Article pubs.acs.org/EF
Spin−Spin Relaxation Time Investigation of Oil/Brine/Sand Systems. Kinetics, Effects of Salinity, and Implications for Wettability and Bitumen Recovery Valeska Gonzalez, Marc Jones, and Spencer E. Taylor* Centre for Petroleum and Surface Chemistry, Department of Chemistry, University of Surrey, Guildford, Surrey GU2 7XH, U.K. S Supporting Information *
ABSTRACT: Improving the efficiency of secondary and tertiary oil recovery is one of the major challenges of the crude oil industry. Arguably the most significant advance made in recent years has been the realization of the importance of water chemistry during oil recovery. This has led to the concept of low-salinity waterflooding for conventional oil reservoirs, for which reducing the total salinity of the injection water has been found to improve oil recovery rates. Although the precise mechanisms responsible for the improvements are not completely understood, it is acknowledged that specific interactions in the crude oil/ brine/rock (COBR) systems will modify wettability and interfacial energy. The present paper extends investigations of COBR interactions to higher viscosity oils and considers implications for heavy oil recovery. We have used NMR relaxation time measurements to study interactions in oil/brine/sand (OBS) systems containing either natural bitumen or a polybutene hydrocarbon (Glissopal). Exposing the oil-coated sands to water or aqueous group 1 and group 2 metal chloride solutions enabled the T2 relaxation time spectrum to be determined as a function of time. The observed decreases in the geometric mean T2 values with time obey first-order kinetics; for bitumen-coated sands, the rate constants are consistent with diffusion of water through the bitumen. Opto-digital microscopy verified the formation of ∼1−3 μm diameter water droplets in the initially dry bitumen coating, suggesting that water nucleation and growth also occur. This was not observed for the Glissopal-coated sand samples. No evidence was found for displacement of either viscous oil from the sand grains, although optical microscopy did reveal rearrangement of the bitumen coating, which possibly exposes fresh sand surfaces to the aqueous phase. This behavior is consistent with the finding that the original T2 parameters determined for fresh sand are not fully restored simply by contacting the bitumen-sand surface to water or aqueous salt solutions under the ambient experimental conditions. Glissopal-coated sands exhibited smaller time-dependent T2 changes compared with bitumen-coated sands. While not displacing viscous oils from the sand surface under the experimental conditions used, it is conjectured that water ingress into the surface oil layer could weaken oil/sand interactions which by analogy with recent studies on conventional oil recovery could provide an additional heavy oil recovery mechanism under more dynamic or higher temperature conditions.
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rate of conventional oil.1 The early work showed as much as ∼10% increase in recovery upon reducing the overall salinity, as well as identifying specific cation effects (monovalent vs multivalent) on wettability.2 Subsequently, other mechanisms underpinning low-salinity technology have also been suggested, and ongoing research is being directed at a better understanding of processes occurring in the reservoir3 as low-salinity waterflooding begins to be implemented for full-scale field use, e.g., BP’s Clair Ridge development.4 Many subsequent investigations have considered the nature of interfacial interactions occurring when low-concentration salt solutions are injected into crude oil/brine/rock (COBR) systems. Although these studies have not yet produced a definitive explanation for low-salinity recovery, they have yielded valuable insight into interactions occurring at interfaces within these complex systems which often result in modifications to wettability and interfacial tension.5−10 However, the complexity in COBR systems is also highlighted by the apparently contradictory effects of salt concentration on
INTRODUCTION Despite the development and introduction of alternative energy technologies, the demand for oil and gas is likely to continue for many years to come in order to satisfy increasing requirements for energy and petroleum-derived products. This situation has encouraged the exploitation of unconventional crude oil resources and interest in the development or improvement of technologies that lead to improved oil production once primary oil recovery is no longer economic. Secondary oil recovery technologies are based on the injection of pressurized water or gas to drive additional crude oil to the producer wells, and tertiary (enhanced) oil recovery approaches are then applied to recover oil that is trapped in inaccessible pores or is too viscous to be extracted by conventional methods. Improving oil production rates in safe and innovative ways during secondary and tertiary oil recovery continues to be one of the main challenges faced by the oil industry. One significant advance made in recent years, which has partly motivated the present work, is that reservoir water chemistry, and in particular the ionic composition, has a significant effect on oil recovery. An important demonstration was the work of Tang and Morrow in which reducing the total salinity of injection water led to improvements in the recovery © XXXX American Chemical Society
Received: October 7, 2015 Revised: December 18, 2015
A
DOI: 10.1021/acs.energyfuels.5b02352 Energy Fuels XXXX, XXX, XXX−XXX
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Energy & Fuels crude oil/saline water interfacial tension,6−11 suggesting the additional importance of reservoir mineralogy and crude oil and brine composition.5 In all types of crude oil reservoir, wettability has a significant influence on oil recovery, and understanding this property is important for identifying and selecting feasible recovery strategies or predicting production rates.2,4,5,12 Such factors are crucial for the development and efficient exploitation of oilfields,13,14 and it is now reasonably well established that the ionic composition of aqueous phases within conventional oil reservoirs influences recovery, whether through modifying wettability or as a result of other mechanisms. In contrast to the above-mentioned studies, however, in the present paper we consider the effects of salinity and aqueous phase composition in oil/brine/sand (OBS) systems containing highly viscous oil phases, using NMR relaxation time measurements to determine aqueous phase distributions relating to wettability. We focus on the use of the NMR transverse relaxation time (T2) as a sensitive measure of the local environment of protons in associated liquids, particularly water.15,16 This approach probes the wettability of surfaces because the spin relaxation of bulk liquids generally occurs more slowly than the relaxation of liquid in contact with solid surfaces, such as pore walls, and the latter surface relaxation process is the predominant mechanism in water-wet rocks. This is exemplified in the work of AlMahrooqi et al., in which Amott and USBM wettability determinations of sandstone core plugs were compared with NMR T2 measurements.15 In the present study we are further interested in using temporal changes in NMR water proton T2 relaxation times to determine kinetic effects occurring in OBS systems for different aqueous phase compositions.
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18.2 MΩ·cm) was from a Millipore Direct-Q water purification system. An estimate of the sand surface area was made by assuming spherical grains with an equivalent mean diameter equivalent to 250 μm, corresponding to 60#. If the bulk density of the quartz sand is taken as 2250 kg/m3, then the specific surface area is ∼0.01 m2/g excluding micro- and mesopores, and is therefore smaller than the value determined by Alipour Tabrizy et al. of 0.65 m2/g from BET analysis for this sand size fraction.17 Methods. The NMR experiments involved placing either coated or uncoated sand samples in contact with deionized water or aqueous salt solutions. Most of the experiments involved using sand coated with the JACOS natural bitumen, but for comparison with a cleaner hydrocarbon, samples of sand coated with two viscous Glissopal polybutenes have also been included. Preparation of Coated Sands. Three sets of sand samples were prepared containing 10 or 20 mg/g of (a) JACOS bitumen (designated A and B, respectively), (b) Glissopal 1000 (designated C and D, respectively), and (c) Glissopal 2300 (designated E and F, respectively). The coated sands were prepared by dissolving an appropriate mass of the respective oil in toluene and adding the required amounts of sand, mixing well, and allowing the toluene to evaporate. The samples were typically used within 1 day of preparation to avoid any long-term effects which might be attributed to “aging”. However, although we did not make specific determinations as a function of time since preparation, some measurements were repeated after the samples had been standing for 1−2 months, with no significant differences being apparent. Based on the estimated sand specific surface area of ∼0.01 m2/g average thicknesses of the coatings for the 10 and 20 mg/g sand samples correspond to ∼0.9 and ∼1.8 μm, respectively. Compared with the original sand, the coated sand samples were shown to be hydrophobic from their ability to float on a pure water surface, indicating a relatively high effective contact angle on water.18 NMR Measurements. For each experiment, an aliquot (∼1 g) of the particular sand was placed in an 8 mm NMR tube, and aqueous phase (0.1 mL) was added by syringe. Note that the pore volume in each sample is ∼0.25 mL such that the sand is deliberately under-saturated with respect to the added water in order to improve the relative response to surface water with respect to bulk water. The salts used in this study included KCl, LiCl, NaCl, CaCl2·2H2O, and MgCl2·6H2O, each being tested at low (950 ppm) and high (100 000 ppm) salt concentrations. Ultrapure deionized water was used in making the aqueous solutions and for comparative tests. The experiments presented in this work were carried out at ambient temperature using a 20 MHz Maran benchtop instrument (Oxford Instruments, Abingdon, Oxfordshire, UK) controlled by a Kea-2 spectrometer (Magritek, New Zealand). A CPMG pulse sequence19,20 was used to measure the T2 relaxation time measured at regular intervals. The parameters used in the experiments are given in Table 2. The optimal settings of echo time and number of echoes were determined with reference to the work of Ronczka and Müller-Petke.21 Echo time and the number of echoes were each varied to minimize the energy input to the sample without compromising the ability to obtain the complete spectrum of relaxation times. The acquired data sets were then inverted by software running the algorithm developed else-
EXPERIMENTAL SECTION
Materials. The bitumen sample used in this study originated from the JACOS (Japan Canada Oil Sands Ltd.) Hangingstone demonstration project, and was used as received. The bitumen was produced using steam-assisted gravity drainage (SAGD), and Table 1 lists some
Table 1. Some Properties of the JACOS Bitumen Determined in This Study
a
property
value
apparatus/method
density (20 °C), g/mL viscosity (21 °C), Pa·s
1.017 342
pentane-insoluble asphaltenes, %w/w water content, ppm salt content, g/m3
16.3 55 79
total acid number, mg KOH/g
2.96a
pycnometer/gravimetry Brookfield RS-CPS+ rheometer/rotational viscometry ASTM D6560 Karl−Fischer titration ASTM D3230 (electrometric method) ASTM D664
Supplier’s data.
Table 2. Acquisition Parameters Used for the CPMG Pulse Sequence
relevant properties of this oil. Glissopal 1000 and 2300 are viscous polybutenes and were generous gifts from BASF (Ludwigshafen, Germany). The indicated grades refer to their molar masses; their respective viscosities at 25 °C are 12 and 107 Pa·s, as determined using rotational viscometry (CarriMed CSL rheometer), the latter value being extrapolated from higher temperature measurements, and their specific gravities were 0.90 ± 0.1 (manufacturer’s data at 25 °C). Laboratory Reagent grade toluene was from Fisher Scientific. The chloride salts and sand (50−70#) were purchased from Sigma-Aldrich UK and used as received. Deionized (ultrapure) water (resistivity = B
parameter
value
no. of echoes 2τ, ms no. of scans P90, μs P180, μs dwell time, μs no. of echo points
256 20 64 6 (at −6.6 dB) 6 (at −3.3 dB) 1 16 DOI: 10.1021/acs.energyfuels.5b02352 Energy Fuels XXXX, XXX, XXX−XXX
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Energy & Fuels where22 which generates an “inverse Laplace transform” (ILT) based on Matlab code provided by Victoria University (Wellington, New Zealand). Using the ILT enabled the T2 distributions to be calculated, allowing fluid−solid interactions to be monitored and corresponding wettability or wettability changes to be inferred. From the T2 distributions, geometric mean T2 values, i.e., T2gm, are calculated according to eq 1, in which Ai represents the amplitude of
⎛ ∑n Ai ln T2i ⎞ ⎟⎟ T2gm = exp⎜⎜ 1 n ⎝ ∑1 Ai ⎠
(1)
each T2 value. T2gm values therefore provide a convenient weighted average measure of water proton environments based on surface and bulk water protons, reflecting the affinity of water for the surface, and can be used, for example, to monitor changes in wettability,16,23−26 as previously demonstrated by Hum and Kantzas.27 Digital Optical Microscopy. The condition of the oil/sand samples in the presence and absence of water was assessed using an Olympus DSX500 opto-digital microscope. Polarized light microscopy was found to be the best method to highlight bitumen and water domains on the sand grains.
Figure 1. T2 relaxation spectra for deionized water in contact with bitumen-coated sand B for different (indicated) times. For comparison, the black line is the initial spectrum for deionized water in contact with fresh (uncoated) sand.
times,36 although the low oil concentrations in these systems represent very minor contributions and would not significantly interfere with interfacial water relaxations. Increasing the contact time with water (also found with saline solutions, see Supporting Information) produces a general shift in both main peaks toward lower relaxation times as a result of increasing interactions of the water protons with the sand surface. The spectra also show a growth in amplitude of the shortest relaxation time peak at the expense of the longer bulk relaxation (compare initial and 5-day spectra in Figure 1). On the other hand, deionized water in contact with clean sand, also shown in Figure 1 (which produces an essentially time-invariant spectrum), shows a principal contribution from the surface relaxation component at 0.1 s with a smaller bulk water peak at ∼1.2 s. An intermediate relaxation component at ∼0.4−0.5 s is also a characteristic of spectra for clean sand, although we found that the latter two peaks are not always as well resolved, appearing, for example, similar to the 5day spectrum for the coated sand in Figure 1. Initial contact with the bitumen-coated sand is seen in Figure 1 to produce a fast relaxation peak of ∼0.2 s, compared with ∼0.1 s for clean sand. This relaxation peak decreases to the value found for clean sand at longer contact times (between 5 and 17 h in Figure 1), indicating that direct contact between water and the sand surface is restricted in the initial stages. In addition, the amplitude of the ∼0.1 s peak for coated sand at longer contact times (up to 5 days) is significantly lower than for clean sand, indicating incomplete interaction between water and the sand surface. The corresponding kinetic plots of the geometric mean T2gm values extracted from each T2 distribution spectrum obtained at different deionized water contact times for clean sand and sand B are shown in Figure 2. Initially, the mixture has a high T2gm, consistent with a higher relative contribution from interactions involving bulk water. T2gm then decreases with time in a firstorder kinetic process until a steady plateau value is attained after ∼7−8 h. Rate constants for the change in T2gm with time are determined from exponential fits to the data according to eq 3, in which T2gm(0) and T2gm(∞) are the respective initial and equilibrium T2gm values, and k is the first-order rate constant for the intervening change.
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RESULTS AND DISCUSSION Bitumen-Coated Sand + Water. As explained by Korringa et al.,28 surfaces affect NMR relaxation times through the surface-to-volume ratio (S/V) and surface relaxivity (ρ), the latter being strongly affected by the presence of paramagnetic surface species.29,30 The surface area is a key factor in porous media, while the relaxivity is sensitive to interactions between fluid molecules and paramagnetic surface species.31 From T1 measurements on sand and silica, Bryar et al. found that the surface relaxivity increased linearly with the surface concentration of paramagnetic ions (Fe3+ in their case).32 Since bulk and surface fluid relaxation T2 values are related according to eq 2, in which D is the diffusion coefficient of the fluid molecules, γ Dγ 2G2TE 2 1 1 S = + ρ2 + T2 T2,bulk V 12
(2)
is the gyromagnetic ratio of the proton nucleus, G is the gradient strength, and TE is the echo spacing, increases in surface paramagnetic (or free radical) species leading to an increase in surface relaxivity will produce a decrease in the surface T2.32 Bryar and Knight33 considered the G term in eq 2 to be approximately zero, enabling calculation of the surface relaxivity from the respective surface and bulk relaxation times. For our system, bitumen coatings are likely to contain additional paramagnetic impurities which could enhance relaxation phenomena,33 e.g., vanadyl porphyrins and aromatic radicals associated with the asphaltene fraction.34 However, although overall concentrations of these species within the surface coating will be low, they could be higher at the sand surface as a result of adsorption,35 since diluted bitumen was used in preparing the sand samples. Figure 1 contains typical T2 relaxation spectra for bitumencoated sand contacted with deionized water, which show the distribution of water protons between different environments. These spectra generally comprise a short relaxation time peak (∼0.1 s) originating from water molecules associated with the silica surface, and a longer relaxation time peak (∼1−2 s) typical of bulk water. Proton relaxation resulting from the viscous hydrocarbons would also be expected to occur at short
T2gm = [T2gm(0) − T2gm(∞)] exp( −kt ) + T2gm(∞)
C
(3)
DOI: 10.1021/acs.energyfuels.5b02352 Energy Fuels XXXX, XXX, XXX−XXX
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Figure 2. Plot of T2gm against time for deionized water in contact with clean sand (open circles) and bitumen-coated sand B (filled circles). The solid line is a first-order exponential fit (eq 3) to the coated sand data. The dashed line is the mean value for clean sand.
Consistent with the spectra shown in Figure 1, it can also be seen in Figure 2 that the equilibrium T2gm does not attain the corresponding time-invariant mean value (238 ms) found for an uncoated clean sand surface, confirming that the contacting water only partially wets the sand surface under these experimental conditions. In comparison with these values of T2gm, we found that contacting sand with bulk JACOS bitumen in the absence of water is characterized by a steady T2gm value of ∼3 ms, indicating that this interaction would not be expected to contribute significantly to the overall T2gm in mixed systems containing water. Bitumen Displacement Mechanisms. We consider that two possible mechanisms may account for the observed T2gm time dependence. The first of these involves the aqueous phase initially penetrating regions of exposed sand where the bitumen film is incompletely or only partially present. The timedependent T2gm behavior would therefore reflect the conversion of bitumen/sand into water/sand surfaces (i.e., displacement). The second mechanism involves water (and possibly ions37) being solubilized in the bitumen, followed by diffusion to the sand surface (i.e., solution-diffusion). In the latter case, the time-dependent T2gm behavior could be expected to show characteristics of a water diffusion process. Further consideration of these mechanisms will be discussed below based on results from a larger range of systems. Bitumen-Coated Sand + Sodium Chloride Solutions. Figure 3 shows the initial and equilibrium T2 distributions for sand B in contact with the high and low sodium chloride concentration solutions. The trend is very similar to that shown in Figure 1 for deionized water. Thus, with increasing water contact time, T2gm decreases as before. However, it is noticeable that the relative change for the low-salinity solution (Figure 3a) is similar to that found for water, as might be expected, whereas the high-salinity solution (Figure 3b) shows a relatively lower contribution from interfacial water as equilibrium is reached. This behavior is also clearly seen in the T2gm profiles shown in Figure 4. As before, the data are fitted according to eq 3
Figure 3. Initial (filled squares) and equilibrium (open squares) T2 distributions for sodium chloride solutions in contact with sand B: (a) 950 ppm and (b) 100 000 ppm.
Figure 4. Plots of T2gm against time for sand B in contact with sodium chloride solutions (950 ppm, filled circles, and 100 000 ppm, filled triangles). The solid lines are pseudo-first-order exponential fits to the data (eq 3). The open symbols refer to T2gm values for the corresponding solutions in contact with uncoated sand, and the dashed line indicates the mean T2gm value.
representing first-order kinetics. The corresponding NaCl solutions in contact with clean sand are invariant with time. It is noticeable from these results that the low-concentration NaCl solution more closely approaches the T2gm value for clean D
DOI: 10.1021/acs.energyfuels.5b02352 Energy Fuels XXXX, XXX, XXX−XXX
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Energy & Fuels sand, although the data also indicate further changes in T2gm after the fitted first-order curves, possibly suggesting that a further, slower process may also be occurring. In addition to salt concentration, however, the bitumen coverage also has a significant effect on the NMR behavior. Thus, Figure 5 shows data for short contact times exemplifying
both sands A and B approach approximately similar equilibrium T2gm(∞) values (396 and 407 ms, respectively), these remain somewhat higher than the value of 238 ms for the clean sand surface. Bitumen-Coated Sand + Other Alkali and Alkaline Earth Metal Chlorides. The general trends described above are shown by all the metal chloride solutions studied, as is apparent from the fitting parameters given in Table 3 (T2gm− time plots for high and low salt concentrations of KCl, LiCl, CaCl2, and MgCl2 on sands A and B are provided as Supporting Information). The corresponding k, T2gm(0), and T2gm(∞) values for the additional chloride salts similarly show that fluid and solid interactions are dependent on the bitumen thickness and salt concentration. The rate constants are seen to be consistently larger for sand A than for sand B, as will be discussed in more detail later, and T2gm(∞) values are lower for low salt than for high salt concentration, as can be seen in Figure 6. Therefore,
Figure 5. Plots of T2gm against time for deionized water in contact with sand A (filled circles) and sand B (filled triangles). The solid lines are pseudo-first-order exponential fits to the data (the fitting parameters being given in Table 3). The open circles refer to time-invariant T2gm values for the corresponding solutions in contact with uncoated sand with the dashed line indicating the mean value.
the different initial kinetics for the two bitumen loadings in sand samples A and B. The lower bitumen content sand A is characterized by a slightly higher initial T2gm(0) value, and, more significantly, attains the equilibrium T2gm(∞) value more rapidly compared with sand B. This comparison serves to illustrate the effect of coating thickness on the kinetics of the change in T2gm. The T2gm values reflect the overall change in proton environments within the system, with the observed time-dependence being a consequence of increased water/sand interactions. Thus, it would be expected that complete displacement of bitumen from the sand should return its surface to its original water-wet condition. However, as mentioned above, and as is also evident from Table 3, although
Figure 6. T2gm(∞) values for solutions of the indicated metal chloride salts on sands A (blue) and B (red). The dashed line represents the T2gm(∞) value for water on fresh, untreated sand. The inset shows the averaged T2gm(∞) data for sands A and B and all the salts studied, to illustrate the dependence on salt concentration.
Table 3. T2gm(0), T2gm(∞), and Rate Constants (k) for Bitumen-Coated Sand Samples A and B, Calculated Based on Eq 3 sand A, 10 mg/g
sand B, 20 mg/g
salt
salt concn (ppm)
T2gm(0) (ms)
T2gm(∞) (ms)
k (min )
T2gm(0) (ms)
T2gm(∞) (ms)
k (min−1)
none (deionized water)
−
838
407
0.0847
747
396
0.0082
LiCl
950 100 000
963 934
359 516
0.0862 0.0325
656 1120
350 606
0.0113 0.0050
NaCl
950 100 000
1003 914
392 436
0.0625 0.0351
799 1130
360 578
0.0159 0.0093
KCl
950 100 000
1084 975
398 449
0.0549 0.0375
1270 1180
405 525
0.0085 0.0104
MgCl2
950 100 000
866 1021
362 463
0.0797 0.0362
790 1050
336 513
0.0111 0.0113
CaCl2
950 100 000
721 757
337 476
0.0340 0.0261
959 924
344 421
0.0127 0.0165
E
−1
DOI: 10.1021/acs.energyfuels.5b02352 Energy Fuels XXXX, XXX, XXX−XXX
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Figure 7. Rate constants for (a) 950 ppm and (b) 100 000 ppm metal chloride solutions on bitumen-coated sands A (blue bars) and B (red bars). The dashed lines are the corresponding rates for deionized water on the respective coated sands.
depart from the general trend. However, as Figure 5 shows, for a given salt solution the T2gm(∞) values are independent of the thickness of the bitumen film, which indicates that since the equilibrium condition is similar for both film thicknesses, it is only the rate that is thickness-dependent. Possible Mechanisms Responsible for the Observed T2gm Kinetic Behavior. In considering reasons for the change in T2gm with time, earlier in this paper we advanced displacement and solution/diffusion as two possible candidate mechanisms. However, using opto-digital microscopy, we found little evidence for bitumen displacement from the sand surface even after extended soak periods in the different solutions, although as Figure 8 shows, there were some noticeable
even when compared with water, lower concentrations of monovalent (with the possible exception of KCl) and divalent salts typically produce T2gm(∞) values indicative of stronger interactions (i.e., greater wetting) with the sand surface. On the other hand, the T2gm(∞) values for the concentrated salt solutions were all higher than for water. The inset to Figure 6 emphasizes the effects of salt concentration for both sand samples and deionized water, such that the lower concentration salt solutions produce more favorable interactions with bitumen-coated sand, although the T2gm(∞) values are still consistently higher than the clean sand value. The potential roles of divalent cations in low-salinity oil recovery mechanisms, particularly wettability alteration, have been the subject of several recent studies.17,38−42 One of the main general conclusions from these studies is that the presence of divalent cations significantly influences the wettability of rock surfaces, and that the specific removal of Ca2+ and Mg2+ ions increases water-wettability.42 The cations are believed to promote oil-wettability by binding acidic oil components to mineral surfaces.17,42 It may therefore be significant that the lower concentrations of Ca2+ and Mg2+ examined in the present study are seen to exhibit marginally lower T2gm(∞) values for the divalent cations (Figure 6), implying that these cations have slightly greater affinities toward sand surfaces compared with monovalent cations, which is a prerequisite for the cation binding mechanism. The measured rate constants are also dependent on the metal ion, its concentration and the bitumen coating, as shown in Figure 7. Once again, for the low-concentration salt solutions and sand A (Figure 7a), it is evident that some of the rate data are significantly lower than the deionized water value, i.e., for NaCl, KCl, and CaCl2. The corresponding rate data for sand B are less sensitive to the different salt solutions. This is also the case for the higher concentration salt solutions with sand A, although CaCl2 appears to be an exception (Figure 7b). On the other hand, the behavior of the higher concentration solutions in contact with sand B shows an opposing trend across the salt series studied. At present we are not clear as to the reason for this. Unsurprisingly, based on the respective average bitumen thicknesses of the surface coatings, the rate constants for water and the aqueous solutions are higher for sand A than for sand B. This reflects the easier access to the sand surface for the former as a result of lower surface coverage or smaller diffusion distances within the surface films, although CaCl2 is seen to
Figure 8. Opto-digital polarized light microscope images of sand B (20 mg/L bitumen): (a) as prepared and (b) after being left to soak for 2 weeks in deionized water. The scale bars are both 400 μm.
changes in the surface distribution of bitumen. After exposing the bitumen-coated sand to water (for 2 weeks in this example), the bitumen appears on the sand grains as relatively evenly distributed patches. On closer inspection, however, it is also apparent that the bitumen has become saturated with water droplets with diameters in the range ∼1−3 μm, as shown in Figure 9. Although it is difficult to be explicit in explaining the presence of water droplets in the surface bitumen, the finding is consistent with a solution/diffusion process, as suggested earlier, in which solubilized water has nucleated and grown (or coalesced) into larger droplets. A similar phenomenon has recently been reported elsewhere in the context of explaining low-salinity waterflooding mechanisms for conventional oils.3 Sohrabi et al. observed F
DOI: 10.1021/acs.energyfuels.5b02352 Energy Fuels XXXX, XXX, XXX−XXX
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in which kB is the Boltzmann constant, T the absolute temperature, η the film viscosity, and a the radius of the diffusing water species. This results in eq 6, from which the diffusion rate is expected to be inversely proportional to h2.
k=
kBT 6πηah2
(6)
In the multiple emulsion study, water transportation was considered to occur via reverse (i.e., w/o) microemulsion droplets of radius 3 nm.37 In our system, however, while it is possible that certain species in the bitumen could participate in a similar transport mechanism involving water, it is difficult to predict their size. Instead, we use eq 6 to calculate the apparent size of a diffusing species consistent with the NMR rate data. Thus, Figure 10 shows a plot of k vs h2 using all the rate data from Table 3 (the spread in the data is covered by the error
Figure 9. Opto-digital polarized light microscope image showing a close-up of bitumen-rich regions on sand B (20 mg/L bitumen) after being exposed to deionized water. The inset shows a 3D view in which the indicated droplets are seen to protrude from the surface of the bitumen. The scale bar of the main image is 20 μm.
the formation of water “micro-dispersions” when contacting certain crude oils with low-salinity water.3 These authors have proposed that microdispersion formation is accompanied by removal of indigenous surface-active species that are responsible for the original oil-wet condition from the rock surfaces to the bulk oil, thereby reducing the oil−surface interaction. We propose that in the present case the driving force for water diffusion is a salinity gradient caused by residual salt and water in the original bitumen, which, from the data in Table 1, is oversaturated (at 20 °C, the saturation concentration of NaCl is 35.89 g/100g water,43 cf. 79 mg/55 mg ≡ 143.6 g/100 g in the bitumen sample). As will be discussed subsequently, it is also to be expected that surface-active components in the oil will play an active role. One particular question to be addressed, however, is whether the observed T2gm kinetic results are consistent with a water diffusion process through an oil film? From Table 3 and Figure 7, it is evident that the rates of change of T2gm, as measured by the k values, are some 10 times faster for sand A (10 mg/g) compared with sand B (20 mg/g). On the basis of the microscopy evidence in Figure 9, this is consistent with water uptake by the oil, which is likely to occur initially by the solution/diffusion process discussed above. Following the treatment of water diffusion through an oil film of thickness h in water-in-oil-in-water (w/o/w) multiple emulsions given by Cheng et al., the diffusion rate, given by37
k=
D h2
Figure 10. Plot of the diffusion rate constant, k, against 1/h2. The error bars represent the spread of the data for all bitumen systems given in Table 3, and the drawn line is based on eq 6 and parameters given in the text.
bars) and the average bitumen film thicknesses given earlier in this paper. The data have been converted to SI units, and from the regression line (fitted through the origin), an estimated value for the radius of the diffusing species of 0.9 nm is obtained using the bitumen viscosity given in Table 1. Although the calculated size of the diffusing species is smaller than the reverse microemulsion droplets,37 it is consistent with solubilized water molecules or aggregates. A representation of the present system is suggested in Figure 11, in which solubilized water molecules (and ions) diffuse from the aqueous solution toward the bitumen/sand interface where the droplets accumulate, coalesce and partially wet the sand surface without displacing the viscous bitumen film. Thus, the difference between T2gm(∞) values for coated sand and a clean sand surface largely reflects the partially wetted condition. It is possible that an adsorbed film comprising indigenous hydrophobic surface-active species from the bitumen is present on the sand surface, which would also serve to restrict direct water contact and complete wetting. Polybutene-Coated Sands + Water. From the preceding discussion, it was suggested that surface-active components in the bitumen film play an important role in the solution/ diffusion mechanism. In an attempt to reduce or completely remove these contributions, comparative experiments have been conducted using a “cleaner” system based on sand coated
(4)
is combined with the diffusion coefficient D given by the Stokes−Einstein equation,
D=
kBT 6πηa
(5) G
DOI: 10.1021/acs.energyfuels.5b02352 Energy Fuels XXXX, XXX, XXX−XXX
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Table 4. Summary of ΔT2gm Values for the Three Oil Phases Studied sample designation
sand coating
surface coverage (mg/g)
ΔT2gm (ms)
A B
bitumen
10 20
431 351
C D
Glissopal 1000
10 20
54 86
E F
Glissopal 2300
10 20
116 170
Thus, depending on the Glissopal grade used and its surface coverage, the ΔT2gm values for the coated sands are some 2−8 times less than for the corresponding bitumen-coated sands, with the smallest values produced by Glissopal 1000. In the absence of surface-active components, therefore, the T2gm(0) and T2gm(∞) values most likely reflect the initial extent of surface coverage, such that the lower values found for Glissopal 1000 are indicative of thinner films and greater interaction between water and the sand surface. The more viscous Glissopal 2300 provides a greater barrier for water to access sand surface sites, as is initially the case for bitumen (cf. Figures 5 and 12). Unlike the bitumen-coated sands, however, the time dependence of T2gm is substantially reduced for the Glissopal coatings, prompting our interpretation that the extent of water diffusion in the latter is very much less than for bitumen. In support of this, we were unable to find microscopic evidence of entrained water droplets as observed for bitumen (Figure 9). In Figure 13 are shown T2gm(∞) data for the two Glissopalcoated sand systems with deionized water to demonstrate the
Figure 11. Schematic showing a possible mechanism for the interaction between water and bitumen-coated sand. Water is solubilized by surface-active species in the oil (highly exaggerated as “tadpoles”) in the form of reverse micelles, which then diffuse through the film toward the hydrophilic sand surface, where partial wetting occurs. Complete wetting is restricted by the presence of a hydrophobic surface film and high bitumen viscosity. Water droplet growth is also possible with time.
with viscous polybutene hydrocarbons which contain minimal surface-active components. In Figure 12 are shown T2gm profiles for Glissopal 1000coated sands C and D (10 and 20 mg/g, respectively) and
Figure 13. Relationships between T2gm(∞) and the amount of Glissopal 1000 (sands C and D, circles) and Glissopal 2300 (sands E and F, triangles) on sand. The error bars represent the standard deviations of the data shown in Figure 12 for contact times in excess of 45 min.
Figure 12. Plots of T2gm against time for deionized water in contact with sands C (triangles), D (circles), E (diamonds), and F (squares). The solid lines are pseudo-first-order exponential fits to the data. The open circles refer to T2gm values for deionized water in contact with uncoated sand with the dashed line indicating the corresponding mean T2gm value.
effect of polybutene coating density which are consistent with the interaction of water with sand surfaces containing an oil film (most likely with incomplete coverage). Relevance to COBR Systems and Wettability. On the basis of the present experimental approach which has focused on the use of NMR T2 relaxation time measurements, we have seen no evidence for the displacement of viscous oil phases from sand surfaces as a result of exposure to various aqueous salt solutions. On the other hand, there is evidence to suggest that the observed time dependence of T2gm is a result of water
Glissopal 2300-coated sands E and F (10 and 20 mg/g, respectively) in contact with deionized water. In comparison with the corresponding bitumen-coated sand data with deionized water, the Glissopal profiles show smaller differences between T2gm(0) and T2gm(∞) (i.e., ΔT2gm), as Table 4 shows for equivalent surface coverages. H
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Energy & Fuels incorporation into bitumen films covering the sand grains. Exposure to water, typically for up to 2 weeks, led to the appearance of “emulsified” water droplets in the size range of 1−3 μm, which has been interpreted as originating from solution/diffusion followed by growth (or coalescence), as the water concentration increases within the bitumen. Thus, the time dependence of T2gm does not solely reflect a wettability change, but also an increase in water immobilized in the bitumen film, for which the presence of an osmotic driving force together with surface-active components is required to provide a transport mechanism through the film. The salinity of the various aqueous phases used in this study moderates this behavior as would be expected for an osmotic mechanism, although we cannot rule out additional specific ion effects. In support of this, sands coated with a cleaner viscous hydrocarbon exhibit reduced time-dependent T 2gm behavior, consistent with the absence of components which facilitate water transportation. As discussed briefly above, in addition to changes due to surface wettability, from eq 2 it is evident that the presence of an organic film on a solid surface may also influence proton relaxation by smoothing out surface roughness and hence decreasing the effective surface area. Surface relaxivity will also be affected by the presence of an organic film which would lead to shielding of water protons from paramagnetic centers present in the solid surface. For example, Bryar and Knight found a marked decrease in surface relaxivity of quartz sand in the presence of surface Athabasca bitumen which, according to eq 2, would be expected to increase T2,surface.33 According to our present findings, the two homologous Glissopal oils appear to exhibit different shielding behavior, as reflected in their respective T2gm(∞) values (Figure 13), which may be a consequence of their different viscosities. The more viscous Glissopal 2300 may be more immobilized on the surface and less prone to possible surface redistribution as seen for bitumen in Figure 8b. Bitumen or other crude oils might be expected to show further differences due to other paramagnetic content in the oil. Thus, NMR relaxation measurements in the OBS system have shown that water diffusion into a surface bitumen film occurs on a time scale of minutes to hours, depending on the salinity of the external brine phase. Although not studied here as a variable, the “internal salinity” of the oil would also be important for an osmotically driven process. We conjecture that expansion of the surface oil film as water is absorbed could influence oil recovery; in effect, the original oil phase becomes a water-in-oil emulsion. Other influential factors include the increased viscosity of the emulsion compared with the oil phase, the removal of surface-active species from the solid surface as a result of competition with emulsified water droplets,3 and the effect of modified interactions between the emulsion and the solid surface. Water droplets penetrating the hydrophobic surface layer and coalescing with the sand surface may also effect a wettability change and disrupt oil contact, facilitating oil displacement.
explain the observed relaxation time behavior. It is suggested that water additionally diffuses into the bitumen coating under an osmotic driving force as a result of salt (and water) content in the bitumen. This leads to an accumulation of water droplets within the bitumen, as has been observed using optical microscopy. In the absence of a transport mechanism, as in the case of the viscous hydrocarbon, significantly reduced timedependent changes in T2gm are produced. As a result of the present experimental findings, we have conjectured that this mechanism may have implications for the recovery of heavy oil and bitumen, similar to that proposed for lighter crude oils,3 involving water uptake by the oil to form emulsions which modify interactions within the COBR systems.
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ASSOCIATED CONTENT
S Supporting Information *
The Supporting Information is available free of charge on the ACS Publications website at DOI: 10.1021/acs.energyfuels.5b02352. Figures SI1−SI7, showing T2gm vs time profiles for potassium, lithium, magnesium, and calcium chlorides, and Figures SI8−SI10, showing initial and final T2 distributions for aqueous solutions of KCl, LiCl, and MgCl2 on sand B at 950 and 100 000 ppm (PDF)
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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 The authors gratefully acknowledge financial support from BP for this work and for establishing the Centre for Petroleum and Surface Chemistry at Surrey. The Glissopal polybutene samples were generously supplied by BASF, Lugwigshafen. We thank the reviewers for raising some relevant and constructive points which have greatly improved the paper.
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REFERENCES
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CONCLUSIONS In this study NMR relaxation has been demonstrated as a useful tool to evaluate interactions between oil-coated sands and aqueous salt solutions. We originally set out to use NMR geometric mean relaxation times27 to investigate how salt type and concentration influence the wettability of oil-coated sands. However, we found that wettability changes alone did not fully I
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