Abstract
Produced water re-injection (PWRI) has been used in the oil industry in concept and application. The long-term injectivity of PWRI wells often declines for various reasons, including but not limited to, complex fracture propagations from injection wells to production wells, potential cap rock interference, and formation damage by suspended solids, and inadequate pumping capacity to maintain desired and favorable fracture propagation conditions.
In fracture modeling, in-situ conditions of the target sand formations (e.g. stress magnitudes and direction, Poisson's Ratio, Young's Modulus, temperature, thermal expansion coefficient, and reservoir properties) has significant effects on fracture propagation and injectivity. The importance of these parameters are noteworthy, during the planning stage of the PWRI, these parameters should be characterized as accurately as possible for prediction of fracture dimensions to be propagated from injection wells to production wells. Other operational parameters, such as the number of injection wells, well trajectory, and injection water temperature and pump capacity can be optimized to determine and maintain the long-term injectivity and fracture propagation without interfering with other production wells and especially the cap rock.
In this paper, PWRI modeling software was used to model fracture propagation and injectivity during PWRI periods. Two cases were studied for planning and decision-making of PWRI application in sand formations. In the first case, the fracture propagation into upper cap rock was studied for various water injection volumes and solids concentrations. The fracture propagation was observed with increasing reservoir pressure for a continuous 15 years of injection and the stress profile contrast. In the second case, fracture propagation analysis of water injection wells was performed with potential completion problems (i.e. tubing to annulus communication or casing shoe bursting) and interference between injection and production wells. The results demonstrate that for both cases, the injection fluid temperature was an important factor that could considerably change the fracture length size and provided information about the fracture propagation from injection to production wells. The fracture size and injectivity index also depended on the concentration of total suspended solids that affected the injectivity.
