Low Salinity Flooding Research Articles

A critical review of carbonate reservoir wettability modification during low salinity waterflooding

The nature of carbonate reservoirs promotes the adsorption of oil onto the rock surface hence making oil recovery a challenge even with the interventions of varied chemical EOR methods. Recently, low salinity water flooding has become of great interest since it is cost-effective and environmentally friendly. Although low salinity waterflooding has been highly investigated in sandstone reservoirs, it is not the same for carbonate reservoirs due to its complexities. Nonetheless, it has been proposed as a favourable technique to mobilise the trapped oil in carbonate reservoirs. Wettability alteration is regarded as the most accepted mechanism for low salinity flooding but has not been well understood making field scale applications doubtful. In this paper, we present a detailed review of the wettability alteration mechanisms in carbonate reservoirs during low salinity waterflooding. Parameters influencing wettability alteration in carbonates and the interactions that occur at the rock/brine/oil interface are also presented. The different methods utilised for wettability measurements during low salinity waterflooding are also reviewed including their drawbacks and advantages and recommendations. This will provide an improved understanding of the low salinity flooding application in carbonate reservoirs.

A Guide for Selection of Aging Time and Temperature for Wettability Alteration in Various Rock-Oil Systems.

Wettability alteration has been identified to be one of the important mechanisms to improve the microscopic recovery in many of the enhanced oil recovery (EOR) methods including polymer flood, surfactant flood, low salinity flood, microbial flood, alkaline flood, etc. Ensuring the oil-wet nature of the formation before flooding in the laboratory is necessary to study the efficiency of the EOR process, which targets microscopic recovery through wettability alteration. Nevertheless, altering the wettability depends on several parameters, such as aging time, aging temperature, core nature, oil properties, etc. Although several researchers investigated the effect of individual parameters on wettability alteration, the literature is scarce, and the question of what is the shortest and yet the most reliable aging time for ensuring wettability alteration for the specific rock-oil system at different temperatures remains unclear. This paper attempts to seek an answer to this question by compiling the relevant literature to find the effect of individual parameters such as different aging times, temperatures, oil compositions, and rock lithologies on wettability alteration. Results observed from data analysis showed different windows for aging conditions depending on the core sample lithology, initial wettability, and type of oil used. It was noticed that the higher the asphaltene content in the crude oil used, the lower the time and temperature that it takes to alter the sample wettability. Aging a sandstone core under 80 °C using crude oil with 11 wt % % asphaltene took 7 days to shift the core from strongly water-wet to neutral-wet. The same wettability alteration was achieved in 14 days when aging the sandstone sample at 90 °C using crude oil with 0.85 wt % asphaltene content. Generally, it was observed that the aging time decreased as the temperature increased. Moreover, as the sample has a lower initial water wettability condition, the time that it needs to be aged becomes higher. Results indicated that carbonates in general require less aging time to alter their wettability condition to oil-wet, around 1-7 days, compared with sandstones, around 14-21 days.

Enhancement of Oil Recovery in West Qurna-1 Carbonate Reservoir by Injecting Seawater

Seawater injection is a novel emerging technology for enhancing oil recovery in Middle East carbonate reservoirs. This paper investigated the mechanism of seawater injection in Mishrif formation for the West Qurna-1 oil field. The decline in the pressure of West Qurna-1 needs pressure support by water injection, where it is a supergiant oil field. This study is significant because seawater injection technology is considered a future technology in the south of Iraq for several reasons. One of these reasons is the scarcity of fresh water in the Middle East, especially in Iraq, and the second reason is the availability of seawater, which is close to Basra city. This paper aims to study the essential parameters that influence the oil recovery via sweater injection as well as the inherent mechanisms that help increase the oil recovery. Collected five core plugs from producing units of Mishrif formation, MB1, and MB2, having different petrophysics properties where the permeabilities ranged from 6 to 143 md. Two types of water are used formation water and seawater. We conduct core flood experiments on chosen carbonate core samples and formation water from Iraq's West Quran-1 carbonates. The common belief facts that low salinity flooding of oil recovery gives more producing oil for the same volume of water injected due to wettability alteration. The analysis of injected and producing water indicates that higher concentrations of SO4-2 and Ca-2 ions change the wettability of the rock to more water-wet. Consequently, the oil recovery increases by 10-15 % when using seawater, which is richer in these ions.

Theoretical and Experimental Study of Fine Migration During Low-Salinity Water Flooding: Effect of Brine Composition on Interparticle Forces

Summary The majority of sandstone reservoirs contain clay particles. When clay is exposed to low-salinity water, fine detachment and migration occur due to multi-ion exchange and electrical double layer (EDL) expansion. Fine migration due to low-salinity water enhances oil recovery while damaging injection and production wells. This research investigates the effect of clay particles' weight percentage (wt%), ionic strength, total dissolved solids, and the injection rate of the low-salinity water on fine migration. The interparticle forces of kaolinite-kaolinite and kaolinite-quartz systems in various mediums were determined. Ten quartz sandpacks containing 2, 5, and 10 wt% of kaolinite were made to simulate clay-rich sandstone reservoirs. Afterward, different brines (10 and 50 mM solutions of NaCl, CaCl2, MgCl2, and Na2SO4 salts as well as seawater and its diluted samples) were injected into these sandpacks with different scenarios. It was observed that the interparticle forces for both systems in the presence of 10 mM solutions of NaCl, Na2SO4, and also 50 mM NaCl are repulsive. Therefore, even by injecting the low flow rate of these samples (0.1 cm3/min), the total fine migration was observed leading to intense permeability reduction in high clay-rich sandstones. However, in the case of low clay-containing sandpacks, the magnitude of permeability starts to rise a while after getting imposed to fine migration. In the presence of brines containing 50 mM MgCl2 and CaCl2, seawater, and its five-times diluted sample, the interparticle forces were an attraction, and fine migration occurred under no condition. However, using other samples of low-salinity water, the interparticle forces in the kaolin-kaolin system were repulsive and attractive in the kaolin-quartz system. Therefore, the phenomenon of partial fine migration occurs while flooding. So, in low-clay sandpacks, fines migrated only in high rate injection. However, the fine migration was evident for sandpacks containing 10 wt% of clay particles even by low flow rate injection. In general, there is a trade-off between the intensity of fine migration and divalent cations concentration in flooding water. Eliminating these cations or using them at 10 mM concentration may result in total fine migration, which is beneficial for low clay-containing media but damages clay-rich ones strongly. A high concentration of these cations prevents fines from movement, eradicating low-salinity flooding advantages. However, using medium concentrations results in partial fine migration, and the intensity, in this case, depends on clay concentration and flooding rate.

The mechanistic investigation on the effect of the crude oil /brine interaction on the interface properties: A study on asphaltene structure

• The Asphaltene molecular Structure was determined by ATR and EDAX analysis. • the Asphaltene adsorption rate at the interface highly depends on the brine salinity. • compaction of the Asphaltene molecules Structure significantly affects the adsorption behavior of the Asphaltene. • The concentration of Asphaltene fraction in the crude oil has a key role in fluid–fluid interaction. • Asphaltene molecules accumulate at the oil-brine interface and perform the Asphaltene-ion-bound with the dissolved ions. Despite many attempts to study the interaction of fluids in low-salinity flooding, they do not examine the principles of interphasic transition phenomena. This study aims to provide a new understanding of liquid–liquid interactions during the low-salinity water interaction through a series of experiments on the oil, emulsion, and aqueous phase. Three samples of crude oils with different asphaltene concentrations and structures with known physical properties are in contact with different solutions. The brine pH, conductivity, and crude oil viscosity experiments before and after contacting the oil with brine showed that the heteroatom concentration and compaction of crude oil asphaltene fraction and the brine salinity affect the rate of the migration of crude oil polar component toward the interface. Moreover, the IFT measurement illustrated that interface interactions are affected by several parameters such as dissolved ion type, the concentration of the brine, and the concentration of the polar components in crude oil. The solubility of crude oil polar species such as naphthenic acids in the brine does not always increase by decreasing the salinity of the aqueous phase. To verify this important finding, UV–Vis spectroscopy and FTIR were performed on the brine and crude oils before and after in contact with each other.

The non-linear effect of oil polarity on the efficiency of low salinity waterflooding: A pore-level investigation

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

Pore-Scale X-ray Imaging of Wetting Alteration and Oil Redistribution during Low-Salinity Flooding of Berea Sandstone

Observations over a range of scales show that lowering the salinity of injected water can alter the wetting state of a rock, making it more water-wet. However, there remains a poor understanding of how this alteration affects the distribution of fluids over the pore and pore-network scale and how this wetting alteration leads to oil recovery. In this work, we observe how oil and brine redistribute in the pores of rocks in response to low-salinity flooding. We use X-ray μ-CT scanning to image tertiary low-salinity waterflooding in two Berea sandstone cores. The wetting state of one core is altered with exposure to crude oil. We characterize the wetting state of both samples using imagery of fluid–solid fractional wetting and pore occupancy analysis. In the unaltered rock, oil saturation, fractional mineral area covered by oil, and size distribution of oil-filled pores remain constant between high-salinity flooding and subsequent low-salinity floods. In contrast, in the altered sample, we observe a shift in the mineral area covered by oil after low-salinity flooding toward decreasing coverage, consistent with a change to a less oil-wetting state. This change is also reflected in the observed variation in fluid pore occupancy. The wetting alteration results in the redistribution of 22% of oil within the rock, but an additional recovery of just three percentage points. The success of low-salinity waterflooding depends on both a wetting alteration and a pore structure, which facilitates the production of mobilized oil.

Numerical Simulation of the Combined Effects of Low Salinity Water and Alkaline-Surfactant-Polymer Flooding

Low Salinity Water (LSW) and Alkaline-Surfactant-Polymer (ASP) flooding are emerging enhanced oil recovery methods that help recover oil from the reservoir after primary and secondary recovery processes. Experimental studies on LSW and ASP flooding have indicated potential in additional oil recovery. In this paper, numerical simulation was performed to study the combined effects of LSW and ASP flooding. A heterogenous reservoir initially saturated with oil and water was modelled using Eclipse. The wells were completed with an inverse five-spot pattern and the production life of the reservoir was taken to be five years. The results showed that LSW flooding using a salt concentration of 1 000 ppm achieved a higher oil recovery than conventional (high salinity) water flooding with a salt concentration of 35 000 ppm. The oil recovery for conventional water flooding was 59.5% and that of low salinity flooding was 64.1%. The overall oil recovery for LSW combined with alkaline, surfactant and polymer flooding were 64.1%, 70.5% and 62.6%, respectively. The model indicated an increase in overall oil recovery of 91% when alkaline, surfactant and polymer were combined and injected as the same slug as opposed to the injection of the chemicals individually. This was attributed to the synergy of the chemicals. The alkaline and the surfactant reduce the interfacial tension between the oil and water and the polymer improves the mobility ratio thereby increasing sweep efficiency.

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.

An investigation into the roles of chlorides and sulphate salts on the performance of low-salinity injection in sandstone reservoirs: experimental approach

Numerous studies have been carried out to ascertain the mechanisms of low-salinity and smart water flooding technique for improved oil recovery. Focus was often on brine composition and, specifically, the cationic content in sandstone reservoirs. Given the importance of the salt composition and concentration, tweaking the active ions which are responsible for the fluids–rock equilibrium will bring into effect numerous mechanisms of displacement which have been extensively debated. This experimental study, however, was carried out to evaluate the extent of the roles of chloride- and sulphate-based brines in improved oil recovery. To carry this out, 70,000 ppm sulphates- and chloride-based brines were prepared to simulate formation water and 5000 ppm brines of the same species as low-salinity displacement fluids. Core flooding process was used to simulate the displacement of oil by using four (4) native sandstones core samples, obtained from Burgan oil field in Kuwait, at operating conditions of 1500 psig and 50 °C. The core samples were injected with 70,000 ppm chloride and sulphates and subsequently flooded with the 5000 ppm counterparts in a forced imbibition process. Separate evaluations of chloride- and sulphate-based brines were carried out to investigate the displacement efficiencies of each brine species. The results showed that in both high- and low-salinity displacement tests, the SO4 brine presented better recovery of up to 89% of the initial oil saturation (Soi). Several mechanisms of displacement were observed to be responsible for improved recovery during SO4 brine displacement. IFT measurement experiments also confirmed that there was reduction in IFT at test conditions between SO4 brine and oil and visual inspection of the effluent showed a degree emulsification of oil and brines. Changes in pH were observed in the low-salinity flooding, and negligible changes were noticed in the high-salinity floods. These results provide an insight into the roles of chloride and sulphate ions in the design of smart “designer” water and low-salinity injection scenarios.

Insights into the mechanisms affecting water/oil interfacial tension as a function of salt types and concentrations

The interfacial tension (IFT) between oil and water impacts many industrial operations. For example, in low salinity flooding, water with optimal salinity is injected into an oil reservoir, to change the oil/water interfacial tension and fluid/rock interfacial energy to mobilize trapped oil and enhance the displacement of oil. Theoretical and experimental studies have shown that different ions can enhance or inhibit the production. To develop a fundamental understanding of IFT in these systems, particularly in the context of salinity and the ion-type effect, molecular dynamics simulations were used to probe the change in IFT with the salt types and concentrations. In agreement with experimental measurements, our results show that the oil/water IFT increases with increasing salt concentration, with the increase dependent on the salt species. The results revealed that the presence of divalent anions at the interface increases the electrostatic interactions, which leads to a smaller increase in the IFT compared to other salts. Moreover, the analysis showed that the increase in IFT is due to ion depletion near the interface. The water orientations at the interface and the bulk explain why this depletion occurs.

Using Low Salinity Waterflooding to Improve Oil Recovery in Naturally Fractured Reservoirs

Low salinity waterflooding is an effective technique to accelerate and boost oil recovery. The impact of this technique has been investigated widely in laboratories for various scales and rock typing, most of which have demonstrated a potential improvement in oil recovery. This improvement has been attributed to several chemical and physical interactions that led to a change in the wettability to become more water-wet, as well as a reduction in the residual oil saturation. Meanwhile, it is rare to find a discussion in the literature about the efficiency of low salinity flooding in naturally fractured reservoirs. Therefore, in this work, we investigate the potential advantages of this method in fractured reservoirs using numerical simulations. A new approach to estimate the weighting factor using a tracer model has been proposed to determine the brine salinity and, hence, its properties in the mixing region. We have also used the relative permeability curves as a proxy for any physical and chemical mechanisms which are not represented explicitly in the model. The simulation outcomes highlighted the advantage of low salinity waterflooding in fractured reservoirs. An increment in oil recovery by 10.7% to 13% of Stock Tank Oil Initially In Place (STOIIP) was obtained using the dual- and single-porosity model, respectively. Therefore, the low salinity waterflooding technique represents a promising low-cost, effective method in fractured reservoirs.

Salinity-dependent alterations of static and dynamic contact angles in oil/brine/calcite systems: A molecular dynamics simulation study

In this study, classic Molecular Dynamics (MD) simulations with established force fields were first performed to investigate the salinity effects on the static contact angle of a n-decane droplet immersing in water atmosphere within a calcite nanochannel to advance our microscopic understanding on low salinity flooding. By applying an external body force, dynamic contact angle of n-decane in water phase was also studied in the presence of various salt concentrations based on Non-Equilibrium MD simulation. The predicted n-decane static contact angles are around 59.68° ± 0.26°, which agree well with experimental results in previous studies. A reduction of the static contact angle of the nanodrop is observed with the increase of salinity, which implies an enhancement of surface hydrophilicity. Under flow conditions, the deformation of nanodrop, as evidenced by the centre of mass analysis, becomes faster by increasing the salt concentration. The recovery/mobility of the n-decane nanodrop is, however, still significantly restricted by the adsorption interaction between the substrate and n-decane phase, which may lead to droplet snapping off and/or breaking up into small droplets.

Pore-scale numerical simulation of low salinity water flooding using the lattice Boltzmann method

HypothesisThe change of wettability toward more water-wet by the injection of low salinity water can improve oil recovery from porous rocks, which is known as low salinity water flooding. To simulate this process at the pore-scale, we propose that the alteration in surface wettability mediated by thin water films which are below the resolution of simulation grid blocks has to be considered, as observed in experiments. This is modeled by a wettability alteration model based on rate-limited adsorption of ions onto the rock surface. SimulationsThe wettability alteration model is developed and incorporated into a lattice Boltzmann simulator which solves both the Navier-Stokes equation for oil/water two-phase flow and the advection-diffusion equation for ion transport. The model is validated against two experiments in the literature, then applied to 3D micro-CT images of a rock. FindingsOur model correctly simulated the experimental observations caused by the slow wettability alteration driven by the development of water films. In the simulations on the 3D rock pore structure, a distinct difference in the mixing of high and low salinity water is observed between secondary and tertiary low salinity flooding, resulting in different oil recoveries.

Barium Sulfate Scaling and Control during Polymer, Surfactant, and Surfactant/Polymer Flooding

SummaryBarium sulfate (BaSO4) scale is a serious problem that is encountered during oilfield production and has been studied mainly for fields undergoing waterflooding. Chemical enhanced oil recovery (cEOR) processes involve interactions between the injected brine and the formation brine, rock and oil. Very little work has appeared in the literature on how cEOR processes can influence the severity of the mineral scaling problem that occurs in the field and how this can be managed. This study investigates barium and sulfate coproduction behavior, the deposition of BaSO4 in the formation and in the producer wellbore, and its inhibition during polymer, surfactant, and surfactant/polymer (SP) flooding cEOR processes. To aid the cEOR economic decision, assessment of the impact of cEOR flooding type on both scale management and oil recovery is performed.Reservoir simulation has been used in this study, employing homogenous and heterogeneous two-dimensional (2D) areal and vertical models. Data from the literature are used to define the parameters controlling the physical and chemical functionality of anionic surfactant and partially hydrolyzed polyacrylamide (HPAM) polymer [e.g., oil/water interfacial tension (IFT), IFT, polymer viscosity, and SP adsorption]. Assessment is made of the minimum inhibitor concentration (MIC) required to control the scale that is predicted to occur due to the changes in brine composition induced by the water and chemical flooding processes. The expected retention and release of a phosphonate scale inhibitor (SI) during squeeze treatments in the production wells is modeled.The high viscosity and more stable HPAM polymer slug reduces the mixing between the injected and the formation brines, especially with low-salinity low-sulfate (SO42−) make-up brine, reducing BaSO4 scale precipitation in the formation, delaying and reducing the potential scale risk in the producer wellbore compared to normal waterflooding. During surfactant flooding, from an oil recovery perspective, the optimal phase type and salinity can be any of the three microemulsion (ME) phase types, depending on the system multiphase parameters. However, the scaling risk can be different to that in the waterflooding case, depending on the IFT, ME phase type, the injected salinity, and sulfate concentration. In SP flooding, low-salinity make-up brine is preferred to enhance oil recovery, and it also delays and reduces scale risk. The impact of the injection brine salinity, SO42− concentration, and changing brine composition due to ion reactions affects the produced water rates, the number of required squeeze treatments and MIC values over time. This, then, impacts the inhibitor retention and release, which influences the treatment volumes and cost required to control scale over field life. Considering the economic impact of cEOR flood type on both oil recovery and scale management, low-salinity SP flooding is demonstrated to be the most viable option, showing the highest positive net present value (NPV).The study shows that barium and sulfate coproduction and the evolving scale risk depend on the mobility ratio (which is determined by the injected brine and oil viscosities) on the oil/water IFT, on the level of chemical adsorption, and on the selected brine salinity. The severity of the scale risk is also impacted by the flood techniques used, with the extent of reservoir reactions having an effect on the MIC required to control scale and the squeeze treatment volumes required to maintain production after breakthrough.

Investigation of modified Water chemistry for improved oil recovery: Application of DLVO theory and surface complexation model

It is widely accepted that oil recovery during waterflooding can be improved by modifying the composition of the injected brine. A typical approach is diluting the formation water to a specific lower salinity. However, recent experimental studies report the adverse effect of formation water dilution on oil recovery for specific oil/brine/rock systems. The adverse effect depends on the interactions within the system and is more pronounced in carbonates. In this study, we investigated the effect of water composition on the performance of low salinity water injection by considering the complex interaction of oil, brine, and rock system.A surface complexation model (SCM) is developed to calculate the zeta-potential at oil and rock surfaces. Considering a water film between oil and rock and using DLVO theory, attractive/repulsive forces between oil/brine and brine/rock interfaces are calculated. Contact angle is predicted employing the augmented Young-Laplace equation. Our zeta potential calculations based on the SCM reproduced the experimental data of oil/brine and brine/calcite zeta potential measurements. Our contact angle calculations using the DLVO theory and the augmented Young-Laplace equation accurately estimated the dynamic trend of contact angle during low salinity flood. Modeling wettability alteration as a function of contact angle was sufficient to predict the low salinity effect. The developed model is implemented in a comprehensive compositional reactive transport simulator to validate the proposed approach.

Insights into the role of clays in low salinity water flooding in sand columns

Clays in sandstone are thought to be a key factor in low salinity (LS) water flooding. This study investigates the effects of quartz, kaolinite and illite in LS water flooding in synthetic sand columns as a function of temperature. Four chromatography columns containing different amounts of pure quartz sand, illite, and kaolinite (100% quartz sand; 95/5% sand/illite; 95/5 sand/kaolinite; and 95/2.5/2.5% sand/illite/kaolinite). The use of these synthetic columns gives full control over mineralogy. These columns were saturated with high salinity (HS) formation water with 0.01 M (M) sodium acetate and aged for a week at 70 °C. They were then flooded with waters (yes, the use of water to displace water) with various salinities at four different temperatures (25, 70, 90 and 120 °C). Effluent concentrations of Ca2+ and acetate (CH3COO−) and pH were measured. This is a novel experimental design, where formation water containing sodium acetate is flooded with waters of varying salinity to gain insight into LS flood performance and possible recovery mechanisms. The hypothesis pursued here is that the behavior of the acetate ion (attached to matrix minerals during the aging process and then released due to ionic exchange) in an LS flood would provide a valuable analog that would simulate the bonding of carboxylic acids in crude oils with reservoir matrix minerals (and subsequent desorption during LS flooding). Key results include the following: (a) Our hypothesis was correct—the use of Na acetate behaved analogously to carboxylic acid, giving useful insights; (b) The quartz-only column showed strong evidence (elevated pH, presence of Ca2+ and acetate in effluent) of ionic exchange due to LS flooding, showing that pure quartz is responsive to LS flooding and that clays are not absolutely needed; (c) Quartz plus kaolinite plus illite gave a slightly higher response than pure quartz so clays can play a role. Oil displacement results were also done for a pure quartz sand column, and this showed a strong response to the LS flood, confirming that clays are not absolutely needed.

Adsorption of silica nanoparticles and its synergistic effect on fluid/rock interactions during low salinity flooding in sandstones

Several research works have shown the potential of incremental oil recovery by low salinity water (LSW) injection. The research in this area has also shown that LSW interaction with rock’s mineral (sandstone and chalk) raises the potential for formation damage by produced fines. The objectives of this work are to address the adsorption of silica nanoparticles (NPs) on sandstone and their effect on fluid/rock interaction during LSW flooding. Isothermal static adsorption of NPs on sandstone minerals surfaces showed a higher adsorption affinity on quartz surface compared to kaolinite. This was also shown by scanning electron microscope images. The adsorption of NPs was enhanced by increasing salinity. To investigate the dynamic adsorption, a co-injection of about 0.033 g NPs slug with tracer (about 0.13 g of LiCl2) as a reference. The estimated irreversible adsorption of NPs in the berea flooding of core was about 35%. While estimated desorption of the flooded core was about 21.2%. Detailed mass balance analysis is included. It was observed that the adsorption/desorption processes of silica NPs are influenced by the pH wherein increased alkalinity favors NP desorption. NP adsorption on the mineral surface during combined LSW and NP flooding was shown to reduce mineral dissolution, ion exchange, loss of cementing mineral and reduced resistance to flow compared to LSW alone. Surface forces estimation showed that combining LSW with NPs reduced the repulsion between fines and berea. The work here demonstrated the synergistic effect of combining the two technologies of LSW and nanoparticles where the probability of formation damage in sandstone reservoirs is reduced.

Effect of Silica Nanoparticles on Fluid/Rock Interactions during Low Salinity Water Flooding of Chalk Reservoirs

The main objective of this work is to address the adsorption of Silica nanoparticles (NPs) dispersed in different brines on chalk surfaces and their effect on fluid/rock interaction. Isothermal static and dynamic adsorption on chalk are addressed here. Isothermal static adsorption showed increased adsorption of NPs at higher salinity. The tests were performed to cover wide range of injection scenarios with synthetic seawater (SSW) and low salinity water (LSW). The selected LSW composition here is based on 1:10 diluted SSW, which has shown to have superior performance compared to other ion compositions. The dynamic adsorption tests of NPs showed reduction of calcite dissolution of about 30% compared to LSW alone. That is, silica nanofluid hinders calcite dissolution i.e., has less effect on chalk matrix integrity which is a major concern in chalk reservoir, if low salinity is employed for enhanced oil recovery. Both scanning electron microscope images and pressure drop across the core during nanofluid injection indicated no throat blockage. Based on ion tracking and the monitored pH, the mechanism(s) for NP adsorption/desorption are suggested. The results from this study suggests a synergy wherein adding relatively small amount of silica NPs can improve the performance of low salinity floods.

Effectiveness of oil displacement by sequential low-salinity waterflooding in low-permeability fractured and non-fractured chalky limestone cores

Low-salinity waterflooding has been recognized as a method of enhancing oil recovery in low-permeability reservoirs. This method is relatively inexpensive and can be easily implemented in the field. Various mechanisms of low-salinity flooding have been proposed including interfacial tension reduction, wettability alteration (cation exchange), change in pH (increase), emulsion formation, and clay migration. Hydraulic fracturing has been known as a technique of stimulating hydrocarbon flow from low-permeability matrix into wellbores by creating high-conductivity fractures. The objective of this study is to evaluate the effectiveness of sequential low-salinity brine flooding process to enhance oil recovery in low-permeability fractured and non-fractured chalky limestone core samples. The low-salinity waterflooding tests were conducted with synthetic brines of five different salinity concentrations, namely, 157,662, 72,927, 62,522, 6252, and 1250 ppm. The properties of these brines have been thoroughly investigated in the laboratory. The crude oil and chalky limestone core samples, permeability range between 0.01 and 1.2 millidarcy, were gathered from a selected oil field in United Arab Emirates. When used as an opening move in a three-stage sequential brine flooding (SW/10→SW/50→SW 6xSO4− 2), sea water diluted ten times at 6252 ppm (SW/10) has been found to yield the highest oil recovery in fractured and non-fractured tests at the prevailing reservoir conditions, of 82.64 and 76% of OOIP, respectively. In all sequential brine flooding scenarios tested, sea water with sulfate concentration spiked six times (SW 6 × SO4− 2) only slightly increased oil recovery. The highest observed incremental recovery with sulfate spiking was 2.083% of OOIP. The effectiveness of oil displacement by sequential brine flooding has been attributed to mineral dissolution and fines migration which resulted in a favorable wettability alteration. This postulation of flow mechanism is confirmed by introducing a “flow resistance index” concept and measurements of key properties of the injected and effluent brines of each stage of the attempted sequential brine flooding scenarios. Results of this study could be consulted when selecting most efficient EOR method to develop tight carbonate oil reservoirs in the UAE and worldwide.