Passive seismic imaging of subsurface natural fractures: application to Marcellus shale microseismic data

Abstract

Imaging and characterizing subsurface natural fractures that are common in the Earth crust has been a long-sought goal in seismology. We present an application of a 3-D passive seismic fracture imaging method applied to Marcellus shale microseismic data for mapping natural fractures. Unlike conventional seismic imaging methods that need source information, the proposed imaging method does not require source information and is flexible enough to apply to any passive seismic data where the source location is unknown or inaccurate. We first test our imaging approach using surface microseismic monitoring array data in 3-D synthetic examples. The finite-aperture fractures are designed by an open-source discrete fracture network software. Compared to conventional source-dependent fracture imaging, the proposed source-independent imaging approach produces superior images of fractures with less ambiguity. These tests also illustrate that the proposed method is less sensitive to the accuracy of background velocity and less affected by the sparse and irregular acquisition geometry which often cause acquisition-footprint issues in convention imaging methods. The final test in the field microseismic data from the Marcellus Shale (Pennsylvania) demonstrates the applicability of the proposed imaging method. Field data results indicate two clusters of east-northeast fractures existed above and below the hydraulic fracturing zone, which corroborates previous work that found two main types of faults in the study area.

Passive seismic imaging of subwavelength natural fractures: theory and 2-D synthetic and ultrasonic data tests

“…In this study, I incorporated the subwavelength fractures (1 m scale) in the models and I limited myself in 2-D to comprise the efficiency and limited computational resources. In a companion paper (Huang & Zhu 2018), we present realistic 3-D synthetic tests to study the source-receiver geometry effects on the fracture imaging and also results from a field microseismic data test.…”

Source‐Independent Passive Seismic Reverse‐Time Structure Imaging With Grouping Imaging Condition: Method and Application to Microseismic Events Induced by Hydraulic Fracturing

“…When wavefield is back‐propagated, transmitted wave and its associated converted wave (or reflected wave and its associated converted wave) simultaneously arrive at the conversion points. Therefore, it is possible to image the locations of impedance changes by utilizing the coherence between transmitted and converted waves (or reflected wave and its converted wave) (Huang & Zhu, ; Shabelansky, ; Shang et al, , ; Xiao & Leaney, ; Zhu, ). For the source‐independent elastic reverse‐time imaging using converted waves, it includes three steps: back‐propagation of the elastic wavefield, separation of the P and S wavefields, and application of the proper imaging condition.…”

“…Similar concepts have also been applied to teleseismic waveforms to image the Moho discontinuity (Shang et al, , ). Instead of using converted waves, transmitted and scattered waves can also be used for imaging the fractures with passive seismic waveforms by taking advantage of the coherence between them (Huang & Zhu, ; Zhu, ; Zhu & Sun, ). This concept has been successfully tested on both synthetic and real data sets with surface and downhole geophones.…”

Recent Advances and Challenges of Waveform‐Based Seismic Location Methods at Multiple Scales

“…In this method, no source information is required, and zero‐lag cross correlations of the back‐propagated direct and scattered wavefields are used to image the scatters and fractures. Numerical examples and an ultrasonic data set have indicated the approach's improved performance in imaging fractures compared to standard RTM, while a field microseismic data from the Marcellus Shale demonstrated the feasibility of the proposed method in imaging subsurface natural fractures (T. Zhu, ; Huang & Zhu, ).…”

“…In addition, in the context of microseismic monitoring, it is difficult to obtain an accurate tomographic model due to the poor coverage of the receiver arrays (e.g., downhole monitoring) or a limited number of well‐located microseismic events (Bardainne & Gaucher, ). Reservoir imaging using passive seismic data and seismic migration techniques can help resolve field‐scale velocity variations, and this emerging area still faces many challenges (Grechka et al, ; Huang & Zhu, , see Section ). The relative location method (Fitch, ; Spence, ) has been demonstrated to be an effective alternative method, which can compensate the implicit velocity errors and anomalies and create correct relative location of the located events.…”