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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

Geological resource analysis of shale gas/oil in Europe

June 2016 I 2


June 2016 I 3

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


June 2016 I 4

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.


June 2016 I 5

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

questionnaire

EUOGA association status

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.


June 2016 I 6

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.


June 2016 I 7

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 hydro-

carbon 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.


June 2016 I 8

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.


June 2016 I 9

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

Basin index

Country code

Basin name Screening ID

Shale name

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 Lublin Basin

1053 Lower Palaeozoic shales

T3 PL South Lublin Basin and Narol Basin

1054 Lower Palaeozoic shales

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 - Forebalkan

1058 J1 shale & clay limestones

1059 J2 shale

Kamchia basin 1060 Oligocene shale

T5 UA Dniper Donetsk Basin 1043 Black Shale

T6 PL Carboniferous basin of Fore-Sudetic Monocline

1055 Lower Carboniferous shale

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


June 2016 I 10

Basin index

Country code


Shale name

1006 Riva_di_Solto

1007 Marne di Bruntino

T10a NL Northwest European Carboniferous Basin

1064 Geverik Member

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 Basin/Broad 14s Basin

1065 Posidonia Shale

T25c DE Northwest German Basin 0 Blättertone/Fish Shale

0 Mid Rhaetian shale

2012 Wealden


June 2016 I 11

Basin index

Country code


Shale name

2012 Posidonia Shale

T25c and T32

DE Northwest German Basin

and Upper Rhine Graben 2012 Posidonia Shale

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 and T32

DE Upper Rhine Graben and Molasse Basin

0 Fish shale

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


June 2016 I 12

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)

Index Basin Country Shale(s) Age Screening-

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


June 2016 I 13

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


June 2016 I 14

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


June 2016 I 15

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


June 2016 I 16

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

General information


Index

T1

Norwegian-

Danish-

S.Sweden

(Caledonian

foreland)

S Alum Shale

M.

Cambrian-L.

Ordovician

1015

S Alum Shale

M.

Cambrian-L.

Ordovician

1016

DK Alum Shale

M.

Cambrian-L.

Ordovician

1019

B2 Fennoscandian

shield S Alum Shale

Cambrian-

Ordovician 1017

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.


June 2016 I 17

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.



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


June 2016 I 18

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 syn-

depositional 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.


June 2016 I 19


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).


Occurrence of shale

Mapping status

Moderate

Sedimentary Variability

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


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.


Moderate


June 2016 I 20

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.,

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(eds): The Jurassic of Denmark and Greenland. Geological Survey of Denmark and

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June 2016 I 22

T02 - Baltic Basin – Cambrian-Silurian Shales

General information


Index

T2

Baltic

Palaeobasin LV No name Lower Ordovician 1001

Baltic Basin S Alum Shale

Formation

M. Cambrian - E.

Ordovician 1014

Sorgenfrei

Tornquist Zone S

Alum Shale

Formation

M. Cambrian - E.

Ordovician 1015

Norwegian-

Danish-Scania DK Alum shale

M. Cambrian - E.

Ordovician 1019

Baltic Basin LT

Upper Ordovician-

Llandovery

Shales#

Middle-Late

Llandovery (Late

Ordovician)

1061

Baltic Basin PL Lower Palaeozoic

shales*

Upper Cambrian to

Llandovery 1051

Płock‐Warsaw

zone PL

Lower Palaeozoic

shales*

Upper Cambrian to

Llandovery 1052

Podlasie basin

and North Lublin PL

Lower Palaeozoic

shales+

Silurian (Llandovery

to Wenlock) 1053

* 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.


June 2016 I 23

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



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.,


June 2016 I 24

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


June 2016 I 25

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.


Occurrence of shale

Mapping status

Moderate


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


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 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.


High


Shallow

Mineral composition

Unknown


June 2016 I 26

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)


June 2016 I 27


Occurrence of shale layer

Mapping status

Unknown Only outlines of the assessment unit were provided


Moderate


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


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.


June 2016 I 28

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.


Unknown



Mapping status

Moderate Thickness and depth map available


Moderate


Moderate


Data availability

Poor

HC system

Possible On- and offshore exploration wells have encountered oil and oil shows,

no production.


June 2016 I 29


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).


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.


June 2016 I 30

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).



Mapping status

LT: Good Thickness and depth map available

P: Unknown Only outlines available


Moderate Facies changes within the Baltic Basin depending on the depositional

setting


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.



June 2016 I 31

Data availability

Moderate

HC system

Possible


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.


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


June 2016 I 32

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 north-

eastern 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).



Mapping status

LT: Moderate Total Lower Silurian depth and thickness map available

P: Unknown Only outlines were provided


Moderate Large scale facies changes within the Baltic Basin depending on the

depositional setting


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.


Data availability

Moderate

HC system

Possible


Moderate

Recoverability

Depth

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

south.

Mineral composition


June 2016 I 33

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).


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).



Mapping status

Unknown Only outlines provided


Moderate


Moderate to high


Data availability

Moderate

HC system

Unknown


Moderate

Recoverability

Depth


June 2016 I 34

Average 1000-5000m

Mineral composition

No data

References

Brangulis A.J., Kuršs V., Misāns J., Stinkulis Ģ. 1998. Geology of Latvia. Geological

map at the scale 1:500 000 and description of the Pre-Quaternary deposits. (Ed. by

J.Misāns). Riga, State Geological Survey of Latvia.70.

Cocks, L.R.M., McKerrow, W.S. 1997. Baltica and its margins in the Ordovician and

Silurian. Terra Nostra 97/11, 39-42.


Tennyson, M.E., and Whidden, K.J., 2013. Undiscovered Gas Resources in the Alum


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.

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Devonian oils. Biuletyn Państwowego Instytutu Geologicznego, 402: 75-100 (in

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June 2016 I 35

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June 2016 I 37

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

General information


Index

T3

South Lublin

Basin and Narol

Basin

PL Lower Palaeozoic

shales

Silurian

(Llandovery to

Wenlock)

1054

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.



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


June 2016 I 38

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 deep-

water 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.


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


June 2016 I 39

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”.



Mapping status

P: Unknown Only outlines provided

UA: Moderate Depth and thickness maps available


Moderate


Moderate to high


Data availability

Moderate

HC system

Unknown


Unknown

Recoverability

Depth

Average 1000-5000m

Mineral composition

No data

References

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



June 2016 I 40




and Lublin- Podlasie Basins (Poland). Przegląd Geologiczny, volume 58, p. 226–249 (in

Polish).





June 2016 I 41

T04 - Moesian Platform and Kamchia Basin

General information

Index Basin Country Shale(s) Age

Screening-

Index

(summarized

in 2001)

T4

Moesian

Platform

BG Lower Paleozoic

Shales

Silurian to Lower

Devonian 1056

RO Tandarei Graptolitic

Black Shales

U OrdovicianU

SilurianL Devonian 1038

BG

Upper Paleozoic

shale & coal

Succession

Trigorska &

Konarska Fms

Lower Carboniferous

(Middle

Mississippian, Upper

Visean)

1057

RO Calarasi bituminous

limestones

U DevonianL

Carboniferous 1039

RO Vlasin black shale

Formation U Carboniferous 1040

BG

J1 shale & clay

limestones Ozirovo

Fm

(Bucorovo &

Dolnilucovit Mbs)

Jurassic (Sinemurian

‐ Toarcian) 1058

BG J2 shale Etropole

Fm (Stefanets Mb)

Aalenian Lower

Bajocian 1059

Kamchia

Basin BG Ruslar Fm Oligocene 1060

Black Sea

shelf RO Oligocene n/a

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.


June 2016 I 42

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



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:


June 2016 I 43

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


June 2016 I 44

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.


June 2016 I 45


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.


Occurrence of shale

Mapping status


datapoints)


Moderate


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


Proven source rock

Unknown


High

Recoverability

Depth

Average 1000-5000m

Mineral composition

No data Described as carbonated claystones with organic matter


June 2016 I 46

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.


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%.


Occurrence of shale

Mapping status

Moderate Interpolated thickness maps are available


Moderate


High

HC generation

Available data

Moderate

Proven source rock



Unknown

Recoverability

Depth

Unknown

Mineral composition


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.


June 2016 I 47

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.


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.


Occurrence of shale

Mapping status


datapoints)


Moderate


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


High From early mature to anthracite level


June 2016 I 48

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.


The kerogen type ist type III.


Occurrence of shale

Mapping status

Moderate interpolated thickness maps available




Moderate to High

HC generation

Available data

Moderate

Proven source rock



Unknown

Recoverability

Depth

Unknown

Mineral composition


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


June 2016 I 49

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.


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).


Occurrence of shale

Mapping status


data points)


Low


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).



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


June 2016 I 50

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).


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,


Occurrence of shale

Mapping status


data points)


Low


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



Recoverability

Depth

Average 1000-5000m

Mineral composition

Favourable Inferred brittle lithology


June 2016 I 51

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.


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.


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


June 2016 I 52

was confirmed the main role of Oligocene deposits in the generating of oil and gas

from the north-eastern flank of the Histria depression.


Occurrence of shale

Mapping status


datapoints)




Low

HC generation

Available data

Good

Proven source rock



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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June 2016 I 59

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

General information (see excel table from GEUS)


Index

T5 Dnieper-

Donets Basin UA

Rudov Beds

(Upper Visean Shales)

(Lower Serpukhovian)

Upper Visean

(Upper Visean)

(Serpukhovian)

1043

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.


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


June 2016 I 60

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.


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


June 2016 I 61

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%)


Occurrence of shale

Mapping status

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


Low to Moderate Marine conditions existed throughout the basin when the shales

were deposited.


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.


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


References


June 2016 I 62

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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


June 2016 I 63

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



Index

T6

Forel-Sudetic

Monocline

Basin

PL Lower Carboniferous

shales and siltstones

Lower

Carboniferous 1055

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.


June 2016 I 64

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).


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


June 2016 I 65

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.


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.


June 2016 I 66

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.


High


Moderate to High Fold and thrust deformation as well as younger phases of

extensive subsidence and uplift


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.


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

Recoverability

Depth

Average 1000-5000m

Mineral composition


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:


June 2016 I 67

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.


Tennyson, M.E., and Whidden, K.J., 2013. Undiscovered Gas Resources in the Alum


http://dx.doi.org/10.3133/fs20133103.ISSN 2327– 6932 (online).

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


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).


June 2016 I 68

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., 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).



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.


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).


June 2016 I 69

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).

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.

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.

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).


June 2016 I 70

T07a - Hungary – Kössen Marl, Zala Basin



Index

T7a Zala Basin

(Pannonian) HU Kössen Marl

Norian, Late

Triassic 1049

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.


June 2016 I 71

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



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


June 2016 I 72

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.


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


June 2016 I 73

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.




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).


June 2016 I 74


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.


June 2016 I 75

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.


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


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.



June 2016 I 76

T07b - Hungary – Tard Clay, Hungarian Palaeogene Basin



Index

T7b

Hungarian

Palaeogene

Basin

HU Tard Clay Oligocene 1050

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 Bu ̈kk,

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 Bu ̈kk 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 palaeo-

geographic 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


June 2016 I 77

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.



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


June 2016 I 78

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)


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


June 2016 I 79

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.




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.


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).


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


June 2016 I 80

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


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


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


June 2016 I 81

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.


June 2016 I 82

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

General information


Index

T7c Pannonia,

Mura-Zala SLO Haloze-Špilje Fm. Shale Neogene

1066&1068

(gas),

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.



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


June 2016 I 83

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.


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.


Occurrence of shale


June 2016 I 84

Mapping status

Good


Moderate to High


Moderate several subbasins and inverse antiforms

HC generation

Available data


Proven source rock

Possible Gas and oil shows detected in wells in the area



Recoverability

Depth

Average 1000-5000m

Mineral composition


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.

http://www.geo-zs.si/podrocje.aspx?id=489


June 2016 I 85

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.

http://transenergy-eu.geologie.ac.at/Downloads/outputs/Summary%20report%20of%20geological%20models/Summary%20report%20of%20geological%20models.pdf




June 2016 I 86

T08 - Vienna Basin – Mikulov Marl



Index

T8

Vienna Basin A Mikulov Marl Fm.

(Mergelsteinserie)

U. Jurassic

(Oxfordian –

Kimmeridgean)

1018

SE Bohemian

Massif CZ Mikulov Fm.

U. Jurassic

(Oxfordian –

Kimmeridgean)

1063

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.


June 2016 I 87

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.


June 2016 I 88

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.



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.


June 2016 I 89

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).


June 2016 I 90

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


June 2016 I 91

?

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


June 2016 I 92

North-West Boundary of the Vienna Basin

Ele

vati

on

be

low

Sea

Le

vel [

m]

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

Full thicknessof the Mikulov Fm.

encountered

NW Boundary of the

Vienna Basin

Thic

knes

s o

f th

e M

iku

lov

Mar

ls [

m]

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


June 2016 I 93


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


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.


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.


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


June 2016 I 94

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.


June 2016 I 95

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.


June 2016 I 96

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

General information


Index

T9 Lombardy

Basin

I Meride Fm Ladinian 1005

I Argilliti di Riva di Solto

Fm Norian 1006

I Marne di Bruntino

formation

E.

Cretaceous 1007

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.


June 2016 I 97

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.



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


June 2016 I 98

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.


June 2016 I 99

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.


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


June 2016 I 100

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.


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.


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.


June 2016 I 101


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.


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).


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.


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.


June 2016 I 102

Mineral composition


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.


June 2016 I 103

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

General information


Index

T10a Northwest

European

Carboniferous

Basin

NL Geverik Member Namurian A 1064

T10b UK

Carboniferous

UK Bowland-Hodder Carboniferous 1077

T22 Campine B Chokier Carboniferous 1048

Westphalian A+B Carboniferous 1045

T23 Mons B Chokier Carboniferous 1046

T24 Liege B Chokier Carboniferous 1047

T33 Northern

Germany

D Hangender

Alaunschiefer and

Kohlenkalk-Facies

Carboniferous 2013*

*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.


June 2016 I 104

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).


June 2016 I 105



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).


June 2016 I 106


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).


June 2016 I 107


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.


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).


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.


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



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


June 2016 I 108

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.


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.


June 2016 I 109


Occurrence of shale

Mapping status

Good Depth and thickness maps available on unit level based on seismic

interpretation and well data.


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.


Moderate Distributed over several rift basins and local erosion

HC generation

Available data


Proven source rock

Proven Bowland-Hodder formations have sourced conventional fields

(Smith/DECC, 2011)



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


June 2016 I 110

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.


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%.


Occurrence of shale

Mapping status


datapoints)


Moderate to High


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


Proven source rock



June 2016 I 111



Recoverability

Depth

Average 1000-5000m

Mineral composition


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.


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.


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.




June 2016 I 112



HC generation

Available data


Proven source rock




Recoverability

Depth

Average 1000-5000m

Mineral composition


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.


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%.

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June 2016 I 116

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

General information


Index

T11a Umbria-Marche I Marne del Monte

Serrone Formation

E. Jurassic

(Toarcian) 1009

T11a Umbria-Marche I Marne a Fucoidi

Formation

E. Cretaceou

(Aptian-

Albian)

1010

T11b Emma I Emma Formation L. Triassic –

E. Jurassic 1008

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.


June 2016 I 117



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.


June 2016 I 118

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.


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.




of these resources:




Occurrence of shale

Mapping status



subsurface data.


June 2016 I 119





platform complex. Even within these restricted basin lateral changes are

expected based on to relatively shallow depositional depths.




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.


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


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).


June 2016 I 120

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).


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.




of these resources:




Occurrence of shale

Mapping status



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.





platform complex.



June 2016 I 121



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.





and overmature).


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

Mineral composition


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 lime-

stones (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.


June 2016 I 122

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).


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




of these resources:




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.


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





June 2016 I 123

HC Generation

Available data




Proven source rock








and overmature).


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

Mineral composition


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).


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.


June 2016 I 124

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June 2016 I 128

T12 - Ribolla Basin (Italy) – Argille Lignitifere



Index

T12 Ribolla I Argille Lignitifere

Miocene

(Tortonian-

Messinian)

1011

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.


June 2016 I 129



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).


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


June 2016 I 130

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.


Occurrence of shale

Mapping status

Good Well data and a recently acquired 2D seismic survey exist were used to

construct improved depth maps.


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


Low The geological structure is relatively simple as is confirmed by

interpretation of a 2008-2010 2D seismic survey.

HC generation

Available data




Proven source rock





Low Thermal maturity is only affected by a single burial event. Besides

depth, maturity modelling is predominantly dependent on maturity-


June 2016 I 131

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.


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.


June 2016 I 132

T13 - Ragusa Basin (Italy) – Triassic shales

General information


Index

T13 Ragusa I Noto & Streppenosa

Shales

Triassics

1012, 1013

Geographical extent

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


June 2016 I 133

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.



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 tectono-

sedimentary 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


June 2016 I 134

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


June 2016 I 135

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.


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



subsurface data.





platform complex. Even within these restricted basin lateral changes are

expected based on to relatively shallow depositional depths


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.



complex structural history. In combination with local basaltic intrusions


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

Mineral composition

1012 - Poor very clay rich (>50% clay content)

1013 – No data


June 2016 I 136

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.

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.

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.

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.

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.


AAPG Bull., 70, 2, 103-130.


June 2016 I 137

T14 - Dinarides – Lemeš

General information


Screening-

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


June 2016 I 138



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


June 2016 I 139

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.


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).



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.


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.


Low Maturity in the early oil window (0.5-0.7% VRo) throughout the basin


June 2016 I 140


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

Mineral composition



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.


June 2016 I 141

T15a – Cantabrian Massif

General information


Screening-

Index

T15a Cantabrian

Massif E

Formigoso Fm Silurian 1032

Carboniferous

Formations Carboniferous 1031

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.


June 2016 I 142



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.


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.


June 2016 I 143

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.


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.


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.



Mapping status

Poor Only the general outline of the basin is known


Moderate to High Deposits are an alternation of continental and marine depositis


Moderate to High


June 2016 I 144

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


Unknown


Shallow to deep The depths of the formations are not well known, they are

estimated to lie between 0 and 6000m

Mineral composition


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.


June 2016 I 145

T15b – Basque-Cantabrian Basin

General information


Screening-

Index

T15b

Basque-

Cantabrian

Basin

E

Carboniferous

Formations Carboniferous 1030

Camino Fm. Lower Jurassic

(Liassic) 1027

Lower Cretaceous

Formations Lower Cretaceous 1028

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.



June 2016 I 146



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.


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.



Mapping status

Poor Only outlines for the basin are available, thickness and depth are not

known


Moderate to High Coals and coaly shales deposited in a marginal marine

environment form the potential shale gas rocks.


High


June 2016 I 147

HC generation

Available data

Moderate Few samples from two wells with TOC and Rock-Eval analyses

Proven source rock

Proven


Unknown


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.


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, over-

mature 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-


June 2016 I 148

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.



Mapping status

Poor Only outlines for the basin are available, thickness and depth are not

known


Low Laterally continuous hemipelagic type sedimentation


Moderate

HC generation

Available data

Moderate

Proven source rock

Possible Formation has been attributed to a known accumulation


Unknown


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


June 2016 I 149

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.



Mapping status

Poor


High Described formations are very thick with about 1-2% of the formations

have actual potential


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.


Unknown


June 2016 I 150


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



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 (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.


June 2016 I 151

T16 - Guadalquivir

General information


Screening-

Index

T16 Guadalquivir E

Guadalquivir

Carboniferous

shales

Carboniferous 1026

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.




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.


June 2016 I 152

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


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


June 2016 I 153

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


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


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.




June 2016 I 154

Mapping status

Poor


High Multiple subbasins with lateral and vertical facies changes


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


Unknown


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



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 (1987). Contribucion de la exploracion petrolifera al conocimiento de la geología

de España.


June 2016 I 155

T17 - Ebro

General information


Screening-

Index

T17 Ebro E

Carboniferous

shales Carboniferous 1024

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.




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.


June 2016 I 156

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.


Unknown



Mapping status

Poor


High


High

HC generation

Available data

Poor

Proven source rock

Unknown


Unknown

Recoverability


June 2016 I 157

Depth

Average Depth estimated between 1650 and 4000m

Mineral composition


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.


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.



Mapping status

Poor


High


June 2016 I 158


Low

HC generation

Available data

Moderate Detailed analyses on outcrop samples

Proven source rock

Unknown


Unknown


Shallow to Average Depth estimated between 0 and 3800m

Mineral composition


References







(ALGECO2). Volumen II-1- Cadena Pirenaica y Cuenca del Ebro. Geología.


June 2016 I 159

T18 - Duero

General information


Screening-

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.




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.


June 2016 I 160

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.


Unknown



Mapping status

Poor


High


High Intraplate basin with complex Mesozoic and Cenozoic evolution

HC generation

Available data


June 2016 I 161

Moderate Some samples available from wells

Proven source rock

Unknown


Unknown

Recoverability

Depth

Average Assumptions place the formations between 1000 and 2500m.

Mineral composition


References






June 2016 I 162

T19 – Iberian Chain

General information


Screening-

Index

T19 Iberian Chain E

Sierra de la

Demanda and

Aragonian Branch

Carboniferous 1022

Lower Cretaceous

shales

Lower Cretaceous

Cretaceous 1021

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.




The materials forming the Iberian System are mainly Mesozoic and Tertiary age,

although locally outcropping Paleozoic base materials integrated in the Alpine folding.


June 2016 I 163

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


June 2016 I 164

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


Unknown



Mapping status

Poor


Moderate


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


Unknown


Shallow to Average Assumptions place the formations between 0 and 2500m depth.

Mineral composition


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


June 2016 I 165

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.



Mapping status

Poor


High Deposited in coastal wetlands and shallow depositional environments


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


High Immature to overmature in different parts of the basin


Shallow Assumptions place the formation between 0 and 1000m depth.


June 2016 I 166

Mineral composition


References



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





(ALGECO2). Volumen III-1- Cadena Ibérica y Cuencas del Tajo y Almazán. Geología.


June 2016 I 167

T20 – Catalonian Chain

General information


Screening-

Index

T20 Catalonian

Chain E Catalonia shales Carboniferous 1020

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).




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.


June 2016 I 168

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


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.



Mapping status

Poor


High


High

HC generation

Available data

Poor

Proven source rock

Unknown


Unknown


Shallow to Average Estimated depth between 0 and 2000m.


June 2016 I 169

Mineral composition


References









(ALGECO2). Volumen III-1- Cadena Ibérica y Cuencas del Tajo y Almazán. Geología.


June 2016 I 170

T21 - Pyrenees

General information


Screening-

Index

T21 Pyrenees E

Liassic shale Lower Jurassic

(Liassic) 1033

Cabo Fm. Lower Cretaceous 1034

Burgui Fm. and

Vallfogona Fm. Eocene 1035

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.




The South-Pyrenean Basin is part of the Pyrenean range where Precambrian to

Cenozoic materials outcrop.


June 2016 I 171

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.


Some levels have locally 85 and 115 L/t of kerogen.

Chance of success component description (1033)


Mapping status

Poor


Moderate


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


Unknown


Average Estimated depth between 2000 and 4300m.

Mineral composition


June 2016 I 172

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


The TOC values of this Formation range between 0.5-1.74%.



Mapping status

Poor


Moderate


Moderate Located in the Bòixols thrust sheets

HC generation

Available data

Poor

Proven source rock

Unknown


Unknown



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


June 2016 I 173

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


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


June 2016 I 174

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


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.



Mapping status

Poor


Moderate


Low Deposited in synclines associated with thrust faults

HC generation

Available data

Moderate

Proven source rock

Unknown


Low Measurements show a maturity in the early oil window (0.5-0.7% Ro)



Mineral composition


References




June 2016 I 175

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







(ALGECO2). Volumen II-1- Cadena Pirenaica y Cuenca del Ebro. Geología.


June 2016 I 176

T25 - Northwest European Basin (Central Europe) – Mesozoic shales

General information


Index

T25a

Northwest

European

L.

Jurassic

NL Posidonia Shale Toarcian 1065

T25c

Northwest

German

Basin

D

Posidonien Schiefer Toarcian 2012*

Wealden Tithonian-Berriasian n/a*

Blättertone/Fischschiefer Barremian/Aptian n/a*

Mid Rhaetian shale Rhaetian n/a*

T25d

Weald

Basin SE

England

UK

Kimmeridge Clay Kimmeridgian-Tithonian

(Late Jurassic) 1070

Mid Lias Clay Pliensbachian 1074

Oxford Clay Oxfordian 1075

Upper Lias Clay Early Toarcian 1076

Corallian Clay Oxfordian 1078




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).


June 2016 I 177

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).


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


June 2016 I 178

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.


June 2016 I 179

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.


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.


Occurrence of shale

Mapping status






HC generation

Available data


June 2016 I 180


Proven source rock

Possible HC shows and accumulation in other setting probably from same SR



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).


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


June 2016 I 181

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).



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.


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.


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


June 2016 I 182

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


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


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.


June 2016 I 183

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.


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.


Occurrence of shale

Mapping status


datapoints)






June 2016 I 184

HC generation

Available data


Proven source rock




Recoverability

Depth


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.


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


June 2016 I 185

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.


Occurrence of shale

Mapping status






HC generation

Available data


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.


Moderate Low maturity in general, due to thickness of the formation, some

maturity variation with depth at one location

Recoverability

Depth

Shallow mainly <1000m


June 2016 I 186

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.


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.


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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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

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.

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.


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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.

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Ladage, S. et al. (2016) Schieferöl und Schiefergas in Deutschland – Potentiale und

Umweltaspekte. Bundesanstalt für Geowissenschaften und Rohstoffe (BGR), Hannover.



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.

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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.

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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


June 2016 I 190

T26 – Paris Basin and Autun Basin – Permo-Carboniferous and Jurassic shales

General information


Index

T26a Paris

Basin F

Promicroceras Late Pliensbachian 1082

Amaltheus Sinemurian 1083

Schistes Carton Toarcian 1084

T26b Autun

Basin F Autun Permian 1081

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.


June 2016 I 191



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.


The TOC content ranges from 0.2-0.9 wt% (Bessereau and Guillocheau, 1994).


Occurrence of shale

Mapping status


datapoints)






June 2016 I 192

HC generation

Available data


Proven source rock




Recoverability

Depth

Shallow to Average <1000m – 5000m

Mineral composition


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.


TOC ranges from 2-4 wt% with a maximum HI value of 130 mg HC/g TOC (Bessereau

and Guillocheau, 1994).


Occurrence of shale

Mapping status


datapoints)





HC generation

Available data


Proven source rock




June 2016 I 193


Recoverability

Depth


Mineral composition


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.


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).


Occurrence of shale

Mapping status


datapoints)





HC generation

Available data


Proven source rock





June 2016 I 194

Recoverability

Depth


Mineral composition


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.


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.


Occurrence of shale

Mapping status

Poor


High fluvio-lacustrine setting


High

HC generation

Available data

Poor

Proven source rock

Unknown


Unknown

Recoverability

Depth

Shallow < 1000m

Mineral composition



June 2016 I 195

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.


June 2016 I 196

T27 - Aquitaine

General information


Screening-

Index

T27 Aquitaine F Sainte Suzanne

Marls

Aptian

(Cretaceous) 1085

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.



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


June 2016 I 197

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.


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.



Mapping status

Poor No outlines provided


Low


Low and High Depending on the position in the basin.

HC generation

Available data

Poor

Proven source rock

Unknown


Unknown


Unknown

Mineral composition


June 2016 I 198


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


June 2016 I 199

T28 - South Eastern basin

General information


Screening-

Index

T28a South Eastern

basin F

Schistes Cartons

Fm Jurassic 1084

T28b Stephano-

Permian Basin F

Permo-

Carboniferous

Permo-

Carboniferous 1080

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.



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)


June 2016 I 200

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.


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.



Mapping status

Poor


High Assessment area includes multiple formations with highly variable

sedimentary setting.


June 2016 I 201


High Area consists of multiple small sub basins with different tectonic

histories.

HC generation

Available data

Poor

Proven source rock

Unknown


High


Unknown

Mineral composition


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.


The South-East Basin lacks precise and dedicated studies for unconventional

resources.



Mapping status

Poor


High Assessment area includes multiple formations with highly variable

sedimentary setting.



June 2016 I 202

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.


High


Unknown

Mineral composition


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.


June 2016 I 203

T30 – Lusitanian Basin, Portugal

General information


Screening-

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.


June 2016 I 204



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


June 2016 I 205

(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.


June 2016 I 206

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


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


June 2016 I 207

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.



Mapping status

Poor Only the outlines of the basin are available.


Moderate The whole succession is made up out of multiple formations with

different distributions within the basin.


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


Moderate Maturity varies between immature and gas mature


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.


June 2016 I 208

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.


June 2016 I 209

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.


June 2016 I 210

T31, T32 – Southern Germany – Mesozoic shales

General information


Index

T31 Molasse

Basin D Fish shale* Oligocene n/a

T32

Upper

Rhine

Graben

D Posidonien Schiefer* Toarcian (Jurassic) 2012

Fish shale* Oligocene n/a




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.


June 2016 I 211



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


June 2016 I 212

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.


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.


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.



Schumacher, M.E., 2002. Upper Rhine Graben: Role of reexisting structures during rift

evolution. Tectonics 21(1), 6-1 – 6-17.

http://www.bgr.bund.de/DE/Themen/Energie/Downloads/Abschlussbericht_13MB_Schieferoelgaspotenzial_Deutschland_2016.html

http://www.bgr.bund.de/DE/Themen/Energie/Downloads/Abschlussbericht_13MB_Schieferoelgaspotenzial_Deutschland_2016.html


June 2016 I 213

T34 - Midland Valley Scotland

General information


Screening-

Index

T34 Midland Valley

Scotland UK

Gullane Visean 1079

Limestone Coal

Fm Serpukhovian 1071

West Lothian Oil

Shale unit Visean 1072

Lower Limestone

Fm Visean 1073

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.


June 2016 I 214

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.



The prospective Midland Valley of Scotland units were deposited in lacustrine, fluvio-

deltaic 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.


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.


June 2016 I 215

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.


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.


June 2016 I 216

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 fluvio-

deltaic 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.


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.



June 2016 I 217


Mapping status

Good Depths maps based on seismic interpretation and well logs area

available for all formations as well as shale percentage maps


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.


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


High Several past burial events as well as magmatic intrusions cause high

variability of the organic matter maturity


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.


June 2016 I 218

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.


June 2016 I 219

T35 – Czech Republic – Lower Carboniferous shales of the Culm Basin



Index

T6 Culm Basin CZ Lower Carboniferous

shales and siltstones

Lower

Carboniferous 1086

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.


June 2016 I 220


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,


June 2016 I 221

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.


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).


June 2016 I 222

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.


Moderate Sedimentary modelling can be applied to enhance the current status of

lithological trends.


Moderate The basin experienced burial and uplift. The prospective area is outside

the thrust-and-fold belt.


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.


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.


June 2016 I 223

Andrews I.J., 2013. The Carboniferous Bowland Shale gas study: geology and


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)


June 2016 I 224

T36 - Caltanissetta Basin (Italy) – Messinian shales

General information


Index

T36 Caltanissetta I Sapropelic marls/Tripoli

early

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.


June 2016 I 225



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).


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


June 2016 I 226

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).


Occurrence of shale

Mapping status

Poor No map, only outlines


Moderate Due to structural complexity difficult to determine


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


High Heavenly folded and a huge range in depths probably lead to very small

and scattered sections that reached maturity.

Recoverability

Depth

Shallow <1000m

Mineral composition



fraccability




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.


June 2016 I 227

B01 - Transilvanian Basins – Neogene Shales

General information


Index

B1 Transilvanian Basin

RO Upper

Badenian Miocene 1041

RO Lower

Sarmatian Miocene 1042

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.



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


June 2016 I 228

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


June 2016 I 229

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).


June 2016 I 230

Figure 2 Structural map with isochronous (ms TWT) – top of the Middle Badenian


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.


June 2016 I 231


Occurrence of shale

Mapping status

Moderate Depth map in time available for the Middle Badenian


Moderate



HC generation

Available data

Poor no data

Proven source rock

Possible Biogenic HC accumulations known, source rock unit unclear.


Immature Biogenic system

Recoverability

Depth

Average to Deep

Mineral composition


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.

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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,

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