Summary Waterflooding for enhanced oil recovery requires that injected waters must be chemically compatible with connate reservoir waters, in order to avoid mineral dissolution-and-precipitation cycles that could seriously degrade formation permeability and injectivity. Formation plugging is a concern especially in reservoirs with a large content of carbonates, such as calcite and dolomite, as such minerals typically react rapidly with an aqueous phase, and have strongly temperature-dependent solubility. Clay swelling also can pose problems. During a preliminary waterflooding pilot project, the Poza Rica-Altamira oil field, bordering the Gulf coast in the eastern part of Mexico, experienced injectivity loss after 5 months of reinjection of formation waters into Well AF-847 in 1999. Acidizing with hydrochloric acid (HCl) restored injectivity. We report on laboratory experiments and reactive-chemistry modeling studies that were undertaken in preparation for long-term waterflooding at the Agua Fría reservoir. Using analogous core plugs obtained from the same reservoir interval, laboratory core-flood experiments were conducted to examine the sensitivity of mineral-dissolution and -precipitation effects to water composition. Native reservoir water, chemically altered waters, and distilled water were used, and temporal changes in core permeability, mineral quantities, and aqueous concentrations of solutes were monitored. The experiments were simulated with the multiphase, nonisothermal reactive transport code TOUGHREACT™ (Lawrence Berkeley National Laboratory, Berkeley, California, 2004), and reasonable-to-good agreement was obtained for changes in solute concentrations. Clay swelling caused an additional impact on permeability behavior during coreflood experiments, whereas the modeled permeability depends exclusively on chemical processes. TOUGHREACT was then used for reservoir-scale simulation of injecting ambient-temperature water (30°C, 86°F) into a reservoir with initial temperature of 80°C (176°F). Untreated native reservoir water was found to cause serious porosity and permeability reduction because of calcite precipitation, which is promoted by the retrograde solubility of this mineral. Using treated water that performed well in the laboratory flow experiments was found to avoid excessive precipitation and allowed injection to proceed.