Critical review of low-salinity waterflooding

Journal of Petroleum Science and Engineering 120 (2014) 216–224

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Journal of Petroleum Science and Engineering journal homepage: www.elsevier.com/locate/petrol

Critical review of low-salinity waterflooding J.J. Sheng n Texas Tech University, Lubbock, TX 79409, USA

art ic l e i nf o

a b s t r a c t

Article history: Received 23 January 2014 Accepted 31 May 2014 Available online 12 June 2014

It was observed that higher oil recovery could be obtained when low-salinity (LS) water flooded a core of high-salinity initial water about 15 years ago. Such low-salinity waterflooding benefit or effect has drawn the oil industry attention since then. In the recent years, many researchers conducted laboratory corefloods, and several companies carried field tests. The objectives of these efforts were (1) to conform the benefits and (2) find the mechanisms of such benefit. Although most of the results confirmed the positive effect, some results showed no benefit. Many mechanisms have been proposed, but there is no consensus of the dominant mechanism(s). The oil industry is continuing the effort to discover the effect. This paper is to provide a critical review of the results and to summarize the achievements of the industry's effort. This paper aims to provide the status of the art. The information provided in this paper hopefully will help to speed up our further efforts to explore this effect. The following contents are reviewed: (1) history of low-salinity waterflooding; (2) laboratory observations; (3) field observations; (4) working conditions of low-salinity effect; (5) mechanisms of low-salinity waterflooding; and (6) simulation of low-salinity waterflooding. In this paper, the mechanisms proposed in the literature and their validity are discussed. & 2014 Elsevier B.V. All rights reserved.

Keywords: low-salinity waterflooding enhanced oil recovery improved oil recovery waterflooding salinity

Contents 1. 2. 3.

4. 5. 6.

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Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A brief history of low-salinity waterflooding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Laboratory observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1. Typical behavior of low-salinity waterflooding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2. Low-salinity benefits under reservoir conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3. Effect of connate water saturation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4. Effect of the salinity of connate water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5. Effect of injection water salinity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.6. Effect of wettability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Field observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Working conditions of low-salinity effects. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mechanisms of low-salinity waterflooding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1. Fine mobilization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.2. Limited release of mixed-wet particles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3. Increased pH and reduced IFT similar to alkaline flooding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4. Multicomponent ion exchange (MIE) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.5. Double layer effect. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.6. Salt-in effect. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.7. Osmotic pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.8. Wettability alteration. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Tel.: þ 1 806 834 8477. E-mail address: [email protected]

http://dx.doi.org/10.1016/j.petrol.2014.05.026 0920-4105/& 2014 Elsevier B.V. All rights reserved.

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7. Further discussion . . . . . . . . . . . . . . . . . . . 8. Simulation of low-salinity waterflooding . 9. Concluding remarks. . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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1. Introduction Injection of low-salinity (LS) water has widely been practiced because the water sources are available and relatively cheaper among other practical advantages. But the EOR potential was not recognized until Morrow and his co-workers (Jadhunandan, 1990; Jadhunandan and Morrow, 1991, 1995; Yildiz and Morrow, 1996; Tang, 1998; Tang and Morrow, 1997, 1999) observed from their experimental work that oil recovery depended on water composition. Since then, many coreflood tests have been published to address the low-salinity effect on waterflooding oil recovery. Most of the results (but not all) showed that higher oil recovery could be obtained when the salinity of injection water is much lower than that of the formation water. Meanwhile, different mechanisms have been proposed to explain this low-salinity effect. There is no consensus about dominant mechanisms. Apparently, people believe that low salinity waterflooding could provide higher oil recovery. Some doubt it because some experiments did not show the benefit. This paper is to summarize and analyze the published laboratory and field observations. The mechanisms proposed in the literature and their validity are discussed.

2. A brief history of low-salinity waterflooding When Morrow and his coworkers studied the wettability effect on waterflooding recovery, they found that changes in injection brine composition affected oil recovery (Jadhunandan, 1990; Jadhunandan and Morrow, 1991, 1995). Subsequently, Yildiz and Morrow (1996) confirmed that brine composition could indeed affect the waterflooding oil recovery, but they stated that whether more oil could be obtained depended on specific conditions of crude oil/brine/rock systems. Tang and Morrow (1997, 1999) advanced the research on the impact of brine salinity on oil recovery. It was followed by the active research by the oil company British Petroleum (BP) (Webb et al., 2004, 2005a, 2005b; McGuire et al., 2005). BP's work includes numerous core floods at ambient and reservoir conditions with live oils in both secondary and tertiary modes, single-well tracer tests, and log–inject–log tests. The company's work led to the registration of the LoSal™–EOR process trademark. Meanwhile, the researchers from several oil companies (e.g., TOTAL, Shell, Statoil) and universities worked on this topic as well. In recent years, many companies and universities have been actively doing the research. The number of published papers increased from 5 in 2007 to 25 in 2010 (Morrow and Buckley, 2011).

3. Laboratory observations Since Morrow's group presented additional oil recovery from low-salinity waterflooding, many experimental coreflood tests have been conducted. Apparently, most of coreflood tests show positive results. In some core floods, no incremental oil recovery was observed. In this section, we only present typical observations. More experimental data will be presented when the mechanisms are discussed later.

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3.1. Typical behavior of low-salinity waterflooding Typical behavior of low-salinity waterflooding may be summarized as follows. (1) As the injection brine salinity was reduced lower (often much lower) than the initial brine salinity in the core, more oil was produced. (2) During the stage the injection brine salinity was reduced, a higher-pressure drop was observed. This phenomenon was interpreted by Tang and Morrow (1999) as permeability reduction caused by fine migration. This phenomenon was also observed by Zhang et al. (2007). (3) When the water of reduced salinity was injected, maximum pH values were about 9 or lower. 3.2. Low-salinity benefits under reservoir conditions BP used a coreflood facility in which live oil could be used and the reservoir conditions could be simulated (Webb et al., 2005a). In a presented case of secondary waterflooding, the formation water salinity was 28,000 ppm and the injection water salinity was 1400 ppm. The recovery factor increased from 69.5% to 83.5% the original oil in place (OOIP). In another secondary flood, a higher incremental oil recovery was obtained. For two tertiary floods, 1500 ppm water injection followed 15,000 ppm secondary waterflooding. The oil recoveries increased from 63% to 71% and from 75% to 84% for these two tertiary floods. They concluded that to get a low-salinity benefit the salinity should be as low as 4000 ppm. 3.3. Effect of connate water saturation Tang and Morrow (1999) observed that when the initial water saturation was zero, the oil recovery from a high-salinity (HS) water injection was almost the same as that from a LS (1% of the HS) water injection. Zhang and Morrow (2006) observed that the oil recovery generally increased with initial water saturation for secondary recovery by injection of LS brine. In other words, to have the LS effect, the existence of connate water was needed. 3.4. Effect of the salinity of connate water Sharma and Filoco (1998) found that the salinity of connate water was the primary factor controlling the oil recovery. When the salinities of connate water were 0.3%, 3% and 20% NaCl while the injection water salinity was 3% NaCl, the oil recovery was greater for lower connate brine salinities. They attributed this dependence to alteration of the wettability to mixed-wet conditions from water-wet conditions during the drainage process. Mixed-wet cores showed lower residual oil saturations than strongly water-wet or oil-wet cores (Jadhunandan and Morrow, 1995). Such result that higher oil recovery was obtained with the lower salinity of connate water is also supported by McGuire et al. (2005) data and Zhang and Morrow's (2006) data. 3.5. Effect of injection water salinity When we talk about the low-salinity benefit, we mean that higher oil recovery will be obtained when the salinity of injection water is lower than that of existing or initial (connate) formation

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water. However, this result is not supported by all the published experimental data. Sharma and Filoco (1998) observed that the salinity of connate water was the primary factor controlling the oil recovery, and the salinity of injection brine did not affect oil recovery. As the salinity is increased, electrostatic repulsion decreases owing to screening of the surface charges (Adamson and Gast, 1997). Higher salinity should, therefore, result in less stable brine films. However, this was not observed in their experiments. Zhang and Morrow (2006) even presented data showing lower-injection water salinity resulted in a lower recovery than that from higher-salinity water, although more cases showed that lower-salinity injection water resulted in higher recovery. In Yildiz and Morrow's (1996) experiments, two brine and two oils were used. Brine 1 – 4% NaClþ0.5% CaCl2. Brine 2 – 2% CaCl2. The two oils were Moutray crude oil and Alaskan oil. When the Moutray oil was used and when the formation water and injection water had the same brines, the oil recovery factor for Brine 2 was 5.5% higher than that for Brine 1. However, when the Alaskan oil was used, an opposite result was obtained where the oil recovery factor for Brine 1 was 16% higher than that for Brine 2. When the Moutray oil was used, the formation water was Brine 2, and the core was flooded by Brine 2 first followed by Brine 1, only 0.5% more oil was obtained. When the formation water was Brine 1, and the core was flooded by Brine 1 first followed by Brine 2, 2.9% more oil was obtained. Such results are not consistent with the expectation from the LS effect, because Brine 1 had less ionic strength than Brine 2. Yildiz and Morrow attributed the above results to the wettability difference caused by crude oil and aging conditions. Nevertheless, in most of the published cases, a higher oil recovery was obtained when the salinity of injection water is lower than that of connate water. And the injection water salinity was low enough. Tang and Morrow (1999) used 10% connate water salinity. McGuire et al. (2005) did not see the effect when the salinity was higher than 7000 ppm in their single-well chemical tracer test (SWCTT) tests. Webb et al. (2005a) used 1000–4000 ppm which was less than 5% of formation total dissolved solids (TDS) (80,000 ppm). Zhang et al. (2007) observed that the low salinity of 1500 ppm which was about 5% formation water salinity resulted in sharp increase in the tertiary recovery and in the differential pressure. 8000 ppm was not sufficient even removing divalents. 4% additional recovery was obtained when additional divalent ions were added to the injection brine of 1500 ppm salinity. Jerauld et al. (2008) proposed 10–25% of connate water salinity or 1000– 2000 ppm based on practices in the laboratory and field. Probably, 10% of connate water salinity is a good start. 3.6. Effect of wettability Jadhunandan and Morrow (1995) found that the wettability related to initial water saturation in the cores. With higher initial water saturation, the cores showed more water-wet. And the oil recovery increased from strongly water-wet to a maximum close to neutral wet, which was agreed by Sharma and Filoco (1998). Their objective of that paper was not to correlate oil recovery with the water salinity. But their data showed that cores with lower calcium concentration (or ionic strength) were more water-wet. The LS effect may be related to wettability. For the cores with high initial salinity, LS water injection will make the cores more waterwet and result in a higher oil recovery. 4. Field observations BP has run four sets of SWCTT in Alaska North Slope and confirmed that the favorable laboratory results could be replicated

in the field after injection of LS water of 5–10% of formation water salinities. The reductions in residual oil saturations were 4%, 4%, 8%, and 9% in these four tests (McGuire et al., 2005). Another field test in a BP mature offshore oil field, Endicott field, located on the North Slope of Alaska demonstrated that reduced-salinity waterflooding worked at inter-well distances (1040 ft in this case). The reduced-salinity waterflooding reduced water cut from 95% to 92% (Seccombe et al., 2010). In a log–inject–log test, typically 0.1–0.15 pore volumes of highsalinity brine were injected first to obtain the baseline residual oil saturation. This was followed by sequences of more dilute brine followed by high-salinity brine. Multiple log passes were conducted during each brine injection. At least three further passes were run to ensure that a stable saturation value had been established after injection of each type of brine. The results showed 0.25–0.5 reduction in residual oil saturation when waterflooding with low-salinity brine (Webb et al., 2004). In a Middle Eastern sandstone reservoir, the formation wettability is mixed-wet to oil-wet. The formation water salinity was 100,000 ppm. The salinity of injection water was changed to 1000 ppm in March 2000. An oil bank arrived at the production end in 2003 with a temporary drop in water cut (Ligthelm et al., 2009). Robertson (2007) compared three waterflooding field performances in Wyoming. These analog fields had been under LS waterflooding with the salinity ratios of injection water to formation water of 0.0621, 0.0787, and 0.1667. The oil recoveries at 0.3 Pore Volume (PV) of produced fluid are almost linearly correlated with the salinity ratios. With a lower salinity ratio, a higher oil recovery was obtained. Preflush using LS water before surfactant–polymer flooding was carried to condition the reservoir in the early days. Such preflush water should bring incremental oil if low-salinity waterflooding worked. However, apparently, no oil rate increase was observed during the fresh water preflush in the North Burbank Unit surfactant–polymer pilot in Osage County, Oklahoma (Trantham et al., 1978) and Loudon surfactant pilot (Pursley et al., 1973). No injectivity issue was reported. Thyne and Gamage, 2010 evaluated the LS waterflooding effects in the fields in the Powder River Basin of Wyoming. They found no increase in recovery for the 26 fields where low salinity water was injected, when they compared with the 25 fields where mixed water or formation water was injected. Among these 51 fields, the salinity of injected water was significantly reduced in 38 fields, whereas there was little reduction in salinity in the rest of 13 fields. There was no correlation observed between the salinity reduction and oil recovery factor. Skrettingland et al. (2011) evaluated LS waterflooding for the Snorre field. The core flooding results showed that Statfjord cores had an incremental oil recovery of 2% of OOIP by injection of diluted seawater, while the Lunde cores did not show response. A SWCTT did not show reduction in residual oil saturation. Their explanation was that the reservoirs were already in optimum wetting conditions so that a significant improvement in oil recovery could not be obtained by LS waterflooding.

5. Working conditions of low-salinity effects Based on the corefloods and research work published so far, the working conditions of the LS waterflooding effect may be summarized as follows. (1) Presence of clays. It is believed that clays are important in the LS effect. It may be necessary to have kaolinite. Kaolinites and illites are non-swelling clays that tend to detach from the rock surface and migrate when the colloidal conditions are conducive for release (Mohan et al., 1993).

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However, the types and amount of clays are not clearly defined in the literature. Different authors reported the importance of different types of clays (Skrettingland et al., 2011). (2) Presence of polar oil (Tang and Morrow, 1999; Suijkerbuijk et al., 2012). (3) Presence of initial or connate water (Sharma and Filoco, 1998; Tang and Morrow, 1999; Zhang and Morrow, 2006). (4) Presence of divalents in the initial water (Lager et al., 2006). (5) Salinity shock – the salinity of injected water must be significantly lower than the preceding water salinity (Mohan et al., 1993; Webb et al., 2005a; Zhang et al., 2007; Buckley and Morrow, 2010). This effect will be reduced in field scale because of salinity buffering. Note that the above conditions cannot guarantee the LS effect, as some cases did not show the effect, even though the conditions were apparently met. And all of these conditions may not be necessary, as some cases had the low-salinity effect, but all the conditions were not met, as discussed later in this paper.

6. Mechanisms of low-salinity waterflooding Seventeen mechanisms of low-salinity waterflooding have been proposed in the literature, as follows: (1) fine migration (Tang and Morrow, 1999); (2) mineral dissolution (Buckley and Morrow, 2010); (3) limited release of mixed-wet particles (Buckley and Morrow, 2010); (4) increased pH effect and reduced interfacial tension (IFT) (McGuire et al., 2005); (5) emulsification/snap-off (McGuire et al., 2005); (6) saponification (McGuire et al., 2005); (7) surfactant-like behavior (McGuire et al., 2005); (8) multicomponent ion exchange (MIE) (Lager et al., 2006); (9) double layer effect (Ligthelm et al., 2009); (10) particle-stabilized interfaces/ lamella (Buckley and Morrow, 2010; Morrow and Buckley, 2011); (11) salt-in effects (RezaeiDoust et al., 2009); (12) osmotic pressure (Buckley and Morrow, 2010); (13) salinity shock (Buckley and Morrow, 2010); (14) wettability alteration (more water-wet) (Buckley and Morrow, 2010); (15) wettability alteration (less water-wet) (Buckley and Morrow, 2010); (16) viscosity ratio (Buckley and Morrow, 2010); and (17) end effects (Buckley and Morrow, 2010). Most of these mechanisms are related to each other. For example, to have fine mobilization, fines must be available in the injection fluid. The available fines could be mineral dissolution or released particles. Thus the limited release of mixed-wet particles and mineral dissolution are related to fine migration. As a result of mineral dissolution, the viscosity of LS solution has a higher viscosity. Saponification, surfactant-like behavior, and emulsification/snap off are related to increased pH effect and reduced IFT. Osmotic pressure and salinity shock are directly related to salinity contrasts between the initial water and displacing water. The end effect occurs in laboratory scale. In this section, we will discuss major mechanisms and their working conditions. 6.1. Fine mobilization In principle, clay tends to hydrate and swell when contacting with fresh water. In other words, insufficient salts in water cannot prevent clay hydration and swelling. Fine migration occurs if the ionic strength of injected brine is less than a critical flocculation concentration. The critical flocculation concentration is strongly dependent on the relative concentration of divalent cations. Divalent cations lower the repulsive force by lowering the Zeta potential. Therefore, they have been known to stabilize clay. A less-saline solution destabilizes clay and silt in the formation. The clay and silt, upon dispersion, flow with water. Water preferentially flows along high permeability channels or zones. The clay and silt dispersing in water become lodged in the smaller pores or pore throats. Then the formation permeability is reduced, and the

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water is forced to take other flow paths. As a result, the sweep efficiency is improved. Poorly cemented clay particles, such as kaolinite and illite, can become detached during aqueous flow, especially when flowing brines become fresher (Boston et al., 1969). Martin (1959) and Bernard (1967) observed that clay swelling and/or dispersion accompanied by increased differential pressure, and incremental oil recovery resulted. Kia et al. (1987) reported that when sandstones were previously exposed to sodium salt solutions, flooding these sandstones by fresh water resulted in the release of clay particles and a drastic reduction in permeability. The permeability reduction was lessened, however, when calcium ions were also present in the salt solution. Formation damage was virtually eliminated when the solution composition was adjusted to give calcium surface coverage greater than a critical value of 75%, or when a solution Ca2 þ fraction is greater than 20–30%. Tang and Morrow (1999) concluded that fine mobilization (mainly kaolinite) increased recovery based on their observations: (1) a fired/acidized Berea core did not show the sensitivity of salinity on oil recovery, whereas an unfired Berea core did; (2) for clean sandstones, the increase in oil recovery with the decrease in salinity was less than that for the clay sands. Khilar and Fogler (1984) results showed a 30% reduction in permeability when the pretreatment was carried out with cesium-salt solutions, a reduction of more than 95% with a sodium-salt pretreatment, and virtually no reduction when the cation in the solution was divalent. However, Lager et al. (2006) reported that no fine migration or significant permeability reductions was observed during numerous BP LS corefloods under reduced conditions and full reservoir conditions, although these corefloods had all shown increased oil recovery. Zhang and Morrow (2006) reported that limited production of clay particles was observed, but permeability damage, if any, was minimal. Zhang et al. (2007) reported that no clays were produced at the effluent stream. Valdya and Fogler (1992) reported that a gradual reduction in salinity kept the concentration of fines in the flowing suspension low, with formation damage minimized or totally avoided. Boussour et al. (2009) reported no LS effect but with sand production in their experiments. Many coreflood experiments showed an increase in the differential pressure in the beginning but decrease later during LS water injection (Tang and Morrow, 1999; Zhang and Morrow, 2006; Zhang et al., 2007). The increases in the differential pressure in the beginning of LS waterflooding are shown in Table 1. In many cases, the differential pressures were doubled. Brine/rock interaction may result in the increase in differential pressure. However, the small or no response in flooding mineral oils implies that clay swelling and clay migration is of second order. Polar oil must participate in this blockage of pores. Complex crude oil/brine/rock interaction must come into play. In other words, the LS effect is not caused by simple mechanical fine migration. Then what is it? If we believe that low-salinity can result in more water-wet, then the differential should decrease rather increase. In addition to fine migration, osmotic effect, decrease in ion binding (Lager et al. 2006), oil viscosity, interfacial viscosity, transient emulsion formation, interfacial tension gradient resulting from gradients in brine composition, might also play a role in oil mobilization (Zhang et al., 2007). The formation of interfaces, especially in the form of clay-stabilized lamella, will enhance the possibilities to develop capillary structures that cause the large resistance to brine flow. 6.2. Limited release of mixed-wet particles Tang and Morrow (1999) explained this mechanism. Crude oil initially coats fines which attach to pore walls. When the salinity is

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Table 1 Differential pressure (Δp) and pH in low-salinity corefloods. Test # pH Before pH After Δp Before Δp After Sources psi psi A1 A2 A3 A4 A5 B1 B2 B3 B4 T1F1 T1F2 T1F3 1 2 1 2 3 4 1 2

6.2 8 5.6 6 6 8 7 5.6 6 8 8 8 5 6.5

5.2 8 8

6.2 8 6.3 6.2 6.3 7 5.8 6.1 7.6 9 9 9 6 9.5

6 9 10

4 2.8 1 1.9 1.8 2.6 2 0.56 2.7 1.8 2 2.5

9 4.9 4.8 2.5 4.2 4.5 3.8 4.8 9.7 2.4 2.6 3.7

2 2 2 0.5

2 5.8 15 4.5

Zhang et al. (2007) Zhang et al. (2007) Zhang et al. (2007) Zhang et al. (2007) Zhang et al. (2007) Zhang et al. (2007) Zhang et al. (2007) Zhang et al. (2007) Zhang et al. (2007) Tang and Morrow (1999) Tang and Morrow (1999) Tang and Morrow (1999) Lager et al. (2006) Lager et al. (2006) Zhang and Morrow (2006) Zhang and Morrow (2006) Zhang and Morrow (2006) Zhang and Morrow (2006) McGuire et al. (2005) McGuire et al. (2005)

reduced, the electrical double layer in the aqueous phase between particles is expanded and the tendency to strip fines is increased. The stripped fines migrate and aggregate so that the oil coalesces. Thus limited removal of mixed-wet fines from pore walls results in locally heterogeneous wetting conditions so that oil recovery is improved. This mechanism combines the DLVO theory and fine migration. The DLVO theory is named after Derjaguin, Landau, Verwey, and Overbeek. 6.3. Increased pH and reduced IFT similar to alkaline flooding Emulsification/snap-off, saponification, and surfactant-like behavior are all related to increased pH and reduced IFT mechanisms. They are discussed in this section collectively. McGuire et al. (2005) proposed that low-salinity mechanisms could be due to increased pH and reduced IFT similar to alkaline flooding. This increase in pH is due to exchange of hydrogen ions in water with adsorbed sodium ions (Mohan et al., 1993). Another related mechanism is that a small change in bulk pH can impose a great change in the zeta potential of the rock. When pH is increased, organic materials will be desorbed from the clay surfaces (Austad, 2013). In Kia et al.'s (1987) experiments, the sandstone was saturated with sodium chloride and/or calcium chloride solutions and flooded by fresh water. The pH of the solutions entering the sandstone was about 6.5 for all experiments. The pH of the effluent, however, was found to be about 7.5 during the CaCl2 salt flow, 8.6 during NaCl salt, and 8.3 with fresh water flow. The increase in pH is a result of the solubilization of trace amounts of dissolvable minerals, such as calcite. Valdya and Fogler (1992) studies showed that dispersion of clays was minimized at low pH. Ion exchange between the adsorbed Naþ and Hþ in solution in LS water injection resulted in an increased OH  concentration in bulk solution (i.e. pH increase). The pH increase amplified the release of fines and led to a drastic reduction in permeability. They reported little change in permeability when fluids with increasing pH were injected until an injection pH of 9 was reached. At a pH 411, a rapid and drastic decrease in the permeability was observed. However, in a typical low-salinity flooding, pH was lower than 9, as shown in Table 1. Table 1 lists the pH values before and after

LS water injection in the literature. In most of the cases, pH was lower than 7. In some cases, pH was unchanged. To explain why such a low pH works, Austad et al. (2010) proposed a hypothesis that cation exchange resulted in local pH increase close to clay surfaces. Zhang et al. (2007) reported that after LS brine injection, a slight rise and drop in pH were observed. But no clear relationship between effluent pH and recovery was observed. Under high pH conditions, organic acids (saponifiable components) in crude oil react to produce in situ surfactant (soap) that can lower oil/water interfacial tension. The generated soap helps forming oil/water or water/oil emulsions due to lower IFT. This emulsification may improve water sweep efficiency. However, in a typical alkaline solution, pH is usually 11–13. To be able to generate soap, pH needs to be greater than 9 (Sheng, 2011). Another fact is that the oil/water interfacial tension in LS waterflooding is not too low. Zhang and Morrow (2006) reported IFT of 16 dyn/cm. Buckley and Fan (2007) measured IFT values were above 10 mN/m with pH o9. Such IFT is not low enough to reduce residual oil saturation in tertiary LS waterflooding. It has been observed from many field projects that the level of improved oil recovery from alkaline flooding is low. Based on analysis of the data reported by Mayer et al. (1983), the incremental oil recovery factor over waterflooding was 1–2% in most of the projects, and 5–6% in a few projects. If the low-salinity mechanism is related to increased pH and reduced IFT similar to alkaline flooding, the improved oil recovery factor should be even lower than that from alkaline flooding. Because the pH from actual tests was lower than what is required to achieve saponification or emulsification and fine migration, the pH mechanism similar to alkaline flooding may not work in LS waterflooding. The pH value at the effluent end could increase or decrease depending on other chemical reactions, as explained by Austad (2013). Therefore, the pH value cannot be used to confirm the low-salinity waterflooding. 6.4. Multicomponent ion exchange (MIE) Owing to the different affinities of ions on rock surfaces, the result of multicomponent ion exchange (MIE) is to have multivalents or divalents such as Ca2 þ and Mg2 þ strongly adsorbed on rock surfaces until the rock is fully saturated. Multivalent cations at clay surfaces are bonded to polar compounds present in the oil phase (resin and asphaltene) forming organo-metallic complexes and promoting oil-wetness on rock surfaces. Meanwhile, some organic polar compounds are adsorbed directly to the mineral surface, displacing the most labile cations present at the clay surface and enhancing the oil-wetness of the clay surface. During the injection of LS brine, MIE will take place, removing organic polar compounds and organo-metallic complexes from the surface and replacing them with uncomplexed cations. Lager et al. (2006) reported that their experimental results matched the prediction from this hypothesis. First, the North Slope core sample was prepared to the representative initial water saturation and aged in the dead crude oil. The initial screening experiments were conducted at 25 1C. A conventional high-salinity (HS) waterflood gave a recovery of 42% OOIP, and a tertiary LS flood resulted in a total recovery of 48% OOIP (i.e., an additional 6% OOIP). A second suite of experiments was conducted at the reservoir temperature (102 1C). A conventional HS waterflood resulted in a recovery of 35% OOIP. The core was flushed with the brine containing only HS NaCl until Ca2 þ and Mg2 þ was effectively eluted from the pore surface. The initial water saturation was re-established, and the sample was aged in the crude oil. A HS waterflood consisting of NaCl (no Ca2 þ and Mg2 þ ) resulted in a recovery of 48% OOIP. A tertiary LS flood was then conducted (again no Ca2 þ and Mg2 þ ), and no additional recovery observed.

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Both Ca2 þ and Mg2 þ were strongly adsorbed until the rock matrix was fully saturated. When the salinity of injection water is different from that of initial water, a new equilibrium must be reached. The equilibrium must be governed by the law of mass action. Whether cations adsorbed or desorbed is not only determined by the injected brine composition, but also by the adsorbed concentrations. 6.5. Double layer effect

Fig. 1. Diagram showing the relationship among pH, salinity and wettability (Drummond and Israelachvili, 2002).

This sequence indicated that HS connate brine containing Ca2 þ and Mg2 þ resulted in the low recovery factors (42% and 35%). Removing Ca2 þ and Mg2 þ from the rock surface before waterflooding led to a higher recovery factor (48%) irrespective of salinity. They noted that no improvement in oil recovery was observed, when LS water was injected into a clastic reservoir where the mineral structure was preserved. Apparently, their proposed MIE explains why LS waterflooding did not work when a core was acidized and fired. The reason is that the cation exchange capacity of the clay minerals was destroyed. This explains why LS water injection has little effect on mineral oil, as reported by Tang and Morrow (1999) and Zhang et al. (2007), because no polar compounds are present to strongly interact with the clay minerals. Another supporting result is that adding divalent (Ca2 þ ) in LS brine did not result in additional oil in Tang and Morrow's corefloods. The proposed mechanism of multicomponent exchange (MIE) is also supported by the pore-scale model proposed by Sorbie and Collins (2010). However, Zhang et al. (2007) reported that additional recovery was obtained when switched from 8000 ppm brine to 1500 ppm brine even with divalent ions added. Yildiz and Morrow's (1996) data showed the highest oil recovery when the initial formation brine contained 2% CaCl2 flooded by the brine with 4% NaClþ 0.5% CaCl2 and then by 2% CaCl2. The MIE mechanism cannot explain the Sharma and Filoco (1998) experiments either where more oil was recovered in lower initial salinity cases while the injected water composition was the same. Here is a further discussion about cation (ion) exchange. During the isotherm and cation exchange capacity (CEC) measurements, Meyers and Salter (1984) observed that the steady-state effluent concentrations of calcium and magnesium were observed to be slightly greater than the injected concentrations. These excess concentrations increased as the injection concentrations decreased. When NaCl brine was injected into the cores, “residual” calcium and magnesium concentrations were still observed in the effluent. However, Valocchi et al. (1981) injected fresh water in a brackish water aquifer and noticed that the concentration of Ca2 þ and Mg2 þ in different control wells were lower than the invading water and the connate brine. Lager et al. (2006) reported similar results. In their coreflood, the injected brine had Mg2 þ concentration (55 ppm) similar to the connate water, but the chlorite concentration was lower. The effluent concentration showed a sharp decrease in Mg2 þ in the beginning. This indicated that Mg2 þ was strongly adsorbed by the rock matrix. Heriot Watt University performed two different floods on the same system.

The double layer theory or the DLVO theory describes the force between charged surfaces interacting through a liquid medium. It combines the effects of the van der Waals attraction and the electrostatic repulsion due to the so-called double layer of counter ions. Low salinity brine reduces clay–clay attraction by expansion of the electric double-layer. Limited release of clay particles may depend on subtle oil/brine/rock interactions that involve the charge distributions of individual kaolinite platelets. Cryo scanning electron microscopy (Cryo-SEM), environmental scanning electron microscope (ESEM) and X-ray photoelectron spectroscopy (XPS) studies showed attachment of crude oil to kaolinite (Zhang and Morrow, 2006). LS water makes water film more stable owing to this expanded double layer effect, resulting in more water-wet on clay surfaces and more oil is detached. On the opposite site, the adsorption of divalents at the oil/water and water/sand interfaces changes the water-wet to oil-wet (Liu et al., 2007). Kia et al. (1987) have reported that in the presence of Na þ , the surface of kaolinite carries a negative charge, and the electrical charge present on the edge surface is a strong function of the solution pH. Most of the reported values show that edges of kaolinite particles are negatively charged when pH is higher than 6–8. For some brine compositions, both oil/brine and brine/solid interfaces have the same charge (Buckley et al., 1998). Thus, there is electrostatic repulsion between these interfaces. When LS brine is injected, the repulsion is increased. When HS brine is injected, due to screening of the surface charges (Adamson and Gast, 1997), the repulsion is decreased. For the exactly same mechanism that the electrostatic repulsion is increased when LS brine is injected, the water film between the oil/brine and brine/particle will be more stable. The rock surfaces change from oilwet to more water-wet or mixed-wet. Mixed-wet cores show lower residual oil saturations than strongly water-wet or oil-wet cores. The oil recovery is higher. This mechanism is supported by the experiments reported by Ligthelm et al. (2009). However, Sharma and Filoco (1998) observed that water film was more stable at high salinities in their experiments, inconsistent with the DLVO theory or the above observations. 6.6. Salt-in effect 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 (RezaeiDoust et al., 2009). Therefore, a decrease in salinity below a critical ionic strength can increase the solubility of organic material in the aqueous phase, so that oil recovery is improved. This mechanism is similar to the wettability alteration from oil-wet to more water-wet. The increase of organic solubility in the water phase is equivalent to desorption of oil drops from the clay surfaces. However, this mechanism cannot explain the dependence of mineral composition, pH, salinity shock, etc. 6.7. Osmotic pressure Sandengen and Arntzen (2013) demonstrated using experiments that oil droplets acted as semi-permeable membranes; oil

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droplets could move under an osmotic pressure gradient. They proposed that such osmotic gradient relocates oil by expanding an otherwise inaccessible aqueous phase in a porous rock medium. They hypothesized that LS water could relocate oil and open new water pathways (a microscopic diversion mechanism) in a field case. This is due to water being transported away from the main flow paths and into a less conductive network by diffusion through oil. They believed that a system on the oil-wet side, with high oil saturation, high temperature and a wide pore size distribution should represent the ideal case for osmosis to have an effect. This mechanism cannot explain the need of existence of crude (polar) oil and clays. 6.8. Wettability alteration As mentioned earlier, brine films are more stable at a lower salinity. This suggests that LS water will cause cores to become mixed-wet (less water-wet). Mixed-wet cores show lower residual oil saturations or higher oil recoveries than strongly water-wet or oil-wet cores (Morrow, 1990; Morrow et al., 1998). Buckley et al. (1998) explained wettability alteration as a result of the interaction between crude oil and reservoir rock. Berg et al. (2010) experimentally showed that wettability alteration could be achieved by LS water. Nasralla et al. (2011) showed that LS water could decrease contact angles. Yousef et al. (2011) and Zekri et al. (2011) reported that LS water injection could change wettability to more water-wet in carbonates. Vledder et al. (2010) even provided a proof of wettability alteration in a field scale. Drummond and Israelachvili (2002) showed that the wettability was altered from oil-wet to water-wet at pH 49 and from water-wet to intermediate-wet at pH o 9, as shown in Fig. 1. In other words, wettability alteration is possible in all the pH ranges (either higher or lower than 9). In LS waterflooding, pH is most likely below 9 (see Table 1). The possibility is that the wettability is changed from water-wet to intermediate-wet or mixed-wet. This can also explain why connate water is needed for the LS effect because the existence of connate water makes water-wettability possible. The wettability alteration is the most frequently suggested mechanism (Morrow and Buckley, 2011). Many other mechanisms can be related to this mechanism. Wettability alteration could be the end result of other mechanisms. This is likely an explanation of the LS effect on oil recovery.

in seawater flooding has been almost exclusively done by Austad and his co-workers, which is summarized in Austad, 2013.

8. Simulation of low-salinity waterflooding Several authors tried to simulate LS waterflooding. Their general approach is to modify relative permeability and capillary pressure curves as a function of salinity. For example, Jerauld et al. (2008) modeled low-salinity waterflooding using an empirical approach. The residual oil saturation is interpolated by salinity between a low salinity and a high salinity. Relative permeability curves and capillary pressure curves for LS and HS are input. The actual relative permeability and capillary pressure values at a specific saturation are the weighted averages of their HS and LS values. The weighing factor, w, is based on w¼

Sorw  SLS orw LS SHS orw  Sorw

ð1Þ

where Sorw are input values as a function of salinity, the superscript HS and LS donate high salinity and low salinity. In Mahani et al's. (2011) model, wettability changes suddenly from oil-wet to water-wet in a specific simulation block when the volume fraction of the LS water is above a defined volume fraction threshold value, f, which is called the mixing factor defined as f¼

TDSHS  TDSThreshold TDSHS  TDSLS

ð2Þ

where TDS is the salinity, the subscript Threshold is the salinity at which the LS effect starts to work. Wu and Bai (2009) included the salt as a separate composition and modeled the relative permeability changes with salt concentration. Omekeh et al. (2012) considered the effect of dissolution/ precipitation of various carbonate minerals and multiple ion exchange (MIE). The total release of divalent cations from the rock surface gives rise to a change of the relative permeability such that more oil is mobilized. The combined effect of MIE and dissolution/ precipitation is modeled to determine how pH and the total release of divalent cations are affected. They used a black-oil modeling approach but included Na þ , Ca2 þ , Mg2 þ , SO24  and Cl  ions in water phase. Dang et al. (2013) used a compositional simulator to include geochemical processes like intra-aqueous and mineral reactions.

7. Further discussion

9. Concluding remarks

From the above discussions, we can see that there is no consensus about the primary mechanisms. For each mechanism, counter examples of data can always be found. This is the challenge to define LS waterflooding mechanisms. Another puzzle is that the incremental oil recovery is relatively high compared with other chemical flooding processes, such as surfactant flooding. Is the low-salinity waterflooding so powerful? In Daqing chemical EOR floods, fresh water (o 1000 ppm) was injected into reservoirs of about 7000 ppm. The average incremental oil recovery from Chinese polymer flooding project is about 9% according to our survey (not published). Then how much incremental recovery is due to the freshwater flooding? If the real mechanisms of LS waterflooding can be identified, the result should definitely help to design chemical flooding. Another interesting observation is that some of the listed mechanisms do not actually require the salinity change from high to low. This review focuses on the LS waterflooding in sandstone reservoirs. Strictly speaking, it is not the LS effect in carbonate reservoirs; it is the effect of sea water flooding. The research work

From the above discussion, we can see that there is no consensus regarding which mechanism works in the low-salinity waterflooding. Most likely, several mechanisms work under a specific condition. And different mechanisms work in different conditions. Among the proposed mechanisms, probably most plausible mechanism is wettability alteration. This mechanism can be used to explain more cases, because wettability can be changed from oil-wet to water-wet, or from water-wet to intermediate or mixed wet. In either way, oil recovery factor could be improved. Many mechanisms could result in wettability alteration. In other words, wettability alteration may not be a cause, rather it is an effect. From the reported results both in laboratory and in field, lowsalinity has a positive effect or benefit to oil recovery. However, the magnitude of incremental oil recovery should not be expected as high as observed in laboratory, because many pore volumes of LS water were injected in laboratory, which is not realistic in actual field waterflooding projects. Another fact is that generally LS water is used in chemical flooding. Consider the magnitude of

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incremental oil recovery from chemical flooding projects, the incremental oil recovery from low-salinity effect only should not be too high. Because the low-salinity effect deems to be positive, and more importantly, low-salinity waterflooding is environmentally friendly and does not require much more investment in facility, efforts to improve understanding the low-salinity effect will continue.

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