Low Salinity Effect at Pore Scale - American Chemical Society

Apr 5, 2016 - 14, 633−662. (46) Verwey, E. J. W.; Overbeek, J. T. G. In Theory of the Stability of. Lyophobic Colloids; Elsevier Publishing Company...
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Low Salinity Effect at Pore Scale: Probing Wettability Changes in Middle East Limestone N. R. Pedersen,*,† T. Hassenkam,† M. Ceccato,† K. N. Dalby,† K. Mogensen,‡,§ and S. L. S. Stipp† †

Nano-Science Center, Department of Chemistry, University of Copenhagen, 2100 Copenhagen, Denmark Maersk Oil and Gas A/S, Esplanaden 50, 1098 Copenhagen, Denmark

‡

ABSTRACT: The effectiveness of low salinity flooding for enhanced oil recovery (EOR) in sandstone reservoirs has been demonstrated in core plug and field tests as well as at molecular scale, but in carbonate reservoirs the results are mixed. With atomic force microscopy (AFM) chemical force mapping (CFM), using a methyl (CH3) functionalized tip, we tracked the wettability of limestone pore surfaces (before and after solvent treatment) during exposure to high and low salinity solutions at a submicrometer scale. The correlation between adhesion and salinity was weak for both the treated and the fresh samples, but detailed analysis of the force maps demonstrated that on the fresh limestone there are areas that clearly respond to changes in salinity. Adhesion decreased when salinity decreased on some areas, and on others adhesion increased. To understand this behavior, we analyzed the surfaces with X-ray photoelectron spectroscopy (XPS) and energy dispersive X-ray spectroscopy (EDXS). The amount of organic material on the solvent treated samples was lower than on the fresh samples, but the amount and type of organic compounds were considerably different. These differences provide a likely explanation for the differences in the effectiveness of low salinity flooding that have been reported in the literature and lead us to conclude that for the samples analyzed in our study, the response in carbonate rocks is controlled by an intricate interplay between the composition of the tightly adsorbed organic material, the minerals on which it is adsorbed, and the functional groups present in the oil. Consequently, if the effectiveness of low salinity flooding in carbonate reservoirs is to be predicted, characterization of the organic compounds in the oil and on the pore surfaces is essential.

1. INTRODUCTION Water flooding, typically with seawater or formation water, has been used for many years to improve oil recovery. Chemical additives for enhanced oil recovery (EOR) are expensive so there is considerable interest in the potential of low salinity flooding, where the only requirement is to decrease the salinity of the injected water. Low salinity flooding is effective for oil recovery from sandstone in core plug and field tests1−4 and high resolution studies show that surface properties change in response to low salinity solutions,5−8 but for carbonate reservoirs studies suggest that low salinity flooding works for some samples9−11 but not for others.12−14 In theory, low salinity solutions are expected to increase the hydrophilic behavior of the mineral surfaces, resulting in oil release. Positive results in core plug tests on carbonate rocks have been achieved by injecting artificial seawater with ∼90% less NaCl than in seawater, but the concentrations of some naturally occurring ions, i.e. SO42−, Ca2+, and Mg2+, were kept at seawater levels.15−17 A limitation, however, was that effectiveness could only be demonstrated when temperature was >70 °C.15,18 In another study, a 4-fold molar concentration increase in SO42− and a 50-fold molar concentration reduction in NaCl optimized oil production from core plugs.19 In sandstone reservoirs, low salinity flooding is most effective where the salinity of the injected fluid is between 1,400 and 5,000 ppm8,20−25 and there is no evidence for temperature dependence. There is general agreement12 that divalent ions must be present in the formation water, polar components are required in the crude oil, and the presence of clay in the reservoir is essential.4,26,27 It has not yet been established if © XXXX American Chemical Society

these requirements also hold for carbonate rocks. Previous work has demonstrated the effectiveness of atomic force microscopy (AFM), in chemical force mapping (CFM) mode, for observing changes in surface wettability that result from changing the salinity of the solution in contact with mineral grains from sandstones.5,6,28,29 The experiments used AFM tips functionalized with molecules ending in methyl (−CH3) to make them hydrophobic or carboxyl (−COO(H)) to make them polar, either neutral or acidic, depending on the pH of the solution. A change toward slightly more water wet pore surfaces has been suggested as one of the main causes for the low salinity response.12 A methyl tip probes the wettability of a surface. The adhesion force therefore provides us with a link between the response to change in salinity that we observe with the methyl tip and the effect on wettability on our surfaces. Wettability differences can be effectively mapped at submicrometer resolution,28,30,31 which provides a detailed picture of the heterogeneity of natural samples, even at the pore scale. In this work, we used CFM to map changes in wettability on limestone samples. Previous research demonstrates that mineral surfaces in nature and in the laboratory are never pure and clean but rather, organic compounds adsorb on them and for the species that adsorb strongly, the surface properties are modified.5,28,32,33 Organic material is present on all mineral surfaces, i.e. on pure mineral samples in the laboratory, on pore surfaces Received: October 30, 2015 Revised: April 5, 2016

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chipped from the inside of the core plug, to minimize contamination from fingerprints and drilling fluid, and the fragments were glued to a microscope cover glass using a very thin strip of epoxy (Dana lim 334). Thus, we prepared 4 samples from the fresh piece of core and 5 from the treated piece of core. 2.3. Solutions. All solutions were made with ultrapure deionized water (Milli-Q, resistivity >18.2 MΩ·cm) and chemicals of reagent grade or better. The composition of all solutions is summarized in Table 1. The artificial seawater (ASW) salinity was 36,500 ppm total

from rocks that have never come into contact with oil or gas, and on the pore surfaces in an oil bearing formation. In a recent study, Matthiesen and colleagues (2014)5 demonstrated the role that adsorbed organic compounds play in the low salinity response in sandstone samples. Here we demonstrate the presence of organic compounds on Middle East limestone pore surfaces, we characterize the effect of this organic material on surface interaction in the pores, and we use the new information to explain why low salinity flooding causes increased oil recovery in some carbonate reservoirs but not in others.

Table 1. Composition of the Artificial High Salinity (HS) and Low Salinity (LS) Solutions

2. MATERIALS AND METHODS

pH 8.2−8.3

2.1. Chemical Force Mapping (CFM) with an Atomic Force Microscope (AFM). We used an MFP-3D AFM from Asylum Research, Santa Barbara, USA, to collect force maps with 50 × 50 data points (force curves) over an area of 5 × 5 μm2, as described elsewhere.28 The measurements were collected with Olympus biolever AFM probes, using the short cantilevers, which have a spring constant in the range of 20 to 30 pN/nm and a radius of curvature of ∼30 nm. The tips were UV/ozone treated (Bioforce Nanosciences: UV/Ozone Procleaner) for 20 min and then functionalized by exposure for at least 24 h to a solution of 3 to 5 mM hexadecanethiol (99%, Sigma-Aldrich) dissolved in 99.8% pure ethanol to produce the −CH3 tips. The cantilever was rinsed with pure ethanol just before use. Prior to every measurement, the deflection sensitivity of the cantilever was measured, and the spring constant was determined by a fit to the spectrum of the thermally induced oscillations.34 The dwell time was set to 0.1 s, the scan rate to 4 Hz, and the velocity to 6.38 μm/s. A force map takes about 17 min to capture. All the measurements were conducted in solutions at room temperature. An example of a force curve is shown in Figure 1. The tip approaches the surface (red curve)

Ca Mg K Na HCO3 SO4 Sr Cl

ASW [g/L] HS

ALSW [g/L] LS

MSW [g/L] HS

MLSW [g/L] LS

0.48 1.39 0.48 11 0.12

0.019 0.053 0.021 0.46 0.005

22

0.92

0.49 1.4 0.45 14 0.022 0.23 0.008 24

0.024 0.069 0.023 0.7 0.0011 0.012 0.0004 1.2

dissolved solids. This served as the high salinity (HS) solution. From it, we made an artificial low salinity solution (ALSW) by diluting ASW 25 times with ultrapure water, to 1,500 ppm. This is the low salinity (LS) solution. These two solutions (ASW and ALSW) have been described and used in previous studies.5,35 We also made artificial Middle East seawater (MSW, salinity 43,500 ppm), which was similar to ASW except for the presence of sulfate and strontium and slightly higher bicarbonate. The MSW is also HS. The artificial Middle East low salinity seawater (LSW, 2,150 ppm) was MSW diluted 20 times. Following equilibration of the solutions with air, droplets of 0.2 M NaOH were added to bring the pH to 8.2−8.3, which is the equilibrium state for aqueous solution equilibrated with calcite in a system open to atmospheric CO2. During the experiments, the salinity and composition of the solutions in the fluid cell were changed by sequentially extracting ∼70% of the liquid with a syringe and replacing it with the new solution, as described by Hilner and colleagues.8 The solution was not removed entirely at one time to avoid drying the sample and losing the imaging location. After 5 solution exchange cycles, we assumed the composition to have been changed. Solution replacement took ∼4 min. 2.4. X-ray Photoelectron Spectroscopy (XPS). The XPS analyses were made using a Kratos Axis UltraDLD instrument, operated with a monochromatic AlKα X-ray source (hν = 1,486.6 eV) at a power of 150 W. We used a rectangular spot size of 0.21 mm2. Analysis depth on calcite with these conditions is about 10 nm. Survey scans were acquired over the 0 to 1355 eV range, with pass energy of 160 eV and a step size of 0.5 eV. High resolution scans of the C 1s region (280−295 eV) were acquired with pass energy of 10 eV and a step size of 0.1 eV. The pressure in the analysis chamber was in the 10−9 Torr range. The generated XPS data were processed using the CasaXPS software. The spectra are shown with energy scale correction, obtained by assigning the carbonate C 1s peak energy to 290.1 eV.32 Surface concentration (atom %) was determined by fitting the core level spectra using Gaussian−Lorentzian curves after the background was removed with a Shirley fit; the values reported represent the average of at least two separate analyses. Element distribution (atom %) was determined from survey spectra. The values reported represent the average of at least two separate analyses. Uncertainty is shown in parentheses. Analyzer transmission correction was applied to the intensities, and the relative sensitivity factors (RSF) from the Kratos library were used for element quantification, as implemented in CasaXPS Version 2.3.13 (Neal Fairley, www.casaxps.com). The influence of the mean free path for the various energies was not considered. Overall uncertainty was 10 to 15%.

Figure 1. An example of a force curve. The tip approaches (red), feels the surface, and is deflected (positive force). Then the tip retracts (blue). If the surface feels sticky to the tip, it adheres, and a certain amount of force is required to pull it away (adhesion force, ∼1.2 nN in this case). The adhesion work required is the area under the curve, shown in green. and comes into contact. It deflects linearly with displacement in z until it reaches the trigger point (positive force). Hereafter, the cantilever retracts (blue curve). The tip remains in contact with the surface until the spring force of the cantilever is the same as the adhesion force and the tip snaps off. 2.2. Samples. Two samples from the same limestone core plug were used in this study: (i) an untreated sample, fresh from the core, which had been stored under dry conditions and (ii) a sample that had been solvent cleaned by repeated flushing with a mixture of solvents until the effluent liquid was clear in a Soxhlet apparatus, with a mixture of 7% methanol and 93% dichloromethane. The AFM samples were prepared by the method described by Hassenkam and colleagues.35 Briefly, millimeter size pieces were B

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Energy & Fuels 2.5. Scanning Electron Microscopy (SEM) with Energy Dispersive X-ray Spectroscopy (EDXS). A FEI Quanta 3D FEG SEM was used to image the samples, with a voltage contrast detector (vCD), an accelerating voltage of 10 kV, and a beam current of 8 nA. An Oxford X-Max EDXS spectrometer was used to determine the composition of the samples. We analyzed the samples without conductive coating to preserve the delicate features. Instead, the system was run in low vacuum mode with water vapor at 0.6 mbar to minimize charging.

3A and B. These two series are typical of the many experiments performed. For the fresh sample, average adhesion varied between 4,900 and 5,600 pN, and for the treated sample, adhesion varied from 210 to 390 pN. The average adhesion was not correlated with salinity, i.e. the adhesion averaged over the entire analyzed surface, so there was no evidence for an overall low salinity effect. This is clearer in Figures 3C and D, where data are plotted for a number of samples, from longer series where salinity was toggled from high to low through many cycles. Although we cannot extrapolate data from 2 samples (a fresh and a treated sample) over an entire oil field, the repeatability of the experiments indicates that these differences provide a meaningful average. The initial adhesion for the fresh samples varied from about 600 to 8,000 pN, whereas for the treated samples, adhesion ranged from 70 to 3,500 pN. The difference in the overall adhesion on the treated sample, compared to the fresh sample, is explained by a decrease in organic material after the solvent treatment. The range in average adhesion for the various untreated samples, and for the treated samples, is a reflection of the heterogeneity of the pore surfaces. The heterogeneity of wetting properties, even over the scale of tens of nanometers, is quite remarkable. It means that some sites on grain surfaces would respond strongly to a change in pore fluid composition while others might not. Therefore, one hypothesis for the lack of an observable low salinity effect in limestones is that the very localized variations in adhesion average out, obscuring any trends. We tested this possibility on a number of our adhesion map series (Figure 4). On the fresh sample (Figure 4A), we identified locations where adhesion during exposure to HS solution was high (orange rhombs) and low (green rectangles). When we changed solution salinity, adhesion decreased where initial adhesion had been high, indicating a low salinity response, i.e. more hydrophilic. However, we also observed that some areas, where adhesion was initially low in contact with the high salinity solution, showed a reverse response, becoming more hydrophobic in low salinity solution, i.e. higher adhesion (Figure 4A and Table 2). We followed the same procedure for the treated sample (Figure 4B), focusing on areas that, during exposure to high salinity solutions, had high (yellow triangle), low (green rectangle), and medium (pink triangle) adhesion. Again, the difference in adhesion reflects a difference in surface properties, but during exposure to low salinity solutions wettability did not change. This means that whatever is on the surface that provides the low salinity effect (or the reverse effect) is removed by the solvent treatment. Our hypothesis is that the organic material, that was removed by the solvent treatment, is responsible for the wettability changes observed on the fresh sample. We return to this point later. Each pixel in the force maps is an independent measurement. Natural surfaces, such as reservoir pore surfaces, are very heterogeneous. On the force maps, the variation from one pixel to the next is not a result of error or uncertainty, it is a result of different adhesions at each point. We divided the maps into regions according to trends in the response. This does not mean that the response inside each region is expected to all be the same. There is variability inside each box, but the measurements inside one box are more similar to each other than those in another box. An estimate for standard error for the maps of Figure 4A is so low (0.97 to 2.1 pN for the area framed in orange and 15 to 20 pN for the area framed in green) that error bars are not visible in the plot. There is no clear

3. RESULTS AND DISCUSSION Figure 2 shows representative SEM images of the fresh and the solvent treated limestone samples. They show the topography

Figure 2. Typical scanning electron microscopy (SEM) images of a) a fresh and b) a solvent treated sample. A patch of crude oil is indicated by the red arrow. The red and black box, in the lower left corners, illustrates the size of the area that we examined with force mapping.

of the surfaces created by breaking the sample, which exposes grain boundaries and pores within the rock. Grain size is heterogeneous, ranging from a few hundred nanometers to several micrometers. The appearance of the two samples is very similar, as expected, because they were part of the same geological layer. In the solvent treated sample (Figure 2B) there is very little evidence of crude oil, such as we see in the fresh sample (red arrow, Figure 2A). EDXS data are consistent with higher C on the fresh sample. The AFM force maps were made on sample surfaces similar to the ones shown. The small box in the lower left corner shows the size of the area represented by the force maps. 3.1. Adhesion Force Mapping. Figure 3 shows the adhesion force measured from a typical area on the fresh and treated samples. Response to the hydrophobic tip shows that adhesion, i.e. wettability, varies over the surface on both samples, over a range of three and a half orders of magnitude, from 2 pN to 8.3 nN. Inhomogeneous wettability means that some areas on the pore surfaces would act as anchors, attracting and retaining oil, whereas other areas are more prone to oil release. Overall, considering the average adhesion for the whole surfaces scanned, there are no consistent correlations with salinity. In some areas, such as the edges of topographic features, adhesion correlates with surface structure, which is expected because there is more surface at a step edge or in a cavity for reaction with the tip28 and with the organic molecules. In general, adhesion differences result from a variation in footprint, i.e. the area of interaction between the tip and the sample changes because of topography or difference in the properties of the surface, such as true differences in adhesion force, indicating differences in wettability. The average adhesion for each map was determined from areas that we could be sure were precisely the same throughout the whole sequence; such areas are framed in green on Figures C

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Figure 3. Typical height and adhesion force maps for A) fresh and B) treated samples in a solution alternating in salinity from high (HS), to low (LS), to HS, to LS, in this case using ASW. The first image in each sequence shows topography, where white represents higher features, and the following four images are adhesion maps, where blue represents low adhesion and black to pink represents increasing adhesion. The adhesion force scale bars (right side) are not the same for the two series, but the units are the same, i.e. [10−9 N] or [nN]. It takes ∼17 min to collect the data for each map and each map in the series was separated by ∼4 min, when the solution was changed. An unavoidable artifact in AFM imaging is drift. Therefore, to be sure we compare the same area for each map in a series, we use data only from areas that we can recognize by the pattern of specific features. The green boxes show the areas analyzed, and the average adhesion is noted at the top of each image. (C and D) average adhesion data from longer sequences, using ASW and MSW for 4 fresh (C) and 5 treated (D) samples.

Figure 4. Height images and adhesion maps for the a) fresh sample and b) treated sample, during initial exposure to the high salinity solution (MSW). Regions with high and low adhesion are marked in a) by orange and green frames. Adhesion does not generally correspond with topography. When salinity is changed, initial high adhesion decreases (plus signs, orange line), but adhesion in the areas where it was initially low increases (crosses, green lines). This results in no change to the average for the whole map (open dots, black line). b) On the image from the treated sample during exposure to high salinity, we have framed areas where adhesion is high (yellow), medium (pink), and low (green). The units of the adhesion scale bar is Newtons (N).

D

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termination of the pure, clean bulk calcite mineral structure and the −CH3 tip but rather between the methyl tip and adsorbed water. To characterize the composition of our samples, we analyzed them with energy dispersive X-ray spectroscopy coupled with scanning electron microscopy (SEM-EDXS), which provides information about the near surface, ∼1 μm deep. These samples had not been in the AFM. On the treated sample, we collected 4 element maps and 19 EDXS spectra from specific sites. We found primarily C, Ca, and O but also traces of Fe, S, and Al. On the fresh sample, 4 element maps and 21 EDXS spectra showed C, Ca, and O and minor amounts of Na, Ni, Cr, and Fe, along with trace amounts of Al, Si, S, Cl, Mn, and Mg. We assume the Ca, C, and O come from calcite (CaCO3), with some C coming from oil in the fresh sample. The Al and Si could be associated with nanoclays, which have been shown to exist on chalk surfaces.31 The Fe and S are likely from pyrite (FeS2) a common accessory mineral in limestone, although, along with Na, Cl, and Mg, they could be remnants formed from the evaporation of the formation water during sample storage. Mg is known to substitute for Ca in the calcite lattice, so in addition to coming from formation water, it could also be in the mineral. The Ni and Cr are unusual in limestone and could come from oil or contamination from the tools used to extract the samples. Although EDXS gives us an overview of the bulk chemistry of the samples, to further characterize the organic material, we analyzed the samples using X-ray photoelectron spectroscopy (XPS), which provides information about surface composition to a maximum depth of ∼10 nm (Table 3). Despite the fact that the EDXS and XPS signals are derived from different areas in the crystal (bulk vs surface), there is an agreement in the elements detected. However, the sensitivity of the XPS allows more than just an examination of the overall surface composition; high resolution peaks in XPS spectra reveal specific chemical information. For example, in Figure 5, the C 1s spectra indicate C that is bonded to O in carbonate from calcite (at 290.1 eV) as a separate species from C−C and C−H bonds from hydrocarbons (∼285 eV). The high resolution C 1s spectra can be fitted with peaks representing specific organic carbon species, differentiated by their binding energies, i.e. C− C/C−H/CC at 285.0 eV, C−O/C−N at 286.1 eV, CO at 287.6 eV, and O−CO at 289.1 eV.32 From fitting the peaks, the relative proportion of organic carbon in the top few nanometers for both samples can be determined (Table 3). On the untreated sample, we could identify the carbon compounds chiefly as hydrocarbons (C−H, C−C, and CC). Spectra from the sample that had been treated with solvents to remove as much of the hydrocarbons as possible contained more carboxylate (O−CO), carbonyl CO, and C−O or

Table 2. Relative Change in Adhesion for the Regions Marked on the Map of Figure 4A, Comparing Response in High and Low Salinity Solutionsa

a

%

HS to LS

LS to HS

HS to LS

LS to HS

orange green

20 [−280] −9 [30]

−16 [180] 15 [−50]

12 [−160] −64 [190]

−7 [80] 29 [−140]

The absolute change in adhesion is shown in brackets.

correlation between surface features and adhesion or, more importantly, between overall average adhesion and salinity. Wettability is often described in terms of contact angle. It is not possible to measure a contact angle from the surface of a particle that is smaller than the smallest droplet one can make so we cannot measure a true contact angle on these submicrometer scale features. However, the contact angle can be estimated by transforming the adhesion work (Figure 1, green area), that is experienced by the AFM tip, into a value that corresponds to a contact angle. One can derive adhesion work, W, from integrating the area under the retraction force curve over the region spanning from tip−surface contact, i.e. zero separation, to snap off, the distance at which the tip springs free of the surface. From the adhesion work and the Young-Dupré equation γoil − water(1 − cos θ ) = W

(1)

we can determine the contact angle, θ. γoil−water represents the oil−water interfacial tension. This is assumed to be mN ∼50 m .36−38 From the AFM data, adhesion work was normalized to the surface area where the tip is in contact with the surface, i.e. ∼365 nm2.28 For one of the solvent treated samples, the calculated contact angle is ∼15°, indicating a hydrophilic surface, and for another, not more than 90°, an indication of mixed wet. For the fresh samples, the contact angles are high, 180°, hydrophobic, as expected for surfaces where oil is visibly present. This result implies that sample handling and storage are important factors in core testing. 3.2. Surface Composition. The heterogeneity of adhesion force implies differences in surface composition. For both types of samples, it is very unlikely that we were probing pure calcite surfaces. When we cleave pure, clean, Iceland spar calcite, the surface is completely water wet. A water droplet spreads across the entire surface immediately. AFM measurements conducted by our group28 on freshly cleaved calcite showed no adhesion, i.e. 0 adhesion force, a completely water wet surface. This is probably because our methyl tip is not able to displace the water that structures itself on calcite to delocalize dangling charge.32,39 Thus, the real interaction is not between the

Table 3. Element Distribution (Atom %) in the Top 10 nm of the Limestone Fragments, Derived from X-ray Photoelectron Spectroscopy (XPS)a

a

sample

O 1s

fresh treated

3.8 (0.2) 30.2 (0.5)

C 1s

Cl 2p

Ca 2p

Na 1s

S 2p

N 1s

Si 2p

Mg 2s

92.2 (0.1) 0.10 (0.01) 1.0 (0.1) 0.0 1.6 (0.1) 0.1 (0.1) 1.2 (0.2) 0.0 54.6 (0.7) 0.0 11.9 (0.1) 0.0 2.7 (0.1) 0.6 (0.1) 0.0 0.0 Species of Organic Carbon, i.e. % of Total Carbon Determined from High Resolution C 1s Spectra

Al 2s

organic C

0.0 0.0

98.6 (0.3) 78.1 (0.3)

sample

C−C/C−H/CC

C−O/C−N

CO

O−CO

CO32−

fresh treated

94.5 (1.0) 65.7 (1.9)

4.2 (1.0) 8.9 (0.2)

0.0 3.5 (0.9)

0.0 1.9 (1.0)

1.3 (0.1) 20.0 (1.1)

Uncertainty is shown in parentheses. E

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desorbed from the surface. The reversible response we do observe in the orange frame in Figure 4A suggests that the process behind the low salinity response in this region is the same as for sandstone. Part of the low salinity effect in sandstone has been explained by DLVO theory,45,46 where the electric double layer expands as ionic strength decreases, causing a decrease in adhesion. Surface charge is a main parameter in DLVO theory so a different surface charge for limestone than for sandstone could partly explain why carbonate rocks do not show a consistent low salinity response. The surface charge of calcite is not welldefined, because the potential determining ions are not OH− and H+, as with oxide minerals, but rather Ca2+ and HCO3−.47 Thus, pH at the point of zero charge (pHpzc) for limestone depends completely on the composition of the solution, explaining the wide range in values reported in the literature,48−55 but in any case, it is certainly above 7, in contrast with ∼3 for quartz and the silicates,56,57 which dominate sandstones. The surface charge would determine which functional groups would preferentially adsorb, and this would then affect the surface charge of the organic compounds that the pore fluids would encounter. If the organic compounds in contact with pore fluids in carbonate rocks create a surface that has little or no charge when in contact with our solutions, then according to DLVO theory, repulsion from the electric double layer is expected to be very low. This fits well with what we observe. However, if the interaction is controlled by DLVO forces, the electrical double layer would expand with increasing temperature, and the effect of low salinity would be amplified. The experiments were conducted at room temperature and pressure, thus not under reservoir conditions. However, AFM experiments on other samples in the temperature range of reservoirs suggest that adhesion change increases, typically by 10 or 20% for experiments at 75 or 80 °C. The effect that we observe at room temperature would be amplified under reservoir conditions so the results give a first indication that this method can be used to investigate subtle variations in wettability. The absolute wettability we measure is certainly not what it would be in the reservoir, but the change in wettability is representative and useful for determining how the low salinity response could be improved. Data from the adhesion force measurements can be used to screen for the most optimum conditions for core plug experiments, and when adhesion force data are combined with results from traditional core plug tests performed at reservoir conditions, they can help to constrain a low salinity response prediction with greater accuracy. We can expect the composition of the organic material to vary locally, generating local differences in surface charge, thus local differences in response to changed solution salinity. The type of organic matter that is adsorbed by a mineral surface and the charge of the surface that it generates depend on three factors: the composition of the pore fluid (oil, water, and gas), the composition of the organic compounds that were already associated with the pore surfaces, and the composition of the underlying mineral. Thus, the history of the pore surfaces and fluid plays an important role. With this in mind, we can explain the differences in published results for sandstone and carbonate reservoirs. Organic molecules that are tightly bonded to mineral surfaces serve as anchors for oil, controlling the low salinity response. The type and amount of adsorbed organic material, thus surface charge, would vary. We see this reflected in the literature for reports on low salinity studies in both sandstone

Figure 5. High resolution XPS spectrum of the C 1s region from a treated and a fresh limestone sample. Information depth is ∼10 nm. On the fresh sample, the hydrocarbon layer is so thick that nearly no photoelectrons from the underlying calcite can escape to generate a peak in the carbonate region (290.1 eV).

C−N. These results demonstrate that polar compounds remain adsorbed on the calcite surface during solvent treatment. This is consistent with the more hydrophilic behavior observed in the force maps of the treated samples (Figure 3B) and with previously published results,40−43 where ethanol (C−OH) and carboxyl (O−COH) were demonstrated to bind very strongly to calcite. 3.3. The Effect of Surface Composition on the Low Salinity Response. On experiments in sandstone, the low salinity response can clearly be observed using CFM on treated and fresh samples.5−8 Hassenkam and colleagues44 and Matthiesen and colleagues5 demonstrated that overall adhesion and the low salinity response are strongly influenced by the organic materials that are naturally present on all mineral surfaces, even when they have never been in contact with oil or gas. In several experiments with the same conditions as presented in this study, the average adhesion on grains from sandstone that had been solvent treated was ∼110 pN,5 which is comparable to the average adhesion obtained in our study on the treated sample, i.e. 150 pN. There are millions of different types of organic molecules in seawater, where the sediments formed, and in petroleum, which migrated into the reservoir later. Each has its own composition, structure, and binding affinity for calcite and for other organic molecules, which makes the similarity of these numbers quite remarkable. The average adhesion on the grains from fresh sandstone from an oil reservoir was ∼260 pN,5 whereas that of our untreated samples was ∼2,600 pN. This difference is easily explained by the difference in the type and amount of organic compounds present on the surfaces. The fresh sandstone samples had been stored in kerosene, whereas the limestone sample had been stored dry and retained more of the original oil. The evidence from sandstone presented previously5 and the results of this work demonstrate that the organic carbon compounds, which are naturally associated with mineral surfaces, play a role in the low salinity response and that this response is controlled by the type of functional groups in the adsorbed material. The low salinity response does not depend directly on the mineral surface but rather the properties of the mineral surface control which organic species adhere most strongly. Thus, the underlying mineral composition is an important factor. We have not, in any of our experiments, observed a significant irreversible drop in the overall adhesion with low salinity flooding, as one would expect if polar material F

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ACKNOWLEDGMENTS We thank the members of the NanoGeoScience Research Section for lively and helpful discussions, Nico Bovet for guidance with the manuscript, and Maria Bruun Bjørn for general help in the laboratory.

and carbonate rocks. Some show a response and some do not. Our submicrometer scale observations from the Middle East limestone cores show no salinity response for some areas, a positive response for others, and a reverse response for others, controlled by local differences in wettability. Depending on the proportion of species that form these areas, the overall response to low salinity flooding could be positive or negative or neutral.

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REFERENCES

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4. SUMMARY We used chemical force mapping (CFM) to generate adhesion maps with submicrometer resolution on Middle East limestone samples from an oil reservoir. The mapping demonstrated very local differences in wettability, thus contact angle. We could observe no low salinity response on either fresh samples or those that had been treated with solvents to remove the hydrocarbons, when we considered the average wetting behavior over the entire map, but we could see a clear response on local areas. Adhesion was generally an order of magnitude higher on the untreated sample where organic compounds had not been removed by solvent treatment. X-ray photoelectron spectroscopy (XPS) showed much more organic material, chiefly hydrocarbons, on the fresh sample, but the solvent treated sample retained considerable organic material (78%) with a higher proportion of carboxylate, carbonyl, and hydroxyl functional groups. Their polar nature is consistent with the lower adhesion, i.e. more hydrophilic, and is also consistent with the more strongly bonded, polar material remaining on the calcite surfaces. On both the solvent treated and the fresh samples, we observed sites where initial adhesion was high, medium, and low. On the treated samples, the adhesion properties did not change with change of salinity, but on the fresh sample, the high adhesion patches became less adhesive, i.e. more water wet, when salinity decreased and the low adhesion patches became more adhesive, thus a reverse effect. The heterogeneous behavior resulted in average overall wettability that did not change in response to changes in salinity. The presence of organic material and its contribution to the low salinity effect, and the variability that local differences can have, helps us explain the difference in behavior reported for low salinity studies on carbonate rocks in the literature. Low salinity response in sandstones and carbonate rocks probably all depends on the type and quantity of tightly adsorbed organic compounds, but the difference in surface charge of calcite compared with the silicates typical of sandstones would certainly influence the type of organic compounds that adsorb and thus make a much narrower window for a low salinity response in limestones. Consequently, if the effectiveness of low salinity flooding in carbonate reservoirs is to be predicted, characterization of the organic compounds in the oil and on the pore surfaces is essential.

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University of Copenhagen.

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The authors declare no competing financial interest. G

DOI: 10.1021/acs.energyfuels.5b02562 Energy Fuels XXXX, XXX, XXX−XXX

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DOI: 10.1021/acs.energyfuels.5b02562 Energy Fuels XXXX, XXX, XXX−XXX