Integration of Microseismic Data and an Unconventional Fracture Modeling Tool to Generate the Hydraulically Induced Fracture Network: A Case Study From the Cardium Formation, West Central Alberta, Canada
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Cited by 4 publications
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Microseismic monitoring of hydraulic fracturing in unconventional reservoirs is a valuable tool for delineating the effectiveness of stimulations, completions, and overall field development. Important information, such as fracture azimuth, fracture length, height growth, staging effectiveness, and many other geometric parameters, can typically be determined from good quality data sets. In addition, there are parameters now being extracted from microseismic data sets, or correlated with microseismic data, to infer other properties of the stimulation/completion system, such as stimulated reservoir volume (SRV), discrete fracture networks (DFNs), structural effects, proppant placement, permeability, fracture opening and closure, geohazards, and others. Much of the information obtained in this way is based on solid geomechanical or seismological principles, but some of it is speculative as well.This paper reviews published data where microseismic results have been validated by experiments using some type of ground-truth or alternative measurement procedure, discusses the geomechanics and seismological mechanisms that can be reasonably considered in evaluating the likelihood of inferring given properties, and appraises the uncertainties associated with monitoring and the effect on any inferences about fracture behavior. Considerable data now exist from tiltmeters, fiber-optic sensing, tracers, pressure sensors, multi-well-pad experiments, and production interference that can be used to aid the validation assessment.Relatively limited microseismic results have actually been validated in any consistent manner. Fracture azimuth from microseismic has been verified across a wide range of reservoir types using multiple techniques. Good validation of fracture length and height were performed in sandstones for planar fractures; fracture length and height in typical horizontal completions with multiple fractures or complexity have a lesser degree of verification. Other parameters, such as complexity, discrete fracture networks, source parameters, and SRV, have little supporting evidence to provide validation, even though they might have sound physical principles underlying their application. It is clear that microseismic monitoring would benefit from more attention to validation testing. In many cases, the data might be available but have not been used for validation purposes, or such results have not been published.
Microseismic monitoring of hydraulic fracturing in unconventional reservoirs is a valuable tool for delineating the effectiveness of stimulations, completions, and overall field development. Important information, such as fracture azimuth, fracture length, height growth, staging effectiveness, and many other geometric parameters, can typically be determined from good quality data sets. In addition, there are parameters now being extracted from microseismic data sets, or correlated with microseismic data, to infer other properties of the stimulation/completion system, such as stimulated reservoir volume (SRV), discrete fracture networks (DFNs), structural effects, proppant placement, permeability, fracture opening and closure, geohazards, and others. Much of the information obtained in this way is based on solid geomechanical or seismological principles, but some of it is speculative as well.This paper reviews published data where microseismic results have been validated by experiments using some type of ground-truth or alternative measurement procedure, discusses the geomechanics and seismological mechanisms that can be reasonably considered in evaluating the likelihood of inferring given properties, and appraises the uncertainties associated with monitoring and the effect on any inferences about fracture behavior. Considerable data now exist from tiltmeters, fiber-optic sensing, tracers, pressure sensors, multi-well-pad experiments, and production interference that can be used to aid the validation assessment.Relatively limited microseismic results have actually been validated in any consistent manner. Fracture azimuth from microseismic has been verified across a wide range of reservoir types using multiple techniques. Good validation of fracture length and height were performed in sandstones for planar fractures; fracture length and height in typical horizontal completions with multiple fractures or complexity have a lesser degree of verification. Other parameters, such as complexity, discrete fracture networks, source parameters, and SRV, have little supporting evidence to provide validation, even though they might have sound physical principles underlying their application. It is clear that microseismic monitoring would benefit from more attention to validation testing. In many cases, the data might be available but have not been used for validation purposes, or such results have not been published.
Understanding the created fracture geometry is key to the effectiveness of any stimulation program, as fracture surface area directly impacts production performance. Microseismic monitoring of hydraulic stimulations can provide in real-time extensive diagnostic information on fracture development and geometry. Thus, it can help with the immediate needs of optimizing the stimulation program for production performance and long-term concerns associated to field development. However, microseismic monitoring is often underutilized at the expense of productivity in the exploration and appraisal phases of a field. Geology is a fundamental element in the design of a stimulation program and the interpretation of its results. Rock properties and geomechanics govern the achievable fracture geometry and influence the type of fluids to be injected in the formation and the pumping schedule. Rock layering controls the location of the monitoring device, guides the depth at which perforations should be located, and influences how hydrocarbons flow within the formation. Despite this importance, the impact geology may have on the stimulation results is often overlooked as it is all too common to see assumed laterally homogeneous formations, invariant stress field (both laterally and vertically), stimulated fractures having a symmetric planar geometry, etc. As exploration and appraisal moves toward active tectonics areas (as opposed to relatively quiet passive margins and depositional basins), understanding the impact of complex geology and the stress field on fracture geometry is critical to optimizing stimulation treatments and establishing robust field development plans. Mapping of hypocenters detected using microseismic monitoring is an ideal tool to help understand near- and far-field fracture geometry. Additionally, moment tensor inversion performed on mapped hypocenters can contribute to understanding the rock failure mechanisms and help with evaluating asymmetric and complex fracture geometry. Understanding this fracture complexity helps address key uncertainties such as achievable fracture coverage of the reservoir. We present the results of several hydraulic fracture stimulations in various geological environments that have been monitored using microseismic data. We illustrate with these case studies that in some rare cases, simple radial and planar fracture system (often mislabeled penny shape-like fracture) may be generated as predicted using simple modeling techniques. However, in most cases, the final fracture system geometry is complex and asymmetric, largely governed by stress, geologic discontinuities, rock fabric, etc. Understanding this impact and optimizing the well design to enhance productivity is key to evaluating reservoir potential and commercial viability during exploration and appraisal phases and for maximizing return on investment during development.
Geomechanics plays a significant role in hydraulic fracture initiation and propagation and in the interaction between hydraulic fractures and natural fractures, especially in unconventional reservoirs. This paper provides a detailed description of a geomechanical characterization and modeling study for evaluating the impact of geomechanics on completions and hydraulic fracturing stimulations optimization in the Montney resource play, Canada. Following an integrated workflow, 1D mechanical earth models (MEM) for ten wells were constructed in the study area. These 1D MEMs include elastic and strength properties, pore pressure, direction and magnitude of in-situ stresses. Extensive rock mechanics core testing data were used to calibrate the elastic and strength properties. Pore pressure and fracture closure pressure data from diagnostic fracture injection tests were also available to calibrate pore pressure and minimum in-situ stress. Maximum horizontal stress was constrained by modeling wellbore stability and matching it with caliper logs and wellbore stability features on wellbore image. A 3D mechanical earth model was subsequently constructed using a 3D geological model, the 1D MEMs, and seismic inversion data. Elastic properties from seismic inversion were used to populate mechanical properties in the 3D model. In-situ stresses were numerically simulated to account for the impact of faults and structural and mechanical property variation on in-situ stress distribution. The geomechanical analysis shows that there is a decreasing trend in Young’s modulus from upper Montney to lower Montney while Poisson’s ratio is relatively constant in the Montney. The pore pressure in some parts of the field is high and varies across the field. Stress regime is predominantly strike-slip with relatively large stress anisotropy, and this has implications on the hydraulic fracture network that would be simulated, shearing of natural fractures and the stimulated reservoir volume. Rock elastic and strength properties, pore pressure, and in-situ stresses were found to be heterogenous across the whole field. The relatively large variation in pore pressure in the study area and the structural complexities have large impact on the distribution of stresses. Faults alter the stress distribution locally and could affect hydraulic fracture propagation. Hydraulic fracture simulations were subsequently performed, and the geometry of the simulated hydraulic fractures and the stimulated reservoir volume were validated with microseismic events. The effects of geomechanics on fracture geometry and ultimately reservoir production were evaluated. Because of the significant impact of geomechanics on hydraulic fracturing, it is critical to characterize and model geomechanics accurately. This paper provides a comprehensive approach and application to a field in the Montney, showcasing the integrated method of geomechanical characterization and hydraulic fracture simulation and production modeling using various data. The analysis provides an interrelationship among geomechanical parameters, microseismicity and stimulated reservoir volume.
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