Through the study of microseismic focal mechanisms, information such as fracture orientation, event magnitude, and in situ stress status can be quantitatively obtained, thus providing a reliable basis for unconventional oil and gas exploration. Most source inversion methods assume that the medium is isotropic. However, hydraulic fracturing is usually conducted in sedimentary rocks, which often exhibit strong anisotropy. Neglecting this anisotropy may cause errors in focal mechanism inversion results. We have developed a microseismic focal mechanism inversion method that considers velocity anisotropy in a vertically transverse isotropic medium. To generate synthetic data, we adopt the moment-tensor model to represent microearthquake sources. We use a staggered-grid finite-difference method to calculate synthetic seismograms in anisotropic media. We perform seismic moment-tensor (SMT) inversion with only P-waves by matching the synthetic and observed waveforms. The synthetic and field data sets are used to test the inversion method. For the field data set, we investigate the inversion stability using randomly selected partial data sets in the calculation. We pay special attention to analyze the sensitivity of the inversion. We test and evaluate the impact of noise in the data and errors in the model parameters (VP0, ε, and δ) on the SMT inversion using synthetic data sets. The results indicate that, for a surface acquisition system, our method can tolerate moderate noise in the data and deviations in the anisotropy parameters can cause errors in the SMT inversion, especially for dip-slip events and the inverted percentages of non-double-couple (DC) components. According to our study, including anisotropy in the model is important to obtain reliable non-DC components of moment tensors for hydraulic fracturing-induced microearthquakes.

During unconventional resources exploration, ignoring shale anisotropy may lead to wrong seismic interpretations, thus affecting the accuracy and credibility of sweet spots prediction and reservoir characterization. In order to investigate the impact of shale anisotropy on the seismic wavefield, we propose a quantitative evaluation method by calculating the waveforms’ amplitude and phase deviations. Based on the 3D elastic wave equation and the staggered-grid finite-difference method, the forward modeling theory with the consideration of shale anisotropy is established. Then, we use the envelope misfit (EM) and phase misfit (PM) parameters to illustrate the differences in waveforms’ amplitude and phase morphology, which are caused by anisotropy. Lastly, by comparing the waveforms of the models with/without anisotropy and calculating their EM and PM values, a practical and quantitative evaluation method is constructed. We used synthetic models of different complexity and oilfield models to validate the proposed method. Through the research, we also gained some new insights about the anisotropy’s effects. For a certain medium model, the impact of shale anisotropy on seismic wavefield is complicated and needs specific analysis. The proposed method provides a useful and quantitative tool for the evaluation of shale anisotropy’s impact.

In unconventional oil and gas development, the hydraulic fracturing (HF) technique is adopted to inject high-pressure fluid into the reservoir and change its pore-fracture connection structure to enhance production. HF causes the rocks to crack and generates microseismic events (with moment magnitudes of $M_{\mathrm{w}}\le 3$). Studying the microseismic focal mechanisms (shear/tensile/compressive HF cracks) is helpful for characterizing fracture geometry, monitoring the in situ stress state, and evaluating the HF effects to optimize the reservoir reconstruction for increasing production. Due to fluid injection activity, there may be non-double-couple (non-DC) mechanisms associated with HF cracks, and the commonly used double-couple (DC) source model may not be suitable. For the moment tensor (MT) source model, which is commonly used to describe the non-DC mechanism, inversion is challenging in single-well monitoring. The shear-tensile general dislocation (GD) model includes a non-DC mechanism, and its inversion is more constrained than the full MT model by specifying the focal mechanism as shear-tensile (or compressive) faulting. This paper reports a focal mechanism inversion case study of HF shear/tensile/compressive cracks in a tight oil reservoir in the Ordos Basin, China. We perform inversions based on the DC, GD, and MT source models, respectively. The results indicate that, for the downhole monitoring geometry in this study, most of the DC inversions fail to obtain proper synthetic and observed waveform fitting results, and the MT inversion results of different microseismic events exhibit worse consistencies than the GD results. According to the GD results, almost all the HF cracks can be explained as strike-slip faulting and most cracks correspond to non-negligible tensile/compressive mechanisms. Our study suggests that the GD source model is preferred in downhole microseismic monitoring to obtain reliable shear/tensile/compressive HF cracks, and the inverted non-zero slope angle reduces the uncertainty in fracturing geometry characterization, which will help improve microseismic studies and HF evaluations for enhanced resource recovery.

Research on the non-double-couple (NDC) components in an earthquake is important for characterizing true source processes. The moment-tensor (MT) source model is commonly used to study NDC earthquakes. However, MT inversions are still challenging when earthquakes have small magnitudes, especially microearthquakes. The general-dislocation (GD) model specifies the focal mechanism as a shear-tensile slip on a fault plane; thus, GD inversion is better constrained than MT inversion. We focus on GD model-based waveform forward modeling and its application to microseismic source inversions. We expand the generalized reflection-transmission matrix method to synthesize waveforms based on the GD model and fully describe a GD source with five parameters: the scalar seismic moment (which defines the magnitude) and the strike, dip, rake, and slope angles (which define the fault geometry). We compare the GD, MT, and double-couple models and introduce the differences in their characterization and wave synthesis theories. We have developed a GD model-based microseismic focal mechanism inversion method that requires calculating only four angles under hybrid constraints. Two sets of solutions correspond to the same seismograms in a GD model-based inversion. These two solutions have the same scalar seismic moment and slope angle but different strike, dip, and rake angles, and we have derived formulas for mapping from one solution to the other. Synthetic and field surface microseismic data sets are used to test our GD model-based modeling and inversion methods. According to our study, the GD model is effective in microseismic focal mechanism inversion. By developing specific wave synthesis and inversion methods for the GD model, we offer a novel perspective to study this model and the NDC mechanisms for hydraulic fracturing-induced microearthquakes.