Wettability Alteration in High-Temperatureand High-Salinity Carbonate Reservoirs

Gaurav Sharma, Baker Hughes, and Kishore K. Mohanty, University of Texas at Austin

Summary

The goal of this work was to change the wettability of a carbonaterock from mixed-wet toward water-wet at high temperature andhigh salinity. Three types of surfactants in dilute concentrations(<0.2 wt%) were used. Initial surfactant screening was performedon the basis of aqueous stability at these harsh conditions. Con-tact-angle experiments on aged calcite plates were conducted tonarrow the list of surfactants, and spontaneous-imbibition experi-ments were conducted on field cores for promising surfactants.Secondary waterflooding was carried out in cores with and with-out the wettability-altering surfactants. It was observed that mostbut not all surfactants were aqueous-unstable by themselves atthese harsh conditions. Dual-surfactant systems, mixtures of anonionic and a cationic surfactant, increased the aqueous stability.Some of the dual-surfactant systems proved effective for wettabil-ity alteration and could recover could recover 70 to 80% OOIP(original oil in place) during spontaneous imbibition. Secondarywaterflooding with the wettability-altering surfactant increasedthe oil recovery over the waterflooding without the surfactants(from 29 to 40% of OOIP).

Introduction

Approximately half of the world’s discovered oil reserves are incarbonate reservoirs, and many of these reservoirs are naturallyfractured (Roehl and Choquette 1985). Carbonate reservoirs oftenhave a high degree of heterogeneity, and the pore structure iscomplex. The carbonate rocks are often mixed-wet to oil-wetbecause of the positive zeta-potential of the rock surface, thehardness of the brine, and the presence of asphaltenes and organicacids in the oil. As a result of microscopic oil trapping and macro-scopic bypassing, waterflooding in carbonate reservoirs is oftenpoor (Manrique et al. 2006). Improved oil recovery from oil-wet,low-permeability carbonate reservoirs is a great challenge.

Reservoir wettability plays an important role during water-flooding. In a water-wet reservoir, water occupies the relativelysmaller pores and oil occupies the larger pores. At a given satura-tion, water reactive permeability is lower than that of the oil. Thuswater breaks through relatively late (depending on the oil-water-viscosity ratio and reservoir heterogeneity). In an oil-wet reser-voir, water breaks through early (given similar viscosity ratio andheterogeneity) and oil is coproduced with water for many porevolumes (PV) of water injected. The residual-oil saturationdepends on wettability, the minimum being for mixed wettability,lower than either strongly water-wet or oil-wet rocks (Salathiel1973, Jadhunandan and Morrow 1995). Reservoir wettability alsoaffects the bypassing of oil in lower-permeability zones. In awater-wet medium, water can be imbibed into bypassed zones bycapillary forces, thus reducing bypassing. In oil-wet media,bypassing is expected to be higher because capillary forces dis-courage water invasion into these bypassed zones. The goal ofthis study was to identify a wettability-altering agent that can beadded to a waterflood that would change wettability and improveoil recovery in a secondary waterflooding of a nonfractured car-bonate rock.

There are two main approaches to wettability alteration inoriginally oil-wet carbonate rocks. The first approach is through achange in the brine ionic composition. Strand et al. (2006, 2008)have shown that addition of sulfate and other potential-determin-ing ions can change the wettability of originally oil-wet chalkcores at high temperatures (above 90�C). Increase in water-wet-ness was demonstrated by imbibitions of these brines into origi-nally oil-wet chalk cores. It is hypothesized that sulfate ionsreplace the adsorbed negatively charged organic-acid groups, thusmaking the surface more water-wet. High temperature is impor-tant for kinetics fast enough for this ion exchange. Yousef et al.(2010) have shown that diluting the injection-brine salinity for ahigh-temperature and high-salinity carbonate reservoir improvesthe wettability toward a more water-wet state and gives an addi-tional oil recovery of almost 20% over injection of sea brine.

The second approach involves surfactants to alter the wettabil-ity of carbonate rocks, generally from oil-wet to intermediate- orwater-wet. Standnes and Austad (2000, 2003) have conducted a se-ries of studies on oil recovery from oil-wet chalk cores by use ofcationic surfactant solutions. They have shown that cationic surfac-tants, such as dodecyl trimethyl ammonium bromide (DTAB), arequite effective [recovery of approximately 70% of oil remainingafter brine imbibition (OOIP)] in imbibing water into originallyoil-wet cores at concentrations higher than their critical micelleconcentration (approximately 1 wt%). The imbibition mechanismis proposed as the formation of ion-pairs by the interaction betweensurfactant monomers and adsorbed organic carboxylates from thecrude oil. This process can be effective at low temperatures. Ani-onic (Seethepalli et al. 2004; Adibhatla and Mohanty 2008; Hira-saki and Zhang 2004) and nonionic (Xie et al. 2004; Wu et al.2006) surfactants that alter wettability of originally oil-wet carbon-ate rocks have also been identified. These surfactants alter the wett-ability by micellar solubilization of adsorbed hydrophobiccomponents. More than 60% of the original oil can be recoveredfrom initially oil-wet cores by dilute (0.05 wt%) alkaline/surfac-tant-solution imbibition at room temperature (Seethepalli et al.2004). The adsorption of anionic surfactants on calcite mineral canbe suppressed by the addition of an alkali. The anionic-surfactant-solution imbibition process has been modeled, and the simulatorresults match the experimental results at the laboratory scale(Adibhatla and Mohanty 2008). The simulations show that increasein water-wettability increases oil relative permeability, whichenhances the rate of oil drainage by gravity. Anionic-surfactant so-lution imbibes from the sides (and the bottom), and oil is recoveredfrom the top in imbibitions experiments. Gupta and Mohanty(2010) have studied the effect of temperature on the wettabilityalteration with anionic and nonionic surfactants at low salinity andhardness of the brine. There are few papers in the literature on wett-ability-altering surfactant formulations for carbonate reservoirs athigh temperature (>90�C) and high salinity (>50,000 ppm withhardness). Harsh conditions such as high temperature and high sa-linity restrict the use of many surfactants, mainly as a result ofaqueous instability.

The goal of this work was to alter wettability for a high-tem-perature, high-salinity carbonate reservoir using dilute surfactantsolutions. The reservoir studied in these experiments was a non-vuggy grainstone carbonate reservoir (mainly limestone with asmall amount of dolomite and trace amounts of quartz and clays).The reservoir temperature is 100�C (212�F). The salinity ofthe connate water was approximately 200,000 ppm, and the reser-voir was being waterflooded with a brine of lower salinity

Copyright VC 2013 Society of Petroleum Engineers

This paper (SPE 147306) was accepted for presentation at the SPE Annual TechnicalConference and Exhibition, Denver, Colorado, USA, 30 October–2 November 2011, andrevised for publication. Original manuscript received for review 19 July 2011. Revised paperreceived for review 2 June 2012. Paper peer approved 6 July 2012.

646 August 2013 SPE Journal

(approximately 60,000 ppm with 650 ppm of Ca2þ and 2,110 ppmof Mg2þ). The surfactants tried for this study were mainly non-ionic, with a few anionic and cationic surfactants. During thisresearch, mostly simple surfactant systems (single surfactant, dualsurfactants) were tried; no alcohols or polymers were used. Wehave identified a few surfactant systems on the basis of their aque-ous stability and wettability. We have conducted waterfloods withor without these surfactants.

Methodology

Chemicals. Various commercially available nonionic surfactantswere chosen such that their cloud point (CP) in water was above100�C; they are listed in Table 1. These were surfactants from thehomologous series of nonyl phenol (NP) ethoxylates (DOWChemical); the homologous series of 15-S-ethoxylates (DOWChemical); and TDA 30EO (Sasol). Two anionic surfactants,ethoxylated sulfonates AV-70 and AV-150 (BASF), were used inthis study. Ethoxylation of sulfonates improves their salt toler-ance, and these surfactants are aqueous-stable at high tempera-tures. Cationic surfactants tested were cetyltrimethylammoniumbromide (CTAB), DTAB (Arcos Organics), Arquad C-50, andArquad T-50 (AkzoNobel). The formation brine was prepared bymixing 150.6 g of NaCl, 70.0 g of CaCl2�2H2O, 20.6 g ofMgCl2�6H2O, and 0.5 g of Na2SO4 in 1 L of deionized (DI) water.The injection brine was prepared by mixing 41.2 g of NaCl, 2.4 g

of CaCl2�2H2O, 17.9 g of MgCl2�6H2O, 0.2 g of NaHCO3, and6.4 g of Na2SO4 in 1 L of DI water. Field dead oil was supplied byan oil company and stored under a nitrogen blanket.

Contact Angle. The wettability alteration of oil-aged calcitemineral plates is tested into various surfactant solutions. The cal-cite (from Ward’s Natural Science) acts as a proxy for the carbon-ate reservoir. The plates (approximately 1� 1� 0.25 in.) are cutfrom a calcite block along the cleavage plane. The top and bottomsurfaces of these plates are then ground using a diamond plate andpolished using a set of coarse and fine polishing plates (200#,400#, and 600#). Polished calcite plates (Fig. 1) are aged in theformation brine for 1 day at 80�C. Then the plates are removedfrom the formation brine, the excess water is dripped off theplates, and they are immersed in the crude oil. These plates arethen aged for 5 to 7 days at 80�C.

Various surfactant solutions prepared by mixing surfactant andinjection brine are poured into an optical cell (from Hellma). Theaged plates are first immersed briefly in another beaker containingformation brine; if the oil sticks to the surface of calcite plates,they are placed in the optical cell containing brines and surfactantsolutions. These plates rest on the top of a Teflon bar placedinside the optical cell. The optical cell is then sealed and placed inan oven at 80�C. Thereafter, the contact angles of oil drops sittingon the calcite plate are observed for at least a couple of days.Fig. 2 shows the oil drops on an oil-aged calcite plate placed in

TABLE 1—SURFACTANTS USED

Surfactant Chemical Description (Supplier)

Nonionic surfactants

NP-10 Nonyl phenol 10 ethoxylate (Dow)

NP-30 Nonyl phenol 30 ethoxylate (Dow)

NP-50 Nonyl phenol 50 ethoxylate (Dow)

NP-70 Nonyl phenol 70 ethoxylate (Dow)

15-S-15 Secondary alcohol 15 ethoxylate (Dow)

15-S-20 Secondary alcohol 20 ethoxylate (Dow)

15-S-30 Secondary alcohol 30 ethoxylate (Dow)

15-S-40 Secondary alcohol 40 ethoxylate (Dow)

TDA 30EO Tridecyl alcohol 30 ethoxylate (Sasol)

Anionic surfactants

AV-70 7-Ethoxy sulfonate (BASF)

AV-150 15-Ethoxy Sulfonate (BASF)

Cationic surfactants

CTAB Cetyl trimethyl ammonium bromide (ARCOS)

DTAB Dodecyl trimethyl ammonium bromide (ARCOS)

Arquad C-50 Cocoalkyl trimethyl ammonium chloride (AkzoNoble)

Arquad T-50 Stearyl trimethyl ammonium chloride (AkzoNoble)

Fig. 1—1 3 1 3 25-in. polished calcite plate. Fig. 2—Aged calcite plate in the formation brine.

August 2013 SPE Journal 647

the formation brine; oil seems to wet the calcite plate. Contactangles were measured by a Rame-Hart goniometer. The reservoirtemperature is 100�C, but these experiments were conducted at80�C to avoid evaporation issues.

Core Preparation. Field cores were cleaned, dried, and thenvacuum saturated with the formation brine. These steps were car-ried out at room temperature in a Hassler-type coreholder with anoverburden pressure of approximately 1,000 psi. Oil was theninjected at a high pressure (approximately 200–300 psi) to bringthe core to the residual-water saturation. The air permeability, airporosity, permeability to brine (at Sw¼ 1), and permeability to oil(at Sw¼ Swr) were measured. Then the core plug was removedfrom the core holder, placed in glass jar containing crude oil, andkept in an oven at 80�C for at least 1 month. This process ages thereservoir core, and we presume that it restores it nearly to its orig-inal wettability and saturation state.

Imbibition. The surfactant solutions that seemed promising incontact-angle experiments were then used for imbibition experi-ments on reservoir core plugs. For spontaneous imbibitions, theaged core plugs were placed at the experimental temperature inspecially designed imbibition cells (air-tight and able to withstandpressure of approximately 3 atm) containing brine or surfactantsolutions (Fig. 3). The reservoir temperature is 100�C, but theseexperiments were conducted at 92�C to minimize evaporationissues. The core plug is first placed in the formation brine for 7 to10 days to confirm the oil-wetness of the core plug. In the originalstate of the core plug, only 10 to 15% of the oil (of OOIP) isrecovered (attains plateau in 2 to 3 days), and the oil sticks to thesurface like a film. This restored-state core plug is then placed in

a surfactant solution (Fig. 4). If the surfactant solution imbibesinto the core plug, then oil is pushed out of the core plug and col-lects in the neck of these glass cells, which are calibrated to indi-cate the volume collected. This oil is reported as the recoveredoil; the oil stuck on the core surface is not included. Dependingon the efficacy of the surfactant solution, this experiment contin-ues for 1 to 2 months until oil is no longer expelled from the plug.

Coreflood. The purpose of this experiment was to compare theefficacy of the dilute surfactant formulation in a secondary floodwith that of an ordinary waterflood of a restored-state core (for oilrecovery and recovery rate). The reservoir temperature is 100�C,but these experiments were conducted at 95�C to minimize evapo-ration issues in the effluent samples. The secondary flood usingdilute surfactant formulation is referred to here as a modifiedwaterflood. The surfactant formulation (used in dilute concentra-tion) that gave higher oil recovery/recovery rate during imbibitionexperiments was selected for this coreflood. During the water-flood, 5 PV of brine was injected first at a constant flow rate of0.06 cm3/min (approximately 1 ft/D of interstitial velocity). Then,the flow rate was increased in steps to 1 cm3/min (additional 5-PVinjection) and 10 cm3/min (another 10-PV injection). Becausethese are carbonate cores with heterogeneous pore structure,higher flow rates also recover additional oil because of increasingbut low capillary number (Kamath et al. 2001). After the water-flood, each core was resaturated with the crude oil, which returnedit to its original saturation state (Soi � 0.7) and prepared it for themodified waterflood. In the modified waterflood, the surfactant/brine was injected for 1 PV followed by 4 PV of surfactant-freebrine injection at a constant flow rate of 0.06 cm3/min. Then theflow rate was again increased in steps to 1 cm3/min (additional 5-PV injection) and 10 cm3/min (another 10-PV injection). Weassumed that the wettability state of the core was not changed af-ter the first waterflood (supported by imbibition experiments withthe injection brine). The oil recovery and oil cut of the waterfloodare compared with those of the modified waterflood. Fig. 5 showsa schematic of the coreflood apparatus.

Results

Aqueous Stability. Nonionic Surfactants. The nonionic surfac-tants used during this study are of the form R-EOx, where R is ahydrocarbon chain (eg., nonyl, tridecyl, etc.) attached to a chaincontaining several EO (ethoxy or -CH2CH2O-) groups. Surfac-tants that contain the same R but a different number of EO groupsare part of the same homologous series of surfactants. Nonionicsurfactants are supposed to have a CP (i.e., a temperature abovewhich they do not give a clear solution in brine) (Schott 2003).The CP is a function of the molecular structure and brine ioniccomposition (Schott and Royce 1984). Fig. 6 shows the CP of NP

Fig. 3—Imbibition cell with oil accumulation in neck.

Fig. 4—Close-up of the top surface of a core.

648 August 2013 SPE Journal

ethoxylate homologous series in DI water and injection brine. Asthe number of ethoxy groups increases, the CP increases, but itreaches a plateau beyond approximately 30 ethoxy groups. As thesalinity of the brine increases, the CP decreases. The electrolytespresent in the injection brine reduce the amount of water mole-cules available for hydration of the ethoxy moiety of thesurfactant.

Fig. 7 shows the CP of 15-S-ethoxylate homologous series inDI water and injection brine. Again, as the number of ethoxygroups increases, the CP increases, but it reaches a plateau beyondapproximately 30 ethoxy groups. As the salinity of the brineincreases, the CP decreases. TDA 30EO had a cloud point of110�C with the DI brine and 85�C in the injection brine. Eventhough the listed (DI water) CP of most of these surfactants wasabove 100�C, in the presence of injection brine, the CPs werebelow 100�C, making them unsuitable for injection as a singlesurfactant.

Anionic Surfactants. A few anionic surfactants were testedduring this research. Most of the commercially available anionicsurfactants consist of a hydrocarbon chain and sulfonates or sul-fates; they may also contain -EO (ethoxy), -PO (propoxy), or -BO

(butoxy) groups in between. At high temperatures, the sulfatestend to undergo hydrolysis; many anionic surfactants precipitatein the presence of divalent ions Ca2þ/Mg2þ and also adsorb oncarbonate minerals. Thus, we chose only two anionic surfactants,AV-70 and AV-150, which are ethoxylated sulfonates. These sur-factants were soluble and stable with the injection brine at 100�C.

Cationic Surfactants. Many commercially available cationicsurfactants are ammonium salts of a hydrocarbon chain. Cationicsurfactants tested were CTAB, DTAB, Arquad C-50, and ArquadT-50. Their solutions with the injection brine were clear and sta-ble at 100�C.

The interfacial tension (IFT) of the injection brine with eachsurfactant (0.2 wt%) and the field dead oil was measured by thependant-drop method using a Rame-Hart goniometer at a largewater/oil ratio (approximately 100) at 25�C; these values weremostly between 1 and 10 dyne/cm. These surfactants do not de-velop ultralow IFT at the salinities studied, even at 100�C.

Dual-Surfactant Systems. Because most of the nonionic sur-factants used were not aqueous-stable at 100�C, we decided totest some dual-surfactant systems. The CPs are shown in Table 2.Addition of small amounts of anionic or cationic surfactants to anaqueous solution of nonionic surfactants increases the CPs of thenonionic surfactants (Schott and Royce 1984). This effect is alsoknown as “salting in” of the nonionic surfactant. The nonionicsurfactants form mixed micelles with the other surfactant andbecome aqueous-stable. Dual-surfactant systems tested here haveCPs greater than 100�C and thus can be used with the injectionbrine.

Contact Angle. Calcite plates act as good substitutes for the fieldcarbonate rocks for wettability screening. After a week of agingthe plate with crude oil, the plates showed strongly oil-wet charac-ter in the formation brine (Fig. 2). Oil stuck to the plate like films.The plate also showed an oil-wet character when placed in the

SOLTROL BRINE

BPR

ACCUMULATOR

SURF

0-100psi

FC

CORE HOLDER PUMPS

Fig. 5—Coreflood apparatus.

020

40

60

80

100

Clo

ud p

oint

, °C

120

140

20 40No. of ethoxy groups

CP in injection brine

CP in DI water

60 80

Fig. 6—CP of NP ethoxylates as a function of the number ofethoxy groups.

070

80

90

100

110

Clo

ud p

oint

, °C

120

130

10 20No. of ethoxy groups

CP in injection brine

CP in DI water

30 40 50

Fig. 7—CP of 15-S-ethoxylates as a function of the number ofethoxy groups.

TABLE 2—CPs OF DUAL-SURFACTANT MIXTURES TESTED

Nonionic Cationic CP (�C)

Increase

in CP (�C)

0.2 wt% NP-10 0.2 wt% DTAB 125–130 80–85

0.1 wt% NP-10 0.2 wt% DTAB >130 >85

0.2 wt% NP-10 0.2 wt% C-50 >130 >85

0.2 wt% NP-10 0.2 wt% T-50 >130 >85

0.2 wt% 15-S-15 0.1 wt% DTAB 95–100 10–15

0.2 wt% 15-S-20 0.1 wt% DTAB 105–110 15–20

August 2013 SPE Journal 649

injection brine. Dilute surfactants were added to the injectionbrine to change wettability from oil-wet to water-wet. Surfactantschanged the contact angle on the calcite plate to various degrees.Some surfactants hardly altered the contact angle, whereas somechanged it significantly. The calcite plate is labeled oil-wet if thecontact angle is >110�, intermediate-wet for 70–110�, and water-wet for contact angle <70�.

The assessment of wettability alteration on the calcite plate isa subjective process, because many oil drops stick to the calciteplate, and they vary in their final contact angle. We have assessedthe wettability alteration on calcite plate qualitatively rather thanby directly measuring the contact angle of each oil drop on thesurface and then averaging it. In addition, most of the experimentswere repeated; the original and the repeat experiments were simi-lar but not identical. This might be attributed to different levels ofsurface irregularity, surface contamination, and the contaminationof the optical glass box containing the dilute surfactant solution.For all these reasons, we use the calcite-plate experiment as aqualitative screening step.

Nonionic Surfactants. Because the nonionic surfactants werenot aqueous-stable at the reservoir temperature (100�C), theseexperiments were conducted at 80�C. It also helped us avoidissues of evaporation from the optical cell at the higher tempera-ture. These experiments show the trend of wettability alterationwith increasing number of ethoxylates for the same homologousseries.

Dilute concentration (<0.2 wt%) of TDA 30EO changes thecontact angle to intermediate-wet (not shown). We also observedvariation in wettability alteration when the concentration of TDA30EO was varied. We observed that as the concentration of TDA30EO was decreased from 1 wt% to 0.02 wt%, the wettabilityalteration increased (i.e., the calcite plate became more water-wetin 0.02% TDA 30EO). Similar observations have also been madeby Gupta and Mohanty (2010) with different surfactants. Fig. 8

shows the contact angles on aged calcite plates for the surfactantsin the homologous series of NP-ethoxylates (as well as 15-S-ethoxylates); wettability alteration was qualitatively reduced asthe number of EO groups increased. Fig. 9 shows the contactangles on aged calcite plates for the surfactants in the homologousseries of 15-S-ethoxylates. Again, the surface was more water-wetfor surfactants with a smaller number of EO groups. In addition,the IFT of these surfactant solutions increased as the number ofEO groups increased for both of the homologous series (Table 1).The NP-ethoxylates and 15-S-ethoxylates used could alter thewettability to intermediate-wet only.

Anionic Surfactants. The two anionic surfactants tried atdilute concentration (0.1 wt%), AV-70 and AV-150, altered thewettability to intermediate-wet (Fig. 10). The wettability usingAV-150 looked more water-wet than that of AV-70.

Cationic Surfactants. DTAB was mixed with injection brineto make a 1 wt% solution. The wettability alteration observedwith this was from initial oil-wet to final intermediate-wet, asshown in Fig. 11. CTAB is not aqueous-stable at 100�C and wasnot used. Arquad C-50 and T-50 showed no wettability alterationon the aged calcite plate (Fig. 11).

Dual-Surfactant Systems. Among the dual-surfactant systemstested in this research, two of them appeared promising for wett-ability alteration. These two are 0.2 wt% NPþ 0.1 wt% DTABand 0.2 wt% 15-S-ethoxylateþ 0.1 wt% DTAB, which showedwettability alteration from initial oil-wet to final intermediate-wet(Fig. 12). Both of these surfactant systems were used further forspontaneous-imbibition experiments.

Spontaneous Imbibition. Spontaneous imbibition is the secondstep to confirm the effectiveness of wettability-altering surfac-tants. Table 3 lists core properties, surfactants, and final recoveryby spontaneous imbibition. These surfactants looked promising in

0.2 wt% NP-10 in injection brine 0.2 wt% NP-30 in injection brine

0.2 wt% NP-50 in injection brine 0.2 wt% NP-70 in injection brine

Fig. 8—Contact angle on calcite plates with 0.2 wt% NP-ethoxylates.

650 August 2013 SPE Journal

0.2 wt% 15-S-15 in injection brine 0.2 wt% 15-S-20 in injection brine

0.2 wt% 15-S-30 in injection brine 0.2 wt% 15-S-40 in injection brine

Fig. 9—Contact angle on calcite plates with 0.2 wt% 15-S-ethoxylates.

0.1 wt% AV-70 in injection brine 0.1 wt% AV-150 in injection brine

(a) (b)

Fig. 10—(a): 0.1 wt% AV-70 in injection brine. (b): 0.1 wt% AV-150 in injection brine.

1 wt% DTAB in injection brine 1 wt% C-50 in injection brine 1 wt% T-50 in injection brine

Fig. 11—Contact angle on calcite plates with cationic surfactants.

August 2013 SPE Journal 651

the calcite-plate experiments. Because these experiments takemore than a month to complete, only a limited number of experi-ments were conducted. These spontaneous imbibitions were con-ducted at 92�C.

Experiments 1 through 4 show that the imbibition oil recoveryfrom restored-state core plugs in the presence of either formationbrine or injection brine is low (10–15%). The oil imbibing out ofthe core sticks to the core surface in the form of films, suggestingthat these cores are mixed-wet. Because most of the single non-ionic surfactants were aqueous-unstable at 100�C, only TDA30EO was used for imbibition experiment. It should be noted thatthe wettability alteration on calcite plates at low concentrations ofTDA 30EO (0.05 wt%) was better than that with nonionic surfac-tants. Even though the oil imbibing out beaded up on the top sur-face of the core plug (also on the sides initially), suggestingwettability alteration, only 20% of OOIP was recovered in thisexperiment. Among the cationic surfactants, only DTAB (1 wt%)was used for imbibition experiment, and it recovered 72% of

OOIP (after brine imbibitions). Other researchers (Standnes andAustad 2000) have used this surfactant extensively.

Because one of the goals of this study was to find surfactantsystems that can be used at dilute concentrations, the emphasiswas on dual-surfactant systems in the imbibition experiments.During the contact-angle experiments, the greatest wettabilityalteration was observed for the lowest member of a homologousseries of nonionic surfactants. Therefore, among the dual-surfac-tant systems, systems made with NP-10 and 15-S-15 were used.In Experiment 5, 0.2 wt% NP-10þ 0.2 wt% DTAB recovered asmuch as 73.7% of OOIP by spontaneous imbibition. This experi-ment was repeated again with a different core plug to verify its ef-ficacy and again the recovery was 81.4% of OOIP (Experiment6). We decided to halve the amount of surfactant but 0.1 wt% NP-10þ 0.1 wt% DTAB was aqueous-unstable at 100�C; thus, weconducted the experiment using 0.1 wt% NP-10þ 0.2 wt%DTAB. The recovery was approximately 73.4% of OOIP (Experi-ment 7). After the success of dual-surfactant system consisting ofNP-10, we used systems made of higher members of the same ho-mologous series, NP-30 (0.2 wt% NP-30þ 0.2 wt% DTAB) andNP-50 (0.2 wt% NP-50þ 0.2 wt% DTAB), for imbibition experi-ments (Experiments 8 and 9). Similar to the trend observed duringcalcite-plate experiments, the recovery here decreased for highermembers of the homologous series. Furthermore, 0.2 wt% 15-S-15þ 0.2 wt% DTAB recovered only approximately 9.6% ofOOIP (Experiment 10).

These results show that (1) some of the surfactants that couldalter wettability on calcite-plate experiments do not recover muchoil in spontaneous imbibition and thus calcite-plate experimentsshould be used only as a screening step; (2) spontaneous-imbibi-tion experiments are more definitive and more realistic; and (3)oil recovery by imbibition decreases as the number of ethoxygroups increases for the same homologous series of nonionic sur-factants (which were used to make the dual-surfactant systems).

Fig. 13 shows the imbibition oil recovery as a function of timefor some of the dual-surfactant systems and for 1 wt% DTAB

0.2 wt% 15-S+0.2 wt% DTAB in injection brine 0.2 wt% NP+0.2 wt% DTAB in injection brine

Fig. 12—Contact angle on calcite plates with dual surfactants.

TABLE 3—SPONTANEOUS-IMBIBITION TESTS WITH AND WITHOUT SURFACTANTS

Expt.

No.

Length

(in.)

Core Plug Properties

Surfactant/Brine

Recovery

(% OOIP)Dia. (in.) / (%) k (md) Soi

1 1.97 1.46 26.8 338.2 0.61 Formation Brine 10.2

2 1.49 1.48 24.8 775 0.69 Formation Brine 13.9

3 1.35 1.48 25.4 660.6 0.71 Formation Brine 14.6

4 1.87 1.46 25.1 88.3 0.73 Injection Brine 9.6%

5 1.97 1.46 26.8 338.2 0.55 0.2 wt% NP-10þ0.2 wt% DTAB 73.7

6 1.49 1.48 24.8 775 0.59 0.2 wt% NP-10þ0.2 wt% DTAB 81.4

7 1.35 1.48 25.4 660.6 0.61 0.1 wt% NP-10þ0.2 wt% DTAB 73.4

8 1.63 1.50 25.6 343.9 0.74 0.2 wt% NP-30þ0.2 wt% DTAB 5.7

9 1.52 1.50 23.1 664 0.77 0.2 wt% NP-50þ0.2 wt% DTAB 13.3

10 1.87 1.46 25.1 88.3 0.73 0.2 wt% 15S15þ0.2 wt% DTAB 9.6

11 1.59 1.47 24.3 59.4 0.68 0.05 wt% TDA 30EO 20.5

12 1.98 1.47 23.7 42.7 0.73 1 wt% DTAB 72

00

0.2

0.4

0.6

Oil

reco

very

(fr

actio

n of

OIP

)

0.8

1

10 20 30

Expt. #5 Expt. #6 Expt. #7 Expt. #10 Expt. #12

Time (days)40 50 60

Fig. 13—Oil recovery during imbibition vs. time.

652 August 2013 SPE Journal

(Experiments 5 through 7, 10, and 12). Except for Experiment 12,the recovery had almost reached the maximum within a month.These core samples varied significantly in permeability and some-what in length and porosity. We needed a scaling for the variationin core properties to compare these results. Mattax and Kyte(1962) have proposed the following equation for scaling of brineimbibition for different oil/brine/rock systems:

td ¼ Ct

ffiffiffiffik

/

srlw

1

L2; ð1Þ

where td is dimensionless time, C is the unit conversion factor(C¼ 0.018849), t is the imbibition time in minutes, k is permeabil-ity in millidarcies, / is fractional porosity, r is the IFT in dynes/centimeter, lw is water viscosity in cp, and L is a characteristiclength of the core plug. This equation assumes constant water-wetwettability, constant IFT, and similar oil/water viscosity (Ma andMorrow 1993), which is not the case here. The dimensionless timetakes into account the variation in core size, permeability, IFT, andviscosity between experiments. This scaling will not be applicablefor our imbibition experiments, where the composition of the brinechanges as well as IFT and wettability.

Despite these differences, we used this dimensionless time toscale the variations in permeability, length, and porosity. The twoexperiments with 0.2 wt% NP-10þ 0.2 wt% DTAB (performedwith two separate core plugs) have similar recovery but differentrecovery rates. When the recovery is plotted against the dimen-sionless time, both the recovery curves look similar (as shown inFig. 14). The final oil recovery with 0.1 wt% NP-10þ 0.2 wt%DTAB is similar to 0.2 wt% NP-10þ 0.2 wt% DTAB, but the re-covery rates in dimensionless time are quite different. DTAB (1wt%) also performs similarlly to the dual-surfactant system 0.2wt% NPþ 0.2 wt% DTAB, as is evident from the recovery versus(vs.) dimensionless time plot.

Coreflood. Because the dual-surfactant system 0.2 wt% NPþ 0.2wt% DTAB gave large spontaneous imbibition, it was used for

the modified waterflood. This was the best system (dilute concen-tration, high imbibition recovery, and high recovery rate duringimbibition) among those tested in this study. During the water-flood and the modified waterflood, the core was first flooded withbrine/surfactant at 0.06 cm3/min (interstitial velocity¼ 1 ft/D) for5 PV. Then the flow rate was stepped up to 1 cm3/min (interstitialvelocity¼ 17 ft/D), and 5 PV of injection brine was floodedthrough the core. Finally, the flow rate was stepped up to 10 cm3/min (interstitial velocity¼ 167 ft/D), and an additional 10 PV ofinjection brine was injected through the core. As mentionedbefore, this was done to observe the rate dependence of residual-oil saturation for these carbonate cores. Table 4 summarizes theproperties of the core composite. The coreflood experiments wereconducted at 95�C.

Table 5 summarizes the waterflood and surfactant-enhancedmodified-waterflood results. For the first 5 PV injected at 1 ft/D,the cumulative oil recovery was higher for the modified water-flood (40% OOIP) compared with that of the waterflood (29%OOIP). These floods were conducted at typical field flow rates.Fig. 15 compares the cumulative oil recovery of the waterflood tothat of the modified waterflood for the first 5 PV. Oil produced af-ter breakthrough in the surfactant-modified waterflood wasapproximately 25% of OOIP compared with approximately 7% inthe waterflood. Fig. 16 shows the pressure drop for the two water-floods. The maximum pressure drop is less than 2 psi/ft in bothcases, a reasonable value for fields. The pressure drop was slightlylower in the case of the surfactant-modified waterflood. Manywaterfloods in fields are limited by the injection of 3 to 5 PVthroughput. The increase in oil recovery from 29 to 40% in thefirst 5 PV at the field rate is significant. By addition of a dilutewettability-altering surfactant, the secondary waterflood oil recov-ery can be improved. There is no polymer, alkali, or cosolvent inthis chemical flood.

After the 5-PV throughput, we increased the flow rates by 10and 100 times the typical field rates. These results are not directlyapplicable to the field conditions but show the sensitivity of theremaining oil saturation to flow rate. The second 5 PV of water-flooding occurred at 17 ft/D (1 cm3/min), an artificially high ve-locity. In the waterflood, 25% OOIP was recovered; in themodified waterflood, 15% OOIP was recovered. The additionaloil recovery is caused by both the reduction in capillary end effect(Mohanty and Miller 1991) and the dependence of remaining oil

. . . . . . . . . . . . . . . . . . . . . . . . . .

00

0.2

0.4

0.6O

il re

cove

ry (

frac

tion

of O

IP)

0.8

1

50 100 150

Expt. #5 Expt. #6 Expt. #7 Expt. #10 Expt. #12td (dimensionless time)

200 250

Fig. 14—Oil recovery during imbibition vs. dimensionless time.

TABLE 4—CORE-COMPOSITE PROPERTIES

Core Composite (by joining 3 core plugs)

Length (in.) 6.0

Diameter (in.) 1.5

Porosity (%) 24.5

Air permeability (md) 120.7

Brine permeability (md) 85.0

Oil relative permeability at Soi (basis: brine permeability) 0.61

TABLE 5—SUMMARY OF COREFLOOD RESULTS

Waterflood Modified Waterflood

Soi 0.71 0.70

Surfactant injected@0.06 cm3/min (PV) None 1.2

Brine injected@0.06 cm3/min (PV) 5 3.8

Oil recovery (%OOIP) in first 5 PV 29% 40%

Brine injected@1 cm3/min (PV) 5 5

Oil recovery (%OOIP) in second 5 PV 25% 15%

Brine injected@10 cm3/min (PV) 10 10

Oil recovery (%OOIP) in last 10 PV 3% 6%

Brine endpoint permeability at Sorw (md) 0.39 0.45

Total oil recovery (%OOIP) 57% 61%

August 2013 SPE Journal 653

saturation on the capillary number at low capillary number regimefor carbonate rocks (Kamath et al. 2001). In the last 10-PV injec-tion at 167 ft/D (10 cm3/min), 3–6% of OOIP was recovered.Most of the recoverable oil was recaptured before the injection ofthe flow rate. The endpoint brine permeability was calculated atthe end of the highest rate flood. Because the total oil recoverywas similar for both the floods, the endpoint brine permeabilitywas also similar.

Fig. 17 shows the effluent surfactant concentration in themodified waterflood; both surfactants were produced together.The adsorption (or retention) of surfactants was calculated by ma-terial balance. The adsorption was 0.24 mg/g of rock for surfac-tant NP-10 and 0.2 mg/g of rock for surfactant DTAB. Thecationic surfactants adsorb less than the nonionic surfactant on thecarbonate rock. These numbers can be used in estimating thepropagation of surfactants in the field. This study shows that sec-ondary waterflooding with a dilute wettability-altering surfactantcan improve the oil-recovery rate significantly at the laboratoryscale. The pressure drop in the modified waterflood is similar tothat of the waterflood. One would expect that the stability of themodified waterflood on a large scale would be similar to that ofthe waterflood, but further research should be conducted to verifythis conjecture.

Conclusions

• As the number of EO groups (in the same homologous series ofnonionic surfactants) increases, the water-wetness of the calciteplate decreases.

• Dual-surfactant systems are suitable for wettability alteration inhigh-temperature, high-salinity reservoirs because of aqueousstability.

• Mixture of cationic and nonionic surfactants in dilute concen-tration can recover approximately 70 to 80% of the oil by spon-taneous imbibition.

• Secondary waterflooding with a dilute wettability-altering sur-factant can improve the oil recovery significantly over that of awaterflood in the laboratory setting. The first-5-PV oil recoveryincreased from 29% OOIP to 40% OOIP.

Acknowledgments

This work was partially supported by grants from Qatar NationalResearch Foundation, American Chemical Society–PetroleumResearch Fund, and the Chemical EOR joint industry project ofthe Center for Petroleum and Geosystems Engineering.

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0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 4.50 5.000

0.1

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0.5

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ssur

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psi)

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Fig. 16—Pressure drop during waterflood and modified water-flood.

0 1 2 3

DTAB NP-10

4 50

200

400

600

Con

c. (

ppm

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PV injected

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Gaurav Sharma is currently a geoscientist with Baker Hughes.Sharma’s research interests include reservoir characterization,geophysical monitoring, and enhanced oil recovery (EOR). Heholds an MS degree in petroleum engineering from the Univer-sity of Texas at Austin and a BS degree in chemical engineer-ing from the Indian Institute of Technology, Kanpur.

Kishore K. Mohanty earned a BS degree from the Indian Insti-tute of Technology, Kanpur, and a PhD degree from the Uni-versity of Minnesota, both in chemical engineering. He iscurrently a professor of petroleum engineering at the Universityof Texas at Austin. Mohanty’s research is directed at EOR, for-mation evaluation, improved fracturing, and nanotechnol-ogy. Mohanty was the Executive Editor of the SPE Journal from2001 to 2003. He received the Pioneer Award during the SPEIOR Symposium in 2008.

August 2013 SPE Journal 655