Low Salinity Waterflooding Research Papers (original) (raw)

Many experimental investigations on carbonated water injection (CWI) have shown an increase in oil recovery which CWI is defined as the process of injecting CO 2-saturated water in oil reservoirs as a displacing fluid. In every enhanced oil recovery method, the potential formation damage of the injected fluid is considered. This is due to the fact that the injection of incompatible fluids often causes clay swelling and fines migration and thus impairs the formation permeability. Permeability reduction by clay particles mostly depends on its distribution which can be pore lining, pore bridging, dispersed or combination of these causing pore blocking or pore-throat diameter reduction. Besides, fine migration is considered as an important mechanism of recovery improvement during injection of low-salinity water in sandstone oil reservoirs. The present paper investigates the impact of injection of carbonated water and brines with the different salt concentrations on oil recovery and formation damage focusing on permeability variation. The investigation has been done on 12 relatively homogeneous clay-containing sandstone cores, while the compositions of the injection water were varied from 40,000 to 1000 ppm, at 176° F and 2000 psi. The amount of recovery improvement and permeability drop recorded in all tests and the fine effluent of two experiments were analysed using XRD, one for CWI and one for WF (water flooding). In all salinities, CWI has shown more oil recovery improvement than conventional water. CWI of 40,000 ppm showed the minimum permeability reduction of 6 percent, while the highest permeability was obtained by injection of water with 1000 ppm. Maximum ultimate oil recoveries of 61.2% and 42% were achieved by 1000 ppm both for CWI and WF, respectively. In comparison with brine injection, CWI resulted in more permeability drop in salinity above critical salt concentration (CSC), while below CSC, WF has caused more formation damage than CWI. Experimental results also showed that fine migration was the main reason behind formation damage. It was also revealed that permeability was significantly reduced due to fine production in the effluent.

- by and +1
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- Oil and gas, Enhanced Oil Recovery, CO2 emissions, Low Salinity Waterflooding

The use of smart water has become the main priority for most oil companies due to significant benefits shown in various studies. The considerable potential of this method in increasing oil recovery along with the economic considerations has caused the study of smart water injection as an EOR method to have significant development. Smart water injection due to advantages such as low cost, availability, the possibility of use in different conditions (deep reservoirs and high-temperature reservoirs), the possibility of combining with other EOR methods (carbonate smart water, surfactant flooding, WAG, alkaline flooding, etc.), and good recovery potential has all the characteristics of an optimal EOR method. In this review, important and effective parameters and operating mechanisms for smart water injection in sandstone and carbonate reservoirs are briefly described.

- by Behnam ranjbar and +2
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- Enhanced Oil Recovery, Wettability Alteration, Low Salinity Waterflooding, chemical EOR

- by Hassan Mahani
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- Petrophysics of the carbonates, Carbonates, Porous Media, Wettability Alteration

Natural gas may consider the most popular energy source in recent era and the demand for it in recent years has been dramatic. However, natural gas is existed in deep reservoirs so it may contents many impurities for instance, hydrogen sulphide, carbon dioxide and mercury. Indeed, these impurities may cause several technical problems for instance, corrosion and environment pollution. Therefore, raw natural gas should be purify before processing it to global gas markets and amine gas sweetening process may consider the most common technology to remove acid gases from natural gas stream. Thus, this study aims to treat a given composition natural gas stream with a moderate hydrogen sulphide contents about 2500ppm vie engineering mathematical calculations for MEA circulation rate that was about 490 gpm. The amine circulation rate is considered quite important amine gas sweetening parameters that should be at optimum value to achieve optimum acid gas removal and meet the product requirement. Thus, the amine circulation rate examined by material balance calculations for amine contactor tower. As a result, it is found that 490 gpm amine circulation rate is an effective value to reduce hydrogen sulphide contents to 4ppm which it meets the gas pipelines and gas sell contracts specification.

- by Jagar A . Ali
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- Wellbore Stability, Low Salinity Waterflooding

This paper discusses the application of low hardness alkali water compositions (LHAW) as a
secondary and tertiary displacement agent for EOR. A comparative analysis of the impact of low
salinity water (LSW) and LHAW water on interfacial tension, contact angle on rock, adsorption
of ions, emulsion stability and clay swelling is presented. LHAW application contributes to the
formation of stable water in oil (w/o) emulsions and a decrease in clay swelling compared to
LSW. Adsorption values for both fluids are similar. Contact angle measurements show that both
LSW and LHAW reduce interfacial tension compared to Synthetic Caspian Sea water (SCSW),
by up to 17% and 94% respectively. Similar results were observed for contact angle
measurements. Flooding experiments were conducted in secondary and tertiary modes. In
secondary flooding the two water compositions LHAW-2 and LHAW-1 increased the oil
recovery (%OOIP) in comparison with SCSW at water breakthrough, by 29% and 25%
respectively . The final oil recovery increases were 21% and 15% respectively. In tertiary
flooding, tests showed that LHAW-2 and LHAW-1 oil recoveries (%OOIP) compared to LSW
were 13 % and 10% respectively. The oil recovery rate for LHAW solutions was not linear
versus lnt as was that for LSW. This was proposed as a consequence of emulsions generation
while water-cut is below 50% however, above 50% water cut the rate stabilizes.

In recent years, it has been observed that the injection of low salinity water in sandstone reservoirs causes an incremental recovery in original oil in place (OOIP). Various theories were proposed to explain the improvement in oil recovery, however there is no consensus on what is considered the principal mechanism behind the low salinity effect. It is a fact that the recovery is due to the chemical composition of injected water and mineralogical characteristics of formation. The interaction of these systems is still being debated in the literature. This study is based on theoretical and experimental analyzes showing the main hypotheses proposed over the recent years, the possible processing plants for treatment of offshore low salinity waterflooding, and some cases of success or failure of the tests in oil fields around the world.

- by Fabiane Quitério
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- Petroleum, Reservoir, Low Salinity Waterflooding
- by Hassan Mahani
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- Wettability, Wettability Alteration, Low Salinity Waterflooding, Sandstones

In recent years, research activity on the recovery technique known as low salinity waterflooding has sharply increased. The main motivation for field application of low salinity waterflooding is the improvement of oil recovery by acceleration of production (’oil faster’) compared to conventional high salinity brine injection. Up to now, most research has focused on the core scale by conducting coreflooding and spontaneous imbibition experiments. These tests serve as the main proof that low salinity waterflooding can lead to additional oil recovery. Usually, it is argued that if the flooding experiments show a positive shift in relative permeability curves, field application is justified – provided the economic considerations are also favorable. In addition, together with field pilots, these tests resulted in several suggested trends and underlying mechanisms related to low salinity water injections that potentially explain the additional recovery. While for field application one can rely on the core scale laboratory tests which can provide the brine composition dependent saturation functions such as relative permeability, they are costly, time consuming and challenging. It is desirable to develop predictive capability such that new candidates can be screened effectively or prioritized. This has not been yet achieved and would require under-pinning the underlying mechanism(s) of the low salinity response. Recently, research has intensified on smaller length scales i.e. the sub-pore scale. This coincides with a shift in thinking. In field and core scale tests the main goal was to correlate bulk properties of rock and fluids to the amount of oil recovered. Yet in the tests on the sub-pore scale the focus is on ruling out irrelevant mechanisms and understanding the physics of the processes leading to a response to low salinity water. Ultimately this should lead to predictive capability that allows to pre-select potential field candidates based on easily obtained properties, without the need of running time and cost intensive tests. However, low salinity waterflooding is a cooperative process in which multiple mechanisms acting on different length and time scales aid the detachment, coalescence, transport, banking, and eventual recovery of oil. This means investigating only one particular length scale is insufficient. If the physics behind individual mechanisms and their interplay does not transmit through the length scales, or does not explain the observed fast and slow phenomena, no additional oil may be recovered at core or field scale. Therefore, the mechanisms are not discussed in detail in this review, but placed in a framework on a higher level of abstraction which is ’consistency across the scales’. In doing so, the likelihood and contribution of an individual mechanism to the additional recovery of oil can be assessed. This framework shows that the main uncertainty lies in how results from sub-pore scale experiments connect to core scale results, which happens on the length scale in between: the pore-network scale. On the pore-network scale two different types low salinity responses can be found: responses of the liquid-liquid or the solid-liquid interfaces. The categorization is supported by the time scale differences of the (optimal) response between liquid-liquid and solid-liquid interfaces. Differences in time scale are also observed between flow regimes in water-wet and mixed-wet systems. These findings point to the direction of what physics should be carried from sub-pore to core scale, which may aid in gaining predictive capability and screening tool development. Alternatively, a more holistic approach of the problems in low salinity waterflooding is suggested.

Low-salinity waterflooding (LSF) is one of the least-understood enhanced-oil-recovery (EOR)/improved-oil-recovery (IOR) methods, and proper understanding of the mechanism(s) leading to oil recovery in this process is needed. However, the intrinsic complexity of the process makes fundamental understanding of the underlying mechanism(s) and the interpretation of laboratory experiments difficult. Therefore, we use a model system for sandstone rock of reduced complexity that consists of clay minerals
(Na-montmorillonite) deposited on a glass substrate and covered with crude-oil droplets and in which different effects can be separated to increase our fundamental understanding. We focus particularly on the kinetics of oil detachment when exposed to lowsalinity (LS) brine.
The system is equilibrated first under high-salinity (HS) brine and then exposed to brines of varying (lower) salinity while the shape of the oil droplets is continuously monitored at high resolution, allowing for a detailed analysis of the contact angle and the
contact area as a function of time. It is observed that the contact angle and contact area of oil with the substrate reach a stable equilibrium at HS brine and show a clear response to the LS brine toward less-oil-wetting conditions and ultimately detachment from the clay substrate. This behavior is characterized by the motion of the three-phase (oil/water/solid) contact line that is initially pinned by clay particles at HS conditions, and pinning decreases upon exposure to LS brine. This leads to a decrease in contact area and contact angle that indicates wettability alteration toward a more-waterwet state.When the contact angle reaches a critical value at approximately 40 to 50�, oil starts to detach from the clay. During detachment, most of the oil is released, but in some cases a small amount of oil residue is left behind on the clay substrate.
Our results for different salinity levels indicate that the kinetics of this wettability change correlates with a simple buoyancy- over adhesion-force balance and has a time constant of hours to days (i.e., it takes longer than commonly assumed).
The unexpectedly long time constant, longer than expected by diffusion alone, is compatible with an electrokinetic ion-transport model (Nernst-Planck equation) in the thin water film between oil and clay. Alternatively, one could explain the observations only by
more-specific [non- Derjaguin–Landau–Verwey–Overbeek (DLVO) type] interactions between oil and clay such as cation-bridging, direct chemical bonds, or acid/base effects that tend to pin the contact line.
The findings provide new insights into the (sub) pore-scale mechanism of LSF, and one can use them as the basis for upscaling to, for example, pore-network scale and higher scales (e.g., core scale) to assess the impact of the slow kinetics on the time scale of an LSF response on macroscopic scales.

In biodiesel production, downstream purification is an important step in the overall process. This article is a critical review of the most recent research findings pertaining to biodiesel refining technologies. Both conventional refining technologies and the most recent biodiesel membrane refining technology are reviewed. The results obtained through membrane purification showed some promise in term of biodiesel yield and quality. Also, membranes presented low water consumption and less wastewater discharges. Therefore, exploration and exploitation of membrane technology to purify crude biodiesel is necessary. Furthermore, the success of membrane technology in the purification of crude biodiesel could serve as a boost to both researchers and industries in an effort to achieve high purity and quality biodiesel fuel capable of replacing non-renewable fossil fuel, for wide range of applications.

- by Abdul Aziz
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- Engineering, Information Technology, Economics, Process Optimization

This report evaluates the effectiveness of low-salinity waterflooding in the Minnelusa Formation in the Powder River Basin of Wyoming. The Minnelusa sandstone play constitutes a resource of over one-hundred fields with cumulative production of more than 600,000,000 barrels of oil. We conducted initial laboratory screening using Minnelusa oil and rock with synthetic brine, supplemented with geochemical models of low-salinity injection, to evaluate the potential for low-salinity waterflooding in this formation. The laboratory experiments showed little or no incremental recovery from low-salinity injection. Calculation and comparison of recovery factors for 51 Minnelusa reservoirs were used to further evaluate the effectiveness of low-salinity waterfloods at the field scale. There was no increase in recovery for fields that used low salinity injection (26) compared to fields with mixed or formation water injection (25). Since some Minnelusa fields have relatively fresh formation water, the amount of dilution was quantified using the salinity ratio (SR), defined as the ratio of salinity of injected water to salinity of formation water. This analysis showed that while some fields actually had little or any salinity reduction (13), the remaining fields with significant dilution (38) still showed no correlation between dilution and recovery factor. Since some postulated mechanisms involve change in wettability, injection of low-salinity water may produce later water breakthrough. Analysis of water breakthrough timing and watercut evolution for 23 fields found no significant difference between fields with low-salinity injection and mixed-water or saline injection.

- by Geoffrey Thyne
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- Low Salinity Waterflooding

Low salinity waterflood (LSF) is a promising improved oil recovery (IOR) technology. Although, it has been demonstrated that LSF is an efficient IOR method for many sandstone reservoirs, the potential of LSF in carbonate reservoirs is still not well-established as only a limited number of successful coreflood experiments are available in the literature. Therefore, the aim of this study was to examine the oil recovery improvement by LSF in carbonate reservoirs by performing coreflood experiments.
This paper proposes an experimental approach to qualitatively evaluate the potential of LSF to improve oil recovery and alter the rock wettability during coreflood experiments. The corefloods were conducted on core plugs from two Middle Eastern carbonate reservoirs with a wide variation of rock properties and reservoir conditions. Seawater and several dilutions of formation brine and seawater were flooded in the tertiary mode to evaluate their impacts on oil recovery compared to formation brine injection. In addition, a geochemical study was performed using PHREEQC software to assess the potential of calcite dissolution by LSF.
The experimental results confirmed that lowering the water salinity can alter the rock wettability towards more water-wet, causing improvement of oil recovery in tertiary waterflood in plugs from the two reservoirs. Furthermore, seawater is more favorable for improved oil recovery than formation brine as injection of seawater after formation brine resulted in extra oil production. This demonstrates that the brine composition plays an important role during waterflooding in carbonate reservoirs, and not only the brine salinity. It was also observed that oil recovery can be improved by injection of brines that cannot dissolve calcite based on the geochemical modeling study. This implies that calcite dissolution is not the dominant mechanism of IOR by LSF.
To conclude, this paper demonstrates that low-salinity waterflood has a good potential as an IOR technology in carbonate reservoirs. In addition, the proposed experimental approach ensures the verification of LSF effect, either it is positive or negative. However, further research is required to explore the optimum salinity and composition and the most influential parameters affecting LSF response.

Low salinity waterflooding (LSF) is receiving increased interest as a promising method to improve oil recovery efficiency. Most of the literature agrees that on the Darcy scale, LSF can be regarded as a wettability modification process leading to a more water-wet state, although no general consensus on the microscopic mechanisms has been reached. While wettability alteration may be a valid causal mechanism also on the pore scale, it is currently unclear how oil that detaches from mineral surfaces within individual pores connects to an oil bank or finds its way to a producer. In order to establish a link between the pore scale and the Darcy scale description, the flow dynamic at the scale of (networks of) multiple pores should be investigated. One of the main challenges in addressing phenomena on this intermediate "pore network" scale is to design a model system representative for natural rock. The model system should allow for a systematic investigation of influencing parameters with pore-scale resolution whilst simultaneously being large enough to capture larger length scale effects like saturation changes and the mobilization and connection of oil ganglia.

- by Hassan Mahani
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- Visualization, Microfluidics, Clay Minerals, Wettability Alteration

In the last few years it has become widely accepted in the industry that Low Salinity Flooding (LSF) works by changing reservoir wettability towards a more water-wet state. Most of the published experimental data to quantify the LSF effect focus on comparing ultimate recovery of low salinity (LS) and high salinity (HS) waterflooding experiments either in secondary and/or tertiary mode. A wide range in incremental oil recovery is reported in the literature, from 0 to more than 20% of OIIP. To assess the potential of LSF and to enable upscaling of the LSF benefit to reservoir scale, the relative permeability curves for HS and LS brine should be determined. In only a few published cases, the experimental data was interpreted using numerical simulations to derive relative permeability curves for both low and high salinity water.

Many studies indicate the recovery of crude oil by waterflooding can be improved by lowering the salinity of injected water. This so-called low-salinity effect is often associated with the change of the wetting state of
rock towards more water-wet. However, it is not very well understood how wettability alteration at the pore level could lead to an increase in production at the Darcy scale.
Therefore, this study aims at direct observation of the wettability-change-driven fluid reconfiguration related to a lower-salinity (LS) flood at the pore-network scale, using synchrotron beamline-based fast X-ray computed tomography.
Cylindrical outcrop rock samples were initialized by first saturating them with high-salinity (HS) brine, then displacing the HS brine with crude oil down to residual water saturation. After this initialization the rock samples were aged to establish wettability states assumed to be close to mixed-wet conditions. During the flooding experiments, the pore-scale fluid distribution was imaged at a voxel resolution of 3 μm and (under flowing conditions) a time resolution of 10 s for a full 3D image. The micro-CT flow experiments were conducted on both sandstone and carbonate rocks, all in tertiary mode and at identical field relevant flow rates. The real-time imaging shows the presence of an oil/water structure in addition to the oil and water phases and a saturation change during the HS waterflood which approaches a stable equilibrium at its
end. During flow of both HS and LS brine we observe (re-)connection and disconnection of the oil phase which are characteristics of ganglion dynamics. In addition, we observe relatively slow pore-filling events that we believe to be characteristic of the mixed-wet state of the sample. Preliminary analysis indicates that upon lowering of injection brine salinity individual pores change occupancy, however further research is required to draw definitive conclusions.

- by Hassan Mahani
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- Wettability, Micro-CT, Wettability Alteration, Low Salinity Waterflooding

Laboratory studies have shown that wettability of carbonate rock can be altered to a less oil-wetting state by manipulation of brine composition and somewhat reduction of salinity. Our recent study (see Mahani et al. 2015b) suggests that surface-charge-alteration is likely to be the driving mechanism of the low salinity effect in carbonates. Various studies have already established the sensitivity of carbonate surface charge to brine salinity, pH and potential-determining ions in brines. However, in the majority of the studies single salt brines or model carbonate rocks have been used and it is fairly unclear i) how natural rock reacts to reservoir-relevant brine as well as successive brine dilution, ii) whether different types of carbonate reservoir rocks exhibit different electrokinetic properties and iii) how the surface charge behavior obtained at different brines salinities and pH can be explained.
This paper presents a comparative study aimed at gaining more insights into the electrokinetics of different types of carbonate rock. This is achieved by zeta-potential measurements on Iceland spar calcite and three reservoir-related rocks – middle-eastern limestone, Stevns Klint chalk and Silurian dolomite outcrop – over a wide range of salinity, brine composition and pH. With a view to arriving at a more tractable approach, a surface complexation model implemented in PHREEQC (PH REdox EQuilibrium in C language) software is developed to relate our understanding of the surface reactions to measured zeta-potentials.
It was found that regardless of the rock type, the trends of zeta-potentials with salinity and pH are quite similar. For all cases, the surface-charge was found to be positive in high-salinity formation water, which should favour oil-wetting. The zeta-potential successively decreased towards negative values when the brine salinity was lowered to seawater level and diluted seawater. At all salinities, the zeta-potential showed a strong dependence on pH, with positive slope with pH which remained so even with excessive dilution. The sensitivity of the zeta-potential to pH-change was often higher at lower salinities.
The existing surface complexation models cannot predict the observed increase of zeta-potential with pH; therefore a new model is proposed to capture this feature. According to modelling results, formation of surface species, particularly >CaSO4- and to a lower extent >CO3Ca+ and >CO3Mg+, strongly influence the total surface charge. Increasing the pH turns the negatively charged moiety >CaSO4- into both negatively charged >CaCO3- and neutral >CaOHº entities. This substitution reduces the negative charge of the surface. The surface concentration of >CO3Ca+ and >CO3Mg+ moieties changes little with change of pH.
Nevertheless, besides similarities in zeta-potential trends, there exist notable differences in terms of magnitude and isoelectric point (IEP) even between carbonates that are mainly composed of calcite. Amongst all the samples, chalk particles exhibited the most negative surface charges, followed by limestone. In contrast to this, dolomite particles showed the most positive zeta-potential, followed by calcite crystal. Overall, chalk particles exhibited the highest surface reactivity to pH and salinity change, while dolomite particles showed the lowest.

- by Hassan Mahani
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- Carbonates, Electrokinetics, Wettability Alteration, Low Salinity Waterflooding

The low salinity effect (LSE) in carbonate rock has been less explored compared to sandstone rock. Laboratory experiments have shown that brine composition and (somewhat reduced) salinity can have a positive impact on oil recovery in carbonates. However, the mechanism leading to improved oil recovery in carbonate rock is not well understood. Several studies showed that a positive LSF effect might be associated with dissolution of rock, however, due to equilibration, dissolution may not contribute at reservoir scale which would make LSF for carbonate rock less attractive for field applications. This raises now the question whether calcite dissolution is the primary mechanism of the LSF effect. In this paper we aim to first demonstrate the positive response of carbonate rock to low salinity and then to gain insight into the underlying mechanism(s) specific to carbonate rock. We followed a similar methodology as in sandstone rock (see Mahani et al. 2015) by using a model system comprised of carbonate surfaces obtained from crushed carbonate rocks. Wettability alteration upon exposure to low salinity brine was examined by continuous monitoring of the contact angle. Furthermore, the effective surface charge at oil-water and water-rock interfaces was quantified via zeta-potential measurements. Mineral dissolution was addressed both experimentally and with geochemical modeling using PHREEQC. Two carbonate rocks with different mineralogy were investigated: Limestone and Silurian dolomite. Four types of brines were used: High salinity formation water (FW), Seawater (SW), 25×diluted SW (25dSW) and 25×diluted SW equilibrated with calcite (25dSWEQ). It was observed that by switching from FW to SW, 25dSW and 25dSWEQ, the limestone surface became less oil-wet. The results with SW and 25dSWEQ suggest that the low salinity effect occurs even in the absence of mineral dissolution, because no dissolution is expected in SW and none in 25dSWEQ. The wettability alteration to less oil-wetting state by low salinity is consistent with the zeta-potential data of limestone indicating that at lower salinities the charges at the limestone-brine interface become more negative indicative of a weaker electrostatic adhesion between the oil-brine and rock-brine interfaces, thus recession of three-phase contact line. In comparison to limestone, a smaller contact-angle-reduction was observed with dolomite. This is again consistent with the zeta-potential of dolomite showing generally more positive charges at higher salinities and less decrease at lower salinities. This implies that oil detachment from dolomite surface requires a larger reduction of adhesion forces at the contact line than limestone. Our study concludes that surface-charge-change is likely to be the primary mechanism which means that there is a positive low salinity effect in carbonates without mineral dissolution.

- by Hassan Mahani
- •
- Clay Minerals, Carbonates, Dolomites, DLVO theory

The reduction of interfacial tension (IFT) due to its effects on the recovery of residual oil has made it a very important element in the enhanced oil recovery (EOR) process. Surfactants or biosurfactants can reduce IFT and improve recovery by decreasing IFT. The structure of asphaltene in crude oil makes it capable of acting as a surface-active material. On the other hand, the formation of biosurfactants, which reduce IFT, is one of the major mechanisms for microbial enhanced oil recovery. In the present study, with the aim of investigating the interaction of asphaltene and Geobacillus stearothermophilus bacteria, the percentages of 0, 1, 5, and 6.4% of asphaltene in oil with bacteria were investigated in the presence of NaCl, MgCl2, and CaCl2 salts at salinities of 0, 1000ppm and 5000ppm. The results showed that the presence of Geobacillus stearothermophilus bacteria due to the formation of biosurfactant will be able to reduce IFT both in the presence of salt and in the absence of salt. Results show that asphaltene along with Geobacillus stearothermophilus bacteria has a complex interaction at the two-phase interface, resulting in a dual behavior in IFT with the increase in asphaltene content. The results showed that increasing the percentage of asphaltene to one percent will cause the biosurfactant to move away from the aqueous phase/oil interface, resulting in increased IFT. Further increase of asphaltene percentage from 1 has shown that the interaction of asphaltene and bacteria to produce intrinsic surfactant and biosurfactant in both the presence of salt and in the absence of salt to reduce IFT. The behavior of bacteria and asphaltene in the presence of different salts at different salinities has shown that the formation of biosurfactants arising from bacteria and intrinsic surfactants arising from asphaltene will be determined by how salt interacts with bacteria and asphaltene.

- by Behnam ranjbar and +1
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- Low Salinity Waterflooding, Geobacillus, Low salinity water flooding (LSW)

Several laboratory studies and some field trials have already demonstrated the potential of lowering the injected brine salinity and/or manipulating composition to improve oil recovery in carbonate reservoirs. Laboratory SCAL tests such as coreflooding and imbibition are key steps to screen low salinity waterflood (LSF) for a particular field to (i) ensure that there is LSF response in the studied rock/oil/brine system, (ii) find the optimal brine salinity, (iii) extract relative permeability curves to be used in the reservoir simulation model and quantify the benefit of LSF and (iv) examine the compatibility of injected brine with formation brine and rock to derisk any potential scaling or formation damage caused by fines mobilization.

- by Hassan Mahani
- •
- Enhanced Oil Recovery, Carbonates, Wettability, Low Salinity Waterflooding

Low-salinity waterflooding (LSF) is receiving increased interest as a promising method to improve oil-recovery efficiency. Most of the literature agrees that, on the Darcy scale, LSF can be regarded as a wettability-modification process, leading to a morewater-wet state, although no consensus on the microscopic mechanisms has been reached. To establish a link between the pore-scale and the Darcy-scale description, the flow dynamic at an intermediate scale-i.e., networks of multiple pores-should be investigated. One of the main challenges in addressing phenomena on this scale is to design a model system representative of natural rock. The model system should allow for a systematic investigation of influencing parameters with pore-scale resolution while simultaneously being large enough to capture larger-lengthscale effects such as saturation changes and the mobilization and connection of oil ganglia.

- by Hassan Mahani
- •
- Microfluidics, Electrokinetics in Microfluidics, Clay Minerals, Wettability

Laboratory studies have shown that wettability of carbonate rock can be altered to a less oil-wetting state by manipulation of brine composition and reduction of salinity. Our recent study (see suggests that a surface-charge change is likely to be the driving mechanism of the low salinity effect in carbonates. Various studies have already established the sensitivity of carbonate surface charge to brine salinity, pH and potential-determining ions in brines. However, it has been less investigated i) whether different types of carbonate reservoir rocks exhibit different electrokinetic properties, ii) how the rocks react to reservoir-relevant brine as well as successive brine dilution and iii) how the surface charge behavior at different salinities and pH can be explained.

- by Hassan Mahani
- •
- Enhanced Oil Recovery, Carbonates, Electrokinetics, Wettability Alteration

Several studies conducted mainly on the laboratory scale indicate that in carbonate rocks oil displacement can be influenced by the ionic composition of the brine, providing an opportunity to improve recovery by optimizing the brine mixture used in secondary or tertiary recovery. In industry this topic has been termed "low salinity flooding (LSF) in carbonates" while the underlying mechanisms are not very well understood. The increased oil recovery has been attributed to wettability alteration to a more water-wet state. However, in some studies a positive low salinity effect (LSE) has been ascribed to dissolution of rock, which occurs on the laboratory scale but due to equilibration of brine with carbonate minerals on larger length scales this is not relevant for the reservoir scale. Therefore, the objective of this paper is to gain a better understanding of the underlying mechanism(s) and investigate whether calcite dissolution is the primary mechanism of the LSE.

- by Hassan Mahani
- •
- Electrostatics, Wettability Alteration, Low Salinity Waterflooding, Carbonate Rock

Several laboratory tests have already demonstrated the potential of lowering/manipulating the injected brine salinity and composition to improve oil recovery in carbonate reservoirs. However, laboratory SCAL tests are still required to screen low salinity waterflood (LSF) for a particular field to (i) ensure that there is LSF response in the studied rock/oil/brine system, (ii) find the optimal brine salinity, (iii) extract relative permeability curves to be used in the reservoir simulation model and quantify the benefit of LSF and (iv) examine the compatibility of injected brine with formation brine and rock to de-risk any potential formation damage or scaling. This paper presents an extensive LSF SCAL study for one of the carbonate reservoirs and the numerical interpretation of the tests. The experiments were performed at reservoir conditions using representative reservoir core plugs, crude oil and synthetic brines. The rock was characterized using different measurements and techniques such as porosity, permeability, semi-quantitative X-ray diffraction (XRD), scanning electron microscopy (SEM), and mercury intrusion capillary pressure (MICP). The characterization work showed that the plugs can be classified into two groups (uni-modal and bi-modal) based on porosity/permeability correlation and pore throat size distribution. The SCAL experiments were divided in two categories. Firstly, spontaneous imbibition and qualitative unsteady-state (USS) experiments were performed to demonstrate the effect of low salinity brines. In addition, these experiments helped to screen different brines (seawater and different dilutions of seawater) in order to choose the optimal brine composition that showed the most promising effect. Secondly, quantitative unsteady-state (USS) experiments were conducted and modeled using numerical simulation to extract relative permeability curves for high salinity and low salinity brines by history-matching production and pressure data. Moreover, the pressure drop was monitored during all tests to evaluate any risk of formation damage. The main conclusions of the study: 1-The spontaneous imbibition and qualitative USS experiments showed extra oil production due to wettability alteration when switching from formation brine to seawater or diluted seawater subsequently, 2-Oil recovery by LSF can be maximized by injection of brine at a certain salinity threshold, at which lowering the brines salinity further may not lead to additional recovery improvement, 3-The LSF effect and optimal brine salinity varied in different layers of the reservoir, 4-The quantitative USS showed that LSF can improve the oil recovery factor by up to 7% at core scale compared to formation brine injection.
This paper proves the potential of LSF to improve oil recovery in carbonate rock. However, the results demonstrate that the effect of LSF may vary in different layers within the same carbonate reservoir, which indicates that LSF effect is very dependent on the rock properties/mineralogy.

- by Hassan Mahani
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- Carbonates, Wettability, Low Salinity Waterflooding, SPECIAL CORE ANALYSIS

Oil recovery by low salinity waterflooding in secondary and tertiary modes was investigated in the present study. Cores from Berea outcrop sandstone and Minnelusa reservoir sandstone were used in the single phase and two phase experiments. Two types of Minnelusa crude oils were used in the two phase experiments. The single phase experiments provided the baseline for pH and pressure changes in the two phase experiments.
Set of experiments were performed by using low salinity brine for the tertiary waterflood recovery method where oil saturated cores were first flooded with high salinity brine to simulate the secondary recovery method. In the second set of experiments, oil saturated cores were directly flooded with the low salinity brine. Conductivity and pH analysis of effluent brines were performed in all the single phase and two phase experiments.
Increase in oil recovery with low salinity brine as the invading brine was observed in both secondary and tertiary modes (2-8% OOIP) with Berea sandstone. However, higher oil recoveries (5-8% OOIP) were observed when low salinity waterflooding was implemented as a secondary recovery method. Minnelusa reservoir cores had little to no response to low salinity brine when it was used as a tertiary recovery method. However, Minnelusa cores showed an increase in oil recovery (10-22 % OOIP) with both types of crude oils when it was used as a secondary recovery method. An increase in pH of the effluent brine was observed during the low salinity brine injection in both Minnelusa and Berea cores. However, magnitude of the pH increase was smaller with the Minnelusa cores compared to Berea cores.
The level of investigation into the mechanism of low salinity incremental production has sharply increased in the past two years. Most of the studies focus on core floods using the tertiary mode. Our work contributes systematic coupled secondary and tertiary mode experiments that offer an expanded dataset for all researchers to use in investigation of the mechanisms.

- by Geoffrey Thyne
- •
- Enhanced Oil Recovery, Low Salinity Waterflooding

The efficiency of low salinity waterflooding, particularly during tertiary mode injection, is highly controlled by in situ mixing between the stagnant regions holding high salinity water (HSW) and the flowing regions containing low salinity water (LSW) because it impacts directly the electrokinetics of wettability alteration and the time scale of the low salinity effect. This study aims to address the effects of oil polarity and charged rock surfaces on the time scale of mixing and transport under two-phase flow conditions. A systematic series of micromodel experiments were performed. The micromodels were first saturated with high salinity formation brine and oil (both model and crude oil); thereafter, HSW and LSW were injected sequentially and the mixing time was carefully monitored. Besides, the polarity of model oils was manipulated by adding oleic acid as the representative for the acidic functional groups of crude oil. In addition to the experimental work, conceptual computational fluid dynamics (CFD) simulations were performed to get further insights into the experimental observations and to identify the dominant parameters on the time scale of mixing in stagnant regions. The experimental results show that the time scale of ionic transport in stagnant regions can be slowed down 10−16 times by the increase of the polar fractions of oil, where the time scale cannot be simply described by the Fickian diffusion. It is postulated that the stronger electrical field established in the water film by the increase of oil polarity lowers the solute transport rate according to the Poisson−Nernst−Planck theory. The results were further verified by using crude oil which is highly polar and contains complex types of polar components such as resins/asphaltenes. Experimental results clearly indicated the electrokinetics effect as the time scale was increased even further. Nevertheless, the mixing time does not vary linearly with the polar group fraction and follows a rather logarithmic trend. The CFD simulation confirms that the effective diffusion coefficient (which is influenced by the oil polarity and the induced electric field) is the predominant parameter determining the time scale of mixing. Other parameters such as film thickness/film length and salinity gradient have comparatively a lesser effect on the time scale of mixing in the stagnant regions.

One of the key open questions in the area of low or controlled salinity water flooding (LSWF or CSWF) is how the observed oil recovery at macro-scale (e.g. Darcy or core-scale) can the explained and what underlying microscopic mechanisms drive it. Thus far, the micromodel investigation of LSWF has been limited to sandstones, remaining challenging to apply to carbonates. In this paper we aim to i) extend the capability to fabricate a novel calcite micromodel using Iceland spar calcite crystal, ii) investigate the pore-scale mechanisms leading to oil recovery from carbonates. A target crude oil-brine-rock (COBR) system was first selected. To screen potential brines which can produce low-salinity-effect (LSE) and to guide the design of the micromodel experiments, contact angle measurements were carried out using two methods: i) contact angle under fixed, and ii) under dynamic salinity condition. The micromodel displacement experiments were then performed by flooding an oil saturated model with high salinity water followed by low salinity water injection to displace the high salinity water and observe any potential changes to the configuration and saturation of the residual oil. Additionally, the effect of connate water presence on the efficiency of LSE was investigated. To account for the time effects of the low salinity process, the experiments were monitored for an extended time period in order of several days to a month. For the COBR system studied in the micromodel, the results clearly show that when brine salinity is lowered the microscopic sweep efficiency is improved; providing a direct in-situ evidence for wettability alteration to a more water-wetting state. The presence of connate water enhanced the efficiency of LSWF both in terms of speed (time-scale) and quantity of oil recovery. It is postulated that in the presence of connate water an initial water-film around the calcite surface is present which facilitates the diffusive transport of brine ions when low salinity is injected. Thus it is favorable to have an initial water film present; a case for mixed-wettability. We observed that the oil production was non-instantaneous characterized by a prolonged induction time and a slow "layer-by-layer" recovery either from the pore body or throat wall; a process we refer to as "peel-off". Before the oil can be removed from the calcite surface, de-wetting (or de-pinning) patterns were formed which grew and coalesced toward formation of a clearly visible larger pattern. Ultimately, the remaining oil under low salinity was comparatively much less compared to the end of high salinity step. The observed mechanism of the oil recovery and the slow associated time have direct implications for the pore-scale simulation of the process and upscaling to Darcy-scale, and the design of laboratory experiments to avoid false negative results. They would also likely imply lack of a clear oil-bank observation at core scale.

- by Hassan Mahani
- •
- Microfluidics, Carbonates, Wettability, Wettability Alteration

Low salinity waterflooding has proven to accelerate oil production at core and field scales. Wettability alteration from a more oil-wetting to a more water-wetting condition has been established as one of the most notable effects of low salinity waterflooding. To induce the wettability alteration, low salinity water should be transported to come in contact with the oil-water interfaces. transport under two-phase flow conditions can be highly influenced by fluids topology that creates connected pathways as well as dead-end regions. It is known that under two-phase flow conditions, the pore space filled by a fluid can be split into flowing (connected pathways) and stagnant (deadend) regions due to fluids topology. Transport in flowing regions is advection controlled and transport in stagnant regions is predominantly diffusion controlled. To understand the full picture of wettability alteration of a rock by injection of low salinity water, it is important to know i) how the injected low salinity water displaces and mixes with the high salinity water, ii) how continuous wettability alteration impacts the redistribution of two immiscible fluids and (ii) role of hydrodynamic transport and mixing between the low salinity water and the formation brine (high salinity water) in wettability alteration. To address these two issues, computational fluid dynamic simulations of coupled dynamic two-phase flow, hydrodynamic transport and wettability alteration in a 2D domain were carried out using the volume of fluid method. The numerical simulations show that when low salinity water was injected, the formation brine (high salinity water) was swept out from the flowing regions by advection. However, the formation brine residing in stagnant regions was diffused very slowly to the low salinity water. The presence of formation brine in stagnant regions created heterogeneous wettability conditions at the pore scale, which led to remarkable two-phase flow dynamics and internal redistribution of oil, which is referred to as the "pull-push" behaviour and has not been addressed before in the literature. our simulation results imply that the presence of stagnant regions in the tertiary oil recovery impedes the potential of wettability alteration for additional oil recovery. Hence, it would be favorable to inject low salinity water from the beginning of waterflooding to avoid stagnant saturation. We also observed that oil ganglia size was reduced under tertiary mode of low salinity waterflooding compared to the high salinity waterflooding. Pore-Scale Mechanisms of Low Salinity Waterflooding. Low salinity waterflooding is a relatively new enhanced oil recovery (EOR) technology in which the ionic strength and composition of injection water are designed to achieve an additional oil recovery. Low salinity waterflooding has been a point of discussion since 1967 1. The potential of this technology was first demonstrated by Tang and Morrow 2 through experiments, where up to 15% additional oil was produced from the core with substantial reduction of salinity of the injecting water 2. In sandstone reservoirs, the injection water should have a much lower salinity compared to the formation brine, while in carbonate reservoirs that cannot be necessarily the case due to the fundamental differences in geochemis-try and rock-fluid interactions. Several factors such as rock heterogeneity, mineralogy of rock, brine composition and crude oil chemistry control performance of low salinity waterflooding 3-5. The general consensus in literature 1 University of Manchester, School of chemical engineering and Analytical science, Sackville St, Manchester, M139PL, United Kingdom. 2 Manchester Metropolitan University, centre for Mathematical Modelling and flow Analysis,

This paper presents an analytical solution of a non-self-similar, two-phase, multi-component problem of polymer slug injection with varying water salinity (ionic strength) in oil reservoirs. The non-Newtonian properties of polymers are incorporated into the fractional flow, yielding the velocity dependency of the fractional-flow function. Using the Lagrangian coordinate instead of time allows splitting the initial system (n þ 1 Â n þ1) into a n Â n system for concentrations and one scalar hyperbolic equation for phase saturation, which allows for full integration of the non-self-similar problem of wave interactions. The solution includes implicit formulae for saturation, polymer, and salt concentrations and front trajectories of the components. The solution allows determining the slug size of the low-salinity water that prevents the contact between the polymer and the high-salinity water.

- by Rouhi Farajzadeh and +2
- •
- Enhanced Oil Recovery, Low Salinity Waterflooding, Improved Oil Recovery

Single phase and two phase laboratory core flooding experiments were performed on Berea sandstone with Minnelusa crude oil over different temperatures ranging from 25 to 90ºC. The single phase experiments provide the baseline for the two phase experiments. Two phase experiments were conducted in both secondary and tertiary modes. Increase in oil recovery was observed with the low salinity waterflooding (2-8% OOIP) for the Berea sandstone core plugs in all tertiary cases. Temperature is an important factor during preparation to create a system that produces incremental production in response to low salinity injection. However, contrary to prior work, in our experiments the lower aging and displacement temperature produced higher initial displacement and incremental oil recovery for the same oil-brine-rock system. The aging temperature also effects the initial and final pH values with higher temperature producing lower pH values. There also appears to be a decrease in the recovery with increasing temperature separate from the effect of aging temperature. that supports a mechanism that involves chemical reactions.
This paper provides information pertinent to the oil recovery by law salinity flooding which could be utilized to maximize the response of experimental system, better understand the mechanism, and help screen candidates for low salinity waterflooding.

- by Geoffrey Thyne
- •
- Enhanced Oil Recovery, Low Salinity Waterflooding

An understanding of clay mineral surface chemistry is becoming critical as deeper levels of control of reservoir rock wettability via fluid–solid interactions are sought. Reservoir rock is composed of many minerals that contact the crude oil and control the wetting state of the rock. Clay minerals are one of the minerals present in reservoir rock, with a high surface area and cation exchange capacity. This is a first-of-its-kind study that presents zeta potential measurements and insights into the surface charge development process of clay minerals (chlorite, illite, kaolinite, and montmorillonite) in a native reservoir environment. Presented in this study as well is the effect of fluid salinity, composition, and oilfield operations on clay mineral surface charge development. Experimental results show that the surface charge of clay minerals is controlled by electrostatic and electrophilic interactions as well as the electrical double layer. Results from this study showed that clay minerals are negatively charged in formation brines as well as in deionized water, except in the case of chlorite, which is positively charged in formation water. In addition, a negative surface charge results from oilfield operations, except for operations at a high alkaline pH range of 10–13. Furthermore, a reduction in the concentrations of Na, Mg, Ca, and bicarbonate ions does not reverse the surface charge of the clay minerals; however, an increase in sulfate ion concentration does. Established in this study as well, is a good correlation between the zeta potential value of the clay minerals and contact angle, as an increase in fluid salinity results in a reduction of the negative charge magnitude and an increase in contact angle from 63 to 102 degree in the case of chlorite. Lastly, findings from this study provide vital information that would enhance the understanding of the role of clay minerals in the improvement of oil recovery.

The types of clay minerals and cations are the factors controlling improved recovery from low-salinity water (LSW) injection. In this paper, a surface complexation model was developed to predict the clay surface charge that develops for different brine compositions and salinities. It was followed by microfluidic experiments to visualize the individual performances of illite, kaolinite, and brine compositions and salinities during LSW injection. An automated measurement was conducted using an algorithm that determines contact angles from pore-space images. Our model results were substantiated against microfluidic observations. Based on the observations coupled with the simulation results, it is concluded that in kaolinite as an edge-charge-dominated clay, the charge development is significant under differing pH and ionic strengths. Accordingly, it responded well to LSW in the system under study, whereas illite as a basal-charged clay did not. This could elucidate the unlike sensitivities of clays to LSW, which in turn leads to different extents of wettability alteration.

- by Chenhao Sun
- •
- Microfluidics, Clay Minerals, Low Salinity Waterflooding

Oil polarity is an important property impacting the efficiency of low salinity waterflooding (LSWF). It directly affects fluid/fluid and rock/fluid interactions, controlling the interfacial properties and forces. However, the current findings in the literature on the effect of concentration of polar components on oil recovery by LSWF are contradictory. Therefore, the main objective of this paper is to investigate how the type of non-polar fractions and the concentration of acidic polar oil constituents change the trapped oil saturation at the pore-scale during LSWF. In this regard, we conducted a series of microfluidics LSWF experiments in both secondary and tertiary modes, using clay-free glass micromodels of representative elementary volume (REV) size. Both model oils and crude oil were tested. The polarity of model oils was manipulated by introducing different amounts of oleic acid into the samples. In addition, the contact angle under dynamic salinity alteration (CA-DSA), interfacial tension (IFT), and oil/brine zetapotential were measured as a function of oil polarity for a detailed understanding of the pore-scale results. Based on the results, polar acidic fraction increases both the oil-wetting tendency under high salinity (HS) condition and the degree of wettability alteration under low salinity (LS) condition. Increasing the concentration of the polar components in the model oils resulted in reducing oil/brine IFT by 7-9 mN/ m in HS and 8-12 mN/m in LS. As the IFT was reduced, the sweep efficiency of both HS and LS flooding was improved, which can be ascribed to the reduction of capillary trapping. However, the change of IFT by change of salinity was minor; thus, it cannot be considered a primary mechanism of LSWF. The ultimate oil recovery from HS and LS injection steps was highest when crude oil was used than using the most polar model oil. In the absence of polar components, no incremental oil recovery during LSWF was observed regardless of the molecular weight of the model oil. The efficiency of LSWF with all the polar oils was higher in the secondary injection than in the tertiary mode, as also reported in corescale studies. The main novel insight from the study is that the oil recovery factor by LSWF is logarithmically correlated with the oil polarity. The measured zeta-potential at the oil/brine interface also confirms a logarithmic correlation between the oil/brine interface potential and the concentration of polar components in the oil samples. This highlights that the bulk concentration of polar groups and their respective concentration at the oil/brine interface are not linearly related. Therefore, the acid number alone cannot predict the concentration of polar components at the interface and is not recommended to be used for screening potent oils.

- by Hassan Mahani
- •
- Wettability, Micromodels, Low Salinity Waterflooding, Pore scale

During the low salinity waterflooding (LSWF) of a viscous asphaltic oil reservoir, fluid-fluid interactions have a large influence on the fluid flow, pore-scale events, and thus oil recovery efficiency and behavior. In-situ water-in-oil (W/O) emulsion formation is a consequence of crude oil and brine interfacial activities. Despite the published studies, the pore-scale mechanisms of W/O emulsion formation and the role of injected brine salinity, injection rate, and pore-scale heterogeneity on emulsion formation and stability requires a deeper understanding. To address these, a series of static and dynamic micro-scale experiments were performed. The salinity dependent oil-brine interactions were characterized using interfacial tension (IFT) measurements, brine pH measurement, Fourier-transform infrared spectroscopy (FTIR), and W/O emulsion analysis. The results of static experiments showed that regardless of brine salinity, W/O emulsion does not form spontaneously and shear force is required. However, the microfluidic LSWF experiments revealed considerable formation of W/O emulsions and water-breakup. This was concomitant with fluctuations in the differential pressure. The pressure fluctuation was intensified as salinity was reduced, but was highest at the lowest IFT. Moreover, the severity of emulsion formation was intensified at lower rates and by increasing the pore-scale heterogeneity. Two principal mechanisms of W/O emulsion and water-breakup were identified: water snap-off, and water shortcut. The high viscosity of the asphaltic oil intensifies the former mechanism. While the latter is formed in water-wet regions and via movement of the waterfront through the thin layer of connate water. Emulsion division and rupture are two additional/axillary mechanisms leading to further break-up of the water phase. Emulsion formation leads to pore-scale flow diversion which in addition to other mechanisms contributes to improving oil recovery by LSWF. The novel insights gained in this study contribute to a better understanding of LSWF as well as other water-based EOR methods in viscous asphaltic oil reservoirs.

- by Hassan Mahani
- •
- Microfluidics, Enhanced Oil Recovery, Low Salinity Waterflooding, Emulsions

The interaction between fluid-fluid and solid-fluid interfacial forces and surface roughness controls the wettability. The ionic strength is the most important factor that controls electrostatic forces. Thus, a modification of the ionic strength can potentially lead to a change of the wettability, as shown in recent experimental works related to low-salinity waterflooding, which is an enhanced oil recovery technology. Despite the significant research published on this topic, for the first time, we present how a change of the ionic strength alters the wettability in a pore network micromodel made of silanized polydimethylsiloxane (PDMS). We visualized the invasion of brine in an elongated hydrophobic PDMS micromodel, initially saturated with Fluorinert. Under different injection rates and ionic strengths and using image processing, we quantified the contact angle distribution in the flow network, the recovery curve with time, the brine breakthrough time, and the temporal change of resident saturation. The results imply that there is an optimal range of salinity at which saturation change accelerates and the breakthrough saturation maximizes, which highlights the concept of optimal salinity in wettability alteration. Also, we observed a shift of the contact angle distribution toward a more water-wet state. Given the nonmonotonic trend of the breakthrough saturation with brine salinity, as well as recovery time versus the ionic strength, we conclude that the induced surface roughness is not the primary drive behind the accelerated saturation change. Therefore, the recovery time difference can be primarily attributed to the local alterations of the wetting properties of the porous medium due to the change of the ionic strength.

- by Hassan Mahani
- •
- Microfluidics, Wettability, PDMS, Low Salinity Waterflooding

It has been proposed that increased oil recovery in carbonates by modification of ionic composition or altering salinity occurs mainly at temperature exceeding 70-80⁰C. The argument was that elevated temperatures enhance adsorption of the potential determining ions which then modifies wettability to less-oil-wetting state. According to this rationale, it becomes questionable if diluted brines or brines without these ions can be still applicable. Therefore, the aim of this paper is to investigate if the wettability alteration truly depends on temperature and if so how the trend with temperature can be explained. We followed a combined experimental and theoretical modeling approach. The effect of brine composition and temperature on carbonate wettability was probed by monitoring contact angle change of sessile oil droplets upon switch from high salinity to lower salinity brines. IFT measurements as function of salinity and temperature along with extensive ζ-potential measurements as a function of salinity, pH, temperature and rock type were conducted. Interaction potentials between oil and carbonate surfaces were estimated based on DLVO theory and its consistency with oil droplet data was checked to draw conclusions on plausible mechanisms. Three carbonate rocks (two limestones and one dolomite) were used along with two reservoir crude oils, high salinity formation water (FW), seawater (SW) and 25 time diluted seawater (25dSW) as low salinity (LS) brine. It was observed that i) wettability alteration to less-oil-wetting state can occur at ambient temperature for specific rock types and brines, ii) there is no univocal increase in response to SW and LS brine at elevated temperature. The largest improvement in wettability was observed for dolomite while among the limestones only one rock type showed noticeable wettability improvement at elevated temperature with SW. The difference in behavior between limestones and dolomite indicate that the response to brine composition change depends on rock type and mineralogy of the sample. These observations are consistent with the ζ-potential trends with salinity at a given temperature. Dolomite generally shows more positive ζ-potential than limestones. But even the two limestones react differently to lowering salinity and exhibit different magnitude of ζ-potential. Moreover, it is observed that at specific salinity an increase in temperature leads to reduction of ζ-potential magnitude on both rock/brine and oil/brine interfaces toward zero potential. This can affect positively or negatively on the degree of wettability alteration (to less oil-wetting state) at elevated temperature depending on the sign of oil/brine and rock/brine ζ-potential in SW/LS. The observed trends are reflected in the DLVO calculations which shows consistency with contact angle trends with temperature and salinity. According to the DLVO calculation lack of response to SW/LS in some of the systems above can be explained by stronger electrostatic attractive forces under SW/LS than HS. This study concludes that a combined surface-charge-change and double-layer expansion is a plausible mechanism for the wettability alteration in carbonate rocks.

- by Hassan Mahani
- •
- Enhanced Oil Recovery, Carbonates, Wettability, Dolomites

A novel photolithography-based technique was developed to fabricate a quasi-2D heterogeneous calcite micromodel of representative elementary volume size. The effect of brine-chemistry on the mobilization of capillarity and heterogeneity trapped oil after high salinity water injection was evaluated by using diluted seawater, and seawater modified with calcium, sulphate, and silica nanoparticles. Preliminary brine screening was performed based on modified contact angle experiments under dynamic salinity alteration. The main findings are that the chemical composition of brine impacts both the ultimate oil recovery and its speed. The highest and fastest oil recovery was obtained with diluted seawater and seawater augmented with nanoparticles. We also found that the ex-situ contact angle results, indicative of wettability alteration, can be predictive of each brine performance at the pore network-scale. A slow recovery process, from 7 days up to 12 days, without any oil banking, was observed with all the brines. Due to the time-dependent nature of the wettability alteration process, mere injection of brines, even several pore-volumes and the viscous force exerted by flooding, were not sufficient to result in any additional oil production. Oil production was obtained only during the shut-in period via enhanced spontaneous imbibition of brine into the pores and throats. This highlights that a sufficient soaking time (at least for laboratory scale experiments) would be necessary to assess suitability of brines and determine accurately the incremental oil recovery by low salinity waterflooding (LSWF).

- by Hassan Mahani
- •
- Carbonates, Enhanced Gas Recovery, Wettability, Photolithography

- by abdul aziz
- •
- Engineering, Information Technology, Economics, Process Optimization

Objective: The present paper investigates the effect of nanoparticle concentrations on the interfacial tension and wettability during the low salinity water flooding (LSWF) at microscale. Method: A wide range of LSW concentrations were prepared and investigated for their ability to modulate the interfacial tension with crude oil. The impact of salinity on the fluid-rock interactions was studied through contact angle measurements on water-wet, intermediate-wet and oil-wet glass substrates. Nanofluid systems at a fixed concentration of 0.1wt% were prepared by mixing the hydrophilic silica NPs with a wide range of LSW concentrations. Likewise, the impact of silica nanoparticles on the IFT was investigated. Results: The fluids interactions results suggest that the lowest IFT value can be achieved at 5000ppm. Contact angle studies in all wettability systems indicated a negligible effect of water salinity on the wettability alteration. However, the presence of silica nanoparticles in low saline water significantly reduced the values of IFT and contact angle. Consequently, the wettability was altered to a more waterwet condition. Conclusion: Oil displacement experiments in both water-wet, intermediate-wet and oil-wet glass micromodels indicated that LSW-augmented functional silica nanoparticles can offer enormous potential for improving oil recovery. A synergistic effect of LSW and the adsorption of nanoparticles at the interfaces appears to explain the improved oil sweep efficiency.

- by Shirin Safarzadeh and +1
- •
- Nanotechnology, Silica Nanoparticles, Micromodels, Contact angle

Dynamics of pressure field evolution inside thin films under the effect of ionic strength gradient is not well understood. Dynamics of the pressure field is important as it controls the film hydrodynamics and also change of contact angle due to the change of ionic strength. The major two potentials building the total pressure in thin films are osmotic and electrostatic potentials. In thin films, these two components are working against each other, while the reduction of ionic strength will decrease the osmotic pressure, it will increase the electrical double layer thickness. However, this interaction is controlled by transport of ions and the transport time-scale. Here, we present a model that couples Nernst−Planck and Poisson equations to simulate ionic transport and also Stokes equation augmented by the Maxwell stress tensor (MST) to simulate the pressure field. Results show a highly nonlinear behavior in the pressure field that is initiated by diffusion of the ions in a channel which is initially filled by a high ionic strength electrolyte and is exposed to a bulk solution with lower ionic strength. Results show that diffusion length (transport length) and the overlapping of the double layers affect the pressure field significantly. The results imply that in thin films where ionic diffusion is expected, interfaces can deform due to the nonlinear pressure field, which is triggered by the asymmetric and multidirectional transport of ions. This brings a new insight into thin film hydrodynamics that can contribute to understanding the dimple formation in thin films.

- by Hassan Mahani
- •
- Thin Films, Diffusion, Electrokinetics, Contact angle

Microbial enhanced oil recovery (MEOR), due to the formation of biofilm and the presence of biosurfactants generated by microorganisms in the reservoir, can play a role in reducing interfacial tension (IFT) and wettability alteration. In this work, the fluid-fluid interaction by measuring the IFT has been evaluated for combining two EOR methods, including low salinity water and MEOR, due to the high importance of fluid-fluid interaction in EOR. Geobacillus stearothermophilus has been used as a bacterium to study changes in IFT. The effect of different salts, including monovalent and divalent cations and anions at different salinities, on biosurfactant performance, is investigated using IFT measurements. Also, the type of oil is evaluated in terms of its acidic and basic properties on the performance of biosurfactants. According to the results of this study, injection of Geobacillus stearothermophilus bacteria reduces interfacial tension in acidic oil by 10.26% and in basic oil by 5.26%. According to the results, increasing salinity in the presence of oil-containing asphaltene with basic properties increases the IFT of the solution containing Geobacillus stearothermophilus bacteria, but in the presence of acidic oil, a decrease in IFT is observed. The most significant effect of reducing the IFT of acidic oil and solution containing Geobacillus stearothermophilus is obtained in the presence of the following salts, respectively: CaCl2>MgCl2>NaCl. The results show that with increasing CaCl2 concentration, the IFT between basic oil and Geobacillus stearothermophilus solution gradually increases. This ascending trend is in the presence of NaCl salt with a lower slope. However, in the presence of MgCl2 salt, dual behavior is observed before and after the concentration of 1000 ppm, so that before this concentration, the IFT increases and then decreases. The findings of this study can help for a better understanding of the interaction of bacteria with asphaltenic oils in the presence of effective salts for low salinity water injection. The results of this study showed that by combining low salinity water with bacteria, less IFT could be obtained than low salinity water or bacteria alone.

- by Behnam ranjbar and +1
- •
- Enhanced Oil Recovery, Colloidal and Interfacial Phenomena, Interfacial Tension, Low Salinity Waterflooding

- by Abdul Aziz
- •
- Engineering, Information Technology, Economics, Process Optimization

While the “low salinity waterflooding” (LSWF) has been praised for enhancing oil recovery from different core rocks, the performance of the technique in different wettability environments remains unclear. The consensus is that LSWF does not work well in water-wet carbonate oil reservoirs. The main research objective was to determine the effect of LSWF on the displacement efficiency (DE) in different wettability environments. Carbonate core flooding experiments on rocks with different wettabilities were performed at in-situ reservoir conditions using seawater as a “base water”. Seawater was sequentially diluted 10 to 50 times and spiked 2 and 6 times with sulfate. Following sequential flooding with four different waters, the DEs were measured for different wettabilities. Five different sequential brine floodings were performed on carbonate rocks. Results indicated that optimum low salinity water is a function of system wettability. Seawater (≈ 50,000 ppm) is the optimum brine for oil...

While the "low salinity waterflooding" (LSWF) has been praised for enhancing oil recovery from different core rocks, the performance of the technique in different wettability environments remains unclear. The consensus is that LSWF does not work well in water-wet carbonate oil reservoirs. The main research objective was to determine the effect of LSWF on the displacement efficiency (DE) in different wettability environments. Carbonate core flooding experiments on rocks with different wettabilities were performed at in-situ reservoir conditions using seawater as a "base water". Seawater was sequentially diluted 10 to 50 times and spiked 2 and 6 times with sulfate. Following sequential flooding with four different waters, the DEs were measured for different wettabilities. Five different sequential brine floodings were performed on carbonate rocks. Results indicated that optimum low salinity water is a function of system wettability. Seawater (≈ 50,000 ppm) is the optimum brine for oil-wet and intermediate-wettability systems. Sequential flooding consisting of seawater followed by diluted seawater in a water-wet system yielded the highest DE of 88%. Besides, low-salinity brine followed by sulfate performed better in a water-wet environment than in oil-and intermediate-wettability systems.

- by Eghbal Sahraei
- •
- Oil and gas, Enhanced Oil Recovery, Low Salinity Waterflooding, Formation Damage

- by ABDUL AZIZ
- •
- Engineering, Information Technology, Economics, Biodiesel

Wettability alteration is the principal low-salinity-effect (LSE) in many oil-brine-rock (OBR) systems. Our recent experimental results have demonstrated that wettability alteration by low salinity is slow. It is expected that the electrical behavior of oil/brine and rock/brine interfaces and the water film geometry control both the transient hydrodynamic pressure, and the timescale of ionic transport in the film, thus the kinetics and degree of wettability alteration. In this paper, the electro-diffusion process induced by the imposed ionic strength gradient is simulated by solving Poisson-Nernst-Planck equations in a water film bound between two charged surfaces, using a finite element-based computational fluid dynamics method. Both the non-equilibrium electric-double-layer (EDL) pressure and the timescale of diffusion under different plausible electrical boundary conditions (BCs) are determined. The numerical results show that electro-diffusion in the thin film is non-Fickian, strongly dependent on the electrical BCs, and significantly (10-20 times) slower than Fickian diffusion. Among various BCs, those which lead to the strengthening of the electrostatic force, or electric field (such as constant charge BC), are the most favorable in terms of observing LSE. Moreover, it is found that the contribution of the osmotic pressure in the vicinity of the pore (bulk) fluid is negligible and that Maxwell stress is the dominant source of EDL force build-up. This force can then trigger wettability alteration. Furthermore, while both film length and Colloids and Surfaces A: Physicochemical and Engineering Aspects 620 (2021) 126543 2 thickness influence the electrical interaction of interfaces, the film thickness affects mainly the EDL force rather than the rate of ionic transport. On the contrary, the film length has a significant effect on the timescale of diffusion. The effect of the ionic strength gradient on the timescale of diffusion and LSE is relatively minor. This study provides novel insights into the role of the electrical behavior of OBR interfaces and film phenomena in the rate of ionic transport and establishment of low salinity in the film. Thin film modeling is a means to develop predictive capability for LSWF, screen OBR candidates, and to determine favorable conditions to observe LSE. Moreover, the slow kinetics of LSE necessitates accounting for the time-effect in the experimental evaluation of LSWF.

- by Hassan Mahani
- •
- Enhanced Oil Recovery, Electrokinetics, DLVO theory, Wettability Alteration

In this work sensitivity studies were carried out considering both water-wet and oil wet
systems. Low salinity waterflood was investigated and the contact angles, the interfacial
tension and the spread of the pore radius were varied to study how the oil recovery changes
and to see what variables effect the enhanced oil recovery (EOR) the most.
Many scientists have suggested that a cause of increased oil recovery due to injection of low
salinity water is because of one of the mechanisms or rather effects of low salinity, such as
wettability alteration, changes in pH or fines migration alone. However, we believe low
salinity injection will not lead to only one of the effects/mechanisms, but a series of effects
will happen. This was proved by Hamouda et al (2014). They concluded that the main factors
that govern low salinity water performance in EOR are the degree of the mineral/brine
interaction that would increase the sweep efficiency. Hamouda et al (2014) suggested an
equation explaining the increase of pH, hence increae in [K+]. This is basically due to ion
exchange and the result of this interaction is formation of fines. As the fines migrate, the
sweep efficiency is enhanced.
Zhao, et al (2010) suggested that the oil-wet fraction plays a more important role in
determining recovery than the contact angle in the oil wet reserts. Our results show that
changes in distribution lead to the most significant changes in oil recovery. It is shown that
the best oil recovery is obtained when the reservoir is mixed wet, when there is a decrease in
either the contact angle ratio or the IFT ratio and when the distribution is 30.
In order to get a recovery that is reasonable and within its intervals of [0,100], Rw< R2<R1.
This is only happening when there is a small decrease in the contact angle ratio, so that θ2 <
θ2. For example θ2 = 115 and θ2 = 125. Where Rw is determines the amount of water-wet
and oil-wet pores (r>Rw are oil-wet pores, and r<Rw are water-wet pores), R1 is the
percolation radius and R2 is the new radius after a change in either the contact angle or the
IFT ratio.

- by Sh Al
- •
- Reservoir Engineering, Matlab, Reservoir Simulation, Matlab Programming