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Cut surface and block of coralline limestone from the Devonian Iberg limestone in the Harz Mountains, Germany. The voids cement and a droplet of impsonite. Photographic montage: the droplet is ~1 cm across; corals are ~0.5 cm wide. Specimens in the corals are partly filled by pyrobitumen (impsonite). Foreground is a drusy macropore partly filled with sparry calcite courtesy of Barbara Teichert and Hans-Dieter Vosteen; Prepared by Peter Rendschmidt; Photographed by Wolfgang Hake; all BGR. SPBA-Compleet 22-04-10 13:52 Pagina 225

Chapter 13 — Petroleum generation and migration

Chapter 13 Petroleum generation and migration

Authors Bibliographic reference Thomas Pletsch (BGR), Jörg Appel (BGR), Dariusz Botor (AGH University of Science & Technology), Gion Kuper (Integrated Geochemical Interpretation Ltd), Jolanta Kus (BGR), Rüdiger Lutz (BGR), Pletsch, T., Appel, J., Botor, D., Clayton, C.J., Duin, E.J.T., Faber, E., Górecki, W., Kombrink, H., Kosakowski, P., Kuper, G., Chris Clayton (Consultant), Ed Duin (TNO), Eckhard Faber (BGR), Wojciech Górecki (AGH University of Anders Mathiesen (GEUS), Christian Ostertag-Henning (BGR), Bartek Papiernik (AGH University of Science Kus, J., Lutz, R., Mathiesen, A., Ostertag-Henning, C., Papiernek, B. & Van Bergen, F., 2010. Petroleum generation and Science & Technology), Henk Kombrink (TNO), Paweł Kosakowski (AGH University of Science & Technology), & Technology) and Frank van Bergen (TNO) migration. In: Doornenbal, J.C. and Stevenson, A.G. (editors): Petroleum Geological Atlas of the Southern Permian Basin Area. EAGE Publications b.v. (Houten): 225-253.

1 Introduction A petroleum system is a conceptual framework that includes a pod, or a group of closely related pods, A source rock is a sedimentary rock that contains sufficient and appropriate organic matter to generate of active petroleum source rock that has generated oil and gas. A petroleum system also comprises petroleum under the conditions mentioned above. A number of petroleum provinces can be delineated Petroleum migration, its way from the source rock to the reservoir, takes place out of sight in the deep the overlying strata that have brought the source rock into the appropriate temperature range where within the SPBA, which host one or more petroleum systems (Figure 13.1) and are separated from other subsurface. Even in places where former sedimentary basins have been uplifted and eroded to expose the petroleum is generated and expelled. These fluids usually start migrating, often along discrete pathways provinces either by areas that lack this particular productive or prospective petroleum system or, in the porous or fractured rocks that form the petroleum migration pathways, there are no visible traces of its within carrier beds or tectonic fractures. Eventually, a portion of the migrated hydrocarbons may fill a case of directly adjacent provinces, by significant differences in their generation and migration history. movement. However, evidence of the process is occasionally seen in the form of bitumen impregnations. trap and accumulate in economic quantities in one or more reservoirs beneath a seal. A petroleum system includes all formations, processes and products. In contrast to the petroleum systems, which are distinguished on the basis of their source-rock ages and 1.1 Definitions histories, shallow-gas occurrences are characterised by the depth of their ultimate reservoir. Shallow gas This following account also includes undiscovered accumulations, in much the same way as ‘total petroleum is commonly defined as gas accumulations in sediments down to depths of 1000 m below surface, although Petroleum generation and migration in an area as large and geologically complex as the SPB area is so systems’ have been defined. Because this chapter focuses on petroleum generation and migration, the the petroleum industry tends to be pragmatic, regarding it as gas above the first casing point. Shallow diverse that an entire Atlas series would be required to cover all aspects. However, there are general traits number of individual petroleum systems with differing reservoir stratigraphies have been summarised gas can be of either microbial (also referred to as ‘biogenic’ by geoscientists) or thermogenic origin. across the basin that allows a summary to be made. The summary is organised by referring to the main and referred to by their source-rock stratigraphy only. Biogenic gas is produced by microbial breakdown of organic matter at shallow depths and is almost petroleum systems. completely composed of methane. The microbes that generate methane from organic matter are archaea, Six major petroleum systems are described and grouped according to the age of the respective petroleum a separate, ancient kingdom of organisms. Petroleum is naturally occurring and consists mainly of hydrocarbon molecules that often contain source rocks. The most important petroleum systems of the SPB in terms of petroleum reserves and substantial amounts of contaminants such as sulphur, nitrogen, oxygen, trace metals and other elements regional distribution are associated with the Upper Carboniferous (Westphalian) coals for natural gas For further information see Miles (1994), Magoon & Dow (1994), Magoon & Beaumont (2000), Magoon in both subsurface and surface rocks. Petroleum may occur in gaseous, liquid or solid state depending and the Lower Jurassic Posidonia Shale Formation for oil. Other petroleum systems are less productive & Schmoker (2000), Gluyas & Swarbrick (2003), Allen & Allen (2005). on the properties of these compounds and the temperature and pressure conditions. The commonly and regionally widespread, but still provide a significant economic benefit. used synonyms for petroleum are ‘hydrocarbon’ and ‘oil and gas’.

0¡ 5¡E 10¡E 15¡E 20¡E 0¡ 5¡E 10¡E Fields related to Paleozoic source rocks Oil Gas Oil and gas

Present-day facies distribution of Stassfurt Baltic Basin carbonates and equivalents (Zechstein) Marine evaporites (restricted basin) Tail End Turbidites (slope) Graben 55¡N Carbonates and local anhydrite (platform) Evaporites and clastics (sabkha and Anglo-Dutch Basin and North German Basin alluvial plain) Dutch Central 55¡N Not present or massif/high Graben East Midlands Pomerania and Cleveland Basin Lower Saxony Basin and Dogger Troughs

West Netherlands Basin and Broad Fourteens Basin Fore-Sudetic Monocline and Brandenburg Lublin Basin

Figure 13.1 The petroleum provinces and districts in the Southern Permian Weald Basin Basin area: a. Fields related to Paleozoic source rocks are shown along with the present- day distribution of the Zechstein 50¡N Stassfurt carbonates and facies equivalents (Upper Permian); b. Fields related to Mesozoic source 50¡N 0100 200 300 km rocks are shown along with the present- 0100 200 300 km day distribution of the main Mesozoic Fields related to Mesozoic source rocks Present-day distribution of Jurassic source rocks a. source rocks. Oil Bo Member Gas Lias (Weald Basin) In the background of the frontispiece photograph on the opposite page, a slab of coralline limestone from the Devonian Iberg in the Harz Mountains of Germany shows voids in the corals that are filled Oil and gas Posidonia Shale Formation with impsonite, a dense and hard bitumen. In the foreground, a piece of carbonate rock from the same formation has cavities that are partly filled with sparry calcite cement and a droplet of impsonite. b. The impsonite is attributed to petroleum generation from Middle Devonian source rocks and migration into the voids of the Upper Devonian reefal limestone (Jacob et al., 1981).

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Chapter 13 — Petroleum generation and migration

1.2 Source-rock and petroleum characterisation, data handling and presentation geochemical analyses, such as gas chromatography-mass spectrometry (GC-MS) and gas chromatography- Geochemical data are made available for interpretation through the graphs and diagrams included in this isotope ratio mass spectrometry (GC-IRMS), investigate the molecular and isotopic signatures of the chapter. In addition to being a powerful visualisation tool, combining parameters in cross-plots allows The various source rocks found in the SPBA each have different characteristics with respect to their organic matter. This includes the study of biomarkers (e.g. steranes), or geochemical fossils, which better sample discrimination and identification of trends. The main plot-types used in this chapter to organic matter. These different properties influence the timing of hydrocarbon generation, the quality preserve characteristics of the original biochemical precursors. Molecular indicators can be used to assess describe the different source rocks are shown in Figure 13.3. Trend lines and interpretations are based and quantity of generated oil and gas. The optical and chemical characteristics of organic matter can the effects of thermal maturity, biodegradation and migration. on published literature. be used to describe the source-rock properties, indicating organic richness, kerogen quality, source-rock maturity, and source-rock facies. Maturation is the general process of thermal alteration of organic matter (kerogen) in a sedimentary For a full list of technical terms the reader is referred to the Glossary (Appendix 1), which includes rock. It is used as a more readily measurable proxy for generation of hydrocarbons from a source rock, the various terms for optical and geochemical analyses and other relevant parameters. For further Hydrocarbon generation and subsequent expulsion are the result of processes associated with the thermal applying indicators such as Rock-Eval Tmax, vitrinite reflectance and spore colour indices. The relationship information see Staplin (1969), Espitalié et al. (1977, 1985), Peters (1986), Tissot & Welte (1984), Smith maturation of organic matter upon burial of a source rock. Kerogen is transformed to hydrocarbons as between the most commonly used maturity parameters, Tmax and vitrinite reflectance, is shown in (1993), Mukhopadhyay & Dow (1994), Tyson (1995), Hunt (1996) and Peters et al. (2005). temperatures increase. Whether oil or gas is generated depends mainly on the type of kerogen, and thereby Figure 13.2c for data from the SPB. It should be noted that both parameters may differ slightly with on the origin of the organic matter. Terrestrial organic matter is typically gas-prone (vitrinitic, type III), different kerogen types or lithology, but also with different laboratories. whereas aquatic (mostly algal) organic matter is primarily oil-prone (liptinitic, types I and II). The Rock-Eval 2 Main petroleum systems Hydrogen Index (HI) expresses the kerogen’s hydrocarbon potential. The HI values decrease with increasing The data presented in the graphs and diagrams in this chapter were compiled from various sources, maturity as generation progresses and the kerogen is converted to oil, wet gas and condensates, and dry representing the different regions in the SPB and the different petroleum systems. The majority of data 2.1 Pre-Devonian gas (Figure 13.2a). Whereas the different kerogen types can be distinguished from their initial, immature were supplied by the national institutes TNO-NITG, POGC/PGI, BGR, and GEUS, with additions from CCGS, HI values, these characteristics do not apply at advanced levels of maturation (Figure 13.2b). Type III IGI’s World Data, and selected publications (see ‘further information’ suggestions at the end of the regional 2.1.1 Baltic Basin kerogen will retain hydrocarbon potential at higher maturities than kerogen types I and II. The main phase sections). The data were arranged by region, following the geographical distribution of source-rock of oil generation is therefore at lower temperatures than the main gas-generation phase. Hydrocarbon intervals, with the focus on the source rocks relevant for the petroleum systems in each region. Excellent source rocks are well-known throughout the Lower Paleozoic (Cambrian, Ordovician, and generation and subsequent expulsion also reduces the total organic carbon (TOC) content of a source Silurian) succession and are widespread in the eastern part of the SPB area (see Section 3.2 in Chapter 4). rock. These factors influence the interpretation of data from mature source-rock samples. All data in the database meet the quality assurance standards of the laboratories and institutes that These organic-rich sediments are either unknown or they were buried too deeply in the central and released the data. Further quality control criteria were stringently applied before presentation in this western SPBA to be considered prospective; their generative potential was largely exhausted (Chapter 4, Organic geochemical and optical analyses provide insight into kerogen characteristics. Samples are chapter. Rock-Eval pyrolysis data only include samples still retaining more than 0.5% TOC content and Figure 4.3). Post-Caledonian subsidence was lower only in the western Baltic Basin (Peri-Baltic Syneclise, analysed from cores, sidewall cores, drill-cuttings and outcrops, as well as oil and gas samples. Elemental with a pyrolytic yield (S2) of 2 kg/tonne or higher. This is a prerequisite for a reliable Tmax value. As a Baltic Depression; Figure 13.4), which lay distal to the Variscan foredeep. Moderate overburden thickness analysis and Rock-Eval pyrolysis yield bulk source-rock properties such as TOC content, HI, Production further criterion, only Tmax values between 360 and 600°C are included. HI values were deemed unreliable and heat flow consequently protected the prolific Lower Paleozoic source rocks in the Baltic Basin from Index (PI) and Tmax. Organic petrology, the optical study of sedimentary organic matter, not only if outside 20 to 1200 mg/g TOC. Vitrinite reflectance measurements were only used when values were overmaturation, except in the south-western area adjacent to the Teisseyre-Tornquist Zone. Petroleum provides information on the origin of the kerogen but also yields maturity parameters such as vitrinite within the range 0.2 to 4% Ro, which provides the most reliable measurements. Care was taken to generation started during the Caledonian Orogeny at about 400 Ma. reflectance (% Ro), Spore Colour Index (SCI) and the Thermal Alteration Index (TAI). High-resolution minimise the inclusion of measurements of cavings and reworked vitrinite. Lower Paleozoic proven and potential source rocks in the Baltic Basin include Lower to Middle Cambrian claystones, Upper Cambrian to Lower Ordovician black shales that correlate stratigraphically with the Alum Zone Hydrocarbons generated Temp VR SCI Coal rank Processes Rock-Eval hydrogen index (mg Py/g TOC) Figure 13.2 Source-rock characterisation, hydrocarbon generation and thermal maturity: (¡C) (% Ro) 0 100 200 300 400 500 600 700 Shale Formation in Scandinavia, the Middle Ordovician Kukersite and the Upper Ordovician to lower Silurian 0 400 a. Cartoon illustrating hydrocarbon generation from a source rock as a function of maturity Early Reduction in graptolite shales (see Chapter 4, Figure 4.16). These Cambrian, Ordovician, and Silurian source rocks 25 Biogenic CH4 0.2 (methanogenesis) onset, TOC due to Late onset, and the approximate equivalent burial depth (from IGI’s ig.NET and modified after Tissot and Gas broad decarboxylation narrow window contain relatively homogeneous type I or II kerogen (Figure 13.5). window Welte, 1984). This diagram is based on the assumption of a constant geothermal gradient 1 50 Kerogen 420 0.5% Ro Oil Lignite formation

with depth and time. At shallow depths, biogenic gas is produced as a product of fermentation, Biomarkers Type III 0.7% Ro 75 0.4 4 Type I It was only after the evolution of higher land plants in mid-Silurian times that humic organic matter formed reaching commercial accumulations only where sedimentation rates are high. In oil-prone 2 440 Type II

(¡C) a major constituent of source rocks. This should be taken into account when interpreting Rock-Eval data 100 C34H54 source rocks, oil generation commences between 80 and 115°C, but hydrocarbons will only 0.6 6 max of pre-Devonian source rocks that indicate type III kerogen. Obviously, this kerogen can not be attributed 3 C10H18 460 be expelled where primary migration is highly efficient. The main phase of oil generation 125 High to a terrestrial source, but other reasons for the type III composition of the organic matter could be the volatile C H

Catagenesis 0.8 7 7 13 and expulsion is between 115 and 145°C. Oil is expelled from thicker source rock units with Depth (km) 1.0% Ro

Oil window Immature existence of marine organic structures with pyrolytic character resembling that of humic compounds or

4 150 1.0 9 C5H10 Rock-Eval T 480 efficiencies typically in the range 60 to 80%. Between 145 and 160°C, the late phase of oil Medium 1.3% Ro Bituminous volatile the depletion of hydrogen-rich compounds, the course of maturation, or oxidation of organic matter. 1.3 9 generation is associated with cracking of previously generated oil to give progressively lighter Wet gas 175 Low 5 CH4 500 oils and condensate. At higher temperatures the oil-prone source rock is post-mature. No volatile Mean compostion of generated hydrocarbons 200 2.2 10+ Kerogen residue Lower to Middle Cambrian shales are widespread in the north-western, deeper part of the Baltic Basin. generative capacity remains and reservoired oil is cracking down to wet gas or condensate. (Semi-) tends towards

Dry gas 6 Anthracites graphite 520 Oil window (T ) They may attain more than 100 metres thickness; however, their TOC contents are usually modest (0.5-1%). Gas-prone (vitrinitic) organic matter requires higher maturities to generate hydrocarbons. max

Metagenesis Diagenesis Their role as an effective source rock is not proven. Major gas generation starts in the late-mature oil stage (145-165°C) and continues to at least a. b. 220°C. Included in the figure is a comparative maturity table, showing the approximate level of The Upper Cambrian to Lower Ordovician Alum Shale Member is a regional black-shale source rock that maturation associated with each generative phase. It should be noted that SCI scales may vary; 600 is found from southern Norway to Estonia. It is thickest (up to 150 metres) in an elongated, north-west– b. Plot of Hydrogen Index (HI) versus Tmax, showing the transformation paths of the different ImmatureOil zone Wet gas Dry gas TOC (%) 2 - 5 south-east-trending trough (Chapter 4, Figure 4.18). Southwards, the Alum Shale isopachs are truncated standard kerogen types with maturation (from IGI’s ig.NET and modified after Cornford et al., 580 5 - 10 by the Caledonian Deformation Front extending from southern Denmark across Rügen Island to the Łeba 1998). Upon maturation, the HI drops as the source-rock kerogen is transformed and oil and 10 - 20 High, where the Alum Shale is up to 20 m thick. The sequence pinches out eastwards, where there are gas are generated. The index value may initially rise as a result of TOC reduction due to 560 20 - 40 partly correlative, Upper Cambrian shelf sandstones (Figure 13.4). The Alum Shale is an excellent source decarboxylation. Different kerogen types follow different transformation pathways with 540 rock, with increased organic-carbon contents and pyrolytic yields. The sequence has retained major maturity. Whereas the hydrocarbons are generated from type III kerogen over a broad maturity 40 - 70 520 generative potential in spite of its increased maturity at its southern limit. The Alum black shales have interval, the hydrocarbon generation window for type I kerogens is very narrow. The generative 70 - 100 potential of liptinitic kerogens is lost at a lower maturity than that of vitrinitic kerogens, as been eroded in the central Baltic Basin to the north-east of Kaliningrad and Gotland. The Lower Ordovician 500 Lower Cretaceous Dictyonema and Ceratopyge Shales may contribute to the overall source potential of the Baltic Basin, but shown by the crossing transformation pathways. The cartoon includes a tentative correlation of (¡C) Upper Jurassic max their input to existing discoveries is not proven. T with vitrinite reflectance (dashed lines). It should be noted that the T value is partly T 480 max max Middle Jurassic kerogen dependent; 460 Lower Jurassic c. Plot showing the relationship between the most commonly used maturity parameters, Upper Permian Middle Ordovician (Caradocian) deep-water black shales are excellent source rocks in Lithuania and onshore Kaliningrad where they are up to 40 m thick and their TOC contents can exceed 6%. The black vitrinite reflectance and Rock-Eval Tmax. The diagram includes all high quality data from the 440 Lower Permian SPBA Project Database (TOC >2%, S2 >2kg/t). Even for this large dataset the scatter around Silesian shales are thermally mature in the south-western Baltic Basin. Lower Silurian black shales and other 420 the general correlation trend is limited. This underlines the usefulness of the generally less Dinantian organic-rich facies within the thick Silurian section provide some of the prolific source rocks throughout

accurate Tmax parameter as a maturity indicator. Samples may fall outside the general trend for 400 the basin. A 5 to 25 m-thick sequence of lower Silurian (Llandovery) deep-water black shales is rich in a variety of reasons. Tmax values may be influenced by factors like drilling mud contamination, Main oil window oil-prone organic matter. 380 bitumen staining, or the retention of pyrolysate in the kerogen or mineral matrix. Vitrinite 0.2 0.3 0.4 0.51 2 3 4 reflectance measurements may also be influenced by bitumen staining or may represent Vitrinite reflectance (% Ro) allochthonous material (reworked, caved) rather than indigenous vitrinite. c.

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Chapter 13 — Petroleum generation and migration

Maturity generally increases towards the south-west due to maximum subsidence near the Tesseiyre- The main reservoirs are porous and fractured Middle Cambrian sandstones. Their depth increases content and quartz overgrowth. Other reservoirs include Ordovician and Silurian carbonate mud mounds Tornquist Zone during the Late Paleozoic, whereas source rocks are usually immature in north-eastern dramatically from surface outcrops in western Lithuania to more than 3000 m in western Poland and reefal limestone in western Lithuania. Ordovician and Silurian shales form the regional top seal. Latvia both onshore and offshore. Deviations from this general maturity trend are related to locally (Chapter 4, Figure 4.11) following the regional dip towards the south-west. Reservoir poro-perm (porosity Ø Upper Cambrian clays provide additional seals in the south-west Baltic Basin. enhanced burial along the major faults that define the structural grain of the basin. and permeability K) properties decrease considerably beneath 2000 m depth due to increasing clay Traps are mostly structural in the sandstone play with tilted blocks and horsts generating 4-way dip closures. Mid-Devonian tectonics appear to have created both the structural traps and their fracture

Production index porosity. The overlying organic-rich shales provide the seals. Cambrian traps were repeatedly charged 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 from Cambrian, Ordovician and Silurian sources. The carbonate plays often have a combination of structural 1000 400 HI = 800 Tmax (¡C) TOC (%) Cenozoic and stratigraphic closure, where the carbonate mud mounds pass laterally into non-reservoir carbonates. 0.5 - 1 Upper Cretaceous 600 400 - 420 410 1 - 2 Lower Cretaceous 400 Oil generation in the western part of the basin started during the late Silurian (Wenlock), whereas 420 - 435 2 - 5 Upper Jurassic generation in the central part began during the Mid- to Late Devonian and lasted until the Early 5 - 10 Middle Jurassic 200 435 - 445 420 Lower Jurassic Carboniferous (Figure 13.6). Generation resumed in Permian to Mesozoic times when Cambrian and 10 - 20 445 - 455 Upper Triassic Silurian source rocks were buried to depths that allowed expulsion of dominantly liquid hydrocarbons 100 100 455 - 470 430 20 - 50 Lower Triassic in the east and gaseous hydrocarbons in the west. Type I kerogen 470 - 540 Upper Permian

(¡C) 440 Lower Permian Type II kerogen 50 - 100 max The major regional faults are considered to be migration pathways. The Cambrian oil traps are related to

T Silesian Dinantian local uplift during the long-term tectonic evolution of the basin. Oil generated in the most deeply buried Rock-Eval S2 (kg/t) Type III kerogen 450 Devonian Lower Paleozoic source rocks in the south-western Baltic Basin migrated up-dip to the east and north-east, Silurian where reservoir properties were better than those directly above the source kitchen. In the eastern 10 460 Ordovician Baltic Basin, oil generation decreased after the Mid-Devonian and stopped by Mid-Carboniferous times. Cambrian Carboniferous uplift and erosion in the eastern Baltic Basin appear to have strongly influenced the 470 Well-drained Precambrian source rock migration pathways and migration efficiency. Poorly-drained Undefined source rock 480 0 1 10 100 Crude oils within the Cambrian reservoirs have moderate gravities (26-42°API) that decrease with reservoir a. TOC (%) d. depth, low sulphur (<0.25%) and low asphaltene (<3%) contents. The highest gravity crude oils have 42 to 78% saturated components with predominantly light n-alkanes. C -C n-alkanes, maxima at C and HI (mg/g TOC) 13 19 15 lower amounts of n-alkanes with a carbon number greater than 19. CPI values are close to unity. 0 100 200 300 400 500 600 700 800 900 1000 10 CPI 400 S2 (kg/t) Terrestrial organic matter Biodegraded/immature Pristane/phytane ratios range from 2.07 to 2.65 and increase towards the south-west. Type III kerogen 0.0 - 0.4 2 - 5 Mixed sources 410 0.4 - 0.8 Type II kerogen 5 - 15 Marine organic matter 0.8 - 1.2 For further information see Neumann & Weil (1984), Buchardt & Lewan (1990), Brangulis et al.(1992), 420 15 - 30 Type I kerogen Gérard et al. (1993), Kanev et al. (1994), Bandlova et al. (1995), Kattai et al. (1997), Zdanaviciute & 30 - 60 1.2 - 1.6 430 Bojesen-Koefoed (1997), Buchardt et al. (1999), Domżalski et al. (2004), Otmans (2004), Zdanaviciute & 60 - 120 1 1.6 - 2.0 Lazauskiene (2004, 2007). 440 Oxidising 120 - 200 Early mature 450 2.0 - 3.0 17

(¡C) 200 - 300 460 Not available max Pr/nC T 470

480 0.1 Reducing 490 Figure 13.3 Geochemical data of Precambrian to Cenozoic samples of the SPB area:

500 Mature a. Pyrolytic yield (S2) versus Total Organic Carbon (TOC) plot, modified after Langford and Blanc-Valleron (1990). The lines in the diagram indicate the Hydrogen Index (HI), which is calculated from the two parameters in the plot. Higher HI 510 values correspond to higher quality (more oil-prone) kerogen;

520 0.01 b. Tmax versus HI plot (modified after Espitalié et al., 1984). The trend lines show the transformation pathways upon 0.01 0.1 1 10 100 Ph/nC18 maturation for the standard kerogen types (modified after Cornford et al., 1998). The plot can be used to determine the b. e. approximate kerogen type and provides an indication of the maturity level at which the source-rock kerogen transforms 100 0 and hydrocarbons are generated; 900 TOC (%) Plankton and algae 60 c. Pseudo- Van Krevelen plot (modified after Espitalié et al., 1977 and Peters, 1986). The genetic curves for the standard 0.5 - 1 (variable sources) Type I kerogen 90 10 800 1 - 2 Open marine 50 kerogen types are shown. Each kerogen type follows a different pathway during maturation as it becomes more depleted in Shallow marine 2 - 5 80 20 hydrogen and oxygen relative to carbon. The combination of the HI and Oxygen Index (OI) in this diagram provides an or coastal 40 700 25 - 10 Deltaic-terrigenous estimate of kerogen type and maturation of a sample; 30 70 30 Frequency d. T versus Production Index (PI) plot (modified after Banerjee et al., 1998a). The trend lines show the increase in 10 - 20 Tertiary coals max 600 Type II kerogen Uncommon C 20 volatile organic compounds (S1) with maturity as hydrocarbons are generated from the source rock. At higher maturity 60 40 29 20 - 50 steranes (%) hydrocarbons are no longer retained by the source rock and the system is drained (decrease in PI). The diagram also 500 10 50 50 reveals hydrocarbon staining in immature samples (high PI at low Tmax); 50 - 100 steranes (%) 28 0 C e. Pr/nC versus Ph/nC plot (modified after Lijmbach, 1975). The proportion of pristane and phytane to their 400 0 0.51.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 17 18 40 60 Pr/Ph (a/b) HI (mg/g TOC) neighbouring n-alkanes on the chromatogram provides an indication of the source-rock depositional environment, in Pr/Ph particular with respect to oxygenation and organic-matter type. However, interpretations are complicated as the ratios 300 30 70 0.0 - 0.6 Type III kerogen 0.6 - 1.4 decrease with increased maturity, but increase through biodegradation; 200 20 80 1.4 - 2.0 f. Sterane ternary diagram (modified after Huang and Meinschein, 1979). The source environment interpretation applied 2.0 - 3.0 to the C27, C28 and C29 steranes is based on the distributions of the precursor C27, C28 and C29 sterol-homologues in modern 100 10 90 environments. The diagram works on the principle that C29 sterols are more typically associated with land plants, whereas Type III/IV kerogen 3.0 - 5.0 0 100 algae are the primary producers of C and C sterols (Zumberge, 1987b). However, there is much overlap between the 0 27 28 0 25 50 75 100 125 150 175 200 225 250 275 300 100 90 80 70 60 50 40 30 20 10 0 5.0 - 8.0 different source environments (Moldowan et al., 1985). The main use of the diagram is therefore to characterise different OI (mg/g TOC) C steranes (%) c. f. 27 source rocks by their sterane distribution signature. Plots produced using IGI’s p:IGI-3.

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Chapter 13 — Petroleum generation and migration

18¡E 20¡E 22¡E 1000 HI = 800 Tmax (¡C) CPI 10 Biodegraded/immature 0.9 - 1.1 600 400 - 420 400 1.1 - 1.3 420 - 435

200 435 - 445 56¡N Baltic Sea 445 - 455 Oxidising 100 100 1 Lithuania 455 - 470 Early mature Not

Type I kerogen 17 available

Type II kerogen Pr/nC

Rock-Eval S2 (kg/t) Type III kerogen 0.1 Reducing 10 BALTIC BASIN Mature Russia

55¡N Kaliningrad 0.01 0 1 10 100 0.01 0.1 1 10 100 TOC (%) Ph/nC18 a. d. HI (mg/g TOC) 0 100 200 300 400 500 600 700 800 900 1000 400 100 0 n S2 (kg/t) Plankton and algae 7 Gda sk Type III kerogen 2 - 5 (variable sources) Gdansk IG-1 410 90 10 6 Type II kerogen 5 - 15 Open marine 5 420 Type I kerogen Shallow marine 15 - 30 or coastal 80 20 4 430 30 - 60 Deltaic-terrigenous

70 30 Frequency Poland Tertiary coals 3 440 54¡N 60 - 120 Uncommon C 60 40 29 2 Chojnice 450 steranes (%) 0 100 km Not available 1 (¡C) 50 50 460 steranes (%)

max 28 0

Extent of the Alum Shale Formation prior to erosion Gas T C 0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 Upper Cambrian shelf sandstone Oil 470 40 60 Pr/Ph (a/b) Present-day distribution of Cambrian Oil and gas Pr/Ph 480 30 70 0.8 - 1.2 490 1.2 - 1.6 20 80 1.6 - 2.0 500 Figure 13.4 The Baltic Basin petroleum province with locations of fields and 10 90 2.0 - 3.0 accumulations charged by pre-Devonian source rocks. The distribution of Upper 510 Cambrian and Lower Ordovician organic-rich mudstones (Alum Shale and 0 100 520 3.0 - 8.0 Dictyonema Shale) is prior to erosion (from Vejbæk et al., 1994). The regional 100 90 80 70 60 50 40 30 20 10 0 C27 steranes (%) distribution and thickness of the Alum Shale is shown in Figure 4.18. 0 200 km b. e.

Production index Vitrinite reflectance (% Ro) Tmax (¡C) 2.2 Early Carboniferous, Namurian 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 0.0 0.4 0.81.2 1.6 2.0 400 420 440460 480 500 400 TOC (%) 0 0 Selected wells 2.2.1 Anglo-Dutch and North German basins 0.5 - 1 Gdansk IG-1 410 1 - 2 Koscierzyna IG-1 1 1 Lower Carboniferous and Namurian source rocks in the central Northwest European Carboniferous Basin 2 - 4 Zarnowiec IG-1 Other locations (NWECB; the Netherlands, Denmark and Germany onshore area) have proven to be a significant contributor or 420 4 - 8

of charge to petroleum discoveries and developed fields in the area. High maturity levels and unfavourable 8 - 12 2 2 timing of generation are the main reasons that this otherwise prolific source rock does not play a greater 430 12 - 16 role in charging known petroleum accumulations. However, as they are inferred to be widespread, Lower

Carboniferous and Namurian source rocks have the potential to feature in future discoveries. (¡C) 440 16 - 20 3 3 max T Depth (km) Depth (km) The NWECB experienced a tensional regime during the Early Carboniferous. As seen in northern England 450 4 4 (Chapter 6), a fault-block system comprising horsts and grabens probably characterised the central NWECB. The horst blocks are typically sites where carbonate platforms developed, whereas the grabens were filled 460

with platform debris and some siliciclastic fine-grained material (Chapter 6, Figure 6.9). An extensive 5 5 Silurian 470 Well-drained Ordovician delta complex (the Yoredale delta) prograded into the north-west of the basin. A foredeep filled with source rock flysch sediments developed parallel to the southern NWECB margin. This system was largely incorporated Poorly-drained Cambrian source rock Precambrian into the Variscan fold-and-thrust belt during the Late Carboniferous. 480 6 6 c. f.

Lower Carboniferous and Namurian source rocks were deposited in two distinct depositional environments Figure 13.5 Geochemical data from different Precambrian, Cambrian, Ordovician, and Silurian formations in the Baltic c. Tmax versus Production Index (PI). Mature Ordovician samples partly retain already generated hydrocarbons; across the central NWECB. Black shales formed in fully marine deep-water troughs (basins) and coals Basin: d. Pr/n versus Ph/n; developed on terrestrial to marginal-marine delta plains (Chapter 6, Figure 6.18). Basinal shales, some a. Pyrolytic yield (S2) versus TOC. Most immature source rocks contain type II kerogen irrespective of their age. Another e. Sterane ternary diagram. The sterane composition indicates marine algal organic matter. Inset shows pristane/phytane enriched in organic matter, were deposited alternating with carbonates on the slopes of the carbonate group of samples, most of which are mature, plots as type III kerogen. Note that land plants that evolved in Silurian times ratios, which are high compared to the Mesozoic source rocks in the region;

platforms and in the basinal areas. When carbonate production ceased at the Namurian-Viséan transition, contributed a negligible fraction to the biomass by the time of source-rock formation; f. Vitrinite reflectance and Rock-Eval Tmax parameters plotted against sub-bottom depth. Note two different reflectance basinal black shales were also deposited on the carbonate platforms in areas where sedimentation rates b. Tmax versus Hydrogen Index (HI). The unusually elevated Tmax values of the richest Silurian and Ordovician samples gradients within closely adjacent locations in Pomerania. Tmax values display an unusual maturity increase upsection. had remained limited (e.g. on the Derbyshire Block; the Bowland and Geverik members). In the basinal implies an organic-matter composition that is less thermally labile than standard type II kerogen; Plots produced using IGI’s p:IGI-3.

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Chapter 13 — Petroleum generation and migration

Gdansk IG-1 Age (Ma) The original source-rock composition and quality of Lower Carboniferous and Namurian black shales is Analogous to the lower maturity of Lower Carboniferous and Namurian source rocks along the northern 550 500 450 400 350 300 250 200 150 100 50 0 poorly known due to the limited amount of well data and elevated maturity (Figure 13.8). Lowermost NWECB margin and the south-eastern North Sea, gas generation only began during the Cenozoic and Paleozoic Mesozoic Cenozoic Namurian hot shales (equivalent to the Bowland Shale) from the Ems Estuary area have more than 2% TOC continues to the present day. In the central NWECB, the great thickness of Upper Carboniferous rocks Cambrian Ordovician Silurian Devonian Carboniferous Permian Triassic Jurassic Cretaceous Paleogene Neogene 0 content and kerogen types I and II. In the southern Netherlands, Namurian hot shales have TOC contents and the high heat flow at the end of the Carboniferous caused the main phase of hydrocarbon generation of up to 10%, mainly of type II. In the south-eastern North Sea, organic matter is of type III kerogen with from Lower Carboniferous and lower Namurian source rocks to range from the mid-Westphalian (B-D) well 0.5 20 TOC contents up to 2%. Dispersed terrestrial organic matter in paralic Namurian deposits has moderate to into Stephanian times. The most important reservoir (Rotliegend sandstones) and seal (Zechstein) in the low HI values (50-80) and maturity (<0.8% Rr). NWECB had not been deposited by then; therefore, much of the hydrocarbons must have migrated to the 1 surface and been lost (Figure 13.9). Late Cretaceous inversion induced decreasing temperatures and 40 Maturity is generally low along the northern NWECB margin where the burial depth and thickness of the hydrostatic pressures in the uplifted pre-Westphalian source rocks in the western German sector of the 1.5 Carboniferous succession are rather limited. The maturities of Lower Carboniferous Yoredale Formation North Sea and the Duck’s Bill region, causing gas generation to cease. Desorption from gas-prone source 60 coals and Namurian deposits of the northern Dutch D and E offshore blocks indicate that they are in the rocks and free-gas exsolution added to the pool of newly accumulated gas. 2 80 Depth (km) oil window. In the western German sector of North Sea, the Tournaisian successions are moderately mature,

80 100 showing good gas potential, whereas Visean deposits, with the exception of those with high vitrinite For further information see Gerling et al. (1999a), Hoffmann et al. (2001, 2005, 2008), Kus et al. (2005), 2.5 reflectance values caused by localised Permo-Carboniferous magmatic sills, are in general below the gas Kombrink (2008), De Jager & Geluk (2007) and Drozdzewski (2009). 120 window. In the south-eastern North Sea, the present-day maturity of lower Namurian and Visean deposits 3 140 100 is often well below 1.5% Rr (excluding areas affected by Permo-Carboniferous magmatic intrusions). The 2.2.2 East Midlands 120 deposits south of the proven Yoredale facies in the UK and Dutch offshore sectors have maturities in the 3.5 Vitrinite reflectance (% Ro) Isotherm (¡C) gas window or are overmature. For example, the present-day maturity of lower Namurian source rocks in The East Midlands oil province consists of a series of largely concealed Carboniferous sub-basins bordered 0.5 - 0.7 0.7 - 1.0 1.0 - 1.3 Position of stratal boundary through time the Ems Estuary area vary from 3.7% to 5.1% Rr. Farther east and to the south, Lower Carboniferous and on the south by the London-Brabant Massif, to the west by the Derbyshire Dome and to the north by the Namurian source rocks are also found or expected to be overmature. Market Weighton Block, which separates the province from the Cleveland Basin. Over 30 fields have been a. exploited, mostly for oil but with some gasfields in the west. Basin formation commenced in the Late Age (Ma) 2¡W 0¡ 2¡E 550 500 450 400 350 300 250 200 150 100 50 0 Devonian and continued throughout most of the Early Carboniferous, producing structures with a dominant north-west–south-east trend and a subsidiary north-east–south-west trend controlled mainly Paleozoic Mesozoic Cenozoic MID NORTH SEA HIGH by Caledonian structures in the basement (Figure 13.10). The timing of movements on individual faults Cambrian Ordovician Silurian Devonian Carboniferous Permian Triassic Jurassic Cretaceous Paleogene Neogene varied considerably such that the main depocentres formed from early to late Dinantian and early Source rock Newcastle Westphalian times. However, in general the main Dinantian tilted fault blocks were covered by Upper Reservoir rock Carboniferous sediments (Figure 13.11). ALSLTON BLOCK Seal rock

Overburden rock 55¡N Late Carboniferous (Variscan) east–west compressional movements led to inversion of the area, commonly Underburden rock along the original extensional faults. This was followed by regional tilting to the east associated with Trap formation Permian and Mesozoic subsidence in the North Sea, which resulted in a thin Permian to Mesozoic cover 43/10-1 that generally thins north-westwards. These strata have only a few low-amplitude structural closures and Gen./migr./accum. are generally considered non-prospective for petroleum exploration. A further period of inversion of the Preservation ASKRIGG BLOCK whole sequence during the Cenozoic was associated with Alpine movements, and erosion from this 41/24a-2 43/20b-2 400 Ma Critical moment Kirby Misperton 43/17b-2 44/16-2 inversion continues to the present day. The extent of Cenozoic uplift is not known with any certainty, CLEVELAND BASIN 43/24-1 b. 43/25-1 although apatite fission-track analyses and sonic-velocity studies suggest about 1200 m of uppermost Figure 13.6 a. Burial and thermal history model results for Gdánsk IG-1 well. See Figure 13.4 for location. Note the rapid Cretaceous and Cenozoic strata have been removed. subsidence and burial during Silurian to Devonian times and ensuing Carboniferous and Permian uplift, followed by renewed rapid burial in the earliest Mesozoic (modified after Botor & Kosakowski (2000) using the Harland et al.(1989) time scale); MARKET The main source rocks in the East Midlands are found in Namurian strata. These are early Namurian distal b. Event chart for the pre-Devonian petroleum system of the western Baltic Basin. Note three periods of petroleum generation. WEIGHTON 48/03-3 54¡N prodelta shales (e.g. upper part of the Bowland Shales and equivalents), which were deposited in the main GAINSBOROUGH BLOCK TROUGH sub-basins (Figure 13.10). The middle Dinantian shales and limestones found at outcrop or in wells (e.g. areas, black-shale deposition may well have continued from the Visean into the Namurian. As the most Milldale Limestone) are less important potential source rocks. Westphalian coals are widespread and were important sediment source area was to the north, sediment-starved conditions and associated black-shale EDALE previously worked extensively; however, generally they are not sufficiently mature to have contributed BASIN deposition were confined mainly to the central and southern NWECB. Wells to the north of the Ruhr Basin significantly to the area’s petroleum accumulations. The TOC content of the Namurian shales is poorly and in the eastern Netherlands (Winterswijk-01) have penetrated Lower Carboniferous sections that known, but probably varies between 2 and 10%. Carbon-isotope data suggest that two main source rocks consist almost entirely of basinal black shales (Culm facies and Upper Alum Shale Formation (Chapter 6, EAST MIDLANDS have contributed; a dominant source contributing oils around δ13C of –30‰ correlates with the prodelta WIDMERPOOL GULF 48/23-3 Figure 6.7). Namurian shales, whereas isotopically heavier (around –27‰) oil is encountered in the Caunton and Nottingham Kelham Hills fields and the Newark discovery (Figures 13.10 & 13.12f). Oil from the Newark area is Magnetotelluric soundings indicate a good conductor at 7000 to 9000 m depth ascribed to black-shale facies thought to be derived from marine bands and local interdistributary-channel mudstones, probably within

deposited in graben structures in the central NWECB (Chapter 6, Figure 6.18). Lower Carboniferous or 53¡N the Namurian sequence. Namurian black shales can be inferred based on nitrogen concentrations in reservoirs in the central NWECB, Leicester as these may have contributed nitrogen during late maturation. The relatively high nitrogen content LONDON-BRABANT MASSIF Maturation is difficult to constrain due to the limited number of published maturity measurements in the (15%) in reservoirs such as Groningen may point to an ‘old’ charge event with nitrogen being sourced region. Where data are available, most wells show a higher maturity gradient in the pre-upper Westphalian from Namurian basinal shales. Gas composition in the Ems Estuary area and the south-eastern North Sea strata, suggesting a higher geothermal gradient at that time, although the picture is complicated by also indicates a pre-Westphalian sapropelic source rock. In the UK offshore, Namurian source rocks are erosion at the Carboniferous Variscan Unconformity. Maturity of the Namurian source rocks is thought 0 100 km inferred to have contributed to the Flora field in the southern Central Graben. In the German offshore to be higher in the basinal areas (Gainsborough Trough and Widmerpool Gulf) and hydrocarbons probably

sector, reservoirs with a Namurian contribution are found in Zechstein carbonates and in Carboniferous, Dinantian basins migrated towards the shelf areas. Rotliegend and Upper Jurassic sandstones. Namurian source rocks were encountered in hole Q1 in the Dinantian shelf areas south-eastern North Sea and in boreholes in the Ems Estuary area. Based on this information and limited Present-day distribution of Carboniferous sediments Thermal modelling suggests Late Carboniferous generation (Figure 13.13). This would have been arrested in well and seismic data, the basinal shales are likely to occur from the UK (Figure 13.7) to eastern Germany Gas the extreme west by erosion along the Pennine uplift during the Variscan Orogeny, although generation would (Chapter 6, Figure 6.18). Oil have resumed and extended eastwards by regional subsidence during Permian and Jurassic times. Migration Well with Namurian black shales patterns were also influenced by the north-west–south-east-trending structural grain, which concentrated In the north-western NWECB, extending into the present-day German and Danish offshore sectors, Figure 13.7 The western area of the Northwest European Carboniferous Basin with source rocks in the elongated grabens (Gainsborough Trough, Widmerpool Gulf etc.; Figure 13.10). Migration Lower Carboniferous and Namurian coal seams were formed in the Yoredale delta system (Chapter 6, location of fields and accumulations charged by Namurian source rocks. Elevated routes over significant distances are anticipated to explain the hydrocarbon occurrences in the region. Figure 6.6). In the south-eastern North Sea, lower Namurian deposits consist of alternating shales and nitrogen concentrations in Rotliegend reservoirs broadly correlate with the occurrence sandstones with conglomeratic horizons and sporadic coal seams, coal tonstein and seat earths. of overmature Lower Carboniferous black shales. 0 200 km

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Chapter 13 — Petroleum generation and migration

Age (Ma) All of the accumulations in the West Midlands are trapped in anticlinal structures that are either relic probably coinciding with remigration at the end of the Carboniferous. Anything generated more recently 400 350 300 250 200 150 100 50 0 rollovers, inversion fault controlled, or above horst blocks. Most of these structures formed early during (i.e. Jurassic to Cretaceous) was available to charge structures essentially in their present-day configuration Paleozoic Mesozoic Cenozoic rifting, but all have been significantly modified during subsequent inversion periods. This inversion, and the with insignificant secondary alteration, other than possibly biodegradation if reservoired at shallow depths. Devonian Carboniferous Permian Triassic Jurassic Cretaceous Tertiary Permian-Jurassic tilting episode, has resulted in considerable remigration of all oil and gas generated during Reservoir presence is rarely a problem for exploration in the East Midlands, which has abundant reservoir- E M L E L E M L E M L E M L E L Paleogene Neogene the Carboniferous. This is clearly seen for example in the Bothamsall oilfield where at least two phases of quality carbonates and particularly clastic beds. The principal producing reservoirs are sandstones within charge can be recognised; an early charge associated with Carboniferous burial and a subsequent charge, the Westphalian Coal Measures (e.g. Gainsborough, Eakring, Duke’s Wood, Welton, Beckingham). In places Northern Netherlands onshore

1000 HI = 800 Tmax (¡C) CPI Northern Netherlands 10 Terrestrial organic matter Biodegraded/immature 0.3 - 0.5 offshore 600 400 - 420 Mixed sources 0.5 - 0.7 400 Marine organic matter 420 - 435 0.7 - 0.9 Southern Netherlands onshore 0.9 - 1.1 200 435 - 445 1.1 - 1.3 445 - 455 Oxidising Figure 13.9 Generation and expulsion of hydrocarbons from Lower Carboniferous and Namurian source rocks in the 100 100 455 - 470 1 1.3 - 1.5 Early mature Netherlands through time, illustrating the early generation phase for these rocks. 470 - 540

Type I kerogen 17 540 - 600 1.5 - 2.0

Type II kerogen Not Pr/nC where the basal sands of meandering deltaic channels are locally stacked, reservoirs more than 100 m thick available 2.0 - 3.0 are possible. Oil is also found in levee and distributary mouth and bar sands, usually thinly interbedded Rock-Eval S2 (kg/t) Type III kerogen Undetermined with siltstones. These are sealed intraformationally by overbank and floodplain shales. A second important 0.1 Reducing reservoir is the Namurian Millstone Grit (e.g. Gainsborough-Beckingham, Eakring, Duke’s Wood and 10 Bothamsall), sealed by shales at the base of the Coal Measures. These are fluviodeltaic and turbiditic and, Mature although somewhat scattered, they usually have a very significant net-to-gross ratio in their upper part. Other minor reservoir intervals include fractures at the top of the Dinantian Carboniferous limestone, sealed by Namurian shales, which has produced small quantities of oil at Hardstoft, Eakring, Duke’s Wood, 0.01 0 1 10 100 0.01 0.1 1 10 100 Plungar and Nocturn. The basal Permian sands have not yet yielded a commercial discovery but contain TOC (%) Ph/nC18 a significant oil show at Nocton. The extensive syn-rift Devonian Old Red Sandstone, which underlies the a. d. Carboniferous in much of the basin, is also a prospective future target although the limited tests so far HI (mg/g TOC) have proved fruitless, as would Dinantian patch-reefs if they could be found in the subsurface (analogous 0 100 200 300 400 500 600 700 800 900 1000 400 100 0 to the now-exposed Windy Knoll) exposure in Derbyshire. S2 (kg/t) Plankton and algae 10 Type III kerogen 2 - 5 (variable sources) 9 410 90 10 Type II kerogen Open marine 8 5 - 15 For further information see Hawkins (1978), Kirby & Swallow (1987), Fraser and Gawthorpe (1990) and 420 Type I kerogen Shallow marine 7 or coastal 80 20 Fraser et al. (1990). 15 - 30 6 430 Deltaic-terrigenous 5 Tertiary coals 70 30 Frequency 2.2.3 Cleveland Basin 440 4 Uncommon C 3 60 40 29 450 steranes (%) 2 The Cleveland Basin forms the north-west extension of the Southern North Sea Gas Basin and shares much of

(¡C) 50 50 1 its geology with the adjacent Sole Pit Trough. It is mainly a Jurassic to Early Cretaceous structure, overlying 460 steranes (%)

max 28 0 T C 0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 an older Carboniferous basin. In both cases, the dominant fault zone appears to have been in the north 470 40 60 Pr/Ph (a/b) Pr/Ph although antithetic faults are also present to the south. The basin is fault-bounded to the north against 480 30 70 0.4 - 0.8 the Durham coalfield (immature Westphalian) and to the south by a complex fault zone (Vale of Pickering- 490 0.8 - 1.2 Flamborough Head Fault Zone) against the Market Weighton Axis and the Selby coalfield (also immature 20 80 1.2 - 1.6 Westphalian), which separates it from the East Midlands province (see previous section, Figure 13.15). 500 Seven gasfields have been discovered: Caythorpe, Eskdale, Kirby Misperton, Lockton, Malton, Marishes and 10 90 1.6 - 2.0 510 Pickering (Figure 13.14). During the Devonian, the Cleveland area probably acted as a sediment source. 0 100 520 2.0 - 3.0 Sedimentation commenced during the Tournaisian, somewhat later than in the East Midlands. Due to its 100 90 80 70 60 50 40 30 20 10 0 proximal setting with respect to the sediment source in the north, Namurian source rocks in the Cleveland C27 steranes (%) b. e. Basin are mainly characterised by coals. Major periods of inversion took place at the end of the Carboniferous (Variscan Unconformity) and during the Cenozoic (Alpine Orogeny) towards the east–west basin axis Production index 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 (Figure 13.15). The basin thickens considerably to the east. Although there have been a number of small 400 TOC (%) gas discoveries, the understanding of the petroleum geology of the Cleveland Basin is still at an early stage. 1 - 3 410 3 - 6 Namurian shales or coals are thought to be the source of the gas discoveries in the Cleveland Basin. Most 6 - 10 of the Westphalian strata were eroded and now remain only as isolated outliers (e.g. a small north-west– 420 10 - 20 south-east-trending patch at Robin Hood’s Bay, Figure 13.14). The maturity of Namurian shales in the Cleveland Basin is thought to be high, probably in the dry-gas window, as even Middle Jurassic coals have 20 - 40 430 vitrinite reflectance values between 0.82 and 0.87% Ro (Figure 13.16). 40 - 80 (¡C) 440 Figure 13.8 Geochemical data from Lower Carboniferous and Namurian source rocks of the central Northwest Hydrocarbon generation had probably started by Late Carboniferous times (Figure 13.17), although the max T European Carboniferous Basin: most important petroleum generative phase took place during the Jurassic and Cretaceous. Migration 450 a. Pyrolytic yield (S2) versus TOC. The high-TOC samples mostly represent Visean (Yoredale Formation) coals during Jurassic and Cretaceous burial was mainly southwards to a postulated Market Weighton granite derived from the north-western part of the basin. The data cluster near the origin comprises Visean and dome, although some northward migration would also have been possible. 460 Namurian (black) shale samples, probably of marine origin;

Namurian b. Tmax versus Hydrogen Index (HI); Most production to date has been from fault traps along the southern fault zone. These mainly 470 Well-drained Visean source rock c. Tmax versus Production Index (PI); east–west-trending Jurassic and Cretaceous faults cut across the predominantly north–south-trending Poorly-drained Tournaisian d. Pr/n versus Ph/n; Permian facies belts. Consequently, the most recent discoveries (Malton, Pickering and Kirby Misperton) source rock Undefined 480 e. Sterane ternary diagram. Most samples are derived from marine source rocks. Inset shows pristane/phytane are located along a north–south trend within this southern fault zone. Trap breaching and remigration c. ratios. Plots produced using IGI’s p:IGI-3. towards the basin axis were the key features associated with Cenozoic Alpine inversion.

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Chapter 13 — Petroleum generation and migration

0¡ There are reservoir rocks in Namurian sandstones (Kirby Misperton field), basal Permian Rotliegend Subcrop at the base Permian sandstones (Caythorpe field) and fractured Zechstein dolomites (Caythorpe, Eskdale, Malton and Marishes Bolsovian fields). The Jurassic sequence also includes numerous sandstones of reservoir quality. There is probably Duckmantian Langsettian further potential along the faulted northern basin margin extending offshore; however, this has only Namurian been poorly explored so far. Namurian/Westphalian MARKET-WEIGHTON BLOCK Tournaisian/Visean 2.2.4 Pomerania Pre-Devonian Igneous Pomerania is situated on the Trans-European Suture Zone (TESZ), a mosaic of crystalline blocks separated

Trumfleet Dinantian shelf areas from the East European Platform by the Koszalin Fault Zone. To the south, the Variscan Deformation Front Crosby Warren Gas forms the transition to the folded Carboniferous rocks of the Polish Trough. Twelve Carboniferous-sourced Oil gasfields have been proven in Pomerania (Figure 13.18). Broughton Hatfield Fault During the Early Carboniferous, the Pomerania region formed the southern shelf area of the Eastern Brigg European Platform, characterised by mixed siliciclastic-carbonate shallow-marine deposits (see Chapter 6, GAINSBOROUGH TROUGH Cross-section in Figure 13.11 Figure 6.10). The area was uplifted during the Namurian and acted as a source of clastic material for the Everton sedimentary basins of central and southern Poland. Sedimentation resumed during Westphalian times. Corringham The transition from deltaic to fluvial conditions only took place during the Westphalian C, in contrast to most areas in the NWECB, where it had occurred during the early Westphalian. From Rotliegend to Beckingham Glenworth Gainsborough Late Cretaceous times, the area was part of an extensive basin until Alpine inversion caused Pomerania to be uplifted (Figure 13.19). The Tournaisian, Visean and Westphalian black shales that occur across East Glentworth Saltfleetby the entire Pomeranian region are the main source rocks. Uplift has largely restricted Namurian source West Firsby South Leverton C. Hanworth rocks to southern Pomerania. Thin Westphalian coal seams also occur. Scampton North 0 200 km Calow Torksey Bothamsall Scampton Stainton Keddington FarleyÕs Wood Beckering Tournaisian and Visean shales have average TOC contents of 1.5% and 1.1% respectively, both with Newton-on-Trent Cross-section Nettleham maximum values of about 10% (Figure 13.20a). Westphalian shales have average TOC content of 0.3% in Figure 13.11 Welton Egmanton Fiskerton Airfield (up to 2.2%). Namurian and Westphalian bituminous coal streaks and interbeds are usually less than 0.5 m Whisby Reepham thick. Kerogen is mainly gas-prone type III with admixtures of type II (Figure 13.20a & b). Average Eakring Hydrogen Indices decrease upwards from the Lower Carboniferous (180 mg/g) to the Upper Carboniferous EAST MIDLANDS SHELF (110 mg/g), but they typically have a wide range. Stable carbon-isotope data from natural-gas samples Kirklington Ironville Kelham Hills corroborate a major contribution from Carboniferous type III kerogen. Some thin layers are characterised by significant alginite contents. The Lower Carboniferous clayey-marly Sąpolno Formation has considerable amounts of oil-prone, structureless, fluorescing sapropelic organo-mineral associations with liptinite Newark area (type II kerogen). Tournaisian samples in particular are predominantly in the type II kerogen field (Figure 13.20a). Saturated hydrocarbon compositions are generally homogeneous, which is reflected by indices such as the ratio of the abundance of odd carbon number normal alkanes to even carbon number Nottingham normal alkanes (Carbon Preference Index, CPI), the pristane/n-C17 ratio, phytane/n-C18 ratio and Cropwell Butler pristane/phytane ratio (Pr/Ph). WIDMERPOOL GULF Belvoir 53¡N Both Tmax and vitrinite reflectance values indicate that the Tournaisian to Westphalian source rocks are Kinoulton mostly marginally mature to mature (Figure 13.20b; Chapter 6, Figure 6.19). The highest present-day Rempstone maturity varies around 1.8% Ro, indicating the gas-generating potential of Carboniferous source rocks Long Clawson in the southern Pomeranian petroleum province. 0 25 km Figure 13.10 The East Midlands petroleum province with locations of fields and accumulations charged by Namurian source rocks. A first generation and migration phase took place in the Late Carboniferous at maturities of about 0.6 to 0.8% Ro (Figure 13.21). In places where the petroleum potential was not exhausted during the course of this early generation phase, there were two more generative phases in the Triassic-Jurassic and in

SSW NNE Late Cretaceous times, when maturities reached 1.4 to 1.8% Ro. The latter phase generated gases that Hathern Shelf Widmerpool East Midlands Shelf Gainsborough Trough South Humberside probably migrated over distances that did not exceed several tens of kilometres. Hathern-1 Gulf Ilkeston-1 Eakring-146 FarleyÕs Wood-1 Beckingham-1 Gainsborough-2 Shelf Traps are both structural and stratigraphic, but are small and often accompanied by faults. Some traps 0 Triassic have the characteristics of combined structural and stratigraphic trapping. Reservoirs include Visean Permian limestones (Ø: 2-16%, K: 100-400 mD), Namurian (Ø: 16-23%; K: 208-274 mD), Westphalian (Ø: 5-15%; K: 1 Namurian/Westphalian 74-190 mD) and Rotliegend sandstones. The fluvial Rotliegend sequence is up to 750 m thick (the total Lower Carboniferous siliciclastics Rotliegend section is much thicker) and contains a number of potential reservoir units. The maximum 2 Lower Carboniferous carbonates Paleozoic basement thickness of the aeolian sandstones is usually less than 50 m. Both fluvial and aeolian sandstones have fair porosities (Ø: 0-13%, generally <5%), although their permeabilities are mostly less than 1 mD. 3 Oil Depth (km) In contrast to the primary matrix porosity, fracture porosities and permeabilities can be considerable. 0 4 km 4 Zechstein salt and anhydrite form the seal for the Carboniferous and Rotliegend reservoirs, whereas intraformational seals play only a minor role (Chapter 7; Figure 13.21).

5 Natural gas in the Pomeranian reservoirs is rich in nitrogen (39-78%) and contains 22 to 58% methane, 6 some ethane, propane and helium. The nitrogen content increases westwards and less evidently to the south.

7 For further information see Karnkowski, (1996, 1999b) and Kotarba et al. (2004, 2005). Figure 13.11 Cross-section through the East Midlands petroleum province (see Figure 13.10 for location). Based on Fraser & Gawthorpe (1990).

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Chapter 13 — Petroleum generation and migration

Age (Ma) 1000 HI = 800 Tmax (¡C) CPI 400 350 300 250 200 150 100 50 0 10 Terrestrial organic matter Biodegraded/immature 0.7 - 0.9 600 400 - 420 Mixed sources Paleozoic Mesozoic Cenozoic 0.9 - 1.1 400 Marine organic matter Devonian Carboniferous Permian Triassic Jurassic Cretaceous Tertiary 420 - 435 1.1 - 1.3 E M L E L E M L E M L E M L E L Paleogene Neogene 200 435 - 445 Source rock 445 - 455 Oxidising 100 100 Not 1 Early mature Reservoir rock available

Type I kerogen 17 Seal rock

Type II kerogen Pr/nC Overburden rock Trap formation Rock-Eval S2 (kg/t) Type III kerogen Generation 0.1 Reducing 10 Migration Accumulation Mature Preservation

Figure 13.13 Event chart for the Early Carboniferous and Namurian petroleum system in the East Midlands petroleum 0.01 0 1 10 100 0.01 0.1 1 10 100 province. TOC (%) Ph/nC18 0¡ a. d. HI (mg/g TOC) 0 100 200 300 400 500 600 700 800 900 1000 400 100 0 S2 (kg/t) Plankton and algae 7 Type III kerogen 2 - 5 (variable sources) 410 90 10 6 Type II kerogen Open marine 5 - 10 5 420 Type I kerogen Shallow marine or coastal 80 20 10 - 20 4 430 Deltaic-terrigenous

70 30 Frequency Tertiary coals 3 440 Uncommon C 60 40 29 2 450 steranes (%) Cross-section 1 in Figure 13.15 (¡C) 50 50 460 steranes (%)

max 28 0 T C 0 0.2 0.4 0.6 0.81.0 1.2 1.4 1.6 1.8 2.0 2.2 2.4 2.6 2.8 3.0 470 40 60 Pr/Ph (a/b)

480 30 70 Pr/Ph Eskdale 490 0.8 - 1.2 20 80 1.2 - 1.6 500 10 90 1.6 - 2.0 510 2.0 - 3.0 0 100 520 100 90 80 70 60 50 40 30 20 10 0 C27 steranes (%) b. e. Lockton

Production index Pickering 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 400 Ð22 Kirby Misperton TOC (%) 13 13 Type CV = Ð2.53 δ Csats + δ Carom Ð 11.65 1 - 2 Oil Malton Ð23 410 2 - 3 CV = 0.47 Rock Marishes 3 - 4 Ð24 Nonmarine 420 4 - 6 Ð25

6 - 8 Ð26 430 Caythorpe

Ð27

(¡C) 440 Marine max Ð28 T

450 Ð29 C aromatic fraction (ä pdb) 13

δ 0 25 km Ð30 460 54¡N Ð31 Subcrop base Permian 470 Well-drained Bolsovian source rock Ð32 Poorly-drained Namurian Duckmantian source rock Langsettian 480 Ð33 Visean (part a. only) Ð34 Ð33Ð32 Ð31 Ð30 Ð29 Ð28 Ð27 Ð26 Ð25 Ð24 Namurian 13 δ C saturate fraction (ä pdb) Tournaisian/Visean c. f. Figure 13.12 Geochemical data from Lower Carboniferous and Namurian source rocks (and oils) in the East Midland Dinantian shelf areas Gas petroleum province: a. Pyrolytic yield (S2) versus TOC; b. Tmax versus Hydrogen Index (HI); c. Tmax versus Production Oil Index (PI); d. Pr/n versus Ph/n; e. Sterane ternary diagram. Most samples are derived from open-marine source rocks. Fault Inset shows pristane/phytane ratio; f. Carbon-isotope values from oils and source rocks (from Fraser et al., 1990). 0 200 km Plots produced using IGI’s p:IGI-3. Figure 13.14 The Cleveland Basin petroleum province with locations of fields and accumulations charged by Namurian source rocks.

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Chapter 13 — Petroleum generation and migration

NW SE Major trap formation and migration probably took place during Triassic and Jurassic times. The traps The most prominent reservoirs for the Carboniferous source rocks are quartzitic Rotliegend sandstones. Stainmore Basin Cleveland Basin are mostly stratigraphic and may be stratigraphic/structural (fault-related, e.g. Radlin field; see There are minor accumulations in Carboniferous and Zechstein reservoirs, which are sealed by Zechstein Durham TeesideCleveland Anticline Lockton Anticline coalfield Chapter 7; Section 6.4.2). Unconformity-related and facies-related stratigraphic traps are common at anhydrite and halite. North of the Wolsztyn High, the Rotliegend succession consists of up to 750 m-thick 0 the northern margin of the Wolsztyn High. The effects of post-Cretaceous inversion on the initiation, aeolian sandstones (Ø: 5-21%, K: 0.1->100 mD). Farther north, their total thickness increases to almost compartmentalisation and destruction of traps are currently being studied. 1000 m (Øav: 1-16%, Kav: 0-25 mD). About 100 m-thick fluvial and alluvial Rotliegend sandstones form Mercia Mudstone

1 Hartlepool Brotherton Formation Sherwood Sandstone Fault Kirkham Abbey Formation 1000 HI = 800 Tmax (¡C) CPI Cadeby Formation 10 Terrestrial organic matter Biodegraded/immature 0.7 - 0.9 600 400 - 420 Mixed sources Vale of 0.9 - 1.1 2 Seaton Carew Fault Pickering 400 Marine organic matter Fault Depth (km below sea level) 420 - 435 1.1 - 1.3 Butterknowle Fault Cleveland Dyke 200 435 - 445 1.3 - 1.5 Upper Triassic Lower Paleozoic 0 10 km Cretaceous 445 - 455 Lower Permian Igneous dyke Oxidising 1.5 - 2.0 100 100 455 - 470 1 Early mature Upper Westphalian Carboniferous 470 - 540 Middle Jurassic Namurian Type I kerogen 17 2.0 - 3.0 Not Lower Upper Devonian Ð Carboniferous (Dinantian) Type II kerogen available Pr/nC Figure 13.15 Cross-section through the Cleveland Basin petroleum province. See Figure 13.14 for location. Rock-Eval S2 (kg/t) Type III kerogen 0.1 Reducing 2.2.5 Fore-Sudetic Monocline (Wielkopolska petroleum province) 10

The Fore-Sudetic Monocline is bound to the north by the less-faulted Carboniferous rocks of Pomerania, Mature and to the east and south-east by the Holy Cross Mountains and the Upper Silesian Basin. A similar setting is found westwards in eastern Germany, whereas the southern boundary is poorly defined as a 0.01 result of its deep burial. Many reservoirs of various ages have been charged by Carboniferous source rocks 0 1 10 100 0.01 0.1 1 10 100 (Figure 13.22). Only one Carboniferous reservoir unit has been found to date (in the Paproć C field), TOC (%) Ph/nC18 whereas there are abundant Rotliegend and Zechstein discoveries and fields. a. d. HI (mg/g TOC) 0 100 200 300 400 500 600 700 800 900 1000 100 0 Carboniferous rocks in the Fore-Sudetic Monocline are deeply buried (Figure 13.23) and consist mainly 400 4 S2 (kg/t) Plankton and algae Type III kerogen of Lower Carboniferous flysch sediments deposited in the Variscan foreland basin. Late Carboniferous 2 - 5 (variable sources) 410 90 10 Type II kerogen Open marine post-orogenic deformation caused intense faulting (the area is mostly south of the Variscan Deformation 5 - 15 3 420 Type I kerogen Shallow marine Front). Uplift led to the erosion of the thick Namurian to Westphalian cover; only isolated areas of Upper 15 - 30 or coastal 80 20 Carboniferous rocks remain. From Rotliegend to Late Cretaceous times, this area was part of an extensive 430 Deltaic-terrigenous 30 - 60 2 basin; however, Alpine inversion led to uplift, especially in the north-eastern area of the Fore-Sudetic Tertiary coals 70 30 Frequency 440 60 - 100 Uncommon C Monocline. 60 40 29 450 steranes (%) 1 100 - 200

(¡C) 50 50 The Fore-Sudetic Monocline is subdivided into three regions on the basis of its reservoir rocks and gas 460 steranes (%)

max 28 0 compositions. Thirty-eight gasfields occur in the uppermost Rotliegend sandstones north of the Wolsztyn T C 0 0.5 1.0 1.5 2.0 2.5 3.0 470 40 60 Pr/Ph (a/b) High. The Wolsztyn High is a pre-Permian ridge where Rotliegend reservoir sandstones are absent (subcrop Pr/Ph 480 of pre-Carboniferous rocks, Figure 13.22). There are six gasfields in the Zechstein Limestone of the 30 70 0.4 - 0.8 Z1-Werra cyclothem on the Wolsztyn High. South of the high, gasfields are found in the uppermost 490 0.8 - 1.2 Rotliegend sandstones, in the Zechstein Limestone, and often in both. 20 80 1.2 - 1.6 500 1.6 - 2.0 10 90 Lower Carboniferous and Namurian source rocks are mainly shales with dispersed organic matter that were 510 2.0 - 3.0 0 100 deposited in the Variscan foredeep. Organic-carbon contents are generally lower (up to 4%), more humic 520 and gas-prone in the Fore-Sudetic Monocline than in other Polish Carboniferous basins (Figure 13.24a). 100 90 80 70 60 50 40 30 20 10 0 3.0 - 5.0 C27 steranes (%) The organic material consists mainly of vitrinite group macerals, whereas the inertinite group is b. e. subordinate and the liptinite group macerals are marginal. There are subordinate quantities of oil-prone Production index and mixed type II and III kerogen. However, reliable characterisation of the original kerogen is severely 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 hindered by the high maturity of most samples obtained from the area (Figure 13.24b). 400 TOC (%) 1 - 3 Lower Carboniferous source rocks in the Fore-Sudetic Monocline are overmature in large areas due to 410 3 - 6 deep burial, Early Permian magmatism and hydrothermal activity. Maturity increases towards the axis 6 - 10 of the Mid-Polish Trough and the eastern Fore-Sudetic Monocline due to deeper burial and higher heat 420 10 - 20 flow. T values range from 440 to 520°C (Figure 13.24b) and vitrinite reflectance from 1 to 5%. max 20 - 40 Transformation ratios of Carboniferous deposits correspond mainly to the thermogenic dry-gas phase. 430 40 - 80 In rapidly subsiding areas with high heat flow (80-100 mW/m2), petroleum generation started as early as (¡C) 440 max the Late Carboniferous (Figure 13.25) and kerogen was almost completely transformed (transformation T ratio near 100%; Figure 13.24b & c). In the areas of the Fore-Sudetic Monocline where petroleum 450 potential still existed after the Carboniferous, generation resumed in Mid-Triassic to Late Jurassic and in Late Cretaceous times, as it did in the Pomerania region. Peak thermal maturities locally reached 460 5% Ro leading to dry-gas generation and overcooking. The main migration that led to the filling of 470 Well-drained Namurian numerous reservoirs took place during the Triassic to Jurassic. A second, Late Cretaceous migration source rock Figure 13.16 Geochemical data from Lower Carboniferous and Namurian source rocks in the Cleveland Basin Poorly-drained Visean phase was less intense. Gases migrated only short distances, up to some ten kilometres at most. petroleum province: a. Pyrolytic yield (S2) versus TOC; b. T versus Hydrogen Index (HI); c. T versus source rock Undefined max max 480 Production Index (PI); d. Pr/n versus Ph/n; e. Sterane ternary diagram. Most samples are derived from open- c. marine source rocks. Inset shows pristane/phytane ratios. Plots produced using IGI’s p:IGI-3.

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Chapter 13 — Petroleum generation and migration

Age (Ma) WSW ENE K.P.-IG 1 400 350 300 250 200 150 100 50 0 Dargobadz-1 Zastan-2 Kamien Pomorski-7 Wrzosowo-1 Paleozoic Mesozoic Cenozoic Miedzyzdroje-5 Laska-1 Laska-2 Zastan-1 K.P.-6 Wrzosowo-2 Strzezewo-1 Sadlno-1 Trzebusz-1 Dzwibzyno-3

Devonian Carboniferous Permian Triassic Jurassic Cretaceous Tertiary 0 E M L E L E M L E M L E M L E L Paleogene Neogene

Source rock 1 Reservoir rock 2 Seal rock

Overburden rock 3 Depth (km) Trap formation Generat./migrat./accum. 4 Preservation 5 Figure 13.17 Event chart for the Early Carboniferous and Namurian petroleum system in the Cleveland Basin petroleum province. Upper Cretaceous 0 5 km Upper Triassic Ð Lower Cretaceous

14¡E 16¡E Triassic (Buntsandstein and Muschelkalk) Zechstein Upper Rotliegend (reservoir) Lower Rotliegend Upper Carboniferous Cross-section Lower Carboniferous and older in Figure 13.19 Zechstein Main Dolomite (source rock / reservoir) Koszalin Gas Gorzyslaw N Daszewo N Figure 13.19 Schematic cross-section of the Pomeranian Basin (Cenozoic and Quaternary section removed) Trzebusz Oil 0 200 km 54¡N (modified after Górecki et al., 2008). See Figure 13.18 for location. Krummin Gorzyslaw S Bialogard Wrzosowo Wierzchowo Miedzyzdrojedroje E Przyt—r Ciechnowo Production index Miedzyzdroje 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1000 400 Pomerania HI = 800 Tmax (¡C) TOC (%) 0.5 - 1 600 400 - 420 410 1 - 2 400 420 - 435 2 - 4 Szczecin 0 100 km 200 435 - 445 420 4 - 6 445 - 455 Permian subcrop Gas 6 - 8 100 100 430 Stephanian Asturian Type I kerogen 8 - 12

Bolsovian (¡C) 440 Type II kerogen max

Duckmantian T Carboniferous Langsettian Rock-Eval S2 (kg/t) Type III kerogen 450 Namurian Namurian/Westphalian 10 460 Tournaisian/Visean Devonian Pre-Devonian 470 Well-drained 0 200 km source rock Igneous Poorly-drained source rock Figure 13.18 The Pomeranian petroleum province with locations of petroleum fields and accumulations charged by Early 480 0 1 10 100 Carboniferous and/or Namurian black shales (field locations are not shown on the German side of the petroleum province). TOC (%) a. c.

effective gas reservoirs along the margins of the Wolsztyn High. The reservoir quality deteriorates rapidly HI (mg/g TOC) with increasing burial depth towards the north, due to compaction and illite growth. Even the areas with 0 100 200 300 400 500 600 700 800 900 1000 400 S2 (kg/t) 7 Visean reduced reservoir quality are prospective for tight gas and stratigraphic traps. Zechstein reservoirs, Type III kerogen 2 - 5 Tournaisian including reefal limestones up to several tens of metres thick (Øav: <25% Kav: <40 mD) are found on the 410 Type II kerogen 5 - 10 Wolsztyn High and other local basement highs. They host a number of gasfields (e.g. Kościan, Bonikowo, 6 420 Type I kerogen 20 - 30 Paproć W and Wielichowo). South of the Wolsztyn High, Rotliegend aeolian and fluvial sandstones are 430 again the major reservoirs, although they are thinner than those to the north of the high (up to 550 m, 60 - 100 5 mostly less than 300 m; Ø: 3-23%, K: 0.1-100 mD). Producing reservoirs are also found in shallow-marine 440 barrier and platform Zechstein limestones (porosities 1-13%). Both the Zechstein carbonates and Rotliegend 450 4 sandstones are productive in some fields (e.g. Grabówka and Dobrzeń). (¡C) 460 max T The composition of natural gas in the Fore-Sudetic Monocline is diverse. North of the Wolsztyn High, it 470 Frequency 3

is mostly methane (70-90%) with admixtures of nitrogen (<25%), higher hydrocarbons (<2%), CO2 (<2%) 480 Figure 13.20 Geochemical data from and traces of helium. The gas quality decreases southwards and south-westwards, where fields contain 2 Lower Carboniferous source rocks from 490 16-80% of methane, 20-78% of nitrogen, similar CO2 and higher hydrocarbon contents, but with increased the Pomeranian petroleum province: helium concentrations (up to 0.6%). 500 a. Pyrolytic yield (S2) versus TOC; 1 510 b. Tmax versus Hydrogen Index (HI); For further information see Zdanowski & Żakowa (1995), Karnkowski, (1996, 1999b), Kotarba et al. (2002, c. Tmax versus Production Index (PI); 520 0 2004, 2005) and Grotek (2004). 0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.61.8 2.0 2.2 2.4 2.6 2.8 3.0 d. Pristane/phytane ratios. b. d. Pr/ph (a/b) Plots produced using IGI’s p:IGI-3.

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Chapter 13 — Petroleum generation and migration

Age (Ma) 1000 400 350 300 250 200 150 100 50 0 2.2.6 Lublin Basin HI = 800 Tmax (¡C) 600 455 - 470 Paleozoic Mesozoic Cenozoic The Lublin Basin is situated in the south-west of the East European Platform and is bound to the south-west 400 470 - 540 Devonian Carboniferous Permian Triassic Jurassic Cretaceous Tertiary by the Holy Cross Mountains and Małopolska Massif. To the north-west, it passes into the poorly known Not available 200 Source rock and deeply buried Mid-Polish Trough. Petroleum in the Lublin Basin is mostly natural gas with limited Reservoir rock amounts of oil. There are four fields in the basin, which are probably sourced from Carboniferous rocks, at 100 Seal rock 100 Stężyca, Świdnik (oil and gas), Wilga, and Minkowice (gas). The Carboniferous development of the Lublin Type I kerogen Overburden rock Basin is associated with a system of approximately north-west–south-east-trending longitudinal fault Type II kerogen Trap formation zones related to Variscan reactivation of the Teisseyre-Tornquist Zone (Figure 13.26). Generat./migrat./accum. Type III kerogen The Carboniferous (upper Visean) succession rests unconformably on older Paleozoic formations in large Rock-Eval S2 (kg/t) Preservation areas of the Lublin Basin (Figure 13.27). An alternating sequence of clastics and carbonates was deposited Figure 13.21 Event chart for the early Carboniferous and Namurian petroleum system in the Pomeranian petroleum during the Visean. In Namurian times, coal-bearing deposits were formed during cycles of shallow-shelf, 10 province. Timescale of Harland et al. (1989). deltaic and fluviolacustrine environments with low to moderate sand content. By late Westphalian times the Lublin Basin had undergone structural inversion in the thrust-fault stress regime and fluviolacustrine deposits with high sand content had accumulated. Post-Carboniferous development of the Lublin Basin was characterised by steady subsidence during the Permian to Early Cretaceous. Late Cretaceous and Early 0 1 10 100 Cenozoic inversion led to uplift of the basin. TOC (%) a.

14¡E 16¡E 18¡E Permian subcrop 900 TOC (%) Stephanian 0.5 - 1 Langsettian Type I kerogen 800 1 - 2 Namurian 2 - 3 Namurian/Westphalian 700 3 - 4 Tournaisian/Visean Devonian 600 Type II kerogen Pre-Devonian Poznan 500 Gas Paproc-29 « Namurian black shales present 400 52¡N HI (mg/g TOC) Cross-section WOLSZTYN HIGH Katarzynin 2 in Figure 13.23 300 Type III kerogen Brandenburg 200 FORE-SUDETIC MONOCLINE 100 Type III/IV kerogen 0 0 25 50 75 100 125 150 175 200 225 250 275 300 OI (mg/g TOC)

Figure 13.22 The Fore-Sudetic Monocline petroleum province b. HI (mg/g TOC) 51¡N with locations of fields and accumulations charged by Early 0 100 200 300 400 500 600 700 800 900 1000 Carboniferous and/or Namurian black shales (field locations 0 100 km 400 S2 (kg/t) 0 200 km not shown on the German side of the province). Type III kerogen 410 0.5 - 1 Type II kerogen 1 - 2 SW NE 420 Type I kerogen 2 - 3 Fore-Sudetic Monocline Mogilno-L—d«z Trough Radlin-22 430 3 - 4 Pogorzela-6 Pogorzela-6 Radlin-19 Bazzyn-1 l Wilkoniczki-1 l Jarocin-7 Radlin-5 Komorze-1 Wilczna-1 S upia-1 Bu akow-1 440

0 Upper 450 Cretaceous Lower (¡C) 460

1 max

Upper T Middle Jurassic 470 2 Lower 480 Upper 3 Middle Triassic 490 Lower 500 Zechstein (regional seal) 4 Rotliegend (reservoir) 510 Namurian Depth (km) Upper Carboniferous Visean 5 Lower (source rock) 520 Folded Carboniferous Ð Variscides (source rock) 6 Main Dolomite (source rock / reservoir) c. Zechstein Limestone (reservoir) Figure 13.24 Geochemical data from different Lower Carboniferous and Namurian formations in the Fore-Sudetic Monocline: 7 Gas a. Pyrolytic yield (S2) versus TOC. All samples are within the type III kerogen field III kerogen; b. The pseudo-Van Krevelen

plot shows that samples are aligned along the type III/IV kerogen (humic and/or recycled) trend line; c. Tmax versus 0 20 km 8 Hydrogen Index (HI). The elevated maturity of the measured samples resulted in the depletion of generative potential. Figure 13.23 Schematic cross-section of the Fore-Sudetic Monocline (Cenozoic and Quaternary section removed) (modified after Górecki, 2006a). See Figure 13.22 for location. Plots produced using IGI’s p:IGI-3.

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Chapter 13 — Petroleum generation and migration

Age (Ma) Source rocks occur across the entire Lublin Basin except at the margins and a central north-west– 1000 350 300 250 200 150 100 50 0 HI = 800 Tmax (¡C) south-east-trending axis where Namurian sediments were partly eroded. As seen in Pomerania and the Paleozoic Mesozoic Cenozoic 600 400 - 420 Fore-Sudetic Monocline, the source rocks in the Lublin Basin are typically thick Visean to Westphalian Carboniferous Permian Triassic Jurassic Cretaceous Paleogene Neogene 400 siliciclastics with dispersed organic matter. Coal seams occur in the Namurian and lower Westphalian 420 - 435 Rock units succession. 200 435 - 445 Source rock 445 - 455 Reservoir rock Visean shales have an average TOC content of 1.8%; the organic matter is mixed type II/III (Figure 13.28a). 100 100 Seal rock In addition to the predominantly low-TOC shales, there are local thin coal layers (<0.4 m thick) mainly in Type I kerogen Overburden rock the eastern Lublin Basin. Increased pyrolytic yield (S2) values are attributed to higher contents of liptinite Type II kerogen Trap formation group macerals in some samples. In contrast to the marine or transitional (subordinately terrestrial) origin of the Visean organic matter, the Namurian and Westphalian organics are mainly terrestrial. Namurian Rock-Eval S2 (kg/t) Type III kerogen Generat./migrat./accum. siliciclastics have similar average TOC contents (2%) and maximum values (15.5%). Westphalian siliciclastics Preservation have an average TOC content of 1.5%. In addition to the dispersed organic matter, there are up to 100 10 208 Ma Critical moment intercalated coal seams, eight of which are up to 3.5 m thick. Coal seams comprise up to 8% of the lower Figure 13.25 Event chart for the Early Carboniferous and Namurian petroleum system in the Fore-Sudetic Monocline Westphalian section and up to 3% of the Namurian section. In general, the Namurian and Westphalian petroleum province. Timescale of Harland et al. (1989). coals in the Lublin Basin are marginally mature (0.71-0.81% Ro) with minor quantities of methane. The T (415-445°C) and Ro (0.4-1.2%) values of the organic matter from the entire top-Westphalian to max 0 1 10 100 base-upper Visean section are surprisingly uniform (Figure 13.28b & c). TOC (%)

22¡E a. Permian subcrop HI (mg/g TOC) Asturian 0 100 200 300 400 500 600 700 800 900 1000 400 Bolsovian S2 (kg/t) Type III kerogen 52¡N Duckmantian 410 2 - 5 Type II kerogen Langsettian 5 - 15 Carboniferous Westphalian 420 Type I kerogen 15 - 30 Namurian 430 30 - 60 Namurian/Westphalian Tournaisian/Visean 440 60 - 120 Devonian 450 Pre-Devonian 120 - 240

(¡C) 460 max Wilga Gas T 470 Oil Oil and gas 480 Namurian black shales present Cross-section Major faults 490 in Figure 13.27 500 Stezyca 510

520

LUBLIN BASIN b. Swidnik Production index) 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 Minkowice 400 TOC (%) 1 - 3 51¡N 0 200 km 410 3 - 6 6 - 10

420 10 - 20

20 - 40 430

0 50 km Figure 13.26 The Lublin Basin petroleum province with locations of fields and 40 - 80

accumulations charged by Early Carboniferous and/or Namurian black shales. (¡C) 440 max T

SW Stezyca Anticline Zelech—w-Kock Anticline NE 450 Stezyca-1 Zelech—w-1 Stanin-1

Cenozoic 460 0 Upper Cretaceous Lower 470 Well-drained Westphalian 1 Upper source rock Jurassic Poorly-drained Namurian Middle source rock Visean 2 Upper Triassic 480 Permian 3 Upper Carboniferous (source rock / c. reservoir / seal) Figure 13.28 Geochemical data of samples from different lower Carboniferous and Namurian formations of the Lublin Basin: Depth (km) Lower Carboniferous (source rock) 4 Upper a. Pyrolytic yield (S2) versus TOC. In addition to many mature and non-source rock samples and a few immature coal samples Devonian Middle with type III kerogen there are a number of atypical samples with hydrogen-rich kerogen; b. Tmax versus Hyrdogen Index (HI). 5 Silurian Figure 13.27 Schematic cross-section Samples are mostly marginally mature to mature and comprise some unusual samples with type I kerogen; c. Tmax versus Ordovician 0 5 km of the Lublin Basin (modified after Production Index (PI). Maturity-induced depletion has led to well-drained source-rock conditions. Plots produced using 6 Oil and gas Górecki, 2006a). IGI’s p:IGI-3.

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Chapter 13 — Petroleum generation and migration

The timing of petroleum generation and migration in the Lublin Basin, as well as reservoir and seal deposits. The Stężyca oilfield is the most important in the region and comprises six reservoirs that range to magmatic intrusions. In the southern North Sea and the Netherlands, the Coal Measures are mostly in the stratigraphy, differs significantly from the Pomeranian and Fore-Sudetic Monocline petroleum province in age from lower Namurian A to Westphalian B (Chapter 6). gas window, although in parts of the Cleaver Bank High area the Coal Measures are still in the oil window. (Figure 13.29). Generation started during the Westphalian in most of the area (transformation ratio The slightly higher coal maturity in the Broad Fourteens Basin than on the Cleaver Bank High is due to the mainly ~25%, reaching up to 60%) and had ended by the time of the Asturian inversion (300 Ma). In the For further information see Botor et al. (2002), Kotarba et al. (2002), Karnkowski (2003a) and Grotek (2004). deeper burial of the former (Figure 13.31f). Farther east in the North German Basin, Westphalian organic north-western Lublin Basin, petroleum generation continued until the end of the Cretaceous (65 Ma), matter is mostly in the gas window or overmature. The anomalously high coalification of gas-prone with transformation ratios never exceeding 11% at the base of the Lower Carboniferous. Many of the 2.3 Westphalian Westphalian source rocks in the Ems Low is a matter of ongoing research. Until a few years ago the localised source rocks still have generating potential, and petroleum migration from the latest Westphalian coalification maxima were attributed to magmatic intrusion of the Bramsche and Apeldorn offshoots to the throughout the Mesozoic was probably minor (Figure 13.29). 2.3.1 Anglo-Dutch and North German basins south-east. More recent studies suggest very pronounced deep burial of the sedimentary sequence prior to Late Cretaceous inversion. Hydrocarbon accumulations are found within a north-west–south-east-trending zone of anticlinal The largest Carboniferous petroleum (mainly gas) system in the SPB is sourced from Westphalian Coal structures along the basin axis. Structural, fault-related traps formed mainly during the Asturian Measures in an area extending from the UK offshore sector to western Germany (Figure 13.30). Despite Generation from Westphalian coals was widespread until Mid-Jurassic times (Figure 13.32), following (latest Carboniferous to Early Permian; ~300 Ma), but trap formation resumed in Mesozoic times as seen the widespread distribution of the Coal Measures, their depositional environment and related source-rock which there is a distinction between the Cimmerian rift basins and the platforms and highs (see Chapter 3, in Pomerania. The main reservoirs are Namurian fluvial sandstones (Ø: 1-22%, K: 1-400 mD), which are properties are very similar throughout the area. However, there are considerable variations in other Figure 3.19 for the locations of Jurassic rift basins in the SPB). During Late Jurassic to Early Cretaceous sealed by interdistributary fine-grained sediments, prodelta shales and marine bands. The Carboniferous aspects of their petroleum geology such as their generation, migration and accumulation. There are also rifting, hydrocarbon generation accelerated within the rift basins as a result of increased subsidence and rocks in the north-western Lublin Basin are covered by mainly carbonate and anhydrite Zechstein considerable contributions to parts of the discoveries and fields of the region from Lower Carboniferous increased basal heat flow. As a consequence, the kerogen in these graben areas was almost completely and Namurian source rocks. transformed. In the Lower Saxony and Broad Fourteens basins for instance, gas generation was most intense from Jurassic to Late Cretaceous times and left no generation potential. Because the Zechstein Wilczanka-1 Ð Northern Lublin Basin Age (Ma) The region was cross-cut by numerous Mesozoic faults, associated horsts, grabens and platforms, which seal is missing in the latter, most gas generated prior to the main phase of trap formation (Late Cretaceous 400 350 300 250 200 150 100 50 0 resulted in differences in burial depth and timing of the generation of the Coal Measures, along with a and younger) was lost. 0 Cenozoic 10 20 wide range of post-Carboniferous reservoir rocks and seals. More than 700 reservoirs were filled with gas 30 0.5 40 Cretaceous sourced mainly or exclusively from the Coal Measures. In contrast, Jurassic uplift of the platforms and highs led to interruption of hydrocarbon generation in 50 60 Albian these areas. In places where subsequent burial caused temperatures at the Westphalian source-rock levels 1 70 Oxfordian- Although the oldest coal seams are found in Lower Carboniferous rocks (Yoredale Formation; Section 2.2.1), to exceed the maximum temperatures reached earlier, gas generation resumed and eventually filled traps Kimmeridgian 80 the most important coal-bearing deposits, the Westphalian Coal Measures, are Langsettian to Bolsovian. that formed after the uplift and inversion events. 90 1.5 The deposits are up to 3000 m thick. The coals can form up to 6% of the section after compaction. The

Depth (km) Westphalian thickness of individual coal seams rarely exceeds a few metres and is mostly less than a metre. In most Generation from Westphalian coals resumed during enhanced Neogene subsidence on the Pompeckj Block, 2 areas, the coals have a cumulative thickness of several tens of metres. The swamps in which these peat where generation was most intense during Triassic to Jurassic burial. Generation in the Jurassic graben layers developed were part of an extensive lower-delta plain that covered large areas of the NWECB. areas halted during the Late Cretaceous due to inversion-related uplift and declining heat flow. At the 100 2.5 Namurian basin margins, where inversion had been limited and was followed by strong Cenozoic subsidence such The Coal Measures (Chapter 6, Figure 6.17) are found in large areas of the SPB, although their as at the south-west margin of the West Netherlands Basin, charge from the Westphalian resumed during 3 present-day distribution is affected by erosion. In particular, the northern and southern margins have the Cenozoic and continued to the present day. Bychawa IG-1 Ð Southern Lublin Basin been uplifted and the coal-bearing succession has been removed. Elsewhere, tectonic inversion, especially Age (Ma) 400 350 300 250 200 150 100 50 0 during the late Carboniferous, has resulted in partial or locally complete removal of the Coal Measures. Widespread charge of Rotliegend reservoirs took place until Jurassic times (Figure 13.32). Gas was lost Quaternary 0 20 from some accumulations due to Late Jurassic and Late Cretaceous tectonic breaching of the existing 30 40 Rock-Eval pyrolysis results from both coals and samples with no coals indicate the predominance of kerogens traps. Renewed generation and migration during the Neogene resulted in some of these reservoirs being 0.5 50 Upper Cretaceous 60 that straddle the boundary between oil-prone type II and gas-prone type III over a large range of TOC refilled. Consequently, the gas generated from deeper sources was largely replaced by gas derived from 70 contents (Figure 13.31a). Oil staining is found above some of the shale layers overlying the coal seams, Westphalian sources with concurrent changes in gas composition. This type of evolution is envisaged for 1 80 60 90 Oxfordian- especially in the bands formed during marine incursions, which indicates their oil-generation potential. the Lauwerszee Trough to the west of the Groningen field, where low nitrogen contents are attributed to 100 Kimmeridgian Namurian A a more recent charge from Westphalian coals. Falling temperatures and hydrostatic pressures of the uplifted 1.5 110 70 Depth (km) 120 Upper Visean Within a wide maturity range, large parts of the Westphalian Coal Measures in the North Sea and adjacent Coal Measures due to late Cretaceous inversion may have brought about additional gas desorption from 130 80 2 140 onshore areas are in the oil and gas window (Figure 13.31b & f). Local coalification anomalies are related these gas-prone source rocks and so adding to the pool of free gas. 150 2¡E 4¡E 6¡E 8¡E 10¡E 12¡E 2.5 Vitrinite reflectance (% Ro) Isotherm (¡C) Present-day distribution of Carboniferous sediments 0.5 - 0.7 0.7 - 1.0 Position of stratal boundary through time Present-day distribution of Westphalian source rocks Flensburg Gas a. Oil and gas Age (Ma) 400 350 300 250 200 150 100 50 0 Paleozoic Mesozoic Cenozoic Kiel

Devonian Carboniferous Permian Triassic Jurassic Cretaceous Tertiary 54¡N Source rock

Reservoir rock Hamburg Seal rock Groningen Overburden rock Bremen Trap formation Gen./migr./accum. Preservation Amsterdam Ipswich Hannover b. Figure 13.29 a. Burial and thermal history of wells Wilczanka-1 and Bychawa IG-1, which are typical for the northern Rotterdam Magdeburg 52¡N and southern parts of the Lublin Basin respectively (modified after Botor et al. 2002). Timescale of Harland et al. (1989). The main phase of hydrocarbon generation when upper Visean and Namurian source rocks reached the oil window over Figure 13.30 The Anglo-Dutch much of the basin was during the Late Carboniferous and ended with Asturian inversion (~304 Ma). Only in the NW Lublin and North German basins petroleum Dortmund Bruges Basin did hydrocarbon generation continue until the end of the Cretaceous (~65 Ma). Maturities and transformation ratios province with locations of fields Dunkirk Antwerp Gent of organic matter in Westphalian rocks are low. Most coals did not generate significant amounts of hydrocarbons; and accumulations charged by the 0 100 km b. Event chart for the early Carboniferous and Namurian petroleum system in the Lublin Basin petroleum province. Westphalian Coal Measures. Brussels 0 200 km

Petroleum Geological Atlas of the Southern Permian Basin Area 237 SPBA-Compleet 22-04-10 13:53 Pagina 238

Chapter 13 — Petroleum generation and migration

1000 Age (Ma) HI = 800 Tmax (¡C) CPI 10 Terrestrial organic matter Biodegraded/immature 400 350 300 250 200 150 100 50 0 0.9 - 1.1 600 400 - 420 Mixed sources Paleozoic Mesozoic Cenozoic 400 Marine organic matter 1.1 - 1.3 420 - 435 Devonian Carboniferous Permian Triassic Jurassic Cretaceous Tertiary 1.3 - 1.5 200 435 - 445 E M L E L E M L E M L E M L E L Paleogene Neogene

445 - 455 Oxidising 1.5 - 2.0 Source rock 100 100 455 - 470 1 Early mature Reservoir rock 470 - 540 Undetermined

Type I kerogen 17 Seal rock

Type II kerogen Pr/nC Overburden rock

Rock-Eval S2 (kg/t) Trap formation Type III kerogen 0.1 Reducing Generation/migrat./accum. 10 Figure 13.32 Event chart for the Westphalian petroleum system in the Anglo-Dutch and North German basins petroleum Mature province.

Hydrocarbons generated from the Coal Measures accumulated in reservoirs at almost all stratigraphic 0.01 0 1 10 100 0.01 0.1 1 10 100 levels. The major control appears to be the presence or absence of sealing units in the overburden. TOC (%) Ph/nC18 Traps in combination with Carboniferous reservoirs are mostly dip-fault closures at the Base Permian a. d. Unconformity. Stratigraphic traps also occur in places such as the Weissenmoor field in Germany. Where HI (mg/g TOC) there are Rotliegend sandstones, the Carboniferous sandstones only contain gas where the height of the 0 100 200 300 400 500 600 700 800 900 1000 400 100 0 trap exceeds the thickness of the Rotliegend, for example, in the Groningen field. In the area from S2 (kg/t) Plankton and algae 10 Type III kerogen 5 - 15 (variable sources) 9 Groningen southwards to offshore blocks K and L, gas in Rotliegend reservoirs is mostly trapped in simple 410 90 10 Type II kerogen 15 - 30 Open marine 8 horst blocks. Zechstein traps are predominantly fault-dip closures, with some 4-way dip closures. In the 420 Shallow-marine 7 Type I kerogen 30 - 60 80 20 Jurassic basins of the southern Netherlands, the typical trapping style in the Triassic play comprises or coastal 6 430 Deltaic-terrigenous Late Jurassic horst blocks, whereas in the offshore sector most traps are turtle-back anticlines, salt-wall 60 - 100 5 Tertiary coals 70 30 Frequency bounded or fault-dip closures related to halokinesis of the Zechstein salt. 440 4 100 - 200 Uncommon C 3 60 40 29 450 steranes (%) 2 The seals in the Silverpit / Cleaver Bank High area are formed by claystones and evaporites of the Silverpit 200 - 300 (¡C) 50 50 1 Formation and locally by intra-Westphalian shales and tight faults. Zechstein evaporites form the most 460 steranes (%)

max 28 0 T C 012345678 important seal in the eastern Netherlands and neighbouring Germany. 470 40 60 Pr/Ph (a/b) Pr/Ph 480 30 70 1.2 - 1.6 The majority of fields in the Anglo-Dutch Basin (78%) have reserves in Rotliegend sandstones. Most of 490 1.6 - 2.0 the fields are located in the basin axial areas where thick Zechstein evaporites were deposited and which 20 80 2.0 - 3.0 form the major seal. A minority are located on the basin margin with slope and lagoonal/platform Zechstein 500 facies. Evaporites in these marginal deposits appear to form a proper seal to the Rotliegend reservoirs. 10 90 3.0 - 5.0 510 There are no Rotliegend fields in the so-called ‘Fringe’ Zechstein where there is a lack of evaporites that 0 100 520 5.0 - 8.0 could form a seal. The presence of Rotliegend reservoirs is also facies dependent and therefore they do 100 90 80 70 60 50 40 30 20 10 0 not occur in the shaly deposits of the Silverpit Formation. C27 steranes (%) b. e. Where the Zechstein salt is present, it provides an effective seal for Carboniferous and especially Rotliegend Production index Vitrinite reflectance (% Ro) 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 0.0 0.8 1.62.4 3.2 4.0 reservoirs. Carboniferous reservoirs are found in the Silverpit / Cleaver Bank area, in the north-eastern 400 240 0 TOC (%) Mature Post mature part of the Netherlands and in western Germany. Gas-bearing Westphalian sandstones often show fair to 0.5 - 1 good poro-perm properties in the UK and the Netherlands (Ø average: 9%, Ø max: 20%; K average: 1-2 mD, 410 1 - 2 locally >100 mD). However in the Ems Low, the reservoir properties of Carboniferous sandstones are

200 Immature 1 2 - 5 generally poor and although gas-bearing they rarely warrant commercial production due to their low 5 - 10 420 porosity and permeability. 10 - 20 160 2 430 20 - 40 Most of the gasfields that produce from Zechstein platform-carbonate reservoirs are found along the 40 - 70 southern margin of the SPB. A small number of Zechstein fields are connected to Rotliegend reservoirs,

(¡C) 440 120 3 forming a stack of multiple reservoirs (e.g. the Coevorden field; see Section 6.3.4 in Chapter 6). Sealing

max 70 - 100 T Frequency Depth (km) is provided by Zechstein salts and anhydrites. Fractured Stassfurt carbonates are the most important 450 Broad Fourteens and West Netherlands reservoirs in the Ems area as the Rotliegend deposits are much thinner and have suffered severe reservoir 80 4 basins deterioration due to illite growth. 460 Cleaver Bank High North-west European 40 5 Carboniferous Basin Triassic reservoirs occur in a variety of trap styles at locations where the Zechstein seal is absent or 470 Well-drained Anglo-Dutch Basin source rock breached. The distribution of Buntsandstein fields can be correlated with the underlying Rotliegend Poorly-drained gasfields or the productive Zechstein Stassfurt Carbonate. There is a direct relationship between the source rock Westphalian 480 0 6 migration barriers and migration pathways in the Zechstein. The Upper Triassic evaporitic shales generally 0.4 0.81.2 1.6 2.0 2.4 2.8 c. f.Vitrinite reflectance (% Ro) g. form the top seal of the reservoirs with sporadic sealing by Lower Cretaceous shales in places where the Triassic succession is truncated by the Base Cretaceous Unconformity. Side seals are provided by Figure 13.31 Geochemical data from Westphalian formations in the Anglo-Dutch and North German basins: a. Pyrolitic e. Sterane ternary diagram. The sterane composition indicates the expected strong terrestrial component in the coal juxtaposed Upper Triassic to Lower Jurassic shales in the horst structure. yield (S2) versus TOC. Coals with a Hydrogen Index (HI) of 200 or more would actually be oil-prone. However, maturity acts samples. However other samples reveal a distinct marine organic-matter influence. Inset shows pristane/phytane ratio, to depress the HI, as the pyrolytic yield is more rapidly depleted than organic richness (TOC), therefore lowering the HI; which covers a range that comprises both humic and sapropelic kerogen; Some of the Upper Jurassic and Lower Cretaceous hydrocarbon fields have a varying contribution (major

b. Tmax versus Hydrogen Index (HI); f. Vitrinite reflectance histogram. Differences in the maturity distribution of the Broad Fourteens and West Netherlands to minor) from Westphalian source rocks. The distribution of these fields is restricted to the Cimmerian c. Tmax versus Production Index (PI); basins are related to different burial depths. Inset shows vitrinite reflectance versus sub-bottom depth; rift basins. This contribution is also limited by an unfavourable timing of charge, with pre-inversion d. Pr/n versus Ph/n; g. Vitrinite reflectance versus sub-bottom depth. Plots produced using IGI’s p:IGI-3. generation from the Westphalian prior to the main phase of trap formation during the Late Cretaceous.

238 Petroleum Geological Atlas of the Southern Permian Basin Area SPBA-Compleet 22-04-10 13:53 Pagina 239

Chapter 13 — Petroleum generation and migration

14¡E 16¡E Minor accumulations of Westphalian-derived gas are found in the Chalk Group and the Cenozoic (e.g. the For further information see Gerling et al. (1996a, 1996b) and De Jager & Geluk (2007). Harlingen field in the northern Netherlands). 2.4.1 Pomerania For further information see Patijn (1964), Faber et al. (1979), Mathisen & Budny (1990), Schröder et al. (1991a), Lokhorst et al. (1998), Gerling et al. (1999a, 1999b), Hoffmann et al. (2005) and De Jager & Geluk On the north-eastern margin of the Zechstein Sea, Stassfurt Carbonate and Main Dolomite sediments were Koszalin (2007). laid down on Werra evaporites on a narrow, poorly differentiated north-west–south-east-trending platform. Most Zechstein petroleum discoveries and fields in Pomerania contain oil, although gasfields also occur 2.4 Zechstein 54¡N (Figures 13.33 & 13.34). Average reservoir porosities in the Zechstein carbonates / Main Dolomite members vary widely (0-10%; 6% on the Kamień Pomorski Platform) and average permeabilities rarely exceed 10 mD. The lower Zechstein is a peculiar petroleum system. In contrast to other systems, rock units of the same stratigraphic group, such as the carbonate and evaporite members of the Main Dolomite and Older Halite, Zechstein source rocks in Pomerania reached the early generation phase (>10% transformation ratio) as well as the Stassfurt Carbonate and Halite members (Chapter 8), constitute the petroleum source rocks, Pomerania during the Early Triassic in the axial part of the basin and the Late Triassic on the platform (Figure 13.35). the reservoir rocks and the regional top seals. Early generation started at burial depths greater than 2500 m. Subsidence of the source-rock interval into the oil window, equivalent to entering the expulsion window (25-65% transformation ratio), took The arid evaporative conditions that controlled deposition of the lower Zechstein succession limited Szczecin place from Mid-Triassic to Cretaceous times at more than 2700 m burial depth. Late generation, up to the both the accumulation of terrestrial organic matter and its riverine transport towards the Zechstein Sea. exhaustion of the source potential (65-90%), took place from the Early Triassic in the basin to the Late The deposition of humic kerogen was greatly reduced as a result. The contribution of humic type III Present-day facies distribution of the Stassfurt Carbonates and equivalents (Zechstein) Cretaceous on the slope and platform, when the petroleum potential of kerogen from the Main Dolomite kerogen is usually subordinate, both in the basinal mudstones and on the carbonate platforms. In Marine evaporites (restricted basin) source rocks became exhausted. Turbidites (slope) contrast, accumulation of lower plant, mostly algal, organic matter dominated the open-marine and Carbonates and local anhydrite (platform) lagoonal environments. Sapropelic kerogen consequently prevails in the depositional environments of Evaporites and clastics (sabkha and alluvial plain) The most favourable reservoir properties are found in carbonate grainstones and packstones deposited in the Main Dolomite Formation (Zechstein Carbonate), although during maturation it may have lost its Not present or massif/high high-energy barrier and slope environments. However, secondary cementation and recrystallisation render potential to generate oil locally. these properties highly variable, both laterally and vertically, even within individual discoveries, and may Gas lead to severe reservoir deterioration. For example, in the Kamień Pomorski oilfield, zero-porosity and Oil source rocks such as the basal Zechstein Kupferschiefer (Copper Shale) Member and the Stinkschiefer Oil 0 200 km zero-permeability zones within the reservoir considerably constrain the migration pathways. The directly Member of the lower Hauptdolomit / Main Dolomite Formation are widely distributed across the SPB Figure 13.33 The Pomeranian petroleum province with locations of fields and accumulations charged by Zechstein source overlying Basal Anhydrite (A2) and Older Salt (Na2) members, and other Zechstein evaporites, form (Figure 13.33). The dark-coloured Copper Shale Member is a metal-enriched basinal deposit characterised rocks. Note the striking coincidence of fields with the carbonate-platform facies belt in the eastern SPB. In the western efficient seals for the Main Dolomite reservoirs. by increased organic-carbon contents. During deposition of the basinal Stinkschiefer Member (fetid shale), part of the basin only a few, isolated fields occur within the area of basinal palaeoenvironments (i.e. Stadskanaal, the correlative Stinkkalk and Stinkdolomit members were deposited as isolated pods on the arid platforms Gieterveen, and E13-1). Pomeranian Zechstein-sourced crude oils have densities higher than 0.8 g/cm3 (lower than 45° API). The and slopes around the Zechstein Basin (Chapter 8). heaviest oils occur in slope accumulations (Wysoka Kamieńska) and the lightest oils are found in basinal Charges from algal source rocks were probably largest in the platform areas where conditions for growth deposits. Organic-sulphur content (0.18-1.32 wt.%) is positively correlated with oil density throughout The Zechstein carbonates were considered to be among the most prospective reservoirs for both oil and gas of the algae that create this type of kerogen were most favourable. Type I kerogen significantly improves the region. Oil composition is relatively homogeneous across the palaeogeographic zones of the province. in the Netherlands and Germany until the late 1950s. However, most Zechstein discoveries in the western the source-rock quality, but its contribution to the overall charge is difficult to assess due to its great Oils mostly consist of saturated hydrocarbons (> 57 wt.%), which have low saturated versus aromatic SPB are sourced from Carboniferous deposits and only a few have a Zechstein source (Figure 13.33). This loss of mass during generation. Petroleum generated from the algal source rocks had extremely short hydrocarbon concentrations (3.6-8.3) that suggest short migration distances. The composition of n-alkanes is partly related to the limited thickness (minor petroleum yields) of the Zechstein source rocks and to migration pathways because the lagoonal deposits are often fringed, underlain or overstepped by and isoprenoids (CPI, Pr/n-C17, Ph/n-C18 and Pr/Ph) indicates a marine origin. Such an environment is later flushing of many Zechstein-sourced accumulations by Westphalian gas. high-energy carbonate grainstone and packstone with excellent reservoir properties. marked by CPI values lower than 1, increased relative concentration of the C12 alkylbenzene, the presence of isoprenbenzene and isoprentoluene (C27 iso) and CPI of alkylcyclohexanes markedly higher than 1. Another reason for the patchy distribution of major Zechstein-sourced petroleum accumulations is that The downside of these peculiar carbonate-evaporite source rocks is their tendency to generate undesirable Pr/Ph ratios lower than unity in all oils indicates anoxic conditions during deposition of the organic matter. the widespread basinal sediments often have limited source-rock qualities. Organic-carbon contents and non-hydrocarbon gases, such as H2S, CO2, and N2. Furthermore, because lower Zechstein source rocks were Gammacerane, isorenieratane and acrylic isoprenoids in most platform oils, and their higher-than-unity generative potential within the Stinkschiefer Member are therefore generally low. Permeabilities are also formed only under regionally restricted environmental conditions, the structures were charged with homohopane index, point to their generation in a photic-zone anoxia and to deposition in a carbonate low and reservoir facies are scarce in the typical carbonate mudstones of the basinal palaeoenvironments. petroleum generated within limited areas at high rates along short migration pathways, and so volumes environment under reducing conditions. The lack of these latter compounds in the basin suggests There is usually sufficient type II kerogen for petroleum generation in sediments on the toe and on the tend to be low. suboxic deposition and attendant decomposition, leading to lower hydrocarbon accumulation in this middle slope, where there are also adequate reservoir facies. area. Particularly increased diasterane concentrations, the presence of secohopanes and the absence of Fields and economically interesting discoveries sourced from carbonate-evaporite facies are found gammacerane in crude oils from the basin, testify to their derivation from clayey deposits. Thermal maturity There are notable contributions from lower Zechstein source rocks in Rotliegend and Buntsandstein along the northern (Pomerania) and southern (Fore-Sudetic Monocline, Thüringian Basin) margins of of the crude oils corresponds to the trend of increasing organic-matter transformation towards the axial accumulations between the south-eastern North Sea and the Ems Low, where oil-prone Zechstein source the Zechstein Sea. Whereas production on the German side of these provinces (Vorpommern, Lusatia parts of the basin and ranges from the top to the middle oil window. rocks are often correlated with high condensate contents in Rotliegend gas. Residual oil in the Slochteren and Thüringian Basin) is relatively minor, oil accumulations charged from Zechstein source rocks are sandstone suggests an early oil charge from lower Zechstein source rocks. However, the composition of the mainstay of the Polish oil industry. Hydrogen sulphide in natural gas from the Kamień Pomorski, Rekowo and Brzozówka-1A fields was mostly condensates from Upper Carboniferous to Bunter reservoirs in the Ems Low differs significantly from that formed through microbial reduction, whereas thermochemical sulphate reduction accounts for about half of typical lower Zechstein oils. Apart from these few fields, and contributions to oil accumulations, most Regional maturity trends are controlled mainly by burial depth. As burial depth is in turn commonly of the H2S in the Błotno field. The predominance of the microbial component is evidence for early trapping of the economically interesting discoveries from Zechstein sources are concentrated in the eastern SPB. concordant with the zonal palaeoenvironmental and facies pattern of the Zechstein Sea, the maturity and efficient sealing by the Stassfurt evaporites. trends grossly follow the different facies belts. Organic matter deposited in the platform environments, The Zechstein petroleum system in the central and eastern SPB is distinguished by the following commonly buried to 1000 m depth, is therefore generally at an early mature stage (0.5-1% Rr). Maturity Further reading: Głogoczowski & Jędrychowska (1974), Głogoczowski et al. (1977), Kosakowski & Kotarba characteristics: gradually increases up to the late condensate and dry-gas phases (>1% Rr) in source rocks deposited in (2002), Kotarba et al. (2000a), Kotarba et al. (2003), Kosakowski et al. (2003), Kowalski (2006), Kotarba & the palaeoenvironmental diversity of its source rocks, including carbonate-evaporite facies; slope and basinal palaeoenvironments that were typically buried to depths greater than 1800 m; Wagner (2007). very short migration pathways from shallow-water algal laminites to the adjacent carbonate sandstones; overmaturity prevails in the deepest parts of the basin. complex post-trapping histories with widespread flushing of existing accumulations, mostly by 2.4.2 Fore-Sudetic Monocline and Brandenburg Westphalian-sourced gas. Crude oils attributed to Zechstein sources share a number of compositional properties (even-numbered n-alkane predominance, high triterpane and sterane content, low diasterane concentration, pristane/ In contrast to the north-eastern Pomeranian margin, the bathymetry of the south-western Zechstein Sea Although slope and basinal facies have been invoked as sources for a number of deposits, the most phytane ratio <1) which suggest a moderately mature carbonate source rock. Geochemical differences was highly variable (Figure 13.36). Platform lagoons were separated from the slope by carbonate sand characteristic source rocks in the central/eastern Zechstein petroleum provinces are the laminated in the oils and source rocks of Pomerania and the Fore-Sudetic Monocline and adjacent regions are bars and the platform margin was dissected by large-scale deep embayments and intervening salients. carbonate mudstones and boundstones that were laid down in low-energy evaporitic lagoons on the described in the regional sections below. The latter are referred to as ‘peninsulas’ or ‘off-platform highs’ with isolated carbonate platforms on top platform or on detached platforms (also called ‘off-platform high’ or ‘peninsula’). They locally contain (e.g. the Grotów ‘peninsula’; Figure 13.37). These bays, salients and off-platform highs produced a complex abundant (>20% TOC), hydrogen-rich type I kerogen and botryococcene, a remnant of botryococcus Natural gas is derived from either lower Zechstein or pre-Zechstein sources. Autochthonous gas mostly lateral facies pattern in the developing carbonate-dominated deposits of the Stassfurt Formation. algae that is commonly detected in these oil-prone source rocks. consists of microbial methane with minor thermocatalysed methane and higher hydrocarbon homologues. Deposition of the Stassfurt Carbonate is characterised by facies belts that are broadly parallel to the + Nitrogen is possibly derived from ammonium (NH4)-enriched formation water. Allochthonous gas is coal- margin. The facies consist of coastal sabkhas and neritic carbonate sand shoals on the platform margin derived methane and nitrogen from pre-Zechstein sources. and off-platform highs to thin-bedded carbonate mudstones on the slope and in the basin.

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Chapter 13 — Petroleum generation and migration

HI (mg/g TOC) Production index 0 100 200 300 400 500 600 700 800 900 1000 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1000 400 400 4 Tmax (¡C) S2 (kg/t) TOC (%) HI = 800 Type III kerogen 2 - 5 0.5 - 1 600 380 - 420 410 Type II kerogen 5 - 10 410 1 - 3 400 420 Type I kerogen 420 - 435 10 - 20 3 - 6 200 435 - 445 430 420 6 - 9 3 20 - 30 445 - 455 440 9 - 12 100 100 455 - 470 430 450 Type I kerogen 8 - 12 (¡C) (¡C) 440 2 Type II kerogen 460 max max T T 470 Frequency Rock-Eval S2 (kg/t) Type III kerogen 450 480 10 490 460 1

500 470 Well-drained source rock 510 Poorly-drained source rock 520 480 0 0 1 10 100 0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 TOC (%) Pr/ph (a/b) Late Permian

a. b. c. d. Figure 13.34 Geochemical data from lower Zechstein samples of the Pomeranian petroleum province: Sediment samples Oil samples a. Pyrolytic yield (S2) versus TOC. Most samples are immature and contain type II kerogen. The presence of some samples Late mature extract C17 Mid-mature oil C C Well: Sidlowo-1 Well: Daszewo R1K with type III kerogen is probably unrelated to input of higher plant remains, but likely reflects depletion due to thermal 17 18 C18 Rr = 1.15% Rr = 0.80% maturation; Phytane b. T versus Hydrogen Index (HI). The unusually low T values of the richest samples may indicate an organic-matter Ph max max C24 composition that is thermally more labile than standard type II kerogen; Pr C24 Intensity c. Tmax versus Production Index (PI). Unusually elevated PI values are likely related to the presence of migrated hydrocarbons; Intensity C30 Pr d. Pr/nC17 versus Ph/nC18; C e. Chromatograms of n-alkanes and isopreonoid distribution in Zechstein Main Dolomite carbonate sediment samples; 30 f. Chromatograms of n-alkanes and isopreonoid distribution in Zechstein Main Dolomite oil samples. Plots produced using IGI’s p:IGI-3. 1020 30 40 50 60 70 80 90 100 1020 30 40 50 60 70 80 90 100

C20 Mid-mature extract Phytane Early mature oil Well: Wysoka C17 Well: Wysoka Kamienska-1 Kamienska-2 C18 Rr = 0.60% C18 C20 Slightly restricted conditions developed in the lagoons along the Thüringian margin; however, more Rr = 0.80% C24

pronounced restriction influenced the environments on the Fore-Sudetic Slope, including its Lusatian Pr C24 segment (Brandenburg Slope). The Brandenburg Slope developed much like the Fore-Sudetic Monocline Intensity Intensity C Ph with concentric facies belts around the Zechstein Basin. In contrast to the open slopes of the Fore 17 C30 Sudetic Monocline and Lower Lusatia, Stassfurt deposits of the Thüringian Basin were deposited in an C30 Pr originally north-north-east-trending extension of the central European Zechstein Sea. Before it was flooded by the Zechstein Sea, the Thüringian Basin was part of the Saar-Saale Trough that accumulated up to several hundred metres of Westphalian and Rotliegend siliciclastics in an intramontane setting. 1020 30 40 50 60 70 80 90 100 1020 30 40 50 60 70 80 90 100 Early mature extract C Phytane Early mature oil 17 C C20 Well: Petrykozy-7K 18 C Well: Wapnica-1 Opinions are divided regarding the major source-rock facies of the area. The platform carbonates appear R = 0.66% 20 R = 0.50% C r r 18 Pr to be the source in the Fore-Sudetic Monocline, whereas the main charge on the Brandenburg Slope stems Ph C24 C24

from source rocks deposited on the slope and in the basin. C17

C30 Intensity Intensity Pr The Grotów salient (Figure 13.37) is an excellent example of variability in lithofacies, palaeogeography, C30 petrophysics and structure of the most prospective zone of the Fore-Sudetic Monocline petroleum province. The potential source and reservoir facies were deposited close to each other within the basinal, slope and platform environments. Carbonates deposited on the platform, and within oolite barriers, commonly consist 1020 30 40 50 60 70 80 90 100 1020 30 40 50 60 70 80 90 100 of grainstones and packstones with porosities up to 26%. However, deposits with average permeabilities Retention time (minutes) Retention time (minutes) greater than 10 mD are only found in limited areas (e.g. the Barnówko-Mostno-Buszewo oilfield and the e. f. Lubiatów-Międzychód-Grotów oil and gasfield.) Pr/Ph, Pr/n-C17 and Ph/n-C18 indicators. The indicators are evidence of algal-source matter (CPI values and considerable H2S (Mostno, Zielin fields, Stanowice-2 well). There may be a substantial admixture of gas As seen in Pomerania, petroleum generation in the Fore-Sudetic Monocline basinal deposits started during Pr/Ph less than 1), principally in the middle and final phases of low-temperature thermocatalytic processes from highly mature type III kerogen from probable Carboniferous source rocks in wells Chlebowo-10, earliest Triassic times, with burial depth greater than 1700 m (Figure 13.38). The Main Dolomite source (the oil window). They are also evidence for the absence of secondary processes of biodegradation. These Suęcin-21, Kościan-9, Kościan-11, and Wierzchowice-20. rocks entered the oil window in the Late Triassic (basinal deposits) with burial to approximately 2000 m, oils are characterised by densities of 0.736 to 0.896 g/cm3 and sulphur contents ranging from 0.08 to and in the Early Jurassic (platform deposits) with burial to about 1800 to 2200 m. After the Early Jurassic, 1.67 wt.%. The sulphur contents increase with increasing densities. Analysis of relative concentrations In addition to the Zechstein hydrocarbons, nitrogen probably entered several reservoirs on the Brandenburg generation spread across the entire carbonate platform of the Fore-Sudetic – Silesian region. Generation of aromatic sulphur compounds (methyl-dibenzotiophenes) allows the estimation of the thermal Slope and in the Thüringian Basin after the reservoirs became hydrocarbon-charged. The nitrogen is derived ended during the Late Triassic (basin) and in the Middle Jurassic (platform). The source rocks on the maturity. In the north, vitrinite reflectance ranges from 0.6 to 1.25% and increases from the west to from deeply buried Paleozoic sediments. High CO2 contents in the gasfields of Thüringia correlate with Brandenburg Slope entered the oil window during the Jurassic and reached peak generation (0.8-1.2% the east. In the south, values range from 0.6 to 0.98%. The ratio of saturated to aromatic hydrocarbons Cenozoic basaltic volcanism. The H2S can be explained by either bacterial or thermochemical sulphate vitrinite reflectance equivalent) prior to the Late Cretaceous inversion. in these zones is less than 25, which confirms the short migration routes from the source rocks. reduction. The methane content in the larger deposits (Behringen, Mühlhausen) is about 50%.

Crude oils that accumulated in the Main Dolomite rocks of the Fore-Sudetic Monocline were generated Natural-gas composition in the Fore-Sudetic Monocline is more variable than in Pomerania. It usually For further information see Głogoczowski & Jędrychowska (1974), Głogoczowski et al. (1977), Botz et al. from type II kerogen, as indicated by the distribution of n-alkanes and isoprenoids, and values of the contains negligible microbial components, but thermochemical sulphate reduction has produced (1981), Gerling et al. (1996a,1996b), Wehner (1997), Behla et al. (1998), Karnin et al. (1998), Merkel et al.

240 Petroleum Geological Atlas of the Southern Permian Basin Area SPBA-Compleet 22-04-10 13:53 Pagina 241

Chapter 13 — Petroleum generation and migration

14¡E 16¡E 18¡E Jarkowo-2 Present-day facies distribution of the Stassfurt Carbonate and equivalents (Zechstein) Age (Ma) ! !

! 350 300 250 200 150 100 50 0 ! Marine evaporites (restricted basin) 0 Quaternary ! Turbidites (slope) Carbonates and local anhydrite (platform) 30 Jurassic 1 ! ! !! ! 0.5 ! Evaporites and clastics (sabkha and alluvial plain) ! ! ! ! ! ! !!! ! ! ! ! ! ! ! ! ! ! ! ! !! ! ! ! ! ! ! ! ! ! ! ! ! ! ! 40 ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! Not present or massif/high ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! Triassic 3 ! ! 1 ! ! 50 ! Gas ! ! ! ! ! ! ! ! ! Triassic 2 ! !! ! ! 60 ! ! Poznan! Oil ! ! 1.5 ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !!! 70 ! ! ! ! ! Triassic 1 !

! 2 ! ! 52¡N ! ! ! ! ! ! ! ! ! ! !!! ! 80 ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! 110 ! ! ! !! ! ! ! ! ! ! 2.5 ! ! ! ! ! !! ! ! ! !

Depth (km) Permian 2 !! ! ! ! ! ! ! !! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !! !! ! !! ! ! ! !!!! ! ! ! ! ! ! ! 90 ! !! ! ! ! !! !! ! 120 ! ! ! ! ! ! ! ! !! ! ! ! ! ! ! ! ! ! ! ! ! ! s.m. Ca2 ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! 130 ! ! ! ! ! ! ! Permian 2 ! Brandenburg ! ! ! ! ! ! ! ! !! ! ! 3 ! ! ! ! ! ! ! !! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !! ! ! ! ! ! ! ! ! ! ! ! ! ! !! ! ! ! ! ! !! ! !!! ! FORE-SUDETIC MONOCLINE ! !!!! ! ! ! ! ! ! Permian 1 ! ! ! ! ! ! ! 100 ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! 3.5 ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !! ! ! ! ! ! ! ! ! ! ! ! ! !! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !!! !! !! ! ! ! !! !! ! !!!! ! ! ! ! ! ! ! !!!! ! ! !!! ! ! ! ! ! ! ! ! ! ! ! ! ! !!!!! ! ! ! ! ! ! 4 ! !

! !!! ! ! ! ! ! ! ! ! ! !

!

4.5 ! ! Vitrinite reflectance (% Ro) Isotherm (¡C) 51¡N Figure 13.36 The Fore-Sudetic and Brandenburg petroleum 0.5 - 0.7 0.7 - 1.0 Position of stratal boundary through time 0 100 km province with locations of fields and accumulations charged a. 0 200 km by Zechstein source rocks. Age (Ma) Isotherm (¡C) 350 300 250 200 150 100 50 0 NE SW Paleozoic Mesozoic Cenozoic Grotow-6 Grotow-2 Miedzychod-5 Miedzychod-4 Lubiatow-1 5835000 Grotow-1 Lubiatow-4 Lubiatow-2 3564000 2900 Carboniferous Permian Triassic Jurassic Cretaceous Tertiary 5840000 3560000 3556000 Source rock 5845000 Ð2800 3000 Reservoir rock 5850000 Ð3000 Seal rock 5855000 3100 Overburden rock Ð3200 Ð2800 3200 Trap formation Ð3400 Depth (km)

Gen./migr./accum. Ð3000 Ð3600 3300 Preservation Ð3800 Ð3200 Critical moment Ð4000 3400 Grotow-6 Grotow-2 Miedzychod-5 Miedzychod-4 Lubiatow-1 Ð3400 5836000 Grotow-1 Lubiatow-4 Lubiatow-2 b. 2900 Porosity total Ð3600 5840000 Figure 13.35 a. Burial history and modelled vitrinite reflectance history for well Jarkowo-2. Timescale of Harland et al. 0.3 3000 0.25 Ð3800 0.2 (1989); b. Event chart for the Zechstein / Main Dolomite petroleum system in the Pomeranian petroleum province. 5844000 0.15 0.1 Ð4000 3100 0.05 (1998), Piske & Rasch (1998), Piske et al. (1998), Rasch et al. (1998), Schwark et al. (1998), Strohmenger 3566000 5848000 3200

et al. (1998), Kotarba et al. (2000a), Kosakowski & Kotarba (2002), Kosakowski et al. (2003), Kotarba et al. Depth (km) 3564000 Mudstone (2003), Kowalski (2006) and Kotarba & Wagner (2007). 3562000 Grainstone 3300 3560000 5852000 Boundstone

2.5 Jurassic 3558000 Oil-water contact Oil contour 3400 3556000 Grotow-6 Grotow-2 Miedzychod-5 Miedzychod-4 Lubiatow-1 Gas contour Major source rocks were formed during various episodes in Jurassic times, notably in the lowermost Jurassic Grotow-1 Lubiatow-4 Lubiatow-2 3554000 2900 (Pliensbachian to Sinemurian Lias Shales), the Lower Jurassic (Toarcian) Posidonia Shale Formation, the Sw 1 Middle to Upper Jurassic (Callovian-Oxfordian) Oxford Clay Formation, and the upper Kimmeridge Clay 0.9 3000 0.8 Formation (Chapter 10, Figure 10.13). In contrast to the central North Sea, where the Kimmeridge Clay 0.7 0.6 is the main source rock, the Posidonia Shale is the most important source rock for oil in large areas of the 0.5 3100 0.4 0.3 SPB. Its bituminous character results from pelagic deposition under anoxic conditions. The composition 0.2 0.1 of oil generated from the Posidonia Shale is similar to that from the minor bituminous intercalations that 3200 Depth (km) occur locally in the Lower Jurassic to Upper Cretaceous section. It is therefore difficult to distinguish and Figure 13.37 Fence diagram of the Zechstein Main Dolomite in the western part of the Grotów ‘peninsula’ quantify the individual source-rock contributions in an oilfield with multiple sources. of the Fore-Sudetic Monocline in western Poland (left panel; view from the NW). The panels on the right show 3300 the microfacies, total effective porosity (matrix pore space and fractures), and water saturation of the pore The Posidonia Shale is a very distinctive interval throughout the western SPB area and shows up as an space. The best reservoir properties with permeabilities up to 40 mD occur within grainstones of the oolite 3400 0 2 km excellent reflector on seismic profiles. Its present-day distribution is restricted to the centres of rift basins barriers and grainstones on the toe-of-slope. that formed in the Late Jurassic (e.g. West Netherlands and Broad Fourteens basins, Dutch Central Graben, Lower Saxony Basin and Dogger Troughs). Given the uniform character and thickness (mostly around 30 m The wide distribution of the Posidonia Shale from the UK (Jet Rock Member) to Germany (Posidonienschiefer, 2.5.1 Weald Basin of dark-grey to brownish-black, bituminous, fissile claystones) across these basins, the Posidonia Shale or Ölschiefer) suggests deposition during a period of high sea level and restricted sea-floor circulation. was probably deposited over a greater area; its present-day distribution reflects erosion on the basin In eastern Germany (Mecklenburg and Brandenburg), the lower Toarcian is represented by greenish-grey The Weald Basin of southern England is the north-east extension of the larger Wessex Basin, which margins and bounding highs. mudstones with calcareous concretions in the lower part. Farther east and into Poland, source-rock quality formed on the eastern side of an extensive Triassic rift system. The Weald Basin itself forms an asymmetric deteriorates with the common intercalation of siltstones and fine-grained sandstones in the progressively east–west-trending structure (Figure 13.40). Triassic strata in the Wessex Basin are initially conglomerates organic-poor mudstones (Chapter 10, Figure 10.13). followed by sandstones (the Sherwood Sandstone Group) overlain by marls and clays of the Mercia Mudstone

Petroleum Geological Atlas of the Southern Permian Basin Area 241 SPBA-Compleet 22-04-10 13:53 Pagina 242

Chapter 13 — Petroleum generation and migration

HI (mg/g TOC) Kaleje-10 0 100 200 300 400 500 600 700 800 900 1000 1000 400 Age (Ma) Tmax (¡C) S2 (kg/t) Neogene HI = 800 Type III kerogen 350 300 250 200 150 100 50 0 2 - 5 0 Quaternary 600 400 - 420 410 20 Paleogene Type II kerogen 5 - 10 J 3 400 Jurassic 2 420 - 435 420 Type I kerogen 0.5 10 - 20 40 Jurassic 1 200 435 - 445 430 20 - 40 1 445 - 455 440 60 Triassic 3 100 100 455 - 470 450 1.5 Type I kerogen 470 - 540

80 Triassic 2 (¡C) Type II kerogen 460 max 2 T Depth (km) Triassic 1 470 Rock-Eval S2 (kg/t) 100 Type III kerogen 2.5 480 Permian 2 10 Source rock 490 3 Permian2 Permian 1 500 120 3.5 510

520 Migdzych—d-4 0 1 10 100 b. Age (Ma) TOC (%) Production index Late Permian 350 300 250 200 150 100 50 0 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 0 Neogene a. 400 30 Paleogene TOC (%) 40 1 - 2 0.5 50 Cretaceous 2 Figure 13.39 Geochemical data from lower Zechstein samples of the Fore-Sudetic Monocline petroleum province: 410 2 - 4 60 70 Jurassic 3 a. Pyrolitic yield (S2) versus TOC. Most immature source rocks contain type II kerogen. Another group of samples, most 4 - 8 1 Jurassic 2 80 of which are mature, contains type III kerogen. Note that the presence of type III kerogen is probably unrelated to input Jurassic 1 420 8 - 12 90 of higher plant remains, but likely reflects depletion due to thermal maturation; 1.5 100 Triassic 3 b. T versus Hydrogen Index (HI). 110 max 430 120 130 The unusually low Tmax values of the richest samples may indicate an organic matter composition that is thermally more 2 Triassic 2 Depth (km)

130 labile than standard type II kerogen; (¡C) 440 130 max

140 c. T versus Production Index (PI). Unusually elevated PI values likely related T 2.5 Triassic 1 max 150 140 to the presence of migrated hydrocarbons; 450

3 Permian 2 d. Chromatograms of n-alkanes and isopreonoid distribution in Zechstein Main Dolomite carbonate sediment samples; Source rock 160 Permian 2 e. Chromatograms of n-alkanes and isopreonoid distribution in Zechstein Main Dolomite oil samples. 460 3.5 Plots produced using IGI’s p:IGI-3. Vitrinite reflectance (% Ro) Isotherm (¡C) 470 Well-drained source rock 0.5 - 0.7 1.0 - 1.3 Position of stratal boundary through time Poorly-drained 0.7 - 1.0 1.3 - 2.6 source rock c. 480 a. Sediment samples Oil samples Age (Ma) Late mature oil Late mature oil C18 350 300 250 200 150 100 50 0 C17 Well: R—zansko-1 Well: R—zansko-4 Rr = 1.20% Rr = 1.50% Paleozoic Mesozoic Cenozoic C24 Carboniferous Permian Triassic Jurassic Cretaceous Tertiary

E L E M L E M L E M L E L Paleogene Neogene Intensity Intensity Phytane Source rock Ph C17 C C18 Reservoir rock Pr 30 Pr C20 Seal rock C24 C30 Overburden rock 0708010 20 30 40 50 60 90 0708010 20 30 40 50 60 90 ? Trap formation C24 Mid-mature oil Late mature oil Well: Kije-9 Well: Buszewo-5 Gen./migr./accum. Rr = 0.72% Rr = 1.20% Phytane

Preservation C17 C C C20 18 18 C Critical moment Pr 20 C17 C24 Intensity Intensity b. C30 Figure 13.38 a. Burial history and modelled vitrinite reflectance history for Kaleje-10 and Międzychód-4 wells. Timescale Ph C30 Pr of Harland et al. (1989); b. Event chart for the Zechstein / Main Dolomite petroleum system in the Fore-Sudetic Monocline petroleum province. 0708010 20 30 40 50 60 90 0708010 20 30 40 50 60 90 C20 Mid-mature oil Phytane Early mature oil C C17 Group, although their distribution is largely restricted to the west of the Weald Basin. Early Jurassic C18 24 Well: Lus—wko-1 C18 Well: G—rzyca-3 Rr = 0.73% Rr = 0.60% transgression resulted in a thick cyclic sequence of variably thick shales and carbonates controlled by Pr C20 continued extensional faulting. Tectonic activity continued into the Early Cretaceous with deposition of the Ph C30 nonmarine Wealden Series of shales, marls and sands. By mid-Cretaceous (Late Cimmerian Unconformity) C24 Intensity Intensity times, extension had ceased and thermal subsidence resulted in deposition of an initially clastic sequence C17 Pr

(the Greensand) overlain by a thick Upper Cretaceous Chalk Group sequence. Sedimentation finally ended C30 during the Miocene when inversion of the original extensional faults was associated with Alpine movements to the south. During this time, the whole Wealden area was uplifted to form the present-day ‘Wealden Anticlinorium’ (Figure 13.41). d. 0708010 20 30 40 50 60 90 e. 0708010 20 30 40 50 60 90 Retention time (minutes) Retention time (minutes)

242 Petroleum Geological Atlas of the Southern Permian Basin Area SPBA-Compleet 22-04-10 13:53 Pagina 243

Chapter 13 — Petroleum generation and migration

2¡W 0¡ Production index 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1000 400 HI = 800 Tmax (¡C) TOC (%) 0.5 - 1 600 360 - 400 London 410 1 - 3 LONDON PLATFORM 400 400 - 420 3 - 6 PEWSEY SUB-BASIN 6 - 10 200 420 - 435 420 Not 10 - 20 Cross-sectionection 100 100 available 430 in Figure 13.41 20 - 40 WEALD BASIN Type I kerogen

(¡C) 440 40 - 60 Portsmouth Type II kerogen max

51¡N T HAMPSHIRE-DIEPPE HIGH Rock-Eval S2 (kg/t) Type III kerogen 450 PORTLAND-WIGHT SUB-BASIN

WEALD-ARTOIS 10 460 BASIN 0 100 km DIEPPE HIGH 0 200 km 470 Well-drained source rock Present-day relics of Late Jurassic basin Poorly-drained source rock Present-day distribution of Liassic source rocks 480 Gas 0 1 10 100 a. TOC (%) c. Oil Major faults HI (mg/g TOC) 0 100 200 300 400 500 600 700 800 900 1000 Figure 13.40 The Weald Basin petroleum province with locations of fields and accumulations charged by Lower Jurassic 400 S2 (kg/t) CPI 10 Terrestrial organic matter Biodegraded/immature Type III kerogen 0.9 - 1.1 source rocks. 410 2 - 5 Mixed sources Type II kerogen 5 - 15 Marine organic matter 1.1 - 1.3 420 Type I kerogen N S 15 - 30 1.3 - 1.6 Shalford Godley Bridge Bolney Storrington- 430 Anticline Anticline Anticline Henfield 30 - 60 1.6 - 2.2 Gault Formation and Lower Greensand Group Projected base of Chalk Group Anticline Oxidising 440 60 - 100 North Downs South Downs 1 Early mature Undetermined 0 Chalk Group 450 17 Wealden and Purbeck groups 100 - 200 (¡C)

460 Pr/nC

1 Portland Group & max T 200 - 320 Kimmeridgian roup) lian G 470 Ordovician- Oxfordian (Coral 2 Silurian Devonian Lias Group Portsdown Fault 480 0.1 Reducing Lower Carboniferous 490 3 Hogs Back Fault Depth (km below sea level) Mature 500 Upper Fault 0 5 km Cretaceous Lower 510 Upper 0.01 Middle Jurassic 520 0.01 0.1 1 10 100 Ph/nC Lower b. d. 18 Triassic, locally with Permian 100 0 Paleozoic Differentiation of the relative contribution of Liassic-sourced and Oxford Clay-sourced oils to the known Plankton and algae 6 (variable sources) Figure 13.41 Cross-section of the Weald Basin. See Figure 13.40 for location. accumulations is problematic, as both source rocks supply oils with essentially identical geochemical 90 10 Open marine 5 characteristics. However, there is a subtle difference in the carbon-isotopic ratio of the two, which may Shallow marine There are three major source rocks in the Weald Basin; Liassic shales, the Oxford Clay and the Kimmeridge be of potential use. or coastal 80 20 4 Deltaic-terrigenous Clay. The upper Liassic rocks (including the Toarcian Posidonia Shale equivalent) may contain low levels 3

70 30 Frequency of generally poor-quality organic matter, but they are widely considered to be volumetrically insignificant. The Upper Jurassic Kimmeridge Clay is the richest source rock with typically more than 10% TOC contents Tertiary coals Uncommon C 2 29 Liassic source rocks are restricted to the Hettangian to Sinemurian section. These rocks have a distinct and type II oil-prone kerogen with a variable but low terrestrial type III kerogen component (Figure 13.42). 60 40 steranes (%) small-scale rhythmicity of organic-rich shales and intervening organic-poor limestones attributed to Organic richness in the Kimmeridge Clay has been attributed to freshwater capping associated with very 1 50 50 periodic influxes of clastic sediment associated with the development of slightly fresher water capping slow-moving currents flowing southwards in the North Sea. The Kimmeridge Clay is immature wherever steranes (%) 28 0 C 0 0.2 0.4 0.6 0.81.0 1.2 1.4 1.6 1.8 2.0 2.2 2.4 2.6 2.83.0 3.2 that restricted water overturn. Organic-carbon contents are typically in the order of a few percent, although it is encountered although basin-modelling studies suggest that the basal sections may be marginally 40 60 Pr/Ph (a/b) local values up to 7% have been reported; however, source-rock quality deteriorates eastwards. The organic mature in the basin axial region. matter is dominantly type II with low background levels of type III (Figure 13.42). The Lias shales are at 30 70 least marginally mature in almost all of the Weald Basin and reach well into peak-oil generation in the There are numerous clastic and carbonate reservoirs in the Weald Basin, almost exclusively within 20 80 Pr/Ph depocentre with vitrinite reflectance values up to 0.85%. Oil generation probably commenced during the the Jurassic succession, although there is an accumulation in Rhaetic beds at Humbly Grove. The most 1.2 - 1.6 Early Cretaceous and peaked around mid-Late Cretaceous times when the Lias in the basin centre may have important reservoir is the Bathonian Great Oolite, sealed by the Oxford Clay (Storrington-1 well, 10 90 just reached the gas window (Figure 13.43). Humbly Grove, Horndean, Goodworth, Singleton, Stockridge, Lidsey and Baxters Copse). There are minor 1.6 - 2.0 accumulations in other units such as Upper Jurassic Corallian limestone reservoirs sealed by Kimmeridge 0 100 Not available 100 90 80 70 60 50 40 30 20 10 0 The Oxfordian-age Oxford Clay Formation consists of a sequence of commonly sulphur-rich marine black Clay (Palmers Wood; see Section 3.6.1 in Chapter 10), or Upper Jurassic Portland beds sealed by the C27 steranes (%) shales with TOC contents up to 12%. Organic matter is mainly type II with local intervals of mixed type II Purbeck anhydrite (Godley Bridge). The Triassic Sherwood Sandstone Group is a potential reservoir in the Lower Cretaceous Kimmeridge Clay Formation and type III (Figure 13.42). The Oxford Clay appears to have been deposited in a large restricted basin that west of the region, sealed by the Mercia Mudstone Group, which has proven successful in the Lias-sourced Upper Oxford Clay Formation filled up over time, as evidenced by a general decrease in TOC contents and indications of bottom-water Wytch Farm field. Middle Jurassic Lias Group oxygen depletion upwards in the sequence. Vitrinite reflectance values of up to 0.74% have been reported Lower Other units from Penshurst in the basin centre, roughly corresponding to peak-oil generation, although the Oxford The three major clay-rich intervals in the sequence (Lias, Oxford Clay and Kimmeridge) had a profound e. Clay is either immature or only marginally mature in much of the area. This is supported by thermal influence on migration patterns by partitioning the sequence into vertically constrained Triassic, Middle Figure 13.42 Geochemical data from different Lower Jurassic formations of the Weald Basin: a. Pyrolytic yield (S2)

modelling that also suggests oil expulsion may have commenced in Early to mid-Cretaceous times and Jurassic and Upper Jurassic. migration cells. Lateral migration was extensive within these cells, starting versus TOC; b. Tmax versus Hydrogen Index (HI); c. Tmax versus Production Index (PI); d. Pr/nC17 versus Ph/nC18; continued until basin inversion in the Miocene (Figure 13.43). from Liassic source rocks in the Early Cretaceous. For example, the Stockridge field lies 30 km from the e. Sterane ternary diagram. Inset shows pristane/phytane ratios. Plots produced using IGI’s p:IGI-3.

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Chapter 13 — Petroleum generation and migration

Age (Ma) 4¡E F17-FB F17-FA 250 200 150 100 50 0 F17-3 F17-4 F17-7 F17-5 Mesozoic Cenozoic ELBOW RINGK¯BING-FYN HIGH 55¡N SPIT 1 Triassic Jurassic Cretaceous Tertiary HIGH MID NORTH SEA HIGH E M L E M L E L Paleogene Neogene 1.5 Source rock 2 ? Reservoir rock ? Seal rock STEP GRABEN 2.5 HELGOLAND Overburden rock BASIN 3 Trap formation Figure 13.43 Event chart Two-way travel time (s) 3.5 Generat./migrat./accum. for the Lower Jurassic Preservation petroleum system in the Weald 4 Re-migration during inversion Critical moment Basin petroleum province. 4.5 Neogene Reservoir 0 5 km Tertiary probable limit of mature Liassic source rocks. Reversed extensional faults provided additional tectonic SCHILL GRUND HIGH Paleogene Fault Upper Source rock controls on migration. Where inversion was extensive, these faults allowed petroleum flow into numerous DUTCH CENTRAL GRABEN Cretaceous Lower vertically aligned reservoir intervals via reservoir-reservoir juxtaposition. CLEAVER BANK HIGH Upper Cross-section Jurassic in Figure 13.49 Lower The most important traps in the area are structural closures associated with Cenozoic inversion. These Middle and Upper Cross-section Triassic are often found in tilted fault blocks on the original footwall of extensional faults or in isolated horsts. in Figure 13.45 Lower Potential also exists in original rollover anticline structures, albeit tightened during inversion, but these Zechstein have not yet proved successful. No stratigraphic pinch-out traps have been identified so far. Significantly, Figure 13.45 Cross-section of the Dutch Central Graben. Hydrocarbons generated from the Posidonia Shale Formation inversion on these structures also had a dramatic effect on fault-seal breaching during the Cenozoic; 54¡N migrate upwards to reservoirs associated with salt diapirs. See Figure 13.44 for location. a number of present-day accumulations are probably the result of re-migration at this time. TERSCHELLING BASIN The best reservoirs are the post-rift Rijswijk, Berkel and IJsselmonde sandstones that were deposited For further information see Ebukanson & Kinghorn (1985, 1986a), Fleet & Brooks (1987), Penn et al. (1987) as coastal barrier complexes overlying the Late Cimmerian Unconformity. Traps occur mainly as 4-way

and Butler & Pullen (1990). 0 50 km AMELAND BLOCK dip closures along anticlinal trends that formed in response to the Late Cretaceous and Paleogene inversion along the south-western basin margin. In some fields in the West Netherlands Basin, the oil 2.5.2 Dutch Central Graben Present-day relics of Late Jurassic basin was biodegraded at the onset of the Cenozoic. Due to tectonic inversion, reservoirs were then at or near Present-day distribution of Posidonia Shale source rocks the surface where bacteria had access to fresh meteoric waters. The Posidonia Shale source rock also The thickness of Upper Triassic to Lower Jurassic deposits varies considerably across the Dutch Central Gas shows signs of biodegradation in places within the West Netherlands Basin. Fields in the Broad Fourteens Oil Graben as a result of synsedimentary movements of the Zechstein salt (Figure 13.44 & 13.45). In contrast, Basin are located along the north-eastern margin of the inverted basin in Q1, K18 and L16. Oil and gas the Posidonia Shale Formation is uniformly thick, indicating relative tectonic quiescence during deposition. Major faults For further information see Bodenhausen & Ott (1981), (Wong et al., 1989), Roelofsen & De Boer (1991), The Posidonia Shale in the Dutch Central Graben is a marine bituminous source rock with common type II Wong (1991), De Jong & Laker (1992), Goh (1994), Van Adrichem Boogaert & Kouwe (1993-1997), kerogen, although some analyses indicate type III (Figure 13.46). The average TOC content is about 8% Figure 13.44 The Dutch Central Graben petroleum province with locations of fields De Jager et al. (1996), Den Hartog Jager (1996), Racero-Baena & Drake (1996), Van Balen et al. (2000), (up to 15%), with HI values up to 850 mg/g. The Posidonia Shale can be recognised on wireline logs by its and accumulations charged by the Posidonia Shale Formation. 0 200 km Verweij (2003), De Jager & Geluk (2007) and Nelskamp et al. (2008). high gamma-ray and resistivity readings (Figure 13.47). Log evaluation shows a gradual increase in TOC contents and HI values from bottom to top ending with an abrupt decline. This abrupt change seems to Formation has remarkably uniform thickness, whereas there are large thickness variations in the underlying 2.5.4 Lower Saxony Basin and Dogger Troughs correspond to a temporary flooding event and the initiation of an anoxic environment with evidence of Aalburg Formation in the Broad Fourteens and West Netherlands basins. Tectonic activity was limited maximum flooding in the middle of the formation. Type II kerogen is probably prevalent in the middle during the Toarcian. A sequence of fine-grained marine sediments was deposited during the Early Jurassic within the incipient part of the formation and less common at its top and bottom. Lower Saxony Basin and the Dogger Troughs (Figures 13.54 & 13.55). The gradual transition from the Source-rock characterisation of the Posidonia Shale indicates type II kerogen, with an average TOC mainly grey claystones and marlstones west of the Weser River to more frequent sandstone beds and The timing of oil generation from the Posidonia Shale depends on the location within the basin content of about 7% and increased HI values (Figure 13.52a & b). Biomarker analyses indicate early sedimentary iron ores in the easternmost part of the basin point to an eastward shoaling. Within this (Figure 13.48). The southern sector of the Dutch Central Graben has been strongly inverted and there mature marine organic matter (Figure 13.52d). Log evaluation in the Posidonia Shale shows the highest section, which is up to 800 m thick, organic-rich sediments accumulated in a very restricted depositional is currently no oil generation as present-day temperatures in the Posidonia Shale are lower than those TOC contents related to maximum flooding at the base of the formation, gradually decreasing upwards. environment and form a member of the Toarcian Posidonia Shale Formation. Geochemical data indicate an reached before inversion. In the north, the Posidonia Shale has reached its deepest burial and is still The dissimilar log pattern to that seen in the Dutch Central Graben indicates the different depositional anoxic lower water column; palynomorph data have been interpreted as invoking reduced salinities in the generating oil. Several oil discoveries were made in Upper Jurassic and Lower Cretaceous sandstones, conditions during the Toarcian. surface-water layer. This interval is the main source rock for hydrocarbons within the Lower Saxony Basin which may be attributed to charge from the Posidonia Shale, with minor contributions from the Upper east of the Ems River. Triassic Sleen and Lower Jurassic Aalburg formations. Both the West Netherlands and Broad Fourteens basins were inverted at the end of the Cretaceous (Figure 13.51). Depending on burial after inversion, which varied throughout the basins, generation either The Dogger Troughs include the West and East Holstein troughs on the eastern and western flanks of the Traps are structural and include 4-way dip closures (turtle-back structures) and tilted fault blocks. The ceased before the inversion or continued into the Cenozoic. Generation continued where post-inversion Glückstadt Graben, and the Jadeberger Trough in the North German Basin. The Glückstadt Graben formed southern sector of the graben is structurally more complex and compartmentalised due to strong inversion. burial was deeper (i.e. where temperatures are higher) than pre-inversion burial. Erosion took place in during Late Permian to Early Triassic rifting and rapidly filled with several kilometres of Upper Triassic Oil shows that are probably derived from the Posidonia Shale have been encountered in the Chalk Group the most inverted areas. Present-day oil accumulations are found at locations where suitable reservoir siliciclastics. After the Late Triassic, rising Zechstein salt formed north-north-west-trending diapiric plug in this southern area. The Hanze field in the northern Dutch Central Graben was discovered in 1996 in deposits were preserved. The Posidonia Shale is immature for oil at some well locations on the horst and wall structures. Marginal basins (rim-synclines) subsided around the periphery of the diapirs. The block F2 and was the first, and so far the only, economic oil accumulation offshore (Figure 13.49). structures in the West Netherlands Basin (Figure 13.52e & f). As oil occurs in proximity to these immature rim-synclines include the Holstein Trough, which subsided in Early to Mid-Jurassic times. The Posidonia areas, there is an implication that main oil generation took place in adjacent grabens and oil migrated Shale deposited within the Holstein Trough was buried by a relatively thin Upper Jurassic to Lower For further information see Wong et al. (1989), Wong (1991), Van Adrichem Boogaert & Kouwe (1993) and into the structural traps. In places where the Posidonia Shale is highly mature, it may have contributed Cretaceous cover with a number of erosional unconformities. Further subsidence varied strongly within De Jager & Geluk (2007). gas to Jurassic and Cretaceous reservoirs. the individual rim-synclines.

2.5.3 West Netherlands and Broad Fourteens basins Oil has been encountered in several Triassic reservoirs that are attributed to a Posidonia Shale source, The source rock has an average thickness of 25 m, but may be up to 50 m thick in the Gifhorn Trough. where the oil migrated across faults from downthrown blocks into the older reservoirs. However, most oil The average organic-carbon content is 8%, but can be as high as 20% with the higher values found mainly Whereas salt tectonics are dominant in the Dutch Central Graben, the West Netherlands and Broad reservoirs were found in Upper Jurassic and Lower Cretaceous sandstone reservoirs. The reservoirs occur to the west of the Weser. The organic matter consists mainly of alginite and bituminite with increasing, Fourteens basins and the Roer Valley Graben are characterised by a horst and graben configuration in clastic Upper Jurassic to Lower Cretaceous syn-rift deposits and early post-rift deposits of Early but still subordinate, vitrinite contents to the east (Figure 13.56f). In addition to the organic petrographic related to Jurassic rift and Cretaceous inversion events (Figure 13.50 & 13.51). The Posidonia Shale Cretaceous age that show rapid facies variations from continental to marine (Figure 13.53). observations, the available Rock-Eval data (Figure 13.56a to c) with an average HI value of 520 for the

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Chapter 13 — Petroleum generation and migration

1000 L05-4 HI = 800 Tmax (¡C) CPI 10 Terrestrial organic matter Biodegraded/immature 0.9 - 1.0 ILD GR DT TOC 600 400 - 420 Mixed sources 400 Marine organic matter 1.0 - 1.3 0 50 0 200 0 200 020 420 - 435 Undetermined 2865 200 435 - 445

445 - 455 Oxidising 2860 100 100 1 Early mature

Type I kerogen 1& 4 2855 Type II kerogen Pr/nC

3 Rock-Eval S2 (kg/t) Type III kerogen 2850 0.1 Reducing 10 2 Frequency 2845 Mature 1

2840 0.01 0 0 1 10 100 0.01 0.1 1 10 100 0 0.2 0.4 0.6 0.81.0 1.2 1.4 1.6 1.8 2.0 Pr/Ph (a/b) TOC (%) Ph/nC18 2835 a. d. HI (mg/g TOC) Vitrinite reflectance (% Ro) Tmax (¡C) 0 100 200 300 400 500 600 700 800 900 1000 0.0 0.4 0.81.2 1.6 2.0 400 420 440460 480 500 2830 400 S2 (kg/t) 0 0 Type III kerogen 2 - 5 410 Subsea true vertical depth Type II kerogen 5 - 15 Figure 13.47 Log response of Posidonia Shale Formation in 2825 420 Type I kerogen 15 - 30 1 1 well L05-4 in the Dutch offshore sector including a calculated

430 30 - 60 TOC log with measured TOC plotted for comparison. The 2820 calculation method makes use of the gamma-ray (GR), sonic 440 2 2 60 - 100 (DT), and deep resistivity logs (ILD). A shaly interval consists 450 2815 Not of a shale matrix (by gamma ray), some porosity (by sonic), and available Cenozoic (¡C) 460 3 3 Upper possibly (light) hydrocarbons (also sonic). The deep-reading max Cretaceous T 2810 Depth (km) Depth (km) Lower resistivity responds strongly to the presence of hydrocarbons, 470 Upper i.e. the resistivity will increase. If there are no hydrocarbons Jurassic 480 4 4 Lower and there is only (saline) water present in the shale pores, the 2805 Upper Triassic 490 sonic and resistivity logs will overlay if they are properly scaled. Upper Permian In an organic-rich section, there will be a distinct separation 500 5 5 Lower 2800 Silesian between the sonic and resistivity logs. The amount of separation 510 indicates the amount of organic material.

520 6 Posidonia Shale Formation at the beginning of the inversion in contrast to pronounced pre-Santonian subsidence, especially west b. e. of the Ems. In most areas of the basin, the Posidonia Shale had already reached the oil window during Production index 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 the Early Cretaceous and entered the gas window, at least in the southern and western areas of the basin, 400 TOC (%) Posidonia Shale, mostly classify the organic matter as type II kerogen with a transition to a mixed type during the Cenozoic. Differing subsidence/uplift histories locally resulted in the preservation of immature 1 - 2 II/III kerogen in the easternmost part of the basin. This interpretation is corroborated by biomarker data, Posidonia Shales, for example, in the southern Hils Syncline where the maturity sequence is within a short 410 2 - 4 which show a predominance of the C27 steranes (Figure 13.56E) and carbon-isotopic data. The genetic distance. Maturity in the Dogger Troughs is usually lower than in Posidonia Shale-sourced accumulations 4 - 6 potential of this source rock can be as high as 120 kg HC/t rock, but averages about 50 kg HC/t rock. of the Lower Saxony Basin, with most fields showing less than 0.7% Ro. 420 6 - 9 9 - 12 The reservoir rocks for the hydrocarbons sourced from the Posidonia Shale within the Lower Saxony Asphalt relics and the results of basin-modelling studies indicate a first phase of oil generation and 430 12 - 15 Basin are mostly siliciclastic, to a lesser extent calcareous sandstones, ranging in age from Rhaetian to migration before the Santonian, although almost all of the oil has been lost from the pre-inversion Maastrichtian. The age of the productive reservoir rocks generally decreases from east to the west. The reservoir rocks due to structural rearrangement or erosion. This event represents the critical moment in (¡C) 440 majority of oil reservoirs in the eastern basin are in Aalenian sandstones, whereas between the Weser and the evolution of the Posidonia Shale petroleum system in the Lower Saxony Basin. max T Ems rivers, most of the production is from reservoirs in Bajocian, Bathonian and Callovian sandstones or 450 Oxfordian and Kimmeridgian limestones. In the western basin, the Valanginian sandstones are the most The second phase of oil generation and migration started in the Early Cenozoic and may be continuing important hydrocarbon reservoir rocks. today (Figure 13.57). For most fields, the geochemical-maturity data of the oils equal the maturity of 460 the underlying Posidonia Shale in the directly surrounding areas, implying a very short and mainly The seals for most oil accumulations are formed by Lower to Middle Jurassic and Hauterivian-Albian shales, 470 Well-drained Age (Ma) source rock and locally by Tithonian evaporites. In addition to their importance as seals, the thick Cretaceous claystone Poorly-drained 150 100 50 0 source rock sequences acted as overburden before the Late Cretaceous inversion. 480 Mesozoic Cenozoic Jurassic Cretaceous Tertiary c. A variety of traps are found throughout the Lower Saxony Basin. Structural traps are the most widespread and include traps related to salt diapirism (e.g. Figure 13.55), rollover structures or anticlines. Both E M L E L Paleogene Neogene Figure 13.46 Geochemical data from the Posidonia Shale Formation in the Dutch Central Graben: facies and unconformity-related stratigraphic traps are common in the easternmost Lower Saxony Basin. Source rock a. Pyrolytic yield (S2) versus TOC; Unconformity traps predominate in areas where transgressive Valanginian to Albian sedimentary rocks Reservoir rock b Tmax versus Hydrogen Index (HI); truncate the Jurassic reservoirs rocks. Seal rock c. Tmax versus Production Index (PI); Overburden rock d. Pr/nC versus Ph/nC . Inset shows pristane/phytane ratios; Thermal maturation of the Posidonia Shale source-rock interval occurred mainly during pre-Turonian 17 18 Trap formation e. Vitrinite reflectance and Rock-Eval Tmax parameters of Silesian to Cenozoic samples plotted against sub-bottom depth. subsidence, but continued after Late Cretaceous inversion into Cenozoic times (Figure 13.57). There is Figure 13.48 Event chart of the southern part of Generation Plots produced using IGI’s p:IGI-3. an ongoing debate about the relative importance of additional extreme heating by magmatic intrusions the Dutch Central Graben, based on basin modelling.

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Chapter 13 — Petroleum generation and migration

N S 4¡E 6¡E SW NE F17-1 L02-5 CLEAVER 0 BANK 0 HIGH BROAD FOURTEENS BASIN

1

0.5

SOLEPIT TROUGH TEXEL-IJSSELMEER HIGH 53¡N 2

1

Depth (km) 3

1.5

Amsterdam CENTRAL NETHERLANDSNETHER BASIN 4 WEST NETHERLANDS BASIN 2 NETHER LANDS BASIN 5

Two-way travel time (s) Cenozoic Posidonia Shale Formation 0 5 km 2.5 Rotterdam 52¡N Upper Coal Measures Cretaceous Lower Oilfield Upper Gasfield Jurassic 3 Middle and Lower Triassic LONDON-BRABANT MASSIF Permian Figure 13.51 Schematic section through the West Netherlands Basin ROER VALLEY Carboniferous and older (after De Jager et al., 1996). 3.5 GRABEN 0Bruges 100 km Antwerp The TOC content generally increases upwards in the formation, along with a shift from generally gas-prone Present-day relics of Late Jurassic basin to generally oil-prone characteristics. The richest interval, the Bo Member (former ‘Hot Unit’), is in the Neogene Posidonia shale Formation 0 2 km Present-day distribution of Posidonia Shale source rocks upper part of the Farsund Formation. Source-rock quality decreases towards the Salt Dome Province Paleogene Middle Gas Triassic reflecting both the thinning of the prolific upper part of the formation and shallower and more oxygenated Lower Cretaceous Lower Oil conditions during deposition. Upper Zechstein Oil and gas Middle Jurassic Sub-Zechstein Major faults Lower Fault The Jurassic discoveries in the Danish Central Graben have all been drilled where significant structural components in the plays have been recognised. This highlights the less-mature exploration status of the Figure 13.49 Seismic cross-section through the Dutch Central Graben. Petroleum generated from the Posidonia Shale Figure 13.50 The West Netherlands and Broad Fourteens basins petroleum province plays compared with other parts of the North Sea, where the focus has long been on Jurassic stratigraphic Formation migrates upward to reservoirs associated with salt tectonics. See Figure 13.44 for location. with locations of fields and accumulations charged by the Posidonia Shale Formation. 0 200 km traps. In the Feda Graben, the basal Farsund Formation also has good oil-generating properties, as indicated by the Gert-2 well north of 56°N. Similarly good source potential is expected in the Outer vertical migration path of less than 5 km. Several oilfields exhibit high gas:oil ratios with stable isotopic The compositions and carbon-isotopic signatures of associated gases revealed different types. The Rough Basin, although the Farsund Formation probably thins westwards. compositions of the gases invoking their thermal generation. This may point to either admixture of associated gases, most of which are microbially generated methane in the Jaderberger Trough (Elsfleth thermogenic gas or to oils already in place. East of the Weser, the generation-accumulation efficiency and Varel fields), indicate a source-rock maturity of about 0.6%. Associated gases of the East Holstein The source-rock potential of the Farsund Formation is very variable. The prolific, more terrestrially influenced, is 5%, indicating that most of the hydrocarbons have been lost during Late Cretaceous inversion or later Trough are progressively intermixed northwards with gases generated from a Zechstein source. oil-prone source-rock intervals are found in the lower part of the Upper Jurassic (Lola Formation) and may due to missing traps. Petroleum generation in the Holstein Troughs reached its peak at 55-35 Ma when For further information see Adriasola-Muñoz et al. (2007), Baldschuhn et al. (1996), Binot et al. (1993), constitute additional sources for liquid petroleum. In many areas, the uppermost Farsund Formation has not subsidence increased around some of the diapirs leading to a maturity of up to 0.8% Rr in the structurally Buntebarth & Teichmüller (1979), Grassmann et al. (2005), Kockel et al. (1994), Maystrenko et al. (2005), reached the level of maturity required to generate enough hydrocarbons to explain the in-place reserves. deeper parts of the Heide Trough; lateral migration was up to 5 km. Numerical modelling of the thermal Petmecky et al. (1999), Rodon & Littke (2005), Rullkötter & Marzi (1988), Schwarzkopf & Leythaeuser history successfully reproduces the present-day reservoir temperature when a basal heat flow of 50 mW/m2 (1988) and Wehner et al. (1979). Lower Jurassic deposits are known to occur in the Central Graben (Danish and German sectors), but have not is assumed. developed as source rocks. In contrast, the Middle Jurassic Bryne Formation contains coals and organic-rich 2.5.5 Tail End Graben lacustrine shales with good to excellent type III kerogen source rocks (Figure 13.61). The Lower to Middle Severe biodegradation reduced the oil quality in a number of shallower fields, especially in the eastern Jurassic coals formed in a humid, warm-temperate to subtropical, weakly seasonal climate. The Bryne Lower Saxony Basin. Interestingly, the risk of microbial degradation is strongly reduced where sealing The Danish Central Graben is generally considered to be a mature region with 91 exploration wells Formation is best known from the Søgne Basin north of 56°N. The Middle Jurassic coals in the Søgne Basin Middle Jurassic shales are preserved above the Aalenian reservoir. In unconformity traps, where the (Figure 13.58). The exploration focus was on reservoirs within the Chalk Group, which hosts the majority are mostly found at depths between about 3400 to 3800 m (VR from 0.75-0.89% Ro) although they may be transgression locally truncated this seal such that Cretaceous shales acted as the seal, biodegradation of currently proven reserves. Prior to 1995, the targets were primarily Jurassic, Triassic and Zechstein buried to around 5000 m towards the Tail End Graben. Nine coal seams have been identified in the basin; has frequently affected the quality of the organic matter. The petroleum in several reservoirs, especially reservoirs, but the discovery of the Upper Paleocene Siri field turned the focus towards Paleogene plays the thickest seam is about 2 m thick. The coals are vitrinite-rich and characterised by high inertinite in fields west of the Ems, was generated from both the Posidonia Shale and Wealden source rocks (see (see Chapters 14 and 15). Oil and gas/condensate in Middle and Upper Jurassic sandstones is the main contents, which may be the dominant component. Similar intervals may be present in the Tail End Graben, Section 2.6.1). secondary exploration objective in the Danish Central Graben after the Chalk Group (Figure 13.59). but data coverage is poor and therefore it is difficult to give average values. The timing of oil generation The majority of exploration wells in the 1980s were drilled on either a primary or secondary target in from the Farsund Formation depends on the location within the Danish Central Graben (Figure 13.62). In contrast to the Lower Saxony Basin, where admixtures of Wealden-sourced oil and pre-Jurassic-sourced the Jurassic. Many of these wells did find hydrocarbons, demonstrating the existence of active petroleum gas is common, oil compositions in the Dogger Troughs are remarkably homogenous and point to a Posidonia systems in the sector. However, the quantity and quality of the reservoirs was often highly variable and For further information see Damtoft et al. (1992), Hemmet (2005), Ineson et al. (2003), Megson & Hardman Shale source. Contributions from other potential source rocks are either minor or non-existent. Notably, so to date only a few discoveries have been declared economic. (2001), Møller et al. (2003), Petersen (2006), Petersen et al. (1998) and Petersen & Nytoft (2006, 2007b). the analyses of oils from different Mittelplate reservoirs corroborated their derivation from a compositionally and thermally uniform Posidonia Shale source. They are products of the early to peak generation phases. The major and most prolific oil and gas source rock in the Tail End Graben of the Danish Central Graben is 2.6 Early Cretaceous Systematic depth trends of maturity-related geochemical parameters correlate with oil quality and point to the marine, type II Upper Jurassic Farsund Formation (Kimmeridge Clay Formation equivalent, Ryazanian; the dominant control of oil (and source-rock) maturity on oil quality. Oil quality improves with increasing Ineson et al., 2003). The Farsund Formation covers the entire Danish Central Graben except for major highs 2.6.1 Lower Saxony Basin oil maturity. Lower maturity oils occur at greater depths, which excludes gravitational segregation as the such as the Inge-Mads High in the Outer Rough Basin towards the west (Figure 13.58). Large thickness cause of the quality trend. The least mature oils are found in the structurally deepest reservoirs. There are variations are evident, with more than 3000 m-thick deposits in the Tail End Graben. The thickest are The restricted shallow-water conditions that prevailed during the Late Jurassic culminated in the no indications for major alteration, biodegradation or water washing. However, there is a deterioration in found towards the Coffee Soil Fault, and are 1500 to 2250 m thick in the Feda Graben farther north deposition of Tithonian rock-salt layers and time-equivalent lacustrine sediments. Increased vertical oil quality (increasing density and sulphur contents) with increasing structural depth. Deterioration with (Figure 13.60). movements resulted in a complex, small-scale pattern of rapidly subsiding graben structures next to depth and moderate reservoir temperatures (<100°C) preclude thermal cracking as a mechanism. sediment-starved horsts. In the Early Cretaceous, most of the basin was occupied by swamp areas in front

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Chapter 13 — Petroleum generation and migration

1000 Age (Ma) HI = 800 Tmax (¡C) CPI 10 Terrestrial organic matter Biodegraded/immature 150 100 50 0 0.7 - 0.9 600 400 - 420 Mixed sources Mesozoic Cenozoic 400 Marine organic matter 0.9 - 1.1 420 - 435 Jurassic Cretaceous Tertiary 1.1 - 1.3 200 435 - 445 E M L E L Paleogene Neogene 1.3 - 1.5 445 - 455 Oxidising Source rock 100 100 1 Early mature Undetermined Reservoir rock

Type I kerogen 17 8 Seal rock

Type II kerogen Pr/nC 7 Overburden rock 6

Rock-Eval S2 (kg/t) Trap formation Type III kerogen 5 0.1 Reducing Generation/migration/accumulation 10 4 Frequency Preservation 3 a. Mature 2 Age (Ma) 1 250 200 150 100 50 0 0.01 0 Mesozoic Cenozoic 0 1 10 100 0.01 0.1 1 10 100 0 0.2 0.4 0.6 0.81.21.0 1.4 1.6 1.82.0 Pr/Ph (a/b) TOC (%) Ph/nC18 Triassic Jurassic Cretaceous Tertiary

a. d. E M L E M L E L Paleogene Neogene HI (mg/g TOC) Source rock 0 100 200 300 400 500 600 700 800 900 1000 Ottoland-1 Tmax = 418¡C 400 S2 (kg/t) Reservoir rock Type III kerogen 410 2 - 5 Seal rock Type II kerogen 5 - 15 Figure 13.53 Event charts Overburden rock 420 Type I kerogen 15 - 30 of: a. the Broad Fourteens Intensity Trap formation 430 30 - 60 Basin; and b. the West Generation Netherlands Basin. b. 440 60 - 100 0 10 20 30 40 50 60 70 8¡E 10¡E 12¡E 450 Woubrugge-1 Tmax = 419¡C RINGK¯BING-FYN HIGH (¡C) 460 max T 470 Kiel Intensity 480 HELGOLAND BASIN DOGGER TROUGHS 490 Rostock 0 10 20 30 40 50 60 70 MECKLENBURG BASIN 500 54¡N Haastrecht-1 Tmax = 429¡C 510 EAST TROUGHHOLSTEIN Increasingly maturity 520 WEST TROUGHHOLSTEIN Intensity

b. GRONINGEN BLOCK Hamburg

Production index 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.80.9 1.0 0 10 20 30 40 50 60 70 400 TOC (%) Gaag-1 Tmax = 436¡C 1 - 2 Groningen POMPECKJ HIGH 410 2 - 4 Bremen 4 - 6 53¡N

420 6 - 9 Intensity ALTMARK-BRANDENBURG 9 - 12 EMSLAND LOW BASIN 430 12 - 15 0 10 20 30 40 50 60 70 Time (minutes)

(¡C) 440 e. Cross-section

max in Figure 13.55 T LOWER SAXONY BASIN Hannover 450

460 Magdeburg Lower Jurassic ?ERODED TH†RINGIAN BASIN 470 Well-drained Intensity Posidonia Shale 52¡N source rock Formation M†NSTERLAND BASIN Poorly-drained 0 100 km source rock Posidonia Shale 480 Formation 0 10 20 30 40 50 60 70 Present-day relics of Late Jurassic basin c. f. Time (minutes) Present-day distribution of Posidonia source rocks Gas Figure 13.52 Geochemical data from the Posidonia Shale Formation in the Broad Fourteens and West Netherlands basins: Oil a. Pyrolytic yield (S2) versus TOC; b. Tmax versus Hydrogen Index (HI); c. Tmax versus Production Index (PI); Major faults d. Pr/nC17 versus Ph/nC18. Early mature Posidonia samples with the highest TOC plot in the field indicating marine deposits in a reduced environment suggesting restricted water circulation. Inset shows pristane/phytane ratios; Figure 13.54 The Lower Saxony Basin and Dogger Troughs petroleum e. n-alkane distribution in source-rock extracts from samples of the Posidonia Shale Formation, showing the effect of maturity; province with locations of fields and accumulations charged by the f. n-alkane pattern of oil with a Posidonia Shale Formation source. Plots produced using IGI’s p:IGI-3. Posidonia Shale Formation. 0 200 km

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Chapter 13 — Petroleum generation and migration

1000 SW NE HI = 800 Tmax (¡C) CPI 10 Terrestrial organic matter Biodegraded/immature 0.7 - 0.9 Undetermined Wietze Wolthausen 600 400 - 420 Mixed sources 400 Marine organic matter 0.9 - 1.1 0 420 - 435 1.1 - 1.3 200 435 - 445 1 1.3 - 1.5 445 - 455 Oxidising 100 100 455 - 475 1 Early mature 1.5 - 2.2 2

Type I kerogen 17

11 3 Type II kerogen Pr/nC Depth (km) 10 9 Rock-Eval S2 (kg/t) Type III kerogen 8 4 0.1 Reducing 7 10 6 5

5 Frequency Cenozoic 0 2 km Mature 4 3 Upper 2 Lower Cretaceous 1 ÔWealdenÕ, BŸckeberg Formation 0.01 0 0 0.4 0.81.2 1.6 2.0 2.4 2.8 Upper 0 1 10 100 0.01 0.1 1 10 100 TOC (%) Ph/nC Pr/Ph (a/b) Middle Jurassic 18 Lower a. c. Upper HI (mg/g TOC) Middle Triassic 0 100 200 300 400 500 600 700 800 900 1000 400 S2 (kg/t) Lower Type III kerogen Zechstein 410 2 - 5 Type II kerogen Sub-Zechstein Figure 13.55 Cross-section through the Lower Saxony Basin. Example 5 - 15 420 Fault of a structural trap created by salt diapirism in the eastern Lower Saxony Type I kerogen 15 - 30 Unconformity Basin (after Baldschuhn et al., 1996). See Figure 13.54 for location. 430 30 - 60 C27 steranes 440 of the deltas in the east and more-or-less continuous lake systems to the west. Sediments deposited in 60 - 100 these palaeoenvironments are referred to as the widespread Bückeburg or ‘Wealden’ Formation in Germany 450

(¡C) C steranes and as the regionally more limited Coevorden Formation in the Netherlands (Figure 13.63). East of the 460 29 max Intensity Weser River, coaly deposits are intercalated in mainly siliciclastic successions. Thick sequences of dark T 470 claystones, bituminous ‘paper shale’, and intercalated Cyrena shell horizons accumulated in a large lake system between the present-day Weser and Ems rivers. 480

490 The thickness of the paper-shale source rock is not well defined, mainly because detailed knowledge of the 500 Posidonia Shale Formation variability of the hydrocarbon potential within the Wealden is very limited. Average thickness is commonly Liassic assumed to be 25 m, but the total of the lacustrine Wealden 1 to 6 sequence may account for up to 1100 m 510

of sediment in the rapidly subsiding grabens at the southern basin margin (Figure 13.64: Chapter 11). The 520 Posidonia Shale Formation 32 33 34 3536 37 3839 40 41 42N organic-carbon content is up to 14% with an average of about 5% west of the Weser. The organic matter in Time (minutes) the Wealden paper shales in the lake areas consists mainly of alginite (Figure 13.65) with some bituminite. b. d. Admixtures of terrigenous organic particles are more pronounced towards the east and the south, building up local coal seams in the delta areas. Rock-Eval data (Figure 13.65) point to the excellent hydrocarbon K16115_F potential of a mixed type I/II kerogen with HI values up to 950 (average of 600) in the lake area that developed between the Weser and Ems areas. Eastwards, low HI and increased Oxygen Index (OI) values indicate a type II/III mixture. The biomarker data support the latter conclusion by the higher percentages of C29 steranes (Figure 13.65) in source-rock samples from the area. The genetic potential of this source-rock interval may be as high as 125 kg HC/t rock, but it is highly variable as mentioned above. The Figure 13.56 Geochemical data from the Posidonia Shale Formation and other Liassic samples from the Lower Saxony Basin and the Dogger Troughs: Wealden paper shale between the Weser and Ems has genetic potential averages of about 40 kg HC/t rock. a. Pyrolytic yield (S2) versus TOC. In addition to many mature and non-source rock samples and a few immature coal samples with type III kerogen there are a number of atypical samples with hydrogen-rich kerogen;

The most important reservoir rock for the hydrocarbons sourced from the Wealden paper shale within b. Tmax versus Hydrogen Index (HI). Samples are mostly marginally mature to mature and comprise unusual type-I kerogen samples; the Lower Saxony Basin are Valanginian sandstones. Intraformational sandstones and coquinites, and c. Pr/nC17 versus Ph/nC18. Inset shows pristane/phytane ratios; Hauterivian and Aptian reservoir rocks, also yield minor production mainly to the west of the Ems River. d. Molecular biomarker characteristics of a typical Posidonia Shale sample from the Lower Saxony Basin. The depicted m/z 217 trace was reconstructed

from the single parent-daughter transitions from the metastable reaction monitoring measurement. The predominance of the C27 steranes over C28 and Seals for most of the oil accumulations sourced or co-sourced from Wealden paper shale are formed by C29 steranes points to the dominance of algal remains in the organic matter; Hauterivian to Albian shales. In addition to their importance as seals, the thick Cretaceous claystone e. Reflected-light micrograph (blue fluorescence excitation) of particulate organic matter in typical Posidonia Shale sample. Note the bright background fluorescence due to dispersed organic material in addition to the small yellow alginite particles. sequences acted as overburden before Coniacian inversion. Structural traps predominate in the western 0 50 µm part of the Lower Saxony Basin. Large anticlines, which may be combined with adjacent overthrusts, Plots produced using IGI’s p:IGI-3. e. are typical of the trap style in the area west of the Ems. The indications for a first phase of oil generation and expulsion from the Wealden paper shale prior to west of the Weser, the generation-accumulation efficiency is about 10% for the Wealden paper shale, Thermal maturation of the Wealden shale source-rock interval started during pre-Turonian subsidence, Santonian inversion are concentrated in the area west of the Ems. However, as mentioned above for the indicating that most of the hydrocarbons generated have been lost either during the inversion interval, but continued after the Santonian during the Cenozoic. The importance of extreme heating by magmatic Posidonia Shale-sourced oils, no economic oil accumulations survived the subsequent structural changes or more probably later due to missing traps. intrusions at the beginning of the inversion, in contrast to pronounced subsidence during pre-Santonian and Cretaceous erosion. The second phase of oil generation and migration started in the Early Cenozoic times, especially west of the Ems, is less pronounced for the Wealden shale than for the Posidonia Shale. and may be continuing today (Figure 13.65). In fields west of the Ems, geochemical maturity data from Hydrocarbons in the reservoirs of several fields were generated from both the Posidonia Shale In most areas of the basin, the Wealden paper shale reached the oil window in the Late Cretaceous; in the the oils are comparable to the maturity of the Wealden paper shale in the vicinity, implying short (Figure 13.65) and the Wealden/Coevorden Formation, especially those west of the Ems. Both source central and southernmost part of the basin, it entered the gas window in the Cenozoic. The strong migration distances. Several oilfields near the Ems exhibit increased gas:oil ratios, with stable isotopic rocks can be identified by biomarker and isotope data. variations in overburden and the possible local influence of deep magmatic intrusions led to sharp compositions of the gases invoking their thermal generation, perhaps from deep-seated Carboniferous maturity gradients between different tectonic blocks in the Lower Saxony Basin. coals. This may point to either admixture of thermogenic gas or to oils already in place. In the areas

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Age (Ma) WSW ENE 200 150 100 50 0 Mid North Sea High Feda Gert Ridge Gertrud Mandal High S¿gne Basin Ringk¿bing-Fyn High Mesozoic Cenozoic Graben Graben (East North Sea High) W. Lulu-2 Jurassic Cretaceous Tertiary Kim-1 Lone-1 Rita-1 Gert-2 Gert-3N Mona-1 Karl-1 W. Lulu-4 Lulu-1 Cleo-1 Elna-1

E M L E L Paleogene Neogene 0 Post Ryazanian Source rock 1 Upper Volgian Ð Ryazanian Reservoir rock 2 Lower and Upper Volgian Seal rock 3 Upper Kimmeridgian Ð Lower Volgian 4 Callovian Ð Upper Kimmeridgian Overburden rock 5 Lower Jurassic Trap formation Depth (km) 6 Coffee Soil Fault Triassic Ð Lower Jurassic Zechstein Generat./migrat./accum. 7 Figure 13.57 Event chart of the Posidonia Sub-Zechstein Preservation 8 Shale petroleum system in the Lower Saxony Fault Critical moment 0 5 km Basin (after Kockel et al., 1994). a.

4¡E WSW ENE W E Heno Plateau Tail End Graben Kim-1, Ravn-1 Elin-1 Nora-1 John-1 John Flank-1A-2 Nils-1 O-1 56¡N Cross-section 0 OUTER ROUGH BASIN in Figure 13.60b 1 2 3 4 Coffee Soil Fault 5

TAIL END GRABEN Depth (km) 6 Coffee Soil Fault 7 8 9

b. c.

Figure 13.60 Cross-sections through the Tail End Graben petroleum province and adjacent areas: a. Northern Danish from these traps leads to preferential dismigration of the lighter hydrocarbons into shallower sediments ELBOW SPIT HIGH Cross-section in Central Graben; b. Tail End Graben and Heno Plateau; c. Salt Dome Province (modified after Møller & Rasmussen, 2003). and, in some cases, to the surface. Microbial and thermogenic processes lead to different carbon-isotope DUTCH CENTRAL GRABEN Figures 13.60c See Figure 13.58 for locations. signatures that can, in turn, be used to indicate the gas origin. Other sources of gas (destabilised gas STEP GRABEN hydrates, volcanic/hydrothermal emanations) are thought to be irrelevant in the southern North Sea. The Schoonebeek oilfield in the Netherlands and its extension into Germany (where it is still producing) is the most prominent oilfield in the SPB area that was charged from Lower Cretaceous deposits (Section 4.1 Major incentives to investigate seismic shallow-gas indicators include risk and hazard prevention

0 50 km in Chapter 11). It is the largest onshore oilfield in western Europe, with an initial in-place volume of associated with drilling into unknown gas-bearing sediments. A blow-out is the most dangerous of these about 1 bln barrels of which 25% had been produced before it was closed in 1996. The source rocks of drilling hazards. Another aspect is the effect shallow gas has on the engineering behaviour (particularly Present-day relics of Late Jurassic basin the oil are lacustrine shales with algal, type I source rocks of the Coevorden Formation. Geochemical data the shear strength and consolidation characteristics) of unlithified sediments; the construction of Present-day distribution of Upper Jurassic source rocks indicate that the oil is an early expulsion product of a source rock with low maturity, consistent with the petroleum infrastructure or windfarms may be impaired on these potentially unstable substrates. Gas high viscosity of the oil (25° API). There are no signs of biodegradation. However, a contribution from Natural-gas seeps may be indicated by methane-derived authigenic carbonates (MDAC) at the sea bed. Oil Oil and gas the Posidonia Shale source rocks that occur west of the field can not be excluded. The oil from the As well as providing uneven sea-bed foundations and obstacles to sea-bed structures such as cables and Major faults Schoonebeek field is produced from the Lower Cretaceous Bentheim Sandstone at a depth of about 800 m. pipelines, MDAC structures are identified by the European Commission’s Habitats Directive as sensitive habitats that should be avoided by offshore operations. For further information see Binot et al. (1993), Kockel et al. (1994), Baldschuhn et al. (1996), Mutterlose & Bornemann (2000), NITG (2000), Adriasola-Muñoz et al. (2007) and De Jager & Geluk (2007). Pockmarks (sea-bed depressions formed by the erosion of soft, fine-grained seabed sediment by escaping Figure 13.58 The Tail End Graben petroleum province with locations of fields fluids) may also indicate current or former migration of gas (either microbial or thermogenic). Although and accumulations charged by Jurassic source rocks. 0 200 km common in large parts of the northern North Sea in the SPB, they seem to be restricted to parts of the 3 Shallow gas and bright spots in the southern North Sea Dutch sector. Freak sandwaves, also thought to be attributable to gas seepage, have also been described No palaeostructure, Structural trap: oil migrated Stratigraphic trap (loss of reservoir from the southern North Sea. Knowledge and understanding of the distribution, size and extent of shallow high porosities, into palaeostructure; later quality) or migration trap Ð loss of no hydrocarbons titled OWC migration energy The SPB, like many other petroleum provinces, contains several known accumulations and abundant gas and associated features is therefore crucial to safe drilling, construction and other offshore operations.

cene Un indications of shallow gas (Figure 13.67). Shallow gas is commonly defined as gas occurrences in sediments -Mio con Lateral movement in the Tor Formation, id for M mity a few kilometres per million of years down to depths of 1000 m below surface, although the petroleum industry tends to be pragmatic, regarding The presence of gas in the shallow subsurface can be an indication of deeper hydrocarbon fields. Further it as gas above the first casing point. In addition to carbon dioxide, hydrogen sulphide, and nitrogen motivation is the prospect of future exploitation of large shallow-gas accumulations that might become No lateral movement there is a group of lighter hydrocarbons. The most common gaseous hydrocarbon is methane, although economically viable. For example, local gas power-plants could supplement offshore windfarms during below the Tor Formation Ekofisk Formation Tor Formation ethane, propane, butane and pentane (and the respective alkenes) also occur. periods of low wind, which requires the amount of gas in place and its quality or composition to be studied, starting with shallow-gas indicators. Tight Zone Hod Formation Hydrocarbons in sediments can originate from microbial/biogenic or thermogenic processes. Biogenic Hidra Formation Plenus Marl gas is by microbial breakdown of organic matter at shallow depth. It is almost completely composed 3-D seismic datasets are the best tools to evaluate the position and extension of shallow-gas indicators. Lower Cretaceous of methane. The microbes that generate methane from organic matter are archaea which comprise In combination with other seismic-analysis methods such as amplitude variation with offset (AVO), and in

Upper Jurassic a separate, ancient species of organisms. comparison with data from wells, the gas assumed to be associated with seismic indicators can be corroborated and quantified. Gases in the pore space of rocks, even at concentrations as low as 0.5%, can Microbial gas found at greater depths may have generated in situ at this depth or it may have been buried change both their elastic properties and densities, which in turn may lead to considerable changes in the during times of higher subsidence rates from originally shallower depths. Thermogenic gas is generated propagation and reflection of seismic waves. This may lead to peculiar features in (P-wave) reflection- Figure 13.59 Schematic model illustrating the entry points and various oil-migration paths in the complex Chalk Group from organic matter by thermokinetic breaking of carbon bonds of complex kerogen molecules at higher seismic data, such as bright spots, chimneys, and acoustic blanking. of the Tail End Graben (modified after Megson & Hardman, 2001). temperatures. Hydrocarbons can accumulate in traps during buoyancy-driven secondary migration. Leakage

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Production index Age (Ma) 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.80.9 1.0 250 200 150 100 50 0 1000 400 0 HI = 800 Tmax (¡C) TOC (%) Quaternary 3 1 - 3 600 400 - 420 Miocene 4 410 3 - 6 1 400 420 - 435 6 - 10 Miocene 1 2 Oligocene 1 200 435 - 445 420 10 - 20 445 - 455 20 - 40 100 100 3 Lower Cret. 2 Not 430 Lower Cret. 1 available Type I kerogen 40 - 90 Depth (km) Upper Jurassic 3 4 (¡C) 440 Type II kerogen Upper Jurassic 1 max T 5

Rock-Eval S2 (kg/t) 450 Type III kerogen Middle Triassic Lower Triassic 6 10 460 Vitrinite reflectance (% Ro) Position of stratal boundary through time Immature Ð 0.25 - 0.55 470 Well-drained Early oil Ð 0.55 - 0.7 source rock Poorly-drained Main oil Ð 0.7 - 1 source rock Late oil Ð 1 - 1.3 480 0 1 10 100 Wet gas Ð 1.3 - 2 TOC (%) a. d. a. Age (Ma) 250 200 150 100 50 0 100 0 12 Paleozoic Mesozoic Cenozoic 1000 Plankton and algae HI = 800 Tmax (¡C) 11 (variable sources) Permian Triassic Jurassic Cretaceous Tertiary 90 10 600 400 - 420 Open marine 10 9 E M L E M L E M L E L Paleogene Neogene 400 Shallow marine 420 - 435 or coastal 80 20 8 7 Source rock Type I kerogen Deltaic-terrigenous 200 435 - 445 6

70 30 Frequency Reservoir rock Tertiary coals 5 Type II kerogen Not C 4 Seal rock 100 available Uncommon 100 60 40 29 steranes (%) 3 Overburden rock Type III kerogen 2 50 50 1 Trap formation steranes (%) 28 0 C 012345678 Generation/migration/accumulation 40 60 Pr/Ph (a/b)

Rock-Eval S2 (kg/t) Pr/Ph b. 30 70 1.5 - 2 Figure 13.62 a. Burial history and modelled vitrinite reflectance history for well in the Tail End Graben; b. Event chart 10 2 - 3 20 80 for the Upper Jurassic Farsund Formation and the Middle Jurassic Bryne Formation in the Tail End Graben. 3 - 4

10 90 4 - 5 8¡E 10¡E

0 100 5 - 7 Bremen 0 1 10 100 100 9080706050403020100 TOC (%) C27 steranes (%) Not available 53¡N Cross-section POMPECKJ HIGH in Figure 13.64b b. e. EMSLAND LOW HI (mg/g TOC) Vitrinite reflectance (% Ro) 0 100 200 300 400 500 600 700 800 900 1000 0.0 0.4 0.81.61.2 2.0 400 S2 (kg/t) 0 Type III kerogen 410 2 - 5 Cross-section Type II kerogen 5 - 20 in Figure 13.64a 1 DALFSEN 420 Type I kerogen 20 - 50 HIGH LOWER SAXONY BASIN Hannover

430 50 - 100 Cenozoic 440 2 CENTRAL Upper NETHERLANDS 100 - 150 Cretaceous BASIN Lower BASIN M†NSTERLAND BASIN 450 150 - 225 Upper 0 100 km 52¡N ?ERODED THURINGIAN (¡C) 460 3 Middle Jurassic max

T Lower Present-day relics of basin 470 Depth (km) Lower Triassic Present-day distribution Wealden source rocks 4 Upper Oil 480 Permian Lower Major faults 490 Bo Member 500 5 Farsund Formation 510 Ula Formation Bryne Formation 520 6

c. f. 0 200 km

Figure 13.61 Geochemical data of samples from different Jurassic formations of the Tail End Graben: c. Tmax versus Production Index (PI). Maturity-induced depletion has led to well-drained source rock conditions; Figure 13.63 The Lower Saxony Basin petroleum province with locations of fields and accumulations charged by Wealden a. Pyrolytic yield (S2) versus TOC. In addition to many mature and non-source rock samples and a few immature coal d. Pr/nC17 versus Ph/nC18; source rocks. samples with type III kerogen there are a number of atypical samples with hydrogen-rich kerogen; e. Sterane ternary diagram;

b. Tmax versus Hydrogen Index (HI). Samples are mostly marginally mature to mature and comprise unusual type I kerogen f. Vitrinite reflectance plotted against sub-bottom depth. samples; Plots produced using IGI’s p:IGI-3.

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SSW SSE NNW SW NE S N Damme Trough Lembruch Steinfeld Trough Diepholz Rheden Dickel Donstorf Trough Aldorf RŸhle Annaveen Cenozoic Upper 0 0 Lower Cretaceous ÔWealdenÕ, BŸckeberg Formation 1 1 Upper Middle Jurassic Lower 2 2 Upper Middle Triassic 3 3 Depth (km) Depth (km) Lower Zechstein 4 4 Sub-Zechstein Fault 5 5 Unconformity 0 2 km a. b. Figure 13.64 Cross-sections through the Lower Saxony Basin (after Baldschuhn et al., 1996): a. Variability in thickness of the Wealden shale caused by variable subsidence rates; b. dominating structural traps in large anticlines in the area west of the Ems River. See Figure 13.63 for locations.

HI (mg/g TOC) Production index 0 100 200 300 400 500 600 700 800 900 1000 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.80.9 1.0 1000 400 400 Tmax (¡C) S2 (kg/t) TOC (%) HI = 800 Type III kerogen 2 - 5 0.5 -1 600 425 - 435 410 Type II kerogen 5 - 10 410 1 - 2 400 420 435 - 445 Type I kerogen 10 - 20 2 - 3 3 - 4 200 445 - 455 430 20 - 40 420 440 4 - 6 100 100 40 - 60 430 450 6 - 8 Type I kerogen (¡C) (¡C) 460 440 Type II kerogen max max T T 470

Rock-Eval S2 (kg/t) Type III kerogen 450 480

10 490 460

500 470 Well-drained source rock 510 Poorly-drained source rock 520 480 0 1 10 100 TOC (%) a. b. c.

Vitrinite reflectance (% Ro) 0.0 0.4 0.81.61.2 2.0 0 110 Terrestrial organic matter Biodegraded/immature Borehole Ð eastern Lower K15534_F2 10 Saxony Basin Mixed sources 100 Borehole Ð western Lower C29 steranes Marine organic matter Saxony Basin C steranes 90 27 0.5

80 Oxidising 1 Early mature 70 1 1000) × 17 60

Pr/nC 50 Depth (km) 1.5 Abundance ( 40 0.1 Reducing 30

2 Mature 20

10 0 50 µm 0.01 2.5 0 0.01 0.1 1 10 100 32 33 34 3536 37 3839 40 41 42N Ph/nC18 Time (minutes)

d. e. f. g.

Figure 13.65 Geochemical data from Wealden Shale formations in the Lower Saxony Basin: e. Vitrinite reflectance and Rock-Eval Tmax parameters plotted against sub-bottom depth; g. Reflected-light micrograph (blue fluorescence excitation) of particulate organic matter a. Pyrolytic yield (S2) versus TOC; f. Molecular biomarker characteristics of a Wealden Shale sample from the centre of the basin. The depicted m/z 217 trace in a Wealden paper shale sample. Note the bright background fluorescence due to dispersed

b. Tmax versus Hydrogen Index (HI); was reconstructed from the single parent-daughter transitions from the metastable reaction monitoring measurement. The organic material in addition to the small yellow alginite particles. c. Tmax versus Production Index (PI); similar abundance of the C27 and C29 steranes depicts a sedimentary environment with mixtures of algal and land plant Plots produced using IGI’s p:IGI-3. d. Pr/nC17 versus Ph/nC18; derived material;

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Chapter 13 — Petroleum generation and migration

Age (Ma) 2¡E 4¡E 6¡E 8¡E 150 100 50 0 Shallow gasfields Mesozoic Cenozoic 57¡N Bright spots Jurassic Cretaceous Tertiary

M L E L Paleogene Neogene

Source rock Reservoir rock Seal rock Figure 13.66 Event chart for the Wealden Overburden rock petroleum system in the Lower Saxony Basin Trap formation (after Kockel et al., 1994). Lower Cretaceous traps Generat./migrat./accum. are stratigraphic (facies and unconformity traps) Preservation whereas the predominant Upper Cretaceous traps 56¡N Critical moment are mostly structural.

Bright spots are common and among the best known direct hydrocarbon indicators in seismic data. They appear as strong-amplitude anomalies in seismic sections of different sedimentary and tectonic settings. They may indicate the presence of microbial as well as thermogenic gas and have been used in petroleum exploration since the 1970s.

Bright spots are induced by strong variation in seismic impedance in the rocks (i.e. seismic velocity and/or density changes). A single sudden increase of impedance with depth generates a seismic signal of

unambiguously positive polarity (‘hard kick’). A sharp decrease in velocity and/or density results in negative 55¡N polarity of the pertinent seismic reflection (‘soft kick’). The reasons for increasing velocity include sediment cementation or igneous intrusions. Coal beds, peat, gas-charged or over-pressured sediments lead to decreasing velocity (Figure 13.68). The tuning effect of thinly bedded interfaces can also cause bright spots without a particular correlation between sediment properties and polarity of seismic response. Bright spots occur in a variety of petroleum trap systems, for example in anticlines and pinch-out traps.

3.1 Bright spots in anticlines

Salt tectonics have produced numerous anticlines in the shallow subsurface of the southern North Sea and northern Europe. These anticlines can serve as structural traps for hydrocarbons. The correlation of salt domes and bright spots can be established in the central and southern part of the north-western 54¡N German sector (the so-called ‘Entenschnabel’) and in the adjacent Danish and Dutch sectors in the Central and Step grabens. In most cases, the bright spots agglomerate in a circular pattern above the crest of salt diapirs where a complex system of crestal faults has developed. Along these faults, and often unilaterally aligned with them, numerous bright spots are observed that can be explained by either migration of gas 0 100 km along the faults into layers with higher permeability or by in situ generation of microbial methane 0 200 km trapped against sealing faults (Figures 13.69 & 13.70). Figure 13.67 Distribution of bright spots and amplitude anomalies in the southern North Sea. Bright spots are observed on 2D- and 3D-seismic data as high amplitudes, probably caused by microbial or thermogenic gas in the pore fluid. Most Well data confirmed the increase in methane concentrations in sandy layers above the salt diapirs. The bright spots were found at the top of Pliocene sands. Linear alignments of some bright spots in the English and German available seismic data elsewhere in the German sector of the southern North Sea show a lack of bright North Sea sectors are related to the locations of the 2D-seismic lines used rather than to geological structures.

spots associated with salt tectonics. Common -depth points 2632 25782525 2472 24182365 2312 22582205 2152 20982045 1992 19381885183217781725 1672 16181565 0 Gas is produced from shallow gasfields in the Netherlands and Denmark. The sources of these shallow-gas occurrences might be deeper lying source rocks, i.e. the gas is of thermogenic origin. First analyses of gas 0.1 samples from the sea floor in the ’Entenschnabel’ corroborate the assumption that gas of thermogenic 0.2 origin migrates from deeper sources towards the sea bed. 0.3 3.2 Bright spots in pinch-out traps 0.4

Bright spots may occur where porous strata pinch-out due to facies change or where they were 0.5 erosionally truncated and terminate against a seal (Figure 13.71). Pinch-out traps are common in fluvial 0.6 and delta foresets or beneath unconformities. The Baltic River System, which developed from mid- 0.7 Miocene times and occupied a large area of the southern North Sea (Chapter 12), offers appropriate Base Upper North Sea Group (base Neogene) conditions for this trap type due to the common development of inclined horizons. Negative polarity Two-way travel time (s) 0.8 (‘soft kick’) of the bright spots is considered to be an indicator of gas beneath the pertinent interface. 0.9 Gas chimneys are characterised by a zone or column of reflections that are discontinuous, chaotic, Figure 13.68 Bright spots caused by peat and shallow gas in the Dutch North Sea sector. The interpreted 1.0 and/or attenuated in comparison with the adjacent sediment (Figure 13.72). This type of amplitude horizon is the Mid-Miocene Unconformity. High amplitudes between the common depth point (CDP) 2300 anomaly is indicative of the leakage of fluids, including hydrocarbon gas, from a deeper reservoir. Many 1.1 and 2600 are probably caused by a peat layer close to the sea floor. The associated high amplitudes in the of the seismic anomalies indicating leakage are found in places where there are salt domes and where subsurface are sea level and inter-bed multiples. The bright spot between CDP 1600 and 1700 at about 1.2 the associated normal faults provide effective migration pathways for thermogenic gas from deeper 0.4 s two-way travel time on top of a salt diapir is from an unconsolidated gas-charged Pliocene sand reservoirs. layer. The gas is probably thermogenic and comes from a deeper source. A push-down effect occurs at 0 2 km about 0.9 s beneath the gas reservoir. There are indications of a gas chimney at around CDP 2100.

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Acknowledgements 0.5

0.6 We express our gratitude to the following for their contributions to our chapter: Hilmar Rempel, Michael Lines, Rene Thomsen and Jean-Pierre Houzay critically revised sections of the manuscript and provided 0.7 constructive comments. J.F. Deconinck (Univ. Dijon) and F. Baudin (Univ. Paris) made Rock-Eval data 0.8 from the Wessex Basin available. Aenne Balke, H. Keppler, Georg Scheeder, M. Weiss (BGR, Hannover), Tove Nielsen (GEUS, Copenhagen), B. Herrmann (LBEG, Hannover), J. Hettelaar, Harry Veldt (TNO, Utrecht) 0.9 and Franz Kockel (Grossburgwedel) provided important interpretive or technical support. The geochemical 1.0 plots in this chapter have been produced using IGI’s p:IGI-3 software.

1.1

1.2 Two-way travel time (s)

1.3

1.4

1.5

1.6 Figure 13.69 Fault-related bright spot in the Dutch North Sea sector. The gas-charged Pliocene sediments are located on top of a salt diapir. The fault probably acted as a conduit for thermogenic gas from a deep- 0 2 km seated source. The interpreted horizon is the Mid-Miocene unconformity.

0 0

Fault 0.5 Bright spots 0.5 Chimney

1 1 Two-way travel time (s) Two-way travel time (s) Figure 13.72 Chimney induced by gas-rich pore fluids, where gas is rising from deeper sources vertically or 1.5 diagonally along faults towards the sea bed and locally 1.5 Top of salt diapir increases the gas content of the sediment. Note the chaotic reflection pattern in the upper 0.3 s TWT and 0 1 km the push-down effect of reflections at about 0.9 s 0 1 km and 1.25 s. Figure 13.70 Bright spots above a diapir in the German North Sea sector. Bright spots between 0.4 to 0.8 s two-way travel time are probably related to gas-charged sediments. The bright spot around 1.6 s TWT is interpreted as amplitude anomalies induced by well-cemented caprocks at the top of the diapir. The chimney pattern is probably the result of destruction of stratification by overpressure or from the inhomogeneous distribution of gas within the sediments, which lead to variations in seismic velocities 0 and chaotic reflections in the seismic profile. Because p-wave velocities of gas-charged porous sediments 0.1 are lower than those of the same sediment with a liquid pore fluid, reflections beneath a gas chimney commonly display a push down effect (Figure 13.68). 0.2 Possible chimney 0.3 Other direct hydrocarbon indicators are common (pockmarks at the sea bed, acoustic blanking and acoustic turbidity near the surface) although they are difficult to identify on standard petroleum 0.4 industry seismic data. Acoustic blanking, places where there are weak or absent reflections on seismic profiles, may occur where gas-charged sediment overlie the blanked zone and reduce the energy of the 0.5 seismic wave, or where rising gas has disrupted the sediment structure/bedding. Gas concentrations of

Two-way travel time (s) 0.6 0.5% are sufficient to cause acoustic blanking. Acoustic turbidity is a laterally limited zone of chaotic Pinch-out trap seismic reflections on seismic data. Reflectors within these zones appear weakened and/or chaotic. 0.7 This may result from the disruption of the sedimentary reflectors by over-pressured fluids or from inhomogeneous gas distribution within the sediment. Both acoustic blanking and turbidity can best 0.8 be observed on high-frequency seismic data. 0 5 km For further information see Schroot & Schüttenhelm (2003), Schroot et al. (2005), Judd & Hovland (2007) Figure 13.71 Bright spot in a pinch-out trap in the German North Sea sector. The amplitude of the marked anomaly and Kuhlmann & Wong (2008). increases updip. This may be related to the presence of gas in the layer, which accumulates in the upper part of the structure where it increases the acoustic impedance contrast at its top interface.

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