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The Yinggehai Basin is an important Cenozoic gas bearing basin in the South China Sea. With the gradual improvement of gas exploration and over-development in shallow layers, deep overpressured layers have become the main target for natural gas exploration. There are no large-scale faults in the strata above the Meishan Formation in the central depression, and hydraulic fracturing caused by overpressure in mudstone cap rocks is the key factor for the vertical differential distribution of gas. In this paper, based on the leak-off data, pore fluid pressure, and rock mechanics parameters, the Fault Analysis Seal Technology (FAST) method is used to analyze the hydraulic fracture risk of the main mudstones in the central depression. The results show that the blocks in the diapir zone have been subjected to hydraulic fracturing in the Huangliu cap rocks during the whole geological history, and the blocks in the slope zone which is a little distant from the diapirs has a lower overall risk of hydraulic fracture than the diapir zone. In geological history, the cap rocks in slope zone remained closed for a longer time than in diapir zone and being characterized by the hydraulic fracture risk decreases with the distance from the diapirs. These evaluation results are consistent with enrichment of natural gas, which accumulated in both the Yinggehai Formation and Huangliu Formation of the diapir zone, but it only accumulated in the the Huangliu Formations of the slope zone. The most reasonable explanation for the difference of the gas reservoir distribution is that the diapirs promote the development of hydraulic fractures: (1) diapirism transfers deep overpressure to shallow layers; (2) the small fault and fractures induced by diapir activities weakened the cap rock and reduced the critical condition for the natural hydraulic fractures. These effects make the diapir zone more prone to hydraulic fracturing, which are the fundamental reasons for the difference in gas enrichment between the diapir zone and the slope zone.

Understanding geomechanical properties of rocks at multiple scales is critical and relevant in various disciplines including civil, mining, petroleum and geological engineering. Several upscaling frameworks were proposed to model elastic properties of common rock types from micro to macroscale, considering the heterogeneity and anisotropy in the samples. However, direct comparison of the results from different upscaling methods remains limited, which can question their accuracy in laboratory experiments. Extreme heterogeneity of natural rocks that arises from various existing components in them adds complexity to verifying the accuracy of these upscaling methods. Therefore, experimental validation of various upscaling methods is performed by creating simple component materials, which is, in this study, examining the predicted macroscale geomechanical properties of 3D printed rocks. Nanoindentation data were first captured from 3D printed gypsum powder and binder rock fragments followed by, triaxial compression tests on similar cylindrical core plugs to acquire modulus values in micro and macroscale respectively. Mori-Tanaka (MT) scheme, Self-Consistent Scheme (SCS) method and Differential Effective Medium (DEM) theory were used to estimate Young’s modulus in macroscale based on the results of nanoindentation experiments. The comparison demonstrated that M-T and SCS methods would provide us with more comparable results than DEM method. In addition, the potential applications of 3D printed rocks were also discussed regarding rock physics and the geomechanics area in petroleum engineering and geosciences.

Understanding the carbon dioxide (CO2) solubility in formation brines is of great importance to several industrial applications, including CO2 sequestration and some CO2 capture technologies, as well as CO2-based enhanced hydrocarbon recovery methods. Despite years of study, there are few literature data on CO2 solubility for the low salinity range. Thus, in this study, the solubility of CO2 in distilled water and aqueous ionic solutions of NaCl, MgCl2, CaCl2 and MgCl2 + CaCl2 were obtained in a low salinity range (0–15,000 ppm) at temperatures from 298–373 K and pressures up to 20 MPa using an accurate and unconventional method called potentiometric titration. An experimental data set of 553 data points was collected using this method. The results of the experiments demonstrate that increasing pressure increases the solubility of CO2 in various brines, whereas increasing temperature and salinity reduces the solubility. The role of different ions in changing the solubility is elaborated through a detailed discussion on the salting-out effect of different ionic solutions. To verify the experimental results of this research, the solubility points obtained by the potentiometric titration method were compared to some of the well-established experimental and analytical data from the literature and a very good agreement with those was obtained.

Using the conventional fracture parameters is difficult to characterize and predict the complex natural fractures in the tight conglomerate reservoirs. In order to quantify the fracture behaviors, a fractal method was presented in this work. Firstly, the characteristics of fractures were depicted, then the fracture fractal dimensions were calculated using the box-counting method, and finally the geological significance of the fractal method was discussed. Three types of fractures were identified, including intra-gravel fractures, gravel edge fractures and trans-gravel fractures. The calculations show that the fracture fractal dimensions distribute between 1.20 and 1.50 with correlation coefficients being above 0.98. The fracture fractal dimension has exponential correlation with the fracture areal density, porosity and permeability and can therefore be used to quantify the fracture intensity. The apertures of micro-fractures are distributed between 10 μm and 100 μm, while the apertures of macro-fractures are distributed between 50 μm and 200 μm. The areal densities of fractures are distributed between 20.0 m·m−2 and 50.0 m·m−2, with an average of 31.42 m·m−2. The cumulative frequency distribution of both fracture apertures and areal densities follow power law distribution. The fracture parameters at different scales can be predicted by extrapolating these power law distributions.