Hydrocarbon discoveries in the Western Black Sea have proved the presence of both thermogenic and biogenic petroleum systems. The presence of Tertiary biomarkers in oils from the Romanian part of the Western Black Sea sub‐basin, and correlation with Oligocene to Lower Miocene black shales, suggests that the thermogenic petroleum system is sourced mainly by the Oligocene – Miocene Maikop Group. Older source rocks may also be present locally in other parts of the sub‐basin, but their contribution is currently poorly understood. This paper presents the results of 3D basin modelling which was intended to evaluate charge models for prospects in the Western Black Sea sourced by the Maikop Group shales. The model is built on the regional‐scale interpretation of recently acquired, long‐offset 2D reflection seismic data, and was calibrated with proprietary and published well, geochemical and temperature data. The sensitivity of the thermal models on source maturity was tested. The basin models investigated two end‐member heat‐flow scenarios, “hot” and “cold”. Whereas the “hot” model more successfully reproduces the field and well data in shelfal areas of the Western Black Sea, the “cold” model is considered to be more valid for deeper‐water areas. Hydrocarbon expulsion maps were calculated for both scenarios at key stratigraphic levels, with preferential migration routes identified. The results of the basin modelling suggest that the most likely source rocks for the oils in accumulations offshore Romania are located in the mid‐Maikop Group (Upper Rupelian? to Chattian). Core data from offshore wells indicate that the source rocks consist of black shales with fair to good oil generation potential (TOC ∼ 0.5 to 4.5%, HI <600 mg/g TOC, and mixed Type II/III kerogen). At the present day, these shales are in the early oil window offshore Romania to the SE of the producing fields, and in the wet gas window further to the east. Hydrocarbon expulsion from the mid‐Maikop interval began during the Middle Miocene, but significant volumes of liquids were generated only in the Late Miocene with the peak of expulsion not yet reached. Charging the accumulations on the Romanian Shelf requires lateral migration along the base‐Oligocene unconformity over distances of about 20–50 km. In addition, hydrocarbons have charged underlying Eocene and Cretaceous reservoir sections by lateral downward migration, filling structural traps and spilling over to higher structural levels. The results highlight the underexplored potential associated with the Maikop Group in the Western Black Sea.

Although a number of significant oil and gas discoveries have been made within the Western Black Sea and the surrounding area, only sparse data about migration mechanisms are available. In this paper, biomarker and isotope data from five oilfields and one oil show located offshore Bulgaria and Romania (in the western Black Sea), and from one field onshore Georgia (at the margin of the eastern Black Sea), were compared with geochemical data from potential source rock intervals from borehole samples. The source rock data came from offshore Bulgaria and outcrop samples from onshore Georgia. The biomarker data indicates that all the oils analysed were generated by source rocks of Late Cretaceous or Cenozoic age. In the Western Black Sea sub‐basin, the most likely source rocks are Oligocene to Lower Miocene shales of the Maikop Group. Compound‐specific isotope data indicate that Lower Oligocene source rocks are the most significant although a contribution by Lower Miocene diatom‐rich source rocks cannot be excluded. For an oil sample from the Shromisubani field onshore Georgia, isotope data from individual n‐alkanes together with biomarker data indicates that the oil contains a mixture of hydrocarbons generated from the Middle Eocene Kuma Formation and the Oligocene part of the Maikop Group. Oligocene and Miocene source rocks are immature at the shelfal locations where the oil samples were recovered. Charge for these hydrocarbon accumulations is interpreted to have been provided by long‐distance lateral migration from source kitchens in more central parts of the Black Sea basin, where Oligocene and (some) Miocene source rocks are within the oil and gas window. The results of this study highlight the prospectivity of recently‐discovered deep‐water plays, and significantly de‐risk future deep‐water projects within the Black Sea area.

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This paper describes the key findings of a regional study that targeted the unconventional potential of exploration assets hold by OMV Petrom in Romania. Three unconventional plays have been evaluated, including the (1) Silurian and (2) the Dogger on the East European Margin (including Moesia), and the (3) Oligocene in Maramures (Pienides). The Silurian shales are at 2-4 km depth in the gas window on Western-Central Moesia. Maturity in most cases has been reached by the Late Paleozoic and it was followed by significant exhumation during the Hercynian Orogeny. The quality of Silurian shale represents a major uncertainty, due to the sparse dataset represented by old wells. The Dogger shales of Northern Moesia are in the oil and gas window under the most external thrusts of the Carpathians at depths that exceed 4 km. The shales have TOC values up to 6 %. Oligocene shales with TOC of up to 10 % in Maramures are in the oil window at depths of less than 2 km. This makes them a very attractive target for shale-oil exploration. However, major setbacks are the complex tectonic structure, rugged topography and large-scale exhumation. Ongoing exploration efforts for non-conventional plays are targeted to define the mechanical properties and the exploration sweet spots in the above mentioned plays, but also assessing the potential of the Late Paleozoic bituminous dolomites of Moesia and other black shales in the Carpathians.