The Point Thomson unit owners are proposing to develop the unit’s Thomson Sand as a gas field.
But what if it’s an oil field?
The Alaska Oil and Gas Conservation Commission, which has to approve hydrocarbon off-take rates before any production can begin, says that according to its regulations, the Thomson Sand is an oil field.
Before it can make a ruling changing that status it is going to need more cooperation than it is currently getting.
And it is going to need the owners to complete studies of alternative developments of the Thomson Sand reservoir, not just a gas-production alternative.
That was the message from commission Chairman John Norman to the Alaska Department of Natural Resources in advance of a hearing on the appeal from DNR’s Oct. 27, 2005, amended decision which found the unit in default.
He said Point Thomson unit operator ExxonMobil Production is behind in sharing information with the commission and has not yet filed for pool rules.
In its latest plan of development for the Point Thomson unit (see story in Oct. 29 issue of Petroleum News), unit operator ExxonMobil said the owners had initiated the process of applying for pool rules from the commission. It also said the owners and AOGCC “agreed to a protocol for the sharing of confidential data with the agency” in April, and in May, held a comprehensive Point Thomson review for AOGCC and its consultants.
ExxonMobil said in the proposed plan of development that the Point Thomson owners would continue to share confidential technical data with AOGCC in a data room. Once that process is completed, the owners would submit “a request for approval of a conservation order to authorize the desired gas offtake rate from the Thomson Sand reservoir.”
Commission disagrees
Norman disagreed with Exxon’s characterization of ongoing work between the agency and the owners.
And he disagreed with the characterization of the Thomson Sand as a gas pool.
The commission’s responsibilities include “preventing waste and insuring greater ultimate recovery of oil and gas resources located within the State of Alaska,” Norman said. Commission regulations define an oil well as “… a well that produces predominantly oil at a gas-oil ratio of 100,000 scf/stb (standard cubic feet per stock tank barrel) or lower, unless on a pool by pool basis the commission establishes another ratio.” Since DNR’s Oct. 27, 2005, amended decision says the Point Thomson unit contains at least 8 trillion cubic feet of gas and 200 million barrels of gas condensate and oil, “the effective gas-oil ratio for this reservoir is 40,000 scf/stb — significantly less than the 100,000 scf/stb limit set by regulations,” he said.
Norman said the commission has not received an application for pool rules for Point Thomson, and will presume the Thomson Sand reservoir at Point Thomson to be an oil pool “unless and until the commission establishes Pool Rules that provide otherwise.”
Gas cycling had been considered “a viable alternative for reservoir development” at Point Thomson until recently. The owners’ plan of development now proposes gas sales, but: “If major gas offtake from the PTU is the preferred alternative then it is essential that an application for Pool Rules be filed with the commission at an early date.”
He said the commission is concerned with the statement in the plan of development that the owners have been working, over the past year, to develop the Thomson Sand as gas, because the commission “currently classifies the TSR as an oil reservoir.”
Maximizing value not reason for committing waste
As for the assertion in the plan of development that “the most value” for the unit owners and the state will be “if the Point Thomson gas field is developed as part of a pipeline project,” Norman said the commission’s “responsibility is to prevent the physical waste of hydrocarbon resources. Maximizing value to the owners and the state at the possible expense of additional reserves is not a valid reason for committing waste.”
Norman said the Point Thomson owners “have yet to demonstrate to the satisfaction of the commission that developing the PTU as a gas field will be the only viable alternative for a prudent operator to pursue. Until they do, the commission will continue to regard the PTU as an oil field and steps taken towards developing it as a gas field risk being viewed as steps taken towards wasting hydrocarbon resources. Point Thomson could be part of a gas line project and still cycle condensate first; if the operator makes prudent use of the time available.”
The commission also included a short paper on its role in approving pool rules which describes the advantages and disadvantages of different development methods for reservoirs like the Thomson Sand, a retrograde condensate reservoir, a reservoir which is deeper and has higher pressures and temperatures than a conventional reservoir. Exxon “has indicated that the preferred scenario is to develop Point Thomson as if it were a normal gas field, which would likely result in significant loss of condensate,” the commission said.
Commission does not have data access
The plan of development also says the owners will share data with the AOGCC via a data room.
Norman said the agreement adopted in April called for ExxonMobil to advise the commission when the Point Thomson depletion plan study begins and provide access to the data room no later than Sept. 1. “As of this date,” Norman said, “the PTU owners have not made the data room available to the commission,” although in an Aug. 24 letter ExxonMobil proposed modifying the study to provide data in phases, with the result of the first phase, a gas field classification study, to be presented to the commission in the second half of September.
Norman said this study has not yet been presented to the commission.
He also said that based on information from the owners, it appears they “intend to complete work on the gas sales case prior to commencing work on alternative development scenarios.” If the owners apply for a gas offtake rate “prior to completion of the analysis of alternative development scenarios, they risk having the commission deny their application as incomplete,” Norman said.
Norman agreed with the statement in the plan of development that the commission and its consultants had a comprehensive review of Point Thomson work on May 11, including discussion of previous gas injection development efforts.
But, he said, the owners “declined to provide the commission with a copy of this presentation and said that this was the last time the commission would see the gas injection development scenario as it had been eliminated as a development option.”
Norman said the proposed plan of development appears to recognize that with changes in the state’s oil tax structure and in market conditions, a gas injection project “may be viable and will be reconsidered, but with the gas sales development remaining as the preferred scenario.”
Commission needs cooperation
With cooperation from the Point Thomson owners and a timely application for pool rules and a depletion plan for the Thomson Sands reservoir, “we expect to be able to discharge our responsibilities within the time line proposed by the operator. On the other hand, if we fail to receive full and timely cooperation from the owners, project delays could result,” Norman said.
The commission believes several things need to be completed before the submission of pool rules, he said, including geological engineering and economic models “necessary to evaluate the gas sales and alternative development scenarios”; evaluation of alternative development scenarios; and drilling the well proposed in the plan of development. “Selection of the drilling location for this well should be done in consultation with the DNR and the commission to help ensure that it will answer the questions that must be answered and, that can only be answered by drilling a well or wells.”
There also needs to be resumption and timely completion of the process established between the commission and the Point Thomson owners.
Norman said the commission “does not believe that the uncertainty that still exists about the potential development of the PTU can be used as justification for a decision that may promote waste of tens to hundreds of millions of barrels of oil and condensate. This is especially true in light of the fact that much of this uncertainty could have been eliminated already had the PTU owners adhered to the work commitments specified in previous PODs and agreements.”
