Performance Of Low-salinity Waterflooding Research Articles

Pore-Scale Simulation of the Effect of Wettability Alteration on Flow Transport Kinetics in 3D Natural Porous Media

Summary Wettability alteration commonly occurs in subsurface two-phase displacements, such as enhanced hydrocarbon recovery, hydrogen storage, and carbon dioxide sequestration. A comprehensive understanding of two-phase flow transport kinetics during wettability alteration in natural rocks is essential for optimizing these processes. To address this, a wettability alteration model induced by low-salinity waterflooding (LSWF) was implemented based on the volume of fluid (VOF) method and the compressive continuous species transfer (C-CST) method in the OpenFOAM platform, which integrates the pore-scale two-phase fluid flow and the advection-diffusion of species. Following validation against experimental data from existing literature, extensive direct numerical simulations (DNSs) were conducted in an actual 3D sandstone sample obtained by microcomputed tomography (micro-CT) images. The effects of the wettability alteration degree, wettability alteration model, and capillary number on dynamic salt dispersion and fluid redistribution are considered in simulation works. The findings indicate that a higher wettability alteration degree facilitates the release of more oil trapped in smaller pores toward the outlet, while the mobilized oil might become trapped again due to snap-off in larger downstream pores. Moreover, due to the presence of alternative flow pathways in the system, the backflowed oil induced by heterogeneous salinity distribution might not be effectively recovered. A faster wettability alteration rate enhances the performance of LSWF because of the rapid reduction of entry capillary pressure and the delayed negative effect of salt dispersion. In terms of the capillary number, a higher capillary number accelerates the diffusion of species to the three-phase contact line and reduces the occurrence of snap-off retrapping, thereby increasing ultimate oil recovery. This study contributes to a deeper understanding of the microscopic displacement mechanism during the wettability alteration processes, especially for LSWF, in 3D heterogeneous porous media.

Pore-scale investigation of low-salinity water flooding in a heterogeneous-wet porous medium

Low-Salinity Water Flooding (LSWF) is a technique aimed at modifying the interactions between rock and fluids particularly altering wettability and reducing interfacial tension (IFT). However, there remains limited understanding of how heterogeneous wettability and the presence of Initial Water Saturation (Swi) can impact the effectiveness of LSWF. This study contributes to a deeper understanding of LSWF mechanisms in the context of heterogeneous wettability, while also considering Swi. The simulations were conducted using OpenFOAM, employing a non-reactive quasi-three-phase flow solver that accounts for wettability alteration and IFT reduction during the mixing of Low-Salinity (LSW) and High-Salinity Water (HSW). A heterogeneous pore geometry is designed, and four distinct scenarios are simulated, encompassing both heterogeneous and homogeneous wettability conditions while considering the presence of Swi. These scenarios included secondary High-Salinity Water Flooding (HSWF), tertiary and secondary LSWF. Notably, the simulations reveal that secondary LSWF consistently yields the highest oil recovery across all scenarios, achieving recovery rates of up to 96.98 %. Furthermore, the presence of Swi significantly influences the performance of LSWF in terms of oil recovery, particularly in heterogeneous wettability conditions where it boosts recovery by up to 3.5 %, but in homogeneous wettability, it decreases recovery by nearly 26 %. These simulations also underscore the pivotal role played by the distribution of oil and HSW phases in profoundly affecting the outcomes of LSWF.

The impact of grain size heterogeneity on the performance of low-salinity waterflooding in carbonate formations

Low-salinity waterflooding (LSWF) is a proven enhanced oil recovery method for many target fields. The efficiency of this technique depends on both operational factors as well as reservoir settings such as heterogeneity. Micro-scale rock heterogeneity can critically affect the performance of LSWF as it governs the flow path of the injected water, oil-brine-rock contacts and trapping mechanisms, thus sweep efficiency. However, there exist lack of experimental data and detailed understanding of the effect of grain size heterogeneity on LSWF performance. To address this gap, a systematic series of coreflooding experiments were designed using artificial calcite core plugs to investigate the effect of micro-scale heterogeneity, such as grain size and grain heterogeneity, on oil recovery factor by high-salinity waterflooding (HSWF) and LSWF. High salinity formation water, seawater, and diluted seawater were used as injection brines. For this purpose, two relevant grain size ranges (a) from 38 to 75 µm and (b) from 75 to 125 µm were considered to fabricate homogeneous plugs. Heterogeneous core plugs were made by mixing (a) and (b) grain samples. The artificial cores were initialized with the formation brine and crude oil, and aged to restore wettability. Then a set of coreflooding experiments were performed using the mentioned brine samples, in both secondary and tertiary modes by considering a shut-in period.The results reveal that grains size (or micro-scale) heterogeneity has a significant negative impact on both HSWF and LSWF performance and reduces the oil recovery efficiency of HSWF by approximately 15%. This is primarily attributed to the bypassing and entrapment of oil in heterogeneous cores. Moreover, the results show that regardless of the grain size, LSWF in homogeneous plugs result in almost similar recovery factors. The key finding of this study is that LSWF in heterogeneous plugs is more effective and recovers almost 10% more oil compared to HSWF. This is attributed to wettability alteration as indicated by the reduction of water relative permeability endpoint and delay of breakthrough time. The improvement in oil recovery was consistent with the results obtained from the flotation tests and dynamic IFT measurements. However, although LSWF outperforms HSWF in heterogeneous cores, the ultimate recovery factor becomes less in these plugs. Besides, superior performance of secondary flooding was observed compared to tertiary mode for LSWF, especially in cores with heterogeneous grain sizes, leading to almost 10% higher recovery factor.The novel insights gained through this research help identify the proper targets for LSWF in terms of small-scale heterogeneity and can be potentially applied in other water-based EOR techniques.

Effect of oil chemistry on the performance of low-salinity waterflooding in carbonates: An integrated experimental approach

Chemical enhanced oil recovery (cEOR) relies on the interactions between surface-active components (SACs) of the oil-in-place and injected chemicals to induce favorable physico-chemical changes. This study investigates the effect of oil chemistry on the performance of chemically-tuned waterflooding (CTWF) in carbonate rocks. Coreflood experiments were performed at 90°C using four model oils, each containing a single SAC (acetic acid, decanoic acid, stearic acid or quinoline) to evaluate the effect of oil composition on oil recovery. Complementary characterization techniques including thermal gravimetric analysis (TGA), attenuated total reflectance (ATR-FTIR) and zeta potential (ζ) were used to understand the underlying rock-oil-brine interactions that take place during CTWF, including SAC adsorption to the rock surface, strength of adsorption, partitioning into the brine phase, and electrostatic interactions, respectively. Sessile drop contact angle measurements were also performed to quantify the wetting behavior of the different SACs. Results of this study show that oil chemistry plays a significant role in triggering different oil-brine-rock interactions. Characterization of those interactions is crucial to explain the discrepancies in oil recovery observed in the CTWF literature. In this study, differences in the underlying oil-brine-rock interactions translated into significant variation in oil recovery ranging between 8.9 and 43.9 % after one pore volume injected (PVI). ATR-FTIR results showed that in-situ soap generation was detected for oils with longer chain carboxylic acids, whereas no soaps were observed for oils that have acetic acid or quinoline. Combined with sessile-drop contact angle measurements, a relationship is observed between SAC partitioning into the brine phase and water-wetting behavior. Additionally, TGA measurements suggested that long chain carboxylic acids chemisorb to the rock surface, making wettability alteration to a less oil-wetting state during CTWF more challenging, whereas intermediate chain carboxylic acids only physisorb leading to a more pronounced wettability alteration to a less oil-wetting state, ultimately yielding the highest recovery of ∼49.9 %. Finally, TAN was found to be an insufficient oil descriptor, where oils with the same TAN yielded different CTWF effects. Hence, a more robust oil analysis is crucial for more accurate prediction and modeling of CTWF behavior.

Impact of Brine on Disjoining Pressure and Rock Wettability of Oil, Brine, and Mineral Systems

The alteration of rock wettability is essential for improving the efficiency of low-salinity water flooding. However, the fundamental understanding of this process remains unclear. In this paper, an extended Derjguin–Landau–Verwey–Overbeek (DLVO) theoretical model was applied to study the effects of cation types, brine concentrations, and mineral types on rock wettability in an oil–brine system. The zeta potential was measured to analyze the electric double layer. The oil–rock contact angles were tested to evaluate the wettability. The disjoining pressure was also estimated to analyze the rock wettability changes. The divalent cation showed a greater ability to compress the electric double layer. The lower concentrations of cations led to a thicker water film, promoting the detachment of oil from the rock surface. Clay minerals showed a greater impact on the wettability of rocks than quartz. This study improves the fundamental understandings of alteration of wettability in brine, oil, and rock systems and elucidates the mechanisms of disjoining pressure effects on low-salinity water flooding while shedding some light on improving the performance of low-salinity water flooding.

Effect of Oil Chemistry on the Performance of Low-Salinity Waterflooding in Carbonates: An Experimental Workflow to Characterize Rock-Oil-Brine Interactions

Effect of Oil Chemistry on the Performance of Low-Salinity Waterflooding in Carbonates: An Experimental Workflow to Characterize Rock-Oil-Brine Interactions

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.

Triple-layer surface complexation modelling: Characterization of oil-brine interfacial zeta potential under varying conditions of temperature, pH, oil properties and potential determining ions

Low salinity water flooding (LSWF) is a popular enhanced oil recovery technique. Among factors that affect the performance of LSWF, geochemical interaction at the oil-brine interface and the associated enterokinetic properties plays a prominent role. This work presents a triple-layer surface complexation model for predicting the zeta potential of the oil-brine interface. We improve upon previous modelling studies by incorporating the effects of (1) temperature variation, (2) basic (-NH) oil surface group interactions (3) adsorption of sodium ions on outer and inner Helmholtz planes and (4) the presence of sulphate ions in brine. Model validation against published experimental data shows model accuracy between 66% and 99%. The model displays higher accuracies at lower salinities (making it particularly suited for LSWF applications), intermediate pH and higher total acid number. In addition, a correlation between (-NH) site density and total acid/base numbers is proposed. A sensitivity study performed utilising the developed model showed that higher sulphate concentration in the brine and elevated temperature makes the zeta potential at the oil-brine interface more negative. In addition, the sensitivity study indicates that a higher concentration of basic polar oil compounds is less favourable as it may result in less water-wet conditions in the reservoir.

Data-Driven Connectionist Models for Performance Prediction of Low Salinity Waterflooding in Sandstone Reservoirs.

Low salinity waterflooding (LSWF) and its variants also known as smart water or ion tuned water injection have emerged as promising enhanced oil recovery (EOR) methods. LSWF is a complex process controlled by several mechanisms and parameters involving oil, brine, and rock composition. The major mechanisms and processes controlling LSWF are still being debated in the literature. Thus, the establishment of an approach that relates these parameters to the final recovery factor (RFf) is vital. The main objective of this research work was to use a number of artificial intelligence models to develop robust predictive models based on experimental data and main parameters controlling the LSWF determined through sensitivity analysis and feature selection. The parameters include properties of oil, rock, injected brine, and connate water. Different operational parameters were considered to increase the model accuracy as well. After collecting the relevant data from 99 experimental studies reported in the literature, the database underwent a comprehensive and rigorous data preprocessing stage, which included removal of duplicates and low-variance features, missing value imputation, collinearity assessment, data characteristic assessment, outlier removal, feature selection, data splitting (80–20 rule was applied), and data scaling. Then, a number of methods such as linear regression (LR), multilayer perceptron (MLP), support vector machine (SVM), and committee machine intelligent system (CMIS) were used to link 1316 data samples assembled in this research work. Based on the obtained results, the CMIS model was proven to produce superior results compared to its counterparts such that the root mean squared rrror (RMSE) values for both training and testing data are 4.622 and 7.757, respectively. Based on the feature importance results, the presence of Ca2+ in the connate water, Na+ in the injected brine, core porosity, and total acid number of the crude oil are detected as the parameters with the highest impact on the RFf. The CMIS model proposed here can be applied with a high degree of confidence to predict the performance of LSWF in sandstone reservoirs. The database assembled for the purpose of this research work is so far the largest and most comprehensive of its kind, and it can be used to further delineate mechanisms behind LSWF and optimization of this EOR process in sandstone reservoirs.

The effect of carbonate rock wettability on the performance of low salinity waterflooding: an experimental approach

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

Pore-doublet computational fluid dynamic simulation of the effects of dynamic contact angle and interfacial tension alterations on the displacement mechanisms of oil by low salinity water

Using our recently developed model, for the first time in the literature, the effect of fluid/fluid and rock/fluid interactions on the performance of Low Salinity Waterflooding (LSWF, as an Enhanced Oil Recovery process) at pore-doublet scale is investigated. The model is incorporated into OpenFOAM and both the Navier-Stokes equation for oil/water two-phase flow and the advection-diffusion equation for ion transport (at both fluid/fluid and rock/fluid interface) are solved via direct numerical simulation (DNS).The model is validated against imbibition and drainage pore-doublet experiments reported in the literature, and then applied to investigate the sole effect of wettability alteration as well as its coupled effect with interfacial tension (IFT) variations on the redistribution and transport of phases within the model. Different degrees of contact angle alteration, different trends of IFT variations reported in the literature, as well as different injection scenarios (secondary or tertiary) are considered.Simulation results show that in the case of high salinity water flooding (HSWF), IFT (within the range of 30 to 5 mN.m−1) has very limited effect on the residual oil saturation of the investigated model. For the case of HSWF in the oil-wet pore-doublet model (contact angle = 140°), significant amount of oil will be trapped in the small pores of the model. This residual oil cannot be produced in the absence of wettability alteration, no matter how much the IFT be reduced during LSWF (even as low as 0.1 mN.m−1). However in the absence of any IFT variation (IFT = 10 mN.m−1), the residual oil ganglia can be displaced with the sufficient degree of wettability alteration (contact angles below or equal to 30°). Nevertheless, in the presence of adequate contact angle reduction, fluid/fluid interactions (different IFT variation) can affect the outcome of the enhanced oil recovery. The LSWF performance boosts under appropriate degree of fluid/fluid and rock/fluid interactions as it leads to the coalescence of the detached or partially detached residual oil blobs and progress of chasing water front in both small and large pores of the doublets towards the downstream of the model. The results confirm the importance of fluid/fluid interactions such as IFT variation on such coalescence and dynamic LSWF, especially in the case of secondary LSWF.

Effect of different low salinity flooding schemes and the addition of alkali on the performance of low-salinity waterflooding during the recovery of heavy oil from unconsolidated sandstone

Low salinity waterflooding (LSW) is a promising enhanced oil recovery process. The LSW advantage has been associated to changes in rock wettability toward a more water wet state. This study evaluated the effect of different flooding schemes on the performance of LSW in terms of production rate and incremental oil recovery from sand-pack systems. This work also investigated the main mechanism prompting sand wettability changes during LSW.Flooding Scheme-1 consisted of high salinity waterflooding, low salinity waterflooding, alkali aided low salinity waterflooding, and low salinity waterflooding. Flooding Scheme-2 consisted of low salinity waterflooding, alkali aided low salinity waterflooding, and low salinity waterflooding. Flooding Scheme-3 consisted of alkali aided low salinity flooding and low salinity waterflooding. The main mechanism causing wettability reversal was verified employing contact angle analysis, inductively coupled plasma spectrometry, and scanning electron microscopy.This new study reveals in a straightforward manner the effect of low salinity waterflooding schemes on both production rate and incremental oil recovery. LSW in secondary mode, as conducted in FS-2, expedited the oil production rate by 15% and increased the overall oil recovery by 20% relative to flooding schemes FS-1 and FS-3. Furthermore, this study determined that multi-component ionic exchange was the dominant mechanism for the reversal of sand wettability to a more water wet state.This paper provides new insights for heavy oil producers on the relevance of the flooding schemes during LSW and on the dominant mechanism for wettability alteration during the recovery of heavy oil from unconsolidated sands.

Detecting pH and Ca2+ increase during low salinity waterflooding in carbonate reservoirs: Implications for wettability alteration process

Wettability alteration appears to be an important physiochemical process during low salinity waterflooding (LSWF) in carbonate reservoirs. However, the leading factor(s) behind wettability alteration remains unclear. In particular, the relative contribution of calcite dissolution induced pH and Ca2+ increase has not been explicitly quantified. We thus hypothesized that the pH increase plays a significant role in the wettability alteration, whereas the increase of Ca2+ plays a minor role. To test this hypothesis, we performed a geochemical study and examined the effects of salinity level on calcite dissolution and pH increase against the recovery factor profile obtained from the literature. The calcite dissolution was evaluated by equilibrating different brines with calcite. The equilibrated pH and brine compositions were then to be employed to quantify the Ca2+ increase and calculate surface species and electrostatic force between oil-brine-calcite interfaces.Our results show that low salinity water (LSW) indeed triggers calcite dissolution, which induces the pH increase from 1 to 2 units, whereas only causes less than 10% increase of Ca2+ concentration in the low salinity water. Surface complexation modelling implies that Ca2+ concentration variation may not lead to significant chemical surface species variation on calcite surfaces, but the pH increase would play an important role on oil-brine interfaces especially for the oils with high base component (-NH+). Moreover, geochemical modelling shows that at least 5 times dilution of the original brine is required to obtain a pH increase from 6.5–7.0 to 8.0–8.5, which seems to be essential for triggering the wettability alteration. We argue that high salinity formation brines with the low initial pH (5.5 to 6.5), high basic component oils, and at least five-time dilution could be the three key favourable elements to trigger the low salinity effect in carbonate reservoirs. This work provides a practical framework to screen potential carbonate reservoirs and predict LSWF performance.

Thermodynamic modeling of the temperature impact on low-salinity waterflooding performance in sandstones

Low-salinity waterflooding has emerged as an innovative technique to improve oil recovery. Extensive research has been devoted to providing a better understanding of the mechanisms involved and to optimize its performance. Among those mechanisms, multi-component ion exchange mechanism explains the coordination of surface complexes in a way that highlights the essence of low-salinity waterflooding. However, the impact of temperature on low-salinity waterflooding is still poorly understood. We used surface complexation modeling to study both the oil/brine and mineral/brine interfaces up to a temperature of 150 ∘C. Given the heterogeneity of the oil interface, we studied three oil interfaces with varying total base number to total acid number ratios. It was determined that temperature is a critical factor in estimating the performance of low-salinity waterflooding. While temperature reduces the pH range at which low-salinity waterflooding yields positive effect for basic oil, it shifts the pH window at which low-salinity waterflooding has potentially negative results to lower pH values for neutral oil. In addition, the temperature magnifies the ability of low-salinity waterflooding to enhance surface potential. Our results support the need for conducting experimental work at the relevant reservoir temperature to evaluate the performance of low-salinity waterflooding.

Using nanofluids to control fines migration for oil recovery: Nanofluids co-injection or nanofluids pre-flush? -A comprehensive answer

This paper provides a comprehensive study to evaluate and optimize the effectiveness of nanofluids to both prevent fines migration and enhance oil recovery using different utilization approaches: nanofluids co-injection and pre-flush. To do that, 1) a comprehensive review of both laboratory experiments and field cases is adopted to confirm the effectiveness of nanoparticles to control fines migration. 2) A novel model of maximum fines retention concentration is then introduced to find out the physical mechanisms on how nanoparticles control fines migration. 3) Through matching with lab experiments, the physical behaviors of fines migration and attachment with the effects of different types of nanofluids are characterized, including fines attachment and straining rates, and breakthrough time of injected fines. 4) As a new criterion, mitigation index (MI) is defined to find out the more excellent performance of nanofluids pre-treatment that of nanofluids co-injection. 5) The pros and cons of fines migration on performance of low-salinity water flooding are discussed comprehensively, in this work, and the success of combining nanofluids with low-salinity water flooding is also confirmed to achieve more oil recovery. The outcomes of this work will help extend the applications of nanofluids in reservoirs suffering from problems of fines migration.

The Role of Sandstone Mineralogy and Rock Quality in the Performance of Low-Salinity Waterflooding

Summary Recent field applications and laboratory studies have recognized that low-salinity waterflooding (LSW) is a potentially effective technique to achieve sufficient recovery in sandstone reservoirs. Researchers have noted that the impacts of clay content, rock permeability, and pore-throat radius are still unclear on the performance of LSW. This paper reports the results of coreflood, zeta-potential, X-ray-powder-diffraction (XRD), X-ray-fluorescence (XRF), scanning-electron-microscope (SEM), nuclear-magnetic-resonance (NMR), and high-pressure-mercury-injection experimental investigations on these parameters. The main objectives of this work are to examine the performance of LSW by use of four sandstone rocks during secondary- and tertiary-recovery modes; to investigate the role of clay content, rock permeability, and average pore-throat radius on the performance of LSW; and to evaluate the effects of mineral type, brine salinity, cation type, and pH on the zeta-potential measurements. Zeta-potential measurements were conducted for rock/brine interfaces to determine the suitable injection brine for the used sandstone rocks. Various brines were used, including seawater (SW), 20% diluted SW, 0.5 wt% NaCl, 0.5 wt% MgCl2, and 0.5 wt% CaCl2. Then, a set of comprehensive coreflood tests were conducted with Bandera, Parker, Gray Berea, and Buff Berea outcrop sandstone cores. The coreflood experiments were conducted with 6- and 20-in.-length and 1.5-in.-diameter outcrop cores at 185°F. Oil recovery, pressure drop, and pH were observed and analyzed after each coreflood experiment. On the basis of the results attained, the Parker, Bandera, Gray Berea, and Buff Berea sandstone cores showed additional oil recoveries of 4.3, 9.2, 13.3, and 17.1% of original oil in place (OOIP), respectively, through the injection of low-salinity brine (5,000 ppm NaCl) as the secondary recovery mode. The average pore-throat radius (rock quality) has a higher effect in the performance of LSW than in high-salinity waterflooding (HSW) on the secondary recovery mode. The incremental oil recovery (microscopic) for the LSW increased from 4.3 to 17% when the average pore-throat radius (R35) of the core increased from 1.4 to 8.5 µm. The total clay content and the clay composition are not the main factors that influence the LSW performance. The distribution of the clays seems to be playing a significant role. The measured zeta potentials of kaolinite and montmorillonite particles in 5,000 ppm NaCl brine at 77°F and pH 7 were −26.5 and −29.4 mV, respectively. The zeta-potential values indicated a stronger negative charge on muscovite and albite minerals of −33.8 and −31.5 mV, respectively. Zeta-potential values indicated a less-negative charge on the chlorite and illite particles than the other minerals. It seems that chlorite and illite contribute to a smaller electrical-double-layer expansion than those of kaolinite, feldspars, montmorillonite, and muscovite. On the other hand, the zeta-potential values of calcite and dolomite particles are 1.0 and −4.5 mV, respectively. The presence of dolomite and calcite would decrease the effect of the low-salinity brine to improve oil recovery.

Laboratory Investigations To Determine the Effect of Connate-Water Composition on Low-Salinity Waterflooding in Sandstone Reservoirs

Summary Most previous low-salinity-waterflooding studies focused on injection-brine salinity and composition. The question remains: How do the salinity and composition of the reservoir connate water (CW) affect the low-salinity-waterflooding performance? The main objectives of this work are to evaluate the potential of low-salinity waterflooding (LSW) on the performance of oil-recovery improvement by use of Buff Berea sandstone and Bandera sandstone cores; examine the effect of the salinity of the reservoir CW; investigate the role of the cation composition (Na+, Ca2+, and Mg2+) of the reservoir CW; and study the effect of temperature and pore-throat distribution on the performance of LSW. In this research, 11 spontaneous-imbibition (SI) experiments and six coreflood experiments were performed. Two sandstone types (Bandera and Buff Berea) with different mineralogy compositions were used. Furthermore, ζ-potential measurements were conducted for oil/brine interfaces to investigate the interaction between brine and crude oil interfaces. In addition, coreflood experiments were performed to validate the SI results and examine the effect of the CW-salinity variation. The reservoir-CW composition had a dominant influence on the oil-recovery rate. The changes in the cation composition of reservoir CW (Ca2+, Mg2+, and Na+) showed a measurable change in the oil-production trend. Reservoir cores saturated with CW containing divalent cations of Ca+2 and Mg+2 showed higher oil recovery than cores saturated with monovalent cations (Na+). The results demonstrate that the SI produced oil ranging from 38 to 69% of original oil in place (OOIP) for high-permeability Buff Berea cores (164–207.7 md), whereas the produced oil of the low-permeability Bandera cores (31.1–39.2 md) ranged from 20 to 51.5% of OOIP at 77 °F and 14.7 psia. In all cases, a measurable ion exchange was observed, whereas there was no significant change in the pH value of the imbibition brine during the experiments. The ion-exchange effect was more pronounced than the pH effect in the low-salinity-waterflooding performance for Buff Berea and Bandera sandstone. The total oil recovery increased from 51.9 to 58.9% OOIP when the divalent-cation (Ca+2 and Mg+2) concentration of the reservoir CW increased from 709 to 12,210 ppm for injected-brine salinity of 500 and 5,000 ppm, respectively. On the other hand, increasing the monovalent-cation (Na+) concentration from 610 to 54,400 ppm resulted in a slight increase in oil recovery (2.3% of OOIP).

An Experimental Study of CO2-low Salinity Water Alternating Gas Injection in Sandstone Heavy Oil Reservoirs

Several studies have shown that oil recovery significantly increased by low salinity water flooding (LSWF) in sandstones. However, mechanism of oil recovery improvement is still controversial. CO2 that develops buffer in presence of water is expected as a deterrent factor in LSWF efficiency based on mechanism of IFT reduction due to pH uprising. No bright evidence in literature supports this idea. Here, a set of core floods including a pair of CO2 WAG and a pair of water injection tests are conducted and, the efficiency of LSWF and high salinity water flooding (HSWF) were compared for each pair. HSWF was followed by LSWF in tertiary mode. Results showed that not only CO2 does not deteriorate LSWF recovery efficiency, but also improves recovery. Since CO2-low salinity WAG showed best performance among types by constant pore volume injected. Positive results in both secondary and tertiary modes with Kaolinite free samples used here showed that Kaolinite release is not the critical phenomenon in LSWF brisk performance. Also different pressure behaviour of CO2 WAG processes in comparison with reported behaviour of LSWF proves that LSWF performance may not depend on how pressure changes through flooding.

Laboratory investigation on effects of initial wettabilities on performance of low salinity waterflooding

This paper presents investigation on the relationship between rock wettability and oil recovery with low salinity water injection as secondary recovery process. Coreflooding experiments have been performed at room conditions on Berea cores with four different wettabilities ranging from water- to oil-wet. Brines and n-decane were used as displacing and displaced phases, respectively. The results showed that, for all the salinities, oil recovery increased as wettability changed from water- to neutral-wet conditions. Further change in rock wettability from neutral- to oil-wet condition resulted in decreased oil recovery. It was also interesting to observe that oil recovery is higher for low salinity waterflood (LSW) as compared to high salinity waterflooding when implemented as secondary recovery process. Increase in pressure drop and hence decrease in effective permeability was also observed during LSW process in most of the cases considered.