Fourth EAGE Eastern Mediterranean Workshop

The onshore Axios-Thermaikos basin in northern Greece developed during the Neogene. An offshore gas field has been verified in the area, indicating significant potential for hydrocarbon resources. Although many surveys have been conducted, a complete model of its subsurface remains unpublished. The primary goal of this study is to increase the overall understanding of the hydrocarbon potential of the basin through a comprehensive analysis of multi-geophysical (gravity, magnetic, reflection seismic) and borehole data. The gravity and magnetic data were analyzed to identify the structural and lithological trends governing the formation and evolution of the basin. The magnetic data were used to delineate the sediment-basement boundary. The seismic data were analyzed using various attributes to interpret and reconstruct the geological contacts and tectonic regime of the basin. Density variations in depth were investigated by utilizing two-dimensional forward modeling, constrained by seismic data. The 2D gravity model shows the boundaries between the geological formations and the prominent faults. Preliminary three-dimensional models were created using the seismic data and the stratigraphy obtained from boreholes. These models depict the stratigraphic and tectonic regimes, identifying potential hydrocarbon traps and providing insights into the various depositional environments that have influenced the basin over time.

41 high-impact exploration wells have been drilled in the Eastern Mediterranean over the past decade, accounting for 5% of the 864 wells drilled globally. The region delivered 6.7bnboe (98% gas), accounting for 8% of the total discovered resource globally in high impact exploration. Eni’s Zohr discovery in 2015 opened the second largest new gas play to emerge globally since 2014, with ∼24tcf gas discovered. The cycle time from discovery to first gas at the Zohr and Tamar discoveries outperform almost all other frontier gas discoveries made since 2006, setting an important standard for the industry to aspire to. The region is well placed to replace the supply of Russian gas to Europe following war in Ukraine, and is experiencing a rejuvenation with ∼10% of global high-impact wells planned for 2023.

Shallow to deep-water carbonates have long been considered as the main reservoir level in the exploration activities in Western Greece. Although, thick (> 1m), good quality sandstone beds do occur within the Oligocene and Miocene clastic section, this interval has only been considered so far in terms of top seal integrity. The identification of several structural and stratigraphic traps within the late Tertiary clastic section in the newly acquired 2D and 3D seismic data from the North Ionian and Kyparissiakos blocks has created the need for the understanding of their reservoir quality and distribution. A comparison between seismic data and outcrop observations is presented in this work, in order to assess the potentiality of these formations to contain adequate reservoir levels.

The main goal of this study is to identify and map the gas expulsion features that are identified in the newly acquired seismic cube from the North Ionian block in offshore Western Greece and assess their origin. The extensive gas expulsion features throughout North Ionian Block, in combination with the presence of proven source rocks, clearly demonstrate the presence of a working petroleum system. Thermogenic and biogenic origin of gas is supported by the basin modeling results.

The multiple hydrocarbon indications throughout Western Greece, the Katakolo oil field offshore west Peloponnese, and the well documented source rocks (SR) all suggest an active petroleum charge system. However, the complex geology (thrust and fold belt) and the salt tectonic movements make the oil-to-source rock correlation substantially challenging. The subject of the present study is to challenge the existing interpretation and assess potential kitchens. The examined SR samples are from wells and outcrops covering the period from upper Triassic to upper Miocene. Hydrocarbon samples include oils from shallow wells on Zakynthos, asphalts, and extracts from Eocene impregnated limestones from outcrops along the west coast of Peloponnese. The rock samples were studied by applying Rock-Eval 7S and organic petrography, whereas GC/GC-MS were applied for the oils/asphalts and extracts. The results of this study suggest a strong correlation of the examined oils/asphalts with the Jurassic SR intervals of the Ionian basin and the most external part of the fold and thrust belt (FTB). No correlation to Miocene SR intervals was observed. The study also grouped the oils from Zakynthos and Kyllini into the same family. The high SI and the organic sulfur-rich kerogen low activation energies suggest a low-temperature oil generation.

Connected to the awarded hydrocarbon exploration blocks that have been tendered recently offshore Crete, Greece, and looking for possible geological analogues, a survey has been conducted in a proximal onshore area. The goal is to identify potential, Cenozoic age, source rocks (SRs) that have not been evaluated yet. For that, a detailed sampling campaign of upper Miocene siliceous intervals took place. It was followed by Rock-Eval VI pyrolysis. Based on the results, the studied stratigraphic intervals could provide a potential source rock for hydrocarbon generation in the eastern Mediterranean.

A multidisciplinary survey was carried out by Oceanus-Lab (University of Patras) and HelleniQ Upstream on board the R/V AEGAEO (HCMR) for the detection of gas related morphological features and possible gas seepages at the Kyparissiakos Gulf. For the survey, acoustics (multibeam echosounders, MBES), seismics (airgun), geochemical (gas geochemistry) and sensors (methane) approaches were used. The initial selection of the survey area was based on seismic interpretation and other data provided by HelleniQ Upstream. The multibeam and airgun survey showed an important pockmark field in the lower slope of Kyparissiakos Gulf at water depth of 1050m. The field consisted by two pockmark groups is located close to a deep-sea channel and seems to be related to gravitative mass movements. Moreover, subbottom profiling data, collected in the wider area, showed acoustic anomalies which are related to gas charged sediments (gas chimneys). The isotopic composition of seepage gases from a pockmark in group B showed thermogenic origin.

The Epirus region in Western Greece demonstrates important hydrocarbon potential indicated by widespread oil-seeping, which proves that all elements and processes of a petroleum system are present and active. This study compares biomarker signatures of biodegraded solid bitumen samples from 3 sites [Petousi, Elataria and Vassiliko (the last two SB yet unreported)], with those from source rock samples obtained from two of the most promising oil-prone source rocks outcropping in Epirus i.e., the Pantokrator Shale and the Toarcian Lower Posidonia Shale, aiming to assess oil affinities. Petousi and Elataria solid bitumens were both found filling joints within the sediments of the Toarcian Lower Posidonia Shale Fm, whereas Vassiliko solid bitumen was obtained from Triassic collapse-breccias. The results suggest that the solid bitumen in Elataria Lower Posidonia Shale exhibits geochemical similarity to the Lower Posidonia Shale source rock. Petousi solid bitumen although found in Lower Posidonia Shale source rock has likely derived form the adjacent Pantokrator Shale of Pantokrator bituminous limestones. Vassiliko solid bitumen likely originate from a source matching Pantokrator Shale geochemical characteristics. Moreover, bitumen yields of these source rocks indicate that Pantokrator Shale generation potential well exceeds that of the Lower Posidonia Shale.

The study introduces new features in field development plans that could be applied in the Eastern Mediterranean region. Monte Carlo simulations are employed to analyze volumetric data, aiming to identify and quantify uncertainties related to estimation processes, including well logs, cores, well test data, and the transition from one-dimensional to three-dimensional reservoir models. Findings from these simulations, combined with material balance equations are used to formulate a CO2 injection scheme for enhanced natural gas recovery. Suggesting their inclusion in Field Development Plan (FDP) documents, these simulations could impact costs (potentially reducing them through carbon tax incentives) and environmental assessments. Algorithms are also applied to optimize drilling operations, designing casing configurations for cost minimization and material durability against external forces. Additionally, a Kernel algorithm is introduced to identify spatial risks for health and safety during field accidents. The study makes use of Monte Carlo simulations to analyze project cashflows, quantifying financial risks tied to project development. In conclusion, these proposed methodologies can be easily integrated into the current FDP, offering significant benefits in terms of uncertainty and risk quantification to inform decision-making.