What’s new in production

	Vol. 230 No. 5
DAVID MICHAEL COHEN, MANAGING EDITOR, DAVID.COHEN@WORLDOIL.COM

Hydrate production and CO₂ injection: Two birds with one stone

For decades researchers have known that enormous amounts of energy lay trapped on- and offshore in the form of hydrates—crystalline ice structures containing methane and other gases. Just to help paint a picture, a recent study by the US Minerals Management Service estimated the in situ methane resource trapped in hydrates in the Gulf of Mexico alone at 21,000 Tcf of gas, three times the world’s proved gas reserves. The sheer size of the resource at stake has driven methane hydrate research worldwide.

The primary challenge is developing a production method capable of yielding sufficient flowrates to make hydrates economic, despite the hydrates’ difficult location. To date, no production method for gas hydrates has demonstrated commercial viability.

Most known methane hydrates occur either in deep water on the continental shelf or in the Arctic within and below permafrost layers of rock. Deepwater hydrates are usually at shallow depths beneath the seafloor, and thus are at low pressure, making the possibility of achieving and sustaining high flowrates very small. Economically, it would be similar to drilling a deepwater well to produce coalbed methane.

On the Arctic side, the hydrates are more accessible, since they are onshore and occur at depths between 1,500 and 3,000 ft. However, the gas must be considered stranded because of the lack of pipeline infrastructure. Furthermore, when pipelines from the Arctic to southern markets do get built, as they inevitably will, low-flowrate hydrate gas will be incapable of competing with the 100 Tcf or more of conventional (i.e., high-flowrate) Arctic gas that is waiting in situ for transport in those pipelines.

New hydrate production method. An upcoming field trial funded by the US Department of Energy may shift this equation somewhat in the favor of Arctic hydrate production by establishing a new method of producing methane from hydrates while simultaneously trapping carbon dioxide underground. The method, developed by ConocoPhillips in conjunction with the University of Bergen in Norway, involves the exchange of a CO₂ for methane in the clathrate “cage” water molecules that forms the hydrate structure.

The patented method uses the difference in Gibbs free energy between carbon dioxide and methane hydrates (CO₂ hydrates are slightly more thermodynamically stable) to produce the methane while trapping the CO₂ in the hydrate. ConocoPhillips has successfully demonstrated the process in its laboratories.

The field trial, to be conducted on Alaska’s North Slope, will require drilling a well into a subterranean hydrate, injecting liquid CO₂ into the hydrate and subsequently producing the exchanged methane through the same wellbore.

Because there is no local source of CO₂, it will have to be transported to the site in trucks. Nevertheless, ConocoPhillips considers the North Slope to be the most cost-effective testing area because of its extensive geologic data set, established infrastructure and experienced operators. The company hopes to drill the well and run the trial within a year.

If it works, the procedure will leave intact the hydrate structure. This would give the new method an important advantage over previously developed techniques to extract gas from hydrates, which rely on heating or depressurizing. In addition to the large energy costs of these methods, they also melt the hydrate, which can lead to destabilization and collapse of the hydrate sediments and inhibit production.

Changing the equation. The North Slope is a particularly appropriate site in which to test this process, since its own vast methane hydrates are likely to be among the first produced commercially if it works. Because of the carbon dioxide sequestration that occurs, a successful trial could simultaneously make methane production from hydrates on the North Slope more economically attractive and remove a significant obstacle to the building of the long-anticipated natural gas pipeline to enable production of the region’s conventional gas.

Natural gas in Prudhoe Bay contains about 12.5% carbon dioxide, which would have to be removed before piping the gas to southern markets, both to avoid pipeline corrosion and to maximize the throughput of actual product. Dealing with all that CO₂ could be a major expense for North Slope producers, or, if used to produce additional gas from hydrates, it could be a great asset. Knowing that an available and potentially profitable CO₂ disposal option existed might help the producers and other interested parties make the commitment to finally get an Alaskan gas pipeline built.

Thus, even if the CO₂-methane hydrate exchange process does not yield high production flowrates, it could still be economically viable since the process would be an enabler of conventional gas production in the region instead of a competitor.

Effect of climate policy. The likelihood that the US will soon pass a carbon tax or cap-and-trade legislation strengthens the economic case for using CO₂ to produce methane. Projects to develop underground carbon dioxide sequestration are becoming increasingly common in the energy industry, both in anticipation of climate change legislation and for enhanced oil recovery. This technology will become a necessary part of fossil fuel production around the world as more nations restrict emissions of carbon dioxide into the atmosphere.

Storing CO₂ underground is an expensive endeavor, largely due to the cost of moving the gas from the plant to the injection site. In a carbon-regulated economy, using that CO₂ to produce gas from methane hydrates may prove more beneficial than using it to sweep the remaining oil out of mature reservoirs, especially given the smaller carbon footprint of burning natural gas. As an environmental bonus, trapping CO₂ in underground hydrates is likely to be a much more permanent storage option than other underground carbon sequestration concepts being developed.

It’s exciting when energy research simultaneously yields solutions to multiple problems. We’ll be keeping an eye on this research to see if its promising implications for the industry are realized.