1. Introduction
An increase in oil recovery by using water with low-salinity components in sandstone reservoirs was first observed by Martin [
1]. Later on, subsequent studies have found that not only could low-salinity water flooding (LSWF) lead to an increase in oil recovery, but also, smart/modified water flooding (SWF) can contribute to higher oil recovery. Some researchers have used the terms low salinity and smart/modified water synonymously [
2]. On the one hand, low salinity defines the dilution of injected water (i.e., sea water) with fresh water in order to reduce the total dissolved solids (TDS) [
3,
4]; thus, ionic strength of the injected water is reduced, but hardness could be the same. On the other hand, smart/modified water deals with the manipulation of ionic strength (hardness) of the injected water [
5]. This manipulation aims to disturb the established rock-oil-brine ionic equilibrium, which could result in optimum oil recovery by improving the microscopic displacement efficiency. Hence, the hardness of the injected water is also manipulated with the ions’ concentration. Different mechanisms have been appointed as the ones favoring oil recovery due to SWF, but wettability alteration is believed to be the main driver [
6,
7,
8,
9]. Further recovery mechanisms can be mineral dissolution, fines migration, multicomponent ion change (MIE) [
10] and surface potential change.
Previous studies using carbonate and sandstone rock samples have confirmed that the presence of divalent cations (Ca
+2, Mg
+2) in the formation water and the spiked (increased) amount of
SO4−2 in the injected brine have resulted in an increase in oil recovery [
11,
12,
13,
14,
15]. The combination of divalent cations and spiked sulfate is expected to disturb the ionic equilibrium of the rock-brine-oil system in the reservoir. It has also been found that sulfate ions can displace the long-chain carboxylic acids (oil component) adsorbed on the rock surface and further reduce the adsorption of these acids on the rock surface [
16,
17].
For sandstone reservoirs, clay and quartz are negatively charged surfaces under the reservoir pH conditions and the negative polar compounds of the oil are attached to the rock-surface through divalent ions’ bridging (Ca
+2 and Mg
+2 present in formation brine) [
18]. The positive polar compounds of the oil are directly attached to negatively charged rock surfaces. This chemical bondage results in an oil wetting condition of the sandstone reservoir, as presented in
Figure 1A. It is therefore expected that the spiked amount of
SO4−2 in the injected brine will disturb the ionic equilibrium of the system, resulting in the replacement of the negative polar compound present in the oil with
SO4−2 through Ca
+2 and Mg
+2 bridging the rock surface. Thus, oil polar compounds are released and
SO4−2 are attached to the rock surface through ionic bridging, resulting in a water-wet state rock surface [
18], as shown in
Figure 1B. The described process will be catalyzed if low-saltwater flooding is performed. Low salt will further dilute the divalent cations in the formation brine and will cause the release of the negative polar compounds of the oil.
Spiked divalent ions normally used to design modified water are termed as the potential determining ions (PDI), which could contribute to additional oil recovery, according to Zhang et al. [
14]. The non-PDI are monovalent ions that have no significant influence to contribute additional oil recovery. Thus, monovalent ions should either be removed or require dilution to design smart/modified water. Among divalent PDI, sulfate is the most effective ion in both sandstone and carbonate reservoirs [
17] for modified water design. In spite of that, a too-high concentration of the sulfate can be problematic when more of the dissolved material than could be dissolved (supersaturation) by divalent cations (Ba
+2, Sr
+2 and Ca
+2) is present in the formation water. Due to the supersaturation and chemical reactions, precipitation of CaSO
4, BaSO
4 and SrSO
4 will occur (scaling problems). If the reservoir temperature is high enough, then this scaling issue can be even worse, as high temperature enhances the precipitation process [
19,
20]. This scaling process, in turn, will cause strong injectivity issues due to the generated formation damage and pore plugging around the wellbore [
21,
22,
23].
Those scaling and injectivity problems will challenge the efficiency of smart/modified water injection and will make any project un-economical. In 2016, Ghosh et al. [
21] studied ways to predict the formation of precipitation using a simulation technique and presented the scale control methods. Furthermore, modified water with the increased amount of sulfate in combination with other enhanced oil recovery (EOR) methods is expected to produce the additional oil recovery owing to the multi-recovery mechanism.
As one step further, the combination of polymer flooding with other EOR techniques has demonstrated positive effects on oil recovery [
24,
25,
26,
27,
28]. The performance of the polymer flood is dependent on the ionic composition of reservoir brine or make-up water [
29,
30,
31,
32]. The higher the ionic composition of brine, the higher the decrease in polymer viscosity, which in turn will negatively influence polymer viscoelasticity [
29,
33,
34,
35,
36].
In practice, a reservoir is pre-flushed with low-salinity water to reduce reservoir brine salinity [
37]. By that logic, polymer flooding, after the modified water flooding, is expected to recover additional oil. Pre-flush-modified water will alter the reservoir wettability and detach the long-chain acidic carboxylic group. Follow-up low-concentration polymer flood after modified water will recover this detached and trapped oil because of the improved mobility ratio [
38]. Similarly, diluted brine injection in combination with the polymer flood has shown an increase in recovery in sandstone core plugs [
25,
28,
38]. This is because of the combined process of both EOR techniques (wettability alteration by low saltwater and improved displacement efficiency by polymer flood). Additionally, modified water will require a smaller polymer concentration to design a favorable mobility ratio. Hence, a lesser amount of polymer will be required to achieve the desired viscoelastic properties [
39]. These polymer viscoelastic properties improve the displacement efficiency on a micro-scale during polymer flooding [
40,
41].
Additionally, over the past years, studies have investigated the role of interfacial rheology (dynamic interface response) in the brine-oil system [
42]. Improved dynamic stability forms a mechanically viscoelastic interfacial surface at the brine–oil interface and will support a snap-off of big oil droplets. Studies show that this viscoelastic film is formed when the naphthenic acids and asphaltene present in crude oil and divalent ions in the aqueous phase are accumulated at the interface [
43,
44], but this layer is sensitive to brine salinity and forms a more stable layer under low-salt brines. Experiments have been conducted in which sulfate was found to improve interfacial rheology between two phases and result in higher oil recovery [
41]. In other words, from a fluid–fluid interaction point of view, sulfate could improve this viscoelastic interface, resulting in oil phase snap-off suppression and an increase in the oil drop size [
44]. This fluid–fluid interaction is developed at the interface between the oil polar compounds and ions present in the brine.
This work focuses on investigating the impact of the sulfate ions for the design of modified water flooding in the sandstone reservoir rock. Low-concentration polymer flooding is adopted as the mobility controller after modified water to observe any additional oil recovery because of multi-recovery mechanisms. First, brine flooding was implemented for 1.5 pore volume (PV) and subsequently, polymer flooding was performed to define the synergies/benefits of the low-cost hybrid EOR technique.
Different injection schemes of low-salinity hybrid EOR methods have been proposed and the promising oil recovery results have been investigated [
45,
46,
47,
48,
49,
50,
51,
52,
53,
54,
55]. Some researchers proposed combining foam injection with low salinity, while others proposed surfactant and smart water flooding to achieve the optimum oil recovery results. Similarly, literature has presented the potential benefits of combining water containing low-salt compounds and polymer [
25,
50,
51,
52,
53,
54]. However, little attention has been given to how sulfate optimization can boost the benefits even higher, not only on the added value for polymer application but also for the oil recovery. Results obtained in this investigation concluded that spiked sulfate in low-salt brine acted as a PDI to catalyze the wettability alteration process. Equally, low-concentration polymer solutions in spiked sulfate brine improved the polymer viscoelastic properties in porous media, resulting in a higher pressure drop to contribute additional oil recovery. It is there where the novel information is found. We provide an important set of data that serve as additive information to the existing body of literature and that can be of great benefit for the state of knowledge in the petroleum industry, in the constant search for cost-efficient EOR processes.
5. Conclusions
Based on the obtained data and observations of the experimental conditions presented here, the proposed sulfate-modified low-salt water process produced important results that indicate its potential influence on wettability alteration. Moreover, the work presented here provides a detailed workflow to evaluate the combined application of modified water and polymer flooding. Researchers assessing similar processes can implement this workflow.
The evaluation of polymer performance provides important findings; in particular, polymer solutions prepared in the presence of sulfate in the brine had higher viscosity compared to other brines with the same TDS (g/L). According to the rheological evaluation, linear viscoelastic measurements cannot clearly differentiate the viscoelastic response between the polymer solutions due to the lower concentrations implemented in this work. Nevertheless, the increase in sulfate led to an enhancement of the polymer viscoelastic properties determined through the increase in injection pressure observed from the core flooding experiments. The evaluation also shows that increasing the amount of sulfate made the solution more sensitive to mechanical degradation when flowing through pipes and valves. Current industry applications seek to use low shear valves to minimize this impact.
For the two-phase flooding, core floods showed that low-salt or sulfate-modified water flooding should be performed before polymer flooding to achieve higher oil recovery. Otherwise, brine flooding after polymer flooding will follow the same path of pre-injected polymer without having contact with oil. Furthermore, sulfate-modified water flooding and DSSW injection produced almost the same recovery in the secondary-mode. However, in the tertiary-mode, polymer injection after sulfate-modified low-salinity water flooding produced 4% more oil compared to polymer flooding after DSSW. It is assumed that this additional oil is due to the higher pressure/viscoelastic response for polymer-SW. Finally, recovery experiments showed that SW and DSSW contributed to extra recovery compared to SSW in the secondary mode due to wettability alteration; however, the overall combination of SW and polymer resulted in the higher recovery. The findings obtained by the two-phase flooding experiments support that both brines (SW and DSSW) induce wettability alteration of the rock, pointing out that the wettability change for the case of sulfate-modified water strongly follows the presence of 2SO4−2 as a catalyst for the alteration to take place.