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No off ramps Exxon insists it will take Point Thomson to small-scale production by 2014 Alan Bailey Petroleum News
Does the 23rd and latest plan of development for the ExxonMobil-operated Point Thomson unit at the eastern end of Alaska’s North Slope just present a series of good intentions, or does it commit the oil companies to bring the unit into production? That proved to be the core question that permeated the Alaska Department of Natural Resources Point Thomson hearing that started on March 3.
In the 30 years since discovery, the owners of the Point Thomson unit have investigated options for developing the Point Thomson field, but the field remains a concept on a drawing board, with no oil or gas produced.
The major working interest owners of the unit are ExxonMobil, Chevron, BP and ConocoPhillips.
Thorny issue The failure to put Point Thomson into production has become a thorny issue, in part because the field is large — according to Alaska Department of Natural Resources 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.
Tom Irwin, commissioner of the Alaska Department of Natural Resources, spelled out his expectations for the Point Thomson hearing in his introductory remarks in a packed Regulatory Commission of Alaska hearing room in Anchorage.
Irwin said that the Point Thomson decision would be his and his alone and would be made on the basis of testimony and exhibits. He said that he needed answers to several questions. In particular he wanted to know why the companies believed that DNR should accept another plan of development.
“I need to understand how, in light of the history of this unit, DNR can be assured that the commitments made in the 23rd plan of development will be met,” Irwin said. “I need to understand why you think DNR should approve a plan of development that is retroactive. I need to understand why you think it is reasonable for DNR to approve a plan of development that continues for six more years and does not appear to have any intervening enforcement benchmarks. I need to understand your view on what will happen if any of the commitments in the 23rd plan of development are not timely performed. I need to understand whether this plan will fully develop and delineate all of the resources in the unit.
“Now, let me be very clear: I’ve looked through the history of this unit and a clear pattern emerges. DNR’s patience was exhausted when the decision was made to reject the 22nd plan of development. Your job is to convince me that the pattern has been changed.”
Discovered in 1977 First discovered by Exxon in 1977, the Point Thomson field consists mainly of a high-pressure gas condensate reservoir. Although the field could be operated as a conventional gas field, the production of condensate from the field requires a procedure known as gas cycling. In gas cycling, the reservoir pressure is maintained by injecting produced gas back into the reservoir, thus flushing condensate in vapor form to the surface.
The production of condensate is desirable because it has a higher economic value than natural gas and, in liquid form, it could be mixed with crude oil for export through the trans-Alaska oil pipeline. However, a gas cycling field would be more expensive and more technically difficult to implement than a straightforward gas field. On the other hand, blowing down the reservoir as a gas field would likely result in less gas recovery than would otherwise be possible. In addition there is as yet no means of marketing gas from the North Slope.
In fact a Point Thomson unit expansion in 2001 had been predicated on the pursuit of a major gas cycling project in the unit. But in late 2003 the unit owners told the state that the gas cycling proposal was not viable. The owners subsequently changed their focus to developing the field as a major gas field and in September 2004 submitted a 21st plan of development that involved investigating that option.
Rejection of 22nd POD In 2005 Mark Myers, the then director of Alaska’s Division of Oil and Gas, rejected the unit owners’ 22nd plan of development because it made “no commitment to timely develop and produce PTU oil, gas, or gas condensate.” The 22nd plan proposed “additional studies to determine if the PTU lessees can design a commercially viable production project,” the division said. Instead the state wanted a plan that would include drilling commitments and a clear movement to commercial production from the Point Thomson field.
Rejection of the 22nd plan of development in effect placed the Point Thomson unit into default.
Mike Menge, then DNR commissioner, granted an extension of the unit pending legislative review of Gov. Frank Murkowski’s North Slope gas line contract with the North Slope producers. The contract never received legislative approval and Menge terminated the unit in November 2006.
The oil companies appealed the DNR decision in the Alaska Superior Court. On Dec. 27, 2007, the court ruled that DNR acted properly when it rejected the 22nd plan of development. However, the court directed DNR to give the Point Thomson owners one last chance to come up with an “appropriate remedy” — an alternative to unit termination — by holding the DNR administrative hearing that commenced March 3.
New plan In response, ExxonMobil filed a new plan of development, the 23rd plan, with the state. That plan proposes a cycling project involving the drilling of five wells and leading to production of 10,000 barrels a day of condensate from Point Thomson by the end of 2014. A pipeline would carry condensate from the field to the Badami pipeline for shipment to the trans-Alaska pipeline.
In addition to bringing the field into production, this relatively small-scale development would serve as a test bed for a larger scale field development and, thus, mitigate some of the risks associated with a larger project. (Under former plans of development ExxonMobil proposed an initial large-scale development that would produce 60,000 to 75,000 barrels a day.)
In testimony before Irwin and hearing officer Nan Thompson at the DNR
hearing, ExxonMobil Alaska Production Manager Craig Haymes gave several
reasons why his company thinks DNR approval of the 23rd plan of development would be in the public interest.
“The POD clearly lays out a plan of timely production. It clearly lays out delineation of all of the resources at Point Thomson and the ability to tie these into production. It clearly will deliver state taxes and royalties. It creates employment opportunities. … Work commences this year — engineering work, work on operating the rig and progressing towards mobilizing that drill rig and getting the facilities ready for installation,” Haymes said. “The POD also gets Point Thomson ready for a major gas sales development.”
Both the wells and the facilities on the surface are being designed and built for expandability, he said.
“We believe that (unit) termination is not in the public interest,” Haymes said. “The state judiciary standing committee on Feb.13 gave an indication that the termination process would probably extend towards 2010, 2011. … By 2010 we would have drilled a minimum of two wells and be onto our third well and have significant engineering on the way.”
In the event of unit termination, it would conservatively take new owners a decade to establish the unit, drill exploration wells, obtain seismic information and do engineering studies. Then by the time a new project is designed, the total delay in field development would probably be 15 to 17 years, compared with ExxonMobil’s plan to have production starting in less than seven years, Haymes said.
Remedy for rejection But does the new 23rd plan of development remedy DNR rejection of the 22nd plan, Irwin asked.
By clearly laying out a timeline to production by 2014, the new plan is unique in the history of Point Thomson, Haymes responded.
“Why should DNR trust ExxonMobil … in the light of the fact that this unit was formed more than 30 years ago and, despite the fact that it is known to contain valuable hydrocarbon resources … not a single drop of oil or gas has ever been produced?” Irwin asked.
Point Thomson is a significant resource with significant risks, Haymes responded.
“The state and the owners recognize those risks and have jointly worked on various plans of development and focus areas up through POD 21,” Haymes said. “The focus has been on gas sales, gas cycling, (gas) blowdown, small options, large options.”
Over the years the owners have put considerable effort into learning and gathering information about the field.
“Over $800 million has been invested in Point Thomson to date,” he said. “The owners are all committed to commercializing the Point Thompson resource and that goal has always been in front of us and in front of the state.”
The new plan of development will achieve that goal in a manner that maximizes the value of the resource, conserves the resource for future expansion, allows for learning about the reservoir, minimizes environmental impacts and does all of this in a timely manner, Haymes said.
“ExxonMobil and the owners are committed to this project. It’s an unconditional commitment,” Haymes said. “We’ve secured a rig; we’ll be upgrading that rig in May of this year.”
ExxonMobil is obtaining materials and will commence the drilling in the winter of 2008-09, he said.
“We’ve laid out a very detailed plan that will allow you and the owners to monitor plan,” Haymes said. “… This is very different. This is a unique plan of development.”
Haymes also said that the owners have modified the unit operating agreement for Point Thomson to make the voting requirement for unit decisions 50 percent rather than 65 percent, “to remove any other impediments that might be in the way of moving this project forward.”
Later in the hearing Chevron’s Alaska General Manager John Zager confirmed that the new voting rules would prevent a single owner from vetoing a unit decision. The revised operating agreement also contains language that protects the project schedule, Kevin Brown, BP’s manager of gas business development, told the hearing.
Monitoring progress Irwin also quizzed Haymes on what would happen if development did not progress as planned.
“ExxonMobil and the owners will report progress through the plan of development,” Haymes said. “If there was a delay in an activity … we would talk with DNR on what new factor that is and what we would do to meet that gap, to ensure we could take this through to early production. We have a lot of incentive to bring on production earlier, not later.”
“What happens if DNR does not think progress has been adequate?” Irwin asked.
“The Point Thomson unit operating agreement provides provisions for DNR to take action if they believe we are not meeting our commitment in this plan of development,” Haymes said.
Haymes was not specific about what those unit operating agreement provisions are.
But later in the hearing Haymes stressed again that the Point Thomson unit owners view the 23rd plan of development as a binding agreement to take the field into production.
“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.”
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