Low Salinity Enhanced Oil Recovery Research Articles

Effects of brine valency and concentration on oil displacement by spontaneous imbibition: An interplay between wettability alteration and reduction in the oil-brine interfacial tension

Brine fluids have recently been of high interest to enhanced oil recovery process in both academia and industry. Both diluted formation brines and specifically formulated brines were reported to improve crude oil displacement in porous rock, owing to either their bulk salinity or brine-type. Mechanisms for such an improvement were widely proposed, including microscopic interfacial phenomena: wettability alteration and reduction in the oil-brine interfacial tension (σ), although their synergistic or interlinked contributions were vaguely clarified. To elucidate insights into this “low-salinity” enhanced oil recovery, crude oil displacement by spontaneous imbibition was conducted in the current research with focus on the effects of brine valency and concentration. Monovalent (NaCl) and divalent (CaCl2) brines at elevated concentrations (10, 100, and 1000 mM) were examined as imbibing fluids. Changes in the three-phase contact angle and the crude oil-brine interfacial tension were also investigated. Imbibition results showed that NaCl brine at ‘suitable’ concentration (100 mM) displaced greater oil (95.8 %) than too-low (10 mM) or too-high (1000 mM) concentrations, and these monovalent brines displaced more effective than those of divalent CaCl2 due to an oil-wetting as a result of divalent ion bridging phenomenon. This echoes crucial influences of both brine valency and concentration. Since no direct individual contribution from either the contact angle or σ on the oil displacement was obtained, an interplay between these two parameters were thought to control. The imbibition results were a capillary-dominated process (capillary number < 2.1 × 10−6), re-confirmed by their correlations with the calculated capillary pressures and inverse Bond numbers. The findings revealed that in a given imbibition system a required σ is a wettability-dependent: water-wet system needs high σ to enhance a driving capillarity while oil-wet system prefers lower σ to weaken a resisting capillary force. Brine formula directly attributed to wettability and σ: NaCl brines secure water-wetting with high σ while CaCl2 brines reduced σ more effectively with an assured oil-wetting. Low-salinity enhanced oil recovery mechanism was thus found to be contributed from capillary effect, which was an interplay between the interfacial tension and wettability. Paring these two parameters by formulating imbibing brine to anticipate high oil recovery is crucial and of challenge.

Upscaling Low-Salinity Benefit from Laboratory Scale to Field Scale: An Ensemble of Models with a Relative Permeability Uncertainty Range

Summary The distribution of low-salinity benefit for an ensemble of models is required to evaluate low-salinity enhanced oil recovery (OREC) projects. To enable this, low-salinity pseudorelative permeability curves are required to estimate the benefit of low-salinity waterflooding at the field level. We present how the low-salinity benefit can be propagated through an ensemble of full-field models in which each simulation case could have a set of distinctive high-salinity pseudos. A 0.5-ft vertical resolution sector and its 10-ft upscaled counterpart are used. Relative permeability curves and the low-salinity benefit from corefloods are used in the high-resolution sector to create profiles. Pseudohigh- and low-salinity curves are generated for the upscaled sector by history matching high-salinity and incremental low-salinity profiles. Low-salinity benefit is typically measured from corefloods and the same benefit is often assumed at the field scale. Our results show that generating low-salinity curves for high-salinity pseudos using low-salinity benefit from corefloods slightly underestimates the true low-salinity benefit at field scale estimated from high-resolution models. This conclusion is consistent for two extreme relative permeability scenarios tested (i.e., a high-total-mobility unfavorable fractional flow and low-total-mobility favorable fractional flow). Including capillary pressure in high-resolution models was crucial. We would have come to another conclusion if we had not used capillary pressure in fine-grid simulation as approximately one-third of the benefit of low-salinity waterflooding was attributable to more favorable capillary pressure under low-salinity injection. We demonstrate how a set of high-salinity relative permeability data obtained from corefloods, which encompasses a range for fractional flow and total mobility, can be included in ensemble modeling appropriately and how low-salinity benefit could be estimated for such an ensemble. It is adequate to generate low-salinity curves for bounding high-salinity sets of curves. The bounding low-salinity curves can then be used to estimate low-salinity curve for any interpolated high-salinity curve. This workflow significantly simplifies the process of generating the distribution of low-salinity benefit corresponding to an ensemble of models which may be calibrated to limited history.

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.

Technology Focus: EOR Operations (November 2021)

As the discovery rate of new hydrocarbon resources decreases, the need for more-efficient enhanced-oil-recovery (EOR) processes increases. Unlike in the past, however, when the efficiency was defined in terms of maximizing the recovery factor (RF), the new interpretation of efficiency is based on optimizing the balance between RF and the reduction of carbon footprint. This is done through an integrated approach in which both surface and subsurface elements of the oil-production systems are used to determine energy efficiency and carbon footprint of a unit volume of oil produced by EOR methods. When choosing traditional EOR methods, new innovations may be needed to arrive at new injectant composition to reduce emissions or make the process more efficient. Adding chemicals to the injectant gas to improve the mobility ratio and increase the sweep efficiency is desirable. One example is the use of hydrogels. These are hydrophilic structures that swell when hydrated. Hydrogels are of interest in EOR because of their ability to respond to stimuli such as pH, temperature, light, and ionic strength. EOR methods that involve use of fresh water are also switching to alternative methods that reduce or remove its usage as part of water sustainability. The produced water could be treated properly to make it suitable for injection. Alternatively, polymers that are effective under high salinity or temperature could be used to deal with injecting saline water. For unconventional reservoirs, waterless fracturing techniques are progressing. Paper SPE 201609 discusses the application of a reversible hydrogel that can be added to the injected carbon dioxide (CO2) stream in order to make it a more-efficient injectant for EOR and, hence, create more opportunity for CO2 storage. Paper SPE 202809 deals with utility of new polymers that are suitable for injection into carbonate reservoirs under high-temperature and ultrahigh-salinity conditions. Finally, paper OTC 30437 discusses ways of mitigating safety risks associated with CO2 waterless fracturing in unconventional reservoirs as part of water sustainability as well as prevention of environmental pollution. Recommended additional reading at OnePetro: www.onepetro.org. SPE 200357 - Fundamental Investigation of Auto-Emulsification of Water in Crude Oil: An Interfacial Phenomenon and Its Pertinence for Low-Salinity EOR by Duboué Jennifer, TotalEnergies, et al. SPE 205118 - Experimental Design and Evaluation of Surfactant Polymer for a Heavy-Oil Field in South of Sultanate of Oman by Ali Reham Al-Jabri, Petroleum Development of Oman, et al. SPE 200256 - Chemical Enhanced Oil Recovery and the Dilemma of More and Cleaner Energy by Rouhi Farajzadeh, Delft University of Technology, et al.

SARA-Based Correlation To Describe the Effect of Polar/Nonpolar Interaction, Salinity, and Temperature for Interfacial Tension of Low-Asphaltene Crude Oils Characteristic of Unconventional Shale Reservoirs

Summary Oil/water interfacial tension (IFT) is an important parameter in petroleum engineering, especially for enhanced-oil-recovery (EOR) techniques. Surfactant and low-salinity EOR target IFT reduction to improve oil recovery. IFT values can be determined by empirical correlation, but widely used thermodynamic-based correlations do not account for the surface-activities characteristic of the polar/nonpolar interactions caused by naturally existing components in the crude oil. In addition, most crude oils included in these correlations come from conventional reservoirs, which are often dissimilar to the low-asphaltene crude oils produced from shale reservoirs. This study presents a novel oil-composition-based IFT correlation that can be applied to shale-crude-oil samples. The correlation is dependent on the saturates/aromatics/resins/asphaltenes (SARA) analysis of the oil samples. We show that the crude oil produced from most unconventional reservoirs contains little to no asphaltic material. In addition, a more thorough investigation of the effect of oil components, salinity, temperature, and their interactions on the oil/water IFT is provided and explained using the mutual polarity/solubility concept. Fifteen crude-oil samples from prominent US shale plays (i.e., Eagle Ford, Middle Bakken, and Wolfcamp) are included in this study. IFT was measured in systems with salinity from 0 to 24% and temperatures up to 195°F.

Deep-sea reverse osmosis desalination for energy efficient low salinity enhanced oil recovery

The decrease in the oil discoveries fuels the development of innovative and more efficient extraction processes. It has been demonstrated that Enhanced Oil Recovery (EOR, or tertiary recovery technique) offers prospects for producing 30 to 60% of the oil originally trapped in the reservoir. Interestingly, oil extraction is significantly enhanced by the injection of low salinity water into oilfields, which is known as one of the EOR techniques. Surface Reverse Osmosis (SRO) plants have been adopted to provide the large and continuous amount of low salinity water for this EOR technique, especially in offshore sites. In this article, we outline an original solution for producing low salinity water for offshore EOR processes, and we demonstrate its energy convenience. In fact, the installation of reverse osmosis plants under the sea level (Deep-Sea Reverse Osmosis, DSRO) is found to have significant potential energy savings (up to 50%) with respect to traditional SRO ones. This convenience mainly arises from the non-ideality of reverse osmosis membranes and hydraulic machines, and it is especially evident – from both energy and technological point of view – when the permeate is kept pressurized at the outlet of the reverse osmosis elements. In perspective, DSRO may be a good alternative to improve the sustainability of low salinity EOR.

A New Multiscale Computational Model for Low Salinity Waterflooding in Clay Bearing Sandstones

We develop a new multiscale model to compute effective properties such as relative permeability, contact angle and partition coefficients in low salinity enhanced oil recovery processes for two-phase flow in sandstones containing reactive surfaces of kaolinite clay. In this setting, we construct a three-scale approach which entails the local nanoscale description ruled by the electro-chemistry of a confined electrolyte solution containing Na+, $$Ca^{2+}$$ , $$H^+$$ , $$Cl^-$$ and $$OH^-$$ ions residing between bounded crude-oil droplets at residual saturation and clay substrate. Our analysis focuses on the case of surface complexation geochemical reactions between the ionic species of the invading water and the electrically charged kaolinite and oil–water interfaces. In this scenario, we construct a local electric double layer problem for the electric potential based on a non-symmetric Poisson–Boltzmann equation supplemented by nonlinear boundary conditions with the magnitude of the surface charge strongly dictated by the geochemical reactions. By invoking the local mechanical equilibrium of the electrolyte solution and solving numerically the nonlinear problem using the finite element method, we compute the local ionic profiles and reconstruct numerically the disjoining pressure and adsorption isotherms for each ionic species for a wide range of brine compositions and pH of the water phase. Furthermore, combining the disjoining pressure results with the Frumkin/Derjaguin wetting theory allows to compute the dependence of the contact angle on wettability, pH and salinity. Subsequently, the formal homogenization procedure is adopted to upscale the pore-scale flow and ion transport to the macroscale giving rise to a new Darcy scale coupled flow/transport model. The hyperbolic part of the nonlinear homogenized model is solved analytically in an 1D example of enhanced oil recovery.

Insights into Nanoscale Wettability Effects of Low Salinity and Nanofluid Enhanced Oil Recovery Techniques

In this study, enhanced oil recovery (EOR) techniques—namely low salinity and nanofluid EOR—are probed at the nanometer-scale using an atomic force microscope (AFM). Mica substrates were used as model clay-rich rocks while AFM tips were coated to present alkyl (-CH3), aromatic (-C6H5) and carboxylic acid (-COOH) functional groups, to simulate oil media. We prepared brine formulations to test brine dilution and cation bridging effects while selected concentrations (0 to 1 wt%) of hydrophilic SiO2 nanoparticles dispersed in 1 wt% NaCl were used as nanofluids. Samples were immersed in fluid cells and chemical force mapping was used to measure the adhesion force between polar/non-polar moieties to substrates. Adhesion work was evaluated based on force-displacement curves and compared with theories. Results from AFM studies indicate that low salinity waters and nanoparticle dispersions promote nanoscale wettability alteration by significantly reducing three-phase adhesion force and the reversible thermodynamic work of adhesion, also known as adhesion energy. The maximum reduction in adhesion energy obtained in experiments was in excellent agreement with existing theories. Electrostatic repulsion and reduced non-electrostatic adhesion are prominent surface forces common to both low salinity and nanofluid EOR. Structural forces are complex in nature and may not always decrease total adhesion force and energy at high nanoparticle concentration. Wettability effects also depend on surface chemical groups and the presence of divalent Mg2+ and Ca2+ cations. This study provides fresh insights and fundamental information about low salinity and nanofluid EOR while demonstrating the application of force-distance spectroscopy in investigating EOR techniques.

Oil and Water Interactions during Low-Salinity Enhanced Oil Recovery in Water-Wet Porous Media

The role of emulsions should be an important factor in additional oil recovery during low-salinity water flooding (LSWF); however, it has been rarely discussed in previous studies. In this study, t...

Study Investigates Smart Waterflooding in Sandstone Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 193238, “Investigation of Smart Waterflooding in Sandstone Reservoirs: Experimental and Simulation Study, Part 2,” by Hasan N. Al-Saedi, SPE, Missouri University of Science and Technology and Missan Oil Company; Ralph E. Flori, SPE, Missouri University of Science and Technology; and Alsaba Mortadha, Australian College of Kuwait, prepared for the 2018 Abu Dhabi International Petroleum Exhibition and Conference, 12–15 November, Abu Dhabi. The paper has not been peer reviewed. In this paper, the authors consider the effect of water chemistry on water/rock interactions during seawater and smart waterflooding of reservoir sandstone cores containing heavy oil. Oil recovery, surface-reactivity tests, and multicomponent reactive-transport simulation were conducted to understand smart waterflooding better. The authors determine that lowering magnesium-ion (Mg2+) concentration results in lower additional oil recovery, and that lowering calcium-ion (Ca2+) concentration leads to higher additional oil recovery. Introduction “Smart water” (SW) can be defined as a water engineered by manipulating the ionic composition (adding or removing ions) regardless of the resulting salinity. An upward pH shift has been reported in the literature during low-salinity (LS) and/or smart waterflooding. That upward shift modifies the wettability of sandstone, thereby increasing oil recovery. When high salinity is displaced by LS water, Ca2+ will be desorbed from the clay surface because ion exchange occurs between hydrogen (H+) and Ca2+ at the negative sites of the clay surface. The organic materials will be then desorbed from the clay because of the reaction between the protonated basic and the acidic materials with hydroxide. The authors’ investigations on free-clay sandstone provided a different insight into such reactions. The observations from chromatographic columns of quartz showed an increase in the acetate detachment from the quartz surface with a significant pH jump during LS waterflooding. The oil-recovery observations from the quartz column supported the proposed mechanism. Previous systematic laboratory works indicated that the abundance of Mg2+ in the formation water (FW) is more effective than Ca2+ for a higher LS enhanced-oil-recovery (EOR) effect. Conversely, the abundance of Ca2+ in the injected LS water has a larger effect on LS EOR. When Mg2+ was present in the LS water, no oil-recovery improvement occurred. Methodology Brines. Synthetic FW and SW were prepared by dissolving sodium chloride (NaCl), calcium chloride (CaCl2), and magnesium chloride (MgCl2) in deionized water. Crude Oil. A reservoir crude oil was de-livered from eastern Kansas from the Bartlesville sandstone reservoir. The crude oil had a viscosity of approximately 600 cp at ambient temperature. The density is 0.83 gm/cc at 20°C. Reservoir Rock Description and Core Preparation. Five Bartlesville sandstone reservoir cores were drilled from the original 3-in. diameter to a 1-in. diameter preserved core from eastern Kansas. The preserved reservoir sandstone cores were delivered with 3-in. diameter. The most abundant mineral was quartz, followed by clays.

From Atoms to Pre-salt Reservoirs: Multiscale Simulations of the Low-Salinity Enhanced Oil Recovery Mechanisms

The goal of this review paper is two-fold: bringing an updated survey on the literature of the proposed mechanisms behind the low-salinity enhanced oil recovery (EOR) and propose ways to model them based on simulations coupling atomic to reservoir scales. The low salinity water injection (LSWI) presents some advantages over other EOR techniques since it is a cost-effective method, has no inherent environmental damage and does not affect the subsequent stages of crude oil treatment and refinement. The LSWI is particularly interesting for exploration and production on pre-salt carbonate reservoirs. We couple the LSWI mechanisms with molecular modeling methodologies, addressing their use to describe the EOR via LSWI. From the molecular modeling, one can obtain parameters for the large-scale reservoir simulators, thus, improving their accuracy. Therefore, the molecular modeling approaches are complementary tools to optimize the EOR via LSWI. Among all the involved mechanisms on the LSWI, the wettability alteration is pointed out by several authors as the fundamental one, to explain the EOR. However, there are controversies related to its cause: salting-in effect, multi-component ionic exchange, pH alteration, electric double layer expansion, fines migration, limited release of particles and osmotic pressure are among the main proposals. In this sense, several molecular modeling techniques have been explored to foster theories that explain the possible mechanisms and optimize the oil production combining the molecular dynamics simulations and Ab initio calculations with reservoir simulators.

Combined microfluidics–confocal Raman microscopy platform for studying enhanced oil recovery mechanisms

AbstractTo study the mechanism of enhanced oil recovery, it is important to characterize the three‐dimensional spatial distribution of various chemical species, especially water and oil, and their evolution during the course of water flooding. For example, visualizing the (selective) removal of oil from clay or silica substrates by low salinity water can yield important insights. Here, we present a platform that uses a microfluidic device (to represent water flooding at the pore scale) in combination with confocal Raman microscopy. Distributions of oil, water, and minerals are resolved at submicrometer resolution upon flooding water with changing composition. Using glass and gibbsite to mimic sandstone and clay, and water containing divalent cations (Ca2+), we find that oil containing a fatty acid preferentially adsorbs on the gibbsite. Removal of the divalent cations leads to release of the oil droplet. This finding is consistent with the multiple ion exchange mechanism and underlines that the presence of clay is important for low salinity enhanced oil recovery. We expect that our platform will pave the road towards systematic screening of water flood compositions in more complex systems.

Technology Focus: EOR Modeling (January 2019)

Technology Focus As far as I am concerned, 2018 became the year I dealt with some aspect of enhanced oil recovery (EOR) every week. I had noticed that, in recent years, interest in bringing EOR to field operations had been growing everywhere. As operators and asset owners worked continually to increase efficiency in oil production, they all realized that part of efficiency improvement is increasing recovery factors. Everybody now is extremely focused on recovering more from the reservoirs they have. Of course, limited exploration and maturing fields are some of the motives behind that new attitude. Additionally, oil price is at a point now that allows for EOR but is still too low for exploration. Global interest in implementing EOR had a clearly positive outcome on the quality of the technical papers reviewed this year. All EOR schemes were covered superbly, and discussions were well advanced. Along with new insights for conventional EOR schemes, emerging EOR schemes such as low-salinity waterflooding and EOR for unconventionals were deliberated extensively. Enhancements in understanding how each EOR system works, leading to improvements in EOR modeling and forecasting, certainly will make future EOR projects more successful. We should add the effect of ever-growing cloud computation and the Internet of Things to the anticipated success of new EOR projects. The effect of those enablers is going to benefit EOR projects in every way, from better project design to improved field management. Finally, we are able to construct reservoir models that include all EOR-relevant aspects of the reservoir in all scales. Along with that, the physics for almost all EOR schemes are captured in EOR forecasting models. Practically limitless computer access also will play a significant role in ensuring the success of EOR field management. Selecting only three papers among so many good ones was a difficult task. The following papers will give you some feeling about the noteworthy advancements happening in EOR performance and modeling. While you are focused on EOR, please consider checking out the other great papers listed as recommended additional reading. Recommended additional reading at OnePetro: www.onepetro.org. SPE 189785 A Parametric Study on the Applicability of Miscible-Gases-Based EOR Techniques in Unconventional Liquids-Rich Reservoirs by Dheiaa Alfarge, Iraqi Ministry of Oil, et al. SPE 190250 Systematically Optimized Surfactant Formulation and Injection Design To Reduce Chemicals While Maintaining Performance by Gayani W.P. Pinnawala Arachchilage, Chevron, et al. SPE 190305 Diffusion-Dominated Proxy Model for Solvent Injection in Ultratight Oil Reservoirs by M. Cronin, The Pennsylvania State University, et al. SPE 191474 Application of Artificial Intelligence for Mechanistic Modeling and Probabilistic Forecasting of Hybrid Low-Salinity Chemical Flooding by Cuong Dang, Computer Modelling Group, et al. SPE 191530 An Equation of State To Model Microemulsion-Phase Behavior in the Presence of Cosolvents Using Average-Solubilization Theory by Soumyadeep Ghosh, Chevron, et al.

Composition in the Interface between Clay Mineral Surfaces and Divalent Cation Electrolytes.

The interfacial free energy of a solid, which determines its adsorption properties, depends on interactions between the surface and the fluid. A change in surface composition can completely change the behavior of the solid. Decades of work have explored adsorption and its effects at solid-fluid interfaces from the macroscopic perspective and using molecular modeling, so the concept of the electric double layer (EDL) is well established in the community. However, direct, molecular level, experimental observations of the composition within the interface region, and its change with time and conditions, are not abundant. We used cryogenic X-ray photoelectron spectroscopy (cryoXPS) to observe the composition in the clay mineral-solution interface region as a function of bulk solution composition, on illite and chlorite in MgCl2 and CaCl2 electrolytes, over a range of concentrations (1-125 mM), in situ, on vitrified samples. These samples were prepared from very thin smears of centrifuged wet paste that were instantaneously chilled to liquid N2 temperature. They preserved the adsorbed solution in its amorphous state, maintaining the location of the ions and water with respect to the solid, without the disruption that occurs during drying or the rearrangement that results as water crystallizes during freezing. With decreasing ionic strength, we could directly monitor the loss of negative charge in the interface region, producing an anion deficiency, as predicted by theory. The Cl-/Me2+ ratio dropped below 1 for chlorite at 12-25 mM MeCl2 and for illite at 75-100 mM. In addition to better understanding of clay mineral behavior in solution, this work demonstrates that only those clay minerals where surface charge density is the same or lower than that for chlorite contribute to a low salinity enhanced oil recovery response (LS EOR). This explains many of the contradictory results from studies about the role of clay minerals in LS EOR.

Organic-Silica Interactions in Saline: Elucidating the Structural Influence of Calcium in Low-Salinity Enhanced Oil Recovery

Enhanced oil recovery using low-salinity solutions to sweep sandstone reservoirs is a widely-practiced strategy. The mechanisms governing this remain unresolved. Here, we elucidate the role of Ca2+ by combining chemical force microscopy (CFM) and molecular dynamics (MD) simulations. We probe the influence of electrolyte composition and concentration on the adsorption of a representative molecule, positively-charged alkylammonium, at the aqueous electrolyte/silica interface, for four electrolytes: NaCl, KCl, MgCl2, and CaCl2. CFM reveals stronger adhesion on silica in CaCl2 compared with the other electrolytes, and shows a concentration-dependent adhesion not observed for the other electrolytes. Using MD simulations, we model the electrolytes at a negatively-charged amorphous silica substrate and predict the adsorption of methylammonium. Our simulations reveal four classes of surface adsorption site, where the prevalence of these sites depends only on CaCl2 concentration. The sites relevant to strong adhesion feature the O− silica site and Ca2+ in the presence of associated Cl−, which gain prevalence at higher CaCl2 concentration. Our simulations also predict the adhesion force profile to be distinct for CaCl2 compared with the other electrolytes. Together, these analyses explain our experimental data. Our findings indicate in general how silica wettability may be manipulated by electrolyte concentration.

Favorable Temperature Gradient for Maximum Low-Salinity Enhanced Oil Recovery Effects in Carbonates

Experimentally, it has been found that Ca2+ and SO42– are key ions in the Smart Water wettability alteration process in limestone and that low-salinity (LS) enhanced oil recovery (EOR) effects in limestone can be observed if the formation minerals also include dissolvable anhydrite, CaSO4. A diluted brine, such as a standard LS brine, contains low amounts of Ca2+ and SO42–, which prevent wettability alteration from taking place. However, if the formation contains anhydrite mineral, Ca2+ and SO42– are supplied to the injection brine through dissolution, and in that case, a standard LS brine can cause wettability alteration in a limestone reservoir. A tertiary LS EOR effect of 22% original oil in place was observed at 100 °C during viscous flooding of 100 times diluted formation water in a limestone reservoir core containing anhydrite. Anhydrite dissolution and precipitation is dependent upon the temperature, and the solubility of anhydrite in water decreases as the temperature increases. In this paper, the...

Osmosis as Mechanism for Low-Salinity Enhanced Oil Recovery

SummaryWe believe that osmosis has been overlooked as a possible mechanism for observed low-salinity enhanced-oil-recovery (EOR) effects. Osmosis can occur in an oil/water/rock system when injecting low-salinity water, because the system is full of an excellent semipermeable membrane—the oil itself.In the present work, water transport through oil films was visualized both in 2D micromodels and in sandstone cores imaged in a microcomputed tomography (CT). After treating these model systems with hexamethyldisilazane (HMDS) to render them more oil-wet, water became discontinuous, and it was possible to establish osmotic gradients. Either expansion or contraction of the connate water was observed, depending on the direction of the imposed salinity gradient.Because osmosis could be the underlying mechanism for low-salinity EOR, two changes in research strategy are proposed: Most importantly, the use of spontaneous-imbibition tests as evidence for wettability alteration in low-salinity water should be critically reinvestigated. This is because observed production could have stemmed from “osmotic expansion” of the connate water rather than wettability change. Second, much research focus should be shifted from sandstone reservoirs to fractured oil-wet carbonates. Osmosis potentially yields larger responses for the latter reservoir type, whereas from a mechanistic perspective the reason behind low-salinity EOR functioning in both sandstones and carbonates deserves further attention.

Compositional modeling of nanoparticle-reduced-fine-migration

During waterflooding, formation fines migration is a recognized reason for well injectivity and productivity reduction in sandstone reservoirs. Permeability decrease due to fines migration is one of the major issues in the application of low salinity enhanced oil recovery techniques. Recently, nanoparticles injection is found to reduce the fines release in sandstone cores through adsorption on the pore surface. In this research, a numerical model is developed to explore the coupling processes of nanoparticle transport, fine attachment and release, aqueous species reactive transport, and multiphase flow.Components including oil, water, salt, fine particles and nanoparticles are considered in this model. Both fluid dynamics and physical interactions are integrated in the coupled simulation approach. The nanoparticles exist in aqueous phase during injection, and can be attached to the solid surfaces to decrease surface energy. The formation fines can be suspended in aqueous phase, or retained by pore throats that decrease the permeability. The fines retention is modeled as a dynamic process where the retention rate is a function of salinity, nanoparticle adsorption, and flow velocity. The wettability alteration due to nanoparticle and low salinity is also included. A compositional simulator is developed based on implicit pressure explicit composition to include the detailed mathematical description of the complex processes.This paper provides detailed procedures of building a nanoparticle and fines transport and interaction model. To calibrate the diffusion/dispersion and adsorption isotherm constants, lab core flow experiments with nanoparticle injection are simulated. The fines migration experiments are simulated with and without nanoparticle injection at varying salinity. Simulation results demonstrate that the nanoparticle injection can effectively reduce the fine release and prevent permeability decrease at different salinity. In addition, the heterogeneous field scale simulation was performed. The oil recoveries with and without nanoparticle injection are compared for low salinity water injection. The simulation results indicate that using nanoparticles in low salinity waterflooding can improve oil recovery with mitigated formation damage.This work demonstrates a compositional model that can be used to simulate nanoparticle technology enhancing waterflooding performance. It is believed to be the first numerical model that explicitly includes the nanoparticle transport and its effect on fines migration. This paper will improve the understanding of geochemical conditions and spatial distribution of fines retention and whether the sweep efficiency will be improved.

Experimental Study of the Response Time of the Low-Salinity Enhanced Oil Recovery Effect during Secondary and Tertiary Low-Salinity Waterflooding

Despite it more than 500 papers being published on low-salinity (LS) water injection into sandstone oil reservoirs to enhance oil recovery, very few field applications of this enhanced oil recovery (EOR) technique are known. Laboratory investigations of LS water floods under tertiary conditions have shown varying results, and especially, the response time for establishing a new bank of oil in the porous medium has been too slow for application in the field. Usually, many pore volumes (PVs) of LS brine must be injected to obtain an increase in recovery of 5–10% of original oil in place (OOIP). Provided that the initial reservoir conditions for observing LS EOR effects are present, a close connection between the imposed pH gradient and additional oil recovery has been experimentally verified. To improve the chemical understanding of the LS EOR mechanism, it appeared important to study the development of the pH gradient because the HS brine is displaced by the LS brine. Therefore, the relationship between th...

Low Salinity EOR Effects in Limestone Reservoir Cores Containing Anhydrite: A Discussion of the Chemical Mechanism

It is well accepted that seawater injection is able to improve the water wetness of carbonate reservoirs at high temperatures, and in that way, it can act as an enhanced oil recovery (EOR) fluid. A recent laboratory investigation showed that increased oil recovery also was obtained from carbonate reservoir cores by successively flooding composite limestone cores by 2, 10, and 20 times diluted seawater. The study confirmed that it is possible to obtain low salinity EOR effects also in carbonates, and not only in sandstones. In the present study, preserved reservoir core material from a similar limestone formation was used with the objective to obtain a chemical understanding of the mechanism for the improved oil recovery. It was verified, that the core material contained significant amounts of anhydrite (CaSO4), which appeared to be the key factor for observing the low salinity EOR effect. The concentration of sulfate in the injection brine increased due to increased dissolution of anhydrite as the salinit...