An Innovative Study to Predict Fracture Propagation in High Temperature Reservoirs with In-Situ Stresses Regime Affected by Cold Fluids Injections

Abstract

Hydraulic fracturing has been an industry standard for the past decades; however, most recent applications are performed in extreme down-hole conditions: complex stresses regime, extended reach sections, abnormal pressure and temperature gradients proved to be strenuous challenges, especially with limited time and budgets. This paper explores the challenges of designing, completing and fracturing High Temperature (HT) tight reservoirs. A novel approach to the problem was mandatory to account for thermal effects on stress regime to increase overall chances of success of stimulation treatments. This multi-disciplinary method interconnects petro-physics, rock mechanics, fluid dynamics and operations by combining data from literature and from the field with the purpose of providing a tailored solution to the new challenges ahead. Hydraulic fracturing in High Temperature reservoirs is indeed a demanding task, for which specialized products have been developed throughout time, such as for example, HT fracturing fluids. However, despite accounting for HT gradients, sometimes the outcomes of hydraulic fracturing activity were surprising or inexplicable; sometimes, even disappointing. Therefore, "post-mortem" reviews are often a must-do: data coming from the field and post-treatments results are analysed from scratch, wiping out any known-fact about the specific well and revising all the possible root causes for the anomalous behaviours. Petro-physical data, tectonic regime, stresses, hydraulic fracturing geometry and diagnostics were entirely accounted for to provide an explanation of the final well results, ultimately resulting in more questions than answers, as it so often happens with science. In drilling operations, the thermal effect of cold fluids on fracture gradients and its influence on losses has been deeply investigated, becoming an industry best practice. However, the effect of cool-down due to fluid injection at high rates with hydraulic fracturing applications are not captured by dedicated literature and, even less, by modelling softwares. As a result, a non-conventional approach to the creation of a geo-mechanical model that could take into account the thermal effect of cold frac fluids injection was elaborated and several sensitivities to understand fracture propagation mechanism were performed, highlighting a wide range of variability which is attributable to the influence of temperature on stress regime. High temperature reservoirs proved easier to frac than expected due to the decrease in terms of pressure required to initialize a fracture. However, this phenomenon could hide potential dangers when it is required to contain such fracture in the targeted interval. The correct modelling of such effect is of extreme importance to forecast fracture geometry, proppant placement and final conductivity requiring to re-adapt and re-adjust field-proven, industry-standardized hydraulic fracturing models and practices to match results with expectations.