By Perry Fischer, Editor

Eight technical papers were presented on methane hydrate as a resource at OTC 2008. A ninth presentation was given at an OTC luncheon by Brad Tomer, director of the Strategic Center for Natural Gas and Oil Laboratory, an NETL lab. Mr. Tomer gave an overview of the massive and rapidly expanding amount of research ongoing in methane hydrates as a resource. The US National Methane Hydrates R&D Program has participation from seven governmental agencies, six national laboratories, seven oil/oil-service companies and five universities.

The presentation showed the usual goals: to better understand, to experiment, to characterize, and so on (this writer has been watching this research for the past 15 years, and these bullet points seem unchanging). But there is more research going on now than ever before, and it’s occurring in more than a dozen nations, with slow progress being made.

One promising finding was revealed by Mr. Tomer. For years, folks have worried that methane hydrates have an Achilles’ heel. When gas trapped in its ice cage (clathrate) is dissociated by depressurization, the hydrate gas volume undergoes a 160X expansion. The concern is that this endothermic reaction will cause the just-liberated methane and water to re-form into hydrates, and the best that you could get from depressurizing a borehole was a pulsed, long-frequency production scenario. Fortunately, that has not proven to be as big a problem as previously thought.

Tomer showed a slide with a laboratory simulation of production. While the production did vary sinusoidally, it did not stop. In response to a question from the audience, Tomer said that, while still a concern, it appears that adding enough heat (probably in the form of hot water) to raise the temperature just 1°C is enough to keep the hydrate from re-forming.

Assessment of methane hydrates resources always grabs the headlines, since there’s much more energy in hydrates, in situ, than all of the recoverable oil and gas resources worldwide. For example, a just-released MMS assessment of the Gulf of Mexico shows a mean of 21,000 Tcf of methane (as hydrates) in place, which is three times the world’s proved gas reserves. However, since most hydrates occur in mud, silt, sand and other poorly consolidated formations, it’s a fairly meaningless fact. Recovery, at least from these formations, is unlikely, since permeability near the borehole would probably be destroyed in the production process. Nevertheless, 6,700 Tcf of the GOM in situ hydrates occur in sandstone, which offers some hope of production.

You might read that, in all likelihood, methane hydrates have already been produced. But while true, that’s a technicality. While production from the top seal of some conventional, shallow, Arctic or deepwater gas reservoir has probably occurred in a limited fashion, that is not what is meant when considering hydrates as a resource.

Regrettably, the one thing that counts the most - flowrates - is being held secret. Without relatively high flowrates, in the range of millions of cubic feet a day, nothing else would matter. And likewise, if modestly high flowrates could be established, nothing else matters; money would pour into these research projects. So far, the scant information that this writer has heard from private sources suggests that flowrates are anemic.

A clue to the reason for the secrecy can be found in a recent US report, “Report to Congress: An assessment of the Methane Hydrate Research Program.” The report reads, “Other energy-hungry countries, such as Japan, India, China, and South Korea, are each annually outspending the United States on hydrates-related research by up to a factor of ten. The US is beginning to lose its lead in hydrate science and technology ... This ‘wait-and-adopt’ strategy also relegates the US to second place status in the pursuit of potentially valuable technology patents.”

However, to this writer, it would seem that revealing production test data, what little there is, while holding the production methods secret, would secure funding for national prestige and intellectual property purposes, provided, of course that the production volumes were encouraging.

The problem with these hydrates is that they are sort of caught in an economic “box.” On the deepwater side, where most hydrates occur, lie the economics of deepwater development, which, at this point, seem insurmountable. Although they lie in deep water, hydrates are usually found at rather shallow depths beneath the seafloor. Like most unconventional gas resources, they are not high pressure. Thus, high flowrates-which are necessary to be economic in deepwater environments, not to mention competitive with conventional gas wells-will be extremely difficult to achieve and, more importantly, sustain.

On the other side of the box lies the Arctic. These methane hydrates are more readily accessible and, at first glance, more economically viable than their deepwater cousins. However, like all Arctic gas resources, they are stranded until long, expensive pipelines can be built southward to markets. Such pipelines are inevitable, but at best, it will be 2019 before they are flowing. Tomer said NETL thinks that Arctic hydrates will be commercially produced by 2020-2025. But the big catch is that there are at least 100 Tcf of Arctic gas available that is conventional, i.e., high flowrate.

Therefore, it is very likely that hydrate-derived gas, with its relatively low flowrates, will have to wait until Arctic conventional gas production is in a mature state before a methane hydrate well could get nominated for pipeline transport. That could take 50 years. The situation is akin to other low-flowrate, unconventional gas formations, such as coalbed methane and shale gas. In fact, if methane hydrates were located in temperate climes on land, then they probably would already be in production.