’s Alaska asset development manager, told the 2008 Resource Development Council annual conference in Anchorage Nov. 19.

“We at Chevron believe that there is a significant opportunity here in Cook Inlet but it’s a very challenging basin in which to operate,” Wright said.

Chevron has been involved in the Cook Inlet oil and gas industry for more than 50 years and now operates five gas fields, four oil fields and two gas storage facilities in and around the Inlet. The company also has working interests in two other non-operated gas fields.

Declining production

Net daily Chevron production from the Cook Inlet basin amounts to about 8,500 barrels of oil and 78 million cubic feet of gas, Wright said. But production is well below peak levels and continues to decline steadily. Total oil production from all operators in the Cook Inlet has dropped from a peak 200,000 barrels per day in the late 1970s to 11,000 bpd currently, Wright said.

And natural gas deliverability has fallen especially fast in the last three years, a fact that is of great concern for local residents because of their dependence on gas for heating and power generation. The decline is particularly apparent for the four largest gas fields — Beluga River, North Cook Inlet, Grayling Gas Sands and Kenai — where the total combined production rate has fallen from about 14 billion cubic feet per month in January 2004 to less than 9 bcf per month now, Wright said.

The one bright spot in this overall picture is the Ninilchik field where an aggressive development program has succeeded in pushing the production rates up, he said.

The gas cliff

But a projection into the future of Cook Inlet gas production that Alaska’s Division of Oil and Gas prepared in December 2006 shows future production sliding down a cliff as the output tails off from the various gas fields. And current production volumes suggest that those division predictions may, in fact, have been somewhat optimistic, Wright said.

The production decline has continued, despite a high level of new capital investment by all of the major Cook Inlet producers, he said.

“We do hope, however, that new drilling at … Ninilchik and Beluga River will help us stem that rate of gas decline, but there’s no scenario that we foresee now that will entirely eliminate that gas decline by infill development drilling in current fields,” Wright said.

Wright said that Chevron and Unocal, which Chevron acquired in 2005, had drilled six Cook Inlet exploration wells in recent years but that the exploration results had proved disappointing.

“That’s coupled with the fact that … much of the prospective area around Cook Inlet now has significant surface occupancy restrictions which will impact future exploration and development activities around the Inlet,” Wright said.

And faced with the sobering realities of a mature oil province, Chevron has been pursuing a redevelopment strategy in both its oil and its gas properties, Wright said.

“Overall in the last 12 months Chevron has spent over $200 million on oil and gas development in the Cook Inlet,” Wright said. “We are really committed to doing what we can to step up both the oil and the gas production out of the Inlet.”

Oil drilling

On the oil front, the company has embarked on a new drilling program.

“We’ve undertaken a multi-year program to stem the oil decline rates in our three (offshore) Cook Inlet oil fields,” Wright said. “We’ve implemented a program of infill and step-out drilling at the Granite Point field and we’re working to optimize our waterflood secondary recovery programs at the McArthur River field, to try to milk the last remaining barrels out of that field.”

In the summer of 2008 Chevron kicked off its new drilling program with two wells off the Granite Point Anna platform. Unfortunately these wells did not meet pre-drill expectations, thus illustrating the inherent risks associated with drilling in the unpredictable river-deposited, or fluvial, reservoir sands of the Cook Inlet, Wright said.

“Although we’re drilling in an existing field, there’s a lot of stratigraphic variability in these fluvial channel sands and there are fluid contact variabilities as well as formation water resistivity variabilities that still haven’t been fully resolved,” Wright said. “… Those risks and uncertainties have not been overcome yet, and it’s a concern that factors into our overall redevelopment strategy going forward.”

At the McArthur River and Trading Bay oil fields, Chevron has been using a hydraulic workover unit to perform shallow zone well recompletions. The company is also converting wells from gas lift operation, to reduce gas fuel consumption and thus make more gas available for the local gas market, Wright said.

At McArthur River Chevron has to contend with major water production.

“We’re moving nine barrels of water for every barrel of oil we produce (at McArthur River) and that’s one of the reasons that our operating expense on a unit (of production) basis is quite high in the Cook Inlet,” Wright said.

However, Chevron does anticipate forging ahead with its Cook Inlet oil redevelopment efforts.

“Our anticipated capital investments for our Cook Inlet oil redevelopment program over the next three to five years are in the range of $100 million to $200 million, but that is dependent on our ability to establish a consistent track record of success,” Wright said.

Wright added a caveat that Chevron is also re-assessing its “opportunity catalogue” in the light of the current collapse in commodity prices.

Gas development

When it comes to Cook Inlet natural gas, Chevron, along with the other Cook Inlet producers, is aggressively redeveloping the existing gas fields, to try to hold back the dramatic production decline rates, Wright said. Recently, Chevron has been active in the ongoing development of seven gas fields, he said.

Chevron’s Happy Valley field on the Kenai Peninsula has seen some new development drilling.

“We have drilled two gas development wells the last 12 months and we’re currently in the process of putting those on line,” Wright said. “… We actually did a second pad installation to accommodate some of the newer production there and we’re in the process of testing some new fracture stimulation technology on one of those wells.”

At Swanson River Chevron has been using the Nabors 106E rig to accomplish workovers and to drill a new gas development well. The company has been operating this rig for winter exploration drilling in the White Hills region of the North Slope, and then moving the rig to the Kenai Peninsula for drilling at other times of the year.

Chevron sees the Ninilchik gas field on the western Kenai Peninsula as a continuing focus for bolstering Cook Inlet gas production. The field, part owned by Chevron and operated by Marathon Oil Co., has seen three new gas development wells in the past 12 months, Wright said. A new compressor has also been installed on one of the well pads to boost gas deliverability from the field, he said.

Chevron also is part owner of the ConocoPhillips-operated Beluga River field on the west side of the Cook Inlet. The field owners have just completed a program to drill two new wells and do a well workover, Wright said.

“This is the first development activity at the Beluga River field in over 10 years, a fact we’re quite proud of,” he said.

In an agreement between Chevron and ConocoPhillips, Chevron is now using the Nabors rig 129 that drilled at Beluga River to do some winter drilling in a couple of Chevron gas fields on the west side of the Inlet.

“We expect to be drilling at the Ivan River field within the next week, and then we’ll move over and drill a well at Stump Lake field later this winter,” Wright said. “… This is the first time that we’ve partnered with a company to try to keep a rig active year round on the west side of the Cook Inlet.”

And, offshore, Chevron has being working on its major Grayling Gas Sands gas field, which has its reservoir in strata above the McArthur River oil field.

“In the Grayling Gas Sands at the McArthur River field we have drilled two additional gas development wells and have expanded our gas compression capabilities there,” Wright said.

Chevron has also been maintaining its two gas storage facilities, at Swanson River and Pretty Creek, with some expansion at Pretty Creek, to bolster deliverability during periods of high winter demand for utility natural gas.

And the company plans to continue to invest heavily in further Cook Inlet gas development.

“Our projected investment rate over the next three to five years in the Cook Inlet will be in excess of $200 million and we feel every dollar of that is needed to help stem that (production) decline,” Wright said.

However, the company elected not to bid on a new Enstar Natural Gas Co. gas supply contract opening for the years 2012 to 2016 because Chevron was unable to document the required future gas deliverability to meet the contract commitments, Wright said. Enstar is the main gas utility for Southcentral Alaska.

And Wright emphasized the challenges of exploring and developing in the Cook Inlet region. In addition to dealing with the geologic uncertainties and complexities of the Cook Inlet basin, drilling costs are exceptionally high, he said. It is possible to drill and complete a 7,000-foot oil well in West Texas for about $1 million, he said.

“A comparable well drilled off our Anna platform would cost about $10 million to $12 million to drill and complete,” Wright said.

There’s also a significant cost involved in the maintenance and refurbishment of the aging Cook Inlet oil and gas infrastructure, he said.

Fracture stimulation

Modern fracture stimulation technologies may prove to be a key to future Cook Inlet gas production by releasing tight gas from some reservoirs that have hitherto been viewed as uneconomic, Wright said. These technologies have been in use in the Lower 48 for a long time and have improved dramatically in the past 10 years, he said.

“I think if there’s one opportunity that I could identify that may make a step change in addressing that overall Cook Inlet gas decline rate it is the application of fracture technologies efficiently and effectively around the inlet,” Wright said.

Exploiting these technologies might take the concerted effort of a coalition of producers and service companies, he said, adding that the working relationships between the various Cook Inlet producers are now especially good.

However, Wright commented that the producers need the assurance of predictable and stable markets to attract the necessary investments to stem production declines. And meeting the challenges of Cook Inlet will require the support of the regulators and local utilities.

“We also need the support of the regulatory industry and the local utilities in meeting both the near-term and long-term energy needs of Southcentral Alaska,” Wright said.






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