A Practical Guide to Interpreting Microseismic Measurements
- Craig L. Cipolla (Schlumberger) | Mark Gavin Mack (Schlumberger) | Shawn C. Maxwell (Schlumberger) | Robert C. Downie (Schlumberger)
- Document ID
- Society of Petroleum Engineers
- North American Unconventional Gas Conference and Exhibition, 14-16 June, The Woodlands, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2011. Society of Petroleum Engineers
- 1.8 Formation Damage, 2.5.1 Fracture design and containment, 2 Well Completion, 5.1.2 Faults and Fracture Characterisation, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 4.1.5 Processing Equipment, 7.6.2 Data Integration, 4.3.4 Scale, 1.2.2 Geomechanics, 5.2 Reservoir Fluid Dynamics, 5.1.5 Geologic Modeling, 3 Production and Well Operations, 4.1.2 Separation and Treating, 2.4.3 Sand/Solids Control, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.1.8 Seismic Modelling, 5.1.7 Seismic Processing and Interpretation, 1.10 Drilling Equipment, 2.2.2 Perforating, 5.5 Reservoir Simulation, 1.2.3 Rock properties, 5.8.2 Shale Gas, 5.8.1 Tight Gas, 5.1 Reservoir Characterisation
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Thousands of hydraulic fracture treatments have been monitored in the past ten years using microseismic mapping, providing a wealth of measurements that show a surprising degree of diversity in event patterns. Interpreting the microseismic data to determine the geometry and complexity of hydraulic fractures continues to be focused on visualization of the event patterns and qualitative estimates of the "stimulated volume??, which has led to wide variations and inconsistencies in interpretations.
Comparing the energy input during a hydraulic fracture treatment and resultant energy released by microseismic events demonstrates that the seismic deformation is a very small portion of the total deformation. The vast majority of the energy is consumed in aseismic deformation (tensile opening) and fluid friction (Maxwell et al. 2008). Proper interpretation of microseismic measurements should account for both seismic and aseismic deformation, coupling the geomechanics of fracture opening and propagation with the shear failures that generate microseisms.
Interpretation of microseismic measurements begins with an evaluation of location uncertainty, using signal-to-noise ratios and error ellipsoids, along with event moment magnitude. In some cases, microseismic event location uncertainty is erroneously interpreted as fracture complexity. The next step is to normalize the data and correct for observation well bias, both distance and azimuth, including use of seismic radiation patterns. Without these corrections fracture behavior from well to well or stage to stage (especially in horizontal wells) can easily be misinterpreted. Advanced geophysical processing that describes the failure mechanisms in more detail may also aid in the interpretation. The final step in the interpretation is to include the geomechanics of the overall process, accounting for the fracture treatment volumes injected, the net pressure in the hydraulic fracture(s) and the shear failures that generated the microseisms. This final, critical step is often overlooked when interpreting microseismic measurements. The paper provides a comprehensive, yet practical guide to the interpretation of microseismic measurements.
The introduction of microseismic hydraulic fracture monitoring (MSM) has added immensely to our understanding of fracture propagation, especially in unconventional reservoirs such as gas shale (Fisher et al. 2002; Maxwell et al. 2002; Maxwell et al. 2008; Daniels et al. 2007; Le Calvez et al. 2007; King et.al. 2008; King 2010; Warpinski et al. 2008; Vincent 2009; and Waters et al. 2009). MSM is the most widely used technology to measure hydraulic fracture geometry because it provides the most complete picture of hydraulic fracture growth. Microseismic monitoring, which is a straightforward application of earthquake seismological principles, consists of the detection, location, and further analysis of extremely small seismic events induced by the fracturing process (Albright and Pearson 1982; House 1987). Fig. 1 illustrates the basic principles of MSM. Typically, arrays of multiple receivers are positioned over a 300 to 1,000 ft (~100m to 300m) vertical interval in a single nearby offset well. The microseismic events are usually not detectable as discrete events at the surface but only from other wellbores within about 3,000 ft (~900m) of the fracture treatment well.
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