Mobilization of Fine Particles during Flooding of Sandstones and

Mar 10, 2011 - The mounting evidence that waterflooding of clay-containing sandstone reservoirs using floodwater with reduced salinity can enhance oil...
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Mobilization of Fine Particles during Flooding of Sandstones and Possible Relations to Enhanced Oil Recovery Andrew Fogden,*,† Munish Kumar,‡ Norman R. Morrow,§ and Jill S. Buckley§ †

Department of Applied Mathematics, Research School of Physics and Engineering, Australian National University, Canberra ACT 0200, Australia ‡ DigitalCore Pty Limited, 73 Northbourne Avenue, Canberra ACT 2600, Australia § Department of Chemical and Petroleum Engineering, University of Wyoming, Laramie, Wyoming 82071, United States

bS Supporting Information ABSTRACT: The mounting evidence that waterflooding of clay-containing sandstone reservoirs using floodwater with reduced salinity can enhance oil recovery, but with unpredictably large variation in responses, demands improved understanding of the underlying mechanisms. Mobilization of clays and other fines is one candidate mechanism. Flow experiments in Berea sandstone plugs were designed such that the change in their fines distribution from before to after the oil and water injections could be imaged in exactly the same pores using scanning electron microscopy. This technique also allowed imaging of the wettability distribution on pore surfaces and was coupled to spectroscopic analysis of the adsorbed asphaltene amounts. One-phase flows switching from highto low-salinity water led to only a low level of fines mobilization, compared to two-phase experiments in which high- or low-salinity water displaced crude oil from mixed-wet prepared plugs. The images reveal that loosely bound, partially oil-wet fines lining sandstone grains are stripped by the adhering oil during its recovery and redeposited on grains further downstream. Reduced salinity increases the fraction of fines thus mobilized by weakening their bonds to grains and strengthening their bonds to oil. Evidence suggests that these more oil-wet fines stabilize the water-in-oil curved menisci, which can aid in maintaining the connectivity of the oil phase and thus enhance oil recovery.

’ INTRODUCTION There is widespread interest in the mechanisms by which oil recovery is increased by either displacement of oil with lowsalinity water at high initial oil saturation or by mobilization of residual oil established by high-salinity flooding. Laboratory results indicate that the onset of increased recovery by low-salinity flooding, if observed, occurs at salinities below 5000 ppm. This cutoff is not well-defined and is dependent on the specific components of the water phase and the properties of the rock and crude oil. Tang and Morrow1,2 concluded that increased recovery from sandstone by low-salinity flooding requires the presence of clay, an initial water saturation, and crude oil. Later, the study of the displacement of refined oil from mixed-wet rocks showed that the presence of a crude oil/water interface is also necessary.3 The sufficient conditions are still uncertain, as evidenced by examples of a lack of increase in oil recovery when all necessary conditions are fulfilled.4,5 Nevertheless, successful field tests,6,7 other field-wide analyses,8 and recent laboratory studies that have identified positive responses in an increasing range of outcrop and reservoir rocks9-12 have spurred interest in identifying targets for low-salinity projects. In the clay-bearing Berea sandstone first investigated by Tang and Morrow,2 an increase in the effluent pH was observed and ascribed to ion exchange with high-surface-area clays. However, effluent interfacial tensions were diminished by less than 30% from ∼25 mN/m, insufficient for improved recovery by lowering the ratio of capillary to viscous forces.13 Further, for many subsequently investigated crude oil/rock combinations that responded r 2011 American Chemical Society

to low-salinity flooding, the effluent pH ranged from a little below to just above neutral.3,14 Tang and Morrow2 noted that increased recovery was accompanied by the production of water-wet fine particles that sank to the bottom of the oil/water separator and the possible presence of partially oil-wet fines in a small rag layer between produced oil and water. It was hypothesized that improved oil recovery involved the release of mixed-wet fines from pore walls, possibly together with the dislodgement of water-wet particles. Sarkar and Sharma15 earlier reported that the rate of fines production in response to the decreased salinity of the injected water was diminished in the presence of crude oil. For many crude oil/water/ rock combinations, the production of fines in the effluent was not observed, and, accordingly, Lager et al.14 argued that the increased oil recovery did not involve their movement. However, a lack of observation of fines production from cores does not preclude substantial local mobilization and migration at pore scales, especially in the case of predominantly oil-wet fines, for which relatively small populations in the produced oil would be difficult to detect visually. The interpretation of pressure measurements with respect to fines migration in low-salinity waterfloods is inconclusive. Dissolution of rock minerals was also discounted by Lager et al.14 as a feasible explanation for improved oil recovery by Received: November 21, 2010 Revised: February 9, 2011 Published: March 10, 2011 1605

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Table 1. Porosity, Absolute Permeability, Brunauer-Emmett-Teller Specific Surface Area, Cation-Exchange Capacity (CEC), and Relative Abundance of Kaolinite (K), Illite (I), and Chlorite (C) from X-ray Diffraction, for the Berea Samples, plus Average Oil Recovery (Rwf, as a Percentage of the Original Oil in Place) by High- or Low-Salinity Flooding4 Rwf 2

Berea sample

porosity (%)

permeability (mD)

area (m /g)

CEC (mequiv/100 g)

clays

high (% OOIP)

low (% OOIP)

B1

21.5

680

0.851

0.196

K>I>C

65.1

81.5

B2

22.8

290

B3

24.6

320

B4

20.5

30

74.1

72.6

K>C>I 1.150

0.290

K=C>I

Figure 1. (a) Cut halves of a rock plug, of diameter 8 mm, illustrating the experimental setup (although with halves pressed together in the plug holder) and (b) diagram of the SEM imaging protocol for each cut face.

low-salinity waterflooding. However, subsequent studies have shown that the extent of dissolution depends on rock mineralogy. In essentially clay-free sandstone and carbonate cores that contain soluble minerals such as anhydrite, dissolution may be the primary factor contributing to increased oil recovery.12 In other cases, such as Berea sandstone, the amount of material available for dissolution is much less, although careful measurements have shown an extended production of low levels of calcium and magnesium.16 The extent to which low levels of dissolution contribute to improved oil recovery by low-salinity waterflooding remains an open question. In addition, low-level dissolution complicates efforts to study the effects of specific ionexchange reactions that have been hypothesized to account for improved recovery in low-salinity waterfloods.14 The current study focuses on the microscopic tracking of changes in the location of fines and deposited organic materials including asphaltenes that accompany injection of water and reduction in its salinity. Crude oil/water combinations and Berea sandstone samples for which variable low-salinity response was observed in core flooding experiments4 have been selected for this study.

’ EXPERIMENTAL SECTION Rocks and Plug Preparation. Four Berea sandstones, labeled B1-B4, were selected. Some properties are given in Table 1, measured on the supplied cores or from data on sister cores.4 Samples B1 and B4 are representative of the standard Berea and low-permeability Berea, with absolute permeability of ∼500 and 60 mD, respectively.4 All samples contain complex clay mixtures of kaolinite, illite, and chlorite.4 Measured pore-size distributions and the X-ray diffractogram of B2 are provided in the Supporting Information. Smaller plugs, of diameter and length of 8 and 20 mm, were dry-cut from the cores and then sleeved with a heat-shrink fluoropolymer and wet-cut in half with a Struers saw (Figure 1a). The halves were mounted, with cut faces abutted, in a plug

holder within a flow cell connected to a motorized syringe pump, for cleaning by successive injection of 75 pore volumes (PVs) of toluene (99.5%; Sigma-Aldrich), a 50/50 (v/v) blend of toluene and methanol (99.8%; Sigma-Aldrich), and then methanol, followed by light vacuum drying at 60 °C. This defines the “before” state of each plug. Liquids and Flow Experiments. The crude oil, from the Minnelusa formation (Gibbs Field, WY), has a density of 0.9062 g/cm3, a viscosity of 77.2 mPa 3 s, an n-C7 asphaltene content of 9.0 wt %, and acid and base numbers of 0.17 and 2.29 mg of KOH/g of oil (all at room temperature)17 and was filtered before use. The high-salinity brine, corresponding to 38 650 ppm Minnelusa formation brine, contained 28.99 g/L of NaCl, 2.79 g/L of CaCl2 3 2H2O, 1.42 g/L of MgCl2 3 6H2O, and 6.90 g/L of Na2SO4 (all analytical grade) in deionized water from a Millipore Milli-Q system (as used throughout). Its elemental composition is thus as follows: Na, 13 640; Ca, 760; Mg, 170; Cl, 19 420; SO4, 4660 (all ppm). Lowsalinity water was a 100-fold dilution of high-salinity brine. Both were introduced at their natural pH ∼6.0 and subsequently buffered by the rock. Core-flood experiments4 on sister cores of the standard and low-permeability Berea samples, with this same oil displaced by either of these same two water compositions, gave the average recovery values included in Table 1. In particular, B1 exhibited enhanced recovery for low-salinity water injection, while B4 did not. All flow experiments involved driving water or oil at a rate of ∼1  10-3 cm3/s through the pore volume (1 PV ∼ 0.22 cm3) of the plug halves, contacted face to face in the above-mentioned cell. The first step, namely, saturation and equilibration with high-salinity brine, comprised injection of 35 PV of this brine, immersion of the cell in a bath of the brine for ∼1-2 h of degassing under very light vacuum, followed by further injection of 10 PV, and shut-in for 12-24 h. The second step, aimed at producing a mixed-wettability starting state,18 involved drainage of brine by injecting 20 PV of crude oil at 70-75 °C, followed by aging at 75 °C for 3 days. For the waterflooding step, using either high- or low-salinity water, 20 PV was injected at 65-70 °C, followed 10 min later by another 20 PV. The steps to flush both liquids began with removal of the residual crude oil by injection of 100 PV of decalin (decahydronaphthalene, 98%; Sigma-Aldrich) at 65-75 °C until 1606

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Figure 2. Subsets of registered tomogram slices from a Berea B1 plug in the dry state (at left), saturated with high-salinity brine (middle), and flooded with low-salinity water (right). Edge lengths of the image squares are (a-c) 3.26 mm and (d-f) 214 μm. the effluent was colorless and then 50 PV of n-heptane (99%; Riedel-de Haen) at 25 °C to remove maltenes from the oil deposits. Following this, 75 PV of methanol was injected at 25 °C to remove salt. The plug halves were then immersed in decalin (30 min.), heptane (10 min.), and 77.5/ 22.5 (v/v) methanol/water (4 days at 65 °C), followed by light vacuum drying at 25 °C. This constitutes the “after” state of each plug. For onephase, high-to-low-salinity water experiments, the second step was omitted; waterflooding was performed with low-salinity water, and the decalin and heptane flushing was skipped.

Analysis by Scanning Electron Microscopy (SEM) and X-ray μ-CT. In the “before” and “after” states, both cut faces were imaged with a field-emission scanning electron microscope (Zeiss UltraPlus Analytical) under high vacuum in secondary electron mode at 1 kV, without any conductive coating. Each face was traversed by a series of 18 micrographs at magnification 303 (Figure 1b), within each of which a close-up image (magnification 3110) of a single pore was acquired. The systematic protocol facilitated navigation to this same set of pores in “before” and “after” states. For one-phase experiments, the results of this 2D SEM-imaging approach, necessitating cutting and flushing, were compared to those using X-ray μ-CT19 to 3D-image whole plugs (5 mm diameter) in their wet states. Tomograms in each state comprised 20483 voxels, at 2.97 μm/voxel resolution, and were compared using a registration algorithm. Quantification of Oil Deposits. In the “after” state, post-SEM imaging, the amount of wettability-altering oil deposits on rock internal surfaces was determined for each plug half. Because oil built up heavily near its injection inlet, a 4 mm section was cut from this end (Figure 1a) and discarded to allow fairer comparison. Each half was crushed and bathed in 10 g of decalin (18 h) to remove any unbound oil and then bathed in 6 g of heptane (6 h) to remove residual maltenes, after which the powder was dried at 50 °C. The asphaltene-based deposits were dissolved using an 87.3/12.7 (w/w) azeotropic blend of chloroform (99%; Sigma-Aldrich) and methanol,20 which was decanted after 18 h. These asphaltene solutions from each plug half were analyzed with a UV-visible scanning spectrophotometer (Shimatzu UV-3101PC) to measure absorbance over 200-800 nm. Calibration standards were prepared by separating the asphaltene fraction of the crude oil, via heptane precipitation and centrifugation, and dissolving the solid at known concentrations in the same azeotropic blend. Their absorbance at 525 nm exhibited a Beer-Lambert linear dependence (see the Supporting

Information), enabling deduction of the asphaltene/rock mass ratio for each plug half, assuming that the separated asphaltene fraction is reasonably representative of the adsorbed organic material. Emulsion Stability Testing. To test the ability of the sandstone clays and fines to stabilize oil-in-water emulsions, fresh, cleaned pieces of Berea were crushed with a mortar and pestle and size-fractionated using sieves of mesh 125 and 63 μm on a vibrating plate (Fritsch Pulverisette). The grains retained by these two sieves were separated from the clay/ fines flour retained by the smaller mesh and the pan. Clays and fines totaled 7.1, 7.5, and 8.0 wt % of rock for B1, B2, and B4, respectively. Glass vials containing 48 mg of clay/fines and 3.2 g of high- or lowsalinity water were sonicated for 10 min and equilibrated for 8 h, after which 0.29 g of crude oil was added to fill the vial, and then sealed. The contents thus comprised 1.4 wt % clay/fines and a 1/10 oil/water volume ratio. The vials were aged at 60 °C for 12 h and then shaken for 2 min. Prior to analysis, each was again removed from the oven and shaken for 2 min, directly after which the vial was placed horizontally and the number of oil drops remaining stable and unattached to the vial wall was monitored with the aid of optical microscopy (Nikon AZ100M) over 6 min at room temperature. The vial was returned to the oven and stood vertically for 9 h, after which it was again laid horizontal to count the oil drops. Two replicates were performed for each Berea/brine combination.

’ RESULTS One-Phase Systems. Flow experiments in which the rock plug is saturated with high-salinity brine, and then flooded with low-salinity water, in the absence of crude oil, were analyzed using X-ray μ-CT for Berea sample B1 and the SEM approach for samples B1, B3, and B4. For the former approach, Figure 2 displays subsets of the same representative tomographic slices of the rock in its dry starting state and its wet states filled with highsalinity and, in turn, low-salinity water. The large field of view in Figure 2a-c verifies that all quartz and feldspar grains remain in place throughout the experiment, as expected. Digital zooms, such as Figure 2d-f, show that the submatrix of clay aggregates filling, spanning, or lining pores between grains generally also appears immobile. While some pores exhibit slight changes, these 1607

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Figure 3. Low-magnification SEM images of the same location on a cut face of Berea B1, in the states (a) before and (b) after one-phase, high-to-lowsalinity waterflooding, with 100 μm scale bars. The high-magnification images in Figure 4 are of the rectangular subareas marked.

are close to the voxel resolution limit; thus, structural and mineralogical identification of individual particles or small aggregates having moved is not possible for X-ray μ-CT of these systems. For the cut-face SEM-imaging approach illustrated in Figure 1, a representative registered pair of low-magnification micrographs for this same Berea B1 in the states “before” (postcleaning and drying) and “after” (postflooding with low-salinity water and subsequent methanol flushing and drying) is shown in Figure 3. All images for all samples analyzed show that sandstone grains are cleanly cut by the blade, and debris is absent from the cut surfaces and pores. Further, at this low magnification, the “before” and “after” states in all images and samples (both one- and two-phase systems presented below) are largely indistinguishable. This replicates the observation from μ-CT, suggesting that while the rock plug is naturally perturbed by creation of the cut halves, and any subsequent abrasion between faces in contact in the plug

holder, the rock and pore environments below the cut surfaces are largely unperturbed mechanically and respond to flow in a manner similar to that in an uncut plug. Following the protocol in Figure 1b, the clay-filled pore framed by a rectangle in Figure 3 was selected for high-magnification imaging, with this corresponding pair displayed in Figure 4. The clay framework appears undamaged by the cutting and the flow of water, again in line with the μ-CT results and above interpretations; this observation applies to all pores imaged for all samples. While the flow experiments do not lead to pore blockage and thus presumably do not have a strong impact on the absolute permeability of the rock, the majority of these high-magnification SEM images of pores show movement of fine mineral particles at or below μ-CT resolution, e.g., the features circled in Figure 4b. The degree of change due to fines mobilization and recapture was quantified by analyzing the set of pairs of high-magnification SEM images of pores in both cut faces (Figure 1b), totaling 1608

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Figure 4. High-magnification SEM images of the same pore in a cut face of Berea B1 (a) before and (b) after one-phase, high-to-low-salinity waterflooding, with 10 μm scale bars. Ellipses mark mineral features in part b not present in part a or vice versa.

Figure 5. Percentage fraction of high-magnification SEM image areas exhibiting changes in the mineral particle locations after one-phase, highto-low-salinity waterflooding of three Berea samples.

28 pairs for each sample. In the “after” image, the pixel area of each altered feature was summed to yield the percentage fraction of the total micrograph area (i.e., roughly the cross-sectional area of the pore body) having undergone change from the “before” image. Its average and standard deviations over the 28 images were then determined. Changes due to the occasional largerscale isolated event (e.g., a fragment chipped off a grain to lodge in the pore), involving single particles above 5 μm diameter, were not counted because they most likely occurred during handling of the plug halves between the “before” and “after” states. The averages and standard deviations for the one-phase flow experiments are graphed in Figure 5. All three Berea samples yield very similar average area fractions of fines mobilization, around 2%, without any significant trend reflecting their differing absolute permeabilities or oil recoveries in Table 1. Moreover, 1609

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Figure 6. High-magnification SEM images of the same pore in a cut face of Berea B1 (a) before and (b) after oil recovery by high-salinity brine flooding, with 10 μm scale bars. Arrows in part b indicate some of the locations of asphaltenic deposits.

the nature of the fines mobilization is in all three cases similar to that in Figure 4. Particles undergoing movement, and depositing on the stationary matrix of the well-bonded or intergrown clay aggregates in pores and the grain walls bounding pores, include individual platy clays (kaolinite and also possibly illite) and others of more blocky form, as well as submicrometer particles of less discernible form, sometimes agglomerated. Generally, their shape and/or size are suggestive of being more loosely bound in the “before” state. Identification of the same mobilized particle in the “before” and “after” images is very rare, implying that the migration spans multiple pores. However, migration may also include additional transport, or agglomeration, of the water-mobilized fines by the subsequent flushing and drying steps. In Figure 5, the least permeable Berea B4 exhibits the largest variability in fines mobilization, presumably reflecting the more limited choice of preferred pathways for their transport and emphasizing that lower

starting permeability (and higher clay content) increases the likelihood and severity of further permeability reduction due to pore blockage. Two-Phase Systems. The same SEM approach was applied to two-phase flow experiments, in which plugs of Berea B1 and B2, initially saturated with high-salinity brine and then drained by crude oil and aged, were subsequently flooded with either highor low-salinity water. Figures 6 and 7 show high-magnification image pairs, each focusing on a single clay-containing pore in B1, for oil recovery by high- and low-salinity flooding, respectively. (Image pairs for B2 are given in the Supporting Information.) Again, while the grains and bonded clay frameworks remain immobile, many small-scale changes (not circled in Figures 6b and 7b) occur. For two-phase systems, the “after” state is distinguished from the “before” state both by movement of the mineral particles and now also by asphaltene-based films deposited from 1610

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Figure 7. High-magnification SEM images of the same pore in a cut face of Berea B1 (a) before and b) after oil recovery by low-salinity waterflooding, with 10 μm scale bars. Arrows in part b indicate some of the locations of asphaltenic deposits.

the oil at locations on the mineral surfaces (some of which are marked by arrows in Figures 6b and 7b). Our analysis of the 28 pore image pairs for each system focuses only on the former changes due to fines mobilization and recapture; however, these are strongly coupled to the latter changes caused by local wettability alteration. Areas with asphaltene-based films will be referred to as oil-wet and areas without as water-wet. These terms are relative; the extent to which the deposits alter wettability is not determined. However, analogous experiments with the same crude oil on smooth, flat, kaolinite-coated glass substrates demonstrated that deposition of these films leads to a substantial increase in the water/oil contact angle and thus a shift toward oil wetting.21 The pores in Figures 6b and 7b both exhibit substantial deposition of asphaltene films on grain surfaces. Some deposit is also present on their clay aggregates, but to a lesser extent. Other pores appear to retain their water-wet condition, with grain surfaces

mainly free from deposit and clays remaining clean. The distribution of wettability alteration is largely dictated by whether the capillary pressure applied during oil drainage exceeds the local entry threshold for pore bodies and throats, set by their size and shape. Here the capillary pressure appears sufficient for oil to intrude pores and alter the wettability of their low-curvature grain walls but often insufficient to substantially displace water from the tighter constrictions associated with clay aggregates (or corroded feldspar grains and other microporosity), while other pores are shielded by tight connections. A full investigation of the wettability distribution was not undertaken, but rather each imaged pore was categorized as oil-wet or water-wet, depending on whether or not a considerable fraction of its grain areas bore visible asphaltene-based films. The degree of fines mobilization from “before” to “after” images was obtained using the same procedure as that for the one-phase systems to calculate the percentage fraction of micrograph pixels 1611

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Figure 8. (a) Average percentage fraction of high-magnification SEM image areas exhibiting changes in the mineral particle locations after oil recovery by high- or low-salinity flooding for two Berea samples, showing the contributions from oil-wet and water-wet pores and (b) the separate oil-wet and water-wet statistics comprising it. (c) Spectroscopically determined relative mass of asphaltene on rock for the extracted plug halves and their weighted average, after the flow experiments, and (d) the relationship between data in parts a and c.

occupied by a relocated mineral phase, now also classifying each image as oil-wet or water-wet. Figure 8a plots the overall averages from all pores imaged, subdivided into the relative contributions from oil-wet and water-wet pores. These two contributions are the product of the fraction of imaged pores of this category and the average area fraction of the relocated mineral phase within this category. Figure 8b separately plots the latter averages (per pore) and standard deviations. Further, the fraction of pores of each category is given by the number within each bar in Figure 8b. All two-phase systems exhibit significantly higher overall averages in Figure 8a than the one-phase systems in Figure 5, so crude oil accentuates fines mobilization and increases its sensitivity to the salinity of the water injected to recover oil. One-phase experiments are too simplistic to predict the fines behavior in oil recovery applications. The response of the B1 samples in Figures 5 and 8a shows that fines mobilization for high-to-low-salinity waterflooding without crude oil roughly doubles for high-salinity flooding with oil present. Accordingly, local movement of fines can be considerable during recovery from clay-rich sandstone reservoirs by flooding with typically high-salinity brines. For B1, oil recovery by flooding instead of low-salinity water gives a further doubling, and the same is true of B2, albeit with the somewhat lower overall averages in Figure 8a. Parts a and b of Figure 8 show that the oil-wet pores are chiefly responsible for these higher mobilizations in the two-phase systems. Both wettability categories separately exhibit these same trends of increasing mobilization for low-salinity injection. The trend of greater mobilization for B1 over B2 is also observed. However, the results for the water-wet pores are quite similar for all four samples. Indeed, it is suspected that the water-wet average for B1 with low-salinity flooding is somewhat exaggerated by the inclusion of pores with some (but not a majority of) oil deposits.

The degree of mobilization in water-wet pores is thus comparable to the oil-free systems in Figure 5. The main difference between the low-salinity floods of B1 and B2 in Figure 8a can be attributed to the fraction of pores classified as oil-wet (the numbers in Figure 8b). The main cause of the greater fines mobilization in the presence of oil is the extra contribution from mineral particles associated with the oil deposit films on grain walls of oil-wet pores. Figures 6 and 7 display this change from water-wet, particle-free walls in the “before” state to oil-wet, particle-studded walls in the “after” state. This change is most strikingly visible on the smooth quartz overgrowths in these figures. Figure 9 shows another example, for the case of B1 after low-salinity flooding. In the gutter where overgrowths meet, residual water is able to sustain high interfacial curvature during drainage and aging, so the surfaces remain water-wet, i.e., without asphaltene film deposition, and are also free of particles. Outside this gutter, the more open regions are directly exposed to oil, which deposits the asphaltene films seen coating the quartz surfaces in Figure 9, within which many particles are littered. These particles comprise mineral fines and their agglomerates, often of a complex form intermingled with asphaltenes; thus, the identity of the constituent minerals is difficult to distinguish morphologically. In the enumeration of the fractional changes plotted in Figure 8a,b, only the areas associated with the mobilized and recaptured mineral particles are counted and not the entire extent of the film-coated area. The greater changes for lowsalinity flooding are due to greater the density of fines within oil-wet regions on grains. Oil Deposit Amounts. While the SEM approach has been demonstrated to be capable of imaging asphaltene films on grains and clays in these Berea samples, a more exhaustive SEM analysis 1612

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Figure 9. Higher-magnification SEM image of two abutting quartz overgrowths on a grain of Berea B1 after oil recovery by low-salinity flooding, showing distribution of oil-wet subareas and mobilized fines, with 2 μm scale bars. Arrows indicate boundaries of the asphaltenic films.

Figure 10. (a) Frequency of crude oil drops remaining stable in high- or low-salinity water containing clay/fines of the three Berea samples. Error bars indicate standard deviations of the two replicates. (b) Optical micrograph of oil drops stabilized by B2 clay/fines in high-salinity brine, with scale bar 0.5 mm.

would be required to quantify wettability via area coverage of these films and determine the differences between high- and lowsalinity “after” states. In particular, magnifications around an order of magnitude higher than that (3110) used in Figures 6 and 7 would be necessary to quantify film coverage, especially on rougher surfaces. Instead, the asphaltenes comprising these films were solvent-extracted from the crushed plug halves and analyzed by UV-visible spectrophotometry, to yield the total asphaltene mass per rock mass. The resulting mass ratios are presented in Figure 8c. Because a 4 mm section was trimmed from the inlet face of the upstream half (Figure 1a), the weighted average per plug in Figure 8c is slightly closer to the downstream value. This average asphaltene amount is greater for low-salinity rather than high-salinity flooding, and for B1 over B2, and so exhibits the same trends as fines mobilization in Figure 8a,b. The specific asphaltene content of the downstream half is greater than that of the upstream half, whereas the one-ended injection of oil (Figure 1a) in our drainage procedure would, from the literature,22 be expected to produce the opposite gradient, i.e., with wettability alteration decreasing along the oil injection direction. This implies that the asphaltene deposit is transported in this same injection direction during waterflooding and also further transported by the subsequent solvent flushing. Because all samples share a common drainage and aging history, an extra deposit in the low-salinity case must be formed during flooding. The solvent flushing procedure is the same for all two-phase samples;

thus, while such processes during core cleaning have been shown to cause some clay migration,23 the clear differences between samples in Figure 8 imply that this contribution is small relative to waterflooding. All information from SEM images (Figures 6, 7, and 9), and the similarities between trends in Figure 8a-c points to oil-aided mobilization of mineral particles (kaolinite plus fines of unspecified mineralogy) during recovery, in the process of which the particles exposed to oil become more oil-wet, boosting the asphaltene content at their final location downstream. Figure 8d plots the weight-average asphaltene amount in Figure 8c versus the average contribution of oil-wet pores to fines mobilization in Figure 8a. The extrapolated case of zero fines mobilization (i.e., the y intercept in Figure 8d) may correspond to the state directly after aging, which exhibits greater wettability alteration for B1 compared to B2, because of its likely greater desaturation at the applied capillary pressure of drainage. Although the data are very limited, it appears that, from these different starting levels for B1 and B2, the subsequent increase in asphaltene-based film deposition is associated with the degree of fines mobilization. Fines Stabilization of Oil in Water. Figure 10a plots the average number of oil drops in high- or low-salinity water that remain stable 6 min after cessation of shaking because of Berea clay/fines at their interfaces. Reference experiments without particles yielded no stable drops in either aqueous phase. The clay/ fines of all Berea samples tested gave greatly increased stability of 1613

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the oil-in-water structures for the high-salinity case, with numbers of droplets that were 6-9 times larger than those for low salinity. For both water compositions, the clay/fines of B2 gave the greatest stability (see Figure 10b), followed by B4 and B1. The vials were then allowed to stand for 9 h at 60 °C, during which time the oil drops were compressed toward the top under hydrostatic pressure and then recounted. For the high-salinity samples, on average 87% of the original drop count in Figure 10a was retained, while for low salinity, only 29% of the already small populations in Figure 10a survived (with B2 contributing the majority of this retention).

’ DISCUSSION For the one-phase experiments, no disintegration or mobilization of clay frameworks and aggregates is observed. Clay assemblies presumably remain stable as they are first exposed to highsalinity brine with sizable concentrations of divalent cations, specifically 19 and 7.0 mM of Ca2þ and Mg2þ, respectively, prior to dilution.24 It is not known whether the small fraction of fines mobilized in these aqueous-phase-only experiments was already partially liberated by the shear force of the initial high-salinity brine flow. The results in Figure 8b for two-phase systems only exposed to high-salinity brine, and in the water-wet pores having limited contact with oil, suggest that part of the ∼2% image area change due to mobilization in Figure 5 already occurs in this initial state. The switch to low-salinity water liberates other fines because of stronger electrostatic repulsion between the negatively charged particles and grains (the range of which, i.e., the Debye length, increases by an order of magnitude upon dilution). For the two-phase experiments, it thus appears that a very small fraction of fines are already mobilized in the high-salinity brine-saturated initial state, and the subsequent drainage by crude oil may add to this, depending on whether the interfacial tension of the moving oil/water meniscus acts directly on the fines. During drainage, most fines would be shielded by water, either in a thinning layer that contributes to retention of fines by capillary action at the surfaces of invaded pores or by residual bulk water resisting displacement from tight confines. Moreover, the water-receding contact angle is generally low,25 so it is likely that comparatively little mobilization takes place during drainage and aging. Aging at least partially alters the wettability of exposed grain surfaces and fines lining them, thus instilling some degree of oil/fines adhesion. At the commencement of flooding with either water composition, the situation can be idealized as in the upper picture of Figure 11, where hatched and solid blocks indicate loosely and strongly bound fines, respectively, and locally oil-wet mineral surfaces are represented by lines. The forced mobilization of oil during flooding pulls adhering, loosely bound fines with it. The low-salinity flood increases the fraction of these stripping-prone hatched particles, both by the above-mentioned increase in mineral/mineral repulsion across water and by increased oil/ mineral attraction across water. The latter effect, i.e., increased oil wetness and oil adhesion at reduced salinity, has been demonstrated by contact-angle measurements of crude oil drops, for a range of water compositions at intermediate pH values, on quartz,26 mica,27 and kaolinite.21 Fines thus mobilized can remain at the oil/water interface responsible for their stripping or enter the oil bulk (the two dotted arrow options in the upper picture of Figure 11). In either scenario, the increased oil exposure will increase the oil wetness of the mobilized fines. Given that

Figure 11. Illustration of the possible mechanisms of fines mobilization occurring during oil recovery by waterflooding. Hatched particles are loosely bound and become mobilized. Lines on mineral surfaces represent asphaltene-based films. The two dotted arrows denote mobilization to either the oil/water interface or the oil bulk.

mineral fines generally have a strong affinity for crude oil/water interfaces,28-31 this option appears energetically preferable (see below). Continued stripping of fines from grains by the moving meniscus will lead to interfacial overcrowding, as will a reduction in the interface area upon passage of the meniscus through pore throats and smaller pores. A continuous cycle of stripping and redeposition of fines, now in a more oil-wet state, would be expected, as in the lower picture of Figure 11. This is consistent with the fines-littered oil-wet regions on grains prevalent in SEM images (Figures 6, 7, and 9). Because of this turnover, the fraction of fines in the plug effluent may be quite low. Thus, fines may play a significant role in recovery even in the absence of substantial produced quantities. For our flow experiments on small plugs designed for microscopy, the volumes were too small to visually observe the presence or absence of effluent fines. The large core experiments on Berea B1 and B4 using the same crude oil and high- and lowsalinity water did not show significant fines production.4 Literature often focuses on salinity-induced changes in wettability, with the majority inferring a shift to increased water wetness in conjunction with low-salinity flooding. These findings can only be reconciled with the higher residual asphaltene contents after low-salinity flooding in Figure 8c, in line with contact-angle studies demonstrating increased oil wetness at low salinity, if fines mobilization occurs. In this case, as shown in the lower picture of Figure 11, the rock surfaces stripped of partially oil-wet fines become more water-wet, and if their redeposition primarily occurs in already oil-wet regions, then the extra asphaltene will contribute little if any extra oil-wetness there. In this interpretation, the water composition influences the recovery of a given oil from a given sandstone by dictating the fraction of mobilized fines, their wettability alteration, and so their ability to stabilize oil/water menisci. Figure 10a demonstrates that oil-in-water menisci (curving toward oil) are strongly stabilized by clay/fines in high-salinity brine, which from general theoretical and experimental considerations of Pickering emulsions32 implies that the particles are relatively hydrophilic. This is consistent with the above-mentioned contact-angle studies,21,26,27 demonstrating greater silicate water wetness in high salinity. Conversely, the more oil-wet state of clay/fines at low salinity favors stabilization of the inverse structure of water-in-oil. Literature on kaolinite-stabilized water-in-oil emulsions, for the same salt solutions and oil considered here, further supports this expectation.30 At the negative capillary pressures applied over 1614

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Energy & Fuels connected oil domains during oil recovery by forced imbibition of water, the menisci curve toward water (Figure 11) and are thus best stabilized by fines at low salinity. In this case, the fines aid perseverance of oil-phase continuity by reducing snap-off. On the other hand, at high salinity the fines are more water-wet and suited to stabilizing disconnected oil globules of the opposite sign of curvature, with the undesirable consequence of providing a prohibitive steric barrier to their coalescence. So, while in both cases the fines aid oil/water interfacial stability, the implications at high and low salinity can be diametrically opposed. It appears likely that the enhanced oil recovery observed4 from low-salinity flooding of B1 derives from the ability of its fines to be mobilized and rendered partially oil-wet, assuming that the clays separated by crushing in Figure 10a are representative of this mobile subset. Although two-phase SEM experiments were not performed on B4, the similarities between it and B1 in Figures 5 and 10a suggest that its lack of low-salinity response4 stems from its low permeability and hindered access of oil to clays. Core floods have not been performed on B2, although its somewhat reduced mobilization of fines (Figure 8) and more water-wet behavior of its clays (Figure 10) would suggest a lowsalinity response less than that for B1.

’ CONCLUSIONS The current set of imaging tools to visualize and quantify the effects of multiphase flow in rocks was expanded by developing a SEM approach to image the “before” and “after” states in the same pore. Although this approach involves the creation of cut faces and flushing of the liquids for dry imaging, it provides the resolution necessary to image changes in the location of the mineral phases, down to submicrometer sizes, and the presence of even thinner organic films on rock surfaces. This technique was applied to analyze crude oil recovery from sandstone plugs by waterflooding with high- and low-salinity water. Some mobilization of loosely bound fine particles occurred in one-phase aqueous flow experiments but was considerably greater in the presence of crude oil because of its ability to strip partially oil-wet fines lining grains during waterflooding. For both high- and lowsalinity flooding, stripped fines are carried by the oil phase and redeposited downstream, although the effect is greater for low salinity. A significant net increase in the amount of asphaltenebased film after low-salinity flooding implies that, in addition to the contribution from migration of mixed-wet particles, adsorption is increased because released fines account for a large fraction of newly exposed mineral surface where further adsorption can occur. The salinity-sensitive ability of fines to stabilize oil/ water interfaces, and implications for oil recovery, was addressed. Future studies would be well served by combining the SEM approach, for probing subpore mechanisms, with X-ray μ-CT, for visualizing their effect on pore-scale oil/water configurations, together with other nondestructive techniques (e.g., magnetic23) to monitor clay migration. ’ ASSOCIATED CONTENT

bS

Supporting Information. Mercury porosimetry of Berea samples (Figure S1), X-ray diffractogram of sample B2 (Figure S2), calibration for the asphaltene amount from UV-visible spectrophotometry (Figure S3), and SEM images of B2 after flooding (Figures S4-S6). This material is available free of charge via the Internet at http://pubs.acs.org.

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’ AUTHOR INFORMATION Corresponding Author

*E-mail: [email protected]. Telephone: þ61-261254823. Fax: þ61-261250732.

’ ACKNOWLEDGMENT The authors thank the Digital Core Consortium Wettability Satellite member companies, the University of Wyoming Enhanced Oil Recovery Institute, and industry for financial support and are thankful for an ARC Discovery Grant (to A.F.). The Australian Partnership for Advanced Computation is thanked for computing resources, as is Peigiu Yin for assistance in acquiring rock petrophysical properties. ’ REFERENCES (1) Tang, G. Q.; Morrow, N. R. SPE Res. Eng. 1997, Nov, 269–276. (2) Tang, G. Q.; Morrow, N. R. J. Pet. Sci. Eng. 1999, 24, 99–111. (3) Zhang, Y.; Xie, X.; Morrow, N. R. Proceedings of the 2007 SPE Annual Technical Conference, Anaheim, CA, Nov 11-14, 2007; Paper 109849. (4) Zhang, Y.; Morrow, N. R. Proceedings of the 2006 SPE Improved Oil Recovery Symposium, Tulsa, OK, Apr 22-26, 2006; Paper 99757. (5) Boussour, S.; Cissokho, M.; Cordier, P.; Bertin, H.; Hamon, G. Proceedings of the 2009 SPE Annual Technical Conference, New Orleans, LA, Oct 4-7, 2009; Paper 124277. (6) Webb, K. J.; Black, C. J. J.; Al-Jeel, H. SPE 2004, 89379. (7) Seccombe, J. C.; Lager, A.; Jerauld, G.; Jhaveri, B.; Buikema, T.; Bassler, S.; Denis, J.; Webb, K.; Cockin, A.; Fueg, E. Proceedings of the 2010 SPE Improved Oil Recovery Symposium, Tulsa, OK, Apr 24-28, 2010; Paper 129692. (8) Vledder, P.; Fonseca, J. C.; Wells, T.; Gonzalez, I.; Ligthelm, D. Proceedings of the 2010 SPE Improved Oil Recovery Symposium, Tulsa, OK, Apr 24-28, 2010; Paper 129564. (9) Agbalaka, C. C.; Dandekar, A. Y.; Patil, S. L.; Khataniar, S.; Hemsath, J. R. Transp. Porous Media 2009, 76, 77–94. (10) Alagic, E.; Skauge, A. Energy Fuels 2010, 24, 3551–3559. (11) Austad, T.; RezaeiDoust, A.; Puntervold, T. Proceedings of the 2010 SPE Improved Oil Recovery Symposium; Tulsa, OK, Apr 24-28, 2010; Paper SPE 129767. (12) Pu, H.; Xie, X.; Yin, P.; Morrow, N. R. Proceedings of the 2010 SPE Annual Technical Conference; Florence, Italy, Sept 19-22, 2010; Paper 134042. (13) Tang, G. Q.; Morrow, N. R. Geophys. Monogr. 2002, 129, 171–179. (14) Lager, A.; Webb, K. J.; Black, C. J. J.; Singleton, M.; Sorbie, K. S. Petrophysics 2008, 49, 28–35. (15) Sarkar, A. K.; Sharma, M. M. J. Pet. Technol. 1990, 42 (5), 646–652. (16) Meyers, K. O.; Salter, S. J. Proceedings of the 1984 SPE/DOE Enhanced Oil Recovery Symposium, Tulsa, OK, Apr 15-18, 1984; Paper 12696. (17) Tie, H. G.; Tong, Z. X.; Morrow, N. R. Proceedings of the 2003 International Symposium of the Society of Core Analysts, Pau, France, Sept 21-24, 2003; Paper 2003-02. (18) Salathiel, R. A. Trans. Am. Inst. Min., Metall., Pet. Eng., Soc. Min. Eng. AIME 1973, 255, 1216–1224. (19) Sakellariou, A.; Sawkins, T.; Senden, T. J.; Limaye, A. Physica A 2004, 339, 152–158. (20) Dubey, S. T.; Waxman, M. H. SPE Res. Eng. 1991, Aug, 389395. (21) Lebedeva, E. V.; Fogden, A.; Senden, T. J.; Knackstedt, M. A. Proceedings of the 2010 International Symposium of the Society of Core Analysts, Halifax, Canada, Oct 4-7, 2010; Paper 2010-11. 1615

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