Abstracts ESG Solutions 2015-2016 For more information, please contact Melissa Hoy, Technical Marketing Coordinator at melissa.hoy@esgsolutions.com Visit us online at www.esgsolutions.com Abstract #1 Fracture size scaling of hydraulic fracture stimulations in shale reservoirs It is becoming widely evident that hydraulic fracture stimulations in shale reservoirs can result in the generation of events with magnitudes M>0. These events are of concern to the public as potential geohazards possibly affecting groundwater conditions and surface infra-structure, and to engineers for optimizing productivity and engineering design. Typically, in these environments, recording bandwidth limitations has resulted in a bias towards the consideration of events with M<0. This in turn has limited the observable fracture sizes to those constrained within lithologic units. By extending the recording bandwidth to lower frequencies, the dimensions of the observable fractures are also extended to include larger fractures/faults activated during the stimulation. Our observations suggest that these larger scale events contribute upwards of 80% of the overall seismic budget or energy release associated with the stimulation process. Effective analysis of scaling relations independent of recording further suggests that a breakdown in scaling can be related to the presence of barriers to growth such as contrasts in rock properties associated with different lithologic units. Generally, detected larger magnitude events are associated with smaller magnitude events, M < 0, suggesting that these events can be used to characterize aspects of the rupture process, whereas their associated signals observed with the low frequency network can be used to characterize the overall fracture/fault behavior. By accounting for the presence of larger events, additional activated fracture surface area within the reservoir results in a significant increase in surface area. In an example provided, these events account for a further ~10 km 2 of additional activated fracture surface area than estimated based on using only high-frequency-based microseismic recordings. Overall, the identification of the actual discrete fracture network over many size scales allows for a better understanding of the fracturing processes and size scaling associated with stimulations and their impact on production. Abstract #2 A Decade Monitoring Shale Gas Plays Using Microseismicity: Advances in the Understanding of Hydraulic Fracturing Over the past decade, microseismic monitoring has become the most widely used approach to understand of in-situ reservoir behavior during hydraulic fracture stimulations. From early monitoring performed in the Barnett Shale to current programs in the Horn River and Marcellus formations, we review the evolution of microseismic monitoring from the viewpoint of data collection (single versus
multi-well array configurations, use of long lateral stimulation wells), data analysis and the incorporation of microseismic parameters to constrain and validate reservoir models. We conclude with a look at multi-array microseismic results from hydraulic fracture stimulations of various North American shale plays to illustrate how microseismic analysis has aided in the understanding of reservoir characteristics and in turn, helped to plan more effective stimulation programs. We highlight case studies where microseismic monitoring was used to help assess fracture dimensions, stage spacing and well spacing. In addition, we look at how the use of advanced analysis techniques such as seismic moment tensor inversion (SMTI) has helped propel the industry forward and allowed operators to gain a better estimate of the stimulated reservoir volume, the discrete fracture network and the effective fluid flow by understanding details on individual rupture mechanisms and how these mechanisms change depending on treatment program, local stresses and local geology. Abstract #3 Microseismic event growth and interaction with local geology across multiple horizons of the Permian Basin Marc Prince, Senior Seismologist, ESG Solutions As operators in the Permian Basin continue to focus on unconventional plays including the Wolfcamp, Bone Spring, Spraberry and Cline, geoscientists working in the region are increasingly using geological and geophysical data to optimize drilling and completions strategies in an effort to maximize well productivity. Microseismic monitoring is one such geophysical tool that provides operators with a wealth of feedback on the nature of fracture stimulations in these formations. By characterizing and evaluating factors such as fracture containment, lithological characteristics, geomechanical properties, stress regimes and distribution of natural fractures, an opportunity exists to apply learnings to design more effective stimulation programs. New developments in advanced microseismic analysis designed to better understand in-situ reservoir behavior are also emerging with considerable success. Here we present results from numerous case studies throughout the Permian basin and demonstrate how operators are using these results to evaluate wellbore spacing, compare completions parameters, characterize out-of-zone growth and understand stress release in order to optimize subsequent treatments. The introduction of new sensor deployment strategies have also shed light on the relationship between hydraulic fracture stimulation and fault activation in other north American unconventional formations and may provide similar benefit to operators in the Permian. Evaluation of critically stressed fractures or faults in the vicinity of target production zones may have implications for estimates of reservoir deformation or communication across lithological boundaries. Understanding the nature of faultrelated induced seismicity and their relationship to the injection processes is critical to define the potential for out-of-zone growth, but also to understand the role that larger-scale fractures play with respect to the dynamics of the reservoir. Abstract #4 Real Time Automated Alarm System for Long Term Reservoir Monitoring of Induced Seismicity The process and benefits of implementing a real time alarm system as an emergency response system for induced seismicity of long term reservoir monitoring are described. Example case studies are considered for long term reservoir cyclic steam injection operations. The primary goal of the automatic
alarm system is to address responsible operation and environmental compliance, and hazard risk. This includes evaluating out-of-zone growth, maintaining caprock integrity, well casing failures, clustering of seismicity and identifying unknown faults or nearby structures. Seismicity is alerted based on a real-time system via automated email alerts. The alerts are based on specified depth constraints: critical depth (red alert), intermediate depth (yellow alert) and low depth (green alert). The alarm system will alert on the occurrence of seismicity within the pre-determined depth criteria and on other specified constraints such as moment magnitude and apparent stress. The critical alert signifies the occurrence of seismicity above the caprock and signals the operator to cease injections until further investigation. Intermediate alert signifies the occurrence of seismicity just below the caprock and signals a warning that injections rates may need to be reduced. Low depth alert signifies the occurrence of seismicity at reservoir depth and injection may continue. There are three stages to the real time alarm system: (A) Classification, (B) Auto Location, and (C) Alert that will be described in detail. A cross correlation technique is used to correlate incoming seismicity with catalogued waveforms such as noise, electrical and surface signals. The email alert notifies the operator of the alert level, the time and location of the event, the moment magnitude and the closest observation array. Two case studies on long term reservoir monitoring examine additional features of implementing a clustering alert and a casing failure alert in two different geological regions. Future directions may involve integrating waveform characteristics and analysis of source parameters to provide a more robust alarm system to better understand the dynamics of shallow seismicity from deeper seismicity. Abstract #5 The Influence of Mesh Size on Fracture Network Growth Microseismic analysis is used to determine event locations, event strength, stress and energy release, and relative fracture lengths. Additionally, fracture orientations are calculated using Seismic Moment Tensor Inversion. These microseismic observables are used together with the detailed hydraulic fracture treatment data to identify several dynamic changes in the growth of the discrete fracture network. In this example, we identify a preferred fracture set that is consistent with the regional stress and easily activated throughout the treatment program. A secondary fracture set is also observered but is only temporarily activated by increases in mesh size. Abrupt changes in failure type were linked to changes in the treatment program, such as mesh size, providing insight into the role and effectiveness of both fluid and proppant on extending the connected DFN. Finally, the spatiotemporal distribution of microseismic events indicates local variations in geology and/or stress that act as potential barriers to growth, reducing the overall effectiveness of the treatment program. Combining advanced microseismic analysis with detailed treatment data reveals several important changes in the dynamic growth of the discrete fracture network and allows for the identification of the key treatment parameters responsible for them. Transient changes in fracture orientation and event distribution are observed in response to the change in proppant size and indicates that proppant may play an important role in helping to activate additional fracture sets, thereby increasing the connectivity and efficiency of the overall discrete fracture network.
Abstract #6 Characterizing the Dynamic Growth of a Fracture Network At the most basic level microseismic analysis reveals the position of events and a snapshot of what is happening at any given time. Some events are directly related to the injection of fluid/proppant and others are due to changes in the far-field stress. Both the engineering (treatment) parameters and the stress field are dynamic and a great deal of information can be obtained by considering the spatiotemporal dynamics of the processes involved. With the start of hydraulic fracturing microseismic events occur at increasing distance from the perf zone and mimic a diffusive dynamic process. The introduction of proppant increases event rates further from the perf zone as well as localized events behind the extending frac. Generally, the total lateral extent of growth and the success of a hydraulic fracture depends on the characteristics of the rock formation, the pre-existing fracture network, the treatment program, and the physics of hydraulic fracturing. In this paper, we use microseimic data to characterize the evolution of deformation over time. This moves beyond conventional static interpretations to reveal important processes influencing the dynamic expansion of a fracture network. We introduce a new parameterization that considers the diffusivity of the observed microseismicity which can be related to the ease in which the inelastic seismic deformation field can diffuse (Difusivity Index), the degree of deformation for a given stress and therefore the susceptibility to fracturing (Fracability Index), the ratio of viscous to elastic forces which represents the ease with which the reservoir deforms in response to fluid injection (Softening Index) and the identification of areas where fluid connectivity is hindered by fracture and stress complexity (Stress Index). Our observations suggest that the Fracability Index reveals regions of low deformation and high stress associated with potential barriers to flow. The Softening Index correlates well with the Fracability Index and can be used to differentiate hard regions behaving elastically from soft regions that show more plastic deformation. Further, heterogeneity in the Diffusivity Index can be related to the advancement of the frac whereas the Stress Index indicates stimulation extent, revealing differences between dry and wet fractures. Our observations suggest that microseismicity can be used to differentiate hard regions behaving elastically from soft regions that show more plastic deformation. Abstract #7 Shearing vs Shear-tensile Failures in Unconventional Plays and Their Potential Impact on Stimulation Effectiveness Sheri Bowman-Young and Ted Urbancic, ESG Solutions Microseismic monitoring has been a well-established practice in the hydraulic fracturing industry for over a decade now, allowing operators to determine event (fracture) locations, magnitudes and to estimate the relative geometry of the fractured zone. The increase in multi-well pads has increased the information that can be obtained from microseismic monitoring by providing the opportunity for multiarray monitoring. With multiple monitoring arrays, the coverage of the events radiation patterns is robust enough to enable the calculation of failure characteristics, such as fracture orientation and principal strain/stress axes, through moment tensor inversion of microseimic signals.
The moment tensor of an event is a representation of the mechanism responsible for the observed radiation of seismic energy; in other words, it defines the mode of failure that caused the microseismic event. Seismic moment tensor inversion (SMTI) is the process by which these mechanisms are determined and can be obtained for an event that has a high signal to noise ratio observed on multiple arrays and with sufficient volumetric coverage around the source to allow for a unique solution to be determined. By inverting for the failure mechanisms of these events, we can distinguish between tensile crack opening (increase of volume), tensile crack closing (loss of volume) or shear (pure slip on a plane) fractures as well as previously mentioned, the orientation of these fracture planes. The orientation of the fracture planes can be used to assess the fracture network and to distinguish between activation of natural fractures and new fractures being created. In our study we compare microseismic results from various hydraulic fracture stimulations, including examples from the Permian, where the array configuration allowed for SMTI to be performed on the events. Through these examples, we will show how differing geological settings combined with differing completion programs resulted in very different fracture behaviour. In most cases, injection results in the activation of pre-existing fractures, however, the modes of failure appear to be site/geologically different. In some sites, failures are dominated by sub-vertical shear-tensile failures, exhibiting both opening and closing during different injection intervals, whereas as other sites exhibit vertical shearing with little to no tensile behaviour. These differences are reflected in the calculated enhanced fluid flow rates (or relative permeability values) and thereby may be an indication of the stimulation effectiveness or in-effectiveness.