CO2-brine Interfacial Tension Research Articles

Improved neural network model based on dung beetle algorithm to predict CO2-brine interfacial tension

Geological carbon sequestration refers to the permanent storage of captured CO2 through injection into subterranean saline or rock formations. The CO2-brine interfacial tension (IFT) is a crucial factor that significantly impacts the process's efficacy. Since the experimental determination of the IFT of brine and CO2 is both time-consuming and expensive, and a variety of sources of error may occur, developing a well-prepared and dependable model of CO2-brine IFT is crucial. In this paper, an attempt has been made to investigate the dung beetle optimization algorithm based back propagation neural network (DBO-BPNN) model for predicting CO2-brine IFT. The model contains 2616 experimental data of CO2-brine/water interfacial tension collected from various literatures, which can be divided into three regimes to be investigated: pure CO2-brine, pure CO2-water and impure CO2-water, and takes into account six independent variables: pressure, temperature, monovalent cation molality (Na+ and K+), bivalent cation molality (Ca2+ and Mg2+) in brine and the molar fractions of N2 and CH4 in the injected CO2 stream. The model's efficacy is assessed using a range of statistical and graphical techniques, and the model's validity is validated through the implementation of leverage methods, which identify anomalies across the entire dataset. Finally, the model is further compared with other intelligent models such as particle swarm optimization (PSO)-BPNN and grey wolf optimizer (GWO)-BPNN in terms of runtime, storage space and accuracy. According to the results, the DBO-BPNN model provides the best levels of accuracy and precision, with determination coefficient (R2), root mean square error (RMSE) and average absolute relative deviation (AARD%) of 0.9743, 1.598 and 3.16, respectively, and the R2 is enhanced by 0.8% and 2.2% in comparison to GWO-BPNN and PSO-BPNN models. Additionally, the DBO-BPNN model exhibits the least execution time, a reduction of 6.4% and 13.1% in comparison to GWO-BPNN and PSO-BPNN models, respectively. In addition, the DBO-BPNN model occupies storage space in the middle of the GWO-BPNN and PSO-BPNN models. The findings establish a dependable and robust framework that enables precise forecasting of the CO2-brine IFT.

CO2-brine interfacial tension correlation based on the classical orthogonal polynomials: monovalent salts with common anion

CO2-brine interfacial tension correlation based on the classical orthogonal polynomials: monovalent salts with common anion

Influence of carbon nanodots on the Carbonate/CO2/Brine wettability and CO2-Brine interfacial Tension: Implications for CO2 geo-storage

Understanding the interfacial and wettability phenomena of the CO2-brine and rock-CO2-brine system plays a key role in the geo-storage of CO2 and in their security containment. Carbon nanodots (CNDs) have been identified as a promising surface-active agent for altering the wettability from strongly oil-wet into water-wet in the carbonate reservoirs, thus it contributed for the oil recovery increment in the carbonate formations. However, no consideration was given to the application of CNDs for the enhancement of CO2 geological storage and containment security in the carbonate formations. In the current study, we assessed the impact of CNDs on the residual and structural trapping of CO2 in the carbonate reservoir. The contact angles (θ) of the CO2-brine-carbonate rock system were studied before and after the treatment of CNDs for both the clean and crude oil-aged samples. Subsequently, we also investigated the CO2-seawater interfacial tensions (IFT) with and without CNDs addition. All these measurements were performed as a function of CNDs concentration (0–1000 ppm), temperature (20–80 °C) and pressure (14.7–3000 psi). The results showed that the clean carbonate rock remained strongly water-wet before and after CNDs-treatment. The oil-wet carbonate sample was turned into CO2-wet at all investigated temperatures when the pressures increased to 1000 psi, however, it turns to be weakly water-wet upon treatment with CNDs at the highest pressure (3000 psi). Specifically, at 3000 psia and 20 °C, the contact angle of oil-wet carbonate reduced from 122° to 86° with the addition of CNDs at the increased concentration of 1000 ppm. Such wettability modifications in carbonate formations will enhance the efficacy of CO2 storage potential, and eventually, this will help to de-risk their security containment. The θ generally demonstrated a declining trend with the increase of CNDs concentration but it slightly increased with the rise in temperature and pressure. These results suggest that warmer reservoirs and increased storage depth could be unfavorable for CO2 storage in carbonate formations. Thus, the pre-injection of a minimal concentration of CNDs in the formation would improve CO2 storage effectively. Also, no significant change was observed in the CO2-seawater IFT in the presence of CNDs, which indicates that the capillary trapping of CO2 could be favorable due to their lower contact angle and high CO2-brine IFT as the most suitable condition to maintain the high capillarity. The study demonstrates that the highly stable, freely soluble, easy detectable, scalable, and economically viable CNDs has the potency to enhance the containment security of CO2 in carbonate formation.

An improved simple correlation for accurate estimation of CO2-Brine interfacial tension at reservoir conditions

A newly developed CO2−brine interfacial tension (IFT) correlation has been successfully developed to more accurately estimate the CO2−brine IFT for a wide range of reservoir pressure, temperature, and formation water salinity. The new CO2−brine correlation is expressed as a function of CO2-water density difference (function of pressure and temperature), temperature, and the valence-weighted molality of the cations. The novel aspect of the approach was to both correlate with density difference and include accurate temperature dependence of the parameters. This prediction model originated from a CO2−brine IFT database from the literature that covers 1298 CO2−brine IFT data including 484 for pure water and CO2. To examine its predictive capacity, the new CO2−brine IFT correlation is compared with four commonly used IFT correlations in the literature. It is found that the new CO2−brine IFT correlation provides more comprehensive and accurate reproduction of the literature pure CO2−pure water IFT data with an average absolute relative error (AARE) of 2.4% and standard deviation (SD) of 3.2%. In addition, the newly developed CO2−brine IFT correlation results in the accurate prediction of the CO2−brine IFT with an AARE of 2.4% and a SD of 3.4%.

Effect of Fluid–Rock Interactions on In Situ Bacterial Alteration of Interfacial Properties and Wettability of CO2–Brine–Mineral Systems for Geologic Carbon Storage

This study explored the feasibility of biosurfactant amendment in modifying the interfacial characteristics of carbon dioxide (CO2) with rock minerals under high-pressure conditions for GCS. In particular, while varying the CO2 phase and the rock mineral, we quantitatively examined the production of biosurfactants by Bacillus subtilis and their effects on interfacial tension (IFT) and wettability in CO2-brine-mineral systems. The results demonstrated that surfactin produced by B. subtilis caused the reduction of CO2-brine IFT and modified the wettability of both quartz and calcite minerals to be more CO2-wet. The production yield of surfactin was substantially greater with the calcite mineral than with the quartz mineral. The calcite played the role of a pH buffer, consistently maintaining the brine pH above 6. By contrast, an acidic condition in CO2-brine-quartz systems caused the precipitation of surfactin, and hence surfactin lost its ability as a surface-active agent. Meanwhile, the CO2-driven mineral dissolution and precipitation in CO2-brine-calcite systems under a non-equilibrium system altered the solid substrates, produced surface roughness, and caused contact angle variations. These results provide unique experimental data on biosurfactant-mediated interfacial properties and wettability in GCS-relevant conditions, which support the exploitation of in situ biosurfactant production for biosurfactant-aided CO2 injection.

A Supervised Learning Approach for Accurate Modeling of CO2–Brine Interfacial Tension with Application in Identifying the Optimum Sequestration Depth in Saline Aquifers

The CO2-brine interfacial tension (IFT) is a key parameter affecting the CO2 storage capacity in saline aquifers and therefore, should be accurately characterized to ensure the optimal design of CO...

Measurement and estimation of CO2–brine interfacial tension and rock wettability under CO2 sub- and super-critical conditions

Saline aquifer storage is considered to be a promising method of carbon dioxide (CO2) mitigation. The CO2–brine interfacial tension (IFT) and the caprock wettability under reservoir temperature and pressure conditions are essential for storage capacity estimation. In this study, the CO2–brine (NaCl + KCl) IFTs were obtained by using the pendant drop method under 298–373 K temperature, 3–15 MPa pressure, and 1.0–4.9 mol·kg−1 salinity. A detailed analysis of the relationship of IFT with temperature, pressure, and salinity was conducted. In addition, an empirical equation was developed to estimate the CO2–brine IFTs in a wide range of temperatures, pressures, and salt molality. The contact angles (CAs) of brine on quartz, Berea Sandstone, and limestone surfaces in the presence of supercritical, liquid, and gaseous CO2 were measured by using the sessile drop method, and the wettability alteration of the rock surfaces in the presence of supercritical CO2 was systematically investigated. According to the results, the CO2–brine IFTs increased with salinity and temperature and decreased with pressure until reaching a plateau. For a CO2–mixed brine system, a linear relationship between the IFT increase (Δγ) and molality was observed. The CAs of the different rock samples varied with temperature and pressure. However, all the three rock samples became less water-wet when the CO2 phase state changed from subcritical to supercritical.

Impact of nanoparticles on the CO2-brine interfacial tension at high pressure and temperature

HypothesisNanofluid flooding has been identified as a promising method for enhanced oil recovery (EOR) and improved Carbon geo-sequestration (CGS). However, it is unclear how nanoparticles (NPs) influence the CO2-brine interfacial tension (γ), which is a key parameter in pore-to reservoirs-scale fluid dynamics, and consequently project success. The effects of pressure, temperature, salinity, and NPs concentration on CO2-silica (hydrophilic or hydrophobic) nanofluid γ was thus systematically investigated to understand the influence of nanofluid flooding on CO2 geo-storage. ExperimentsPendant drop method was used to measure CO2/nanofluid γ at carbon storage conditions using high pressure-high temperature optical cell. FindingsCO2/nanofluid γ was increased with temperature and decreased with increased pressure which is consistent with CO2/water γ. The hydrophilicity of NPs was the major factor; hydrophobic silica NPs significantly reduced γ at all investigated pressures and temperatures while hydrophilic NPs showed only minor influence on γ. Further, increased salinity which increased γ can also eliminate the influence of NPs on CO2/nanofluid γ. Hence, CO2/brine γ has low, but, reasonable values (higher than 20 mN/m) at carbon storage conditions even with the presence of hydrophilic NPs, therefore, CO2 storage can be considered in oil reservoirs after flooding with hydrophilic nanofluid.The findings of this study provide new insights into nanofluids applications for enhanced oil recovery and carbon geosequestration projects.

Effects of Na+, K+, Ca2+, and Mg2+ cations on CO2–brine interfacial tension under offshore storage conditions

AbstractThe laboratory determination of CO2‐brine interfacial tension is very important for estimating the storage capacity of saline aquifers during the CO2 sequestration process. In this paper, we measured CO2 and the brine interfacial tension using the pendant‐drop method at a temperature of 285–300 K and pressure of 3–9 MPa. The brine was composed of Na+, K+, Ca2+, and Mg2+ cations with different molalities. The experimental results indicate that interfacial tension increased with temperature and salinity but decreased with pressure until it reached a plateau. At the same temperature and pressure, the plateau value increased with increasing brine salinity for all types of brines used in this work. Moreover, the plateau exists whenever the CO2 is liquid. The interfacial tension between CO2 and brine with bivalent cations is larger than that between CO2 and monovalent brines. Finally, we established an empirical equation based on the relationship between interfacial tension and temperature, pressure, and salt molality grounded on experimental data, which allows the evaluation of CO2–brine interfacial tension values with a mean deviation of ±4 mN·m−1. © 2018 Society of Chemical Industry and John Wiley & Sons, Ltd.

Modeling of CO2-brine interfacial tension: Application to enhanced oil recovery

ABSTRACTDevelopment of reliable and accurate models to estimate carbon dioxide–brine interfacial tension (IFT) is necessary, since its experimental measurement is time-consuming and requires expensive experimental apparatus as well as complicated interpretation procedure. In the current study, feed forward artificial neural network is used for estimation of CO2–brine IFT based on data from published literature which consists of a number of carbon dioxide–brine interfacial tension data covering broad ranges of temperature, total salinity, mole fractions of impure components and pressure. Trial-and-error method is utilized to optimize the artificial neural network topology in order to enhance its capability of generalization. The results showed that there is good agreement between experimental values and modeling results. Comparison of the empirical correlations with the proposed model suggests that the current model can predict the CO2–brine IFT more accurately and robustly.

Characterizing the CO2-brine interfacial tension (IFT) using robust modeling approaches: A comparative study

Interfacial phenomenon between CO2 and aqueous phases affects the distribution and behavior of fluids in porous media, and also plays a major role in determining the usefulness of enhanced oil recovery methods particularly CO2 flooding. Therefore, in this study, the interfacial tension (IFT) between CO2 and brine is predicted as a function of the temperature, pressure, bivalent cation molality, monovalent cation molality as well as methane and nitrogen mole fractions using three robust modeling strategies called gene expression programming (GEP), decision tree (DT), and least squares support vector machine (LSSVM). Furthermore, the outcomes obtained by the methods mentioned above have been assessed by comparing with the reported estimates of artificial neural network (ANN) in the literature. Amongst the all models proposed in the current study, it is demonstrated that the developed regression DT tool and the available ANN in literature are the most precise models which could be applied properly as the reliable methods for the characterization and determination of IFT between CO2 and brine, and also for geological CO2 storage.

On the estimation of CO2-brine interfacial tension

Measurement of CO2-brine interfacial tension (IFT) in laboratory is time consuming, expensive and may exhibit various sources of errors. Hence, developing precise models for estimation of the CO2-brine IFT sounds to be greatly important. In this work, it has been attempted to study the application of two computer based models, namely radial basis function neural network optimized by particle swarm optimization method (PSO-RBF) and adaptive neuro-fuzzy inference system trained by hybrid method (Hybrid-ANFIS) for estimation of CO2-brine IFT. It is worthwhile to state that the database of this work includes 1716 CO2-brine IFT data collected from literature. The brine consists of NaCl, KCl, Na2SO4, MgCl2 or CaCl2. The performance of these models was evaluated through various statistical and graphical methods. The results of the above-mentioned models were also measured against four correlations of IFT presented in former literature works. Consequently, it was found that the aforementioned models exhibit more accurate results than empirical correlations for different systems including pure CO2-pure water, pure CO2-brine and impure CO2-water systems. Furthermore, the Hybrid-ANFIS model provides superior and most precise outcomes compared to PSO-RBF model with an overall R2 and AARD% values of 0.9892 and 1.96%, respectively.

Impact of pressure and temperature on CO2–brine–mica contact angles and CO2–brine interfacial tension: Implications for carbon geo-sequestration

Precise characterization of wettability of CO2–brine–rock system and CO2–brine interfacial tension at reservoir conditions is essential as they influence capillary sealing efficiency of caprocks, which in turn, impacts the structural and residual trapping during CO2 geo-sequestration. In this context, we have experimentally measured advancing and receding contact angles for brine–CO2–mica system (surface roughness ∼12nm) at different pressures (0.1MPa, 5MPa, 7MPa, 10MPa, 15MPa, 20MPa), temperatures (308K, 323K, and 343K), and salinities (0wt%, 5wt%, 10wt%, 20wt% and 30wt% NaCl). For the same experimental matrix, CO2–brine interfacial tensions have also been measured using the pendant drop technique. The results indicate that both advancing and receding contact angles increase with pressure and salinity, but decrease with temperature. On the contrary, CO2–brine interfacial tension decrease with pressure and increase with temperature. At 20MPa and 308K, the advancing angle is measured to be ∼110°, indicating CO2-wetting. The results have been compared with various published literature data and probable factors responsible for deviations have been highlighted. Finally we demonstrate the implications of measured data by evaluating CO2 storage heights under various operating conditions. We conclude that for a given storage depth, reservoirs with lower pressures and high temperatures can store larger volumes and thus exhibit better sealing efficiency.

Estimation of CO2–brine interfacial tension using an artificial neural network

Experimental determination of CO2–brine interfacial tension (IFT) usually requires expensive apparatus and sophisticated interpretation procedure and is time-consuming. Hence, it is of practical importance to develop an accurate and reliable model for determining the CO2–brine IFT. This paper presents the use of feed forward artificial neural network (ANN) to accurately estimate CO2–brine IFT based on a database acquired from previous literature. The database consists of a total of 1716 CO2–brine IFT datasets that cover relatively large ranges of pressure (0.1–60.05MPa), temperature (5.25–175°C), total salinity (0–5molkg−1) and mole fractions (0–80%) of impure components. Six independent variables were considered to develop the IFT estimation model: pressure, temperature, monovalent cation (Na+ and K+) molality, bivalent cation (Ca2+ and Mg2+) molality in brine, and mole fractions of N2 and CH4 in injected CO2 streams. The ANN topology was optimized by trial-and-error in order to enhance its capability of generalization and the optimal one was determined to be 6-10-20-1 (10 and 20 neurons in the first and second hidden layers, respectively). The accuracy of the proposed ANN model was highlighted by four evaluation matrices, namely mean absolute error (MAE), mean absolute relative error (MARE), mean squared error (MSE), and determination coefficient (R2) between the measured and estimated IFT. The ANN model was further compared against four empirical IFT correlations developed in previous studies. It was observed that the ANN model outperforms significantly the empirical correlations and provides the most accurate IFT reproduction with respect to pure CO2–pure water, pure CO2–brine and impure CO2 systems.

Accurate Determination of the CO2–Brine Interfacial Tension Using Graphical Alternating Conditional Expectation

A newly developed CO2–brine interfacial tension (IFT) correlation based on the alternating condition expectation (ACE) algorithm has been successfully proposed to more accurately estimate the CO2–brine IFT for a wide range of reservoir pressure, temperature, formation water salinity and injected gas composition. The new CO2–brine correlation is expressed as a function of reservoir pressure, temperature, monovalent cation molalities (Na+ and K+), bivalent cation molalities (Ca2+ and Mg2+), N2 mole fraction and CH4 mole fraction in injected gas. This prediction model is originated from a CO2–brine IFT database from the literature that covers 1609 CO2–brine IFT data for pure and impure CO2 streams. To test the validity and accuracy of the developed CO2–brine IFT model, the entire dataset was divided into two groups: a training database consisting of 805 points and a testing dataset consisting of 804 points, which was arbitrarily selected from the total database. To further examine its predicted capacity, the...