Methane on Ice

The price of natural gas in North America has reached record highs in recent years, undermining profitability for chemical producers that rely on the gas as a feedstock and enticing them to invest overseas where they can find cheaper raw materials. It has also spurred debate over importing liquefied natural gas, which could supplement North American production and put a ceiling on natural gas prices.

But importation isn't the only option for additional supplies of gas. Little known to most people other than geologists is that deep beneath the ocean and buried under Arctic permafrost lie many more moles of methane, the main component of natural gas, than the U.S. could ever use. There is a catch, however: The methane is in the form of methane hydrates.

Under high pressure and low temperature, methane can be trapped in cagelike structures of water molecules; the resulting complexes are known as methane hydrates. Methane hydrate crystals resemble ice, and to the natural gas industry they are better known as a nuisance because they plug up pipelines where water has seeped in.

More exotic are the vast quantities of methane hydrates found naturally in the ocean or the Arctic. On the sea floor, they form huge mounds that support biological communities. One of their more famous inhabitants is the centipede-like "ice worm" that digs nooks and crannies in the mounds.

The hydrates are much more than an oddity--they are a resource that rings nearly every continent. Timothy S. Collett, a research geologist with the U.S. Geological Survey (USGS), has estimated that there could be as much as 317 quadrillion cu ft of methane gas stored in hydrates in the U.S. By comparison, the Department of Energy estimates that there are 187 trillion cu ft of natural gas reserves in the U.S.

USGS estimates there are as many as 49,000 quadrillion cu ft of hydrate-based gas reserves in the world's oceans and up to 12,000 quadrillion cu ft on land, though estimates vary wildly. Conventional reserves are estimated at 13 quadrillion cu ft.

With the gas crisis in the U.S., hope is increasingly being put on methane hydrates. In a speech on energy policy this spring before the National Petrochemical & Refiners Association's annual meeting, Federal Reserve Board Chairman Alan Greenspan noted their promise as a source of energy that is "perhaps a generation or more" away.

We don't necessarily have to wait that long, says Arthur H. Johnson, president of Hydrate Energy International (HEI) and adjunct research professor in Tulane University's department of chemical and biomolecular engineering. He says commercial production of natural gas from hydrates could be only three to five years away. But he jokes that "10 years from now, it could still be three to five years out."

Recovering hydrates isn't simply a matter of designing a ship that will dredge up the mounds on the sea floor, Johnson says. He calls this idea economically "dicey" and environmentally impossible, given the complex ecosystems associated with the hydrates. And, he notes, drilling too close to the mounds is illegal in the U.S. anyway.

"What we need is a reservoir rock very similar to what we need with conventional oil and gas development," Johnson says--rock such as sandstone with methane hydrates dispersed in the pore space. Such rock would also have to be in "the hydrate stability zone," where there are low temperatures and high pressures, but not so deep that geothermal energy prevents hydrate formation.

THESE FACTORS whittle down the amount of commercially recoverable hydrates. "It is not how many molecules of hydrate there are in the world," he says. "It is where it is concentrated in sufficient volume that you can commercially produce it and get commercial volumes out."

For example, Collett estimates there are about 1.3 quadrillion cu ft of methane in the Blake Outer Ridge off the coast of the Carolinas. Johnson notes, however, "The problem is that the rock is an extremely tight shale." He says, moreover, that there is a low percentage of hydrates in that rock, submerged under two miles of ocean and with no pipeline infrastructure to take the gas to shore. "There is no way you are going to produce that," he says.

Although Johnson calls the big numbers associated with hydrates mostly hype, more realistic estimates are still impressive. "You are still talking thousands of trillion cubic feet but not hundreds of thousands. You are still looking at a potential resource that is perhaps an order of magnitude greater than the conventional gas resource," he says.

This gas hydrate resource is already generating commercial interest. Clyde Payn, president of the Catalyst Group in Spring House, Pa., is compiling a report on alternative energies, including a section on hydrates written by HEI's Johnson, for a consortium of companies, including chemical manufacturers that hope to reduce energy costs. "People don't realize that a number of commercial field programs have been under way to develop this resource--on land, at least--for the past eight years."

In fact, it has already been commercialized--that is, if one believes the story of a mysterious Soviet gas field in the early 1970s. In this Siberian field, it is believed that the depressurization from conventional natural gas production dissociated methane from the hydrates, which then replenished the gas in the field.

In a $5 million study, BP Exploration Alaska, along with DOE and other partners, are exploring for hydrates in the North Slope of Alaska, specifically in the Eileen Trend region, which includes the BP-owned Milne Point Unit (MPU). A total of 44 trillion cu ft of methane could be trapped as hydrates in the Eileen Trend.

The research is yielding promising results, according to Robert B. Hunter, a consultant with ASRC Energy Services who leads the effort for BP. "More detailed seismic and well data interpretation within MPU has identified several gas hydrate prospective areas in the northernmost portion of the Eileen Trend." However, he adds, it is still not known how much of the methane is commercially recoverable.

Also in the North Slope, Anadarko Petroleum, with the National Energy Technology Laboratory and other partners, last year completed a project to drill a 2,300-foot well. Though they found some gas and water, the effort yielded no hydrate. It did, however, test a new kind of onshore drilling platform modeled after offshore platforms and meant to minimize the environmental footprint of Arctic drilling.

In late 2003, a consortium of government and private industry from the U.S., Canada, Japan, India, and Germany wrapped up the Mallik 2002 project in Mackenzie Delta in Canada's Northwest Territories. The consortium found natural gas hydrate and successfully tested methane production using both heating and depressurization to dissociate gas from the hydrate.

HEI's Johnson says the flow rates associated from depressurizing the wells--which is thought to have been the means of production in Siberia--may be too slow for commercial viability.

Methods of heating the wells in which steam is produced on the surface and then pumped down the well shaft are problematic, Johnson says, because the steam loses energy on the way. A promising technology, he says, is the down-hole burning, where the heat source is sent down the well itself.

Precision Combustion of North Haven, Conn., has developed a down-hole burner using its catalytic combustion technology. "People have long tried to develop a down-hole burner," the company's president, Kevin Burns, says, but they have not succeeded because the burners haven't been able to put out enough heat.

Precision Combustion's technology is based on platinum group metal catalytic surfaces that allow for controlled burning. It will burn about 15% of the gas that is released from the hydrates, 30-50% less energy use than surface heating technologies, Burns says.

The company has only tested the technology in the lab. Its first commercial test in the field will likely be for heavy oil production, and then the firm expects to move on to testing in a natural gas hydrate well.

Ultimately, the success of methane hydrates will depend on how costly a source of natural gas they are. Johnson estimates the cost at $4.00-$5.00 per thousand cubic feet, lower than today's roughly $9.00 natural gas price in North America. However, gas hydrates will have to compete with liquefied natural gas, which is worth importing when gas is about $4.00.

Johnson, a proponent of hydrates and other alternative fuels such as coal-bed methane, says it would be a shame if North America ended up importing natural gas instead of finding it at home. "To actually plan a future where we, say in 15 years, are importing natural gas like we are importing oil is a defeatist and a very dangerous position to take," he says. "We may end up there, but it is not what I want to do."