Energy Fuels 2009, 23, 4479–4485 Published on Web 08/12/2009
: DOI:10.1021/ef900185q
Smart Water as Wettability Modifier in Carbonate and Sandstone: A Discussion of Similarities/Differences in the Chemical Mechanisms A. RezaeiDoust, T. Puntervold,* S. Strand, and T. Austad University of Stavanger, 4036 Stavanger, Norway Received March 5, 2009. Revised Manuscript Received July 2, 2009
Waterflooding has for a long time been regarded as a secondary oil recovery method. In the recent years, extensive research on crude oil, brine, and rock systems has documented that the composition of the injected water can change wetting properties of the reservoir during a waterflood in a favorable way to improve oil recovery. Thus, injection of “smart water” with a correct composition and salinity can act as a tertiary recovery method. Economically, it is, however, important to perform a waterflood at an optimum condition in a secondary process. Examples of smart water injection in carbonates and sandstones are: (1) injection of seawater into high temperature chalk reservoirs and (2) low salinity floods in sandstone reservoirs. The chemical mechanism behind the wettability alteration promoted by the injected water has been a topic for discussion both in carbonates and especially in sandstones. In this paper, the suggested mechanisms for the wettability modification in the two types of reservoir rocks are shortly reviewed with a special focus on chemical similarities and differences. The different chemical bonding mechanisms of polar components from the crude oil onto the positively charged carbonate and the negatively charged quartz/ clay indicates a different chemical mechanism for wettability modification by smart water in the two cases.
OOIP, compared to injection of formation brine in a spontaneous imbibition process. When performing a viscous flood with only 1 psi differential pressure, the oil recovery increased from 40 to 60% OOIP. Thus, SW appears to change the capillary pressure curve in a positive way for enhanced oil recovery from the chalk fields. The pioneering work by Yildiz and Morrow in 19968 showed that the ionic composition of the injected brine influenced the oil recovery in a forced displacement process in sandstone. Nine years later it was documented by Webb et al. that increased oil recovery from sandstones by waterflooding was obtained by injecting water of low salinity (Figure 2).9 Since then, the same research group has performed several studies at complete reservoir conditions, which have confirmed the results from Morrow et al. In most cases, the extra oil recovered from low salinity flooding varied in the range of 5-20% of OOIP.9-12 There is no doubt that the injection of water with a specific composition is able to change the thermodynamic equilibrium between the different phases in a favorable way during the production period. The change in the equilibrium is mostly linked to the interaction between the injected water and the
Introduction Initially, in an oil reservoir, a thermodynamic equilibrium has been established between the rock, formation water, and oil through millions of years. In many cases, the wetting condition for oil displacement is not optimal with the available source of injection water. The wetting condition can, however, be improved by modifying the ionic composition of the injected fluid. Through extensive work by Austad et al.1-5 it has been verified that seawater, SW, is able to improve the water wetness of carbonates, especially chalk, leading to increased oil recovery both by spontaneous imbibition and forced displacement at high temperatures (Figure 1).6 Webb et al.7 have verified the effect of SW by performing studies on Valhall chalk cores at reservoir conditions. They observed that the whole capillary pressure curve was changed by applying SW compared to formation water. Seawater injection increased the oil recovery by 40% of original oil in place, *To whom correspondence should be addressed. E-mail: tina.puntervold@ uis.no. (1) Zhang, P. Water-based EOR in Fractured Chalk ; Wettability and Chemical Additives; Ph.D. Thesis, University of Stavanger: Norway, 2006; ISBN: 82-7644-293-5. (2) Høgnesen, E. J. EOR in Fractured Oil-Wet Chalk ; Spontaneous Imbibition of Water by Wettability Alteration; Dr. Ing. Thesis, University of Stavanger: 2005C (3) Puntervold, T. Waterflooding of Carbonate Reservoirs ; EOR by Wettability Alteration; PhD Thesis, University of Stavanger: Norway, 2008; ISBN 978-82-7644-347-9. (4) Standnes, D. C. Enhanced Oil Recovery from Oil-Wet Carbonate Rock by Spontaneous Imbibition of Aqueous Surfactant Solutions; Dr. Ing. Thesis, NTNU: Norway, 2001. (5) Strand, S. Wettability Alteration in Chalk - A Study of Surface Chemistry; Dr. Ing. Thesis, University of Stavanger: 2005. (6) Strand, S.; Puntervold, T.; Austad, T. Energy Fuels 2008, 22, 3222– 3225. (7) Webb, K. J.; Black, C. J. J.; Tjetland, G., A laboratory study investigating methods for improving oil recovery in carbonates. International Petroleum Technology Conference (IPTC), Doha, Qatar, Nov 21-23, 2005. r 2009 American Chemical Society
(8) Yildiz, H. O.; Morrow, N. R. J. Pet. Sci. Eng. 1996, 14, 159–168. (9) Webb, K. J.; Black, C. J. J.; Edmonds, I. J., Low salinity oil recovery - The role of reservoir condition corefloods. Paper C18 presented at the 13th European Symposium on Improved Oil Recovery, Budapest, Hungary, April 25-27, 2005. (10) Lager, A.; Webb, K. J.; Black, C. J. J., Impact of brine chemistry on oil recovery. Paper A24 presented at the 14th European Symposium on Improved Oil Recovery, Cairo, Egypt, April 22-24, 2007. (11) Lager, A.; Webb, K. J.; Collins, I. R.; Richmond, D. M., LoSal enhanced oil recovery: Evidence of enhanced oil recovery at the reservoir scale. Paper SPE 113976 presented at the 2008 SPE/DOE Improved Oil Recovery Symposium, Tulsa, OK, USA, April 19-23, 2008. (12) Webb, K. J.; Lager, A.; Black, C. J. J., Comparison of high/low salinity water/oil relative permeability. Paper SCA2008-39 presented at the International Symposium of the Society of Core Analysts, Abu Dhabi, U. A. E., Oct 29 to Nov 2, 2008.
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paper shortly lists the suggested chemical mechanisms for wettability modification by smart water in carbonates and sandstones, and subsequently both similarities and differences regarding the mechanisms have been evaluated. Smart Water in Chalk/Carbonates Through systematic experimental studies, it was verified that Ca2þ, Mg2þ, and SO42- were the active ions in the wettability alteration process. The wettability alteration became more efficient as the temperature increased above 100 °C. Each of the parameters Ca2þ, Mg2þ, SO42-, and T were varied separately to verify their impact on oil recovery in a spontaneous imbibition process. It was also documented by ζ potential measurements that these ions acted as potential determining ions toward chalk, that is, they were able to adsorb onto the chalk surface.15,16 On the basis of the experimental results, a chemical mechanism was proposed involving mutual interactions between Ca2þ and SO42- and also between Mg2þ and SO42- at the chalk surface, causing displacement of adsorbed organic materials. As the temperature increases, SO42- adsorbs more strongly onto the positively charged chalk surface. Due to a decrease in the positive surface charge, more Ca2þ will be attached to the surface, probably in the Stern layer.17 Sulfate is solvated by hydrogen bonds in water, and the increased reactivity of SO42- toward the chalk surface at high temperature is partly due to breakage of these hydrogen bonds. The mutual interaction between SO42- and Ca2þ at various temperatures at the chalk surface is clearly illustrated by panels a and b of Figure 3. Thus, as long as both anionic and cationic potential determining ions are present in solution, the ζ potential will not change very much as the temperature is increased, but the reactivity of the actual ions will increase.17 Mg2þ is strongly hydrated in water at low temperature, which decreases its reactivity toward other minerals. This is the reason for the relatively high concentration of Mg2þ found in SW. As the temperature increases, Mg2þ becomes partly dehydrated and its reactivity increases. In addition, the dielectric constant of the water decreases, which may decrease the solubility of Mg2þ. Increased reactivity of Mg2þ is also illustrated by the ion-pair formation with SO42- in water:18
Figure 1. Oil recovery from two chalk cores (C#4 and C#5) at 110 °C by successive spontaneous imbibition (SI) and viscous flooding (VF) of formation water (FW) and seawater (SW). Injection rate: 0.06-0.10 PV/day. The differential pressure across the core varied from 6 psi at the start to 3 psi at the end. Swi ∼ 0.1, and the oil acid number was 1.9 mg KOH/g.6
Figure 2. Low salinity in a tertiary flow mode.9
rock surface. In terms of wettability modification, the activation energy, or energy barrier for the chemical reactions needed for wettability improvement to take place, is crucial. If the reaction rate is too slow, then the new equilibrium will not be established during the time frame of the waterflood, and improvements of the waterflood will not be achieved. The reservoir temperature plays a very important role here because the activation energy is strongly dependent on the temperature.13,14 The activation energy for the wettability modification is related to how strongly the polar oil components are bonded to the mineral surface, the solvency of the polar components in the actual phases, and the reactivity of the ions present in the injected water. Generally, the bonding energy between polar components in the oil and carbonates is higher than what is observed for minerals such as clays and silica, which are present in sandstones. In porous media, multiphase fluid flow, such as water and oil, is dictated by the wetting properties of the rock. It has been documented that the wetting properties can be altered in a favorable way to enhance oil recovery by optimizing the ionic properties of the injected water. Because of different chemical and physical rock properties related to carbonates and sandstones, it could be valuable to compare the two processes. This
Mg2þ þ SO4 2 - ¼ ½Mg2þ 3 3 3 SO4 2 - ðaqÞ
ð1Þ
As the temperature increases, the equilibrium is moved to the right. In a competitive adsorption onto chalk of equimolar solutions of Ca2þ and Mg2þ at room temperature, Ca2þ adsorbed more strongly than Mg2þ; but at high temperature, Mg2þ became much more reactive and even displaced Ca2þ from the chalk surface lattice. By flooding SW slowly (1 pore volume/day, PV/d) through a carbonate core at 130 °C, the molar decrease in [Mg2þ] was equal to the molar increase in [Ca2þ], Figure 4.19 Within the accuracy of the analysis, no change in [SO42-] was observed, indicating that a potential precipitation of CaSO4(s) is small. The increase in [Ca2þ] of SW appeared to correlate linearly with temperature (Figure 5).20 (15) Zhang, P.; Austad, T. Colloids Surf. A 2006, 279, 179–187. (16) Zhang, P.; Tweheyo, M. T.; Austad, T. Colloids Surf. A 2007, 301, 199–208. (17) Strand, S.; Hoegnesen, E. J.; Austad, T. Colloids Surf. A 2006, 275, 1–10. (18) Carlberg, B. L.; Matthews, R. R., Solubility of calcium sulfate in brine. Oilfield Chemistry Symposium of the Society of Petroleum Engineers of AIME, Denver, Colorado, USA, May 24-25, 1973. (19) Strand, S.; Austad, T.; Puntervold, T.; Hoegnesen, E. J.; Olsen, M.; Barstad, S. M. F. Energy Fuels 2008, 22, 3126–3133. (20) Puntervold, T.; Austad, T. J. Pet. Sci. Eng. 2008, 63, 23–33.
(13) Puntervold, T.; Strand, S.; Austad, T. Energy Fuels 2007, 21 (6), 3425–3430. (14) Puntervold, T.; Strand, S.; Austad, T. Energy Fuels 2009, 23, 2527–2536.
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Figure 4. Molar concentrations of Ca2þ, Mg2þ, and SO42- in the effluent when flooding SW through a limestone core at 130 °C are compared to the molar concentrations in SW. Flow rate: 1 PV/d.19
Figure 5. The increase in Ca2þ concentration due to substitution by Mg2þ present in SW, as a function of temperature.20
Figure 3. (a) The relative concentrations of tracer, SCN-, and sulfate, SO42-, are plotted against pore volume, PV. The retention/adsorption of sulfate increases as the temperature increases. [Ca2þ] and [SO42-] are constant and equal to the corresponding concentrations in SW.17 (b) The concentration of Ca2þ in solution decreases as the retention of SO42- increases with increasing temperature. [Ca2þ] and [SO42-] are equal to the corresponding concentrations in SW.17
The substitution reaction on the chalk surface is schematically illustrated by eq 2. The substitution reaction does not change the surface charge of the chalk. Ca;CaCO3 ðsÞ þ Mg2þ ¼ Mg;CaCO3 ðsÞ þ Ca2þ
ð2Þ
A summary of the impact of Ca2þ, Mg2þ, SO42-, and T on the oil recovery from chalk of low water wetness in a spontaneous imbibition process is illustrated by Figure 6. Four chalk cores were prepared using a crude oil with high acid number (AN = 2.1 mg KOH/g) and NaCl similar to SW salinity as initial brine.16 After aging at 90 °C in crude oil for 4 weeks, the cores were imbibed with NaCl brine containing different amounts of SO42-, (0, 1, 2, and 4 the SW concentration of SO42-). No significant increase in oil recovery was detected, neither at 70 nor 100 °C. Thus, SO42- in the presence of NaCl is not able to change the wettability to improve spontaneous imbibition (SI). If, however, either Ca2þ or Mg2þ were present together with SO42-, improved SI was observed. It has been documented that SI of SW at 130 °C increased the water-wet surface fraction of a chalk plug from about 0.6 to 1.0.21 A chemical mechanism for wettability alteration, which is in line with experimental observations, was proposed and is illustrated
Figure 6. Spontaneous imbibition tests on 4 chalk cores were performed at 70, 100, and 130 °C. Initial brine: NaCl. Imbibing brine: NaCl-solution with different amounts of SO42- (0, 1, 2, and 4 SW concentration). Spontaneous imbibition occurred when Mg2þ or Ca2þ was added to the imbibing fluids.16
in Figure 7.16 In the case of Ca2þ and SO42- as the wettability modifiers, SO42- will adsorb onto the positively charged chalk surface, and the positive surface charge is decreased. More Ca2þ can then be attracted to the surface due to less electrostatic repulsion, panels a and b of Figure 3, and Ca2þ can react with carboxylic material and displace it from the surface according to the following reaction: RCOO - ;Ca;CaCO3 ðsÞ þ Ca2þ þ SO4 2 ¼ RCOO;Caþ þ Ca;CaCO3 ðsÞ þ SO4 2 -
(21) Austad, T.; Strand, S.; Puntervold, T.; Ravari, R. R., New method to clean carbonate reservoir cores by seawater. Paper SCA2008-15 presented at the International Symposium of the Society of Core Analysts, Abu Dhabi, U.A.E., Oct 29 to Nov 2, 2008.
ð3Þ
SO42- only acts as an important catalyst promoting an increase in the concentration of Ca2þ close to the surface. In 4481
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• The type of clay may play a role. • Oil
• Water - Formation water must contain divalent cations, that is, Ca2þ, Mg2þ.23 • Initial formation water (FW) must be present. • Efficiency is related to initial water saturation, Swi.
Figure 7. Schematic model of the suggested mechanism for the wettability alteration induced by SW. (A) Proposed mechanism when Ca2þ and SO42- are active. (B) Proposed mechanism when Mg2þ and SO42- are active.16
- Low salinity fluid usually between 1000 and 2000 ppm, but effects have been observed up to 5000 ppm. • Appears to be sensitive to ionic composition (Ca2þ vs Naþ).
the case of Mg2þ and SO42- as the wettability modifiers, we suggest that Mg2þ is able to displace the Ca2þ ion, which is connected to the carboxylic group, in the same way as Mg2þ is able to displace other Ca2þ ions from the surface lattice of the chalk. Also this reaction is catalyzed by SO42-, which is clearly demonstrated by the very small increase in oil recovery for the imbibition test without added SO42-, Figure 6 (pink squares). This substitution can be illustrated by the following reaction: -
RCOO ;Ca;CaCO3 ðsÞ þ Mg þ SO4 2þ
- pH of effluent water usually increases a little. • It is not verified if pH changes are needed for observing low salinity effects. • Production/migration of fines - In some cases production of fines have been detected, but low salinity effects have also been observed without visible production of fines.23
2-
¼ Mg;CaCO3 ðsÞ þ RCOO;Caþ þ SO4 2 -
- Must contain polar components (i.e., organic acids and/or bases) • No effects have been observed using refined oil free from polar components.
ð4Þ
• Permeability decrease - Usually an increase in pressure over the core is detected when switching to the low salinity fluid, which may be related to migration of fines or formation of an oil-water or a water-in-oil emulsion. - There is a lack of experimental evidence to say that observed low salinity effects are accompanied by permeability reduction. - Researchers at BP have performed waterflood experiments where they hardly saw any variation in end point relative permeability data between high and low salinity waterfloods, in both secondary and tertiary mode.12
The conditions for obtaining improved water wetness by “smart water” in carbonates may be summarized in the following way: • The injected water must contain SO42- in addition to either Ca2þ or Mg2þ or both. • High temperature, usually >90 °C. Smart Water in Sandstones During the last years, there have been several papers and presentations at various conferences on low salinity flooding, and discussion of the chemical mechanism has been a very common issue. The scope of this paper is not to go into detail concerning the argumentation behind the suggested mechanisms, but rather look at possible links between the surface chemistry causing improved oil recovery by smart water from the two types of rock, carbonate and sandstone. The conditions for observing low salinity effects will be listed briefly, and then there will be a presentation of the proposed mechanisms up until today. Conditions for Low Salinity Effects. The listed conditions for low salinity effects are mostly related to the systematic experimental work by Tang and Morrow,22 but some points have also been taken from the work by Lager et al.10,23 • Porous medium - Sandstones • Low salinity effects have not been documented in pure carbonates, but Pu et al. have observed low salinity effects in a sandstone containing dolomite crystals.24
• Temperature - There appears to be no temperature limitations to where low salinity effects can be observed. Most of the reported studies have, however, been performed at temperatures below 100 °C. It is often reported in the literature that low salinity effects have been observed both in a secondary and tertiary flood mode. In a tertiary flood mode, the core is first flooded with formation water (FW) until the oil production plateau is reached. Thereafter, the injected fluid is switched to low salinity water by diluting the FW with distilled water until the salinity is in the range of 1000-2000 ppm. When performing a secondary low salinity flood, the core is restored after the flooding with FW, and a new flood is performed with the low salinity water. The oil recoveries from the two floods are then compared. Very often it has been observed that the increase in oil recovery is higher in a secondary flood compared to a tertiary flood. Recently, a study on oil recovery by cyclic waterflooding of mixed-wet sandstone and limestone performed by Loahardjo et al.25
- Clay must be present (22) Tang, G.-Q.; Morrow, N. R. J. Pet. Sci. Eng. 1999, 24, 99–111. (23) Lager, A.; Webb, K. J.; Black, C. J. J.; Singleton, M.; Sorbie, K. S. Petrophysics 2008, 49 (1), 28–35. (24) Pu, H.; Xie, X.; Yin, P.; Morrow, N. R., Application of coalbed methane water to oil recovery by low salinity waterflooding. Paper SPE 113410 presented at the 2008 SPE Improved Oil Recovery Symposium, Tulsa, OK, USA, April 19-23, 2008.
(25) Loahardjo, N.; Xie, X.; Morrow, N. R., Oil recovery by cyclic waterflooding of mixed-wet sandstone and limestone. The 10th International Symposium on Reservoir Wettability, Abu Dhabi, U. A. E., Oct 2728, 2008.
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Table 1. Maximum Adsorption, Γmax, of Benzoic Acid onto Kaolinite at 32 °C31 pHinitial 5.3 6.0 8.1
alkaline flood. To generate in situ surfactants from carboxylic compounds, the acid number of the crude oil should be >0.2 mg KOH/g. Low salinity effects have been observed for crude oils with AN < 0.05 mg KOH/g. Furthermore, the increase in pH is in many cases not more than 1 pH unit, which causes the water to become only slightly basic. It is doubtful that the small increase in pH can decrease the interfacial tension (IFT) enough to promote low salinity effects, as pointed out by Lager et al. as well.23 It may, however, affect adsorption/desorption of carboxylic material onto clay, as will be discussed later in the paper. Multi-ion Exhange. The mechanism termed “multi ion exchange” (MIE) was suggested by Lager et al.23 It was assumed that the low salinity effect was related to increased water wetness of clay minerals. Since divalent ions must be present in the formation water, it was suggested that the presence of Mg2þ and Ca2þ plays an important role in the interaction between the clay minerals and surface active components in the crude oil. An adsorption model where Ca2þ acts as a bridge between the negatively charged clay surface and carboxylic material was suggested, and the organic material was supposed to be removed by cationic ion exchange at the surface. In that way, the MIE mechanism is of the same nature as the proposed mechanism for wettability modification in carbonates using SW.16 However, there is an important difference between the two cases; the salinity of the smart water in carbonates is quite different from the low salinity water in sandstones. Seawater is not regarded as low salinity water, and normally, it should not show low salinity effects in sandstones, but it does improve oil recovery from chalk at high temperatures. Contrary to chalk, it is very difficult to draw a reliable chemical reaction model that illustrates the MIE mechanism in sandstone as suggested by Lager et al.23 When the salinity decreases, there will be a net desorption of adsorbed ions from the clay surface and into the aqueous phase. Maybe then, a new and different relative ionic concentration in the aqueous phase will promote displacement of adsorbed organic material. Salting-in Mechanism. The thermodynamic equilibrium between the phases (water/oil/rock), which has been established during geological time, is disturbed by changing the salinity of the water. The solubility of polar organic components in water is affected by ionic composition and salinity, and the terms salting-out/salting-in effects have been used in the chemical literature. The solubility of organic material in water can be drastically decreased by adding salt to the solution, that is the salting-out effect, and the solubility can be increased by removing salt from the water, that is, the salting-in effect. There is a large number of examples in the literature where salting in and salting out effects of organic material have been observed: • Salinity gradients to optimize conditions for surfactant flooding (oil-in-water, three-phase, water-in-oil micro emulsions) • Critical micelle concentration, CMC, is related to salt effects • Adsorption at interfaces (oil-water, water-rock) • Solubility/precipitation of carboxylic material
Γmax, μmol/m2 3.7 1.2 0.1
showed increased oil recovery from restored cores using the same FW as was used in the first flood. In consequence, low salinity effects observed during a secondary flood mode need not to be linked solely to decrease in salinity of the injected fluid. This is surely new and interesting information about crude oil-brine-rock interactions. It is obvious that a chemical mechanistic study of the low salinity effect in sandstones is much more complicated compared to studying wettability alteration in chalk by smart water. Probably, the low salinity effect is a result of different mechanisms acting together, each with its own contribution. The different mechanisms, which have been proposed up to now, for example, fines migration, pH increase, multi-ion exchange (MIE), and our own hypothesis termed, “salting-in effects”, will be briefly described below. Migration of Fines. Tang and Morrow22 suggested that the low salinity water could release clay fragments, so-called fines, which could be transported along the oil-water interface. The release of clay particles will improve the water wetness of the clay minerals, but perhaps, even more important, the released clay particles can block pore throats and divert the flow of water into nonswept pores to improve the microscopic sweep efficiency. Skauge et al.26 draw an analogy to the enhanced oil recovery, EOR, technique using linked polymer solutions. Even though the linked polymer particles are much smaller than the pore throats in sandstone, it has been verified by a number of laboratory and field tests in China that injection of linked polymer gels improves oil recovery compared to ordinary polymer flooding.26,27 Skauge28 suggested a “log-jamming” process at the pore throat entry because the acceleration of the linked polymer particles will be slower than water due to differences in mass. Thus, it is believed that diverted flow is caused by the release of fines, which blocks the pore throats, and the observed improvement in oil recovery is not necessarily caused by a wettability modification, but rather by improved microscopic sweep efficiency. It should also be noted that Tang and Kovscek29 suggested release of fines as the mechanism for wettability alteration when injecting steam into diatomic reservoir rock. Increase in pH. On the basis of the fact that pH usually increases in a low salinity flood, McGuire et al.30 suggested that improved oil recovery could be related to a type of (26) Skauge, A.; Fallah, S.; McKay, E., Modeling of LPS Linked Polymer Solutions. The 29th IEA Workshop & Symposium, Beijing, China, Nov 3-5, 2008. (27) Li, M., Linked polymer solution (LPS) and its application in EOR. The 29th IEA Workshop & Symposium, Beijing, China, Nov 3-5, 2008. (28) Skauge, A., Microscopic diversion ; A new EOR technique. The 29th IEA Workshop & Symposium Beijing, China, Nov 3-5, 2008. (29) Tang, G.-Q.; Kovscek, A. R., Wettability alteration of diatomite induced by hot-fluid injection. Paper SPE 77461 presented at the 2002 SPE Annual Technical Conference and Exhibition, San Antonio, TX, USA, Sept 29 to Oct 2, 2002. (30) McGuire, P. L.; Chatham, J. R.; Paskvan, F. K.; Sommer, D. M.; Carini, F. H., Low salinity oil recovery: An exciting new EOR opportunity for Alaska’s North Slope. Paper SPE 93903 presented at the 2005 SPE Western Regional Meeting, Irvine, CA, USA, March 30 to April 1, 2005.
Organic material in water is solvated by the formation of a water structure created by hydrogen bonds around the hydrophobic part. The organic compounds are in that way structure makers. Inorganic ions (Ca2þ, Mg2þ, Naþ) break up the water structure around the organic molecules, and 4483
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Figure 8. Illustration of salt effects on desorption/resolubilization of 4-tert-butyl benzoic acid (PTBBA) in an aqueous kaolinite suspension. HS = high salinity brine and LS = low salinity brine.
thereby decrease the solubility, that is, they are structure breakers. The relative strength of the cations as structure breakers is reflected in their hydration energy. Therefore, divalent ions have a much stronger effect on the solubility of organic material in water. A decrease in salinity below a critical ionic strength can increase the solubility of organic material in the aqueous phase. This is called the salting-in effect, and it is part of our low salinity mechanism hypothesis. The above statement is in line with experimental results showing that significant low salinity effects on oil recovery have only been observed at salinities below a certain value, usually at salinities in the range of 2000-3000 ppm.9 It has been reported that exchanging Naþ by Ca2þ in the low salinity water decreases the efficiency of the low salinity flood.22 Taking into account the listed conditions for observing low salinity effects and the described effect of salt on the solubility of organic material in water, we suggest that some organic material will be desorbed from the clay by a saltingin effect and in this way contribute to the low salinity mechanism. The salting in mechanism is, of course, based on the assumption that low salinity effects are linked to improved water wetness of the clay. Therefore, the adsorbed organic material must be loosely bond to the surface and be able to be desorbed from the surface because of increased solubility in water. It is well-known that clay can act as a cation exchanger, and the cation replacing order is:
benzoic acid onto kaolinite from an aqueous 0.1 M NaCl solution is reported to be very sensitive to pH.31 According to Table 1, an increase in pH from 5.3 to 6.0 decreases the adsorption of benzoic acid onto kaolinite by a factor of ∼3.1. Provided that there is a reasonable reversibility in the adsorption process, then even a small increase in pH can facilitate the release of organic carboxylic material from the clay surface. Figure 8 shows the results from a preliminary study on the adsorption/precipitation and desorption/resolubilization of 4-tert-butyl benzoic acid in an aqueous suspension of kaolinite. Thirty weight percent of kaolinite powder was equilibrated with high salinity brine under rotation for 2 h. From a ∼0.07 M acid stock solution at slightly basic conditions, ∼0.01 M acid was added to the kaolinite/brine sample and left to equilibrate for 24 h under rotation. The 25 000 ppm high saline water contained equal concentrations of Ca2þ and Mg2þ (0.038 mol/L) in addition to NaCl. The experiments were conducted at room temperature. The samples were then centrifuged at 2500 rpm for 20 min. A 100 μL portion of the supernatant was diluted to 10 mL with distilled water. The absorbance was measured at a wavelength of 235 nm using a UV spectrophotometer. The concentration of 4tert-butyl benzoic acid in the supernatant was found by using a calibration curve. The discrepancy between initial acid concentration and the concentration in the supernatant was assumed to be the amount of acid adsorbed onto the kaolinite. An isotherm of the adsorption/precipitation of 4tert-butyl benzoic acid onto kaolinite was obtained using high saline water. Subsequently, two parallel desorption/ resolubilization tests were performed at low and high salinity. The low salinity water was obtained by diluting the high salinity water with distilled water down to 500 ppm. In the desorption with high salinity water, the whole supernatant was substituted with fresh high salinity water, keeping mass balance of the acid. In the case with low salinity water desorption, approximately half of the supernatant was
Liþ < Naþ < Kþ < Mg2þ < Ca2þ < Hþ As the salinity of the equilibrium water decreases, cations will desorb from the clay surface. At the same time, the solubility of organic compounds increases and some carboxylic material bonded to the surface through a Ca2þ bridge can then desorb from the surface. The release of cations from the clay surface will increase the pH of the new equilibrium solution as shown below for Ca2þ: Ca2þ ;ClayþH2 O ¼ Hþ ;ClayþCa2þ þOH -
ð5Þ
Very often a temporary increase in pH is observed in the effluent fluid in a low salinity flood. The adsorption of
(31) Madsen, L.; Lind, I., SPE Reservoir Evaluation & Engineering 1998, February, 47-51.
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: DOI:10.1021/ef900185q
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tures by a mechanism, which may be characterized as a MIE in line with the description by Lager et al.10 The wettability modification in carbonates can take place at high salinities, that is, SW salinity. Depending on the temperature, if SW is diluted by distilled water to a low saline fluid, ∼2000 ppm, the oil recovery will decrease due to a decrease in the active ions. Why is the MIE mechanism for low salinity flooding in sandstones only taking place at low salinity conditions? Multi-ion exchange could equally well take place at high salinities provided that the injected water contains a different relative concentration of the active cations compared to the initial FW. For the MIE mechanism in carbonates, the specific role of the individual ions (Ca2þ, Mg2þ, and SO42-) has been identified in detail. If, however, MIE is the mechanism for wettability modification of clay in the low salinity process, the specific chemical role of the actual ions has not been characterized to the same level. Release of adsorbed organic matter from the carbonate surface is impossible by just improving the solubility in the water phase by lowering the salinity. In that way, the wettability alteration in carbonates cannot be promoted by a salting-in effect. Due to the much weaker bonding of organic materials to the clay surface, the salting-in effect can contribute to wettability modification in a low salinity flood. Besides, a small increase in pH can have a great impact on the affinity of carboxylic materials toward the clay surface.
substituted with fresh low salinity water, keeping mass balance and salinity control. These experiments showed that more carboxylic acid remained adsorbed/precipitated when trying to desorb with high saline water. As the salinity decreased, less carboxylic acid remained adsorbed/precipitated. Unfortunately, this test cannot discriminate between adsorbed and precipitated carboxylic acid, because the pH was at times in an area that could possibly lead to precipitation of the acid. Anyhow, the test shows that the salinity of the water is important. Similarities/Differences between the Chemical Mechanisms in Carbonate and Sandstone A question to be asked is: “Is the improved oil recovery from carbonates and sandstone by smart water caused by a wettability modification toward a more water-wet system”? For carbonates, it is definitely documented that SW is able to improve the water wetness at high temperatures. For a long time, the effect of low salinity flooding of sandstones has been associated with improved water wetness of the present clay materials. If fines are released from the clay, this will increase the water wetness of the clay, but in addition it may improve the microscopic sweep efficiency by a diversion of flow due to trapping of fines in pore throats. In analogy to the suggested flooding mechanism of a linked polymeric solution, no wettability modification is needed to observe improved oil recovery by microscopic flow diversion. The most striking difference between the wetting properties in carbonates and sandstone is the adsorption strength of the organic materials attached to the rock. The carboxylic material adsorbs strongly onto the calcite surface, and it is very difficult to remove it by traditional solvent cleaning.32 It can be removed by increasing the surface reactivity of the potential determining ions Ca2þ, Mg2þ, and SO42- at high tempera-
Conclusion At the present stage, the chemical mechanisms behind enhanced oil recovery using smart water appear to be different in carbonates and sandstones. No obvious similarities have been noticed from published work so far. Acknowledgment. The authors acknowledge Talisman Energy Norge A.S. and TOTAL for financial support.
(32) Thomas, M. M.; Clouse, J. A.; Longo, J. M. Chem. Geol. 1993, 109, 201–213.
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