Mitigating Risks in Hydraulic Fracture Design for a Complex Carbonate Reservoir

Abstract

Abstract We use advanced modeling techniques to optimize wellbore landing, completion configuration, and stimulation treatments in a complex carbonate reservoir in the Middle East. The reservoir, where target formations are highly laminated, naturally fractured, and stresses are transitional as a function of depth, presents conditions for which a more sophisticated stimulation design approach is required. A meticulous analysis of wellbore image logs and detailed forward modeling of the geometry of the drilling induced tensile fractures revealed that in situ stresses rapidly transition between strike-slip and reverse faulting as a function of depth. The log-derived geomechanical model was calibrated against wellbore failure observations, laboratory measurements, and mini-frac test results. The stresses and rock properties were mapped to the 3D reservoir volume assuming a horizontally layered formation. Models of hydraulic fracture propagation in the presence of natural fractures and laminations under vertically heterogeneous stress conditions were investigated using a 3D simulator that couples geomechanics, fracture mechanics, fluid behavior, and proppant transport. Modeling results reveal hydraulic fracture propagation is profoundly influenced by the complex stresses and structures in this reservoir. Simulation results indicate that vertical hydraulic fracture propagation (height, growth) is controlled by stress contrasts, stress state, elastic, and strength variations between adjacent formations, and the frictional strength of weak bedding discontinuities that are ubiquitous in tight formations. Results also show limited height growth within a reverse-faulting zone where modeling predicts a tendency for the development of horizontal limbs ("T-shaped" fractures). Hydraulic fracture geometry is significantly different in the presence of weak bedding compared to bedding with sufficient strength to transmit crack tip stresses across the interfaces. Significant amounts of fluid and proppant can be diverted into created horizontal fractures in this reservoir. Increasing fluid viscosity improves the propped surface area and controls the height growth within the zone of interest. Capturing such subsurface complexities and using them to simulate hydraulic fracture propagation helps us to improve treatment designs, reduce operational costs, and ultimately improve hydrocarbon recovery. This study illustrates that for more complex reservoirs where spatial heterogeneities, preexisting natural fractures, or transitional stress states are present, using advanced 3D modeling is essential. Through parametric stimulation modeling, design parameters can be refined to achieve optimal solutions to better manage the controllable drilling, completion, stimulation, and production parameters that present the primary risks to development in tight/unconventional reservoirs.