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Vol. 14, No. 41 Week of October 11, 2009
Providing coverage of Alaska and northern Canada's oil and gas industry

Picking the test site

Researchers study potential areas for North Slope gas hydrate production test

Alan Bailey

Petroleum News

Researchers engaged in a multiyear joint government, industry and university project to investigate the production of natural gas from gas hydrates under Alaska’s central North Slope are selecting a site for a long-term production test. And drilling from the Prudhoe Bay field L pad into some nearby stacked, hydrate-filled sands seems the most likely scenario for setting up the test environment, said Tim Collett of the U.S. Geological Survey and Ray Boswell of the U.S. Department of Energy in the latest edition of the DOE “Fire in the Ice” newsletter.

And, while the site evaluation progresses, DOE and BP are forming an Alaska North Slope joint industry project, to seek broader participation in the gas hydrate research, Collett and Boswell said.

In a parallel project, ConocoPhillips is working with DOE to plan a test of gas hydrate production by injecting waste carbon dioxide into hydrate deposits.

Gas hydrate (or more correctly “methane hydrate”) consists of a white crystal-like substance that concentrates natural gas by trapping methane molecules inside a lattice of water molecules (methane is the primary component of natural gas). The hydrates remain stable within a certain range of temperature and pressure, but when decomposed yield about 164 times their volume in methane.

Huge volumes

The huge volumes of methane locked up in gas hydrate deposits straddling the base of the permafrost under the North Slope could become a major source of natural gas for export through a future North Slope gas line if, that is, researchers can solve the puzzle of how to produce gas from the hydrates in a sustainable and economically viable manner. The central North Slope is one of the world’s most favorable sites for possible gas hydrate production, because the hydrates are on land close to an existing oil and gas infrastructure.

In 2007 BP drilled the Mount Elbert gas hydrate stratigraphic test well from an ice pad in the Milne Point unit, a drilling venture that formed part of the same project that is now evaluating production test sites.

The Mount Elbert well enabled the recovery of gas hydrate samples and some limited testing of the production characteristics of the hydrates found around the well bore. And results from Mount Elbert, and from another well, the Mallik gas hydrate test well in northern Canada, have convinced the U.S. Geological Survey to classify some gas hydrate deposits as “technically recoverable,” with the most likely production mechanism being depressurization of free gas associated with the hydrates — depressurization through a production well would cause some hydrate to decompose, thus releasing more free gas.

Sustained production?

But the path toward moving some of the known gas hydrate deposits into an “economically recoverable” status requires, among other things, a demonstration that effective gas production from the hydrates can be sustained over long periods of time. Hence the need for a production test of the type that the North Slope team is planning: The brief insights into production that were gained at Mount Elbert and Mallik may or may not presage successful long-term, viable production possibilities.

“A reservoir’s initial production response often provides limited insight into actual deliverability due to transient effects that are very difficult to understand,” Collett and Boswell said. “Because the time required for the production response to stabilize may take many months or more, a key criterion for gas hydrate production testing is the availability of a site that allows continuous access over a sufficient duration to provide meaningful data on reservoir performance. This could mean only a month or so if the test produces large and stable volumes quickly; it could mean several years if all the planned contingencies for supplemental testing need to be invoked.”

And the need for long-term access to the test site will require the use of an existing gravel well pad, rather than a temporary ice pad of the type used at Mount Elbert, they said.

Unfortunately, the need for a long-term well pad precludes the possibility of using the Mount Elbert surface well site for a production test, thus requiring the use of “a high-angle to horizontal well path that would cross at least one major fault” to access the Mount Elbert gas hydrate deposits from an existing gravel pad, Collett and Boswell said. And although Mount Elbert offers the advantage of a proven and tested gas hydrate deposit, the complexities of the required drilling, completion and logging operations would significantly raise the risk, and presumably the cost, of the project.

Low temperatures

The Milne Point gas hydrate reservoirs themselves also suffer from a significant disadvantage: Reservoir modeling indicates that the relatively low temperatures of between 2 degrees and 3 degrees Celsius in the reservoirs would likely delay initial production of gas after a well has been drilled, while also slowing subsequent production. Temperatures just a few degrees higher would eliminate the production delay and substantially increase production rates, the modeling shows.

These various issues at Milne Point are pointing the researchers toward the use of the Prudhoe Bay L pad, where hydrate-bearing reservoir sands close to the well pad are similar to the Milne Point reservoirs and about 3 C warmer. Another possible Prudhoe Bay location, at the old Kuparuk State 3-1-11 well, does not have an operational gravel pad and would require a significant investment in infrastructures upgrades, Collett and Boswell said.

Other sites considered consist of a couple of locations on the eastern margin of the Kuparuk River unit, and a location to the east of Prudhoe Bay L pad. The Kuparuk locations appear to suffer from reservoir temperature issues similar to Milne Point, while presenting a higher level of geologic risk. The location to the east of L pad presents the major advantage of reservoir temperatures around 12 C, but suffers from a lack of nearby surface facilities, as well as lacking nearby well penetrations to confirm reservoir continuity.

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