Summary Fault shear slip potential is analyzed in the area where induced earthquakes (up to 3.9 Mw) occurred in May-June 2015 approximately 30 km south of Fox Creek, Western Canada Sedimentary Basin, Canada. The induced earthquakes were generated by the hydraulic fracturing of the Upper Devonian Duvernay Formation. Interpretation of a 3D seismic survey and analysis of the ant tracking attribute identifies a linear discontinuity that likely represents a subvertical fault with strike length of 1.4 km, which is aligned with the zone of induced earthquake hypocenters. 1D-3D geomechanical modeling is conducted to characterize mechanical rock properties, initial reservoir pressure and stress field. Hydraulic fracture propagation and reservoir pressure buildup simulations are run to analyze lateral fluid pressure diffusion during well treatment. The interaction of natural fractures introduced as Discrete Fracture Network and hydraulic fractures is tested. 3D poroelastic reservoir geomechanical modeling is completed to simulate slip reactivation of the identified fault zone. The obtained results support that additional pressure buildup of 20 MPa in treatment wells can propagate laterally along hydraulic fractures (and potentially natural fracture network) for about 550 m and reach the fault zone. The increase of fluid pressure by 20 MPa in the fault zone results in dextral slip along the fault, mostly in the interval of the Duvernay and overlying Ireton Formations, corroborating prior focal mechanism results and hypocentral depths. The simulations indicate that lateral transmission of additional fluid pressure from the fracturing stimulation area to the fault zone could happen in a few days after the treatment of lateral wells that is supported by the observed induced earthquakes. This study helps to quantify changes in fluid pressure and stresses that may result in fault shear slip during hydraulic fracturing and predict the potential of induced seismicity connected to hydrocarbon production from the Duvernay Play.

Hydraulic fracturing in multi stage horizontal unconventional wells is perhaps one of the most important if not the most important in the drilling and completion cycle of these wells. It's also the most applied technique repeatedly in multiple formations throughout the world and yet the question that looms large over us, do we understand the fracture geometry in these unconventional environments.Year on year most unconventional formations seem to fall in line with the industry trend of increasing lateral lengths and pumping more stages to improve production and recovery. Again, we need to ask ourselves if this is sustainable. Introspection of data available from public data seems to indicate that a significant chunk of these wells buck the trend of increased lateral lengths and stages and we still continue to apply these techniques especially in a price sensitive oil market. What if we could challenge this paradigm through a systematic engineering process that could relate the impact of fracture geometry and well spacing? We selected one of the up and coming plays in Canada that is on the road to development called the Duvernay.The Duvernay Formation is a unit of the Woodbend Group and is considered as the source rock for prolific reservoirs such as the Leduc reefs. Duvernay formation holds an estimated 443 trillion cubic feet of gas and 61.7 billion barrels of oil.This paper is an attempt to model and understand complex hydraulic fractures in a multi well pad environment coupled with production modelling to understand drainage patterns. Public data from the IHS database was used to construct and build a geocellular model and wells that had petrophysical and geomechanical data were used to build a representative well pad model. Using the model built complex fractures using the unconventional fracture models were simulated in a multi well pad environment. Impact on reservoir drainage has been assessed with various simulations by changing different parameters with respect to hydraulic fracturing. The results of these various simulations are presented in the paper and these simulations act as a tool to understand when possible interference may occur in these pads. Spacing of wells and frac sizes can be adjusted to minimize competitive drainage between wells.

Stimulating Shale Gas Wells has become a mundane activity with very little or no engineering. The industry has focused heavily on reducing costs and increasing efficiencies of operations that there is seldom any time for engineering. The lack of any horizontal logging information, assumptions that rock quality does not change have led to excel driven spreadsheets doing glorified mass balances which are considered as the fracture designs of today. In addition to this the same fracture treatment is pumped stage after stage well after well. Needless to say the industry's lack of ability to model these complex fractures has also contributed to the exercise of moving away from fundamental fracture design. This trend has resulted in productivities of wells being all over the place that mostly are unexplained. The industry is beginning to realize that a significant % of the wells drilled in unconventionals are not profitable.Refracturing is also gaining prominence because of a single important factor that primary initial completions are ineffective. Shale 2.0 is all about integrating seismic to stimulation information to provide better answers and ultimately better productivity via simple measurements in the lateral. These measurements are ultimately used to engineer the completion, design and understand the science behind fracturing than just merely pumping the job. This paper details the planning, design and evaluation processes in the application of a new workflow called the Unconventional Reservoir Optimized Completion workflow. This revolutionary Seismic to Stimulation workflow demonstrates with examples how we have migrated, a dominant well centric process to a reservoir centric process. A significant step change in fracture modelling has been applied using unconventional fracture models which have the ability to model complex fractures using discrete fracture networks. These models can be validated using microseismic and when calibrated with production can become a powerful prediction tool. Experiences and lessons learned in the Canadian Montney will be presented.

Geomechanics plays a significant role in hydraulic fracture initiation and propagation and in the interaction between hydraulic fractures and natural fractures, especially in unconventional reservoirs. This paper provides a detailed description of a geomechanical characterization and modeling study for evaluating the impact of geomechanics on completions and hydraulic fracturing stimulations optimization in the Montney resource play, Canada. Following an integrated workflow, 1D mechanical earth models (MEM) for ten wells were constructed in the study area. These 1D MEMs include elastic and strength properties, pore pressure, direction and magnitude of in-situ stresses. Extensive rock mechanics core testing data were used to calibrate the elastic and strength properties. Pore pressure and fracture closure pressure data from diagnostic fracture injection tests were also available to calibrate pore pressure and minimum in-situ stress. Maximum horizontal stress was constrained by modeling wellbore stability and matching it with caliper logs and wellbore stability features on wellbore image. A 3D mechanical earth model was subsequently constructed using a 3D geological model, the 1D MEMs, and seismic inversion data. Elastic properties from seismic inversion were used to populate mechanical properties in the 3D model. In-situ stresses were numerically simulated to account for the impact of faults and structural and mechanical property variation on in-situ stress distribution. The geomechanical analysis shows that there is a decreasing trend in Young’s modulus from upper Montney to lower Montney while Poisson’s ratio is relatively constant in the Montney. The pore pressure in some parts of the field is high and varies across the field. Stress regime is predominantly strike-slip with relatively large stress anisotropy, and this has implications on the hydraulic fracture network that would be simulated, shearing of natural fractures and the stimulated reservoir volume. Rock elastic and strength properties, pore pressure, and in-situ stresses were found to be heterogenous across the whole field. The relatively large variation in pore pressure in the study area and the structural complexities have large impact on the distribution of stresses. Faults alter the stress distribution locally and could affect hydraulic fracture propagation. Hydraulic fracture simulations were subsequently performed, and the geometry of the simulated hydraulic fractures and the stimulated reservoir volume were validated with microseismic events. The effects of geomechanics on fracture geometry and ultimately reservoir production were evaluated. Because of the significant impact of geomechanics on hydraulic fracturing, it is critical to characterize and model geomechanics accurately. This paper provides a comprehensive approach and application to a field in the Montney, showcasing the integrated method of geomechanical characterization and hydraulic fracture simulation and production modeling using various data. The analysis provides an interrelationship among geomechanical parameters, microseismicity and stimulated reservoir volume.

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