Abstract
High breakdown pressure is one of the major challenges of deep and tight gas reservoirs. In certain wells, achieving breakdown pressures within the tubular completion yield limit is not possible. Such zones may have to be abandoned without fracturing. Using thermally controlled fluid can lower the formation temperature and ultimately reduce the stresses of tight gas reservoir formations near the wellbore. The objective of this study was to prove numerically that having a cooled near-wellbore region is a feasible and effective solution for reducing breakdown pressure. An integrated hydraulic fracturing and reservoir simulator developed at the University of Texas at Austin was utilized for this study. The simulator is a non-isothermal multi-phase black oil flow in the reservoir, fracture, and wellbore domains. This research found that using thermally controlled fluid is effective at reducing breakdown pressure. Under simulated conditions, the bottomhole pressure decreased by up to 60% when the temperature of the near-wellbore region was reduced by 60℉. Injecting thermally controlled fluid not only reduced the high breakdown pressure but also improved the hydraulic fracture's efficiency and complexity. This technique is novel and has not yet been studied in depth in the literature. Utilizing thermally controlled fluid could be a cost-effective solution for reducing high breakdown pressure in tight gas reservoirs.
•Coupled black-oil flow in reservoir, fracture, and wellbore domains employed in tight gas reservoir stimulation.•Reduction of high breakdown in tight gas reservoirs through cooling.•Significant impact of temperature differences on fracture growth.•Higher reduction in the total minimum horizontal stress due to cooling.•Impact of various thermal and geomechanical parameters on effectiveness of cooling.