Underwater Conventional and Unconventional Oil and Gas in the Arctic

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Hydrocarbons under the Arctic and sub-Arctic seas have been known about for a long time. Gas and oil were found first in the northward extension of the Prudhoe Bay province and in the Canadian Arctic Islands. Those discoveries were followed by further finds in the Barents Sea, the Pacific to the east of Sakhalin, off Newfoundland and in Davis Strait, and in the northern Caspian Sea (where despite its low latitude many of the ice problems found further north are still present). Many areas of the Arctic seas have not been explored. Currently there is exploration in the Kara Sea and the Chukchi Sea.

The potential difficulties are formidable. It will be essential that production schemes be safe against any possibility of environmental pollution. Some environmental campaigners are viscerally opposed to any Arctic development. They can reliably be anticipated to oppose every project on principle and will deploy every argument that can be dreamed up, whether scientifically credible or not. The current controversy over the Keystone pipeline to bring tar-sands crude to the United States illustrates the political influence of that lobby. Nervousness about any petroleum development offshore has been heightened by the recent spill in the Gulf of Mexico. It is being pointed out that that accident occurred in good weather in the early summer and that the immense resources of people and equipment in the Gulf could immediately be brought into action. In the Arctic, the response would inevitably be less prompt, particularly in the long winter.

Developments will have to be economically and financially sensible. In the past, those factors were not always given the highest priority. In the 1970s and early 1980s, a tsunami of enthusiasm for Arctic hydrocarbon developments led promoters to put forward huge and grandiose projects that would have been very expensive indeed, always assuming that they would have been able to get past the regulatory process. Oil and gas prices had risen greatly and the received opinion was that the rise was inexorable, sustained by rising consumption and by instability in the Middle East. Anyone who questioned the cost and economic viability of those projects was given a standard answer. “We are talking about $10 [per thousand cubic feet] gas,” the writer was told in 1980 by the manager of one Arctic project, “don’t worry about it!”

The mood changed abruptly when oil and gas prices collapsed after 1985. One company insisted that an oil project would only be approved if it still made financial sense when the oil price is $10 a barrel, a hard target to reach anywhere, and still more so in the Arctic. The companies that only two years earlier had planned big Arctic developments gave thanks that their projects had encountered regulatory delays and had not gone ahead.

Slowly, confidence in the Arctic offshore future has recovered. The oil price has recovered—and the gas price recovered somewhat—although not to the $10 level, and then dropped back in response to the discovery of methods of producing shale gas economically. Some Arctic offshore projects began to look attractive again. Though there was a huge drop in the intensity of research and engineering after 1985 and many people moved out of the subject, some people persisted, and a core competency remained. The experience earned in the 1970s is still available in part—much of it was documented—and the few installations that were undertaken are still in place.

Another factor has been the development of fresh thinking about ‘unconventional’ hydrocarbons, which were scarcely thought about thirty years ago. Shale gas is in vogue because of advances in fracturing technology and it is having a wide-ranging effect on thinking about the energy future. Hydrates (Sloan and Koh, 2007; Makogon, 1997) are attracting increased attention. A gas hydrate is a solid compound of water and hydrocarbon gas, usually mostly methane but also ethane and propane, rather like snow, and is stable at low temperatures and high pressures. A simple way of remembering the location of the state boundary is to recall that at 4 MPa (580 psi) pressure the temperature at which methane hydrate is just stable is 4°C (39.2°F). A higher temperature requires a higher pressure for hydrate stability.

One estimate (Kvenvolden, 1993) has it that gas hydrate world reserves correspond to 700 years of current world consumption. Saying that is of course rather easy, and we are still a way from knowing how best to produce gas from hydrates economically, but some progress has been made (Falser et al., 2012, 2013). Research on production from hydrates has been slowed by the fashion for shale gas, which is widely present in politically stable regions and whose production may be more straightforward. Hydrate development does continue however, above all in Japan, China, and Korea. The Japanese are reported to be planning a production trial in 2014 in 800 m of water in the Nankai Trough, almost ideally positioned immediately south of Honshu. Gas from hydrates can be produced by a combination of reduction in pore pressure and a modest increase in temperature induced by downhole heating, probably as part of a dual wellbore system. Heating is desirable because the dissociation of a hydrate is endothermic, and therefore depressurization without heating can lead to further cooling and restabilization of the hydrate.

Hydrates will certainly be found in the Arctic, and will be at particularly shallow depths, because the seabed water temperature is often about –1.8°C, the freezing point of seawater. If for example the water is 100 m deep, the water pressure in the seabed is hydrostatic, and the geothermal gradient is 25°C/km, the methane/water phase boundary will be reached about 300 m below the mudline. It may in fact be worthwhile to re-examine the logs of earlier drilling operations to look more closely for indications of the presence of gas hydrates.

This article sets out to survey the current state of knowledge. It begins with a brief recap of the history, and then examines where we are and what remains to be done. The survey is prompted in part by two recent (2013) conferences. The first was the biannual POAC (Port and Ocean Engineering under Arctic Conditions) conference, held in Espoo, Finland in June, and covering the whole range of Arctic offshore engineering, from survey though structure design to operations. The second was a conference on ice gouging, ISAMP (Ice Scour and Marine Pipelines), held in St. Johns, Newfoundland in May. Ice gouging—called ‘ice scour’ in Canada—occurs when drifting sea ice or an iceberg comes into contact with the seabed. The ice is observed to be strong enough to cut into the seabed to a depth of several metres, and to cut long and deep gouges. A simple calculation shows that the force applied by the ice to the seabed to cut some of the gouges that have been observed must be several thousand tonnes. If a pipeline were in the way, the pipeline would inevitably be damaged severely. This has been a major design issue for seabed pipelines in the Arctic, and is examined below.

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