Tight sandstone reservoir has been characterized by low permeability and porosity, developed micro-nanopore throats, strong capillary forces, and high content of clay minerals. It is vulnerable to damage caused by water sensitivity during the processes of reservoir development, which significantly impedes the hydrocarbon production. Hence, it is important to analyze the damage mechanism of water sensitivity to avoid the production decrease. However, the conventional steady-state method is time-consuming and inaccurate for evaluating the water-sensitivity damage in tight low-permeability reservoirs. Aiming at this problem, this paper introduced pressure transmission test (PTT), a time-saving and accurate method, to quantitatively evaluate the degree of damage by water sensitivity. Moreover, lithofacies analysis methods, consisting of computed tomography (CT) scanning, scanning electron microscopy (SEM), and X-ray diffraction (XRD), are also used to evaluate the reservoir properties, which can provide a basis for analyzing the potential damage factors. The CT scanning results show that the developed micropore throat in the target reservoirs has poor connectivity. The XRD results indicate that the target reservoir mainly consists of a mixed-layer illite/smectite and smectite, which is consistent with the observation by SEM experiments. The results of PTT show that the ultimate average damage rate of water sensitivity is approximately 62.94%, attributed to the medium-strong water sensitivity. Compared with the conventional steady-state method measuring the outlet flow of the core, this method can reduce the experimental errors merely by recording the pressure data varying with time. Moreover, it is also applicable for evaluating other types of formation sensitivity damage, such as alkali and acid sensitivity damage for low-permeability reservoirs.

In the past decade, significant advances in reservoir stimulation and enhanced oil recovery technologies have resulted in rapid production growth in unconventional reservoirs

The Shunbei oil formation is a deep, high-temperature carbonate reservoir. Acid fracturing is an effective technology to stimulate this formation. For acid fracturing, the temperature field is fundamental information for the acid system selection, acid–rock reaction, live acid penetration distance prediction, acid fracturing design, etc. Therefore, in this paper, we conduct a numerical study on the temperature field in acid fracturing to account for the acid–rock reaction in the Shunbei formation. Firstly, a new mathematical model of the fracture temperature field during acid fracturing is established based on the laws of mass and energy conservation and acid–rock reaction kinetics. The fracture model is based on a PKN model, which accounts for a few factors, such as the acid–rock reaction heat, acid–rock reaction rate dependence on the temperature, and the fracture width change with acid erosion. Then, the numerical mode is developed. Next, an extensive numerical study and a parameter analysis are conducted based on the model with the field data from the Shunbei formation. The study shows that the acid–rock reaction in acid fracturing has obvious effects on the temperature field, resulting in a 10~20 °C increase in the Shunbei formation. The acid–rock reaction dependence on temperature is a factor to be accounted for. The rock dissolution increases first and then decreases from the inlet to the tip of the fracture, unlike the monotonous decrease without temperature dependence. The temperature gradient is high near the inlet and then decreases gradually. Beyond half of the fracture, the temperature is close to the formation temperature. The temperature drops fast in the initial injection stage and tends to stabilize at about 50 min.

Successful matrix acidizing for extremely thick carbonate reservoirs with long horizontal well sections and strong heterogeneity requires efficient temporary plugging and diverting of acid fluid, ensuring acid fluid distribution to each production layer. Foamed-viscoelastic-surfactant (Foamed-VES) acid combines the benefits of both foam acid and viscoelastic surfactant (VES) acid, integrating foam plugging and viscous plugging. It can achieve uniform acid distribution in highly heterogeneous reservoirs. However, little research has been conducted on the wormhole propagation law of foamed-VES acid. To address this gap, this study established a mathematical model of foamed-VES acid wormhole propagation based on the dual-scale model. The model was coupled with a random porosity distribution generated with geological statistical software. The effects of different factors on foamed-VES acid etching were simulated. Numerical results show that foamed-VES acid can stimulate low-permeability reservoirs with a permeability differential of 20. Its inherent mechanism lies in the synergy of foam plugging and VES viscous plugging. This study enhances our understanding of the acid diversion mechanism of foamed-VES acid, providing a theoretical foundation for on-site acidizing treatment.

Multi-stage fracturing of horizontal wells is an indispensable technology to create complex fracture networks, which can unlock production potential and enable commercial productivity for shale gas with low porosity and permeability. Real-time monitoring of fracture networks is essential for adjusting key parameters, mitigating fracturing risks, and achieving optimal fracturing effects. Micro-seismic monitoring technology accurately captures and describes the development of fracture networks by detecting micro-seismic waves generated through rock ruptures, providing valuable insights into the evaluation of post-fracturing. In this study, we first introduced the basic parameters of well X that were obtained by laboratory experiments and logging interpretation, including porosity, gas-bearing properties, mineral composition, rock mechanics, and crustal stress. Then, the hydraulic fracturing scheme was designed on the basis of the geological engineering characteristics of well X. Finally, we conducted a comprehensive analysis of various factors that can affect hydraulic fracturing. This included an examination of the impact of pre-fluid temporary plugging and fracture complexity on the overall effectiveness of the operation. Based on the laboratory experiments and theoretical analysis, the following conclusions can be drawn: (1) fracture size is essentially formed when the fluid strength exceeds 35 m³/m; (2) both preflush with high viscosity and the amount of power sand exceeding 20 cubic meters are conducive to the propagation of fracture height; (3) temporary plugging balls facilitate the balanced propagation of multiple fracture clusters within a stage, whereas temporary plugging particles promote the formation of complex fractures; and (4) geological conditions are a prerequisite for creating a complex network of fractures, and only engineering techniques can facilitate the appropriate enhancement of fracture complexity. This study provides an essential method for the fracturing design of shale gas.