Geological Resource Analysis of Shale Gas and Shale Oil in Europe

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Draft Report for DG JRC in the Context of Contract JRC/PTT/2015/F.3/0027/NC "Development of shale gas and shale oil in Europe"

European Unconventional Oil and Gas Assessment (EUOGA)

Geological resource analysis of shale gas and shale oil in Europe

Deliverable T4b

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Geological resource analysis of shale gas/oil in Europe

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Geological resource analysis of shale gas/oil in Europe

Table of Contents

Table of Contents ...... 3 Abstract ...... 6 Executive Summary ...... 7 Introduction ...... 8 Item 4.1 Setup and distribute a template for uniformly describing EU shale plays to the National Geological Surveys ...... 12 Item 4.2 Elaborate and compile general and systematic descriptions of the shale plays from the NGS responses ...... 15 T01, B02 - Norwegian-Danish-S. Sweden – Alum Shale ...... 16 T02 - Baltic Basin – Cambrian-Silurian Shales ...... 22 T03 - South Lublin Basin, Narol Basin and Lviv-Volyn Basin – Lower Paleozoic Shales ...... 37 T04 - Moesian Platform and Kamchia Basin ...... 41 T05 - Ukraine – Dnieper-Donets Basin Lower Carboniferous Black Shales ...... 59 T06 - Poland – Lower Carboniferous shales of the Fore-Sudetic Monocline Basin ...... 63 T07a - Hungary – Kössen Marl, Zala Basin ...... 70 T07b - Hungary – Tard Clay, Hungarian Palaeogene Basin ...... 76 T07c - Pannonia, Mura-Zala Basin - Haloze-Špilje Fm. Shale ...... 82 T08 - Vienna Basin – Mikulov Marl ...... 86 T09 - Lombardy Basin (Italy) – Triassic – E. Cretaeous shales ...... 96 T10, T22, T23, T24, T33 - Northwest European Carboniferous Basin (Central Europe) ...... 103 T11 - Emma, Umbria-Marche Basins (Italy) – Triassic – E. Cretaceous shales ...... 116 T12 - Ribolla Basin (Italy) – Argille Lignitifere ...... 128 T13 - Ragusa Basin (Italy) – Triassic shales ...... 132 T14 - Dinarides – Lemeš ...... 137 T15a – Cantabrian Massif ...... 141 T15b – Basque-Cantabrian Basin ...... 145 T16 - Guadalquivir ...... 151 T17 - Ebro ...... 155 T18 - Duero ...... 159 T19 – Iberian Chain ...... 162 T20 – Catalonian Chain ...... 167 T21 - Pyrenees ...... 170 T25 - Northwest European Basin (Central Europe) – Mesozoic shales ...... 176 T26 – Paris Basin and Autun Basin – Permo-Carboniferous and Jurassic shales ...... 190 T27 - Aquitaine ...... 196 T28 - South Eastern basin ...... 199 T30 – Lusitanian Basin, Portugal ...... 203 T31, T32 – Southern Germany – Mesozoic shales ...... 210 T34 - Midland Valley Scotland ...... 213 T35 – Czech Republic – Lower Carboniferous shales of the Culm Basin ...... 219 T36 - Caltanissetta Basin (Italy) – Messinian shales ...... 224 B01 - Transilvanian Basins – Neogene Shales ...... 227

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Geological resource analysis of shale gas/oil in Europe

This report is prepared by Susanne Nelskamp and the TNO EUOGA team, (TNO- Geological Survey of the Netherlands) in March 2017, as part of the EUOGA study (EU Unconventional Oil and Gas Assessment) commissioned by JRC-IET. The report is based on information gathered from European National Geological Surveys (NGS’) between February and December 2016. The report is a draft version and a final version will be issued later as part of the project.

The information and views set out in this study are those of the author(s) and do not necessarily reflect the official opinion of the Commission. The Commission does not guarantee the accuracy of the data included in this study. Neither the Commission nor any person acting on the Commission’s behalf may be held responsible for the use which may be made of the information contained therein.

No third-party textual or artistic material is included in the publication without the copyright holder’s prior consent to further dissemination and reuse by other third parties. Reproduction is authorised provided the source is acknowledged.

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Geological resource analysis of shale gas/oil in Europe

Citation to this report is Nelskamp, S., 2017. Geological resource analysis of shale gas and shale oil in Europe. Report T4b of the EUOGA study (EU Unconventional Oil and Gas Assessment) commissioned by JRC-IET. Invited Countries Completed EUOGA association status questionnaire Austria Yes Participant Belgium Yes Participant Bulgaria Yes Participant Croatia Yes Participant Cyprus no No known resources Czech Republic Yes Participant Denmark Yes Participant Estonia Yes No known resources Finland Yes No known resources France Yes Participant Germany No The NGS are not able to participate in EU tenders Greece No The NGS have decided not to participate Hungary Yes Participant Ireland Yes The NGS have decided not to participate Italy Yes Participant Latvia Yes Participant Lithuanian Yes Participant Luxembourg No No known resources Malta Yes No known resources Netherlands Yes Participant Norway Yes No known resources on-shore Poland Yes Participant Portugal Yes Participant Romania Yes Participant Slovakia Yes The NGS have decided not to participate Slovenia No Participant Spain Yes Participant Sweden Yes Participant Switzerland No The NGS have decided not to participate United Kingdom Yes Participant Ukraine yes Participant Overview of countries invited to participate in EUOGA and their association to the project.

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Geological resource analysis of shale gas/oil in Europe

Abstract Within task 4 of the EUOGA Project the geological descriptions of the different basins within Europe and the potential shale gas targets in the basin were collected and summarized. A general template for the description was developed, and, based on the information provided by the National Geological Surveys (NGS), completed for each submitted basin and formation. In addition to the geological descriptions, general hydrocarbon play indicators were assessed in order to indicate whether a shale formation is present and whether it contains technically recoverable hydrocarbon resources (hereafter: chance of success). This assessment was performed in a consistent and uniform manner for each formation and involved a semi-quantitative scoring of critical data for assessing (1) the presence and characteristics of the shale formation, (2) overall sedimentological and structural complexity influencing hydrocarbon generation and distribution, (3) the probability of an existing shale gas/oil system (organic content, maturity, proven hydrocarbon generation) and (4) geological factors influencing the technical recoverability of hydrocarbon resources contained in the shale (depth of the formation and mineralogical composition). The results from Task 4 are used as a basis for the quantitative volume assessment of potential shale hydrocarbon resources under Task 7.

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Executive Summary Task 4 delivered the geological descriptions and unconventional hydrocarbon play characteristics of 82 shale formations occurring within 38 sedimentary basins across Europe. National Geological Surveys (NGS) participating in the EUOGA project provided all public data and information available from their respective countries, using a common description template developed by the EUOGA project team members. Further input was obtained from the data retrieval under Task 5 and Task 6.

The analysis of the basins includes (1) the general description of the basins and formations, (2) the link to the CP sheets (Screening_ID) and the GIS environments generated in Tasks 5 and 6, (3) the geographical extent of the basin, (4) the assessed formations within the basin (in figure), (5) a brief description of the depositional and structural setting of the basin, (6) a description of the individual shale formations in the basin, with depth, thickness and shale gas/oil properties, and (7) a chance of success assessment.

The chance of success assessment describes all formations in a semi-quantitative scoring on the distribution of the shale, the hydrocarbon system and the recoverability of the resources. It focuses on the presence and characteristics of the shale formation, overall sedimentological and structural complexity influencing hydrocarbon generation and distribution, the probability of an existing shale gas/oil system (organic content, maturity, proven hydrocarbon generation) and geological factors influencing the technical recoverability of hydrocarbon resources contained in the shale (depth of the formation and mineralogical composition).

The availability and quality of information as well as the level of knowledge regarding shale formations and prospective hydrocarbon resources therein, differs greatly per basin and per country. Overall some 78% of the formations are considered to be reasonably well understood with fair to good information coverage. In these cases there is often a good indication that mature and gas/oil-bearing shales are present.

The reliability and accuracy of the analysis of chance of success also strongly depends on the completeness and quality of the basin descriptions, but also on how well these descriptions can be translated into the specified categories. The certainty by which the presence of a shale can be predicted is strongly depending on the available information from wells and seismic. In mature hydrocarbon provinces the data density is generally high enough to accurately map the outline of a prospective shale formation. However, in many of the underexplored regions the exact outline of the formation is less well established, especially when the shale distribution within the given outline is known to be heterogeneous. The presence of a mature and hydrocarbon generating shale formation can be predicted more reliably when conventional oil and gas accumulations are identified in the same basin. The presence of conventional resources however, does not tell whether the shale resources are also recoverable. The recoverability is the most challenging risk factor in shale gas and shale oil development as this is depending mainly on the local conditions and information for shale plays in Europe is very sparse.

The results of this assessment are summarized in Appendix A of this report and in the Appendix of report T7b.

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Introduction This report presents the first standardized geological descriptions for the countries where information was available. The general geological description of the shale gas and oil layers that were submitted by the individual geological surveys are compiled and standardized. These descriptions have been circulated back to the geological surveys for confirmation and correction.

Special focus is set on the description of so called risk-components that is incorporated into the final assessment of the layers. In this first step the overall chance of success of the shale layer as well as the presence of mature organic matter is incorporated.

Figure 1 Overview of the sedimentary basins of Europe and the basins assessed in the EUOGA project. The T-numbers are the basin identifyers for each basin (see table 1). For some of the asessed units no outline is available.

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Table 1 Overview of the described basins and shale formations in this report

Basin Country Basin name Screening Shale name index code ID B1 RO Transylvania 1041 1042 B2 SE Fennoscandian Shield 1017 Alum Shale O1 RO Black_sea 0 BG Kamchia basin 1060 Oligocene shale T1 SE Norwegian-Danish-Scania 1015 Alum 1016 Alum DK Norwegian-Danish-Scania 1019 Alum T2a LV Baltic Palaeobasin 1001 No name SE Baltic Basin 1014 Alum Shale Sorgenfrei Tornquist Zone 1015 Alum Shale DK Norwegian-Danish-Scania 1019 Alum LT Baltic Sedimentary Basin 1061 Upper Ordovician-Llandovery Shales T2b PL Baltic Basin 1051 Lower Palaeozoic shales T2c PL Płock-Warsaw zone 1052 Lower Palaeozoic shales T2d PL Podlasie Basin and North 1053 Lower Palaeozoic shales Lublin Basin T3 PL South Lublin Basin and Narol 1054 Lower Palaeozoic shales Basin UA Lviv-Volyn Basin 1062 Black Shale T4a BG Moesian Platform 1056 Lower Paleozoic shale T4b RO Moesian 1038 1039 1040 BG Moesian Platform 1057 Upper Paleozoic shale Moesian Platform - 1058 J1 shale & clay limestones Forebalkan 1059 J2 shale Kamchia basin 1060 Oligocene shale T5 UA Dniper Donetsk Basin 1043 Black Shale T6 PL Carboniferous basin of Fore- 1055 Lower Carboniferous shale Sudetic Monocline T7a HU Zala Basin 1049 Kössen Marl T7b HU Hungarian Paleogene Basin 1050 Tard Clay T7c SI Mura-Zala Basin 1066 Haloze-Špilje Fm. Shale 1067 Haloze-Špilje Fm. Shale T8 AT Vienna Basin 1018 Mikulov Marl CZ SE Bohemian Massif 1063 Mikulov Fm. T9 IT Lombardy Basin 1005 Meride

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Basin Country Basin name Screening Shale name index code ID 1006 Riva_di_Solto 1007 Marne di Bruntino T10a NL Northwest European 1064 Geverik Member Carboniferous Basin T10b UK Wales-East Midlands 1077 Bowland-Hodder T11a IT Umbria - Marche Basin 1009 Marne del Monte Serrone 1010 Marne a Fucoidi T11b IT Emma Basin 1008 Emma Limestones T12 IT Ribolla Basin 1011 Argille lignitifere T13 IT Ragusa 1012 Noto 1013 Streppenosa T14 HR Dinarides Mts. 1004 Lemeš T15 ES Basque-Cantabrian 1027 Basque-Cantabrian Liassic 1028 Basque-Cantabrian Lower Cretaceous 1029 Basque-Cantabrian Upper Cretaceous 1030 Basque-Cantabrian Carboniferous Cantabrian Massif 1031 Cantabrian Massif Carboniferous 1032 Cantabrian Massif Silurian T16 ES Guadalquivir 1026 Guadalquivir Carboniferous T17 ES Ebro 1024 Ebro Carboniferous 1025 Ebro Eocene T18 ES Duero 1023 Duero Carboniferous T19 ES Iberian 1021 Iberian Lower Cretaceous 1022 Iberian Carboniferous T20 ES Catalonian Chain 1020 Catalonian Chain Carboniferous T21 ES Pyrenees 1033 Pyrenees Liassic 1034 Pyrenees Lower Cretaceous 1035 Pyrenees Eocene T22 BE Campine Basin 1045 Westphalian A and B Formations 1048 Chokier & Souvré hot shales T23 BE Mons Basin 1046 Chokier shales T24 BE Liège Basin 1047 Chokier alum shales T25a NL West Netherlands 1065 Posidonia Shale Basin/Broad 14s Basin T25c DE Northwest German Basin 0 Blättertone/Fish Shale 0 Mid Rhaetian shale 2012 Wealden

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Basin Country Basin name Screening Shale name index code ID 2012 Posidonia Shale T25c DE Northwest German Basin 2012 Posidonia Shale and and Upper Rhine Graben T32 T25d UK Weald Basin SE England 1070 Kimmeridge Clay 1074 Mid Lias Clay 1075 Oxford Clay 1076 Upper Lias Clay 1078 Corallian Clay T26a FR Paris Basin 1082 Promicroceras 1083 Amaltheus 1084 Schistes Carton T26b FR Autun Basin 1081 Autun T27 FR Aquitaine Basin 1085 Suzanne Marls T28a FR South Eastern Basin 1084 Schistes Carton T28b FR Stephano-Permian Basin 1080 Permo-Carboniferous T30 PT Lusitanian basin 1087 T31 DE Upper Rhine Graben and 0 Fish shale and Molasse Basin T32 T33 DE Northern Germany 2013 Hangender Alaunschiefer and Kohlenkalk-Facies T34 UK Midland Valley Scotland 1071 Limestone Coal Fm 1072 West Lothian Oil Shale unit 1073 Lower Limestone Fm 1079 Gullane Unit T35 CZ Culm Basin 1086 Culm Shale T36 IT Caltanissetta Basin 0 Sapropelic marls/Tripoli

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Item 4.1 Setup and distribute a template for uniformly describing EU shale plays to the National Geological Surveys

Basin Index – Basin name – Shale name

General information

Table 4.1 The general information is compiled together with GEUS (Task 5 and 6) Screening- Index Basin Country Shale(s) Age Index

Geographical extent (incl. map if available) A brief description of the geographical extent of the basin and the described shale layers within.

Geological evolution and structural setting

Syndepositional setting A brief description of the syndepositional geological evolution at the time of the deposition of the shale layers. In this part the following questions are answered: What is the lateral continuity of the shale? In what type of depositional system was the shale deposited? Can we expect significant facies changes within the basin? Are there significant changes in thickness within the basin?

Structural setting The structural history of the basin after the deposition of the shales. In this part the following questions are addressed: Did any tectonic processes influence the lateral continuity of the shale? Are there areas with significant erosion or faulting? Here the preservation of generated oil and gas is also addressed by giving a brief description of the basin history including time of maximum burial/temperature of the shale and major erosion phases that can influence the preservation of generated hydrocarbons if available.

Organic-rich shales A short description of the shale layer, e.g. sedimentary features. This description is given per individual shale layer separately. In the case that there is only one shale layer in the basin this description will be left out as it is already covered in the syndepositional chapter of the geological evolution.

Depth and thickness The average depth and thickness of the layer and if known the depth and thickness trends throughout the basin for each shale layer.

Shale gas/oil properties Maturity, total organic carbon content (TOC) and other organic petrographic parameter. How much organic matter is present in the shale and what do we know about the lateral extent and type of organic matter? Is there an established hydrocarbon system in the basin that is sourced by the shale? Are there any known

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hydrocarbon fields that are sourced by the shale? Where are these located within the basin? Are there any gas shows on logs of the shales? What is the maturity of the shale? How does the maturity change throughout the basin? Is the system biogenic or thermogenic?

Chance of success component description In the chance of success component description the previously described depositional and structural setting as well as shale properties are summarized and categorized for the general assessment. The subdivision in these categories gives a general overview of the success factors associated with the shale gas/oil system. In the final report of WP 4 a summary table with the categories for all assessed shales is presented. This overview gives a general idea of the type of shale, its complexity and amount of data. This is used to categorize and compare the overall uncertainty that is associated with the assessment. For example shales with little data and high structural complexity have a high chance of not containing any gas compared to shales with a large amount of data, good seismic interpretation and known HC content and mineral composition. The results of this classification are also taken into account in the final GIIP/OIIP calculation, where few data/low chance of success shales are assigned a higher range of values and therefore a higher uncertainty.

Occurrence of shale

Mapping status Poor no map, only outlines Moderate depth map, thickness map based on interpolation/average values (few datapoints) Good seismic interpretation, interpolated map (many datapoints)

Sedimentary variability High very strong local differences, difficult to predict Moderate depositional environment changes gradually throughout the basin Low very homogeneous character throughout the basin

Structural complexity High thrust setting, mountain belt, drastic compression Moderate layer faulted, locally eroded, subsidence, uplift and salt tectonics Low layer cake setting, predominantly steered by subsidence

HC generation

Available data Poor no data Moderate few data points (< 20) Good good database (>20)

Proven source rock Unknown no information Possible HC shows and accumulation in other setting probably from same SR Proven HC fields in study area proven to be sourced from shale gas layer

Maturity variability High high local maturity variations (related to excessive faulting or magmatism) Moderate basin wide trends related to present or past burial depth variations Low very similar maturity throughout the basin

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Recoverability

Depth Shallow <1000m Average 1000-5000m Deep >5000m

Mineral composition No data average mineral composition was not provided Unknown average mineral composition does not allow any assumptions on fraccability Favourable brittle mineral composition (>80% carbonates and/or quartz), fracturing tests, log interpretation Poor very clay rich (>50% clay content)

References

All relevant literature references for the basin

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Item 4.2 Elaborate and compile general and systematic descriptions of the shale plays from the NGS responses

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T01, B02 - Norwegian-Danish-S. Sweden – Alum Shale

General information Screening- Index Basin Country Shale(s) Age Index M. S Alum Shale Cambrian-L. 1015 Norwegian- Ordovician Danish- M. T1 S.Sweden S Alum Shale Cambrian-L. 1016 (Caledonian Ordovician foreland) M. DK Alum Shale Cambrian-L. 1019 Ordovician Fennoscandian Cambrian- B2 S Alum Shale 1017 shield Ordovician

Geographical extent The Alum shale is present in the Norwegian-Danish-S.Sweden Basin (Center and rim of N. Permian basin) and the Baltic basin (Bornholm area). It was mainly preserved in the former Caledonian foreland (Tornquist Sea), the remnants of which are presently situated north of the Trans European Suture Zone Fault (Thor-Tornquist Suture or Thor Suture through southern Denmark) bounded to the south by the Ringkøbing-Fyn High (Figure 2; an area also referred to as the Tornquist Fan). For this area, the Alum Shale is assumed to occur in all areas where the Lower Paleozoic is present.

Figure 1 – Distribution of the Lower Palaeozoic strata. The coloured areas represent different basins.

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Figure 2 Terranes amalgamated to form Laurussia. Non-palinspastic map after Pharaoh et al. (2010) and sources therein. Note that the Rheno-Hercynian Zone is interpreted as the Variscan-deformed southern margin of Laurussia.

Geological evolution and structural setting

Syndepositional setting The sediments of the Alum Shale formation were deposited in an epicontinental sea at the passive margin of Baltica during Middle Cambrian to Early Ordovician opening of the Iapetus/Tornquist Ocean. During maximum flooding in the Early Ordovician, organic-rich intervals were deposited over an area of more than 1,000,000 km2 (Nielsen and Schovsbo, 2011). Deposition was influenced by synrift extentional tectonics. The Alum organic-rich shales mainly represent an outer-shelf environment shale and are intercalated with some limestone and antraconite interbeds. Generally, lateral continuity is high and facies variability low.

Structural setting During the Early Ordovician, Avalonia drifted away from Gondwana (Trench & Torsvik, 1992), northwards in connection to opening of the Rheic Ocean (Cocks & Fortey, 1982) to the south of Avalonia. Subduction of the Iapetus/Tornquist Ocean in a number of southerly dipping subduction systems also triggered this drift (Figure 2). Evidence of the subduction of oceanic crust of the Iapetus/Tornquist Ocean beneath Avalonia is shown by the Middle to Upper Ordovician calc-alkaline volcanic rocks found in England and Belgium (Pharaoh, 1999). During Llandovery and Wenlock times, the Tornquist Ocean, initially characterized as a passive margin of Baltica, evolved into a major subsiding foreland basin north of the Silurian Avalonian-Baltica convergence zone (Schovsbo, 2003) and the Danish-North German-Polish Caledonides. Basin

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modelling suggests that the Silurian subsidence and related high temperatures caused the Alum shales within the Caledonian foreland basin to be at least in the oil maturity zone (Gautier et al. 2013). In most areas deep burial resulted in temperatures sufficient to bring the organic matter to a maturation rank of dry gas, cracking previously formed oil.

In addition to the Middle Cambrian to Lower Ordovician Alum Shale deposits there are some organic-rich Silurian shales formed in the same basin. These are named the Rastrites and the Cyrtograptus shales. They are however, in comparison to the Alum Shale thinner and less TOC-rich Alum Shale and consequently not incorporated in the EUOGA project.

Continental convergence during Silurian times led to the complete closure of the Tornquist Ocean. The development of a thrust-and-fold belt and its successive movement over the south-west margin of Baltica led to further subsidence (Poprawa et al., 1999) and synsedimentary compressive tectonics in the foreland (Beier et al., 2000) generating thrusts and faults in the Alum Shale Formation.

Following the end-Silurian accretion of Avalonia to Baltica, orogen-parallel collapse of the Arctic-North Atlantic Caledonides commenced under a sinistral transtensional setting during the latest Silurian and Early Devonian, as shown by the development of intramontane Old Red Sandstone basins and the widespread granitic plutonism commonly seen in northern England (Ziegler, 1989; Braathen et al., 2002). The Early Devonian tectonic evolution affected the lower Palaeozoic shales throughout Denmark and adjacent areas, bringing the shales up to depths <1,000 m in some areas.

In the Carboniferous and early Permian, the Palaeozoic succession was faulted, tilted and subjected to intensive erosion (Variscan unconformity; (Mogensen and Korstgård, 2003). Consequently, the Palaeozoic shales occur today as remnants in tilted fault blocks, which include strata as young as earliest Permian. The fault blocks are preserved beneath the Variscan unconformity and overlain by rocks of the Late Permian and younger strata. Local Permo-Carboniferous igneous intrusions are not assessed to have affected the regional maturity.

Discontinuous subsidence occurred in the Permo-Triassic, Early Cretaceous, and Paleogene, followed by uplift in the late Neogene and by glacial erosion in the Pleistocene.

Basin modelling suggests that the thermal rank reached during the early Palaeozoic was never exceeded during the reburial phases. Therefore, a second episode of gas generation is considered unlikely, except in the deeper parts of the Danish-Norwegian Basin where the present-day depth of the lower Palaeozoic exceeds 7 km (Lassen and Thybo, 2012).

Organic-rich shales

Depth and thickness In northern Denmark the Alum Shale can reach 180 meters (m) in thickness (Nielsen and Schovsbo, 2006). Southward it thins to <20 m, probably as a result of syndepositional uplift and erosion near the margins of the Baltic Shield. Consequently Palaeozoic shales are not considered to be potentially productive south of the Ringkøbing-Fyn High in Denmark. A complex structural history underlies the present- day depth distribution between 1.5 and 7 km.

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Shale gas/oil properties The Alum Shale contains a marine type II kerogen that yields lighter hydrocarbons on maturation than typical type II kerogen (see Sanei et al., 2014 for a recent review). In most areas thick overlying successions of sedimentary strata buried the Alum Shale (and other lower Palaeozoic shales) to depths of 4 to 5 km, bringing them to thermal maturity for oil and gas (greater than 2-percent graptolite reflectance; 1.6-percent Ro, vitrinite reflectance-equivalent maturity, Buchardt and others, 1997; Petersen and others, 2013). It is assumed that, given the thickness and richness of the shales (TOC’s up to 17%), this burial history resulted in the generation of large volumes of hydrocarbons. A TOC loss with maturity appears to exists (Schovsbo et al., 2014) as immature shales have average TOC’s of 8-12% (H/C high), whereas shales in the dry gas window have TOC’s between 6-8% (H/C low).

Gas content are about 30 scf/ton in exploration wells in Scania and nortern Denmark (Ferrand et al. 2016; Pool et al. 2012). In scientific wells both termogenic and biogenic gas has been observed (Schultz et al. 2015; Schovsbo & Nielsen 2017).

The prospective areas, based on thickness and burial depth (Schovsbo et al., 2014, their Fig. 3) largely follow the margins of the Norwegian–Danish Basin. Sweet spots were defined as fault blocks that contain Alum Shale thicker than 20 m, gas mature and within a current depth interval of 1.5–7 km. Additionally, the probability of gas retention within is regarded highest if the shale is overlain by more than 1 km of Palaeozoic strata, i.e., areas that underwent less intensive Late Palaeozoic uplift and erosion (Schovsbo et al. 2014).

Chance of success component description

Occurrence of shale

Mapping status Moderate

Sedimentary Variability Low Deposited in an epicontinental sea at the passive margin of Baltica.

Structural complexity High The development of a thrust-and-fold belt and its successive movement over the south-west margin of Baltica led to further subsidence and synsedimentary compressive tectonics in the foreland generating thrusts and faults in the Alum Shale Formation.

HC generation

Data availability Moderate

HC system Possible Few proposed accumulations in offshore Poland and Gotland. Alum Shale drilled in Northern Jutland in 2015. According to industry report the shale was thinner than expected (40 m) and had a low gas content of 30 scf/ton.

Maturity variability Moderate

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Recoverability

Depth Shallow to Deep

Fraccability Unknown

References Beier, H., Maletz, J. & Böhnke, A., 2000. Development of an Early Palaeozoic foreland basin at the SW margin of Baltica. Neues Jahrbuch für Geologie und Paläontologie, Abhandlungen 218: 129-152. Braathen, A., Osmunden, P.T., Nordgulen, Ø., Roberts, D. & Meyer, G.B., 2002. Orogen-parallel extension of the Caledonides in northern Central Norway: an overview. Norwegian Journal of Geology 82: 225-241.

Buchardt, B., Nielsen, A.T. & Schovsbo, N.H. 1997: Alun Skiferen i Skandinavien. Geologisk Tidsskrift 1997(3), 1–30.

Cocks, L.R.M. & Fortey, R.A., 1982. Faunal evidence for oceanic separations in the Palaeozoic of Britain. Journal of the Geological Society 139: 465-478. Gautier, D.L., Charpentier, R.R., Gaswirth, S.B., Klett, T.R., Pitman, J.K., Schenk, C.J., Tennyson, M.E., and Whidden, K.J., 2013, Undiscovered Gas Resources in the Alum Shale, Denmark, 2013: U.S. Geological Survey Fact Sheet 2013–3103, 4 p., http://dx.doi.org/10.3133/fs20133103

Ferrand, J., Demars, C., Allache, F., 2016. Denmark - L1/10 Licence relinquishment recommendations report. Total E&P, Memo 1-9. Available from: http://www.ft.dk/samling/20151/almdel/efk/bilag/353/1651289.pdf. Verified 29.3.2017.

Lassen, A. & Thybo, H. 2012: Neoproterozoic and Palaeozoic evolution of SW Scandinavia based on integrated seismic interpretation. Precambrian Research 204– 205, 75–104.

Mogensen, T.E. & Korstgård, J.A. 2003: Triassic and Jurassic transtension along part of the Sorgenfrei–Tornquist Zone, in the Danish Kattegat. In: Ineson, J.R. & Surlyk, F. (eds): The Jurassic of Denmark and Greenland. Geological Survey of Denmark and Greenland Bulletin 1, 439–458.

Nielsen, A.T. & Schovsbo, N.H. 2011: The Lower Cambrian of Scandinavia: depositional environment, sequence stratigraphy and palaeogeography. Earth Science Reviews 107, 207–310.

Nielsen, A.T., Schovsbo, N.H. (2006) Cambrian to basal Ordovician lithostratigraphy in southern Scandinavia. Bulletin of the Geological Society of Denmark, 53, 47-92.

Petersen, H.I., Schovsbo, N.H. & Nielsen, A.T. 2013: Reflectance measurements of zooclasts and solid bitumen in Lower Palaeozoic shales, southern Scandinavia: correlation to vitrinite reflectance. International Journal of Coal Petrology 114, 1–18.

Pharaoh, T.C., 1999. Palaeozoic terranes and their lithospheric boundaries within the Trans-European Suture Zone (TESZ): a review. Tectonophysics 314: 17-41.

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Pharaoh, T.C., Winchester, J.A., Verniers, J., Lassen, A. & Seghedi, A., 2006. The Western Accretionary Margin of the East European Craton: an overview. In: Gee, D.G. and Stephenson, R.A. (Eds): European Lithosphere Dynamics. Geological Society Memoir (London): 291-312.

Pharaoh, T.C., Dusar, M., Geluk, M.C., Kockel, F., Krawczyk, C.M., Krzywiec, P., Scheck-Wenderoth, M., Thybo, H., Vejbæk, O.V. & Van Wees, J.D., 2010. Tectonic Evolution. In: Doornenbal, J.C. and Stevenson, A.G. (Eds): Petroleum Geological Atlas of the Southern Permian Basin Area. EAGE Publications b.v. (Houten): 25-57.

Pool, W., Geluk, M., Abels, J., Tiley, G., 2012. Assessment of an unusual European Shale Gas play — The Cambro-Ordovician Alum Shale, southern Sweden: Proceedings of the Society of Petroleum Engineers/European Association of Geoscientists and Engineers Unconventional Resources Conference, Vienna, Austria, March 20–22, 2012, 152339.

Poprawa, P., Sliaupa, S., Stephenson, R., Lazauskiene, J. (1999) Late Vendian-Early Paleozoic tectonic evolution of the Baltic Basin: regional tectonic implications from subsidence analysis. Tectonophysics, 314, 219-239.

Sanei, H., Petersen, H.I., Schovsbo, N.H., Jiang, C., Goodsite, M.E. (2014) Petrographic and geochemical composition of kerogen in the Furongian (U. Cambrian) Alum Shale, central Sweden: Reflections on the petroleum generation potential. International Journal of Coal Geology, 132, 158-169.

Schovsbo, N.H. (2003) The geochemistry of Lower Paleozoic sediments deposited on the margins of Baltica. Bulletin of the Geological Society of Denmark, 50, 11-27.

Schovsbo, N.H., Nielsen, A.T., Gautier, D.L., 2014. The Lower Palaeozoic shale gas play in Denmark. Geological Survey of Denmark and Greenland Bulletin 31, 19–22.

Schovsbo, N.H., Nielsen, A.T., 2017. Generation and origin of natural gas in Lower Palaeozoic shales from southern Sweden. Geological Survey of Denmark and Greenland Bulletin 39. In press

Schulz, H.-M., Biermann, S., van Berk, W., Krüger, M., Straaten, N., Bechtel, A., Wirth, R., Lüders, V., Schovsbo, N.H., Crabtree, S., 2015. From shale oil to biogenic shale gas: retracing organic-inorganic interactions in the Alum Shale (Furongian-Lower Ordovician) in southern Sweden. AAPG Bulletin 99, 927–956.

Trench, A. & Torsvik, T.H., 1992. The closure of the Iapetus Ocean and Tornquist Sea: new palaeomagnetic constraints. Journal of the Geological Society 149: 867-870.

Ziegler, M.A., 1989. North German Zechstein facies patterns in relation to their substrate. Geologische Rundschau 78: 105-127.

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T02 - Baltic Basin – Cambrian-Silurian Shales

General information Screening- Index Basin Country Shale(s) Age Index Baltic LV No name Lower Ordovician 1001 Palaeobasin Alum Shale M. Cambrian - E. Baltic Basin S 1014 Formation Ordovician Sorgenfrei Alum Shale M. Cambrian - E. S 1015 Tornquist Zone Formation Ordovician Norwegian- M. Cambrian - E. DK Alum shale 1019 Danish-Scania Ordovician T2 Upper Ordovician- Middle-Late Baltic Basin LT Llandovery Llandovery (Late 1061 Shales# Ordovician) Lower Palaeozoic Upper Cambrian to Baltic Basin PL 1051 shales* Llandovery Płock‐Warsaw Lower Palaeozoic Upper Cambrian to PL 1052 zone shales* Llandovery Podlasie basin Lower Palaeozoic Silurian (Llandovery PL 1053 and North Lublin shales+ to Wenlock) * The Polish Formations were combined into one unit per basin. They consist of three formations, the Piasnica Formation of Late Cambrian to Tremadocian age, the Sasino Formation of Late Ordovician age, the Pasłęk Formation of Llandowery age and the Pelplin Formation of Wenlock age. The three formations are described separately in the following. # The Lithuanian Formations with shale gas/oil potential were combined into one unit for the basin. They consist of the Fjäcka-Mossen Formation of Late Ordovician age and the Raikiula-Adavere formations of Llandovery age which are situated on top of each other. + In the Podlasie basin and North Lublin Basin the Polish potential shale gas/oil formations are the Llandovery Paslek Formation and the Wenlock Pelplin Formation.

Geographical extent The Baltic Basin (BB) is part of system of marginal basins situated along the western edge of the East European Craton (EEC; Poprawa et al. 1999). It consists of a Peri- Baltic sub-basin, in the vicinity of the present-day Baltic Sea, and a Peri-Tornquist sub-basin along the Tornquist-Teisseyre Zone (TTZ). The Peri-Tornquist is a high dip sub-basin with a paleothickness in the range 2000-5000 m within the 200-300 km wide area. The Peri-Baltic sub-basin is 400 km wide with thicknesses ranging 500- 2000 m. In the Lithuanian-Estonian borderland paleothicknesses are less than 500 m. The TTZ, approximately coincident with the North German-Polish Caledonian Deformation Front (CDF), forms the south-western margin of the Baltic Basin. The south-eastern margin of the Baltic Basin is flanked by the Mazury-Belarus High (Paškevičius, 1994) and the Baltic Shield lies to the North-East and North.

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Figure 1 Distribution of the Lower Paleozoic shales. The coloured areas represent different basins.

Geological evolution and structural setting

Syndepositional setting The Early Palaeozoic tectonic evolution of the Baltic Basin was intimately related to tectonic processes along of the SW and NW margins of Baltica (Sliaupa et al., 1997). Subsidence within the Peri-Tornquist sub-basin started in the Late Vendian and by the end of the Early Cambrian it expanded to the east creating a much broader basin. The general trend of subsidence indicates three main stages of basin development: Late Vendian-Middle Ordovician passive margin stage, followed by a convergent margin stage during Late Ordovician-Silurian times, in turn followed by abrupt deceleration of subsidence during the Early Devonian (Poprawa et al., 1999).

The initial stage of basin development was related to the break-up of the Precambrian Rodinia supercontinent during Late Vendian-Early Cambrian times (Torsvik et al.,

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1992). The Late Vendian to Middle Cambrian subsidence has been interpreted as an extensional event related to continental rifting west of the present-day TTZ. The transition from an active extensional to a passive thermal sag setting occurred in the Late Cambrian and until the Middle Ordovician basin development was driven by a thermal cooling subsidence mechanism (Sliaupa et al., 1997; Poprawa et al., 1999, Lazauskiene et al., 2002). The Middle Cambrian-Middle Ordovician period was characterized by a general decrease of subsidence rate.

The situation markedly changed from passive to convergent margin setting in Late Ordovician-Silurian times. A gradual increase of subsidence rate, which is characteristic for basins developed under a compressional tectonic regime, is observed during the Silurian with the maximum subsidence rate occurring in Pridoli epoch. Subsidence rates increased towards the west, towards the North German-Polish Caledonian Deformation Front (Sliaupa et al., 1997; Poprawa et al., 1999). The docking and later collision between the Baltica and Eastern Avalonia occurred in Late Ordovician times (Torsvik et al., 1996) and overthrusting of accretionary NGPC wedges onto the western margin of Baltica produced the Baltic foreland basin (Sliaupa et al., 1997; Poprawa et al., 1999). Simultaneously, during the Middle Ordovician Baltica drifted towards Laurentia (Torsvik et al., 1996) and collided with it during Middle-Late Silurian times (Cocks et al., 1997).

Structural setting The Baltic Basin is the largest sedimentary basin located on the western margin of the East European Craton. The structure of the basin is defined by features within the underlying Precambrian crystalline basement. Several major structural units are distinguished including the Baltic (Polish-Lithuanian) Depression, the Latvian Saddle, the slope of the Belarus–Mazurian High, the southern slope of the Baltic Shield, the Central Baltic Depression, the Polish-Lithuanian Depression and the Latvian– Estonian Monocline (Suveizdis, 1979; Paškevičius, 1997). The Baltic Depression comprises one of the major structural units of the Baltic basin. It is bounded by the Teisseyre– Tornquist Zone (TTZ) in the southwest, while the Baltic Shield flanks it in the North. The Latvian Saddle forms the eastern limit of the Baltic Syneclise and the southeastern margin is flanked by the Belarus–Mazurian High (Paškevičius, 1997).

The crystalline basement occurs at a depth of 500-1000 m in the North and East of the Baltic Basin, increasing to a depth of 2 300 m in the Western Lithuania and to 3000-5000 m to the southwest close to TTZ (Paškevičius 1997; Suveizdis 2003). The crystalline basement of metamorphic and magmatic rocks has a block-like structure, strongly dissected by tectonic faulting. The faults are oriented N-S, W-E, NW-SE and NE-SW predominantly. Two major systems of late Caledonian reverse faults, oriented W-E (WSW-ENE) and SW-NE (SSW-NNE) prevail in the studied area (Sliaupa et al., 2002). Numerous local uplifts are confined by SSW-NNE trending faults. In most of the territory the Cambrian and younger sediments overlie the deeply eroded surface of crystalline basement.

The sedimentary cover of the Baltic Basin is represented by Vendian and all the systems of the Phanerozoic to Quaternary (Shogenova et al., 2009). Within this succession Baikalian, Caledonian, Hercynian and Alpine structural-sedimentary complexes are distinguished. The complexes differ by their geological composition and structural patterns, being separated by the periods of non-deposition and erosion that, in turn, reflects the major orogenic events in the Baltic Basin (Suveizdis, 2003). The Baikalian complex embraces Riphean and Vendian strata and the Baltic Series of the lowermost Cambrian, are thickening eastwards from 30 up to 265 m. The complex is represented by volcanomictic gravellite, sandstones and shales and up to 120 m thick lowermost Cambrian claystones (so-called Blue Clays). The Caledonian complex

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comprises the major hydrocarbon prospective strata within the Baltic Basin. Thickness of the Caledonian complex varies from 400 m in the eastern part of the basin to 2500 m close to TTZ. At the base of the Caledonian complex the Lower-Middle Cambrian sandy succession interbedded with siltstone and shales (50–200 m) occurs, being overlain by 20 m thick Upper Cambrian black organic rich shales. Upper Cambrian sediments are covered by 35–250 m thick Ordovician shales and carbonates, passing to 200–1260 m Silurian graptolite shales (Paškevičius, 1997).

Organic-rich shales

Middle Cambrian to Early Ordovician - Alum Shale (Denmark and Sweden) The deposition of the Alum Shale extended from the Norwegian-Danish-Swedish Basin across the Sorgenfrei-Tornquist Zone into the Baltic Basin. For a detailed description please refer to the description of the Alum Shale in Basin T1.

Chance of success component description Occurrence of shale

Mapping status Moderate

Sedimentary Variability Low Deposited in an epicontinental sea at the passive margin of Baltica.

HC generation

Data availability Moderate

HC system Possible Only minor oil accumulations have been proposed to be sourced from the Alum Shale mostly offshore Poland and on the Swedish Island of Gotland, Baltic Sea.

Maturity variability High

Recoverability

Depth Shallow

Mineral composition Unknown

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Upper Cambrian to Tremadocian shales (Piaśnica bituminous shale formation, Poland) The Upper Cambrian to Tremadocian bituminous shales developed in the northern part of the Polish onshore Baltic Basin and in its offshore part (Szymański, 2008; PGI-NRI, 2012). The Polish name for the Upper Cambrian to Tremadocian bituminous shale is Piaśnica bituminous shale formation (Poprawa, 2010) and it can be correlated with Alum shale in Denmark/Skåne (Gautier et al., 2013) and in Lithuania (Lazauskienė, 2015) though there seems to be no direct connection between the Polish and Lithuanian plays (a sandstone-rich facies appears in between - Modliński, 2010).

Depth and Thickness The thickness of the Piaśnica bituminous shale formation is limited, particularly in the onshore part of the basin where only several meters on average were deposited (up to 16.9 m at Baltic seashore, 5 m on average), while in the Polish offshore sector reaches 34 m (Szymański, 2008; Modliński, 2010; Więcław et al., 2010).

Shale oil/gas properties This shale is characterized by high organic matter content with measurements on individual wells between 3–12 % TOC (lower values onshore, higher offshore; Więcław et al., 2010; PGI-NRI, 2012). The average TOC in the onshore part of Polish Baltic basin is about 5.5 % (Więcław et al., 2010; laboratory analyses on core samples taken from wells located mostly at or close to seashore, i.e. in the northernmost part of the basin).

Figure 2 Assessment zones for the Lower Paleozoic shale gas/oil basins. The yellow areas refer to shale gas zones (Vitrinite equivalent reflectance 1.1-3.5 %RVequ), the green zones refer to shale oil zones (0.6-1.1 %RVequ)

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Chance of success component description Occurrence of shale layer

Mapping status Unknown Only outlines of the assessment unit were provided

Sedimentary variability Moderate

Structural complexity High along the southern margin of the basin, moderate in the centre of the basin

Generation of HC system

Data availability Moderate

HC system Possible

Maturity variability Moderate

Recoverability Depth Average Between around 1000m in the easternmost part to more than 4500m in the west.

Mineral composition Unknown

Early Ordovician Shales (Zebrus Formation, Latvia) The lowermost part of the sequence locally includes thin dark shale beds (Weiss et al., 1997). Zebrus Formation is widespread in all the Baltic Syneclise.

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Figure 3 Distribution of the prospective area of the Zebrus Formation

Depth and Thickness Thickness of the Ordovician succession in Latvia`s onshore area varies from 42 m (in the northeast and northwest part of Latvia) to 257 m (in the central and southeastern part of Latvia). Thickness of the Ordovician succession in Latvia`s offshore area varies from 74 m to 146 m (Brangulis et al., 1998). The thickness of the Zebrus formation is 2-50 m (data from DB “Urbumi”) and it is situated at more than 1500 m depth.

Shale oil/gas properties Unknown

Chance of success component description Occurrence of shale layer

Mapping status Moderate Thickness and depth map available

Sedimentary variability Moderate

Structural complexity Moderate

Generation of HC system

Data availability Poor

HC system Possible On- and offshore exploration wells have encountered oil and oil shows, no production.

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Maturity variability Unknown

Recoverability

Depth Average 1000-5000m

Mineral composition Unknown

Late Ordovician Shales (Sasino shale formation, Poland; Fjäcka and Mossen formations in Lithuania)

The Upper Ordovician shale, mainly Caradoc, developed in the central and western part of the Baltic Basin, as well as in the western part of the Podlasie Depression. In the north-western part of the Baltic-Podlasie-Lublin Basin, i.e. at the Łeba Elevation, the onset of organic rich sediment deposition was even earlier, during late Llanvirn. The deposition was diachronically expanding in time towards east and south-east, systematically replacing laterally limestone and marl deposition with claystone and siltstone (Modliński and Szymański, 1997; Poprawa, 2010). During Ashgill time eustatic sea level drop caused expansion of the carbonate sedimentation into all the here discussed basins, except of the Łeba Elevation where organic rich shale deposition continued. The Polish name for the Upper Ordovician shale is Sasino shale formation (Poprawa, 2010) and it could be likely correlated with Caradoc-Ashgill shales in southern Scandinavia (Schovsbo, 2015; Fjäcka and Mossen formations) and Lithuania (Lazauskienė, 2015) depending on maturity, TOC and other parameters.

Depth and Thickness In the central and eastern part of the Baltic Basin (Lithuania and Latvia) the potential source rocks comprises dark grey and black shales of the Late Ordovician Late Caradoc-Early Asghill (Katian) Fjäcka and Mossen formations. Both units are generally thin, reaching only up to 5–10 m; the average thicknesses of Fjäcka and Mossen Formations are 6 m and 4 m respectively.

Thickness of the Upper Ordovician shale (Sasino shale formation) increases from the east towards the west and north-west: in the onshore Baltic basin from 3.5 m to 37 m with an average of about 20 m (Modliński and Szymański, 1997; Modliński, 2010; PGI-NRI, 2012), In the Podlasie Depression and the basement of Płock-Warszawa Trough the thickness ranges from 1.5 m to 52 m with an average of about 30 m (Modliński and Szymański, 2008; Modliński, 2010; PGI-NRI, 2012).

Shale oil/gas properties In the Lithuanian area TOC contents are mostly in the 0.9 to 10 % range, with occasional higher values of up to 15 %. Oil and gas generation potential averages are 22 kg HC/t rock, rarely reaching 55–70 kg HC/t rock. Hydrogen Index reaches up to 521 mg HC/g TOC, Tmax is around 424°C (Zdanaviciute, Lazauskiene, 2004, 2007, 2009). The source rock facies is of kerogen type II, reflecting marine conditions. Thermal maturity of the organic matter is between less than 0.7 and more than 1.5 % reflectance of Vitrinite equivalent.

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Figure 4 Thermal maturity of the organic matter in the central part of the Baltic Basin (Lithuania, Lazauskiene et al. 2014)

The individual wells on the Polish part of the onshore Baltic Basin have an average TOC content of 1 % to 3.5 % with an average of about 1.5% (Poprawa, 2010; Więcław et al., 2010). The highest TOC values were measured in the area of the Łeba Elevation where organic rich shales are present both in the Caradoc and (especially) the Ashgill (Więcław et al., 2010). In the western and central part of the Podlasie Depression the average TOC content of the Upper Ordovician shale is between 1 % and 1.25 % (Poprawa, 2010), while in the basement of the Płock- Warszawa Trough it ranges between 2.1 to 3.76 % TOC (Poprawa, 2010). In the Lublin region the average TOC of the Early Ordovician sediments is less than 1 % (Poprawa, 2010).

Chance of success component description Occurrence of shale layer

Mapping status LT: Good Thickness and depth map available P: Unknown Only outlines available

Sedimentary variability Moderate Facies changes within the Baltic Basin depending on the depositional setting

Structural complexity LT: Moderate P: High In the centre of the Basin getting more complex towards the basin margins, especially along the thrust front along the TTZ.

Generation of HC system

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Data availability Moderate

HC system Possible

Maturity variability Moderate

Recoverability

Depth Shallow to Average

Mineral composition Unknown

Early Silurian Shales (Llandovery – Pasłęk formation, Poland; Raikiula- Adavere formations, Lithuania)

During the Early Silurian the eustatic sea level rise caused widespread deposition of organic rich shale (PGI-NRI, 2012). The Llandovery (organic rich) siltstone and claystone sediments are present throughout most of the basin with the exception of the south-eastern Lublin region (Poprawa, 2010, Schovsbo, 2015, Lazauskienė, 2015). The bottom part of the Llandovery is often represented by an organic rich bituminous shale (Poprawa, 2010). In the eastern part of the Baltic Basin the lower Llandovery bituminous shale is locally replaced by a black nodule limestone (Jaworowski & Modliński, 1968). The Polish name for Llandovery claystones is Pasłęk shale formation and the organic rich lower Llandovery is called Jantar bituminous shale member (Poprawa, 2010). The lateral equivalent of the Pasłęk shale formation in southern Scandinavia consists of predominantly siltstones and therefore is not considered to have shale gas potential. (Schovsbo, 2015) while the Lithuanian Llandovery Raikiula- Adavere formations (Lazauskienė, 2015) is considered to be the lateral equivalent. In the south-eastern Lublin region where Poland borders with Ukraine no Llandovery sediments were preserved due to a hiatus (Poprawa, 2010).

The Middle-Upper Llandovery succession in Lithuania is composed of dark grey and black graptolite shales and dark grey and black clayey marlstones.

Depth and Thickness The thickness of the Llandovery clay facies (Pasłęk formation) in Poland ranges between 10 and 70 m, and is most often between 20 to 40 m generally increasing towards the west (Modliński 2010; PGI-NRI, 2012). The average value for the is about 40 m in the northern part of the Baltic Basin, 20 m in the centre and around 30 m in the Podlasie and Lublin basins (according to maps in Modliński, 2010; also there is a hiatus in SW part of the Lublin Basin).

The thickness of the Raikiula-Adavere formations in Lithuania is between 15 and 80m thick. It is located at depth between 1500 and 2100m.

Shale oil/gas properties Within the Lithuanian part of the Baltic Basin organic matter content generally ranges from 0.7 to 9–11%, but can be as high as 16.46 % (Zdanaviciute, Lazauskiene, 2004). Oil and gas generation potential of this source rock complex in the central part

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of the Baltic Basin ranges from 7–10 to 57 kg HC/t rock with Hydrogen Index values in the 294–571 mg HC/g TOC range. The most organic rich rocks with an average thickness of 30 meters are recorded in the lowermost part of the complex (within the Middle Llandovery shaly strata) while TOC gradually decreases towards the top of the section. The average TOC content in the Middle Llandovery graptolite shales reaches up to 1.58 %. The organic matter of the Early Palaeozoic succession is of „oil- producing" sapropel type II of marine origin and mixed “oil-gas producing” type II/III; it contains a large amount of marine amorphous and algal kerogen; therefore, kerogen type II is dominating. The organic matter of the Lower Paleozoic source rocks can be attributed to the “oil-prone” sapropel type, related to fine-grained sediments of marine origin.

The lower part of the Llandovery section is for a major part of the basin characterized by especially high TOC contents (Jantar bituminous shale member, Klimuszko, 2002; Poprawa, 2010). The highest measured TOC content reaches 20 %, while the average TOC content of the Llandovery claystones usually equals 1 % to 3 % in the central part of the Baltic basin, 1.5-6 % in the Podlasie basin and about 3 % in the northeastern part of the Lublin region (Poprawa, 2010). In the southernmost part of the Lublin region the average TOC in the Llandovery clay facies is usually below 1 % (Poprawa, 2010).

Chance of success component description Occurrence of shale layer

Mapping status LT: Moderate Total Lower Silurian depth and thickness map available P: Unknown Only outlines were provided

Sedimentary variability Moderate Large scale facies changes within the Baltic Basin depending on the depositional setting

Structural complexity LT: Moderate P: High In the centre of the Basin getting more complex towards the basin margins, especially along the thrust front along the TTZ.

Generation of HC system

Data availability Moderate

HC system Possible

Maturity variability Moderate

Recoverability

Depth Average Around 1000m in the centre of the basin to more than 4500m in the south.

Mineral composition

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Unknown

Early Silurian shales (Wenlock – Pelplin formation, Poland) The upper part of Lower Silurian in the Baltic basin consists of claystones of Wenlock and Ludlow age that are partly rich in organic matter (Pelplin formation) which are gradually replaced in westerly direction by organic lean siltstones and mudstones (rarely sandstones) of the Kociewie formation (Poprawa, 2010). The Wenlockian part of Pelplin formation, especially lower Wenlock, is richer in organic matter than the Ludlowian part (Karcz, 2015). Wenlock claystones of the Pelplin formation are present in the Baltic and Podlasie basins and are a quite abundant in Lublin region (Poprawa, 2010). The Pelplin formation of the Lublin region, especially in SE part, could be correlated with the Ukrainian counterpart (Kytayhorod and Bagovytsya stages of Wenlock - Radkovets, 2015).

Depth and Thickness The thickness of the Wenlock section in Poland varies significantly laterally from less than 100 m in the eastern part of the Podlasie Depression and Lublin region, to more than 1000 m in the western part of the Baltic Basin (Modliński, 2010).

Shale oil/gas properties Average TOC contents in a range of 1 % to 2 % are characteristic for the Wenlock sediments in the eastern Baltic Basin, as well as in a part of Podlasie Depression and Lublin region (generally increasing from NW to SE). In a remaining part of the study area the average TOC content of the Wenlock sediments is less than 1 % (Poprawa, 2010). All of these values are measured on homogenized samples from thick rock complexes so it is possible that there are shale layers with higher TOC contents within the Wenlock (Poprawa, 2010).

Chance of success component description Occurrence of shale layer

Mapping status Unknown Only outlines provided

Sedimentary variability Moderate

Structural complexity Moderate to high

Generation of HC system

Data availability Moderate

HC system Unknown

Maturity variability Moderate

Recoverability

Depth

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Average 1000-5000m

Mineral composition No data

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Cocks, L.R.M., McKerrow, W.S. 1997. Baltica and its margins in the Ordovician and Silurian. Terra Nostra 97/11, 39-42.

Gautier, D.L., Charpentier, R.R., Gaswirth, S.B., Klett, T.R., Pitman, J.K., Schenk, C.J., Tennyson, M.E., and Whidden, K.J., 2013. Undiscovered Gas Resources in the Alum Shale, Denmark, 2013: U.S. Geological Survey Fact Sheet 2013–3103, 4 p., http://dx.doi.org/10.3133/fs20133103.ISSN 2327– 6932 (online).

Jaworowski K., Modliński Z., 1968. Lower Silurian nodular limestones in north-eastern Poland. Geological Quarterly, 12(3): 493-506 (in Polish).

Karcz P., 2015. Shale Gas Potential of the North-Central Onshore Area of the Balic Basin. Tethys- Atlantic Interaction Along the European-Iberian-African Plate Boundaries. AAPG European Regional Conference, 18-19.05.2015, Lisbon, Portugal.

Klimuszko E. 2002. Silurian sediments from SE Poland as a potential source rocks for Devonian oils. Biuletyn Państwowego Instytutu Geologicznego, 402: 75-100 (in Polish).

Lazauskiene, J., Stephenson, R. A, Sliaupa, S., Van Wees, J. D., 2002. 3D flexural model of the Silurian Baltic Basin. Tectonophysics 346, 115-135.

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Modliński Z., Szymański B., 1997. The Ordovician lithostratigraphy of the Peribaltic Depression (NE Poland). Geological Quarterly, 41(3): 273-288.

Modliński Z., Szymański B., 2008. Lithostratigraphy of the Ordovician in the Podlasie Depression and the basement of the Płock-Warsaw Trough (eastern Poland) Biul. Państw. Inst. Geol., 430: 79-112 (in Polish).

Paškevičius J. 1994. Silūras. In: Geology of Lithuania. Grigelis., A., Kadūnas, V. (eds.) [In Lithuanian: Silūras. Lietuvos geologija]. Vilnius. 67–97.

Paškevičius, J., 1997. The geology of the Baltic Republics. Vilnius, 387. PGI-NRI, 2012. “Assessment of Shale Gas and Shale Oil Resources of the Lower Paleozoic Baltic- Podlasie-Lublin Basin in Poland, First Report.” Warsaw, Poland.

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Poprawa, P., Sliaupa, S., Stephenson, R., Lazauskiene, J., 1999. Vendian–Early Palaeozoic subsidence history of the Baltic Basin: geodynamic implications. Tectonophysics 314, 219–239.

Poprawa, P., 2010. Shale Gas Potential of the Lower Palaeozoic Complex in the Baltic and Lublin- Podlasie Basins (Poland). Przegląd Geologiczny, volume 58, p. 226–249 (in Polish).

Radkovets., N., 2015. The Silurian of southwestern margin of the East European Platform (Ukraine, Moldova and Romania): lithofacies and palaeoenvironments. Geological Quarterly, 2015, 59 (1): 105–118 DOI: http://dx.doi.org/10.7306/gq.1211

Sliaupa, S., Poprawa, P., Lazauskiene, J., 1997. The Palaeozoic subsidence history of the Baltic Syneclise in Poland and Lithuania. Geophysical Journal Vol. 19, N1. Kiev. 137-139.

Sliaupa, S., Lazauskiene, J., Laskova, L., Cyziene, J., Laskovas, J., Motuza, V., Korabliova, L., 2002. Evolution of petroleum system of Lithuanian offshore. Zeitschrift für Angewandte Geologie 2, 41-63.

Sliaupa S., Fokin P., Lazauskiene J., Stephenson R. A. 2006. The Vendian-Early Palaeozoic sedimentary basins of the East European Craton. Geological Society, London, Memoirs. 32(1). 449–462.

Schovsbo N. H., 2015. Overview of the status for shale oil/gas in Denmark. EUOGA kick-off meeting Copenhagen, 7/12-2015 (presentation).

Shogenova, A., Sliaupa, S., Vaher, R., Shogenov, K., Pomeranceva, R. 2009. The Baltic Basin: structure, properties of reservoir rocks, and capacity for geological storage of CO2. Estonian Journal of Earth Sciences. 58(4). 259–267.

Suveizdis, P. 1979. Tectonics of the Baltic States. Academy of Sciences of Lithuania. 90.

Suveizdis, P. 2003. Tectonic structure of Lithuania. (In Lithuanian). Institute Geology and geography. Vilnius. 160 p.

Szymański B., 2008. A lithological and microfacies record of the Upper Cambrian and Tremadocian euxinic deposits in the Polish part of the Baltic Depression (Northern Poland). Biul. Państw. Inst. Geol., 430: 113-154 (in Polish).

Torsvik, T. H., Smethurst, M. A., Van der Voo, R., Trench, A., Abrahamsen, N., Halvorsen, E., 1992. Baltica. A synopsis of Vendian-Permian palaeomagnetic data and their palaeotectonic implications. Earth-Sci. Rev. 33, 133-152.

Torsvik, T. H., Smethurst, M. A., Meert, J. G., Van der Voo R., McKerrow, W. S., Brasier, M. D., Sturt, B. A., Walderhaug H. J. 1996. Continental break-up and collision in the Neoproterozoic and Palaeozoic—a tale of Baltica and Laurentia. Earth-Science Reviews. 40(3). 229–258.

Weiss H.M., Kanev S.V., Ritter U., Smelror M., Zdanavičiūte O. 1997. Paleozoic source rocks of the Baltic and Skagerrak regions: Main report. IKU SINTEF GROUP IKU Petroleum Research, Trondheim, Norway. 208. (Latvian State Geological Fund No 25075)

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Więcław D., Kotarba M. J., Kosakowski P., Kowalski A., Grotek I., 2010. Habitat and hydrocarbon potential of the lower Paleozoic source rocks in the Polish part of the Baltic region. Geol. Quart., 54 (2): 159-182. Warszawa.

Zdanavičiūtė, O., Lazauskiene, J., 2004. Hydrocarbon migration and entrapment in the Baltic Syneclise. Organic Geochemistry 35(4), 517-527.

Zdanavičiūtė, O., Lazauskiene, J., 2007. The Petroleum potential of the Silurian succession in Lithuania. Journal of Petroleum Geology 30(4), 325-337.

Zdanavičiūtė, O., Lazauskienė, J. 2009. Organic matter of Early Silurian succession – the potential source of unconventional gas in the Baltic Basin (Lithuania). Baltica, Vol. 22 (2), 89–98.

Zdanaviciute, O., Lazauskiene, J., Khoubldikov, A.I., Dakhnova, M.V., Zheglova T. 2012. Geochemistry of oils and petroleum potential of the Middle Cambrian succession in the central Baltic basin. Journal of Petroleum Geology. Vol.35. 237-254.

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Geological resource analysis of shale gas/oil in Europe

T03 - South Lublin Basin, Narol Basin and Lviv-Volyn Basin – Lower Paleozoic Shales

General information Screening- Index Basin Country Shale(s) Age Index South Lublin Silurian Lower Palaeozoic Basin and Narol PL (Llandovery to 1054 shales T3 Basin Wenlock) Lviv‐Volyn UA Black shale Lower Silurian 1062

Figure 1 Distribution of the Lower Paleozoic potential shale gas formations. The coloured areas represent different basins.

Geographical extent The south Lublin Basin and Narol Basin in Poland and the Lviv-Volyn Basin in the Ukraine are laterally continuous (Fig. 1). They are located on the margin of the Lvov Paleozoic trough at the edge of the East European Platform. The Lviv-Volyn Basin extends about 190 km along strike and is at its widest position about 60km wide.

Geological evolution and structural setting

Syndepositional setting The Silurian is the main petroleum source rock and shale gas exploration targets in the Lviv-Volyn Basin. Compared with Poland, the reservoir characteristics of the Silurian shale in western Ukraine are less certain. Prospective marine black shales of

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Geological resource analysis of shale gas/oil in Europe

Silurian age extend continuously within a 50- to 200- km wide Paleozoic belt, from Poland all the way to the Black Sea. In western Ukraine, Silurian deposits of southeast Poland’s Lublin Basin continue into the adjoining Lviv-Volyn Basin, where 62 conventional oil and gas fields have been developed. About 400 to 1,000 m of deepwater Silurian shale is present, transitioning eastward into thinner, shallow-water carbonates. The Ludlow member of the Silurian is considered the most prospective interval. The Ludlow ranges from 400 to 600 m thick and occurs at depths of 2 to 3 km in western Ukraine.

Structural setting The moderately complex Lviv-Volyn Basin of western Ukraine is similar to the Lublin Basin in southeast Poland. However, the Silurian black shale belt becomes structurally simpler as it trends towards the southeast across southwestern Ukraine and northern Romania until it reaches the Black Sea. Much of the Lviv-Volyn Basin appears to be too deep and faulted for shale development.

However, the Silurian belt becomes wider and structurally simpler as it continues further to the southeast across western Ukraine and northern Romania. After some tectonic disturbance, the Silurian belt re-enters southern Ukraine and eastern Romania in the Scythian Platform before heading out into the Black Sea. It then briefly re- emerges onto land on the Crimean Peninsula near Odessa before continuing offshore. As the foreland basin to the Carpathian thrust belt, this shale belt dips gently to the southwest and is characterized by mostly simple structure with few faults.

Early Silurian shales (Wenlock – Pelplin formation, Silurian black shales, Ukraine)

The Wenlockian part of Pelplin formation, especially lower Wenlock, is richer in organic matter than the Ludlowian part (Karcz, 2015). Wenlock claystones of the Pelplin formation are present in the Baltic and Podlasie basins and are a quite abundant in Lublin region (Poprawa, 2010). The Pelplin formation of the Lublin region, especially in SE part, could be correlated with the Ukrainian counterpart (Kytayhorod and Bagovytsya stages of Wenlock - Radkovets, 2015).

Depth and Thickness

The thickness of the Wenlock section in Poland varies significantly laterally from less than 100 m in the eastern part of the Podlasie Depression and Lublin region, to more than 1000 m in the western part of the Baltic Basin (Modliński, 2010).

Compared with Poland, the reservoir characteristics of the Silurian shale in western Ukraine are less certain. About 400 to 1,000 m of deepwater Silurian shale is present, transitioning eastward into thinner, shallow-water carbonates. The Ludlow member of the Silurian is considered the most prospective interval. The thickness of the Ludlow ranges from 400 to 600 m and it occurs at depths of 2 to 3 km in western Ukraine.

Shale oil/gas properties

Average TOC contents in a range of 1 % to 2 % are characteristic for the Wenlock sediments in a part of Podlasie Depression and Lublin region (generally increasing from NW to SE). In a remaining part of the study area the average TOC content of the Wenlock sediments is less than 1 % (Poprawa, 2010; PGI-NRI, 2012). All of these values are measured on homogenized samples from thick rock complexes so it is

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possible that there are shale layers with higher TOC contents within the Wenlock (Poprawa, 2010).

Silurian shale TOC may be lower in Ukraine than in Poland, at least based on the single well data point available. Most TOC measurements at a depth range of 1,400 to 1,592 m in this well were less than 1%. However, the original TOC is estimated at 3% prior to thermal alteration. Given the depositional environmental of the Silurian, it is likely that higher TOC exists in places. Thermal maturity mapping, calculated from conodont alternation index, indicates the Silurian is entirely in the dry gas window (Ro of 1.3% to 3.5%). Several (possibly spurious) over-mature values of 5% Ro also were measured. Maturation is believed to have occurred prior to the Mesozoic. As Sachsenhofer and Koltun (2012) noted: “additional investigations are needed to investigate lateral and vertical variations of TOC contents and refine the maturity patterns in Lower Paleozoic rocks”.

Chance of success component description Occurrence of shale layer

Mapping status P: Unknown Only outlines provided UA: Moderate Depth and thickness maps available

Sedimentary variability Moderate

Structural complexity Moderate to high

Generation of HC system

Data availability Moderate

HC system Unknown

Maturity variability Unknown

Recoverability

Depth Average 1000-5000m

Mineral composition No data

References

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Modliński Z., (ed.), 2010. Paleogeological atlas of the sub-Permian Paleozoic of the East-European Craton in Poland and neighboring areas. PGI-NRI, Warsaw, Poland.

Poprawa, P., 2010. Shale Gas Potential of the Lower Palaeozoic Complex in the Baltic and Lublin- Podlasie Basins (Poland). Przegląd Geologiczny, volume 58, p. 226–249 (in Polish).

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Geological resource analysis of shale gas/oil in Europe

T04 - Moesian Platform and Kamchia Basin

General information Screening- Index Index Basin Country Shale(s) Age (summarized in 2001) Lower Paleozoic Silurian to Lower BG 1056 Shales Devonian Tandarei Graptolitic U OrdovicianU RO 1038 Black Shales SilurianL Devonian Upper Paleozoic Lower Carboniferous shale & coal (Middle BG Succession 1057 Mississippian, Upper Trigorska & Visean) Konarska Fms Moesian Calarasi bituminous U DevonianL RO 1039 Platform limestones Carboniferous Vlasin black shale T4 RO U Carboniferous 1040 Formation J1 shale & clay limestones Ozirovo Jurassic (Sinemurian BG Fm 1058 ‐ Toarcian) (Bucorovo & Dolnilucovit Mbs) J2 shale Etropole Aalenian Lower BG 1059 Fm (Stefanets Mb) Bajocian Kamchia BG Ruslar Fm Oligocene 1060 Basin Black Sea RO Oligocene n/a shelf

Geographical extent The Moesian Platform covers the northern half of Bulgaria and the southern part of Romania. It is dominated by a thick (4–13 km) Phanerozoic sedimentary succession and block-faulted uplifts and depressions, horsts and grabens of different ranks. To the NE the Moesian Platform is separated from Scythian Platform by the North Dobrogea Orogen. The easterly Platform part is downwarped to the Black Sea. In contrast to surrounding thrust-fold belts, the Moesian Platfom has a flat topography with typical elevation only up to 200 m above sea level. The geological boundary of the Platform is well defined by the leading edge of the surrounding Alpine thrust belts.

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Figure 1 Extent of the Paleozoic and Mesozoic potential shale formations in Romania and Bulgaria. The coloured areas represent different basins.

Geological evolution and structural setting

Syndepositional setting The Middle Cambrian-Upper Carboniferous megasequence can be further subdivided into three lithological subunits, reaching 5500 m in total thickness (Tari et al., 1997): 1. The lower clastic group (Cambrian - Lower Devonian) contains basal clastic formations made up of arkose-like and quartzitic sandstones with silt and shale intercalations. This sequence is overlain unconformably by Silurian-Lower Devonian shales with an average thickness of 2500 m. 2. The carbonate group (Middle - Upper Devonian) is predominantly composed of massive limestones and dolomites, with bituminous limestones and evaporitic levels, reaching a total thickness up to 2800 m. 3. The upper clastic group (Carboniferous) is represented by shale dominated Lower Carboniferous succession and a characteristic Upper Carboniferous coal succession overlain by silts, marls, and sandstones with a typical thickness of 700-800 m. These molasse-like clastics are missing in certain areas.

The Permian-Triassic megasequence (Tari et al., 1997) is very different from the underlying sequence, having red-colored continental clastics, and evaporitic and carbonated rocks with maximum thickness (>6000 m) in the Alexandria basin. Above major basement uplifts, such as in the area of the North Bulgarian arch, this megasequence may be partially or completely missing, primarily due to postdepositional erosion rather than nondeposition. Within the Permian-Triassic megasequence, three subunits can be distinguished:

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Geological resource analysis of shale gas/oil in Europe

1. The lower red clastic group (Permian-Lower Triassic) directly overlies the Hercynian unconformity and is composed of clay, silt, sand, quartzitic sandstone, calcareous sandstone, and conglomerate with interbeddings of dolomitic limestones, anhydrite, and salt. The total thickness of this subunit can reach 2700 m. Figure 6 shows an unconformity between the Permian and the Lower Triassic. According to many authors, this unconformity reflects not only a break in sedimentation, but it is the result of the latest Hercynian orogenetic event. 2. The carbonate group (Anisian-Carnian) averages -1000 m in thickness, ransitionally overlying the shallow-water clastics. This succession is predominantly composed of neritic limestone and dolomites with marl and anhydrite/salt intercalations. 3. The upper red clastic group (Upper Triassic) can have a maximum thickness of about 1200 m; however, this succession is only locally developed. This unit is made up of shales, marls, sands, sandstones, and conglomerates, deposited dominantly in continental environments. Anhydrites, gypsum, and, rarely, salt can also be found (Georgiev, 1983).

Magmatic activity was quite common during this megacycle, especially at the beginning of the Permian and around the boundary of the Middle-Upper Triassic. Effusive volcanic activity produced rocks of bimodal composition accompanied by large volumes of pyroclastites.

The Jurassic-Cretaceous megasequence (Lower Jurassic-Senonian) (Tari et al., 1997) can reach a maximum thickness of 3500 m, mostly in the southern, Bulgarian side of the platform. After the break of deposition at the end of the Triassic, sedimentation typically resumed in the Middle Jurassic and lasted, with a short break in the Aptian, until the Senonian. This megasequence is characterized by carbonate development.

1. The sedimentary column begins with continental to neritic clastics with a maximum thickness of -600 m. Whereas sedimentation in the northern side of the platform did not commence until the Toarcian, it started at significantly earlier times in the southern side, locally as early as in the Cimmerian. 2. Starting with the Callovian, clastic sediments were replaced by massive carbonates with an average thickness of 1700 m, developed in both neritic and pelagic facies. Locally, reefal buildups can be found in Urgonian facies. Within this carbonate complex, a somewhat subdued unconformity may correspond to the Late Cimmerian orogenic phase. The carbonate succession has some siliciclastic intercalations in it formed during the Albian and Cenomanian. 3. Above a major unconformity, the Senonian is unevenly developed throughout the area, and it is mostly missing in the northwestern part of the Bulgarian Moesian Platform. Its thickness is typically a few hundred meters and is mainly composed of neritic limestones.

The Paleogene-Neogene megasequence (Paleocene- Pleistocene) shows an asymmetry in space and time, reflecting the changing influence exerted by the Balkans and the Carpathians, respectively (Tari et al., 1997).

1. The Paleocene and Eocene sedimentation is thick (<1600 m) locally in the southern part of the platform, whereas it is missing or very thin in the north. The lithology is characterized by marls and sandstones, and locally by carbonates. A major unconformity on top of the Paleogene succession marks an

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extended period of subaerial exposure and erosion during the late Oligocene and early Miocene. 2. The Neogene succession is developed in western and eastern parts of the Bulgarian Moesian Platform A relatively thin (20-200 m), middle Miocene shallow-water carbonate-dominated unit is overlain by upper Miocene deeper- water clastics, marls, and sandstones. 3. The Quaternary formations are of various thicknesses (0-200 m), developed mainly at the margins of the platform where significant neotectonic uplift occurred since the Pliocene. Consequently, these deposits are composed of continental clastics, such as conglomerate, sand, clay, and loess.

Structural setting The Moesian Platform is a stable continental block, comprises 4-13 km thick sub- horizontal Paleozoic, Mesozoic and Neozoic sediments overlying a pre-Paleozoic metamorphic basement. It consists of several superimposed basins: Cambrian-Early Devonian, Middle Devonian-Permian, Triassic, Early-Midle Jurassic, Late Jurassic-Mid Cretaceous, Late Cretaceous Paleogene and Neogene-Quaternary. The structural pattern over the platform is typical of cover deformation over reactivated basement block faults. In the southern platform margin deformation appears to be similar to, but less intense, that in the adjacent Alpine thrusts belt: the main structures are reverse faults or not so steep to sloping thrusts and associated uplifts

The Moesian Platform stretches between Southern Carpathians and Balkans (Dabovski & Zagorchev, 2009). The Platform is overthrusted by the Balkan thrust system to the south, while the Carpathian thrust system forms the northern boundary; both are Cenozoic features related to Alpine tectonics. The orogeny of the Balkanides ceased in the Eocene, whereas the Carpathians stopped their collision in the Miocene, when the platform was finally shaped (Georgiev et al., 2001).

Major unconformities occur at the base of the Triassic, Mid-Jurassic, Mid-Cretaceous and Mid- Eocene which are correlated with the main compressive events of the Alpine fold-and-thrust belt. Compression culminated toward the end of the Early Cretaceous and the end of the early middle Eocene (Georgiev et al., 2001).

The angular unconformity developed at the Triassic-Jurassic boundary is important from a tectonic and petroleum point of view. Below it, the Triassic successions are weakly deformed everywhere into open folds and faulted block structures. The overlying Jurassic, Lower and Upper Cretaceous sediments are nearly horizontal (dips of 1º-4º), and normal faults, horsts and grabens dominate the structural pattern (Georgiev & Atanasov, 1993; Tari et al., 1997).

Lower Paleozoic shales and Tandarei Graptolitic Black Shales (1056 and 1038) The known extent of this shale unit is limited in the easternmost by the uplifted Vetrino block of North Bulgarian arch, bounded by Aksakovo fault to east, by Vetrino fault to west and by Dulovo fault to north, (Kalinko – ed., 1976; Bokov & Tchemberski – eds, 1987; Atanasov & Georgiev, 1987). These shales are drilled until now by only 2 boreholes: Vetrino 2 drilled the full section and Mihalitch 2 penetrated only the upper 700 m.

Depth and Thickness The drilled gross thickness is about 2000 m, but organic-rich thickness averages about 500-550 m. Silurian shales are at buried depths of 1000 to above 3500 m, but the available data are very scant.

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Geological resource analysis of shale gas/oil in Europe

Shale oil/gas properties Up to Late Paleozoic – Early Mesosoic hiatus the burial depths of Silurian shales were enough for development of hydrocarbon generation in them. However, during the intensive tectonics and erosional processes in Late Paleozoic – Early Mesozoic time the generated gas (modest in volumes by TOC) had escaped the Silurian shales and they are degasified at present. Measured TOC contents range from 0.4 to 3.4%, maturity ranges from gas mature to overmature.

Balteș (1983b) suggests that the organic matter consists predominantly of type I kerogen for the Ordovician-Silurian shales. Analyses show TOC contents for the Tandarei formation between 0.2 and 4.5%, but on average lower than 1%.

According to more recent analyses (Coltoi el al, 2016) the Tandarei Graptolitic Black Shales of Calarasi-Tandarei perimeter are of type II kerogen with a residual TOC content of less than 1.2 % measured on overmature samples and can reach up to 1.6 % TOC.

Chance of success component description

Occurrence of shale

Mapping status Moderate depth map, thickness map based on interpolation/average values (few datapoints)

Sedimentary variability Moderate

Structural complexity High The known area is intensively faulted and fragmented in blocks with vertical displacement of up to 2000 m and many inversion and erosion periods took place in the geological history

HC generation

Available data Moderate few data points (< 20)

Proven source rock Unknown

Maturity variability High

Recoverability

Depth Average 1000-5000m

Mineral composition No data Described as carbonated claystones with organic matter

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Geological resource analysis of shale gas/oil in Europe

Calarasi bituminous limestones (1039) The carbonate group (Middle - Upper Devonian) is predominantly composed of massive limestones and dolomites, with bituminous limestones and evaporitic levels, reaching a total thickness up to 2800 m.

Depth and Thickness It has a thickness between 100 and 2400m.

Shale oil/gas properties Balteș (1983b) suggests that the organic matter from the Upper Devonian bituminous limestones and dolomites consists of mixed kerogen (types I+ 11, but predominantly type I). Analyses show TOC contents between 1 and 2.4%.

Chance of success component description

Occurrence of shale

Mapping status Moderate Interpolated thickness maps are available

Sedimentary variability Moderate

Structural complexity High

HC generation

Available data Moderate

Proven source rock Unknown no information

Maturity variability Unknown

Recoverability

Depth Unknown

Mineral composition No data average mineral composition was not provided

Trigorska & Konarska Fms (1057) The upper clastic group (Carboniferous) is represented by shale dominated Lower Carboniferous succession and a characteristic Upper Carboniferous coal succession overlain by silts, marls, and sandstones with a typical thickness of 700-800 m. These molasse-like clastics are missing in certain areas.

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Geological resource analysis of shale gas/oil in Europe

Depth and Thickness In the western more elongated and narrow zone the Lower Carboniferous thicknesses grow fast towards Danube River to 3000 m and more. Buried depths to top of Lower Carboniferous range between 2700 and 3400 m. In the eastern uplifted zone the Lower Carboniferous sequence occurs on shallower depth, between 850 and 3100 m. The total and shale net thicknesses are respectively above of 1000 m and 400 m.

Shale oil/gas properties In the estern more elongated and narrow zone shale TOC values tend to be good and very good (up to 3-4% and more). Kerogen type is II-III, maturation ranges from transition to post mature (0.6 – 1.9 % Ro), anthracite inclusions have been observed (Nikolov et al., 1990). There is absorbed gas in the shales with methane content of 3.5-50% (Nikolov, 2014). The available geological and especially geochemical data are very scant for estimation of shale gas potential. But there are preconditions it to be moderate to good if the thicknesses are above 400 –500 m.

In the eastern uplifted zone the shale organic content has the next parameters: TOC – up to 3 % (average less 2%); kerogen tends to III-th type, maturity is high - up to anthracite level (Todorov, 1990; Todorov et al., 1992), as it is for Upper Carboniferous coals in Dobroudja field (Nikolov, 1988).

However, critical for this zone is the absence of gas shows during the drilling, as it is also in Dobroudja coal field. The intensive faulting and fragmentation in blocks with high vertical displacement and many inversions and erosions in the geological history (Atanasov & Georgiev, 1987; Kalinko – ed., 1976; Bokov & Tchemberski – eds, 1987) have caused escaping and vertical migration of the generated gas (modest in volumes by TOC). So the Lower Carboniferous shales in this zone are strongly degasified at present.

Chance of success component description

Occurrence of shale

Mapping status Moderate depth map, thickness map based on interpolation/average values (few datapoints)

Sedimentary variability Moderate

Structural complexity Moderate to High Structural setting: extension (orogeny collapse) Structural unit: North Bulgarian Uplift, Alexandria depression, Southern Dobudja

HC generation

Available data Good

Proven source rock Unknown

Maturity variability High From early mature to anthracite level

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Geological resource analysis of shale gas/oil in Europe

Recoverability

Depth Average

Mineral composition No data

Vlasin black shale Formation (1040) Upper Carboniferous black shales

Depth and Thickness The thickness ranges from 100 to 900m. The depth of the formation is not known.

Shale oil/gas properties The kerogen type ist type III.

Chance of success component description

Occurrence of shale

Mapping status Moderate interpolated thickness maps available

Sedimentary variability Moderate depositional environment changes gradually throughout the basin

Structural complexity Moderate to High

HC generation

Available data Moderate

Proven source rock Unknown no information

Maturity variability Unknown

Recoverability

Depth Unknown

Mineral composition No data average mineral composition was not provided

J1 shale & clay limestones Ozirovo Fm (Bucorovo & Dolnilucovt Mbs) (1058) The Jurassic sediments are classified as continental to neritic clastics with a maximum thickness of approximately < 1000 m. Whereas sedimentation in the northern side of

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Geological resource analysis of shale gas/oil in Europe

the platform did not commence until the Toarcian, it started at significantly earlier times in the southern side, locally as early as in the Cimmerian.

Depth and Thickness The thicknesses vary between 200 and 500 m in the western part of the outlined area, but eastward they reduce to 40-50 m. Depth increases southwards from 2600m to 4500m.

Shale oil/gas properties Total organic content is usually between 1% and 2%, rarely more. Organic type is I-II and its transformation rate increases southward from peak to late maturity stage (by Ro and Tmax values).

Chance of success component description

Occurrence of shale

Mapping status Moderate depth map, thickness map based on interpolation/average values (few data points)

Sedimentary variability Low

Structural complexity Moderate Structural setting: extension (Passive margin) Structural unit: Moesian Platform & Forebalkan

HC generation

Available data Good

Proven source rock Proven The drilled by Direct Petroleum Bulgaria well Devensi in the southwestern part of outlined area tested good gas-condensate flow from Dolnilucovit member (TransAtlantic Petroleum Ltd, 2011; EIA, 2015).

Maturity variability Moderate basin wide trends related to present or past burial depth variations

Recoverability

Depth Average 1000-5000m

Mineral composition No data

J2 shale Etropole Fm (Stefanets Mb) (1059) The Jurassic sediments are classified as continental to neritic clastics with a maximum thickness of approximately >1000 m. Whereas sedimentation in the northern side of

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Geological resource analysis of shale gas/oil in Europe

the platform did not commence until the Toarcian, it started at significantly earlier times in the southern side, locally as early as in the Cimmerian.

Depth and Thickness The Stefanets member contains thick (from 250 m to southwest up to 50 m to east) carbonate-rich (up to 40-50%) black shale that was deposited in a marine environment. The Stefanets shale generally ranges from 2500 to above 4250 m depth and is overpressured in most of the western zone, with an elevated pressure gradient of 0.78 psi/ft (TransAtlantic Petroleum Ltd, 2011; EIA, 2015).

Shale oil/gas properties Total organic content ranges from 0.7% to 2.95%, kerogen type II predominate (SGRG, 2011; TransAtlantic Petroleum Ltd, 2011; EIA, 2015; Georgiev & Ilieva, 2007; Georgiev & Dabovski, 1997; Georgiev et al., 2001). Thermal maturity falls in the oil window in the north, increasing to wet and dry gas in the south near the Balkan thrust belt (Ro 1.0% to 1.5%). Porosity is assumed to be moderately high (3-4%). Gas recovery rates also could be favorable based on the inferred brittle lithology. In 2011 Direct Petroleum Bulgaria drilled near by a new Peshtene 11 exploration well to core and tests the Etropole shale. This well penetrated about 350 m of Etropole shales with numerous gas shows (C1-C3) at depth 3500-3800 m,

Chance of success component description

Occurrence of shale

Mapping status Moderate depth map, thickness map based on interpolation/average values (few data points)

Sedimentary variability Low

Structural complexity Moderate Structural setting: extension (Passive margin) Structural unit: Moesian Platform & Forebalkan

HC generation

Available data Good

Proven source rock Possible Multiple gas shows in exploration well

Maturity variability Moderate basin wide trends related to present or past burial depth variations

Recoverability

Depth Average 1000-5000m

Mineral composition Favourable Inferred brittle lithology

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Geological resource analysis of shale gas/oil in Europe

Kamchia Basin and Romanian Black Sea shelf The Ruslar Fm (Juranov, 1991) is spread in the Kamchia basin, which extends mainly offshore in the Western Black Sea. However the western basin periphery is exposed onshore and has been a target for oil-gas exploration for over 60 years. The eastern offshore basin prolongation shows that it gradually deepens and expands eastwards, and merges with the Western Black Sea basin floor (WBSB). The Eocene-Oligocene sequence represents the major sedimentary fill in the western shallower periphery of the basin, while the Neogene thickness increases notably towards the WBSB floor (Georgiev, 2012). The onshore basin area, called Kamchia depression, is small (about 200 km2) with sedimentary feeling of up to 1300 – 1400 m (above the Illyrian unconformity). But to the eastwards offshore the basin gradually enlarges up to 60-70 km and deepens to 7000 m, with area of extend near to 2000 km2.

Ruslar Fm (1060) This sequence comprises mainly shale and claystone, occasionally grading to siltstone.

Depth and Thickness It has a total thickness of 100-400 m in the southern basin slope to more than 1000- 1500 m northwards to the basin axial zone and eastwards to the Western Black Sea Basin. It is an equivalent of the Maykop Fm, which is the basic source unit in the larger Black Sea-Caspian domain. The depth in the onshore is between 100 and 2000m with on average 200-300m. In the offshore the formation is much deeper.

Shale oil/gas properties The organic matter content is good to very good (1.4 – 2.8%), dominated by amorphous kerogen type II. The Pyrolysis Hydrogen index (HI) ranges from 30-50 to over 300, which indicates mainly degraded humic organic composition (Sachsenhofer et al., 2009. At the drilled depth intervals the formation is immature (0.27% - 0.35% Ro) and generate only biogenic gas.

Romanian Oligocene source rock (n/a) Oligocene sediments have sourced several oil and gas fileds on the Romanian Black Sea shelf, especially in the location of the Histria Depression.

Depth and Thickness The formation was drilled at depth between 1000 and 5000m and can have a thickness between 20 and 1300m in the centre of the basin.

Shale oil/gas properties Samples from 9 wells from the Albatros, Minerva, East Lebăda, West Lebăda, Sinoe, Portiţa, Midia, Ovidiu and Cobălcescu oil and gas fields were analysed for organic matter content and source rock potential. The results obtained show that Oligocene can be considered as source rock, but its potential of hydrocarbon generation becomes obvious only in the Ovidiu-Cobălcescu area (TOC between 0.4 and 3%, average 1.35%). Also, the extension of Oligocene to south-eastward, in the area of the deeper basin could be favourable (Morosanu, 2012). The investigated Oligocene sediments show that these rocks are immature or very close to the maturity limit, but are not in the oil window (Geochem, 1993, 1994). In the last decade many isotopic and molecular analyses of the oils and bitumen extracted from the source rocks were performed (Şaramet, 2004, Şaramet et al. 2005, Cranganu and Şaramet, 2011) and

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was confirmed the main role of Oligocene deposits in the generating of oil and gas from the north-eastern flank of the Histria depression.

Chance of success component description

Occurrence of shale

Mapping status Moderate depth map, thickness map based on interpolation/average values (few datapoints)

Sedimentary variability Moderate depositional environment changes gradually throughout the basin

Structural complexity Low

HC generation

Available data Good

Proven source rock Proven HC fields in study area proven to be sourced from shale gas layer

Maturity variability Moderate From immature in the shallow areas to at least oil mature more towards the basin center.

Recoverability

Depth Shallow to deep

Mineral composition No data

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Balteș, N. (1983a). The relationship between phytometamorphism and the oil and gas- bearing potential of the Bibesti-Bulbuceni area, (in Romanian, with English abstract). Studii si cercetari de Geologic Academia Romana, Bucuresti, 29, 54-59

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Cavazza W., Roure F., Spakman W., Stampfli G., Ziegler P.(Eds) (2004) The Transmed Atlas – the Mediterranean region – from crust to mantle - Transect III. Springer (CD- ROM).

Colţoi, O., Nicolas, G., Safa, P., 2016. The assessment of the hydrocarbon potential and maturity of Silurian intervals from Eastern part of Moesian Platform – Romanian Sector. Marine and Petroleum Geology, Volume 77, Pages 653–667

Cranganu, C., Villa, M. A., Şaramet, M., Zacharova, N., 2009. Petrophysical characteristics of source and reservoir rocks in the Histria Basin, Western Black Sea. Journal of Petroleum Geology, 32, 357-372.

Cranganu, C., Şaramet, M., 2011. Hydrocarbon generation and accumulation in the Histria Basin of the Western Black Sea. In: A. L. Ryann and N. J. Perkins (Eds), The Black Sea: Dynamics, Ecology and Conservation, Nova Publishers, 243-263.

Daborowski, T. and Groszkowski, J., 2012. “Shale Gas in Bulgaria, the Czech Republic and Romania: Political Context, Legal Status, and Outlook.” Centre for Eastern Studies, Warsaw, Poland, 30 p.

Dabovski, C., Boyanov, I., Khrischev, Kh., Nikolov, T., Sapounov, I., Yanev, Y., Zagorchev, I. (2002) Structure and Alpine evolution of Bulgaria. Geologica Balc., 32, 2–4; 9–15.

Dabovski, C., Kamenov, B., Sinnyovski, D., Vasilev, E., Dimitrova, E., Bayraktarov, I. (2009) Upper Cretaceous geology. In: Zagorchev, I., Dabovski, C., Nikolov, T. (eds) Geology of Bulgaria, vol. II. 5 Mesozoic geology, Sofia, prof. M. Drinov acad. publ. house, 303-589.

Dabovski, C., Zagorchev, I. (2009) Mesozoic evolution and Alpine structure. In: Zagorchev, I., Dabovski, C., Nikolov, T. (eds) Geology of Bulgaria, vol. II. 5 Mesozoic geology, Sofia, prof. M. Drinov acad. publ. house, 13-37.

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Dinu, C., Wong, H.K., Tambrea, D., Matenco, L (2005) Stratigraphic and structural characteristics of the Romanian Black Sea shelf. Tectonophysics 410 (2005) 417 – 435

Dinu, C., H. K. Wong, and D.Ţambrea (2002) Stratigraphic and tectonic syntheses of the Romanian Black Sea Shelf and correlation with major land structures, in Geology and Tectonics of the Romanian Black Sea Shelf and Its Hydrocarbon Potential,BGF Spec. Publ.,vol.2, edited by C. Dinu and V. Mocanu, pp. 101–117, Vergiliu, Bucharest.

Georgiev, G. (1996) Development of the Triassic evaporite basin in the Eastern Balkan / Forebalkan foldbelt. In Wessely, G. and Liebl, W. (Eds.): Oil and Gas in Alpidic Thrustbelts of Central and Eastern Europe, EAGE Special Publication No. 5, 201-206.

Georgiev G. (2000). Oil-oil and oil-source correlation for the major crude oils in Bulgaria. Annuaire de l’Universite de Sofia “St. Kliment Ohridski”, Faculte de Geologie et Geographie, l.1 Geologie, t. 92, p. 39-60.

Georgiev G. (2004) Geological structure of Western Black Sea region. In: Proceedins of 66th EAGE Conference & Exhibition, 7-10 June 2004 Paris-France, Extended Abstracts.

Georgiev, G. (2012) In Bulgaria no conditions for shale gas discoveries with economic importance, BGNES, March 2012 (http://video.bgnes.com/view/34064)

Georgiev, G. (2012) Geology and Hydrocarbon Systems in the Western Black Sea. Turkish Journal of Earth Sciences [Turkish J. Earth Sci.], vol. 21, 723-754.

Georgiev G., Atanasov A. (1993) The importance of the Triassic-Jurassic Unconformity to the Hydrocarbon Potential of Bulgaria. First Break, 11, 489 - 497.

Georgiev, G., Bechtel, A., Sachsenhofer, R., Gratzer, R. (2001). Petroleum Play- Concept for Main Oil/Gas Fields in the Southern Moesian Platform (Bulgaria). Proceedings of EAGE 63rd Conference & Technical Exhibition, Amsterdam-The Netherlands, Extended Abstracts (P-512).

Georgiev, G., Botoucharov, N., Bechtel, A. (2007) Oil to Triassic source correlations: an example from Southern Moesian Platform edge (N. Bulgaria). Proceedings of 69th EAGE Conference & Exhibition, 11-14 June 2005 London-England, Extended Abstracts. Georgiev, G., Dabovski, Ch. (1997) Alpine structure and Petroleum geology of Bulgaria. Geology and Mineral resources, 8-9, 3-7.

Georgiev, G., Dabovski, C., Stanisheva-Vassileva, G. (2001) East Srednogorie-Balkan Rift zone. In: P. A. Ziegler, W. Cavazza, A. H. F. Robertson & S. Crasquin-Soleau (Eds.): PeriTethyan Rift/Wrench Basins and Passive Margins (Peri-Tethys Memoir 6), Mem. Mus. natn. Hist.nat., 186, 259-293.

Georgiev, G., Ilieva, A. (2007) Selanovtsi oil accumulation – geological and genetic model. – Annuaire de l’Universite de Sofia “St. Kl. Ohridski”, Fac. Geol. & Geogr., l.1 – Geologie, t. 100, 67 -96.

Georgiev, G., Ognyanov, R. & Bokov, P. (1993) Thrust tectonics in the Northern Balkanides and hydrocarbon prospect evaluation. - 5th Conference and Technical Exhibition of EAPG, Stavanger, Extended Abstracts of Papers (P - 532).

Gheorghe, S., Barbuliceanu, N., Raschitor, G., Burneiu, L. (2004). Comparative study of the carbonate and clay source rocks in the Bibesti - Bulbuceni, Malu Mare, Fauresti

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and Mitrofani perimeter. Romanian National Oil and Gas Symposium brochure (2004) 1-12 (In Romanian)

Ionescu G., 2002. Facies architecture and sequence stratigraphy of the Black Sea offshore Romania. In Dinu C. and Mocanu V. (Eds.), Geology and tectonics of the Romanian Black Sea shelf and its hydrocarbon potential. BGF - Special volume no. 2. 43-51.

Ionescu G., Sisman M., Cataraiani R., 2002. Source and reservoir rocks and traping mechanism on the romanian Black Sea shelf. In Dinu C. and Mocanu V. (Eds.), Geology and tectonics of the Romanian Black Sea shelf and its hydrocarbon potential. BGF - Special volume no. 2, 67-83.

Iordan, M. (1988) Biostratipraphy of the Devonian in Romania. Devonian of the World. Proc. 2nd Intern. Symp. Devonian System, Calgary – 1987, Canada, vol. 14 (1). Canadian Society of Petroleum Geologists, Calgary.

Iordan, M. (1992) Biostratigraphic age indicators in the Lower Palaeozoic succesion of the Moesian Platform of Romania. Geologica Carpathica 43 (4), 231 – 233.

Juranov, S. (1991) Stratigraphy of the Upper Cretaceous series and the Paleogene System in the marine borehole sections at the village of Samotino. Review of the Bul. Geol. Soc., 52, 3, 19-29.

Kalinko, M. K. (ed.) (1976) Geology and oil-gas bearing capacity of Bulgaria. Moscow, Nedra, 242 p., (in Russian).

Kulaksazov, G., Tenchov, Y. (1973) Lower Carboniferous stratigraphy in Dobrudja coal basin. Bulletin of Geological Institute, series of stratigraphy & lithology, 22, 39-53.

Kulke, H. (1994) Bulgaria. In H. Kulke (ed.): Regional Petroleum Geology of the World. Part I: Europe and Asia. Berlin, Stuttgart: Gebrüder Bornträger, 313-317.

Lafargue, E., Ellouz, N.,Roure, N. (1994). Thrust-controlled exploration plays in the Outer Carpathians and their foreland (Poland, Ukraine and Romania). First Break, 12, 69-79

Moroşanu I., 1990. The Tectonic of Preoligocene Formations as Identified by Means of Seismic Data in Portiţa- Lebăda Area ( Romanian Continental Shelf of the Black Sea). Revue Roumaine de Geophysique, 34, 71-87.

Moroşanu I., 1994. New Targets for oil in the Black Sea Tertiary, Symposium of the Petroleum Geology and Hydrocarbon Potential of the Black Sea Area. Special Publication, 39. Varna, Bulgaria.

Moroşanu I., 1996. Tectonic Setting of the Romanian Offshore at the Pre-Albian Level. In Oil and Gas in Thrustbelts and Basins, Alpidic Regions-Central and Eastern Europe. Geological Society of London, Special Publication No. 5, 315-323.

Moroşanu I., 2012. The hydrocarbon potential of the Romanian Black Sea continental plateau. Romanian Journal of Earth Sciences, vol. 86 (2012), issue 2, p. 91-109.

Nikolov, K. 2014. Bulgarian unconventional hydrocarbon resources with a focus on the Carboniferous strata. – In: Geological characteristics of continuous petroleum

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resources and resources abundance evaluation assessment methodology for shale gas/oil in some European countries, MsC thesis, Aalborg University Esbjerg, 73-93.

Nikolov, Z. -ed. (1988) Geology of Dobroudja coal basin. Sofia, Thechnica, 150 p.

Nikolov, Z., Popova, K., Popov, A. (1990) Coal-bearing Upper Paleozoic sediments in R-1 Novacene (Central North Bulgaria). Rev. Bul. Geol. Soc., 51, 1, 39-47.

Okay, A.I., Özcan, E., Cavazza, W., Okay, N., Less, G. (2010) Basement types, Lower Eocene series, Upper Eocene olistostromes and the initiation of the southern Thrace basin, NW Turkey. Turkish Journal of Earth Sciences, 19, 1-25.

Paraschiv, D. (1979a). Romanian oil and gas fields. Institutul de Geologie si Geofizica, Bucuresti. Studii tehnice si economice. Seria A, 13

Paraschiv, D. 1979b. Moesian Platform and its hydrocarbon fields (in Romanian, with English abstract). Editura tehnica, Bucuresti

Paraschiv, D. 1983. Stages in the Moesian Platform history. Anuarul Institutului de Geologie si Geofizica, LX, 177-188

Paraschiv, D. 1984. The evolution of the hydrocarbon field distribution in the Moesian Platform. Anuarul Institutului de Geologie si Geofizica, LXTV, 205-213

Pătruț, I., Butac, A., Balteș, N. (1983). Main stages of hydrocarbon generation and accumulation on the Romanian territory of the Moesian Platform. Anuarul Institutului de Geologie si Geoflzica, LX, 315-322

Pene, C. (1996). Hydrocarbon generation modelling in the west of the Moesian Platform, Romania. Petroleum Geoscience, Vol. 2, 1996, pp.241-248

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Popescu, B. M. (1995). Romania’s petroleum systems and their remaining potential. Petroleum Geoscience 1, 337-350

Sachsenhofer, R. F., Stummer, B., Georgiev, G., Bechtel, A., Gratzer, R., Coric, S., Dellmour, R. (2009) Depositional environment and source potential of the Oligocene Ruslar Formation (Western Black Sea). Marine and Petroleum geology, 26, 57-84.

Sapunov, I. (1983) Jurassic system. In Atanasov, A. &, Bokov, P. (Eds) Geology and oil-gas prospects of Moesian Platform in Central North Bulgaria. Sofia, Technika, 18- 28.

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Şaramet, M., Gavrilescu, Gh., Cranganu, C., 2005. The role of Oligocene formations in hidrocarbon generation and accumulation in the Histria petroleum system of the Romanian shelf of the Black Sea. 27, 295 – 301.

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Todorov, I., Schegg, R., Chochov, S. (1992) Maturity studies in the Carboniferous Dobroudja coal basin (NE Bulgaria) – coalification, clay diagenesis and thermal modeling. International Journal of Coal Geology, 161-185.

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Vuchev, V., Bokov, P., Monov, B., Atanasov, A., Ognyanov, R., Tochkov, D. (1994) Geologic structure, Petroleum exploration development and Hydrocarbon potential of Bulgaria. In: Hydrocarbons of Eastern Central Europe – Habitat, Exploration and Production history (B. M. Popescu – ed.), Springer-Vergal Berlin Heidelberg, 29-69.

Zilinski, R.E., Nelson, D.R., Ulmishek, G.F., Tonev, K., Vladov, J., and Eby, D.E., 2010. “Unconventional Plays in the Etropole Petroleum System, Southern Moesian Plate, Bulgaria.” AAPG Search and Discovery Article 90109 (Abstract), American Association of Petroleum Geologists, European Region Annual Conference, Kiev, Ukraine, October 17-19.

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T05 - Ukraine – Dnieper-Donets Basin Lower Carboniferous Black Shales

General information (see excel table from GEUS) Screening- Index Basin Country Shale(s) Age Index Rudov Beds Upper Visean Dnieper- T5 UA (Upper Visean Shales) (Upper Visean) 1043 Donets Basin (Lower Serpukhovian) (Serpukhovian)

Geographical extent The Eastern Ukrainian Dnieper-Donets Basin (DDB) represents a 700km and 40-70km wide failed rift basin on the Eastern European – Russian Craton that formed during the Mid to Late Devonian. The basin extends to the northwest into the shallower and less prospective Pripyat Trough in Southern Belarus, and continues in southern direction into the Donbas Fold Belt of southwestern Russia. The prospective extent of the basin exists almost entirely within Ukrainian borders.

Figure 1 Geographical extent of the Dniepr-Donets Basin in northeastern Ukraine. The coloured areas represent different basins.

Geological evolution and structural setting

Syndepositional The DDB developed as a rift system within the East European – Russian Craton. Sediments of Devonian to Tertiary age rest on a crystalline basement and have been deposited over four tectonic stages: a Middle Devonian pre-rift sequence, an Upper

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Devonian syn-rift sequence, a thick Carboniferous to Lower Permian post-rift sag sequence and a Triassic to Tertiary post-rift platform sequence. The Carboniferous post-rift sag sequence exceeds 11km of total thickness in the inverted southern Donbas Fold Belt. The black shales and numerous coal seams define the main source for the conventional oil and gas fields in the DDB. During a long period of ca. 290 – 340 million years after the main rift stage, the basin evolved from a deep marine setting into a shallow marine to continental depositional environment as sedimentation rates exceeded subsidence. The Early Visean to Serpukhovian black shales, including the Rudov Beds are of marine origin (Bechtel et al., 2014). The middle to Upper Carboniferous section is mostly parallic to continental and incorporates more than 300 coal seams. Although the architecture of the DDB is relatively simple, strike-slip movements along a main WNW-ESE principal displacement zone affected local depositional environments, resulting in the development of many pull-apart basins that are divided by structural highs.

Structuration Deep-seated dextral en-echelon faults belonging to a principal WNE-ESE displacement zone, define the main intra-basinal structural trend of the DDB. This trend developed during the syn-rift and post-rift sag stage and resulted in the formation of many half- grabens with dimensions in the order of 50-100km by 20-40km (Ulmishek, 2001). The basin itself is bounded by two major NW-SE trending basement fault systems. After the post-rift sag stage, the basin succession was strongly inverted and folded in the Donbas Fold Belt located south of Ukraine. This belt formed as a result of Hercynian continental collision and compression.

Organic-rich shales

Depth and thickness The depth of the Lower Carboniferous black shales in the DDB varies between 100 and 8000m. The total thickness of the Lower Carboniferous interval ranges from 100m along the basin margins up to 5700m in the center of the basin. The net thickness of prospective layers is estimated to be ca. 400m with a maximum thickness of 800m. Within the total shale interval, the black shales of the Lower Visean Rudov beds are considered the most prospective layer for shale gas. These beds are on average 30- 40m thick with maximum observed thicknesses of ca. 70m. The Upper Visean and Lower Serpukhovian shales are reported to be less rich in TOC. Thicknesses are not reported but estimated to range between 100 and 800m.

Shale gas/oil properties The northwestern and central part of the basin and the flanks are least mature, mostly staying within the oil window. Towards the southeast and deepest parts of the basin maturity increases and moves into the dry gas window.

The organic-rich middle section of the Rudov Beds has 3.0% to 10.7% TOC (average 5%), mostly Type III with some Type II kerogen. Additional slightly leaner (TOC of 3.0% to 3.5%) but still quite prospective source rocks occur in the Upper Visean above the Rudov Beds, while the Lower Serpukhovian contains black shales with up to 5% TOC.

Thermal maturity of the Rudov Beds and the overlying Upper Visean is mainly in the oil window (Ro 0.8-1.0%) in the central and northwestern DDB, increasing to dry gas maturity (Ro 1.3-3.0%) in the southeast. For example, the Rud-2 petroleum well in the DDB penetrated a nearly 1-km thick Carboniferous Upper Visean shale interval at a depth of 4 to 5 km TOC of up to 4% in this interval is within the oil thermal maturity

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window (Ro 0.8-1.0%). The oil window in this basin appears to be normally to under- pressured, while the dry gas window is likely to be over-pressured due to ongoing gas generation, although pressure data control is poor.

The Rudov Beds are rich in siliceous radiolarian with high porosity (6%), making them potentially brittle, while the lower part of the formation is high in calcite as well as clay. They are considered prospective within a 10,150-mi2 depth-controlled belt that surrounds the axis of the DDB (predominantly Srebnen and Zhdanivske depressions). Salt intrusions may sterilize some of the mapped prospective area (ca. 10%)

Chance of success component description Occurrence of shale

Mapping status Moderate The DDB has been extensively explored with many wells drilled.

Sedimentary variability Low to Moderate Marine conditions existed throughout the basin when the shales were deposited.

Structural complexity Low to Moderate Subsidence alternated with several compressional pulses and salt tectonics. A simple dip slope architecture exists at the southwest flank while a more faulted and tectonically complex situation is found at the northeast flank. The heavily deformed and folded Donbas Fold Belt does not belong to the prospective area.

Hydrocarbon generation

Available data Good

Proven source rock Proven The DDB contains a mature oil and gas system with >200 proven oil and gas reservoirs and information from over 1000 wells.

Maturity variability Moderate The distribution of maturity is quite well understood and varies gradually with some local degradation due to salt tectonic movements and uplift

Recoverability

Depth Average 1000-5000m

Mineral composition Poor very clay rich (>50% clay content)

References

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Arsiriy, Yu.A., Bilyk, A.A., et al (Eds), 1984. Atlas of geological structure and oil-gas- bearing of Dniprovsko-Donetska Depression - Kyiv: Ministry of Geology of Ukrainian SSR, UkrNIGRI. - 190 p. (In Russian).

Bechtel, A., Gratzer R., Makogon V., Misch D., Prigarina T., and Sachsenhofer, R. F., 2014. Oil-Source Rock and Gas-Source Rock Correlations in the Dniepr Donets Basin (Ukraine): Preliminary Results. AAPG International Conference & Exhibition, Istanbul, Turkey, September 14-17, 2014

EIA, 2013. Technically Recoverable Shale Oil and Shale Gas Resources. U.S. Energy Information Administration (EIA). https://www.eia.gov/analysis/studies/worldshalegas/pdf/Eastern_Europe_BULGARIA_ ROMANIA_UKRAINE_2013.pdf

Lazaruk, J.G. 2015, PROSPECTS AND PROBLEMS OF DEVELOPMENT OF SOURCES OF UNCONVENTIONAL HYDROCARBON OF THE VOLYN-PODOLIA OIL AND GAS FIELD OF UKRAINE Paper 1. Perspectives of shale gas of Oleska site. Geological Journal (Ukraine). - 2015.- No 1 p. 7-16

Lukin A.E., 2010. Shale gas and its production prospects in Ukraine. Paper 2. Black shale complexes of Ukraine and the prospects for their gas content in the Volyn- Podolia and the North-Western Black Sea region. Geological Journal (Ukraine). - 2010.- No 4 p. 7-24

Lukin, A.E., 2010. Shale gas and perspectives of its exploitation in Ukraine. Paper 1. Shale gas problem state-of-art (based on its resources development in USA), Geological Journal (Ukraine). - No. 3. - p. 17-33 (In Russian).

Lukin, A.E., 2011. Perspectives of shale gas in Dniprovsko-Donetskiy Aulacogene, Geological Journal (Ukraine). - No. 1. - p. 21-41 (In Russian).

Lukin, A.E., 2011. On the nature and gas-bearing perspectives of the low permeable rocks in the sedimentary layer of the Earth. Proceedings of the National Academy of Sciences of Ukraine. - No. 3. - p. 114-123 (In Russian).

Sachsenhofer, R.F., Shymanovskyy, V.A., Bechtel, A., Gratzer, R., Horsfield, B., Reischenbacher, D., 2010. Paleozoic source rocks in the Dnieper-Donets Basin (in Ukraine) / Pet. Geosci., v. 16, p. 377-399.

Ulmishek, G.F., 2001. Petroleum Geology and Resources of the Dnieper-Donets Basin, Ukraine and Russia. U.S. Geological Survey Bulletin 2201-E - Version 1.0

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T06 - Poland – Lower Carboniferous shales of the Fore- Sudetic Monocline Basin

General information (see excel table from GEUS) Screening- Index Basin Country Shale(s) Age Index Forel-Sudetic Lower Carboniferous Lower T6 Monocline PL 1055 shales and siltstones Carboniferous Basin

Geographical extent The Fore-Sudetic Monocline Basin (FSMB) is a ca. 200km by 100km, NW-SE oriented Carboniferous basin in the western part of Poland (Figures 1 and 2). The entire basin is positioned in Poland and considered to be a southern continuation of the Mid-Polish Trough. The Lower Permian Rotliegend sandstone has been developed for tight gas production while shale gas is being explored in the Lower Carboniferous interval. With its regular shape, the structural geology of the basin is relatively simple, but poor quality of available seismic data in this region masks the true geologic structure.

Figure 1 Geographical extent of the Lower Carboniferous shales in the Fore-Sudetic Monocoline basin in southwestern Poland. The coloured areas represent different basins.

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Figure 2 The target basins for shale gas and oil in Poland: 1-4 - resource assessment units within the onshore Lower Paleozoic Baltic-Podlasie-Lublin basin (after Kiersnowski and Dyrka, 2014), 5 -Lower Carboniferous basin of the Fore-Sudetic Monocline (FSMB).

Geological evolution and structural setting

Syndepositional The Lower Carbiferous shales of the FSMB (actually claystones, siltstones and mudstones, accompanied by sandstones, coals and carbonates), are associated with the development of depositional facies in the Variscan flysch basin in Visean and Namurian A. They are the source rocks in case of Rotliegend conventional and tight gas fields in the Polish Southern Permian basin (Wójcicki et al., 2014). These source rocks contain organic matter mostly of a humic nature gas-prone Type III kerogen of a non (deep) marine origin and, rarely, mixed Type II/III kerogen (Botor et al., 2013).

The Lower Carboniferous shales of the FSMB might be an equivalent of Lower Carboniferous black shales (Culm) in Northwest German Basin (Ladage and Berner, 2012), and, to some extent, Lower Carboniferous Bowland shales in northern England (Andrews, 2013). However, there is no direct connection between Polish and German plays.

Structuration The Lower Carboniferous flysch complex in question (Culm) is characterized by a complicated tectonic setting of fold and thrust deformations (Mazur et al., 2003; Wójcicki et al., 2014), which makes it difficult to recognize the regularities governing their natural cracks. It was uplifted in Late Carboniferous to Early Permian, when volcanic activity peaked, then a substantial burial in Mesozoic occurred, and in Late

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Cretaceous to Paleogene a massive uplift and erosion took place, especially in S and SE part of the FSMB area (Botor et al., 2013).

Organic-rich shales

Depth and thickness The present-day depth of the top of Lower Carboniferous within the FSMB is 1250- 3750 m, increasing towards NNE. The top of gas window zone appears within depth range of about 1700-3500 m (deepest in north) and thickness of gas window zone is over 1000 m (Wójcicki et al., 2014).

Thickness of the Lower Carboniferous shales within the FSMB is not known in detail (most likely several hundred meters). In Siciny 2 well (San Leon, 2012) two shale gas intervals (gross thickness 195 and 105 m, respectively) were encountered within depth range of about 2000-3000 m. One is found in Namurian A and one in Visean (gross thickness 130 m). Furthermore two tight gas intervals appear within the same complex. Based on this information, the mean gross thickness of Lower Carboniferous shales in Siciny 2 well is estimated to be 430 m.

Shale gas/oil properties Prospective formations of Lower Carboniferous within the FSMB (Fig 1) occur within gas window (1.1<=Ro<3.5) only. Values of key reservoir parameters are based on information available in publications and presented in Table 1.

Thermal maturity of Lower Carboniferous shales in the area of the FSMB increases towards SE, NW and N (Botor et al., 2013), and generally ranges within the assessment unit between 1.1-3.0 % (wet and dry gas window). In southern and northernmost part of the area the Lower Carboniferous shales exhibit highest maturity values, while lowest maturity is found in the central part. Average TOC content is in a range of 1 % to 2 % (Botor et al., 2013).

The Lower Carboniferous shales of the FSMB are characterized by a wide range of clay content (25 - 66 %), porosity (1.36 - 8.10 %; average 3.7 %) and gas saturation of pore spaces (30-80 %; San Leon, 2012). In Siciny 2 well the average TOC of clean Lower Paleozoic shales is about 1.55 % (range 1,2-3.25 %; San Leon, 2012). There is no published information regarding the share of shales with TOC>2%. Therefore the effective thickness of prospective shales in the FSMB is set to the value of net thickness proposed by EIA (2013, 2015), which is estimated to be 55 m. However, as an average value of TOC in this play, a value halfway between the threshold (2.0%) and the maximum value (3,25 %), i.e. 2.63 %, seems to be more likely than the value assumed by EIA (2013, 2015), i.e. 3 %. This may result in a reduction of effective thickness.

Assuming average porosity and median value of gas saturation obtained in case of Siciny 2 well (San Leon, 2012), average gas filled porosity can be estimated as about 2 %. Average value of adsorbed gas content (Langmuir isotherm/sorption capacity) 1.25 m3/t (average of values measured in 15 US shale basins) and average density of shale 2.6 kg/m3 (Andrews, 2013) can be ascertained provisionally. According to San Leon press release (San Leon, 2012) a slight overpressure was registered in Lower Carboniferous shales in Siciny 2 well.

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Risk components Occurrence of shale

Mapping status Poor Continuity of the shales is mostly assumed from indirect evidence as well data are very sparse and available seismic data is of poor quality.

Sedimentary variability High

Structural complexity Moderate to High Fold and thrust deformation as well as younger phases of extensive subsidence and uplift

Hydrocarbon generation

Available data Moderate Only very little data is available to determine the distribution of TOC and maturity.

Proven source rock Proven The FSMB does contain a proven gas system which is sources from the Lower Carboniferous.

Maturity variability Moderate Regional trends suggest it improves in SE, NW and N direction.

Recoverability

Depth Average 1000-5000m

Mineral composition Unknown average mineral composition does not allow any assumptions on fraccability

References

Andrews I.J., 2013. The Carboniferous Bowland Shale gas study: geology and resource estimation. British Geological Survey for Department of Energy and Climate Change, London, UK.

Andrews, I.J., 2014. The Jurassic shales of the Weald Basin: geology and shale oil and shale gas resource estimation. British Geological Survey for Department of Energy and Climate Change, London, UK.

ARI (Advanced Resources International Inc)., 2009 Vello A. Kuuskraa, Scott H. Stevens, Advanced Resources International "Worldwide Gas Shales and Unconventional Gas: A Status Report, December 2009. Report for EIA (Energy Information Administration: Washington, DC.), Annual Energy Outlook. 2009.

Botor D., Papiernik B., Maćkowski T., Reicher B., Kosakowski P, Marzowski G., Górecki W. 2013. Gas generation in Carboniferous source rocks of the Variscan foreland basin:

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implications for a charge history of Rotliegend deposits with natural gases. Annales Societatis Geologorum Poloniae 83, pp. 353-383.

Charpentier, R.R., and Cook, T.A., 2010. Improved USGS methodology for assessing continuous petroleum resources, version 2: U.S. Geological Survey Data Series 547, 22 p. and program. Revised November 2012.

EIA, 2011. Analysis & Projections. World shale gas resources: An initial Assessment of 14 regions outside the Unites States. U.S. Energy Information Administration.

EIA (U.S. Energy Information Administration), 2013. Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States. June 2013. Washington DC.

EIA (U.S. Energy Information Administration), 2015. Technically Recoverable Shale Oil and Shale Gas Resources: Poland. September 2015. Washington DC.

Gautier, D.L., Pitman, J.K., Charpentier, R.R., Cook T., Klett, T.R.& Schenk, C.J., 2012. Potential for Technically Recoverable Unconventional Gas and Oil Resources in the Polish-Ukrainian Foredeep, Poland, 2012. Ed. Stauffer P.H., U.S. Department of the Interior, U.S. Geological Survey. Fact Sheet 2012–3102.

Górecki W. (ed.), 2006. Atlas of geothermal resources of Paleozoic formations in the Polish Lowlands. AGH, 2006, Kraków.

Grotek I. 2006. Thermal maturity of organic matter of sedimentary cover of Pomeranian sector of Teisseyre-Tornquist zone, Baltic basin and neighboring areas. Prace Państwowego Instytutu Geologicznego, 186: 253-270 (in Polish).

Jaworowski K., Modliński Z., 1968. Lower Silurian nodular limestones in north-eastern Poland. Geological Quarterly, 12(3): 493-506 (in Polish).

Karcz P., 2015. Shale Gas Potential of the North-Central Onshore Area of the Baltic Basin. Tethys - Atlantic Interaction Along the European-Iberian-African Plate Boundaries. AAPG European Regional Conference, 18-19.05.2015, Lisbon, Portugal.

Karnkowski P., 1999. Oil and Gas deposits in Poland. „GEOS”, Kraków.

Kiersnowski H., Dyrka I., 2013. Ordovician-Silurian shale gas resources potential in Poland: evaluation of Gas Resources Assessment Reports published to date and expected improvements for 2014 forthcoming Assessment. Przegląd Geologiczny, vol. 61, no. 11/1, 2013.

Klimuszko E. 2002. Silurian sediments from SE Poland as a potential source rocks for Devonian oils. Biuletyn Państwowego Instytutu Geologicznego, 402: 75-100 (in Polish).

Krzywiec P., 2011. Interpretacja tektoniczna profili sejsmicznych w rejonie otworu wiertniczego Darżlubie IG 1. Profile Głębokich otworów wiertniczych Państwowego Instytutu Geologicznego, Zeszyt 128 – Darżlubie IG 1, 151-153 (in Polish).

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Ladage S., Berner U. (eds), 2012. Abschätzung des Erdgaspotenzialsausdichten Tongesteinen (Schiefergas) in Deutschland. Raport BGR, Hannover, maj 2012.

Lazauskienė J., 2015. Unconventional Hydrocarbon Systems and Potential in Lithuania. EUOGA kickoff meeting Copenhagen, 7/12-2015 (presentation).

Mazur S., Kurowski L., Aleksandrowski P., Żelaźniewicz A., 2003. Variscan Fold-Thrust Belt of Wielkopolska (W Poland): new structural and sedimentological data. Geolines v. 16, pp. 71-73.

Modliński Z., Szymański B., 1997. The Ordovician lithostratigraphy of the Peribaltic Depression (NE Poland). Geological Quarterly, 41(3): 273-288.

Modliński Z., (ed.), 2010. Paleogeological atlas of the sub-Permian Paleozoic of the East-European Craton in Poland and neighboring areas. PGI-NRI, Warsaw, Poland.

Nehring-Lefeld M., Modliński Z., Swadowska E., 1997. Thermal evolution of the Ordovician in the western margin of the East-European Platform: CAI and Ro data. Geol. Quart., 41(2): 129-138.

PGI-NRI, 2012. “Assessment of Shale Gas and Shale Oil Resources of the Lower Paleozoic Baltic-Podlasie-Lublin Basin in Poland, First Report.” Warsaw, Poland.

Poprawa P., Šliaupa S., Stephenson R.A., Lazauskienė J., 1999. Late Vendian-Early Palaeozoic tectonic evolution of the Baltic Basin: regional implications from subsidence analysis. Tectonophysics, 314: 219-239.

Poprawa, P., 2010. Shale Gas Potential of the Lower Palaeozoic Complex in the Baltic and Lublin-Podlasie Basins (Poland). Przegląd Geologiczny, volume 58, p. 226–249 (in Polish).

Sandrea R., Sandrea I., 2014. New well-productivity data provide US shale potential insights. Oil & Gas Journal, Vol. 112, Issue 11, 11/03/2014.

San Leon Energy, 2012. San Leon Energy provides Siciny-2 update. News Release, 26 June 2-12.

Schovsbo N. H., 2015. Overview of the status for shale oil/gas in Denmark. EUOGA kick-off meeting Copenhagen, 7/12-2015 (presentation).

Swadowska E., Sikorska M. 1998. Burial history of Cambrian rocks of the Polish part of the East European Platform as based on reflectance of vitrinite-like macerals. Prz. Geol., 46(8): 699-706 (in Polish).

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Tari G., Poprawa P., Krzywiec P., 2012. Silurian Lithofacies and Paleogeography in Central and Eastern Europe: Implications for Shale Gas Exploration. Society of Petroleum Engineers – SPE 151606.

Wójcicki A., Kiersnowski H., Dyrka I., Adamczak-Biały T., Becker A., Głuszyński A., Janas M., Kozłowska A., Krzemiński L., Kuberska M., Pacześna J., Podhalańska T., Roman M., Skowroński L., Waksmundzka M.I., 2014. "Assessment of undiscovered gas resources in selected tight gas reservoirs of Poland". PGI-NRI, Warsaw (in Polish with English summary).

Wood Mackenzie, 2009. Unconventional Gas Service. Analysis Poland/Silurian Shales, August 2009.

Żelichowski A.M., Kozłowski S., (red.), 1983. Atlas of geological structure and mineral deposits in the Lublin region. Polish Geological Institute, Warsaw (in Polish).

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T07a - Hungary – Kössen Marl, Zala Basin

General information (see excel table from GEUS) Screening- Index Basin Country Shale(s) Age Index Zala Basin Norian, Late T7a HU Kössen Marl 1049 (Pannonian) Triassic

Geographical extent Formations representing the evolution of the Kössen Basin (Rezi Dolomite, Kössen Formation) are known in the southwestern part of the Transdanubian Range Unit (Figures 1 and 2). They overlie the platform facies of the Main Dolomite and, interfingering with the Dachstein Formation, pinch out northeastward (Haas 2012).

Figure 1 Location of the Kössen Marl. The coloured areas represent different basins.

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Figure 2 Basins with discovered and prospective unconventional hydrocarbon resources in Hungary (KOVÁCS and FANCSIK 2015)

Geological evolution and structural setting

Syndepositional setting At the end of the Middle Norian, as a prelude to the Ligurian-Penninic Ocean Branch formation in the southwestern part of the Transdanubian Range, extensional basins began to form leading to stabilization of the restricted subtidal conditions in this area. Thinly bedded bituminous dolomite (Rezi Dolomite) in the Southern Bakony and the Keszthely Mts. represents this sedimentary environment (Végh 1964; Budai and Koloszár 1987; Haas 1993, 2002). In the Late Norian, a significant climatic change led to increased influx of fine terrigenous material and deposition of dark grey, organic rich marl and clayey marl in the restricted basin (Kössen Formation). The thickness of this formation is a few hundred metres in the inner part of the basin. In coquina layers or lenses a rich bivalve fauna (Rhaetavicula contorta (Potlock), Modiola, Pteria, Gervillia) can be found. As a consequence of the development of the "Kössen Basin" the previously marginal carbonate platform was transformed into an isolated platform (Haas 2012) and, most probably due to the more humid climatic conditions from the beginning of the Late Norian on the pervasive early dolomitization came to an end in the platform area (Haas and Budai 1999). Subsequently only partially dolomitized and later on undolomitised sequences were formed. In the inner part of the platform cyclic, peritidal-subtidal (lagoonal) carbonate accumulation continued until the Late Rhaetian. A prevailing part of the 500-800 m-thick Lofer-cyclic Dachstein Limestone was deposited in this period (Haas 2012).

Structural setting The area of the Zala Basin is part of the larger Transdanubian Range Unit which is bounded by major structural lineaments and was one of the exotic terranes that were squeezed out from their earlier position during the early Tertiary as a result of the northward motion of the Adria Microplate (Haas et al. 2009). The Zala Basin was affected by uplift during the Alpine orogeny. Oil generation and expulsion in the Zala

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basin began in the Miocene during rapid subsidence and heating caused by lithospheric extension in the Pannonian basin.

Organic-rich shales

Depth and thickness The extent of the Kössen Marl has been investigated in the wells drilled in the Zala Basin and in Transdanubian Range outcrops. There are 534 wells drilled in the area, which have well-top information. 230 wells were drilled into the Triassic, but only 32 wells penetrated the Kössen Marl, as over large areas it had been eroded during Alpine orogenic events in Cretaceous and Palaeogene times (KŐRÖSSY, 1988). The thickness of the formation in the Zala Basin wells ranges between 17 and 575 m, with an average of 200 m, while the total area is around 1500 km2 (BADICS and VETŐ 2012). In the outcrops in the Transdanubian Range it varies between 150 m and 50 m and finally thins to 30 m in the north-east (Haas, 1993).

The Kössen Marl has been eroded in the north-western part of the basin, where Upper Cretaceous strata directly overlie the eroded top of the thick Norian Main Dolomite. Towards the west and south-west, the formation is buried very deeply, down to 5000- 6000 m, under thick Upper Cretaceous and Neogene sediments, so its presence under the western part of the Zala Basin and in Slovenia is likely but unproven. Towards the south it is eroded again along the strike-slip zone of the Balaton line. Beneath the southern part of the Zala Basin, south of the Balaton Line, Triassic strata belong to the South Karavanka Unit, which has a different non-source facies.

Shale gas/oil properties The Kössen Formation consists of marl, limy marl, dolomitic marl or silty marl, with limestone and dolomite interbeds, mainly in the transitional parts. It is very rich in organic material and includes alginite in places (Solti G. et al., 1987). The rock composition is monotonous. It is dominantly pelitic in the internal parts of the depositional basin. Towards the basin margins, in the transitional zones, dolomitic limestone, clayey limestone, marl, and limy marl layers alternate cyclically, and the proportion of pelitic layers gradually decreases. The type of lamination changes depending on the rock composition. Marls are thin bedded, laminated. Calcareous marl and argillaceous limestone is thin-bedded, with undulating parting surfaces; clayey interbeds and flaser structure are discernible. Interbeds of argillaceous dolomite are thin-bedded, sometimes even microlaminated and platy. The dark grey colour is characteristic of the limestone and dolomite interbeds but especially of the marly rock types. Limestone interbeds are often greenish or brownish and sometimes they are spotted. The shade of grey colour depends primarily on the organic material and also on the pyrite content. On weathered surfaces these rocks are faded or brownish in colour.

The bulk organic geochemistry of the formation (BRUKNERWEIN and VETŐ, 1986; HETÉNYI, 1989; VETŐ et al., 2000; HETÉNYI et al., 2002) and an evaluation of the planktonic production and preservation of the organic matter (VETŐ et al., 2000) have been published in detail. These publications used data mainly from the two scientific boreholes, Zalaszentlászló-1 (Zl-1) and Rezi-1 (Rzt-1). In both wells the entire sequence contains immature algal kerogen, the vitrinite-reflectance is between 0.32 and 0.35%, while the T-max values range from 395 to 435 ˚ C. In the 131 samples analysed the TOC content ranges between 0.07 and 31.5%, with an average of 3.86%. The S2 average is22 mg HC/g rock; the HI average is 516 mg HC/g TOC(Fig. 10 ).In all but one of the 36 samples studied, the atomic Sorg /Corg ratio values are 0.04-0.19; they commonly contain type IIS kerogen. The total carbonate content is

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40-90%, the quartz is 4-20% and the clay is 8-42%. Clay minerals consist mostly of kaolinite and illite-smectite (VETŐ et al., 2000; HETÉNYI et al., 2002) (BADICS and VETŐ 2012 ).

The thermal and maturity history and timing of the hydrocarbon generation in the Zala basin has been investigated by PetroMod software (BADICS and VETŐ 2012). A 3D basin model was created using regional depth maps. The observed present-day surface heat-flow and heat-flow evolution during the Neogene (DÖVÉNYI and HORVÁTH, 1988; Dövényi, 1994) and the average annual temperature (12 C) were used as thermal boundary conditions. The observed surface heat flow in the Zala Basin is 80-100 mW/m2. The 3D model was calibrated to match the measured temperature and vitrinite reflectance data in 25 wells. The amount of eroded section during the Late Cretaceous-Palaeogene uplift event was estimated. The present-day heat-flow could be calibrated very accurately due to the large number of calibration wells. The employed heat-flow history resulted in an uncertainty of the calculated maturity values of (plus-minus) 0.2% Ro. Most of the burial and thermal maturation took place in the Neogene, so the timing uncertainty was small. The calculated present-day maturity map is shown in Fig. 10f. The deepest part of the Kössen Marl is at 250 C, this being in theory gas generation zone today in the south-western parts of the basin. Under the Nagylengyel field the Kössen Marl is still calculated to be in the oil generation window, while in the north-east it is immature. The gas-mature area is around 270 km2, the oil mature is 450 km2 and the immature area is 780 km2 (BADICS and VETŐ 2012).

The Kössen Marl in the basin center was buried into the oil generation zone between 15 and 12 Ma, and into the gas generation zone from 12 Ma onwards in the southwest, based on 3D basin modelling study of the Zala basin. The present-day maturity and maturity history broadly confirm the results of CLAYTON and KONCZ (1994).

Risk components

Occurrence of shale

Mapping status Good A relatively large amount of well data is available and many studies have been performed in the area.

Sedimentary variability Low very homogeneous character throughout the basin

Structural complexity Moderate Challenging due to the influence of tectonic events near the Alpine orogeny.

HC generation

Available data Moderate

Proven source rock Proven Several fields producing Triassic oil are known in the area. Koncz (1990) and CLAYTON and KONCZ (1994) confirmed the oil-source rock correlation, therefore the Kössen-Cretaceous(!) petroleum system can be considered as known (BADICS and VETŐ 2012).

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Maturity variability Moderate

Recoverability

Depth Average 1000-5000m

Mineral composition Unknown to Favourable average mineral composition varies between 8 to 40% of clay

References BADICS, B., VETŐ, I., 2012, Source rocks and petroleum systems in the Hungarian part of the Pannonian Basin: The potential for shale gas and shale oil plays: Marine and Petroleum Geology 31, 53-69 http://www.sciencedirect.com/science/article/pii/S0264817211002017

BRUCKNER-WEIN, A., VETŐ, I.,1986, Preliminary organic geochemical study of an anoxic Upper Triassic sequence fromW. Hungary: Organic Geochemistry 10, 113-118. http://www.sciencedirect.com/science/article/pii/0146638086900148

CLAYTON, J.L., KONCZ, I., 1994, Petroleum geochemistry of the Zala Basin, Hungary: American Association of Petroleum Geologists Bulletin 78, 1-22.

DANK, V., 1985. Hydrocarbon exploration in Hungary, in: Hala, J. (Ed.), Neogene mineral resources in the Carpathian Basin. Budapest, Hungarian Geological Survey, 8th Congress of the Regional Committee on Mediterranean Neogene Stratigraphy, pp. 107-213.

DANK, V., 1988, Petroleum geology of the Pannonian Basin, Hungary – An overview. In: Royden, L.H., Horváth, F. (Eds.), The Pannonian Basin: A Study in Basin Evolution: American Association of Petroleum Geologists Memoir, vol. 45, 319-331.

DOLTON, G.L., 2006, Pannonian Basin Province, Central Europe (Province 4808), Petroleum Geology, Total Petroleum Systems, and Petroleum Resource Assessment.: U.S. Geological Survey Bulletin, vol. 2204-B 47.

DÖVÉNYI, P., HORVÁTH, F., 1988, A review of temperature, thermal conductivity, and heat flow data for the Pannonian basin. In: Royden, L., Horváth, F. (Eds.), The Pannonian Basin: A Study in Basin Evolution: American Association of Petroleum Geologists Memoir, vol. 45, 195-233.

HAAS, J., 1993, Formation and evolution of the Kössen Basin in the Transdanubian Range: Földtani Közlöny 123, 34-54.

HAAS, J., HÁMOR, G., JÁMBOR, Á, KOVÁCS, S., NAGYMAROSY, A., SZEDERKÉNYI, T., 2012, Geology of Hungary. Springer, London, p.244

HAAS, J., BUDAI, T., CSONTOS, L., FODOR, L., KONRÁD, GY, 2010, Pre-Cenozoic Geological Map of Hungary, 1:500 000: Geological Institute of Hungary.

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HETÉNYI, M., 1989, Hydrocarbon generative features of the upper Triassic Kössen Marl from W. Hungary: Acta Mineralogica-Petrographica Szeged XXX, 137-147.

HETÉNYI, M., BRUKNER-WEIN, A., SAJGÓ, CS., HAAS, J., HÁMOR-VIDÓ, M., SZÁNTÓ, ZS., TÓTH, M., 2002, Variations in organic geochemistry and lithology of a carbonate sequence deposited in a backplatform Basin (Triassic, Hungary): Organic Geochemistry 33, 1571-1591. http://www.sciencedirect.com/science/article/pii/S0146638002001882

KONCZ, I., 1990, The origin of the oil at the Nagylengyel and nearby fields: General Geological Review Journal of the Hungarian Geological Society 25, 55-82 (in Hungarian with English abstract).

KÖRÖSSY, L., 1988, Hydrocarbon geology of the Zala Basin, Hungary: General Geological Review Journal of the Hungarian Geological Society 23, 3-162 (in Hungarian with English abstract).

SZALAY, Á, KONCZ, I., 1991, Genetic relations of hydrocarbons in the Hungarian part of the Pannonian Basin. In: Spencer, A.M. (Ed.), Generation, Accumulation and Production of Europe’s Hydrocarbons: Special Publication of the European Association of Petroleum Geoscientists, vol. 1, 317-322.

VETŐ, I., HETÉNYI, M., HÁMOR-VIDÓ, M., HUFNAGEL, H., HAAS, J., 2000, Anaerobic degradation of organic matter controlled by productivity variation in a restricted late Triassic Basin: Organic Geochemistry 31, 439-452. http://www.sciencedirect.com/science/article/pii/S0146638000000115

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T07b - Hungary – Tard Clay, Hungarian Palaeogene Basin

General information (see excel table from GEUS) Screening- Index Basin Country Shale(s) Age Index Hungarian T7b Palaeogene HU Tard Clay Oligocene 1050 Basin

Figure 1 Location of the Tard Clay. The coloured areas represent different basins.

Geographical extent The Hungarian Palaeogene Basin (HPB) is located in the northern part of Hungary, along a SW-NE-striking belt (Haas, 2012). A small part of the basin extends over the border into Slovakia. The basin or basin system was formed over a basement made up of several different pre-Tertiary tectonic units: the Transdanubian Range, the Bükk, the Gemer, and Veporic Units (Haas 2012). To the northwest, in Transdanubia, the Palaeogene formations are bordered by the Rába Lineament; to the northwest the Hurbanovo-Diósjenő Line makes a sharp boundary for the Palaeogene rocks. More to the northwest the original shoreline of the basin forms the boundary of the extension of the Palaeogene formations. To the south and southeast the Palaeogene basin is limited by the Balaton Lineament. South of the Bükk Mts. the limit of the subsurface Palaeogene deposits is uncertain. Some evidence supports the theory (Nagymarosy 1990; Csontos et a1. 1992) that the HPB was previously in a very close palaeogeographic connection with the Slovene Palaeogene Basin; they are probably dislocated parts of a single, large basin. The Tard Clay was deposited in the HPB but it

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might occur also in the eastern parts of the Somogy Trough. Within the HPB the prospective black shales of the Tard Formation cover a total area of ca. 7800 km2.

Geological evolution and structural setting

Syndepositional setting Until the Ottnangian the HPB was divided by the SW-NE directed Buda lineament, a major treshold-like paleorelief element (Báldi and Nagymarosy 1976). The term "Palaeogene Basin" is used here in a wider sense: it comprises all the sedimentary sequences of this area ranging from the Middle Eocene up to the Early Ottnangian. These sequences form a single great sedimentary cycle, and there is no sense in subdividing them artificially. The simplified lithostratigraphic chart of the HPB can be found in Haas (2012).

In Early Oligocene times the Late Eocene sedimentation was followed by the so-called "intra Oligocene denudation" in the area W of the Buda Line (Zala Basin, Bakony, Gerecse, Dorog-Esztergom Basin). The area northwest of the Buda Line was uplifted and denudation removed the top part (locally also even the lower part) of the Eocene sequences in the largest part of the Transdanubian Range. Southeast of the Buda Line sedimentation continued into the Oligocene. During the Kiscellian the HPB became a stagnant, restricted basin. The seaways toward the Mediterranean were shut off due to the orogeny in the South Alpine-Dinaridic belt. Its northern connection to the global marine system had been temporarily closed due to the uplift of the Rhenodanubian Flysch-Magura Flysch Belt. All of these processes might have been combined with a third or second-order eustatic sea level drop between 30 and 32 Ma (Baldi 1986; Nagymarosy 1993; Nagymarosy et al. 1995) and led to the formation of the anoxic Tard Clay Basin. The anoxic environment that existed during the Early Oligocene marks the birth of the Paratethys (Schulz et al. 2005; Piller et al. 2007). Black shales were formed everywhere in the Alpine foreland, the Carpathian Flysch troughs, the Hungarian and Transylvanian Palaeogene Basins. Menilites were formed in the Carpathians. The early Kiscellian (NP 21 to NP 23 nannoplankton zones) in Hungary is characterised by extremely low depositional rates (30-50 m/Ma) is associated with the deposition of anoxic black shale (Tard Clay) which reaches a thickness of ca. 80-100 m in the southern belt of North Hungary. The Tard Clay records a five million year long anoxic cycle initiated by isolation of the sea. This anoxia may have been a consequence of the first separation of the Paratethys, as indicated by the first appearance of Paratethys-endemic molluscs: Cardium lipoldi, Ergenica cimlanica, andfanschinella sp. (Báldi 1986; Popov et al. 1985; Nevesskaja et al. 1987). In the Tard Clay white laminae of monospecific calcareous nannoplankton assemblages alternate with black sapropel indicating probably brackish water conditions (Nagymarosy 1983; Rogl 1998). After the restricted basin conditions of the Tard Clay, normal marine conditions were restored by the Upper Oligocene (Late Kiscellian, NP 24 nannoplankton zone). The pelagic and bathyal Kiscell Clay was deposited in some places in a thickness up to 700-800 m. East of Budapest, the lower member of the Kiscell Clay contains frequent sandstone interbeds which are locally of turbiditic character.

Structural setting The Tard Clay was deposited in the Hungarian Palaeogene Basin, which developed during Eocene and Early Oligocene times as a wrench-basin (Nagymarosy, 1990) or a retro-arc fore deep (TARI et al., 1993) due to the convergence between the Apulian, Pelso and Tisza microplates and the European plate. The Hungarian Palaeogene Basin

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underwent structural inversion in the Middle Oligocene, accompanied by development of an offset trough to the east, followed by general uplift and erosion.

Organic-rich shales

Depth and thickness In the 85 wells that penetrated the Tard Clay (KŐRÖSSY 2004) the thickness ranges between 8 and 200 m (at the type locality it may even reach a thickness of 300 m), with an average of 68 m. In the Buda Mountain outcrops it is around 70 m thick. The depth of the Tard Clay interval ranges between 0 (outcrop) and ca. 6 km)

Shale gas/oil properties The sedimentological and geochemical characterization of the Tard Formation has been described by BRUKNER-WEIN et al. (1990); VETŐ and HETÉNYI (1991); VETŐ et al. (1999), dealing with the Tard Clay profile penetrated by the Alcsútdoboz-3 (Ad-3), Cserépváralja-1 (Cs-1) scientific; and Nagykökényes-I (Nk-I) and Veresegyháza-1(V- 1) exploration wells. The uppermost part and the lower half of the Tard Clay are of marly lithology without lamination, while the bulk of its upper half is dominated by silty lithology and shows well-developed lamination. The silty and well-laminated part of the formation contains up to 60% clay minerals, while their amount ranges between 30 and 40% in the marly lithologies. Smectite makes up about 30-40% of the clay minerals (Viczián pers. comm. in BADICS and VETŐ 2012).

Kerogen in the Ad-3 section is clearly immature with T-max values mostly below 425 C. In the 93 samples analyzed the TOC ranges between 0.41 and 4.98%, with an average of 2.21% (Fig. 18a). The net source rock (>1%TOC) is about 40-50% of the formation thickness based on the Rock-Eval data from the mentioned wells.The S2 average is 6.47 mg HC/g rock; the HI 252 mg HC/g TOC(Fig. 18c). On the TOC vs S2 plot the immature Tard Clay samples are divided into two groups. Silty samples and those from the upper marly interval contain reactive kerogen, rich in hydrogen; the slope of the best-fit line gives HIo (sensu Jarvie et al.,2007) of 433 mg HC/g TOC. This finding agrees well with the high abundance of algae in the palynological residue. The reactive kerogen of the lower marly interval is relatively poor in hydrogen as witnessed by the flatter slope of the best-fit line. Samples from two other immature sections (Cs-1 and V-1) plot to the same area as the Ad-3 samples, so 433 mg HC/g TOC seems to be a good approximation of the HIo for the upper part of the Tard Clay in the whole Palaeogene Basin. The Nk-I exploration well penetrated a mature Tard Clay section between 2930 and 3020 m, characterized by T-max values >430 C. TOC ranges between 1.1 and 3.2%.These values are much below those from the Ad-3 well, as the Tard Clay has realized a significant part of its hydrocarbon potential at this well location (BADICS and VETŐ 2012).

The observed present-day surface heat-flow in the Palaeogene Basin is 80-110 mW/m2 (DÖVÉNYI, 1994). The 3D model of BADICS and VETŐ (2012) was calibrated to match the measured temperature and vitrinite reflectance data in 12 wells. The heat-flow history and the estimated erosion maps used as input could result in an uncertainty of the calculated maturity values of 0.2% Ro. According to 3D regional basin model of BADICS and VETŐ (2012), the section is immature above 1300 m, oil- mature (defined as 0.6-1.3% Ro) between 1300 and 3000 m and gas-mature (defined as >1.3% Ro) below 3000 m, but large local variations exist due to extensive Early and Middle Miocene volcanism. The deepest part of the Tard Clay is at 220-250 C temperature in the dry gas generation zone today in the central part of the basin, north of Nk-I. Between the Demjén and Mezőkeresztes fields in the north-east it is

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also gas-mature. The total gas-mature area is around 1900 km2, the oil mature is ca.2600 km2 and the immature is 3300 km2 (BADICS and VETŐ 2012).

Risk components

Occurrence of shale

Mapping status Good A relatively large amount of wells controls the mapped outlines of the formation.

Sedimentary variability Low very homogeneous character throughout the basin

Structural complexity Low The HPB was characterized by essentially continuous sedimentation from Late Eocene to Middle Miocene times and the development of the basin was strongly controlled by the tectonic movements. Although unconformities can be identified within the Miocene and Pliocene sequences, there was little or no erosion in the inner part of the basin.

Hydrocarbon generation

Available data Moderate

Proven source rock Possible The Hungarian Paleogene Basin is however relatively unexplored for hydrocarbons. Generation of hydrocarbons probably occurred from Late Miocene to present-day, depending on the amount of tectonically induced subsidence. A detailed oil source rock correlation is however missing. Therefore the level of certainty of the Tard-Kiscell petroleum system is only hypothetical (BADICS and VETŐ 2012).

Maturity variability Moderate

Recoverability

Depth Average The depth of the Tard Clay is mostly within the range considered feasible for shale gas/shale oil development (ca. 1-5 km). These depths also strongly overlaps with the intervals in the HPB that are considered mature for oil and gas.

Mineral composition Unknown Average mineral composition does not allow any assumptions on fraccability. The high illite content could represent problems for the fracturing (BADICS and VETŐ 2012).

References BADICS, B., VETŐ, I., 2012, Source rocks and petroleum systems in the Hungarian part of the Pannonian Basin: The potential for shale gas and shale oil plays: Marine

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and Petroleum Geology 31, 53-69 http://www.sciencedirect.com/science/article/pii/ S0264817211002017

BECHTEL, A., HÁMOR-VIDÓ, M., GRATZER, R., SACHENHOFER, R., F., PÜTTMANN, W., 2012, Facies evolution and stratigraphic correlation in the early Oligecene Tard Clay of Hungary as revealed by maceral, biomarker and stable isotope composition: Marine and Petroleum Geology 35, 55-74 http://www.sciencedirect.com/science/article/pii/S0264817212000554

BRUKNER-WEIN, A., HETÉNYI, M., VETŐ, I., 1990. Organic geochemistry of an anoxic cycle: a case history from the Oligocene section, Hungary. Organic Geochemistry 15, 123-130. http://www.sciencedirect.com/science/article/pii/014663809090077D DANK, V., 1988. Petroleum geology of the Pannonian Basin, Hungary – An overview. In: Royden, L.H., Horváth, F. (Eds.), The Pannonian Basin: A Study in Basin Evolution.

DOLTON, G.L., 2006. Pannonian Basin Province, Central Europe (Province 4808) - Petroleum Geology, Total Petroleum Systems, and Petroleum Resource Assessment. In: U.S. Geological Survey Bulletin, 2204-B, 47 http://pubs.usgs.gov/bul/2204/b/pdf/b2204-b_508.pdf

DÖVÉNYI, P., HORVÁTH, F., 1988. A review of temperature, thermal conductivity, and heat flow data for the Pannonian basin. In: Royden, L., Horváth, F. (Eds.), The Pannonian Basin: A Study in Basin Evolution. American Association of Petroleum Geologists Memoir, vol. 45, pp. 195-233.

HAAS, J., HÁMOR, G., JÁMBOR, Á, KOVÁCS, S., NAGYMAROSY, A., SZEDERKÉNYI, T., 2012. Geology of Hungary. Springer, London, Budapest, 244p. HAAS, J., BUDAI, T., CSONTOS, L., FODOR, L., KONRÁD, GY, 2010.PreCenozoic Geological Map of Hungary, 1:500 000. Geological Institute of Hungary.

HERTELENDI, E., VETŐ, I., 1991. The marine photosynthetic carbon isotopic fractionation remained constant during Early Oligocene. Palaeogeography, Palaeoclimatology, Palaeoecology 83, 333-339. http://www.sciencedirect.com/science/article/pii/003101829190059Z

KÓKAI, J., POGÁCSÁS, G., 1991. Tectono-stratigraphical evolution and hydrocarbon habitat of the Pannonian Basin. In: Spencer, A.M. (Ed.), Generation, Accumulation and Production of Europe’s Hydrocarbons. Special Publication of the European Association of Petroleum Geoscientists, vol. 1, pp. 307-317.

KŐRÖSSY, L., 2004. Hydrocarbon geology of the Palaeogene Basin, northern Hungary. General Geological Review Journal of the Hungarian Geological Society 28, 9-121 (in Hungarian with English abstract).

MILOTA, K., KOVÁCS, A., GALICZ, ZS, 1995. Petroleum potential of the north Hungarian Oligocene sediments. Petroleum Geoscience 1, 81-87.

SZALAY, Á, KONCZ, I., 1991. Genetic relations of hydrocarbons in the Hungarian part of the Pannonian Basin. In: Spencer, A.M. (Ed.), Generation, Accumulation and Production of Europe’s Hydrocarbons. Special Publication of the European Association of Petroleum Geoscientists, vol. 1, pp. 317-322.

TARI, G., BÁLDI, T., BÁLDI-BEKE, M., 1993. Paleogene retroarc flexural basin beneath the Neogene Pannonian Basin d A geodynamic model. Tectonophysics 226, 433-455. http://www.sciencedirect.com/science/article/pii/0040195193901313

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VETŐ, I., HETÉNYI, M., 1991. Fate of organic carbon and reduced sulphur in dysoxic- anoxic Oligocene facies of the central Paratethys (Carpathian Mountains and Hungary). In: Tyson, R.V., Pearson, T.H. (Eds.), Modern and Ancient Continental Shelf Anoxia. Geological Society Special Publication, vol. 58, pp. 449-460.

VETŐ, I., NAGYMAROSY A., BRUKNER-WEIN, A., HETÉNYI, M., SAJGÓ, CS., 1999. Salinity changes control, isotopic composition and preservation of the organic matter: the Oligocene Tard Clay, Hungary, revisited. In: 19th International Meeting on Organic Geochemistry, Abstract Vol., pp. 411- 412.

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T07c - Pannonia, Mura-Zala Basin - Haloze-Špilje Fm. Shale

General information Screening- Index Basin Country Shale(s) Age Index 1066&1068 Pannonia, (gas), T7c SLO Haloze-Špilje Fm. Shale Neogene Mura-Zala 1067&1069 (oil)

Geographical extent The Mura-Zala Basin represents a SW part of the Pannonian Basin System

Figure 1 Location of the Haloze-Špilje Fm. The coloured areas represent different basins.

Geological evolution and structural setting

Syndepositional setting Sedimentation in the Mura-Zala Basin started in the Karpatian times (Basic Geological Map of Yugoslavia, 1:100,000, and Basic Geological Map of Slovenia and Croatia, 1:100,000). Basal conglomerates, breccias, oyster banks and tuffs were initially deposited over the pre-Neogene (mainly Mesozoic and Paleozoic) metamorphic, carbonate and clastic rocks. Sedimentation was then continued by alternative deposition of marls/marlstones and sands/sandstones. This so called Haloze Formation is interpreted to be formed in terrestrially influenced as well as (later) in marine

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environments. The energy level in the Pannonian Basin decreased in the Badenian times, and the Pannonian Sea reached its largest areal dimensions. Coarse clastic deposition was gradually replaced by finer and finer sediments as sandstones and marls, and locally algal (reef) limestones, all these in marine environments. On the basis of lithology and paleonthological evidence, this sequence is called the Špilje Formation.

Structural setting The Mura-Zala Basin represents a SW part of the Pannonian Basin System which is a back-arc basin formed in the time from Tertiary-Ottnangian up to Quaternary (Royden & Horváth, 1988). Due to collision of the southern (African) and the northern (Euroasian) tectonic plates, the Eastern Alpine rock masses moved (“escaped”) along the strike-slip faults toward east and formed the Carpathian belt (Ratschbacher et al., 1991a,b). The mentioned movement is known as the “Alpine eastward tectonic escape”. Consequently, an area between the Alps, the Carpathian belt and the Dinarides sank.

The Mura-Zala Basin is tectonically composed of sub-basins or depressions (Radgona and Ljutomer sub-Basins), blocks/horsts or massifs (Southern Burgenland Horst, Murska Sobota Block) and antiforms (Ormož-Selnica-Lovászi Antiform).

Organic-rich shales

The Haloze and Špilje Formations The Haloze and Špilje Formations together were termed in the past as the Murska Sobota Formation. Haloze and Špilje Formations are covered by the Lendava, Mura and Ptuj-Grad Fms, which are together up to ca 4000 m thick in the geological profiles, or even more if erosion is taken into account. Correlating formations to the Haloze Fm. are the Tekeres Fm. in Hungary, and the Gamlitzer Schlier, Arnfelser Konglomerat, Leutschacher Sand, Sinnersdorf Fm. and Rust Fm. in Austria (Maros et al., 2012). Correlating formations to the Špilje Fm. are the Tekeres, Szilagy, Kozard and Enrőd Fms. in Hungary, and the “Mbc” unit and the Gleisdorf Fm. in Austria (Maros et al., 2012). The Haloze and Špilje Fms. together correspond to the Prkos, Prečec, Moslavačka gora and Vukovar Fms. in different tectonic units (Sava and Drava Depressions, and Slavonija Deep) in Croatia (Velić et al. 2002)

Depth and thickness The total thickness of the Haloze Formation is on average 370 m thick (based on data from 25 wells; Šram et al., 2015). The total thickness of the Špilje Formation is on average 485 m thick (based on data from 77 wells; Šram et al., 2015). In the different subbasins the thickness of the potential shale gas/oil intervals varies between 130 and 780m. The depth of the intervals varies per basin as well. The formations can be found at depth between 1500m and 4000m.

Shale gas/oil properties The average TOC of the formations is relatively low and was determined to be between 1 and 2%. The potential intervals have maturities between 0.7 and 2.1 % Vitrinite reflectance and are therefore in the oil and gas generating windows. The kerogen type of the formations is type III to II.

Chance of success component description Occurrence of shale

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Mapping status Good

Sedimentary variability Moderate to High

Structural complexity Moderate several subbasins and inverse antiforms

HC generation

Available data Good good database (>20)

Proven source rock Possible Gas and oil shows detected in wells in the area

Maturity variability Moderate basin wide trends related to present or past burial depth variations

Recoverability

Depth Average 1000-5000m

Mineral composition Unknown average mineral composition does not allow any assumptions on fraccability

References Jelen, B. & Rifelj, H. 2011: Površinska litostratigrafska in tektonska strukturna karta območja T-JAM projekta, severovzhodna Slovenija = Surface litostratigraphic and tectonic structural map of T-JAM project area, northeastern Slovenia 1: 100.000 (in Slovenian). Geological Survey of Slovenia. http://www.geo-zs.si/podrocje.aspx?id=489

Šram, D., Rman, N., Rižnar, I. & Lapanje, A. 2015: The three-dimensional regional geological model of the Mura-Zala Basin, northeastern Slovenia = Tridimenzionalni regionalni geološki model Mursko-zalskega bazena, severovzhodna Slovenija. Geologija, 58/2: 139-154, doi: 10.5474/geologija.2015.011.

Sachsenhofer, R. F., Jelen, B., Hasenhüttl C., Dunkl, I. & Rainer, T. 2001: Thermal history of Tertiary basins in Slovenia (Alpine-Dinaride-Pannonian junction). Tectonophysics, 334/2: 77-99. ISSN 0040-1951.

Jelen, B. 1985/86: Poizkus iskanja organskih parametrov terciarnih sedimentnih kamenin v vzhodni Sloveniji.

Hasenhüttl, C., Kraljić, M., Sachsenhofer, R.F., Jelen, B. & Rieger, R. 2001: Source rocks and hydrocarbon generation in Slovenia (Mura Depression, Pannonian Basin). Marine and Petroleum Geology, 18: 115-132, doi:10.1016/S0264-8172(00)00046-5.

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Maros, G. - with 31 co-authors from Hungary, Austria, Slovakia and Slovenia, 2012: Summary report of geological models - Transenergy Project. MFGI Budapest, GBA Vienna, ŠGÚDŠ Bratislava, GeoZS Ljubljana, 189 p. http://transenergy- eu.geologie.ac.at/Downloads/outputs/Summary%20report%20of%20geological%20m odels/Summary%20report%20of%20geological%20models.pdf

Rajver, D., Ravnik, D., Premru, U., Mioč, P, Kralj, P., 2002: Slovenia. In: Hurter, S. & Haenel, R. (Eds.), Atlas of Geothermal Resources in Europe), Plates 74-76. - Leibniz Institute for Applied Geosciences (GGA), Hannover.

Dövényi, P. & Horváth, F. 1988: A review of temperature, thermal conductivity, and heat flow data for the Pannonian Basin. In: Royden, L.H. & Horváth, F. (Eds.), The Pannonian Basin. A study in basin evolution. Am. Assoc. Pet. Geol. Mem. 45, 195-233.

Bavec, M. and 17 co-authors, 2005: Overview of geological data for deep repository for radioactive waste in argillaceous formations in Slovenia. Geological Survey of Slovenia, 131 p.

Djurasek, S. 1988: Rezultati suvremenih geofizičkih istraživanja u SR Sloveniji (1985- 1987) = Results of geophysical exploration in Slovenia (1985-1987). Nafta, 39, 311- 326.

Mioč, P. & Marković, S. 1998: Tolmač za geološko karto list Čakovec 1:100 000 (Guidebook to the Geological map - Sheet Čakovec, 1:100 000; in Slovene). Inštitut za geologijo, geotehniko in geofiziko Ljubljana in Institut za geološka istraživanja Zagreb,84p.

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T08 - Vienna Basin – Mikulov Marl

General information (see excel table from GEUS) Screening- Index Basin Country Shale(s) Age Index

U. Jurassic Mikulov Marl Fm. Vienna Basin A (Oxfordian – 1018 (Mergelsteinserie) Kimmeridgean) T8 U. Jurassic SE Bohemian CZ Mikulov Fm. (Oxfordian – 1063 Massif Kimmeridgean)

Geographical extent The Mikulov Marl is present below the Vienna Basin and Korneuburg Basin (also referred to as the Thaya Basin) and Zdanice nappe in the south-eastern Czech Replublic (Figures 1 and 2). It is preserved at depths > 1.5 km buried beneath the frontal Alpine-Carpathian thrust belt (Helveticum and Rhenodanubian Flysch). In the East it probably extends as far as the Pieniny Klippen Belt and Northern Calcareous Alpine – Inner Carpathian overthrust units.

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Figure 1 Location of the Mikulov Marl Fm. in the Czech Republic and Austria below and adjacent to the Vienna Basin. The coloured areas represent different basins.

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Figure 2 The extent of the Mikulov Marl Fm. with indication of depth and maturity. The hashed area marks the (local) selection criteria (depth between 4000-7000m and maturity > 0,7% Ro). Topography adapted from NatGeo_World_Map. Inset shows the regional setting.

Geological evolution and structural setting

Syndepositional setting The Lower Austria Mesozoic Basin (LAMB) and the adjacent basin in the SE Czech Republic was formed during Jurassic-Cretaceous opening of the Alpine Tethys (Wessely 1987, Adamek 2005, Picha et al. 2006). The syn-rift sequence consists of Middle Jurassic deltaic and prodeltaic formations which are trapped in half grabens along Middle Jurassic east dipping normal faults. Upper Jurassic Mikulov Marls were deposited due to thermal subsidence of the Bohemian Massif in a post-rift phase under restricted marine conditions of a passive margin basin.

Structural setting During the extensional tectonic phase, normal faulting shaped the SE margin of the Bohemian Massif. It faded out by the end of Middle Jurassic with a few exceptions, e.g. the Mailberg and the Kronberg faults. Cretaceous marine regression was associated with the first indications of plate convergence. Three major paleovalleys and submarine canyons (Nesvacilka, Vranovice, and Tulln, Adamek 2005; Picha et al. 2006) were carved in the Jurassic formations along active extensional faults of late Cretaceous to Paleocene age. In the Eocene, they were filled by deepwater siliciclastic sediments. The Alpine–Carpathian fold and thrust belts (FTB) formed during the late Eocene – early Miocene. The N- to NW-directed shortening led to overthrusting of the Alpine Tethyan successions onto the previously rifted European Platform (e.g. Granado et al., 2016 and reference therein). The Alpine Mesozoic to Paleogene flysch units were detached from the Tethyan basins, imbricated and emplaced over the Upper Jurassic Mikulov marl.

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On top of the Flysch Zone and the more internal parts of the Alpine–Carpathian FTB, the Vienna and Korneuburg Basins evolved in the early-to-late Miocene. Lower Miocene “piggy-back” and Midle Miocene “pull apart” mechanism associated with “strike-slip” faulting played an important role in making the Vienna basin up to 6000 m thick (e.g. Royden, 1985; Wessely, 1987, 1988; Fodor, 1995; Krejci et al. 1996; Strauss et al., 2001, 2006; Hinsch, Decker & Peresson, 2005; Arzmüller et al. 2006; Hölzel et al. 2010). The later phase of evolution was controlled mainly by thermal subsidence (Prochac et al. 2012). The huge amount of subsidence and accumulation of a thick basin fill led to deep burial and maturation of the Mikulov Formation (Ladwein 1988).

Organic-rich shales

Mikulov Marls The Upper Jurassic marls are lithologically rather uniform, exhibiting several detritical marker layers. The stratigraphic position is proven by ammonites, indicating a Kimmeridgian to Tithonian age. To the NW the marls are fringed by a time-equivalent carbonate platform of the Altenmarkt Formation that contains several internal facies, with from bottom to top bedded, partly cherty or dolomitic limestones , algal/sponge reefs and coral reefs, respectively. The transition to the Mikulov Marl is diachronous (overall transgressive) and marked by the slope facies of the “Falkenstein-Fm.” This formation consists of coarse calciclastics, mostly embedded in a marly matrix. Ammonites indicate an Oxfordian to Tithonian age. The Mikulov Marl Fm. is either overlain by biodetritic carbonatic sandstones of the Kurdejov Formation, the reefoidal, partly dolomitic “Ernstbrunn Limestone” of Tithonian to lowermost Creaceous age, or is unconformably overlain by the Upper Cretaceous Ameis Fomation (Glauconitic Ss.) Fm. The Czech part of the Mikulov Fm. is described more in detail by Adamek (2005).

Depth and thickness The Mikulov Marl Formation (MMF) reaches a thickness of more than 1000 m (2000 m in Cz). The largest thicknesses occur through duplications related to external alpidic thrusting within the Alpine- Carpathian foreland (Figure 3-5).

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Figure 3 Thickness (left) and depth (right) of the Mikulov Marls (m). Topography adapted from NatGeo_World_Map.

Figure 4 Top of the Jurassic sediments (km), SE Czech Republic

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Figure 5 Base of the Jurassic sediments (km), SE Czech Republic

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North-West Boundary

of the Vienna Basin Elevation below Sea Level [m] [m] Level below Sea Elevation

Figure 6. Top of the Mikulov Fm. (m) in the SE Czech Republic.

NW Boundary Full thickness of the of the Mikulov Fm. Vienna Basin

encountered

Marls [m] [m] Marls Mikulov

Thicknesstheof

Figure 7. Thickness of the Mikulov Marls (m) in the SE Czech Republic.

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Shale gas/oil properties The Mikulov Marl is several hundreds of meters thick, has a kerogen type II-III and TOC’s ranging between 1.6-10%, but mostly above 2.0%. In addition, it has a wide lateral extent and covers the appropriate maturity range (Ladwein, 1988; Ladwein et al., 1991; Francu et al. 1996). In fluorescent light microscopy planktonic algae form the dominant organic matter, the algae lamellae act as oil-wet migraticion avenues (Francu et al. 2013). Lowest reservoir temperature is 70°C. Assuming a geothermal gradient of 2,7° to 2,9° per 100 m, the oil window is at 4000-6000 m depth (Ladwein, 1988). In the Zistersdorf UT-2 a temperature of 230°C has been recorded at 8553 m. The shallower part of the Mikulov Fm. (1500-4000 m) is immature, a deeper part is within the oil and thermogenic gas windows, and at depth over 8000 m in the eastern part MM is overmature (Ladwein et. al., 1991). At a mean depth of 5500 m, the maturity is of 1.2%Ro. Porosities and permeabilities are low in case of normal pressure. In case of overpressure, which is common below the Vienna Basin, porosity may reach 8 or 9% (Milan and Sauer, 1996). The monotonous lithology of the Mikulov Fm. is shown in Fig. 6 on the Well log correlation charts.Chance of success component description

Chance of success component description

Occurrence of shale

Mapping status Good A vast amount of subsurface seismic- and well data exists

Sedimentary variability Low The Mikulov Marl has a wide lateral extent and is lithologically rather uniform.

Structural complexity Moderate The overburden units of the Mikulov Fm. include the Alpine-Carpathian nappes. Jurassic rocks are not significantly deformed. Site specific reverse faulting led to tectonic doubling. This phenomenon is with further investigation.

HC Generation

Data availability Good The Vienna Basin is widely studied. Biomarkers have been evaluated and MPI–based maturity parameters work better than microscopic vitrinite reflectance. At present, kinetic parameters are being investigated.

HC system Proven The Mikulov Marl is the proven source rock for oil and gas in the Vienna Basin (Ladwein, 1988, Francu et al. 1996, Picha and Peters 1998). The modelled oil window is at 4000-6000 m depth and covers a large area.

Maturity variability Moderate Maturation was controlled by burial due to lower Miocene ovrthrusting by the external Alpine-Carpathian units (Flysch Belt) and middle to upper Miocene burial by the Vienna Basin deposition. Maturation and HC generation is predictable using basin modelling.

Recoverability

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Depth Average to Deep Mature shales in the subsurface mostly at depths of 4-6 km

Fraccability Unknown More studies are wanted to provide deeper insight in fraccability. Mikulov Marl has very low content of expandable clays (smectite). Carbonate content makes the rock rather brittle.

References

Adamek, J., 2005. The Jurassic floor of the Bohemian Massif in Moravia – geology and paleogeography. Bull. Of Geosciences, 80, 4, 291-305.

Fodor, L. 1995. From transpression to transtesion: Oligocene-Miocene structural evolution of the Vienna Basin and the East-Alpine-Western Carpathian junction. Tectonophysics 242, 151–82.

Francu, J., Radke, M., Schaefer, R.G., Poelchau, H.S., Caslavsky, J., Bohacek, Z., 1996. Oil-oil and oil-source rock correlation in the northern Vienna basin and adjacent Flysch Zone. In: Oil and Gas in Alpidic Thrustbelts and Basins of Central and Eastern Europe. Wessely, G. and Liebl, W., eds, EAPG Spec. Publ. No. 5, Geological Society Publishing House, Bath, 343-354.

Francu, J., Horsfield, B. And Schenk, H.J., 2013. Jurassic source rock kinetics and the petroleum system of the SE Bohemian Massif. In : J.A. González-Pérez, F.J. González- Vila, Nicasio T. Jiménez-Morillo and G. Almendros (eds.): Book of Abstracts 26th International Meeting on Organic Geochemistry, Costa Adeje, Tenerife. 391-392.

Gradano, P., Thöny, W., Carrera, N., Gratzer, O., Strauss, P. and Munoz J.A. Basement-involved reactivation in foreland fold-and-thrust belts: the Alpine– Carpathian Junction (Austria). Geological Magazine, available on CJO2016. doi:10.1017/ S0016756816000066.

HINSCH,R.,DECKER,K.&PERESSON, H. 2005. 3-D seismic interpretation and structural modelling in theVienna Basin: implications for Miocene to recent kinematics. Austrian Journal of Earth Sciences 97,38–50.

HÖLZEL, M., DECKER,K.,ZÁMOLYI,A.,STRAUSS,P.&WAGREICH, M. 2010. Lower Miocene structural evolution of the central Vienna Basin (Austria). Marine and Petroleum Geology 27, 666–81.

Krejci O., Francu J., Poelchau H.S., Müller P., Stranik Z., 1996. Tectonic evolution and oil and gas generation model in the contact area of the North European Platform with the West Carpathians. In: Oil and Gas in Alpidic Thrustbelts and Basins of Central and Eastern Europe. G. Wessely and W. Liebl, eds., EAPG Spec Publ. No. 5, Geological Society Publishing House, Bath, pp. 177-186.

Ladwein, H. W., 1988. Organic geochemsitry of Vienna Basin: Model for hydrocarbon generation in overthrust belts. AAPG Bulletin, 72, 586-599.

Ladwein, W., Schmidt, F., Seifert, P. & Wessely, G., 1991. Geodynamics and generation of hydrocarbons in the region of the Vienna basin, Austria. In: Spencer, A.

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M. (ed.) Generation, accumulation, and production of Europe’s hydrocarbons. Oxford University Press, Oxford, EAPG Special Publication, 1, 289-305.

Milan, G., and R. Sauer, 1996, Ultra-deep drilling in the Vienna basin— A review of geological results, in G. Wessely and W. Liebl, eds., Oil and gas in Alpidic thrust belts and basins of Central and Eastern Europe: European Association of Petroleum Geoscientists and Engineers Special Publication 5, p. 109-117.

Pícha, J. F., Peters, E., 1998. Biomarker oil-to-source rock correlation in the Western Carpathians and their foreland, Czech Republic. Petroleum Geoscience 4, 289–302.

Picha, F.J., Stranik, Z., Krejci, O., 2006. Geology and hydrocarbon resources of the Outer West Carpathians and their foreland, Czech Republic. In J. Golonka and F.J. Picha, eds. The Carpathians and their foreland: Geology and hydrocarbon resources. AAPG Memoir 84, 49-175.

Prochac, R., Pereszlenyi, M. and Sopkova, B., 2012. Tectono-sedimentary features in 3D seismic data from the Moravian part of the Vienna Basin. First Break, 30, 49-56.

ROYDEN, L. H. 1985. The Vienna basin: a thin-skinned pull-apart basin. In Strike Slip Deformation, Basin Formation and Sedimentation (eds. K. Biddle & N. Kristie-Blick), pp. 319–38. Society of Economic Paleontologists and Mineralogists, Special Publication no. 37.

STRAUSS,P.,HARZHAUSER, M., HINSCH,R.&WAGREICH,M. 2006. Sequence stratigraphy in a classic pull-apart basin (Neogene,ViennaBasin). A 3D seismic based integrated approach. Geologica Carpathica 57, 185–97.

STRAUSS,P.,WAGREICH, M., DECKER,K.&SACHSENHOFER, R. F. 2001. Tectonics and sedimentation in the Fohnsdorf-Seckau Basin (Miocene, Austria): from a pull-apart basin to a half graben. Internationla Journal of Earth Sceinces 90, 549-559.

WESSELY, G. 1987. Mesozoic and Tertiary evolution of the Alpine-Carpathian foreland in eastern Austria. Tectonophysics 137, 45–9.

WESSELY, G. 1988. Structure and development of the Vienna Basinin Austria. InThe Pannonian Basin: a Study of Basin Evolution (eds L. H. Royden & F. Horvarth), pp. 333–46. America Association of Petroleum Geologists, Memoir no. 45.

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T09 - Lombardy Basin (Italy) – Triassic – E. Cretaeous shales

General information Screening- Index Basin Country Shale(s) Age Index

I Meride Fm Ladinian 1005

Lombardy Argilliti di Riva di Solto T9 I Norian 1006 Basin Fm

Marne di Bruntino E. I 1007 formation Cretaceous

Geographical extent A good assessment of the geographical extent of Middle-Late Triassic and Early Cretaceous organic rich deposits in the Lombardy Basin, in general, is hampered by the complex paleogeography. However, it can be said that the areal extents of the units in the Lombardy Basin are very limited (few tens of km2) and their thicknesses register sharp lateral variations that are very difficult to map with the poor subsurface data available.

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Figure 1 Location of the Meride Fm, the Argilliti di Riva di Solto Fm and the Marne di Bruntino formation in northern Italy. The coloured areas represent different basins.

Geological evolution and structural setting

Syndepositional setting The depositional history of the Lombardy Basin began between the middle Permian and the Late Triassic with continental clastic deposition at the start of Tethyan rifting (break up Pangea). Detailed correlation shows that in fact two (or three) distinct

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phases of rifting occurred during Triassic and three during Liassic to middle Jurassic times. These phases are separated by time intervals of relative tectonic quiescence.

In the Middle Triassic, a marine transgression, in combination with synsedimentary tectonics, controlled a complex paleogeographic setting dominated by N-S structural troughs. The Ladinian consist of carbonate platform deposits (e.g. the Esino formation) and intercalcated limestones (e.g. the Meride and Perledo-Varenna formations) and black shales (the Besano Fm) deposited in the intra-platform anoxic troughs. These organic-rich units can be correlated with the Grenzbitumenzone of Swiss.

The Late Triassic was characterized by sedimentation of shallow marine carbonates on the shelves and pelagic limestones and -marls in the deeper basins. In the whole of the Southern Alps, the latest Carnian and/or the earliest Norian are marked by renewed extensional tectonism that induced new subsidence and transgression. As a consequence the existing troughs widened and deepened and accommodated the thickest and most organic rich rocks during the Norian stage (Stefani & Burchell, 1990) (e.g. Argilliti di Riva di Solto). This sedimentation was accompanied by a tectonic phase interpreted as the beginning of the rifting that eventually (in the Jurassic) led to the opening of the Ligurian-Piedmont ocean (or Alp-Tethys). The later Lombardy Basin (and Southern Alps in general) belonged to the southern passive Tethys margin.

In the late Triassic, during Rhaetian, Tethyan (Ligurian) rifting periodically slowed down and the basin fill was topped by a carbonate ramp (Zu Limestone), followed by the development of a new carbonate platform (Conchodon formation) (Gaetani et al. , 1998). During the latest Trias-earliest Jurassic (Lias) a new extensional phase took place. Extension then shifted westward and in the Ligurian-Piedmont area the oceanic crust was formed no later than Late Jurassic times. From this age up to the Lower Cretaceous, the Southern Alps underwent a post-rift thermal subsidence (Bertotti et al., 1993, and references therein). The Jurassic and Cretaceous units in the Lombardy Basin are represented by a thick basin succession that was filling the subsiding basins (Jadoul and Galli, 2008). In the Southern Alps, Early Jurassic (Toarcian) black shales occur in the Lombardy Basin, on the Trento Plateau, in the Belluno Trough and in the Julian Basin (Farrimond et al., 1988). However, their distribution is not continuous across the region and in some areas of the Lombardy Basin lack black shales (Jenkyns, 1988).

Structural setting The three organic-rich units of the Lombardy Basin here considered are deposited during different stage in the Permian – Cretaceous evolution from rift basin to passive margin (rift to drift). The regional distribution of the organic matter maturity seems to be mainly controlled by differential burial during the Norian-Liassic extensional rift phase and by high heat flow (Fantoni and Scotti, 2003). During the Alpine orogeny, the Tethys Ocean closed and the former passive marginstarted to override the Eurasian plate on which the Lombardy Basin evolved as a back-arc basin. Due to this orogeny, nowadays these source-rock units appear in a tilted monocline with 30° SW dip under the Po river plain (Bertello et al., 2010) although the complex structural history might have affected the vertical position and maturation level of the units through time differently.

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Organic-rich shales

The Besano (Be), Meride (Me) and Perledo-Varenna (PV) formations (1005) The Besano (Be), Meride (Me) and Perledo-Varenna (PV) formations are units deposited in intraplatform anoxic troughs during the Ladinian. These units can be correlated with Grenzbitumenzone (Swiss). All three units share some common lithological characteristics (Bongiorni, 1987; Gaetani et al., 1992; Jadoul & Tintori, 2012):

. dark-grey limestone (mudstone and wackestone) and dolomite (with variable quantity of bitumen) in planar beds; they can either show lamination or no structure at all. This lithofacies makes up about 90% of the unit thickness; . black fissile marl and shale (oil shale), which may form 10 to 50 cm sets; . calcarenite and slump beds.

Depth and thickness The thickness of the units ranges from 100 to 400 meters, and the shale lithofacies from 10 to 40 meters (max thicknesses reported for the Meride formation). The units pass laterally and upward to the platforms carbonates of the Esino Fm. It is reported (Bertello et al., 2010) that these units have been found as deep as 4500 meters in the Gaggiano 1 well (Bongiorni, 1987) where they source important oil fields in the western part of the Po Plain (e.g. the Gaggiano, Trecate and Villafortuna fields). A maximum depth of >7000 m can be inferred from published regional cross sections.

Shale oil/gas properties The TOC average value reported for these units is 0.9% (Lindquist, 1999), however, detailed sampling revealed significant intraformational variability in the Besano Formation, with TOC values ranging from less than 1% to greater than 35% TOC (Katz et al.,2000). The formations are characterized by type II kerogen content (55% amorphous, 28% herbaceous, 17% woody) (Pieri and Mattavelli, 1986). The vitrinite reflectance range from 0.39% Ro, registered in the Besano formation (Katz et al., 2000) to 2.17% Ro for the outcropping part of the Perledo-Varenna formation (Gaetani et al., 1992). Gas generation values between 420 – 800 mgHC/g are derived from the plot reported by Katz et al. (2000).

Argilliti di Riva di Solto Fm (1006) The Norian Argilliti (shales) di Riva di Solto formation is subdivided in two lithozones: A lower lithozone of max 200 m (ARS1, Jadoul and Galli, 2008) consisting of black, thin laminated organic rich shales, marly shales, minor dark grey marls, muddy limestones and paraconglomerates. The blackish shales are grouped in metre-scale layers, and at the base of the lithozone, a 5 meters thick layer of black shales with TOC >5% is locally documented. Slump deposits occur in the whole lithozone.

An upper lithozone of max 800 m (ARS2,Jadoul and Galli, 2008) comprising cyclic alternations of thin bedded black micritic limestones and marls.

Deposition of laminated organic rich shales and marls (lower lithozone) occurred in sea floors (troughs) located below the photic zone under prevalent anaerobic- subanaerobic conditions as testified by the abundance of preserved AOM.

Depth and thickness In the public subsurface data the Argilliti di Riva di Solto Fm (SI 1006) has been recognized only in two wells (Franciacorta 001 and Gerola 001) at the boundary with

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the outcropping Southern Alps, at depth of ≈ 3,000 meters. Riva et al. (1986) only present a schematic distribution of the unit. A maximum depth of >7000 m can be inferred from published regional cross sections.

Shale oil/gas properties The outcropping rocks of the upper Triassic Argilliti di Riva di Solto Fm in the Iseo Lake area are highly overmature Ro = 4% (Stefani and Burchell, 1990) and are characterized by abundant diasterane content. Both marine and continental kerogen types II and III occur (13-21% amorphous, 34-59% herbaceous, 28-45% woody) with a pristane/phytane ratio near 1 (Stefani and Burchell, 1990, 1993). TOC ranges from 0.5 to 5% with an average value of 1.3%, with a sulfur content of 3.1% and HI of 251 mg HC/g rock (Lindquist, 1999).

Marne di Bruntino formation (1007) The Lower Cretaceous Marne di Bruntino formation consists of thin and medium bedded, black to purple red shales (average thickness 10 meters) and marlstones, locally fissile, following by thick alternations of arenaceous pelitic and marly calcareous turbidites (average thickness 70 meters), in homogeneous or graded beds, associated with multicolored shales and black shales. The depositional environment is bathial with periodic anoxic conditions. They are outcropping in the western part of the Southern Alps and encountered in the Gerola-001 well in the Po Plain.

Depth and thickness Net thickness of the black shales of the Marne di Bruntino formation (SI 1007) are estimated at 10-50 meters, whereas the entire formation ranges between 70-140 meters. The formation is outcropping in the western part of the Southern Alps and drilled in the Po Plain where it ranges in depth between ~300 meters (Gerola 001 well) to ~5000 meters (Malossa field). However, the formation is not continuously present and it is not possible to define a well constrained depth trend.

Shale gas/oil properties In the Marne di Bruntino formation TOC ranges from 0.03 and 15.5%, with an average value of 1.01%. The generation potential ranges from 0.87 to 107.6 mg HC/g rock for samples with at least 1.0% organic carbon (Katz et al., 2000) with kerogen types II and III.

Chance of success component description (1005, 1006, 1007) The lack of specific literature or assessments concerning unconventional resources in Italy are mainly related to some geological factors that reduce the economic interest of these resources: 1. limited and discontinuous extension of the organic-rich rocks; 2. great variability of the thermal maturity due to complex structural history; 3. rocks with high thickness have low TOC (<<2%); 4. rocks with high TOC have low thickness (<<20 meters). Moreover it is very difficult to map the areal extent and depth of these discontinuous organic-richunits because of the scattered distribution of subsurface data.

Occurrence of shale

Mapping status Poor In general it is very difficult to map the areal extent and depth of the discontinuous organic-rich units because of the scattered distribution of subsurface data. Thicknesses register sharp lateral variations that are very difficult to map with the poor subsurface data available.

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Sedimentary variability High The depositional heterogeneity is largely related to the basin physiography during deposition that was marked by areas of differential subsidence rates leading to formation of restricted basins inside the platform complexes. Within these restricted basin lateral changes are expected based to occur.

Structural complexity High Thicknesses and depths are affected by syn-tectonic deposition and later thrust tectonics.

HC generation

Available data Poor Since most oil field permits are still active, well logs are not publicly available, except the Gaggiano 1 well log that was published in a simplified form by Bongiorni (1987) providing information on the top of the Meride formation in the Gaggiano oil field. Because of the unavailability of E&P data, Scotti and Fantoni (2015) reconstructed the thermal history from organic matter maturity data obtained from samples collected from sedimentary units outcropping in the Southern Alps.

Proven source rock Proven Maturity profiles of some basinal successions (Scotti and Fantoni, 2015) suggest that the Upper Triassic source rocks could already have attained high maturity levels during the Mesozoic. This is even more likely for the deeper Middle Triassic source rocks. The organic matter maturity seems to be mainly controlled by differential burial during the Norian-Liassic extensional phase and by high heat flow during rifting. Where the traps are formed by post Early Cretaceous Alpine compressional structures, the timing of hydrocarbon generation and expulsion is important. Ladinian organic rich units important oil fields in the Po Plain (e.g. the Gaggiano, Trecate and Villafortuna fields). For this realm it is suggested that due to low Rhaetian-Liassic burial the source rocks preserve their entire original petroleum potential before the strong Neogene- Quaternary burial occurred. The high recent heating then allows a generation/expulsion of hydrocarbons after trap formation (Novelli et al., 1987).

Maturity variability High The Triassic units show high variability in the degreed of maturation, from highly overmature to immature. A general decrease in maturity can be inferred from the outcropping areas in the north (overmature) to the Po basin in the south (mature), suggesting that the Mesozoic architectural basin trends were inverted during Alpine compression.

Recoverability

Depth Average to deep A large range in depth exist: from outcrop to 3 km depth underneath the Po Valley, to as deep as 7 km the subsurface mostly at depths of 4-6 km.

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Mineral composition No data average mineral composition was not provided

References Bertotti G., Picotti V., Bernoulli D. and Castellarin A. [1993] From rifting to drifting: tectonic evolution of the Southalpine upper crust from the Triassic to the Early Cretaceous. Sedimentary Geology, 86, 1/2, 53 - 76.

Bongiorni, D. (1987). The hydrocarbon exploration in the Mesozoic structural highs of the Po Valley: the example of Gaggiano. Atti Tic. Sc. Terra, 31, 125-141.

Fantoni R. and Scotti P. [2003] Thermal record of the Mesozoic extensional tectonics in the Southern Alps. Atti Tic. Sci. Terra, 9, 96 – 101.

Gaetani, M., Gnaccolini, M., Poliani, G., Grignani, D., Gorza, M., and Martellini, L. (1992). An anoxic intraplatform basin in the Middle Triassic of Lombardy (southern Alps, Italy): anatomy of a Hydrocarbon source. Riv. It. Paleont. Strat., 97 (3-4), 329- 354.

Jadoul, F., and Tintori, A. (2012). The Middle-Late Triassic of Lombardy (I) and Canton Ticino (CH). In “Pan-European Correlation of the Triassic - 9th International Field Workshop”. September 1-5, 2012.

Katz, B.J., Dittmar, E.I., and Ehret, G.E. (2000). Geochemical review of carbonate source rocks in Italy. Journal of Petroleum Geology, vol.23(4), 399-424.

Lindquist, S.J. (1999). Petroleum Systems of the Po Basin Province of Northern Italy and Northern Adriatic Sea: Porto Garibaldi (Biogenic), Meride/Riva di solto (Thermal), and Marnoso Arenacea (Thermal). USGS Open-File Report 99-50-M.

Pieri, M., and Mattavelli, L. (1986). Geologic framework of Italian petroleum resources. AAPG Bull., 70, 2, 103-130.

Riva, A., Salvatori, T., Cavaliere, R., Ricchiuto, T., and Novelli, L. (1986). Origin of oils in Po Basin, Northern Italy. Org. Geochem., 10, 391-400.

Scotti, P. and Fantoni, R. (2008) Thermal Modelling of the Extensional Mesozoic Succession of the Southern Alps and Implications for Oil Exploration in the Po Plain Foredeep. 70th EAGE Conference and Exhibition, Rome. Extended abstract.

Stefani, M., and Burchell, M. (1990). Upper Triassic (Rhaetic) argillaceous sequences in northern Italy: depositional dynamics and source potential, in Huc, A.Y., ed., Deposition of Organic Facies, AAPG Studies in Geology, 30, American Association of Petroleum Geologists, p. 93-106.

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T10, T22, T23, T24, T33 - Northwest European Carboniferous Basin (Central Europe)

General information Index Basin Country Shale(s) Age Screening- Index T10a Northwest NL Geverik Member Namurian A 1064 European Carboniferous Basin T10b UK UK Bowland-Hodder Carboniferous 1077 Carboniferous Chokier Carboniferous 1048 T22 Campine B Westphalian A+B Carboniferous 1045 T23 Mons B Chokier Carboniferous 1046 T24 Liege B Chokier Carboniferous 1047 T33 Northern D Hangender Carboniferous 2013* Germany Alaunschiefer and Kohlenkalk-Facies *The description of the German potential shale oil and gas formations is based on the detailed report of Ladage et al. (2016). As Germany is not participating in this study, no additional ranking of the German formations is performed.

Geographical extent

Figure 1 Location of the Carboniferous formations in the Northwest European Carboniferous Basin. The coloured areas represent different basins.

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Organic-rich Upper Carboniferous shales were deposited in a number of foreland basins of the Variscan orogen and are found in a number of countries. In the Netherlands they are part of the Geverik Member of the Epen Formation, which is the time-equivalent of the Upper Bowland Shale Formation in the United Kingdom (Andrews, 2013), the Chockier and Souvré Formations in Belgium and the Upper Alum Shale Formation (Hangender Alaunschiefer) in Germany (Figure 2).

Figure 2 Lithostratigraphic column of the Carboniferous in the Northwest European Carboniferous Basin with the Bowland (Kombrink et al., 2010).

Figure 3 Dinantian paleogeography with the distribution area of the Carboniferous shales visible in the green and grey areas (Kombrink el al. 2010).

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Geological evolution and structural setting

Syndepositional setting During the early Carboniferous in most of the region carbonates were deposited in a typical sediment-starved setting while to the north a fluviodeltaic system developed (Figure 3). During the lower-Pennsylvanian the region was subjected to a tropical equatorial climate together with a rising sea level changing the setting to a siliciclastic environment resulting in the marine black-shale deposition of the Upper Carboniferous. The northward migrating Variscan deformation front caused a progradational setting combined with tectonic uplift. Deeper Namurian marine environments evolved into shallow swampy forests in which the coal deposits formed. Sequential flooding driven by internal basin dynamics, glacial and interglacial cycles and the migrating Variscan front caused the cyclic occurrence of peats and coals, sandstones and mudstones.

Structural setting Three main periods of subsidence, separated by the Asturian and Kimmerian uplift, affected the Silesian strata. After the Variscan orogeny and the cessation of the compressional movements the area experienced regional uplift and erosion accompanied by strong magmatism, especially in eastern Germany. Afterwards rapid thermal subsidence resulted in the creation of an inland basin and the deposition of a thick succession of Permo-Triassic deposits. During the Jurassic the Kimmerian tectonic phase, related to the crustal separation in the Central Atlantic caused erosion of potentially several hundreds of metres of Triassic and Jurassic strata (Van Keer et al., 1998; Helsen & Langenaeker, 1999). After the Kimmerian uplift deposition of Upper Cretaceous and Cenozoic sediments under moderate subsidence occurred. Nonetheless, this burial history is not uniform throughout the entire basin. There are significant evolutional differences due to predominant block faulting during the Late Carboniferous (Bouckaert & Dusar, 1987, Doornenbal and Stevenson, 2010).

Organic-rich shales

Geverik Member of the Epen Formation, The Netherlands The Epen Formation was originally described by Van Adrichem Boogaert and Kouwe (1993-1997) as a series of dark-grey to black mudstones with a number of sandstone intercalations. It was deposited during the Namurian (Serpukhovian to Lower Bashikirian, 326 to 316 Ma.) and has been encountered in 12 wells in onshore the Netherlands. The stratigraphic sequence includes the basal organic-rich Geverik Member, which has been encountered at five well locations.

The Geverik Member is a partially silicified, bituminous calcareous black shale. The depositional setting is interpreted as a series of recurring cycles of delta progradation into a predominantly lacustrine basin (Van Adrichem Boogaert & Kouwe, 1993-1997).

Depth and Thickness The Epen Formation is over 1000 m thick at its maximum and consists of a number of coarsening-upward sequences of 250-300 meters thick, organized into several smaller order, 30-50 m thick, coarsening-upward sequences. The Geverik Member at the base of the Epen Formation is expected to be 50–70 m thick and present over a large area.

The Epen Formation is expected to be found in the subsurface of almost all of the Netherlands, but has only been drilled up to depths of 4-5 km (wells LTG-01 and UHM- 02, e.g., Zijp & Ter Heege, 2014).

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Shale oil/gas properties QEM-SCAN analyses on the Geverik Member show that most of the samples contain a very high silica content and very low clay content (Zijp et al. 2013). Gerling et al (1999) and De Jager et al (1996) suggest that the Geverik Member may have caused hydrocarbon charge, although no oil or gas deposits have been found that can be exclusively linked to the Epen Formation.

The mud logs from wells RSB-01, EMO-01 and LTG-01 give clear gas kicks at the level of the Westphalian coal seams, indicating gas preservation potential of the coals at substantial depths (>1700m). However, gas kicks are also present in the coal-barren upper parts of the Epen Formation in these wells. Even the basal parts of the Epen Formation in the LTG-01 and UHM-02 wells, which are expected to be highly mature, appear to contain some gas though at very low levels. Though these observations do not provide any conclusive evidence on the potential of the Epen Formation and cannot be easily converted into gas contents of the rock, they do provide ground for further investigation into the potential for shale gas (Van Bergen et al. 2013).

Vitrinite reflectance measurements show maturities of 2% to up to 4% depending on the present-day burial depth and basin setting. A calibrated maturity model is available for most of the Netherlands (Figure 4) showing the range of maturity.

TOC measurements on the Epen Formation show values of up to 5% with an average value of 1.1%. Type of organic matter is generally described as Type II even though the exact determination is difficult because of the high maturity of the organic matter. The basal Geverik Member shows higher TOC values.

Figure 4 Maturity map of the Geverik Member of the Carboniferous Epen Formation in the Netherlands, based on basin modeling (Zijp et al. 2015).

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Chance of success component description

Ocurrence of shale layer

Mapping status Moderate The Carboniferous shales does not have many well penetrations (in the Netherlands) and is badly visible on seismic.

Sedimentary variability High to Moderate It is a poorly mapped shale and does not have much core material, for the Dutch part. For logs it is apparent that there are three types of succession of Geverik Member and the underlying strata (carbonate platform present or not, and gradual deepening of the basin).

Structural complexity Moderate The Carboniferous Epen Formation is not expected to have much structural complexity, with gradual deeping from the Limburg/Belgium area to more than nine kilometres depth in the centre of the Netherlands. The formation (in the Netherlands) is not clearly visible on seismic, making it difficult to make a reliable map out of it.

HC generation

Data availability Moderate

Proven source rock Possible The Lower Carboniferous Epen Formation is a suggested source rock, although no oil or gas deposits have been found that are exclusively linked to this formation.

Maturity variability Moderate to High Maturity variability is unknown as too little material is at hand. There is one well with 1200m of core where measurements have been performed on, but not on much other material.

Recoverability

Depth Average to Deep

Mineral composition Favourable brittle mineral composition (>80% carbonates and/or quartz), fracturing tests, log interpretation

Bowland-Hodder Formation UK The description of the Bowland-Hodder unit was taken from the detailed assessment study of the BGS (Andrews, 2013).

The Bowland-Hodder unit is a seismically-defined unit comprising a deep organic-rich shale dominated succession, including the Hodder Mudstone and the Bowland Shale formations and intervening minor shale beds. The lower part of the Bowland-Hodder

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unit comprises a thick, syn-rift, shale-dominated facies which passes laterally to age- equivalent limestones that were deposited over the adjacent highs and platforms. The presence of slumps, debris flows and gravity slides (Gawthorpe & Clemmey 1985, Riley 1990) are evidence for relatively steep slopes, which may have been the result of instability induced by tectonic activity. A combination of syn-depositional tectonics, fluctuating sea levels, climate change, and evolution of the carbonate ramps/platforms surrounding the basin resulted in a variety of sediments being fed into the basin at different times. Localised breccias are present close to the basin-bounding faults (Smith et al. 1985, Arthurton et al. 1988).

The upper part of the Bowland-Hodder unit comprises basinal shales that were deposited both in the basins and across most of the platforms, following the drowning of the highs. These condensed zones are laterally continuous, rather than enclosed within basins, but are considerably thicker and richer in organic material within the basins which had a stratified water column. Within the Bowland Basin, individual beds can be easily correlated between (currently unreleased) wells, providing further evidence of relative stability in the upper unit.

Depth and thickness The top of the Bowland-Hodder unit lies at depths of up to 4750 m across the assessment area, with the greatest depth of burial occurring in the Bowland Basin of Lancashire, beneath the Permo-Triassic Cheshire Basin and in eastern Humberside.

The thickness of the Bowland-Hodder unit mirrors the regional Early Carboniferous structural configuration, with greatly expanded sections in the syn-rift basins.

From outcrop data, the Bowland Basin is estimated to contain up to 268 m of Bowland Shale (Brandon et al. 1998) and 900 m of Hodder Mudstone (Riley 1990). In the subsurface, seismic interpretation suggests the complete Bowland-Hodder unit reaches a thickness of up to 1900 m. The Bowland-Hodder unit is equally thick, or thicker, within the narrow, fault-bounded Gainsborough, Edale and Widmerpool basins with up to 3000 m, 3500 m and 2900 m respectively. The Cleveland Basin maintains a more uniform thickness, with the distribution of net shale controlled by facies changes to the north and south. Kirky Misperton 1 drilled a complete Bowland-Hodder unit thickness of 1401 m.

The organic-rich upper part of the Bowland-Hodder unit is typically up to 150 m thick, but locally reaches 890 m. The syn-rift lower part of the Bowland-Hodder unit is considerably thicker, reaching 3000 m in the depocentres.

Shale gas/oil properties A review of all available total organic carbon data show that most samples are from the upper part of the Bowland-Hodder unit. Values fall in the range >0.2 to 8%, with most shale samples in the range 1-3% TOC. Smith et al. (2010) give a similar range up to 10%.

Ewbank et al. (1993) reported Type II kerogen in the Widmerpool Gulf, Edale Basin, Goyt Trough and mudstones interbedded with carbonates on the Derbyshire High; Type III was also present.

From an analysis of all available maturity data of the Bowland-Hodder unit in the study area, it can be deduced that an Ro of 1.1% (equating to the onset of significant gas production) can be reached at a present-day depth of anything between outcrop and 2900 m.

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Chance of success component description

Occurrence of shale

Mapping status Good Depth and thickness maps available on unit level based on seismic interpretation and well data.

Sedimentary variability Moderate Depositional environment depends on structural setting, different facies in sub-basins and intermediate platforms as well as towards the basin margins. Main target formation (Upper Bowland-Hodder) relatively homogeneously distributed troughout the basin.

Structural complexity Moderate Distributed over several rift basins and local erosion

HC generation

Available data Good good database (>20)

Proven source rock Proven Bowland-Hodder formations have sourced conventional fields (Smith/DECC, 2011)

Maturity variability Moderate basin wide trends related to present or past burial depth variations

Recoverability

Depth Shallow to Average

Mineral composition No data average mineral composition is not available

Chokier, Belgium The Silesian is characterized by siliciclastic sedimentation in equatorial circumstances, linked to the influx of eroded material from the northward migrating Variscan front, as well as mainly continental organic deposits (peats).

The first layers to superimpose the underlying Visean dolomites, however, are black shales. These Namurian shales are typically described as rich in marine fauna, evidencing a deep marine setting. The basal layers of these Namurian shales are the Chokier and Souvré Formations. At the same time the Chokier/Souvré formations in the Liège basin and Mons basin were deposited as well as the equivalent Epen shales in the Netherlands and the Bowland shales in the UK, although paleo environments may differ and include e.g. lagoon settings.

The Souvré Formation consist according to Bouckaert (1967) and Langenaeker & Dusar (1992) of basinal mudstones whereas the Chokier Formation is a delta sequence. Both deposits consist of 2 peculiar rock types: finely bedded phtanites and organic-rich, pyrite-rich fossiliferous shales (ampelites). The Chokier formation is rich

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in fossils and carbonaceous, ferruginous carbonate nodules with uncompressed goniatites and other fossils (Van Scherpenzaal, 1875; Purvez, 1881; Fourmarier, 1910; Dusar, 2006).

Depth and thickness Several authors (e.g. Vandenberghe et al., 2001; Loveless et al., 2013; Kochereshko, 2015, Doornenbal and Stevenson, 2010; Kombrink, 2008) argue that both Namurian and Chokier Formation thickens towards the north and northeast of the Campine Basin, which is supported by well data. The Souvré Formation reaches up to 15m in thickness in the Turnhout well and in the eastern Campine Basin whereas the Chokier Formation reaches up to 24 m in the Turnhout well and increases towards the East. In the Geverik well (NL), in the southeast of the Campine Basin, the Chokier Formation measures up to 95 m.

Less information is available for the Mons Basin. A rough estimated thickness of 55 m is assumed and a minimal expected depth of the Chokier Formation of 1500 m. The restricted Chockier area in the Liége Basin covers 16 km2 with a depth between 1500 and 1800 m and a thickness between 90 and 110 m.

Shale gas/oil properties Geophysical log data (e.g. Merksplas well), i.e. gamma logs, and sample analysis (e.g. Turnhout well) prove the presence of a high concentrations of radioactive U and Th isotopes (Kochereshko, 2015). These radioactive shales are therefore often referred to as ‘hot shales’ which are used as a geophysical stratigraphic marker for the Visean-Namurian border. According to unpublished measurement results the TOC of the formations lies between 0.8 and 18%.

Chance of success component description

Occurrence of shale

Mapping status Moderate depth map, thickness map based on interpolation/average values (few datapoints)

Sedimentary variability Moderate to High

Structural complexity High The Mons and Liége Basins are located in the Variscan deformation zone. Moderate The Campine Basin lies north of the Variscan Front, and was only marginally influenced by Variscan compressive tectonics. Instead, the evolution of the Campine basin is dominated by extensive tensile normal faulting (Langenaeker, 2000).

HC generation

Available data Moderate few data points (< 20)

Proven source rock Unknown no information

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Maturity variability Moderate basin wide trends related to present or past burial depth variations

Recoverability

Depth Average 1000-5000m

Mineral composition Unknown average mineral composition does not allow any assumptions on fraccability No data Mons and Liége Basin

Westphalian A & B coalbed roof shales, Belgium

With the onset of the Westphalian, the depositional environment turned more and more continental, allowing for organic material to accumulate in swampy area which would later form the coal seams. The Lower Westphalian coal-bearing sequence consists of coal, mudstone, siltstone, sandstone and rootlet beds (Calver, 1969).

In the recent work Vandewijngaerde et al. (2013, 2014, 2015) presents a literature review that shows that both units represent a slightly different palaeogeographic setting. The Westphalian A is characteristic for the lower delta plain with fast, strongly pronounced flooding with maximal flooding surfaces right on top of the coal seam. The Westphalian B is transitional towards the upper delta plain, resulting in a more gradual flooding with maximal flooding surfaces at some distance above the coal seam. This difference reflects the increasing influence of the Variscan tectonics. The uplifted hinterland became more proximal during Westphalian B resulting in a stronger slope, better drainage and lower preservation potential of the organic matter, but also a transition from oligotrophic to ombotrophic peats.

Depth and thickness Depths go from 1502 m BMSL in the west to 3880 m BMSL in the east and northeast. The Westphalian A and B reaches up to 668 m of thickness in the Turnhout well and increases towards the east. Accurate net thicknesses are not yet available. Estimates place the net shale thickness between 6.5 and 39 m.

Shale gas/oil properties The organic-rich mudstones surrounding the coal layers are currently studied in the frame of the increased interest in gas shales (Vandewijngaerden et al., 2013, 2014, 2015). Based on first results, the average content of Total Organic Carbon (TOC) of the Westphalian A and B coalbed roof shales is around 5.5%, the maturity higher than 2 %Vr and the kerogen type II and III.

Chance of success component description

Occurrence of shale

Mapping status Moderate The isopach of the Westphalian A & B deposits was added as an interpolation grid out of well data from 7 wells.

Sedimentary variability Low very homogeneous character throughout the basin

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Structural complexity Moderate layer faulted, locally eroded, subsidence, uplift and salt tectonics

HC generation

Available data Moderate few data points (< 20)

Proven source rock Unknown no information

Maturity variability Moderate basin wide trends related to present or past burial depth variations

Recoverability

Depth Average 1000-5000m

Mineral composition Poor very clay rich (>50% clay content)

Hangender Alaunschiefer, Germany

The Hangender Alaunschiefer are organic-rich intercalations in the Kulm facies. The Kulm facies consists of fine to coarse grained siliciclastics with intercalated carbonate or volcanic layers and is present to the north of the Rheinish Massif and underneath the Rhine- and Münsterland. Organic-rich intervals of the same age were also identified in northeastern Germany and can be considered a lateral equivalent. This formation is also the lateral equivalent to the Chokier Formation in Belgium and the Geverik Member in the Netherlands.

Depth and thickness The thickness of the organic-rich intervals of the Hangender Alaunschiefer varies from a few meters to tens of meters (4-110m) and is slightly reduced towards the north. The formation is situated at the surface on the Rheinish Massif and dips towards the north. In the area of the Lippstädter Gewölbe it is situated at depth between 1500, and 3500m while it was encountered at depth between 4000 and 5500m in wells in the Rhine- and Münsterland. At the northernmost limit of the Münsterland it is situated at depth of more than 5000m.

Shale gas/oil properties Total organic carbon contents on avarage are around 2.5% with a maximum of 7.3%. Kerogen type is in general type II marine organic matter. The maturity varies between 2.5 to more than 4%.

References

Andrews, I.J. 2013. The Carboniferous Bowland Shale gas study: geology and resource estimation. British Geological Survey for Department of Energy and Climate Change, London, UK.

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Arthurton, R.S., Johnston, E.W. & Mundy, D.J.C. 1988. Geology of the country around Settle. Memoir of the British Geological Survey, Sheet 60 (England and Wales).

Balen, R.T. van, Van Bergen, F., De Leeuw, C., Pagnier, H., Simmelink, H., Van Wees, J.D., and Verweij, J.M., 2000. Modelling the hydrocarbon generation and migration in the West Netherlands Basin, the Netherlands. Geologie en Mijnbouw / Netherlands Journal of Geosciences 79: 29-44.

Bergen, F. van, M.H.A.A. Zijp, S. Nelskamp, H. Kombrink, [2013], ‘Shale gas evaluation of the Early Jurassic Posidonia Shale Formation and the Carboniferous Epen Formation in the Netherlands’, in J. Chatellier and D. Jarvie, eds., Critical assessment of shale resource play: AAPG Memoir 103, p1-24, 2013

Bouckaert J., 1967. Namurian transgression in Belgium. Rocznic Polskiega Towarzystwa Geologicznego (Annales of Polisch geological Society), 37-1: 145- 150.Demler, A., 1997. Structure tectonique du bassin houiller du Hainaut. Annales de la Société Géologique du Nord, 5 (2e série) : p 7-15.

Bouckaert J. & Dusar M. 1987. Arguments géophysicques pour une tectonique cassante en Campine (Belgique), active au Paléozoïque supérieur et réactivée depuis le Jurassique supérieur. Ann. Soc. Géol. Nord, CVI : p 201-208.

Bouw, S. and Lutgert, J. [2012] Shale Plays in The Netherlands. SPE/EAGE European Unconventional Resources Conference and Exhibition, SPE 152644

Brandon, A., Aitkenhead, N., Crofts, R.G., Ellison, R.A., Evans, D.J. & Riley, N.J. 1998. Geology of the country around Lancaster. Memoir of the British Geological Survey, Sheet 59 (England & Wales).

Calver M.A., 1969. Westphalian of Britain. Cong. International Stratigraphie et Géology Carbonifére. 6the Steffield. England. 1967. Compte Rendu, v.1, p 233-254

De Jager, J., Doyle, M.A., Grantham, P.J. & Mabillard, J.E., 1996. Hydrocarbon habitat of the West Netherlands Basin. In: Rondeel, H.E., Batjes, D.A.J. and Nieuwenhuijs, W.H. (Eds): Geology of Gas and Oil under the Netherlands. Kluwer Academic Publishers (Dordrecht): 191-210.

Doornenbal J.C. and A. G. Stevenson, 2010, Petroleum geological atlas of the Southern Permian Basin area: Houten, EAGE Publications b.v. (Houten)

Dusar M. 2006. Chokierian. Geologica Belgica 9/1-2: p 177-187.

EIA/ARI World Shale Gas and Shale Oil Resource Assessment, Technically Recoverable Shale Oil and Shale Gas Resources: An Assess-ment of 137 Shale Formations in 41 Countries Outside the United States

Ewbank, G., Manning, D.A.C. & Abbott, G.D. 1993. An organic geochemical study of bitumens and their potential source rocks from the South Pennine Orefield, central England. Organic Geochemistry 20: 579–598.

Fourmarier P., 1910. Texte explicatif du levé géologique de la planchette de Seraing (N° 134). Service géologique de Belgique: p 1-29.

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Gawthorpe, R.L. & Clemmey, H. 1985. Geometry of submarine slides in the Bowland Basin (Dinantian) and their relation to debris flows. Journal of the Geological Society of London 142: 555-565.

Gerling, P., Geluk, M.C., Kockel, F., Lokhorst, A., Lott, G.K. & Nicholson, R.A., 1999. NW European Gas Atlas – new implications for the Carboniferous gas plays in the western part of the Southern Permian Basin. In: Fleet, A.J. and Boldy, S.A.R. (Eds): Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. The Geological Society (London): 799-808.

Helsen S. & Langenaeker V. 1999. Burial history of coalification modelling of Westphalian strata in the eastern Campine Basin (northern Belgium). Belgian Geological Survey, Ministry of Economic Affairs, Professional Paper, 23 pp.

Hulten, F.F.N. van [2012] Devono-carboniferous carbonate platform systems of The Netherlands, Geologica Belgica 15(4), 284- 296.

Jager, J. de and M. C. Geluk, 2007. Petroleum Geology. In: Wong, T. E., Batjes, D. A. J. and De Jager, J. (Eds) Geology of the Netherlands. Royal Dutch Academy of Arts and Sciences, Amsterdam, 237–260.

Kochereshko P. 2015. Correlating geophysical well-log data and cored intervals for amending incomplete data from the Chokier Formation, Campine Basin. MSc Geology thesis at University of Ghent. Promotor: Prof. Dr. Van Rooi D; Copromotor: Dr. Piessens K.

Kombrink H. 2008. The Carboniferous of the Netherlands and surrounding areas. A basin analysis: Ph.D. thesis, University of Utrecht, Utrecht, no. 294, 184 pp.

Kombrink, H., Besly, B.M., Collinson, J.D., Den Hartog Jager, D.G., Drozdzewski, G., Dusar, M., Hoth, P., Pagnier, H.J.M., Stemmerik, L., Waksmundzka, M.I. & Wrede, V., 2010, Carboniferous, in Doornenbal J.C. and Stevenson A.G., eds., Petroleum geological atlas of the Southern Permian Basin area: Houten, EAGE Publications b.v. (Houten), p. 81–99.

Ladage et al. (2016) Ladage, S. et al. (2016) Schieferöl und Schiefergas in Deutschland – Potentiale und Umweltaspekte. Bundesanstalt für Geowissenschaften und Rohstoffe (BGR), Hannover. (http://www.bgr.bund.de/DE/Themen/Energie/Downloads/Abschlussbericht_13MB_Sc hieferoelgaspotenzial_Deutschland_2016.html)

Langenaeker V. & Dusar M. 1992. Subsurface facies analysis of the Namurian and earliest Westphalian in the western part of the Campine Basine (N-Belgium). Geologie en Mijnbouwn 71: p 161-172

Lott, G.K., Wong, T.E., Dusar, M., Andsbjerg, J., Mönnig, E., Feldman- Olszewska, A. & Verreussel, R.M.C.H. [2010] Jurassic. In: Doornenbal, J.C. and Stevenson, A.G. (Eds) Petroleum Geological Atlas of the Southern Permian Basin Area. EAGE Publications (Houten), 175–193.

Loveless S., Lagrou D., Laenen B., Bos S. 2013. Potential Role of Shale Gas and the Energy Mix of Flanders. Conference, Geologica Belgica ‘Gas shales in Belgium?’, Namur, 11/10/2013.

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Purves J.C. 1881. Sur la délimitation et la constitution de l’étage houiller inférieur de la Belgique. Bulletin de l’Académie royale de Belgique, Classe des Sciences, 3° série, 2: p 514-568.

Riley, N.J. 1990. Stratigraphy of the Worston Shale Group (Dinantian), Craven Basin, north-west England. Proceedings of the Yorkshire Geological Society 48(2): 163-187.

Smith, K., Smith, N.J.P. & Holliday, D.W. 1985. The deep structure of Derbyshire. Geological Journal 20: 215-225.

Smith, N., Turner, P. & Williams, G. 2010. UK data and analysis for shale gas prospectivity. In: Vining, B.A. & Pickering, S.C. (eds) Petroleum Geology: From Mature Basins to New Frontiers – Proceedings of the 7th Petroleum Geology Conference, 1087–1098.

Van Adrichem Boogaert, H.A. & Kouwe, W.F.P., 1993. Stratigraphic nomenclature of the Netherlands, revision and update by RGD and NOGEPA. Mededelingen Rijks Geologische Dienst 50: 1-40.

Van Keer I., Muchez P.H. & Viaene W., 1998. Clay mineralogical variations and evolutions in sandstone sequences near a coal seam and shales in the Westphalian of the Campine Basin (NE Belgium). Clay Mineral 33., p 159-169

Van Scherpenzeel T. J. 1875. Compte rendu de l’excursion du 21 septembre 1875. Annales de la Société géologique de Belgique, 2: CXLVII-CLX.

Vandenberghe N., Dusar M., Boonen P., Lie S.F., Voets R. & Bouckaert J. 2001. The Merksplas-Beerse geothermal well (17W265) and the Dinantian reservoir. Geologica Belgica, 3/3-4: p 349-367.

Vandewijngaerde W., Nzekwe O., Piessens K. & Dusar M. 2013. The potential of organic rich roof shales in coal sequences: re-evaluation of Westphalian samples in well KB174, Campine Basin, Belgium. Documenta Geonica, 1, p 171 – 176.

Vandewijngaerde W., Piessens K., Krooss B., Bertier P., Swennen R. 2014. Influence of palaeoenvironment and palaeogeography on source rock potential and theoretical gas storage capacity of roof shales (drilling KB174, Hechtel-Hoef, Campine Basin, Belgium. Conference paper, MECC 2014.

Vandewijngaerde W., Bertier P., Piessens K., Krooss B., Weniger F. & Swennen R. 2015. Pore and Sorptio characteristics of Westphalian Shale deposits in the Campine Basin

Zijp, M.H.A.A., Nelskamp, S., Schavemaker, Y., ten Veen, J.H., ter Heege, J.H. (2013) Multidisciplinary Approach for Detailed Characterization of Shale Gas Reservoirs, a Netherlands Showcase, OTC-24383-MS

Zijp, M.H.A.A., S. Nelskamp, R. Verreussel, J. ter Heege, ‘The Geverik Member of the Carboniferous Epen Formation, Shale Gas Potential in Western Europe’, IPTC-18410- MS, International Petroleum Technology Conference, Doha, Qatar, December 2015

Zijp, M.H.A.A., ter Heege, J. [2014] Shale gas in the Netherlands: current state of play. International Shale Gas & Oil Journal, Volume 2, Issue 1, February 2014

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T11 - Emma, Umbria-Marche Basins (Italy) – Triassic – E. Cretaceous shales

General information Screening- Index Basin Country Shale(s) Age Index Marne del Monte E. Jurassic T11a Umbria-Marche I 1009 Serrone Formation (Toarcian) E. Cretaceou Marne a Fucoidi T11a Umbria-Marche I (Aptian- 1010 Formation Albian) L. Triassic – T11b Emma I Emma Formation 1008 E. Jurassic

Geographical extent The extent of the Triassic – Early Cretaceous organic rich shales in the Emma Basin and Umbra-Marche basins is depicted in Figure 1.

Figure 1 Location of the Marne del Monte Serrone Formation, the Marne a Fucoidi Formation and the Emma Formation. The coloured areas represent different basins.

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Geological evolution and structural setting

Syndepositional setting The Central and Southern Apennines show a similar Mesozoic history dominated by the formation and evolution of a sedimentary wedge on the southern Neotethyan passive margin. Stratigraphic and structural data of the various tectonic units that form the Apennines confirm a complex Mesozoic paleogeographic setting, characterized by a large Late Triassic shallow-water carbonate platform evolving in a carbonate platform-basin systems as a consequence of a rifting stage that affected the whole Neotethyan region during the Early Jurassic. Many paleogeographic restorations have provided models which differ in the relative position and number of carbonate platforms and basins. Geophysical data and field analyses support the hypothesis of two carbonate platforms (Apenninic platform and Apulian platform) separated by a deep basin (Lagonegro-Molise basin). Moreover, the evolution of the northern sector of the Apenninic Platform is characterized by the Tuscany-Umbria-Marche Basin connected to the North Tethys rifting systems. The Late Triassic Apenninic platform was dominated by deposition of evaporites (Anidridi di Burano, Carnian-Rhaetian) and cyclic dolomites (Dolomia Principale, Norian-Raethian).

The extensional tectonics that affected the platform areas during the Late Triassic to Early Jurassic produced various depositional settings associated with areas of differential subsidence rates. In several restricted basins inside the platform complex, Upper Triassic euxinic sediments are encountered, such as in the Emma Basin in the Adriatic offshore, the Pelagruza Basin in the Dinaric offshore, and several onshore basins (e.g. Vradda in Gran Sasso and Filettino in the Simbruini; Finetti et al., 2005). Some of these restricted basins persisted during the Mesozoic, becoming parts of larger basins, which is the case for the Emma Basin, while others were filled as carbonate platform conditions were restored (e.g. Filettino Basin).

The Umbria-Marche basin, one of the persistent basins, developed along the northern sector of the Lazio-Abruzzo carbonatic shelf (Finetti et al., 2005) during the Jurassic - Cretaceous period and was persistent until early Cenozoic times. The stratigraphic succession of this domain is prevalently a basin sequence (Finetti et al., 2005), characterized by limestones, cherty and marly limestones, marls and hemipelagic clay, with local evidence of carbonate re-sedimentation. In general, the Umbria-Marche pelagic Mesozoic sequence shows a low naphtogenic potential excepted for some levels where euxinic black shale and rich organic matter levels occur, these include the Marne del Monte Serrone Formation, the Marne a Fucoidi Formation and the Livello Bonarelli. These organic enriched formations are related to main Oceanic Anoxic Events (OAE’s) and are characterized by relatively high total organic carbon (TOC) values and are clearly synchronous across Tethys and in global context (Jenkyns, 2010; Soua, 2014).

Structural setting At present the Triasic-Cretaceous platform-basin succession is taken up in the Central- Northern Apenninic fold and thrust belt (Bigi et al., 2011) formed during the eastward convergence of the Triassic – Miocene carbonate succession of the Adria continental margin (Lazio-Abruzzi and Apulia-Adriatic platforms) over younger Neogene- Quaternary Apulian foreland basins. Most oil reservoirs in the Adriatic and Apulian area reside in overridden platform slivers taken up in the orogeny (Bigi et al., 2011). Consequently, source rocks occur at a wide range of depth levels and may be duplicated by tectonic stacking.

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Organic-rich shales

Emma Formation (1008) The Emma Formation includes Upper Triassic and Lower Jurassic bituminous limestones (Dolomie Bituminose) and evaporitic- and euxinic black shales. These together with euxinic limestones inside the Burano formation are considered the source rocks for many conventional oil reservoirs in the Adriatic and Apulian area (Novelli and Demaison, 1988; Zappaterra, 1994; Bertello et al., 2010).

Depth and thickness The depth of the top of the Triassic evaporites of the Emma Limestones Formation reaches 7,000 meters east of the Teramo thrust (Bigi et al., 2011). Deep wells of the Gargano and Apulian areas show that the present depth of the Upper Triassic black shales, which are often thin and irregular in occurrence, is 4,500 to 5,000 meters. In the Apulian and southern Adriatic basin, the depth of Emma Limestones Formation is estimated at 5,000-6,000 meters (Mazzuca et al., 2015). The thickness of this potential source rock is between 50-200 meters based on subsurface and outcrop data. The net thickness ranges between 5-24 m.

Shale oil/gas properties The geochemical parameters estimated for the Late Triassic evaporites and euxinic deposits explored in the Adriatic–Apulia area (amongst which the Emma Limestone Formation) outcropping in the Apennines range or could be summarized as follows.

Table 1 Overview of the main properties of the organic-rich intervals.

Chance of success component description The lack of specific literature or assessments concerning unconventional resources in Italy are mainly related to some geological factors that reduce the economic interest of these resources: 1. limited and discontinuous extension of the organic-rich rocks; 2. rocks with high thickness have low TOC (<<2%); 3. rocks with high TOC have low thickness (<<20 meters).

Occurrence of shale

Mapping status Poor In general it is very difficult to map the areal extent and depth of the discontinuous organic-rich units because of the scattered distribution of subsurface data.

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Sedimentary variability High The depositional heterogeneity is largely related to the basin physiography during deposition that was marked by areas of differential subsidence rates leading to formation of restricted basins inside the platform complex. Even within these restricted basin lateral changes are expected based on to relatively shallow depositional depths.

Structural complexity High Thicknesses and depths are affected by syn-tectonic deposition and later thrust tectonics.

HC generation

Available data Moderate Some exploration wells are public and used for assessment of shale oil/gas potential. Most, however, are confidential and most data on shale properties comes from outcrops analogues.

Proven source rock Proven Multiple working petroleum systems (oil) are present in the Adriatic and Apulian area that reside in the thrusted Apulian platform-to-basin Even stacked systems exist. No further details given.

Maturity variability High A great variability of the thermal maturity is expected due to the complex structural history. Source rocks occur at a wide range of depths and are likely to exhibit a wide range of maturation levels (including in- and overmature).

Recoverability

Depth Average to Deep

Mineral composition No data average mineral composition was not provided

Marne del Monte Serrone Formation (1009) This formation was deposited in a basinal environment characterized by an articulated physiography and bathymetry consisting of structural highs and subsiding basins, inherited from the break-up and drowning of the Early Jurassic Calcare Massiccio carbonate platform. In the Central Northern Apennines the Marne del Monte Serrone Formation (RSN) consists of Early Toarcian deposits enriched in organic carbon. This formation is interposed between a calcareous unit (Corniola - COI) and a reddish nodular calcareous marly one (Rosso Ammonitico Umbro-Marchigiano). The RSN mostly consists of organic rich shale, marly-clay and marly-limestones, deposited in a low- oxygenated basin (Palliani et al., 1998). The physiography and bathymetry of the Early Toarcian Umbria-Marche basin strongly controlled the type, the accumulation and the preservation rate of the total organic matter (Gugliotti et al., 2012; Parisi et al., 1996).

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Depth and thickness The thickness of the RSN is variable and related to the morphology of the basin and the different extent of the stratigraphic succession. In the Umbria-Marche outcrops, the net thickness of Toarcian black shales and black shale-like deposits ranges from 1 to 24 meters, with minimum values in the condensed succession (Parisi et al., 1996). Although this stratigraphic interval displays characteristics typical of potential source rocks, the thickness of the organic-rich interval is much more variable and limited. No specific information is available for the characteristics of this formation in the subsurface. Based on the seismic profiles across the anticlines penetrated by the Cornelia 1 and Pesaro Mare wells to the north of Ancona, the depth of the top of the RSN is estimated to be at least 4,000-5,000 meters for the Northern Adriatic basin (Casero and Bigi, 2013).

Shale oil/gas properties The lithofacies deposited on the structural highs in the basinal setting are characterized by low TOC % 0.1-0.3. The poorly-oxigenated, black shale and black shale-like sediments originated in the deepest portions of the basin, show higher TOC % 0.5-2.7 (Parisi et al., 1996). The TOC values estimates of Katz et al. (2000) are 0.19–2.34% (mean 0.95%) and the mean value of the Total hydrocarbon generation potential is 6.19 mg HC/g rock. The organic matter is mostly composed of a mixture of continental organic debris and marine components such as dinoflagellate cysts, foraminifera linings and Tasmanaceae algae (Gugliotti et al., 2012); Katz et al. (2000) classified these sources rock as Type II-III.

Although this stratigraphic interval displays characteristics typical of potential source rocks, the thickness of the organic-rich interval is limited and highly variable.

Occurrence of shale

Mapping status Poor In general it is very difficult to map the areal extent and depth of the discontinuous organic-rich units because of the scattered distribution of data. Although, in outcrop, this stratigraphic interval displays characteristics typical of potential source rocks, the thickness of the organic-rich interval is much more variable and limited. No specific information is available for the characteristics of this formation in the subsurface.

Structural complexity

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High Thicknesses and depths are affected by syn-tectonic deposition and later thrust tectonics.

HC generation

Available data Poor Most data on shale properties comes from outcrops analogues.

Proven source rock Possible Based on seismic data, the source rock is thought to be present underneath Northern Adriatic basin (not encountered though) and might contribute to the petroleum system.

Recoverability

Depth Average In the subsurface mostly at depths of 4-5 km

Mineral composition No data average mineral composition was not provided

Marne a Fucoidi Formation (1010) Within the Cretaceous succession of the Umbria – Marche Basin (UMB), the Marne a Fucoidi Formation is one of the best-preserved deep-marine archive of the Aptian– Albian. It represents a distinctive multicolored interlude with more shale, outcropping in many sections from the Umbria-Marche Apennines to the Gargano area. This formation consists of thinly interbedded pale reddish to dark reddish, pale olive to dark reddish brown and pale olive to grayish olive marl-stones and calcareous marlstones together with dark gray to black organic carbon-rich shales, usually with a low carbonate content, and yellowish-gray to light gray marly limestones and limestones (Coccioni et al., 2012). Several distinctive organic-rich black shale and marl marker beds occur within the Aptian-Albian interval (Cresta et al., 1989), some of which have been identified as the regional sedimentary expression of OAE1a to OAE1d (Coccioni et al., 2012 and references therein). The Selli Level is one of the major episodes of organic-matter deposition of the Lower Aptian, constituting a basinal marker bed at the base of the Marne a Fucoidi Fm. It represents a radiolaritic bituminous ichtyolitic horizon recording the Lower Aptian global OAE1a (Baudin et al., 1998, and references therein).

Depth and thickness The exposed sequence of the Marne a Fucoidi Formation near Gubbio is >50 m thick, with a net source-rock thickness in excess of 8 m. Arthur and Silva (1982) observed that the highest levels of organic enrichment are largely confined to a 20 m thick, lower to lower-middle Albian interval at Gubbio. Fiet (1998) reported that within the Umbria-Marche Basin, as many as 150 thin black shales may be present in a 42 m gross interval.

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The depth of the top of the Marne a Fucoidi is very variable ranging between ~2,000 meters below the Montagna dei Fiori thrust, up to 5,000 meters below the Teramo thrust, in the Adriatic area (Bigi et al., 2011). In the Central Adriatic Basin, the depth of the top Marne a Fucoidi formation is between 4,000-5,000 meters (Casero and Bigi, 2013).

Shale oil/gas properties The Poggio Guaine section, located between Mount Nerone and Cagli, is considered a type section for the Aptian-Albian interval in the UMB. In this section the total thickness of the Marne a Fucoidi Formation is 82.53 m (Coccioni et al., 2012). Based on field observations of the Marne a Fucoidi Katz et al. (2000) suggests that a typical organic-rich sequence is less than 0.25 m thick, and that organic-rich/organic-poor cycles are 1.5 m thick. The exposed sequence near Gubbio is >50 m thick, implying a net source-rock thickness in excess of 8 m. Arthur and Silva (1982) observed that the highest levels of organic enrichment are largely confined to a 20 m thick, lower to lower-middle Albian interval at Gubbio. Fiet (1998) reported that within the Umbria- Marche Basin, as many as 150 thin black shales may be present in a 42 m gross interval. The geochemical parameters estimated for the Marne a Fucoidi Formation outcropping in the Central Apennines are summarized as follows.

Table 2 Overview of the main parameters of the organic rich intervals

Occurrence of shale

Mapping status Moderate Outcrop data is widespread and reveal a rather continuous presence. However, for the subsurface, iIn general, it is very difficult to map the areal extent and depth of the shale layer.

Sedimentary Variability Low Due to the pelagic origin, the observed depositional heterogeneity is low

Structural complexity High Thicknesses and depths are affected by syn-tectonic deposition and later thrust tectonics.

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HC Generation

Recoverability

Depth Average In the subsurface mostly at depths of 4-5 km

Mineral composition No data average mineral composition was not provided

Livello Bonarelli (not considered in assessment) The Livello Bonarelli represents a regional marker bed located at the top of the Scaglia Bianca Formation, close to the Cenomanian/Turonian boundary. This marker consists of organic-rich sediments related to the well-known Oceanic Anoxic Event 2 (OAE2 – Scoppelliti et al., 2006). Unlike the surrounding formations, which are rich in foraminifera, strata associated with the Bonarelli Event are rich in radiolaria and fish remains (Jenkyns, 2010). Such a shift may indicate an increase in primary productivity.

Depth and thickness Although the Cenomanian-Turonian Bonarelli Event displays some of the most high levels of organic enrichment, in the Umbria-Marche domain it obtains thicknesses in outcrop of less than 2 meters at Furlo and Gubbio sections (Passerini et al., 1991).

Shale oil/gas properties Unweathered samples from the Bonarelli Event analyzed by Katz et al. (2000) contained as much 27.5% TOC (mean value 7.71%). Hydrocarbon generation potential in excess of 280 mg HC/g rock have been determined for this interval, with a mean generation potential of ≈ 60 mg HC/g rock. When severely weathered, organic carbon contents are less than 0.5% (Katz et al 2000). Pieri and Mattavelli (1986) described the kerogene type of the Livello Bonarelli as “90% amorphous and marine” and reported an average TOC value of 5.12. The study carried out by Scoppelliti et al. (2006) confirms the high TOC values for the Bonarelli black shale in the Bottaccione section (Scopelliti et al., 2006). Because of the limited thickness the Livello Bonarelli does not show a relevant interest as potential shale oil source rock and will not be involved in the further assessment.

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References Andrè, P., and Doulcet, A. (1991). Rospo Mare Field – Italy , Apulian Platform, Adriatic Sea. AAPG Treatise of Petroleum Geology, Atlas of Oil and Gas Fields A-06, 29-54.

Arthur, M., and Silva, I.P. (1982). Recoverability of widespread organic carbon-rich strata in the Mediterranean Tethys. In: Schlanger, S. 0. and Cita, M. B. (Eds), Nature and Origin of Cretaceous Carbon-Rich Facies. Academic Press (London), 7-54.

Baudin, F., Herbin, J.-P., Bassoullet, J.-P., Dercourt, J., Lachkar, G., Manjvit, H. and Renard, M. (1990). Distribution of organic matter during the Toarcian in the Mediterranean Tethys and Middle East. In: Hue, A. Y. (Ed.), Deposition of Organic Fades. AAPG Studies in Geology, 30, 73-91.

Bechstadt, T., Boni, M., Iannace, A. and Koster, J. (1989). Upper Triassic source rocks from Alps and Southern Apennines (Austria, Italy). Abstracts 28th International Geological Congress, 1, 109.

Bencini, R., Bianchi, E., De Mattia, R., Martinuzzi, A., Rodorigo, S. and Vico, G. (2012). Unconventional Gas in Italy: the Ribolla Basin. AAPG, Search and Discovery Article #80203.

Bertello, F., Fantoni, R., Franciosi, R., Gatti, V., Ghielmi, M., and Pugliese, A. (2010). From thrust-and-fold belt to foreland: hydrocarbon occurrences in Italy. In Vining, B.A. & Pickering, S. C. (eds) Petroleum Geology: From Mature Basins to New Frontiers

– Proceedings of the 7th Petroleum Geology Conference, 113–126. DOI: 10.1144/0070113.

Bigi, S., Casero, P. and Ciotoli, G. (2011). Seismic interpretation of the Laga basin; constraints on the structural setting and kinematics of the Central Apennines. Journal of the Geological Society, London, 168, 1–11. doi: 10.1144/0016-76492010-084.

Bongiorni, D. (1987). The hydrocarbon exploration in the Mesozoic structural highs of the Po Valley: the example of Gaggiano. Atti Tic. Sc. Terra, 31, 125-141.

Brosse, E., Loreau, J.P., Huc, A.Y., Frixa, A., Martellini, L., Riva, A., 1988. The organic matter of interlayered carbonates and clays sediments — Trias/Lias, Sicily. Org. Geochem. 13, 433–443.

Brosse, E., Riva, A., Santucci, S., Bernon, M., Loreau, J.P., Frixa, A., 1990. Some sedimentological and geological characters of the late Triassic Noto formation, source rock in the Ragusa basin (Sicily). Org. Geochem. 16, 715–734.

Butler, R.W.H., Lickorish, W.H., Grasso, M., Pedley, H.M., Ramberti, L., 1995. Tectonics and sequence stratigraphy in Messinian basins, Sicily: Constraints on the initiation and termination of the Mediterranean salinity crisis. Geol. Soc. Am. Bull., 107, 425-439.

Casero, P., and Bigi, S. (2013). Structural setting of the Adriatic basin and the main related petroleum exploration plays. Marine and Petroleum Geology, 42, 135–147.

Ciarapica, G., and Passeri, L. (2005). Ionian Tethydes in the Southern Apennines. In CROP PROJECT: Deep Seismic Exploration of the Central Mediterranean and Italy, Edited by I.R. Finetti © 2005 Elsevier.

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Coccioni, R., Jovane, L., Bancalà, G., Bucci, C., Fauth, G., Frontalini, F., Janikian, L., Savian, J., Paes de Almeida, R., Mathias, G. L., and Ferreira da Trindade, R. I. (2012). Umbria-Marche Basin, Central Italy: A Reference Section for the Aptian-Albian Interval at Low Latitudes. Sci. Dril., 13, 42-46. doi:10.5194/sd- 13-42-2012.

Cresta, S., Monechi, S., and Parisi, G. (1989). Stratigrafia del Mesozoico al Cenozoico nell’area Umbro-Marchigiana. Mem. Descr. Carta Geol. Italia, 34, 185 pp.

Dyni, J. R., 1988, Review of the geology and shale-oil resources of the tripolitic oil- shale deposits of Sicily, Italy. USGS Open-File Report, 88-270.

Fantoni, R., and Scotti, P. (2003). Thermal record of the Mesozoic extensional tectonics in the Southearn Alps. Atti Tic. Sc. Terra, serie spec. 9, 96-101.

Farrimond, P., Eglinton, G., Brassell, S.C., and Jenkyns, H.C. (1988). The Toarcian black shale event in northern Italy. Org. Geoch., 13 (4-6), 823-832.

Fiet N. (1998). Les black shales, un outil chronostratigraphique haute resolution. Exemple del' Albien du bassin de Marches-Ombrie (ltalie centrale). Bull. Soc. Geol. France, 169, 221-231.

Finetti, I.R., Calamita, F., Crescenti, U., Del Ben, A., Forlin, E., Pipan, M., Prizzon, A., Rusciadelli, G., and Scisciani, V. (2005). Crustal Geological Section across Central Italy from the Corsica Basin to the Adriatic Sea Based on Geological and CROP Seismic Data. In CROP PROJECT: Deep Seismic Exploration of the Central Mediterranean and Italy, Edited by I.R. Finetti © 2005 Elsevier.

Frixa, A., Bertamoni, M., Catrullo, D., Trinicianti, E., Miuccio, G., 2000. Late Norian — Hettangian palaeogeography in the area between wells Noto 1 and Polpo 1 (S-E Sicily). Mem. Soc. Geol. Ital. 55, 279– 284.

Gaetani, M., Gnaccolini, M., Jadoul, F., Garzanti, E. (1998). Multiorder Sequence Stratigraphy in the Triassic system of Western Southern Alps. In “Mesozoic and Cenozoic Sequence Stratigraphy of European Basins”, SEPM Sp. Publ. 60, 701-717.

Gugliotti, L., Cirilli, S., and Buratti, N. (2012). The Early Toarcian anoxic event and shale gas potential: the case history of the Marne del Monte Serrone Formation (Central Italy). Rend. Online Soc. Geol. It., 21, 993-994.

Jadoul, F., and Galli, M.T. (2008). The Hettangian shallow water carbonates after the Triassic/Jurassic biocalcification crisis in the Western Southern Alps: the Albenza Formation. Riv. Ital. Paleont. Strat., 114, 453-470.

Jenkyns, H. C. (2010). Geochemistry of oceanic anoxic event. Geochem. Geophy. Geosy., 2010, 11(3), 1–30.

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Katz, B.J., Dittmar, E.I., and Ehret, G.E. (2000). Geochemical review of carbonate source rocks in Italy. Journal of Petroleum Geology, vol.23(4), 399-424.

Mazzuca, N., Bruni, A., and Jopen, T. (2015). Exploring the potential of deep targets in the South Adriatic Sea: insight from 2D basin modeling of the Croatian offshore. Geologia Croatica, 68/3, 237–246.

Nicolai, C., and Gambini, R., 2007, Structural architecture of the Adria platform-and- basin system, in Mazzotti, A., Patacca, E., and Scandone, P., eds., Results of the CROP Project, Sub-project CROP 04 Southern Apeninnes (Italy): Bollettino della Società Geologica Italiana (Italian Journal of Geoscience), Special Issue no. 7, p. 21–37.

Novelli, L., and Demaison, G. (1988). Triassic oils and related hydrocarbons "kitchens" in the Adriatic Basin. American Association of Petroleum Geologists Mediterranean Basins Conference, Nice, France. (Abstract.)

Novelli, L., Welte, D.H., Mattavelli, L., Yalçin, M.N., Cinelli, D., and Schmitt, K.J. (1988). Hydrocarbon generation in southern Sicily. A three dimensional computer aided basin modeling study. Organic Geochemistry, 13 (1-3), 153–164.

Palliani, R B., Cirilli S., and Mattioli, E (1988). Phytoplankton response and geochemical evidence of the Lower Toarcian relative sea level rise in the Umbria- Marche basin (central Italy). Palaeogeography, Palaeoclimatology, Palaeoecology, 142, 33-50.

Parisi, G., Ortega Huertas, M., Nocchi, M., Palomo, Monaco, P., Martinez, F. (1996). Stratigraphy and geochemical anomalies of the early Toarcian oxygen-poor interval in the Umbria-Marche Apennines (Italy). GEOBIOS, 29 (4), 469-484.

Passerini, M.M., Bettini, P., Dainelli, J., and Sirugo, A. (1991). The "Bonarelh Horizon" in the Central Apennines (Italy): Radiolarian biostratigraphy. Cretaceous Research, 12, 321-331.

Patacca, E., Scandone, P., Giunta, G., and Liguori, V. (1979). Mesozoic paleotectonic evolution of the Ragusa zone (South eastern Sicily). Geol. Romana ,18, 331–369.

Pieri, M., and Mattavelli, L. (1986). Geologic framework of Italian petroleum resources. AAPG Bull., 70, 2, 103-130.

Riva, A., Salvatori, T., Cavaliere, R., Ricchiuto, T., and Novelli, L. (1986). Origin of oils in Po Basin, Northern Italy. Org. Geochem., 10, 391-400.

Scopelliti G., Bellanca A., Neri R., Baudin F., Coccioni R. (2006) - Comparative high- resolution chemostratigraphy of the Bonarelli Level from the reference Bottaccione section (Umbria–Marche Apennines) and from an equivalent section in NW Sicily: Consistent and contrasting responses to the OAE2. Chemical Geology 228, 266– 285.

Shiner, P., Bosica, B., Turrini, C. (2013). The Slope Carbonates of the Apulian Platform – an under-explored play in the Central Adriatic. AAPG Conference, Barcelona, April 2013.

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Soua, M. (2014). A Review of Jurassic Oceanic Anoxic Events as Recorded in the Northern Margin of Africa, Tunisia - Journal of Geosciences and Geomatics, 2 (3), 94- 106. Available online at ttp://pubs.sciepub.com/jgg/2/3/4 © Science and Education Publishing. DOI:10.12691/jgg-2-3-4

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T12 - Ribolla Basin (Italy) – Argille Lignitifere

General information (see excel table from GEUS) Screening- Index Basin Country Shale(s) Age Index Miocene T12 Ribolla I Argille Lignitifere (Tortonian- 1011 Messinian)

Geographical extent The extent of the Miocen Argille Lignitifere within the Ribolla Basin is depicted in figure 1.

Figure 1 Location of the Argille Lignitifere. The coloured areas represent different basins.

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Geological evolution and structural setting

Syndepositional setting The history of the Ribolla Basin is connected with extension in the Tyrrhenian basin with the rifting migrating from west to east, from Miocene up to Plio-Pleistocene (Scrocca et al., 2003). The extension is marked by the development of NW-SE normal faults and NE-SW faults. The infilling of the Ribolla Basin is characterized by a transgressive succession that unconformably overlies the mainly Cretaceous allochthonous units (Flysch Liguridi) that belong to the pre-existing Alpine-Apenninic orogenic belt. From the base, the succession consists of:

. Estuarine sand and conglomerates followed by marls, . Clay and sand with euxinic coal layers and organic rich shaly coals, . Brackish fauna marls with sand layers and conglomerates, . Lagoonal evaporite clays and marls.

The Late Miocene succession is unconformably overlain by Plio-Pleistocene alluvial deposits.

Structural setting The Late Miocene succession and its coal layers are gently folded due to synsedimentary extensional events. The syncline is NW-SE oriented with a SE plunge. The coal layers outcrop in the northern part of the basin and down dip toward SE. Burial due to basin subsidence continued until Quaternary.

Organic-rich shales

The Argille Lignitifere Formation The Argille Lignitifere Formation of Tortonian-Messinian age, was deposited in a lagoonal/lacustrine environment and consists of clay and sand with euxinic coal layers and organic rich shaly coals (Bagaglia). At its base the organic rich sequence consists of one laterally continuous 9-11 meter thick seam of coal and black shale.

Depth and Thickness The Argille Lignitifere Formation is up to 80 meters thick. The thickest single coal layer is 6 meters, with some local depositional thickening up to 15 meters. The net thickness has been estimated, along the Tuscany west coast, for an area outside the Ribolla basin, and ranges from 0 to 8 meters (Bencini et al., 2012). The gas is interpreted to be producible from both the coal and the organic rich shale that is associated with the coal seam, at an average depth of approximately 1,000 m (Bencini et al., 2012).

Shale oil/gas properties An assessment of CBM and shale gas potential by Bencini et al. (2012) focus on the “Fiume Bruna” and “Casoni” exploration licences. All the data here reported come from this study. TOC value ranges from 1.38 to 56.14% and 20% on average (Bencini et al., 2012), with the highest values in the coals. Vitrinite reflectance values range from 0.825 to 1.302 %.

Miocene age organic rich sequence consists of one laterally continuous 9-11 meter thick seam of coal and black shale, which is saturated with thermogenic (dry) gas. The gas is interpreted to be producible from both the coal and the organic rich shale at an

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average depth of approximately 1,000 m. The considered interval responds more like a gas shale than a classic high permeability coal and is able to produce excellent quality natural gas by desorption after stimulation. Permeability is in the range of 1-2 mD.

Additionally, there are indications that the 70 meter thick laminated marl and clay sequence immediately above the main seam may be prospective for shale gas as well (Bencini et al., 2012). As such the tens of meter thick coal and gas shale interval may be considered a single play with the following characteristics: . The coal and gas shale have similar gas content of 4.7 m3/t (152 scf/ton) at approx. 80 bar. . The dry organic rock has 1-2 mD permeability and is gas saturated* . The coal seam responds overall more like a gas shale than a classic high permeability CBM coal . The potentially productive area is in excess of 190 km2 based on the extent of the coal seam at a depth of 1000 m. . Estimated 27.4 BCM (968 BCF) of gas in place, . Estimated 5.7 BCM (203 BCF) of recoverable gas, . 69% Shale Gas and 31% CBM/CSM. * Considering that the section has not been uplifted, this means that the coal /gas shale seam produced many times the gas it is able to trap by absorption in the matrix, and that the seam is always saturated with gas.

Chance of success component description

Occurrence of shale

Mapping status Good Well data and a recently acquired 2D seismic survey exist were used to construct improved depth maps.

Sedimentary Variability Moderate The lateral extent of the coal and shaly coals is not entirely continuous.

Structural complexity Low The geological structure is relatively simple as is confirmed by interpretation of a 2008-2010 2D seismic survey.

HC generation

Maturity variability Low Thermal maturity is only affected by a single burial event. Besides depth, maturity modelling is predominantly dependent on maturity-

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depth relationship and a proper assessment of the geothermal gradient. The latter is suggested to be twice as high as normal based on extrapolation of borehole temperatures. However, older measurements reveal different gradients (Bencini et al., 2012). Modelled vitrinite reflectance is based on the extrapolated thermal gradient and converted to coal maturity by correlation with the Horseshoe Canyon / Drumheller coal maturity vs depth relationship in the Alberta Basin.

Recoverability

Depth Average The gas is interpreted to be producible from both the coal and the organic rich shale that is associated with the coal seam, at an average depth of approximately 1,000 m Variations in thicknesses and depths are only affected by syn-depositional (subsidence).

Fraccability Favourable Independent Energy Solutions (IES), recently completed the FB2 coal bed methane (CBM) well in its target zone present at a depth of 340 m (1100 ft) and executed a test of the coal's productivity in this shallower part of the Ribolla basin (incorporating both the Casoni and Fiume Bruna blocks). A hydraulic fracture operation coupled with a ceramic proppant, designed to enhance productivity, completed successfully and this was followed by a production test that began on 17 April 2010 (source: http://www.energy-pedia.com).

References Bencini, R., Bianchi, E., De Mattia, R., Martinuzzi, A., Rodorigo, S. and Vico, G. (2012). Unconventional Gas in Italy: the Ribolla Basin. AAPG, Search and Discovery Article #80203.

Scrocca, D., Doglioni, C. and Innocenti, F. (2003). Constraints for an interpretation of the Italian geodynamics: a review. In: Scrocca, D., Doglioni, C., Innocenti, F., Manetti, P., Mazzotti, A., Bertelli, L., Burbi, L. and D’Offizi, S. (Eds.), CROP Atlas: seismic reflection profiles of the Italian crust. Mem. Descr. Carta Geol. D’It., 62, 15-46.

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T13 - Ragusa Basin (Italy) – Triassic shales

General information Screening- Index Basin Country Shale(s) Age Index Noto & Streppenosa Triassics T13 Ragusa I 1012, 1013 Shales

Geographical extent

Figure 1 Location of the Noto & Streppenosa Shales in southern Sicily. The coloured areas represent different basins.

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The extent of the Triassic organic rich shales within the Ragusa Basin is depicted in Figure 1. The Ragusa basin lies onshore and offshore in the southeastern part of Sicily and represents the foreland region and continues offshore southwards in the Sicily Channel and eastwards in the Ionian sea.

Geological evolution and structural setting

Syndepositional setting The Ragusa basin lies onshore and offshore in the southeastern part of Sicily, the Hyblean plateau (Guarnieri et al., 2004), and represents one of the tectonic troughs that developed during the Lower Jurassic along the Apulian (African s.I.) margin of the opening Tethys. During the Norian–Rhaetian times (Frixa et al., 2000) two different palaeogeographic domains developed within the Hyblean area characterized by different subsidence and sedimentation rates (Frixa et al., 2000). Shallow water depositional environments and lower subsidence rate affected the northern part of the Hyblean plateau. In Norian time, the area was characterized by the dolomitic peritidal sedimentation of the Sciacca Formation (coeval to the lower-middle Norian Dolomia Principale Formation in the Southern Alps). During the end of Rhaetian the area began to drown and although the subsidence was less pronounced with respect to the southern area, a shallow euxinic lagoonal basin developed. The Noto Formation, dated as Rhaetian by palynological data (Frixa et al., 2000), consists of alternating black shales and micritic, microbial dolomitic limestones. In this area the observed lack of stratigraphic continuity (Upper Norian–Lower Rhaetian) between the Sciacca Formation and the Noto Formation has been interpreted as a sedimentary hiatus (Frixa et al., 2000). In the southern sector (explored by the Marzamemi 1, Pachino 4 and Polpo 1 wells), the tectonic activity was more pronounced and the considerable subsidence was balanced by high sedimentation rate. Here, the organic-rich basinal shales and limestones of the Streppenosa Formation were deposited under prevailing reducing conditions.

Structural setting The thick succession of Triassic- Lower Jurassic platform and slope to basin carbonates, during the Late Miocene-Pliocene got involved in the foreland and foredeep chains as the result of Alpine collision between the African and the European plates (Patacca et al., 1979; Brosse et al., 1988). The basin then belonged to the Hyblean foreland, characterized by carbonate sedimentation. Consequently, the Triassic platform carbonates are unconformably overlain by Jurassic-Eocene pelagic carbonates and Cenozoic open shelf clastic deposits. In Sicily, overthrusting by the deformation front occurred in Pliocene/Pleistocene time, leaving the Hyblean plateau as sink area for Plio-Pleistocene alluvial deposits. The long and complex tectonosedimentary history produced multiple phases of vertical and lateral displacement (Accaino et al., 2011; Catalano et al., 2012).

Organic-rich shales

Noto Formation The Noto formation of Rhaetian age is recognized as the main source rock for the oil fields in the Ragusa Basin (Pieri and Mattavelli, 1986; Novelli et al., 1988; Brosse et al., 1988). In the Hyblean Plateau it consists of several lithotypes:

. laminated black-shales (rarely silty) . laminated limestones; laminae consist of mudstones and shales, often recrystallized and sometimes dolomitized, algal-mats, centimeter-thick layers of pelletoidal

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packstones and decimeter-thick layers of mudstones with ostracods (especially in the Nobile-1 and Gela 32 wells) . recrystallized mudstones and wackestones, with shaley or micritic, sometimes dolomitized, lithoclasts or herbaceous fragments . dolomitic breccias.

Depth and Thickness The Noto formation is rather constant in thickness and does not exceed 300 m. Depth of top is 2,862 meters and bottom 3,076 meters in the Noto2 onshore well.

Shale Oil Properties The highest petroleum potentials are associated with the black-shales and argillaceous laminites intercalated within the above mentioned lithofacies. TOC ranges between 0.2 – 10.0%, with an average of 4.0 %. Kerogen is of Type II. High TOC values were encountered in samples at a depth around 1,800-1,900 meters (Pieri & Mattavelli, 1986, Brosse et al., 1988-1990). Hydrogen Index values range from 300 to 550 mg/gTOC (Novelli et al., 1988). Very limited thicknesses of the shale layers are found, for example in the Noto-2 onshore well (chosen as type-stratigraphic section). The largest thickness for a single shale layer is ~13 meters at a depth of 3,017 meters and the shale layers thickness in this well usually varies 1-2 meters. The limited extent confirmed by other wells, limits the economic interest of the Noto formation as a shale oil resource.

Streppenosa Formation The Streppenosa formation, considered a source rock as the Noto Formation, is composed of three members (Frixa et al., 2000) that from bottom to top can be schematized as follows: . The Lower Streppenosa Member, assigned to the Norian–Rhaetian on the basis of calcareous nannofossils in the onshore Pachino 4 well consists of packstone and mudstone/wackestone with abundant radiolarians and frequent fine resedimented calciturbiditic packstone. Basalt horizons and silty shale occur in the lowest part of this member. . The Middle Streppenosa Member has been mostly referred to as Rhaetian (from 4794 m to 2640 m in the onshore Pachino 4 well) and is characterized by dominance of mudstones and wackestones with frequent intraclastic peloidal and oolitic thin intercalations (often recrystallized or dolomitized) and black silty shales. Limestones and shales are often laminated and contain plants debris. Basaltic intrusions mainly in the upper portion are also present. Bioclasts consist of radiolarians, sponge spicules, ostracodes, benthic foraminifers, echinoderm fragments, gastropods and scattered ammonites. . The Upper Streppenosa Member was dated as Hettangian (Frixa et al., 2000) and mainly consists of gray-green shales/marls with scattered fine grained intraclastic– oolitic packstone. Radiolarians, sponge spicules, benthic foraminifers, echinoderm remains, ostracods and some gastropods are the most common bioclasts. Siltstones, fine grained quartzarenites and recrystallized mudstones occur at the base of the member. Frequent intercalations of gray, silty shales and mud-stones are more common in the upper part. Horizons of tuff, basaltic lava are still present (within the interval from 2550 m to 2400 m in the onshore Pachino 4 well).

Depth and Thickness The thickness of the Upper Streppenosa Member varies between 100 m in the Noto area to 600 m in the southern basin area (Frixa et al., 2000). The thickness of the

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Streppenosa formation as a whole is also highly variable, especially in the southeastern part of the Basin, where it may reach 3,000 metres or more.

Shale Oil Properties The theoretical highest petroleum potential is associated to the intercalated black- shales of the Middle Streppenosa Member. The Upper Streppenosa Member has an average TOC of 0.8%. (Pieri & Mattavelli, 1986, Brosse et al., 1988). Hydrogen Index (Novelli et al., 1988) values range from 50 to 200 mg/g TOC. Both members present limited thickness of the shale layers in available well stratigraphy (usually < 20 meters), as such the economic interest of the Streppenosa formation as a shale oil resource is limited.

Chance of success component description (1012, 1013)

Occurrence of shale

Mapping status Poor In general it is very difficult to map the areal extent and depth of the discontinuous organic-rich units because of the scattered distribution of subsurface data.

Sedimentary Variability High The depositional heterogeneity is largely related to the basin physiography during deposition that was marked by areas of differential subsidence rates leading to formation of restricted basins inside the platform complex. Even within these restricted basin lateral changes are expected based on to relatively shallow depositional depths

Structural complexity High Both the limited depositional extent and later structuration make that the economic interest of formations as a shale oil resource is limited

HC generation

Available data Low Only one exploration well, to date, exists.

Proven source rock Unknown No working petroleum systems (oil) is present.

Maturity variability High A great variability of the thermal maturity is expected due to the complex structural history. In combination with local basaltic intrusions

Recoverability

Depth Average In the subsurface mostly at depths of 2-3 km.

Mineral composition 1012 - Poor very clay rich (>50% clay content) 1013 – No data

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References Accaino F., Catalano R., Di Marzo L., Giustiniani M., Tinivella U., Nicolich R., Sulli A., Valenti V. & Manetti P. (2011) - A crustal seismic profile across Sicily. Tectonophysics, 508, 52-61.

Brosse, E., Loreau, J.P., Huc, A.Y., Frixa, A., Martellini, L., Riva, A., 1988. The organic matter of interlayered carbonates and clays sediments — Trias/Lias, Sicily. Org. Geochem. 13, 433–443.

Catalano R., Valenti V., Albanese C., Sulli A., Gasparo Morticelli M., Accaino F., Tinivella U., Giustiniani M., Zanolla C., Avellone G. & Basilone L., (2012) - Crustal structures of the Sicily orogene along the SIRIPRO seismic profile”. 86° Congresso Nazionale della Società Geologica Italiana “Il Mediterraneo: un archivio geologico tra passato e presente”, 18-20 Settembre 2012, Arcavacata di Rende (CS). Rend. Online Soc. Geol. It., 21, 67-68.

Frixa, A., Bertamoni, M., Catrullo, D., Trinicianti, E., Miuccio, G., 2000. Late Norian — Hettangian palaeogeography in the area between wells Noto 1 and Polpo 1 (SE Sicily). Mem. Soc. Geol. Ital. 55, 279– 284.

Guarnieri, P., Di Stefano, A., Carbone, S., Lentini, F., Del Ben, A., 2004. A multidisciplinary approach to the reconstruction of the Quaternary evolution of the Messina Strait. In: Pasquaré, G., Venturini, C., (Eds.), Mapping Geology in Italy. APAT, 45–50.

Patacca, E., Scandone, P., Giunta, G., and Liguori, V. (1979). Mesozoic paleotectonic evolution of the Ragusa zone (South eastern Sicily). Geol. Romana ,18, 331–369. Pieri, M., and Mattavelli, L. (1986). Geologic framework of Italian petroleum resources. AAPG Bull., 70, 2, 103-130.

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T14 - Dinarides – Lemeš

General information Screening- Index Basin Country Shale(s) Age Index

T14 Dinarides HR Lemeš Late Jurassic 1004

Geographical extent The Lemeš study area is part of the NW-SE oriented Dinarides, located between the mountains Svilaja and Mali Kozjak (Figure 1).

Figure 1 Position of Lemeš deposits in the Dinarides Mountains. The colored areas represent different basins

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Geological evolution and structural setting

Syndepositional setting Lemeš sediments were deposited on the Adriatic Carbonate Platform (AdCP), which became a separate paleogeographic entity during the middle/late Early Jurassic after the disintegration of the Southern Tethyan Megaplatform (STM or Adria block) (Vlahović et al., 2005). Consequently, during Toarcian times, the AdCP, one among numerous large and extensive Mesozoic Tethyan platforms, was individualized and surrounded by deep water facies of platform and open Tethys (Tišljar et al., 2002 and Vlahović et al., 2002). The AdCP is characterized as a relative uniform shallow marine deposition during the Late Early and Middle Jurassic and by facies differentiation ranging from emergent parts of the platform to relatively deeper depositional sets as a consequence of the interaction of synsedimentary tectonics during the Late Jurassic, especially the Kimmeridgian (Tišljar et al., 2002, Velić et al., 1994, Velić et al., 2002a, Velić et al., 2002b, Lawrence et al., 1995 and Vlahović et al., 2005). During Kimmeridgian to Tithonian times, Lemeš sediments were deposited in a relatively shallow trough of a relatively narrow Tethyan bay, which penetrated from the NE margin into the inner part of the central part of the AdCP. Tectonic movements within the platform formed a SW–NE trending relatively shallow intra-platform trough, which represents a specific depositional event caused by the formation of pull-apart basins (Velić et al., 2002a and Velić et al., 2002b). The palaeogeographic distribution of facies during that time resulted from the gradual progradation of reefal and peri-reefal facies followed by oolitic facies culminating with the final infilling of the intra-platform trough and re-establishment of peritidal facies (Velić et al., 1994, Velić et al., 2002a and Velić et al., 2002b). Due to this sedimentary development, the Lemeš is partly a diachronous facies ranging from the Kimmeridgian to Early Tithonian.

Structural setting The AdCP lasted from Early Jurassic to end Cretaceous resulting in deposition of 3500– 5000 m of carbonates before its final disintegration. The end of the AdCP between the Cretaceous and Paleogene is characterized in most parts by a regional emergence. Deposition during the Paleogene was controlled mainly by intense synsedimentary tectonic deformation of the former platform area where Eocene carbonates were deposited followed by flysch sediments marking the beginning of final uplifting of Dinarides that reached its maximum during the Oligocene-Miocene (Vlahović et al., 2005). According to the geodynamic relationships of the Dinarides (Lawrence et al., 1995), the Late Jurassic Lemeš deposits at the end of Cretaceous was buried to at least 3000 m (as compared to the present position of the Late Jurassic in the subsurface of the Adriatic basin) and at a critical point, due to the intense compressional tectonics during the Late Paleogene, even up to 5000 m (as anticipated from the structural profiles) before it was uplifted to the surface during the Oligocene- Miocene.

Whole process also triggered formation of the External Dinaric Imbricate Belt with Thrust Front of the External Dinarides against Adriatic-Apulian Foreland. The whole area presents Dinaric Frontal Thrust Belt formed by ovethrusting (Placer et al., 2010).

Organic-rich shales

‘‘Lemeš” facies The Late Jurassic organic rich ‘‘Lemeš” facies is located in the mountain ridge Lemeš (part of Dinarides Mts.) between the mountains Svilaja and Mali Kozjak (Figure 1). Its facies is described as platy limestone interbedded with chert and sporadically bentonite layers and tuffs, as well as organic rich laminated limestone and calcareous

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shale. The Lemeš deposits Unit 4 is the most interesting unit with respect to source rock potential. Unit 4 beds are characterized by alteration of cherty, silicified, detrital limestone with organic rich laminated limestone and calcareous shale. These organic rich laminae possess a mud supported matrix (micritic calcite and partly clay particles) and are classified as fine biopelmicrites (mudstone) (Blažeković Smojić et al., 2009).

Depth and Thickness The thickness of organic rich laminated limestone and calcareous shale of the Lemeš deposits Unit 4 beds ranges from 3–70 m. The Poštak site (Rastičevo, north of Knin) contains calcareous shale, very rich in organic matter, with a thickness up to 20 m and the sum of the varying organic rich deposits of the Lemeš Unit 4 beds at 55–70 m thick. These organic rich beds occur throughout the Late Jurassic syncline that covers an area of 42 km2 (Blažeković Smojić et al., 2009). For the assessment a thickness of between 12 and 20 m is given and a depth between 0 and 930 m.

Shale oil/gas properties The laminated limestones and calcareous shales of the Kimmeridgian–Tithonian Lemeš deposits are found to be a very good to excellent, highly oil prone carbonate source rocks. The Unit 4 strata contain abundant organic matter (TOC values 3–9%) that is hydrogen rich (Rock-Eval Hydrogen Index 509–602 mg HC/g TOC; atomic H/C ratios 1.4–1.7). The kerogen is sulfur rich (Type II-S, 9 wt% S) and is composed almost exclusively of fluorescent amorphous organic matter derived mostly from the algal/phytoplankton biomass enriched by bacterial biomass (Blažeković Smojić et al., 2009).

Chance of success component description

Occurrence of shale layer

Mapping status Moderate A general map with the outlines of the shale gas layer, structural information as well as general depth, thickness, TOC and maturity information are available.

Sedimentary Variability Moderate The Lemeš deposits are described to have been deposited in a relatively shallow intra-platform trough and are partly diachronous.

Structural complexity High The basin is part of the Dinarides foreland fold and thrust belt.

HC generation

Available data Moderate Few source rock samples from outcrops, no subsurface data available

Proven source rock Possible HC shows and accumulation in other setting probably from same source rock as indicated by several occurrences of migrated HC and oil seeps on the surface suggesting that at least portions of a complete petroleum system exist.

Maturity variability Low Maturity in the early oil window (0.5-0.7% VRo) throughout the basin

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Recoverability

Depth Average In the subsurface mostly at depths of 2-3 km.

Mineral composition Favourable brittle mineral composition (>80% carbonates and/or quartz), fracturing tests, log interpretation

References Blažeković Smojić, S., Smajlović, J., Koch, G., Bulić, J., Trutin, M., Oreški, E., Alajbeg, A. & Veseli, V. (2009): Source potential and palynofacies of Late Jurassic “Lemeš facies”, Croatia. Organic Geochemistry 40, 833-845.

Lawrence, S.R., Tari-Kovačić, V. & Gjukić, B. (1995): Geological evolution model of the Dinarides. Nafta 46, 103–113.

Placer, L., Vrabec, M. & Celarc, B. (2010): The bases for understanding of the NW Dinarides and Istria Peninsula tectonics: -Geologija, 53/1, 55-86.

Tišljar, J., Vlahović, I., Velić, I. & Sokač, B. (2002): Carbonate Platform megafacies of the Jurassic and Cretaceous Deposits of the Karst Dinarides.– Geologia Croatica, 55/2, 139–170.

Velić, I., Vlahović, I. & Tišljar, J. (1994): Late Jurassic lateral and vertical facies distribution: from peritidal and inner carbonate ramps to perireefal and peritidal deposits in SE Gorski Kotar (Croatia). Géologie Méditerranéenne 21, 177–180.

Velić, I., Vlahović, I. & Matičec, D. (2002a): Depositional sequences and palaeogeography of the Adriatic carbonate platform. Memorie della Societá Geologica Italiana 57, 141–151.

Velić, I., Tišljar, J., Vlahović, I., Velić, J., Koch, G. & Matičec, D. (2002b): Palaeogeographic variability and depositional environments of the Upper Jurassic carbonate rocks of Velika Kapela Mt. (Gorski Kotar Area, Adriatic carbonate platform, Croatia). Geologia Croatica 55, 121–138.

Vlahović, I., Tišljar, J., Velić, I. & Matičec, D. (2002): Karst Dinarides are composed of relics of a single Mesozoic platform: facts and consequences. Geologia Croatica 55, 171–183.

Vlahović, I., Tišljar, J., Velić, I. & Matičec, D. (2005): Evolution of the Adriatic Carbonate Platform: Palaeogeography, main events and depositional dynamics. - Palaeogeography, Palaeoclimatology, Palaeoecology, 220, 333-360.

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T15a – Cantabrian Massif

General information Screening- Index Basin Country Shale(s) Age Index

Formigoso Fm Silurian 1032 Cantabrian T15a E Carboniferous Massif Carboniferous 1031 Formations

Geographical extent The Cantabrian Massif extends over the NE part of the Iberian Massif and represents the external zone of the Variscan Orogeny in the NW of the Iberian Peninsula (Figure 1). It consists of rocks varying in age from the Precambrian to the Carboniferous. Geologically, a division of the Cantabrian Zone has been established into seven different geographical units, that are from west to east: Somiedo, La Sobia-Bodón, Aramo, Central Carboniferous Basin, Mesozoic-Tertiary Cover, Ponga and Picos de Europa Units. The Cantabrian Massif extends over an approximate surface of 19,000 km2

Figure 1 Location of the Spanish Basins. The coloured areas represent different basins.

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Geological evolution and structural setting

Syndepositional setting The basinal deposits are composed of the Lancara Limestones, Oville slates and sandstones and the Barrios quarzites with a Cambrio-Ordovician age. The Silurian is represented by the Formigoso slates and Furada sands. Devonian is represented by the Rañeces complex, Moniello Limestones, Naranco sands, Candás Limestones and Candamo Limestones. The Carboniferous sequence is constituted by the Griotte and Montaña Limestones and the Lema and Sama groups (alternation between marine and continental deposits with coal beds).

Structural setting The Cantabrian Massif represents the external zone of the Variscan Orogen in the NW of the Iberian Peninsula, with materials varying in age from the Precambrian to the Carboniferous. A large number of thrusts and folds can be observed and define the Asturian Arc. Seven different units have been established, from west to east: Somiedo, La Sobia,-Bodón, Aramo, Central Carboniferous Basin, Mesozoic-Tertiary Cover, Ponga and Picos de Europa Units. These alloctonous units were emplaced in a foreland propagating sequence displaying varied geometries betwee the Westphalian to Stephanian. Movement converges as a whole towards the core of the Asturian Arc interpreted as a progressive series of rotational displacements (Pérez-Estaún, et. al).

Organic-rich shales

Silurian Formigoso Fm. The Formigoso Fm. is part of the Somiedo Unit. It is formed by black and gray shales, with thin interbedded bio-turbated siltstones and sandstones (quartzarenites) these are progressively more abundant toward the top of the formation, with frequent graded layers of shales.

Depth and Thickness The thickness of the whole Somiedo Unit varies between 70 to 200 meters. Specific thickness of the Formigoso Fm. is unknown.

Shale oil/gas properties The dominant type of organic matter is of amorphous non-fluorescent nature (amorfinita). Vitrinite particles are very small. The average reflectance of the pseudo- vitrinite is 1.09%. With transmitted light, a brown amorphous organic matter is predominant indicating a TAI (Thermal Alteration Index) of 3. The color of pollen and spores is consistent with a vitrinite reflectance around 1.1%. Reflectance values and the color of the palynomorphs indicate that the organic matter is within the window of wet gas. The values of S1 and S2 are very low, not reaching 0.1 between them, so the potential of the Formigoso Formation as source rock is doubtful. However, it should be noted that these values are obtained from outcrop samples, so the value of this data should be verified with undisturbed samples. The value of HI (5) confirms that the generated hydrocarbon would be natural gas.

Carboniferous San Emiliano Fm. The San Emiliano Formation makes part of the Sobia-Bodon Unit and is predominantly a terrigenous succession with a Namurian-Westphalian age. It has thin limestone levels in the middle and some coalbeds towards the top.

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Depth and Thickness The thickness of the Sobia-Bodon Unit is up to 2000 meters. A specific thickness for the San Emiliano Formation is unknown.

Shale oil/gas properties The dominant type of organic matter is vitrinite. Inertinite is less common and is represented by inertodetrinite. The amorphous organic matter is granular with a fluorescence of light brown tones. The average vitrinite reflectance is 0.66%. The amorphous organic matter is yellowish brown in color, indicating a 2.5 TAI. Pollen and spores are amber, corresponding to a vitrinite reflectance of about 0.65%. Vitrinite reflectance values and palynomorphs color indicate that the organic matter is in an early stage of maturity within the oil generation window. The vitrinite reflectance indicates that it is in the oil generation window (0.66%), at an early stage. S1 and S2 values do not, a priori, suggest a suitable source rock. The value of the HI is 9 indicating potential natural gas generation.

Carboniferous Fresnedo Fm. The Fresnedo Formation is located in the Central Carboniferous Basin. It is predominantly shaly, interbedded with minor sandstones (about 7% of the total) up to 470 meters thick containing some turbidites, breccias and calcareous olistolites, seperated, where present, between two important levels of interbedded limestones: the Mountain Limestone (Fms Barcaliente and Valdeteja) and the Massive Limestone. The Fresnedo Formation is Westphalian in age and is laterally equivalent to the Valdeteja Formation, on contact, the Fresnedo Fm. wedges out into the Valdeteja Fm.

Depth and Thickness The Fresnedo Formation has a thickness of up to 470 meters.

Shale oil/gas properties Vitrinite is the predominant organic matter type. Inertinite is also frequent and is represented by inertodetrinite. The amorphous organic matter is granular and sometimes weakly fluorescent. Vitrinite average reflectance is 1.07%. The amorphous organic matter is brown, suggesting TAI 3. The pollen and spores are brown and their color also fits with a vitrinite reflectance of about 1.1%. Vitrinite reflectance values and color palynomorphs indicate that the organic matter is within the window of wet gas.

S1 and S2 sum does not allow the Fresnedo package to qualify as source rock. The value of HI (3) confirms that the generated hydrocarbon potential would be natural gas.

Chance of success component description

Occurrence of shale layer

Mapping status Poor Only the general outline of the basin is known

Sedimentary Variability Moderate to High Deposits are an alternation of continental and marine depositis

Structural complexity Moderate to High

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HC generation

Available data Moderate Few samples from outcrops, no subsurface data available

Proven source rock Possible Gas found in Carboniferous setting within the basin complex

Maturity variability Unknown

Recoverability

Depth Shallow to deep The depths of the formations are not well known, they are estimated to lie between 0 and 6000m

Mineral composition No data average mineral composition was not provided

References ACIEP, GESSAL (2013): Evaluación preliminar de los recursos prospectivos de hidrocarburos convencionales y no convencionales en España.

Maio, F., Aramburu, C. and Underwood, J. (2011). Geochemistry of Ordovician and Silurian Black Shales, Cantabrian Zone, Asturias and Leon Provinces, Northwest Spain. Adapted from poster presentation at AAPG International Conference and Exhibition, Milan, Italy, October 23-26, 2011. http://www.searchanddiscovery.com/pdfz/documents/2011/50529maio/ndx_maio.pdf. html

Alvarez, R., Menendez, R., Ordoñez, A. and Cienfuegos, P. (2012). Preliminary study of the potential for natural-gas recovery and geological CO2-sequentration in lutite from de Cantabrian Basin. Seguridad y Medio Ambiente. Year 32 N 128 Fourth Quarter 2012. Fundación MAPFRE. https://www.fundacionmapfre.org/documentacion/publico/en/catalogo_imagenes/ima gen.cmd?path=1072549&posicion=2

IGME (1981). Estudio de las posibilidades de explotación de energía geotérmica en almacenes profundos de baja y media entalpía del territorio nacional.

Pérez-Estaún et al. (1988). A thin-skinned tectonic model for an arcuate fold and thrust belt. The Cantabrian Zone (Variscan Ibero-Armorican Arc). Tectonics, 7, 517- 537 pp.

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T15b – Basque-Cantabrian Basin

General information Screening- Index Basin Country Shale(s) Age Index

Carboniferous Carboniferous 1030 Formations Lower Jurassic Basque- Camino Fm. 1027 T15b Cantabrian E (Liassic) Lower Cretaceous Basin Lower Cretaceous 1028 Formations Valmaseda Fm. Upper Cretaceous 1029

Geographical extent The Basque-Cantabrian basin represents the western extension of the Pyrenean Range. To the west it is limited by the Cantabrian Massif and to the east by the Paleozoic Basque Massif. The southern edge borders the Cenozoic basins of Duero and Ebro.

Figure 1 Location of the Spanish Basins. The coloured areas represent different basins.

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Geological evolution and structural setting

Syndepositional setting The Basque-Cantabrian basin contains in its central part a very thick mid-Triassic to lower Neogene series of marine deposits, several thousand meters thick. The sequence starts with fluvial sediments consisting of clays, sandstones and conglomerates belonging to the Bundsandstein facies. Subsequent thick layers of evaporite sediments (gypsum, anhydrite and salt) were deposited, forming the “Keuper facies” , the main source of later diapirs. Source rocks were deposited in the Jurassic and Lower Cretaceous and reservoirs are found in the Lower Cretaceous sandstones and Upper Cretaceous limestones.

Structural setting The Basque-Cantabrian Basin is a Mesozoic-Cenozoic basin generated by two stages of subsidence (rifting): Triassic and Lower Cretaceous. It features a thick sedimentary record that was later folded and faulted during the Alpine Orogeny.

Organic-rich shales

Basque-Cantabrian Carboniferous The Gaviota Field source rock consists of Westphalian-Stephanian bituminous coals with maturity level values ranging from 0.6 to 0.9 Ro. Even though only two wells reached the Carboniferous, geochemical analysis and the lack of other source rocks, leave no doubt that the source rock is in the Stephanian B and C. This source rock was deposited in a marginal marine environment and its organic richness is present in the thin bituminous coal levels and intervening shales.

Depth and Thickness Thickness unknown, although a minimum of 500m of section was cut by the wells. Estimated depth for the formation is between 0 and 2500m.

Shale gas/oil properties This source rock consists of kerogen type II-III and is rich in lipids. TOC varies between 28% for the shales and 51% for the coals and coaly shales. Results of rock- eval pyrolysis indicate the S2 peak to range from 40 to 150 mg/g. The IF value is very valuable, ranging between 145 and 260.

Chance of success component description

Occurrence of shale layer

Mapping status Poor Only outlines for the basin are available, thickness and depth are not known

Sedimentary Variability Moderate to High Coals and coaly shales deposited in a marginal marine environment form the potential shale gas rocks.

Structural complexity High

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HC generation

Available data Moderate Few samples from two wells with TOC and Rock-Eval analyses

Proven source rock Proven

Maturity variability Unknown

Recoverability

Depth Shallow to average The depths of the formations are not well known, they are estimated to lie between 0 and 2500m.

Mineral composition No data Average mineral composition is unknown

Basque-Cantabrian Liassic Camino Fm. Diffraction shows that the rocks have high contents of carbonates, quartz and feldspars with illite and pyrite and clorites as accessory minerals.

Depth and Thickness Estimated thickness for the formation is 50 to 190m of which aproximately 25 to 100m are considered to be organic rich. The formation is assumed to be at depth between 0 and 7000m.

Shale gas/oil properties The average TOC values of the Pliensbachian black shales range between 3 to 6 wt %. Maximum values are usually found for the black shale horizon developed during the T. iberx zone, coinciding with the minimum carbonate content of the succession. Those samples exhibit TOC values up to 8.7 wt %.

The rest of the Pliensbachian hemi-pelagic facies show lower TOC values. This content varies between 0.4 wt % for non-organic marls to 2.4% in organic marls.

The lower Toarcian sediments are organically poor (TOC<1%), however, a TOC peak is observed within the back shale interval of the late Tenuicostatum - Early Sepentinus zones (TOC up to 1.8%). The lowest TOC of the succession corresponds to the upper Domerian unit of limestones developed at the end Pliensbachian.

The hydrocarbon potential of the black shales and organic marls has been evaluated with Rock-eval pyrolysis. In mature black shales samples the S2 value averages 5-10 mg/g but it can reach values up to 20 mg/g. Immature black shales samples yielded excellent values with maximum peaks between 10 and 57 mg HC/g. Finally, overmature samples collected in the deepest parts of the Polientes-Sedano Trough only yielded poor amounts of hydrocarbons (1.5 mg HC/g). The hydrocarbon potential decreases dramatically in the limestone-marl alternations, with maximum values of 2- 3 mg HC/g for immature samples.

The average hydrogen Index of the samples shows that the black shales are characterized by hydrogen rich type I/II kerogens. Mature samples of the Polientes-

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Sedano Trough show average values between 350-450 mg HC/g TOC. Samples of the immature Southwestern Marginal Domain reveal initial Hydrogen Index values of up to 600-750 mg HC/g TOC. Finally, over-mature samples from the central Polientes- Sedano trough are characterized by extremely low HI values (>50 mg HC/g TOC). The organically poor limestones and marls show lower HI values of about 100 and 200 mg HC/g TOC.

Chance of success component description

Occurrence of shale layer

Mapping status Poor Only outlines for the basin are available, thickness and depth are not known

Sedimentary Variability Low Laterally continuous hemipelagic type sedimentation

Structural complexity Moderate

HC generation

Available data Moderate

Proven source rock Possible Formation has been attributed to a known accumulation

Maturity variability Unknown

Recoverability

Depth Shallow to deep The depth of the formations are not known, they are estimated to lie between 0 and 7000m.

Mineral composition No data Average mineral composition is unknown.

Lower Cretaceous Errenaga, Lareo; Peñascal, Elekorta and Patrocinio Fms

Depth and Thickness The Peñascal and Elekorta Formations are up to 1,000 m thick, organic rich intervals within these formations have thicknesses between 50 and 200m. Estimates place the depth of the formations between 0 and 5500m.

Shale gas / oil properties From east to west, TOC values of the Errenaga Formation are all below 0.6% in the Iribas section, and below 1% in the Igaratza section (most of them below 0.75%). In the Ataun section (only the central shaly part) all lie below 1%, and all but two are below 0.75%. In general terms, the Errenaga Formation shows an increase in TOC content from east (Iribas) to west (Ataun). This trend parallels an increase in the

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siliciclastic character and thickness of the Formation. The lutite interval within the D. weissi and D. deshayesi zones has a relative low TOC. Practically all values from this interval are below 0.5%, with a maximum of 0.28% in Iribas, 0.63% in Igaratza and 0.87% in Ataun.

The TOC results of the Lareo Formation have a minimum of 0.28% and maximum of 2.09%. The values of T max are between 494°C and 550°C.

Black shales equivalent to the OAE 1a are located around 600 meter depth in the D. deshayesi ammonite zone, and TOC values reach up to 1.7% and 0.5 % average.

The total organic carbon content of the Patrocinio Formation (80m) in the Florida section is relatively low, with values ranging from 0.1 to 0.5 wt%. In the Cuchía section it is slightly higher than in the La Florida section, all values are below 1 wt% (i.e. 0.1 to 0.8 wt%). Other authors obtained values ranging from 0.12% and 1.37%.

Upper cretaceous Valmaseda Fm.

Depth and thickness The total thickness of the Valmaseda Formation is over 2,000 m, organic rich intervals within these formations have thicknesses between 50 and 200m. Estimates place the depth of the formations between 0 and 3500m.

Shale gas / oil properties San Leon Energy`s separate characterization of the Valmaseda Formation and the Enara Shale indicates that the TOC, while up to 3.6% locally, averages only about 1%. Traditionally the shales and/or black siltstone of the Valmaseda formation have a TOC between 1.5% and 2% for the thicker sections.

Chance of success component description

Occurrence of shale layer

Mapping status Poor

Sedimentary Variability High Described formations are very thick with about 1-2% of the formations have actual potential

Structural complexity Moderate

HC generation

Available data Moderate

Proven source rock Possible Gas accumulations in the area were linked to these source-rocks, early production tests showed gas production from the Valmaseda Fm.

Maturity variability Unknown

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Recoverability

Depth Shallow to deep The depth of the formations are not known, they are estimated to lie between 0 and 3500m for the Upper Cretaceous and from 0 to 5500m for the Lower Cretaceous.

Mineral composition No data Average mineral composition is unknown

References ACIEP, GESSAL (2013): Evaluación preliminar de los recursos prospectivos de hidrocarburos convencionales y no convencionales en España.

EIA/ARI World Shale Gas and Shale Oil Resource Assessment, Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States http://www.eia.gov/analysis/studies/worldshalegas/pdf/fullreport.pdf

San Leon Energy web page http://www.sanleonenergy.com/operations-and- assets/spain-cantabarian-ebro.aspx

Quesada, S., Robles, S. and Dorronsoro, C. (1996). Caracterización de la roca madre del Lías y su correlación con el petróleo del Campo de Ayoluengo en base a análisis de cromatografía de gases e isótopos de carbono (Cuenca Vasco-Cantábrica, España). Geogaceta, 20 (1) (1996), 176-179. http://www.sociedadgeologica.es/archivos/geogacetas/Geo20%20(1)/Art45.pdf

Barnolas, A. and Pujalte, V. (2004): La Cordillera Pirenaica. In: Geología de España (J. A. Vera, Ed.), SEG-IGME, Madrid, 282.

IGME (1981). Estudio de las posibilidades de explotación de energía geotérmica en almacenes profundos de baja y media entalpía del territorio nacional.

IGME (2010). Selección y caracterización de áreas y estructuras geológicas susceptibles de constituir emplazamientos de almacenamiento geológico de CO2 (ALGECO2). Volumen I-1 - Cadena Cantábrica y Cuenca del Duero - Geología.

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T16 - Guadalquivir

General information Screening- Index Basin Country Shale(s) Age Index

Guadalquivir T16 Guadalquivir E Carboniferous Carboniferous 1026 shales

Geographical extent Guadalquivir Basin is an elongated depression trending in ENE-WSW direction, which is a foreland basin type and is located between the Betic orogen in the south and the passive Iberian Massif margin in the north.

Figure 1 Location of the Spanish Basins. The coloured areas represent different basins.

Geological evolution and structural setting

Syndepositional setting The sedimentary basin fill takes place between the Tortonian and Pleistocene. During the Tortonian, the compressive stresses in the foreland fold belt brought down olistostromes from the South. The northern boundary of the basin is defined by an almost straight line separating the Paleozoic and Mesozoic rocks of the Cenozoic Sierra Morena basement.

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The substrate of the Neogene basin is composed of metamorphic or igneous Paleozoic rocks. In its eastern and western margins the Mesozoic formations emerge, consisting of a basal Triassic in the germanic facies and a Jurassic-Cretaceous carbonate series which progressively appears more complete eastward.

The upper Quaternary-Miocene filling is divided into several units, which form five depositional sequences that prograde from the north, east and south margins towards the center of the basin and are named by age order: Atlantis, Bética, Andalusia, Marismas and Odiel.

Structural setting Its genesis takes place as a result of the deformation of the lithosphere caused during the placement and stacking of External Betic Units. Based on its structural evolution it can be subdivided into three zones. . South-western zone: The south-western zone ranges from the Atlantic coastline to the province of Sevilla, following the structural trend of WNW-ESE Sud-Portuguese Zone and the northern boundary of the Culm facies of the area. . Western central zone: The western-central zone is smaller and coincides with the hypothetical extension of the The Mariánicas coal basin, through the Villanueva del Río y Minas coalfield towards the SE, in concordance with the syncline of Viar, within the area of Ossa-Morena. We can distinguish three zones: a western area formed by Permian materials; a central area formed by upper-Carboniferous successions of lower Devonian, faulted and refolded on which there is a NW-SE syncline consisting of conglomerates, sandstones and carbonaceous shales of the Upper Carboniferous and a eastern metamorphic zone. . Eastern zone

Organic-rich shales

Gualdalquivir Carboniferous

South-western zone This facies can be considered equivalent to the Lower Alentejo Flysch Group located in the Portuguese Algarve that has been assessed as a shale gas objective. In particular the Mértola, Mira and Brejeira formations of Carboniferous age were studied. Together they form a turbidite sequence that progrades to the southwest. The age ranges from the top Visean to the top Moscovian.

Depth and Thickness Unknown

Shale oil/gas properties TOC values vary between 0.26 and 1.86%, with a mean of 0.81, 0.91 and 0.72 respectively. Most of the samples have values of 0.5 to 1.0%. However, it can be assumed that these values represent 40% of the original, due to carbon consumption during the maturation process. Recalculating the initial TOC values, they would result in a range of 0.65 to 4.59, with mean values of 2.02, 2.28 and 1.80, most often between 1.0 to 4.0%.

Western central zone There is no background study of this shale on the content and status of organic matter. However in the 80’s, IGME was carried out a campaign to estimate bituminous

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shales across the country. The Ossa-Morena coalfields, located to the NW (Maimona, Bienvenida, Fuentes del Arco and Casas de Reina), were studied but without conclusive results. The Puertollano coalfield, located about 200 km NE in the Central Iberian Zone, was also investigated.

This site was the subject of exploitation of oil shales and coal between 1953 and 1966. The three horizons are called A, B and C, in-between of two layers of coal, sandstones and graywackes with about 110-130 m thick.

Depth and Thickness

Thickness about 110 – 130 m

Shale oil/gas properties The prospective levels, considered at the time as exploitable for oil, had oil yields of 5- 6%, 12-24% and 10-14% respectively, resulting in an average yield of 10.5% by weight. The mineralogical composition is 40% mica, 25% kaolinite and 20% quartz. The distillate oil has a C/H ratio of around 7.5 and contents of S and N of around 0.6 and 0.8% respectively. The distillate gas reaches a yield of 40 Nm3/t.

Eastern zone In the eastern part of the Guadalquivir basin it is estimated that resources can be found associated with shales and greywackes of the Culm de los Pedroches (within different units), associated with the Obejo-Valsequillo domain of the Central Iberian Zone, which would be under the discordant sequence of the sedimentary basin.

Within the Pedroches Unit, the Culm facies consists of alternating sandstones and shales that can be divided into several sections: basal section of very fine grained purple slates, with interbedded volcaniclastic materials; fine-grained green slates with interbedded carbonate; and sandstones filling submarine channels.

Inside the Guadalbarbo Unit, SW from the above, the Culm includes: very fine grained gray shales interbedded between basaltic lava flows and medium grained dark greywackes, which together indicate shallower conditions than the previous platform.

Further south, the Guadiato Unit contains, in the southernmost part, a detrital subunit of Culm facies formed by alternating conglomerates, shales and sandstones with calcareous levels and volcanic rocks and other subunit, further north, detrital- carbonated with black shales and sands with plant remains.

Depth and Thickness Unknown

Shale oil/gas properties Palynological studies have provided preliminary information about the state of maturation of the organic matter from thermal alteration index (TAI). Thus, in the three zones the TAI is between 6 and 7, equivalent to R0 2 to 4, indicating a range between semi-anthracite and anthracite, except a case where it would be 2/3 (0.3 to R0 0.4) corresponding to the lignite-subbituminous rank.

Chance of success component description

Occurrence of shale layer

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Mapping status Poor

Sedimentary Variability High Multiple subbasins with lateral and vertical facies changes

Structural complexity High

HC generation

Available data Poor

Proven source rock Possible Gas fields were found in the area and a potential oil shale was tested for oil yield

Maturity variability Unknown

Recoverability

Depth Shallow to Average Assumptions place the formations between 0 and 4300m depth

Mineral composition No data For most of the formations Poor In the case of the tested oil shale

References ACIEP, GESSAL (2013): Evaluación preliminar de los recursos prospectivos de hidrocarburos convencionales y no convencionales en España.

J.L. García-Lobón, C. Rey-Moral, C. Ayala, L.M. Martín-Parra, J. Matas, M.I. Reguera (2014) Regional structure of the southern segment of Central Iberian Zone (Spanish Variscan Belt) interpreted from potential field images and 2.5 D modelling of Alcudia gravity transect. Tectonophysics 614 (2014) 185–202.

IGME (1981). Estudio de las posibilidades de explotación de energía geotérmica en almacenes profundos de baja y media entalpía del territorio nacional.

IGME (1987). Contribucion de la exploracion petrolifera al conocimiento de la geología de España.

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T17 - Ebro

General information Screening- Index Basin Country Shale(s) Age Index

Carboniferous Carboniferous 1024 T17 Ebro E shales Armancies Fm Eocene 1025

Geographical extent The Tertiary Ebro Basin is, geographically, a triangular depression, framed by the Pyrenees to the north, the Iberian Range to the south and the Costero-Catalana chain to the east. At its western end it joins the Duero Basin along the corridor of the Bureba.

Figure 1 Location of the Spanish Basins. The coloured areas represent different basins.

Geological evolution and structural setting

Syndepositional setting The base of the Tertiary is located more than 3,000 meters below sea level in the Pyrenean mountain range and presents a trend of expansive overlap to the south, with the oldest materials covering the Pyrenees margin and the most modern the Iberian margin.

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Structural setting The Tertiary Ebro Basin is, geographically, a triangular depression, framed by the Pyrenees to the north, the Iberian Range to the south and the Costero-Catalana chain to the east. At its western end it joins the Duero Basin along the corridor of the Bureba. Represents the last evolution phase of the foreland southpyrenaic basin. Its actual structure and limits were formed during the Upper Oligocene and Lower Miocene when southpyrenaic frontal thrusts reached their final emplacement.

Organic-rich shales

Carboniferous The only Paleozoic outcrop is the Puig Moreno, located in the central area of the basin, near the border with the Iberian and Costero-Catalana chains. It consists of three Carboniferous outcrops under the Paleogene series, similar to the series of Montalban (Central Spain) and located to the NE of it. It covers an area of about 2 km2 and the sequence is dated to be of Lower Carboniferous and Namurian-Westphalian age. The stratigraphic sequence consists of sandstones, calcarenites, greywacke and quartzite levels. However, some authors have dated this outcrop as Stephanian and linked it to the Carboniferous of the Cantabrian Zone, so that the Carboniferous of Puig Moreno and the Montalban region (Central Spain) would not be time-equivalent.

Depth and Thickness The depth is estimated between 1650 and 4000m. Wells in a nearby area encountered Paleozoic sediments at depth between 1000 and 2000m.

Shale gas/oil properties Unknown

Chance of success component description

Occurrence of shale layer

Mapping status Poor

Sedimentary Variability High

Structural complexity High

HC generation

Available data Poor

Proven source rock Unknown

Maturity variability Unknown

Recoverability

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Depth Average Depth estimated between 1650 and 4000m

Mineral composition No data average mineral composition was not provided

Eocene Armancies Fm The Armancies Formation is an Eocene carbonate slope succession in the Catalonian South Pyrenean basin. It lowermost 200 m are made of a thin-bedded facies of wackestones alternating with dark pelagic fauna of miliolids, ostracods, bryozoans, and planktonic foraminifers and show significant bioturbation. The lime-mudstone beds show a massive structure or planar millimeter laminations. They may contain sparse pelagic fossils of planktonic foraminifers, ostracods, and dinoflagellates; they do not show any bioturbation.

Depth Thickness It ranges from 500 to 700 m in thickness. The prolific part is estimated to be 25 to 50m thick and situated at depth between 0 and 3800m.

Shale gas/oil properties The lower part of the formation shows a low organic content (< 0.5% TOC). The rest of the formation can reach individual TOC values of about 14%, hence this source rock qualifies as a typical oil shale. Rock-Eval Pyrolysis analysis offers a mean S2 value of 25 mg HC/g, and a mean S1 value around 1.0 mg HC/g. This is typical of an initial oil window. The T max maturity parameter ranges from 432 to 440°C (mean = 434°C). This degree of evolution is in accordance with the very low value of carbonyl and carboxyl groups, as determined by IR spectrometry and NMR on a Fischer assay extract. The proton NMR shows an aromatic/aliphatic hydrocarbon ratio of 1:4, as expected in earlier stages of catagenesis. N-alkane gas chromatography profiles show n-C 15 to n-C 19 prevalence and that neither even nor odd carbon numbers prevail. This distribution perfectly matches that of typical sediments of marine origin and also agrees with the obtained hydrogen index values (mean HI = 500 mg HC/g TOC). Sedimentological and geochemical results indicate an autochthonous marine organic matter and the potential of these slope shales is good oil-prone source beds.

The Terrades quarries are located in the most eastern part of the Cadí thrust sheet, in the shelf facies of the Armàncies Formation. Rock-Eval pyrolysis of the most shaly levels in the quarries yields S1 values up to 1.9 mg HC/g of rock, S2 up to 22.6 mg HC/g of rock, TOC up to 2.8% in weight and an average Tmax of 343°C. The extracts of the source rocks, and the oil shows associated with fractures, have saturated hydrocarbon fractions characterised by the dominance of C17-C22 n-alkanes with an even-carbon-number preference and pristane/phytane ratios b1. These molecular signatures reflect the anoxic, carbonate-depositing environment of the source rock.

Chance of success component description

Occurrence of shale layer

Mapping status Poor

Sedimentary Variability High

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Structural complexity Low

HC generation

Available data Moderate Detailed analyses on outcrop samples

Proven source rock Unknown

Maturity variability Unknown

Recoverability

Depth Shallow to Average Depth estimated between 0 and 3800m

Mineral composition No data average mineral composition was not provided

References ACIEP, GESSAL (2013): Evaluación preliminar de los recursos prospectivos de hidrocarburos convencionales y no convencionales en España.

IGME (1981). Estudio de las posibilidades de explotación de energía geotérmica en almacenes profundos de baja y media entalpía del territorio nacional.

IGME (2010). Selección y caracterización de áreas y estructuras geológicas susceptibles de constituir emplazamientos de almacenamiento geológico de CO2 (ALGECO2). Volumen II-1- Cadena Pirenaica y Cuenca del Ebro. Geología.

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T18 - Duero

General information Screening- Index Basin Country Shale(s) Age Index

T18 Duero E Duero shales Carboniferous 1023

Geographical extent The Duero Basin is located in the northwest quadrant of the Iberian Peninsula. It has traditionally been considered an intraplate basin with complex evolution which began at the end of the Cretaceous.

Figure 1 Location of the Spanish Basins. The coloured areas represent different basins.

Geological evolution and structural setting

Syndepositional setting The Mesozoic substrate of the basin includes deposits from the Triassic to Upper Cretaceous. It contains an accumulation of tertiary pre and syntectonic materials that reach 3,500m although most of the outcrops correspond to Tertiary postectonic deposits.

Structural setting Depending on the tecto-sedimentary features several sectors are distinguished: . North sector, which behaves as a foreland basin of the Cantabrian mountain range at least since the Eocene.

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. Eastern Sector, related in the same way with the Alpine evolution of the Iberian Range. . Western and south-western sector, which is characterized by horst and grabens tectonics with NE-SW faults and its conjugates, mainly during the Paleogene. . South Sector, which acted as a foreland basin of the Central System during the Oligocene-Miocene.

Organic-rich shales

Duero Carboniferous In the Duero basin there are no Paleozoic outcrops, however under the Mesozoic and Tertiary cover in the northern and eastern part of the basin, we can expect the continuation of the basement constituting the Paleozoic of the West Asturian-Leonese and Narcea Antiform.

The first is a series of Stephanian basins outcrops west of the Cantabrian Zone. The materials rest discordantly on a Cambrian, Ordovician and Silurian series. The most important outcrop of the area is in the Bierzo basin, although other smaller basins exist towards the NW (Tormaleo and San Antolín basins). The stratigraphic sequence in all of them is formed by quartzite conglomerates at the base followed by levels of shales and sandstones with carbonaceous levels. Ages are Stephanian B-C.

East of the abovementioned, in an innermost position with respect to the Asturian Arc, there is a series of Stephanian outcrops over the Precambrian (and Cambrian) of Narcea, similar to the above which could be of interest. The largest is the Villablino basin, with a 3,000 m thick series. The basal sedimentation is represented by breccias and polygenic conglomerates. Following these materials are cyclic sandstones, shales and coalbeds. The age of the set is Stephanian B-C. Other basins of interest are Tineo (800 m thick), Cangas del Narcea (200 m), Carballo (800 m), Rengos (1,500 m), La Magdalena (1,500 m).

Depth / Thickness The total thickness reaches 1,800 m, decreasing northward.

Shale gas/oil properties Unknown

Chance of success component description

Occurrence of shale layer

Mapping status Poor

Sedimentary Variability High

Structural complexity High Intraplate basin with complex Mesozoic and Cenozoic evolution

HC generation

Available data

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Moderate Some samples available from wells

Proven source rock Unknown

Maturity variability Unknown

Recoverability

Depth Average Assumptions place the formations between 1000 and 2500m.

Mineral composition No data average mineral composition was not provided

References ACIEP, GESSAL (2013): Evaluación preliminar de los recursos prospectivos de hidrocarburos convencionales y no convencionales en España.

IGME (1981). Estudio de las posibilidades de explotación de energía geotérmica en almacenes profundos de baja y media entalpía del territorio nacional.

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T19 – Iberian Chain

General information Screening- Index Basin Country Shale(s) Age Index

Sierra de la Demanda and Carboniferous 1022 T19 Iberian Chain E Aragonian Branch Lower Cretaceous Lower Cretaceous 1021 shales Cretaceous

Geographical extent The Iberian Chain (or Iberian System) and the Costero-Catalana Chain are two partially eroded alpine structures located east of the Iberian Peninsula. Both, form two tectonic units of similar age and style. This is a series of mountain ranges of NW-SE (Central Spain) and NE-SW (Cordillera Costero-Catalana) that link in its eastern and southern ends, through El Maestrazgo.

Figure 1 Location of the Spanish Basins. The coloured areas represent different basins.

Geological evolution and structural setting

Syndepositional setting The materials forming the Iberian System are mainly Mesozoic and Tertiary age, although locally outcropping Paleozoic base materials integrated in the Alpine folding.

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At the same time there are subsiding depressed areas in which, especially during the Early Cretaceous, thick layers of sediment, such as Cameros and Maestrazgo basins, were accumulated.

Structural setting Overall, the degree of deformation is moderate, with very little alpine foliation and a very low degree of metamorphism.

Organic-rich shales

Sierra de la Demanda This unit is located on the northern tip of the Iberian Range, and is formed by the mountains of La Demanda, Cameros, Urbión and Cebollera, in which the E-O guidelines predominate. The Sierra de la Demanda is essentially made up of Paleozoic materials. The succession of Stephanian-Westfalian age, is composed of two major groups: Lower set, consisting of an alternation of conglomerates, sandstones and shales with carbon levels and rich flora. Conglomerates are divided into three levels that are decreasing in thickness and grain size to top. Upper set of finely laminated sandstones and shales with abundant marine fauna, presenting to the top lenticular dolomitic levels. The total succession can be subdivided into five mega-sequences. Each megasequence comprises two terms: . A lower detrital term composed of conglomerates and coarse sandstones. . An upper term consisting of fine sandstones and shales, including carbonated lenses.

Depth/Thickness Unknown

Shale Gas/Oil properties Unknown

Aragonian Branch It is located SE of the structural unit Cameros - Demanda. It consists of the Moncayo, La Virgen, Victor, Algairén and Cucalón Sierras, forming a marked NW-SE direction. The tertiary basin of Calatayud is located within the Aragonian Branch. Paleozoic materials outcrop in the cores of the structures, and Mesozoic materials around them. The Paleozoic Montalbán Massif forms the core of an anticlinal structure of NW-SE direction. The Montalbán Massif is formed mostly by Carboniferous materials which lie unconformably on the Devonian. The Carboniferous is unconformably covered by Triassic materials and, locally, by a possibly Permian unit. In the Montalbán Massif the general succession is summarized in: . Sandstones, sandstone flysch, greywackes and slates, Namurian-Westphalian. . Sandstones, quartzites, limestone flysch, slates and greywackes, Namurian. . Ordovician shales and sandstones. The set of Lower Carboniferous terms corresponds to the sequence of Montalban, which is affected by intense diastrophism. The Carboniferous of the Sierra de la

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Demanda, which is posterior in age, has a net posttectonic character, so it is justified to think that it lies unconformably on Montalbán carboniferous sequences.

Depth/Thickness Unknown

Shale gas/oil properties Unknown

Chance of success component description

Occurrence of shale layer

Mapping status Poor

Sedimentary Variability Moderate

Structural complexity Moderate Very little alpine foliation and a very low degree of metamorphism

HC generation

Available data Poor

Proven source rock Unknown No effective petroleum system was found during exploratory acitivities

Maturity variability Unknown

Recoverability

Depth Shallow to Average Assumptions place the formations between 0 and 2500m depth.

Mineral composition No data average mineral composition was not provided

Iberian Lower Cretaceous There are several pre-extensional deposits that are potential source rocks, such as the Pozalmuro Fm (Callovian in age), a siliciclastic-carbonate platform sequence with black-shales deposits, and the Torrecilla and Aldealpozo Fms (Oxfordian and Kimmeridgian in age respectively), carbonate units formed in a shallow carbonate ramp environment. In the syn-extensional record the most of the depositional sequences contain dark carbonate and/or fine-grained deposits, which suggest potential source rocks for the basin. The largest and most abundant of these deposits are found in the DS3 (Valdeprado Fm, Berrasian in age), constituted by thinly laminated black-shales, deposited in coastal wetlands and shallow depositional environments. In the DS7 (Abejar Fm, Late Barremian and Early Aptian in age) dark-grey shale intervals appear

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interbedded with sandstone bodies, deposited in a fluvial-lacustrine system. In the same DS7 (Enciso Gr, Late Barremian and Early Aptian in age) dark shale-marlstone deposits interbedded with sandstone and limestone beds appear too generated in fluvio-lacustrine coastal wetland depositional systems. In the DS8 (Escucha Fm, Late Aptian-Early Albian) thin layers of shaly-coal and shales are interbedded with sandstones originated in a fluvial and coastal depositional environment.

Depth/Thickness Unknown

Shale Gas/Oil properties For these deposits the original type of kerogen is inferred from interpretation of the depositional environment: Type II for the Jurassic marine deposits, Type I for the DS3 deposits and Type III-Type I for the DS7 deposits. In the northern and central sectors of the basin rocks attained over-mature to dry-gas thermal conditions, whereas rocks in the southern sector and in the footwall of the thrust only reached the immature to early oil-window thermal condition. In the southern sector of the Cameros Basin they are characterized by abundant organic matter remnants (TOC from 2 to 17%) and immature to early oil-window thermal conditions (0.38-0.75% Ro), indicating a high hydrocarbon potential for these rocks (S2 from 11 to 123 mg HC/g and HI values from 23 to 715 mg HC/g TOC), whereas in the central and northern sectors only residual kerogen composed of vitrinite, inertinite and solid bitumen particles is observed.

Chance of success component description

Occurrence of shale layer

Mapping status Poor

Sedimentary Variability High Deposited in coastal wetlands and shallow depositional environments

Structural complexity Moderate Very little alpine foliation and a very low degree of metamorphism

HC generation

Available data Moderate

Proven source rock Unknown No effective petroleum system was found during exploratory acitivities

Maturity variability High Immature to overmature in different parts of the basin

Recoverability

Depth Shallow Assumptions place the formation between 0 and 1000m depth.

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Mineral composition No data average mineral composition was not provided

References ACIEP, GESSAL (2013): Evaluación preliminar de los recursos prospectivos de hidrocarburos convencionales y no convencionales en España.

Ramos, A., Sopeña, A., Sanchez-Moya, Y. and Muñoz, A. (1996). Subsidence analysis, maturity modelling and hydrocarbon generation of the Alpine sedimentary sequence in the NW of the Iberian Ranges (Central Spain). Cuadernos de Geología Iberica, num. 21, pp. 23-53. Servicio de Publicaciones. Universidad Complutense, Madrid, 1996. http://revistas.ucm.es/index.php/CGIB/article/view/CGIB9696220023A

IGME (1981). Estudio de las posibilidades de explotación de energía geotérmica en almacenes profundos de baja y media entalpía del territorio nacional.

IGME (2010). Selección y caracterización de áreas y estructuras geológicas susceptibles de constituir emplazamientos de almacenamiento geológico de CO2 (ALGECO2). Volumen III-1- Cadena Ibérica y Cuencas del Tajo y Almazán. Geología.

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T20 – Catalonian Chain

General information Screening- Index Basin Country Shale(s) Age Index

Catalonian T20 E Catalonia shales Carboniferous 1020 Chain

Geographical extent It is a narrow belt of mountains, linked in origin to the Iberian Range, which is divided into three main units: Litoral Chain, Prelitoral Depression and Prelitoral Chain (East to West).

Figure 1 Location of the Spanish Basins. The coloured areas represent different basins.

Geological evolution and structural setting

Syndepositional setting The Northern half of the basin consists mainly of granites and metamorphic rocks of the Paleozoic, while the southern half consists of predomantly Mesozoic outcrops.

Structural setting It is a narrow belt of mountains that closes the Ebro basin in the in the Pyrenaic Foreland, which is divided into three main units: Litoral Chain, Prelitoral Depression and Prelitoral Chain (E to W). It is linked in origin to the Iberian Range.

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Organic-rich shales

Catalonian chain Carboniferous In the southern sector of the Catalan Coastal Chain the Carboniferous occupies a considerable extent, all around the Prades mountains and the Priorat. The basal part is formed by a level of lidites with phosphatic nodules, 10 to 20 m thick and probably Tournaisian in age. Above the lidites a carbonate horizon can be found formed by limestones commonly dolomitized or recrystallized or green and purple shales with thin layers of limestone. Above is a thick succession with the typical Culm facies (=flysch), typical of the Hercynian syntectonic series. This series is best represented in The Priorat. It consists essentially of shales, sandstones, conglomerates and several limestone horizons intercalated in the lower half of the series. Age would be Namurian-Westphalian, which match the ages assigned to the Montalbán Massif in the Iberian Chain.

Depth/Thickness Up to 2000 meters thick

Shale gas/oil properties In the Carboniferous of the Priorat area, the conodontal elements extracted from the carbonate levels of the base of the Culm series have CAl values of 6.5; 7; 7,5 and 8, which would indicate a possible over-maturation of organic matter.

Chance of success component description

Occurrence of shale layer

Mapping status Poor

Sedimentary Variability High

Structural complexity High

HC generation

Available data Poor

Proven source rock Unknown

Maturity variability Unknown

Recoverability

Depth Shallow to Average Estimated depth between 0 and 2000m.

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Mineral composition No data average mineral composition was not provided

References ACIEP, GESSAL (2013): Evaluación preliminar de los recursos prospectivos de hidrocarburos convencionales y no convencionales en España.

San Leon Energy web page http://www.sanleonenergy.com/operations-and- assets/spain-cantabarian-ebro.aspx

IGME (1981). Estudio de las posibilidades de explotación de energía geotérmica en almacenes profundos de baja y media entalpía del territorio nacional.

IGME (2010). Selección y caracterización de áreas y estructuras geológicas susceptibles de constituir emplazamientos de almacenamiento geológico de CO2 (ALGECO2). Volumen III-1- Cadena Ibérica y Cuencas del Tajo y Almazán. Geología.

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T21 - Pyrenees

General information Screening- Index Basin Country Shale(s) Age Index

Lower Jurassic Liassic shale 1033 (Liassic) T21 Pyrenees E Cabo Fm. Lower Cretaceous 1034 Burgui Fm. and Eocene 1035 Vallfogona Fm.

Geographical extent The Pyrenean range stretches from the Gulf of León in the Mediterranean to the Bay of Biscay in the Atlantic. The eastern boundary of the South-Pyrenean slope is the Mediterranean Sea, the western boundary is represented by the structural alignment formed by the Basque-Cantabrian basin. To the south it borders the Rioja-Ebro Basin and at the eastern end with the Catalonian Chain.

Figure 1 Location of the Spanish Basins. The coloured areas represent different basins.

Geological evolution and structural setting

Syndepositional setting The South-Pyrenean Basin is part of the Pyrenean range where Precambrian to Cenozoic materials outcrop.

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Structural setting It is a structurally complex area, with a number of south verging sheets from the Alpine orogeny between the axial part of the Pyrenees in the North and the thrust over the Ebro Basin in the South. Structurally it is characterized by double verging tectonics.

Organic-rich shales

Pyrenees Liassic The study area is located in the so-called Central South-Pyrenaic Unit which is made up, from South to North, of the marginal ranges of the Montsec and Bòixols thrust sheets, formed by cover materials (Mesozoic and Paleogene). The Jurassic sequence has two differentiated sections with possible interest due to kerogen contents, the lower is located at the Lias base, immediately over sandy and silty sediments with breccia levels (so-called ferruginous lower Lias breccia). The other section is a laminated black marl of Upper-Middle Liassic age, possibly Toarcian.

Depth / Thickness The thickness of the section with kerogenic calcschists does not exceed 7 m.

Shale gas/oil properties Some levels have locally 85 and 115 L/t of kerogen.

Chance of success component description (1033)

Occurrence of shale layer

Mapping status Poor

Sedimentary Variability Moderate

Structural complexity High On the marginal ranges of the Montsec and Bòixols thrust sheets

HC generation

Available data Poor

Proven source rock Unknown Hydrocarbon generation possible from samples of the formation

Maturity variability Unknown

Recoverability

Depth Average Estimated depth between 2000 and 4300m.

Mineral composition

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No data

Lower Cretaceous Cabo Fm. The lower Cretaceous Cabo Fm is part of the Central South-Pyrenaic Unit, which is composed (from south to north) of the Bòixols thrust sheet. The sequence comprises a series of interbedded limestones and marlstones ranging from the late Barremian to the early Aptian. It is formed by intermittent dark limestone and marlstone layers associated with extremely low diversity and scarce benthic fauna, a low bioturbation index (0–3) and a high TOC (up to 1.7 wt %). This indicates recurrent oxygen- deficient conditions within the lowest 31 m of the section and more uniform oxygenation in the upper 54 m. EDS analyses confirmed the presence of clastics (mainly aluminum silicates) in the matrix.

Depth / Thickness Thickness is unknown

Shale gas/oil properties The TOC values of this Formation range between 0.5-1.74%.

Chance of success component description (1034)

Occurrence of shale layer

Mapping status Poor

Sedimentary Variability Moderate

Structural complexity Moderate Located in the Bòixols thrust sheets

HC generation

Available data Poor

Proven source rock Unknown

Maturity variability Unknown

Recoverability

Depth Shallow to Average Estimated depth between 200 and 2200m.

Mineral composition Favourable X-ray diffraction (XRD) results conclude a 30% average non-carbonate bulk mineral content in the sediment, this is interpreted to represent evidence for a sustained terrestrial flux as the source of nutrients in the basin. The non-carbonate fraction is dominated by quartz (average, 14%) whereas the clay mineral assemblages are characterized by high

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illite content (>73 relative %) with minor concentrations of kaolinite (<5%), illite/smectite mixed layers (<17%) and chlorite (<15%).

Eocene Western Zone Burgui Fm. The Jaca Basin occupies the eastern sector of the major Jaca-Pamplona basin, an east-west elongated basin located within the Gavernie structural unit of the western Pyrenees. It is flanked by the Exteriores range to the south, the upper Cretaceous- Paleocene carbonate platform to the north, the Boltaña anticline to the east and the Navarra diapiric lineation to the west, delimiting an area of 150 x 45 km. The Jaca Basin formed during the early pyrenean convergent phase, when the initial thrusting increased subsidence and produced a dramatic paleogeographic change: the shallow marine Mesozoic and early Tertiary environment of the Jaca high evolved into deep-water conditions during Cuisian times. Since then, this syn-tectonic sedimentary trough experienced a complex depositional and tectonic history until sedimentary infill and tectonic activity halt during Miocene times.

The Burgui marl and limestone has been recognized as the source rock for the Serrablo field. Other authors have previously postulated the existence of deeper source rocks in the Upper Cretaceous or Triassic intervals. The Burgui marl and limestone comprises hemipelagic slope facies deposited during the early tectonic phases on the backlimbs and troughs of the early Eocene ramps. Its sedimentation is controlled by its structural position. There is a facies between the carbonate facies (Guara Fm.) accumulated at the highs of the frontal ramps and the marly facies (Burgui Fm.). Consequently, there is strong structural control on the location and extent of the source rock, which youngs to the south as a consequence of the progradation of the thrust front.

Depth / Thickness Thickness around 300m

Shale gas/oil properties Limited geochemical studies were conducted on samples from several wells indicating that the Eocene sediments present low organic matter content with average TOC values between 0.1 to 0.4% (maximum 0.57%). The organic matter consists of inertite and woody material and locally herbaceous and algae material has been described. The maturity level of the Eocene section has been determined by spore coloration and vitrinite reflectance methods.

The Eocene flysch is generally immature. Only the lowermost flysch section is mature. This lower flysch comprises argillaceous limestone interbedded with marls. In some wells, a few metres in thickness, dark shales interval has been encountered.

It is a thick section (300 m) of Ypresian hemipelagic shale, kerogen type III with TOC below 0.6% and Ro (%) between 1.0 and 1.3 values. This poor source rock quality is compensated by its significant thickness.

Eocene Eastern Zone Vallfogona Fm. The area is located in the Cadí thrust sheet, which is made up of very thick Lower- Middle Eocene and Paleocene sediments.

The Vallfogona Fm is composed of deep water marine sediments deposited by high density gravity currents. The shales are dominant in the lower part, occasionally

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alternating with sandstones characterized by Bouma sequences. In the upper part, slumps are predominant and turbiditic facies are more proximal.

Depth / Thickness Thickness up to 900m

Shale gas/oil properties Organic analysis and petrographic observations allow us to distinguish two types of samples (A and B) in accordance with their organic characteristics. In type A samples, the Rock-Eval pyrolysis shows Hydrogen Index (HI) values from 236 to 365, Total Organic Carbon (TOC) from 0.83 to 0.99%, Tmax from 437 to 439°C, and S2 from 1.91 to 18.42 mg HC/g rock. Type B samples have HI values from 287 to 390, TOC from 0.64 to 1.09%, Tmax from 433 to 439°C, and S2 from 1.84 to 4.25 mg HC/g rock. The recognizable organic elements in both types are mainly constituted by filamentous algae, occurring as continuous lamina with yellow fluorescence, dinoflagellates, and resinite. Vitrinite is only present in minor amounts in type B samples. The organo-mineral matrix could present framboidal and disperse pyrite and, in type A samples, the presence of dolomite crystals is frequent.

Chance of success component description (1035)

Occurrence of shale layer

Mapping status Poor

Sedimentary Variability Moderate

Structural complexity Low Deposited in synclines associated with thrust faults

HC generation

Available data Moderate

Proven source rock Unknown

Maturity variability Low Measurements show a maturity in the early oil window (0.5-0.7% Ro)

Recoverability

Depth Shallow to Average Estimated depth between 0 and 4500m.

Mineral composition No data average mineral composition was not provided

References ACIEP, GESSAL (2013): Evaluación preliminar de los recursos prospectivos de hidrocarburos convencionales y no convencionales en España.

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Caja, M. A. and. Permanyer, A. (2008) Significance of organic matter in Eocene turbidite sediments (SE Pyrenees, Spain). Naturwissenschaften (2008) 95:1073–1077. https://www.researchgate.net/publication/5234748_Significance_of_organic_matter_i n_Eocene_turbidite_sediments_SE_Pyrenees_Spain

San Leon Energy web page http://www.sanleonenergy.com/operations-and- assets/spain-cantabarian-ebro.aspx

IGME (1981). Estudio de las posibilidades de explotación de energía geotérmica en almacenes profundos de baja y media entalpía del territorio nacional.

IGME (2010). Selección y caracterización de áreas y estructuras geológicas susceptibles de constituir emplazamientos de almacenamiento geológico de CO2 (ALGECO2). Volumen II-1- Cadena Pirenaica y Cuenca del Ebro. Geología.

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T25 - Northwest European Basin (Central Europe) – Mesozoic shales

General information Screening- Index Basin Country Shale(s) Age Index Northwest European T25a NL Posidonia Shale Toarcian 1065 L. Jurassic Posidonien Schiefer Toarcian 2012* Northwest Wealden Tithonian-Berriasian n/a* T25c German D Basin Blättertone/Fischschiefer Barremian/Aptian n/a* Mid Rhaetian shale Rhaetian n/a* Kimmeridgian-Tithonian Kimmeridge Clay 1070 (Late Jurassic) Weald Mid Lias Clay Pliensbachian 1074 T25d Basin SE UK Oxford Clay Oxfordian 1075 England Upper Lias Clay Early Toarcian 1076 Corallian Clay Oxfordian 1078

*The description of the German potential shale oil and gas formations is based on the detailed report of Ladage et al. (2016). As Germany is not participating in this study, no additional ranking of the German formations is performed.

The descriptions of the shales from the UK Weald Basin are from the UK assessment published by Andrews (2014).

Geographical extent The Jurassic in Northwest Europe is characterised by several prolific source rocks. They were deposited in a shallow epicontinental basin extending from west to east from eastern UK onshore to Poland and north to south from offshore southern Norway to Germany (Figures 1 and 2).

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Figure 1 Location of the Mesozoic shale formations in the Northwest European Basin. The coloured areas represent different basins.

Figure 2 Distribution area of Lower Jurassic source rocks (Lott et al., 2010).

Geological evolution and structural setting

Syndepositional During the Lower Jurassic rising sea levels and local tectonic subsidence caused flooding from the Tethys area and establishment of an open, shallow marine epicontinental sea extending from eastern UK onshore to Poland and from Germany to

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southern Norway. In most of the area the Lower Jurassic is characterised by open marine, fine grained mudstone sedimentation. Close to the bounding Fennoscandian and East European Platform, sedimentation is coarse-grained fluviodeltaic and nonmarine. Ongoing transgression during the Toarcian caused a link to the Boreal Sea in the North. This coincides with the deposition of the wide spread organic rich Posidonia Shale Formation (Posidonien Schiefer in Germany, Upper Lias Clay in the UK). However, conditions throughout the Lower Jurassic allowed for the deposition of shales, locally enriched in organic matter (e.g., Mid Lias Clay).

During the Middle Jurassic uplift of the Mid North Sea Dome and the Highs/Platforms surrounding the basin caused severe erosion and the change of sedimentation to prograding fluviodeltaic complexes. The connection ot the Boreal Sea was lost and no significant organic rich shales were deposited in the area.

During the Late Jurassic, another sea level rise and the collapse of the Mid North Sea Dome reopened the connection to the Boreal Sea. Local deposition of organic rich shales resumed in the UK area while deposition in the Netherlands was dominated by fluviodeltaic or lacustrine sandstones with occasional coal layers. The area of Germany was controlled by the connection to the Tethys Ocean and is characterised by fine- grained carbonates. During the latest Jurassic fully marine conditions returned in the northwest of the basin with the deposition of the very prolific Kimmeridge Clay Formation in the UK on- and offshore and the northern Dutch Central Graben (Lott et al., 2010).

Structuration Deposition of the Jurassic in the Northwest European Basin was controlled by the ongoing opening of the North Atlantic rift system and the realigning of the extension from east-west oriented extension, causing accelerated subsidence in north-south oriented grabens, to large scale thermal uplift of the Mid North Sea Dome and widespread erosion of Lower Jurassic sediments across the area. During the Late Jurassic crustal extension across the North sea rift system caused the development of north-west trending transtentional basins in the southern part of the area, again causing severe erosion on the basin flanks.

During the Mid-Cretaceous the North Sea rift system became inactive and the area experienced regional thermal subsidence. During the Late Cretaceous the onset of the closure of the Tethys Ocean resulted in compressional stresses that culminated in the inverse reactivation of the faults controlling the Mesozoic basins. The compressional movements lasted until the Paleocene and caused severe erosion in the basins along the southern margin of the basin complex and uplift of the surrounding highs. During the Neogene the offshore area was part of the North Sea sag basin while the surrounding areas were further uplifted, causing the Jurassic to partly outcrop at the surface (Pharaoh et al., 2010).

In the centre of the basin the Jurassic is strongly influenced by salt tectonics.

Organic-rich shales

Mid-Rhaetian Shales The Mid-Rhaetian Shales were deposited as a localised basin facies within the Northwest German Basin. They consist of grey to dark grey pyritic claystones with several organic rich intercalated layers.

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Depth and Thickness The thickness varies between a few meters on structural highs to more than 100m in the area of Bremen and is on average about 40m thick. The intercalated bituminous layers have an individual thickness of a few meters. In the center of the Northwest German Basin, the Rhaetian shales are buried to depth of several kilometres while they outcrop in the south of the basin.

Shale oil/Gas properties Analyses show an average TOC of 4% and maturities ranging from oil to gas mature.

Mid Lias Shales The Mid Lias Shales are represented by a fairly uniform shale lithology (confirmed by its uniform geophysical log responses) with some of the highest gamma-log responses of the entire Lias, and have been dated as Pliensbachian in age. The lower part is assigned an early Pliensbachian age on company composite logs; so strictly speaking the unit spans the uppermost Lower and lowest Middle Lias.

Depth and Thickness In the subsurface of the Weald Basin, there is a 100-375 ft-thick (30-110 m) shale between the Lower Lias Limestone-Shales unit and the Middle Lias Limestone. This unit is thickest in the Lockerley 1 well, but in the Wealden depocentre it is 125-300 ft (40-90 m) thick. It is situated at depth between 500 and 2500m.

Shale oil/Gas properties This unit contains 9-37% organic-rich shale in the ‘core mature area’ as defined by Andrews (2014). In that area, total organic carbon contents of up to 2.07% have been recorded in Baxters Copse 1. Based on all available geochemical data, the average TOC for the Mid Lias Clay samples is 1.2%, with 8 of the 94 analyses recording TOC >=2%. In the ‘core mature area’, the average TOC is 1.1% and average S1 is 0.88 mgHC/gRock. The highest TOC values are 3.95% in Shrewton 1 and 5.94% in Marchwood 1. These wells are both in the west of the study area, where the unit is immature. Two samples have an oil saturation index greater than 100 after applying an evaporative correction of 2.42; both are in East Worldham 1. In this study, the Mid Lias Clay is mature for oil generation in the ‘core mature area’, with a maximum net mature organic-rich shale thickness of 62 ft (19 m). Nowhere has the Mid Lias Clay been buried sufficiently deeply to have entered the gas window as modelled in this study.

Chance of success component description Occurrence of shale

Mapping status Good seismic interpretation, interpolated map (many datapoints)

Sedimentary variability Low very homogeneous character throughout the basin

Structural complexity Moderate layer faulted, locally eroded, subsidence, uplift and salt tectonics

HC generation

Available data

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Good good database (>20)

Proven source rock Possible HC shows and accumulation in other setting probably from same SR

Maturity variability Moderate basin wide trends related to present or past burial depth variations

Recoverability

Depth Shallow to average < 1000-5000m

Mineral composition No data

Posidonia Shale Formation/Posidonienschiefer/Upper Lias Clay Posidonia Shale of Toarcian age is a very distinctive interval throughout Northwest Europe, with a present-day distribution from U.K. (Jet Rock Member in the Cleveland Basin and Upper Lias Clay in the Weald Basin) to Germany (Posidonienschiefer, or Ölschiefer). Given the uniform character and thickness (mostly around 30-60 m of dark-grey to brownish-black, bituminous, fissile claystones) across these basins, it is commonly suggested that the Posidonia Shale was probably deposited over a large area during a period of high sea level and restricted sea-floor circulation. Its present- day distribution is due to erosion on the basin margins and bounding highs (Pletsch et al., 2010, Van Bergen et al. 2013, Zijp et al. 2015a).

The Posidonia Shale Formation in the Netherlands developed conformably on the non- bituminous claystones of the Lower Jurassic Aalburg Fm. although locally bituminous sections in the Aalburg Fm. are known (De Jager et al., 1996). The formation consists of dark-grey to brownish-black bituminous fissile claystones and is a very distinctive interval throughout the Netherlands which can be recognized on wire-line logs by its high gamma ray and resistivity readings (Van Adrichem Boogaert and Kouwe, 1993- 1997).

In the Weald Basin argillaceous lithologies again dominate in the Upper Lias Clay. In these wells, shales and siltstones form the lower half of a further liming-upwards or coarsening upwards log motif, but elsewhere they are replaced entirely by siltstones and sandstones.

Depth and Thickness In the Netherlands the Posidonia Shale Formation can be found at depths ranging from 1800-3800 m depth. The Formation is between 30 and 60 m thick and is identified as a bituminous dark-grey to brown black fissile claystone (Verreussel et al. 2013, van Bergen et al. 2013, Zijp et al. 2013). In the Northwest German Basin the Posidonienschiefer is situated at depth between 1000 and 2500m. In relation with salt tectonics its depth can vary strongly over short distances. It is on average 20m thick. In the Weald Basin the Upper Lias Clay is typically 50-220 ft thick (15-70 m), but reaches a thickness of 290 ft (90 m) further west at Furzedown 1. It is situated at depth between 500 and 2500m (Heege et al. 2015).

Shale oil/gas properties Source rock characterization indicates an overall Type II kerogen, with an average TOC content of about 5-7% (can be up to 14%) and average HI values of 550 mg/g

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TOC. HI values can be higher than 1000 mg/g for immature samples. Biomarker analyses indicate marine organic matter (Pletsch et al., 2010).

Maturity of the formation is strongly linked to the basin history of the sub-basins. It ranges from immature to gas mature. In the West Netherlands Basin measured maturity decreases from residing in the oil window in the west to immature in the east, corresponding with the occurrences of oil fields in the west that are lacking in the east. However, the measurements are performed on samples from wells that were preferably drilled on structural highs, showing lower maturities as could be expected from surrounding lower areas. Basin modelling indicates small areas that are expected to be gas mature. The maturity of the Posidonienschiefer in the Northwest German Basin decreases northwards. It is in gas mature along the southern margin of the basin and oil mature further north, according to published and unpublished data (Wehner et al. 1988, Binot et al. 1993, BGR internal data).

In the Weald Basin, the Upper Lias Clay organic rich layers can reach 15-28% of the total formation in the ‘core mature area’. Based on all available geochemical data, the average TOC for the Upper Lias samples is 1.6%, with 6 of the 28 analyses recording TOC >=2%. There are four recorded TOCs greater than 5% in Shrewton 1 and two in East Wordham 1 (maximum 6.0%). Two samples have an oil saturation index greater than 100 after applying an evaporative correction of 2.42; both are in East Worldham 1.

In the basin centre, where the unit lies within the oil window, the average TOC is 1.45% and the average S1 is 1.07 mgHC/gRock. In this ‘core mature area’, the net thickness of mature organic-rich shale reaches 112 ft (34 m). Nowhere has the Upper Lias been buried sufficiently deeply to have entered the gas window as modelled in this study (Andrews, 2014).

Chance of success component description

Occurrence of shale layer

Mapping status Good Within the Netherlands, Germany and the UK the Posidonia Shale is well documented, visible on seismic and drilled by a large number of wells.

Sedimentary variability Low Within the subsurface of the Netherlands the facies variability of the Posidonia Shale is low. There are some differences within the Dutch subsurface, although the formation can be recognized throughout. Outcrop studies in the Yorkshire coast of England of the time equivalent Jet Rock member show similar features. The sedimentary variability of the Upper Lias Clay in the Weald Basin is not known.

Structural complexity Moderate Within the whole area substantial faulting followed by inversion has caused compartmentalisation of the formation. Because of this the depth of the formation can change dramatically over short distances (10-15 km). In addition salt tectonics has locally influenced the depth and distribution of the formation.

HC system

Available data

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Good

Proven source rock Proven The Lower Jurassic shales of Northwest Europe are within the oil to gas maturity window, and have sourced many oil and gas fields. UK Possible

Maturity variability Moderate The variations in maturity in the basin are mainly related to differences in past and present burial depth. The shales are found from immature to overmature within the basin.

Recoverability

Depth Shallow to Average <1000-5000m

Mineral composition Poor very clay rich (>50% clay content) UK Unknown (clay content between 33 and 63% in TOC rich intervals Andrews, 2014)

Oxford Clay and Corallian Clay During Oxfordian times, tectonic activity was characterised by regional flexural subsidence, with little or no syndepositional faulting (except in the uppermost Corallian [Sequence 4] in Dorset, Newell 2000). The lithologies and hence the geophysical log responses of the Oxford Clay vary across the Weald Basin. In the extreme east of the study area, the gamma-log response is uniform. Elsewhere, there is a tripartite division, with a lower-gamma, carbonate-rich unit between two shales.

The presence of sandstones and limestones differentiates the Corallian Group from the Oxford Clay, but the intervening shales, which are frequently thick, are most similar to those of the overlying Kimmeridge Clay. Typically, the Corallian Clay has a higher gamma-log response than the Oxford Clay, alluding to the fact that it may be more organic-rich. In the west, the term Ampthill Clay is often used on composite logs for this unit.

In the Weald Basin, the Corallian Group contains coral-dominated patch reefs and oolitic shoals, developed locally along the northern basin margins (Sun & Wright 1989, Sun et al. 1992) and stormdominated offshore sandstones (Sun 1992), separated by mudstones deposited on an offshore shelf. These limestones and sandstones form the reservoirs of several conventional oil and gas fields in the Weald Basin.

Depth and Thickness The Oxford Clay reaches a maximum thickness of 590 ft (180 m) in Shrewton 1 in the extreme west of the study area. Elsewhere, it is commonly 200-500 ft (60-150 m) thick in the central part of the Weald, thinning towards the London Platform to the north and also towards the east, south and south-west.

The Corallian Clay reaches a maximum thickness of 263 ft (80 m) in Rogate 1 and thins in all directions away from this depocentre. Across most of the Weald Basin, thicknesses of 50-250 ft (15-75 m) are commonplace.

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The exact depth of the formations is not known, however, they are situated between the Kimmeridge Clay Formation and the Mid Lias Clay and therefore assumend to be between 0 to 500m minimum and 1200 and 2500m maximum.

Shale oil/Gas properties The Oxford Clay samples have a relatively low average TOC (1.4%), but an increased number of samples have TOC >= 2%. Of the 156 samples of Oxford Clay analysed, 34 recorded TOC >=2% (Andrews, 2014).

The higher TOC samples all originate from the poorly-sampled, lower 50-100 ft (15- 30 m) of the unit, which has a distinctive low-velocity (high interval transit time), but only slightly elevated gamma-log response. The remainder of the Oxford Clay is organically lean. The average log-derived TOC for the whole Oxford Clay is 2.8%. This method also confirms that the lower Oxford Clay is an organic-rich unit, with a maximum TOC of 7.8%. This lower unit deserves further investigation as a potential ‘sweet-spot’ for shale exploration.

Rock-Eval S1 data for the formation reach 2.6 mgHC/gRock in the organic-rich lower unit in East Worldham 1, but is generally less than half this figure. Even in this very limited dataset, it is significant that applying an evaporative correction of 2.42 to these three S1 values and dividing by their respective TOC (2.7-6%), gives an oil saturation index of 101, 109 & 126 (above the 100 required for producible oil sensu Jarvie 2012).

Type II kerogen predominates in the lower Oxford Clay, with mainly Type III kerogen in the upper part (Penn et al. 1987, England 2010).

Several publications state that the Oxford Clay is within the oil window in at least part of the Weald Basin (Lamb 1983, Ebukanson & Kinghorn 1986, Penn et al. 1987, McLimans & Videtich 1989, Butler & Pullan 1990). Using a maximum burial depth of 7,000 ft (2,130 m) prior to uplift, Andrews (2014) maps an area across which at least the base of the Oxford Clay is mature (Ro > 0.6%).

Although not one of the traditionally recognised source rocks in the Weald, high TOCs have also been recorded in the shales of the Corallian Group. The average TOC from all available Corallian analyses is 1.1%, with 8 of the 91 analyses recording TOC >=2%. The highest value is 5.4% in Egbury 1. The Passey TOC average is 3.8%, with a maximum of 5.4%. This higher average value may reflect the poor sampling rate of the 91 geochemical analyses.

According to Andrews (2014) the Corallian Clay is partly within the oil window.

Chance of success component description Occurrence of shale

Mapping status Moderate depth map, thickness map based on interpolation/average values (few datapoints)

Sedimentary variability Moderate depositional environment changes gradually throughout the basin

Structural complexity Moderate layer faulted, locally eroded, subsidence, uplift and salt tectonics

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HC generation

Available data Good good database (>20)

Proven source rock Unknown no information

Maturity variability Moderate basin wide trends related to present or past burial depth variations

Recoverability

Depth Shallow to Average <1000-5000m

Mineral composition Unknown Clay content between 33 and 63% in TOC rich intervals (Andrews, 2014)

Kimmeridge Clay Formation In the Kimmeridge Clay Formation argillaceous rocks are dominant, with some being organic-rich, although there is a paucity of ‘hot shales’ with high gamma-log peaks in the Weald area. This difference is highlighted by comparison with the well-studied Swanworth Quarry and Metherhills boreholes in Dorset (Tyson et al. 2004) and the absence of the Kimmeridge oil shale or Blackstone Bed in the Weald Basin.

Depth and Thickness The thickness of the Kimmeridge Clay follows the pattern of the underlying Corallian Clay, with over 1,800 ft (550 m) deposited in the centre of the basin, thinning radially. The thickest well penetration is 1,864 ft (568 m) in Balcombe 1. The depth of the top of the Formation is between 0 and 1200m.

Shale oil/Gas properties The Kimmeridge Clay samples from the Weald Basin wells again show lower TOC values (average TOC = 2.8%) than equivalent strata in Dorset (average TOC = 3.8%), but there remains a large proportion of the samples with TOC> 2%. The log-derived average TOC for the Weald Basin is 3.8%, with a maximum of 21.3%.

Log-derived average TOC for the Weald Basin is 3.8%, with a maximum of 21.3% in the middle Kimmeridge Clay, between and immediately below the so called mid- Kimmeridgian micrites. This part of the succession deserves further investigation as a potential ‘sweet-spot’ for shale exploration and as part of a hybrid Bakken-type shale play in association with the adjacent micrites.

Rock-Eval S1 data for the formation reach 7.9 mgHC/gRock in Bolney 1, but is generally considerably less than this figure. Applying an evaporative correction of 2.42 to the S1 values and dividing by their respective TOC, gives a wide range of oil saturation index values from 5 to 358; five sample have a OSI above the 100 required for producible oil sensu Jarvie (2012).

Type II kerogen predominates in the basin-centre Kimmeridge Clay, with varying amounts of terrestrially derived Type III also present, but especially closer to the

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basin margins (Scotchman 1991). Over shelf areas, mixed Type II-Type III kerogens are prevalent.

Publications suggest a wide range of maturity for the Kimmeridge Clay Formation e.g., immature on the basin margins and only mature for oil generation in a small area in the basin centre (Gallois 1979, Lamb 1983, Ebukanson & Kinghorn 1986, Penn et al. 1987, McLimans & Videtich 1989, Butler & Pullan 1990, Burwood et al. 1991), immature across all of both the Weald and Wessex basins (Hawkes et al. 1998), or maturity levels >1.0% Ro in the centre of the Weald Basin (Williams 1986). This wide range of opinions can be explained by the poor correlation of vitrinite reflectance to maturity.

Andrews (2014) proposes a maturity model where the Kimmeridge Clay close to the micrites in this well is likely to have a maturity of Ro = 0.57-0.67%. This suggests that at least the base of the Kimmeridge Clay is mature across the central part of the Weald Basin. The upper part, which is more organic-rich, has a smaller prospective area due to a combination of shallower maximum burial depth and shallower current- day depth after uplift; the latter factor is particularly important in the eastern part of the area.

Chance of success component description

Occurrence of shale

Mapping status Good seismic interpretation, interpolated map (many datapoints)

Sedimentary variability Low very homogeneous character throughout the basin

Structural complexity Moderate layer faulted, locally eroded, subsidence, uplift and salt tectonics

HC generation

Available data Good good database (>20)

Proven source rock Possible Oil found within the mid-Kimmeridge I-micrite in Balcombe 1 may provide evidence for both maturity and the capacity of the Kimmeridge Clay to generate oil, at least locally.

Maturity variability Moderate Low maturity in general, due to thickness of the formation, some maturity variation with depth at one location

Recoverability

Depth Shallow mainly <1000m

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Mineral composition Unknown to Poor Clay contents of the Kimmeridge Clay are generally greater than 20%, and can reach 65% (Cox & Gallois 1981, Morgan-Bell et al. 2001). The average of all Kimmeridge Clay samples had a TOC of 0.6-12% and a total clay content of 6-59% (Andrews, 2014). Just the organic-rich shales (TOC of 2-12%) had a clay content of 33-53%.

Wealden Clay Formation The Wealden Formation was deposited in a widespread closed lake setting located in northern Germany. In the basin centre, located between the Emsland and the Mittelweser dark grey, organic rich claystones were deposited.

Depth and Thickness At the surface north of the Wiehengebirge and the Teutoburger Wald, further north at depth between 100 and 1700m. In the centre of the basin the total thickness of the Wealden Formation can reach up to 700m, the organic rich intervals are assumed to be between 30 and 220m thick.

Shale oil/Gas properties The organic-rich intervals of the Wealden Formation were deposited in a lacustrine (Type I) facies. Average TOC values of 3.3 % were measured with minimum and maximum values of 1.1% and 14.4% respectively. According to published maturity maps and measurements the formation can locally reach oil and gas maturity.

Blättertone/Fischschiefer The Lower Cretaceous Blättertone were deposited in a shallow marine sea with a lot of separated sub basins that extended from the Emsland to the Polish border. Up to 30 thin organic rich intervals are locally intercalated in the marly succession. They are mainly located in local salt rim synclines.

Depth and Thickness The individual organic rich intervals are thin, the thickest interval is the final layer called “Fischschiefer” with up to 10m. A combined total thickness of 20 to 50m is assumed for all organic rich intervals. Along the southern margin of the basin they are situated at the surface, dipping towards the centre of the basin in the north where they can be at depth of up to 2600m.

Shale oil/Gas properties The Blättertone have an average TOC of 4.9% and can locally reach up to 12%. They are considered to be thermally immature and have reached oil maturity only very locally.

References

Van Adrichem Boogaert, H. A., and W. F. P. Kouwe, 1993– 1997, Stratigraphic nomenclature of the Netherlands, revision and update by RGD and NOGEPA: Haarlem, Mededelingen Rijks Geologische Dienst, 50 p.

Andrews, I.J. 2014. The Jurassic shales of the Weald Basin: geology and shale oil and shale gas resource estimation. British Geological Survey for Department of Energy and Climate Change, London, UK.

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Bouw, S. and Lutgert, J. [2012] Shale Plays in The Netherlands. SPE/EAGE European Unconventional Resources Conference and Exhibition, SPE 152644.

Burwood, R., Staffurth, J., de Walque, L. & De Witte, S.M. 1991. Petroleum geochemistry of the Weald-Wessex Basin of southern England: a problem in source-oil correlation. In: Manning, D. (ed.) Organic Geochemistry: advances and applications in energy and the natural environment. Extended abstracts. 15th meeting of the European Association of Organic Geochemists. Manchester University Press, Manchester, 22-27.

Butler, M. & Pullan, C.P. 1990. Tertiary structures and hydrocarbon entrapment in the Weald Basin of southern England. In: Hardman, R.F.P. & Brooks, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publication 55: 371-391.

Cox, B.M. & Gallois, R.W. 1981. The stratigraphy of the Kimmeridge Clay of the Dorset type area and its correlation with some other Kimmeridgian sequences. Report of the Institute of Geological Sciences 80/4.

Ebukanson, E.J. & Kinghorn, R.R.F. 1986. Maturity of organic matter in the Jurassic of southern England and its relation to burial history of the sediments. Journal of Petroleum Geology 9(3): 259-280.

England, M.L. 2010. Oil generation, migration and biodegradation in the Wessex Basin (Dorset, UK). Ph.D. Thesis, University of Newcastle-upon-Tyne.

Gallois, R.W. 1979. Oil shale resources in Great Britain. Report by Institute of Geological Sciences commissioned by the Department of Energy. Includes nine appendices.

Hawkes, P.W., Fraser, A.J. & Einchcomb, C.C.G. 1998. The tectono-stratigraphic development and exploration history of the Weald and Wessex basins, Southern England, UK. In: Underhill, J.R. (ed.) Development, Evolution and Petroleum Geology of the Wessex Basin. Geological Society Special Publication 133: 39-66.

Heege, J. ter, Zijp, M., Nelskamp, S., Douma, L., Verreussel, R., Veen, J. ten, Bruin, G. de, Peters, R. 2015. Sweetspot identification in underexplored shales using multidisciplinary reservoir characterization and key performance indicators: Example of the Posidonia Shale Formation in the Netherlands. Journal of Natural Gas Science and Engineering 27, 558-577.

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Jager, J., M. A. de, Doyle, P. J., Grantham, and J. E. Mabillard, 1996, Hydrocarbon habitat of the West Netherlands Basin, in H. E. Rondeel, D. A. J. Batjes and W. H. Nieuwenhuis, eds., Geology of gas and oil under the Netherlands: Dordrecht, Kluwer, p. 191–209.

Jarvie, D.M., 2012. Shale resource systems for oil and gas: Part 2—Shale-oil resource systems. In: Breyer, J.A. (ed.). Shale reservoirs—Giant resources for the 21st century. American Association of Petroleum Geologists Memoir 97: 89-119.

Ladage, S. et al. (2016) Schieferöl und Schiefergas in Deutschland – Potentiale und Umweltaspekte. Bundesanstalt für Geowissenschaften und Rohstoffe (BGR), Hannover. (http://www.bgr.bund.de/DE/Themen/Energie/Downloads/Abschlussbericht_13MB_Sc hieferoelgaspotenzial_Deutschland_2016.html)

Lamb, R.C. 1983. Hydrocarbon prospectivity of the Weald and eastern English Channel. Volume 5: source rock potential and maturity. IGS Deep Geology Unit report to Department of Energy 83/3/5.

Lott, G.K., Wong, T.E., Dusar, M., Andsbjerg, J., Mönnig, E., Feldman- Olszewska, A. & Verreussel, R.M.C.H., 2010. Jurassic. In: Doornenbal, J.C. and Stevenson, A.G. (Eds) Petroleum Geological Atlas of the Southern Permian Basin Area. EAGE Publications (Houten), 175–193.

McLimans, R.K. & Videtich. P.E. 1989. Diagenesis and burial history of Great Oolite Limestone, southern England. American Association of Petroleum Geologists Bulletin 73: 1195-1205.

Morgans-Bell, H.S., Coe, A.L., Hesselbo, S.P., Jenkyns, H.C., Weedon, G.P., Marshall, J.E.A., Tyson, R.V. & Williams, C. J. 2001. Integrated stratigraphy of the Kimmeridge Clay Formation (Upper Jurassic) based on exposures and boreholes in south Dorset, UK. Geological Magazine 138(5): 511–539.

Newell, A.J. 2000. Fault activity and sedimentation in marine rift basin (Upper Jurassic, Wessex Basin, UK). Journal of the Geological Society, London 157: 83-92.

Penn, I.E., Chadwick, R.A., Holloway, S., Roberts, G., Pharaoh, T.C., Allsop, J.M., Hulbert, A.G. & Burns, I.M. 1987. Principal features of the hydrocarbon prospectivity of the Wessex-Channel Basin, UK. In: Brooks, J. & Glennie, K.W. (eds) Petroleum Geology of Northwest Europe. Graham & Trotman, London. Pp 109-118.

Pharaoh, T.C., Dusar, M., Geluk, M.C., Kockel, F., Krawczyk, C.M., Krzywiec, P., Scheck-Wenderoth, M., Thybo, H., Vejbæk, O.V. & Van Wees, J.D., 2010. Tectonic evolution. In: Doornenbal, J.C. and Stevenson, A.G. (editors): Petroleum Geological Atlas of the Southern Permian Basin Area. EAGE Publications b.v. (Houten): 25-57.

Röhl, H.-J., Schmid-Röhl, A., Oschmann, W., Frimmel, A., Schwark, L., 2001. The Posidonia Shale (Lower Toarcian) of SW-Germany: an oxygen-depleted ecosystem controlled by sea level and palaeoclimate. Palaeogeography, Palaeoclimatology, Palaeoecology, 165, 27-52.

Scotchman, I.C. 1991. Kerogen facies and maturity of the Kimmeridge Clay Formation in southern and eastern England. Marine and Petroleum Geology 8: 278-295.

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Sun, S.Q. 1992. A storm-dominated offshore sandstone interval from the Corallian Group (upper Jurassic), Weald Basin, southern England. Marine and Petroleum Geology 9: 274-286.

Sun, S.Q. & Wright, V. 1989. Peloidal fabrics in Upper Jurassic reefal limestones, Weald Basin, southern England. Sedimentary Geology 65: 165-181.

Sun, S.Q., Fallick, A.E. & Williams, B.P.J. 1992. Influence of original fabric on subsequent porosity evolution: an example from the Corallian (Upper Jurassic) reefal limestones, the Weald Basin, southern England. Sedimentary Geology 79: 139-160.

Tyson, R.V. 2004. Variation in marine total organic carbon through the type Kimmeridge Clay Formation (Late Jurassic), Dorset, UK. Journal of the Geological Society, London 161: 667–673. Data available at http://kimmeridge.earth.ox.ac.uk/database

Verreussel, R.M.C.H., Zijp, M.H.A.A., S. Nelskamp, L. Wasch, G. de Bruin, J. ter Heege and J. ten Veen. 2013. Pay-zone identification workflow for shale gas in the Posidonia Shale Formation, the Netherlands, First Break Volume 31, February 2013

Williams, P.F.V. 1986. Petroleum geochemistry of the Kimmeridge Clay of onshore southern and eastern England. Marine and Petroleum Geology 3(4): 258-281.

Zijp, M.H.A.A. Nelskamp, S.N., Schavemaker, Y.A., ten Veen, J.H., ter Heege, J.H. [2013] Multidisciplinary Approach for Detailed Characterization of Shale Gas Reservoirs, a Netherlands Showcase. Offshore Technology Conference, Brasil, OTC- 2483-MS

Zijp, M.H.A.A., ten Veen J., Verreussel, R., ter Heege, J., Ventra, D., Martin, J. [2015a] Shale gas formation research: from well logs to outcrop - and back again. First Break Volume 33, February 2015

Zijp, M.H.A.A., Nelskamp, S., Verreussel, R., ter Heege, J. [2015b] The Geverik Member of the Carboniferous Epen Formation, Shale Gas Potential in Western Europe, IPTC-18410-MS

Zijp, M.H.A.A., ter Heege, J. [2014] Shale gas in the Netherlands: current state of play. International Shale Gas & Oil Journal, Volume 2, Issue 1, February 2014

Zijp, M., ten Veen, J., Ventra, D., Verreussel, R., van Laerhoven, L., Boxem, T. [2014] New Insights From Jurassic Shale Characterization: Strenghten Subsurface Data With Outcrop Analogues

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T26 – Paris Basin and Autun Basin – Permo- Carboniferous and Jurassic shales

General information Screening- Index Basin Country Shale(s) Age Index Promicroceras Late Pliensbachian 1082 Paris T26a F Amaltheus Sinemurian 1083 Basin Schistes Carton Toarcian 1084 Autun T26b F Autun Permian 1081 Basin

Geographical extent The Paris Basin covers the northern half of France and is with approximately 110000 km2 the largest onshore basin in France (Figure 1). It is surrounded by four massifs, the Armorican Massif in the west, the Massif Central in the south, the Vosges in the east and the Ardennes in the northeast.

Figure 1 Location of the Paris Basin and the potential shale gas/oil formations within. The colored areas represent different basins.

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Geological evolution and structural setting

Syndepositional setting During the Carboniferous and Permian sedimentation occurred in several separate troughs. During the Early Jurassic the Paris Basin was part of the shallow epicontinental sea on the margin of the Tethys. Deposition of organic rich shales and carbonates is mainly controlled by sea level fluctuations, the establishment of a connection to the Tethys, basin subsidence rates and water oxygenation. During the Lower Jurassic several transgressive/regressive cycles can be identified that can be linked to the deposition of the organic rich shales of the Paris Basin (Bruneau et al. 2017).

Structural setting The Paris Basin is a Mesozoic basin superimposed on Carboniferous and Permian troughs and Paleozoic basement. In the centre of the basin the Mesozoic and Cenozoic sediments are up to 3000m thick. Along the basin margins the Carboniferous and Permian troughs have been uplifted to the surface.

Subsidence initiated during the Permo-Triassic extensional phase and subsidence rates were highest during the Triassic and Lower Jurassic. During the Late Jurassic to Early Cretaceous tectonic compression caused uplift and erosion of the basin margins. During the Latest Cretaceous to Eocene the Alpine and Pyrenean orogeny caused severe compression accociated with inversion of pre-existing faults and again erosion on the basin margins.

Organic-rich shales

The Promicroceras Shales Fm The Promicroceras shale source rocks consist of blue-grey illitic shales. The reference well Couy-1bis crossed all the Lower Jurassic black shale formations and is now a standard for establishing the sequence stratigraphy framework of the Jurassic (Védrine and Lasseur, 2011).

Depth and Thickness No isopach map is available for the specific interval of the Promicroceras Shales Fm. The Lotharingian Isopach map shows thicknesses between 0 and 50m.

Shale oil/gas properties The TOC content ranges from 0.2-0.9 wt% (Bessereau and Guillocheau, 1994).

Chance of success component description Occurrence of shale

Mapping status Moderate depth map, thickness map based on interpolation/average values (few datapoints)

Sedimentary variability Low very homogeneous character throughout the basin

Structural complexity Moderate layer faulted, locally eroded, subsidence, uplift and salt tectonics

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HC generation

Available data Moderate few data points (< 20)

Proven source rock Unknown no information

Maturity variability Moderate basin wide trends related to present or past burial depth variations

Recoverability

Depth Shallow to Average <1000m – 5000m

Mineral composition No data average mineral composition was not provided

The Amaltheus Shale Fm The Amaltheus Formation shale source rocks comprise grey, silty, and micaceous illitic shales.

Depth and Thickness The isopach map published by Vedrine & Lasseur (2011) for the Carixian-Domerian deposits showing values between 0 and 200m, albeit not matching exactly the Amaltheus Shales interval, is the closest approximation.

Shale oil/gas properties TOC ranges from 2-4 wt% with a maximum HI value of 130 mg HC/g TOC (Bessereau and Guillocheau, 1994).

Chance of success component description Occurrence of shale

Mapping status Moderate depth map, thickness map based on interpolation/average values (few datapoints)

Sedimentary variability Low very homogeneous character throughout the basin

Structural complexity Moderate layer faulted, locally eroded, subsidence, uplift and salt tectonics

HC generation

Available data Moderate few data points (< 20)

Proven source rock Unknown no information

Maturity variability

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Moderate basin wide trends related to present or past burial depth variations

Recoverability

Depth Shallow to Average <1000-5000m

Mineral composition No data average mineral composition was not provided

The ‘Schistes Carton’ Fm The Schistes Carton Fm, also known as “Lias Marneux” in the SE of France was deposited during the Toarcian across a large area encompassing several European basins. They are the local equivalent of the Posidonia Shale Formation of the Netherlands.

Depth and Thickness Thickness of 0m along the basin margins and up to 55m in the basin centre.

Shale oil/gas properties The Schistes Carton Formation is actually the most extended and most organic rich of the Jurassic black shales formations, with an average TOC around 4-5% (Espitalié, 1987). It is to some extent comparable to the Bakken shales of the U.S. (Monticone et al., 2012). The OM is a type II kerogen (marine bacterial and algal) with an Hydrogen Index (HI) values ranging from 500 to 750 mg HC/g TOC (Delmas et al., 2002). The oil window of the Schistes Cartons has been traced from the compilation of T max values. The source rock in the Schistes Carton Fm is thought to have maturated in the deepest area, at depths of 2600-2700m, during Maastrichian times and ongoing (Espitalié et al.1987).

Chance of success component description

Occurrence of shale

Mapping status Moderate depth map, thickness map based on interpolation/average values (few datapoints)

Sedimentary variability Low very homogeneous character throughout the basin

Structural complexity Moderate layer faulted, locally eroded, subsidence, uplift and salt tectonics

HC generation

Available data Good good database (>20)

Proven source rock Proven HC fields in study area proven to be sourced from shale gas layer

Maturity variability Moderate basin wide trends related to present or past burial depth variations

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Recoverability

Depth Shallow to Average <1000-5000m

Mineral composition No data average mineral composition was not provided

Autun The Autunian series comprises the Lower Autunian, including an “autuno-stephanian” interval (the Autunian is not sedimentologically distinct from the Stephanian), and the Upper Autunian.

Depth and Thickness The Autunian series is more than 1000m thick.

Shale oil/gas properties The lacustrine deposits are organic rich, with oil shales and bogheads. The various oil shales intervals were investigated and the potential estimated (Marteau et al., 1982). The petroleum potential ranges from 70 to 100 kg/t and is twice that of the Schistes Cartons.

Chance of success component description

Occurrence of shale

Mapping status Poor

Sedimentary variability High fluvio-lacustrine setting

Structural complexity High

HC generation

Available data Poor

Proven source rock Unknown

Maturity variability Unknown

Recoverability

Depth Shallow < 1000m

Mineral composition No data average mineral composition was not provided

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References Bruneau, B., Chauveau, B., Baudin, F., Moretti, I. (2017) 3D stratigraphic forward numerical modelling approach for prediction of organic-rich deposits and their heterogeneities. Marine and Petroleum Geology 82, 1-20.

Marteau P., Bourrat M., Chateauneuf J.J., Clozier L., Farjanel G., Feys, R., Valentin J. (1982) les schistes bitumineux du bassin d’Autun, Etude géologique et estimation des réserves. BRGM report 82 SGN 484 GEO, 86 p.

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T27 - Aquitaine

General information Screening- Index Basin Country Shale(s) Age Index

Sainte Suzanne Aptian T27 Aquitaine F 1085 Marls (Cretaceous)

Geographical extent The Aquitaine Basin is the second largest basin of France (66 000 km²).

Figure 1 Location of the Aquitaine Basin southern France. For the formations in these basins no outlines were available.

Geological evolution and structural setting

Syndepositional setting The Sainte Suzanne Marls Fm were deposited in a HST setting of a 3rd order sequence. These black shales deposited into losangic contiguous pull apart basins.

Structural setting The Aquitaine Basin is a polyphased basin, which initiated during the Triassic and evolved according to both Tethyan and Atlantic riftings as a passive margin with classical pre-syn and post- rift successions till the Late Cretaceous. Since then, the Iberia microplate motion has caused a tectonic inversion and has finally led to collision with the Eurasian plate, giving birth to the Pyrenean orogenic belt during the

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Paleogene. In response to that collision, the Aquitaine Basin evolved as a retroforeland basin with a classical underfill/overfill megasequence throughout the Cenozoic. For its long and complex evolution, the triangular-shaped Aquitaine Basin can be divided into a northern part which did not undergo much deformation and middle and southern parts which are a complex puzzle of sub-basins under the Cenozoic molassic cover, with some places that cumulated up to 11 km of deposits.

Organic-rich shales The ‘Sainte Suzanne Marls’ Fm The Sainte-Suzanne Marls Fm is also known as the Deshayesites Marls Fm. It is made of homogenous marine, organic-rich shales with occurrence of bioclastic marly limestones.

Depth and Thickness No extensive mapping has been done, however, the formation can reach a thickness of several hundreds of meters.

Shale oil/gas properties The Sainte Suzanne Marls formation has a mean TOC of 1-2%. The OM is of type II origin, but the formation only crossed into the oil window in the southern parts of the basin (Serrano et al., 2006). Up to now the Sainte-Suzanne marls have been considered mainly as caprock for petroleum and gas systems rather than a potential source and were not extensively studied with an exploration perspective.

Chance of success component description

Occurrence of shale layer

Mapping status Poor No outlines provided

Sedimentary Variability Low

Structural complexity Low and High Depending on the position in the basin.

HC generation

Available data Poor

Proven source rock Unknown

Maturity variability Unknown

Recoverability

Depth Unknown

Mineral composition

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No data average mineral composition was not provided

References Serrano O., Delmas J., Hanot F., Vially R., Herbin Jp., Huel P., Tourliere B. (2006) – Le Bassin d’Aquitaine : valorisation des données sismiques, cartographie structurale et potentiel pétrolier. Ed. BRGM, 245 p., 142 figures, 17 tableaux, 17 annexes

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T28 - South Eastern basin

General information Screening- Index Basin Country Shale(s) Age Index

South Eastern Schistes Cartons T28a F Jurassic 1084 basin Fm Stephano- Permo- Permo- T28b F 1080 Permian Basin Carboniferous Carboniferous

Geographical extent The South-East Basin is the third most extended basin of France. It is triangular shaped, with the rhodanian corridor as the main axis, from the Burgundy High and the Bresse Graben (North) to the Provence and Camargue domains (South).

Figure 1 Location of the South Eastern Basin and the underlying Stephano Permian Basin in southern France. For the formations in these basins no outlines were available.

Geological evolution and structural setting

Syndepositional setting The Permo-carboniferous shales deposited in a continental to paralic setting, including bogheads, in a late orogenic (post-variscan) extensional setting, creating numerous small grabens.

The Schistes cartons deposited in a deep, open plateform environment, conected to the opening Tethys Ocean (cf. Paris Basin)

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Structural setting The South-East basin is a polyphased basin, which initiated during the Triassic and evolved according to the Tethyan rifting as a passive margin with classical pre-syn and post- rift successions till the Late Cretaceous, including the ‘Vocontian Trough’ episode. Since then, the closure of the Tethys Ocean caused a tectonic inversion which eventually led to collision with the African and Apulian plates from the Late Paleogene to Present times (Alpine orogeny). In response to that collision, the South-East Basin evolved as a foreland basin with a classical underfill/overfill megasequence from the Eocene. The Massif Central acted as a rigid block during the collision, limiting the westward extension of the foreland basin. Finally, during the late Neogene, the Messinian crisis played a significant role in the sedimentary infill with development of large and deep canyons and karstic networks. For its long and polyphased evolution, the South-East Basin is highly complex, with numerous blocks and sub-basins together with thick (up to 11 km) but highly variable sedimentary succession (Debrand-Passart et al., 1984a, 1984b).

Organic-rich shales

Permo-Carboniferous The Stephanian stratotype comes from Saint-Etienne city, famous for its coal resources which have been mined for more than 150 years. In the South-East Basin, several Stephanian and Permian basins are identified along Hercynian structures.

Depth and Thickness Thickness and depth are highly variable and specific for each subbasin. In general the thickness of the Permo-Carboniferous succession is 10 to 1300m and the average depth varies between 300 and 4500m.

Shale oil/gas properties Not much public data regarding thickness or TOC content is available from these scattered basins. The high subsidence permitted the accumulation of very thick terrestrial series but with frequent lateral changes. Coal seams vary greatly because lenticular shaped, but the organic deposits can represent up to 10% of the Stephanian series in the Blanzy Basin. In the Lonsle-Saunier Basin, only known from drilling survey, the coal seams represent only 5% of the 600 m thick Stephanian series. All the Carboniferous basins comprise several coal seams or bituminous shales. Conversely, only some of the Permian basins are organic rich (boghead and bituminous shales) such as the Blanzy-Creuzot Basin and the Causses Basin for which no TOC/isopach data is available. Available TOC measurements vary between 0.02% to more than 20% between the different formations and basins. Maturity according to Rock-Eval analyses ranges from immature to gas mature and the type of organic matter ranges from Type III coal for the Carboniferous formations to Type I for the Autunian.

Chance of success component description

Occurrence of shale layer

Mapping status Poor

Sedimentary Variability High Assessment area includes multiple formations with highly variable sedimentary setting.

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Structural complexity High Area consists of multiple small sub basins with different tectonic histories.

HC generation

Available data Poor

Proven source rock Unknown

Maturity variability High

Recoverability

Depth Unknown

Mineral composition No data average mineral composition was not provided

Schistes Carton Formation Lateral equivalent to the Schistes Carton of the Paris Basin.

Depth and Thickness The Toarcian deposits are thicker in the Southern part of the South-East Basin (south of Lyon), with up to 500 m. In the northern part, the Schistes Cartons Fm is absent (except in Franche-Comté, NE) because of the regional condensed sedimentation around the Lyon High. Conversely, the Schistes Cartons Fm is well developed in the southern part, despite synsedimentary tectonics at some places (Causses Basin). Finally, the Subalpine domain recorded a proximal-distal sequence from the south (Nice, Castellane) to the North (Mont Blanc) but with condensed or absence of the Schistes Carton Fm.

Shale oil/gas properties The South-East Basin lacks precise and dedicated studies for unconventional resources.

Chance of success component description

Occurrence of shale layer

Mapping status Poor

Sedimentary Variability High Assessment area includes multiple formations with highly variable sedimentary setting.

Structural complexity

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High Area consists of multiple small sub basins with different tectonic histories.

HC generation

Available data Poor

Proven source rock Possible The Schistes Carton are a proven source rock in the Paris Basin and other Basins in Europe.

Maturity variability High

Recoverability

Depth Unknown

Mineral composition No data average mineral composition was not provided

References Debrand-Passart S., Courboulaix S., Lienhardt M.-J. (1984) Synthèse géologique du Sud-Est de la France. Vol1 : Stratigraphie et paléogéographie. Mém. BRGM Fr. Vo n°125, 617p.

Debrand-Passart S., Courboulaix S., Lienhardt M.-J. (1984) Synthèse géologique du Sud-Est de la France. Vol2 : Atlas. Mém. BRGM Fr. Vo n°126, 158 p.

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T30 – Lusitanian Basin, Portugal

General information Screening- Index Basin Country Shale(s) Age Index

T30 Lusitanian Basin P Jurassic shales Lias 1087

Geographical extent The Lusitanian Basin, located on and off west-central Portugal, is one of the major sedimentary onshore and offshore basin of Portugal which contains formations with potential for conventional and unconventional resources. It is limited on the east by the Iberian Meseta and extends from south of Lisbon north to about Porto. It extends for about 250 km north-south in west-central Portugal and 100 km east-west.

Figure 1 Location of the Lusitanian Basin in Portugal. The coloured areas represent different basins.

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Geological evolution and structural setting

Syndepositional setting The stratigraphy and sedimentology of Lusitanian Basin is well established (e.g., Azeredo et al., 2003; Carvalho et al., 2005; Duarte et al., 2004; Kullberg et al., 2013; Leinfelder and Wilson, 1989; Rasmussen et al., 1998; Rey et al.,2006; Wilson et al., 1989; Wilson, 1979, 1988).

The Lower Jurassic sedimentary record is particularly well represented in Lusitanian Basin Massif and corresponds to a thick carbonate succession, comprising up to 550 m of mostly marl-limestone alternations, characterizing much of the upper Sinemurian– Toarcian series of the basin (Soares et al., 1993; Duarte and Soares, 2002; Duarte et al., 2004, Duarte et al., 2010). These facies, comprising abundant nektonic and benthic macrofauna, are included in the Upper Triassic–Callovian 1st-order cycle (Wilson et al., 1989; Soares et al., 1993; Duarte, 1997; Azerêdo et al., 2002, 2003; Duarte et al., 2004) and are associated with a palaeogeography controlled by an epicontinental sea, sustained by a low-gradient carbonate ramp dipping towards the northwest (Duarte, 1997, 2007; Duarte et al., 2004). In this geological context, the upper Sinemurian– Pliensbachian interval is characterized by the occurrence of organic-rich facies regarded as a potential oil sourcerock (Oliveira et al., 2006).

The Sinemurian-Pliensbachian series show important changes in the depositional system (Duarte et al., 2010), from lower-upper Sinemurian peritidal facies (Coimbra Formation (Fm); Azerêdo et al., 2008) to Pliensbachian hemipelagic deposits (including the Vale das Fontes and Lemede formations; Duarte and Soares, 2002).

However, in the western sectors of the basin, such as Peniche, S. Pedro de Moel, Figueira da Foz and Montemor-o-Velho, hemipelagic deposition started earlier during the late Sinemurian (Oxynotum-Raricostatum zones; Água de Madeiros Fm.; Duarte and Soares, 2002; Duarte et al., 2004, 2006). All these units are characterized by different marl/limestone relations, organic matter content and specific benthic/nektonic macrofauna and microfauna

Structural setting The onshore basin represents the proximal element of a much larger Mesozoic- Cenozoic basin system which extends offshore into the Porto and Galicia Basins to the north and the Peniche Basin to the west.

The Lusitanian Basin is an Atlantic margin rift basin formed in the Mesozoic (e.g., Rasmussen et al., 1998) located on the occidental margin of the Iberian Massif with approximately 5 km thick of sediments. According to several authors (e.g. Azerêdo et al., 2003; Rasmussen et al.,1998; Wilson et al.,1989) this basin is related to the opening of the North Atlantic Ocean and is filled with sediments from the Upper Triassic to the Cretaceous covered with Cenozoic sediments but Upper Jurassic sediments being the thicker portion of it.

Lusitanian Basin is limited to the East by the Porto-Tomar fault and a complex set of NNW–SSE faults, and to the West by the Berlenga horst, a tectonic high that was emerged during almost all the basinal history. The evolution of the Lusitanian Basin is linked to four Late Triassic–Early Cretaceous rift phases that produced a high compartmentalization of the basin (Alves et al., 2002; Kullberg, 2000; Kullberg et al., 2006; Rasmussen et al., 1998). The syn-rift sedimentary evolution and tectonic style of the basin during extension and posterior inversion was controlled also by other important factor being the presence of a mid-level décollement in the syn-rift deposits

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(Alves et al., 2002; Kullberg et al., 2006; Rasmussen et al., 1998; Soto et al., 2012). The uppermost Triassic–Hettangian evaporates (Dagorda Formation) constitute this décollement that is present in almost all the basin and can reach 1000 to 1500 m thick in the deepest areas of the basin.

Four rift phases have been recognized in the Lusitanian Basin (Alves et al. 2002; Kullberg 2000; Kullberg et al., 2006; Rasmussen et al., 1998; Stapel et al., 1996).

. Rift 1 (Triassic–Hettangian) the beginning of the continental rifting is characterized by sedimentation in grabens and half-grabens as demonstrated by strong thickness changes (Stapel et al., 1996) and the geometry observed from offshore seismic profiles (Rasmussen et al., 1998). This tectonic style was strongly conditioned by the previous Variscan structures (Ribeiro et al., 1990; Wilson et al., 1989). Sedimentation during this rift phase comprises the continental–fluvial detrital deposits of the base units of the Silves Group (Conraria and Penela Fm.; in Soares et al., 2012) and the supratidal sabhka evaporites of Dagorda Fm. . Rift 2 (Sinemurian–Late Oxfordian). It comprises carbonate units deposited over a westward-tilted ramp (Coimbra, Brenha/Candeeiros, Cabaços and Montejunto Formations). This thick sequence (>1500 m) was controlled by N–S faults and is principally located in the central part of the basin, South of the Nazaré fault. The principal faults responsible for the subsidence were oriented N–S, but also for the first time in the basin history, other faults oriented ENE–WSW to E–W controlled facies distribution and thickness changes. . Rift 3 (Kimmeridgian–Early Berriasian). Distinct sub-basins were individualized and filled with mixed continental-marine deposits showing a complex facies pattern (Abadia/Alcobaça and Lourinhã Formations), dominated by siliciclastic influxes into the basin. The petrology of proximal members indicates that the Variscan basement was exposed during the Early Kimmeridgian (Leinfelder and Wilson, 1989). As in the previous Rift 2, the stretching episode is more pronounced to the South of the Nazaré fault than to the North (Stapel et al., 1996) being the depocentre of the basin oriented N–S to NNE–SSW (Wilson, 1988). . Rift 4 (Late Berriasian–latest Aptian). The Torres Vedras Group deposited during this rift phase exhibits simple facies geometry, with largely fluvial siliciclastic sands and conglomerates interfingering with shallow water carbonates. The rift initiation is marked by a regional unconformity characterized both by an angular unconformity over tilted half-grabens below and a clear change in lithology with conglomerates succeeded by progradation of a clastic wedge. That regional unconformity is probably due to thermal uplift induced by lithospheric stretching during the final rifting phase that generally precedes crustal separation (Ziegler, 1992).

Organic-rich shales Água de Madeiros Formation This unit, resting over the inner-shelf Coimbra Fm., has been subdivided into two members: the Polvoeira Member (Mb.) at the base, and the Praia da Pedra Lisa Mb.at the top. The base of Polvoeira Mb. consists of marl-limestone alternations that become progressively more argillaceous, presenting several organicrich facies horizons. The middle-upper part of this member is a rhythmic succession with marl/limestone ratios around 1.5 to 2. Limestones generally correspond to fossiliferous wackestones that are sometimes rich in ostracods, molluscs and organic matter.

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Depth and Thickness Where its type-sections is defined (S. Pedro de Moel) (Duarte and Soares, 2002; Duarte et al., 2004b, 2006), the thickness of this member is approximately 42 m, decreasing to 10 m in Peniche and Montemor-o-Velho.

Vale das Fontes Formation The Pliensbachian Vale das Fontes Fm., ranging in age from the lowermost Jamesoni to the uppermost Margaritatus zone interval, represents the return to a marly sedimentation, widespread across the whole basin. It is particularly well exposed in the western part of the basin and is subdivided into three informal members:

Marls and limestones with Uptonia and Pentacrinus Mb.- This unit is characterized by bioturbated decimetre marl/centimetre-thick marly limestone alternations. Across the basin, an increase is observed in the marly character from the proximal to the distal sectors.

Lumpy marls and limestones Mb. - This unit is defined by the occurrence of lumpy facies (Hallam, 1971; Dromart and Elmi, 1986; Elmi et al., 1988; Fernández-López et al., 2000), interbedded in a marl-limestone succession. The lumps have a microbial origin and consist of micritic grumose concretions, generally subspherical-shaped and reaching several centimetres in size. Interbedded in these facies, metricscale grey to dark marls occur. This unit ranges from the Jamesoni to the Luridum subzone interval.

Marly limestones with organicrich facies Mb. -This unit is characterized by an increase of the marly terms of the serie, alternating with centimetrethick limestone facies. In the distal regions, such as the Peniche, S. Pedro de Moel and Figueira da Foz sectors, organic-rich sediments are particularly abundant. This member comprises the Luridum Subzone (topmost of Ibex Zone) to the uppermost Margaritatus Zone interval.

Depth and Thickness The Vale das Fontes Formation is approximately 75-90 m thick in the western part of the basin.

Lemede Formation This unit, from Upper Pliensbachian, generally comprises centimetre marl/decimeter limestone bioturbated alternations. In the southeastern part of the LB, such as Tomar, facies are much more bioclastic (packstone to grainstone) and locally dolomitic. This unit ranges in age from the Spinatum Zone to the lowermost part of Polymorphum Zone.

Depth and Thickness It reaches a thickness of approximately 30 m in the northwest of the basin

Shale oil/gas properties 23 shallow wells were drilled (160 m average depth, one well 451 m deep) to collect cuttings and conventional cores in the Lias section over a wide geographic area. The main conclusions are discussed in McWhorter et al., 2014. Porosity (from shallow wells) ranges from 0.2 to 19.8% over a total thickness of up to 400 m (average 200 m). The Lower Jurassic is characterized throughout the basin by a TOC average range of 2.3 to 5.9%, Ro values of 0.5 to 1.8%, and quartz-carbonate content of 63.8 to 83.7%. Organic matter in the Lower Jurassic is dominantly kerogen type II in the prospective middle of the basin, with drilling depths of 1000 to 3500 m, where Tmax

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mapping also shows the thermal maturity necessary for oil and gas generation (greater than 450 degrees in the prospective areas).

Additional information, such as oil and gas shows in old wells throughout the basin, oil seeps at the surface, and live oil in shallow Lias cores verify a viable resource interval.

Chance of success component description

Occurrence of shale layer

Mapping status Poor Only the outlines of the basin are available.

Sedimentary Variability Moderate The whole succession is made up out of multiple formations with different distributions within the basin.

Structural complexity Moderate

HC generation

Available data Moderate In an exploration study 23 shallow wells were drilled and samples were analysed.

Proven source rock Possible Oil and gas shows were encountered in old wells

Maturity variability Moderate Maturity varies between immature and gas mature

Recoverability

Depth Average In the subsurface mostly at depths of 1-3.5 km.

Mineral composition Unknown to Favourable Mineralogical analyses show a quartz-carbonate content of 63.8 to 83.7%

References Alves, T.M., Gawthorpe, R.L., Hunt, D.W., Monteiro, J.H., 2002. Jurassic tectonosedimentary evolution of the Northern Lusitanian Basin (offshore Portugal). Marine and Petroleum Geology 19, 727–754.

Azerêdo, A.C., Duarte, L. V., Henriques, M H., Manuppella, G., 2003. Da dinâmica continental no Triásico aos mares do Jurássico Inferior e Médio. Cadernos de Geologia de Portugal, Lisboa, Instituto Geológico e Mineiro, 43pp.

Azerêdo, A.C., Wright, V.P. and Ramalho, M.M., 2002. The Middle–Late Jurassic forced regression and disconformity in central Portugal: eustatic, tectonic and climatic effects on a carbonate ramp system. Sedimentology, 49, 1339–1370.

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Carvalho, J., Matias, H., Torres, L., Manupella, G., Pereira, R., Mendes-Victor, L., 2005. The structural and sedimentary evolution of the Arruda and Lower Tagus subbasins, Portugal. Mar. Pet. Geol. 22, 427-453.

Duarte, L.V., 1997. Facies analysis and sequential evolution of the Toarcian-Lower Aalenian series in the Lusitanian Basin (Portugal). Comunicações do Instituto Geológico e Mineiro, 83, 65-94.

Duarte, L.V., 2007. Lithostratigraphy, sequence stratigraphy and depositional setting of the Pliensbachian and Toarcian series in the Lusitanian Basin (Portugal). In: ROCHA, R.B. (Ed.), The Peniche section (Portugal). Contributions to the definition of the Toarcian GSSP. International Subcommission on Jurassic Stratigraphy, 17–23.

Duarte, L. V. and Soares, A.F., 2002. Litostratigrafia das séries margo-calcárias do Jurássico Inferior da Bacia Lusitânica (Portugal). Comun. Instituto Geológico e Mineiro, 89, 135–154.

Duarte, L.V., Silva, R.L., Oliveira, L.C.V., Comasrengifo, M.J. and Silva, F., 2010. Organic-rich facies in the Sinemurian and Pliensbachian of the Lusitanian Basin, Portugal: Total Organic Carbon distribution and relation to transgressive-regressive facies cycles. Geologica Acta, 8, 325–340.

Duarte, L.V., Wright, V.P., López, S.F., Elmi, S., Krautter, M., Azerêdo, A.C., Henriques, M.H., Rodrigues, R., Perilli, N., 2004. Early Jurassic carbonate evolution in the Lusitanian Basin (Portugal): facies, sequence stratigraphy and cyclicity. In: Duarte, L.V., Henriques, M.H. (eds.). Carboniferous and Jurassic Carbonate Platforms of Iberia. 23rd IAS Meeting of Sedimentology, Coimbra, Field Trip Guide Book, 1, 45- 71.

Gonçalves, P. A., Freitas da Silva, T., Mendonça Filho, J. G., Flores, D., 2015. Palynofacies and source rock potential of Jurassic sequences on the Arruda sub-basin (Lusitanian Basin, Portugal). Marine and Petroleum Geology, 59, 575-592.

Kullberg, J.C., 2000. Evolução tectónica mesozóica da Bacia Lusitaniana. Unplubl. PhD Thesis, Univ. Nova Lisboa, 361 p.

Kullberg, J.C., Rocha, R.B., Soares, A.F., Rey, J., Terrinha, P., Callapez, P., Martins, L., 2006. A Bacia Lusitaniana: Estratigrafia, Paleogeografia e Tectónica. In: Dias, R., Araújo, A., Terrinha, P., Kullberg, J.C. (Eds.), Geologia de Portugal no contexto da Ibéria. Univ. Évora, pp. 317–368.

Leinfelder, R.R., Wilson, R.C.L., 1989. Seismic and sedimentologic features of the Oxfordian–Kimmeridgian syn-rift sediments on the eastern margin of the Lusitanian Basin. Geologische Rundschau 78, 81–104.

McWhorter, S., Torguson,W., McWhoter, R., 2014. Characterization of the Lias of the Lusitanian Basin, Portugal, as an Unconventional Resource Play. AAPG 2014 Annual Convention and Exhibition, Houston, Texas, April 6-9, 2014, AAPG 2014.

Oliveira, L.C.V., Rodrigues, R., Duarte, L.V., Lemos, V., 2006. Avaliação do potencial gerador de petróleo e interpretação paleoambiental com base em biomarcadores e isótopos estáveis do carbono da seção Pliensbaquiano-Toarciano inferior (Jurássico inferior) da região de Peniche (Bacia Lusitânica, Portugal). Boletim de Geociências da Petrobras, 14(2), 207-234.

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Rasmussen, E.S., Lomholt, S., Andersen, C. and VejbÆk, O.V., 1998. Aspects of the structural evolution of the Lusitanian Basin in Portugal and the shelf and slope area offshore Portugal. Tectonophysics, 300, 199–225.

Rey, J., Dinis, J.L., Callapez, P., Cunha, P.P., 2006. Da rotura continental à margem passiva. Composiç~ao e evoluç~ao do Cret_acico de Portugal. In: Cadernos de Geologia de Portugal. Instituto Geol_ogico e Mineiro, Lisboa.

Ribeiro, A., Kullberg, M.C., Kullberg, J.C., Manuppella, G., Phipps, S., 1990. A review of Alpine Tectonics in Portugal: foreland detachment in basement and cover rocks. Tectonophysics, 184, 357–366.

Soares, A.F., Kullberg, J.C., Marques, J.F., Rocha, R.B., Callapez, P.M., 2012. Tectonosedimentary model for the evolution of the Silves Group (Triassic, Lusitanian Basin, Portugal). Bull. Soc. Geol. France, 183(3), 203-216.

Soares, A.F., Rocha, R.B., Elmi, S., Henriques, M.H., Mouterde, R., Almeras, Y., Ruget, C., Marques, J., Duarte, L.V., Carapito, C. and Kullberg, J.C., 1993. Le sous-bassin nord-lusitanien (Portugal) du Trias au Jurassique moyen: histoire d’un “rift avorté”. Comptes Rendus de l’Académie des Sciences de Paris, 317, 1659–1666.

Soto, R., Kullberg, J. C., Oliva-Urcia, B., Casas-Sainz, A. M., Villalaín, J. J., 2012. Switch of Mesozoic extensional tectonic style in the Lusitanian Basin (Portugal): Insights from magnetic fabrics, Tectonophysics, doi:10.1016/j.tecto.2012.03.010

Stapel, G., Cloetingh, S., Pronk, B., 1996. Quantitative subsidence analysis of the Mesozoic evolution of the Lusitanian Basin (western Iberian margin). Tectonophysics, 266, 493–507.

Wilson, R.C.L., 1979. A reconnaissance study of Upper Jurassic sediments of the Lusitanian Basin. Ciências Terra, Univ. Novo Lisb. 5, 53-84.

Wilson, R.C.L., 1988. Mesozoic development of the Lusitanian Basin. Revista Sociedad Geologica de España 1, 393–407.

Wilson, R.C.L., Hiscott, R.N., Willis, M.G., Gradstein, F.M., 1989. The Lusitanian Basin of westcentral Portugal: Mesozoic and Tertiary tectonic, stratigraphy, and subsidence history. In: Tankard, A.J., Balkwill, H.R. (Eds.), Extensional Tectonics and Stratigraphy of the North Atlantic Margins: AAPG Memoir, 40, pp. 341–361.

Ziegler, P.A., 1992. Geodynamics of rifting and implications for hydrocarbon habitat. Tectonophysics, 215, 221–253.

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T31, T32 – Southern Germany – Mesozoic shales

General information Screening- Index Basin Country Shale(s) Age Index Molasse T31 D Fish shale* Oligocene n/a Basin Upper Posidonien Schiefer* Toarcian (Jurassic) 2012 T32 Rhine D Graben Fish shale* Oligocene n/a *The description of the German potential shale oil and gas formations is based on the detailed report of Ladage et al. (2016). As Germany is not participating in this study, no additional ranking of the German formations is performed.

Geographical extent The Molasse Basin is the northern foreland basin of the Alpine Orogeny. It extends from Switzerland through southern Germany to the northern part of Austria. Its southern margin is the Alpine mountain chain, to the north it is bounded by the Schwabian and Franconian Jurassic mountains.

The Upper Rhine Graben is part of the European Cenozoic Rift system. It extends in north-south direction from the northern edge of the Jura Mountains in Switzerland to the area around Frankfurt in Germany. On the east and west the Black Forest and the Vosges are located respectively.

Figure 1 Location of the Fish Shale and the Posidonia Shale Formations in southern Germany. The colored areas represent different basins.

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Geological evolution and structural setting

Syndepositional setting The Molasse Basin formed during the Early Oligocene and contains up to 6km of shallow marine and fluviatile sediments deposited in the alpine foreland setting.

During the Lower Jurassic the area of the present-day Upper Rhine Graben was part of the shallow marine norther margin of the Tethys sea. Uplift of the Rhenish Massif to the north during the Late Jurassic to Late Cretaceous caused non-deposition and erosion. Sedimentation during the Cenozoic started with sub-aerial deposits, lacustrine carbonates and swamps located in individual lakes. After the onset of rifting the sedimentary fill consist of marls and evaporites grading to freshwater limestones. Increasing relief along the flanks resulted in the deposition of conglomerates and river fans. After the Rupelian a series of transgressions caused deposition of marine clays and marls interruped by fluvial-lacustrine deposits in lowstand situations (Schumacher, 2002).

Structural setting The basin was formed in a classic orogenic foreland basin setting on the northern margin of the Alpine orogeny. Continuous movement towards the north caused deformation of the southernmost areas of the basin and creating a fold and thrust belt along the French-Swiss border and along the southern margin of the basin in Germany. In other locations the whole basin fill was moved towards the north along a salt detachment zone.

The Upper Rhine Graben formed on preexisting Paleozoic structures during the Oligocene as a result of the Alpine orogeny. The irregular collision of the European and African plates resulted in the formation of extensional structures in the foreland basin of the Alps with substantial crustal thinning and related volcanic activity. The graben is still active today.

Organic-rich shales

Fischschiefer (Fish shale) In the Molasse Basin, the Fischschiefer is part of the “Unteren Meeresmolasse”. A connection with the Tethys during the Lower Oligocene in combination with fresh water resulted in a brackish environment. In this environment finely laminated bituminous clays and carbonate layers were deposited under anoxic conditions.

In the Upper Rhine Graben the Fischschiefer is part of the Bodenheim Formation which is characterised by finely laminated, dark brown to gray, organic rich clay and carbonaceous silt layers. Towards the basin margins it intercalates with the coarse clastic coastal facies of the Alzey Formation.

Depth and thickness In the undeformed foreland molasse the Fischschale dips towards the Alps at is estimated to be at depth of appoximately 3000m. Further to the south multiple thrust sheets can result in duplications of the formations, causing the Fischschiefer to be locally at the surface and also in greater depth of up to 5000m. It has an average thickness of 20 to 25m with a maximum of 50m.

In the center and north of the Upper Rhine Graben the Fischschiefer is usually located at depth of more than 1000m partly more than 3000m. In the south of the graben it is

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usually located at depth of less than 1000m. It thickness increases towards the north, with 10-30m in the southern an central part of the graben and 25 to 80m in the north.

Shale gas/oil properties The Fischschiefer in the Molasse Basin is of type I to type II organic matter and has TOC contents of 2-4% according to measurements. Due to the low geothermal gradient in the Molasse Basin it is assumed to be immature for oil and gas generation in most of the area, only in the deep settings in the south of the basin it probably reached oil maturity.

Measurements show that the Fischschiefer in the Upper Rhine Graben can have TOC contents of up to 10% with an average of 4%. In the northern, deeper part of the graben the Fischschiefer can reach oil maturity, gas maturity is reached only locally.

Posidonien Schiefer Posidonia Shale of Toarcian age is a very distinctive interval throughout Northwest Europe, with a present-day distribution from U.K. (Jet Rock Member in the Cleveland Basin and Upper Lias Clay in the Weald Basin) to Germany (Posidonienschiefer, or Ölschiefer). Given the uniform character and thickness (mostly around 30-60 m of dark-grey to brownish-black, bituminous, fissile claystones) across these basins, it is commonly suggested that the Posidonia Shale was probably deposited over a large area during a period of high sea level and restricted sea-floor circulation.

The Posidonien Schiefer is located at the surface in the Schwabian and Franconian Jurassic Mountains and dips towards the south east beneath the Molasse Basin. In the Upper Rhine Graben it is present at the surface along the graben shoulders but has been drilled in deep wells in the center of the graben.

Depth and thickness The thickness of the Posidonienschiefer in southern Germany is generally below 20m, in some areas of the Upper Rhine Graben is has an average thickness of 20-25m. In this area it is situated at depth between 1000 and 5000m.

Shale gas/oil properties Measurements on a few samples from deep wells from the Upper Rhine Graben show an average maturity of the Posidonienschiefer of 1% Vr. Gas potential is expected in deeper areas.

References Ladage, S. et al. (2016) Schieferöl und Schiefergas in Deutschland – Potentiale und Umweltaspekte. Bundesanstalt für Geowissenschaften und Rohstoffe (BGR), Hannover. (http://www.bgr.bund.de/DE/Themen/Energie/Downloads/Abschlussbericht_13MB_Sc hieferoelgaspotenzial_Deutschland_2016.html)

Schumacher, M.E., 2002. Upper Rhine Graben: Role of reexisting structures during rift evolution. Tectonics 21(1), 6-1 – 6-17.

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T34 - Midland Valley Scotland

General information Screening- Index Basin Country Shale(s) Age Index

Gullane Visean 1079 Limestone Coal Serpukhovian 1071 Midland Valley Fm T34 UK West Lothian Oil Scotland Visean 1072 Shale unit Lower Limestone Visean 1073 Fm

The descriptions in this report are mainly based on the detailed assessment of the Midland Valley Basin published by Monaghan (2014).

Geographical extent

Figure 1 Location of the Midland Valley Basin in Scotland. For the location of the shale units check Monaghan (2014). The coloured areas represent different basins.

Underlying the Central Belt of Scotland from Girvan to Greenock in the west, and Dunbar to Stonehaven in the east is the geological terrane of the Midland Valley of Scotland. It is a fault-bounded, WSW–ENE trending Late Palaeozoic sedimentary basin, bounded by the Caledonide Highland Boundary Fault to the north and the Southern Upland Fault to the south, with an internally complex arrangement of Carboniferous sedimentary basins and Carboniferous volcanic rocks overlying Lower Palaeozoic strata.

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The interbedded Carboniferous sedimentary and volcanic rocks of the Midland Valley of Scotland form a succession up to locally over 18,000 ft (5,500 m) thick.

Geological evolution and structural setting

Syndepositional setting The prospective Midland Valley of Scotland units were deposited in lacustrine, fluviodeltaic and shallow marine depositional environments which varied in space and time. Marine beds are identified at many levels, and are more dominant in some units (e.g. Lower Limestone Formation), but on a regional scale it is not possible to identify a specific prospective ‘marine shale’ interval.

Structural setting A wide variety of fault orientations, sub-basins and differential uplift patterns across the Midland Valley of Scotland result from a complex Palaeozoic to recent basin history. Broadly, four stages can be summarised: Late Devonian to Early Carboniferous basin formation in the Variscan foreland; Mid to Late Carboniferous basin formation to inversion and syndepositional magmatism; Latest Carboniferous to Permian tholeiitic magmatism and post-orogenic extension; Post Carboniferous deposition, uplift and erosion As a result, the Carboniferous Midland Valley of Scotland is not a simple graben containing a single basin; it is composed of a series of inter- related depocentres and intra-basinal highs. The main structural features include the deep low of the Midlothian-Leven Syncline in the Firth of Forth, Fife and Midlothian, the shallower Clackmannan Syncline and the Lanarkshire Basin in the Central Coalfield area.

Organic-rich shales

Gullane unit The Gullane Formation at outcrop (Mitchell & Mykura 1962) consists of a cyclical sequence of fine- to coarse-grained sandstone interbedded with grey mudstone and siltstone, as recognised in the Lothians south of the Firth of Forth. Subordinate lithologies are coal, seatrock, ostracod-rich limestone/dolostone, sideritic ironstone and rarely, marine beds with restricted faunas. The depositional environment was predominantly fluvio-deltaic, into lakes that only occasionally became marine (Browne et al. 1999). The Gullane Formation is of TC palynomorph zonation (Neves et al. 1973, Neves & Ioannides 1974) Asbian age (Waters et al. 2011). In the deep wells, the Gullane Formation is not recognised farther west than Leven Seat 1 (where it is interbedded within volcanic rock), Pumpherston 1 and Rosyth 1 wells. In the west, the unit is missing by unconformity, or replaced by volcanic rocks in the Inch of Ferryton 1, Rashiehill and Salsburgh 1A wells and at outcrop. In the Straiton 1 well, mudstone forms a large proportion of the Gullane Formation, whereas the character in the Carrington 1 and Stewart 1 wells is more heterolithic.

Depth and Thickness The Gullane unit is approximately 560m thick in outcrops in the east and about 800m in well Pumpherston 1.

Shale oil/gas properties According to Monaghan (2014) the Gullane unit is dominated by TOC values between 1-3.5%, with a smaller number of high TOC samples. Samples from the Gullane unit plot within the range of Type I, Type II and Type III kerogens.

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West Lothian Oil-Shale unit The West Lothian Oil-Shale unit is characterised by thin seams of oil-shale in a cyclical sequence dominated by sandstones interbedded with grey siltstones and mudstones. Subordinate lithologies include coal, ostracod-rich (and occasionally algal) limestone/dolostone, sideritic ironstone and marine beds, including bioclastic limestones with rich and relatively diverse marine faunas (Browne et al. 1999). Thick, pale green-grey or grey argillaceous beds containing volcanic detrital components (historically termed ‘marl’) are present (Jones 2007), as well as beds of tuff and ash (e.g. the Port Edgar Ash). The West Lothian Oil-Shale Formation is of Asbian to Brigantian age, NM-VF palynomorph zones (Browne et al. 1999, Waters et al. 2011). An estimated 5% of the West Lothian Oil-Shale Formation is considered to be marine- influenced (M. Browne pers. comm. 2014).

Jones (2007) defined 11 sedimentological facies within the West Lothian Oil-Shale Formation; these represent variations within a predominantly lacustrine environment. Periods of lake development and expansion were marked by deposition of lacustrine limestones and desiccation-cracked mudstones, with lake maxima marked by the deposition of oilshale facies. The lakes were generally filled by fine-grained siliciclastic (muddy) sediment, although minor channel systems fed coarser sediment (sand) into the lakes via small prograding delta systems. The calcareous mudstone (‘marl’) facies comprised a significant component of altered volcanic material. Marine faunas are usually diverse and marine strata could make up approximately 40% of the succession (M. Browne pers. comm.).

Depth and Thickness The West Lothian Oil-Shale Formation is up to 3,675 ft (1,120 m) thick and crops out over a large area of West Lothian and also on the western side of the Midlothian Syncline, south of Edinburgh.

Shale oil/gas properties Oil-shales sensu stricto form only about 3% (by thickness) of the West Lothian Oil- Shale Formation and are highly kerogen-rich, TOC-rich (up to 35%) sediments ranging from a few inches to 16 ft (5 m) thick (Loftus & Greensmith 1988). In thin section, the oil-shales are thinly laminated and are believed to be of laminar algal and discrete algal body origin (Loftus & Greensmith 1988, Parnell 1988, Raymond 1991). The oil- shales are interpreted as algal oozes (blooms) formed in shallow, stratified lakes, characterised by anerobic bottom conditions (Parnell 1988), though marine ostracods in some oil-shales imply marginal marine conditions existed at times (Wilkinson 2005, Jones 2007).

The source rock potential of the West Lothian Oil-Shale Formation was reviewed by Parnell (1988). He considered the oil-shales to be a high quality oil-prone source rock, with up to 30% TOC. Other shales and dark limestones within the formation were also considered to have petroleum source potential, with TOC values ranging from 1.5 to 22.7% (Parnell 1988).

According to Monaghan (2014) the West Lothian Oil-Shale unit has a large proportion of the samples between 1-7% TOC and a significant number between 7% and 30%. By contrast, the Lawmuir Formation, the basin margin equivalent of the West Lothian Oil-Shale Formation, has TOC < 2% in three of the four samples analysed (the fourth having TOC = 2.09%).

Samples from the West Lothian Oil-Shale unit plot within the range of Type I, Type II and Type III kerogens.

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Limestone Coal Formation The Limestone Coal Formation comprises sandstone, siltstone, mudstone, seatrock and coal or blackband ironstones in repeated cycles. The siltstone and mudstone are usually grey to black. Coal seams are common and many exceed a foot in thickness. Minor lithologies include cannel, and clayband ironstone. Thick multi-storey sandstones are present, though locally, successions may be particularly sandy or argillaceous. Regionally correlated marine bands that reach over 165 ft (50 m) in thickness (e.g. Black Metals Member along the Kilsyth Basin) consist largely of carbonaceous mudstone with clayband ironstones. Up to 30% of the lower part of the formation may be marine influenced. Stronger fluvial influences in the cyclical Limestone Coal Formation strata are noted in channel belts in the Clackmannan area and to the east of the Midland Valley (Read et al. 2002), along with active fault and fold growth. The palaeogeography for the Limestone Coal Formation highlights growth on synsedimentary folds and faults, and the palaeocurrent directions of fluvial systems taken from Read (1988) and Hooper (2004). Eruption of lavas and tuffs occurred in the Bathgate and Saline hills.

Depth and Thickness The Limestone Coal Formation of Namurian (Pendleian) age is more than 1,800 ft (550 m) thick in places.

Lower Limestone Formation The Lower Limestone Formation consists of repeated upward-coarsening cycles of limestone, mudstone, siltstone and sandstone. Thin beds of seatearth and coal may cap the cycles. The limestones, which are almost all marine and fossiliferous, are pale to dark grey in colour. The mudstones, many of which also contain marine fossils, and siltstones are predominantly grey to black. Nodular clayband ironstones and limestones are well developed in the mudstones (Browne et al. 1999). The depositional environment is interpreted as the repeated advance and retreat of fluviodeltaic systems into a marine embayment of varying salinity. Rocks of the Lower Limestone Formation are the most marine of the units considered prospective for shale, with up to 70% of the succession containing rich marine faunas.

Depth and Thickness The Lower Limestone Formation is up to 240m thick.

Shale oil/gas properties Organic-rich shales within the Lower Limestone to Coal Measures formations were also considered potential sources of hydrocarbons by Parnell (1984). It was considered that dark lacustrine shales and dolomitic laminites had some hydrocarbon generating potential (Parnell 1988). Turner (1991) analysed 27 Ballagan Formation shale samples, reporting values ranging from less than 0.01% carbon at Dunbar (East Lothian) to 1.2% carbon at Ballagan Burn (north of Glasgow).

According to Monaghan (2014) the Lower Limestone and Limestone Coal formations commonly have TOC values of 3-7.5%, with values between 9-30% measured in carbonaceous mudstones.

Limestone Coal Formation samples are indicative of Type I kerogens, whereas Lower Limestone Formation samples are aligned with Type III kerogens.

Chance of success component description

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Occurrence of shale layer

Mapping status Good Depths maps based on seismic interpretation and well logs area available for all formations as well as shale percentage maps

Sedimentary Variability High The formations are deposited as several cycles of mudstones, limestones, silt and sandstones with occasionally coals in fluvio-deltaic environments with some marine intercalations.

Structural complexity High several tectonic phases influenced the basin and subdivided it into several subbasins

HC generation

Available data Good

Proven source rock Possible Oil and gas shows in wells suggest that a tight oil/gas play could be present

Maturity variability High Several past burial events as well as magmatic intrusions cause high variability of the organic matter maturity

Recoverability

Depth Shallow to Average In most of the basin the formations are located at depth around 1000m in the basin center they can reach down to 5000m

Mineral composition Unknown to poor Average mineral composition is poor but some intervals show higher percentage of brittle minerals

References Browne, M.A.E., Dean, M.T., Hall, I.H.S., McAdam, A.D., Monro, S.K. & Chisholm, J.I. 1999. A lithostratigraphical framework for the Carboniferous rocks of the Midland Valley of Scotland. British Geological Survey Research Report, RR/99/07.

Hooper, M. 2004. The Carboniferous evolution of the Central Coalfield Basin, Midland Valley of Scotland: implications for basin formation and the regional tectonic setting. Unpublished PhD thesis, University of Leicester.

Jones, N.S. 2007. The West Lothian Oil-Shale Formation: results of a sedimentological study. British Geological Survey Internal Report, IR/05/046. 63pp.

Loftus, G.W.F. & Greensmith, J.T. 1988. The lacustrine Burdiehouse Limestone Formation—a key to the deposition of the Dinantian Oil Shales of Scotland. Geological Society, London, Special Publications 40: 219-234.

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Monaghan, A.A. 2014. The Carboniferous shales of the Midland Valley of Scotland: geology and resource estimation. British Geological Survey for Department of Energy and Climate Change, London, UK.

Mitchell, G.H. & Mykura, W. 1962. The geology of the neighbourhood of Edinburgh. (3rd edition). Memoir of the Geological Survey, Sheet 32 (Scotland).

Neves, R., Gueinn, K.J., Clayton, G., Ioannides, N.S., Neville, R.S.W. & Kruszewska, K. 1973. Palynological correlations within the Lower Carboniferous of Scotland and northern England. Transactions of the Royal Society of Edinburgh 69: 23-70.

Neves, R. & Ioannides, N.S. 1974. Palynology of the Lower Carboniferous (Dinantian) of the Spilmersford Borehole, East Lothian, Scotland. Bulletin of the Geological Survey of Great Britain 45: 73-97.

Parnell, J. 1988. Lacustrine petroleum source rocks in the Dinantian Oil Shale Group, Scotland: a review. In: Fleet, A.J., Kelts, K. & Talbot, M.R. (eds) Lacustrine Petroleum Source Rocks. Geological Society Special Publication 40: 235-246.

Raymond, A.C. 1991. Carboniferous rocks of the Eastern and Central Midland Valley of Scotland: organic petrology, organic geochemistry and effects of igneous activity. Unpublished Ph.D Thesis, University of Newcastle upon Tyne.

Read, W.A. 1988. Controls on Silesian sedimentation in the Midland Valley of Scotland. In: Besly, B.M., Kelling, G. (eds) Sedimentation in a synorogenic basin complex: the Upper Carboniferous of northwest Europe. Blackie and Son, Glasgow. 222–241

Read, W.A., Browne, M.A.E., Stephenson, D. & Upton, B.J.G. 2002. Carboniferous. In: Trewin N.H. (ed) The Geology of Scotland. Fourth Edition. The Geological Society, London, 251-300.

Turner, M.S. 1991. Geochemistry and diagenesis of basal Carboniferous dolostones from Southern Scotland. PhD thesis, University of East Anglia.

Waters, C.N., Browne, M.A.E., Jones, N.S. & Somerville, I.D. 2011. Midland Valley of Scotland. Chapter 14 in Waters C.N. et al. A revised correlation of Carboniferous rocks in the British Isles. The Geological Society of London Special Report 26: 96-102.

WILKINSON, I.P. 2005. Ostracoda from the West Lothian Oil Shale Formation. British Geological Survey Internal Report IR/05/036.

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T35 – Czech Republic – Lower Carboniferous shales of the Culm Basin

General information (see excel table from GEUS) Screening- Index Basin Country Shale(s) Age Index Lower Carboniferous Lower T6 Culm Basin CZ 1086 shales and siltstones Carboniferous

Geographical extent

The Culm basin (CB) occurs in the eastern Czech Republic (Figure 1). It consists of the West and East Culm subbasins, the latter subcrops below the West Carpathian Foredeep and Flysch Belt. The area of the CB exposed to the surface is about 4000 km2 and CB below the West Carpahians is about 4700 km2. Potential shale gas occurrence covers a partial area outlined in Figure 1.

Figure 1 Location of the Culm Basin in the Czech Republic. The colored areas represent different basins.

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Geological evolution and structural setting

Syndepositional The Lower Carboniferous Culm basin (CB) in the Czech Republic is the most south- easterly part of the European Variscan foreland basin system known as the Moravo- Silesian Terrane (Figure 1, Pharaoh et al. 2010). The NNE-SSW-trending basin forms the eastern margin of the Bohemian Massif. The syntectonic foreland basin formed due to load-driven subsidence in a compressional regime. Sedimentation started at about 340 Ma b.p., i.e. about 10-15 Ma earlier than the rest of the Variscan foreland. It contains up to 7.5 km of deep marine sediments deposited as an axial turbidite system sourced from S-SW (Hartely and Otava 2001). The Paleozoic burial was deep in the West and decreased towards the East (Francu et al. 2001). The Culm basin is overlain by Late Carboniferous Upper Silesian Coal basin in the North and Nemcicky basin in the southern segment. Jurassic carbonates and marls (Mikulov Fm.) and Eocene shales (Nesvacilka Fm.), both candidates for shale gas, cover the Culm in the southern part. In the Miocene, the eastern part of the CB was buried below the West Carpathian Foredeep and fold-and –thrust belt.

Fig. 2. Paleogeography and tectonic scheme of the Variscan terranes (Pharaoh et al. 2010 and sources therein) showing the position of the Culm basin in the Moravo-Silesian terrane adjacent to the Rheno- Hercynian terrane.

The Czech Culm basin is built by black shales, silts, and sandstones. They are correlated with similar lithologies of the Fore-Sudetic Monocline Basin (FSMB) in Poland (Botor et al. 2013), North German basin (Ladage and Berner, 2012), and Lower Carboniferous Bowland shales in northern England (Andrews, 2013).

Structuration The Czech Culm basin experienced tectonic deformation during the end of Lower Carboniferous (Viséan) and the present western part exposed at the surface forms a fold and thrust belt with tectonic shortening from W to E. The deformation decreases below the Carpathians. This part of the CB represents the marginal foreland basin,

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which was least affected by the Variscan orogeny and is considered as the best preserved part of the CB for shale gas exploration.

Organic-rich shales

The culm rocks include black shales and silts deposited under anoxic conditions and elevated total organic carbon content (TOC). These source rocks contain kerogen type III and partly mixed type II-III. For more details we refer to Albrycht et al. (2014).

Depth and thickness The present-day depth of the top of Lower Carboniferous within the CB is 2100-7000 m, thickness increases in general towards the W, in the adjacent mountains up to 7500 m. In the prospective area gross thickness ranges from 100 to 1250 m with average of 675 m. Net thickness range from 30 to 250 m with average of 140 m.

Shale gas/oil properties TOC varies with the lithology from 0.59 to 11.33%. Prospective formations of Lower Carboniferous in the CB occur within the later oil and gas windows (0.8-2.2%Ro). Regional pattern of thermal maturity at the top Viséan shales is in Fig. 3. In general the maturity increases from SE to NW and follows the increasing maximum burial depth from the foreland to the fold-and-thrust belt (Francu 2000; Francu et al. 1999, 2002a, b; Gerslova et al. 2016). Gas shows and light hydrocarbon liquids have been reported in the exploration boreholes in the Culm intervals. The maximum burial was reached by the end of the Carboniferous (Weniger et al. 2012). Temperature at the reservoir level varies from 80 to 210°C (Myslil et al. 2002).

Fig. 3. Thermal maturity pattern at the top of Culm shales and silts compiled for EUOGA. The red colors show high vitrinite reflectance values of the overmature window while the prospective area follows the blue-green-yellow interval (Dvorak and Wolf 1979; Francu et al. 2002).

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The average porosity range from 0.05 to 13%, adsorbed gas content (Langmuir isotherm/sorption capacity) may be estimated from analogy to be about 1.25 m3/t and average density of shale 2.6 kg/m3 (Andrews, 2013).

Risk components Occurrence of shale

Mapping status Variable Available seismic data is of variable quality but the surfaces and faults are interpreted and mapped.

Sedimentary variability Moderate Sedimentary modelling can be applied to enhance the current status of lithological trends.

Structural complexity Moderate The basin experienced burial and uplift. The prospective area is outside the thrust-and-fold belt.

Hydrocarbon generation

Available data Moderate Well logs, seismic surveys, kerogen type, TOC, Rock-Eval and vitrinite reflectance are available together with core samples from the exploration boreholes.

Proven source rock Proven Part of the Culm basin does contain a proven gas system in the Lower Carboniferous.

Maturity variability Moderate Maturity shows clear regional trends increasing from SE to NW.

Recoverability

Depth Average 2100-7000 m

Mineral composition Proven rather brittle siltstones and shales rich in quartz and low amount of expandable clay minerals.

References

Albrycht, I., Bigaj, W., Dvorakova, V., Francu, J., Garpiel, R., Osicka, J., Mathews, A., Sikora, A., Sikorski, M., Smith, K. C., Tarnawski, M. and Wagner, A. (2014): The development of the shale gas sector in Poland and its prospects in the Czech Republic - analysis and recommendations. The Kosciuszko Institute, 96 p.

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Andrews I.J., 2013. The Carboniferous Bowland Shale gas study: geology and resource estimation. British Geological Survey for Department of Energy and Climate Change, London, UK.

Botor D., Papiernik B., Maćkowski T., Reicher B., Kosakowski P, Marzowski G., Górecki W. 2013. Gas generation in Carboniferous source rocks of the Variscan foreland basin: implications for a charge history of Rotliegend deposits with natural gases. Annales Societatis Geologorum Poloniae 83, pp. 353-383.

Dvorak, J. and Wolf, M., 1979. Thermal metamorphism in the Moravian Paleozoic (Sudeticum, CSSR). N. Jb. Geol. Palaont. Mh., 1979, 10, 596-607.

Francu E., Francu J., Kalvoda J., 1999. Illite crystallinity and vitirnite reflectance in Paleozoic siliciclastics in the SE Bohemian Massif as evidence of thermal history. Geologica Carpathica, 50, 5, 365-672, ISSN 1335-0552.

Francu, E., 2000. Optical properties of organic matter in Devonian and Lower Carboniferous black shales in the northern Drahany Upland, Bull. of Czech Geol. Soc., 75, 2, 115–120.

Francu, E., Francu, J., Martinec, P., Krejčí, O., 2002a. Coal rank and pyrolitic characteristics in the boreholes in the Upper Silesian Basin. In -: Documenta Geonica, The 5th Czech and Polish Conference Geology of the Upper Silesian Basin, s. 65-68. – Ústav geoniky AV ČR. Ostrava. ISBN 80-7275-024-0.

Francu E., Francu J., Kalvoda J., Poelchau H.S., Otava J., 2002b. Burial and uplift history of the Palaeozoic Flysch in the Variscan foreland basin (SE Bohemian Massif, Czech Republic) In: Bertotti G., Schulmann K., Cloetingh S., eds.: Continental collision and the tectono-sedimentary evolution of forelands. European Geophysical Society - Stephan Mueller Special Publication Series, Vol. 1, European Geosciences Union Stephan Mueller Special Publication Series, 1, 167–179.

Gerslova, E., Goldbach, M., Gersl, M. and Skupien, P., 2016. Heat flow evolution, subsidence and erosion in Upper Silesian Coal Basin, Czech Republic. International Journal of Coal Geology, 2016, roč. 154-155, č. 1, s. 30-42. ISSN 0166-5162.

Hartley, A. J. and Otava, J., 2001. Sediment provenance and dispersal in a deep marine foreland basin: the Lower Carboniferous Culm basin, Czech Republic, J. Geol. Soc., 158, 137–150.

Ladage S., Berner U. (eds), 2012. Abschätzung des Erdgaspotenzialsausdichten Tongesteinen (Schiefergas) in Deutschland. Raport BGR, Hannover, 2012.

Myslil V., Burda J., Francu J., Stibitz M. (2002) Czech Republic. In: Hurter S. and Haenel R., eds., Atlas of Geothermal Resources in Europe. EUR, Luxembourg, Belgium, 17811, 26-27, 77-78 and Plates 13 and 14 (8 p.) ISSN 1018-5593 ISBN 92-828- 0999-4.

Weniger, P., Francu, J., Krooss B.M., Buzek F., Hemza P., Littke R. (2012) Geochemical and stable carbon isotopic composition of coal-related gases from the SW Upper Silesian Coal Basin, Czech Republic. Organic Geochemistry, 53, 153-165 (IF 2,79)

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T36 - Caltanissetta Basin (Italy) – Messinian shales

General information Screening- Index Basin Country Shale(s) Age Index

early T36 Caltanissetta I Sapropelic marls/Tripoli Messinian Not listed

Geographical extent The extent of the Triassic organic rich deposits within the Caltanissetta Basin is depicted Figure 1. The Caltanissetta Basin lies onshore in broad belt, trending NE-SW across the central part of Sicily island.

Figure 1 Location of the sapropelic marls of the Tripoli Formation. The coloured areas represent different basins.

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Geological evolution and structural setting

Syndepositional setting The Caltanissetta basin was formed as a foredeep during Alpine convergence in front of the progressively southward migrating Maghrebian orogenic front since the beginning of Neogene period. The Caltanissetta basin, trending NE-SW across the Sicily island, continued to be affected by compressive deformations during the Messinian and thus evolved into an accretionary wedge. Active thrust may have formed growth anticlines separating isolated synclines along the margins of the basin (Butler et al., 1999). As a result, starting in the Tortonian (Late Miocene), a great complexity of thrust-top basins developed. The deposition of the major part of the early Messinian Tripoli Fm took place in these basins in near normal marine conditions submitted to cyclically controlled variations of productivity. The formation is composed of a repetition of sedimentary triplets composed of homogeneous marls, laminated marls (sapropel) and diatomites that are usually interpreted as being constrained by the astronomical precession. Polished specimens of tripolitic marls from the Cozzo Disi sulfur mine revealed much interstitial pale orange-fluorescing organic matter (probable bituminite), sparse vitrinite or inertinite, and much finely disseminated pyrite under UV reflected light (Dyni, 1988).

The Tripoli Fm grades upward into the Calcare di Base Fm which displays the first evidence of evaporite precipitation (gypsum and halite) and is commonly considered as the true onset of the Mediterranean Salinity Crisis, preceding the deposition of the evaporitic formations (Gessoso Solfifera group). The calcareous marls of the Trubi Formation were deposited on top of the evaporite beds, which marks the return to normal deep-water marine conditions within the basin. A mixed assemblage of marine and continental sediments of Pliocene and Quaternary age was deposited on the Trubi beds.

Structural setting Much of the Tripoli formation is found in small, commonly faulted, synclinal structures. Uplift and emergence associated with folding and faulting has locally exposed the Tripoli Fm, typically in small synclinal structures, within the basin (Dyni, 1988). In parts of the basin, however, the formation is buried 900 or more meters below the surface. Locally, such as at the Cozzo Disi mine the formation is strongly folded. In other areas, such as at the oil-shale mine near Serradifalco and near Villarosa, the formation is relatively little disturbed (Dyni, 1988).

Organic-rich shales

Depth and Thickness The Tripoli deposits reach a maximum thickness of 45 m in the center of the basin. Uplift and emergence of the Messinian rocks with folding and faulting has locally exposed the Tripoli Fm, typically in small synclinal structures, within the basin (Dyni, 1988).

Shale Oil Properties Determinations of the Tripoli formation are sparse. Shale-oil yields estimated from Rock-Eval data range from 8 to 125 l/meter ton with a mean shale-oil estimate of 32.9 l/meter ton (Dyni, 1988). The petroleum potential (oil and combustible gas) for fresh Tripoli rocks is estimated to about 51-88 billion barrels of oil equivalent for a 3,000 km2 less tectonically disturbed part of the Caltanissetta Basin. Plots of the S2

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and S3 data on a Van Krevelen diagram indicate a type I kerogen; Tmax of the kerogen were found to range between 300° - 400° C (Dyni, 1988).

Chance of success component description Occurrence of shale

Mapping status Poor No map, only outlines

Sedimentary variability Moderate Due to structural complexity difficult to determine

Structural complexity High Heavenly folded and a huge range in depths probably lead to very small and scattered sections that reached maturity.

HC generation

Available data Moderate Few Rock-Eval measurements

Proven source rock Unknown

Maturity variability High Heavenly folded and a huge range in depths probably lead to very small and scattered sections that reached maturity.

Recoverability

Depth Shallow <1000m

References Butler, R.W.H., Lickorish, W.H., Grasso, M., Pedley, H.M., Ramberti, L., 1995. Tectonics and sequence stratigraphy in Messinian basins, Sicily: Constraints on the initiation and termination of the Mediterranean salinity crisis. Geol. Soc. Am. Bull., 107, 425-439.

Dyni, J. R., 1988, Review of the geology and shale-oil resources of the tripolitic oil- shale deposits of Sicily, Italy. USGS Open-File Report, 88-270.

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B01 - Transilvanian Basins – Neogene Shales

General information Screening- Index Basin Country Shale(s) Age Index Upper RO Miocene 1041 Badenian B1 Transilvanian Basin Lower RO Miocene 1042 Sarmatian

Geographical extent The Transylvanian Basin (Figure 1) is the most important zone with gas accumulation in Romania.

Figure 1 Location of the Transilvanian Basin. The coloured areas represent different basins.

Geological evolution and structural setting

Syndepositional setting From a geotectonic point of view, the Transylvanian Basin is a typical back-arc basin (Săndulescu 1988) related with the Carpathian subduction in the Miocene. The Transylvanian Basin is developed on a basement which was built beginning with the late Albian and it is overlapping on the Carpathian Alpine nappes. Therefore, this basin comprises two groups of tectonic units: Carpathian deformed units (including Tethyan Suture Zone, known as the Vardar-Mureş unit) and Upper Cretaceous - Middle Miocene post-tectogenetic sedimentary cover (Săndulescu 1994). The sedimentary cover of the

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Transylvanian Basin has formed during to five sedimentary cycles: Upper Cretaceous, Paleogene, Lower Miocene, Middle – Upper Miocene and Pliocene.

Major sedimentation during Upper Badenian to Sarmatian deposited thick shallow marine to lacustrine clastics. In lithostratigraphic terms (Ciupagea et al. 1970; Săndulescu 1984, 1988), the basement of the Transylvanian Basin consists of metamorphic rocks, magmatic (mafic and ultramafic) rocks and sedimentary rocks (Upper Triassic – Lower Cretaceous sedimentary cover). The metamorphic rocks are present in the Inner Dacides (western part of the basin) and Median Dacides (in the eastern part of the basin) while the mafic and ultramafic rocks belonging to the ophiolitic complex (Transilvanides) which separates the two assemblages of metamorphic units as a noth-eastern extension – the Southern Apusenides – Metaliferous Mountains (the so-called Mureş zone). The latest tectonic events (The Wallachian phase) recorded in the Transylvanian Basin are related to the continental collision between the Tisza-Dacia block and the Scythian Platform (Săndulescu 1984; Bădescu 2005) when the Eastern Carpathians have been uplifted with 4-5 km. This process led to the tilting and uplif of the entire basin toward west-southwest and determined the deposition of the clastic sediment in the distal zone. Note that sediments were affected by the diapiric processes which were reactivated from to the Late Sarmatian.

Lacustrine Pannonian deposits disposed in fan-deltas are syn-tectonic to Carpathian nappes emplacement. Subsequent uplift and erosion at the end of Pannonian mark the end of basinal sedimentation in Transylvania. Most of the unconformities are linked to adjacent Carpathians Miocene tectonic movements.

Structural setting The Carpathians, the Eastern Alps and the Dinarides resulted from the Triassic and Cenozoic continental collision of the European and African plates with other small blocks (Săndulescu 1984; Hosu 1999). The extensional phase (simple shear) in the Transylvanian domain (Wernicke, 1981 fide Bădescu 1998a; Ciulavu et al. 2000) is well evidenced by the position of the normal fault system (Jurassic ages), oriented approximately on N-S direction, found mostly in the central area and at a lesser extent in the northern part. The shortening of the Tethyan crust in the Carpathians domain started during Early Cretaceous. During this time the subduction has been materialized by emplacement of the overthrust nappes on the continental margin of the European plate and in the Tethyan oceanic lithosphere. This compressional event is clearly evidenced in the Transylvanian Basin by the N-S trending overthrusts with eastern vergency. Upper Cretaceous Laramian compressions are related to the continuation of the subduction of the Getic microplate under Foreapulian block (Hosu 1999) followed by the collision. These processes led to new deformations followed by the major phase of erosion that was accompanied by the banatitic magmatims. These small rifts occur in the northern part of the Transylvanian Basin. The closure of Tethys Ocean (In the Late Cretaceous) joined the Tisza-Dacia unit and the Alcapa block (Hosu 1999) along the Mid-Hungarian line. After the completion of the Cretaceous structural configuration in the Carpathian area, the main tectonic events that were recorded during the Early Miocene (Pătraşcu et al. 1994) have been the push to the north and the clockwise rotating of the Tisza-Dacia block. In the Transylvanian domain, the Paleogene (Ciulavu 1998) is post-rift tectonic phase and is characterized by a weak compressional activity. Therefore, during the Paleocene, the basement of the Transylvanian basin has been affected by intense erosion in some areas. The resulted sediments forming continental deposits (alluvial cones and fluvial facies, Hosu 1999). The Mid-Cretaceous overthrusts from the

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northern part of the Transylvanian basin were reactivated during to the Eocene period. Thus, the Eocene erosion generated the sediments that were deposited in two basins. In the Early Miocene, an overthrust of the northern extremity of Alcapa unit over Tisza-Dacia block was possible due to the transpressional movements along the "Mid- Hungarian line". The result of this process is the occurrence of a flexural basin during the Late Oligocene – Burdigalian. This basin functioned as a typical foreland basin (Ciulavu 1998) with E-W direction, developed in front of the overthrust structures to Pienides zone. The uplift of the Transylvanian Basin at the end of Lower Oligocene (except for the northern part) is very clearly evidenced by the presence of the unconformity which is situated at the base of Dej Tuff Complex (Ciupagea et al. 1970). The basin reached its present shape in the Neogene, more precisely at the end of the Old Styrian tectogenesis, when the sedimentation of Hida formation began. According to Săndulescu (1994), the basinal subsidence was controlled and directed by the deformation of its surrounding areas (especially the Eastern Carpathians). Regional sedimentation started in Upper Lower Badenian with shallow marine clastics associated with first regional Carpathians volcanic, followed by hypersaline type sedimentation (Salt Formation) during Middle Badenian.

Organic-rich shales

Upper Badenian and Lower Sarmatian The Upper Badenian sediments were deposited in a higly restricted environment with poorly oxygenated bottom water conditions (Palcu et al. 2015). The Lower Sarmatian shows evidence of full anoxia in combination with brackish water conditions (Palcu et al. 2015)

Depth and Thickness The geological mappings and exploration drilling in the Transylvanian Basin, identified Cenozoic sediments reaching 6000 to 8000m of thickness and consisting of an alternation of clays, marls, sandstones, sands and conglomerates. The structural map of the top of the Middle Badenian shows the formation at a depth between 1000 and 3000 ms (time, Figure 2).

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Figure 2 Structural map with isochronous (ms TWT) – top of the Middle Badenian

Shale oil/gas properties The bituminous schists in the Ileanda beds, the radiolarian schist and, generally, all the marly horizons belonging to the Badenian and Sarmatian are considered likely to be hydrocarbon source rocks. In the Transylvanian basin 99% of the gas is methane and it has the biogenic origin, the formations have not reached a themogen stage.

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Chance of success component description

Occurrence of shale

Mapping status Moderate Depth map in time available for the Middle Badenian

Sedimentary variability Moderate

Structural complexity Moderate layer faulted, locally eroded, subsidence, uplift and salt tectonics

HC generation

Available data Poor no data

Proven source rock Possible Biogenic HC accumulations known, source rock unit unclear.

Maturity variability Immature Biogenic system

Recoverability

Depth Average to Deep

Mineral composition No data average mineral composition was not provided

References Ciulavu, D. 1998. Tertiary tectonics of The Transilvanian Basin. PhD Thesis, Vrije Universiteit, 138 p., Amsterdam.

Ciupagea, D., Paucă, M. and Ichim, T. 1970. Geology of the Transylvanian Depression. Romanian Academy Publishing House, Bucharest, 256 p. (in Romanian).

Colţoi, O. and Pene, C. 2010. Reserse fault system Cenade-Ruşi-Veseud. Abstracts Volume of XIX Congress of the CBGA, Geologica Balcanica 39. 1-2, Bulgarian Academy of Sciences, 78.

Colţoi, O. 2011. Processes of forming and evolution of the diapiric structures and their roles in the hydrocarbon accumulation. Unpublish. PhD Thesis, University of Bucharest. 131 p., Bucharest.

Dan V. Palcu, Maria Tulbure, Milos Bartol, Tanja J. Kouwenhoven, Wout Krijgsman (2015) The Badenian–Sarmatian Extinction Event in the Carpathian foredeep basin of Romania: Paleogeographic changes in the Paratethys domain, Global and Planetary Change, Volume 133, Pages 346-358

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Huismans, R. S., Bertotti, G., Ciulavu, D., Sanders, C. A. E., Cloetingh, S. & Dinu, C. [1997] Structure evolution of the Transylvanian Basin (Romania): a sedimentary basin in the bend zone of the Carpathians. Tectonophysics, 272, p. 249-268.

Krézsek, C. and Bally, A.W. 2006. The Transylvanian Basin (Romania) and its relation to the Carpathian fold and thrust belt: insights in gravitational salt tectonics. Marine and Petroleum Geology, 23, 405–442.

Paraschiv, D. 1979. Romanian Oil and Gas Fields. Institute of Geology and Geophysics. Technical and Economical Studies, A Series, 13, 381 p., Bucharest.

Pene, C. and Colţoi, O. 2005. Study of the salt movement mechanisms in the Transylvanian basin. Journal of the Balkan Geophysical Society, 8, Suppl. 1, 513-516.

Pene, C. and Colţoi, O. 2006. Relationships between gas accumulation and salt diapirism in the Transylvanian Basin. 68st EAGE Conference & Exhibition, Extended Abstracts, P173.

Pene, C., Colţoi, O. and Grigorescu, S. 2012. Badenian Evaporite Evolution and Methane Entrapment in the Transylvanian Basin. 74st EAGE Conference & Exhibition, Extended Abstracts, P052.

Schmid, S., Bernoulli, D., Fügenschuh, B., Mațenco, L., Schefer, S., Schuster, R., Tischler, M. and Ustaszewski, K. 2008. The Alpine-Carpathian-Dinaridic orogenic system: correlation and evolution of tectonic units. Swiss Journal of Geosciences, 101(1), 139-183.

Săndulescu, M. 1988. Cenozoic tectonic history of the Carpathians; In: L. Royden, L. Horvath, F. (eds.): The Pannonian Basin: a study in basin evolution. AAPG Mem., 45, 17-25.

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