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 “I?nik 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.

SOURCE