Pore-Scale Distribution of Crude Oil Wettability in Carbonate Rocks

Article pubs.acs.org/EF

Pore-Scale Distribution of Crude Oil Wettability in Carbonate Rocks Rohini Marathe, Michael L. Turner, and Andrew Fogden* Department of Applied Mathematics, Research School of Physics and Engineering, Australian National University, Canberra ACT 0200, Australia S Supporting Information *

ABSTRACT: Carbonate reservoir rocks can exhibit highly variable and intricate pore systems at multiple scales, for which the distribution of wettability is largely unknown. To improve understanding of pore-scale wettability, a set of outcrop and reservoir carbonate plugs was treated by partial drainage of brine by crude oil and aging, for a variety of brine−oil combinations and conditions. Wettability alteration was imaged by high resolution scanning electron microscopy of the oil footprint remaining on internal rock surfaces after removal of oil and brine with mild solvents. The wettability distribution on the calcite microparticles, which comprised microporous regions and lined vugular macropores, showed a characteristic, but unconventional, mixed-wet pattern of distinct, coexisting oil-wet and water-wet subareas. Oil deposition was limited to the less crystalline (anhedral) faces of these particles, while neighboring crystalline (euhedral) facets remained water-wet. Supporting measurements of ζ-potential, contact angle, and initial brine saturation demonstrated that this face-selective alteration was formed by spontaneous drainage during aging, which appeared to favor oil deposition on facet edges and surrounding anhedral faces, thus preventing brine drainage from euhedral facets. This unifying pattern may simplify the integration of realistic wettability distributions into pore models of carbonate cores to predict oil recovery. Spontaneous imbibition of brine was sometimes observed to cause retraction of oil deposits on anhedral faces. The visualization of such changes can aid in designing the ionic composition of the flood brine to induce a shift toward water-wetting and enhance recovery from carbonates.

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tests, for example, the Amott-Harvey or USBM indexes.9 From such global responses, native-state or restored reservoir carbonates are commonly classed as oil-wet, intermediate-wet (lacking a strong preference for oil or water throughout), or mixed-wet (possessing domains preferring oil and others preferring water).11 Many studies have attempted to build an understanding of rock wettability from the underlying interfacial interactions in model systems (e.g. calcite to represent carbonate rock). The electrostatic interactions of oil and rock across brine can be modeled from measurement of ζ-potential of the two interfaces in isolation. Around neutral pH, calcite generally bears a positive charge,12,13 while crude oil interfaces are negatively charged by deprotonation of polar acid groups.13,14 Electrostatic attraction is thus expected to favor wettability alteration, especially given the strong specific binding of carboxylic acids to calcium ions15 (which also contributes to the abovementioned cleaning difficulties). Contact angle of crude oil drops on calcite crystals or polished marble in brine have been measured in various ways, to assess oil adhesion as indicative of wettability alteration, or to estimate brine-receding and -advancing angles during drainage and imbibition.13,16−18 Alteration yielding advancing angles in the intermediate- to oil-wet regimes has often been observed, although the strong dependence on the crude cannot be universally correlated to oil properties.19 Atomic force microscopy of the asphaltenic adsorbate or deposit on calcite has generally shown a

INTRODUCTION The oil recovery literature contains far fewer studies of carbonate rocks than of sandstones.1 The need to redress this imbalance is great, as carbonate reservoirs hold about one-half of the world’s oil reserves. Carbonates can exhibit extreme morphological complexity at all scales. Systems have been proposed to classify their rock textures and fabrics from deposition and diagenesis and to catalog their pore types within the categories of fabric-selective or -nonselective, and interparticle or vuggy.2−4 Oil recovery by carbonate waterflooding or spontaneous imbibition is strongly impacted by these various pore types present and their heterogeneous distributions.5−8 The coexistence of features as disparate as microporosity, vugs, and fractures poses special challenges. Characterization of recovery in terms of geological/petrophysical classifications requires that the dependence of the wettability state on these classifications is known. Moreover, predictive modeling of recovery from cores would require independent knowledge of the wettability distribution down to the pore scale. The wettability state is established during reservoir formation, as oil intruding into the brine-saturated pore space comes into contact with some rock surfaces. At these locations, adsorption or deposition of the oil’s more polar components, namely asphaltenes and resins, alters the local surface chemistry to more oil-wetting.9 Laboratory core analysis often attempts to restore the native reservoir state by first cleaning the rock to its original water-wetness (which is especially difficult for carbonates5,10) and then performing primary drainage of formation brine by crude oil to a relevant initial saturation, followed by aging. Core-scale quantification of wettability can be obtained from brine imbibition and oil secondary drainage © 2012 American Chemical Society

Received: June 27, 2012 Revised: September 19, 2012 Published: September 21, 2012 6268

dx.doi.org/10.1021/ef301088j | Energy Fuels 2012, 26, 6268−6281

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Table 1. Molar Concentration of Ions, Total Dissolved Salt (TDS), Ionic Strength (IS), and pH of the Four Brines, and pH of Their 10-Fold Dilutions (see the Supporting Information) brine

Na (M)

K (M)

Ca (M)

Mg (M)

Cl (M)

SO4 (M)

HCO3 (M)

TDS (g/l)

IS (M)

pH

pH dilute

CaCl2 SSW FW SW0Na

0 0.4791 1.0000 0.0500

0 0.0125 0.0050 0.0100

0.4505 0.0214 0.0290 0.0130

0 0.0563 0.0080 0.0450

0.9010 0.6472 1.0700 0.1260

0 0 0 0.0240

0 0 0.0090 0.0020

50.000 36.679 63.026 10.050

1.35 0.72 1.12 0.26

6.5 6.8 7.5 7.9

6.4 6.6 7.1 7.8

Table 2. Rocks and Their Pore Metrics from MICP (Mean and Standard Deviation of Two Samples) rock Edwards limestone Indiana limestone Austin chalk reservoir carbonate reservoir carbonate reservoir carbonate reservoir carbonate

abbrev.

1 2 3 4

EL IL AC RC1 RC2 RC3 RC4

porosity (%) 19.8 16.3 22.4 26.0 11.8 36.4 19.0

pore vol. (cm3/g)

± 0.4 ± 1.0 ± 1.5 ± 1.0 ± 0.6

0.094 0.075 0.109 0.139 0.049 0.217 0.087

± 0.002 ± 0.003 ± 0.020 ± 0.010 ± 0.001

throat diam., median (μm) 4.75 0.77 0.66 4.18 1.53 0.87 1.22

± 0.08 ± 0.00 ± 4.28 ± 0.01 ± 0.08

surface area (m2/g) 0.18 0.48 0.78 0.44 0.19 1.19 0.49

± 0.00 ± 0.03 ± 0.19 ± 0.03 ± 0.01

Initial brine saturation of the plugs partially drained by oil is measured using a titration technique sensitive to small volumes. (4) The pore-scale wettability distribution in the plugs after aging or spontaneous imbibition is imaged by SEM and compared to results of extraction and spectroscopy. Finally, potential applications of this improved knowledge of carbonate wettability to modeling of oil recovery are outlined.

continuous coating, which becomes thicker and more stable with oil aging.19 Other studies have inferred pore-scale wettability information from the macroscopic distribution of oil and brine in rocks. Quantitative statistical techniques include electrical response20 or NMR surface relaxation.21 Core-scale mapping of oil and brine during or after flow has been performed by nuclear tracer imaging,7,22 magnetic resonance imaging, or X-ray computed tomography (CT).6 Pore-scale imaging has been achieved using environmental- or cryo-scanning electron microscopy (SEM).23−25 Advances in microtomography (μ-CT) have bridged these two scales to provide three-dimensional (3D) images of carbonate plugs26 and oil and brine in their pores.27 These techniques support the view that the variations in size, geometry, connectivity, and type of pores coexisting in a reservoir carbonate generally lead to mixed-wettability. Three subclasses of this state have been termed mixed-wet-large, mixed-wet-small, or mixed-wet-fractional, depending on whether the alteration to oil-wetting occurs preferentially in macropores, micropores, or both, respectively. 25 Some carbonate studies suggested a mixed-wet-large distribution, due to small pores retaining brine by capillary forces5,23 or sizeexclusion of asphaltene particulates,24 while other work inferred a mixed-wet-small condition.8 The importance of such subtleties has been underlined by demonstrations of enhanced recovery from carbonates by design of the injection brine ionic composition to modify wettability.28 An approach attempting to integrate the studies of rocks and model substrate analogs has employed high resolution SEM to image their adsorbed/deposited asphaltenes from wettability alteration, after subsequent removal of the overlying oil and brine with mild solvents.29−31 In a preliminary investigation of two carbonates using this versatile visualization technique, a macroporous sucrosic dolomite exhibited a typical mixed-wetlarge wettability distribution, while a microporous limestone showed a more unusual form of mixed wettability.32 The current study extends this work to a large set of carbonate miniplugs and their brine/oil treatments, and is comprised of the following experimental steps: (1) Interactions of the chosen brine/oil combinations with the model substrate calcite are investigated by ζ-potential, contact angle, and SEM imaging of surface-bound asphaltenes. (2) Pore structure of the dry rocks is characterized by mercury porosimetry, μ-CT, and SEM. (3)

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EXPERIMENTAL SECTION

Oils, Brines, and Solvents. Two crude oils previously studied in the literature1,29,30,33−35 were used. The asphaltic crude denoted WP (Alaska) has a density of 0.9125 gcm−3, viscosity of 111 mPa·s, n-C6 asphaltene content of 6.3 wt %, and acid and base numbers of 1.46 and 2.49 mg KOH/g, all at room temperature.34 The more moderately asphaltic crude is from Cottonwood Creek (Wyoming), a dolomite reservoir of Permian age. This oil, denoted CW, has a density of 0.8874 gcm−3, viscosity of 24.1 mPa.s, n-C7 asphaltene content of 2.3 wt %, and acid and base numbers of 0.56 and 1.83 mg KOH/g at room temperature35 and was sparged with N2 to remove H2S. Four brines were prepared from analytical reagent grade (BDH AnalaR) salts with deionized water (Millipore Milli-Q), according to literature recipes in Table 1 for CaCl2 solution,33,36 simplified seawater1,33 (SSW), carbonate formation brine28 (FW), and seawater without NaCl (SW0Na).28 They were vacuum degassed and used at the pH in Table 1. Solvents used were decalin (decahydronaphthalene, 99%), nheptane (99%), methanol (99.8%), and toluene (99.9%), all from Merck, and dichloromethane (DCM, 99.5%, Chem Supply) and chloroform (99%, Sigma-Aldrich). Rocks. Two forms of calcite were used as model substrate, namely powder (99%, Univar) and a large rhombic crystal (Iceland spar). The powder was ground with mortar and pestle to submicrometer size, and the single crystal was cleaved into smaller rhombs of edge length ∼5 mm. Both were stored in CaCO3-saturated water. The rock study used seven limestone cores, three from North American outcrops and four from Middle Eastern reservoirs (Table 2). Small plugs were wet-cut and -cored from each, usually to 12 mm height and 5 mm diameter, and immersed in methanol for 2 h, and then vacuum-dried at 22 °C. The dry plugs were μ-CT scanned at the ANU facility.37 Offcut pieces ∼0.5 g were analyzed by Mercury Injection Capillary Pressure (MICP, Micromeritics AutoPore IV). Atomic composition was determined semiquantitatively from energy-dispersive X-ray spectroscopy (EDS) of carbon-coated slabs on a field emission SEM (FESEM, Zeiss UltraPlus Analytical) at 15 kV (Table 3). Outcrop plugs were cleaned of organics by immersion in toluene (75 °C), 50/50 (v/v) toluene/methanol (22 °C), and methanol (22 °C). The reservoir cores had been cleaned by the supplying companies. Their plugs were further cleaned of oil residues by 6269


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Table 3. Rock Average Atomic Composition from EDSa rock

Ca (%)

Mg (%)

Si (%)

Al (%)

Fe (%)

EL IL AC RC1 RC2 RC2 large crystals RC2 microporosity RC3 RC4

99.5 95.8 97.9 98.6 73.2 57.2 98.9 98.3 98.1

0.4 1.0 1.1 1.2 26.8 42.7 1.1 1.6 1.9

0.1 2.9 0.3

0.1 0.1

0.2 0.4

retracted at the same rate to record the brine-advancing angle. Two drops per brine/oil combination were analyzed. Brine−Oil Treatment of Plugs and Calcite. Each cleaned plug was vacuum saturated with the initial brine for at least 3 h, then transferred to stand in a glass vial (10 mm diameter) prefilled with 1.8 g of oil and with 1.0 g of clean quartz sand (F-30, U.S. Silica) at the bottom. The vial was centrifuged at the chosen speed for 20 min, followed by another 20 min with the plug inverted. After this primary drainage, the plug was transferred to a second vial containing 2.5 g of oil, and aged (sealed) for 14 days in an oven. In some cases, the first vial was used to determine the plug’s average initial water saturation (Swi), from the difference between the brine mass saturating the plug (measured gravimetrically) and the brine mass centrifugally drained from the plug into the sand bed. The latter was measured by pipetting off the oil above the bed and homogenizing the remaining oil and brine in the sand by adding 1.9 g of DCM and 0.7 g of methanol, from which the blend’s water content was determined by Karl Fischer titration (870 KF Titrino plus, Metrohm). If spontaneous imbibition was performed, the plug was immersed in the flood brine at the same temperature and duration (14 days) as the preceding aging step. In all cases, the oil and brine were then removed from the plug, first by transferring it to a vial of decalin with quartz sand at the bottom, at this same aging temperature, and centrifuging at 3750 rpm after one day. After 4 days of soaking, the exchanged decalin remained colorless. The plug was transferred to heptane (22 °C) and similarly centrifuged, then switched to 50/50 (v/v) methanol/water (22 °C) and again centrifuged, followed by soaking for 5 h and vacuum drying (22 °C). An analogous, but simplified, procedure was applied to individual calcite rhombs, without the above-mentioned centrifugations. Flooding was performed by advancing the flood brine over the macro-crystal surface at ∼10 μm/s and keeping it immersed for 1 day, after which decalin was added on top and the brine was withdrawn. The soaking in decalin and methanol/water was reduced to 2 h and 20 min, respectively. Analysis of Treated Plugs and Calcite. The calcite rhombs, and most plugs, thus treated were analyzed by FESEM. Plugs were wet-cut

S (%)

0.2 0.1

0.1 0.2

a

For RC2, separate averages are given within its large crystals and microporous regions.

immersion in toluene (75 °C) and DCM (22 °C), and then repeated. The extra cleaning resulted in at most only slight solvent discoloration. The plugs were centrifuged at 3750 rpm after each solvent switch and were finally vacuum dried (22 °C). Surface Chemical Analyses. The electrostatic potential of the calcite−brine or oil−brine interfaces was determined from the electrophoretic mobility in brine of 0.1 wt % suspensions of the ground calcite or 1.0 wt % emulsions of the oil (sonicated for 10 min), using a Zetasizer Nano-ZS (Malvern Instruments). For each brine in Table 1 and its 10-fold dilution, 11 replicates of 10−100 runs per system were acquired. Mobility was converted to ζ-potential via the Smoluchowski equation.38 Oil−brine−calcite contact angles were measured under ambient conditions using a contact angle goniometer (KSV Instruments) for a captive pendant oil drop on a cleaved calcite rhomb in a brine-filled fluid cell. The drop was pumped out upwardly at 0.2 μL/s from a stainless steel hooked syringe to contact the substrate and grown to 4 μL, directly after which the brine-receding contact angle was measured. After 30 min in contact, the drop was

Figure 1. (a) ζ-Potential of calcite powder and oil in the brines of Table 1 and their 10-fold dilutions, with prefix 0.1. (b) Receding (rec) and advancing (adv) angles of oil drops on calcite macro-crystals in the undiluted brines. 6270


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Figure 2. FESEM images (250 nm scale bars) of calcite macro-crystal surfaces after treatment with initial brine/oil/flood brine (if performed), for the combinations (a) CaCl2/CW, (b) CaCl2/CW/CaCl2, (c) SSW/CW, (d) SSW/CW/SSW, (e) SSW/WP, (f) SW0Na/WP, (g) FW/WP, (h) FW/WP/SW0Na.

having lowest pH, highest Ca2+ concentration and highest ionic strength, gives the weakest ζ-potential for oil, while the SW0Na brine, at the opposite extremes of pH, Ca2+, and ionic strength, gives stronger negative values. The reduction in Ca 2+ concentration and ionic strength from 10-fold dilution naturally increases ζ-potential negativity of oil, to more clearly display these same trends in the undiluted brines. ζ-Potential of calcite in Figure 1a is positive or close to zero. Its positivity generally diminishes with decreasing Ca2+ concentration in the undiluted brines and further diminishes on dilution. ζ-Potential of both oils and calcite is more strongly correlated to Ca 2+ concentration than to any other single variable (see the Supporting Information). The mean and standard deviation (from two replicates) of oil−brine contact angles on the natural rhombohedral cleavage faces of calcite macro-crystals are plotted in Figure 1b. Only the combinations matching those in the rock experiments were studied, namely CW and WP oils for SSW brine, CW for CaCl2 brine, and WP for FW and SW0Na brines. The oils again appear to behave similarly, and on the basis of advancing angle, they alter calcite to intermediate-wet or weakly oil-wet. This is consistent with the expected attraction of the predominately

in half crosswise and dried, for their internal rock surfaces and asphaltene deposits to be lightly sputter coated with platinum (around 2 nm thick) and secondary-electron imaged at 1 kV. Plugs without this coating gave very similar images, but of lower quality due to beam charging. Other uncoated plugs were immersed in azeotropic chloroform/methanol (87.3%/12.7% w/w, at 22 °C) for 4 days to extract asphaltenes. Absorbance of the extracted solutions was measured by UV−visible spectrophotometry (Shimatzu UV3101PC) and converted to asphaltene concentration using calibration standards, prepared by precipitating the oil’s asphaltenes in heptane.

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RESULTS AND DISCUSSION Calcite−Oil Interactions. Oil−brine ζ-potential generally depends on (a) pH, which dictates the deprotonation and protonation of acid and base groups of the adsorbed asphaltenes, (b) specific ion chemistry, which causes differential binding of ions to these organic molecules (especially Ca2+ to deprotonated acids), and (c) total ionic strength, which increases the electrostatic screening of the double layer.12−15 The mean and standard deviation (error bars) of ζ-potential for the two oils and calcite in the four brines of Table 1 and their 10-fold dilutions are plotted in Figure 1a. Both oils show similar, negative values for a given brine. The CaCl2 brine, 6271


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Figure 3. μ-CT images of plugs, showing a vertical slice along the cylinder axis, for the outcrop carbonates (a) Edwards limestone (EL; 5 mm diameter at 3.3 μm/voxel resolution), (b) Indiana limestone (IL; 5 mm at 3.0 μm/voxel), (c) Austin chalk (AC; 3.7 mm at 2.1 μm/voxel). Scale bars are 0.5 mm.

The nanoscopic domains of stranded brine presumably correspond to the gaps in coverage in these images. The extent of asphaltene deposition is sufficient for all substrates to be regarded as oil-wet to some extent, in line with Figure 1. However, deposits from CW oil (Figure 2a, c) are thicker and coarser than those from WP (Figure 2e−g). The latter are texturally similar to deposits from this same oil on glass and kaolinite in previous studies.29,30 Deposition tendency is primarily dictated by (a) electrostatic interfacial interactions, which are similar for the two oils (Figure 1a) and (b) asphaltene stability against surface precipitation, which is also similarly strong (judging from CW and WP data in the CO-wet database39,40). Their distinction in Figure 2 presumably arises from differences in the later stages of asphaltene accumulation and rearrangement within the deposit during aging. For the flooded counterparts (Figure 2b, d, h), calcite coverage by asphaltenic residuals is reduced, implying that the flood induces a shift toward water-wetness. The residual demonstrates partial retraction and detachment of the oil film due to flooding brine connecting with and expanding the preexisting nanodomains of initial brine. This film decomposition is most striking for WP oil (going from Figure 2g to h), which exhibits fluidic textures similar to those after flooding of silicate substrates.29,30 The less dramatic effects for CW oil (going from Figure 2a to b, or from c to d) are possibly due to reduced mobility of its thicker, more particulate oil film. The

oppositely charged oil and calcite interfaces. Moreover, the two cases with highest receding angles, for WP in FW or SW0Na brines, correspond to the largest difference between oil and calcite potentials in Figure 1a. This suggests that some oil adhesion and wettability alteration may develop at even this early stage. However, after 30 min in contact, the advancing angle (and hysteresis) is lowest for these same two cases. One interpretation is that the premature adhesion may trap a substantial fraction of brine as films or droplets between local contact points, while the less-oppositely charged interface pairs in the other cases may allow fuller drainage prior to adhesion, leading to a stronger joint. To more closely mimic the treatment of the rock plugs, fresh calcite rhombs were drained of their initial brine, aged in oil (for 14 days at 60 °C), optionally immersed in flood brine, and then solvent rinsed. Representative FESEM images of the substrate-bound oil residues on the natural rhombohedral cleavage faces are given in Figure 2 for the eight combinations of initial brine/oil/flood brine used in rock experiments. In all cases, calcite is uniformly decorated, but incompletely covered, by residues in the form of asphaltenic nanoparticle aggregates, even in the vicinity of step defects. For samples without flooding (Figure 2a, c, e−g), the above-mentioned initial brine trapped under the collapsing oil film can gradually drain across the substrate during aging. However, drainage progressively slows due to concomitant increase in asphaltene deposition. 6272


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Figure 4. μ-CT images of plugs, showing a vertical slice along the cylinder axis, for the reservoir carbonates (a) RC1 (4 mm diameter at 2.3 μm/ voxel resolution), (b) RC2 (3 mm at 1.7 μm/voxel), (c) RC3 (5 mm at 3.6 μm/voxel), (d) RC4 (5 mm at 3.0 μm/voxel). Scale bars are 0.5 mm.

fact that the flood brine is the same as the initial brine in these two CW cases may also limit change. Rock Fabrics and Pore Characteristics. All rocks except RC2 are essentially monomineralic calcite (Table 3). A representative slice of a 3D tomogram (comprising 20483 voxels) is shown in Figures 3 and 4 for the outcrop and reservoir rocks. The brightest features, having highest X-ray attenuation, are solid calcite, while the darkest features are macropores. Intermediate grayscales correspond to varying degrees of subresolution calcite microporosity. FESEM images in Figure 5 illustrate typical features at higher resolution, which will lead on to wettability distribution analysis from even higher magnification micrographs in a following section. These latter micrographs were acquired in pores at depths well below the plug face, to avoid cutting and handling damage. The averaged pore volume distribution of all pore throat sizes from MICP is plotted in Figure 6, and the key indices are listed in Table 2. Indiana limestone (IL) is a standard model rock for oil research,41,42 while Edwards limestone (EL) has been suggested as an alternative.1 Both have the depositional texture of grainstones.2 As shown in Figure 3a, EL particles (grains) are fossil shells, and interparticle porosity is largely occluded by calcite cement. Its pore space is vuggy,4 exhibiting separate and touching vugs from intrafossil and moldic pores. Some remain empty, some are infilled with calcite, and others house coarse microporosity. Figure 5a shows an empty vug (lower left) and

another that is almost completely cement-filled (upper right). Vug walls for EL and all other rocks are lined by calcite microparticles; thus, neighboring vugs (e.g., Figure 5a) are connected via the intercrystal microporosity of their linings. The EL pore metrics in Table 2 agree with the literature,1,43 which reports air permeability ∼13 mD. While IL also contains fossil shell particles, oolites are prevalent (Figure 3b). Intraparticle cementation is more extensive than for EL, thus IL’s macroporosity is primarily interparticle.4 The microporous layers encapsulating particles are usually finer than for EL and are only distinguished in μ-CT as darker gray rings. Figure 5b shows an oolite remnant with concentric lamellae of fine calcite microparticles arranged radially, separating its microporous interior (upper) from the interparticle pore space containing coarse recrystallized calcite (lower). The more pronounced fine microporosity of IL is also evident from its throat sizes in Figure 6a. The metrics in Table 2 are intermediate to reported ranges, which give air permeability of 4−57 mD.41 Outcrop Austin chalk (AC) is comprised of small, well sorted, spheroidal or ellipsoidal plankton shell remnants, which are strongly cemented and partly recrystallized. Its fabric resembles a scaled-down version of IL, in which the interparticle (and occasional intraparticle) macro/mesopores are just resolvable by μ-CT (Figure 3c), and intercrystal microporosity is much more prevalent throughout the matrix (Figure 6a). Some clay is also present in both rocks (Table 3). 6273


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Figure 5. FESEM images (20 μm scale bars) of various forms of pore space in the rocks (a) EL, (b) IL, (c) AC, (d) RC1, (e) RC2, (f) RC3, (g) RC4.

Figure 5c shows a packing of its particles, again with outer shells of radially aggregated fine microparticles, and cemented or microporous interiors. Of the reservoir carbonates, RC3 is also a chalk. Resolvable fossil remnants in Figure 4c are sparse. The mainly featureless gray regions dominating the tomogram correspond to fine calcite microparticles, aggregated as very small fossil skeletons, including calcite-plated coccoliths (middle of Figure 5f) or their fragments. The high porosity of RC3 (Table 2) and its intercrystal pore throats around 1 μm are typical of chalks. Reservoir carbonate RC1 has the most core-scale heterogeneity, giving rise to a markedly bimodal throat size distribution (Figure 6b). Regions of this grainstone (Figure 4a lower) comprise relatively intact, poorly sorted, fossil particles, with prevalent interparticle macropores and some intrafossil vugs. In other regions (Figure 4a upper), fossils are more fragmented, compacted, recrystallized, and cemented, with a greater occurrence of small moldic pores and microporosity. Intercrystal micropores are present in the matrix and vug walls (Figure 5d). The fabric of RC4 (Figure 4d) is somewhat similar to the less permeable regions of RC1. The μCT resolvable pores are principally small vugs, from intact fossil

skeletons and moldic pores, in a matrix of calcite microparticles and cement (Figure 5g). The RC2 rock in Figure 4b has the texture of a grainstone of poorly sorted fossils, which diagenically transformed to large crystals via dolomitization (judging from their high Mg content in Table 3). Porosity is low (Table 2), as it is mainly limited to calcite microparticle regions between dolomitic crystals (left and right in Figure 5e). Initial Saturation of Plugs. The cleaned plugs saturated with initial brine were primary drained by centrifugation in oil. Samples for which the resulting plug-averaged initial water saturation, Swi, was measured (prior to aging) are listed in Table 4, giving the mean and standard deviation from sister plugs. The coefficient of variation of 7% is acceptably low, considering the limits to accuracy for plugs with such high external surface/ internal volume ratio. Furthermore, the results show the expected trends of Swi decreasing with centrifuge speed and being largely invariant to the oil (Figure 7a). The saturations in Table 4 average over 60%, and all are substantially higher than typical levels in oil-producing carbonate reservoirs.1 This reflects the relatively low spin speeds used and possibly also the relatively short (40 min) duration. A study43 of centrifugal drainage of EL cores reported equilibration times on the order 6274


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Figure 6. Averaged mercury intrusion curves for the (a) outcrop and (b) reservoir carbonates. Symbols denote the average value of the smallest throat diameter penetrated by CW oil via centrifugation at 2000 (diamonds), 2500 (triangles), or 3750 rpm (squares), inferred from the measured Swi values.

Figure 7. (a) Initial water saturation of plugs of three rocks after centrifugation in oil at the given rpm values. (b) Two estimates of the diameter of the smallest oil-penetrated pore throat, compared to their 45° equivalence line.

Table 4. Initial Water Saturation of Plug Samples and Two Estimates of Smallest Oil-Intruded Pore Throat rock

initial brine

crude oil

speed (rpm)

EL EL EL EL EL EL IL IL AC AC RC1 RC2 RC2 RC3 RC4

SSW SSW SSW SSW SSW SSW SSW SSW SSW SSW SSW SSW FW SSW FW

CW CW CW WP WP WP CW CW CW WP CW CW WP CW WP

2000 2500 3750 2000 2500 3750 2000 2500 3750 3750 3750 3750 3750 3750 3400

Swi (%) 70.3 60.1 35.8 62.1 59.5 30.2 73.1 71.0 73.4 74.7 44.2 53.2 52.2 86.9 75.7

± 3.8 ± 8.4 ± 2.3

± 7.9 ± 3.9 ± ± ± ± ±

5.1 1.2 7.1 0.8 1.8

throat diam. (μm) MICP

throat diam. (μm) centrif.

6.39 5.58 3.40 5.78 5.56 2.82 4.99 4.51 2.57 2.76 1.75 1.61 1.58 1.07 1.90

6.89 4.41 1.96 8.38 5.36 2.38 6.89 4.41 1.96 2.38 1.96 1.96 1.74 1.96 2.12

Young−Laplace equation to pore throat diameter, d, of capillary tube drainage: Pc =

4γ cos θ 1 Δρω 2(R e 2 − R i 2) = 2 d

(1)

Here, ω is the angular speed, and Ri and Re are the radial distances from the axis of rotation to the inflow and outflow (bottom of sand pack, where Pc = 0) faces. Also, Δρ is the brine−oil density difference, γ is its interfacial tension, and θ is the receding contact angle (Figure 1b). The Pc(Swi) data from centrifugation can be assessed against the MICP equilibrium curves, after normalization by the factor 4γ cos θ in eq 1 to allow a comparison of inferred values of the smallest intruded throat diameter. The centrifuge estimate from eq 1 is listed in Table 4, alongside the alternative MICP-derived estimate. The latter is the smallest mercury-drained throat size at the fraction of mercury intrusion matching the oil intrusion measured after centrifugation (i.e. (100 − Swi)%). This is illustrated for each CW oil centrifuge experiment in Table 4 by the symbols on the MICP curves in Figure 6. The centrifuge and MICP estimates are plotted in Figure 7b. Their correlation is not strong, but it is reasonable, given the uncertainties in Swi stemming from the small volumes and heterogeneities of plugs, the seven different rocks comprising the data points, possible slightly incomplete reservoir core cleaning,5 and the lack of Hassler-Brunner correction of plug-averaged Swi to its inflow face value.44 This provides semiquantitative validation of our mini-plug protocol, and suggests that the centrifuged saturations are near equilibrium. Imaging of Asphaltene Deposits on Rock Surfaces after Aging. A large set of plug samples for each rock were

of days; however, the volume of such cores is more than 300 times that of our mini-plugs, and the final averaged Swi values are comparable to those for EL in Table 4. Higher spin speeds of forced drainage were not used here, in order to examine the tendency of brine-filled carbonate micropores to spontaneously drain during aging, thus allowing an assessment of their oil affinity (as discussed below). The equilibrium capillary pressure, Pc, at the inflow plug face is given by Hassler and Brunner,44 and is related via the 6275


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contact times suffice to alter angles to above 90°, favoring spontaneous drainage. Prolonged aging is mainly required to facilitate expulsion of brine to provide continued access for the wettability alteration. Spontaneous drainage would naturally be much less widespread in standard-sized cores, for which such high Swi values before aging would preserve large brine-filled subvolumes of unaltered wettability after aging. However, spontaneous drainage may contribute to the observed variable efficiency of core aging protocols.22 Core wettability alteration is (a) mostly uniform and complete if crude oil is pumped through during aging (giving an extra pressure drive for the ongoing drainage), (b) prone to heterogeneities (possibly caused by the spontaneous effect) for immersion in static oil, and (c) very incomplete for static aging without excess oil (which precludes further drainage).22 Each individual calcite microparticle, irrespective of morphology, generally has a subhedral texture. It thus possesses a mix of flat, smooth, well-formed crystal faces, termed euhedral, and curved, rough, poorly formed faces, termed anhedral. In Figure 8a, asphaltenic deposit is apparent as the characteristic nodular film on anhedral faces and as thicker build-up on the bounding edges of euhedral faces, while the euhedral faces are mainly or completely clean. All imaged microparticles for all samples (e.g., Figures 9 and 10) follow this same pattern of face-selective wettability alteration. In a preliminary FESEM investigation,32 it was suggested that such a distribution could arise from the differing populations and arrangements of calcium and carbonate ions exposed at these various faces, which could exhibit differing affinities for the oil’s polar molecules across the brine. However, from the larger set of images in the current study, euhedral faces appear to be deposit-free regardless of their calcite crystal lattice orientation and ionic composition, implying that an alternative mechanism is at play. The proposed alternative mechanism for this unifying trend of patterned pore-scale wettability is illustrated in Figure 8c. From Figure 1a, the oil and ground calcite interfaces are predominately oppositely charged and mutually attractive. During spontaneous drainage, the thinning brine film surrounding a calcite microparticle is thus expected to be unstable everywhere, but should rupture first at the locations where the disjoining pressure is most attractive. Flat facet edges have the highest density of incomplete lattice bonds available for binding acid and base groups at the oil interface. This strong chemical affinity is reinforced by the extra attraction of the oil meniscus as it conforms to the strongly convex local curvature at these edges.25 Film rupture should thus begin at euhedral face edges, consistent with the heavy deposition seen there. Anhedral faces also possess high-energy lattice defects, so drainage then proceeds across these faces, using their roughness as conduits, which generally results in a reasonably complete coverage by deposits there. On the other hand, the oil-wet rims around euhedral faces prevent drainage of their brine films, which remain and protect against wettability alteration. FESEM images often show that this demarcation is less pronounced for larger calcite crystals (∼10 μm or above). For example, the large euhedral faces in Figure 8b bear scattered asphaltenes, despite the edge deposition. These brine films are probably sufficiently extensive to accommodate some local rupture, with brine accumulating between deposits. For all comparable rock samples, deposits on microparticles for WP oil appear to be locally somewhat thicker than for CW. The aged calcite macro-crystals in Figure 2 showed the opposite trend. These rhombic single crystals are presumably a

prepared for FESEM of the deposits (i.e. the footprint of wettability alteration). The initial brine/oil combinations analyzed were SSW/CW, SSW/WP, FW/WP, and CaCl2/ CW, and the four centrifugation speeds were 2000, 2500, 3400, and 3750 rpm. Aging was at 60 °C (for AC, RC1, RC2, and RC3 rocks) or 75 °C (for EL, IL, AC, and RC4 rocks) for 14 days, unless otherwise stated.

Figure 8. FESEM images (250 nm scale bars) of deposits on (a) RC2 with CW oil, and (b) RC1 with WP, both with SSW brine drained at 3750 rpm and aged at 60 °C. (c) Diagram of proposed mechanism.

The representative subset of FESEM images in Figures 8−10 illustrates the wettability distributions. The textures of the asphaltene nanoparticle aggregates forming the deposits (on calcite rhombs and on rock) are only discernible at very high magnification. The field of view of each image is thus limited to several micrometers, that is, a few calcite microparticles. However, the observations pertain to both micropores and macropores, since the walls of the latter are lined by microparticles. Deposits are never observed here to cover all internal rock surfaces, but are very pervasive. The high Swi values before aging (Table 4) are thus not a hindrance to substantial alteration toward oil-wetting, provided that the plug remains in contact with bulk oil to draw upon during aging. This is consistent with the contact angle results (Figure 1b), which showed that short 6276


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Figure 9. FESEM images (250 nm scale bars) of deposits on calcite microparticles for (a, b) EL, drained at 2500 rpm and aged at 75 °C; (c, d) RC1 and (e, f) RC2, both drained at 3750 rpm and aged at 60 °C. The left column (a, c, e) and right column (b, d, f) are for CW and WP oil, respectively, and the brine is SSW in all cases.

faces is even thinner than for IL; its fine nodule texture is only just discernible in Figure 10b, despite the higher magnification. This image is taken from the center of the micrograph in Figure 5c, within the radial aggregates of the fossil shell. Similarly thin coverage of anhedral faces is also prevalent for microparticles inside the fossils and in the matrix. Deposits also cover the clay particles seen. Sister AC samples were aged at 60 or 75 °C; Figure 10b corresponds to the higher temperature. For 60 °C the deposits are even less developed, suggesting that wettability alteration is less complete. For the reservoir carbonate RC1, asphaltenes on the anhedral faces of microparticles in vug walls and the matrix are relatively heterogeneously distributed, with some (Figure 9c, d) bearing thick, uneven deposition, while others are more lightly decorated. Many surfaces are littered with asphaltene strings (bottom left of Figure 9d), which presumably formed along edges but were dislodged during solvent soaking. For RC2, microparticles are only present between the large dolomitized crystals; Figure 9e is a close-up of the center of the microporous region in Figure 5e. RC2 exhibited locally thick deposits on anhedral microparticle faces, especially for SSW/ WP (Figure 9f). Deposits on RC3 generally appeared thinner than on the other reservoir carbonates. Figure 10c, d shows zoom-ins of the coccolith near the center of Figure 5f, showing the exclusion of deposition from the euhedral faces of calcite

reasonable indicator of depositional tendencies on large euhedral faces in rocks (e.g., Figure 8b), but have less relevance to the small anhedral faces, which may dominate wettability alteration. Figure 9 compares deposits from CW and WP oils under the same conditions on three rocks. Figure 10 provides images of the other four rocks in various aged states. These, and related samples not shown, are discussed below. For EL rock, the deposits are generally fairly light, and somewhat difficult to distinguish in Figure 9a, b. Higher magnification confirms that they selectively cover only anhedral faces, extending to the boundaries of microparticles and to their prismatic tube-like nanopores. For EL experiments (with CW oil), which varied centrifugation speed from 2000 to 2500 to 3750 rpm, microparticles lining vug walls consistently received deposit, while those comprising intravug microporosity exhibited progressively increasing oil exposure. For IL rock samples, most anhedral microparticle faces are covered with asphaltenics, but more thinly than for EL, probably due to the prevalence of less accessible intraparticle microporosity in IL. Figure 10a is a close-up of these light deposits on microparticles comprising the radially oriented aggregates within the layer of the oolite at the center of Figure 5b. Coarser recrystallized particles (e.g., bottom right of Figure 5b) show a sparse, incompletely covering, scattering of deposits on their large euhedral faces, analogous to Figure 8b. For AC rock, the deposit selectively covering only the anhedral microparticle 6277


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Figure 10. FESEM images (250 nm scale bars) of deposits on microparticles for (a) IL (SSW/CW, 2500 rpm, 75 °C), (b) AC (SSW/CW, 3750 rpm, 75 °C), (c, d) RC3 (SSW/CW, 3750 rpm, 60 °C), (e) RC4 (FW/WP, 3400 rpm, 75 °C), and (f) RC4 (CaCl2/CW, 3400 rpm, 75 °C for 7 days).

Figure 11. FESEM images (250 nm scale bars) of residues on microparticles after spontaneous imbibition for (a) RC2 (FW/WP/SW0Na, 3750 rpm, 60 °C) and (b) RC4 (FW/WP/SW0Na, 3400 rpm, 75 °C).

presumably corresponding to thin lenses of brine that were unable to drain during this shortened aging. For both the FW/ WP and CaCl2/CW combinations of initial brine/oil in Figure 10e, f, additional experiments on RC4 used instead a 90-day aging at 90 °C. The undrained spots for CaCl2/CW were no longer apparent, while deposition for FW/WP remained similar to Figure 10e. This extended treatment at elevated temperature did not result in deposit encroaching on euhedral faces. Comparison of Asphaltene Residuals on Rock Surfaces after Spontaneous Imbibition. Two reservoir rocks, RC2 and RC4, having FW/WP as initial brine/oil, were

plates. Other, more isotropic microparticles in RC3 offer a greater fraction of anhedral surface for deposition. For the reservoir carbonate RC4, microparticles building the vug walls and matrix (Figure 5g) exhibit deposition analogous to RC1 and RC2. Asphaltenes from WP oil appear to overcompensate for their avoidance of euhedral faces by depositing excessively on anhedral faces (Figure 10e). Figure 10f is of RC4 with CW oil and CaCl2 initial brine, aged for only 7 days at 75 °C,32 that is, half the usual duration. Its deposits on anhedral faces are characteristically lighter than for WP, but now, they also exhibit roughly circular uncovered spots, 6278


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Table 5. Relative Amount of Asphaltenes Solvent-Extracted from Plug Samples rock

initial brine

crude oil

speed (rpm)

aging temp. (°C)

EL EL EL EL IL AC AC RC1 RC1 RC2 RC2 RC2 RC3 RC4 RC1 RC2 RC2 RC3 RC4

SSW SSW SSW SSW SSW SSW SSW SSW SSW SSW SSW FW SSW FW SSW SSW FW SSW FW

CW CW CW WP CW CW WP CW WP CW WP WP CW WP CW CW WP CW WP

2000 2500 3750 2000 2500 3750 3750 3750 3750 3750 3750 3750 3750 3400 3750 3750 3750 3750 3400

75 75 75 75 75 75 75 60 60 60 60 60 60 75 60 60 60 60 75

centrifuged (to the Swi in Table 4) and aged for 14 days, as usual, after which the plugs were immersed in SW0Na brine for 14 days at this same temperature. The asphaltenic textures on many microparticle anhedral faces are as in Figure 11. Relative to the deposit after aging (e.g., comparing Figures 10e and 11b), spontaneous imbibition removes some deposit with the bulk oil, leaving partially retracted and coalesced remnants. The reduction in asphaltene coverage decreases oil-wetness to partially reinstate the original water-wet calcite. The changes resemble those for the same treatment of calcite rhombs in Figure 2g, h. However, the effect is less striking in the rocks, presumably because flood brine only enters a fraction of the pores, and oil film retraction is limited by the finite extent of faces. Other RC4 plugs, aged for 90 days at 90 °C and then brine-immersed for 90 days at 90 °C, also showed evidence of deposit retraction and removal, for this FW/WP/SW0Na combination of initial brine/oil/flood brine or CaCl2/CW/ CaCl2. The results are qualitatively consistent with literature studies of an outcrop chalk (also having this same FW as connate brine), for which spontaneous imbibition in this same SW0Na brine induced a shift to increased water-wetness.28 Asphaltene Extracts from Rock. Images of deposits should be partnered with independent statistical measures. To this end, the dry plugs were extracted in azeotropic chloroform/methanol to determine absorbance of the dissolved asphaltenics from UV−visible spectrophotometry (over 800− 300 nm wavelengths). Absorbance was converted to concentration by normalization to dilute solutions (in this same azeotropic blend) of the oil’s asphaltenes, which exhibited Beer−Lambert linearity. Samples for which this analysis was performed are listed in Table 5, along with the inferred mass (mg) of asphaltenes per dry plug mass (g) or rock surface area (m2, from Table 2). Figure 12 plots the key results. This method can only compare the extractable fraction of asphaltenes, and its underestimation of the true amount may vary with carbonate and oil types.5,10 Samples without spontaneous imbibition will first be discussed. The amounts in Table 5 are always higher for WP oil than for CW under the same conditions. This agrees with the FESEM observation that WP leads to thicker deposits,

flood brine

asphaltene (mg/g)

asphaltene (mg/m2)

SSW SSW SW0Na SSW SW0Na

0.032 0.047 0.082 0.179 0.091 0.124 0.649 0.451 0.519 0.238 0.462 0.184 0.222 0.541 0.437 0.243 0.422 0.317 0.707

0.17 0.25 0.45 0.97 0.19 0.16 0.83 1.04 1.19 1.27 2.48 0.99 0.19 1.11 1.00 1.30 2.26 0.27 1.45

Figure 12. Mass of extracted asphaltenes per plug surface area, after centrifugal drainage at the given speed (rpm) and aging, for (a) four rocks, all with SSW as initial brine and without subsequent spontaneous imbibition (S.I.), and (b) four reservoir rocks, without or with spontaneous imbibition, for two initial brine/oil/flood brine combinations.

which are sometimes more piled-up and weakly bound to the rock, and thus more extractable. The outcrop rocks usually give lower amounts than their reservoir counterparts. For EL, the values are generally low, even relative to the rock’s small surface area, and increase with centrifuge speed as expected. The amounts per rock area for IL and AC are similar to, but slightly lower than, their EL counterparts. These trends are consistent with the thinness of CW asphaltenics lining anhedral faces in FESEM images. The overall amount extracted from the outcrops thus increases with their surface area but less than predicted by a simple linear scaling. This is presumably due to 6279


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the concomitant increase in Swi (Table 4) with surface area, which delays wettability alteration. For RC1, amounts in Table 5 are high, especially for CW oil, reflecting the locally thick, heterogeneous deposition in Figure 9c, d. The values for RC2, relative to its limited surface area, are generally highest of all rocks. This confirms that it presents the starkest contrast in pore-scale wettability, with anhedral faces bearing thick deposits while the prevalent euhedral faces are largely deposit-free (e.g., Figure 9f). Note though that the RC2 value in Table 5 with FW as initial brine is less than for SSW, with all other variables fixed. This may reflect a less extensive spontaneous drainage due to its lower contact angle hysteresis in Figure 1b. For RC3, the amount per surface area in Table 5 is lowest of all reservoir carbonates, as was also inferred from FESEM. This rock possesses the most pronounced microporosity, and accordingly has the highest Swi in Table 4, from which its 14-day aging at 60 °C was probably insufficient to fully develop deposits on anhedral faces. The amount per surface area for RC4 in Table 5 is similar to the analogous RC2 sample, as were the FESEM images. The five samples at the bottom of Table 5 underwent spontaneous imbibition and are plotted in Figure 12b beside their non-flooded counterparts. For the SSW/CW/SSW combination of initial brine/oil/flood brine, spontaneous imbibition gave no change in extracted asphaltenes, while for FW/WP/SW0Na the amounts increase. In FESEM, these same latter samples showed deposit retraction after spontaneous imbibition (Figure 11). Their counterintuitive increase in extracts partly stems from the distinction between asphaltene coverage and extractable amount. While spontaneous imbibition can decrease coverage, and thus oil-wetness, the resulting retracted residuals are presumably more readily extracted (e.g., compare Figure 2g and h). While FESEM was not performed on the SSW/CW/SSW rock samples, the lack of change in extracts after spontaneous imbibition suggests that their asphaltene distributions are mainly unperturbed. This may be due to the less fluidic, more particulate nature of CW oil deposits, clearly visible in FESEM on the calcite rhombs (Figure 2c and d), combined with the use of the same SSW as initial and flood brine. Applications to Wettability Typing and Modeling. Increased capillary pressure of primary drainage increases rock oil-wetness by forcing oil into smaller pores and by favoring rupture of brine films; aging aids the latter process.9,22,24,45 Aging can also aid the former process, as the ongoing wettability alteration can further reduce Swi by facilitating spontaneous oil penetration into undrained pores. By either pathway, the wettability distribution may pass from water-wet to mixed-wet-large (i.e., with most oil-wetness in larger pores) toward (pore size-independent) mixed-wet-fractional.25 In carbonates, spontaneous wettability alteration of calcite particles increases with reduction in their size and/or face crystallinity. Alteration of carbonates with macro- and micropore walls built from similar particles would be expected to terminate at a mixed-wet-fractional state. Rocks with macropores bounded by larger or more crystalline particles than in micropores should, by spontaneous means, ultimately attain a mixed-wet-small state (i.e., with most oil-wetness in smaller pores), but may instead be mixed-wet-fractional as initial forced drainage is biased toward alterating these large, flat particles. For a carbonate plug, an experimental procedure for quantitative mapping of its pore-scale wettability distribution would begin with FESEM imaging of the asphaltene coverage

of a representative sampling of larger surfaces and calcite microparticles. The coverage of the former may be quite similar throughout the plug, if all large surfaces were drained by oil. If the microparticles conform to the pattern in this study, their euhedral faces will be clean, while anhedral faces will be either covered or clean, depending on whether or not oil penetrated the given subvolume. Three local coverage values may thus suffice to describe plug wettability. Lower-resolution techniques (e.g., nano/micro-CT) capable of distinguishing face morphologies could then be used to populate the plug with these facetagged values. An oil−brine advancing contact angle must be assigned to each of these three face-coverage scenarios to predict waterflood recovery. While goniometry on a clean or oil-treated calcite crystal is the standard approach,13,16−18 deposits on these model substrates may differ from those on carbonate rock faces.

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CONCLUSIONS

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ASSOCIATED CONTENT

The pore-scale distribution of wettability alteration in carbonate rocks was visualized by FESEM of asphaltenic deposits for a large set of outcrop and reservoir rock plugs, combinations of initial brine and crude oil, and centrifugal drainage and aging conditions. This technique was supported by characterization of the rocks by μ-CT, the interfaces and wetting by ζ-potential and contact angle goniometry, the drained amount by Karl Fischer titration, and the deposit amount by UV−visible spectrophotometry. Key conclusions are as follows. (1) Electrostatic attraction of the oppositely charged oil and calcite interfaces drives wettability alteration and further drainage of brine during aging. (2) The spontaneous alteration and drainage of calcite microparticles preferentially occur at edges of euhedral facets and over anhedral faces, leaving the euhedral facets undrained and water-wet. (3) This unconventional mixed-wettability of microparticles prevailed in all samples. (4) Flooding with brine preserves this pattern but can weaken the oil-wetness of anhedral faces. (5) The unifying pattern of wettability may simplify the construction of realistic pore models of carbonate cores to predict recovery.

S Supporting Information *

Salt concentrations comprising the four brines (Table S1) and correlation of ζ-potential to calcium ion concentration (Figure S1). This information is available free of charge via the Internet at http://pubs.acs.org/.

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AUTHOR INFORMATION

Corresponding Author

*Telephone: +61-261254823. Fax: +61-261250732. E-mail: [email protected]. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS Financial support from the member companies of the Digital Core Consortium Wettability Satellite is acknowledged. Warwick Hillier (ANU) is thanked for access to the UV− visible spectrophotometer. 6280


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(33) Tie, H.; Tong, Z.; Morrow, N. R. Proceedings of the International Symposium of the Society of Core Analysts, Pau, France, Sept. 22−25, 2003; Paper 2003-02. (34) Loahardjo, N.; Xie, X.; Morrow, N. R. Energy Fuels 2010, 24, 5073−5080. (35) Tong, Z.; Morrow, N. R. J. Pet. Sci. Eng. 2006, 52, 149−160. (36) Graue, A.; Tonheim, E.; Baldwin, B. Proceedings of the 3rd International Symposium on Evaluation of Reservoir Wettability and Its Effect on Oil Recovery, Laramie, WY, Sept. 21−23, 1994. (37) Sakellariou, A.; Sawkins, T. J.; Senden, T. J.; Limaye, A. Phys. A 2004, 339, 152−158. (38) Hunter, R. J. Foundations of Colloid Science, Vol. I; Oxford University Press: Oxford, 1987. (39) Buckley, J. S.; Wang, J. X. J. Pet. Sci. Eng. 2002, 33, 195−202. (40) Buckley, J. S.; Wang, J. X.; Creek, J. L. Solubility of the least soluble asphaltenes. In Asphaltenes, Heavy Oils, and Petroleomics; Mullins, O. C., Sheu, E. Y., Hammami, A., Marshall, A. G., Eds.; Springer: New York, 2007; pp 401−437. (41) Churcher, P. L.; French, P. R.; Shaw, J. C.; Schramm, L. L. Proceedings of the SPE International Symposium on Oilfield Chemistry, Anaheim, CA, Feb. 20−22, 1991; Paper 21044. (42) Hatiboglu, C. U.; Babadagli, T. J. Pet. Sci. Eng. 2007, 59, 106− 122. (43) Fernø, M. A.; Treinen, R. ; Graue, A. Proceedings of the International Symposium of the Society of Core Analysts, Calgary, Canada, Sept. 10−12, 2007; Paper 2007-22. (44) Hassler, G. L; Brunner, E. Trans. AIME 1945, 160, 114−123. (45) Xie, X.; Morrow, N. R. Petrophysics 2001, 42, 313−322.

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Pore-Scale Distribution of Crude Oil Wettability in Carbonate Rocks

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