Modeling Field Injectivity Tests and Implications for In Situ Stress Determination

Abstract

Knowledge of underground stresses (e.g., minimum horizontal stress) is vital for many aspects of oil and gas development, such as wellbore stability evaluation, lost-circulation prediction, casing design, hydraulic-fracturing design, sand-production prediction, and reservoir-compaction evaluation. Field injectivity tests performed during drilling a well, such as the extended leak-off test (XLOT) and pump-in and flowback (PIFB) test, are the primary method for obtaining that information. In this study, a fully coupled fluid-flow and geomechanics model was developed for numerical simulation of field injectivity tests. The model takes into account key elements of the tests, including fluid flow into the well, hydraulic fracture propagation, fluid flow in the fracture, pore-fluid flow, and deformation of formation rock. The model is validated against an existing analytical model and a field test reported in the literature. Finally, numerical examples are shown for injectivity tests with pump-in, shut-in, and flowback stages in formations with high permeability and low permeability, respectively. The development of fracture geometry and injection pressure was quantified during the tests. The results show that the essential features of injectivity tests observed from field practices can be captured by the model. It is demonstrated that fluid leak-off on fracture surfaces can significantly influence pressure response and fracture behavior. The results also illustrate that the traditional method for interpretation of the test based on time development of injection pressure has difficulty in properly determining the minimum principal in situ stress in formations with low permeability because of limited leak-off. The model presented in this article provides a useful tool for optimizing the design of injectivity tests, ensuring sufficient and high-quality data, and aiding interpretation of the tests.