BP Exploration (Alaska) Inc. partnered with U.S. officials this month to drill an exploratory well into a natural gas hydrate-bearing core on the North Slope, and though the test results may not be known for months, the possibilities are staggering.
Already known to hold enormous conventional reserves, the North Slope also holds the possibility of as much as 450 Tcf of untapped gas hydrate, which is about 12 times the 35 Tcf of conventional gas known to exist within the Alaskan fields.
BP drilling crews and scientists from the U.S. Department of Energy (DOE) and the U.S. Geological Survey (USGS) targeted the Sagavanirktok formation in the Mount Elbert prospect accumulation, which is below the permafrost at an ice pad location at Milne Point. The Milne Point oilfield, northwest of the Prudhoe Bay oilfield, is owned and operated by BP. The DOE funded the estimated $4.6 million cost to drill the well.
"With this project, we have significantly increased our understanding of gas hydrate-bearing formations on the Alaska North Slope," said Scott Digert, BP resource manager and the project's technical adviser. "The results also illustrate the value of collaborative research."
Gas hydrate in the North Slope has been known for decades, but up to now, producers have focused their interest on the conventional crude oil and gas reserves. Producers also have been awaiting technology, challenged to find a way to separate the natural gas from the solid gas-water-ice "clathrate" in which the gas hydrate occurred.
Methane hydrate is formed within and beneath permafrost in onshore areas and beneath the sea floor in offshore regions. On the North Slope at Milne Point, gas hydrate is dispersed in deposits beneath the permafrost, about 1,800-2,500 feet below the surface. The gas is contained within a solid clathrate structure, which compresses 160-180 unit volumes of gas into a single volume of gas hydrate.
From the 3,000-foot-deep test well, core, wireline logs, and wireline down-hole testing are expected to help the drilling and research team assess gas hydrate-bearing sediment, shallow reservoirs, and fluid properties. Subsequent data collection and analysis will continue for several months, and eventually, a report on the findings will be released.
The test well is part of the ongoing research partnership between BP and the DOE's National Energy Technology Laboratory, which began in 2002. Gas hydrate is an ongoing DOE research target (see Daily GPI, Nov. 8, 2005; March 3, 2005).
In the joint effort, BP contributed seismic data, staffing and program oversight. The on-site coring and data team included scientists from the USGS, DOE, Oregon State University and an observer from India's hydrate program. Also participating were members of the Arctic Slope Regional Corporation and the universities of Alaska and Arizona.
Drilling crews and research team members collected about 430 feet of core samples using drilling mud chillers and a wireline-deployed coring system that had been used in the Mackenzie Delta and in some Lower 48 states, but never in Alaska (see Daily GPI, Dec. 11, 2003). The cylindrical core segments, about three inches in diameter, were shipped to Anchorage for temporary storage before being distributed to gas hydrate researchers around the country.
BP's current focus is to successfully complete the stratigraphic test well, and "potential future program efforts" will be determined with DOE once an evaluation is completed. Digert said the next step in research is to drill a well to test production from a hydrate, but that is likely more than a year away.
Drilling a well into hydrates and running it as a conventional gas well will bring gas to the surface, Digert noted. However, using current technology the well would not flow at full pressure for long because the formation would tend to freeze.
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