Carbonated water flooding (CWI) increases oil production due to favorable dissolution effects and viscosity reduction. Accurate modeling of CWI performance requires a simulator with the ability to capture the true physics of such process. In this study, compositional modeling coupled with surface complexation modeling (SCM) are done, allowing a unified study of the influence in oil recovery of reduction of salt concentration in water. The compositional model consists of the conservation equations of total carbon, hydrogen, oxygen, chloride and decane. The coefficients of such equations are obtained from the equilibrium partition of chemical species that are soluble both in oleic and the aqueous phases. SCM is done by using the PHREEQC program, which determines concentration of the master species. Estimation of the wettability as a function of the Total Bound Product (TBP) that takes into account the concentration of the complexes in the aqueous, oleic phases and in the rock walls is performed. We solve analytically and numerically these equations in 1 - D in order to elucidate the effects of the injection of low salinity carbonated water into a reservoir containing oil equilibrated with high salinity carbonated water.

Production of mature oil fields emits significant amount of CO₂ related to circulation and handling of large volumes of gas and water. This can be reduced either by (1) using a low-carbon energy source and/or (2) reducing the volumes of the non-hydrocarbon produced/injected fluids. This paper describes how improved oil recovery techniques can be designed to reduce CO₂ intensity (kgCO₂/bbl oil) of oil production by efficient use of the injectants. It is shown that CO₂ emissions associated with injection of chemicals is strongly influenced by water cut at the start of the project, extent of the water cut reduction, and chemical utilization factor defined as the volume of produced oil per mass or volume of the injectant. As an example, for the oil field considered in this study, 3–8% reduction in water cut can result in 50–80% reduction in its CO₂ intensity. In addition to the incremental oil production with lower CO₂ intensity, the earlier implementation of enhanced oil recovery methods can extend the lifetime of the mature fields if carbon emission cut-offs are applied. In case of CO₂ enhanced oil recovery (EOR), the large storage potential for CO₂ can significantly reduce the overall CO₂ emissions of oil, albeit at a large energetic cost. For CO₂ EOR using CO₂ captured from gas power plants, improving the utilization factor from 2 bbl/tCO₂ to 4 bbl/tCO₂ can reduce the CO₂ intensity of the produced oil from 120 kgCO₂/bbl to 80 kgCO₂/bbl (33% reduction).

This paper presents an assessment of the life-cycle exergetic efficiency and CO2 footprint of the underground biomethanation process. The subsurface formation, hosting microorganisms required for the reaction, is utilized to convert CO2 and green (produced from renewable energy) hydrogen to the so-called "green"or synthetic methane. The net exergy gain and CO2 intensity of the biomethanation process are compared to the alternative options of (1) green H2 storage (no energy upgrading process to CH4) and (2) fossil-based CH4 with carbon capture and storage (CCS), i.e., blue CH4. It is found that with the current state of the technology and within the assumptions of this study, the exergy return on the exergy invested for underground biomethanation does not outperform the direct storage and utilization of green H2. The maximum exergetic efficiency of the biomethanation process is calculated to be 15-33% for electricity and 36-47% for heating, while the overall exergetic efficiency of the direct use of H2 for electricity is estimated to be between 20 and 61%. Moreover, the energy produced from the underground biomethanation process has the largest CO2 intensity among the studied options. Depending on the technology used in the CCS and hydrogen production stages, the CO2 intensity of the electricity generated from synthetic CH4 can be as large as 142 g CO2/MJe, which is at least 56-73% larger than those of the two other studied cases.

A method based on the concept of exergy-return on exergy-investment is developed to determine the energy efficiency and CO₂ intensity of polymer and surfactant enhanced oil recovery techniques. Exergy is the useful work obtained from a system at a given thermodynamics state. The main exergy investment in oil recovery by water injection is related to the circulation of water required to produce oil. At water cuts (water fraction in the total liquid produced) greater than 90%, more than 70% of the total invested energy is spent on injection and lift pumps, resulting in large CO₂ intensity for the produced oil. It is shown that injection of polymer with or without surfactant can considerably reduce CO₂ intensity of the mature waterflood projects by decreasing the volume of produced water and the exergy investment associated with its circulation. In the field examples considered in this paper, a barrel of oil produced by injection of polymer has 2–5 times less CO₂ intensity compared to the baseline waterflood oil. Due to large manufacturing exergy of the synthetic polymers and surfactants, in some cases, the unit exergy investment for production of oil could be larger than that of the waterflooding. It is asserted that polymer injection into reservoirs with large water cut can be a solution for two major challenges of the energy transition period: (1) meet the global energy demand via an increase in oil recovery and (2) reduce the CO₂ intensity of oil production (more and cleaner energy).

This work uses pilot examples of CO₂ enhanced oil recovery to analyze whether and under which circumstances it is exergetically favorable to sequester CO₂ through enhanced oil recovery. We find that the net storage efficiency (ratio between the stored and captured CO₂) of the carbon capture and storage (CCS)-only projects is maximally 6–56% depending on the fuel used in the power plants. With the current state of technology, the CCS process will re-emit a minimum of 0.43–0.94 kg of CO₂ per kg of CO₂ stored. From thermodynamics point of view, CO₂ enhanced oil recovery (EOR) with CCS option is not sustainable, i.e., during the life cycle of the process more energy is consumed than the energy produced from oil. For the CCS to be efficient in reducing CO₂ levels (1) the exergetic cost of CO₂ separation from flue gas should be reduced, and/or (2) the capture process should not lead to additional carbon emission. Furthermore, we find that the exergy recovery factor of CO₂-EOR depends on the CO₂ utilization factor, which is currently in the low range of 2–4 bbl/tCO₂ based on the field data. Exergetically, CO₂ EOR with storage option produces 30–40% less exergy compared to conventional CO₂ enhanced oil recovery projects with CO₂ supplied from natural sources; however, this leads to storage of >400 kg of extra CO₂ per barrel of oil produced.

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.

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.