Wettability is a major factor that affects the flow behavior and recovery efficiency in oil reservoirs. In this study, the effects of wettability on water-oil relative permeability (kr), capillary pressure (Pc) curve and capillary desaturation curve (CDC) have been investigated in laboratory on core scale. Water floods and surfactant floods at different capillary numbers (Nc) were carried out in sandstone rock at different wettability conditions. These floods were followed by oil floods. The kr and Pc curves were estimated by history matching the experimental production and pressure drop. The recovery after water flood was higher at non water-wet conditions but a higher throughput of water was needed. Estimated kr and Pc curves vary with the wettability of the rock. The relative permeability of the wetting phase is more curved than that of the non wetting phase. The measured CDC for oil in mixed-wet condition and the CDC for water in water-wet condition deviate from the typical CDC shape. In these cases, it is found that the measured remaining oil or water saturation is a function of the number of pore volumes injected and also it is largely affected by capillary end effects. Since the residual saturation is difficult to be obtained in core floods at non water-wet conditions, the measured CDC in laboratory experiments does not represent the true CDC. More focus should be directed at relative permeability (corrected for capillary end effects) than the residual oil saturation. The results presented in this paper demonstrate the importance of the wettability of rock on recovery efficiency and also the importance of correcting the laboratory data especially predicting the flow behaviour of non water-wet conditions. Remaining oil saturation based on relative permeability should be used instead of residual oil saturation in evaluation of the potential for tertiary recovery, e.g. surfactant.

The effect of interfacial tension (IFT) on the displacement of the nonwetting and wetting phases has been investigated by the use of simulations/history matching of flooding experiments. In surfactant flooding, a conventional assumption is to neglect the effect of capillary pressure (P c ) on measured two-phase properties. The methodology applied in this paper allows improved interpretation of experimental results by correcting for the influence of capillary end effects on the measured capillary desaturation curve (CDC) and on the estimated relative permeability (k r ).Three fluid systems of different IFTs were prepared by use of a solvent system (CaCl 2 brine/iso-octane/isopropanol) rather than a surfactant system with the assumption that both systems have similar flood behavior at reduced IFT. Three coreflood cycles, including multirate oil injection (drainage) followed by multirate water injection (imbibition), were carried out at each IFT in water-wet Berea cores. The k r functions corrected for capillary end effects were derived by numerically history matching the experimental production and pressure-drop (PD) history.A typical CDC is observed for the nonwetting phase oil, with a roughly constant plateau in residual oil saturation (ROS), S or , below a critical capillary number (N cc ) and a declining slope above N cc toward zero S or . No influence of P c was found for the nonwettingphase CDC.The results from the displacement of the wetting phase formed an apparent CDC with a declining slope and no N cc . Analyzing the wetting-phase results, we find that the wetting-phase CDC is not a true CDC. First, it is a plot of the average remaining water saturation (S w ) in the core which, in all the experiments, is higher than residual water saturation, S wr , obtained from P c measurements. Second, we find that the remaining S w is only partly a function of N c . At low N c , the water production (WP) is limited by capillary end effects. Rate-dependent WP observed with the high-IFT system is fully reproduced in simulations by use of constant k r and P c . The remaining wetting-phase saturation at a low capillary number (N c ) is a result of the core-scale balance between viscous and capillary forces and would, for example, depend on the core length. At a higher N c , the WP is found to be limited by the low k r tail, typical for wetting phases. However, we find that the k r functions become rate dependent at a higher N c , and we assume that this rate dependency can be modeled as a function of N c . The remaining wetting-phase saturation at a higher N c would then be a function of N c and the number of pore volumes (PVs) injected. The observed N c dependency in the flow functions indicates a potential for the accelerated production of the wetting phase by use of surfactant.Assuming that the results obtained here for the wetting phase also apply to oil in a mixed-wet system, it is strongly recommended to evaluate the effect of both P c and N cc when designing a surfactant model for a mixed-wet field. IntroductionAf...

In surfactant flooding, a conventional assumption is to neglect the effect of capillary pressure on measured two-phase flow properties such as remaining saturations and relative permeabilities. This often leads to poor interpretation of laboratory data used as input in surfactant models. This paper describes the experimental and simulation work undertaken to study how the remaining saturation at different capillary number can depend on capillary end effects and production rate. Three fluid systems of different interfacial tensions (IFTs) were prepared using a solvent system (CaCl2-brine/iso-octane/iso- propanol) rather than a surfactant system with the assumption that both systems have similar flood behaviour at reduced interfacial tension. Three core flood cycles, including multirate oil injection (drainage) followed by multirate water injection (imbibition), were carried out at each IFT in water-wet Berea cores. Relative permeability functions corrected for capillary end effects were derived by numerically history-matching of the experimental production and pressure drop history. A typical capillary desaturation curve (CDC) is observed for the non-wetting phase oil, with a roughly constant plateau in residual oil saturation, Sor, below a critical capillary number (Ncc) and a declining slope above Ncc towards zero Sor. No influence of capillary pressure was found for the non-wetting phase CDC. The results from displacement of the wetting phase formed an apparent CDC with declining slope and no critical capillary number. Analysing the wetting phase results, we find that the wetting phase CDC is not a true CDC. Firstly, it is a plot of the average remaining water saturation in the core which in all the experiments is higher than residual water saturation, Swr, obtained from capillary pressure measurements. Secondly, we find that the remaining water saturation is only partly a function of Nc. At low Nc, the water production is limited by capillary end effects. Rate dependent water production observed with the high IFT system is fully reproduced in simulations using constant relative permeability and capillary pressure. The remaining wetting-phase saturation at low Nc is a result of the core-scale balance between viscous and capillary forces and would e.g., depend on the core length. At higher Nc, the water production is found to be limited by the low relative permeability tail typical for wetting phases. However, we find that the relative permeability functions become rate dependent at higher Nc, and this rate dependency can assumingly be modelled as function of Nc. The remaining wetting phase saturation at higher Nc would then be a function of Nc and the number of pore volumes injected. The observed Nc dependency in the flow functions indicates a potential for accelerated production of the wetting phase by using surfactant. Assuming that the results obtained here for the wetting phase also applies to oil in a mixed-wet system, it is strongly recommended to evaluate both the effect of capillary pressure and capillary number when designing a surfactant model for a mixed-wet field.

Surfactants have been considered to mobilize the residual oil left after water flooding of oil reservoirs. The focus has been on surfactant flooding of water-wet reservoirs utilizing mainly their ability to reduce oil-water interfacial tension, while the potential of surfactant flooding for non water-wet reservoirs has not been investigated too much degree. The purpose of this study was to investigate the effect of reducing the interfacial tension between oil and water on the relative permeability curves at different wettability conditions. Several core flooding experiments were carried out at different wettability conditions including multiple rate water flooding followed by multiple rate surfactant floods. The wettability conditions were characterized before and after the core floods. Relative permeability functions and capillary pressure curves were estimated by history matching the recovery and the pressure drop data obtained from the core floods. For the non water-wet systems the measured remaining oil saturation was found to decrease with increasing capillary number at low capillary number. The measured capillary desaturation curve (CDC) for the mixed-wet and oil-wet conditions are not true CDC and must be corrected for capillary end effects. The relative permeability was found to vary with capillary number and also with wettability. At low capillary numbers typical for water flooding, the relative permeability curves were constant. By increasing the capillary number the relative permeability for oil was found to increase for mixed-wet and oil-wet conditions. Since most of the sandstone reservoirs are characterised as mixed-wet, the potential for classical surfactant flooding can be low because the real residual oil saturation is low. The oil recovery from mixed-wet reservoirs can be accelerated by alteration of the relative permeability curves by surfactants.

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