Progress made on methane from hydrates


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Doyon Drilling’s Rig 14 drilled a BP hydrates test in February 2007 at the Milne Point field on the North Slope. The Mt. Elbert well was a joint BP-U.S. Department of Energy project to drill into a hydrate and extract core samples for analysis and testing.

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Government and industry scientists say they are making good progress toward production of methane gas from hydrates, a potentially vast hydrocarbon resource. Methane is the main component of natural gas.

This is still a science project, but knowledge is being gained step-by-step, researchers with the Department of Energy, the U.S. Geological Survey and industry said in interviews with the Journal.

Hydrates are frozen lattice-like structures that form at shallow depths in certain combinations of pressure and temperature offshore or within onshore permafrost areas of the Arctic, including the North Slope. They are capable of holding immense amounts of methane. The question has always been whether methane can be extracted and at rates that are economical to produce.

“It has been only been in the last 10 years, through drilling and coring programs, that we’ve started to get a better understanding of hydrates in their different settings,” said Tim Collett, head of the USGS hydrates program.

This is giving industry more confidence that extracting resources from hydrates might be someday practical, and that it’s not some exotic form of energy, he said.

Some breakthroughs now point toward ways hydrates can be produced. It’s now understood, for example, that the geologic systems that generate conventional petroleum also produce the methane that winds up in hydrates.

“The factors that control the formation of petroleum traps, source rock, migration, a link to sandstone — are all the same as with conventional natural gas,” Collett said. “We know now, for example, that the methane in hydrates in the Prudhoe Bay field leaked out of the Prudhoe and Kuparuk conventional fields, as well as the Ugnu,” heavy oil field.

Another accomplishment, Collett said, is that it has been shown that methane can be produced from hydrates with conventional producing wells and drill rigs.

It has also been demonstrated that production can be done from hydrates in sandstone formations, which is important because sandstone has permeability, allowing the methane to flow.

In contrast, scientists have yet to understand how permeability can be established in the unconsolidated clay and mud formations where most offshore hydrates are commonly found.

Collett said hydrate saturations in sandstones are also typically much greater and therefore more likely to be economically produced than hydrates in the unconsolidated clay and mud.

 

Production tests

The Ignik Sukumi test well drilled and tested by ConocoPhillips on the North Slope in 2011 and 2012 represented the third production test of methane from a hydrate, and the first to feature testing of methane production initiated by chemical injection followed by depressurization, said Ray Boswell. Boswell heads the hydrates program at the U.S. Department of Energy’s National Energy Technology Laboratory.

In addition to ConocoPhillips, The Japan Oil, Gas and Metals National Corp. and the U.S. DOE were partners in the Ignik Sukumi and contributed funds.

The test well produced for about 30 days.

“Production was erratic at first but stabilized in the last 18 days,” which was encouraging, Boswell said.

The previous sustained hydrate production was from the Mallik well in Canada’s MacKenzie Delta, which flowed about 6 days based on direct well depressurization. There were two separate production tests at Mallik done at different times, making Sukumi well the third test. Boswell said the next step should logically be a longer production test of at least 12 months to 18 months.

Prior to the most recent Mallik test in 2007 and 2008, and the Ignik Sukumi well was the BP-operated Mt. Elbert test drilled in 2007 in the Milne Point field on the Notrh Slope. This wasn’t drilled to test production but to extract core samples for testing and to confirm the ability to even find hydrates through existing seismic data.

An attempt to test production from a hydrate in 2003, Anadarko Petroleum Co.’s Hot Ice No. 1, also on the North Slope, failed because the hydrate that had been predicted wound up not being at the location predicted by seismic.

Following that result, industry and the government agencies stepped up development on seismic procedures to better predict hydrates. The 2007 Mt. Elbert well confirmed those worked — the hydrate was where it was supposed to be, and was even thicker than was predicted. This success was demonstrated again at a larger scale in 2009 in a drilling program conducted by a Chevron group, including the DOE and USGS in the Gulf of Mexico.

Gas hydrate-bearing sands were discovered in accordance with predictions in 6 out of the 7 wells drilled, Boswell said.

 

Commercializing hydrates

Figuring out how to produce a hydrate commercially is now the challenge.

Temperature and pressure are both factors in hydrate formation, and an initial thought, tested at the Mallik site in 2002, was that the hydrate could be gradually warmed to allow methane to come out, Collett said.

“We looked first at thermal methods but concluded they would require a great deal of energy — you essentially heat the rock around the hydrate — so that brought us to depressurization, which is now the favored approach,” he said.

Depressurization is fairly straightforward because it can be done by drilling into the hydrate and creating a lower pressure zone in the well, just as in any conventional well, said Boswell. The technique was shown to be workable in the Mallik well in Canada.

One complication is that depressurization also has a cooling effect, creating a “freezeback.” Methane can flow briefly but then it freezes up again, Collett said. A solution to this might be a system to provide limited heat right at the well bore to prevent freezing, he said.

More production testing will allow researchers to do the modeling needed to show the right balance. The goal is to control the thermal exchange and predict the rate of gas flow, Collett said.

Meanwhile, ConocoPhillips and the University of Bergen in Norway have developed a third approach — a methane-CO2 “exchange” mechanism. The idea is to inject carbon dioxide into the hydrate so that the C02 molecules replace — and eject — the methane molecules.

The well is then depressurized to enable the released gas to flow. The technique had been demonstrated in the laboratory but ConocoPhillips had been looking for a place to field-test it and chose the North Slope.

What was intriguing about the exchange concept is that the CO2 molecule appears to be preferred by the hydrate over a methane molecule, said, David Schoderbek, ConocoPhillips’ manager for the Ignik Sukumi test.

“This leads us to believe the carbon dioxide hydrate will be more stable than the methane hydrate,” Schoderbek said.

A site for the Ignik Sukumi well was found in the western part of the Prudhoe Bay field. Several hydrate intervals were found by prior industry drilling but only one was tested, a 30-foot-thick zone at 2,200 feet. The gas mixture injected included nitrogen and CO2.

The project was an operational and scientific success, Boswell said.

“We injected nitrogen and C02 as planned without fracturing the formation,” he said. “On subsequent depressurization, we recovered primarily methane with production being very stable over the final two-plus weeks of the test.”

Over the 30-day test, about 210,000 cubic feet of the CO2 and nitrogen mixture were injected in the two weeks prior to the flowback test, and in the following flowback test nearly 1 million cubic feet of methane mixed with some of the CO2 and nitrogen was produced.

“Most of it was methane,” Schoderbek said. “We are encouraged by results but relative to these numbers it is important to remember that the actual field trial tested both exchange and depressurization.”

Boswell said, “We won’t really know what the (production) mechanism was until our analysis is complete — how much of production was due to the exchange and how much from other factors. It’s encouraging but we’re still unsure just what process took place, an exchange or something else. Not all the CO2 came back, so it is likely that there was some exchange.”

An initial analysis won’t be available until the end of the year or early spring, he said.

The C02 exchange has possible advantages over depressurization. One is that it could preserve the hydrate structure, where depressurization essentially dissolves the hydrate. This has implications for preventing surface subsidence where hydrates are shallow, as they are on the North Slope.

Also, exchanging CO2 for methane in the hydrate provides a place to potentially sequester C02. That could be important on the North Slope because the known Prudhoe Bay and Point Thomson conventional gas accumulations contain C02, which must be disposed of when commercial gas production begins.

If Arctic hydrates are to be tested further the work is best done on the Alaska North Slope because of the presence of infrastructure. The Ignik Sukumi and Mt. Elbert wells were both drilled on temporary ice pads but near the all-year road systems and support facilities of the oil fields.

Further testing on temporary pads is still an option the next steps will need a place with year-around access.

 

Whole lot of hydrates

Hydrates are spread widely across the Arctic in permafrost regions, which cover vast onshore areas of Alaska, Canada’s Mackenzie Delta and Arctic Islands, and Russia.

Where there are sedimentary basins, hydrocarbon source rocks and conventional oil and gas reservoirs overlain by permafrost, it’s likely that methane escaping from the conventional traps will accumulate in hydrates just below or within the permafrost, Collett said.

Hydrates are found offshore on continental shelves. Although the majority of marine hydrate is found at low saturations in the unconsolidated clay and muds, substantial deposits have been discovered offshore Japan, where initial offshore production testing is expected to begin next year, and in the Gulf of Mexico during the 2009 drilling program.

Collett said the understanding gained of the North Slope hydrates from the 2007 test was key to enabling the USGS to make its first assessment of technically-recoverable methane from hydrates in 2008. That assessment indicated 85.4 trillion cubic feet across the North Slope.

Despite the potential, North American markets are saturated with inexpensive shale gas, which dampens the enthusiasm for U.S. producers to tackle a future source of unconventional gas, Collett said.

Given that, Japan, South Korea and India, may lead the next steps with hydrates. Those countries lack domestic oil and gas and are therefore more motivated, he said. DOE and the U.S. Geological Survey hope to stay engaged. It’s probable that at least one North Slope producer would be involved if further tests are done on the Slope, however.

 

Tim Bradner can be reached at tim.bradner@alaskajournal.com.

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