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Thomson gas cycling gets lots of study In affidavit, Craig Haymes, Exxon’s Alaska manager, reviews history of working interest owners’ work on condensate production Kristen Nelson Petroleum News
Unit operator ExxonMobil has told the state that the Point Thomson 23rd proposed plan of development is different than previous PODs because it takes the field to production. It also comes out of a long history of gas cycling proposals at the field, adjacent to the Arctic National Wildlife Refuge on the eastern side of the North Slope.
“ExxonMobil is committed to POD 23. There are no off-ramps,” Craig Haymes, ExxonMobil Production Co.’s Alaska production manager, said in a March 14 post-hearing affidavit. “In contrast to prior PODs, ExxonMobil and the other owners have agreed to assume the economic, reservoir and technological risks” in the 23rd plan of development.
The Point Thomson working interest owners — major owners are unit operator ExxonMobil along with Chevron and BP — have disagreed with the state over when and how Point Thomson should be developed. ConocoPhillips is the fourth largest owner, with a 5 percent position; there are also a number of smaller working interest owners.
ExxonMobil, Chevron and BP have all submitted letters from senior management committing to the proposed 23rd plan, which is a multiyear plan leading to liquids production from a gas cycling project.
The Alaska Department of Natural Resources rejected the owners’ 22nd plan of development and terminated the unit.
Superior Court Judge Sharon Gleason concurred with DNR’s refusal to accept the 22nd plan of development, but ordered the department to consider remedies and report back to her.
The 23rd plan of development, submitted by the working interest owners earlier this year, was the focus of a five-day remand hearing held early in March.
DNR Commissioner Tom Irwin told the Point Thomson unit owners at the beginning of the hearing that they needed to convince him that the proposed 23rd POD for the Point Thomson Unit is different than the first 22 plans. Irwin said he had “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.”
Exxon: commitments have been met Both Irwin and hearing officer Nan Thompson asked questions about previous proposals for cycling projects at the field.
In his affidavit Haymes said the Point Thomson owners worked on a gas cycling project to produce condensate in the 1980s, but concluded the risk was too great.
How is this plan different? The owners “have agreed to assume the economic, reservoir and technological risks in the pursuit of delineating and producing the Point Thomson resources. This was not the situation in the past,” he said, repeating the assertion that in the 23rd POD the owners assume the risk.
Having discovered a “substantial” gas resource “with a thin oil leg,” the owners concluded early on that commercial development would have to wait on gas transportation facilities, but the owners continued to explore other means of commercializing the resource, he said. In 1985 they told the state that screening studies indicated Point Thomson reserves “may be sufficient” to support commercial gas cycling for condensate recovery, a project which could start up in the early 1990s.
Point Thomson is a high-pressure gas condensate field and a gas cycling project requires reinjecting gas at reservoir pressure.
Owners eager to commercialize Haymes said the Point Thomson owners were “eager to commercialize the resources” and did numerous engineering design studies for gas cycling, but told the state in the mid-‘80s that further field and laboratory testing and modeling would be required to confirm both technical and economic feasibility.
In 1986, after a year of study, the owners still believed cycling was a feasible option. The project being studied included 12 producers and eight injectors.
At the end of 1987, the owners told DNR they favored cycling because it allowed liquids production prior to major gas sales, but said they had not been able to resolve “the numerous concerns” owners had about the cycling project. They told the state condensate recovery is risky because of complex geology — “there may be more faulting than what the maps currently showed” — and there could be substantial variation in rock properties as well as in depositional trends.
The high-pressure reservoir was also a concern because continuous reinjection at the required pressure was unproven. Well tests also showed a wide range in condensate yields, with development costs estimated to exceed $1 billion (1987 dollars).
By 1988, the majority of the Point Thomson owners had concluded that cycling was high risk and uneconomic; efforts were refocused on better understanding the reservoir for development either as a cycling project or for gas sales.
Cycling evaluated again in 1990s By the 1990s, Haymes said, the Point Thomson owners were again looking at cycling as an alternative — in the event gas transportation never became available or wasn’t likely to become available in the foreseeable future. Reservoir description and performance projects would have to be thoroughly studied, the owners told DNR.
In 1993 the owners told DNR they had reaffirmed that gas cycling was still not appropriate and that gas sales were viewed as the only appropriate development option; they proposed to continue studying the reservoir for gas sales.
But by 1996, when it seemed gas sales were not on the horizon, the owners refocused on a cycling project.
By the fall of 1997, cycling had passed initial screening and the owners proposed to complete remaining scoping to refine gas cycling as a development option.
The project being studied in 1999 had eight producers and seven injectors producing 1 billion cubic feet a day of gas, which the owners hoped would produce 50,000-70,000 barrels per day of condensate. The owners said a major uncertainty was estimating condensate yield over the life of the project.
They focused on “ways to reduce project costs, maximize liquid recovery, and manage project risk and uncertainty.”
Optimistic assumptions ExxonMobil prepared an internal planning document in January 2003 containing “an aggressive schedule based on more than a dozen optimistic assumptions” for a gas cycling project, Haymes said, but later informed the state “that it thought this project might not be viable because of cost and reservoir uncertainties.” In any event, ExxonMobil told the state, the schedule was too aggressive — it had been based on President Bush’s call for federal agencies to accelerate the approval process for important projects.
The owners did further work “to reduce costs and enhance recovery,” but by early 2005 had concluded that cost reduction efforts still had not yielded a “commercially viable project.”
“As a result, and in light of the recent movement toward a gas pipeline,” the focus shifted to gas sales, Haymes said.
“During the hearing, I was asked questions that implied the (Point Thomson Unit) Owners have never been serious about developing the resources at Point Thomson and therefore cannot be trusted to implement the delineation drilling and cycling project contained in POD 23,” he said. “Those implications cannot be reconciled with the large amounts of time and money, and the substantial efforts made by the WIOs, to identify a cycling project that was commercially viable, particularly during the 1983-1988 and 1998-2003 time periods,” $67 million during PODs 18-21 alone, some 160 staff years spent on cycling and other Point Thomson issues.
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