Methane hydrates are still decades away. U.S. House hearing 2009.

[ The U.S. Department of Energy says: “At today’s gas prices, there are no economically recoverable deposits…and the commercialization of methane hydrates is likely to be several decades away….Although the size of the global methane hydrate resource is estimated to be enormous—eclipsing even global coal resources (more than several thousand gigatons of carbon)—only a small fraction of all methane hydrate deposits could ever be commercially extractable, even at very high natural gas prices”.  Or perhaps never: see my post “Why we aren’t mining methane hydrates now — or perhaps ever“.

Alice Friedemann  author of “When Trucks Stop Running: Energy and the Future of Transportation, 2015, Springer]

House 111-32. July 30, 2009. Unconventional fuels part II: the promise of methane hydrates. U.S. House of Representatives. 50 pages


We do not yet know if these accumulations exist in sufficient concentration to make them economically viable, nor do we know whether even concentrated accumulations can be developed economically.

Much more information is needed on: (1) the geology of the hydrate-bearing formations, both on a large scale (the distribution of hydrates throughout the world) and on a small scale (their occurrence and distribution in various host sediments); (2) the reservoir properties/characteristics of gas hydrate reservoirs; (3) the production response of various gas hydrate accumulations; and (4) the economics controlling the ultimate resource potential of gas hydrates.

Technical challenges

Gas hydrate wells will be more complex than most conventional and unconventional gas wells due a number of technical challenges, including:

  • Maintaining commercial gas flows with high water production rates
  • Operating with low temperatures and low pressures in the well-bore
  • Controlling formation sand production into the well-bore
  • Ensuring well structural integrity with reservoir subsidence

Technologies exist to address all of these issues, but will add to development costs. Gas hydrate development also has one distinct challenge compared to other unconventional resources, and that is the high cost of transportation to market.

Most gas fields require some compression to maximize reserve recovery, but this typically occurs later in the life of the field after production starts to fall below the plateau rate. For a gas hydrate development, the required pressure to cause dissociation will require the use of inlet compression throughout the life of the field including the plateau production time. This will require a larger capital investment for compression at the front end of the project, and will also result in higher operating costs over the life of the project.

Water production is not uncommon in gas wells, however water rates are typically less than say 10 bbls/MMscf (barrels of water per million standard cubic feet of gas) for water of condensation and/or free water production. Wells that produce excessive amounts of water are typically worked-over to eliminate water production or shut-in as non-economic. The water production from a gas hydrate reservoir could be highly variable, however water:gas ratios in excess of 1,000 bbls/MMscf are possible. This water must be removed from the reservoir and wellbore to continue the dissociation process. On this basis, a gas hydrate development will require artificial lift such as electric submersible pumps or gas lift, which will also increase capital and operating costs over the life of the field. But it is important to highlight that the water in gas hydrate contains no salts or impurities, it is fresh water and may be a valuable co-produced product of a gas hydrate development.

The combination of low operating pressures and high water rates will require larger tubing and flowlines for a gas hydrate development, in order to minimize friction losses and maximize production. Additional water handling facilities and water disposal will also be required. Larger inhibitor volume (such as glycol) will be required to prevent freezing and hydrate formation in tubing and flow-lines. Other items such as sand control, reservoir subsidence, down-hole chemical injection, possible requirements for near well-bore thermal stimulation, etc., will also require additional capital and operating costs for gas hydrate developments compared to conventional gas developments.

Onshore gas hydrates in North America are located on the North Slope of Alaska and on the Mackenzie Delta in Canada. These resources, along with significant volumes of already discovered conventional gas, are stranded without a pipeline to market. In order to compete for pipeline capacity, the economics of onshore gas hydrate developments must be attractive at prevailing gas prices.

By all estimates, the majority of gas hydrates considered for production are located in sandstone reservoirs in deepwater environments. Deepwater drilling technology and experience continues to evolve, and the worldwide deepwater fleet continues to expand. However the deepwater environment is still a very high cost and very high risk area of operation. Offshore gas hydrate developments must have strong economic drivers in order to compete with other deepwater exploration and development opportunities. Adding on the risk of gas hydrates is yet another level of risk to add onto the existing high-risk drilling in deep water.

Significant scientific and exploration work must be completed before gas hydrates can be considered as a viable source of natural gas. Critical among these tasks remains the validation reservoir and well performance through extended field testing that demonstrates the ability to produce gas hydrates at commercial rates with current technology.

So far the small-scale experiments have not been able to bring gas hydrates as far as the surface of the ocean.

On the basis of the studies done to date, gas hydrate developments will have capital and operating costs significantly higher than other unconventional or conventional developments due to well productivity, low operating pressures and temperatures, and high water production rates. Surface facilities for gas hydrate developments will also be higher due to the requirements for larger surface flowlines and inlet facilities (required because of low pressures and water production rates) and the requirement for inlet compression into the processing plant.

SBC. June 2015. Gas Hydrates. Taking the heat out of the burning-ice debate. Potential and future of Gas Hydrates. SBC energy institute.

it is largely agreed that, using current technologies, gas hydrates are likely to be more expensive to recover than most other gas resources.In most cases, gas-hydrate recovery is expected to require more wells per unit of space.Gas-hydrate recovery would also exhibit a higher water-to-gas ratio, which may require special facilities and oversized flow lines.  In addition, it involves dissociation operations e.g. using compressors and requires artificial-lift infrastructure and cutting-edge monitoring and control instruments.As well as exploration and production costs, gas-hydrate economics may also be affected in some regions by high transport costs:resources can be located far from markets, in harsh marine or permafrost environments, and face the usual “stranded gas” issue. Therefore the business case for gas hydrates would be improved in locations where synergies with conventional oil and gas operations could be leveraged.

In addition, deposits in permafrost environments would typically be cheaper to exploit than marine accumulations, because operations would be based on land. Gas hydrates seem very unlikely to be competitive in gas-rich regions.

The energy density of gas hydrates in situ is lower than that of conventional gas accumulations. This has important consequences for the economic viability of recovering methane hydrates, e.g. it is likely to require more wells.  98% of hydrate resources are estimated to be offshore and 2% in permafrost

A few of the many challenges (see pages 45-46 for others)

Significant amounts of sand can be produced if mitigation actions are not undertaken.In April 2007,a huge amount of produced sand led to the termination of the Mallik production test after 60 hours.
While sand-control devices such as sand screens can limit sand production, they can also cause production damage if they or the formation near the borehole become plugged with mobile solids.

Geomechanical hazards are less understood than other operational challenges faced by gas-hydrates production.In the absence of long-duration production test, they have not been yet empirically experienced, but only modeled by numerical reservoir simulators.Therefore, geomechanics is one of the biggest uncertainties associated with gas-hydrates production

As gas hydrates dissociate, the mechanical strength of the reservoir diminishes.Indeed,dissociation is accompanied by a decrease in the pressure of the formation and the removal of pore-filling “material”,which puts reservoir integrity at risk.This issue is particularly acute in shallow marine sediments and, as a result, it may be preferable to exploit deeper hydrate formations.In permafrost, the thickness of the overlying ice sheet and a smaller reduction in pressure should minimize the subsidence issue.

In addition, uncontrolled gas flow and sediment wellbore instability caused by the heating of sediments in the vicinity of production wells need to be monitored.Finally,horizontal well completion in shallow, unconsolidated sediments may be challenging.

Expensive monitoring

Gas-hydrate production requires the deployment of extensive monitoring systems in order to improve understanding of gas-hydrate dynamics ultimately optimizing recovery), but also to detect, prevent and mitigate potential safety and environmental hazards.

In Nankai Trough,for instance, two monitoring wells 2 were drilled in the vicinity of the production well as part of the production test.These wells were equipped with two types of temperature sensors: 1) Distributed Temperature Sensing (DTS) devices covering the entire borehole for autonomous, long-term monitoring measurement accuracy of +/- 0.5 ° C, and autonomous over 18 months; 2) Array-type Resistance Temperature Detector RTD devices placed across the gas hydrate reservoir with higher temperature resolution accuracy +/- 0.1 ° C for real-time monitoring during production tests.

In addition to pressure and temperature measurement, methane-emission detection and repair devices will be essential, especially in the Arctic


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