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Vol. 20, No. 36 Week of September 06, 2015
Providing coverage of Alaska and northern Canada's oil and gas industry

Question of volumes

Prudhoe Bay interest owners make the gas offtake case for AKLNG project

ALAN BAILEY

Petroleum News

During a public hearing of the Alaska Oil and Gas Conservation Commission on Aug. 27 the Prudhoe Bay oil field’s working interest owners presented testimony for a request to increase the natural gas offtake limit for the field. The increased offtake is needed to supply gas to the AKLNG project, a project for major gas exports from the North Slope.

The commission, with a mandate to ensure maximum hydrocarbon recovery from Alaska petroleum resources, has to determine whether to allow an increase to the current cap of 2.7 billion cubic feet per day and, if so, by how much. Gas, recycled rather than exported, has value in enticing more oil from field reservoirs. And oil has a higher hydrocarbon content than gas.

The AKLNG project needs commission approval for the required offtake volumes, prior to deciding in 2016 on whether to proceed to the hugely expensive front-end engineering and design phase of the project. The project involves the construction of a gas treatment plant on the Slope, a major gas pipeline to Southcentral Alaska, and a liquefied natural gas facility on the Cook Inlet.

Maximum of 4.1 bcf

BP, supported by ExxonMobil, has asked the commission to raise the gas extraction limit to 4.1 billion cubic feet per day, a volume that the company says would cover the amount of gas required for export and for North Slope gas uses, plus an additional volume that would be available as a contingency, should other gas sources earmarked for export become subject to some form of production glitch. But there is disagreement among the Prudhoe Bay working interest owners over how high the maximum permitted volume needs to be. ConocoPhillips, supported by Chevron, has told the commission that a daily limit of 3.6 bcf would sufficient.

In pre-filed testimony BP told the commission that the AKLNG project is being designed to intake North Slope gas at an average daily rate of 3.5 bcf. Of that volume, 2.7 bcf would come from Prudhoe Bay, and the remaining 0.8 bcf from the Point Thomson field, a major gas-condensate field that ExxonMobil is currently developing. With a further 0.6 bcf needed as fuel to power North Slope facilities, for field operations and for minor local gas sales, the total gas offtake from Prudhoe Bay under normal circumstances would average some 3.3 bcf per day, once gas exporting starts, BP says.

But, should the supply from Point Thomson go offline, Prudhoe Bay would need to supply 3.6 bcf per day to the LNG project, after taking into account the fact that Prudhoe Bay gas contains a significant amount of carbon dioxide that would need to be removed from the LNG supply stream. Adding in another 0.5 bcf for fuel gas and other needs leads to that 4.1 bcf per day of maximum gas extraction that BP and ExxonMobil have requested, BP has told the commission.

“This is all built upon a strong and viable continued oil development and production in the Prudhoe Bay oil field,” Bruce Laughlin, BP reservoir management team lead, told the AOGCC commissioners during the Aug. 27 hearing.

David Van Tuyl, BP regional manager and lead for the AKLNG project, told the commissioners that having an adequate contingency volume within the permitted offtake volume would give potential investors in the AKLNG project and buyers of LNG greater confidence in the project.

“In a sense it’s like insurance. You hope you don’t need it but if, in the event, one of these things happens, it’s a wonderful thing to have,” Van Tuyl said.

ConocoPhillips: 3.6 bcf is enough

ConocoPhillips, however, argues that its recommended maximum offtake of 3.6 bcf per day would more than cover any contingencies that might arise, while also ensuring minimization of the impact of gas production on liquids production from the Prudhoe Bay field.

“We do believe that it’s prudent not to pull the field any harder than is necessary,” Eric Reinbold, ConocoPhillips manager of subsurface development for Prudhoe Bay, told the commissioners.

Reinbold said that ConocoPhillips’ analysis has indicated that the contingency volume within the 3.6 bcf per day amount would cover worst case scenarios for gas supply interruptions. The maximum daily offtake figure represents an annual average; it is possible to temporarily exceed that daily limit, even up to 4.1 bcf, provided that the annual average is not exceeded, Reinbold commented.

Besides, should a problem occur that would require the Prudhoe Bay field to supply all of the gas for the AKLNG project, there would be sufficient advance notice of a setback of this scale to allow AOGCC to consider a further increase to the gas offtake limit, he said.

Commission Chair Cathy Foerster commented that the commission’s concern is purely ensuring the maximum recovery of hydrocarbons and the minimization of waste, and that, in its deliberations, the commission does not consider companies’ needs for commercial flexibility.

But BP argues that the question of whether to allow a 4.1 bcf versus a 3.6 bcf limit would make very little difference to ultimate hydrocarbon recovery from Prudhoe Bay.

The company has used its computer-based field model to run a series of theoretical future scenarios, ranging from business-as-usual oil production through the “gas reference case” involving 3.3 bcf per day of gas offtake, through to the 4.1 bcf per day required in the “sensitivity case,” the company said in a pre-hearing filing. In each scenario the BP analysts assumed a continuation of development drilling in the field, albeit with, in the gas export scenarios, some gas injection wells being converted to gas producers later in field life.

Increased recovery of 3.6 billion boe

The model indicated that, in the gas reference case, the export of gas from the field would cause a loss of total oil production of some 200 million barrels. However, the export of large volumes of gas would increase the total hydrocarbon recovery by 3.6 billion barrels of oil equivalent, net of that 200 million barrel loss of oil. Approximately 22 trillion cubic feet of gas would be recovered from the field. In the 4.1 bcf per day case, increased gas production would more than offset a further reduction in total oil production, resulting in a slight increase of 0.1 billion barrels of total oil equivalent produced, BP says.

Laughlin said that gas exports are projected to start in 2025.

Reinbold said that although the field modeling is robust, the modeling contains uncertainties, especially in regard to the impacts of different gas offtake rates on total gas production. ConocoPhillips would prefer to keep the offtake rate lower until there is more confidence in the outcomes of higher rates, he said. The working interest owners have been discussing this issue for several months but have been unable to come to an agreement, he said.

Impact on other fields?

One concern is the potential impact of the export of Prudhoe Bay gas on other North Slope fields where gas is used for enhanced oil recovery. Asked by Foerster about potential oil production losses at fields such as Alpine and Kuparuk River that currently use natural gas, Reinbold said that Prudhoe Bay is currently only exporting gas to Kuparuk River and that those exports would continue, regardless of major gas exports from Prudhoe Bay.

Foerster asked what would happen, should someone develop a new gas field on the North Slope to develop some of the estimated 150 trillion cubic feet of undiscovered gas under the Slope. Van Tuyl said that the AKLNG project would be expandable to accommodate additional gas, should the need arise.

Foerster also said that the order that the commission issues in response to the Prudhoe Bay offtake request may include an expiry date for the offtake authorization. “Sunset clauses” of this type have become standard practice in commission orders, she said. Van Tuyl responded that AOGCC approval of gas offtake volumes would underpin gas sales and purchase agreements for the AKLNG project. Shortening the duration of the offtake authorization would be viewed by prospective LNG buyers as an additional contract risk - LNG purchase contracts typically have durations of as much as 30 years, he said.



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