To identify the type of main flow channels of complex porous media in oil and gas reservoirs, the “main flow channel index” is defined as the ratio of comprehensive permeability obtained from well test to matrix permeability obtained from core analysis or well logging. Meanwhile, a mathematical model is established based on equivalent flow assumption, the classification method for main flow channels is put forward, and quantitative characterization of main flow channels is realized. The method has been verified by analysis of typical gas reservoirs. The study results show that the “main flow channel index” can quantitatively classify types of flow channels. If the index is less than 3, the matrix pore is the main flow channel; if the index is between 3 and 20, the fracture is the main flow channel and the matrix pore acts as the supplement one; if the index is more than 20, the fracture is the only seepage channel. The dynamic analysis of typical gas reservoirs shows that the “main flow channel index” can be used to identify the type of flow channel in complex porous media, guiding the classified development of gas reservoirs, and avoiding development risk.

The gas transport in shale nanopores is always one of the major concerns in terms of the development of shale gas reservoirs. In this study, the gas flow regimes in shale nanopores were classified and analyzed according to Knudsen number. Then the gas flow model considering Darcy flow, slip flow, transition flow, molecular free flow and adsorption effect was proposed to evaluate the gas flow behavior in shale nanopores. The result shows that the contributions of Darcy flow, slip flow and transition flow in shale nanopores are reciprocal, and are mainly dominated by pore radius and pressure. The adsorption effect greatly influences the total mass flux. The total mass flux will increase as Langmuir pressure and temperature increase while it will decrease with reservoir pressure and the adsorption thickness. These results can provide insights for a better understanding of gas flow in the shale nanopores so as to optimize the production performance of shale gas reservoirs.

The estimated ultimate recovery (EUR) of a single shale gas well is one of the important evaluation indicators for the scale and benefit development of shale gas, which is affected by many factors such as geological and engineering, so its accurate prediction is difficult. In order to realize the accurate prediction of ultimate recovery, this study considered 172 shale gas wells in the Weiyuan block as samples and selected 19 geological and engineering factors that affect the ultimate recovery of shale gas wells. Furthermore, eight key controlling factors were selected by means of the Pearson correlation coefficient and maximum mutual information coefficient comprehensive evaluation method. The data were divided into training and testing samples. Different numbers of training samples were selected and seven schemes were designed. Based on the key controlling factors, the ultimate recovery prediction model for shale gas wells in this block was established through multiple regression methods. The effectiveness of the prediction model was verified by analyzing the testing samples. The result shows that with the increase of the size of training samples, the error of the ultimate recovery predicted by the model gradually decreases gradually. When predicting the single gas well, the average absolute error of ultimate recovery is less than 20% if the number of the training gas well is more than 80. When analyzing the development potential of similar blocks without drilling, the error of the sum of ultimate recovery is less than 10% if the size of the training gas well reaches 60.

Three-dimensional (3D) geological property modeling is used to quantitatively characterize various geological attributes in 3D space based on geostatistics with the help of computer visualization technology, and the results are often stored in grid data. The 3D geological property modeling includes two main components, grid model generation and property interpolation. In this review article, the existing grid generation methods are systematically investigated, and both traditional and multiple-point geostatistical algorithms involved in interpolation methods are comprehensively analyzed. It is shown that considering the numerical simulation of oil reservoirs, the orthogonal hexahedral grid remains the most suitable grid model for simulations in petroleum exploration and development. For the interpolation methods aspect, most geological phenomena are nonstationary, to simulate various types of reservoirs; the main development trends are increasing geological constraints and reducing the limitation of stationarity. Both methods have certain constraints, and the multiscale problem of multiple-point geostatistics poses a main challenge to the field. In addition, the deep-learning based method is a new trend in geological property modeling.

As an emerging unconventional energy resource, shale gas has great resource potential and developmental prospects. The effective evaluation of geological sweet spots (GSS), engineering sweet spots (ESS) and comprehensive sweet spots (CSS) is one of the main factors for a high-yield scale and economic production of shale gas. Sweet spot evaluation involves a comprehensive analysis based on multiple parameters. Conventional evaluation methods consider relatively simple or single factors. Although the main influencing factors are understood, the influence of different factors is as of yet unknown, and a comprehensive consideration may strongly affect the evaluation results. In this paper, the fuzzy mathematics method is introduced for shale gas sweet spot evaluation. With the help of fuzzy mathematics tools, such as membership function, the objective of comprehensive sweet spots evaluation based on multiple parameters is realized. Additionally, the reliability of the evaluation of sweet spots is improved. Firstly, previous research results are used for reference, and the evaluation factor system of geological and engineering sweet spots of shale gas is systematically analyzed and established. Then, the basic principle of the fuzzy comprehensive evaluation method is briefly introduced, and a geological engineering integrated shale gas sweet spots evaluation method, based on the fuzzy comprehensive evaluation method, is designed and implemented. Finally, the data from HB blocks in the Z shale gas field in China are adopted. According to the evaluation results, the modified method is tested. The results show that the method proposed in this paper can synthesize a number of evaluation indices, quickly and effectively evaluate the GSS, ESS and CSS in the target area, and the results have high rationality and accuracy, which can effectively assist in well-pattern deployment and fracture design.

Horizontal wells’ multi-section and multi-cluster hydraulic fracturing plays an important role in the efficient development of shale gas. However, the influence of the perforating hole and natural fracture dip angle on the process of hydraulic fracture initiation and propagation has been ignored in the current researches. This paper presents the results related to a tri-axial large-scale hydraulic fracturing experiment under different natural fracture parameters. We discuss the experimental results relating to the near-wellbore tortuosity propagation of hydraulic fractures. Experimental results showed that the triaxial principal stress of the experimental sample was deflected by the natural fracture, which caused significant near-wellbore tortuosity propagation of the hydraulic fractures. The fractures in most rock samples were not perpendicular to the minimum horizontal principal stress after the experiment. As well, the deflection degree of triaxial principal stress direction and the probability of hydraulic fractures near-wellbore tortuosity propagation decreased with the increase of the natural fracture dip angle. After hydraulic fractures’ tortuous propagation, the hydraulic fractures will propagate in the direction controlled by the triaxial stress in the far-wellbore area. For reservoirs with natural fractures, proppant in hydraulic fracturing should be added after the fractures are fully expanded to prevent sand plugging in tortuous fractures. When the permeability of natural fractures is low, the volume of fracturing fluid entering natural fractures is small, and hydraulic fractures are easy to pass through the natural fractures.