Hydraulic fracturing is frequently used to create the reservoir-wellbore connectivity required to produce the hydrocarbon from tight formations. Many factors can be considered as risks to the success of operations. One arises in reservoirs with a water-bearing zone in close proximity to the net pay. Many times, the risk of fracture growth into the water zone limits the stimulation options and eliminates the option of a hydraulic fracturing treatment, thereby constraining the well’s future production. The challenges increase when the reservoirs are deep, hot, and exhibit a high Young’s modulus. Under these conditions, it greatly increases the risk of an early screenout, and the introduction of fracturing fluid into the formation before a high-conductivity proppant pack is fully placed will damage the formation and hinder production. In Saudi Arabia, a well in a relatively new field encompassed all three challenging characteristics. The target reservoir section was between two water-bearing zones, had high bottomhole temperature, and high Young’s modulus. Traditional polymer-based crosslinked fluids would address the challenges from the perspective of proppant placement. However, these thick crosslinked fluids would also risk in uncontrolled fracture growth into the water zones. A polymer-free, high-temperature viscoelastic surfactant (VES) fracturing fluid was used to balance the risks of incomplete proppant placement, formation damage, and fracture growth that would result in water production. The VES fluid selected for treatment of Well SH-3 has a low viscosity compared to that of a traditional crosslinked fluid; it therefore generates less net pressure and thus lowers the risk of the fracture growing into the water zones. It also has excellent capacity to carry and suspend proppant. To increase its efficiency, the VES fluid was further enhanced by using a degradable fluid-loss additive. Pumped on a conservative schedule, the hydraulic fracturing treatment placed 61,500 lbm of proppant into the thin reservoir section between two water-bearing zones without any operational issues. The Minifrac analysis, stress profile calculation, and fracture geometry characterization, as well as no water production, has confirmed the controlled fracture height growth. Furthermore, pre- and post-stimulation analyses validated the improved productivity, giving a successful stimulation option for the development of this field.


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