Now the U.S. Department of Energy is working with two Alaska oil and gas producers and a regional municipal government in an effort to find out.

Test wells planned in 2010 and 2011 could point the way toward a way of economically extracting methane from hydrates.

A gas hydrate is a crystalline solid where a methane molecule is trapped in a cage of water molecules, essentially ice that contains gas.

The potential resources are immense. Methane hydrates may contain more organic carbon than all the world's coal, oil and non-hydrate natural gas combined, the U.S. Geological Survey says.

Much of this is in difficult-to-reach offshore hydrates, but a lot of it is onshore in Arctic regions.

Studies by USGS geologists indicate a potential resource of 500 trillion cubic feet of in-place methane in hydrates believed to exist across Alaska's North Slope. From 44 trillion to 100 trillion cubic feet of this could exist right at industry's doorstep, below or near the existing oil field infrastructure on the slope, the agency says.

The question is whether methane can actually be produced from a hydrate, and the North Slope will provide a good test bed to find out, the DOE believes.

The agency has enlisted two producing companies, BP and ConocoPhillips, to try out two separate production ideas. The North Slope Borough is engaged in a separate project with DOE to assess whether hydrates are replenishing gas reserves in two small gas fields the borough operates near Barrow, 180 miles west of the North Slope fields. The borough will also drill a production test well in the East Barrow gas field.

Methane hydrates exist under certain pressure and temperature conditions, and they are known to exist offshore in buried sediments along continental shelves in several regions of the world.

Conditions are also ripe for onshore methane hydrates in Arctic regions, where there are underground geologic formations that contain hydrocarbons. This includes much of the North Slope and many parts of northern Canada and Russia.

Onshore hydrates appear to be formed by the migration of methane upward from the deeply buried source rocks into hydrates that form to trap the methane just below the permafrost, at depths of 2,000 feet to 4,000 feet.

The onshore hydrates, at least on the North Slope, also appear to be in thicker layers and more concentrated than offshore hydrates, and could therefore be easier to find and possibly produce, says Gordon Pospisil, technology and project manager of BP's Alaska hydrate program.

David Schoderbek, Conoco's Alaska hydrates project director, said offshore hydrates appear to occur in lower concentrations and in non-reservoir rocks, with densities that could be in the range of 20 percent. In contrast, the onshore hydrates on the North Slope appear to occupy as much as 60 percent to 80 percent of the pore space in sandstone.

North Slope producers have long known that hydrates exist around the large producing North Slope fields, where they were considered hazards when drill crews would unexpectedly encounter them while drilling conventional wells. Hydrates are believed to have caused gas "blowouts," or dangerous uncontrolled flows of gas, on wells on the North Slope.

Recent advances in seismic techniques and interpretation of well logs, or data gathered during drilling has allowed hydrates to be identified and mapped with greater accuracy.

Pospisil said what makes the North Slope ideal as a test-bed is the presence of industry infrastructure - availability of rigs and services, roads, utilities - that will allow production tests to be done more economically than in offshore regions.

BP's hydrate test project has been underway since 2002 in collaboration with the DOE. The goal is a long-term hydrate production test. The company drilled a well in the Milne Point field in 2007 to confirm results of its seismic profiling and to extract cores, or samples of rock containing methane hydrates. The project was successful on both counts: Drilling showed the hydrate was right where it was supposed to be, Pospisil said, and 100 feet of hydrate core was extracted. The test also showed the reservoir rock to contain higher saturation of hydrate than expected.

In a second phase of the project, BP will drill a second well and conduct a long-term production test that could last between three and 18 months, Pospifil said. Locations for the well are still being considered. It could be in the Milne Point, Kuparuk River fields or the western part of the Prudhoe Bay field, he said.

The test will involve gradually depressuring the hydrate to encourage the methane to flow, Pospifil said. Potential problems include possible re-freezing of the hydrate around the well-bore, which would impede the methane entering the well. This might be controlled by installing a heat tape to keep the temperature above freezing at the well perforations, or the points where gas would enter the well.

Problems could include sand and water that could flow into the well and impede the flow of methane to the surface.

Pospisil believes the sand problem can be solved just as solutions are being found for sand production that occurs with heavy oil. Handling the water that is produced imposes a cost, but it might also be an advantage because the water will be fresh, not briny like most water produced with oil and gas. Pure water is ideal for use in enhanced oil recovery projects in nearby conventional producing fields.

ConocoPhillips' carbon dioxide injection test, also planned for 2010, attempts to demonstrate in the field a process the company has successfully shown to work in the laboratory, that a CO2 molecule will displace the methane molecule in a hydrate while also preserving its structure, according to Schoderbek.

The downside of other hydrate production concepts, such as pressure drawdown, is that they could destabilize the hydrate, creating the problem of sand and water coming up the well. If the hydrate is preserved, however, only methane comes up the well, Schoderbek said.

ConocoPhillips' lab work has also shown that replacing methane with carbon dioxide in the hydrate appears to strengthen it.

"We believe the CO2 molecule is preferred by the hydrate over a methane molecule, which also leads us to believe the carbon dioxide hydrate will be more stable," Schoderbek said.

If carbon dioxide injection can be shown to work the procedure might also lead to a way of sequestering CO2 in hydrates. Conventional gas on the North Slope's Prudhoe Bay field contains 12.5 percent carbon dioxide and it will have to be separated and disposed of if an Alaska gas pipeline is built and gas sales begin.

The third hydrate drilling project is near Barrow, at the East Barrow and Walapka gas fields south of the community. These fields are now producing, but there is some evidence, not yet confirmed, that hydrates are present in both fields and may be feeding new gas into the reservoirs, according to Tom Walsh, managing director of Petrotechnical Resources of Alaska, the North Slope Borough's consulting firm on the project.

With support from DOE, the borough hopes to drill a pilot test well in late 2010 to confirm the presence of a hydrate and possibly extract a core sample, and then follow up with a production test well later in the year, Walsh said.

The Barrow test will try a different production technique than those attempted by BP and ConocoPhillips. The well will penetrate the hydrate, if it is there, and draw gas from an accumulation of free gas in the resevoir. By monitoring the gas production and pressure changes the borough will be able to detect if the hydrate is feeding gas into the resevoir. If it is, there may be much more potential reserves in the gas fields around Barrow than now estimated, Walsh said.

Tim Bradner can be reached at timbradner.@alaskajournal.com.