In a move to get closer to developing its own domestic fossil fuel, Japan is extracting natural gas from an offshore deposit of methane hydrates. The tests that are set to run until the end of this month mark the first time such production methods have been tested in a deep-sea formation.

Methane hydrates—frozen deposits of the main ingredient in natural gas found in ocean sediments and near permafrost—are thought to be abundant. Worldwide, such deposits contain about 35 percent more gas than other reserves. In Japan, offshore deposits could supply the country with 100 years of natural gas, say researchers.

Experts say the Japanese tests, coming a little over two years after the Fukushima nuclear disaster, demonstrate the country’s commitment to mastering production of gas from the resource, one of its few domestic sources of energy. The state-backed Japan, Oil, Gas and Metals National Corporation (JOGMEC), which is running the test, says there is enough natural gas in the eastern Nankai trough near Japan to displace 11 years of liquefied natural gas imports.

“When you meet scientists in Japan who are working on this, it strikes you that there is a sense of national urgency in developing a domestic hydrocarbon fuel source,” says Carolyn Ruppel, the chief of the Gas Hydrates Project at the United States Geological Survey. She calls the test “hugely significant as a milestone.”

JOGMEC estimates it can commercially extract methane from its offshore resources by 2019. But it’s still not clear that methane hydrates can be tapped economically and in an environmentally safe manner. “No one is going to claim this is an economically viable source of energy. It’s still very much in the research and development phase,” says Ruppel.

Releasing the methane trapped in the lattice-like structures of gas hydrates requires lowering the pressure or increasing the temperature. In their offshore test, Japanese engineers used the depressurization method, where a well is drilled into a formation and water is pumped out. The difference in pressure between the underground deposit and the well causes the methane to break free, says Ray Boswell, the methane hydrates technology manager at the National Energy Technology Laboratory.

Another technique is to inject steam into a well to stimulate the flow of methane, but it requires a significant amount of energy and, on its own, appears to be inefficient. “The depressurization approach seems to be likely to produce at the highest rates, with periodic application of heat. Ultimately, it will be some combination,” Boswell says.

Last week, Boswell and his colleagues presented data from a production test completed last spring where methane flowed for six weeks from a formation below permafrost in the North Slope of Alaska. In this test, done in conjunction with JOGMEC and ConocoPhilips, carbon dioxide was injected into a sandy deposit and exchanged with the methane. Although still experimental, the method could effectively sequester atmospheric carbon dioxide and remove natural gas, a relatively clean-burning fossil fuel. The carbon dioxide also plays a role in “liberating” the methane, but understanding how efficiently and how quickly the reaction occurs needs further study, Boswell says.

Potential environmental hazards are being examined as well. One concern is that removing gas will cause changes in the geology, for example, causing sediments to compact or seafloor topography to change. Part of Japan’s methane hydrate research in the years ahead will involve gathering data on how drilling affects the surrounding environment.

What’s more, methane is a potent greenhouse gas. And just as in conventional natural gas drilling, a broken well can cause the release of the gas. But drilling in a methane hydrate formation can actually be less risky than other forms of gas drilling, Boswell says. The flow of gas, which is trapped in the cage-like hydrates, will stop naturally once pumping stops, he says.

Beyond technical issues, there are a number of economic and logistical barriers. Arctic locations are the most likely to be drilled first because there is already a drilling infrastructure there, say experts. But many locations with gas hydrates, including offshore Japan, lack a natural gas pipeline, says Ruppel. Government-funded researchers will need to perform a test that lasts several months before commercial oil and gas companies will invest money for exploration, she says. But such a demonstration would be expensive.

Still, given the relative high price of natural gas in Japan—this week it hit over $16 per million metric BTU, compared to around $3.50 in the United States—the country has plenty of motivation to make the technology work. “Given the current momentum and significant funding of the Japanese Gas Hydrate program, it is very possible that [Japan] could be first to commercially produce natural gas from hydrates offshore,” says Carolyn Koh, professor at the Colorado School of Mines’ Center for Hydrate Research.