Assessing the Shale Gas Potential of the Northwest Carboniferous Basin of Ireland’’ September 2012

Home , Geology of Ireland, Leitrim Group, Tyrone Group

ASSESSING THE SHALE GAS POTENTIAL OF THE

NORTHWEST CARBONIFEROUS BASIN OF IRELAND

A Thesis submitted to the University of Manchester for the degree ‘MSc By Research Basin Studies and Petroleum Geoscience’ in the Faculty of Engineering and Physical Sciences

2012

SAMI MOHAMED KHATTAB

School of Earth, Atmospheric & Environmental Sciences

In the name of Allah, Most Gracious, Most Merciful...

UNIVERSITY OF MANCHESTER Sami Mohamed Khattab MSc By Research Basin Studies and Petroleum Geoscience ‘‘Assessing the Shale Gas Potential of the Northwest Carboniferous Basin of Ireland’’ September 2012

ABSTRACT

The success of shale gas in the US has ignited companies to explore the unproven shale gas potential European basins hold. Past exploration in the Northwest Carboniferous Basin of Ireland confirms the presence of gas shows concentrated in thick source rocks with high thermal maturities, but its shale gas potential is yet to be understood. This research has assessed the shale gas potential of the Bundoran, Benbulben, Carraun and Dergvone Shales aiming to understand the variability in source rock potential, generation and adsorption history, and mudstone lithofacies. To achieve this a comprehensive integrated study of outcrop and subsurface exploration data has been undertaken. Outcrop data comprises sedimentary logging, sample collection and a spectral gamma ray survey, as well as thin section and TOC analysis. Subsurface exploration data comprises geochemical data and well logs.

Shale gas potential is encouraging in the Bundoran Shale in which it is the primary target, while the Benbulben Shale is a secondary target where deep enough. The Carraun and Dergvone Shales are high risk as occur at maximum depths of <300m. The highest shale gas potential occurs in the Lackagh Hills and Thur Mountain region in the Ballymote Syncline where the thickest, deepest, and sufficiently mature formations are encountered. A good data set in the north of the basin suggests this region is high risk due to shallow depths, while the central and southern areas are medium risk where greater depths are encountered. The key risks in the Bundoran Shale are depth, TOC% and the uncertainty of microfacies variation in the middle section. There is a lack of data coverage in the Lackagh Hills and Thur Mountain area as the exploration wells have been drilled on the basin highs, causing a major uncertainty with respect to source rock potential and mudstone lithofacies variability. The author recommends drilling a stratigraphic well in the center of the basin (Lackagh Hills and Thur Mountain area) to fully assess the variation in TOC% and microfacies variation by analysing wireline logs, core and XRD data. 3

TABLE OF CONTENTS

1. INTRODUCTION, AIMS & DATA SET ...... 17

1.1 Introduction ...... 17

1.2 Aims ...... 18

1.3 Data Set ...... 18

2. LITERATURE REVIEW ...... 19

2.1 Literature & Stratigraphy ...... 19

2.2 Shale Gas Overview ...... 21

2.2.1 Shale Gas & Mudstones ...... 21

2.2.2 Classification of Shale Gas System ...... 22

2.2.3 Fundamental Shale Gas Requirements ...... 23

2.2.4 Production Processes ...... 23

2.3 Exploration History ...... 24

2.3.1 First Phase: 1962-66 ...... 24

2.3.2 Second Phase: 1980-87 ...... 24

2.3.3 Third Phase: 1996-2001 ...... 24

2.3.4 Current Exploration ...... 24

2.4 Regional Tectonic Setting ...... 25

2.4.1 The Caledonian Orogeny ...... 26

2.4.2 The Variscan Orogeny ...... 26

2.4.3 Burial History of Ireland ...... 27

2.4.4 Maturation of Ireland ...... 28

2.5 Basin Evolution ...... 29

2.5.1 Structural Framework ...... 29

2.5.2 Courceyan ...... 30

2.5.3 Chadian – Arundian ...... 30

2.5.4 Arundian – Holkerian ...... 31

2.5.5 Holkerian – Asbian ...... 31

2.5.6 Asbian – Brigantian ...... 32

2.5.7 Brigantian – Arnsbergian ...... 32

2.5.8 Maturation of NW Carboniferous Basin ...... 33

2.6 Facies Descriptions of Shale Gas Formations ...... 33

2.6.1 Bundoran Shale (Lower Lisgorman) ...... 33

2.6.2 Benbulben Shale (Upper Lisgorman) ...... 34

2.6.3 Carraun Shale ...... 35

2.6.4 Dergvone Shale ...... 36

3. METHODOLOGY ...... 37

3.1 Subsurface Data ...... 37

3.1.1 Structure of Shale Gas Formations ...... 37

3.1.2 Geochemical Evaluation ...... 37

3.1.3 Contour Maps ...... 38

3.1.4 Wireline Logs ...... 38

3.2 Field Work ...... 38

3.2.1 Sedimentary Logging and Sample Collection ...... 38

3.2.2 Spectral Gamma Ray Survey ...... 39

3.3 Laboratory Work ...... 39

3.3.1 Thin Section Analysis ...... 39

3.3.2 Total Organic Carbon Analysis ...... 39

3.4 Basin Modelling ...... 42

4. RESULTS ...... 43

4.1 Subsurface Data ...... 43

4.1.1 Structure of Shale Gas Formations ...... 43

4.1.2 Geochemical Evaluation ...... 46

4.1.3 Wireline Log Analysis: Sweet Spots ...... 52

4.2 Field & Laboratory Work ...... 53

4.2.1 Bundoran Shale ...... 53

4.2.2 Benbulben Shale ...... 61

4.2.3 Carraun Shale ...... 65

4.2.4 Dergvone Shale ...... 68

4.3 Basin Modelling ...... 75

4.4 Risk Assessment ...... 79

5. DISCUSSION & INTERPRETATION ...... 81

5.1 Bundoran Shale ...... 81

5.1.1 Source Rock Potential ...... 81

5.1.2 Hydrocarbon Generation and Expulsion History ...... 82

5.1.3 Mudstone Lithofacies ...... 83

5.2 Benbulben Shale ...... 86

5.2.1 Source Rock Potential ...... 86

5.2.2 Hydrocarbon Generation and Expulsion History ...... 87

5.2.3 Mudstone Lithofacies ...... 87

5.3 Carraun Shale ...... 89

5.3.1 Source Rock Potential ...... 89

5.3.2 Hydrocarbon Generation and Expulsion History ...... 89

5.3.3 Mudstone Lithofacies ...... 90

5.4 Dergvone Shale ...... 91

5.4.1 Source Rock Potential ...... 91

5.4.2 Hydrocarbon Generation and Expulsion History ...... 91

5.4.3 Mudstone Lithofacies ...... 92

6. CONCLUSIONS ...... 94

7. RECOMMENDATIONS ...... 96

REFERENCES ...... 97

APPENDICES ...... 106

Final word count: 23,157

Word count in main text: 17,792

LIST OF FIGURES

Figure 1. Map of northwest Ireland showing study area ...... 18 Figure 2. Generalised stratigraphy of the NW Carboniferous Basin of Ireland ...... 20 Figure 3. Petrologic settings of shale gas plays...... 21 Figure 4. Map of the licences awarded to Tamboran and Langco ...... 25 Figure 5. Regional tectonic setting during the Caledonian Orogeny ...... 26 Figure 6. Regional tectonic setting of NW Europe in the Middle Devonian and Early Carboniferous during the Variscan Orogeny ...... 27 Figure 7. Thermal history of NW Ireland and the NW Carboniferous Basin ...... 27 Figure 8. Thermal maturity levels of Carboniferous rocks in Ireland ...... 28 Figure 9. Structural map of the study area ...... 29 Figure 10. Photograph of the equipment used for the extraction of organic carbon ...... 41 Figure 11. Photograph of the LECO instrumentation...... 42 Figure 12. Well correlation across the Ballymote Syncline ...... 44 Figure 13. Isopach and depth maps of the Bundoran Shale using wells A to I ...... 45 Figure 14. Isopach and depth maps of the Benbulben Shale using wells A to I ...... 45 Figure 15. Lithostratigraphic diagram of upper Leitrim Group in Thur Mountain and Lackagh Hills ...... 46 Figure 16. Map of the total radioactivity of Northern Ireland section of basin ...... 47 Figure 17. Summary of geochemical data from well B ...... 48 Figure 18. Summary of geochemical data from well G ...... 49 Figure 19. Average TOC% maps of Bundoran and Benbulben Shales ...... 50 Figure 20. Vitrinite reflectance maps of the Bundoran and Benbulben Shales...... 51 Figure 21. Simplified outcrop map of the Sligo and Ballymote Synclines ...... 53 Figure 22. Satellite image showing location of the Bundoran Shale type section .. 53 Figure 23. Sedimentary log of lower 30.45m of Bundoran Shale, TOC% and spectral gamma ray data ...... 54

Figure 24. Ballyshannon Limestone: a) Rhythmical cyclicity of bioclastic limestone and siltstone. b) Well preserved crinoid ossicle 1.5m in length ...... 55 Figure 25. Bundoran Shale: a) Beneath the yellow line=0-6.32m. b) Displays homogeneous nature of the matrix and an erosive surface. c) Concretionary nodules ...... 55 Figure 26. Bundoran Shale: a) Parasequences in the 3.10m sequence. b) Two dominant orientations of vertical parallel fractures ...... 56 Figure 27. Bundoran Shale: a) The lowermost exposed section in the western section b) 7-10mm thick and 5-7cm long vertical burrow ...... 56 Figure 28. Bundoran Shale: 17.15m to 20.3m ...... 57 Figure 29. Bundoran Shale: Shows gross structure at the top of the section ...... 57 Figure 30. Bundoran Shale: a) Corals in life position. b) Spiriferida brachiopod. c) Chondrites. d) Bottom of surface located at 26.3m - heavily bioturbated. e) Vertical burrows, possibly Ophiomorpha or Arenicolites. f) Flame structure. 58 Figure 31. PLATE 1: Bundoran Shale microfacies ...... 59 Figure 32. Benbulben Shale: Study area of ''Blue Rock'' outcrop ...... 61 Figure 33. Benbulben Shale: a) Large-scale structure of the outcrop. b) Close up of shale at the base of the exposure ...... 61 Figure 34. Benbulben Shale: Red box shows the study area of the ''Tievebaun Mountain'' outcrop ...... 62 Figure 35. Benbulben Shale: A graphic log showing the gross structure of the 25m section...... 62 Figure 36. Benbulben Shale: Spectral gamma ray and TOC% data of the lower 6m of the Benbulben ‘‘Tievebaun Mountain’’ outcrop ...... 63 Figure 37. Benbulben Shale: a) 25m section from figure 35. b) Close up of thick 70cm siltstone beds at base of outcrop. c) Solitary coral ...... 63 Figure 38. PLATE 2: Benbulben Shale – ''Tievebaun Mountain'' microfacies ...... 64 Figure 39. Carraun Shale: Shows the variable accessibility along the stream where the Carraun Shale is exposed ...... 65 Figure 40. Carraun Shale: a) Shows the well-exposed bedrock stream. b) Shows the hammer stuck in the rock due to the softness caused by the clay rich composition...... 65 Figure 41. Carraun Shale: Sedimentary log, spectral gamma ray and TOC% data of the lower 5m of the Carraun Shale outcrop ...... 66 Figure 42. PLATE 3: Carraun Shale microfacies ...... 67 9

Figure 43. Dergvone Shale: a) Base of waterfall where Tullyclevaun Shale is exposed. b) Pyritised burrow. c) Pyritised goniatites ...... 69 Figure 44. Dergvone Shale: Sedimentary log, spectral gamma ray and TOC% data of the lower 3m of the Tullyclevaun (Dergvone) Shale outcrop ...... 69 Figure 45. PLATE 4: Tullyclevaun (Dergvone) Shale microfacies ...... 70 Figure 46. Dergvone Shale: Sedimentary log, spectral gamma ray and TOC% data of Dergvone Shale Road Section ...... 71 Figure 47. PLATE 5: Dergvone Shale (Road Section) microfacies ...... 72 Figure 48. Dergvone Shale: Sedimentary log, spectral gamma ray and TOC% data of Dergvone Shale - Killooman Shale...... 73 Figure 49. PLATE 6: Killooman (Dergvone) Shale microfacies ...... 74 Figure 50. ‘‘More accurate’’ schematic heat flow diagram ...... 75 Figure 51. Representative schematic adsorption potential model ...... 76 Figure 52. 1D basin model - well I ...... 77 Figure 53. Heat flow model correlated with vitrinite reflectance data for well I ... 77 Figure 54. 1D basin model (well I) with no thick Carboniferous deposits, no Variscan uplift and a deeper Mesozoic burial...... 78 Figure 55. Heat flow model correlated with vitrinite reflectance data for ‘‘Thick Permo-Triassic’’ Model ...... 78 Figure 56. Common Risk Segment map risking the source presence of the Bundoran Shale ...... 79 Figure 57. Common Risk Segment map risking the source presence of the Benbulben Shale ...... 79 Figure 58. Radar plot of the Carraun Shale risking depth, thickness, TOC%, Ro% and Tmax against minimum fundamental shale gas requirements for shale gas ...... 80 Figure 59. Radar plot of the Dergvone Shale risking depth, thickness, TOC%, Ro% and Tmax against minimum fundamental shale gas requirements for shale gas ...... 80

LIST OF TABLES

Table 1. TOC% data of field samples ...... 47 Table 2. Tmax data of field samples ...... 47 Table 3. Hydrogen index data of field samples ...... 47 Table 4. ‘Sweet spots’ mapped in the Bundoran Shale ...... 52 Table 5. Displays key basin model results for well C ...... 76 Table 6. Displays key basin model results for well I ...... 77

LIST OF APPENDICES

Appendix 1. Lithostratigraphic diagram correlating the stratigraphy across the three sub-basins ...... 106 Appendix 2. Summary of hydrocarbon shows/flows and gas compositions encountered by exploration wells drilled in the Ballymote Syncline ...... 107 Appendix 3. Map of the British Isles illustrating the configuration of Lower Carboniferous sedimentary basins and their major basin bounding faults ... 108 Appendix 4. Key to cross-sections and bedrock geology map ...... 109 Appendix 5. Cross-sections E - H ...... 110 Appendix 6. Cross-sections C - D ...... 111 Appendix 7. Solid bedrock geology map of the Sligo and Ballymote Synclines with the structural framework of the basin ...... 112 Appendix 8. Variation in thickness and depths of the shale formations across the basin in a general NW-SE direction from Benbulben to Bencroy ...... 112 Appendix 9. Summary of geochemical data from well A ...... 113 Appendix 10. Summary of geochemical data from well C ...... 114 Appendix 11. Summary of geochemical data from well F ...... 115 Appendix 12. Summary of geochemical data from well I ...... 116 Appendix 13. Flow test results obtained from the 1962 drillig of well G ...... 117 Appendix 14. Flow test results obtained from the 1981 re-entry programme for well G ...... 117 Appendix 15. Wireline data for Bundoran Shale in well D ...... 118 Appendix 16. Wireline data for Bundoran Shale in well E ...... 118 Appendix 17. Wireline data for Bundoran Shale in well F ...... 119 Appendix 18. Wireline data for Bundoran Shale in well G ...... 119 Appendix 19. Wireline data for Bundoran Shale in well I ...... 120 Appendix 20. Fracture orientation in the Bundoran Shale in the Eastern Section of the type section ...... 120 12

Appendix 21. Burial history and heat flow model of well A ...... 121 Appendix 22. Burial history and heat flow model of well B ...... 122 Appendix 23. Burial history and heat flow model of well F ...... 123 Appendix 24. Burial history and heat flow model of well G ...... 124 Appendix 25. Sorption capacities of type I, II and III kerogens ...... 125

DECLARATION

I declare that no portion of the work referred to in the thesis has been submitted in support of an application for another degree or qualification of this or any other university or other institute of learning.

COPYRIGHT STATEMENT i. The author of this thesis (including any appendices and/or schedules to this thesis) owns certain copyright or related rights in it (the “Copyright”) and he has given The University of Manchester certain rights to use such Copyright, including for administrative purposes. ii. Copies of this thesis, either in full or in extracts and whether in hard or electronic copy, may be made only in accordance with the Copyright, Designs and Patents Act 1988 (as amended) and regulations issued under it or, where appropriate, in accordance with licensing agreements which the University has from time to time. This page must form part of any such copies made. iii. The ownership of certain Copyright, patents, designs, trade marks and other intellectual property (the “Intellectual Property”) and any reproductions of copyright works in the thesis, for example graphs and tables (“Reproductions”), which may be described in this thesis, may not be owned by the author and may be owned by third parties. Such Intellectual Property and Reproductions cannot and must not be made available for use without the prior written permission of the owner(s) of the relevant Intellectual Property and/or Reproductions. iv. Further information on the conditions under which disclosure, publication and commercialisation of this thesis, the Copyright and any Intellectual Property and/or Reproductions described in it may take place is available in the University IP Policy (see http://documents.manchester.ac.uk/DocuInfo.aspx?DocID=487), in any relevant Thesis restriction declarations deposited in the University Library, The University Library’s regulations (see http://www.manchester.ac.uk/library/aboutus/regulations) and in The University’s policy on Presentation of Theses.

DEDICATION

I would like to dedicate this thesis to my kind and loving parents Mohamed and Ann Khattab, my two brothers Ahmed and Ryan, and my grandparents Svend and Anne-Lise Bjergegaard who have always believed in me. God bless you.

ACKNOWLEDGEMENTS

I gratefully thank BNK Petroleum for their kind generosity in providing me the opportunity of a lifetime to undertake this research project, in particular Dr. Steven Warshauer and Mr. James Hill. I give my gratitude to my supervisors Prof. Kevin Taylor, Prof. Jonathan Redfern, Prof. Brian Williams and Mr. James Armstrong for the continuous support they have provided me throughout the course of this research project. Thank you to Mr. Tony Bazley (Director at Tamboran Resources) and Mr. Koen Verbruggen (Principal Geologist at Geological Survey of Ireland) for providing assistance during the first field excursion. A very special thank you goes to Ms. Cath Davies, Senior Analytical Research Technician in the Geochemistry Lab in the SEAES department, for being an absolute star! I am very thankful to Kathleen Nolan for being such a fantastic research colleague; I appreciate everything she has done for me. Thank you to Ali Dawood for kindly proof reading my thesis and last but not least, I would like to give a special mention to Rosanne Mckernan, because if it were not for her I wouldn’t be where I am today, so thank you.

1. INTRODUCTION, AIMS & DATA SET

1.1 Introduction

The introduction of shale gas has dramatically changed the US gas market in the last 10 years, transforming USA from a net importer of gas to a net exporter, predicted to be self sufficient for at least the next 90 years (Northern Ireland Assembly, 2012). Based on the success in the USA, and owing to 5,760 tcf (trillion cubic feet) of technically recoverable shale gas worldwide (624 tcf in Europe), the world gas market has huge potential to be re-shaped, reducing the dominance of traditional gas exporting countries (EIA, 2011). This has ignited companies to explore the great potential European basins hold for shale gas.

Energy security is vital for the economic growth of any country. In Ireland 25% of their energy supply comes from gas, only 13% of this is sourced from indigenous gas fields, while the remaining 87% is sourced from the UK’s North Sea [URL 1]. In the long-term Ireland will need to find an alternative to its current gas supplies, with one such option being shale gas. The Northwest (NW) Carboniferous Basin of Ireland is currently the principal basin being appraised for its shale gas potential in Ireland. Past exploration confirms the presence of gas shows concentrated in thick source rocks with high thermal maturities, but its shale gas potential is yet to be understood. The basin is located in the NW of Ireland covering an area of approximately 100km by 120km, overlapping the political boundaries of Ireland and Northern Ireland (Figure 1).

Atlantic 50km Ocean NORTHERN IRELAND N

North Irish Sea Sea Dublin Manchester Co. Donegal Donegal 20km IRELAND N

Ballyshannon London Atlantic Bundoran Lower Lough Ocean A Erne C SLIGO B SYNCLINE D E Enniskillen F Sligo H Inishcrone G I Co. Sligo BALYYMOTE Lough SYNCLINE Allen Co. Cavan Co. Leitrim Leitrim

Co. Mayo CARRICK Co. Rosscommon SYNCLINE Co. Longford Figure 1. Map of northwest Ireland- Red line outlines the NW Carboniferous Basin of Ireland. The exploration wells (A –I) used in this research are shown by the red dots. Blue line indicates the orientation of the well correlation diagram in section 4.1.1. Blue box outlines contour maps produced using well data (Basin outline obtained from Corcoran and Clayton, 2001).

1.2 Aims

The aim of this research is to assess the shale gas potential of the NW Carboniferous Basin of Ireland focussing on the Bundoran, Benbulben, Carraun and Dergvone Shales. This will be achieved by assessing their source rock potential, mudstone lithofacies variability, and generation and adsorption history. These formations will be analysed at different scales ranging from basin scale (km) down to microscopic scale (mm>). The data will be risked using minimum fundamental shale gas requirements to define potential shale gas areas. The research project will focus on the Ballymote and Sligo Synclines (Figure 1). The Carrick Syncline will not be included in this study as it contains a section dominated by non-shale facies that display no evidence of gas shows (Appendix 1) (Caldwell, 1959).

1.3 Data Set

This research has undertaken a comprehensive integrated study of outcrop and subsurface exploration data. Outcrop data comprises sedimentary logging, sample collection and a spectral gamma ray survey, as well as thin section and TOC% analysis. Subsurface exploration data comprises geochemical data and well logs. 18

2. LITERATURE REVIEW

2.1 Literature & Stratigraphy

Sheridan (1972) was the first to devise the name ‘NW Carboniferous Basin of Ireland’ using exploration data from the Ambassador Oil Company to incorporate the regional scale of the basin (Naylor and Shannon, 2010). The central section of the basin was named the ‘Lough Allen Basin’ by Sheridan (1977) to account for the structural and geological differences (Somerville et al., 2009; Philcox et al., 1992). Principal studies have been able to obtain a thorough understanding of the overall regional tectonic setting, basin evolution, stratigraphy, depositional history, and structure of the basin by using outcrop, borehole, seismic reflection, gravimetric and palynological data. However, there is a lack of data in the literature regarding the microfacies and mineralogical variation, as past research has focused on palynological studies.

Important literature regarding tectonics of NW Europe includes Coward (1990, 1995), Leeder (1988), Cope et al., (1992) and McKerrow (2000). Literature regarding basin evolution includes Philcox et al., (1992), Somerville et al., (1992) and Worthington and Walsh (2011). Literature regarding stratigraphy and outcrop data includes Dixon (1972), Oswald (1955), Higgs (1984), Brandon and Hodson (1984), Caldwell (1959), Naylor and Shannon (2010), Avbovbo (1973), George and Oswald (1957), Smith (1995), Sheridan (1972) and MacDermot et al., (1996).

The stratigraphy of the NW Carboniferous Basin can be divided into the conformable successions of the Tyrone and Leitrim Groups. The stratigraphy falls under four of the six major eustatic cycles that occurred during the British and Irish Carboniferous (Figure 2) (Ramsbottom, 1973; George, 1978).

Sea Level Cycles Depositional Environments Basinal or Pro-delta Supra-tidal Delta Top or to Turbidite or Fluviatile & Time Lithology Formation Transgression Regression Shallow Marine 318Ma Delta Front Subaerial Bencroy Shale Fm. 8

Arnsbergian Lackagh Sst. Fm.

Gowlaun Shale Fm. 7

SILESIAN Briscloonagh Sst. Fm. Namurian Pendleian Dergvone Shale Fm.

326Ma Carraun Shale Fm. 6 Brigantian Leitrim Group Bellavally Fm. 328Ma Glenade Sst. Fm.

Meeneymore Fm.

Dartry Lst. Fm. Asbian including Reef Lst. 5 Glencar Lst. Fm.

332Ma

Visean Benbulben Shale Fm. MISSISSIPPIAN Holkerian Mullaghmore Sst. Fm. 339Ma Bundoran Shale Fm. 4

Dowra Sst. Fm Arundian ANTIAN Tyrone Group N Ballyshannon Lst. Fm. 3

DI 343Ma

345Ma Chadian Basal Clastics 349Ma

Tournasian Courceyan Old Red Sandstone

359Ma Figure 2. Generalised stratigraphy of the NW Carboniferous Basin of Ireland. Illustrates the major sea level cycles during the British and Irish Carboniferous - Cycles 7 and 8 have been interpreted. Displays the evolution of depositional environments through time (Adapted from Brandon and Hodson, 1984; Higgs, 1984, Ramsbottom, 1973; and Naylor and Shannon, 2010). 20

2.2 Shale Gas Overview

2.2.1 Shale Gas & Mudstones

Shale gas is an unconventional gas resource in which in situ natural gas is trapped within a sedimentary rock known as shale. Shale is the textural term for a fissile mudstone containing mm scale laminations of >50% silts and clays below 1/16mm (<63 μm) grain size (Aplin et al., 1999; Stow, 1981; Adams et al., 1994). Major depositional settings of muds occur in any relatively low energy environment where bottom water turbulence is minimal. This includes fluvial floodplains, lacustrine, deltaic, coastal, distal areas of platforms/ramps, basin slopes, toe of slope, and basin floor environments (Tucker, 2001; Slatt, 2011; Potter et al., 2005). However, suspensions of mud are prone to flocculation of up to 1mm in diameter that can be deposited in higher energy environments than previously thought (per.com J. Schieber 15/05/12). Figure 3. Petrologic settings of Shale Gas Plays (Alix et al., 2010).

The origin of muds is of detrital, productivity and/or authigenic derived material determined by the environment of deposition (Macquaker et al., 2007). Mudstones are compositionally variable consisting of metastable clay minerals, quartz and feldspar debris, carbonates, organic matter and heavy minerals (Potter et al., 2005). Characterisation of the lithofacies is important with regards to the amount of stress and type of Carbonate Minerals fluids needed during Hall, 4th Unconventional Gas hydraulic fracturing, as Technical Forum, April 2010 Calcareous Siliceous or Dolomitic Dolomite Vernick & Landis, 1996 Mudstone the most silica rich and AAPG Bulletin 80, 531-544 Eagle Ford brittle shale gas Pettijohn, 1975 Sedimentary Rocks formations normally have Niobrara Argillaceous Siliceous the most productive wells Marlstone Marlstone Monterey (Jarvie et al., 2007). Haynesville Montney Argillaceous Muskwa L. Marcellus Barnett Figure 3 illustrates there Mudstone Siliceous Bakken Monterey Average Shale Bazhenov Mudstone are no producing Siliceous Porcellanite Quartz + Clay Shale argillaceous shale gas Minerals Feldspar plays. Understanding the Figure 3. Petrologic Settings of Shale Gas Plays (Alix et al., 2010) geological and biotic processes in these depositional systems is fundamental to characterising the outcrop to thin section heterogeneity variability to localise the distribution of shale gas sweet spots (K. Taylor, per.com 15/03/12). 21

Sequence stratigraphy can be used to predict sweet spot variation in shale gas formations by analysing the systematic changes of mudstone architecture at a parasequence scale (Passey et al., 2010). Each 1-3m thick parasequence relates to a particular depositional environment through time allowing the vertical variation in composition and organic matter over a cm-m scale to be predicted (Passey et al., 2010). The balance between organic production, destruction by bacteria and oxidisation, and dilution by sediment determines the accumulation and preservation of organic matter that is required to form shale gas (Passey et al., 2010). The level of dissolved oxygen at the sediment-water interface is the fundamental control on benthic activity, bioturbation, colour, pyrite and TOC% in the mudstone. This is known as the ‘redox front’ (Potter et al., 2005).

The physical and chemical properties of muds cause them to be very susceptible to diagenetic processes. Flocculation results in a large variety of potential primary pore structures surviving burial that are critical to porosity and permeability (per.com J. Schieber 15/05/12). The gas generated during burial is stored in the free matrix of the pores, natural fractures (formed mainly from tectonic activity and hydrocarbon generation) and within the kerogen, as well as being adsorbed onto the surface of the organic matter and pore walls (Passey et al., 2010). Rich mature source rocks tend to have higher porosities because as the kerogen generates gas it leaves behind void space. This is important because organic pores tend to retain the highest amounts of gas (per.com K. Bohacs 15/05/12).

2.2.2 Classification of Shale Gas System

A shale gas system is an unconventional petroleum system in which the shale acts as a source, reservoir and a seal (per.com J. Armstrong, 06/10/11). Although conventional petroleum system concepts such as trap formation and migration pathways do not need to be considered, processes such as generation, adsorption and expulsion are vital to assessing the GIIP of a shale gas system (Magoon and Dow, 1994; Jarvie et al., 2007). Shale gas plays in the US are normally either biogenic plays, producing methane at shallow depths of <1km by methanogenic bacteria, or over-mature type II source rocks produced at depths of several kilometers in the gas window, generating methane by the thermal cracking of oil from kerogen (Jarvie et al., 2007).

2.2.3 Fundamental Shale Gas Requirements

Shale gas plays contain a wide range of successful exploration criteria, however there has been minimal shale gas exploration and production in Europe compared to USA, therefore it is only possible to refer to USA when analysing successful exploration criteria for shale gas (per.com P. Poprawa, 13/03/11). Exploration criteria can be split into reservoir and source rock properties due to the unconventional nature of the shale gas system (per.com J. Armstrong, 06/10/11).

The fundamental requirements of successful shale gas plays have >1% TOC, high Si%, low clay %, >40m thick, >1000km2, >1km deep, gas window thermal maturity levels, low expulsion potential and have a natural fracture network (Jarvie et al., 2007; Bouhlel and Bryant, 2012). It must be stressed that shales are highly heterogeneous causing every shale gas play to be unique. Consequently exploration criteria cannot simply be transferred from one successfully producing play to one that is being assessed for success to be guaranteed [URL 2].

2.2.4 Production Processes

Multi-stage hydraulic fracturing is a process used to increase the effective porosity of shale for gas to flow at commercial rates. A mixture of water, proppant (99.5%) and chemicals (0.5%>) are pumped into the well at extremely high pressures to propagate fractures in the shale (US Shale Gas Primer, 2009). The choice and quantity of chemicals used will largely depend on the type and quantity of clay, as clay can swell when in contact with fracking fluids [URL 6]. Under equivalent levels of hydraulic pressure clay is able to absorb more pressure than silica, bending rather than failing like silica does (Canadian National Energy Board, 2009).

Horizontal drilling is a process where up to 16 horizontal wells are drilled from one well pad [URL 3]. When the vertical well is close to the formation it is turned roughly 90° to drill roughly parallel for up to 1-2km. This allows a greater volume of the fracture network to be intersected increasing the recovery factor (<20%), decreasing well costs and decreasing the overall environmental impact (Bouhlel and Bryant, 2012). However, if the shale formation is too shallow there may not be enough space to rotate the well to horizontal, therefore a high potential shale gas formation can lose all its potential if too shallow (per.com J. Redfern 30/08/12).

2.3 Exploration History

2.3.1 First Phase: 1962-66

The first exploration licence was awarded to a consortium comprising Ambassador Irish Oil Company, Conoco and Marathon in 1962 to drill in the NW Carboniferous Basin (MacDermot et al., 1996). Nine wells were drilled including Dowra-1, Macnean-1 and Big Dog-1 encountering gas shows/flows in tight reservoirs that include the Dowra, Drumkeeran and Mullaghmore Sandstones (See Appendix 2 for summary of gas shows/flows) (Naylor and Shannon, 2010). The presence of gas shows indicate the existence of an active petroleum system, sourced and sealed by the Bundoran and Benbulben shales. Up to 2.9km of Courceyan to Arnsbergian limestones, organic rich marine shales and deltaic sandstones overlaying Caledonian basement were encountered (Philcox et al., 1992).

2.3.2 Second Phase: 1980-87

In 1980 a consortium led by Marinex Petroleum obtained a license for further exploration in the Dowra-1 and Macnean-1 wells. Marinex increased flow rates almost tenfold by acidizing and fracturing the sandstones, however this could not be sustained for commercial production (MacDermot et al., 1996). In 1984-85 a consortium led by Aran Energy drilled two wells in Ireland and two in Northern Ireland. Macnean-2, Drumkeeran South-1, Slisgarrow-1 and Kilcoo Cross-1 all had minor gas shows but did not flow gas to the surface (MacDermot et al., 1996).

2.3.3 Third Phase: 1996-2001

Thur Mountain-1 and Dowra-2 were drilled in Ireland, while four wells were drilled in County Fermanagh (Naylor and Shannon, 2010). Unsuccessful coal-bed methane exploration has also taken place as recently as 2009. A total of thirteen exploration wells have been drilled between 1962 and 2001, while six were hydraulically fractured [URL 4 & 6]. Well reports reveal the shale formations have never been fractured or tested for production.

2.3.4 Current Exploration

In February 2011, onshore petroleum licences were granted to Tamboran Resources and Lough Allen Natural Gas Company (Langco) lasting 24 months 24

covering an area of 1630km2 (Figure 4) [URL 5]. Internal estimates by Tamboran reveal 10.7-21.3tcf of GIIP in the Bundoran Shale with the potential for recoverable gas of 1.6-3.2 tcf (15% recovery factor), and 0.8-1.6tcf of GIIP in the Benbulben Shale with the potential for recoverable gas of 0.1-0.2tcf (10% recovery factor) [URL 6]. Tamboran Resources consider Leitrim to be the most viable county for shale gas exploration in Ireland, and are planning to begin fracking in southwest Co. Fermanagh in Northern Ireland in 2014 without the use of chemicals in the fracking fluid [URL 6]. Tamboran Resources are optimistic of drilling 100 well pads 2km apart over a 15-year period, with the entire project lasting 50 years [URL 6].

Donegal 20km Co. Donegal N NORTHERN

Bundoran Lower Lough IRELAND Erne Atlantic A Ocean C B Benbulben Crockauns Enniskillen Thur D Mountain E F Sligo Lackagh Hills Inishcrone H Corry Lough G Cuilcagh Mountain Allen Co. Sligo I Bencroy

Leitrim Co. Leitrim Co. Cavan Co. Mayo

Co. Rosscommon Co. Longford

2010 Onshore Licensing Area Tamboran - Licensing Area (ROI) Exploration Well Mountain/Hill LANGCO - Licensing Area Tamboran - Licensing Area (Northern Ireland) Well Correlation

Figure 4. Map of the licences awarded to Tamboran and Langco in February 2011. Blue box outlines contour maps generated using well data (Adapted from [URL 7] and DCENR).

2.4 Regional Tectonic Setting

Three major orogenic cycles determine the tectonic framework of NW Europe. These are the Laxfordian (1800-1700Ma), the Caledonian (500-400Ma) and the Variscan Orogenies (400-300Ma) (Coward, 1990; Rao et al., 2006). It is the Caledonian and Variscan Orogenic cycles that are responsible for shaping the tectonic framework of the British Isles (Price and Max, 1988).

2.4.1 The Caledonian Orogeny

The Caledonian Orogeny is a broad

term describing a sequence of tectonic

events in which Avalonia, Baltica and

Laurentia collided to form Laurussia

resulting in the closure of the Iapetus

Ocean (Figure 5) (McKerrow et al.,

2000; Rao et al., 2006; Woodcock and

Strachan, 2002). During the Silurian

continental fragments and magmatic

arcs concreted onto the Proterozoic

Laurentian craton, with the final

closure of the Iapetus Ocean occurring

due to Late Caledonian displacement

(Coward, 1990; Naylor and Shannon,

2010). This altered and offset earlier

Caledonian crustal framework forming

NE-SW sinistral strike-slip faults

(Coward, 1995). Caledonian

deformation is distributed across a

continuous interconnected fault system

below Carboniferous cover Figure 5. Regional tectonic setting showing different stages of the Caledonian Orogeny (Worthington and Walsh, 2011). (Naylor and Shannon, 2010).

2.4.2 The Variscan Orogeny

The Variscan orogeny of NW Europe formed from Late Devonian-Early Carboniferous accretion of magmatic arcs and crustal blocks of the African portion of Gondwana onto the southern margin of Laurussia, resulting in the closure of the Proto-Tethys Ocean (Figure 6) (Timmerman, 2004; Woodcock and Strachan, 2002). Late Devonian transtension at the southern margin of Laurussia formed a back-arc basin, separating Avalonia from Laurussia, and forming the Rhenohercynian Ocean (Timmerman, 2004). Final subduction of the Rhenohercynian Ocean occurred in the Early Carboniferous, causing N-S extension

pervasively reactivating the NE-SW trending

Caledonian fault network. This formed a series of fault controlled extensional basins across

NW Europe and Britain, closing and opening at various times during the Carboniferous, inheriting the NE-SW lineaments of the Caledonian basement (Appendix 3) (Leeder,

1988; Cope et al., 1992; Woodcock and Strachan, 2002; Coward, 1990). Lithospheric stretching caused Calc-alkaline volcanism in the Tournasian and peaked in the Visean

(Timmerman, 2004). Further collision of Gondwana and Laurussia resulted in inversion Figure 6. Regional tectonic setting of at the beginning of the Permian (Naylor and NW Europe in the Middle Devonian and Early Carboniferous (Naylor and Shannon, 2010).

Shannon, 2010).

2.4.3 Burial History of Ireland

The geology of onshore Ireland is extremely fragmented comprising mainly NW Carboniferous rocks and very limited N Carboniferous 4IME-A Basin '# Permian to Tertiary rocks (Corcoran and Clayton, 2001; Croker, 1995; Allen et al.,

4EMPERATURE²# 2002). Coupling this limitation with the ²# inability of AFTA and vitrinite reflectance to 4IME-A NW 200 Ireland record post-Variscan lower palaeothermal events, it is extremely difficult to accurately interpret Ireland’s post-Variscan burial 4EMPERATURE²# 200°C history (Green et al., 2000). Ireland has been Regional Cooling Events s -A,ATE#ARBONIFEROUSTO0ERMIAN subjected to repeated cycles of burial and s -A-IDDLE*URASSIC s -A%ARLY#RETACEOUS s -A%ARLY4ERTIARY KM exhumation since the Variscan Orogeny s -A,ATE4ERTIARY

(Figure 7) (Green et al., 2000). Clayton, 1989 Figure 7. Thermal history of NW Ireland suggests there was 5-7km of Carboniferous and the NW Carboniferous Basin constrained using AFTA and vitrinite burial to account for the high thermal reflectance data (Adapted from Green et al., maturities encountered in Carboniferous 2000 and Green et al., 2001).

strata (Naylor, 1992). Ireland was emergent for much of the Permo-Triassic, resulting in isolated areas of deposition in which these sediments rest unconformably on folded Carboniferous rocks (Naylor, 1992).

2.4.4 Maturation of Ireland

Maturity increases southwards across Ireland caused by Variscan granites and a regional advective system in the south of Ireland (Figure 8) (Parnell et al., 1996; Sevastopulo, 1981; Corcoran and Clayton, 2001). The primary mechanism for thermal maturation is burial (Clayton, 1989). The Cornubian batholith and the Haig Fras granitic plutons intruded the foreland basin to the south of Ireland. Not only was this a major source of heat, this also created a hydraulic head to drive gravity driven fluids northwards, causing Carboniferous palaeogeothermal gradients and organic maturity levels to rapidly vary laterally (Corcoran and Clayton, 2001).

86 D.V. CORCORAN & G. CLAYTON In Carboniferous strata ...... ,,, ...... ", maturity increases from 57 ~ N Ro% 3.0-5.0 in the 56~ , ..3 ~ ,// ~! / southwest to Ro% 0.6 in

01-.,,. %. the northeast (Clayton, 55 ~ N j :':':-:':':':':':':':<':':.': ~,-~ -~ 1989; Green et al., 2000). -'-" ' ~_ ii ~ 54~ ~i~ ~ Northern Ireland is ~// ~ ~ immature to early mature 53 ~ N t.--I

for gas generation present 52 ~ N day (Ro% >1.0) (Corcoran

51~ and Clayton, 2001). Post-

~q ...... 1.. 50~ N I Variscan strata have low ~: ! \: I -s ".... vitrinite reflectance "" o t/~ "" " .... i ...... Scale: /0 50 I t LEGEND ~ ] values, for example Ro% ~-~,~-~ ISO Maturity Contour (Rm%) ~ Top Carboniferous within gas generating window at max. burialdepths -dashedwhere conjectural ~ Direction of regional Variscan hydrothermal flow Carboniferous Source Rocks Absent/Supra Mature for gas I 0.46-0.53 in the generation present day ;: Carboniferoussections (Avg. palaeogeothermal gradient ~ I Fig. 19. Peak maturity levels of Carboniferous rocks: generalized Rm% contour map for Carboniferous and older sediments that subcrop the Saalian Unconformity surface. Rm% levels in Carboniferous rocks manifest a general decreaseFigure towards the8 . northThermal indicating maturity a fall in Variscan levels palaeotemperatures of Carboniferous in this direction. rocks Rapid in lateral Campanian chalk breccia at variations in palaeogeothermal gradients are consistent with a gravity-driven hydrothermal system discharging heated Ireland.fluids, along faultThe systems Variscan and fracture Cornubian zones, in a foreland batholith platform area. and With the respect Haig to organic Fras maturity levels and timing, the southern area is dominated by early maturity and high Variscan heat flows as a result of Ballydeenlea in Co. Kerry intrusion of Variscan granites and a regional advective system. The northern area is dominated by later maturity becausegranitic of relatively plutons lower Variscanintruded heat flows at to the the distal southend of the of regional Ireland advective (Corcoran system and is overprinted and by Mesozoic burial. Modified after Clayton et al. (1989), Maddox et al. (1995), Newman (1999) and Middleton et al. (2001).Clayton, 2001). (Allen et al., 2002).

2.5 Basin Evolution

2.5.1 Structural Framework

The NE-SW trending basin can be divided into three structurally separate sub- basins controlled by major faults; the Sligo Syncline, the Ballymote Syncline and the Carrick Syncline (Figure 9) (Oswald, 1955; Price and Max, 1988; Somerville et al., 1992). Post-Carboniferous tectonic activity folded the basin fill into broad synclines plunging ENE (Oswald, 1955; Dixon, 1972).

10km A N SLIGO B Atlantic GF Benbulben SYNCLINE C D Ocean Crockauns E F Ox-Ballyshannon OMPF Skreen High Dowra-Macnean High Lackagh Hills H G Cuilcagh Ox Mts. Inlier BF NOMF Lough Trough Allen Drumkeeran-Slisgarrow I

Ballymote BALLYMOTE CVF SYNCLINE

Gorteen Curlew Mts. Inlier CARRICK CF SYNCLINE Cloone

Selected less Major Faults Mountain/Hill Exlporation Well Well Correlation important faults Pre-Carboniferous NOMF: North Ox Mountains Fault GF: Grange Fault inliers OMPF: Ox Mountains-Pettigoe Fault WF: Woodbrook Fault

CVF: Clogher Valley Fault BF: Belhavel Fault Syncline

CF: Curlew Fault Outline of Lough Allen Basin (Philcox et al., 1992) Anticline Figure 9. Structural map of the study area focussing on the Ballymote and Sligo Synclines. Blue box outlines contour maps generated using well data (Adapted from Somerville, 2009; Philcox et al., 1992 and Macdermot et al., 1996).

The Curlew Fault on the northern side to the Curlew Mountains Inlier bounds the basin to the south (Worthington and Walsh, 2011; Price and Max, 1988). The Fintona Block marks the NE margin of the basin, a near rectangular 23 by 49km NE trending Devonian Old Red Sandstone fault bounded block (Price and Max, 1988). 29

The Ox Mountains Inlier is located through the middle of the basin trending NE- SW, separating the Sligo and Ballymote Synclines, bounded by the Ox Mountains- Pettigoe and North Ox Mountains faults (Max and Riddihough, 1975; MacDermot et al., 1996). There are two major intra-basinal structures within the Ballymote Syncline defined as the Dowra-Macnean High and the Drumkeeran-Slisgarrow Trough (Philcox et al., 1992). Within the Ballymote Syncline are two smaller synclines with an orientation of ENE-WSW, as well as other smaller unnamed shallow dipping <10 degrees anticlinal and synclinal structures, and anything more than 10 degrees is associated with faulting (MacDermot et al., 1996). Some formations extend beyond the basin margins described, however they are not as persistent or thick relative to the formations in this region of the NW Carboniferous Basin (Philcox et al., 1992).

2.5.2 Courceyan

Basin formation began in the Early Courceyan by movement along the SE section of the Caledonian Ox Mountains Inlier and the Curlew Fault. This continued into the Arundian with the main phase of rifting during the Late Courceyan (Philcox et al., 1992). Half-graben formation initiated the development of fluvial processes and alluvial fans depositing the Kilcoo Sandstone Formation and the Basal Clastics (Brunton and Mason; 1979; Philcox et al., 1992; MacDermot et al., 1996). In the Late Courceyan the sea migrated inland engulfing coastal plains and small hills leaving the Ox-Ballyshannon High emergent (Philcox et al., 1992; MacDermot et al., 1996). The source of sand changed to the NE rather than the NW reflecting uplift from outside the basin (Philcox et al., 1992). The Kilbryan Limestone is absent in the Dowra-Macnean High extending as far as the Belhavel Fault, but is found north in the basin in the Slisgarrow area (MacDermot et al., 1996).

2.5.3 Chadian – Arundian

In the Early Chadian differential subsidence rapidly formed the Dowra-Macnean High and the Drumkeeran-Slisgarrow Trough. A long-term regional northwards marine eustatic transgression submerged the previously emergent Ox- Ballyshannon High and Ox Mountains (Graham, 1996; MacDermot et al., 1996). The regional deposition of the Kilbryan and Ballyshannon Limestone occurred as the sea engulfed 90% of the Irish landmass (MacDermot et al., 1996). Cleaner

limestones formed in clear shelf waters over the highs, while in the troughs a thick succession of muddy basinal facies formed (Philcox et al., 1992; George and Oswald, 1957). Succeeding the Ballyshannon Limestone is a sudden change to mud deposition marking a change in basin evolution (MacDermot et al., 1996).

2.5.4 Arundian – Holkerian

Formation of the Ox Mountains culminated in this period separating the Ballymote and Sligo Synclines (Dixon, 1972). Activity on the Curlew Fault continued into the Holkerian with the Curlew Inlier separating the Ballymote syncline from the Carrick Syncline (Philcox et al., 1992), evident by the absence of the Mullaghmore and Benbulben Formations in the Carrick Syncline (Somerville et al., 2009). Fault activity caused a variation in sediment thickness in the hanging walls (Philcox et al., 1992). Major uplift enhanced fluvial processes and created accommodation for the deposition of the Bundoran Shale, resulting in 330m of erosion of the Curlew Inlier Block supplying copious amounts of muds to be transported into the basin (MacDermot et al., 1996). The Bundoran Shale was deposited in a relatively deep marine depositional environment in a fairly uniform water depth across the basin indicated by its consistent facies, however it is three or four times thinner on the highs compared to in the troughs (MacDermot et al., 1996). Uplift around the margin caused the Dowra and Drumkeeran Sandstones to be restricted to the basin center (Philcox et al., 1992). The Mullaghmore Sandstone formed from a southward prograding shallow marine delta sourced by onshore rivers (Graham, 1996; Buckman, 1992). Delta building was synchronous with subsidence in the center of the basin, resulting in the stacking of parasequences of thin-bedded fine- grained sandstones and siltstones, overlain by fluvial cross-bedded and parallel- bedded sandstones (Philcox et al., 1992; MacDermot et al., 1996).

2.5.5 Holkerian – Asbian

Slow uniform subsidence and eustatic sea level rise resulted in a rapid transgression causing the regional deposition of the Benbulben Shale (Philcox et al., 1992; Somerville et al., 1992). In the Late Asbian mud supply rapidly decreased resulting in the formation of a >12,000km2 regionally extensive moderately deep carbonate platform (MacDermot et al., 1996; Somerville et al., 2009). This period is represented by the deepest water levels in the basin of at least 120m (MacDermot

et al., 1996). Regional uplift of the Fintona Block subaerially exposed the Dartry Limestone in the northern part of the platform marking the end of the carbonate platform with much of it being eroded (Somerville et al., 2009).

2.5.6 Asbian – Brigantian

Following on from the Tyrone Group was the deposition of the mainly clastic Leitrim Group (Higgs, 1984). Regional regression deposited the Meeneymore Formation in a supratidal and sabkha environment sourced by erosion from the Fintona Block (Mitchell and Owens, 1990; MacDermot et al., 1996). The exhumed Dartry topography is thought to have caused a variation in thickness of the Meeneymore Formation (MacDermot et al., 1996). Across the Clogher Valley Fault the Meeneymore Formation is five times thicker indicating substantial syn- sedimentary fault tectonics (Philcox et al., 1992). Half-graben sedimentation causes the southwards prograding deltaic Glenade Sandstone thickness to change from 300m in the north to 4m in the south (MacDermot et al., 1996; Mitchell and Owens, 1990; Philcox et al., 1992).

2.5.7 Brigantian – Arnsbergian

There is little evidence for fault-controlled sedimentation during this period. The Carraun Shale was deposited in a gradually deepening sea with short-lived period shallowing up events (MacDermot et al., 1996). The Dergvone Shale marks the first deposition of Namurian sediments in a rapidly subsiding basin caused by regional thermal subsidence creating >100m of accommodation (MacDermot et al., 1996; Mitchell and Owens, 1990). Ocean chemistry oscillated during this period due to the rapid deposition of mud resulting in the formation of bands of ironstone (MacDermot et al., 1996; Frank and Tyson, 1995). The Briscloonagh Sandstone formed from a southward prograding delta mixing with turbidity currents transporting sand into the basin (MacDermot et al., 1996). The Gowlaun Shale marks a rise in relative sea level forming thick deposits of muds south of the delta complex. The deltaic Lackagh Sandstone formed from a series of shallowing upward cycles of muds and silts at the base, up to vegetated swamps at the top. The Bencroy Shale formed from rising relative sea level (MacDermot et al., 1996).

2.5.8 Maturation of NW Carboniferous Basin

The NW Carboniferous Basin is in the dry gas generation window (Rm% >1.2-3.0) (Corcoran and Clayton, 2001). Maturation evidence suggests 3-5km of post- Silesian exhumation from the NW Carboniferous Basin of Ireland (Philcox et al., 1992). Naylor, 1992 suggests exhumation of up to 4.2km of post-Silesian sedimentary cover has occurred. Maximum hydrocarbon generation was attained in the late Carboniferous, ceasing between 300-250Ma due to relatively low heat flows caused by Variscan uplift (Green et al., 2000; Philcox et al., 1992).

Philcox et al., 1992 states maturity is governed by Carboniferous burial, not Mesozoic. Whereas Corcoran and Clayton, 2001 states Mesozoic reburial provides the necessary heat flow for continuing maturation to generate a gas charge before the subsequent Late Mesozoic-Early Cenozoic exhumation (125-110Ma). Without Mesozoic burial the heat flow is insufficient to generate significant amounts of gas. This interpretation is consistent with the occurrence of gas in the Mullaghmore sandstone of the Dowra-1 well (Corcoran and Clayton, 2001). Lower reflectances occur over structural highs and vary laterally along the same stratigraphic horizons (Philcox et al., 1992). 65 million years ago the opening of the NE Atlantic Ocean formed NW-SE vertical fissures that acted as pathways for the intrusion of dolerites. These Tertiary dykes are located at the periphery of the basin to the southwest having a minor influence on thermal maturity (MacDermot et al., 1996).

2.6 Facies Descriptions of Shale Gas Formations

2.6.1 Bundoran Shale (Lower Lisgorman)

Oswald (1955) describes the Bundoran Shale as a calcareous mudstone containing thin beds of impure limestones, becoming sandier when in proximity to the Mullaghmore Sandstone (Oswald, 1955). The formation includes two basal sandstone members, the Dowra Member located in the north, and the Drumkeeran Sandstone member located in the south (George et al., 1976; Philcox et al., 1992). The formation is poorly exposed inland due to glacial deposits obscuring bedrock.

The lower 33m of the Bundoran Shale is described as calcareous grey fossiliferous mudstones containing abundant brachiopods (large pustulose productaceans,

spiriferids, orthids, and strophomenids), fennestilid bryozoans, zaphrentid corals, crinoids, echinoids and root tufts of sponges (Dixon, 1972; MacDermot et al., 1996; Avbovbo, 1973). The upper 53m has a micaceous composition with alternating dark grey shales and silts, and large amounts of crinoids and brachiopods that has been deposited in a pro-delta environment as the Mullaghmore formation developed (MacDermot et al., 1996).

Philcox (1983a) describes a 95m succession from a cored borehole named Lurganboy, located 12km SW of Kilcoo Cross-1 just north of the Ox Mountains Inlier (MacDermot et al., 1996). The lower section consists of interbedded limestones and shales with a 50:50 limestone:shale ratio, overlain by dark grey poorly fossiliferous shale containing thin laminated fine sandstone and siltstones, and capped by interbedded calcareous shale and nodular fine calcarenites (MacDermot et al., 1996). It is 185m thick at O’Donnell’s Rock consisting of a mixture of poorly fossiliferous micaceous calcareous shale, grading into platy argillaceous micrite with thin interbeds of calcareous siltstone and non-calcareous shale (MacDermot et al., 1996; Dixon, 1972). The facies changes to micritic limestone towards the southwest of the basin (Dixon, 1972).

2.6.2 Benbulben Shale (Upper Lisgorman)

The Benbulben Shale has a similar lithology to the Bundoran Shale, but more calcareous and fossiliferous containing abundant bioclastic debris consisting of crinoids, brachiopods, solitary corals and bryozoans (Dixon, 1972; Oswald, 1955). These fossils are very well preserved indicating the absence of sediment surface transportation and post-depositional reworking (Dixon, 1972). 5-10cm limestone beds account for 15% of the formation where they are more common at the top and bottom (MacDermot et al., 1996). In between is dark grey laminated calcareous shale with dark platy argillaceous micrite beds, gradually changing to medium-grey micrite with less calcareous and argillaceous shale near the top (Dixon, 1972). The upper 30m contains the highest concentration of fossils indicating a very gradual gradational contact with the overlying Glencar Limestone (Oswald, 1955). The limestone beds increase in thickness until it becomes massive dark grey limestone with thin beds of shale (Oswald, 1955).

2.6.3 Carraun Shale

This formation is made up of dark grey to black, calcareous, pyritic, highly fossiliferous shales and shaly mudstones, thinning in a southwards direction (Brandon and Hodson, 1984). The Carraun shale contains five members of varying lithologies indicating a variation in its depositional environment. At the base of the formation are numerous thin, compact and extensive micrite limestone bands that form the Derreens Limestone Member. In the middle of the formation is one stromatolitic limestone band called the Tawnyunshinagh Limestone Member (Brandon and Hodson, 1984). In the upper section of the formation there are three thin micrite beds. These are the Ardvarney Limestone Member, the Sranagross Member and the Camderry Member (Brandon and Hodson, 1984).

The 4.5-5.5m thick Derreens Limestone Member is a hard, grey, fossiliferous shale alternating between shaly mudstone, grey fossiliferous micritic mudstone, and nine limestone beds <0.3m thick that weather pyrtious (Brandon and Hodson, 1984). Shallow water benthic marine fauna dominates this member, whereas the rest of the formation comprises nektonic marine fauna of goniatites and bivalves (Brandon and Hodson, 1984). Shales between the Derreens Limestone Member and the Tawnyunshinagh are grey, highly fossiliferous calcareous shales with infrequent thin unfossiliferous limestone beds, and faunal bands of pyritised goniatites in the lower section (Brandon and Hodson, 1984).

The Tawnyunshinagh Limestone Member is up to 1.95m thick, consisting of two beds of stromatolitic micritic limestone of intertidal origin (Brandon and Hodson, 1984). Above this member the Carraun Shale is made up of roughly 20m of dark grey, fossiliferous calcareous shales. Within the shale are three thin persistent micritic dolomite and limestone beds, containing diagnostic goniatite faunas (Brandon and Hodson, 1984). The Ardvarney Limestone Member is a single 0.3m thick bed of compact, grey micrite. The Sranagross Member is a 0.15-0.61m thick shaly, dark grey dolomite/limestone (Brandon and Hodson, 1984). The Camderry Member is made up of two impure shaly, dark grey dolomite beds, separated by a 0.3-1.2m thick poorly fossiliferous grey shale bed, where the top dolomite bed is always twice as thick as the bottom dolomite bed (Brandon and Hodson, 1984; Smith 1995).

2.6.4 Dergvone Shale

This formation is comprised of four main shale facies in a rhythmical order (Brandon and Hodson, 1984; MacDermot et al., 1996):

1. Greyish black, pyritic, occasionally calcareous shale containing abundant crushed goniatites and bivalves, and forms thin marine bands. 2. Similar as type 1, but less fossiliferous. 3. Dusky blue, fissile, pyritic and unfossiliferous. Sometimes micaceous where lenticular sideritic mudstone beds and nodules occur. 4. Greyish blue, micaceous and silty shale with infrequent plant debris. Frequent thin sandstone and siderite mudstone beds, often becoming sandier passing into flaggy sandstones.

The environment of deposition is an offshore marine environment (Brandon and Hodson, 1984). Types 1 and 2 dominate the lower section of the Dergvone Shale, and types 3 and 4 dominate the upper section (Brandon and Hodson, 1984). There are five members in the Dergvone Shale Formation that consist of the Gubaveeny Shale Member, Black Mountain Shale Member, Tullyclevaun Shale Member, Tonlegee Shale Member and Killooman Shale Member (Brandon and Hodson, 1984).

The Gubaveeny Shale Member is the basal member consisting of type 1 shales 9m thick. The Black Mountain Shale Member is type 2 shale and 30-69m thick. It is very homogeneous, non-calcareous, iron stained and the lower section contains goniatites and bivalves (Brandon and Hodson, 1984; Smith, 1995). The Tullyclevaun Shale Member comprises 4.6m of type 1 shale (Brandon and Hodson, 1984). Shales between the Tullyclevaun and Tonlegee Shale Members are blue, very fissile, fine grained, and pyrite rich. The Tonlegee Shale Member is comprised of 4.9m of shale identical to the Tullyclevaun Shale Member. Shales between the Tonlegee and Killooman Shale Members consist of 4.6m of type 2 shales, overlain by fissile type 3 shales containing sideritic mudstone lenticles (Brandon and Hodson, 1984). The Killooman Shale Member is comprised of 4.4m of type 1 shale. The Dergvone Shale Formation above the Killooman Shale Member is comprised entirely of type 3 and type 4 shales, as well as thin widespread horizons of turbidite sandstones (Brandon and Hodson, 1984).

3. METHODOLOGY

3.1 Subsurface Data

3.1.1 Structure of Shale Gas Formations

A basin scale (km) lithological well correlation will be constructed in order to determine the variation in thicknesses, depths and lateral variability of the shale formations. This will be completed using data from well reports, cross-sections and geological bedrock maps from the Geological Survey of Ireland. The orientation of the correlation will be perpendicular to the NE-SW structural configuration of the basin to acquire a representative structure of the basin.

3.1.2 Geochemical Evaluation

Geochemical evaluation will consist of analysing exploration data, comprising TOC; vitrinite reflectance; rock-eval pyrolysis (Tmax, hydrogen index, oxygen index); kerogen type and Spore Colour Index data. This will enable an understanding of the geochemical variation that occurs within the formations and across the basin. The integration of this data will determine the source rock potential and help to define the sweet spots. Past exploration has focussed on acquiring data with respect to the reservoirs, resulting in an unrepresentative spread of data in the Bundoran and Benbulben Shales.

3.1.3 Contour Maps

GoldenSoftware-Surfer® will be utilised to produce contour maps illustrating the variation in the thicknesses, depths, TOC and vitrinite reflectances of the shale formations. Such maps will be overlaid to create risk segment maps to define the source presence of the Bundoran and Benbulben Shales, highlighting the areas with the highest potential. The Kriging gridding method will be used.

3.1.4 Wireline Logs

The definition of sweet spots will apply the ‘most likely’ and ‘best-case’ scenarios using different cut off values from gamma ray and resistivity well logs. In general, source rocks normally have API values of >150, however the Bundoran and Benbulben Shales exhibit low values in the region of 50-100 API. Therefore, 80 API will be used as a most probable value, and 60 API will be used as a best-case scenario. Resistivity values of 20ohm-m will be used as a cut-off value [URL 8]. Only wells F and I have both wireline log data and geochemical data, as a consequence, only these two wells can be used to integrate wireline log and geochemical analysis. The gas reading and composition of any gas shows will be obtained from well reports.

3.2 Field Work

3.2.1 Sedimentary Logging and Sample Collection

Sedimentary logging and sample collection will be undertaken in the basin to analyse mineralogical and microfacies variability of the potential shale gas formations to determine the different lithofacies. Changes in facies with regards to colour, grain size, texture, sedimentary structures, bedding nature, mineralogy, bioturbation, fossils and diagenetic features will be observed at an outcrop (m) and hand specimen (cm-mm) scale. The sampling rate is determined by how the facies visually changes in a vertical direction. The outcrop localities have been selected from previous sedimentological and palynological research, which have been performed for these regions of the basin.

3.2.2 Spectral Gamma Ray Survey

A handheld gamma ray spectrometer (RS-125 Super-SPEC) was used in the field to measure the spectral gamma radiation of the shale. It measures the elemental abundances of Th, U and K emitted from naturally occurring isotopes in the rock (Rider and Kennedy, 2011). A full technical description of the spectrometer used can be found at [URL 9]. The aim of the survey was to help characterise how the depositional environment varied through the section.

The assay mode was used to measure U, Th and K concentrations with a sampling rate of 1 minute. Before recording any sample measurements it is required to stabilise the background radiation. The standard gamma ray (SGR) is the sum of Th, U and K in API units. It is calculated by multiplying U (ppm) by 8.09, Th (ppm) by 3.93 and K (%) by 16.32 (Rider and Kennedy, 2011).

3.3 Laboratory Work

3.3.1 Thin Section Analysis

Thin sections of samples will be produced in order to optically analyse mineralogical and microfacies variability at a mm> scale that cannot be observed at outcrop. Interpretations will be combined with the fieldwork to characterise the depositional environment with respect to sediment type and input, textural variation, type of cement, pores and organic content. Nomenclature proposed by Macquaker and Adams, 2003 will be used to describe the microfacies variation.

3.3.2 Total Organic Carbon Analysis

Introduction

The TOC contents of the samples were analysed by initially removing the inorganic carbon using 6M acid (Figure 10), and subsequently analysed on a LECO (Figure 11). The LECO (TruSpec CN) is designed to analyses multiple elemental abundances operating at 850-950°C [URL 10]. The main safety hazards in the procedure are the use of 6M acid, and also from dust generated grinding the samples. To mitigate these risks rubber gloves, safety goggles and a lab coat must be worn at all times. For the whole procedure 1 litre of 6M acid was prepared by mixing 500ml of water with 500ml of 12M acid. The 12M acid had been produced 39

by sub-boiling and distillation, ensuring procedural blank contamination level would be low. Filtering under vacuum pressure was used as opposed to gravity filtration to save time and further minimise blank values.

Extraction of Organic Carbon

1. Carefully place the shale sample into a clean mortar, and using a pestle grind the sample until it becomes powder. Deposit the powder into a small re-sealable plastic bag and label it. Thoroughly wash the pestle and mortar with water before grinding a new sample. 2. Place a clean 50ml glass beaker on the balance, zero the balance, and wait until fully stable at 0.0000g. Using a spatula accurately weigh 0.2g of the powdered sample and record the mass to four decimal places. 3. In a fume cupboard pipette 10ml of 6M HCl carefully into the beaker and gently rotate the contents of the beaker. Leave for 30 minutes rotating again 30 seconds prior to completion. 4. Using the same procedure as step 3, prepare two blank samples without sediment (show sample mass of 1,000 on LECO software). 5. Attach a ceramic Buchner filter funnel onto a 250ml Buchner vacuum flask, and then using plastic tweezers place a 47mm glass fibre filter inside the filter funnel. Make sure there are no gaps between the glass fibre filter and the filter funnel. 6. During the 30 minutes reaction time, attach a vacuum filter pump to the mains tap, and then attach the other end of the vacuum pump onto the side arm of the Buchner vacuum flask. 7. At 30 minutes fill the beaker with approximately 40ml deionised water and immediately pour the contents of the beaker into the filter funnel. Thoroughly rinse the beaker with deionised water into the flask so no sediment remains. Once all of the contents have been filtered, fill the beaker with 50ml of deionised water and again pour into the filter funnel. Repeat this. Ensure no sediment is remaining on the sides of the filter funnel or beaker. 8. Carefully use a thin metal rod and tweezers to remove the filter paper and place onto tin foil. Label the tin foil and leave for 24 hours at room temperature to dry.

9. Fold the dried filter papers in half and then fold the sides into the middle. Place this on a small circular piece of LECO tin foil, and gently roll into a capsule measuring approximately 1-1.5cm in length and 3-4mm diameter. Do this on a clean sheet of paper to collect loose grains. Place in a small re- sealable plastic bag and label.

6M Acid

Filter Device Vacuum Pump

Buchner 10ml Pipette Vacuum Flask

Figure 10. Photograph of the key equipment used in this study for the extraction of organic carbon in the fume cupboard.

Analysis of Organic Carbon by LECO

1. Run 10 blanks in the LECO software to obtain baseline level. 2. Use the LECO software to check which standardised level of carbon should be used to correct the drift calibration. 3. Place a LECO tin foil on the balance and zero. Using a spatula accurately weigh out 0.1g of the standardised C standard soil selected by LECO, and then seal the contents by rolling the foil into a small tight ball. 4. Place the balls into the automated carousel and press analyse. 5. Place your TOC samples in the automated carousel and enter the original mass into the software. Make sure there are no loose edges on the samples. 6. Press analyse to start the LECO software to begin analysing. Ensure the chlorine trap is in place and the porous crucible is empty. This will need emptying after 13-14 samples. 7. The LECO will continue to automatically analyse until all samples, standards and blanks have been analysed.

LECO TruSpec CN LECO Software Automated Carousel

Figure 11. Photograph of the LECO instrumentation.

3.4 Basin Modelling

BasinMod software will be employed to produce 1D models of wells: A, B, C, F, G and I using the tectonic history of Ireland, vitrinite reflectance and Apatite Fission Track Analysis (AFTA) data. Wells D, E and H do not have any thermal maturity data to model. The models generated in this study aim to minimise the risk of potential shale gas production by addressing key issues such as burial history, thermal history, and timing of possible gas generation. Additionally, the adsorption capacity of kerogen and gas with respect to each burial and exhumation phase will be examined. Heat flow values of 80-120 mW/m2 will be applied for periods of relatively high heat flow, whereas values of 30-50 mW/m2 will be applied for periods of relatively low heat flow. It is assumed that in 1D modelling all heat flow is in a vertical direction (Hantschel and Kauerauf, 2009). The European average present day heat flow, 64 mW/m2 and present day surface temperature of 20°C for Ireland will be used (Corcoran and Clayton, 2001).

4. RESULTS

4.1 Subsurface Data

4.1.1 Structure of Shale Gas Formations

The well correlation in figure 12 illustrates the variation of the stratigraphy encountered by the exploration wells. The Tyrone Group is encountered in all the wells, while only five of the lower formations of the Leitrim Group were encountered. Both the Bundoran and Benbulben formations are laterally continuous across the basin, encompassing an area of roughly 1,200km2 in the Ballymote Syncline.

Thickness data obtained from the E–H cross section (Appendices 4-8) show both shale formations thicken in a southerly direction from Benbulben culminating under Corry Mountain and well I. The variation in thickness is greatest across intra-basinal structures, where both formations are thickest in the Drumkeeran– Slisgarrow Trough and thinnest on the Dowra–Macnean High. This is displayed well in the isopach and depth map of the Bundoran Shale where there is a sharp decrease in thickness over the Dowra–Macnean High (Figures 13 & 14). This change is less obvious in the Benbulben Shale. The average thickness of the Bundoran Shale is 468m compared to 266m of the Benbulben Shale. Both formations occur at greater depths in the Ballymote Syncline compared to the Sligo Syncline shown by the cross-section and well correlation diagrams.

Figure 12. Well correlation of the six exploration wells across the Ballymote Syncline - approximately 38km from wells A to I.

Depth Map of Bundoran Shale (Top Surface) Isopach Map of Bundoran Shale (Top Surface)

Thickness (m) Depth (m)

Northing

Northing Deeper

Thicker

m m Easting Easting

Figure 13. Isopach and depth maps of the Bundoran Shale using wells A to I. Depth and thickness have a positive correlation – deepest/thickest in the southwest in the Drumkeeran-Slisgarrow Trough and shallowest/thinnest in the east on the Dowra-Macnean High.

Depth Map of Benbulben Shale (Top Surface) Isopach Map of Bundoran Shale (Top Surface)

Thickness (m) Depth (m)

Thicker

Northing Northing

Deeper

Easting m Easting m

Figure 14. Isopach and depth maps of the Benbulben Shale using wells A to I. Depth and thickness have a negative correlation – deepest and thinnest in the southwest in the Drumkeeran-Slisgarrow.

Figure 15. Lithostratigraphic diagram of upper Leitrim Group in Thur Mountain and Lackagh Hills adjacent to Lough Allen displaying the Dergvone Shale in detail (Brandon and Hodson, 1984).

The geological outcrop map, cross-sections and well correlation diagram all agree the Leitrim group is restricted to the Ballymote Syncline, with the thickest succession occurring in the hills situated around Lough Allen (Figure 13 & 14). The Carraun and Dergvone Shales are laterally discontinuous restricted to the Lackagh Hills, Corry Mountain and Bencroy Mountain (Figure 15). Appendix 8 shows all the potential shale gas formations are at their deepest and thickest in this area. Both the Carraun (<52m) and Dergvone Shales (<170m) are thinner compared to the Bundoran and Benbulben Shales, and occur at shallower depths of <180m.

4.1.2 Geochemical Evaluation

Field Samples

The following geochemical data consists of TOC%, Tmax and hydrogen index measured using field samples collected during previous hydrocarbon exploration in the Irish and Northern Irish section of Ballymote Syncline (Tables 1-3 & Figure 16). It gives a general idea of the geochemical characteristics of the shale formations without going into too much detail. There is minimal rock-eval data in the Benbulben Shale and no data in the Bundoran Shale.

Shale TOC% of Field Samples Formation Average Minimum Maximum Dergvone 3.50 1.73 5.08 Carraun 2.04 0.23 4.45 Benbulben 0.92 0.35 1.35 Bundoran 0.94 0.42 1.24 Table 1. TOC% data of field samples ranging from 0.92% in the Benbulben Shale to 3.50% in the Dergvone Shale.

Shale Tmax (°C) of Field Samples Formation Average Minimum Maximum Dergvone 455 439 472 Carraun 453.5 449 458 Benbulben 452 452 452 Bundoran - - - Table 2. The Benbulben, Carraun and Dergvone Shales are all late mature with respect to oil generation as are between 450-460°C.

Shale Hydrogen Index of Field Samples Formation Average Minimum Maximum Dergvone 26 16 38 Carraun 38 12 72 Benbulben 26 17 35 Bundoran - - - Table 3. The shale formations are all gas prone indicated by the data being below 200.

Figure 16. Map of the total radioactivity from GSNI’s 2005 Tellus airborne geophysical Figure C4 survey Radioactivity of Northern (Total Count) Ireland. fromThe GSNI’s red zones Tellus reveal airborne relatively geophysical high radioactivity, survey green of reveals 2005. Red relatively areas medium indicate relatively radioactivity, high rad blue ioactivityreveals and low blue radioactivity, pareasurple relativelyreveals water and the red dots low. Low to moderate revealslevels of locations of exploration radioactivity characterise wells. The Bundoran Shale (outcrop location shown by red outline)the Bundoran Shale, outlined in red. (Purple areas indicate is characterised water)

by low to medium levels of radioactivity [URL 14].

Well Data

Wells B and G (Figure 17 & 18) are the principal wells with respect to assessing the gross TOC% variation as they contain the highest density of data (See Appendices 9-12 for wells A, C, F and I). The thermal maturity is considerably higher in well G and I compared to wells A, B, C and F. The Bundoran Shale is in the dry gas window in wells G and I, whereas in the other wells it is in the wet gas window. The Benbulben Shale is in the wet/dry gas window in wells G and I, whereas in the other wells it is in the late mature/wet gas window. Compositional analysis of the gas shows in the Mullaghmore Sandstone (1237-1243m) from well G indicate the gas is dry, containing >92% methane and minor amounts of C2< hydrocarbons (See Appendices 13 & 14).

Figure 17. Summary of geochemical data from well B displaying the stratigraphy, TOC%, vitrinite reflectance, spore colour index, hydrogen index and kerogen composition.

Wells B and G both agree the highest TOC% zone in the Bundoran Shale is in the mid to upper 60% of the formation. The TOC% does not increase above 1.0% in either well averaging a high of 0.8-0.95%. The Benbulben Shale’s highest TOC% zone (2.5%) is in the basal section of well B, correlating with the only sapropel (Type II) kerogen rich zone found in both shale formations, apart from the trace amounts found throughout. The Benbulben Shale averages similar TOC% values with the Bundoran Shale of 0.9%.

Figure 18. Summary of geochemical data from well G showing the stratigraphy, TOC% and vitrinite reflectance.

TOC% Variation Map: Bundoran Shale

TOC%

Increasing

Northing

Increasing

m Easting

Figure 19. Average TOC% maps of the TOC% Variation Map: Benbulben Shale Bundoran and Benbulben Shales constrained using well data. Both maps have a lot of uncertainty as only two of the wells (B & G) contain enough data to interpret the TOC% variation with a TOC% high level of confidence. However, what is certain is the relatively low TOC% encountered in both formations across the basin. No data in well I for Northing Benbulben Shale.

Increasing

Easting m

Vitrinite Re!ectance (%): Bundoran Shale

Vitrinite Re!ectance (%)

Northing

Increasing

Easting Vitrinite Re!ectance (%): Benbulben Shale

Vitrinite Re!ectance (%)

Northing

Increasing

Easting Figure 20. Vitrinite reflectance (%) maps of the Bundoran and Benbulben Shales using well data. Maturity increases in southerly direction in both formations. 51

4.1.3 Wireline Log Analysis: Sweet Spots

Gamma ray and resistivity logs have been integrated with well geochemical data to delineate the richest organic zones in the Bundoran Shale (Table 4). Most-likely gamma ray values of 100 API were used to delineate organic rich zones. However, the Bundoran Shale is characterised by low API values of 60-100, rarely exceeding 80. The Bundoran Shale has consistently higher API values than the Benbulben Shale, and its highest API values are in the middle 50-60% of the formation, but this is normally only by 10-20 API for discrete periods. Resistivity data was regularly between 15-20, only exceeding 20 when in proximity to the gas filled Dowra, Drumkeeran and Mullaghmore Sandstones.

Well Summary of Sweet Spots: Bundoran Shale Depth (m) Thickness (m) D 1029-1177 148 E 823-945 122 F 695-796 101 G 1067-1158 91 I 1264-1419 155 Table 4. ‘Sweet spots’ mapped in the Bundoran Shale using gamma ray and resistivity data - See appendices 15-19 for wireline logs.

4.2 Field & Laboratory Work

Key Outcrop Localities Bundoran Dergvone & Dergvone (a, b, c) Gowlaun Shales Carraun Benbulben Carraun Shale E Bundoran A N Bundoran & Benbulben Shales C B Pre-Carboniferous Inliers Benbulben Truskmore F Belmore Cross-section D Mountain line Crockauns Thur Atlantic Mountain Mountain Ocean E Exploration O’Donnell’s F Well Rock Sligo Lackagh Hills G

(a) H Cuilcagh (c) G Ox Mountains (b) Inlier Lough I Corry Allen Bencroy Mountain C

Bricklieve Curlew Mountains Mountains Inlier H Leitrim Curlew D 15km Mountain Figure 21. Simplified outcrop map of the Sligo and Ballymote Synclines showing the localities of the six outcrops studied (Adapted from MacDermot et al., 1996).

4.2.1 Bundoran Shale

Location of outcrop studied

The type section is just south of Aughrus Point at Bundoran where the lower 33m of the Bundoran Shale is well exposed along the coast (Figure 22) (Avbovbo, 1973; MacDermot et al., 1996). There is roughly a 4m break in the succession caused by a sea wall in the middle of Bundoran Beach.

0 ft 1000 Ballyshannon Limestone N 0 m 200

Sea Eastern Wall Section Western Section Figure 22. Satellite image showing location of the Bundoran Shale type section with reference to Bundoran town (A) {URL 11]. 53

Description of fieldwork

Overall the lower 30.45m consist of grey to dark grey, silt grained, calcareous, brittle to friable, fossiliferous and highly bioturbated clay rich mudstones containing abundant crinoids, brachiopods, solitary corals and bryozoans (Figure 23). It is interbedded with well-cemented coarse silt to very fine-grained sand and fossiliferous limestone beds. Up the section there is an overall decrease in concentration and size of fossils, well-cemented beds and diagenetic nodules, as well as an increase in fissility. The total API reaches 175 between 15-20m where it is dominated by U and K, and reaches a low of 50 in the upper 5m. U, Th and K follow the same cyclical trends of increasing and decreasing every 0.5-1m. The TOC% decreases in the lower 6m, but increases in the upper 15m from 0.9% to 1.2%. There is no petroliferous smell.

Limestones Total Organic

Mud Wacke Pack Grain & Rud Bound Total API Uranium API Thorium API Potasium API

Bundoran BeachMud Sand Gravel Carbon (%) LIMESTONES Scale (m) Lithology mud wacke pack grain rud & bound mud wacke pack grain rud & bound Clay Silt vf f m c vc Gran Pebb Cobb Boul 0.2 0.4 0.6 0.8 1.0 1.2 1.4 50 100 150 10 20 30 40 50 60 70 80 90 10 20 30 40 50 60 70 80 90 10 20 30 40 50 60 70 80 90 Notes Facies Notes Fossils Facies Fossils

Lithology MUD SAND GRAVEL Scale (m)

Lithology MUD SAND GRAVEL Scale (m) Bioturbation Bioturbation

vf m vc

clay silt gran pebb cobb boul 1 clay silt ff c gran pebb cobb boul 1

2.2m of dark grey, fissilefissile shales with no prominent largelarge body fossils.fossils. Contains At no point was pyrite observed. 30 imprintsAtimprintsno pointof brachipodswas pyrite observed.and crinoids, and well cemented horizons increasingincreasing inin 30 thicknessthickness up thethe package. Similar shale as below but lessless fossilsfossils and slightly darker. 28.5m= Similar toto thethe faciesfacies below however itit isis more fossiliferousfossiliferous containing small mm/cm scale fragmentedfragmented crinoids and brachipods. On thisthis side of thethe beach 29 compared toto thethe main part of Bundoran Beach thethe tectonictectonic fracturesfractures are not as 29 consistent. Where locatedlocated theythey have a 160-180 degree strike. ItIt isis very obvious thatthat fromfrom after thethe 5.3m package thethe concentration and size of fossilsfossils and well cemented InIn thethe lowerlower section at around 26m therethere isis evidence of corals inin a lifelife assemblage inin beds decreases. thethe upper 1m of thisthis 5.3m package. Corals are on average 12cm long/5cmlong/5cm wide, and 2828 brachipods are 5-8cm long/3-5cmlong/3-5cm wide. Weathering appears very blocky with minor amounts of fissility.fissility. [Sample[Sample B13 takentaken 30cm fromfrom thethe top].top].

2727

2626 Lower contact (wavy(wavy line)line) representedrepresented by laterallylaterally continuous 2-3cm thickthick weathered Evidence of corals and brachipods inin a lifelife assemblage inin thethe upper 1m of thisthis 5.3m out hollow. [Sample[Sample B14 takentaken 30cm up fromfrom thethe lowerlower contact]. package. Corals are on average 12cm long/5cmlong/5cm wide, and brachipods are 5-8cm 25 2525 long/3-5cmlong/3-5cm wide. Weathering appears very blocky with minor amounts of fissility.fissility. [Sample[Sample B13 takentaken 30cm fromfrom thethe top].top].

24 24 Evidence of remnantremnant wavy laminationslaminations thatthat are laterallylaterally discontinuous over short distances of 5-10cm. Appearance of cm scale brachipods and solitary corals inin upper 2m. Numerous episodes[Sample B12of highlytakenconcentratedat 23.3m]. fossilfossil richrich horizons spread 5-20cm apart consisting 23 [Sample B12 taken at 23.3m]. 23 of crinoids, brachipods and corals. Fossil richrich beds are mm toto 5cm thickthick but on avarage 1-2cm thick.thick.

2222

21 21 At a large-scalelarge-scale perspective thisthis 5.3m package has similar featuresfeatures of very dark grey, fissilefissile toto platy bedding, and similar sized and spaced well cemented beds throughout.throughout. [Sample[Sample B11 takentaken 20cm up]. 5.3m package fromfrom 20.30m toto 25.60m. Small well Compared toto previous faciesfacies thisthis faciesfacies isis darker grey, appears more fissile,fissile, lessless preservedLower contactcrinoidsmarkedup totoby3mmlaterallywide.continuous 2-3cm thick weathered out hollow. Lowerfossiliferousfossiliferouscontactandmarkeddominatedby laterallyby crinoidscontinuousinin thethe2-3cmlowerlower 3-4mthick ofweatheredthethe package.out hollow. 20 2020 Main heterogeneities are well cemented beds thatthat become thickerthicker up thethe unit and possibleProminentsmallnodular5cmhorizonsfiningfining upirregularlyirregularlycycles as darkerspaced,and2-5cmweathersthickthickoutandmore5-7cmeasilylong.long.close toto thethe well cemented beds. Overall dark grey colour inin shale intervalsintervals with a speckled appearance on thethe freshfresh 1919 surface, while well cemented beds have a lighterlighter grey colour.

1818 Fragmented well preserved crinoids on bedding surface 5-6cm longlong and 1cm wide locatedlocated consistently throughthrough unit. Many cm scale horizontal burrows surrounding 17 fossil.Upperfossil. ReactscontactwitherodedHCl=calcareousaway leavingcomposition.2-3cm thick Fromlaterally17.15mcontinuoustoto 20.30mhollow.isis [B10].[B10].Fines up DarkUppergreycontactlaminatedlaminatederodedwellawaycementedleaving 2-3cmshales. thick laterally continuous hollow. Fines up 17 overInterbeddedInterbedded10cm totowithdarker1-2cmgrey/blackthickthick wellclayscementedbefore erodedhorizonshorizonslightly coarser thanthan fissilefissile shale. Prominent and weather differently toto shale. No major body fossils.fossils. 1616 Fissile, no obvious fossils,fossils, similar faciesfacies toto [B9].[B9]. Similar faciesfacies toto [B9].[B9]. Very dark grey, contains many well cemented beds, at cm scale 1cmbreakswideintointoandsheets,5-7cmbutlonglongat mmverticalscaletubetubeappearsshapes.homogenousLocated betweendue toto absencecoarse andof wellfinerfiner Wellpreservedgradecementedbeds.laminations.laminations.silty fissile/platyfissile/platy unit. No largelarge prominent fossils,fossils, however therethere are 15 grade beds. small mm-cm scale fragmentedfragmented fossilsfossils (crinoids,(crinoids, brachipods). Although itit breaks intointo 15 So farfar all beds reactreact toto HCl indicatingindicating a calcareous composition. Prominent 3cm thickthick sheets, at a mm scale laminationslaminations are not very evident with a near homogeneous bulbous nodular horizons concentrated inin upper section. There are fewfew 1-2cm darker internalinternal structure. grey/black horizons thinningthinning out over a m scale and scattered inin different places, no 1414 systematic pattern toto them.them. [B9].[B9].

1313

1212

1111

Dark grey at base becoming lighterlighter coloured up thethe unit, platy toto fissilefissile but mostly 10 There isis a change toto crinoids dominating thisthis unit. 0.5/1cm long/wide,long/wide, sparesly appearsB8 Middlehomogenousand Upper arebasedfromfromontwotwothetheparasequenceway itit fracturesfracturesunits.[B8[B8 Upper]. 10 concentrated and foundfound inin 1-2cm thickthick horizons.

Upper contact marks an increaseincrease inin concentration of well cemented coraser grained Dark grey toto black, fissile,fissile, overall coarsening upwards fromfrom thethe base. Contains 9 beds thatthat have a constant thicknessthickness of 2-3cm. 9 laterallylaterally continuous irregularlyirregularly spaced nodules along a horizon thatthat are hard and 9 The twotwo well cemented beds ate 8.6m and 9m are extremely fossiliferousfossiliferous consisting protruding fromfrom thethe exposure. First appearance of shard likelike weathering. mm-cm of small cm scale crinoids, brachipods and corals. scaleWell cementedimpressionsimpressionshorizonof brachipods. [B8[B8 Middle at 9m]. Well cemented horizon Wavy contact representsrepresents a laterallylaterally continuous 2-3cm thickthick weathered out horizon. 8 8 Darker grey/black justjust above thisthis contact, becoming slightly lighterlighter grey up thethe unit Sample. [B8[B8 Lower]. LowerOverallcontactthinningisis ofweatheredsilty bedsoutand(represented(representedhigher concentrationby wavy line),line),of claylaterallylaterallyrich bedscontinuous,up the ClayOverallrichrichthinningbeds lesslessof fossiliferoussiltyfossiliferousbeds andbuthighercontainconcentration1-2cm sizedof solitaryclay richcorals,beds upcrinoidsthe and 7 Clay2-3cmpackagerichrichthickthickfrombedshollow.6.95mare darktogrey/black7.40m. whereas thethe silty beds are dark grey inin colour [B7].[B7]. 7 brachipods.package from 6.95m to 7.40m. 7 SimilarBlack, fissile,fissile,faciesfaciesclaytoto [B6a][B6a]richrichbutwithhasmmthickerthickerscale finingfragmentsfiningfragmentsup bedsof brachipodscontainingandsolitarycoralscorals,[B6.5].[B6.5]. brachipods and crinoids [B6b].[B6b]. Small-scaleMud richrich bedfiningfiningwhereuperodessequencesin,in, softerof harder,and nocoarser,major bodymorefossils.fossils.prominent highly fossiliferousVeryClayfossiliferousrichrichsimilarhorizoncharacteristicsbedserodesup toto moreinwardsinwardstoto erodedB4. However,wheremudveryrichrichthisthismuddybeds.isis thethe[B6a].[B6a].1-2cmmost fossiliferousfossiliferoussized corals,unitbrachipodsso farfar 6 6 andcontainingsolitaryverycoralswell[B6a[B6apreservedtakentaken fromfromsolitarylowerlowercorals,muddybrachipodssection]. and crinoids 1cm by 3-4cm inin size. Well cemented as very hard when struck with hammer. Laminations on freshfresh surface and appears homogenised inin places. Contains twotwo laterallylaterally continuous horizons of diagenetic nodules draped over by bedding (one(one horizon very prominent 5 5 locatedlocated 20cm fromfrom top).top). These are 3-4cm thickthick by 5-7cm long.long. So farfar all thethe units 5 formform effervescence on contact with HCl, thereforetherefore itit isis calcareous. Cross-cutting sub-vertical planar parallel fracturesfractures are present throughout,throughout, however theirtheir concentration varies between different localitieslocalities on thethe outcrop ratherrather thanthan varying inin 4 4 different facies.facies. Average strikes are 276 degrees and 183 degrees. Filled with quartz 4 veins inin places. [B5].[B5].

WellDarkcementedgrey to black,bed,fissile,lightlight greyprotrudingtoto grey inwellin colour.preserved 1cm wide crinoids and 1-2cm 3 Dark grey to black, fissile, protruding well preserved 1cm wide crinoids and 1-2cm 3 wide brachipods, mm scale solitary corals, no pyrite seen so far.far. As itit finesfines upwards thethe concentration and thicknessthickness of thethe well cemented beds decreases. [B4].[B4]. VeryWell cementeddark grey,bedmm[B3.5].[B3.5].scale brachipod fragments,fragments, speckled appearance & easily breaks DarkNoin sheetsfossils,fossils,grey,onlittlehomogeneouslittlecmfissility,fissility,scale [B3].nointernalinternallaminationslaminationsstructurepreserved.& well cementedVery fossiliferousfossiliferous[B[B 2.5]. containing many 2 in sheets on cm scale [B3]. 2 flattenedflattened fossils:fossils: crinoids, brachipods and corals. Fossils are well distributed throughoutDarkthroughoutgrey, speckledthisthis unit.appearanceBreaks intointoonnon-fissilefreshfresh surface,fragments,fragments,appearsmatrixfissilefissileappearstoto platyhomogenous.but no Nodulesprimary laminationslaminationslocatedlocated alongpreserved.a horizonNot25cmveryup,fossiliferous-smallfossiliferous-smallprominent 3-4cm0.5/1cmwide andsized6-7cm long,long, resistantbrachiopodsresistant toto waetheringand crinoidsandpreserved.very hardTherewhenisisstrucksomewithminorhammerlaterallateralandvariationare homogenousinin thethe 1 1 internally.concentrationinternally. [Sample[Sampleof fossilsfossilsB1]. along thethe same horizons over 10-20cm distance. Nodules 3-5cm inin diameter locatedlocated inin irregularirregular places. [Samples[Samples B-1 and B-1.5]. 0 Figure 23. Shows sedimentary log of the lower 30.45m of the Bundoran Shale, TOC% and spectral gamma ray. Coloured lines adjacent to the log correlate to lines in the photographs in the ensuing text.

Eastern Section Underlying the Bundoran Shale on the northern end of the beach is the Ballyshannon Limestone. It is a rhythmically bedded bioclastic limestone interbedded with siltstone, and is gradational with the overlying Bundoran Shale 54

evident by an overall upward increase in siltstone beds (Figure 24a). The contact is located in the middle of the beach covered by sand. The matrix is dominated by fragmented crinoid ossicles <1cm in diameter supported by mud, as well as crinoids of up to 1.5m in length (Figure 24b). It also contains well-preserved spiriferida brachiopods, corals and bryozoans, as well as vertical parallel pre- healed calcite filled fractures.

a b

Figure 24. a) Rhythmical cyclicity of bioclastic limestone and siltstone. b) Well preserved crinoid ossicle 1.5m in length, and evidence of the calyx preserved just above the hammer.

The lowermost 6.32m of the Bundoran Shale consist of dark grey silty shales, calcareous, micaceous, homogeneous matrix and fossiliferous mudstone (Figure 25a). Small mm sized minerals reflect light at particular angles giving the shale a speckled appearance. Found throughout are 1-3cm thick shelly lag deposits consisting mostly of fragmented crinoids (Figure 25b), as well as brachiopods and solitary corals. There are several well-cemented slightly coarser grained 2-3cm thick unfossiliferous beds that decrease in concentration up the unit. The yellow line indicates a sudden change to a cyclical package consisting of very fossiliferous mudstones interbedded with clay rich beds until 7.40m, and below the yellow line are bulbous concretions protruding from the surface located at 6.10m (Figure 25c).

a b c

Figure 25. a) Beneath the yellow line=0-6.32m. b) Displays the homogeneous nature of the matrix and an erosive surface highlighted by the pencil. c) Concretionary nodules protruding from surface.

This is followed by a 3.10m sequence of less fossiliferous mudstones containing two stacked coarsening up units above the orange and red lines in figure 26a. They are darker grey at the base becoming slightly lighter up the units, with an increase 55

in the concentration of coarse silt/fine grained sand well cemented beds. The orange line located at 7.83m marks a 1-2cm thick laterally continuous weathered out horizon (Figure 26a). The outcrop contains vertical parallel fractures filled with precipitated calcite (Figure 26b). The concentration of the fractures varies between different locations highlighted in figure 26a, as this shows the package above the red line having more fractures compared to the packages below.

a b

Figure 26. a) Above the orange and red lines are two parasequences. The orange line displays a good example of the laterally continuous weathered out horizons. b) Two dominant orientations of vertical parallel fractures occur (183-276) (Appendix 20) (Equivalent stratigraphy to section just below orange line in 26a).

Western Section

14.5m to 17.15m consists of dark grey, silty, homogeneous, calcareous mudstone containing sparsely concentrated mm-cm scale fragmented brachiopods and crinoids, and 5-7cm long and 1cm wide vertical burrows (Figure 27). The upper contact is marked by a 1-2cm laterally continuous weathered out horizon. Contains bulbous nodular concretions along a horizon located in the upper 2.65m.

a b

Figure 27. a) The lowermost exposed section in the western section. Yellow line = 17.5m, marking a laterally continuous 1-2cm thick weathered out horizon. b) 7- 10mm thick and 5-7cm long vertical burrow.

17.15m to 20.3m comprises dark grey, homogeneous, speckled mudstones that contain numerous well-cemented beds increasing in thickness up to the top contact (Figure 28). The upper contact at the red line marks a 1-2cm laterally 56

continuous weathered out horizon (orange line). It has a very similar facies to the previous facies, separated by the laterally continuous weathered out horizon.

Figure 28. 17.15m to 20.3m (yellow line is 17.15m and orange line marks 20.3m).

The unit between 20.3m and 25.6m is similar to the 3.15m unit below it. The lower 3m appears to have some degree of gross fissility becoming less apparent in the top 2m. Overall it consists of dark grey, slightly fissile mudstone with sparsely concentrated well-preserved mm sized crinoids (Figure 28a & 28b). There are many well-cemented beds becoming more clustered towards the top of the unit. Small mm-cm sized brachiopods and solitary corals appear in the upper 1-2m as numerous episodes of fossil rich concentrated horizons spaced 5-20cm apart, and on average 2cm thick. The upper contact is marked by a laterally continuous weathered out horizon (red line in Figure 29a).

a b

Figure 29. a) Red line = 25.6m. Shows gross structure at the top of the succession. b) Green line = 28.60m.

The lower 50cm of the following 2.90m (25.6-28.60m) are essentially muddy limestone beds containing large well preserved of corals, crinoids, brachiopods and bryozoans (Figure 29 & 30). The corals are found as pods of 30-40cm wide circular mounds situated on average 1-3m apart. Large thick-shelled brachiopods are well preserved protruding from the beds. Fragments of bryozoans are found close to the corals and the surface is heavily bioturbated with Chondrites. For the remaining 2.40m until 28.60m it grades up into darker coloured, silty, calcareous mudstones containing well-cemented thin limestone beds.

a b c

d e f

Figure 30. a) Corals in life position (pencil 15cm long and 0.8cm wide). b) Spiriferida brachiopod (Scale = white line 10cm long). c) Chondrites. d) Bottom of surface located at 26.3m - heavily bioturbated. e) Vertical burrows in same bioturbated bed, possibly Ophiomorpha or Arenicolites. f) Flame structure (27m).

At 28.60-29.00m is a 40cm thick well-cemented limestone bed that acts as a good marker bed (green line in Figure 29b). The last 1.45m above the green line in figure 29a is the upper most exposed part of this coastline. It consists of dark grey silty shales interbedded with numerous well coarser well-cemented beds increasing in thickness upward.

Microfacies Variation

PLATE 1: Bundoran Shale

Microfacies: 1. Poorly sorted relict lamination silt bearing mudstone 2. Bioclastic silt bearing mudstone 3. Mud bearing siltstone 4. Heavily bioclastic mudstone 6 5. Homogeneous silt bearing mudstone 6. Thickly laminated muds and silts with erosive bases

4 (See log for microfacies variation)

1 6 1 2

3 4

3 1 2 1 1 5 6

Figure 31. PLATE 1: Bundoran Shale - Low power microphotographs showing the representative microfacies of all the thin-sections examined in the Bundoran Shale.

Six different microfacies have been identified based mainly on textural differences. Overall the composition is calcareous and argillaceous, containing 5-60% sub- rounded to sub-angular quartz, supported by a light to dark brown clay rich matrix. Quartz identified by grey to white interference colours, undulose extinction and lack of cleavage. Contains variable sized calcitic bioclastic fragments and evidence of bioturbation throughout. Relict laminations are defined by grain size 59

and colour, often associated with small-scale mm-cm fining up sequences. Magnification of x10 indicates strongly aligned muscovite micas in all the slides, displaying bright interference colours and a needle like habit. There is no visible porosity in any of the slides and are all moderate to poorly sorted. This is due to all the slides containing calcite cement in varying amounts (<30%), revealing high relief, grey colour in PPL (Plane Polarized Light) and pale pink and green interference colours.

1. Poorly sorted relict lamination silt bearing mudstone Poorly sorted, clay rich, relict laminated containing sub-rounded quartz silt grains making up 10% of the composition. Evidence of fining up, homogenised areas and infilled burrows. Contains very small angular shell fragments and coarse glauconite rounded brown/green grains that have moderate birefringence.

2. Bioclastic silt bearing mudstone Similar microfacies as number 1. Contains bioclastic fragments of bivalves and crinoids making up 5-10% of the matrix. These are commonly concentrated along particular horizons, as well being scattered throughout.

3. Mud bearing siltstone This microfacies is representative of the coarse silt beds found throughout the succession. Dominated by sub-angular to sub-rounded quartz making up 60% of the composition supported by fine-grained clays with infrequent brown/orange lithic fragments.

4. Heavily bioclastic mudstone This microfacies was only encountered in the upper 5m and is made up of 50% bioclasts comprised of bivalves, crinoids and corals supported by a dark coloured clay and organic matter rich matrix.

5. Homogeneous bioturbated silt bearing mudstone Homogeneous fine-grained quartz supported by a light brown coloured matrix with some minor amounts of isotropic material.

6. Thickly laminated muds and silts with erosive bases Quartz rich bed cutting down into the underlying mudstone that has a similar facies as microfacies 3.

4.2.2 Benbulben Shale

‘‘Blue Rock’’

Location of outcrop studied

This first outcrop, of two, has not been cited in the literature, however to the locals it is known as ‘‘Blue Rock’’ (Figure 32) (GR 0536323 6026726). The steep nature of the exposure makes it impossible to conduct a sedimentary log.

Description of outcrop studied

This section of the Benbulben Shale is dominated by dark grey, argillaceous, calcareous, silty, fossiliferous mudstone 30m interbedded with thin 5-20cm grey crystalline blocky limestone beds that become more concentrated higher up the succession (Figure 33a). The Figure 32. Location of outcrop studied – mudstone has a speckled appearance Yellow line marks gradational contact with overlying Glencar Limestone. caused by mm scale minerals appearing silvery as they reflect light. It is concentrated with bioclastic material consisting mostly of crinoid stems, bryozoans and brachiopods that are irregularly distributed throughout, while the limestone beds contain large well-preserved corals. When struck with a hammer the fresh surface of the shale is firm while the limestone beds are firm-hard fracturing in a conchoidal manner, while the concretionary nodules 2-3cm in diameter are very hard. 10cm further in where the shale is fresher, it is less friable, darker grey and slightly more fissile. There is no petroliferous smell (Figure 33b).

a b

Figure 33. a) Large-scale structure of the outcrop showing shale interbedded with limestone beds. b) Close up of shale at the base of the exposure. 61

‘‘Tievebaun Mountain’’

Location of outcrop studied

The second outcrop is located close to the Tievebaun Stream (which has a complete Limestone 99m section) located on the upper slopes of Tievebaun Mountain (GR 17680 35090) Mudstone (Figure 34) (MacDermot et al., 1996). Accessibility on this stream is very Figure 34. Red box shows the study area. dangerous due to the bedrock of the steep slope being wet and covered in moss causing it to be extremely slippery. The shallow dip and steep nature of the cliff face meant a 30m section was graphically logged, while the base of it was sampled.

Description of outcrop studied

This consists of a 25m section located in the upper Benbulben Shale (Figure 34). It contains 5-60cm thick well-cemented crystalline limestone beds that become thicker and more concentrated closer to the overlying Glencar Limestone contact

(Figure 35). The API rarely exceeds Graphic Log of Upper Section of Benbulben Shale 75, with an even spread of U, Th and K NW SE (Figure 36). Limestone beds are more concentrated here compared to the ‘‘Blue Rock’’ outcrop, and the mudstone is lighter grey, more Shale decreases upwards calcareous, clay rich and more Limestone increases upwards fossiliferous containing bioclastic debris consisting of crinoids, brachiopods, solitary corals and bryozoans (Figures 37a-c). The Spectral gamma-ray mudstone is more blocky and 4 section (6m) 4 4 3 homogeneous, however there is some 2 2 5m 3 degree of gross fissility, and it 2 Numbers correlate to 1 weathers more easily indicated by micro-facies being more friable. There is no Figure 35. A graphic log showing the gross structure of the 25m section. petroliferous smell.

Total Organic Total API Uranium API Thorium API Potasium API Carbon (%) Scale (m) 0.2 0.4 0.6 0.8 1.0 1.2 1.4 25 50 75 10 20 30 40 50 60 70 80 90 10 20 30 40 50 60 70 80 90 10 20 30 40 50 60 70 80 90

6.0

5.5

5.0

4.5

4.0

3.5

3.0

2.5

2.0

1.5

1.0

0.5

0 Figure 36. Spectral gamma ray and TOC% data of the lower 6m of the Benbulben ‘‘Tievebaun Mountain’’ outcrop.

a b c

Figure 37. a) 25m section from figure 35. b) Close up of thick 70cm siltstone beds at base of outcrop. c) Solitary coral.

Compared to the Bundoran Shale it is a lot more calcareous, argillaceous and fossiliferous containing fewer crinoids and more corals. The corals are very well preserved protruding from the surface, often found concentrated along the same beds.

Microfacies Variation PLATE 2: Benbulben Shale - Tievebaun Mountain Microfacies: 1. Bioclastic argillaceous silt bearing mudstone 2. Limestone with shelly bioclastic fragments 3. Bioclastic argillcaeous cement bearing mudstone 4. Bioclastic argillcaeous organic rich mudstone

1 2

3 4

Figure 38. PLATE 2: Benbulben Shale – Tievebaun Mountain - Low power microphotographs showing the four microfacies representative of all the thin-sections examined from this outcrop.

The main differences in microfacies 1, 2 and 3 are the varying amounts of bioclastic fragments, silt grade quartz, calcite bearing cement and the colour of the clay rich matrix (Figure 38). No visible porosity was observed, however rare microfractures are encountered and are normally infilled with calcite. The overall calcareous and argillaceous composition is similar to the Bundoran Shale, however there is considerably higher proportion of fossiliferous and calcitic material. The upper section of the spectral gamma ray section has the highest percentage of organic matter indicated by the darker brown matrix. Facies 1, 3 and 4 are very similar to the microfacies of the Bundoran Shale, with the main difference being a greater concentration of bioclastic material in the Benbulben Shale. 64

4.2.3 Carraun Shale

Location of outcrop studied

A complete 56m section is exposed in the stream between the townlands of Carraun and Lugasnaghta on the northern flank of Dough Mountain (Figure 39) (GR 19550 34305) (Smith, 1995; MacDermot et al., 1996). Overall exposure is good, while accessibility along the stream is variable caused by steep banks, collapsed trees, boulders, and up to 50cm deep pools of water.

Figure 39. Shows the variable accessibility along the stream where the Carraun Shale is exposed.

Description of outcrop studied

An overall assessment along the section indicates the Carraun Shale is a dark grey/brown, clay rich, calcareous, pyritic, friable and fossiliferous mudstone (Figure 40). There is an absence of any petroliferous smell on a fresh surface. It is very soft when struck with a hammer easily crumbling into small pieces.

a b

Figure 40. a) Shows the well-exposed bedrock stream. b) Shows the hammer stuck in the rock due to the softness caused by the argillaceous composition.

A 4.98m thick composite log was carried out in the lower part of the section that can be divided into two main facies (Figure 41). The lower 1.68m consists of dark grey mudstones interbedded with well-cemented very coarse siltstones beds. The siltstone beds decrease in thickness over 1.5m until the shale fines upwards over 8cm to coarse clays. It appears homogeneous with little evidence of laminations and a very minor speckled appearance on a fresh surface.

The upper 3.3m consists of very dark grey fossiliferous mudstones containing well- preserved casts of gastropods, brachiopods, ammonites and vertical burrows at a mm/cm scale. There is evidence of mm scale laminations that are more preserved compared to the lower facies, and there are no well-cemented beds present. There is a sparsely concentrated concretionary horizon 30cm up the facies containing hard dense concretions 5-10cm long and 3-5cm high. The TOC% is variable on a small-scale of 1.5m ranging between 0.5-1.3%. Untitled LIMESTONES

mud wacke Limestonespack grain rud & bound Total Organic MUD SAND GRAVEL NOTES Mud Wacke Pack Grain & Rud Bound

SCALE (m) Total API Uranium API Thorium API Potasium API LITHOLOGY Mud Sand Gravel Carbon (%) Scale (m) Lithology vf m vc STRUCTURES / FOSSILS Clay Silt vf f m c vc Gran Pebb Cobb Boul clay silt f c gran pebb cobb boul 0.2 0.4 0.6 0.8 1.0 1.2 1.4 50 100 25 50 75 25 50 75 25 50 75

4.5

3.5

2.5

1.5

0.5 Coarser bed

0 Figure 41. Sedimentary log, spectral gamma ray and TOC% data of the lower 5m of the Carraun Shale outcrop.

Total API does not exceed 125 and is determined mostly by Th with approximately even contributions of U and K. The bedding consists of shallow 5-10° dipping

synclines and anticlines, with the river cutting through the axial plane and therefore flows parallel to the strike of the bedding. It contains small thrust folds that have not been encountered in any other shale formation.

Untitled Microfacies LIMESTONES Variation

mud wacke Limestonespack grain rud & bound

MUD SAND GRAVEL NOTES Mud Wacke Pack Grain & Rud Bound SCALE (m) LITHOLOGY PLATE 3: Carraun Shale Mud Sand Gravel Scale (m) Lithology vf m vc STRUCTURES / FOSSILS Clay Silt vf f m c vc Gran Pebb Cobb Boul clay silt f c gran pebb cobb boul Microfacies: 1. Thick clay rich beds and conglomerate 4.5 2. Bimodal conglomerate 3. Mud bearing siltstone 44 4. Homogeneous silt bearing claystone (See log for microfacies variation)

3.5 4

2.5

22 1 2

4 1.5

11 3

0.5 2 1 0 3 4

Figure 42. PLATE 3: Carraun Shale - Low power microphotographs showing the four microfacies representative of all the thin-sections examined in the sedimentary log.

Four different microfacies have been identified based on textural and compositional differences (Figure 42). These microfacies contain the highest proportion of clay compared to the Bundoran and Benbulben Shales. The matrix is similar throughout with the main differences caused by grain size and bioclastic material. Contains variable sized calcitic bioclastic fragments and evidence of bioturbation.

1. Thick clay rich beds and conglomerates Consists of 2mm thick parallel beds of alternating very fine-grained brown clay material that does not display any interference colours, with sub-

angular silt grade quartz grains, and very coarse silt grains that do not go into distinction in cross polar. Vertical calcite filled fractures intersects the bedding.

2. Polymodal conglomerate Similar composition to microfacies 1, however there is a greater proportion of coarser material. Thin beds occur that are concentrated with quartz. The darker coarser grains have tabular habits that are generally aligned.

3. Mud bearing siltstone The highest quartz concentrated microfacies encountered. Moderately sorted, sub-angular to sub-rounded quartz grains showing signs of laminations.

4. Homogeneous silt bearing claystone Dominated by very fine-grained clay material with minimal quartz and bioclastic fragments. Shows evidence of relict laminations in center of photo where change in colour is encountered across a horizontal line.

4.2.4 Dergvone Shale

‘’Tullyclevaun Shale’’

Location of outcrop studied

Three out of the four facies comprising the Dergvone Shale have been studied to obtain an overall understanding of the facies variation. The first outcrop is a stream section comprising the type 1 Tullyclevaun Shale Member at the first waterfall at the base of the stream (Figure 43a). Also contains shales above it that may be the type 2 Tonlegee Shale Member, or a continuation of type 1 (GR 968 282) (Brandon and Hodson, 1984).

Description of outcrop studied

The 4.6m thick type 1 member is located at the base of the waterfall in the lower section of this stream section (Brandon and Hodson, 1984). It consists of dark grey to black, fissile, hard, non-calcareous, petroliferous, pyritic, clay rich fissile

mudstone containing pyritised goniatites and vertical burrows (Figures 43a,b). It is very brittle fracturing in a conchoidal style, and has a papery fissility. It doesn’t have a clay smell, but does feel like clay when grinded between teeth. It contains mm scale pyrite framboids. Displays evidence of weathered iron and sulphur indicated by red and yellow rich fluids.

a b c

Figure 43. a) Base of waterfall where Tullyclevaun Shale is exposed. b) Pyritised burrow. c) Pyritised goniatites.

Two distinct waterfalls mark where the lithology becomes harder, the first is in figure 43a, and the second is located 10-15m upstream where it is approximately 7-8m high. The shale at the second waterfall has very similar properties as the first waterfall, Total Organic Total API Uranium API Thorium API Potasium API Carbon (%) however it is Scale (m) 1.0 2.0 3.0 4.0 100 200 300 40 80 120 160 200 240 280 40 80 120 160 200 240 280 40 80 120 160 200 240 280 softer as 3.0 when rubbed

with fingers 2.5 the clay grains easily 2.0 come off. It has a strong 1.5 petroliferous smell when 1.0 struck with a

0.5 hammer.

0 Figure 44. Sedimentary log, spectral gamma ray and TOC% data of the lower 3m of the Tullyclevaun (Dergvone) Shale outcrop. This outcrop has a very high total API of >300, mostly dominated by U, with Th dominating the lower 1m, and the U increasing in the upper 2m. High TOC% of 3.8 was encountered.

Microfacies Variation

PLATE 4: Tullyclevaun (Dergvone) Shale Microfacies: 1. Organic, clay rich mudstone 2. Bioturbated, relict lamination, clay rich mudstone

1 2

Figure 45. PLATE 4: Tullyclevaun (Dergvone) Shale - Low power microphotographs showing the two microfacies representative of all the thin-sections examined in the sedimentary log.

Two different microfacies have been identified based on textural and compositional differences (Figure 45). Both microfacies are clay rich mudstones, however microfacies 1 contains a higher proportion of organic material. The middle section of the microfacies 1 is slightly lighter compared to the upper and lower section of the image. Evidence of flattened and aligned clay rich pellets that are more concentrated in the darker areas in the upper and lower section. Microfacies 2 is bioturbated with evidence of relict lamination and clays/fine silts.

‘‘Road Section’’

Location of outcrop studied

A small road section was logged, sampled and a gamma ray survey was carried out (GR 955 317) (MacDermot et al., 1996). It consists of type 3 or 4 facies based on being topographically above the Tullyclevaun Shale.

Description of outcrop studied

This 4.25m high and 6m wide section comprises dark grey/black, clay rich, fissile, pyritous, micaceous, and homogeneous mudstone containing small cm scale imprints of brachiopods. It weathers grey and red, and contains thin well- cemented silt rich beds that have a conchoidal fracture. High TOC% of 3.7 was encountered, and the total API is less compared to the Tullyclevaun Shale with values of 100-150 varying over cycles of 0.5m. Th dominates the total API rather than U, and K also has a low contribution similar to the Tullyclevaun Shale. Untitled LIMESTONES

mud Limestoneswacke pack grain rud & bound

MUD SAND GRAVEL Total OrganicNOTES Mud Wacke Pack Grain & Rud Bound SCALE (m)

LITHOLOGY Total API Uranium API Thorium API Potasium API Mud Sand Gravel Carbon (%) Scale (m)

Lithology vf m vc STRUCTURES / FOSSILS clay silt gran pebb cobb boul Clay Silt f vf cf m c vc Gran Pebb Cobb Boul 0.5 1.0 1.5 2.0 2.5 3.0 3.5 50 100 150 20 40 60 80 100 20 40 60 80 100 20 40 60 80 100

4.5

Very dark black (darker than before), fissile, homogenous and very weathered in places. Overall very similar facies throughout the 4.25m without much variation. 44

3 3.5 2

No fissility to any of the well cemented horizons. Conchoidal fracturing throughout with some degree of fissility, small 2.5 impressions of brachipod fragments.

Coarser silty mm thick horizons lower down in this unit Well cemented prominent horizon resistant to weathering 22 1 Clay rich, very dark grey/black, fissile, 2cm wide imprints of brachipod fragments, no other signs of fossils [Db3]

1.5

Same facies as below seperated by a thin well cemented coarser bed [Db2] with no fissility to it. 0.5

Clay rich as not gritty in teeth, fissile on a mm-cm scale, very dark grey/black, 1 Fe stained red weathering, no fossils, speckled appearance, laterally discontinuous lighter and slightly siltier horizons low down in the unit [Db1]. 0

Figure 46. Sedimentary log, spectral gamma ray and TOC% data of Dergvone Shale Road Section.

Microfacies Variation

PLATE 5: Dergvone Shale - Road Section Microfacies: 1. Bioturbated, relict lamination, clay rich mudstone 2. Silt bearing mudstone 3. Thickly bedded quartz rich siltstone

1 22

Figure 47. PLATE 5: Dergvone Shale (Road Section) - Low power microphotographs showing the three microfacies representative of all the thin-sections examined in the sedimentary log.

Three different microfacies have been identified based on textural and compositional differences (Figure 47). Considering the size of the outcrop, there is relatively a lot of microfacies variation over the 4.25m. Microfacies 1 is a mixture between microfacies 1 and 2 of the Tullyclevaun Shale. Microfacies 3 was encountered above microfacies 2 on the same slide. Contains a considerable amount of quartz that increases upwards. Evidence of erosive surfaces between the quartz rich material and the mudstone.

‘‘Killooman Shale’’

Location of outcrop studied

An exposure of the Killooman Shale comprising type 1 facies located adjacent to a stream section in the Graffy River was sampled, and a spectral gamma ray survey was undertaken (GR 954 301) (Brandon and Hodson, 1984).

Description of outcrop studied The owner of the land, of which the stream flowed through, gave advice to not attempt to go in the stream as the steep slopes and fast flowing water were far too dangerous. Instead a small 2.25m exposure laterally equivalent to the top of the Killooman Shale in the stream section was sampled and measured for its gamma ray variation. Stratigraphically this outcrop is located in the middle of the Dergvone Shale (Figure 15). It comprises muds and interbedded coarse silts of a very well cemented nature. These have a sheet like architecture consisting of 60% coarse silts and 40% mudstone. The mudstone is light grey, fissile, micaceous, and the siltstone beds are quartz rich becoming thicker up the exposure. Sparsely concentrated bioclasts of brachiopods and crinoids occur in the mudstone beds. 20-25m above the Total Organic Total API Uranium API Thorium API Potasium API Carbon (%) Scale (m) stratigraphy from 0.1 0.2 0.3 0.4 0.5 0.6 0.7 50 100 10 20 30 40 50 60 70 80 90 10 20 30 40 50 60 70 80 90 10 20 30 40 50 60 70 80 90 this outcrop are 2.5 very fine-grained clean light grey 2.0 sandstone beds that are most likely 1.5 the Lacoon Flagstone Member. 1.0 The total API is between 90 and 0.5 145 API, and is dominated by Th 0 in which the U is Figure 48. Sedimentary log, spectral gamma ray and TOC% data of Dergvone Shale - Killooman Shale. relatively low, while the K gradually increases with small-scale fluctuations.

Microfacies: ‘‘Killooman Shale’’ PLATE 6: Dergvone Shale - Killooman Shale

Micro-Facies: 1.

Figure 49. PLATE 6: Killooman (Dergvone) Shale - Low power microphotographs showing the two microfacies representative of all the thin-sections examined in the sedimentary log.

One sample was obtained in the mudstone beds to reveal a very well sorted quartz dominated matrix with minor amounts of finer grained material. The quartz grains are matrix supported, and shows evidence of minor amounts of porosity.

4.3 Basin Modelling

Basin modelling results reveal the Bundoran, Benbulben, Carraun and Dergvone Shales all have moderate adsorption potentials. Two different models have been produced to account for the fragmented nature of Ireland’s onshore post-Variscan history. The first and more accurate model has been constrained by analysing the tectonic history of Ireland, denudation and AFTA data to reveal periods of burial and exhumation. A schematic heat flow model illustrating this is displayed below.

Permo-Triassic Rifting 270-210 Higher Rifting & Variscan Igneous Activity Rapid heat !ow Uplift Post-Liassic Inversion 65-60 Subsidence 310-270 Unconformity 359-310 180-100 360 Time (Ma) 300 240 180 120 60 Lower heat !ow Late Triassic Late Cretaceous Regional Sedimentation Sedimentation Cooling Event 210-190 100-70 25-15

Figure 50. ‘‘More accurate’’ schematic heat flow diagram illustrating the relative changes in heat flow caused by the tectonic events of Ireland since the beginning of basin formation in the Courceyan.

The hydrocarbons in this basin are thermogenic in origin. The more accurate schematic heat flow model (Figure 50) is based on 5km of pre-Variscan burial to justify the high palaeotemperatures attained before Variscan uplift. It accounts for Ireland remaining positive for much of the Permo-Triassic resulting in minimal onshore deposition. The basin model of well C has been used to produce a representative schematic adsorption potential model of all the wells (Figure 51). Wells A, B, C and F all have similar terminal depths and heat flow histories, whereas wells G and I have been subjected to slightly higher heat flows, in which well I has the highest terminal depth and heat flow history. Slight differences in the adsorption potential will occur based on the depths and the amount of overburden. The basin models of wells C and I are displayed; while the other modelled wells are located in appendices 21 to 24. The less accurate ‘‘Thick Permo-Triassic’’ basin model has not accounted for deep Carboniferous burial or Variscan uplift. Instead it has an extra 2km of Permo-Triassic strata encountered in well Larne-2 from the nearby offshore Ulster Basin, but has the same amount of Tertiary deposits (Figure 54). 75

Risks associated with this basin modelling includes the absence of pressure data making it difficult to accurately constrain the adsorption potential, therefore a schematic model was constructed based on the tectonic history of Ireland (Figure 51). Ireland’s complicated fragmented onshore tectonic history causes there to be many uncertainties. Therefore to determine how this may affect the generation and adsorption potential of the different shale formations, variations including no Variscan uplift and deep Permo-Triassic burial have been modelled.

Representative Schematic Adsorption Potential Model (Based on Well C) ADSORPTION POTENTIAL:

Increases with decreasing temperature Temperature (°C ) (Orange Lines) Increases with increasing pressure

) Maximum n Increases with increasing TOC% o Adsorption t / Increases with kergoen type (scf

l Deglaciation a

i & Present Day t n te

o Igneous

p Glaciation Activity n o i

t Fracturing p r

o Fracturing s Tectonic d

A Stress Maximum Burial: Purple line is adsorption potential Max. T(°C) & P

Pore Pressure (PSI) Quat. Carboniferous Permian Triassic Jurassic Cretaceous Palaeogene Neo. Minor Exhumation & Burial Phases

Key Events of Bundoran Shale 341Ma: Bundoran Deposition Mesozoic 320Ma: Gas Generation Burial 300Ma: Carboniferous Maximum Burial 200Ma: Gas Generation Variscan Uplift 210Ma: Jurassic Maximum Burial

Figure 51. Representative schematic adsorption potential mode l- focuses on Bundoran Shale.

Shale Well C Basin Model: Key Points Formation Carboniferous Burial Mesozoic Burial Initial Gas Main Gas Max. Initial Gas Main Max. Generation Generation Palaeo Generation Gas Palaeo -temp Generation -temp Benbulben 317Ma 300Ma 180°C - - 80°C Bundoran 330Ma 312Ma 200°C 210Ma 200Ma 110°C Table 5. Displays key generation and palaeotemperatures for well C basin model. 76

Basin Model: Well I

Figure 52. 1D basin model constructed for well I showing all the formations.

Shale Well I Basin Model Key Points Formation Carboniferous Burial Mesozoic Burial Initial Gas Peak Gas Max. Initial Gas Peak Gas Max. Generation Generation Palaeo Generation Generation Palaeo -temp -temp Dergvone 310Ma 300Ma 150°C - - 80°C Carraun 310Ma 300Ma 160°C - - 90°C Benbulben 325Ma 300Ma 210°C 210Ma 190Ma 100°C Bundoran 330Ma 300Ma 240°C 230Ma 190Ma 160°C Table 6. Displays key generation and palaeotemperatures for well I basin model.

Figure 53. Heat flow model correlated with vitrinite reflectance data for well I.

Thick Permo-Triassic Basin Model

Figure 54. 1D basin model constructed for well I with no thick Carboniferous deposits, no Variscan uplift and deeper Mesozoic burial.

This has resulted in a very different burial and thermal history causing different petroleum system events. Rapid Carboniferous burial initiated gas generation for the Bundoran and Benbulben Shales at around 325Ma, and then simultaneous Mesozoic burial continued this until approximately 150Ma. Maximum palaeotemperatures of 240°C in the Bundoran Shale were reached in the Late Triassic, while 210°C was subjected to the Benbulben Shale. The Carraun and Dergvone Shales have a similar burial history, however gas generation initiated at approximately 220Ma, lasting approximately until Figure 55. Heat flow model correlated with vitrinite reflectance data for ‘‘Thick Permo-Triassic’’ Model. 150Ma.

4.4 Risk Assessment

Source Presence Risk Map: Bundoran Shale A Key 350,000 N B Low Risk Depth: <700m C Thickness: >100m 345,000 TOC%: <0.7 Depth: >1000m Ro: >1.3% TOC%: >1

340,000 Medium Risk F Thickness: 40-100m Depth: 700-1000m 335,000 Ro: 1-1.3% Northing TOC%: 0.7-1.0

330,000 High Risk G Thickness: <40m Depth: <700m 325,000 Ro: <1.0% TOC%: <0.7

320,000 I 10km 190,000 195,000 200,000 205,000 Easting Figure 56. Common Risk Segment map risking the source presence of the Bundoran Shale by overlaying the previous thickness, depth, vitrinite reflectance and TOC% maps.

Source Presence Risk Map: Benbulben Shale A Key 350,000 TOC%: >1 N B Low Risk C Thickness: >100m 345,000 Depth: >1000m Ro: >1.3% TOC%: >1

340,000 Medium Risk TOC%: 0.7-1.0 F Thickness: 40-100m Depth: 700-1000m 335,000 Ro: 1-1.3% Northing TOC%: 0.7-1.0

330,000 High Risk G Thickness: <40m TOC%: <0.7 Depth: <700m 325,000 Ro: <1.0% TOC%: <0.7

320,000 I 10km 190,000 195,000 200,000 205,000 Easting

Figure 57. Common Risk Segment map risking the source presence of the Benbulben Shale by overlaying the previous thickness, depth, vitrinite reflectance and TOC% maps. 79

Radar Plot: Carraun Shale

Depth (m) KEY (Top Surface) 2000 Minimum Shale Gas Values

Carraun Shale Values

1000 Thickness (m) Tmax (°C) (Top Surface) 500 490 200 480 470 460 450 440 100 430 420 410

1.5 2.5

3 5 Ro% TOC% Figure 57. Radar plot of the Carraun Shale risking depth, thickness, TOC%, Ro% and Tmax against minimum fundamental shale gas requirements for shale gas.

Radar Plot: Dergvone Shale

Depth (m) KEY (Top Surface) 2000 Minimum Shale Gas Values

Dergvone Shale Values

1000 Thickness (m) Tmax (°C) (Top Surface) 500 490 200 480 470 460 450 440 100 430 420 410

1.5 2.5

3 5 Ro% TOC% Figure 58. Radar plot of the Dergvone Shale risking depth, thickness, TOC%, Ro% and Tmax against minimum fundamental shale gas requirements for shale gas.

5. DISCUSSION & INTERPRETATION

5.1 Bundoran Shale

5.1.1 Source Rock Potential

The Bundoran Shale has a low to moderate generating potential caused by 0.94% TOC, gas prone HI values of <30 and type III kerogen, and late mature to dry gas thermal maturities. There is encouraging shale gas potential on the edge of the basin where exploration data focuses on the highs, however there is risk associated with the central and southern areas due to a lack of data coverage. Based on a good data set in the north of the basin, the source presence risk map indicates it is high risk caused by depths of <700m. Medium risk is attributed to the central and southern portion of the basin where higher depths occur, but slightly lesser TOC% values are encountered. There is a possibility TOC% may improve in the center of the basin where the thickest and deepest succession occurs, however there is no data to prove this.

The key risk factors to its shale gas potential are its depths of 700-950m and its low to moderate generating potential. However, the high thicknesses and lateral extensiveness of the Bundoran Shale increases the volume of TOC% and hence its generating potential. Analysis of TOC% and gamma ray values suggests the middle to upper 60% of the formation is the most organic rich zone. Thickness and maturity are low risk across the basin as the minimum vitrinite reflectance encountered was 1.4%.

The Bundoran Shale is regarded as the main source rock to the basin based on its higher thermal maturity data compared to the Benbulben Shale, sourcing the excellent dry gas encountered in the overlying Mullaghmore Sandstone. This would benefit fluid flow dynamics of the methane in the matrix during fracking. However, from the shallow depths it can be assumed it is not overpressured, making fracking and turning the drillbit to horizontal more difficult. The linear profile of the vitrinite reflectance graphs indicates the heating mechanism is caused by conformable burial. Variation of vitrinite reflectance along the same stratigraphic horizon is caused by the flux of hydrothermal fluids through the coherent Caledonian fault network.

5.1.2 Hydrocarbon Generation and Expulsion History

Basin modelling shows gas generation initiated at 330Ma and ceasing during Variscan uplift, with subsequent Mesozoic burial generating gas at 210Ma and ceasing after Mesozoic uplift. Higher transformation ratios of 0.95 occur in well I due to deeper burial, and also in well G caused by the migration of superheated hydrothermal fluids through a coherent Caledonian fault network during the Variscan Orogeny. The more northerly wells have similar but lower transformation ratios of 0.8-0.85, caused by their more distal location from the Variscan Front during Carboniferous burial.

Gas shows prove the Bundoran Shale has retained a proportion of the generated gas, however it is likely much of the original gas has been expelled, evident from gas shows in the formations above and below the Bundoran Shale. Maximum burial is the time at which the highest rate of gas generation and the simultaneous fracturing of the source rock would have occurred, causing rates of desorption and expulsion to be at their highest. Subsequent uplift would have increased the adsorption potential with decreasing temperature, however there is still a large possibility much of this gas may have been expelled over the last 150Ma. The adsorption potential is decreased by the low TOC% as there is less surface area for gas molecules to attach to. But this is increased by type III kerogen having the highest sorption capacity of any kerogen types (Appendix 25). Overpressured zones are favourable to keeping the gas free in the matrix. As the Bundoran Shale is unlikely to be overpressured, it can be assumed the gas present is most likely

adsorbed which would make it more difficult to produce from. The same can be said for the Benbulben, Carraun and Dergvone Shales.

This basin has a similar basin model with the Clare Basin, however data from Doonbeg-1 shows the Clare Basin has been subjected to much higher vitrinite reflectance values of >4 Ro%. Doonbeg-1 contains no gas shows, yet the Clare Shale was an extremely high quality source rock with a high generating potential. The Clare Shale was subjected to extremely high palaeotemperatures of >200°C during Carboniferous burial caused by the proximal location to the Variscan front, superheated hydrothermal fluids and advective heating (Corcoran and Clayton, 2001). Based on inputting this into a basin model and generating a transformation ratio of >0.99, it is most probable all the kerogen would have been generated. Therefore there is a large possibility all the gas desorbed and expelled during subsequent periods of burial and uplift. It can be concluded the lesser palaeotemperatures in the Carboniferous burial, and the generation period in the Mesozoic burial, are key to the Bundoran Shale having present day adsorption potential. The same can be said for the Benbulben, Carraun and Dergvone Shales.

5.1.3 Mudstone Lithofacies

Depositional Environment

The underlying Ballyshannon limestone was deposited in a shallow marine tropical carbonate environment. Relative sea level rise occurred due to differential subsidence causing 330m uplift of the Curlew Inlier in the Arundian, sourcing mud to the gradually deepening basin allowing the regional deposition of the Bundoran Shale. The environment of deposition for the lower 30m of the Bundoran Shale is an oxic marine continental shelf in the offshore-transition zone located below the wave base. Tropical onshore rivers was the source of mud, transporting eroded material from the quartz and feldspar rich Curlew Inlier, as well as fluvial soils. Shedding from the Ballyshannon Limestone supplied carbonate material to form a mud dominated carbonate system. The high Th from the spectral gamma ray analysis indicates a high terrestrial input.

Overall it is a moderate energy system where the redox front is in the sediments. Storms were a key method for transporting sediment and bioclastic material into

the more distal areas of the basin. Aligned micas are consistently encountered in the thin sections indicating a strong current may have operated. The biotic community of fragmented calcitic crinoids, brachiopods, rugose corals and bryozoans highlights the diverse nature of the marine environment. The dominance of crinoids supports the marine shelf depositional environment hypothesis. The glauconite bearing microfacies 1 in the basal section indicates initial relatively shallow marine waters, deepening upwards as microfacies 1 phases out. Outcrop and microfacies analysis shows evidence of bioturbation and advective processes, in which organisms were responsible for the intense reworking and burrowing of the freshly deposited sediment, destroying much of the original fabrics and organic matter. The onshore tropical climate during the Carboniferous would have had high production rates of terrestrial organic matter to account for the high rates of destruction on the shelf. This goes against the common theory that you need deep anoxic basins to produce source rocks as suggested in the literature. Rapid sedimentation and Carboniferous burial would have been the major mechanism in preserving the organic matter.

The input of mud fluctuated through time causing thick muddy limestone beds to develop, often associated with bioclastic material in thin section and low total API values at outcrop. The thick limestone beds at 25-27m are found in their life assemblage indicating rapid deposition of mud to preserve them. The thick-shelled brachiopods located in the same bed may have been transported from a higher energy environment proximal to the shoreline. Flame structures in some coarse silt/fine-grained sandstone beds suggest rapid deposition caused by a fluctuating input of coarser grained material into the basin. The morphology and nature of the vertical burrows indicate they may be Ophiomorpha, inferring that relative sea level may have fluctuated to a near-shore environment through time.

The activity of normal faults is the major control for the distribution of organic matter in the basin. The Bundoran Shale is three or four times thicker in the troughs compared to the highs, therefore it can be assumed the oxygen levels at the sediment water interface would have been at their lowest in the deepest part of the Drumkeeran-Slisgarrow Trough, preserving a higher rate of the organic matter due to their being less destruction by oxidation and organisms. However, high TOC% values also occur on the Dowra-Macnean High that would have had slightly 84

shallower waters during deposition. Both wells F and I have only one data point for TOC% in the Bundoran Shale, making it difficult to fully determine the accuracy of this hypothesis. The highest TOC% zone in the middle 60% of the formation and can be interpreted to be the deepest point in time during deposition of the Bundoran Shale. There are no high TOC% events in any of the well data indicating no major high primary productivity events. Although data shows the lower section is calcareous and argillaceous rich, the Bundoran Shale gradually becomes more calcareous upwards, and then more micaceous in the upper section when in proximity to the overlying deltaic Mullaghmore Sandstone, deposited in a prodelta environment.

The laterally continuous weathered out hollows are most likely bentonites sourced from volcanic ash deposits. These form large marker beds that would be present across the entire basin. Brandon and Hodson, 1984 state there are four laterally widespread k-bentonite beds near the top of the Carraun Shale, making it more probable that these are bentonite beds in the Bundoran Shale. They are compositional zones of weaknesses causing them to erode at a faster rate than the surrounding rock. Fluids have circulated along zones of weaknesses causing carbonate fossils to re-precipitate as nodules. Calcite has precipitated into open fractures, and some fossils are silicified evident by them protruding from the bedding.

Implications for Shale Gas Potential

The lower 30m of the Bundoran Shale is high risk for shale gas production. Outcrop data reveals the friable nature of the shale, and microfacies variation shows it is heavily bioturbated, clay rich and lacks significant quantities of organic matter. The argillaceous clay rich composition is high risk for shale gas production as clays respond plastically to high pressures during fracking. There is no visible porosity due to the high clay content. Uncertainty remains regarding the type of clays present. For the Bundoran Shale to have any shale gas potential in the upper section where the high TOC% zones occur, it would have to be dominated by carbonates as carbonates respond to fracking in a similar way to silica. Although outcrop analysis has proved successful in assessing the shale gas potential in the lower section, there is no access to the mid to upper section of the Bundoran

Shale’s facies variation. However, well reports are promising as they suggest the general composition of the formation to be calcareous with impure beds of limestones.

5.2 Benbulben Shale

5.2.1 Source Rock Potential

The Benbulben Shale has a very similar source rock potential to the Bundoran Shale, however it has shallower depths, lower thermal maturities and contains notable geochemical differences. Like the Bundoran Shale it has a low to moderate generating potential caused by 0.92% TOC, gas prone HI values of <30 and type III kerogen, and late mature to dry gas thermal maturities. However, a high TOC% (2.45) and oil prone (100% sapropel) zone is encountered in the lower 91m (300ft) of the formation in well B in the northern section of the basin. Yet wells A and C, located close to well B and in the same interval, contain lower TOC% (1.0- 1.3) and type III macerals. The shale gas potential is not as encouraging as the Bundoran Shale, as it has been defined as high risk across the basin. The north of the basin has the highest risk caused by depths of 91m and vitrinite reflectance values of <1.3 Ro%. The central and southern portions of the basin are also high risk caused by the highest depths of 701m encountered in well I. Thickness and thermal maturity do not pose any risk in this section of the basin, while low TOC% does.

TOC% is highest in the northern section of the basin where values of 1-1.3% are encountered. This gradually decreases to 0.2% in well G in the south of the basin, however the absence of data in well I means there is a lot of uncertainty with respect to the TOC% distribution across the basin. TOC% recorded in wells B and G are generally around 0.9% with peaks of 1.15%, except for in the upper section where values of 0.27-0.71% are recorded, and the lower section of well B in the type II rich zone. Although this high TOC% zone in well B in the north of the basin has the highest potential, its very shallow depths of 91m mean it would be very difficult to produce from, to the point that its shale gas potential in this region is negligible. The central to southwest area of the basin has the highest source rock potential based on its depth (701m) and thicknesses (220-260m), however the low TOC% (0.20-0.70) recorded in this region is very high risk. It must be stressed 86

there is a lack of data in this central/southern region in which there is a possibility TOC% may increase in the center of the basin.

5.2.2 Hydrocarbon Generation and Expulsion History

Basin modelling shows gas generation initiated at 330Ma in the northern area of the basin, and 320Ma in the southern area of the basin, ceasing during Variscan uplift. Palaeotemperatures of 210°C were reached at maximum Carboniferous burial, while 100°C was reached at maximum Mesozoic burial. Subsequent Mesozoic burial generated gas at 210Ma in the southern area of the basin, with minimal gas generation in the northern area. Higher transformation ratios of >0.90 occur in wells G and I. The more northerly wells have similar but lower transformation ratios of 0.70-0.80, caused by their more distal location from the Variscan Front during Carboniferous burial.

Gas shows prove the Benbulben Shale has retained a proportion of the generated gas, however it is likely much of the original gas has been expelled, evident from gas shows in the formations above and below the Bundoran Shale. The adsorption potential is likely to be lower than the Bundoran Shale, caused by the combination of very shallow depths in the north of the basin, and very low TOC% values towards the south of the basin. However, in the center of the basin it is possible TOC% may increase and therefore so will the adsorption potential.

5.2.3 Mudstone Lithofacies

Depositional Environment

The Benbulben Shale is a continuation of the Bundoran Shale that has been interrupted by a delta-building episode. This is evident from outcrop and microfacies analysis revealing a very similar lithology, except the Benbulben Shale is considerably more fossiliferous and calcareous. Like the Bundoran Shale, the environment of deposition for the Benbulben Shale is an oxic marine continental shelf in the offshore-transition zone located below the wave base. Slow uniform subsidence and eustatic sea level rise initiated limestone formation at the base of the formation following the deposition of the Mullaghmore Sandstone. With increasing water depths and mud supply the regional deposition of the Benbulben Shale occurred, eventually evolving into a deep carbonate platform forming the 87

Glencar and Dartry limestones.

The ‘‘Blue Rock’’ outcrop is less fossiliferous, more fissile and darker grey compared than ‘‘Tievebaun Mountain’’ outcrop indicating a deeper period in the basin compared to the upper section. The ‘‘Tievebaun Mountain’’ outcrop formed in shallower waters compared to the ‘‘Blue Rock’’ outcrop evident by an increase in limestone beds and fossils. Sea level and the input of mud fluctuated through time to allow the development of thin limestone beds. It is evident from high Th in the spectral gamma ray logs that onshore rivers during the tropical palaeoclimate of the Lower Carboniferous supplied copious quantities of terrestrial mud. This is backed up by type III kerogen being the dominant kerogen type. The high fossiliferous content, intense bioturbation, low total API and low TOC% indicates oxygen levels were high, causing rates of destruction of organic matter to be very high. The sapropelic zone in well B in the north of the basin represents a period of high primary productivity during a period of reduced bottom water oxygen levels.

Implications for Shale Gas Potential

The lithofacies of the Benbulben Shale has higher shale gas potential than the Bundoran Shale due to the more calcareous nature of the composition. But the micrite argillaceous beds encountered in the middle of the formation lower its shale gas potential. Uncertainty remains regarding the type of clays present.

5.3 Carraun Shale

5.3.1 Source Rock Potential

Data is limited regarding the source rock potential of the Carraun Shale as it is only encountered in well I in which there is no geochemical data, except for vitrinite reflectance values of 2.1 Ro%. However, field samples data reveal an average TOC% of 2.04, Tmax of 453.5, and a HI of 38 giving it a moderate generating potential. High gas readings were recorded in the Carraun Shale proving gas has been generated, steadily decreasing from 131m down to 143m towards the base of the formation. Although its TOC% is 2.04%, over twice as much as the Bundoran Shale, it is 12 times thinner than the Bundoran Shale at 46-52m, drastically decreasing its source rock potential compared to the Bundoran Shale. This highlights the importance of thickness and how it can increases the generating potential of a source rock by simply increasing the volume of the kerogen.

As it is impossible to produce a common risk segment map of the Carraun Shale due to the lack of data coverage, a radar plot was made to compare its characteristics with the fundamental shale gas requirements mentioned in section 2.2.3. The highest risk to its shale gas potential is the shallow depths as its greatest depths occur at 250-300m in the Lackagh Hills and Thur Mountain region, and depths of 119m in well I. The Tmax is relatively quite low, however its thickness, vitrinite reflectance and TOC% are sufficient enough to give it a good generating potential. There is a lot of uncertainty regarding the distribution of its source rock potential across the basin due to the lack of data coverage. Any conclusions made using anything but data from field samples and well I would be a guess.

5.3.2 Hydrocarbon Generation and Expulsion History

Basin modelling shows gas generation initiated at 310Ma in the southern area of the basin, ceasing during Variscan uplift. Palaeotemperatures of 160°C were reached at maximum Carboniferous burial, while 90°C was reached during Mesozoic burial that would have unlikely generated large amounts of gas. Transformation ratios of >0.9 are recorded in well I. Gas shows prove the Carraun Shale has retained a proportion of the generated gas, however it is likely much of the original gas has been expelled. The adsorption potential is likely to be lower

than the Bundoran and Benbulben Shales due to the combination of very shallow depths in the north of the basin.

5.3.3 Mudstone Lithofacies

Depositional Environment

The general composition of the stream section is argillaceous and calcareous, however there are several different members comprising micrite and stromatolitic limestones indicating a variable depositional environment through time (Brandon and Hodson, 1984). Outcrop and microfacies data suggest the depositional environment was an oxic marine continental shelf in the offshore-transition zone located below the wave base. Deposition occurred in a gradually deepening see evident by the overlying Dergvone Shale forming in depths of over 100m. The diverse marine fauna and bioturbation suggest an oxic environment. It can be inferred from the thin micrite and stromatolitic limestones that short-lived shallowing up events occurred as a result of relative sea level change.

The varying amounts of pyrite and bioturbation indicate the redox front migrated through the sediment-water interface through time. This can account for the greater preservation of organic matter encountered in this formation compared to the Bundoran and Benbulben Shales. It can be inferred from the relatively low total API and high Th that organic preservation was low in the lower section of the Carraun Shale, while the input of terrestrial material was high. Encountered in the lower section of the Carraun Shale are several coarse siltstone beds, and at sub- mm scale conglomerate microfacies that suggests high-energy conditions.

Implications for Shale Gas Potential

The soft and friable clay rich composition makes this formation high risk with respect to potential shale gas formation. Uncertainty remains regarding the type of clays present.

5.4 Dergvone Shale

5.4.1 Source Rock Potential

Data is limited regarding the source rock potential of the Dergvone Shale as it is only encountered in well I. The Dergvone Shale has a high generating potential caused by 4.01% TOC, 2.12 Ro% vitrinite reflectance, gas prone HI values of 14 and type III kerogen, and late mature to dry gas thermal maturities. Field samples data reveal an average TOC% of 3.50, Tmax of 455 and HI of 26. High gas readings were recorded in the Dergvone Shale proving gas has been generated, steadily decreasing when in proximity to the Carraun Shale, indicating it has a higher generating potential than the Carraun Shale. The lowest section (Tullyclevaun Shale) of the formation has the highest source rock potential indicated by the highest total API, highest TOC% and strongest petroliferous smell compared to the other localities studied. It can be inferred water depths gradually decreased up the section as the formation evolved to the deltaic Briscloonagh Sandstone forming in a highstand systems tract. The highest source rock potential occurs in the transgressive systems tract during the deepest part of the basin. Type 1 and 2 facies have the best facies with respect to source rock potential.

As it is impossible to produce a common risk segment map of the Dergvone Shale due to the lack of data coverage, a radar plot was made to compare its characteristics with the fundamental shale gas requirements mentioned in section 2.2.3. The highest risk to its shale gas potential is the shallow depths as its greatest depths are 120-180m in the Lackagh Hills and Thur Mountain region, and depths of 0m in well I making it very high risk for potential shale gas production. The Tmax is relatively quite low, however its thickness, vitrinite reflectance and TOC% are sufficient enough to give it a good generating potential. There is a lot of uncertainty regarding the distribution of its source rock potential across the basin due to the lack of data coverage. Any conclusions made using anything but data from field samples and well I would be a guess.

5.4.2 Hydrocarbon Generation and Expulsion History

Basin modelling shows gas generation initiated at 310Ma in the southern area of the basin, ceasing during Variscan uplift. Maximum palaeotemperatures of 150°C 91

were reached at 300Ma, while 80°C was reached during Mesozoic burial that would have unlikely generated large amounts of gas. Transformation ratios of >0.9 are recorded in well I. Gas shows prove the Dergvone Shale has retained a proportion of the generated gas, however it is likely much of the original gas has been expelled. The strong petroliferous smell encountered at outcrop indicates hydrocarbons have been generated and have present day adsorption potential. The adsorption potential is likely to be lower than the other shales, caused by the combination of very shallow depths in the north of the basin.

5.4.3 Mudstone Lithofacies

Outcrop and microfacies analysis suggests the depositional environment is in a distal basinal floor. The main mechanism of sedimentation is suspension settling of mud transported into this region of the basin by storms and turbidity currents in which sedimentation rates would have been very low. Although this shale does not possess high shale gas potential based on its shallow depths, it serves as a good analogue study to the Namurian Clare, Holywell, Bowland and Barnett Shales as possess similar outcrop and microfacies characteristics.

The total API gradually decreases up the section from >300API in the Tullyclevaun Shale down to <150API in the Killooman Shale. This correlates to gradually increasing Th and decreasing U, caused by gradually decreasing water depths up the section as the formation changed to the deltaic Briscloonagh Sandstone during a highstand systems tract. Pyritised burrows and goniatites suggest the redox front would have oscillated through the sediment-water interface through time for colonisation of the sediment and pyrite to form. The water column may have been oxic, while the sediment-water interface would have had very low oxygen levels or even completely anoxic periodically through time. This is very beneficial for high rates of preservation of organic matter.

At outcrop the Tullyclevaun Shale is too fine grained to identify the mineralogy, becoming slightly coarser in the road section. Conchoidal fracture suggests a quartz rich mudstone, however there is uncertainty whether it is detrital or cement origin. Microfacies analysis shows the matrix to be concentrated with organic matter. Facies 3 and 4 become more common up the formation due to

being in proximity to the Briscloonagh Sandstone. Microfacies analysis of the Killooman Shale shows it has a layer-cake architecture of coarse silts and fine silts, while microfacies analysis displays a high percentage of detrital quartz and low TOC% of 0.55. It is likely turbidity currents had a bigger influence on the formation of the Dergvone Shale close to the deltaic Briscloonagh Sandstone, causing higher energy conditions, the supply of coarser sediment and more oxygenated waters.

Implications for Shale Gas Potential

Based on an overall high quartz content the Dergvone Shale may be more frackable than the other shale formations as these are more clay rich.

6. CONCLUSIONS

• The highest shale gas potential is in the Lackagh Hills and Thur Mountain region in the Ballymote Syncline where the thickest, deepest, and sufficiently mature formations are encountered. • There is a lack of data coverage in the Lackagh Hills and Thur Mountain area as the exploration wells have been drilled on the basin highs, causing a major uncertainty with respect to source rock potential and mudstone lithofacies variability in this region. • Shale gas potential is the most encouraging in the Bundoran Shale due to it containing excellent quality gas, occurring at the greatest depths and having the highest thermal maturities. Analysis of TOC% and gamma ray values suggests the middle to upper 60% of the formation has the highest organic rich zone. • The key risks in the Bundoran Shale are depth, TOC% and microfacies variation. • Thickness and maturity are low risk in all the formations. • The Benbulben Shale is a secondary target for potential shale gas production where deep enough as contains strong gas shows. • The Bundoran and Benbulben Shales are the most laterally extensive and deepest formations across the basin, while the Carraun and Dergvone Shales are restricted to the Ballymote Synclines situated at relatively shallow depths of <300m. • The Bundoran and Benbulben Shales can be considered as a continuation of one another, interrupted by the deltaic Mullaghmore Sandstone Formation, as share

very similar lithological and geochemical characteristics, with some notable differences. • The Bundoran and Benbulben Shales will have the highest potential where most calcareous rich. The best potential is most likely in the middle section where it is likely to be most calcareous, however it is uncertain what the true microfacies variation is. • The lower section of the Bundoran at Aughrus Point is high risk for shale gas production due to being very clay rich. • Although the Carraun and Dergvone Shales are gas bearing, they are too high risk for potential shale gas production due to their shallow depths. The argillaceous rich composition of the Carraun Shale makes it high risk. • The Dergvone Shale is as an evolution of the Carraun Shale caused by rising relative sea level, and although the Dergvone may be high risk with respect to shale gas production, it serves as a good analogue to study organic rich Namurian shales. • Basin modelling shows Carboniferous burial is responsible for the main phase of gas generation, supplemented by a secondary phase of minor gas generation during the Mesozoic burial. • Basin modelling of the Clare Shales shows Mesozoic burial is important for the moderate present day adsorption potential encountered in the basin.

7. RECOMMENDATIONS

There are uncertainties in the data coverage as the exploration wells have been drilled on the basin highs. Therefore, there is a possibility that in the Bundoran and Benbulben Shales TOC% and silica content may improve in the center of the basin. There is encouraging shale gas potential on the edge of the basin, and although the central and southern areas are more encouraging, there is risk associated due to a lack of data. The author recommends drilling a stratigraphic well in the central/southern part of the basin in the Lackagh Hills and Thur Mountain area to obtain core, and to conduct a suite of wireline log analysis, to fully assess the variation in TOC%, silica and carbonate content, as well as analysing XRD data. It would be beneficial to conduct a 3D seismic survey of the study area to assess the subsurface structure, as there are several shallow normal faults. If this is not done, there is a possibility that hydraulic fracturing could reactivate a fault like what happened with Cuadrilla Resources in Blackpool in April 2011. If this proves successful, an application can be made to drill an exploration well to perform production tests by hydraulically fracturing the shale. However, this will depend on whether Ireland removes their current moratorium on hydraulically fracturing. Northern Ireland does not have a moratorium on hydraulically fracturing, but their portion of the basin is higher risk (mainly due to lesser depths) than that of Ireland.

REFERENCES

ADAMS, A.E., MACKENZIE, W.S., & GUILFORD, C., 1994. Atlas of sedimentary rocks under the microscope. 4th ed. USA: Halsted Press. 3-31.

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104

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105

APPENDICES

Appendix 1

Sligo Syncline & O’Donnell’s Ballymote Carrick

Cuilcagh Mountains Rock Syncline Syncline

sub-stages Regional

Carraun Scarden Carraun

Shale Shale Shale Brigantian Bellavally Bellavally Bellavally Roscunnish Formation Formation Formation Shale Glenade Sandstone Glenade Sandstone Glenade Sandstone

Leitrim Group Leitrim Formation Formation Formation Meenymoore Meenymoore Meenymoore Formation Formation Formation

Dartry Limestone Dartry Limestone Asbian Asbian Formation Formation Brisklieve Cavetown Limestone Limestone Group Group Glencar Limestone Glencar Limestone Formation Formation

Lisgorman Lisgorman Benbulben

Tyrone Group Tyrone Shale Shale Shale Formation Formation Croghan Limestone

Mullaghmore Mullaghmore Mullaghmore Group Holkerian Arundian - - Arundian Sandstone Sandstone Sandstone

Lithostratigraphic diagram correlating the stratigraphy across the three sub-basins. Stratigraphic names based on Oswald (1955), Caldwell (1959), Dixon (1972), Brandon and Hodson (1984), and MacDermot et al., (1996) (Adapted from Somerville et al., 2009).

106

Appendix 2

Well Well G Well G (80’s) Well E Well B (60’s) Benbulben No gas recorded No gas recorded ? Minor shows (852-866ft) Mullaghmore Minor shows – 2386- Minor shows – 15,000cfgd Four shows (10- 2400ft 2386-2400ft (1725ft) 500 units) at 1530, (Averaged 35 units of 1796, 1842 and methane down to 1920-2015ft 4057ft) Bundoran Background Background ? ? gas reading gas reading Dowra 31,000cfgd (4050- 258,000cfgd ? <35 units in minor 4080ft) (traces of oil in (4050-4080ft) shows (3413- core analysis) 3470ft) Ballyshannon Averaged 130 units of No gas recorded ? 120 units (4013ft) methane from 4057ft <35 units (4152- down to 6005ft 4180ft) Well Macnean-2 Drumkeeran Dowra-2 Thur Mountain-1 South-1 Benbulben Gas readings fairly Background gas Gas Readings Gas ranged 0.01%- uniform throughout readings from ranged: 0.03% to 0.02% between averaging 0.1% at top – 200-8236ft 0.11% - averaged 1980-2090ft dominated by C1 0.07% Mullaghmore Fas readings ranged Highest between: 0.08% to 0.10% 440mcf/day 0.02%-0.08% averaging 200-590ft (20-25 (759-830m) 0.05%. Dominated by C1 units) Only C1 recorded Bundoran Highest gas levels And 2700-4870ft 0.04% to 0.12% Gas ranged 0.01- encountered: 0.1% to (10-25 units) 0.04%. Only C1 0.2%. Averaged 0.22% recorded. between 2230- 2400ft. .02-1.0% between 2990-3230ft. Dowra Total gas averaged ? 640mcf/day Gas ranged 0.01- 0.01% (1248-1260m) 0.05% C1. Drumkeeran N/A ? N/A N/A

Ballyshannon Gas ranged 0.05-2.0%. ? No gas recorded ?

Summary of hydrocarbon shows/flows and gas compositions encountered by exploration wells drilled in the Ballymote Syncline (Data obtained from [URL 12], MacDermot et al., 1996, Shannon and Naylor, 2010, well reports and mudloggers reports).

107

Appendix 3

Map of the British Isles illustrating the configuration of Lower Carboniferous sedimentary basins and their major basin bounding faults (Worthington and Walsh, 2011).

108

Appendix 4

Key to Cross-Sections & Bedrock Geology Map

Leitrim Group Lower Dinantian Limestones LTG Letrim Group TW Twigspark Fm.

gian BKU r LA Lackagh Sandstone Fm. Bricklieve Limestone Upper Fm.

BKL Arnsbe GO Gowlaun Shale Fm. Bricklieve Limestone Lower Fm.

LG Namurian BR Briscloonagh Sandstone Fm. Lisgorman Shale Fm.

endleian DO Dergvone Shale Fm. Greyfield Fm. P

CA Carraun Shale Fm. BK Bricklieve Limestone Fm. antian g BE Bellavally Shale Fm. CL Croghan Limestone Fm. Bri

BM GE Glenade Sandstone Fm. Ballymore Bed (Shales)

ME Meenymore Fm. OK Oakport Limestone Fm.

KB Kilbryan Limestone Fm. Asbian Tyrone Group BO Boyle Sandstone Fm.

DA Dartry Limestone Fm. Visean Devonian GC Glencar Limestone Fm. ORS Old Red Sandstone Fm.

BB Benbulben Shale Fm. KW erian Keadew Fm. k

Hol MU Mullaghmore Sandstone Fm. MO Moygara Fm.

BU Bundoran Shale Fm. BNdk Drumkeeran Sandstone Member (BN) Cambro - Ordovician DO Dowra Sandstone Member (BN) Arundian CG Cloonygowan Fm. BS Ballyshannon Limestone Fm. Dalradian or older

Chadian SW Slishwood Division

SWQ Psammitic paragneiss

Key to cross-sections and bedrock geology map (appendices 5-7) (GSI).

109

Appendix 5

Cross-section E – H (GSI).

110

Appendix 6 D Boyle BO south east KW MG Curlew Inlier Mountains

Curlew Mountains Curlew Curlew Fault Curlew BO ORS BO Ballinafad BS LG KB BKL BKU Bricklieve Mountains Syncline Ballymote Ballymote Cross-section C-D BO 5

ORS

Fault Killavil - Belhavel - Killavil km BS LG LTG BKL BKU CG BKU BS LG KB CG BO BKL (vertical scale) scale 1.67 times horizontal 0 C House Newpark north west

Cross-section C – D (GSI).

111

Appendix 7

KEY (Same Abbreviations DE: Dergvone Shale as Appendix 4) CA: Carraun Shale N BB: Benbulben Shale BN: Bundoran Shale E 1 F 2

3 G

4 5 C

13KM H

Solid bedrock geology map showing the Sligo and Ballymote synclines with the structural framework of the basin - Red line is cross section line for cross-sections in appendices 4-5. Numbers are from appendix 8 (Adapted from GSI).

Appendix 8

Shale Variation in Thickness of Shale Gas Formations (m) Formation Benbulben Leean Lackagh Hills and Corry Bencroy Mountain Mountain Thur Mountains Mountain Mountain (1) (2) (3) (4) (5) Gowlaun Absent Absent 55-60 60 64 Dergvone Absent Absent 137-170 96 85 Carraun Absent Absent 52 51 46 Benbulben 131 78 191 239 ? Bundoran 101 162 479 658 ? Shale Variation in Depths of Shale Gas Formations (m) (Top Surface) Formation Benbulben Leean Lackagh Hills and Corry Bencroy Mountain Mountain Thur Mountains Mountain Mountain (1) (2) (3) (4) (5) Gowlaun Absent Absent 60 60 ? Dergvone Absent Absent 180 120 ? Carraun Absent Absent 299 240 ? Benbulben 400 389 689 838 ? Bundoran 850 659 898 1079 ?

This shows the variation in thicknesses and depths of the shale formations across the basin in a general NW-SE direction from Benbulben to Bencroy (see cross-section line). (? = no data and (1-5) relate to location on bedrock geology map in appendix 7) (Brandon and Hodson, 1984; MacDermot et al., 1996). 112

Appendix 9

Summary of geochemical data from well A showing the stratigraphy, TOC%, vitrinite reflectance and kerogen composition analysis.

113

Appendix 10

Summary of geochemical data from well C showing the stratigraphy, TOC%, vitrinite reflectance and kerogen composition analysis.

114

Appendix 11

Summary of geochemical data from well F showing the stratigraphy, TOC%, vitrinite reflectance and hydrogen index.

115

Appendix 12

Summary of geochemical data from well I showing the stratigraphy, TOC%, vitrinite reflectance kerogen composition analysis.

116

Appendix 13

Gas Gas Sample Analysis (G: 1962) Components Sample No. 1 (Hole %) Methane 89 Ethane 4 Propane Trace Butane Trace

Hydrogen 7 B.T.U 990

Flow test results obtained from the 1962 drilling of well G showing the composition of gas obtained from the Mullaghmore Sandstone between 4058-4078ft. It can be concluded the gas is dry.

Appendix 14

Gas Gas Sample Analysis (Re-entered G: 1981) Component Sample No. 1 (Hole %) Sample No. 2 (Hole %) Methane 91.91 91.86 Ethane 0.72 0.73 Propane 0.02 0.02 Butane Trace Trace

CO2 0.23 0.24 Nitrogen 7.12 7.15

Flow test results obtained from the 1981 re-entry programme for well G showing the composition of gas obtained from two samples of the Mullaghmore Sandstone. It can be concluded the gas is dry with 7.12% of nitrogen and a specific air gravity (air = 1) of 0.589.

117

Appendix 15 Appendix 16

Well D: Bundoran Shale Well E: Bundoran Shale

Resistivity Gamma-Ray Gamma-Ray

80 API 20 ohm-m 3377ft

3400ft 0 - 160 API

80 API

2700ft 3500ft

Sweet Spot: 483ft

2800ft

3600ft

Sweet Spot 400ft Thick

2900ft

3700ft

3000ft

3800ft

3100ft

3860ft

118

Appendix 17 Appendix 18

Well F: Bundoran Shale Well G: Bundoran Shale

Resistivity 60 API Gamma Ray 2279ft 20 ohm-m 60 API 20 ohm-m 3500ft 3500ft 2300ft

3600ft 3600ft

2400ft

Sweet Spot 331ft thick

3700ft 3700ft

2500ft

3800ft 3800ft

Dowra Sst. 2600ft 2610ft No de!nite sweet spot - but lower 300ft contains highest gamma ray and resistivity values

119

Appendix 19

Well I: Bundoran Shale Appendix 20

Gamma Ray Resistivity Fracture Orientations in the Bundoran Shale in the Eastern 60 API Section 4148ft 20 ohm-m Strike Strike 280 278 184 186 272 275 172 187 277 276 179 180 4200ft 275 276 174 188 278 272 186 190

4300ft Sweet Spot: 507ft

4400ft

4500ft

4655ft

120

Appendix 21

WELL A

Burial history and heat flow model of well A.

121

Appendix 22

WELL B

Burial history and heat flow model of well B.

122

Appendix 23

WELL F

Burial history and heat flow model of well F.

123

Appendix 24

WELL G

Burial history and heat flow model of well G.

124

Appendix 25

Sorption capacities of type I, II and III kerogens [URL 13].

125