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

Effect of Sulfate-Based Scales on Calcite Mineral Surface Chemistry: Insights from Zeta-Potential Experiments and Their Implications on Wettability

Scale formation and deposition in the subsurface and surface facilities have been recognized as a major cause of flow assurance issues in the oil and gas industry. Sulfate-based scales such as sulfates of calcium (anhydrite and gypsum) and barium (barite) are some of the commonly encountered scales during hydrocarbon production operations. Oilfield scales are a well-known flow assurance problem, which occurs mainly due to the mixing of incompatible brines. Researchers have largely focused on the rocks' petrophysical property modifications (permeability and porosity damage) caused by scale precipitation and deposition. Little or no attention has been paid to their influence on the surface charge and wettability of calcite minerals. Thus, this study investigates the effect of anhydrite and barite scales' presence on the calcite mineral surface charge and their propensity to alter the wetting state of calcite minerals. This was achieved vis-à-vis zeta-potential (ζ-potential) measurement. Furthermore, two modes of the scale control (slug and continuous injections) using ethylenediaminetetraacetic acid (EDTA) were examined to determine the optimal control strategy as well as the optimal inhibitor dosage. Results showed that the presence of anhydrite and barite scales in a calcite reservoir affects the colloidal stability of the system, thus posing a threat of precipitation, which would result in permeability and porosity damage. Also, the calcite mineral surface charge is affected by the presence of calcium and barium sulfate scales; however, the magnitude of change in the surface charge via ζ-potential measurement is insignificant to cause wettability alteration by the mineral scales. Slug and continuous injections of EDTA were implemented, with the optimal scale control strategy being the continuous injection of EDTA solutions. The optimal dosage of EDTA for anhydrite scale control is 5 and 1 wt % for the formation water and seawater environments, respectively. In the case of barite, in both environments, an EDTA dosage of 1 wt % suffices. Findings from this study not only further the understanding of the scale effects on calcite mineral systems but also provide critical insights into the potential of scale formation and their mechanisms of interactions for better injection planning and the development of a scale control strategy.

Data-Driven Connectionist Models for Performance Prediction of Low Salinity Waterflooding in Sandstone Reservoirs

Low salinity waterflooding (LSWF) and its variants also known as smart water or ion tuned water injection have emerged as promising enhanced oil recovery (EOR) methods. LSWF is a complex process controlled by several mechanisms and parameters involving oil, brine, and rock composition. The major mechanisms and processes controlling LSWF are still being debated in the literature. Thus, the establishment of an approach that relates these parameters to the final recovery factor (RF_f) is vital. The main objective of this research work was to use a number of artificial intelligence models to develop robust predictive models based on experimental data and main parameters controlling the LSWF determined through sensitivity analysis and feature selection. The parameters include properties of oil, rock, injected brine, and connate water. Different operational parameters were considered to increase the model accuracy as well. After collecting the relevant data from 99 experimental studies reported in the literature, the database underwent a comprehensive and rigorous data preprocessing stage, which included removal of duplicates and low-variance features, missing value imputation, collinearity assessment, data characteristic assessment, outlier removal, feature selection, data splitting (80-20 rule was applied), and data scaling. Then, a number of methods such as linear regression (LR), multilayer perceptron (MLP), support vector machine (SVM), and committee machine intelligent system (CMIS) were used to link 1316 data samples assembled in this research work. Based on the obtained results, the CMIS model was proven to produce superior results compared to its counterparts such that the root mean squared rrror (RMSE) values for both training and testing data are 4.622 and 7.757, respectively. Based on the feature importance results, the presence of Ca²⁺ in the connate water, Na⁺ in the injected brine, core porosity, and total acid number of the crude oil are detected as the parameters with the highest impact on the RF_f. The CMIS model proposed here can be applied with a high degree of confidence to predict the performance of LSWF in sandstone reservoirs. The database assembled for the purpose of this research work is so far the largest and most comprehensive of its kind, and it can be used to further delineate mechanisms behind LSWF and optimization of this EOR process in sandstone reservoirs.

Data-Driven Analyses of Low Salinity Waterflooding in Carbonates

Low salinity water (LSW) injection is a promising Enhanced Oil Recovery (EOR) technique that has the potential to improve oil recovery and has been studied by many researchers. LSW flooding in carbonates has been widely evaluated by coreflooding tests in prior studies. A closer look at the literature on LSW in carbonates indicates a number of gaps and shortcomings. It is difficult to understand the exact relationship between different controlling parameters and the LSW effect in carbonates. The active mechanisms involved in oil recovery improvement are still uncertain and more analyses are required. To predict LSW performance and study the mechanisms of oil displacement, data collected from available experimental studies on LSW injection in carbonates were analyzed using data analysis approaches. We used linear regression to study the linear relationships between single parameters and the incremental recovery factor (RF). Correlations between rock, oil, and brine properties and tertiary RF were weak and negligible. Subsequently, we analyzed the effect of oil/brine parameters on LSW performance using multivariable linear regression. Relatively strong linear correlations were found for a combination of oil/brine parameters and RF. We also studied the nonlinear relationships between parameters by applying machine learning (ML) nonlinear models, such as artificial neural network (ANN), support vector machine (SVM), and decision tree (DT). These models showed better data fitting results compared to linear regression. Among the applied ML models, DT provided the best correlation for oil/brine parameters, as ANN and SVM overfitted the testing data. Finally, different mechanisms involved in the LSW effect were analyzed based on the changes in the effluent PDIs concentration, interfacial tension, pH, zeta potential, and pressure drop.

Impact of Iron Minerals in Promoting Wettability Alterations in Reservoir Formations

Asphaltene adsorption and deposition onto rock surfaces are predominantly the cause of wettability and permeability alterations which result in well productivity losses. These alterations can be induced by rock-fluid interactions which are affected by well operations such as acidizing, stimulation, gas injections, and so forth. Iron minerals are found abundantly in sandstone reservoir formations and pose a problem by precipitation and adsorption of polar crude components. This is due to rock-fluid interactions, which are dependent on reservoir pH; thus, this research work studied the surface charge development of pyrite, magnetite, and hematite. To ascertain conditions that will result in iron mineral precipitation and adsorption of asphaltene on iron mineral surfaces, zeta potential measurement was carried out. This is to determine the charge and colloidal stability of the iron mineral samples across wide pH values. Experimental results show that the charge development of iron minerals is controlled by mineral dissolution, the formation of complexes, adsorption of ions on the mineral surface, and the collapse of the double layer. The findings provide insights into the implications of iron mineral contacting crude oil in reservoir formations and how they contribute to wettability alterations due to different well operations.

Role of Monovalent and Divalent Ions in Low-Salinity Water Flood in Carbonate Reservoirs: An Integrated Analysis through Zeta Potentiometric and Simulation Studies

The presence of principal ions in the water injected is essential for enhanced oil recovery by formation of water-wet state in carbonates. This study reaffirms this and presents an evaluation of the positive influence of both divalent as wells as monovalent ions on wettability alteration mechanisms during low salinity waterflooding using brines of varying ionic composition, referred to as “smart brines”. Zeta potentiometric analysis and reservoir simulation studies were conducted with diluted and smart brines that were prepared by varying the composition of principal ions. Surface charge of oil-saturated whole core samples of rock in the presence of various diluted and smart brines was estimated by zeta potential measurements. A comprehensive analysis of zeta potentiometric and reservoir simulation studies was done to establish and investigate the linkage between the recovery mechanism and the incremental recovery achieved. It is noted that zeta potential increases with the increasing level of dilution and it can be attributed to electric double-layer mechanism. On the contrary, simulation studies implied a different mechanism where an increase in effluent’s pH and Ca2+ mole fraction along with decrease in moles of minerals and saturation index implied rock dissolution was dominant mechanism. Moreover, the effect of mineral dissolution beyond the injection block is highly doubtful. This study demonstrates that an integrated approach from both zeta potentiometric and simulation studies can be used to provide insights into the underlying science of interactions at pore scale during a low salinity waterflood using smart brines. With the aid of an adequately designed upscaling procedure and protocol, the laboratory results can be further used towards developing field-scale models to obtain with realistic recovery factors with optimized brine composition and salinity.

A mechanistic investigation of low salinity water flooding coupled with ion tuning for enhanced oil recovery

Oil recovery by low salinity water flooding (LSWF) from carbonate reservoirs has gained tremendous attention in recent years due to its cost-effectiveness and environment-friendly nature. The mechanisms of low salinity water flooding for enhanced oil recovery are very complex and depend on the mineralogy of the formation rock, properties of injection brine and reservoir fluids. The present work aimed at the optimization of salinity and concentration of potential determining ions (PDIs) in injection water for enhanced oil recovery from carbonate reservoirs. Initially, we conducted a series of experiments on the dilution effect of seawater (SW) with the help of rock/fluid and fluid/fluid interactions via interfacial tension (IFT), zeta potential and contact angle measurements. This offered an optimum salinity (20dSW) with an 11% increase in recovery of the original oil in place (OOIP) over the SW injection in secondary flooding mode. Then, the ion tuning was done on the optimum salinity (20dSW) by manipulating the PDIs (Ca²⁺, SO₄ ^2- and Mg²⁺) while keeping ionic strength constant. The properties of ion tuned brine were optimized by zeta potential and contact angle measurements. The core flooding experiments performed with the injection of designed ion tuned water obtained by dilution and ion tuning of SW showed more than 20% OOIP as incremental recovery over the SW injection. Effluent analysis after the flooding confirms that the main mechanisms for enhanced oil recovery include calcite dissolution and wettability alteration due to interplay of PDIs.

Review of low salinity waterflooding in carbonate rocks: mechanisms, investigation techniques, and future directions

This review analyses the fundamental thermodynamic theory of the crude oil-brine-rock (COBR) interface and the underlying rock-brine and oil-brine interactions. The available data are then reviewed to outline potential mechanisms responsible for increased oil recovery from low salinity waterflooding (LSWF). We propose an approach to studying LSWF and identify the key missing links that are needed to explain observations at multiple length scales. The synergistic effect of LSWF on other chemical enhanced oil recovery methods such as surfactant, alkaline, nanoparticle and polymer flooding are also outlined. We specifically highlight key uncertainties that must be overcome to fully implement the technique in the field.

Variations in Wettability and Interfacial Tension during Alkali-Polymer Application for High and Low TAN Oils

The injection of chemicals into sandstones can lead to alterations in wettability, where oil characteristics such as the TAN (total acid number) may determine the wetting state of the reservoir. By combining the spontaneous imbibition principle and the evaluation of interfacial tension index, we propose a workflow and comprehensive assessment to evaluate the wettability alteration and interfacial tension (IFT) when injecting chemical-enhanced oil-recovery (EOR) agents. This study examines the effects on wettability alteration due to the application of alkaline and polymer solutions (separately) and the combined alkali–polymer solution. The evaluation focused on comparing the effects of chemical agent injections on wettability and IFT due to core aging (non-aged, water-wet and aged, and neutral to oil-wet), brine composition (mono vs. divalent ions); core mineralogy (~2.5% and ~10% clay), and crude oil type (low and high TAN). Amott experiments were performed on cleaned water-wet core plugs as well as on samples with a restored oil-wet state. IFT experiments were compared for a duration of 300 min. Data were gathered from 48 Amott imbibition experiments with duplicates. The IFT and baselines were defined in each case for brine, polymer, and alkali for each set of experiments. When focusing on the TAN and aging effects, it was observed that in all cases, the early time production was slower and the final oil recovery was longer when compared to the values for non-aged core plugs. These data confirm the change in rock surface wettability towards a more oil-wet state after aging and reverse the wettability alteration due to chemical injections. Furthermore, the application of alkali with high TAN oil resulted in a low equilibrium IFT. By contrast, alkali alone failed to mobilize trapped low TAN oil but caused wettability alteration and a neutral–wet state of the aged core plugs. For the brine composition, the presence of divalent ions promoted water-wetness of the non-aged core plugs and oil-wetness of the aged core plugs. Divalent ions act as bridges between the mineral surface and polar compound of the in situ created surfactant, thereby accelerating wettability alteration. Finally, for mineralogy effects, the high clay content core plugs were shown to be more oil-wet even without aging. Following aging, a strongly oil-wet behavior was exhibited. The alkali–polymer is demonstrated to be efficient in the wettability alteration of oil-wet core plugs towards a water-wet state.

Hybrid Engineered Water–Polymer Flooding in Carbonates: A Review of Mechanisms and Case Studies

The fast depletion of oil reserves has steered the petroleum industry towards developing novel and cost-effective enhanced oil recovery (EOR) techniques in order to get the most out of reservoirs. Engineered water–polymer flooding (EWPF) is an emerging hybrid EOR technology that uses the synergetic effects of engineered water (EW) and polymers to enhance both the microscopic and macroscopic sweep efficiencies, which mainly results from: (1) the low-salinity effect and the presence of active ions in EW, which help in detachment of carboxylic oil material from the rock surface, wettability alteration, and reduction in the residual oil saturation; (2) the favorable mobility ratio resulting from the use of a polymer; and (3) the improved thermal and salinity resistance of polymers in EW. Various underlying mechanisms have been proposed in the literature for EW EOR effects in carbonates, but the main driving factors still need to be understood properly. Both polymer flooding (PF) and EW have associated merits and demerits. However, the demerits of each can be overcome by combining the two methods, known as hybrid EWPF. This hybrid technique has been experimentally investigated for both sandstone and carbonate reservoirs by various researchers. Most of the studies have shown the synergistic benefits of the hybrid method in terms of two- to four-fold decreases in the polymer adsorption, leading to 30–50% reductions in polymer consumption, making the project economically viable for carbonates. EWPF has resulted in 20–30% extra oil recovery in various carbonate coreflood experiments compared to high-salinity water flooding. This review presents insights into the use of hybrid EWPF for carbonates, the main recovery driving factors in the hybrid process, the advantages and limitations of this method, and some areas requiring further work.

A Laboratory Approach on the Hybrid-Enhanced Oil Recovery Techniques with Different Saline Brines in Sandstone Reservoirs

As foams are not thermodynamically stable and might be collapsed, foam stability is defined by interfacial properties and bulk solution. In this paper, we investigated foam injection and different salinity brines such as NaCl, CaCl2, KCl, and MgCl2 to measure cumulative oil production. According to the results of this experiment, it is concluded that sequential low-salinity water injections with KCl and foam flooding have provided the highest cumulative oil production in sandstone reservoirs. This issue is related to high wettability changes that had been caused by the KCl. As K+ is a monovalent cation, KCl has the highest wettability changes compared to other saline brines and formation water at 1000 ppm, which is due to the higher wettability changes of potassium (K+) over other saline ions. The interfacial tension for KCl at the lowest value is 1000 ppm and, for MgCl2, has the highest value in this concentration. Moreover, the formation brine, regarding its high value of salty components, had provided lower cumulative oil production before and after foam injection as it had mobilized more in the high permeable zones and, therefore, large volumes of oil would be trapped in the small permeable zones. This was caused by the low wettability alteration of the formation brine. Thereby, formation water flowed in large pores and the oil phase remained in small pores and channels. On the other hand, as foams played a significant role in the mobility control and sweep efficiency, at 2 pore volume, foam increased the pressure drop dramatically after brine injection. Consequently, foam injection after KCl brine injection had the maximum oil recovery factor of 63.14%. MgCl2 and formation brine had 41.21% and 36.51% oil recovery factor.

Effects of Slug Size, Soaking, and Injection Schemes on the Performance of Controlled Ions Water Flooding in Carbonates

The results of many previous studies on low salinity/controlled ions water (CIW) flooding suggest that future laboratory and modeling investigations are required to comprehensively understand and interpret the achieved observations. In this work, the aim is co-optimization of the length of the injected slug and soaking time in the CIW flooding process. Furthermore, the possibility of the occurrence of several governing mechanisms is studied. Therefore, the experimental results were utilized to develop a compositional model, using CMG GEM software, in order to obtain the relative permeability curves by history matching. It was concluded that CIW slug injection, concentrated in the potential-determining ion, can increase oil recovery under a multi ion exchange (MIE) mechanism. The wettability of the carbonate rocks was changed from a mixed or oil wet state toward more water wetness. However, there is a CIW slug length, beyond which extending the length does not significantly improve the rock wettability, and consequently, the oil production, which is known as the optimum slug size. This implies that the optimization of the injection process, by minimizing the slug size, can decrease the need for the CIW supply, therefore lowering the process expenditure. Moreover, if the exposure time of the rock and CIW is increased (soaking), a higher level of ion substitution is probable, leading to more oil detachment and production. Rock dissolution/precipitation (leading to a pH change) was found to have a negligible contribution.

Optimization of contact angle and interfacial tension measurements for fluid/rock systems at ambient conditions

Quantification of interfacial tension (IFT) and contact angles is essential to characterize reservoir fluid-fluid and rock-fluid interactions. However, these measurements are highly dependent on chemical structure, surface residues, system conditions, flow dynamics and interface interactions. Interfacial interactions are specifically important for secondary and tertiary oil recovery processes where water or brine is injected to recover residual oil through complex multi-phase - rock/brine/oil- interactions Due to the delicate interactions across the interfaces, these systems are subjected to variations and inconsistencies that might be difficult to eliminate, thus, affecting the reliability, reproducibility, and certainty of the data. Therefore, reliable measurements need to eliminate fundamental sources of error and remove surface contaminants. To optimize these measurements, the presented methods take a holistic approach to carefully and reliably optimize the procedure for interfacial tension and contact angle measurements for fluid-fluid and rock-fluid interaction studies at ambient conditions (22.0 ± 2 °C and atmospheric pressure).

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The presented method ensures minimization of impurities that alter interfacial tension measurements;

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Enhanced preparation for tested surfaces for contact angle measurements, and;

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Optimization of procedure at ambient conditions