Experimental investigations of the wettability of clays and shales

Transcription

1 JOURNAL OF GEOPHYSICAL RESEARCH, VOL. 114,, doi: /2008jb005928, 2009 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 Liu 2 Received 14 July 2008; revised 26 February 2009; accepted 14 April 2009; published 11 July [1] Wettability in argillaceous materials is poorly understood, yet it is critical to hydrocarbon recovery in clay-rich reservoirs and capillary seal capacity in both caprocks and fault gouges. The hydrophobic or hydrophilic nature of clay-bearing soils and sediments also controls to a large degree the movement of spilled nonaqueous phase liquids in the subsurface and the options available for remediation of these pollutants. In this paper the wettability of hydrocarbons contacting shales in their natural state and the tendencies for wettability alteration were examined. Water-wet, oil-wet, and mixed-wet shales from wells in Australia were investigated and were compared with simplified model shales (single and mixed minerals) artificially treated in crude oil. The intact natural shale samples (preserved with their original water content) were characterized petrophysically by dielectric spectroscopy and nuclear magnetic resonance, plus scanning electron, optical and fluorescence microscopy. Wettability alteration was studied using spontaneous imbibition, pigment extraction, and the sessile drop method for contact angle measurement. The mineralogy and chemical compositions of the shales were determined by standard methods. By studying pure minerals and natural shales in parallel, a correlation between the petrophysical properties, and wetting behavior was observed. These correlations may potentially be used to assess wettability in downhole measurements. 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,, doi: /2008jb Introduction [2] Trapping and retention of nonaqueous phase liquids are important considerations for the petroleum industry and also for the prevention and remediation of environmental damage associated with the spillage of chemical products or waste. A successful study of liquid distribution and liquid/ liquid displacement in complex mineral systems (e.g., porous sediments or soils) requires the development of reliable techniques for wettability and surface characterization. The majority of research on the dynamics and trapping of nonaqueous fluids has focused on granular geomaterials such as sandy aquifers and sandstone reservoirs, while the fine-grained and clay-rich lithologies that typically retard or trap nonaqueous phase liquids have received much less attention. A mud or a shale layer in the subsurface is usually assumed to act as a perfect seal to the nonaqueous phase. The implicit assumption is that fine, clay-rich rocks are inherently water-wet (i.e., hydrophilic) so that a capillary pressure barrier is formed. If the surfaces of minerals 1 Ian Wark Research Institute, University of South Australia, Mawson Lakes, South Australia, Australia. 2 CSIRO Petroleum, Kensington, West Australia, Australia. 3 CSIRO Materials Science and Engineering, Clayton South, Victoria, Australia. 4 CSIRO Land and Water, Urrbrae, South Australia, Australia. Copyright 2009 by the American Geophysical Union /09/2008JB005928$09.00 constituting the seal are naturally hydrophobic, or become so with time, then the supposed barrier may leak, and retardation of oil or contaminant flow through the seal will happen 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 reservoirs because of their low permeability and high capillary entry pressure. Capillary sealing requires that the rock is substantially water-wet. Typically, a zero contact angle for water is assumed for shales, though this is not usually confirmed by measurements [Anderson, 1986a]. There is mounting evidence that shales become (patchily) oil-wet through in situ maturation of organic matter [Boult et al., 1997] or exposure to polar compounds in formation waters [Larter and Aplin, 2005]. It is therefore worthwhile testing the wettability of shale caprocks through controlled experiments. The ultimate aim of this research is to compile a database combining geological information about caprocks and relationships of these parameters to their physico-chemical properties, which are assessed by X-ray diffraction (XRD), scanning electron microscope (SEM) and cation exchange capacity (CEC) as well as bulk chemistry and wettability tests. A secondary aim is to investigate which petrophysical methods may be used to predict these properties from downhole log data or rapid nondestructive tests on core samples. While the focus here is on mudrocks, the 1of11

2 Table 1. Samples Used in This Study Sample Code Sample Composition and Treatment Q Quartz clean (hydrophilic): cleaned with sulphuric acid and potassium hydroxide QM Quartz methylated (hydrophobic): cleaned as above and then methylated with TMCS M Montmorillonite clay M+Q Montmorillonite clay (10%) added into coarse quartz (90%) K Kaolinite L1_390 Hydrophilic shale (quartz 20%, orthoclase 11%, illite 49%, chlorite 2%, hematite 5%, dolomite 13%) CEC = 30 cmol/kg; SSA = 9.2 m 2 /g O1A Hydrophobic shale (quartz 41%, kaolin 42%, mica 16%, hematite < 1%, siderite < 1%) CEC = 13 cmol/kg; SSA = 3.3 m 2 /g xxx-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) methods developed will be useful in formation evaluation of shaly sands, to give an indication of wettability at an early stage and/or to monitor wettability changes that may occur in the critical near-wellbore region during production from clay-rich reservoirs. [4] To understand wettability, we need to study several parameters of the system, such as surface texture, micromorphology of the porosity, brine composition and oil composition and phase state at the prevailing pressurevolume-temperature conditions [Drummond and Israelachvili, 2004]. In this study, it is necessary to consider shales as multimineral composites with wetting behavior influenced by their various components. Other parameters that affect wettability are the chemical composition and physicochemical properties of the brine and the crude oils, which vary depending on the nature of the source rocks, maturation history, migration, biodegregation and so on [Buckley, 2001]. Effective, nondestructive methods are required to monitor the various aspects of fluid-rock interaction. Highresolution methods such as environmental scanning electron microscopy (ESEM) and atomic force microscopy (AFM) are valuable tools to directly probe mineral surfaces and identify adsorbed species, but less useful when one attempts to understand processes occurring throughout a porous medium under dynamic conditions of fluid displacement. Thus optical and fluorescence microscopy, scanning electron imaging as well as NMR spectroscopy and dielectric measurements are used to assess liquid/solid interactions and liquid mobility within the pores space of a model rock composed of packed powdered shale, clay or quartz samples. These methods have a substantial history in rock wettability research [Anderson, 1986b; Buckley, 2001; Morrow and Mason, 2001] but they have rarely been used in combination, and few studies have been conducted specifically on clays and shales. 3. Materials and Methods [5] The same physico-chemical interactions that control interfacial interactions in the subsurface also exert a combined effect on wettability measurements made in the laboratory. As a result, we had to divide this study into several steps and build up knowledge of the individual phenomena involved [Clennell et al., 2006]. Each method probes one or more fundamental properties or processes (e.g., hydrophobicity, adhesion forces, displacement kinetics, swelling, etc.). By applying several methods together and complementing them with direct microscopic observations and spectroscopic analysis, we obtain an understanding of how these competing effects interact in natural scenarios Samples [6] Initially, simple model systems (Table 1) were used: quartz silt (Q), montmorillonite clay (M) and its mixture with quartz (M+Q), kaolinite (K). The quartz surfaces were thoroughly cleaned using sulphuric acid, hydrogen peroxide and potassium hydroxide to ensure a high level of surface cleanliness. Under such conditions, the quartz surface is strongly hydrophilic. Surface modified quartz (QM) was produced by reacting clean and dry samples with trimethylchlorosilane (TMCS). TMCS reacts with the hydroxyl groups ( silanols ) present on the surface of quartz. Trimethyl groups are thus chemically grafted onto the surface which then becomes hydrophobic. To explore the effects of natural wettability variation two shales from Australia were chosen: (1) a sample from the Bass Basin (O1A), which contains quartz and kaolin and is hydrophobic, and (2) a sample from the continental Officer Basin in Western Australia (L1_390), which contains abundant illite and is strongly hydrophilic (Table 1). The shales were examined in an original state of preserved water content (taken from the drill core and stored under oil) and also in a dried and powdered form. It was verified that the interior parts of the preserved shales were not penetrated by the storage oil (Shell P-874, containing alkanes and napthenes), using fluoresence microscopy on the broken open surface: no fluorescence was detected [Liu and Eadington, 2005]. [7] For microscopic observations and the sessile drop method, flat fragments of rocks were used. For imbibition and pigment extraction as well as in dielectric and NMR measurements, granulated shale samples ( mm grain size) were examined, focusing our attention on wettability effects as well as accessing a large internal surface of the multimineralic shales without requiring extraordinarily high capillary pressures [Diggins and Ralston, 1993]. In the imbibition tests we were using highly refined oil (Shell Ondina 15, that is nonadditive, aromatic free, paraffinic white mineral oil). In order to study the wettability changes after interaction with crude oil, we tested the quartz silt, clay and granulated shales before and after a simplified aging process (heating in oil at 70 C for 24 h). Dupuy Crude, from Western Australia was used for the treatment (44 45 API, h 20 C = 1.59 mpa s) Contact Angle Measurement [8] The contact angle, the basic characteristic of wettability, can be easily observed and measured considering a 2of11

3 drop of liquid sitting on a flat fragment of a mineral as in Figure 1 [Anderson, 1986b]. The contact angle on a hydrophilic surface is low (Figure 1a). On the hydrophobic surface of a naturally oil-wet reservoir rock (a shaly sandstone from a field in the Perth Basin) water formed a drop with a sharp mineral/water/air contact line, displaying a contact angle of 110 (Figure 1b). The advancing contact angle was determined by recording and analyzing digital images of a drop of liquid on the mineral surface [Kumar et al., 2005; Shedid and Ghannam, 2004; A. Borysenko et al., Wettability measurements in model and reservoir shale systems, SCA International Symposium, Trondheim, Society of Core Analysts, Norway, September 2006]. The accuracy of the measurement is affected by the roughness and heterogeneity of the surface [Neumann and Good, 1979] despite the fact that flat quite smooth fragments were purposely selected. The different contact angles on the left Figure 1. Sessile drop tests. (a) A water droplet on the air dry surface of hydrophilic shale L1_390 in original state. (b) Example of a water droplet on the air dry surface of an oil-wet reservoir rock from the Perth Basin, Western Australia. (c) Measurement of oil/water contact angle made with a water droplet under hexadecane on the surface of crude oil treated shale sample L1_390-C. (d) Water droplet under the same oil-immersed conditions for a treated shale sample O1A-C. Figure 2. Cell for forced imbibition tests. It consists of a glass tube 20 cm long (30 mm inner diameter), Teflon caps (consisting of plug which is inserted directly in the tube and screws to fix inlet and outlet tubes), rubber O-rings to make the cell waterproof, and inlet and outlet pipes (3 mm inner diameter). 3of11

4 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 bars indicate the error due to surface roughness and heterogeneity (estimated from 10 individual measurements made across the sample). and right side of the droplet in Figure 1b illustrate this clearly. The contact angles reported here are an average over at least 10 measurements on different locations of the solid sample. The precision of our contact angle measurements is ±5 or better Liquid-Liquid Extraction [9] A disadvantage of the sessile drop method is that it requires a relatively large flat area. For small particles a more suitable technique is film (or skin) flotation technique [e.g., Fuerstenau et al., 1991]. During the test, 1 g of granulated sample (grain size <10 mm) was placed inside the separating funnel together with 20 ml of water and 20 ml of a single component oil (hexadecane). The funnel was thoroughly shaken for 5 min and allowed to settle. As a result of the competition between oil and water for the surfaces, some particles sank in the water while other particles kept floating in the oil depending on their wettability. The distribution of particles between the oil and water phases provides a quantitative measure of the hydrophobicity of the shale Spontaneous and Forced Imbibition [10] A more realistic assessment of wettability in the porous medium of a shale is obtained through imbibition experiments. The effect of interfacial interactions can be characterized by the rate and quantity of oil recovery during spontaneous imbibition [Morrow and Mason, 2001]. In the spontaneous imbibition test, the mineral powder is packed into 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 oil expelled from the sample. Thus we follow how the fluid initially present is displaced by a second immiscible fluid with 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, the measurement of permeability was obstructed by intensive water adsorption by clays so of particular interest were the capillary entry pressure (for the nonwetting phase to penetrate the packed bed), the relative permeability to water and oil, the sweep efficiency (residual saturation) and the spatial distribution 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 ( mm size) were used because it is impractical to force fluids through intact shales. The packed beds present a large mineral area to the invading and retained fluid and therefore adequately reflect the wettability of the mineral assemblage. The pressure generated by a water injection (at constant flow rate) was monitored with time Dielectric Methods [13] The dielectric constant of a porous material is strongly affected by fluid content and distribution. Water has a high dielectric constant (80) compared with mineral grains or oils (typically 4 5). At high frequency (1 3 GHz), the value of the dielectric constant reflects mainly the amount of water compared with air, solids and oil (according to a volumetric mixing law) [Sweeney et al., 2007]. Surface active clay-rich materials and samples with multiple fluid films exhibit a greater dielectric constant at low frequencies MHz. The value of the dielectric constant at around 10 MHz depends on fluid proportions, thickness of the adsorbed films and mineralogy. Changes in dielectric constant over time can be used as a sensitive measure of liquid redistribution in the sample. The dielectric loss at low frequency (<100 MHz) depends mainly on ohmic conductivity. Samples with higher water content and more clay show a greater loss i.e., are less resistive than samples with low water content or without clay. [14] After initial frequency sweep tests to determine a suitable frequency that shows substantial changes with fluid saturation, a single frequency of 10 MHz for presentation of dielectric results was chosen. Our dielectric measuring system consisted of a Vector Network Analyzer (Agilent 4of11

5 Figure 4. Results of liquid-liquid extraction tests. Distributions of particles (size 1 mm) between water and 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 for 24 h). ENA 5071B) and a coaxial probe (end-loaded transmission line) 6 mm in diameter that was placed against the sample. The software (Agilent 5071A) returns both the real part of the relative permittivity (dielectric constant) and the imaginary relative permittivity (dielectric loss) at each frequency. The dielectric spectra therefore consist of two continuous functions that are relatively smooth in variation with frequency over the interval of measurement. A more familiar parameter, resistivity, r, was calculated from the dielectric loss, e 00,asr =(2p f e 0 e 00 ) 1, where f is frequency and e 0 is the permittivity of free space. [15] Measurements were started with powdered shale pretreated in crude oil and then water was added drop-wise up to around 80% saturation. After each hydration step, the weight change was measured and a dielectric spectrum was acquired. At each point, sufficient time (from several minutes to several hours) was allowed for stable values of the real and imaginary permittivity to be obtained NMR Methods [16] The displacement processes in either spontaneous or forced imbibition may be monitored by proton NMR spectroscopy [Chen et al., 2006; Fleury and Deflandre, 2003; Manalo et al., 2003]. The most straightforward analysis method is determination of the bulk sample transverse nuclear spin relaxation time decay. T 2 was obtained with a low field NMR spectrometer (2 MHz Maran Ultra) using the Carr-Purcell-Meiboom-Gill (CPMG) pulse sequence in a uniform magnetic field. The low-field NMR methods probe a sample volume of cm 3 and require about 1 5 g of hydrogen-bearing liquid in the sample to produce reliable results. The advantage is relative insensitivity to the magnetic susceptibility contrasts of grains and matrix that are problematic in real rocks if measured at high magnetic fields. [17] A conventional regularized least squares inversion routine was used to invert the decaying echo train to a T 2 spectrum. In the Maran Ultra instrument, the initial echo signal is detected after an interval of around 250 ms and with 230 ms interecho spacing, so only liquid-borne protons with a spin lifetime of at least tens of ms are detected. Practically this means that liquids in pores of all sizes down to hundreds of nanometer are completely detected, together with some fluid in smaller pores and bound to surfaces. Surface- and solid-bound protons and protons in nanometersized pores are not detected with this instrument. The T 2 value for bulk water is around 3 s, while that for Ondina 15 oil is 115 ms. The South Australian light crude oil has a multiexponential T 2 distribution centered around 100 ms. 4. Results and Discussion 4.1. Wettability [18] The L1_390 shale is water wet in its natural (untreated) state as are many shales. In this case water spontaneously spreads on their surface (Figure 1a) and the 5of11

6 Figure 5. Curves illustrating the progress of spontaneous imbibition by showing the percentage of oil displaced by water versus time: clean quartz (open circles), hydrophilic shale L1_390 (open triangles), kaolinite (solid squares), methylated quartz (solid circles), montmorillonite (open squares), hydrophobic shale O1A (solid triangles) (OOPI signifies original oil in place). advancing contact angle is low (10 30 ). However, on the reservoir rock, shown in Figure 1b, water forms a sharp three-phase contact line and the advancing contact angle of 120 indicates a strongly hydrophobic, i.e., oil-wet behavior. This wetting behavior is enhanced when air is replaced with oil. The solid/liquid/liquid contact angle can be small (e.g., 30 in Figure 1c) or very large ( ) for crude oil treated rocks (Figure 1d). The effect of crude oil treatment can be very different. The crude oil forms a layer on a hydrophobic surface and makes it even more hydrophobic (Figure 1d). However, in other samples, which are hydrophilic, (e.g., L1_390 in Figure 1c) the contact angle in air remains below 60 even after crude oil treatment. It appears that in this case the crude oil does not form a continuous layer due to the very different rock-oil interactions. This layer is easily destroyed when the treated surface is exposed to water. The rehydration of shale L1_390-C was followed with optical microscopy. An intensive slaking and the formation of multiple microcracks on the shale surface were observed. The fast formation of cracks is accompanied by a decrease in the contact angle. The water in air contact angle on the hydrophilic shale L1_390-C decreased from 130 after oil treatment to a 30 within few minutes only (Figure 3). In contrast, little change in contact angle was observed on the hydrophobic shale O1A-C (Figure 3). It seems natural, in case of light crude oil, that a hydrophilic surface, containing polar and dissociating groups retains affinity for water even after crude oil treatment. Tests were also performed with pure kaolinite and a quartz-montmorillonite mixture. For kaolinite, there was a small decrease in the contact angle, the later reaching a higher plateau value in comparison to a less hydrophobic montmorillonite-quartz mixture (Figure 3). This test very clearly differentiates between samples of varying wettability. [19] The observed water/oil contact angles are relevant to capillary invasion of an initially water-saturated caprock above an oil reservoir. In order to use the data in a predictive manner, a correction for the interfacial tension changes with temperature would have to be made [Buckley, 2001]. However, for screening purposes, ambient condition wa- Figure 6. Pressure curves from forced imbibition tests employing a constant rate of flow of 1 ml/min from a syringe infusion pump. Dotted gray line, methylated hydrophobic quartz; solid gray line, oil treated hydrophilic shale L1_390-C; solid black line, oil treated hydrophobic shale O1A-C. Treated shales show capillary entry pressure, whereas clean quartz does not. Rapidly falling segments of the curves occurred when the pump was switched off, after Darcy flow was established for some time. This did not occur with sample L1_390C. 6of11

7 in time reverted to a water-wet state: more than 80% of the powder remained in the water (Figure 4b). For montmorillonite, this took several hours of exposure to water. On the contrary with kaolin, which has a higher affinity for oil, the hydrophobicity persisted even when exposed to water (compare Figures 4a and 4b). The present observations are in line with previous findings [Bantignies et al., 1997; Cosultchi et al., 2005; H. G. Rueslåtten et al., A combined use of CRYO-SEM and NMR-spectroscopy for studying the distribution of oil an brine in sandstones, paper presented at SPE/DOE IOR Symposium, Society of Petroleum Engineers, Tulsa, Oklahoma, April 1994]. Figure 7. Time evolution of (a) dielectric constant and (b) resistivity of shale samples: O1A-CW (open circles) and L1_390-CW (open triangles) after initial water saturation; O1A-CW (solid circles) and L1_390-CW (triangles) 24 h later; quartz (solid squares) after initial injection and unchanged 24 h later (points superposed). ter/air contact angles are useful to distinguish shales that are hydrophilic or hydrophobic as well as for assessing the effect of sample treatments such as methylation or aging in oil Liquid-Liquid Extraction [20] The formation of an oil film on the surface of rocks results in a significant reduction of the specific surface energy and a substantial alteration of the wettability. This is clearly seen in the liquid-liquid extraction tests presented in Figure 4. In their natural state (before aging) montmorillonite and L1_390 shale show a high affinity for water, shale O1A, and quartz show moderately hydrophobic behavior with 40 50% of the particles in the water phase and kaolinite only 10% (Figure 4a). The hydrophobicity of the last three samples strongly increases after crude oil treatment: more than 90% of the kaolin particles are extracted in the oil phase and less then 20% of quartz and O1A shale powder is suspended in water. The L1_390-C shale and the montmorillonite were not permanently altered though, and 4.3. Spontaneous and Forced Imbibition [21] In hydrophilic samples, the rate of spontaneous imbibition is high, and limited by the permeability of the porous medium. On the other hand, if the sample is strongly hydrophobic then very little water will enter the sample, and consequently only a small amount of oil will be recovered. Behavior between these two extreme limits indicates an intermediate wetting state. In our tests the highest rate of oil recovery during spontaneous imbibition was measured for clean quartz followed by the most hydrophilic shale L1_390 (Figure 5). A lower spontaneous imbibition rate was found for methylated quartz, QM, and practically no oil displacement by water was observed with the hydrophobic shale O1A-C (Figure 5). A slower oil recovery was observed with montmorillonite in comparison with kaolin (Figure 5), which is the opposite of the wetting behavior seen in the liquid-liquid extraction tests (Figure 4). This difference is attributed to the significant swelling of the montmorillonite powder during hydration, which reduces pore and interparticle 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 packed particle beds (Figure 6). The degree of hydrophobicity of the sample can be quantified by the pressure required to break through the capillary resistance [Al-Bazali et al., 2008]. In the clean quartz samples, Q, the pressure profile characteristic of a Darcy flow begins to develop on commencement of water injection. That is, water immediately enters the sample with no capillary entry pressure to overcome. In the powdered and oil-aged shales, when water injection commences, the pressure rises up to a certain value from where a more gradual curve develops. For samples L1_390-C and O1A-C we deduce that it was necessary to overcome a capillary entry pressure of about 6 kpa and 10 kpa respectively. Thus the observed capillary entry pressure is larger for more hydrophobic samples. [23] After the initial injection, the pressure increases slowly as water penetrates the pack and then reaches saturation, with a plateau value for quartz and O1A-C shale; that is, these samples develop a Darcy flow. In sample L1_390-C the pressure continues to rise without reaching an equilibrated plateau and this we attribute to a gradual rehydration and swelling that reduces the permeability of the packed bed Dielectric Measurements [24] Two stages of water saturation were also identified by dielectric measurements at 10 MHz (Figure 7). At low 7of11

8 Figure 8. Nuclear magnetic resonance results following oil and water treatments on quartz model system. Transverse relaxation time (T 2 ) spectrum of (a) hydrophilic and (b) hydrophobic quartz presaturated with oil and then rehydrated. For reference, the T 2 peaks of quartz completely saturated with oil (gray dashed line) and quartz completely saturated with water (black dashed line) are also shown. water saturation, all samples (quartz and shales Figure 7a) have a low dielectric constant (10). As hydration progressed, the dielectric constant increased. The lowest dielectric constant was found for quartz, reflecting the small specific surface area of quartz compared with clay minerals: the latter have surface charges that become polarized at low frequency, contributing to the measured dielectric constant [Cosenza and Tabbagh, 2004]. At low and moderate saturation, quartz resistivity exceeds the value obtained for shales (Figure 7b), reflecting entrapment and isolation of the water phase by oil films. [25] For shales, increasing water saturation results in an increase in the dielectric constant and a monotonic decrease in resistivity for the hydrophilic shale L1_390-CW. Water effectively wets the surface after displacing the oil, ensuring effective charge mobility. On the contrary, for hydrophobic shale and quartz the resistivity decreases until the water saturation reaches 5% (Figure 7b). Then the resistivity essentially remains at a plateau (with a slight increase for quartz due to polarization of oil/water interfaces in porous space). This plateau in the resistivity indicates that in hydrophobic shale and quartz both liquids, oil and water, are redistributed in such a way that efficient conduction pathways through the interaggregate pore space cannot be established. This effect is illustrated even more strongly when samples were kept over 24 h to allow spontaneous liquid/liquid redistribution and equilibration within the pore space. While the hydrophilic sample L1_390-CW shows the 8of11

9 Figure 9. Nuclear magnetic resonance results following oil and water treatments on quartzmontmorillonite model system. Transverse relaxation time (T 2 ) spectrum after water saturation only (gray line); after oil saturation only (gray dotted line); and following oil/water displacement from an initially oil saturated sample following a period of rehydration (solid black line). same decrease of resistivity (as described above), for hydrophobic shale O1A-CW there is a significant increase in the dielectric constant and resistivity at 5 15% of water saturation. Thus in hydrophobic shale O1A-CW, water becomes spontaneously displaced from the surface and entrapped in rock pore space. During water injection both oil and water apparently become redistributed, depending on the rock surface wettability. This directly affects the dielectric properties of the system and can be used for monitoring the rock wetting behavior NMR Spectroscopy [26] NMR transverse relaxation time (T 2 ) spectra are presented in Figure 8 for quartz particles of mm diameter, the pore size is typically mm across. In this case both oil and water are located in the large pores. The T 2 distribution for quartz presaturated with oil and then gradually rehydrated is essentially a superposition of the signals obtained for each individual liquid (oil plus water). T 2 distributions are different for clean quartz (Figure 8a) and hydrophobic (methylated) quartz (Figure 8b). The water peak is higher for the hydrophilic quartz while in the hydrophobic sample the oil peak dominates. Therefore more oil is displaced by water from a pore space of equivalent geometry when the solid surface is hydrophilic. [27] The T 2 distributions acquired in the quartz-montmorillonite mixture (M+Q; 90% quartz, 10% montmorillonite) are shown in Figure 9. The light gray dotted line shows the oil peak ( ms) after oil saturation of the mineral bed. That can be compared to water saturated sample: The T 2 distribution, shown as a gray line, where distinct peaks of clay-bound water (below 10 4 ms) are easily distinguished from the water peak located within intergranular pores (T 2 > 10 5 ms). The black line shows the T 2 peak obtained after rehydration of the oil saturated M+Q sample. The resultant T 2 is a superposition of both the oil and water peaks. At the same time, the oil peak at T 2 <10 4 ms is displaced by the water peak. In this case both liquids are bound more tightly to the surface than in the case of coarse quartz (compare Figures 9 and 8). Liquid/liquid displacement occurs within a more confined pore space: the peaks are located at lower times due to the presence of clay particles in the intergranular pore space. [28] In crude oil-treated granular shale packs exposed to water by forced imbibition, the T 2 peak of the clay-bound water is even more distinct at T ms (Figure 10). It is much 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 T 2 = ms is higher in O1A-C. During water penetration into the crude-treated hydrophilic shale L1_390-C (Figure 10a), the oil peak at ms shifts to the left and decreases; at the same time the peaks for clay-bound water (T 2 <10 3 ms) and interparticle pore space water (T ms) grow. This probably reflects the displacement of the surface oil film by the water. On the contrary, during water penetration into the hydrophobic shale O1A-CW (Figure 10b), we observe negligible growth of the oil peak (T 2 = ms). Further water penetration was accompanied by a growth of the water peaks at T 2 >10 5 ms, reflecting filling of interparticle pore space, where water avoids the surfaces and does not cause liquid/liquid displacement. 5. Summary [29] Our results illustrate that shale samples are particularly challenging for wettability studies due to the difficulty in accessing the very restricted or tight pore space with different liquids. We have focused our work on understanding the fundamental interfacial phenomena before attempting direct measurements on shales in their intact state, and in situ conditions of elevated pressure and temperature. We 9of11

10 Figure 10. Nuclear magnetic resonance results following oil and water treatments on crude oil treated shales prepared as granular packs. T 2 spectrum of (a) hydrophilic sample L1_390 and (b) hydrophobic sample O1A shale. The solid line is the sample after oil treatment only, and the dashed line is the relaxation distribution after water injection. approached the problem using model systems and crushed shale particle packs to access polymineralic internal surfaces, employing a range of characterization methods each of which gives us a part of the overall picture. The sessile drop method is a very direct measure of relative wetting tendency but is effective for qualitative considerations only due to the effect of surface roughness and heterogeneity. Liquid/liquid extraction, spontaneous and forced imbibition are also relatively simple methods and require further information to confirm the surface properties in order that we can interpret their outcomes reliably. We used dielectric and NMR spectroscopy to obtain finer level information about which fluid was preferentially wetting the surfaces within the shale packs; the approach seems to have been validated by the good correspondence between what we deduce from these spectroscopic probes and what we observe in macroscopic measurements. [30] We have demonstrated that mineralogically and texturally distinct shales show different affinities for oil and water, ranging from strongly hydrophilic to strongly hydrophobic. By comparing pure minerals and natural shales, the influence of mineralogical structure and wettability of the individual shale components (clay minerals and quartz) on liquid/liquid displacement and liquid distribution inside granular shale packs was examined. 10 of 11

11 [31] Identifying petrophysical signatures of the prevailing wetting state and assessing the susceptibility to wettability alteration (e.g., by drilling fluids or during production processes) is highly desirable for shales as well as various reservoir lithologies. We have demonstrated that dielectric and NMR methods, used already for reservoir rocks, are applicable 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 highly consistent pattern, most of our work so far has focused on a detailed understanding of two end-member shales (L1_390 which is hydrophilic and O1A which is hydrophobic). We now need to understand how representative these two shales are when compared with a wider range of mudrock categories. The differences between O1A and L1_390 are not only mineralogical: while we do believe that the kaolinitic nature of O1A is important in its relative hydrophobicity, in line with previous studies on reservoir rocks ([Buckley, 2001; Zhang et al., 2000; H. G. Rueslåtten et al., presented paper, 2004]), there are also substantial differences in texture, with the L1_390 sample being extremely fine grained in its illitic matrix and O1A being relatively silty. We are therefore proceeding to apply our various screening methods on a wider variety of preserved and dried shales, to confirm and reinforce the predictive value of our results. 6. Conclusion [33] Our most important finding is that not all shales are the same as far as wettability is concerned. There is a significant variation in surface affinity for oil versus water, as determined by particle partition experiments, contact angle measurements on intact samples and a wide range of porous pack experiments on crushed samples. Initial correlations suggest that hydrophilic shales have a higher surface activity (surface charge density and specific area, combining to produce higher CEC), and that illitic and smectitic mudrocks are more hydrophilic whereas kaolinitic mudrocks are potentially hydrophobic, being wet preferentially by oil and retaining that tendency after hydration. The direct observations using optical and fluorescence microscopy as well as low vacuum SEM confirmed our interpretations of the petrophysical responses (NMR and dielectric) concerning those shales which are hydrophilic and chose which have a tendency to adsorb oil and even become oil wet. The petrophysical findings and microscopic observations are consistent with the measurements of the wetting and swelling tendencies of the powders and intact shales. [34] Acknowledgments. This paper is a contribution to the Joint Industry 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 to publish. The participation of Woodside and Chevron is through the Western Australian Energy Research Alliance. The Wealth from Oceans National Research Flagship is thanked for substantial financial coinvestment in the project. Origin Energy and the Geological Survey of Western Australia are thanked for the provision of the preserved shales cores used in the study. Finally, support from the ARC linkage scheme is gratefully acknowledged. References Al-Bazali, T. M., et al. (2008), Capillary entry pressure of oil-based muds in shales: The key to the success of oil-based muds, Energy Sources, Part A, 30(4), , doi: / Anderson, W. G. (1986a), Wettability literature survey Part 1: Rock/oil/ brine interactions and the effects of core handling on wettability, J. Pet. Technol., 38, Anderson, W. G. (1986b), Wettability literature survey - Part2: Wettability measurement, J. Pet. Technol., 38, Bantignies, J.-L., et al. (1997), Wettability contrasts in kaolinite and illite clays; characterization by infrared and X-ray absorption spectroscopies, Clays Clay Miner., 45(2), , doi: /ccmn Boult, P. J., et al. (1997), Capillary seals within the eromanga basin, AAPG Mem., 67, Buckley, J. S. (2001), Effective wettability of minerals exposed to crude oil, Curr. Opin. Colloid Interface Sci., 6(3), , doi: /s (01) Chen, J., et al. (2006), NMR wettability indices: Effect of OBM on wettability and NMR responses, J. Petrol. Sci. Eng., 52, , doi: /j.petrol Clennell, M. B., et al. (2006), Shale petrophysics: Electrical, dielectric and nuclear magnetic resonance studies of shales and clays, Trans. Annu. Logging Symp. SPWLA, 47th, paper KK. Cosenza, P., and A. Tabbagh (2004), Electromagnetic determination of clay water content: Role of the microporosity, Appl. Clay Sci., 26, 21 36, doi: /j.clay Cosultchi, A., et al. (2005), Adsorption of crude oil on Na+-montmorillonite, Energy Fuels, 19, , doi: /ef049825a. Diggins, D., and J. Ralston (1993), Particle wettability by equilibrium capillary pressure measurements, Int. J. Coal Prep. Utilization, 13(1 2), 1 19, doi: / Drummond, C., and J. Israelachvili (2004), Fundamental studies of crude oil-surface water interactions and its relationship to reservoir wettability, J. Petrol. Sci. Eng., 45, 61 81, doi: /j.petrol Fleury, M., and F. Deflandre (2003), Quantitative evaluation of porous media wettability using NMR relaxometry, Magn. Reson. Imaging, 21, , doi: /s x (03) Fuerstenau, D. W., et al. (1991), Characterization of the wettability of solid particles by film flotation. 1. Experimental investigation, Colloids Surf., 60, , doi: / (91)80273-q. Jada, A., et al. (2006), Montmorillonite surface properties modifications by asphaltenes adsorption, J. Petrol. Sci. Eng., 52, , doi: / j.petrol Kumar, K., et al. (2005), AFM study of mineral wettability with reservoir oils, J. Colloid Interface Sci., 289, , doi: /j.jcis Larter, S. R., and A. C. Aplin (2005), Fluid flow, pore pressure, wettability, and leakage in mudstone cap rocks, in Evaluating Fault and Cap Rock Seals, edited by P. Boult and J. Kaldi, pp , Am. Assoc. of Petrol. Geol., Tulsa, Okla. Liu, K., and P. Eadington (2005), Quantitative fluorescence techniques for detecting residual oils and reconstructing hydrocarbon charge history, Org. Geochem., 36, , doi: /j.orggeochem Manalo, F., et al. (2003), Soil wettability as determined from using lowfield nuclear magnetic resonance, Environ. Sci. Technol., 37, , doi: /es Morrow, N. R., and G. Mason (2001), Recovery of oil by spontaneous imbibition, Curr. Opin. Colloid Interface Sci., 6(4), , doi: /s (01) Neumann, A. W., and R. J. Good (1979), Techniques of measuring contact angles, Surf. Colloid Sci., 11, Shedid, S. A., and M. T. Ghannam (2004), Factors affecting contact-angle measurement of reservoir rocks, J. Petrol. Sci. Eng., 44, , doi: /j.petrol Sweeney, J. J., et al. (2007), Study of dielectric properties of dry and saturated Green River oil shale, Energy Fuels, 21, , doi: /ef070150w. Zhang, G. Q., et al. (2000), Interpretation of wettability in sandstones with NMR analysis, Petrophysics, 41(3), A. Borysenko, J. Ralston, and R. Sedev, Ian Wark Research Institute, University of South Australia, Mawson Lakes, SA 5095, Australia. (rossen.sedev@unisa.edu.au) 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, Australia. 11 of 11