The role of deep-burial dissolution in the creation of porosity in carbonates has been discussed controversially in the recent past. We present a case study from the Upper Permian Zechstein 2 carbonate reservoirs of the Lower Saxony Basin in northwest Germany. These reservoirs are locally characterized by high amounts of carbon dioxide (CO2) and variable amounts of hydrogen sulfide (H2S), which are derived from thermochemical sulfate reduction (TSR) and inorganic sources. To study the contribution of these effects on porosity development, we combine petrography, stable isotope, and rare earth and yttrium (REY) analyses of fracture cements with Raman spectroscopy and δ13C analyses of fluid inclusions. It is shown that fluid migration along deep fault zones created and redistributed porosity. Fluid inclusion analyses of vein cements demonstrate that hydrothermal fluids transported inorganic CO2 into the reservoir, where it mixed with minor amounts of TSR-derived organic CO2. The likely source of inorganic CO2 is the thermal decomposition of deeply buried Devonian carbonates. The REY distribution patterns support a hydrothermal origin of ascending iron- and CO2-rich fluids causing dolomitization of calcite and increasing porosity by 10%–16% along fractures. This porosity increase results from hydrothermal dolomitization and dissolution by acids generated from the reaction of Fe2+ with H2S to precipitate pyrite. In contrast, hydrothermal dolomite cements reduced early diagenetic porosity in dolomitic intervals by approximately 17%. However, the carbonate dissolution in the predominantly calcitic host rock results in a net increase in porosity and permeability in the vicinity of the fracture walls, which has to be considered for modeling reservoir properties and fluid migration pathways.