Article pubs.acs.org/EF
Conceptual Darcy-Scale Model of Oil Displacement with Macroemulsion Bernardo Engelke,† Marcio S. Carvalho,*,† and Vladimir Alvarado*,‡ †
Department of Mechanical Engineering, Pontifícia Universidade Católica do Rio de Janeiro, Rio de Janeiro, RJ, 22453, Brazil Department of Chemical and Petroleum Engineering, University of Wyoming, Laramie, Wyoming 82071, United States
‡
ABSTRACT: Experiments have shown that injection of oil-in-water macroemulsions can be used as an effective enhanced-oil recovery (EOR) method, with potential increase in the volume of oil recovered. As emulsion drops move through the pore space, they give rise to multiscale flow effects that are commonly associated with mobilization of residual oil and macroscale mobility control or conformance. Compared to water injection, emulsion flooding can improve the macroscopic reservoir sweep as well as reduce the residual oil saturation. Prediction of reservoir flooding scenarios requires a physically meaningful two-phase flow model that accounts for the presence of emulsion drops in the aqueous phase. Conceptually in this work, we describe emulsions as an aqueous phase containing a certain concentration of oil drops. The aqueous-phase dynamic properties depend on the emulsions and porous media characteristics. Here, we propose to represent emulsion injection effects in a simplified fashion through changes in the relative permeability curves of both the aqueous and oil phases. Steady-state two-phase flow experiments were conducted to evaluate these relative permeability curves with and without the presence of oil drops dispersed in the aqueous phase. The effect of the relative permeability curves on Darcy-scale or continuum oil displacement was evaluated by comparing numerical reservoir-scale predictions of oil recovery for water and emulsion flooding using the experimentally determined relative permeabilities.
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INTRODUCTION The nonlinear response or behavior of flow of dispersions through porous media relates directly to the mechanisms responsible for enhanced oil recovery in many different processes.1−5 In the particular case of emulsions, the dispersion can be purposely injected from the surface or the effects emerge from emulsions formed in situ as a result of the injection of chemical blends. McAuliffe6 described a technically successful enhanced oil recovery (EOR) field pilot test using macroemulsion flooding. An incremental total recovery of 55 000 bbl of oil was attributed to the injection of 0.03 pore volumes, 14% oil emulsion. These results indicate better sweep efficiency of water chasing an emulsion bank, with lower water−oil ratio (WOR) in production wells. Recent field results show the potential of emulsions as conformance agents. The observed blocking mechanisms can be attributed in part to the pressure drop−flow rate response of behavior of emulsion flow in porous media.7 Similarly, several research groups have proposed that in situ generated emulsions in chemical flooding of heavy oil reservoirs contribute significantly to oil displacement.8−12 Despite the early success of emulsion as an EOR agent, fundamental understanding of emulsion flow at the pore and Darcy or continuum scales is still required to develop physically based models of emulsion flow through porous media and its application in EOR processes. In retrospect, the two main targets of EOR methods are the reduction of the mobility ratio between the phases to improve the efficiency of horizontal and vertical reservoir sweep and the mobilization of residual oil behind the displacement front. The addition of polymers and other additives into a lower viscosity © 2013 American Chemical Society
displacing liquid is a common approach to increase its viscosity and consequently the reservoir sweep efficiency.13,14 In more recent times, it has been realized that, contrary to the accepted wisdom that comes from two-phase flow analysis of water and oil in porous media, the viscoelastic response of high molecular weight polymer solutions affects the pore-scale flow, increasing the volume of oil mobilized by aqueous-phase flooding.15−18 According to traditional thought, polymer flooding can offer mobility control efficiency by raising the aqueous-phase viscosity but not displacement or mobilization of residual oil efficiency. It appears that this is not the case that more recent experimental evidence seems to offer.13,14 Guillen et al.19 have shown that emulsion flow behavior in porous media affects the displacement of oil by a water phase in a multiscale manner. Pore blockage by the dispersed phase of an emulsion diverts the flow path at the pore level, dislodging previously trapped oil ganglia, leading to changes in the residual oil saturation. Visualization experiments19 clearly show the mobilization of residual oil after slugs of oil−water emulsion were injected in a transparent porous media. In macroscopic terms, pore blockage by emulsion drops reduces the aqueous-phase mobility, leading to a more uniform sweep. Guillen et al. also have shown evidence of this mechanism. Core flooding results in sandstone cores with two different permeabilities arranged in a parallel configuration19 evidence that water is diverted toward the low permeability core after a slug of emulsion is simultaneously injected into the cores, increasing the overall sweep. This remarkable result is obtained even though the rheometric Received: August 31, 2012 Revised: March 15, 2013 Published: March 21, 2013 1967
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Figure 1. Sketch of experimental setup used to evaluate the relative permeability curves.
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viscosity of emulsions used in the experiments is essentially the same as that of water. Macroemulsions offer a different mobility control and pore level displacement mechanisms2 that are based on capillarity arising from curved interfaces, in contrast with viscosifying the displacing phase or viscoelastic flow behavior. We have shown that these effects can provide an explanation for EOR observations during emulsion flooding. As oil drops in oil-in-water emulsions encounter pore throats, the mobility of the continuous (water) phase can drastically reduce, depending on the emulsion characteristics and local flow conditions. The larger flow resistance derived from drop deformation can lead to small-scale flow diversion and therefore mobilize oil previously trapped during a waterflooding phase. The effect of capillary number and ratio of emulsion drop size to pore throat diameter on the mobility of oil−water emulsions was studied in microchannel flow, core flooding experiments and network modeling by Cobos et al.20 and Romero et al.21 To study reservoir-scale emulsion flooding operations, it is important to be able to describe these multiscale effects of emulsion drops on oil displacement with a model that is able to capture all the previously described effects. Conceptually, a dilute emulsion can be described as an aqueous phase containing a given concentration of oil droplets, and its flow behavior may be incorporated in the water-phase mobility. This allows the use of conventional macroscopic two-phase (oil/ aqua) flow models. From the experimental aforementioned results presented by Guillen et al.,19 the presence of oil drops lowers the residual oil saturation and also reduce the relative permeability of the aqueous phase, as long as the overall capillary number is below a critical value. In this work, steady-state determined relative permeability curves of oil and aqueous phase (with and without oil drops) were probed for two drop size distributions. The effect of the relative permeability change on the oil displacement process is evaluated at the reservoir scale by comparing the predicted volume of oil displaced by water and emulsion flooding using the calculated relative permeability curves.
EXPERIMENTAL SETUP AND PROCEDURES
The experimental setup used in the analysis is sketched in Figure 1. The experiments were conducted using the TEMCO CFS-830-SS coreflooding system. The system consisted of two syringe pumps (ISCO 500DX), stainless steel transfer vessels (TEMCO), a core holder (LABCONTE, Brazil), a fraction collector (Gilson, FC-204), and a precision balance (OHAUS, Adventurer Pro AV2101). The transfer vessels and core holder were installed inside an oven (Despatch, LBB2-18-1) to control the temperature during experiments. The temperature was set at T = 44 °C for all cases analyzed. Two pressure transducers (Validyne, DP360-40 and DP360-60) were installed to measure the injection and confining pressures. By opening and closing different valves, the injection of water, emulsion, and oil could be easily controlled. A cylindrical Bentheimer sandstone plug with diameter and length equal to D = 3.8 cm and L = 8.86 cm, respectively, was used as the porous material. The measured porosity and permeability were ϕ = 21.7% and K = 2.1 D. Bentheimer rock samples with properties very similar (22.5% in porosity and 1−2 Darcy in permeability) to those of the plugs used in our experiments have been characterized with mercury porosimetry, scanning electron microscopy, and pulsed-field gradient NMR.22 The rock was found to be relatively homogeneous with a unimodal pore size distribution centered at approximately 40 μm as interpreted by the authors in the cited reference from mercury porosimetry analysis. A mineral oil (Shell Morlina 150) was used as the oil phase and to formulate the emulsions. At the experimental temperature, the oil viscosity and density were μo = 104 cP and ρo = 870 kg/m3, respectively. The aqueous phase consisted of a surfactant (Ultrol L80) solution in NaCl brine. The salt concentration was 15 g/L, and the surfactant concentration was 0.6 g/L. Emulsion stability tests were conducted, and the results show that their drop size distribution did not vary significantly during the experiments. The aqueous-phase viscosity and density were μw = 0.64 cP and ρw = 1000 kg/m3, respectively. Oil-in-water emulsions were prepared by mixing the mineral oil with the aqueous phase in a high power benchtop mixer (UltraTurax homogenizer, IKA-Werke 20). The dispersed phase concentration was cd = 3% by volume. Two emulsions with different drop size distributions were prepared by changing the rotation speed of the mixer impeller. Emulsion 1 was prepared by mixing the oil and brine for 2 min at 24 000 rpm. The drop size distribution obtained with a light diffraction system (Malvern Mastersizer 2000) is shown in 1968
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Figure 2. 90% of the oil volume was dispersed in drops with diameter less than 38 μm, for example, d0.9 = 38 μm. A gentler mixing speed of
Figure 3. Inlet pressure during the two-phase flow of oil and water at different values of flow rate ratio. Figure 2. Drop size distribution for two different emulsions obtained with different mixing procedures. 13 500 rpm yielded an emulsion with larger drops (emulsion 2), as shown in Figure 2. For this emulsion, d0.9 = 230 μm. The oil fraction was low enough as to produce no appreciable effect on the aqueousphase viscosity and density. The sandstone core was initially saturated with the aqueous phase, which was later displaced by the mineral oil until reaching the irreducible (connate) water saturation. At this point, the steady-state pressure difference was used to evaluate the oil-phase relative permeability at this saturation by directly using two-phase Darcy law. The aqueous-phase volumetric flow rate was raised in small steps as the oil-phase flow was decreased, keeping the total flow rate constant. At each fractional flow, the aqueous-phase saturation was evaluated by mass balance, and the steady-state pressure difference was used to determine relative permeabilities through Darcy law. This procedure was repeated for the pure aqueous phase, which we will refer to as waterflooding in the rest of the article, and the two emulsions, referred to as emulsion flooding.
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RESULTS AND DISCUSSION Waterflooding. After the sandstone core was fully saturated with the aqueous phase, oil was injected at constant flow rate (Q = 2 mL/min) until reaching the connate water saturation, Swc = 9.7%. The calculated relative permeability of the oil phase at this saturation was ko(Swc) = 0.87. After this, oil and the aqueous phase were injected simultaneously at different fractional flow while keeping the total volumetric flow rate constant, as previously described. The evolution of the injection pressure with time is shown in Figure 3. A steady state was rapidly reached at each flow rate ratio. The water and oil relative permeability curves are presented in Figure 4. The calculated residual oil saturation was Sorw = 65.5%. It is worth noticing that the high residual oil saturation and the curvature of the oil relative permeability curve are consequence of the high viscosity ratio, for example, μo/μw ≈ 160. Emulsion 1 Flooding. At the end of the waterflooding experiment, oil was injected to drain the aqueous phase until reaching its irreducible saturation. A steady state was reached
Figure 4. Relative permeability curves of oil and water.
after the injection of approximately 5 pore volumes. The connate water saturation after this second drainage was again Swc = 9.7%. Emulsion 1 was used as the aqueous phase in this second experiment. The pressure difference as a function of time at the different flow rate ratios is shown in Figure 5. After an initial transient period, pressure oscillates about an apparent steadystate mean value. As explained by Cobos et al.,20 this oscillation is associated with the flow of oil drops through pore throats. It is important to notice that at large oil fractional flow, that is, low aqueous-phase saturation, the pressure difference is very close to that of the water flooding experiments (Figure 3). The viscosity ratio was larger than 100, which is considered rather large for waterflooding. At the highest aqueous fractional flow (higher water flow rate and lower oil flow rate, labeled with a “6” in Figure 5), the pressure difference is higher than results of 1969
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relative permeability is lower. Moreover, the presence of the oil drops of the emulsion reduces the value of the end point of the aqueous-phase curve, indicating that the oil drops reduce significantly the mobility of the aqueous phase at the residual oil saturation. These effects are clearly in accordance to the findings of Guillen et al.19 in which emulsion acts on the displacement of oil both at the pore and macro scales. Emulsion 2 Flooding. The effect of the emulsion drop size on the two-phase flow is determined through a third experiment. Emulsion 2, which contained larger drops (d0.9 = 230 μm), was used as the aqueous phase in this case. The emulsion with larger drops likely blocked a larger number of pores resulting from capillary-trapped oil drops of the emulsion, as evidenced by the pressure response (Figure 7). Oil was again
Figure 5. Inlet pressure during the two-phase flow of oil and emulsion 1 at different values of flow rate ratio.
waterflooding (Figure 3), indicating a lower mobility of the aqueous phase containing oil droplets. The residual oil saturation at the end of the experiment was Sore1 = 58.8%. The reduction in residual oil saturation indicates that the emulsion oil drops dispersed in the aqueous phase enable mobilization of a larger volume of oil when comparing to the case of pure aqueous phase. This is consistent with earlier observations in transient experiments.23 The calculated relative permeability curves are shown in Figure 6. The plot also shows the curves obtained during waterflooding, as basis for comparison. The relative permeability curves are shifted to the right according to the change on the residual oil saturation. Therefore, at a given aqueous-phase saturation, the oil relative permeability is higher, and the water
Figure 7. Inlet pressure during the two-phase flow of oil and emulsion 2 at different values of flow rate ratio.
Figure 6. Relative permeability curves of oil and emulsion 1.
injected until reaching the connate-water saturation of Swc = 10.2%, which was again close to the values obtained after the initial and second drainage, for example, Swc = 9.7%. The experimental procedure followed to determine the relative permeabilities was the same one used in the two previous experiments. The evolution of the inlet pressure at the different fractional flow is shown in Figure 7. As before, after an initial transient period, pressure oscillates about an apparent steadystate mean value. The relative permeability curves are shown in Figure 8. Again, the waterflooding curves are presented as basis for comparison. The residual oil saturation at the end of the process was Sore2 = 44.9%, much lower than that obtained after waterflooding (Sorw = 65.5%). The value of the relative permeability of the aqueous phase at the residual oil saturation was lower in the case of emulsion, again indicating the oil drops not only enabled mobilization of a larger volume of oil, leading to a lower residual oil saturation, but also reduced the mobility of the aqueous phase. It is interesting to notice that the behavior presented here through steady-state determination of the relative permeability curves is very similar to the one depicted by Arhuoma et al.8 for 1970
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grid densities and finding no significant effect of the grid choice. This is equivalent to a 2D vertical section of a reservoir that can also be considered a section of a line drive. An injector and a producer were placed at both ends of the reservoir, as sketched in Figure 9. The porosity of each cell was equal to the porosity of the Bentheimer sandstone used in the experiments, for example, ϕ = 21.7%. Absolute permeability was assigned to each grid cell following a uniform random density function with values between 1600 and 2500 mD, so that the average permeability was also equal to the permeability of the Bentheimer core, that is, K = 2130 mD. The realization of the permeability field used in all of our simulations is presented in Figure 9. The fluid properties were the same as those used in the experimental determination of the relative permeability curves, that is, μo = 104 cP, ρo = 870 kg/m3, μw = 0.64 cP, and ρw = 1000 kg/m3. All effects associated with the presence of emulsion drops were reflected through changes in the relative permeability curves. A pseudocompositional model was build in CMG-STARS.24 The fluids and porous matrix were considered incompressible, and the viscosities were kept independent of pressure. In the model, the dispersed-phase concentration in the water phase was described through a tracer transport equation. The value of the dispersed phase concentration in each gridcell was used to calculate the relative permeabilities by linearly interpolating the zero concentration curves, determined through the waterflooding experiments presented before, and the curves corresponding to 3% emulsion 2, presented in Figure 8. The initial condition corresponded to an oil saturation of Soi = 90.3% (Sw = Swc = 9.7%) throughout the reservoir. The aqueous phase was injected at a constant flow rate Qw = 200 mL/min for approximately 4.8 pore volumes. The oil production at the outflow well and oil saturation maps were determined for two different cases, a pure water flooding and an emulsion injection. The results are shown in Figure 10 for both cases. The saturation maps are depicted for the times indicated in the oil recovery plot. Because of the higher density of the water phase, gravitational segregation is clearly observed in the water
Figure 8. Relative permeability curves of oil and emulsion 2.
the case of alkaline flooding. They determined relative permeability curves by history matching of transient oil production during water and alkaline flooding. The observed changes on the relative permeability curves were similar to the ones discussed in this work. They associated the changes to the in situ generation of emulsions during alkaline flooding.
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IMPACT OF RELATIVE PERMEABILITY ON OIL RECOVERY An analysis of synthetic scenarios was conducted in order to compare the impact of emulsion droplets dispersed in water on oil recovery in contrast with water flooding, when represented through changes of relative permeabilities. A two-dimensional (2D) mesh (50 × 20 cells) was used to set up a model reservoir with dimensions equal to 100 × 20 × 1 m3. This mesh was selected for convenience after testing several
Figure 9. 2D reservoir model and absolute permeability map. 1971
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Figure 10. Oil recovery factor comparison during water and emulsion 2. The water-phase saturation at selected pore volumes injected are also shown.
flooding case, which leads to a very early water breakthrough, at approximately 0.07 pore volumes injected. In contrast, when emulsion is injected, significant mitigation of the early water breakthrough resulting from gravitational segregation is observed. At 0.07 pore volumes, the displacement front in the emulsion flooding remains away from the producer, as shown in the leftmost saturation map. In the case of emulsion injection, emulsion breakthrough occurs after approximately 0.15 pore volumes. Until then, clean oil continues to be produced. The recovery factor at water breakthrough is approximately 18%, almost twice as much as in the case of waterflooding. A higher water saturation behind the displacement front is also observed in the case of emulsion flooding. This is a direct consequence of the lower residual oil saturation at the end point of the emulsion permeability curves. After the aqueous-phase breakthrough, the rate of oil production is considerably higher in the case of emulsion injection. This is due to a combined effect of a more uniform volumetric sweep and lower residual oil saturation behind the front. Both production curves exhibit a second transition to an even lower production rate, associated with the arrival of the mean displacement front, as indicated on the rightmost saturation
maps. At the end of the floods, after the injection of 4.8 pore volumes, the recovery factor obtained with the emulsion injection is RFe ≈ 50%, almost doubling the value observed in the case of water injection, that is, RFw ≈ 27.5%.
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FINAL REMARKS In this research, we determined relative permeability curves through steady-state two-phase flow of aqueous and oil phases, for water and oil-in-water emulsions, as a way to represent the effect of the emulsion drops on the multiphase flow. Our conceptual representation of emulsion effects through relative permeability curves effectively accounts for the multiscale mechanisms previous demonstrated experimentally by Guillen et al.19 Moreover, the curves presented here and obtained through steady-state experiments are qualitatively similar to those presented by Arhouma et al.,25 obtained by history matching transient coreflooding experiments for the case of in situ generated emulsion. Reservoir scale simulations of oil recovery using the calculated relative permeability curves to represent emulsion flooding effects, indicate that emulsions could delay water breakthrough and increase the overall recovery. These potential 1972
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(21) Romero, M. I.; Carvalho, M. S.; Alvarado, V. Phys. Rev. E 2011, 84, 046305. (22) Verganelakis, D.; Crawshaw, J.; Johns, M.; Mantle, M.; Scheven, U.; Sederman, A.; Gladden, L. Magn. Reson. Imaging 2005, 23, 349− 351. (23) Guillen, V. R.; Romero, M. I.; Carvalho, M. S.; Alvarado, V. Int. J. Multiphase Flow 2012, 43, 62−65. (24) STARS Version 2011 User’s Guide; Computer Modelling Group: Houston, TX, 2011. (25) Arhuoma, M.; Dong, M. Z.; Yang, D. Y.; Idem, R. Ind. Eng. Chem. Res. 2009, 48, 7092−7102.
benefits could result in both a more uniform displacement front and a lower oil saturation behind the front. In this paper, we provide evidence that emulsion flooding could be used as a way to mitigate gravitational segregation or the so-called “water tonguing”. Results show that a proper dispersion of only 3% oil drops in water has the potential to double the volume of oil recovered for the synthetic case analyzed here. Additional modeling work will help to verify the generality of the observed results in this work.
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AUTHOR INFORMATION
Corresponding Author
*E-mail:
[email protected] (M.S.C.);
[email protected] (V.A.). Notes
The authors declare no competing financial interest.
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ACKNOWLEDGMENTS
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REFERENCES
B.E. was supported by a scholarship from the Brazilian Research Council (CNPq). This research was funded by Petrobras.
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