Brine Salinity Research Articles

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

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

Preparation of illite coated geomaterial microfluidic surfaces: Effect of salinity and heat treatment

Unique characteristics of clay (e.g., high surface area, deficiency in positive charges) make any clay abundant shales a good source of adsorbed gas. However, the presence of clay in porous media can also affect shale rock's producibility. The clay-water interaction can cause significant swelling and fines migration in the formation and impair the overall hydrocarbon recovery from shale.Geomaterial micromodels, developed by functionalizing traditional glass or PDMS surfaces with geomaterials (e.g., calcite, Quartz, clay), can represent the physicochemical properties of the natural porous media and have been used during the last few years to understand and evaluate the solid-fluid physicochemical interactions. This study focuses on developing a clay-coated geomaterial surface and investigates the effect of base fluid's salinity on clay adsorption to the glass surface. Glass capillary tubes and straight channel borosilicate glass micromodels are coated with Illite clay to represent the pore-scale clay chemistry of Caney Shale, a Mississippian unconventional play in Southern Oklahoma, USA. 10 wt% of Illite clay slurries made with brines of four different salinities are used to coat the glass-capillary tubes to understand the effect of salinity in clay adsorption on the glass surface and overall coating quality. To achieve a stable coating and evaluate the impact of heat treatment on coating's stability, straight channel glass flow cells coated with Illite clay are heat-treated at low (25 °C) and high temperature (125 °C), and the results are compared with an untreated coated surface. Flooding tests were carried out with brines of different salinities on the coated surface to evaluate the stability of the coating.The experimental results indicated a strong relationship between the brine's salinity and the adsorption of clay particles on the glass surface. An increase in brine concentration resulted in improved adsorption of clay particles on the glass surface. Experiments involving heat treating the glass surface following the coating demonstrated significant improvement in the stability of the coating.

Relative Permeability of Hydrogen and Aqueous Brines in Sandstones and Carbonates at Reservoir Conditions

AbstractGeological hydrogen storage in depleted gas fields represents a new technology to mitigate climate change. It comes with several research gaps, around hydrogen recovery, including the flow behavior of hydrogen gas in porous media. Here, we provide the first‐published comprehensive experimental study of unsteady state drainage relative permeability curves with H2‐Brine, on two different types of sandstones and a carbonate rock. We investigate the effect of pressure, brine salinity, and rock type on hydrogen flow behavior and compare it to that of CH4 and N2 at high‐pressure and high‐temperature conditions representative of potential geological storage sites. Finally, we use a history matching method for modeling relative permeability curves using the measured data within the experiments. Our results suggest that nitrogen can be used as a proxy gas for hydrogen to carry out multiphase fluid flow experiments, to provide the fundamental constitutive relationships necessary for large‐scale simulations of geological hydrogen storage.

A detailed study on the rheological behavior of a novel cellulose-based hydrophobically-modified polymer

Hydrophobically-modified cellulose derivatives have been considered for improved oil recovery applications. However, the subsurface reservoir environment defined by combinations of brine salinity, temperature, and porous media-induced shear can pose an adverse challenge to the mobility control prospects of these materials. Previous studies have focused mostly on amphiphilic cellulose ethers. This study is based on a cellulose ester, herein, a novel polymeric surfactant derived from sodium cellulose sulfate is investigated. Rheological studies were carried out on the novel material under variable external reservoir conditions. From the results, the amphiphilic polymer was able to initiate associative behavior at a low concentration of 0.15 g/L. The biopolymeric surfactant exhibited tolerance to temperature and shear over the tested range of 35 °C to 75 °C, and 100 RPM to 250 RPM respectively by retaining its original rheological profile. The viscosity improved over a brine salinity range of 10,000ppm to 60,000ppm as it increased from 45.75 cp to 49.1 cp. From these findings, it can be inferred that the novel cellulose derivative is a good mobility control agent, and should be considered for oilfield applications that target cheap, cost-effective, and environmental-friendly operations.

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

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

Impact of rock morphology on the dominating enhanced oil recovery mechanisms by low salinity water flooding in carbonate rocks

Because of the complex nature of carbonate reservoirs, the required conditions for effective Low Salinity Water Flooding (LSWF) in these reservoirs need further and in depth investigation. In the present study, three calcite cores, i.e. Cal-1, Cal-2, and IL, with the same chemical composition are subjected to tertiary low salinity water flooding (LSWF), while the crude oil and composition of flooding brine kept the same. The experimental results show significant difference in the amount of enhanced oil recovery, as IL had the most additional oil recovery (20.8 % of IOIP), followed by Cal-2 (10.5 % of IOIP) and Cal-1 (3.9 % of IOIP). The results of contact angle, zeta potential, and effluent pH showed that the same geochemical reaction occurred for all three cores. High-resolution FE-SEM images demonstrate that the only difference in these three cases is the rock morphology. Dynamic contact angle measurements indicate that wettability alteration depends on the dominating mechanisms (diffusion/advection) that controls the replacement of high salinity thin water film (which is flanked by crude oil and rock) with the surrounding low salinity brine. The wide pore size distribution of Cal-1 compared to Cal-2 and IL results in a more diffusion-controlled oil recovery mechanisms, which is confirmed by the late-time and the gradual response of Cal-1 to tertiary LSWF. Also, a direct relation between effluent pH and the tertiary oil recovery of Cal-1 highlighted the role of the thickness of the water film in the diffusion rate. More homogenous Cal-2 has a high early oil recovery; however, the angular shape of its particles leads to a partial diffusion-controlled regime that causes a late-time recovery. Finally, the uniform and the rounded particles of IL drift the impact of diffusion away. The results of the present is study emphasizes the role of heterogeneity and angularity on the performance of tertiary LSWF.

Relevance of zeta potential as a tool for predicting the response of controlled salinity waterflooding in oil–water-carbonate systems

Zeta potential has been proposed as a key parameter for predicting the response of controlled salinity waterflooding, as correlation with additional oil recovery has previously been established. However, it is unclear if there is a causal effect and if this parameter can be used as a unique predictive tool. We provide new insights with a detailed investigation into the role of the change of polarities of oil/water/rock interfaces on the additional oil recovery. Core flooding experiments with streaming potential and electrophoretic mobility measurements were performed to obtain insights into the electrostatic interactions that occur during oil recovery on Estaillades rock. Two different injection scenarios were followed in one crude oil/brine/rock (COBR) system: one conventional injection with decreasing salinity and one inverse injection with increasing salinity.Results indicated that oil recovery in secondary mode was more important using formation brine compared to low salinity brine. Also, almost no additional oil recovery was observed in tertiary mode irrespective of the injection scenario. Rock/water zeta potential was found positive in formation brine, and negative in the low salinity brines. The determination of oil/water polarity was more difficult as many inconsistencies between streaming potential and electrophoretic mobility measurements were observed. We propose several explanations for these discrepancies, including that the difference in zeta potential at fully water saturation and at residual saturation is not necessarily dependent on oil polarity as it can be induced by a change in rock exposed surface and in the distribution in water flow paths during measurements. The overall results suggest that zeta potential cannot be used as a unique indicator to predict the low salinity response of a COBR system.

The Origin of Synchysite-(Ce) and Sources of Rare Earth Elements in the Rožná Uranium Deposit, Czech Republic

Synchysite was identified in the Rožná uranium deposit in a quartz–carbonate–sulfide vein, which is a part of the late (post-uranium and, post-Variscan) stage of the development of the hydrothermal system. The synchysite forms needles or lamellae, which are almost exclusively bound to the quartz filling of the veins. The structure of the quartz vein-filling, i.e., the preserved tubular syneresis crack pattern, Liesegang bands formed by hematite, chaotic grain size distribution of quartz grains, and ribbons of fibrous SiO2 grains, indicate that the synchysite crystallized in a silica gel. Its formation may be explained by the reaction of hydrothermal acid fluids rich in Fe2+ and rare earth elements (REEs) with alkaline Ca2+ HCO3− and F-rich fluids expelled from the gel during syneresis, or by its ageing. The subsequent recrystallization of the gel to form euhedral quartz grains was accompanied by the deformation of previously formed Liesegang rings, and the development of quartz rosettes. The study of fluid inclusions indicated that the silica gel originated at a very low temperature. The temperatures of the homogenization of two-phase inclusions in carbonate and quartz vein-filling varied between 38 and 74 °C, and the salinity ranged between 4 and 10 wt.% NaCl equiv. The δ13C carbonate values (from −4.65 to −5.21‰, PDB) indicate the deep-seated source of CO2, and δ18O values (from 14.76 to 18.22‰, SMOW) show that the source of the hydrothermal fluids was mainly surface water, with a possible admixture of fossil saline brines. The main sources of REEs are thought to have predominantly been uranium minerals (coffinitized uraninite and coffinite) that form a part of the breccia fragments embedded in the vein filling. The results illustrate the significant mobility of REEs in the late, low-temperature hydrothermal system, and they indicate the multiple remobilizations of REEs in the uranium deposits in general.

Effect of brine salinity and hydrolyzed polyacrylamide concentration on the Oil/Brine and Brine/Rock Interactions: Implications on enhanced oil recovery by hybrid low salinity polymer flooding in sandstones

The main idea behind the application of Low salinity polymer flooding (LSPF) enhanced oil recovery (EOR) method is that diluted brine improves the oil recovery by wettability alteration from oil-wet (OW) towards water-wet (WW) condition, while polymer enhances the mobility of the displacing phase. However the possible effect of polymer on the fluid/fluid and fluid/rock interactions are not investigated systematically in the literature. The main objective of the present reserach is to examine the possible effect of hybrid application of low-salinity and polymer on the brine/rock and brine/oil interfaces properties. Formation water (FW) and sea water (SW) and its two different dilutions, i.e. twice concentrated (2xcSW) and 10 times diluted (10xdSW) along with different concentrations of HPAM as polymer, i.e. 250, 500, 1000 and 2000 ppm, are considered. Silicate substrates are used as representative of the main mineral in sandstone rocks and both WW and OW conditions evaluated. To understand the dominant oil/brine and rock/brine interactions, different properties such as brines pH, oil/brine interfacial tension, oil/brine zeta potential, rock/brine zeta potential and oil contact angle on the rock surface (in the presence of the desired aqueous sample) are investigated.Experimental results are in line with each other and confirm the influence of both aqueous salinity and polymer concentrations on all the measured properties i.e. IFT, wettability and zeta potentials. Fluid/fluid and rock/fluid interactions are proposed for justification of the observed experimental results. The results can be used to shed lights on the possible recovery mechanisms and designing of successful hybrid low salinity polymer flooding.

Low salinity water flooding: Evaluating the effect of salinity on oil and water relative permeability curves using coupling of DLVO and geochemical reactions

Enhancing the oil recovery of carbonate reservoirs with acidic oil depends on injected brine composition and salinity throughout the low salinity water flooding. The typical description of this phenomenon on oil and water relative permeability curves is being put forward by the process-dependent interpolation function, which barely addresses the underlying fundamentals governing the direct impact of wettability alteration and geochemical reactions on flow saturation functions. The main objective of this work is to perform an integrated investigation of the effect of salinity on oil and water relative permeability curves by dynamic coupling of the Derjaguin, Landau, Verwey, and Overbeek (DVLO) theory and geochemical reactions. We studied both the single and two-phase systems using the basis of the geochemical reactions to track the variations of the wetting and non-wetting phase relative permeability curves. In the single-phase scenario, the results show the superiority of the reactive flow modeling technique with kinetic-controlled reactions, in the range between [2–4] of the Damkohler number, to yield a better result for the experimental effluent ions' concentrations than the equilibrium approach. In addition, the single-phase results under dynamic conditions propose Civan correlation as the best predictor of residual resistance factor (RRF) by numerically adjusting the correlation of coefficients based on the physical variables - salinity, dimensionless consumed ion concentration, and Peclet number. Accordingly, the results indicate a novel linkage between the single-phase and two-phase results in the sense that RRF under single-phase mode can be used to estimate the change in the wetting phase relative permeability under the two-phase mode. The single-phase methodology provides the capability for an improvement – up to 15% - in the prediction of the pressure drop curve. For two-phase cases, our procedure involved coupling the characterized geochemical reactions and the DLVO theory to consider the effect of injected water composition on contact angle as the static two-phase parameter. The phase-field method is coupled with DLVO theory to calculate the relative permeability curves for the non-wetting phase, which corresponds to the contact angle at each simulation time step. The two-phase results indicate an improvement – up to 30% - in the prediction of the recovery factor curve, on a history-matching basis, using the DLVO theory with contact angle-dependent correlation of non-wetting phase relative permeability curve. The main novelties of this study are using the single-phase dynamic permeability impairment results in calculating the variation of the wetting-phase relative permeability curve. Moreover, dynamic coupling of DLVO and non-linear contact angle-dependent correlation is used to calculate the non-wetting phase relative permeability curve. According to these novelties, more accurate prediction of the laboratory production profiles can be obtained.

Dissolution Rate of Nanomaterials Determined by Ions and Particle Size under Lysosomal Conditions: Contributions to Standardization of Simulant Fluids and Analytical Methods.

Dissolution of inhaled engineered nanomaterials (ENM) under physiological conditions is essential to predict the clearance of the ENM from the lungs and to assess their biodurability and the potential effects of released ions. Alveolar macrophage (AM) lysosomes contain a pH 4.5 saline brine with enzymes and other components. Different types of artificial phagolysosomal simulant fluids (PSFs) have been developed for dissolution testing, but the consequence of using different media is not known. In this study, we tested to which extent six fundamentally different PSFs affected the ENM dissolution kinetics and particle size as determined by a validated transmission electron microscopy (TEM) image analysis. Three lysosomal simulant media were consistent with each other and with in vivo clearance. These media predict the quick dissolution of ZnO, the partial dissolution of SiO2, and the very slow dissolution of TiO2. The valid media use either a mix of organic acids (with the total concentration below 0.5 g/L, thereof citric acid below 0.15 g/L) or another organic acid (KH phthalate). For several ENM, including ZnO, BaSO4, and CeO2, all these differences induce only minor modulation of the dissolution rates. Only for TiO2 and SiO2, the interaction with specific organic acids is highly sensitive, probably due to sequestration of the ions, and can lead to wrong predictions when compared to the in vivo behavior. The media that fail on TiO2 and SiO2 dissolution use citric acid at concentrations above 5 g/L (up to 28 g/L). In the present selection of ENM, fluids, and methods, the different lysosomal simulant fluids did not induce changes of particle morphology, except for small changes in SiO2 and BaSO4 particles most likely due to ion dissolution, reprecipitation, and coalescence between neighboring particles. Based on the current evidence, the particle size by TEM analysis is not a sufficiently sensitive analytical method to deduce the rate of ENM dissolution in physiological media. In summary, we recommend the standardization of ENM dissolution testing by one of the three valid lysosomal simulant fluids with determination of the dissolution rate and halftime by the quantification of ions. This recommendation was established for a continuous flow system but may be relevant as well for static (batch) solubility testing.

Effect of fluid saturation and salinity on sandstone rock weakening: experimental investigations and interpretations from physicochemical perspective

Fluid saturation plays an important role in rock weakening. However, few researches reveal the controlling factor(s) behind the rock weakening particularly from geochemical perspective. We performed rock failure/fracture reactivation tests on dry and wet samples (saturated with high/low salinity brine). We examined the effect of fluid saturation and salinity on rock mechanical properties through a unique triaxial compression system with combination of micro-seismicity monitoring. Besides, the induced time-dependent micro-seismicity events were located to characterize the fracture orientation together with medical CT imaging. Moreover, we performed geochemical modelling to link the surface energy to rock mechanics from geochemical perspective.Our results show that the peak stress of saturated samples is 11.7% to 15.0% less than unsaturated samples, confirming that fluid saturation can weaken rock. Lowering salinity appears to play a negligible role in the reduction of elastic modulus and peak stress of intact sandstones. We also did not observe the expansion of micro-seismicity cloud along main fracture plane, suggesting that lowering salinity may not trigger micro-fracture generation under confining condition. However, sample saturated with low salinity brine shows a much slower increase rate of differential stress during the plastic deformation to reach yield point during fracture reactivation process compared to the sample saturated with high salinity brine. This work contributes to the existing knowledge of rock weakening by providing quantitative geochemical characterization with implications in water-assisted enhancing hydrocarbon recovery and CO2 geological storage.

A gradient-based deep neural network model for simulating multiphase flow in porous media

Simulation of multiphase flow in porous media is crucial for the effective management of subsurface energy and environment-related activities. The numerical simulators used for modeling such processes rely on spatial and temporal discretization of the governing mass and energy balance partial-differential equations (PDEs) into algebraic systems via finite-difference/volume/element methods. These simulators usually require dedicated software development and maintenance, and suffer low efficiency from a runtime and memory standpoint for problems with multi-scale heterogeneity, coupled-physics processes or fluids with complex phase behavior. Therefore, developing cost-effective, data-driven models can become a practical choice, and in this work, we choose deep learning approaches as they can handle high dimensional data and accurately predict state variables with strong nonlinearity. In this paper, we describe a gradient-based deep neural network (GDNN) constrained by the physics related to multiphase flow in porous media. We tackle the nonlinearity of flow in porous media induced by rock heterogeneity, fluid properties, and fluid-rock interactions by decomposing the nonlinear PDEs into a dictionary of elementary differential operators. We use a combination of operators to handle rock spatial heterogeneity and fluid flow by advection. Since the augmented differential operators are inherently related to the physics of fluid flow, we treat them as first principles prior knowledge to regularize the GDNN training. We use the example of pressure management at geologic CO2 storage sites, where CO2 is injected in saline aquifers and brine is produced, and apply GDNN to construct a predictive model that is trained with physics-based simulation data and emulates the physics process. We demonstrate that GDNN can effectively predict the nonlinear patterns of subsurface responses, including the temporal and spatial evolution of the pressure and CO2 saturation plumes. We also successfully extend the GDNN to convolutional neural network (CNN), namely gradient-based CNN (GCNN), and validate its capability to improve the prediction accuracy. GDNN has great potential to tackle challenging problems that are governed by highly nonlinear physics and enable the development of data-driven models with higher fidelity.

The impact of salinity, alkalinity and nanoparticle concentration on zeta-potential of sand minerals and their implication on sand production

The effect of brine salinity, cation type, pH, and produced sand on zeta potential (ZP) measurements with and without the presence of silica nanoparticles is investigated through pH measurement, static tests for sand and ZP measurements as well as Field Emission Scanning Electron Microscope (FESEM) analyses. Three important factors were investigated: composition of the injected brine, surface charge and pH. Their influence on stability of nanoparticles in the injected brine and amount of sand segregation was determined and the analysis of the new outcomes based on rock/brine ZP measurements was reported. The results show that the use of silica nanoparticles with high pH helps in preventing sand production and that pH has a main effect on the surface charge of the sand particle released, affecting the ZP of the solution. Nanoparticles can be active as a coating on sand grains and prevent sand segregation during water flooding. Divalent cations have been found to acquire a more substantial impact on neutralizing the negative charge of the sand particles than monovalent cations at the same concentration and pH conditions at 25 ℃. The value of ZP becomes of higher negative value with the decrease of brine salinity. The effectiveness of SiO2 nanoparticles is quite different for soft water and smart water. For soft water, the nanoparticles work more effective at pH higher than 8; and for smart water, the nanoparticles perform better at pH lower than 8. To reduce sand production with the use of silica nanoparticles, it is highly suggested to increase pH, as pH and sand production mechanisms were observed to be inversely related.

Impact of Reservoir Heterogeneity on Diluted Geothermal Brine Reinjection

Many geothermal plants have been shut down due to reinjection problems with the heat-depleted brine. In Denmark, only one out of three plants that extract heat from a geothermal fluid distributed to the district heating system is still working. In general, the large salinity of heat-depleted geothermal brines can be used to produce electricity with the help of turbines and generators through an osmotic power unit known as a SaltPower plant. Harnessing more energy out of the reinjection of geothermal brines is feasible without compromising the overall reservoir assurance when the iron is kept under control. This study is an attempt to determine the feasibility of the reinjection of a diluted geothermal brine with ethylenediaminetetraacetic acid (EDTA) into homogeneous and heterogeneous sandstone rocks. The results from the coreflooding experiments show an improvement in the rock properties both in porosity and permeability for homogeneous and heterogeneous rocks. EDTA not only avoids the precipitation of Fe(III) oxides inside the porous media but can also be used for scale removal and matrix acidizing in geothermal reservoirs.

Carbonated Water Injection in Oil-Wet Carbonate Rock Samples: A Pore-Scale Experimental Investigation of the Effect of Brine Composition

Research into the application of carbonated water injection (CWI) for oil recovery has primarily focused on sandstone reservoirs. Therefore, characteristic pore-scale mechanisms that principally depend on the injected brine composition in oil-wet carbonates are still poorly understood. This study uses a pore-scale approach that incorporates core flooding with microcomputed tomography (micro-CT) imaging to investigate underlying mechanisms during CWI with different brine compositions and salinities in oil-wet carbonate rocks. The results reveal that mere carbonation of brine deficient in potential determining ions (PDIs)─Ca2+, Mg2+, and SO42–─does not improve the oil displacement efficiency in oil-wet carbonates. Particularly, certain pore-scale phenomena─wettability reversal and interfacial tension (IFT) reduction─that control the oil displacement efficiency do not significantly change toward desirable states. Extant oil-wet conditions were maintained as we observed a marginal reduction in the average in situ contact angle. In addition, the equilibrium oil–brine IFT was similar to that of oil–brine systems characterized by high brine salinity. Contrarily, enriching low-salinity seawater, containing definite amounts of PDIs, with CO2 promoted superior oil recovery within all pore-size groups with an overall incremental value as high as 24%. This enhanced performance was evidenced by a dominance of wettability reversal to near-neutral states, which created a more favorable capillary pressure required for pore-level displacements. Wettability alteration originated from the reduction in electrostatic attraction between oil–brine and brine–rock interfaces through surface adsorption of SO42– ions in low-pH environments. These observations establish wettability reversal aided by PDIs as the overriding pore-scale oil-recovery mechanism in oil-wet carbonates during CWI.

Temperature and basinal fluid controls on feldspar diagenesis, Lower Cretaceous sandstones, Scotian Basin, Canada

The passive-margin Scotian Basin accumulated thick Upper Jurassic–Lower Cretaceous deltaic sandstones and shales, which were influenced by high heat flow in the mid-Cretaceous and deformed by salt tectonics. This study takes advantage of the complex thermal history and record of saline fluid flow in the basin to determine the relative importance of burial depth, temperature, salinity of basinal brines, overpressure, and sandstone permeability in controlling the dissolution of detrital feldspar and growth of authigenic K-feldspar and albite. Feldspar grains and volcanic lithic clasts from two transects, with differing thermal and salt tectonic histories, were studied by scanning electron microscope (SEM) backscattered electron images, energy-dispersive spectroscopy, SEM cathodoluminescence (CL) imaging, and hot-cathode CL microscopy. Published fluid inclusion measurements are integrated with burial history curves and timing of deformation on salt detachment surfaces to provides a new synthesis of the post-Jurassic thermal and saline fluid flow history of the basin. Surface-controlled dissolution of K-feldspar and growth of authigenic K-feldspar rims occur from 1.5 to 3.1 km. More destructive transport-controlled dissolution, down to 3.9 km, is more effective in thick-bedded permeable sandstones that acted as fluid pathways. Albitization of detrital K-feldspar and sodic plagioclase, and of feldspars in volcanic lithic clasts was facilitated by high Na+ content of formation waters migrating preferentially through such pathways at the time of silica and carbonate cementation, with strong albitization coinciding with transport-controlled dissolution of K-feldspar. Authigenic albite partially fills pores created by K-feldspar dissolution. Overpressured conditions enhance albite authigenesis, as a result of slower fluid advection. Episodic release of hot, saline, overpressured fluids in the zone of surface-controlled dissolution of K-feldspar favoured albitization but had no detectable effect on K-feldspar dissolution. Basin hydrology plays a definitive role in feldspar diagenesis, producing patterns that cannot be interpreted as a simple consequence of temperature and activity of Na+.

Investigation of Brine pH Effect on the Rheological and Viscoelastic Properties of HPAM Polymer for an Optimized Enhanced Oil Recovery Design.

A novel approach to improve viscous and viscoelastic properties by exploiting the pH and salinity sensitivity of HPAM polymer is proposed in this paper. Polymer flooding is a well-developed and effective enhanced oil recovery technique. The design of the makeup brine is one of the most critical phases of a polymer flood project, since the brine composition, salinity, and pH directly influence the polymer viscosity and viscoelasticity. However, the viscoelastic properties of hydrolyzed polyacrylamide polymers have not been given much consideration during the design phase of polymer flood projects. Our experimental study focuses on the optimization of the makeup water design for polymer flooding by evaluating the optimum solution salinity and pH for better stability and improved viscoelastic behavior of the polymer. Initially, the brine salinity and ionic composition is adjusted and then hydrolyzed polyacrylamide (HPAM) polymer solutions of varying pH are prepared using the adjusted brine. Rheological experiments are conducted over a temperature range of 25–80 °C and at different aging times. Polymer thermal degradation as a function of pH is assessed by examining the solutions at 80 °C for 1 week. Amplitude sweep and frequency sweep tests are performed to determine the viscoelastic properties such as storage modulus, loss modulus, and relaxation time. A 15–40% increase in the polymer solution viscosity and a 20 times increase in relaxation time is observed in the pH range of 8–10 in comparison to the neutral solution. This can be attributed to the low-salinity ion-adjusted environment of the makeup brine and further hydrolysis and increased repulsion of polymer chains in an alkaline environment. These results indicate that the viscoelastic properties of a polymer are tunable and a basic pH is favorable for better synergy between the brine and the polymer. Alkaline low-salinity polymer solutions have exhibited 60% higher thermal stability in comparison to acidic solutions and thus can be successfully applied in high-temperature reservoirs. The results of this study show that polymer solutions with an optimum pH in the basic range exhibit a higher viscoelastic character and an increased resistance toward thermal degradation. Hence, the polymer solution salinity, ionic composition, and pH should be adjusted to obtain maximum oil recovery by the polymer flooding method. Finally, this study shows that more effective polymer solutions can be prepared by adjusting the pH and designing a low-salinity water/polymer recipe to get the additional benefit of polymer viscoelasticity. The optimized low-salinity alkaline conditions can reduce the residual oil saturation by stronger viscous and viscoelastic forces developed by more viscous polymers. The findings of this study can be employed to design an optimum polymer recipe by tuning the brine pH and salinity for maximum incremental oil recovery, particularly in high-temperature and high-salinity formations.

Theoretical and experimental study of a new freezing desalination system assisted by ultrasound

Compared with traditional seawater desalination methods, freezing desalination has gotten more attention for its advantages in reducing energy consumption and environmental protection. In this study, a new freezing desalination assisted by ultrasonic is proposed to improve desalination efficiency. A detailed freezing desalination model is established based on phase transition analysis and ultrasonic-assisted freezing theory. The experiment system is also developed to analyze the desalination process. The factors such as temperature, interface transformation and salinity in the process of droplet freezing under the action of ultrasound were analyzed and discussed. The result showed that the salinity of the droplet residual brine could decline to less than 2.4% when the initial salinity was 5% and droplet diameter was 2 mm after 1 min centrifugal treatment. After the treatment, the salinity of the existed ice-brine mixing was decreased below 0.2%. According to experiments and simulation analysis, the application of ultrasonic wave in freezing desalination can effectively increase the freezing speed of droplets and improve the efficiency of desalination. This study will contribute to the application of ultrasonic in the freezing desalination.

Long-Term Treatment of Highly Saline Brine in a Direct Contact Membrane Distillation (DCMD) Pilot Unit Using Polyethylene Membranes.

Membrane distillation (MD) is an attractive separation process for wastewater treatment and desalination. There are continuing challenges in implementing MD technologies at a large industrial scale. This work attempts to investigate the desalination performance of a pilot-scale direct contact membrane distillation (DCMD) system using synthetic thermal brine mimicking industrial wastewater in the Gulf Cooperation Council (GCC). A commercial polyethylene membrane was used in all tests in the DCMD pilot unit. Long-term performance exhibited up to 95.6% salt rejection rates using highly saline feed (75,500 ppm) and 98% using moderate saline feed (25,200 ppm). The results include the characterization of the membrane surface evolution during the tests, the fouling determination, and the assessment of the energy consumption. The fouling effect of the polyethylene membrane was studied using Humic acid (HA) as the feed for the whole DCMD pilot unit. An optimum specific thermal energy consumption (STEC) reduction of 10% was achieved with a high flux recovery ratio of 95% after 100 h of DCMD pilot operation. At fixed operating conditions for feed inlet temperature of 70 °C, a distillate inlet temperature of 20 °C, with flowrates of 70 l/h for both streams, the correlations were as high as 0.919 between the pure water flux and water contact angle, and 0.963 between the pure water flux and salt rejection, respectively. The current pilot unit study provides better insight into existing thermal desalination plants with an emphasis on specific energy consumption (SEC). The results of this study may pave the way for the commercialization of such filtration technology at a larger scale in global communities.