The Alaska Oil and Gas Conservation Commission has published an application by ExxonMobil for pool rules for the Point Thomson gas-condensate field that the company is developing on the North Slope. The initial development of the field is targeting the production of condensate by the recycling of natural gas through the field reservoir, but the company is asking permission for a subsequent offtake up to 1,100 million cubic feet per day of gas, if a proposed plan for the export of North Slope gas through a major gas pipeline and liquefied natural gas facility comes to fruition.
AOGCC has scheduled a public hearing on Sept. 1 to gather testimony on the pool rule proposal.
Gas and condensate
The massive Point Thomson field contains both natural gas and condensate, a mixture of low-density hydrocarbons, at exceptionally high pressure. And, over the years, the relative merits of producing gas versus condensate from the field have been much debated. In the absence of a means of shipping North Slope gas to market, the question of producing gas from the field has been something of a moot point. On the other hand, the physical characteristics of the Point Thomson field reservoir and the fluids that it contains require the recycling of gas through the reservoir to maintain reservoir pressure to maximize condensate production. And, although a gas cycling development entails some technical risk, the liquid condensate could be exported though the existing North Slope oil pipeline infrastructure.
AOGCC has a mandate to ensure maximum Alaska hydrocarbon production, although the commission cannot force an oil company to conduct a project that is uneconomic. In the case of the Point Thomson, the field’s condensate has a higher hydrocarbon content than the field’s gas, thus making the condensate a desirable production target. And the field’s Point Thomson Sand reservoir contains a thin rim of heavy oil below the massive pool of gas and condensate.
Initial Production System
ExxonMobil calls its current Point Thomson development, designed for the production of condensate through the cycling of gas through the field reservoir, the Initial Production System, or IPS. The development, which involves two gas injection wells and one gas-condensate production well, is at an advanced stage, with startup expected in early 2016. About 10,000 barrels per day of condensate from the field will be delivered to the trans-Alaska pipeline via a new Point Thomson pipeline that connects to the export pipeline for the Badami field, between Point Thomson and the central North Slope.
On Aug. 25 AOGCC formally approved ExxonMobil’s request for permission to inject gas into the Point Thomson reservoir for the IPS. In its area injection order approving the request the commission said that the IPS project would not waste hydrocarbons. The commission also said that it had appropriately classified condensate and oil in the field reservoir as the Point Thomson Sand Undefined Oil Pool.
But with the production from the IPS being modest in scale, should the next step be an expansion of the gas cycling condensate production system? Or should the field focus instead on gas production, assuming that the North Slope gas export project moves ahead? Point Thomson gas looms large in the economics of the gas export project, commonly referred to as the AKLNG project.
Prefers gas export project
In its pool rule application, ExxonMobil says that it favors moving straight from the IPS to a Point Thomson gas export project, rather than expanding the gas cycling arrangements. The gas export option would result in some condensate production, but would leave more condensate in the ground than would the expanded gas recycling route. But the loss of condensate output would be offset by savings in the use of gas as fuel for driving the gas recycling process, the company says. And, while either development option would result in around the same total hydrocarbon recovery, the gas export route would bring those hydrocarbons to market earlier, the company argues.
Under a major gas export scenario, the gas offtake from Point Thomson would average 820 million cubic feet per day, with the offtake peaking at 920 million cubic feet per day in the winter, according to ExxonMobil’s pool rule application. Thus, the requested annual average offtake rate of 1,100 million cubic feet per day would allow flexibility in the design and operation of the Point Thomson facilities and wells, the application says.
The ultimate quantity of hydrocarbons that can be extracted from the field is, in fact, relatively insensitive to the withdrawal rate, with the withdrawal rate impacting the length of time required to achieve maximum extraction rather than the ultimate volume extracted, the pool rules application says.
Approval needed
ExxonMobil says that it applying now for approval for its proposed development path for Point Thomson in order to obtain approval in time to support the required engineering schedules for both the proposed Point Thomson gas expansion project and the AKLNG project.
“Approval of an allowable gas offtake rate is needed to commit to the substantial Point Thomson unit engineering costs required to progress this effort and to have a firm basis to design the Point Thomson wells and facilities,” the application says.
The AKLNG project is working towards a major threshold in the second quarter of 2016, at which point the project must decide whether to move into the hugely expensive stage of conducting the project’s front-end engineering and design.
“A key consideration for the project participants will be that sufficient gas supplies will be available to support the project,” the pool rules application says.
Gas cycling evaluated
The pool rules application says that a full-field gas cycling project for Point Thomson was intensely evaluated in the early 2000s but was not found to be economically viable.
“Major impediments were the limited amount of condensate that could be recovered, the high cost of the facilities and wells, and the significant risks associated with a gas cycling development,” the application says, commenting that especially high required reservoir injection pressures form a key differentiating factor from gas condensate production elsewhere in the world.
“While the IPS production operations will provide useful information about the reservoir, no scenarios have been identified in which this information would materially improve the current outlook for the viability of expanded gas recycling,” the application says.
Gas for Prudhoe
ExxonMobil says that it has also evaluated an option to inject Point Thomson gas into the primary reservoir of the Prudhoe Bay oil field. Although this option could provide a means of accelerating by one or two years the development of gas exporting from the Point Thomson field, this shortening of the timeline would be unlikely to provide sufficient justification for the development costs and diversion of resources required, the application says.
“Any further consideration of this option would depend upon progress on the AKLNG project,” the application says.
With a known thin rim of oil located below the gas pool in the Point Thomson reservoir, oil production is another possibility in the field. But this oil, being heavy and viscous, would be difficult to produce - ExxonMobil says that it has evaluated this option and determined that production from the oil rim is not viable.
“Study results … indicate that initially heavy oil from the oil rim would be recovered, followed by high rates of gas and water within weeks or months of initial production,” the pool rules application says.
