Enhanced Oil Recovery (EOR) by Combining Surfactant with LowSalinity InjectionAnnette Meland Johannessen* and Kristine Spildo
Centre for Integrated Petroleum Research (Uni CIPR), University of Bergen, Allegaten 41, 5007 Bergen, Norway
ABSTRACT: When injecting low salinity (LS) water, it is believed that destabilization of oil layers adhering to mineral surfacescould be a contributing mechanism to enhanced oil recovery (EOR). Surfactant flooding is a proven EOR technique byincreasing the capillary number. The combination of LS water at reduced capillarity can avoid retrapping of destabilized oil andexceed recoveries of either of the techniques applied alone. In this study, we have used an alcohol propoxy sulfate mixed with aninternal olefin sulfonate to compare the oil recovery in a low salinity surfactant (LSS) flooding process at moderately low IFTs tothat of an optimal salinity surfactant (OSS) injection process at ultralow IFT. The surfactant formulation was selected on thebasis of an initial screening phase using a North Sea crude oil and diluted seawater. Its effect on oil recovery efficiency in differentinjection scenarios was investigated using crude oil aged Berea sandstone cores. The results showed comparable recoveries forthe LSS flooding at a capillary number 2 orders of magnitude lower than that for the surfactant flooding at ultralow IFT. Inaddition, retention values in the latter case were around 60% higher than for the LS case. On the basis of this, it appears that theLSS process may be more economically efficient than an OSS injection process at ultralow IFT.
1. INTRODUCTIONLow salinity (LS) water injection is an emerging enhanced oilrecovery (EOR) technique1−10 where it is believed thatdestabilization of oil layers adhering to mineral surfaces couldbe a contributing mechanism. Surfactant flooding is a provenEOR technology where surfactant added to the injection waterimproves recovery by increasing the capillary number.11−13 Thecapillary number, Nc, refers to the dimensionless ratio ofviscous to capillary forces, which commonly is defined as
μσ
=Nu
c (1)
where u is the Darcy velocity, μ is the viscosity of the displacingfluid, and σ is the interfacial tension between the oil and thedisplacing fluid.Increasing Nc reduces the amount of oil retained in the
formation by capillary forces and/or remobilizes oil that isalready capillary trapped. By combining these two techniques ina low salinity surfactant (LSS) injection process, an increase inrecovery that exceeds that of either of the techniques appliedalone has been observed.8,9
Even though many studies have shown a negligible responseto LS injection, the most encouraging results show up to 25%OOIP additional recovery.14 Compositions of LS injectionwater used in field tests range from 2 to 3000 ppm;14 however,the low salinity effect (LSE) has been reported for brinecompositions of up to 5000 ppm.8 Despite growing interest inlow salinity brine injection for EOR purposes, a consistentmechanistic explanation of the LSE has not yet emerged.14 Asnoted by the authors, the various circumstances under whichLSE may or may not be observed indicates that there areprobably more than one contributing mechanism. The type andamount of clays present has been suggested as important forLSE. Nonetheless, wettability change from less to more water-wet conditions is the most frequently suggested cause ofincreased recovery by low salinity brine injection. If that is the
case, the process should not work on water-wet cores.However, Ashraf el al.39 found that although the ultimate oilrecovery was largest for neutral wet Berea cores, the largest LSEwas found for water-wet conditions. Thus, at present, there isno consistent correlation between wettability and LSE.Spildo et al.9 showed that even though LS injection alone
gave negligible oil recovery, a combination of LS and surfactantflooding on intermediate-wet cores gave higher recoveries thanwhat would be predicted by the relationship between capillarynumber and residual oil saturation for Berea, published byGarnes et al.12 This was achieved at low surfactantconcentration with a moderate reduction in IFT showing lowretention values.
APS and IOS Surfactants. Alcohol propoxy sulfates (APS)have previously been studied for EOR purposes. The propoxy(PO) groups are weakly hydrophobic functional groups thathave affinity for the interface and thus increase the width of theultralow IFT region.15 The degree of propoxylation can be usedto tailor the surfactant to a given crude oil, temperature, andsalinity, as the addition of PO groups lowers optimum salinity.Further, the presence of PO groups also adds calcium toleranceto the surfactant.16−20 The use of PO groups, and branching ofsuch, also tends to decrease the order of micellar structures.This again tends to reduce equilibration time and promotes theformation of microemulsions instead of unwanted gel and otherviscous phases. Sulfate surfactants, however, have limitedtemperature stability and are restricted to reservoirs up toapproximately 60 °C. At higher temperatures, the sulfates tendto hydrolyze.15
Ideally, one would like to limit the number of components ina surfactant formulation, i.e. surfactant, cosurfactant, and
cosolvent, as much as possible. This gives the system addedrobustness and eliminates possible challenges related tochromatographic separation of the components. However, inmany cases, mixtures are needed to avoid the formation ofhighly viscous phases and obtain clear, stable surfactantsolutions that are suitable for injection. Earlier studies haveshown that mixed surfactant systems of APS with differentcarbon chain cuts of internal olefin sulfonate (IOS) rangingfrom C15 to C28 provide advantages in matching a system tospecific conditions,21−23 in addition to showing no measurablechromatographic separation during core floods.37 The mixedsurfactant systems can improve microemulsion phase behaviorwith a wider salinity window in the Winsor III region, improveaqueous solubility, show good tolerance of divalent ions, andrequire low cosolvent concentrations, or even no cosolvent.It should also be noted that APSs have previously been
reported to give low IFT and high oil mobilization without theaddition of cosurfactants or cosolvents.22,23
Phase Behavior. In the following, we classify micro-emulsion systems as Winsor I, Winsor II, or Winsor III.24
Winsor I and II refer to two phase equilibrium between amicroemulsion and an excess phase: in a Winsor I system, theequilibrium is between oil-in-water microemulsion and anupper excess oil phase, whereas in the Winsor II system theequilibrium is between a water-in-oil microemulsion and alower excess water phase. The Winsor III system has a middlemicroemulsion phase in equilibrium with an upper excess oilphase and a lower excess water phase. At optimal salinity (S*)or OS, the middle microemulsion phase solubilizes equalvolumes of oil and water. The volume of oil or water pervolume of surfactant at S* is referred to as the solubilizationparameter at optimum SP*:
* = =VV
VV
SP o
s
w
s (2)
where Vi is the volume of oil (o), water (w), and surfactant (s).The middle microemulsion phase has been reported to show
very low IFTs against oil and water,28−30 with a minimum whenthe microemulsion phase contains equal amounts of oil andwater. The interfacial tension between oil and water (σ) at anoptimum can be calculated using the Chun Huh relation:30
σ =*
C(SP )2 (3)
C is an empirical constant, usually 0.3 mN/m.Changing variables such as salinity, type of oil, cosolvent,
surfactant concentration, and water−oil ratio (WOR) will leadto a shift in phase behavior. For example, for anionic surfactantsthe phase behavior changes from Winsor I → Winsor III →Winsor II as the salinity increases. The opposite is observedwhen the alkane carbon number (ACN) of the oil phaseincreases, i.e., the phase behavior changes from Winsor II →Winsor III → Winsor I as S* increases.25
Standard procedures, like using NaCl brines, high surfactantconcentration, alkanes as an oil phase, and 1:1 WOR, areusually used when performing phase behavior experiments inorder to quickly screen surfactants and obtain comparable datasets across different studies. However, a phase behavior studywith 1:1 WOR may not be representative of a surfactantflooding experiment, which is conducted at residual oilsaturation, Sor. Salager et al.
25 claimed that the effect of varyingsurfactant concentration and WOR on the system type for
anionic surfactants is complex. Healy et al.28 reported that S*increases as WOR increases. On the other hand, Tien andBettahar26 found a decrease in S* with increasing WOR forsodium dodecyl benzene sulfonate, while Flaaten et al.27 founda slight decrease in S* with decreasing total surfactantconcentration for an APS-IOS surfactant system.Surfactant concentrations during the phase behavior screen-
ing process are also usually higher than what is normally used ina flooding process. However, lowering the surfactantconcentration may cause changes in the phase behavior system.Salager et al.25 stated that the optimum surfactant solution,obtained from minimum IFT at low surfactant concentrationand no detectable three-phase behavior, can be correlated to S*that normally is found for high surfactant concentration fromthree-phase behavior and minimum IFT. Wu et al.17 reliedsolely on IFT measurements when searching for optimalsalinity for branched APS surfactants for improved oil recovery.In this study, an APS and IOS1518 blend is used to compare
the oil recovery in a combined LSS flooding process atmoderately low IFTs to that of a surfactant injection process atultralow IFT. The surfactant formulation was selected on thebasis of an initial phase behavior screening process and IFTmeasurements where variation in surfactant concentration andWOR have been taken into consideration, using a North Seacrude oil and diluted synthetic seawater (SW). The effect on oilrecovery efficiency in different injection scenarios wasinvestigated using crude oil aged Berea sandstone cores.Surfactant retention was also measured and compared in theLS and the high salinity regimes to highlight the economicbenefit from operating in a LS environment.
2. EXPERIMENTAL SECTION2.1. Fluids. The compositions of the brines used in the flooding
experiments are listed in Table 1.
Ionic strength, I, is defined as
∑==
I c z12 i
n
i i1
2
(4)
where c is molality [mol/kg] and z is the valence of the ion.The 0.43 × SW brine is the concentration where ultralow IFTs were
obtained and will be referred to as the optimal salinity (OS) brine inthe following. The 0.07 × SW one is the low salinity (LS) brine.
In static phase behavior tests, different dilutions of SW than thosementioned in Table 1 were used, as well as different concentrations ofpure sodium chloride (NaCl) brines.
Surfactant Solutions. A series of branched C12−13 alcohol−xPO−sulfates (x = 7, 9, and 13) with purities of 32%, 27%, and 28%,
Table 1. Concentration [ppm] and Ionic Strength [mol/kg]of SW and Dilutions of SW
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respectively, were evaluated through phase behavior experiments. Theywere tested in mixtures with an internal olefin sulfonate cosurfactantwith a C15−18 hydrocarbon chain length (IOS1518) with a purity of33%. Secondary butanol (SBA) was used as a cosolvent. All of thesurfactants used in this study were supplied by Shell.Oils. The oils used in this study and their physical properties at 50
°C are listed in Table 2.
The alkanes, n-octane (C8) and n-decane (C10), were only used instatic phase behavior experiments for initial screening of surfactants.Crudes A and B are North Sea crude oils coming from the samereservoir, only from different batches. Crude B was the oil suppliedwhen the supply of crude A ran out. Crude A was used for aging threecores with permeabilities around 100 mD, cores L1−L3, and crude Bwas used for aging two cores with permeabilities around 300 mD,cores H1 and H2. Before the flooding experiments started, the crudeswere modified with the addition of xylene to obtain a morerepresentative viscosity ratio under typical North Sea reservoirconditions. The amount added was a trade-off between achieving alow viscosity and a low dilution factor. After the aging procedure,crude A mod and crude B mod were used to flush through cores L1−L3 and cores H1 and H2, respectively, to replace the aging oil.2.2. Static Phase Behavior Screening and IFT Measure-
ments. Test samples were prepared by adding a fixed amount ofsurfactant, cosurfactant, and cosolvent to NaCl brines or diluted SWbrines of varying salinities and mixed with the appropriate oil. Thesamples were prepared in specially designed, graduated pressure tubes,placed in mixing rigs, and stored in heating cabinets at 50 °C.Solubilization parameters (SPi) were obtained by measuring the phaseheights in the samples after equilibrium was reached. S* wasdetermined by the intersection point when SPw and SPo were plottedas a function of salinity. IFTs were measured at a total surfactantconcentration of 0.2 wt % (3:1 surfactant, cosurfactant ratio) with 0.2wt % SBA for various diluted SW brines at 50 °C. The surfactantsolutions were measured against crude A mod and crude B mod usinga spinning drop tensiometer (SITE100 from KRUSS).2.3. Core Material and Core Preparation. Berea sandstone was
used as the core material in this study. Table 3 shows the Berea coremineralogy, clay type, and content for a typical core from the batch ofBerea used.The cores designated L1−L3 come from a heterogeneous core
material containing visual deformation bands/lamina. The host rockwhich represents the largest part of the rock was characterized ashomogeneous. The deformation bands stretch along the core with alower porosity and permeability than the host rock, giving absolutepermeabilites to water (Kw) of around 100 mD. The cores designatedH1−H2 had a Kw around 300 mD and did not contain visiblelaminations. Core properties and aging procedures are summarized inTable 4.
The dimensions of the cores are similar with core lengths around 10cm, cross-sectional areas around 11 cm2, PVs around 22 mL, andporosity around 20%.
Dry core samples were mounted in Hassler core holders with anoverburden pressure of 20 bar, and saturated with SW under vacuumto determine pore volumes (PVs) and porosities. Absolutepermeabilities to water were measured at 100% SW saturation beforethe cores were drained with filtered crude oil to establish initial watersaturation, Swi. The cores were aged at 110 °C in order to get awettability state other than strongly water-wet. L1−L3 were aged fortwo weeks, while H1 and H2 were aged for four weeks due to delayedinitialization of the core flooding experiments. It should be noted,however, that equal amounts of oil were flushed through each of thecores during the aging process. After aging, crude oil was displaced byfour PVs of crude A mod or crude B mod, which were used for relativepermeability measurements and otherwise throughout the experi-ments.
Figure 1 shows an illustration of the core displacement setup. Thedisplacement experiments were carried out at 50 °C at an injectionrate of 0.1 mL/min followed by increased injection rates of 0.5 and 1mL/min, after each injection step to minimize capillary end effects.Relative permeabilities were measured after each injection step. Thecoreflooding tests were either performed in tertiary (cores L1−L3) orsecondary mode (cores H1 and H2). Tertiary mode refers to aflooding sequence starting with an initial SW flood to establish residualoil saturation, Sorw, followed by a waterflood at reduced salinity, andfinally surfactant injection at reduced salinity. In secondary mode, theSW flooding step is omitted, and brine with reduced salinity wasinjected directly at Swi, followed by surfactant injection at reducedsalinity.
The process of combining LS brine injection with a reducedcapillarity environment is referred to as LSS injection. The LSSinjection was evaluated using cores L1, L3, and H1. Cores L2 and H2,on the other hand, were flooded with a surfactant solution at OS (0.43× SW). This salinity is associated with a minimum in IFT for theselected surfactant system, but it is too high for a low salinity effect14
and will be referred to as optimal salinity surfactant (OSS) in thefollowing. Thus, these experiments are representative of classicalsurfactant injection experiments.
2.4. Dispersion Measurements. To gain better understanding ofthe fluid flow in the core material, both with and without laminations,dispersion measurements were conducted at Sor and at 100% watersaturation. Dispersion profiles for all the cores at Sor and at 100% watersaturation after cleaning were obtained by measuring the effluentresistance when brine with a different salinity from the connate brine(i.e., different resistance) was injected.
2.5. Retention Measurements. In addition to measuring theeffluent surfactant concentration after the core flooding experiments,surfactant retention experiments with retention profiles wereperformed on two cores, R1 and R2, at 100% water saturation. The
Table 2. Oil Density (ρ) and Viscosity (μ) at 50 °C
oil ρ (g/cm3) μ (mPa·s)
C8 0.68 0.39C10 0.71 0.63crude A 0.85 20crude A mod (25% xylene) 0.87 3.3crude B 0.906crude B mod (23% xylene) 0.893 3.3
Table 3. Berea Core Mineralogy
mineral quartz K feldspar plagioclase calcite dolomite siderite pyrite clay
Table 4. Core Properties, Aging Oil, and Time for EachCore
core Swi Kw [mD] aging oil aging time
L1 0.33 100 crude A 2 weeksL2 0.32 100 “ “
L3 0.30 85 “ “
H1 0.26 330 crude B 4 weeksH2 0.34 320 “ “
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cores are from the laminated material and have similar core propertiesto those of L1−L3. Surfactant concentration was measured by apotentiometric autotitrator from Metrohm. The effluent surfactantsamples were titrated against a cationic surfactant supplied byMetrohm, a dialkyl methylimidazolium chloride called TEGOtrantA100.The pH’s in the effluent fractions were measured using a standard
pH electrode.
3. RESULTS AND DISCUSSION
3.1. Phase Behavior and Interfacial Tension. The goalof the phase behavior studies was to find a surfactantformulation which could show ultralow IFT at a salinity toohigh for a LS effect to be expected and at the same time showlow, but not ultralow, IFT at a salinity considered to be in theLS region. That way, we can compare the efficiency of the twoprocesses of low salinity surfactant (LSS) injection andsurfactant injection at optimal salinity (OSS) in terms ofincreased oil recovery and surfactant retention.In order to be used in coreflood experiments, the surfactant
formulation has to fulfill certain requirements. The aqueoussurfactant solution should be stable with no precipitation orphase separation at the given temperature and salinity. Afurther requirement is a low tendency to form viscous phases.Such phases tend to form outside the three phase region,18
which is important to prevent, especially since the LSS floodingexperiments takes place here. The surfactant formulationshould also have as short of an equilibration time as possible.Ideally, one would like to limit the number of components in
a surfactant formulation to increase the system’s robustness andget simpler logistics for an off-shore operation. Therefore,phase behavior studies were initially performed without theaddition of cosurfactant or cosolvent to the NaCl brine.However, the results showed poor phase behavior character-istics; highly viscous phases formed over a wide salinity rangewith no visible three phase region. Adding cosolvent, SBA, anda small amount of IOS1518 as a cosurfactant improved thephase behavior. However, at salinities outside the three phaseregion, viscous phases still remained (see Figure 2).Equilibration times were on the order of three weeks.Since some of the flooding experiments will take place at LS
conditions in the Winsor I region, it is important to eliminateviscous behavior here. To achieve this, the surfactant tocosurfactant ratio was further reduced due to viscous behavioroutside the Winsor III region. A 3:1 ratio of APS to IOS1518has proven successful in other studies15,19,27 and was thusselected. In this case, the total surfactant concentration waskept at 3.33 wt % with 3 wt % SBA added as the cosolvent inNaCl brine. Results of the phase behavior tests are summarized
in Table 5. Compared to the formulation with a 7:1 ratio, thisformulation showed reduced equilibration time (<24 h) and no
viscous phase formation. The salinity window, i.e., the range ofsalinity giving rise to Winsor III behavior, and optimal salinitywere increased. The latter is likely due to the 3:1 systemcontaining a larger amount of the more hydrophilic IOS1518surfactant, which shows an optimal salinity of 10 wt % NaClwith decane at 50 °C.31
As expected, SP* decreases and S* increases with increasingACN from octane to decane. Further, as the hydrophobiccharacter of the surfactant increases with an increasing numberof PO groups, SP* increases, and S* decreases, consistent withresults obtained by Barnes et al.19 If the aim of the phasebehavior studies was to find a surfactant solution showing lowIFT under LS conditions, the surfactant choice would probablybe the 9 or 13 PO system due to high SP* at low S*, Table 5.However, in this study we have to consider the surfactant’sability to show both low IFT under low salinity conditions andultralow IFT at a higher salinity, which must be outside what isconsidered the LS region.
Figure 1. Illustration of the experimental setup for dynamic core displacements.
Figure 2. Phase behavior for 2 wt % total surfactant concentration (7:1ratio of C12−13PO9-to-IOS1518) and 2 wt % SBA with n-decane(WOR = 1:1) as a function of NaCl concentration. Salinity is given as% NaCl at the base of the tubes and increases from left to right. Notethe viscous phases outside the III phase region.
Table 5. Phase Behavior Results for 3.33 wt % APS andIOS1518 with a 3:1 Ratio, and 3 wt % SBA
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After phase behavior screening using model oils and pureNaCl brines, phase behavior experiments with various oils anddiluted SW were performed for the APS with 7 PO mixed withIOS1518 and SBA. The background for choosing this surfactantformulation will be discussed later in this section. The resultsare shown in Table 6, with the salt scan for crude B mod inFigure 3.
Going from NaCl brine to diluted SW makes the water phasemore polar and thus less compatible with oil. This significantlyreduces SP*. S* is also slightly reduced, which is expected asdivalent ions are more effective in packing the surfactantmolecules together, which results in a faster phase transition.32
A further reduction in S* is seen when the oil phase ischanged from decane to crude A, while there is no significanteffect on SP*. When crude A is diluted with xylene to crude Amod, however, S* decreases while SP* increases slightly. This isconsistent with the trend seen for a decrease in ACN of the oilphase on going from decane to octane (see Table 5); i.e., theequivalent ACN of the crude decreases when it is diluted withxylene, and consequently it becomes easier to solubilize. Thesame trend is observed when going from stock-tank oil (STO)
to live crude oil; i.e., the equivalent ACN decreases.38 Crude Bis a different batch of crude oil from the same North Sea field.When Crude B diluted with xylene, crude B mod, is used in theexperiments, a further decrease in S* is found. Also, SP*increases from 8 to 12.5 going from crude A mod to crude Bmod. Thus, crude B mod seems to have a lower equivalentACN than crude A mod.When the total surfactant concentration is reduced to 2 wt %
using crude B mod, S* decreases to 1.5 wt % NaCl, and SP*increases to 15. Further, the salinity window, i.e., the regionwhere three phase behavior is seen, is roughly halved. When thetotal surfactant concentration was further reduced to 1 wt %,only one of the test tubes showed three phase behavior (S*around 1 wt % NaCl), while no clear indication of the optimalsalinity was seen in the phase behavior tests performed at thetarget concentration for the flooding experiments (0.2 wt %total surfactant). Nonetheless, the salinity screening at low totalsurfactant concentrations showed that there was no viscousphase formation. The decrease in S* with decreasing surfactantconcentration is in accordance with the results obtained byFlaaten et al.27 on similar systems.By extrapolation, the trend of decreasing S* with decreasing
surfactant concentration for the C12−13PO7 formulationwould show S* below 1 wt % NaCl (0.24 × SW) for a totalsurfactant concentration of 0.2 wt %. However, this may onlybe true when the water−oil ratio is 1 for this system. Phasebehavior experiments were therefore conducted when thesurfactant formulation (3.33 wt % C12−13PO7 IOS1518, 3 wt% SBA) and the diluted SW concentration (0.38 × SW) wereheld constant, with the WOR as the variable. WOR started at 1and was gradually increased to observe the effect on phasebehavior.
Table 6. Phase Behavior Results for 3.33 wt % TotalSurfactant Concentration in a 3:1 C12−13PO7:IOS1518Blend with 3 wt % SBA Added
oil SP* S* [x × SW] S* [wt % NaCl]
C10 7.5 1.14 4.9crude A 7.5 1.09 4.6crude A mod 8 0.50 2.1crude B mod 12.6 0.43 1.8
Figure 3. Solubilization parameters (upper left), phase ratio (upper right), and phase behavior tubes (WOR = 1:1) for the crude B mod scan, as afunction of salinity. Salinity is given as fractions of SW salinity at the base of the tubes and increases from left to right.
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The graph in Figure 4 shows increasing SPw and decreasingSPo with increasing WOR; i.e., as the WOR is increased,solubilization of oil in water increases, indicating the phasetransition Winsor II → Winsor III → Winsor I for this system.Visual observation of the phase behavior tubes photographed inFigure 4 shows that the first four tubes from the left display aclear excess water phase, an excess oil phase, and a middlemicroemulsion phase, i.e., Winsor III. With a further increase inWOR, in tube 5 from the left, an upper microemulsion phasewith a yellow colored water phase is observed. The colorchange in the water phase from clear to yellow indicates smallamounts of solubilized oil, and the system moves towardWinsor II. In the tube to the far right, i.e., the largest WOR, allof the oil is solubilized in the water phase. Thus moving fromleft to right, i.e., increasing WOR, a phase transition of WinsorII → Winsor III → Winsor I occurs. This result is in line withthat reported by Healy et al.28
Spinning drop tensiometry was used to measure IFT at atotal surfactant concentration of 0.2 wt % at 50 °C, as this wasthe chosen concentration and temperature for the core floodingexperiments. Measurements were performed over a salinityrange of diluted SW for the three APS surfactants (7, 9, and 13PO groups). Each sample was allowed to spin until the dropwas stable, usually taking around 1 h.Building on previous LS experiments with pure NaCl brines,9
it was decided to use a SW dilution with an ionic strength equalto that of a 3000 ppm NaCl solution, which corresponds to0.07 × SW. For the surfactant blend with 7 PO, the IFT at thisSW dilution is 0.018 mN/m. A minimum in IFT was found at asalinity of 0.43 × SW, i.e., OS, with a value in the ultralowregion (IFT = 3 × 10−4 mN/m), see Figure 5. At a totalsurfactant concentration of 0.2 wt %, the volume of the middle-phase microemulsion is too small to be visually detected orsampled for IFT measurements due to the low total surfactantconcentration. Consequently, the spinning drop measurementswere conducted on phases that were not equilibrated inadvance. However, the phases were allowed to equilibrate in thetensiometer while spinning. The IFTs in Figure 5 weremeasured against crude A mod. Equivalent IFTs were measuredfor crude B mod at the flooding salinities. There should be agood distance in terms of salinity between the OS and LSregion to make sure that there is no effect of reduced salinity onoil recovery in the OS case. The other two surfactants with 9and 13 PO have a more hydrophobic character due to a largernumber of PO groups and, thus, displayed the ultralow region
at a lower SW concentration, hence closer to the LS regionthan what was observed for the 7 PO blend.The mismatch between the optimum formulation found by
IFT measurements and that found by phase behaviorexperiments may be due to the large WOR difference inphase behavior experiments compared with IFT measurements.According to Healy et al.,33 interfacial tensions observed willdepend on the specific ratios of water to oil used in theexperiment as well as on the surfactant concentration.On the basis of the phase behavior studies and IFT
measurements, the surfactant system with C12−13PO7 showedsuitable behavior for this study’s purpose and was selected forcore flooding experiments.
3.2. Core Flooding Results. This section will discuss thefive core flooding experiments beginning with the coressubjected to low salinity surfactant (LSS) injection, followedby the cores subjected to optimal salinity surfactant (OSS)injection at ultralow IFT.
LSS Flooding. Figure 6 shows the oil recovery and thedifferential pressure (dP) as a function of injected PVs for coreL1. Initial SW flooding, with a flooding rate of 0.1 mL/min,resulted in a recovery of 73.0% OOIP. Thus, a significant partof the total volume in place was recovered in this first step. Twophase production continued after water breakthrough (WBT)at 0.39 PVs. To eliminate end effects, the injection rate wasincreased in steps at the end of each flooding sequence. Thisgave a final oil recovery by SW injection of 76.0% OOIP.Injection of the LS brine gave an additional recovery of 0.7%OOIP. Injection of LSS gave a small oil bank with a
Figure 4. SP for water and oil at increasing WOR (left). Phase behavior tubes with increasing WOR (right).
Figure 5. IFT as a function of salinity for the 0.2 wt % APS 7PO blendand crude A mod.
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corresponding increase in pressure drop over the core as seenin Figure 6. The last percentages of oil were produced asalternating pure oil and emulsion, hence the moderate slope inthe oil recovery curve over the last injected PV in Figure 6.Final recovery was 84% OOIP. It should be noted that since theSW recovery was high, we may not see the full potential of theLSS process in this experiment.The experiment in core L1 was duplicated in core L3, Figure
7. In this case, the SW flooding resulted in a recovery of 60%
OOIP, which is 16% lower than after the injection of SW forL1. Neither increased injection rates nor LS flooding gaveadditional recovery. This time a pure oil bank was producedduring the LSS injection step with a corresponding increase inpressure drop over the core, resulting in a final recovery of 85%OOIP.Core H1 is a different core material from cores (L1 and L3)
used in the previous experiments, with a Kw around 300 mD,and no visible laminations.A direct LS water injection, without a preceding SW flood,
gave a WBT at 0.46 PV in core H1, Figure 8. Two phaseproduction followed by increased rates gave a total recovery of
60% OOIP. After 1.7 PV, the injection fluid was changed toLSS, which mobilized oil to a total recovery of 90% OOIP.
OSS Flooding. A surfactant flooding process outside the LSregion and in the ultralow IFT region for the given surfactantsystem was performed in core L2, to compare the efficiency of amore conventional surfactant flooding process to that of a LSSprocess. The results are shown in Figure 9. Injection of SW
resulted in an oil recovery of 62.0% OOIP. WBT was observedafter 0.43 PV. Two phase production continued for 1−2 PVafter breakthrough. The sequence continued with the injectionof OS brine, to replace the SW. No oil was produced duringthis step, nor during the increased injection rates. Increasedpressure over the core was observed due to the formation of anoil bank after injecting the surfactant solution. A total of 23.2%OOIP additional oil was recovered, giving a final oil recovery of85.2% OOIP.In core H2, OS brine was injected directly without a
preceding SW flood. This gave a recovery of 55% OOIP, whichis 7% lower than for the LS secondary mode approach. WBTwas observed after 0.37 PV. Injection of OSS resulted in an oilbank which contributed to a total recovery of 92% OOIP. Ahigh recovery was expected in this experiment as the surfactantflooding took place at ultralow IFT between the surfactant
Figure 6. Oil recovery [% OOIP], WBT, and dP profile as a functionof PV injected for core L1. Injection rate is increased from 0.1 mL/minto 0.5 and 1 mL/min after each flooding sequence.
Figure 7. Oil recovery [% OOIP], WBT, and dP profile as a functionof PV injected for core L3. Injection rate is increased from 0.1 mL/minto 0.5 and 1 mL/min after each flooding sequence.
Figure 8. Oil recovery [% OOIP], WBT, and dP profile as a functionof PV injected for core H1. Injection rate is increased from 0.1 mL/min to 0.5 and 1 mL/min after LS injection.
Figure 9. Oil recovery [% OOIP], WBT, and dP profile as a functionof PV injected for core L2. Injection rate is increased from 0.1 mL/minto 0.5 and 1 mL/min after each flooding sequence.
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solution and the oil. The results are shown graphically in Figure10.
3.3. Dispersion. Dispersion profiles for all the cores L1−L3and H1 and H2 are shown in Figure 11. The dispersionmeasurements are carried out at Sor and at 100% Sw after thecores have been washed with toluene and methanol. In ahomogeneous core displaying ideal dispersion, half of theinjected concentration breaks through after 1 PV with theprofile being symmetrical around this point.36 Earlier break-through is associated with the presence of isolated pores thatare not participating in flow, meaning that the effective PVduring flow is less than the total PV. Tailing of the tracerprofile, i.e. deviation from symmetry, is due to mass exchangewith dead-end pores.The dispersion profiles at Sor, left in Figure 11, show a
distinction between the two homogeneous cores (H1 and H2)from the three heterogeneous cores (L1−L3). The homoge-neous cores display close to ideal dispersion behavior, while theheterogeneous cores break through earlier, indicating the
presence of isolated pores that do not contribute to flow.The dispersion curve for core L2 (blue curve) at Sor showssignificant tailing of the tracer profile, indicating mass exchangewith dead-end pores. After cleaning, at 100% water saturation,the profile shifts toward the right, showing a more symmetricaland ideal dispersion, right in Figure 11. One possibleexplanation for the observed shift is that residual oil is blockingpores, especially in the laminations since the porosity andpermeability are lower here, giving rise to both isolated anddead-end pores. By cleaning the core, previously isolated anddead-end pores become accessible and contribute to the fluidflow; i.e., a more ideal dispersion is displayed.Differences between the profiles at Sor and at 100% Sw are
also observed for L1. At Sor, L1 is the core showing the highestdegree of isolated pores as the profile breaks through earliest;however it is relatively symmetrical, indicating few dead-endpores. After cleaning L1, the tracer profile still breaks throughearly, indicating that the core contains isolated pores both at Sorand at 100% Sw. After cleaning L1, the profile shifts to having along tailing. It may be that removing residual oil opens up dead-end pores causing tailing of the profile due to mass exchangewith these pores. On the basis of dispersion measurements, L1seems to be the most heterogeneous core used in this study.With the core flooding experiments in mind, the heterogeneousproperties of L1 may have contributed to the different behaviorin secondary mode in this core compared to the other cores.And it may explain the different behavior that was observed inthe duplicate experiment in L3. H1 and H2 do not display largevariations in Sor compared to at 100% Sw, indicating a morehomogeneous material.The lowest graph in Figure 11 illustrates the difference for a
homogeneous core relative to a heterogeneous core at 100%water saturation and at Sor.
3.4. Summary Core Flooding Results. Table 7summarizes oil recoveries, Sor, after various flooding stages,the Nc during flooding stages, as well as relative permeabilitymeasurements.
Figure 10. Oil recovery [% OOIP], WBT, and dP profile as a functionof PV injected for core H2. Injection rate is increased from 0.1 mL/min to 0.5 and 1 mL/min after OS injection.
Figure 11. Dispersion profiles for L1−L3 and H1 and H2 at Sor (left) and Sw = 1 (right) and dispersion profiles for L1 and H1 at both Sor and Sw =1(bottom). The fractional flow of water is plotted against the effective PV, i.e., PV corrected for the presence of residual oil.
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The relative permeability to oil after aging at 110 °Cdecreases to around half of the measured value before aging forall of the cores, indicating a shift in wettability to a less water-wet state.Sor for core L1 is 0.16 after waterflooding, as opposed to
close to 0.30 for the other cores, thus the low potential for theLSS process. The oil mobilized by the LSS process in this coremay not have been enough to form a continuous oil bank;instead an alternating oil and emulsion was produced. Thenature of the heterogeneity in L1 may have affected the coreflooding result and thereby explains the difference in recoveryand Sor after waterflooding compared to the other cores.The core material in H1 and H2 is more homogeneous
without visible laminations. The change in oil saturation, ΔSo,after direct LS injection in H1 is 10 saturation units higher thanafter direct OS injection in H2. This is in line with previousresults reported by, for example, Zhang and Morrow.5 LSinjection in tertiary mode, i.e., after an initial SW flood, in L1and L3 gave a negligible increase in oil recovery.Sor after surfactant floods reaches values ≤0.1 in all cores
independent of flooding procedure. The lowest Sor wasobtained in core H2, which was flooded at optimal salinitywith minimum IFT.The surfactant floods in L1, L3, and H1 were all in the LS
regime with a moderate reduction in IFT (0.02 mN/m).Normalized Sor, i.e. Sor(LSS)/Sor(LS), for L3 and H1 were 0.37 and0.25, respectively. In both cases, the oil recoveries aresignificantly higher than what would be predicted from capillarydesaturation curves (CDC) measured on Berea cores.12 Thisincrease in recovery above what is expected from a CDC isattributed to the combined effect of low salinity and surfactant(LSS). Even though oil production during LS injection ismarginal, oil may nonetheless be redistributed and/or oil layersmay be destabilized due to changes in crude oil−brine−rockinteractions taking place during LS injection. Redistribution ofoil is expected to result in fluctuations in the differentialpressure measured across the cores during LS injection. Thus,significant redistribution of oil is less likely to occur in cores L1,L3, and H1 as there is little response on the differential
pressures during LS injection. Still, even with a moderatereduction in IFT, such as in the LSS flooding experiments inthis study, oil layer destabilization coupled with reducedcapillarity may give rise to added recovery beyond what wouldbe expected by the action of the surfactant alone.The Nc’s during the OSS flood in L2 and H2 are around 2
orders of magnitude higher than during the LSS flood in L1,L3, and H1. However, the final recoveries and Sor are more orless equal, highlighting the combined effect of LSS.Identical core preparations and flooding sequences were
performed on cores L1 and L3, yet the production profiles inthese experiments show large variations. This may be a result ofthe laminations in the cores and address the problem ofreproducibility in heterogeneous core material.
3.5. Dynamic Retention. During a surfactant floodingprocess in an oil containing core, retention mechanisms includeadsorption on the mineral surface, precipitation of surfactant,and surfactant partitioning into the oil phase.34 In a dynamicretention experiment in an oil free core, such as in cores R1 andR2, the last mechanism above is excluded.Dynamic retention experiments were performed in two
heterogeneous Berea cores named R1 and R2, withpermeabilities around 100 mD, at 100% Sw. R1 and R2 weresaturated with LS and OS brine, respectively. Retentionprofiles, Figure 12, were obtained by injecting a surfactantslug (R1 = 5 PV and R2 = 6 PV) into the core which had asalinity corresponding to the surfactant solution salinity. Theslugs contained the same components and concentrations as inthe flooding experiments and were followed by a continuousinjection of chase water with the appropriate salinity. Theeffluent was collected in fractions at different cumulativeinjection volumes to be analyzed for total surfactant content bypotentiometric titration.Comparing the two graphs in Figure 12, it is seen that the
LSS solution injected into core R1 saturated with LS brinebreaks through nearly 1 PV before the OSS solution injectedinto core R2 saturated with OS brine, indicating higherretention in R2. Another indication of higher retention is thesmaller area under the graph for R2 despite the larger slug size
Table 7. Summary of Relative Permeabilities, Nc, Recoveries and Sor at Different Injection Stagesa
aLS brine is used in L1, L3, and H1. OS brine is used in L2 and H2.
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injected in this core. Adsorption equilibrium, C/C0 = 1, isobtained for a larger number of fractions in R1 than R2, despitethe larger slug injected in R2.Retention data for cores L1−L3 and H1 and H2 were
obtained as a supplement to the core displacement experi-ments. The surfactant solutions were continuously injected inall cores, Figures 6−10.R2, L2, and H2 are flooded with the OSS solution, whereas
R1, L1, L3, and L1 are flooded with the LSS solution. Table 8shows the retention data for the cores where all of the OS corefloods display a higher retention than the LS core floods.Average retention is 0.39 mg surfactant/g rock for the OSfloods and 0.24 mg surfactant/g rock for the LS floods. Thisverifies that retention increases with increasing salinity.35
Surfactant retention is higher during flow through a 100%water saturated core than during flow at Sor in all experiments.One possible explanation for the lower retention values duringflow at Sor could be oil occupying adsorption sites on the rocksurface and thus making less sites available for surfactantadsorption.
4. CONCLUSIONSA 3:1 ratio of an APS 7 PO and IOS1518 blend show goodaqueous solubility and microemulsion phase behavior over awide range of salinities containing divalent ions.The tested Berea cores, both homogeneous and heteroge-
neous, show insignificant response to LS injection alone.A moderate reduction in IFT under LS conditions gives
similar oil recoveries as ultralow IFT at higher salinity. The LSSfloods give higher oil recovery than what would be predicted bythe Nc relationship. The OSS floods give oil recoveries in linewith what would be expected by the Nc relationship.Heterogeneity in core material can affect the flooding
behavior and cause difficulties with respect to reproducibility.However, dispersion measurements at various Sor’s can helpreveal heterogeneities and help interpret the results.
The surfactant retention values are lower in a LS environ-ment (average of 0.24 mg surfactant/g rock) than in an OSenvironment (average of 0.39 mg surfactant/g rock) both at100% water saturation, and when oil is present.
SBA = secondary butanol alcoholSP = solubilization parameterSoi = initial oil saturationSor(LS) = residual oil saturation after the low salinity floodSor(LSS) = residual oil saturation after combined low salinitysurfactant floodSor(OS) = residual oil saturation after the optimal salinity floodSor(OSS) = residual oil saturation after the optimal salinitysurfactant floodSor(SW) = residual oil saturation after seawater floodSTO = stock-tank oilSW = synthetic seawaterSw = water saturationSwi = initial water saturationu = Darcy velocityVo = volume oilVs = volume surfactantVw = volume waterWBT = water breakthroughWOR = water−oil ratioz = valence of ionμ = viscosityρ = densityσ = interfacial tension
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