Effect of Alkaline Preflush in an Alkaline-Surfactant-Polymer Flood

Effect of Alkaline Preflush in an Alkaline-Surfactant-Polymer FloodKrishna Panthi and Kishore K. Mohanty*

Department of Petroleum and Geosystems Engineering, The University of Texas at Austin

ABSTRACT: An ultralow interfacial tension alkali-surfactant-polymer formulation was developed for a sandstone reservoir.Phase behavior was studied with the reservoir oil at different water−oil ratios and varying salt/alkali concentrations. The rheologyof the resulting microemulsion phases was measured with and without polymers. The surfactant formulation was tested with afield core and an out-crop core, with and without an alkaline preflush. Waterflood recovered about 48% of the oil in place andreduced the oil saturation to 35% for the field core. The tertiary ASP injection in the field core without alkaline preflush yielded80% cumulative oil recovery; the recovery increased to 85% in the same core (and the same surfactant formulation) if the alkalinepreflush was used. The oil recovery in the out-crop core with the alkaline preflush was 94%. Alkaline preflush increases the coresalinity to the optimum salinity of the surfactant formulation before the surfactant slug.

■ INTRODUCTION

Waterflood recovers about a third of the oil from petroleumreservoirs because of capillary trapping and large-scalebypassing due to permeability heterogeneity. In the U.S.,about 168 billion barrels of oil have been recovered, but about377 billion barrels have been left behind in known reservoirs.1

Tertiary recovery techniques such as chemical flooding,miscible gas displacement, and thermal recovery are neededto extract a part of this remaining oil.Chemical flooding using alkali, surfactants, and polymers

(alkaline-surfactant-polymer or ASP) is a flexible techniqueapplicable to many reservoirs. Surfactants lower the oil/waterinterfacial tension to the order of 0.001 mN/m so that theviscous forces can overcome the capillary forces and mobilizeisolated oil blobs.2 Alkali form soap with acidic crude oils andlower surfactant adsorption.3−5 Polymers increase the viscosityof the aqueous phase and reduce bypassing.6 Past phasebehavior experiments have shown that many surfactants have athree-phase microemulsion (Winsor III) phase behavior at anintermediate salinity.7,8 The interfacial tension has an inversecorrelation with the oil and water solubilization in themicremulsion phase.9 The interfacial tension is ultralow(about 0.001 mN/m) in these three-phase systems.10

Many new surfactants have been discovered for chemicalflooding in the last 20 years. For example, the internal olefinsulfonate surfactants are stable in high temperature reservoirs.11

The propoxy and ethoxy sulfate and sulfonate surfactants aretolerant of high salinity.12 Large hydrophobe (CnH2n + 2, n > 20)surfactants with more than 20 propoxy and ethoxy groups havebeen synthesized and used in surfactant formulations13 forviscous oils.There was a successful field pilot of chemical flooding in

Illinois in 1980s.14−16 There have been many pilots of polymerand ASP techniques in the Daqing field in China in the lasttwenty years, but chemical flooding is not applied routinelyafter waterfloods.17 The increased oil price in the last five yearshas increased the interest in ASP flooding, but there is nosimple method to identify the chemicals needed for a particularoil reservoir. The transport of alkali, surfactants, and polymersthrough the reservoir rock is also not well understood.

Surfactant formulation development for a specific reservoir isa complex procedure. The phase behavior is studied with thefield oil and brine for many surfactants. The surfactants areidentified which give three-phase behavior at a salinity close tothe reservoir salinity. Cosurfactant, alkali, and alcohol are oftenadded to improve the phase behavior and avoid liquidcrystalline phases.18,19 The polymer is then added to increasethe viscosity of the aqueous phase for mobility control. All ofthe chemicals are checked for long-term chemical and thermalstability at the reservoir conditions. Coreflood experiments arethen conducted in outcrop or reservoir cores to study thetransport of all of the chemical constituents, adsorption, and oilrecovery.9

This article outlines a chemical formulation development fora sandstone reservoir. The phase behavior with the reservoir oilwas studied for many surfactant combinations. The results withthe selected formulation are described below. The viscosity ofthe three-phase system with polymer was measured. Thenwaterflood and tertiary ASP floods were conducted in anoutcrop core and a reservoir core. The effectiveness of the ASPflood with and without the use of an alkaline preflush isdescribed below.

■ EXPERIMENTAL METHODOLOGYChemicals. Commonly available chemicals were used in the

surfactant formulation. Surfactants Tridecyl Alcohol Propoxy Sulfate(TDA−PO−SO4) and C20−24 Internal Olefin Sulfonate (C20−24IOS) were obtained from Stepan chemical company. PolymerHPAM 3330 was obtained from SNF Floerger company. Its molecularweight was 8 × 106 gm/mol and the degree of hydrolysis was 25−30%.Sodium carbonate (Na2CO3) was used as the alkali. The injection (andformation) brine composition was approximated by 192 ppmpotassium chloride (KCl), 19601 ppm sodium chloride (NaCl) and1228 ppm sodium bicarbonate (NaHCO3), which is called the“synthetic injection brine”. The stock tank oil from the reservoir wasused. Its density was 0.86 g/cm3 and viscosity was 12 cP at 59 °C, the

Received: November 12, 2012Revised: February 1, 2013Published: February 5, 2013

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© 2013 American Chemical Society 764 dx.doi.org/10.1021/ef301847z | Energy Fuels 2013, 27, 764−771

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reservoir temperature. The total acid number of the oil was 2.04 mgKOH per gm of oil.Phase Behavior. Equal volumes of oil and 1 wt % surfactant

solution were mixed in pipettes and sealed. They were equilibrated atthe reservoir temperature and their phase volumes were observed.NaCl concentration was varied (in a series of pipettes) keeping theconcentrations of KCl, NaHCO3, Na2CO3, and surfactant constant.The solubilization of the oil and water in the microemulsion phaseswas calculated from the phase volumes. The interfacial tension wasestimated from the Huh equation.8 The phase behavior was studied asa function of water-to-oil ratio (WOR). Polymer (2500 ppm HPAM)was added to some of the phase behavior samples and the viscosity ofthe equilibrated phases was measured by an ARES rheometer. Theviscosity was measured at shear rates ranging from 1 to 100 s−1.Core Material. Two reservoir core plugs were combined together

to get a total length of 9.6 in.. This core mount is referred to as theField Core in Table 1. The diameter was 1.5 in. The porosity was 20%

and the permeability 990 mD for brine. The pore volume was 51.3cm3. The out-crop core was a Berea sandstone having a length of 10.69in. and diameter of 1.49 in.. The porosity was 18% and thepermeability was obtained as 300 mD for brine. The pore volumewas 55 cm3.Core Preparation. The cores were first fully saturated with the

formation brine and then flooded with the reservoir oil. They werethen aged at 80 °C for about two months to attain reservoirwettability. After aging, the cores were flooded with 2 PV of fresh oiland kept in an oven at the reservoir temperature, 59 °C. It is presumedthat this preparation brings the core to its reservoir condition at thetime of waterflood.The cores were then flooded in a vertical orientation with 3 PV of

synthetic formation brine from the bottom at the rate of 1 ft/D andthen 2 PV of the same brine was injected at the rate of 10 ft/D. Thefirst step represents a waterflood at a typical field rate; the second stepis conducted to identify any capillary end effect.ASP Coreflood. The tertiary ASP flood consists of an ASP slug

followed by a polymer slug which is followed by injection brine. Thesurfactant concentration in the ASP slug was half of that in the phasebehavior experiment, a total of 0.5 wt %. The larger amount is used inthe phase behavior experiment so that the third phase volume wouldbe large enough to be measured accurately. In Core Floods 2 and 3, analkaline preflush slug is injected before the ASP slug. The slugcompositions are given in Table 2. In coreflood 1, after waterflood, 0.3pore volume of ASP slug was injected, followed by about 1 pore

volume of the mixture of field brine and 2500 ppm HPAM3330. Thispolymer slug was followed by about 1 pore volume of syntheticinjection brine. Then the core was cleaned and prepared, as describedabove. The second ASP flood was similar to the first ASP flood exceptfor one difference. After the waterflood, an alkali preflush was injectedfor 0.4 PV before the injection of ASP slug. This slug consisted ofsynthetic formation brine, NaCl, and NaCO3. Coreflood 3 wasconducted in the outcrop core; the procedure was similar to CoreFlood 2.

The core used in Core Flood 1 was cleaned in the following mannerafter the ASP flood: it was first injected with a 2 PV of brine followedby 2 PV of tetrahydrofuran (THF), which was further followed by 2PV of chloroform, followed by 3 PV methanol, and flooded with about10 PV of brine again. Injection of oil led to a high residual watersaturation of about 49%. To lower the Swi, 1.5 PV of a viscous oil wasinjected and then 1 PV of 1:1 mixture of the viscous oil and the fieldoil, which was followed by 2 PV of the field oil. The core was thenaged in oven at the reservoir temperature, 59 °C. This core was thenused in Core Flood 2.

■ RESULTS AND DISCUSSIONS

Phase Behavior. The surfactant formulation consisted of0.75 wt % TDA−PO−SO4 as a surfactant, 0.25 wt % C20−24IOS as a cosurfactant, and 0.5 wt % Na2CO3 in the syntheticinjection brine to which an additional amount of NaCl (0−2.5wt %) was added. Equal amounts of reservoir dead oil andsurfactant solution were mixed in pipettes, that is, WOR = 1.Part a of Figure 1 shows the phase behavior as a function of theadditional NaCl concentration (0−2.5 wt %). At low salinity(tubes AO-41, AO-42), there are two phases: the bottom phaseis the microemulsion; the top phase is oil (Type I). Threephases (water, microemulsion, and oil) exist in the intermediatesalinity (in 4 samples AO-43 to AO-46); this is called Type IIIphase behavior. Two phases (water and microemulsion) exist atthe high salinity for the tubes AO-47 to AO-49 (Type II). Thisis the typical oil−water−surfactant phase behavior. Part b ofFigure 1 shows water and oil solubilization ratios. The optimalsalinity is 1.1 wt % additional NaCl; the solubilization ratio (S)at the optimum is 19. The interfacial tension in this system isestimated from the Huh equation, IFT (mN/m) = 0.3/S2. Thelowest IFT is 0.0028 mN/m. This IFT is adequate formobilization of oil in porous media, as will be shown in thecorefloods.The phase behavior experiments were conducted at WOR

other than 1. The effect of WOR on the type of phase behavioris shown in Figure 2. A high WOR corresponds to a small oil/(oil+water); Type III phase behavior shifts to a smaller salinity.A high WOR also corresponds to less soap formation becauseof lower amount of oil. Thus, the soap to synthetic surfactantratio is lower at a high WOR. This shows that the syntheticsurfactant is more hydrophobic than the soaps generated by thereaction with alkali. The WOR is important when dealing withacidic oils which contain naphthenic acids or other similarorganic compounds that become soaps when reacts with alkali.HPAM (2500 ppm) was added to the brine at the optimal

salinity (for WOR = 1). Equal volume of oil was then added tothe surfactant−polymer solution. Mixing of oil, brine,surfactant, and polymer at the optimal salinity resulted inthree phases. Figure 3 shows the viscosity of the pure oil andthe three equilibrium phases at the optimum salinity. The oilviscosity is independent of the shear rate. The top phaseviscosity is almost equal to that of the oil. The middle phaseand bottom phase viscosities are shear rate dependent. Themiddle phase viscosity is about 2 to 3 times more viscous than

Table 1. List of Coreflood Experiments

flood # core conditionlength(inch)

Φ(%)

k(mD)

Soi(%)

1 field no preflush 9.6 20 990 672 field preflush 9.6 20 990 793 outcrop preflush 10.7 18 300 79

Table 2. Slug Compositions in ASP Flood

chemicalwaterflood brine

(ppm)preflush slug

(ppm)ASP slug(ppm)

polymer slug(ppm)

PV injected 5 0.4 0.3 1TDA−PO−SO4

3750

C20−24IOS

1250

HPAM 2500 2500NaCl 19 600 30 600 11 000 +

19 60019 600 +5000

Na2CO3 5000 5000NaHCO3 1228 1228 1220 1220KCl 192 192 192 192

Energy & Fuels Article

dx.doi.org/10.1021/ef301847z | Energy Fuels 2013, 27, 764−771765

the oil at 10 s−1 shear rate. This indicates that the middle phaseis high structured as also shown by Kaler et al.20

Core Floods. Table 1 shows the conditions for thecorefloods. Two corefloods were conducted with the reservoircore and one with the out-crop core.

Core Flood 1. This core flood was conducted in the reservoircore with the reservoir dead oil. The waterflood was followedby ASP flood. Figure 4 shows the oil recovery during waterflooding. The initial oil saturation was about 67%. Waterfloodat 1 ft/D rate reduced the oil saturation to 35% in about 3 PVinjected. The water injection rate was then increased by 10times, but very little oil was produced implying minimalcapillary end effect.The waterflood was followed by 0.3 PV ASP slug which

included 0.375% TDA−PO−SO4, 0.125% C20−24 IOS, 5000ppm Na2CO3, 11 000 ppm NaCl, and 2500 ppm HPAM3330 inaddition to the simulated injection brine. After the ASP slug, a 1PV polymer slug was injected which included 5000 ppm NaCland 2500 HPAM3330 in the simulated formation brine; thesimulated formation brine was injected after the polymer slugfor 2 PV. Figure 5 shows the tertiary oil recovery during ASPflooding. In the beginning, no oil was produced because thecore was at waterflood residual at the start of the surfactantflood. Oil bank broke through at about 0.5 PV injected. Oil cutincreased to 85% for a short time and then decreased. Most ofthe oil was produced by 1.75 PV injection; the residual oilsaturation was reduced to 13%. Cumulative oil recovery for thewaterflood was 47%; at the end of the ASP flood the cumulativerecovery rose to 80%. Table 3 reports the oil recovery in thecorefloods.Figure 6 shows the conductivity of the effluent brine in Core

Flood 1; both waterflood and chemical flood effluents areplotted together in this figure. The conductivity is a proxy forthe brine salinity. It shows that the conductivity startsincreasing at about 5.5 PV injection, reaches a highestconductivity of 570 μS briefly between 6 PV and 6.2 PVinjection and decreases. It does not quite reach 75% of theinjected ASP value (600 μS). There is mixing between theformation brine and the surfactant slug and the optimal salinityis not attained throughout the surfactant slug. In the nextcoreflood, a preflush of the optimal salinity brine was injectedahead of the ASP slug to separate it from the field brine. Thedecrease of salinity after the surfactant slug is desirable toreduce surfactant retention and increase the polymer solutionviscosity (due to the salinity decrease).

Core Flood 2. In Core Flood 2, the core flooding was donein the same core under the same conditions as Core Flood 1,but the core was preflushed with 0.4 pore volume of optimumsalinity brine (no surfactant or polymer) before injecting theASP slug. Also, the salinity of the polymer slug was 70% of theoptimum salinity.

Figure 1. Phase behavior at 59 °C with 0.75% TDA−PO−SO4 as asurfactant, 0.25% C20−24 IOS as a cosurfactant, 0.5% Na2CO3 andscanning with 0−2% NaCl in addition to synthetic injection brine,WOR = 1 (a) photograph of pipettes (AO-41 to AO-49 in increasingorder of additional NaCl from 0% to 2%), (b) oil and watersolubilization ratios.

Figure 2. Effect of water−oil ratio on phase behavior.

Figure 3. Viscosity of original oil and oil-surfactant water equilibratedphases at the optimum salinity (WOR = 1).



The field core was brought to Swi after the Core Flood 1, asdescribed in the methodology section. The core was thenflooded with 3 PV of synthetic formation brine, from thebottom at the rate of 1 ft/D and then 2 PV of the same brine

was injected at the rate of 10 ft/D. These floods represent awaterflood. Then 0.4 PV of preflush (brine at optimum salinity,that is, a mixture solution of softened field brine, 5000 ppmsodium carbonate, and 11 000 ppm additional NaCl), wasinjected. The next slug was 0.3 pore volume of ASP. It included0.375% TDA−PO−SO4, 0.125% C20−24 IOS, 5000 ppmNa2CO3, 11 000 ppm NaCl, and 2500 ppm HPAM3330 inaddition to the simulated formation brine. After 0.3 PV of ASPslug injection, 1 PV of the mixture of 2500 ppm HPAM3330and 26 000 ppm salinity brine, that is, simulated field brinealong with 5000 ppm additional NaCl, was injected. This slugwas followed by about 2 PV of simulated field brine.

Figure 4. Water flood oil recovery, Core Flood 1.

Figure 5. Tertiary chemical flood oil recovery, Core Flood 1.

Table 3. Oil Recovery in Coreflood Experiments

flood # core condition

initial oilsaturation

(%)

WF oilrecovery (%OOIP)

WF+ASPrecovery (%OOIP)

1 field nopreflush

67 47 80

2 field preflush 79 42 853 outcrop preflush 79 48 94



Figure 7 shows the oil recovery during water flooding. Theinitial oil saturation was about 78%. Waterflood at 1 ft/D ratereduced the oil saturation to about 46% in about 3 PV injected.The water injection rate was bumped up by 10 times, but verylittle oil was produced indicating little capillary end effect.Figure 8 shows the tertiary oil recovery during preflushfollowed by ASP flooding, which was further followed bypolymer flooding. In the beginning, some oil was produced at alow oil cut because of the preflush; then the oil bank brokethrough at about 0.5 PV injected. Oil cut increased to 40% forsome time and then slowly decreased. Most of the oil isproduced by 1.5 PV injections; the residual oil saturation wasreduced to 11%. Cumulative oil recovery for the waterflood was42%; at the end of the ASP flood the cumulative recoveryincreased to 85% OOIP.Figure 9 shows the pressure drop during the tertiary

recovery. The pressure drop started at about 5 psicorresponding to brine flow at the Sorw, increased to about 35psi during the ASP injection and then decreased to below 20 psiduring polymer injection. Eventually, it fell to about 5 psi

during the brine flood at the end. The high pressure dropduring the ASP slug indicates a high viscosity for themicroemulsion phase, as seen in Figure 3. The oil recoverycan be further improved by decreasing the microemulsionviscosity.

Figure 6. Conductivity of effluents: Core Flood 1(solutions are diluted200 times, conductivity of SFB = 460 μS, ASP solution = 800 μS, andpolymer slug = 720 μS), Core Flood 2 (solutions are diluted 400times, conductivity of SFB = 230 μS, preflush = 400 μS, solution = 400μS, and polymer slug = 359 μS).



Figure 9. Pressure drop during tertiary oil recovery, Core Flood 2.



The conductivity of the effluent brine (both waterflood andASP flood) is plotted together in Figure 6 (along with that ofCore Flood 1). It shows that the salinity increased to thehighest salinity (conductivity above 300 μS, 75% of the injectedASP conductivity) at about 5.3 PV, before the arrival of thesurfactant slug and was sustained during the surfactant slug, upto 6.7 PV injected. The use of the alkaline preflush moved themixing with the formation brine away from the surfactant slug.Figure 10 shows the pH of the effluent brine; both waterflood

and ASP flood are plotted together. The pH increases when thepreflush is injected and maintains the high pH conditionthroughout the surfactant injection.The effluent surfactant concentration was measured and is

shown in Figure 11. It is not shown, but the two surfactantsmoved together in the core. Surfactant breakthrough occurredat 5.7 PV injected. The oil also arrived at about the same time.This shows that the surfactant slug did not push the oil bankeffectively. Ideally, the surfactant should have broken throughafter the oil bank. The retention of surfactant in the core wascalculated from the effluent surfactant concentration bymaterial balance. The retention was 0.015 mg of the surfactantper gram of the core, which is a reasonably low (<0.3 mg/g).Core Flood 3. In Core Flood 3, the core flooding was

conducted in an out-crop core under the same conditions asCore Flood 2. The comparison of the two floods shows theeffect of field core complexity.The out-crop core was brought to Swi, as described in the

methodology section. The core was then flooded with 3 PV ofsynthetic formation brine, from the bottom at the rate of 1 ft/Dand then 2 PV of the same brine was injected at the rate of 10ft/D. These floods represent a waterflood. Then 0.4 PV of

preflush (brine at optimum salinity, i.e., a mixture solution ofsoftened field brine, 5000 ppm sodium carbonate, and 11 000ppm additional NaCl), was injected. The next slug was 0.3 PVof ASP. It included 0.375% TDA−PO−SO4, 0.125% C20−24IOS, 5000 ppm Na2CO3, 11 000 ppm NaCl, and 2500 ppmHPAM3330 in addition to the simulated formation brine. After0.3 PV of ASP slug injection, 1 PV of the mixture of 2500 ppmHPAM3330 and 26000 ppm salinity brine, that is, simulatedfield brine along with 5000 ppm additional NaCl, was injected.This slug was followed by about 2 PV of simulated field brine.Figure 12 shows the oil recovery during water flooding. The

initial oil saturation was about 79%. Water flood at 1 ft/D ratereduced the oil saturation to about 42% in about 3 PV injected.The water injection rate was bumped up by 10 times, but verylittle oil was produced indicating little capillary end effect. Theoil recovery in the waterflood was 47% of the OOIP. Figure 13shows the tertiary oil recovery during preflush followed by ASPflooding which was further followed by polymer flooding. Inthe beginning some oil was produced at a low oil cut because ofthe preflush; then the oil bank broke through at about 5.5 PVinjected. The surfactant injection started at 5.4 PV. Oil cutincreased to 50% for a brief period and then slowly decreased.Most of the oil was produced by 8 PV injection (2.6 PV aftersurfactant injection initiation); the residual oil saturation wasreduced to 4%. Cumulative oil recovery for the waterflood was47%; at the end of the ASP flood the cumulative recoveryincreased to 94% OOIP. This flood showed that the surfactantformulation is very effective in a relatively homogeneous core.The effluent viscosity (at 10 s−1 shear rate) is shown in

Figure 14. The viscosity is a proxy for the presence of polymerand shows that the chemicals (surfactant and polymer) breaksthrough around 6.2 PV injected. Two-thirds of the oil bank isproduced by this time indicating that the ASP slug pushed theoil bank. The pressure drop data for the ASP flood is shown inFigure 15; it was about 3 psi during the alkaline preflush at theflow rate of 0.05 ft/D. The pressure drop increased to about 13psi during the ASP and polymer injection. It fell back to about 3psi after brine injection.The conductivity of the effluent brine for both waterflood

and chemical flood are plotted together in Figure 16. Theconductivity increased above 3mS (75% of the injected ASPsolution conductivity) between 6 and 7 PV during thesurfactant injection. The salinity decreased during the polymerflood and the subsequent brine flood. The salinity gradientdrives the fluids into the type I region after the surfactant slug,

Figure 10. pH of effluent samples during Core Flood 2.

Figure 11. Concentration of surfactants in effluent samples and cumulative oil recovery (twice diluted), Core Flood 2.



which drives the surfactants into the aqueous phase whichminimizes surfactant retention.This study showed that a combination of a propoxy sulfate

and a sulfonate surfactant can develop low interfacial tensionwith a reservoir crude oil. Because the oil is active, soap isgenerated with its reaction with alkali. Therefore, the syntheticsurfactant requirement is small, 0.5 wt %. The corefloodsshowed that the ASP formulation is effective in mobilizing the

oil left behind by the water flood. The alkaline preflush beforethe surfactant injection brings up the core salinity to theoptimal salinity before the ASP slug and increases oil recovery.The microemulsion phase viscosity is higher than the oilviscosity; alcohols could be used to reduce the viscosity of themiddle microemulsion phase (in future studies).

■ CONCLUSIONS

This article describes a systematic laboratory approach to ASPflooding that successfully tested chemical formulations usingphase behavior experiments, and validated their ability torecover oil from reservoir cores. A mixture of two surfactantsTDA−PO−SO4 and C20−24IOS showed three-phase micro-emulsion behavior with the crude oil and Na2CO3 as the alkali.A solubilization ratio of 19 was obtained at the optimal salinitywhich corresponds to an interfacial tension of 0.0028 mN/m.The optimal salinity at a WOR = 1 corresponded to an additionof 1.1 wt % NaCl and 5000 ppm Na2CO3 to the syntheticinjection brine. As the WOR decreased the optimal salinitydecreased, unlike the trend in typical active oils. This impliesthat the soap generated is more hydrophilic than the synthetic



Figure 14. Viscosity of the effluent water phase, Core Flood 3.



surfactants used. When polymer is added to the surfactant-brinethat is equilibrated with oil, the bottom phase (excess water)and the middle phase (microemulsion) show shear dependenceand high viscosity; but the top phase (oil) is Newtonian with aviscosity identical to that of the oil. At most, water floodrecovered 48% OOIP and reduced the oil saturation to 35%.The tertiary ASP injection in the field core without alkalinepreflush yielded 80% cumulative oil recovery; the recoveryincreased to 85% in the same core (and the same surfactantformulation) if the alkaline preflush was used. The tertiary ASPinjection in an out-crop Berea core with an alkaline preflushyielded 94% oil recovery, which shows that the surfactantformulation is very effective in a relatively homogeneous core.Alkaline preflush increases the core salinity to the optimumsalinity of the surfactant formulation before the surfactant slug.

■ AUTHOR INFORMATIONCorresponding Author*Tel: 512-471-3077, fax: 512-471-9605, e-mail: [email protected] authors declare no competing financial interest.

■ ACKNOWLEDGMENTSThe authors would like to thank the industrial affiliates of theChemical Enhanced Oil Recovery project at the University ofTexas at Austin for the financial support.

■ REFERENCES(1) Mohanty, K. K. AIChE J. 2003, 49, 2454−2460.

(2) Stegemeier, G. L. Presented at the AIChE Symposium on ImprovedOil Recovery by Surfactant and Polymer, Kansas City, MO, April 12−14,1976.(3) Nelson, R. C.; Lawson, J. B.; Thigpen, D. R.; Stegemeier, G. L.Presented at the Symposium on Improved Oil Recovery, Tulsa, OK, April15−18, 1984, Paper SPE 12672.(4) Hirasaki, G. J.; Miller, C. A.; Puerto, M. Presentation at the SPE2008 Annual Technical Conference and Exhibition, Denver, September21−24, 2008, Paper SPE 115385.(5) Liu, S.; Li, R. F.; Miller, C. A.; Hirasaki, G. J. Presentation at theSPE/DOE 2008 Improved Oil Recovery Symposium, Tulsa, USA, April19−23, 2008, Paper SPE 113936.(6) Al-Dhafeeri, A. M.; Seright, R. S.; Nasr-El-Din, H. A.; Sydansk, R.D. Presentation at the SPE International Improved Oil RecoveryConference in Asia Pacific, Kuala Lumpur, Malaysia, December 5−6,2005, Paper SPE 97542.(7) Winsor, P. A. Solvent Properties of Amphiphilic Compounds;Butterworths Scientific Publication: London, 1954.(8) Healy, R. N.; Reed, R. L.; Stenmark, D. K. Soc. Pet. Eng. J. 1976,16, 147−160 SPE-5565-PA..(9) Huh, C. J. Colloid Interface Sci. 1979, 71, 408−426.(10) Nelson, R. C.; Pope, G. A. Soc. Pet. Eng. J. 1978, 18, 325−338SPE-6773-PA..(11) Barnes, J. R.; Dirkzwager, H.; Smit, J.; Smit, J. P.; On, A.Presented at the Symposium on Improved Oil Recovery, Tulsa, OK, April24−28, 2010, Paper SPE 129766.(12) Wu, Y.; Iglauer, S.; Shuler, P.; Tang, Y.; Goddard, W. A. TensideSurf. Det. 2010, 47, 3.(13) Lu, J.; Britton, C.; Solairaj, S.; Liyanage, P. S.; Kim, D. H.;Adkins, S.; Arachchilage, G. W. P.; Weerasooriya, U.; Pope, G. A.Presented at the SPE Improved Oil Recovery Symposium, Tulsa,Oklahoma, USA, April 14−18, 2012, Paper SPE 154261 MS.(14) Reppert, T. R. Presented at the SPE/DOE Improved Oil RecoverySymposium, Tulsa, Oklahoma, USA, April 22−25, 1990. Paper SPE20219.(15) Huh, C.; Lange, E. A.; Cannella, W. J. Presented at the SPE/DOEImproved Oil Recovery Symposium, Tulsa, Oklahoma, USA, April 22−25, 1990, Paper SPE 20235.(16) Maerker, J. M.; Gale, W. W. SPE Reservoir Engineering 1992,36−44.(17) Demin, W.,; Jiecheng, C.; Junzheng, W.; Zhenyu, Y.; Yuning, Y.;Hongfu, L. Presented at Improved Oil Recovery Conference, KualaLumpur, Malaysia, October 25-26, 1999. Paper SPE 57288.(18) Jackson, A. J. Experimental Study of the Benefits of SodiumCarbonate on Surfactants for Enhanced Oil Recovery. MS Thesis, TheUniversity of Texas at Austin, Austin, TX, 2006.(19) Levitt, D. B. 2006. Experimental Evaluation of High Perform-ance EOR Surfactants for a Dolomite Oil Reservoir. MS Thesis, TheUniversity of Texas at Austin, Austin, TX.(20) Kaler, E. W.; Davis, H. T.; Scriven, L. E. J. Chem. Phys. 1983, 79,5685.

Figure 15. Pressure drop data for tertiary chemical flood, Core Flood 3.

Figure 16. Conductivity of effluent samples during Core Flood 3.Solutions are diluted 40 times and conductivity of SFB = 2.3 mS,preflush = 3.97 mS, ASP solution = 4.0 mS, and polymer slug = 3 mS.



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Effect of Alkaline Preflush in an Alkaline-Surfactant-Polymer Flood