Abstract
Scaling phenomenon is a major problem that occurs when water is injected for oil displacement and pressure maintenance in oilfields. This phenomenon of precipitation and accumulation of oilfield scale due to incompatibility between formation and injected water is induced around the well bore after water breakthrough at reduced reservoir pressure. The effect results in formation damage which may negatively impact on reservoir performance well bore performance and the success of water flooding project that depends on mobility ratio. This paper presents an analytical model based on existing thermodynamic models for predicting brine mobility, hydrocarbon mobility and mobility ratio of water flooded reservoir with possible incidence of scale precipitation and accumulation. The key operational and reservoir/brine parameters which influence the mobility ratio such as salt concentration in the brine, produced water rate, pressure drawdown, reservoir temperature were identified using this model.
Results of the study shows that the mobility ratio of a water flooded reservoir remains constant until water breakthrough and achieves an increasing local maximum at 10% pore volume injected water as the flow rate of produced water increases with a significant jump beyond the critical flow rate observed at mobility ratio of 1. Similar results corroborating above were obtained with variation in skin factor.
This model therefore can be used to diagnose, evaluate and simulate mobility ratio and skin factor in a water flood scheme enabling production engineers plan an economically efficient water flood scheme.
