Oil-source rock correlation was performed to reveal the contribution of several potential source rock horizons to the charging of hydrocarbon reservoirs in the Ukrainian Dniepr-Donets Basin (DDB). HI values of the least mature Rudov Beds (<300 mgHC/gTOC) agree with the presence of a mixed type III/II kerogen. However, a potential to generate low-wax Parafinic-Naphthenic-Aromatic oils was determined for samples from the basin center, based on pyrolysis experiments. Furthermore, it could be proven by combined isotopic and biomarker data, that Upper Visean intervals, particularly the most prolific “Rudov Facies”, are likely the most important source for hydrocarbons in the region. Study results revealed a correlation between δ13C of the aliphatic fraction of crude oils and the δ13C of methane in gas samples, arguing for a common (Upper Visean) source. Following the general proof that Upper Visean black shales in the northwestern DDB are partly prone to the generation of liquid hydrocarbons, a laterally well-resolved evaluation of their shale oil/gas potential was performed focusing on the key parameters (i) shale thickness, (ii) thermal maturity, (iii) mineralogy, as well as (iv) generation potential based on pyrolysis experiments. Average TOC contents of Rudov Beds within the Srebnen Bay, up to 100 meters thick, are very high (>4 %). Average TOC contents of wells north and northwest of the Srebnen Bay are significantly lower (<4 %), but still in the range of 2-4 %TOC over a relatively wide lateral extend. The thickness of these rocks is generally lower (20-40 m; max. 60 m) compared to basinal wells. In contrast, TOC contents <2 % along the northeastern basin margin indicate that these rocks do not hold a shale gas/oil potential. Apart from an obvious maturity trend, pyrolysis experiments indicate a higher amount of oil-prone type II kerogen in the basinal facies, whereas marginal samples dominated by vitrinite macerals are predominantly gas-prone. High TOC contents (up to 10 %) along the southeastern basin margin are partly caused by a higher amount of inertinite macerals in these samples. However, the cut-off maturity for shale oil (liquids) production (0.8 %Rr) is reached only at considerable depths > 4.0-4.5 km within the Srebnen Bay, whereas the shale gas cut-off (1.2 %Rr) is not reached within the northwestern DDB at all. Sufficient thermal maturity is reached only in great depths (> 5.5 km) along the basin axis within the central DDB and at even greater depths in southeastern positions. Apart from that, kinetic experiments suggest that earlier hydrocarbon generation, e.g. due to present type IIS kerogen, cannot be assumed. The mineralogy of Rudov Beds varies strongly in lateral and vertical directions, limiting the predictability of shale brittleness. The desired amount of 60 wt.% brittle minerals (quartz, feldspar, etc.) is reached only partly by samples from the siliceous (basinal), and rarely by samples from the transitional and lagoonal (clayey & calcareous) facies. In summary, findings of this study arouse the question if the Upper Visean succession in the DDB, despite a considerable amount of oil/gas-in-place, will be an economic play in the future. An innovative part of this study focused on the pore space-generation within organic matter during thermal maturation. According to SEM and FIB/BIB-SEM data, nanopores are not abundant in primary macerals (e.g. vitrinite) even in overmature rocks, whereas they develop within secondary organic matter (bitumen) formed mainly at gas window maturity. Frequently occurring sub-micrometer porosity was detected within mudstones at a vitrinite reflectance >2.0 %Rr. However, such pores have also been detected in solid bitumen of oil-prone samples at oil window maturity (0.65-0.8 %Rr), arguing for the necessity to combine organic geochemical analysis with high resolution-imaging, for a better characterization of pore growth in organic matter.