Temperature Effects on Surfactant-Aided Imbibition Into Fractured Carbonates

Abstract

Abstract Little oil is recovered from fractured oil-wet carbonate rocks by waterflooding. Surfactant treatments are being developed to enhance oil recovery from such formations. This work investigates the effect of temperature on such surfactant treatments. Anionic and nonionic surfactants have been identified for oil recovery from fractured low permeability carbonate rocks at high temperatures. For most of the surfactants studied, optimal salinity decreases slightly or remains unchanged with an increase in temperature. Contact angles on initially oil-wet calcite plates decrease on addition of most of the surfactants; the final contact angle decreases with the increase in temperature for all the surfactants in the current study. Oil recovery rate due to surfactant solution imbibition increases with temperature for all surfactants. At 90°C, high recovery (~60% OOIP in 30 days) was obtained for many surfactants at very low surfactant concentrations (<0.1 wt%) in tight (~15 md) carbonate cores. Surfactant brine imbibition was found to be a gravity driven process. Increase in temperature leads to reductions in viscosity and contact angle (which in turn increases oil relative permeability) which enhances the oil recovery rate. Introduction More than half of the world's remaining oil is in carbonate reservoirs.1 Many carbonate reservoirs are naturally fractured and oil-wet / mixed-wet.2,3 Oil-wet reservoirs with high matrix porosity and low matrix permeability give very low waterflood oil recovery.4 Most of the displacing fluid passes through the fractures without sweeping the oil-wet matrix. Surfactant treatment for wettability alteration is one of the techniques to recover oil from such reservoir.5–13 Cationic,7–9 anionic,5,6,10 and nonionic11,13 surfactants have been identified which alter wettability of originally oil-wet carbonate rocks. Surfactants alter the wettability by solubilizing adsorbed hydrophobic components. More than 60% of the original oil can be recovered from initially oil-wet cores by dilute (0.05 wt%) alkaline surfactant solution imbibition at the room temperature. The adsorption of anionic surfactants on calcite mineral can be suppressed by the addition of an alkali.5,6 The anionic surfactant solution imbibition process has been modeled and the simulator results match the experimental results at the laboratory-scale. The simulations show that increase in water-wettability increases oil relative permeability which enhances the rate of oil drainage by gravity. Surfactant solution imbibes from the sides (and the bottom) and oil is recovered from the top. Reservoir permeability, wettability, fracture distribution, oil density, and viscosity are the key parameters which affect the final oil recovery and recovery rates.14 Reservoir temperature can also play an important role in oil recovery from oil-wet fractured carbonate reservoirs. Phase behavior of surfactants/oil/water mixture, wettability, interfacial tension (IFT), viscosity of oil, surfactant diffusivity and imbibition rates can be affected by temperature. The effect of temperature on the phase behavior for both anionicand non-ionic surfactants15–18 has been reported in literature. Skauge et al.15 found the shift of phase behavior from Winsor II+ to Winsor II-, i.e., an increase in optimal salinity with an increase in temperature, for alkylbenzene sulfonate and secondary alkane sulfonate with sodium chloride brine, heptane and n-butanol (as co-solvent) system. They found no definite trend for alkylaryl ethoxylated sulfonate. Healy et al.17 also found an increase in optimal salinity with an increase in temperature for alkyl sulfonates with a mixture of paraffinic and aromatic oils. Meldal et al.16 observed a shift from Winsor II- through III towards II+ with an increase in temperature for branched ethoxylated sulfonate surfactants with Gullfaks field oil. The shift depends on the type of oil, surfactant and brine composition. The effect of temperature on IFT has also been studied. Healy et al.17 and Shito et al.18 found that aqueous-microemulsion (middle phase) IFT decreases with an increase in temperature while microemulsion-oil phase IFT showed the opposite trend. Hanly et al.19 observed a reduction in IFT with an increase in temperature for a non-ionic surfactant and crude oil system. Hill et al20 saw a similar effect for a sulfonate and a crude oil. Wang et al.21 and Hamouda et al.22 found IFT both increasing or decreasing depending on the composition of the system.