Origin, migration and alteration of hydrocarbons in the Austrian sector of Alpine Foreland Basin PhD Thesis Łukasz Pytlak, MSc Supervisor: Univ.-Prof. Mag.rer.nat Dr. mont. Reinhard F. Sachsenhofer, Department Applied Geosciences and Geophysics Chair of Petroleum Geology Montanuniversität Leoben Leoben, 2017 Affidavit I declare in lieu of oath, that I wrote this thesis and performed the associated research myself, using only literature cited in this volume. MSc Łukasz Pytlak 2 Acknowledgements First and foremost, I would like to thank my supervisors, Reinhard Sachsenhofer and Doris Gross, for their invaluable guidance throughout the process of writing this thesis. Secondly, I would like to extend my gratitude to Rohoel-Aufsuchungs AG for providing me the access to the samples and data which made this thesis possible. I also owe my thanks to Rohoel-Aufsuchungs AG employees Hans-Gert Linzer, Alan Reingruber, Wilma Troiss, Werner Tschelaut and Christoph Janka for their motivation and dedicating their time to assist me in all aspects of this thesis. Co-operation between Montanuniversität Leoben and Rohoel-Aufsuchungs AG in the frame of the FFG-Bridge Project (836527) resulted as numerous articles and conference papers. The most meaningful full research articles are: Pytlak et al., 2016. Generation, mixing and alteration of thermogenic and microbial gas in oil deposits: The case of the Alpine Foreland Basin (Austria). Marine and Petroleum Geology 78, 575-592 Pytlak et al., 2016. Gas accumulations in Oligocene-Miocene reservoirs in the Alpine Foreland Basin (Austria): evidence for gas mixing and gas degradation. International Journal of Earth Sciences Pytlak et al., 2017. Composition of diamondoids in oil samples from the Alpine Foreland Basin, Austria: potential as indices of source rock facies, maturity and biodegradation. Journal of Petroleum Geology 40, 153-171 Pytlak et al., (under review). Light hydrocarbon geochemistry of oils in the Alpine Foreland Basin: Impact of geothermal fluids on the petroleum system. Geofluids Pytlak et al., (under review). Origin of condensates co-produced with microbial gas in the Alpine Foreland Basin (Austria): lessons learned from ancillary geochemical methods. Organic Geochemistry Here I want to thank the editors Christopher Tiratsoo (Journal of Petroleum Geology), Robert Ondrak (GFZ German Research Centre for Geoscience, Marine and Petroleum Geology) and Wolf-Christian Dullo (International Journal of Earth Sciences), the reviewers Andrea Vieth-Hillebrand (GFZ), Gabor C. Tari (OMV), C. Ungureanu (OMV), G.N. Gordadze (Gubkin University) and two anonymous reviewers for their suggestions, which helped to improve the articles (and the present thesis) considerably. I am immensely grateful to Adam Kowalski (AGH University of Science and Technology) for help with GC-MS/MS, enabling a part of my thesis which resulted from an Elsevier Research Scholarship 2015 (see section 8). Special thanks go to Achim Bechtel and Reinhard Gratzer (both from Montanuniversität Leoben) for sharing with me their knowledge on geochemistry and guiding me through the laboratory work. A big “thank you” goes to Walter Prochaska (Montanuniversität Leoben), Albrecht Leis (JR-AquaConSol GmbH) and Suryendu Dutta (Indian Institute of Technology Bombay) for providing me the results, which became an integral part of this thesis and help with establishing the analytical method. A sincere thank-you to my colleagues at the Chair of Petroleum Geology for all the support and help during hard times. Last but not least, “thank-you” to my wife Joanna, my family and friends for being the people I can always count on. 3 Abstract Two petroleum systems are present in the eastern (Austrian) sector of the Alpine Foreland Basin. Whereas oil and thermogenic gas in Mesozoic and Eocene reservoir rocks have been generated beneath the Alps in Lower Oligocene source rocks, relative dry gas in Oligocene–Miocene clastic rocks deposited in the deep marine basin-axial channel system (Puchkirchen Channel) is interpreted as microbial in origin. Detailed investigations of the molecular and isotope composition of hydrocarbon samples from Cretaceous, Eocene and Oligocene/Miocene reservoirs (representing all producing fields) give new insight into the filling history of traps. 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, both generated from the same source rock, but at different maturity levels. API gravity of (non-altered) oils and the development of gas caps in the eastern part of the study area 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. However, those gases are enriched in 2H isotope suggesting different methanogenesis pathways. 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 (e.g., KK field). All other fields contain varying amounts of thermogenic gas/condensate, which have been generated from a source rock with oil-window maturity. Moreover, concentration of diamondoids (and their 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 4 reservoirs. Upward migration occurred along discrete fault zones (e.g., H field) or through low-permeability caprocks. Local erosion of Lower Oligocene sediments, the principal seal for the thermogenic petroleum system, as well as a high percentage of permeable rocks within the Puchkirchen Channel favored upward migration and mixing of thermogenic and microbial gas. The same (Lower Oligocene) source rock for condensates in Oligocene/Miocene reservoirs and oils in Cenomanian/Eocene reservoirs is proven by geochemical features. All gas and condensate samples in Oligocene/Miocene reservoirs are biodegraded. Biodegradation and the formation of secondary microbial gas resulted in gas drying. Therefore, the gas samples analyzed in this study are relative dry, despite significant contributions of thermogenic hydrocarbons. Biodegradation probably continues at present time. The degree of biodegradation, however, decreases with depth. Diamondoid hydrocarbons were detected in the saturated fraction of all analysed oils. 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. In the Alpine Foreland Basin, 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 results indicate that the composition of diamondoids in oils from the Austrian part of the Alpine Foreland Basin 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. Apart from petroleum, the basin hosts a significant geothermal potential, which is based on the regional flow of meteoric water through Malmian carbonate rocks. 57 oil samples and 19 water samples (representing 28 fields) were measured for chemical snd isotopic compositions. Oils are predominantly composed of n-alkanes, while some samples are progressively depleted in light aromatic components. The depletion in aromatic components relative to abundant n-alkanes is an effect of water washing. Besides a progressive depletion in aromatics, 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 5 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