Produced water generated by hydrocarbon production from the Mississippian Barnett Shale in the Fort Worth Basin has been injected into geologically complex carbonates of the Ordovician Ellenburger Group (EBG) for 20 yr. The basin experienced anomalous seismicity in the crystalline basement induced by the associated pore pressure increase. A comprehensive hydrogeologic flow model of the EBG covering ∼30 counties provides estimates of pore pressure evolution through space and time that can be used for understanding the seismic events and for management of the disposal resource. A salient aspect of the model is the thorough treatment of faults and fractures. They form important features of these structurally complex formations, and their permeability was estimated through a discrete fracture network modeling approach. A total of 127 salt-water disposal wells injected a cumulative volume of 2.23 billion bbl (354 × 10⁶ m³) from ∼2003 to 2018. Overall, the EBG is very resilient to large injection volumes with small pore pressure increases up to 1.4 MPa (200 psi). Several high-permeability faults act as pressure distribution and attenuation features, distributing pressure increases vertically and preventing it from extending to the next fault compartment. However, pressure diffusion away from injection centers is controlled by the fractured rock matrix. In addition, the overlying Barnett modulates pressure increases when in direct contact with the EBG because it acts as a compressible cushion, but the impact of gas production does not seem to be as significant. Water withdrawal from the EBG through gas production wells, which has been observed, also contributes to limiting the pressure increases.