Gas hydrates are being considered as an alternative energy resource of thefuture since they exist in enormous quantities in permafrost and offshoreenvironments. However, gas production potential from hydrate reservoirs throughdifferent production schemes has not been fully investigated yet. This workintroduces a simple analytical model for simulating gas production from hydratedecomposition in porous media by a depressurization method. We consider the heat transfer to the decomposing zone, intrinsic kinetics ofhydrate decomposition, and gas-water two-phase flow as the three primarymechanisms involved in hydrate decomposition in porous media. In this study, the relative importance of these mechanisms is compared over a realistic rangeof the physical properties. It is shown that for the cases studied, the effectof two-phase flow is significantly smaller than the heat transfer and theintrinsic kinetics of hydrate decomposition. Considering the rate-controllingmechanisms, an analytical model is developed to predict the performance ofdecomposition of gas hydrates in porous media. The model is used to performsensitivity studies to investigate the feasibility of commercial gas productionfrom hydrate reservoirs. The results suggest that significant quantities of gascan be produced from gas hydrate reservoirs where the hydrate overlies the gaszone. Such reservoirs have been found in the permafrost regions of Siberia, Alaska, and Canada. Introduction The enormous natural gas reserves associated with the in situ gas hydratesin permafrost regions and offshore environments of the earth is expected to bean energy resource of the future. The gas could be produced from the hydratedissociation by depressurization, thermal stimulation, solvent injection, or acombination of these methods. The potential for gas production from hydratereservoirs through different production techniques is still uncertain and underinvestigation. One method of investigation is with the help of mathematicalmodels. For a mathematical model to be representative, it should include theimportant mechanisms. In a depressurization scheme considered in this study, three important mechanisms are involved: intrinsic decomposition of the hydratethat results in reduced temperature; heat flow towards the cooled zone thatprovides the necessary energy for further decomposition; and, flow of thedecomposed gas and water through the porous rock.

IntroductionToday, increasingly more stringent environmental considerations require that clean sources of energy be found. It is therefore anticipated that the demand for natural gas will continue to increase significantly. Some studies indicate that the amount of methane trapped in gas hydrates in natural settings is 100 times that of conventional gas reserves (1,2) . Therefore, gas hydrates are being considered as a potential source for natural gas production. However, it is not clear what percentage of this huge resource is recoverable, and the technologies for recovering natural gas from hydrates are still under development. Sloan (3) has presented an extensive review of some suggested methods, including depressurization, thermal stimulation, and inhibitor injection. The least energy intensive process is thought to be the depressurization method, since in this method the heat of decomposition is provided by the surrounding formation. AbstractGas hydrates as a significant resource of natural gas have attracted considerable attention in recent years. However, the severe environmental conditions of gas hydrate reservoirs and the solid form of hydrates require extensive technological development before commercial gas production becomes possible. Numerical studies often give useful information for predicting the potential and technical viability of a recovery process.This paper presents a 2D cylindrical simulator for gas production from hydrate reservoirs. The model includes the equations for gas-water two-phase flow, conductive and convective heat transfer, and intrinsic kinetics of hydrate decomposition. The simulator is used to model a hydrate reservoir where the hydrate-bearing layer overlies a free gas zone, such as those discovered in the arctic. A well is drilled and completed in the free gas zone. Pressure reduction in the free gas zone leads to the decomposition of the overlying hydrate and subsequent production of the generated gas.In this paper, we study the impact of the overlying hydrate in improving the production performance of the underlying gas reservoir and investigate the effect of various parameters on gas production behaviour. The rate of gas generated and produced, pressure, temperature, and saturation distributions are studied to investigate the sensitivity of results on individual input parameters. The results suggest that the development of gas reservoirs with overlying hydrates can lead to significant production rates and that the top hydrates have a large impact on increasing the reserve and improving the productivity of the underlying gas reservoir.Modelling of gas production from hydrate reservoirs involves solving the coupled equations of mass and energy balances. A review of analytical and numerical models given by Hong et al. (4) suggests that two approaches with respect to conditions at the decomposition zone have been taken: equilibrium and non-equilibrium. In models using the equilibrium approach, the three-phase hydrate-gas-water interface is at a thermodynamic equilibrium. The ...

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Impure CO2 containing less than 2% H2S has been injected since 2002 into the depleted Long Coulee Glauconite F gas Pool in southeastern Alberta. Breakthrough was observed within one to three years in producing wells, leading to their abandonment. Simulation studies reported in this paper indicate that additional gas was recovered as a result of CO2 injection. An interesting observation at the breakthrough wells was that the CO2 broke through ahead of the H2S. The partitioning of the H2S and CO2 as they flow through the reservoir was studied in detail. One objective of the reported work is examination of interactions of the injected gas with the in-situ fluids and the displacement of the in-situ gas by the injection gas, for better understanding of the mechanisms involved in enhanced-gas recovery. Another objective of the work is to study factors that affect the spread of the injected gas in a depleted oil and gas reservoir and its implications with respected to CO2 geological storage. The results of this study indicate that at low pressures, the injected gas occupies a large reservoir volume and exhibits little density difference with the in-situ fluids, leading to rapid spread of the injected gas and early breakthrough. Also, it was found that in the case of Long Coulee Glauconite F gas Pool the well-spacing used for production did not allow a detailed geological characterization that was required for accurate prediction of breakthrough as a result of gas-gas displacement. Simulation studies, together with displacement experiments in the laboratory reported elsewhere, confirmed that the preferential solubility of H2S in the reservoir water led to stripping of the H2S at the leading gas front and it delayed its breakthrough relative to that of CO2. The implications of such chromatographic partitioning of H2S and CO2 in geological storage of impure CO2 streams are discussed. Introduction Carbon dioxide capture and storage in geological formations is considered to be one of the practical options for reducing atmospheric greenhouse gas emissions. A number of operators in Alberta have implemented injection into depleted gas and oil pools as a means of disposal and storage of acid gas, which is a mixture of H2S and CO2 stripped off produced sour gas before sending the natural gas to markets (Bachu and Gunter 2005). In many cases the composition of the injected gas is similar to that of impure CO2 in that the majority of the injected gas is CO2. For example, in the Long Coulee Glauconite F Pool in southeastern Alberta (Figure 1), CO2 concentration in the injected gas is about 98% (with H2S making up the majority of the balance). Significant interest has been shown in the study of these reservoirs as commercial-scale analogues for geological storage of CO2 (Bachu and Gunter 2005, Bachu and Haug 2005). The authors have studied five of these projects where either breakthrough of the injected gas in producing wells, or significant pressurization was observed. One objective of this paper is to examine the behavior of the Long Coulee Glauconite F Pool for the purpose of better understanding the spread of impure CO2 in a depleted oil and gas reservoir and its implications with respected to CO2 geological storage. In addition, CO2 injection could provide the opportunity for enhanced gas recovery (Mamora and Seo 2002, Oldenburg 2003, Sim et al. 2008). As we shall see, the modeling study indicates that additional gas was recovered as a result of the injection process. The second objective of this paper is to investigate enhanced gas recovery as a result of displacement of the in-situ gas by the injected gas. Special attention was given to better understanding of the mechanisms that lead to mixing of the injected gas and the in-situ fluids as this affects the spread of the injected gas and the recovery of the in-situ fluids. In the following the history of Long Coulee Glauconite F Pool is presented briefly, followed by basic fluid and reservoir characterization. The simulation and associated sensitivity studies, as well as their use for better understanding of the spread of the injected gas and displacement of the in-situ gases, are then presented.