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A major gas source for the future? DOI announces USGS assessment of North Slope gas hydrates and strikes a note of optimism about possible future production Alan Bailey Petroleum News
On Nov. 12 the U.S. Department of the Interior announced the release of the U.S. Geological Survey assessment of technically recoverable gas from gas hydrates on the North Slope. As reported in the Oct. 26 issue of Petroleum News, the assessment estimates a mean recoverable gas resource of 85 trillion cubic feet, with a possible range of 25 tcf to 157 tcf, from a 55,000-square-mile region that encompasses the central and southern North Slope; a major portion of the National Petroleum Reserve-Alaska; much of the coastal plain of the Arctic National Wildlife Refuge; and some nearshore areas of the Beaufort and Chukchi seas.
Gas hydrate consists of a white crystalline substance that concentrates natural gas by trapping methane molecules inside a lattice of water molecules (methane is the primary component of natural gas). The hydrate crystals remain stable within a certain range of temperature and pressure. But when decomposed the crystals yield about 164 times their volume in methane.
“This assessment is the first ever resource estimate of technically recoverable natural gas hydrates in the world that can be produced by existing conventional technology,” said Secretary of the Interior Dirk Kempthorne in announcing the release of the assessment. “… We conclude that natural gas hydrates could add significantly to the U.S. energy mix.”
De-pressuring USGS Director Mark Myers explained that the assessment assumes gas production from the hydrates by de-pressuring the hydrate reservoir.
“This study assumes basically one well per square mile … vertical wells and simple depressurization,” Myers said. The USGS scientists did not consider the use of horizontal wells, which would likely improve productivity, he said.
Other potential hydrate production techniques, such as heating the hydrate reservoir or using carbon dioxide to displace methane from the hydrate crystals, have not been demonstrated to be feasible and were not considered in the assessment.
The assessment does not consider whether gas hydrate production would be economically viable. Economical viability would depend on the location of the hydrates, the size of the hydrate accumulation, factors such as whether there is free gas associated with the hydrates and the cost of transporting produced natural gas to market, Myers said.
The next step in the path to determining economic viability would be an extended production test to demonstrate that model rates of production derived from short term tests can be sustained for a long time period, he said.
“That testing right now is being planned for 2009-2011 with a partnership on the North Slope of Alaska,” Myers said. “… Those tests we hope will occur anywhere starting from next winter for the next several years.”
Could be viable But the close proximity between the North Slope gas hydrates and the existing oil and gas infrastructure would minimize the cost of bringing the hydrates into production. Engineering studies have indicated that production could be viable, but engineering theory needs to be proved out using those extended production tests, Myers said.
“Let’s say we’ve got the assumptions right. We’re (then) looking certainly at prices under $10 per mcf and, depending on whether there’s infrastructure or not, prices that could be significantly less than that,” Myers said.
And, although there are local uses for natural gas on the North Slope, commercial production would require a North Slope gas line to ship the gas to market. The timing of bringing gas hydrate production on line would need to synchronize with bringing a North Slope gas line into operation, Myers said.
On the other hand, there are substantial gas hydrate deposits in the Gulf of Mexico, where there is an existing natural gas pipeline infrastructure.
“In the Gulf of Mexico there are hydrates under known infrastructure already connected to pipelines and that production could occur at any time that folks thought they could demonstrate long-term production capacity,” Myers said.
USGS research scientist Timothy Collett said that a joint industry project led by Chevron has been studying gas hydrates in the Gulf of Mexico and plans to start investigating gas hydrates in sand reservoirs in March.
Global interest Further afield, there are major gas hydrate programs in Japan and India. There are two drilling programs offshore Japan and USGS has partnered with India to drill at about 30 sites offshore that country, Collett said. There are also large gas hydrate drilling programs offshore South Korea and China, he said.
“Countries with rapidly emerging economies and economic needs for resources are quickly moving forward and looking at hydrates as a potential resource,” Collett said.
Meantime on the North Slope, BP is involved in a joint government, industry and university gas hydrate research project and in February 2007 drilled the Mount Elbert gas hydrate stratigraphic test well at Milne Point. ConocoPhillips also has an active North Slope gas hydrate program and is investigating the possibility of using gas hydrate production as a means of sequestering carbon dioxide, Collett said.
“Right now both of those companies are moving forward with a pretty aggressive exploration, research and evaluation program, mainly to look at the recoverability of hydrates,” Collett said.
And Myers feels optimistic about progressing towards the production of the hydrates.
“This is not really a 10-year type window for understanding,” Myers said. “This hopefully is a matter of a few years until we have that next step where we can say how much of that technically recoverable resource do we think is economically recoverable under various cost scenarios, demand and infrastructure scenarios.”
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