Simulation of subsea gas hydrate exploitation

The recovery of methane from gas hydrate layers that have been detected in several subsea sediments and permafrost regions around the world is a promising perspective to overcome future shortages in natural gas supply. Being aware that conventional natural gas resources are limited, research is going on to develop required and sustainable technologies for the production of natural gas from such new sources since the early 1990s. In recent years, intensive research has focused on the capture and storage of CO2 from combustion processes to reduce climate impact. While different man-made or natural reservoirs like deep aquifers, exhausted oil and gas deposits or other geological formations are considered to store gaseous or liquid CO2, the storage of CO2 as hydrate in former methane hydrate deposits is another promising alternative. Due to beneficial stability conditions, methane recovery may be well combined with CO2 storage in the form of hydrates. Regarding technological implementation many problems have to be overcome. Within the scope of the German research project »SUGAR« different technological approaches for the optimized exploitation of gas hydrate deposits are evaluated and compared by means of dynamic system simulations and analysis. Detailed mathematical models for the most relevant chemical and physical processes are developed. The basic mechanisms of gas hydrate formation/ dissociation and heat and mass transport in porous media are considered and implemented into simulation programs. Simulations based on geological field data have been carried out. The effects occurring during gas production and CO2 storage within a hydrate deposit are identified and described for various scenarios. The behavior of relevant process parameters such as pressure, temperature and phase saturations is discussed for different strategies. Simulation results for different scenarios, e. g. simple depressurization and CO2 injection, reveal that both the production of natural gas and the CO2 storage are possible with acceptable rates. In case of simultaneous CO2 injection an increased production rate can be expected. The results strongly depend on deposit conditions, especially multiphase flow rates are dominated by permeability terms - in other words the reservoir permeability controls production and injection rates. Furthermore, the heat transport within heterogeneous layered deposits leads to enhanced hydrate decomposition and thus higher production rates