ABSTRACT: Continuous microseismic monitoring was carried out around 9 producing longwall top coal caving (LTCC) panels with concurrently recorded daily face advance rates at Coal Mine Velenje in Slovenia over a 27-month monitoring period. The monitoring results suggested that spatial and magnitude characteristics of microseismicity are dominated by those of underlying fractures, while microseismic event rate is under the combined effects of local natural fracture abundance and mining intensity. On this basis, a data-driven yet physics-based forecasting methodology was established for LTCC induced hazardous microseismicity, which is above a given threshold of energy magnitude and within a certain distance to the longwall face. Statistical analyses were first conducted to characterise temporal, magnitude and spatial characteristics of long-term recorded microseismicity, based on which a short-term forecasting model was developed to calculate the probability of hazardous microseismicity considering the three characteristics. The model developed was employed to forecast the likelihood of hazardous microseismicity at one of these LTCC panels, and the forecasted results were supported by the monitoring. This statistical model has important implications in the evaluation of mining-induced hazards, and it can be used to optimise longwall face advance rates to minimise the risk of hazardous microseismicity in burst-prone deep-level mining sites.

ABSTRACT: The Hydraulic Fracturing Field Test (HFTS) project, fielded within the Wolfcamp Formation in the Permian Basin, provides an excellent opportunity to further develop our understanding of the geomechanical response to hydraulic stimulation and associated fluid transport in shale lithologies. In addition to a full set of geophysical and tracer observations, the project obtained core samples from wells drilled through the stimulated region, characterizing the propagation of fractures, reactivation of pre-existing natural fractures, and placement of proppant. We present our analysis of the HFTS using the GEOS code. In this preliminary phase, we focus upon the response to stimulation of a single stage in the Middle Wolfcamp Formation. Our results emphasize the importance of accounting for preexisting natural fractures in predicting the stimulated volume. The combination of published data we assembled to construct the preliminary geological model can serve as a resource for other practitioners seeking to validate models against the HFTS observations. We also discuss future work that will address interactions between wells within the same and differing zones, along with microscale investigations into the influence of bedding upon fracture height growth.

ABSTRACT: By examining the collective behavior of microseismicity using Dynamic Parameter Analysis (DPA) the stress response associated with the hydraulic stimulation in the Midland Basin, Texas for stacked wells are examined to understand the critical role of stress and the potential for well performance as identified through increased stimulated surface area accessible for production. Based on our observations, a clear demarcation in stress behavior is observed based on treatment order, the ability of different formations to dissipate load, and the relative distance to the treatment zone itself. The role of pre-fractured and depleted zones are also examined and their effect on observed stress behavior is identified. By integrating DPA with operational influences, such as stimulation order, the potential exists for identifying the occurrence of enhanced slip of previously stimulated fractures leading to increased production. In low permeability targets with negligible leakoff rates, we suggest that fluid and proppant stresses can push the stimulated fabric into a critically stressed region. With continued stress loading, the local stress regime within depleted reservoirs appear to be perturbed and cause fractures to reactivate under stress. In our study this resulted in enhanced production associated with increased activation of surfaces in the upper treatment zone.

ABSTRACT: Mining-induced microseismicity has been extensively used to evaluate the potential for rock bursts and coal and gas outbursts in underground coal mines. In a research project completed a few years ago, it was observed that characteristics of microseismicity around a longwall working panel were fairly consistent over the monitoring period until a heterogeneous zone with a relatively high coal strength was reached. The current research presented in this paper aims at achieving a better understanding of the effect of heterogeneity on microseismic activity in longwall coal mining. A microseismicity modelling approach which combines deterministic stress and failure analysis together with a stochastic fracture slip evaluation was used to simulate the evolution of microseismicity induced by the progressive face advance passing through a heterogeneous zone. The heterogeneous zone was taken into account by varying the material strength of the elements within the high strength zone and the fracture attributes within this zone. Results have shown that both the high rock strength of coal lithotype and low fracture intensity within this zone contribute to the decrease in seismic event counts, and that the increase in energy released results from the combined effects of increased stress drops and slipped fracture sizes when the high strength zone is approached.

ABSTRACT: The concept of Stimulated Reservoir Volume (SRV) has spawned numerous reservoir engineering models to approximate the production mechanisms associated with complex hydraulic fractures and to facilitate production modeling and well performance evaluations.

ABSTRACT: Hydraulic fracturing induced microseismicity is often attributed to pore pressure changes alone thereby neglecting the role of elastic stress perturbations due to fracture opening. Here we show how fracture opening affects the in situ elastic stresses and the pore pressure diffusion profiles, and subsequently potential of shear slippages along pre-existing fault planes. We compute the Coulomb failure function for a stationary hydraulic fracture by combining the elastic stress perturbations due to opening of the fracture and the pore pressure changes due to fluid diffusion in the surrounding rock. Results show that for a fixed length of hydraulic fracture, the first events in time occur near the crack tip region where the Coulomb stress changes are positive due to elastic stress perturbations. The pore pressure diffusion subsequently leads to microseismic events near the fracture face where elastic stress perturbations have a stabilizing effect. Thus the elastic stress changes ahead of the crack tip due to fracture opening facilitate failure and this process affects the spatio-temporal distributions of microseismicity.

Abstract: The state of field stresses is an important factor in the design and execution of hydraulic fracturing treatments. The absolute and relative magnitudes of horizontal stresses directly affect the minimum treatment horsepower requirement and the final stimulation pattern. While the minimum horizontal stress (s hmin ) can be directly measured by a mini-frac or a leakoff test, there is no direct means to measure the magnitude of maximum horizontal stress (s Hmax ). In this paper, we introduce a new method for determination of s Hmax direction and magnitude from microseismic focal mechanisms induced by hydraulic fracturing treatments. The focal mechanisms that meet a certain criterion are used to first determine the s Hmax direction. Knowing the direction of horizontal stresses, the reference coordinate system of principal stresses is formed by assuming the vertical stress as a principal stress. The normalized magnitude of s Hmax is then calculated for each qualifying focal mechanism as a function of normalized s Hmin magnitude. The undisturbed s Hmax magnitude is estimated by interpretation of calculated s Hamx magnitudes for all focal mechanisms. The method was used to estimate direction and magnitude of s Hmax for two projects in the Marcellus Shale, located approximately 30 miles away from one another. Introduction The state of stress in a formation can be characterized by direction and magnitude of the three principal stresses. For close-to-surface projects, where undisturbed rock is accessible, techniques such as over-coring, flat jack test, hydraulic fracturing, and borehole slotter (Jaeger et al., 2008, Amadei and Stephansson, 1997) can be used to measure the stress magnitudes at the study region. In the case of unconventional reservoirs, however, access to the undisturbed rock is very limited, and most conventional stress measurement techniques cannot be applied. A common assumption in these cases is that the vertical stress is a principal stress whose magnitude is determined by calculating the weight of overburden rock from density logs. This assumption holds true in most cases, considering the high depth of unconventional reservoirs, except for cases where a geological feature such as a fault or fold changes the state of stress locally. Given the orthogonality of principal stresses, this assumption requires that the other two principal stresses be horizontal. Thus, the problem of determining the field stresses is reduced to finding the direction and magnitude of horizontal stresses.

Abstract: The Raft River geothermal field located on the Idaho-Utah border is the site of a Department of Energy (DOE) Enhanced Geothermal System (EGS) demonstration project. The field consists of four production and four injection wells drilled into Precambrian metamorphic rocks. The purpose of this project is to stimulate a sub-commercial well, RRG-9 ST1, using a combination of hydraulic and thermal techniques. These stimulations have led to a significant improvement in the performance of the well. Over time, injection rates have increased from near zero in June 2013 to the current flow rates of 3546 Lpm (937 gpm) (February, 2016), at constant or decreasing wellhead pressures. This injectivity improvement was achieved through a combination of three hydraulic stimulations accompanied by thermal contraction of the surrounding rocks from continuous injection of sub reservoir temperature water from the geothermal plant. Geological studies, borehole imaging, and temperature surveys indicate that the water injected into RRG-9 ST1 flows into a fracture zone at 1722 m MD (5650 ft.). It is suggested this fracture zone connects with a larger northeast-trending shear zone within the Elba Quartzite referred to as the Narrows Zone. This zone acts as both a barrier and a conduit to fluid movement within the field. Both thermal and hydraulic stimulation effects contribute to the increase in permeability and injectivity of the well. Introduction The Raft River geothermal field located roughly 160 km (100 miles) northwest of Salt Lake City on the Utah-Idaho border is the site of a Department of Energy (DOE) Enhanced Geothermal System (EGS) demonstration project. Four production wells (RRG-1, 2, 4, and 7) and four injection wells (RRG-3, 6, 9 ST1, and 11), drilled into Precambrian rocks, produce roughly18,925 Lpm (5000 gpm) generating between 10.5 and 11.5 MW of electrical power, Figure 1. Geologic analysis, geochemical data, microseismic monitoring, and borehole imaging provide a conceptual model of the geothermal system surrounding RRG-9 ST1. Both production and injection wells encountered nearly 1524 m (5000 ft.) of discontinuous Quaternary and Tertiary volcanic and volcanoclastic rocks before reaching the metamorphic Precambrian basement. Further treatment of the geologic setting of Raft River is given by Konstantinou et al. (2012) and Nash and Moore (2012). Geochemical analysis of water collected from the wells indicate that the geothermal reservoir is split into northwest and southeast compartments with little or no fluid communication between them. Ayling and Moore (2013) suggest the field is separated by a low permeability northeast striking, steeply dipping fault located in the Precambrian basement, referred to as the Narrows Zone, Fig. 1. Microseismic events attributed to the stimulation program occur in a linear trend moving to the northeast, consistent with the location of the Narrows Zone. The open hole section of the RRG-9 ST1 was imaged in 2012 and a permeable fracture was identified intersecting the well at 1719 to 1725 m MD (5640 to 5660 ft.) striking to the northeast in the direction of the Narrows Zone. It is suggested that projecting this fracture to the northeast will lead it to intersect with the Narrows Zone.

Abstract: Induced seismicity associated with hydraulic stimulation for the development of underground resources has been recognized as a risk factor in causing seismic hazards and is of public concern. To understand the simple physics behind induced seismicity, we analyzed the stress state of a fault plane where large seismicity was induced during hydraulic stimulation in the Cooper Basin, Australia and Basel, Switzerland. Using information regarding the stress magnitude and orientation, and the geometry of the fault plane where large events occurred, the stress state of these events was evaluated and the pore pressure necessary to cause shear slip was estimated. The fault plane of the large event in the Cooper Basin was close to being well oriented and only needed small increase in pore pressure (~10MPa) to induce shear slip. It was also discovered that the fault plane of the largest event at Basel required a moderate increase in pore pressure of around 20 MPa to induce a seismic event. Other large events occurring at different depths needed much lower pore pressures to induce shear slip. On the fault planes at Basel where these large events occurred, large shear stress was present, suggesting causality between shear stress and event magnitude. Introduction Hydraulic stimulation is a necessary technology for the enhancement of formation permeability or improvement in system productivity in Enhanced/Engineered Geothermal System (EGS) projects. With the increasing demand for renewable energy, this technology has been used in many EGS projects to create economically feasible geothermal reservoirs. This method, also known as “fracking”, is used in the extraction of unconventional resources such as shale gas/oil. Fluid injection can induce shear slip on existing fractures or can initiate fractures leading to increased permeability. Acoustic energy released simultaneously with rock failure is often observed as induced seismicity, which is considered as the evidence relating these phenomena. The growing number of large-magnitude, induced seismic events has recently been recognized as a serious problem associated with hydraulic stimulation in geothermal development (Majer et al., 2007). Although the magnitude of induced seismicity is typically less than 1.0, these large magnitude events have had moderate magnitudes ( M w 2~) and it is possible for them to be felt by local residents and also cause seismic hazards. Therefore, a quick development of methods to control seismic activity is necessary, and regulations or protocols based on scientific knowledge for sustainable and reliable geothermal development are required. However, many aspects of the physical mechanism related to large events remain unknown. In modeling the propagation of injected fluid, as fluid flows through the flow paths in an existing fracture, pore pressure in the reservoir increases with pumping pressure. In an arbitrary existing fracture under tri-axial stress, this increase in pore pressure weakens the effective normal stress. When the shear stress working on a given fracture overcomes shear friction, the result is shear slip. This is known as the Coulomb failure criterion and is the principal behind induced seismicity. It can be described mathematically using equation (1),.

Abstract: We use here a fully hydraulically-mechanical coupled, 3-D model (Damjanac and Cundall, 2014) to simulate fault reactivation during a hydraulic fracturing treatment. Synthetic seismicity from the model helps quantify seismic energy released by the slippage on the fault. The model is based on a case study in the Horn River Basin by Snelling et al., 2013a. The multi-stage hydraulic fracture model is able to reproduce seismic deformation characteristics observed in field data. Results show that even stages distant from the fault have an influence on the slippage on the fault with a delayed effect. If the first injection stage is the closest to the fault, a large area will be slipping. Successive stages will have a lesser impact due to stress shadowing. If the first stage is farthest from the fault, then slippage on the fault will be gradual, reducing the amount of seismic moment release in a short period of time. This model can be used as a framework to examine the impact of other geomechanical characteristics or other operational factors, which could help establish best practices to mitigate seismicity when faults begin to be active. Introduction Induced seismicity has become a concern for hydraulic fracturing operations in British Columbia and Alberta, Canada. Seismic monitoring is now mandatory for stimulation of two shale formations in this region. The challenge of hydraulic stimulations in areas prone to induced seismicity remains because mitigation can only be achieved with a good understanding of the underlying mechanisms linking multi-stage hydraulic fracturing operations and induced seismicity. Geomechanical modeling is the best way to understand this link because it allows investigation of the interactions between multiple hydraulic fractures by modeling different injection scenarios and assessment of the sensitivity to different parameters. Many authors have proposed models to investigate induced seismicity (for instance, Goertz-Allmann and Wiemer, 2013; Rutqvist et al., 2013). Most find a strong correlation between pore pressure increase and areas where large magnitude events occur. The models indicate that the increase in pore pressure is caused by the hydraulic fracture following fluid injection. None of these models can produce synthetic seismicity for quantitative comparison with recorded seismicity. The multi-stage hydraulic fracture model presented here is based on a fully hydraulically-mechanical coupled, 3-D model (Damjanac and Cundall, 2014) which produces synthetic seismicity, which can help quantify the seismic energy released by slippage on faults (Zhang et al., 2015).

Abstract: Microseismic events are commonly recorded during hydraulic fracturing experiments. In microseismic interpretations, each event is often regarded as causally independent and uncorrelated to neighboring ones. In reality, both the rock deformation (static stresses) and transient wave motion (dynamic stresses) associated with microseismic events influence the stress field together with the external loading (fluid injection). It is thus very likely that many microseismic events are caused by both static and dynamic stress changes. In other words, some events may be caused by propagation of transient waves instead of the stress changes purely related to fluid injection. We study dynamic triggering of acoustic emissions as an analogy of microseismic events using numerical simulations of a biaxial deformation test by means of a bonded-particle method. We apply an external vibration at the bottom platen of the model to study the influence of transient wave motion on failure in a controlled fashion. Our results show that the external vibration can advance the formation of the upcoming large local failure events and delay or advance the final catastrophic failure depending on the vibrational amplitude. Introduction In hydraulic fracturing, microseismic events are taken independently in that they are all attributed to the developing hydraulic fractures and no event causes another one. The hydraulic fractures are the result of tensile and shear failure imposed by fluid injection, leading to pore pressure diffusion as well as the large static elastic stress perturbations in the surrounding areas due to imposed volumetric changes. Conversely, seismologists believe that earthquakes are caused by both static and dynamic stress perturbations (Freed, 2005) in that one event may cause another one, leading to the concept of main shocks and aftershocks. Static stress perturbations leave a permanent imprint on the stress field (e.g., a developing hydraulic fracture). Dynamic stress perturbations are generally due to transient waves propagating through the medium. Both dynamic and static stress perturbations can trigger failure, in particular if the system is critically stressed. Our long-term goal is to investigate the effect of dynamic stress perturbations on microseismic event characteristics. Unlike destructive laboratory tests, numerical simulations have the advantage of repeatability. They provide direct means to measure variables associated with particle dynamics which cannot be done in laboratory or field. We use the bonded-particle method (Ponyondy and Cundall, 2004). It models the real material as a set of particles bonded together according to user-defined microproperties, which present macroproperties, e.g. the bulk modulus, of the real material. Saving the effort in defining complex constitutive relationships, the bonded-particle method can create cracks spontaneously due to local stress concentrations exceeding the bond strength. This makes BPM an optimal method for failure simulation.

Abstract: A 3D geomechanical model of a hydraulic fracture treatment in the Horn River Basin was calibrated by comparing synthetic microseismic events to field data. Using this calibrated model, sensitivity studies were performed to determine the effect of geological parameters and operational variables on the resulting fracture geometry and microseismic response. Microseismic geomechanics was shown to be a reliable calibration methodology for this model because changes in hydraulic fracture geometry were reflected by changes in the microseismic calibration. The results show that the orientation of the DFN is a key parameter driving the microseismic response. When hydraulic fractures intersect natural fractures at high angles, the pre-existing fractures are stimulated more and exhibit a greater microseismic response. Application of the calibrated model to optimize completion changes is demonstrated by investigating the effect of several potential changes on fracture geometry. Introduction Hydraulic fracturing of horizontal wells has been an important factor in the development of low permeability formations such as shales (Gale et al., 2007). The high-pressure injection of hydraulic fracturing fluid creates tensile fractures which may connect with and activate natural fractures. Hydraulic fracture modeling requires close coupling between the hydraulic (fluid flow) and mechanical models. For tight formations, the geomechanical aspect of the model is even more important than in conventional reservoirs, because natural fractures can play an important role in production. Hydraulic fracturing typically causes microseismicity, usually through shear deformation (slip) on natural fractures and bedding planes. This microseismicity is the only far-field measurement of fracture geometry, and can be used to calibrate geomechanical models of fracture geometry and proppant distribution. This paper presents a case study in which a coupled hydraulic-geomechanical simulator ( 3DEC , Damjanac and Cundall, 2016) is used to simulate hydraulic fracture growth in a naturally fractured formation and predict the corresponding microseismicity. The mechanical model is constructed with principal stresses, pore pressure and mechanical properties obtained from well logs, and a Discrete Fracture Network (DFN) is embedded in the stimulated area. The evolution of the mechanical deformation during the hydraulic fracturing process is simulated, including both the creation of new (hydraulic) fractures and the activation of pre-existing natural fractures. The model is calibrated by comparing the synthetic microseismic (MS) events with the field data.

Abstract: Conventional microseismic analysis is often inadequate to determine whether refracture treatments stimulate undepleted areas or simply re-stimulate already-depleted areas. The Eagle Ford refracture treatment case study in this paper demonstrates the application of microseismic geomechanics to assess the effectiveness of diversion and estimate the distribution of fluid between previously stimulated and unstimulated areas. The case study shows that depletion-induced changes in stress can enhance diversion, and the distribution of fluid between fractures in depleted and undepleted areas evolves during the treatment. The geomechanical model is used to identify the characteristic pressure signature and microseismic patterns associated with different hydraulic fracture geometries. A practical diagnostic of diversion effectiveness based on microseismic moment is derived from advanced microseismic analysis of the geomechanical response, and some options for completion optimization are suggested. Introduction Due to the low permeability of shale reservoirs, it is generally assumed that production occurs only from those parts of the reservoir that are close to the hydraulic f racture or to natural fractures activated by the stimulation process. Many older horizontal wells were stimulated with 10 or fewer stages, with the stages separated by some distance, due to limitations of completion hardware technology. This resulted in sub-optimal stimulation and some areas of the laterals were not stimulated at all. Refracturing these older wells has been seen as an opportunity for oil and gas operators to increase production at a lower cost than drilling new wells. In some cases, diverters are used to block access to open fractures and redirect the refracture treatment to stimulate new areas around the wellbore that were not accessed by the initial treatment. It is important to know whether the diversion is successful or if the initial fractures are being reopened. Microseismic data is often used as a tool to visually assess the geometry of hydraulic fractures, and the related stimulation. This paper shows that this simplistic approach (assuming that microseismic activity is associated with fluid flow and stimulation) is inadequate for refracturing. A more complete workflow and modeling methodology is demonstrated using an Eagle Ford case study.

Abstract Large underground powerhouse caverns in the mighty Himalayan region during construction and their operation after their completion experiencing instabilities, which are need to be monitored for life time using a real time regional monitoring systems for the safety of the structure, installed machinery and workmen. These structures experienced many incidents of strata instabilities during construction period including large roof falls and even during its operation in the form of large number of rockbolt violent failures etc. Since the conventional instrumentation that was installed during construction was not able to provide adequate information about the regional stability. A high resolution sixty channel real time, remote monitoring microseismic system was established in one of the project site with the objective to provide information related to the regional strata behaviour in real time and to address the regional structural and strata stability around the powerhouse caverns. The microseismic data is continuously recorded, auto processed and displayed in near real time at the central data recording laboratory situated inside the underground powerhouse and at regional data processing centers located far away from the site. The microseismic data acquired were analyzed and mapped on the 3D plan of the caverns. Statistical data analysis using source parameters of microseismic events were carried out to correlate the events with rock bolt failures in order to study the signatures of the precursory signals. Few microseismic events occurred in clusters at some regions and majority of the microseismic events have the local magnitudes in the range of at about -2.5. The range of recorded events local magnitudes indicates that the cavern was stable during the monitoring period, there is no development of stress pockets or migration (changes in stress) of stress regime. The changes in the stress have been very low indicating the stability of the strata. The recorded low values show the efficiency of the monitoring system in response to minor changes of strata behaviour. This paper presents the real time microseismic monitoring of regional strata behaviour of the underground hydro powerhouse caverns for about a period of one and half year after the commissioning of real time monitoring system in September 2013 and correlation of microseismic activity to explain the rock bolt failures and the caverns regional strata stability.

Abstract While numerous definitions of what makes Unconventional Plays ‘unconventional’ have been put forth, ranging from the reliance on horizontal wells and hydraulic fracturing technology to the often ultra-low permeability of the matrix, a key characteristic of Unconventionals is the impact of geomechanics on hydraulic fracturing in reservoir formations with natural fractures and/or weakness planes (e.g., bedding planes). Critical geomechanics effects include the influence of: 1) all three principal stress magnitudes; 2) anisotropy in the stress magnitudes; 3) the orientation of the stress field; 4) in-situ pressure (e.g., pressure within the natural fractures and weakness planes); 5) natural fracture and weakness plane frequency and connectivity; 6) natural fracture and weakness plane orientation relative to the stress field; 7) natural fracture and weakness plane mechanical properties (elastic properties such as stiffness as well as strength properties such as cohesion and friction coefficient); 8) natural fracture and weakness plane initial aperture; and 9) the interaction with operational parameters during a hydraulic fracture stimulation (e.g., rate, volume, and viscosity). In this paper, the authors review the importance and impact of these critical geomechanical parameters on hydraulic fracturing design and effectiveness in Unconventionals. 1. INTRODUCTION Numerous definitions of what makes Unconventional Plays ‘unconventional’ have been put forth ranging from the reliance on horizontal wells and hydraulic fracturing technology to the often ultra-low permeability of the matrix (as low as single-digit nanodarcy). However, an important key to Unconventionals is the impact of geomechanics on hydraulic fracturing in reservoir formations with natural fractures and/or weakness planes (e.g., bedding planes), which has often made hydraulic fracture design and implementation both challenging and inconsistent in Unconventionals. While commercial hydraulic fracturing has been conducted for more than 65 years [1], hydraulic fracture design has been based upon the assumption that equal half-length, bi-planar fractures will develop since a dominant control on fracture length is fracture height growth, which itself is dominantly controlled by the vertical profile of the minimum in-situ principal stress, Shmin [2]. This assumption is often valid because hydraulic fractures are created using hydraulic energy, which acts omni-directionally, ensuring that hydraulic fracture propagation always follows the path of least resistance, which itself is often dominated by a laterally-uniform stress field.

Abstract Hydraulic fracturing has become increasingly prevalent in the oil and gas industry as well as in enhanced geothermal systems as a method to increase the permeability of rock masses. However, the process is still not very well understood in terms of the fracture mechanisms that occur as cracks initiate, propagate and coalesce. Laboratory tests can be useful in this regard as they provide insights into fracture behaviour during hydraulic loading under controlled conditions. This paper describes the development of an acoustic emissions setup capable of capturing a stream of data over approximately five seconds corresponding to crack initiation and propagation. The AE setup was used in a series of hydraulic fracturing experiments on granite specimens. It was found that for one particular specimen, few emissions were observed until the applied water pressure reached 90% of the failure pressure. After this point it was observed that low energy emissions were produced at a constant rate until approximately 0.1s before failure, whereupon a series of higher energy emissions occur. These higher energy emissions were compared to high speed video taken at 15 000 fps, and it was observed that significant local white patching (microcracking) occurred in this time period. Finally, crack initiation appears to be related to the onset of a high amplitude emission with a duration of 0.3s, as observed using high speed video. 1. INTRODUCTION It is a well-known phenomenon that the rate of acoustic emissions increases close to the time at which shear failure occurs [1]. This is particularly true in brittle materials, where the rate of emissions often exceeds that which can be handled by the acquisition system [2], [3]. AE systems have traditionally had issues recording data at the time of a fracturing event due to hit based architecture, where the system acquires data in discrete segments and requires time to re-arm after every hit. It is possible to circumvent this problem by use of a continuous waveform recorder [4], however in such an approach the data only span a limited time window due to memory limitations. Consequently, any longer experiment would require a separate hit based acquisition system to acquire data in the early phase of the experiment. The main disadvantages of such a setup is that splitting the sensor signal into two acquisition systems increases the electronic noise in all voltage readings, the continuous data can often consume significant memory space, and analysis can become more difficult due to sheer volume of data. As a result, it would be ideal to develop a single acquisition system with both hit-based and continuous modes of operation.

Abstract The Northwest Geysers EGS Demonstration Project started in 2011 at The Geysers (California). The goal was to create an EGS by injecting cool water at relatively low pressure into a known high temperature reservoir located deep down below the conventional geothermal steam reservoir. Here, we present (1) tomography images of the seismic velocity (Vp, Vs) and attenuation (Qp, Qs) built from microseismic data recorded before injection and during the first 60 days of injection, (2) the spatiotemporal distribution of the microseismicity over 270 days of injection, and (3) a 3D thermo-hydro-mechanical modeling of the EGS. The results show the development of a seismically quiet domain around the injection well surrounded by a seismically active domain. The modeling with comparison to field data indicates that the seismically quite (aseismic) domain is due to the presence of the injected cold water. Thermal processes cause a cooling-stress reduction preventing shear reactivation. This process is accompanied by aseismic plastic shear strain, which can be interpreted as slow slip events. In the seismic domain, microseismicity is caused by the reactivation of the preexisting fractures due to injection-induced pressure increases in steam pressure. 1. INTRODUCTION Injecting fluid into a rock formation reduces the effective stress and can lead to brittle failure [1]. Such fracture reactivation can be accompanied by microseismic events due to the release of preexisting tectonic stresses. The monitoring of microseismic activity can provide valuable information concerning the response of the reservoir to water injection. The occurrence of microseismicity at a point remote from the injection interval indicates that the point has a hydraulic connection to the borehole interval. However, it does not necessarily mean that significant fluid flow occurs along the connection [2]. Moreover, during the reservoir stimulation, aseismic deformations can play an important role on the reservoir development during hydraulic stimulation [3]. In this paper, we present data collected during the Northwest Geysers EGS Demonstration project [4,5]. The project aims to develop an EGS by directly and systematically injecting cool water at relatively low pressure into a vapor-dominated geothermal reservoir with temperatures up to 400 °C. We focus our study on the relationship between the formation of the liquid saturated zone and the distribution of the seismic and aseismic deformations. First, we present the Northwest Geysers EGS Demonstration project, a 3-D seismic tomography performed during the first months of injection and the microseismic activity by using the Seismicity-Based Reservoir Characterization approach [6, 7]. Finally, we discuss our observations with the results of a 3-D Thermo-Hydro-Mechanical (THM) numerical model simulation of the EGS area.

Abstract In unconventional hydrocarbon resources, the estimation of the expected ultimate recovery for individual wells and the appropriate spacing for infill drilling near existing wells both have strong economic implications. A field test called microseismic depletion delineation has previously been proposed as a method to probe the reservoir directly to determine the extent of the depleted region near horizontal wells that have been produced for a significant period of time. In this work, we performed a numerical simulation of a microseismic depletion delineation field test in order to further understand the physical mechanisms that underpin the method. The modeling framework developed herein can be used to help design field tests and interpret field observations. We observed that application of a model that coupled fluid flow, fracture mechanics, poroelasticity, and geologic structure was able to produce the physical behavior necessary to interpret observations from microseismic depletion delineation field tests. 1. INTRODUCTION The successful exploitation of unconventional resources depends on the ability to develop strategic engineering designs using economic considerations as the primary drivers. In shale oil plays, like the Bakken for instance, suitable wellpad geometries and well trajectories are first determined and then repeated many times in an efficient pattern in order to reduce drilling costs. Similarly, hydraulic fracture treatments are commonly performed in repeatable patterns across many wells. This methodology is attractive from an economic standpoint, but given that heterogeneity exists in all reservoirs and that operational difficulties can arise, the approach may not always result in the optimal recovery for a given well. Evidence from field data has indicated that productivity of individual wells, and even individual completion stages, can be highly variable [1, 2]. It is useful to develop tests that can be applied in the field in order to assess the recovery efficiency of wells and individual completion stages within each well. This information can be helpful from a reservoir management perspective, for example, in order to estimate ultimate recovery or to determine appropriate spacing for infill drilling in a given asset.

Abstract The contribution of natural fractures to well performance in hydraulically fractured horizontal wells in shale reservoirs is not fully understood. To better understand the influence of natural fractures on well performance, numerical discrete element modelling software was used to simulate the hydraulic fracturing process in shale. Two cases were analyzed: one with natural fractures and the other without natural fractures. For the first case, the modelling results show that critically stressed natural fractures undergo shear failure caused by the injected water from the hydraulic fracturing process, as well as tensile failures on the extreme limits of natural fracture planes. In the second case without natural fractures, there are only tensile failures associated with the hydraulic fracturing process. The microseismic energy of these shear and tensile failure events are simulated by the modelling software and recorded as a function of time or amount of injected fluid. Analyzing the results from both cases reveals a significant difference in the number and magnitude of microseismic events. A variation in the coefficient b of the Gutenberg-Richter’s empirical formula for the magnitude-frequency relation is observed with and without natural fractures. Similar variations in b value measurements are observed using downhole microseismic measurements from hydraulic fracturing in horizontal shale wells. For the downhole microseismic magnitude-frequency relations, it is recommended to use the coefficient b of the Gutenberg- Richter’s empirical formula to indicate the presence or the lack of natural fractures in shale reservoirs. 1. INTRODUCTION Downhole, buried array or surface microseimic measurements are used to infer the size of the stimulated rock volume during hydraulic fracturing in vertical and horizontal wells. It is, however, often difficult to establish a significant correlation between microseismic events (dots in the box) and well performance. To better understanding the hydraulic fracturing process in complex rocks various numerical models are being developed. One such approach — discrete element modeling (DEM) — simulates the hydraulic fracturing process in a rock matrix with or without natural fractures. An output of this modeling method is the microseismic energy associated with either the microcrack of the host material and/or microslip along natural fracture/joint surfaces. The modeling of this microseismic energy is complex and needs to be validated.

Abstract A better understanding of the energy budget has important implications for enhancing the efficiency of hydraulic fracturing treatments. In particular, what percentage of the input treatment energy is released as radiated energy? What characterizes the deformation of the failure? We use a bonded-particle modeling approach to investigate both the radiated energy release and the amount of brittle failure. To test our model, we simulate triaxial compression tests on calibrated sandstone samples. Our results show that much of the failure is marked by a tensile component, despite the development of one or two large shear planes crosscutting the samples. Additionally, only 2.5% of the input energy is radiated as seismic waves. We propose an updated empirical energy-magnitude relation: log E R = 1.9MW +8.5, where E R is the radiated energy and MW is the event moment magnitude. This relation is an alternative to the commonly used Kanamori relationship and more applicable for the small-magnitude acoustic emissions in triaxial tests and likely microseismic events in hydraulic fracturing experiments, which are both marked by strong tensile deformation. Close examination of the source mechanisms of the induced acoustic emissions reinforce the complex nature of the micromechanics behind rock fracturing in general, due to strong deviations of the local stress field from the applied external field.