Chemical enhanced oil recovery (EOR) processes are usually used as additives for hydrocarbon production due to its simplicity and relatively reasonable additional production costs. Polymer flooding uses polymer solutions to increase oil recovery by decreasing the water/oil mobility ratio by increasing the viscosity of the displacing water. The commonly used synthetic water-soluble polymer in EOR application is partially hydrolyzed polyacrylamide (HPAM). However, synthetic polymers in general are not attractive because of high cost, environmental concerns, limitation in high temperature, and high-salinity environment. Guar gum is an environmentally friendly natural water-soluble polymer available in large quantities in many countries and widely used in various applications in the oil and gas industry especially in drilling fluids and hydraulic fracturing operations; however, very limited studies investigated on guar as a polymer for EOR and no any study investigated on its uses in high-temperature and high -salinity reservoirs. The objective of this study is to confirm the use of guar gum as a natural polymer for EOR applications in sandstone reservoirs and investigate its applicability for high-temperature and high-salinity reservoirs. The study experimentally investigated rheological characteristics of a natural polymer obtained from guar gum with consideration of high temperature (up to 210 °F) and high salinity (up to 20% NaCl) and tested the guar solution as EOR polymer. The results of this study show that the guar solution can be used as an environmentally friendly polymer to enhance oil recovery. Based on the results, it can be concluded that guar gum shows shear-thinning behavior and strongly susceptible to microbial degradation but also shows a very good properties stability in high temperature and salinity, where in low shear rate case, about 100 cp viscosity can be achieved at 210 °F for polymer prepared in deionized water. Guar polymer shows good viscosity in the presence of 20% NaCl where the viscosity is acceptable for temperature less than 190 °F. Also, the flooding experiment shows that the recovery factor can be increased by 16%.

In hydraulic fracturing, fracturing fluids are used to create fractures in a hydrocarbon reservoir throughout transported proppant into the fractures. The application of many fields proves that conventional fracturing fluid has the disadvantages of residue(s), which causes serious clogging of the reservoir's formations and, thus, leads to reduce the permeability in these hydrocarbon reservoirs. The development of clean (and cost-effective) fracturing fluid is a main driver of the hydraulic fracturing process. Presently, viscoelastic surfactant (VES)-fluid is one of the most widely used fracturing fluids in the hydraulic fracturing development of unconventional reservoirs, due to its non-residue(s) characteristics. However, conventional single-chain VES-fluid has a low temperature and shear resistance. In this study, two modified VES-fluid are developed as new thickening fracturing fluids, which consist of more single-chain coupled by hydrotropes (i.e., ionic organic salts) through non-covalent interaction. This new development is achieved by the formulation of mixing long chain cationic surfactant cetyltrimethylammonium bromide (CTAB) with organic acids, which are citric acid (CA) and maleic acid (MA) at a molar ratio of (3:1) and (2:1), respectively. As an innovative approach CTAB and CA are combined to obtain a solution (i.e., CTAB-based VES-fluid) with optimal properties for fracturing and this behaviour of the CTAB-based VES-fluid is experimentally corroborated. A rheometer was used to evaluate the visco-elasticity and shear rate & temperature resistance, while sand-carrying suspension capability was investigated by measuring the settling velocity of the transported proppant in the fluid. Moreover, the gel breaking capability was investigated by determining the viscosity of broken VES-fluid after mixing with ethanol, and the degree of core damage (i.e., permeability performance) caused by VES-fluid was evaluated while using core-flooding test. The experimental results show that, at pH-value (6.17), 30 (mM) VES-fluid (i.e., CTAB-CA) possesses the highest visco-elasticity as the apparent viscosity at zero shear-rate reached nearly to 106 (mPa·s). Moreover, the apparent viscosity of the 30 (mM) CTAB-CA VES-fluid remains 60 (mPa·s) at (90 °C) and 170 (s^-1) after shearing for 2-h, indicating that CTAB-CA fluid has excellent temperature and shear resistance. Furthermore, excellent sand suspension and gel breaking ability of 30 (mM) CTAB-CA VES-fluid at 90 (°C) was shown; as the sand suspension velocity is 1.67 (mm/s) and complete gel breaking was achieved within 2 h after mixing with the ethanol at the ratio of 10:1. The core flooding experiments indicate that the core damage rate caused by the CTAB-CA VES-fluid is (7.99%), which indicate that it does not cause much damage. Based on the experimental results, it is expected that CTAB-CA VES-fluid under high-temperature will make the proposed new VES-fluid an attractive thickening fracturing fluid.

This contribution focuses on surface complexes in the calcite-brine-surfactant system. This is relevant for the recovery of oil when using a new hybrid enhanced oil recovery (EOR) method, which combines smart-water (i.e., ionically modified brine) and foam-flooding (SWAF) of light oil with dissolved carbon dioxide (CO₂) at high pressure in carbonate (i.e., calcite) reservoirs. Using this new hybrid EOR-method (i.e., the SWAF-process) is not only economically attractive (i.e., it reduces opex costs) but also enhances the effectiveness of the production process, and thus reduces the environmental impact. Ionically modified brine (i.e., low-salinity) has a dual improvement effect. It not only leads to more stable foam lamellae, but also helps to change the carbonate rock wettability, leading for some conditions to more favorable relative permeability behavior. The mechanism for the modified permeability behavior in the presence of ionically modified brine is only partly understood. Therefore, we study this process initially in a zero dimensional (thermodynamics) setting, which can be used for the one dimensional (1D) displacement process with an oleic phase that contains carbon dioxide (CO₂) and an aqueous phase that contains both carbon dioxide (CO₂) and all the ionic substances. Using DLVO theory and surface complexation modeling to better understand the mechanism(s) of ionically modified brine as wettability modifier and foam stabilizer. We perform simulations using both (NaCl) and (MgCl₂) to show the effect of a divalent ion at the high-salinity (8500 mmol/kg-w) and low-salinity (0.4 mmol/kg-w) for both ambient-conditions at (25°C) and at the reservoir-conditions (80°C). We confine our analysis to a description that uses the Dzombak-Morel model of surface complexes, which is based on the Debye-Hückel theory (i.e., valid up to ionic strength of 0.3 (mol/kilogram of water)). We also investigate the effect of carbon dioxide (CO₂) on the stability of low-salinity foam-laminae. We model the foam-laminae, which contain as surface complex a (cationic) surfactant in an aqueous phase. We use the PHREEQC-software to calculate the surface charge and the surface potential. The presence of a carbon dioxide (CO₂) phase leads to dissolution of four valent C(IV) compounds in the aqueous film. PHREEQC also calculates the equilibrium concentrations and surface potential and allows the study of the effect of salinity and the carbon dioxide (CO₂) gas pressure. For the soap-film (foam-film) in a carbon dioxide (CO₂) atmosphere we do use Pitzer activity coefficients (i.e., valid up to 6 (mol/kilogram of water)). As our aim is to show the methodology and the versatility of this approach, we leave more realistic choices of these parameters for future work.sFor the conditions considered we can qualitatively state that, in the presence of (NaCl i.e., at pH > 10) and (MgCl₂ i.e., pH > 10.3), the low-salinity case shows a more stable water-film behavior at (25°C) and at (80°C) than the high-salinity case for both (25°C) and (80°C). Moreover, high carbon dioxide (CO₂) pressures have a destabilizing effect on the film, as they reduce the surface potential. A reduced surface potential leads to a decreasing electrostatic double layer repulsion and thus destabilizes the foam-film, whereas low-salinity leads to less screening of the surface potential and thus improves the stability of the foam-film. The low-salinity flow is characterized by a high residual oil saturation and low end-point permeability for the two phase oil-water flow. This leads to a more favorable mobility ratio and thus a more favorable displacement process. For the calcite surface an enhanced stability helps to stabilize the water film on the calcite surface if the oil-water surface charge has the same sign as the surface charge on the calcite surface. Our calculations show the pH range where the sign of these charges is the same or opposite at low-salinity and high-salinity conditions. Admittedly these calculations only show trends, but can be used to delineate optimal conditions for the application of “Smart Water Assisted Foam (SWAF) Flooding”. It is expected that the SWAF-process under the optimum conditions will make the proposed new hybrid Enhanced Oil Recovery (EOR) process environmentally and economically attractive.

The proposed study of combined low salinity foam Injection using DLVO-theory (i.e., Derjaguin, Landau, Verwey, and Overbeek) and surface complexation modeling or SCM, is a follow up of a previous study of a Novel Hybrid Enhanced Oil Recovery Method by Smart Water-Injection and Foam-Flooding in Carbonate Reservoirs (SPE-196407-MS). The method combines the advantages of our new designed "smart-water" (i.e., ionically modified brine or low salinity) injection with foam drive recovery. Our new desined "smart-water" injection has a double enhancement effect. It leads to change the limestone rock (i.e., calcite) wettability from oil or mixed-wet to more water wet (i.e., stable water-film), and helps to improve the stability of the foam-film. In the previous study (SPE-196407-MS) we investigated the impact of our "smart water" or low salinity injection on the surface complexes by simulating one single base case scenario, which equivalent to [NaCl 0.4 mMol/liter]. We use computr program (PHREEQC) to obtain the equilibrium concentrations and zeta-potential (surface potential or electro-kinetic potential), and to invetigate the effect of water-salinity and CO₂ pressure for a given choice of the surfactant (i.e. carboxylic acid R-COOH). In addition, for the surface complexation model, we studied the model of Dzombak and Morel, which uses Debye Huckel activity coefficients (i.e., valid up to ionic strength I = 0.3 mol/kilogram of water) (SPE-196407-MS). In this contribution (OTC-30301-MS), we use the DLVO-theory and SCM (surface complexation modeling) to create multiple scenarios of smart water (i.e., ionically modified brine) to study its impact on surface complexes during fluid-rock interaction process (i.e., calcite-water interface and oil-water interface). To be specific, we use PHREEQC to simulate and compare two case scenarios; the case of low salinity (NaCl 0.4 mmol/kg-water) and the case of high salinity [NaCl 8500 mMol/liter]. Also, for better optimization of the factors affecting the surface complex modeling, in this work, we modified the model of Dzombak and Morel, by using more accurately activity coefficient given by Pitzer coefficients above (0.3 mol/kgwater) (i.e., valid up to ionic strength I = 6 mol/kg-water). Additionally, the surface charge and the surface complexes are calculated, implemented and built-in using geochemical code PHREEQC. Further input: fraction of sites that bind the carboxylic acids (R-COOH) and bind the carbonates (CaCO₃) surface complex are (1.67×10⁻⁶) and (4.1 × 10^-6) respectivly, and surface area per gram of solid is (1 m²/g) for both the oleic and calcite interface (Hassan, et al., 2020). Moreover, we applied Gibbs rule to determine the number of chemical degrees of freedom. In our case, we have two numbers of degrees of freedom, and its chosen to be pH and ionic strength. Also, we examined the effect of pH and carbon dioxide (CO₂)-pressure on the surface complexes (i.e., surface charge and surface potential) for both scenarios (i.e., low salinity [NaCl 0.4 mmol/kg-water] and high salinity [NaCl 8500 mmol/kg-water]) (Hassan, et al., 2020). Qualitatively we can state that, the stability of a water film between the rock-aqueous phase / oil aqueous phase interfaces is resolute by the active sites on carbonate rock (i.e., calcite) and oil. If they with a charge of the same sign, a water film is usually stable. The foam stability is determined by the double layer (charged surface + counter ions in solution) repulsion, which is electrostatic and attractive the Van der Waals forces, which are determined by the dielectric coefficients of the constituting layers. If the electrostatic forces dominate the foam film is considered stable. It is conjectured that, high carbon dioxide pressures have a destabilizing effect on the film for both cases (i.e., low salinity [NaCl 0.4 mmol/kg-water] and high salinity [NaCl 8500 mmol/kg-water]), as they reduce the surface potential. A decreased surface potential leads to a reducing electrostatic double layer repulsion (EDL) and thus destabilizes the stability of the foam film, whereas low salinity leads to less screening of the surface potential and thus improves the stability of the foam film lamellae. The activity coefficients are more accurately given by the Pitzer coefficients above (0.3 mol/kg-water) (i.e., valid up to 6 [mol/kg-water]). It is shown that, manipulating surface complexes by imposing different salinity and pH can help to obtain mixed-wet or oil-wet behavior, with more favorable residual oil saturations, accepting the occurrence of less favorable mobility ratios. Clearly, the choice of optimal conditions is case dependent; if the mobility ratio is already favorable as to be expected with foam flow, mixed-wet conditions are favored with low residual oil saturations. Thus, an optimal choice of the pH that at the same time leads to a stable brine film on the calcite surface, and a stable foam film requires fine tuning.

Recent developments in Radio Frequency (800 MHz–1000 MHz) Identification (RFID) devices suggest that it is possible to use them for wireless laboratory measurements of the dielectric coefficients (or compositions) of fluid mixtures with possible spin-off for their use in the petroleum engineering practice. The advantage of RFID devices is their small size (0.095×0.008×0.001 m³), the developments to make them increasingly smaller and that they do not require the use of leak prone connecting cables. RFID measures the response of a sample volume of interest irradiated by a radio frequency electromagnetic (EM) wave. The response can be expressed in terms of various response functions, e.g. two scattering functions (S₁₁ and S₂₁) or the minimum irradiated power (P_min). The response functions can be measured using a state-of-the-art RFID device (CISC RFID Xplorer-200), which operates in the range between 800 and 1000 MHz. The effect of the dielectric coefficient on the RFID response was tested by placing the RFID tag in different media with various dielectric coefficients ε ranging from 1 to 80. The overall purpose is to develop a work-flow to relate the response functions obtained with RFID technology to the dielectric coefficient and thus the composition of fluid mixtures in which an RFID tag can be immersed. An application is to measure fluid compositions during a spontaneous imbibition experiment in an Amott-cell. As an intermediate step we measure the composition dependence of the partial molar volume of diethyl ether (DEE) in brine and the partial molar volume of DEE in oil by using an Anton Paar density meter. The relation between the dielectric coefficients and the volume fraction can be obtained with the Böttcher mixing rule. The DEE volume fraction range of interest is 0–8% volume fraction in the aqueous solution whereas DEE volume fraction range of interest is 0–100% volume fraction in oleic solutions. For better understanding of the measurement results, we used COMSOL™ simulations, which show that the response functions depend on the dielectric coefficient in a vessel of appropriate dimensions filled with a fluid of choice. The measurements show that the minimum power at the tag position P_min is the preferred response function and that the sensitivity of P_min was highest at 915 and 868 MHz for aqueous (8.547×10⁻⁶) and oleic (1.905×10⁻⁴) solutions respectively. The measurement error is of the same order of magnitude as the errors mentioned above (Hon, 1989) ensuing from evaporation of DEE during the preparation of the calibration fluids or the approximate nature of the Böttcher mixing rule. We conclude that it is possible to use RFID technology for contact-less measurements of the compositions of fluids in imbibition experiments.