Oil and gas shales of Northern Germany: Implications from organic geochemical analyses, petrophysical measurements 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.

Daniel Mohnhoff

aus Linnich

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

Tag der mündlichen Prüfung: 07. Dezember 2015

Diese Dissertation ist auf den Internetseiten der Hochschulbibliothek online verfügbar

Acknowledgments I

Acknowledgments

First of all, I like to express my gratitude to Prof. Dr. Ralf Littke for giving me the opportunity to pursue a PhD in Petroleum Geoscience at the Institute of Geology and Geochemistry of Petroleum and Coal at RWTH Aachen University. I like to thank him for the valuable input, careful supervision and outstanding support he provided during the course of my studies. Furthermore, I thank Prof. Dr. Brian Horsfield, GFZ, for his work as reviewer of this thesis.

I sincerely thank Dr. Bernhard M. Krooss, Dr. Amin Ghanizadeh and Reinhard Fink for introducing me to the petrophysical analytical procedures utilized in this thesis. Their constant support and the resulting fruitful discussions are much appreciated and deepened my understanding of petrophysics significantly.

A special gratitude goes to Dr. Benjamin Bruns and Dr. Victoria Sachse for their continuous and tireless support regarding the building of a 3D high resolution basin model. In this context, I thank Schlumberger for providing an academic license of the PetroMod software.

I sincerely like to acknowledge and thank my friends, fellows and colleagues at the Institute of Geology and Geochemistry of Petroleum and Coal who accompanied me over the last years and provided an outstanding work environment.

My deepest regards go to my wife Charlotte, who constantly and relentlessly supported and encouraged me during the creation of this thesis.

Dedicated to my family.

Abstract II

Abstract

Based on an increasing demand the recent development of the world energy led to a shift of interest towards the assessment and, partially, exploitation of unconventional petroleum resources, especially in the U.S. Strong advances in well completion technologies such as artificial reservoir stimulation (hydraulic fracturing) and multi-lateral wells enabled the utilization of these previously inoperable assets. Following these initial successes in exploration and production of shale gas in particular, unconventional reservoirs became a prominent target for scientific and commercial investigations worldwide. Exploration and evaluation of shale gas systems, and unconventional hydrocarbon reservoirs in general, are being performed in Europe to potentially increase the domestic hydrocarbon production. In Germany, the main focus lies on organic-rich shale formations that are known to have sourced conventional oil- and gas fields. In this context, the main source rocks investigated are the Mississippian Upper Alum Shale, the Toarcian Posidonia Shale and the Berriasian Wealden shales. Production history and -experience of shale gas in the U.S. showed that a multitude of factors influence the suitability and production performance of low permeable rocks. These factors include (organic) geochemical, mineralogical, petrophysical and reservoir characteristic properties. The organic geochemical component defines the quality and quantity of hydrocarbons generated from these rocks and has a strong influence on the adsorption of gas molecules on particulate organic matter (kerogen). Typical organic geochemical parameters include the kerogen type, total organic carbon (TOC) content and the hydrogen index (HI), which define the quality of a source rock. Petrophysical properties represent critical parameters for the potential storage capacity in intergranular spaces (porosity) of rocks as well as production related factors (permeability). Information on the mineralogical composition allows an estimate of susceptibility to artificial stimulation techniques, while reservoir scaled characteristics provide information on both hydrocarbon generation and storage variability (burial/uplift history, compaction, thermal maturity, facies variation etc.). A multitude of different analytical procedures was performed to gain information on many of these aspects for the Wealden shales and the Posidonia Shale. The main focus was set hereby on the organic geochemical and –petrological inventory of the Wealden shales and the influence of hydrocarbon generation and expulsion/retention on the petrophysical parameters of organic-rich shales using the example of the Posidonia Shale. Based on these findings, a high resolution 3D numerical basin model was established to estimate the amount of adsorbed and free gas in these formations throughout the central Lower Saxony Basin, representing a much more detailed approach than those of previously published studies. The sample suite investigated from three wells from the central area of the Lower Saxony Basin represent a thermal maturity series of the Berriasian Wealden shales ranging from immature/early mature samples from one well to overmature shales in two additional wells. Data Kurzfassung III from vitrinite reflectance measurements are hereby supported by several biomarker ratios. The analyzed samples revealed four intervals which can be described as excellent source rocks of lacustrine origin, comprising type I kerogen, based on organic geochemical and –petrographical analyses. Effects of oil generation and migration is evident from petrographical analyses of the overmature sample sets. Alginite present in the early mature samples, including botryococcus algae of brackish to lacustrine origin, is replaced by an extensive solid bitumen network in the overmature counterparts. Strong small scale heterogeneities of depositional environment are expressed in the variability of source related biomarker inventories throughout the Wealden succession. Pore space evolution in dependence of thermal maturation was studied using a novel flow- through extraction procedure on core samples of the Posidonia Shale from the Hils Syncline, Germany. The subsequent removal of soluble organic matter resulted in a significant increase of porosity and permeability in all investigated samples. Open fractures were generated by this procedure which are predominantly oriented parallel to the bedding of the rocks as determined via organic petrography. Residues of hydrocarbons precipitated from the solvent indicate a flow direction of DCM along these fractures. Analyses of the gained extracts revealed substantially different hydrocarbon compositions at different time steps during the extraction runs. Results from a high resolution 3D numerical basin model of the central Lower Saxony Basin show that adsorbed depends mainly on the source rock quality and burial history of the investigated Posidonia Shale and Wealden shale horizons. The amount of free gas in the pore system is strongly influenced by the sealing capacity of overlying strata.

Kurzfassung IV

Kurzfassung

Die weltweit steigende Nachfrage nach fossilen Energieträgern führte in den letzten Jahren zu einer Erweiterung der Explorations- und Produktionsaktivitäten von konventionell geförderten Kohlenwasserstoffen hin zu unkonventionellen Ressourcen. Vor allem in den USA wurden durch Weiterentwicklungen von Bohrlochkomplettierungsmethoden und künstlicher Reservoirstimulationstechniken (Hydraulic Fracturing) vormals inoperable Reservoire erschlossen. Im Anschluss an diese ersten Erfolge in der Exploration und Produktion von Schiefergas entwickelten sich unkonventionelle Reservoire zu wichtigen Zielen für wissenschaftliche und kommerzielle Untersuchungen weltweit. Exploration und Evaluierung von Schiefergassystemen, und unkonventionellen Kohlenwasserstoffvorkommen im allgemeinen, werden derzeit in Europa intensiviert, um die inländische Produktion von Kohlenwasserstoffen zu erhöhen. In Deutschland liegt der Schwerpunkt der Forschungsaktivitäten auf organik-reichen Schieferformationen, die zuvor konventionelle Öl- und Gasfelder gespeist haben. In diesem Zusammenhang liegt der Fokus der derzeitigen Forschungen auf dem Hangenden Alaunschiefer (Mississippium), dem Posidonienschiefer (Toarcium) und den Wealden-Schiefern (Berriasium). Produktionsdaten von Schiefergasreservoiren aus den USA haben gezeigt, dass eine Vielzahl von Faktoren die Eignung solcher niedrig-permeablen Gesteine zur Kohlenwasserstoffförderung beeinflusst. Diese Faktoren umfassen (organisch-) geochemische, mineralogische, petrophysikalische und Reservoir-charakteristische Eigenschaften. Die organisch-geochemische Komponente definiert die Qualität und Quantität von Kohlenwasserstoffen, die von diesen Gesteinen erzeugt werden können, und hat einen starken Einfluss auf die Adsorption von Gasmolekülen auf partikulärer organischer Substanz (Kerogen). Zu den typischen organisch- geochemischen Parametern gehören der Kerogen-Typ, der organische Kohlenstoffgehalt (TOC) und der Wasserstoffindex (HI). Diese Parameter definieren die Qualität eines Muttergesteins. Petrophysikalische Eigenschaften umfassen kritische Parameter für die mögliche Speicherkapazität in interkristallinen Hohlräumen (Porosität) von Gesteinen sowie produktionsbezogene Faktoren (Permeabilität). Informationen über die mineralogische Zusammensetzung ermöglichen eine Abschätzung zur Durchführbarkeit künstlicher Stimulationstechniken, während Reservoir-umfassende Eigenschaften sowohl Auswirkungen auf die Kohlenwasserstoffgenese als auch deren Speicherung haben (Versenkungs- /Hebungsgeschichte, Kompaktion, thermische Reife, Fazieswechsel etc.). Eine Vielzahl von unterschiedlichen Analyseverfahren wurde angewandt, um Informationen über einen Großteil dieser Aspekte für die Wealden-Schiefer und den Posidonienschiefer zu gewinnen. Der Forschungsschwerpunkt wurde hierbei auf das organisch-geochemische und –petrologische Inventar der Wealden-Schiefer und den Einfluss von Kohlenwasserstoffgenese und - expulsion/retention auf die petrophysikalischen Eigenschaften organisch-reicher Schiefer am Beispiel des Posidonienschiefers gelegt. Basierend auf diesen Ergebnissen wurde ein Kurzfassung V hochauflösendes numerisches 3D Beckenmodell des zentralen Niedersächsichen Beckens erzeugt, um die Menge des generierten, adsorbierten und freien Methans in diesen Formationen abzuschätzen. Die untersuchten Proben aus drei Bohrungen aus dem zentralen Bereich des Niedersächsischen Beckens stellen eine thermische Reifeserie der Berriasischen Wealden-Schiefern dar. Diese umfassen thermisch unreife bis wenig reife Gesteine aus einer Bohrung und überreife Wealden- Schiefer Proben aus zwei weiteren Bohrungen. Daten aus Vitrinitreflektionsmessungen werden hierbei durch mehrere Biomarkeranalysen gestützt. Die untersuchten Proben weisen vier Intervalle aus, die als ausgezeichnete Erdölmuttergesteine lakustrinen Ursprungs eingeordnet werden können, basierend auf der Identifizierung von Typ-I-Kerogen durch organisch- geochemische und -petrographische Analysen. Auswirkungen der thermischen Reifung auf das Gesteinsgefüge durch Erdölgenese- und -migration können aus petrographischen Untersuchungen der überreifen Probenserien abgeleitet werden. Zahlreich vorhandener Alginit in den unreifen Proben, einschließlich Botryococcus Algen aus brackisch-lakustrinem Ablagerungsmilieu, wird durch ein umfangreiches Festbitumen-Netzwerk in den überreifen Gegenstücken ersetzt. Des Weiteren wurde die starke Heterogenität der Ablagerungsbedingungen durch Variabilitäten von Biomarker-Indikatoren in der vertikalen Abfolge der Wealden-Schiefer belegt. Die Entwicklung des Porenraums in Abhängigkeit von thermischer Reifung organik-reicher Gesteine wurde unter Verwendung eines neuen Durchflussextraktionsverfahrens an Kernproben des Posidonienschiefers aus der Hils Mulde untersucht. Die so erzielte Entfernung von löslichen organischen Stoffen führt zu einer signifikanten Zunahme der Porosität und Permeabilität in allen untersuchten Proben. Offene Kluftstrukturen parallel zur Gesteinsschichtung wurden durch organisch petrographische Untersuchungen nach der Extraktion dokumentiert. Fluoreszierende Rückstände von Kohlenwasserstoffen in diesen Klüften weisen auf eine vorrangige Flussrichtung des organischen Lösungsmittels entlang dieser Wegsamkeiten hin. Untersuchungen der gewonnenen Extrakte der jeweiligen Zeitschritte ergaben wesentliche Unterschiede in der Kohlenwasserstoffzusammensetzung im Vergleich zu den Extrakten, die aus den Proben vor und nach den Durchflussversuchen analysiert wurden. Die Ergebnisse aus einer hochauflösenden 3D-numerischen Beckenmodellierung des zentralen Niedersächsen Beckens zeigen, dass die Menge an adsorbiertem Methan im Posidonienschiefer und den Wealden-Schiefern hauptsächlich von der organisch-geochemischen Beschaffenheit und der Versenkungsgeschichte abhängt. Die Menge an freiem Methan im Porenraum hingegen wird stark vom Dichtungsvermögen der überlagernden Deckschichten kontrolliert.

List of content VI

List of content

Acknowledgments ...... I Abstract ...... II Kurzfassung ...... IV List of content ...... VI List of figures ...... VIII List of tables ...... X List of abbreviations ...... XI List of units ...... XIII 1. Introduction ...... 1 1.1. Motivational context ...... 1 1.2. Unconventional petroleum resources ...... 1 1.3. Unconventional petroleum systems in Germany ...... 3 1.4. The Lower Saxony Basin ...... 4 1.4.1. Geography, stratigraphy and structural evolution ...... 4 1.4.2. Petroleum systems of the LSB ...... 5 1.5. The Mississippian Upper Alum Shale ...... 6 1.6. The Toarcian Posidonia Shale ...... 7 1.7. The Berriasian Wealden formation ...... 8 1.8. Structure of this thesis ...... 10 2. Organic geochemistry and petrography of Lower Cretaceous Wealden black shales of the Lower Saxony Basin: The transition from lacustrine oil shales to gas shales ...... 12 2.1. Abstract ...... 12 2.2. Introduction ...... 13 2.3. Methods ...... 16 2.4. Results and discussion ...... 20 2.4.1. Organic matter quantity and quality ...... 20 2.4.2. Thermal maturity ...... 36 2.4.3. Maturity related biomarker analysis ...... 38 2.4.4. Source related biomarker analysis ...... 43 2.5. Conclusions ...... 46 3. Flow-through extraction of oil and gas shales under controlled stress using organic solvents: Implications for organic matter-related porosity and permeability changes with thermal maturity ...... 47 3.1. Abstract ...... 47 3.2. Introduction ...... 47 List of content VII

3.2.1. Samples ...... 50 3.3. Experimental ...... 51 3.3.1. Permeability and flow-through solvent extraction experiments ...... 51 3.3.2. Elemental analysis (TOC and TIC) ...... 55 3.3.3. Rock-Eval pyrolysis ...... 55 3.3.4. TLC-FID compound group analysis of solvent extracts ...... 55 3.3.5. Organic Petrography ...... 56 3.4. Results and Discussion ...... 56 3.4.1. Extractable organic matter (bitumen) - definition ...... 56 3.4.2. Extraction efficiency ...... 57 3.4.3. Extract composition (compound groups) ...... 59 3.4.4. Maturity-related compositional changes ...... 65 3.4.5. He-porosity and permeability ...... 66 3.4.6. Organic petrography ...... 70 3.4.7. Evaluation of observations ...... 73 3.4.8. Mass balance ...... 76 3.4.9. Gas shale equivalent ...... 80 3.5. Conclusions ...... 81 4. Estimates of shale gas contents in the Posidonia Shale and Wealden of the westcentral Lower Saxony Basin from high-resolution 3D numerical basin modelling ...... 83 4.1. Abstract ...... 83 4.2. Introduction ...... 83 4.3. Geodynamic evolution ...... 86 4.4. Methods ...... 87 4.4.1. Model definition ...... 89 4.4.2. Stratigraphy and lithology ...... 89 4.4.3. Source rock characteristics ...... 90 4.4.4. Source rock thickness ...... 91 4.4.5. Kinetic parameters ...... 92 4.4.6. Calculation of gas adsorption ...... 94 4.4.7. Boundary conditions ...... 94 4.4.8. Calibration ...... 96 4.5. Results and Discussion ...... 97 4.5.1. Maturity and temperature evolution ...... 97 4.5.2. Methane adsorption capacity and gas content ...... 100 4.5.3. Alternative scenarios and modelling results ...... 105 4.5.4. Implications for gas production ...... 110 4.6. Conclusions ...... 111 5. Summary and conclusions ...... 114 6. Final remarks, limitations and outlook ...... 120 7. References ...... 123 Curriculum Vitae ...... 137

List of figures VIII

List of figures

Fig. 2-1: Overview map of the Lower Saxony Basin (Bruns et al., 2013)...... 13 Fig. 2-2: Combined stratigraphic charts from Mutterlose and Bornemann (2000) and the Isterberg 1001 well from Berner et al. (2010)...... 15 Fig. 2-3: TOC content (in wt-%) plotted against depth for the analyzed wells...... 21 Fig. 2-4: Total sulfur (TS; wt-%) content plotted against the total organic carbon (TOC; wt-%) content for all samples with normal marine lines (after Berner, 1984)...... 22 Fig. 2-5: Ternary diagram showing the original sedimentary composition of the samples from well Ex-A...... 23

Fig. 2-6: Classification of kerogen type using S2 yields and TOC content (in wt-%) (a) as well as HI and Tmax values (b) derived from Rock-Eval measurements...... 25 Fig. 2-7: Petrographical photographs showing different organic components of samples from Ex-A...... 26 Fig. 2-8: Petrographical photographs of samples from well Ex-B...... 28 Fig. 2-9: Petrographical photographs showing the disperse bitumen matrix (a) and (b) in samples of well Ex-C...... 29 Fig. 2-10: Thermovaporisation gas-chromatograms (fingerprints) of samples from well a) Ex-A, b) Ex-C, and c) Ex-B...... 33 Fig. 2-11: Open-System Pyrolysis GC-FID ...... 35 Fig. 2-12: Comparison between a detailed present-day maturity map of the Wealden derived from basin modeling for the LSB from Bruns et al. (2013) with maturity isolines from Bartenstein et al. (1971)...... 37 Fig. 2-13: General elution order of methylated adamantanes and diamantanes...... 39 Fig. 2-14: Maturity parameters derived from biomarker analysis plotted versus depth...... 42

Fig. 2-15: Crossplot of the ratios pristane/n-C17 and phytane/n-C18 ...... 43

Fig. 2-16: Ternary diagram of C27 – C29 sterane isomers ...... 44 Fig. 2-17: Total ion count chromatogram of sample GASH_1978 ...... 45 Fig. 3-1: Flow-scheme of the experimental set-up for solvent flow-through extraction and gas permeability tests under controlled stress...... 51 Fig. 3-2: Experimental workflow comprising sample preparation, pre- and post-experimental poro-perm tests, solvent flow-through extraction, post experiment bulk extraction and compound group analysis by TLC-FID (IATROSCAN)...... 53 Fig. 3-3: Cumulative flow-through solvent extract (SE) yields and composition of plug Wickensen (a), Harderode (b) and Haddessen (c)...... 58 List of figures IX

Fig. 3-4: Organic compound distribution for sample 10/116 (Wickensen) determined via TLC-FID at n=10 per extract...... 60 Fig. 3-5: Organic compound distribution for sample 10/102 (Harderode) determined via TLC-FID at n=10 per extract...... 62 Fig. 3-6: Organic compound distribution for sample 10/111 (Haddessen) determined via TLC-FID at n=10 per extract...... 63 Fig. 3-7: Average composition of time step extracts...... 65 Fig. 3-8: Apparent permeability coefficients determined with helium (Klinkenberg-plot) for all samples measured...... 67 Fig. 3-9: Microphotographs of sample Wickensen 10/116 before extraction...... 69 Fig. 3-10: Microphotographs of sample Haddessen 10/111 prior to extraction, exhibiting large fracture filling solid bitumen bodies under incident light...... 72 Fig. 3-11: Schematic model of pore space evolution upon maturation of the Posidonia Shale...... 73 Fig. 4-1: Overview map of Germany and the Lower Saxony Basin (modified from Senglaub et al. 2006) with a geological map based on the depth maps of Baldschuhn et al. (1996), utilised for the 3D numerical basin model in this study, and geographical/geological features of the study area...... 85 Fig. 4-2: A SW–NE transect through the Lower Saxony Basin after Littke et al. (2008) ...... 88 Fig. 4-3: Calibration of the modelled and measured vitrinite reflectance data (crosses) of three cells in the northern (A), central (B) and southern (C) part of the study area...... 95 Fig. 4-4: Total erosion thickness map (Late Cretaceous erosion) for the West-Central Lower Saxony Basin...... 96 Fig. 4-5: Present day maturity maps at the top of the source rock horizons Posidonia III, Wealden I and Wealden IV...... 99 Fig. 4-6: Bulk adsorption capacity expressed in tons of methane for the Posidonia Shale units...... 102 Fig. 4-7: Temperature (in °C), gas generation balance (cumulative amount of CH4 generated in t/cell), adsorbed gas content (in t/cell) and adsorption capacity (in scf/t) evolution of the Posidonia III unit through geological history from time of deposition to present day...... 103 Fig. 4-8: Adsorbed gas contents in standard cubic feet of gas per ton of rock for the Posidonia Shale at present day...... 105 Fig. 4-9: Adsorption capacity expressed in tons of methane per cell unit for the Wealden shale units. . 108 Fig. 4-10: Adsorbed gas contents in standard cubic feet of gas per ton of rock for the Wealden shales at present day...... 109

List of figures X

Fig. 4-11: Temperature (in °C), gas generation balance (cumulative amount of CH4 generated in t/cell), adsorbed gas content (in t/cell) and adsorption capacity (in scf/t) evolution of the Wealden II unit ..... 110

List of tables

Table 2-1: Thermovaporisation and Open-Pyrolysis-GC-FID boiling ranges yields...... 30 Table 2-2: Open-Pyrolysis-GC-FID single compound yields as input parameters for determination of kerogen quality and structure using ternary diagrams...... 31 Table 2-3: Isoprenoid and n-alkane ratios determined via gas chromatography. OEP: odd-even predominance. CPI: carbon preference index. Please refer to the text for definitions...... 38 Table 2-4: Compound assignment for Fig. 2-13...... 40 Table 2-5: Maturity parameters and ratios for Ex-A. MAI: methyl adamantine index. MDI: methyl diamantane index. MPI: methyl phenanthrene index...... 41 Table 2-6: Maturity parameters and ratios for Ex-C and Ex-B...... 42 Table 3-1: Petrophysical and elemental geochemical characteristics of source rock samples before flow- through extraction...... 49 Table 3-2: Petrophysical and elemental geochemical characteristics of source rock samples after flow- through extraction...... 68 Table 3-3: Effluent masses and volumes of DCM at 20°C (ρ = 1.3266 g/cm³) and extract yields of the individual sequential steps...... 77

Table 3-4: Extract yields of compound groups for the bulk original sample (SEi), the sample plug after flow-through experiment (SEf), and cumulative sequential extracts (SEt) as well as respective extraction efficiencies...... 78 Table 4-1: Sedimentary thicknesses and organic geochemical source rock parameters for the investigated horizons...... 89 Table 4-2: Stratigraphic age assignment and petrophysical properties of the user-defined lithologies. ... 93 Table 4-3: Assigned Langmuir sorption parameters...... 97 Table 5-1: Parameters critical for production of best producing gas shale plays in the US in comparison with properties of potential gas shale formations in Germany...... 118

List of abbreviations XI

List of abbreviations

BI = Bitumen Index

BRr = Random Bitumen Reflectance C = Carbon Ca = Calcium CBM = Coal Bed Methane CEBS = Central European Basin System CPI = Carbon Preference Index DCM = Dichloromethane E = East

Edes = Desorption Energy EMPG = ExxonMobil Production Deutschland GmbH Fe = Iron FID = Flame Ionization Detector Fig. = Figure GASH = Gas Shales in Europe GC = Gas Chromatography GFZ = GeoForschungsZentrum GIP = Gas in Place GK = Gauss-Krüger H = Hydrogen HC = Hydrocarbon HF = Heat Flow HI = Hydrogen Index K = Potassium LSB = Lower Saxony Basin m/z = Mass-To-Charge Ratio Ma = Million Years MA = Methyl Adamantane MAI = Methyl Adamantane Index MD = Methyl Diamantane

List of abbreviations XII

MDI = Methyl Diamantane Index MeOH = Methanol MPI = Methyl Phenanthrene Index MS = Mass Spectrometry MSSV = Micro Scale Sealed Vessel N = North nL = Maximum Langmuir Sorption Capacity O = Oxygen OEP = Odd Even Predominance OI = Oxygen Index P = Pressure PI = Production Index PWD = Paleo Water Depth pL = Langmuir Pressure R (biomarker) = Rectus S (biomarker) = Sinister S = Sulfur s = Standard Deviation

S1 (Rock-Eval) = Amount of free hydrocarbons generated from the sample

S2 (Rock-Eval) = Amount of hydrocarbons generated from kerogen of the sample

S3 (Rock-Eval) = Amount of CO2 generated from the sample SWIT = Sediment Water Interface Temperature T = Temperature Tab. = Table TH = Thorium TIC = Total Inorganic Carbon Tm = 17α(H)-22,29,30-Trisnorhopane

Tmax = Temperature of Maximum Pyrolysis Yield TOC = Total Organic Carbon TR = Transformation Ratio TS = Total Sulfur

List of abbreviations XIII

Ts = 18α(H)-22,29,30-Trisnorneohopane

Tvap = Thermovaporization U = Uranium U.S. = United States V, v, vol = Volume v. = Version VDF = Variscan Deformation Front vL = Langmuir Volume

VRr, %R0 = Random Vitrinite Reflectance wt = Weight ρ = Density

ρads = Adsorbed Phase Density

List of units

% = Percent ° = Degree µ = Micro = 1*10-6 bar = Bar C = Celsius cal = Calorie D = Darcy g = Gram h = hecto = 1*102 K = Kelvin k = Kilo = 1*103 l = Litre M = Mega = 1*106 m = Meter m = Milli = 1*10-3 n = nano = 1*10-9

List of units XIV mol = Mol Pa = Pascal ppm = Parts per Million scf = Standard Cubic Foot; 1scf = 0.0283 m³ (at 1013.25 hPa and 15 °C) t = Ton W = Watt

Introduction 1

1. Introduction

1.1. Motivational context

In the last decade, the fossil fuel market in the United States of America has changed dramatically. New drilling and well completion technologies enabled the access to oil and natural gas resources from very fine grained rock formations with low natural porosity. While the creation of artificial fluid pathways via hydraulic fracturing was already performed for several decades in conventional hydrocarbon reservoirs, the combination with multilateral wells led to a development of source rock formations as possible natural gas reservoir. A strong focus was hereby set on source rocks of existing, typically well-known, hydrocarbon systems.

Due to the utilization of these domestic unconventional hydrocarbon resources, namely shale gas, the US succeeded in covering its own natural gas demand and developing into a natural gas exporting country. Following this shale gas boom, many countries started reappraisals of abundant source rock formations including China, Russia and the European countries. The aim of this thesis is the characterization of two important source rocks in Germany in the context of meeting the requirements to be regarded as possible unconventional reservoirs while containing liquid (shale oil) or gaseous hydrocarbons (shale gas).

1.2. Unconventional petroleum resources

The term unconventional petroleum resources originally stems from the evaluation of economical feasibility of hydrocarbon reservoirs. While conventional resources are considered as accumulations of petroleum which are relatively easily accessible with standard methods, unconventional resources are defined by the need of more advanced technological efforts to be an economically viable option. These new techniques include hydraulic fracturing, (multi-) lateral wells, directional drilling and reservoir stimulation. Although production from tight reservoirs and coal seams (coal bed methane), where stimulation methods do not necessarily have to be applied, have been referred to as “unconventional” in the past, this classification is solely based on economic decisions (Law and Curtis, 2002). In general, unconventional resources can be described as hydrocarbon plays where standard definitions of petroleum system elements are not

Introduction 2 distinctively divided anymore (Magoon and Dow, 1994). A rock formation regarded as an unconventional reservoir can for example be the source rock, the reservoir and the trapping lithological medium at the same time (e.g. oil- and gas shales).

Especially organic-rich shales, next to coal beds, are addressed as self-sourcing reservoirs, although migration into the rock formation from other sources is possible. The hydrocarbons generated by the kerogen upon thermal maturation can be stored in the shale formation itself either as free hydrocarbons in the pore volume of the rock or, in case of gas, as adsorbed phase on pore walls within kerogen or organic matter. A lithological trapping effect can occur when the shale formation inherits substantially low permeability hence prohibiting the generated hydrocarbons from being expelled. While free hydrocarbons represent the bulk mass of petroleum in oil shales, sorption processes are important factors for the storage capacity in gas shales (Ross and Bustin, 2009). Physical sorption and sorption capacity depends hereby strongly on the pressure and temperature regime as well as on the burial history and water content of the rock formation. Generally, increasing pressure favors the adsorption of gas molecules, while increasing temperature leads to desorption. Due to a steady increase of pressure and temperature with increasing burial depth in a sedimentary basin, sorption capacity and therefore the actual adsorbed mass of gas changes significantly during the burial and uplift history of a gas shale. Detailed calculations on the dependence of sorption capacity to pressure and temperature and hence burial depth have been published in the past by several authors for coals (Krooss et al., 2002; Li et al., 2010; Busch and Gensterblum, 2011; Gensterblum et al., 2013) as well as for shales (Gasparik et al., 2014). The same authors also reported the generally observable competitive sorption behavior of water and gas molecules which is expressed by lower adsorption capacity at increasing water content (Merkel et al., 2015).

While the amount of hydrocarbons present in oil- and gas shales is mainly controlled by porosity and sorption characteristics, mineralogy has a strong effect on the porosity, permeability and production critical properties like frackability. In many cases of producing plays, the term shale is misleading. The comprehensive term “shale” used in this thesis can be subdivided into more detailed lithological descriptions of the rocks spanning from shaly siltstones, mudstones and claystones over siliceous shales, carbonate-rich shales and marlstones to lithologies that even

Introduction 3 contain enough carbonates to be regarded as shaly limestones. Depending on the lithology encountered in an unconventional reservoir, petrophysical properties like porosity and permeability vary significantly. For production purposes, rocks enriched in brittle minerals like quartz and carbonates are favorable for hydraulic stimulation purposes, while large amounts of certain clay minerals reduce the performance of creating artificial fractures (Aoudia et al., 2010).

To assess the quality of a potential oil- or gas shale play, all previously described properties have to be taken into consideration. While there are no standard criteria which can be easily applied to every rock formation considered as possible unconventional reservoir, comparisons to data of already well producing plays can give good indications for a later production stage performance. For this reason, Jarvie (2012) compiled large datasets of the best producing shale gas plays in the US, which reveals the importance of several parameters. These include hydrocarbon generation potential expressed by the total organic carbon content (TOC) and hydrogen index (HI), the free and adsorbed gas content, petrophysical properties like porosity and permeability, geological parameters like gross and net thickness of the respective formations and simplified mineralogical information based on the silica, clay mineral and carbonate content. Additional properties can be found in the list, which are derived from production data like production and first year decline rate.

1.3. Unconventional petroleum systems in Germany

While shale gas plays as well as their industrial and commercial use are very well developed in the US, unconventional resources characterization in Europe can still be classified as being in a stage of appraisal. This is caused by several factors which influence the suitability and development of shale gas plays especially in Germany including environmental concerns, the distribution of strongly populated areas, infrastructural issues, economic evaluations and, in context of this thesis, geologic uncertainties. While hydrocarbon-bearing source rocks are abundant in multiple basins throughout the US, the number of potential oil and gas shale formations in Germany is limited. The most promising targets for potential exploration in Northern Germany include, in descending depositional age, Lower Carboniferous Lower- and

Introduction 4

Upper Alum Shales, the Lower Jurassic Posidonia Shale and the Lower Cretaceous shales of the Wealden formation. Additionally, the Posidonia Shale is also abundant in Southern Germany, including parts of the Upper Rhine Valley and the Molasse Basin. Nevertheless, the majority of exploration activities focuses on the Central European Basin System (CEBS) and, as part of it, the Lower Saxony Basin (LSB).

1.4. The Lower Saxony Basin

1.4.1. Geography, stratigraphy and structural evolution

The Lower Saxony Basin, as part of the Central European Basin System, is located in Northern Germany and spans approximately 400 km in E-W direction and 100 km in N-S direction. Its dimensions and geographical extent are controlled by the surrounding geological structures which also mark the limits of the basin. In the south, the basin is bordered by the Rhenish Massif, a paleo-mountain range of Paleozoic strata which was uplifted during the Variscan orogeny. The foreland basin filling of this orogeny forms the basement of the LSB (Betz et al., 1987). This basement shows signs of structural overprint due to the orogeny in the southern parts, while the northern extension of orogenic influence, the Variscan Deformation Front, is evident in the basin itself. The northern boundary is defined by the Pompeckj Block, a basin where Lower Cretaceous sediments are absent and a regional Albian unconformity is well defined (Petmecky et al., 1999). The same criteria holds true for the East Netherlands High which marks the western margin of the LSB, while the easternmost extension is the Gifhorn Trough. The core part of the basin can be roughly defined as being situated between the German rivers Ems and Weser.

Stratigraphically the sedimentary infill of the Lower Saxony Basin is mainly of Mesozoic age ranging from thick terrestrial Triassic deposits to Jurassic sediments of mainly marine origin to shallow marine and, at later stages, open marine strata in the Early Cretaceous. In the Late Cretaceous a basin inversion induced by the initializing Subhercynian orogeny occurred, leading to substantial uplift and erosion of predominantly Cretaceous strata, locally even affecting deeper stratigraphic units of Jurassic, Triassic and Carboniferous age (Bruns et al., 2013). In the Cenozoic, sediments of Tertiary age are recorded which, probably due to the Pyrenean tectonic influence,

Introduction 5 show signs of erosion starting from the Miocene. Finally, Quaternary deposits occur only in minor thickness throughout the basin (Bruns et al., 2013). Additionally, Late Permian Zechstein salt deposits led to extensive diapirism especially in the eastern parts of the LSB, whereas thicknesses of Zechstein salt are generally low in the western part of the basin. Although these salt diapirs are less common and usually smaller in dimension than those of the Pompeckj Block, they had a major influence on the structural configuration of the LSB, creating onlap and horst structures of overlying strata, accompanied by corresponding fault systems along their flanks (Betz et al., 1987). The main phase of the salt movement in the Lower Saxony Basin can be attributed to the Late Jurassic age when salt pillows and walls formed (Bruns et al., 2013; Maystrenko et al., 2013).

1.4.2. Petroleum systems of the LSB

Next to the occurrence of ore deposits, the Lower Saxony Basin is an important exploration and production area for petroleum and natural gas since the 19th century. Large and economically feasible discoveries have been made in carbonate and sandstone formations of Paleozoic to Mesozoic age. Oil production focuses mainly on clastic reservoirs in the Middle Jurassic, Upper Jurassic and Lower Cretaceous where shales of Albian and Santonian age act as local seals, depending on the geographical region where an appropriate facies was preserved despite the Late Cretaceous basin inversion. These oil reservoirs are believed to have been charged after the basin inversion and probable oil accumulations existing prior to the inversion were drained due to the event (Binot et al., 1993). Next to oil fields, large condensate and natural gas (wet gas) accumulations have been encountered in Jurassic reservoir rocks. Oil-source rock correlations led to the identification of the Lower Jurassic (Toarcian) Posidonia Shale (Lias ε) and, in the western parts of the LSB, the Lower Cretaceous (Berriasian) Wealden Shales (Bückeberg Formation) as viable source rocks for these accumulations. In addition to this entirely Mesozoic petroleum systems, large dry gas reservoirs have been found in Zechstein carbonate sequences where the Zechstein salt provided an excellent seal lithology. These gas fields were charged by thick coal seams known from the Carboniferous (Westfalian) in this area. While a development of coal bed methane (CBM) production from these coals, as an unconventional source of natural gas, is

Introduction 6 considered nowadays, this thesis focuses on the characterization and evaluation of the Posidonia Shale and Wealden Shales as probable oil and gas shales.

1.5. The Mississippian Upper Alum Shale

Although the Mississippian Upper Alum Shale, in combination with the Lower Alum Shale, can be traced from the northern rim of the Rhenish Massif across Northern Germany to the German- Danish border by magnetotelluric measurements (Hoffmann et al., 2001), this shale sequence is of no importance regarding a consideration as a source for unconventional hydrocarbon production due to the very deep burial of this Carboniferous strata in the LSB. Further south however, the Upper Alum Shale occurs at relatively shallow depths in the Münsterland Basin, bordering the LSB to the south, and is therefore included in this thesis to give a complete overview of potential oil- and gas shales in Northern Germany. Detailed investigations of this formation, which also occurs in the Netherlands (Geverik Member) and Belgium (Chokier formation) (Kombrink et al., 2010), have been published recently in terms of an organic- and inorganic geochemical assessment (Uffmann et al., 2012) and gas-in-place estimations using 3D numerical basin modeling studies of the Münsterland Basin (Uffmann and Littke, 2013; Uffmann et al., 2014). Outcrops of the Upper Alum Shale can be found mainly on the northern margin of the Rhenish Massif and the Ardennes where Carboniferous sediments have been uplifted strongly. Abundances south of these paleo-mountain ranges are not recorded due to complete erosion which also affected older stratigraphic units. Additonal outcrops can be found in NE- Germany around the Harz Mountains (Kerschke and Schulz, 2013). The Upper Alum Shale was deposited in a marine environment as part of the foreland basin of the northward progressing Variscan orogeny and thicknesses of the formation vary significantly between the individual localities. The equivalent Chokier formation reaches thicknesses between 20 and 150 m, depending on the location within the Dinant-Theux Basin in Belgium. Thicknesses in Germany increase from the western part of the Rhenish Massif with 50 – 70 m to up to 110 m in the eastern regions. Lithologically, the Upper Alum Shale can be described as a siliceous black shale with varying carbonate contents.

Introduction 7

Although no location is known where the Upper Alum Shale can be still regarded as thermally immature, very high total organic carbon contents (TOC) of up to 7 wt-% and an average of around 3 wt-% in overmature samples combined with the organic facies derived from organic petrographical investigations allow a characterization as excellent petroleum source rock initially containing type II kerogen (Uffmann et al., 2012; Kerschke and Schulz, 2013). A good correlation between microfacies assemblages and TOC contents were found by Nyhuis et al. (2014) for the Chokier formation which attributes the preservation of organic matter more to high sedimentation rates rather than extensive anoxicity. Based on these investigations an original hydrogen index of 500 mg HC/g TOC can be assumed for this source rock formation (Uffmann et al., 2014).

1.6. The Toarcian Posidonia Shale

As the most important source rock for hydrocarbons in the LSB, the Toacrian Posidonia Shale has been studied intensively in the past. The importance is not only defined by its excellent geochemical properties but also by its geographical extent, occurring in eastern England (Yorkshire Basin), the North Sea, the Netherlands, Northern Germany (CEBS and LSB), southern Germany and even in the Paris Basin (Riegel et al., 1986; Littke et al., 1991a; Schwark and Frimmel, 2004). In the LSB, the Posidonia Shale is present where the Lower Jurassic sediments are not eroded due to uplift. In the southern parts, the Posidonia Shale crops out at hill ranges of the Wiehengebirge. The Posidonia Shale was deposited in an epicontinental sea with strong sea level variations through time, resulting in a restricted marine setting during sea level low stand leading to oxygen depletion of bottom waters which favored organic matter preservation (Schmid-Röhl et al., 2002). Thicknesses are relatively homogenous throughout the LSB with around 40 meters in the central basin part. Minor variations occur depending on the paleotopographical features on which the Posidonia Shale was deposited. The formation itself can be subdivided into three separate units depending on biostratigraphical definitions. Based on the occurrence of ammonites, these zones are called tenuicostatum, falciferum and bifrons, which can be determined in all basins where the Posidonia Shale is abundant (Frimmel et al., 2004). Next to this subdivision, Littke et al. (1991a) established a classification of three units based on lithological

Introduction 8 and geochemical parameters for samples from the Hils Syncline, Northern Germany, which more or less correlates with the biostratigraphical definitions. This classification originates from the strong differences in shale composition which defines the lowermost unit as an organic-rich marlstone and the other two units as organic-rich calcareous shales, based on the varying carbonate and organic carbon contents. These changes in geochemical features are directly linked to facies development and sea level changes in the epicontinental setting (Schmid-Röhl et al., 2002). Additionally, this threefold division can also be identified by geophysical logging methods mainly based on gamma ray and deep induction recordings (Mann and Müller, 1988). In the course of this thesis, the division based on Littke et al. (1991a) is utilized because it reflects essential information regarding the source rock quality and reservoir properties of the single units.

The Posidonia Shale is regarded as an excellent source rock for petroleum generation. This assessment originates from evaluation of total organic carbon contents, organic petrographical and –geochemical properties. TOC contents are generally high, reaching up to 14 wt-% in thermally immature sequences with an average of around 10 wt-%, while alginites of phytoplanktonic origin constitute the main organic component of the shales. The abundant kerogen is classified as type II, yielding HI values of around 700 mg HC/g TOC on average as determined by Rock-Eval analyses of several authors (Rullkötter et al., 1988; Littke et al., 1991a; Sundararaman et al., 1993). However, TOC contents and Rock-Eval parameters differ significantly in the aforementioned units, enabling a subdivision based on these properties in the first place.

1.7. The Berriasian Wealden formation

While in the Jurassic sedimentation a marine origin is recorded, terrestrial influence increases in the Early Cretaceous in the LSB. In the Berriasian, sediments of a terrestrial environment are especially encountered in the Wealden formation (also known as German Wealden), caused by a widespread regression at that time (Elstner and Mutterlose, 1996). This formation is characterized by a brackish- to freshwater-lacustrine depositional environment of a lake system with regional extent. Under these conditions, several members of organic-rich lacustrine shales

Introduction 9 were deposited. Although this terrestrial sedimentation prevailed during the Berriasian, several marine transgressions led to vertical sedimentary diversity, expressed by horizons of limestones, mudstones and organic-lean shales, in the Wealden formation. Additionally, the lacustrine shales are regionally confined by sandstones, siltstones and claystones of fluvio-deltaic origin in the east and limestone sequences in the west (Elstner and Mutterlose, 1996). Due to the internal heterogeneity of the entire sedimentary column, a division into six subformations (Wealden 1-6), based on biostratigraphic investigations, is possible. A fully developed freshwater facies was only established in Wealden 1-4, while smaller marine incursion led to a brackish environment from the base of Wealden 3 onwards. Purely marine conditions were established at the base of Wealden 4 for a short time and in the uppermost Wealden 6, when the whole system changed to a marine facies. In the course of this thesis, the term Wealden shales refers to, if not stated otherwise, the organic-rich shales of lacustrine origin in the succession which can be regarded as petroleum source rock based on their organic geochemical and -petrographical composition.

The organic-rich Wealden shale sequences yield high TOC values at immature stages of up to 20 wt-% with an average of around 8 wt-%. The kerogen is regarded as type I as determined by Rock- Eval pyrolysis measurements with HI values reaching up to 900 mg HC/g TOC (Berner et al., 2010). This data suggests that the Wealden shales predominantly generate long chained liquid hydrocarbons upon maturation. Nevertheless, in late mature to overmature stages these components can be transformed to short-chained hydrocarbons (e.g. methane) due to secondary cracking. Organic petrographical properties include the occurrence of an alginite dominated microstructural matrix of planktonic origin and the occurrence of brackish- and freshwater alginites (Botryococcus). Due to the heterogenic nature of these sediments, source rock qualities change periodically within the sedimentary column, subdividing the shale sequences into several source rock horizons with individual thicknesses between 10 and 30 m, interlayered by deposits of mainly organic-lean shales.

Introduction 10

1.8. Structure of this thesis

In Chapter 2 a variety of geochemical and biomarker data is presented and discussed including organic petrographical information to characterize the Berriasian Wealden shales based on samples from three wells in the central part of the Lower Saxony Basin. These analyses have been carried out to geochemically assess the gas shale potential of these organic-rich shales. Chapter 2 has been published in Organic Geochemistry as:

Rippen, D., Littke, R., Bruns, B., Mahlstedt, N., 2013. Organic geochemistry and petrography of Lower Cretaceous Wealden black shales of the Lower Saxony Basin: The transition from lacustrine oil shales to gas shales. Organic Geochemistry 63, 18-36.

Chapter 3 presents a new approach combining organic geochemical analyses with petrophysical measurements on porosity and permeability to determine the influence of hydrocarbon generation and organic residues on the porosity and permeability of organic-rich shales of different thermal maturity. This Chapter has been published in the International Journal of Coal Geology:

Mohnhoff, D., Littke, R., Kross, B.M., Weniger, P., 2015. Flow-through extraction of oil and gas shales under controlled stress using organic solvents: Implications for organic matter-related porosity and permeability changes with thermal maturity. International Journal of Coal Geology 157. 84-99.

In Chapter 4 new basin modelling results on the central Lower Saxony Basin are provided incorporating detailed analyses on the Wealden shales carried out in Chapter 2 with an additional focus on the Toarcian Posidonia Shale. This high resolution 3D numerical basin modelling approach was used to assess the adsorbed and free gas contents of the aforementioned formations in relation to their respective source rock potential. Chapter 4 has been published in the German Journal of Geology (ZDGG) as:

Mohnhoff, D., Littke, R., Sachse, V.F., 2015. High-resolution 3D numerical basin modeling of the West-Central Lower Saxony Basin: Examples of unconventional hydrocarbon resources of Northern Germany. German Journal of Geology (ZDGG) 167 (2-3), 295-314.

Introduction 11

Furthermore, results of analyses carried out during the creation of this thesis on the gas shale potential of the Upper Alum Shale and microfacies analyses of the Belgian equivalent, the Chokier Formation, have been published as:

Uffmann, A.K., Littke, R., Rippen, D., 2012. Mineralogy and geochemistry of Mississippian and Lower Pennsylvanian Black Shales at the Northern Margin of the Variscan Mountain Belt (Germany and Belgium). International Journal of Coal Geology 103, 92-108. and

Nyhuis, C.J., Rippen, D., Denayer, J., 2014. Facies characterization of organic-rich mudstones from the Chokier Formation (lower Namurian), south Belgium. Geologica Belgica 17 (3-4), 311-322.

Wealden black shales 12

2. Organic geochemistry and petrography of Lower Cretaceous Wealden black shales of the Lower Saxony Basin: The transition from lacustrine oil shales to gas shales

2.1. Abstract

Ninety-seven Wealden black shale samples from three wells in the Lower Saxony Basin have been studied by organic geochemical and organic petrographical methods to determine their maturity, organic facies and depositional environment. The maturities of the three wells range from early mature (Ex-A), late to postmature (Ex-C) to overmature (Ex-B) as determined by vitrinite reflectance measurements, diamondoid ratios, and other geochemical maturity parameters. Ex- C and Ex-B show distinct petrographic features related to oil generation and migration. In particular, the occurrence of dispersed solid bitumen replacing initial type I kerogen suggests a formerly active petroleum system. Structural and textural differences between early mature alginites and solid bitumen in postmature to overmature samples show an alteration of the pore system with increasing maturity. A freshwater depositional environment is indicated by widespread occurrence of botryococcus algae and other small alginite particles predominating in the immature well. These alginites are absent in the more mature gas shales of wells Ex-C and Ex- B. Geochemical evidence of algae and phytoplankton in general is provided by numerous biomarker parameters, while the occurrence of β-Carotane in some samples indicates events of increased salinity, although no hypersaline conditions are inferred due to very low gammacerane indices. Increased amounts of vitrinite and inertinite in samples of Ex-B suggest locally significant terrigenous input of organic matter for some periods during Wealden Shale deposition. High sulfur/organic carbon ratios provide evidence for sulfate rich waters and (partly) anoxic bottom water conditions. While the lower mature lacustrine source rocks generate paraffinic/waxy oils, gas and condensates are produced at post-mature stages. Furthermore, maturity distribution maps from 3D numerical petroleum systems modeling reveal substantial differences, in respect to petroleum generation.

Wealden black shales 13

2.2. Introduction

Fig. 2-1: Overview map of the Lower Saxony Basin (Bruns et al., 2013).

Petroleum source rocks have long been regarded as the source of almost all oil and gas found in conventional reservoirs. Recently, new drilling and fracturing technologies allowed extracting hydrocarbons directly from within these fine grained rocks which have a low permeability (Curtis, 2002; Littke et al., 2011). Especially exploration for, and production from, gas shales became a major element of energy supply in the United States of America, inspiring intense research activities around the world. So far, most gas shales that have been studied are silica rich, marine Palaeozoic sedimentary rocks (Jenkins and Boyer, 2008; Chalmers et al., 2012; Uffmann et al.,

Wealden black shales 14

2012). Here we report results of an investigation of a lacustrine sequence of Early Cretaceous age. This so-called Wealden Shale occurs in northwestern Germany in great thickness (500 m and more) and has partly reached the thermal gas generation stage. A detailed study on the organic geochemistry of immature Wealden Shale from the westernmost part of the Lower Saxony Basin has recently been published by Berner et al. (2010). Here we present data on another core of immature Wealden Shale situated further to the east which was sampled in detail. In addition, we took samples from two more mature cores in the central part of the basin. This is one of the rare situations when a systematic comparison of immature and overmature source rocks is possible. Especially for lacustrine organic matter rich shales, this has rarely been done.

The Lower Saxony Basin (LSB) is situated north of the Rhenish Massif and Münsterland Basin covering an area of about 400 km in east-west and 100 km in north-south direction (Mutterlose and Bornemann, 2000; Voigt et al., 2008). It is part of the Central European Basin System (CEBS) which evolved from extensional processes during the Permian (Littke et al., 2008). There Permo- Triassic and younger sediments are underlain by Late Carboniferous and Devonian sedimentary units. At the southern margin of the CEBS, several subbasins evolved during the Late Jurassic and Early Cretaceous when rapid burial took place. The sediments of the LSB reached maximum burial depth and maximum temperatures during the late Early Cretaceous or early Late Cretaceous, before strong uplift, inversion and erosion started (Petmecky et al., 1999; Senglaub et al., 2005; Voigt et al., 2008). The basin is bordered to the north by the Pompeckj block (Fig. 2-1). To the south it extends to the Münsterland Basin, while the eastern limit is marked by the Gifhorn Trough.

Wealden black shales 15

Fig. 2-2: Combined stratigraphic charts from Mutterlose and Bornemann (2000) and the Isterberg 1001 well from Berner et al. (2010). The profiles are arranged by their location (east to west) in the LSB. Note that the lithological subdivisions of the Isterberg 1001 well are strongly simplified.

Within the basin, the Berriasian Wealden Formation is widespread comprising a terrigenous coal- bearing facies as well as black shales of high organic matter content in the west (Fig. 2-2). Thus the Wealden facies is known to be heterogeneous, comprising fully terrigenous to fully marine sediments. The Berriasian black shale sequences themselves are no exception, ranging from brackish-lacustrine to marine depositional environments due to several marine ingressions (Elstner and Mutterlose, 1996). Although these black shale units have been known for decades (Anderson, 1962; Betz et al., 1987), the only detailed geochemical investigations were performed recently with a local focus (Berner et al., 2010; Berner, 2011). Due to the rising economic interest in unconventional gas resources in Europe, more detailed research on samples encompassing an expanded area seems appropriate.

Wealden black shales 16

The major objective of this work is to describe in detail organic facies and hydrocarbon generation potential of the immature Wealden, as well as changes of the organic matter during maturation to the postmature and overmature equivalents.

2.3. Methods

Ninety-seven core samples from three wells (Ex-A, Ex-B, Ex-C) within the Lower Saxony Basin were made available by a petroleum company. The samples cover different depth intervals within the Berriasian Wealden Formation. All samples were taken from dark shale/marlstone intervals; other lithologies were not sampled. It should be noted that the samples from the immature Ex-A core appear much brighter than those from the more mature Ex-B and Ex-C cores which have passed peak oil generation. Before further handling, all samples were dried overnight at 40 °C. Subsequently, one half of every sample was crushed and milled to achieve a fine powder for organic compound extraction and biomarker analysis. The other half underwent preparation of polished sections for organic petrographical analysis. Details of the microscopic methods including vitrinite reflectance analysis and fluorescence studies are described in Taylor et al. (1998) in general and by Sachse et al. (2011) and Littke et al. (2012) specifically for the laboratory conditions at RWTH Aachen University.

The reflectance measurements were calibrated using standards of known reflectance: yttrium- gallium-garnet (0.889 %) and gadolinium-gallium-garnet (1.721 %). To achieve a statistically representative amount of data, it was attempted to perform at least 50 measurements per sample. It should be noted that only few samples contain vitrinite. Instead the samples from Ex- B and Ex-C are rich in finely dispersed solid bitumen which was used for measurements. Conversion of solid bitumen reflectance to vitrinite reflectance followed the equation

VRr = (BRr + 0.2443)/1.0495 (1) from Schoenherr et al. (2007).

Determination of the total organic carbon (TOC) was conducted with a Leco SC-632 combustion oven after removal of carbonate carbon from the powdered sample material by diluted HCl. The temperature was held at 400 °C for 3 minutes followed by heating at a rate of 25 °C/min up to

Wealden black shales 17

850 °C, held for 5 minutes. The CO2 released by the combustion of organic compounds in the oven under oxygen atmosphere was measured using an infrared detector. Based on the CO2 amount, the organic carbon content of the samples was calculated.

Additionally, the total inorganic carbon (TIC) was measured for 36 samples of well Ex-A. Measurements were performed using an Elementar LiquiTOC II with a solid phase module. 100 mg of untreated, crushed rock samples were combusted in two steps: At the first stage temperature increased rapidly up to 550 °C held for 600 s and then further up to 1000 °C held for 400 s. TIC values are calculated from gas yields at 1000 °C. Results of TOC values for these samples calculated from CO2 yields at 550 °C were in good accordance to TOC measurements performed with the Leco SC-632 (see above). This is important, because Wealden Shale contains some siderite (FeCO3) which can decompose at temperatures even lower than 550 °C.

Total sulfur (TS) analysis was performed on 94 samples with a Leco S200 combustion oven at a temperature of 1800 °C under oxygen atmosphere. The released SO2 concentrations were recorded by an infrared detector.

Rock-Eval pyrolysis measurements were performed using a DELSI INC Rock-Eval 6 instrument. The principle procedures of Rock-Eval pyrolysis are described in Espitalié et al. (1985). Measurements followed the procedures described in the NIGOGA, 4th Edition. The temperature program was set to an isotherm of 300 °C, held for 3 minutes, followed by a heating phase with a rate of 25 °C/min up to 650 °C. An external standard was used as every tenth sample to ensure a good quality of measurements. Parameters derived from Rock-Eval pyrolysis include hydrogen index (HI), oxygen index (OI) and the production index (PI) which were calculated from integrated peak areas of the detected gas phases during pyrolysis. Furthermore, the temperature of maximum pyrolysis yield

(Tmax) was measured.

Open-System-Thermal-Analysis-GC-FID was performed at GFZ Potsdam for 12 Ex-A samples, 14 Ex-C samples, and 14 Ex-B samples to characterize organic matter quality, i.e. amount and composition of petroleum and kerogen on a molecular level. Analytical steps include thermovaporisation (Tvap) of untreated, powdered whole rock samples and subsequent open- system pyrolysis of the sample residue using the same equipment. Milligram quantities of each

Wealden black shales 18 sample were weighed into glass capillaries (Micro-Scale-Sealed-Vessels) which were then sealed by a H2 flame after reducing the internal volume from ca. 40 µl to ca. 15 µl with pre-cleaned quartz sand. For Tvap, tubes were purged 5 minutes at 300 °C using a Quantum MSSV-2 Thermal Analyzer© and then cracked open by a piston device coupled with the injector. The released volatile hydrocarbons were transferred to a liquid nitrogen cooled trap which, after ten minutes, was heated to 300 °C for analysis of products by gas chromatography. Online gas chromatography was performed using an Agilent GC 6890A gas chromatograph equipped with a 50 m HP-Ultra 1 column, 0.32 mm i.d. and 0.52 μm thickness as well as a flame ionisation detector (FID). The GC oven temperature was programmed from 30 °C to 320 °C at 5 °C/min. Helium was used as a carrier gas with a flow rate of 30 ml/min. Open system pyrolysis was performed after thermovaporisation by heating the residue in a flow of helium from 300 °C to 600 °C at 40 °C/min whereas the final temperature was maintained for 2 minutes. Generated products were again collected in the cryogenic trap and subsequently analysed as previously described.

For both methods product quantification of different boiling ranges and individual compounds was based on external standardisation using n-butane. Response factors for all compounds were assumed to be the same with the exception of methane whose response factor is 1.1. Prominent hydrocarbon peaks were identified by reference chromatograms and using GC ChemStation© software from Agilent Technologies. Reproducibility of measured product concentration is generally better than 4 % (Schenk et al., 1997).

Samples for molecular geochemical analyses including determination of biomarker maturity parameters were selected based on TOC content and vitrinite reflectance. The focus was on the low mature samples from well EX-A, but few additional samples from the highly mature cores of Ex-B and Ex-C were also measured. In each case 1 g of powdered sample material were extracted using 40 ml of DCM and 40 ml of hexane under ultrasonic treatment and overnight stirring. Polarity chromatography induced fractionation was performed over a fused silica packed baker bond column into three subfractions using 5 ml pentane for the saturated fraction, 5 ml of pentane:DCM (40:60) for the aromatic fraction and 5 ml MeOH for the residual organic compounds.

Wealden black shales 19

The aliphatic and aromatic fractions were analyzed by gas chromatography using a Carlo Erba Instruments HRGC 5300 flame ionization gas chromatograph (GC-FID) by injecting a splitless volume of 1 µl. The GC was equipped with a Zebron ZB-1 30 m x 0.25 mm x 0.25 μm fused silica column. H2 was used as carrier gas with a velocity of 40 cm/s.

Temperature programs differed for the aliphatic fraction and the aromatic fraction. The aliphatic fraction was analyzed at 80 °C, held for 3 min and followed by a 3 °C/min heating rate up to 310 °C at 10 min isothermal time. For the aromatic fraction a faster program was used starting at 80 °C at a 3 min isotherm and a 5 °C/min heating rate up to 300 °C, held for 10 min.

The aliphatic fraction was subsequently injected into a gas chromatograph coupled to a mass spectrometer (GC-MS). The GC was a Hewlett Packard Series II 5890 with a Zebron ZB-1 30 m x 0.25 mm x 0.25 μm fused silica column, using the same temperature program as for the analysis of the saturated fraction with the HRGC 5300. Carrier gas was He with 35 cm/s velocity. The MS was a Finnigan MAT 95 operated in full-scan mode from m/z 35 to 700 with a scan rate of 0.5 s/decade and an interscan time of 0.1 s.

For the interpretation of the GC-MS data, the Xcalibur software from Finnigan was used. Identification of the single compounds was achieved by comparison with reference material and published mass spectra. Additionally, documented elution orders in dependence of retention times from several sources (Chen et al., 1996; Schulz et al., 2001; Peters et al., 2005; Wang et al., 2006) have been compared to the measured gas chromatograms. Biomarker ratios were calculated from integrated peak areas.

Results on large scale thermal maturation are derived from a 3D numerical petroleum system model and based on Bruns et al. (2013). In this former study the burial, temperature, maturation and pressure history of the Lower Saxony Basin and adjacent areas was reconstructed and input as well as output data of the model are carefully described (Bruns et al., 2013). Here, the application to the Wealden petroleum source rock is shown.

Wealden black shales 20

2.4. Results and discussion

2.4.1. Organic matter quantity and quality

The total organic carbon (TOC) measured from samples of well Ex-A (Fig. 2-3) ranges from 2–18 wt-% with a mean value of 6.2 wt-%, revealing an excellent petroleum source rock. Mean TOC values for wells Ex-B and Ex-C are slightly lower with 5.4 wt-% and 5.5 wt-%, respectively. Although these average values are quite similar, the values scatter within each of the three wells significantly. This is most pronounced for well Ex-C, which contains two samples of coal-bearing shales with TOC values > 12 wt-% (Fig. 2-3). In none of the wells, a clear depth trend is discernible, but exceptional very high TOC contents (> 10 wt-%) only occur in the lower half of the sequence. It has to be noted that the samples of the middle depth intervals of Ex-A and Ex-B correspond to the lithostratigraphic unit Wealden 3. The equivalent samples from this formation are represented by the lower half of well Ex-C in Fig. 2-3. Sampled intervals which are stratigraphically higher or lower are from younger and older Wealden formations, respectively.

The slightly lower average TOC values in wells Ex-B and Ex-C are partly due to the increased maturity and realization of most of the petroleum generation potential. Based on detailed studies on the more homogeneous Posidonia Shale from the same basin, it can be assumed that about half of the original TOC gets lost upon maturation (Rullkötter et al., 1988) for a maturity range between 0.5 and 1.5 %VRr. The difference in TOC between Ex-A and the thermally mature wells Ex-B and Ex-C is less pronounced, probably mainly due to facies differences. It can be expected that the original TOC values (before petroleum generation) of the Ex-B and Ex-C values were much higher, in the order of 10 wt-%. This can also be deduced from the difference in HI values, which are very high in Ex-A and much lower in Ex-C and Ex-B, indicating realization of most of the petroleum generation potential (see below).

Wealden black shales 21

Fig. 2-3: TOC content (in wt-%) plotted against depth for the analyzed wells.

Wealden black shales 22

Fig. 2-4: Total sulfur (TS; wt-%) content plotted against the total organic carbon (TOC; wt-%) content for all samples with normal marine lines (after Berner, 1984). Open circles represent carbonate rich samples of Ex-A.

Total sulfur (TS) content in combination with TOC content reveals that the Wealden black shales were deposited partly under anoxic bottom water conditions (Fig. 2-4). This is evident from the high TS/TOC ratios of many of the samples, suggesting presence of hydrogen sulfide within the water column. Such high TS/TOC ratios can be expected for marine shales, but are uncommon for freshwater-derived black shales (Berner, 1984), because typical freshwater is depleted in sulfate. The surprisingly high TS content of many of the samples therefore indicates not only anoxic depositional environments but also sulfate-rich freshwater. It might be speculated that Permian salt domes and salt glaciers provided the additional sulfate in the lakes during Lower Cretaceous times (Mohr et al., 2005). Interestingly, the carbonate-rich samples from well Ex-A (open circles in Fig. 2-4) follow the “marine” trend line of Berner (1984), whereas the carbonate-depleted samples show a strong variability in TS/TOC ratios. Wells Ex-A and Ex-C show a wide range of

Wealden black shales 23

TS/TOC ratios, with the low values (in the right part of the diagram) being partly due to terrigenous input in coal-bearing shales. Such coaly material has typically low TS/TOC ratios. The two Ex-C samples with 13 wt-% and 18 wt-% TOC belong to this group as proven by high percentages (28 wt-% and 31 wt-%, respectively) of inertinite and vitrinite particles. On the other hand, samples from Ex-B seem to be more homogeneous with TOC values from 3–8 wt-% and TS values always < 3.5 wt-%.

Fig. 2-5: Ternary diagram showing the original sedimentary composition of the samples from well Ex-A. Open circles represent samples with high HI values. The arrow represents the trend line of organic matter depletion in carbonate environments, indicating nutrient deficiency during deposition (after Sachse et al., 2012b).

Based on TOC, TS, and carbonate contents, the original sedimentary composition (before bacterial sulphate reduction) was reconstructed after Littke et al. (1991a) using the data of 36

Wealden black shales 24 samples of well Ex-A. The sedimentary composition is clearly dominated by silicates with values varying between 45 and 91 vol-% (Fig. 2-5). Organic matter accounts for 6 – 23 vol-%, whereas carbonate content is highly variable, ranging between 0.1 and 46 vol-%. The plot clearly indicates that most samples are poor in carbonate (less than 20 vol-%), but that some organic matter-rich marlstones occur as well. In carbonate-dominated sedimentary systems, organic matter tends to show a good positive correlation with silicate content, because increased silicate content is usually accompanied by increased nutrient supply (Littke et al., 1991a, Sachse et al., 2012b). In contrast, in silicate dominated systems in which nutrient supply is always sufficient, carbonate can be positively correlated to organic matter content (Sachse et al., 2012a) reflecting stronger input of aqueous (planktonic) biomass, possibly due to better preservation and/or dilution of organic matter-rich marls by additional clay minerals/silicate. Here, samples with 5 to 25 vol-% carbonate seem to have quite uniform organic matter content of about 10 to 18 vol-%, with a slight tendency of increase with increasing carbonate confirming the above observation. However, at very low carbonate content (< 5 vol-%) and very high carbonate content (>25 vol-%) we observe a much greater scatter (6 to 24 vol-%, Fig. 2-5). In case of the high carbonate contents, a negative correlation between carbonate and organic matter seems to evolve indicating nutrient-deficiency in carbonate dominated systems. In any case, all samples with carbonate content greater than 10 vol-% (with just one exception) are hydrogen-rich (HI > 700 mg/g TOC; see below) whereas the majority of the silicate-rich (carbonate <10 vol-%) samples has HI values lower than 700, indicating a slightly greater input of hydrogen-depleted (terrestrial) organic matter or greater degradation of aquatic organic matter.

Basic information on organic matter quality and petroleum generation potential is derived from organic petrography and Rock-Eval pyrolysis (Fig. 2-6). Samples from well Ex-A have highly variable S2 and HI values (Fig. 2-6a and Fig. 2-6b) reaching a maximum of more than 100 mg/g rock and more than 800 mg/g TOC, respectively. Most of the samples have high to very high S2 and HI values indicating type I or type I-II kerogen, but there are also a few samples with only moderate values as typical of type II-III kerogen. The samples of Ex-B and Ex-C follow the maturity related trend lines for type I kerogens (Fig. 2-6b) with maximum HI values of 200 mg/g TOC for samples of Ex-C and hydrogen depleted organic matter in samples of Ex-B with maximum HI

Wealden black shales 25 values of 100 mg/g TOC. Maximum HI values are generally found in the upper depth intervals of the latter wells and correlate with higher S1 values and lower Tmax values. Both features are indicators for a “carryover”-effect of high molecular weight S1 compounds into the S2 peak. Production Index (PI) values are very low in Ex-A (0.01-0.02) and much higher in Ex-C and Ex-B (0.19-0.38 and 0.13-0.42, respectively) indicating for Ex-A that no or little petroleum generation has taken place. This is surprising in view of the advanced Tmax-values as well as maturity-related biomarker ratios (discussed below). We assume a thermally very stable type I kerogen for the Wealden Shale which is only converted into hydrocarbons at high temperatures. Even for such a stable type I kerogen the observed Tmax-values in the range of 445-453 °C, at very high HI values, are exceptional.

Fig. 2-6: Classification of kerogen type using S2 yields and TOC content (in wt-%) (a) as well as HI and Tmax values (b) derived from Rock-Eval measurements.

Wealden black shales 26

Fig. 2-7: Petrographical photographs showing different organic components of samples from Ex- A. (a) and (b) Remains of Botryococcus algae under fluorescent light. (c) Foraminifers under fluorescent light. (d) Same as c under incident white light. (e) Lamalginite matrix under fluorescent light (f) Fish remains under fluorescent light.

Wealden black shales 27

Organic petrography revealed significant differences in maceral composition of the samples. The samples of Ex-A contain predominantly telalginite (large algal bodies) and lamalginite (µm thick, fluorescing strings of probable algal origin; Taylor et al., 1998). The large algal bodies are almost exclusively composed of remains of botryococcus algae (Fig. 2-7a and Fig. 2-7b) which are distinct indicators for a brackish-lacustrine depositional environment (Batten and Grenfell, 1996). Botryococcus algae are hydrogen-rich at low levels of thermal maturity (Metzger and Largeau, 2005) which fits well to the high S2 and HI values of most of the samples reflecting the presence of type I kerogen. Fluorescence colors are intense throughout the samples, suggesting a low maturity (lower than peak oil generation stage). Interestingly, botryococcus algae occur in all samples of well Ex-A, although the uppermost interval has been classified as marine in origin. Other macerals, in particular maceral groups vitrinite and inertinite are rare in all samples from well Ex-A. Fossil shells and fish remains have been found abundantly in some samples (Fig. 2-7 c- f). The relative amount of fluorescing alginite over total macerals is greater than 90 vol-% for almost all samples. Volume percentages of macerals in well Ex-A vary between 2 and > 20 vol-% and are in principal agreement with TOC values indicating that most of the organic matter occurs in the form of well visible macerals.

The samples of well Ex-C show a different maceral composition. Due to the high thermal maturity, there are no primary alginite macerals visible any more. No traces of the large botryococcus algae can be observed at the maturity stage represented by this well. Instead a network of solid bitumen exists as well as some dark fluorescing “spots” (meta-alginite sensu Littke et al., 1988). This type of material seems to be typical for post-mature black shales at a maturity range between about 1.3% and 2.0% vitrinite reflectance, i.e. the “wet gas window”. Some of the solid bitumen is concentrated in fractures. In addition, in a few samples large terrigenous inertinite and vitrinite particles (up to > 300 µm in diameter) occur, indicating a different facies and more terrigenous input at the location of that well (Fig. 2-8).

Wealden black shales 28

Fig. 2-8: Petrographical photographs of samples from well Ex-B. (a) and (e) show large inertinites. (b) and (f) show large vitrinite particles. (c) and (d) show the bitumen accumulations in pore spaces and natural fractures.

Wealden black shales 29

In the samples of well Ex-B, liptinitic material (alginite) is completely missing as a result of the complete decomposition of these hydrogen-rich materials at this maturity stage. Organic matter does not show any fluorescence or at best a very weak fluorescence, i.e. not even the “meta- alginite” visible in low amounts in Ex-C occurs here. The organic matter is dominated by a solid bitumen matrix often filling fracture networks throughout the samples (Fig. 2-9). This appearance seems to be typical of black shales that have reached maturities > 2% vitrinite reflectance, i.e. the “dry gas window”. Vitrinite and inertinite are more abundant in Ex-B (3-5 vol-%) than in Ex-A (around 2 vol-%), but less abundant than in Ex-C (7-10 vol-% on average).

Fig. 2-9: Petrographical photographs showing the disperse bitumen matrix (a) and (b) in samples of well Ex-C. (c) and (d) show bitumen accumulations in natural fracture system in the samples.

Wealden black shales 30

A comparison between the samples of the different wells and maturity intervals shows that a complete restructuring of the algal material takes place during maturation. In fact, there are no textural or structural similarities between the primary alginite in the early mature samples from well Ex-A and the solid bitumen from the wells Ex-C and Ex-B. While the alginites are mainly laminated due to depositional processes, the solid bitumen fills intergranular spaces and fractures unrelated to lamination. Taking into consideration that large volumes of rock are affected by this conversion of organic matter, influence on the pore system such as generation of secondary porosity and pore plugging are the result. With increasing maturity to postmature stages and beyond, a development of secondary porosity within the solid bitumen due to gas generation is probable (Bernard et al., 2012) but was not investigated in this study.

Table 2-1: Thermovaporisation and Open-Pyrolysis-GC-FID boiling ranges yields.

Wealden black shales 31

Open system thermal analysis-GC-FID results for 40 samples from wells Ex-A-C-B are displayed in Table 2-1and Table 2-2 as well as in Fig. 2-10 and Fig. 2-11. Thermovaporisation GC-FID gas chromatographic fingerprints reveal for samples of well Ex-A (Fig. 2-10a) that in the upper depth interval (samples 1–4) free hydrocarbons are of marine character, as can be deduced from a domination of intermediate n-alkane chains (n-C6-14) over longer -alkane chains (n-C15+), whereas in all other intervals (samples 5–12) free hydrocarbons are of lacustrine character, as longer n- alkane chains dominate over intermediate n-alkane chains (Horsfield, 1997). Nevertheless, the detected free hydrocarbons might represent in-situ first formed products from thermal kerogen decomposition but they could also comprise fractions of migrated oil changing the organic matter characteristic.

Table 2-2: Open-Pyrolysis-GC-FID single compound yields as input parameters for determination of kerogen quality and structure using ternary diagrams of Larter (1984), Horsfield (1989) and Eglinton et al. (1990).

Wealden black shales 32

Upon open system pyrolysis GC-FID, all immature Wealden Shale samples from Ex-A generate intermediate to long straight chain aliphatic hydrocarbons dominated pyrolysates in which only minor amounts of aromatic hydrocarbons or sulfur containing compounds are present, and essentially no phenolic compounds. Using three ternary diagrams, in which those readily identifiable aliphatic, aromatic, oxygen- and sulfur-bearing compounds are employed (Table 2-2, Fig. 2-11) the kerogen structure, i.e. quality can be characterised. Fig. 2-11a shows the kerogen petroleum type organofacies classification established by Horsfield (1989), which employs the aliphatic fraction, i.e. intermediate and long n-alkyl chain length distribution versus total gas C1-5, based on the observation that the relative abundance of each homologue in the pyrolysate is controlled to variable degrees by the chain length of the linear aliphatic precursor moiety in the kerogen. The type of petroleum products generated from all samples independent of depth interval can therefore be described as paraffinic high wax oil, whereas the wax content is strongly variable even within single depth intervals. The molecular structure of kerogens yielding this type of pyrolysates is related to the selective preservation of the outer cell walls of lacustrine microalgae, which are highly aliphatic (Berkaloff et al., 1983), e.g. remains of Botryococcus braunii in the case of Green River Shale or, as demonstrated here by organic petrography, Wealden Shales (also compare Mahlstedt and Horsfield, 2012). The extent of change in chain length distribution has been earlier described by Sachsenhofer (1994), with lowest wax contents for anoxic marine deposition and highest wax content for non-marine environments. In the ternary diagram of Larter (1984) (Fig. 2-11b), which was originally implemented to distinguish between phenol-rich and phenol-poor type III source rocks, the amount of kerogen representing land plant derived moieties can be inferred by relative proportions of phenol, n-octene and m,p-xylene in the pyrolysate. In accordance with petrographical observations, all Ex-A samples plot in the aquatic organic matter field without indication of the presence of higher land plant derived material such as vitrinite. The use of 2,3-dimethylthiophene and o-xylene and n-C9:1 in a ternary diagram (Fig. 2-11c) as proposed by Eglinton et al. (1990) allows the discrimination of source rocks deposited in marine or hypersaline sedimentary environments and those deposited in freshwater lacustrine or terrigenous environments. Very low relative amounts of sulfur compounds are generated upon the pyrolytic breakdown of kerogen within samples from well Ex-A indicating deposition of the organic matter rather in a freshwater lacustrine environment.

Wealden black shales 33

Fig. 2-10: Thermovaporisation gas-chromatograms (fingerprints) of samples from well a) Ex-A, b) Ex-C, and c) Ex-B. Most large peaks represent straight chain aliphatic compounds (n-alkanes).

Thermovaporisation GC-FID fingerprints reveal for samples of post- to overmature wells Ex-C and Ex-B (Fig. 2-10b and Fig. 2-10c) that paraffinic/waxy oil is present in the upper depth intervals (samples 13-20 for EX-C and samples 27–30 for EX-B), whereas the lower depth intervals contain

Wealden black shales 34 only gas/condensates or light oil (C15+ < 95%) in relatively low amounts (Table 2-1). It is not easily possible to deduce whether the free hydrocarbons are in situ in origin or migrated, but it can be assumed that the presence of long versus short chained dominated thermal extracts is neither only a function of initial organic matter type, which was shown to be rather similar for all depth intervals in well Ex-A, nor of maturity, which is as high as 2.2 %VRr in the upper depth interval in well Ex-B and only 1.9 %VRr in the lower depth intervals of well Ex-C. In any case, hydrothermal solutions circulating at the base of the successions might also influence the composition of the products in place, a topic discussed in the following section. One interesting feature mentioned earlier in a related context is that open system pyrolysis GC-FID yields are generally higher for depth intervals in which long alkyl chain dominated thermal extracts are encountered (Table 2-1) hinting again to the occurrence of a “carryover” of high molecular weight S1 compounds (Thermovaporisation) into the S2 open system pyrolysis temperature range. Nevertheless, absolute open system pyrolysis yields are much lower for samples from wells Ex-C and Ex-B than for samples from well Ex-A because the labile, hydrogen-rich kerogen part is already almost completely converted to “dead” carbon and petroleum which has already left the source rock. The use of the three ternary diagrams previously applied to characterise the kerogen structure of immature Wealden Shale samples is therefore rather limited in the case of post- to overmature samples. Nevertheless, yields of the relevant single compounds are given in Table 2-2 for completeness. It can be assumed that gas window mature samples from wells Ex-B and Ex-C mainly generate a short chain dominated, aromatic pyrolysate, with compositions falling in the gas and condensate field of Horsfield (1989), when the “carryover” signature of free and high molecular weight oil compounds is ignored.

In general, oil impregnations from different sources than the formation itself can be almost excluded for Ex-A due to i) the very low PI values (0.01-0.02) and ii) no indications of presence of solid bitumen or oil fluid inclusions by organic petrography. The only indication exists for the uppermost interval in Ex-A for which the open system pyrolysis revealed a geochemical fingerprint typical of marine source rocks while this interval has a lacustrine fingerprint according to the results of thermovaporisation. This lacustrine signal might be due to some impregnation from deeper Wealden intervals, although the very low PIs do not indicate this. In any case,

Wealden black shales 35 variability in some biomarker parameters within this well provides further evidence that soluble organic matter is mainly pristine in this well.

In contrast, for wells Ex-C and Ex-B an oil impregnation in the upper intervals is highly likely. The PI values in these sections are significantly higher (0.31 and 0.39 on average, respectively) than in the deeper intervals of wells Ex-C and Ex-B and much higher than in Ex-A. Additionally, the “carryover” signatures and some abnormally high HI values (Fig. 2-6) for these intervals hint to such an impregnation.

Fig. 2-11: Open-System Pyrolysis GC-FID: Typing of molecular kerogen structure and petroleum type organofacies using ternary diagrams of (a) Horsfield (1989), (b) Larter (1984) and (c) Eglinton et al. (1990)

Wealden black shales 36

2.4.2. Thermal maturity

A first maturity characterization can be derived from Rock-Eval pyrolysis results. High HI values (Fig. 2-6) indicate low to moderate maturity for samples from well Ex-A, whereas low HI values in combination with high Tmax values indicate an increased maturity for Ex-C and especially for Ex-B (Peters et al., 1986).

Vitrinite reflectance (VRr) measurements could only be obtained for a limited number of samples due to the small number and small size of vitrinite particles, especially in well Ex-A. The results indicate an early to medium mature stage for Ex-A (about 0.50–0.60 %VRr; see also Table 2-5). However, terrigenous macerals like inertinite and vitrinite are scarce to absent in most of the samples from this well, resulting in a small amount of reflectance values for the whole succession and some uncertainty. Tmax values for this well are quite variable ranging from 423 °C to 453 °C. These variable values can be affected by a rather high thermal stability of freshwater algae (type I kerogen, Schenk et al., 1990), which preserved their hydrogen (high HI and S2 values) up to the

“peak oil” generation stage. It should be noted that all Tmax values greater than 445 °C occur in the lower half of the studied section, i.e. at depths greater than 950 m indicating some progress in maturation.

Vitrinite reflectance values for well Ex-C range from 1.50 %VRr at 613 m depth to 1.93 %VRr at

921 m depth. Such an increase of VRr over 300 m depth is unusual and might be explained by either (i) some uncertainties with respect to the measurement, because only data from a few samples are available or (ii) hydrothermal solutions circulating at the base of the succession from

Ex-C. For the samples of well Ex-B, the maturity range is relatively narrow with 2.2 %VRr at 991 m depth and 2.3 %VRr at 1340 m depth. VRr values for the high maturity range are consistent with data from Rock-Eval pyrolysis. In summary Ex-A is the lowest mature succession at the early stage of the oil window. Peak oil generation has definitely not been reached. The Wealden in Ex-C is post-mature and has entered the wet gas window, while the samples of Ex-B are overmature but still within the dry gas window.

Detailed and extensive 3D basin modeling revealed significant and comprehensive differences of maturity distribution of the Wealden formation throughout the LSB and parts of the Pompeckj

Wealden black shales 37 and Münsterland basins. Fig. 2-12 shows the extracted present-day maturity map, based on calibration data at over 425 locations (Bruns et al., 2013), in comparison with maturity isolines published by Bartenstein et al. (1971) for the same formation. Both approaches show the highest maturities in the central part of the basin. However, the model reveals that the maturity distribution is much more complex and heterogeneous than initially proposed. Furthermore, the E-W strike of the elliptical isolines from Bartenstein et al. (1971) is contradicted by the NW-SE trending iso-reflectance zones of the 3D model, showing that the areas of highest maturity of the Wealden, and therefore the area of deepest burial is oriented parallel to the NW-SE striking front of the Hercynian orogeny. Furthermore, the denudation zones in which the Wealden formation has been completely eroded are depicted in more detail in the model. In some aspects however, the model complements the earlier work by mapping out some conspicuous features in more detail. A good example is the restricted zone of elevated maturities > 0.7 %VRr in the area NE of the city of Hannover, as already inferred, based on data from one well, by Bartenstein et al. (1971).

Fig. 2-12: Comparison between a detailed present-day maturity map of the Wealden derived from basin modeling for the LSB from Bruns et al. (2013) with maturity isolines from Bartenstein et al. (1971).

Wealden black shales 38

2.4.3. Maturity related biomarker analysis

Biomarker analyses were performed to further investigate maturity. The n-alkane distribution was analyzed by using gas chromatography. Table 2-3 summarizes the results for odd/even predominance (OEP, Scalan and Smith, 1970), carbon preference index (CPI, Bray and Evans,

1961) and other deterministic ratios of isoprenoids and n-alkanes. The OEP(1) is defined as (C21 +

6C23 + C25) / (4C22 + 4C24). OEP(2) is defined as (C25 + 6C27 + C29) / (4C26 + 4C28). CPI is defined as

2(C23 + C25 +C27 +C29) / [C22 + 2(C24 + C26 + C28) + C30]. OEPs and CPIs > 1.0 indicate immature or early mature samples. Table 2-3 shows that samples down to 849 m depth of Ex-A have OEPs and CPIs > 1.0 and are therefore considered immature/early mature which is in accordance with Rock- Eval and microscopy results. Additionally, maturity was also determined from aromatic compounds. The methylphenanthrene indices (MPI) were calculated after Radke and Welte (1983) and are basically in good accordance with the vitrinite reflectance measurements.

Table 2-3: Isoprenoid and n-alkane ratios determined via gas chromatography. OEP: odd-even predominance. CPI: carbon preference index. Please refer to the text for definitions.

Methylated adamantane compounds (m/z 136, 135, 149 and 163) and methylated diamantanes (fragment ions m/z 188, 187 and 201) were found in most of the samples. A general elution order

Wealden black shales 39 of these compounds is shown in Fig. 2-13 and the according peak assignment is given in Table 2-4. The methyl adamantane index (MAI) and methyl diamantane index (MDI) with the ratios 1-MA/(1- MA + 2-MA) for MAI and 4-MD/(1-MD + 3-MD + 4-MD) for MDI (Chen et al., 1996) have been used to determine maturity parameters. The results are shown in Table 2-5 and Table 2-6. Although, ratios within the same well vary seemingly unrelated to burial depth, both ratios increase significantly from well to well and are therefore supporting the vitrinite reflectance data (Fig. 2-14). Ratio scattering within the same wells may be caused by facies effects (Schulz et al., 2001) and may hint to marine ingressions in the upper part of the sequence during the Berriasian (Elstner and Mutterlose, 1996).

Fig. 2-13: General elution order of methylated adamantanes and diamantanes.

For well Ex-A, sterane and hopane related maturity ratios were calculated. C27–C29 diasterane and

C27–C29 regular sterane isomers and homologues were measured using the m/z 259 and 217 ion traces, respectively. Identification of these compounds was supported with analysis of m/z 372,

Wealden black shales 40

386 and 400 ion traces. Sterane and hopane based parameters can only be applied for samples below the postmature stage (Peters et al., 2005). In fact, identification of diasteranes and steranes in samples from wells Ex-B and Ex-C was not possible due to absence of steranes at the respective maturity ranges.

Table 2-4: Compound assignment for Fig. 2-13.

In Ex-A C27 steranes are generally predominant with the following relative abundances: C27 steranes > C29 steranes > C28 steranes > C27–C29 diasteranes. The results (Table 2-5) show a significant increase of the C27–C29 diasteranes/(C27–C29 diasteranes + C27–C29 steranes) with increasing depth for Ex-A, rendering this ratio effective as a maturity indicator within the succession. In contrast, other sterane derived maturity parameters such as the C29 sterane isomer ratios C29 ββ/(ββ + αα) and C29 20S/(20S + 20R) show no clear trend with increasing burial depth. The values seem to have reached an equilibrium due to maturation (Peters et al., 2005) of about

0.55 for the C29 20S/(20S + 20R) and 0.68 for the C29 ββ/(ββ + αα).

Wealden black shales 41

Table 2-5: Maturity parameters and ratios for Ex-A. MAI: methyl adamantine index. MDI: methyl diamantane index. MPI: methyl phenanthrene index. Ts: 18α(H)-22,29,30-Trisnorneohopane. Tm: 17α(H)- 22,29,30-Trisnorhopane. Please refer to the text for definitions.

Maturity ratios derived from terpanes were also determined. Peaks were measured on the m/z 191 fragmentogram with additional qualitative analysis of m/z 370, 384, 398, 412, 426 and 440 for the hopane homologues. Several hopane homologues can be used to determine maturity. Ts/(Ts + Tm) is a ratio of 18α(H)-22,29,30- Trisnorneohopane (Ts) and the thermally less stable 17α(H)-22,29,30-Trisnorhopane (Tm). They were measured using the ion trace of m/z 191 with additional analysis of the M+ ion at m/z 370. Other

ratios used include the C30 Hopane/C30 Moretane

ratio and the C29 Ts / C29 Norhopane ratio. From these ratios only Ts/(Ts + Tm) seems to indicate a trend with increasing depth. In summary, biomarker ratios for Ex-A indicate a maturity in the oil-window, but peak oil generation has clearly not been reached. This supports the information of vitrinite reflectance and Rock-Eval data.

Wealden black shales 42

Table 2-6: Maturity parameters and ratios for Ex-C and Ex-B. MAI: methyl adamantine index. MDI: methyl diamantane index. MPI: methyl phenanthrene index. Please refer to the text for definitions.

Fig. 2-14: Maturity parameters derived from biomarker analysis plotted versus depth. MDI: methyl diamantane Index. MAI: methyl-adamantane Index. Ts: 18α(H)-22,29,30-Trisnorneohopane. Tm: 17α(H)-22,29,30-Trisnorhopane.

Wealden black shales 43

2.4.4. Source related biomarker analysis

The ratios of the isoprenoids pristane and phytane to the straight chain C17 and C18 n-alkanes (Fig. 2-15) reveal organic matter input from mixed sources for most of the samples from well Ex-A. However, organic petrography clearly shows the predominance of freshwater algae with only very little contribution from land plants. In this respect, the graphic interpretation fields in Fig. 2-15 are a simplification and maybe misleading for lacustrine/brackish deposits. A near shore lacustrine depositional environment as inferred by the observation of botryococcus algae is underlined by the geochemical fingerprint of these samples. The input of higher land plant material is low. Further investigation of the sum of C27–C29 sterane isomers (Fig. 2-16) measured via GC-MS shows a similar geochemical discrimination of the organic matter type. Planktonic algal organic matter constitutes the main precursor of the organic compounds detected. However, outliers reveal a broader range of origin, probably caused by the earlier mentioned short lived marine ingressions.

Fig. 2-15: Crossplot of the ratios pristane/n-C17 and phytane/n-C18 as indicator for depositional environments of organic matter after Lijmbach (1975).

Wealden black shales 44

Gammacerane is an indicator for hypersaline depositional environments. High gammacerane/17α(H),21β(H)-30-hopane ratios indicate salinity induced water column stratification and therefore anoxicity (Peters et al., 2005). Although gammacerane was found in three samples from Ex-A, the gammacerane indices are very low. Therefore, salinity induced stratification of the water column is unlikely to have caused anoxic conditions. On the other hand, traces of β-Carotane were found in several samples. The presence of β-Carotane is a clear sign of saline lacustrine or highly restricted marine depositional environments (Hall and Douglas, 1983).

Fig. 2-16: Ternary diagram of C27 – C29 sterane isomers for the determination of organic matter type of well Ex-A.

Although huge amounts of botryococcus remains were identified by using organic petrography, no botryococcane was found in any sample. However, macrocyclic alkanes, clearly identified by their characteristic mass spectra and the predominant m/z 111 fragment ions, elute between the

Wealden black shales 45 n-alkanes on the total ion count chromatogram (Fig. 2-17). These compounds are believed to be derived from Botryococcus braunii (Audino et al., 2001a, b). The chromatogram of Fig. 2-17 is from sample GASH_1978 which has an OEP > 1.0, specifically observable for the n-alkanes eluting later than n-C20 by alternating peak heights for odd and even numbered n-alkanes. The macrocyclic alkanes elute between the n-alkane homologue series, follow the general peak height distribution of their n-alkane counterparts and show similar odd numbered alkane predominance.

Fig. 2-17: Total ion count chromatogram of sample GASH_1978 showing odd n-alkane (filled circles) predominance (> n-C22) and elution of macrocyclic alkane (circles).

Wealden black shales 46

2.5. Conclusions

Organic petrography revealed a clear predominance of alginite, i.e. lamalginite and botryococcus algae, limiting the depositional environment of the samples of well Ex-A to a lacustrine/brackish setting. This data is supported by findings of macrocyclic alkanes throughout most of the samples of Ex-A, underlining botryococcus algae as precursor and allowing a classification in combination with Rock-Eval and TOC data as type I kerogen. Slightly higher terrigenous contributions can be deduced for Ex-C and Ex-B based on vitrinite content.

Minor periods of increased salinity were indicated by the occurrence of β-carotane in some samples from this succession and high sulfate concentrations in the lakes are indicated by high sulfur/organic carbon ratios.

Maturities for the samples of well Ex-A have been investigated by vitrinite reflectance, Tmax values and various other maturity parameters indicating a maturity within the early oil window. Diamondoids and vitrinite reflectance where used to determine maturity ranges of the Ex-C and Ex-B well samples which are late mature and overmature, respectively. The occurrence of solid bitumen constituting part of the rock matrix as a fine network and filling also natural fractures suggests significant hydrocarbon generation within these samples. The thermal conversion of the algal material to petroleum with increasing maturity lead to an alteration of the pore system due to both filling of pore spaces and generation of secondary porosity.

The in-situ composition of petroleum analyzed by Tvap GC-FID and found in samples of well Ex-A and in the upper intervals of the wells Ex-C and Ex-B can be described as paraffinic high wax oil, which fits well to a lacustrine depositional environment and petroleum type organofacies predictions using open-system pyrolysis GC-FID. The highly mature kerogen within samples from wells Ex-C and Ex-B exhibits some remaining potential to generate short–chained hydrocarbons, i.e. gas and condensate.

3D numerical petroleum system modeling showed substantial differences with respect to thermal maturity and petroleum generation stages for different parts of the Lower Saxony Basin. Orientation and distribution of high maturity intervals reflect basin characteristics, i.e. strongly uplifted zones in the central part of the basin.

Flow-through extraction of oil and gas shales 47

3. Flow-through extraction of oil and gas shales under controlled stress using organic solvents: Implications for organic matter-related porosity and permeability changes with thermal maturity

3.1. Abstract

Four core plugs from the Lower Jurassic Posidonia Shale of the Hils Syncline in northern Germany have been subjected to flow-through extraction tests with dichloromethane (DCM) under controlled stress conditions in a tri-axial flow cell. The samples represent a maturity sequence from 0.53 to 1.45 %VRr. The bitumen sequentially extracted from the natural pore space of the shale plugs was analyzed for its geochemical composition. Changes in rock matrix density, porosity and permeability resulting from the removal of soluble organic matter were determined. The relative porosity increase of the plugs after extraction ranged from 6 to 13 % and correlated with the extract yield. Klinkenberg-corrected permeability coefficients measured with helium increased by a factor of 17.0 for the immature/early mature sample and 26.6 for the overmature sample. Petrographical investigations after extraction indicate that fluid flow occurred predominantly parallel to bedding as evidenced by open fractures and fractures bearing residues that apparently precipitated from the DCM solution. Compositional variations of the extracts over time are interpreted in terms of the organic geochemical inventory of bitumen associated with the natural pore system and its accessibility at different maturity levels. These patterns deviate strongly from the bulk rock extracts of the powdered samples.

3.2. Introduction

Increased production from unconventional hydrocarbon resources in the US has led to a scientific and industrial focus on oil and gas shales in Europe. In several European countries, geological surveys and petroleum companies have started to evaluate and characterize abundant black shale formations for their prospectivity and gas shale properties such as organic richness, thermal maturity, porosity and matrix permeability (Horsfield and Schulz, 2010). In Germany, three

Flow-through extraction of oil and gas shales 48 formations are regarded as the most important targets for gas shale exploration: the Lower Carboniferous Upper Alum Shale (Uffmann et al., 2013), the Lower Jurassic Posidonia Shale (Bruns et al., 2013) and the Lower Cretaceous Wealden Shale (Berner, 2011; Rippen et al., 2013). Among these promising black shale formations, the Posidonia Shale of the Lower Saxony Basin is the most well-known and investigated one. Core material from the Hils Syncline, representing a complete maturity range of the Posidonia Shale from immature to overmature samples has been studied intensively in the past (e.g. Leythaeuser et al., 1988; Littke et al, 1988; Rullkötter et al., 1988; Littke et al., 1991a; Littke et al., 1991b; Littke et al., 1991c; Sundararaman et al., 1993; Bernard et al., 2012). While most of these studies dealt with the organic petrological, organic geochemical and sedimentological properties, recent publications by the GASH (Gas Shales in Europe) Consortium research framework focused also on the petrophysical characterization of these fine grained sedimentary rocks. These investigations included measurements of permeability with different permeating fluids (Ghanizadeh et al., 2014) and determination of porosity and gas sorption capacity (Gasparik et al., 2014).

Systematic and significant changes in porosity and permeability of black shales due to thermal maturation have been documented. Ghanizadeh et al. (2014) report a decrease in porosity by up to 70 % from the immature to mature stage of the Posidonia Shale. Similar observations have been made for other gas shales such as the New Albany Shale (Mastalerz et al., 2013). This development has been attributed to pore throat or pore plugging by hydrocarbons generated in the “oil window”. With ongoing maturation and upon entering the gas window, porosities are reported to increase again. In overmature samples, secondary cracking of primary petroleum (mostly solid bitumen) creates secondary porosity (Bernard et al., 2012). Due to the interconnectivity of this secondary pore system, a significant increase of permeability can be observed over the same maturity range (Ghanizadeh et al., 2014). Nevertheless, isolated pores that do not contribute to permeability can still exist within organic matter as known from coal research (Giffin et al., 2013). Furthermore, recent studies on the Woodford shale suggest more complex dependencies for intra-organic porosity development such as organic matter composition and a stress-supporting mineral matrix (Curtis et al., 2012). Estimating the accessible porosity and permeability in the oil- and gas mature stage of black shales is crucial for the

Flow-through extraction of oil and gas shales 49 successful production from oil- and gas shales. Porosity not only influences the maximum amount of free gas/oil that can be stored in carbonaceous shales. It also controls the accessibility of sorption surfaces of organic matter and clay minerals. In addition, matrix permeability directly influences the production performance of shales.

Table 3-1: Petrophysical and elemental geochemical characteristics of source rock samples before flow-through extraction.

Flow-through extraction of oil and gas shales 50

This study was undertaken to investigate how soluble organic matter (bitumen) is distributed in the pore space of carbonaceous shales of different maturity levels and how it influences porosity and permeability with progressing thermal maturation. In particular, it aimed at estimating the portion of transport porosity occupied by bitumen (in the immature stage) and residual bitumen (e.g. solid bitumen, in a petrographical sense) in mature to overmature stages.

Flow-through extraction experiments were performed in tri-axial flow cells under in-situ stress conditions using the organic solvent dichloromethane (DCM) as permeate.

By reconstituting in-situ stress conditions it was attempted to close artificial pathways (fractures, cracks) resulting from stress relief and sample preparation. Permeability measurements were conducted before and after the extraction runs to estimate changes in pore interconnectivity and effective transport porosity.

In addition, the extracts collected in long-term flow tests were examined to assess the compositional differences of solid bitumen in larger and smaller pores. For this purpose, the bulk and sequential extracts were screened by thin-layer chromatography combined with a flame ionization detector (TLC-FID).

3.2.1. Samples

The flow-through solvent extraction experiments described here were conducted on core plugs of the Lower Jurassic (Toarcian) Posidonia Shale collected from three shallow wells from the Hils Syncline in the Lower Saxony Basin (Littke et al., 1991a). The sample set represents a complete range of thermal maturity ranging from immature (Wickensen; 0.53 %VRr), oil-window maturity (Harderode; 0.88 %VRr) and overmature (Haddessen; 1.45 %VRr). The actual plugs and sample coding used in this work are the same as in the work of Ghanizadeh et al. (2014) (Table 3-1).

Flow-through extraction of oil and gas shales 51

3.3. Experimental

3.3.1. Permeability and flow-through solvent extraction experiments

Experimental set-up

Fig. 3-1 shows a flow-scheme of the experimental set-up used for the flow-through extraction tests and the permeability measurements conducted in this study. The “triaxial” flow cell in this setup is used to apply stress to the sample during measurements and extraction. These cells were constructed to accommodate samples of 28.5 mm diameter and lengths of several millimeters to a few centimeters. Axial load is applied by cylindrical pistons, while confining pressure (Pconf) is applied via a high-pressure liquid chromatography (HPLC) pump using water as confining fluid. Axial load and confining pressure can be controlled and adjusted independently. Stainless steel metal filters are installed above and below the sample to divert and disperse the fluid flow.

Fig. 3-1: Flow-scheme of the experimental set-up for solvent flow-through extraction and gas permeability tests under controlled stress.

Flow-through extraction of oil and gas shales 52

This setup effectively creates two compartments of defined volumes depending on the lengths of the piston capillaries and the void volume of the metal filters, separated by the sample plug.

Additionally, each compartment is connected to a pressure transducer (Pup, Pdown in Fig. 3-1). Before each experiment run, the volumes of the compartments were determined by helium expansion from a calibrated volume.

Three valves are connected to the triaxial cell as shown in Fig. 3-1. Valve V1 is used for fluid selection and allows a rapid change from gas supplied from a pressure cylinder and solvent (DCM) provided by a HPLC pump operated in constant pressure mode. Valve V2 is used for opening and closing the upstream compartment. Valve V3 is used for pressure equilibration between the upstream and downstream compartments and as a fluid outlet through the graduated pipette. Extract sampling was then performed through valve V4, allowing gravity-driven flow of the fluid from the graduated pipette into the sampling vial.

Workflow

The workflow of the experimental procedure is shown in Fig. 3-2. The sample plugs were first dried in a vacuum oven at 105°C and their dimensions and weights were noted. Subsequently their grain density (skeletal density) and porosity was determined. After installing the samples in the triaxial flow cell their permeability coefficients were determined as a function of stress using helium as permeating fluid.

Porosity measurements

The porosity of the dry samples was determined from skeletal density (“grain density”) obtained from helium expansion (pycnometry) and the bulk volume of the plugs calculated from their diameter and length. Density and porosity of the sample plugs were determined before and after the flow-through experiments.

Flow-through extraction of oil and gas shales 53

Fig. 3-2: Experimental workflow comprising sample preparation, pre- and post-experimental poro- perm tests, solvent flow-through extraction, post experiment bulk extraction and compound group analysis by TLC-FID (IATROSCAN).

Permeability tests with helium

Permeability measurements with helium were performed before and after the flow-through extraction tests to assess changes in permeability coefficients resulting from bitumen extraction. The measurements were conducted according to the procedure described by Ghanizadeh et al. (2014) as non-steady state experiments at a constant temperature of 30°C.

An initial gas pressure difference was established across the sample. The pressure increase and decline in the lower and upper cell compartments, respectively, were monitored in 60 s intervals.

The measurements were performed at a confining pressure (Pconf) of 30 MPa and the mean pore pressure (Pm) was successively increased from 0.5 to 2.5 MPa in 0.5 MPa increments. The measuring temperature was kept constant at 30°C throughout the experiments.

Flow-through extraction of oil and gas shales 54

Flow-through extraction tests

Extraction runs were started immediately after the end of the last gas permeability measurements on the original sample plug. The plug was first flooded with DCM at a constant pressure of 10 MPa in the upstream compartment, while the lower compartment valve (V3 in Fig. 3-1) was closed. During the extraction runs, the pressure of the upper cell compartment was kept constant and pressures were recorded for the upper and lower compartments at 60 s intervals. Every 24 hours the downstream compartment was opened for exactly 2 minutes and the extract was allowed to flow into the graduated pipette. After reading the extract volume, valve 4 was switched and the solvent extract transferred into sampling vials for analysis. In total, 10 flow- through extracts were collected during each test.

The extracts were evaporated and the sample vials weighed to determine the solvent extract (SE) yield of each extraction step in relation to the sample vial weight before the extraction procedure.

After the flow-through extraction tests the core plug was cut in half along the cylinder axis. One half of the material was crushed, powdered and subjected to Rock-Eval pyrolysis and conventional solvent extraction with subsequent compound group analysis. The other half was used for petrographic analysis.

Solvent extraction of bulk samples

To assess the efficiency and exhaustion of the flow-through extraction procedure, aliquots of around 2 g of the original bulk sample were crushed, powdered and extracted with 40 mL DCM for 1 hour in an ultrasonic bath followed by overnight stirring. The extracts were evaporated and the residues weighed to determine the amounts of extracted bitumen. The initial and final bulk extracts, denoted as SEi and SEf, were analyzed with the same procedures as the flow-through solvent extracts (see below).

Flow-through extraction of oil and gas shales 55

3.3.2. Elemental analysis (TOC and TIC)

Total organic carbon (TOC) and total inorganic carbon (TIC) contents of the samples were measured with a LiquiTOC II instrument (Elementar Analysensysteme GmbH) equipped with a solid phase module. The samples were dried and ground to a very fine powder of which approximately 100 mg was transferred into a crucible. Carbon analysis was performed in an oxygen current. The powder was first heated to 550 °C held for 10 minutes and then heated to

1000 °C, held for 400 seconds. The amounts of CO2 released by the combustion of organic compounds up to 550 °C and the degradation of carbonate at higher temperatures were determined using an infrared detector. Based on the CO2 generated, the organic and inorganic carbon content of the samples was calculated. Carbonate content was calculated as calcite (CaCO3 = TIC · 8.333) because this is known to be the dominant carbonate phase in the Lower Toarcian Posidonia Shale (Littke et al., 1991c).

3.3.3. Rock-Eval pyrolysis

Rock-Eval pyrolysis measurements were performed using a DELSI INC Rock-Eval 6 instrument in a nitrogen current. The fundamentals of Rock-Eval pyrolysis are described in Espitalié et al. (1985). Measurements followed the procedures of the Norwegian Industry Guide for Oil and Gas Analysis (NIGOGA; Weiss et al., 2000). The temperature program started at 300 °C; this temperature was held for 3 minutes, followed by a heating phase with a rate of 25 °C/min up to 650 °C. An external standard was used as every tenth sample to ensure a good quality of measurements. Parameters derived from Rock-Eval pyrolysis include S1, S2 and S3 peaks. From the areas of these peaks normalized to TOC, Hydrogen Index (HI), Oxygen Index (OI) as well as Production Index (PI) and the Bitumen index (BI) values were calculated (Table 3-1). Furthermore, the temperature of the maximum rate of pyrolysis yield (Tmax) was measured.

3.3.4. TLC-FID compound group analysis of solvent extracts

Compound group analyses of the solvent extracts were performed by a Thin-Layer Chromatograpy – Flame Ionization Detector (TLC-FID) system (Iatroscan MK-5; Iatron

Flow-through extraction of oil and gas shales 56

Laboratories). The extracted bitumen from each time step as well as the bulk extracts were prepared for TLC-FID analysis by addition of 1 mL of DCM to each sample vial. Each extract composition was determined on a complete thin-layer chromatographic rack consisting of ten Chromarods (type SIII). Each Chromarod was spotted with 3 µL of extract and developed in n- hexane (33 min), toluene (16 min) and a mixture of DCM:MeOH with a volumetric ratio of 93:7 (4 min). The Chromarods were dried after each step for 2 min at room temperature. This procedure enabled the separation and identification of saturated hydrocarbons, mono-and diaromatic hydrocarbons, polyaromatic hydrocarbons resins and other polar compounds and asphaltenes. The FID of the MK-5 instrument was operated with an air flow rate of 2000 mL/min and a hydrogen flow rate of 150 mL/min. The chromatograms were recorded using the Atlas chromatographic analysis system (LabSystems). Peak integration and identification was performed with the corresponding software.

3.3.5. Organic Petrography

Polished sections for organic petrographic analysis were prepared according to the procedures described in Littke et al. (2012). Microscopic analyses were carried out using a Zeiss Axio Imager.M2m microscope for incident light and fluorescence mode illumination equipped with Zeiss VIS-LED light source and a Basler Scout camera system. Observations were made at 500x magnification using a 50x/1.0 Epiplan-NEOFLUAR oil immersion objective with Zeiss immersion oil (ne=1.518; 23°C). Data and image processing was performed with the DISKUS Fossil software suite developed and distributed by Technisches Büro Carl H. Hilgers.

3.4. Results and Discussion

3.4.1. Extractable organic matter (bitumen) - definition

While bitumen is geochemically defined as the soluble part of sedimentary organic matter (in contrast to the insoluble kerogen; Hunt, 1996) of a rock, the term “bitumen” is also used in a petrographical sense, including terms like e.g. pyrobitumen, solid bitumen and migrabitumen (Cardott et al., 2014 and references therein). To avoid confusion, the term “solvent extract” (SE)

Flow-through extraction of oil and gas shales 57 is used in this study when referring to the geochemically extracted bitumen. Solvent extracts from extracted powders are denoted as SEi (i for initial) or SEf (f for final after time-step extraction). Solvent extracts from flow-through tests under tri-axial stress are named according to the extraction time, e.g. SE24h (solvent extract taken after 24 hours).

Solid bitumen in the petrographic sense can be identified and differentiated under the microscope by its fluorescence (Senftle et al., 1987). Most of the solid bitumen observed in the mature and over-mature Posidonia Shale studied here shows only weak fluorescence (Littke et al., 1988). In contrast, strongly fluorescent solid bitumen was found in the plugs after the flow- through extraction experiments in the triaxial cell. This post-extraction solid bitumen is referred to as SBf.

3.4.2. Extraction efficiency

Judging by extract color and gas chromatographic analyses of the last extract fractions, the extraction of the plugs by solvent flow-through experiments was never exhaustive.

The extraction efficiency, as defined here, is the ratio of the total flow-through extract yield and the initial solvent extract sum of total flow-through extract and final solvent extract of the treated plug. It is thus a measure of the accessibility of the extractable organic matter by the solvent- conducting interconnected pore system and provides qualitative and (semi-) quantitative information on the distribution of the bitumen in the source rock.

Fig. 3-3 shows the incremental and cumulative flow-through SE yields for the three samples (Wickensen 10/116, Harderode 10/102 and Haddessen 10/111) as a function of the extraction time steps. For the Harderode sample plug 10/105, oriented perpendicular to bedding, no measurable solvent flow could be established after 72 hours with pressure differential of 10 MPa. For the other three samples, the cumulative yields ranged from 16 to 30 mg/g TOC (1.9 - 2.1 mg/g rock). The extraction efficiencies of these plugs were 54, 40 and 61 %, respectively.

Flow-through extraction of oil and gas shales 58

Fig. 3-3: Cumulative flow-through solvent extract (SE) yields and composition of plug Wickensen (a), Harderode (b) and Haddessen (c).

Flow-through extraction of oil and gas shales 59

This result indicates that even with an efficient organic solvent only a portion of the bitumen present in the carbonaceous shales can be extracted via the natural connected pore space and that extraction efficiency depends on sample orientation. The extraction efficiency is very likely to increase with flow-through time because after establishment of viscous solvent flow through the large interconnected pore system, the extraction process will become diffusion-controlled. Thus, it must be envisaged that solvent (DCM) diffuses from the main flow pathways into dead- end pores or the kerogen, and that bitumen molecules, mobilized by dissolution, counter-diffuse towards the main flow pathways. This concept is supported by the declining SE24h-240h yields (Fig. 3-3). Isolated pores will not contribute to the amount of flow-through extractable bitumen.

3.4.3. Extract composition (compound groups)

Wickensen (0.53 %VRr; 10/116)

Fig. 3-4, Fig. 3-5 and Fig. 3-6 show the results of the TLC-FID compound group analyses of the bulk and sequential extracts for the three samples.

For the immature Wickensen sample (10/116) polyaromatic hydrocarbons are predominant in the bulk extract of the powdered rock (SEi in Fig. 3-4), followed by mono-/diaromatic compounds. Saturates contribute only about 10 % (Fig. 3-4). Polyaromatic compounds are also the predominant group in the sequential extracts, but saturates and mono-/diaromatic compounds occur in approximately equal abundance. With ongoing extraction, the compositions of the extracts change significantly. In the SE24h extract, saturates are much more abundant than in SEi, while the relative percentage of polyaromatic compounds is significantly lower than in the initial bulk extract. While the first flow-through extracts still reveal a higher percentage of mono- /diaromatic compounds than saturates, this difference becomes less pronounced in later extracts

(SE120h+). Here a general compositional pattern emerges where saturates resemble in relative abundance their bulk sample counterparts and mono-/diaromatic hydrocarbon portions are lower than those of the bulk sample. At SE96h+ the relative abundance of the polyaromatic

Flow-through extraction of oil and gas shales 60 compounds exceeds the one of the bulk compound. An overall increase of this compound group can be observed over time, although it shows strong fluctuations.

Fig. 3-4: Organic compound distribution for sample 10/116 (Wickensen) determined via TLC-FID at n=10 per extract. An overall increase of polyaromatic compounds is pronounced here accompanied by a general decrease of mono-/diaromatic compounds and saturates.

Deviations from these general trends can be observed in SE120h and SE240h. The latter shows the lowest percentages of polyaromatic compounds within the entire series, contrasting the general increase of this compound group over time. This results in a relative increase of the other compounds with the exception of polar and asphaltene components. SE120h shows an exceptional distribution in terms of polar and asphaltene compound abundances while yielding the highest percentage of polyaromatic hydrocarbons. The relatively high amount of the former leads to unusually low relative abundances of saturates and mono-/diaromatic compounds in comparison to other extracts adjacent to SE120h (Fig. 3-4).

Flow-through extraction of oil and gas shales 61

The SEi comprises the soluble organic matter in the entire porosity including both large and small pores as well as isolated pores and material sorbed on the surface of kerogen. For the Wickensen

SEi compositional features resemble those of the (cumulative) sequential extracts, indicating that the pore system consists of large and interconnected pores. The major trend in the sequential extracts is a decrease of mono-/diaromatic fractions and an increase in polyaromatic compound yields over extraction time. The latter could be partly desorbed from kerogen or derived from smaller and less accessible pores.

Overall, the SE of the immature sample contains much more polyaromatic hydrocarbons and much less saturates and mono-/diaromatic hydrocarbons than the SEs of both the oil-window and the overmature sample. This difference is attributed to the earliest petroleum generation stage, when few saturated, mono-/diaromatic hydrocarbons are generated.

Harderode (0.88 %VRr; 10/102)

For the oil-window sample from the Harderode well, the SEi is characterized by a predominance of the mono-/diaromatic hydrocarbon fraction, while polyaromatic compounds constitute around 30 % and saturates 17 % of the bitumen. Saturated hydrocarbons are more abundant than in the immature Wickensen sample but less abundant than in the overmature Haddessen sample (see below). Polar and asphaltene compounds show the lowest yields, similar to the other samples investigated (Fig. 3-5).

The compositions of the sequential extracts deviate more strongly from the SEi composition than for the immature/early mature and overmature samples. The saturate fraction of the sequential extracts ranges around 30 % in all time steps with relatively small variation. The strongest variability is observed in the mono-/diaromatic compounds. These yields decrease over time to a minimum around 16 % for SE96h and then steadily increase again. The opposite trend is observed for the polyaromatic compounds the proportion of which increases from SE24h to SE240h and then decreases again steadily. This variation is complementary to the trends of the mono-/diaromatic compound abundances.

Flow-through extraction of oil and gas shales 62

The flow-through extracts of the mature Harderode sample have the highest proportions of polar components (5 %) of the three samples investigated in this study. In the corresponding initial (SEi) and final (SEf) extracts the relative abundance of the polar components is significantly lower (ca. 1 %).

Fig. 3-5: Organic compound distribution for sample 10/102 (Harderode) determined via TLC-FID at n=10 per extract. The abundance of saturates is relatively constant for all time series extracts while the trends observable for the aromatic and polyaromatic compound distribution seems to be coupled (see text for detailed discussion).

The same phenomenon is observed for the asphaltenes, which constitute only negligible proportions of the bulk extracts (SEi and SEf) but correspond to about 1.5 % of the flow-through.

The SE72h flow-through extract of the Harderode samples showed an elevated yield and a deviating composition pattern (Fig. 3-3). It has an elevated mono-/diaromatic compound fraction resembling to the pattern of the bulk solvent extracts (SEi and SEf).

Flow-through extraction of oil and gas shales 63

The initial and final bulk solvent extracts of the Harderode sample SEi and SEf are very similar. Both are characterized by much higher percentages of mono-/diaromatic hydrocarbons than in the immature and overmature samples.

However, the time step extracts differ considerably, providing information on the easily accessible pore system. This system contains much more saturated hydrocarbons and polycyclic aromatic hydrocarbons as well as polars compared to SEi and SEf. In contrast, the percentage of mono-/diaromatic hydrocarbons is much smaller. In the case of Harderode, mono-/diaromatic hydrocarbons seem to be hidden in the non-accessible smaller pores. The accessibility of polyaromatic hydrocarbons increases over time, although with some scatter, indicating that they get partly accessed at a later stage, probably from kerogen surfaces.

Fig. 3-6: Organic compound distribution for sample 10/111 (Haddessen) determined via TLC-FID at n=10 per extract. A steady increase of polyaromatic compounds over time is visible for the sampled extracts which is much more distinct than that of the Wickensen sample (compare Fig. 3-4). In contrast to this increase of the relative percentage, saturates decrease steadily over time. Mono-/diaromatic compounds show a rather random pattern with an initial increase and a subsequent decrease of their abundance.

Flow-through extraction of oil and gas shales 64

Haddessen (1.45 %VRr; 10/111)

Clear trends are visible for the time-step extracts of the overmature sample 10/111 (Fig. 3-6). Overall, the relative amount of saturates decreases over time while that of polyaromatic and polar compounds increases. The SEi composition indicates predominantly saturated hydrocarbon compounds. This composition is nearly matched in late stage extracts (SE192h+). Early time step extracts are even more enriched in saturates while polyaromatic compounds are low in concentration relative to the SEi composition. Subsequent extracts, on the other hand, show a steady decrease of saturates and a corresponding increase of polyaromatic compounds (Fig. 3-6), reaching the level of SEi and SEf. Likewise, asphaltene percentages increase to a level of the SEi asphaltene percentage. Polar components resemble the SEi compositional abundance at SE120h+ with the exception of SE240h. Mono-/diaromatic hydrocarbons slightly increase to SE96h and then decrease again to a percentage equal to that of the SE24h composition.

These observations indicate that extracts from initially connected and easily accessible pore space have substantially different compositions than those that are only accessed after a longer period of time. The presence of high percentages of saturates in the initial time step extracts was also observed for the other samples, but is most pronounced in this overmature Posidonia Shale. Due to the fact that the same solvent (DCM) was used at all times and also for SEi and SEf, a solvent- related selectivity can be excluded. Therefore, this finding indicates an initially low accessibility of more polar compounds (such as polyaromatic hydrocarbons and other polar compounds). Fluid paths are blocked by saturates or polar compounds are preferentially hidden within the smaller pores. Additionally, desorption of the more polar compounds from kerogen or solid bitumen surfaces might occur, but might take time, so that it is not effective in the first time step extracts. Another feature is the increasing asphaltene content over time, which also suggests a late-stage accessibility. Bernard et al. (2012) observed the formation of nanopores in solid bitumen during maturation of gas shales. These, mostly isolated, pores are suggested to originate from gas generation due to secondary cracking of oil. Within this newly generated pore space, polyaromatic and other polar compounds might be concentrated as compared to the larger interconnected inter-mineral porosity. This evolution of pore space might explain, why the

Flow-through extraction of oil and gas shales 65 observed differences in time step extract composition are most pronounced for the overmature Posidonia Shale sample.

Fig. 3-7: Average composition of time step extracts. The proportion of aromatic components in solvent extracts decreases with increasing thermal maturity, while the amount of saturates increases.

3.4.4. Maturity-related compositional changes

Comparison of the compound distribution of the flow-through extracts of samples of different maturity reveals general trends of the hydrocarbon evolution during thermal maturation. Based on FTIR and NMR analyses several authors (Smernik et al., 2006 and references therein; Al- Sandouk-Lincke et al., 2013) report an increase in aromaticity of kerogen with thermal maturity. However, an opposite trend is observed for the bitumen extracted from the accessible pore space by sequential solvent flow-through tests (Fig. 3-7). This might be due to early generation of large molecules within the early mature oil window stage including many polyaromatic compounds (Fig. 3-3). More stable bonds within the kerogen structure such as aliphatic side-chains and small

Flow-through extraction of oil and gas shales 66 aromatic ring systems releasing saturates and mono- and diaromatic hydrocarbons are only broken at higher maturity leading to higher percentages of these compound groups while the kerogen simultaneously becomes more aromatic and more condensed. The aforementioned trends are visible for the average time-step composition and a similar relationship can be observed in the SEis and SEfs (compare Fig. 3-4, Fig. 3-5 and Fig. 3-6).

3.4.5. He-porosity and permeability

Porosity values (determined by He pycnometry) and permeability coefficients measured in this study are similar to those determined by Ghanizadeh et al. (2014) on the same sample set indicating a good reproducibility for these types of measurements. He-porosity is highest (17.8 vol-%) for the immature Wickensen 10/116 sample, decreases to 5.2 vol-% for the oil-mature Harderode 10/102 sample and increases again to 13.4 vol-% for the overmature Haddessen 10/111 sample (Table 3-1). Similar porosity trends with minima in the oil window and subsequent increase in the overmature maturity range have been described for e.g. the Barnett Shale, the New Albany Shale and the Posidonia Shale in the past. The minima are interpreted as a consequence of bitumen blocking pore throats during the main phase of oil generation (Loucks et al., 2009; Bernard et al., 2011; Mastalerz et al., 2013; Ghanizadeh et al., 2014).

Initial permeability before extraction is low for all samples, with Klinkenberg-corrected permeability coefficients of 61.1, 28.3 and 35.9 nD, respectively, and correlates with porosity values. The initial Klinkenberg-corrected He-permeability of the oil-mature Harderode sample orientated perpendicular to bedding was 0.8 nD, and this sample was not permeable to DCM. Therefore, flow-through extraction results are only available for the plug drilled parallel to bedding. Ghanizadeh et al. (2014) found permeabilities parallel to bedding to be higher by one to two orders of magnitude than those measured perpendicular to bedding. The permeability trends are, just like the porosity trends, attributed to pore or pore throat plugging due to bitumen generation and migration. Solid bitumen occurrences, especially in the Posidonia Shale, range from finely dispersed to large solid bitumen bodies and even solid bitumen veins (Littke et al., 1988), which is a clear indicator of extensive hydrocarbon generation and migration. Additionally,

Flow-through extraction of oil and gas shales 67 these solid bitumen particles can be porous, especially in the gas window (Bernard et al., 2013; Klaver et al., 2015). However, the impact of this organic matter-associated pore system on permeability depends strongly on its interconnectivity.

Fig. 3-8: Apparent permeability coefficients determined with helium (Klinkenberg-plot) for all samples measured. Note that no post-extraction permeability measurements could be performed on samples 10/102 and 10/. Plug 10/102 broke in half along the bedding plane after flow-through extraction. Plug 10/105 (Klinkenberg-corrected original gas permeability: 0.8 nD) could not be percolated with DCM.

After flow-through extraction, permeability had increased by factors of 17.0 for the immature Wickensen 10/116 sample and 26.6 for the overmature Haddessen 10/111 sample, with final values in the microdarcy range (1038.6 nD and 955.8 nD, respectively) (Table 3-2; Fig. 3-8). He- porosity increased likewise from 17.8 vol-% to 18.9 vol-% for the immature/early mature Wickensen sample, 5.2 to 5.8 vol-% for the oil-mature Harderode sample and 13.4 to 15.1 vol-% for the overmature Haddessen sample. Permeability after extraction for sample Harderode 10/102 could not be measured due to disintegration of the plug alongside bedding possibly

Flow-through extraction of oil and gas shales 68 caused by bedding parallel fractures, leading to a reduction of cohesion. This problem did not arise for samples orientated parallel to bedding, although open fractures were also present (see organic petrographical section). In the case of Harderode, the sample perpendicular to bedding had a very low Klinkenberg-corrected permeability of 0.8 nD. This permeability is twenty to thirty times lower than the permeability at the immature and overmature stages (Table 3-1).

Table 3-2: Petrophysical and elemental geochemical characteristics of source rock samples after flow-through extraction.

Flow-through extraction of oil and gas shales 69

Fig. 3-9: a and b: Microphotographs of sample Wickensen 10/116 before extraction. a: elongated, bedding parallel fish remains and pyrite. b: same as a) under fluorescent light, also showing the lamalginite dominated matrix of the sample. c-f: Microphotographs of sample Wickensen 10/116 after extraction with open fractures predominantly oriented parallel to bedding (c); incident light image. d: same image in fluorescence mode exhibiting open, bedding parallel fractures (white

Flow-through extraction of oil and gas shales 70 arrows). e and f: fish remains under incident light (e) and in fluorescence mode (f) exhibiting fractures perpendicular to bedding.

3.4.6. Organic petrography

Wickensen (0.53 %VRr; 10/116)

Organic petrographical analyses were carried out to observe probable changes in textural and compositional features before and after extraction. Fig. 3-9a, b show microphotographs of the immature to early mature Wickensen 10/116 sample before extraction, exhibiting a lamalginite dominated layered structure. Additionally, fish remains are commonly encountered in the sample exhibiting a dark color under incident light and yellowish to brownish fluorescence (Fig. 3-9a, b). In the extracted sample few open fractures are present with an orientation parallel to bedding (Fig. 3-9c-d). Fluid flow perpendicular to bedding might be indicated by fractures crosscutting fish remains, possibly acting as connections between the predominant bedding parallel fracture systems (Fig. 3-9e, f).

Harderode (0.88 %VRr; 10/102)

For the oil mature Harderode 10/102 sample, solid bitumen is restricted to a filamentous appearance of some micrometers width and some tens of micrometers length, oriented parallel to bedding showing a dark brown fluorescence color. Occasionally, a second solid bitumen type can be observed, 5-10 µm thick but with a smaller lateral extent oriented bedding parallel. Similar structural features and organic particles can be observed in the extracted sample, which also shows several open fractures. These fractures are mainly oriented parallel to bedding. The fact that sample 10/102 was plugged parallel to bedding gives rise to the interpretation that extraction, driven by primary fluid flow along bedding, destabilized the sample. Nevertheless, the observed open fractures show that DCM also entered the rest of the sample. It is important to note that for the very low permeable sample Harderode 10/105 (see Table 3-1) no differences between the extracted and non-extracted sample could be observed, i.e. this sample showed no signs of open fractures after extraction.

Flow-through extraction of oil and gas shales 71

Haddessen (1.45 %VRr; 10/111)

In the overmature Haddessen 10/111 sample open fractures parallel to bedding have been observed in the non-extracted samples, which are partly filled with non-fluorescing solid bitumen (Fig. 3-10a, b). Similar observations were made by Littke et al. (1988) on a large number of samples from the same well. Solid bitumen occurs also as fine grained particles throughout the sample, constituting a matrix with the mineral matter and as fluorescing lenses (“metaalginite” of Littke et al., 1988). Additional solid bitumen occurs as large vein fillings, i.e. as massif, dark grey bodies in incident light showing no fluorescence (Fig. 3-10a, b). This solid bitumen type is often accompanied by fine grained, grey solid bitumen vein fillings probably originating from a later migration event. The related fracture porosity in the non-extracted sample is possibly the main contributor to the high overall porosity and permeability in comparison to the oil mature sample, although other types of secondary porosity, e.g. in organic matter exist as well (Loucks et al., 2009; Bernard et al., 2012). These fractures are observed to be mainly of bedding parallel nature and can hence be responsible for the large permeability anisotropy measured by Ghanizadeh et al. (2014).

The extracted sample shows the most significant changes resulting from DCM permeation. Fig. 3-10 exhibits large bedding parallel fracture systems crosscutting the whole sample. The largest of those fractures could already be seen macroscopically upon inspection of the sample after extraction. In fluorescence mode, residues most probably precipitated from the DCM solution during drying of the sample show a bright red color (red arrows in Fig. 3-10). This observation indicates that fractures are the result of extraction by DCM permeating through the sample. The fact that the non-extracted sample does not show these features supports that they were created by the extraction procedure. The fractures, as a pathway for DCM, are observed in three different occurrences. Open, empty fractures (white arrows, Fig. 3-10) with no residues are most abundant as well as open fractures partially filled with oil residues. A lesser amount of fractures was observed which are completely filled with residual organic material (e.g. Fig. 3-10d). Additionally, these fractures crosscut an almost perpendicular calcite vein of around 50 µm width (Fig. 3-10d- f). This fracture system, extending through the whole sample, explains the large percentage of 61

Flow-through extraction of oil and gas shales 72

% of total extractable bitumen in comparison to the smaller extraction efficiencies of the immature and oil mature samples.

Fig. 3-10: a and b: Microphotographs of sample Haddessen 10/111 prior to extraction, exhibiting large fracture filling solid bitumen bodies under incident light. c-f: Microphotographs of sample Haddessen 10/111 after extraction. c and d: bedding parallel open fractures (white arrows) and partially filled fractures in fluorescence mode. Fluorescing material of red color (red arrows) are residues of hydrocarbons precipitated from the DCM solution during the drying procedure, showing the prominent flow paths of DCM through the sample. e and f: filled (red arrow) and non- filled (white arrow) bedding parallel fractures crosscutting a mineralized vein showing significant fluid transport through inter-crystalline pore space under incident light (e) and in fluorescence mode (f).

Flow-through extraction of oil and gas shales 73

3.4.7. Evaluation of observations

Fig. 3-11: Schematic model of pore space evolution upon maturation of the Posidonia Shale.

The effect of extraction on the petrophysical and textural features of the investigated organic matter-rich marlstones is significant, creating new porosity. It might be argued that these changes are “artefacts” and that the observed fracture systems have been induced by unloading of the sample after extraction in the tri-axial flow cell or by preparation of the polished sections. While this might have had an effect on the opening width of the unfilled fractures, it does not explain fractures that show residual matter from DCM extraction (Fig. 3-10c-f). These strongly fluorescing residues cannot be observed in the non-extracted sample and have hence been introduced by the extraction procedure. Therefore, it is highly likely that, independent of the actual fracture morphology in the stressed state of the sample, these fractures were (partly) created by extraction. The more extensive fracture systems in all extracted samples compared to those in a non-extracted state suggest fracture generation and fluid flow along these paths. A sealing failure of the lead casing in the tri-axial flow cell leading to a bypass of DCM and hence only surface extraction can be excluded due to the fact that permeability values measured prior to extraction match those reported for the same samples by Ghanizadeh et al. (2014). Therefore, it can be concluded that the extracts gained by this procedure represent the samples’ internal soluble organic matter inventory. Additionally, open fractures which could host DCM as permeate have

Flow-through extraction of oil and gas shales 74 been observed in earlier works on peak oil mature and overmature Posidonia Shale (Littke et al., 1988), similar to the observations made in this study on the non-extracted samples.

Fig. 3-11 shows a schematic overview of pore space evolution upon maturation of the Posidonia Shale. In the immature stage, pore space is strongly influenced by bedding-parallel orientation of alginite and clay mineral dominated matrix, resulting in pores of elongated shape. While these pores are mainly connected parallel to bedding, pore throats perpendicular to bedding allow fluid flow vertically through the rock. Nevertheless, these vertical pathways are much less pronounced, leading to a strong permeability anisotropy (Ghanizadeh et al., 2014). In particular, these pore throats are reported, based on SEM observations, to be up to two thousand times smaller than the actual pore dimensions for the Posidonia Shale (Klaver et al., 2012). In the oil window total porosity is reduced by compaction due to deeper burial and the occurrence of solid bitumen resulting from oil generation, effectively blocking pore throats. This decrease in porosity also results in the lowest permeability measured in the maturity series. Permeability anisotropy prevails during this stage being one to two orders of magnitude lower perpendicular to bedding than parallel to bedding (Table 3-1), controlled by the layered mineral and organic matter matrix, although the long alginite stripes are replaced by metaalginite and solid bitumen. Littke et al. (1988) observed open fractures parallel to bedding in some of the samples from the same well. Thus some migration pathways might exist at the stage of peak oil generation, but the bulk of the rock has very low permeability. In the gas window, porosity is created by secondary cracking of residual organic matter and solid bitumen leading to gas generation and thus increasing total porosity (Bernard et al., 2011). Data from permeability measurements suggests that these new pores are capable of establishing an interconnected system leading to an increase of permeability in comparison to shales in the oil window. Nevertheless, larger effects on permeability enhancement are probably a result of bedding parallel fractures commonly observed in the gas mature stage. While significant amounts of pore space are occupied by solid bitumen, secondary porosity and fractures in combination with residual initial pore space lead to an increase of permeability by up to two orders of magnitude above permeability measured for shales at the peak oil generation stage. Additionally, investigations by Wei et al. (2014) on the New Albany

Flow-through extraction of oil and gas shales 75

Shale suggest an increase of mesopore volumes due to solvent extraction of organic-rich shales at high thermal maturities.

Some implications for hydrocarbon production from the Posidonia Shale can be made from these geochemical and petrophysical observations. Liquid hydrocarbon production has to take place from shales in the early or late oil window. In the early stage (0.6 – 0.8 %VRr), large percentages of initial porosity are still present in the shale, while solid bitumen precipitation has only minor effects on porosity loss. At this stage, hydrocarbons are characterized by high amounts of aromatic and polycyclic aromatic compounds.

Production in the late oil window (1.0 – 1.2 %VRr) would initially yield higher percentages of saturated compounds. Their concentration would be expected to decrease over time of production, whereas that of aromatic compounds would increase. Solid bitumen abundance is high at this stage. Generation of secondary porosity and fractures will enhance permeability and probably new fractures and pathways will be generated during oil production, even without fracking the rock. The amount of bitumen extracted from the plugs is highest (compared to the bitumen yield from the respective powdered material) indicating that production from these late oil/early gas generation stage should be more effective than from peak oil and early mature source rocks.

Production from shales at peak-oil stage would definitely require the generation of artificial fluid pathways to overcome pore throat plugging effects caused by extensive solid bitumen abundance in combination with the absence of secondary porosity and few secondary fractures.

Finally it should be noted that only one or two samples from the 30-40 m thick Posidonia Shale sequence drilled in each of the three wells were studied here. The lithotypes of the Posidonia Shale range from marly claystones to marlstones; also some variability in organic geochemical properties occurs. Thus the three samples cannot be considered to be representative of the entire black shale sequence.

The question remains of how an “adsorbed oil” fraction as proposed by Schwark et al. (1997) influences the general hydrocarbon composition during the sequential extraction. Schwark et al. (1997) observed a decrease in aliphatic components over time in sequential extracts and an

Flow-through extraction of oil and gas shales 76 associated increase of resin and asphaltene yields, accompanied by a strong decrease of recovered solvent volumes. Although the extractions performed by Schwark et al. (1997) concentrated on reservoir sandstones, some implications can be derived for the extraction of source rocks. Due to the high amounts of organic matter and clay minerals in organic-rich shales, adsorption of oil fractions is highly likely in such systems. However, Schwark et al. (1997) used a variety of different organic solvent combinations to specifically remove adsorbed oil separately from a “free oil” phase. By using only a specific solvent like DCM through the whole extraction procedure, as it was performed in this study, extracts cannot be easily distinguished as holding hydrocarbons from a free or adsorbed phase. However, the Haddessen sample showed a clear trend of compositional changes over time which corresponds to the findings of Schwark et al. (1997). The decrease in saturated components with increasing polyaromatic and polar components as well as asphaltenes could indicate removal of adsorbed hydrocarbon phases.

3.4.8. Mass balance

The volumes of DCM percolated through the samples during the individual extraction steps have been calculated from the masses and the density of DCM (1.3266 g/cm³ at 20 °C). These volumes were then normalized to the pore volumes of the samples as determined by helium pycnometry. The detailed masses and volumes of DCM and masses of hydrocarbon extract for each time step are listed in Table 3-3. The total volumes of DCM percolated through the samples ranged between 5 and 10 pore volumes.

For the Wickensen sample the volume of DCM recovered at each time step corresponded to approximately 1.06 of the original pore volume (He accessible) while for the Harderode sample the average percolation volume was only about one half of the pore volume and 60 vol-% for the Haddessen sample. Judging from the amounts of DCM recovered in the individual extraction steps and the extraction efficiencies it is very likely that only a certain portion of the total pore volume was percolated by DCM and that channelized flow occurred through the sample. This is supported by observations of hydrocarbon residues probably precipitated from solution in fractures of the

Flow-through extraction of oil and gas shales 77

Haddessen sample. Detailed results of initial and final extract masses as well as the cumulative time sequence extracts for individual compound groups are shown in Table 3-4.

For the Wickensen sample the total extract from the original sample (normalized to 1 g of rock mass) amounted to 3.48 mg/g rock (26.72 mg /g TOC), while the final extract yield was 1.63 mg/g rock (13.14 mg/g TOC). This goes along with a strong reduction of S1 values and the according changes in PI and BI values (Table 3-1 and Table 3-2). While these values indicate an extraction of about half of the original solvent extract during sequential plug extraction, 2.03 mg/g rock (15.59 mg/g TOC) were recovered in the time step extracts (Table 3-4). For the Wickensen sample, extraction masses recovered during the sequential procedure match the difference between the solvent extract masses from the powdered cutting material (SEi) and the residual extraction mass from the powdered plug sample (SEf) very well. The small deviation occurring in this balance might be caused by inaccuracies regarding weighing procedures for these small amounts of extracts. From this data an extraction efficiency of 54 % can be determined.

Table 3-3: Effluent masses and volumes of DCM at 20°C (ρ = 1.3266 g/cm³) and extract yields of the individual sequential steps. The DCM volume was normalized to the initial pore volume of the plug as determined by He-pycnometry.

Flow-through extraction of oil and gas shales 78

Table 3-4: Extract yields of compound groups for the bulk original sample (SEi), the sample plug after flow-through experiment (SEf), and cumulative sequential extracts (SEt) as well as respective extraction efficiencies. Yields are normalized to the mass of 1 g of rock and initial/final TOC contents.

Flow-through extraction of oil and gas shales 79

For the Harderode sample a large disparity in mass balance occurs. For this sample, the initial and post-experimental extracts amount to 3.25 mg/g rock (41.10 mg/g TOC; Table 3-4) and 3.06 mg/g rock (38.85 mg/g TOC), respectively. However, the sequential yield amounted to 2.07 mg/g rock (26.22 mg/g TOC) and therefore exceeds the recorded difference of extract mass between the powdered cuttings (SEi) and the powdered plug sample (SEt) by far. Rullkötter et al. (1988) reported the average extraction yield for Harderode samples as being 110.6 ± 22.2 mg/g TOC based on the analysis of 17 samples. Although Rullkötter et al. (1988) investigated a larger sedimentary sequence spanning over 31 m in this well, the measured yields of 41.1 mg/g TOC (for

SEi; Table 3-4) in our study seem to be very low in comparison. By assuming that the amounts of extractable organic matter determined for SEi does not represent the maximum amount of solvent extract recoverable from the extracted plug, the amounts of sequential extracts (SEt) and the residual extracts of the plug sample after treatment (SEf) can be combined to evaluate the maximum amount of extractable organic matter present in the plug sample before sequential extraction (SEt + SEf). This way, the initially available extractable organic matter in the plug sample would amount to 79.95 mg/g TOC. This value is still lower than the values published by Rullkötter et al. (1988) but is almost double the amount of the extract mass of the powdered cuttings and is hence more reliable for evaluating the extraction efficiency (40 %) for the Harderode sample. However, judging from the limited changes of S1, BI and PI for the Harderode sample before and after extraction, extraction efficiencies seem to be much lower than determined by this method. Reasonably higher bulk extraction yields as published by Rullkötter et al. (1988) seem to be more probable.

Another problem occurs in the mass balance of the Haddessen sample. The masses of solvent extract before and after sequential extraction amounts to 1.86 mg/g rock (28.90 mg/g TOC; Table 3-4) and 1.19 mg/g rock (18.52 mg/g TOC), respectively. The cumulative sequential extraction yielded 1.89 mg/g rock (29.39 mg/g TOC) in total. Therefore, the amount of sequential extracts

(SEt) gained exceeds the initially determined bulk extraction mass determined on powdered cuttings (SEi). While the amount of extractable organic matter for the powdered cuttings matches the published data by Rullkötter et al. (1988) for Haddessen samples (29.1 ± 2.6 mg/g g TOC), the combined extraction mass of SEt and SEf (47.91 mg/g TOC) exceeds this value. However, this

Flow-through extraction of oil and gas shales 80 discrepancy is not as strong as for the extract masses gained from powdered cuttings of the Harderode sample. Nevertheless, S1, B1 and PI values for the Haddessen sample indicate an effective removal of soluble organic matter from the plug caused by the sequential extraction runs. The calculated extraction efficiency of 61 % can therefore be taken as indicative.

Based on the amount of difficulties encountered in a mass balancing approach for the Harderode sample, further investigations on the small scale variability of TOC content and extract yields is needed to establish reliable standards for flow-through experiments of this kind for future analyses on larger sample sets.

3.4.9. Gas shale equivalent

To address the probable performance upon hydrocarbon and especially methane production from the Posidonia Shale, characteristic properties of the Posidonia Shale can be compared to an already producing shale gas play in the US. The most conspicuous mineralogical property of the Posidonia Shale is its carbonate richness (up to 60 vol-% carbonate; Littke et al., 1991a; Gasparik et al., 2014) combined with relatively low percentages of quartz and clay minerals. The Cretaceous Eagle Ford shale in the US is also characterized by very high carbonate contents (up to 60 vol-%; Jarvie, 2012) and varying quartz and clay mineral contents. Furthermore, the kerogen of the Eagle Ford shale is of marine origin and is classified as type II like the Posidonia Shale. Present day TOC values (at overmature stages) account for up to 8.5 wt-% in the Eagle Ford shale (Jarvie, 2012) which also reflects the properties determined for the Posidonia Shale. Additionally, secondary porosity in organic matter due to gas generation present in the Posidonia Shale (Bernard et al., 2013) also occurs in the Eagle Ford shale (Walls and Sinclair, 2011).

However, permeability values reported for the Eagle Ford shale are, on average, ten times higher than those of the Posidonia Shale, ranging up to 1 µD (Jarvie, 2012) in comparison to 0.100 µD for the Posidonia Shale (Ghanizadeh et al., 2014). This might be caused by less pronounced solid bitumen plugging. The high amounts of solid bitumen identified in the Posidonia Shale samples might provide high capacities for gas adsorption in this shale sequence, combined with the occurrence of secondary organic matter porosity. In this regard, Gasparik et al. (2014) report an

Flow-through extraction of oil and gas shales 81 excess sorption value of 0.11 mmol/g at 10 MPa and 65 °C for dry overmature Haddessen samples in comparison to 0.07 mmol/g for dry oil-mature Harderode samples, 0.04 mmol/g for an Eagle

Ford sample of 0.9 %VRr (similar to Harderode) and values ranging between 0.01 and 0.1 mmol/g for Barnett Shale. All above sorption isotherms were measured at the same pressure and temperature conditions. Methane production from gas shales would initially drain free gas until a disequilibrium between the free and adsorbed gas phase in these shales would result in desorption of gas molecules from organic matter surfaces, caused by a reduction in pore pressure. The overall well established pore network, including the organic matter porosity, as determined by the flow–through extraction runs would support the drainage of hydrocarbons from a large percentage of the total pore volume.

3.5. Conclusions

The solvent flow-through extraction of core plugs under controlled stress conditions performed in this study has provided new information on the accessibility and composition of bitumen in the Posidonia Shale at different maturities. Furthermore, the experiments revealed details on porosity and permeability evolution, the distribution of bitumen in the pore system and potential fluid pathways. The following conclusions can be derived:

1) Porosity and permeability of the shales decrease dramatically within the oil window leading to very low values at peak oil generation stage. A subsequent increase of both these petrophysical parameters was observed towards the overmature stage of the Posidonia Shale. Permeability parallel to bedding of Posidonia Shale at peak oil generation is one to two orders of magnitude higher than permeability perpendicular to bedding. 2) Bedding-parallel fractures and solid bitumen-filled veins occurred in the Posidonia Shale at peak oil generation and overmature stage, but not at the immature stage. 3) Different types of solid bitumen occur in oil-mature and overmature rocks.

New insights obtained by this procedure are:

Flow-through extraction of oil and gas shales 82

1) Extraction efficiencies from the natural pore system for immature/early mature (54 % of total extractable bitumen), oil-mature (40 % of total extractable bitumen) and overmature Posidonia Shale (61 % of total extractable bitumen) are are good but not exhausting. 2) The molecular composition of the bitumen from the natural pore system varies significantly with progressive extraction. 3) The compositions of the cumulative solvent flow-through extracts differ significantly from the bulk solvent extracts of the shales. 4) The original fracture and transport pore system of the shale samples is extended by DCM extraction resulting in an increase of He-porosity by 0.6 to 1.7 %. 5) Preferred fluid flow occurs parallel to bedding, even across mineralized veins. This is supported by hydrocarbon precipitation from DCM solution in bedding-parallel fractures. 6) The initial Klinkenberg-corrected permeability increased by a factor of 17 for the immature Posidonia Shale from 61.1 nD to 1038.6 nD and by a factor of 27 from 35.9 nD to 955.8 nD for the overmature shale due to bitumen extraction from the natural pore system. 7) For liquid hydrocarbon production at oil-mature stages, highest yields from the natural pore system can be expected in the early and late oil window. In the early oil window, the effect of solid bitumen plugging is indicated to be of minor influence and the primary pore network provides sufficient flow paths resulting in relatively high permeabilities. The hydrocarbon composition at this stage would be dominated by aromatic and polyaromatic compounds. In the late oil window, the onset of secondary porosity generation leads to higher permeabilities in comparison to peak oil mature shales where a permeability and porosity minimum is pronounced due to extensive solid bitumen pore plugging. Hydrocarbon compositions are expected to be enriched in saturates at early production stages, while aromatic and polyaromatic compound percentages would rise over production time.

Finally, it should be noted, that analysis on more samples is necessary in order to understand porosity and permeability changes in the Posidonia Shale which is composed of marly claystones and marlstones with variable carbonate content.

High-resolution 3D numerical basin modelling 83

4. Estimates of shale gas contents in the Posidonia Shale and Wealden of the west- central Lower Saxony Basin from high-resolution 3D numerical basin modelling

4.1. Abstract

A high resolution 3D numerical basin model of the west-central part of the Lower Saxony Basin was built to reconstruct the thermal and burial/uplift. The main objective of this study was to estimate the gas content in two source rock formations, namely the Posidonia Shale and the Wealden shales. Based on the organic-geochemical data and source rock quality for subunits of these formations the gas storage capacity of these gas shale horizons was analyzed in detail. The numerical simulations included the drafting of bulk adsorption capacity and adsorbed gas content maps as well calculations regarding the amount of gas stored in the pore space of these rocks in the central part of the basin where these source rocks reached high thermal maturities, i.e. the gas window. The reconstruction of the gas generation and storage history show that these parameters depend strongly on the burial/uplift history of the inverted Lower Saxony Basin. While the rapid burial prior to inversion led to an effective generation and storage of methane in these rocks, the subsequent strong uplift had only a small influence on the total amount of adsorbed gas. At present day, the Posidonia Shale and the Wealden shales are undersaturated in methane regarding the bulk adsorption capacity and the amount of gas which is actually present in an adsorbed phase. For the Posidonia Shale, the reduction in adsorbed gas content was caused by deep burial and high temperatures, leading to a reduction in adsorption capacity and subsequent desorption of gas volumes. For the Wealden shales, which did not reach burial depths similar to those of the Posidonia Shale, a reduction of adsorption capacity and hence adsorbed gas contents was caused by uplift during the Late Cretaceous basin inversion.

4.2. Introduction

In recent times, hydrocarbon production from unconventional resources gained strong interest due to the rising oil and gas prices. While this development has led to a “shale gas boom” in the US, potential source rock horizons are now also investigated in other parts of the world to assess the shale gas potential. In Germany, most promising formations can be found in the Palaeozoic,

High-resolution 3D numerical basin modelling 84 namely the Namurian Upper and Lower Alum Shale (Uffmann et al., 2012; Uffmann and Littke, 2013; Uffmann et al., 2014), and the Mesozoic strata of Northern Germany. In the Mesozoic, the main focus lies on the Posidonia Shale (Bernard et al., 2013; Bruns et al., 2013; Bruns et al., 2015) and the shales of the Wealden (Berner et al., 2010; Berner, 2011; Rippen et al., 2013; Ziegs et al., 2014), which are both also known to be effective source rocks for conventional oil accumulations (Littke et al., 2008). Recently, BGR published a compilation on shale gas in Germany (BGR, 2016), concluding that the Lower Saxony Basin bears the highest shale gas potential. The latter two formations are in the focus of this work about the Lower Saxony Basin. In a previous work, the task to estimate gas contents and adsorption capacity in these source rocks was approached by 3D numerical basin simulation utilising sorption and organic geochemical data for a wider area (Bruns et al., 2015). These numerical models had a resolution of 1000 x 1000 m per cell and defined the source rock formations as homogenous strata, ignoring vertical heterogeneity for the sake of reducing complexity and computing time. Especially for the Wealden Shale, geochemical parameters were taken as an average across the whole succession, which is a strong simplification, considering that lithological horizons with variable source rock qualities are distributed across the entire Wealden formation (Berner et al., 2010; Berner, 2011; Rippen et al., 2013). The inventory of organic carbon and hence kerogen depends strongly on the development of the appropriate facies, which is of fresh to brackish water lacustrine conditions for the Wealden Shales. These conditions are known to have changed periodically over the depositional history of the Wealden Formation (Elstner and Mutterlose, 1996). The Wealden Formation reaches a maximum thickness of 1100 m in the Lower Saxony Basin of which only a fraction can be regarded as an excellent source rock based on total organic carbon content, occurrence of low-salinity algae types and kerogen quality. For the Posidonia Shale, the same rules apply. While the thickness reaches around 40 m on average, a threefold subdivision with changing lithologies and source rock parameters can be applied following Littke et al. (1991) and Frimmel et al. (2004). In the latter paper, chemostratigraphic methods were mainly used to investigate the Posidonia Shale in Southwest Germany, while Littke et al. (1991) focused on the geochemical source rock quality and mineralogy of the Posidonia Shale in the Hils Syncline to identify different units. Nevertheless, both subdivisions more or less correlate with each other. Based on these findings, a reassessment of the Posidonia Shale and the Wealden Shales regarding the oil and gas shale potential in the

High-resolution 3D numerical basin modelling 85 west-central Lower Saxony Basin is performed in this work, using a high-resolution 3D numerical basin modelling approach, which incorporates the detailed stratigraphy of these source rocks.

Fig. 4-1: Overview map of Germany and the Lower Saxony Basin (modified from Senglaub et al. 2006) with a geological map based on the depth maps of Baldschuhn et al. (1996), utilised for the 3D numerical basin model in this study, and geographical/geological features of the study area. Main faults are shown by dashed lines.

High-resolution 3D numerical basin modelling 86

4.3. Geodynamic evolution

The Lower Saxony Basin (LSB) is one of the inverted Permo-Triassic sedimentary basins of the Central European Basin System (Littke et al., 2008) and covers an area of roughly 30 000 km2. The basin’s structural borders are defined by the Pompeckj Block in the north, the Gifhorn Trough in the east, the Rhenish Massif in the south and the East-Netherlands High in the West. Our study is focused on the west-central part of the Lower Saxony Basin, roughly between the rivers Ems in the west and Weser in the east (Fig. 4-1), including the northern margin bordering the Pompeckj Block.

In the Central European Basin System, basin formation started with subsidence during the Late Permian, resulting in the deposition of thick cyclic carbonate and salt deposits in a restricted shallow marine environment, caused by several transgressions and regressions (Zechstein cycles; Warren, 2008). The bulk of the sedimentary rocks that accumulated in the basin are, however, of Mesozoic age. In the Triassic, further subsidence coupled with rifting activity occurred. Terrestrial to deltaic, thick sedimentary rocks represent the Early Triassic. (It should be noted that the German subdivision Buntsandstein–Muschelkalk–Keuper does not correspond exactly to the international stratigraphic subdivision of the Triassic; see Stollhofen et al., 2008). Additionally, salt movement set in, creating salt pillows and diapirs especially in the northern parts of the Central European Basin System. A change to marine conditions is apparent in the Middle Triassic when carbonates and evaporites were deposited. After renewed continental deposition in the latest Triassic, marine conditions set in and prevailed during the Early Jurassic, when clastic sedimentation continued. During the Jurassic, a major transgression event led to the establishment of an extensive epicontinental sea in which euxinic conditions occurred, resulting in the deposition of the Toarcian Posidonia Shale. Tectonically, the Late Jurassic induced the nucleation of the Lower Saxony Basin evolution as an independent basin. While extension and strong subsidence occurred in the LSB, uplift of the surrounding areas led to a separation of the basin system. Subsidence progressed in the LSB during Early Cretaceous times and the depositional environment changed to a non-marine setting in the Berriasian, resulting in the deposition of lacustrine cycles, including the Wealden Shales, of up to 700 m thickness in the central part of the basin and roughly 400 m at the basin margins (Stollhofen et al., 2008). In detail,

High-resolution 3D numerical basin modelling 87 the Wealden Formation is characterized by several marine transgressions, which led to the deposition of limestones and claystones, interbedded with the lacustrine shale sediments. From the Valanginian onwards, marine conditions prevailed for the rest of the Early Cretaceous. In the Late Cretaceous, basin inversion induced by Africa–Iberia–Europe convergence (Kley and Voigt, 2008) caused intense uplift and erosion of the Mesozoic strata in the LSB. Post-inversion Tertiary deposits can be found in the LSB, accompanied by minor erosional events in the Miocene and Pliocene, followed by Quaternary sedimentation. The evolution of the Lower Saxony Basin is described in Littke et al. (2008) and Bruns et al. (2013). A SW–NE transect after Littke et al. (2008) is shown in Fig. 4-2, depicting the major fault system present during the deposition of the Wealden (Early Cretaceous), the Late Cretaceous basin inversion and the present day structure.

4.4. Methods

To assess hydrocarbon generation and storage of the Posidonia Shale and the total organic carbon (TOC)-rich Wealden Shales, a 3D basin model was constructed using the Schlumberger AaTC PetroMod® software v.2013.2. This numerical basin modelling software uses forward modelling techniques to reconstruct the history of a basin by integrating geological events such as sedimentation and erosion as well as geochemical and petrophysical processes over geological times. The evolution of these properties is calculated for defined cell dimensions and time steps starting with the deposition of the oldest layer and subsequently progressing forward to the present time step. During the successive reconstruction of the modelled basin, rock properties such as compaction and temperature are calculated and assigned to each cell. Additional properties such as total/effective porosity, thermal maturity, hydrocarbon generation and expulsion/retention, fluid flow/migration, petroleum composition and adsorption capacity are determined based on these basic simulated results (Hantschel and Kauerauf, 2009; Bruns et al., 2015).

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Fig. 4-2: A SW–NE transect through the Lower Saxony Basin after Littke et al. (2008) showing the major structural elements (faults) during the Early Cretaceous (deposition of the Wealden), the Late Cretaceous basin inversion and at present day. Location is shown in Fig. 4-1.

High-resolution 3D numerical basin modelling 89

4.4.1. Model definition

This study focuses on the west-central part of the LSB. Roughly, the eastern and western borders of the model are marked by the rivers Ems in the west and Weser in the east. This area of interest was determined based on Bruns et al. (2013) and Bruns et al. (2015) in which thermal maturity maps revealed this area as most promising for the investigated source rocks to have generated and stored shale gas, but also shale oil. Additionally, the dimensions of the model are loosely confined by the abundance of the Wealden shale source rock facies. The model itself covers an area of 52.2 km in east-west and 117 km in north-south extent with a total number of nearly 6.5 million cells and a high horizontal resolution of 150 x 150 m. The vertical resolution is defined by the individual layer thicknesses and is confined to a maximum vertical cell size of 400 m. The model consists of 24 layers ranging from Triassic to Quaternary deposits. Additionally, the model is underlain by a basement layer of a constant thickness of 2000 m. Corresponding depths horizon maps for the Mesozoic strata have been used from the Geotectonic Atlas of NW-Germany by Baldschuhn et al. (1996) in their maximum initial resolution of 150 x 150 m.

Table 4-1: Sedimentary thicknesses and organic geochemical source rock parameters for the investigated horizons.

4.4.2. Stratigraphy and lithology

A detailed stratigraphic input list with corresponding depositional ages and lithology types is shown in Table 4-1. While the depositional ages of each unit are defined based on the German Stratigraphic Chart (STDH, 2012), lithologies have been mainly compiled from Ziegler (1990) by unifying the main lithological features represented in the according sedimentary strata. Changes

High-resolution 3D numerical basin modelling 90 in facies within the investigated area have been taken into consideration, which is an important factor e.g. for the Wealden Shales due to the relatively confined palaeogeographic occurrence of the lacustrine system in which these sediments were deposited. In general, specific, mixed lithologies were used for most of the units because predefined lithologies included in the PetroMod software were too inaccurate to describe the petrophysical properties. Source rock horizons were split into several layers with individual rock properties. The petrophysical properties inherent to all lithology types are essential parameters for the model. These properties include the amount of elements (U, Th, 40K), which produce heat through radioactive decay, the thermal conductivity, heat capacity, density, initial porosity and the Athy’s factor, which describes the compaction behaviour of a rock. While these parameters are inherent to the individual lithologies, additional boundary conditions, controlled by the basin’s evolution and geological history, substantially affect the thermal regime.

4.4.3. Source rock characteristics

Next to achieving a very high horizontal resolution, the main target of the new model is to analyse different lithostratigraphic subunits of the Posidonia Shale and the Wealden Shale in detail. For the Posidonia Shale a threefold subdivision (Posidonia I–III) is utilised, which is mainly defined by mineralogical composition and varying average TOC contents for the individual horizons. The lowermost Posidonia I unit is classified as an organic-rich marlstone yielding in different profiles up to 60 wt-% CaCO3 on average (Littke et al., 1991; Gasparik et al., 2014). The TOC content of this unit reaches average values of 10 %. The basal succession is the thinnest for all three units, corresponding to 8 m out of the total thickness of 40 m for the Posidonia Shale. For Posidonia II, carbonate contents are significantly lower, reaching only 40 wt-% CaCO3 on average (Littke et al. 1991), defining the lithology as carbonaceous shale. TOC contents are slightly lower, averaging around 9 wt-%. This is caused by the incorporation of a “low-carbon zone” in unit II described by Littke et al. (1991), which leads to an overall lower average TOC content. Posidonia III is characterised by a similar mineralogical composition, but generally higher TOC contents, averaging at 12 wt-% (Table 4-2).

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The Wealden Shales are characterised by a strongly heterogeneous thickness distribution across the Lower Saxony Basin depending on the occurrence and extent of the lacustrine systems during the time of deposition. In total, four source rock horizons (Wealden I–IV) have been defined based on the depth and thicknesses present in three wells investigated in the study area by Rippen et al. (2013). Due to the lack of detailed lithological descriptions of the bituminous source rock intervals in the Wealden in publicly available literature, standard shale lithologies incorporating varying TOC contents (Table 4-2) defined in the PetroMod software have been used (compare Table 4-1). These lithologies have been mixed with fractions of a marlstone lithology to account for the carbonates in schill and lumachelle layers typically occurring in these shales (Füchtbauer and Goldschmidt 1964, Berner et al. 2010). Interbedding these source rock horizons, organic-lean shale intervals have been defined (“Wealden 1–4 non source”). It has to be noted that the numbering of the source rock intervals is not related to the lithostratigraphic subdivision of the Wealden (Wealden 1–6; Mutterlose and Bornemann, 2000) and only reflects the occurrence of the respective source rock horizons in the sedimentary column.

4.4.4. Source rock thickness

To define the thickness of the individual Wealden Shale horizons throughout the LSB, the uppermost interval of the combined Upper Jurassic and Wealden stratigraphy derived from Baldschuhn et al. (1996) has been split into several units with a fixed thickness ratio. This is a necessary simplification due to the lack of detailed depth maps of these units. A comparison between the depths and thicknesses reported by Rippen et al. (2013) for the location of three wells with the model input showed a good agreement. The combined maximum thickness for the Wealden Shales, including source rock and non-source rock intervals, reaches around 950 m in the basin centre, which is smaller than thickness data published by Bruns et al. (2015). However, it has to be noted that the lowermost Wealden members beneath the first defined source rock interval investigated by Rippen et al. (2013) are not resolved and the total thickness of the Wealden is therefore assumed to be larger. Resulting from that, the modelled layer beneath the Wealden comprises the Upper Jurassic and Lower Berriasian strata (Table 4-1). For the Posidonia Shale, a constant combined thickness of 40 m was defined throughout the investigated area.

High-resolution 3D numerical basin modelling 92

Thicknesses of the divided lithological groups are 8 m for the lower most unit and 16 m each for the middle and upper units and have been simplified after the observations from Littke et al. (1991) and Frimmel et al. (2004). It should be noted, that in reality some thickness variation has to be expected for the marine Posidonia Shale (see Song et al., 2015) and a very significant thickness and facies variation for the lacustrine Wealden Shales.

4.4.5. Kinetic parameters

Kinetic data can describe processes depending on temperature and time quantitatively, e.g. petroleum generation, increase of vitrinite reflectance, smectite-illite transformation. Processes affecting sedimentary systems in a temperature regime between 0 and 300 °C are almost always kinetically controlled and thus differ from metamorphic processes at temperatures above 300 °C. To accurately model the hydrocarbon generation potential and timing of the source rock intervals, predefined kinetic data can be used in the Petro- Mod software, which are based on published information. Nevertheless, custom-made kinetics measured on the investigated source rocks will usually lead to results that are more precise. In our model, kinetic data published in Bruns et al. (2015) were utilised, which are derived from Di Primio and Horsfield (2006). This so-called “PhaseKinetics” approach is based on compositional kinetic analyses and includes additional parameters such as secondary cracking. Compositional kinetics are measured by a gas chromatographical analysis of petroleum components released during the pyrolysis of kerogen from the respective source rock interval. While Di Primio and Horsfield (2006) performed a detailed phase analysis of 14 compounds, the complexity of such a phase system is simplified by reducing these results to four compound groups, which are C1 (methane), C2–C5, C6–C14 and C15+ compounds. In this phase model it is assumed that compounds >C6 can generate methane due to secondary cracking. As a basis for the calculation of hydrocarbon generation, TOC and HI values have been assigned to the individual source rock horizons based on analyses by Rullkötter et al. (1988) for the Posidonia Shale and Berner (2011) as well as Rippen et al. (2013) for the Wealden Shales (Table 4-1). However, it has to be noted that the HI values assigned for the Posidonia Shale represent low-end values.

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Table 4-2: Stratigraphic age assignment and petrophysical properties of the user-defined lithologies.

.

High-resolution 3D numerical basin modelling 94

4.4.6. Calculation of gas adsorption

Adsorption of methane on organic matter or clay minerals is an important storage mechanism in shales (Gasparik et al., 2014) and even the predominant mechanism in coals. Adsorption depends on pressure and temperature, but also on competition of different fluids for sorption sites (i.e. water, methane, carbon dioxide), type of organic matter and clay mineralogy (Merkel et al., 2015). Adsorption capacity for the organic-rich shale intervals was calculated based on the Langmuir approach. For this method, laboratory data on Langmuir sorption parameters had to be defined.

These parameters include the Langmuir pressure (PL), the Langmuir volume (VL), the sorption enthalpy (Edes) and a reference temperature at which the experimental measurements were performed (T0; 65 °C). These parameters have been adapted from Gasparik et al. (2014) and are defined for a sample of the Posidonia Shale with a fixed TOC content (7.7 wt-%) and a vitrinite reflectance value (1.5 %VRr) to which the data was normalised. By defining a scaling factor in the Petro-Mod software, it is assumed that the complete amount of kerogen is able to adsorb methane, including inert kerogen at higher thermal maturities. For the Wealden Shales, Langmuir parameters have been adapted from Bruns et al. (2015) and are listed in Table 4-3.

4.4.7. Boundary conditions

The thermal boundary conditions of a model consist of the heat flow, which is applied to the base of the sedimentary column and the surface water interface temperature. The average heat flow of the continental crust is 60 mW/m2 at present time (Allen and Allen, 2013) and fluctuations and changes throughout the geological history of a basin depend strongly on events such as rifting phases and subsequent cooling of the lithosphere. Rifting phases are usually accompanied by a relatively fast increase in basal heat flow, while the following thermal rebound happens gradually over time until constant heat flow is reached (Waples, 2001). By assuming present-day continental lithosphere conditions between rifting phases, this average value is assumed as 60 mW/m2. The surface water interface temperature (SWIT) serves as a fixed temperature value at the surface of the sedimentary column from which the geothermal gradient is calculated. The SWIT is derived from palaeobathymetric data at the sediment surface-water contact and strongly depends on the palaeogeographic latitude of the basin and – in case of marine conditions – on palaeo-water depth. In PetroMod, the palaeolatitude and resulting global mean surface

High-resolution 3D numerical basin modelling 95 temperatures are based on the reconstruction by Wygrala (1989), while palaeobathymetric data were implemented from various sources (Kockel, 2002; Miller et al., 2005; Littke et al., 2008).

Fig. 4-3: Calibration of the modelled and measured vitrinite reflectance data (crosses) of three cells in the northern (A), central (B) and southern (C) part of the study area. Variations in total eroded sedimentary thicknesses and heat flow values have been applied to investigate the sensitivity of the calibration. The used heat flow trend based on Bruns et al. (2013) (D) for the Lower Saxony Basin with incresed heat flows due to rifting events is shown in the lower part.

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4.4.8. Calibration

Calculation of vitrinite reflectance utilised the Easy-R0 approach by Sweeney and Burnham (1990) in PetroMod as this algorithm covers a wide range of vitrinite reflectance (0.3–4.6 %VRr). Calibration of the resulting model was performed by comparing the calculated vitrinite reflectance and downhole temperature data with measured data from wells and outcrops. In total, 147 locations (wells and outcrops) within the modelled area were used to reconstruct the burial history of the LSB. 144 of these locations were also utilised in the model of Bruns et al. (2013). Three additional wells have been included based on Rippen et al. (2013), for which detailed vitrinite reflectance data are available. The source rock intervals for the Wealden Shales were defined based on data from these wells.

Fig. 4-4: Total erosion thickness map (Late Cretaceous erosion) for the West-Central Lower Saxony Basin. Strongest erosion affected the south-western part of the basin (north-west of the city of Osnabrück) where a maximum of 7000 m of sediments were eroded during the Late Cretaceous basin inversion.

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Table 4-3: Assigned Langmuir sorption parameters. *Input parameters in PetroMod; standard temperature and pressure (STP) at 273.2 K and 0.1 MPa. Data has been adapted from Gasparik et al. (2014) for the Posidonia Shale and Bruns et al. (2015) for the Wealden.

4.5. Results and Discussion

4.5.1. Maturity and temperature evolution

Fig. 4-3 shows the calibration for three representative wells in the southern, central and northern parts of the investigated area. Variations in the total eroded sedimentary thicknesses and heat flow trend have been applied to investigate the influences of these parameters on the calibration quality. From Fig. 4-3 it is apparent that the best model fit is achieved by implementing the highest eroded sedimentary thicknesses in the southern parts of the LSB where Triassic strata are exposed at the surface, in combination with increased heat flows during rifting events. For the exemplary well in this area, a cumulative eroded thickness of 4000 m fits the measured vitrinite reflectance data very well (Fig. 4-3). The total amount of eroded sedimentary thickness decreases steadily towards the north. In the central part of the basin, where Lower Cretaceous sediments are preserved, the amount of eroded sedimentary thickness decreases to about 1000 m and to much lower values in the northern parts of the LSB. A modification of the total amount of eroded sedimentary thickness by 400 m or more results in a less accurate calibration. By setting the heat flow to a constant value of 60 mW/m2 over time, the effect of increased heat flows during rifting events on the calibration can be assessed (Fig. 4-3). While these heat flow peaks had no significant effect on the deeply buried sedimentary strata in the south, a negative shift of calculated vitrinite reflectance values in comparison with the measured values can be seen for the central and northern part of the LSB. In these regions the periods of increased heat flow had a significant effect on thermal maturation of the sedimentary column.

High-resolution 3D numerical basin modelling 98

In contrast, while small adjustments of 5 mW/m2 (Fig. 4-3) to the heat flow trend only show relatively minor changes in the calculated vitrinite reflectance and hence calibration accuracy in the northern part, the southern part of the LSB exhibits stronger variations.

Adopting the heat flow maps that were utilised by Bruns et al. (2013), adjustments to erosion thicknesses and therefore burial depth had to be applied to achieve a good correlation between measured and calculated vitrinite reflectance data. These differences are mainly attributed to the use of slightly different lithologies and the absence of Zechstein salt in the model, which is part of the unresolved basement layer. Nevertheless, eroded thicknesses with a maximum of 7000 m in the southwestern central parts of the basin (Fig. 4-4) fall between the 6700 m calculated in Bruns et al. (2013) and the 7200 m calculated in Senglaub et al. (2006).

All rocks reached highest temperatures in the Late Cretaceous (89 Ma) at the time of deepest burial prior to the Late Cretaceous basin inversion. The resulting thermal maturity is highest in the basin centre, reaching for the Posidonia Shale over 4 %VRr, and decreasing northward to values around 1 %VRr at the basin margin, where the Posidonia Shale was not, or only slightly, affected by Late Cretaceous basin inversion (Fig. 4-5). For the Wealden Shales, the uppermost defined source rock (Wealden IV) horizon reaches thermal maturities of more than 2 %VRr in relatively confined parts in the central and eastern parts of the LSB. Lower maturities not reaching the dry gas stage (<1.3 %VRr) are observed at the northern margin of the basin (Fig. 4-5). The lowermost Wealden source rock formation (Wealden I) reveals higher thermal maturities due to high sediment thicknesses between the single Wealden source rock intervals in the basin centre, partially reaching 4 %VRr. From Fig. 4-5 it is apparent that the individual source rock horizons are eroded to different extent in the southern and eastern parts of the basin. The intense uplift and erosion in the southern and eastern parts of the basin during the Late Cretaceous basin inversion partially affected Jurassic (and older) strata in these areas and hence the Wealden sediments have been eroded or partly eroded as well. The Lower Jurassic and thus the Posidonia Shale have been less affected by erosion than the Upper Jurassic, but for about 10 % of the total study area the Posidonia Shale has been eroded (Fig. 4-5).

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Fig. 4-5: Present day maturity maps at the top of the source rock horizons Posidonia III, Wealden I and Wealden IV. Blank areas indicate erosion.

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4.5.2. Methane adsorption capacity and gas content

Posidonia Shale

Present day bulk adsorption capacity and adsorbed gas content maps have been generated for the Posidonia Shale and Wealden Shale source rock horizons using the properties calculated by PetroMod for each cell. Fig. 4-6 depicts the spatial distribution of the bulk adsorption capacity for the three lithological units of the Posiodnia Shale. Although the same type of maps has been calculated and published by Bruns et al. (2015), the adsorption capacity yields substantially different results in the current model. While Bruns et al. (2015) proposed a maximum adsorption capacity of around 1.5 x 106 t per cell volume (1 km x 1 km x 30 m), the current model projects an average adsorption capacity of 2000 t per cell volume (150 m x 150 m x 40 m). By normalising the amount to the same cell volume (6.6 x 104 t), the data published by Bruns et al. (2015) exceeds this value by a factor of 22. The adsorption mass proposed by Bruns et al. (2015) is due to a bug in the software at that time (an erratum is currently written) and would translate to a volume of ca. 726 scf/t for methane at standard conditions (1013.25 hPa, 20 °C). This value is six times higher than the proposed maximum from laboratory measurements on dry Posidonia Shale samples published in the same work. In comparison, 2000 t of methane corresponds to a volume of 43 scf/t, which fits to the laboratory data.

The bulk adsorption capacity shown in Fig. 4-6 depends largely on the assigned TOC values, the layer thickness of the stratigraphic unit for which it has been calculated and the present day temperature and pressure regime at the individual depths. The TOC content effectively determines the amount of kerogen present in the sample on which gas molecules can be adsorbed. Increasing pore pressure favours the adsorption of gas molecules, while higher temperatures lead to desorption. In geological systems, temperature and pressure can be attributed to burial depth depending on geothermal gradient, hydrothermal activity and/or other influencing factors, which change the temperature and pressure conditions in the subsurface. At just a few hundred metres depth, methane adsorption capacity is low due to low pressures. Up to about 2–3 kilometres depth, an optimum zone is reached, where a high methane sorption potential exists (see Fig. 4 in Uffmann et al., 2014).

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For the lowermost Posidonia I unit, present day adsorption capacity is highest in the northern part of the basin where the Posidonia Shale has not been buried as deeply as in the basin centre. The average amount of gas that can be adsorbed per cell volume is less than 1000 tons. Adsorption capacity for the Posidonia II unit reaches generally higher values but with a smaller spatial distribution (Fig. 4-6). The increase in capacity is mainly caused by the double amount of thickness attributed to the Posidonia II unit (16 m) in relation to the Posidonia I unit (8 m). The strong influence of TOC and hence kerogen content is observed in this map for the Posidonia III unit, which has the same thickness as Posidonia II, but higher adsorption capacity. These observations indicate that all three units are promising gas shale formations.

In Fig. 4-7 the evolution of the bulk adsorption capacity is shown throughout the burial history of the Posidonia III unit. A sorption capacity maximum of around 3100 tons per cell volume was achieved during the Late Jurassic when pressure influence on sorption kinetics outweighed temperature effects. However, temperatures in the basin were then not high enough for gas to be effectively be generated from the kerogen present in the rock. The onset of gas generation and, as a result, gas sorption started at 157 Ma, which was followed by a rapid uptake of gas as an adsorbed phase. In the Early Cretaceous (137 Ma) adsorbed gas contents matched the maximum capacity, significantly decreasing due to further burial. Desorption processes occurred in the Early and Late Cretaceous when the Posidonia Shale reached its maximum burial depth. The large reduction of sorption capacity after 140 Ma is caused by higher heat flows induced by rifting at the Late Jurassic/Lower Cretaceous boundary. During the Late Cretaceous basin inversion, the Posidonia Shale was uplifted to more shallow depth, which led to an increase in sorption capacity. Nevertheless, adsorbed gas contents did not exceed the maximum capacity present at the time of deepest burial (89 Ma) until present day. The actual adsorbed gas mass is shown in Fig. 4-8 in detail for the individual Posidonia Shale units. The middle unit II has the lowest amounts of adsorbed gas normalised to the mass of rock, which is directly related to its lower TOC content in comparison with the other Posidonia Shale units. The largest volumes of gas can be expected in the northern-central basin parts for all units of the Posidonia Shale where the formation was buried to shallower depth than in the basin centre. In the north, a sharp drop is

High-resolution 3D numerical basin modelling 102 visible, which corresponds to the area of the Pompeckj Block, where no erosion as has occurred (Fig. 4-4).

Fig. 4-6: Bulk adsorption capacity expressed in tons of methane for the Posidonia Shale units.

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Fig. 4-7: Temperature (in °C), gas generation balance (cumulative amount of CH4 generated in t/cell), adsorbed gas content (in t/cell) and adsorption capacity (in scf/t) evolution of the Posidonia III unit through geological history from time of deposition to present day.

Wealden shales

Adsorption capacities for the Wealden source rock horizons are generally lower, considering the larger thicknesses of the individual units compared to the Posidonia Shale. At present day, Wealden unit II has the highest capabilities of adsorbing gas (Fig. 4-9). The amount is generally higher in the northwestern and central parts of the basin where the lower source rock units reached the dry gas window. Unlike the Posidonia Shale, the Wealden units’ thicknesses vary significantly throughout the basin. Elevated values, especially for units I and II can therefore be attributed to high sediment thicknesses. Additionally, unit II comprises the highest TOC contents of all units, rendering it the most prolific horizon for adsorbed gas. This is also expressed in the

High-resolution 3D numerical basin modelling 104 calculated adsorbed gas contents for the individual units (Fig. 4-10). The spatial distribution of adsorbed gas volumes reveals the importance of sedimentary thickness for the total amount of absorbable gas mass. While the adsorption capacity maps show a good potential in the northwestern parts of the basin, the highest volumes of adsorbed gas have been calculated for the central and northern-central parts of the LSB. By combining observations on adsorption capacity and adsorbed gas volumes at present time, unit II holds the best potential for shale gas production of the Wealden Shales, followed by unit I, III and IV.

The development of adsorption capacity and actual amounts of adsorbed gas for the Wealden II unit from the central basin are shown in Fig. 4-11. After deposition, the Wealden source rock units, similar to the Posidonia Shale, were buried rapidly due to strong sedimentation in the Early Cretaceous. Following this, pore pressure and temperatures increased, leading to a steep rise of adsorption capacity shortly after deposition. Due to the increase of temperature, a steady decline in adsorption capacity set in, which continued until the time of deepest burial in the Late Cretaceous. A complete saturation of adsorbed gas was reached shortly before the Late Cretaceous basin inversion and subsequent uplift of the Wealden strata, which led to a slight increase of adsorption capacity. Changes to the adsorption capacity during the Cenozoic were induced by small increases of burial depth caused by the deposition of Tertiary and Quaternary deposits. The adsorption capacity at present times is nevertheless similar to the palaeo-capacity at 89 Ma. The Wealden II unit inherits less gas in a sorbed state than the present day adsorption capacity could support. This is mainly caused by the uplift to depths close to the surface, which has resulted in partial degassing through gas migration towards the surface.

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Fig. 4-8: Adsorbed gas contents in standard cubic feet of gas per ton of rock for the Posidonia Shale at present day.

4.5.3. Alternative scenarios and modelling results

In the first scenario, the free and adsorbed gas contents of the individual source rock horizons were calculated without the presence of a sealing caprock, enabling unhindered upward migration of generated hydrocarbons from the source rocks. Therefore, these calculated gas

High-resolution 3D numerical basin modelling 106 amounts represent a worst case scenario for free gas masses accumulated in the potential gas shales. The amount of free gas in the pore space of the investigated horizons at present day is generally low in this scenario due to expulsion upon thermal maturation and compaction. The total amount of adsorbed gas for the entire Posidonia Shale in the investigated area sums to 5.4 x 108 t, while the amount of free gas is 5.9 x 106 tons. Thus 99 % of the total gas in the Posidonia Shale is calculated to be in an adsorbed phase. For the Wealden Shales the amount of adsorbed gas for all four source rock horizons sums to a value of 2.9 x 108 t with a free gas phase of 2.4 x 107 t, resulting in a higher percentage of free gas of 8 % in the Wealden Shales. In both cases free gas accumulations are concentrated in the north of the basin where compaction induced by burial, and hence pore volume reduction, did not affect the respective stratigraphic units as strongly as in the basin centre. In the second scenario the model-based maximum storage capacity for gas in the pore space of the Posidonia Shale was calculated by assuming that the entire pore volume was filled with methane. To calculate the mass of methane under this assumption a gas density formula was used to estimate the density of methane under in-situ conditions for each cell by incorporating present day pore pressure and temperature data:

(4.1) ( , ) = 𝑛𝑛𝑛𝑛𝑚𝑚𝑚𝑚𝑚𝑚ℎ𝑎𝑎𝑎𝑎𝑎𝑎𝑝𝑝𝑚𝑚 𝜌𝜌𝑚𝑚𝑚𝑚𝑚𝑚ℎ𝑎𝑎𝑎𝑎𝑎𝑎 𝑝𝑝𝑚𝑚 𝑇𝑇𝑚𝑚 𝑧𝑧𝑧𝑧𝑧𝑧𝑇𝑇𝑚𝑚 This equation is derived from the real gas law, where ρmethane is the density of methane as a function of the modelled pore pressure and temperature, n is the number of moles, Mmethane is the molecular weight of methane, pm is the modelled pore pressure, z is the compressibility (gas- deviation) factor, R is the gas-law constant and Tm is the modelled reservoir temperature. By ignoring the gas-deviation factor of methane (z = 1) the calculation was simplified to give a rough estimate of methane amounts in the reservoir. The mass of methane in the pore space was then determined by using the calculated pore volume of the Posidonia Shale from the model with the equation

( , ) = ( , ) , (4.2)

𝑚𝑚𝑚𝑚𝑚𝑚ℎ𝑎𝑎𝑎𝑎𝑎𝑎 𝑚𝑚 𝑚𝑚 𝑚𝑚𝑚𝑚𝑚𝑚ℎ𝑎𝑎𝑎𝑎𝑎𝑎 𝑚𝑚 𝑚𝑚 𝑚𝑚 𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝 𝑚𝑚 𝑝𝑝 𝑇𝑇 𝜌𝜌 𝑝𝑝 𝑇𝑇 ∙ 𝑉𝑉

High-resolution 3D numerical basin modelling 107 with mmethane as the reservoir temperature and pore pressure dependent mass of methane,

ρmethane as the density function from eq. 1 and Vm,pore as the modelled pore volume. Although secondary porosity generation in organic matter was considered during simulation of the model, the average calculated porosity of the overmature Posidonia Shale is only 5.7 %.

By using these calculations, the combined mass of methane for all areas where the Posidonia

8 Shale units reached thermal maturity to enable gas generation (>1.2 %VRr) amounts to 6 x 10 t. Calculating adsorbed masses of methane in this scenario is difficult due to the unknown state of equilibrium between the free gas phase in the pore space and the adsorbed gas phase. Additionally, these estimates represent the maximum available storage capacity for methane in the pore space of the Posidonia Shale when other liquid or gas phases such as water, CO2 etc. are not present, which is highly unlikely under real geological conditions. In any case, the number of 6 x 108 t is in the same range is the 5.4 x 108 t calculated for sorbed gas in the first scenario, i.e. the percentage of free gas would be close to 50 %.

Based on laboratory measurements of porosity available for the Posidonia Shale, another scenario for maximum amounts of gas in the pore volume can be considered. Ghanizadeh et al. (2014) published helium-pycnometry data on overmature Posidonia Shale samples from the Hils Syncline (Haddessen well), Northern Germany. The average value of this data is 12 % He-porosity and is hence much higher than the porosities calculated by PetroMod for the Posidonia Shale in the Lower Saxony Basin. Clearly the algorithms to calculate secondary porosity in overmature petroleum source rocks are far from being reliable at present. Therefore, the real measured data are considered here.

By assuming an average porosity of 12 % for the Posidonia Shale in areas where this formation reached the gas window (>1.2 %VRr) and using the equations from the previous scenario, the maximum storage capacity for methane amounts to 1.7 x 1010 t. However, aside from the simplifications made to the gas density equation used also in the previous scenario, it has to be noted that helium has a much smaller molecular diameter than methane. Therefore, He- porosities determined by Ghanizadeh et al. (2014) might not represent the maximum effective porosity for methane. Thus the number of 1.7 x 1010 t of free gas is regarded as too high, defining the absolute upper limit of possible gas content. In any case, the data published by Ghanizadeh

High-resolution 3D numerical basin modelling 108 et al. (2014) on the Posidonia Shale and other carbonaceous shale formations suggest a strong increase of porosity in such source rocks at thermal maturities beyond the oil generation window due to the generation of secondary porosity caused by gas generation (Bernard et al., 2012).

Fig. 4-9: Adsorption capacity expressed in tons of methane per cell unit for the Wealden shale units.

High-resolution 3D numerical basin modelling 109

Fig. 4-10: Adsorbed gas contents in standard cubic feet of gas per ton of rock for the Wealden shales at present day.

High-resolution 3D numerical basin modelling 110

Fig. 4-11: Temperature (in °C), gas generation balance (cumulative amount of CH4 generated in t/cell), adsorbed gas content (in t/cell) and adsorption capacity (in scf/t) evolution of the Wealden II unit through geological history from time of deposition to present day.

4.5.4. Implications for gas production

A qualitative production efficiency forecast for the individual horizons can be made based on the amount of mineral percentages in the individual units. To successfully stimulate an unconventional reservoir using hydraulic fracturing, the brittleness of the targeted horizon is of great importance. While minerals like quartz and carbonates (e.g. calcite or dolomite) favour the creation of artificial fractures to enhance permeability, mechanically weaker minerals (e.g. clay minerals) can significantly reduce the performance of reservoir stimulation (Aoudia et al., 2010). Whereas the Posidonia Shale is not as enriched in silica (i.e. quartz derived from siliceous fossils) as other promising gas shales such as the Mississippian Upper Alum Shale (Uffmann et al., 2012), large quantities of carbonates are present in these shales. Littke et al. (1991) calculated, based on total inorganic carbon data, carbonate contents of up to 40 % on average for the Posidonia units II and III. Quartz contents are generally lower than 20 % (Gasparik et al., 2014).

High-resolution 3D numerical basin modelling 111

The Wealden Shales are generally poor in silica compared to an average shale composition (Berner, 2011), which reflects an above average content of clay minerals. Based on these datasets it is likely that the Posidonia Shale is more suited for the application of hydraulic fracturing techniques. Observations on secondary porosity generated upon thermal maturation within the organic matter of the Posidonia Shale (Bernard et al., 2013, Ghanizadeh et al., 2014) additionally leads to the assumption of enhanced matrix permeability despite the primary porosity reduction through compaction during burial. This might have a positive effect on production performances. Finally, microbial methane production may have added to total methane in place, especially where the Posidonia Shale is at shallow depth. It is well known from the adjacent coal-bearing Ruhr area, that isotopic compositions of methane suggest a significant admixture of microbial gas in shallow Carboniferous coals, whereas the deep coals further north have a purely thermogenic signal (Thielemann et al., 2004).

4.6. Conclusions

Petroleum source rocks in the west-central part of the Lower Saxony Basin have been investigated with respect to thermal maturity distribution, adsorption capacity and gas contents using high- resolution 3D numerical basin modelling. The aim was to evaluate these properties for a set of distinct source rock horizons in the Lower Jurassic (Toarcian Posidonia Shale) and the Lower Cretaceous (Berriasian Wealden Shales) comprising different lithologies, organic geochemical features and hydrocarbon generation kinetics. The outcome of the modelling procedure can be summarised as follows:

(i) The Toarcian Posidonia Shale reached high thermal maturities at the time of deepest burial (89 Ma) in the centre of the LSB. Strong uplift occurred during the Late Cretaceous due to the influence of the Subhercynian inversion event.

(ii) Detailed analysis of the individual lithological units of the Posidonia Shale revealed the highest adsorption capacity in terms of mass of methane in the uppermost unit III due to high initial TOC contents and hence large amounts of kerogen, which provides sorption surfaces.

High-resolution 3D numerical basin modelling 112

(iii) The highest amounts of adsorbed methane have been calculated for the northern- central parts of the basin where all Posidonia Shale units have been buried to shallower depth than in the central basin parts while still reaching a thermal maturation stage enabling dry gas generation.

(iv) Highest methane saturations have been reached at 137 Ma for the Posidonia Shale. A significant reduction in adsorbed gas contents occurred shortly thereafter due to rapid burial. Present day adsorbed gas saturations reflect those at the time of deepest burial (89 Ma). Although the sorption capacity increased in the Late Cretaceous, adsorbed gas amounts remained constant due to the exhausted generation potential of the Posidonia Shale.

(v) For the Wealden intervals, highest thermal maturities have been calculated for the lowermost Wealden I unit, which reaches partially over 4 %VRr in the basin centre. Immature to early mature rocks can still be encountered at the northern margin of the Lower Saxony Basin. Due to the stratigraphically elevated position, unit IV reached lower thermal maturities while still reaching the gas window in the central basin parts.

(vi) In terms of adsorption capacity and adsorbed gas volumes, Wealden unit II has the highest potential, followed by units I, III and IV. The high adsorption capacities are due to the larger thickness and a higher average initial TOC content of unit II in comparison to the other intervals. These properties also led to the largest volumes of gas adsorbed in this unit for the Wealden Shales.

(vii) Highest adsorbed gas saturation for the Wealden intervals was reached during the time of deepest burial (89 Ma). The subsequent uplift in the Late Cretaceous had only small effects on the overall sorption capacity of this rock unit and only small amounts of gas desorbed after the basin inversion until present day. Nevertheless, the Wealden Shales are undersaturated in respect to the maximum sorption capacity at present day while the generation potential in the basin centre is exhausted.

(viii) Different scenarios were tested based on the calculated maps of the model and available laboratory data. The purely model-based scenario for available gas contents can

High-resolution 3D numerical basin modelling 113

be used to estimate the amount of adsorbed gas for the different source rock horizons, while the calculations from laboratory data can be used as an estimate of maximum gas storage in these systems.

(ix) According to the mineralogical composition of the Posidonia Shale units and the Wealden Shale intervals, the Posidonia Shale exhibits a better potential for the successful utilisation of reservoir stimulation techniques such as hydraulic fracturing.

Summary and conclusions 114

5. Summary and conclusions

In this thesis the two most promising organic-rich shale formations of Northern Germany and especially the Lower Saxony Basin have been investigated to assess their organic geochemical and petrophysical potential as probable unconventional reservoirs for hydrocarbons, including shale oil and shale gas. Additionally, these parameters have been implemented into a 3D numerical basin model for the west-central Lower Saxony Basin to estimate the gas-in-place (GIP) that could possibly be encountered in these formations.

Chapter 2 dealt with the organic geochemical characterization of the Wealden shales based on the analysis of samples from three wells within the Lower Saxony Basin. This work is scientifically valuable due to the scarcity of publicly available data on these potential source- and unconventional hydrocarbon bearing rocks. Although similar approaches have been performed in earlier works (Berner et al., 2010; Berner, 2011), investigations on sample material from the central basin parts have never been published before. The findings and core results of Chapter 2 for the Wealden shales can be summarized by the following points describing the organic geochemical inventory and classification:

1) Through the analysis of samples from three wells throughout the LSB, four horizons could be identified which yield sufficiently high TOC and HI values to be regarded as excellent petroleum source rocks. 2) The Berriasian Wealden shales with source rock qualities have been deposited under a lacustrine to brackish environment, which provided favorable living conditions for hydrogen rich botryococcus type algae. The occurrence of this algae type has been confirmed by organic petrographical investigations and the findings of macrocyclic n- alkanes in solvent extracts of immature to early mature Wealden shale samples. These observations in combination with elemental organic geochemical data (TOC, HI and OI) and the overall high amounts of lamalginites encountered in these samples allows a classification as source rock initially containing type I kerogen. 3) In Berriasian times the depositional environment changed periodically leading to increased salinity of the lake system as well as higher sulfate concentrations. This

Summary and conclusions 115

conclusion is based on the observation of moderate amounts of β-carotane and high sulfur contents in some samples. 4) The three wells investigated represent a maturation series for the Wealden shales, where Ex-A can be classified as early mature in respect to oil generation based on vitrinite

reflectance measurements, Tmax values and organic geochemical maturity parameters like diamondoid ratios and hopane isomerization. Based on these parameters, wells Ex-C and Ex-B can be regarded as thermally late mature and overmature. 5) Upon maturation, these rocks generate paraffinic oil with high wax contents as deduced from Thermovaporization-GC-FID measurements. Residual solid bitumen effectively occupies pore spaces and alters the pore system intensively in combination with the creation of a secondary pore system within organic matter due to gas generation. 6) 3D numerical basin modeling results in Chapter 2 revealed new insights in terms of the spatial distribution of thermal maturity for the Wealden shales in the Lower Saxony Basin.

While Chapter 2 dealt with the organic geochemical inventory and the source rock and unconventional reservoir potential of the Wealden shales, equivalent data and literature on this topic are readily available for the Toarcian Posidonia Shale. However, sample material from the Posidonia Shale from three different wells in the Hils Syncline has been used to tackle the question of how the pore system changes upon thermal maturation of organic-rich shales due to the generation and expulsion of hydrocarbons as well as the occurrence of residual organic matter. Additionally, the organic geochemical composition of the soluble organic matter was investigated in this context. For this reason, a combination of petrophysical and organic geochemical methods were used in Chapter 3 to perform a more fundamental research on these phenomena that have a strong influence on the storage capacity and production performance of unconventional shale reservoirs. The outcome of this work can be summarized in the following points:

1) Upon maturation of the Posidonia Shale, a strong decrease of porosity and permeability is observable in oil mature samples due to the generation of hydrocarbons and accompanied pore space occupation. In gas mature samples, porosity and permeability increase again which is associated with the creation of a fracture system and the generation of secondary porosity in organic matter.

Summary and conclusions 116

2) The amount of extractable organic matter by using the novel approach described in Chapter 3 accounts for 54 % (immature), 40 % (oil mature) and 61 % (overmature) in comparison to the total amount of extractable organic matter from these shales after sequential extraction and the sum of extracts gained by the sequential procedure. These values provide indications on the naturally accessible pore space occupied by soluble organic matter in the respective samples. 3) The individual molecular composition of the stepwise extracts changes significantly over time, depending on the accessibility of soluble organic matter. 4) Porosity values and permeability increases strongly after the extraction procedure for every sample investigated which is a result of the extension of natural fracture systems caused by DCM permeation and interaction with, and solution of, soluble organic matter.

In Chapter 4, information gained in the previous chapters has been incorporated in a high- resolution 3D numerical model for the west-central part of the Lower Saxony Basin. The aim was to estimate the gas content (adsorbed and free phase) in relation to the burial history and the varying rock specific parameters in the individual source rock formations by subdividing the Posidonia Shale and the Wealden shales into more detailed lithological units depending on their mineralogy and source rock properties. New insights gained by this approach include, among others:

1) The uppermost carbonaceous shale unit of the Posidonia shale (unit III) inherits the highest adsorption capacity of the three subunits which is attributed to the highest average TOC contents of this interval for the whole Posidonia Shale. 2) In general, the highest adsorbed gas contents for the Posidonia Shale units can be expected in the northern parts of the Lower Saxony Basin where the Posidonia Shale has not been buried to depths where an accompanied increase in temperatures led to a strong reduction in adsorption capacity as seen for the central basin parts. 3) Free gas contents are generally low in the presented scenario which lacks lithological seals that would favor hydrocarbon retention. 4) Of the four Wealden source rock intervals, unit II exposes the highest adsorption capacity, originating from the generally high average TOC contents of this unit and the largest

Summary and conclusions 117

thickness of the investigated horizons. Accordingly, the highest amounts of adsorbed gas were calculated for this Wealden interval. 5) Free gas contents for the Wealden units are generally higher than in the Posidonia Shale, but depend largely on assumptions on sealing capacity. 6) From the perspective of production performance, the Posidonia Shale might be more susceptible to reservoir stimulation techniques such as hydraulic fracturing due to the generally higher percentages of brittle minerals in the respective lithological units.

To assess not only the potential for unconventional hydrocarbon production but also give a preview of the possible production performance of the investigated shale formations, a comparison with actually producing shale gas plays from the US, incorporating the findings of this thesis and a multitude of data available from literature which provide a comprehensive overview, is of great value. A thorough compilation of hydrocarbon potential and parameters critical for production that has been published by Jarvie (2012) for the best producing shale gas formations in the US which can act as reference keys to the understanding and classification of possible unconventional shale reservoirs in Germany where production data is absent. In Table 5.1a data selected from Jarvie (2012) are extended by the information gained on the investigated shale formations in this thesis. Additional parameters such as the occurrence of secondary porosity in organic matter and the Namurian Upper Alum Shale as third prospective shale formation have been taken into account for this comparison. For the references of the included properties, please refer to Table 5.1b as literature matrix.

From Table 5.1a it is apparent that the Namurian Upper Alum Shale exhibits reservoir properties that resemble those of the Barnett Shale which was also proposed based on a comparison of a more limited data set by Uffmann et al. (2012). Significant conformities can be seen in the mineralogical content, the initial TOC contents, initial HI indices and the typical depth of these silica rich shales at which the thermally overmature Barnett Shale and the Upper Alum Shale can be encountered at present day and are hence likely to contain commercially feasible natural gas volumes. For the Barnett Shale, gas contents of 8.5 – 10 m³/ton of rock have been reported which fits the range of the estimated gas contents by 3D numerical basin modeling by Uffmann et al. (2014) for the Upper Alum Shale.

Summary and conclusions 118

Table 5-1: a) Parameters critical for production of best producing gas shale plays in the US in comparison with properties of potential gas shale formations in Germany. Values represent average values with ranges given in brackets. b) Reference matrix for Table 5-1a. * values at thermally overmature stage.

Summary and conclusions 119

Based on the mineralogy, the Cretaceous Eagle Ford shale seems to be a possible counterpart for the Early Jurassic Posidonia Shale of Northern Germany. The partially very high carbonate contents of up to 60 vol-% represent a relatively unique property for a possible unconventional reservoir. Although the Posidonia Shale exhibits a similar porosity range to that of the Eagle Ford shale, permeability values differ significantly. Nevertheless, probable gas contents from a minimum scenario (compare Chapter 4) derived from numerical basin modeling and the depth of the Posidonia Shale are in good accordance to those values reported for the Eagle Ford shale.

At the current state, finding a wealth of data on gas producing counterparts for the Wealden shales which were also deposited in a lacustrine environment and contain type I kerogen is impossible. The reason for this is that there are no producing lacustrine shale gas plays established in the world at present day which go beyond the stage of testing. However, shale gas exploration in lacustrine systems is under way, especially in Chinese basins (Li et al., 2007; Yanjun et al., 2013; Hao et al., 2013), and oil production from lacustrine shales is performed in several countries (Dyni, 2006). From the data published by Jarvie (2012), the Haynesville shale was used as a reference play due to its matching organic geochemical parameters like initial TOC and HI contents as well as mineralogical components. The Haynesville shale contains a reasonably high amount of clay minerals which can also be determined for the Wealden shales. This is accompanied by relatively low silica contents and mediocre amounts of carbonates. It was initially very rich in organic matter and yielded high initial hydrogen indices of up to 722 mg HC/g TOC (Table 5-1a), which resembles the properties of the Wealden shales. Estimated gas contents for the Wealden also fall in line with the reported gas contents of the Haynesville shales. Nevertheless, it has to be kept in mind that the marine depositional environment in which the Haynesville shale was deposited differs strongly from a distinct lacustrine system, not only with respect to the kerogen type and hence the composition of generated hydrocarbons.

As a conclusion it can be stated that the Posidonia Shale exhibits the best potential to be used as an unconventional resource for hydrocarbons. It is ubiquitously abundant in Northern Germany and reached thermal maturities to enable gas generation. As the most important source rock for conventional hydrocarbon accumulations in Germany it is very well studied and a wealth of information is available. The gap of information regarding essential reservoir properties including

Summary and conclusions 120 petrophysical parameters has been largely filled recently through investigations performed by the GASH consortium. Furthermore, the Eagle Ford shale in the US proves that such carbonate rich shale systems can be viable resources for shale gas. From the properties presented in recent publications (see Table 5-1a) a good potential can also be attributed to the Upper Alum Shale. Geochemical and petrophysical parameters as well as potential gas contents are promising for this formation. However, exploration efforts have to be concentrated on the relatively confined and densely populated area of the Münsterland Basin and the northern rim of the Rhenish Massif (Uffmann et al., 2012; Uffmann et al., 2014) which reduces the total amount of possibly producible natural gas in comparison to the Posidonia Shale. The same criteria applies to the Wealden shales which, due to the regionally confined occurrence of a suited source rock facies, requires a profound knowledge of the paleogeographical conditions and the thermal history of the Lower Saxony Basin. Additionally, the high clay mineral content of the Wealden shales might influence attempts of stimulation techniques at production stages negatively. However, the Wealden shales exhibit a good hydrocarbon potential and, as presented in this thesis, reasonably high gas contents.

6. Final remarks, limitations and outlook

During the course of this thesis numerous methods and techniques have been utilized to tackle practical and fundamental questions about parameters influencing the quality of unconventional hydrocarbon reservoirs in shales. This and the broad scientific interest and research topics for these shale systems show that integrational approaches combining different branches of geoscientific work (sedimentology, inorganic/organic geochemistry, mineralogy, petrophysics, numerical basin modeling etc.) are vital to the understanding of unconventional reservoirs as a whole. Although the data presented in this work covers and reduced a huge amount of previous uncertainties regarding the investigated formations, a multitude of parameters remain unknown.

The organic geochemical parameters presented in Chapter 2 for the Wealden shales represent a first approach in describing these attributes for the basinal facies of the Wealden. Nevertheless, assessing the source rock potential and identifying potential exploration targets via these

Summary and conclusions 121 methods provide only a minor fraction of information needed to develop these shales as unconventional reservoir. Although potential gas contents have been presented for the individual Wealden source rock intervals in Chapter 4, detailed petrophysical data on these formations are not available. Information on porosity and permeability as well as a detailed lithological description based on mineralogical investigations are needed to enhance e.g. numerical modeling approaches and would also allow initial production estimates. Furthermore, reference plays in terms of shale gas are yet to be developed and described in detail to widen the knowledge about lacustrine, type I kerogen containing source rocks as potential reservoirs. Much uncertainty remains for the Wealden shales, especially in a complex basin such as the Lower Saxony Basin.

In Chapter 3 a novel approach was introduced to determine the evolution of the pore system in an organic-rich shale upon thermal maturation in dependence of hydrocarbon generation by combining well established petrophysical techniques of porosity and permeability determinations with organic geochemical methods. Although the information gained by this procedure provided a deeper insight on the mechanisms and intensity of pore space and permeability reduction and enhancement in shale systems, this study has to be regarded as a first approach for further investigations. This arouses from the limited data set of only four samples investigated in this experimental setup. A clear disadvantage of this method is the large amount of time needed to perform these measurements. This originates from the careful sample preparation needed and the rather long extraction runs to achieve good results. Furthermore, this measurement setup proved to be impracticable for samples with very low initial permeability. However, the scientifically valuable information gained by this procedure might outweigh the effort. Applications on large sample sets including artificial maturation series would provide new insights and new ways of determining the influence of organic matter on pore space systems and matrix permeability in organic-rich shales. A final contribution could be the implementation of the gained information into numerical basin modeling software to predict and calculate the evolution of porosity in organic-rich shales more accurately.

Detailed investigations on the burial history and petroleum system evolution based on a lithological subdivision of the Posidonia Shale and the Wealden shales was performed using a high-resolution 3D numerical basin modeling approach in Chapter 4. Although these

Summary and conclusions 122 investigations resulted in new information on the probable thermal history and gas contents of these organic-rich shale formations, several refinements and enhancements of the input parameters would result in significant improvements. Although the reconstruction of paleotemperatures by calibrating the model with measured vitrinite reflectance data yields good results, the incorporation of geochemical maturity parameters would be useful to verify these data. Incorporation of geophysical data would allow a refinement in terms of the amount of radioactive elements (gamma ray/spectral ray logs) in shales and hence radiogenic heat generation in these rocks. The effect of compaction and porosity reduction, which has a strong influence on the hydrocarbon storage potential of shales, could be clarified by using detailed neutron and sonic logs. As stated before, the effect of pore reduction due to bitumen plugging should be implemented which is an important parameter in organic-rich shales. Specifically, mineralogical studies would lead to a better understanding of the Wealden shales and would refine the modeling results significantly.

As a final remark it has to be stated that until drilling programs provide more core material of the mentioned formations in Germany for scientific studies, all estimates on the economic viability of these shales have to be regarded as speculative.

References 123

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Curriculum vitae 137

Curriculum Vitae

DANIEL MOHNHOFF

BORN RIPPEN 27 Invercargill Drive, Lower Hutt 5010, New Zealand Office: +64 4 5704719 [email protected] Work experience • GNS Science, Lower Hutt, New Zealand

Petroleum Geochemist February 2016 – ongoing • Institute of Geology and Geochemistry of Petroleum and Coal (LEK), RWTH Aachen

PhD Student / Assistant Researcher February 2012 – May 2015 • GeoService Soltenborn, Aachen Student / Technical assistant October 2007 – October 2011

Education • RWTH Aachen University

PhD. Applied Geosciences/Petroleum Geosciences, February 2012 – December 2015 • RWTH Aachen University

MSc. Applied Geosciences, April 2009 – September 2011 Major in Geology, Geochemistry and Economic Geology Grade: 1.2 • RWTH Aachen University

BSc. Applied Geosciences, April 2006 – March 2009 Grade: 1.9

Curriculum vitae 138

Teaching experience • Instructor for several practical PetroMod courses as part of the lecture course “Sedimentary Basin Dynamics” held at the Institute of Geology and Geochemistry of Petroleum and Coal (LEK), RWTH Aachen University. • Instructor for several practical courses of “Coal Petrography” at the Institute of Geology and Geochemistry of Petroleum and Coal (LEK), RWTH Aachen University.

Skills MS Office Applications (Excel, Powerpoint, Access, Publisher), Schlumberger IES Petromod, ZetaWare Genesis, ZetaWare KinEx, Zetaware Trinity, SMT Kingdom Suite, Atlas CDS, Thermo Xcalibur, QGIS, Perkin Elmer Spectrum

Languages German (native speaker), English (business fluent)

Memberships Verein Aachen Geologen (VAG - Aachen Geological Union), Deutsche Geologische Gesellschaft – Geologische Vereinigung (DGGV - German Geological Union), European Association of Geoscientists and Engineers (EAGE), American Association of Petroleum Geologists (AAPG)

Peer-reviewed publications Uffmann, A.K., Littke, R., Rippen, D., 2012. Mineralogy and geochemistry of Mississippian and Lower Pennsylvanian Black Shales at the Northern Margin of the Variscan Mountain Belt (Germany and Belgium). International Journal of Coal Geology 103, 92–108. Rippen, D., Littke, R., Bruns, B., Mahlstedt, N., 2013. Organic geochemistry and petrography of Lower Cretaceous Wealden black shales of the Lower Saxony Basin: The transition from lacustrine oil shales to gas shales. Organic Geochemistry 63, 18-36. Nyhuis, C.J., Rippen, D., Denayer, J., 2014. Facies characterization of organic-rich mudstones from the Chokier Formation (lower Namurian), south Belgium. Geologica Belgica 17 (3-4), 311- 322. Mohnhoff, D., Littke, R., Krooss, B.M., Weniger, P., 2015. Flow-through extraction of oil and gas shales under controlled stress using organic solvents: Implications for organic matter- related porosity and permeability changes with thermal maturity. International Journal of Coal Geology 157. 84-99. Mohnhoff, D., Littke R., Sachse, V.F., 2015. Estimates of shale gas contents in the Posidonia Shale and Wealden of the west-central Lower Saxony Basin from high-resolution 3D numerical basin modelling. German Journal of Geology (ZDGG) 167 (2-3), 295-314.