## 1 Introduction  
Natural gas hydrates are non-stoichiometric ice-like compounds formed by the trapping of a guest molecule (usually methane gases) in a cage of hydrogen-bonded water molecules and were discovered in 1810 by Sir [PERSON] [1]. Methane gas hydrate is considered to be a clean energy, because it burns cleanly and produces less CO\({}_{2}\) than petroleum and coal [2]. Accordingly, it can replace conventional energy sources, such as coal, petroleum and natural gas. Generally, gas hydrates are discovered in permafrost, marine sediments and deep lakes, where several necessary conditions are satisfied at the same time [3]. These conditions include low temperature (typically less than 300 K), high pressure (typically over 0.6 MPa) and the presence of methane gas and free water. Figure 1 represents that where gas hydrate has been recovered, where it is inferred to be present on the basis of seismic data and where drilling expeditions have been completed in permafrost and deep marine environments [4]. The worldwide resource of natural gas hydrate is estimated to be 3000 trillion cubic meters (TCM), which is much larger than that of conventional gas (-404 TCM) and shale gas (204-456 TCM) [5]. Marine sediments contain nearly 99 percent of global gas hydrate resources and have great potential as a new energy resources. Methane is not currently commercially produced from gas hydrates anywhere in the world; some countries have conducted field trials, for example, Messoyakha gas field in Russia, Malik site in Canada, Alaska's North Slope in USA, Nankai Trough in Japan and Northern South China Sea in China [6]. As shown in Figure 2, production technologies of the gas hydrate are related to hydrate dissociation in the P-T diagram [7]. There are three gas hydrate production methods using hydrate dissociation, namely the depressurization method, thermal stimulation method and gas-swapping or inhibitor-injection method. In the depressurization method, reservoir pressure is reduced to dissociate the gas hydrate below the phase boundary. This method is the simplest and most economical when compared to the other methods. The reservoir temperature is increased to destabilize the gas hydrate by injecting hot fluids or direct electrical heating in the thermal stimulation method. However, it is economically unfavorable, because the energy amount to increase the temperature of hydrate-bearing sediments (HBSs) is extremely high. In the gas-swapping or inhibitor-injection method, new hydrate phase equilibrium (dash line) is acquired by the injection of gas or inhibitor, as illustrated in Figure 2. Methane gas in hydrate is replaced with injected gas, and it is released. For example, CO\({}_{2}\) can be used to displace methane from the hydrate while being trapped as CO\({}_{2}\) hydrate. However, the CO\({}_{2}\) hydrate formation can result in pore-space clogging, followed by a substantial decrease of porosity and permeability [8]. This phenomenon leads to severe loss of hydraulic conductivity. Finally, injecting inhibitors, such as methanol or brine, also dissociate hydrate. However, this method is not widely used in real cases because of non-economic and non-environmental drawbacks [9; 10]. Thus, depressurization method is the best method for successful methane recovery from hydrate deposits [11; 12]. However, most HBSs consist of unconsolidated porous layers, and subsidence occurs in unconsolidated sands when the reservoir pressure drops below a critical value [13; 14]. Figure 1: Distribution map of gas hydrate [4]. Figure 2: Hydrate dissociation in P-T diagram [7]. Therefore, gas hydrate production that uses the depressurization method can lead to subsidence, due to the decreased strength and stiffness of HBS [15; 16; 17; 18]. This subsidence may induce various geological disasters, such as sediment deformation, casing deformation and production platform collapse [19]. However, there have been no research studies for preventing subsidence in the case of gas hydrate production until now.