Is Methane Hydrate the Energy Source of the Future?

Shale has the spotlight for now. But there's another, lesser-known substance with the potential to yield even greater quantities of natural gas: methane hydrate.

Hydrates consist of a lattice-like structure of frozen water molecules and methane. On the surface, they look like an ordinary block of ice. But when you hold a match to them, they burn—a visual cue signaling methane release.

"A lot of geoscientists are fascinated by hydrates because of how odd it is that you can take methane gas and add water and have it result in something with such a concentrated store of energy," said Peter Flemings, a member of the Energy Department's methane hydrate advisory committee and professor at the department of geological sciences at the University of Texas (Austin).

Hydrates form when methane and water combine under cold temperatures in a relatively high-pressure environment and are commonly found in arctic regions or in shallow sediments below relatively deep water along the outer continental shelf.

The Energy Information Administration estimates that hydrates contain more carbon than every fossil fuel available on Earth combined. EIA also reports that these ice-like structures could hold anywhere from 10,000 trillion to more than 100,000 trillion cubic feet of natural gas. By way of comparison, the administration, which acts as the independent statistical arm of the Energy Department, said in 2013 that there are just over 7,000 trillion cubic feet of technically recoverable shale gas deposits throughout the world.

All this potential isn't lost on the administration. DOE has been conducting research into methane hydrates on and off since the 1980s and recently re-upped its commitment to understanding the substance with an announcement last month that it plans to pour close to $5 million into funding for research projects exploring the potential energy source and how it could be extracted.

"We know that methane hydrates hold vast potential as a future energy resource," said Ray Boswell, the program manager on methane hydrates for the department's National Energy Technology Lab, said. "We've gotten past the question of does this substance really exist and is it available, and now we're really working to figure out how much of it is in a condition to where we can realistically consider it a part of our future energy reserve, and we're working towards that."

When asked if methane hydrates stand to play a role in the president's all-of-the-above energy strategy, Boswell replied: "Yes, absolutely."

There are risks inherent in the extraction of natural gas from hydrates, however.

Since hydrates are typically found in shallower regions than shale gas deposits, one concern is that drilling into the substance could trigger ground surface collapse.

"If you drill a hole five feet down and remove a large amount of material, there are more odds of the ground caving in than you would have if you drill 10,000 feet down," Flemings said.

Another frequently cited concern is that methane, a powerful greenhouse gas, could leak out during extraction.

Boswell insists, however, that the potential for unintended methane gas release is no higher with methane hydrates than with shale rock formations.

"That's a common misconception," he commented. "But the risks associated with hydrates are very similar to the risks that are dealt with and managed every day by the oil and gas industry in the process of drilling for natural gas in shale."

Don't expect natural gas production from hydrates to get off the ground in the U.S. anytime soon, however. As long as shale gas remains so readily available, there is no real incentive to commercialize the technology.

"At the end of the day, producing natural gas from hydrates is still much more expensive than shale gas or other conventional methods," Flemings said.

But the costs incurred to extract shale gas have dropped dramatically over the past decade, and so, too, could the price of technology needed to grab gas from methane hydrates. If that day comes, a tidal wave of fossil fuels will flood the American energy landscape.

click map for enlarged view

Natural gas hydrate occurs worldwide in oceanic sediment of continental and insular slopes and rises of active and passive margins, in deep-water sediment of inland lakes and seas, and in polar sediment on both continents and continental shelves. In aquatic sediment, where water depths exceed about 300 m and bottom water temperatures approach 0° C, gas hydrate is found at the seafloor to sediment depths of about 1100 m. In polar continental regions, gas hydrate can be present in sediment at depths between about 150 and 2000 m. Thus, natural gas hydrate is restricted to the shallow geosphere where its presence affects the physical and chemical properties of near-surface sediment.

This updated global inventory reports on natural gas hydrate recovered from 44 regions worldwide and includes 113 regions where the presence of gas hydrate has been inferred from geophysical, geochemical, and geological evidence. The potential amount of methane in natural gas hydrate is enormous, with current estimates converging around about 10 exagrams (10,000 gigatons) of methane carbon. This large reservoir of methane, located globally within 2000 m of the solid surface, is of major interest as a potential:

energy resource,
factor in global climate change, and
geohazard.

A Global Inventory of Natural Gas Hydrate Occurrence
U.S. Geological Survey
http://walrus.wr.usgs.gov/globalhydrate/

http://www.netl.doe.gov/technologies/oil-gas/FutureSupply/MethaneHydrates/projects/DOEProjects/MH_42496ScientificStudies.html

Accomplishments

Task 1 – Characterization and Assessment of Natural Gas Hydrates in Permafrost Environments
This task addressed the critical issues associated with potential production of gas hydrates (and associated free gas) in the Prudhoe-Kuparuk area of the Alaska North Slope. The primary focus was to assess the geophysical characteristics of in situ natural gas hydrates and to support U.S. DOE-funded extended gas hydrate production tests of the Eileen and Tarn gas-hydrate/free-gas accumulations.

USGS worked directly with BPXA and their contractors to design and implement the North Slope of Alaska Mt. Elbert 1 Gas Hydrate Test Well, which was spudded on February 3, 2007.

The USGS coordinated the efforts of BPXA and the U.S. DOE at Milne Point, Alaska, and participated in wellsite wireline coring, well logging, and sampling/pressure testing using a modular formation dynamics tester (MDT) during the 22-day drilling program. The project cored to a depth of 760 meters, logged to a depth of 914 meters, and tested for gas hydrate response at four depth intervals using MDT. From the coring program, there was 85% recovery, with approximately 250 samples selected for laboratory analyses and 11 gas-hydrate samples preserved in either liquid nitrogen or pressure vessels for analysis.

The major scientific achievement at this site is that two high-saturation gas hydrate-bearing intervals were identified, as predicted from pre-drilling geological and geophysical analysis using prospecting methods developed by the USGS. The two units were an upper 14-m thick gas hydrate-bearing reservoir of sandstone (unit “D”) and a lower 16 m thick unit, also a reservoir. Both units had gas hydrate saturations of 60–75%. Two technological firsts were also achieved: (1) conducting wireline retrievable coring in the relatively unconsolidated sub-permafrost sediments in the North Slope and (2) conducting open-hole MDT testing within gas hydrate-bearing intervals. For more information see the BP Exploration Alaska project, “Alaska North Slope Gas Hydrate Reservoir Characterization” (DE-FC26-01NT41332).

The wireline logging produced an outstanding dataset of permafrost and gas hydrate properties. The open-hole MDT testing also produced an outstanding dataset of gas hydrate response during testing. Research is now being conducted to analyze the physical formation properties of the Mt. Elbert samples and to compare the detailed drilling results with pre-drilling models so that the models can be refined and improved. A Mt. Elbert data set was also developed as a case study to be utilized in the DOE-funded “International Effort to Compare Methane Hydrate Reservoir Simulators”.

Using calibration data from the Mt. Elbert gas hydrate stratigraphic test well, the USGS has reprocessed and inverted 3-D seismic data to further refine the limits of the Milne Point Units C and D gas hydrate occurrences. This effort has resulted in the generation of an updated time-depth model, a structural map, a hydrate saturation map, and hydrate reservoir thickness maps for Mt. Elbert prospect. The USGS continues to participate in project meetings focused on detailed planning for the future Alaska North Slope long-term gas hydrate production testing program under a new IA, DE-FE0002911. USGS efforts also included developing and editing papers prepared for the North Slope of Alaska Mount Elbert Gas Hydrate Stratigraphic Test Well Scientific Results Volume, to be published as a special edition of Marine and Petroleum Geology. USGS scientists made a major commitment to this special volume by authoring and/or coauthoring over half of the 25 papers included in this publication.

USGS scientists provided technical and scientific support for the ConocoPhillips (CP) project by contributing to the development of the coring and logging research plan for the upcoming “CO2 gas hydrate production test well.” The USGS contributions included providing required geologic data from our historical work in northern Alaska, and providing expert knowledge on well logging, conventional coring, pressure coring, seismic characterization, sediment physical properties, organic geochemistry, and process modeling.

With the Bureau of Land Management, the USGS processed and analyzed 3-D seismic grids and related 2-D seismic and well data from the National Petroleum Reserve-Alaska (NPRA) in order to identify gas hydrate prospects. This research focused on gathering existing geologic and geophysical data to construct a new gas hydrate stability map for the eastern portion of the NPRA. The research resulted in a new North Slope Alaska gas stability field map as interpreted from the USGS “Borehole Temperature Logs from Arctic Alaska”. These data have been released on the following web site, http://esp.cr.usgs.gov/data/bht/alaska/ [external site].

In a related effort, in collaboration with the Bureau of Land Management, the USGS completed the first assessment of undiscovered technically recoverable gas hydrate resources beneath the North Slope of Alaska. For the Northern Alaska Gas Hydrate Total Petroleum System, the USGS estimated that the total undiscovered natural gas resources in gas hydrate are about 85 trillion cubic feet (TCF). More information can be found at http://pubs.usgs.gov/fs/2008/3073/ [external site].

Ummm... it’s in the water. So how does drilling cause “ground surface collapse”?

What a dip-wad! (the author)

Sometimes peoples leg-bone just ain’t connected to their brain-bone!

The author might have written it better. But the ground, (Ocean Floor), has more of a chance of collapsing with the weight of the water on top as the Hydrates are removed.

Which has its own measure of risk, imagine a Methane Ice breakthrough rising to the surface of the surrounding water. The potential there for methane poisoning of the water is pretty high and the release of the sublimating ‘ice’ into methane gas into the atmosphere is there too.

Once all of these risks and potential hazards are worked around there is a lot of energy available as well as ‘feed-stock’ for various industries that can use it to produce other goods and materials.

It looks like a cube of ice burning.

Yes, for the lab demonstration and pictures that capture attention, the sample is kept cold enough to keep the water in ice form. The methane is trapped inside like shown below.

In this form, there is a lot more water than methane. The pilot projects attempted to find a economic production methods try to release the methane from the ice while still in place. It is far easier (cheaper) to handle gas in pipes like traditions natural gas production. Also far less material is moved and brought to the surface.

It doesn’t have to thaw to release the gas, just disturbing it, changing the pressure, can cause it to release “part” of the gas.

In warmer conditions, such as the ocean floor, it is true that sufficient depressurization will thaw the ice releasing the gas. Japan did that the second time, after warming the first time. Remember that steam, water, ice are functions of pressure as well as temperature. Both control the physical form of H₂O

The only way "disturbing" it can sufficiently release the gas is if the material was already at the temperature/pressure line where it was ready to change state with little more energy.

BP's work in the arctic under the land on the North Slope required warming. It is too cold there for depressurization to work alone.

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