Hydraulic Blowout Control Requirements for Big-Bore and HP/HT Developments: Validation With Field Experience

Abstract Although advances in drilling and well intervention technology have made blowouts a rare phenomenon, their consequences are often of such a magnitude that for each development a contingency plan should be available aimed at limiting the damage and regaining control over the outflow of the well rapidly. This plan should consider all possible blowout scenarios and the corresponding response. When capping, the most efficient method, is not an option, e.g. for subsea or underground blowouts, downhole injection of kill fluids through an existing conduit or relief well(s), the hydraulic or "dynamic" kill, is the next best alternative. To plan for such an operation prior to actually spudding the development wells, a number of parameters needs to be known such as the required number and dimensions of relief wells, kill fluids and kill rates, pump capacity etc. For HPHT and big bore developments, these requirements cannot be derived from experience. It is shown here that the requirements depend on a limited number of factors such as the pressure regime of the blowing formation and flow resistance of the blowing well. This allows formulation of guidelines for hydraulic blowout control for (un-) conventional developments, even when the exact circumstances of a blowout are not known, as is the case in contingency planning. A comparison with selected field cases of blowouts demonstrates that the formulated guidelines match the experience with actually killing these blowouts in terms of the number of wells, pump rates, and kill fluids etc. that were eventually required. This gives the confidence that the guidelines are a good starting point for contingency planning. The case of a giant North Sea gas field is discussed to demonstrate this.