Field development planning is critical in the development of successful EOR programmes. Various types of information are required from reservoirs regarding the interaction of the crude oil/brine/rock (COBR) system so as to optimize the EOR process. Core analysis studies are central to gathering the information needed for optimizing EOR. In this paper, investigation of the effect of brine salinity and temperature in the wettability of reservoir rocks is the focus of this paper.

The new contribution in the current work is that it provides a novel approach in combining experimental techniques: displacement tests, which is dominated by capillary imbibition, and non destructive, nuclear magnetic resonance (NMR), to track the effect of brine salinity and temperature in the COBR system. For the first time, this combination of techniques is applied in core scale experiments. Furthermore, the emphasis of rock interaction as a function of brine salinity and temperature was investigated by tracking the relative permeability behaviour during forced displacement experiments in a viscous dominated regime. Integration of the results from these experiments provides a framework for understanding COBR interaction in terms of wettability in static and dynamic displacements.

Four main results emerge from this study:

  • Reducing the salinity of brine with monovalent cations increases the oil recovery in sandstones. The presence of clay is not a necessary condition to observe the low salinity effect. The mechanism of increasing the oil recovery is by shifting the wettability of rock surface towards a more water-wet state.

  • Increasing temperature from 20˚C to 60˚C causes a large decrease (50%) of recovery factor, IAH and INMR suggesting that the wettability is shifted towards an oil-wet state.

  • Increasing temperature in carbonates increases recovery factor by less than 4%. IAH and INMR indicate the wettability is not shifted significantly towards an water-wet state.

  • The dynamic viscous force effect has two patterns of injectivity to sweep the residual oil as brine salinity change. The first is sweeping the oil with high injectivity, which occurs between 0.5 M NaCl brine and 0.1 M NaCl brine. The second is sweeping the oil with loss of water injectivity between 0.1 M NaCl brine and 0.01 M NaCl brine. The potential reason of losing injectivity is attributed to a detachment of the clay that coats the grains leading to a blockage of pore throats.

The implication of these results can enhance the understanding of wettability alteration as part of reservoir managment during designing a field pilot test.

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