ARTICLE pubs.acs.org/EF
Effect of Water Salinity and pH on the Wettability of a Model Substrate Andrew Fogden* Department of Applied Mathematics, Research School of Physics and Engineering, Australian National University, Canberra ACT 0200, Australia
bS Supporting Information ABSTRACT: While the wettability of oil reservoirs has been the focus of many studies, little is known as to whether, and to what extent, the wettability evolves during oil recovery by waterflooding. To this end, a model silicate substrate, namely glass, was treated by oil drainage of the surrounding salt solution and aging (representing the initial state), followed by oil displacement by a second salt solution (flooded state). The two states were analyzed by scanning electron microscopy of the oil components attached to the substrate and measurement of their influence on macroscopic contact angles. Initial-state wettability took the form of an incomplete asphaltenic film interrupted by nanoscale channels and pockets of trapped salt solution. The film was observed to remain fluidic and, on flooding, could retract and detach to leave a more incomplete coverage, usually of oil nanodroplets. The influence of pH of the initial and flooding solutions on these two states was generally opposite; high pH, at which oilsubstrate repulsion is prevalent, tended to reduce film coverage in the initial state but aid its retention by the substrate on flooding. Contact angles on flooded substrates depended on this residual adhering nanoscale oil and on the ability of bulk oil to adhere by reconnecting to it. Again, the pH dependence of these two factors was opposite. The results suggested a possible supplementary mechanism for enhanced recovery by low salinity flooding.
’ INTRODUCTION Oil recovery by waterflooding of a reservoir is greatly influenced by the wettability,1 that is, the preference of the rock surface to contact oil or aqueous phase at the molecular level. The wettability state prior to recovery reflects both this thermodynamic preference and the liquid distribution in pores from brine drainage by the accumulated oil. At pore wall subareas over which brine drains to a thin film, originally water-wet mineral(s) can be sufficiently attracted to the oil interface to adsorb or cause deposition of its polar components, namely, asphaltenes and resins. The resulting mixed-wet state comprises these wettabilityaltered subareas and the unaltered remainder protected by local retention of bulk brine.26 Many studies710 have focused on the wettability alteration of such originally water-wet subareas in isolation, idealized as smooth mineral substrates (of quartz,7,8 mica,9 or glass10). The tendency for alteration was characterized by monitoring over short times the macroscopic contact angle of oil on the substrate in the brine. Substantial hysteresis between the water-receding angle and the larger water-advancing angle indicated the onset of adsorption/deposition of asphaltenes. For the simplest situation of brines comprising single 1:1 electrolytes without divalent ions, the experimental trends were fairly consistent with the Derjaguin LandauVerweyOverbeek (DLVO) theoretical description of mineral and oil interacting across the brine film. This theory incorporated charge regulation into the electrostatics to account for the pH-dependent ionization of acid and base groups at both interfaces.3,8,10 At lower pH, these groups favor mutual attraction of the substrate and oil interfaces and, hence, wettability alteration, while repulsion to resist alteration is favored at higher pH, in line with the observations. In related work,5,1113 the model substrates were treated by oil drainage of the brine and aging, in analogy to the reservoir state, r 2011 American Chemical Society
followed by organic solvent rinsing of bulk oil, to visualize the fine-scale structure of the adsorbate/deposits with atomic force microscopy. The images showed aggregated asphaltenic nanoparticles, either covering the substrate12 or with uncovered gaps presumably occupied by trapped water.5,11,13 Deposit height or roughness bore some relation to the macroscopic contact angles on the treated substrates.11,13 The advancing angle thus measured on solvent-rinsed substrates is only relevant to waterflooding of oil adhering to pore wall subareas if their wettability remains unchanged during flooding. Mixed-wet models of rock pore networks have been constructed to describe flooding via pore-scale displacements.4,5,14 The models typically incorporated the simplifying assumption that bulk oil was cleanly removed from subareas while their wettability remained intact. Experimental evaluation of flooding-induced wettability changes is thus essential to test these assumptions and further develop predictive capabilities for oil recovery. A growing number of studies showed improved recovery from clay-rich sandstones by low salinity waterflooding,1519 or from carbonates using brines of appropriate divalent ion concentrations.20 The boost was commonly thought to result from such wettability changes during flooding, which acted to liberate oil by debonding asphaltenes from oil-wet subareas, which thus reverted toward their water-wet original state.16,17,1921 It is difficult though to identify a single cause from indirect coreflood observations on these complex systems. Such floods also change rockbrine interactions to favor clay detachment from sandstone grains or the partial dissolution of minerals, which may also liberate oil.15,16,22,23 Further, the dissolution or clay cation exchange can Received: June 24, 2011 Revised: September 25, 2011 Published: October 07, 2011 5113
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Energy & Fuels induce pH shifts,15,16,18,19,21 possibly reducing oil adhesion to grains. Clarification of the mechanisms again calls for the extension of the model substrate analyses of the wettabilityaltered initial state (pertaining to the reservoir prior to recovery) to its changes on flooding. Some studies have begun touching on these issues.5,11 Work24 on glass substrates showed that the contacting oil film remained liquidlike and could partially withdraw during flooding, which laid the foundation for the present work. The current study considers originally water-wet glass substrates prepared to their initial wettability-altered state in high salinity brine at various pH values and then waterflooded without or with brine dilution, again at various pH values. The surface-bound oil residues are probed by scanning electron microscopy and contact angle measurements. This fundamental insight into causes and effects of wettability change is broadly relevant to oil recovery and, specifically, for quartz grains in sandstones. In the more specific context of low salinity flooding of clay-rich sandstones, we evaluate the scope for grain wettability change caused by either the brine dilution itself or any pH shift induced by this dilution.
’ EXPERIMENTAL SECTION Materials. The asphaltic crude oil, designated as WP, has a density of 0.9125 g 3 cm3, a viscosity of 111 mPa 3 s, an n-C6 asphaltene content of 6.3 wt %, and the acid and base numbers 1.46 and 2.49 mg KOH/g oil (all at 22 °C).25 It was filtered at 5 psi through three Whatman no. 4 filter papers before use. The organic solvents used were decalin (decahydronaphthalene, 98%) and methanol (99.8%), from SigmaAldrich. Salt solutions were made from NaCl and CaCl2 3 2H2O (AnalaR) with deionized water (Millipore Milli-Q). The salt ratio was 90 wt % NaCl and 10 wt % CaCl2 for the two total concentrations of 50 g/L (i.e., 770 mM NaCl + 45 mM CaCl2) and 1 g/L (15 mM NaCl + 0.90 mM CaCl2). Solutions were vacuum degassed and prepared at three pH values: unadjusted (pH 5.9 ( 0.2) or adjusted to 4.0 ( 0.1 with HCl or 9.0 ( 0.2 with NaOH. Microscope glass slides (Knittel Gl€aser) were precleaned with ethanol, water, and a radio frequency water-vapor plasma (50 W for 1 min). ζ potentials of the crude oil (emulsified at 0.2 wt % by sonication for 10 min) and the glass slide (ground) in the salt solutions were determined using a Zetasizer Nano-ZS (Malvern Instruments). Statistics of the electrophoretic mobility were gathered from three measurements of 10100 runs per sample and converted to ζ potential via the Smoluchowski equation. Treatment of Substrates with Oil and Salt Solutions. The treatments to simulate reservoir wettability states prior to or during recovery by waterflooding were based on published procedures.24 A glass substrate piece (7 mm 26 mm) was immersed in a salt solution (2.5 mL) in a vial, and crude oil (0.5 mL) was pipetted on top. After 6 h at room temperature to establish substratebrine and oilbrine equilibrium, the salt solution was withdrawn by pipet from the vial bottom while oil was added to the top. Further drainage of the water film enveloping the oil-immersed substrate was achieved by centrifuging the vial at 3000 rpm for 10 min. It was then aged at 60 °C for 30 ( 2 days. For some samples, the wettability of this initial state was investigated by using organic solvent to rinse the bulk oil, while minimizing any perturbation of its adsorbate/deposits. Decalin proved to be an appropriate solvent, as it dilutes the bulk oil but is a poor solvent for asphaltenes and resins in isolation. (Decalin is similarly used in rock core flood testing to prepare the mixed-wet-film state, by displacing the crude oil without removing the wettability alteration it created.26) The oil-immersed, aged substrate was transferred to a vial of decalin for 20 min and then to a second decalin bath for 2 h, which remained colorless. The substrate was then bathed in methanol for 10 min to remove salt and dried under light vacuum for 3 h at room temperature.
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The remainder of the set of samples in their initial state after aging was instead flooded with a second salt solution to examine the effect of recovery on the wettability state. Each vial was partly immersed in a water bath at 60 °C while a syringe pump pipetted the salt solution into the vial bottom at 2.5 cm3/h, corresponding to interfacial advance at 10 μm/s over the substrate. This was maintained for 1 h, after which the bulk oil had risen above the substrate. The vial was then centrifuged at 3000 rpm for 10 min to strip any macroscopic oil drops from the substrate. The oil in the upper phase was decanted, after which the centrifugation and decantation were repeated once, and any oil remaining at the air interface was removed using lint-free tissue. The substrate was transferred to methanol for 10 min and then dried under ambient conditions. Analysis of the Wettability States. The matrix of glass samples prepared for analysis of the initial wettability state used the 50 or 1 g/L salt solution, each at pH 4, 6, or 9. The matrix for the analysis of the wettability state after flooding used the 50 g/L solution as the initial brine, again, at these three pH values. Subsequent flooding was performed with the 50 or 1 g/L solution, at each of the three pH values. For each salinitypH combination in both of these states, two replicate substrates were prepared; one for the imaging of oil deposits and residues by field emission scanning electron microscopy (FESEM) and the other for contact angle measurement. The two analyses are similar to those in previous work24,27,28 and are summarized below. FESEM (Zeiss UltraPlus Analytical) was performed under high vacuum in secondary electron mode at 1 kV, prior to which the substrates were lightly sputter coated with platinum. Compared to traditional SEM, FESEM allows much higher magnification and, at small voltages and apertures, to minimize beam-induced charging and damage, necessary for the imaging of nanoscale organics. Contact angle measurements were performed under ambient conditions using a contact angle goniometer (KSV Instruments) for a captive pendant drop of the crude oil on substrates pretreated to their initial or flooded wettability states as described above. The fluid cell was filled with the same salt solution used to establish the initial wettability (for nonflooded samples) or used in flooding. The substrate was glued to a mounting stub, immersed in this salt solution, lightly degassed for 10 min, and affixed to the cell lid. An oil drop was pumped out upward at 0.6 μL/s from a stainless steel hooked syringe of outer and inner diameter 0.65 and 0.31 mm and left in the brine for 2 min. After contact with the substrate, the oil drop was grown slightly (to 4 μL), directly after which the drop profile was imaged and its water-receding contact angle was measured through the aqueous phase. The drop was left in contact for 2 min and then retracted at the same rate, and the water-advancing contact angle was measured. The short durations of oil drop exposure to brine and substrate helped to avoid substantial new deposition during measurement. The procedure was duplicated for 3 or 6 oil drops per nonflooded or flooded substrate. The same instrument was also used to measure the interfacial tension of crude oil in each salt solution.
’ RESULTS ζ potential. Measurement of the ζ potential of the glass and crude oil, separately equilibrated in each of the salt solutions, provides insight into the electrostatic and acidbase interactions of the DLVO theory, contributing to the complex behavior observed when the substrate is exposed to both liquids. The values are plotted in Figure 1 and are in line with results for similar systems.8,10,27 Both interfaces are amphoteric and bear an increasingly strong negative charge at higher pH as a result of the deprotonation of their acid groups. The isoelectric point of glass is around pH 2, so its negative charge persists in all solutions studied. Positive charge on the oil interface becomes pronounced at pH 6 and below, especially for low salinity (Figure 1b), in 5114
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Figure 1. ζ potential of ground glass and emulsified crude oil in the (a) high and (b) low salinity solutions, at the three pH values: 4, 6, and 9. The extra points (dotted curves) for glass verify that its isoelectric point is close to pH 2.
Figure 2. FESEM images of oil deposits on glass for the 50 g/L initial salt solution at pH 6, either (a) without flooding, or (c) flooded with this same solution; (b) and (d) are the corresponding binarized images. Images are 3.0 μm 2.0 μm; the scale bar in (a) is 500 nm and applies to all.
which electrostatics are more weakly screened. The positive charges arise from the protonation of base groups of polar oil components, possibly together with the binding of calcium ions. It can thus be anticipated that the interaction of pristine glass and oil interfaces across an intervening film of salt solution transitions from more repulsive to more attractive with decreasing pH. Measures of Oil Deposits. For each of the 24 samples for microscopy, 16 FESEM images at 100 000 magnification (and comprising 2048 1536 pixels) were acquired at a fixed pattern of locations over the piece. Each micrograph was analyzed using ImageJ software to extract statistical metrics for the in-plane distribution of oil deposits. Deposits generally appear lighter than
the glass background, enabling them to be segmented by thresholding grayscale values. Examples are given in Figure 2. From these binarized images, the 2D metrics determined were (a) coverage (total percentage of substrate image area occupied by deposit), (b) particle area (of the base of individual deposit particles contacting the substrate), and (c) particle circularity (dimensionless ratio of this particle base area to the area of a circle having the same perimeter). The latter two metrics were obtained from the ImageJ particle analyzer tool and converted to area-weighted averages per image. Thus, from each image, a single value of coverage, average particle area, and average particle circularity is obtained. It is convenient to replot 5115
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Figure 3. Average (a) area and (b) acircularity of individual deposit particles on glass per FESEM image versus their coverage of this image, giving one point for each image of each sample, either flooded (unfilled diamonds and curve fit) or nonflooded (filled triangles). The coefficient of determination, R2, of the fit is (a) 0.26 and (b) 0.72.
circularity, C, as its complementary measure, 1 C, termed the acircularity, for which 0 then corresponds to a perfect circle and values increase toward 1 for highly irregular, noncompact shapes. Figure 3 presents plots of average deposit particle area and acircularity against coverage from all FESEM images. The fits in Figure 3 to the flooded samples show that particle area is, at most, only very weakly correlated (linearly) to coverage, while acircularity displays a somewhat stronger correlation (for a reciprocal offset power law). Accordingly, graphs plotted against coverage and acircularity will have similar shapes. Scatter is greatest for the flooded samples, which do not follow the same trend lines as the nonflooded samples. Flooding removes the vast majority of macroscopic bulk oil from the glass, with the occasional remnant macrodrop stripped by the subsequent centrifugation. Decalin post-rinsing, which is necessary for the analysis of the initial wettability state, is thus not required for the flooded analogs. Consequently, flooded samples (e.g., Figure 2c) bear all adhering oil, while those without flooding (but with decalin rinsing, e.g. Figure 2a) bear only the adsorbate/deposit, that is, the footprint of adhering oil. Although the term oil “deposit” will be used in both states, the two cannot be directly compared. A study24 systematically analyzed the effects of various solvent post-treatments and attempted a direct comparison of both states. After decalin rinsing of both, the asphaltenic residues on glass were less for the flooded state than for the initial state and gave lower contact angles, verifying the shift toward water-wetness. However, the decalin rinsing underestimated this shift by overestimating the deposits remaining after flooding. Such rinsing of the flooded state switches the continuous phase from aqueous to oleic, effectively inverting the surface structures from oil-in-water to water-in-oil types and causing extraneous deposition during this upheaval. Rinsing instead with only methanol avoids this inversion and faithfully reproduces the flooded state deposits24 and, thus, was used here. Figure 4 displays the corresponding plot of brine advancing and receding contact angles, measured for each oil pendant drop applied to each pretreated glass substrate. As shown there, the flooded samples can be fitted to a power law: 1 θA =180 ¼ að1 θR =180Þn
ð1Þ
where θR and θA are the receding and advancing angles, with a = 0.63 and n = 1.64. Eq 1 has no physical significance, and it merely
Figure 4. Advancing versus receding contact angles from all oil pendant drop runs on all pretreated substrates: flooded (unfilled diamonds and curve fit) or nonflooded (filled triangles).
serves to assess the correlation. Although the fit is fair (R2 = 0.73), the deviations are larger at the lower end where most measurements (flooded and nonflooded state) reside. We reemphasize that the data do not allow direct comparison between these two states as a result of their differing post-rinsing. Although the flooded samples are free of oil macrodrops, some residues at the larger end of the microscopic scale resist removal by centrifugation. A contact angle run, in which the pendant drop encounters such residues, displays a very high receding angle (with correspondingly high advancing angle), giving the trail of points at the higher end of Figure 4 for flooded samples. For these points, the pendant drop does not directly probe the substrate wettability; accordingly, measurements with a receding angle above 80° were excluded from the statistics. From the three metrics per image and two angles per pendant drop, the average and standard deviation for each sample are listed in Table 1. They are plotted and analyzed below, along with FESEM images showing the most representative member of their set, with metrics closest to the average. The standard deviations in Table 1 reflect the sampling uncertainty due to large-scale variations in these properties over the substrate piece. The deposit particle area and the circularity also vary within each FESEM image. The standard deviations of the particle area within the images average 0.20 103 and 1.3 103 μm2 for nonflooded and flooded samples, while for circularity the values are 0.16 and 0.12, respectively. These internal variations 5116
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Table 1. Averages and Standard Deviations of the Three Metrics of Oil Deposits from Image Analysis of FESEM Micrographs, with the Corresponding OilBrine Contact Angles, for All 24 Samples with Varying Concentration (g/l) and pH of Initial and Flooding Brinesa flood brine
initial brine g/l
a
pH
g/l
pH
coverage, %
particle area, 103μm2
circularity
θR, deg
θA, deg
50
4
27.8 ( 6.3
0.41 ( 0.07
0.500 ( 0.09
56 ( 1
134 ( 2
50
6
36.1 ( 5.3
0.41 ( 0.10
0.402 ( 0.05
55 ( 1
141 ( 10
50
9
32.3 ( 3.6
0.41 ( 0.04
0.477 ( 0.05
50 ( 2
112 ( 6
1
4
30.1 ( 8.9
0.46 ( 0.30
0.501 ( 0.14
55 ( 2
138 ( 2
1 1
6 9
32.1 ( 4.8 23.0 ( 2.9
0.53 ( 0.16 0.23 ( 0.03
0.480 ( 0.09 0.625 ( 0.04
52 ( 4 45 ( 2
127 ( 7 120 ( 6
50
4
50
4
14.8 ( 3.2
3.11 ( 1.90
0.528 ( 0.20
59 ( 3
125 ( 11
50
6
50
4
16.5 ( 4.1
2.17 ( 0.77
0.704 ( 0.16
49 ( 5
113 ( 9 109 ( 8
50
9
50
4
12.0 ( 1.5
1.58 ( 0.24
0.800 ( 0.06
45 ( 8
50
4
50
6
9.7 ( 3.0
2.17 ( 1.94
0.792 ( 0.08
48 ( 5
113 ( 3
50
6
50
6
11.8 ( 3.3
1.02 ( 0.24
0.828 ( 0.06
42 ( 2
108 ( 10
50
9
50
6
12.7 ( 8.3
0.91 ( 0.31
0.666 ( 0.22
54 ( 5
117 ( 9
50 50
4 6
50 50
9 9
12.8 ( 4.9 9.7 ( 2.9
2.10 ( 1.48 1.91 ( 1.11
0.565 ( 0.22 0.752 ( 0.07
53 ( 5 45 ( 8
120 ( 10 110 ( 12
50
9
50
9
22.3 ( 5.8
1.82 ( 0.76
0.361 ( 0.18
54 ( 6
125 ( 8
50
4
1
4
10.8 ( 1.3
0.86 ( 0.05
0.851 ( 0.04
57 ( 5
119 ( 9
50
6
1
4
7.3 ( 1.9
0.66 ( 0.11
0.880 ( 0.01
42 ( 8
107 ( 3
50
9
1
4
4.3 ( 1.9
0.60 ( 0.13
0.857 ( 0.05
54 ( 4
117 ( 9
50
4
1
6
9.3 ( 2.4
1.45 ( 0.70
0.580 ( 0.08
53 ( 5
118 ( 6
50
6
1
6
8.3 ( 1.5
0.97 ( 0.12
0.857 ( 0.04
46 ( 7
111 ( 10
50 50
9 4
1 1
6 9
21.0 ( 8.2 14.1 ( 1.8
1.58 ( 0.65 1.56 ( 0.30
0.489 ( 0.21 0.689 ( 0.07
55 ( 7 50 ( 4
121 ( 17 108 ( 7
50
6
1
9
17.1 ( 2.2
1.45 ( 0.35
0.613 ( 0.05
47 ( 4
114 ( 4
50
9
1
9
34.1 ( 3.0
1.47 ( 0.44
0.274 ( 0.06
58 ( 2
134 ( 13
The first six samples were not flooded.
are not uncertainties; rather, they reflect the natural distribution of particles present. Initial Wettability State. Figure 5 shows the most representative micrographs of the distribution of organics adsorbed/ deposited on glass after the drainage of each salt solution by crude oil and aging, with solvent post-rinsing. A previous study28 by the author used fluorescence spectroscopy to verify that such organics consist of asphaltenes plus associated resins. The deposit textures in this initial wettability state in Figure 5 appear qualitatively similar, comprising nanoparticles of primary-aggregated asphaltenes, which often form irregular, secondary-aggregated chains, separated by relatively clean substrate. These finescale gaps were presumably occupied by nanochannels and nanopockets of water trapped under the collapsing oil interface and hindered from draining.5,6,11,24 Averaging over all six samples, the deposits cover 30% of the substrate and their individual base area has an equivalent circle diameter of 32 nm. Parts a and b of Figure 6 plot the corresponding averages of the two FESEM metrics of oil deposit coverage and deposit particle acircularity from Table 1, while parts c and d of Figure 6 plot the associated contact angles. Although the error bars are quite large, some differences between samples can be distinguished from the image measures. All three measures are lowest for the 1 g/L solution at pH 9. For low values of all measures, the deposits are sparse, small and compact, indicative of the low affinity of oil for the substrate in the solution. This is consistent with the
discussion of Figure 1, as glass and oil interfaces are most strongly repulsive at pH 9 at low salinity. However, the 1 g/L solution at pH 4, in which the attraction of the oppositely charged interfaces is strongest, is not distinguished by especially high deposition in Figures 5 and 6a and b. Instead, the deposit measures appear to be largest at pH 6 for both salinities. Electrostatic interactions within the DLVO theory are best suited to predicting the propensity for deposition during the approach of oil to pristine glass in a salt solution (i.e., the state shown in schematic Figure 7a).8,10,24 Even in this case of first approach, the DLVO theory is not quantitatively accurate, as the charge groups on the oil interface are borne by the polymer-like layer of its adsorbed, aggregated polar components.29 This presumably extends the range of interactions beyond the very short Debye screening length (0.32 nm) at high salinity. Thus, despite the small magnitude of the ζ potentials in Figure 1a, differences with pH in Figure 6 persist at this high salinity, as also observed in other studies by the author.24,27,28 Over the month of aging, the deposit amount and density attained in the initial wettability state (schematic Figure 7b) are the result of the slow reconfiguration and packing of these aggregated polar components, introducing further theoretical complications of nonDLVO polymeric interactions. However, it seems intuitively reasonable that overly strong interfacial attractions may limit deposit coverage by increasing water trapping under the rapidly collapsing and sticking oil film.5,6,24 It is thus not unexpected that 5117
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Figure 5. FESEM images of oil deposits on glass for the six salinitypH combinations of the initial salt solution, without flooding, and post-rinsed with decalin and methanol. Images are 3.0 μm 2.0 μm; the scale bar in the bottom left image is 500 nm and applies to all. The top left and bottom right images show additional debris particles, sporadically precipitated on all samples.
the milder, short-range attraction and repulsion for high salinity and/or intermediate pH 6 tend to give more deposition (larger metrics) in Figure 6a and b. The effect is analogous to that for the oilwater interfacial tension, which similarly exhibits a peak at pH 6 in Figure 6e as a result of the milder state of ionization under these conditions. This slightly higher tension at pH 6 also aids somewhat the spreading of oil on the pristine substrate to avoid water trapping. Figure 6e also confirms that no significant saponification of the polar components of this oil to produce natural surfactants takes place over pH 49. Measurement of an oil pendant drop on the footprint-bearing, pre-prepared substrate in the initial salt solution (schematic Figure 7c) gives some estimate of the implications of the deposit for contact angles in this state. On the basis of the advancing angles in Figure 6d, all six substrates are classed as altered to oil-wet, without a universal dependence on salinity. However, angles in Figure 6c and d generally decrease with increasing pH. While the angles are naturally dictated by the extent of the preexisting deposit, they also depend on the bulk oil’s ability to displace the intervening salt solution to molecularly contact this deposit (as it would in the initial reservoir state) during the drop experiment. The latter measurement-dependent effect is governed by the above-mentioned DLVO interactions of the interfacial approach of the bulk oil (to both the deposit and the glass, as interaction length scales can be similar to deposit feature sizes). This effect thus contributes to the observed decrease in angles with pH. The decrease is clearest for receding angle in Figure 6c, during the measurement of which the interfaces begin their approach to contact. (The lower interfacial tension at pH 9 in Figure 6e also contributes slightly to its lower receding angle.) The advancing angle at low salinity in Figure 6d also displays this decrease with pH. At high salinity, the interactions are weaker and the extent of the preexisting deposit is more decisive; thus, its advancing angles mirror more the deposit metrics in Figure 6a and b, appearing to peak at pH 6.
While the possible presence of calcium bound to the oil interface could accentuate its adhesion to glass at lower pH, calcium does not appear to bridge the negatively charged interfaces at pH 9, judging from the low values of long-time deposition and short-time contact angles in Figure 6 for the 1 g/L brine at pH 9. It is also worth noting that, of the three metrics, acircularity gives best correlation to both angles (see the Supporting Information). For longer drop contact times than the 2 min used here, the extra step of reestablishing molecular contact would have a lesser influence on the advancing angle, however, with increased risk of bulk oil redissolving the deposit. Flooded Wettability State. Figure 8 shows lower magnification micrographs of the various types of distributions of oil remaining on glass in the flooded samples. Most samples appear qualitatively as in Figure 8a, in which the remnants are nanoscale oil droplets of fluidic form, as was also the case in the previous study.24 The nanodroplets are arranged into a foamlike pattern, implying that, during flooding, the advancing water increasingly perforates the interfacial film of oil contacting the substrate, partly by swelling the preexisting trapped water (schematic Figure 7d). The oil film retracts and detaches with the bulk oil, taking the adsorbed/deposited asphaltenes with it. Further swelling of perforations decomposes the remaining film to a foam network of connected struts. The struts, in turn, decompose to the nanodroplets via Rayleigh instability (schematic Figure 7e). This texture forms during flooding and does not arise from centrifugation (see the Supporting Information). Samples for which the salt solutions lead to greater residue retention (schematic Figure 7f) may show the same structure as shown in Figure 8a, still with quite low particle acircularity but with higher coverage and increased particle (nanodroplet) size. Alternatively, the structures in Figure 8bd may occur. In Figure 8b, the oil film retracts to a nanofoam, the struts of which remain largely intact, while Figure 8c shows a mixture of reasonably 5118
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Figure 6. (a) Coverage and (b) acircularity of oil deposits from image analysis, and (c) receding and (d) advancing contact angles, on glass pretreated to its initial wettability state in each of the six salt solutions, without flooding, and post-rinsed with decalin and methanol. The oilsalt solution interfacial tension is plotted in (e).
Figure 7. Schematic of the configurations of salt solutions, oil, and the asphaltenic deposits on the substrate in the following states: (a) pristine (subscript 0), (b and c) initial wettability (subscript i), (dg) first flooded (subscript f), and (h) postflooded (subscript f2).
completely decomposed nanodroplets and nonretracted, residual microblobs. Figure 8d shows a microfoam, from which bulk oil has apparently detached to leave stranded this relatively flat footprint, within the cells of which the nanofoam subtexture further retracts. All samples exhibit some heterogeneity in residues over the glass piece, although generally one of these four types is predominant (see the Supporting Information). For images of connected foams, the brightness variations along their struts and nodes unavoidably lead to some disconnection during segmentation. The resulting values of particle area and acircularity, while very high, thus underestimate somewhat their true levels. Figures 9 and 10 show the most representative micrographs of oil deposits remaining on glass for each combination of the three pH values of the 50 g/L initial solution and the three pH values of the 50 g/L (Figure 9) or 1 g/L (Figure 10) flood. Figure 11 plots the corresponding averages of the two metrics of oil deposit coverage and particle acircularity from Table 1, while Figure 12 5119
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Figure 8. FESEM images of four textures of oil deposits remaining on glass after salt solution flooding and methanol post-rinsing. Images are 12.3 μm 8.4 μm; the scale bar in (a) is 1 μm and applies to all.
plots the associated receding and advancing contact angles of oil pendant drops. Figure 13 shows the correlation between these angles and acircularity for all flooded samples. Other graphs are given in the Supporting Information. Consider first the general features of Figures 913. Over all samples in Table 1, the deposit metrics of coverage, particle area and acircularity average 14%, 1.5 103 μm2, and 0.33 after flooding and 30%, 0.41 103 μm2, and 0.50 without flooding. The lower coverage after flooding is due to its removal of deposit. The greater particle area and lesser acircularity in flooded samples are chiefly due to the absence of decalin post-rinsing; the nanodroplets retain bulk oil and are thus larger and more fluidic than their footprints. The receding and advancing angles on flooded samples vary by as much as 17° and 27°, respectively, depending on the initial/flood pH and salinity. While such differences are substantial, the standard deviations in Table 1 average 5° and 9°, respectively, limiting somewhat the reliability of differences and extraction of trends from contact angle data alone, even for this sizable matrix of brines. The independently determined FESEM metrics thus provide invaluable support to the pendant drop measurements, serving to more clearly decouple the causes and effects of wettability. While Cassie’s law30 predicts that contact angles are dictated by deposit coverage, the correlation here is almost nonexistent. Instead, it could be expected that particle acircularity is more closely related to receding and advancing angles, as the clean, compact retraction of nanodroplets should favor similar behavior for the macroscopic pendant drop. This is indeed the case; acircularity exhibits the best correlation (albeit still not strong) to these
angles in Figure 13, as for the initial wettability states. Figures 11 and 12 do not display a universal trend in flood salinity; the averages of each metric and angle over the nine samples for the 50 and 1 g/L floods are almost identical, as for initial wettability. While the solution pH is again responsible for the clearest differences, its interplay with salinity gives rise to important tendencies described below. We begin by analyzing the residual deposits (Figures 911), that is, the root of wettability change, and we will start with the three simplest cases in which initial and flooding solutions and pH are identical. These lie along the upward diagonal in Figures 9 and 11a and c. For 50 g/L flooding at pH 4 matching the initial state, the residual comprises foam struts and more solidlike microblobs; thus, coverage and acircularity are high. This exemplifies the strong adhesion (schematic Figure 7f) expected from “sticky” bonds between deprotonated acid groups on glass and protonated base groups on polar oil components under the acidic conditions. With the 50 g/L solution at pH 6 in both states, the residual is small nanodroplets of low coverage and very low acircularity, characteristic of weak adhesion (schematic Figure 7e). The mild, short-range interactions in this solution, which appeared to be most conducive to rearranging polar oil components to build deposit of the highest coverage and acircularity in the initial state (Figure 6a and b), similarly allow the greatest reversibility during flooding. For the 50 g/L flood at pH 9, oilglass repulsion is increased and initial-state deposition is somewhat lower (Figure 6a and b); however, the result is a very high coverage and acircularity of incompletely retracted and stranded residues (top right image in Figure 9). This is unlikely to 5120
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Figure 9. FESEM images of oil deposits remaining on glass for the nine pH combinations of the 50 g/L initial salt solution (columns) and 50 g/L flooding solution (rows). Samples were methanol post-rinsed. Images are 3.0 μm 2.0 μm; the scale bar in the bottom left image is 500 nm and applies to all.
be the result of adhesion by calcium bridging of the two interfaces, as this effect was not apparent in the initial state. Instead, the substantial residual is thought to be due to precursor film thickening. On flooding, the repulsion at pH 9 can drive rapid swelling of the frequent nanochannels of trapped solution, increasing the flood’s ability to infiltrate along the substrate ahead of the advancing bulk meniscus. While the infiltration and swelling cause some retraction of surface oil, the increasingly thick and watery layer can prematurely disconnect this oil from the bulk oil. This limits the surface oil’s removal by bulk coalescence and meniscus sweeping, and the effective advancing angle of the meniscus would be lowered (schematic Figure 7g). The deposit and residual deposit in the initial and flooded states thus display largely opposite trends with pH, even when the solution composition is unchanged. Consider now the samples in Figures 9 and 11a and c in which the initial and flood salinity remain the same (50 g/L) while pH is changed. For an initial pH 4, in the left column of these figures, the increase in flood pH from 4 to 6 reduces residue extent, size, and acircularity by reducing adhesion. This can be due to the reequilibration of the interfaces to the weaker, more reversible interactions at pH 6 or disturbance of the initial acidbase bonding at pH 4 without attaining the new equilibrium. Increasing the flood pH to 9 leads to much less removal of deposit, presumably because the increased repulsion again creates the film thickening precursor, aided by the highest prevalence of nanochannels in the pH 4 initial state of lowest coverage (Figure 6a
and b). For initial pH 6 (middle column of Figures 9 and 11a and c), the flood at the matching pH is ideal for the reversal of deposition; perturbation from pH 6 gives poorer removal, signified by higher acircularity. In particular, flood pH 4 increases acidbase adhesion, while flood pH 9 introduces some film thickening, although now to less effect owing to the paucity of nanochannel pathways in the pH 6 initial-state deposit of highest coverage (Figures 6a and b). For initial pH 9 (right column of Figures 9 and 11a and c), lowering of the flood pH from 9 to 6 to 4 decreases repulsion to progressively switch off film thickening and enhance deposit removal. As flood pH 4 removes somewhat more than pH 6, equilibrium perturbation, rather than reequilibration, is the probable cause. We now turn to the samples for low salinity floods in Figures 10 and 11b and d, for which both salinity and pH can be perturbed from initial to flooded states. While the results are somewhat similar to their high salinity counterparts, it is notable that, for all initial-state pH values, the postflooding residual increases (with respect to all metrics) with flood pH. Again, the dependence on flood pH is largely the opposite of that for the solution pH in the initial wettability state (Figure 6a and b), or the pristine state. This emphasizes that experimental or theoretical analyses of single-brine wettability would be poor indicators of flooding response. To understand the results, recall that reduced salinity increases the strength of oilglass electrostatic repulsions or attractions (Figure 1). It also applies an extra osmotic pressure to swell the nanochannels filled with high 5121
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Figure 10. FESEM images of oil deposits remaining on glass for the nine pH combinations of the 50 g/L initial salt solution (columns) and 1 g/L flooding solution (rows). Samples were methanol post-rinsed. Images are 3.0 μm 2.0 μm; the scale bar in the bottom left image is 500 nm and applies to all.
salinity solution in the initial-state deposit. Accordingly, the scope for water film thickening greatly widens for the 1 g/L floods at pH 9 (top row in Figures 10 and 11b and d), which duly bear substantial residual deposit. The residual decreases with decreasing initial pH along this top row as stronger initial oilglass attraction better resists re-equilibration to the repulsive condition favoring swelling. The 1 g/L floods at pH 4 (bottom row in Figures 10 and 11b and d) show this same counterintuitive effect that introducing a strong oilglass attraction can minimize residuals. The attraction across nanochannels inhibits their swelling to preserve the connectivity of surface oil to bulk oil, aiding removal by the sweeping meniscus. Residual coverage now decreases with increasing initial pH along this bottom row, in line with the growing need for attraction to resist swelling. The previous study24 only tested the extremes of pH 4 and 9, with residual deposit being generally lower in the latter case and, also, decreasing with salinity (from 0.01 to 1 M NaCl). However, it is difficult to compare the results, as this earlier study24 used a different crude oil and brine, a shorter oil aging time (6 days versus 30 here), and initial and flooding brines of identical composition (i.e., high salinity flooded with high, or low with low). These latter two factors will tend to increase the similarity between trends in the initial and flooded states and reduce deposits for pH 9 brines in which the interfacial repulsion slows their build-up and development of adhesion. Further work on other oilbrinesilicate systems is needed to assess the generality of the trends in residual deposit of the current study.
The advancing contact angles during first flooding (schematic Figure 7dg) are unknown. They would not be the same as their values measured on the initial wettability state (schematic Figure 7c), even if such measurements were to use the appropriate combination of initial solution (to establish this state) and flood solution (surrounding the oil pendant drop), owing to the decalin post-rinsing. This step destroys the fluidity of deposits and, thus, their ability to transform during flooding. The receding and advancing contact angles in Figure 12 of the oil pendant drop on the flooded substrate thus pertain to the postflooded state (schematic Figure 7h). They are the respective angles at which upstream mobilized oil subsequently enters a flooded pore and is, in turn, displaced during continued flooding. Figure 12 will also not capture the full effects of residual fluidity, owing to evaporation of lighter oil fractions during drying prior to measurement. The similarity between the receding and advancing angle trends in Figure 12 is due to their fair correlation in Figure 4, and the resemblance of these to the acircularity trends in Figure 11c and d reflects the fair correlations in Figure 13. Thus again, the angles are chiefly dictated by the preexisting residual deposit plus the extra contribution from DLVO-type interactions governing the reestablishment of molecular contact of bulk oil with the residue in the flood solution (schematic Figure 7h). With respect to this latter effect, the pendant drop contact time should be chosen to match typical durations of oil temporary residence in pores during flooding. Here, the time was fixed at the same value (2 min) as for the initial state measurements. 5122
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Figure 11. (a and b) Coverage and (c and d) acircularity of oil deposits remaining on glass for the nine pH combinations of the 50 g/L initial salt solution and the (a and c) 50 g/L or (b and d) 1 g/L flooding solution. Samples were methanol post-rinsed.
Figure 12. (a and b) Receding and (c and d) advancing contact angles on glass pretreated to its flooded wettability state, for the nine combinations of initial and flooding solution pH for (a and c) 50 g/L or (b and d) 1 g/L flooding. Substrates were post-rinsed with methanol, after which contact angles were measured for oil pendant drops in the flooding solution.
As mentioned previously, molecular contact is more rapidly attained for more attractive interactions at lower pH. On the other hand, the extent of deposit residue generally increases with flood
pH. Flooding conditions giving greatest residual deposit are often those for which new bulk oil will take longer time to reestablish contact with it. The molecular contact contribution to wettability 5123
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Figure 13. Correlation of (a) receding and (b) advancing angles to acircularity from FESEM image analysis, for all 18 flooded samples in Table 1.
partly cancels the residual deposit contribution, and accordingly, the pH response of the contact angles in Figure 12 is somewhat more muted than expected from Figure 11. In rare extreme conditions, the former contribution can dominate. One example is for the initial state at pH 4 flooded with low salinity solution, in the left column of Figures 10, 11b and d, and 12b and d. In this case, residual deposit metrics increase with flood pH, as a result of the film thickening mechanism; however, contact angles decrease with pH as the attraction driving molecular contact (pH 4) or the repulsion hindering it (pH 9) is so strong at low salinity. Further, it is likely that, for this pendant drop in pH 4, the attraction has not only reestablished contact with the residues but also begun realtering wettability of the uncovered subareas between them. It should be borne in mind that the issues of flooding residuals adhering to the substrate and their subsequent contact with bulk oil do not only apply to these nanoscale deposits. As mentioned in the context of Figure 4, the flood also leaves occasional larger microscopic oil remnants, even for our model systems of slow advance over smooth glass. These were excluded from the analyses of wettability state in order to differentiate their cause and effect. However, they are a reality, and so, re-exposure of the flooded substrate to oil should be modeled as a receding meniscus simultaneously reconnecting to substrate-stranded remnants of both size scales. In particular, microscopic blob or rivulet remnants can be expected, even in the absence of the rupture of pore-spanning lenses.5
’ DISCUSSION The discussion focuses on applications of the model substrate results to wettability issues of oil recovery from sandstone reservoirs. A study24 demonstrated that the nanodroplet features remaining on glass after flooding were qualitatively similar to those on an analogously prepared sandstone rock; however, the vastly more complex nature of rock will clearly influence its responses. Grain surfaces bear roughness, possibly together with heterogeneity in mineralogy and/or particulate linings. These features influence the initial wettability state of the reservoir prior to recovery and, hence, its changes during flooding. Roughness would be expected to retain the salt solution by capillarity in the initial state, increasing the micro/nanochannels permeating the deposit under bulk oil in wettability-altered subareas. Associated particles with potentially high oil affinity, such as kaolinite, may be fully infiltrated by oil in the initial state,28 reducing the presence of channels there. These two channel scenarios could increase or decrease the likelihood of deposit removal during
flooding, depending on brine composition and pH, and specifically, the propensity for precursor film thickening. Both of these features introduce topographical variations over pore walls, which disrupt the lateral cooperativity of surface oil retraction. The frequency of nanodroplets and larger microscopic residues hindered or pinned from further retraction will thus increase somewhat relative to glass. By the same token, their reconnection to bulk oil later entering and exiting the pore may be less frequent than on glass, if shielded by the topography. These physical features, and any chemical heterogeneity, will also directly contribute extra variability and added hysteresis to contact angles and their wettability-induced changes. Irrespective of the exact roles of these sandstone features, the results and interpretations on glass suggest a new view of wettability during flooding. This could have special relevance to enhanced or improved oil recovery strategies attempting to tailor the in situ wettability changes.1519,21,22 Figures 912 are consistent with the precursor film thickening mechanism (schematic Figure 7d and g) becoming prevalent for flood solutions favoring nanochannel swelling, that is, for high salinity at high pH or low salinity at moderate-high pH. By this mechanism, a pore wall subarea that is altered to oil-wet in the reservoir, and remains so throughout flooding, could conceivably behave as if more waterwet during the displacement of its adhering bulk oil, because the advancing meniscus angle is lowered by the local disconnection from bridging surface oil. This could benefit recovery, as the oilwetness may help to preserve the connectivity of bulk oil, while the pseudo-water-wetness may allow its detachment and displacement at less severe capillary pressures. Low salinity flooding of clay-rich sandstones1519,21,22 may generally fit these necessary conditions for film swelling, especially if salinity reduction causes a rise in pH, even if only locally and/or temporally, as a result of clay ion exchange or mineral dissolution.15,16,21 In this view, the ion exchange could not only aid oil detachment from the clay itself17,19 but also act at a distance via pH to aid oil detachment from neighboring quartz grains. The growing weight of observations that low salinity corefloods of clay-rich sandstones produce highly variable recoveries18,22 may partly stem from the previously mentioned rock-specific features possibly diminishing the strong response seen on glass. Many of these studies attribute enhanced recovery for low salinity flooding to a more permanent shift of the rock surfaces to a cleaner, more water-wet state. Recall though that the flooded glass sample exhibiting greatest removal of deposit and lowering of contact angle is the middle entry in Figures 9, 11a and c, and 12a and c, in which the 50 g/L solution at intermediate pH 6 is both the initial 5124
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’ CONCLUSIONS This study used glass model substrates to provide deeper insight into the mechanisms underlying changes in wettability of rock pore walls in oil reservoirs during recovery by waterflooding. Scanning electron microscopy was demonstrated to be a convenient means of imaging the adhering oil residues, especially after flooding, to distinguish the two factors which together dictate wettability, namely, the modification of substrate surface chemistry by these residues and their effect on macroscopic contact angles. It was shown that wettability can change continually during flooding, over the course of an oil-containing rock pore being first swept by the advancing water and later repopulated by upstream oil to be subsequently swept again. As the oil remains fluidic across the nanometers closest to the substrate, the wettability can undergo similar interfacial tension-driven reconfigurations (coalescence and snap-off) as the bulk oil being displaced from the pore. Accordingly, wettability can change not only with pore occupation but also with the displacement rate and the mode of water advance (film flow versus piston flow) and in response to any associated shift in local solution conditions. It was shown that, under some conditions of salinity and pH, flooding can transform the most oilwet initial states on glass to the least oil-wet or cause oil-wet walls to release oil in a more water-wet manner. This suggests supplementary mechanisms for enhanced recovery from clay-rich sandstones by low salinity flooding. ’ ASSOCIATED CONTENT
bS
Supporting Information. Particle area of oil deposits in the initial wettability state (Figure S1), correlation of contact angles to coverage, particle area, and acircularity of oil deposits in the initial wettability state (Figure S2), FESEM images of deposits remaining on flooded glass samples, verifying the lack of dependence on centrifugation speed (Figure S3) and illustrating the typical variations over the substrate (Figure S4), particle area of oil deposits in the flooded state (Figure S5), correlation of contact angles to coverage and particle area of oil deposits in the flooded state (Figure S6). This material is available free of charge via the Internet at http://pubs.acs.org.
’ AUTHOR INFORMATION Corresponding Author
*Telephone: +61-261254823. Fax: +61-261250732. E-mail:
[email protected].
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’ ACKNOWLEDGMENT Financial support from the member companies of the Digital Core Consortium Wettability Satellite and an ARC Discovery Grant are acknowledged. Evgenia Lebedeva is thanked for performing the contact angle and interfacial tension measurements, as are Norman Morrow and Jill Buckley (University of Wyoming) for valuable discussions. 5125
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