Conceptual Darcy-Scale Model of Oil Displacement withMacroemulsionBernardo Engelke,† Marcio S. Carvalho,*,† and Vladimir Alvarado*,‡

†Department of Mechanical Engineering, Pontifícia Universidade Catolica 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-oilrecovery (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 mobilitycontrol or conformance. Compared to water injection, emulsion flooding can improve the macroscopic reservoir sweep as well asreduce the residual oil saturation. Prediction of reservoir flooding scenarios requires a physically meaningful two-phase flowmodel that accounts for the presence of emulsion drops in the aqueous phase. Conceptually in this work, we describe emulsionsas an aqueous phase containing a certain concentration of oil drops. The aqueous-phase dynamic properties depend on theemulsions and porous media characteristics. Here, we propose to represent emulsion injection effects in a simplified fashionthrough changes in the relative permeability curves of both the aqueous and oil phases. Steady-state two-phase flow experimentswere conducted to evaluate these relative permeability curves with and without the presence of oil drops dispersed in the aqueousphase. The effect of the relative permeability curves on Darcy-scale or continuum oil displacement was evaluated by comparingnumerical reservoir-scale predictions of oil recovery for water and emulsion flooding using the experimentally determined relativepermeabilities.

■ INTRODUCTION

The nonlinear response or behavior of flow of dispersionsthrough porous media relates directly to the mechanismsresponsible for enhanced oil recovery in many differentprocesses.1−5 In the particular case of emulsions, the dispersioncan be purposely injected from the surface or the effects emergefrom emulsions formed in situ as a result of the injection ofchemical 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 wasattributed to the injection of 0.03 pore volumes, 14% oilemulsion. These results indicate better sweep efficiency ofwater chasing an emulsion bank, with lower water−oil ratio(WOR) in production wells. Recent field results show thepotential of emulsions as conformance agents. The observedblocking mechanisms can be attributed in part to the pressuredrop−flow rate response of behavior of emulsion flow inporous media.7 Similarly, several research groups haveproposed that in situ generated emulsions in chemical floodingof heavy oil reservoirs contribute significantly to oil displace-ment.8−12

Despite the early success of emulsion as an EOR agent,fundamental understanding of emulsion flow at the pore andDarcy or continuum scales is still required to develop physicallybased models of emulsion flow through porous media and itsapplication in EOR processes.In retrospect, the two main targets of EOR methods are the

reduction of the mobility ratio between the phases to improvethe efficiency of horizontal and vertical reservoir sweep and themobilization of residual oil behind the displacement front. Theaddition of polymers and other additives into a lower viscosity

displacing liquid is a common approach to increase its viscosityand consequently the reservoir sweep efficiency.13,14 In morerecent times, it has been realized that, contrary to the acceptedwisdom that comes from two-phase flow analysis of water andoil in porous media, the viscoelastic response of high molecularweight polymer solutions affects the pore-scale flow, increasingthe volume of oil mobilized by aqueous-phase flooding.15−18

According to traditional thought, polymer flooding can offermobility control efficiency by raising the aqueous-phaseviscosity but not displacement or mobilization of residual oilefficiency. It appears that this is not the case that more recentexperimental evidence seems to offer.13,14 Guillen et al.19 haveshown that emulsion flow behavior in porous media affects thedisplacement of oil by a water phase in a multiscale manner.Pore blockage by the dispersed phase of an emulsion diverts theflow path at the pore level, dislodging previously trapped oilganglia, leading to changes in the residual oil saturation.Visualization experiments19 clearly show the mobilization ofresidual oil after slugs of oil−water emulsion were injected in atransparent porous media. In macroscopic terms, pore blockageby emulsion drops reduces the aqueous-phase mobility, leadingto a more uniform sweep. Guillen et al. also have shownevidence of this mechanism. Core flooding results in sandstonecores with two different permeabilities arranged in a parallelconfiguration19 evidence that water is diverted toward the lowpermeability core after a slug of emulsion is simultaneouslyinjected into the cores, increasing the overall sweep. Thisremarkable result is obtained even though the rheometric

Received: August 31, 2012Revised: March 15, 2013Published: March 21, 2013

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© 2013 American Chemical Society 1967 dx.doi.org/10.1021/ef301429v | Energy Fuels 2013, 27, 1967−1973

viscosity of emulsions used in the experiments is essentially thesame as that of water. Macroemulsions offer a different mobilitycontrol and pore level displacement mechanisms2 that arebased on capillarity arising from curved interfaces, in contrastwith viscosifying the displacing phase or viscoelastic flowbehavior. We have shown that these effects can provide anexplanation for EOR observations during emulsion flooding. Asoil drops in oil-in-water emulsions encounter pore throats, themobility of the continuous (water) phase can drastically reduce,depending on the emulsion characteristics and local flowconditions. The larger flow resistance derived from dropdeformation can lead to small-scale flow diversion and thereforemobilize oil previously trapped during a waterflooding phase.The effect of capillary number and ratio of emulsion drop sizeto pore throat diameter on the mobility of oil−water emulsionswas studied in microchannel flow, core flooding experimentsand network modeling by Cobos et al.20 and Romero et al.21

To study reservoir-scale emulsion flooding operations, it isimportant to be able to describe these multiscale effects ofemulsion drops on oil displacement with a model that is able tocapture all the previously described effects. Conceptually, adilute emulsion can be described as an aqueous phasecontaining a given concentration of oil droplets, and its flowbehavior may be incorporated in the water-phase mobility. Thisallows the use of conventional macroscopic two-phase (oil/aqua) flow models. From the experimental aforementionedresults presented by Guillen et al.,19 the presence of oil dropslowers the residual oil saturation and also reduce the relativepermeability of the aqueous phase, as long as the overallcapillary 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 therelative permeability change on the oil displacement process isevaluated at the reservoir scale by comparing the predictedvolume of oil displaced by water and emulsion flooding usingthe calculated relative permeability curves.

■ EXPERIMENTAL SETUP AND PROCEDURESThe experimental setup used in the analysis is sketched in Figure 1.The experiments were conducted using the TEMCO CFS-830-SScoreflooding system. The system consisted of two syringe pumps(ISCO 500DX), stainless steel transfer vessels (TEMCO), a coreholder (LABCONTE, Brazil), a fraction collector (Gilson, FC-204),and a precision balance (OHAUS, Adventurer Pro AV2101). Thetransfer vessels and core holder were installed inside an oven(Despatch, LBB2-18-1) to control the temperature during experi-ments. The temperature was set at T = 44 °C for all cases analyzed.Two pressure transducers (Validyne, DP360-40 and DP360-60) wereinstalled to measure the injection and confining pressures. By openingand closing different valves, the injection of water, emulsion, and oilcould be easily controlled.

A cylindrical Bentheimer sandstone plug with diameter and lengthequal to D = 3.8 cm and L = 8.86 cm, respectively, was used as theporous material. The measured porosity and permeability were ϕ =21.7% and K = 2.1 D. Bentheimer rock samples with properties verysimilar (22.5% in porosity and 1−2 Darcy in permeability) to those ofthe plugs used in our experiments have been characterized withmercury porosimetry, scanning electron microscopy, and pulsed-fieldgradient NMR.22 The rock was found to be relatively homogeneouswith a unimodal pore size distribution centered at approximately 40μm as interpreted by the authors in the cited reference from mercuryporosimetry analysis.

A mineral oil (Shell Morlina 150) was used as the oil phase and toformulate the emulsions. At the experimental temperature, the oilviscosity 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 thesurfactant concentration was 0.6 g/L. Emulsion stability tests wereconducted, and the results show that their drop size distribution didnot vary significantly during the experiments. The aqueous-phaseviscosity and density were μw = 0.64 cP and ρw = 1000 kg/m3,respectively. Oil-in-water emulsions were prepared by mixing themineral oil with the aqueous phase in a high power benchtop mixer(UltraTurax homogenizer, IKA-Werke 20). The dispersed phaseconcentration was cd = 3% by volume. Two emulsions with differentdrop size distributions were prepared by changing the rotation speedof the mixer impeller. Emulsion 1 was prepared by mixing the oil andbrine for 2 min at 24 000 rpm. The drop size distribution obtainedwith a light diffraction system (Malvern Mastersizer 2000) is shown in

Figure 1. Sketch of experimental setup used to evaluate the relative permeability curves.

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Figure 2. 90% of the oil volume was dispersed in drops with diameterless than 38 μm, for example, d0.9 = 38 μm. A gentler mixing speed of

13 500 rpm yielded an emulsion with larger drops (emulsion 2), asshown in Figure 2. For this emulsion, d0.9 = 230 μm. The oil fractionwas low enough as to produce no appreciable effect on the aqueous-phase viscosity and density.The sandstone core was initially saturated with the aqueous phase,

which was later displaced by the mineral oil until reaching theirreducible (connate) water saturation. At this point, the steady-statepressure difference was used to evaluate the oil-phase relativepermeability at this saturation by directly using two-phase Darcylaw. The aqueous-phase volumetric flow rate was raised in small stepsas the oil-phase flow was decreased, keeping the total flow rateconstant. At each fractional flow, the aqueous-phase saturation wasevaluated by mass balance, and the steady-state pressure difference wasused to determine relative permeabilities through Darcy law. Thisprocedure was repeated for the pure aqueous phase, which we willrefer to as waterflooding in the rest of the article, and the twoemulsions, referred to as emulsion flooding.

■ RESULTS AND DISCUSSIONWaterflooding. 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 phaseat this saturation was ko(Swc) = 0.87. After this, oil and theaqueous phase were injected simultaneously at differentfractional flow while keeping the total volumetric flow rateconstant, as previously described. The evolution of the injectionpressure with time is shown in Figure 3. A steady state wasrapidly reached at each flow rate ratio. The water and oilrelative permeability curves are presented in Figure 4. Thecalculated residual oil saturation was Sorw = 65.5%. It is worthnoticing that the high residual oil saturation and the curvatureof the oil relative permeability curve are consequence of thehigh 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 untilreaching its irreducible saturation. A steady state was reached

after the injection of approximately 5 pore volumes. Theconnate water saturation after this second drainage was againSwc = 9.7%.Emulsion 1 was used as the aqueous phase in this second

experiment. The pressure difference as a function of time at thedifferent flow rate ratios is shown in Figure 5. After an initialtransient period, pressure oscillates about an apparent steady-state mean value. As explained by Cobos et al.,20 this oscillationis associated with the flow of oil drops through pore throats. Itis important to notice that at large oil fractional flow, that is,low aqueous-phase saturation, the pressure difference is veryclose to that of the water flooding experiments (Figure 3). Theviscosity ratio was larger than 100, which is considered ratherlarge 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

Figure 2. Drop size distribution for two different emulsions obtainedwith different mixing procedures.

Figure 3. Inlet pressure during the two-phase flow of oil and water atdifferent values of flow rate ratio.

Figure 4. Relative permeability curves of oil and water.

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waterflooding (Figure 3), indicating a lower mobility of theaqueous phase containing oil droplets. The residual oilsaturation at the end of the experiment was Sore1 = 58.8%.The reduction in residual oil saturation indicates that theemulsion oil drops dispersed in the aqueous phase enablemobilization of a larger volume of oil when comparing to thecase of pure aqueous phase. This is consistent with earlierobservations in transient experiments.23

The calculated relative permeability curves are shown inFigure 6. The plot also shows the curves obtained duringwaterflooding, as basis for comparison. The relative perme-ability curves are shifted to the right according to the change onthe residual oil saturation. Therefore, at a given aqueous-phasesaturation, the oil relative permeability is higher, and the water

relative permeability is lower. Moreover, the presence of the oildrops of the emulsion reduces the value of the end point of theaqueous-phase curve, indicating that the oil drops reducesignificantly the mobility of the aqueous phase at the residualoil saturation. These effects are clearly in accordance to thefindings of Guillen et al.19 in which emulsion acts on thedisplacement of oil both at the pore and macro scales.

Emulsion 2 Flooding. The effect of the emulsion drop sizeon the two-phase flow is determined through a thirdexperiment. Emulsion 2, which contained larger drops (d0.9 =230 μm), was used as the aqueous phase in this case. Theemulsion with larger drops likely blocked a larger number ofpores resulting from capillary-trapped oil drops of the emulsion,as evidenced by the pressure response (Figure 7). Oil was again

injected until reaching the connate-water saturation of Swc =10.2%, which was again close to the values obtained after theinitial and second drainage, for example, Swc = 9.7%. Theexperimental procedure followed to determine the relativepermeabilities was the same one used in the two previousexperiments. The evolution of the inlet pressure at the differentfractional flow is shown in Figure 7. As before, after an initialtransient period, pressure oscillates about an apparent steady-state mean value.The relative permeability curves are shown in Figure 8.

Again, the waterflooding curves are presented as basis forcomparison. The residual oil saturation at the end of theprocess was Sore2 = 44.9%, much lower than that obtained afterwaterflooding (Sorw = 65.5%). The value of the relativepermeability of the aqueous phase at the residual oil saturationwas lower in the case of emulsion, again indicating the oil dropsnot only enabled mobilization of a larger volume of oil, leadingto a lower residual oil saturation, but also reduced the mobilityof the aqueous phase.It is interesting to notice that the behavior presented here

through steady-state determination of the relative permeabilitycurves is very similar to the one depicted by Arhuoma et al.8 for

Figure 5. Inlet pressure during the two-phase flow of oil and emulsion1 at different values of flow rate ratio.

Figure 6. Relative permeability curves of oil and emulsion 1.

Figure 7. Inlet pressure during the two-phase flow of oil and emulsion2 at different values of flow rate ratio.

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the case of alkaline flooding. They determined relativepermeability curves by history matching of transient oilproduction during water and alkaline flooding. The observedchanges on the relative permeability curves were similar to theones discussed in this work. They associated the changes to thein situ generation of emulsions during alkaline flooding.

■ IMPACT OF RELATIVE PERMEABILITY ON OILRECOVERY

An analysis of synthetic scenarios was conducted in order tocompare the impact of emulsion droplets dispersed in water onoil recovery in contrast with water flooding, when representedthrough 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 × 1m3. This mesh was selected for convenience after testing several

grid densities and finding no significant effect of the grid choice.This is equivalent to a 2D vertical section of a reservoir that canalso be considered a section of a line drive. An injector and aproducer were placed at both ends of the reservoir, as sketchedin Figure 9. The porosity of each cell was equal to the porosityof the Bentheimer sandstone used in the experiments, forexample, ϕ = 21.7%. Absolute permeability was assigned toeach grid cell following a uniform random density function withvalues between 1600 and 2500 mD, so that the averagepermeability was also equal to the permeability of theBentheimer core, that is, K = 2130 mD. The realization ofthe permeability field used in all of our simulations is presentedin 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 ofemulsion drops were reflected through changes in the relativepermeability 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 themodel, the dispersed-phase concentration in the water phasewas described through a tracer transport equation. The value ofthe dispersed phase concentration in each gridcell was used tocalculate the relative permeabilities by linearly interpolating thezero concentration curves, determined through the water-flooding experiments presented before, and the curvescorresponding 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. Theaqueous phase was injected at a constant flow rate Qw = 200mL/min for approximately 4.8 pore volumes. The oilproduction at the outflow well and oil saturation maps weredetermined for two different cases, a pure water flooding and anemulsion injection. The results are shown in Figure 10 for bothcases. The saturation maps are depicted for the times indicatedin 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.

Figure 9. 2D reservoir model and absolute permeability map.

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flooding case, which leads to a very early water breakthrough, atapproximately 0.07 pore volumes injected. In contrast, whenemulsion is injected, significant mitigation of the early waterbreakthrough resulting from gravitational segregation isobserved. At 0.07 pore volumes, the displacement front inthe emulsion flooding remains away from the producer, asshown in the leftmost saturation map. In the case of emulsioninjection, emulsion breakthrough occurs after approximately0.15 pore volumes. Until then, clean oil continues to beproduced. The recovery factor at water breakthrough isapproximately 18%, almost twice as much as in the case ofwaterflooding. A higher water saturation behind the displace-ment front is also observed in the case of emulsion flooding.This is a direct consequence of the lower residual oil saturationat the end point of the emulsion permeability curves. After theaqueous-phase breakthrough, the rate of oil production isconsiderably higher in the case of emulsion injection. This isdue to a combined effect of a more uniform volumetric sweepand lower residual oil saturation behind the front. Bothproduction curves exhibit a second transition to an even lowerproduction rate, associated with the arrival of the meandisplacement front, as indicated on the rightmost saturation

maps. At the end of the floods, after the injection of 4.8 porevolumes, the recovery factor obtained with the emulsioninjection is RFe ≈ 50%, almost doubling the value observed inthe case of water injection, that is, RFw ≈ 27.5%.

■ FINAL REMARKS

In this research, we determined relative permeability curvesthrough steady-state two-phase flow of aqueous and oil phases,for water and oil-in-water emulsions, as a way to represent theeffect of the emulsion drops on the multiphase flow.Our conceptual representation of emulsion effects through

relative permeability curves effectively accounts for themultiscale mechanisms previous demonstrated experimentallyby Guillen et al.19 Moreover, the curves presented here andobtained through steady-state experiments are qualitativelysimilar to those presented by Arhouma et al.,25 obtained byhistory matching transient coreflooding experiments for thecase of in situ generated emulsion.Reservoir scale simulations of oil recovery using the

calculated relative permeability curves to represent emulsionflooding effects, indicate that emulsions could delay waterbreakthrough and increase the overall recovery. These potential

Figure 10. Oil recovery factor comparison during water and emulsion 2. The water-phase saturation at selected pore volumes injected are alsoshown.

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benefits could result in both a more uniform displacement frontand a lower oil saturation behind the front. In this paper, weprovide evidence that emulsion flooding could be used as a wayto mitigate gravitational segregation or the so-called “watertonguing”. Results show that a proper dispersion of only 3% oildrops in water has the potential to double the volume of oilrecovered for the synthetic case analyzed here. Additionalmodeling work will help to verify the generality of the observedresults in this work.

■ AUTHOR INFORMATION

Corresponding Author*E-mail: msc@puc-rio.br (M.S.C.); valvaradarad@uwyo.edu(V.A.).

NotesThe authors declare no competing financial interest.

■ ACKNOWLEDGMENTS

B.E. was supported by a scholarship from the Brazilian ResearchCouncil (CNPq). This research was funded by Petrobras.

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