ConocoPhillips group evaluating Alaska hydrate test

An industry-government group has recovered gas from methane hydrates through a well on the Alaska North Slope in a tightly controlled test in which carbon dioxide and nitrogen were injected and the pressure reduced.

Single truckloads of CO2 and nitrogen were injected and then the well pressure reduced via a downhole jet pump in the first test of a technology developed by ConocoPhillips and the University of Bergen, Norway.

Earlier theory, based on laboratory studies, held that hydrate response to CO2 injection would be very slow and injection difficult due to low permeability, but experimental and modeling work suggested potential for applications in natural reservoirs that required testing in a field setting to evaluate.

Ray Boswell, technology manager for gas hydrates at the US Department of Energy’s National Energy Technology Lab in Pittsburgh, said the partners plan to evaluate complex data from the proof-of-concept flow test for several months before attempting to express the specific results.

DOE described the experiment as having achieved a steady flow of gas but did not enumerate the rate. DOE said, “Ongoing analysis of the extensive datasets acquired at the field site will be needed to determine the efficiency of simultaneous CO2 storage in the reservoirs.”

The flow test was conducted in February-April at the Ignik Sikumi-1 well drilled the prior winter in the western Prudhoe Bay Unit. ConocoPhillips as operator perforated a 30-ft thick zone in the Tertiary Sagavanirktok C sand formation with 75% average hydrate saturation at about 2,200 ft in the 2,597-ft vertical well.

Japan Oil, Gas & Metals National Corp., which has been studying gas hydrates in the Nankai Trough offshore Honshu, Japan, was also a partner in the North Slope test (OGJ, Sept. 5 and 12, 2005).

DOE described the North Slope test as a tightly controlled scientific experiment to learn how the reservoir would respond to the chemical injection and subsequent staged reductions in pressure. CO2 and nitrogen were injected for 13 days followed by a flowback period during which the companies recovered methane, CO2, nitrogen, and water for 30 days.

The production technology differed from that used at the Mallik 3L-18C well in the Mackenzie Delta of Canada’s Northwest Territories, in which pressure reduction was used to destabilize the hydrate formation in 2007-08.

The US Geological Survey has assessed enormous resources of methane in hydrates in Alaska and worldwide, but DOE noted that it may take years to make sustained production economically viable.

Contact Alan Petzet at alanp@ogjonline.com.

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