Wettability Alteration Research Papers - Academia.edu (original) (raw)

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 and +2
- •
- Enhanced Oil Recovery, Wettability Alteration, Low Salinity Waterflooding, chemical EOR

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

This document reviews the various techniques to measure wettability of rocks toward oil with a focus on methodologies that may be relevant for measuring wettability in shales. The two formations of interest are the Bakken and Eagle Ford Shales. Wettability measurement techniques were developed for sandstone rocks. Shales present several basic problems when employing standard techniques because of their small grain size, low permeability and reactive components.
This document contains a short review of shale oil and gas production, an overview of the relevant features of shale pore systems, and briefly summarizes the Bakken and Eagle Ford Shale properties of interest as regards wettability. A review of the current standard methodologies for measuring wettability and their limitations showed that current methods are unable to provide fast quantitative results. A new method is aloso reviewed that offers rapid measurement of wettability with semi-quantitative results that can be easily refined. This modified flotation method offers the advantages of low cost and rapid measurement of many samples over a short time. The method allows measurement of not just wettability, but also pH and associated aqueous parameters and can be performed at elevated temperature applicable to the formations of interest. The table below summarizes the important aspects of each technique.

- by Geoffrey Thyne
- •
- Wettability Alteration, Wetting and Wettability

In this study, synthesized TiO 2 /SiO 2 hybrid nanoparticles were used to fabrication of hydrophilic coating with high stability on superhydrophobic surface of carbonate rock. For this purpose, n-heptane droplet contact angle in water medium was measured on the rock surface before and after treatment. The TiO 2 /SiO 2 nanoparti-cles were synthesized by modified sol-gel method. This method is based on increasing functional groups on the surface of the TiO 2 nanoparticles to produce high hydrophilic nanoparticles. The synthesized nanoparticles were characterized by Scanning electron microscopy (SEM), Fourier transform infrared spectroscopy (FTIR) and X-ray diffraction (XRD) analyses. The chemical composition and morphology of untreated and treated rock surface were determined using XRD and SEM analyses. It was observed that the n-heptane droplet was instantly spread on the untreated rock and its contact angle in water medium was 0°, in the other hand the water contact angle in n-heptane medium was 168°, so the un-coated rock was superhydrophobic. After adsorption of nanoparticles on the rock surface, the n-heptane droplet contact angle changed to 165° and the water contact angle changed to 0° so the coated rocks were superhydrophilic. The fabricated nano-coatings exhibited high thermal stability and moderate mechanical stability; also the coated surfaces had high stability in contact with salt solution, the results were encouraging. Applications of these nano-coatings include surfaces where cleanliness is paramount such as in hospitals as well as the maintenance of building facades and protection of public monuments from weathering. Novel industrial application includes wettability alteration of oil wet carbonate rock for enhanced oil recovery (EOR).

- by Marzieh Sadat Hosseini and +1
- •
- Nanoparticles, Synthesis, Hydrophilicity, Wettability Alteration
- 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.

Wettability alteration can occur at diﬀerent stages during the producing life of a reservoir. Oil recovery from oilwet
reservoirs can signiﬁcantly be increased by altering its wettability from an oil-wet to a strongly water-wet condition. Chemical
agents such as surfactants are known as wettability modiﬁers in oil-wet systems. More recently, nanoﬂuids prepared by dispersing
nanoparticles in several liquid agents have been considered as potential wettability modiﬁers. In this work, the eﬀectiveness of
alumina-based nanoﬂuids in altering the wettability of sandstone cores with an induced oil-wet wettability was experimentally
studied. Eight nanoﬂuids with diﬀerent nanoparticles concentration, ranging from 100 ppm to 10000 ppm, were prepared by dispersing alumina nanoparticles in an anionic commercial surfactant. The eﬀect of nanoﬂuids on wettability alteration was
investigated by contact angle and imbibition tests, and it was shown that designed nanoﬂuids could signiﬁcantly change the
wettability of the sandstone cores from a strongly oil-wet to a strongly water-wet condition. Imbibition tests also allowed
identifying the eﬀect of nanoparticles concentration on the suitability of the treatment for enhancing the imbibition process and restoring the original core wettability. Results showed that the eﬀectiveness of the anionic surfactant as wettability modiﬁer could
be improved by adding nanoparticles in concentrations lower or equal than 500 ppm. The best performance was achieved when a
concentration of 100 ppm was used. Additionally, a core displacement test was carried out by injecting in a sand pack a nanoﬂuid prepared by dispersing alumina nanoparticles in distillated water. The treatment was eﬀective in altering the sand pack wettability
from an oil-wet to a strongly water-wet condition as indicated by a signiﬁcant reduction in the residual water saturation and a
displacement to the right of the oil relative permeability curve and the crossover point.

- by Farid B. Cortés and +1
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- Wettability, Wettability Alteration, Sandstone Petrology

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
- •
- 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.

Recent interest in the use of nanoparticles in emulsion stabilization has driven increased efforts to understand how
7 the characteristics of the particles influence the emulsion properties. While it is clear that the contact angle and wettability must
8 play significant roles in determining the type of emulsion formed, it is not straightforward to measure the contact angle of a
9 nanoparticle. In this paper, we compare multiple techniques for characterizing the water−air contact angle of silica nanoparticles
10 while systematically varying the hydrophobicity of the nanoparticles using silanization. We then compare the performance of the
11 particles in decane/water emulsions. While the heat of immersion measured by microcalorimetry is found to provide the best
12 method for discriminating between the wettability of the particles, the fraction of surface covered by the silane groups was
13 observed to affect the structure of the emulsion more profoundly than the differences in the contact angles of the particles.
14 Furthermore, we find that the phase of initial dispersion is extremely influential in determining the resulting emulsion type and
15 droplet size.

- by Javen S Weston and +2
- •
- Nanoparticles, Contact angle, Wettability Alteration, Colloidal Silica

Low Salinity Flooding (LSF) is an emerging technology to improve oil recovery for both sandstone and carbonate reservoirs. Low salinity water injections for oil recovery have shown seemingly promising results in the case of clay-bearing sandstones saturated with asphaltic crude oil. Testing over the last 20 years has shown that incremental oil recovery using this method can be potentially significant, with sandstone reservoirs showing an incremental oil recovery range of between 5% and 30% of original oil in place (OOIP).The underlying mechanisms behind this phenomenon is not well understood, but many researchers have suggested that it is related to complex crude oil/brine/rock interactions. In recent years, positive results have been presented regarding the combination of low salinity water and surfactant injection. The answer requires a thorough understanding of oil recovery mechanism of low salinity water injections. Numerous hypotheses have been proposed to explain the increased oil recovery using low salinity water, including migration of detached mixed-wet clay particles with absorbed residual oil drops, wettability alteration toward increased water-wetness, and emulsion formation. The mechanisms of enhanced recovery are considered to be decrease of residual oil saturation and alternation of rock wettability. In addition, the mobility control mechanism due to induced fines migration by low salinity water, and the consequent flux diversion is also a possible mechanism for enhanced recovery in low salinity water flooding. It has been suggested that low saline water flooding has a potential for improved oil recovery in all clayey sandstone formation containing crude oil. The result from different work indicates that the initial wetting condition is a crucial property for the effect of low salinity injection. It is obvious that the dominant mechanisms of low-salinity waterflooding are yet to be discovered. However, wettability is considered a key factor that affects fluid distribution in a porous medium. Therefore, the main objective of this paper is to provide theoretical understanding of the effect of brine salinity on rock-wettability alteration for a better understanding of low-salinity-water mechanisms. This paper also contains different effects, parameters and mechanisms which alters wettability of rock towards more water wet condition, which ultimately helps to enhance recovery from sandstone reservoir.

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
- •
- 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
- •
- Carbonates, Electrokinetics, Wettability Alteration, Low Salinity Waterflooding

ABSTRACT Experiments to understand the effect of surface wettability on impact characteristics of water drops onto solid dry surfaces were conducted. Various surfaces were used to cover a wide range of contact angles (advancing contact angle from 48 • to 166 • , and contact angle hysteresis from 5 • to 56 •). Several different impact conditions were analyzed (12 impact velocities on 9 different surfaces, among which 2 were superhy-drophobic). Results from impact tests with millimetric drops show that two different regimes can be identified: a moderate Weber number regime (30 < W e < 200), in which wettability affects both drop maximum spreading and spreading characteristic time; and a high Weber number regime (W e > 200), in which wettability effect is secondary, because capillary forces are overcome by inertial effects. In particular, results show the role of advancing contact angle and contact angle hysteresis as fundamental wetting parameters to allow understanding of different phases of drop spreading and beginning of recoiling. It is also shown that drop spreading on hy-drophilic and superhydrophobic surfaces occurs with different time scales. Finally, if the surface is superhydrophobic, eventual impalement, i.e., transition from Cassie to Wenzel wetting state, which might occur in the vicinity of the drop impact area, does not influence drop maximum spreading. C 2012 American Institute of Physics. [http://dx.doi.org/10.1063/1.4757122]

- by Marco Marengo
- •
- Engineering, Wetting and Spreading, Mathematical Sciences, Wettability

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

TX 75083-3836, U.S.A., fax 01-972-952-9435.

- by Dandina Rao
- •
- Wettability Alteration

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

Condensation heat transfer performance can be improved by increasing the condensate removal rate. Commonly, this can be achieved by promoting dropwise condensation mode in which super/hydrophobic coatings applied on the entire condenser surface. Herein, alternative mini-scale straight patterns consisted of hydrophobic (b) and less-hydrophobic (a) regions were formed on the condenser tubes. The existence of the two adjacent regions generates wettability gradient which can mitigate condensate and increase its removal rates. A parametric study was conducted to experimentally determine the influence of (b/a) ratios on the heat transfer performance and droplet dynamic under saturation condition near the atmosphere pressure with the presence of non-condensable gases (air). The results reveal that all patterned surfaces exhibited a drastic enhancement in terms of condensation heat transfer coefficient and heat flux compared to those of filmwise condensation. More interestingly, some (b/a) ratios significantly outperformed a surface with a complete dropwise condensation. In addition, an optimum (b/a) ratio of (2/1) exists with b and a-regions widths of 0.6 mm and 0.3 mm, respectively. The heat transfer coefficient of the optimum ratio is peaked at a value of 85 kW/m 2 K at a subcooling of 9 °C, which is 4.8 and 1.8 times that of a complete filmwise and dropwise condensation, respectively. Our study also reveals that the b-regions served mainly as droplet nucleation sites with rapid droplets mobility; whereas the a-regions promoted droplet removal from the neighboring b-regions, and served as drainage paths where condensate can be drained quickly under gravitational force. Furthermore, the existence of both a and b-regions on the condensing surface controls the droplets maximum diameters of the growing dro-plets on the b-regions. The maximum diameter is approximately 0.56 ± 3% mm, which is 26% the size of the droplets maximum diameter on a full b-region surface. In summary, this wettability-driven mechanism allows droplets to be removed from the condensing surface at higher rates, leading to a substantial enhancement in the condensation heat transfer coefficient.

- by Mohammad Alwazzan and +2
- •
- Hybrid Systems, Heat Transfer, Wettability Alteration, Condensation

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

Data from the literature suggest that the rebound of a drop from a surface can be achieved when the wettability is low, i.e., when contact angles, measured at the triple line (solid−liquid−air), are high. However, no clear criterion exists to predict when a drop will rebound from a surface and which is the key wetting parameter to govern drop rebound (e.g., the "equilibrium" contact angle, θ eq , the advancing and the receding contact angles, θ A and θ R , respectively, the contact angle hysteresis, Δθ, or any combination of these parameters). To clarify the conditions for drop rebound, we conducted experimental tests on different dry solid surfaces with variable wettability, from hydrophobic to superhydrophobic surfaces, with advancing contact angles 108°< θ A < 169°and receding contact angles 89°< θ R < 161°. It was found that the receding contact angle is the key wetting parameter that influences drop rebound, along with surface hydrophobicity: for the investigated impact conditions (drop diameter 2.4 < D 0 < 2.6 mm, impact speed 0.8 < V < 4.1 m/s, Weber number 25 < We < 585), rebound was observed only on surfaces with receding contact angles higher than 100°. Also, the drop rebound time decreased by increasing the receding contact angle. It was also shown that in general care must be taken when using statically defined wetting parameters (such as advancing and receding contact angles) to predict the dynamic behavior of a liquid on a solid surface because the dynamics of the phenomenon may affect surface wetting close to the impact point (e.g., as a result of the transition from the Cassie−Baxter to Wenzel state in the case of the so-called superhydrophobic surfaces) and thus affect the drop rebound.

- by Fabio Villa and +1
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- Multidisciplinary, Wettability, Contact angle, Wettability Alteration

Low saline water injection has recently gained a wide interest from researchers, oil companies, and governments, who are evaluating the economical and the most effective method to improve the recovery of oil. While field tests laboratory work have pointed out that water flooding with low-salinity can have positive results on oil recoveries. Up-to-date, researchers have conducted numerous core flood tests in order to determine the effects of low-salinity water flooding over rock wettability. The general phenomena accepted is that low-saline water injection effects are caused by rock wettability modification, however the methods involved in this process are static or not fully understood. The aim of this study is to provide information effectively that will help to accelerate the efforts to investigate this effect. In this study, different laboratory observations including the benefits under reservoir conditions, operating conditions to have a positive result of low saline and effects of low-saline water flooding and its different proposed mechanisms have been analyzed.

- by Abdul Haque Tunio and +1
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- Enhanced Oil Recovery, Wettability Alteration, Water Flooding and Ultimate Reocovery, Improved Oil Recovery

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
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- 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,

The water flooding in the carbonate fracture reservoir is low efficiency because of higher permeability in fractures than in matrix, and water will not imbibe spontaneously into the matrix due to a negative capillary pressure. Spontaneous imbibition of water into carbonate fracture reservoir is a very important issue in secondary oil recovery method. However, almost more than 80% of the entire known carbonate reservoir can be categorized as oil wet. It is therefore important to find methods to alter the wettability from oil-wet to water-wet conditions that are effective in order to improve the recovery from carbonate fracture reservoir. So far, two methods have been developed wettability alterations: 1) addition of certain chemical surface active agent to the injection water, and 2) thermally wettability alteration by steam injection. In this study, an oil sample with 20 API was used to investigate the effect of the understudied surfactants on wettability alteration in the oil-water-limestone system. Understudied surfactants were SDBS (sodium dodecylbenzene sulfonate), C 12 TAB (dodecyl trimethyl ammonium bromide), C 16 TAB (hexadecyl trimethyl ammonium bromide) and Triton X-100 that were utilized at 0.5, 1.5 and 2.5 wt% concentrations. The experiments were performed several times (0, 1, 6, 12, 24, 48, 72, 96 h) after injection of oil drop under limestone rock sample at reservoir temperature of 80 o C. The obtained results showed that the increasing each of the surfactant could cause wettability alteration of the rock from oil-wet towards water-wet situation by passing of time. This alteration was very sharp at the beginning, but it was increases slightly at the time. It was observed that Triton X-100 was more efficient than C 16 TAB, C 12 TAB and SDBS to alter the wettability of the rock.

A successful approach to wettability alteration requires several key steps: screening the formation to identify current wettability, simple laboratory tests to evaluate the increased recovery potential, economic evaluations to estimate costs and benefits, and finally, well-constrained geochemical models to help correctly design the wettability-modifying fluids. While some current assumptions will be refined as we become more knowledgeable, the basic idea, that we can alter wettability with water chemistry to optimize recovery seems well justified.

- by Geoffrey Thyne
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- Enhanced Oil Recovery, Wettability Alteration

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.

Reservoir rock wettability has been linked to the adsorption of crude fractions on the rock, with much attention often paid to the bulk mineralogy rather than contacting minerals. Crude oil is contacted by different minerals that contribute to rock wettability. The clay mineral effect on wettability alterations is examined using the mineral surface charge. Also, the pH change effect due to well operations was investigated. Clay mineral surface charge was examined using zeta potential computed from the particle electrophoretic mobility. Clay minerals considered in this study include kaolinite, montmorillonite, illite, and chlorite. Results reveal that the clay mineral charge development is controlled by adsorption of ionic species and double layer collapse. Also, clay mineral surface charge considered in this study shows that their surfaces become more conducive for the adsorption of hydrocarbon components due to the presence of salts. The salt effect is greater in the following order: NaHCO3 < Na2SO4 < NaCl < MgCl2 < CaCl2. Furthermore, different well operations induce pH environments that change the clay mineral surface charge. This change results in adsorption prone surfaces and with reservoir rock made up of different minerals, and the effect of contacting minerals is critical as shown in our findings. This is due to the contacting mineral control wettability rather than the bulk mineralogy.

- by Isah Mohammed
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- Wettability Alteration, Asphaltenes adsorption

Asphaltene adsorption and deposition onto rock surfaces are predominantly the cause of wettability and permeability alterations which result in well productivity losses. These alterations can be induced by rock−fluid interactions which are affected by well operations such as acidizing, stimulation, gas injections, and so forth. Iron minerals are found abundantly in sandstone reservoir formations and pose a problem by precipitation and adsorption of polar crude components. This is due to rock−fluid interactions, which are dependent on reservoir pH; thus, this research work studied the surface charge development of pyrite, magnetite, and hematite. To ascertain conditions that will result in iron mineral precipitation and adsorption of asphaltene on iron mineral surfaces, zeta potential measurement was carried out. This is to determine the charge and colloidal stability of the iron mineral samples across wide pH values. Experimental results show that the charge development of iron minerals is controlled by mineral dissolution, the formation of complexes, adsorption of ions on the mineral surface, and the collapse of the double layer. The findings provide insights into the implications of iron mineral contacting crude oil in reservoir formations and how they contribute to wettability alterations due to different well operations.

Most of the wells in oil and gas industry are vertical. These wells have low risk in terms of its construction and maintenance and easy to drill as compare to horizontal drilling. Horizontal wells are drilled to enhance production and performance of well by providing wide range of well bore (contact area) with reservoir thatâ€™s why horizontal drilling is very popular. Horizontal and vertical wells though have number of advantages but there are some disadvantages and one of them is skin. Skin is basically the measure of amount of damage around the well bore in reservoir. Damage near well bore may cause by fine migration, wettability reverse, solid plugging, drilling fluid etc. Intensity of positive skin ranges from 0 to 50 indicates damaged reservoir and intensity of negative skin ranges from -0 to -5 indicates improved reservoir after implementing stimulation job. It is estimated that production from two third of horizontal and vertical wells are reduced because of skin. For minimizing formation damage reactive solution of chemicals either Hydro Caloric Acid or Hydro Fluoric Acid are used known as acidizing. The research methodology is to first collect information/data from fields regarding formation damage in vertical well and horizontal well having the same reservoir then by using simulation software analysis take place between horizontal well and vertical well in terms of production. In case of horizontal well formation damage caused to reduce the production from 15 MMSCFD to 10 MMSCFD. By applying proposed treatment job the production increase to 18.364 MMSCFD while in case of vertical well formation damage caused to reduce the production from 5 MMSCF/D to 3 MMSCF/D. By applying appropriate treatment job the production increase to 4.618 MMSCF/D.

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
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- 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
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- Thin Films, Diffusion, Electrokinetics, Contact angle

An extensive systematic study was designed to investigate the effect of geochemical parameters in wetting sandstone and carbonate rock-oil-brine systems. The geochemical parameters investigated in this project are: rock mineralogy (Austin chalk, Indiana limestone, Silurian dolomite, and Berea sandstone), aqueous chemistry (pH and salinity), oil chemistry and temperature. If the effects of the proposed parameters are examined with respect to each other, an overwhelming number of experiments would be required. Therefore, conventional experimental studies such as contact angle measurements and flow through porous media experiments cannot be used to study all the parameters in the allocated time for this project. This paper will present an alternative method of estimating wettability that is much faster and has high repeatability, and thus creates a well-informed screening tool to sort through different possible chemical conditions present in the reservoir and pick the parameters of interest for further study.

- by Geoffrey Thyne and +2
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- Wettability, Wettability Alteration

Wettability alteration can occur at different stages during the producing life of a reservoir. Oil recovery from oilwet reservoirs can significantly be increased by altering its wettability from an oil-wet to a strongly water-wet condition. Chemical agents such as surfactants are known as wettability modifiers in oil-wet systems. More recently, nanofluids prepared by dispersing nanoparticles in several liquid agents have been considered as potential wettability modifiers. In this work, the effectiveness of alumina-based nanofluids in altering the wettability of sandstone cores with an induced oil-wet wettability was experimentally studied. Eight nanofluids with different nanoparticles concentration, ranging from 100 ppm to 10000 ppm, were prepared by dispersing alumina nanoparticles in an anionic commercial surfactant. The effect of nanofluids on wettability alteration was investigated by contact angle and imbibition tests, and it was shown that designed nanofluids could significantly change the wettability of the sandstone cores from a strongly oil-wet to a strongly water-wet condition. Imbibition tests also allowed identifying the effect of nanoparticles concentration on the suitability of the treatment for enhancing the imbibition process and restoring the original core wettability. Results showed that the effectiveness of the anionic surfactant as wettability modifier could be improved by adding nanoparticles in concentrations lower or equal than 500 ppm. The best performance was achieved when a concentration of 100 ppm was used. Additionally, a core displacement test was carried out by injecting in a sand pack a nanofluid prepared by dispersing alumina nanoparticles in distillated water. The treatment was effective in altering the sand pack wettability from an oil-wet to a strongly water-wet condition as indicated by a significant reduction in the residual water saturation and a displacement to the right of the oil relative permeability curve and the crossover point.

- by Juliana Giraldo
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- Engineering, Wettability, Wettability Alteration, CHEMICAL SCIENCES

- by marco ruiz
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- Engineering, Wettability, Wettability Alteration, CHEMICAL SCIENCES

- by Saheed Alade
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- Wettability Alteration, Asphaltenes adsorption

Al-Sn based alloys are widely used as plain bearings in several engineering applications, particularly in internal combustion engines. The microstructures of these alloys are composed by two main phases, alpha-Al and betha-Sn. The latter provides the low friction coefficient required for bearing applications. The new combustion engines and hybrid systems impose harder working conditions to plain bearings, thus the bearing materials need to be stronger with improved friction properties. The conventional Al20Sn1Cu (wt.%) alloy produced at different cooling rates by means of different casting processes such as Belt Casting, Twin Roller and Single Roller Melt Spinning techniques was studied. The effects of the cooling rate and of the Mn addition on the microstructure and properties were studied. The samples produced by
the melt-spinning technique with cooling rates higher than ~5 x 10E5 K/s conducts the alloy to a solidification pathway in a metastable condition through a miscibility gap. A microstructure characterized by an homogeneous small rounded b-Sn particles distributed in a refined alpha-Al grain size matrix is obtained.
Samples produced with cooling rate higher than ~1.4 x 10E6 K/s show an anisotropic microstructure of a <100> alpha-Al crystallographic texture in a columnar microstructure. The melt-spun samples with an
isotropic microstructure reach a Vickers hardness 86% higher and an improved wetting property than the alloy produced by the traditional Belt-Casting technique. However the melt-spun samples with crystallographic texture showed a downfall in the properties. The addition of Mn leads to a more homogeneous and refined microstructure independently of the casting technique used.

- by Fernando Audebert
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- Microstructure, Aluminium Alloys, Wettability Alteration, Bearings

Capillary driven surface oscillations of liquid argon (Tsat = 87.3 K at 1,013 hPa) have been investigated in a partly filled right circular cylinder under non-isothermal boundary conditions. The oscillations take place during the reorientation from the normal gravity surface position towards a new position upon step reduction of gravity. The situation is similar to the end of thrust in a rocket tank when the cold propellant moves along the warmer tank wall driven by capillary forces. The aim was to investigate the influence of the temperature difference between the slightly subcooled cryogenic liquid and the superheated cylinder wall on the oscillations and their characteristics in a single-component, two-phase system. Axial wall temperature gradients of averaged 0.15 K/mm − 1.93 K/mm above the normal gravity surface position were implemented. A general dependence of the reorientation behavior on the gradient value was observed, concerning the apparent contact line behavior, the frequency and damping of the oscillations of the free surface center point, and the apparent contact angle. The behavior of the ullage pressure was found to follow the behavior of the contact line.

- by Nikolai Kulev
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- Mechanical Engineering, Aerospace Engineering, Cryogenics, Phase Transformations

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
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- Enhanced Oil Recovery, Electrokinetics, DLVO theory, Wettability Alteration

Prediction of intrinsic surface wettability from first-principles offers great opportunities in probing new physics of natural phenomena and enhancing energy production or transport efficiency. We propose a general quantum mechanical approach to predict the macroscopic wettability of any solid crystal surfaces for different liquids directly through atomic-level density functional simulation. As a benchmark, the wetting characteristics of calcite crystal (10.4) under different types of fluids (water, hexane, and mercury), including either contact angle or spreading coefficient, are predicted and further validated with experimental measurements. A unique feature of our approach lies in its capability of capturing the interactions among various polar fluid molecules and solid surface ions, particularly their charge density difference distributions. Moreover, this approach provides insightful and quantitative predictions of complicated surface wettability alteration problems and wetting behaviors of liquid/liquid/solid triphase systems

- by Hassan Mahani
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- Fluid flow in porous media, Micro-CT, Wettability Alteration, SPECIAL CORE ANALYSIS

In quantitative log interpretation it is common to assume that electrical conductivity is governed by Archie's law. The law is empirical and assumes a clean consolidated sand. Moreover, it also assumes that electrical conductivity is only present in the brine. Archie's law is parameterized by the cementation exponent denoted with m, and the saturation exponent denoted with n. The log interpretation requires estimation of n and m. Traditionally, petrophysical and electrical properties are obtained from laboratory experiments. In this study, we applied a direct pore-scale modeling approach to predict electrical and petrophysical properties across a wide range of rocks from the Norwegian Continental Shelf (NCS). The consistency of predicted properties was then verified against available datasets for the investigated samples.

- by Sina Rezaei Gomari
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- Petrophysics, Wettability Alteration

In this paper, contact angles in a rock/heavy-oil/steam system were measured to observe the degree of wettability alteration when unconventional chemicals were added to steam. A heavy-crude-oil obtained from a field in Alberta (27,780 cP at 25°C) was used in all contact angle measurements and the measurements were repeated on different types of substrates (quartz and calcite). In addition to this observation, surface tension tests between heavy-oil and steam were also conducted to study the change in interfacial properties. All measurements in this research were conducted at a range of temperatures up to 200°C in a high-temperature-high-pressure IFT device. In gaining a comprehensive evaluation of this mechanism, several impacting factors such as pressure, phase change, and type of rock were taken into consideration and evaluated separately. Different types of novel chemical additives—biodiesel, Switchable-Hydrophilicity Tertiary Amines (SHTA), nanofluids (dispersed SiO2 and ZrO2), ...

- by randy pratama
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- Materials Science, Reservoir Engineering, Biodiesel, Nanoparticles

When considering the wettability state during steam applications, we find that most issues remain unanswered. Removal of polar groups from the rock surface with increasing temperature improves water-wettability; however, other factors, including phase change, play a reverse role. In other words, hot water or steam shows different wettability characteristics, eventually affecting the recovery. Alternatively, wettability can be altered using steam additives. The mechanism of this phenomenon is not yet clear. The objective of this work was to quantitatively evaluate the steam-induced wettability alteration in different rock systems and analyze the mechanism of wettability change caused by the phase change of water and by chemical additives. Heavy oil from a field in Alberta (27,780 cp at 25°C) was used in contact-angle measurements conducted on quartz, mica, calcite plates, and rock pieces obtained from a bitumen-containing carbonate reservoir (Grosmont). All measurements were conducte...

- by randy pratama
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- Materials Science, Reservoir Engineering, Nanomaterials, Nanotechnology

Surfactant flooding is one of the common tertiary method to recover remaining oil in the reservoir, by reducing the interfacial tension (IFT) between two immiscible fluids nevertheless, current surfactant forms emulsion and difficult to achieve ultra-low IFT between the water and oil without addition of co-surfactant. In this research, two types of anionic lignosulphonate-based surfactants, Sodium Ligno-sulphonate (SLS) and Calcium Lignosulphonate (CLS) are chosen as co-surfactant. The main surfactant used in this project is the common anionic surfactant, Sodium Dodecyl Sulfate (SDS) at a fixed concentration of 4 mmol/l. Each type of co-surfactant with different concentrations (0.5%, 1.0%, 1.5% and 2.0 wt %) was mixed with 4 mmol/L of SDS at each test tube to create the surfactant solution. The result of the experiment showed that at 0.5 wt % for SLS and CLS surfactant solution, the contact angle of oil to surface lowered down with a reduction of 6 and 7 respectively. This indicate that the system will be more water-wet which the oil droplet will be less adhesive to the rock surface. In conclusion, by using the optimum concentration of 0.5 wt % lignosulphonate as co-surfactant is able to alter the wettability of rocks and it is recommended to test the biological-based co-surfactant at increasing temperature as an alternative to enhance the surfactant flooding performance which improves the oil recovery.

- by Bella Aziz
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- Wettability, Wettability Alteration