Ice to Burn

Up Here Business October 2008

Quickly now: what are the planet’s largest known reserves of hydrocarbon? If you said oil, natural gas or coal you’re way out. Add all of those together and you’re still not there. The answer is gas (or methane) hydrates – near-pure methane gas locked up in cages of ice molecules under unique conditions of high pressure and low temperature.

Found primarily in sub-permafrost sediments and offshore continental shelves, the extent of the world’s hydrate deposits isn’t really known yet. The best known are the Alaskan North Slope, Mackenzie Delta, Siberia, and offshore areas of Japan, South Korea, China, India and the Gulf of Mexico. The U.S. Geological Survey estimates U.S. domestic volumes at 200,000 trillion cubic feet. Natural Resources Canada figures our potential could be 29,000 tcf. Put that into perspective by considering that all the known conventional gas reserves remaining in the Western Canadian Sedimentary Basin come in under a relatively paltry 60 tcf.

Just a few short decades ago, hydrates were nothing but a nuisance. They’d form in, and plug, wellbores and gas pipelines. But as a massive and clean-burning energy resource they’re rapidly looming large on the radar. At this year’s Offshore Technology Conference in Houston, four full sessions were devoted to gas hydrates.

Ubiquitous as they are, production is the challenge – although in theory it sounds simple. Because hydrates need high pressures and low temperatures to maintain their state, either decreasing pressure or increasing temperature will coax the methane to dissociate from its icy host.

In the 1930s, and as late as 1972, it was determined from cores taken in Alaska that production would be uneconomic at those times. It wasn’t until 1998 that serious international research towards eventual commercial production started and that research took place right here in North – in the Mackenzie Delta with a well at the rich Mallik gas hydrate field near the town of Inuvik, NWT. Mallik was ideal. Discovered by Imperial Oil in 1971-72 it boasts a 110-metre zone of highly concentrated hydrates. The Geological Survey of Canada estimates the Mackenzie Delta-Beaufort Sea region may contain 564 tcf of hydrates; a 1995 GSC study revealed 17% of onshore Mackenzie Delta wells and 63% of Beaufort Sea wells contained hydrates.

Japan, an energy-poor country, took a major interest and participation. Shortly after the Mallik well, a Japanese consortium drilled into an offshore hydrate formation in the Nankai Trough, one kilometre below Japanese waters. It was as encouraging as Mallik, with hydrate concentrations up to 80 per cent in confined sandstone reservoirs – features drillers like.

It was clearly time to keep up the momentum. U.S., Canadian, German, Indian and Japanese researchers converged on Mallik for a second big drilling session, a $25-million program in the winter of 2001-2002. This time they’d drill a production research well and two scientific observation wells. A prime objective was, which is better to stimulate hydrates production – depressurization or hot fluid circulation? Both were tried. Gas-bearing cores and reams of acquired data did reveal initially that either method was feasible but more analysis was needed. Meanwhile, Japan returned to its Nankai drilling program with 15 successful wells.

By winter 2006-2007, after several conferences and scientific papers, the newest phase in hydrates research cranked up again in the Mackenzie Delta. Analyses and extensive numerical modeling together with better knowledge of hydrate formation geologies had shown that depressurization was the production technique of choice. The time had come to undertake an extended production test with it.

With Inuvik’s Aurora College as the operator and Inuvialuit Oilfield Services the project managers, Japan and Natural Resources Canada got the new project underway. The 1998 well was reopened and modified for the new test. “Our goal was to carry out a short production test to gain some practical experience with various engineering aspects and collect some basic scientific information with an advanced well logging and monitoring program,” says Scott Dallimore, a research scientist with the Geological Survey of Canada and the lead Canadian scientist for the Mallik program.

There were some initial setbacks. After setting a submersible pump near the bottom of the hydrate zone to depressurize the formation by dropping the well’s water level, sand flowed into the borehole, which hindered the pump’s operation. Nevertheless, good volumes of gas were produced for several hours – the world’s first gas production by the depressurization of natural gas hydrate in a geological formation. But to be convincing, a production test needs to demonstrate more than a few hours’ flow. Dallimore says much was learned about the formation’s response, but some technical challenges remained. So, “in the fall of 2007 we went back to the drawing board and we went to the field in January with a much simpler plan and a great deal more experience,” he says

The goal of that winter’s field activities was to undertake longer term gas hydrate production testing after figuring out ways of preventing the sand accumulation and other technical problems encountered in early 2007. Special sand control devices were installed downhole and the pump ran continuously for six days in March.

There were a few surprises at first. “One was just prior to testing when the initial reaction of the gas hydrate was so vigorous we had to close our blowout preventer and cut our downhole cables,” Dallimore says. But stable gas flow was soon established and measured at the surface with a sustained flare of the hydrate dissociated gas lighting up the Arctic sky. Dallimore says that was his highlight of the season. “There was great relief that we actually had got the job done and excitement with the flow rates,” he says.

But as good as the results from the 2007 drill program had been, the 2008 Mallik production test was a world milestone. The six-day test confirmed for the first time that continuous gas flow ranging from 2,000 to 4,000 cubic metres per day could be sustained from a gas hydrate formation. Dallimore says there are still scads of data to analyze but they’ve established that depressurization is the correct approach to unlock hydrates from their hosts.

The test also corroborated to a large extent numerical modeling of gas hydrates production undertaken earlier. “No matter where you are – oceans or Arctic – if depressurization does not work for you, forget it,” says University of California scientist George Moridis. A hydrates specialist, Moridis completed extensive and complex numerical simulations for the first hydrates production tests and says the problem with using heat circulation is the energy losses. “You waste about 90 per cent of it so only 10 per cent is available to raise the temperature of the hydrate and its porous medium,” he says.

Dallimore says the gas rate prediction by the gas hydrate reservoir simulation matches well with their observed values and will contribute to the development of more sophisticated production techniques. “We have also taken great care to publish all of our results with more than 100 technical papers,” he says. “Modelers, engineers and scientists can turn to Mallik as perhaps the best documented gas hydrate site in the world.”

While proof of concept has been established for the types of gas hydrate formations seen under 700 metres of permafrost, different considerations are in order for offshore hydrate production such as that being pursued by Japan in the Nankai Trough. Structures can be radically different.

“Hydrates of reservoir quality are found in sandy soils or gravels – high permeability, high porosity soils,” explains Moridis. “If these are not highly compressed then the hydrate itself doesn’t give strength to the geological medium. As you destroy the hydrate to produce gas that strength goes away.” Which can lead to collapse of the well or, worse, the undersea formation. “Because what’s happening is you’re transferring more and more stresses from the hydrates to the grains of the medium,” he says. A catastrophic collapse could mean release of massive volumes of methane gas – a potent greenhouse gas. Moridis says these problems aren’t insurmountable but have to be accounted for in the design. Already several academic papers have reported on seafloor subsidence in conventional offshore drilling that may have been triggered by gas hydrate dissociation, suggesting precautionary measures. Since methane hydrate is up to 30 times more powerful than CO2 as a greenhouse gas a massive uncontrolled release could dangerously accelerate global warming.

Moreover, Moridis says all offshore hydrate deposits aren’t alike. Offshore India is one example. “What you see there is instead of hydrates between the grains of the porous medium, which is what we want in most cases, you have veins or seeps extruding in very soft muddy sediments,” he says. These present fresh difficulties when it comes to production design. “Once you take out the hydrates, which are 20 per cent of the system, you leave a void and there is a collapse.” He says this can make production, at least with present technology, expensive. “With today’s best technology we can handle production where subsidence is less than 5 per cent,” he says. “Or in extreme cases 7 per cent. So in the muddy sediments where subsidence is 20 or higher we’re talking a different situation.”

Despite some of the challenges and uncertainties about hydrates, the race is already on to bring them to market. With Nankai’s stronger undersea geology, Japan has stated its intention to begin producing gas from offshore hydrates commercially by 2016. But Dallimore believes that first commercial production of gas hydrates will take place in the Arctic, but only “if a gas pipeline is completed to the Mackenzie Delta or northern Alaska.”

Moridis agrees. “In terms of technical feasibility the Arctic appears to be the first place it would happen,” he says. But again there’s the Northern pipeline caveat. “The chances are that the first production will be from the Nankai Trough offshore Japan,” he concedes. “Money has been allocated, platforms have been installed. They’ve already drilled 36 wells, they know what’s happening and chances are by 2016 they will be producing commercial quantities.”

But that wouldn’t leave Canada out of the picture. “What is going to be the long term future of unconventional gas in Canada?” asks Mike Dawson, president of the Canadian Society for Unconventional Gas. “I think it has to be hydrates.” Dawson says if there were transport mechanisms, or even liquefied natural gas facilities, the resource is easily accessible at the present time. “There is existing technology that we apply to our conventional and unconventional oil and gas. Much of it is applicable to hydrates production in today’s known deposits. To actually get producing gas from hydrates is technologically feasible right now.” And, he adds, in the long run hydrate gas in the Arctic could easily be competitive with Beaufort Sea gas.

Northern businesses have had a small taste already. Ninety-four percent of last winter’s $18.2-million Mallik project spending reportedly went to Inuvialuit businesses like Aurora Expediting Services, Polar Oilfield Services and Akita Equtak Drilling.

Another Northern-concentrated firm, Calgary-based MGM Energy Corp, already has hydrates production in its sights. “My view of hydrates, from the time I was director of research with a major Northern oil company, was that in the long haul, hydrates could be the natural gas version of oil sands,” says Gary Bunio, MGM’s vice-president of operations. “There is that much potential. And in fact it’s a more environmentally friendly fuel so it has even longer potential.”

It’s not all talk with MGM, either. Bunio says the bulk of its Northern lands have large hydrate deposits. “In particular the land around our Umiak gas discovery (located in the Mackenzie Delta) has tremendous gas hydrate potential. It only makes sense for us to start working on hydrates now, so that once we’ve produced the easier gas we can take the same wells and move up-hole and then use those same wells. If we’ve done our technology correctly, we can produce the hydrates above and get more resource and more production as we go through. We’re not a very big company but we’re trying to work our way through how in the long haul we’d be able to capture this resource.”

And Bunio reckons if gas prices stay the way they are and world natural gas demand stays the way it is, hydrates will become the fuel of the future. “It makes the most sense for people like us. If you’re going to be in the natural gas business anywhere in the world, in 40 or 50 years you’re going to be producing gas hydrates.”


Sidebar:

The Hydrates X-Files

Think Fox Mulder (pictured) has some wacky theories? Check out what some people think gas hydrates have been responsible for.


The loss of Flight 19 (and other Bermuda Triangle mysteries)
The loss of five US Navy Avenger torpedo bombers in December 1945 is, arguably, the most famous incident to occur in the notorious Bermuda Triangle off the southeast coast of Florida. The planes took off from Fort Lauderdale on a routine training flight over the Atlantic and never returned. A Mariner flying boat sent to search for them also strangely disappeared. No official cause was ever found, but numerous wacky theories have sprung up to explain their disappearance – aliens, electronic fog, giant waves, even citizens of lost Atlantis.

Another explanation for the planes’ and some other ships’ disappearances in the Triangle has been bubbles of seafloor methane hydrates. Freed from undersea deposits by seismic action, the methane reduced the water’s buoyancy immediately sinking any ship in the right place at the wrong time – with no time to call for help. It has been theorized that methane’s effect on airplanes would be quick too: depriving an engine of oxygen or causing them to explode from red-hot engine exhaust.

The extinction of the mammoth
Methane hydrates have even been blamed for the extinction of megafauna like mammoths and giant ground sloths 10,000 years ago – often attributed to overhunting by early Clovis populations. An independent research paper presented at Indiana University Southeast in 2007 espoused a hypothesis linking climate change to massive releases of methane hydrates off the Norwegian and Amazon coasts, inducing major changes in ocean circulation and precipitation patterns wiping out the animals’ natural food sources. Research on this theory continues.



 
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