Gulong shale oil reservoir is rich in resources, high in clay minerals, and densely developed bedding fractures. Generally, reverse composite volume fracturing technology is used to establish oil and gas flowing channel, in which slickwater is beneficial to opening bedding fractures and improving the complexity of artificial fractures. The microscopic damage and adaptability research of slickwater on reservoir are of great significance for improving fracturing effect. This paper take the microscopic damage and adaptability of slickwater to Gulong shale reservoir as research object. Micro damage experiments of five kinds of slickwater were conducted to research the micro damage and adaptability of slickwater to Gulong shale reservoir. The results of nuclear magnetic resonance and CT analysis show that the binding degree of type B, C, and E slickwater is small, the pore damage is small, the total porosity increases greatly, and the number of fractures increases, which is conducive to the fracturing fluid backflow. The scanning electron microscope analysis results show that the chemical element adsorption of type B and E slickwater is relatively light, pore filling is not serious, element migration is prominent, and intergranular pores increase. Comprehensive analysis shows that type B and E slickwater have good adaptability to Gulong shale oil reservoir. The research results are of great significance to the optimization of hydraulic fracturing fluids for the Gulong shale, the identification of the characteristics of pore throat damage caused by fracturing fluids, and the adaptability of fracturing fluid to reservoirs, which are conducive to improving the effectiveness of reservoir stimulation.

In situ-generated acid is commonly employed in ultra-deep, high-temperature carbonate reservoirs during acid fracturing to increase the effective acid penetration distance. However, the variation pattern of acid-etched fracture conductivity with in situ-generated acid has not been systematically studied. This paper investigates the evolution of the conductivity of primary and secondary fractures through a series of experiments involving in situ acid displacement and acid-etched fracture conductivity measurement. Based on the experimental results, a calculation model for the conductivity of acid-etched fractures with in situ-generated acid was established. The study indicates that after acid etching, rough particulate points and grooved dissolution patterns form on the surfaces of primary and secondary fractures, respectively. The dissolution volume in primary fractures is greater than that in secondary fractures, with both showing a linear increase over time. Due to the presence of dissolution grooves on the surfaces of secondary fractures, their conductivity is higher than that of primary fractures under the same acid–rock contact time. The conductivity of both primary and secondary fractures increases with the acid–rock contact time. However, beyond approximately 70 min of contact time, the conductivity of primary fractures shows no significant increase. The conductivity of primary and secondary fractures with in situ-generated acid is slightly lower than that with gelled acid under the same contact time, but significantly higher than that with crosslinked acid. This study provides guidance for the design and parameter optimization of acid fracturing in ultra-deep, high-temperature carbonate reservoirs.

The global shale gas resources are huge and have good development prospects, but shale is mainly composed of nanoscale pores, which have the characteristics of low porosity and low permeability. Horizontal drilling and volume fracturing techniques have become the effective means for developing the shale reservoirs. However, a large amount of mining data indicate that the fracturing fluid trapped in the reservoir will inevitably cause hydration interaction between water and rock. On the one hand, the intrusion of fracturing fluid into the formation causes cracks to expand, which is conducive to the formation of complex fracture networks; on the other hand, the intrusion of fracturing fluid into the formation causes the volume expansion of clay minerals, resulting in liquid-phase trap damage. At present, the determination of well closure time is mainly based on experience without theoretical guidance. Therefore, how to effectively play the positive role of shale hydration while minimizing its negative effects is the key to optimizing the well closure time after fracturing. This paper first analyzes the shale pore characteristics of organic pores, clay pores, and brittle mineral pores, and the multi-pore self-absorption model of shale is established. Then, combined with the distribution characteristics of shale hydraulic fracturing fluid in the reservoir, the calculation model of backflow rate and shut-in time is established. Finally, the model is validated and applied with an experiment and example well. The research results show that the self-imbibition rate increases with the increase in self-imbibition time, and the flowback rate decreases with the increase in self-imbibition time. The self-imbibition of slick water is the maximum, the self-imbibition of breaking fluid is the minimum, and the self-imbibition of mixed fluid is the middle, and the backflow rates of these three liquids are in reverse order. It is recommended the shut-in time of Longmaxi Formation shale is 17 days according to the hydration and infiltration model.

The change of fracture propagation direction caused by stress interference between fractures is one of the main reasons that affect shale gas productivity. Natural fractures will be damaged by the induced stress, and the induced stress field produced by natural fracture damage will in turn affect the propagation of hydraulic fractures. Previous studies usually ignored the impact of stress field variation caused by natural fracture damage, leading to inaccurate fracture propagation simulation results. A new model for simulating hydraulic fracturing-induced stress field is established with consideration of the influence of natural fracture damage. Then, the natural fracture-induced stress is analyzed in open and closed fracture states. Through superposition of stress fields of natural fractures and hydraulic fractures, the interaction among open and closed natural fractures, reservoir and hydraulic fracture, and the corresponding fracture property evolution are studied. The results demonstrate that induced stress is not affected by elastic modulus and Poisson's ratio of the rock. The induced stress difference at the fracture tip is proportional to the net pressure and the length of hydraulic fractures. The results provide guidance for the optimal design of fracturing. When the deflection angle of hydraulic fracture is less than 90°, the maximum induced stress difference at the fracture tip decreases with the reduction in the deflection angle. When the deflection angle of hydraulic fracture is smaller than 90° or the deflection angle of natural fracture is smaller than 45°, the steering of hydraulic fracture is less hindered, which is beneficial to the formation of complex fracture network.

For tight reservoirs, horizontal wells and multi-stage fracturing can generate a complex fracture network that realizes economic and effective development. The volume and complexity of the fracture network are of great significance to accurately predicting the productivity of tight oil wells. In this work, a mathematical model of a multiphase flow is proposed to evaluate the stimulation effect based on the early flowback data. The model showing the early slope of the material balance time (MBT) and production balance pressure (RNP) can help estimate the effective stimulated volume of the horizontal well. The linear flow region can be determined from the slope of the log–log plot of the MBT versus RNP curve, which equals 1. The method is verified by commercial simulation software, and the calculated stimulated volume is consistent with the statistical results of simulation results. Results also show that the flow pattern of the fracture–matrix system can be judged by the slope of the flowback characteristic curve in the early stage of flowback, and then the complexity of the fracture network can also be obtained. The proposed method can provide an avenue to evaluate the fracturing work using the flowback data quickly.

Distributions of pore pressure and water saturation in matrix around fractures after hydraulic fracturing and shut-in period will impact the shale gas well production significantly. However, the influences of hydraulic fracturing and shut-in period on pore pressure and water saturation are not considered in the classical reservoir simulations. In this work, the embedded discrete fracture model (EDFM), which is convenient to be coupled with an existing reservoir simulator with high computational efficiency, was employed to simulate the hydraulic fracture propagation coupled with matrix flow. Then, we developed a model for simulating the integration process of hydraulic fracturing, shut-in period, and well production based on the dual media theory. Distributions of pore pressure and water saturation varying in different periods and the production decline of shale gas well were obtained through the integrated simulation model. The calculation result was validated by the field bottom hole pressure data of a shale gas well in Sichuan Province, China. Simulation results show that the variation of bottom hole pressure is not smooth during the fracture propagation process because the initiations of different fractures are not simultaneous. The fracturing fluid flow-back rate of shale gas well is much lower than that of conventional reservoirs. There is still a large amount of fracturing fluid retained in micro-fracture systems and matrix of shale after production. It is also found that the permeability of the micro-fracture system determines the drop rate of bottom hole pressure and the size of stimulated reservoir volume (SRV) determines the decrease amplitude of bottom hole pressure.

The concentration of CO2 in the global atmosphere, which is increasingly annually with continued industrial development, affects both the global climate and the ecological environment. To control the concentration of atmospheric CO2, various methods of carbon capture and sequestration have been proposed and continue to be developed. Among them, CO2 sequestration in saline aquifers has potential for effective high-capacity carbon storage. This work reviews both the research status of structural, residual, solubility, and mineral CO2 sequestration in saline aquifers, and the research progress associated with the integrity of cement sheaths and caprocks. The findings indicate that structural sequestration research must comprehensively consider the influence of various factors, and that the capacity of structural sequestration must be evaluated based on the actual geological conditions of the saline aquifer, caprock properties, and CO2 injection rate. The heterogeneity of the caprock and dynamic changes of CO2 concentration are not considered in current simulations of the effect of chemical interaction between CO2 rich brine and the caprock. Residual sequestration and solubility sequestration are mutually interactive; therefore, exploration of the residual sequestration mechanism must consider the impact of solubility sequestration. Models for simulation of CO2 solubility sequestration in an entire saline aquifer should be developed to reservoir scale and must consider reservoir heterogeneity. (C) 2022 Sichuan Petroleum Administration. Publishing services by Elsevier B.V. on behalf of KeAi Communication Co. Ltd.

The volume fracturing technology along with horizontal well is the main technology to obtain commercial oil flow in shale reservoirs because of the low porosity and low permeability. Whether the fracturing fluid has the potential of shale matrix imbibition oil recovery after a large amount of slickwater injected into the reservoir is a research hotspot at present. Therefore, it is of great significance to study the law of imbibition and replacement during the shut-in time. Aiming at the Jimsar area, there are several steps in this study in order to explore the new law of fracturing fluid imbibition and oil recovery in shale reservoirs. Primarily, the distribution of pressure and saturation during fracturing time and shut-in time is accurately described by the numerical simulation method. Furthermore, the sensitivity analysis is carried out from two aspects of geological and fracture factors. Eventually, the evaluation of optimal shut-in time is taken by imbibition replacement balance. According to the numerical simulation results, the pressure diffuses rapidly among the matrix during the shut-in time in the hydrophilic reservoir. After 65 days of well shut-in, the whole reservoir tends to be at the same pressure and reaches the equilibrium of imbibition replacement. Contrarily, the pressure of the lipophilic reservoir diffuses slowly and only propagates in the secondary fracture or the matrix near the fractures. The fracture system remains a “high-pressure area” for a long time during shut-in. Additionally, the optimal shut-in time chart of different geological parameters and fracture parameters is drawn to optimize the shut-in time. This research work has a certain reference value for the optimization of shut-in time after fracturing in Jimsar and similar shale oil wells.

The fractures and vugs of the carbonate reservoirs in the Tarim Basin, China, have good prospects for exploration and development. However, the carbonate reservoirs of Tarim basin are characterized by the different scale, large regional differences and strong heterogeneity, which result in the big difficulties in logging identification. Types and characteristics of fractured-vuggy carbonate reservoirs can be visually and clearly identified by core and imaging log data the, but the cost of acquisition is high and the data are few. Conventional logging is low in cost and widely used. It is currently the key research direction to identify different reservoir types of carbonate rocks by using conventional logging data. Factor analysis (FA) is a multivariate statistical method that integrates variables with complex relationships into a few independent factors to achieve information enrichment. It can reflect the relationship between the original variables and the factors, and each factor is highly explanatory. At present, there are relatively few studies on logging identification of fractured-vuggy carbonate reservoirs by factor analysis. The fractures and caverns of the carbonate reservoirs in the second section of the Lianglitage Formation in the eastern part of the Tazhong area are developed, and the reservoir types are diverse and heterogeneous. Various reservoir types can be clearly identified on core and imaging logging, but it is difficult to identify in the absence of core and imaging logging data, which affects reservoir prediction and evaluation. In order to solve this problem, four reservoir types and two non-reservoir types are divided based on core, thin sections and image logging data. The reservoir types include fractured reservoir, vuggy reservoir, fractured-vuggy reservoir and cavern reservoir, and non-reservoir types include mud fillied non-reservoir and compact non-reservoir. According to these types, the conventional logging information is calibrated. Three principal factors are extracted from the six well logging parameters (GR、AC、REN、CNL、RD and∣RD/RS－1∣) by FA, which are interpreted as pore factors, fracture factors and mud factors. Finally, the factor score is calculated, and various reservoir and non-reservoir types can be effectively identified according to the factor score cross-plots. This method is used to identify the reservoir of XX well, and has high consistence with the core and imaging logging data.