This paper probes the transport of CO 2 soluble surfactant for foaming in porous media. We numerically investigate the effect of surfactant partitioning between the aqueous phase and the gaseous phase on foam transport for subsurface applications when the surfactant is injected in the CO 2 phase. A 2-D reservoir simulation is developed to quantify the effect of surfactant partition coefficient on the displacement conformance and CO 2 sweep efficiency. A texture-implicit local-equilibrium foam model is embedded to describe how the partitioning of surfactant between water and CO 2 affects the CO 2 foam mobility control when surfactant is injected in the CO 2 phase. We conclude that when surfactant has approximately equal affinity to both the CO 2 and the water, the transport of surfactant is in line with the gas propagation and therefore the sweep efficiency is maximized. Too high affinity to water (small partition coefficient) results in surfactant retardation whereas too high affinity to CO 2 (large partition coefficient) leads to weak foam and insufficient mobility reduction. This work sheds light upon the design of water-alternating-gas-plus-surfactant-in-gas (WAG + S) process to improve the conventional foam process with surfactant-alternating-gas (SAG) injection mode during which significant amount of surfactant could possibly drain down by gravity before CO 2 slugs catch up to generate foam in situ the reservoir.

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Given the increasing demand for energy globally and depleting oil and gas resources, it is crucial to increase the production from existing reservoirs by introducing new technologies for Improved/Enhanced Oil Recovery (IOR/EOR). This contribution presents a novel hybrid IOR/EOR method, which combines smart water (SW) and foam flooding, known as Smart Water Assisted Foam (SWAF) flooding. The optimal conditions of the SWAF technology will be interpreted using experimental laboratory design (i.e., experimental data). The experimental design was divided into three main steps. The first step is obtaining rock wettability measurements using contact angle measurements. This step aims to select the optimum SW composition that changes the carbonate rock's wettability from oil-wet towards more water-wet and faster oil recoveries. The water-wet condition leads to high residual oil saturations and low end-point permeabilities. This is conductive to favourable mobility ratios and efficient water-oil displacement. However, high residual oil saturations are unfavourable to the high ultimate oil recovery as much oil stays behind. Secondly, the chemical screening follows, where two tests were performed, viz., (i) an Aqueous Stability Test (AST), (ii) and a Foamability and Foam Stability Tests (FT/FST). This step aims to generate a stable foam (i.e., surfactant aqueous solution + gas) in the absence and presence of crude oil with different TAN (Total Acid Number) and TBN (Total Base Number), viz., crude oils Type-A and Type-B. Favourable mobility ratio is achieved by the presence of foam, which leads to excellent displacement efficiency. Thirdly, core flooding tests are performed. This step aims to select the best formulations through SWAF core flooding tests to obtain the ultimate recovery factor under different injection scenarios. The optimal SWAF condition combines high ultimate recovery with the best displacement efficiency. It is shown that the enormous changes in wettability were seen for SW (MgCl2) solution at 3500 (ppm) for both crude oils Type-A and Type-B. It has been shown that the use of a cationic surfactant CTAB (i.e., cetyltrimethylammonium-bromide) in the positively charged carbonates (with an isoelectric point of pH = 9) is more effective than the use of anionic surfactant, e.g., Alpha Olefin Sulfonate (AOS). The aim is to create an optimum surfactant aqueous solution (SAS). The SAS stability is considerably affected by the concentration of both the SW (MgCl2) and surfactant (CTAB). In the absence of oil, the strength of foam (SAS and Gas) is highly dependent on the concentration and composition of the SW in the SAS. In the presence of oil, foam generation and stability are better when the crude oil has a low TAN and high TBN. From the core flooding tests for crude oils Type-A and Type-B, the ultimate residual oil recovery was achieved by the MgCl2 - foam injection combination (i.e., incremental oil recovery of 42%, which is equivalent to a cumulative oil recovery of 92%). In summary, SWAF under the optimum conditions is a promising method to increase the oil recovery from carbonate reservoirs.

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/kg-water) (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.

This contribution focuses on recovery of oil by using a newly hybrid Enhanced Oil Recovery (EOR) method, which combines smart water (i.e. ionically modified brine) and foam flooding of light oil with dissolved carbon dioxide at high pressure in carbonate reservoirs. 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 from oil-wet to more water-wet, which has for some conditions 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 use the DLVO (i.e. Derjaguin, Landau, Verwey, and Overbeek) theory (i.e. which considers double layer repulsion, born repulsion, and Van der Waals attraction) and surface complexation modeling to better understand the mechanism(s) of ionically modified brine as wettability modifier and foam stabilizer. We use the PHREEQC software to obtain the equilibrium concentrations and surface potential and to study the effect of salinity and carbon dioxide gas pressure for a given choice of the surfactant (i.e. carboxylic acid R-COOH). It is conjectured that high carbon dioxide 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 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. The low-salinity flow is characterized by a high residual oil saturation and low end-point permeability for the two-phase oil-water flow. For the calcite surface an enhanced stability help 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 use of combined Smart Water Assisted Foam (SWAF) flooding.