Researchers still working to unlock hydrates
An image of gas hydrates burning is seen in this U.S. Geological Survey photo. Gas hydrates are naturally-occurring “ice-like” combinations of natural gas and water that have the potential to provide an immense resource of natural gas from the world’s oceans and polar regions.
Photo/Courtesy/US Geological Survey
Step by step, scientists in the U.S. and Japan are finding ways methane might be commercially produced from hydrates, the ice-type structures that exist onshore and offshore in certain environments and hold immense amounts of methane.
Methane is the main component of natural gas.
Marine methane hydrates exist along the continental shelves of many nations, including the U.S., and onshore in the Arctic where they are locked within, but primarily below permafrost that overlies petroleum-producing geologic systems across large areas of northern Alaska and Canada, and no doubt the Russian Arctic.
The estimates of technically recoverable resources of methane from hydrates are staggering, as much as 43,000 trillion cubic feet, or tcf, worldwide, but whether the methane can be commercially produced from a hydrate is still a big question.
Some compare this, however, to the early days of shale and tight gas research, where research and technology breakthroughs ultimately led to a booming new industry.
The U.S. Department of Energy’s National Energy Technology Laboratory and the U.S. Geological Survey are the U.S. agencies most engaged in the hydrates work. The Japanese partner has been the Japan Oil, Gas, Metals National Corp., a joint government-industry entity.
Companies involved have included BP and ConocoPhillips in tests on the North Slope, and Chevron in tests in the Gulf of Mexico.
How much of the resource is there?
A lot: Hydrates exist in certain conditions of pressure and temperature overlying petroleum-producing geologic systems, and scientists now believe they are more common than once thought. The 43,000-tcf global resource estimate is for methane in-place, that is physically present in sand-rich sediments, which are the most feasible types of deposits, and excludes additional volumes that occur more widely disseminated in muds.
Earlier, in 2008, Timothy Collett and a team at the USGS did the first estimate of what might be recovered with technology today in a specific region. The estimate was 85 trillion cubic feet of technically recoverable resources on the North Slope.
Finding a way to extract the methane is the challenge. After several major field projects in Alaska and Canada, scientists now see a path toward hydrate wells that could produce as much as 10 million cubic feet per day of methane using procedures now identified and possibly 60 million cubic feet per day or more if those can be combined someday with other advanced technologies, like horizontal production wells.
In a hydrates workshop in Alaska in late July, Ray Boswell of the U.S. Department of Energy’s National Energy Technology Laboratory and Brian Anderson, Professor of Chemistry at the University of West Virginia in Morgantown, said the most promising production technique to date appears to be gradual depressurization of a hydrate combined with periodic injection of water to stop the hydrate well from freezing up.
The two spoke during an International Association of Energy Economists conference in Anchorage.
“Initial concepts for hydrate production focused on injection of warm water to melt the hydrate. That approach does work, but appears unlikely to produce gas at the rates necessary to make wells profitable,” Boswell said in an interview.
A major breakthrough occurred, he said, when free water was found in test wells and a concept was developed to use downhole pumps to remove the water, which allowed pressure in the reservoir to be rapidly reduced.
“This ‘depressurization’ approach is likely to be the foundation of future production systems,” Boswell said. “However, due to the unique chemistry of hydrates, whenever they melt they cool the surrounding environment, which could lead to freezing of the free water. Therefore, other approaches, such as the periodic injection of warm water will likely be needed.”
However, another potential problem is that because depressurization dissolves the hydrate it causes the reservoir to compact, and surface subsidence may occur in locations where hydrates are near surface, such as the Arctic.
Another technique tested that would keep the some hydrate intact involved injection of carbon dioxide to displace the methane. This involved exchanging methane molecules with carbon dioxide molecules in the hydrate.
The exchange mechanism has been shown to work but tests also showed that the volumes of methane that could be produced are likely to be less than with depressurization.
“However, carbon dioxide injection might make sense where there is also a need to sequester CO2 or where subsidence issues are acute and cannot be dealt with other solutions,” Boswell said.
What’s is needed now, Bowell said, is a long-term production test to try out the procedures scientists now think are most likely to work. Alaska’s North Slope is now considered to be the best place for a long-term test because hydrates are known to exist adjacent to industry infrastructure like roads, utilities and camps for personnel.
BP and ConocoPhillips participated in two earlier North Slope hydrate tests but getting industry interest now may be a challenge given the present glut of cheap shale gas in North America. Also, 35 trillion cubic feet of conventional gas is still stranded on the North Slope with a gas pipeline only in a concept phase.
Given all this, industry’s appetite for spending money on researching a huge new gas resource is uncertain. Japanese groups may step up to the plate, however, after successful tests earlier this year in Japan of the first test production of methane from an offshore hydrate. Japanese groups also partnered DOE on the most recent test in Alaska with ConocoPhillips.
The State of Alaska may also get involved.
“We believe we could really firm up the science with a long-term production project like this,” state Oil and Gas Director Bill Barron said.
The state has a cooperation agreement with the DOE on hydrate research, with DOE Acting Assistant Secretary Christopher Smith and Alaska Natural Resources Commissioner Dan Sullivan signing the agreement April 16.
“The goal is to form an government/industry consortium that will collaborate with global hydrates experts in government, industry and academia on this opportunity,” Barron wrote in an email. “Every party in the consortium will bring what they can to best contribute to the organization. The State has land and resources, the DOE has funding and scientific expertise, the USGS has global scientific expertise in hydrates, the industry has operational expertise and extensive (research and development) resources, and the universities have research and computer simulation capabilities. We are going to be much stronger working together to unlock the technical hurdles of hydrates.”
Barron isn’t concerned about the apparent lukewarm industry interest, either.
“The companies will make decisions based on their portfolios,” of assets, he said. “We believe this project would be in the best interests of the country and the state.”
“Both BP and CPA (ConocoPhillips), along with DOE’s National Energy Technology Labs have been involved in this research in the past and I am sure they are evaluating their options,” Barron wrote.
Barron said the near-term objective of state and DOE teams is to identify a site for the production outside the existing oilfields but near enough to benefit from the oilfield infrastructure.
The state has set aside 26,000 acres of unleased land just north of the Prudhoe Bay field for hydrate research and is working with DOE to determine the best site for a production test, he said. The test would eventually require a gravel well pad, utilities and facilities to support drilling, Barron said, and it’s best to do this outside the operating oil fields so research drilling won’t risk interfering with production operations.
“The goal is to have an operation which could eventually test the resource on a continuous basis, testing various production scenarios and configurations, regardless of season.” Barron said.
It’s premature, for now, to speculate on the duration of a test.
“There is so much unknown about hydrate production and reservoir response,” he said.
Boswell said the test should extend for at least 18 months.
“We’d like a site that did not artificially limit our time,” he said. “We need a site, funding, required permits, and industry and international partners. Depending on the nature of the site and quality of data, we may need to collect additional geologic-geophysical data to confirm presence and nature of hydrate reservoirs prior to establishing the site.
“Final details of the well completion and testing plan would be agreed-upon by the project partners, but an expectation would be to minimize test complexity and focus on production by depressurization.”
Scientists have learned a lot about methane hydrates from test drilling programs over the last 15 years. The chemical structure of a hydrate was known in theory as early as 1810 but it was not known they could exist in nature. In the 1930s they were detected forming in gas pipelines where they were a hazard, but it was only in the early 1980s that a hydrate was observed for the first time in a natural state, on the seafloor. It’s now thought they are common where conditions are right.
Offshore, along the continental shelf, hydrates are found in the upper layers of sediment where water depths exceed 1,300 feet. In the Arctic, hydrates are found at shallower depths onshore, typically from 650 feet to 3,600 feet because of permafrost, which on the North Slope extends to about 2,000 feet.
Because access is easier onshore than offshore, the Arctic has always been the laboratory of choice for most hydrate research. In 1998, scientists scored the first success in producing methane at the Mallik well in the MacKenzie River delta of Northwest Territories in Canada.
There was a follow-up test in 2002 where scientists attempted to liberate methane through thermal means, by pumping in hot water. In a two-day test, 468 cubic meters of methane were produced.
The next step came in 2007 at the Mt. Elbert test well at Prudhoe Bay, which was operated by BP and with DOE and the USGS as partners. Here the goal wasn’t so much to produce methane as to confirm that newly-developed seismic procedures could locate hydrates with confidence, and to extract and analyze hydrate core. All objectives were accomplished.
At the Mt. Elbert well, researchers were also able to make a resource estimate of a discreet hydrate accumulation for the first time, estimating a range of 50 billion to 168 billion cubic feet of technically recoverable methane.
“This was a breakthrough because it showed us a process to find the hydrate,” and estimate the resource, Boswell said.
It was this confirmation of the seismic technique, at Mt. Elbert, that also allowed the U.S. Geological Survey to make the first estimate of technically recoverable methane resources across much of the North Slope of 85 tcf.
The estimate excluded the Barrow area in the National Petroleum Reserve-Alaska, however, where hydrates are also thought to exist.
As at Mallik, an important finding at Mt. Elbert was the presence of reservoir water that is necessary to enable production by depressurization, Boswell said.
There were further tests at Mallik in 2007 and 2008 by the governments of Japan and Canada that involved more expansive testing and refinement of depressurization techniques. In 2007, the Mallik well produced 28 thousand cubic feet, or mcf, over two days, but the following year 458 mcf were produced over six days.
The effort shifted back to Prudhoe Bay in 2011 with the Iġnik Sikumi well, operated by ConocoPhillips with the DOE and USGS as partners. The initial objective at Iġnik Sikumi was to field-test the injection of carbon dioxide and nitrogen to displace methane from the hydrate, which ConocoPhillips had done in a laboratory.
The well would then be depressurized to determine the response of the reservoir to the gas injection procedure. Over 30 days, about 1 million cubic feet of gas was produced, 84 percent of it methane.
In the depressurization part of the test the research team reduced pressure to assess the extent of exchange of methane with carbon dioxide and to see when the freeze-back would happen.
“The exchange was confirmed, although the extent of the process is still under study, and the freeze-back did not occur, which was a surprising finding,” Boswell said.
Earlier this year Japan’s offshore test by the Japan’s JOGMC produced more than 4 million cubic feet of methane over 6 days, achieving daily rates of 700 mcf/day, using depressurization.
“The Japanese have built on what had been learned from the prior research in the Arctic. It is gratifying to see that what is being learned in Alaska and elsewhere can be successfully applied offshore,” Boswell said.
Mark Myers, former director of the U.S. Geological Survey and now vice chancellor for research at the University of Alaska Fairbanks, has always felt that the North Slope hydrates could be an important resource.
When he was director of Alaska’s Division of Oil and Gas Myers pushed industry to join the hydrates research work with the DOE and USGS, believing that vast resources that might be unlocked could be important in backstopping the supplies of conventional gas for a gas pipeline.
Tim Bradner can be reached at email@example.com.