mmmll Draft Report for DG JRC in the Context of Contract JRC/PTT/2015/F.3/0027/NC "Development of shale gas and shale oil in Europe" European Unconventional Oil and Gas Assessment (EUOGA) Geological resource analysis of shale gas and shale oil in Europe Deliverable T4b
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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
Geological resource analysis of shale gas/oil in Europe
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
Geological resource analysis of shale gas/oil in Europe
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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.
Geological resource analysis of shale gas/oil in Europe
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.
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Abstract Within task 4 of the EUOGA Project the geological descriptions of the different basins
within Europe and the potential shale gas targets in the basin were collected and
summarized. A general template for the description was developed, and, based on the
information provided by the National Geological Surveys (NGS), completed for each
submitted basin and formation. In addition to the geological descriptions, general
hydrocarbon play indicators were assessed in order to indicate whether a shale
formation is present and whether it contains technically recoverable hydrocarbon
resources (hereafter: chance of success). This assessment was performed in a
consistent and uniform manner for each formation and involved a semi-quantitative
scoring of critical data for assessing (1) the presence and characteristics of the shale
formation, (2) overall sedimentological and structural complexity influencing
hydrocarbon generation and distribution, (3) the probability of an existing shale
gas/oil system (organic content, maturity, proven hydrocarbon generation) and (4)
geological factors influencing the technical recoverability of hydrocarbon resources
contained in the shale (depth of the formation and mineralogical composition). The
results from Task 4 are used as a basis for the quantitative volume assessment of
potential shale hydrocarbon resources under Task 7.
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Executive Summary Task 4 delivered the geological descriptions and unconventional hydrocarbon play
characteristics of 82 shale formations occurring within 38 sedimentary basins across
Europe. National Geological Surveys (NGS) participating in the EUOGA project
provided all public data and information available from their respective countries,
using a common description template developed by the EUOGA project team
members. Further input was obtained from the data retrieval under Task 5 and Task
6.
The analysis of the basins includes (1) the general description of the basins and
formations, (2) the link to the CP sheets (Screening_ID) and the GIS environments
generated in Tasks 5 and 6, (3) the geographical extent of the basin, (4) the assessed
formations within the basin (in figure), (5) a brief description of the depositional and
structural setting of the basin, (6) a description of the individual shale formations in
the basin, with depth, thickness and shale gas/oil properties, and (7) a chance of
success assessment.
The chance of success assessment describes all formations in a semi-quantitative
scoring on the distribution of the shale, the hydrocarbon system and the recoverability
of the resources. It focuses on the presence and characteristics of the shale formation,
overall sedimentological and structural complexity influencing hydrocarbon generation
and distribution, the probability of an existing shale gas/oil system (organic content,
maturity, proven hydrocarbon generation) and geological factors influencing the
technical recoverability of hydrocarbon resources contained in the shale (depth of the
formation and mineralogical composition).
The availability and quality of information as well as the level of knowledge regarding
shale formations and prospective hydrocarbon resources therein, differs greatly per
basin and per country. Overall some 78% of the formations are considered to be
reasonably well understood with fair to good information coverage. In these cases
there is often a good indication that mature and gas/oil-bearing shales are present.
The reliability and accuracy of the analysis of chance of success also strongly depends
on the completeness and quality of the basin descriptions, but also on how well these
descriptions can be translated into the specified categories. The certainty by which the
presence of a shale can be predicted is strongly depending on the available
information from wells and seismic. In mature hydrocarbon provinces the data density
is generally high enough to accurately map the outline of a prospective shale
formation. However, in many of the underexplored regions the exact outline of the
formation is less well established, especially when the shale distribution within the
given outline is known to be heterogeneous. The presence of a mature and 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.
Geological resource analysis of shale gas/oil in Europe
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Introduction This report presents the first standardized geological descriptions for the countries
where information was available. The general geological description of the shale gas
and oil layers that were submitted by the individual geological surveys are compiled
and standardized. These descriptions have been circulated back to the geological
surveys for confirmation and correction.
Special focus is set on the description of so called risk-components that is
incorporated into the final assessment of the layers. In this first step the overall
chance of success of the shale layer as well as the presence of mature organic matter
is incorporated.
Figure 1 Overview of the sedimentary basins of Europe and the basins assessed in the EUOGA project. The T-numbers are the basin identifyers for each basin (see table 1). For some of the asessed units no outline is available.
Geological resource analysis of shale gas/oil in Europe
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Table 1 Overview of the described basins and shale formations in this report
T33 DE Northern Germany 2013 Hangender Alaunschiefer and Kohlenkalk-Facies
T34 UK Midland Valley Scotland 1071 Limestone Coal Fm
1072 West Lothian Oil Shale unit
1073 Lower Limestone Fm
1079 Gullane Unit
T35 CZ Culm Basin 1086 Culm Shale
T36 IT Caltanissetta Basin 0 Sapropelic marls/Tripoli
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Item 4.1 Setup and distribute a template for uniformly describing EU shale plays to the National Geological Surveys
Basin Index – Basin name – Shale name
General information
Table 4.1 The general information is compiled together with GEUS (Task 5 and 6)
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
Geological resource analysis of shale gas/oil in Europe
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hydrocarbon fields that are sourced by the shale? Where are these located within the
basin? Are there any gas shows on logs of the shales? What is the maturity of the
shale? How does the maturity change throughout the basin? Is the system biogenic or
thermogenic?
Chance of success component description
In the chance of success component description the previously described depositional
and structural setting as well as shale properties are summarized and categorized for
the general assessment. The subdivision in these categories gives a general overview
of the success factors associated with the shale gas/oil system. In the final report of
WP 4 a summary table with the categories for all assessed shales is presented. This
overview gives a general idea of the type of shale, its complexity and amount of data.
This is used to categorize and compare the overall uncertainty that is associated with
the assessment. For example shales with little data and high structural complexity
have a high chance of not containing any gas compared to shales with a large amount
of data, good seismic interpretation and known HC content and mineral composition.
The results of this classification are also taken into account in the final GIIP/OIIP
calculation, where few data/low chance of success shales are assigned a higher range
of values and therefore a higher uncertainty.
Occurrence of shale
Mapping status
Poor no map, only outlines
Moderate depth map, thickness map based on interpolation/average values (few
datapoints)
Good seismic interpretation, interpolated map (many datapoints)
Sedimentary variability
High very strong local differences, difficult to predict
Moderate depositional environment changes gradually throughout the basin
Low very homogeneous character throughout the basin
Structural complexity
High thrust setting, mountain belt, drastic compression
Moderate layer faulted, locally eroded, subsidence, uplift and salt tectonics
Low layer cake setting, predominantly steered by subsidence
HC generation
Available data
Poor no data
Moderate few data points (< 20)
Good good database (>20)
Proven source rock
Unknown no information
Possible HC shows and accumulation in other setting probably from same SR
Proven HC fields in study area proven to be sourced from shale gas layer
Maturity variability
High high local maturity variations (related to excessive faulting or
magmatism)
Moderate basin wide trends related to present or past burial depth variations
Low very similar maturity throughout the basin
Geological resource analysis of shale gas/oil in Europe
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Recoverability
Depth
Shallow <1000m
Average 1000-5000m
Deep >5000m
Mineral composition
No data average mineral composition was not provided
Unknown average mineral composition does not allow any assumptions on
fraccability
Favourable brittle mineral composition (>80% carbonates and/or quartz), fracturing
tests, log interpretation
Poor very clay rich (>50% clay content)
References
All relevant literature references for the basin
Geological resource analysis of shale gas/oil in Europe
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Item 4.2 Elaborate and compile general and systematic descriptions of the shale plays from the NGS responses
Geological resource analysis of shale gas/oil in Europe
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T01, B02 - Norwegian-Danish-S. Sweden – Alum Shale
General information
Index Basin Country Shale(s) Age Screening-
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.
Geological resource analysis of shale gas/oil in Europe
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Figure 2 Terranes amalgamated to form Laurussia. Non-palinspastic map after Pharaoh et al. (2010) and sources therein. Note that the Rheno-Hercynian Zone is interpreted as the Variscan-deformed southern margin of Laurussia.
Geological evolution and structural setting
Syndepositional setting
The sediments of the Alum Shale formation were deposited in an epicontinental sea at
the passive margin of Baltica during Middle Cambrian to Early Ordovician opening of
the Iapetus/Tornquist Ocean. During maximum flooding in the Early Ordovician,
organic-rich intervals were deposited over an area of more than 1,000,000 km2
(Nielsen and Schovsbo, 2011). Deposition was influenced by synrift extentional
tectonics. The Alum organic-rich shales mainly represent an outer-shelf environment
shale and are intercalated with some limestone and antraconite interbeds. Generally,
lateral continuity is high and facies variability low.
Structural setting
During the Early Ordovician, Avalonia drifted away from Gondwana (Trench & Torsvik,
1992), northwards in connection to opening of the Rheic Ocean (Cocks & Fortey,
1982) to the south of Avalonia. Subduction of the Iapetus/Tornquist Ocean in a
number of southerly dipping subduction systems also triggered this drift (Figure 2).
Evidence of the subduction of oceanic crust of the Iapetus/Tornquist Ocean beneath
Avalonia is shown by the Middle to Upper Ordovician calc-alkaline volcanic rocks found
in England and Belgium (Pharaoh, 1999). During Llandovery and Wenlock times, the
Tornquist Ocean, initially characterized as a passive margin of Baltica, evolved into a
major subsiding foreland basin north of the Silurian Avalonian-Baltica convergence
zone (Schovsbo, 2003) and the Danish-North German-Polish Caledonides. Basin
Geological resource analysis of shale gas/oil in Europe
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.
Geological resource analysis of shale gas/oil in Europe
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Shale gas/oil properties
The Alum Shale contains a marine type II kerogen that yields lighter hydrocarbons on
maturation than typical type II kerogen (see Sanei et al., 2014 for a recent review). In
most areas thick overlying successions of sedimentary strata buried the Alum Shale
(and other lower Palaeozoic shales) to depths of 4 to 5 km, bringing them to thermal
maturity for oil and gas (greater than 2-percent graptolite reflectance; 1.6-percent Ro,
vitrinite reflectance-equivalent maturity, Buchardt and others, 1997; Petersen and
others, 2013). It is assumed that, given the thickness and richness of the shales
(TOC’s up to 17%), this burial history resulted in the generation of large volumes of
hydrocarbons. A TOC loss with maturity appears to exists (Schovsbo et al., 2014) as
immature shales have average TOC’s of 8-12% (H/C high), whereas shales in the dry
gas window have TOC’s between 6-8% (H/C low).
Gas content are about 30 scf/ton in exploration wells in Scania and nortern Denmark
(Ferrand et al. 2016; Pool et al. 2012). In scientific wells both termogenic and
biogenic gas has been observed (Schultz et al. 2015; Schovsbo & Nielsen 2017).
The prospective areas, based on thickness and burial depth (Schovsbo et al., 2014,
their Fig. 3) largely follow the margins of the Norwegian–Danish Basin. Sweet spots
were defined as fault blocks that contain Alum Shale thicker than 20 m, gas mature
and within a current depth interval of 1.5–7 km. Additionally, the probability of gas
retention within is regarded highest if the shale is overlain by more than 1 km of
Palaeozoic strata, i.e., areas that underwent less intensive Late Palaeozoic uplift and
erosion (Schovsbo et al. 2014).
Chance of success component description
Occurrence of shale
Mapping status
Moderate
Sedimentary Variability
Low Deposited in an epicontinental sea at the passive margin of Baltica.
Structural complexity
High The development of a thrust-and-fold belt and its successive movement
over the south-west margin of Baltica led to further subsidence and
synsedimentary compressive tectonics in the foreland generating thrusts
and faults in the Alum Shale Formation.
HC generation
Data availability
Moderate
HC system
Possible Few proposed accumulations in offshore Poland and Gotland. Alum
Shale drilled in Northern Jutland in 2015. According to industry report
the shale was thinner than expected (40 m) and had a low gas content
of 30 scf/ton.
Maturity variability
Moderate
Geological resource analysis of shale gas/oil in Europe
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.
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)
Geological resource analysis of shale gas/oil in Europe
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Chance of success component description
Occurrence of shale layer
Mapping status
Unknown Only outlines of the assessment unit were provided
Sedimentary variability
Moderate
Structural complexity
High along the southern margin of the basin, moderate in the centre of the
basin
Generation of HC system
Data availability
Moderate
HC system
Possible
Maturity variability
Moderate
Recoverability
Depth
Average Between around 1000m in the easternmost part to more than 4500m in
the west.
Mineral composition
Unknown
Early Ordovician Shales (Zebrus Formation, Latvia)
The lowermost part of the sequence locally includes thin dark shale beds (Weiss et al.,
1997). Zebrus Formation is widespread in all the Baltic Syneclise.
Geological resource analysis of shale gas/oil in Europe
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Figure 3 Distribution of the prospective area of the Zebrus Formation
Depth and Thickness
Thickness of the Ordovician succession in Latvia`s onshore area varies from 42 m (in
the northeast and northwest part of Latvia) to 257 m (in the central and southeastern
part of Latvia). Thickness of the Ordovician succession in Latvia`s offshore area varies
from 74 m to 146 m (Brangulis et al., 1998). The thickness of the Zebrus formation is
2-50 m (data from DB “Urbumi”) and it is situated at more than 1500 m depth.
Shale oil/gas properties
Unknown
Chance of success component description
Occurrence of shale layer
Mapping status
Moderate Thickness and depth map available
Sedimentary variability
Moderate
Structural complexity
Moderate
Generation of HC system
Data availability
Poor
HC system
Possible On- and offshore exploration wells have encountered oil and oil shows,
no production.
Geological resource analysis of shale gas/oil in Europe
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Maturity variability
Unknown
Recoverability
Depth
Average 1000-5000m
Mineral composition
Unknown
Late Ordovician Shales (Sasino shale formation, Poland; Fjäcka and Mossen
formations in Lithuania)
The Upper Ordovician shale, mainly Caradoc, developed in the central and western
part of the Baltic Basin, as well as in the western part of the Podlasie Depression. In
the north-western part of the Baltic-Podlasie-Lublin Basin, i.e. at the Łeba Elevation,
the onset of organic rich sediment deposition was even earlier, during late Llanvirn.
The deposition was diachronically expanding in time towards east and south-east,
systematically replacing laterally limestone and marl deposition with claystone and
siltstone (Modliński and Szymański, 1997; Poprawa, 2010). During Ashgill time
eustatic sea level drop caused expansion of the carbonate sedimentation into all the
here discussed basins, except of the Łeba Elevation where organic rich shale
deposition continued. The Polish name for the Upper Ordovician shale is Sasino shale
formation (Poprawa, 2010) and it could be likely correlated with Caradoc-Ashgill
shales in southern Scandinavia (Schovsbo, 2015; Fjäcka and Mossen formations) and
Lithuania (Lazauskienė, 2015) depending on maturity, TOC and other parameters.
Depth and Thickness
In the central and eastern part of the Baltic Basin (Lithuania and Latvia) the potential
source rocks comprises dark grey and black shales of the Late Ordovician Late
Caradoc-Early Asghill (Katian) Fjäcka and Mossen formations. Both units are generally
thin, reaching only up to 5–10 m; the average thicknesses of Fjäcka and Mossen
Formations are 6 m and 4 m respectively.
Thickness of the Upper Ordovician shale (Sasino shale formation) increases from the
east towards the west and north-west: in the onshore Baltic basin from 3.5 m to 37 m
with an average of about 20 m (Modliński and Szymański, 1997; Modliński, 2010;
PGI-NRI, 2012), In the Podlasie Depression and the basement of Płock-Warszawa
Trough the thickness ranges from 1.5 m to 52 m with an average of about 30 m
(Modliński and Szymański, 2008; Modliński, 2010; PGI-NRI, 2012).
Shale oil/gas properties
In the Lithuanian area TOC contents are mostly in the 0.9 to 10 % range, with
occasional higher values of up to 15 %. Oil and gas generation potential averages are
22 kg HC/t rock, rarely reaching 55–70 kg HC/t rock. Hydrogen Index reaches up to
521 mg HC/g TOC, Tmax is around 424°C (Zdanaviciute, Lazauskiene, 2004, 2007,
2009). The source rock facies is of kerogen type II, reflecting marine conditions.
Thermal maturity of the organic matter is between less than 0.7 and more than 1.5 %
reflectance of Vitrinite equivalent.
Geological resource analysis of shale gas/oil in Europe
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Figure 4 Thermal maturity of the organic matter in the central part of the Baltic Basin (Lithuania, Lazauskiene et al. 2014)
The individual wells on the Polish part of the onshore Baltic Basin have an average
TOC content of 1 % to 3.5 % with an average of about 1.5% (Poprawa, 2010;
Więcław et al., 2010). The highest TOC values were measured in the area of the Łeba
Elevation where organic rich shales are present both in the Caradoc and (especially)
the Ashgill (Więcław et al., 2010). In the western and central part of the Podlasie
Depression the average TOC content of the Upper Ordovician shale is between 1 %
and 1.25 % (Poprawa, 2010), while in the basement of the Płock- Warszawa Trough it
ranges between 2.1 to 3.76 % TOC (Poprawa, 2010). In the Lublin region the average
TOC of the Early Ordovician sediments is less than 1 % (Poprawa, 2010).
Chance of success component description
Occurrence of shale layer
Mapping status
LT: Good Thickness and depth map available
P: Unknown Only outlines available
Sedimentary variability
Moderate Facies changes within the Baltic Basin depending on the depositional
setting
Structural complexity
LT: Moderate
P: High In the centre of the Basin getting more complex towards the basin
margins, especially along the thrust front along the TTZ.
Generation of HC system
Geological resource analysis of shale gas/oil in Europe
June 2016 I 31
Data availability
Moderate
HC system
Possible
Maturity variability
Moderate
Recoverability
Depth
Shallow to Average
Mineral composition
Unknown
Early Silurian Shales (Llandovery – Pasłęk formation, Poland; Raikiula-
Adavere formations, Lithuania)
During the Early Silurian the eustatic sea level rise caused widespread deposition of
organic rich shale (PGI-NRI, 2012). The Llandovery (organic rich) siltstone and
claystone sediments are present throughout most of the basin with the exception of
the south-eastern Lublin region (Poprawa, 2010, Schovsbo, 2015, Lazauskienė, 2015).
The bottom part of the Llandovery is often represented by an organic rich bituminous
shale (Poprawa, 2010). In the eastern part of the Baltic Basin the lower Llandovery
bituminous shale is locally replaced by a black nodule limestone (Jaworowski &
Modliński, 1968). The Polish name for Llandovery claystones is Pasłęk shale formation
and the organic rich lower Llandovery is called Jantar bituminous shale member
(Poprawa, 2010). The lateral equivalent of the Pasłęk shale formation in southern
Scandinavia consists of predominantly siltstones and therefore is not considered to
have shale gas potential. (Schovsbo, 2015) while the Lithuanian Llandovery Raikiula-
Adavere formations (Lazauskienė, 2015) is considered to be the lateral equivalent. In
the south-eastern Lublin region where Poland borders with Ukraine no Llandovery
sediments were preserved due to a hiatus (Poprawa, 2010).
The Middle-Upper Llandovery succession in Lithuania is composed of dark grey and
black graptolite shales and dark grey and black clayey marlstones.
Depth and Thickness
The thickness of the Llandovery clay facies (Pasłęk formation) in Poland ranges
between 10 and 70 m, and is most often between 20 to 40 m generally increasing
towards the west (Modliński 2010; PGI-NRI, 2012). The average value for the is about
40 m in the northern part of the Baltic Basin, 20 m in the centre and around 30 m in
the Podlasie and Lublin basins (according to maps in Modliński, 2010; also there is a
hiatus in SW part of the Lublin Basin).
The thickness of the Raikiula-Adavere formations in Lithuania is between 15 and 80m
thick. It is located at depth between 1500 and 2100m.
Shale oil/gas properties
Within the Lithuanian part of the Baltic Basin organic matter content generally ranges
from 0.7 to 9–11%, but can be as high as 16.46 % (Zdanaviciute, Lazauskiene,
2004). Oil and gas generation potential of this source rock complex in the central part
Geological resource analysis of shale gas/oil in Europe
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).
Chance of success component description
Occurrence of shale layer
Mapping status
LT: Moderate Total Lower Silurian depth and thickness map available
P: Unknown Only outlines were provided
Sedimentary variability
Moderate Large scale facies changes within the Baltic Basin depending on the
depositional setting
Structural complexity
LT: Moderate
P: High In the centre of the Basin getting more complex towards the basin
margins, especially along the thrust front along the TTZ.
Generation of HC system
Data availability
Moderate
HC system
Possible
Maturity variability
Moderate
Recoverability
Depth
Average Around 1000m in the centre of the basin to more than 4500m in the
south.
Mineral composition
Geological resource analysis of shale gas/oil in Europe
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).
Shale oil/gas properties
Average TOC contents in a range of 1 % to 2 % are characteristic for the Wenlock
sediments in the eastern Baltic Basin, as well as in a part of Podlasie Depression and
Lublin region (generally increasing from NW to SE). In a remaining part of the study
area the average TOC content of the Wenlock sediments is less than 1 % (Poprawa,
2010). All of these values are measured on homogenized samples from thick rock
complexes so it is possible that there are shale layers with higher TOC contents within
the Wenlock (Poprawa, 2010).
Chance of success component description
Occurrence of shale layer
Mapping status
Unknown Only outlines provided
Sedimentary variability
Moderate
Structural complexity
Moderate to high
Generation of HC system
Data availability
Moderate
HC system
Unknown
Maturity variability
Moderate
Recoverability
Depth
Geological resource analysis of shale gas/oil in Europe
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
Geological resource analysis of shale gas/oil in Europe
June 2016 I 63
T06 - Poland – Lower Carboniferous shales of the Fore-Sudetic Monocline Basin
General information (see excel table from GEUS)
Index Basin Country Shale(s) Age Screening-
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.
Geological resource analysis of shale gas/oil in Europe
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).
Geological evolution and structural setting
Syndepositional
The Lower Carbiferous shales of the FSMB (actually claystones, siltstones and
mudstones, accompanied by sandstones, coals and carbonates), are associated with
the development of depositional facies in the Variscan flysch basin in Visean and
Namurian A. They are the source rocks in case of Rotliegend conventional and tight
gas fields in the Polish Southern Permian basin (Wójcicki et al., 2014). These source
rocks contain organic matter mostly of a humic nature gas-prone Type III kerogen of
a non (deep) marine origin and, rarely, mixed Type II/III kerogen (Botor et al., 2013).
The Lower Carboniferous shales of the FSMB might be an equivalent of Lower
Carboniferous black shales (Culm) in Northwest German Basin (Ladage and Berner,
2012), and, to some extent, Lower Carboniferous Bowland shales in northern England
(Andrews, 2013). However, there is no direct connection between Polish and German
plays.
Structuration
The Lower Carboniferous flysch complex in question (Culm) is characterized by a
complicated tectonic setting of fold and thrust deformations (Mazur et al., 2003;
Wójcicki et al., 2014), which makes it difficult to recognize the regularities governing
their natural cracks. It was uplifted in Late Carboniferous to Early Permian, when
volcanic activity peaked, then a substantial burial in Mesozoic occurred, and in Late
Geological resource analysis of shale gas/oil in Europe
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.
Shale gas/oil properties
Prospective formations of Lower Carboniferous within the FSMB (Fig 1) occur within
gas window (1.1<=Ro<3.5) only. Values of key reservoir parameters are based on
information available in publications and presented in Table 1.
Thermal maturity of Lower Carboniferous shales in the area of the FSMB increases
towards SE, NW and N (Botor et al., 2013), and generally ranges within the
assessment unit between 1.1-3.0 % (wet and dry gas window). In southern and
northernmost part of the area the Lower Carboniferous shales exhibit highest maturity
values, while lowest maturity is found in the central part. Average TOC content is in a
range of 1 % to 2 % (Botor et al., 2013).
The Lower Carboniferous shales of the FSMB are characterized by a wide range of clay
content (25 - 66 %), porosity (1.36 - 8.10 %; average 3.7 %) and gas saturation of
pore spaces (30-80 %; San Leon, 2012). In Siciny 2 well the average TOC of clean
Lower
Paleozoic shales is about 1.55 % (range 1,2-3.25 %; San Leon, 2012). There is no
published information regarding the share of shales with TOC>2%. Therefore the
effective thickness of prospective shales in the FSMB is set to the value of net
thickness proposed by EIA (2013, 2015), which is estimated to be 55 m. However, as
an average value of TOC in this play, a value halfway between the threshold (2.0%)
and the maximum value (3,25 %), i.e. 2.63 %, seems to be more likely than the
value assumed by EIA (2013, 2015), i.e. 3 %. This may result in a reduction of
effective thickness.
Assuming average porosity and median value of gas saturation obtained in case of
Siciny 2 well (San Leon, 2012), average gas filled porosity can be estimated as about
2 %. Average value of adsorbed gas content (Langmuir isotherm/sorption capacity)
1.25 m3/t (average of values measured in 15 US shale basins) and average density of
shale 2.6 kg/m3 (Andrews, 2013) can be ascertained provisionally. According to San
Leon press release (San Leon, 2012) a slight overpressure was registered in Lower
Carboniferous shales in Siciny 2 well.
Geological resource analysis of shale gas/oil in Europe
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.
Sedimentary variability
High
Structural complexity
Moderate to High Fold and thrust deformation as well as younger phases of
extensive subsidence and uplift
Hydrocarbon generation
Available data
Moderate Only very little data is available to determine the distribution of TOC and
maturity.
Proven source rock
Proven The FSMB does contain a proven gas system which is sources from the
Lower Carboniferous.
Maturity variability
Moderate Regional trends suggest it improves in SE, NW and N direction.
Recoverability
Depth
Average 1000-5000m
Mineral composition
Unknown average mineral composition does not allow any assumptions on
fraccability
References
Andrews I.J., 2013. The Carboniferous Bowland Shale gas study: geology and
resource estimation. British Geological Survey for Department of Energy and Climate
Change, London, UK.
Andrews, I.J., 2014. The Jurassic shales of the Weald Basin: geology and shale oil and
shale gas resource estimation. British Geological Survey for Department of Energy and
Climate Change, London, UK.
ARI (Advanced Resources International Inc)., 2009 Vello A. Kuuskraa, Scott H.
Stevens, Advanced Resources International "Worldwide Gas Shales and
Unconventional Gas: A Status Report, December 2009. Report for EIA (Energy
Information Administration: Washington, DC.), Annual Energy Outlook. 2009.
Geological resource analysis of shale gas/oil in Europe
June 2016 I 76
T07b - Hungary – Tard Clay, Hungarian Palaeogene Basin
General information (see excel table from GEUS)
Index Basin Country Shale(s) Age Screening-
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
Geological resource analysis of shale gas/oil in Europe
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.
Geological evolution and structural setting
Syndepositional setting
Until the Ottnangian the HPB was divided by the SW-NE directed Buda lineament, a
major treshold-like paleorelief element (Báldi and Nagymarosy 1976). The term
"Palaeogene Basin" is used here in a wider sense: it comprises all the sedimentary
sequences of this area ranging from the Middle Eocene up to the Early Ottnangian.
These sequences form a single great sedimentary cycle, and there is no sense in
subdividing them artificially. The simplified lithostratigraphic chart of the HPB can be
found in Haas (2012).
In Early Oligocene times the Late Eocene sedimentation was followed by the so-called
"intra Oligocene denudation" in the area W of the Buda Line (Zala Basin, Bakony,
Gerecse, Dorog-Esztergom Basin). The area northwest of the Buda Line was uplifted
and denudation removed the top part (locally also even the lower part) of the Eocene
sequences in the largest part of the Transdanubian Range. Southeast of the Buda Line
sedimentation continued into the Oligocene. During the Kiscellian the HPB became a
stagnant, restricted basin. The seaways toward the Mediterranean were shut off due
to the orogeny in the South Alpine-Dinaridic belt. Its northern connection to the global
marine system had been temporarily closed due to the uplift of the Rhenodanubian
Flysch-Magura Flysch Belt. All of these processes might have been combined with a
third or second-order eustatic sea level drop between 30 and 32 Ma (Baldi 1986;
Nagymarosy 1993; Nagymarosy et al. 1995) and led to the formation of the anoxic
Tard Clay Basin. The anoxic environment that existed during the Early Oligocene
marks the birth of the Paratethys (Schulz et al. 2005; Piller et al. 2007). Black shales
were formed everywhere in the Alpine foreland, the Carpathian Flysch troughs, the
Hungarian and Transylvanian Palaeogene Basins. Menilites were formed in the
Carpathians. The early Kiscellian (NP 21 to NP 23 nannoplankton zones) in Hungary is
characterised by extremely low depositional rates (30-50 m/Ma) is associated with the
deposition of anoxic black shale (Tard Clay) which reaches a thickness of ca. 80-100
m in the southern belt of North Hungary. The Tard Clay records a five million year long
anoxic cycle initiated by isolation of the sea. This anoxia may have been a
consequence of the first separation of the Paratethys, as indicated by the first
appearance of Paratethys-endemic molluscs: Cardium lipoldi, Ergenica cimlanica,
andfanschinella sp. (Báldi 1986; Popov et al. 1985; Nevesskaja et al. 1987). In the
Tard Clay white laminae of monospecific calcareous nannoplankton assemblages
alternate with black sapropel indicating probably brackish water conditions
(Nagymarosy 1983; Rogl 1998). After the restricted basin conditions of the Tard Clay,
normal marine conditions were restored by the Upper Oligocene (Late Kiscellian, NP
24 nannoplankton zone). The pelagic and bathyal Kiscell Clay was deposited in some
places in a thickness up to 700-800 m. East of Budapest, the lower member of the
Kiscell Clay contains frequent sandstone interbeds which are locally of turbiditic
character.
Structural setting
The Tard Clay was deposited in the Hungarian Palaeogene Basin, which developed
during Eocene and Early Oligocene times as a wrench-basin (Nagymarosy, 1990) or a
retro-arc fore deep (TARI et al., 1993) due to the convergence between the Apulian,
Pelso and Tisza microplates and the European plate. The Hungarian Palaeogene Basin
Geological resource analysis of shale gas/oil in Europe
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)
Shale gas/oil properties
The sedimentological and geochemical characterization of the Tard Formation has
been described by BRUKNER-WEIN et al. (1990); VETŐ and HETÉNYI (1991); VETŐ et
al. (1999), dealing with the Tard Clay profile penetrated by the Alcsútdoboz-3 (Ad-3),
Cserépváralja-1 (Cs-1) scientific; and Nagykökényes-I (Nk-I) and Veresegyháza-1(V-
1) exploration wells. The uppermost part and the lower half of the Tard Clay are of
marly lithology without lamination, while the bulk of its upper half is dominated by
silty lithology and shows well-developed lamination. The silty and well-laminated part
of the formation contains up to 60% clay minerals, while their amount ranges between
30 and 40% in the marly lithologies. Smectite makes up about 30-40% of the clay
minerals (Viczián pers. comm. in BADICS and VETŐ 2012).
Kerogen in the Ad-3 section is clearly immature with T-max values mostly below 425
C. In the 93 samples analyzed the TOC ranges between 0.41 and 4.98%, with an
average of 2.21% (Fig. 18a). The net source rock (>1%TOC) is about 40-50% of the
formation thickness based on the Rock-Eval data from the mentioned wells.The S2
average is 6.47 mg HC/g rock; the HI 252 mg HC/g TOC(Fig. 18c). On the TOC vs S2
plot the immature Tard Clay samples are divided into two groups. Silty samples and
those from the upper marly interval contain reactive kerogen, rich in hydrogen; the
slope of the best-fit line gives HIo (sensu Jarvie et al.,2007) of 433 mg HC/g TOC.
This finding agrees well with the high abundance of algae in the palynological residue.
The reactive kerogen of the lower marly interval is relatively poor in hydrogen as
witnessed by the flatter slope of the best-fit line. Samples from two other immature
sections (Cs-1 and V-1) plot to the same area as the Ad-3 samples, so 433 mg HC/g
TOC seems to be a good approximation of the HIo for the upper part of the Tard Clay
in the whole Palaeogene Basin. The Nk-I exploration well penetrated a mature Tard
Clay section between 2930 and 3020 m, characterized by T-max values >430 C. TOC
ranges between 1.1 and 3.2%.These values are much below those from the Ad-3 well,
as the Tard Clay has realized a significant part of its hydrocarbon potential at this well
location (BADICS and VETŐ 2012).
The observed present-day surface heat-flow in the Palaeogene Basin is 80-110
mW/m2 (DÖVÉNYI, 1994). The 3D model of BADICS and VETŐ (2012) was calibrated
to match the measured temperature and vitrinite reflectance data in 12 wells. The
heat-flow history and the estimated erosion maps used as input could result in an
uncertainty of the calculated maturity values of 0.2% Ro. According to 3D regional
basin model of BADICS and VETŐ (2012), the section is immature above 1300 m, oil-
mature (defined as 0.6-1.3% Ro) between 1300 and 3000 m and gas-mature (defined
as >1.3% Ro) below 3000 m, but large local variations exist due to extensive Early
and Middle Miocene volcanism. The deepest part of the Tard Clay is at 220-250 C
temperature in the dry gas generation zone today in the central part of the basin,
north of Nk-I. Between the Demjén and Mezőkeresztes fields in the north-east it is
Geological resource analysis of shale gas/oil in Europe
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.
Sedimentary variability
Low very homogeneous character throughout the basin
Structural complexity
Low The HPB was characterized by essentially continuous sedimentation
from Late Eocene to Middle Miocene times and the development of the
basin was strongly controlled by the tectonic movements. Although
unconformities can be identified within the Miocene and Pliocene
sequences, there was little or no erosion in the inner part of the basin.
Hydrocarbon generation
Available data
Moderate
Proven source rock
Possible The Hungarian Paleogene Basin is however relatively unexplored for
hydrocarbons. Generation of hydrocarbons probably occurred from Late
Miocene to present-day, depending on the amount of tectonically
induced subsidence. A detailed oil source rock correlation is however
missing. Therefore the level of certainty of the Tard-Kiscell petroleum
system is only hypothetical (BADICS and VETŐ 2012).
Maturity variability
Moderate
Recoverability
Depth
Average The depth of the Tard Clay is mostly within the range considered
feasible for shale gas/shale oil development (ca. 1-5 km). These depths
also strongly overlaps with the intervals in the HPB that are considered
mature for oil and gas.
Mineral composition
Unknown Average mineral composition does not allow any assumptions on
fraccability. The high illite content could represent problems for the
fracturing (BADICS and VETŐ 2012).
References
BADICS, B., VETŐ, I., 2012, Source rocks and petroleum systems in the Hungarian
part of the Pannonian Basin: The potential for shale gas and shale oil plays: Marine
Geological resource analysis of shale gas/oil in Europe
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
Geological resource analysis of shale gas/oil in Europe
June 2016 I 86
T08 - Vienna Basin – Mikulov Marl
General information (see excel table from GEUS)
Index Basin Country Shale(s) Age Screening-
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.
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Figure 1 Location of the Mikulov Marl Fm. in the Czech Republic and Austria below and adjacent to the Vienna Basin. The coloured areas represent different basins.
Geological resource analysis of shale gas/oil in Europe
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Figure 2 The extent of the Mikulov Marl Fm. with indication of depth and maturity. The hashed area marks the (local) selection criteria (depth between 4000-7000m and maturity > 0,7% Ro). Topography adapted from NatGeo_World_Map. Inset shows the regional setting.
Geological evolution and structural setting
Syndepositional setting
The Lower Austria Mesozoic Basin (LAMB) and the adjacent basin in the SE Czech
Republic was formed during Jurassic-Cretaceous opening of the Alpine Tethys
(Wessely 1987, Adamek 2005, Picha et al. 2006). The syn-rift sequence consists of
Middle Jurassic deltaic and prodeltaic formations which are trapped in half grabens
along Middle Jurassic east dipping normal faults. Upper Jurassic Mikulov Marls were
deposited due to thermal subsidence of the Bohemian Massif in a post-rift phase under
restricted marine conditions of a passive margin basin.
Structural setting
During the extensional tectonic phase, normal faulting shaped the SE margin of the
Bohemian Massif. It faded out by the end of Middle Jurassic with a few exceptions,
e.g. the Mailberg and the Kronberg faults. Cretaceous marine regression was
associated with the first indications of plate convergence. Three major paleovalleys
and submarine canyons (Nesvacilka, Vranovice, and Tulln, Adamek 2005; Picha et al.
2006) were carved in the Jurassic formations along active extensional faults of late
Cretaceous to Paleocene age. In the Eocene, they were filled by deepwater siliciclastic
sediments. The Alpine–Carpathian fold and thrust belts (FTB) formed during the late
Eocene – early Miocene. The N- to NW-directed shortening led to overthrusting of the
Alpine Tethyan successions onto the previously rifted European Platform (e.g. Granado
et al., 2016 and reference therein). The Alpine Mesozoic to Paleogene flysch units
were detached from the Tethyan basins, imbricated and emplaced over the Upper
Jurassic Mikulov marl.
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On top of the Flysch Zone and the more internal parts of the Alpine–Carpathian FTB,
the Vienna and Korneuburg Basins evolved in the early-to-late Miocene. Lower
Miocene “piggy-back” and Midle Miocene “pull apart” mechanism associated with
“strike-slip” faulting played an important role in making the Vienna basin up to 6000
m thick (e.g. Royden, 1985; Wessely, 1987, 1988; Fodor, 1995; Krejci et al. 1996;
Strauss et al., 2001, 2006; Hinsch, Decker & Peresson, 2005; Arzmüller et al. 2006;
Hölzel et al. 2010). The later phase of evolution was controlled mainly by thermal
subsidence (Prochac et al. 2012). The huge amount of subsidence and accumulation of
a thick basin fill led to deep burial and maturation of the Mikulov Formation (Ladwein
1988).
Organic-rich shales
Mikulov Marls
The Upper Jurassic marls are lithologically rather uniform, exhibiting several detritical
marker layers. The stratigraphic position is proven by ammonites, indicating a
Kimmeridgian to Tithonian age. To the NW the marls are fringed by a time-equivalent
carbonate platform of the Altenmarkt Formation that contains several internal facies,
with from bottom to top bedded, partly cherty or dolomitic limestones , algal/sponge
reefs and coral reefs, respectively. The transition to the Mikulov Marl is diachronous
(overall transgressive) and marked by the slope facies of the “Falkenstein-Fm.” This
formation consists of coarse calciclastics, mostly embedded in a marly matrix.
Ammonites indicate an Oxfordian to Tithonian age. The Mikulov Marl Fm. is either
overlain by biodetritic carbonatic sandstones of the Kurdejov Formation, the reefoidal,
partly dolomitic “Ernstbrunn Limestone” of Tithonian to lowermost Creaceous age, or
is unconformably overlain by the Upper Cretaceous Ameis Fomation (Glauconitic Ss.)
Fm. The Czech part of the Mikulov Fm. is described more in detail by Adamek (2005).
Depth and thickness
The Mikulov Marl Formation (MMF) reaches a thickness of more than 1000 m (2000 m
in Cz). The largest thicknesses occur through duplications related to external alpidic
thrusting within the Alpine- Carpathian foreland (Figure 3-5).
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Figure 3 Thickness (left) and depth (right) of the Mikulov Marls (m). Topography adapted from NatGeo_World_Map.
?
Figure 4 Top of the Jurassic sediments (km), SE Czech Republic
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?
Figure 5 Base of the Jurassic sediments (km), SE Czech Republic
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North-West Boundary of the Vienna Basin
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.
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Shale gas/oil properties
The Mikulov Marl is several hundreds of meters thick, has a kerogen type II-III and
TOC’s ranging between 1.6-10%, but mostly above 2.0%. In addition, it has a wide
lateral extent and covers the appropriate maturity range (Ladwein, 1988; Ladwein et
al., 1991; Francu et al. 1996). In fluorescent light microscopy planktonic algae form
the dominant organic matter, the algae lamellae act as oil-wet migraticion avenues
(Francu et al. 2013). Lowest reservoir temperature is 70°C. Assuming a geothermal
gradient of 2,7° to 2,9° per 100 m, the oil window is at 4000-6000 m depth (Ladwein,
1988). In the Zistersdorf UT-2 a temperature of 230°C has been recorded at 8553 m.
The shallower part of the Mikulov Fm. (1500-4000 m) is immature, a deeper part is
within the oil and thermogenic gas windows, and at depth over 8000 m in the eastern
part MM is overmature (Ladwein et. al., 1991). At a mean depth of 5500 m, the
maturity is of 1.2%Ro. Porosities and permeabilities are low in case of normal
pressure. In case of overpressure, which is common below the Vienna Basin, porosity
may reach 8 or 9% (Milan and Sauer, 1996). The monotonous lithology of the Mikulov
Fm. is shown in Fig. 6 on the Well log correlation charts.Chance of success component
description
Chance of success component description
Occurrence of shale
Mapping status
Good A vast amount of subsurface seismic- and well data exists Sedimentary variability
Low The Mikulov Marl has a wide lateral extent and is lithologically rather
uniform.
Structural complexity
Moderate The overburden units of the Mikulov Fm. include the Alpine-Carpathian
nappes. Jurassic rocks are not significantly deformed. Site specific
reverse faulting led to tectonic doubling. This phenomenon is with
further investigation.
HC Generation
Data availability
Good The Vienna Basin is widely studied. Biomarkers have been evaluated and
MPI–based maturity parameters work better than microscopic vitrinite
reflectance. At present, kinetic parameters are being investigated.
HC system
Proven The Mikulov Marl is the proven source rock for oil and gas in the Vienna
Basin (Ladwein, 1988, Francu et al. 1996, Picha and Peters 1998). The
modelled oil window is at 4000-6000 m depth and covers a large area.
Maturity variability
Moderate Maturation was controlled by burial due to lower Miocene ovrthrusting
by the external Alpine-Carpathian units (Flysch Belt) and middle to
upper Miocene burial by the Vienna Basin deposition. Maturation and HC
generation is predictable using basin modelling.
Recoverability
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Depth
Average to Deep Mature shales in the subsurface mostly at depths of 4-6 km
Fraccability
Unknown More studies are wanted to provide deeper insight in fraccability.
Mikulov Marl has very low content of expandable clays (smectite).
Carbonate content makes the rock rather brittle.
References
Adamek, J., 2005. The Jurassic floor of the Bohemian Massif in Moravia – geology and
paleogeography. Bull. Of Geosciences, 80, 4, 291-305.
Fodor, L. 1995. From transpression to transtesion: Oligocene-Miocene structural
evolution of the Vienna Basin and the East-Alpine-Western Carpathian junction.
A good assessment of the geographical extent of Middle-Late Triassic and Early
Cretaceous organic rich deposits in the Lombardy Basin, in general, is hampered by
the complex paleogeography. However, it can be said that the areal extents of the
units in the Lombardy Basin are very limited (few tens of km2) and their thicknesses
register sharp lateral variations that are very difficult to map with the poor subsurface
data available.
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Figure 1 Location of the Meride Fm, the Argilliti di Riva di Solto Fm and the Marne di Bruntino formation in northern Italy. The coloured areas represent different basins.
Geological evolution and structural setting
Syndepositional setting
The depositional history of the Lombardy Basin began between the middle Permian
and the Late Triassic with continental clastic deposition at the start of Tethyan rifting
(break up Pangea). Detailed correlation shows that in fact two (or three) distinct
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phases of rifting occurred during Triassic and three during Liassic to middle Jurassic
times. These phases are separated by time intervals of relative tectonic quiescence.
In the Middle Triassic, a marine transgression, in combination with synsedimentary
tectonics, controlled a complex paleogeographic setting dominated by N-S structural
troughs. The Ladinian consist of carbonate platform deposits (e.g. the Esino
formation) and intercalcated limestones (e.g. the Meride and Perledo-Varenna
formations) and black shales (the Besano Fm) deposited in the intra-platform anoxic
troughs. These organic-rich units can be correlated with the Grenzbitumenzone of
Swiss.
The Late Triassic was characterized by sedimentation of shallow marine carbonates on
the shelves and pelagic limestones and -marls in the deeper basins. In the whole of
the Southern Alps, the latest Carnian and/or the earliest Norian are marked by
renewed extensional tectonism that induced new subsidence and transgression. As a
consequence the existing troughs widened and deepened and accommodated the
thickest and most organic rich rocks during the Norian stage (Stefani & Burchell,
1990) (e.g. Argilliti di Riva di Solto). This sedimentation was accompanied by a
tectonic phase interpreted as the beginning of the rifting that eventually (in the
Jurassic) led to the opening of the Ligurian-Piedmont ocean (or Alp-Tethys). The later
Lombardy Basin (and Southern Alps in general) belonged to the southern passive
Tethys margin.
In the late Triassic, during Rhaetian, Tethyan (Ligurian) rifting periodically slowed
down and the basin fill was topped by a carbonate ramp (Zu Limestone), followed by
the development of a new carbonate platform (Conchodon formation) (Gaetani et al. ,
1998). During the latest Trias-earliest Jurassic (Lias) a new extensional phase took
place. Extension then shifted westward and in the Ligurian-Piedmont area the oceanic
crust was formed no later than Late Jurassic times. From this age up to the Lower
Cretaceous, the Southern Alps underwent a post-rift thermal subsidence (Bertotti et
al., 1993, and references therein). The Jurassic and Cretaceous units in the Lombardy
Basin are represented by a thick basin succession that was filling the subsiding basins
(Jadoul and Galli, 2008). In the Southern Alps, Early Jurassic (Toarcian) black shales
occur in the Lombardy Basin, on the Trento Plateau, in the Belluno Trough and in the
Julian Basin (Farrimond et al., 1988). However, their distribution is not continuous
across the region and in some areas of the Lombardy Basin lack black shales
(Jenkyns, 1988).
Structural setting
The three organic-rich units of the Lombardy Basin here considered are deposited
during different stage in the Permian – Cretaceous evolution from rift basin to passive
margin (rift to drift). The regional distribution of the organic matter maturity seems
to be mainly controlled by differential burial during the Norian-Liassic extensional rift
phase and by high heat flow (Fantoni and Scotti, 2003). During the Alpine orogeny,
the Tethys Ocean closed and the former passive marginstarted to override the
Eurasian plate on which the Lombardy Basin evolved as a back-arc basin. Due to this
orogeny, nowadays these source-rock units appear in a tilted monocline with 30° SW
dip under the Po river plain (Bertello et al., 2010) although the complex structural
history might have affected the vertical position and maturation level of the units
through time differently.
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Organic-rich shales
The Besano (Be), Meride (Me) and Perledo-Varenna (PV) formations (1005)
The Besano (Be), Meride (Me) and Perledo-Varenna (PV) formations are units
deposited in intraplatform anoxic troughs during the Ladinian. These units can be
correlated with Grenzbitumenzone (Swiss). All three units share some common
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.
Geological resource analysis of shale gas/oil in Europe
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Geological evolution and structural setting
Syndepositional setting
The Central and Southern Apennines show a similar Mesozoic history dominated by
the formation and evolution of a sedimentary wedge on the southern Neotethyan
passive margin. Stratigraphic and structural data of the various tectonic units that
form the Apennines confirm a complex Mesozoic paleogeographic setting,
characterized by a large Late Triassic shallow-water carbonate platform evolving in a
carbonate platform-basin systems as a consequence of a rifting stage that affected the
whole Neotethyan region during the Early Jurassic. Many paleogeographic restorations
have provided models which differ in the relative position and number of carbonate
platforms and basins. Geophysical data and field analyses support the hypothesis of
two carbonate platforms (Apenninic platform and Apulian platform) separated by a
deep basin (Lagonegro-Molise basin). Moreover, the evolution of the northern sector
of the Apenninic Platform is characterized by the Tuscany-Umbria-Marche Basin
connected to the North Tethys rifting systems.
The Late Triassic Apenninic platform was dominated by deposition of evaporites
(Anidridi di Burano, Carnian-Rhaetian) and cyclic dolomites (Dolomia Principale,
Norian-Raethian).
The extensional tectonics that affected the platform areas during the Late Triassic to
Early Jurassic produced various depositional settings associated with areas of
differential subsidence rates. In several restricted basins inside the platform complex,
Upper Triassic euxinic sediments are encountered, such as in the Emma Basin in the
Adriatic offshore, the Pelagruza Basin in the Dinaric offshore, and several onshore
basins (e.g. Vradda in Gran Sasso and Filettino in the Simbruini; Finetti et al., 2005).
Some of these restricted basins persisted during the Mesozoic, becoming parts of
larger basins, which is the case for the Emma Basin, while others were filled as
carbonate platform conditions were restored (e.g. Filettino Basin).
The Umbria-Marche basin, one of the persistent basins, developed along the northern
sector of the Lazio-Abruzzo carbonatic shelf (Finetti et al., 2005) during the Jurassic -
Cretaceous period and was persistent until early Cenozoic times. The stratigraphic
succession of this domain is prevalently a basin sequence (Finetti et al., 2005),
characterized by limestones, cherty and marly limestones, marls and hemipelagic clay,
with local evidence of carbonate re-sedimentation. In general, the Umbria-Marche
pelagic Mesozoic sequence shows a low naphtogenic potential excepted for some
levels where euxinic black shale and rich organic matter levels occur, these include the
Marne del Monte Serrone Formation, the Marne a Fucoidi Formation and the Livello
Bonarelli. These organic enriched formations are related to main Oceanic Anoxic
Events (OAE’s) and are characterized by relatively high total organic carbon (TOC)
values and are clearly synchronous across Tethys and in global context (Jenkyns,
2010; Soua, 2014).
Structural setting
At present the Triasic-Cretaceous platform-basin succession is taken up in the Central-
Northern Apenninic fold and thrust belt (Bigi et al., 2011) formed during the eastward
convergence of the Triassic – Miocene carbonate succession of the Adria continental
margin (Lazio-Abruzzi and Apulia-Adriatic platforms) over younger Neogene-
Quaternary Apulian foreland basins. Most oil reservoirs in the Adriatic and Apulian area
reside in overridden platform slivers taken up in the orogeny (Bigi et al., 2011).
Consequently, source rocks occur at a wide range of depth levels and may be
duplicated by tectonic stacking.
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Organic-rich shales
Emma Formation (1008)
The Emma Formation includes Upper Triassic and Lower Jurassic bituminous
limestones (Dolomie Bituminose) and evaporitic- and euxinic black shales. These
together with euxinic limestones inside the Burano formation are considered the
source rocks for many conventional oil reservoirs in the Adriatic and Apulian area
(Novelli and Demaison, 1988; Zappaterra, 1994; Bertello et al., 2010).
Depth and thickness
The depth of the top of the Triassic evaporites of the Emma Limestones Formation
reaches 7,000 meters east of the Teramo thrust (Bigi et al., 2011). Deep wells of the
Gargano and Apulian areas show that the present depth of the Upper Triassic black
shales, which are often thin and irregular in occurrence, is 4,500 to 5,000 meters. In
the Apulian and southern Adriatic basin, the depth of Emma Limestones Formation is
estimated at 5,000-6,000 meters (Mazzuca et al., 2015). The thickness of this
potential source rock is between 50-200 meters based on subsurface and outcrop
data. The net thickness ranges between 5-24 m.
Shale oil/gas properties
The geochemical parameters estimated for the Late Triassic evaporites and euxinic
deposits explored in the Adriatic–Apulia area (amongst which the Emma Limestone
Formation) outcropping in the Apennines range or could be summarized as follows.
Table 1 Overview of the main properties of the organic-rich intervals.
Chance of success component description
The lack of specific literature or assessments concerning unconventional resources in
Italy are mainly related to some geological factors that reduce the economic interest
of these resources:
1. limited and discontinuous extension of the organic-rich rocks;
2. rocks with high thickness have low TOC (<<2%);
3. rocks with high TOC have low thickness (<<20 meters).
Occurrence of shale
Mapping status
Poor In general it is very difficult to map the areal extent and depth of the
discontinuous organic-rich units because of the scattered distribution of
subsurface data.
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Sedimentary variability
High The depositional heterogeneity is largely related to the basin
physiography during deposition that was marked by areas of differential
subsidence rates leading to formation of restricted basins inside the
platform complex. Even within these restricted basin lateral changes are
expected based on to relatively shallow depositional depths.
Structural complexity
High Thicknesses and depths are affected by syn-tectonic deposition and
later thrust tectonics.
HC generation
Available data
Moderate Some exploration wells are public and used for assessment of shale
oil/gas potential. Most, however, are confidential and most data on
shale properties comes from outcrops analogues.
Proven source rock
Proven Multiple working petroleum systems (oil) are present in the Adriatic and
Apulian area that reside in the thrusted Apulian platform-to-basin Even
stacked systems exist. No further details given.
Maturity variability
High A great variability of the thermal maturity is expected due to the
complex structural history. Source rocks occur at a wide range of depths
and are likely to exhibit a wide range of maturation levels (including in-
and overmature).
Recoverability
Depth
Average to Deep
Mineral composition
No data average mineral composition was not provided
Marne del Monte Serrone Formation (1009)
This formation was deposited in a basinal environment characterized by an articulated
physiography and bathymetry consisting of structural highs and subsiding basins,
inherited from the break-up and drowning of the Early Jurassic Calcare Massiccio
carbonate platform. In the Central Northern Apennines the Marne del Monte Serrone
Formation (RSN) consists of Early Toarcian deposits enriched in organic carbon. This
formation is interposed between a calcareous unit (Corniola - COI) and a reddish
nodular calcareous marly one (Rosso Ammonitico Umbro-Marchigiano). The RSN
mostly consists of organic rich shale, marly-clay and marly-limestones, deposited in a
low- oxygenated basin (Palliani et al., 1998). The physiography and bathymetry of the
Early Toarcian Umbria-Marche basin strongly controlled the type, the accumulation
and the preservation rate of the total organic matter (Gugliotti et al., 2012; Parisi et
al., 1996).
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Depth and thickness
The thickness of the RSN is variable and related to the morphology of the basin and
the different extent of the stratigraphic succession. In the Umbria-Marche outcrops,
the net thickness of Toarcian black shales and black shale-like deposits ranges from 1
to 24 meters, with minimum values in the condensed succession (Parisi et al., 1996).
Although this stratigraphic interval displays characteristics typical of potential source
rocks, the thickness of the organic-rich interval is much more variable and limited.
No specific information is available for the characteristics of this formation in the
subsurface. Based on the seismic profiles across the anticlines penetrated by the
Cornelia 1 and Pesaro Mare wells to the north of Ancona, the depth of the top of the
RSN is estimated to be at least 4,000-5,000 meters for the Northern Adriatic basin
(Casero and Bigi, 2013).
Shale oil/gas properties
The lithofacies deposited on the structural highs in the basinal setting are
characterized by low TOC % 0.1-0.3. The poorly-oxigenated, black shale and black
shale-like sediments originated in the deepest portions of the basin, show higher TOC
% 0.5-2.7 (Parisi et al., 1996). The TOC values estimates of Katz et al. (2000) are
0.19–2.34% (mean 0.95%) and the mean value of the Total hydrocarbon generation
potential is 6.19 mg HC/g rock. The organic matter is mostly composed of a mixture of
continental organic debris and marine components such as dinoflagellate cysts,
foraminifera linings and Tasmanaceae algae (Gugliotti et al., 2012); Katz et al. (2000)
classified these sources rock as Type II-III.
Although this stratigraphic interval displays characteristics typical of potential source
rocks, the thickness of the organic-rich interval is limited and highly variable.
Chance of success component description
The lack of specific literature or assessments concerning unconventional resources in
Italy are mainly related to some geological factors that reduce the economic interest
of these resources:
1. limited and discontinuous extension of the organic-rich rocks;
2. rocks with high thickness have low TOC (<<2%);
3. rocks with high TOC have low thickness (<<20 meters).
Occurrence of shale
Mapping status
Poor In general it is very difficult to map the areal extent and depth of the
discontinuous organic-rich units because of the scattered distribution of
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.
Sedimentary variability
High The depositional heterogeneity is largely related to the basin
physiography during deposition that was marked by areas of differential
subsidence rates leading to formation of restricted basins inside the
platform complex.
Structural complexity
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High Thicknesses and depths are affected by syn-tectonic deposition and
later thrust tectonics.
HC generation
Available data
Poor Most data on shale properties comes from outcrops analogues.
Proven source rock
Possible Based on seismic data, the source rock is thought to be present
underneath Northern Adriatic basin (not encountered though) and might
contribute to the petroleum system.
Maturity variability
High A great variability of the thermal maturity is expected due to the
complex structural history. Source rocks occur at a wide range of depths
and are likely to exhibit a wide range of maturation levels (including in-
and overmature).
Recoverability Depth
Average In the subsurface mostly at depths of 4-5 km
Mineral composition
No data average mineral composition was not provided
Marne a Fucoidi Formation (1010)
Within the Cretaceous succession of the Umbria – Marche Basin (UMB), the Marne a
Fucoidi Formation is one of the best-preserved deep-marine archive of the Aptian–
Albian. It represents a distinctive multicolored interlude with more shale, outcropping
in many sections from the Umbria-Marche Apennines to the Gargano area. This
formation consists of thinly interbedded pale reddish to dark reddish, pale olive to
dark reddish brown and pale olive to grayish olive marl-stones and calcareous
marlstones together with dark gray to black organic carbon-rich shales, usually with a
low carbonate content, and yellowish-gray to light gray marly limestones and 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.
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The depth of the top of the Marne a Fucoidi is very variable ranging between ~2,000
meters below the Montagna dei Fiori thrust, up to 5,000 meters below the Teramo
thrust, in the Adriatic area (Bigi et al., 2011). In the Central Adriatic Basin, the depth
of the top Marne a Fucoidi formation is between 4,000-5,000 meters (Casero and Bigi,
2013).
Shale oil/gas properties
The Poggio Guaine section, located between Mount Nerone and Cagli, is considered a
type section for the Aptian-Albian interval in the UMB. In this section the total
thickness of the Marne a Fucoidi Formation is 82.53 m (Coccioni et al., 2012). Based
on field observations of the Marne a Fucoidi Katz et al. (2000) suggests that a typical
organic-rich sequence is less than 0.25 m thick, and that organic-rich/organic-poor
cycles are 1.5 m thick. The exposed sequence near Gubbio is >50 m thick, implying a
net source-rock thickness in excess of 8 m. Arthur and Silva (1982) observed that the
highest levels of organic enrichment are largely confined to a 20 m thick, lower to
lower-middle Albian interval at Gubbio. Fiet (1998) reported that within the Umbria-
Marche Basin, as many as 150 thin black shales may be present in a 42 m gross
interval. The geochemical parameters estimated for the Marne a Fucoidi Formation
outcropping in the Central Apennines are summarized as follows.
Table 2 Overview of the main parameters of the organic rich intervals
Chance of success component description
The lack of specific literature or assessments concerning unconventional resources in
Italy are mainly related to some geological factors that reduce the economic interest
of these resources:
1. limited and discontinuous extension of the organic-rich rocks;
2. rocks with high thickness have low TOC (<<2%);
3. rocks with high TOC have low thickness (<<20 meters).
Occurrence of shale
Mapping status
Moderate Outcrop data is widespread and reveal a rather continuous presence.
However, for the subsurface, iIn general, it is very difficult to map the
areal extent and depth of the shale layer.
Sedimentary Variability
Low Due to the pelagic origin, the observed depositional heterogeneity is low
Structural complexity
High Thicknesses and depths are affected by syn-tectonic deposition and
later thrust tectonics.
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HC Generation
Available data
Moderate Some exploration wells are public and used for assessment of shale
oil/gas potential. Most, however, are confidential and most data on
shale properties comes from outcrops analogues.
Proven source rock
Proven Multiple working petroleum systems (oil) are present in the Adriatic and
Apulian area that reside in the thrusted Apulian platform-to-basin Even
stacked systems exist. No further details given.
Maturity variability
High A great variability of the thermal maturity is expected due to the
complex structural history. Source rocks occur at a wide range of depths
and are likely to exhibit a wide range of maturation levels (including in-
and overmature).
Recoverability Depth
Average In the subsurface mostly at depths of 4-5 km
Mineral composition
No data average mineral composition was not provided
Livello Bonarelli (not considered in assessment)
The Livello Bonarelli represents a regional marker bed located at the top of the Scaglia
Bianca Formation, close to the Cenomanian/Turonian boundary. This marker consists
of organic-rich sediments related to the well-known Oceanic Anoxic Event 2 (OAE2 –
Scoppelliti et al., 2006). Unlike the surrounding formations, which are rich in
foraminifera, strata associated with the Bonarelli Event are rich in radiolaria and fish
remains (Jenkyns, 2010). Such a shift may indicate an increase in primary
productivity.
Depth and thickness
Although the Cenomanian-Turonian Bonarelli Event displays some of the most high
levels of organic enrichment, in the Umbria-Marche domain it obtains thicknesses in
outcrop of less than 2 meters at Furlo and Gubbio sections (Passerini et al., 1991).
Shale oil/gas properties
Unweathered samples from the Bonarelli Event analyzed by Katz et al. (2000)
contained as much 27.5% TOC (mean value 7.71%). Hydrocarbon generation
potential in excess of 280 mg HC/g rock have been determined for this interval, with a
mean generation potential of ≈ 60 mg HC/g rock. When severely weathered, organic
carbon contents are less than 0.5% (Katz et al 2000). Pieri and Mattavelli (1986)
described the kerogene type of the Livello Bonarelli as “90% amorphous and marine”
and reported an average TOC value of 5.12. The study carried out by Scoppelliti et al.
(2006) confirms the high TOC values for the Bonarelli black shale in the Bottaccione
section (Scopelliti et al., 2006). Because of the limited thickness the Livello Bonarelli
does not show a relevant interest as potential shale oil source rock and will not be
involved in the further assessment.
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References
Andrè, P., and Doulcet, A. (1991). Rospo Mare Field – Italy , Apulian Platform, Adriatic
Sea. AAPG Treatise of Petroleum Geology, Atlas of Oil and Gas Fields A-06, 29-54.
Arthur, M., and Silva, I.P. (1982). Recoverability of widespread organic carbon-rich
strata in the Mediterranean Tethys. In: Schlanger, S. 0. and Cita, M. B. (Eds), Nature
and Origin of Cretaceous Carbon-Rich Facies. Academic Press (London), 7-54.
Baudin, F., Herbin, J.-P., Bassoullet, J.-P., Dercourt, J., Lachkar, G., Manjvit, H. and
Renard, M. (1990). Distribution of organic matter during the Toarcian in the
Mediterranean Tethys and Middle East. In: Hue, A. Y. (Ed.), Deposition of Organic
Fades. AAPG Studies in Geology, 30, 73-91.
Bechstadt, T., Boni, M., Iannace, A. and Koster, J. (1989). Upper Triassic source rocks
from Alps and Southern Apennines (Austria, Italy). Abstracts 28th International
Geological Congress, 1, 109.
Bencini, R., Bianchi, E., De Mattia, R., Martinuzzi, A., Rodorigo, S. and Vico, G.
(2012). Unconventional Gas in Italy: the Ribolla Basin. AAPG, Search and Discovery
Article #80203.
Bertello, F., Fantoni, R., Franciosi, R., Gatti, V., Ghielmi, M., and Pugliese, A. (2010).
From thrust-and-fold belt to foreland: hydrocarbon occurrences in Italy. In Vining,
B.A. & Pickering, S. C. (eds) Petroleum Geology: From Mature Basins to New Frontiers
– Proceedings of the 7th Petroleum Geology Conference, 113–126. DOI:
10.1144/0070113.
Bigi, S., Casero, P. and Ciotoli, G. (2011). Seismic interpretation of the Laga basin;
constraints on the structural setting and kinematics of the Central Apennines. Journal
of the Geological Society, London, 168, 1–11. doi: 10.1144/0016-76492010-084.
Bongiorni, D. (1987). The hydrocarbon exploration in the Mesozoic structural highs of
the Po Valley: the example of Gaggiano. Atti Tic. Sc. Terra, 31, 125-141.
Brosse, E., Loreau, J.P., Huc, A.Y., Frixa, A., Martellini, L., Riva, A., 1988. The organic
matter of interlayered carbonates and clays sediments — Trias/Lias, Sicily. Org.
Geochem. 13, 433–443.
Brosse, E., Riva, A., Santucci, S., Bernon, M., Loreau, J.P., Frixa, A., 1990. Some
sedimentological and geological characters of the late Triassic Noto formation, source
rock in the Ragusa basin (Sicily). Org. Geochem. 16, 715–734.
Geological resource analysis of shale gas/oil in Europe
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T28 - South Eastern basin
General information
Index Basin Country Shale(s) Age
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.
Geological evolution and structural setting
Syndepositional setting
The Permo-carboniferous shales deposited in a continental to paralic setting, including
bogheads, in a late orogenic (post-variscan) extensional setting, creating numerous
small grabens.
The Schistes cartons deposited in a deep, open plateform environment, conected to
the opening Tethys Ocean (cf. Paris Basin)
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Structural setting
The South-East basin is a polyphased basin, which initiated during the Triassic and
evolved according to the Tethyan rifting as a passive margin with classical pre-syn and
post- rift successions till the Late Cretaceous, including the ‘Vocontian Trough’
episode. Since then, the closure of the Tethys Ocean caused a tectonic inversion which
eventually led to collision with the African and Apulian plates from the Late Paleogene
to Present times (Alpine orogeny). In response to that collision, the South-East Basin
evolved as a foreland basin with a classical underfill/overfill megasequence from the
Eocene. The Massif Central acted as a rigid block during the collision, limiting the
westward extension of the foreland basin. Finally, during the late Neogene, the
Messinian crisis played a significant role in the sedimentary infill with development of
large and deep canyons and karstic networks. For its long and polyphased evolution,
the South-East Basin is highly complex, with numerous blocks and sub-basins
together with thick (up to 11 km) but highly variable sedimentary succession
(Debrand-Passart et al., 1984a, 1984b).
Organic-rich shales
Permo-Carboniferous
The Stephanian stratotype comes from Saint-Etienne city, famous for its coal
resources which have been mined for more than 150 years. In the South-East Basin,
several Stephanian and Permian basins are identified along Hercynian structures.
Depth and Thickness
Thickness and depth are highly variable and specific for each subbasin. In general the
thickness of the Permo-Carboniferous succession is 10 to 1300m and the average
depth varies between 300 and 4500m.
Shale oil/gas properties
Not much public data regarding thickness or TOC content is available from these
scattered basins. The high subsidence permitted the accumulation of very thick
terrestrial series but with frequent lateral changes. Coal seams vary greatly because
lenticular shaped, but the organic deposits can represent up to 10% of the Stephanian
series in the Blanzy Basin. In the Lonsle-Saunier Basin, only known from drilling
survey, the coal seams represent only 5% of the 600 m thick Stephanian series. All
the Carboniferous basins comprise several coal seams or bituminous shales.
Conversely, only some of the Permian basins are organic rich (boghead and
bituminous shales) such as the Blanzy-Creuzot Basin and the Causses Basin for which
no TOC/isopach data is available. Available TOC measurements vary between 0.02%
to more than 20% between the different formations and basins. Maturity according to
Rock-Eval analyses ranges from immature to gas mature and the type of organic
matter ranges from Type III coal for the Carboniferous formations to Type I for the
Autunian.
Chance of success component description
Occurrence of shale layer
Mapping status
Poor
Sedimentary Variability
High Assessment area includes multiple formations with highly variable
sedimentary setting.
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Structural complexity
High Area consists of multiple small sub basins with different tectonic
histories.
HC generation
Available data
Poor
Proven source rock
Unknown
Maturity variability
High
Recoverability Depth
Unknown
Mineral composition
No data average mineral composition was not provided
Schistes Carton Formation
Lateral equivalent to the Schistes Carton of the Paris Basin.
Depth and Thickness
The Toarcian deposits are thicker in the Southern part of the South-East Basin (south
of Lyon), with up to 500 m. In the northern part, the Schistes Cartons Fm is absent
(except in Franche-Comté, NE) because of the regional condensed sedimentation
around the Lyon High. Conversely, the Schistes Cartons Fm is well developed in the
southern part, despite synsedimentary tectonics at some places (Causses Basin).
Finally, the Subalpine domain recorded a proximal-distal sequence from the south
(Nice, Castellane) to the North (Mont Blanc) but with condensed or absence of the
Schistes Carton Fm.
Shale oil/gas properties
The South-East Basin lacks precise and dedicated studies for unconventional
resources.
Chance of success component description
Occurrence of shale layer
Mapping status
Poor
Sedimentary Variability
High Assessment area includes multiple formations with highly variable
sedimentary setting.
Structural complexity
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High Area consists of multiple small sub basins with different tectonic
histories.
HC generation
Available data
Poor
Proven source rock
Possible The Schistes Carton are a proven source rock in the Paris Basin and
other Basins in Europe.
Maturity variability
High
Recoverability Depth
Unknown
Mineral composition
No data average mineral composition was not provided
References
Debrand-Passart S., Courboulaix S., Lienhardt M.-J. (1984) Synthèse géologique du
Sud-Est de la France. Vol1 : Stratigraphie et paléogéographie. Mém. BRGM Fr. Vo
n°125, 617p.
Debrand-Passart S., Courboulaix S., Lienhardt M.-J. (1984) Synthèse géologique du
Sud-Est de la France. Vol2 : Atlas. Mém. BRGM Fr. Vo n°126, 158 p.
Geological resource analysis of shale gas/oil in Europe
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T30 – Lusitanian Basin, Portugal
General information
Index Basin Country Shale(s) Age
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.
Geological resource analysis of shale gas/oil in Europe
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Geological evolution and structural setting
Syndepositional setting
The stratigraphy and sedimentology of Lusitanian Basin is well established (e.g.,
Azeredo et al., 2003; Carvalho et al., 2005; Duarte et al., 2004; Kullberg et al., 2013;
Leinfelder and Wilson, 1989; Rasmussen et al., 1998; Rey et al.,2006; Wilson et al.,
1989; Wilson, 1979, 1988).
The Lower Jurassic sedimentary record is particularly well represented in Lusitanian
Basin Massif and corresponds to a thick carbonate succession, comprising up to 550 m
of mostly marl-limestone alternations, characterizing much of the upper Sinemurian–
Toarcian series of the basin (Soares et al., 1993; Duarte and Soares, 2002; Duarte et
al., 2004, Duarte et al., 2010). These facies, comprising abundant nektonic and
benthic macrofauna, are included in the Upper Triassic–Callovian 1st-order cycle
(Wilson et al., 1989; Soares et al., 1993; Duarte, 1997; Azerêdo et al., 2002, 2003;
Duarte et al., 2004) and are associated with a palaeogeography controlled by an
epicontinental sea, sustained by a low-gradient carbonate ramp dipping towards the
northwest (Duarte, 1997, 2007; Duarte et al., 2004). In this geological context, the
upper Sinemurian– Pliensbachian interval is characterized by the occurrence of
organic-rich facies regarded as a potential oil sourcerock (Oliveira et al., 2006).
The Sinemurian-Pliensbachian series show important changes in the depositional
system (Duarte et al., 2010), from lower-upper Sinemurian peritidal facies (Coimbra
Formation (Fm); Azerêdo et al., 2008) to Pliensbachian hemipelagic deposits
(including the Vale das Fontes and Lemede formations; Duarte and Soares, 2002).
However, in the western sectors of the basin, such as Peniche, S. Pedro de Moel,
Figueira da Foz and Montemor-o-Velho, hemipelagic deposition started earlier during
the late Sinemurian (Oxynotum-Raricostatum zones; Água de Madeiros Fm.; Duarte
and Soares, 2002; Duarte et al., 2004, 2006). All these units are characterized by
different marl/limestone relations, organic matter content and specific
benthic/nektonic macrofauna and microfauna
Structural setting
The onshore basin represents the proximal element of a much larger Mesozoic-
Cenozoic basin system which extends offshore into the Porto and Galicia Basins to the
north and the Peniche Basin to the west.
The Lusitanian Basin is an Atlantic margin rift basin formed in the Mesozoic (e.g.,
Rasmussen et al., 1998) located on the occidental margin of the Iberian Massif with
approximately 5 km thick of sediments. According to several authors (e.g. Azerêdo et
al., 2003; Rasmussen et al.,1998; Wilson et al.,1989) this basin is related to the
opening of the North Atlantic Ocean and is filled with sediments from the Upper
Triassic to the Cretaceous covered with Cenozoic sediments but Upper Jurassic
sediments being the thicker portion of it.
Lusitanian Basin is limited to the East by the Porto-Tomar fault and a complex set of
NNW–SSE faults, and to the West by the Berlenga horst, a tectonic high that was
emerged during almost all the basinal history. The evolution of the Lusitanian Basin is
linked to four Late Triassic–Early Cretaceous rift phases that produced a high
compartmentalization of the basin (Alves et al., 2002; Kullberg, 2000; Kullberg et al.,
2006; Rasmussen et al., 1998). The syn-rift sedimentary evolution and tectonic style
of the basin during extension and posterior inversion was controlled also by other
important factor being the presence of a mid-level décollement in the syn-rift deposits
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(Alves et al., 2002; Kullberg et al., 2006; Rasmussen et al., 1998; Soto et al., 2012).
The uppermost Triassic–Hettangian evaporates (Dagorda Formation) constitute this
décollement that is present in almost all the basin and can reach 1000 to 1500 m thick
in the deepest areas of the basin.
Four rift phases have been recognized in the Lusitanian Basin (Alves et al. 2002;
Kullberg 2000; Kullberg et al., 2006; Rasmussen et al., 1998; Stapel et al., 1996).
Rift 1 (Triassic–Hettangian) the beginning of the continental rifting is characterized
by sedimentation in grabens and half-grabens as demonstrated by strong thickness
changes (Stapel et al., 1996) and the geometry observed from offshore seismic
profiles (Rasmussen et al., 1998). This tectonic style was strongly conditioned by
the previous Variscan structures (Ribeiro et al., 1990; Wilson et al., 1989).
Sedimentation during this rift phase comprises the continental–fluvial detrital
deposits of the base units of the Silves Group (Conraria and Penela Fm.; in Soares
et al., 2012) and the supratidal sabhka evaporites of Dagorda Fm.
Rift 2 (Sinemurian–Late Oxfordian). It comprises carbonate units deposited over a
westward-tilted ramp (Coimbra, Brenha/Candeeiros, Cabaços and Montejunto
Formations). This thick sequence (>1500 m) was controlled by N–S faults and is
principally located in the central part of the basin, South of the Nazaré fault. The
principal faults responsible for the subsidence were oriented N–S, but also for the
first time in the basin history, other faults oriented ENE–WSW to E–W controlled
facies distribution and thickness changes.
Rift 3 (Kimmeridgian–Early Berriasian). Distinct sub-basins were individualized and
filled with mixed continental-marine deposits showing a complex facies pattern
(Abadia/Alcobaça and Lourinhã Formations), dominated by siliciclastic influxes into
the basin. The petrology of proximal members indicates that the Variscan basement
was exposed during the Early Kimmeridgian (Leinfelder and Wilson, 1989). As in the
previous Rift 2, the stretching episode is more pronounced to the South of the
Nazaré fault than to the North (Stapel et al., 1996) being the depocentre of the
basin oriented N–S to NNE–SSW (Wilson, 1988).
Rift 4 (Late Berriasian–latest Aptian). The Torres Vedras Group deposited during this
rift phase exhibits simple facies geometry, with largely fluvial siliciclastic sands and
conglomerates interfingering with shallow water carbonates. The rift initiation is
marked by a regional unconformity characterized both by an angular unconformity
over tilted half-grabens below and a clear change in lithology with conglomerates
succeeded by progradation of a clastic wedge. That regional unconformity is
probably due to thermal uplift induced by lithospheric stretching during the final
rifting phase that generally precedes crustal separation (Ziegler, 1992).
Organic-rich shales
Água de Madeiros Formation
This unit, resting over the inner-shelf Coimbra Fm., has been subdivided into two
members: the Polvoeira Member (Mb.) at the base, and the Praia da Pedra Lisa Mb.at
the top. The base of Polvoeira Mb. consists of marl-limestone alternations that become
progressively more argillaceous, presenting several organicrich facies horizons. The
middle-upper part of this member is a rhythmic succession with marl/limestone ratios
around 1.5 to 2. Limestones generally correspond to fossiliferous wackestones that are
sometimes rich in ostracods, molluscs and organic matter.
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Depth and Thickness
Where its type-sections is defined (S. Pedro de Moel) (Duarte and Soares, 2002;
Duarte et al., 2004b, 2006), the thickness of this member is approximately 42 m,
decreasing to 10 m in Peniche and Montemor-o-Velho.
Vale das Fontes Formation
The Pliensbachian Vale das Fontes Fm., ranging in age from the lowermost Jamesoni
to the uppermost Margaritatus zone interval, represents the return to a marly
sedimentation, widespread across the whole basin. It is particularly well exposed in
the western part of the basin and is subdivided into three informal members:
Marls and limestones with Uptonia and Pentacrinus Mb.- This unit is characterized by
bioturbated decimetre marl/centimetre-thick marly limestone alternations. Across the
basin, an increase is observed in the marly character from the proximal to the distal
sectors.
Lumpy marls and limestones Mb. - This unit is defined by the occurrence of lumpy
facies (Hallam, 1971; Dromart and Elmi, 1986; Elmi et al., 1988; Fernández-López et
al., 2000), interbedded in a marl-limestone succession. The lumps have a microbial
origin and consist of micritic grumose concretions, generally subspherical-shaped and
reaching several centimetres in size. Interbedded in these facies, metricscale grey to
dark marls occur. This unit ranges from the Jamesoni to the Luridum subzone interval.
Marly limestones with organicrich facies Mb. -This unit is characterized by an increase
of the marly terms of the serie, alternating with centimetrethick limestone facies. In
the distal regions, such as the Peniche, S. Pedro de Moel and Figueira da Foz sectors,
organic-rich sediments are particularly abundant. This member comprises the Luridum
Subzone (topmost of Ibex Zone) to the uppermost Margaritatus Zone interval.
Depth and Thickness
The Vale das Fontes Formation is approximately 75-90 m thick in the western part of
the basin.
Lemede Formation
This unit, from Upper Pliensbachian, generally comprises centimetre marl/decimeter
limestone bioturbated alternations. In the southeastern part of the LB, such as Tomar,
facies are much more bioclastic (packstone to grainstone) and locally dolomitic. This
unit ranges in age from the Spinatum Zone to the lowermost part of Polymorphum
Zone.
Depth and Thickness
It reaches a thickness of approximately 30 m in the northwest of the basin
Shale oil/gas properties
23 shallow wells were drilled (160 m average depth, one well 451 m deep) to collect
cuttings and conventional cores in the Lias section over a wide geographic area. The
main conclusions are discussed in McWhorter et al., 2014. Porosity (from shallow
wells) ranges from 0.2 to 19.8% over a total thickness of up to 400 m (average 200
m). The Lower Jurassic is characterized throughout the basin by a TOC average range
of 2.3 to 5.9%, Ro values of 0.5 to 1.8%, and quartz-carbonate content of 63.8 to
83.7%. Organic matter in the Lower Jurassic is dominantly kerogen type II in the
prospective middle of the basin, with drilling depths of 1000 to 3500 m, where Tmax
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mapping also shows the thermal maturity necessary for oil and gas generation
(greater than 450 degrees in the prospective areas).
Additional information, such as oil and gas shows in old wells throughout the basin, oil
seeps at the surface, and live oil in shallow Lias cores verify a viable resource interval.
Chance of success component description
Occurrence of shale layer
Mapping status
Poor Only the outlines of the basin are available.
Sedimentary Variability
Moderate The whole succession is made up out of multiple formations with
different distributions within the basin.
Structural complexity
Moderate
HC generation
Available data
Moderate In an exploration study 23 shallow wells were drilled and samples were
analysed.
Proven source rock
Possible Oil and gas shows were encountered in old wells
Maturity variability
Moderate Maturity varies between immature and gas mature
Recoverability Depth
Average In the subsurface mostly at depths of 1-3.5 km.
Mineral composition
Unknown to Favourable Mineralogical analyses show a quartz-carbonate content
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T34 - Midland Valley Scotland
General information
Index Basin Country Shale(s) Age
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.
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The interbedded Carboniferous sedimentary and volcanic rocks of the Midland Valley of
Scotland form a succession up to locally over 18,000 ft (5,500 m) thick.
Geological evolution and structural setting
Syndepositional setting
The prospective Midland Valley of Scotland units were deposited in lacustrine, 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.
Shale oil/gas properties
According to Monaghan (2014) the Gullane unit is dominated by TOC values between
1-3.5%, with a smaller number of high TOC samples. Samples from the Gullane unit
plot within the range of Type I, Type II and Type III kerogens.
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West Lothian Oil-Shale unit
The West Lothian Oil-Shale unit is characterised by thin seams of oil-shale in a cyclical
sequence dominated by sandstones interbedded with grey siltstones and mudstones.
Subordinate lithologies include coal, ostracod-rich (and occasionally algal)
limestone/dolostone, sideritic ironstone and marine beds, including bioclastic
limestones with rich and relatively diverse marine faunas (Browne et al. 1999). Thick,
pale green-grey or grey argillaceous beds containing volcanic detrital components
(historically termed ‘marl’) are present (Jones 2007), as well as beds of tuff and ash
(e.g. the Port Edgar Ash). The West Lothian Oil-Shale Formation is of Asbian to
Brigantian age, NM-VF palynomorph zones (Browne et al. 1999, Waters et al. 2011).
An estimated 5% of the West Lothian Oil-Shale Formation is considered to be marine-
influenced (M. Browne pers. comm. 2014).
Jones (2007) defined 11 sedimentological facies within the West Lothian Oil-Shale
Formation; these represent variations within a predominantly lacustrine environment.
Periods of lake development and expansion were marked by deposition of lacustrine
limestones and desiccation-cracked mudstones, with lake maxima marked by the
deposition of oilshale facies. The lakes were generally filled by fine-grained siliciclastic
(muddy) sediment, although minor channel systems fed coarser sediment (sand) into
the lakes via small prograding delta systems. The calcareous mudstone (‘marl’) facies
comprised a significant component of altered volcanic material. Marine faunas are
usually diverse and marine strata could make up approximately 40% of the succession
(M. Browne pers. comm.).
Depth and Thickness
The West Lothian Oil-Shale Formation is up to 3,675 ft (1,120 m) thick and crops out
over a large area of West Lothian and also on the western side of the Midlothian
Syncline, south of Edinburgh.
Shale oil/gas properties
Oil-shales sensu stricto form only about 3% (by thickness) of the West Lothian Oil-
Shale Formation and are highly kerogen-rich, TOC-rich (up to 35%) sediments ranging
from a few inches to 16 ft (5 m) thick (Loftus & Greensmith 1988). In thin section, the
oil-shales are thinly laminated and are believed to be of laminar algal and discrete
algal body origin (Loftus & Greensmith 1988, Parnell 1988, Raymond 1991). The oil-
shales are interpreted as algal oozes (blooms) formed in shallow, stratified lakes,
characterised by anerobic bottom conditions (Parnell 1988), though marine ostracods
in some oil-shales imply marginal marine conditions existed at times (Wilkinson 2005,
Jones 2007).
The source rock potential of the West Lothian Oil-Shale Formation was reviewed by
Parnell (1988). He considered the oil-shales to be a high quality oil-prone source rock,
with up to 30% TOC. Other shales and dark limestones within the formation were also
considered to have petroleum source potential, with TOC values ranging from 1.5 to
22.7% (Parnell 1988).
According to Monaghan (2014) the West Lothian Oil-Shale unit has a large proportion
of the samples between 1-7% TOC and a significant number between 7% and 30%.
By contrast, the Lawmuir Formation, the basin margin equivalent of the West Lothian
Oil-Shale Formation, has TOC < 2% in three of the four samples analysed (the fourth
having TOC = 2.09%).
Samples from the West Lothian Oil-Shale unit plot within the range of Type I, Type II
and Type III kerogens.
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Limestone Coal Formation
The Limestone Coal Formation comprises sandstone, siltstone, mudstone, seatrock
and coal or blackband ironstones in repeated cycles. The siltstone and mudstone are
usually grey to black. Coal seams are common and many exceed a foot in thickness.
Minor lithologies include cannel, and clayband ironstone. Thick multi-storey
sandstones are present, though locally, successions may be particularly sandy or
argillaceous. Regionally correlated marine bands that reach over 165 ft (50 m) in
thickness (e.g. Black Metals Member along the Kilsyth Basin) consist largely of
carbonaceous mudstone with clayband ironstones. Up to 30% of the lower part of the
formation may be marine influenced. Stronger fluvial influences in the cyclical
Limestone Coal Formation strata are noted in channel belts in the Clackmannan area
and to the east of the Midland Valley (Read et al. 2002), along with active fault and
fold growth. The palaeogeography for the Limestone Coal Formation highlights growth
on synsedimentary folds and faults, and the palaeocurrent directions of fluvial systems
taken from Read (1988) and Hooper (2004). Eruption of lavas and tuffs occurred in
the Bathgate and Saline hills.
Depth and Thickness
The Limestone Coal Formation of Namurian (Pendleian) age is more than 1,800 ft (550
m) thick in places.
Lower Limestone Formation
The Lower Limestone Formation consists of repeated upward-coarsening cycles of
limestone, mudstone, siltstone and sandstone. Thin beds of seatearth and coal may
cap the cycles. The limestones, which are almost all marine and fossiliferous, are pale
to dark grey in colour. The mudstones, many of which also contain marine fossils, and
siltstones are predominantly grey to black. Nodular clayband ironstones and
limestones are well developed in the mudstones (Browne et al. 1999). The
depositional environment is interpreted as the repeated advance and retreat of 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.
Shale oil/gas properties
Organic-rich shales within the Lower Limestone to Coal Measures formations were also
considered potential sources of hydrocarbons by Parnell (1984). It was considered that
dark lacustrine shales and dolomitic laminites had some hydrocarbon generating
Trewin N.H. (ed) The Geology of Scotland. Fourth Edition. The Geological Society,
London, 251-300.
Turner, M.S. 1991. Geochemistry and diagenesis of basal Carboniferous dolostones
from Southern Scotland. PhD thesis, University of East Anglia.
Waters, C.N., Browne, M.A.E., Jones, N.S. & Somerville, I.D. 2011. Midland Valley of
Scotland. Chapter 14 in Waters C.N. et al. A revised correlation of Carboniferous rocks
in the British Isles. The Geological Society of London Special Report 26: 96-102.
WILKINSON, I.P. 2005. Ostracoda from the West Lothian Oil Shale Formation. British
Geological Survey Internal Report IR/05/036.
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T35 – Czech Republic – Lower Carboniferous shales of the Culm Basin
General information (see excel table from GEUS)
Index Basin Country Shale(s) Age Screening-
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.
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Geological evolution and structural setting
Syndepositional
The Lower Carboniferous Culm basin (CB) in the Czech Republic is the most south-
easterly part of the European Variscan foreland basin system known as the Moravo-
Silesian Terrane (Figure 1, Pharaoh et al. 2010). The NNE-SSW-trending basin forms
the eastern margin of the Bohemian Massif. The syntectonic foreland basin formed due
to load-driven subsidence in a compressional regime. Sedimentation started at about
340 Ma b.p., i.e. about 10-15 Ma earlier than the rest of the Variscan foreland. It
contains up to 7.5 km of deep marine sediments deposited as an axial turbidite
system sourced from S-SW (Hartely and Otava 2001). The Paleozoic burial was deep
in the West and decreased towards the East (Francu et al. 2001). The Culm basin is
overlain by Late Carboniferous Upper Silesian Coal basin in the North and Nemcicky
basin in the southern segment. Jurassic carbonates and marls (Mikulov Fm.) and
Eocene shales (Nesvacilka Fm.), both candidates for shale gas, cover the Culm in the
southern part. In the Miocene, the eastern part of the CB was buried below the West
Carpathian Foredeep and fold-and –thrust belt.
Fig. 2. Paleogeography and tectonic scheme of the Variscan terranes (Pharaoh et al. 2010 and sources therein) showing the position of the Culm basin in the Moravo-Silesian terrane adjacent to the Rheno-Hercynian terrane.
The Czech Culm basin is built by black shales, silts, and sandstones. They are
correlated with similar lithologies of the Fore-Sudetic Monocline Basin (FSMB) in
Poland (Botor et al. 2013), North German basin (Ladage and Berner, 2012), and
Lower Carboniferous Bowland shales in northern England (Andrews, 2013).
Structuration
The Czech Culm basin experienced tectonic deformation during the end of Lower
Carboniferous (Viséan) and the present western part exposed at the surface forms a
fold and thrust belt with tectonic shortening from W to E. The deformation decreases
below the Carpathians. This part of the CB represents the marginal foreland basin,
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which was least affected by the Variscan orogeny and is considered as the best
preserved part of the CB for shale gas exploration.
Organic-rich shales
The culm rocks include black shales and silts deposited under anoxic conditions and
elevated total organic carbon content (TOC). These source rocks contain kerogen type
III and partly mixed type II-III. For more details we refer to Albrycht et al. (2014).
Depth and thickness
The present-day depth of the top of Lower Carboniferous within the CB is 2100-7000
m, thickness increases in general towards the W, in the adjacent mountains up to
7500 m. In the prospective area gross thickness ranges from 100 to 1250 m with
average of 675 m. Net thickness range from 30 to 250 m with average of 140 m.
Shale gas/oil properties
TOC varies with the lithology from 0.59 to 11.33%. Prospective formations of Lower
Carboniferous in the CB occur within the later oil and gas windows (0.8-2.2%Ro).
Regional pattern of thermal maturity at the top Viséan shales is in Fig. 3. In general
the maturity increases from SE to NW and follows the increasing maximum burial
depth from the foreland to the fold-and-thrust belt (Francu 2000; Francu et al. 1999,
2002a, b; Gerslova et al. 2016). Gas shows and light hydrocarbon liquids have been
reported in the exploration boreholes in the Culm intervals. The maximum burial was
reached by the end of the Carboniferous (Weniger et al. 2012). Temperature at the
reservoir level varies from 80 to 210°C (Myslil et al. 2002).
Fig. 3. Thermal maturity pattern at the top of Culm shales and silts compiled for EUOGA. The red colors show high vitrinite reflectance values of the overmature window while the prospective area follows the blue-green-yellow interval (Dvorak and Wolf 1979; Francu et al. 2002).
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The average porosity range from 0.05 to 13%, adsorbed gas content (Langmuir
isotherm/sorption capacity) may be estimated from analogy to be about 1.25 m3/t and
average density of shale 2.6 kg/m3 (Andrews, 2013).
Risk components
Occurrence of shale
Mapping status
Variable Available seismic data is of variable quality but the surfaces and faults
are interpreted and mapped.
Sedimentary variability
Moderate Sedimentary modelling can be applied to enhance the current status of
lithological trends.
Structural complexity
Moderate The basin experienced burial and uplift. The prospective area is outside
the thrust-and-fold belt.
Hydrocarbon generation
Available data
Moderate Well logs, seismic surveys, kerogen type, TOC, Rock-Eval and vitrinite
reflectance are available together with core samples from the
exploration boreholes.
Proven source rock
Proven Part of the Culm basin does contain a proven gas system in the Lower
Carboniferous.
Maturity variability
Moderate Maturity shows clear regional trends increasing from SE to NW.
Recoverability
Depth
Average 2100-7000 m
Mineral composition
Proven rather brittle siltstones and shales rich in quartz and low amount of
expandable clay minerals.
References
Albrycht, I., Bigaj, W., Dvorakova, V., Francu, J., Garpiel, R., Osicka, J., Mathews, A.,
Sikora, A., Sikorski, M., Smith, K. C., Tarnawski, M. and Wagner, A. (2014): The
development of the shale gas sector in Poland and its prospects in the Czech Republic
- analysis and recommendations. The Kosciuszko Institute, 96 p.
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June 2016 I 223
Andrews I.J., 2013. The Carboniferous Bowland Shale gas study: geology and
resource estimation. British Geological Survey for Department of Energy and Climate