Flue gas injection into gas hydrate reservoirs for methane recovery and carbon dioxide sequestration

Significance Statement

The recovery of methane from gas hydrates found in permafrost regions and subsea sediments has gained interest, with several methods for this recovery being suggested. The methods include thermal stimulation, depressurization, carbon dioxide replacement, inhibitor injection, or a combination of these methods. Though technically feasible, the suggested methods face challenges in their ability to economically produce methane at a viable rate. Therefore, the development of new commercially viable methods for the recovery of methane from reservoirs of gas hydrates, has become critical.

In a recent paper published in Energy Conversion and Management, Jinhai Yang and colleagues proposed direct flue gas injection into reservoirs of gas hydrates to break down methane hydrates and regain methane from the gas hydrates, and at the same time isolate the carbon dioxide part of flue gas as carbon dioxide hydrate or carbon dioxide-mixed hydrates in the formations of the hydrate reservoir. The method enhances the viability of the depressurization method for the severe conditions in hydrate reservoirs.

In their study silica sand, which simulated marine sediments, was saturated with water after which the system was pressurized through methane injection at room temperature. The cooling of the system resulted in the formation of methane hydrate, after which the system was depressurized and heated to a desired pressure and temperature respectively to activate the process of methane recovery. The methane hydrate saturation and the remaining water including methane gas were then analyzed.

The authors observed that the methane decomposition kinetic process occurred in 3 stages. In the first stage, the flue gas that was injected reduced the methane concentration around the methane hydrate crystals, which caused the gas hydrate stability zone to shift. This resulted in quick methane hydrate dissociation to produce increased quantities of methane, and as a consequence, the system approached a new thermodynamic equilibrium.

The second stage exhibited a gradual rise in methane concentration to a level at which the system neared equilibrium. This resulted in the slowing down of the decomposition of the methane hydrate. The recovery rate of methane in this stage is almost 100 times lower than that in the first stage.

In the final stage, more methane was generated from the decomposition of the methane hydrate as a result of stepwise depressurization of the system at constant temperature. The injected flue gas causes decomposition of methane hydrate at a pressure above its dissociation pressure, which minimizes the required hydrate reservoir depressurization degree for the production of methane gas. This in effect means reduced pressure difference between the production well and the hydrate reservoir and hence reduced driving force for sand migration and water flow. This improves the viability of the depressurization method for severe reservoir conditions of gas hydrates.

The research team examined the hydrate reservoir’s potential for carbon dioxide capture and storage and noted that there was a continuous decrease in the carbon dioxide ratio suggesting that these molecules are converted into hydrates. Approximately 70% of the carbon dioxide present in the flue gas was converted to hydrate. Further, at low temperatures, hydrate reservoirs were found to be the better choice for carbon dioxide capture and storage through flue gas injection. Direct injection of flue gas into gas hydrate reservoirs for methane recovery and geological storage of carbon dioxide simultaneously eliminating the need for a a separate carbon dioxide capture process that makes up 65% to 80% of total CCS costs.


Jinhai Yang, Anthony Okwananke, Bahman Tohidi, Evgeny Chuvilin, Kirill Maerle, Vladimir Istomin, Boris Bukhanov, Alexey Cheremisin. Flue gas injection into gas hydrate reservoirs for methane recovery and carbon dioxide sequestration. Energy Conversion and Management 136 (2017) 431-438.

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