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Detecting Marine Gas Hydrates
Naomi Lubick

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Mining for tomorrow


Policy-makers and geoscientists alike have hopes for gas hydrates as a new source of energy, but exactly how much of the icy substance exists remains contentious (see story). Part of the problem is that methods to image them in deepwater deposits around the world have had varied and sometimes limited success. To better find large enough deposits to extract, in addition to resolving issues of safety and climate effects (see story), scientists are working to improve seismic profiling techniques and other tools for better mapping of gas hydrates.

In 2001, researchers using the submersible Alvin photographed hydrate forming under a rock overhang near Blake Ridge, offshore of Georgia, at a site where the Ocean Drilling Project drilled in 1995. Image courtesy of Woods Hole Oceanographic Institution.

“Even drilling doesn’t tell you how much is there,” says Roy Hyndman, a senior research scientist at the Geological Survey of Canada, in Sydney, British Columbia. And often, “it’s gone before you get it to the surface.” Hyndman says that “the future in mapping is to try to establish the concentrations and amounts. We know that very poorly, much more so than people appreciate.” He says that estimates from seismic profiles — the typical method for detecting gas hydrates — often can be off by a factor of 10.

Gas concentrations of several percent in sediment layers could be enough to get an indication of their presence using seismic profiles, says Emrys Jones, the manager of the ChevronTexaco Joint Industry Project in the Gulf of Mexico. Seismic arrays are composed of a sound source, such as air guns (usually a dozen or more of them), and moving or stationary receivers; the reflected sound waves provide a 2-D portrait of a slice through Earth’s surface. The sound waves travel through the water column and back as compression or P waves, representing the vertical motion of materials as the waves pass.

The velocity of seismic waves translates to the consistency of the sediments, says Matt Hornbach, a Ph.D. candidate at the University of Wyoming at Laramie. Through looser sediments, such as mud, compression waves travel at a maximum of 1,500 to 1,700 meters per second. That’s slow, Hornbach says, particularly in comparison to sound traveling through pure gas hydrate, at 3,000 to 3,600 meters per second.

“When sediment has hydrate in it, it freezes and becomes a more rigid material,” says Nathan Bangs, a senior researcher at the Institute for Geophysics at the University of Texas, Austin. If it occurs in veins or in the pore spaces of sediments, “it’s sort of like a cement,” he says, which also makes the material more rigid and speeds up seismic wave velocities.

Hornbach, with his advisor Steve Holbrook and co-workers, recently studied Blake Ridge, offshore of Georgia. Using a variety of sensors, digital reprocessing of the seismic data and a high density of 2-D profiles, they created a 3-D model of the velocities of the sediments there, like those used in both industry and academia for studying gas and oil reservoirs. They found the traditional signature for gas hydrates in their seismic profile, which is called a bottom-simulating reflector, generally referred to as a BSR. The reflecting layer roughly parallels the seafloor and marks a transition in the velocity of reflected sound waves as they pass though icy gas hydrates to sediments below that contain “free” gas.

Jones of ChevronTexaco says that “it turns out that a bottom-simulating reflector is neither necessary nor an indicator of a hydrate layer.” The Ocean Drilling Program on Blake Ridge confirmed that gas hydrates could exist where bottom-simulating reflectors were not detected (gas hydrates were spread out in the area; results from a second drilling leg at Hydrate Ridge, offshore of Oregon, are still forthcoming). In the Gulf of Mexico, for example, fluid flow (brine formed near salt domes) and varying heat flows may have disrupted any evidence of a bottom-simulating reflector, Jones says.

So far, seismic surveys of the Gulf of Mexico have given no indication of substantial layers of gas hydrates. “But we haven’t been looking for them,” Jones says. “There may be; we don’t know.” Upcoming drilling in the region should confirm it either way (see sidebar from feature story).

Still, seismic indicators remain the most important for future exploration, and the key may be shear or S waves, researchers say. Shear waves have different vector components of horizontal movement, and are converted from compressional waves passing through gas hydrate zones. Although models have focused on compression waves in order to draw out regions of interest, Jones notes that “industry can go back into the data and reanalyze it,” looking for shear wave velocities.

“More researchers are using techniques that can directly measure shear wave characteristics in gas hydrate zones,” says Carolyn Ruppel, a geophysicist at Georgia Tech in Atlanta. Because compression and shear waves deform materials differently, “these differences can be exploited to learn more about the amount and distribution of gas hydrate.”

With her co-worker Carlos Santamarina, a civil engineering professor, and others, Ruppel has studied synthetic gas hydrates in the lab to measure a variety of properties in different sediments and pressures. The researchers have found that both the pressure and the amount of gas hydrate affect measured compression and shear wave velocities. At depth, Ruppel notes that “shear wave velocities are far more sensitive than compressional velocities to the concentration and distribution of gas hydrate.” She also says that at natural concentrations, “it may remain pretty hard to detect the presence of gas hydrate with conventional seismic methods or to determine exactly how the gas hydrate is distributed in the sediments.”

Researchers say that one solution for detecting shear waves and getting higher resolution is to use multicomponent systems, with a variety of receivers. For example, Bangs points to experiments with seismometers sitting on the seafloor and in boreholes to better measure shear waves. And a Naval Research Laboratory experiment has placed both source and receiver at or near the ocean bottom, which increases the imaging resolution. Ocean-bottom cables with a variety of instruments “can collect multicomponent data over a broad area,” Bangs says. “That may be the best way to study hydrates,” though the current cost — of millions of dollars — makes it rare for now.

Another technique uses the variations in velocities from sound sources and receivers in different positions. This “amplitude-versus-offset” method is relatively new for studying gas hydrates, according to Hyndman, who compares it to skipping rocks over water at different angles: The rocks bounce at shallow angles but sink if dropped vertically, much like sound waves will pass through materials at one angle but reflect at others.

Signal frequencies are also important, says Hyndman, who notes that industry systems are usually considered to be low frequency in order to “penetrate quite deeply,” to oil and gas reservoirs past the depths where gas hydrates are stable. But higher frequencies give better spatial resolution, he says, for “seeing” layers and velocities more clearly in shallow sediments. Higher frequency “also resolves the geological structure that contains the hydrate,” Hyndman says, revealing “mainly the deformation, the folding and faulting in the sediments that channel this methane gas, which then deposits this hydrate.”

Hyndman names at least two other promising experimental methods that do not incorporate seismic techniques. Sensitive gravimeters can track how much the seafloor moves with changing water weight from moving waves: A seafloor frozen with gas hydrates would not depress as much.

Another method uses electromagnetic measurements along the seafloor, “rather like prospecting for minerals on land,” he says. “On land, we’re usually looking for something electrically conducting — metallic or ore. With gas hydrates, we’re looking for something that does not conduct.” Ruppel says that the electromagnetic method has promise but “limited applicability,” mostly for use in areas where gas hydrates are present in shallow sediments.

In general, researchers in academia and industry are focused on improving seismic detection, which remains costly, to see if gas hydrate predictions match what is actually there. In addition to cruise and equipment costs for collecting data, the computing power and disk space needed for processing is quite large, Hornbach says. However, in the past three years those computing costs have decreased as the terabytes necessary for 3-D modeling become cheaper.

Nevertheless, so far, “in most places we’ve looked, there’s not much hydrate relative to the amount of sediments there,” Bangs says. “I suspect that there’s a lot of forms that hydrate can occur in. It’s hard to look at one area and say ‘this is typical’ until we’ve studied more.”

Mining for tomorrow

The future is a long way off when it comes to prospects for mining and producing gas hydrates from marine sediments. Although some land-based recovery operations have had success, marine sites will remain difficult, if not technologically surreal.

Marine gas hydrates could clog choke lines that deliver lubricant to drillheads, or freeze pipes and blowout preventers, and cause a variety of other problems, should they be mined with traditional drill-well technology. Any solutions, at this point, remain futuristic. Image courtesy of Maurer Technology.


“Mining is definitely way off into the future,” says George Moridis of Lawrence Berkeley National Lab in Berkeley, Calif. Moridis notes success in permafrost regions such as the Mallik site in the Arctic, where gas hydrates have been successfully heated or depressurized in order to capture the natural gas trapped in the icy structures (see story, "Fire in Ice"). In water, “the basic approach up to now [would be] to use conventional technology,” he says. But “the deeper you are, the more expensive it is and more difficult it is.”

Like conventional drilling for oil and gas in ocean settings, future drilling for marine gas hydrates might involve a platform or riser, or even a drill ship, that sinks a drill pipe into the seafloor. The drill head would be lubricated by a heavy fluid, as in normal drilling, but to make sure that the heat of drilling does not dissociate gas hydrates — which come apart with increases in temperature or decreases in pressure — cool water could be pumped in from the ocean water column, from an insulated pipe.

In projects that core hydrates, such as legs of the Ocean Drilling Program in the Pacific Northwest, and in Japanese drilling projects already under way, researchers do not use risers partly because blowouts are a distinct possibility. Working without a riser leaves room for escaping gas, according to Tom Williams, vice president of the geophysical engineering group Maurer Technology. In the right conditions, gas from hydrates can be compressed more than 600 times what it would be normally, “so you can imagine how [the] gas would expand as it travels up a riser,” he says. “This could be a major blowout — not unlike a rocket headed straight up the riser toward the drill ship” (see sidebar [in print only], page 21).

Even on land or in traditional marine drilling without the presence of gas hydrates, such blowouts are still a concern. But if a submarine deposit were destabilized, and the gas hydrate layer was acting as a cap for a free-gas layer below, the consequences could be a huge gas bubble traveling up through the water column, Moridis says. But he notes that marine hydrates might also be somewhat easier to produce because of the incremental inhibiting benefits of salt.

A more futuristic scenario for gas hydrate mining envisions production almost at the source, using a drilling rig firmly anchored on the seafloor, perhaps operated remotely by a ship above. Future gas hydrate miners could “theoretically bring it up in the same form as it is so it doesn’t turn to gas and expand,” Williams says. But the technology to transport gas hydrates from seafloor to sea surface remains unimagined at the moment.

Some scientists remain skeptical that deepwater hydrates will be mineable at a large scale. “Most gas hydrates are finely dispersed in sediments and will never be recoverable economically,” says Alexei Milkov of BP, who cites significantly lower amounts of marine gas hydrate than others (see story). However, profitable recovery of localized highly-concentrated gas hydrate accumulations is possible, he adds.

Practically speaking, Williams says, “we really need to get a better understanding of the resource before we decide how to mine it.”

NL

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Lubick is a staff writer for Geotimes.

Links:
"Gas Hydrates as a Future Energy Resource," Geotimes, November 2004
"Methane Hydrate and Abrupt Climate Change," Geotimes, November 2004
Sidebar: "U.S. projects under way," Geotimes, November 2004
"
Fire in Ice: What Are Gas Hydrates?," Geotimes, November 2004

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