Experimental investigations of the wettability of clays and shales

Experimental investigations of the wettability of clays and shales

Artem Borysenko,1 Ben Clennell,2 Rossen Sedev,1 Iko Burgar,3 John Ralston,1

Mark Raven,4 David Dewhurst,2 and Keyu Liu2

Received 14 July 2008; revised 26 February 2009; accepted 14 April 2009; published 11 July 2009.

[1] Wettability in argillaceous materials is poorly understood, yet it is critical tohydrocarbon recovery in clay-rich reservoirs and capillary seal capacity in both caprocksand fault gouges. The hydrophobic or hydrophilic nature of clay-bearing soils andsediments also controls to a large degree the movement of spilled nonaqueous phaseliquids in the subsurface and the options available for remediation of these pollutants. Inthis paper the wettability of hydrocarbons contacting shales in their natural state and thetendencies for wettability alteration were examined. Water-wet, oil-wet, and mixed-wetshales from wells in Australia were investigated and were compared with simplifiedmodel shales (single and mixed minerals) artificially treated in crude oil. The intact naturalshale samples (preserved with their original water content) were characterizedpetrophysically by dielectric spectroscopy and nuclear magnetic resonance, plus scanningelectron, optical and fluorescence microscopy. Wettability alteration was studied usingspontaneous imbibition, pigment extraction, and the sessile drop method for contact anglemeasurement. The mineralogy and chemical compositions of the shales were determinedby standard methods. By studying pure minerals and natural shales in parallel, acorrelation between the petrophysical properties, and wetting behavior was observed.These correlations may potentially be used to assess wettability in downholemeasurements.

Citation: Borysenko, A., B. Clennell, R. Sedev, I. Burgar, J. Ralston, M. Raven, D. Dewhurst, and K. Liu (2009), Experimental

investigations of the wettability of clays and shales, J. Geophys. Res., 114, B07202, doi:10.1029/2008JB005928.

1. Introduction

[2] Trapping and retention of nonaqueous phase liquidsare important considerations for the petroleum industry andalso for the prevention and remediation of environmentaldamage associated with the spillage of chemical products orwaste. A successful study of liquid distribution and liquid/liquid displacement in complex mineral systems (e.g.,porous sediments or soils) requires the development ofreliable techniques for wettability and surface characteriza-tion. The majority of research on the dynamics and trappingof nonaqueous fluids has focused on granular geomaterialssuch as sandy aquifers and sandstone reservoirs, while thefine-grained and clay-rich lithologies that typically retard ortrap nonaqueous phase liquids have received much lessattention. A mud or a shale layer in the subsurface is usuallyassumed to act as a perfect seal to the nonaqueous phase.The implicit assumption is that fine, clay-rich rocks areinherently water-wet (i.e., hydrophilic) so that a capillarypressure barrier is formed. If the surfaces of minerals

constituting the seal are naturally hydrophobic, or becomeso with time, then the supposed barrier may leak, andretardation of oil or contaminant flow through the seal willhappen only by virtue of its low effective permeability.

2. Specific Aims and Scope of the Present Study

[3] Shales/mudrocks act as seals to petroleum reservoirsbecause of their low permeability and high capillary entrypressure. Capillary sealing requires that the rock is substan-tially water-wet. Typically, a zero contact angle for water isassumed for shales, though this is not usually confirmed bymeasurements [Anderson, 1986a]. There is mounting evi-dence that shales become (patchily) oil-wet through in situmaturation of organic matter [Boult et al., 1997] or exposureto polar compounds in formation waters [Larter and Aplin,2005]. It is therefore worthwhile testing the wettability ofshale caprocks through controlled experiments. The ulti-mate aim of this research is to compile a database combin-ing geological information about caprocks and relationshipsof these parameters to their physico-chemical properties,which are assessed by X-ray diffraction (XRD), scanningelectron microscope (SEM) and cation exchange capacity(CEC) as well as bulk chemistry and wettability tests. Asecondary aim is to investigate which petrophysicalmethods may be used to predict these properties fromdownhole log data or rapid nondestructive tests on coresamples. While the focus here is on mudrocks, the

JOURNAL OF GEOPHYSICAL RESEARCH, VOL. 114, B07202, doi:10.1029/2008JB005928, 2009ClickHere

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1Ian Wark Research Institute, University of South Australia, MawsonLakes, South Australia, Australia.

2CSIRO Petroleum, Kensington, West Australia, Australia.3CSIRO Materials Science and Engineering, Clayton South, Victoria,

Australia.4CSIRO Land and Water, Urrbrae, South Australia, Australia.

Copyright 2009 by the American Geophysical Union.0148-0227/09/2008JB005928$09.00

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methods developed will be useful in formation evaluationof shaly sands, to give an indication of wettability at anearly stage and/or to monitor wettability changes that mayoccur in the critical near-wellbore region during produc-tion from clay-rich reservoirs.[4] To understand wettability, we need to study several

parameters of the system, such as surface texture, micro-morphology of the porosity, brine composition and oilcomposition and phase state at the prevailing pressure-volume-temperature conditions [Drummond and Israelachvili,2004]. In this study, it is necessary to consider shales asmultimineral composites with wetting behavior influencedby their various components. Other parameters that affectwettability are the chemical composition and physicochem-ical properties of the brine and the crude oils, which varydepending on the nature of the source rocks, maturationhistory, migration, biodegregation and so on [Buckley,2001]. Effective, nondestructive methods are required tomonitor the various aspects of fluid-rock interaction. High-resolution methods such as environmental scanning electronmicroscopy (ESEM) and atomic force microscopy (AFM)are valuable tools to directly probe mineral surfaces andidentify adsorbed species, but less useful when one attemptsto understand processes occurring throughout a porousmedium under dynamic conditions of fluid displacement.Thus optical and fluorescence microscopy, scanning electronimaging as well as NMR spectroscopy and dielectric meas-urements are used to assess liquid/solid interactions andliquid mobility within the pores space of a model rockcomposed of packed powdered shale, clay or quartz samples.These methods have a substantial history in rock wettabilityresearch [Anderson, 1986b; Buckley, 2001; Morrow andMason, 2001] but they have rarely been used in combina-tion, and few studies have been conducted specifically onclays and shales.

3. Materials and Methods

[5] The same physico-chemical interactions that controlinterfacial interactions in the subsurface also exert a com-bined effect on wettability measurements made in thelaboratory. As a result, we had to divide this study intoseveral steps and build up knowledge of the individualphenomena involved [Clennell et al., 2006]. Each methodprobes one or more fundamental properties or processes(e.g., hydrophobicity, adhesion forces, displacement kinet-ics, swelling, etc.). By applying several methods togetherand complementing them with direct microscopic observa-tions and spectroscopic analysis, we obtain an understand-

ing of how these competing effects interact in naturalscenarios.

3.1. Samples

[6] Initially, simple model systems (Table 1) were used:quartz silt (Q), montmorillonite clay (M) and its mixturewith quartz (M+Q), kaolinite (K). The quartz surfaces werethoroughly cleaned using sulphuric acid, hydrogen peroxideand potassium hydroxide to ensure a high level of surfacecleanliness. Under such conditions, the quartz surface isstrongly hydrophilic. Surface modified quartz (QM) wasproduced by reacting clean and dry samples with trimethyl-chlorosilane (TMCS). TMCS reacts with the hydroxylgroups (‘‘silanols’’) present on the surface of quartz. Tri-methyl groups are thus chemically grafted onto the surfacewhich then becomes hydrophobic. To explore the effects ofnatural wettability variation two shales from Australia werechosen: (1) a sample from the Bass Basin (O1A), whichcontains quartz and kaolin and is hydrophobic, and (2) asample from the continental Officer Basin in WesternAustralia (L1_390), which contains abundant illite and isstrongly hydrophilic (Table 1). The shales were examined inan ‘‘original’’ state of preserved water content (taken fromthe drill core and stored under oil) and also in a dried andpowdered form. It was verified that the interior parts of thepreserved shales were not penetrated by the storage oil(Shell P-874, containing alkanes and napthenes), usingfluoresence microscopy on the broken open surface: nofluorescence was detected [Liu and Eadington, 2005].[7] For microscopic observations and the sessile drop

method, flat fragments of rocks were used. For imbibitionand pigment extraction as well as in dielectric and NMRmeasurements, granulated shale samples (150–180 mmgrain size) were examined, focusing our attention on wet-tability effects as well as accessing a large internal surfaceof the multimineralic shales without requiring extraordinarilyhigh capillary pressures [Diggins and Ralston, 1993]. In theimbibition tests we were using highly refined oil (ShellOndina 15, that is nonadditive, aromatic free, paraffinicwhite mineral oil). In order to study the wettability changesafter interaction with crude oil, we tested the quartz silt, clayand granulated shales before and after a simplified agingprocess (heating in oil at 70�C for 24 h). Dupuy Crude, fromWestern Australia was used for the treatment (44–45 API,h20�C = 1.59 mPa s).

3.2. Contact Angle Measurement

[8] The contact angle, the basic characteristic of wetta-bility, can be easily observed and measured considering a

Table 1. Samples Used in This Study

Sample Code Sample Composition and Treatment

Q Quartz clean (hydrophilic): cleaned with sulphuric acid and potassium hydroxideQM Quartz methylated (hydrophobic): cleaned as above and then methylated with TMCSM Montmorillonite clayM+Q Montmorillonite clay (10%) added into coarse quartz (90%)K KaoliniteL1_390 Hydrophilic shale (quartz 20%, orthoclase 11%, illite 49%, chlorite 2%, hematite 5%, dolomite 13%) CEC = 30 cmol/kg;

SSA = 9.2 m2/gO1A Hydrophobic shale (quartz 41%, kaolin 42%, mica 16%, hematite < 1%, siderite < 1%) CEC = 13 cmol/kg; SSA = 3.3 m2/gxxx-C Sample xxx, treated in crude oil (70�C for 24 h)xxx-CW Sample xxx, treated in crude oil and exposed to water (rehydrated)

B07202 BORYSENKO ET AL.: WETTABILITY OF CLAYS AND SHALES

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drop of liquid sitting on a flat fragment of a mineral as inFigure 1 [Anderson, 1986b]. The contact angle on ahydrophilic surface is low (Figure 1a). On the hydrophobicsurface of a naturally oil-wet reservoir rock (a shalysandstone from a field in the Perth Basin) water formed adrop with a sharp mineral/water/air contact line, displayinga contact angle of 110� (Figure 1b). The advancing contactangle was determined by recording and analyzing digitalimages of a drop of liquid on the mineral surface [Kumar etal., 2005; Shedid and Ghannam, 2004; A. Borysenko et al.,Wettability measurements in model and reservoir shalesystems, SCA International Symposium, Trondheim, Soci-ety of Core Analysts, Norway, 12–16 September 2006].The accuracy of the measurement is affected by the rough-ness and heterogeneity of the surface [Neumann and Good,1979] despite the fact that flat quite smooth fragments werepurposely selected. The different contact angles on the left

Figure 1. Sessile drop tests. (a) A water droplet on the airdry surface of hydrophilic shale L1_390 in original state.(b) Example of a water droplet on the air dry surface of anoil-wet reservoir rock from the Perth Basin, WesternAustralia. (c) Measurement of oil/water contact angle madewith a water droplet under hexadecane on the surface ofcrude oil treated shale sample L1_390-C. (d) Water dropletunder the same oil-immersed conditions for a treated shalesample O1A-C.

Figure 2. Cell for forced imbibition tests. It consists of aglass tube 20 cm long (30 mm inner diameter), Teflon caps(consisting of plug which is inserted directly in the tube andscrews to fix inlet and outlet tubes), rubber O-rings to makethe cell waterproof, and inlet and outlet pipes (3 mm innerdiameter).


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and right side of the droplet in Figure 1b illustrate thisclearly. The contact angles reported here are an average overat least 10 measurements on different locations of the solidsample. The precision of our contact angle measurements is±5� or better.

3.3. Liquid-Liquid Extraction

[9] A disadvantage of the sessile drop method is that itrequires a relatively large flat area. For small particles amore suitable technique is film (or skin) flotation technique[e.g., Fuerstenau et al., 1991]. During the test, 1 g ofgranulated sample (grain size <10 mm) was placed insidethe separating funnel together with 20 mL of water and20 mL of a single component oil (hexadecane). The funnelwas thoroughly shaken for 5 min and allowed to settle. As aresult of the competition between oil and water for thesurfaces, some particles sank in the water while otherparticles kept floating in the oil depending on their wetta-bility. The distribution of particles between the oil and waterphases provides a quantitative measure of the hydrophobic-ity of the shale.

3.4. Spontaneous and Forced Imbibition

[10] A more realistic assessment of wettability in theporous medium of a shale is obtained through imbibitionexperiments. The effect of interfacial interactions can becharacterized by the rate and quantity of oil recovery duringspontaneous imbibition [Morrow and Mason, 2001]. In thespontaneous imbibition test, the mineral powder is packedinto a small vial, then fully saturated with crude oil and,after that, immersed in a sealed glass container full of water.The oil recovery, relative to the ‘‘original oil in place’’ (%OOIP), was monitored by measuring the volume of oilexpelled from the sample. Thus we follow how the fluidinitially present is displaced by a second immiscible fluidwith a higher affinity for the solid surface.[11] In forced imbibition tests, the displacing liquid is

driven by an externally applied pressure. In this case, themeasurement of permeability was obstructed by intensive

water adsorption by clays so of particular interest were thecapillary entry pressure (for the nonwetting phase to pene-trate the packed bed), the relative permeability to water andoil, the sweep efficiency (residual saturation) and the spatialdistribution of the trapped fluid on the pore scale.[12] The apparatus used for the forced imbibition test is

presented in Figure 2. Packed beds of shale particles (100–250 mm size) were used because it is impractical to forcefluids through intact shales. The packed beds present a largemineral area to the invading and retained fluid and thereforeadequately reflect the wettability of the mineral assemblage.The pressure generated by a water injection (at constantflow rate) was monitored with time.

3.5. Dielectric Methods

[13] The dielectric constant of a porous material isstrongly affected by fluid content and distribution. Waterhas a high dielectric constant (�80) compared with mineralgrains or oils (typically 4–5). At high frequency (1–3 GHz),the value of the dielectric constant reflects mainly theamount of water compared with air, solids and oil (accord-ing to a volumetric mixing law) [Sweeney et al., 2007].Surface active clay-rich materials and samples with multiplefluid films exhibit a greater dielectric constant at lowfrequencies 1–100 MHz. The value of the dielectric con-stant at around 10 MHz depends on fluid proportions,thickness of the adsorbed films and mineralogy. Changesin dielectric constant over time can be used as a sensitivemeasure of liquid redistribution in the sample. The dielectricloss at low frequency (<100 MHz) depends mainly onohmic conductivity. Samples with higher water contentand more clay show a greater loss i.e., are less resistivethan samples with low water content or without clay.[14] After initial frequency sweep tests to determine a

suitable frequency that shows substantial changes with fluidsaturation, a single frequency of 10 MHz for presentation ofdielectric results was chosen. Our dielectric measuringsystem consisted of a Vector Network Analyzer (Agilent

Figure 3. Decrease of air-water contact angle on hydrophobic shale O1A (solid triangles); kaolinite(solid squares), montmorillonite (open squares); hydrophilic shale L1_390 (open triangles). Vertical barsindicate the error due to surface roughness and heterogeneity (estimated from 10 individualmeasurements made across the sample).


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ENA 5071B) and a coaxial probe (end-loaded transmissionline) 6 mm in diameter that was placed against the sample.The software (Agilent 5071A) returns both the real part ofthe relative permittivity (dielectric constant) and the imag-inary relative permittivity (dielectric loss) at each frequency.The dielectric spectra therefore consist of two continuousfunctions that are relatively smooth in variation with fre-quency over the interval of measurement. A more familiarparameter, resistivity, r, was calculated from the dielectricloss, e00, as r = (2p f e0e

00)�1, where f is frequency and e0 isthe permittivity of free space.[15] Measurements were started with powdered shale

pretreated in crude oil and then water was added drop-wiseup to around 80% saturation. After each hydration step, theweight change was measured and a dielectric spectrum wasacquired. At each point, sufficient time (from severalminutes to several hours) was allowed for stable values ofthe real and imaginary permittivity to be obtained.

3.6. NMR Methods

[16] The displacement processes in either spontaneous orforced imbibition may be monitored by proton NMRspectroscopy [Chen et al., 2006; Fleury and Deflandre,2003; Manalo et al., 2003]. The most straightforwardanalysis method is determination of the bulk sample trans-verse nuclear spin relaxation time decay. T2 was obtainedwith a low field NMR spectrometer (2 MHz Maran Ultra)using the Carr-Purcell-Meiboom-Gill (CPMG) pulse se-

quence in a uniform magnetic field. The low-field NMRmethods probe a sample volume of 20–70 cm3 and requireabout 1–5 g of hydrogen-bearing liquid in the sample toproduce reliable results. The advantage is relative insensi-tivity to the magnetic susceptibility contrasts of grains andmatrix that are problematic in real rocks if measured at highmagnetic fields.[17] A conventional regularized least squares inversion

routine was used to invert the decaying echo train to a T2spectrum. In the Maran Ultra instrument, the initial echosignal is detected after an interval of around 250 ms and with230 ms interecho spacing, so only liquid-borne protons witha spin lifetime of at least tens of ms are detected. Practicallythis means that liquids in pores of all sizes down tohundreds of nanometer are completely detected, togetherwith some fluid in smaller pores and bound to surfaces.Surface- and solid-bound protons and protons in nanometer-sized pores are not detected with this instrument. The T2value for bulk water is around 3 s, while that for Ondina 15oil is 115 ms. The South Australian light crude oil has amultiexponential T2 distribution centered around 100 ms.

4. Results and Discussion

4.1. Wettability

[18] The L1_390 shale is water wet in its natural (un-treated) state as are many shales. In this case water spon-taneously spreads on their surface (Figure 1a) and the

Figure 4. Results of liquid-liquid extraction tests. Distributions of particles (size 1 mm) between waterand oil (South Australian light crude, 45 API). Powdered shales (O1A and L1_390) and minerals (Q,quartz; M, montmorillonite; K, kaolinite) were tested (a) before and (b) after aging in crude oil (70� for24 h).


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advancing contact angle is low (10�–30�). However, on thereservoir rock, shown in Figure 1b, water forms a sharpthree-phase contact line and the advancing contact angle of120� indicates a strongly hydrophobic, i.e., oil-wet behav-ior. This wetting behavior is enhanced when air is replacedwith oil. The solid/liquid/liquid contact angle can be small(e.g., 30� in Figure 1c) or very large (140–160�) for crudeoil treated rocks (Figure 1d). The effect of crude oiltreatment can be very different. The crude oil forms a layeron a hydrophobic surface and makes it even more hydro-phobic (Figure 1d). However, in other samples, which arehydrophilic, (e.g., L1_390 in Figure 1c) the contact angle inair remains below 60� even after crude oil treatment. Itappears that in this case the crude oil does not form acontinuous layer due to the very different rock-oil inter-actions. This layer is easily destroyed when the treatedsurface is exposed to water. The rehydration of shaleL1_390-C was followed with optical microscopy. An in-tensive slaking and the formation of multiple microcrackson the shale surface were observed. The fast formation ofcracks is accompanied by a decrease in the contact angle.The water in air contact angle on the hydrophilic shaleL1_390-C decreased from 130� after oil treatment to a 30�within few minutes only (Figure 3). In contrast, little changein contact angle was observed on the hydrophobic shaleO1A-C (Figure 3). It seems natural, in case of light crudeoil, that a hydrophilic surface, containing polar and disso-ciating groups retains affinity for water even after crude oiltreatment. Tests were also performed with pure kaoliniteand a quartz-montmorillonite mixture. For kaolinite, therewas a small decrease in the contact angle, the later reach-ing a higher plateau value in comparison to a lesshydrophobic montmorillonite-quartz mixture (Figure 3).This test very clearly differentiates between samples ofvarying wettability.

[19] The observed water/oil contact angles are relevant tocapillary invasion of an initially water-saturated caprockabove an oil reservoir. In order to use the data in a predictivemanner, a correction for the interfacial tension changes withtemperature would have to be made [Buckley, 2001].However, for screening purposes, ambient condition wa-

Figure 5. Curves illustrating the progress of spontaneous imbibition by showing the percentage of oildisplaced by water versus time: clean quartz (open circles), hydrophilic shale L1_390 (open triangles),kaolinite (solid squares), methylated quartz (solid circles), montmorillonite (open squares), hydrophobicshale O1A (solid triangles) (OOPI signifies original oil in place).

Figure 6. Pressure curves from forced imbibition testsemploying a constant rate of flow of 1 mL/min from asyringe infusion pump. Dotted gray line, methylatedhydrophobic quartz; solid gray line, oil treated hydrophilicshale L1_390-C; solid black line, oil treated hydrophobicshale O1A-C. Treated shales show capillary entry pressure,whereas clean quartz does not. Rapidly falling segments ofthe curves occurred when the pump was switched off, afterDarcy flow was established for some time. This did notoccur with sample L1_390C.


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ter/air contact angles are useful to distinguish shales that arehydrophilic or hydrophobic as well as for assessing theeffect of sample treatments such as methylation or aging inoil.

4.2. Liquid-Liquid Extraction

[20] The formation of an oil film on the surface of rocksresults in a significant reduction of the specific surfaceenergy and a substantial alteration of the wettability. This isclearly seen in the liquid-liquid extraction tests presented inFigure 4. In their natural state (before aging) montmoril-lonite and L1_390 shale show a high affinity for water,shale O1A, and quartz show moderately hydrophobic be-havior with 40–50% of the particles in the water phase andkaolinite only 10% (Figure 4a). The hydrophobicity of thelast three samples strongly increases after crude oil treat-ment: more than 90% of the kaolin particles are extracted inthe oil phase and less then 20% of quartz and O1A shalepowder is suspended in water. The L1_390-C shale and themontmorillonite were not permanently altered though, and

in time reverted to a water-wet state: more than 80% of thepowder remained in the water (Figure 4b). For montmoril-lonite, this took several hours of exposure to water. On thecontrary with kaolin, which has a higher affinity for oil, thehydrophobicity persisted even when exposed to water(compare Figures 4a and 4b). The present observationsare in line with previous findings [Bantignies et al., 1997;Cosultchi et al., 2005; H. G. Rueslatten et al., A combineduse of CRYO-SEM and NMR-spectroscopy for studying thedistribution of oil an brine in sandstones, paper presented atSPE/DOE 27804 IOR Symposium, Society of PetroleumEngineers, Tulsa, Oklahoma, 17–20 April 1994].

4.3. Spontaneous and Forced Imbibition

[21] In hydrophilic samples, the rate of spontaneousimbibition is high, and limited by the permeability of theporous medium. On the other hand, if the sample is stronglyhydrophobic then very little water will enter the sample, andconsequently only a small amount of oil will be recovered.Behavior between these two extreme limits indicates anintermediate wetting state. In our tests the highest rate of oilrecovery during spontaneous imbibition was measured forclean quartz followed by the most hydrophilic shale L1_390(Figure 5). A lower spontaneous imbibition rate was foundfor methylated quartz, QM, and practically no oil displace-ment by water was observed with the hydrophobic shaleO1A-C (Figure 5). A slower oil recovery was observed withmontmorillonite in comparison with kaolin (Figure 5),which is the opposite of the wetting behavior seen in theliquid-liquid extraction tests (Figure 4). This difference isattributed to the significant swelling of the montmorillonitepowder during hydration, which reduces pore and interpar-ticle space so that both liquids become trapped [Jada et al.,2006].[22] Forced imbibition was used to investigate the process

of liquid penetration and interface evolution in packedparticle beds (Figure 6). The degree of hydrophobicity ofthe sample can be quantified by the pressure required tobreak through the capillary resistance [Al-Bazali et al.,2008]. In the clean quartz samples, Q, the pressure profilecharacteristic of a Darcy flow begins to develop on com-mencement of water injection. That is, water immediatelyenters the sample with no capillary entry pressure toovercome. In the powdered and oil-aged shales, when waterinjection commences, the pressure rises up to a certain valuefrom where a more gradual curve develops. For samplesL1_390-C and O1A-C we deduce that it was necessary toovercome a capillary entry pressure of about 6 kPa and10 kPa respectively. Thus the observed capillary entrypressure is larger for more hydrophobic samples.[23] After the initial injection, the pressure increases

slowly as water penetrates the pack and then reachessaturation, with a plateau value for quartz and O1A-C shale;that is, these samples develop a Darcy flow. In sampleL1_390-C the pressure continues to rise without reaching anequilibrated plateau and this we attribute to a gradualrehydration and swelling that reduces the permeability ofthe packed bed.

4.4. Dielectric Measurements

[24] Two stages of water saturation were also identifiedby dielectric measurements at 10 MHz (Figure 7). At low

Figure 7. Time evolution of (a) dielectric constant and(b) resistivity of shale samples: O1A-CW (open circles) andL1_390-CW (open triangles) after initial water saturation;O1A-CW (solid circles) and L1_390-CW (triangles) 24 hlater; quartz (solid squares) after initial injection andunchanged 24 h later (points superposed).


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water saturation, all samples (quartz and shales Figure 7a)have a low dielectric constant (�10). As hydration pro-gressed, the dielectric constant increased. The lowest di-electric constant was found for quartz, reflecting the smallspecific surface area of quartz compared with clay minerals:the latter have surface charges that become polarized at lowfrequency, contributing to the measured dielectric constant[Cosenza and Tabbagh, 2004]. At low and moderate satu-ration, quartz resistivity exceeds the value obtained forshales (Figure 7b), reflecting entrapment and isolation ofthe water phase by oil films.[25] For shales, increasing water saturation results in an

increase in the dielectric constant and a monotonic decreasein resistivity for the hydrophilic shale L1_390-CW. Water

effectively wets the surface after displacing the oil, ensuringeffective charge mobility. On the contrary, for hydrophobicshale and quartz the resistivity decreases until the watersaturation reaches 5% (Figure 7b). Then the resistivityessentially remains at a plateau (with a slight increase forquartz due to polarization of oil/water interfaces in porousspace). This plateau in the resistivity indicates that inhydrophobic shale and quartz both liquids, oil and water,are redistributed in such a way that efficient conductionpathways through the interaggregate pore space cannot beestablished. This effect is illustrated even more stronglywhen samples were kept over 24 h to allow spontaneousliquid/liquid redistribution and equilibration within the porespace. While the hydrophilic sample L1_390-CW shows the

Figure 8. Nuclear magnetic resonance results following oil and water treatments on quartz modelsystem. Transverse relaxation time (T2) spectrum of (a) hydrophilic and (b) hydrophobic quartzpresaturated with oil and then rehydrated. For reference, the T2 peaks of quartz completely saturated withoil (gray dashed line) and quartz completely saturated with water (black dashed line) are also shown.


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same decrease of resistivity (as described above), forhydrophobic shale O1A-CW there is a significant increasein the dielectric constant and resistivity at 5–15% of watersaturation. Thus in hydrophobic shale O1A-CW, waterbecomes spontaneously displaced from the surface andentrapped in rock pore space. During water injection bothoil and water apparently become redistributed, dependingon the rock surface wettability. This directly affects thedielectric properties of the system and can be used formonitoring the rock wetting behavior.

4.5. NMR Spectroscopy

[26] NMR transverse relaxation time (T2) spectra arepresented in Figure 8 for quartz particles of 150–180 mmdiameter, the pore size is typically 20–50 mm across. In thiscase both oil and water are located in the large pores. The T2distribution for quartz presaturated with oil and then grad-ually rehydrated is essentially a superposition of the signalsobtained for each individual liquid (oil plus water). T2distributions are different for clean quartz (Figure 8a) andhydrophobic (methylated) quartz (Figure 8b). The waterpeak is higher for the hydrophilic quartz while in thehydrophobic sample the oil peak dominates. Therefore moreoil is displaced by water from a pore space of equivalentgeometry when the solid surface is hydrophilic.[27] The T2 distributions acquired in the quartz-montmo-

rillonite mixture (M+Q; 90% quartz, 10% montmorillonite)are shown in Figure 9. The light gray dotted line shows theoil peak (104–106 ms) after oil saturation of the mineral bed.That can be compared to water saturated sample: The T2distribution, shown as a gray line, where distinct peaks ofclay-bound water (below 104 ms) are easily distinguishedfrom the water peak located within intergranular pores (T2 >105 ms). The black line shows the T2 peak obtained afterrehydration of the oil saturated M+Q sample. The resultantT2 is a superposition of both the oil and water peaks. At the

same time, the oil peak at T2 < 104 ms is displaced by thewater peak. In this case both liquids are bound more tightlyto the surface than in the case of coarse quartz (compareFigures 9 and 8). Liquid/liquid displacement occurs within amore confined pore space: the peaks are located at lowertimes due to the presence of clay particles in the intergran-ular pore space.[28] In crude oil-treated granular shale packs exposed to

water by forced imbibition, the T2 peak of the clay-boundwater is even more distinct at T2 � 103 ms (Figure 10). It ismuch larger for the hydrophilic sample L1_390-C (Figure 10a)in comparison with the hydrophobic one O1A-C (Figure 10b).In contrast, the oil peak at T2 = 104–105 ms is higher inO1A-C. During water penetration into the crude-treatedhydrophilic shale L1_390-C (Figure 10a), the oil peak at104–105 ms shifts to the left and decreases; at the same timethe peaks for clay-bound water (T2 < 103 ms) and interpar-ticle pore space water (T2 � 105–106 ms) grow. Thisprobably reflects the displacement of the surface oil filmby the water. On the contrary, during water penetration intothe hydrophobic shale O1A-CW (Figure 10b), we observenegligible growth of the oil peak (T2 = 104–105 ms). Furtherwater penetration was accompanied by a growth of the waterpeaks at T2 > 105 ms, reflecting filling of interparticle porespace, where water avoids the surfaces and does not causeliquid/liquid displacement.

5. Summary

[29] Our results illustrate that shale samples are particu-larly challenging for wettability studies due to the difficultyin accessing the very restricted or ‘‘tight’’ pore space withdifferent liquids. We have focused our work on understand-ing the fundamental interfacial phenomena before attempt-ing direct measurements on shales in their intact state, andin situ conditions of elevated pressure and temperature. We

Figure 9. Nuclear magnetic resonance results following oil and water treatments on quartz-montmorillonite model system. Transverse relaxation time (T2) spectrum after water saturation only(gray line); after oil saturation only (gray dotted line); and following oil/water displacement from aninitially oil saturated sample following a period of rehydration (solid black line).


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approached the problem using model systems and crushedshale particle packs to access polymineralic internal surfa-ces, employing a range of characterization methods each ofwhich gives us a part of the overall picture. The sessile dropmethod is a very direct measure of relative wetting tendencybut is effective for qualitative considerations only due to theeffect of surface roughness and heterogeneity. Liquid/liquidextraction, spontaneous and forced imbibition are alsorelatively simple methods and require further informationto confirm the surface properties in order that we caninterpret their outcomes reliably. We used dielectric andNMR spectroscopy to obtain finer level information aboutwhich fluid was preferentially wetting the surfaces within

the shale packs; the approach seems to have been validatedby the good correspondence between what we deduce fromthese spectroscopic probes and what we observe in macro-scopic measurements.[30] We have demonstrated that mineralogically and tex-

turally distinct shales show different affinities for oil andwater, ranging from strongly hydrophilic to strongly hydro-phobic. By comparing pure minerals and natural shales, theinfluence of mineralogical structure and wettability of theindividual shale components (clay minerals and quartz) onliquid/liquid displacement and liquid distribution insidegranular shale packs was examined.

Figure 10. Nuclear magnetic resonance results following oil and water treatments on crude oil treatedshales prepared as granular packs. T2 spectrum of (a) hydrophilic sample L1_390 and (b) hydrophobicsample O1A shale. The solid line is the sample after oil treatment only, and the dashed line is therelaxation distribution after water injection.


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[31] Identifying petrophysical signatures of the prevailingwetting state and assessing the susceptibility to wettabilityalteration (e.g., by drilling fluids or during productionprocesses) is highly desirable for shales as well as variousreservoir lithologies. We have demonstrated that dielectricand NMR methods, used already for reservoir rocks, areapplicable to clays and shales.[32] Petrophysical properties were consistent with wetting

behavior and the swelling tendency of the shale minerals.While our results from wettability assays show a highlyconsistent pattern, most of our work so far has focused on adetailed understanding of two end-member shales (L1_390which is hydrophilic and O1A which is hydrophobic). Wenow need to understand how representative these two shalesare when compared with a wider range of mudrock catego-ries. The differences between O1A and L1_390 are not onlymineralogical: while we do believe that the kaolinitic natureof O1A is important in its relative hydrophobicity, in linewith previous studies on reservoir rocks ([Buckley, 2001;Zhang et al., 2000; H. G. Rueslatten et al., presented paper,2004]), there are also substantial differences in texture, withthe L1_390 sample being extremely fine grained in its illiticmatrix and O1A being relatively silty. We are thereforeproceeding to apply our various screening methods on awider variety of preserved and dried shales, to confirm andreinforce the predictive value of our results.

6. Conclusion

[33] Our most important finding is that not all shales arethe same as far as wettability is concerned. There is asignificant variation in surface affinity for oil versus water,as determined by particle partition experiments, contactangle measurements on intact samples and a wide rangeof porous pack experiments on crushed samples. Initialcorrelations suggest that hydrophilic shales have a highersurface activity (surface charge density and specific area,combining to produce higher CEC), and that illitic andsmectitic mudrocks are more hydrophilic whereas kaoliniticmudrocks are potentially hydrophobic, being wet preferen-tially by oil and retaining that tendency after hydration. Thedirect observations using optical and fluorescence micros-copy as well as low vacuum SEM confirmed our interpre-tations of the petrophysical responses (NMR and dielectric)concerning those shales which are hydrophilic and chosewhich have a tendency to adsorb oil and even become oilwet. The petrophysical findings and microscopic observa-tions are consistent with the measurements of the wettingand swelling tendencies of the powders and intact shales.

[34] Acknowledgments. This paper is a contribution to the JointIndustry Project ‘‘Integrated Predictive Evaluation of Traps and Seals’’(IPETS). We thank the sponsors Chevron, Woodside, Santos, Origin,Anadarko, PIRSA, and Schlumberger for their support and permission topublish. The participation of Woodside and Chevron is through the WesternAustralian Energy Research Alliance. The Wealth from Oceans NationalResearch Flagship is thanked for substantial financial coinvestment in theproject. Origin Energy and the Geological Survey of Western Australia arethanked for the provision of the preserved shales cores used in the study.Finally, support from the ARC linkage scheme is gratefully acknowledged.

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��A. Borysenko, J. Ralston, and R. Sedev, Ian Wark Research Institute,

University of South Australia, Mawson Lakes, SA 5095, Australia.([email protected])I. Burgar, CSIRO Materials Science and Engineering, Clayton South, Vic

3169, Australia.B. Clennell, D. Dewhurst, and K. Liu, CSIRO Petroleum, 26 Dick Perry

Avenue, Kensington, WA 6151, Australia.M. Raven, CSIRO Land and Water, Waite Road, Urrbrae, SA 5064,

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Experimental investigations of the wettability of clays and shales