Every country with a history of petroleum exploration has acquired geological knowledge of its sedimentary basins and might therefore make use of a newly emerging resource—as there is the potential to decarbonise energy and industry sectors by geological storage of CO₂. To reduce its greenhouse gas emissions and contribute to meeting the Paris agreement targets, Croatia should map this potential. The most prospective region is the SW corner of the Pannonian basin, but there are also offshore opportunities in the Northern and Central Adriatic. Three “geological storage plays” are suggested for detailed exploration in this province. Firstly, there are three small gas fields (Ida, Ika and Marica) with Pliocene and Pleistocene reservoirs suitable for storage and they can be considered as the first option, but only upon expected end of production. Secondly, there are Miocene sediments in the Dugi otok basin whose potential is assessed herein as a regional deep saline aquifer. The third option would be to direct future exploration to anticlines composed of carbonate rocks with primary and secondary porosity, covered with impermeable Miocene to Holocene clastic sediments. Five closed structures of this type were contoured with a large total potential, but data on their reservoir properties allow only theoretical storage capacity estimates at this stage.

The thick Lake Pannon sedimentary record provides insights into the downdip and lateral development of stratigraphic surfaces through the analysis of the basin-scale clinoform progradation. The clinoform architecture from the eastern part of the Drava Basin (Pannonian Basin System) was interpreted to reflect the base-level changes. A major downlap surface interpreted as a flooding event followed by rejuvenation of slope progradation was recognized on 2D seismic sections. Detailed 3D seismic interpretation combined with well data revealed that the large sigmoidal and the overlying small oblique clinoform sets that downlap the large one only apparently produce the geometry of a maximum flooding surface. Instead, the 3D mapping revealed the influence of two competing slope systems arriving from the north and northwest. Lateral switching of sediment input, similar to many recent deltaic systems. e.g., Danube and Po rivers led to the variability of stratigraphic surfaces, lithology, and thickness, which resulted in non-uniform shelf-edge migration. These observations were supported by forward stratigraphic modeling simulating different scenarios, which led to the generation of the depositional architecture with an apparent maximum flooding surface. This study also implies the potential pitfalls in basin analysis based only on scarce 2D seismic and emphasizes the role of lateral variations in sediment input controlling the depositional architecture.

Total CO₂ storage capacities are estimated in numerous studies, but there is lack of research of possible injection rates at a particular site. We performed compositional simulation with permeability variation (based on log-normal distribution parameters of measured data from similar formations in an oil field above the aquifer) in order to include changes of aqueous and gaseous phase properties (composition, viscosities, density), and heterogeneity of a regional CO₂ storage site. We performed sensitivity tests on vertical permeability multiplier, different grid block sizes, diffusivity and capillary pressures to detect the key parameters for injectivity and storage efficiency. In this way, we modelled heterogeneity of CO₂ storage site and possible injection rate in this detail for the first time. Based on pressure analysis in simulation cases, we found that it will be hard to avoid fracturing near-wellbore zone, but fracturing these zones might also increase the injectivity, and this can still be done without damaging the cap rock. Simulation results showed that maximum pressure will occur in zones above wellbores at the short period after the injection, and almost no change of average pressure in regional aquifer will be noticeable, which leads to conclusion that the total (theoretical) storage capacity is not the key issue for CO₂ storage in aquifers and that injectivity for storage site (expressed as rate) should be the key parameter for selecting the pilots for CO₂ storage.

The deep saline aquifer (DSA) Poljana in the Upper Pannonian Poljana Sandstones of Sava depression, the SW part of the Pannonian basin system, was identified as a potential CO₂ storage object in previous works. Its boundaries have been redefined and its general model further developed, including the areal distribution of porosity based on analyses of 23 well logs. The sandstones were deposited in turbiditic and deltaic facies that caused considerable variations of porosity, which was further influenced by diagenetic processes. A comparison of altogether 355 pairs of porosity and permeability measurements on core plugs from 16 wells indicated 2 different sets of samples: impermeable samples with effective porosities reaching 18% and permeable samples which showed correlation between porosity and permeability. Accordingly, the permeability model was developed as semi-categorical with two categories: the first category comprising parts of DSA Poljana with porosity values exceeding 18%, where permeability was correlated with porosity, although with limited reliability, and the second category comprising model cells with porosity values below the threshold of 18%, where permeability should not be correlated with porosity due to the appearance of impermeable values. This approach enabled delineation of areas where permeability can be estimated with greater certainty, which is of utmost importance for the planning and development of CO₂ storage projects and/or energy storage projects with respect to fluid injectivity. This approach can be used in areas with similar geological settings and limited datasets as an important step from regional capacity estimations towards the detailed, local-scale investigations.

In the continental part of Croatia, oil and gas have been discovered in more than 60 locations. Most reservoirs are in the Neogene/Quaternary basin infill, but the largest ones are found in the basement rocks. Decades of exploration have left a significant vintage dataset and substantial knowledge of the subsurface geology and reservoir properties. Since 2005, research efforts have been redirected towards CO ₂ geological storage capacity estimates, and the first results were obtained relatively quickly. All identified potential storage objects – deep saline aquifers, depleted hydrocarbon fields and oil reservoirs that are suitable for CO ₂ enhanced oil recovery (CO ₂ -EOR) – can be regarded as prospective. The deep saline aquifers are defined on a regional scale and their estimated capacity is the highest (2584 Mt), but this is ‘theoretical capacity’ that can only be used to outline the total resource base. The storage capacity estimated for the selected 14 depleted hydrocarbon fields sums to 143.6 Mt, and this is a viable capacity that might be developed as soon as a particular field stops with production, but the most promising storage objects are the seven fields that have reservoirs suitable for CO ₂ -EOR operations. The most recent models have revealed that seven active EOR fields operating in parallel between 2025 and 2040 could store up to 1.2 Mt CO ₂ a ⁻¹ , while producing c. 1.2 Mt a ⁻¹ of additional oil. This is very high for a country with only 5.5 Mt CO ₂ a ⁻¹ in point sources.