Maturity parameters based on the light hydrocarbons fraction, as well as diamondoid isomerization indices and 13C of ethane and propane show that light hydrocarbons in oils from Cenomanian/Eocene reservoirs have been generated from a source rock with late oil window maturity (1.1-1.2% Rr). This is a higher maturity level than indicated by biomarker isomerization ratios and MPI-1 (0.6-0.9 %Rr) and points to mixing of two end-member oil phases generated at different maturity levels. API gravity of (non-altered) oils and the development of gas caps are controlled by the relative percentage of the hydrocarbons with higher maturity. Mixing of fluids with different maturities is also supported by evidences for evaporative fractionation. In contrast, most Cenomanian/Eocene fields trap methane derived from a source which is not thermogenic. Shallow northeastern reservoirs trap methane interpreted as secondary microbial in origin. The same process is proposed here as source of methane in north-western deposits. Fields along the southern margin of the Alpine Foreland Basin, where reservoir temperature exceeds 80°C, host methane generated during primary organic matter degradation. Thus, Eocene layers should be considered as additional potential source rocks. Presence of pure microbial gas in Oligocene/Miocene reservoirs is rare and limited mainly to the northern basin flank. All other fields contain varying amounts of thermogenic gas/condensate, which have been generated from a source rock with oil-window maturity. Concentration of diamondoids (and isomerization indices) in the condensates are positively correlated with percentages of thermogenic methane in co-produced (microbial) gas. Consequently, the condensates are explained as products of evaporative fractionation of oils in Cenomanian/Eocene reservoirs. The same (Lower Oligocene) source rock for condensates in Oligocene/Miocene reservoirs and oils in Cenomanian/Eocene reservoirs is proven by geochemical features. Biodegradation of condensates and the formation of secondary microbial gas resulted in gas drying. A biodegraded oil sample from a shallow reservoir in the northeastern part of the study area showed an enrichment in diamondoids due to the molecule’s high resistance to microbial degradation. Biomarker-derived maturity parameters do not show a convincing correlation with diamondoid maturity parameters. Moreover, no cracking trend based on biomarkers and diamondoid concentrations was observed. The composition of diamondoids in oils is mainly controlled by heterogeneities in the Lower Oligocene source rocks, including the occurrence of a redeposited source rock succession in the western part of the study area. By contrast, EAI-1 (the ethyladamantane index) shows a good correlation with various maturity parameters and seems to be independent of source rock facies. The depletion in aromatic components in oils compare to relative abundant n-alkanes, is an effect of water washing. Water washing causes a reduction in API gravity and removal of sulphur bearing compounds. Waters co-produced with oils that are affected by water washing show a progressive reduction in salinity and depletion in 2H and 18O isotopes, indicating that the degree of water washing is mainly controlled by the inflow of meteoric water from Malmian carbonates. Most strongly affected oils are located in the shallow northern and northeastern part of the study area. In some fields with Cenomanian reservoirs, a hydraulic connectivity with the thermal aquifer is evident. However, water washing is also recognized in Eocene reservoirs in areas where the Malmian aquifer is missing. This shows that existing flow models for the regional geothermal aquifer have to be modified. Therefore, the results emphasize the importance of combining data from the petroleum and geothermal industry, which are often handled separately.