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AOGCC approves Point Thomson field pool rules Approves initial gas-cycling condensate production followed by major gas sales up to 1.1 bcf per day through AKLNG project ALAN BAILEY Petroleum News
In an order issued on Oct. 15 the Alaska Oil and Gas Conservation Commission approved pool rules for the Point Thomson field that ExxonMobil is developing on the North Slope. The rules, which envisage the initial cycling of gas through the Point Thomson reservoir for condensate production, allow for the eventual annual average offtake of up to 1.1 billion cubic feet per day of natural gas. Gas from Point Thomson is an essential component of a project for the export of gas from the North Slope for delivery to market as liquefied natural gas.
The North Slope gas export project, known as AKLNG, needs assurance that the Prudhoe Bay and Point Thomson fields will be allowed to export sufficient gas for project viability, before a decision on committing to the huge cost of front-end engineering and design for the North Slope gas treatment plant, the export gas pipeline and a major liquefied natural gas plant on Cook Inlet, the facilities that form the main components of the project.
The commission, also on Oct. 15, issued an order allowing an increase in the maximum withdrawal rate for natural gas from the Prudhoe Bay field (see story on page 1 of this issue).
Development plan The Point Thomson field contains both natural gas and condensate, a mixture of low-density hydrocarbons, all at an exceptionally high pressure of about 10,100 pounds per square inch. Optimum production of the condensate from the field requires the maintenance of the reservoir pressure through the recycling of gas through the reservoir. ExxonMobil, the field operator, in what it refers to as the Initial Production System, or IPS, anticipates starting condensate production in early 2016, recycling all natural gas other than gas used as fuel, and delivering liquid condensate at a rate of up to 10,000 barrels per day into the North Slope pipeline system through an export pipeline constructed from Point Thomson.
Assuming that the AKLNG project comes to fruition, with gas sales perhaps starting in 10 years time, ExxonMobil plans to convert the Point Thomson wells and facilities to focus on gas production - condensate would continue to be produced along with the gas, but at a faster rate of decline than would likely have happened should gas cycling have continued. To provide for an estimated average supply of some 0.8 bcf per day for AKLNG, ExxonMobil asked for and the commission has approved a maximum average daily offtake of 1.1 bcf, a volume that can support the needs of the AKLNG project while also allowing the use of some gas for fuel and accommodating some operational flexibility.
During a Sept. 1 hearing, ExxonMobil told the commission that expanding the initial gas cycling operation at the field, to maximize condensate production rather than export gas, would be uneconomic, especially given the exceptionally high pressures in the field and the relatively low anticipated condensate yield. And the company provided evidence from reservoir simulations that ultimate hydrocarbon recovery from the field would be relatively insensitive to the mode of development used.
The Point Thomson reservoir is estimated to contain 8 trillion cubic feet of natural gas.
Classified as oil field Condensate, being a liquid when delivered, is technically viewed as a form of light oil. And according to the commission’s pool rule order, ExxonMobil anticipates the ratio of gas to oil at the onset of gas exports to be below a level of 20,000 cubic feet of gas per barrel of oil, thus compelling the commission to classify the Point Thomson wells as oil wells and the Point Thomson hydrocarbon pool as an oil pool. But, with the gas to oil ratio being higher than is normal for an oil well, the commission is authorizing an exemption from normal gas-oil ratio regulations.
The pool rules that AOGCC has now issued for the field are based on ExxonMobil’s preferred plan of development. However, the commission requires annual reviews of reservoir parameters and a report on the performance of the IPS system five years after sustained production starts and at least one year before gas sales from Point Thomson begin. The IPS-performance report, which must consider issues such as any presence of compartmentalization in the field reservoir and must give an account of the properties of the fluids in the reservoir, must discuss whether the move towards major gas sales is still the best way to develop the field.
The order says that the Point Thomson condensate and gas accumulation lies under a designated area straddling the Beaufort Sea coast and is about 500 feet thick. This accumulation forms a cap over a rim of heavy oil about 37 feet thick and containing an estimated 160 million barrels of oil. ExxonMobil has said that oil production from the oil rim is impractical because, given the viscosity of the oil and the fact that the oil forms a relatively thin layer, water and gas above and below the oil would tend to break through into production wells soon after production started. In its pool rules order, AOGCC has accepted that production from the oil rim “is not feasible with current technology.”
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