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Washington, DC - A fully instrumented well that will test innovative technologies for producing methane gas from hydrate deposits has been safely installed on the North Slope of Alaska. As a result, the "Iġnik Sikumi" (Iñupiaq for "fire in the ice") gas hydrate field trial well will be available for field experiments as early as winter 2011-12.

The well, the result of a partnership between ConocoPhillips and the Office of Fossil Energy’s (FE) National Energy Technology Laboratory, will test a technology that involves injecting carbon dioxide (CO2) into sandstone reservoirs containing methane hydrate. Laboratory studies indicate that the CO2 molecules will replace the methane molecules within the solid hydrate lattice, resulting in the simultaneous sequestration of CO2 in a solid hydrate structure and production of methane gas.

Methane hydrate consists of molecules of natural gas trapped in an open rigid framework of water molecules. It occurs in sediments within and below thick permafrost in Arctic regions, and in the subsurface of most continental waters with a depth of ~1,500 feet or greater. Many experts believe it represents a potentially vast source of global energy and FE scientists have studied methane hydrate resource potential and production technologies for more than two decades. Researchers are addressing such important issues as seafloor stability, drilling safety, and a range of environmental issues, including gas hydrate’s role in changing climates.

The recently completed operations include the acquisition of a research-level suite of measurements through the sub-permafrost hydrate-bearing sediments. The data confirm the occurrence of 160 feet of gas-hydrate-bearing sand reservoirs in four separate zones, as predicted, and provide insight into their physical and mechanical properties. An array of down-hole pressure-temperature gauges were installed in the well, as well as a continuous fiber-optic temperature sensor outside the well casing, which will monitor the well as it returns to natural conditions following the drilling program.

In coming months, field trial participants will review the data to determine the optimal parameters for future field testing. Current plans are to re-enter the well in a future winter drilling season, and conduct a 1-2 month program of CO2 injection and well production to assess the efficiency of the exchange process. Following those tests, the remaining time available before the spring thaw (as much as 40 days) may be used to test reservoir response to pressure reduction in the wellbore. This alternative methane-production method, "depressurization," recently proved effective during short-term testing conducted by the governments of Japan and Canada at a site in northwestern Canada.


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