Unconventional Oil and Gas Potential of the Toarcian Posidonia Shale

Unconventional oil and gas potential of the Toarcian Posidonia Shale Formation in the crossjunction of Lower Saxony Basin, Pompeckj Block and Gifhorn Trough, Northern Germany: Implications from Organic Petrography, Geochemistry and 3D Numerical Basin Modelling

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 M.Sc.

Alexander Thomas Stock

aus Köln

Berichter: Univ.-Prof. Dr. rer. nat. Ralf Littke Prof. Dr. Brian Horsfield

Tag der mündlichen Prüfung: 05.Oktober 2017

Diese Dissertation ist auf den Internetseiten der Hochschulbibliothek online verfügbar II

Acknowledgements

I would like to express my utmost gratitude to Prof. Dr. Ralf Littke for enabling me to pursue a PhD in the field of Petroleum Geoscience at the Institute of Geology and Geochemistry of Petroleum and Coal at RWTH Aachen University. His tutelage and knowledge, combined with his outstanding support during my studies enabled me to persecute this degree, for which I am very grateful. Furthermore, I would like to express my gratitude towards Prof. Dr. Brian Horsfield for his work as a reviewer of this thesis and for enabling my research stay at the GFZ Potsdam.

I am additionally very grateful for the help and support of Dr. Benjamin Bruns and Dr. Victoria Sachse, Dr. Daniel Mohnhoff, Dr. Alexej Merkel, Dr. Reinhard Fink and Dr. Arne Grobe, who helped with problems and questions regarding the various analytical techniques conducted within the scope of the thesis and who were always there for further fruitful discussions.

Further gratitude is due for Donka Macherey, Annette Schneiderwind and Yvonne Esser for all the technical support and for tirelessly answering questions regarding the analytical methods.

I would sincerely thank all my friends, colleagues and fellows during my stay at the Institute of Geology and Geochemistry of Petroleum and Coal who provided a wonderful work environment and inspired some of the best and funniest lunch break discussions.

My deepest regards go to my family, especially my father and grandmother who provided support and encouragement during the creation of this thesis.

III

Abstract

Petroleum production in Germany has a longstanding history that already started in the late 18th century in NW-Germany. Although petroleum production in Germany has rapidly declined from the early 1960’s onwards, there is still ongoing production in Germany. The production itself however faces strong challenges, as low oil prices due to a wealth of unconventional gas production in the US strongly influence the expensive domestic oil production in Germany. While the demand for petroleum and petroleum products is still high, conventional oil production in Germany declines, as known reservoirs are nearing the end of their lifecycle and further exploration efforts have been on a low level. The success of the unconventional oil and gas production, especially in the US, could act as an example in how to increase domestic production and to reduce the dependence on oil and gas imports. Although hydraulic fracturing, often a prerequisite for unconventional hydrocarbon production, is currently prohibited, an assessment of the theoretical potential and the location of so called “sweet-spots” can help in determining the suitability of the here chosen study area for conventional and unconventional petroleum potential, should the need for increasing domestic production or for reduced dependence on exporting countries arise.

The chosen study area, a triple-junction of geological basin, namely the Pompeckj Block, the Lower-Saxony Basin and the Gifhorn Trough, located in NW-Germany, has been the target in past exploration and production efforts and still presents a major target in petroleum exploration and assessments for the future. The presence of Cretaceous (Wealden) and Jurassic (Posidonia Shale) marlstones and shales, as well as Carboniferous black shales and coals, acting as source rocks present within the basin systems, marks this area as a prominent oil and gas province. Especially the unconventional petroleum potential within the basin presents an up to date untapped resource that could be utilized, similar to the US shale gas boom, to increase the domestic production here in Germany. Current and past research on especially the Posidonia Shale in Germany have verified its suitability as a potential source rock in unconventional petroleum production due to its inherent type II hydrogen-rich kerogen, high TOC values and good thickness.

To correctly assess the petroleum potential of the Posidonia Shale within the study area, this thesis studied its source rock characteristics, the oil properties of oils sourced by the Posidonia Shale and used 3D numerical basin modelling to illustrate its distribution and potential. Organic geochemical analysis and bulk geochemical analysis conducted on oil IV samples from locations within the eastern LSB, the Pompeckj Block and the Gifhorn Trough and on Posidonia Shale analogue samples certified the excellent quality of the oils, with API° values higher than 30° and confirmed that the oils present in the study area are mainly sourced from Posidonia Shale source rocks alone. There was no apparent contribution of the lacustrine Wealden Shales recognizable. In depth kerogen analysis, using a maturity series of kerogen concentrates from Posidonia Shale samples allowed for insights into the petroleum composition at different maturities along the natural maturation pathway, providing a better mode of prediction for cracking products at certain maturities. This, in combination with petroleum kinetics measurements, was used to calibrate and create a 3D numerical basin model of the area, utilizing a threefold division of the Posidonia Shale and predicting petroleum accumulations and volumes, within potential reservoirs and for the unconventional potential within the three lithologic source rock units.

The results from the high resolution 3D numerical basin model indicate that different localities within the study area show different predispositions in their potential for oil and gas production. Based on their maturity assessment, gas potential is present in the Central LSB and parts of the Pompeckj Block, while higher oil potential can be found on the rims of the LSB, in the Gifhorn Trough and in larger parts of the Pompeckj Block. While large parts of the produced hydrocarbons have been expelled from the source rock lithology, especially large parts of gas can be still retained in the pore system as free gas and in an adsorbed phase. However, especially the free gas shows a strong dependence, similarly to oil, on the sealing capacity of the overlying strata.

Kurzfassung

Die Erdölförderung in Deutschland hat eine weitreichende Geschichte, welche bereits im 18. Jahrhundert begonnen hat. Auch wenn die Erdölförderung in Deutschland seit den 1960ern rapide abnimmt, gibt es dennoch einen Anteil an heimischer Öl- und Gasförderung in Deutschland. Die deutsche Öl- und Gasförderung ist jedoch einigen Herausforderungen unterworfen, nicht zuletzt der hohe Preis einheimischer Förderung gepaart mit dem seit Ende 2015 geringen Ölpreis aufgrund von Überproduktion, nicht zuletzt wegen der unkonventionellen “Shale Gas” und „Shale Oil“ Förderung der USA. Zwar ist der Bedarf an Öl und Gas in Deutschland weiterhin hoch, die deutschen Produktionsmengen nehmen jedoch ab, auch auf Grund des Lebenszyklus von Erdöl- und Erdgas-Lagerstätten, von denen sich viele ältere Felder dem Ende der Produktion nähern. Witere Exploration in Deutschland trifft zum einen auf eine zunehmend kritische Wahrnehmung in der Öffentlichkeit, zum anderen sind die Produktionskosten relativ hoch. Der Erfolg der unkonventionellen Öl- und Gasproduktion in den USA kann hier als ein Beispiel dienen wie auch durch politischen Hilfe die einheimische Produktion wieder erhöht und gleichzeitig die Importabhängigkeit reduziert werden kann. Kritisch betrachtet wird vor allem die Technik des “Hydraulic Fracturing”, auch Fracking genannt, welche jedoch oft eine Voraussetzung für die unkonventionelle Förderung ist. Diese Studie soll dazu dienen, das theoretische Potential und die Lage von potentiellen Explorationszielen in NW-Deutschland zu erfassen, falls in näherer Zukunft ein erneutes Bestreben nach deutscher Erdöl- und Erdgas-Produktion besteht, auch um wirtschaftspolitisch unerwünschte Importabhängigkeiten zu reduzieren.

Der ausgewählte Arbeitsbereich, welcher das Niedersächsische Becken, den Pompeckj Block und den Gifhorner Trog mit einschließt, ist bereits als eine der ertragreichsten Erdöl- und Erdgasprovinzen in Deutschland bekannt. Durch die Präsenz der Wealden-Shales (Kreide), des Posidonienschiefers (Jura) und von Karbonischen Schwarzschiefern und Kohlen, welche als Muttergesteine für Erdöl und Erdgas dienen können, ist diese Region eine der Kohlenwasserstoff-höffigsten in Deutschland. Da sich die Förderung in diesem Gebiet bisher primär auf konventionelles Erdöl- und Erdgas beschränkt hat, besteht hier auch ein riesiges Potential zur unkonventionellen Förderung. Besonders das Potential des Posidonienschiefers ist in rezenten Studien als exzellent ausgewiesen worden, vor allem da er ein VI wasserstoffreiches Typ-II Kerogen beinhaltet, bei hohen TOC-Werten und einer hohen Mächtigkeit.

Um das Potential des Posidonienschiefers im Arbeitsbereich möglichst genau vorhersagen zu können, wurden im Verlauf dieser Arbeit dessen Muttergesteins-Charakteristika und die Öl- Eigenschaften von natürlichen Erdölen analysiert. Auf großem Maßstab wurde die Lagerstättenbildung mit Hilfe von numerischer 3D Modellierung berechnet. Hierbei zeigte sich, dass Öle des Posidonienschiefers eine sehr gute Qualität aufweisen, mit API°-Werten größer als 30 ° und dass im Arbeitsgebiet der Einfluss der Wealden-Tonsteine auf die Erdölbildung gering ist. Mit Hilfe der Analyse einer Kerogenkonzentrat-Reifeserie konnten neue Erkenntnisse in Bezug auf die Zusammensetzung der während der thermischen Reifung freigesetzten Stoffklassen gewonnen worden, was eine zusätzlich Vorhersage von “Crack”- Produkten bei der Entstehung von Öl und Gas aus dem Muttergestein ermöglicht. In Kombination mit Petroleum-Reaktions- Kinetiken wurden diese Daten als Basis für ein numerisches 3D Beckenmodell des Arbeitsgebietes verwendet, mit dessen Hilfe die genaue Lage und das Potential von Erdöl- und Erdgas-Lagerstätten prognostiziert werden soll.

VII

Table of Contents Acknowledgements II Abstract III Kurzfassung V Table of Contents VII List of Abbreviations X List of Figures XII List of Tables XVII List of Units XVIII

2 Geochemical composition of oils from the Gifhorn Trough and Lower Saxony Basin in comparison to Posidonia Shale source rocks from the Hils Syncline, northern Germany ...... 15 2.1 Abstract ...... 15 2.2 Introduction ...... 15 2.3 Geological Background ...... 18 2.4 Samples and methods ...... 20 2.4.1 Elemental analysis ...... 21 2.4.2 Vitrinite reflectance measurements ...... 21 2.4.3 Density measurements ...... 22 2.4.4 Geochemical analyses & bulk sample extraction ...... 22 2.4.5 TLC-FID (Iatroscan) ...... 24 2.4.6 Rock-Eval Pyrolysis ...... 24 2.5 Results ...... 24 2.5.1 Shallow boreholes from the Hils-syncline ...... 24 2.5.2 Oil samples from the LSB and the Gifhorn Trough ...... 25 2.6 Discussion ...... 30 2.6.1 Petroleum source rocks ...... 30 2.6.2 Origin and maturity of the oils ...... 33 2.7 Conclusions ...... 39 3 Organic geochemistry and petrology of Posidonia Shale (Lower Toarcian, Western Europe) – the evolution from immature oil-prone to overmature dry-gas kerogen ...... 42 3.1 Abstract ...... 42 3.1.1 Introduction ...... 42 3.2 Methods and samples ...... 46 3.2.1 Sample origin ...... 46 3.2.2 Kerogen concentration ...... 46 3.2.3 Organic petrography ...... 46 VIII

3.2.4 Rock-Eval pyrolysis ...... 47 3.2.5 Elemental analysis ...... 47 3.2.6 Curie Point-Pyrolysis-GC-MS (CP-Py-GC-MS) ...... 47 3.2.7 FT-IR-spectroscopy ...... 48 3.3 Results ...... 48 3.3.1 Microscopy, elemental analysis and Rock-Eval pyrolysis ...... 48 3.3.2 Curie Point-Pyrolysis-GC-MS (CP-Py-GC-MS) ...... 55 3.3.3 FT-IR ...... 64 3.4 Discussion ...... 67 3.4.1 Differences between bulk samples and kerogen concentrates ...... 67 3.4.2 Sample maturity and bulk geochemistry ...... 68 3.4.3 Maturity and structural changes in kerogen ...... 71 3.4.4 Maturation products and kerogen cracking ...... 72 3.5 Conclusions ...... 72 4 The Posidonia Shale of Northern Germany – Unconventional oil and gas potential from high resolution 3D numerical basin modelling of the cross-junction between the Easter Lower Saxony Basin, Pompeckj Block and Gifhorn Trough ...... 76 4.1 Abstract ...... 76 4.2 Introduction ...... 76 4.2.1 Stratigraphic Framework ...... 78 4.2.2 Petroleum Systems in the Central European Basin System (CEBS) ...... 80 4.2.3 Petroleum Generation Kinetics ...... 81 4.3 Methods ...... 83 4.3.1 Bulk Geochemistry ...... 83 4.3.2 Compositional Petroleum Kinetics ...... 83 4.3.3 3D Numerical Basin Modelling & Calibration...... 84 4.3.4 Model Outline ...... 85 ...... 85 4.3.5 Stratigraphy and Lithology ...... 88 4.4 Results & Discussion ...... 93 4.4.1 Maturity of the Posidonia Shale Units ...... 93 4.4.2 Unconventional oil and gas potential and alternative scenarios ...... 95 4.4.3 Implications for unconventional hydrocarbon production within the eastern LSB, the Gifhorn Trough and the Pompeckj Block ...... 101 4.4.4 Conclusion and Outlook ...... 104 5 Final Conclusion ...... 107 IX

5.1 Summary ...... 107 5.2 Final Remarks and outlook ...... 111 6 References ...... 113 7 Curriculum Vitae ...... 133

List of Abbreviations

API = American Petroleum Institute BGR = Bundesamt für Geowissenschaften und Rohstoffe CEBS = Central European Basin System CPI = Carbon Preference Index CP-Py-GC-MS = Curie Point-Pyrolysis GC-MS Fracking = Hydraulic Fracturing FT-IR = Fourier Transformation Infrared Spectrometer FZ Jülich = Forschungszentrum Jülich GC-FID = Gas chromatograph coupled with a flame ionization detector GC-MS = Gas chromatograph coupled with a mass spectrometer GDGT = Glycerol Dialkyl Glycerol Tetraethers GI = Gelification Index GWI = Ground-Water Index GWIac = Ground-Water Index Based on Ash Content HI = Hydrogen Index IR = Infrared LSB = Lower Saxony Basin LBEG = Landesamt für Bergbau, Energie und Geologie Niedersachsen MDR = Methyldibenzothiophene Ratio MPI = Methylphenantrene index MSSV = Microscale sealed vessel technique NMR = Nuclear Magnetic Resonance NWG-gas shales = North-West German-Gas Shales OI = Oxygen Index PI = Production Index Ro = Equivalent Vitrinite Reflectance Value S = Sulfur SWIT = Sediment Water Interface Temperature TLC-FID = Thin-layer chromatography coupled with a flame ionization detector XI

TIC = Total Inorganic Carbon TOC = Total Organic Carbon TPI = Tissue Preservation Index

Tmax = Maximum Calculated Temperature from Rock-Eval Pyrolysis UBA = Umweltbundesamt VPDB = Vienna PeeDee-Formation Belemnite (Standard) VRr = Vitrinite Reflectance Measured on Random Oriented Grains VSMOW = Vienna Standard Mean Ocean Water (Standard) YAG = Yttrium-Aluminium Garnet

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List of Figures

Figure 1.1a: Oil fields and prospective exploration areas for conventional and unconventional oil in Germany, modified after LBEG (2016). on Page 4

Figure 1.1b: Gas fields and prospective exploration areas for conventional and unconventional gas production, modified after LBEG (2016). on Page 5

Figure 2.2a: Geology of the Gifhorn Trough, indicating major stratigraphic and structural units with the Quaternary, Tertiary and Upper Cretaceous removed, as well as locations of oil production (modified after Boigk, 1981). on page 17

Figure 2.2b: Geological map of the Hils-Syncline showing the location of boreholes Wenzen (1), Dohnsen (2), Harderode (3) and Pötzen (4); Quaternary and Tertiary removed, modified after Bartenstein et al. (1971). on Page 19 Figure 2.3: Stratigraphy of the North-West Lower Saxony Basin from the Permian until recent times (after Maystrenko et al. (2008)) and petroleum system events linked to the sedimentary successions in the LSB (after di Primio et al. (2008)). Rock signatures were used according to Shell Standard Legend (1995). % BOE = barrel of oil equivalent. on page 20

Figure 2.4: GC-FID of the aliphatic fraction, displaying the different degree of degradation of the oils samples, Steimbke-Ost 10 (top), Steimbke-Alt WA 317 (middle) and Eystrup 5 (bottom). on page 31

Figure 2.5: GC-MS ion traces of m/z = 191 and m/z = 217 for the samples Steimbke-Ost 10 (top), Steimbke-Alt WA 317 (middle) and sample Eystrup 5 (bottom). on page 32

Figure 2.6: Calculated Ro based on MPI-1 and MDR for the oil samples and samples from the borehole Dohnsen and Harderode. Oil samples show similarity to peak oil mature source rocks from Harderode in some parts but are generally more mature. There is no similarity recognizable with the early mature Dohnsen samples. on page 34

Figure 2.8: Pristane/Phytane vs Dibenzothiophene/Phenanthrene plot of oil samples, indicating the depositional facies of the source rock. on page 37

Figure 2.9: Modelled maturity map of the Posidonia Shale of the Lower Saxony Basin, Gifhorn Trough and parts of the Pompeckj Block (after Bruns et al., 2013). on page 38

Figure 2.10: Saturated hydrocarbons and aliphatic/aromatic ratio plotted against depth for the oil samples from the LSB and the Gifhorn Trough. Arrow marks trend of increased aliphatic/aromatic ratio with depth. on page 39 XIII

Figure 3.2: Paleogeographic map of the Liassic continental shelf on a current map of Western Europe. Figure modified after Schwark and Frimmel (2004), based on Ziegler (1982). on page 45 Figure 3.2: Pseudo-van-Krevelen diagram displaying kerogen type based on HI and OI values from Rock-Eval pyrolysis. on page 49

Figure 3.3a: Tmax [°C] vs VRr [%] plot, displaying the difference between measurements conducted on bulk samples and kerogen concentrates. on page 50

Figure 3.3b: VRr [%] vs HI [mg HC/g TOC] plot of all samples, showing the evolution of type I-II kerogen with increasing maturity (vitrinite reflectance). on page 51 Figure 3.4a-h: Micropetrographic photographs of polished sections. The long axis of each photograph is equivalent to 250 μm. Photos A, C, E, G, H were taken under reflected white light and photographs B, D, F under incident fluorescence light. A) Mostly argillaceous matrix with pyrite nodules (Py) and alginites (visible in B). Sample Wenzen (immature, 0.5 % VRr). B) Same sample area as A). Note the bright yellow fluorescence of the telalginites (TA) and lamalginites (LA). C) Inertinite (In) and pyrite nodules (Py). Sample Dohnsen (mature, 0.7 % VRr). D) Same sample area as C). Telalginite (TA) and lamalginite (LA) clearly visible due to bright yellow fluorescence. E) Pyrite nodules (Py) occurring dispersed throughout the sample. Sample Harderode (mature, 0.87 % VRr). F) Same sample area as E). Note that telalginite (TA) still shows yellow fluorescence but overall fluorescence colors are clearly darker as compared to photos B) and D) due to higher thermal maturity. G) Inertinite (In) and pyrite nodules (Py). Sample Pötzen (postmature, 1.49 % VRr, converted from solid bitumen reflectance). No visible fluorescence was observed. H) Pyrite nodules (Py) and solid bitumen (SB). NWG-gas shale sample (outcrop) (highly overmature, 3.0 % VRr, converted from solid bitumen reflectance). on page 51

Figure 3.4i-o: Typical palynofacies. All unoxidized residues. Photographs I, K, M, O, P were taken using transmitted white light and photographs J, L, N under incident fluorescence light. I) Light brown to brown amorphous organic matter and phycoma of Tasmanites. Sample Wenzen (immature, 0.5 % VRr). J) Same sample area as I). Note the bright yellow fluorescence of the Tasmanites phycoma. K) Amorphous organic matter with badly preserved marine microplankton. Sample Dohnsen (mature, 0.7 % VRr). L) Same sample area as K). Marine microplankton clearly visible due to fluorescence. M) Amorphous organic matter with fragments of algal remains, hardly visible in transmitted white light. Sample Harderode (mature, 0.87 % VRr). N) Same sample area as M). Algal remains and amorphous organic matter show weaker fluorescence compared to sample Wenzen. O) Dark brown to black amorphous organic matter. No visible fluorescence was observed. Sample Pötzen (postmature, 1.49 % VRr, converted from solid bitumen reflectance). P) Dark brown to black amorphous organic matter. No visible fluorescence was observed. ). NWG-gas shale sample (outcrop) (highly overmature, 3.0 % VRr, converted from solid bitumen reflectance). on page 52

Figure 3.5a: CP-Py-GC-MS chromatogram (650 °C) for the sample from Luxembourg. The green squares are representative of sulfur atoms. on page 57

Figure 3.5b: CP-Py-GC-MS chromatogram (650 °C) for the sample from Pötzen. on page 58

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Figure 3.5c: CP-Py-GC-MS chromatogram (650 °C) for the non-weathered sample of the NWG-gas shale. on page 59

Figure 3.6a: CP-Py-GC-MS chromatogram (920 °C) for sample from Luxembourg. The green squares are representative of sulfur atoms. on page 60

Figure 3.6b - CP-Py-GC-MS chromatogram (920 °C) for sample from Pötzen. on page 61

Figure 3.6c - CP-Py-GC-MS chromatogram (920 °C) for the non-weathered gas shale (well) sample. The green square are representative of sulfur atoms. on page 62

Figure 3.7: Cp-Py-GC-MS results for kerogen concentrates plotted versus vitrinite reflectance. A) Toluene/Heptane ratio (pyrolysis temperature 650 °C). B) Toluene/Heptane ratio (pyrolysis temperature 920 °C). C) Alkene/alkane ratio (pyrolysis temperature 920 °C). on page 63

Figure 3.8a: Normalized FT-IR spectra, of four kerogen concentrate samples of varying maturity. Wavenumbers between 3000 - 2800 cm-1 represent the symmetric and asymmetric -1 oscillations of CH2 bonds. Wavenumbers between 1800 – 1500 cm the aromatic C=O and C=C oscillations, with the fingerprint area at wavenumbers smaller than 1500 cm-1. on page 65

Figure 3.8b: Normalized FT-IR spectra, of four bulk samples of varying maturity (see Fig. 3.8a). on page 66

Figure 3.9a: Aliphatic CH2+CH3 (Ali. C-H)/(Aro. C=C) ratio plotted against VRr. on page 66

Figure 3.9b: Aliphatic CH2+CH3 (Ali. C-H)/(C=C+C=O) ratio plotted against VRr. on page 66

Figure 3.10: Rock-Eval pyrolysis parameters from bulk samples and kerogen concentrates plotted against one another. A) HI Kerogen conc. vs HI bulk samples cross plot for all analyzed samples. B) OI Kerogen conc. vs OI bulk samples cross plot for all analyzed samples. C) Tmax Kerogen conc. vs Tmax bulk samples cross plot for all analyzed samples. on page 70 Figure 4.1: Palaeogeographic map of the southern margin of the CEBS during the Coniacian to Maastrichtian with locations of inverted areas and post inversion deposits (after Voigt et al., 2008), with the study area marked in black. The red line marks the profile location illustrated in Fig. 4.2 and the red circles mark the well locations of the calibration wells illustrated in Fig. 4.3. on page 78 Figure 4.2: Profile through the transition zone between the Pompeckj Block in the north and the Lower Saxony Basin in the South. The three time steps shown are the Middle Jurassic, Late Cretaceous and present day (from Littke et al., 2008). on page 82 Figure 4.3a: Maturity calibration for wells within the Pompeckj Block, Gifhorn Trough and the Lower Saxony Basin, displaying the comparison of measured and calculated vitrinite reflectance within the study area. The exact well location can be found in Fig. 4.1 and the XV burial history in Fig. 4.3b1-2. Vitrinite reflectance calculation according to Sweeney and Burnham (1990). on page 86 Figure 4.3b-1: Burial history plots of two well locations (calibration wells) marked in Fig. 4.3a. on page 87

Figure 2.3b-2: Burial history plots of two well locations (calibration wells) marked in Fig.4.3a. on page 86

Figure 4.4: Maximum erosional thicknesses of the Upper Jurassic erosion event within the study area. on page 90 Figure 4.5: Maximum erosional thicknesses of the Upper Cretaceous erosion event within the study area. on page 91 Figure 4.6: Thermal maturity of Posidonia Shale within the study area, based on the Easy Ro approach of Sweeney and Burnham (1990). on page 95 Figure 4.7: Transformation ratios [%] of the kerogen for the uppermost and lowermost Posidonia Shale unit. Posidonia Shale unit III (top) and Posidonia Shale unit I (bottom). on page 98 Figure 4.8: Hydrocarbon generation for two compound classes of liquid hydrocarbons. Generation of C15+ hydrocarbons (top) and generation of C6-C14 hydrocarbons (bottom) combining all three units of the Posidonia Shale. The figure shows the total amount of hydrocarbon generated over time assuming a completely open system. on page 99 Figure 4.9: Hydrocarbon gas generation maps. Generation of C2-C5 hydrocarbons (top) and generation of methane (bottom) combining all three units of the Posidonia Shale. on page 100 Figure 4.10: Hydrocarbon zones of the upper and lower Posidonia Shale units showing the potential for oil, oil/gas (mixed) and dry gas production. on page 103 Figure 4.11: Adsorption capacity of the Posidonia Shale unit III within the study area in Mton/grid cell. Note the low adsorption capacity along the uplifted/inverted southern margin of the study area. on page 104

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List of Tables Table 2.1: Geochemical analysis results for the source rock samples from the boreholes Wenzen, Dohnsen, Harderode and Pötzen from the Hils Syncline. Both Wealden samples from well EX-C were taken from Rippen et al. (2014). on page 26

Table 2.2: Results from geochemical analysis for the oil samples from the LSB and Gifhorn Trough. on page 29

Table 2.3: TLC-FID (Iatroscan) results for the oil samples from the Lower Saxony Basin and the Gifhorn Trough. on page 35

Table 3.1: TOC, vitrinite reflectance values and Rock-Eval pyrolysis results for all 10 bulk samples. on page 53

Table 3.2: TOC, vitrinite reflectance values and Rock-Eval pyrolysis results for all 10 kerogen concentrate samples. on page 53

Table 4.1: Maximum thicknesses and bulk geochemical properties of the Posidonia Shale horizons in the study area. Thicknesses in parentheses are maximum thicknesses in the area of the Gifhorn Trough. on page 91 Table 4.2: Stratigraphic age assignment and petrophysical properties of the lithologies used in the 3D basin model. on page 92 Table 4.3: Mean compositional hydrocarbon production balance of the Posidonia Shale within the study area. on page 97

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List of Units

% = Percent ‰ = Permill ° = Degree µ = Micro = 1*10-6 C = Celsius cal = Calorie cm = Centimeter cm-1 = Wavenumber δ = Density = g/cm3 eV = Electron Volt g = Gram K = Kelvin k = Kilo kg = Kilogram km = Kilometer km² = Square Kilometer km³ = Cubic Kilometer M = Mega = 1*106 Ma = Million Years min = Minute m, m = Meter, Milli = 1*10-³ m² = Square Meter m³ = Cubic Meter mt = Megaton = 1*106 tons n = Nano = 1*10-9 ppm = Parts per Million t = Ton = 1*10³ kg W = Watt wt.-% = Weight Percent

1. Introduction 1.1. Introduction to this Thesis During the last decade, following a drastic change in the petroleum industry with the rapid integration and success of new drilling and well completion techniques, unconventional oil and gas production has been on the rise. Advance in horizontal drilling techniques, multilateral wells and hydraulic fracturing led to the production of hydrocarbons from compact shale source rock units, tight gas trapped in highly compacted sandstones and coalbed methane. This led to a production boom in the U.S.A., where especially source rocks from well-known hydrocarbon systems were targeted. The targeted source rocks included the Eagleford, the Barnett and the Haynesville shale. Utilizing this new method of production, partially validated due to high oil and gas prices, the U.S.A. emerged as one of the world’s largest producers of natural gas, limiting their dependence on foreign natural gas imports. Similar potential in petroleum production from unconventional sources exists also in Europe, where source rock formations in Poland, Ukraine, the UK, the Netherlands and Germany show similar promising shale oil and shale gas reserves.

While the shale gas boom in the U.S.A. was enabled and aided by specific policies put in place to stimulate domestic hydrocarbon production, the situation in Europe, especially in Germany, is different. Domestic oil and gas production in Germany has been unwarranted by the public for the last decades, leading to a strong decline in production. While additional factors such as high production costs and unfavorable hydrocarbon formations play a great role in this, especially anxiety regarding natural disasters and contaminations, coordinated by the green movement in Germany led to a bad public opinion on oil and gas production. Especially hydraulic fracturing (fracking) earned a bad reputation with the public in Western Europe. This led to several statements by the Environmental Protection Agency in Germany (Umweltbundesamt; UBA), favoring a strong restriction on this technique (Umweltbundesamt, 2014), even though several federal agencies favored its application (BGR, 2016). Even though the application of unconventional hydrocarbons production is strongly limited in Germany, the low domestic oil and gas production is a ground for concern, leading to continuous studies of potential formations in Germany in case of a strong increase in hydrocarbon prices. Knowledge on these potential resources might in such case enable a domestic German production, especially in case of problems with foreign imports of oil and gas. 2

The study area chosen in this thesis represents an extension of the area analyzed by Rippen et al. (2016), who focused in depth on the western LSB and the Wealden formation and is a more detailed view into an area investigated by Bruns et al. (2013), featuring a more detailed resolution and the threefold division of the Posidonia Shale source rock. There have been more investigations within the area, featuring a combination of the here used methods of organic petrography, organic geochemistry and 3D numerical basin modelling, such as Uffmann et al. (2012), Blumenstein-Weingartz (2012) and Schwarzkopf and Leythaeuser (1988), although all this work featured on either a single structure within the here used study area, or on coherent reactions connected to the Posidonia Shale petroleum generation. This work presents a possibility for a more detailed insight into the petroleum potential of the Posidonia Shale within the area, while also investigating basic features related to the hydrocarbon liberation from the Posidonia Shale kerogen, as well as the quality of hydrocarbons that have been expelled from this source rock.

1.2. Conventional and Unconventional Petroleum Potential in Germany The unconventional petroleum potential (Bundesamt für Geowissenschaften und Rohstoffe, BGR, 2016) in Germany is considerably high (Bundesamt für Geowissenschaften und Rohstoffe, BGR, 2016), if compared to the actual annual production from mostly conventional reservoirs of petroleum in Germany. While unconventional petroleum resources are initially classified based on their economic feasibility, they also represent petroleum production possibilities beyond the traditional production from well-known high permeable reservoirs once these have depleted. Since the production in Germany faces a steady decline in recent years, partially to due to older fields nearing the end of their production cycle, new exploration targets such as unconventional resources are getting more interesting, since targeting these reservoirs limits the requirements on traditional petroleum system elements (Magoon and Dow, 1994), namely source, migrations pathways, reservoir and trap, since the hydrocarbons can be produced from the low permeable source rock itself. The hydrocarbons within the source rock are mostly present as free hydrocarbons within the pore volume of the rock, or as an adsorbed phase for high volatile hydrocarbons (gas). Strong factors influencing the possibility and capacity of hydrocarbon storage within geologic formations are porosity, pressure, water content, temperature, burial history and subsequently the sorption capacity as a factor influenced by all factors above. There are of course more factors influencing the quality and potential of petroleum within potential formations, such as the mineralogy, which 3 greatly influences a lot of factors mentioned above, the heterogeneity of the formation, meaning how strong facies variations are in lateral directions and the actual chemical composition and the type of the kerogen responsible for hydrocarbon generation. All these factors combined can pre-determine the suitability of certain formations for unconventional hydrocarbon production (Jarvie, 2012).

Potential formations for unconventional petroleum production in Germany include Carboniferous coals, the Lower Carboniferous Lower- and Upper Alum Shales, the Lower Jurassic Posidonia Shale and the Lower Cretaceous shales of the Wealden formation. Depending on their location and maturity, these formations present potential exploration targets, especially in areas where the presence of hydrocarbons in conventional reservoirs is already known, namely the Northwest German basin, here split into the Lower Saxony Basin, the Pompeckj Block and the Gifhorn Trough, the Upper-Rhine Graben structure, the molasse basin in southern Germany and the Thuringian basin. All structures show unconventional petroleum potential, with certain structures being more proficient for unconventional oil (Fig. 1.1a), others for unconventional gas production (Fig. 1.1b).

1.3. Petroleum Systems of the Lower Saxony Basin, Gifhorn Trough and Pompeckj Block The petroleum systems in the Central European Basin System comprise primarily of Upper Carboniferous coals as a source rock for deeper Permian and Triassic reservoir rocks, in the case of gas plays, and a system of Jurassic (Posidonia Shale) and subordinated Berriasian (Wealden) (primarily in the west) source rocks and Mesozoic/Tertiary reservoir rocks in the case of oil plays (Boigk, 1981; Bayer et al., 2008; di Primio et al., 2008). The main reservoir successions as well as source rock contribution show a strong trend within the CEBS. With the contribution of the Wealden decreasing towards the east of the LSB (Binot et al., 1993; Wehner, 1997) the Posidonia Shale can be assumed as the main source rock for the Hamburg- Gifhorn area. There, reservoir successions comprise of Jurassic Dogger α and β as well as Lower Kimmeridgian sandstones, Tithonian carbonates and marls, Valangian sandstones, Ypresian α/β-sands and Rupelian Neuengammer sands. Similar to other petroleum systems in the CEBS, the formation of traps is closely linked to the Zechstein evaporites forming salt domes and walls, while anticline structures, unconformity related structures and fault-bound trap types are subordinate (Kockel et al., 1994).

Figure 1.1a - Oil fields and prospective exploration areas for conventional and unconventional oil in Germany, modified after LBEG (2016).

Figure 1.1b – Gas fields and prospective exploration areas for conventional and unconventional gas production, after LBEG (2016)

1.3.1. Paleozoic The Paleozoic source rock units are primarily Pennsylvanian sedimentary rocks with cyclothematically bedded claystones, siltstones and sandstones, with intercalated coal seams, which are the major source rock for the main gas generation in the CEBS (Littke et al., 1995; Gaupp et al., 2008; Bruns, 2014). These formations have been deposited in a deltaic fluvial environment in a tropical climate. Within the siltstones and sandstones interbedding the coal seams, dispersed coaly material can be found. These successions have been deposited in a deltaic coastal environment and can be classified as a typical type III kerogen. Typical reservoir rocks for the gas sourced from this system are the volcanic and siliciclastic sediments of the Rotliegend Formation and the Zechstein- and Staßfurt-Carbonates which have been deposited during the Permian. This petroleum system is prevalent for roughly 50 % of Germany’s gas reservoirs (LBEG, 2016). Additional source rock potential, though only in minor occurrence is present in the Kupferschiefer and Stinkkalk within the Zechstein, with the Zechstein salt generally acting as a seal for the Paleozoic gas plays. Unconventional systems within the Paleozoic are mainly coalbed methane, from the coal seams within the Pennsylvanian, tight gas from sandstones deposited under aeolian conditions and Pennsylvanian and Mississippian shales with considerable organic matter (Littke et al., 2011)

1.3.2. Mesozoic The Mesozoic source rocks units comprise of the Toarcian Posidonia Shale and the Berriasian Wealden shales/marlstones. The Toarcian Posidonia Shale, part of the Liassic- Dogger group, contains an oil-prone type-II kerogen with an initially high TOC of 2-15 wt.- % and was deposited in an oxygen depleted environment. Rapid sedimentation during the Jurassic, following a global sea-level rise during the Rhaetian, was partly related to salt- diapirism and favored the deposition of the organic matter rich Liassic as well as Dogger sediments (Schwarzkopf, 1988; Brink et al., 1992; Betz et al., 1987). This Liassic Dogger group consists of marlstones, carbonates, sandstones and shales, offering the possibility to act as reservoirs, in case of the sandstones, and carbonates as well as seals, in case of the marls and claystones, for the underlying Posidonia Shale source rock (Kockel et al., 1994). The Posidonia Shale itself exhibits a threefold stratigraphy, with a lower marlstone unit (Unit I), a middle calcareous-rich shale unit, featuring bivalve shells (Unit II) and an upper calcareous shale unit (Unit III) with the total thickness of all units varying between 15-32 m in the area of the Lower Saxony Basin and the Pompeckj Block and up to 80 m in total thickness in the area of the Gifhorn Trough. The most prominent reservoir rocks of the Posidonia Shale play 7 are Triassic rocks charged by downward expulsion alongside present faults and Lower Cretaceous as well as Dogger sandstones. The Wealden source rocks, not characterized in depth in this thesis, featured depositional conditions in a brackish-lacustrine to marine setting. This setting lead to Wealden thicknesses that reach locally up to 1000 m, but are subject to strong layering, with prominent type I organic rich shale horizons often intersected by prograding limestone, mudstone and organic-lean shale horizons. The Wealden, especially the lacustrine shale horizons are locally confined by sandstones, siltstones and claystones towards the east and limestone sequences in the west (Rippen et al., 2013). Due to its strong variation in homogeneity, and its type I character, requiring higher temperatures and pressures to enable hydrocarbon liberation, as well as its presence in largely shallow depth within the study area, the Wealden has not been subject to a more detailed analysis here.

1.4. Methods Several methods from different geological fields have been used as analytical techniques within the scope of this thesis. Combining organic petrography, organic geochemistry and 3D basin systems modelling, allowed for a deeper insight into the Posidonia Shale composition and its reaction upon thermal maturation due to increasing temperatures and pressures. While organic petrography delivers information about the present state of organic matter, its maturity and consequently its preservation or degradation, organic geochemistry can gather information about the correlation of said organic matter to hydrocarbons such as oil and gas and it can help in predicting the production or expulsion potential as well as the quality of hydrocarbons from kerogen cracking under increasing thermal maturity. All this information is vital in calibrating a 3D numerical basin model which then in turn, can be used to predict not only the quality or quantity of hydrocarbons, but also the location, allowing for the identification of so called “sweet spots” for conventional and unconventional hydrocarbons.

1.4.1. Organic Petrography Organic petrography, here mainly the analysis of the maceral composition within source rock samples and the determination of vitrinite reflectance for maturity determination, play a vital role in the first assessment of potential formations. The maceral composition of a source rock can pre-determine its suitability for the production of certain hydrocarbons, with liptinite-rich organic matter usually indicating a predisposition for oily long chained compounds and vitrinite/inertinite-rich organic matter favoring short chain compounds. The presence of certain macerals, typically of algal origin, can help in the identification of the depositional 8 environment and can lead to the determination of the kerogen type, which also allows for a first determination of kerogen reaction under thermal maturation (Taylor et al. 1998). While type I kerogen, typically deposited in a lacustrine to brackish environment, produces mainly waxy oils and therefore needs a higher maturity to enable kerogen cracking and the production of hydrocarbons, type II kerogen, deposited in a marine environment, often under reducing conditions, favors the production of medium length hydrocarbon compounds. Kerogen type III, typically deposited under terrestrial to fluvial conditions on the other hand favors the production of short chain hydrocarbons, and at a certain maturity primarily gas compounds.

Vitrinite reflectance is one of the most accurate methods of measuring maturity within source rocks. Utilizing the property of vitrinite to increase its reflectance upon increasing temperature with increasing burial, it can be used to determine the maximum temperature a rock has been influenced by, as the reflectance is prograding and preserves only the highest temperature/pressure conditions the rock has been influenced by (Taylor et al. 1998). Its easy application and short preparation time make it the superior optimal method of maturity measurement, as compared to methods like conodont alteration index (CAI), apatite fission tracks, spore color index or fluid inclusions, which require intensive training or preparation.

1.4.2. Organic Geochemistry Organic geochemical methods applied here allow for a wide range of utilization in the geosciences. The determination of bulk geochemical parameters such as total organic carbon content (TOC), sulfur content and carbonate content, which are primary indicators for the suitability and quality of an organic matter containing rock as a source rock. Rock-Eval Pyrolysis can utilize these bulk parameters and further quantify the potential of expelled hydrocarbons as well as the potential amount of already expelled hydrocarbons. By combining these two methods, one already has substantial information for a first quality assessment of certain formations, especially their suitability as an oil- or gas-prone source rocks, their inherent maturity and first implications towards the quality of hydrocarbons liberated from the source rock.

More detailed geochemical analysis, utilizes the analysis of source rock samples either on with chemical solvents extracted source rock material, or on kerogen concentrate, with the application of gas chromatographic measurements. Depending on the wanted information the material can be analyzed using a gas chromatograph equipped with a flame-ionization 9 detector (GC-FID), which is especially suited for the determination of hydrocarbon composition from oil of gas expelled by a source rock, or to analyze the composition of oil from an already developed field or from an oil show. This method in addition, allows for the determination of source rock kinetics, if the samples are specifically prepared beforehand. More detailed analysis regarding the source rock or oil composition for special compounds which can be used to determine the depositional environment, the maturity of a source rock or even to allow for a source rock oil correlation is possible in utilizing gas chromatographic measurement, with the option of adding a superposed pyrolysis apparatus, in combination with a mass spectrometer (GC-MS). Using this type of analysis, geochemical maturity parameters, such as the in this work used Methylphenantren index (MPI), sterane and hopane indices for source rock/oil correlations and for determination of depositional environment and facies correlation. Further analysis mostly conducted on crude oil within the scope of this thesis included, namely measurements of density (API°) and the allocation of compounds within the oil based on thin-layer chromatography coupled with a flame-ionization detector (TLC-FID; Iatroscan), allowed for a more detailed qualification of the oil produced from the Posidonia Shale source rock based on maturity and location within the study area.

1.4.3. 3D numerical basin Modelling

3D numerical basin modelling provides an integrative approach in the understanding, reconstruction and derived prediction of geological processes during the evolution of a sedimentary basin throughout its geological history. Utilizing petrographical and geochemical data, a model can be calibrated using mathematically conceived tools recreating the chemical and physical processes that lead to the development of a sedimentary basin (Welte and Yalcin, 1987; Poelchau and Zwach, 1994; Neunzert et al., 1996). These processes are the foundation for the forward modelling approach of the here used software Petromod ®, which models geological processes within a sedimentary basin along geological time periods. While especially depositional and tectonic aspects play a strong role in the physical and geological aspects of a sedimentary basin model, they need to be as exact as possible, so as not to diminish the quality of the geochemical and petrographical data used to calculate and predict hydrocarbon accumulation, quality and location within the numerical basin model. Especially the thermal maturity, as a property dependent on several factors, e.g. rate of burial, pore pressure, temperature and heat flow, plays a crucial role. 10

To account for the variation of the elements making up the model, the model is split into discrete events and time steps, as well as in pre-defined grid cells, so as not to make the calculation of the model impossible. This makes an optimization process using multiple forward simulations and combining them possible, until the desired present-day basin geometry matches the known structure of today’s sedimentary basin.

1.5. Objectives of this Thesis The objective of this study is an application of geochemical and petrographical analysis to petroleum systems modelling within a well-known study area, which incorporates the eastern part of the Lower Saxony Basin, the Gifhorn Trough to the east and the Pompeckj Block to the north. As the Lower Saxony Basin and the Gifhorn Trough are areas with a long lasting tradition of hydrocarbon exploration and production, there have been many investigations made for the geodynamic evolution of this area, as well as several studies related to the petroleum potential within sub-parts of the study area. Utilizing analyses made on source rock of analogue Posidonia Shale source rock samples from the Hils Syncline, the properties and cracking tendencies of the Posidonia Shale have been investigated, giving insight into the kerogen structure and hydrocarbon liberation of the Posidonia formation. This allows for a first determination of possible hydrocarbon quality and quantity due to thermal maturation of the Posidonia Shale within the study area. This in turn can be utilized to further correlate and calibrate the created 3D numerical basin model. To more accurately describe and verify the quality of hydrocarbons sourced by the Posidonia Shale, 29 oil samples from oil fields within the study area were subject of analysis within the scope of this work, to ultimately analyze the quality of oil sourced by the Posidonia Shale within the Central European Basin System (CEBS). Especially the determination of the likely maturity of the source rocks during the expulsion of the hydrocarbons was an important factors, as this has shown that oil generation from the Posidonia Shale is favored even at higher maturities than the peak oil maturity (0.7- 0.9 % VRr). The analysis of the compound classes of the oils sourced from the Posidonia Shale allows for a good quality assessment, making sure that aliphatic and aromatic compounds are in abundance as compared to polar and hetero compounds.

Ultimately combining the analytical parts of this thesis, allowed for a good data set on which the 3D numerical basin model could be created, which in itself follows the groundwork set by Bruns (2015) and Mohnhoff (2016) and expands upon their achievements within parts of the study area, gaining new information about the Posidonia Shale source rock and its associated conventional an unconventional potential within the study area, namely: 11

I. Showing the inherent qualities of the Posidonia Shale sourced oils, even in places where the initial maturity of the source rock is not optimal, or where the reservoir has been partially affected by degradation processes. II. Showing the properties of hydrocarbons directly created from kerogen cracking at different maturities to attempt a better prediction of hydrocarbon composition at varying maturities of the source rock. III. Creating a 3D numerical basin model which incorporated all the data collected within the scope of the thesis in an attempt to get more detailed information regarding the prime conventional and unconventional “sweet spots” for hydrocarbon production and exploration within the study area.

1.6. Thesis Structure The chapters comprising this thesis where published as manuscripts as follows:

Chapter 2

This chapter focusses on the geochemical composition of oils sourced by the Posidonia Shale source rock and compares these to data obtained from the analysis of analogue source rock samples of the Posidonia Shale from the Hils Syncline.

Chapter 3

Stock, A., Littke, R., Schwarzbauer, J., Horsfield, B., Hartkopf-Fröder, C., 2017. Organic geochemistry and petrology of Posidonia Shale (Lower Toarcian, Western Europe) – The evolution from immature oil-prone to overmature dry gas-prone kerogen. International Journal of Coal Geology 176.

This chapter deals with the kerogen structure of the Posidonia Shale, utilizing pyrolysis GC- MS measurements to accurately describe changes in the hydrocarbon liberation behavior with increasing maturation of the source rock. Ranging from immature (0.5 % VRr) to gas-mature (3.0 % VRr), the samples provided a wide spread in maturities, which can be typically found 12 throughout a large study area such as the one that is subjected to analysis within the scope of the thesis.

Chapter 4

Stock, A.T., Littke, R., 2017. The Posidonia Shale of Northern Germany – Unconventional oil and gas potential from high resolution 3D numerical basin modelling of the cross-junction between the Eastern Lower Saxony Basin, Pompeckj Block and Gifhorn Trough. In Review.

Chapter 4 represents a manuscript currently in review for a special issue titled “Mesozoic Resource Potential within the Southern Permian Basin” of The Geological Society of London that comprises the results obtained from 3D numerical basin modelling for the study area. Incorporating map information from the Geotektonik Atlas of Northwestern Germany and geochemical and petrographical data obtained from the publications of Chapter 2, 3, this paper presents new quantitative results on the conventional and unconventional hydrocarbon potential within the Northwestern German Basin, adding valuable information for potential exploration within the area in the near future.

Further publications as a second author include:

El Atfy, H., Brocke, R., Uhl, D., Ghassal, B., Stock, A.T., Littke, R., 2014. Source rock potential and paleoenvironment of the Miocene Rudeis and Kareem formations, Gulf of Suez, Egypt: An integrated palynofacies and organic geochemical approach. International Journal of Coal Geology 131, 326-343.

Baboolal, A., Littke, R., Wilson, B., Stock, A.T., Knight, J., 2016. Petrographical and geochemical characterization of lignites, sub-bituminous coals and carbonaceous sediments from the Erin Formation, Southern Basin, Trinidad – Implications from microfacies, depositional environment and organic matter alteration. International Journal of Coal Geology 163, 112-122.

2 Geochemical composition of oils from the Gifhorn Trough and Lower Saxony Basin in comparison to Posidonia Shale source rocks from the Hils Syncline, northern Germany

2.1 Abstract Twenty-four oils from reservoirs in the Lower Saxony Basin and the adjacent Gifhorn Trough were analyzed for their molecular geochemical composition, sulfur content and density (API values). The results were used to determine oil quality, degree of degradation and to correlate the oils with different source rocks known from the area. Early Toarcian Posidonia Shale was sampled at different levels of maturity for this purpose and literature data on Wealden shales were used for comparison.

Oils are characterized by low to moderate sulfur contents and variable densities, including some heavy oils. Heavy oils and oils characterized by a significant hump indicating biodegradation are usually found in shallow reservoirs (depth <1500 m). All oils are characterized by a clear predominance of n-alkanes of medium-chain length over those of long chain length, which is typical of mature oils. Other parameters such as the distribution of aromatic hydrocarbons or the varying but mostly low concentration of steranes and hopanes also indicate that oils represent the peak oil generation stage. Based on ratios of iso-alkanes over n-alkanes and geological evidence, it is likely that the Posidonia Shale is the principal source rock for the oils.

2.2 Introduction Both the Lower Saxony Basin (LSB) and especially the Gifhorn Trough (Fig. 2.1, 2.2a) are known as two of the oldest oil producing provinces in Germany. The Gifhorn Trough can be regarded as the easternmost part of the LSB, but has a slightly different geological history. The first successful oil-bearing well was drilled in 1859 in Wietze, located in the eastern part of the LSB, with the first commercial production wells drilled in 1899. In the early 20th century, all oil produced in northern Germany originated from the LSB and Gifhorn Trough. Even today, roughly 50 % of the German oil is produced from oil fields located in the LSB and the Gifhorn Trough. For both areas, the Lower Jurassic (Posidonia Shale) source rock of the Early Toarcian (Lias epsilon) is regarded as the main source rock (Schwarzkopf and Leythaeuser, 1988; Kockel et al., 1994; Wehner, 1997; Bruns et al., 2013). In addition, Upper 16

Carboniferous coals are important source rocks for gas and Lower Cretaceous (Wealden) shales act as source rocks for oil and gas in the Western LSB. The Posidonia Shale, as the major oil source rock in large parts of the Central European Basin System, has been the center of attention for basic scientific research in the past. This is the case especially in the area of the Hils Syncline (Fig. 2.2b), where it was drilled and sampled in close proximity to the surface at various maturities, ranging from immature to post-mature. (Littke et al., 1988, 1991; Mann and Müller, 1988; Leythaeuser et al., 1987, Rullkötter and Marzi, 1988; Schenk and Horsfield, 1998)

Figure 2.1: Palaeogeographic map of the southern margin of the Central European Basin during the Coniacian to Maastrichtian with locations of inverted areas and post-inversion deposits (after Voigt et al., 2008). In contrast little information is available on the oils, especially from the here analyzed formations. Binot et al. (1993), Kockel et al. (1994) and Wehner (1997) provided information on the genesis and migration of oils related to the LSB and sourced by the Posidonia Shale. Based on crude oils from the Gifhorn Trough, Welte (1967) described how maturity of the source rock related to the regional geologic history can influence the geochemistry of the generated oils. Schwarzkopf (1988) investigated origin and migration of oils especially from the central part of the Gifhorn Trough, where the Posidonia Shale is in the early mature to mature range. Blumenstein-Weingartz (2011) subsequently analyzed biodegradation on oils 17 from the Gifhorn Trough and related this data to the applicability of modelling and predicting the degree of degradation of oils using 3D system modelling tools.

The focus of this paper is on the origin of oils in the LSB and Gifhorn Trough based on the analysis of 24 samples. Results are compared to those from solvent extracts of Posidonia Shale of different maturity levels. Furthermore kitchen areas for oil generation are discussed, using basin modelling results and maturity information.

2.3 Geological Background The inverted LSB is located in North-West Germany. It is part of the Central European Basin System (CEBS; Littke et al., 2008) and bordered by the Pompeckj Block to the north and north-east, the inverted Central Netherlands Basin to the west, the Cretaceous Münsterland Basin to the south and the Harz Mountains and Subhercynian Basin to the east (Fig. 2.1). Extension and subsidence in the Late Permian initiated the evolution of the LSB and continued until the formation of various sub-basins during the Late Jurassic to Early Cretaceous basin differentiation (Voigt et al., 2008). Especially during the Late Jurassic, basin evolution was dominated by crustal extension across the North-Atlantic rift system (Stollhofen et al., 2008), leading to only small changes in structural frame, but influencing sea-levels and overall tectonic activity (Ziegler, 1990). During the latest Jurassic and the Early Cretaceous, variable but partly very high sedimentation rates existed due to various sub-basin developments (Littke et al., 2011). During this phase of subsidence, the adjoining structural elements of the CEBS experienced intense uplifting (Bruns et al., 2013) while being controlled by transtension along NW-SE striking faults, leading to dissymmetric sedimentation along the basin axis in the LSB. This in turn favored higher sedimentation rates within the center of the basin (Senglaub et al., 2005). During this period a maximum of 4000 m of sediment were deposited, which, with the onset of the Alpine orogeny and the inversion of the LSB, were subsequently subjected to erosion (Sirocko et al., 2008; Adriasola-Munoz et al., 2007)

The Gifhorn Trough, adjoining the eastern part of the LSB, is a 100 km long and roughly 50- 70 km wide Rhenish-striking depression in the eastern part of the LSB, located about 50 km north-east of Hannover (Fig. 2.1). Rapid sedimentation during the Jurassic was partly related to salt diapirism and led to above-average thickness of marine, organic matter rich Liassic as well as Dogger sediments (Schwarzkopf, 1988; Brink et al., 1992; Betz et al., 1987). Highest thicknesses for these sediments can be found in the axial parts of the Gifhorn Trough. The sedimentary succession of the deposited thick black shales is rarely interbedded with smaller layers of deltaic and marine sandstones (Lias α, Dogger β, Dogger ε). During the Triassic salt tectonics began to influence the area of the Trough and still continues until today. The thick evaporites which were deposited during the Permian Zechstein initiated the evolution of salt- pillows and salt-diapirs (Fig. 2.2a). The continuous development of salt tectonics is of utmost importance for the hydrocarbon-systems in the Gifhorn Trough due to the trap-potential of salt structures as well as the higher heatflow-values associated with salt tectonics, influencing 19 the temperature history of source- and reservoir-rocks (Trusheim, 1960; Neunzert et al., 1996; Schwarzer and Littke, 2007).

Figure 2.2b: Geological map of the Hils-Syncline showing the location of boreholes Wenzen (1), Dohnsen (2), Harderode (3) and Pötzen (4); Quaternary and Tertiary removed, modified after Bartenstein et al. (1971). The petroleum systems in the eastern part of the LSB (Fig. 2.3) comprise primarily of Upper Carboniferous coals as a source rock for deeper Permian and Triassic reservoir rocks, in the case of gas plays, and a system of Jurassic (Posidonia Shale) and subordinated Berrisian (Wealden) source rocks and Mesozoic/Tertiary reservoir rocks in the case of oil plays (Boigk, 1981; Bayer et al., 2008; di Primio et al., 2008). The main reservoir successions as well as source rock contribution show a strong trend within the CEBS. With the contribution of the Wealden decreasing towards the east of the LSB (Binot et al., 1993; Wehner, 1997) the Posidonia Shale can be assumed as the main source rock for the Hamburg-Gifhorn area. 20

There, reservoir successions comprise of Jurassic Dogger α and β as well as Lower Kimmeridgian sandstones, Tithonian carbonates and marls, Valangian sandstones, Ypresian

Figure 2.3: Stratigraphy of the North-West Lower Saxony Basin from the Permian until recent times (after Maystrenko et al. (2008)) and petroleum system events linked to the sedimentary successions in the LSB (after di Primio et al. (2008)). Rock signatures were used according to Shell Standard Legend (1995). % BOE = barrel of oil equivalent. α/β-sands and Rupelian Neuengammer sands. Similar to other petroleum systems in the CEBS, the formation of traps is closely linked to the Zechstein evaporites forming salt domes and walls, while anticline structures, unconformity related structures and fault-bound trap types are subordinate (Kockel et al., 1994).

2.4 Samples and methods The sample database used for this publication comprises 16 core samples, taken from four shallow boreholes in the Hils Syncline, namely Wenzen, Harderode and Pötzen, drilled by the BGR Hannover, and Dohnsen drilled by the FZ Jülich. All 16 core samples represent Early 21

Toarcian Posidonia Shale at different maturity stages. In addition, information from two comparative Wealden samples from well EX-C located within the LSB was taken from Rippen et al. (2013).

In addition to the core samples, as analogue examples for the petroleum source rocks in the Gifhorn Trough, 24 oil samples from oil fields of the LSB, the Pompeckj Block as well as the Gifhorn Trough were analyzed using a gas chromatograph equipped with a flame-ionization detector (GC-FID), a gas chromatograph with a mass spectrometer (GC-MS) and thin-layer chromatography with a flame-ionization detector (TLC-FID; Iatroscan) as analytical techniques. All oil samples are from the inventory of the Erdölmuseum Wietze and might represent dead oil, being stored under low pressure leading to a loss in volatile components which might influence API values.

2.4.1 Elemental analysis Measurements of the organic as well as inorganic carbon of source rocks were conducted using a liquiTOC solid module. In preparation of the measurements, the material was ground and homogenized. For every measurement the samples were weighed in steel crucibles and inserted into the liquiTOC. Afterwards the sample was heated in the presence of oxygen until combustion, measuring the produced CO2 at an IR-detector.

Analysis of the sulfur content was conducted using a total evaporation analyzer of the model LECO S 200, and a calibration ring of known sulfur content (0.323 wt.-%) together with a Lecocell fluxing agent. For every measurement, after calibration, 100 mg of sample was weighed in and spiked with fluxing agent and iron shavings. Subsequently the sample was introduced into an induction oven, were it was heated up to 1800 °C. The developing gas was then introduced into an infrared-cell, where SO2 was detected through infrared-light adsorption.

2.4.2 Vitrinite reflectance measurements Vitrinite reflectance measurements were performed based on Sachse et al. (2012) on polished sections using a Zeiss Axio Imager microscope, equipped with a tungsten-halogen lamp (12 V, 100 W) in incident light using a 50X/0.85 Epiplan-NEOFLUAR oil immersion objective with a 546 nm filter, at a magnification of 500x in a darkened room. 22

Vitrinite reflectance was measured against an Yttrium-Aluminum-Garnet (YAG) standard with a known reflectance of 0.898 %, using Zeiss immersion oil with a refractive index of ne = 1.518 at 23° C. The reflectance measurements were conducted at random orientation.

2.4.3 Density measurements Oil density was measured using pycnometers with capillary-plugs, according to DIN EN ISO 3838. Before every measurement the pycnometers were cleaned using acetone and were subsequently dried in an oven under vacuum. After the preparatory cleaning, the pycnometers were cooled down to room temperature, static electricity was discharged and they were weighed in with a weighing accuracy of 0.1 mg. Calibration was conducted using freshly prepared distilled water at 20 ± 0.05 °C. After an hour in a temperature-constant water bath at 20 ± 0.05 °C and subsequent drying and discharging static electricity again, the pycnometers were weighed in keeping the same temperature. The same procedure was then applied using the oil sample, so that the relative density of the oils compared to water at the same volume could be determined. Calculation of API values was done using the following formula, using the calculated relative density of the oils (ρrel):

141.5 퐴푃퐼 푔푟푎푣𝑖푡푦 = − 131.5 휌푟푒푙

2.4.4 Geochemical analyses & bulk sample extraction For the extraction of the bulk source rock samples, 5 g of bulk rock powder were extracted using ultrasonic treatment and overnight stirring with 40 ml dichloromethane and 40 ml hexane. The extracts were fractionated by means of bakerbond-column using the following solvents: i) the aliphatic hydrocarbons were eluted by 5 ml of n-pentane, ii) the aromatic hydrocarbons with 5 ml of n-pentane:dichloromethane in a 2 to 3 ratio. Geochemical analysis on the oils samples was conducted according to Sachse et al. (2012), fractioning the samples into 5 groups based on their chemical composition, using 5 mL of the following solvents with a bakerbond-column: i) aliphatics (solvent: n-pentane); ii) monoaromatics (solvents: n- pentane:dichloromethane (95:5)); iii) diaromatics (solvents: n-pentane:dichloromethane (90:10)); iv) hetero compounds (solvents: n-pentane:dichloromethane (40:60)); v) polar compounds (solvent: methanol). The aliphatic fractions, for both the oils and the rock extracts, were analyzed using a Fison Instruments GC 800 Series ECD 850 gas 23 chromatograph with an on-column injector, a Zebron ZN-1 Hat Inferno silica capillary column (30 m x 0.25 mm) and a flame-ionization-detector (FID). The applied temperature program started at 80 °C (hold for 3 min.) and temperature was raised at 5 °C/min up to 300 °C (hold for 20 min.).

The following geochemical formulas (Bray and Evans, 1961; Tissot et al., 1971) were used for calculation based on the results of the GC-FID measurements:

2 ∗ (C + C + C + 퐶 ) 퐶푎푟푏표푛 푃푟푒푓푒푟푒푛푐푒 퐼푛푑푒푥 (퐶푃퐼) = 23 25 27 29 퐶22 + 2 ∗ (퐶24 + 퐶26 + 퐶28) + 퐶30

퐶 + 퐶 + 퐶 퐿𝑖푔ℎ푡 − ℎ푦푑푟표푐푎푟푏표푛 퐶푃퐼 (퐿퐻퐶푃퐼) = 17 18 19 퐶27 + 퐶28 + 퐶29

푃푟𝑖 푃푟𝑖푠푡푎푛푒 (𝑖퐶 ) = 17 푃ℎ푦 푃ℎ푦푡푎푛푒 (𝑖퐶18)

The aromatic as well as the aliphatic hydrocarbon fraction, were subjected to analysis with a Finnigan MAT 95SQ mass spectrometer coupled with a Hewlett Packard Series II 5890 gaschromatograph. The spectrometer was used in the electron-ionization mode with ionization energy of 70 eV and a starting temperature of 260 °C. The GC was equipped with a Zebron ZB-1 silica capillary column (30 m x 0.25 mm). Helium was used as the carrier gas and the same temperature program as for the GC-FID was used.

The following geochemical formulas were applied for calculation based on the results of the GC-MS measurements:

1,5∗((2−푀푃퐼)+(3−푀푃퐼)) 푀푃퐼 − 1 = (Radke and Welte, 1983) (푃)+(1−푀푃퐼)+(9−푀푃퐼)

(4−푀퐷퐵푇) 푀퐷푅 = (Radke, 1988) (1−푀퐷퐵푇)

For the calculation of corresponding vitrinite reflectance values for the maturity assessment, the Methyl-phenanthrene Index (MPI-1) with the formula after Radke and Welte (1983) and the Methyl-dibenzothiophene ratio (MDR) with the formula after Radke (1988) was used:

푅표 = 0.6 ∗ (푀푃퐼 − 1) + 0.4

푅표 = 0.073 ∗ 푀퐷푅 + 0.51 24

2.4.5 TLC-FID (Iatroscan) The Iatroscan or TLC- FID analysis was done under a constant helium-flow of 140-150 ml/min and a pressure of 2 bar. Each chromarod was spiked with a drop of the sample material and then immersed at the bottom in different solvents as a pre-treatment before measuring. The chromarods were first treated with hexane (33 min.), then toluene (16 min.) and lastly with DCM:MeOH in a 93:7 ratio (4 min.). Afterwards, each chromarod was measured for 30 s and analyzed using Atlas software.

2.4.6 Rock-Eval Pyrolysis Rock-Eval pyrolysis measurements were performed in a nitrogen current using a DELSI INC Rock-Eval 6 instrument. The fundamentals of Rock-Eval pyrolysis are described in Espitalié et al. (1985). The temperature program started at 300 °C; this temperature was held for 3 min, followed by a heating phase with a rate of 25 °C/min up to 650 °C. An IFP-standard was used to calibrate the measurements and to ensure reproducibility. Parameters derived from Rock- Eval pyrolysis include the S1, S2 and S3 peak. From the S2 peak areas, normalized to TOC of the peaks, the Hydrogen Index (HI) values were calculated.

2.5 Results

2.5.1 Shallow boreholes from the Hils-syncline The analyzed samples (Tab. 2.1; Fig. 2.2b) show due to their varying maturity strongly deviating properties. This is especially the case for the vitrinite reflectance values, ranging from 0.51 % in the immature Wenzen samples to up to 1.56 % for the overmature Pötzen samples. The oil mature samples Dohnsen and Harderode show intermediate thermal maturities of 0.72 % and 0.88 %, respectively. Similar maturity dependent trends can be observed in the TOC contents of the samples, decreasing steadily with increasing thermal maturity. TOC concentrations start at a maximum of 11.3 % for the immature Wenzen samples down to a minimum of 3.4 % for the overmature Pötzen samples. This decrease is mainly due to kerogen conversion to oil and gas (Rullkötter and Marzi, 1988; Mohnhoff et al., 2016), but also due to facies variability. Pristane/phytane ratios can provide important information on depositional conditions, but are also influenced by thermal maturity (ten 25

Haven et al., 1987). Ratios increase towards the higher mature samples from ~0.93 for the Wenzen samples towards ~1.5 for the Pötzen samples. A retrograde trend can be observed for the Pri/nC17 and Phy/nC18 ratios, which decrease with increasing maturity: from ~6.01 towards ~0.16 and from ~3.42 to ~0.11, respectively. The MPI-1 and MDR were measured on the mature samples of the shallow boreholes Dohnsen and Harderode for comparison with the oil samples. Values are higher for samples from the more mature Harderode well. Mean values of ~0.80 for the MPI-1 and ~4.54 for the MDR at Harderode compare to mean values of ~0.46 and ~1.87 at Dohnsen. However, there is a slight offset recognizable between the calculated vitrinite reflectance values from the MPI-1 and MDR, i.e. lower thermal maturities for the MDR as compared to the MPI-1.

2.5.2 Oil samples from the LSB and the Gifhorn Trough

2.5.2.1 Density and sulfur contents The oil samples from the LSB and the Gifhorn Trough show large variability in their density and to a certain degree also in their sulfur contents. A few oils were degraded to an almost solid phase. For those no density measurements could be applied without altering the state and ultimately the chemical composition of the samples. The calculated API values range between 31.76 ° and 15.04 ° (Tab. 2.2), varying between a light-crude (> 31.1 ° API) and heavy-crude oil (<22.3 ° API).

Similar to the density values, the sulfur contents of the oils show a wide range between 0.31 wt.-% for sample GR. Lessen 14 and 3.17 wt.-% sulfur for sample Volkensen 6 (Tab. 2.2), with a mean sulfur content of 0.94 wt.-% of all samples. 26

Table 2.1: Geochemical analysis results for the source rock samples from the boreholes Wenzen, Dohnsen, Harderode and Pötzen from the Hils Syncline. Both Wealden samples from well EX-C were taken from Rippen et al. (2014).

Sample.-No. Depth [m] TOC [%] HI [mg HC/g TOC] VRr [%] Pri/Phy Pri/nC17 Phy/nC18 CPI MPI-1 calc. Ro MDR calc. Ro Wenzen 12_1242 33.50 8.90 630 0.51 0.93 5.01 2.60 1.26 / / / / 12_1245 36.50 7.10 607 0.51 0.94 4.76 2.36 1.10 / / / / 12_1247 38.50 11.30 685 0.52 0.91 6.01 3.42 0.86 / / / / Dohnsen 13_1268 45.50 8.0 575 0.72 0.95 0.63 0.88 0.95 0.48 0.69 1.77 0.64 13_1274 52.50 8.6 453 0.74 0.98 0.97 1.23 0.94 0.46 0.68 1.76 0.64 13_1278 56.50 8.5 466 0.72 0.97 0.86 1.19 0.96 0.47 0.68 1.86 0.65 13_1282 60.50 8.4 435 0.71 0.94 0.84 1.19 0.97 0.46 0.68 1.74 0.64 13_1286 64.50 7.9 492 0.73 0.93 0.75 1.06 0.99 0.46 0.68 1.86 0.65 13_1288 66.50 5.7 540 0.73 0.93 0.71 0.99 0.98 0.45 0.67 2.00 0.66 13_1292 72.50 8.5 520 0.72 0.86 0.53 0.76 0.98 0.45 0.67 1.80 0.64 13_1296 77.50 6.1 553 0.72 0.94 0.83 1.10 0.94 0.45 0.67 1.89 0.65 Harderode 12_1617 51.82 7.00 348 0.89 1.39 0.31 0.41 1.08 0.79 0.87 4.70 0.85 12_1621 55.90 8.10 338 0.87 1.23 0.39 0.32 1.01 0.84 0.90 4.62 0.85 12_1623 58.00 10.70 386 0.88 1.21 0.32 0.26 1.14 0.78 0.87 4.3 0.82 Pötzen 12_1496 39.50 3.40 238 1.56 1.59 0.16 0.11 0.71 / / / / 12_1500 43.50 3.60 228 1.51 1.29 0.16 0.16 0.98 / / / / Wealden EX-C 710.64 17.40 203 / 4.79 0.13 0.03 0.92 0.72 0.83 / / EX-C 921.24 4.29 24 1.93 1.30 0.06 0.05 / 1.34 1.20 / /

2.5.2.2 Saturated hydrocarbons Based on the analysis of the saturated fraction of all oil samples, the oils display differing distributions of saturated hydrocarbons (Fig. 2.4). Samples Barenburg 2, Barenburg 52, Barver 3, Barver Süd, Eilte West 14, Eystrup-Verden 2, Steimbke-Ost 10, Suderbruch 11, Suderbruch M57, Suderbruch V97, Sulingen V4, Volkensen 6, Wehrbleck 1, Wehrbleck-Ost 37, Nienhagen, Lehrte and Wietingsmoor 15 all display a marine-like oil distribution, with a high abundance of short- to medium-chain n-alkanes. The GC-MS traces m/z = 191, and m/z = 217, show hopane presence up to C35, while steranes

Sample Steimbke-Alt WA 317 is the only sample where there is a very strong hump in the chromatogram visible, with few aliphatic hydrocarbon peaks. A predominance of short-chain hydrocarbons can be recognized. Hopanes are present, while steranes >C25 are completely absent.

The chromatograms of samples Eystrup 5, Gr. Lessen 14, Steimbke-Lichtenmoor So. 39 and Steimbke Nord-Wa 211 show a hump and no long-chain n-alkanes, i.e. a strong dominance of short-chain hydrocarbons. The GC-MS traces show almost no hopanes and a low concentration of C27 and C28 steranes.

2.5.2.3 Aromatic hydrocarbons and thiophenes The analysis of the methylphenanthrenes allows for an appraisal of the maturity of the source rock through the application of the methylphenanthrene index (Radke and Welte, 1983), which can be calculated into corresponding vitrinite reflectance (% Rc) of the source material.

Almost all samples show maturities between 0.9 - 1.1 % Rc, indicating oil production from mature source rocks, well past the onset of petroleum generation. The lowest maturity was estimated for sample Eystrup-Verden 2, with a calculated vitrinite reflectance of 0.87 %, while the highest maturity was measured for sample Steimbke-Alt WA 317 with a calculated vitrinite reflectance of 1.08 %. The latter observation is surprising in view of the presence of steranes and hopanes. Another maturity parameter applied is based on the methyldibenzothiophene ratio (MDR) (Radke and Wilsch, 1994). The values indicate 28 maturities lower than those obtained by the analysis of the methylphenanthrenes (Tab. 2.1). The mean MDR yielded corresponding vitrinite reflectance values roughly lower by 0.1 %. The lowest obtained maturity was measured in sample Eystrup-Verden 2, with a calculated vitrinite reflectance of 0.8 %. The highest obtained maturity was measured in sample Wehrbleck 1, with a calculated vitrinite reflectance of 0.95 %. If compared to each other, both calculated maturities from these parameters correlate well, even if results from source rock extracts of the oil mature samples from the boreholes Dohnsen and Harderode are included in the calculation (r2 = 0.68; Fig. 2.6).

2.5.2.4 Compound groups Results obtained from the TLC-FID analysis (Tab. 2.3) conducted on the oil samples show a clear dominance of aromatic compounds for almost all of the oils. The highest aliphatic/aromatic compound ratio is achieved for the samples Suderbruch M 57 and Nienhagen, with a ratio of 0.97 and 0.99, respectively. The lowest ratios can be attributed to samples Eystrup 5, Steimbke-Alt WA 317, Nienhagen, Lehrte, Gr. Lessen 14, Steimbke- Lichtenmoor So. 39 and Steimbke-Nord WA 211. Especially polar compounds and hetero compounds occur in higher quantities in samples of the oil types II and III. Highest amounts of polar compounds occur in the sulfur-rich sample Volkensen 6 (27 %), whereas in sample Suderbruch hetero compounds reach more than 20 %.

Table 2.2: Results from geochemical analysis for the oil samples from the LSB and Gifhorn Trough.

Depth Sulfur δ API Oil LHC CP Pri/P Pri/nC Phy/nC MPI- calc. MD calc. Well Formation [m] [%] g/cm³ ° Type PI I hy 17 18 1 Ro R Ro2 Barenburg Valendis- / 1.0 / / 1 6.0 0.9 1.27 0.37 0.34 1.04 1.02 5.67 0.92 Barenburg 2 SandstoneValendis- 680 1.0 / / 1 6.2 1.0 1.15 0.29 0.24 1.06 1.04 5.85 0.94 Barenburg 52 SandstoneJura 911 1.0 / / 1 4.9 1.0 1.32 0.23 0.19 1.02 1.01 5.77 0.93 Barver 3 Jura 974 1.4 / / 1 6.1 0.9 1.2 0.31 0.25 0.97 0.98 5.35 0.90 Barver Süd 1 Jura 1302 0.5 0.87 30.0 1 3.6 1.1 1.08 0.58 0.65 0.97 0.98 5.11 0.88 Eilte-West 14 Upper Malm 2 1492.6 0.7 0.96 15.2 1 4.0 1.0 1.01 0.49 0.7 0.99 0.99 5.24 0.89 Eystrup 5 Dogger delta 1051 1.2 0.96 15.0 3 / / / / / 0.94 0.96 4.52 0.84 Eystrup-Verden 2 DoggerSandstone delta 1071 1.2 0.96 15.0 1 5.8 1.0 0.68 0.25 0.48 0.78 0.87 4.01 0.80 Gr. Lessen 14 SandstoneValendis- 957 0.3 / / 3 / / / / / 0.99 0.99 5.88 0.94 Steimbke-Alt WA SandstoneWealden 271.4 0.7 0.95 17.2 2 / / / / / 1.13 1.08 4.69 0.85 Steimbke317-Lichtenm. Doggerclay 684.8 1.1 0.96 16.0 3 / / / / / 0.88 0.93 3.75 0.78 SteimbkeSo- Nord39 WA Upper-Kimmeridge 593.04 0.9 0.95 17.7 3 / / / / / 0.98 0.99 4.59 0.85 Steimbke211-Ost 10 Dogger 1300.5 1.2 0.86 31.8 1 5.7 0.9 0.99 0.41 0.83 0.89 0.93 4.03 0.80 Suderbruch Dogger / 1.2 0.91 23.6 1 4.9 0.9 1.23 0.38 0.62 0.98 0.99 4.34 0.83 Suderbruch 11 Dogger 2036.5 1.1 0.87 29.9 1 4.9 0.9 1.03 0.47 0.68 0.97 0.98 4.23 0.82 Suderbruch M 57 Serpulit u. Münder 1595.3 0.5 0.89 26.7 1 6.0 0.9 1.24 0.63 0.49 0.82 0.89 3.32 0.75 Suderbruch V 97 ValendisMarl 1158 1.2 0.91 23.1 1 6.3 1.1 1.32 0.48 0.64 0.89 0.93 4.25 0.82 Sulingen V 4 Valendis- 955 0.4 / / 1 4.9 0.9 0.92 0.49 0.7 1.02 1.01 5.79 0.93 Volkensen 6 SandstoneJura 2112 3.2 0.93 20.6 1 6.4 1.0 0.63 0.22 0.51 1.05 1.03 4.88 0.87 Wehrbleck 1 Jura 1026.5 0.5 / / 1 5.9 1.0 1.11 0.41 0.47 1.04 1.02 6.02 0.95 Wehrbleck-Ost 37 Valendis- 821 0.5 / / 1 5.1 1.0 1.52 0.45 0.22 0.87 0.92 4.64 0.85 Wietingsmoor 15 SandstoneValendis- 910.7 0.4 / / 1 5.4 0.9 0.76 0.24 0.39 1.01 1.01 5.32 0.90 Nienhagen SandstoneValendis / 0.8 / 29.3 1 5.9 1.1 1.3 0.59 0.62 0.92 0.95 4.22 0.82 Lehrte Dogger epsilon / 0.7 / 18.2 1 4.2 1.1 1.33 0.29 0.3 0.92 0.95 4.09 0.81 30

2.6 Discussion

2.6.1 Petroleum source rocks Since petroleum generation is strongly linked to the quality of the organic matter of the potential source, a comparison of oils with extracts from Posidonia Shale of different levels of maturity can help in understanding and quantifying oil generation. In the LSB the exceptional situation exists that the possible oil source rocks are available from cored intervals in wells at various maturity levels. A scientific exploration program was devoted to the Posidonia Shale, which was recovered from shallow boreholes of which Wenzen (0.51 % VRr), Dohnsen (0.72 % VRr), Harderode (0.88 % VRr) and Pötzen (1.53 % VRr) are discussed here. As a second source rock, Wealden samples are discussed mainly based on a detailed study by Rippen et al. (2013). The Posidonia Shale source rock analogues from the Hils Syncline show a typical development for a maturity series, ranging from immature to mature up to overmature/gas mature. TOC values decrease with increasing maturity, mainly due to hydrocarbon generation already taking place in the oil mature samples. This is in principal agreement to earlier studies on the LSB (Wehner et al., 1997) and Hils Syncline (Littke et al., 1988). During maturation, also non-hydrocarbon fluids such as water and carbon dioxide are generated, as well as solid residue (solid bitumen). A mass balance for the Posidonia Shale at different levels of maturation has been published by Rullkötter and Marzi, (1988), although not exactly for the same wells investigated here. Our results are in principal agreement and confirm the loss of about half of the kerogen as volatile products. Although hydrocarbon production leads to a reduction of TOC, a direct calculation of volume of produced hydrocarbons from Rock-Eval data (see Cooles et al., 1986) is complex, e.g. because hydrogen availability and liberation is often underestimated in open-system pyrolysis (Li et al., 2015). Reflectance values of the organic matter increase with increasing thermal maturity from 0.5 to 1.5 % VRr, while HI-values decrease from 685 to 24 mg hc/g TOC. Maturity related changes are also reflected in the molecular composition of hydrocarbons. 31

Because the oils investigated show a rather high maturity stage, we discuss only molecular

Figure 2.4: Figure 2.4: GC-FID of the aliphatic fraction, displaying the different degree of degradation of the oils samples, Steimbke-Ost 10 (top), Steimbke-Alt WA 317 (middle) and Eystrup 5 (bottom). parameters based on n- and iso-alkanes as well as aromatics. Significant changes were observed for Pri/Phy, Pri/nC17 and Phy/nC18 ratios. While an increase in the Pri/Phy ratio can mainly be attributed to a preferential release of sulfur-bound phytol in the early stages of maturation (De Graaf et al., 1992), the decrease in Pri/nC17 and Phy/nC18 results from enhanced n-alkane generation during progressing maturation. Both parameters show a positive correlation for the source rock samples of different maturity (r2=0.94) (Fig. 2.7). If compared to the geochemical results from the oils, the Harderode samples provide the best analogue fit, showing similar Pri/nC17 and Phy/nC18 ratios. 32

Figure 2.5: GC-MS ion traces of m/z = 191 and m/z = 217 for the samples Steimbke-Ost 10 (top), Steimbke-Alt WA 317 (middle) and sample Eystrup 5 (bottom). 33

In the LSB another possible source rock is the Wealden (Binot et al., 1993; Kockel et al., 1994; Berner et al., 2010), although it has to be noted that it occurs in a brackish-lacustrine facies with predominant hydrogen-rich kerogen only in the western part of the basin. Based on results of Rippen et al. (2013) values for Wealden shales at moderate and high levels of maturity have been added to Table 2.2. Based on Pri/nC17 and Phy/nC18 ratios, Wealden shales show usually a more oxic depositional environment as compared to Posidonia Shale and as compared to the oils analyzed. In other words the Posidonia Shale is regarded the most probable source rock for the oils.

2.6.2 Origin and maturity of the oils Based on geochemical data and geological considerations Posidonia Shale is regarded as the major source rocks of the oils of the Gifhorn Trough and LSB investigated here. In particular the Pri/nC17 and Phy/nC18 data fit very well to extracts from the Posidonia Shale (Fig. 2.7). Using the pristane/phytane ratio and the ratio of dibenzothiophene/phenanthrene, a carbonate- rich marine shale (Fig. 2.8) can be deduced as source rock of the oils. This is typical for the Posidonia Shale, which has been deposited under marine conditions and is carbonate-rich. Some samples from the lowermost part of the Posidonia Shale even contain >50 % carbonate (Song et al., 2015).

Typical petroleum generated by the Posidonia Shale is clearly linked to maturation, favoring saturated hydrocarbons during early maturation stages and showing an increase in aromatic components during later stages of oil maturity. With the onset of overmature conditions, short chained saturated hydrocarbons are once again prevalent (Horsfield and Düppenbecker, 1990; Düppenbecker and Horsfield, 1989; Mohnhoff et al., 2016). This fits well with the data obtained from the compound analysis of oils (Tab. 2.3), where the more mature oils show a predominance of aromatic compounds over saturated hydrocarbons.

The calculated maturities for the oils fit well with maturities obtained from a modelling study conducted by Bruns et al. (2013; Fig. 2.9), although the maturities of the source rock at current depth and maturity are assumed to be a little higher. There is also no apparent difference between maturities of the oil samples from the eastern LSB compared to those from the Gifhorn Trough. This coincidence may be due to the fact that both samples from the Gifhorn Trough are derived from fields located on the flank of the structure, where Posidonia Shale is at similar maturity. Thus studied oil fields are located in areas, where the Posidonia 34

Shale has maturity levels close to peak oil generation; they are not situated in areas where Posidonia Shale is immature or early mature. This pattern suggests rather short lateral migration distances, although the much higher permeability parallel to bedding as compared to perpendicular to bedding (Ghanizadeh et al., 2014) would promote intraformational lateral migration.

The variability of the sulfur content of the oils is surprising in view of the quite uniform molecular ratios. The same holds true for the variability in Pri/Phy ratios. The latter observation may be partly related to the different levels of biodegradation, i.e., a stronger phytane degradation is reported for oils affected by bacterial activity (Nakajima et al., 1985). Similarly biodegradation is known to lead to loss of hydrocarbons and thus an increase in sulfur content.

However, the API values show no good correlation with sulfur content, in contrast to observations on other degraded or non-degraded oils (e.g. Abeed et al., 2012). There is also no apparent trend visible between the sulfur content and the reservoir depth, whereas API values are linked to reservoir depth, showing higher densities at shallower reservoirs. Especially reservoirs located below 1000 m depth show very high densities, often below 15 ° API. The only exception to this is sample Eilte-West 14, where similarly low API values are

Table 2.3: TLC-FID (Iatroscan) results for the oil samples from the Lower Saxony Basin and the Gifhorn Trough.

observed at a depth of 1500 m. This observed depth trend is typical for oil plays (Palmer, 1993; Volkman, 1984; Bailey et al., 1973; Jones et al., 2008) due to the possibility of meteoric water entering the shallower reservoir, importing bacteria, and possibly leading to biodegradation and/or water washing. In addition to these criteria, for reservoirs to be affected by bacterial degradation, temperatures lower than 80 °C are needed since these do not eliminate the bacterial population (Wilhelms et al., 2001) efficiently, and promote bacterial activity. It should be noted that in rare cases where the strong nutrient supply occurs, bacteria might survive even slightly higher temperatures (Parkes et al., 1994). Based on the Iatroscan results (Fig. 2.10; Tab. 2.3), water washing seems unlikely as the source of oil degradation, since especially aromatic compounds are still present in high quantities in all samples. However, in type III oils with the strongest effects from biodegradation, polyaromatic compounds occur in higher percentages as compared to mono+di-aromatic as well as saturated hydrocarbons.

We consider the generally low to moderate sulfur contents of the oils as an indication of kerogen type. Sulfur rich kerogen tends to generate sulfur rich oil (Ho et al., 1974; Baskin and Peters, 1992); this is typical of marine carbonate source rocks, in which carbonate 36 content is much higher than in the Posidonia Shale, even though it is a major constituent there. Low organic sulfur content is in agreement with high pyrite content of these source rocks (Song et al., 2015). With respect to sulfur content, Volkensen 6 oil is exceptional, showing a value of 3.17 % (Tab. 2.1). The same oil is also low in saturated hydrocarbons as well as mono- and di-aromatics and very much enriched in polar and hetero compounds. Whereas all these features are typical of biodegraded oils the missing hump in the gas chromatogram as well as the high concentration ratio of n-alkanes over iso-alkanes points towards an undegraded oil. Interestingly Pri/Phy ratios are the lowest among all studied oils

Figure 2.7: Pri/nC17- and Phy/nC18-plot of the analyzed source rock samples and the oils from the LSB and Gifhorn Trough. Oil samples plot between peak oil mature Harderode and latest oil mature Pötzen source rocks. for Volkensen 6. This strange pattern might be related to a co-source from a Permian carbonate source rock deposited under strongly reducing conditions, or due to several oil charge phases into the reservoir. If a second source would be responsible for this pattern, such a source rock would be expected to have sulfur rich kerogen and low Pri/Phy ratios.

There is also a slight correlation (r2 = 0.63) between API values and the aliphatic/aromatic ratio, indicating that high API oils coincide with higher contents of aliphatics in the oils. Saturated hydrocarbon percentages reach from 44.69 % in sample Suderbruch M57 to 12.37 % in sample Barenburg, usually occurring in smaller percentages as compared to the aromatic compounds. 37

Figure 2.8: Pristane/Phytane vs Dibenzothiophene/Phenanthrene plot of oil samples, indicating the depositional facies of the source rock. Based on the results of the GC-FID, the oil samples can be classified into three distinct oil types, presenting different exposure to biodegradation. Oil type I (Fig. 2.4) shows only minor biodegradation and is representative for most of the oil samples. N- and iso-alkanes appear undegraded and no “hump” can be recognized. Hopanes are only present until C35, while steranes occur only up to C27.

Oil type II is indicative of strong biodegradation, showing a distinct “hump”. Both high molecular and low molecular –weight aliphatic hydrocarbons occur. In particular hopanes only up to C35 occur. Only the sample from well Steimbke-Alt Wa 317 fits to this oil type, presenting this particular type of degradation of a less mature oil.

Oil type III shows also a hump, but almost no long-chain aliphatic hydrocarbons (Fig. 2.4). Steranes occur in very low concentrations, while hopanes are almost completely absent. Only four samples show the characteristics of this oil type, namely sample Eystrup 5, Gr. Lessen 14, Steimbke-Lichtenmoor So 39 and Steimbke-Nord WA 211.

Figure 2.9: Modelled maturity map of the Posidonia Shale of the Lower Saxony Basin, Gifhorn Trough and parts of the Pompeckj Block (after Bruns et al., 2013). Signs of strong biodegradation are visible in oil types II and III, particularly the degradation of longer chained n-alkanes is obvious for these oil types. Oil type III if compared to oil type II contains almost no steranes and hopanes. These compounds can be affected by biodegradation (Reed, 1977; Seifert and Moldowan, 1981), but to a much lesser extent than n-alkanes (Rubinstein et al., 1977, Connan et al., 1979; Goodwin et al., 1982). These missing components are accordingly related to higher maturity rather than biodegradation. The exact nature of selective degradation including also typical biomarkers such as steranes and hopanes is still not quite well understood. According to Wenger et al. (2001), sterane and hopane degradation is only present if biodegradation has progressed further than is indicated in the GC traces. Schwarzkopf (1990) reported for oil samples from the mature Meerdorf oil field (0.85 % VRr) a similar pattern. Thus the variability in the absence or presence of steranes and hopanes is probably related to a combination of advanced thermal maturity and biodegradation. 39

2.7 Conclusions 24 oils from the LSB and the Gifhorn Trough have been analyzed, showing variable densities, sulfur contents and geochemical composition. By comparing the oils to source rock extracts, the Jurassic Posidonia Shale was identified as principle source rock.

The Posidonia Shale in the LSB and in the Gifhorn Trough is an organic-rich marlstone, bearing hydrogen-rich kerogen. Sulfur is mainly bound in pyrite and only in a small percentage in organic matter. Several molecular ratios are regarded specific of the Posidonia Shale and can be used for correlation studies. Furthermore there is a systematic change in a number of maturity parameters, allowing the assignment of source rock maturities to specific oils. 40

Through the analysis of the maturation series of the Posidonia Shale and the systematic comparison, peak oil-mature samples from the Harderode well (0.88 % VRr) were identified as best equivalents for the oils of the LSB and Gifhorn Trough, although the oils show maturity values that are slightly higher. The calculated oil maturities range between 0.8- 1.05 % VRr (based on aromatic hydrocarbon parameters). The observed oil maturities also fit to calculated maturities of the Posidonia Shale based on numerical petroleum system modelling. The studied oil fields are located in areas, where the Posidonia Shale has maturity levels close to peak oil generation; they are not situated in areas where Posidonia Shale is immature or early mature. This pattern suggest rather short lateral migration distances, although the much higher permeability parallel to bedding as compared to perpendicular to bedding would promote intraformational lateral migration. However, the situation in the Gifhorn Trough is a little different, due to strong maturity differences over short distances. This is a direct result of the structure of the Trough and its geotectonic evolution. The here presented oils from the Gifhorn Trough are only from locations on the rim of the structure. It should also be mentioned that less mature oils, compared to those analyzed here, can be found in the Lower Saxony Basin as well.

Most oil samples from the LSB and the Gifhorn Trough show no or little secondary alteration (type I oils), but some oils (type II and III oils) show severe biodegradation affecting e.g. long-chain n-alkanes. These oils are also enriched in high-molecular weight products and heterocompounds. The fact that most of these degraded oils are derived from shallow reservoirs is an indication that this pattern is mainly to be expected at depths of less than about 1500 m.

3 Organic geochemistry and petrology of Posidonia Shale (Lower Toarcian, Western Europe) – the evolution from immature oil-prone to overmature dry-gas kerogen

3.1 Abstract Kerogen concentrates as well as whole rock samples of the Lower Jurassic Posidonia Shale, representing a complete maturity series from immature to highly overmature, were analyzed using organic petrography, palynology, bulk geochemical analysis, FT-IR and Curie Point- pyrolysis GC-MS (CP-Py-GC-MS) in order to investigate changes in kerogen composition with increasing maturation. Vitrinite reflectance ranged from 0.5 to 3 %. Maturity-related changes were observed for bulk geochemical data, e.g. a decline in TOC as well as OI and HI values due to increasing defunctionalization, aromatization and cracking. FT-IR spectra show a decrease in functional group bands with increasing maturation. CP-Py-GC-MS measurements indicate an increase in hydrocarbons, especially for short- and medium-length n-alkanes, with a strong predominance of short-length alkanes at highest maturities (2.79 - 3

% VRr). This effect, however, depends also on the applied pyrolysis temperature, where higher temperatures (920 °C, as compared to 650 °C) favor generation of short-length n- alkanes, especially for samples at high levels of maturation. Ratios of aromatic over aliphatic hydrocarbons or alkenes over alkanes show a non-steady evolution, depending also on the applied pyrolysis temperatures, indicating that higher pyrolysis temperatures are needed for pyrolytic alkene formation, with a maximum alkene formation for samples within early overmature maturities (~1.4 % VRr).

3.1.1 Introduction For many years, kerogen studies have been mainly conducted using microscopic techniques (e.g. Staplin, 1969; Mastalerz et al., 2012; Gorbanenko and Ligouis, 2014; Hartkopf-Fröder et al., 2015), focusing on properties like maceral composition, which provides information on organic matter distribution and variability but lack quantitative chemical information. Rock- Eval pyrolysis on the other hand, using the total organic matter without differentiating between the contributing fractions, estimates the total hydrocarbon production from a source rock (Espitalié et al., 1977; Longbottom et al., 2016; Chen et al., 2016; Delvaux et al., 1990; Hartman-Stroup, 1987). Rock-Eval pyrolysis results are also influenced by interaction 43 between organic and mineral matter (Espitalié et al., 1980; Horsfield et al., 1983; Peters, 1986; Jasper et al., 2009). On the other hand, very detailed molecular organic geochemical studies are often performed on fractions of solvent extracts from such source rocks (e.g. n- alkanes as part of bitumen), which, though representing only a minor part of the total organic matter, provide detailed insights into precursor biota and ecosystems (Peters et al., 2005).

Kerogen, which is the major part of total organic matter in almost all rocks, has been studied less frequently using FT-IR, μ-FT-IR or NMR techniques, which provide further information on the chemical composition allowing the analysis of aliphatic and aromatic moieties as well as functional groups in the kerogen and their change with increasing maturation (Witte et al., 1987; Rullkötter and Michaelis, 1990; Lis et al., 2005; Preston et al., 2011; Fleury and Romero-Sarmiento, 2016). Pyrolysis (e.g. Cp-Py-GC-MS) in either closed or open systems, has been used to describe the chemical structure of kerogen upon maturation (al Sandouk- Lincke et al., 2013; Lis et al., 2008; Dieckmann et al., 2000; Horsfield, 1984; Horsfield et al., 1998, 1983). These methods provide information related to kerogen structure as well as abundance and selective liberation of hydrocarbons and heterocompounds from kerogen. Organic matter within petroleum source rocks undergoes substantial physical and chemical changes upon maturation (van Krevelen, 1993; Behar et al. 1997; Vandenbroucke and Largeau, 2007), which are mainly related to elimination, aromatization, condensation and carbon-carbon bond cleavage (Lewan, 1983). Related structural and chemical changes have been investigated (Radke and Willsch, 1993; Vandenbroucke et al., 1993; Schaefer and Littke, 1987; Witte et al., 1987), taking into account different heating rates (Dieckmann et al., 2000; Dieckmann et al., 1998; Horsfield and Düppenbecker, 1991; Düppenbecker and Horsfield, 1989) and kerogen type.

The quantification of changes in structure and composition during maturation requires a homogeneous maturity series which is not significantly affected by variability in organic facies, therefore a wide ranging maturity series from the same facies/formation is needed to evaluate compositional changes during burial and thermal maturation. The Posidonia Shale (Lower Toarcian, Liassic) of the Hils Syncline (northern Germany) is considered to be such a natural laboratory because of its uniform organic facies at various maturities. Various studies on maturity effects have been conducted on this source rock in the past, e.g. on mass balances (Rullkötter et al., 1988), maceral transformation (Littke et al., 1988), kinetics of petroleum generation (Schenk and Horsfield, 1998; Schaefer et al., 1990), and organic matter porosity evolution (Bernard et al., 2012; Klaver et al., 2012). These former studies did, however, not 44 take into account “gas shales”, i.e. samples with maturities greater than 1.4 % VRr. More mature Posidonia Shale was not considered, although higher maturities are reached in the southwestern Lower Saxony Basin (up to at least 3 % vitrinite reflectance; Bruns et al., 2013). Interactions between the mineral and organic facies, especially related to the aromatization process, have an only small influence (Rose et al., 1992) and are discussed here with respect to FT-IR and Rock-Eval data.

The Lower Jurassic Posidonia Shale and its time-equivalent bituminous sedimentary rocks are regarded as one of the most important petroleum source rocks in Western Europe bearing oil-prone type I-II kerogen (Rullkötter et al., 1988), extending over large parts of the southern UK and North Sea, Germany, the Netherlands, Switzerland and France. The main geological basins associated with these source rocks are the Yorkshire Basin, the southern North Sea, the Northwest-German Basin and its extensions into the Netherlands, the Southwest-German Basin and the Paris Basin (Fig. 3.1). These source rocks are characterized by high organic carbon (TOC) contents and a clear, negative carbon isotope excursion (Song et al., 2016: Fig. 3.3a, b). The Posidonia Shale was deposited in a low energy environment under largely anoxic to euxinic marine conditions in a sea rich in nutrients (Riegel et al., 1986; Littke et al., 1991a; Schmid-Röhl et al., 2002). These conditions favored the preservation of organic matter leading to very high total organic carbon contents reaching locally up to 15 % (Littke et al., 1991a). Although the Posidonia Shale is largely associated with oxygen-depleted environments, short phases of more oxygenated bottom water conditions have also been recognized (Wignall and Hallam, 1991; Roehl et al., 2001; Song et al., 2015, 2016) throughout its deposition. Due to these slightly changing conditions, also associated with variations in sea-level and paleoclimate variability (Frimmel et al., 2004), the Posidonia Shale in northern Germany is divided into three units: a marlstone unit as the lowest member, featuring the highest carbonate contents of the formation, a calcareous shale unit in the middle featuring bivalve shells and a calcareous shale unit as the top unit, featuring less fossils and the highest clay content of all three units (Littke et al., 1991a,b). 45

Figure 3.1: Paleogeographic map of the Liassic continental shelf on a current map of Western Europe. Figure modified after Schwark and Frimmel (2004), based on Ziegler (1982). In this study, a series of ten immature to overmature Posidonia Shale samples was investigated using standard petrographical and geochemical analyses such as vitrinite reflectance and Rock-Eval pyrolysis as well as Curie Point-pyrolysis-GC-MS (CP-Py-GC- MS) (Larter and Douglas, 1982; van Bergen, 1999) and FT-IR measurements (Schenk et al., 1986; Lis et al., 2005). In order to investigate mineral matrix effects, both whole rock samples and kerogen concentrates were investigated and results for both sets of samples compared. The aim of this study is the quantification of kerogen conversion through the relative proportions of volatile aliphatic and aromatic compounds and the ratio of alkane and alkene, resulting from elimination processes and cracking taking place with increasing maturation up to a maturity of 3 % VRr and its relation to the gross ratio of aliphatic to aromatic moieties within the kerogen. In comparison to earlier studies listed above, CP-Py- GC-MS analysis as well as FT-IR measurements were applied to overmature gas shales of the Posidonia with maturities of up to 3 % which can lead to a more complete consideration of kerogen evolution for the Posidonia Shale in the future.

3.2 Methods and samples

3.2.1 Sample origin Ten Posidonia Shale samples of varying maturity, ranging from immature to overmature, from various wells and outcrop locations in Western Europe were analyzed. Eight immature to early gas mature samples originate from shallow boreholes Wenzen, Dielmissen, Dohnsen, Harderode and Pötzen from the Hils Syncline (Germany; see Rullkötter et al., 1988), an outcrop in the UK (Runswick Bay) as well as from wells located in the Netherlands (Loon op Zand well LOZ-1) and Luxembourg (see Song et al., 2015). Two samples are highly overmature North-West German “gas shales” (NWG-gas shales in the following), marking the end of the maturity series. One of these samples (outcrop Schwarzkreidegrube Vehrte, Germany) is strongly weathered, which affects predominantly the pyrite content, but possibly also kerogen composition (Littke et al., 1991b), while the other represents a core sample drilled in a well.

3.2.2 Kerogen concentration Preparation of the kerogen concentrates was performed on pulverized aliquots of the sample material. After drying, acid dissolution was conducted using HCl and HF (but no oxidizing solutions), as described by Batten (1999) and Green (2001). Samples were not heated to avoid chemical or structural changes in kerogen. Also we did not make use of sieving and heavy liquid treatment as this may distort the composition (Tyson, 2006). Accordingly pyrite is preserved in the kerogen concentrates and organic matter is chemically and structurally not significantly altered. The kerogen-pyrite concentrates were finally kept in a dry environment to avoid molding. No extraction with DCM was carried out.

3.2.3 Organic petrography Polished sections were prepared from whole rock pieces of each sample. Details of sample preparation are described in Littke et al. (2012). The setup on which measurements were performed is a Zeiss Axio Imager microscope equipped with a tungsten-halogen lamp and a 50x/0.85 Epiplan-NEOFLUAR oil immersion objective and a 546 nm filter for vitrinite reflectance measurements in incident light. Vitrinite reflectance was measured against an Yttrium-Aluminium-Garnet (YAG) standard with an established reflectance of 0.898 % in 47 case of immature and mature samples and against a Gadolinium-Gallium-Garnet (GGG) standard with a known reflectance of 1.716 % for the overmature samples. All measurements were conducted using Zeiss immersion oil with a refractive index of ne= 1.518 at 23 °C and at random orientation of the grains. Evaluation of maceral composition was performed with the same basic equipment, but using in addition blue light excitation to achieve fluorescence of the macerals. More details of the equipment and procedure are described in Sachse et al. (2012).

3.2.4 Rock-Eval pyrolysis Rock-Eval pyrolysis was performed using the standard Basic/Bulk-Rock method. We used a Rock-Eval 6 device following the methods described in Espitalié et al. (1977) and Lafargue et al. (1998). The displayed parameters Tmax (°C), hydrogen index (HI) (mg HC/g TOC), oxygen index (OI) (mg CO2/g TOC) and production index (PI) were calculated using the S1

(mg HC/g rock), S2 (mg HC/g rock) and S3 (mg CO2/g rock) peaks obtained from Rock-Eval pyrolysis measurements.

3.2.5 Elemental analysis Determination of total organic carbon and total inorganic carbon was conducted using a LiquiTOC II apparatus in a single analytical run, with calibration being performed before every measurement. Procedures for the TOC/TIC determination using this particular apparatus are described in Bou Daher et al. (2015) in more detail. Sulfur determination was conducted using a Leco S200 total evaporization analyzer with calibration rings of known sulfur content (0.323 wt.-%) and a Lecocell fluxing agent with iron shavings for calibration before every measurement.

3.2.6 Curie Point-Pyrolysis-GC-MS (CP-Py-GC-MS) About 1 mg of each kerogen concentrate sample was pyrolyzed twice at temperatures of 650 °C and 920 °C, respectively, for 10 s using a CP pyrolyser (Fischer GSG CPP 1040 PSC) coupled to a gas chromatograph (Fisons 800 series) linked with a quadrupole mass spectrometer (Thermoquest MD 800). The temperatures used, allow for comparability of all samples, with the minimum temperature of 650 °C, still enabling information from the highly 48 overmature samples, which at lower temperatures yielded no evaluable results. The highest temperature of 920 °C allowed for the best possible evaluation of the overmature samples, while also providing analyzable information for even the low mature samples. The gas- chromatographic column was a Zebron ZB-1 (30 m x 25 mm i.d., film thickness 0.25 μm). Directly behind the injector a cryo-trap with liquid nitrogen was installed. The injection was conducted using splitless injection mode (splitless time 1 min) at an injector temperature of 270 °C and a starting oven temperature of 40 °C (held for 3 min.) up to an end temperature of 310 °C which was held for 20 minutes. The temperature gradient was set to 3 °C/min. The source temperature of the MS was 200 °C, using 70 eV ionization and a scan range from m/z 50-550. Peak identification was performed using mass spectral libraries (NIST 14 MS Database) and by comparison of mass spectra and gas chromatographic retention with comparable data (al Sandouk-Lincke et al., 2013).

3.2.7 FT-IR-spectroscopy FT-IR-spectroscopy was performed on both bulk samples and kerogen concentrates, using a Perkin Elmer Spotlight 400 FT-IR microscope for the kerogen concentrates and a Perkin Elmer Frontier FT-IR equipped with a Universal Attenuated Total Reflection (ATR) sampling accessory for the bulk measurements. Measurements were conducted using an optical resolution of 4 cm-1. Analysis were carried out using less than a gram of sample material for each measurement with a scanning range of 4000-650 cm-1.

To account for reduced reflectance and increasing absorption due to the present mineral matter within the samples, all displayed samples were subjected to baseline corrections using the Software Spectrum by Perkin Elmer.

3.3 Results

3.3.1 Microscopy, elemental analysis and Rock-Eval pyrolysis The bulk samples exhibited TOC contents up to 13 % and showed a trend of decreasing TOC contents with increasing maturation (Tab. 3.1). At immature levels, TOC is high varying between 8 % (Luxembourg) and 13 % (the Netherlands). Rock-Eval pyrolysis results reveal HI and OI values ranging from 735 mg HC/g TOC to 7 mg HC/g TOC and from 51 mg

CO2/g TOC to 6 mg CO2/g TOC, respectively (Fig. 3.2, Tab. 3.1). Tmax values are quite 49 uniform for the immature and oil-generation stages, respectively, and much higher for the gas-mature sample Pötzen. No Tmax values were obtained for the two most mature samples, due to the very low S2 signal of the samples, hindering an accurate determination of Tmax values.

Figure 3.2: Pseudo-van-Krevelen diagram displaying kerogen type based on HI and OI values from Rock-Eval pyrolysis. The ten kerogen concentrates have TOC values ranging from 24 % to 71.1 %, TIC contents from 0.1 % to 0.4 % and Tmax values from 419 °C to 440 °C (Tab. 3.2). No reliable Tmax values were obtained for the two highly overmature gas shale samples (Tab. 3.2). Sulfur values show the greatest variability, ranging from 0.7 % for the weathered outcrop gas shale sample, to 27.2 % for the Harderode sample (Tab. 3.2). Based on Tmax the lowest maturity is assigned to three samples from Wenzen, Luxembourg and the Netherlands. Their respective

Tmax values are 419 °C, 423 °C and 435 °C and HI values range from 673 to 752 mg HC/g TOC (Fig. 3.2). 50

Figure 3.3a: Tmax [°C] vs VRr [%] plot, displaying the difference between measurements conducted on bulk samples and kerogen concentrates.

Figure 3.3b: VRr [%] vs HI [mg HC/g TOC] plot of all samples, showing the evolution of type I-II kerogen with increasing maturity (vitrinite reflectance). 51

Figure 3.4a-h: Micropetrographic photographs of polished sections. The long axis of each photograph is equivalent to 250 μm. Photos A, C, E, G, H were taken under reflected white light and photographs B, D, F under incident fluorescence light. A) Mostly argillaceous matrix with pyrite nodules (Py) and alginites (visible in B). Sample Wenzen (immature, 0.5 % VRr). B) Same sample area as A). Note the bright yellow fluorescence of the telalginites (TA) and lamalginites (LA). C) Inertinite (In) and pyrite nodules (Py). Sample Dohnsen (mature, 0.7 % VRr). D) Same sample area as C). Telalginite (TA) and lamalginite (LA) clearly visible due to bright yellow fluorescence. E) Pyrite nodules (Py) occurring dispersed throughout the sample. Sample Harderode (mature, 0.87 % VRr). F) Same sample area as E). Note that telalginite (TA) still shows yellow fluorescence but overall fluorescence colors are clearly darker as compared to photos B) and D) due to higher thermal maturity. G) Inertinite (In) and pyrite nodules (Py). Sample Pötzen (postmature, 1.49 % VRr, converted from solid bitumen reflectance). No visible fluorescence was observed. H) Pyrite nodules (Py) and solid bitumen (SB). NWG-gas shale sample (outcrop) (highly overmature, 3.0 % VRr, converted from solid bitumen reflectance). 52

The immature character is also revealed by their production index (PI), with values of 0.03 and 0.04 for the Luxembourg and Wenzen samples. However, a higher value of 0.13 for the sample from the Netherlands points to impregnations as already discussed by Song et al. (2015). Oxygen Index (OI) values are low for these samples (Tab. 3.2).

Table 3.1: TOC, vitrinite reflectance values and Rock-Eval pyrolysis results for all 10 bulk samples.

OI [mg HI [mg CO2/ TOC TIC S Tmax HC/g g VRr Bulk Samples [wt.-%] [wt.-%] [wt.-%] [°C] TOC] TOC] PI [%] Wenzen 10.5 2.1 3.3 418 699 41 0.03 0.5 Netherlands 13.0 1.5 4.4 426 625 24 0.08 0.55 Luxembourg 7.7 2.8 2.2 424 735 12 0.05 0.56 UK 8.2 0.7 5.8 431 576 33 0.12 0.65 Dielmissen 9.3 4.5 2.9 438 569 21 0.09 0.68 Dohnsen 8.7 6.7 2.6 446 520 17 0.08 0.7 Harderode 7.6 1.1 2.1 447 382 6 0.1 0.87 Pötzen 6.0 2.9 2.0 452 158 6 0.28 1.49* NWG-gas shale 3.9 5.2 2.7 - 12 6 0.7 2.79* (well) NWG-gas shale 1.8 4.4 0.3 - 7 51 0.53 3* (outcrop) * measurements were conducted using solid bitumen reflectance and converted to VRr- values adopting the formula by Landis and Castano (1994) Table 3.2: TOC, vitrinite reflectance values and Rock-Eval pyrolysis results for all 10 kerogen concentrate samples.

TOC S HI [mg OI [mg VRr Kerogen [wt.- [wt.- Tmax HC/g CO2/g (bulk) Samples %] %] [°C] TOC] TOC] PI [%] Wenzen 63.3 9.7 419 752 13 0.04 0.5 Netherlands 33.4 22.7 435 673 2 0.13 0.55 Luxembourg 50.1 19.5 423 742 10 0.03 0.56 UK 62.1 5.6 438 549 13 0.06 0.65 Dielmissen 52.9 15.2 439 586 3 0.12 0.68 Dohnsen 37.1 11.7 440 634 3 0.08 0.7 Harderode 33.7 27.3 440 306 4 0.19 0.87 Pötzen 53.7 20.1 438 145 4 0.27 1.49* NWG-gas shale (well) 24.0 25.7 - 10 5 0.69 2.79* NWG-gas shale (outcrop) 71.2 0.8 - 7 47 0.46 3* * measurements were conducted using solid bitumen reflectance and converted to VRr-values adopting the formula by Landis and Castano (1994) 54

Samples within the immature/very early mature to peak oil-mature stage (Luxembourg, Wenzen, the Netherlands; Dohnsen, Dielmissen, UK, Harderode), display vitrinite reflectance values ranging between 0.55 - 0.87 % VRr and Tmax values between 438 - 440 °C. Although the samples exhibit different vitrinite reflectance values, Tmax values are very similar, with values of 438 °C, 439 °C, 440 °C and 440 °C for the aforementioned samples (Fig. 3.3a). HI values are high for the early mature samples (about 0.7 % VRr), ranging from 634 mg HC/g TOC to 549 mg HC/g TOC and intermediate (306 mg HC/g TOC) for the peak oil-mature sample from Harderode (Fig. 3.3b). OI values are low for all samples, with a slightly higher value recorded for the weathered outcrop sample from the UK.

The Pötzen sample has a maturity of 1.49 % VRr and the two gas shale samples are at 2.79 and 3 % VRr. Tmax values are only available for sample Pötzen. Among the overmature samples, HI values are highest for the Pötzen sample with 145 mg HC/g TOC, revealing some residual hydrocarbon (gas) generation potential, and very low for both gas shale samples with values of 10 and 7 mg HC/g TOC, respectively. OI values are low, except for the strongly weathered gas shale outcrop sample (Tab. 3.1).

Throughout the sample series, from low to high maturity, the samples show variable percentages of macerals (Fig. 3.4a-h). In low mature up to oil-mature samples, including the samples from Luxembourg, Wenzen, the Netherlands, UK, Dielmissen and Dohnsen, liptinite is the dominating maceral group, occurring throughout all samples in the form of lamalginite and telalginite as well as bituminite. The volume percentage of liptinite, identified using fluorescent light, declines with increasing maturity (see Littke et al., 1988). Other macerals are present only in subordinated amounts, such as inertinite, solid bitumen and (very rare) vitrinite.

Maceral composition of the overmature samples from Pötzen and the NWG-gas shales differs completely compared to the low mature samples, with almost no more alginite being present and solid bitumen as the major maceral. The peak oil-mature Harderode sample is intermediate with respect to maceral composition showing still telalginite (tasmanites) and some (remains of) lamalginite.

In all samples the kerogen concentrate is extremely rich in amorphous organic matter. In the Wenzen sample which is thermally immature prasinophyte-phycomata do occur regularly (Fig. 3.4I). Most of them are assigned to Tasmanites/Pleurozonaria. Terrestrial organic matter such as wood, fern spores and pollen (e.g. Classopollis) are very rare. Marine 55 microplankton in samples from Dohnsen and Harderode which are in the very early mature stage is less well preserved (Fig. 3.4K-N) making taxonomic assignment difficult. No phycomata were recorded in the Pötzen and NWG-gas shale (well) samples (Fig. 3.4O-P).

In the immature samples prasinophyte-phycomata show bright yellow fluorescence (Fig. 3.4J) which changes to orange and ceases in the Pötzen and NWG-gas shale (well) samples. Simultaneously, color of amorphous organic matter turns from light brown to dark brown and black (Fig. 3.4O-P). Hence, with increasing maturity palynofacies and fluorescence of algal remains follow the same trend as maceral composition and liptinite fluorescence observed during petrographic analyses of polished sections.

3.3.2 Curie Point-Pyrolysis-GC-MS (CP-Py-GC-MS) Cp-Py-GC-MS was applied to all ten kerogen concentrate samples, using two different pyrolysis temperatures of 650 °C (Fig. 3.5a-c) and 920 °C (Fig. 3.6a-c). These different pyrolysis temperatures have been applied due to the wide range of sample maturity. All samples produce at both pyrolysis temperatures a large quantity of aliphatic hydrocarbons, whereas mono- and polycyclic aromatic compounds as well as cyclic aliphatic compounds occur in minor quantities. Chain length of the aliphatic components was limited to a maximum of C22. In almost all samples oxygen- as well as sulfur-containing compounds are very minor in abundance. An exception is the sample from the UK, where saturated carbonyl compounds occur in greater quantity.

The experiments using a pyrolysis temperature of 650 °C (Fig. 3.5a-c) show the highest variability in the low molecular weight compounds (C8, where the immature samples show a dominance of short-chain compounds.

On the contrary, the oil-mature samples are dominated by medium chained n-alkanes (C10-

C18), but the overmature samples display again a dominance of short-chain compounds. Branched alkanes occur predominantly in the immature and oil-mature samples. The toluene/heptane ratio, indicating the proportion of volatile aromatic over volatile alkane compounds (Fig. 3.7a), illustrates a broad variability for the immature samples. Especially the sample from the Netherlands shows a very high ratio, indicating a greater contribution of low molecular weight aromatic compounds at low maturities. A low value, i.e. low aromaticity was recorded for the peak oil-mature Harderode sample. At higher rank (Pötzen) a higher contribution of aromatic compounds can be observed, i.e. an even ratio between toluene and 56

heptane, whereas the overmature NWG-gas shales (about 3 % VRr) shows a strong predominance of heptane over toluene (which is due to the insufficient pyrolysis temperature for such overmature samples; see below).

The pyrolysis experiments at 920 °C (Fig. 3.6a-c) reveal typical alkene/alkane pairs, with the n-alkenes eluting before the n-alkanes. Whereas immature samples only show low molecular compounds, especially with respect to n-alkanes, the oil-mature samples produce n-alkanes up to C15. The pyrolysis products of the overmature samples, while predominantly consisting of short-chain n- and iso-alkanes, feature higher contents of aromatic compounds, including styrenes and naphthalenes. This high aromaticity is also visible in the toluene/heptane ratio (Fig. 3.7b), which is high for the NWG-gas shales (2.39 and 1.58), while the peak oil-mature Harderode and slightly overmature Pötzen samples show the smallest ratio, indicating the lowest aromaticity. The chromatograms of the pyrolysis series at 920 °C further display a strong predominance of iso-alkenes (Fig. 3.7c) as a result of thermal syn-elimination at higher pyrolysis temperatures (Sunburg, 2010). Whereas this effect diminishes at higher maturities, it leads to very high alkene/alkane ratios at lower maturities, although showing a very broad range. Lower alkene/alkane ratios are observed for the overmature gas shale and Pötzen samples.

A special case in this sample series can be recognized for sample from the UK, where at the higher pyrolysis temperature a large amount of carbonyl compounds was expelled, up to the point that the peak with the greatest area was undecane-1-one. 57

Figure 3.5a: CP-Py-GC-MS chromatogram (650 °C) for the sample from Luxembourg. The green squares are representative of sulfur atoms. 58

Figure 3.5b: CP-Py-GC-MS chromatogram (650 °C) for the sample from Pötzen. 59

Figure 3.5c: CP-Py-GC-MS chromatogram (650 °C) for the non-weathered sample of the NWG-gas shale.

Figure 3.6a: CP-Py-GC-MS chromatogram (920 °C) for sample from Luxembourg. The green squares are representative of sulfur atoms. 61

Figure 3.6b: CP-Py-GC-MS chromatogram (920 °C) for sample from Pötzen.

Figure 3.6c: CP-Py-GC-MS chromatogram (920 °C) for the non-weathered gas shale (well) sample. The green square are representative of sulfur atoms. 63

3.3.3 FT-IR For analysis of FT-IR spectra, typical absorption bands indicating aliphatic bonds, mainly the symmetrical and asymmetrical C-H stretches bonds at wavenumbers of ~2950 - 2750 cm-1 (Blob et al., 1987; Ganz and Kalkreuth, 1991) have been compared to bands indicating aromatic bonds, namely the C=C bond, which can be recognized at wavenumbers ranging -1 from 1800-1550 cm depending on the maturity of the sample (Robin and Rouxhet, 1987). Further interesting spectral areas, namely at 3500 to 3100 cm-1 indicative of free OH bonds, the bond at 3000 cm-1, indicative of aromatic C-H oscillation and the range from 1500 - 650 cm-1, the so called fingerprint, are not subject to analysis here, since the residual inorganic matter containing water prevents an unambiguous signal appraisal in these areas.

Figures 8a and b display the spectra of four selected samples (although analysis has been carried out on all samples), ranging from immature to overmature, for the bulk samples and the kerogen concentrates of the same samples. For the kerogen concentrates, the intensity of the CH3 bands is higher in the immature and oil-mature samples (Wenzen and Harderode) than in the overmature Pötzen and NWG-gas shales. The same holds true for the C=C oscillation intensity, although the signal is stronger at high maturity than that of the aliphatic peaks, indicating a dominance of aromatic compounds in more mature samples. There is also an apparent shift in the peak onset towards lower wavenumbers for the responding peaks visible (Ganz and Kalkreuth, 1991). For the NWG-gas shales almost no aliphatic peaks

(CH2+CH3 bands) can be recognized. For samples Wenzen and Harderode, the fingerprint area looks almost identical, even with respect to peak intensity, while the overmature samples show a stronger deviation. A reason for this might be a slightly different composition of inorganic matter in the samples, where different contents of carbonate, clay minerals and quartz show varying absorptive bands. Aliphatic C-H/(C=C) ratios indicate an increase of aromatic compounds, whereas the aliphatic C-H/(C=C+C=O) ratio illustrates the proportion of aliphatic compounds over aromatic and oxygenated moieties with increasing maturities (Fig. 3.9a-b), which is evidently highest for the highly overmature gas shale samples. 65

Figure 3.8b: Normalized FT-IR spectra, of four bulk samples of varying maturity (see Fig. 3.8a). The bulk samples illustrated in Fig. 3.8b, show a much smaller spread in reflectance intensities. The similarity in the fingerprint area, similar to the kerogen concentrates, is strongest among the samples from Wenzen, Harderode and Pötzen. Although the signal is very good, certain areas of interest overlap with mineral absorption signatures (mainly the 66

C=O bands), making an analysis with the same accuracy as that on the kerogen concentrates impossible.

Figure 3.9a: Aliphatic CH2+CH3 (Ali. C-H)/(Aro. C=C) ratio plotted against VRr.

Figure 3.9b: Aliphatic CH2+CH3 (Ali. C-H)/(C=C+C=O) ratio plotted against VRr. 67

3.4 Discussion The purpose of this work is a qualitative and quantitative determination of hydrogen-rich kerogen conversion. We also seek to extend the current knowledge on this topic to maturities of up to 3 % VRr. Kerogen composition reflects both primary organic facies and maturation upon burial and temperature increase. Here a very similar organic facies can be assumed for all samples, in particular for the samples from northern Germany (Hils syncline and NWG- gas shales).

For the purpose of this study, Rock-Eval pyrolysis and bulk geochemical measurements were conducted to receive information about the chemical composition of the kerogen, as revealed by FT-IR measurements, in particular with respect to the ratio between aromatic and aliphatic compounds. CP-Py-GC-MS measurements provided further information about the conversion products resulting from kerogen aromatization, condensation and carbon-carbon bond breaking, thereby generating aromatic and aliphatic conversion products at different rates. Due to the broad range in maturity of the samples, two different pyrolysis temperatures were applied; the lower one being more suitable for the low mature samples and the higher one for the high mature/overmature samples. Further information was obtained from the ratio between alkane and alkene moieties, where the absence/presence of alkenes is an indicator of elimination processes taking place during the conversion of the kerogen, through the removal of hydrogen and functional groups attached to alkene structures.

3.4.1 Differences between bulk samples and kerogen concentrates Differences were observed between bulk samples and kerogen concentrates, in particular with respect to Rock-Eval parameters (Tab. 3.1 and 2; Fig. 3.10a-c). OI values are higher in bulk samples, probably due to the release of carbon dioxide from (a small) part of the carbonate present or due to the presence of clay in the Posidonia Shale. Interestingly, the overmature Pötzen and NWG-gas shales do not show any significant difference between OI values of bulk and kerogen concentrate samples indicating that carbonate has been thermally stabilized by recrystallization or that thermally instable carbonate has been dissolved and lost during burial and diagenesis. Greatest differences were observed for the low mature Wenzen sample and for the early oil window mature samples Dielmissen and Dohnsen, which contain the highest percentage of carbonate (Table 3.1, 3.2; Fig. 3.10b). Tmax values, if compared for bulk samples and kerogen concentrates, exhibit disparities for samples from Pötzen, Harderode, 68

the Netherlands and the UK (Table 3.1, 3.2; Fig. 3.10c). Although reproduction of Tmax values through Rock-Eval pyrolysis is not perfectly accurate, some differences are too large to be explained through slight inaccuracies. Therefore, these recorded differences are most likely related to the absent, or rather reduced, content of mineral matter in the kerogen concentrates, which apparently influences Tmax values of these samples. This is in accordance with Espitalié et al. (1980), where the strong influence of carbonates, salts and oxygen compounds on Rock-Eval pyrolysis has been demonstrated.

3.4.2 Sample maturity and bulk geochemistry Based on vitrinite reflectance and Rock-Eval pyrolysis measurements the analyzed samples show a great variability in thermal maturity and in hydrocarbon generation potential (Tables 1, 2; Figs. 2, 3a-b). Based on the HI versus OI plot, samples follow the pathway either of type I (kerogen concentrates) or type I-II kerogen (bulk samples; Fig. 3.2). Kerogen concentrates show generally low OI values with the exception of the UK sample (slightly enhanced value) and the NWG-gas shale outcrop sample (much enhanced value). These exceptional values might results from weathering which clearly affects kerogen composition. The weathering effect on pyrite is even more severe than the impact on organic matter as visible from TOC/S ratios. This strong impact of weathering on pyrite/sulfur has already been described before for the Posidonia Shale (Littke et al., 1991b); accordingly sulfur content, TOC/S ratios and microscopic characterization of pyrite can be used as excellent indicators for possible effects of weathering on kerogen and bitumen. If pyrite/sulfur is not or hardly affected by weathering, it can be assumed that also organic matter is also mostly unaffected.

The PI values correspond well to the maturity of the samples as determined by vitrinite reflectance with the highest PI values (0.69, 0.46 and 0.27 in kerogen concentrates) associated with the overmature Pötzen and gas shale samples. There are, however, some discrepancies especially related to the sample from the Netherlands, where a low reflectance of 0.5 % VRr coincides with a relatively high PI value of 0.13 and a quite high Tmax value for the corresponding kerogen concentrate (the value for the bulk sample is in the expected range). This might be related to a short time of heating (e.g. by magmatic or hydrothermal processes) leading to some loss of oxygen (see low OI values) and generation of hydrocarbons, whereas vitrinite reflectance is not affected (Song et al., 2015). PI values might also be higher, because this sample has been drilled at great depth of almost 3 69 kilometers, whereas all other samples are surface near (outcrop or less than one hundred meter depth) and may have lost parts of the highly volatile bitumen fraction. The sample from the Netherlands featured also the highest TOC content of all the samples (13 wt.-% TOC) and a low carbonate content (which is typical of Posidonia Shale in the West Netherlands and Yorkshire Basin; Song et al., 2015).

The Pötzen sample on the other hand, shows a Tmax value of the kerogen concentrate that is too low if compared to its high reflectance value of 1.5 % VRr. While the low HI and OI values of the sample are within the expected range for this maturity, this does not hold true for the Tmax. Reasons for this particular low Tmax value could be related to the replacement of primary macerals by solid bitumen part of which might have a relatively low thermal stability under Rock-Eval conditions. This would, however, not explain the difference between bulk and kerogen concentrate sample which may be due to retention of generated hydrocarbons on the mineral matrix. This effect is much less relevant for the less mature samples, because much greater amounts of hydrocarbons are generated there, overriding the retention capacity of the minerals. It is well known that at low S2 peaks, care has to be taken with respect to interpretation of Tmax values (Peters, 1986; Katz, 1983).

All samples plot in an almost straight line on the Pseudo-van Krevelen diagram (Fig. 3.2), mimicking a type I kerogen in their character, although the Posidonia Shale is a typical marine kerogen and has been often taken as standard example for type II kerogen in common textbooks (Tissot and Welte, 1984: 152). This is indicative of the good organic matter preservation of the Posidonia Shale. An exception here is the outcrop NWG-gas shale sample, which displays a high OI value due to weathering. An excellent maturity trend (for type I or I-II kerogen) is displayed by the HI versus vitrinite reflectance trend (Fig. 3.3b) and can be expressed as 퐻퐼 = 1910푒1.829 푉푅푟 . The trend suggests that hydrocarbon generation, as well as progress of vitrinite reflectance are constant processes during maturation and that there are no “coalification jumps” with respect to these parameters as suggested for other parameters such as liptinite reflectance (Taylor et al., 1998). 70

In contrast, OI values decrease from the immature to the early mature/peak oil-mature stage strongly and then remain almost unchanged up to the gas shale stage. This implies that a major part of the oxygen is lost at an early stage (e.g. loss of methoxy and carboxy moieties), before or at the onset of major oil generation, whereas another part remains preserved even at high maturities (e.g. oxygen containing PACs, such as dibenzofuranes). This evolution as well as the complete restructuring of liptinite macerals into solid bitumen at about peak oil- maturity (Harderode sample in our study) suggests, that other parameters/processes are less continuous than hydrocarbon generation and evolution of vitrinite reflectance.

3.4.3 Maturity and structural changes in kerogen Results from FT-IR measurements reflect the great variability in maturity and related changes in chemical composition (Lis et al., 2005; Steemans et al., 2010). Due to an increase in maturity, the organic matter within organic-rich rocks will be defunctionalized. Accompanied is a relative decrease in aromatic moieties well visible in the FT-IR spectra (Fig.8) for the range of 0.5 - 1.4 % VRr, which is not described in other studies (Behar and Vandenbroucke, 1986). For the high mature gas shale samples, a final increase of aromaticity was measured. Furthermore, a relative decrease of the C=O bond as compared to the C=C bond is observed, fitting well to published trends (Yule et al., 2000; Vandenbroucke and Largeau, 2007). The NWG-gas outcrop shale, however, displays a much stronger contribution of C=O bonds than the gas shale from a well at the same maturity level. This reveals that even at high levels of maturity when kerogen has reached an anthracite-like structure strong oxidation can affect organic matter due to weathering. Oxidation of kerogen at different levels of maturation has also been described by Petsch et al. (2000).

A similar evolution is deduced from CP-Py-GC-MS, where a decline of the ratio of aromatic over aliphatic compounds is observed with increasing maturity within the oil window. Only at higher maturity, this trend is reversed and the aromatic/aliphatic ratio rises towards highly overmature conditions. This trend is very pronounced for a pyrolysis temperature of 920 °C, whereas for the lower pyrolysis temperature of 650 °C, the aromatization towards very high maturities is not observed. Possibly aromatic compounds are not released from the anthracite- like material at the low pyrolysis temperature and higher temperatures are required. Therefore highly mature samples should be studied also at higher pyrolysis temperature (Bernard et al., 2010; al Sandouk-Lincke et al., 2013). This finding has also implications on the widely 72 applied Rock-Eval pyrolysis method, which should be modified for specific needs such as gas shale studies (Romero-Sarmiento et al., 2016).

3.4.4 Maturation products and kerogen cracking The results from CP-Py-GC-MS analyses indicate a predominance of n-alkanes produced from the Posidonia Shale over a wide range of thermal maturity. But at the early stages of maturation, e.g. in immature samples, a removal of aromatic and especially oxygen containing compounds from the kerogen (Rullkötter et al., 1988; Schenk et al., 1990) is observed. Especially during the early stages of maturation hetero-compounds will be expelled, leading to a loss of oxygen and C=O oxygen bonds which can be detected by infrared spectroscopy (Tissot and Welte, 1984; Durand, 1985). Whereas immature samples generate and expel light aromatic compounds as well as aliphatic compounds at low pyrolysis temperatures of 650 °C in large amounts, more mature samples within the oil window generate primarily longer chain aliphatic compounds. This surprising effect is extremely predominant in samples within the oil window, where the majority of expelled products are

C10-C18 n-alkanes (Fig. 3.5a-c). The range and chemical properties of the expelled products can of course vary, e.g. the sample from the UK generated large amounts of carbonyl compounds, probably hinting at a more oxygen-containing kerogen due to depositional environment or weathering for this particular sample. This has to be recognized, as slight changes in depositional environment or kerogen type might take a strong influence on pyrolysis products.

If higher pyrolysis temperatures are applied, further pyrolyzation products can be observed, as alkenes are present within the chromatograms. These alkene compounds are, however, absent in the chromatograms of the overmature gas shale samples, indicating that kerogen conversion has progressed so far, that not enough aliphatic kerogen compounds are available for the elimination leading to alkenes (Sunburg, 2010).

3.5 Conclusions The structure of organic matter within a source rock is strongly linked to thermal maturity.

Here, Posidonia Shale representing immature (0.5 %VRr) to highly overmature gas shale (3.0 73

%VRr) stages has been systematically investigated. Especially analysis on very high mature samples has not been the focus of past research and were presented and evaluated here.

Hydrogen Index (HI) values follow a well-defined trend that can be expressed as 퐻퐼 = 1910푒1.829푉푅푟. This trend is valid both for whole rock and kerogen concentrate samples (Fig.

3.3b, 10a). In contrast, evolution of Tmax, OI and PI values is less uniform and there are significant differences observed between values from kerogen concentrates and whole rock samples. Tmax values tend to be higher for whole rock samples, especially during the peak oil or late oil/early gas stage. OI values, in contrast, are significantly higher in low mature whole rock samples (as compared to kerogen concentrates) due to presence of thermally instable carbonate. This effect diminished at high maturity levels (Fig. 3.10b). OI values decrease strongly in the immature/early mature stage and then remain quite stable (at low level) up to the gas shale stage. PI values of surface near core and outcrop samples seem to be diminished due to low pressures as compared to deep samples, for which higher values are recorded.

Complementary CP-Py-GC-MS and FT-IR analyses revealed a more detailed insight into the chemical composition of the shale samples as well as its modification during thermal alteration. CP-Py-GC-MS results illustrate a decreasing trend to lower aromaticity for a maturity range from 0.5 to 1.4 % VRr, which was not observed in earlier publications. For highly overmature gas shales (>2.7 % VRr), a reverse shift towards higher aromaticity is observed, in accordance to published results. This general behavior is supported additionally by FT-IR analyses pointing to a first reduction of aromatic moieties but lastly to a relative increase. FT-IR analyses gave evidence (also supported by Rock-Eval pyrolysis), that defunctionalization processes occur during thermal alteration, removing hydrogen and oxygen containing moieties. Lastly, alkenes released by pyrolysis are only visible at higher pyrolysis temperature suggesting that elevated energies are needed for eliminating alkenes from the Posidonia shale kerogen. However, pyrolytic alkene formation (as indicated by the alkene/alkane ratio) in correlation with thermal maturity showed a maximum around 1.4 %

VRr.

Weathering, present in one outcrop sample, results in a strong increase of oxygen index values, even for highly overmature gas shale samples with anthracite-like organic matter, which is visible by FT-IR, through an increase in C=O bonds, as well as by OI values from Rock-Eval pyrolysis (see also Petsch et al., 2000). 74

It is noteworthy that the analysis of highly overmature gas shale samples added information on kerogen evolution of Posidonia Shale at the high end of maturity that has often been neglected in past studies on this matter.

4 The Posidonia Shale of Northern Germany – Unconventional oil and gas potential from high resolution 3D numerical basin modelling of the cross-junction between the Eastern Lower Saxony Basin, Pompeckj Block and Gifhorn Trough

4.1 Abstract A high resolution 3D numerical basin model, incorporating the eastern part of the Lower Saxony Basin (LSB), the Gifhorn Trough and parts of the southern Pompeckj Block was built to reconstruct the thermal and structural evolution of this area. The estimation and calculation of the unconventional oil and gas resource density within the Posidonia Shale source rock unit was the main objective of this study. Incorporating organic-geochemical data for the Posidonia Shale source rocks units such as compositional petroleum generation kinetics data, allowed for a more accurate prediction of hydrocarbon potential as compared to large scale models of the area, as well as a better prediction of bulk adsorption capacity and adsorbed gas content. For the proper calculation of oil and gas contents within the source rock lithologies, mineralogy and physical properties of the rocks, such as compressibility, sorption capacity and porosity are important as well as organic matter quantity, quality and thermal maturity. These properties in turn are strongly dependent on the vastly different burial/uplift histories within the LSB, Gifhorn Trough and the Pompeckj Block. The Gifhorn Trough, large parts of the Pompeckj Block and the flanks of the LSB are interesting concerning the unconventional oil potential, with current source rock maturities between 0.65-1.2 % vitrinite reflectance. Central parts of the LSB and small parts of the Pompeckj Block show inherent unconventional gas potential. Methane adsorption capacity is influenced by the burial/uplift history of the basin, which stresses the importance of structural and geochemical interlocking in understanding unconventional hydrocarbon systems.

4.2 Introduction Due to the ongoing need of fossil fuels and following the “shale gas boom” in the US, areas around already exploited German oil fields and potential oil shale plays have been the target of re-evaluation and further investigations. Promising formations for unconventional gas production are Palaeozoic strata, including the Namurian Upper and Lower Alum Shale (Uffmann et al., 2012; Uffmann and Littke, 2013) and the Pennsylvanian sedimentary rocks and coals (Bruns et al., 2013; Bruns et al., 2014). Mesozoic strata, including the Lower 77

Jurassic Posidonia Shale (Bruns et al., 2015; Mohnhoff, 2016) are key horizons and will be the focus of this work. It has to be kept in mind that the Lower Cretaceous Wealden Shales (Berner et al., 2010; Rippen et al., 2013) are also of interest due to their thickness and organic richness. Although unconventional shale oil and shale gas production are currently legally banned in Germany, investigations into the geological petroleum potential within known German oil producing provinces can be beneficial, as there is still much untapped potential within these areas and since the unconventional resources within the basin are poorly constrained so far. One advantage in this respect is the detailed study of the main Mesozoic source rock, the Posidonia Shale, based on shallow cores taken just south of the petroleum- bearing basin in the Hils Syncline at different maturities, ranging from immature to overmature (Rullkötter et al., 1988; Littke et al., 1988, 1991; Horsfield and Düppenbecker, 1991; Frimmel et al., 2004; Horsfield et al., 2010).

To assess the potential resources on a large scale, 3D numerical basin modelling can be a powerful tool. Previous studies in the region either focussed on a wider area employing sorption and organic geochemical data (Bruns et al., 2015) using a 1000x1000 m cell grid and employed the source rock formation as homogenous strata, or focussed on only the Western LSB considering also the Wealden source rock with a higher resolution of 150 x 150 m (Mohnhoff et al., 2015). Other studies focussed primarily on the modelling of geochemical and sedimentological aspects of oil reservoirs within the Gifhorn Trough (Blumenstein- Weingartz, 2012; Schwarzkopf and Leythaeuser, 1988).

In this study, the focus is set on the Toarcian Posidonia Shale and its conventional oil as well as unconventional shale oil potential. Using high resolution 3D numerical basin modelling (150 x 150 m horizontal resolution, maximum of 400 m vertical resolution) coupled with compositional petroleum kinetics of the Posidonia Shale, the aim of this study is to assess the quality and quantity of hydrocarbons generated within the study area which is situated at the intersects between the eastern LSB, the Gifhorn Trough and the southern Pompeckj Block (Fig. 4.1), all being part of the Central European basin system (CEBS) (Littke et al., 2008). 78

Figure 4.1: Palaeogeographic map of the southern margin of the CEBS during the Coniacian to Maastrichtian with locations of inverted areas and post inversion deposits (after Voigt et al., 2008), with the study area marked in black. The red line marks the profile location illustrated in Fig. 4.2 and the red circles mark the well locations of the calibration wells illustrated in Fig. 4.3.

4.2.1 Stratigraphic Framework Lower Saxony Basin

The LSB is a sub-basin of the CEBS and is located in Northern Germany, bordering the Pompeckj Block to the north and northeast, the Central Netherlands Basin to the west, the Cretaceous Münsterland Basin to the south and the Gifhorn Trough and Harz Mountains to the east. Deposition in the LSB, as a part of the CEBS, started in the Palaeozoic (Warren, 2008). Mostly terrigenous sediments were deposited during the Pennsylvanian and Early Permian, first in a tropical humid climate leading to abundant coal deposits, later in an arid climate (Rotliegend), when strong pyroclastic and ignimbrite volcanism affected the area. This initial rifting stage of the CEBS was followed by alternating shallow marine to terrigenous deposition from the latest Permian (Zechstein) to the Late Triassic, which lasted until the onset of Jurassic marine sedimentation. During the latest Jurassic/earliest 79

Cretaceous, the paralic to marine Wealden facies was deposited (Rippen et al., 2013). For the rest of the Cretaceous, marine deposition prevailed. While the sedimentation pattern is quite uniform (although with different thicknesses) in the CEBS from the Carboniferous until the Late Jurassic, basin differentiation became pronounced thereafter, with the development of several sub-basins along the southern basin margin. In these sub-basins, strong subsidence during the Early Cretaceous was followed by uplift and erosion in the Late Cretaceous. The LSB is one prominent example for this type of basin inversion (Senglaub et al., 2005, Voigt et al., 2008). Crustal extension across the North Atlantic rift system might have caused this strong basin differentiation (Voigt et al., 2008; Stollhofen et al., 2008), leading to very high sedimentation rates (Littke et al., 2011; Senglaub et al., 2005) which were enabled by strong uplift of other basin elements at the same time (Bruns et al., 2013). After the onset of the Alpine Orogeny, the LSB was subjected to inversion, leading to subsequent erosion (Sirocko et al., 2008; Adriasoloa-Munoz et al., 2007).

Pompeckj Block

The Pompeckj Block can be regarded as a central element within the CEBS, bordering the inverted Central Netherlands Basin, the inverted LSB and the Gifhorn Trough to the west and south, the Ring-Köbing Fyn High and the Central Graben to the North. Sharing a quite uniform sedimentation with the LSB from the Permian until the Middle Jurassic, subsidence for the Pompeckj Block changed drastically during the Late Jurassic. While strong subsidence affected the LSB, the Pompeckj Block experienced uplift and erosion (Littke et al., 2008; Fig. 4.2). This uplift was followed by marine sedimentation during the Late Cretaceous, partly under pelagic depositional conditions. Inversion and erosion of the LSB at the same time contributed to the sediment fill. Thus the Late Cretaceous inversion of the LSB coincided with strong subsidence and sedimentation within the Pompeckj Block and vice versa. The Pompeckj Block also received moderately thick sediments during the Tertiary, when strong sedimentation prevailed in the North Sea area. Salt tectonics affected the Pompeckj block, in particular in its northern part (Schleswig-Holstein area).

Gifhorn Trough

The Gifhorn Trough, a comparably small Rhenish-striking depression, is bordering the LSB to the east and it shares a similar depositional history as the LSB until the Early Jurassic. Rapid sedimentation during the Jurassic due to strong subsidence was related to salt diapirism, leading to the deposition of very thick marine sediments, especially of Liassic and Dogger age. These conditions also favoured the deposition of a very thick source rock sequence of the Posidonia Shale, which can reach up to 100 m thickness in the area of the Gifhorn Trough (Boigk, 1981; Schwarzkopf, 1988; Brink et al., 1992; Betz et al., 1987), whereas it is usually about 35 to 40 m thick in other parts of the CEBS (e.g. Littke et al., 1988). Similarly, thick Dogger β sandstones occur in up to 8 layers with decreasing thickness towards the west of the structure presenting a good reservoir succession. The structural development of the Gifhorn Trough is strongly linked to the Allertal fault line, where the area north of this line has shown a downwards tilt during the Late Cretaceous inversion of the LSB, allowing for the separation of the Gifhorn Trough from the LSB (Blumenstein- Weingartz, 2012). Since the Triassic, salt tectonics strongly influenced the area, continuing until today.

4.2.2 Petroleum Systems in the Central European Basin System (CEBS) The two main petroleum systems in the study area are of Palaeozoic and Mesozoic age. The Palaeozoic system consists of mainly Pennsylvanian coal-bearing gas source rocks and mainly Permian sandstone reservoir rocks covered by Permian claystones or salt (Littke et al., 1995; Gaupp et al., 2008; Bruns, 2014). The Mesozoic source rock units comprise of the Toarcian Posidonia Shale and the Berriasian Wealden shales/marlstones. The Toarcian Posidonia Shale, an oil-prone type-II kerogen with an initially high total organic carbon (TOC) of up to 12 wt.% was deposited in an oxygen-depleted environment and is widespread in central and northwestern Europe (Song et al., 2015). Reservoir rocks are Dogger sandstones but also younger Jurassic and Cretaceous sandstones and carbonates (Betz et al., 1987). The prolific Lias/Dogger group consists of marlstones, carbonates, sandstones and shales, offering the possibility to act as reservoirs, in case of the sandstones and carbonates as well as seals, in case of the marlstones and shales (Kockel et al., 1994).

The Toarcian Posidonia Shale, which is the main horizon under investigation in this study, can be split into three source rock units (I-III; Tab. 1), based on their rock mineralogy and 81 kerogen composition (Littke et al., 1991; Frimmel et al., 2004; Song et al., 2016). The uppermost unit III (Bifrons), comprises mostly calcareous shale and exhibits the highest TOC and HI-values, paired with high thicknesses. The middle unit II (Falciferum), has the lowest initial TOC values, but displays similar thicknesses as the overlying unit III. The lowest unit I (Tenuicostratum) has a similar TOC as unit II and is highest in carbonate content, but its initial thickness is the lowest compared to the other two Posidonia Shale units. This relation between the different Posidonia Shale units is of course subject to variable depositional conditions within the study area, especially due to differences in water depth and (salt diapirism-induced) subsidence rates. Overall, greatest thicknesses are reached in the Gifhorn Trough.

4.2.3 Petroleum Generation Kinetics During burial, due to excess compaction pressure and increasing temperature, organic matter is thermally degraded. The rate of this degradation is controlled by several factors, including the exposure time of the kerogen (organic matter) to a productive temperature and kinetic reaction parameters for this thermal degradation (di Primio and Horsfield, 2006; Welte et al., 1997). Petroleum generation kinetics can either be implemented into petroleum system and basin modelling as bulk petroleum kinetics or as compositional petroleum kinetics. Whereas bulk petroleum kinetics are more frequently used in sedimentary basin modelling for the prediction of petroleum generation, rate and timing (Tissot et al., 1987; Quigley et al., 1987; Ungerer, 1989; Pepper and Corvi, 1995), compositional petroleum kinetics offer a more complete assessment of timing and production of petroleum within sedimentary basins (Espitalié et al., 1988; Béhar et al., 1992, 1997; Sweeney et al., 1992, 1995; Dieckmann et al., 1998; Vandenbroucke et al., 1999). The first publication of petroleum kinetics for the Posidonia shale was by Schäfer et al. (1990), while Schenk and Horsfield (1998) first showed that a kinetic approach for marine type II source rocks such as the Posidonia Shale is valid. The appraisal of generation rate and timing is of utmost importance for the determination of the conventional/unconventional potential, as well as for the assessment of oil and gas in place in corresponding reservoir systems.

Figure 4.2: Profile through the transition zone between the Pompeckj Block in the north and the Lower Saxony Basin in the South. The three time steps shown are the Middle Jurassic, Late Cretaceous and present day (from Littke et al., 2008).

4.3 Methods

4.3.1 Bulk Geochemistry Bulk geochemical measurements, including the measurement of TOC and Rock-Eval pyrolysis were conducted following the methods described in Stock and Littke (2016) for Posidonia Shale samples from three wells from the Hils Syncline, namely Wickensen, Dohnsen and Harderode and were integrated using mean values illustrated in Table 1.

4.3.2 Compositional Petroleum Kinetics Compositional petroleum kinetics measurements were conducted using a two-stage approach described in Düppenbecker and Horsfield (1989). For the first stage, kerogen decompositional data were obtained from non-isothermal open system pyrolysis, described by Burnham et al. (1987), heating the samples at 0.1°, 0.7° and 5°C/min and using a Green River Shale sample as a standard, allowing for the determination of the degree of kerogen conversion.

The second stage consists of two procedures, one for the determination of the hydrocarbon composition and one for the degree of conversion, using a closed system approach. The first step included the Microscale Sealed Vessel (MSSV) pyrolysis technique described in Horsfield et al. (1989). Following this method, duplicate aliquots were sealed in glass capillary tubes and heated at three different heating rates in a device described by Schäfer et al. (1990) to facilitate heat and mass transfer.

MSSV measurements, using one aliquot, which was cracked open in a helium-flashed furnace at 300°C, allowed for the quantification of C1-C26 n-alkanes, C14-C20 isoprenoids as well as methyl-alkanes, mono-aromatic and di-aromatic hydrocarbons. For the correct identification, the products were compared with reference internal standards using a single internal gas chromatographic step. A second step, done with duplicate aliquots, using the same setup, but keeping temperatures at 300°C and raising the furnace temperature during the run up to 600°C, allowed for the determination of the pyrolysis products from the residual kerogen in a single peak. 84

The results presented here are summed up for four different ranges, of C1 (Methane), C2-C5,

C6-C14 and C15+ using resolved (valley-to-valley) peaks. The gas/oil ratio was determined by dividing the C1 and the C2-C5 components by all other components (C5+). Although a more exact petroleum phase analysis of up to 14 compound groups is possible (di Primio and Horsfield, 2006), a simplification into the above mentioned compounds allows for a detailed enough analysis of the hydrocarbons liberated from the Posidonia Shale. The numerical determination regarding the activation energy and frequency factors were conducted using the program Kinetic 2000 at the GFZ Potsdam, allowing for discrete distribution of activation energies and a single value of the pre-exponential factor. The compositional petroleum generation kinetics used for this model were the ones published by di Primio and Horsfield (2006), and compared to results obtained on Posidonia Shale samples from the more mature wells Dohnsen and Harderode from the Hils Syncline.

Here, temperature and time are the driving properties to predict petroleum generation. Within a sedimentary system, temperatures affecting and influencing sedimentary sequences usually range between 50 and 300°C, where the reactions are predominantly kinetically controlled.

4.3.3 3D Numerical Basin Modelling & Calibration Hydrocarbon generation and storage potential of the Posidonia Shale was calculated in a 3D numerical basin model using the Schlumberger AaTC Petromod© software v.2014.1. This software operates on the basis of forward modelling techniques, allowing for the reconstruction of geological events such as sedimentation and erosion in combination with geochemical and petrophysical processes running simultaneously. The study area is defined through grid cells with a resolution of 150 x 150 m to which the inherent properties are assigned and for which the calculation results from the progressive forward modelling are given as the model output. This output information includes rock properties such as temperature, compaction, thermal maturity of source rock and other units, total/effective porosity, hydrocarbon generation and expulsion, fluid flow, hydrocarbon composition and adsorption capacity (Bruns et al., 2015; Mohnhoff et al., 2016). The model was calibrated using 267 wells within the study area, which were assessed based on their quality of data, assigning unreliable temperature data (e.g. fluorescence based temperature) a lower weight and reliable temperature or maturity data (e.g. vitrinite reflectance) a higher weight. Based on these wells the amount of erosion and heat flow within the study area were determined, and the 3D basin model calibrated (Fig. 4.3a, Fig. 4.3b-I, Fig. 4.3b-II). The calculation of vitrinite reflectance used in this study is based on the Easy-Ro approach by Sweeney and Burnham 85

(1990), utilized by an algorithm in PetroMod that enables calculation of a range of vitrinite reflectance between 0.3-4.6 % VRr based on temperature history. Additional properties which are important for the validation and the assessment of the basin model, such as total/effective porosity, thermal maturity, hydrocarbon generation and migration, petroleum composition and adsorption capacity, as well as oil and gas potential are determined based on the calibration and the basic simulation results obtained for each cell within the study area.

The thermal state of the basin depends on the basal heat flow, the surface/water interface temperature (SWIT), the thermal conductivity of the different lithologic units and radiogenic heat production inside the sedimentary system as well as convective processes. The average heat flow of the continental crust at present is close to 60 mW/m2 (Allen and Allen, 2013). In reconstructions of palaeo heat flows, often high values are assumed for rifting phases, when the mantle/crust boundary is at shallow depth, declining thereafter over periods of 50-100 million years until a constant heat flow is again achieved (Waples, 2001). The sediment/water interface temperature depends on palaeobathymetry and palaeolatitude as well as ocean currents, which are usually neglected in basin models. The PetroMod Software utilizes global mean surface temperatures, based on values from a palaeogeographic reconstruction by Wygrala (1989) with special emphasis on palaeogeographic latitude. Additional information concerning the SWIT were gathered and implemented from Kockel (2002), Miller et al. (2005) and Littke et al. (2008).

4.3.4 Model Outline Comprising of the eastern part of the LSB, parts of the southern Pompeckj Block and the Gifhorn Trough, the study area extends 135 km in an east-west direction and 113 km in a north-south direction, covering a total of 15255 km². The model consists of 18 layers, describing Triassic to Quaternary sediments. The depth horizons for these layers were taken from a digitized version of the Geotectonic Atlas of NW-Germany by Baldschuhn et al. (1996). The resolution of the model is restricted to a maximum cell size of 150 x 150 m, with a maximum vertical resolution of 400 m, although it is primarily defined by the individual layer thickness. As a basement structure, a Palaeozoic basement with a thickness of roughly 2000 m has been assumed.

Since the Toarcian Posidonia Shale represents the horizon which is of most interest in this study, modifications regarding its resolution within the model were made, allowing for a 86 higher resolution and a more accurate lithology of the Posidonia Shale within the study area. The chosen study area represents an extension of the model created by Mohnhoff et al. (2016) and fits in the scope of work by Bruns et al. (2013, 2015). Both works chose different focuses, favouring the Wealden within the western LSB in case of the former, and using a broader resolution for the whole study area for the latter.

Figure 4.3a: Maturity calibration for wells within the Pompeckj Block, Gifhorn Trough and the Lower Saxony Basin, displaying the comparison of measured and calculated vitrinite reflectance within the study area. The exact well location can be found in Fig. 4.1 and the burial history in Fig. 4.3b. Vitrinite reflectance calculation according to Sweeney and Burnham (1990). 87

Figure 4.3b-1: Burial history plots of two well locations (calibration wells) marked in Fig.4.3a.

Figure 4.3b-2: Burial history plots of two well locations (calibration wells) marked in Fig.4.3a.

4.3.5 Stratigraphy and Lithology All assigned stratigraphic unis and their depositional ages can be found in Table 2, using the German Stratigraphic Chart (STD, 2016) as a reference, and the corresponding lithologies 89 were compiled from Ziegler (1990). To more accurately account for changes within the lithologies, especially throughout such a big area, slight adjustments were made to the facies, of especially the Posidonia Shale. This led to the use of specifically created lithologies and lithology maps of the Posidonia Shale, since pre-defined lithologies from the Petromod software inadequately described the lithological properties. The individual properties, as well as additional relevant lithological characteristics, such as the amount of radiogenic elements (U, Th, 40K), which are essential for the radiogenic heat production through their radioactive decaying process were taken from a dataset provided in Bruns et al. (2014). Additional properties which are of importance, include the thermal conductivity, the heat capacity and rock-mechanical properties, such as density, initial porosity and the Athy’s factor.

While all these factors are important concerning the integrity of the basin model, the source rock characteristics of the Posidonia Shale are the most important regarding the actual determination of the hydrocarbon potential and petroleum generation. Utilising a threefold subdivision of the Posidonia Shale into three units (I-III), the differences in mineralogical composition as well as slight differences in kerogen composition are accounted for. Mineralogical composition is of importance, having a strong impact on permeability and fraccability, as well as sorption properties for methane (Sone and Zoback, 2013; Gasparik et al., 2014). The main distinguishing parameters for the Posidonia Shale units are the carbonate and clay content, as well as the TOC content. Within the basal unit I of the Posidonia Shale, the highest carbonate contents are achieved, reaching up to 60 wt.% CaCO3, classifying it as an organic-rich marlstone; on average 10 wt.% TOC are present. This unit is usually the thinnest with total thicknesses of up to 8 m and locally up to 20 m within the Gifhorn Trough.

The Posidonia Shale unit II possesses a lower carbonate percentage of up to 40 wt.% CaCO3 and a slightly lower TOC content of up to 9 wt.%. The total thicknesses, however, increases for this unit, depending on the location, reaching a maximum between 16 m in the LSB and Pompeckj Block and up to 30 m in the Gifhorn Trough. Following up, unit III shows similar carbonate contents, classifying it as a carbonaceous shale unit as well as unit II, but averages the highest TOC contents of up to 12 wt.%. Unit III represents the most productive unit of the Posidonia Shale, averaging similar thicknesses as unit II, but has a higher productive potential due to the presence of a higher quantity of organic carbon. Organic matter is predominantly composed of finely dispersed alginite (Littke et al., 1991). The thicknesses of the Posidonia Shale units had to be simplified based on values obtained from Schwarzkopf and Leythaeuser (1988) for the Gifhorn Trough and Frimmel et al. (2004) for the LSB and 90

Pompeckj Block. In reality, the thickness of the Posidonia Shale unit varies more strongly (Song et al., 2015), but small scale variations as recorded in the outcrop area of the Hils Syncline (Littke et al., 1988) are neither known in any detail for the deep subsurface of the basin nor can they be properly incorporated into the large scale model.

Figure 4.4: Maximum erosional thicknesses of the Upper Jurassic erosion event within the study area. 91

Figure 4.5: Maximum erosional thicknesses of the Upper Cretaceous erosion event within the study area. Table 4.1: Maximum thicknesses and bulk geochemical properties of the Posidonia Shale horizons in the study area. Thicknesses in parentheses are maximum thicknesses in the area of the Gifhorn Trough.

Stratigraphic unit Source rock unit Thickness [m] Initial TOC Initial HI [wt.-%] [mg HC/g TOC]

Toarcian Posidonia Shale 16 (30) 12.0 625 unit III (Bifrons)

Toarcian Posidonia Shale 16 (30) 9.0 600 unit II (Falciferum)

Toarcian Posidonia Shale 8 (20) 10.0 625 unit I (Tenuicostratum)

Table 4.2: Stratigraphic age assignment and petrophysical properties of the lithologies used in the 3D basin model.

Stratigraphy Depos Lithologies Thermal Urani Thori Potassiu Heat Density Initial Athy’s itional Conduct um um m [%] Capacity [kg/m3] Porosity Factor k Age ivity at [ppm] [ppm] at 20° [%] [1/km] [Ma] 20° C/2 C/200° C 00° C [kcal/(kg [W/(m* *K)] K)]

Quaternary – 12-0 Sandstone 3.95/2.9 1.30 3.50 1.30 0.20/0.27 2720 41.0 0.31 Middle (typical) 5 Miocene

Lower 23.8- Sandstone 3.31/2.6 1.78 5.20 1.58 0.20/0.27 2716 46.8 0.41 Miocene 12 (typical), Shale 1 (typical)

Rupelian – 34- Sandstone 3.31/2.6 1.78 5.20 1.58 0.20/0.27 2716 46.8 0.41 Upper 23.8 (typical), Shale 1 Oligocene (typical)

Middle 37-34 Sandstone 1.95/1.9 3.22 10.30 2.42 0.20/0.27 2716 46.8 0.41 Oligocene – (typical), Shale 0 Upper (typical) Eocene

Lower 65-37 Sandstone 1.95/1.9 2.54 10.45 2.43 0.20/0.27 2704 64.2 0.41 Eocene (typical), Shale 0 (typical)

Upper 99-98 Limestone 2.90/2.4 1.90 1.40 0.25 0.20/0.27 2680 70.0 0.90 Cretaceous (chalk, typical) 0

Lower 128- Shale (typical), 1.79/1.8 3.46 11.15 2.56 0.21/0.27 2702 67.1 0.78 Cretaceous 99 Sandstone 1 (typical)

Upper 156.6- Shale (typical), 2.18/2.0 2.80 3.34 1.47 0.20/0.27 2690 2690 0.86 Jurassic & 128 Limestone 2 Wealden (chalk, typical), Shale (oganic rich, organic lean, typical)

Middle 178- Shale (typical), 2.54/2.2 2.50 7.75 2.00 0.20/0.27 2710 55.5 0.57 Jurassic 156.5 Sandstone 1 (Dogger) (typical)

Posidonia 180.2- Shale (organic 1.87/1.8 5.95 6.20 1.57 0.21/0.27 2590 70.0 0.86 Shale III 178 rich) 50%, 5 (Bifrons) Limestone (chalk, typical) 50%

Posidonia 182.4- Shale (organic 1.34/1.5 12.76 7.16 1.66 0.22/0.29 2432 70.0 0.86 Shale II 180.2 rich) 60%, 8 (Falciferum) Limestone (chalk, typical) 40% 93

Posidonia 183.6- Shale (organic 1.91/1.8 3.76 7.76 1.78 0.20/0.27 2638 70.0 0.86 Shale I 182.4 rich) 60%, 8 (Teniucostrat Limestone um) (chalk, typical) 40%

Lower 200- Shale (organic 1.79/1.8 3.52 10.94 2.46 0.21/0.27 2698 70.0 08.4 Jurassic 183.6 lean, typical), 2 (Liassic) Limestone (chalk, typical)

Upper 235- Sandstone 2.54/2.2 2.50 7.75 2.00 0.20/0.27 2710 55.5 0.57 Triassic 200 (typical), Shale 1 (Keuper) (typical)

Middle 243- Limestone 2.30/2.0 2.00 4.00 1.00 0.20/0.27 2730 48.0 0.50 Triassic 235 (shaly) 8 (Muschelkalk )

Lower 251- Sandstone (clay 3.35/2.6 1.50 5.10 3.60 0.21/0.27 2760 40.0 0.32 Triassic 243 rich) 6 (Buntsandstei n)

Zechstein 258- Evaporites 6.54/4.1 0.02 0.01 0.1 0.2/0.29 2740 1 uncomp 251 (typical) 8 actable

Palaeozoic 300- Shale typical), 2.16/2.0 2.75 8.59 2.12 0.21/0.27 2674 59.5 0.63 Basement 258 Sandstone 1 (typical), Coal (pure)

4.4 Results & Discussion

4.4.1 Maturity of the Posidonia Shale Units Figure 3 provides basic information on maturity as related to the structural evolution of the basin, displaying 4 wells from within the study area, one located in the Pompeckj Block, one in the Gifhorn Trough and two wells from the LSB. Good calibration data were available, but usually only from few stratigraphic units and commonly from only one stratigraphic unit within the wells (Fig. 4.3a). It is apparent that during basin evolution, two main erosional events, related to stages of rifting and strong basin subsidence in other parts of the basin have occurred. Only the Pompeckj Block was strongly affected by inversion during the Upper Jurassic/Early Cretaceous, leading to erosion within the area. Maturity data there are usually in accordance with present-day burial and temperature, i.e. maximum maturation occurred during the Neogene. Therefore in the model, 0 m erosion was adopted, i.e. a hiatus, in order to keep the model a simple as possible (Fig. 4.4), although it is clear that some erosion has 94 taken place. In contrast there are restricted areas with high maturities of Jurassic and older rocks, which have been attributed to deep burial during the Upper Jurassic followed by strong erosion (Fig. 4.4). This process also partially affected the Posidonia Shale source rock, which, however, is still present in most of the area. An even stronger erosion took place during the Late Cretaceous basin inversion of the LSB and Gifhorn Trough, where up to 6500 m (Fig. 4.5) of sediment were eroded, which is slightly lower than the values calculated by Bruns et al. (2013), Mohnhoff et al. (2016) and Senglaub et al. (2005) for areas slightly further to the west, where maximum erosion reached 6700 to 7200 m according to these authors. The erosional thicknesses for the Gifhorn Trough are, however, considerably smaller, having little influence on the reservoir and source rock thickness within the area. Due to this strong erosional event related to the basin inversion, the highest temperatures and the coinciding point of deepest burial were reached prior to it, during the Late Cretaceous at roughly 89 Ma within the area of the Gifhorn Trough and LSB. Most or all parts within the Pompeckj Block, which were only affected by the first Late Jurassic/Early Cretaceous inversion event, reached their point of deepest burial in recent times, due to ongoing deposition within the area. Due to these regional erosion events and the presence of Zechstein salt diapirs leading to local erosion, the Posidonia Shale is present in roughly 75 % of the area.

The highest thermal maturities achieved for the Posidonia Shale are located within the centre of the LSB (Fig. 4.6), where vitrinite reflectance values can reach over 4 % VRr. There are, however, small parts within the Pompeckj Block, located in the north-west within the study area, where similarly high maturities of up to 2-3 % VRr are achieved. This assumption is based on few maturity data and has to be verified or falsified in future. Also the strong Upper Jurassic/Lower Cretaceous erosion (Fig. 4.4) assumed for this area is based on these few high maturity values and needs to be carefully checked in future. In large parts of the study area however, the Posidonia Shale’s thermal maturity ranges between 0.5-1.2 % VRr (Fig. 4.6). This allows for a prediction of hydrocarbon generation as based on transformation ratios, especially on oil generation. Whereas areas of interest for gas production are usually limited to maturity ranges between 1.2-3 % VRr (except for microbial gas), areas of interest for unconventional oil production are in a maturity range of 0.65-1.2 % VRr and most conventional oils in the LSB and Gifhorn Trough have maturities corresponding to this range (Stock and Littke, 2016). 95

Figure 4.6: Thermal maturity of the three Posidonia Shale units within the study area, based on the Easy Ro approach of Sweeney and Burnham (1990).

4.4.2 Unconventional oil and gas potential and alternative scenarios The present day transformation ratio of the Posidonia Shale (Fig. 4.7) allows for an estimation of unconventional hydrocarbon production potential within the study area. While a transformation ratio of 100 % would imply that all the reacting kerogen within the petroleum system has been converted, it would also imply presence of much gas or exclusively gas rather than oil. This gas would be stored both as “free” hydrocarbons within the pore space, as well as adsorbed on the remaining kerogen. Such a high transformation rate can be found within areas of the LSB and the above described local areas of high maturity within the Pompeckj Block, the latter being subject to future verification or falsification. All other areas, where the transformation ratio is significantly lower, have a remaining potential for further hydrocarbon generation and are mainly characterized by presence of oil rather than gas. Clearly, the amount of generated hydrocarbons exceeds at many places the storage capacity of the oil shale, especially where peak oil generation stage has (almost) been reached and 96 where porosity and permeability are much reduced (Gasparik et al., 2014; Ghanizadeh et al., 2014). Calculations on composition of generated hydrocarbons from the Posidonia Shale (Tab. 3) show that throughout the maturation of the Posidonia Shale, predominantly hydrocarbons of higher chain-length were liberated (C15+), followed by medium-chain hydrocarbons (C6-C14), then volatile short-chain hydrocarbons (C2-C5) and lastly methane. These generated products, however, have been divided into expelled and retained hydrocarbons. Based on the Petromod calculation, higher chain-length hydrocarbons have been dominantly expelled, with a mean total mass of 171601 Mt, whereas only 919 Mt are retained in the formation itself. These values are somewhat lower for the medium-chain hydrocarbons, where 78613 Mt of hcs expelled contrast with 411 Mt that are retained. Similarly for the volatile short-chain compounds, 16991 Mt of expelled hcs compare to 55 Mt retained. This situation is, however, quite different for methane, of which 7837 Mt have been expelled throughout the geological history, but 5571 Mt retained within the source rock. This different situation for methane is on the one hand related to the adsorptive gas content, where methane will predominantly adsorb on kerogen but also on clay minerals (Gasparik et al., 2014; Ghanizadeh et al., 2014), whereas most longer-chain n-alkanes have a lower sorption potential (Maginn et al., 1995). A second reason is that methane-rich gas has been formed as the last group of hydrocarbons and has had less time for expulsion, whereas long-chain products were generated and expelled first.

Nevertheless, hydrocarbon generation at different maturity levels led to predominantly oil generation from the Posidonia Shale (Fig. 4.8; Fig. 4.9), even for the long-chain hydrocarbons, i.e. there is a direct correlation with the transformation ratio. Even the post- peak oil generation mature source rock produced long-chain hydrocarbons (i.e. oil) to a larger degree as compared to short-chain or volatile gas compounds. This feature is related to the character of kerogen within this world-class oil source rock which is dominated by long- chain n-alkanes (Stock et al., 2017).

These hydrocarbon generation and transformation ratio maps and data have been compared to results by Mohnhoff (2016). Concerning the amount of free gas, within the western LSB, 5571 Mt of free and adsorbed gas are present within the Posidonia Shale in the whole study area based on results from this study. If only the eastern LSB is regarded, a similar value of 853 Mt compared to the Mohnhoff (2016) value of 540 Mt results. 97

Table 4.3: Mean compositional hydrocarbon production balance of the Posidonia Shale within the study area.

Methane [mt] C2-C5 [mt] C6-C14 [mt] C15+ [mt]

Retained Expelled Retained Expelled Retained Expelled Retained Expelled

Total 5571.63 7837.35 55.61 16991.67 411.66 78613.75 919.64 170601.24

PS unit 2340.08 3291.687 23.35 7136.50 172.89 33017.77 386.24 71652.52 III

PS unit 1392.90 1959.33 13.90 4247.91 102.91 19653.43 229.91 42650.31 II

PS unit 1838.63 2586.32 18.35 5607.25 135.84 25942.53 303.48 56298.40 I

Figure 4.7: Transformation ratios [%] of the kerogen for the uppermost and lowermost Posidonia Shale unit. Posidonia Shale unit III (top) and Posidonia Shale unit I (bottom).

Figure 4.8: Hydrocarbon generation for two compound classes of liquid hydrocarbons. Generation of C15+ hydrocarbons (top) and generation of C6-C14 hydrocarbons (bottom) combining all three units of the Posidonia Shale. The figure shows the total amount of hydrocarbon generated over time assuming a completely open system. 100

Figure 4.4: Hydrocarbon gas generation maps. Generation of C2-C5 hydrocarbons (top) and generation of methane (bottom) combining all three units of the Posidonia Shale. 101

4.4.3 Implications for unconventional hydrocarbon production within the eastern LSB, the Gifhorn Trough and the Pompeckj Block Several types of unconventional hydrocarbon resources are present within the Central European Basin study area (BGR, 2016). While the Münsterland Basin situated further to the south provides excellent opportunities for coalbed methane exploration and production, the central-southwestern LSB offers opportunities for shale gas production, and the Gifhorn Trough and the eastern and northern rim of the LSB contain potential shale oil plays. While still large parts of the Posidonia Shale are immature in between these areas of interest, the resource potential within North-West Germany is still enormous (Fig. 4.10). Large areas, where the Posidonia Shale is present and not eroded exhibit excellent oil and gas potential. Our calculations provide evidence of generated, expelled and stored gaseous, mid-chain- length and long-chain hydrocarbons over large areas (Fig. 4.8; Fig. 49). Clearly such data based on laboratory experiments need to be tested in future by real data. Nevertheless, we believe that a combination of experimental data obtained under controlled temperature conditions, in open and closed system on specific source rocks with numerical modelling tools is important in the future to understand large scale geological processes.

The expulsion of hydrocarbons from within a hydrocarbon system and the subsequent adsorption are important parameters, especially for the determination of the oil and gas in place in the source rock and for unconventional production. Especially longer chained hydrocarbons are preferentially produced and expelled from a type II kerogen-bearing source rock such as the Posidonia Shale during the maturation from the immature to the oil mature stage. The expulsion of these hydrocarbons is a process that is strongly related to pressure and bed thickness, where the pressure increased, similar to the maturity of the Posidonia Shale, strongly until roughly 89 Ma ago, when deepest burial followed rapid sedimentation, possibly leading to overpressure in the LSB and Gifhorn Trough.

Pressure also has a crucial influence on the adsorption capacity, leading to a strong increase with increasing pressures, while temperature has the opposite effect. Clearly outcrop and shallow core/cutting samples (a few hundred meters depth) can provide excellent information on source rock properties in general, but to a much lesser extent on gas storage at depth, because most gas has been lost there. Another major factor for gas adsorption within a geological system proves to be the TOC content (Gasparik et al., 2014, Bruns et al., 2015). Highest adsorption capacities are therefore reached in less mature areas of the Posidonia Shale, where the kerogen has not been thermally degraded to a strong degree due to 102 hydrocarbon generation (Fig. 4.11). The TOC contents and volume percentages of organic matter are about twice as high as compared to overmature Posidonia Shale (Rullkötter et al., 1988). This difference greatly influences adsorption capacity. The reduction in adsorption capacity, however, coincides to an increase in pore space which enhances the storage capacity of free gas within the Posidonia Shale units at high maturities. This is due to the fact that new secondary porosity is created at maturities above peak oil stage within the organic matter particles (e.g. Klaver et al., 2016)

Nevertheless, we find a strong preference of gas accumulation within the Posidonia Shale lithologies. The adsorption of methane is favoured within the organic matter pore space and also on the clay mineral interfaces. High TOC and clay mineral contents are present in the uppermost unit of the Posidonia Shale, whereas the underlying two units contain more carbonate on the expense of kerogen and clay minerals. The calculations of adsorption capacities within the Posidonia Shale show vastly different values for the different areas (Fig. 4.11), indicating a strong impact of sorption capacity on total gas in place. Only a fraction of the gas liberated from the kerogen upon maturation due to primary or secondary cracking will actually be adsorbed by the Posidonia Shale, while most methane will be present within the pore space. Porosity is quite high at low levels of maturation, when primary pore space exists, reaches a minimum within the oil window and increases again at high maturities due to secondary porosity generation within kerogen when also microfractures open (Littke et al., 1988, Klaver et al., 2016). This in turn favours unconventional gas production, as methane is predominant in the pore space, although the Posidonia Shale is a classical type II source rocks, and as porosity and permeability tend to increase during gas generation stage within the Posidonia Shale (Ghanizadeh et al., 2014). 103

Figure 4.10: Hydrocarbon zones of the upper and lower Posidonia Shale units showing the potential for oil, oil/gas (mixed) and dry gas production. 104

Figure 4.11: Adsorption capacity of the Posidonia Shale unit III within the study area in Mton/grid cell. Note the low adsorption capacity along the uplifted/inverted southern margin of the study area.

4.4.4 Conclusion and Outlook The Toarcian Posidonia Shale in North-Western Germany has been proven to be one of the major source rocks and hydrocarbon contributors for conventional oil plays within the CEBS (Boigk, 1981; Schwarzkopf and Leythaeuser, 1988; Kockel et al., 1994; Wehner, 1997; Stock and Littke, 2016), but not yet as reservoir for unconventional oil and gas. Our study provides a first quantitative petroleum system analysis indicating a high unconventional petroleum potential for the Posidonia Shale in northern Germany. However, this finally needs to be proven by well and oil flow tests. The socio-ecological and political problems of unconventional oil production in Europe, mainly related to environmental concerns (Kaden and Rose, 2015; Ethridge et al., 2015), are not part of this study, as only the potential resources available from the Posidonia Shale source rock were evaluated here. 105

The Posidonia Shale units I-III investigated here display some disparities in their productivity. Unit III, with the potentially highest TOC values and a comparable thickness with Unit II, shows the highest theoretical potential for unconventional hydrocarbon production. While the other units also display good inherent qualities for unconventional hydrocarbon production, they might not yield as much as the uppermost unit. From a lithological standpoint, if hydraulic fracturing is to be a concern, the lowest unit I, due to its higher carbonate content and the resulting stronger brittleness presents a more interesting target, although the other units are still quite high in carbonate at about 25-30% on average. The high content of clay within all Posidonia Shale units, however, lowers the strong production potential, as clay is mechanically softer compared to quartz and carbonate.

Both high contents of clay and kerogen/TOC lead to a high adsorption potential for methane within the Posidonia Shale, as both factors tend to enhance adsorption capacity values within a geological system. The source rocks reached their maximum thermal maturity in the Upper Cretaceous at their time of deepest burial (89 Ma) in the central LSB and Gifhorn Trough, while this is different in the Pompeckj Block and on the rims of the LSB. Maximum maturities achieved in the Posidonia Shale range up to more than 4 % VRr in the centre of the LSB. Other areas, especially in the Gifhorn Trough and parts of the Pompeckj Block display maturities which are not higher than 1.2 % VRr and therefore targets for oil generation.

106

107

5 Final Conclusion

5.1 Summary The objective of this thesis was the application of geochemical and petrographical analysis, as well as 3D numerical basin modelling to the study area within NW-Germany, to assess different assumptions made on the geo-dynamic evolution of the area and to predict quantity and quality of conventional and unconventional hydrocarbon accumulations. Using the petrographic and geochemical analyses tools, the main contributing source rock within the area, the Posidonia Shale, could be evaluated regarding its oil and gas potential, its maturity distribution and for the appraisal of oil and gas quality sourced from it. Using this information, the 3D numerical basin model could be calibrated assuming burial and thermal histories and leading to different basal heat flow scenarios and accordingly different scenarios of erosion and sedimentation, which are representative of the major uplifting events affecting the study area. Utilizing compositional kinetic data for the immature Posidonia Shale source, not only the generated amount of the bulk hydrocarbon phase, but amounts and predictions for the different petroleum phases could be obtained, allowing for a more exact validation of liquid of gaseous hydrocarbons within prospective reservoirs or accumulated within the source rock itself. The quality of the liquid and gaseous hydrocarbons expelled from the source rock, where indicators of quality are usually linked to ratios between wet/dry gas and contents of other gases (e.g., N2, CO2), is influenced by many factors, including chemical composition, sulfur content and degree of biodegradation due to a reservoir location at low surface depth (<1500 m). The strongest influence on unconventional hydrocarbons, however, is still the current thermal maturity field, allowing for the liberation of hydrocarbons from the kerogen due to cracking. At sufficiently high maturity secondary cracking of the already liberated hydrocarbons occurs. Therefore, an assessment of the current maturity, the inherent source rock quality and composition is of utmost importance to assess the potential for gaseous and liquid hydrocarbon reservoirs within a geological basin system.

108

A Summarization of the accomplishments achieved in this study, comprises:

I. Assessment of the quality of oils sourced by the Posidonia Shale source rock, regarding their composition and their susceptibility to degradation processes. II. Analysis of the petrographical composition of the Posidonia Shale, further used in predicting the quality of the source rock regarding its hydrocarbon potential. III. A geochemical evaluation of the Posidonia Shale kerogen and the amount and quality of hydrocarbons liberated at different thermal maturities. IV. High-resolution modelling of temperature and burial history of the study area comprising of different sedimentary basin and accordingly different geological histories V. Calibrating the model and compiling erosion maps for major uplifting events with help from the obtained geochemical and petrographical data. VI. The creation of high-resolution maturity maps, transformation ratios and expulsion maps for the Posidonia Shale within the study area.

Analyzing hydrocarbons sourced by the Posidonia Shale offered the possibility to assess oil qualities in reservoirs within the study area. To achieve a sufficient analysis, the oils were subjected to physical, bulk geochemical and detailed geochemical analysis. This allowed for more detailed insights into the physical properties, such as density and viscosity, but also into the composition, such as ratios of aliphatic, aromatic, hetero compounds and sulfur contents. All analyzed oils have been predominantly eing sourced by the Posidonia Shale, an organic- rich marlstone with a hydrogen-rich kerogen, where sulfur usually occurs bound in pyrite and only to a very minor percentage in the organic matter (kerogen). Thus, sulfur contents within the oils sourced by the Posidonia Shale are usually low. Comparing the maturity of the oils with their location within the study area, and the calculated source rock maturities for their location, indicates a good comparability of both parameters. Based on this information, it can be assumed that migration within the study area is usually over short lateral distances, whereas a much higher permeability parallel to the bedding should promote lateral migration within the Posidonia Shale unit. This of course is strongly dependent on the location, since all three basin areas of the Northwest Germany Basin System investigated here, namely the Pompeckj Block, the LSB and the Gifhorn Trough, display different reservoir properties. The 109 analysis of mostly oils sourced from peak to post oil mature kerogen (0.8-1.05 % VRr), also shows that a prevalence of short chain hydrocarbons from cracking definitely starts with the beginning of the post-mature gas window (>1.2 % VRr). Conventional oil accumulations, which can be subject to degradation processes such as biodegradation and water-washing, are potentially at risk if the reservoir depth within the study area is lower than 1500 m. The potential degradation especially affects long-chain n-alkanes, leading ultimately to an unwanted enrichment of hetero compounds and high-molecular weight products.

While the quality and actual presence of hydrocarbons generated from a source rock is one of the most important parameters for conventional hydrocarbon production, unconventional hydrocarbon presence and quality are dependent on other factors. These factors are the chemical source rock composition, e.g. sulfur contents, TOC contents and HI- and OI-values, but to a similar degree the mineralogical composition, e.g. clay and carbonate content. This in combination with the maturity of the source rock mentioned before, either displayed as maximum experienced burial temperature/depth, Tmax or vitrinite reflectance values, allows for the prediction of the unconventional hydrocarbon potential of a source rock. The kerogen, the part of organic matter insoluble and responsible for the generation of hydrocarbons through cracking and elimination processes, changes its chemical composition during maturation and due to the subsequent expulsion of hydrocarbons. With increasing maturation, this will lead to a kerogen with increasing carbon content and decreasing contents of oxygen and hydrogen (and finally nitrogen) due to release of hydrocarbons and other fluids. In addition to the reduction of functional groups of the kerogen, the kerogen composition will gain a more aromatic character, favoring a highly aromatic kerogen at very high maturities (>1.4 % VRr). However, this trend is not uniform, since at lower maturity ranges (0.5 – 1.4 % VRr), the kerogen composition indicates a shift towards lower aromaticity alongside its increasing maturation. Only at higher maturities is this trend reversed. The defunctionalization processes that are responsible for this shift occur during the thermal alteration of the kerogen and are responsible for a reduction in hydrogen and oxygen containing moieties. The resulting hydrocarbons which are liberated, have a strong contribution of long-chained alkanes at low maturities to oil-window maturities. Alkene presence, usually related to higher temperatures needed for the elimination processes and cracking, are only present at higher maturities and show a maximum at 1.4 % VRr. Weathering, similar to in-reservoir degradation processes that affect oils, such as water- washing and biodegradation, can also affect the source rocks/kerogen. The effects, mainly an 110 increase in oxygen containing moieties, illustrated by elevated oxygen index values, can be present at all maturity stages of the source rock, even for gas shale samples with an anthracite-like organic matter.

The utilization of basin modelling and petrographic results display that the study area was strongly influenced by transtentional/extensional and transpressional/compressional tectonic events. Using the present structure of the study area, and combining them with the current maturity and layer thicknesses, one can infer that the area has been subject to different burial and temperature histories within its structural blocks and basins. As this model starts with a Paleozoic basement onwards, we can assume that for the used layers deepest burial and consequently highest temperatures have been achieved in parts either during the Late Jurassic (Pompeckj Block), the Upper Cretaceous (LSB, Gifhorn Trough), or in recent times (Pompeckj Block). The reasons for this maturity pattern can be found in the deep burial and high burial temperatures with a subsequent uplift that affected the area at partially different times, i.e. uplift in the Pompeckj Block but burial and sedimentation within the LSB. The maximal achieved erosion within the study area as a results of the numerical basin model is around 6700 m, being even slightly higher for study areas situated more to the west (Bruns et al., 2013; Mohnhoff et al., 2016) including the strongly buried Piesberg area.

The Posidonia Shale source rock, the main focus during the application of the 3D numerical basin modelling, can be highlighted as one of the prime targets for conventional and unconventional hydrocarbon production within the study area encompassing the Pompeckj Block, the LSB and the Gifhorn Trough. The different units of the Posidonia Shale (here unit I-III), all present excellent source rock properties, but show also certain disparities, either in organic matter content and composition or in their mineralogical composition. As especially the different mineralogical composition of a source rock plays a strong role on its suitability for unconventional hydrocarbon production, this has to be kept in mind. The highest unconventional potential can be found in the uppermost unit III, where the highest TOC values in combination with highest thicknesses (up to 30 m) can be found (Tab. 4.1). Based on the calculated production balance of this unit it is also the most productive, contributing almost 45 % of total hydrocarbon production from the Posidonia Shale (Tab. 4.3). While units II and I are not as productive if compared to unit III, they are still very good source rock units, still accounting for roughly 55 % of the potential petroleum resources within the study area. For unconventional production purposes unit I could even be the most interesting, due to its high carbonate content which increases brittleness, a property strongly sought after in a 111 potential unconventional reservoir as it enhances its suitability for hydraulic fracturing. Methane adsorption, however, is lower in unit III, as higher clay and TOC contents favor the adsorption of methane within a lithological unit.

Maturities of the Posidonia Shale (Fig. 4.6) show great variations throughout the study area. Especially the center of the LSB, where the highest maturities within the study area were achieved with values of up to 4 % VRr, and parts of the Pompeckj Block show sufficient maturities for gas production. On the other hand, large parts of the Pompeckj Block, the Gifhorn Trough and the rims of the LSB are suited for oil production, either due to an early mature or oil mature character of the Posidonia Shale source rock in recent times. If combined with the transformation ratios of the source rock units within the area, these areas still present an inherently great potential for conventional and unconventional oil production.

5.2 Final Remarks and outlook As the results presented here, with the exception of the petrographical and geochemical data are the results of a numerical basin model, the results especially of chapter 4 are strongly dependent on the quality and amount of input and calibration data. Even though several simulation runs were performed to achieve the results presented here, it should be noted that this is just a possible scenario for the structural evolution and the thermal reconstruction. If more well data, either through more conducted measurements on the cores or wells, such as porosity, gamma ray or resistivity measurements could be made available, the accuracy in the predictive properties of the model would be further enhanced. In addition to the aforementioned limitations, due to the nature of available calibration data being focussed in already well known petroleum areas, less prospected areas are underrepresented, leading to a further limitation on accurately predicting petroleum resources in less known areas.

Another factor that has to be considered in the evaluation of the results from basin modelling offered here in this study, is the heterogeneity of the facies distribution of the Posidonia Shale. More well data, especially concerning the thickness and mineralogical distribution would be invaluable in increasing the accuracy of the model and in incorporating strong local variations of the source rock, in either potential (TOC, HI), or reaction kinetics of the kerogen with increasing lateral distance from measured well data. This would further help in forecasting strong facies variations that have a strong influence on production properties of unconventional petroleum plays, where brittleness and adsorption properties play a strong 112 role. More available subsurface data, especially related to geometry of reservoir and locating and incorporating fractures into the system would further improve and aid in the assessment of petroleum migration pathways, seal integrity and susceptibility to hydraulic fracturing.

While information on the geochemical composition of oils from the study area have been provided here, further petrographical and geochemical analysis was conducted on source rock samples from analogue samples of the Posidonia Shale from the Hils Syncline, further access to samples and data on oil quality locally produced in Germany is limited. This is due to the governing laws in Germany where exploration and prospective results don’t have to be published. Access to data bases from petroleum producers in Germany would additionally improve our current knowledge of the Posidonia Shale, although a lot of research has been conducted by public research institutes such as the LBEG, the BGR, the German Research Center Jülich, the GFZ Potsdam, and the RWTH Aachen University.

It should finally be mentioned, that the modelling software itself, PetroMod©, is restricting the possibilities in incorporating all the details necessary to describe a petroleum system in a holistic way. It’s currently just not possible to know to a final extent how all the factors and properties of geological rock formations interact with each other and how strong of an influence each parameter has.

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7 Curriculum Vitae Alexander Thomas Stock

______Im Johannistal 6 • 52064 Aachen, Germany [email protected] • +49 176 32095022

Work experience/Internships

August 2013 - Research assistant at RWTH Aachen University, Institute of November 2016 Geology and Geochemistry of Petroleum and Coal (GGPC)

Areas of Interest: Petroleum geochemistry, organic petrography, source rock evaluation, numerical basin modelling

December 2015 - Visiting scientist at GFZ Potsdam, Section 3.2 Organic February 2015 Geochemistry

Area of Interest: Petroleum kinetics and pyrolysis

June 2013 – Technical Assistanc at Velden Sicherheitstechnik GmbH July 2013 (Velden security-technics GmbH)

December 2010 – Student Assistant at RWTH Aachen University, Institute of January 2013 Geology and Geochemistry of Petroleum and Coal (GGPC)

July 2008 – Student internship in reservoir technics at the open-mining September 2008 pit Hambach, RWE Power AG,

Academic education

August 2013 – PhD student at RWTH Aachen University approx. Area of research: Geology and petroleum geochemistry of October 2017 marine source rocks and reservoirs

October 2010 – M.Sc. Applied Geosciences, RWTH Aachen University January 2013 (Grade 1.6 (German); Grade B) 134

Master thesis, in cooperation with Loesche GmbH: Petrology of lignites with special emphasis on briquetting (Grade 1.0 (German); Grade A)

October 2007 – B.Sc. Georessources Management, RWTH Aachen September 2010 University (Grade 2.3 (German); Grade B)

Software-/Language-skills EDV/Analytical skills  MS Office (Excel, Powerpoint, Access, Publisher  Schlumberger Petrel; Schlumberger Petromod  SMT Kingdom Suite  Atlas CDS, Thermo Xcalibur, AMDIS  Perkin Elmer Spektrum  ARC GIS, QGIS

Softskills  Scientific writing and presenting (German & English)  Presentation techniques

 Integrative work in a multicultural and multi-ethnic work environment

 Supervising and managing of scientific work and projects

Languages  German (native language)  English (fluent)  French (basic knowledge)

Relevant scientific publications Stock, A., Littke, R., 2016. Geochemical composition of oils from the Gifhorn Trough and Lower Saxony Basin in comparison to Posidonia Shale source rocks from the Hils Syncline, Northern Germany. German Journal of Geology 167.

Stock, A., Littke, R., Lücke, A., Zieger, L., Thielemann, T., 2016. Miocene depositional environment and climate in western Europe: The lignite deposits of the Lower Rhine Basin, Germany. International Journal of Coal Geology 147.