The laboratory studies undertaken to evaluate and understand formation damage in limestone reservoirs were summarized. The influence of brine composition, salinity of alkaline fluid and injection rate on formation damage were evaluated in unconsolidated cores. In limestone formations, formation water, which was used in injection, and artificially prepared brine in various concentrations, caused the permeability reduction. High pH values in produced water caused the permeability reduction and consequently the pores were plugged and formation damage was observed. The permeability reduction in alkaline flooding experiments was observed as a result of high pH alkaline fluids (NaOH, NaSiO4). The permeability reduction was minimized using brines of NaCl, CaCl2, and KCl mixtures and high oil recoveries were obtained. Suspended solid particles were released and moved with injection water when salt concentration drops below the critical salt concentration, causing the permeability reduction and formation damage. Experiments below the critical salt concentrations, resulted in a reduction in permeability values of unconsolidated limestone samples, whereas, high pH value solutions caused a reduction in permeability values, plugged the pores, and resulted in formation damage.