Effect of surfactants on wettability of near-wellbore regions of gas reservoirs

ngineering 52 (2006) 227–236www.elsevier.com/locate/petrol

Journal of Petroleum Science and E

Effect of surfactants on wettability of near-wellbore regions ofgas reservoirs

B. Adibhatla a, K.K. Mohanty a,⁎, P. Berger b, C. Lee b

a Chemical Engineering, University of Houston, 4800 Calhoun Road, Houston, TX 77204-4004, United Statesb Oil Chem Technologies, United States

Received 21 June 2004; accepted 7 March 2006

Abstract

The flow of gas in tight, low-pressure gas wells can be partially blocked by the water saturation build-up near the hydraulicfracture face if the drawdown pressure does not exceed the capillary pressure. To increase the productivity, the water saturation maybe reduced by alteration of the near-wellbore wettability from water-wet conditions to intermediate-wet conditions. Manysurfactants have been identified which change the wettability of carbonate and sandstone rocks from water-wet to intermediate-wetin water–air–rock systems. Among fluorosilanes, as the number of fluoro groups increases, rocks become less water-wet. One dayof aging period and 1 wt.% concentration appear to be sufficient for altering wettability. Interaction with field brine plays a crucialrole in selection of appropriate surfactants. The increase in gas relative permeability due to the change in wettability is a function ofthe pressure gradient.© 2006 Elsevier B.V. All rights reserved.

Keywords: Wettability; Contact angle; Gas reservoir; Surfactant

1. Introduction

Many gas reservoirs have low permeability. There-fore, they are hydraulically fractured. Brine (withviscosifiers) has been used traditionally as the carrierfluid for proppants in hydraulic fracturing treatmentsbecause of its cost and safety compared to hydrocarbon-based fluids. During fracturing, some of this carrier fluidleaks into the reservoir. Typical gas reservoirs are water-wet and a part of the leak-off brine is retained near thefracture face because of the positive capillary pressure inwater-wet porous media. If the drawdown pressure ishigher than the capillary pressure, the water retention is

⁎ Corresponding author. Tel.: +1 713 743 4331; fax: +1 713 7434331.

E-mail address: [email protected] (K.K. Mohanty).

0920-4105/$ - see front matter © 2006 Elsevier B.V. All rights reserved.doi:10.1016/j.petrol.2006.03.026

small (Van Poolen, 1957; Abrams and Vinegar, 1985).Otherwise, this retained brine can block the flow of gasand impair productivity. If the reservoir produces smallamount of water, water can also build up near thefracture face. The impact of water retention near thefracture face on gas production has been studied earlier(Tannich, 1975; Holditch, 1979).

In a gas well, the capillary pressure (Pc) is thepressure jump across the water–gas menisci. TheYoung–Laplace equation gives the relationship betweenwate–gas interfacial tension (γ), contact angle (θ) andmean radius (rm) of curvature of the interface as follows:

Pc ¼ 2gcoshrm

: ð1Þ

If the contact angle can be increased, then the capillarypressure can be decreased and hence the brine saturation

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http://dx.doi.org/10.1016/j.petrol.2006.03.026

Fig. 1. Schematic diagram of water saturation and capillary end effect near a fracture face (after Mahadevan and Sharma, 2003).

228 B. Adibhatla et al. / Journal of Petroleum Science and Engineering 52 (2006) 227–236

buildup near the fracture face can be lowered. An earlierstudy (Penny et al., 1983) discussed the effects ofcapillary pressure, wettability, pore radius and interfa-cial tension in gas reservoirs. It was concluded that thebest way of productivity recovery would be bywettability alteration. Water buildup has also beenreduced (in a laboratory study) through evaporation byadding volatile solvents like methanol (Mahadevan andSharma, 2003). In this study, as well, it was found thatwettability change improves recovery of the load water.Though methanol leads to load water recovery faster, itcannot mitigate the water accumulation near the fracturedue to the mobile water from the reservoir. An effectiveway to reduce the water saturation near the fracture faceor wellbore would be to change the wettability andhence reduce the water saturation near the fracture faceor wellbore. Fig. 1 depicts the plausible saturationprofile near the wellbore before the treatment withsurfactants.

Importance of wettability alteration has been longrecognized by Buckley and Leverett (1942). Manyresearchers (Willhite, 1986) have studied the effect of

Table 1Surfactants used in the study

Symbol Formula

A 3-(Heptafluoroisopropoxy)proplytrB 1H,1H,2H,2H-perfluourooctylmethC 1H,1H,2H,2H-perfluourooctyltriethD 1H,1H,2H,2H-perfluourodecyltrietE 1H,1H,2H,2H-perfluourododecyltrOSA Oil-soluble amineDTAB Dodecyl trimethyl ammonium broForafac Fluorinated surfactantFluoroPel Fluorinated polymerWSA Water-soluble amine

oil–water wettability on capillary pressure, relativepermeability, residual phase saturation, displacementefficiency, etc. The oil–water wettability of a rockdepends on rock mineralogy, oil and brine compositions(Yan et al., 1997). The zeta potential of minerals and oilaffect the electrostatic interaction (Hirasaki, 1991). Thezeta potentials depend on the brine pH. Oil asphalteneand resin compositions control its interfacial activity.The acid and base numbers also influence the wettability(Buckley, 2001). Core wettability is traditionallymeasured by Amott or USBM wettability index.Morrow and Mason (2001) have reviewed the relationbetween the spontaneous imbibition of brine and corewettability. Most of the research on wettability dealswith oil–water systems.

Penny et al. (1983) have studied gas–water–rocksystems. Although the wettability alteration was a sideeffect of fracturing, it was observed that surfactant basedfracturing fluid increased the productivity, sometimes2–3 times more than the conventionally fractured wells.Li and Firoozabadi (2000) and Tang and Firoozabadi(2002) have used a 3M-manufactured surfactant FC-722

Solvent

iethoxysilane Ethanolyldimethoxysilane Ethanoloxysilane Ethanolhoxysilane Ethanoliethoxysilane Ethanol

Ethanol/watermide Water

WaterFluorinated solventWater

Table 2Field brine composition

Salt Mol. wt. mM/L g/L

CaCl2·2H2O 147.05 20.01 2.94MgCl2·2H2O 203.33 9.99 2.03KCl 74.57 0 0NaCl 58.45 99.49 5.81Fe(NH4)2(SO4)2·6H2O 392.16 0.018 0.007Na2SO4 142.05 1.67 0.24

Table 3Contact angle on calcite surface after 1-day aging and 6-day aging

Surfactant Contact angle (°)

Beforetreatment

After treatment(1-day aging)

After treatment(6-day aging)

A 33.7 64.8 69.0B 32.6 50.6 49.5C 34.0 74.2 73.0D 32.7 111.0 110.0E 33.2 114.4 115.0FluoroPel 33.2 118.0 –

229B. Adibhatla et al. / Journal of Petroleum Science and Engineering 52 (2006) 227–236

and FC-759 in their wettability alteration for applicationin gas-condensate reservoirs. They found that applica-tion of these chemicals resulted in intermediate-wetconditions, which led to considerable changes inimbibition rates and gas relative permeability. Currently,3M does not produce these chemicals anymore forenvironmental reasons.

The goal of this work is to find cost-effectivesurfactants to alter gas well wettability from water-wetto intermediate-wet. We have studied the change inwettability caused by several surface-active agents. Ourmethodology is described in the next section. The resultsare discussed in the following section. The last sectionsummarizes our observations.

2. Experimental procedure

The laboratory studies were conducted in two scales.First, experiments were done at a mineral slab-scale,where carbonate surfaces (calcite and marble) and silicasurfaces (mica and silica wafer) were treated withsurfactant solutions to study their effect on wettability.Second, experiments were done at a core-scale (withlimestone cores) to study the effect of surfactants onrelative permeability and spontaneous imbibition.

Fig. 2. Contact angle change with time; equilibrium contact angle isapproached in a few minutes.

2.1. Fluids used

The surfactants used for this study are listed inTable 1. Five fluorosilanes were studied; they havebeen named A through E. Two amines (from OilChem. Technologies) called OSA (oil-soluble amine)and WSA (water-soluble amine) were tested. Acationic surfactant (DTAB), a fluorinated surfactant(Forafac), and a fluorinated polymer (FluoroPel) werealso tested. The fluorosilanes and OSA are insoluble inwater and their solution is made in ethanol. A fieldbrine of composition listed in Table 2 is used in sometests. A synthetic brine of 0.1 N NaCl prepared indistilled water is used as the liquid phase in most ofthe contact angle measurements. The specific gravityof the brine was 1.01. The experiments wereconducted at ambient temperature conditions whichvaried from 22–24 °C. Air was used as the gas phaseand the plates were dried using dry air.

2.2. Wettability measurements

The effect of surfactant solution on wettability wasdetermined by contact angle measurements. A comput-er-aided digital goniometer is used for determination ofthe advancing and the equilibrium contact angles onplain surfaces. The following procedure is used for thecontact angle determination.

Table 4Contact angle on mica surface after 1-day aging and differentconcentrations


Beforetreatment

After treatment(4 wt.% ethanol)

After treatment(1 wt.% ethanol)

A 17.0 65.5B 16.2 67.7C 16.4 94.0 65.0D 17.2 100.0 120.0E 16.2 115.0 112.0

Fig. 4. Surfaces before treatment with surfactants (a) calcite and (b) mica.

Fig. 3. Possible mechanism of wettability alteration for mica and calcite surfaces.


Carbonate surfaces of calcite and marble were madesmooth by grinding the slabs on a diamond plate. Thisprocedure also exposed an uncontaminated layer ofmineral at the surface. The mineral slabs wereequilibrated with synthetic brine (0.1 N NaCl brine)for a period of 1 day, and then dried before measuringthe initial contact angle between untreated surfaces,water, and air. For sandstone samples, a fresh micasurface (nanometer smooth) was used as the modelsurface and initial contact angle was measured follow-ing aging in synthetic brine. Mica is used because itbehaved similar to silicon wafers in our initial experi-ments and freshly cleaved mica is molecularly smooth.

Fig. 5. Contact angle on calcite surface after

After measuring the initial contact angle, the slabswere immersed in a surfactant solution (of chosenconcentration) for a period of 1 day. The solvents for thesurfactant solutions are listed in Table 1. They wereremoved from the solution and air-dried. The contactangle between the treated surface, water, and air wasmeasured again.

The slabs were immersed back in the surfactantsolution to test for additional deposition and effect ofaging. The treated plates were placed in a synthetic brineand a field brine to study the stability of the depositedlayer in harsh conditions. Fresh mineral surfaces werealso treated with surfactant solutions with 1:1 ratio of

treatment with 4 wt.% (a) D and (b) E.

Fig. 6. Contact angle on mica surface after treatment with 4 wt.% surfactants (a) D and (b) E.

Fig. 7. Contact angle on calcite surface after treatment with 1 wt.% surfactant E (a) after 1-day and (b) after 6-day aging.

Table 5Stability of adsorbed film in field brine calcite surface and effect ofconcentration of surfactants


6-Day aging(4 wt.% ethanol)

Additional 1 weekin field brine

1 wt.% inethanol

A 69.0B 49.5C 73.0 72.5 78.0D 110 111.2 112.8E 115 114.6 112.0


field brine and ethanol to see the effect of field brine oncontact angle.

2.3. Imbibition studies

From studies at the slab-scale, two good surfactants,surfactant D and FloroPel, were chosen for furtherinvestigation on a larger scale. These surfactants wereused to study the change in wettability on a core scale.The following procedure was used to study the impactof wettability alteration in a core scale.

The carbonate cores were vacuum dried and thenfully saturated with the synthetic brine (0.1 N NaCl).The brine permeability was measured. The cores werethen flushed with humidified N2 gas to a residual brinesaturation at a pressure gradient of 10–14 psi/ft. The gaspermeability at this residual saturation was measured.

The cores were then flooded from the opposite endwith 6 PVof ethanol to remove any residual brine. Thecore was then flooded for 3 PV with surfactant solutionsand aged at room temperature for a period of 24 h. Theaged core was then again flooded with 6 PV of ethanolfollowed by 6 PV of synthetic brine to remove non-adsorbed surfactants and ethanol, respectively. The corewas then flooded with humidified N2 gas to a residualbrine saturation at a pressure gradient of 10–14 psi/ft.

The core was then flooded with dry N2 gas at a highpressure gradient of 100 psi/ft. It was then taken out of

the core holder and immersed in brine. The spontaneousimbibition of brine was monitored. A reference core wasalso used to study brine imbibition without surfactanttreatment. After the spontaneous imbibition the coreswere flooded again with brine under vacuum to 100%brine saturation. They were then gas-flooded withhumidified N2 to residual brine saturation at a pressuregradient of 10–14 psi/ft to obtain the gas permeability atthe residual saturation.

3. Results and discussion

In all cases of contact angle measurement, a highinitial contact angle was observed which reduced to asmaller equilibrium contact angle in a few minutes. Fig.2 shows a typical contact angle change with time (for

Table 6Effect of preparation of surfactant in 1:3 ethanol/field brine at 1 wt.%

Surfactant Contact angle (calcite) Contact angle (mica)

In ethanol In ethanol+field brine

In ethanol In ethanol+field brine

C 78.0 26.6 65.0 18.0D 112.8 27.2 120.0 18.4E 112.0 26 112.0 16.7


surfactant B) before and after the surfactant treatment.All the measurements and the effectiveness of surfac-tants are reported here with respect to the finalequilibrium contact angle.

The change in contact angle on the calcite surfacedue to treatment with fluorosilane surfactants andFluoroPel is shown in Table 3. The contact anglemodification for the mica surface is shown in Table 4.FluoroPel did not change the contact angle on mica. Thesurfactant concentration was 4 wt.% in the treatmentsused in these experiments. The surfactants A–E aremethoxy or ethoxy silanes. The mechanism forwettability alteration for mica samples could be bybonding of the silane groups to the (Si-OH) group insilica/mica surfaces, with the fluorine backbone exposedout of the surface; the fluorine backbone provides thewater repellency to the surface. The mechanism ofwettability alteration in calcite is not clearly understood.According to Somasundaran and Agar (1967), thecalcite surface at neutral pH has an excess of thepositive Ca2+, CaHCO3

+, and CaOH+ species. The silanegroups may interact with the Ca-OH+ group in a mannersimilar to the Si-OH group in silica. This may be thereason for wettability alteration on calcite surface,though more studies on this matter should be conductedto understand the mechanism of wettability alteration.The possible mechanism is illustrated in Fig. 3.

Fig. 4 shows the brine drops on untreated calcite andmica; both these surfaces are water-wet. Fig. 5 showsthe brine drops on calcite treated with surfactants D and

Fig. 8. Contact angle on calcite surface after treatment with surfac

E. Fig. 6 shows the brine drops on mica treated withsurfactants D and E. It can be seen (from Tables 3, 4 andFigs. 5, 6) that the surfactants C, D and E make both themica and the calcite surfaces intermediate-wet. As thenumber of fluoro groups increases in the surfactant, theextent of water repellency increases. The accuracy ofmeasurement is about 1°, as shown by the secondcolumn (before treatment) in Tables 3 and 4.

Table 3 also shows the effect of aging time on contactangles on treated calcite. Fig. 7 shows the shapes ofwater drops. There is little difference between 1-dayaging and 6-day aging contact angles. 1-day agingperiod is sufficient for the fluorosilane molecules tobond to the surface, rendering it intermediate-wet. Theweight of the slabs was also monitored and there was nochange in the weight between 1-day and 6-day aging.This suggests no further adsorption of surfactant. Asample treated with a 4 wt.% surfactant C in ethanol wastested for contact angle after 1 yr, and the contact anglewas still in the intermediate-wet region. The treatmentwas hydrolytically stable for at least a period of 1 yr.Samples treated with surfactants D and E at the sameconcentration formed a gel after nearly 7 months,probably due to hydrolysis of silanol bonds.

The stability of the adsorbed fluorosilane surfactantsin field brine was tested by immersing the slabs in thefield brine for a week after the 6-day aging in surfactantsolution. The contact angles after soaking in field brineis not very different from those before, as shown inTable 5. It can be concluded that once the surfactant hasbeen deposited, it is stable in the field brine conditionsfor a week.

The effect of surfactant concentration on thewettability alteration was studied for fluorosilanes C,D, and E (those successful in making surfacesintermediate-wet). The contact angles for 1 wt.%surfactant are compared with those for 4 wt.% inTable 4 for mica and in Table 5 for calcite slabs. It can beseen that a 1 wt.% solution is as effective in wettabilityalteration as 4 wt.% for surfactants D and E.

tant using field brine. (a) Surfactant E, and (b) surfactant D.

Table 7OSA surfactant contact angle on calcite with number of washes

Number of washes Contact angle (°)

0 32.05 63.010 82.020 99.030 108.0


Table 6 gives the contact angle for the fluorosilanesprepared in a 25 wt.% ethanol in field brine solution tostudy the effect of field brine during wettabilityalteration. It was observed that surfactant E formed agel in these conditions, and surfactants C and D formedsuspensions. The calcite and mica plates were dipped inthese solutions and left for aging for a period of 1 day.Fig. 8 shows water drops on the calcite slabs treated withsurfactants E and D in the presence of field brine. Gelformation sequesters most of the surfactant E, leavinglittle surfactant to change wettability, as shown in Fig.8a. In case of surfactant D, a white precipitate formedand covered a part of the mineral surface. Fig. 8b showsthe contact angle at a particular location where there wasa thin layer of white precipitate; the contact angle was120°. But in regions without the precipitate, the contactangle was found to be unaltered (27.2°). The precipitateforms from the hydrolysis of silane in water, which arehydrophobic in nature. These precipitates are not

Fig. 9. OSA surfactant aged calcite plate. (a) Initial contact angle and the equilwashes, initial angle and the equilibrium angle after 2 min.

desirable because they can plug the porous mediumduring the treatment.

Little is known on the hydrolytic stability of silanesurfactants in aqueous solutions or the properties of thedegraded products (Jaeger and Ward, 1982). Grüningand Koerner (1989) have shown that the hydrolysis oftrisiloxanes proceeds very slowly in the pH range of 7–9. Retter et al. (1998) found that for siloxane alkylammonium bromides, hydrolysis decreases with in-crease in the chain length and increases with increasedbranching. They also found that the products ofhydrolysis catalyze the process. More thorough studyof the hydrolytic stability of these surfactants is neededfor long-term field applications.

Table 7 shows contact angles for 0.05 wt.% OSAsurfactant treated calcite surface. The contact angle was32° after the treatment (Fig. 9a). The surface waswashed with water several times and the contact anglewas measured after each wash. It can be seen in Table 7that the contact angle increases with each wash and thesurface becomes intermediate-wet (Fig. 9b). A possiblemechanism for the above behavior is sketched in Fig.10. Anionic surfactants can adsorb on calcite surfaces asshown in Fig. 10a, as described by Somasundaran andKrishnakumar (1997). The 0.05 wt.% OSA used in thisstudy is 10 times its CMC value. Hence, a bilayer canform. The contact angle of a water drop on a bilayer issmall (Fig. 10b) because the ionic groups are exposed. If

ibrium contact angle (drop spreads in <10 s). (b) Contact angles after 10

Fig. 10. Possible mechanisms for intermediate-wet nature of surface after water washing for surfactant OSA. (a) The surfactant arrangement as bilayerafter treatment and air drying, (b) water drop on bilayer, diffusion of surfactants into water droplet because of weak chain–chain interactions, (c)structure of surface after many washes, and the contact angle in the presence of a strongly bound monolayer.

Table 9Properties of the carbonate cores used for spontaneous imbibition

Core 2 7 9

Surfactant None FluoroPel DPermeability k (md) 120 117 119Length (cm) 14.9 14.5 15.2


the chain–chain interactions are not strong, thenrepeated washes remove the second layer of thesurfactants. The bilayer becomes monolayer andhydrocarbon chains are exposed on the monolayer,which make the surface hydrophobic (Fig. 10c).

OSA surfactant does not change the wettability ofmica. WSA, DTAB and Forafac change the wettabilityof mica, but not of calcite. Presumably, these surfactantsare cationic and adsorb on mica. Table 8 shows thewettability alteration on mica surface.

Table 9 gives the physical properties of the carbonatecores used for imbibition studies. It also gives the valuesof relative permeability of gas at residual brinesaturation before and after treatment along with thesaturations. It can be seen that in the case of FluoroPel,the residual brine saturation was altered considerably(∼25%) and the gas relative permeability increasedalmost 160 times after the treatment. A drop of brine

Table 8Effect of other surfactants on wettability alteration on mica plate


Before treatment After treatment

WSA 17.0 90.0DTAB 16.2 63.0Forafac 16.4 63.0

was place on top of the core after treatment withFluoroPel and it was found not to imbibe into the core,and give a surface contact angle of about 113°,indicating a change in wettability of the surface. In thecase of surfactant D, the residual brine saturationdecreased by ∼10% and the gas relative permeabilityincreased by a factor of ∼30. These are significant, butlower than that of FluoroPel. It was noticed that theFloroPel-treated core was intermediate-wet on both flatsides, but the surfactant D-treated core was intermedi-ate-wet only on the surfactant injected flat side. There is

Diameter (cm) 3.82 3.82 3.82Porosity 22.5 22.2 22.6Residual brine saturation beforetreatment (%)

65 67.5 65

Gas permeability at residualsaturation (md)

0.21 0.13 0.25

Residual brine saturation aftertreatment (%)

– 42.5 56.25

Gas permeability at residualsaturation (md)

– 20.5 7.97

Fig. 11. Spontaneous imbibition in carbonate cores at roomtemperature for case of untreated core, core treated with surfactant Dand core treated with FloroPel, Swi=0%, and k=120 md.


a difference in the method of wettability alterationbetween the slab-scale and the core-scale experiments.In slab experiments, the slab was dried after thetreatment. Whereas in the case of core experiments thecores were all flushed with ethanol and brine after thetreatment of the surface. The core flushing sequence canbe improved in the future to achieve more uniformwettability alteration.

Fig. 11 shows the amount of brine imbibedspontaneously as a function of time. The brineimbibition was 67.5% OGIP (original gas in place) inabout 20 h for the untreated core. For the core treatedwith surfactant D, the brine imbibition was about 40%OGIP. For the core treated with FloroPel, it reduced to7.5% OGIP. FloroPel succeeded in changing the

Fig. 12. Residual permeability of gas for treated and untrea

wettability of the core and increasing gas permeabilityat the residual brine saturation.

Two cores, one untreated and the other treated withFluoroPel, were then used to study the gas relativepermeability at different residual water saturations. Thecores were initially 100% water saturated. Then, theywere gas flooded with humidified N2 gas at differentpressure drops. The pressure gradients used were 14 psi/ft, 32 psi/ft, 56 psi/ft, 120 psi/ft and 200 psi/ft. At eachcondition, the core was allowed to reach an equilibrium,which was noted by no additional production of water.The gas relative permeability was measured and theresidual water saturation was back calculated bymonitoring the production of water. The results of theexperiment are shown in Fig. 12. Residual permeabilityis the effective gas permeability at the residual brinesaturation. It can be seen that for the same pressuregradient, the treated core showed a higher gas relativepermeability than the untreated. At low pressuregradients (e.g., 14 psi/ft), the enhancement in gaspermeability is higher than that at high pressuregradients (e.g., 200 psi/ft). The higher residual perme-ability for the treated core is primarily due to the lowerresidual water saturation. Water saturation is higher forthe water-wet case due to capillary end effect whichdecreases with the increase in pressure gradient.

Fig. 12 also shows that the effective gas permeabilityat a fixed water saturation is lower for the untreated corecompared to that for the treated core. For the untreatedcore, the effective permeability would be even higherthan shown in Fig. 12 if the capillary end effect can beremoved. As the core becomes less water-wet, gasrelative permeability decreases. As a fluid becomeswetter, it occupies relatively smaller pores leading to

ted cores at different pressure drops across the core.


lower relative permeability. It is also noted that for thetreated core, as the pressure gradient increases, theresidual water saturation decreases. For 200 psi/ft, thecapillary number defined as Nc ¼ DPk

rL is O(10−5). Thusthe capillary number varies in the range of 10−6 to 10−5.Thus the residual water saturation varies in this range atthis intermediate wettability.

4. Conclusions

Many surfactants have been identified which changethe wettability of carbonate and sandstone rocks fromwater-wet to intermediate-wet in water–air–rock sys-tems. Among fluorosilanes, as the number of fluorogroups increases, the rock becomes less water-wet. Oneday of aging period and 1 wt.% concentration appear tobe sufficient for altering wettability. Interaction withfield brine plays a crucial role in selection of appropriatesurfactants. Wettability alteration can reduce the brinesaturation near the hydraulic fracture faces and increasegas productivity. The increase in gas relative perme-ability due to the change in wettability is a function ofthe pressure gradient. More experiments need to beperformed with low permeability rocks to understandthe mechanisms, the long-term stability, and the effect ofwettability alteration at a reservoir scale.

Acknowledgements

The authors thank NPTO of the US Department ofEnergy (DE-FC26-00NT15125) for providing financialsupport for this project.

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Effect of surfactants on wettability of near-wellbore regions of gas reservoirs