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Providing coverage of Alaska and northern Canada's oil and gas industry
March 2008

Vol. 13, No. 11 Week of March 16, 2008

A matter of trust

Companies testify on why DNR should accept a new Point Thomson plan

Alan Bailey

Petroleum News

Like an unfolding whodunit mystery, the 30-year saga of the undeveloped Point Thomson unit at the eastern end of Alaska’s North Slope raises more questions than answers. When or how will the Point Thomson field be developed? How much recoverable resource does it really contain? And are the unit owners sincere in wanting to see timely development?

At the Alaska Department of Natural Resources Point Thomson hearing held from March 3 to 7 the oil companies rolled out a series of executives and expert witnesses to try to convince DNR Commissioner Tom Irwin and Hearing Officer Nan Thompson that the companies’ latest plan of development represents a turning point in the prospects for hydrocarbons to start flowing from the field.

The Alaska Superior Court had ordered DNR to hold the Point Thomson hearing, to give the oil companies a last chance to offer a remedy for DNR termination of the Point Thomson unit. DNR terminated the unit in 2006, having rejected the 22nd unit plan of development. The unit owners appealed the termination to the Superior Court. And in response to the court’s order for the hearing, the companies proposed a new 23rd plan of development.

That 23rd plan envisages a relatively small-scale gas cycling development to produce 10,000 barrels per day of condensate, using an injector and a producer well with bottom hole locations four miles apart in the core of the main Point Thomson reservoir. The proposed project, which would involve drilling a total of five wells, would also test the oil rim below the gas-condensate pool and oil prospects in what are known as Brookian strata, above the Point Thomson field reservoir. The results of the project envisaged in the 23rd plan would provide insights into how to further develop the unit, the companies say. And development drilling would start in the winter of 2008-09.

According to DNR estimates the field contains 300 million barrels of liquid oil and natural gas condensate and 8 trillion to 9 trillion cubic feet of natural gas.

Risks and uncertainties

Much of the testimony at the hearing revolved around the risks and uncertainties associated with any Point Thomson development, and how those risks and uncertainties play into the past history of the unit and the plan that is now proposed.

One area of risk relates to incomplete knowledge of the oil and gas reservoirs in the unit.

Craig Haymes, ExxonMobil Alaska production manager, told Irwin and Thomson that the field straddles the Beaufort Sea coast — changes in the thickness of the permafrost in the transition from land to the offshore lead to difficulties in interpreting seismic data. Those difficulties lead to uncertainty in the estimates of the Point Thomson reservoir size and a “low side risk,” Haymes said.

Bill Bredar, BP’s subsurface lead for Point Thomson and Badami, talked about the three main Point Thomson resources: the gas-condensate pool (or gas cap), the oil rim below the gas-condensate and the Brookian oil in higher geologic horizons.

Those resources lie in two reservoirs, Bredar said. One of the reservoirs, known as the Thomson reservoir, consists of the Thomson Sand and some older rocks called the pre-Mississippian. That reservoir contains the gas-condensate pool and the oil rim. The other reservoir consists of Brookian sandstones containing the Brookian oil. And although wells drilled in the past have provided valuable information about those reservoirs and hydrocarbon resources, significant unknowns remain about parameters such as the quality of the reservoirs’ rocks, the fluids and the fluid contacts in different parts of the field.

The drilling program envisaged in the proposed plan of development would delineate the resources and provide data points in both reservoirs, Bredar said. All five wells would penetrate the Point Thomson gas pool. Three to five wells would penetrate the oil rim and two or three wells would penetrate the pre-Mississippian. At least the second well and possibly the third well would penetrate the Brookian Calloway prospect, he said.

Gas cap

The gas cap in the Thomson Sand, the main part of the Point Thomson reservoir, forms the largest and most valuable component of the Point Thomson hydrocarbon resource, Bredar said. But, until a North Slope gas export pipeline comes into operation, only the condensate contained in the gas would be produced — when flowed to the surface the condensate would form a liquid that could be exported down the trans-Alaska oil pipeline.

But it is not certain that a gas cycling plant of the type planned for extraction of the condensate would actually work, given the unknowns in the subsurface geology and fluid properties, Bredar said. For example, the gas cycling will involve producing gas and condensate from one well while maintaining reservoir pressure using a gas injector well: No one will know until the gas-cycling plant goes into operation whether the gas pressure maintained by the injector well will communicate with the reservoir pressure at the producer well.

And the reservoir quality is “far less predictable” in the pre-Mississippian component of the Thomson reservoir, Bredar said. In fact the pre-Mississippian may prove too dense in places for drilling, he said.

Heavy oil

The oil rim has been encountered in two exploration wells and the Alaska Oil and Gas Conservation Commission has reported 18 API gravity oil in that rim, Bredar said. However, although that API number indicates heavy oil, Bredar said that he was optimistic that the oil rim could be produced. The state-of-the-art horizontal wells planned to test the oil rim would afford the best chance of producing the oil, he said.

But Bredar sees oil production from the Brookian as less certain than production from the oil rim. In fact there is insufficient information currently available about the Brookian prospects to develop a Brookian development plan, he said.

The North Slope Tarn and Badami fields have Brookian reservoirs, roughly equivalent to the Point Thomson Brookian prospects. But although Tarn has been producing successfully, the performance of Badami has proved very disappointing because of the way in which the Badami reservoir is compartmented.

The Brookian prospects at Point Thomson appear to resemble more closely the Badami reservoir than the Tarn reservoir, Bredar said. He said that the geologic evidence for the similarity between Badami and the Point Thomson Brookian is proprietary and was presented during a confidential session of the hearing.

The proposed Point Thomson development plan includes the gathering of more data from the Brookian to further clarify the comparison with Tarn and Badami. And, given the experience with Badami, extended production testing over at least 30 days would be needed for any development decision for the Point Thomson Brookian, Bredar said.

Reservoir uncertainties

Kevin Brown, manager of gas business development for BP, confirmed his company’s commitment to test the Point Thomson oil rim and talked about the reservoir uncertainties relating to gas cycling for condensate production.

Current knowledge of the reservoir depends on extrapolating relatively sparse data across a 13-mile by 5-mile area, Brown said. And, even with great reservoir models and smart geologists, many unknowns remain that could significantly impact production. For example, different data interpretations lead to large variations in estimated reservoir pressures, he said. And compartmentalization or variations in reservoir quality could inhibit the gas cycling process.

“There’s a lot of uncertainty and that uncertainty translates into the question ‘do we actually have enough (reservoir) sand and connectivity across this reservoir?’” Brown said.

Bill Meeks, ExxonMobil drilling engineering manager, talked about some of the risks and uncertainties associated with drilling at Point Thomson.

The gas in the Point Thomson reservoir is at a pressure of 10,200 pounds per square inch, and that will require drilling mud twice as dense as that used for conventional North Slope wells, Meeks said. The initial Point Thomson injector and producer wells from a single gravel pad will need to be deviated to horizontal reaches of about 10,000 feet, while wells at the outer sides of the reservoir may have reaches of about 13,000 feet.

And as each well bore deviates at an increasing angle from the vertical, more mud pressure will be required to prevent the rock caving in around the well, Meeks explained. But, given the high mud pressure that is already required to counterbalance the reservoir pressure, there is a limit to how much additional pressure can be applied.

“That’s one of the big risks we have at Point Thomson,” Meeks said. “How far can you go?”

Pushing the envelope

Meeks showed a plot of mud weight vs. horizontal reach for a large number of wells that have been drilled worldwide. On that plot, the proposed Point Thomson wells lie at the technical limits of high-pressure, deviated wells that have been drilled to date.

“We’ll learn a lot from these first wells,” Meeks said.

Haymes said that high-pressure operations at Point Thomson would require especially large wellhead structures, rated at 15,000 pounds per square inch.

“These wellheads are triple the size of a typical Prudhoe Bay wellhead,” Haymes said.

And the remoteness of the drilling location coupled with the demands of high pressure drilling translate to especially high drilling costs.

“One Point Thomson well could cost probably 10 to 15 times the amount of one Prudhoe Bay well,” Haymes said.

The proposed Point Thomson processing facilities will also need to accommodate high fluid pressures.

For example, the water-oil-gas separator will need to operate at 3,000 pounds per square inch, requiring 6-inch-thick steel walls.

“That is leading edge technology,” Haymes said.

The compressors used to inject gas into the reservoir would also push the technology envelope — reciprocating compressors would be rated up to 20,000 pounds per square inch, Haymes said.

However, starting field development with a small facility at Point Thomson would manage the technical risks by determining how well the field design works in practice, said Craig Pruitt, ExxonMobil development manager. The use of relatively small-scale production and injection equipment would enable the development of the initial production system with proven technology, he said.

“We’ll get to learn and get that operating experience under our belt before we move on,” Pruitt said. “… This is a world class sized project … for this initial phase of development all by itself.”

And the design does allow for expansion — depending on the results of initial field development, the operations could be extended for large-scale production, including eventual major gas production. In fact ExxonMobil plans from the start to build a 12-inch diameter, 80,000 barrels-per-day Point Thomson liquids export pipeline, sized for eventual production expansion, Pruitt said.

Another chance?

During the course of questioning the various witnesses, Irwin and Thompson frequently came back to questions of why after 30 years DNR should give the Point Thomson working interest owners another chance. How does this 23rd plan of development differ from previous plans, they asked.

The 23rd plan of development forms a firm commitment by all of the owners to take Point Thomson all of the way to production, unlike previous plans which only envisaged taking the field part of the way along that route, Haymes said.

“It is not a plan of development to do an engineering study … and then come back and discuss the next steps,” Haymes said. “It’s …a legally binding commitment from all of the owners through to production. … We did not put penalty payments into this plan of development … because we committed … to take it (the project) all the way to the end. … There are no off ramps. There are no decision points. It’s a black-and-white unconditional commitment. It’s a commitment from all of the owners.”

But why should DNR trust the owners regarding that commitment and why were the proposals in the 23rd plan not developed several years ago? In fact, in the early 2000s the owners had put forward a plan for a Point Thomson large scale, 60,000 to 75,000 bpd gas cycling project. But that project didn’t pan out.

The proposals contained in the 23rd plan of development are a logical outcome of events over the past years, Brown told Irwin and Thomson.

“We’ve looked at a variety of different (gas) cycling cases,” Brown said. “As you start to increase the size of the cycling cases you come back to the whole suite of risks. … We concluded, I think it was in 2003, that the large-scale cycling project wasn’t viable.”

Brown emphasized that the viability issue was not just a question of economic viability but took into account the inherent risks associated with a large-scale project.

“The thing that really would keep me up at night if I were trying to convince our management that we should go ahead with that project is the reservoir uncertainty,” Brown commented.

Gasline negotiations

At about the time that the working owners abandoned the large-scale gas cycling concept, negotiations regarding fiscal terms for a North Slope gas line were under way.

“The focus then turned to gas sales … and that was reflected in the subsequent PODs,” Brown said. “Along with additional study of options, the main focus was on gas sales.”

Consideration of a major gas field development “came to a screeching halt” when the Alaska Legislature rejected the state administration’s gas line contract with the North Slope producers, Brown said. At that point the Point Thomson owners decided that they needed to focus on liquid sales until there is a North Slope gas line to export Point Thomson gas, he said.

In addition, escalating oil prices would likely make a Point Thomson liquids project more viable — BP’s estimated future oil price for planning purposes has increased from $16 in 2003 to $60 in 2007, Brown said.

And the oil companies are flagging their commitment to the new plan by volunteering to spend more than $400 million on drilling new wells early in the project, Haymes said.

“Why would we drill the wells early if we don’t intend to drill them,” he said.

Several witnesses also commented that a change in the voting rules in the Point Thomson unit operating agreement demonstrated working interest owner commitment. The owners have changed the voting requirement for unit decisions from 65 percent to a simple majority.

“It’s simply an agreement amongst the three largest owners,” said Chevron’s Alaska General Manager John Zager. “… In a nutshell it says that if two of the three go one way, the third party is bound to vote in a similar manner. … It ensures no one party can veto (a decision).”

Brown said that BP senior management will provide DNR with a letter confirming the company’s commitment to the Point Thomson project.

“We’re absolutely committed. There will be a letter,” Brown said. In practical terms, BP has sanctioned expenditure on the project, he said.

ExxonMobil senior managers are all aware of this project and fully support the project, Haymes said. A senior company officer will submit a letter to give ExxonMobil’s assurance of that, he said.

Clear timeline

There is a very clear timeline to bring Point Thomson to production, said Haymes.

“The plan of development lays out a very detailed, descriptive foundation to monitor progress,” Haymes said. “… This allows us to monitor progress collectively on this timeline.”

But what consequences might result if the companies did not meet commitments specified in the plan?

BP would be open to consequences such as financial penalties or unit relinquishment, Brown said.

“We believe that the state has sufficiently robust regulations to pursue unit termination and lease termination if we did not comply with the commitments we’ve outlined in this plan of development,” Haymes said. “… We are willing to talk with the state further about what other assurances they believe may be necessary or prudent.”

But with no production from Point Thomson in the 30 years since Exxon first discovered the field, will DNR decide that it is time to give other companies the opportunity to develop the major hydrocarbon resources of the area?

In his introductory remarks on March 3, Irwin said that he would make a decision based on testimony and exhibits.

That decision will presumably depend on an evaluation of whether the Point Thomson unit owners should have developed the unit by now, whether the new plan represents a genuine commitment to move forward and what the potential downside might be of waiting for new unit owners to establish a new unit, research the resources and formulate their development plans. And perhaps there are other alternatives involving new state stipulations for Point Thomson development.






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