Deep saline aquifers in the eastern part of Drava Basin were screened for potential storage sites. The input dataset included three seismic volumes, a rather extensive set of old seismic sections and 71 wells. Out of all identified potential storage objects, only two sites were found to be situated in the favorable geological settings, meaning that the inspected wells drilled through structural traps had a seal at least 20 m thick which was intersected by only a few faults with rather limited displacement. Many more closed structures in the area were tested by exploration wells, but in all other wells, various problems were encountered, including inadequate reservoir properties, inadequate seal or inadequate depth of the identified trap. Analysis was highly affected by the insufficient quality and spatial distribution of the seismic input data, as well as in places with insufficient quality of input well datasets. An initial characterization of identified storage sites was performed, and their attributes were compared, with potential storage object B recognized as the one that should be further developed. However, given the depth and increased geothermal gradient of the potential storage object B, it is possible that it will be developed as a geothermal reservoir, and this brings forward the problem of concurrent subsurface use.

The thermal conductivity of rocks represents one of the significant variables when investigating geothermal potential of an area on a local scale as well as regionally when performing basin analysis with the aim of estimating hydrocarbon potential. While steady-state methods of measuring thermal conductivity are presumed to yield more reliable results, transient methods allow for in situ measurements, thereby considerably simplifying and reducing measurement costs. This study was performed with the goal to expand the understanding of thermal conductivity of rocks typical for the North Croatian Basin (NCB) infill, as well as the underlying basement rocks. The measured values reveal distinct ranges across various lithologies. The thermal conductivity values measured in crystalline rocks are quite consistent, showing narrow ranges of values for each lithotype: for granite the measured values are between 2.317 and 2.486 W m-1 K-1, the value range for gneiss is between 3.332 and 3.565 W m-1 K-1 and the thermal conductivity of amphibolite is in the range between 1.549 and 1.623 W m-1 K-1. In contrast, the thermal conductivity values of sedimentary rocks vary within broader ranges - the values in sandstones range between 1.778 and 2.433 W m-1 K-1, for marlstones the registered range is between 0.917 and 2.323 W m-1 K-1, the values measured in shales range between 0.894 and 2.304 W m-1 K-1 and biocalcarenites show values of thermal conductivity between 0.990 and 2.023 W m-1 K-1. The greater variability in values measured for sedimentary rocks is attributed to the variability in porosity and fluid saturation, as well as the greater variability of mineral composition. Further research is needed to determine which factor has the greatest influence on the variability of thermal conductivity values, i.e. to establish to which extent each of the factors contributes to the measured values.

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.

Croatia has both significant CO2 emissions from the point sources and a history of oil and gas exploration, and this is why the CCS technology surfaced as a viable solution for curbing CO2 emissions on a national level. Since approximately half of emissions from the stationary industrial sources occur along the Adriatic coastline, the entire offshore area became an exploration target. Regional studies revealed the potential storage plays, one of which is in the aquifer of the Mesozoic carbonate complex with dual porosity extending all along the Croatian offshore area. Three structures were chosen in its central part–Klara, Kate and Perina. For the first two, the models were constructed based on the data from old exploration wells and a regional structural map, while for the Perina structure, a new seismic interpretation was added to better characterise its properties. It came out that the Kate structure appears to be the most prospective in general (45 Mt), with neighbouring Klara as the second (39 Mt), while the initially promising Perina (7 Mt) turned out to be of far lesser importance. The Perina structure case is an example that new seismic interpretation can reduce the capacity estimate if it reveals certain limiting factors, in this case, the limitation of structural closure.

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.

Carbon Capture and Storage is a concept that is not yet fully implemented largely because of the high costs. Clustering of industrial stakeholders is imposed as a measure for cost reduction. All relevant emitters, possible transport routes, including existing gas pipeline corridors, and their geographic location in relation to potential storage locations are assessed in this paper. Site availability and CO2 storage capacity are examined, summarizing all study results gathered under the Strategy CCUS project. The CO2 enhanced oil recovery is being studied for CO2 storage rather than extra oil recovery. As logical choices, three clusters were recognized. Only less expensive, onshore injection was taken in consideration for assessment of early (economic) feasibility in the Adriatic, Central, and Eastern clusters. Because of the shorter distance between CO2 emitters and injection sites, the Eastern and Central clusters are being investigated in more detail, despite the fact that the largest point source emitter is in the Adriatic region. Because of small number of point source CO2 emitters and huge theoretical storage capacity, further research is needed to better assess the storage capacities as well as possibilities for development of cross-border projects. Based on previous research (particularly regarding the emitters), the number of facilities (fewer facilities, with more concentrated emissions), and the availability of storage objects, the Eastern cluster is recommended to be further studied as the next stage of Carbon Capture, Utilization and Storage cluster research and development in Croatia and nearby cross-border regions.

The Drava Basin in the SW Pannonian Basin System (PBS) was initially formed by passive rifting with accompanying sedimentary infill. Although this has been the subject of much previous work, an account of tectonic control has been lacking. Based on cores, wire logging, and seismic data, the tectonostratigraphic interpretation, depositional systems, and control on depositional systems of the syn-rift infill of the eastern part of the Drava Basin were studied. The rifting phase is characterised by the formation of half-grabens, grabens, a sag, and supradetachment basin structures with structural ramp and structural highs. The syn-rift infill can be divided into second-order tectonostratigraphic sequences corresponding to the early and late rift stages. The second-order sequences are further subdivided into third-order tectonostratigraphic sequences formed in response to higher-order tectonic events associated with local rift migration. In contrast to the early-stage structures, the late-stage rift structures are primarily controlled by extensional detachments that represent parts of the Drava Rift Fault System (DRFS). The early syn-rift is characterised by continental deposition through alluvial fans, fan deltas, and lacustrine environments. The late syn-rift stage is characterised by marine deposition in shallow water, fan deltas, and submarine slope-aprons, with deep marine sedimentation and intense volcanic activity. The ramp, basin slopes, and fault scarp slopes represent the major sediment transport pathways involved in the formation of alluvial fans, fan deltas, or submarine slope-aprons. Basinal sedimentation and major depocenters are located within synforms formed by structural lows in the geometry of extensional detachments. This study gives an example of syn-rift tectonic control for the SW part of the PBS and the influence of detachment geometry on basin fill. We have presented an approach based on 3D seismostratigraphic interpretation of tectonostratigraphic sequences, and the correlation of seismic facies with depositional environments developed in a back-arc setting.

The eastern Drava Depression in the SW Pannonian Basin System is characterised by passive rifting sedimentary infill. The rifting phase is characterised by the formation of half-graben, graben, sag, and supradetachment basin-type structures, with synthetic transfer zone and structural highs. Most of the extension is accommodated by extensional detachment structures. The entire syn-rift infill can be divided into second-order sequences that correspond to two rift stages (early and late) characterised by different extension rates. Second-order sequences were further subdivided into third-order sequences that formed in response to higher-order tectonic events within one syn-rift stage and are the result of local rift migration. Unlike the early-stage structures, the late-stage rift structures are defined by extension along extensional detachments, which represent the principal syn-rift normal fault system in the study area. The observed extensional detachments and their metamorphic basement indicate a core-complex extension. The early rift is characterised by continental deposition in alluvial fans, fan deltas, and lacustrine environments. The final rift climax stage is characterised by marine deposition in shallow water, fan deltas, and subaquatic fault aprons, with deep marine sedimentation and intense volcanic activity. During the entire syn-rift phase, tectonic movements primarily controlled deposition. The rift climax, however, is characterised by various coeval palaeomorphological features resulting from an inherited complex structural setting. The synthetic transfer zone, basin slopes of retreated fault blocks, and fault scarp slopes denote the main sediment transfer zones active in the formation of alluvial fans, fan deltas, or subaquatic fault aprons. Basinal sedimentation and the main depocentres were located within synforms formed by corrugations of extensional detachments, i.e. with the central position of tectonic subsidence.

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.

One of the most innovative and effective technologies developed in recent decades for reducing carbon dioxide emissions to the atmosphere is carbon capture and storage (CCS). It consists of capture, transport and injection of CO 2 produced by energy production plants or other industries. The injection takes place in deep geological formations with the suitable geometrical and petrophysical characteristics to trap CO 2 permanently in the subsurface, which is called geological storage. In the development process of a potential geological storage site, correct capacity estimation of the injectable volumes of CO 2 is one of the most important aspects. There are various approaches to estimate CO 2 storage capacities for potential traps, including geometrical equations, dynamic modelling, numerical modelling and 3D modelling. In this work, the generation of 3D petrophysical models and equations for calculation of the storage volumes are used to estimate the effective storage capacity of four potential saline aquifers in the Adriatic Sea offshore. The results show how different saline aquifers, with different lithologies at favourable depths, can host a reasonable amount of CO 2 , which will require further and more detailed feasibility studies for each of these structures. A detailed analysis is carried out for each saline aquifer identified, varying the parameters of each structure identified and adapting them for a realistic estimate of potential geological storage capacity. Thematic collection: This article is part of the Geoscience for CO 2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage

A small area covered by a seismic volume was selected for the analysis of using artificial neural networks for the purpose of lithology modelling in a stochastic approach to an otherwise deterministic method. Subsurface lithology was simplified to three categories (sandstone, marl and coal) in accordance with the general geological composition of the Pannonian age sediments in the eastern part of Drava Depression. Two approaches to artificial neural networks were used—training and prediction with a large number of networks with different architecture, and with the same architecture but with the variability of dataset distribution of cases for error calculation in the learning process. Out of a 1000 total cases, 100 realizations of each approach were singled out upon which the data points with probability of 50%, 75% and 90% of occurrence of certain lithology category were upscaled in the model. Six models were generated by indicator kriging. Although in theory, the higher accuracy data should provide a more accurate result, the geologically most sound results were obtained by 50% accuracy data. In higher accuracy results, sandstone lithology was unrealistically over emphasized as a result of the upscaling process, variography and statistical analysis. Presented research can be used in all geoenergy-related subsurface explorations, including hydrocarbon and geothermal explorations, and subsurface characterization for CO2 storage potential and underground energy storage potential as well.

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 main source rock facies in the Croatian part of the Pannonian Basin belong to the Middle Miocene and lower part of the Upper Miocene. These rocks are mainly identified in deep exploration wells, whereas outcrops are rare. Here we report on three stratigraphically different source rock intervals, which were recently discovered at Dilj Mt on the North- Eastern flank of Sava Depression. The oldest source rock interval is located within a continuous succession characterized by interlayering of marls and sandstones with dominant carbonate grains. The source rocks are dark grey, laminated marls with moderate Corg contents (1.7-3.6%) and HI values (470-510 mgHC/gCorg). The source rocks, up to 7 m thick, contain an abundant marine fauna and were dated into the lower NN5 zone (Early Badenian). Maceral composition and Rock-Eval analysis suggest a mixed Type II-III kerogen. In contrast to the above locality, two other outcrops represent re-sedimented source rocks. The source rock clasts are all of similar age, but the age of the debris breccia differs between the two sites. One locality is represented by a debris breccia interval, about 60 cm thick. Two different source rocks facies can be observed among the clasts, one of massive texture and black colour and one dark grey with thin laminae showing slumping. The massive facies contain 8.0 to 10.8% Corg with HI values from 547 to 578 mgHC/gCorg, while the laminated one contains less Corg values (~5.6%) but with higher HI (604 mgHC/gCorg). Geochemical properties and maceral analysis support the presence of oil-prone Type II kerogen. According to the palaeontological record, both the breccia and clasts are of Sarmatian age. The other outcrop with re- deposited source rocks is more than 2.5 m thick and contains significantly larger clasts compared to the first re-sedimented type outcrop (up to 1 m). The age of the source rock clasts is similar that of the previous debris outcrop. Interestingly, the laminated facies is not slumped like in the previous outcrop, but shows micro-faulting indicating a compressional event. The overlying sediments were biostratigraphically dated as Early Pannonian. Geochemical analysis has not yet been performed on samples from this location, but similar values as in samples from the first outcrop are expected based on similar facies and age. All analysed source rocks show very low thermal maturity (%Ro <0.25, Tmax <430 °C), indicating rather shallow burial and very limited uplift during the last compressional phase of the Pannonian Basin. The study results yield important information for the re-evaluation of the petroleum potential of the basin infill, considering the structural and stratigraphic setting of the source rock intervals within the basin. The same rocks in deeper settings might represent significant active source rock intervals that were inadequately considered in previous exploration.

Presented work focuses on the importance of unconformity that separates the Neogene infill from older Palaeozoic and Mesozoic rocks in the Croatian part of Pannonian Basin. Structure map of this horizon nearly represents the thickness map of the Neogene and Quaternary basin fill. Rock formations just below the unconformity are significantly weathered, which results in favourable petrophysical properties, making them interesting from the aspect of geoenergy potential. The pre-Neogene surface was constructed in 1:400,000 scale using publicly available subsurface maps of different scale and different level of detail. Harmonization and compilation of these maps enabled construction of a structured surface with near-vertical fault planes. Supplemental maps were constructed via basin modelling, showing the temperature distribution in the subsurface, potential source rock maturity near the mapped horizon, surface heat flow and geothermal gradient distribution. Constructed maps illustrate the importance of the mapped interval for regional planning of future geoenergy-related research..

Total carbon dioxide ([Formula: see text]) storage capacities are estimated in numerous studies, but there is a lack of research of possible injection rates at a particular site. We have performed compositional simulation with permeability variation (based on log-normal distribution parameters of the measured data from similar formations in an oil field above the aquifer) to include changes of aqueous and gaseous phase properties (composition, viscosities, density), and heterogeneity of a regional [Formula: see text] storage site. We have 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 modeled heterogeneity of a [Formula: see text] storage site and the 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 the 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 indicated that maximum pressure will occur in zones above wellbores at the short period after the injection, and almost no change of average pressure in the regional aquifer will be noticeable, which leads to the conclusion that the total (theoretical) storage capacity is not the key issue for [Formula: see text] storage in aquifers and that injectivity for the storage site (expressed as the rate) should be the key parameter for selecting the pilots for [Formula: see text] storage.