Abstract
High breakdown pressure is one of the major challenges in deep tight gas reservoirs. In certain wells, achieving breakdown pressures within the completion tubular yield limit is not possible, and those zones may have to be abandoned without fracturing. Using thermally controlled fluid can lower the formation temperature and ultimately reduce the stresses of the tight gas reservoir formation near the wellbore. The objective of this study is to prove numerically that having a cooled near-wellbore region is a feasible and effective solution to reduce the breakdown pressure. An integrated hydraulic fracturing and reservoir simulator that has been developed at the University of Texas at Austin is utilized for this study. The simulator is a non-isothermal, multi-phase black-oil flow in reservoir, fracture, and wellbore domains. It was found that using thermally controlled fluid is effective in reducing breakdown pressure. Bottomhole Pressure (BHP) decreased by up to around 60% when the temperature of the near-wellbore region is reduced by 60 °F under the simulated conditions in this study. Injecting thermally controlled fluid did not only reduce the high breakdown pressure but also improve the hydraulic fractures efficiency and complexity. This technique is novel and has not been studied in depth in the literature. Utilizing thermally controlled fluid can be a cost effective solution to reduce high breakdown pressure in tight gas reservoirs.
A New Cost Effective Well Testing Methodology for Tight Gas Reservoirs
