Search Results (6)

The low-velocity non-Darcy effect within the shale matrix significantly influences the well production performance of shale reservoirs, primarily caused by the threshold pressure gradient identified by various researchers. Moreover, in inter-salt shale reservoirs, salt minerals dissolve and diffuse when they encounter water-based working fluids, resulting in substantial alterations in pore structure. This paper introduces a transient pressure model for inter-salt shale oil reservoirs that accounts for oil flow from formation to the wellbore, considering all of the aforementioned mechanisms. The partial differential equations of this dual-porosity model, which incorporate salt dissolution and the low-velocity non-Darcy effect in the shale matrix, are derived. An accurate solution is achieved through the application of Laplace transformation and Green’s functions. We derive the analytical solutions for transient pressure and production in real space by employing the Stehfest numerical inversion method and obtain the bi-logarithmic type curves. Six distinct flow regimes are identified, and the impacts of salt dissolution, the threshold pressure gradient, the cross-flow coefficient, and the storativity ratio are discussed. This analysis holds significant importance for evaluating fluid flow and transport in inter-salt shale oil reservoirs. Full article

Hydraulic fracture morphology and propagation mode are difficult to predict in layers of the various lithological strata, which seriously affects exploitation efficiency. This paper studies the fundamental mechanical and microscopic properties of the two main interfaces in inter-salt shale reservoirs. On this basis, cement-salt combination samples with composite interfaces are prepared, and hydraulic fracturing tests are carried out under different fluid velocities, viscosity, and stress conditions. The result shows that the shale bedding and salt-shale interface are the main geological interfaces of the inter-salt shale reservoir. The former is filled with salt, and the average tensile strength is 0.42 MPa, c = 1.473 MPa, and φ = 19.00°. The latter is well cemented, and the interface strength is greater than that of shale bedding, with c = 2.373MPa and φ = 26.15°. There are three basic fracture modes for the samples with compound interfaces. Low-viscosity fracturing fluid and high-viscosity fracturing fluid tend to open the internal bedding interface and produce a single longitudinal crack, respectively, so properly selecting the viscosity and displacement is necessary. Excessive geostress differences will aggravate the strain incompatibility of the interface between different rock properties, which makes the interfaces open easily. The pump pressure curves’ morphological characters are different with different failure modes. Full article

Oil flow in inter-salt shale oil reservoirs is different from that of other oil fields due to its high salt content. Dissolution and diffusion occur when the salt minerals meet the water-based working fluid, resulting in drastic changes in the shale’s permeability. In addition, ignoring the stress-sensitive effect will cause significant errors in naturally fractured reservoirs for a large number of the natural fractures developed in shales. This study presents a transient pressure behavior model for a multi-stage fractured horizontal well (MFHW) in inter-salt shale oil reservoirs, considering the dissolution of salt and the stress sensitivity mentioned above. The analytical solution of our model was obtained by applying the methods of Pedrosa’s linearization, the perturbation technique and Laplace transformation. The transient pressure of a multi-stage fractured horizontal well in an inter-salt shale oil reservoir was obtained in real space by using the method of Stehfest’s numerical inversion. The bi-logarithmic-type curves thus obtained reflected the characteristics of the transient pressure behavior of a MFHW for the inter-salt shale oil reservoirs, and eight flow periods were recognized in the type curves. The effects of salt dissolution, stress sensitivity, the storativity ratio and other parameters on the type curves were analyzed thoroughly, which is of great significance for understanding the transient flow behavior of inter-salt shale oil reservoirs. Full article

In response to the difficulty of fracture modification in inter-salt shale reservoirs and the unknown pattern of hydraulic fracture expansion, corresponding physical model experiments were conducted to systematically study the effects of fracturing fluid viscosity, ground stress and pumping displacement on hydraulic fracture expansion, and the latest supercritical ${\mathrm{CO}}_2$ fracturing fluid was introduced. The test results show the following. (1) The hydraulic fractures turn and expand when they encounter the weak surface of the laminae. The fracture pressure gradually increases with the increase in fracturing fluid viscosity, while the fracture pressure of supercritical ${\mathrm{CO}}_2$ is the largest and the fracture width is significantly lower than the other two fracturing fluids due to the high permeability and poor sand-carrying property. (2) Compared with the other two conventional fracturing fluids, under the condition of supercritical ${\mathrm{CO}}_2$ fracturing fluid, the increase in ground stress leads to the increase in inter-salt. (3) Compared with the other two conventional fracturing fluids, under the conditions of supercritical ${\mathrm{CO}}_2$ fracturing fluid, the fracture toughness of shale increases, the fracture pressure increases, and the fracture network complexity decreases as well. (4) With the increase in pumping displacement, the fracture network complexity increases, while the increase in the displacement of supercritical ${\mathrm{CO}}_2$ due to high permeability leads to the rapid penetration of inter-salt shale hydraulic fractures to the surface of the specimen to form a pressure relief zone; it is difficult to create more fractures with the continued injection of the fracturing fluid, and the fracture network complexity decreases instead. Full article

Pore structure is the key factor affecting reservoir accumulation and enrichment behavior. Due to the complex mineral components and pore structure of shale oil reservoirs and strong heterogeneity, it is necessary to explore the micro-pore structure characteristics of inter-salt shale. In this study, in order to qualitatively and quantitatively analyze the pore structure of inter-salt shale reservoirs, as well as evaluate the mineral composition and its spatial distribution characteristics, three shale samples from the 10th cyclothem of the Eq3 (Eq3⁴–10 cyclothem) inter-salt shale were selected to acquire 2D and 3D grayscale images by modular automated processing system (MAPS) and X-ray micro-computed tomography (Micro-CT), respectively. The color map of the inlaid characteristics of mineral aggregates was established by Quantitative Evaluation of Minerals by Scanning Electron Microscopy (QEMSCAN), and different mineral types in the grayscale image were determined. After that, the digital core technology was used to reconstruct the core in 3D, and the maximum sphere method was used to extract the pore network model, so as to realize the quantification of micron pore throats and the 3D visualization of inter-shale samples. Meanwhile, in order to compare the fractal characteristics of the pores of the samples, the two-dimensional and three-dimensional fractal dimensions of the three cores were calculated by combining the digital core technique with fractal theory. The study yielded several notable results: the pore structure of inter-salt shale reservoirs is complex and multi-scale, and the CT scanning digital core technology can effectively realize 3D visualization of rock microstructure without damage. The pore types of rock samples are mainly intergranular pores, interparticle pores, and dissolved pores, and the minerals are mainly dolomite, calcite, and glauberite. The micron pore throat radius of the rock sample is 0.5–13.9 μm, the distribution of coordination number is mainly in the range of 1–4, and the shape of the pore throat is mainly triangular and square. The pore space of inter-salt shale has suitable fractal characteristics, and the three-dimensional fractal dimension of the three cores is in the range of 2.41–2.49. In sum, this work used digital core technology to study the microscopic pore structure of inter-salt shale oil, establishing a basis for further understanding of the seepage characteristics and exploration and development of shale oil. Full article

Some inter-salt shale reservoirs have high oil saturations but the soluble salts in their complex lithology pose considerable challenges to their production. Low-field nuclear magnetic resonance (NMR) has been widely used in evaluating physical properties, fluid characteristics, and fluid saturation of conventional oil and gas reservoirs as well as common shale reservoirs. However, the fluid distribution analysis and fluid saturation calculations in inter-salt shale based on NMR results have not been investigated because of existing technical difficulties. Herein, to explore the fluid distribution patterns and movable oil saturation of the inter-salt shale, a specific experimental scheme was designed which is based on the joint adaptation of multi-state saturation, multi-temperature heating, and NMR measurements. This novel approach was applied to the inter-salt shale core samples from the Qianjiang Sag of the Jianghan Basin in China. The experiments were conducted using two sets of inter-salt shale samples, namely cylindrical and powder samples. Additionally, by comparing the one-dimensional (1D) and two-dimensional (2D) NMR results of these samples in oil-saturated and octamethylcyclotetrasiloxane-saturated states, the distributions of free movable oil and water were obtained. Meanwhile, the distributions of the free residual oil, adsorbed oil, and kerogen in the samples were obtained by comparing the 2D NMR T₁-T₂ maps of the original samples with the sample heated to five different temperatures of 80, 200, 350, 450, and 600 °C. This research puts forward a 2D NMR identification graph for fluid components in the inter-salt shale reservoirs. Our experimental scheme effectively solves the problems of fluid composition distribution and movable oil saturation calculation in the study area, which is of notable importance for subsequent exploration and production practices. Full article