EFFECTS OF SALINITY AND FLOW RATE ON FORMATION DAMAGE AND CHARACTERIZATION OF CLASTIC RESERVOIR ROCKS

Formation damage of reservoir rocks has been considered as the main reason for permeability impairment and consequently the principal cause of reduction in oil production. The main objectives of this experimental research are to investigate the effects of brine salinity and injection flow rate on formation damage, plus to characterize the clastic reservoir rocks. Four experiments were undertaken using actual reservoir rock samples. Two experiments were used to study the effects of reducing brine salinity and viscosity on permeability damage for single-phase flow in high and low permeability rocks. The two other tests were used to investigate the effect of flow rate on permeability damage under two-phase flow condition. The Scanning Electron Microscope (SEM) was applied for characterization of the composition of used cores and providing better interpretation of sources and mechanisms of this damage. The results indicated that the increase of injected brine salinity decreases the damage of permeability for low and high salinity injected brines under single-phase flow condition. Furthermore, higher permeability rock is proven to have severe damage than rock of lower permeability for single-phase flow. For two-phase flow condition, permeability decreases when flow rate increase to a certain flow rate and then permeability starts to increase under higher rates. The SEM analysis is used to identify clay type and mechanisms causing permeability damage are fine migration of clays and clay swelling. The application of the attained results of this study can be used to design high and low salinity water floods, validate formation damage numerical models, and provide better interpretations of damage sources/mechanisms.