Journal of Petroleum Science and Engineering 120 (2014) 216–224
Contents lists available at ScienceDirect
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.
n
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: James.sheng@ttu.edu
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
218
J.J. Sheng / Journal of Petroleum Science and Engineering 120 (2014) 216–224
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).
J.J. Sheng / Journal of Petroleum Science and Engineering 120 (2014) 216–224
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
219
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
220
J.J. Sheng / Journal of Petroleum Science and Engineering 120 (2014) 216–224
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.
J.J. Sheng / Journal of Petroleum Science and Engineering 120 (2014) 216–224
221
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
222
J.J. Sheng / Journal of Petroleum Science and Engineering 120 (2014) 216–224
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
J.J. Sheng / Journal of Petroleum Science and Engineering 120 (2014) 216–224
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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