ExxonMobil is continuing to develop its initial drilling plan for Point Thomson — although the Alaska Department of Natural Resources has terminated the unit and the leases — and that plan now includes nine wells, up from the initial five-well plan the company presented to DNR last year.
Craig Haymes, ExxonMobil Production’s Alaska manager, said Jan. 12 that the additional wells reflect the continuous nature of drilling planned for Point Thomson, a high-pressure gas condensate reservoir adjacent to the Arctic National Wildlife Refuge on the eastern North Slope.
The five wells were part of a 23rd plan of development for the unit, designed to test gas cycling and delineate oil accumulations which lie above the condensate reservoir, presented at a remand hearing on unit termination. The plan was rejected by DNR Commissioner Tom Irwin. He confirmed a unit termination process for lack of adequate progress toward development of the unit, which was formed in the late 1970s — a process which began under the previous administration in 2005. Exxon and the other owners are appealing the unit termination decision in Alaska Superior Court.
Haymes was testifying at a hearing before Commissioner Irwin and Hearing Officer Nan Thompson, appealing an August decision by Division of Oil and Gas Director Kevin Banks terminating most of the Point Thomson leases because 90 days had elapsed since termination of the unit and the leases were beyond their primary term. A smaller group of leases, on which discovery wells had been drilled, were also terminated and the wells ruled no longer capable of production.
Attorneys representing the major Point Thomson owners — operator ExxonMobil, BP, Chevron and ConocoPhillips — argued that the terms of the leases provide that drilling operations hold the leases, and that work ExxonMobil has been doing over the last two years falls into the category of drilling operations. They said that for the leases with wells capable of producing, the existence of those wells held the leases.
The five wells in the 2008 plan included a producer and an injector at the central processing facility, the Point Thomson 3 Pad; two oil rim wells from the west pad; and one oil rim well from the east pad.
There is no existing west pad at Point Thomson and initial drilling there will be from an ice pad; there is an existing gravel pad on the east side, but that will be moved because of erosion.
The four additional wells are all from the central pad: two gas wells and two oil rim wells.
What is being discussed now is the first phase and to get to full-field development will require more wells for gas sales; but many wells drilled as part of the initial development will become gas sales wells, Haymes said.
The five oil rim wells are designed for oil production, but also will be drilled through gas. He said the aim is to delineate the oil and produce it if it’s producible. If the oil is not producible these will become gas wells: All wells will be “keepers,” he said.
He said the cost of the wells, an estimated $250 million for the first and $100-$150 million for successive wells, dictates that the wells will always be used: All the central pad wells function as either injectors or producers; all the flank wells will be producers and ultimately, when a gas pipeline is in place, will be useable as gas-sales producing wells.
The additional wells won’t change the proposed 2014 production date, Haymes said. Drilling is not the critical path for Point Thomson development, he said, but conceptual engineering and procurement for the remote development.
Leases ‘enormously’ valuableAttorney Randy Oppenheimer of O’Melveny & Myers told Irwin that ExxonMobil does not believe the unit should have been terminated. He said the Point Thomson leases are “enormously” valuable and should be subject to an adversarial hearing. In early January ExxonMobil requested a transfer of the hearing from DNR to the Office of Administrative Hearings in the Department of Administration.
In opening remarks read into the record Jan. 12, Irwin noted that unit termination was not the subject of the hearing and said the appeal was administrative, “not an adversary proceeding.” DNR’s regulations do not provide “for an adversarial proceeding in which DNR presents evidence before a decision maker unassociated with DNR,” he said.
The director’s decision gave the basis for his decision; the hearing provides appellants an opportunity “to explain to me why they think he made a mistake and to provide me with evidence and legal arguments that support their contention,” Irwin said.
Two categories of leasesThere are two categories of leases.
Appellants argued in a pre-trial brief that nine of the leases have “wells capable of producing oil or gas in paying quantities” and under the lease agreements such wells hold the lease, unless the director provides lessees notice to put the wells on production — and allows a reasonable time to do so.
The other category of leases are held, appellants argued, because they were conducting “drilling operations and performed work on these leases diligently and in good faith, within 90 days after the unit termination decision, which served to extend the terms of the leases. Lessees had a legal right to conduct drilling operations on the leases” and the leases were extended by those drilling operations.
Appellants also argued the director terminated the leases without prior notice and without a hearing, and said they have been “prevented from continuing to conduct drilling operations on the leases by actions by DNR.” They said to the extent that DNR has prevented drilling “by denying drilling permits, the lease terms are extended by the force majeure provisions of the leases.”
Capable of producingThe issue of wells capable of producing got a lot of attention.
Brad Keithley of Perkins Coie, an attorney representing BP, told Irwin this is a contract case, not a regulatory case; it’s determined by the contract, he said. The meaning of important terms in the leases was determined beginning in the late 1960s when the leases were issued, he said, and they are contract terms, not regulatory terms.
The original leases on the DL-1 form provide for extension of the lease by shut-in production, Keithley said.
He said BP would present testimony on wells capable of producing, but since the early 1960s there has always been a one-time determination of capable of producing and whether a well was plugged and abandoned has made no difference to DNR, and DNR has never attempted to decertify a well certified as capable of production in paying quantities.
DNR now argues that once plugged and abandoned, a well cannot be put back into production, Keithley said, but told the commissioner BP would present evidence that a plugged and abandoned well can be re-entered.
Exxon agreesHaymes said seven wells at Point Thomson have been certified by DNR as capable of production, adding that five of those wells were certified after being plugged and abandoned. The companies have also applied to have three additional wells certified, but have not received a response on those requests. The 10 wells are on nine leases.
Doug Morgan, a former ExxonMobil reservoir engineer, said Jan. 13, the second day of the hearing, that there is no reason to believe the wells found capable of producing wouldn’t perform as tested. They would probably perform better, he said, because since liquids from the tests had to be stored in empty tanks on site, there was a restricted testing period. The rate of testing was also restricted with a very small choke used and limited perforation of the interval.
Morgan prepared the applications for the three wells the state has not certified and he said they were as capable of production as those certified. Regulations require that what a well has to pay out to be certified is just the cost of operation — facilities and other investment costs are not considered, he said.
Placement may not be optimalIrwin asked Haymes if the wells identified as capable of production would be put into production.
The wells could be put into production, Haymes said. But they were exploration and delineation wells and while capable of production may not be optimally placed for reservoir development.
Irwin asked if it was technically feasible to produce from all the wells classified as capable of production and Haymes said yes, that plugs would have to be removed from the subsurface and the wells would have to be tied in with the facilities.
In response to a question from Hearing Officer Thompson, Haymes said the wells capable of production were not included in the company’s nine-well drilling plan.
Thompson also asked what the impact would be on drilling plans if they drilled a dry hole. Haymes said if they didn’t find hydrocarbons at one of the planned wells it wouldn’t impact the others because they’re in different areas of the reservoir, but indicated that a dry hole would probably mean the company had encountered a fault and the response to that would be to drill a sidetrack to get into the reservoir.