Microseismic Cloud Research Articles

Integrated analysis of cyclic steam stimulation in a heavy oil reservoir: Microseismicity, brittleness, and landing height

We compare microseismic observations against pumping information, landing heights, and various well logs. The data were acquired during cyclic-steam injection between September 2002 and December 2005. Ninety-five percent of the microseismicity occurred during injection and in the overburden; 70% of the events happened during the first cycle. Microseismicity in the overburden is likely caused by a greater brittleness than in the reservoir and a cluster of microseismic events in regions with a smaller landing height, thereby facilitating dry cracking due to the volumetric expansion of the reservoir. Yet, other areas with equally shallow landing heights displayed little to no microseismicity, pointing to an inhomogeneous steam front. Furthermore, recorded microseismicity is subject to the Kaiser effect in that event rates are low in subsequent cycles until the current injection pressure exceeds the previous maximum, explaining why 70% of the events occurred during the first cycle and possibly why microseismicity during production accounted for only 5%. Microseismicity in brittle formations can be caused by pore-pressure variations (wet cracking) and/or changes in the total stresses (dry cracking). Identification of pore-pressure variations in the overburden is important because it may indicate containment challenges. Analysis of the growth rate of the microseismic cloud combined with the shallow landing height indicated dry cracking to be more likely than wet cracking but analysis of additional data is required to strengthen this conclusion.

Scaling Microseismic Cloud Shape During Hydraulic Stimulation Using In Situ Stress and Permeability

AbstractForecasting microseismic cloud shape as a proxy of stimulated rock volume may improve the design of an energy extraction system. The microseismic cloud created during hydraulic stimulation of geothermal reservoirs is known empirically to extend in the general direction of the maximum principal stress. However, this empirical relationship is often inconsistent with reported results, and the cloud growth process remains poorly understood. This study investigates microseismic cloud growth using data obtained from a hydraulic stimulation project in Basel, Switzerland, and explores its correlation with measured in situ stress. We applied principal component analysis to a time series of microseismicity for macroscopic characterization of microseismic cloud growth in two‐ and three‐dimensional space. The microseismic cloud, in addition to extending in the general direction of maximum principal stress, expanded in the direction of intermediate principal stress. The orientation of the least microseismic cloud growth was stable and almost identical to the minimum principal stress direction. Further, microseismic cloud shape ratios showed good agreement when compared with in situ stress magnitude ratios. The permeability tensor estimated from microseismicity also provided a good correlation in terms of direction and magnitude with the microseismic cloud growth. We show that in situ stress plays a dominant role by controlling the permeability of each existing fracture in the reservoir fracture system. Consequently, microseismic cloud growth can be scaled by in situ stress as a first‐order approximation if there is sufficient variation in the orientation of existing faults.

Transforming microseismic clouds into near real-time visualization of the growing hydraulic fracture

SUMMARY Microseismic observations during unconventional reservoir stimulation are typically seen as a proxy for clusters of hydraulic fractures and the extent of the stimulated reservoir. Such straightforward interpretation is often misleading and fails to provide a physically reasonable image of the fracturing process. This paper demonstrates the application of a physics-based machine learning algorithm which enables a rapid and accurate fracture mapping from the microseismic data. Our training and validation data set relies on a history-matched geomechanical modelling workflow implemented in GEOS software for the Hydraulic Fracturing Test Site 1 (HFTS-1) project. For this study we augmented the simulated fracture growth through geostatistical modelling of induced seismicity, so that the synthetic microseismic catalogue matches the main statistical properties of the field observations. We formulated the problem of mapping the actual fracture in the clutter of events to parallel common video segmentation workflows: several past video frames (microseismic density snapshots) are passed through a deep convolutional network to classify whether a given voxel is associated with a fracture or intact rock. We found that for accurate fracture mapping, the network’s input and architecture must be augmented to incorporate the fluid injection parameters (pressure, rate, concentration of proppant, and location of the perforation within the cluster). The error rate for the network reached as little as 10 per cent of the fracture area, while a conventional microseismic interpretation approach yielded ∼300 per cent. Our approach also yields must faster predictions than conventional methods (minutes instead of weeks), and could enable engineers to make rapid decisions regarding engineering parameters (pumping rate, viscosity) in real time during stimulation.

Interaction of natural and hydraulic fractures: the impact on reservoir pressure buildup and risk of shear fault reactivation in the Upper Devonian Duvernay Formation, Fox Creek, Alberta

The interaction of natural and hydraulic fractures may facilitate lateral fluid propagation in an unconventional reservoir resulting in fast fluid pressure transmission from treatment wells to a fault zone and potential fault shear slip reactivation and associated induced seismicity. Several induced earthquakes (up to 4.1 Mw) occurred since 2013 during hydraulic fracturing of the Upper Devonian Duvernay Formation in the Western Canada Sedimentary Basin. The mechanism of lateral fluid migration in the unconventional reservoir is not well understood. The current study aims to investigate the interaction of natural fractures and hydraulic fractures for the case study in the area south of Fox Creek, where a linear zone of induced earthquakes (up to 3.9 Mw) occurred along a fault in 2015 during hydraulic fracturing of horizontal wells. We analyze the growth of hydraulic fractures in presence of natural fractures, the impact of resulting complex fracture network on fluid transmission and fluid pressure buildup around the treatment wells. Hydraulic fracture modeling (HFM), reservoir simulations and 3D coupled reservoir-geomechanical modeling are applied to match the timing of hydraulic fracture propagation and transmitted fluid pressure increase in the fault zone versus induced earthquake occurrence. HFM results are verified by microseismic clouds distribution. Reservoir simulations are validated by a history matching of fluid injection volume and bottomhole pressure data. Additional HFM simulations are carried out to optimize the pumping schedule in the studied well pad that would help to prevent hydraulic fractures reaching the fault and minimize the risk of induced seismicity.Article highlightsStress anisotropy and simulated natural fractures impact lateral growth of complex hydraulic fractures and reservoir pressure buildup.Predicted fluid pressure transmission to a fault zone results in fault dextral shear slip reactivation matching induced seismicity.Optimized pumping schedule helps to minimize risks of fault reactivation and induced seismicity while preserving overall pad performance.

Simulation of the Production Performances of Horizontal Wells with a Fractured Shale Gas Reservoir

The production performances of a well with a shale gas reservoir displaying a complex fracture network are simulated. In particular, a micro-seismic cloud diagram is used to describe the fracture network, and accordingly, a production model is introduced based on a multi-scale flow mechanism. A finite volume method is then exploited for the integration of the model equations. The effects of apparent permeability, conductivity, Langmuir volume, and bottom hole pressure on gas well production are studied accordingly. The simulation results show that ignoring the micro-scale flow mechanism of the shale gas leads to underestimating the well gas production. It is shown that after ten years of production, the cumulative gas production difference between the two scenarios with and without considering the micro-scale flow mechanisms is 19.5%. The greater the fracture conductivity, the higher the initial gas production of the gas well and the cumulative gas production. The larger the Langmuir volume, the higher the gas production rate and the cumulative gas production. With the reduction of the bottom hole pressure, the cumulative gas production increases, but the growth rate gradually decreases.

A Data-Driven Reduced-Order Model for Estimating the Stimulated Reservoir Volume (SRV)

The main goal of hydraulic fracturing stimulation in unconventional and tight reservoirs is to maximize hydrocarbon production by creating an efficient stimulated reservoir volume (SRV) around the horizontal wells. To zreach this goal, a physics-based model is typically used to design and optimize the hydraulic fracturing process before executing the job. However, two critical issues make this approach insufficient for achieving the mentioned goal. First, the physics-based models are based on several simplified assumptions and do not correctly represent the physics of unconventional reservoirs; hence, they often fail to match the observed SRVs in the field. Second, the success of the executed stimulation job is evaluated after it is completed in the field, leaving no room to modify some parameters such as proppant concentration in the middle of the job. To this end, this paper proposes data-driven and global sensitivity approaches to address these two issues. It introduces a novel workflow for estimating SRV in near real-time using some hydraulic fracturing parameters that can be inferred before or during the stimulation process. It also utilizes a robust global sensitivity framework known as the Sobol Method to rank the input parameters and create a reduced-order (mathematically simple) model for near real-time estimation of SRV (referred to as DSRV). The proposed framework in this paper has two main advantages and novelties. First, it is based on a pure data-based approach, with no simplified assumptions due to the use of a simulator for generating the training and test dataset, which is often the case in similar studies. Second, it treats SRV generation as a rock mechanics problem (rather than a reservoir engineering problem with fixed fracture lengths), accounting for changes in hydraulic fracture topology and SRV changes with time. A dataset from the Marcellus Shale Energy and Environment Laboratory (MSEEL) project is used. The model’s input parameters include stimulation variables of 58 stages of two wells. These parameters are stage number, step, pump rate and duration, proppant concentration and mass, and treating pressure. The model output consists of the corresponding microseismic (MS) cloud size at each step (i.e., time window) during the job. Based on the model, guidelines are provided to help operators design more efficient fracturing jobs for maximum recovery and to monitor the effectiveness of the hydraulic fracturing process. A few future improvements to this approach are also provided.

Calibration of Complex Discrete Fracture Network Using Microseismic Events and Fracture Propagation Modelling with Seamless Reservoir Production Simulation

Abstract During the unconventional reservoir development, a proper modelling of the underground fracture networks and their effects on production is crucial for reservoir development potential and realistic economic analysis. Conventionally, the complex fracture system formed by hydraulic and natural fractures is extremely difficult to capture, let alone to numerically simulate it. Most importantly, the current best solution can only rely on the knowledge of the natural fractures from the geology and geophysics team and hydraulic fractures from the engineering team. Nevertheless, this solution fails to realize the dynamic stress regime variations when fracturing jobs are done within the horizontal wellbore. In this study, a variety of data source and modelling tools is harnessed to delineate a more realistic and representative discrete fracture network (DFN). The first step is to obtain the original natural fractures already depicted from geological and geophysical information and the statistical information regarding the spatial configurations of this DFN. Next, a new set of natural fractures is generated by an in-house natural fracture generator while preserving the spatial characteristics of the original natural fractures at the same time. Then, a combined DFN of the original natural fracture and newly generated natural fractures is accomplished. This combined DFN is then intensity-calibrated by the given microseismic cloud events, especially focusing on the near-wellbore region. Then, a displacement discontinuity method- (DDM-) based in-house hydraulic fracture propagation model is used to generate hydraulic fractures with complex boundaries, honoring the fracturing job logistics from the engineering team. After this step, an ultimate and highly representative DFN can be achieved. By applying this very novel workflow, DFN characterizations of both a single-well scenario and well-pad (3 wells) scenarios have been highly successful. Statistics such as the cluster-wise hydraulic fracture half-length, height, aperture, and numbers of activated/nonactivated natural fractures can be easily presented. Through the powerful numerical method called the embedded discrete fracture model (EDFM), production simulation and stimulated reservoir volume evaluation can be seamlessly studied. Extents of 3D drainage volumes can also be plotted with ease. Overall, a holistic picture regarding the unconventional reservoir’s underground DFN can be reliably depicted, using the proposed workflow.

A Numerical Simulation Approach for Shale Fracture Network Characterization Using Hybrid EDFM Method

Abstract Efficient and economical production in shale reservoirs requires specific knowledge and techniques to characterize the fracture network, which consists of both the large hydraulic fractures and the natural fractures. Current research mainly focuses on the hydraulic fracture part, while research on characterizing the natural fractures is relatively rare due to the complexity and uncertainties of the natural fracture distribution in reservoirs. This paper proposed a numerical method for characterizing this complex fracture network in shale reservoirs which handles both the hydraulic fracture and the natural fractures at full dimensions using a combination of microseismic data, geostatistical information, fracking plan, and reservoir simulation. We use microseismic clouds to generate mappings of hydraulic fractures and choose the most appropriate set using the fracking schedule and flowback simulation. The natural fractures are treated using a fractal probabilistic model calibrated with geostatistical information including fracture length, density, and intensity. Both the hydraulic and fractal natural fractures mentioned above are then modeled using embedded discrete fracture model (EDFM) and are coupled to create the hybrid fracture network and applied with reservoir simulation grids. Numerical simulation is performed to investigate further into the fracture network, and history matching is applied to reduce the uncertainty by select the most appropriate fracture network from multiple realizations. Sensitivity analysis is also performed to analyze the controlled natural fracture parameters on total production. We further used our approach to study a horizontal well performance in the Permian Basin and compared our simulation results with traditional fracture characterization and model methods. Our established work has shown the best agreement with history production data compared with randomized fracture model and the multimedium method. This provides a novel method to characterize fracture networks in shale and may be used to guide production optimizations and plan management.

Real-time analysis and forecasting of the microseismic cloud size: Physics-based models versus machine learning

The spatiotemporal distribution of hydraulic fracturing microseismicity is complicated and depends on various mechanical and diffusional parameters. Hydraulic fracture modeling can aid in understanding fracture propagation and microseismicity. Nevertheless, the complex spatial and temporal interaction of several processes occurring within and around the fracture represents a challenge for developing real-time tools for microseismic prediction. Two approaches are developed to forecast the microseismic cloud size in real time. The first approach uses fracture propagation models to derive the cloud size directly from the microseismic observations. The second approach is based on a convolutional neural network (CNN) trained with the engineering parameters and past microseismic cloud size values. A rolling forecasting strategy is used to train consecutive CNN models in real time to make predictions at a specified time lag. A data augmentation technique known as double noise injection is used to ensure that the amount of training examples available to the machine-learning models at each time step is similar to or larger than the number of free parameters. The results indicate that the CNN outperforms the quality of predictions of the physics-based models but with a reduced prediction capability. The physics-based approach can predict growth at any time but ignores the engineering parameters. Conversely, physics-based methods lead to real-time insights into the fracturing regime, revealing whether microseismicity is most likely generated due to a leak-off-dominated or a storage-dominated regime. The CNN model can forecast the cloud size only at a single future time lag while using the engineering parameters and past cloud growth as input. However, this approach does not provide a physical interpretation of the fracture propagation regime. The prediction accuracy of both methodologies varies depending on the microseismic behavior. We postulate that CNN forecasts could be improved by including more physical constraints into the predictive model.

On how asymmetric stimulated rock volume in shales may impact casing integrity

AbstractMicroseismic data and production logs in our study area have confirmed asymmetric developments of the stimulation rock volume in shales with respect to the wellbore, while severe casing deformation problems have been reported frequently in this area. Here, we propose a systematic methodology to investigate the possibility of casing failure due to strong shear stresses induced by asymmetric stimulated zones. A mechanical earth modeling (MEM) is initially performed to determine the in situ stress field in the target layer before fracturing by incorporating the existing geological features, logging data, and rock anisotropy. Then, we provide a computationally cheap and efficient estimation for stimulated rock volume of each stage by considering the possible overlaps in adjacent stages based on the clustered microseismic clouds. Using this approach, a reservoir‐scale 3D coupled model tied to a more detailed near‐wellbore part incorporating the casing string and the cement sheath is established to simulate the development of stimulation zones, stress redistribution, and their impacts on casing deformation as each stage fracturing treatment chronologically goes on. Our numerical results indicate that continuous redistribution and re‐orientation of stress field near the borehole are tracked during pumping the treatment which reveals formation of some pockets of tensile stresses along and around the wellbore. Asymmetric stimulations are observed to generate strong shear stress on the suspended casing. These shear forces result in deflection and S‐shape deformations accompanied with cross‐sectional ovality. Some regions receive repeating treatments, which results in intensifying formation stress heterogeneity and worsen casing deformation severity. The calculation results are compared with measurement of multi‐finger imaging tool (MIT) to validate the accuracy. Our analysis has indicated that simply increasing the flexural strength by increasing thickness of casing cannot radically mitigate casing deformation problems. This paper presents a novel workflow for a coupled modeling of casing deformation during hydraulic fracturing operations, while current modeling efforts assume symmetric bi‐wing fracture geometries.

Study on the microseismic clouds induced by hydraulic fracturing

ABSTRACT Microseismicity has become a primary tool for detecting the hydraulic fracturing process. However, whether hydraulic fracture (HF) geometry can be accurately inferred from the microseismic (MS) data is in debate. A dynamic geomechanics code is applied to investigate the correlation between the geometry of the HF and the induced MS clouds. Effects of HF length and cohesion on the correlation are studied. Some examples of the rupture patterns along the NFs are presented. The stability around a dynamically propagating HF is also studied. The inclination of the NFs relative to the maximum horizontal principal direction affects the correlation. When the inclination of the NFs relative to the maximum horizontal principal direction is nearly optimal in geomechanics point of view, the induced MS events spread far away from the HF and are almost symmetric about the HF. The MS cloud has a large discrepancy with the HF in length but small discrepancy in strike. When the inclination of the NFs is either high or low relative to the optimal, the induced MS events could be very close to the HF but quite asymmetric about the HF. The MS cloud has a small discrepancy with the HF in length but large discrepancy in strike.

Analysis and prediction of stimulated reservoir volumes through hydraulic fracturing: Examples from western Arkoma Basin

Geologic models built from well logs and natural fracture (NF) parameters obtained at shale and carbonate outcrops/quarries were employed in understand artificial hydraulic fracture (HF) propagation and stimulated reservoir volume (SRV) geometries. We applied field HF treatment parameters from an Arkoma Basin well, located 20–25 miles (32–40 km) east of the studied quarries. We matched the microseismic cloud (MC) geometries of three field stages, followed by sensitivity analyses of various HF treatment and reservoir parameters.Geometry matches reveal that the average NF permeability in the Viola Group Limestone is nearly eight times that in the Woodford Shale. The sensitivity analyses (forward modeling) disclosed several likely outcomes. First, a minor (5 × 10−6) increase in the minimum horizontal tectonic strain and ensuing increase in the minimum horizontal stress resulted in a sizeable transformation of the SRV geometry. Second, pumping at a higher net pressure (ISIP increased from 6500 to 7000 psi) diminished the stimulation volume and opened more previously non-dilatable NFs closer to the wellbore. Higher net pressure also triggered more stimulation downward and out of the target zone in the studied area. Third, halving the number of NFs and doubling their final storage apertures significantly magnified the fracturing-fluid efficiency (i.e., lowered leak off into NFs) in areas where it was restricted from flowing through non-dilatable NFs. Additionally, this modification caused greater lateral growth and comparatively large downward (out of target zone) growth of the HF and NF reactivation front, lowering the effectiveness of the HF job. However, halving the number of NFs and doubling their final storage apertures did not result in a substantial change in the SRV geometry upon allowing fluid flow through non-dilatable NFs. Fourth, altering the well-landing depth within the Woodford Shale did not result in a major shift in the overall stimulation geometry or volume. Most importantly, the simulated hydraulic fractures emanating from the wellbore do not span the entire recorded microseismic cloud length and height.

Role of fracture opening in triggering microseismicity observed during hydraulic fracturing

Hydraulic fracturing in low-permeability hydrocarbon reservoirs creates/reactivates a fracture network leading to microseismic events. We have developed a simplified model of the evolution of the microseismic cloud based on the opening of a planar fracture cavity and its effect on elastic stresses and pore pressure diffusion during fluid injection in hydraulic fracturing treatments. Using a material balance equation, we compute the crack tip propagation over time assuming that the hydraulic fracture is shaped as a single penny-shaped cavity. Results indicate that in low-permeability formations, the crack tip propagates much faster than the pore pressure diffusion front thereby triggering the microseismic events farthest from the injection domain at any given time during fluid injection. We use the crack tip propagation to explain the triggering front observed in distance versus time plots of published microseismic data examples from hydraulic fracturing treatments of low-permeability hydrocarbon reservoirs. We conclude that attributing the location of the microseismic triggering front purely to pore pressure diffusion from the injection point may lead to incorrect estimates of the hydraulic diffusivity by multiple orders of magnitude for low-permeability formations. Moreover, the opening of the fracture cavity creates stress shadow zones perpendicular to the principal fracture walls in which microseismic triggering due to the elastic stress perturbations is suppressed. Microseismic triggering in this stress shadow region may be attributed mainly to pore pressure diffusion. We use the width, instead of the longest size, of the microseismic cloud to obtain an enhanced diffusivity measure, which may be useful for subsequent production simulations.

A New Simple Analytic Equation for Estimating Asymmetric Growth of Stimulated Reservoir Volume in Anisotropic Shales

Summary The objective of this paper is to present the development and application of a simple equation for calculating the asymmetric growth of the stimulated reservoir volume (SRV) in an anisotropic shale–petroleum reservoir using microseismic data, and the hydraulic diffusivities of the anisotropic shale. Calculation of the SRV is a problem tackled with solutions that involve different degrees of complexity. Because shale reservoirs are anisotropic, microseismic events generally develop 3D nonuniform asymmetric patterns around the injection points. This paper presents a new method with an easy–to–use analytic equation that allows for reproducing the asymmetric growth of microseismic events as a function of time by considering reservoir anisotropy. Asymmetric growth refers to the fact that propagation of the microseismic cloud in a given direction can be larger, equal, or smaller compared with the propagation in other directions. Accurate determination of the SRV asymmetric pattern is critical for use in specialized material–balance and reservoir–simulation models of shale–petroleum reservoirs. This determination allows for more–realistic projections of reservoir performance. The novelty of the method is the development of an easy–to–use approach for estimating SRV in a spatially nonuniform asymmetric anisotropic reservoir using octants in a coordinate system. The SRV is calculated from the volume of a symmetric ellipsoid divided by a constant value Vc. This is despite the fact that the point of injection of the fracturing fluids in the asymmetric reservoir can be at, close to, or far from the center of the ellipsoid. The development of Vc is presented in this paper. Use of the SRV calculation model is illustrated with real microseismic data of the Horn River Shale in Canada for a case where Vc is equal to 1.3722. Also presented are calculations of hydraulic diffusivities in this anisotropic shale.

Stress Measurements for an In Situ Stimulation Experiment in Crystalline Rock: Integration of Induced Seismicity, Stress Relief and Hydraulic Methods

An extensive campaign to characterize rock stresses on the decameter scale was carried out in three 18–24 m long boreholes drilled from a tunnel in foliated granite at the Grimsel Test Site, Switzerland. The survey combined stress relief methods with hydrofracturing (HF) tests and concomitant monitoring of induced seismicity. Hydrofracture traces at the borehole wall were visualized with impression packer tests. The microseismic clouds indicate sub-vertical south-dipping HFs. Initial inversion of the overcoring strains with an isotropic rock model yielded stress tensors that disagreed with the HF and microseismic results. The discrepancy was eliminated using a transversely isotropic rock model, parametrized by a novel method that used numerical modelling of the in situ biaxial cell data to determine the requisite five independent elastic parameters. The results show that stress is reasonably uniform in the rock volume that lies to the south of a shear zone that cuts the NNW of the study volume. Stress in this volume is considered to be unperturbed by structures, and has principal stress magnitudes of 13.1–14.4 MPa for σ1, 9.2–10.2 MPa for σ2, and 8.6–9.7 MPa for σ3 with σ1 plunging to the east at 30–40°. To the NNW of the uniform stress regime, the minimum principal stress declines and the principal axes rotate as the shear zone is approached. The stress perturbation is clearly associated with the shear zone, and may reflect the presence of more fragmented rock acting as a compliant inclusion, or remnant stresses arising from slip on the shear zone in the past.

Experimental investigation of in situ and injection fluid effect on hydraulic fracture mechanism using acoustic emission in Tennessee sandstone

Hydraulic fracture propagation and associated rock failure mechanism is dependent on multiple factors including the reservoir pore fluid and its interaction with the rock and the fracturing fluid. This dependence of rock failure on in situ pore fluid could affect the stimulated volume and could manifest itself in the hydraulic fracturing diagnostics such as treatment pressure and microseismic. Therefore, it would be beneficial to an engineer designing, planning or interpreting a fracturing treatment to be aware of expected differences in hydraulic fracture responses in formations having different reservoir fluids, i.e. fracturing a gas or oil bearing formation.We investigate this effect by way of laboratory hydraulic fracturing experiments on triaxially stressed samples of Tennessee sandstone. The acoustic response during rock failure was monitored using 16 P-wave transducers and the waveforms were acquired using a continuous acoustic monitoring system. The effects of pore pressure, water weakening and viscosity of the injection fluids on hydraulic fracture propagation and associated damage are investigated using six experiments on dry, brine saturated and dodecane saturated Tennessee sandstone, fractured with either water (1 cP) or oil (50 cP). Significant rock weakening was observed in fluid saturated samples (breakdown pressures exhibited a reduction of 15–40% from dry state breakdown pressures); the presence of more polar fluid (water) in the pore space resulted in more weakening (800–900 psi lower breakdown pressures when water saturated vs. dodecane saturated). The effect of injection fluid viscosity is observed to be suppressed for fluid saturated samples as breakdown pressures for samples which were saturated with either fluid (brine and dodecane) were observed to be almost same. Acoustic event distributions, continuous stream monitoring, failure mechanisms and permeability measurements on fractured cores all seem to suggest a more complex fracture network in dry rock and more conventional tensile type failure in brine saturated rock. Continuous acoustic stream energy variation with time offers insight into the induced fracture complexity and should be used along with microseismic cloud distributions to assess the stimulated reservoir volume.

A study of 3D modeling of hydraulic fracturing and stress perturbations during fluid injection

This paper investigates a hydraulic fracture development and its potential impact in terms of elastic stress perturbations and fracture triggering. The hydraulic fracture is simulated during fluid injection with a fully coupled hydromechanical 3D discrete-element method in a homogeneous granite without (i.e. intact rock) and with pre-existing fractures. The results of the models show how pre-existing fractures affect the growth rate, the accumulation of the displacement and interaction between hydraulic and mechanically-induced fractures. In the intact rock model, a circular hydraulic fracture grows normal to the minimum principal stress due to successive tensile failures. The measured length of the hydraulic fracture increases as a fractional power of time for a constant injection rate and the maximum aperture is positively correlated to the length. Stress perturbations observed in the model promote tensile and shear failure at the hydraulic fracture tips, but inhibit failure near the fracture walls. We expect microseismicity to be concentrated near the fracture tip, with a more linear shape, assuming negligible pore pressure diffusion. Similar hydraulic fracture behavior is observed in a model with preexisting fractures disconnected to the fluid injection. Conversely, fluid leakage occurs in a model with connected natural fractures. This strongly impacts the growth of the hydraulic fracture, with a fracture length increasing linearly with time, and a very limited fracture aperture that is essentially constant over time. In this case we describe a significant reduction of the elastic stress perturbation and a more elliptically microseismic cloud is expected to grow away from injection point. Such typical signatures can be used for interpretation of ongoing rock deformation in natural hydraulic fracture treatments. These results confirm analytic expectations and give insights into rock deformation occurring in natural hydraulic fracturing.

Using Embedded Discrete Fracture Model (EDFM) in numerical simulation of complex hydraulic fracture networks calibrated by microseismic monitoring data

Hydraulic stimulation of unconventional shale and tight reservoirs often creates a complex induced fracture network, which requires a comprehensive characterization for successful exploitation and development. One of the major technologies applied over the past decade to image hydraulic fractures is microseismic monitoring, which analyzes seismic information recorded during hydraulic stimulation to locate the rock deformation. Results of the microseismic data interpretation are then used to generate and calibrate a model of the hydraulic fracture network. However, because of the complexity of the fracture model and the shortcomings of reservoir simulators, direct application of these complex fracture networks has been very limited. Instead, oversimplified models are used to assess the efficiency of the hydraulic fracturing treatment. Such assessment techniques, without further modeling and simulation of hydrocarbon production and pressure drainage, fail to represent an accurate view of the connectivity and complexity of the fracture system.In this paper, we present the application of an Embedded Discrete Fracture Model (EDFM) in numerical simulation of realistic geometry of fractures. With EDFM, each fracture plane is embedded inside the computational matrix grid and is discretized by cell boundaries. We have implemented EDFM in The University of Texas at Austin (UT) in-house reservoir simulator UTCOMP. We discuss the implementation approach using non-neighboring connections. Using the developed simulator, we studied gas production from hydraulic fracture networks calibrated from actual microseismic monitoring data. We investigated the impact of fracture network geometry on the overall performance of these hydraulic stimulations.Simulation results indicate that the efficiency of well treatment is primarily controlled by the interconnectivity of hydraulic fractures and the distribution of conductivity within the fracture network. For a given microseismic cloud, a wide range of production responses was observed by changing the degree of connectivity in the calibrated model. Moreover, the study showed that taking into account the role of aseismic deformations (such as tensile openings) significantly increased cumulative production forecasts. Neglecting the effect of these fractures may lead to underestimation of ultimate recovery.

Further testing of the bedding-plane-slip model for hydraulic-fracture opening using moment-tensor inversions

Moment tensors are calculated by using the P-wave first motion peak amplitudes of 59 microseismic events with high signal-to-noise ratio. These events are from a surface microseismic data set gathered during hydraulic-fracture stimulation of the Marcellus gas shale in Washington County, Pennsylvania, USA. The majority of these 59 events have a horizontal nodal plane ([Formula: see text] a few degrees) characteristic of a dip-slip/horizontal-slip moment tensor. If the horizontal nodal plane is an auxiliary, the vertical nodal plane has a pure dip-slip motion, which is inconsistent with the opening motion for vertical hydraulic fractures that enables proppant loading. This points to slip on horizontal nodal planes with the auxiliary vertical nodal planes aligned with the local maximum horizontal stress orientation as indicated by drilling-induced fractures in nearby vertical wells. These 59 microseismic events are caused by slip on horizontal mechanical discontinuities such as bedding planes during the opening of vertical hydraulic fractures, a model first proposed by research teams headed by Rutledge and Eisner, respectively. During several stimulation stages in the Washington County Marcellus gas shale, a pattern of opposite slip direction develops within “double lineaments” of microseismic clouds. This suggests that fracking fluid is not only able to move in the direction of fracture propagation, but it can also spread sideways into previously unstimulated rock. A secondary microseismic cloud consistently initiates at approximately 133 m (400 ft) from the position opposite the central perforation toward the unstimulated heel of the horizontal wells. From these moment tensors, we have concluded that microseismic focal mechanisms with horizontal nodal planes are direct evidence of the presence of treatment fluid in open hydraulic fractures.

Fracture modes in the Silurian Qusaiba Shale Play, Northern Saudi Arabia and their geomechanical implications

Fracture and in-situ stress studies were conducted for unconventional prospect evaluation in the Silurian Qusaiba Shale, northern Saudi Arabia. Borehole image logs, oriented cores, seismic, and drilling observations were used in the studies. The fractures include natural fractures and induced fractures. The induced fractures were studied to assess the stress regime in terms of directions and magnitudes. The present day maximum horizontal in-situ stress trend varies from NNW-SSE to NNE-SSW, and shows a regional pattern dominated by Arabian plate tectonics. The relative magnitudes of the current day stresses are characteristic of an extensional to strike-slip regime. Natural fractures of microscopic (microfractures) to macroscopic (macrofractures) scales include extension fractures (joints/veins), and faults manifested as shear and hybrid (extensional-shear and compressional-shear) fractures. Joints clustering into zones are rare, unless when associated with fault zones. Over half of the faults (56%) show clustering into fault zones with their widths (thickness) varying by up to 5 orders of magnitude, and lengths and displacements varying by up to 4 orders of magnitudes respectively. The study identified five distinctive, regional, fracture sets: one gently dipping (bedding-parallel or at low angle to bedding) and up to four moderately to steeply dipping fracture sets: an easterly striking set is the oldest, followed by three younger major sets striking NNW-SSE, N-S, and NNE-SSW. The younger fractures are nearly parallel to the present day maximum horizontal in-situ stress. Crack-seal mechanism (natural hydrofracturing) dominates initial fracture growth, some with several phases of partial to complete mineralization or coating, dominated by calcite, quartz, and dolomite. Aqueous and hydrocarbon gaseous and fluid inclusions are common in the fractures' mineral filling. The regional nature of in-situ stresses and natural fractures means their occurrence, orientation, relative dominance, and relative age and relative apertures are easier to predict and manipulate for well planning and completion, including hydrofracturing. Forward modeling shows that natural fracture network are not critically stressed under reservoir conditions but when subjected to massive hydrofracture stimulation they and the bedding discontinuities form the seeds for the growth of a complex hydrofracture network that potentially grows out of presumed stress-barriers. Lack of stress rotation around faults in wells supports the modeling results. Microseismic monitoring gives time-lapse (incremental) microseismic events of two types; random and linear patterns parallel to maximum horizontal in-situ stress and the predominant natural fracture trend. Bulk microseismic cloud has no unique link to fault trends mapped from high resolution borehole images. This finding challenges the usability of uncalibrated microseimic monitoring of massive hydrofracturing to map faults.