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April 2008

Vol. 13, No. 17 Week of April 27, 2008

Tapping whole new fuel source

Canadian Arctic research team achieves first sustained flow of gas from Mackenzie Delta hydrates

Gary Park

For Petroleum News

It took Alan Greenspan, the former chairman of the U.S. Federal Reserve Board, to inject credibility into what has often been treated as pure science fiction.

“In the more distant future, perhaps a generation or more, there is the potential to develop productive capacity from natural gas hydrates,” he told a Texas conference three years ago, pointing out that the United States alone has an estimated 200 quadrillion — or 200 million billion — cubic feet of hydrates, dwarfing all known global reserves of conventional gas.

But whether the exotic resource can ever become the ultimate answer to world energy needs has been likened to a dream worthy of ancient alchemists.

Known as “ice that burns,” hydrates have grabbed the attention of researchers and industry around the world, with countries such as China, Japan, Korea and India showing special interest as they look for ways to reduce their reliance on energy imports.

Research in Canada

Some of the longest, most detailed research is occurring on Canada’s Mackenzie Delta and Beaufort Sea, a region believed to hold one of the world’s largest concentrations of hydrates.

Serious work has been under way for a decade, culminating in 2002 with the Mallik program, an international joint effort involving scientists from Canada, the U.S., Japan and India, government agencies and industry partners.

The operators drilled one production well and two observation wells into a gas hydrate field on Richards Island which was originally discovered by Imperial Oil in 1970.

The production well recovered about 500 feet of gas hydrate cores, yielding a bundle of detailed information.

The researchers also combined their scientific work on the core samples with production experiments.

Natural Resources Canada, a federal department, noted that “little was known before this project about the technology necessary to produce gas hydrates.”

The experiments included depressurization techniques and thermal heating procedures, resulting in a conclusion that gas hydrates could potentially be produced using either method.

Production technically feasible

The Mallik team said its project established for the first time that “gas production from gas hydrates is technically feasible.”

NRCan also determined that gas hydrate-bearing formations are more permeable than earlier thought, meaning it might be possible to fracture them artificially.

Scott Dallimore, the Geological Survey of Canada scientist in charge of the Mallik program, told reporters three years ago it is “realistic to think that if the market is there along with infrastructure or a local use for gas, hydrates could come on line in 15 years. They have the potential to be a simple add-on to conventional resources.”

But he conceded it will likely be later than 2020 “before we have economic prospects in the offshore,” which has yet to show the same highly-concentrated deposits as the Delta.

Industry commitment key

Jocelyn Grozic, a hydrate researcher and engineering professor at the University of Calgary, is among those who believe commercial production could come a lot sooner if there was an industry commitment.

“If we can recover methane from hydrates, it’s been calculated that this source of energy could provide energy to North America for the next 64,000 years,” she said.

Grozic’s particular interest is learning what happens to surrounding soil and rock formations when hydrate deposits melt and turn into gas, providing better understanding of conditions that may pose problems to offshore drilling rigs.

She said researchers are attempting to develop technology that “can capture this energy in a safe and affordable way. … Before we do anything, we need to know that the gas won’t escape and blow up the side of a well when we try to extract it.”

Sustained flow reported

The Mallik researchers have just reported another breakthrough, claiming to have produced the first constant stream of natural gas from hydrates.

“We were able to sustain flow. … It worked,” Dallimore said.

He said the project demonstrated that “hydrates are responsive enough that you can sustain flow.”

Applying conventional technologies, modifying them, and achieving production is a “big step forward,” Dallimore said.

He said the Mallik well produced for about six days at a lower rate than conventional gas, but roughly equivalent to a coalbed methane well. He is also encouraged by the prospect of hydrates emitting less greenhouse gas than oil or coal.

Dallimore said the next phase is a full-scale pilot project that will embrace commercial production, safety and environmental concerns and issues of how much water and sediment are produced per unit of gas.

But, to date, no Canadian agency has the financial backing to launch the pilot.

Japan tackling deepwater drilling

Meanwhile, a Japanese consortium, motivated by the methane hydrates in the seas around Japan, is tackling the challenges of drilling in deep waters and strong ocean currents as well as figuring out ways to prevent the hydrate samples from melting on the way up, which is a key to commercial production.

The Japanese project is now evaluating resources in selected hydrate fields and is scheduled in the 2012-16 period to develop technologies for commercial production that also mitigate environmental impact.





Alaska gas hydrate research moving slowly

Since 2001 a joint industry, government and university team has been investigating the potential production of natural gas from gas hydrates under Alaska’s central North Slope. These hydrate deposits occur in two major zones known as the Tarn and Eileen trends that lie over parts of the Prudhoe Bay, Milne Point and Kuparuk River oil fields.

BP, ASRC Energy Services, Ryder Scott Co., the U.S. Geological Survey, the U.S Department of Energy, the University of Alaska Fairbanks and the University of Arizona all collaborated in the North Slope project.

Initial phases of the project included an assessment of gas hydrate prospects in the Milne Point area; the modeling of gas hydrate reservoir characteristics and production potential; and the confirmation of the resource potential of the Eileen trend.

Seismic used in locating hydrates

And, in conjunction with a parallel USGS gas hydrate study, the project team developed some techniques for locating subsurface hydrate deposits using seismic data.

In 2005 the project sponsors sanctioned the drilling of a stratigraphic test well. That decision culminated in the 2007 drilling of the Mount Elbert well to a depth of 3,000 feet at Milne Point. BP operated the well, with DOE providing $4.6 million in funding.

The Mount Elbert well proved the effectiveness of the seismic techniques used to locate the gas hydrate deposits and also resulted in the recovery of the first significant gas hydrate core on the North Slope.

Since drilling the well, the project team has been analyzing data and samples from the drilling. The team is using the drilling results and other information to plan what a gas hydrate production test might look like, Rick Baker, methane hydrate team lead in the DOE National Energy Technology Laboratory, told Petroleum News April 24. The team plans to meet with BP in August to seek agreement to move to the next phase of the study, Baker said. That phase might involve some form of production test, depending on the outcome of necessary engineering work.

“It’s at a stage where we’re developing the information for a decision support package,” Baker said.

—Alan Bailey


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