Electrostatics and the Low Salinity Effect in Sandstone Reservoirs

Jan 26, 2015 - There is widespread interest in improved oil recovery by the low salinity ... Citation data is made available by participants in Crossr...
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Electrostatics and the Low Salinity Effect in Sandstone Reservoirs Patrick V. Brady,*,† Norman R. Morrow,‡ Andrew Fogden,§ Vivianne Deniz,§ Nina Loahardjo,‡ and Winoto‡ †

Sandia National Laboratories, Albuquerque, New Mexico 87185-0754, United States Dept. of Chemical and Petroleum Engineering, University of Wyoming, Laramie, Wyoming 82071, United States § Department of Applied Mathematics, Research School of Physics and Engineering, Australian National University, Canberra, Australian Captial Territory 0200, Australia ‡

S Supporting Information *

ABSTRACT: There is widespread interest in improved oil recovery by the low salinity effect (LSE) and a pressing need to better predict the likely response and its relation to wettability change. A LSE in kaolinite-bearing sandstones can arise from detachment of crude oil, by its peeling from rock surfaces due to increased oil/rock repulsion, and/or by detachment of mineral fines with adhering oil, due to increased fines/rock repulsion. In a mixed wet sandstone reservoir, oil is typically in close contact with an extremely small fraction of total rock surface, a key component of which are asperity tips such as at edges of kaolinite platelets. An Integrated pH Ion Surface Electrostatics (IpHISE) model is used to predict speciation and interactions of oil surfaces and kaolinite edges across NaCl and CaCl2 solutions of variable pH in sandstones. At pH < 5, a LSE can arise by weakened oil adhesion due to fewer positively charged oil base groups adsorbed to kaolinite edges. At higher pH, the electrostatics is dictated by competition between negatively and positively charged acid groups produced by respectively deprotonation and calcium binding. The LSE is predicted to be strongest in a narrow range around pH 5−6 in which salinity reduction switches the oil/kaolinite edge interaction to repulsive. At pH > 6, the interaction becomes increasingly repulsive at all salinities. There, a LSE can only arise from the extended range of repulsion, both between oil and kaolinite edges and between the latter and the underlying rock. The existence and cutoff values of these pH ranges depend sensitively upon the oil’s acid number/base number, salt concentrations, and the pH shift caused by injection of low salinity fluid.

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INTRODUCTION It has been shown that brine composition, through its effect on Crude Oil/Brine/Rock (COBR) interactions, can result in large variation in waterflood and spontaneous imbibition recoveries.1 Widespread attention has been given to low salinity waterflooding, especially over the past decade.2 In some cases, low salinity water can prompt the recovery of an additional 10−30% OOIP for the relatively low cost of water treatment. Necessary conditions for improved recovery by low salinity waterflooding from sandstone cores include the presence of crude oil, clay, and connate water.3 Nevertheless, caution must be exercised in implementation of low salinity waterflooding because, in numerous laboratory tests and some pilot tests, no improvement, or only very little additional recovery, was observed.4,5 The circumstances under which oil recovery is improved by the low salinity effect (LSE) need explanation. Proposed LSE mechanisms include double layer expansion between fine particles and Limited Fines Release (LFR) with change in wettability toward water wetness resulting from removal of the mixed wet fines;3 double layer expansion between oil/rock contact areas;6−9 and multicomponent ion exchange (MIE).10 There is a consensus that the LSE is prompted by moderate decrease in adhesion of oil, which translates to increased water wetness. However, global decrease in adhesion to give very strong water wetting is ineffective because the oil would remain trapped. All proposed LSE mechanisms involve electrostatic interactions between COBR surfaces. Three obstacles have © XXXX American Chemical Society

prevented quantitative linking of electrostatics with oil recovery. Core floods and field evidence comingle oil transport with wettability, making it difficult to isolate the specific role of surface chemistry. Surface charge measurements on reservoir materials have historically been performed using zeta potentials, which are not easily converted into predictive thermodynamic models of interfacial reactivity. Lastly, multiple mechanisms can operate simultaneously, preventing resolution of the individual contributions. This paper begins by reviewing the physics of the oil and rock interfaces existing in sandstone reservoirs prior to waterflooding and outlining the methodology for calculation of speciation and complexation of ions at oil interfaces and kaolinite edges in model sandstone systems. Results for the oil and kaolinite edge interfacial charges and their mutual electrostatic interactions are then used to indicate the regimes of pH, salinity, and oil surface parameters under which a LSE can arise. We specifically consider the simultaneous effect of pH and ion exchange on oil and mineral surface electrostatics, which we term an Integrated pH−Ion−Surface Electrostatics (IpHISE) model. Reservoir Wettability. COBR interactions have direct impact on wetting and oil recovery. Oil reservoirs contain an initial water saturation established by drainage. The drainage Received: November 6, 2014 Revised: January 22, 2015

A

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Energy & Fuels process develops extensive oil/water interfaces plus oil/rock close contacts. Salathiel11 proposed that oil/rock close contact provides sites for adsorption of polar components from the oil which results in strongly oil wet surfaces, while noncontacted areas overlain by bulk water remain strongly water wet. The simultaneous existence of contacted and noncontacted areas, described by Salathiel as mixed wet, is the most widely accepted model of reservoir wettability. In the extension by Kovscek et al.,12 adsorption of asphaltenes is assumed to occur over a substantial fraction of the model rock surface and results in completely oil wet surfaces, with contact angles of 180°. However, measured advancing contact angles for crude oil against water on quartz, mica, or soft glass typically range from 30° to 140°13 (i.e., from water wet to oil wet), depending on brine composition, ionic strength, pH, crude oil, and substrate. Higher angles, approaching 160°, can only be attained by destabilizing the oil, for example by adding alkanes to cause surface precipitation of asphaltenes.13 One implication is that the wetting state of the contacted areas can cover a wide range of possibilities, but they do not extend to complete oil wetting. At the other end of the wettability spectrum, there is never complete wetting by water against crude oil as evidenced by nonzero contact angles; water does not spread against crude oil, even on very strongly water wet mineral surfaces. Freer et al.14 recognize the existence of intermediate contact angles and explain effectively 0° or 180° contact angles in terms of pinning because of chemical heterogeneity at the three phase contact line on smooth substrates. Electron micrographs of sandstones typically show pore surfaces with dense populations of surface asperities (Figure 1) and varied mineralogy. The Salathiel model was modified to include the effect of the inherent roughness of pore walls.15 Most of the oil/mineral close contacts are envisioned to occur at the asperity tips (corners and edges) where only a small number of intervening water layers are retained. This condition is referred to as speckled wettability.15 A key input to characterization of wettability alteration is the total interfacial areas created by drainage. The work of drainage, derived from capillary pressure data, sets a theoretical upper limit to the created oil/water and oil/thin water film/rock areas. For drainage to 20% water saturation, only 1/100th of the rock’s Brunauer−Emmett−Teller (BET)16 surface area, at most, is closely contacted by oil.17 This limit must be reduced by the efficiency of conversion of work to surface free energy because the drainage process is inherently irreversible.18 Direct measurements of interfacial areas for a sandstone show that this conversion is only about 36% efficient,19 thus lowering the maximum possible area of close contact to 1/300th of the rock surface. Recently, Kibbey20 showed how the curvature of the air/bulk water surface that spans the peaks of asperities is set by the capillary pressure. For very strongly water wet conditions, the number of engaged asperities increases as the capillary pressure and hence the interfacial curvature increases, even for a relatively smooth sand grain and a manufactured sphere. For rough pore walls in sandstones such as in Figure 1b, assemblies of small mineral crystals typically extend about 10 μm from the underlying grain. A simple illustration of capillary retention within such areas of asperities is presented in Figure 2a. The increase in meniscus curvature, 2/r, with capillary pressure is illustrated for an oil/brine interfacial tension (IFT) of 25 mN/ m. Drainage increases the areas of close contact between rock

Figure 1. SEM images showing (a) rough and comparatively smooth surfaces in a reservoir sandstone that is highly responsive to low salinity waterflooding; (b) close up of a rough area.

Figure 2. (a) Change in curvature of oil/water interfaces with increasing capillary pressure (oil/brine IFT = 25 mN/m); (b) illustration of distribution of oil and water at 5 psi. Green/brown and black/brown boundaries indicate thin and initially thick CWFs, respectively.

and oil at the expense of areas overlain by bulk water. The changes in area are very fast for jumps from unstable to stable oil/water interface configurations. As capillary pressure increases, the number of engaged asperities increases. An area of close contact between rock and oil is separated by what will be referred to as a thin contouring water film (CWF), illustrated by the green asperity tips in Figure 2b. These are potential sites for adsorption of the oil’s polar components, if B

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sum of surface organic acids and bases, nominally quantified through acid number (AN) and base number (BN) measurements on the bulk oil. (3) Surface charge varies with pH as the surface acids and bases lose or acquire H+ to or from solution. (4) The acidity and basicity of the oil surface groups is close to that of their aqueous monomer equivalents. Sandstone BET surface areas mostly fall within 0.3 to 3 m2/g, even though permeabilities can vary by over 6 orders of magnitude. Because surface areas of quartz grains tend to be 0.1 m2/g or less, much of the sandstone area must come from small grain clays whose surface areas27 range from 10 (kaolinite) to 100 (Illite) m2/g. Surface site densities of clays27 are 0.4−6 sites per nm2, equal to 0.67−10 μmol/m2. Given their relatively high area, site density, and reactivity, clay aggregates and their edges are one of the most important sources of pore wall asperities (e.g., in Figure 1b) and thus will play a disproportionately large role in oil/sandstone wettability and adhesion. Below, we focus, in particular, on edges of kaolinite because of its ubiquity in many sandstones, and its previous identification with the LSE (e.g., ref 28). Table 1 lists oil and mineral surface complexation constants that are used, together with assumed oil and mineral surface

thermodynamically favorable. This requires that the total disjoining pressure, given by the sum of capillary pressure of the bulk water/crude oil interface, COBR interfacial interactions across the retained water film, and any meniscus curvature contribution (which will be high for the corners and edges at the tips of asperities), is net attractive. A greater fraction of surrounding rock area (although still very small relative to its BET area) will initially come into more distant contact with the crude oil than for the tip. This fraction is illustrated by the black areas of rock in Figure 2b that are also contoured by the crude oil. Here, the intervening water film is thicker than the thin CWF and will be referred to as a thick CWF. The initial thickness of the thick CWFs depends more on the prevailing capillary pressure, as interfacial interactions and meniscus curvature contributions are weaker there. Aging, Adhesion, and Oil Recovery. The fact that electrostatic attraction occurs within seconds, but 40 days or so aging time is recommended for cores to attain consistent wettability,21−23 shows that additional slow processes, promoted by elevated temperature, are involved in determining the attained wettability state. The aging time is related to several processes, with the main factors being the time required for equilibration of CWFs and adsorption and the stability of the three phase contact lines at the asperities. Even smaller scale roughness than illustrated in Figure 2 may trap pockets of bulk water, which will also affect the equilibration processes. Development of adhesion involves two reorganizational changes within the contact areas. Oil polar species pack into a more fully formed film, and excess water trapped under the film diffuses out. Further, the thin CWF area at each asperity after drainage may expand with aging, encroaching into the initially thick CWF region (from the green into the black shown in Figure 2b). Lateral advance of oil by thinning of the thick CWF at its periphery may be expected if the electrostatic COBR interactions are strongly attractive. The local advance will, however, halt once the three phase line becomes pinned or encounters a valley in which the presence of bulk water results in separation between oil and rock that exceeds the range of electrostatic attraction. Such issues have relevance beyond adhesion; the water retained by asperities largely controls electrical resistivity measurements that, historically, have been empirically correlated with total water saturation. Low salinity waterflooding can decrease oil/rock adhesion by decreasing the number of adhesion sites via desorption of oil polar species from the areas of the developed thin CWFs. Further, enhancement of COBR repulsion across areas overlain by thick CWFs will also promote oil detachment. Both scenarios translate to a shift toward water wetness. Crude oil/brine interfaces in inherently rough glass micromodels can move by a stick/slip motion, related to unpinning at asperities. Decreased pinning results in efficient displacement through peeling of oil from the pore walls. Optimum recovery by the LSE is given by peeling without loss of oil connectivity by snapoff ahead of the mobilized oil. Assumptions and Parameters of Calculations. Here, we expand the approach of Brown and Neustadter,24 Buckley et al.,25 and Dubey and Doe.26 It was argued that oil adhesion is primarily caused by electrostatic attraction between charged oil and mineral surfaces separated by a thin water layer. Changes in pH, salinity, and divalent cation levels (e.g., ref 13) control the strength of attraction and the degree of wetting. Four central features of the model are as follows: (1) The pH is mainly set by rock/brine interactions. (2) Oil/water interface charge is the

Table 1. Surface Complexation Model Input Parameters log K25°C

reaction oil surface −NH+ ↔ −N + H+ −COOH ↔ −COO− + H+ −COOH + Ca2+ ↔ −COOCa+ + H+ quartz >SiOH ↔ >SiO− + H+ >SiOH + Ca2+ ↔ >SiOCa+ + H+ >SiOH + CaOH+ ↔ >SiOCaOH + H+ kaolinite edges >AlOH2+ ↔ >AlOH + H+ >AlOH ↔ >AlO− + H+ >SiOH ↔ >SiO− + H+ >AlOH + Ca2+ ↔ >AlOCa+ + H+ >SiOH + Ca2+ ↔ >SiOCa+ + H+ >AlOH + CaOH+ ↔ >AlOCaOH + H+ >SiOH + CaOH+ ↔ >SiOCaOH + H+ kaolinite basal plane >H + Na+ ↔ >Na + H+ 2>Na + Ca2+ ↔ >Ca + 2Na+

−6.0 −5.0 −3.8 −4.0a −9.7b −4.5b −3.0 −3.8 −7.0 −9.7 −9.7 −4.5 −4.5 −4.6c 0.21d

a

From Buckley et al.25 bSet equal to values for kaolinite. cFrom Wieland et al.32 for montmorillonite. dFrom Wanner et al.33 for montmorillonite.

areas and site densities, to estimate surface charge. All equilibrium constants in Table 1 are from Brady et al.,29 except where noted. It should be emphasized that these constants were developed independently of core flood and reservoir data; there was no fitting of thermodynamic constants. Mineral surface complexation constants came from potentiometric titration measurements. Oil constants are set equal to aqueous monomer values. For example, the acidity of monocarboxylate groups at the oil surface is set equal to that of a dissolved monocarboxylate. Electric double layer effects of the interfaces at large separation are accounted for using a diffuse layer model.30 The geochemical speciation code PHREEQC31 is used to calculate the effect of pH and Ca levels on surface speciation. C

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Energy & Fuels Oil and Sandstone Speciation and Surface Charge. Figure 3a shows calculated 60 °C charged surface species

these ranges each will be more highly charged, polar, and hydrophilic. In short, only general trends in oil surface charge can be predicted by the model used to build Figure 3. −NH+ and −COOCa+ are electrostatically the most likely oil surface species to be attracted to negatively charged sandstone surfaces;25,34 the effect of waterflood chemistry on these interactions can be estimated. Net oil/water surface charge correlates with IFT;35−37 for example, IFT tends to decrease at pH > 5 because of carboxyl deprotonation. However, except at very low or high pH, the IFT decrease caused by changes in reservoir solution chemistry is relatively small38 and is far less than the reduction achieved by surfactant addition. Tang and Morrow3 reported reductions in IFT from about 20 to 16 mN/m from high to low salinity brine. McGuire et al.39 later proposed IFT lowering associated with pH increase as the LSE mechanism. However, many studies conclude the IFT lowering per se is not a key factor in the improved recovery (e.g., refs 3, 6, 40, 41). Clay edges are positively charged at low pH and negatively charged at higher pH. Figure 4 shows calculated 60 °C kaolinite

Figure 3. Crude oil/water interactions. Calculated surface concentration of ionized species at the oil/water interface versus pH for three NaCl concentrations at 60 °C. AN/BN = 0.5 (1 g oil in contact with 1 L of water). (a) NaCl, (b) NaCl + 5 mM CaCl2.

Figure 4. Water/sandstone interactions. Calculated 60 °C kaolinite edge and quartz surface speciation in 1.0 and 0.1 M NaCl solutions (surface site density = 3.84 μmol/m2 for quartz and kaolinite; 11.4 kg quartz and 2.89 kg kaolinite/L water).

concentrations for an oil having 2 nitrogen base groups, −N, for each acid group, −COOH, in NaCl solutions, with 1 g of oil per liter of solution. AN + BN is assumed to equal 1 mg KOH/ g oil, which corresponds to 12 and 6 μmol/m2 of −N and −COOH sites. For pH < 5.7, oil surface charge is dominated by −NH+ groups, and at a given pH, increasing ionic strength increases the number of −NH+ groups. Above pH 5.7, −COO− groups dominate oil surface charge and ionic strength increases the number of these groups. Note that an increase in ionic strength decreases the number of −NH+ groups at pH > 5.7 and −COO− groups at pH < 5.7. Figure 3b shows calculated charged surface species concentrations for the same oil but in NaCl solutions initially containing 5 mM CaCl2. −COOCa+ groups are calculated to form at the model oil surface at pH > 5. Increasing NaCl concentration decreases the number of −COOCa+ groups at a particular pH, largely by decreasing the activity coefficient of dissolved Ca. The trends for the model oil/water interface in Figure 3 are complicated by at least three factors when applied to crude oils. There will be a range of surface group acidity constants because of multiple bonding configurations. The total number of acid and base groups active at the oil surface will be smaller than the acid and base numbers measured by titration because of selfassociation inside the oil. More nitrogen base groups will diffuse from the interior to the surface at pH < 5; more carboxyl groups will be expressed at the surface at pH > 5, because in

edge charge and quartz surface charge in water as a function of pH and NaCl concentration. The two surface charging reactions are >SiOH ↔ >SiO− + H+ >Al:SiOH ↔ >Al:SiO− + H+

>SiOH is a quartz surface site; >Al:SiOH is a kaolinite edge Al or Si site. The second reaction is collectively the second and third kaolinite edge reactions in Table 1. In Figure 4, >Al:SiO− is the sum of >SiO− and >AlO−. The primary difference between the two is that Al sites can acquire an H+ to become >AlOH2+ (see Table 1) at pH < 6. Quartz surfaces are negatively charged above pH 2. The effect on kaolinite edge and quartz surface charge in Figure 4 is similar for increasing pH and increasing NaCl: the negative charge becomes more pronounced. Figure 5 shows calculated 25 and 100 °C Ca2+ sorption to kaolinite edges as a function of pH, NaCl (with initial calcium concentration Ca0 = 20 mM), and temperature for a surface area of 1 m2/g. NaCl depresses Ca2+ sorption, in part by decreasing its activity coefficient as for oil in Figure 3b. Increasing temperature shifts the Ca2+ adsorption isotherm to lower pH. Comparing Figures 3b and 5 (and bearing in mind D

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Figure 5. Water/kaolinite edge interactions. Calculated 25 and 100 °C Ca2+ sorption to kaolinite edges (surface site density = 3.84 μmol/m2; 2.89 kg kaolinite/L water). The solid line is 0.1 M NaCl and the dashed line is 1 M NaCl, both initially containing 20 mM CaCl2.

Figure 6. Predicted electrostatic adhesion of crude oil to kaolinite edges. Calculated dependence of BPS at 60 °C on pH and AN/BN in the high salinity brine and after switching to the low salinity brine (3.4 kg kaolinite/L water and 2.1 kg oil/L water). Dashed lines are high NaCl, Ca; solid lines are low NaCl, Ca.

the log scale of the latter), Ca2+ binding to oil occurs at lower pH than Ca2+ sorption to kaolinite edges; in essence, Ca2+ prefers to bind to oil carboxylate groups. The acid−base reactions at oil and kaolinite surfaces, and Ca2+ coordination to either, should occur very rapidly, within seconds at most. Ca2+ desorption from oil and kaolinite surfaces will take longer, partly due to the requisite reorganization of asphaltene surface structures.14 Bond Product Sum of Oil Interaction with Kaolinite Edges. A simple means of combining the surface charge calculations of oil and kaolinite edges to estimate their mutual electrostatic adhesion is given by the Bond Product Sum (BPS) construct presented in this section. The subsequent section then compares these estimates to calculated oil/kaolinite edge disjoining pressure isotherms. The BPS is the total of the products of the surface concentrations of oppositely charged species on the oil and mineral. Consider two end-member BPS scenarios. If oil and mineral surfaces only contain negatively charged species, the BPS would equal zero because no oppositely charged surface groups exist; electrostatic adhesion would be unlikely, and water wetness would prevail. If the oil and mineral only contain positively and negatively charged surface species, respectively, the BPS would be high, and the potential for adhesion at contact points would be high. For oil/kaolinite edges, the BPS is equal to [>AlOH2+] [−COO−] + [>Al:SiO−] [−NH+] + [>Al:SiO−] [−COOCa+] + [>Al:SiOCa+] [−COO−]; bracketed terms are surface species concentrations in μmol/m2. These are the four oppositely charged oil and kaolinite edge pairs from Table 1. Figure 6 shows calculated 60 °C pH-dependent BPS for two crude oils having AN/BN ratios of 1 and 0 in a sandstone undergoing waterflood. The pair of curves for each AN/BN are before and after snapshots of the high to low salinity transition in a sandstone reservoir with an assumed porosity of 0.20 and 10% v/v kaolinite, having fractional saturations, S, of Swater = 0.30, and Soil = 0.70. The reactive kaolinite edge surface area was set to 1 m2/g, with surface site density of 4 μmol/m2. The oil/rock specific surface area was set to 0.1 m2/g, with oil surface site density of 1.2 μmol/m2. The predicted surface speciation is relatively insensitive to the latter two numbers. Oil interactions with quartz were neglected due to its low surface area. The oil and kaolinite edge surface complexation models were used to calculate the charged site abundances for a high salinity flood −0.4 M NaCl + 5 mM CaCl2 (initially), and for a subsequent

(20-fold diluted) low salinity flood −20 mM NaCl + 0.25 mM CaCl2 (initially). Specifically, the oil and kaolinite edge speciation from equilibration of the system with 1 pore volume (PV) of the high salinity solution were saved from this first calculation and then numerically re-equilibrated with 1 PV of the low salinity solution, and the new speciation was calculated. There is clear distinction between the presented predictions for kaolinite edges and the multicomponent ion exchange concept presented by Lager et al.10 for a smooth substrate. The MIE model should include cation coordination with negatively charged clay edges as well as cation exchange onto negatively charged basal plane sites. However, oil adhesion will differ between clay edges and basal planes. The former varies with pH because of the acid−base functionality of edge charge sites, whereas basal plane cation exchange results from lattice substitution and is largely independent of pH. It is reasonable to focus on kaolinite edges because basal plane charge is relatively low and kaolinite booklets in sandstones typically grow outward from the pore wall. From Figure 6, the BPS suggests that a low salinity waterflood will prompt decreased oil adhesion at pH < 5−6, the magnitude depending on the AN, BN, and pH. The corresponding predicted increase in recovery by the LSE with decreasing pH below pH 6 is consistent with the coreflood observations of van Winden et al.42 What the BPS fails to predict is a LSE at pH > 6 as reported by van Winden et al.42 and others. This may point to a limitation of either the BPS construct or the surface parameters chosen in Figure 6, or it could mean that the LFR mechanism was in play, as discussed in a later section. The simplest way to make the BPS account for a LSE at pH > 6, consistent with coreflood and field results, is by raising the oil −COOCa+ association constant from 10−3.8 (as in Table 1) to 10−3.0; the two are compared in Figure 7 for the AN/BN = 1 case. Specifically, the oil −COOCa+ association constant was changed until the BPS calculation gave a LSE effect at pH > 6. Note that the original constant was not measured, but instead, was estimated from the aqueous calcium−acetate ion association constant; all the other constants in Table 1 have a stronger experimental basis, hence the focus on the oil −COOCa+ association constant. E

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region of minimum LSE, 6 < pH < 7 in the green lines of Figure 7, has been observed in coreflood results.41,43 In Figure 6, BPS predicts that an oil with AN ∼ 0 will see a sizable LSE below pH 6, but only slight LSE at pH > 6. Any increase in pH from H+/Na+ exchange (see below) should prompt a slight overall increase in recovery. The combination of low AN and pH > 6 might explain the poor low salinity response seen at the Snorre Field.44 The Snorre oil had a BN = 1.1 and AN = 0.02 mg KOH/g oil, analogous to the AN/BN = 0 (red line) oil in Figure 6. Coreflood pH ranged from 7.5 to 9.5 (i.e., conditions that Figure 6 indicates limit an electrostatic LSE). However, Skrettingland et al.44 observed a significant LSE for an oil with BN = 1.1 and AN = 3.2 mg KOH/g. Such an oil is closer to the green line in Figure 7 where the adjusted BPS would predict a LSE. Disjoining Pressure of Oil Interaction with Kaolinite Edges. Calculation of the disjoining pressure isotherm of oil and kaolinite edges complements the BPS estimates by giving deeper thermodynamic insight into the interactions and their dependence on interfacial separation. Total disjoining pressure, PTot, across the water between oil and kaolinite edge interfaces, regarded as planes at separation distance L under the Derjaguin approximation, was modeled within the DLVO framework55 as the sum

Figure 7. Calculated dependence of oil/kaolinite edge BPS at 60 °C on pH for high salinity brine and after switching to low salinity brine, for two oils with AN/BN = 1 but with different calcium carboxylate K values (all other parameters are the same as in Figure 6). Dashed lines are high NaCl, Ca; solid lines are low NaCl, Ca.

The BPS predicts a minimum in oil detachment LSE for oils with AN and BN > 0 caused by the increase in the concentration of −NH+ or −COOCa+ groups with decreased salinity that can be seen at pH > 5.3 in Figure 3a and b. This

Figure 8. Total disjoining pressure, under the condition of constant charge (solid lines) or constant potential (dotted lines), versus interfacial separation of the three oils (a−c) and kaolinite edges within sandstone at 60 °C in high salinity brine (at left) and after switching to low salinity brine (at right), at each of six pH values. (All other parameters are the same as in Figures 6 and 7.) F

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Figure 9. Comparison of bond product sum and negative disjoining pressure. BPS (black) and total disjoining pressure (PTot, negated, under the condition of constant charge (green) or constant potential (purple)) between each of the three oils and kaolinite edges within sandstone at 60 °C in high salinity brine (dashed lines) and after switching to low salinity brine (solid lines), each at varying pH. Pressure is evaluated at the barrier in parts a−c and at the fixed separations of 10, 15, and 20 Å for the constant charge case in parts d−f. (All parameters are the same as in Figure 8.)

PTot = PDL − H /(6πL3)

in the BPS calculations. The bulk concentrations of dissolved ions in equilibrium were thus inputted from the same speciation calculations, as were the surface concentrations of charged species on oil and kaolinite edges present at large separation. The kaolinite edges are strongly negatively charged (due to the high site density), and increasingly so for increasing pH and salinity (in line with Figure 4). The oil surface for AN/ BN = 1 transitions from positively to negatively charged around pH 5.2 (similar to the crossover seen in Figure 3) and attains more negative values for K−COOCa+ = 10−3.8 than 10−3.0, while it remains positively charged up to pH 9 for AN/BN = 0 (see the Supporting Information). The magnitude of all total surface charge densities increases with salinity, while the opposite is true of the corresponding surface potentials at large separation. On subsequent approach, both interfaces were assumed to maintain either their surface charge density (i.e., constant charge (CC) condition) or their surface potential (i.e., constant potential (CP)). These conditions represent upper (most repulsive) and lower (most attractive) bounds, respectively, on

The second term is the nonretarded Hamaker pressure, with H taken as 1.0 × 10−20 J.25 The first term, PDL, is the electrical double layer pressure, obtained from numerical solution of the Poisson−Boltzmann (PB) equation for the electrostatic potential field. This DLVO approximation omits, among other things, short-range, repulsive, structural forces.55,56 Such non-DLVO contributions were not included here as their existence at rock surfaces under reservoir conditions has not been established, and neither has a theoretical route to predict their input parameters. For a specific crude oil of interest, electrophoretic mobility of emulsions in dilute NaCl and CaCl2 solutions at varying pH would be measured to infer zeta potential.25 This would then be matched to the PB solution to back out the best-fit acid and base site densities and equilibrium constants, which would provide the oil input values to PHREEQC. However, the results in this section pertain to the COBR model systems used G

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pressure curves under CC (aside from the stronger upturns of BPS for AN/BN = 1 at pH extremes), and their high/low salinity crossovers lie close to the pHHL (as shown by the dotted vertical lines). The greater similarity to CC than to CP stems from CC maintaining on approach the same charged species densities at large separation that were used to calculate BPS. However, as the zero of pressure is not included in the BPS, its trends are not comparable to those of pressure at larger separation in Figure 9d−f. In the context of primary drainage, further thinning of the thin CWF (e.g., marked green in Figure 2b) and adsorption of the oil’s polar molecules will occur at reservoir pH < pHH for the connate brine (which is generally of a different high salinity composition than the flood brine). Rock will also attract oil across regions of thick CWFs (e.g., black in Figure 2b) but at insufficient range to allow substantial adsorption there. For pH > pHH, rock repels oil and the water wet state persists unless the effect of the prevailing capillary pressure on the disjoining pressure overcomes the repulsive barrier, which is unlikely for kaolinite edges given the large maxima in Figure 8. For relevance to the LSE, the mixed wet scenario is assumed to apply. Table 2 categorizes the effects of high and low salinity flooding on thin CWFs and thick CWFs (taken as above

the disjoining pressure calculated using any other formalism. The most realistic intermediate scenario would be charge regulation,55,56 in which both the surface charge and surface potential of the two interfaces vary on approach such that the complexation equilibria of Table 1 are respected at each separation for the corresponding local concentrations of H+ and Ca2+. Figure 8 shows the isotherms of total disjoining pressure versus separation distance on approach of oil to kaolinite edges across the high or low salinity solutions at each of the six pH values. Positive and negative pressures signify repulsion and attraction, respectively. The disjoining pressure profiles are negative and monotonically decrease on approach (i.e., are purely attractive) at lower pH, where the interfaces are oppositely charged, and exhibit a progressively more repulsive barrier at increasingly close separation at higher pH. The oils with AN/BN = 1 and K−COOCa+ = 10−3.8 or 10−3.0 are similarly attracted to kaolinite edges at lower pH, while at higher pH the latter case gives less repulsion, but still substantially more than the least repulsive case of AN/BN = 0. Compared to CC, the more attractive CP condition causes the repulsive barrier to shift outward and weaken or vanish. Salinity decrease also causes the profiles to shift outward and dilate, due to reduced electrostatic screening, while the barrier strengthens or weakens depending on the competing effects. Figure 9a−c shows the maximum in PTot under CC or CP. This barrier height from Figure 8 is negated in Figure 9 to be comparable to BPS in sign, that is, more positive is now more attractive. Profiles without a maximum at a given pH were evaluated at the separation of the nearest higher pH maximum. Each of the three oil/kaolinite edge systems under CC exhibits a sequence of three critical pH values, namely pHL, at which a repulsive barrier first forms for low salinity, followed by the analogous pHH for high salinity, and finally pHHL, beyond which the barrier becomes more repulsive for high salinity than low salinity. For AN/BN = 1 in Figure 9a and c, pHL and pHH are around 4.8 and 5.4, while pHHL shifts from 5.8 for K−COOCa+ = 10−3.8 to 6.4 for K−COOCa+ = 10−3.0 due to the weakened repulsion in high salinity. For AN/BN = 0 in Figure 9b, the corresponding critical pH are around 5.8, 7.2, and 9. These three pH intervals are not manifested under CP. For this condition, Figure 9a shows slightly more barrier repulsion to kaolinite edges in high salinity than in low salinity across all pH, while Figure 9c shows a crossover at pH 5.5. The CP curves in Figure 9b are largely arbitrary because maxima are absent from these profiles in Figure 8b. Significant differences between CC and CP are expected for such asymmetric systems56 and underline the need for the more realistic charge-regulation description of oil/kaolinite edge interaction in future studies. Figure 9d−f shows the corresponding PTot under CC evaluated at constant separation distance (thus having a constant Hamaker attraction) in Figure 8 of 10 Å, which lies beyond the high salinity maxima and close to the low salinity maxima, as well as 15 and 20 Å, which lie on the decaying tails. Note that the pressure scale is exaggerated 10-fold from Figure 9a−c. Increasing separation reduces the magnitude of the curve from that in Figure 9a−c, with its zero remaining fixed at pHH or pHL (as shown by the dashed and solid vertical lines). This compression is greatest for high salinity owing to its shorter Debye length of decay; even 10 Å separation suffices for the higher pH trend of increase in maximum repulsion with salinity in Figure 9a and c to be reversed in Figure 9d and f. The BPS curves in Figure 9a−c are most similar to the maximum

Table 2. Qualitative Behavior of Oil/Kaolinite Edge Disjoining Pressure (Negated so Positive Values Indicate Attraction) in the Four pH Regimes in Figure 9 for Thin and Thick CWFsa

a

Downward and upward arrows represent attraction and repulsion; pink and yellow represent high salinity (HS) and low salinity (LS).

roughly 10 Å to lie on the decaying pressure tails) in terms of the three critical values of pH in Figure 9. This serves to refine the BPS predictions for pH < pHHL into three subscenarios. In the lowest pH range (pH < pHL) in Table 2, oil/kaolinite edge attraction is operative at all salinities. Compared to high salinity, low salinity weakens adhesion (i.e., attraction in close contact) across thin CWFs but grades to strengthening attraction across thick CWFs. Thus, wettability change and tertiary recovery may be limited unless the prevailing capillary pressure and viscous forces provide the added impetus for oil to peel away from the rock. In the second pH range (pHL < pH < pHH), low salinity switches the interaction to repulsive, favoring separation of oil and rock across thick CWFs and promoting detachment (i.e., repulsion from close contact) at thin CWFs. For these conditions, the LSE is expected to be substantial. In the third range (pHH < pH < pHHL), the effect of high salinity switches to give repulsion. If this repulsion is insufficient to detach oil, a tertiary LSE driven by its stronger repulsion at all distances can still be expected. In the highest pH range (pH > pHHL), high H

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Figure 10. (a) Total disjoining pressure, under the condition of constant charge (solid lines) or constant potential (dotted lines), versus interfacial separation of kaolinite edges within sandstone at 60 °C in high salinity brine (at left) and after switching to low salinity brine (at right), at each of six pH values. (b, c) Bond product sum (BPS, black), and total disjoining pressure (PTot, negated, under the condition of constant charge (green) or constant potential (purple)) evaluated at the separation (b) corresponding to maximum repulsion or (c) 10, 15, and 20 Å, in the high salinity brine (dashed lines) and low salinity brine (solid lines), each at varying pH. (All kaolinite surface parameters are the same as in Figures 8 and 9.)

silicate minerals tends to be too slow to buffer pH, though albite dissolution has been argued to raise reservoir pH.47 Fines Migration and Release of Oil. However, what if the clay particles to which oil adheres release and boost recovery by liberating attached oil and/or diverting flow, as proposed for the LFR mechanism? If massive global clay release occurred, as reported for flow of very low sodium brines, the core would plug.48 Plugging is more often associated with a sudden reduction in salinity. Very high counts on particles in aqueous phase effluent were detected by Donaldson and Baker49 and Sarkar and Sharma.50 Fines release from a diatomite increased with temperature as a result of an increase in negative charge on both mineral surfaces.51 However, reservoir pH, which tends to decrease with temperature, would compensate for some of this effect. With regard to the LSE, the increase in recovery of mineral oil reported by Bernard52 at very low sodium concentrations is an outlier because it was accompanied by severe formation damage and gave a much higher increase in pressure drop than any subsequently reported for a crude oil LSE. Tang and

salinity gives stronger repulsion across thin CWFs, so the only driver for oil detachment by LSE is the stronger repulsion across thick CWFs. It should be emphasized that these trends are for CC and that qualitatively different behavior would be predicted for CP. pH Shift. Low salinity corefloods and waterfloods see both increases and decreases in pH. pH will rise because decreased Na+ levels prompt ion exchange uptake of H+:45 >Na + H+ ↔ >H + Na +

Dissolution of calcite or dolomite cements will also increase pH, as will the introduction of a waterflood whose CO2 partial pressure, PCO2, is lower than reservoir PCO2 (e.g., ref 43). In CO2-rich reservoirs, pH can decrease because of increased CO2 solubility in low salinity waterfloods.46 The LSE pH shift is a characteristic of the particular brine/rock interactions. Oil/rock adhesion then responds to the ambient pH. This effect, which could be included in the speciation calculations, will substantially alter the predictions in Figures 6−10, as could the presence of H2S. In sandstones, dissolution/growth of I

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Energy & Fuels Morrow3 observed production of oil-free kaolinite fines in the water phase accompanying a LSE. Such particle release does not occur when the core is fully saturated with brine. Release was ascribed to a local effect related to double layer expansion combined with disturbance caused by detachment of mixed wet clay particles with their adhering oil. Lager et al.28 observed no fines production for reservoir cores. Even if fines do not appear in the effluent, the contribution of this LFR mechanism cannot be discounted; Fogden et al.53 demonstrated movement of very small fines associated with oil within Berea sandstone from SEM observations. After liftoff, fines may adhere to the oil as a Pickering emulsion or separate and possibly reattach downstream. Initial mobilization of fines is predicted to occur when their electrostatic repulsion to the underlying rock exceeds their Hamaker attraction.54 Repulsion and mobilization are expected to be greatest at high pH and low Ca.45 As low salinity solutions are initially low in Ca and generally prompt a rise in pH because of H+/Na+ exchange, they should mobilize clay fines. The following DLVO calculations assess the tendency for kaolinite mobilization due to their edge−edge interactions for the same COBR combinations represented in Figures 6−9. Figure 10a shows the total disjoining pressure isotherms versus separation distance on mutual approach of kaolinite edges across the high and low salinity solutions. For such symmetric systems, the electrical double layer pressure is always repulsive (positive in Figure 10a), and here, it is sufficiently strong compared to the Hamaker pressure that all cases exhibit a maximum in repulsion. Increasing pH monotonically increases the repulsive strength at all separations and decreases the barrier separation. The switch from CP to CC has the same qualitative effect, although the dependence on PB boundary condition is not as substantial as for the asymmetric oil/ kaolinite edge systems in Figure 8. The increased repulsion with pH is due to the kaolinite edge’s increasingly strong negative charge. Increasing salinity also boosts the surface charge magnitude to again increase the barrier height and shift it to smaller distance. However, owing to the concomitant increase in double layer screening with ionic strength, low salinity results in higher repulsion than high salinity at larger separations. The BPS of oppositely charged species on adjacent kaolinite edges is [>Al:SiOH2+] [>Al:SiO−] + [>Al:SiOCa+] [>Al:SiO−]. In Figure 10b, the BPS is plotted and compared to the (negated) maximum pressure from Figure 10a. Both measures of adhesion tendency predict that mutual repulsion of closely contacting kaolinite edges increases with pH and with salinity. The BPS upturn for pH > 7 is due to the onset of Ca2+ binding to, and linkage of, kaolinite edge sites, especially for low salinity (as in Figure 5). However, this contribution to maximum disjoining pressure is overpowered by that of the increasing deprotonation of acid sites, especially for high salinity (as in Figure 4), so the net result is increasing barrier height at this higher pH. Figure 10c shows the (negated) pressure under CC at three fixed separations progressively further beyond the repulsive barrier to demonstrate the transition from high salinity favoring repulsion across thin CWFs to low salinity favoring repulsion across thick CWFs. This transition occurs at 14.5 Å separation for all pH and both boundary conditions. Due to spatial constraints in sandstones, kaolinite edges on separate booklets would not get closer than the distance set by the thick CWFs. Thus, mobilization of kaolinite fines at high pH is more likely at

low salinity. In the above-mentioned competition between H+ and Ca2+ for kaolinite edge association, the increased steepness of the high salinity maximum-pressure curve in Figure 10b at pH > 7, due to preference for loss of H+, perseveres in Figure 10c. The decreased steepness of the corresponding low salinity curve in Figure 10b at pH > 7, due to preference for gain of Ca2+, becomes a slight upturn in Figure 10c at separations beyond 15 Å (also seen in Figure 9). LSE because of the LFR mechanism is thus expected to become operative in the two higher pH ranges in Table 2, in which oil repulsion is also operative at all salinities. At pH > pHHL, low salinity has the same effect on oil/kaolinite edges and between kaolinite edges, namely decreasing repulsion across thin CWFs but increasing repulsion across thick CWFs. The contribution of the two LSE mechanisms, IpHISE and LFR, to increasing microscopic displacement efficiency is therefore difficult to decouple, especially given that oil detachment and stripping of mixed wet fines will both result in a shift toward water wetness in coreflood measurements. Reproducibility of LSE and Model Outcrop Sandstones. Overall, reservoir rock shows more consistent positive response in oil recovery to low salinity than outcrop. While reports of the LSE are numerous, examples of reproducibility of data are rare. Inherent problems of core sampling limit tests of reproducibility for reservoir rocks. A vexing aspect of LSE investigation is that over 20 outcrop sandstones did not yield a source of rock that showed consistent response.5 As yet, no outcrop rock has been identified, which can serve as a reliable model. The presented electrostatic calculations offer several potential explanations that can be tested. Any outcrop weathering that alters the reactivity of kaolinite edge sites could influence the LSE. For example, adsorption of Fe(III) and formation of calcite coatings on edges might occur more readily in outcrop samples than under reservoir conditions, causing less consistent and smaller LSE. If the kaolinite morphology, specifically the basal plane to edge exposure ratio, differs between outcrop and reservoir, again possibly due to weathering processes, the LSE will also be affected, given its delicate dependence on the small fraction of rock surface area overlain by the thin and thick CWFs.

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CONCLUSIONS Invasion of clay-bearing sandstones by low salinity brine can perturb COBR interactions to trigger multiple simultaneous reactions: a change in pH, the loosening of oil from clays, and the loosening of clay fines from underlying rock. Oil closely contacts only a small fraction of sandstone surface, especially asperities (crystal edges and corners), where thin or thick contouring water films can respond differently to waterflood salinity and pH changes. Bond product sums and disjoining pressure calculations are effective indicators of the combination of pH, ionic strength, Ca2+, and oil surface parameters for which electrostatic interactions favor a LSE. Disjoining pressure predicts a LSE sweet spot, which occurs around pH 5−6 for the model oils of this study, within which oil and rock attract in high salinity and repel in low salinity across all separations. The method of linking reservoir morphology, surface chemistry, wettability, and COBR interactions to oil recovery can be readily applied to predict waterflood recoveries in sandstone reservoirs containing clays other than kaolinite and to carbonates. J

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(12) Kovscek, A. R.; Wong, H.; Radke, C. J. A pore level scenario for the development of mixed wettability in oil reservoirs. AIChE J. 2004, 39, 1072−1085. (13) Buckley, J. S.; Liu, Y.; Monsterleet, S. Mechanisms of wetting alteration by crude oil. SPE J. 1998, 54−61. (14) Freer, E. M.; Svitova, T.; Radke, C. J. The roled of interfacial rheology in reservoir mixed wettability. J. Pet. Sci. Engr. 2003, 39, 137− 158. (15) Morrow, N. R.; Lim, H. T.; Ward, J. S. Effect of crude oil induced wettability changes on oil recovery. SPE Form. Eval. 1986, 1, 89−103. (16) Brunauer, S.; Emmett, P. H.; Teller, E. Adsorption of gas in multimolecular layers. J. Am. Chem. Soc. 1938, 60, 309−319. (17) Morrow, N. R.; Mason, G. Areas of crude oil/rock contact that govern the development of mixed-wet rocks. 11th International Symposium on Reservoir Wettability, University of Calgary, Alberta, Canada, Sept. 6−9, 2010. (18) Morrow, N. R. Physics and thermodynamics of immiscible displacement in porous media. Ind. Eng. Chem. 1970, 62, 32−56. (19) Seth, S.; Morrow, N. R. Efficiency of the conversion of work of drainage to surface energy for sandstone and carbonate. SPE Reservoir Eval. Eng. 2007, 10, 338−347. (20) Kibbey, T. C. G. The configuration of water on rough natural surfaces: Implications for understanding air−water interfacial area, film thickness, and imaging resolution. Water Resour. Res. 2013, 49, 4765− 4774. (21) Loahardjo, N. Improved Oil Recovery by Sequential Waterflooding and by Injection of Low Salinity Brine; Ph.D. Thesis, University of Wyoming: Laramie, WY, 2009. (22) Raeesi, B. Measurement and Pore-Scale Modelling of Capillary Pressure Hysteresis in Strongly Water-Wet Sandstones; Ph.D. Thesis, University of Wyoming: Laramie, WY, 2012. (23) Zhou, X.; Morrow, N. R.; Ma, S. Interrelationship of wettability, initial water saturation, aging time, and oil recovery by spontaneous imbibition and waterflooding. SPE J. 2000, 5 (June), 199−2007. (24) Brown, C. E.; Neustadter, E. L. The wettability of oil/water/ silica systems with reference to oil recovery. J. Can. Pet. Technol. 1980, 100−109. (25) Buckley, J. S.; Takamura, K.; Morrow, N. R. Influence of electrical surface charges on the wetting properties of crude oil. SPE Reservoir Eng. 1989, 4, 332−340. (26) Dubey, S. T.; Doe, P. H. Base number and wetting properties of crude oils. SPE Reservoir Eng. 1993, 195−199. (27) Langmuir, D. L. Aqueous Environmental Geochemistry; PrenticeHall: Upper Saddle River, NJ, 1996. (28) Lager, A.; Webb, K. J.; Black, C. J. J.; Singleton, M.; Sorbie, K. S. Low salinity oil recoveryAn experimental investigation, SCA200636. International Symposium of the Society of Core Analysts Trondheim, Norway, 12−16 Sept. 2006. (29) Brady, P. V.; Mariner, P. E.; Krumhansl, J. L. Surface complexation modeling for improved oil recovery. SPE Improved Oil Recovery Symposium, 14−18 April, Tulsa, Oklahoma, U.S.A.; SPE International: Tulsa, OK, 2012. (30) Dzombak, D. A.; Morel, F. M. M. Surface Complexation Modeling: Hydrous Ferric Oxide; John Wiley and Sons: New York, 1990; p 393. (31) Parkhurst, D. L.; Appelo, C. A. J. User’s Guide to Phreeqc (Version 2)A Computer Program for Speciation, Batch-Reaction, One-Dimensional Transport, and Inverse Geochemical Calculations, Water-Resources Investigations Report 99-4259; U.S. Geological Survey: Washington, DC, 1999. (32) Wieland, E.; Wanner, H.; Albinnson, Y.; Wersin, P.; Karnland, O. A Surface Chemical Model of the Bentonite−Water Interface and Its Implications for Modelling the near Field Chemistry in a Repository for Spent Fuel, SKB Technical Report 94-26; Svensk Kärnbränslehantering AB: Stockholm, 1994. (33) Wanner, H.; Wersin, P.; Sierro, P. Thermodynamic Modeling of Bentonite-Ground Water Interaction and Implications for near Field

ASSOCIATED CONTENT

S Supporting Information *

Total surface charge density of the three oils and kaolinite edges (Figure S1), separation corresponding to their maximum repulsion (Figure S2), cross plot of bond product sum and pressure at maximum repulsion (Figure S3), and pressure at 8 Å separation (Figure S4), all in the high and low salinity brines, plus a movie of oil displacement in a micromodel. 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]. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS Funding from the Sandia National Laboratories LDRD program is appreciated. A.N.U. thanks the member companies of the DigiCore Consortium and Wettability Satellite for funding. Support at UW was provided by Chevron, BP, and Statoil, the Wold Chair, and the University of Wyoming Enhanced Oil Recovery Institute. Sandia is a multiprogram laboratory operated by Sandia Corporation, a Lockheed Martin Company, for the United States Department of Energy’s National Nuclear Security Administration under contract DEAC04-94AL85000.

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L

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