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Vol. 13, No. 43 Week of October 26, 2008
Providing coverage of Alaska and northern Canada's oil and gas industry

Hydrate estimate set at 85 tcf

USGS publishes assessment of technically recoverable North Slope gas hydrates

Alan Bailey

Petroleum News

The potential volumes of natural gas tied up in gas hydrates in northern Alaska dwarf the volumes being used to drive the economics of a North Slope gas line — a 1995 USGS assessment of U.S. gas hydrate resources estimated that just the gas hydrates associated with permafrost under Alaska’s North Slope might contain as much as 590 trillion cubic feet of natural gas. And an evaluation of the known gas hydrates in the area of the oil fields of the central North Slope suggested that these deposits by themselves may contain more than 100 tcf.

But how much of this vast gas resource could actually be developed?


As a first go at answering this question, USGS has published its assessment of technically recoverable gas from gas hydrates on the North Slope. USGS has estimated a mean recoverable gas resource of 85 tcf, with a possible range of 25 tcf to 157 tcf, from a 55,000-square-mile region that encompasses the central and southern North Slope; a major portion of the National Petroleum Reserve-Alaska; much of the coastal plain of the Arctic National Wildlife Refuge; and some nearshore areas of the Beaufort and Chukchi Seas.

The high range of uncertainty in the estimate reflects the geologic uncertainty regarding the locations and sizes of the hydrate deposits. And the estimates only relate to gas that might be recovered by means that appear workable using known technologies.

The assessment does not consider whether gas hydrate production would be economically viable. Economic viability would depend on development and production costs, the existence of a mechanism for moving the gas to market and appropriate market pricing for the gas.

Gas hydrate consists of a white crystalline substance that concentrates natural gas by trapping methane molecules inside a lattice of water molecules (methane is the primary component of natural gas). The hydrate crystals remain stable within a certain range of temperature and pressure. But when decomposed the crystals yield about 164 times their volume in methane.

Promising results

Although some limited tests of gas production from gas hydrate deposits have yielded promising results, no one has yet demonstrated full commercial-scale production from hydrates. However, the results from the tests, conducted in the Mallik well in the Mackenzie Delta and the Mount Elbert well on the North Slope, combined with production modeling have led to a view that gas hydrates can technically be recovered, Timothy Collett, USGS North Slope gas hydrate assessment team member, told Petroleum News Oct. 21.

The well tests together with “the production modeling done under the Department of Energy sponsored gas code comparison study … all document the fact that gas hydrates are a technically recoverable resource,” Collett said.

The USGS North Slope assessment says that the most likely production mechanism would be depressurization of free gas associated with the hydrates — depressurization through a production well would cause some hydrate to decompose, thus releasing more free gas.

The Mount Elbert gas hydrate stratigraphic test well, completed at Milne Point on Alaska’s North Slope in February 2007 as part of a joint government, industry and university gas hydrate research project, used a technique called modular dynamic testing to test the production characteristics of a gas hydrate deposit. The well also demonstrated the effectiveness of seismic techniques in locating gas hydrates in the subsurface.

But the stakeholders in this particular research program have yet to decide whether to proceed to the next phase of their project, which would likely consist of some form of production test at the Mount Elbert prospect.

Phased approach

Phase one of the USGS assessment overlapped with the research leading to the Mount Elbert well and focused on gaining an understanding of the known gas hydrates in what is termed the Eileen gas hydrate trend in the central North Slope. In phase two the USGS scientists used their understanding of gas hydrates obtained in phase one to identify and characterize potential gas hydrate deposits across the whole North Slope assessment area. Then in phase three the scientists proceeded through a systematic assessment of technically recoverable gas, using the results of the previous phases.

The upshot was the recognition of three gas hydrate assessment units in northern Alaska. Those assessment units correspond to three major stratigraphic units, the Nanushuk formation, the Tuluvak-Schrader Bluff-Prince Creek formations and the Sagavanirktok formation. These units all occur in what geologists term the Brookian sequence, the youngest of the three major oil and gas bearing rock sequences of northern Alaska. The gas hydrates occur in these relatively young rocks at fairly shallow depths, in a zone that generally straddles the base of the permafrost.

But the gas that forms the gas hydrates has probably migrated upwards from conventional oil and gas fields deeper down.

“As part of the gas hydrate petroleum system assessment, geochemical analysis of known gas hydrate occurrences revealed a link between gas hydrate accumulations and more deeply buried conventional oil and gas occurrences, in which methane migration from depth has charged the reservoir rocks in the gas hydrate stability zone,” USGS said.

And an analysis of industry-acquired seismic data indicated that the North Slope gas hydrates occur in deposits occupying “limited, discrete volumes of rock bounded by (geologic) faults and downdip water contacts,” USGS said. The hydrates probably formed from gas and water when the Arctic became cold about 1.88 million years ago.

Extrapolated across region

USGS used this knowledge of the geology of the gas hydrate deposits to estimate the number and size of potential deposits in each of the assessment units throughout the North Slope region. That led in turn to the estimates of technically recoverable resources.

However, the assessment only included volumes of gas hydrates thought to lie below the base of the permafrost and did not include any free gas below the gas hydrate stability zone. The assessment did not consider the possibility of gas hydrates being associated with some gas fields near Barrow.

And the USGS scientists only counted potential gas hydrate deposits likely to contain 50 billion cubic feet or more of natural gas — that minimum accumulation size is somewhat smaller than what the USGS normally uses for its assessments because many seismically inferred deposits are close to the existing oil and gas infrastructure, USGS said.

About 24 percent of the assessed gas resource is thought to be in the Sagavanirktok formation assessment unit, 33 percent in the Tuluvak-Schrader Bluff-Prince Creek formations assessment unit and 43 percent in the Nanushuk formation assessment unit.

The estimate mean volume of 85 tcf in this new assessment is considerably less than the 590 tcf that USGS estimated in 1995 in part because the new assessment only applies to technically recoverable gas and in part because the 1995 estimate included offshore federal waters, USGS said.

“In addition, the assessment results reported here are based on geologic data that were not previously available, which afforded a greatly improved appreciation of the North Slope gas hydrate petroleum system,” USGS said.

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