## 1 Introduction  
Gas clathrate hydrate has long been a subject of many studies in the oil and gas-related industries, with hydrates as a flow hazard historically being both the focus and the main funding source for hydrate research. The basic building blocks of hydrates are hydrogen-bonded water cages which can trap molecules of certain non-polar substances. These enclosed molecules (often referred to as \"guest\" species or hydrate formers) vary from light hydrocarbons such as methane and ethane, to acid gases such as carbon dioxide and hydrogen sulfide, and to compounds popular as refrigerants in the past. A great number of gas hydrate deposits exist both onshore and offshore all around the world, many of them considered viable potential sources of natural gas [1]. While the natural gas hydrates in sediments are rapidly becoming more and more relevant as an energy source, hydrate-related hydrocarbon fluxes into seawater and atmosphere poses a climate concern, with the geo-hazard aspects related to hydrate-filled sediments now coming to the forefront of hydrate research. A fairly recent innovative approach to hydrate production calls for exchanging carbon dioxide for methane in natural gas hydrate reservoirs, providing a win-win scenario of methane production combined with simultaneous safe CO\({}_{2}\) storage in the form of hydrate. This concept has often been envisaged as occurring at pressures needed for the CO\({}_{2}\) hydrate formation, which will be significantly lower than those of CH\({}_{4}\) hydrate at the same temperature. However, strictly speaking, those conditions are far from being relevant for practical implementations, since they are only relevant for the solid-state exchange mechanism, proven experimentally for temperatures far below zero by [PERSON] et al. [2] and more recently [PERSON] et al. [3]. Above the freezing point, hydrate deposits in the pores will always be in contact with free liquid water [4]. Even in Alaska permafrost, the average hydrate saturation amounts to only about 75%, with hydrate-filled sediment with saturation exceeding 80% being a very rare occurrence. These circumstances will give rise to a very fast mechanism for formation of new CO\({}_{2}\) hydrate from the injected CO\({}_{2}\). Heat released by this phase transition will be rapidly transported through the aqueous phases and assist in the dissociation of in situ CH\({}_{4}\) hydrate [3; 5; 6]. Since this is a liquid-state mechanism, its kinetic rates will be several orders of magnitude higher than those of a solid-state mechanism. Moreover, the two hydrate phases (in situ CH\({}_{4}\) hydrate and the newly formed CO\({}_{2}\) one) will not be actually in contact with each other, making the pressure-temperature equilibrium curves not particularly relevant for the purposes of analysis and illustration. The \"exchange\" phenomenon is rather a process of replacement, where a new hydrate fills the pore space originally filled with CH\({}_{4}\) hydrate. The use of CO\({}_{2}\) for hydrate production is just one of many technologies currently considered for the purposes of releasing CH\({}_{4}\) from in situ hydrates while at the same time storing CO\({}_{2}\) in solid form as a hydrate. Regardless of the technology platform chosen, two criteria must be satisfied. The free energy change associated with the process has to be sufficient to dissociate the hydrate, and the necessary heat for hydrate melting must be supplied. Pressure reduction has long been the method of choice for dissociation of hydrates in natural gas hydrate reservoirs since it is easy to choose the production conditions lying outside hydrate stability limits based on the temperature-pressure stability curve of CH\({}_{4}\) hydrate. However, the question of the dissociation heat supply still remains. Limited temperature gradients will be established by the pressure reduction itself, as well as geothermal gradients. It is outside the focus of this work to discuss whether these gradients will be sufficient to sustain the melting process.