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Prudhoe Bay gas off-take: AOGCC concerned Alaska Oil and Gas Conservation Commission begins inquiry into natural gas sales rate, concerned about how much data field owners will be able to share after problems with 2002 study; may have to do own modeling to support decision Kristen Nelson Petroleum News Editor-in-Chief
How much natural gas can be removed from the Prudhoe Bay reservoir without reducing the recovery of oil? And how can that be determined in advance? Those are the issues the Alaska Oil and Gas Conservation Commission began considering at a March 3 hearing, the first in a series the commission will hold.
The commission is also trying to determine whether it will be able to work with the Prudhoe Bay field owners on their modeling efforts, or will have to do its own modeling.
Reservoir simulation modeling was done before the commission set a gas off-take rate of 2.7 billion cubic feet a day in 1977 — 2 bcf a day of which was designated for pipeline sales — before production began at Prudhoe. (See Part I of this story in the March 13 issue of Petroleum News.)
Commission staff and Frank Blaskovich, a consulting reservoir engineer working on the gas off-take issue for the commission, also had an opportunity to look at a study done in 2002 by the major Prudhoe Bay owners, BP, ConocoPhillips and ExxonMobil, as part of their preliminary gas pipeline project work.
Blaskovich told the commission the 2002 model studies done by the Prudhoe Bay working interest owners were basically a quick analysis for pipeline design. The owners shared the analysis, which they ran to study 40-year gas deliverability using the latest available stimulation model, with the commission.
But, he said, this study was not designed to maximize reservoir performance. And the model, while complex, was out of date.
In an August 2002 visit to BP offices Blaskovich and commission staff looked at nine major gas sale prediction cases and other studies, including a history match. Local cooperation was excellent, he said, but they were not allowed to do any electronic or paper copying.
The model followed industry standards and had innovative special features, but only provided a history match to 1996. While the model provided a good match at field level, Blaskovich said it had an oil production error which was growing with time. 2002 study results The 2002 work found that liquid hydrocarbon recovery during a major gas sale depended on timing of the sale, the gas off-take rate, mitigation measures and field life extension, Blaskovich said. Liquid recovery was found to be a direct function of when a major gas sale begins: the later the start of gas sale: the higher the liquid recovery. Liquid recovery was found to be an inverse function of the gas off-take rate: the lower the gas sales rate, the higher the recovery of liquids.
Liquid-only development was predicted to recover an additional 2 billion barrels, while gas sales could add 3 billion to 4 billion barrels of oil equivalent and extend field life.
The 2002 studies found nothing to indicate you wouldn’t want to do a gas sale, Blaskovich said.
Based on the 1977 and 2002 model studies, Blaskovich told the commission, the existing gas off-take rate should be re-examined. The studies don’t justify it, he said.
He also said the commission needs better information from the operators. And it needs to investigate major gas sales strategies that maximize total North Slope energy recovery.
He recommended independent model studies of Prudhoe Bay and other key fields, and a systems analysis of relationships among all North Slope fields. The commission should also analyze the effects of a major gas sale on other North Slope fields, including Prudhoe Bay liquid rates vs. trans-Alaska pipeline limits; new development opportunities; and gas utilization in other North Slope fields. Gas off-take update Commission Chairman John Norman said it appeared to have been understood in 1977 that once production began the gas off-take rule would need to be updated. As for the 2002 information the commission received from the working interest owners, he said the commission had cooperation, but difficulties with proprietary information. Blaskovich agreed there were limits on how data could be reviewed.
Norman said the commission asked for a conservation issue focus on gas off-take rates from Blaskovich, a focus which didn’t include the time value of money. The state landowner would focus on such issues, he said.
Norman asked Blaskovich if there was a reservoir anywhere in the world comparable to Prudhoe Bay and Blaskovich said he thought Prudhoe was somewhat unique: it’s the only field in the world with so many different reservoir processes going on at the same time, he said, and the processes used to extract the resource are equally complex.
Prudhoe is probably the state of the art field in the world, he said: the increased recovery from original estimates shows what can be done if you keep working. Sponsor group background In addition to presenting testimony at the hearing, the gas sponsor group, BP, ConocoPhillips and ExxonMobil, responded in writing to questions from the commission about the proposed gas sale.
The commission asked about the anticipated timeframe for an open season commitment for the pipeline and the companies said that within a 10-year framework for the project, open season commitments “would occur approximately 18 months after the start of project planning.” A non-binding open season could occur sooner, but not before “the establishment of suitable government frameworks.” The sponsor group said it is working on the government frameworks, but “the exact timing of establishing the government frameworks and the start of project planning is not yet known.”
Government framework includes federal legislation passed last fall, a contract with the state of Alaska for fiscal terms — being negotiated now — and a regulatory framework from the Canadian government, still undetermined.
The commission also asked if gas sales from Point Thomson and other North Slope fields will also be required for a gas project, and the companies said the Point Thomson unit “and other North Slope gas resources are vital to underpin a gas pipeline project.” In addition to known resources, “a pipeline project will likely require significant additional resources to keep it full throughout project life.”
A 35-year project would deliver approximately 50 trillion cubic feet to market at a design capacity of 4 billion cubic feet a day, the companies said, noting that the Alaska Department of Natural Resources in 2004 estimated that 25 tcf could be recovered from Prudhoe Bay with current technology, Point Thomson gas condensate is estimated to contain some 8 tcf of natural gas and 2 tcf are estimated from the Colville River unit, the Duck Island unit (Endicott), the Milne Point unit, the Kuparuk River unit and the Northstar unit. “Recent discoveries in NPR-A will further increase the known resource base,” the companies aid.
An additional 15 tcf from other North Slope leases will be required “to fill the pipeline capacity for 35 years,” the companies said.
The commission asked for the current planned maximum off-take rate and how early off-take could begin.
The companies said 4 bcf a day of natural gas would be delivered to North American markets, an off-take of some 4.5 bcf a day from the North Slope, “with the difference being consumed as fuel and shrinkage.”
The capacity of the project could be increased “through upgrading compression capacity, by installing infill compression stations, or through full or partial looping.”
The earliest start of gas sales off-take would be in the 10th year from the start of project planning, which will only occur after the government framework is established, the companies said.
Prudhoe Bay owners respond The gas sponsor group responded to some of the commission’s questions, the Prudhoe Bay working interest owners to others.
The commission asked when the working interest owners would seek commission approval of a gas off-take rate, and the Prudhoe working interest owners (BP is the Prudhoe operator; ConocoPhillips and ExxonMobil are the other major owners) said it would be desirable to have the off-take rate rule “changed in advance of open season. However, we do not know when open season will occur. And, we are confident that the large increases in total hydrocarbon recovery that will result from the construction of a gas pipeline will justify any pool rule changes that are required to support that gas pipeline.”
In response to the commission’s question on estimated total hydrocarbon recoveries the owners said “there remain numerous variables that could affect any estimate of total hydrocarbon recovery” from Prudhoe, but current estimates are 24 tcf of natural gas deliverable from Prudhoe, with an estimated 13 billion barrels of liquids the total estimated liquids recovery.
As to the impact on liquids recovery and gas recovery based on the rate of gas off-take for a major sale and various depletion scenarios that have been studied the owners said work done to date is preliminary “because of the uncertainties in the timing and rates for a gas project.” The owners said they have tools in place for studies of these issues.
The commission asked about the 2002 study, and whether the Prudhoe Bay owners have “performed the necessary software upgrades and studies to provide the needed certainty with respect to the impacts on total hydrocarbon reserves of gas sales” at currently projected off-take rates and timing.
The owners said they have updated the models “to reflect the most recent information on the Prudhoe reservoir description and production history and a focused effort is ongoing to continue to upgrade and improve the reservoir forecasting tools.” No additional information is available on off-take rate or timing.
As to when the owners would be ready to share their latest studies with the commission, the owners said they will work with commission staff to “design a work program to address the conservation issues related to major gas sales” and any revisions the existing limits on gas off-take, and will address liquid and gas recovery based on different gas off-take rates.
“Subject to PBU confidentiality requirements,” the owners said, they intend to share results of the work with the commission “and work cooperatively to mutually design and implement such new studies as may be needed.”
This work can be completed prior to financial and contractual commitments required for a gas sale, the companies said. Questions to gas group The commission had a number of questions for representatives of the gas sponsor group.
Norman asked Dave Van Tuyl, the commercial manager of BP’s gas group, what plans the producers have for the CO2 that would be removed at a North Slope gas processing facility and Van Tuyl said it would be re-injected at Prudhoe Bay for enhanced oil recovery. Norman also asked where a natural gas liquids facility would be located and Van Tuyl said it could be anywhere, but the 2002 reference case used Alberta because of existing facilities.
Commissioner Dan Seamount asked if the 4.5 bcf would be only for sales. Van Tuyl said the 4.5 bcf would be the volume dedicated to the pipeline and includes fuel gas for the gas project, but excludes Prudhoe Bay fuel gas usage.
Norman asked Joe Marushack, ConocoPhillips Alaska vice president of gas development, if all of the gas would need to go to the Alberta hub to make the project economic or if there will be gas for an Alaska spur line. Marushack said the companies are not ruling out a spur line. In the 2000-01 base case, he said, they had to know where most of the gas would go.
“We’ll look at a tie-in to Southcentral,” Marushack said, although most of the gas is expected to go to the Lower 48.
Rob Mintz, the assistant attorney general who works with the commission, asked how much of the 4-4.5 bcf would come from Prudhoe Bay, and Marushack said 2.9-3 bcf.
Norman asked if the companies understand that the commission has a specific role and it will take time to do specific studies.
Marushack said that was “painfully clear.” Prudhoe Bay owner questions Gordon Pospisil, BP’s waterflood resource manager for greater Prudhoe Bay, told the commission Prudhoe Bay oil production is mature, and gas development will significantly increase total hydrocarbon recovery. A major gas sale will extend field life, he said.
The Prudhoe Bay owners, Pospisil said, will work with the commission to provide gas sales information in a timely manner.
Seamount asked if the model used for the 2002 study has been updated, and Pospisil said the active full-field model used for long-term evaluation, the model described by Frank Blaskovich, “has been updated.” Seamount asked if the model looks at the impact of gas sales and Pospisil said it does.
Seamount also asked about confidentiality issues which limited the access of commission staff to the 2002 study. The Prudhoe Bay unit operating agreement provides that all owners have to agree, but we believe we can share necessary information, Pospisil said.
Asked how BP would work with commission staff on gas off-take studies, Pospisil said it would be similar to efforts in 2002: they would meet with commission staff and share results, and agree on additional studies needed.
Norman said the issue was how the commission might get to the point where it can develop a scientific basis for revising the gas off-take rule. One method would be for the commission to do its own independent study. He told Pospisil that while the owners were offering cooperation, “certain difficulties” were encountered with the 2002 study. Norman said there was a need to reconcile proprietary data with the work of a public agency, which strives to do work in public. How, he asked Pospisil, would you foresee reconciling these different interests?
The 2002 discussions were limited not by what was shared but what was able to be taken away, Pospisil said.
Norman asked at what point the commission would be delaying things if it hadn’t yet made a decision on the gas off-take rate and Pospisil said the owners would be prepared to work with the commission in a timeframe of weeks and months to determine an appropriate off-take rate, but said he couldn’t answer as to a date.
By what event would a decision be needed? Pospisil said it would be helpful for owners to have a ruling on gas off-take for open season.
The March 3 hearing was recessed and will reconvene April 21 at 9 a.m. at the commission’s Anchorage offices.
At that time, Norman said, the commission can pursue the schedule, interaction with the open season and exchange of information with the owners vs. the commission doing its own reservoir modeling study.
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