Low Salinity Effect Research Articles

Preliminary experimental study of low salinity effect on organic polar compounds desorption in Hassi Messaoud field-Algeria

Low salinity water (LSW) injection is a well-recognized enhanced oil recovery method that has proved to increase oil recovery. Despite its simple implementation and low cost, no experimental investigations have been reporting its application in Algeria’s oil fields. The present work investigates the impact of LSW injection and identifies the role of organic polar compounds on oil trapping in Hassi Messaoud oil field. The study involves adsorption/desorption experiments using acid/amine organic polar compounds dissolved in non-polar refined oil while employing rock drilling cuttings. Subsequent validation of desorption data is performed by employing crude oil in both Amott tests and micro-model displacement tests using various water salinity ranges. It was evident that at water salinities ranging from 1000 to 2000 ppm, the interfacial tension decreased to 10−2 mN/m, leading to favorable rock wetting behavior and increased oil recovery of 9.18% and 20.07% for amine and acid compounds, respectively. The wettability alteration mechanism was proposed as the main contributor since the actual interfacial tension of natural surfactant might not significantly impact oil recovery. The implementation of LSW injection in Algerian fields presents fresh prospects for future enhanced oil recovery projects.

Mechanism analysis of injection technique of water composition modification for enhanced oil recovery

ABSTRACT By adjusting the composition of injection water, including ionic type and strength, the goal of enhance oil recovery rate can be achieved. However, there is no clear understanding of which factor, ionic type or strength, has a greater impact. In this paper, based on the formation water of the offshore G oilfield, various brines with different ionic strengths and types were prepared. By measuring the zeta potential of rock powder and oil droplets, three-phase contact angle, interfacial tension between oil and water, emulsification properties of brines, and film strength of oil-water interface, the variation rules of the core wettability and emulsification performance of brine were systematically analyzed when the ionic strength and ionic type were changed. The experimental results showed that ionic strength has a greater impact than that of ionic type. For the oil-water-solid (rock) system of the G oilfield, an ionic strength of 82 mM/kg is the threshold for low salinity effect. Reducing ionic strength resulted in an increase in the hydrophilicity of rock and the ability of water flooding to emulsify oil droplets, which contribute to the improvement of oil displacement efficiency. Theoretically, water flooding to enhance oil recovery can be achieved by only reducing the ionic strength. This understanding was verified by dual polarization interferometry (DPI) experiments and low-field nuclear magnetic resonance experiments, which showed that reducing the salinity of the injection water from 42,000 mg/L (ionic strength of 820 mM/kg) to 4200 mg/L (ionic strength of 82 mM/kg) enhanced the oil recovery by 7.9%.

Investigating the low salinity effect in a sandstone reservoir through electro-kinetic potential analysis

This study employs electro-kinetic potential measurements to predict the low salinity effect in a sandstone reservoir. Through comprehensive investigations utilizing Zeta potential, interfacial tension, FTIR spectroscopy, and contact angle measurements, valuable insights were obtained. Positive zeta potentials for Ethanoic-dodecane oil (+9.34) and Crude oil (+14.31), along with decreasing zeta potential values with decreasing NaCl and CaCl2 concentrations, indicated core aging and the adsorption of organic compounds. Wettability alteration and reduced contact angles further confirmed aging-induced changes. Negative Oil/Brine Zeta potentials and trends in interfacial tension supported the presence of the low salinity effect. This study enhances our understanding of low salinity effects in sandstone reservoirs by characterizing electro-kinetic potentials, wettability alterations, and interfacial tensions. It highlights the potential of electro-kinetic potential measurements as a predictive tool for evaluating the low salinity effect, enabling a more comprehensive assessment of its impact on reservoir performance.

Experimental and theoretical investigation of the impact of crude-oil on the wettability behavior of calcite and silicate due to low salinity effect

Wettability alteration is recognized as the main responsible mechanism for enhanced oil recovery during low salinity water flooding (LSWF) in both carbonates and sandstones. However, there is still a lack of understanding about the possible role of oil type on rock wettability alteration during LSWF. In the current study, contact angle (CA), interfacial tension (IFT), and zeta potentials for both oil/brine and rock/brine interfaces are measured for rock/brine/crude oil systems in a wide range of salinity of seawater. Two different crude oil samples and both calcite and silicate as good end-members of carbonate and sandstones are investigated. For oil A, the CA decreases with brine dilution; however, for oil B, the CA showed almost the opposite trend vs. salinity. The increased water-wetness of silicate compared to calcite surface was more highlighted in lower salinity. The results of zeta potentials showed that diluting seawater (SW) reduced the zeta potentials of rock/brine and oil/brine in all systems. The changes in zeta potential suggest that more dilution shall lead to more water-wetness, which is not in agreement with the CA behavior of two minerals in the case of crude oil B. Based on the augmented Young-Laplace equation, it was demonstrated that there is a good correlation between the IFT and the wettability, especially for calcite minerals. To shed light on the competition between the IFT and the EDL force, a comprehensive model was created to predict the CA results by coupling the surface complexation model (SCM), the DLVO theory, and the Young-Laplace equation. The coupled model successfully predicted the experimental contact angle for both crude oil and rock samples. Analyzing the disjoining pressure curves showed that due to the attractive EDL forces of calcite rocks, the oil/brine IFT solely controls the calcite wettability behavior with salinity. However, for silicate substrates, the high repulsive EDL forces are the main reason for the rock water-wetness at low salinity brines.

A mechanistic study of low salinity water-based nanoparticle-polymer complex fluid for improved oil recovery in sandstone reservoirs

Low salinity water flooding has gained tremendous attention in these days due to its cost-effectiveness and environment-friendly nature. Fine tuning of physico-chemical properties of low saline water by addition of suitable chemicals and nanoparticle (NP) can increase the oil recovery significantly because of synergistic effects. In this study, an attempt has been made to explore the benefit of adding nanoparticle and polymer into low salinity water (LSW) for increased oil recovery. Two complex chemical slugs were prepared with formation water (FW) and LSW as base fluids consisting of different concentrations of polymer and NP. The target viscosity for maximum sweep efficiency was estimated through the total minimum relative mobility concept. The rheological studies of the complex chemical slugs revealed that the addition of NP into polymer solution increased the viscosity significantly because of formation of macromolecular structure. It has been observed that a lower concentration of polymer is required to reach the target viscosity in LSW than FW. The benefits of low salinity effects over high saline formation water are evidenced by the reduction of interfacial tension (IFT), which is further reduced by addition of NP. A low IFT is always desirable for enhanced oil recovery. Contact angle showed a decreasing trend with FW, LSW and Nano fluid solutions respectively but presence of polymer in the slugs shows reverse effect on contact angle. LSW showed higher recovery as compared to FW in secondary recovery stage due to different reported mechanisms. Injection of LSW based complex fluid showed incremental recovery of 13.3 % of OOIP as compared to LSW and 22.0 % of OOIP as compared to conventional FW flooding in secondary stage. Synergistic effect of NP and polymer to form a complex macromolecular structure through hydrogen bonding and low salinity effect led to the improved oil recovery.”

Insights into the Effects of Pore Structure, Time Scale, and Injection Scenarios on Pore-Filling Sequence and Oil Recovery by Low-Salinity Waterflooding Using a Mechanistic DLVO-Based Pore-Scale Model

Summary Despite the proven advantage of the low-salinity waterflooding (LSWF) technique, mechanistic understanding of the underlying phenomena at pore-scale remains uncertain. Hence, the corresponding models have limited predictability. In this study, wettability alteration via electrical double-layer (EDL) expansion is captured in a pore-scale model using a multispecies, multiphase computational fluid dynamics simulator. A combination of a pore-doublet and snap-off model is used to evaluate the low-salinity effect (LSE) in two geometries with different pore-throat size distributions. Contact angle is calculated intrinsically within the model using the concept of disjoining pressure through the implementation of the Derjaguin-Landau-Verwey-Overbeek (DLVO) theory and augmented Young-Laplace equation. The results illustrate that even in a simple pore structure, various pore-filling sequences and recoveries are obtained based on the pore geometrical factors, time effects, backward mixing, and injection scenarios. Secondary LSWF results in higher ultimate oil recovery since both small and large pores are accessible to flow and breakthrough is delayed, giving more time for more efficient displacement. Regarding the pore-throat geometry, the case with larger pores connected via larger throats generally exhibits higher ultimate recoveries. However, the geometry with larger pores connected by small throats results in higher incremental recovery via tertiary LSWF. Moreover, an optimal time scale exists in secondary LSWF due to the snap-off phenomenon, while faster LSE results in higher recovery in tertiary mode. The proposed model is capable of mechanistically capturing and predicting LSE and its subsequent flow dynamics, which exhibits a higher recovery factor by LSWF compared to the commonly used linear wettability model. Thus, this approach improves the predictive capability of the previous models as it does not require contact angle data and arbitrary interpolation schemes.

Toward low-salinity waterflooding predictive capability development in carbonates for fast screening of oil-brine-rock candidates

Despite numerous studies on the low-salinity waterflooding (LSWF) technique, a robust predictive capability has not yet been established. Predictive capability development is essential to reduce costs and time during the early screening or prioritization of candidate fields for LSWF in the opportunity realization process (ORP). This study aims at proposing a set of screening methods that offer the best LSWF predictive capability for various crude oil-brine-carbonate rock systems. In this regard, the robustness of different methods for predicting oil recovery factor (RF) from core-scale spontaneous imbibition (SI) experiments in carbonate rocks was investigated here. The relevant small-scale screening methods were divided into two distinct categories. The first category includes methods based on rock/fluid interactions: wettability assessment based on flotation and contact angle measurement, and geochemical assessment to identify mineral dissolution (and pH change). The second group includes methods based on probing fluid/fluid interactions: oil-brine interfacial tension (IFT) and viscoelasticity, and micro-dispersion formation. The most common types of carbonate rocks, including dolomite, limestone, and chalk, were used to comprehensively evaluate the response of each carbonate rock type to brines of different salinities. Each rock type could be distinguished with its particular microscopic texture, pore-size, grain type, and carbonate mineral structure. According to the SI results, oil recovery strongly depends not only on brine salinity but also on the rock type. The oil RF for Indiana limestone was found to be higher than that for other rock types but showed less sensitivity to the degree of dilution. Additionally, RF from dolomite and chalk plugs showed the most and the least sensitivity to the degree of brine dilution, respectively. We introduced a brine efficiency index based on the SI results to compare the results for different rock types and salinities. The results of the systematic tests performed here showed that variation of IFT and viscoelasticity (expressed as phase angle) with brine salinity reduction was neither significant nor monotonic, and did not correlate with the brine efficiency index. Also, minor/negligible mineral dissolution was observed upon brine-rock contact. On the other hand, wettability results based on contact angle measurement and flotation, as well as microdispersion results strongly correlated with the brine efficiency index over a wide range of brine salinities, which indicates these techniques can quickly predict the potency of a system toward low salinity effect (LSE). It is hypothesized, therefore, that the techniques which involve rock explicitly would be more robust because they capture the rock-type dependency of LSE too. The findings from this study can be used for quick screening of the candidate formations for LSWF, before performing the costly and time-intensive special core analysis (SCAL) experiments. The data provided by this research can also enrich the SCAL data bank toward developing robust data-driven predictive models.

Pore structure and wetting alteration combine to produce the low salinity effect on oil production

Low salinity water flooding is a promising enhanced oil recovery technique that has been observed, in experiments over a range of scales, to increase oil production by up to 14% in some systems. However, there is still no way of reliably predicting which systems will respond favourably to the technique. This shortcoming is partly because of a relative lack of pore scale observations of low salinity water flooding. This has led to a poor understanding of how mechanisms on the scale of micrometres lead to changes in fluid distribution on the scale of centimetres to reservoir scales. In this work, we use X-ray micro-CT scanning to image unsteady state experiments of tertiary low salinity water flooding in Berea, Castlegate, and Bunter sandstone micro-cores. We observe fluid saturations and characterise the wetting state of samples using imagery of fluid–solid fractional wetting and pore occupancy analysis. In the Berea sample, we observed an additional oil recovery of 3 percentage points during low salinity water flooding, with large volumes of oil displaced from small pores but also re-trapping of mobilised oil in large pores. In the Bunter sandstone, we observed 4 percentage point additional recovery with significant displacement of oil from small pores and no significant retrapping of oil in large pores. However, in the Castlegate sample, we observed just 1 percentage point of additional recovery and relatively small volumes of oil mobilisation. We observe a significant wettability alteration towards more water-wet conditions in the Berea and Bunter sandstones, but no significant alteration in the Castlegate sample. We hypothesise that pore structure, specifically the topology of large pores impacted recovery. We find that poor connectivity of the largest pores in each sample is strongly correlated to additional recovery. This work is the first systematic comparison of the pore scale response to low salinity flooding across multiple sandstone samples. Moreover, it gives the first pore scale insights into the role of pore geometry and topology on the mobilisation of oil during low salinity water flooding.

Improved Oil Recovery from Carbonate Reservoirs by Tuning Injection Seawater Composition

In order to improve the adaptability of low-salinity waterflooding technology in some areas where freshwater resources are scarce, we aimed at implementing the low-salinity effect (LSE) in carbonate reservoirs through tuning injection seawater composition. LSE of ion tuning water (ITW) was verified by the results of core flooding tests, obtaining a water-free recovery factor of 50.7% and cumulative oil recovery of 77.2%. The micro mechanisms behind it were revealed via direct force-measuring and Zeta parameter (Zetap) measuring. Our results are expected to provide a new LSW strategy via tuning injection seawater composition in the case of carbonate reservoirs.

Drivers of Low Salinity Effect in Carbonate Reservoirs Using Molecular Dynamic Simulation

• Molecular dynamic simulation of calcite-oil-brine system reveals that monovalent ions are settled at calcite-brine interface. • The time-dependent evolution of the mass density profile demonstrates oil detachment from the calcite mineral. • The extension of the charge density profile coincides to the detachment of oil from the calcite surface. • The MD results show that an electrical double layer (EDL) is formed at calcite-brine interface. • The extension of the charge density profile occure ofter the settling of the monovalent ions at calcite-brine interface. Low salinity water (LSW) flooding has yielded promising results in improving the enhanced oil recovery (EOR) techniques in sandstone and carbonate reservoirs. Despite various studies and advances, the main mechanism behind the oil displacement in the rock-brine-oil system is unclear. To get a better understanding of the governing mechanisms, we used the molecular dynamic (MD) method to simulate a system including calcite-brine-oil under two different scenarios. At T=300 K and T=360 K each scenario is completed during 40 ns using a canonical ensemble. The results show that all mono/divalent ions are hydrated initially. Furthermore, Na + , Cl − and H 2 O molecules reside close to the calcite surface and their positions show little change at different time steps. However, the position of divalent ions is dynamic depending on the simulation time steps. Ca 2+ , which is initially detected at 2.35 Å above the solid surface at T=300 K and T=360 K, migrates away by time. On the other hand, Mg 2+ and SO 4 2− which are invisible up to t = 16 ns even at the radius of 10 Å, move gradually toward the surface with time and consolidate their position after oil displacement. Namely, prior to oil displacement, a shift in Na + , Cl − and Ca 2+ locations is noticed, and the trend of double electric layer (EDL) is extended, which might be the cause of oil displacement. The findings of this study are applicable in the improvement of EOR technology, water resource treatment and contaminant transfer from geological systems, dealing with solid solutions such as ocean-soil systems.

Dynamics of electrostatic interaction and electrodiffusion in a charged thin film with nanoscale physicochemical heterogeneity: Implications for low-salinity waterflooding

The slow kinetics of wettability alteration toward a more water-wetting state by low-salinity waterflooding (LSWF) in oil-brine-rock (OBR) systems is conjectured to be pertinent to the electrokinetic phenomena in the thin brine film. We hypothesize that the nanoscale physicochemical heterogeneities such as surface roughness and surface charge heterogeneity at the rock/brine interface control further the dynamics of electrodiffusion and electrostatic disjoining pressure (Πel), thus the time-scale and the magnitude of the low salinity effect (LSE). In this regard, film-scale computational fluid dynamics (CFD) simulations were performed. The coupled Poisson-Nernst-Planck (PNP) equations were solved numerically in a thin water film confined between a solid surface and oil, both negatively charged. The solid surface is representative of sandstone (quartz/kaolinite) with patchwise physicochemical heterogeneity. The electrical properties of the oil are representative of a crude-oil sample. The OBR system was initially under chemical equilibrium with high salinity (HS) brine, then was exposed to low salinity (LS) brine. The time-scale of reaching chemical equilibrium under LS, and the spatio-temporal evolution of electric potential were investigated. We find that surface roughness (introduced by quartz patches on quartz surface) increases the diffusion time up to 3-fold due to increased tortuosity. However the effect of surface roughness and surface charge heterogeneity (introduced by kaolinite patches on quartz surface) on the effective diffusion coefficient (Deff) is minor. While surface roughness and surface charge heterogeneity affect the disjoining pressure (Πel) significantly, the influence of surface roughness on Πel is more pronounced under HS than LS condition. In contrast, the effect of surface charge heterogeneity is more appreciable under LS than HS. Our findings imply that the LS effect can be enhanced in rough, heterogeneously charged systems like clayey sandstone, although its magnitude depends on the charge density of the roughness and its variation with salinity. We introduce two scaling factors, namely the effective diffusion coefficient (Deff) and the retardation coefficient (ω), to upscale the nanoscale results to pore-scale and beyond.

Pore-scale processes in tertiary low salinity waterflooding in a carbonate rock: Micro-dispersions, water film growth, and wettability change

HypothesisThe wettability change from oil-wet towards more water-wet conditions by injecting diluted brine can improve oil recovery from reservoir rocks, known as low salinity waterflooding. We investigated the underlying pore-scale mechanisms of this process to determine if improved recovery was associated with a change in local contact angle, and if additional displacement was facilitated by the formation of micro-dispersions of water in oil and water film swelling. ExperimentsX-ray imaging and high-pressure and temperature flow apparatus were used to investigate and compare high and low salinity waterflooding in a carbonate rock sample. The sample was placed in contact with crude oil to obtain an initial wetting state found in hydrocarbon reservoirs. High salinity brine was then injected at increasing flow rates followed by low salinity brine injection using the same procedure. FindingsDevelopment of water micro-droplets within the oil phase and detachment of oil layers from the rock surface were observed after low salinity waterflooding. During high salinity waterflooding, contact angles showed insignificant changes from the initial value of 115°, while the mean curvature and local capillary pressure values remained negative, consistent with oil-wet conditions. However, with low salinity, the decrease in contact angle to 102° and the shift in the mean curvature and capillary pressure to positive values indicate a wettability change. Overall, our analysis captured the in situ mechanisms and processes associated with the low salinity effect and ultimate increase in oil recovery.

Atomistic insights into role of low salinity water on montmorillonite-brine interface: Implications for EOR from clay-bearing sandstone reservoirs

Low salinity waterflooding (LSWF) is considered as a potentially promising approach to improve oil production from petroleum reservoirs. Nevertheless, ambiguities about dominant mechanisms and influential factors controlling the wettability alteration on rock surface still remain elusive. To date, the main attention has been given to securitizing the impact of salinity, oil composition, rock surface characteristics, and cationic part of the brine, largely overlooking the impact of anionic components of the brine. However, this is of great importance and interest to clarify how the anionic component of salt can contribute to rock-brine interface characteristics. In this paper, we used Molecular Dynamics (MD) simulation technique to characterize the effect of anionic components of brine solution on intermolecular interactions at the montmorillonite-brine interface. Here, the emphasis was put on NaCl and Na2SO4 brine solution to compare the ionic behavior of Cl- and SO42- in terms of distribution adjacent to the clay surface, potential for ionic aggregation formation, and pairwise interactions over a salinity range of 2000 ppm to 70000 ppm. Results obtained from this research work show that anionic SO42- accumulate nearby the clay surface in the form of ionic aggregations with Na+ cations, compared to the Cl- anions, which are uniformly distribute over the clay surface. The strong propensity of SO42- towards Na+ reduces the possibility of hydration by water molecules, disintegrating the bridging role of Na+ to adsorb oil constituents onto the clay surface. Furthermore, the disparate adsorption of SO42--Na+ aggregation onto the clay slab hinders oil diffusion toward the surface. Finally, besides salinity, anionic components of brine solution have no effect on expansion of the electrical double layer (EDL), casting a shadow on this phenomenon as a driving factor of LSWI-EOR. The results obtained from this research work can further our understanding of clay-brine interaction which is a major mechanism behind low salinity effect in clay-bearing petroleum reservoirs.

Interplay between emulsion stability and wettability alteration: An application for water-based enhanced oil recovery methods

Low salinity waterflooding (LSW) is a popular enhanced oil recovery method, which is mainly grounded on rock wettability improvement. Nevertheless, according to recent studies, the application of LSW is accompanied by some practical challenges, such as the formation of unwanted water-in-oil (w/o) emulsions, which emphasizes the necessity for optimization of the injected brine composition. The present study aims to assess the simultaneous role of brine chemistry and its corresponding potential determining ions (PDIs) on rendering rock hydrophobicity and the formation of tight w/o emulsions. To this end, seawater (SW) and its dilutions combined with a number of ion-engineered solutions consisting of PDIs, namely Mg2+, Ca2+, and SO42- were used to perform a set of contact angle and emulsion stability experiments. The design of experiment (DoE) methodology was also used to optimize the brine chemistry for low salinity water injection based on the outcomes of the experiments. We found that lowering ionic strength of brine from 0.8 mol.L-1 down to 0.1 mol.L-1 provides favorable conditions to generate stable w/o emulsions, with a separated water volume (SWV) as low as 5% of the total initial water after one day of aging at 80 °C. Also, as to the dynamic contact angle results, reduction of brine’s ionic strength down to 0.1 mol.L-1 without ion-tunning improved the wettability alteration index (WAI) merely about 0.2. However, for the ion-tuned solutions, the presence of Mg2+ cations was found not to be in favor of the low salinity effect. Since not only does it cause a small change in the wetting state (WAI < 0.5), but it also boosts the emulsion’s longevity, markedly (SWV < 15%). Contrarily, the presence of SO42- in the brine solution appeared to be more promising because of its strong potential for rendering surface wettability and also reducing emulsion longevity (SWV greater than 50%). As to the presence of Ca2+ cations, results indicated more water-wet surfaces with the WAI of 0.8. Nonetheless, based on the SWV results, Ca2+ cations are prone to form stable emulsions, with SWV ranging from 30% to 5% of the total initial water. Finally, based on the optimization results from DoE, a brine composition in which the concentration of divalent cations (i.e. Mg2+ and Ca2+) is kept minimal and SO42- is the dominant divalent ions is highly likely to induce a unit desirability condition. Also, it was found that the presence of Mg2+ and SO42- in the aqueous phase significantly affects wettability alteration and emulsion generation processes. According to the findings of this study, both brine salinity and its ionic composition should be carefully formulated as they can direct the low salinity effect either in positive or negative ways by improving wettability or generating stable emulsions. The outcomes of the present study can serve as a method for optimizing the water-based enhanced oil recovery approaches.

Experimental investigation of low salinity water-flooding in tight chalk oil reservoirs

Chalk reservoirs, due to their high storage capacity and very low permeability, are one of the most interesting cases for reservoir engineering research on carbonates. They exhibit complex fluid-rock interactions because of their chemically active porous media. This study investigates the effect of brine composition, injection scenario, and temperature on oil recovery by low salinity water-flooding in chalk core samples from a Danish North Sea reservoir. The mechanisms governing oil-brine-rock interactions were also explored. Actual reservoir chalk core samples, without any open fractures, were selected using computed tomography analyses. These cores were saturated with representative fluids (crude oil and synthetic formation brine) and aged at reservoir conditions for approximately three weeks. The role of brine chemistry has been investigated through effluent analysis by ion chromatography, and results indicate that low salinity diluted seawater promotes rock-surface reactions if left to incubate for at least 48 h. Rock dissolution, observed through the monitoring of effluent ions, increased both with increase in temperature and decrease in brine salinity. The recovery curves show that formation water and diluted seawater produce significantly more oil (of the order of 10 % more) at the secondary stage compared to seawater. Additionally, there is also some indication of an effect of low salinity brine at the tertiary stage. These experiments were performed on reservoir materials and corresponding crude oil samples and provide new data on the low salinity flooding potential for chalk, and provide further evidence for the applicability of the low salinity effect in carbonates.

Effect of Total Acid Number and Recovery Mode on Low-Salinity Enhanced Oil Recovery in Carbonates

Summary Low-salinity water (LSW) flooding is an attractive enhanced oil recovery (EOR) option, but its mechanism leading to EOR is poorly understood, especially in carbonate rock. In this paper, we investigate the main reason behind two tertiary LSW coreflood tests that failed to demonstrate promising EOR response in reservoir carbonate rock; additional oil recovery factors by the LSW injection were only +2% and +4% oil initially in place. We suspected either the oil composition (lack of acid content) or the recovery mode (tertiary mode) was inappropriate. Therefore, we repeated the experiments using an acid-enriched oil sample and injected LSW in the secondary mode. The result showed that the low-salinity effect was substantially enhanced; the additional oil recovery factor by the tertiary LSW injection jumped to +23%. Moreover, it was also found that the secondary LSW injection was more efficient than the tertiary LSW injection, especially in the acid-enriched oil reservoir. In summary, it was concluded that the total acid number (TAN) and the recovery mode appear to be the key successful factors for LSW in our carbonate system. To support the conclusion, we also performed contact angle measurement and spontaneous imbibition tests to investigate the influence of acid enrichment on wettability, and moreover, LSW injection on wettability alteration.

Impact of reservoir geochemistry on low salinity waterflooding: Global sensitivity analysis

Low salinity waterflooding (LSW) has been receiving an increasing attention in the industry as it has several advantages over alternative strategies to enhanced oil recovery (EOR), i.e. i) outperforms conventional EOR methods in terms of additional oil recovery, ii) involves lower chemical costs, iii) it is environmentally friendly, and iv) requires a relatively simple field process implementation. We quantify low salinity effect (LSE) on oil recovery upon employing a mechanistic geochemical model under parametric uncertainty. Our ultimate goal is to characterize the impact of the reservoir rock and fluid properties on the performance of LSW. To this end, we propose a geochemical model of LSW built within a commercial compositional reservoir simulator. The model is designed to account for geochemical processes recently identified through experimental and pore-scale analyses, i.e. double layer expansion, multiple ion exchange and mineral dissolution/precipitation. The geochemical model outputs were first compared with two low salinity coreflood experiments reported in the literature and then applied to predict oil recovery under parametric uncertainty. Our study encompasses the effect of formation water ionic concentrations, rock mineralogy and reservoir temperature on LSW performance. Global sensitivity indices were calculated considering reasonable intervals of variability of the studied parameters. Our analysis focuses on the total oil recovery at three different time scales: 6 months (before water breakthrough), 2 years (after water breakthrough), and 10 years (the end of the injection). The results are discussed in the frame of quantitative screening criteria development, which is necessary to assess whether a given reservoir may be a promising candidate for LSW. Our results indicate that reservoir temperature is the parameter which demonstrated the most significant impact on the LSW performance. Ion concentration also displays a significant influence on oil recovery, and we identify different chemical species in carbonate and sandstone environments. On the contrary, mineral composition shows a limited influence on oil recovery. In particular, our results show that clay presence might be not essential for LSW to be effective in sandstone reservoirs. We discuss the impact of our results in the context of experimental design aimed at an improved constraining of LSW parameterization. Our study suggests that reservoir fluid composition (e.g., concentration of Ca2+, SO42− and Na+), in addition to reservoir temperature, should be prioritized in future experimental campaigns to better understand its influence on LSW under different reservoir and operation conditions.

Variability of the Red River Plume in the Gulf of Tonkin as Revealed by Numerical Modeling and Clustering Analysis

We study the daily to interannual variability of the Red River plume in the Gulf of Tonkin from numerical simulations at high resolution over 6 years (2011–2016). Compared with observational data, the model results show good performance. To identify the plume, passive tracers are used in order to (1) help distinguish the freshwater coming from different continental sources, including the Red River branches, and (2) avoid the low salinity effect due to precipitation. We first consider the buoyant plume formed by the Red River waters and three other nearby rivers along the Vietnamese coast. We show that the temporal evolution of the surface coverage of the plume is correlated with the runoff (within a lag), but that the runoff only cannot explain the variability of the river plume; other processes, such as winds and tides, are involved. Using a K-means unsupervised machine learning algorithm, the main patterns of the plume and their evolution in time are analyzed and linked to different environmental conditions. In winter, the plume is narrow and sticks along the coast most of the time due to the downcoast current and northeasterly wind. In early summer, the southwesterly monsoon wind makes the plume flow offshore. The plume reaches its highest coverage in September after the peak of runoff. Vertically, the plume thickness also shows seasonal variations. In winter, the plume is narrow and mixed over the whole water depth, while in summer, the plume can be detached both from the bottom and the coast. The plume can deepen offshore in summer, due to strong wind (in May, June) or specifically to a recurrent eddy occurring near 19°N (in August). This first analysis of the variability of the Red River plume can be used to provide a general picture of the transport of materials from the river to the ocean, for example in case of anthropogenic chemical substances leaked to the river. For this purpose, we provide maps of the receiving basins for the different river systems in the Gulf of Tonkin.

Fluid-Fluid Interactions Inducing Additional Oil Recovery during Low Salinity Water Injection in Inefficacious Presence of Clay Minerals

One the most promising Enhanced Oil Recovery (EOR) methods, Low salinity water injection (LSWI) has faced several critical challenges, of which understanding the underlying mechanism is still of utmost importance. Here, we combine traditional coreflood experiments with several analytical tools to gain an insight into the mechanism of additional oil recovery by LSWI. Two crude oil samples with contrasting propensities to form microdispersion were chosen for coreflood experiments in a clay-rich sandstone core. Microdispersion is a term denoting the spontaneous formation of separated water phases within the crude oil phase by surface-active materials such as asphaltenes and/or carboxylic acids contributing to additional oil recovery by wettability alteration and crude oil swelling. Investigating the reasons behind the different responses to tertiary LSWI, it appeared that clay is not a decisive factor for low salinity effect (LSE) as previously believed. Additionally, surface charge evaluations and ionic composition of effluents showed that electrical double layer expansion and multi-ion exchange (MIE) mechanisms are not primary contributors to LSE. Extensive investigation by FT-IR spectroscopy and water content measurements suggests the underlying mechanism associated with LSWI is microdispersion formation by acidic materials (i.e., carboxylic acids and/or carboxylic functional groups of asphaltenes). The performance of tertiary LSWI, in terms of additional oil recovery, agreed well with the propensities of crude oils toward microdispersion formation. Experimental findings obtained herein contribute to resolve uncertainties around the mechanism of LSWI and look at reservoir eligibility for use of this EOR method.

Pore-Scale Simulation of the Interplay between Wettability, Capillary Number, and Salt Dispersion on the Efficiency of Oil Mobilization by Low-Salinity Waterflooding

Summary Nonuniform mixing during low-salinity waterflooding (LSWF) is a function of the pore geometry and flow patterns within the porous system. Salinity-dependent wettability alteration (WA) changes the entry capillary pressure, which may mobilize the trapped oil depending on the flow regime and salt dispersion pattern. The complex interplay between the wettability, capillary number (NCa), and salt dispersion caused by pore-scale heterogeneity on the efficiency of LSWF is not well understood. In this paper, direct numerical simulations in a pore-doublet model (PDM) were carried out with OpenFOAM® (OpenCFD, Berkshire, UK) using the volume-of-fluid (VOF) method. Oil trapping and remobilization were studied at relevant NCa as low as 10−6 under different initial wettability states. Depending on the effective salinity ranges (ESRs) for the low-salinity effect (LSE), three WA models were implemented, and the effects of WA degree and salinity distribution on LSWF flow dynamics were investigated. The slow process of WA by means of thin film phenomena was captured by considering a diffuse interface at the three-phase contact line. Because of the pore structure of the pore doublet, only in nonwater-wet cases, oil is trapped in the narrower side channel (NSC) after high-salinity waterflooding (HSWF) and may be remobilized by LSWF. In strongly oil-wet cases, oil is recovered gradually by LSWF by means of a film-flow mechanism near the outlet. In moderately oil-wet cases, however, the entire trapped oil ganglion can be mobilized, provided that the entry capillary pressure is sufficiently reduced. The degree of WA, ESR, kinetics of WA, and the wettability of pore surface at the outlet are determining factors in the drainage of the trapped oil. The salt dispersion pattern in the flowing region [i.e., wider side channel (WSC)] controls the wettability distribution and the rate and magnitude of oil recovery from the stagnant region (i.e., NSC). The difference between the WA models is more apparent near the outlet, where the salinity profile is more dispersed. The ESR in which WA occurs determines the speed of the entry capillary pressure reduction and, thus, the recovery factor. In cases where WA occurs at a salinity threshold (ST), the highest recovery is obtained, whereas with the full-salinity-range WA model, the oil recovery performance is lowest. From the capillary desaturation perspective, it is found that the LSE becomes more pronounced when NCa is less than 10−5, and the dispersion regime is in the power-law interval. Because the adverse effect of salt dispersion in the flowing region is delayed, the LSE is intensified. For the simulations to be representative of the actual conditions in the porous medium, much lower NCa than currently used in many research works must be studied. Otherwise, the simulations may lead to over- or underestimation of the LSE. The synergetic or antagonistic effects caused by the interplay between viscous and capillary forces and dispersion may lead to total recovery or entrapment of oil, regardless of WA. Based on the pore geometry, initial wettability state, and balance of forces, the mobilized oil may flow past the conjunction (favorable) or in the backward direction (unfavorable) to the WSC and get retrapped. Successful drainage of oil from the pore system after WA is essential for observing incremental oil recovery by LSWF.