Miscible and immiscible flooding with CO2 of oils containing asphaltene for chalk reservoir is investigated. Oil recovery from model oil and crude oil (30° API gravity), containing 0.35 and 10 wt % asphlatene, respectively, is addressed. n-Decane is used as a reference oil and showed an increase of recovery from 81 to 89% at 50 °C and 90 bar and 80 °C and 140 bar, respectively. Both model and crude oils showed a reduction in the oil recovery from 78.92 to 70.4% and from 37.6 to 36.6%, respectively, at the same conditions as that for the reference oil. The insignificant change in the oil recovery between the two conditions for the crude oil may be due to the high asphaltene content (10%). A model based on the solubility theory is developed to account for the effect of CO2 flooding and is verified using literature data for CO2 flooding. The average deviations of the model for the miscible flooding from the experimental are 15 and 18% for this study and literature data, respectively. The relative contribution of CO2 on asphaltene precipitation because of miscible CO2 flooding is compared to that for the pressure and temperature effect. On the basis of the approach in this work and available data from literature, CO2 critical content lies between 42 and 17 mol % in the liquid phase, with an average value of about 33 mol %.
An EOR study has been performed applying miscible CO 2 flooding and compared with that for water flooding. Three different oils are used, reference oil (n-decane), model oil (n-C10, SA, toluene and 0.35 wt % asphaltene) and crude oil (10 wt % asphaltene) obtained from the Middle East. Stearic acid (SA) is added representing a natural surfactant in oil. For the non-asphaltenic oil, miscible CO 2 flooding is shown to be more favourable than that by water. However, it is interesting to see that for first years after the start of the injection (< 3 years) it is shown that there is almost no difference between the recovered oils by water and CO 2 , after which (> 3 years) oil recovery by gas injection showed a significant increase. This may be due to the enhanced performance at the increased reservoir pressure during the first period. Maximum oil recovery is shown by miscible CO 2 flooding of asphaltenic oil at combined temperatures and pressures of 50 °C/90 bar and 70 °C/120 bar (no significant difference between the two cases, about 1%) compared to 80 °C/140 bar. This may support the positive influence of the high combined temperatures and pressures for the miscible CO 2 flooding; however beyond a certain limit the oil recovery declined due to increased asphaltene deposition. Another interesting finding in this work is that for single phase oil, an almost linear relationship is observed between the pressure drop and the asphaltene deposition regardless of the flowing fluid pressure.
OPEN ACCESSEnergies 2009, 2 715
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.
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