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Gypsum rocks have extremely low permeability and good pressure sealing capability, and they are widely distributed in different strata all over the world. A deep-thick gypsum cap rock is developed in the Paleogene formation of the southwestern Tarim Basin in China. The regions below the gypsum rocks have huge potential for oil and gas resources. Casing deformation and blockage during tripping operations often occur during the drilling process in the gypsum bed, which severely affects the efficient drilling of deep oil and gas. Therefore, it is necessary to comprehensively assess the geostress field of gypsum cap rocks under high-stress background conditions. Through triaxial synchronized mechanical and acoustic testing experiments, high-stress formation environments were simulated and the mechanical parameters of gypsum rocks were obtained. We used dispersion correction technology to transform the measured high-frequency (1 MHz) wave velocities of the samples to the wave velocities of well-logging frequency (20 kHz). The transformed wave velocities can be used for the well-logging assessment of rock mechanical parameters and geostress. We built well-logging interpretation models for the shear-wave slowness, mechanical parameters and geostress of the Paleogene gypsum rocks. Each model showed high assessment accuracy. Combined with the paleomagnetic analysis of the Paleogene gypsum bed and the results of the fast shear-wave direction analysis, radial expansion position analysis and induced fracture analysis on the reservoir below the Paleogene gypsum bed, we suggest that the direction of geostress in the study region is NW10°. Three-dimensional finite element method was used to simulate the geostress field of the gypsum bed. The Paleogene formation in the study region does not have faults. The geostress distribution of the gypsum rock layer is mainly controlled by structural relief, burial depth, and lithology. This study provided a typical example of a comprehensive assessment of the geostress field of deep-thick gypsum cap rocks. [ABSTRACT FROM AUTHOR]

Deep marine tight sandstone oil reservoirs are the subject of considerable research around the world. This type of reservoir is difficult to develop due to its low porosity, low permeability, strong heterogeneity and anisotropy. A marine tight sandstone oil reservoir is present in the Silurian strata in the northern Tazhong area of the Tarim Basin, NW China, at a depth of more than 5000 m. The porosity is between 6% and 8%, and the gas permeability is between 0.1 and 1 × 10 −3 μm 2 . The features of this type of reservoir include the poor effects of conventional fracturing modifications and horizontal wells, which can lead to stable and low levels of production after staged fracturing. Here, we conduct a comprehensive evaluation of the mechanical properties of the rock and the in situ stress of the target tight sandstones by using numerous mechanical and acoustic property tests, conducing crustal stress analysis and using data from thin section observations. The dispersion correction technique is used to transform velocity at the experimental high frequency (1 MHz) to velocity at the logging frequency (20 kHz). The logging interpretation models of the transverse wave offset time, mechanical parameters and in situ stress are calculated, and each model represents a high precision prediction. Simulating the in situ stress field of the Silurian strata using a three-dimensional finite element method demonstrates that the average error between the simulation result and the measured value is less than 6%. The planar distribution of each principal stress is mainly controlled by the burial depth and fault distribution. By conducting in situ stress orientation analysis for the target layer via the analysis of paleomagnetism, borehole enlargement, fast shear wave orientation and stress field simulation, we show that the direction of the maximum horizontal stress is N45E. In this paper, a typical and successful comprehensive evaluation of the stress field of the deep tight sandstone oil reservoir is provided. [ABSTRACT FROM AUTHOR]

The heterogeneity of tight carbonate rocks is directly related to the morphology of micropores and the connectivity of the pore network, which have a great influence on the intrinsic microporosity and fluid flow properties of porous media. However, neither can be quantitatively evaluated by conventional techniques. Based on core observation and thin section analysis, combined with high-resolution field emission-scanning electron microscopy (FE-SEM) and mercury injection capillary pressure (MICP) measurements, we can identify carbonate rock types, determine the microporosity and microstructure and calculate the pore structure parameters. Digital image analysis (DIA) and the fractal dimension (FD) method are used to study the relationship between the quantified pore structure parameters, heterogeneity and fluid flow properties. The results indicate that rock types in 12 carbonate samples are dominated by grainstone and packstone, followed by wackestone and dolomitic packstone. The microporosity of rock types has various microstructure characteristics. Crystalline types of microporosity (the small and large intercrystalline pores) increase pore network connectivity whereas micromoldic pores show variations in connectivity of different lithofacies. However, the small intercrystalline pores contribute little to the permeability because of narrow and complex pore networks for fluid flow. MICP data of samples reveal that these samples are relatively tight with low porosity (avg. 3.7%) and permeability (avg. 0.452mD). The pore-throat radius mainly ranges from 0.1 μm to 1.0 μm, which contributes the highest proportion of permeability to the samples. Fractal dimensions calculated from the “J-curve” models vary between 2.0746 and 2.8551 (avg. 2.331), indicating high heterogeneity. Moreover, the fractal dimension is strongly negatively related to the permeability, average pore throat radius and separation coefficient. Additionally, quantified pore geometric parameters from DIA, including dominant pore size (DOMsize), perimeter over area (PoA), pore body-to-throat ratio (BTR) and average roundness (γ a ), greatly influence the pore structure and fluid flow behavior. The samples with large DOMsize, high γ a , low PoA and low BTR show a low fractal dimension and simple pore network but high permeability. Diagenesis can also affect the fractal pore space and self-similarity pore geometries of carbonates across all length scales. This information about the micropore geometry and microstructure of the carbonate rock will further improve the assessment of its reservoir properties. [ABSTRACT FROM AUTHOR]