The sediment of the hydrate reservoir in the Shenhu Area is mainly clayey silt. Its characteristic small particles and poor cementation challenge the quantification of the reservoir permeability during gas production. An accurate description of the seepage mechanism of the clayey-silt reservoir is the basis, and also a difficulty, of effective development of gas in the South China Sea. In this study, four sets of water seepage experiments under different pressure gradients are carried out using the clayey-silt reservoir sediments, in which the fourth sample was subjected to computed tomographic (CT) scans. The experimental results shows that the clayey-silt reservoir has a compression of the pore structure and decreasing permeability with the increasing pressure gradient. CT images are used to show the reduction of pore spaces for fluid flow. When the pressure gradient is less than 3 MPa per meter, the pore structure of the reservoir has minor changes. When the pressure gradient is greater than this value, the pore structure of the reservoir will be quickly compressed. This leads to a rapid decrease in permeability, and the process of permeability reduction is irreversible. The decrease of permeability can be predicted directly by establishing a power law model with the change of porosity. Our experimental results preliminarily reveal the dynamic evolution law of pore structure and permeability of clayey-silt reservoir in the process of gas hydrate exploitation via depressurization. The permeability evolution law at various pressure gradients provides a scientific and reasonable basis of a productivity control system for clayey-silt gas hydrate in depressurized gas production.

In this paper, a simple and efficient fractal-based approach is presented for capturing the effects of initial void ratio on the soil-water characteristic curve (SWCC) in a deformable unsaturated soil. In terms of testing results, the SWCCs (expressed by gravimetric water content) of the unsaturated soils at different initial void ratios were found to be mainly controlled by the air-entry value (Ψ_a), while the fractal dimension (D) could be assumed to be constant. As a result, in contrast to the complexity of existing models, a simple and efficient model with only two parameters (i.e., D and Ψ_a) was established for predicting the SWCC considering the effects of initial void ratio. The procedure for determining the model parameters with clear physical meaning were then elaborated. The applicability and accuracy of the proposed model were well demonstrated by comparing its predictions with four sets of independent experimental data from the tests conducted in current work, as well as the literature on a wide range of soils, including Wuhan Clay, Hefei and Guangxi expansive soil, Saskatchewan silt, and loess. Good agreements were obtained between the experimental data and the model predictions in all of the cases considered.

In this paper, the nuclear magnetic resonance (NMR) technique is applied to exploring the spontaneous imbibition mechanism in tight sandstones under all face open (AFO) boundary conditions, which will benefit a better understanding of spontaneous imbibition during the development of oil & gas in tight formations. The advantages of nuclear magnetic resonance imaging (NMRI) and NMR T₂ are used to define the distribution of remaining oil, evaluate the effect of micro structures on imbibition and predict imbibition recovery. NMR T₂ results show that pore size distributions around two peaks are not only the main oil distributions under saturated condition but also fall within the main imbibition distributions range. Spontaneous imbibition mainly occurs in the first 6 h and then slows down and even ceases. The oil signals in tiny pores stabilize during the early stage of imbibition while the oil signal in large pores keeps fluctuating during the late stage of imbibition. NMRI results demonstrate that spontaneous imbibition is a replacement process starting slowly from the boundaries to the center under AFO and ending with oil-water mixing. Furthermore, the wetting phase can invade the whole core in the first 6 h, which is identical with the main period of imbibition occurring according to NMR T₂ results. Factors influencing the history of oil distribution and saturation differ at different periods, while it is dominated by capillary imbibition at the early stage and allocated by diffusion at later time. Two imbibition recovery curves calculated by NMRI and NMR T₂ are basically consistent, while there still exists some deviations between them as a result of the resolutions of NMRI and NMR T₂. In addition, the heterogeneity of pore size distributions in the two samples aggravates this discrepancy. The work in this paper should prove of great help to better understand the process of the spontaneous imbibition, not only at the macroscopic level but also at the microscopic level, which is significant for oil/gas recovery in tight formations.