Providing coverage of Alaska and northern Canada's oil and gas industry
January 2009

Vol. 14, No. 4 Week of January 25, 2009

Certified wells good policy

Consultant finds no decertified wells, says certification encourages exploration, development

Kristen Nelson

Petroleum News

When Director of the Division of Oil and Gas Mark Myers declared the Point Thomson unit in default in the fall of 2005 it was for lack of an acceptable plan of development.

He rejected the 22nd unit plan of development submitted by unit operator ExxonMobil, which focused on preparing for gas sales once a North-Slope-to-market gas pipeline was built, while the state wanted the owners to begin producing oil prior to gas sales from the eastern North Slope unit, which was formed in 1977.

When Commissioner of Natural Resources Mike Menge confirmed Myers’ decision in the fall of 2006 he added a new issue. In addition to the lack of an acceptable plan of development, Menge said that Point Thomson exploration wells certified capable of producing in paying quantities were no longer capable of that production.

Menge said in his November 2006 decision that because discovery exploration wells had been plugged and abandoned, none were currently capable of producing. He also said that no production wells have ever been drilled at Point Thomson: The certified wells were discovery wells. As a result, he said, those previously certified wells could no longer be used to hold leases.

The state’s original DL-1 oil and gas lease forms did not require a plan of development for a lease with a well capable of producing in paying quantities — the well by itself was enough to extend the lease beyond its primary term. New-form leases require that certified wells have an annual lease plan, unless the leases are in a unit.

While certified wells would not hold a unit, they hold the lease upon which they are drilled.

Crucial for exploration

“And to me it is really a key component of the state’s oil and gas leasing policy,” said Tom Walsh, a component that ensures that companies can hold onto expensive exploration discoveries until facilities or technology allow their production.

Walsh, a geophysicist and managing partner at Petrotechnical Resources of Alaska, testified for BP Exploration (Alaska) at a mid-January hearing on Point Thomson lease terminations. ExxonMobil (52 percent) and BP (29 percent) held the largest interests in the former unit.

The unit was terminated by DNR Commissioner Tom Irwin last year; that decision is under appeal in Alaska Superior Court. Thirty-one leases in the former unit were terminated last August by Division of Oil and Gas Director Kevin Banks on grounds that the unit had been terminated for 90 days and the leases were beyond their primary term.

Nine of those leases had successful discovery wells on them — wells, the owners argued, capable of producing in paying quantities. Those leases were terminated based on Menge’s decision that the wells were no longer capable or production.

That lease termination decision was appealed in the January hearing before Irwin and DNR Hearing Officer Nan Thompson.

For four days ExxonMobil witnesses described work at Point Thomson, telling Irwin and Thompson that the leases were held by an ongoing drilling program.

ExxonMobil has been preparing an old gravel pad at Point Thomson for drilling it proposes to begin this winter and in September set two conductors, 100-plus feet of pipe through which wells will be drilled.

Attorney Randy Oppenheimer of O’Melveny & Myers, summing up for ExxonMobil, told Irwin and Thompson “there clearly are drilling operations on the Point Thomson leases. ... We believe ... that that holds the leases.” In addition, Oppenheimer said, testimony on the certification issue provides a different and additional reason that the leases are held.

An awkward position

Walsh, testifying Jan. 16 on the fifth day of the week-long hearing, said he didn’t like to interject himself in conflicts between clients — his firm has done work for both the companies and the state — but said “this seems to be a compelling question and something that I wanted to participate in.”

Through 1998 the Division of Oil and Gas maintained a public list of wells certified as capable of producing in paying quantities, Walsh said, and when a new client comes to him, he starts with that list of 112 wells. When clients are looking for prospects to develop, that list provides wells that have discovered oil or gas in paying quantities.

That was his practical background, Walsh said. Then his firm spent two weeks researching certified wells for BP as part of the Point Thomson appeal using publicly available data from the Department of Natural Resources and the Alaska Oil and Gas Conservation Commission.

Walsh said he hasn’t found a current public list of certified wells, but knows “the practice of certifying wells continues and there are recent wells that are certified,” although the publicly available list hasn’t been updated since 1998.

No published standard

Walsh said there is no published standard for minimum rates of oil or gas for certification, so the firm combined information available from the two agencies to determine rates for the certified wells.

For more detailed information they turned to AOGCC well history files, but were only able to complete work on 36 of the 112 wells, using the files to determine test production rates for the wells, the rates used for certification.

Asked by Brad Keithley of Perkins Coie, representing BP, whether there was another way to determine production rates, Walsh said there is no spreadsheet that includes the rates associated with wells. And those rates are not available for wells that are confidential, a status typically allowed by the state when there is unleased acreage in the area of the discovery well.

For oil production, Walsh said test rates on wells certified as capable of production ranged from 57 barrels per day of oil to 4,672 bpd. Of five Point Thomson wells certified but not confidential the rates ranged from 170 bpd to 2,507 bpd.

Walsh’s firm also looked at dates of certification of the wells as capable of production in relation to dates the wells were plugged and abandoned, since Menge’s decision listed the plugged and abandoned status as significant. Of the 112 wells on the certified list, 76 were shown on an AOGCC spreadsheet as plugged and abandoned: on 21 that work was done prior to certification, on three at the same time and on 53 after certification.

But Walsh said the well histories, which contain reports done as wells are being drilled, showed that for many wells not shown as plugged and abandoned cement was actually pumped, which is the work done to plug a well.

Of the 36 well histories the firm had time to research, they found that cement had been pumped into 30 of the wells prior to certification, so they were plugged and abandoned prior to certification. One well was plugged and abandoned at the time of certification and five after certification.

Walsh said plugging and abandonment of exploration wells is a safety issue and the most cost-effective time to do the work is right after a well has been drilled and tested, when equipment is available at the site for the work.

Correspondence found

The well histories also contained some correspondence related to certification.

Of the 36 well histories Walsh’s firm examined, they found some 25 letters related to certification, he said.

There weren’t many examples of standards for certification, but one letter from 1967 described the selling price, terminal charge, transport charge, royalty and tax — all items, Walsh said, used to calculate wellhead price. That price, multiplied by the rate of production and minus operating costs is what the state looked at. It was a positive number, so the well was found capable of producing in paying quantities.

The more usual letter, Walsh said, sounded like someone had witnessed a production test and simply verified that the well produced in paying quantities based on the production rate, with no mention of a calculation.

Walsh said that what is consistent in the letters is they show that “this is a one-time determination using the rate and cost figures to determine certification of these wells” and that there is no indication that wells were subject to ongoing review. There was nothing in the files “indicating that these wells are subject to further review to maintain the certification,” he said.

And correspondence indicated that plugging and abandonment of wells had no effect on certification status.

No decertification info

Walsh said that they found no information on decertification of certified wells.

“No wells in the record that we were able to locate have ever been decertified once certified capable of producing in paying quantities up until the Point Thomson action,” Walsh said. He compared the process to earning a doctorate: You always have that Ph.D., whether or not you practice in the field in which the degree was earned.

Walsh said they did find two instances where the state had ordered leases that contained certified wells into production, one at Middle Ground Shoal and one at Redoubt Shoal.

They researched these two, he said, because of the 112 leases with certified wells these two were the only leases that were no longer active.

What they found was that the state ordered one of the leases into production in 1974; the lease was subsequently relinquished.

In the other case an extension was given to complete a test well or the lease would have been terminated; that lease was also relinquished.

In both cases it was the lease, not the certified well, that was ordered into production, he said.

Old wells not in unit

Outside of Point Thomson, there are five North Slope wells that were certified 20 years ago or longer, are not in production, not in a unit and still holding the lease, Walsh said. There were 10 in that category, he said, but five wells were added to the Oooguruk unit.

With five wells outside of units that are holding leases, Walsh said there are 71 certified wells within producing units on the North Slope.

What that means, he said, is that “some company went out and took great risk to drill a very expensive well and they were able to get that well certified as capable of producing and it allowed them to further appraise and develop those assets, those resources.”

The five certified wells that are now part of Oooguruk had been in and out of a number of units, “they were just never able to be commercialized until Pioneer (Natural Resources) came along.”

Walsh said that’s the case for most of the certified wells on the North Slope: “They had significant impact on proving reserves and eventually ... they were incorporated in those producing units.”

He said he doesn’t see anything different about the certified wells at Point Thomson: “Investments have been made; there have been some resources proven in that area; and there’s a company that may commercialize those.”

Walsh called Point Thomson “very challenged economically and technically,” and said he thought the state was setting a “very dangerous” precedent, especially with gas exploration. Anyone who drills an exploration well for gas on the North Slope “at this point” has to be “concerned that they cannot certify that well as capable of producing and extend the primary term of that lease,” he said.

Other examples

In addition to the certified wells incorporated into the Oooguruk unit, Walsh said other certified wells that helped facilitate North Slope production include Seal Island (developed at Northstar) and the Niakuk 2A and 5 certified wells. The Niakuk 2A was drilled from an offshore island at the end of the primary lease term in 1977 and it wasn’t until 1994 that Niakuk was produced. Walsh said it was “only after 3-D seismic was acquired after these wells had been drilled that the appropriate drill site location was determined to be onshore.”

Walsh called Niakuk “a great example of an area where certified wells were key in allowing an operator the time to technically and feasibly develop these assets.”

He said he expects Gwydyr Bay wells — among the five certified non-unit wells remaining on the North Slope — to eventually be incorporated into the Prudhoe Bay unit.

More research on tap

Walsh said the review his firm did found “there has never been a well decertified until the recent Point Thomson actions” and that plugged and abandoned status “does not have any bearing on certification.” He said information available in the AOGCC well histories is “very consistent and no well’s ever been decertified in the past.”

Irwin asked Walsh if he had examined all of the letters in the department’s lease files. Walsh said they did not use the lease files, but told Irwin he thought those files could be used to extend the research. He told Hearing Officer Thompson that it would be helpful to have access to certification records from 1998 forward and said that in addition to having access to certification letters it would be helpful if an updated version of the certification list was made public.

Walsh also told Thompson that while he hadn’t seen anything indicating decertification, “if there is a policy change that is in effect here that is only recorded in those letters,” then working through the lease files would be “very helpful.”

Keithley said he would appreciate getting letters on certification from the department and said BP was willing to make Walsh’s staff available to look through the lease files.

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