Microseismic monitoring is crucial to improving stimulation efficiency of hydraulic fracturing treatment, as well as to mitigating potential induced seismic hazard. We applied an improved matching and locating technique to the downhole microseismic data set during one treatment stage along a horizontal well within the Weiyuan shale gas play inside Sichuan Basin in SW China, resulting in 3,052 well‐located microseismic events. We employed this expanded catalog to investigate the spatiotemporal evolution of the microseismicity in order to constrain migration of the injected fluids and the associated dynamic processes. The microseismicity is generally characterized by two distinctly different clusters, both of which are highly correlated with the injection activity spatially and temporarily. The distant and well‐confined cluster (cluster A) is featured by relatively large‐magnitude events, with ~40 events of M −1 or greater, whereas the cluster in the immediate vicinity of the wellbore (cluster B) includes two apparent lineations of seismicity with a NE‐SW trending, consistent with the predominant orientation of natural fractures. We calculated the b‐value and D‐value, an index of fracture complexity, and found significant differences between the two seismicity clusters. Particularly, the distant cluster showed an extremely low b‐value (~0.47) and D‐value (~1.35). We speculate that the distant cluster is triggered by reactivation of a preexisting critically stressed fault, whereas the two lineations are induced by shear failures of optimally oriented natural fractures associated with fluid diffusion. In both cases, the spatially clustered microseismicity related to hydraulic stimulation is strongly controlled by the preexisting faults and fractures.

We introduce an improved matching and locating technique to detect and locate microseismic events (−4 < ML < 0) associated with hydraulic fracturing treatment. We employ a set of representative master events to act as template waveforms and detect slave events that strongly resemble master events through stacking cross correlograms of both P and S waves between the template waveforms and the continuous records of the monitoring array. Moreover, the residual moveout in the cross correlograms across the array is used to locate slave events relative to the corresponding master event. In addition, P wave polarization constraint is applied to resolve the lateral extent of slave events in the case of unfavorable array configuration. We first demonstrate the detectability and location accuracy of the proposed approach with a pseudo‐synthetic data set. Compared to the matched filter analysis, the proposed approach can significantly enhance detectability at low false alarm rate and yield robust location estimates of very low SNR events, particularly along the vertical direction. Then, we apply the method to a real microseismic data set acquired in the Weiyuan shale reservoir of China in November of 2014. The expanded microseismic catalog provides more easily interpretable spatiotemporal evolution of microseismicity, which is investigated in detail in a companion paper.

Summary This paper examines the potential of huff ’n’ puff gas-injection method to recover condensate in shale gas–condensate reservoirs by conducting experiments on a shale core. Numerical models were developed to verify experiment results. Our laboratory study shows that condensate recovery was increased to 25% by applying huff ’n’ puff gas injection on a shale core. Also, we compared the efficiency of huff ’n’ puff gas injection with that of gasflooding. At the end of same flooding with time that is the same as the time for five huff ’n’ puff cycles, the condensate recovery is 19%. From the experimental results, we found that huff ’n’ puff was more effective than gasflooding. During the experiment, condensate accumulated near the production-end region. In the huff ’n’ puff process, because the location for injection in the core was the same as that for production, the pressure in the condensate region built up faster than pressure in the flooding experiment. Also, because of the ultralow permeability, the pressure propagation was much slower in the shale core than in a conventional reservoir core, and the efficiency of gasflooding is much lower than that of the huff ’n’ puff. This study indicates that huff ’n’ puff has the potential to effectively enhance condensate recovery in shale gas–condensate reservoirs.

Condensate blockage is a serious problem in shale gas condensate reservoirs. As the pressure decreases lower than dew point pressure, condensate forms. This condensate reduces the relative permeability of gas and the productivity of shale gas condensate reservoirs. Huff-n-puff gas injection is an EOR method in which a well alternates between injection, soaking, and production. Based on the laboratory study conducted by Meng et al. (2015), huff-npuff gas injection was proven as an effective method to enhance condensate recovery for Eagle Ford shale cores. In this paper, a numerical reservoir simulation study is conducted to optimize the application of huff-n-puff gas injection in an Eagle Ford shale gas condensate reservoir. During the injection and soaking process, the pressure of the reservoir s built up, the condensate was revaporized to gas, and then was produced during the production process. Different parameters were investigated including injection time, soaking time, production time, and cycle numbers. The results show that huff-n-puff gas injection is an effective method to enhance condensate recovery in the Eagle Ford shale gas condensate reservoir. It was found that the optimum injection time is the time during which the pressure of the main condensate region can be increased higher than dew point pressure. Also, shorter or even no soaking is more effective. The production time depends on the production decline rate. It is more profitable to start another cycle of huff-n-puff gas injection when the production rate is decreased to a low value.

Cyclic gas injection is considered as an effective and quick responding recovery process that has been widely used in the worldwide. Studies showed that cyclic gas injection combined with modern technologies such as horizontal well drilling and hydraulic fracturing has achieved promising results in low permeability formation. Cyclic gas injection technique was introduced in our earlier publication for improving oil recovery in stimulated fractured shale oil reservoirs. In this paper, we focus on the effect of injected gas composition and fracture properties on oil recovery. Different injection gas scenarios such as lean gas, rich gas and CO2 were included in the simulation in order to analyze the EOR mechanisms of vaporizing, condensing or a combined condensing/vaporizing process. Our simulation results indicate that the stimulated natural fractures are critical to enhancing oil recovery and well productivity performance in shale oil reservoirs. Since the interaction of the induced hydraulic fractures with pre-existing natural fractures and fissures makes the hydraulically fractured reservoir modeling very challenging in shale oil/gas reservoirs, we can use a dual-continuum model by making changes to the fracture permeability and intensity to attain a better characterization of the natural fractures. We conclude that cyclic gas injection in shale oil reservoirs employing hydraulically stimulated fractures is feasible to improve substantial amounts of oil production than primary production.