Water huff and puff in horizontal wells in tight reservoirs has achieved good results in replenishing formation energy. However, after multiple rounds of treatment, a rapid decrease in formation pressure takes place making it difficult to maintain stable production. To improve the oil recovery rate of tight reservoirs, it is imminent to change the development mode. In this work, the stress distribution characteristics at fracture tips were analyzed based on Irwin theory and elastic theory. A model of propagation and closure length of fractures was established based on the propagation mechanism of water injection-induced natural fracture and the energy balance principle of fracture mechanics. Surfactant imbibition experiments were carried out according to the imbibition principle of surfactant system, and the propagation law of natural fractures was described with numerical simulation to analyze the seepage characteristics of dynamic fracture network. On the basis of the above works, alternating water huff and puff into segmented injection and production was proposed according to the distribution law of dynamic fracture network. The developing process of an actual well case by these two developing modes was simulated to predict 18 years of cumulative recovery, pressure distribution, and recovery rate. Results showed that when stress intensity factor exceeds the fracture toughness, the natural fractures will extend along their original directions and get connected, forming an irregular fracture network. The lengths of fractures after propagation and closure will not bring about water channeling for they are far shorter than well and interval spacing. Surfactant could diminish the resistance of boundary layer by reducing the wetting contact angle, ending up with an improvement in imbibition efficiency. Radial displacement and dynamic imbibition occur simultaneously in a dynamic fracture network during the early stage of water injection, while static imbibition mainly occurs during injection shutdown period and well soaking. According to comparison, the swept area of segmented injection and production was larger, ending up with a continuous increase of simulated recovery rate and cumulative recovery. The findings of this study show alternating water huff and puff after to segmented injection and production in fractured tight reservoir can allow full play of dynamic fracture network’s potential and achieve effective enhancement in oil recovery rate.

Transient behavior analysis, including rate transient analysis (RTA) and pressure transient analysis (PTA), is a powerful tool to investigate the production performance of the vertical commingled well from long-term production data and capture the formation parameters of the multilayer reservoir from transient well testing data. Current transient behavior analysis models hardly consider the effect of vertical non-uniform boundary radii (VNBR) on transient performances (rate decline and pressure response). The VNBR may cause an obvious novel radial flow regime and rate decline type, which can easily be mistaken as a radial composite reservoir. In this paper, we present a VNBR transient behavior analysis model, the extended vertical uniform boundary radii (VUBR), to investigate the rate decline behavior and pressure response characteristics through diagnostic type curves. Results indicate that the dimensionless production integral derivative curve or pressure derivative curve can magnify the differences so that we can diagnose the outer-convex shape and size of the VNBR. Therefore, it is significant to incorporate the effects of VNBR into the transient behavior analysis models of the vertical commingled well, and the model proposed in this paper enables us to better evaluate well performance, capture formation characteristics and diagnose flow regimes based on rate/pressure transient data.

Formation damage usually occurs in near-well regions for injection wells completed in offshore oilfields under the development of line drive patterns. However, current works on characterizing the damage by well test analysis were basically focused on using single-phase analogy to solve two-phase flow issues, resulting in errors on the diagnosis and interpretation of transient pressure data. In this paper, we developed a two-phase model to simulate the pressure transient behavior of a water injection well in a multiwell system. To solve the model more efficiently, we used the finite volume method to discretize partially differential flow equations in a hybrid grid system, including both Cartesian and radial meshes. The fully implicit Newton-Raphson method was also employed to solve the equations in our model. With this methodology, we compared the resulting solutions with a commercial simulator. Our results keep a good agreement with the solutions from the simulator. We then graphed the solutions on a log-log plot and concluded that the effects of transitional zone and interwell interference can be individually identified by analyzing specific flow regimes on the plot. Further, seven scenarios were raised to understand the parameters which dominate the pressure transient behavior of these flow regimes. Finally, we showed a workflow and verified the applicability of our model by demonstrating a case study in a Chinese offshore oilfield. Our model provides a useful tool to reduce errors in the interpretation of pressure transient data derived from injection wells located in a line drive pattern.

Horizontal well multi-stage and multi-cluster fracturing technology has played an important role in unconventional reservoir development. However, traditional methods rarely investigated fracturing fluid flow characteristics in reservoirs with abundant natural fractures. Furthermore, affected by the stress interference from dense number of fracturing clusters, some perforations do not form fractures. For deep shale reservoirs, failure to consider these contents may result in unsatisfactory fracturing results for deep shale reservoirs.An innovative approach is introduced in this paper. This innovation can be based on natural fracture development, fracture propagation law and reservoir composition characteristics. The flow regularity of fracturing fluid inside natural fractures was characterized through CT scanning experiments. Numerical simulation is used to analyze fracture propagation in fracturing horizontal well with multi-stage and multi-cluster. Core full component test experiment was conducted to analyze compressibility. In response to the above results, different fracturing process is adopted, the length of fracturing section is adjusted, the number of fracturing clusters is set. Then the fracturing design scheme of each segment is formulated and the fracturing effect and operation lessons of actual wells are analyzed. The results show that obvious pressure interference between developed section and undeveloped section of natural fracture, fracturing fluid first enters the extended natural fracture and then enters other fractures. Therefore, the temporary plugging of the extended natural fracture weakens its preferential tendency to enter the fluid and ensures the uniform migration of fracturing fluid to each fracture. Numerical simulation shows that some perforations do not form effective fractures, due to stress interference caused by excessive number of perforations. Hence, a fracturing scheme with fewer perforation times is adopted to reduce stress interference and improve the efficiency of perforating fracture formation. The results also observe that the reservoir contains plenty of brittle minerals such as calcite, which is easy to cause fractures. However, high silicon content easily form, extremely irregular fracture. Consequently, the fracturing scheme of shortening the length of fracturing section is adopted to strengthen the control of fracture expansion. The fracturing evaluation of the effect shows that the initial production of the well was 6.59 ×104 m3 with a flowback rate of 15.5%. Microseismic monitoring data shows that the reconstruction volume has increased from the original 9.70 ×104 m3 to 1.06 105 m3, the fracturing effect is remarkable.The conclusion of this research supports for deep shale fracturing design and has a vital practical application significance. Compared with conventional fracturing methods, the fracturing performance is significantly improved results from weakening the advanced fluid tendency of natural fractures, decreasing the stress interference between clusters and strengthening the fracture control.Key words: deep shale; natural fracture; stress interference; brittle mineral content; temporary plugging technology