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Where from here?
Scientists continue research into natural gas production from hydrates
Research into possible future natural gas production from massive worldwide deposits of methane hydrate has reached the stage of planning long-term production tests, with the possibility of some of these tests being conducted on the Alaska North Slope, and with Japan hoping to produce gas from its offshore hydrate resources sometime after 2023, Brian Anderson, a fellow in the Department of Energy National Energy Technology Laboratory and Ray Boswell, Department of Energy technology manager for natural gas technology, told a workshop held on July 31 during the International Association for Energy Economics’ North American conference.
Methane hydrate, an ice-like solid with methane, the primary component of natural gas, trapped in a lattice of water molecules, is known to exist in huge quantities in many parts of the world. And for a number of years scientists, intrigued by the possibility of turning at least some of this natural resource into a prolific source of gas for fuel, have been researching the nature of various methane hydrate deposits and the practicalities of extracting gas from the material.The material is stable under a certain range of temperatures and pressures, and moving the temperature or pressure out of this range causes the hydrate to decompose into water and gas. And the relatively low temperatures and high pressures required for stability tend to cause hydrate formation in deep ocean seafloors and around the base of the permafrost under land in regions such as the Alaska North Slope where the ground is frozen to substantial depths.
Vast potential resource
Boswell said that methane hydrate is thought to exist on most of the world’s continental shelf areas, as well as on land in permafrost regions. There is still a huge range of uncertainty in estimates of worldwide gas volumes locked in methane hydrate deposits but, to give a sense of the possible scale of the resource, the mid-point of that range may be around 350,000 trillion cubic feet, he said.“Gas hydrate is one-third of all potential mobile organic carbon on the planet,” Boswell said.
The hydrates typically exist as solids in the pores of subsurface rocks and are also found on the seabed as seeps and mounds. But, given the relatively high concentrations of hydrate that can exist in geologically stable sand deposits and the relative ease with which fluids might flow through these sands to a wellbore, research into the commercial development of methane hydrate has focused on areas where the hydrates are deeply buried in sand, Anderson explained.
The sand deposits likely hold tens of thousands of trillion cubic feet of gas, out of the total of hundreds of thousands of trillion cubic feet that may exist in all types of deposit, he said.
People have conducted detailed methane hydrate assessments for areas where the hydrate deposits appear especially promising as development targets. One of these areas is the North Slope of Alaska, where the U.S. Geological Survey has estimated a total resource of 85 trillion cubic feet of technically recoverable gas in hydrates around the base of the permafrost. In the Gulf of Mexico, another promising area, the Bureau of Ocean Energy Management has estimated the possibility of 21,000 trillion cubic feet of gas in hydrates in methane hydrate deposits of all kinds, with perhaps 6,700 trillion cubic feet of this in sand-based deposits, Boswell said. The Bureau has not yet assessed how much of this Gulf of Mexico resource might be technically recoverable, he said.A similar assessment by the Japanese for the Nankai Trough, a region offshore southeast Japan that perhaps represents 10 percent of Japan’s prospective areas for methane hydrate, found the possibility of 40 trillion cubic feet of gas in place in hydrates, with perhaps 20 trillion cubic feet of that total resource existing in sand-based deposits.
Production of gas from any of these resources would require the deliberate destabilizing of the hydrates, to cause the hydrates to break down into water and methane, releasing the methane into a production gas well. And, although it might be possible to achieve this destabilization by injecting some suitable chemical into the hydrate or by heating the hydrate using steam or hot water, the most practical approach seems to involve reducing the pressure in the hydrate-bearing sand reservoir, Anderson said.Essentially, a well would be drilled into the hydrate reservoir and the reservoir pressure reduced by pumping free water from the reservoir up the well. The pressure reduction would cause the hydrates to start to disassociate, generating methane and additional water. By continuing to pump water out of the well, the reservoir pressure would be maintained at too low a level for hydrate stability, thus causing more hydrate to disassociate, more water to form and methane to pass up the well.
One variant of the process might be operable when a solid hydrate layer lies over free gaseous methane in a subsurface reservoir — the necessary pressure reduction would be achieved by pumping free gas up a well from the reservoir, with the subsequent hydrate disassociation releasing gas to continuously replenish the gas reservoir.
The snag with these apparently simple processes is that the disassociation reaction absorbs heat, thus cooling the reservoir and perhaps inhibiting further disassociation. Thus, for continuous gas production during depressurization heat would need to flow in from the reservoir surroundings.
In 2002 a test in a methane hydrate well in northwestern Canada called the Mallik well attempted methane production through the application of hot water to the hydrate reservoir but found this technique to be ineffective, Anderson said. However, another different test demonstrated that the hydrates could be disassociated through depressurization without the artificial application of heat, a result representing a major breakthrough in methane hydrate research, he said.In 2007 BP, the Department of Energy and the U.S. Geological Survey drilled the Mount Elbert methane hydrate stratigraphic test well at Milne Point on the Alaska North Slope. Tests in this well demonstrated the possibility of de-pressuring the hydrates and thus releasing methane by extracting free water from the hydrate reservoir, Anderson said.
And in 2008 a new test in the Mallik well succeeded in producing about 13,000 cubic meters of gas over a six-day period using depressurization, he said.
Carbon dioxide injection
In 2012 ConocoPhillips, the Department of Energy and a Japanese company conducted a test in the Ignik Sikumi methane hydrate well in the Prudhoe Bay unit on the North Slope to try a combination of depressurization and carbon dioxide injection as a means of methane production from hydrates. The carbon dioxide would displace some of the methane in the hydrate, thus releasing methane in a reaction that generates rather than absorbs heat.The test, involving the injection of nitrogen as well as carbon dioxide, resulted in the production of about one billion cubic feet of a mixture of methane, carbon dioxide and nitrogen, with less carbon dioxide produced than injected, Anderson said.
In 2013 the Japanese drilled a methane hydrate production test well in the Nankai Trough and used a depressurization technique to produce about 706,000 cubic feet per day of gas over a six-day period, Anderson said.
But, despite the success of these various tests, people do not yet know what would happen if production were to be attempted over extended time periods and, hence, whether commercial scale production over perhaps several years would be possible. Much more field testing needs to be done to demonstrate the long-term viability of methane hydrate as an energy source, Boswell said.
Meantime researchers have been using the detailed information obtained from the various well tests done to date to use computer models to simulate possible long-term production scenarios, Anderson said. And results so far for North Slope on-land scenarios indicate that production will be highly sensitive to the condition of the methane hydrate reservoir but that gas production rates in the order of one million to tens of millions of cubic feet per day, with cumulative production of tens of billions of cubic feet per well, may be achievable. The modeling of production from known deposits in the Gulf of Mexico indicates possible offshore production rates of 50 million to 60 million cubic feet per day, Anderson said. But offshore drilling is much more expensive than onshore drilling, he pointed out.
Simulations have also tested the potential to use horizontal wells to increase gas production rates from methane hydrate resources and to evaluate the strain that production places on the reservoir rock, Anderson said.
The next step in hydrate research is to identify optimum sites with appropriate geology for field production tests over relatively long timeframes, Anderson said. Boswell also commented on the need for much additional exploration, confirming, delineating and characterizing methane hydrate resources.With the North Slope being an ideal location for methane hydrate testing, the Department of Energy is interested in further research in the region. The department has signed a memorandum of understanding with the State of Alaska for methane hydrate research in the state. The state has also set aside some North Slope land tracts for possible methane hydrate production testing. The Department of Energy would also like to confirm the existence of methane hydrate resources on the U.S. Atlantic coast and to continue a methane hydrate exploration drilling program that the department started in the Gulf of Mexico, Boswell said.
With international interest in methane hydrate development, as several countries seek some level of energy independence, plans for methane hydrate production testing are moving ahead in different parts of the world. Japan, having conducted its initial test drilling in the Nankai Trough, is preparing to conduct a longer-term offshore production test in 2015. Japan aims to complete the technical development of methane hydrate production by 2018, with a view to starting commercial production from its offshore resources at some time after 2023, Boswell said. South Korea wants to do a field test of its offshore resources within the next couple of years or so. China and India are conducting research into developing their methane hydrate resources, and several other countries around the world are also conducting methane hydrate research