Using Moment Tensors To Determine the Effectiveness of Hydraulic Fracture Stage Spacing
- Marc Prince (Engineering Seismology Group Canada Inc. ESG) | Adam Baig (ESG Engineering Seismology Group) | Theodore I. Urbancic (ESG) | Katherine Buckingham (Engineering Seismology Group Canada Inc. ESG) | Alice Guest (ESG Solutions)
- 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
- 5.1.1 Exploration, Development, Structural Geology, 3 Production and Well Operations, 5.8.2 Shale Gas, 1.6 Drilling Operations, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.8.1 Tight Gas, 2.2.2 Perforating, 4.1.2 Separation and Treating
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Hydraulic fracturing is performed in tight gas shales in order to create extensive fracture networks throughout the reservoir. Often the distance between injection zones is selected in order to maximize the fracturing of the reservoir and minimize the amount of reservoir that remains untreated. Recently, the deployment of three dimensionally distributed geophone arrays allows for Seismic Moment Tensor Inversion (SMTI). Using SMTI, the rock failure mechanisms can be examined both spatially and temporally, showing how the hydraulic fracture treatments interact with each other.
When events from a hydraulic fracture stage grow into previously fractured zone, there are three possible interactions: the fracture network in the previously fractured zone can dialate; the fracture network in the previously fractured zone can experience equal opening and closing result in little to no increase the effective fracture network; or the previously activated fracture network can experience more closure than opening, resulting in reduced productivity in the reservoir. One parameter that can be calculated from the SMTI is the cumulative volumetric strain which provides a parameter that reflects whether the fracture network is dominantly opening or closing over the course of the injection program.
In this study, we examined microseismicty from three stages of a multistage hydraulic fracture treatment in a shale gas reservoir in North America. The SMTI analysis is performed and failure mechanisms are calculated for events over the course of three subsequent stages. From the failure mechanisms, the cumulative volumetric strain is calculated and plotted versus time over the duration of each of the stages. For each of the three stages, the cumulative volumetric strain is compared and the dominant fracture state (opening or closing) is determined. The results suggest that interconnectivity of the hydraulic fracture treatments is complex and can lead to increases or decreases in the effective fracture network.
In hydraulic fracturing, shale gas formations are injected with fluid above reservoir pressure in order to create fracture networks that increase permeability and hydrocarbon recoverability from the reservoir. In many cases, sets of long horizontal parallel wells are drilled and completed with multiple adjacent injection zones or "perforation zones??. Ultimately, the goal of most hydraulic fracturing programs is to extensively fracture the reservoir while minimizing the deformation above and below the treatment zone. In previous studies the interaction of the fracture networks from adjacent injection zones is observed but not often understood. In many cases, the stages are placed relatively close to each other so that the stimulated reservoir volumes of the individual stages overlap. In these cases it is thought that the closely spaced injection zones will interact and fracture density and hydraulic conductivity of the reservoir will increase in between the wells as shown theoretically by Mayerhofer et al. (2008). They concluded that fracturing in the reservoir can be increased if the stress is increased from simultaneously growing opposing fractures.
Often, microseismic monitoring is used to evaluate the effectiveness of the hydraulic fracturing program. In general, microseismic monitoring provides information on the growth of the hydraulic fracture both spatially and temporally. Additional seismic parameters, such as moment magnitude and apparent stress, can be determined from the recorded waveforms. Although these parameters can be used to qualify the effectiveness of the hydraulic fracturing program, they do not completely describe the complexity of fracture growth patterns. To address this question, calculation of the seismic moment tensor is performed to determine the orientation of the fracture plane and it size, and whether or not the fracture is increasing or decreasing volumetrically (opening and closing). This analysis can be performed both spatially and temporally allowing for analysis of the interaction of the various adjacent hydraulic fracture stages. In this study, we show how microseismic data can be used to study the interaction of the individual stages during hydraulic fracturing and determine if the close placement of the stages is indeed improving the fracture density and hydraulic conductivity.
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