On March 23, ExxonMobil filed a “plan of operations” for the eastern North Slope “Point Thomson area” with the Alaska Department of Natural Resources’ Division of Oil and Gas. Unlike previous Point Thomson plans, this application wasn’t called a plan of development, nor did it carry the next plan of development’s number, which would have identified it as the 23rd plan submitted by the operator of the undeveloped Point Thomson unit over the last 30 years.
That’s because both the Point Thomson unit and its leases have been terminated by DNR, although Exxon and other owners are challenging part of those separate decisions in court and in an administrative appeal to the commissioner to halt the process.
Division petroleum manager Nan Thompson told Petroleum News April 5 that the division and other DNR agencies are not reviewing the March 23 plan and well permits submitted by Exxon because of the defunct status of the Point Thomson unit and its leases.
The seven wells Exxon proposes to drill — one per winter — between 2008-09 and 2015 appear to be the same seven wells the company agreed to drill by June 15, 2007, in its 22nd plan of development, and then later asked for the drilling deadline to be extended to June 15, 2009.
No oil wellWhat the March 23 proposal is clearly lacking is the remote oil exploration well Exxon had promised to drill by June 15, 2006, later asking for an extension to June 15, 2007.
In its decisions to terminate the Point Thomson unit and leases, DNR hoped to kick start development of the eastern North Slope field, even though Department of Law representatives said last year that they expect litigation could take two or three years.
The field’s former owners, operator ExxonMobil Production, BP, Chevron and ConocoPhillips — along with a host of smaller owners — at one point were agreed on a gas cycling plan of development for Point Thomson, which would have meant the oil would have been produced first from the condensate and the gas re-injected. The recent brouhaha began in July 2005 when the owners said gas cycling was not economic.
Development drilling that was to begin by June 15, 2006, as previously agreed, was stretched to “three to three and one-half years before field startup,” with field startup tied to a gas pipeline yet to be constructed.
Mark Myers, division director at the time, was concerned about the liquids in the high-pressure Point Thomson condensate reservoir, and shallower oil plays in the unit, a combination of valuable resources, since Point Thomson is thought to hold about 300 million barrels of oil and natural gas condensates, as well as 8 trillion to 9 trillion cubic feet of natural gas.
“Point Thomson is a world-class asset and if it weren’t already under lease you’d have every major oil company in the world lined up to acquire it,” Myers told Petroleum News in August 2005. He said the state wanted to receive full value from Point Thomson, which would mean developing the liquids first, because producing the gas first could result in permanent loss of some of the oil and condensate.
“We’d like to see something similar to Prudhoe, if possible,” he said. “Produce condensate first before going to a gas blowdown scenario.”
Unit terminated in 2006The state signaled the end of its patience in the fall of 2005 when Myers found the Point Thomson unit in default for lack of an approved plan of development.
But a change in leadership at DNR that fall, and continuing negotiations over a gas pipeline fiscal contract between the administration of former Gov. Frank Murkowski and the major North Slope gas holders, BP, ConocoPhillips and Exxon, led to extensions of the appeal from Myers’ decision by a new DNR commissioner, Mike Menge.
The inability of the administration to get legislative approval for the contract, and Murkowski’s defeat in the primary, finally triggered Menge’s Nov. 27 decision to terminate the unit.
Prior to filing a lawsuit, Exxon and ConocoPhillips requested reconsideration of the unit termination. Acting DNR Commissioner Marty Rutherford (now deputy commissioner under Tom Irwin) denied their requests in December and affirmed Menge’s decision “in all respects.”
The former Point Thomson owners promptly filed a lawsuit and Exxon told the state it planned to file an administrative appeal on the division’s termination of the 32 core leases in the unit.
Exxon’s March 23 proposalSo what is Exxon proposing to do in its March 23 filing?
Beginning in the winter drilling season of 2008-09, Exxon plans to drill the first of up to seven wells from two ice pads “on or adjacent to the coastal area of the eastern North Slope’s Point Thomson unit.”
The company is looking at approximately one well per winter season, expecting to be done drilling in 2015.
The two 600 foot by 600 foot ice pads — referred to as the eastern and western pads — might be “saved from year to year through the use of insulating and board techniques,” Exxon said.
The company proposed to stake the pad and well locations in March 2007, which was eight days from ending by the time its paperwork was filed.
The timing of drilling operations “will be dependent upon the availability of materials and drilling equipment. Well heads, casing, and tubing are the longest lead material items and will require at least a year to receive. Sufficient time will also be required to specify, contract, properly equip and mobilize a drilling rig capable of drilling the high pressure, directional wells at Point Thomson,” the company said.
Equipment, staging would take timeBecause of these considerations Exxon said it couldn’t start drilling next winter.
The company is also looking at the alternative of barging equipment, materials and supplies to existing Point Thomson gravel pad No. 3 during the summer and staging the items there.
Two other existing Point Thomson gravel pads, Nos. 1 and 2, might also serve as staging areas.
“Further alternatives under consideration are use of synthetic matting boards in lieu of or in conjunction with ice pads and constructing an ice pad during the winter of 2007-08 and insulating it so that it would be preserved over the following summer,” the company said.
Drilling operations for each well are expected to take 70-80 days. Additional time may be required for coring and testing. Depending on coring and testing, a well might take two seasons to complete, Exxon said, noting that “year around drilling and well operations in the Point Thomson area have historically been done and are feasible.”
A sea-ice access road will be built from “the Prudhoe Bay area to the general Point Thomson area during each winter drilling season. This road, about 57 miles long, will follow the coastline eastward from the Endicott causeway to the vicinity of the Point Thomson Unit No. 3 drill site and the planned eastern pad.”
The two ice pads might be converted to gravel drill sites should Exxon proceed with development.
All wells will be directionally drilled, the surface hole and bottom hole locations within Exxon operated leases.
According to Thompson the seven well locations are in two core unit leases.