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In situ stress is one of the key engineering parameters that ensures caprock integrity in steam-assisted gravity drainage (SAGD) operations. Massive steam injections during an SAGD operation leads to significant changes in the pore pressure, temperature, stress, and volumetric strain in the rock formations. These changes trigger deformation and stress redistribution in the overburdened strata, which could lead to a containment breach of the caprock through shear or tensile failure. To ensure subsurface steam containment, both to satisfy public safety considerations and instill confidence that the steam containment will continue over the necessary timescales, the Alberta government requires every SAGD operator to measure the in situ stress conditions in the oil sands reservoir and its caprock. Minifrac test is a suggested method that can measure the minimum principal stress with high confidence. A safety factor (SF) of 80% is used to determine the maximum operation pressure (MOP) for safe SAGD operations; in other words, MOP = 80%* σ min , where σ min is the minimum principal stress at the base of the caprock. In most cases, this 80% SF safeguards the SAGD injection pressure to always remain lower than the σ min at the base of the caprock, ensuring that no tensile fractures are initiated at the caprock. In this study, we compiled a database containing in excess of 100 minifrac datasets across the Athabasca oil sands region and constructed an in situ stress map. Based on our in situ stress dataset, we developed a quantitative risk model to analyze the effects of uncertainties on the probability of exceedance (i.e., the probability that the MOP exceeds the fracture pressure at the base of the caprock). The risk model involves defining probability distributions to quantify the uncertainties at the shallowest depth and minimum stress gradient. The output of the risk model was a set of predictions of exceedance probabilities, which were computed using Monte Carlo simulations. Through a statistical analysis of this in situ database and risk-based simulation analysis, this study demonstrates the reliability of a SF of 80%. • We compiled a database containing more than 100 minifrac datasets across the Athabasca oil sands region and constructed in-situ stress maps. • It is the first time that the in-situ stress maps in the Athabasca oil sands region are summarized. • It is the first time that the meaning of safety factor in Athabasca SAGD operations is interpreted based on in-situ stress database and risk-based mathematical model. [ABSTRACT FROM AUTHOR]

Fault shear slip potential is analysed in the area where induced earthquakes (up to 3.9 M w) 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 3-D 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 hypocentres. 1-D–3-D geomechanical modelling is conducted to characterize mechanical rock properties, initial reservoir pressure and stress field. Hydraulic fracture propagation and reservoir pressure buildup simulations are run to analyse lateral fluid pressure diffusion during well treatment. The interaction of natural fractures introduced as Discrete Fracture Network and hydraulic fractures is tested. 3-D poroelastic reservoir geomechanical modelling 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. [ABSTRACT FROM AUTHOR]

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