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Continental faulted basins are widely distributed in eastern China. Many of these basins, in which the faults block oil and gas reservoirs, have been explored. The heterogeneity of the reservoirs in fault block is very strong, shich restricts the further efficient development of these kinds of oil and gas fields. In this study, porosity and permeability tests, the use of thin sections of rock, mercury injection experiment and CT scan were used to investigate reservoir quality characteristics and control factors. The results showed that the content of quartz, feldspar, and debris in rock had a significant control function on the quality of the reservoir. Reservoir performance improved with increase of quartz and feldspar content, and worsened with increase of debris content. Taking the Ek1 reservoir in the Wang Guantun area as the specific research object, we developed the following understanding. On the one hand, the main compaction in the study area was mechanical compaction. When the compaction rate was greater than 60%, the porosity and permeability were inversely proportional to the compaction rate. On the other hand, dissolution pores were relatively developed in the study area, and the main types of dissolution were intragranular and intergranular dissolution pores. When the surface porosity of the dissolution pore was over 9.2%, porosity increased significantly the increase of dissolution surface porosity. This showed that dissolution surface porosity had greatly improved the reservoir porosity in this range. [ABSTRACT FROM AUTHOR]

Lacustrine shale, represented by the Middle Permian Lucaogou Formation in the Jimsar Depression in the eastern Junggar Basin, has become one of the main areas of shale oil exploration in China. In this study, we used 137 samples of shale from the Lucaogou Formation, drawn from 14 wells in the Jimsar Depression, to investigate their characteristics of pyrolysis, organic carbon and soluble organic matter content, biomarkers, organic microscopic composition, and vitrinite reflectance. Basin simulation and hydrocarbon generation thermal simulation experiments were also conducted in a closed system. The results of this study indicate that the input of an algae source was dominant in the source rocks of the Lucaogou Formation, that the water in which the rocks were deposited had high salinity and strong reducibility, and that the source rocks were oil-prone. The Lucaogou source rocks generally had good hydrocarbon generation capability, but showed significant heterogeneity. At the end of the Cretaceous period, the shales in the Lucaogou Formation entered the oil-generation window as a whole. Currently, the shales of the Lucaogou Formation are generally in the high-maturity stage in the deep part of the depression, producing a large amount of high-maturity oil and condensate gas, while those in the shallow part have relatively low maturity and can only produce a large amount of conventional crude oil. The maximum crude oil generation rate of the Lucaogou Formation shale obtained from the thermal simulation results was 220.2 mg/g of the total organic carbon (TOC), and the maximum hydrocarbon expulsion efficiency was estimated to be 59.3–76.4%. [ABSTRACT FROM AUTHOR]

Seismic wave exhibits the characteristics of anisotropy and attenuation while propagating through the fluid-bearing fractured or layered reservoirs, such as fractured carbonate and shale bearing oil or gas. We derive a linearized reflection coefficient that simultaneously considers the effects of anisotropy and attenuation caused by fractures and fluids. Focusing on the low attenuated transversely isotropic medium with a vertical symmetry axis (Q-VTI) medium, we first express the complex stiffness tensors based on the perturbation theory and the linear constant Q model at an arbitrary reference frequency, and then we derive the linearized approximate reflection coefficient of P to P wave. It decouples the P- and S-wave inverse quality factors, and Thomsen-style attenuation-anisotropic parameters from complex P- and S-wave velocity and complex Thomsen anisotropic parameters. By evaluating the reflection coefficients around the solution point of the interface of two models, we analyze the characteristics of reflection coefficient vary with the incident angle and frequency and the effects of different Thomsen anisotropic parameters and attenuation factors. Moreover, we realize the simultaneous inversion of all parameters in the equation using an actual well log as a model. We conclude that the derived reflection coefficient may provide a theoretical tool for the seismic wave forward modeling, and again it can be implemented to predict the reservoir properties of fractures and fluids based on diverse inversion methods of seismic data. [ABSTRACT FROM AUTHOR]