Re-Injection is one of the most important methods to dispose fluid associated with oil and natural gas production. Disposed fluids include produced water, hydraulic fracture flow back fluids, and drilling mud fluids. Several formation damage mechanisms are associated with the injection including damage due to filter cake formed at the formation face, bacteria activity, fluid incompatibility, free gas content, and clay activation.
Fractured injection is typically preferred over matrix injection because a hydraulic fracture will enhance the well injectivity and extend the well life. In a given formation, the fracture dimensions change with different injection flow rates due to the change in injection pressures. Also, for a given flow rate, the skin factor varies with time due to the fracture propagation. In this study, well test and injection history data of a Class II disposal well in south Texas were used to develop an equation that correlates the skin factor to the injection flow rate and injection time. The results show that with time, the skin factor decreases until such a point at which the fracture dimensions are sufficient without further propagation to handle the injected water volume (stationary fracture). A constant skin factor is noted after this point. At higher injection flow rates, the constant skin factor achieved is lower because of the larger fracture dimensions developed at higher injection flow rates.
Produced water re-injection (PWRI) is often the safest and most economical method for disposal of produced water in the oil industry. Two key issues that affect the management of PWRI are the formation damage and the constrained pumping pressure at the wellhead. A simulator was developed to handle the design of single-zone or multi-zone water injection in multilayered reservoirs. The simulator can accommodate both vertical and horizontal wells operated under matrix and/or fractured regimes. It is also able to account for the impact of formation damage and user-defined wellhead pressure constraints. Results obtained from the simulator showed good agreement with known injection behaviors. For vertical wells, injection conformance depends on KH (permeability-thickness) and the minimum horizontal stress; in the case of multi-fractured horizontal wells, the outermost fractures (those near the tip and the heel of the horizontal well) are longer than the fractures in the middle. Lastly, by constraining the maximum allowable surface pressure, frictional pressure drops in both the wellbore and fracture cause the injection rate to decline, which in turn affects both the fracture geometry and the maximum disposal volumes.