The most prolific source rock in the eastern Georgian portion of the Kura Basin occurs within the so-called “Maykop Formation” which is traditionally assigned to the Oligocene–Early Miocene. Most of the existing literature on Maykop shales concentrate on the South Caspian Basin and the Azerbaijani portion of the Kura Basin, while age and stratigraphic data for the Georgian sector is scarce. For this reason, the present study aims to (1) investigate the source potential of the Maykop Formation and the underlying Upper Eocene succession specific to the Near-Tbilisi area and (2) establish a new stratigraphic division for the Upper Eocene to Lower Miocene interval. For estimation of source potential and determination of depositional environments, drill cuttings samples from three wells northeast of Tbilisi (Norio-72, Ninotsminda-97, and Manavi-12) were selected for elemental analysis using the LECO and Eltra methods, Rock-Eval pyrolysis, organic petrology, biomarker analysis, and carbonate isotopy. Age assignment of the samples was carried out with calcareous nannoplankton data provided by S. Ćorić. In addition, biomarker analysis on oil samples from the Ninotsminda field and Manavi-12 well enabled source-oil correlation. 1-D thermal maturation modeling allowed estimation of eroded thickness, paleo-heat flow, and the onset of hydrocarbon generation. Although most samples were contaminated by oil-based mud, important results could still be obtained. A revised stratigraphy dates samples to Eocene and Oligocene. Bulk geochemical parameters and biomarkers indicate deposition in dysoxic environments. The organic matter input came from a mixed marine and terrestrial source, resulting in type III-II kerogen in Oligocene rocks and type II-III kerogen in Eocene rocks. Relatively low values for vitrinite reflectance and Tmax show that the studied intervals are immature to marginal mature. Oils from Eocene and Cretaceous reservoirs of the Ninotsminda field and Manavi-12 well form one oil family and were most likely generated from Eocene source rocks. On the other hand, asphaltene-rich oil from the Oligocene reservoir of the Ninotsminda field forms a separate oil family. 1-D thermal models created using data from the Norio-72 and Ninotsminda-97 wells suggest that the two areas experienced different amounts of uplift. The original thickness of the combined Oligocene and Miocene rocks was significantly higher in the Norio area compared to the Ninotsminda area. However, erosion at Norio was minimal (0 to 500 m), while sediments up to 2000 m thick were eroded at Ninotsminda. Due to a relatively low heat flow (approximately 45 mW/m2), significant hydrocarbon generation could have occurred only at a maximum burial depth exceeding 5500 m. Time plots of maturity and transformation ratio calibrated against vitrinite reflectance data imply that hydrocarbon generation from the studied interval began in the Late Miocene at Norio and did not occur at all at Ninotsminda. Results of this study suggest that, following the nomenclature of Peters (1986), the upper part of the Oligocene holds poor hydrocarbon potential, while the lower part holds fair gas and oil potential. The Eocene succession shows very good generative potential for gas and oil.