European Unconventional Oil and Gas Assessment (EUOGA) · 2017-09-13 · stochastic volumetric...

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Final Report for DG JRC in the Context of Contract JRC/PTT/2015/F.3/0027/NC

“Review of results, knowledge gaps and recommendations for future work”

European Unconventional Oil and Gas Assessment

(EUOGA)

Review of results, knowledge gaps

and recommendations for future

work

Deliverable T8

Review of results, knowledge gaps and recommendations

Final Report T8 March 2017 2



Table of Contents

Table of Contents .............................................................................................. 3 Overview of countries invited to participate in EUOGA and their association to the

project ............................................................................................................. 5 Abstract ........................................................................................................... 6 Executive summary ........................................................................................... 7 1. Introduction .................................................................................................15 2. Task 4: Geological resource analysis of shale gas and shale oil in Europe .............17

2.1. Summary of results from task 4 ................................................................17 2.2. Review of the results from Task 4 .............................................................17 2.3. Identified knowledge gaps and recommendations related to task 4 ................20

3. Task 5: Compilation of geological maps and web-portal .....................................22 3.1 Summary of results from task 5 .................................................................22 3.2 Review of the results from Task 5...............................................................22 3.3 Identified knowledge gaps and recommendations related to task 5 .................25

4. Task 6: Overview of shale layers characteristics in Europe relevant for assessment

of unconventional resources ...............................................................................27 4.1. Summary of results from Task 6 ...............................................................27 4.2 Review of the results from Task 6...............................................................28 4.3 Identified knowledge gaps and recommendations related to Task 6 ................30

5. Task 7: Resource Estimation of shale gas and shale oil in Europe ........................33 5.1. Summary of project results from Task 7 .....................................................33 5.2 Review of the results from Task 7...............................................................34 5.2. Identified Knowledge gaps and recommendation related to task 7 .................35

6. Summary of EUOGA results and recommendations ............................................39 6.1 Main results from EUOGA ..........................................................................39 6.2 Main identified knowledge gaps from EUOGA ...............................................40 6.3 Main identified recommendations from EUOGA .............................................41

7. References ...................................................................................................43 8. List of EUOGA deliverables .............................................................................44 Appendix A: Executive summaries for final report 2-7 ...........................................45 Deliverable T2b: Final Technical Report on evaluation of existing assessment

methodologies and the proposed common methodology for pan-EU assessment .......46 Deliverable T3b: Overview of the current status and development of shale gas and

shale oil in Europe ............................................................................................48 Shale gas and Shale oil resources and assessment status ...................................48 Activities related to shale gas and shale oil exploration .......................................49 Member state position towards shale gas and shale oil exploration .......................51 Basin and play overview .................................................................................53

Deliverable T4b: Geological resource analysis of shale gas and shale oil in Europe ....66 Deliverable T6b: Overview of shale layers characteristics in Europe relevant for

assessment of unconventional resources .............................................................67 Deliverable T7b: Resource estimation of shale gas and shale oil in Europe ...............69



This report is prepared by Niels H. Schovsbo, Karen L. Anthonsen, Christian B.

Pedersen, and Lisbeth Tougaard, from GEUS, and Susanne Nelskamp, Mart Zijp and

Hans Doornenbal, from TNO, as part of the EUOGA study (EU Unconventional Oil and

Gas Assessment) commissioned by JRC-IET.

The analyses, interpretations and opinions expressed in this report represent the best

judgments of the Geological Survey of Denmark and Greenland (GEUS) and TNO. This

report assumes no responsibility and makes no warranty or representations as to the

productivity of any oil, gas or other mineral well. All analyses, interpretations,

conclusions and opinions are based on observations made on material supplied by

participating National Geological Surveys (NGS).

The information and views set out in this study are those of the authors 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.

This report is final report, Marts 2017.

Citation to this report is: Schovsbo, N.H., Doornenbal, H., Nelskamp, S., Pedersen,

C.B., Tougaard, L., Zijp, M., Anthonsen, K.L., 2017. Review of results and

recommendations. Delivery T8 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



Abstract

Within the European wide EUOGA project 82 hydrocarbon bearing shale formations

within 21 countries were assessed for their unconventional resource potential. A

stochastic volumetric assessment could be carried out for 49 formations, 15 of which

are concluded to hold both shale gas and shale oil, 26 only gas and 8 only oil. The

total resource estimation for all assessed shale formations in all countries combined

amounts to 89.23 tcm of gas and 31.4 billion barrels of oil in place.

The 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. Gathered data

for each shale formation are stored in an ESRI file geodatabase. The description also

includes a full bibliographic reference database with more than 240 references

comprising the current state of the art of scientific research of European shale gas and

oil.

The EUOGA project has shown that many European shale formations are very sparsely

covered by well data or seismic survey data. This situation specifically exists in regions

with little exploration activities and low levels of (conventional) hydrocarbon

development, but there are also circumstances where the data are available yet

inaccessible due to confidentiality restrictions. The lack of data reduces the

hydrocarbon assessment precision and the resulting uncertainties in areal extent and

thickness have a profound impact on the volume determination. In addition to this the

saturation and porosity are the major uncertainties for determining the free gas and

oil volumes. These parameters tend to vary significantly within a shale formation (i.e.

both depending location-specific conditions).

To reduce the uncertainty of the European unconventional hydrocarbon potential it is

recommended to systematise the desired work in constructing of research consortia

among NGS and centres of excellence within their specific areas of competences. Such

research may ultimate refine, enhance or complete the resource assessments carried

out.

The results of the EUOGA project are:

A common pan-European assessment methodology

A compilation of the current status of the exploration and development of shale gas

and shale oil in Europe

A geological resource analysis including a compilation of geological maps and

characteristics of prospective European gas- and oil bearing shales

A quantitative resource estimation of prospective shale gas and shale oil resources

in Europe based on a common assessment methodology

A report on the results including recommendations for future work (this report)

A web-based interactive database and map application



Executive summary

A consistent and reliable assessment of the European geo-energy resources are the

basis for making informed social, political and commercial decisions. This requires a

shared and integrated geological model of the distribution and properties of Energy

sources and reservoirs, and uniform assessment methods based on robust, scientific

evaluation criteria.

The methodology established in the EUOGA project, where the EuroGeoSurveys

National Geological Surveys (NGS) compile their individual national geological

knowledge into comprehensive regional shale gas and shale oil GIS compilations with

a common Hydrocarbon assessments, has proven to be efficient to generate, easy

accessible, knowledge based, and thus reliable results.

It is recommended that same methodology is implemented in future Geo-energy

assessment studies. These geo-energy topics are:

Geothermal resource assessment

Resource assessment of shale gas and shale oil in offshore basins

Assessment of conventional HC resources

CO2 storage potential assessment

Coal resource assessment

Compiling all these data in the common European Geological Data Infrastructure

(EGDI) database will facilitate decision makers to manage the sub-surface in an

informed social, political manner.

Within the European-wide EUOGA project, 82 hydrocarbon bearing shale formations

within 21 countries were assessed for their resource potential. A stochastic volumetric

assessment could be carried out for 49 formations, 15 of which are concluded to hold

both shale gas and shale oil, 26 only gas and 8 only oil (Figure 1 and 2). The

participating NGS in the EUOGA project provided all public data and information

available from their respective countries. Parameters relevant for resource evaluation

purposes were gathered for each shale layer according to the current, publically

available knowledge using a common description template developed by the EUOGA

project team members. The description also includes a full bibliographic reference

database with more than 240 references comprising the current state of the art of

scientific research of European shale gas and oil.

The total resource estimation for all assessed shale formations in all countries

amounts to 89.23 tcm of gas and 31.4 billion barrels of oil in place (Table 1). The

volume estimations are performed per assessment unit. These units delineate parts of

the shale formations with more or less comparable characteristics. The overall

assessment workflow consists of:

Characterization of each formation by 20 geological assessment parameters. A gross

average value on the basis of the entire EUOGA database was used in case no

concrete determination was available.

Determination of the probability and uncertainty regarding the presence of gas and

oil in the shale formation

Subdivisions of each formation into assessment units using GIS data and cut-off

values

A ranking of the formation based on TOC, depth, thickness and maturity



Applying the accepted parameters as input for a GIIP/OIIP by use of stochastic

volumetric Monte Carlo calculations of the free gas, adsorbed gas and or the oil in

place.

Figure 1. Overview of the basin areas reported to have a potential shale gas and shale

oil resource by the NGS. From EUOGA task 3b report.



Figure 2. Overview of all 21 EU basins with outline of plays identified within the

EUOGA project. From EUOGA task 7b report.

Within the project, the participating NGS have been responsible for identifying the

relevant basins and shale formations within their countries, and providing the

geological descriptions and information. In order to ensure that relevant shale

formations are included, a guideline and selection criteria, based on experiences from

shale gas and shale oil exploitation in the US, were provided. For each of the selected

basins and shale formations the NGS supplied a critical parameter sheet with

measured or estimated parameters for each formation as well as a basin description

report outlining the structural-geological evolution and exploration history of the basin

as well as the most important shale play elements of the potential formation itself.

General hydrocarbon play elements were evaluated in order to provide an indication of

the likelihood that a shale formation is present and contains hydrocarbon resources

(hereafter: chance of success). This evaluation involved a semi-quantitative scoring on

coverage of critical data for assessing 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 assessment results including data provided by participating NGS are stored in an

ESRI file geodatabase. This includes public information about the exploration wells in

each country, geological structural elements and outlines of basins with related

attributes about TOC, maturity, thickness and depth.



Table 1. Overview of total resources summarized per country. *The GIP values for

these countries were calculated for formations between 5 and 7 km depth. From

EUOGA Task 7b report.

The return score of the critical parameters (Table 4) has shown that a good knowledge

level exist on traditional geological parameters such as TOC, maturity and gross

thickness. These parameters have been gathered for correlation and source rock

evaluation purposes for decades. However, for unconventional resources this is not

sufficient for detailed characterisation and a considerable knowledge gap exist in term

of bridging a traditional knowledge-base to a new and in most cases more advanced

state of knowledge.

In terms of assessment of the hydrocarbon resource then the sensitivity analyses

showed that the gas saturation and porosity are the major uncertainties for

determining the free gas and oil volumes. These parameters tend to vary significantly

within a shale formation. As gas saturation is typically determined for tested

hydrocarbon occurrences only the measured values for this parameter are rare (i.e.

the shale plays in Europe are mostly untested and without development).

Porosity is a better-known parameter that is determined from sedimentary core

analyses and wire-line log evaluations. Still only 35% percent of the formations have a

reported value most of which are based on sparse well data that is insufficient to

capture the full extent of regional variations. Porosity and saturation have a strong



weight (linear relationship) in the volume equations which causes a direct

progradation of uncertainties in the end results.

For the adsorbed gas the major influencing uncertainties are associated with the

Langmuir volume and formation thickness. The Langmuir volume parameter is a

generally poorly known factor with little measurements available for a few formations

only (7% of all reported formations). As this parameter has a very large value range

(even within a single formation), it may also have a strong influence on the final

volume estimates. The uncertainties in thickness are logically directly translated into

the volume distribution of the final adsorbed gas. For some formations the thickness is

a very uncertain factor, especially when only the gross formation thickness is known

from incidental well data and the net shale thickness must be estimated from a net-to-

gross relationship.

The validity and accuracy of shale rock and fluid characteristics predominantly

depends on the availability of special well data, measurements and analyses that are

in most cases only available from industry. Again the availability is generally very low

and, with only very few exceptions, insufficient for capturing regional and local

variations. An additional complication is that most exploration activities are aimed at

conventional hydrocarbon reservoirs, leaving most of the source shales out of scope.

Figure 3. Shale ranking/pre-screening criteria used. From EUOGA task 2b report.



Figure 4. Basin classified according to the shale ranking/pre-screening criteria. See

Figure 3 for definition.

On basin scale

For several basins the geological history is still insufficiently understood and better

constraints on the sedimentary evolution and history of burial, uplift and temperature

will help in predicting the hydrocarbon generation.

Many shale formations are very sparsely covered by well data or seismic survey data.

In some cases the mapping even relies on the extrapolation of distal observations.

This situation specifically exists in regions with little exploration activities and low

levels of (conventional) hydrocarbon development, but there are also circumstances

where the data is available, yet inaccessible due to confidentiality restrictions. The

lack of seismic data (3D or dense 2D) reduces the precision by which the extent and

internal depth variations (structuration) of the shale interval can be mapped. The lack

of well data hampers the vertical/stratigraphic constraining of the specific prospective

shale interval, particularly when this interval cannot easily be distinguished in a

seismic section. For many shale formations the depth and thickness are just rough

estimates. The resulting uncertainties in areal extent and thickness often have a

profound and direct impact on the volume determination (i.e. the bulk formation

volume).

In some cases there is no information at all, except for a general indication that

hydrocarbon-bearing shales may be present in the basin. In other cases the shales are

known to exist but they are not recognized as a separate stratigraphic unit

consequently the assessment must be carried out on the entire parent formation in

which they occur, resulting in a severe reduction of precision because the net

thickness as well as other parameters must be derived from inferred information.



Database

The knowledge gaps related to basin scale is also reflected in the database and

mapping. However, in addition to missing data, data in incompatible formats and lack

of data provider and/or confidentially of data also exist. Additional data loss occurred

when the received data did not comply with given standards.

For countries where the NGS did not participate, data were sought to be included from

open sources. This was the case for Germany were public available data from the BGR

homepage (BGR 2016) was used. For non-participating countries like Ireland and

Switzerland no open source databases could be recognised and no data were included.

Reporting and project organisation

Non-participating NGS was an issue that provided the highest level of knowledge loss

that partly could be replaced by the existence of open source databases wherefrom

relevant data could be extracted.

Recommendations

A summary of the recommendations identified in the EUOGA project are presented

below.


recommended to systematise the desired work in constructing of research consortiums

among NGS and centres of excellence within their specific areas of competences such


out.

For general characterisation especially the shale mineralogy is needed and it is

recommended that the importance of this parameter is acknowledged by directing

research. The mineralogy may have an impact on the porosity but this relationship

could not be determined from the available data. Clay minerology is important to

determine the so-called fraccability and influences the recoverability of gas and oil.

Parameters directly related to reservoir evaluation such as storage and transport i.e.

porosity, Langmuir parameters and permeability are recommended to be studied by

directing the research towards these aspects.

Many shale formations lack a proper and distinct stratigraphic definition (i.e. Member

or Formation level). It is recommended that regional stratigraphic studies and well

correlations shall be carried out by participating NGS. The stratigraphic definitions will

allow for a better and more specific mapping of depth, thickness and extent of the

shale layers thereby reducing uncertainties in volume determinations. Stratigraphic

definitions will furthermore help in properly correlating resources across borders and

analysing relevant shale properties. New well data may be needed when vintage data

is lacking or inconclusive for defining the stratigraphic intervals, but this is fully

dependent on industry activity. Governments could aid in shale hydrocarbon

exploration by giving out data which is so far ranked as confidential.

New exploration (industry) or research based stratigraphical drillings

(governments/NGS) are crucial and highly desirable. It is recommended that research

based drilling programs may be set-up to obtain these crucial parameters where

industry activity is not expected in the coming 5-7 years.

The characterization of structural complexity is at the moment not standardized.

Integrated cross-border studies by multiple NGS will improve the understanding of the

potential impact of structural elements on shale hydrocarbon prospectivity and

recoverability for formations that extend country borders.



Shale formations are often not consistently defined (stratigraphically) and mapped

across borders. Better correlation and consistent mapping may allow increase the

benefits from integration datasets from different countries. Consistency can be

improved by better aligning geological research and mapping programmes across

borders. This is among others an objective in GeoERA (a cross-thematic ERANET on

applied geosciences in Europe, recently started in 2017).

Database

The GIS guidelines concerned the optimal exchange formats for various GIS data and

were intended to professionals experienced in data management and general GIS

compilations. This was not always the case and it is recommended that a more

comprehensive guideline describing the work process of the deliveries for non-

professional GIS person should be made in future projects.


The reporting of the 18 month EUOGA project was five mid-term report for tasks and

eight final task reports for each tasks in addition to four progress reports and various

geodatabases. The documentation level was thus significant especially since the data

delivered from NGS did not come in as scheduled. As a consequence, updating of

reports, tables and maps was a continuous process. It is recommended that in future

projects that aim at delivering geodatabases and web-GIS applications that reporting

with paper reports is avoided. Instead, continuous updating via web-GIS is much more

productive and flexible.

The organisational structure used in this project is highly recommended. The

collaboration and commitment of all NGS under the auspices of EuroGeoSurveys (EGS)

was un-paralleled. The project documents that European National Geological Surveys

can work together to provide to a reliable assessment of European unconventional gas

and oil resources enabling a basis for making informed social, political and industrial

decisions.



1. Introduction

The European Unconventional Oil and Gas Assessment (EUOGA) project was launched

in September 2015. The EUOGA project was commissioned by JRC-IET and awarded to

a consortium of the Geological Survey of Denmark and Greenland (GEUS) and TNO on

behalf of EuroGeoSurveys (EGS).

Its mission was to perform a reliable scientific based assessment of European shale

gas and oil resources enabling a basis for making informed social, political and

industrial decisions. The involvement of a large group of National Geological Surveys

(NGS) has be crucial to the project as these institutions possess the fundamental

knowledge about relevant shale gas and oil source within their respective countries

(Figure 5).

The main objectives of EUOGA were:

to develop a common EU resource assessment methodology for shale gas and oil

to carry out an assessment of European shale gas an oil resources

to provide a web-based interactive database and map application

Figure 5. In EUOGA information on shale gas and oil resources for 26 countries are

included. Germany (Bundesanstalt für Geowissenschaften und Rohstoffe, BGR) is not a

member of the EUOGA project consortium. The status and categorisation given for the

situation in Germany reflects the authors judgements based on public documents,



especially the report of Schieferöl und Schiefergas in Deutschland (BGR 2016) and

personal communication. Figure from EUOGA T3b report.

The work interaction between partners in EUOGA was carried out in an organisation

structure as outlined in Figure 6. The GEUS has had the overall project management

together with the systematic gathering of shale formation data and development of

the shale oil and gas geodatabase. The developed a common European shale gas and

oil assessment methodology and preforming the resource estimations has been the

responsibility of TNO. The NGS provided national published information on shale

formations.

The EUOGA project is divided into the 8 following tasks (coordinator):

Task 1: Project management (GEUS)

Task 2: Common EU methodology (TNO)

Task 3: Introductory overview of the current status and development of shale gas

and oil in Europe (GEUS)

Task 4: Geological resource analysis of shale gas and oil in Europe (TNO)

Task 5: Compilation of geological maps and web-portal (GEUS)

Task 6: Overview of relevant shale layer characteristics (GEUS)

Task 7: Resource estimation (TNO)

Task 8: Review of results, knowledge gaps and recommendations for future work

(GEUS)

Figure 6. The EUOGA project organisation.



2. Task 4: Geological resource analysis of shale gas and shale oil in Europe

2.1. Summary of results from task 4

Task 4 delivered the geological descriptions and unconventional hydrocarbon play

characteristics of 82 shale formations occurring within 38 sedimentary basins across

Europe. Participating NGS 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 participating NGS were responsible for identifying the relevant basins and shale

formations within their countries, and providing the geological descriptions and

information. In order to ensure that relevant shale formations are included, a guideline

and selection criteria, based on experiences from shale gas and shale oil exploitation

in the US, were provided. The key criteria are thickness of more than 20 m, TOC

content of more than 2% and depth of less than 7 km.

For each of the selected basins and shale formations, the NGS supplied a critical

parameter sheet with measured or estimated parameters for each formation as well as

a basin description report outlining the structural-geological evolution and exploration

history of the basin as well as the most important shale play elements of the potential

formation itself.

All contributions were evaluated and the results summarized in a comprehensive and

harmonized geological synthesis. In addition to the geological descriptions, general

hydrocarbon play elements were assessed in order to provide an indication of the

likelihood that a shale formation is present and 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 on coverage of critical data for assessing 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 results from Task 4 are used as a basis for the

quantitative volume assessment of potential shale hydrocarbon resources under Task

7.

2.2. Review of the results from Task 4

With regards to the results of Task 4, this paragraph will focus on the following two

questions:

What confidence do we have on the presence and technical recoverability of gas and

oil in shale formations across Europe?

What information and knowledge is available to support this confidence?

Knowledge and information levels

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 biggest unknown, however, is whether these resources are technically and

economically recoverable, assuming the current state-of-art technologies. For this

aspect the EUOGA dataset provides no information.

The best known and most completely assessed shale formations are generally present

in areas with mature and developed conventional hydrocarbon plays. Good examples

are the Lower Palaeozoic shales in Poland (on-going exploration and testing), the Alum

Shale in Sweden and Denmark (recently drilled and tested), and several Mesozoic

shales in the UK, Netherlands, France and Germany (penetrated by many conventional

hydrocarbon wells). The existence of proven hydrocarbon fields is in many cases a

good indication that a mature and functioning source rock system is present whereas

the exploration and development activities have often resulted in a good coverage of

seismic and well data.

For many shale formations however, the level of knowledge is very low and relevant

well data and seismic surveys are either lacking or is confidential. Assumptions

regarding the presence of potential recoverable hydrocarbon resources are in these

cases often based on distal, extrapolated observations. Consequently such formations

are ranked by a low chance of success while prospective volume estimates are

associated with large uncertainties.

Overall it should be realized that the current information on European shales is

sufficient at most to assess the potential resources in a (supra-) regional context.

Local predictions on shale hydrocarbon resources will require very dense drilling

campaigns involving hundreds or thousands of wells to uncover the full potential. Such

information is nowhere present in Europe (not even in Poland were the highest

number of wells have been drilled).

Identification, geographical extent, depth and thickness

The major shale formations in EUOGA are generally well defined and constrained by a

distinct stratigraphic unit (Member or Formation level). Such definition is the key to

accurately mapping the outline, depth and thickness of the prospective interval and

assessing the associated rock and fluid properties. In some instances shale formations

are not specified by a distinct stratigraphic unit and only an approximate age of

deposition and the basin in which they occur, are known. Sometimes a stratigraphic

definition is only available for the encompassing parent unit, in which case the prolific

intervals are indirectly identified from a percentage of organic-rich layers occurring

within the parent unit. In both situations it is difficult or even impossible to accurately

determine depth, thickness and extent of the shale intervals, or to establish

correlations with equivalent formations across borders.

The depth and thickness of the formation are described by minimum, maximum and

average (most-likely) values and cover the variations across the entire formation or

extend of the assessment unit. Even when sufficient data is available for accurate

mapping, these ranges may be very wide when the basin is structurally complex and

no further subdivision in specific assessment units has been made (e.g. depth and

thickness ranges covering both the more shallow basin margin and deep basin centre

regions). When the shale thickness is derived from a percentage of organic-rich layers

within the parent stratigraphic unit, then it is often unknown how thick the individual

prolific shale intervals are (i.e. the shale may be distributed over multiple thin layers

or occur as one, more homogeneous interval). In such cases the validity of the applied

thickness cut-offs may be incorrect.

When well data or seismic data are not available and when the shale interval lacks an

appropriate stratigraphic definition, then the shale layer extent is sometimes defined



by the full basin outlines. This may result in an overestimation of the area where the

distinct prolific interval is located. Where possible, this uncertainty is accounted for in

the minimum and maximum area ranges.

Cross-border correlation

Several assessed basins and shale formations extend across country borders. If

needed the formations was corrected between countries using the knowledge and

information provided by the respective NGS. Often the correlation was not straight

forward, but challenging as stratigraphic definitions and level of knowledge vary per

country. In some cases the formations are not defined in the adjacent areas and

consequently the mapped extent is cut by the country boundaries. Despite these

complications, the project could benefit from the cross-border integration of

information, especially with regards to the regional geological development of some of

the relevant parameters for the volume determination.

Regional geological evolution and structural setting

Compilation of the geological country reports provided by NGS was done in order to

present uniform and systematic descriptions of the geological evolution and structural

setting in the T4 Report. In most cases the descriptions of cross-border shale

formations could successfully be combined in one description.

The European shale formations and basins generally exhibit a relatively complex

structural and sedimentological configuration. The extensively and accurately mapped

Posidonia Shale in The Netherlands for example, is contained within well-defined basin

outlines, but internally this formation is heavily faulted with large vertical offsets. The

degree of complexity often depends on the type of basin as well as on the size of that

basin (e.g. very large basins more likely exhibit extensive lateral sedimentological

variations). In general the younger formations are characterized by less structural

complexity, especially when located away from the major orogenic belts such as the

Alps.

In general there is not such a thing as “a typical European gas shale or oil shale”.

European shale formations and basins have a widely varying appearance and

geological background. The formations are often distributed over smaller sub-basins,

each of which exhibits a unique structural evolution and sedimentary development.

Shales have furthermore developed over different geological time intervals, ranging

from Cambrian (~500 Ma) to Neogene (~20 Ma) age. Consequently it is not easy to

exchange information and knowledge across basins. When a certain shale formation

will be proven successful as technical recoverable resource, then this will have very

little (if any) impact on the prospectivity of other formations. Resolving the shale gas

and shale oil potential in Europe will therefore require a basin-by-basin and formation-

by-formation exploration strategy.

Chance of success components

The overall chance of success is defined by the three main aspects “Occurrence of

shale”, “HC-generation” and “Recoverability”. Each of these aspects has several sub-

components described in Report T2b and T4b. As mentioned earlier, the reliability and

accuracy of these components 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.

Occurrence of shale

The certainty by which the presence of a shale can be predicted is strongly depending

on the available information from wells and seismic. Although this risk is relatively low

in mature hydrocarbon provinces, it can be a significant factor in many of the



underexplored regions, especially when the shale distribution within the given outline

is known to be heterogeneous. In some cases the information submitted by the NGS

was unclear as the outlines of the shale formations were provided without further

background on their geological interpretation and definition. In these instances it is

particularly difficult to determine whether the outline is representative for the shale

occurrence or not (e.g. due to depositional or structural hiatuses not captured by the

outline).

Hydrocarbon generation

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. This situation exists for several of the major shale plays included in

EUOGA (e.g. the Mesozoic shales in Central Europe, the shales of the Dniepr-Donets

Basin in the Ukraine or the biogenic plays in the Transylvanian Basin in Romania). The

presence of conventional resources however, does not tell whether also the shale

resources are recoverable. Neither is this information of great value to estimating the

volumes (except for the gas composition and knowing that parts of the shale

resources have been expelled over geological time). When proven conventional

resources are not present in the basin, this factor must be determined from TOC,

maturity measurements and basin modelling results. Often these data are very sparse

(especially in these regions) and assumptions must be made from distal wells and

outcrops. This leaves a lot of room for uncertainties regarding the presence of

generated hydrocarbon resources.

Recoverability

This is probably the most challenging risk factor in shale gas and shale oil

development as this is depending much on the local conditions and the information is

very sparse. Mineralogical compositions are either not provided by the NGS or the

information did not allow for a clear judgement on the favourability of the

mineralogical composition.

Report T6b provides the exact parameters for each of these components per basin and

per shale formation.

2.3. Identified knowledge gaps and recommendations related to task 4

The following main knowledge gaps and recommendations are identified:

Many shale formations are lacking a proper and distinct stratigraphic definition (i.e.

member or formation level). This can be solved by carrying out regional

stratigraphic studies and well correlations. The stratigraphic definitions will allow for

a better and more specific mapping of depth, thickness and extent of the shale

layers, thereby reducing uncertainties in volume determinations. Stratigraphic

definitions will furthermore help in properly correlating resources across borders and

analysing relevant shale properties. New well data may be needed when vintage

data is lacking or inconclusive for defining the stratigraphic intervals.

In some countries the mapping of subsurface geology is still in an early stage. When

vintage data is available, state-of-art 3D modelling can be used to better determine

the spatial distribution of shale formations, reducing the risks regarding shale

occurrence and predicting/estimating relevant shale properties. If no or little

exploratory (well/seismic) data is available, further mapping will of course be of

minor influence. Making proprietary industry data publicly available may help in

some regions.









Many data sources are still untapped (e.g. mineral composition) or can be upgraded

by new analyses (e.g. TOC, rock pyrolysis, Rock-Eval, maturity) and interpretations.

This action will extend the knowledge on shale properties including maturity and

fraccability. Public dissemination of confidential (proprietary) data from industry

may greatly improve the knowledge levels in many basins. Other regions will

depend on the acquisition of new data.

For several basins the geological history is still insufficiently understood. Knowing

the sedimentary evolution and history of burial, uplift and temperature, will greatly

help in better predicting the hydrocarbon generation in shale layers.

The characterization of structural complexity is still not standardized. Integrated

cross-border studies will improve the understanding of the potential impact of

structural elements on shale hydrocarbon prospectivity and recoverability.

All in all it should be realized that above actions will only increase our knowledge in a

regional context. Further exploration and development of shale gas and shale oil

resources will involve the drilling of tens to even thousands of wells in order to capture

the local variations and to identify hot spots for new exploratory drilling. A

comprehensive and reliable regional geological framework will greatly improve the

value that can be gained from such drilling campaigns, among others assisting in

selecting the best locations to reveal eventual prospective hydrocarbon resources in

the shale formations. Furthermore the regional models will be needed to model the

overall basin evolution and regional structural and depositional development.



3. Task 5: Compilation of geological maps and web-portal

3.1 Summary of results from task 5

The main results of task 5 are an ESRI file geodatabase containing all data provided

by the participating NGS together with the assessment results and a series of maps for

each basin.

The delivered data from the NGS’ included public information about the country’s

exploration wells, geological structural elements and outlines of basins, with related

attributes as TOC (Total Organic Carbon), maturity, thickness and depth. The data are

illustrated in a series of maps delivered in the T5a report (example shown in figure 7).

The database contains 169 basin polygons, whereof 69 have enough data to be

suitable for assessment. The assessment results from EUOGA task 7 are also included

and added to the selected polygons. Additionally, the database contains the extent of

European sedimentary basins relevant for the EUOGA project.

Figure 7. Example of GIS attribute map layer from the EUOGA geodatabase.

3.2 Review of the results from Task 5

In total, 19 out of 21 countries have delivered acceptable GIS data for the EUOGA

project. The deadline for the submission was initially 1st of February 2016. This

deadline was extended to April 30th. By this date only thirteen countries had delivered

the required data (Table 2). Eight countries delivered after the extended deadline and

out of these latecomers four countries delivered very late (after September).



Number of

countries

Delivery within

month in 2016

13 Before May

2 In May and June

2 In September

3 In November

1 In December

Table 2. Number of countries and month of GIS data delivery.

The quality of the delivered data

The quality of the GIS data for each country has been evaluated and the results are

marked with a colour code in Table 3. In the evaluation a red colour indicate that a

country has delivered the requested GIS data, but that the data is in a state that

makes them unusable and no replacement has been received.

The most frequently occurring deficiency in the GIS data was that the polygons did not

contain important attribute information. Supplementary information has been added to

the GIS data when it was available either from the delivered critical parameters (CP)

or from the basin reports. In some cases, the GIS data had attribute information that

did not match the associated delivered critical parameters. Additionally, a frequently

occurring error was that the delivered data were not in the required coordinate system

or the coordinate system was incorrectly re-projected into the required reference

system.

In some cases, data were either in a condition where it was necessary to edit them

manually or re-acquire them from the NGS in order to make them useable. For one

country, the data did not meet the requirements at all and as a workaround polygons

were digitized from delivered isopach contour lines. This was done only where it was

durable and in agreement with the NGS. In one case the NGS was not able to deliver

any GIS data, but instead delivered non-georeferenced tiff files and excel sheets. In

this case basin polygons and well positions were made on basis of the delivered data.

In cases where the geometry of the delivered GIS data was not complete or had minor

errors, new data have been requested from the NGS. Mostly new datasets were

provided, but in situations where the NGS could not provide corrected data, the

necessary editing was done.

Germany was not part of the subcontractors in the EUOGA project. Instead public

available data from the BGR (BGR 2016) were used. Germany has therefore not been

subject to any delivery conditions.

Upon receipt of the GIS data a delivery summary was prepared in a schematic manner

for documentation of when data was received and eventually updated, including a

summary of what kind of data that had been delivered. In addition, it is stated

whether there have been any specific remarks about the attributes data and noted if

any errors or deficiencies occurred. Table 3 summarises the nature and quality of the

received GIS data.



● GIS data delivered

(●) Data delivered on special terms

No remarks

Minor remarks

Major remarks or not accepted

No data received

Country

Well

data

Structural

elements

Outlines of potential

shale oil/gas fm.

Attribute

data

Grid

data

Austria ● ● ●

Belgium ● ● ● ● ●

Bulgaria ● ● ● ●

Croatia ● ● ●

Czech ● ●

Denmark ● ● ● ●

France ●

Germany (●) (●) (●) (●)

Hungary ● ● ● ●

Italy ● ● ●

Latvia ● ● ● ●

Lithuania ● ● ● ● ●

Netherland ● ● ●

Poland ● ● ● ●

Portugal ● ●

Romania ● ● ●

Slovenian ● ● ● ● ●

Spain ● ● ● ●

Sweden ● ● ●

Ukraine ● ● ● ● ●

UK (●) (●) (●)

Table 3. Overview of data quality.

Overview and review of delivered metadata for the GIS data

A metadata schema was prepared for each country’s GIS data delivery and was

completed by the NGS’ themselves except for Romania, Czech and Germany. The

metadata are included as appendix in the EUOGA T5b deliverable.

The metadata schema is primarily for internal registration, to track where the GIS

data originates from and whether they were created especially for the EUOGA project.



The metadata contains the filename of the individual delivered features in the dataset,

with information about responsible organisation, responsible contact person, date of

last revision, spatial resolution, data abstract and a description of origin data and its

history.

3.3 Identified knowledge gaps and recommendations related to task 5

Potential knowledge gaps

Through the processing and data management of the provided GIS data several

common problems have occurred and these were registered within each of the

individual GIS datasets. A large majority of these problems were related to issues

where the GIS data did not meet the requirements specified for the EUOGA project

and in all cases they represent potential knowledge gaps.

In a few cases, no GIS data were available (only printed maps) or only in a wrong

format (e.g. couture lines of top formation, where a formation outline polygon was

needed). In these cases the formation or basin outline was digitized by GEUS, but

potential knowledge gaps might occur as the necessary distinctive local knowledge are

insufficient. In one case, the necessary workload to finish unfinished polygons was

considered too comprehensive and the lack of information too substantial to consider

the areas to have potential for further processing. Consequently the areas have not

been digitized and have been disregarded with a notification to the NGS.

Recommendation for improvements

In several cases, the GIS data were delivered after the agreed deadline. This has

influenced the available time to review and process the data. Furthermore, the delays

impacted the time schedule for subsequent work tasks within the EUOGA project

notably the assessment work in task (T7). It has been critical that in the final

assessment process, the critical parameters and/or the play area was changed after

the geodatabase was finalised. This has resulted in a number of iterative geodatabase

updates.

It was a prerequisite that the delivered GIS data should meet the data terms specified

in the “Terms of Delivery” and GIS guidelines presented at the first EUOGA workshop

in Copenhagen, December 2015. Within the GIS data processing time frame and

budget, no time was allocated to digitalization, re-projection or similar tasks as it was

expected to receive GIS data that could smoothly be integrated. But in some cases

data was delivered without fulfilling the data requirements and no additional data

could be delivered. Therefore, an initial overview of the data format and quality is

recommended as this will allow to plan and allocate time and budget to include

analogue data sets.

Where the NGS were not able to deliver the required data, it could be examined

whether or not alternative data sources could be used as supplement. In total, 19

countries out of 21 delivered acceptable basin outlines, but 11 countries have not

submitted data on wells and/or structural elements. Some of the delivered GIS data

was missing important information (attribute data) and it was not possible to extract

the missing data from either the associated critical parameters excel sheets (Task 6

report) or the geology/basin reports (Task 3 and 4 reports). Often fundamental

attributes as e.g. name, depth, thickness, structure type, etc. was lacking.



Concerning GIS guidelines

The GIS Guidelines were presented and discussed at the EUOGA kick-off meeting in

Copenhagen the 7th of December 2015 and were approved by the participating NGS.

The GIS guidelines comprised standards and work processes primarily concerning the

relevant geology-related data needed for the shale resource analysis and assessment.

The guideline reflected current knowledge and anticipation of the project at that time.

A section in the guideline concerned the optimal exchange formats for the various GIS

data and was intended to experienced professionals in data management and general

GIS compilations. Throughout the guideline, the term “standard” referred to those

principles which are required when creating national GIS compilations, where the term

“guidelines” refers to optional best practices which should be followed to ensure

consistent data formats, data types, spatial references and information attributes

associated with the spatial GIS data.

The requirements in the guidelines were not always met and a lesson learned was that

there should possibly have been written a more comprehensive and descriptive set of

guidelines for the expected work process of delivering data, as experience in data

management and general GIS compilations is highly variable.



4. Task 6: Overview of shale layers characteristics in Europe relevant for assessment of unconventional resources

4.1. Summary of results from Task 6

The main objective of task 6 was to provide a consistent gathering of critical

parameters relevant for assessment of the oil and gas potential. A total of 82 shales

from 33 thermogenic and two biogenic gas bearing onshore basins were characterised

to the best extend of data. The complied data are based on information and expert

judgments gathered from the respective European NGS. Parameters relevant for

resource evaluation purposes were gathered for each shale layer according to the

current, publically available knowledge. The description also includes a full

bibliographic reference database with more than 240 references comprising the

current state-of-the-art of scientific research of European shale gas and oil.

Average properties for all European shales and for typical Carboniferous and Jurassic

shales are presented, applicable as a prior approximation for resource assessment

parameterisation based on European analogues (Table 4). The European shales

compare well with prospective North American shales with respect to lateral extent,

thickness, TOC content, and maturity.

Table 4. Assessment parameterisation based on European analogies based on the

EUOGA critical parameters that uniformly describe the EU prospective shales. The

North American shales are based on Jarvie (2012). Abbreviations: Avg: Arithmetic

mean; Min: Minimum; Max: Maximum; Carbon: Carboniferous; Palaeo.: Palaeozoic.

CP: unique index number. Table from EUOGA task 6b report.

Shales

with

reported

value

Mean

EUOGA

shale

Min

EUOGA

shale

Max

EUOGA

shale

Mean L.

Palaeo.

EUOGA

shale

Min L.

Palaeo.

EUOGA

shale

Max L.

Palaeo.

EUOGA

shale

Mean

Carbon.

EUOGA

shale

Min

Carbon.

EUOGA

shale

Max

Carbon.

EUOGA

shale

Mean

Jurassic

EUOGA

shale

Min

Jurassic

EUOGA

shale

Max

Jurassic

EUOGA

shale

Mean N.

American

Shales

Min N.

American

Shales

Max N.

American

Shales

1. Shale index (CP) 2014Avg 2014Min 2014Max 2016Avg 2016Min 2016Max 2017Avg 2017Min 2017Max 2018Avg 2018Min 2018Max 2015Avg 2015Min 2015Max

2. Gros thickness 52 461 16 2800 353 20 2296 622 50 2800 165 30 650 147 55 366

2a. Net thickness 57 143 8 1504 192 16 1504 140 30 495 162 8 650 83 41 152

2b. Net/Gross 43 47 0 100 68 23 100 40 6 100 35 9 100 70 29 100

3. Depth (m) 64 2372 30 6000 2195 30 4430 1875 1016 4500 2783 465 5500 2565 1311 3810

4. Density (g/cm3) 52 2,45 2,10 2,71 2,51 2,15 2,70 2,50 2,30 2,71 2,50 2,15 2,65

5. TOC (%) 62 3,40 0,50 20,00 4,67 1,12 11,00 2,97 1,00 8,20 5,00 0,95 20,00 2,97 1,33 5,34

6. Porosity (%) 27 4,69 1,50 11,80 4,79 2,00 7,00 3,76 1,50 10,10 6,47 4,20 11,80 6,33 4,00 10,00

7. Maturity (%VR) 47 1,34 0,34 4,00 1,71 0,50 3,00 1,67 1,10 3,09 0,78 0,60 1,20 1,69 1,20 2,50

8. Reservoir pressure

(psi) 25 4093 350 13900 3926 435 7106 3302 370 6527 8189 4786 13900

9. Reservoir

Temperature (°C) 26 94 15 165 74 15 135 97 62 125 126 78 150

10. Gas saturation (%) 19 28 3 67 56 21 67 14 3 55 37 23 50 63 40 90

11. Oil Saturation (%) 7 14 0 70 5 0 6 0 0 0 0 4 1 15

12.Hydrogen index 40 246 2 658 255 55 513 155 30 346 373 6 570 30 10 80

13. Kerogen type 61 II II II-II/III II II

14. Sorption capacity

@ Vr 1,9 % 2 0,18 0,15 0,20 0,20 0,20 0,20 0,15 0,15 0,15

15. Matrix

permeability, nD 7 89 0 340 70 40 100 143 0 340 5 5 5 157 10 1000

16. Adsorbed gas

storage capacity 14 47 33 81 45 44 50 43 33 45 81 81 8117. Compressibility

factor (z) 8 0,98 0,85 1,01 1,00 1,00 1,01 0,93 0,85 1,00

18. BgGas formation

volume factor 10 0,0112 0,0032 0,0212 0,0061 0,0032 0,0133 0,0155 0,0046 0,0212 0,0195 0,0195 0,0195

19. Langmuir Pressure,

Psi 6 1230 395 3916 435 435 435 1739 395 3916 1290 1290 1290

20. Langmuir Volume,

m3 6 69 30 170 36 36 36 58 30 98 170 170 170

21. Average clay

content (%) 29 47 0 80 53 51 56 50 5 80 34 0 53 31 17 51

22. Average quartz-

feldspars content (%) 29 32 4 69 39 33 46 39 15 69 28 4 43 44 17 69

23. Average

carbonate content (%) 29 21 1 96 8 1 11 11 5 26 39 23 96 25 6 67



The European prospective shales are, however, dominated by more clay rich rock

types than producing North American shales. High clay content is known to pose

engineering related difficulties during drilling, completion and production; hence it

may pose challenges for successful implementation of North American shale gas and

oil technologies to Europe.


Initial screening of Europe: EUOGA selection criteria for shale layers

Providing pan-European screening criteria for shales was important during the initial

data gathering steps to focus the work on the most important units and basins on

which more detailed gathering of data was made. The criteria is presented in Table 5

and reflect commonly acceptable screening values chosen to ensure that the right type

kerogen is present (marine) with significant TOC (>2%) values, that the shale has

significant thickness (>20 m), that the thermal maturity ensured generation of

hydrocarbons (at least oil maturity) and that the present day reservoir has maintained

its integrity (medium structural complexity). Present day depth above 7 km is used to

exclude shales that are not within reach of the well bore.

Table 5. Selection criteria for biogenic and thermogenic shale plays. Table from

EUOGA task 6b report.

For biogenic plays the criteria is similar to those used for thermogenic plays with

respect to TOC and thickness cut-offs. The preferential maturity range for this play is

immature to wet-gas mature since the biogenic gas generation depends on

biodegradable kerogen and/or bitumen within the shale (i.e. Krüger et al. 2014). For

biogenic gas to be produced loss of reservoir integrity is typical a requirements (i.e.

Krüger et al. 2014; Schultz et al. 2015). This is typical formed in structural complex

settings (such as in glacier induced fractured shales) where microbial activity occur

due to addition of freshwater into the shales system. Accordingly basins with biogenic

gas shale plays will be screened for by applying a depth criterion > 1 km and raising

the structural complexity from medium to high.

Similar types of screening criteria and considerations as mentioned above is seen in

various global to local assessments reports. Such as Charpentier & Cook (2011), ARI

(2013), Schovsbo et al. (2014) and BGR (2016). Within Europe 82 shale layers meet

the EUOGA screening parameters. For these shales 30 parameters of which 22 could

be specified with a probability density function (min, max, mean and mode of

distribution) data were specified to the best extend of data by the NGS’s. The return

ratio (calculated for numerical data as the ratio of the number of reported mean

values to the total shales layer number) range between 3-100% with an overall

average for all parameters (including non-numerical information) of 50%.



Mean composition for various EUOGA shales

The shale layers in Europe range in age from Cambrian to Neogene. Of all shales

about 52% are Palaeozoic, about 36% Mesozoic and about 11% is younger than this.

The typical EUOGA shale is marine (typically a type II kerogen) and has a TOC content

of 3.4% (Table xx5). The average depth of all layers is 2.3 km and by excluding the

shallow biogenic shale gas related layers, the average depth of the thermogenic layers

are 3.2 km with a range of 1-6 km. The average maturity of the shale layers is 1.3%

Vr and excluding immature layers (<0.6% Vr) the average maturity increases to 1.6%

Vr. The average porosity is 4.7% for the EUOGA shales and the reported gas

saturations is 28% and the oil saturation is 14% of the total porosity volume. The

matrix permeability averages 89 nDarcy. These parameters are, however, calculated

from a rather low number of shale layers as the amount of data in the database is

quite low.

The mineralogical composition covers a wide range of compositions and the term shale

layer is used more as a collective term for fine grained sedimentary rocks. A total of

seventeen shale layers were provided with XRD total rock component (36% of all

shale layers). The majority of the shale layers have total clay content that exceeds

50%.

The most common geological period of all shales is the Carboniferous. Average

compositions for Lower Palaeozoic, Carboniferous and Jurassic shales in the EUOGA

database have been calculated (Table 4). The Lower Palaeozoic shales are the most

clay rich and mature shales whereas the Jurassic shales are on average carbonate rich

and are the least mature shales. The Carboniferous shale is typical less organic rich

than the average shale composition (Table 4). It has an average gross thickness of

620 m but only about 40% of the thickness is prospective. The kerogen type is

reported to be a mix of type II-II/III (Table 4).

Comparison of EUOGA shales to literature data on North American producing

shales

Ten reference basins and shales presented by Jarvie (2012) have been included in

order to compare the EUOGA shale layers and basins with similar North American

cases. These North American shales are all from thermogenic shale gas resource

systems and reflect conditions within the core producing areas of each basin (Jarvie

2012).

The grand average of all EUOGA shale layers lies quite close to the grand average of

all the North American shales (compare CP214 and CP2015 in Table 4). An important

difference for the hydrocarbon assessment is, however, that the European shales on

average have 4.9% porosity whereas the North American shales on average have

6.3%. It must be stated that the European shales are rather poorly characterised with

respect to porosity. Furthermore, the North American shale layers reflect conditions in

the core-area defined as optimal for production - an area definition that the EUOGA

database does not reflect.

The mineralogical compositions of the EUOGA shale layers are rather poorly defined.

Nevertheless, important differences are apparent between the two continents. The

mineralogy of North American shales are typical dominate by non-clay components

and thus the ratio non-clay / total clay is more than 1. As a reflection of this the

compilation by Jarvie (2012) shows that out of the ten shales only one shale layer has

total clay content that exceeds 50%. In contrast to this the larger proportion of the

EUOGA shale layers are clay dominated. Since high clay content is known to pose

engineering related difficulties during drilling, completion and production of

hydrocarbon resource plays in the North America, this is a concern with respect to a



successful implementation of North American technologies to Europe. The EUOGA

database may not, however, reflect the composition within a hypothetical core-

producing area.

Bibliography database for critical parameter data

The bibliography of more than 240 references representing the state-of-the-scientific-

knowledge of the defining the Screening parameters was gathered from the reported

critical parameters sheets. The list of literature represents a review by itself and will

be an important source for future studies. Similar detailed documentation of source

literature for regional complied data is rarely seen i.e. compare to ARI (2013) or

similar studies.

4.3 Identified knowledge gaps and recommendations related to Task 6

The return score on the completed critical parameters sheet together with the

bibliography of shale gas and shale oil related literature are excellent focal point to

identified knowledge gaps in the European community relevant for unconventional

assessment.

Return Scores

The average porosity is 4.9% for the EUOGA shales and the reported gas saturations

in the EUOGA shales is 28% and the oil saturation is 14% of the total porosity volume

(Table 4). The matrix permeability averages 89 nDarcy. These values are calculated

from a rather low number of shale layers as the amount on data in the database is

quite low (Table 4). More research and data from exploration wells is required to

broaden the understanding for these key-parameters. However, we expect that as

time progresses more data will be made public available as it has been the case for

Sweden where important new data has recently been release following the shale gas

exploration program made by Royal Dutch Shell in 2008-2011.

A total of 29 shale layers were provided with XRD total rock component (35% of all

shale layers). Of these three shales have a total carbonate content that exceed 50%.

The 55% of the shale layers have total clay content that exceeds 50%. In this group

total clay may range up to 80% (Table 4).

The mineralogical compositions of the EUOGA shale layers are rather poorly defined

and since high clay content is known to pose engineering related difficulties during

drilling, completion and production of hydrocarbon resource plays in the North

America, this is a concern to a successful implementation of North American

technologies to Europe. This identified knowledge gap within the European community

raises an aspect that merits better characterisation and research.

Initial screening parameters for shales

The data gathering for task 6 was based on the results of the European basins

screening performed by the NGS as an initial part of the project. The screening criteria

were selected on the first workshop and reflect commonly accepted criteria. The NGS,

however, returned data on shales that either did not meet some of the screening

criteria or had un-documented values for key parameters. This is reflected by the TOC

content and the thickness that both were required to be use in the screening. For

these two criteria 22% and 30% of the shales did not have these parameters reported

(Table 4).

All reported shales were registered in the EUOGA database since they were recognised

based on expert judgments (the fact that the NGS reported the shale) as important for

unconventional development in Europe. Nevertheless some NGS might have used a



more strict definition of the screening criteria for selecting shales and thus the EUOGA

database does not necessarily host all shales recognised as important. It is

recommended to have used broader terms for selecting shales thereby including

expert judgments. A term “Recognised by NGS as important although poorly

characterised” would have been in its place. We initial also considered to use the shale

pressure, fraccability, land use and surface area as screening. These features where

not used as they are much more difficult to apply and define in an operationally

manner.

Data gathering for tight gas/oil play and for CBM

It is recommended in future assessment and data gathering that a broader concept of

plays is included. This to ensure that the continuum from shale oil and gas plays to

tight oil/gas plays and to coal bed methane plays are captured. A possibility to harvest

data from the NGS related to these types of plays is highly recommended as it will

give a more complete inventory.

Bibliography

The bibliography created during task 6 consists of more than 240 references. The

references were gathered from reported critical parameter sheet and were used by the

NGS as source reference for their data and are thus very specific in its definition. A

more broadly defined reference database is a recommendation. General literature

gathering could have been part of the data search.

Critical screening sheet

As mentioned above it is recommended that the initial screening parameter was less

robust defined to ensure that more shales were entered in the EUOGA database. For

further gatherings it is recommended also to include distribution modes for mineralogy

and the main types of minerals that are present, and not only its main groups. This is

especially relevant for the EUOGA clays dominated shales. NORM content could have

been relevant to include parameters also relevant for environmental aspects.

The issue of fraccability and thus geomechanical aspects was not covered. Since the

return scores gives a very good picture on the general knowledge levels in EU on shale

research it would be recommended to have included this aspects also in the critical

screening sheet.

Directing research – closing the gaps by future work

The return score of the critical parameters have shown that a good knowledge level

exist on traditional geological parameters such as TOC, maturity, stratigraphy and the

like typical applies for correlation and source rock evaluation. However, for

unconventional resource this is not enough and a considerable knowledge gap exist in

term of bridging the traditional knowledge to the new and in some cases more

advanced research areas needed when the shales are to be evaluated as reservoirs. It

is recommended to systematise the needed work in constructing of research consortia

among NGS and centres of excellence within their specific areas of competences such


out.



national research. Also parameters directly related to reservoir evaluation such as

storage and transport i.e. porosity, Langmuir parameters and permeability are

recommended to be studied by directing the research towards these aspects.



New data and research from shale gas and shale oil exploration and

production

Our knowledge are data driven and for some of the basin assessments could not be

made due to a lack of most basic data such as basin stratigraphy, thickness, TOC etc.

For these basins data for new exploration or research based stratigraphic drillings are

crucial and highly desirable. It is recommended that research based drilling programs

may be set-up to obtain these crucial parameters.



5. Task 7: Resource Estimation of shale gas and shale oil in Europe

5.1. Summary of project results from Task 7

The EUOGA study incorporates data for 82 potentially hydrocarbon-bearing shale

formations within 38 geological basins covering 21 countries of Europe. Based on the

gathered critical parameters (Task 6) and the methodology developed (Task 2), 49

shale formations within 19 countries were selected for a stochastic volumetric

assessment of prospective hydrocarbon resources (Table 1). Fifteen shale formations

are believed to hold both shale oil and shale gas, while 26 shales are considered to be

only gas bearing and 8 shales only oil bearing. The total estimated resource potential

for all assessed countries within the EU is 89.2 tcm of gas initially in place (GIIP) and

31.4 billion barrels of oil initially in place (OIIP) (Table 1).

The volumetric assessment presented is based on the following input and preparatory

steps:

A characterization of each shale formation by 20 geological assessment parameters,

as provided by the NGS and processed as part of EUOGA project task 6. In case no

parameter value has been provided for a certain assessment unit, an average value

has been determined from the combined available parameters for all shale

formations included in EUOGA.

A determination of the probability and uncertainties regarding the presence of gas

and oil in each shale formation (Task 4 report, results summarized in Appendix A).

A subdivision of each shale formation into regional assessment units using GIS data,

parameter values and common agreed cut-off values.

A ranking system based on TOC, depth, thickness and maturity of the shale

formation which leads to three classes of certainty represented in the final numbers

(Figure 3).

Based on the outcomes of these preparatory steps and input data the GIIP/OIIP

calculation per formation and basin were performed applying the Monte Carlo method

as outlined in the EUOGA task 2 report. For gas-bearing shale formations the amounts

of free gas as well as the amounts of adsorbed gas have been estimated. For oil-

bearing shale formations the amount of free oil has been estimated.

Sensitivity analysis of the results shows that the highest uncertainties for free gas are

related to the saturation and the porosity. For the adsorbed gas the highest

uncertainties are related to the Langmuir Volume and the formation thickness and for

the oil in place then the highest uncertainties are related to saturation. For each

formation, however, the exact distribution of these parameters is different and thus

also the resulting influence on the uncertainty. This reflects the initial quality and

quantity of the available data and the assumptions behind. In some cases the

formation thickness has a much higher influence on the uncertainty e.g. when very

little is known about the actual distribution of the formation or the thickness of the

prolific layers within a thick general formation. In other cases, very little to nothing is

known about the porosity and only general assumptions could be made for this very

important but also locally driven parameter. Additional geological studies performed

by the NGS on available conventional exploration data can aid in reducing the

uncertainty of these parameters. Uncertainty with respect to saturation and Langmuir

factors are likely very difficult to reduce. These parameters are very locally driven, can

vary significantly over small distances, and are very difficult to predict on a regional

scale.



The main result of this study is the collection and standardisation of geological data of

potential shale gas/oil formations from the participating European countries and the

identification of gaps in this dataset. During this study it became evident that a lot of

data is still missing from the collection (for various reasons). However this study sets

the base for future extensions and improvements of the database and the unified

integrated method makes is easier to implement new or modified data into updated

calculations.


Resource Estimations

A total of 49 out of the 82 shale formations described in EUOGA meet the information

requirements that allow for a quantitative volume assessment of hydrocarbon

resources. This selection covers the major EU shale plays that are currently considered

to be most promising and prospective from a technical point of view. Most formations

that did not meet the criteria either represent very small or highly uncertain

prospects, although future investigations may still reveal them as viable exploration

targets.

The most frequent reason to reject a formation was the lack of TOC data thus not

knowing if the formation is prolific or not (sixteen cases in total). Other common

reasons as lack of thickness, depth or maturity dismissed a further nineteen

formations.

The applied assessment workflow does not distinguish regional variations within the

shale formation extent, except for the defined assessment units. The outcomes of the

volume estimations are an overall average for shale formation represented by the unit

outline. Due to natural variations of shale properties and spatial geometry, there will

be parts in the unit outline containing either smaller or larger volumes than what could

be expected from the formation average volume. Such variations cannot be deduced

from the current results.

The quality of the resulting volume estimates depends on how well the stochastic

distribution of each input parameter can be determined (e.g. from well

measurements). Given the overall scarcity of information on shale parameters, these

distributions may be very uncertain. This is particularly a concern for parameters that

exhibit large natural variations across the shale formation/basin.

Selective drilling (i.e. exploration focused on parts of the formation where conditions

are expected to be most promising) may be a cause for having a biased stochastic

distribution for certain parameters. In some instances the parameters are determined

from specific parts of a basin that are not necessarily representative for the entire

formation (e.g. data from surface outcrops or basin margins). In cases where certain

parameters could not be provided by the NGS and the determination is based on the

average value from the entire EUOGA dataset or analogues outside Europe, then the

uncertainty regarding the validity of a chosen distribution is even bigger.

In summary, it is very important to consider that the quality of the assessment

outcomes strongly depend on the degree a parameter is likely to vary across the basin

and whether the available information is appropriate for capturing this variation in the

stochastic distributions used for the input parameters. Last but not least, it should be

noted that the workflow does not fully incorporate possible correlations between

parameters that may exist in certain parts of a shale formation (e.g. porosity and



saturation). This is only done for parameters that are indirectly derived from another

parameter (e.g. depth and formation factor).

Sensitivity analyses

Following the resource estimations a sensitivity analysis has been performed which

shows that:

Gas saturation and porosity are the major uncertainties for determining the free gas

and oil volumes. This was already expected, as these parameters tend to vary

significantly within a shale formation (i.e. both depending location-specific

conditions). As gas saturation is typically determined for tested hydrocarbon

occurrences only, the measured values for this parameter are rare (i.e. the shale

plays in Europe are mostly untested and without development). Of all formations

23% of these have a reported value for gas saturation. Porosity is a better-known

parameter that is determined from sedimentary core analyses and wire-line log

evaluations. Still only 35% percent of the formations have a reported value, most of

which are based on sparse well data that is insufficient to capture the full extent of

regional variations. Porosity and saturation have a strong weight (linear

relationship) in the volume equations, which causes a direct progradation of

uncertainties in the end results.



generally poorly known factor with little measurements available for a few

formations only (in total only 7% of the EUOGA formations have a reported value).

As this parameter has a very large value range (even within a single formation), it

may also have a strong influence on the final volume estimates. The uncertainties in

thickness are directly translated into the volume distribution of the final adsorbed

gas. For some formations the thickness is a very uncertain factor, especially when

only the gross formation thickness is known from incidental well data and the net

shale thickness must be estimated from a net-to-gross relationship.

Comparison with existing Resource Estimates

Comparison of the EUOGA results with the European shale gas and shale oil resource

assessment by EIA (2013) shows that estimated volumes are comparable in most

cases. Exceptions to this are the UK shale gas formations. The EUOGA study identifies

substantially higher GIIP estimates than the EIA (2013) study. For shale oil formations

in France, The Netherlands and Poland the EIA (2013) calculates significantly higher

values OIIP than the EUOGA study.

National resource estimations carried out by individual countries are mostly

comparable with the outcomes of the EUOGA study, with the exception of Romania for

which the national study estimates three times higher GIIP volumes and Lithuania for

which also a significantly higher resource estimate is determined by the national

study.

5.2. Identified Knowledge gaps and recommendation related to task 7

Identification of prospective shale formations

In several countries the specific prospective shale intervals are still not identified or

mapped. In some cases there is no information at all, except for a general indication

that hydrocarbon-bearing shales may be present in the basin. In other cases the

shales are known to exist but they are not recognized as a separate stratigraphic unit.

Consequently the assessment must be carried out on the entire parent formation in





Distribution of selected shales






lack of seismic (3D or dense 2D) reduces the precision by which the extent and







volume).

Improvements for calculation parameters







The coverage of the most important parameters needed for the volume determinations

is described below:

TOC: This parameter must be determined from core data, which is sparse for source

shale intervals. In some cases a reasonably reliable estimate can be provided for a

shale formation using a combination of a few measurements and regional knowledge

on the basin evolution. Currently there are quite some formations which have TOC

values (78% of all formations), but sometimes these are derived from logs, from

analogues, or just a few samples are taken for a formations with a size of thousands

of square kilometres. It is advised, also on a smaller (field-scale) that cores samples

are taken to get a better grip on the TOC distributions within one formation.

Maturity: This aspect is often well known in regions with existing hydrocarbon

development as the maturity of a hydrocarbon system can be determined from the

fluid analysis of the tested resources. In combination with a good understanding of the

basin evolution (burial, temperature), the knowledge on maturity can be extrapolated

over larger regions of the basin. Yet again, there are also many areas with little or no

information on maturity.

Porosity: This parameter is commonly determined in wells (either from core or wire-

line logging tools). In EUOGA only one third of the formations have a porosity

determination. Although the porosity is generally very low in shales, the relative

spatial variations can have a significant impact on the volume determinations. Such

variations can only be captured with a lot of well data. If it is known that the shale

formation has been deposited in a very homogeneous sedimentary environment with

equally uniform post-sedimentary and diagenetic development, then the porosity

values of that formation can sometimes be constrained with less well data.

Expansion factor: Currently the expansion factor is calculated using an ideal gas

equation with average reservoir pressure and temperature as input (either determined

from well data or derived from generic pressure/temperature relations with depth). A

better understanding of the spatial variation of these two parameters, as well as the



composition and density of the gas would decrease the uncertainty of this parameter

considerably. The expansion factor is mostly of influence in the case of gas. If

anomalies (i.e. high-pressure cells, local high temperature gradients) are known to be

absent, then it is easier to determine a regional value for a shale formation.

Langmuir pressure and volume: These parameters depend on a wide variety of factors

such as maturity and type of organic matter. Only a few formations have reported

values for the Langmuir parameters, leaving this as a major unknown with a very

large impact on the calculation of adsorbed GIIP volumes.

Saturation: This parameter can only be determined reliably from well measurements

in the direct vicinity. Due to its dependency on a multitude of local conditions, it is

very difficult to extrapolate saturation over larger regions. If known, a typical value

ranges can be applied, but still with high levels of uncertainty. These uncertainties

have a large impact on the final volume estimates. On-going hydrocarbon

development of a shale formation can possibly constrain uncertainty ranges and

provide some keys to predict the variation of saturation.

Interdependencies

Several parameters used in the stochastic volumetric assessment of the GIIP and OIIP

may be correlated to each other (e.g. porosity and saturation). Although the inclusion

of these correlations will normally result in reduction of the stochastic output ranges, it

has been decided not to consider them in the volume calculations. As the correlations

are often specific for a certain formation and basin area, there is not sufficient data in

EUOGA to provide a reliable definition. Future studies focussing on specific areas

within a shale play may however benefit from using them in the equations.

Reduction of uncertainties on regional scale

Some formations are still underexplored in vital regional parameters such as depth,

thickness, TOC, porosity, maturity, reservoir temperature and pressure. This task can

be executed by the individual NGS’ based on already available data or using standard

oil and gas exploration data from previously drilled wells or available seismic surveys.

In some countries this would mean releasing or re-evaluating vintage data to modern

standards.

Already available datasets can be used for a better stratigraphic definition of a shale

formation which will make the mapping of this formation more specific, also in terms

of net to gross. Better regional velocity models can be built to obtain depth converted

seismic data for depth mapping using the existing seismic surveys. National

authorities can aid in this process by simplifying the release of data from specific areas

or type. On a European scale improvement can be gained by correlating cross country

shale occurrences and collaborations between the involved countries.

Different countries will have a different focus on where to point their attention

towards, based on current level of data or social setting concerning shale gas and oil.

Much of the preferred new data will be dependent on activity by oil and gas

companies, for instance shooting of new seismic data and drilling of new wells to

obtain core measurements. Countries which already have well defined and understood

formation will want to look into defining their ‘sweet spots’, as mentioned above. This

will be the case for UK, Poland and the Netherlands which will also look into testing of

the producibility.

Local variations of the parameters

The parameters with the highest uncertainty, the Langmuir volume and the saturation,

are both known to vary significantly on a small scale. As these measurements are not

often taken the first countries and areas which are candidates should be areas with



ongoing or expected shale exploration. For other parameters such as TOC, maturity

and porosity NGS’ could look into measuring surface outcrops of the formations of

interest. If these do not occur then it is likely that research has to wait for oil and gas

companies to request and drill for new wells.

It is recommend that countries which do not release vintage data after a certain

number of years look into this issue to see if wells with expected prospective shale

layers can be released to aid in shale hydrocarbon exploration. The same goes for

seismic data in areas where shale formations are known to occur but are not yet

interpreted, in detail or at all.

Fraccability/Minerology

This study does not consider the influence of shale minerology on the recovery of

hydrocarbons contained in the shale interval. The mineralogy may have an impact on

the porosity, but this relationship could not be determined from the available data.

Furthermore the mineralogy has little impact on the total volumes in place. Shale

minerology is very important to determine the so-called fraccability and influences the

recoverability of gas and oil. As shown in Report T6, the shale mineralogy values are

provided for ca. 36% of reported shales. These data could be used in future

assessments.

Potential technical recovery base on notional development description

A process of upscaling the current resource estimations to technical recoverable

resources is extremely dependent on local surface and geological conditions. Therefore

a general parameter of upscaling is not feasible. If upcoming studies choose to

estimate the technical recoverable resources, we advise to do this on a more local

scale and in areas which current ongoing shale exploration activities in order to get

realistic numbers. It is expected that this will mainly be performed by industry

stakeholders. The NGS’ and governments could profitably look into spatial planning of

ideal drill pad sites with respect to geological conditions and the availability of surface

area.



6. Summary of EUOGA results and recommendations

6.1 Main results from EUOGA

Within the European wide EUOGA project 82 hydrocarbon bearing shale formations

within 21 countries were assessed for their resource potential. A stochastic volumetric

assessment could be carried out for 49 formations of which 15 are concluded to hold

both shale gas and shale oil resources, 26 only gas and 8 only oil. The participating

NGS’ in the EUOGA project provided public data and information available from their

respective countries, using a common description template developed by the EUOGA

project team members. The description also includes a full bibliographic reference

database with more than 240 references comprising the current state of the art of

scientific research of European shale gas and oil.

The volume estimations are performed per assessment unit. These units delineate

parts of the shale formations with more or less comparable characteristics. The overall

assessment workflow consists of:

Characterization of each formation by 20 geological assessment parameters. A gross

average value on the basis of the entire EUOGA database was used in case no

concrete determination was available.

Determination of the probability and uncertainty regarding the presence of gas and

oil in the shale formation (based on Task 4)

Subdivisions of each formation into assessment units using GIS data and cut-off

values

A ranking of the formation based on TOC, depth, thickness and maturity

Applying the accepted parameters as input for a GIIP/OIIP by use of stochastic

volumetric Monte Carlo calculations of the free gas, adsorbed gas and or the oil in

place

The final results are shown in table 1. The total resource estimation for all assessed

shale formations in all countries combined amounts to 89.23 tcm of gas and 31.4

billion barrels of oil in place.

The participating NGS’ identified the relevant basins and shale formations within their

countries, and provided geological descriptions and information based on guideline

and selection criteria prepared by the project teams in GEUS and TNO. For the

selected shale formations the NGS’ delivered a critical parameter sheet with measured

or estimated parameters based on public available sources. The selected basins were

described in a report outlining the structural-geological evolution and exploration

history as well as the most important shale-play elements within the potential

formation.

General hydrocarbon play elements were assessed in order to provide an indication of

the likelihood that a shale formation is present and contains technically recoverable

hydrocarbon resources (hereafter: chance of success). This evaluation involved a

semi-quantitative scoring on coverage of critical data for assessing 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 assessment results including data provided by participating NGS are stored in an

ESRI file geodatabase. This includes public information about each country’s



exploration wells, geological structural elements and outlines of basins with related

attributes about TOC, maturity, thickness and depth.

6.2 Main identified knowledge gaps from EUOGA

On shale scale

The return score of the critical parameters (Table 4) have shown that a good

knowledge level exist on traditional geological parameters such as TOC, maturity and

gross thickness. These parameters have been gathered for correlation and source rock

evaluation purposes for decades. However, for unconventional resource this is not

sufficient for detailed characterisation and a considerable knowledge gap exist in term

of bridging a traditional knowledge-base to a new and in most cases more advanced

state of knowledge.

In terms of assessment of the hydrocarbon resources then the sensitivity analyses

showed that the gas saturation and porosity are the major uncertainties for

determining the free gas and oil volumes. These parameters tend to vary significantly

within a shale formation. As gas saturation is typically determined for tested

hydrocarbon occurrences only, the measured values for this parameter are rare (i.e.

the shale plays in Europe are mostly untested and without development).

Porosity is a better-known parameter that is determined from sedimentary core

analyses and wire-line log evaluations. Still only 35% percent of the formations have a

reported value, most of which are based on sparse well data that is insufficient to

capture the full extent of regional variations. Porosity and saturation have a strong

weight (linear relationship) in the volume equations, which causes a direct

progradation of uncertainties in the end results.



generally poorly known factor with little measurements available for a few formations

only. As this parameter has a very large value range (even within a single formation),

it may also have a strong influence on the final volume estimates. The uncertainties in

thickness are directly translated into the volume distribution of the final adsorbed gas.

For some formations the thickness is a very uncertain factor, especially when only the

gross formation thickness is known from incidental well data and the net shale

thickness must be estimated from a net-to-gross relationship.







On basin scale

For several basins the geological history is still insufficiently understood and better

constraints on the sedimentary evolution and history of burial, uplift and temperature

is will help in predicting the hydrocarbon generation.








lack of seismic (3D or dense 2D) reduces the precision by which the extent and







volume).

In some cases there is no information at all, except for a general indication that

hydrocarbon-bearing shales may be present in the basin. In other cases the shales are

known to exist but they are not recognized as a separate stratigraphic unit

consequently the assessment must be carried out on the entire parent formation in



Database

The knowledge gaps related to basin scale is also reflected in the database and

mapping. However, in addition to missing data, data in incompatible formats and lack

of data provider and/or confidentially of data also exist. Additional data loss occurred

when the received data did not comply with given standards.

For countries where the NGS did not participate data was sought to be included from

open sources. This was the case for Germany were public available data from the BGR

(BGR 2016) was used. For non-participating countries like Ireland and Switzerland no

open source databases could be recognised and no data was included.


Non-participating NGS was an issue that provided the highest level of knowledge loss

that partly could be replaced by the existence of open source databases wherefrom

relevant data could be extracted.

6.3 Main identified recommendations from EUOGA


recommended to systematise the needed work by constructing research consortia

among the European NGS’ and establishing centres of excellence within their specific

areas of competences. Such research constructions may ultimate refine, enhance or

complete the resource assessments carried out.



research. The clay minerology is very important to determine the so-called fraccability

and influences the recoverability of gas and oil.

Parameters directly related to reservoir evaluation such as storage and transport i.e.

porosity, Langmuir parameters and permeability are also highly recommended to be

studied by directing the research towards these aspects.

Many shale formations are lacking a proper and distinct stratigraphic definition (i.e.

Member or Formation level). It is recommended that regional stratigraphic studies and

well correlations are to be carried out. The stratigraphic definitions will allow for a



better and more specific mapping of depth, thickness and extent of the shale layers,

thereby reducing uncertainties in volume determinations. Stratigraphic definitions will

furthermore help in properly correlating resources across borders and analysing

relevant shale properties. New well data may be needed when vintage data is lacking

or inconclusive for defining the stratigraphic intervals.

New exploration or research based stratigraphic drillings are crucial and highly

desirable. It is recommended that research based drilling programs may be set-up to

obtain these crucial parameters.

The characterization of structural complexity is still not standardized. Integrated

cross-border studies will improve the understanding of the potential impact of

structural elements on shale hydrocarbon prospectivity and recoverability.







Database

It is recommended in future shale gas and oil assessments and data gathering

projects that a broader concept of plays is included. This to ensure that the continuum

from shale oil and gas plays to tight oil/gas plays and to coal bed methane plays are

captured. A possibility to harvest data from these plays from the NGS to have a more

complete inventory is highly recommended.

The GIS guidelines distributed to the participating NGS’ concerned the optimal

exchange formats for the various GIS data and were intended to professionals

experienced persons in data management and general GIS compilations. But in many

cases no experienced GIS person was involved in the GIS work and it is therefore

recommended to make a more comprehensive guideline, describing the work process

for non-professionals.


The reporting of the EUOGA project was five mid-term task reports and eight final task

reports, one for each tasks, and in addition four progress reports and various

geodatabases. The documentation level was thus significant especially since the data

delivered from NGS’ did not come in as scheduled. As a consequence, updating of

reports, tables and maps was a continuous process. It is recommended that in future

projects that aim at delivering geodatabases and web-GIS applications that reporting

with paper reports is avoided. Instead, continuous updating via web-GIS is much more

productive and flexible.

The organisational structure used in this project is highly recommended. The

collaboration and commitment of all NGS’ under the auspices of EuroGeoSurveys

(EGS) was un-paralleled. The project documents that European National Geological

Surveys can work together to provide to a reliable assessment of European

unconventional gas and oil resources enabling a basis for making informed social,

political and industrial decisions.



7. References

Advanced Resources International (ARI), 2013. World Shale Gas and Oil Resources

Assessment, prepared for the U.S. Energy Information Administration (EIA), the

statistical and analytical agency within the U.S. Department of Energy, May, 2013.

BGR 2016. Schieferöl und Schifergas in Deutschland. Die Bundesanstalt für

Geowissenschaften und Rohstoffe (BGR), Hannover. 237p. (In German).

http://www.bgr.bund.de/DE/Themen/Energie/Downloads/Abschlussbericht_13MB_Schi

eferoelgaspotenzial_Deutschland_2016.pdf?__blob=publicationFile&v=5

Charpentier, R.R., Cook, T.A., 2011. USGS Methodology for Assessing Continuous

Petroleum Resources: U.S. Geological Survey Open-File Report 2011–1167.

Jarvie, D.M., 2012, Shale resource systems for oil and gas: Part 1—Shale-gas

resource systems. AAPG Memoir 97, 69–87.

Krüger, M., van Berk, W., Arning, E.T., Jiménez, N., Schovsbo, N.H., Straaten, N.,

Schulz, H.-M., 2014. The biogenic methane potential of European gas shale

analogues: Results from incubation experiments and thermodynamic modelling.

International Journal of Coal Geology 136, 59–74.

Schovsbo, N.H., Nielsen, A.T., Gautier, D.L., 2014. The Lower Palaeo-zoic shale gas

play in Denmark. Geological Survey of Denmark and Greenland Bulletin 31, 19–22.

Schulz, H.-M., Biermann, S., van Berk, W., Krüger, M., Straaten, N., Bechtel, A.,

Wirth, R., Lüders, V., Schovsbo, N.H., Crabtree, S., 2015. From shale oil to biogenic

shale gas: retracing organic-inorganic inter-actions in the Alum Shale (Middle

Cambrian-Lower Ordovician) in southern Sweden. AAPG Bulletin 99, 927–956.

http://www.bgr.bund.de/DE/Themen/Energie/Downloads/Abschlussbericht_13MB_Schieferoelgaspotenzial_Deutschland_2016.pdf?__blob=publicationFile&v=5

http://www.bgr.bund.de/DE/Themen/Energie/Downloads/Abschlussbericht_13MB_Schieferoelgaspotenzial_Deutschland_2016.pdf?__blob=publicationFile&v=5



8. List of EUOGA deliverables

Final deliverables made as paper reports are:

Task 1

Anthonsen, K.L. and the EUOGA team, 2015. Final work plan. Report T1 of the EUOGA

study (EU Unconventional Oil and Gas Assessment) commissioned by JRC-IET.

Task 2

Nelskamp, S., Zijp, M.H.A.A., 2016. Final Technical Report on evaluation of existing

assessment methodologies and the proposed common methodology for pan-EU

assessment. Report T2b of the EUOGA study (EU Unconventional Oil and Gas


Task 3

Anthonsen, K.L., Schovsbo, S., Britze, P., 2016. Overview of the current status and

development of shale gas and shale oil in Europe. Report T3b of the EUOGA study (EU

Unconventional Oil and Gas Assessment) commissioned by JRC-IET.

Task 4

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.

Task 5

Tougaard, L., Pedersen, C., 2017. Set of maps for each basin. Report T5a of the

EUOGA study (EU Unconventional Oil and Gas Assessment) commissioned by JRC-IET.

Tougaard, L., Pedersen, C., 2017. Geodatabase. Report T5b of the EUOGA study (EU

Unconventional Oil and Gas Assessment) commissioned by JRC-IET.

Task 6

Schovsbo, N.H., Anthonsen, K.L., Pedersen, C.B., Tougaard, L., 2017. Overview of

shale layers characteristics in Europe relevant for assessment of unconventional

resources. Delivery T6b of the EUOGA study (EU Unconventional Oil and Gas


Task 7

Zijp, M.H.A.A., S. Nelskamp, Doornenbal, J.C., 2017. Resource estimation of shale gas

and shale oil in Europe. Report T7b of the EUOGA study (EU Unconventional Oil and

Gas Assessment) commissioned by JRC-IET.

Task 8

Schovsbo, N.H., Doornenbal, H., Nelskamp, S., Pedersen, C.B., Tougaard, L., Zijp, M.,

Anthonsen, K.L., 2017. Review of results and recommendations. Delivery T8 of the

EUOGA study (EU Unconventional Oil and Gas Assessment) commissioned by JRC-IET.



Appendix A: Executive summaries for final report 2-7



Deliverable T2b: Final Technical Report on evaluation of existing assessment methodologies and the proposed common methodology for pan-EU assessment

Over the last decade, various national assessments of shale gas and shale oil

resources for EU-countries have been published. Due to different and/or

undocumented methodologies, fundamental assumptions and quality and quantity of

underlying geological information, the results of these national assessments are not

always easily comparable and interpretable. This report focusses on the development

and definition of a uniform methodology for estimating (in-place) shale gas and shale

oil resources at the pan-European level. The methodology is compared with existing

published assessments in order to analyse differences and similarities with the various

other methods used, to better understand the variations in published estimations

across Europe and to improve the overall comparability of the pan-European shale

gas/oil assessments with existing studies. The methodology is established to

determine estimates of GIIP (Gas Initially In Place) and OIIP (Oil Initially In Place)

including associated uncertainty bandwidths originating from the various geological

input parameters available.

The developed methodology as well as most previously performed assessment studies

use some sort of combination of the following assessment techniques.

The Prescreening method directly compares shale gas/oil assessment units on the

basis of a preselected set of parameters. Its result is a qualitative comparison of these

parameters per assessment unit and it does not give a quantitative assessment of the

GIIP/OIIP or TRR.

The Analogy method is an indirect approach used to estimate the total recoverable

resources (TRR) or resources initially in place (GIIP/OIIP) on the basis of expert

judgment and validated similarities with developed analogue shale plays. This method

is particularly useful in undrilled or sparsely drilled areas where nearby and tested

analogue shale plays with sufficient production data are present.

Methods previously used in European shale gas/oil assessments

The Volumetric method is used to calculate the total gas/oil initially in place

(GIIP/OIIP) of a subsurface area based on a set of measureable rock parameter. This

method is based on the assumption that the gas is stored as free gas in the pore

space and adsorbed on organic matter or clays while the oil is mainly located in the

pore space. To account for uncertainties related to the input parameters, this method

is mainly used in a probabilistic way, while a deterministic approach can be valid in a

very well-studied area.

The Decline Curve Analysis calculates the TRR assuming the use of current

technology. This technique is applicable where actual production occurs. It is mainly

used to assess the potential of a new well in an already existing production area.

Reservoir simulation is mainly used in conventional oil/gas assessment to calculate the

TRR for individual wells in one reservoir. This method is only applicable in areas with

sufficient geological data to build a reliable reservoir model and enough production

data to calibrate the history matching.

The Resource Triangle method is based on the assumption that the hydrocarbon

resource types follow a triangular distribution based on their abundance, their

reservoir quality and the technology required to produce these resources successfully.

The selected methodology for this study is established to determine estimates of GIIP

(Gas Initially In Place) and OIIP (Oil Initially In Place) including associated uncertainty

bandwidths of different scales originating from the various geological input parameters

available. It can deal with a wide range of available data (amount and quality) and has



the possibility to be upscaled to total recoverable resources (TRR). A combination of

the probabilistic approach of the volumetric method, together with the analogue and

prescreening methods meets all these prerequisites.

In the first step the general uncertainties of the shale gas/oil play are addressed.

This assessment of play success uses available geological parameter and descriptions.

It is based on the reports on the shale gas/oil formations supplied by the respective

national geological surveys which were unified and are presented in the report of WP

A general scheme was developed to describe the plays on a basin by basin level.

In the second step the individual shale formations are subdivided into individual

assessment units based on the heterogeneity of a set of parameters. Important

parameters for this step are depth, thickness, maturity and location (on-, offshore).

Possible additional parameters can be mineralogy and source-rock quality.

The third step is a ranking/prescreening of the shales per country and per basin. This

ranking/prescreening is based on a limited number of parameter and should be done

for each shale assessment unit separately. In this step the general availability of data

for the shale formation is included. This ranking/prescreening is supposed to identify

the most interesting shale formations per country/basin with enough data available for

a full assessment and limit the total number of formations a full assessment is

performed on.

In the fourth step the calculation for the assessed units identified for calculation is

performed using a probabilistic, volumetric approach. For the stochastic calculation for

each parameter the mean, minimum and maximum values are needed along with a

probability density function that describes the distribution of the values in the

assessed unit. These values are then combined by random sampling (Monte Carlo

simulation) and give a probability distribution for the GIIP/OIIP along with an

indication which values have the biggest influence on the uncertainty of the calculated

value.

The final assessment result will give a general assessment of the chance of success of

the play and a ranking for each of the identified shale gas/oil layers together with

suggestions on how to reduce the general uncertainty of the formation. The top

ranking shales with enough data available are included in the detailed calculation of

GIIP/OIIP based on the presented probabilistic, volumetric method. For these shale

layers P50, P10, and P90 values along with the distribution of values and uncertainty

related to each is provided. Furthermore a summary of the main uncertainties that

have the biggest influence on the total range of GIIP/OIIP values of each shale play

are described, together with possibilities to reduce this uncertainty.

In order to discuss the TRR (Technical Recoverable Resources) within a typical shale

gas development area, this report also includes an example of a notional national

shale gas development plan based on available literature.



Deliverable T3b: Overview of the current status and development of shale gas and shale oil in Europe

This report provides an introductory country-per-country overview of the current

status and development of shale gas and shale oil in Europe, based on returned

questionnaires distributed to the National Geological Surveys (NGS) in June 2015 and

updates received in July 2016. The basin-per-basin and play-per-play overview are

based on replies in the questionnaires, supplemented with information given in the

geological basin reports delivered as part of the EUOGA project in 2016.

Various national assessments of shale gas and shale oil resources for the European

countries have been published over the last decade. Differences in methodology,

fundamental assumptions, quality and quantity of the underlying geological

information of these national assessments, implies that results cannot be directly

compared and thus no full overview of the hydrocarbon resource potential from shales

in Europe is available. This report focusses on the level of shale hydrocarbon

exploration activity, state and nature of previous resource assessments and on the

political and public situation related to the exploration and development activities of

shale hydrocarbons within the European Union.

The questionnaires were prepared by GEUS and TNO as part of the EUOGA project and

sent to all member states NGS’ including Ukraine, Switzerland and Norway. Of the 30

questionnaires distributed to the National Geological Surveys, 25 questionnaires have

been completed and returned during the second half of 2015 and in the first half of

2016 (Fig. 1). A summary of the replies is presented in the following sections of this

report. The status and categorisation given for the situation in Germany reflects the

authors judgements based on public documents, especially the report of (BGR 2016)

and personal communication. Germany (BGR) is not a member of EUOGA has not

responded to the questionnaire.

Shale gas and Shale oil resources and assessment status

The NGS’ were asked to elaborate whether their respective country had or expected to

have a shale gas and shale oil resource. If a resource were known, to what extent had

the resource been assessed and by whom.

Four countries replied that they have no hydrocarbon resources in shales onshore or

that the shale gas and oil are not considered thermogenic and that a variable biogenic

shale play was not present. These countries are Estonia, Finland, Norway and Malta.

Consequently no resource assessments had been performed in these countries (Fig.2).

Seven NGS’ responded that their country has a potential shale hydrocarbon resource,

but that it has not been assessed. These countries include Austria, Belgium, Czech

Republic, France, Ireland, Italy and Portugal. In Austria assessment studies are in

progress, but the work is not finalised and the results might not be public.

Four NGS’ responded that their countries have been assessed but without the

involvement of the NGS. These countries are Bulgaria, Hungary, Slovenia and Sweden.

Assessment studies by the NGS are in progress in Hungary and Spain.

Eleven NGS’ responded that their countries have shale hydrocarbon resources and that

it has been assessed with the involvement of the NGS. These countries include

Croatia, Denmark, Germany, Latvia, Lithuania, the Netherlands, Poland, Romania,

Spain (initiated), Ukraine and the United Kingdom. For some countries the



assessments are performed by private companies in specific parts of the country

whereas the NGS has assessed other parts, e.g. in Croatia.

Fig. 1. The 26 countries covered in this report.

Activities related to shale gas and shale oil exploration

The NGS’ were asked to provide a status for the exploration and development of shale

hydrocarbon resources together with a description of the political status. Based on the

response from 25 countries the question about activity level is summarised as follows

(Fig. 3).

In 15 countries there is no activity either because they have no resources, have a

possible resource but no permit have been issued for exploration, or that there is a

political moratorium or ban on shale gas and oil exploration and/or hydro fracturing.

Countries with no resources are Finland, Norway (possibly offshore resources exist,

but are not currently relevant for exploitation) and Malta. In Estonia and Latvia the



unconventional hydrocarbon resources are too shallow and immature to be classified

as true thermogenic shale hydrocarbons and no viable biogenic play is documented.

Fig. 2. Shale gas and shale oil resources and assessment status, by member state.

For country details consult the specific country section.

Countries with a possible shale hydrocarbon resource, but with no present exploration

activities occurring are Austria, Belgium, Bulgaria, Croatia, Czech Republic, France,

Ireland, Italy, Portugal and Sweden.

Five NGS’ reported that that their countries have low activities. This category cover

countries where permits have been issued and/or exploration wells have been drilled

in the past, but only very little or no future activities are expected. These countries

are Denmark, Germany, the Netherlands, Romania and Slovenia. In Slovenia

unconventional hydrocarbon resources are found in sandstone deposits, classified as

“tight gas” and this resource is not considered as a shale hydrocarbon resource.



Three NGS’ have reported that their countries have medium level activities and include

countries where permits have been granted and wells drilled and where future

activities are expected. These countries include Hungary, Lithuania and Spain.

Three NGS’ have reported that their countries have high activity and this category

covers countries where permits have been granted and wells drilled and future

activities will occur, perhaps even on higher levels than what has been seen until now.

These countries include Poland, Ukraine and England in the United Kingdom. For the

United Kingdom the “high level activity” does not cover Scotland and Wales, where a

moratorium is in place, and North Ireland, where there are no active licenses for

unconventional hydrocarbon exploration.

Fig. 3. Activities related to shale gas and oil exploration. For country details consult

the specific country section.

Member state position towards shale gas and shale oil exploration

There is often a close relation between the expected future activity level and the

member state position towards shale gas and oil exploration and hydro fracturing



within the countries. A low support for shale hydrocarbon exploration are in most

cases described as concerns related to the use of hydro fracturing and the

environmental impact. The following part of this section summarises the NGS’ analysis

on the current status in the member states (Fig. 4).

Exploration for unconventional hydrocarbon resources is permitted in seven countries,

implying that the use of hydro fracturing is permitted. These countries are Lithuania,

Poland, Romania, Slovenia, Spain, Ukraine and England (United Kingdom except

Northern Ireland, Scotland and Wales). In Spain and Romania there is no distinction

between conventional and unconventional hydrocarbon resource exploration and

legislation in these countries permits hydrocarbon exploration.

Five countries have an unclarified position on shale hydrocarbon exploration activities

implying that the political position is divergent towards utilisation of shale gas and oil,

or shale gas and oil exploration and development has not yet been an issue. These

countries are Belgium, Czech Republic, Hungary and Portugal.

A group of five countries have no support or a moratorium on unconventional

hydrocarbon exploration activities and/or hydro fracturing. These countries include

Austria, Bulgaria, Denmark, Ireland and the Netherlands.

Five NGS’ reported that hydro fracturing in shale gas and oil deposits is prohibited;

these countries are Croatia, Estonia, France, Germany and Italy. And finally, in five

countries there are no known onshore shale hydrocarbon resources. Countries

included in this category are Finland, Latvia, Malta and Norway. Sweden is included in

this category even though there is a minor biogenic gas resource in central Sweden.



Figure 4. The member state position on shale gas and oil exploration and hydro

fracturing per July 2016. For country details consult the specific country section.

Basin and play overview

This section provides a summary of the basins that host shale gas and oil and of the

shale oil and gas plays itself with emphasis on exploration and production results and

available published assessments. The lists of basins are not complete as data is

progressively being added as they are received from the participating NGS’s. A

complete list will be made as part of the assessment task (T7) within the EUOGA

project and in dialog with the NGS’s. The basins included here are presented in Figure

5. Some of the basins are grouped into larger basins based on the grouping used in

report T4 Geological resource analysis of shale gas and shale oil in Europe. This report

also presents a geological description of the European basins and shales.

Norwegian-Danish-South Sweden basin

The main target for exploration is this basin is the organic rich lower Palaeozoic Alum

Shale Formation (M. Cambrian - L. Ordovician). The up to 180 meter thick formation

is relative tectonically un-disturbed and has for the Danish territory been assessed by



the United States Geological Survey (USGS) (Gautier et al. 2013). Assuming

unrestricted application of best practice current technology, recoverable gas resources

of 0 to 130 × 109 Nm3 gas were estimated onshore (mean = 67 × 109 Nm3 gas) and

0 to 228 × 109 Nm3 gas were estimated offshore (mean = 119 × 109 Nm3 gas), i.e. a

total estimated mean of 186 × 109 Nm3 gas (Nm3: normal cubic metre, unit used for

natural gas at 0°C and 101.325 kPa). The wide range of estimates reflects the sparse

data and the geological uncertainty inherent in the still untested play. The first shale

gas exploration borehole in Denmark, the Vendsyssel-1 was drilled in northern Jylland

in 2015 by the company Total E&P.

A minor resource of biogenic shale gas is present in the Alum Shale in South Central

Sweden on the Fennoscandian shield. The expected amount of gas present has not

merited it for further analysis within the EUOGA context.

Baltic basin

The Baltic basin comprises areas around the Baltic Sea in Denmark, Sweden, Poland,

Latvia, Lithuania, but also include the Podlasis–Lublin basin in Poland and Lviv-Volyn

basin in Ukraine (Fig. 5). The Lower Paleozoic basin at the western slope of the East

European Craton (EEC) has been recognized as one of the most interesting areas for

shale gas (and oil) exploration in Europe. The marine-deposited Upper Ordovician

and/or Lower Silurian graptolitic shale is here the major potential reservoir formation

(Poprawa 2010). Moreover, the Upper Cambrian to Ordovician Alum shale is an

additional target locally in the northern part of the Baltic basin (mainly offshore, a

small part onshore). Organic matter of the Lower Paleozoic shales is characterized by

presence of II type of kerogen (Poprawa 2010).

Unconventional shale oil/gas resource exploration in Latvia has never been carried

out. Data that allows for a evaluation of the potential shale oil/gas formations are

gained from core description and well logging. Available data can be characterized as

sparse, incomplete and contradictory. Four potential shale oil/gas formations are

determined in Latvia, but only the Zebrus Formation (Lower Ordovician) correspond to

some of the EUOGA screening criteria as the formation lays is deeper than 1.5 km and

more than 20 m thick (thickness – gross, m). The formation is, however, immature

and no thermogenic resource is expected.

The major shale oil and gas potential in Lithuania is related to the two major

complexes of the organic-rich source rocks distributed in Western Lithuania, the Upper

Ordovician complex and Lower Silurian complex. The first assessment of

unconventional hydrocarbons in Lithuania has been published by Zdanaviciute and

Lazauskiene (2009). EIA has assessed the Lithuania shale gas/oil resources in 2011,

2013 and 2015. The Lithuanian Geological Survey prepared from 2011 to 2014 a shale

gas report based on actual geological, geophysical and geochemical data. Shale oil

and shale gas resources in-place (GIP and OIP) for Late Ordovician – Early Silurian

section of 110 m thick. The calculated volumes of generated unconventional

hydrocarbons were OIP 3.6 – 18.3 bill. m3 (area: 1134-5691 km2) and GIP 1,03 –

5,13 trill. m3 (area: 1134-5691 km2) (Lazauskiene et al. 2014). Furthermore, have

scientists from the Lithuanian Academy of Sciences in 2013-14, evaluated recoverable

and in-place shale oil and gas resources for Late Ordovician - Early Silurian section in

Šilutė-Tauragė block and western Lithuania (Grigelis ed. 2014)(Fig. 9).

Pilot shale oil/shale gas prospecting projects in western Lithuania started in 2011 and

was carried out by 2 oil companies in 2011-2013. During this period 2 new

prospecting shale oil/gas wells were drilled through the Lower Silurian and Upper

Ordovician strata.



The main target for shale gas and oil in Poland is the Lower Paleozoic Baltic-Podlasie-

Lublin basin (Lower Silurian-Upper Ordovician, locally Upper Cambrian) (PGI-NRI,

2012). The main basin has been studied in PGI-NRI (2012) report „Assessment of

shale gas and oil resources of the Lower Paleozoic Baltic-Podlasie-Lublin Basin in

Poland” and in a number of other published reports (ARI 2009; Wood Mackenzie 2009;

EIA 2011, 2013, 2015; Rystad Energy 2010; USGS - Gautier et al. 2012). These

reports either utilized actual data from archive wells (PGI-NRI, 2012; USGS - Gautier

et al. 2012) or just available publications (ARI 2009; Wood Mackenzie 2009; EIA

2011, 2013, 2015; Rystad Energy 2010). No resource assessment utilizing data from

new wells (property of the concession operators - oil & gas companies) has been

published yet. New PGI report on the shale gas and oil resources of the Lower

Paleozoic Baltic-Podlasie-Lublin basin in Poland, utilizing data from most of these new

wells, has been completed by PGI but not approved by Ministry of Environment yet. In

case of PGI-NRI (2012) report results laboratory analyses of core samples from 39

archive wells were utilized (mainly values of TOC and thermal maturity - R0).

As shown in Fig. 10 discrepancies between results obtained from both approaches and

particular studies are huge - the range of TRRs is two orders of magnitude. One of the

reasons for these discrepancies is the use of different volumetric method and as a

result the net thickness and volume of potentially gas (and/or oil) bearing shales were

overestimated. Another reason for discrepancies consists in the fact the researchers

followed different methodologies and used different assumptions (especially on net

thickness of prospective shales).

The moderately complex Lviv-Volyn Basin of western Ukraine is similar to the Lublin

Basin in southeast Poland. However, the Silurian black shale belt becomes structurally

simpler as it trends towards the southeast across southwestern Ukraine and northern

Romania until it reaches the Black Sea. The Silurian is the main petroleum source rock

and shale gas exploration targets in the Lviv-Volyn Basin. Compared with Poland, the

reservoir characteristics of the Silurian shale in western Ukraine are less certain.

Resource Assessment Risked, technically recoverable resources from Silurian black

shale in the Lviv-Volyn Basin is estimated to be 52 Tcf, out of a risked shale gas in-

place of 363 Tcf. The play has a moderately high resource concentration of about 113

Bcf/mi2, reflecting the significant thickness of the organic-rich shale that is present.

Ukraine’s State Commission on Mineral Resources has estimated that the Oleska shale

gas license area in the Lviv-Volyn Basin has about 0.8 to 1.5 trillion m3 (28 to 53 Tcf)

of shale gas resources. Whether this estimate reflects in-place or recoverable

resources was not specified.

In Ukraine Chevron has been in negotiations with the government for a PSA at the

Oleska field in western Ukraine. This block is along strike with Poland’s Lublin basin,

where Chevron already holds shale licenses. Duration and terms likely would be

similar to those granted to Shell for the permit at Yuzivska field in the eastern Dniepr-

Donets Basin (assigns oil and gas rights to all strata to a depth of 10 km, including

tight and basin-centred gas. The contract allows for 70% investor recovery and a

16.5% government revenue share).

Fore-Sudetic Monocline basin

The Fore-Sudetic Monocline (Lower Carboniferous) has been evaluated by EIA (2013,

2015) reports and its geological-reservoir properties have been studied and reported

in a PGI-NRI report on tight gas (Wójcicki et al. 2014) where area prospective for tight

and shale gas has been delineated. Only one new well for shale and tight gas



prospecting in Lower Carboniferous has been completed there (San Leon 2012) and

only few archive wells explored Lower Carboniferous.

In the Fore-Sudetic Monocline Basin EIA estimated TRRs of 595 Bcm. EIA (2013,

2015). However, the prospective area seems to be overestimated and assumptions on

reservoir parameters appeared to be based on a press release/corporate report from

just one new well. In 2014 PGI-NRI prepared a report on the tight gas potential in

Poland (Wójcicki et al. 2014). In this report the Fore-Sudetic Monocline were included

as a basin where unconventional gas occurs. The area where Lower Carboniferous

sandstones and shales of sufficient maturity (gas window only) appear was delineated.

Dniepr-Donets basin

The main shale targets in Eastern Europe are marine-deposited black shales within the

Carboniferous of the Dniepr-Donets Basin (TRR of 76 Tcf and 1.2 billion barrels, EIA

2013)(Fig. 12). Shale resource assessments are reported to be in progress in Ukraine,

but no official assessments have been published yet.

The State Geological and Subsurface Survey of Ukraine (Derzhgeonadra) has

announced shale gas resources in the country of total 7 trillion m3 (Tm3) or 247 Tcf.

However, the basis for this estimate has not been released and the figure includes

some tight gas resources. The newly created Geological Research and Production

Center in Poltava plans to coordinate shale gas studies in Ukraine, while monitoring

water quality in drilling areas.

On February 23, 2012, the Ukraine government announced a tender for shale

exploration and development in the Oleska and Yuzivska blocks of western and

eastern Ukraine, respectively. In January 2013, Ukraine awarded the first shale gas

PSA, signing with Shell. Shell’s 50-year PSA permit at Yuzivska in the eastern Dniepr-

Donets Basin assigns oil and gas rights to all strata to a depth of 10 km, including

tight and basin-centred gas. The contract allows for 70% investor recovery and a

16.5% government revenue share.

The Dniepr-Donets basin contains a thick sequence of Carboniferous black shale which

may be prospective for oil and gas development. Economically important

Carboniferous coal deposits and tight sands of the Moscovian overlie these shales, but

this coaly sequence does not appear to be a prospective shale target.

The mapped prospective area for the dry shale gas window in southeastern Dniepr-

Donets Basin is estimated to be 6,010 mi2. Lower Carboniferous shale (comprising the

Rudov Beds and portions of the overlying Upper Visean) has a highly favourable

resource concentration of approximately 195 Bcf/mi2. Risked, technically recoverable

shale gas resources are estimated to be 59 Tcf, out of a risked shale gas in-place of

235 Tcf. The wet gas prospective area of the Dniepr-Donets Basin extends over about

2,680 mi2. Risked, technically recoverable resources are estimated at 16 Tcf of shale

gas and 0.5 billion barrels of condensate from in-place shale gas and shale oil

resources of 63 Tcf and 10 billion barrels. The smaller oil window in the northwestern

Dniepr-Donets Basin covers a prospective area of about 1,460 mi2. Risked technically

recoverable resources are estimated to be about 0.7 billion barrels of shale oil and

condensate and 1 Tcf of associated shale gas, out of risked in-place shale oil resources

of 13 billion barrels. Ukraine’s State Commission on Mineral Resources has estimated

that the Yuzivska shale gas license in the eastern Dniepr-Donets Basin has 2-3 Tm3

(71-107 Tcf) of shale gas and tight gas resources. Whether this estimate reflects in-

place or recoverable resources was not specified.



Transilvanian basin

The Transylvanian Basin (Fig. 5) is the most important zone with gas accumulation in

Romania. Also, this sedimentary basin is the main gas producer from southeast

Europe (Popescu 1995). The gas pools are located in the Middle Miocene–Lower

Pliocene (Paraschiv 1979; Popescu 1995). This stratigraphically level is named “Gas-

bearing formation” that accumulated only the biogenic methane gases. In the

Transylvanian basin the 99% of the gas is methane and it has the biogenic origin, is

not reached a thermogenic stage. Until now up to 120 gas fields have been discovered

in the Transylvanian basin, 13 of them were discovered before 1950.

Moesian Platform

The northern part of the Moesian Platform is within the Romanian sector while the

southern part is within the Bulgarian sector. In the Romanian sector the Moesian

Platform covers a surface of more than 43 000 km2 and is bordered by the Carpathian

Orogeny, Balkan and North Dobrogea orogenic systems. It also covers to the east the

continental platform of the Black Sea (Fig. 14).

Moesian Platform is the one of the most important basins for hydrocarbons in

Romania. This major sedimentary basin has all geological conditions for hydrocarbons

generation, migration and accumulation. As concerning the stage of exploration, many

authors considers the Moesian Platform a mature area, but there are still some zones

with unsatisfactory petroleum knowledge e.g. Paraschiv (1979), Popescu (1995) and

Pene el al. (2006). This sedimentary basin is characterized to the existence of the

least three effective petroleum systems, two of them are thermogenic systems

represented by the Palaeozoic and the Mesozoic systems and one is biogenic system

(Neogene system) (Paraschiv 1979; Pene et al. 2006).

The conventional exploration debuted in the early 1950s. In 1956, the first borehole

was drilled which encountered the first hydrocarbon accumulation. Presently, this

number of discovery is increased and it is assumed that the number of oil and gas

fields is about 145. According to Pene (1996) the initial reserves in 1996 discoveries

were 235 x 106t and ultimate resources were at least 237 x 106t (Popescu 1995). Also,

after the same author, the Moesian Platform yields about 40% of the hydrocarbon

production of Romania.

Concerning the suitable areas for calculating the shale gas resources of the Silurian

deposits in the Moesian Platform, there are 3 system plays in Moesian Platform:

Călărași–South Dobrogea Play, Optași–Alexandria Play and Lom-Băilești Play (Fig. 16).

Veliciu and Popescu (2012) have estimated the values (Table 3) of the resources for

these 3 shale gas plays according to the assessment of methods issued by US

Geological Survey (2010).

In the sedimentary successions of the Moesian Platform in Bulgaria, four intervals

dominated by organic-rich dark shale have been identified, which would be of interest

for shale gas. These are: Silurian – Lower Devonian(?) shales; Lower Carboniferous

shales – Trigorska and Konarska Formations; Lower Jurassic shaly sediments –

Ozirovo Formation (Bucorovo & Dolnilucovit Mbs); Middle Jurassic shales – Etropole

Formation (Stefanets Mb). According to the completed study the shale gas potential of

Bulgaria part of the Moesian Platform is moderate to poor. From the estimated 4

targets for shale gas only the Lower Carboniferous shales (in the pointed western

zone) and both Jurassic shale intervals may present a moderate interest.

Dinarides-Lemeš basin

Previous studies of the area Lemeš deposits originated from early 1980’s when the

Croatian oil company INA conducted studies of the petroleum and potential source



rocks from the area of “Lemeš facies” (Jacob et al. 1983. and unpublished data). On

the basis of stratigraphy as well as petrographical and sedimentological features,

Lemeš deposits are divided into 9 units that can be mapped over the entire area. The

thickness of the Lemeš deposits ranges from 250–450 m. The Lemeš deposits Unit 4 is

the most interesting unit with respect to source rock potential and investigations of

source potential, organic geochemistry and palynofacies has been carried out by

Blažeković Smojić et al. 2009.

Hungarian Paleogene basin

During the Early Oligocene (Early Kiscellian) anoxic black shale, named the Tard Clay,

was formed in a thickness of 80-100 m in the southern belt of North Hungary. It is

widely believed that the main source rock of the Hungarian Palaeogene Basin is the

Tard Clay, with minor source potential locally in the overlying Kiscell Clay formations

(Kókai & Pogácsás 1991; Milota et al. 1995). A detailed oil-source rock correlation is

missing, therefore the level of certainty of the Tard-Kiscell petroleum system is only

hypothetical (Badics and Vető 2012). There are 443 wells with well-top information in

the area, of which 85 wells penetrated the Tard Clay (Kőrössy 2004), while the total

area is around 7800 km2. The main conventional fields are Demjén (70 million barrel

oil in-place) and Mezőkeresztes (6.5million barrel oil in-place), both discovered in the

1950s (Fig. 19).

Mura-Zala basin

The most prospective geological area for shale gas and oil in Slovenia is the Mura-Zala

Basin situated in the SW part of the Pannonian Basin System. Three prospective areas

with oil and gas potentially generating strata are differentiated in the Mura-Zala Basin

in Slovenia. Shale oil and gas in Slovenia is only occurring in marls, which are

normally classified as unconventional hydrocarbon sources. However, tight oil and gas

in sandstones are also treated in this study together with shale oil and gas as they

occur together in alternating beds and would be possible to be exploited only with

using stimulation techniques to enhance the recovery of hydrocarbons. Both lithology’s

have low porosities, marls only about a few %, and sandstones about 10 %. Pre-

Tertiary basement rocks were not investigated as source rocks in Slovenia. However,

it is not excluded that the basement rocks – especially carbonates – do have some

potential for oil and/or gas generation. Clarifying of this question remains for the

future exploration.

In western Hungary, the Upper Triassic Kössen Marl has excellent source-rock

potential. Fields producing Triassic oils in the Mura-Zala Basin include Bak,

Barabásszeg, Nagylengyel, Pusztaapáti, and Szilvágy (Fig. 22). The extent of the

Kössen Marl has been investigated in the wells drilled in the Zala Basin and in

Transdanubian Range outcrops. There are 534 wells drilled in the area, which have

well-top information. 230 wells were drilled into the Triassic, but only 32 wells

penetrated the Kössen Marl.

Vienna basin

The main hydrocarbon source rock in the Vienna Basin and Korneuburg Basin (also

referred to as the Thaya Basin) is the Mikulov Marl which is present in a strip

extending northeast of Vienna to the southeast of the Czech Republic (Fig. 20). It is

unknown whether the oil and gas companies operating in Austria have made any

assessment of Austrian shale hydrocarbon resources since no public material is

available.

Molasse basin

Conventional hydrocarbon exploration has been taking place in the Molasse basin

within decades, primarily in Austria and Germany. Over 1200 exploration wells have



been drilled with around 200 conventional oil and gas discoveries. The source rocks in

the Molasse basin are the Permo-Carboniferous Weiach-Formation, the Lower Jurassic

Posidonia shale, and the Paleogene Fish Shale (BGR, 2016). A thorough shale oil and

gas assessments for Germany is published in BGR, 2016. No public assessment for the

Austria part of the Molasse basin is available.

Lombardy basin

Middle Jurassic dark carbonates and mudstones, Early Jurassic age (Toarcian) black

shales and Cretaceous shales and marlstones are potential source rocks in the

Lombardy Basin. No published shale gas/oil assessment for the Lombardy basin exists

and no exploration for shale oil/gas has been performed.

Ribolla basin

The Ribolla basin (Fig. 26) assessment by Bencini et al. (2012) refers to “Fiume

Bruna” and “Casoni” exploration licences and all information included in this reported

is from this study. A Miocene age organic rich sequence consisting of one laterally

continuous 9-11 meter thick seam of coal and black shale, saturated with thermogenic

gas, able to produce excellent quality natural gas by desorption after stimulation. It

has a permeability of 1-2 mD and responds more like gas shale than a classic high

permeability coal. No published shale gas/oil assessment for the Ribolla basin exists

and no exploration for shale oil/gas has been performed.

Emma and Umbria-Marche basin

Bituminous limestone, evaporitic and black shales of the Upper Triassic and Lower

Jurassic (Emma Limestones and limestones inside the Burano formation) are

considered the source rocks for many conventional oil reservoirs in the Emma basin.

In general, the Umbria-Marche pelagic Mesozoic sequence (Jurassic-Cretaceous)

shows a low hydrocarbon potential except for some portion where black shale and rich

organic matter levels occur. No published shale gas/oil assessment for the Emma and

Umbria-Marche basin exists and no exploration for shale oil/gas has been performed.

Ragusa basin

The Ragusa basin lies onshore and offshore in the south-eastern part of Sicily (Fig.

27). The Noto Formation (Rhaetian) is known as the main source rock for the oil fields

in this basin (Pieri & Mattavelli 1986; Novelli et al. 1988; Brosse et al. 1988), but only

very limited thickness of the shale layers are found. No published shale gas/oil

assessment for the Ragusa basin exists and no exploration for shale oil/gas has been

performed.

Caltanissetta basin

The Tripoli formation of early Messinian (upper Miocene) age is composed of a

repetition of sedimentary triplets composed of homogeneous marls, laminated marls

(sapropelic) and diatomites. The petroleum potential (oil and combustible gas) for

fresh tripolitic rocks is estimated to about 51-88 billion barrels of oil equivalent for a

3,000 km2 less tectonically disturbed part of the Caltanissetta basin. No published

shale gas/oil assessment for the Caltanissetta basin exists and no exploration for shale

oil/gas has been performed.

Cantabrian Massif

The Cantabrian Massif comprises materials varying in age from the Precambrian to the

Carboniferous. The Cantabrian Massif extends over an approximate surface of 19 000

km2. Two hydrocarbon wells were made in the area with an approximate equivalent of

0.1 wells for every 1,000 km2. Presence of mine gas has been known since long ago

(methane with ethane traces, etc.) in the coal mines especially in the Central



Carboniferous Basin. Also, the presence of mineral oils, distillates and condensates,

parafin remains, ozoquerites, etc. is detected in the host rock as well as in the coal

beds. All these hydrocarbon displays (solid, liquid and gas) prove that the

carboniferous materials constitute a source rock. No published shale gas/oil

assessment for the Cantabrian Massif exists and no exploration for shale oil/gas has

been performed.

Basque-Cantabrian basin

The Basque-Cantabrian Basin is a Mesozoic-Cenozoic basin generated by two stages of

subsidence (rifting): Triassic and Lower Cretaceous. The Basque-Cantabrian basin has

since the beginning of oil exploration been considered the most interesting area in

Spain because of the presence of abundant surface indications such as tar sands in the

core of the Zamanzas anticline or asphalts present on the edge of most diapirs. It

occupies an area of approximately 21,000 km2 with 202 exploration wells. No

published shale gas/oil assessment for the Basque-Cantabrian Basin exists and no

exploration for shale oil/gas has been performed.

Pyrenees basin

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

Cenozoic materials outcrop. The South-Pyrenean domain encompasses the areas of

the eastern, central and west Pyrenees, and has an area of about 20,000 km2 in which

63 wells have been drilled. The reservoir consists of two thick calcareous mega-

breccias of turbiditic origin forming two separate fields, the Middle and Upper Eocene.

The gas source rock may be the dark hemipelagic clays with a low content of organic

material, but with a thickness of over 300 m. Production began in 1984 and ended in

1989, when the field became an underground gas storage site. No published shale

gas/oil assessment for the Pyrenees basin exists and no exploration for shale oil/gas

has been performed.

Duero basin

With an approximate total area of 47,500 km2, 16 boreholes have been drilled in the

Cuenca del Duero-Almazan. No oil system has been found so far. ENDESA currently

has drilled deep boreholes for CO2 storage research in the area of Sahagún. No

published shale gas/oil assessment for the Duero Basin exists and no exploration for

shale oil/gas has been performed.

Ebro basin

The Ebro Basin occupies an area of about 39,700 km2 and has a total of 41 drilled

boreholes. In the 1980’s Campsa began drilling wells showing the existence of a gas

system in Mesozoic formations below the Tertiary series. Studies in the area suggest

the existence of Jurassic source rocks, and Jurassic reefs or oolitic bars type

reservoirs. The last exploration well drilled in the area in 2010 and has led to the

discovery of a new deposit in the area. No published shale gas/oil assessment for the

Ebro basin exists and no exploration for shale oil/gas has been performed.

Iberian chain basin

It is possible to distinguish six sectors with different characteristics; two of them may

have potential shale gas formations, the Cameros-Sierra de la Demanda Structural

Unit and the Aragonian Branch. The Iberian Range has an area of about 65,000 km2 in

which 18 boreholes have been drilled. The explorations have not found effective

petroleum systems in the area to date. No published shale gas/oil assessment for the

Iberian chain basin exists and no exploration for shale oil/gas has been performed.



Catalonian basin

In the Catalonian Chain area 24 boreholes have been drilled. No proven petroleum

systems are known. No published shale gas/oil assessment for the Catalonian basin

exists and no exploration for shale oil/gas has been performed.

Guadalquivir

Guadalquivir basin covers an area of about 23,000 km2, in which 90 wells have been

drilled. Exploratory activity is concentrated in two clearly distinct periods. In the

period 1945-1969 research period primarily conducted by Adaro, in which wells were

drilled to increase the knowledge of the basin but there were no oil discoveries. From

1981-2004 initiated by the Chevron exploration company that interprets the

Guadalquivir Basin as a landward continuation of the gas fields discovered in the Gulf

of Cadiz. In this period 51 boreholes were drilled. Total production provided by the

Guadalquivir fields (biogenic gas with 98% methane) to December 2004 amounted to

1,199,026 MNm3, of which nearly 90% comes from the Campos de Marismas (1,047

MNm3). The interest of this basin for potential shale gas reservoirs focuses on the

Palaeozoic substrate. The degree of uncertainty is high, since the Palaeozoic has

usually been the level of completion of exploration oil drilling and no petrophysical

data are available. Three zones, where the Palaeozoic is covered by Miocene-

Quaternary sedimentary series with a variable thickness up to approximately 3,500 m

are considered.

Lusitanian basin

Portugal has a potential shale hydrocarbon resource, in particular in the Lower Jurassic

of the Lusitanian Basin. The basin has undergone sporadic drilling episodes since

1906. In 1998-2001 four wells were drilled by Mohave Oil & Gas Corp. for

conventional resources. In the period 2010-2014 Porto Energy undertook a drilling

program where 23 drillings were made as part of an initial exploration of an

unconventional gas at the onshore Lusitanian basin. This exploration identified a group

of formations with potential for unconventional resources as shale gas and shale oil.

The interest was focused on two organic-rich marls, the Polvoeira Member of the Água

de Madeiros Formation and the Vale das Fontes Formation. The 23 boreholes and

reports were retained to GALP (Portugal’s oil and Natural Gas Company) and are not

available for research for the next 5 years whereup there are relashed.

The main conclusions of these findings 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 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. The

Lusitanian basin’s Lias were compared in this study to other unconventional resource

plays in North America (Eagle Ford, Niobrara, and Utica) as well as other Lias plays in

Europe (McWhorter et al. 2014).

Aquitaine basin

The Aquitaine Basin has long exploration history for hydrocarbons and most of the gas

resources are found in the southern sub-basins. Among the source rocks deposits are

the Sainte-Suzanne shales. The Sainte-Suzanne Marls Formation (Early Cretaceous) is

composed of homogenous marine, organic-rich shales with occurrence of bio-clastic



marly limestones. It can reach several hundreds of meters thickness, with a mean

TOC at 1-2%. The OM is of type II origin, but the formation has only crossed the oil

window in the southern parts of the basin (Serrano et al. 2006). The Sainte-Suzanne

marls have been mostly considered as a main cover for petroleum and gas systems

and have not been properly studied in an exploration perspective. The regional

syntheses of the Aquitaine Basin are based on BRGM (1974) and Serrano et al.

(2006).

South East basin (France)

The South-East basin is a poly-phased basin, and consequently 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. Because of its complexity the South-

East Basin has much less been searched for hydrocarbons. The present day

exploration focuses on the Provence, Alès, Causses and Languedoc sub-basins.

In the South-East Basin, several Stephanian and Permian basins are identified along

Hercynian structures. Not much public data regarding thickness or TOC content is

available from these scattered basins. The Schistes Cartons Formation (Lower

Jurassic) deposits are thicker in the Southern part of the South-East Basin (south of

Lyon) with thickness up to 500 m.

Autun basin

The Autun Basin is a low-elevation topographic depression located in the northern part

of the Massif Central. It is a small elliptic basin filled with Carboniferous (Stephanian)

to Permian, the so-called Autunian deposits, separated by an unconformity. The

Autunian series are more than 1000 m thick. The lacustrine deposits are organic rich,

with oil shales and bogheads. The various oil shales intervals were investigated and

the potential estimated (Marteau et al. 1982). The petroleum potential ranges from 70

to 100 kg/t and is twice that of the Schistes Cartons. The total reserves estimated

(max. 300 m depth) are ± 30 Mt.

Paris basin

The main source rocks of the Paris Basin are represented by the Carboniferous to

Permian (Stephanian) coal deposits and associated coal bed methane, and the Lower

Jurassic marine shales. The Lower Jurassic includes the Promicroceras Shale

Formation (Sinemurian), the Amaltheus Shale Formation (Pliensbachian) and the

Schistes Carton Formation (Toarcian).

The Late Carboniferous to Permian sucession has been poorly studied and is rarely the

target of exploration. Therefore, the issues of their extension, thickness, sedimentary

filling, internal geometry and structural control still remain open.

The Lower Jurassic shales are black marine shales source rocks (Sinemurian -

Pliensbachian) containing type II kerogen. The Promicroceras shale Formation source

rocks consist of blue-grey illitic shales with TOC content ranging from 0.2-0.9 wt%

(Bessereau & Guillocheau 1994). The Amaltheus Formation shale source rocks

comprise grey, silty, and micaceous shales. TOC ranges from 2-4 wt% with a

maximum HI value of 130 mg HC/g TOC (Bessereau & Guillocheau 1994).

The Schistes Carton Formation (Lower Jurassic) was deposited during the Toarcian

across a large area encompassing several European basins. This is actually the most

extended and most organic rich of the Jurassic black shales formations, with an

average TOC around 4-5% (Espitalié 1987). It is to some extent comparable to the

Bakken shales in the U.S. (Monticone et al. 2012). The OM is a type II kerogen

(marine bacterial and algal) with a Hydrogen Index (HI) values ranging from 500 to



750 mg HC/g TOC (Delmas et al. 2002). The oil window of the Schistes Cartons has

been traced from the compilation of T max values. The source rock in the Schistes

Carton Formation is thought to have maturated in the deepest area, at depths of

2600-2700m, during Maastrichian times and ongoing (Espitalié et al.1987).

Upper Rhine Graben basin

The approxematly 350 km long and 30 – 40 km wide Upper Rhine Graben has a

Variscan basement (Late Paleozoic), a Mesozoic cover and a Cenozoic sedimentary fill

at the top. The Source rocks are the Lower Jurassic Posidonia Shale and the Oligocene

Fish Shale (BGR 2016).

Northwest European Carboniferous basin

The Northwest European Carboniferous basin includes the Campine, Mons and Liège

basins in Belgium, the Pennine Basin in United Kingdom and Carboniferous shales in

the Netherlands and Germany (Fig. 37). In Europe distribution of Carboniferous shales

are found in a number of countries. In the Netherlands it is called the Geverik Member

of the Epen Formation, this is the time-equivalent of the Upper Bowland Shale

Formation in the United Kingdom (Andrews 2013), the Chockier Formation in Belgium

(Nyhuis et al. 2014), and the Upper Alum Shale Formation in Germany (Kerschke

2013). In Germany the interval has been drilled for exploration but no production has

as of yet occurred (Zijp 2015).

In the Netherlands no oil or gas deposits have been found that can be exclusively

linked to the Epen Formation. The Epen Formation is expected to be present in the

subsurface of almost all of the Netherlands, but has only been drilled in areas where it

is present at a depth of 4-5 km (Zijp & Ter Heege 2014).Of the two licences which

were given out in the Netherlands for unconventional resources the northern one

(Noordoostpolder) was intended to target the Geverik shale. However, all activity was

put on hold in 2010 while the Dutch Government commissioned two studies on the

effects and risks of shale gas exploration.

In Belgium research in the Campine region was performed on the hydrocarbon

potential of the coal deposits and their capability to produce coal bed methane. The

surrounding organic-rich mudstones were largely ignored, but are currently studied in

the frame of the increased interest in gas shales (Van de Wijngaerden et al. 2013,

2014, 2015).

The British Geological Survey (BGS) has assessed the shale gas resources of the

Carboniferous Bowland–Hodder formation in 2013 (Andrews 2013). The organic

content of the Bowland-Hodder shales is typically in the range 1-3%, but can reach

8% (Andrews 2013). Where they have been buried to sufficient depth for the organic

material to generate gas, the Bowland-Hodder shales have the potential to form a

shale gas resource analogous to the producing shale gas provinces of North America

(e.g. Barnett Shale, Marcellus Shale). However, central Britain has experienced a

complex tectonic history and the rocks here have been uplifted and partially eroded at

least once since Carboniferous times. Large volume of gas has been identified in the

shales beneath central Britain, but not enough is yet known to estimate a recovery

factor, or to estimate potential reserves (how much gas may be ultimately produced).

An estimate was made in the previous DECC-commissioned BGS report (2010) that

the Carboniferous Upper Bowland Shale, if equivalent to the Barnett Shale of Texas,

could potentially yield up to 4.7 tcf (133 bcm) of shale gas.

Northwest European Jurassic basin

The Northwest European Jurassic basin includes the Posidonia Shale Formation in the

Netherlands, Germany and France and the Wealden basin in United Kingdom (Fig. 38).



The Posidonia Shale Formation can be classified as a grey to black shale of Early

Jurassic (Toarcian age 182-180 Ma). Equivalent formations are deposited throughout

Europe, for example the Jet Rock Member in the English Yorkshire Basin.

In the western part of the West Netherlands Basin the Posidonia Shale Formation is

known to be the most important source rock for oil occurrences (Van Balen et al.

2000; De Jager and Geluk 2007; Pletsch et al. 2010) and it is suggested that also

some associated gas was sourced from the formation. Of the two licences which were

given out in the Netherlands for unconventional resources the southern one (Noord-

Brabant) was targeted at the Posidonia Shale Formation. However, all activity was put

on hold in 2010 while the Dutch Government commissioned two studies on the effects

and risks of shale gas exploration.

The Lower Jurassic Posidonia Shale is present in the North German basin, Upper Rhine

Graben and a large area in South Germany where the formation partly extends

unterneth the Molasse basin. The German Posidonia Shale has been descriebed and

assessed in BGR (2016).

In the United Kingdom the Weald Basin has a long history of oil and gas exploration;

there are 13 producing sites in the basin, some almost 30 years old. The British

Geological Survey has studied the Jurassic shales of the Weald Basin (see Andrews

2014). The Jurassic of the Weald Basin contains five organic-rich, marine shales.

Where they have been buried to a sufficient depth for the organic material to generate

oil, all five prospective shales are considered to have some potential to form a shale

oil resource analogous, but on a smaller scale, to the producing shale oil provinces of

North America (e.g. Barnett, Woodford and Tuscaloosa). There is unlikely to be any

shale gas potential, but there could be shale oil resources in the range of 2.2-8.5

billion barrels of oil (290-1100 million tonnes) in the ground, reflecting uncertainty

until further drilling is done.

North German basin

The North German basin is well known for its hydrocarbon resources mainly natural

gas. BGR (2016) have identified and assessed several formations with shal gas/oil

exploration potential within the North German basin. These are the Kohlenkalk Facies

(Lower Carboniferous), the Hangender Alaun Shale (Kulm Facies) (Lower

Carboniferous), the Mittelrhät Shale (Upper Triassic), the Posidonia Shale (Lower

Jurassic), the Wealden shale (Lower Cretaceous) and the Blättertone (Lower

Cretaceous). The shale in the North German basin has been descriebed and assessed

in BGR (2016).

Midland Valley Scotland basin

The Midland Valley of Scotland has a long history of oil and gas exploration. The

British Geological Survey (BGS) has studied the Carboniferous shales of the Midland

Valley of Scotland (See Monaghan 2014)(Fig. 39). The Midland Valley has a complex

basin composition with interbedded Carboniferous sedimentary and volcanic rocks

forming a succession up to locally over 5,500 m thick. Potentially prospective

Carboniferous shales are buried beneath an area from Glasgow to Edinburgh, to the

Lothians, Falkirk, Clackmannan and Fife (Monaghan 2014).

As a result of significant burial, uplift and erosion, Carboniferous shales are mature for

oil generation at shallow current-day depths over much of the Midland Valley of

Scotland study area, and gas-mature shales occur at current-day depths from about

700 m below Ordnance Datum. The current day oil- and gas-mature depths of Midland

Valley shales are shallow compared to the UK Bowland-Hodder shales, Jurassic shales

of the Weald and many commercial plays in the USA. Locally, maturation is enhanced



by igneous intrusion (Monaghan 2014). Geological and geochemical criteria that are

widely used to define a successful shale oil and shale gas play can be met in the

Midland Valley of Scotland.

The BGS study offers a range of total in-place oil resource estimates for the

Carboniferous shale of the Midland Valley of Scotland of 3.2 - 6.0 - 11.2 billion bbl

(421-793-1497 million tonnes) (Table 5). Total in-place gas resource estimates are

49.4 – 80.3 – 134.6 tcf (1.40 – 2.27 – 3.81 tcm). The West Lothian Oil-Shale unit

makes the largest contribution to this estimated resource (Monaghan 2014).



Deliverable T4b: Geological resource analysis of shale gas and shale oil in Europe

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 description of the basins includes the general description of the basins and

formations and the link to the CP sheets (Screening_ID) and the GIS environments

generated in Tasks 5 and 6 the geographical extent of the basin and the assessed

formations within (in figure), a brief description of the depositional and structural

setting of the basin, a description of the individual shale formations in the basin, with

depth, thickness and shale gas/oil properties and a chance of success assessment.

The chance of success assessment describes all formations in a semi-quantitative

scoring on coverage of critical data for assessing 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 chance of success components 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. Although this risk is relatively low in mature

hydrocarbon provinces, it can be a significant factor in many of the underexplored

regions, 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 much on the local conditions and information is very sparse.

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

Appendix of report T7b.



Deliverable T6b: Overview of shale layers characteristics in Europe relevant for assessment of unconventional resources

This report provides a comprehensive introductory overview of relevant shale layer

characteristics gathered from the EUOGA participating National Geological Surveys

(NGS) in 2016. This report accompanies the detailed and complete basin-per-basin

and play-by-play overview included in deliverable T4 (Geological resource analysis of

shale gas and shale oil in Europe) and comprises the numerical description of the

shale layers. The overview is based on the returned templates describing the shale

properties and geological reports completed as part of the data gathering. The shale

layer template was prepared as part of the EUOGA project and was send to the

participating NGS (Figure 1).

The EUOGA critical parameter template for uniformly describing EU shale plays

includes 30 parameters of which 22 allow a probability density function to be defined

and six non-numerical parameters. 82 shale layers meet EUOGA screening parameters

and were selected for detailed characterisation by the NGS’s. To simplify identification

of the shale layers and to insure full integration with the GIS web portal and its

underlying geodatabases the shale layers are given a screening index value by the

GEUS team upon retrieval. The screening index number is linked to a critical

parameter (CP) sheet and is used as unique shale ID.

The data source for all parameters is added in a full bibliography with 250 references

that together with the data delivery itself represent a state-of–the-art description of

the current scientific knowledge of European shale gas and oil research. The template

includes 30 parameters of which 22 could be specified with a probability density

function (min, max, mean and mode of distribution). The return ratio (calculated for

numerical data as the ratio of the number of reported mean values to the total shales

layer number) range between 3-100% with an overall average for all parameters

(including non-numerical information) of 50%. The reported information is generally

sufficient to describe the distribution function of the TOC content (78% report a mean

value) and to some extent also the porosity distributions (35% report a mean value).

The mineralogy of the shale layers is partially documented (36% report a mean

composition). For nearly all shales the organic matter type is given and for about 47

shales (or 59%) the thermal maturity of the shales is provided.

Reference shales from selected North American thermogenic and biogenic shale gas

resource systems reflecting the conditions within the core producing areas of each

basin are included for comparison with the EUOGA shales. The EUOGA shale layers

have on average quite similar values as the average of the North American shales. An

important difference for the hydrocarbon assessment is, however, that the European

shales on average have 4.9% porosity whereas the North American shales on average

have 6.3%. It must be stated that the European shales are rather poorly characterised

with respect to porosity. Furthermore the North American shale layers reflect

conditions in the core area - defined as optimal for production - an area definition that

the EUOGA database does not reflect. Mineralogical difference also exists between the

EUOGA shale layers and the North America shale types. The mineralogy of North

American shales is typical dominated by non-clay components and thus the ratio non-

clay / total clay content is higher than one. In contrast the EUOGA shales tend to be

clay dominated and have a ratio of non-clay / total clay content lower than one.



A total of 38 basins have been identified. The basins compares well with known

sedimentary basins in Europe where a shale based hydrocarbon resource system was

known to be present. The 38 EUOGA basins are grouped into 36 thermogenic

hydrocarbon basins and two biogenic shale gas basins and the shale layers assigned to

each basin are presented in this report. To ease identification a unique basins index

numbering system and a unique play acronym labelling system has been designed to

ensure as smooth data handling operations as possible.

Figure 1. Countries that have delivered critical parameters for relevant shale

formations. For Germany, data from BGR (2016) has been used for the main

unconventional shales i.e. Posidonian and Carboniferous shales (CP2012 and CP2013).



Deliverable T7b: Resource estimation of shale gas and shale oil in Europe

This report summarizes the results of Task 7 of the Geological Resource Analyses of

shale gas and shale oil in Europe; the Resource Estimation. The EUGOA study

incorporates data for a total of 81 hydrocarbon-bearing shale formations within 34

geological basins covering 21 countries of Europe (Figure 1, Report T4b and T6b).

Based on the criteria described in T6b and agreed methodology described in T2b, 49

out of the total 81 formations within 19 countries were selected for a stochastic

volumetric assessment of prospective hydrocarbon resources (Table 1). 15 shale

formations are believed to hold both shale oil and shale gas, while 26 formations are

considered to be only gas bearing and 8 formations only oil bearing. The total

estimated resource potential for all assessed countries within the EU is 86.5 tcm of gas

and 30.2 billion barrels of oil in place.

Figure 1. Overview of the 34 identified shale basins within the 21 countries

contributing to the EUOGA study.



Table 1. Overview of total GIIP and OIIP for all 49 EUOGA assessed formations.

The volumetric assessment presented in this report is based on the following input and

preparatory steps:

A characterization of each shale formation by 20 geological assessment parameters,

as provided by the National Geological Surveys and processed by GEUS (Report

T6b). In case no parameter value has been provided for a certain assessment unit,

an average value has been determined from the combined available parameters for

all shale formations included in EUOGA.

A determination of the probability and uncertainties regarding the presence of gas

and oil in each shale formation (report T4b, results summarized in Appendix A).

A subdivision of each shale formation into regional assessment units using GIS data,

parameter values and common agreed cut-off values.

A ranking system based on TOC, depth, thickness and maturity of the shale

formation which leads to three classes of certainty represented in the final numbers.

Based on the outcomes of these preparatory steps and input data the GIIP/OIIP

values per formation and basin were estimated applying the Monte Carlo method as

outlined in report T2b. For gas-bearing shale formations the amount of free gas as

well as the amount of adsorbed gas has been estimated. For oil-bearing shale

formations the amount of free oil has been estimated.



Sensitivity analysis of the results shows that the highest uncertainties lie with gas

saturation and porosity for the amount of free gas, Langmuir Volume and formation

thickness for the amount of adsorbed gas and saturation for the amount of oil in place.

For each formation, however, the exact distribution of the influence of these

parameters is different, based on the quality and quantity of the available data and

the assumptions. In some cases the formation thickness has a much higher influence

on the uncertainty when, e.g., very little is known about the actual distribution of the

formation or the thickness of the prolific layers within a thick general formation. In

other cases, very little to nothing is known about the porosity and only general

assumptions could be made for this very important but also locally driven parameter.

Additional geological studies executed by the National Geological Surveys on available

conventional exploration data can aid in reducing the uncertainty of these parameters.

Uncertainty with respect to saturation and Langmuir factors are likely very difficult to

reduce. These parameters are very locally driven, can vary significantly over small

distances, and are very difficult to predict on a regional scale.

The main result of this study is the collection and standardisation of geological data of

potential shale gas/oil formations from the participating European countries and the

identification of gaps in this dataset. During this study it became evident, that a lot of

data is still missing from the collection (for various reasons). However this study sets

the base for future extensions and improvements of the database and the unified

integrated method makes is easier to implement new or modified data into updated

calculations.

European Unconventional Oil and Gas Assessment (EUOGA) · 2017-09-13 · stochastic volumetric...

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