Hydraulic fracturing (HF) to enhance ultimate hydrocarbon recovery factor – RF – is becoming a more common reservoir stimulation method in higher permeability reservoirs, extending its perceived use beyond merely accelerating production. HF is a complex engineering process with large capital costs; a rational and effective design process is the key step to mitigate the potential economic risks and increase the efficiency of the HF treatment. There are several numerical and analytical methods to simulate HF treatments and estimate the geometry of the induced fracture. In this study, the target reservoir formation, a conventional carbonate gas field, was divided into 5 geomechanical units (GMUs). Each GMU has different permeability values, which range from 3.5 to 300 mD. Geomechanical characteristics of each GMU were defined by laboratory tests to obtain fracture toughness (KIC), hydraulic tensile strength (THF), unconfined compression strength (UCS), Young’s modulus (E), Poisson’s ratio (v), cohesion (c') and internal friction angle (F'). Then, using the finite element method (FEM), HF treatment was simulated in each GMU as continuous fluid (water) injection for 20 minutes at a rate of 20 bbl/min. A cohesive zone model (CZM) was assumed for all units as a behavioral rock failure model. The fracture aperture was compared with geomechanical characteristics of each GMU, showing that aperture is strongly related to E, KIC, and THF rather than v, c', F'. Incidentally, as each of these five parameters (except v) increases, aperture decreases. Because slip and shear dilatancy of induced shear fractures was not addressed in this study, no meaningful relation between fracture aperture and c' or F' exists. For a given volume of injection, fracture length is necessarily in an inverse relationship with the five parameters (except v).

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