Formation of scale in oilfield pipework has long been a problem. It is also likely that scale might form in the near well-bore region of the reservoir. This thesis examines the simulation of the formation damage possible due to scale, supported by experiments involving mixing brines in sandstone cores. Simulation was performed using a network model to represent the sandstone. The model was "damaged" using precipitation theory and observations on the damage caused to experimental cores. Experiments were performed, using quarried sandstone, to provide data for tuning and matching the model. The experiments used a pressure-tapped core holder to provide more detailed information on the scaling process and a new, two fluid, injection system for better control over mixing of the brines. The experiments demonstrated that permeability loss would be most rapid in the initial stages of scaling. The rate of permeability loss decreased with decreasing supersaturation of the brine mix and Increasing distance from the point of mixing. Characterisation of the permeability decline demonstrated a linear correlation between the damage rate and the initial permeability. Some effects on permeability damage due to morphology of the scale crystals were noted. The crystal morphology was shown to be mainly dependant on the solution composition rather than its supersaturation. Results from the model indicated a great sensitivity to the "poro-perm" characteristics of the network model representing the sandstone. No matching of results to experiments was achieved, but the trends with relation to the permeability change were modelled successfully.