Point Thomson planExxonMobil argues for a major gas production field development route ALAN BAILEY Petroleum News
In a Sept. 1 hearing of the Alaska Oil and Gas Conservation Commission, ExxonMobil executives explained to the commissioners why they favor gas production from the giant Point Thomson gas field on the North Slope, rather than expanding the gas cycling operation for condensate production that the company is currently developing. The company has asked the commission to approve pool rules for the field.
Natural gas from Point Thomson forms a critical component of planned gas supplies for the AKLNG project, a project targeting major North Slope gas exports, potentially starting in 2025. ExxonMobil is seeking AOGCC approval of Point Thomson gas production prior to a 2016 decision on whether to proceed to the hugely expensive front-end engineering and design phase of the AKLNG project.
With about three quarters of the AKLNG gas supply slated to come from the Prudhoe Bay oil field, the Prudhoe Bay working interest owners have also applied to AOGCC for approval for the offtake of sufficient Prudhoe Bay gas. Gas offtake from Point Thomson for the project would average 820 million cubic feet per day, peaking at 920 million cubic feet per day in winter, ExxonMobil says. To allow for operational and design flexibility for the Point Thomson field, the company has requested authorization for an average annual offtake rate of up to 1,100 million cubic feet per day.
Gas and condensate The Point Thomson field, at a remote location on the North Slope coast, to the east of current operating oil fields, contains both natural gas and condensate, a mixture of low-density hydrocarbons, all at exceptionally high pressure. The field contains an estimated 8 trillion cubic feet of natural gas in place. Although the condensate is a richer form of hydrocarbon than the gas, and the condensate, as a liquid, could be delivered to market through the existing North Slope oil pipeline infrastructure, maximizing condensate production from Point Thomson would be very challenging. Essentially, to extract as much condensate as possible, gas would have to be recycled through the field reservoir to maintain reservoir pressure, an operation requiring expensive compression equipment and uniformity in the geologic characteristics of the underground reservoir.
In the absence of a means of bringing Point Thomson gas to market and amid an on-going debate over the merits of producing condensate from the field, the field lay fallow for many years. Then, as part of a settlement with the state of Alaska over the status of the leases containing the field, ExxonMobil undertook a modest-scale condensate development, using a gas cycling approach to produce some 10,000 barrels of condensate per day for export through a newly built pipeline from the central Point Thomson pad.
This initial Point Thomson development, dubbed the Initial Production System, or IPS, by ExxonMobil, is expected to come on line in early 2016.
Now, rather than expanding the IPS into a larger scale gas cycling system, ExxonMobil wants to proceed to what it refers to as gas expansion, or GE, a major development aimed at maximizing gas production while also producing some condensate along with the gas.
Development plan The IPS project involves two gas injection wells in a central pad at Point Thomson and a single production well on a western pad. Condensate is separated from produced gas for export, before the gas is compressed to 10,000 pounds per square inch for re-injection into the field reservoir. ExxonMobil reservoir engineer George Eleftheriou told the AOGCC commissioners that the proposed GE project would involve the drilling of seven additional wells, with all 10 of the wells, including the three IPS wells, being used for gas and condensate production. The new wells would be drilled from three pads: the existing central and west pads and a yet-to-be-constructed east pad, Eleftheriou explained.
Reservoir modeling indicates that the Point Thomson field could sustain the required natural gas production rate in excess of 800 million cubic feet per day for 15 to 16 years, with production declining thereafter. Condensate produced along with the gas, on the other hand, would start to flow at a peak rate of 57,000 barrels per day and immediately go into a continuous decline. Total natural gas production over a 30-year project life is estimated at some 6 trillion cubic feet, with about 200 million barrels of condensate being produced over that same timeframe, ExxonMobil says.
Gas separation Gas would be separated from condensate in a surface facility, with the gas being decompressed to 1,060 pounds per square inch for export through a 32-inch diameter pipeline, planned as part of the AKLNG project. The condensate would be exported through the existing Point Thomson pipeline. The use of the gas compressors that form part of the IPS infrastructure would be discontinued. However, ExxonMobil’s development plan includes the possible future installation of new gas compression units, to boost gas production as the field goes into decline. The GE project would also require the construction of new gas gathering pipelines from the east and the west pads, ExxonMobil says.
The GE facilities at Point Thomson would initially require 8 million cubic feet per day of fuel gas, with that fuel consumption rising to 28 million cubic feet per day if compression is installed, ExxonMobil says.
Commission Chair Cathy Foerster confirmed that, given the amount of condensate mixed with the gas at Point Thomson, the commission would view any production well at Point Thomson as an oil well rather than a gas well. Given the projected declines in condensate production under the GE plan, ExxonMobil is asking the commission for an exemption from regulations setting gas-oil ratio limits for oil well production.
Expanded gas cycling Eleftheriou said that ExxonMobil had done significant reservoir simulation and engineering design work for the alternative Point Thomson option of expanded gas cycling, with a focus on condensate production. The company had assessed this option as recently as 2002, and has concluded that gas cycling is not economically viable, with the reservoir pressure and low condensate yield being the main constraints, Eleftheriou said.
“The major challenges of large-scale gas cycling at Point Thomson are that the reservoir pressure is very high and requires large, expensive compression to re-inject the gas,” Eleftheriou said. “And the overall amount of condensate that is produced from the gas is not sufficient to make a viable, standalone project.”
In 2006 ExxonMobil conducted a survey of 230 gas condensate fields worldwide and found that, with none of the fields operating at reservoir pressures comparable to Point Thomson, gas production was the primary means of achieving condensate production, Eleftheriou said. And the condensate to gas ratio in the Point Thomson reservoir is far outside the range needed for gas cycling viability, he said.
Keith Breiner, ExxonMobil technical manager for Point Thomson gas expansion, said that reservoir modeling indicated that gas cycling at Point Thomson for 10 or 20 years before initiating major gas sales from the field might result in 2 to 3 percent of additional hydrocarbon recovery. But that would involve spending a substantial amount of money up front for a potential small gain some distance in the future. Moreover, this evaluation disregards the risks associated with the field, including assumptions about a homogeneous reservoir, no premature breakthrough of injected gas into production wells, and no reservoir compartmentalization. And then there is the possibility of putting the AKLNG project at jeopardy, Breiner said.
Oil rim The existence of a 37-foot thick oil rim below the gas pool at Point Thomson presents a concept for oil development in the field reservoir. But with the oil in this relatively thin rim being heavy and viscous, computer simulations have indicated that the water and gas below and above the oil would tend to “cone” towards production wells soon after oil production started, Eleftheriou said. As a consequence, immediate water and gas breakthrough into wells would render development uneconomic, he said.
The AOGCC commissioners have raised the question of setting expiry dates for their orders relating to gas offtake for both the Prudhoe Bay and the Point Thomson fields. Breiner told the commissioners that this would be problematic for the Point Thomson pool rules because it would introduce gas offtake uncertainty into a project where gas contract and development decisions commit to timeframes of 25 to 30 years.
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