Climate change is an increasingly important issue at all levels, with reducing greenhouse gas emissions being a key challenge. While renewable energy sources have the potential to reduce emissions, CO2 capture (utilisation) and storage (CCS and CCUS) technologies offer significant opportunities, particularly in the oil industry, where they can enhance oil recovery and reduce emissions. Tertiary oil recovery methods aim to extract the oil remaining after primary and secondary phases by increasing oil mobility through reducing viscosity and interfacial tension. Major methods include gas injection, chemical, and thermal methods, with thermal methods being the most relevant. Gas injection methods, especially CO2 injection, have gained popularity due to their effectiveness in enhancing oil recovery and storing CO2. The efficiency of oil displacement from reservoirs is determined by microscopic (displacement sweep efficiency, ED) and macroscopic (volumetric sweep efficiency, EV) displacement coefficients. ED measures the amount of oil displaced in contact with the displacing fluid, while EV indicates the extent of contact between the displacing fluid and the oil-bearing parts of the reservoir. Macroscopic displacement efficiency depends on reservoir heterogeneity, fluid mobility, and well placement, while microscopic displacement efficiency is influenced by capillary number and fluid mobility, represented by the mobility ratio (M) between displacing and displaced fluids. The selection criteria for CO2 injection include historical production analysis, response to secondary recovery, oil and reservoir rock properties, encompassing parameters such as oil density and viscosity, oil saturation, and reservoir depth and permeability. Suitable reservoirs for CO2-EOR (Enhanced Oil Recovery) projects include both carbonate and sandstone reservoirs, where the ability to achieve pressures above the minimum miscibility pressure (MMP) and the absence of geological barriers that would prevent CO2-oil contact are critical factors. Correlations can be useful for preliminary determination of MMP, but their accuracy varies depending on oil composition. Several correlations have been developed for estimation MMP, including works by Holm and Josendal, Yellig and Metcalfe, Cronquist, Lee, Alston, and others. However, due to the variability in oil composition and specific reservoirconditions, none of them is universally applicable. In chemical EOR methods polymers or surfactants are injected to improve the mobility ratio between oil and water and thus increase the efficiency of water-alternating-gas (WAG) injection. Althoug they are effective, their application is limited by high costs, environmental impact, sensitivity to reservoir water salinity, and chemical adsorption on reservoir rock. In recent years, the use of chemical methods in global EOR projects has increased, emphasising the importance of understanding their mechanisms of action. Pilot projects dominate field applications, with only a few examples of systematic polymer and surfactant injection. Conceptual models of oil reservoirs were developed using general reservoir data, petrophysical analyses, PVT (Pressure-Volume-Temperature) data, a database of simulation inputs and results, and processing and correlating resultant data. The data were obtained from official documentation and published studies of INA Plc. (a Croatian national oil company). The PVT data were entered into an input parameter database, and equations of state were adjusted for simulation using the PETEX PVTp program. The first step was to prepare the PVT input data, followed by the creation of numerical reservoir models to be matched with historical production data. Static input data included average values of reservoir parameters such as permeability, porosity, thickness, temperature, and pressure. Following model validation, predictive models were created using Python code to generate text input files for tNavigator. WAG process optimization, including parameters such as WAG ratio, slug duration, injection pattern, and well spacing, was conducted to determine the optimal oil recovery. Various WAG ratios and cycle durations were considered, resulting in 1152 simulation cases per reservoir, totalling 5752 predictive cases for five reservoirs with additional hypothetical 1152 cases per field for two fields where EOR is already implemented. Matching simulation data with historical results is crucial for the validation and calibration of oil reservoir models. The focus was placed on oil production volumes, as it is difficult to achieve complete alignment of produced and injected fluids with homogeneous conceptual models. The results were presented in relevant tables and figures. The matching focused on aligning oil production volumes at the end of the primary production phase (end of 2004) andat the end of 2019. Production was extended until 2024 under the same conditions, with predictive models developed accordingly. EOR has been conducted on the Ivanić Field since 2001, and on the Žutica field since 2015. Additional hypothetical historical cases without EOR implementation before 2025 were created, resulting in 1152 additional predictive cases per field. The results showed that the polymer concentration generally has a negative effect on the storage of CO2, which can be explained by the fact that water occupies the space that could have been occupied by CO2 during storage, and that a higher concentration of polymers in water reduces the mobility of water, which means that water breakthrough is slower, which in turn further increases the retention of the injected water in the reservoir. In the CCUS context, the optimal scenarios include large amounts of CO2 supplied "outside the system", i.e. from an emitter. The storability is defined as the ratio of CO2 retained to CO2 produced, and it is a good indicator of the energy required for storage, which in turn can be a good indicator of the profitability of storage with simultaneous production of hydrocarbons. In pure storage (BAU scenarios, Business-As-Usual after production) this parameter is infinitely large, while low storability may indicate an unprofitable project of CO2 injection and CCUS storage. EOR recovery is a good parameter for comparisons in the context of CCUS. If the recovery is low at the time injection is being considered and the potential additional recovery is equally high, it can be assumed that consideration of CO2-EOR is less likely. In general, it can be observed that indicators followed by high EOR recovery are often the exact opposite of retention indicators. The CO2 efficiency parameter is defined as the product of EOR recovery and storability, and shows how much both recovery and storage increase in relation to the increase in CO2 production. The value of this parameter is generally higher at the beginning for a lower number of production wells, and it was observed that there is a moment when the efficiency reaches a peak value, after which it starts to fall. Finally, the weight coefficients for oil recovery and stored CO2 were considered, and are defined as the share of the net present value (NPV) of oil produced and the share of NPV of stored CO2 in the overall NPV of the project. In other words, for selected price scenarios, the percentage of income from oil production and the percentage share of income from CO2 storage can be determined.