Ionic Strength Brines Research Articles

Machine learning - based shale wettability prediction: Implications for H2, CH4 and CO2 geo-storage

Shale wettability determines shale gas productivities and gas (H2, CH4 and CO2) geo-storage efficiencies. However, shale wettability is a complex parameter which depends on multiple influencing factors, thus very time-consuming and costly to measure experimentally. Herein, we combined the eXtreme gradient boosting (XGBoost) and Shapley additive explanation (SHAP) machine learning methods to accurately predict brine advancing (θA) and receding (θR) contact angles and estimate shale wettability. The XGBoost model demonstrated much higher prediction accuracies than the commonly-used multiple linear regression and partial least squares regression models, e.g., R2 was 0.946–0.999, 0.794–0.821, and 0.635–0.674, respectively for these three models. The SHAP sensitivity analyses showed that total organic carbon content and gas molecular weight (MG) were the two most significant factors influencing shale wettability. In addition, shale hydrophobicity positively correlated with MG, calcite content, pressure and brine ionic strength, while negatively correlated with temperature and quartz content. This work provides an efficient approach for shale wettability estimation, thus aiding in the implementation of improved gas recovery and gas geo-storage processes, to further guarantee energy security and mitigate climate change.

Estimation of CO2-Brine interfacial tension using Machine Learning: Implications for CO2 geo-storage

Carbon capture and storage (CCS) is a promising technique to reduce anthropogenic gases causing climate change. This efficient strategy contributes toward reaching net-zero emissions and consists of capturing CO2, transporting it, and sequestering it deep down into selected geological formations. Subsurface storage of carbon dioxide (CO2) depends on several factors like injectivity, formation characteristics, seal integrity, and the associated rock-fluid and fluid–fluid interactions, etc. One critical parameter, in this context, is the interfacial tension (IFT) of the fluid–fluid system in question i.e., CO2-brine IFT for CO2 geo-storage. While experimental data for IFT of CO2-brine systems have been rigorously reported, and a few studies generated robust correlations to forecast the IFT as a function of its influencing factors, still the correlations lack in terms of accuracy and consideration of the most up-to-date data inventory. This paper thus presents a robust and accurate artificial intelligence (AI) based model to estimate the IFT of CO2-brine systems based on the largest data set (2896 points) utilized so far. A range of intelligent models such as Gradient Boosting (GB), Neural Network (NN), and Genetic Programming (GP) are used here to predict CO2-brine IFT. Furthermore, the most influencing factors are evaluated by using the relevance factor analysis method that helps in determining the weight of the contribution of each parameter on IFT. Our results suggest that: a) Gradient Boosting (GB) model with all its derivatives demonstrates the best accuracy for IFT prediction with a high coefficient of determination (R2) equal to 0.964, b) lowest performance is attributed to GP, and c) the impact of different factors is found to be in the order pressure > temperature > salinity > impurities. Moreover, an improved IFT correlation as a function of thermophysical and chemical properties i.e., temperature, pressure, and salinity is presented to quantify IFT with high precision (R2 = 0.886 and MRAE = 0.295) and significant time saving. This correlation is further validated and results show that it can capture the several chemical and physical processes leading to the various behavior trends of IFT stated in the literature. As a direct application in CO2 geo-storage projects, our proposed correlation is used to determine the optimal storage depth of a real carbonate saline aquifer located onshore of UAE. This study thus provides a robust model to estimate CO2-brine IFT which is important for storage capacity estimations and helps to better understand the factors influencing IFT. The model proposed here captures the dependence of CO2-brine IFT on six independent variables including pressure, temperature, brine ionic strength, cation type, and presence of impurities (CH4 and N2).

Systematic observations of enhanced oil recovery and associated changes at carbonate-brine and carbonate-petroleum interfaces

Enhanced oil recovery (EOR) from carbonates is obtained by injection of controlled ionic strength brines containing “active ions” (e.g., SO42−, Mg2+, Ca2+). It is generally believed that this occurs through the interaction of the active ions at the carbonate-brine interface (e.g., within a thin brine layer separating the petroleum and the carbonate phases). Here, in-situ observations show how one active ion, SO42−, alters behavior at the carbonate-petroleum interface. Displacement of petroleum from initially oil-wet carbonate rocks using brines with variable SO4 concentrations systematically changes oil recovery, in situ contact angles, and connectivity of the oil phase, confirming that the active ion alters interactions at the oil/brine/carbonate interface, as expected. Measurements of model calcite-fluid interfaces show that there is no measurable sorption of SO4 to carbonate-brine interfaces but reveals that the carbonate-petroleum interface is altered by previous exposure to SO4-containing brines. These results suggest that EOR in carbonates is controlled indirectly by active ions. We propose that this may be due to a reduced oleophilicity of the carbonate caused by chemical complexation between the active ion and petroleum’s acidic and basic functional groups. This mechanism explains how both anions and cations act as active ions for EOR in carbonates.

Rheological demonstration of micellization changes of internal olefin sulfonate and alcohol alkoxy sulfate commercial surfactants upon interactions with inorganic salts

The Enhanced Oil Recovery by Chemical methods (CEOR) is carried out through the injection of polymer and/or surfactant solutions. The polymer allows for the increase of the viscosity of the injected water, while the surfactant decreases the interfacial tension between water and crude-oil under reservoir conditions. However, the salinity of the oilfield water sources significantly reduces the ability of synthetic polymer to increase the viscosity and viscoelasticity of the water. Consequently, their use is limited, especially in those oilfields presenting high ionic strength brines. The rheological behavior of surfactant solutions could be considerably enhanced if formed micellar aggregates are in a sufficient number, adequate size, and the interactions among them are sufficiently strong. In this work, the effect of some inorganic salts on the rheological behavior of surfactant solutions in the absence of polymer molecules is studied. To our knowledge, this is the first time commonly anionic surfactants used in CEOR are tested using several cation valences inorganic salts. Results show a trend to increase or induce a shear-thinning behavior of sufficiently concentrated solutions. Solutions exhibiting higher viscosities profiles may display viscoelastic properties that resemble (or even overcome) those of polymeric solutions with similar viscosity profiles. This can be a very promising technique for oil recovery in the absence of traditional polymer molecules under high salinity conditions.

Evaluation of sour gas-low salinity waterflooding in carbonate reservoirs - A numerical simulation approach

Although significant amount of H2S (sour gas) rich natural gas is estimated globally, but not much attention has been given to the application of H2S in the oil recovery process. Recent studies on the use of H2S in oil recovery processes showed that H2S has the potential of improving the oil recovery, and it can be even more effective than using CO2 in some processes. H2S can equally dissolve in the water, react with the reservoir rock to change its surface charge, porosity, and permeability. However, previous investigations on H2S oil recovery attributed the improved oil recoveries to the higher miscibility of H2S in the oil, and the reduction in the oil viscosity. Therefore, there is limited understanding on the H2S-oil-brine-rock geochemical interactions, and how they impact the oil recovery process. This study aims to investigate the interactions between H2S, oil, and carbonate formations, and to assess how the combination of H2S and low salinity water can impact the wettability and porosity of the reservoirs. A triple layer surface complexation model was used to understand the influence of key parameters (e.g., pressure, brine salinity, and composition) on the H2S-brine-oil-rock interactions. Moreover, the effects of mineral content of the carbonate rock on H2S interactions were studied. Thereafter, the results of the H2S-oil-brine-rock interactions were compared with a study where CO2 was used as the injected gas. Results of the study showed that the seawater and its diluted forms yielded identical ζ-potential values of about 3.31 mV at a pH of 3.24. This indicates that at very low pH condition, pH controls the ζ-potential of the oil-brine interface regardless of the brine's ionic strength. The study further demonstrated that the presence of other minerals in the carbonate rock greatly reduced the calcite dissolution. For instance, the calcite dissolution was reduced by 4.5% when anhydrite mineral was present in the carbonate rock. Findings from the simulation also indicated that CO2 produced negative ζ-potential values for the carbonate rocks, and these values were reduced by 18.4%–20% when H2S was used as the gas phase. This implies that the H2S shifted the carbonate rock ζ-potentials towards positive. The outcomes of this study can be applied when designing CO2 flooding and CO2 storage where the gas stream contains H2S gas since H2S greatly influences the dissolution of the carbonate mineral.

Predicting the electrokinetic properties on an outcrop and reservoir composite carbonate surfaces in modified salinity brines using extended surface complexation models

Surface complexation models (SCM), based mainly on the diffuse double layer (DDL) theory, have been used to predict zeta potential at the crude oil-brine-rock (COBR) interface with limited success. However, DDL is inherently limited in accurately predicting zeta potential by the assumptions that all the brine ions interact with the rock surface at the same plane and by the double layer collapse at higher brine ionic strength (>1M). In this work, a TLM-based SCM captured zeta potential trends at the calcite-brine interface with ionic strength up to 3 M. An extended DDL and TLM-based SCMs were used to predict the electrokinetic properties of a composite carbonate rock showing a different mineralogical composition. The extended TLM-based SCM captured the zeta potential prediction trends and magnitude, highlighting the contribution of the inorganic minerals and organic impurities on the composite carbonate surface. In contrast, the extended DDL-based SCM captured the zeta potential trends but failed to capture the magnitude of the measured zeta potential. Interestingly, the TLM-based SCM predicted a positive SP for the rock-brine interface, which could explain the oil-wet nature of composite carbonate rocks due to electrostatic adsorption of negatively charged carboxylic acids. Conversely, the DDL-based SCM predicted a negative SP, leading to an inaccurate interpretation of the electrokinetic properties at the rock-brine interface. Thus, the use of extended TLM-based SCM was required to accurately predict the zeta potential and account for the adsorption of carboxylic acids on the reservoir composite carbonate surface.

Flow performance of a self-assembly biopolymer/β-cyclodextrin/surfactant CO2 foam system in pollutant-free porous media as a flushing agent for in-situ soil remediation applications

The remediation of hydrocarbon contaminated soils is an active research field, in which different remediation technological approaches are currently under evaluation. In this research, a new technology based on a self-assembly biopolymer/β-Cyclodextrin/surfactant (bP/βCD/S) CO2 foam system was evaluated for in-situ soil remediation applications. The biopolymer and surfactant used in this study were xanthan gum and dodecyl trimethylammonium chloride (DTAC), respectively. The stability of the bP/βCD/S and the baseline biopolymer/surfactant, bP/S, CO2 foam systems at different brine salinity and hardness concentrations was evaluated in bulk. Subsequently, the flow behavior and the stability of both foam systems were evaluated through displacement experiments employing unconsolidated sand at different brine concentrations (2.1 and 8.4 wt%) at ambient temperature. The mobility control performance and the stability of both foam systems in contaminant-free sand were evaluated during the displacing experiments using the resistance and the residual resistance factors as performance indicators. The bulk stability tests demonstrate that the bP/βCD/S CO2 foam system displays higher stability relative to the bP/S foam system in both 2.1 wt% (e.g., salinity = 1.73 wt% and hardness = 0.37 wt%) and 8.4 wt% (e.g., salinity = 6.92 wt% and hardness = 1.48 wt%) brine systems. Likewise, the displacement experiments show that the bP/βCD/S CO2 system offers superior mobility control functionality and stability during flow in porous media relative to the baseline polymer/surfactant foam regardless of the brine ionic strength. Consequently, the bP/βCD/S CO2 foam system shows great potential as an effective integrated technology for in-situ soil remediation applications.

Surface Reactivity Analysis of the Crude Oil–Brine–Limestone Interface for a Comprehensive Understanding of the Low-Salinity Waterflooding Mechanism

Low salinity waterflooding (LSWF) has proven to improve oil recovery in carbonate formations through rock wettability alteration although the underlying mechanism remains elusive. In this work, coreflooding coupled with surface reactivity analysis approach was employed to investigate the interplay of wettability alteration mechanisms such as mineral dissolution, electrostatic force reduction and the effect of pH at in-situ conditions. Improved oil recovery (IOR) in tertiary mode observed by coreflooding in Indiana limestone rocks showed a brine ionic strength dependence, i.e. reducing brine ionic strength resulted in an increase in oil recovery. Coreflooding results showed that the seawater and low salinity brines deprived of Mg2+ ions resulted in the lowest IOR in tertiary mode, indicating the significance of Mg2+ on IOR in limestone rocks. Similar results were observed through contact angle measuring showing the limestone rock wettability state dependence on ionic strength and the effect of Mg2+ ion. Su...

Stabilization of Polymer Nanocomposites in High-Temperature and High-Salinity Brines.

Stabilization of polymer nanocomposites in aqueous environment with high salinity has been a constant challenge for their applications. This work aimed to improve the stability of graphene oxide (GO) polyacrylamide nanocomposites at high-temperature and high-ionic-strength brines. GO was synthesized via a modified Hummers’ method and the copolymer of acrylamide (COPAM) was obtained via free-radical polymerization. The covalent functionalization of COPAM with the partially reduced GO (rGO) was successfully achieved. 1,3-Propane sultone was used to further functionalize the obtained rGO–COPAM composites to accomplish the zwitterionic character on the rGO–COPAM surface to get a material with excellent temperature stability and dispersibility in the presence of high ionic strength brines. The synthesized materials were characterized by 1H NMR, gel permeation chromatography, X-ray photoelectron spectroscopy, scanning electron microscopy, transmission electron microscopy analysis, and so forth. The thermal stability of the dispersion at 80 °C for 120 days was observed by visual inspection and spectroscopic analysis. The results showed that the zwitterionic polymer produced excellent brine stability with GO nanosheets and suggested promising applications of zwitterionic polyacrylamide–GO systems especially for enhanced oil recovery.

Brine-Dependent Recovery Processes in Carbonate and Sandstone Petroleum Reservoirs: Review of Laboratory-Field Studies, Interfacial Mechanisms and Modeling Attempts

Brine-dependent recovery, which involves injected water ionic composition and strength, has seen much global research efforts in the past two decades because of its benefits over other oil recovery methods. Several studies, ranging from lab coreflood experiments to field trials, indicate the potential of recovering additional oil in sandstone and carbonate reservoirs. Sandstone and carbonate rocks are composed of completely different minerals, with varying degree of complexity and heterogeneity, but wettability alteration has been widely considered as the consequence rather than the cause of brine-dependent recovery. However, the probable cause appears to be as a result of the combination of several proposed mechanisms that relate the wettability changes to the improved recovery. This paper provides a comprehensive review on laboratory and field observations, descriptions of underlying mechanisms and their validity, the complexity of the oil-brine-rock interactions, modeling works, and comparison between sandstone and carbonate rocks. The improvement in oil recovery varies depending on brine content (connate and injected), rock mineralogy, oil type and structure, and temperature. The brine ionic strength and composition modification are the two major frontlines that have been well-exploited, while further areas of investigation are highlighted to speed up the interpretation and prediction of the process efficiency.

Bulk and Surface Aqueous Speciation of Calcite: Implications for Low-Salinity Waterflooding of Carbonate Reservoirs

Summary Low-salinity waterflooding (LSW) is ineffective when reservoir rock is strongly water-wet or when crude oil is not asphaltenic. Success of LSW relies heavily on the ability of injected brine to alter surface chemistry of reservoir crude-oil brine/rock (COBR) interfaces. Implementation of LSW in carbonate reservoirs is especially challenging because of high reservoir-brine salinity and, more importantly, because of high reactivity of the rock minerals. Both features complicate understanding of the COBR surface chemistries pertinent to successful LSW. Here, we tackle the complex physicochemical processes in chemically active carbonates flooded with diluted brine that is saturated with atmospheric carbon dioxide (CO2) and possibly supplemented with additional ionic species, such as sulfates or phosphates. When waterflooding carbonate reservoirs, rock equilibrates with the injected brine over short distances. Injected-brine ion speciation is shifted substantially in the presence of reactive carbonate rock. Our new calculations demonstrate that rock-equilibrated aqueous pH is slightly alkaline quite independent of injected-brine pH. We establish, for the first time, that CO2 content of a carbonate reservoir, originating from CO2-rich crude oil and gas, plays a dominant role in setting aqueous pH and rock-surface speciation. A simple ion-complexing model predicts the calcite-surface charge as a function of composition of reservoir brine. The surface charge of calcite may be positive or negative, depending on speciation of reservoir brine in contact with the calcite. There is no single point of zero charge; all dissolved aqueous species are charge determining. Rock-equilibrated aqueous composition controls the calcite-surface ion-exchange behavior, not the injected-brine composition. At high ionic strength, the electrical double layer collapses and is no longer diffuse. All surface charges are located directly in the inner and outer Helmholtz planes. Our evaluation of calcite bulk and surface equilibria draws several important inferences about the proposed LSW oil-recovery mechanisms. Diffuse double-layer expansion (DLE) is impossible for brine ionic strength greater than 0.1 molar. Because of rapid rock/brine equilibration, the dissolution mechanism for releasing adhered oil is eliminated. Also, fines mobilization and concomitant oil release cannot occur because there are few loose fines and clays in a majority of carbonates. LSW cannot be a low-interfacial-tension alkaline flood because carbonate dissolution exhausts all injected base near the wellbore and lowers pH to that set by the rock and by formation CO2. In spite of diffuse double-layer collapse in carbonate reservoirs, surface ion-exchange oil release remains feasible, but unproved.

On the estimation of CO2 capillary entry pressure: Implications on geological CO2 storage

The CO2 entry pressure for a specific pore space decreases with increasing storage site depth because the interfacial tension is reduced and the system becomes less water-wet with increasing depth. This is based on the assumption that the pore throat size and shape remain the same, i.e., they are not stress-dependent. The dependency of capillary entry pressure with depth in geological CO2 storage has been reported by only few quantitative investigations, which, however, did not account for the interfacial tension and wettability effects of the brine/CO2/solid system.In this work, a workflow and methodology are proposed to quantify the dependency of capillary entry pressure with depth in subsurface geological CO2 storage. The cap-rock pore spaces are treated as straight capillary tubes whose cross-sections are obtained directly from 2D SEM rock images, and the CO2 capillary entry pressure invading these pore spaces is simulated, under arbitrary wetting conditions, with the use of an in-house novel semi-analytical model. In this model, the brine/CO2 interfacial tension is obtained as a function of the two phases (CO2 and brine) density difference, and the contact angle is evaluated based on the Frumkin–Derjaguin equation, and the disjoining pressures isotherm curves is computed from DLVO theory under various CO2 storage pressure, temperature and brine ionic strength conditions. The dependencies of brine/CO2 interfacial tension, contact angle and capillary entry pressure on CO2 storage depth and brine ionic strength are also investigated.This newly developed model can be used to compute CO2 entry pressure and associated fluid configurations in realistic cap-rock pore spaces which can be extracted from 2D rock images from core samples located at various storage depths and under the examined storage site’s pressure, temperature and brine ionic strength conditions. The proposed workflow for capillary entry pressure estimation and its relationship with depth can enhance our understanding and improve the design and safe storage of CO2 in geological formations.

Controls on the pH of hyper-saline lakes – A lesson from the Dead Sea

The pH of aqueous environments is determined by the dominant buffer systems of the water, defined operationally as total alkalinity (TA). The major buffer systems in the modern ocean are carbonic and boric acids of which the species bicarbonate, carbonate and borate make up about 77%, 19% and 4% of the TA, respectively. During the course of seawater evaporation (e.g. lagoons) the residual brine loses considerable portion of the dissolved inorganic carbon (DIC) and carbonate alkalinity (CA) already at the early stages of evaporation. DIC and CA decrease due to massive precipitation of CaCO3, while total boron (TB) increases conservatively, turning borate to the dominant alkalinity species in marine derived brines. In the present work we assess the apparent dissociation constant value of boric acid (KB′) in saline and hypersaline waters, using the Dead Sea (DS) as a case study. We explain the DS low pH (∼6.3) and the effect of the boric and carbonic acid pK′-s on the behavior of the brine's buffer system, including the pH increase that results from brine dilution.The KB′ in DS was estimated from TB, TA, DIC and pH data measured in this study and early empirical data on artificial DS brines containing just carbonic acid. The KB′ value was corroborated by Pitzer ion interaction model calculations using PHREEQC thermodynamic code applied to the chemical composition of the DS. Our results show that KB′ increases considerably with the brine's ionic strength, reaching in the DS to a factor of 100 higher than in “mean” seawater. Based on theoretical calculations and analyses of other natural brines it is suggested that brines' composition is a major factor in determining the KB′ value and in turn the pH of such brines. We show that the higher the proportion of divalent cations in the brine the higher the dissociation constants of the weak acids (presumably due to formation of complexes). The low pH of the Dead Sea is accordingly explained by its extremely high ionic strength (TDS = 348 g/L) and the dominance of the divalent cation, Mg2+. Other natural hyper-saline brines with high concentration of divalent cations such as Kunteyi Lake in China and Don-Juan Pond in Antarctica follow the same general pattern. In contrast, the high pH of soda lakes results not only from their high TA but also by the dominance of the monovalent cation, Na+. Our study emphasizes the strong control of brine composition on pKB′ and pH. These factors should be taken into consideration when reconstructing past and present environmental evaporitic environments.

Forsterite dissolution rates in Mg‐sulfate‐rich Mars‐analog brines and implications of the aqueous history of Mars

AbstractHigh salinity brines, although rare on Earth's surface, may have been important in the geologic history of Mars. Increasing evidence suggests the importance of liquid brines in multiple locations on Mars. In order to interpret the effect of high ionic strength brines on olivine dissolution, which is widely present on Mars, 47 new batch reactor experiments combined with 35 results from a previous study conducted at 25°C from 1 < pH < 4 in magnesium sulfate, sodium sulfate, magnesium nitrate, and potassium nitrate solutions with ionic strengths as high as 12 m show that very high ionic strength brines have an inhibitory effect of forsterite dissolution rates. Multiple linear regression analysis of the data suggests that the inhibition in dissolution rates is due to decreased water activity at high ionic strengths. Regression models also show that mMg up to 4 m and mSO4 up to 3 m have no effect on forsterite dissolution rates. The effect of decreasing dissolution rates with decreasing aH2O is consistent with the idea that water acts as a ligand that participates in the dissolution process. Less available water to participate in the dissolution reaction results in a slower dissolution rate. Multiple linear regression analysis of the data produces the rate equation . Forsterite in dilute solutions with a water activity of one dissolves twice as fast as those in brines with a water activity of 0.8.

Direct chromatographic separation and quantification of calcium and magnesium in seawater and sediment porewaters

Direct analysis of Ca2+ and Mg2+ is required for accurate determination of metastable carbonate mineral phase saturation states (ΩCaCO3; ΩMgCO3) in seawater, sediment porewaters, and other high ionic strength brines. To this end, we have implemented a method using High Performance Chelation Ion Chromatography (HPCIC) in which metal ion complexation at the stationary phase renders separation efficiency insensitive to high ionic strength matrix effects common to other ion chromatography (IC) methods. This method, using direct automated on‐column injection, vastly increases sample throughput capacity in comparison to current titration methods. Calcium and magnesium ions in IAPSO standard seawater were selectively separated using a monolithic silica column (100 × 4.6 mm ID) activated with a covalently bonded iminodiacetic acid (IDA) chelator. The colored ion complexes resulting from post‐column reaction (PCR) of the ions with a metallochromic indicator, in this case 4‐(2‐pyridylazo)‐resorcinol (PAR), were detected spectrophotometricaly at 510 nm. Optimization of flow rate, eluent concentration, pH, and sample injection volume allowed baseline separation of Mg2+(0.05474 mol kg−1) and Ca2+ (0.01065 mol kg−1) in less than 8 min using 2 µL seawater sample injections. At a flow rate of 1 mL min−1, peak elutions occurred respectively at 4 and 5 min, using an eluent containing 0.1 M potassium chloride and 1 mM nitric acid adjusted to pH 2.5. Retention time variability below 0.5% for both metals following more than 200 injections indicates long‐term stability of the derivatized monolithic silica column. Method application to marine sediment porewaters is discussed.

Characterize Scaling Damage From Pressure Measurements

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 112500, "A New Method To Characterize Scaling Damage From Pressure Measurements," by T. Carageorgos, M. Marotti, and P. Bredrikovetsky, SPE, North Fluminense State University, prepared for the 2008 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 13-15 February. The paper has not been peer reviewed. Productivity-decline prediction is based on mathematical modeling with well-known model coefficients. The sulfate-scaling system contains two governing parameters: the kinetics coefficient, λ, characterizing the velocity of chemical reaction, and the formation damage coefficient, β, showing how the permeability decreases because of salt precipitation. This paper extends previous works with commingled injection of two incompatible waters into the same core with two different ratios of formation water (FW) to seawater (SW). Introduction Barium- and strontium-sulfate scaling is a major problem in waterflood projects with incompatible formation and injected waters. Barium sulfate and resulting scale causes formation damage near the production-well zone. This phenomenon is attributed to precipitation of barium and strontium sulfates from the mixture of both waters and the consequent permeability reduction resulting in loss of well productivity. The chemical incompatibility between the injected SW, which is high in sulfate ions, and the FW, which originally contains high concentrations of barium, calcium, and/or strontium ions, may reduce well productivity, making the waterflood project uneconomical. A reliable model that is capable of predicting such scaling problems would help in planning a waterflood project. It also could aid in selecting an effective scale-prevention technique by predicting scaling tendency, type, and potential severity. A reliable predictive model must use well-known values of the model coefficients. The mathematical model for sulfate scaling contains two phenomenological parameters: λ from the active-mass law of chemical reaction showing how fast the reaction and precipitation occurs, and β reflecting the permeability decrease caused by sulfate-salt deposit. Both coefficients depend on rock-surface mineralogy, pore-space structure, temperature, and brine ionic strength. Therefore, they cannot be calculated theoretically for natural reservoirs and must be deter-mined from laboratory corefloods. Reagent- and deposition-concentration profiles during reactive flows are nonuniform, so the sulfate-damage parameters cannot be calculated directly from laboratory measurements. They must be determined from laboratory coreflood data by use of inverse-problem solutions. The λ can be calculated from break-through concentration in a quasisteady-state coreflood with commingled injection of FW and SW. Then β can be determined from the pressure-drop increase during flooding.

A study of the corrosion products of mild steel in high ionic strength brines

The corrosion layer on steel surfaces that formed after exposure to waste isolation pilot plant (WIPP) brines under anoxic conditions was characterized for chemical composition, thickness and phase composition. The chemical composition of the corrosion layer was determined both by X-ray photoelectron spectroscopy (XPS) and by chemical analysis of acid solutions used to remove the corrosion layer. Atomic force microscopic (AFM) images indicated that the brine-corroded surface layer shows extensive granulation along the contours of the steel surface that is characteristic of sharp polishing marks. The corrosion layer seemed to be porous and could be dissolved and detached in dilute hydrochloric acid. The corrosion layer appears to be composed of iron oxides with some ionic substitutions from the brines. The 77 K Mössbauer spectrum recorded for iron powder leached under similar conditions indicated the corrosion layer was comprised principally of green rust.

Formation damage in smectitic sandstones by high ionic strength brines

The effect of different high ionic strength brines on the permeability of smectitic sands which contain both swelling and non-swelling clays has been studied. Results from this study show that at high concentrations of salt solutions (>0.5 M), the permeability of a smectitic sand is affected by the nature of the hydrated cation of the flowing solution. Flow experiments show that when the sand is exposed to monovalent salt solutions, the permeability decreases with increasing radius of hydration of the cation. Furthermore, the damage to the formation (i.e. permeability reduction) is irreversible. The magnitude of the damage decreases with increasing concentration of salt solutions. Reduction in permeability is attributed to fines movement triggered by the crystalline swelling of expandable clay minerals in the smectitic sands. X-ray diffraction analysis of clay samples from these cores confirms that the permeability loss can be attributed to crystalline swelling. The analysis also shows that the basal spacings exhibit hysteresis. These results and the implications of this mechanism of permeability reduction are discussed.

Geoquímica de las lagunas saladas de los Monegros (Zaragoza). l. determinación experimental de los efectos del reequilibrio mirabilita-solucion con la temperatura en un sistema natural

Geochemical evolution of Los Monegros playa-lakes is affected by temperature fluctuations in the brine body at different time scales. Temperature shifts promote seasonally, daily and even during minor cycles mineralogical and compositional changes. Seasonal impacts of temperature change the brine composition and the crystallized mineral sequences (Pueyo, 1978-79). So, during summer cycle minerals crystallize according to the sequence: carbonates-gypsum-halite; and during winter the sequence of precipitation changes to carbonates-gypsum-mirabilite. Daily cycles also exist during winter brine evolution: mirabilite crystallization occurs during spring nights by lowering temperature, whereas diurnal temperatures promote its dissolution. And when high saturation levels are reached by evaporative concentration and the amount of precipitated mirabilite is important in the system (mirabilite stage, at spring), diurnal temperature fluctuations induce quick mirabilite-solution reequilibrium processes. Sampling of brines during this stage and thermodynamic calculations through the extended HMW model (Harvie, Moller and Weare, 1984) enclosed in the PHRQPITZ code (Plummer et al., 1988) indicate that mirabilite equilibrium holds in spite of variations in the concentration degree and temperature of samples. Field observations confirm that the reequilibrium process is efective in a few minutes when temperature varies only sorne degrees. Experimental determination of mirabilite solubility between Oand 30oC, using a natural brine sampled in advanced concentration stage, allows to isolate temperature effects on solution composition from those of evaporative concentration. Results indicate that modifications of mirabilite solubility produce their maximum effects between 20-30oC, fluctuation common in the natural system during spring: several hundreds of grams/kg water of mirabilite are mobilized, brine ionic strength changes from 4 to 8 molal and water activity varies from 0.943 to 0.896. Thenardite, bloedite and glauberite saturation states are affected by that reequilibrium process but those of gypsum and halite are almost insensitive to it. Predicted brine evolution by means of classical chemical divide or generalized residual alkalinity rules fails because of the special characters of these systems (high concentration solutions and evolution paths under variable temperature conditions). This non-isothermal evolution must be taken into account in more elaborated physicochemical approaches to brine evolution: the normal simplification using isothermal conditions (25oC) in thermodynamic calculations leads to important discrepancies in the predicted timing of mirabilite precipitation refered to field observations. Partial validation of the extended HMW model by comparison of laboratory and field solubility data appear to be confirmed.

A chemical model for the evolution of Australian sodium chloride lake brines

We present a chemical model which calculates the composition of waters as they are progressively concentrated from various starting compositions to determine the important processes leading to the development of Na-Cl type brines typical of Australia. The model can be extended to other continental settings which are characterised by low rainfall, low topographic relief and highly weathered regolith. The model extends previous brine evolution models to include clay mineral-solution reactions as a means of controlling aqueous silica concentrations and we suppress K + concentrations via clay mineral interactions. Our model also evaluates the importance of elevated partial pressures of CO 2 which mimics situations encountered in groundwaterfed systems. Several important controls on major ion evolution were observed: 1. (1) Initial Ca/Alkalinity ratios must be greater than 0.5 to generate Cl-rich brines of circum-neutral pH. One-thousand fold concentration of average Australian river water (Ca/Alk = 0.31) generates alkaline, high pH, brines while the same ionic strength brine derived from mean Australian rainwater (Ca/Alk = 1.2) generates a brine which is two orders of magnitude lower in alkalinity. 2. (2) Elevated pCO 2 values which occur in subsurface waterssuppresses precipitation of carbonate minerals. This allows Ca to build up more quickly thereby accelerating the onset of gypsum precipitation. 3. (3) Aqueous silica concentrations are controlled by equilibrium with clay minerals in the “dilute” waters but reach amorphous silica saturation in concentrated brines because of the reduced activity of the neutral SiO 2(aq) species in high ionic-strength brines. 4. (4) Continual dissolution and reprecipitation of salts in the groundwaters or efflorescent crusts are responsible for minor-and trace-element ratios very different from that of the initial starting waters.