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Sand production has become a common phenomenon in the exploitation of unconsolidated natural gas hydrate reservoirs, which will hinder the long-term production of natural gas hydrate reservoirs. However, there are few literatures reported on the influences in reservoir physical properties such as permeability and porosity, and production laws caused by sand production. This paper provides a numerical model, coupled with reservoir sand-gas-water multiphase flow processes, which is capable to simulate the process of sand production in natural gas hydrate reservoirs. The simulation results indicate that sand settlement is mainly concentrated near the wellbore due to the high concentration of migrated sand. The decrease in reservoir porosity and permeability caused by sand settlement has a significant impact on production. The impact of sand production on reservoir fluid fluidity shows that fluid flow is inhibited near the wellbore, while fluid flow performance increases far away from the wellbore. The numerical model and analysis presented here could provide useful insight into changes in reservoir physical properties and production laws caused by sand production in the natural gas hydrate-bearing marine sediments using depressurization method. [ABSTRACT FROM AUTHOR]

The formation sands of natural gas hydrate (NGH) reservoirs in the South China Sea are fine silty sands with a high content of clay, and it is difficult to be controlled effectively. We carried out a series of experiments to investigate the microcosmic retaining and plugging behavior of screen media with highly argillaceous fine sand samples, with median size of 10.13 μm. The screen sand-retention media and joint involved four types with slot width or accuracy of 20–60 μm. The screen media/joint sample was placed in the linear/radial flowing apparatus, and then the mixture of gas, water and sand were displaced flowing into the media to simulate the sand retaining process. The Microscopic imaging system was used to visually observe the dynamics of sand particle deposition and plugging inside the media as well as on its surface. The plugging permeability and the amount of the passed sand were also analyzed. According to the result, three microcosmic mechanisms of sand retaining and plugging were proposed, concerning fine sand invading and coarse sand bridge, partial sand block, and integrated sand bridge. The plugging permeability performance of screen media generally shows three stages of slow decreasing, rapid increasing and balance. At the balance stage of displacement, the plugging permeability of media sample mostly decreases more than 90%. During the whole test, the sand passing rate tends to slow down gradually, and the final retained sand ratio were more than 85%. Different configurations of sand retraining test show a little difference in plugging performance, depending on the factors of medium type, accuracy, sand characteristics, and flow conditions. Based on the effect of sand retaining and final flow ability observed in these experiments, the sand control in NGH reservoirs with highly argillaceous fine sands is practicable. • Microcosmic retaining and plugging of screen medias by highly argillaceous fine sand in NGH reservoir. • Plugging permeability of screen and the amount of sand production were quantified. • Three microcosmic mechanisms of sand retaining and plugging of screen medias with fine sand from NGH reservoir. [ABSTRACT FROM AUTHOR]

Natural gas hydrate (NGH) is a promising alternative energy resource, whereas marine NGH exploitation suffers from various potential geo-environmental concerns. The existence of a production wellbore not only provides channel for gas extraction, but also causes specific boundary conditions for the occurrence of geo-environmental risks. Almost all kinds of geo-environmental risks during NGH production initiate from time-dependent deformation of the near-wellbore strata. In this paper, the pressuremeter test (PMT) method was firstly introduced to investigate the lateral creep behaviors of the NGH-bearing sediment. The PMT probe was used to apply outwards lateral stress onto the hydrate-bearing sediment to simulate the horizontal stress state of the near-wellbore reservoir during drilling, completion, and/or hydraulic fracturing, during which the pressure inside the wellbore is higher than the reservoirs static pressure. The results indicated that the decelerated creep accounts for more than 70% of the lateral strain before the effective stress reaches the long-term strength. The hardening modulus of the sediment was proven to be increased from the magnitude of ∼102 MPa–∼103 MPa, when the hydrate saturation increases from 2.2% to 50.0%. The PMT creep test results can be used for interpretation of the in-situ horizontal stress and geomechanical parameters such as pro-plastic pressure and ultimate pressure. Based on the fact that PMT test results complies with the previous results from other techniques, a field-applicable PMT technique for NGH reservoir test is suggested to be developed in future study, and a systematic hypothesis and workflow for NGH reservoir modelling is also proposed in this study. • The pressuremeter test was firstly used to characterize creep behaviors of the near-wellbore hydrate-bearing sediment. • Decelerated creep accounts for more than 70% of the lateral strain under relatively low loading stress. • The in-situ horizontal stress and geomechanical properties of HBS could be interpreted via pressuremeter test. • Geomechanical-related techniques are suggested to be incorporated into field survey for marine NGH. [ABSTRACT FROM AUTHOR]

The existence of solid hydrate in porous media always greatly reduces the relative permeability, which limits the development of hydrate reservoirs. Therefore, to recover the gas, it is necessary to carry out reservoir reconstruction measures that induce fractures around the production wells to increase the gas production of hydrate reservoirs. At present, there is limited quantitative research on the promotion of gas production by induced fractures in hydrate reservoirs. In this paper, numerical models of Class Ⅲ hydrate reservoirs with induced fractures are established. By comparing the gas production with and without induced fractures, the effectiveness of induced fractures in promoting the depressurization production of natural gas hydrates is verified. An index of improved efficiency is established and calculated to measure the promotion effect of induced fractures during the fracture promotion stage. The multiple regression calculation formulas of improved efficiency with reservoir geological parameters are obtained by integrating nonlinear regression and linear regression. The calculation model is helpful to quickly and directly measure the rationality and economy of the induced fracture depressurization method to promote hydrate development. • Numerical models of Class Ⅲ hydrate reservoirs with induced fractures are established. • An index of Improved Efficiency is established to measure the promotion effect of induced fractures. • The improved efficiency of induced fractures under different geological parameters is calculated and compared. • The multiple calculation formulas of improved efficiency with geological parameters are obtained by stepwise regression. [ABSTRACT FROM AUTHOR]