Unconventional petroleum systems in NW-Germany and the Netherlands: A 3D numerical basin modeling and organic petrography study Von der Fakultät für Georessourcen und Materialtechnik der Rheinisch-Westfälischen Technischen Hochschule Aachen zur Erlangung des akademischen Grades eines Doktors der Naturwissenschaften genehmigte Dissertation vorgelegt von Dipl.-Geol. Mark Benjamin Bruns aus Koblenz Berichter: Univ.-Prof. Dr. rer. nat. Ralf Littke Univ.-Prof. Peter Kukla, Ph.D. Tag der mündlichen Prüfung: 12. Dezember 2014 Diese Dissertation ist auf den Internetseiten der Hochschulbibliothek online verfügbar Acknowledgements I Acknowledgment My special thanks go to Prof. Dr. Ralf Littke who initially gave me the opportunity to start as a student assistant at the Institute of Geology and Geochemistry of Petroleum and Coal at RWTH Aachen University. His endorsement despite initially uncertain thematic focus and project funding lead up to the possibility to graduate under his supervision. His constant support throughout my studies greatly helped to carry out this doctoral study. I would also like to sincerely thank Prof. Dr. Rolando di Primio for providing access to the GASH initiative which financed parts of this study and for valuable discussions of different basin modeling aspects. Prof. Peter A. Kukla, PhD, is thanked for taking the role of the co- supervisor and putting valuable effort into reviewing this thesis. I thank Matus Gasparik, Jan-Diederik van Wees and Susanne Nelskamp as well as the companies ExxonMobil for providing valuable input data and Schlumberger for an academic license of the PetroMod® software. For the support and training I gratefully acknowledge the whole team of Schlumberger AaTC where I worked as a software tester for several years deepening my expertise in using the PetroMod® software and developing an improved analytical way of questioning simulation results and finding software bugs. Special gratitude goes to my fellows at the Institute of Geology and Geochemistry of Petroleum and Coal for providing a great working environment and occasional insanity in this sane world of working towards a doctorate. Finally, I want to express my very great appreciation to my parents and Nicole Kopriwa for their continuous support and encouragement during my academic studies. Without them I would not be where I am today. Aachen, 22.09.2014 Mark Benjamin Bruns Abstract II Abstract In times of rapidly growing energy demands petroleum exploration focus has shifted more and more towards unconventional petroleum systems due to increasing difficulties in finding and profitably producing from conventional oil and gas fields but also due to recent increases in gas price and enhanced recovery techniques, such as horizontal drilling and hydraulic stimulation which allow production from these tight low-permeable reservoirs. Based on the successful exploration of and production from U.S. American shale gas/oil plays it was discussed whether similarly successful plays would also be available in Europe. In this context, sedimentary basins in NW-Germany and the Netherlands represent amongst others potential targets for shale gas exploration in Europe due to the presence of Cretaceous (Wealden) and Jurassic (Posidonia) marlstones/shales as well as various Carboniferous black shales. Unlike in conventional reservoirs in which gas is stored primarily as compressed (“free”) gas in the intragranular pore space and fractures, a significant proportion of gas in shales can be stored as “sorbed” gas. The sorption of hydrocarbon gas (mostly methane) in shales provides gas storage capacity in addition to the “free gas” capacity in the pore system. The methane sorption is considered to take place predominantly within the microporous organic matter (kerogen) and is controlled by the Total Organic Carbon (TOC), kerogen type, maturity, water saturation and to some extent by the inorganic constituents (clay minerals). Numerical petroleum system modeling provides the only means to combine results from different geological, geochemical and geophysical analysis methods within the frame of a 4D thermo-tectonic reconstruction of the basin´s evolution. Therefore, the aim of this study is to combine basin and petroleum system modeling approaches with petrophysical as well as petrographic methods in order to substantiate former assumptions on the geodynamic evolution of the study area providing a reasonable assessment of the regional shale gas prospectivity and thus reducing potential exploration risks prior to drilling. For this, 3D high resolution petroleum system models of NW-Germany and the Netherlands have been compiled and used to reconstruct the source rock maturation based on calibrated burial and thermal histories. Different basal heat flow scenarios and accordingly different high-resolution scenarios of erosional amount distribution were constructed, representing all major uplift events that affected the study area. The models deliver an independent reappraisal of the tectonic and thermal history that controlled the differential geodynamic evolution and provide a high-resolution image of the maturity distribution and evolution throughout the study area and the different basins. Pressure, temperature and TOC-dependent gas storage capacity and gas contents of different potential source rocks were calculated based on experimentally derived Langmuir sorption parameters and newly compiled source rock thickness maps. With additional petrographic analysis methods assessing the lithological dependency of vitrinite reflectance as a maturity parameter in high rank sedimentary rocks as well as Abstract III utilizing its anisotropic character (at maturity levels above 2% VRr) as stress/strain indicator this study can also contribute to the understanding of burial and temperature history in the Lower Saxony Basin. RIS (Reflectance Indicating Surface) analysis shows a predominantly negative biaxial distribution of vitrinite reflectance indicating the absence of thermal overprinting by a possible magmatic intrusion (Bramsche Massif) during the Upper Cretaceous but, in addition to vertical stresses due to depositional loading, the presence of a secondary stress field not perpendicular to bedding and related to the inversion of the Lower Saxony Basin. This basin belongs to an en-echelon shaped basin sub-system of similar geodynamic evolution which can be tracked throughout the whole Central European Basin System (CEBS). One of the most distinctive aspects of its evolution is the dominant uplift and partial inversion during the Upper Cretaceous ultimately controlling source rock maturation, petroleum generation, migration and trapping. Especially in the Lower Saxony Basin deep subsidence was followed by strong uplift with maximum amounts of up to 6800-8900 m of eroded basin infill during the Subhercynian inversion depending on the modeled basal heat flow trend. Modeling results indicate maturity patterns of the most important petroleum source rocks and also prospective areas within the study area exhibiting shale gas potential at present- day. These areas are confined to the Lower Saxony Basin, southern Gifhorn Trough and West Netherlands Basin. For the Posidonia Shale in the Lower Saxony Basin low bulk adsorption capacities (note that bulk adsorption capacities are given for the total layer thickness within a grid cell size of 1 km2) of about 0.16*106 tons and gas contents of up to 82 scf/ton rock have been predicted. The capacities at the northern and eastern boundaries of the Lower Saxony Basin, Pompeckj Basin and Gifhorn Trough range around 0.3*106 tons. In the West Netherlands Basin, capacities range between 0.14-0.31*106 tons. In the southern area of the Gifhorn Trough and southwestern flank of the West Netherlands Basin average gas contents of up to 95 scf/ton rock have been predicted. Bulk adsorption capacity of the Wealden is proportional to the varying layer thickness and ranges up to 3.45*106 tons. Gas contents have been calculated for the Ems river area with values up to 26 scf/ton rock and the Hunte river area with contents up to 45 scf/ton rock. Kurzfassung IV Kurzfassung In Zeiten rapide ansteigenden Energieverbrauchs hat sich die Fokussierung der Erdöl/- gasexploration zunehmend auf unkonventionelle Lagerstätten verlagert, da Funde neuer konventioneller Lagerstätten immer seltener werden und verbesserte Gewinnungsmethoden eine profitable Produktion aus diesen dichten niedrig-permeablen Lagerstätten erlauben. Basierend auf der erfolgreichen Exploration von und Produktion aus amerikanischen Schiefergas/-ölsystemen, stellt sich die Frage, ob ähnliche Systeme auch in Europa anzutreffen sind. Sedimentbecken in NW-Deutschland und den Niederlanden gehören zu den potentiell möglichen Regionen, in denen Schiefergasförderung aufgrund des Vorkommens von kreidezeitlichen (Wealden) und jurassischen (Posidonia) Mergel- /Tonsteinen sowie verschiedenen karbonischen Schwarzschiefern geologisch möglich erscheint. Anders als in konventionellen Reservoirs, in denen Gas hauptsächlich als komprimiertes „freies“ Gas im Porenraum und Bruchgefüge vorkommt, kann in Tonsteinen ein signifikanter Anteil als „sorbiertes“ Gas gespeichert sein. Die Sorption von Kohlenwasserstoffgasen (hauptsächlich Methan) in Tonsteinen bietet daher zusätzliche Gasspeicherkapazität zur „freien Gas“-Speicherkapazität im Porenraum. Die Sorption von Methan findet hauptsächlich im mikroporösen organischen Material (Kerogen) statt und wird durch den Gehalt an organischem Kohlenstoff (TOC), den