Exxon’s plan for Point Thomson brings field closer to development

Field owners propose development drilling within five years; discussing conceptual development plans with agencies; look to produce gas, then oil

Kristen Nelson

PNA Editor-in-Chief

The Point Thomson field was discovered, and leases unitized, decades ago. The state has allowed the unit, which is adjacent to the western boundary of the Arctic National Wildlife Reserve, to continue without development because there is no pipeline. There still isn’t a pipeline, but development drilling is now on the table for the eastern North Slope unit.

The majority owners at Point Thomson — ExxonMobil, BP and Chevron — have told the state they plan to begin development drilling at the field within 5 years of approval of a plan of expansion-contraction which the state now has under consideration. The state would collect a $2 million penalty if that commitment were not met.

ExxonMobil, operator of the Point Thomson unit, said in the proposal that the Thomson sand gas would be developed first, with Brookian oil reservoirs to follow as capacity in facilities became available, allowing development of the Brookian reserves without the high cost of building standalone facilities and infrastructure and “greatly enhancing the commercial viability of those resources.”

To streamline facility sharing agreements, the owners will align their interests in all the Point Thomson unit reservoirs. ExxonMobil said owners of interests exceeding 95 percent of the total working interest have signed onto the application.

Unit presents challenges

The state, while acknowledging development difficulties, has been urging the companies to get on with it for years. Former Division of Oil and Gas Director Ken Boyd told the House Special Committee on Oil and Gas in 1999 that the Thomson sand is an over-pressured condensate field with 40 to 50 degree American Petroleum Institute gravity oil along with the gas, probably 200-250 million barrels of condensate plus 3-5 trillion cubic feet of gas. In addition, there are shallower Brookian Turbidite oil accumulations similar to Badami and some even shallower oil accumulations.

The companies have looked at the economics, Boyd said, and decided that “without the infrastructure, without a gas line, without a gas sales option,” field development is not economic. Boyd said the Thomson sand will require big wells with three strings of casing: “wells there cost twice as much and more than the wells other places, again because of the extremely high pressure.”

The companies have looked at alternatives that don’t involve gas sales. Jim Branch, Alaska region manager for ExxonMobil, told the Alaska Support Industry Alliance in January 2000 that because there is no gas transportation system, the Point Thomson unit owners have in recent years focused “more on a gas cycling project which would allow the development of the liquid reserves in the near term, yet retain the opportunity to sell gas later.”

In the unit’s 17th plan of development, approved by the state last year, ExxonMobil said the owners have been evaluating the technical challenges of gas cycling for the field because the injection pressure of 11,000 pounds per square inch is believed to be a world record.

Discoveries began in 1977

The Point Thomson exploration unit formed in 1977 had 40,768 acres. It was expanded to 134,920 acres in 1984, but that expansion required one well to be drilled by April 1985 and a second by February 1990 and leases were removed from the unit in 1985 and 1990 because the required wells were not drilled.

Early this year the unit had some 85,000 acres.

Recent expansion discussions began because an ExxonMobil lease adjacent to the unit was nearing expiration, but other owners refused to support expanding the unit by only one lease. Last fall, ExxonMobil began discussions with the state about larger changes in the unit.

The state said it would expect to see specific work commitments before it would consider expanding the unit, and in late January ExxonMobil submitted a plan which included work commitments. The size of the unit would grow substantially. While a core area would be 7,000 acres less than the current 85,000 acres, the total of the core area and three work commitment areas would be approximately 134,000 acres.

Public comments on the proposal closed March 19 and the commissioner of the Department of Natural Resources has 60 days from that date to issue a decision.

The unit’s 18th plan of development is due in early July, and in that plan, ExxonMobil told the state, unit owners will commit to begin development drilling within the core area of the unit within five years of approval of the expansion-contraction application.

Some areas dropped

All or portions of four leases would be contracted out of the unit, three on the southwestern and southern edge, one at the northeastern corner of the unit. All or portions of nine leases would be added to form the core Point Thomson unit area. These leases expand the existing unit to the northwest, north, east, southeast and south.

ExxonMobil said the proposed core area “more closely conforms to the consensus reservoir outlines for the known Thomson and Brookian sand reservoirs.” The core area would contain some 78,000 acres, 7,000 acres less than the present 85,000 acres.

In addition to the core area, the plan proposes three work commitment areas. Area A, including all or portions of four leases, is approximately 15,000 acres on the western border of the unit, and includes the Red Dog exploration well drilled in 1999 and suspended. The work commitment for area A includes creation of a common database in the area by March 31 — including Red Dog 1 well data and the Challenge Island 3-D seismic survey data — and drilling a new well or deepening the Red Dog 1 through the Thomson sand interval in the 2002-03 winter drilling season.

If area A commitments are not met, the tracts would contract out of the unit and, if the well is not drilled, the lessees would pay a $1 million performance penalty to the state.

Area B includes all or portions of four leases, some 17,000 acres on the northwest corner of the unit. The work commitment for B is a well to be drilled no later than the 2004-05 winter season, with a drilling commitment to be included in the plan of development due July 2, 2001. If the commitment is not made the leases would contract out of the unit; if the commitment is made and the well is not spud in 2004-05, the lessees would pay a $250,000 performance penalty to the state.

Area C contains approximately 24,000 acres and includes all or portions of 15 leases. Five of these leases expand the unit to the north; others are contained within the existing unit in the south and southwest.

ExxonMobil said the owners believe area C has been delineated and that more delineation drilling “would amount to economic and physical waste, contrary to State Regulations…” Seven wells have been drilled in area C and seven Thomson sands wells have been drilled close to it. High quality 3-D seismic has also been acquired, processed and interpreted for the area, and tied into well control points.

The Division of Oil and Gas does not specifically estimate oil and gas reserves for Point Thomson in its 2000 annual report, but in 1999 the division estimated undeveloped Point Thomson-Flaxman Island reserves at 200 million barrels of oil and 5 trillion cubic feet of gas. In 2000 the division lists “known onshore” undeveloped North Slope reserves as 202 million barrels of oil and 5 trillion cubic feet of gas.