Technical support for the risk management of unconventional hydrocarbon extraction : final report.
Date: 2016-04-21
Institutions: Directorate-General for Environment
Subjects: accident prevention, energy research, energy technology, environmental protection, fossil fuel, hydraulic energy, natural gas, research and development, research report, technical cooperation

Technical Support for the Risk 
Management of Unconventional 
Hydrocarbon Extraction 

Final Report 

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ISBN 978-92-79-57947-9 
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European Commission DG Environment 

Technical Support for the Risk Management of 
Unconventional Hydrocarbon Extraction 

Final Report 

Amec Foster Wheeler Environment & Infrastructure UK Limited 

August 2015 

Disclaimer 
This Final Report has been prepared by consultants Amec Foster Wheeler 
Environment & Infrastucture UK Ltd.  The views expressed herein are those of the 
consultants alone and do not represent the official views of the Commission. 

Copyright and Non-Disclosure Notice 
The contents and layout of this report are subject to copyright owned by the European 
Commission.  

Third-Party Disclaimer  
Any disclosure of this report to a third party is subject to this disclaimer.  The report 
was prepared by Amec Foster Wheeler at the instruction of, and for use by, our client 
named on the front of the report.  It does not in any way constitute advice to any third 
party who is able to access it by any means.  Amec Foster Wheeler excludes to the 
fullest extent lawfully permitted all liability whatsoever for any loss or damage 
howsoever arising from reliance on the contents of this report.  We do not however 
exclude our liability (if any) for personal injury or death resulting from our 
negligence, for fraud or any other matter in relation to which we cannot legally 
exclude liability. 

Document Revisions ( 

No. 

Details 

Date 

01 

02 

03 

04 

05 

Interim Report 

29th April 2014 

Interim Report 

5th September 2014 

Draft Final Report 

6th February 2015 

Final Report 

Final Report 

22nd July 2015 

17th August 2015 

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Executive Summary 

Purpose of this Report 

This is the Final Report for the project ‘Technical Support for the Risk Management of Unconventional 
Hydrocarbon Extraction’, contract 070251/2014/674828/SER/ENV/F.1.  The report presents an overview of the 
main unconventional fossil fuels (UFF) other than shale gas (‘other UFF’) that require hydraulic fracturing to 
enable hydrocarbon extraction, a comparison of the risks associated with other UFF and shale gas, consideration of 
the adequacy of technical and policy measures to mitigate environmental risks that were developed in previous 
work that focussed on shale gas for the management of risks arising from extraction of other UFF, and a description 
of selected policy options available to implement such measures, should the Commission decide that further action 
at EU level is needed.  This report should be read in conjunction with the study report ‘Technical Support for 
Assessing the Need for a Risk Management Framework for Unconventional Gas Extraction’, contract 
070307/2012/630420/SER/ENV.F.11. 

Context 

In January 2014, the Commission published its Communication and Recommendation on the exploration and 
production of hydrocarbons (such as shale gas) using high volume hydraulic fracturing in the EU2.  In support of 
the Communication and Recommendation, Amec Foster Wheeler Environment & Infrastructure UK Ltd3 undertook 
the study ‘Technical support for assessing the need for a risk management framework for unconventional gas 
extraction’.  Whilst the study focussed on shale gas with consideration of the implications and scope of potential 
policy proposals, there was a need to gather information regarding other UFF. 

Shale gas is the UFF resource with the greatest potential recoverable resources in the EU; consequently work 
carried out to date in studies for the Commission has focused on shale gas.  However, development of UFF other 
than shale gas is also taking place or is planned to take place in the EU, which requires further examination.  The 
analysis in this study builds on the environmental assessment of shale gas carried out under previous work and 
widens the scope of the assessment to other UFF requiring hydraulic fracturing to initiate production (e.g. tight gas, 
tight oil, and coalbed methane (CBM)4).  Other UFF present many of the same risks as shale gas; however, there 

1 Available at http://ec.europa.eu/environment/integration/energy/unconventional_en.htm 
2 Available at http://ec.europa.eu/environment/integration/energy/unconventional_en.htm 
3 Formerly AMEC Environment & Infrastructure UK Ltd 
4 CBM is extracted from virgin coal bed seams that have not been mined in contrast to coal mine and abandoned coal mine methane.  Note that CBM may not 
require hydraulic fracturing to enable successful production.  In the course of this study CBM operations in Europe where hydraulic fracturing has been used or is 
planned has not been identified.  In Australia, where CBM resources are developed, to date less than 5% of CBM wells have been fractured, and this figure is 
unlikely to exceed 10% (New South Wales Government (2014)).  USEPA (2004) indicates that hydraulic fracturing occurs in most CBM basins studied but does not 
indicate the proportion of wells requiring fracturing. 

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are differences between shale gas and other UFF such as techniques used, potential scale, types of geology and the 
depth of the target formations. 

Objective, Scope and Boundary of the Study 

The objective of this study is to build on the study ‘Technical support for assessing the need for a risk management 
framework for unconventional gas extraction’ and to provide support for the preparation of possible Commission 
initiatives on managing risks and potential impacts of other UFF extraction in Europe.  The scope and boundary of 
the study can be summarised5 as: 

•  Categorisation of unconventional fossil fuels; 

•  Comparison of risks and impacts of other UFF with each other and with shale gas; 

•  Development of measures to address any additional risks of UFF; and 

•  Assessment of possible policy options. 

The scope of work does not include offshore UFF which is the subject of a separate Commission study. 

This study has the following limitations: 

•  It should be borne in mind that there is limited extraction of other UFF involving the use of hydraulic 
fracturing in the EU so current work has had to take into account limited existing and potential future 
developments.  The focus of the study is other UFF that uses hydraulic fracturing beyond shale gas. 

•  The focus of the study was on water-based fracturing.  Non-water-based and new technologies would 
require a separate assessment of risks and technical measures if these were to be considered as part of 
a risk management framework. 

•  The influence of fluctuations in oil and gas prices (either up or down) was not assessed in terms of the 
effect this may have on measures that may be required.  However, an indication of the likely impact of 
recent oil and gas price fluctuations is commented on. 

•  It should be noted that the cost estimates exclusively address preventive measures and do not include 

costs for remediation of accidental events. 

•  Estimates of affordability are highly dependent on a number of assumptions, including estimates of 
gas production volumes per well and assumed productive lifetime over which those volumes are 
realised, which will vary on a case by case basis. 

5 For the full scope refer to Section 1.4. 

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•  Compliance costs and affordability estimates are based on best estimates for measure costs using 

single point values for option cost calculation.  Costs may vary and there are uncertainties regarding 
costs across the large number of measures. 

Conclusions 

Differentiating Conventional Fossil Fuels and Unconventional Fossil Fuels 

A universally recognised distinction between conventional fossil fuels (CFF) and UFF is not available.  What is 
considered to be UFF may vary over time depending on various aspects (e.g. resource characteristics, technologies, 
scale, frequency and duration of production from the resource).  The term ‘unconventional’ may be used to identify 
the use of previously rarely deployed techniques; however, such techniques may also be applied to CFF resources 
and so may no longer represent ‘unconventional’ techniques over time.  An alternative definition refers to 
hydrocarbons present in the source rock in which the resource was originally formed.  Such a definition includes 
shale gas and CBM but excludes tight oil and tight gas where hydrocarbons have migrated from a source rock to a 
reservoir. 

A number of potential criteria are possible to differentiate between CFF and UFF.  Firstly, the permeability of the 
reservoir rock may be considered.  Shale gas, tight oil and tight gas are found in formations with lower 
permeability than CFF.  However, the permeability of CBM is more variable and therefore cannot be readily 
distinguished from CFF on this basis.  Secondly, the geological environment in which CFF and UFF are found may 
be used to differentiate as CFF are typically found in discrete accumulations (e.g. where a cap rock overlies and 
contains a reservoir) whereas UFF may be found in much more extensive bodies with more gradational boundaries.  
Thirdly, the techniques used to exploit CFF versus UFF and in particular the scale of drilling are different, with the 
extensive use of horizontal wells, and stimulation being required at the production stage for UFF.  Fourthly, shale 
gas, tight gas and tight oil resources may be grouped as they share characteristics including depth, scale of 
operations at a well pad, the use of multi-well pads (and associated land take) and a requirement for the use of 
hydraulic fracturing to enable production.  CBM resources form a separate group due to the shallower depth, 
reduced scale of operations, the use of hydraulic fracturing which is not always required and the smaller volume of 
fracturing fluid used for fracturing.  In addition, CBM requires groundwater pumping whereas the other forms of 
UFF do not.  Finally, whilst stimulation of reservoirs by hydraulic fracturing can be used in both CFF and UFF, 
there are differences in pressure and the volume of water used in the process. 

Categorisation Options 

Clear categorisation between CFF and UFF and also between different UFF may enable definition of those 
hydrocarbons falling under a given policy instrument.  There is no single categorisation ‘option’ that captures all 
forms of UFF whilst avoiding capturing CFF; however, potential options for categorisation (see Section 2.2.5 for 
further detail and comment on the suitability of options) could be based on the following (or combinations thereof): 

•  Permeability of the reservoir formation. 

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•  Volume of water used in hydraulic fracturing (for shale gas, tight oil and tight gas). 

•  Pressure applied during hydraulic fracturing. 

•  Depth, due to differences in risks presented by shallower operations (proximity to aquifers above 

wells) and deeper operations (greater pressures required for fracturing and the associated well integrity 
requirements). 

•  Depth for CBM, as such operations are more likely to be near aquifers used for drinking water or 

contributing to surface water flow. 

•  Volume of pumped groundwater for CBM. 

Comparison of Risks and Impacts 

Differences in the risk and impacts compared to shale gas were predominantly identified in the hydraulic 
fracturing, well completion and production stages, with CBM being more markedly different than the other UFF 
types.  For tight gas and tight oil, risks and impacts linked to water resource depletion are potentially less 
significant than for shale gas because less water is typically required for the fracturing process. 

For CBM, risks and impacts relating to traffic and air pollution during site identification and preparation, and the 
well design drilling, casing and cementing stage could potentially have lower risks due to the smaller scale and 
duration of operations and shallower well depths and distances resulting in shorter drilling times.  However, for 
CBM, the hydraulic fracturing stage risks and impacts associated with groundwater contamination are potentially 
more significant compared to shale gas due to the comparatively shallower depth of the target formation compared 
to shale gas.  CBM also requires pumping of groundwater at the production stage.  The abstraction of groundwater 
presents a risk to water resources in overlying or lateral formations where a hydrogeological connection exists.  The 
traffic burden (linked to transportation of produced water) and associated risks and impacts for CBM may 
potentially be more significant compared to shale gas. 

Additional risks identified for CBM compared to shale gas were identified including a risk of surface water 
contamination from greater quantities of actively pumped produced water at the surface which must be managed 
and treated to the standard required by permits6.  Also, risks of increased water resource depletion from 
groundwater supplies being drawn down towards the target formation and the potential for groundwater 
contamination due to the need for groundwater pumping and associated potential impacts on groundwater resources 
and quality are possible for CBM. 

6 Produced water has variable quality (e.g. USEPA (2013) and Umweltbundesamt (2013)) indicate a range from 7 to 128,000 mg/l total dissolved solids in produced 
water from CBM formations. 

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Policy Options Assessment 

The costs and benefits of four policy options were assessed.  The options were based on those set out in Section 4 
of AMEC (2014).  The four options were: 

•  Option A:  to take forward guidance and a recommendation under existing legislation, voluntary 

industry agreement and best practice; 

•  Option B:  to amend several existing EU laws and accompany this with guidance; 

•  Option C:  to adopt a new dedicated legal instrument in the form of a directive (setting overall 

goals/principles) and accompany this with guidance; and 

•  Option D:  to adopt a new dedicated legal instrument in the form of a regulation, to set specific 

detailed obligations and accompany this with guidance.  

It should be noted that since the AMEC (2014) work was undertaken, the Commission adopted Recommendation 
2014/70/EU in January 2014.  The Recommendation is one part of Option A but it is not the full Option A. 

Section 5.4 presents details of the costs of the policy options for other UFF.  Compared to the option costs for shale 
gas, annualised costs are lower for tight gas and tight oil due to the greater assumed well lifetime of 20 years 
compared to that assumed for shale gas of 10 years (for example the cost to operators of Option A7 for tight gas and 
tight oil of up to approximately €1 million per pad compared up to approximately €1.5 million per pad for shale 
gas).  For CBM, although the assumed well lifetime is seven years compared to ten for shale gas, a combination of 
fewer measures selected and a reduction of the capital cost associated with well safety due to shallower well depth 
(1,000 m vs. 3,000 m for shale gas) and well horizontal length (250 m vs. 1,350 m for shale gas) combined with 
fewer wells per pad (four per pad vs. eight per pad for shale gas) reduces costs per pad (e.g. the cost to operators of 
Option A for CBM is up to approximately €0.8 million per pad compared to up to approximately €1.5 million per 
pad for shale gas)8. 

Taking account of measures that are likely to be applied as normal practice by operators is important so as not to 
overstate potential compliance costs.  The effect of factoring uptake of measures due to the application of normal 
practice is to reduce the estimated total compliance costs from pre-adjusted estimates.  The total annualised 
compliance costs of the selected policy options per pad taking account of measures that are ‘likely’ to be applied 
and those that will ‘possibly’ be applied are presented in Section 5.4.  The impact of taking account of such 
measures is to reduce costs, e.g. for Option A approximate costs reduce for tight gas and tight oil from up to 
€1 million per pad to up to €0.4 million per pad and for CBM from up to €0.8 million per pad to up to €0.6 million 
per pad). 

7 The cost of Option A will be determined by the level of ambition adopted and hence could incur no cost for operators and authorities if a low level of ambition is 
embraced. 
8 Note that CBM well lifetimes are reported to vary significantly.  USEPA (2013) indicates 5-15 years, Amec Foster Wheeler experience in Australia indicates 2-5 
years and personal communication with European Gas Ltd (2015) has suggested 15-25 years.  Adjusting well lifetime for CBM from 7 to 15 years would result in 
total annualised compliance costs per pad of Option A of approximately up to €0.5m. 

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The estimated compliance costs as a percentage of expected revenues for tight gas are similar in magnitude to those 
calculated for shale gas.  The percentage of expected revenues for CBM and tight oil are higher than for tight gas 
and shale gas.  This is due to the assumed lifetime production volumes and associated revenues, and in addition for 
CBM, the smaller reduction in compliance costs when taking account of measures that may be applied already by 
operators (see Section 5.4.2 for further details on this point).  However, for some CBM, longer well lifetimes and 
higher gas production rates have been reported than those assumed hence compliance costs as a percentage of 
expected revenues will be lower (see Section 5.5. for further detail on this point). 

Administrative costs associated with the options for tight gas, tight oil and CBM will be analogous to those 
determined in AMEC (2014) as the general nature of the options remains consistent.   

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Contents 

1. 
1.1 
1.2 
1.3 
1.4 
1.5 
1.6 

2. 
2.1 
2.2 
2.2.1 
2.2.2 
2.2.3 
2.2.4 
2.2.5 
2.3 

3. 
3.1 
3.2 
3.2.1 
3.2.2 
3.2.3 
3.3 
3.4 
3.4.1 
3.4.2 

4. 
4.1 
4.2 
4.3 

Introduction 

Purpose of this Report 

Context 

Objective 

Scope and Boundary of the Study 

Summary of the Study Process 

Report Structure 

Categorisation of Unconventional Fossil Fuels 

Introduction 

Categorisation of CFF and UFF 

Introduction 

General Categorisation 

Geological and Spatial Categories 

Stimulation and Recovery Techniques 

Summary of Categorisation Options 

Distinguishing Exploration and Production 

Comparison of Risks and Impacts of other UFF with those of Shale Gas 

Introduction 

Approach 

Introduction 

Stage One: Screening 

Stage Two: Risk and Impacts Assessment Evaluation Stage 

Stage One: Screening 

Stage Two: Risk Assessment and Evaluation 

Tight Gas and Tight Oil 

Coalbed Methane 

Measures 

Introduction 

Development of Measures 

Review of Measures 

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1 
1 
2 
3 
4 
4 

7 
7 
7 
7 
8 
15 
17 
19 
21 

29 
29 
29 
29 
30 
31 
34 
46 
46 
47 

61 
61 
61 
64 

 
 
 
 
 
 
 
 
 
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4.3.1 
4.3.2 
4.3.3 

5. 
5.1 
5.2 
5.2.1 
5.2.2 
5.3 
5.3.1 
5.3.2 
5.3.3 
5.3.4 
5.3.5 
5.3.6 
5.4 
5.4.1 
5.4.2 
5.5 

6. 

7. 

Approach 

Outcome of the Review of Existing Measures 

Assessment of Potential Additional Measure Requirements 

Policy Options Assessment 

Introduction 

Approach 

Illustrative Concessions 

Assessment of Measure Impacts 

Selected Policy Options 

Introduction 

Policy Option A: Guidance and Recommendation 

Policy Option B: Amendment to the Acquis plus Guidance 

Policy Option C: Dedicated Directive plus Guidance 

Policy Option D: Dedicated Regulation plus Guidance 

Comparison of the Options 

Policy Option Costs 

Introduction 

Cost of Measures under Each Policy Option 

Policy Option Affordability 

Conclusions 

References 

64 
64 
66 

69 
69 
69 
69 
70 
70 
70 
71 
71 
72 
73 
73 
75 
75 
76 
82 

89 

97 

Table 1.1 
Table 2.1 
Table 2.2 
Table 3.1 
Table 3.2 
Table 3.3 
Table 3.4 
Table 5.1 
Table 5.2 
Table 5.3 
Table 5.4 
Table 5.5 
Table 5.6 
Table 5.7 

Summary of a Selection of Other UFF Parameters 
Comparison of CFF and UFF Criteria 
Stages in CFF and UFF Exploration and Production 
Screening – Comparison of Other UFF and Shale Gas Risks and Impacts (per well basis) 
Risk Assessment of Screened Tight Oil (TO) and Tight Gas (TG) Aspects 
Risk Assessment of Screened CBM Aspects 
Risk Assessment of Further Risks for CBM 
Examples of Possible Amendments to the Existing Acquis to Address Gaps in the Regulation of Unconventional 

2 
10 
22 
42 
49 
53 
60 
72 
74 
Number of Measures in Options 
76 
Tight Gas Annualised Compliance Costs for Policy Options (€ per pad) 
76 
Tight Oil Annualised Compliance Costs for Policy Options (€ per pad) 
77 
CBM Annualised Compliance Costs for Policy Options (€ per pad) 
77 
Shale Gas Annualised Compliance Costs for Policy Options (€ per pad) 
Tight Gas Annualised Compliance Costs for Policy Options, with Adjustments for Non-BAU Measures that are Likely 
to be Applied in Practice (€ per pad), and Difference to Annualised Compliance Costs with No Adjustments (€ 
79 
per pad) 

Gas 

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Table 5.8 

Table 5.9 

Table 5.10 
Table 5.11 
Table 5.12 
Table 6.1 
Table 6.2 

Figure 2.1 
Figure 2.2 
Figure 3.1 

Tight Oil Annualised Compliance Costs for Policy Options, with Adjustments for Non-BAU Measures that are Likely 
to be Applied in Practice (€ per pad), and Difference to Annualised Compliance Costs with No Adjustments (€ 
80 
per pad) 

CBM Annualised Compliance Costs for Policy Options, with Adjustments for Non-BAU Measures that are Likely to 
be Applied in Practice (€ per pad), and Difference to Annualised Compliance Costs with No Adjustments (€ 
per pad) 

81 
84 
Tight Gas Comparison of Costs of Policy Options to Expected Revenues from Natural Gas Sales 
85 
Tight Oil Comparison of Costs of Policy Options to Expected Revenues from Natural Gas Sales 
86 
CBM Comparison of Costs of Policy Options to Expected Revenues from Natural Gas Sales 
93 
Total Annualised Compliance Costs for Operators of the Selected Policy Options for Operators (€ per pad) 
Total Annualised Compliance Costs, with Adjustment for non-BAU measures likely to be applied and possible to be 
94 
15 
16 
32 

Resource Triangle for Gas Resources 
Permeability Scale for Distinguishing Between CFF and UFF 
Risk Matrix 

applied (€ per pad) 

Appendix A 
Appendix B  Measures 
Appendix C 
Appendix D  Measures Included in Policy Options 

Illustrative Concession Information 
Potential Criteria for Categorisation of CFF and UFF 

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1. 

Introduction 

1.1 

Purpose of this Report 

This is the Final Report for a project on ‘Technical Support for the Risk Management of Unconventional 
Hydrocarbon Extraction’, contract 070251/2014/674828/SER/ENV/F.1.  The report presents the outcome of work 
that will provide an overview of the main unconventional fossil fuels other than shale gas (‘other UFF') that require 
hydraulic fracturing to enable hydrocarbon extraction, a comparison of the risks associated with other UFF and 
shale gas, consideration of the adequacy of technical and policy measures to mitigate environmental risks that were 
developed in previous work that focussed on shale gas for the management of risks arising from extraction of other 
UFF and a description of selected policy options available to implement such measures, should the Commission 
decide that further action at EU level is needed. 

1.2 

Context 

In January 2014, the Commission published its Communication and Recommendation on the exploration and 
production of hydrocarbons (such as shale gas) using high volume hydraulic fracturing in the EU9.  In support of 
the Communication and Recommendation, Amec Foster Wheeler Environment & Infrastructure UK Ltd10 
undertook the study ‘Technical support for assessing the need for a risk management framework for 
unconventional gas extraction’, reference ENV.F.1/SER/2012/0033.  Whilst the study focussed on shale gas with 
consideration of the implications and scope of potential policy proposals, there was a need gather information 
regarding other UFF. 

Whilst past EU exploration and production of hydrocarbons including natural gas have focused mainly on 
conventional resources, technological advances, in particular in the United States and Canada, have opened the 
possibility of development of fossil fuels from UFF.  Shale gas is the UFF resource with the greatest potential 
recoverable resources in the EU; consequently work carried out to date in studies for the Commission has focused 
on shale gas.  However, development of UFF other than shale gas is also taking place or is planned to take place in 
the EU, which requires further examination. 

The support provided under this contract provides an assessment of risks and potential impacts of the exploration 
and production of other UFF to enable identification of technical measures to address these risks and impacts.  The 
analysis is based on the environmental assessment of shale gas carried out under previous work and widens the 
scope of the assessment to other UFF requiring hydraulic fracturing to initiate production (e.g. tight gas, tight oil, 
and coalbed methane (CBM)11). 

9 http://ec.europa.eu/environment/integration/energy/unconventional_en.htm 
10 Formerly AMEC Environment & Infrastructure UK Ltd 
11 CBM is extracted from virgin coal bed seams that have not been mined in contrast to coal mine and abandoned coal mine methane.  Note that CBM may not 
require hydraulic fracturing to enable successful production.  In the course of this study CBM operations in Europe where hydraulic fracturing has been used or is 
planned has not been identified.  In Australia, where CBM resources are developed, to date less than 5% of CBM wells have been fractured, and this figure is 
unlikely to exceed 10% (New South Wales Government (2014)).  USEPA (2004) indicates that hydraulic fracturing occurs in most CBM basins studied but does not 
indicate the proportion of wells requiring fracturing. 

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Other UFF present many of the same risks as shale gas.  However, there are differences between shale gas and 
other UFF such as techniques used (e.g. fracturing parameters), potential scale, types of geology and the depth of 
the target formations.  These factors may influence the risks presented and mitigation measures required.  The 
following table summarises a selection of parameters for other UFF. 

Table 1.1 

Summary of a Selection of Other UFF Parameters 

Tight Gas 

Tight Oil 

CBM 

What is it? 

Gas trapped in low permeability 
sandstones and occasionally 
carbonates.  Permeability may be 
<0.1 millidarcy. 

Oil trapped in fine-grained 
sedimentary rock (e.g. siltstones, 
sandstones, carbonates or shale).  
Permeability may be <0.1 millidarcy. 

Gas extracted from un-mined (virgin) 
or un-mineable coal seams.  
Permeability variable. 

Key 
characteristics 

Gas does not flow easily without 
stimulation. 

Oil does not flow easily without 
stimulation. 

Depth of reserves can be shallower 
than other UFF (e.g. 500 to 1,500m). 

Formations can extend for hundreds 
of thousands of km2 and tend to be 
located deep underground (e.g. 1,800 
to 4,200m). 

Horizontal drilling and fracturing 
required. 

Fracturing may require a lower fluid 
injection volume than for shale gas.  
Flowback from hydraulic fracturing 
17-35%. 

Chemical additives are likely to be 
required.  The additives used and 
their volume will be formation specific 
(range 0.5-2.0%).  Additives similar to 
shale gas. 

Vertical, horizontal and multi-lateral 
drilling used. 

Pressure at the reservoir during 
fracturing around 690 bar, but 
influenced by depth. 

Formations tend to be located deep 
underground (e.g. 1,200 to 3,600m). 

Horizontal drilling and fracturing is 
required. 

Similar, or smaller, volumes of 
fracture fluid may be used to that for 
shale gas.  Flowback from hydraulic 
fracturing 10-60% which may contain 
heavy hydrocarbons. 

Similar technology used to that of 
shale gas and similar chemical 
components of fracturing fluids. 

Flowback recovery may be higher 
than that for shale gas (e.g. 
approximately 60% vs. 30% in shale 
gas). 

Pressure at the reservoir during 
fracturing around 552 bar but 
influenced by depth. 

Technology depends on operator 
preferences and coal seam 
properties. 

Requires depressurisation (by 
dewatering) to enable gas extraction 
through desorption from the coal 
resulting in high wastewater volumes.  
The salinity of such pumped water 
may vary from 1-128,000 mg/l 
chloride. 

Typically, fracture fluid volumes and 
pressures used are lower than for 
shale gas.  If hydraulic fracturing 
used, flowback between 61-82%.  
Fracturing is not always required to 
enable gas extraction. 

Vertical, horizontal and multi-lateral 
drilling used. 

Pressure at the reservoir during 
fracturing around 207 bar but 
influenced by depth. 

Sources: selected data from Table 2.1 and Appendix A. 

1.3 

Objective 

The objective of this study is to build on the contract ‘Technical support for assessing the need for a risk 
management framework for unconventional gas extraction’ and to provide support for the preparation of possible 
Commission initiatives on managing risks and potential impacts of other UFF extraction in Europe.  To this end the 
study: 

•  Identifies and assesses relevant measures for managing the risks from UFF developments other than 

shale gas; 

•  Prepares extended support for a possible impact assessment on the need, and possible options for 

further action at EU level, should it be deemed necessary; and 

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•  In collaboration with the Commission and in the context of a possible wider risk management 

framework, provides support for developing possible measures and elements of that framework. 

1.4 

Scope and Boundary of the Study 

The overall scope and boundary of the study can be summarised as: 

•  Categorisation of unconventional fossil fuels: 

-  Establish technical and/or geological criteria that distinguish UFF from CFF12 for possible 

categorisation option/s; 

- 

Identify the risks and impacts of other UFF and compare to shale gas, and define groups of UFF 
with similar risks and impacts; 

-  Assess the extent to which enhanced stimulation techniques with similar risks and impacts are used 

by the conventional oil and gas sector; and 

- 

Identify technical criteria to distinguish between exploration and production phases of UFF, if and 
where relevant. 

•  Comparison of risks and impacts: 

- 

Identify a suitable risk matrix for assessment of risks; 

-  Compare the risk and impact profiles of each UFF group identified with the risks and impacts of 

shale gas activities. 

•  Development of measures: 

-  Assess whether the measures already identified for shale gas are proportionate to the risk and 

impacts of each UFF group; 

-  Propose measures to address additional risks identified for other UFF, if any. 

•  Assessment of policy options: 

-  Development of cost scenarios for policy options including contextualisation of costs with average 

revenues of other UFF activities and, if feasible, monetised benefits from reduced impacts. 

The scope of work did not include offshore UFF which is the subject of a separate Commission study.  It is not the 
purpose of the study to decide upon the most appropriate framework for managing the environmental risks of other 
UFF.  Instead, the aim has been to provide information and data that can be used by the Commission in assessing 
the need for and impacts of any possible policy option, should action at EU level be deemed necessary. 

This study has the following limitations: 

12 Conventional fossil fuels. 

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•  It should be borne in mind that there is limited extraction of other UFF involving the use of hydraulic 
fracturing in the EU so current work has had to take into account limited existing and potential future 
developments.  The focus of the study is other UFF that uses hydraulic fracturing beyond shale gas.   

•  The focus of the study was on water-based fracturing.  Non-water-based and new technologies would 
require a separate assessment of risks and technical measures if these were to be considered as part of 
a risk management framework. 

•  The influence of fluctuations in oil and gas prices (either up or down) is not assessed in terms of the 

effect this may have on measures that may be required.  However, an indication of the likely impact of 
recent oil and gas price fluctuations is commented on. 

•  It should be noted that the cost estimates exclusively address preventive measures and do not include 

costs for remediation of accidental events. 

•  Estimates of affordability are highly dependent on a number of assumptions, including estimates of 
gas production volumes per well and assumed productive lifetime over which those volumes are 
realised which will vary on a case by case basis. 

•   Compliance costs and affordability estimates are based on best estimates for measure costs using 

single point values for option cost calculation.  Costs may vary and there are uncertainties regarding 
costs across the large number of measures. 

1.5 

Summary of the Study Process 

The study built on work carried out previously that focussed on shale gas.  A stepwise process was followed 
entailing (i) categorisation of UFF, (ii) comparison of risks and impacts identified for shale gas with those of other 
UFF to enable assessment of whether the measures already identified for shale gas are proportionate to the risk and 
impacts of other UFF, (iii) development of further measures as necessary and then (iv) assessment of policy options 
selected by the Commission. 

Any required Impact Assessment of the potential policy options is to be carried out by the Commission, taking into 
account not only the information gathered and analysed in this study, but also that of a number of other related 
studies. 

1.6 

Report Structure 

The report is presented in the following sections: 

•  Categorisation of UFF: criteria that may be used for categorising UFF are presented, populated with 

data where possible, and options for categorisation are discussed; 

•  Comparison of risks and impacts: the approach to and results of comparison of risks of other UFF to 

shale gas is presented; 

•  Measures: a review of measures developed for shale gas is presented, together with an assessment of 
whether or not the measures are likely to be proportionate to the risks presented by other UFF; 

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•  Policy options to deliver the measures: a description of policy options followed by an assessment of 
potential options considering specific combinations of measures as selected by the Commission; and 

•  Conclusions. 

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2.  Categorisation of Unconventional Fossil Fuels 

2.1 

Introduction 

The objective of this section is to discuss criteria that may be used to derive a technical definition of the types of 
UFF relevant to the EU (i.e. the types of UFF that might be developed in EU Member States).  In addition, the risks 
and impacts of UFF are discussed with the aim of defining groups of UFF with similar risks and impacts profiles.  
Where relevant, distinctions are made between risks and impacts at the exploration and production phases.  
Consideration has been given to the extent to which stimulation techniques with similar risks and impacts to those 
used in UFF are used by the conventional (CFF) oil and gas sector.  Furthermore, the stages of UFF development 
are described to permit potential distinction between the exploration phases and the production phase of all UFF 
where relevant. 

2.2 

Categorisation of CFF and UFF 

2.2.1 

Introduction 

The oil and gas industry distinguishes between CFF and UFF resources.  This distinction relates to the geological 
setting in which fossil fuel resources are located and not to the fossil fuel itself.   

The United States Energy Information Administration (2013) considers UFF production to be an ‘umbrella term for 
oil and natural gas that is produced by means that do not meet the criteria for conventional production’.  It notes 
that what is considered to be UFF at any particular time is a complex interaction of resource characteristics, the 
exploration and production technology used, the economic environment, and the scale, frequency and duration of 
production from the resource.  It also notes that these factors change over time and that perceptions differ among 
users of the terms CFF and UFF.  A similar consideration of technical difficulty and cost is given in IEA (2012) 
definition, which states that ‘unconventional gas refers to a part of the gas resource base that has traditionally been 
considered difficult or costly to produce’ 

The term ‘unconventional’ is typically used to identify the use of previously rarely used techniques such as 
horizontal drilling and high volume hydraulic fracturing to extract the resource.  However, these techniques are 
now applied to many CFF resources and sufficiently frequently that they no longer represent unconventional 
techniques (DMEA, 2013).  The use of high volume hydraulic fracturing has not been used to any great extent 
within Europe for hydrocarbon extraction.  Lower volume hydraulic fracturing of some tight gas and conventional 
fields has been used in the southern part of the North Sea and in onshore in Germany, the Netherlands, Denmark 
and the UK (AEA, 2012).  

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2.2.2 

General Categorisation 

In general, CFF is defined as oil and gas that flows to a well bore in economic quantities without stimulation, i.e. 
oil and gas production by ‘conventional’ means.  Typically this means that oil and gas flow under pressure when a 
field is first penetrated but at later stages pumping may be used.  However, increasingly stimulation and enhanced 
recovery techniques are used to increase production within CFF as the industry seeks to maximise the amount of oil 
and gas that can be extracted from a field.  The consideration of economic quantities in the definition of CFF would 
mean that what is considered conventional will depend on the cost of extracting the oil and gas, which will vary in 
response to technical developments, field characteristics and externalities including oil and gas prices.  

There is no universally recognised definition of the dividing line between CFF and UFF.  A frequently-quoted 
definition was provided by US Department of Energy in the 1970s based on permeability.  This defined UFF as oil 
and gas in rocks with a permeability of less than 0.1 mD (millidarcy).  However, it is not clear that this definition is 
meaningful in the modern context.  A qualitative definition is set out in DMEA (2013), which suggests that CFF is 
trapped in rock with a ‘high’ porosity and permeability whereas as UFF is still trapped in a source rock 
characterised by ‘low’ permeability.  However, they note that whilst techniques such as horizontal drilling and 
hydraulic fracturing are used to release UFF, horizontal drilling and fracturing are also used for CFF, although the 
combination of horizontal drilling and high volume hydraulic fracturing has rarely been used in Europe to date 
(AEA, 2012).   

An alternative definition is that UFF refers to resources that are found within the source rock in which it was 
originally formed (Umweltbundesamt, 2013).  This definition includes shale gas and CBM but excludes tight oil 
and tight gas where hydrocarbons have migrated from a source rock to a reservoir.  Lechtenbömer et al , 2011 
maintain that there is a no sharp distinction between CFF and UFF when considering permeability and instead 
suggest that there is a continuum from CFF in highly productive fields characterised by high permeability, through 
less productive fields, then tight gas and finally to very low permeability shale gas.  The continuum is illustrated as 
a resource triangle (Figure 2.1) for the permeability range of producing formations (Figure 2.2).   

The German Society for Petroleum and Coal Science and Technology (DGMK) has defined tight gas reservoirs 
with an average effective permeability for gas below 0.6 mD (Hagemann et al 2012), which is also the permeability 
at which lower royalties are payable on extracted gas in Germany. 

The United States Geological Survey (USGS) resource assessment of unconventional oil and gas set out in 
Schmoker (1999) prefers the term ‘continuous accumulations’ to define unconventional resources.  It defines the 
term through 16 geological criteria13 relating to: 

•  The size and areal extent of the deposit and the nature of its boundaries;  

•  The way that hydrocarbons are retained within the reservoir (absence of seals or traps);  

13 (1) is regional in extent, (2) can have diffuse boundaries, (3) has existing "fields" that commonly merge into a regional accumulation, (4) does not have an obvious 
seal or trap, (5) does not have a well-defined gas-water contact, (6) has hydrocarbons that are not held in place by hydrodynamics, (7) commonly is abnormally 
pressured, (8) has a large in-place resource number, but a very low recovery factor, (9) has geologic "sweet spots" of production, (10) typically has reservoirs with 
very low matrix permeabilities, (11) commonly has natural reservoir fracturing, (12) has reservoirs generally in close proximity to source rocks, (13) has little water 
production (except for coalbed methane), (14) has water commonly found updip from gas, (15) has few truly dry holes, and (16) has Estimated Ultimate Recovery 
(EUR) of wells that are generally lower than EURs from conventional gas accumulations 

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•  Relationships to water-filled deposits;  

•  Reservoir permeability;  

•  The pressure regime;   

•  The recovery factor of the reservoir and the total recovery at individual wells.  

However, the term and the criteria used to define it do not appear to have gained common acceptance.  In 
‘Guidelines for application of the petroleum resources management system, 2011’ a joint publication of the Society 
of Petroleum Engineers (SPE), American Association of Petroleum Geologists (AAPG), World Petroleum Council 
(WPC), Society of Petroleum Evaluation Engineers (SPEE) and Society of Exploration Geophysicists (SEG), UFF 
is defined as “Unconventional resources exist in hydrocarbon accumulations that are pervasive throughout a large 
area and that are generally not significantly affected by hydrodynamic influences (also called “continuous-type 
deposits”). Such accumulations require specialized extraction technology, and the raw production may require 
significant processing prior to sale. Set against conventional resources, which exist in discrete petroleum 
accumulations related to a localized geological structural feature and/or stratigraphic condition (typically with each 
accumulation)”.  

Criteria that might be used to distinguish between CFF and UFF are set out in Table 2.1.  Information in Table 2.1 
compares the characteristics of CFF and UFF for these criteria to identify possible means to distinguish between 
categories.  The information is compiled from a variety of researched and referenced literature sources and aims to 
provide a summary of the general nature and scale of significant differences between CFF and the UFF, however, 
the information presented may not cover the diversity of all cases that may be encountered. 

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Table 2.1 

Comparison of CFF and UFF Criteria 

Criteria 

CFF 

Main 

Secondary 

Gas and oil flow to a 
well without stimulation 
or enhanced recovery 

Areal extent of a play 

Recovery factor (% 
resource recovered) 

Reservoir rock geology 

Reservoir rock structure 

UFF 

Shale gas 

No 

Tight gas 

No 

Tight oil 

No 

CBM 

No 

Can extend up to a large 
extent of the formation, 
which can be large e.g. 
250,000 km2 for the 
Marcellus Shale in the US.  
Many European prospects 
have areas >1,000 km2 (A) 

Extensive in the US.  
Potentially large areas in 
Europe (Germany, Hungary) 
but limited information in 
public domain  

Extensive in US 

Limited information on plays 
in Europe.  Potential deposits 
in Europe (27 plays identified 
by IHS CERA, 2013) 

Can extend over large area 
up to the full extent of the 
coal.  Large areas of coal in 
Europe but limited 
information on CBM 
potential.  

15 to 35% (A) 

10% (B) 

1 to 22% (F),  

High (50 to 90% (C,D;E) 

Yes although some 
stimulation/enhanced recovery 
may be required to maximise 
recovery 

Oil and gas fields usually occur 
in defined structural or 
stratigraphic traps that cover 
less than the full area of the 
reservoir, formation or play.  
Typically small surface area in 
Europe e.g. Wytch Farm, UK 
has a mapped surface area of 
<100 km2 (estimated from W) 

High (40 to 80%) (B). Oil being 
at the low end and gas at the 
high end. 

Sandstones 
Carbonates 

Shale 

Sandstones 
Carbonates 

Siltstones, sandstones 
carbonates or shale 

Coal 

Oil and gas found in traps 
created by geological 
structures (e.g. antiforms, 
faults, salt diapirs) 

Occurrence not related to 
traps 

Occurrence not always 
related to traps 

Occurrence not always 
related to traps 

Occurrence not related to 
traps 

Reservoir rock 
permeability 

Various definitions: 
- more than 0.1 mD 
- ‘high’ permeability 

Various definitions: 
- less than 0.1 mD 
- ‘low’ permeability 

Various definitions: 
- less than 0.1 mD 
- ‘low’ permeability 

Various definitions: 
- less than 0.1 mD 
- ‘low’ permeability 

Variable 

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Criteria 

CFF 

UFF 

Main 

Secondary 

Shale gas 

Tight gas 

Tight oil 

CBM 

Reservoir rock 
thickness 

Depth  

Highly variable as it depends 
on the nature of the trap 

Highly variable (e.g. 6-610 m 
for US shales (I) up to 900 m 
in UK in deep basins (O)  

Highly variable 

Highly variable 

Typically thin (<10 m) 

Highly variable but increasingly 
deep 

Variable (e.g. 180 to 4,000 m 
for US shales (I) 

1,800 to 5,500 m (H) 

1,800 to 4,200 m (H) 

Typically deep (e.g. 3,500 to 
5,000 m in Cloppenberg 
Germany (J) 

1,800 to 4,200 m (H) 

Typically deep (e.g. 600 to 
2,900 m in Canada (I) 

1,200 to 3,600 m (H) 

Typically shallow ~e.g. 800 m 
in Falkirk (L); 1,000 m in 
Munsterlander-Becker 
Region, Germany (J), 600 to 
1100 (K), 500 to 1,500 m (H) 

Drilling methods 

Drilling methods do not distinguish between CFF and UFF, i.e the same drilling rigs and drilling methods are used. 

Number and type of 
wells 

No. of wells per 
field  

Typically few wells used but 
number increased when 
enhanced recovery techniques 
used. (e.g. Schoonebeeke in 
the Netherlands required 73 
new wells for steam injection 
(U)) (E.g. Wytch Farm – 
Europe’s largest onshore CFF 
oil field has approximately 100 
wells at 13 sites including 
injection and recovery wells) 
(V).  

Large numbers (e.g. 200 to 
800 proposed for NW 
England (M) 

Large (e.g. 300 wells for tight 
gas in Germany 9 (J) 

Potentially large e.g. in 
Bakken of North Dakota 
between 122 and 189 drilling 
rigs were active (2010 to 
2014) NDIC website access 
02 June 2014 

Current schemes in Europe 
are small e.g. 20 wells in 
Falkirk (L) but schemes in the 
US have a typical size of 70 
wells and the number of 
wells per basin exceeds 
1000 (N) 

Use of horizontal 
wells 

Not always used 

Generally used 

Generally used 

Generally used 

Commonly but not always 
used.  Falkirk scheme 
proposes the use of 
horizontal wells (L) 

Length of 
horizontal 

Variable e.g. up to 4800m at 
Wytch Farm 

900-3,000 m (H) 

30-5,750 m (W) 

800-4,500 m (F, H) 

300-1,200 m (H) 

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Criteria 

CFF 

UFF 

Main 

Secondary 

Shale gas 

Tight gas 

Multi-well pads 

Variable use.  May be used 
onshore to reduce footprint 
(e.g. Wytch Farm in the UK) 

Typical in US.  Multi-well 
pads planned for Europe (J) 

Typical in US (J).  1-14 wells 
per pad (J, W) 

Tight oil 

Typical 

CBM 

Dependant on the technique 
and well configuration used 
to extract gas (e.g. 4 
indicated (K) 

Pad separation  

Large to avoid interference 

1 to 5 km 

1 to 5 km 

1 to 5 km 

Close to create interference  

Well density 

1 well per 10 km2 (V) 

1 well per 1 km2 (V) 

1 well per 1 km2 (V) 

1 well per 1 km2 (V) 

1 well per 0.16 to 0.32 km2 
(C) 

Stimulation by hydraulic 
fracturing  

Hydraulic 
fracturing 

May be used 

Required 

Required 

Required 

Not always used 

Volume of water 
used per well per 
fracture 

Injection pressure 
at reservoir 

0.0 to 700 m3 (H) 

7,600 to 34,100 m3 (H) 

100  to 12,000 m3 (w, x) 

500 to 25,600 m3 (H, I) 

0.0 to 4,700 m3 (H) 

Depends on pressure regime / 
depth 828 bar (H) 

Depends on pressure regime 
/ depth 690 bar (H) 

Depends on pressure regime 
/ depth 690 bar (H) 

Depends on pressure regime 
/ depth 552 bar (H) 

Depends on pressure regime 
/ depth 207 bar (H) 

Use of additives1 

Required 

Required 

Required 

Required 

Not always used 

Use of proppants 

Not always required 

Required 

Required 

Required 

Not always used  

Flowback volume 

30% (H)  

50% (Y) 

17%-35% (H, Z) 

10-60% (H) 

61-82% (H, AA)  

Cavitation 

No information 

No information 

No information 

No information 

Used to increase 
permeability of wells in thick 
coal seams 

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Criteria 

CFF 

UFF 

Main 

Secondary 

Shale gas 

Tight gas 

Tight oil 

CBM 

Enhanced recovery 
techniques used  

Gas injection (carbon dioxide, 
natural gas).  Natural gas used 
in Europe but not carbon 
dioxide (T).  Carbon dioxide has 
been used extensively in the 
US due to availability of natural 
carbon dioxide. 
Water flooding (widely 
practised in Europe (T) 
Chemical flooding 
Heat (steam) injection (used at 
Schoonebeeke, NL (U).  Use is 
highly variable –and increases 
with time (G) 

No evidence of use CO2 
injection at experimental 
stage (B).  Use is variable 
and decreases with time and 
rate of gas production (Q) 

No evidence of use.  Use is 
variable and decreases with 
time and rate of gas 
production (B) 

No evidence of use 

Lowering of hydrostatic 
pressure required.  Use is 
high and decreases with time 
(C,G) 

CO2 injection (technology at 
early stage of development)   

Wastewater – produced 
water 

Presence of 
naturally occurring 
radioactive 
materials (NORM) 

Salinity of water 

Presence is formation specific 

NORM typically present 

Presence is formation 
specific 

Presence is formation 
specific 

Presence is  formation 
specific 

1,000 to 400 000 mg/l salinity 
(S) 

5,000 to 200,000 ppm (P, R, X) 

211 to 107,000 mg/l as 
chloride (I) 

1 to 128,000 mg/l as chloride 
(C, Z),  

Disposal routes 
North America 
(NA) 

Treatment and deep injection in 
NA (to enhance recovery). 
Treatment and discharge to 
coastal waters (e.g. North Sea) 

Treatment and deep injection 
in NA. 
Treatment and discharge to 
inland waters in NA 

Treatment and deep injection 
(e.g. Germany) 

Treatment and deep injection 
in NA 
Treatment and discharge to 
coastal waters (e.g. 
proposed by Dart Energy, in 
UK) 
Treatment and discharge to 
inland waters 

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Notes: 

1 Additives are dependent on factors such as the formation, service company preference and prices. 

References: A USEIA (2013); B MIT (2011); C Halliburton (2008); D Ryder Scott (2006);E Lea et al (2008); F CSUR undated; G USDOI (2011); H ICF (2013); I All Consulting (2012); J Ewen et al. 
(2012); K Environment Agency for England response illustrative play to questionnaire (2014a); L Dart Energy (2012); M Regeneris (2011); N USGS (undated); O DECC (2014); P Cuadrilla 
(http://www.cuadrillaresources.com/wp-content/uploads/2012/02/Summary-of-relevant-analytical-results2.pdf); Q UKWIR, 2014, R UB (2013); S USGS (2002); T Tzimas et al. (2005); U NAM 
(2010); V http://www.bdf.co.uk/projects_wytch_farm.php; W Landesamt für Bergbau, Energie und Geologie (2014), X AEA (2012), Y AMEC (2014), Z Umweltbundesamt (2013), AA USEPA 
(2014) 

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2.2.3 

Geological and Spatial Categories 

As indicated on the resource triangle (Figure 2.1), UFF reserves have a much larger volume (in terms of the volume 
of the reservoir) and they can cover much larger areas than CFF but have a lower amount of gas (or oil) (Holditch, 
2006), or expressed another way UFF are less concentrated than CFF (IEA, 2012).  For example, unconventional 
gas developments in the area of the Marcellus shales in the US (250,000 km2) is 10 times larger than the largest 
CFF gas producing area in the US, the Hugoton Natural Gas Area in Kansas. (IEA, 2012).  As a result, the 
technically recoverable reserves per unit area are lower for UFF than for CFF (IEA, 2012). 

Figure 2.1  Resource Triangle for Gas Resources 

Source: Holditch (2006). 
md: millidarcy 

It is evident from the information in Figure 2.1 and Figure 2.2 that a potentially significant differentiator between 
CFF and UFF is the permeability of the reservoir formation.  Shale gas, tight oil and tight gas are found in 
formations with lower permeability than CFF.  However, the permeability of CBM is more variable and therefore 
cannot be readily distinguished from CFF on this basis.  Hydraulic fracturing of CBM is only likely to be required 
when coal has a low permeability (Halliburton, 2008).  There is, however, a continuum of permeability from CFF 
to UFF) and, therefore, any permeability-based distinction requires an arbitrary line to be drawn on this continuum. 

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Figure 2.2  Permeability Scale for Distinguishing Between CFF and UFF 

Source: King (2012)  
mD: millidarcy 

Another potential distinguishing factor is the geological environment in which CFF and UFF are found, as CFF are 
typically found in a trap, where a cap rock overlies, and contains, a reservoir.  This means that CFF fields are likely 
to have well-defined dimensions.  In contrast, UFF may be found in much more extensive bodies with more 
gradational boundaries from the play, into unproductive strata, where the edge is determined by economic as well 
as geological considerations. 

The need for stimulation is a consequence of the low permeability of shale gas, tight gas and tight oil.  For these 
forms of UFF stimulation is by hydraulic fracturing.  For CBM enhanced recovery by depressurisation 
(groundwater14 pumping) is required but stimulation by hydraulic fracturing may also be used albeit using 
relatively low volumes (0.0 to 4,700 m3) of fluid, typically in vertical rather than horizontal wells (e.g. Halliburton, 
2008).   

A consequence of the low permeability of formations where other UFF are present is that individual wells have a 
limited zone of influence and, therefore, large numbers of wells (typically horizontal wells) are required to access 
the resource.  In contrast, in more permeable CFF formations, hydrocarbons can flow to a well over larger distances 
and therefore fewer wells are required.  Likewise, only vertical wells are typically needed to exploit CCF resources.  
However, even in CFF, large numbers of wells may be required towards the end of a field’s life when enhanced 
recovery techniques such as water flooding may be used to extract remaining reserves, for example Schoonebeeke 
in the Netherlands has had 599 vertical wells drilled and a further 73 wells, including horizontal wells, are in the 
process of being drilled for steam injection to extract oil (NAM, 2010). 

UFF may extend over larger areas than CFF.  Areal extent will in general be greater for shale gas and CBM than 
tight gas and tight oil (i.e. the UFF sources where the source and reservoir rock are the same) because it is related to 
the lateral extent of the sedimentary formation rather than limited to the extent of a trap.  Where sedimentary strata 
are relatively undisturbed, they can extend over many thousands of square kilometres, for example the Marcellus 

14 ‘Groundwater’ means all water which is below the surface of the ground in the saturation zone and in direct contact with the ground or subsoil. 

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Shale in the Eastern United States of America extends over 250,000 km2.  Potential reserves in Europe can be of a 
similar scale (e.g. the Paris Basin extends over 170,000 km2 of which approximately 46,000 km2 is prospective for 
shale gas and in which tight oil reserves are also located (USEIA (2013).  However, most European UFF are less 
extensive.  They also tend to have more structural features, such as faults, than the plays exploited in North 
America.  However, UFF may have limited areal extent, for instance the shale gas resources in the UK are mainly 
located in distinct fault-bounded basins that are of limited areal extent (DECC, 2010) rather than in laterally 
extensive sub-horizontal strata.  

There are differences in the techniques used to exploit CFF and UFF and in particular the number of wells required, 
the extensive use of horizontal wells, and the extent of stimulation required at the production stage.  However, there 
is also increased use of horizontal drilling and stimulation for CFF and in addition enhanced recovery techniques 
(water flooding, CO2 injection, steam injection, chemical flooding etc.).  However, the pressure required and the 
volume of CFF operations are generally less than those in UFF because the rock volume that is to be stimulated is 
smaller (DMEA, 2013)15. 

2.2.4 

Stimulation and Recovery Techniques 

Well stimulation is a general term describing a variety of operations performed on a well to improve productivity.  
It is generally divided into matrix treatments and hydraulic fracturing. 

Matrix treatments are performed below the reservoir fracture pressure and generally are designed to restore the 
natural permeability of the reservoir following damage to the near-wellbore area (Schlumberger Oil Field Glossary 
- http://www.glossary.oilfield.slb.com).  These treatments may be used on hydrocarbon wells for both CFF and 
UFF and are unlikely to be distinctive.  They are not considered further. 

Hydraulic fracturing involves the injection of a liquid under pressure via a well to induce fractures in rock.  The 
liquid may contain particles, such as sand, that are carried into the fractures to maintain them open once the 
pressure has been released.  These are termed proppants.  The fractures allow gas or oil to flow out of the 
formation. 

Where large volumes of fluid are used, then stimulation is sometimes referred to as high volume hydraulic 
fracturing.  This is defined as operations using more than a particular volume of fluid (e.g. 380 m3 (100,000 US 
gallons) of fluid (Michigan Department of Environmental Quality, 2011) per well or 1,140 m3 (proposed by New 
York Department of Environmental Conservation, 2014)).  The European Commission (2014) defined high volume 
hydraulic fracturing as ‘injecting 1,000 m3 or more of water per fracturing stage or 10,000 m3 or more of water 
during the entire fracturing process into a well’. 

Stimulation of reservoirs by hydraulic fracturing is used in both CFF and UFF.  The main differences are the 
pressure and the volume of water used in the process, i.e. whether it is high volume or not; the number of stages of 
hydraulic fracturing (whether it is a multi-stage process or not); the volume and nature of additives and the volume 
and type of proppant used.  In general, the volume of water used in shale gas is larger than is used in tight oil and 

15 Pressure is however reservoir, depth and formation dependent and could require high pressures. 

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particularly tight gas although wells in deep formations or with large horizontal lateral lengths can result in similar 
levels of water use to shale gas (ICF, 2013).  Where hydraulic fracturing is used in CBM, then the volumes are 
typically small (ICF, 2013), the number of stages limited and the composition may vary between water only (as 
proposed by Dart in the UK) or with chemical additives as per shale gas fracturing.  Furthermore, CBM does not 
always require the use of proppant to maintain fractures open as the goal of hydraulic fracturing is to develop and 
enhance the natural ‘cleat’ system within the coal. 

CBM has used a stimulation technique known as cavitation to increase the size of the well at the point where it 
intersects coal seams in thick coal seams.  Cavitation consists of a cyclic and repeated pressurising and de-
pressurising of the wellbore, resulting in mechanical failure of the coal and the formation of a cavity in the coal that 
can be several metres in diameter (Loftin, 2009). 

In addition to stimulation, the oil industry also uses enhanced recovery methods to increase production.  In CFF, 
there are three phases of recovery: primary, secondary and tertiary (e.g. EPRI, 1999), as follows:  

•  Primary recovery occurs when there is sufficient pressure in the reservoir to force oil and gas to the 

surface, or only simple pumping arrangements are required; 

•  Secondary recovery methods involve the injection of fluids to increase reservoir pressure.  Water 

injection is known as water flooding; and 

•  Tertiary recovery or enhanced oil recovery methods increase the mobility of the oil to increase 
extraction using heat (e.g. steam), carbon dioxide, chemical (chemical flooding) or microbial 
treatments. 

The use of these techniques may lead to increased risks and impacts to the environment.  The key additional risks 
and impacts for CFF, when compared to CFF without enhanced (secondary and tertiary) recovery are considered to 
be:  

•  Additional wells are required to provide injection points for steam or water: impacts related to land 

take at additional injection sites; 

•  Construction and drilling at additional injection sites: emissions to air from plant and related traffic;  

•  Water flooding: potential leaks and spills of saline produced water re-used for water flooding resulting 

in water pollution;  

•  Gas (carbon dioxide) injection: risks of fugitive emissions and leaks to atmosphere during the 

collection, transportation, injection and storage; 

•  Chemical flooding: leaks and spills of chemical additives (e.g. alkaline substances, surfactants, 

polymers) resulting in water pollution; 

•  Steam injection: emissions to air (carbon dioxide, NOx) from heat / steam generation. 

Some UFF makes use of some of the enhanced recovery techniques, notably:  

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•  Lowering of hydrostatic pressure used in CBM to promote desorption of methane from coal 

(Halliburton, 2008); and 

•  Injection of CO2 in CBM to reduce partial pressures of methane and to promote desorption of methane 

(USEPA, undated) from coal.  

The above enhanced recovery techniques do not appear to have been used for shale gas, tight gas or tight oil but the 
use of carbon dioxide has been suggested as a possible means to enhance recovery in shale (MIT, 2011). 

2.2.5 

Summary of Categorisation Options 

The term unconventional (fossil fuel) is frequently used in reference to shale gas, tight gas, tight oil and CBM to 
distinguish them from CFF.   However, there is no widely accepted definition of this term and hence no 
unambiguous means of distinguishing all UFF from CFF on the basis of a single technical or geological criterion.  
Information in Table 2.1 presents a comparison of criteria that distinguish CFF and UFF.  There are potentially, 
different categorisation options to group UFF and to then to distinguish these groups from CFF.  A review of 
categorisation options suggests that shale gas, tight gas and tight oil can be grouped together as they share many 
characteristics including: depth; the scale of operations at a well pad; the use of multi-well pads / land take; and a 
requirement for the use of hydraulic fracturing to enable production; although the scale of the characteristics does 
vary across UFF.  CBM forms a separate group and is distinct from shale gas, tight gas and tight oil due to the 
typically shallower depth of operations; the typically reduced scale of operations at well pads; the reservoir type 
(coal); production process (desorption); the use of hydraulic fracturing (not always being required to enable 
production) and the associated volume of fracturing fluid, which is smaller; and the use of chemical additives (not 
always used).  In addition, CBM requires groundwater pumping to reduce pressure, whereas the other forms of 
UFF do not.   

The main potential difference between shale gas, tight gas and tight oil compared to CFF is the use of greater 
volumes of hydraulic fracturing fluid in shale gas and in some tight gas and tight oil plays.  Potentially, therefore, 
fracture fluid volume is a key distinguishing feature of UFF.  However, the definition of what constitutes high 
volume hydraulic fracturing (HVHF) varies from 380 to 10,000 m3 per well depending on the literature sources.  
The need for HVHF is partly a consequence of the lower permeability of UFF when compared to CFF and so 
permeability may also be a distinguishing feature.  CBM is unlikely to use of HVHF at the higher end of the range 
(10,000 m3 per well), but could potentially be captured under the lower limits of the range (380 m3 per well), as 
could CFF if volumes at the higher end of the CFF range are required and the lower limits of the range is used (see 
Table 2.1 for fracture fluid volumes).   

Other differences that may distinguish production of UFF from CFF are:  

•  The greater extent of the reservoir;  

•  The lower proportion of technically recoverable resource;  

•  The larger number of wells required per unit area and per unit of reserve;  

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•  The use of multi-well pads and the size of well pads needed to accommodate multiple wells and 

HVHF; and 

•  The use of horizontal drilling (not always used in CFF). 

The use of HVHF leads to differences with CFF in terms of increased: 

•  Water resource requirements.  

•  Energy consumption (and emissions to air from equipment). 

•  Waste water production. 

CBM may be distinguished from CFF due to:  

•  The nature of the reservoir rock (coal) compared to the sandstones and carbonates typical of CFF;  

•  Coal being both the source rock and reservoir, whereas in CFF the hydrocarbon has migrated from the 

source to the reservoir;  

•  The way in which gas is held by adsorption, rather than in macropores;  

•  The generally limited thickness of the resources;  

•  The potentially shallower depth of the resource; and 

•  The need for groundwater pumping to desorb gas (groundwater pumping is not required for CFF).   

A summary of criteria by which to categorise and hence distinguish between CFF and various UFF is presented in 
Appendix C; from the information, it is apparent that there is unlikely to be a single categorisation ‘option’ that 
captures all forms of UFF whilst avoiding capturing CFF.  Potentially favourable options for categorisation could 
be based on the following (or combinations thereof): 

•  The permeability of the reservoir formation.  It is interesting to note that in Germany a permeability of 
0.6mD is used to determine the royalties payable.  Higher royalties are payable above this value.  The 
0.6mD value is commonly used to establish the divide between CFF and UFF (Figure 2.2); 

•  Volume of water used in hydraulic fracturing (for shale gas, tight oil and tight gas).  An appropriate 

value is likely to be in the range 1,000 to 10,000 m3 per well; 

•  Injection pressure at the reservoir during hydraulic fracturing (for shale gas, tight oil and tight gas) e.g. 

more than 700 bar; 

•  Depth, due to additional risks presented by shallower operations (proximity to aquifers above wells) 
and deeper operations (greater pressures required for fracturing and the associated well integrity 
requirements); 

•  Depth for CBM (operations less than e.g. 1,000 m below ground level) as such operations are more 

likely to be near aquifers used for drinking water or contributing to surface water flow; and 

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•  Volume of pumped groundwater for CBM (operations producing more than e.g. 20 m3/day / well). 

An option based on the volume of water used has the advantage of avoiding most CFF and capturing the principal 
activity that distinguishes UFF from CFF (i.e. high volume hydraulic fracturing).  It is also closely linked to the 
risks and impacts of UFF.  However, the volume used is important.  If set too high it will only capture larger-scale 
operations and may potentially lead to industry tailoring operations to avoid the target.  Further development and 
use of foams and gas for hydraulic fracturing may also render this option irrelevant.  

Specifying a particular (high) injection pressure at the reservoir during hydraulic fracturing would enable capturing 
of UFF but may also capture some CFF.  Pressure is related to depth however, and therefore this will potentially 
not capture shallower UFF operations, although risks and impacts are potentially similar and hence categorisation 
using pressure may be somewhat arbitrary.  There is also a link between pressure and risks and impacts. 

The use of depth to provide categorisation may capture most UFF except CBM.  However, there is not a direct link 
to risk and impacts and therefore this may be seen as arbitrary.  It will also capture CFF.  The specification of a 
depth above which regulation is required links particularly to risks of groundwater pollution but is specific to CBM 
and is unlikely to be applicable to other forms of UFF. 

2.3 

Distinguishing Exploration and Production 

The development of both CFF and UFF can be divided into a series of stages.  Whilst CFF typically develops in 
sequential stages, UFF may be developed in a series of overlapping stages.  CFF development generally follows a 
fairly well-defined sequence compared to UFF which can be less consistent and where development generally 
proceeds in a more incremental fashion.  In UFF development, an operator may be exploring or appraising parts of 
a licenced area (concession) as well as developing and producing from another.  The fluidity of the stages of UFF 
project development increases the complexity of the interactions required between the operator and regulator.  For 
example, the regulatory system in most jurisdictions requires the submission and approval of a field development 
plan at the end of the exploration phase.  The longer development curve for UFF makes it much more difficult to 
develop comprehensive plans, with the risk that relatively small subsequent alterations might trigger the need to 
resubmit and reapprove the entire development (IEA 2012).   

In general terms, exploration seeks to identify whether there is a resource, to define its extent and then to 
demonstrate whether it is technically and economically viable to exploit.  Where a resource has been demonstrated 
to be technically and economically viable then it will move into production, where production is the process of 
extracting the hydrocarbon for use.  The stages in CFF and UFF exploration and production are presented in Table 
2.2.  These phases can be broken down into a number of subphases that are generally recognised within the 
industry. 

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Table 2.2 

Stages in CFF and UFF Exploration and Production 

Stage  

Sub-stage 

Main Activity in 
Stage 

Subsidiary 
activities 

Typical 
duration 

Scale of 
operation 

Exploration 

Identification of resource 

Compilation and review 
of existing information 
(e.g. by government / 
geological survey / oil 
company) 

Licensing  

Non- intrusive exploration 

Evaluate reservoir potential.  Identify 
geological structures (UFF specific) 

Tendering of exploration 
licence 

Non-intrusive 
geophysical testing (i.e. 
without drilling)  

Strategic 
Environmental 
Assessment 
before licensing 
and exploration 
(e.g. UK and 
Lithuania – Milieu, 
2013) 

Ongoing 
activity 

Ongoing 
activity 

Review of existing 
data 

0.5 to 2 
years 

Geophysical 
investigation 

Initial conceptual 
model 

Intrusive exploration (i.e. with drilling) 

Determine whether hydrocarbons are 
present and potential productivity 

Drilling of vertical and 
possibly horizontal wells 
to collect core samples 
for geological appraisal, 
hydrocarbon content, 
mineralogy 

Baseline surveys 
(ecology, 
hydrology, 
groundwater, 
community 
impact) 

1-3 years 

1 to 5 wells 
per licence 
area  
(1 to 5 well 
pads) 

Mobilisation of 
drilling rig and 
equipment and 
people to the drill 
site  

Well pad 
construction 

Drilling of vertical 
or deviated wells 
to gather cuttings, 
core, wireline and 
fluid data 

Trial of hydraulic 
fracturing.  May 
include flow or 
injection testing  

Revised 
conceptual model 
and resource 
estimate 

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Stage  

Sub-stage 

Main Activity in 
Stage 

Subsidiary 
activities 

Typical 
duration 

Scale of 
operation 

Appraisal 

Test and optimise completion 
techniques (UFF specific) and flow 
rates.  Evaluate technical and 
economic viability. 

Appraisal  

Mobilisation 

1-5 years 

5 to 20 wells 
per field / 2 to 
5 well pads 
(more wells 
required for 
UFF than 
CFF) 

Well pad 
construction 

Drilling (vertical) 

Drilling 
(horizontal) 

Casing installation 

Well completion / 
fracturing 

Flowback 

Flow testing 

Final reserve 
estimate 

Development plan 

1-2 years 

Assessment 

Extended flow testing 

Evaluate technical and economic 
viability for the whole project and 
develop plans for production 

Licensing 

Production licence 

Development and 
production 

Apply for licence for production 

Extract oil and gas for production 
purposes.  Many more wells will be 
drilled for UFF than for CFF at more 
locations and at a higher density of 
locations per unit area 

Production wells 

Planning 

7 to 40 
years 

10 to 1,000 
wells 

2 to 100 well 
pads 

Multiple pads and wells 

Pad preparation 

Drilling and fracturing 

Drilling (vertical/ 
horizontal drilling), 
casing & 
completion, 
fracturing & 
flowback 
management) 

Production 

Infrastructure 

Water provision 

Pipelines and / or 
tankers 

Wastewater 
collection and 
transport 

Wastewater 
treatment 

Hydrocarbon 
collection and 
distribution 

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Stage  

Sub-stage 

Main Activity in 
Stage 

Subsidiary 
activities 

Typical 
duration 

Scale of 
operation 

Decommissioning
, restoration and 
aftercare 

Decommissioning 
of above ground 
equipment and 
reclamation 

Plugging of wells 

Removal of well 
pads 

Monitoring 

Notes: The different phases of the exploration process listed in the above have been compiled and adapted from Milieu, 
(2013), CSUR (undated), DMEA (2013), and UKDECC (2013).  This considers development for an entire field (or 
concession).   

Exploration typically begins with a desk study, where all available data and information are collated and used to 
construct a conceptual model of the possible play.  The focus at this stage is on geology and geological structures, 
looking for reservoirs (with potential for gas generation), sealing layers to identify prospective areas.  The results of 
previous exploration efforts may be examined at this stage.  

In the majority of cases, further data collection is then undertaken using non-intrusive surface geophysical 
techniques such as seismic surveys and airborne geophysics to determine the structural composition, configuration 
and faulting of the deep subsurface.  

CFF exploration in particular is focussed on identifying specific geological structures that can retain hydrocarbons, 
in combination with a reservoir.   CFF exploration then proceeds to drilling of a small number of exploration wells 
to test whether there is accumulation of hydrocarbons.  For UFF, specific geological structures are not necessary 
and the entire reservoir is the prospect but exploration may aim to identify ‘sweet spots’ where gas flows are 
higher.  Early exploration wells for UFF are used to collect core samples and to take measurements in the rock but 
are not typically subject to hydraulic fracturing.  However, later exploration or appraisal wells may be hydraulically 
fractured to determine whether gas or oil is present and to test flow rates.  Appraisal and production are 
distinguished by their different objectives but also through their relationship to licensing and permitting 
requirements.  In terms of the technical criteria that distinguish appraisal and production the main difference is in 
the scale of operations at the scale of the concession.  Appraisal typically involves drilling and stimulation of a 
relatively small number of wells, compared to production.  The number of wells is sufficient to obtain samples, test 
the size of the resource (depth and area) and to demonstrate technical and economic viability.  In contrast, 
production seeks to exploit the whole resource to the extent that it is technically and economically viable to do so.  
Production is likely to extend over many years, (20 to 40 years) whereas exploration will be time-limited (often by 
the terms of exploration licences).  It should be noted however, that compared to CFF, UFF is a relatively young 
industry, in which most production has taken place in the last 10 years.  In addition, there have been changes in 
production methods since the earliest wells were drilled.  Consequently, typical well decline rates and lifetimes are 
not well defined (Sandrea, 2012).  For UFF, production at each well peaks early in the life of the well and then 
shows a long-term decline, with initial decline rates of 60% to 80% per year in the early years (Standard and Poor, 

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2011) for US shale gas plays.  Total production per well varies but is estimated to be in the range 3 to 10 billion 
cubic feet (85 to 283 million m3) per well (Standard and Poor, 2011) for a range of US Shales. 

The scale of operations at an individual well pad will be similar at the appraisal stage, to the scale of operations at 
the production stage.  For instance, evaluation wells proposed by Cuadrilla (Cuadrilla Elswick, 2014) at sites in 
Northwest England will involve the drilling and hydraulic fracturing of four wells per single pad at two pads 
followed by extended flow testing for up to one year.  The drilling and hydraulic fracturing operations only differ 
from production in terms of the number of wells and duration of these operations.  

The differences at the scale of the concession in terms of both extent and timescale mean that production is more 
likely to incorporate permanent infrastructure in the form of roads, pipelines, gas production facilities and 
wastewater treatment facilities, whereas appraisal is unlikely to.  

A review of regulatory provisions governing key aspects of unconventional gas extraction (Milieu, 2013) examined 
provisions in the United Kingdom, Spain, Bulgaria, Denmark, Germany, Poland, Lithuania and Romania.  In terms 
of distinguishing exploration and production, the review found that the permitting system for exploration and 
extraction of UFF was the same as for CFF. 

A number of stages can be defined across the well and field lifecycle.  AEA (2012) summarised these stages as:  

•  Stage 1: Site identification and preparation.  Site preparation activities consist primarily of clearing 
and levelling an area of adequate size and preparing the surface to support movement of heavy 
equipment plus design and construction of access routes;  

•  Stage 2: Well design; drilling; casing; cementing; perforation.  The first drilling stage is to drill, case, 
and cement the conductor hole at the ground surface.  A vertical pipe is set into the hole and grouted 
into place.  The second drilling stage is to drill the remainder of the vertical hole.  Surface and 
intermediate casings are constructed, cemented and horizontal bores drilled.  The pipework and 
cement is then perforated, and the wellhead constructed; 

•  Stage 3: Technical hydraulic fracturing.  Water with proppant (typically sand) and chemicals is 

pumped into the well at high pressure;  

•  Stage 4: Well completion and management of wastewater.  During the well completion phase, 

operators need to process flowback and produced water; 

•  Stage 5: Production.  Gas is extracted and put into supply.  Produced water is separated from the gas 

and disposed of; and  

•  Stage 6: Decommissioning/abandonment.  

Within each of these stages there are multiple activities, for example for the hydraulic fracturing stage the 
following sequence of events takes place (CSUR, undated):  

•  Mobilise equipment and fluids to site; 

•  Acid treatment of the well; 

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•  Flush well; 

•  Perforate production tubing; 

•  Rig up equipment; 

•  Pump fluid and  proppant; and  

•  Flush well. 

Hydraulic fracturing in horizontal wells is typically undertaken in stages for discrete intervals of the lateral; up to 
20 hydraulic fracturing stages may be used.  This process typically starts at the furthest extremity of the well and 
works backwards. Each of these stages can be further broken down into sub-stages.  A typical sequence might 
involve (ALL Consulting, 2012): pumping of freshwater to clean out the well followed by an acid flush to remove 
cement from perforations, then a mini-fracture with water then a shut in to measure the formation response, then 
fracture fluid is injected (without proppant), then the proppant is introduced.  

There are only limited technical differences between exploration and production, for example wells are drilled and 
hydraulically fractured using the same methods.  The key distinctions and potential criteria to distinguish between 
the stages are: 

•  Purpose of operation.  For UFF, whilst appraisal of well flow rates requires fracturing and associated 
activities and infrastructure (albeit at a reduced scale and not necessarily permanent), the purpose of 
the operations is not for full-scale production; 

•  Scale of operations. For UFF, production may involve activities at a number of pads and also the 

drilling and fracturing of multiple wells at a single pad.  In this situation, operations at a single well 
pad may continue for months to years and operations across a well field will take place over many 
years; 

•  Infrastructure requirements.  Production of UFF will require additional infrastructure to deliver water 
and remove gas or oil and wastewater.  This infrastructure may include pipelines (e.g. for gas export) 
and roads (e.g. for water and wastewater transport and oil export).  In contrast, exploration will largely 
use road transport; and 

•  Production may also involve the construction of centralised infrastructure. 

Summary 

The overall exploration and production of both CFF and UFF follow a similar process, although there are 
differences in detail of what activities take place in different phases and in the scale of those activities as set out in 
Table 2.2.  Whilst CFF typically develops in sequential stages, UFF may be developed in a series of overlapping 
stages.  There is a distinction between the exploration and production phases of both CFF and UFF in terms of the 
activities and scale of activities and in licensing and permitting.  Exploration and resource appraisal for UFF 
involve drilling and stimulation, the key difference to CFF being the scale of operations.  The differences at the 
scale of the concession in terms of both extent and timescale mean that production is more likely to incorporate 

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permanent infrastructure in the form of roads, pipelines, gas production facilities and wastewater treatment 
facilities, whereas appraisal is unlikely to.  In some cases appraisal may involve extended testing or early 
production hence the boundary with production may be transitional.  The key activities are when hydraulic 
fracturing occurs and when production commences. 

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3.  Comparison of Risks and Impacts of other UFF 

with those of Shale Gas 

3.1 

Introduction 

In Section 2 the technical characteristics of other UFF were compared to shale gas to highlight the similarities and 
differences.  In this section, other UFF are assessed to identify and group similar types of risks and impacts.  

The geological and technical aspects discussed in Section 2 can play a role in categorising UFF.  However, such 
criteria are limited in their capacity to provide categorisation from the perspective of environmental risk and 
impacts.  To enable categorisation by risks and impacts, context needs to be taken into account, for example the 
scale of operations, environmental conditions and operating practice.  The basis of the risk comparison is set out in 
Section 3.2 and the use of an illustrative concession concept to provide a representation of the scale of operations is 
described in Section 5.2.1.  The comparison with shale gas risks and impacts presented in AEA (2012) used ‘per 
well’ as a starting point whilst remaining mindful of cumulative risks; the aim being to identify where risks may 
potentially differ so that required adjustments and further developments could be made to measures to enable 
assessment of potential policy option costs. 

In this section, a critical risk assessment of other UFF is provided together with the scale of likely impacts in 
comparison to the risks and impacts for shale gas.  This information is then used in Section 4 to identify whether 
the measures considered for shale gas are appropriate and proportionate to manage the risks from other UFF.  The 
categorisation of risks and impacts has the following objectives: 

•  Development of a risk matrix for assessment of risks for other UFF compared to shale gas; and 

•  Comparison of the risk and impact profiles of each other UFF group with risks and impacts of shale 

gas activities.  

The risks and measures for shale gas are presented in detail in AMEC (2014) and AEA 2012, the assessment should 
be read in conjunction with the detail presented in these studies. 

3.2 

Approach 

3.2.1 

Introduction 

A two stage approach was developed encompassing: 

1.  A screening stage: identification of risks and impacts of other UFF to take forward to the risk 

assessment and impact evaluation stage by comparing the risks and impacts identified for shale gas 
with those arising from other UFF; 

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2.  Risk assessment and impact evaluation stage: consideration in greater detail of the risks and impacts of 
other UFF that were not screened out in the first stage, or which were identified as additional risks 
compared to those identified for shale gas.  This enabled the identification of those risks for which the 
appropriateness and proportionality of measures already identified for shale gas needed to be 
evaluated. 

This approach involved the development of a risk matrix by which to qualitatively rank the risks identified.  A 
qualitative approach was used due to the lack of quantitative data available across the range of stages and activities 
for UFF.  The comparison with shale gas was based on the per well risks whilst remaining mindful of cumulative 
risks and resulting development footprint arising from concession development, with the aim being to identify 
where risks may potentially differ so that required adjustments to measures could be made.  Risk assessment 
studies such as those by Umweltbundesamt (2013) and also (for CBM in particular) by the Environment Agency 
for England (2014b) and BRGM (2014) were reviewed to provide further information on the characteristics of risks 
presented by other UFF. 

3.2.2 

Stage One: Screening 

The screening stage of the process compared the risks and impacts identified for shale gas with those arising from 
other UFF, specifically tight gas, tight oil and CBM.  In the cases where the level of risk was expected to be 
comparable to shale gas the risk was screened out of the process, because the measures for shale gas are likely to be 
appropriate for the other UFF in these cases.  Only risks that were different to those of shale gas; or those where the 
other UFF risk was new proceeded to the second stage of the assessment. 

The screening process involved the following steps: 

1.  A high-level identification of risks and impacts.  These were grouped into categories to allow comparison 
with published work on the risks and impacts of shale gas.  Categories were assigned on the basis of the 
stages identified in AEA (2012), which follows the development cycle at a single well pad including 
exploratory stages, followed by well completion, production and ultimately well abandonment phases; 

2.  Comparison of risks and impacts.  Risks and impacts were classified by comparison to shale gas as 

‘comparable’, ‘potentially more significant’ or ‘potentially less significant’16.  The comparison was based 
on literature and expert judgement.  Where risks and impacts were identified as ‘comparable’ then no 
further assessment was undertaken, whereas non-comparable risks were taken forward for assessment of 
measures; 

3.  Identification of new risks and impacts.  Due to the differences between the ways in which other UFF are 
developed, there are potentially some additional risks and impacts to those identified for shale gas.  Where 

16 Comparable - expected to have similar magnitude and frequency to shale gas.  Potentially more significant - expected to have greater magnitude and/or greater 
frequency than shale gas.  Potentially less significant - expected to have lower magnitude and/or lower frequency than shale gas.  For example, if an UFF has a 
much lower injected water volume requirement for fracturing than shale gas, the risk related to water resource depletion is potentially less significant due to lower 
magnitude.  The term ‘potentially less significant’, does not mean that a risk is guaranteed to be smaller as the scale of operations could be the same as for shale 
gas (which is possible) and so measures may be required to be the same/similar as the risk level may be comparable to that of shale gas.. 

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additional risks and impacts were identified for other UFF they were assigned to development stages and 
grouped in the same way as the risks and impacts for shale gas. 

The completion of the screening stage provided a ‘screened list’ of risks and impacts to take forward to the risk 
assessment and measure evaluation stage.   

3.2.3 

Stage Two: Risk and Impacts Assessment Evaluation Stage 

The objective of this stage was to consider in greater detail the risks and impacts of other UFF that were identified 
as non-comparable with those of shale gas (potentially more or less significant), or which were in addition to those 
identified for shale gas.  The purpose of this exercise was to identify those risks for which the appropriateness and 
proportionality of measures already identified for shale gas needed to be evaluated.  

Risk Matrix 

A risk matrix (Figure 3.1) based on King (2012), which is similar to that set out in AEA (2012) was used to score 
risks.  The matrix is not identical to that used in AEA (2012) as it incorporates subsequent developments e.g. in 
terms of number and type of descriptions of risks and impacts developed in AMEC (2014) study on shale gas.  The 
matrix in Figure 3.1 has been adapted to retain the salient elements of the table presented by King and AEA but 
with further tailoring of the descriptions to help retain continuity with the AMEC (2014) study.  The matrix 
provides a systematic approach to assess risk based on the likelihood that an incident will occur and the potential 
consequence of that incident.  The matrix scores risk as the product of likelihood and consequence.  The highest 
scores are given to combinations of high likelihood and catastrophic consequence (and vice versa).  The risk score 
permits risks and impacts to be compared. 

Risks and impacts for each category were assessed qualitatively based on expert knowledge informed by the 
literature where possible.  In a number of cases the literature reviewed provides anecdotal experiences of UFF or 
estimated values.  Where possible the risks were reviewed using the quantitative data available.  Where this was not 
the case the available literature was considered as it provides valuable industry insight into the nature of the 
activities and risks presented.  For those risks that are similar to shale gas but which differ for other UFF in terms 
of likelihood or scale of consequences the focus of the assessment was on identifying whether the risks are 
potentially higher or lower for other UFF compared to shale gas.  

The approach then adopted the following steps to use the risk matrix in evaluating the identified risks from Task 1: 

Step 1:  Consider the AEA (2012) assessment of risks.  The AEA work characterises the potential risks that 
would occur if specific mitigation in relation to the risks posed by shale gas extraction (i.e. specific to shale 
gas only) are not implemented. 

Step 2:  Based on the AMEC (2014) work on shale gas and considering further mitigation where measures 
are likely to be applied, consider whether the AEA (2012) risk ranking needs to be adapted. 

Step 3:  Map the results of steps 1 and 2 onto the risk matrix developed for this study. 

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Step 4:  Review other UFF types to consider whether risks are comparable or potentially smaller/greater 
than for shale gas. 

Measures that mitigate environmental risk may already be expected to be adopted by operators (e.g. due to standard 
industry practice, or to minimise financial risk of investments).  It was assumed therefore, that measures that are 
likely to be applied17 by operators are in place to mitigate risk when using the matrix to assess the degree of risk 
(part of steps 2 and 4). 

The consequences of the risk were assessed in terms of impact on the environment only, and effects on humans via 
environmental pathways.  The evaluation did not assess direct human health risks from incidents as this was 
specifically excluded from the study terms of reference.  The definitions derived for consequences and risks are 
based on the nomenclature of King (2012) and AEA (2012) with some further interpretation to account for the 
setting of other UFF.  This additional tailoring of descriptions and scope was necessary to allow the matrix to be 
used for all UFF types; and strikes a balance with a recognised and previously used system within the current 
context of this study. 

Figure 3.1  Risk Matrix 

Consequence of Incident 

1 

2 

3 

4 

5 

Slight 

Minor 

Moderate 

Major 

Catastrophic 

No data 

N
o
t

l

c
a
s
s
i
f
i
a
b
e

l

1  Extremely Rare 

2  Rare 

3  Occasional 

4 

Likely 

5  Highly Likely 

No data 

t
n
e
d
i
c
n

I

f
o
d
o
o
h

i
l
e
k
i
L

1 

2 

3 

4 

5 

2 

4 

6 

8 

10 

3 

6 

9 

12 

15 

4 

8 

12 

16 

20 

5 

10 

15 

20 

25 

Not classifiable 

Key 

Colour 

Level of Risk 

Low 

Moderate 

High 

Very High 

Score 

1 – 4 

5 – 8 

9 – 12 

15 – 25 

17 See section 3 and Table E2 in Appendix E of AMEC (2014). 

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Consequence 

Consequence was assigned as follows:  

•  Slight.  These are incidents which will have immediate but short term impact on the environment 

which naturally remediate after a few days/weeks. Where the severity is ‘low’, it would have direct 
impact on environment with noticeable effects, but these would be limited, i.e., not causing death of 
flora and fauna.  An example of a short term, low severity incident within the ‘slight’ category is 
drilling equipment running with poor efficiency causing a short term spike in the concentration of air 
pollutants (such as oxides of nitrogen and oxides of sulphur) which would affect people and the 
environment.  Once the issue was rectified effect on people and environment would return to pre-
incident conditions within a few hours/days. 

•  Minor.  These are incidents which will have both an immediate and longer term effect (e.g. 

weeks/months) and take a number of months for the environment to naturally remediate, or require 
physical intervention to remediate the effects.  The level of severity is again ‘low’, i.e. they will have a 
noticeable effect on environment without causing widespread death of flora and fauna.  An example of 
an intermediate term, low severity event is a minor leak from the well head which causes land 
contamination by produced fluid. 

•  Moderate. These are incidents which will have an immediate and long term (e.g. years) effect on the 
environment.  Severity will be ‘low’, including chronic but not fatal effects on the environment.  An 
example of a long term, low severity incident might be a loss of produced water at surface level 
(containing remaining fracturing fluids and other contaminants) into waterways causing an increase in 
concentrations of NORM and metals in river sediments. Effects will be likely to last for several years 
without direct intervention but dilution rates will limit the effects of the raised levels. 

•  Major. These are incidents which will have an immediate effect both on a short term basis 

(hours/days) and also longer term (weeks/months/years).  However these events can be remediated 
with direct intervention within a number of weeks of the incident.  The level of severity in these 
incidents will be high causing widespread death to flora and fauna with significant impact on 
ecosystems and local populations, but with managed response the effects should be short term.  An 
example of a short term high severity incident classed as ‘Major’ may be a spillage of large volumes 
of undiluted chemicals into a waterway causing severe effects on aquatic health. 

•  Catastrophic. These are incidents which will have an immediate and prolonged effect on the 

environment lasting several years.  The effects of the incident will be severe and widespread causing 
death to flora and/or fauna or irreversible damage to the environment for several years.  The incident is 
also potentially likely to damage natural resources in an irreversible fashion requiring several years for 
the environment to return to pre-incident conditions.  An example of a long term, high severity 
incident might be extensive contamination of a groundwater aquifer with hazardous and non-
degradable fracturing chemicals. 

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Likelihood 

The following likelihood categories have been used.  The assessment assumes that mitigation measures likely to be 
applied by industry (BAU measures) are in place18.  Cases where such measures are not in place would have a 
higher likelihood. 

•  Extremely rare.  No known events of the risk under review have taken place within the industry 

within Europe or elsewhere. 

•  Rare.  Incidents may have occurred within the industry (Europe or elsewhere) previously but at a very 

low frequency. 

•  Occasional. These are incidents that should not occur under standard practices.  These incidents will 
however be more common place, for example those that are known to have happened historically at 
several companies during operations in Europe or elsewhere.   

•  Likely. These are incidents which are likely to occur.  The frequency of events is more difficult to 
predict, but should be assumed to have happened several times per year at different operating 
companies.  

•  Highly likely. These are incidents which are highly likely to occur.  The frequency of events is more 
difficult to predict, but should be assumed to occur several times per year (or all the time) in each well 
location.  Incidence of the issue is well documented within the industry with good practice guidelines 
warning of its potential. 

3.3 

Stage One: Screening 

The assessment of risks and impacts for other UFF and the comparison to shale gas involved grouping risks into the 
stages of exploration and production described in Section 2.3 for consistency with the six stage approach in AEA 
(2012).  The risks and impacts for the other UFF (tight gas, tight oil and CBM) have been reviewed against these 
stages.  For each of the stages a range of aspects were examined19: 

•  Groundwater contamination; 

•  Surface water contamination; 

•  Water resource depletion; 

•  Air20; 

•  Land take; 

•  Biodiversity; 

18 See section 3 of AMEC (2014) for a full description of the approach and Appendix B of this report. 
19 Regarding potential risks to soil quality, these are accounted for within groundwater contamination and surface water. 
20 Includes emissions of greenhouse gases. 

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•  Noise; 

•  Visual Impact; 

•  Seismicity; and 

•  Traffic. 

Screening Results 

The results of the screening phase consider the main differences in risks and impacts, at each stage, between shale 
gas and other UFF.  The results show that the differences are predominantly within the technical hydraulic 
fracturing, well completion and production stages.  

The results also show that CBM is more markedly different than other types of UFF when compared to shale gas 
and also different from tight gas and tight oil.  These differences arise due to the different properties of the 
reservoir (coal is typically thinner and more brittle than shale and tight sand), the typically shallower depth, the 
lower pressures for hydraulic fracturing, and the higher quantity and different characteristics of produced waters 
associated with the requirement to lower hydrostatic pressure.  Those stages marked as ‘comparable’, had no 
specific risks that resulted in impacts that were significantly different to shale gas and thus no risks from these 
highlighted stages were carried through to stage 2 of the risk assessment.  

Table 3.1 provides a full breakdown of the results of the screening stage.  A discussion for each UFF and stage of 
the fracturing process provided below.  To avoid repetition, tight gas and tight oil are discussed together with 
specific differences relevant to this study indicated (e.g. where gas and oil present contrasting risks or impacts due 
to the difference in the nature of the hydrocarbon). 

Tight Gas and Tight Oil 

The extraction of tight gas and tight oil follows closely related processes to those seen for shale gas.  As such the 
associated risks and impacts from these processes will also be largely similar.  The results of the screening process 
for tight gas and tight oil are therefore discussed here together out of practicality.  There are differences for tight oil 
in surface processes due to differing production and export requirements however, these are comparable with 
conventional oil operations and hence are BAU and addressed through existing industry practice and regulatory 
requirements (such existing practices are not the main focus of this study).  Where differences arise in the risk 
screening of tight gas and tight oil, this is indicated. 

The screening process involved reviewing the identified risks and impacts based on the six stages of the process 
outlined in Section 2.  The findings of this screening process are summarised below.  The stages are consistent with 
those used in AEA 2013 to ensure a consistent approach.  The typical duration and scale of operations over the 
lifecycle stages of development are indicated in Table 2.2. 

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1. Well pad site identification and preparation 

The identification of suitable sites for well placement, preparation of ground and movement of materials using 
heavy equipment are all processes which mirror the technical requirements of site preparation for extraction of 
shale gas.  The associated risks and impacts of these processes will also therefore be mirrored between shale gas 
activities and those seen for tight gas and tight oil.  In terms of the scale of the activity tight oil and tight gas may 
have comparable pad size to shale gas and concession size for tight gas and tight oil could potentially be of a 
similar size21 to that anticipated for shale gas, with the size of the geological formation being the limiting factor 
(Centrica, 2010).  Consequently risks presented at this stage are considered comparable. 

2. Well design, drilling, casing and cementing 

Tight gas and tight oil will follow the same processes as for shale gas during the drilling, cementing of pipes and 
establishment of wells prior to fracturing.  These processes use the same technology during the development of 
pads and wells prior to the hydraulic fracturing stage.  Due to these similarities in the nature and scale of activity 
the associated risks and impacts will also be similar between shale gas extraction and tight gas and tight oil.  
Therefore the risks identified during this stage of the process will be comparable with those seen for shale gas. 

3. Technical hydraulic fracturing stage 

The hydraulic fracturing process for tight gas and tight oil is broadly similar with the main difference being the 
volume of fluid required during fracturing.  Ranges of required fluid for fracturing per well per fracturing event are 
(see Appendix A) based on information from a review of literature: 

•  Shale gas 7,600 – 34,100 m3 (estimate 15,000m3) 

•  Tight gas 100 – 12,000 m3 (estimate 6,000m3) 

•  Tight oil 500 – 25,600 m3 (estimate 11,400m3) 

This demonstrates that as a range, the values broadly overlap between shale, tight gas and tight oil (the variation 
partly influenced by formation depth and horizontal distance of the well, e.g. with the Bakken oil play wells being 
longer than for shale gas as are tight gas wells in the US Rockies gas play).  However based on an ‘estimate’ for 
water demand during fracturing, tight oil and tight gas require less water, this is particularly the case for tight gas 
which is significantly lower than tight oil and shale gas.  The associated risks and impacts for water resource 
depletion within tight gas and tight oil operations may also be correspondingly potentially less significant than for 
shale gas (assuming the same location specific water resource availability conditions); noting the marked difference 
between tight gas and shale in particular.  On this basis the volume of traffic required to transport water to site 
would also be potentially lower than shale gas operations.  This in turn would result in potentially less significant 
risks and impact from traffic to and from site during the hydraulic fracturing stage. 

For tight oil, it is possible that risks and impacts on groundwater contamination arising from migration of oil 
underground could be potentially less significant (rather than comparable as for tight gas) than for shale gas as the 

21 Note however that current tight gas operations in Germany are of limited scale. 

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heavier hydrocarbon will be less mobile in the underground environment than is the case for tight gas.  For 
groundwater contamination arising from surface operations (e.g. due to spills), risks and impacts are potentially 
more significant than for shale gas due to the liquid rather than gaseous nature of the hydrocarbon that will require 
contrasting risk mitigation measures (e.g. to prevent and/or control spillage).  On balance taking account of BAU 
risk mitigation measures22, risks and impacts for tight oil are judged comparable to tight gas. 

4. Well completion 

The well completion stage includes those activities post-fracturing and in preparation of gas/oil production and 
capture.  Reported percentage flowback volume ranges are (see Appendix A): 

•  Shale gas 50%23 

•  Tight gas 17-35% (estimate 25%) 

•  Tight oil 10-60% (estimate 35%) 

Again values are presented as a range with a degree of overlap particularly for shale gas and tight oil.  The 
‘estimate’ for flowback suggests that tight oil may produce less flowback than shale.  For tight gas the flowback 
expected from fracturing processes is lower than shale gas.  This may lead to smaller volumes of flowback which 
have to be managed during the well completion stage and hence potentially less significant related risks for tight 
gas.  For tight oil, flowback may have different composition to shale gas as heavier hydrocarbons (oil) may be 
present.  Oil water mixtures are easily treated by separation and will be a BAU requirement under existing practice 
and regulatory requirements24 hence risks arising from flowback remain comparable overall, once the impact of 
BAU measures is taken into account. The key difference in this case will relate to the volume of traffic assuming 
flowback is removed from site using tankers.  

As noted above under the technical hydraulic fracturing stage, it is possible that risks and impacts on groundwater 
contamination for tight oil may differ from shale gas but on balance are judged comparable overall. 

5. Production 

During the production stage gas/oil is collected from the wells.  This will involve similar processes and associated 
risks for shale gas operations as for tight gas and tight oil.  Typically during this phase the flow of gas/oil is 
determined by a variety of factors relating to the geological nature of the well.  Re-fracturing may be required to 
maximise production from a well and extend the useful life span of producing wells.  Tight gas operations are 
expected to potentially require less water than shale gas operations during the fracturing stage (ICF, 2013), it is 
likewise assumed that less water would also be required for re-fracturing activities.  Just as within the technical 
hydraulic fracturing stage the reduced water requirements for tight oil and tight gas means that the burden and 
associated risks on water resource depletion will be potentially less significant than seen in shale gas.  Equally the 

22 E.g. tank bunding, double-skinned storage tanks, tank level alarms, provision of spill kits, impervious underlay to the site and monitoring arrangements. 
23 50% was used in AMEC (2014) as a reference point referring to work carried out by the Joint research centre.  A range of 0-75% has been reported (AEA (2012)). 
24 I.e. the requirement to meet Water Framework Directive requirements and related discharge consent conditions for treated wastewater. 

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volume of traffic required to transport these materials (i.e. water used for fracturing and waste water) to and from 
site will also be potentially less significant resulting in reduced impact and risks associated with traffic.  Traffic 
will also be associated with the management of produced water from the well during production.  Produced water 
generation is highly variable25 in UFF formations depending on a range of factors such as conditions at the time of 
deposition, rock porosity and connections to groundwater systems.  Traffic associated with produced water 
management for tight gas is assumed to have a similar range of activity as that for shale gas. 

As noted above under the technical hydraulic fracturing stage, it is possible that risks and impacts on groundwater 
contamination for tight oil may differ from shale gas but on balance are judged comparable.  In addition, as noted 
under the completion stage, risks and impacts arising from flowback from tight oil remain comparable; the same 
will also be the case for risks and impacts from produced water where oil may also be present.  For tight oil, 
infrastructure to capture gas from tight oil is assumed to be in place in line with Recommendation 2014/70/EU 
(European Commission 2014)26; and regarding traffic, although there will be increased releases to air arising from 
trucks required to transport oil (pipeline transport is not assumed), flowback generation (from assumed refracturing 
in the production stage) is lower than for shale gas (see technical hydraulic fracturing and completion stages 
above), hence risks and impacts are judged comparable to shale gas. 

Regarding tight oil, there has been issues raised in North America regarding the risks of handling of oil from tight 
oil wells compared to those of handling oil from conventional wells stemming from accidents in the transportation 
of oil from tight oil wells in the Bakken formation.  The incidents with the Bakken formation relate to a series of 
derailments of railway trucks during 2013-14 resulting in oil spills and in some cases, fires.  The accidents were a 
result of poor railway operating practices and infrastructure and incorrect hazard classification of the oil.  This 
resulted in an emergency order being placed on the transportation of crude oil from Bakken shales by rail with 
specific conditions27.  Tight and shale oil from Bakken and Eagle Ford are characterised by batch to batch 
variability, gravity ranges of 20-55o API (i.e. can be heavy or light crudes), low sulphur levels, potentially elevated 
H2S and may contain dissolved gas (methane).  This variability (and associated issues of corrosivity and 
flammability) is found across the continuum of crude oil, whether from tight/shale formations or conventional 
formations.  Crude oil extracted by conventional methods may also contain highly volatile gases, and corrosive 
substances (e.g. sour wells in the North Sea with high H2S levels).  The issues with oil from Bakken shales is 
related to poor practice in incorrect classification of materials (against existing regulations) and poor railway 
operating practices and infrastructure resulting in railroad accidents involving light crude containing light fractions 
with low flashpoints.  Such risks may also be associated with oil produced from conventional wells and hence are 
not specific to oils from tight formations. 

25 E.g. Mantle (2011) indicates ranges of 0.03-0.13 litres produced water/m3 gas with variations also across the early and later stages of well life cycle. 
26 This states that Members States should ensure that if an installation’s primary purpose is producing oil using high-volume hydraulic fracturing, specific 
infrastructure that captures and transports associated natural gas should be installed. 
27 Recommendations were made in early 2014 by the Department of Transport’s (DoT’s) Pipeline and Hazardous Materials Safety Administration (PHMSA) 
regarding properly classifying hazardous materials and reviewing railroad operating practices (e.g. speed restrictions, braking signal propagation systems, routing 
analyses, additional track and rail integrity inspections, more frequent mechanical inspections).  The PHMSA issued a Safety Alert, noting the potential variability of 
crude oil (and that such variability may affect the integrity of packaging or present additional hazards related to corrosivity, sulphur content, and dissolved gas 
content).  Due to concerns over improper classification and packaging of crude oil, the DoT also issued an Emergency Order requiring all shippers to test products 
from the Bakken to ensure the proper classification of crude oil in accordance with the Hazardous Materials Regulations (HMR) before it is transported by rail, while 
also prohibiting the transportation of crude oil in the lowest-strength packing group (the Emergency Order can be accessed here: http://www.dot.gov/briefing-
room/emergency-order). 

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6. Well abandonment 

The final management and closure of a well site once gas/oil production has fallen below viable levels will involve 
a similar set of activities and processes for tight oil, tight gas and shale gas operations.  As these activities and the 
associated risks and impacts are broadly similar regardless of the UFF type the identified risks for this stage will be 
comparable to those for shale gas.  The screening process therefore did not identify any specific items to carry 
forward into the subsequent risk evaluation stage. 

Coal Bed Methane 

The processes, activities and associated risks and impacts for CBM are markedly different from tight oil and tight 
gas, and also for shale gas operations.  This reflects the differences in drilling depth and well arrangements, 
geology of the rock associated with CBM and required process of gas extraction.  The results of the screening stage 
are summarised below. 

1. Well pad site identification and preparation 

As with the other types of UFF and shale gas operations, the identification and preparation phase involves the 
management of surface operations, including excavation and development of well pads for drilling.  However CBM 
operations will typically have smaller well pads than the other types of UFF mentioned (Halliburton, 2008).  The 
Environment Agency for England (2014a) quotes 0.5 hectares per pad.  The smaller scale of the operation and 
equipment required means that the burden on traffic will be potentially less significant than for shale gas 
operations.  Equally the associated air emissions with heavy fuel powered equipment would be expected to be 
potentially less significant than for shale gas, either through the smaller size of equipment, shorter duration of 
work, or both.  The ‘land take’ aspect is more difficult to evaluate: smaller pad sizes should potentially mean 
reduced land take, however Ewen et al. (2012) suggest that CBM wells form a different arrangement to tight gas, 
tight oil and shale, with multiple vertical wells grouped together and then branching out horizontally below ground 
to allow fracturing.  This makes it unclear whether potential land take is genuinely smaller than shale gas or 
broadly comparable. 

2. Well design, drilling, casing and cementing 

During the establishment of wells, including the drilling of boreholes, the shallower depth used for CBM will be 
the key difference between CBM and shale gas operations.  The shallower depth means that smaller rigs are 
required to drill and less material is required for casing and cementing due to shorter wells.  The CBM operation 
carried out within Falkirk, Scotland28 also suggested that during the well drilling stage, due to shallower depth, the 
work was able to be completed in a shorter time than typically seen in shale gas operations.  Within the Falkirk 
CBM operation each vertical well was completed within 14 days with four horizontal bores completed by an 
additional 90 days (in total 22.5 days per horizontal bore) (Dart Energy, 2012) 29.  As a comparison AMEC (2014) 
quotes shale gas operations taking up to 27 days per vertical well and 25 days for each horizontal bore drilled.  The 
shorter drilling period and smaller equipment will mean the potential risks and impacts for releases to air from 

28 Note that the Falkirk operations do not include hydraulic fracturing. 
29 Reduced material requirements and timescales relate to shallower depths rather than the absence of fracturing. 

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power generation plant would be potentially less significant than seen with shale gas.  Equally the reduced need for 
materials would mean a reduction in the volume of traffic and potentially less significant associated risks and 
impacts compared to shale gas. 

3. Technical hydraulic fracturing stage 

During the fracturing stage of the process the key elements that differ from shale gas operations are the depth at 
which fracturing occurs within the rock and the volume of fluid required for fracturing.  These aspects may both 
increase and decrease the associated specific risks and impacts for CBM (in different ways) compared to shale gas.  
CBM fracturing typically occurs at a shallower depth (500 to 1,500 m, see Table 2.1) than shale gas (e.g. 3,000 m) 
which places it closer to groundwater resources.  There will therefore be less separation between CBM and water 
resources than is the case for most tight oil, tight gas and shale operations.  The associated risks and impacts for 
groundwater contamination are therefore potentially more significant for CBM compared to shale gas (if not 
mitigated effectively).  Equally the risk of fugitive emissions from CBM finding their way through rock strata to 
the surface is potentially more significant for CBM compared to shale gas operations.  This reflects the typically 
shallower depth of the fracturing and a potential for a more significant risk of fugitive gas seepage through rock 
within CBM operations (Ewen et al. 2012).  In contrast, there is potential for groundwater contamination risks and 
impacts arising from migration of gas and groundwater migration from deeper CBM target formations (i.e. at a 
depth of 1,500m or more) to be comparable to shale gas (due to a greater distance from groundwater sources and an 
increased potential for geological barriers resulting in a impeded or obstructed risk pathway). 

Ranges of required fluid for fracturing per well in both CBM and shale are (see Appendix A): 

•  Shale gas 7,600 – 34,100 m3 

•  CBM 0 – 4,700 m3 

Lower volumes of water are required during the fracturing operations for CBM compared to shale gas.  The 
reduced water demand will mean that the risk of water resource depletion for CBM is potentially less significant 
than for shale gas.  Equally, lower water requirements during fracturing will reduce the number of vehicles required 
to transport material to and from site and hence traffic burden and its associated risks and impacts for CBM will be 
potentially less significant than that seen within shale gas operations. 

4. Well completion 

The well completion stage will include those activities post-fracturing before gas generation commences.  This 
includes the management of flowback.  As CBM requires lower quantities of water during fracturing compared to 
shale gas operations, the volume of fluid as flowback will also be correspondingly less.  Reported percentage 
flowback volume ranges are (see Appendix A): 

•  Shale gas 50% 

•  CBM 61-82% 

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Whilst percentage flowback is higher, volumes will be lower due to the lower volume of water injected and hence 
the volume of traffic required to remove wastewater for treatment is lower.  The traffic burden and associated risks 
and impacts for CBM will be potentially less significant than for shale gas.  

5. Production 

During the production stage, to maximise production and extend life span of wells, operators may carry out re-
fracturing.  The reduced water demand requirements (compared to shale gas) highlighted during the fracturing 
stage is likely to mean that water demand during re-fracturing is also lower for CBM compared to shale gas.  This 
means that the associated risks and impacts for water resource depletion will be potentially less significant for 
CBM compared to shale gas. 

Conversely the shallower depth of fracturing for extraction of CBM and closer proximity to groundwater resources 
means that the risks and impacts for groundwater contamination and fugitive emissions to air from seepage in rock 
are potentially more significant for CBM compared to shale gas operations.  However, for deeper CBM target 
formations (i.e. at a depth of 1,500m or more) the potential for fugitive emissions to air from gas migration is likely 
to be more comparable to that of shale gas due to a greater depth and an increased potential for geological barriers 
resulting in a impeded or obstructed risk pathway.  There is potential for groundwater contamination risks and 
impacts arising from migration of gas and groundwater migration from deeper CBM target formations to be 
comparable to shale gas as noted under the technical hydraulic fracturing stage above. 

An important additional element to consider with CBM operations during production is the management of 
produced water.  Unlike tight oil, tight gas and shale gas reservoirs where the hydrocarbons are trapped within 
rock, gas associated with CBM adsorbs to the surface of coal.  It is necessary to create the correct pressure balance 
to enable desorption of the gas through pumping of groundwater from the target formation. This results in a 
significant quantity of produced waters for CBM (up to 65m3 per day/per well (IEA, 2012)).  The volume of traffic 
required to transport the volume of produced water to the point of treatment/discharge will therefore also be greater 
(unless pipelines are in place to transfer the produced water).  The traffic burden and associated risks and impacts 
for CBM may be potentially more significant compared to shale gas.  The abstraction of groundwater also presents 
a risk to water resources in overlying or lateral formations where a hydrogeological connection exists.  Shale gas is 
found in less permeable formations, typically at greater depth and separated from fresh water resources by a large 
distance.  There is, therefore a potentially more significant impact from CBM on water resources compared to shale 
gas during production due to its greater potential proximity to potable resources.  

6. Well abandonment. 

The final stage of the fracturing process is well abandonment and closure of the site.  These are activities which 
will be similar across all of the UFF types discussed here.  On this basis the identified risks and impacts for CBM 
are expected to be comparable to those of shale gas.  

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Table 3.1 

Screening – Comparison of Other UFF and Shale Gas Risks and Impacts (per well basis) 

Stage 

Aspect 

Tight gas 

Tight oil 

CBM 

1. Well pad site identification and 
preparation 

Groundwater contamination 

Not applicable 

Surface water contamination risks 

Comparable 

2. Well design, drilling, casing and 
cementing 

Water resource depletion 

Releases to air 

Land take 

Biodiversity impacts 

Noise 

Visual impact 

Seismicity 

Traffic 

Groundwater contamination 

Surface water contamination risks 

Water resource depletion 

Releases to air 

Land take 

Biodiversity impacts 

Noise 

Not applicable 

Comparable 

Comparable 

Not classifiable 

Comparable 

Comparable 

Not applicable 

Comparable 

Comparable 

Comparable 

Not applicable 

Comparable 

Not applicable 

Comparable 

Comparable 

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Not applicable 

Comparable 

Not applicable 

Comparable 

Comparable 

Not classifiable 

Comparable 

Comparable 

Not applicable 

Comparable 

Comparable 

Comparable 

Not applicable 

Comparable 

Not applicable 

Comparable 

Comparable 

Not applicable 

Comparable 

Not applicable 

Potentially less significant 

Not classifiable 

Not classifiable 

Comparable 

Not classifiable 

Not applicable 

Potentially less significant 

Comparable 

Comparable 

Not applicable 

Potentially less significant 

Not applicable 

Comparable 

Comparable 

 
 
 
 
 
 
  
  
  
  
  
  
  
  
  
  
  
  
  
43 

Stage 

Aspect 

Visual impact 

Seismicity 

Traffic 

3. Technical hydraulic fracturing 

Groundwater contamination 

Surface water contamination risks 

Tight gas 

Tight oil 

CBM 

Comparable 

Not applicable 

Comparable 

Comparable 

Comparable 

Comparable 

Not applicable 

Comparable 

Comparable 

Comparable 

Comparable 

Not applicable 

Potentially less significant 

Potentially more significant* 

Comparable 

Water resource depletion 

Potentially less significant 

Potentially less significant 

Potentially less significant 

Releases to air1 

Land take 

Biodiversity impacts 

Noise 

Visual impact 

Seismicity 

Traffic 

4. Well completion 

Groundwater contamination 

Surface water contamination risks 

Water resource depletion 

Releases to air 

Land take 

Biodiversity impacts 

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Comparable 

Not applicable 

Comparable 

Comparable 

Comparable 

Comparable 

Comparable 

Not applicable 

Comparable 

Comparable 

Comparable 

Comparable 

Potentially more significant 

Not applicable 

Comparable 

Comparable 

Comparable 

Comparable 

Potentially less significant 

Potentially less significant 

Potentially less significant 

Comparable 

Comparable 

Not applicable 

Comparable 

Not applicable 

Comparable 

Comparable 

Comparable 

Not applicable 

Comparable 

Not applicable 

Comparable 

Comparable 

Comparable 

Not applicable 

Comparable 

Not applicable 

Comparable 

 
 
 
 
 
 
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
44 

Stage 

Aspect 

Noise 

Visual impact 

Seismicity 

Traffic 

5. Production 

Groundwater contamination 

Surface water contamination risks 

Tight gas 

Tight oil 

CBM 

Not classifiable 

Not applicable 

Comparable 

Not classifiable 

Not applicable 

Comparable 

Not classifiable 

Not applicable 

Comparable 

Potentially less significant 

Potentially less significant 

Potentially less significant 

Comparable 

Comparable 

Comparable 

Comparable 

Potentially more significant* 

Comparable 

Water resource depletion 

Potentially less significant 

Potentially less significant 

Potentially less significant 

Releases to air 

Land take 

Biodiversity impacts 

Noise 

Visual impact 

Seismicity2 

Traffic 

Comparable 

Comparable 

Comparable 

Comparable 

Comparable 

Comparable 

Comparable 

Comparable 

Comparable 

Comparable 

Comparable 

Comparable 

Potentially more significant* 

Not classifiable 

Comparable 

Comparable 

Comparable 

Comparable 

Potentially less significant 

Potentially more significant 

Potentially more significant 

6. Well / site abandonment 

Groundwater contamination 

Not classifiable 

Surface water contamination risks3 

Not applicable 

Water resource depletion4 

Releases to air 

Land take 

Not applicable 

Comparable 

Not classifiable 

Not classifiable 

Not applicable 

Not applicable 

Comparable 

Not classifiable 

Not classifiable 

Not applicable 

Not applicable 

Comparable 

Not classifiable 

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45 

Stage 

Aspect 

Tight gas 

Tight oil 

CBM 

Biodiversity impacts 

Noise5 

Visual impact 

Seismicity 

Traffic 

Not classifiable 

Not applicable 

Not classifiable 

Not applicable 

Not applicable 

Not classifiable 

Not applicable 

Not classifiable 

Not applicable 

Not applicable 

Not classifiable 

Not applicable 

Not classifiable 

Not applicable 

Not applicable 

Notes: 
Comparable: broadly comparable to the risks and impacts of shale gas 
Potentially less significant: has the potential to be less significant than shale gas dependant on aspects such as scale and location specific factors. The term ‘potentially less significant’, 
does not mean that a risk is guaranteed to be smaller as, if the scale of operations is the same as for shale gas (which is possible), measures may be required to be the same/similar as 
the risk level may be comparable to that of shale gas. 
Potentially more significant: has the potential to be more significant than shale gas dependant on aspects such as scale and location specific factors 
Not applicable: aspects that are not relevant to the stage. 
Not classifiable: aspects that are relevant but for which there is insufficient information to enable assessment.  For further information see Section 2 of AEA (2012). 
1 For CBM, potentially more significant releases to air refers to fugitive releases of methane due to likely shallower depth than shale gas and greater potential for methane emigration to 
the surface.  For CBM aspects with an asterisk (*) the comparison may differ for shallow and deep target formations, refer to the screening results discussion for further information. 
2 Refracturing may be needed in the production stage.  In this case risks and impacts would be ‘comparable’ as per the ‘technical hydraulic fracturing’ stage. 
3 Not applicable as no discharges to surface waters at this stage. 
4 Not applicable as no water resource requirements at this stage. 
5 Not applicable as no site production operations at this stage. 

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46 

3.4 

Stage Two: Risk Assessment and Evaluation 

This section presents the findings of the risk assessment.  Those aspects assessed as ‘potentially less significant’ or 
‘potentially more significant’ from the stage one screening process are evaluated.  While the nature and properties 
of tight oil and tight gas represent different technical issues in managing the product extracted, the processes of 
fracturing and extracting the material are the same.  The nature of risks and impacts reviewed in the screening stage 
were generally similar to those of shale gas.  As such, to avoid repetition the discussion for tight oil and tight gas is 
covered here jointly and differences indicated where relevant.  This is followed by the discussion for CBM 
indicating aspects that may differ if target formations are shallow or deep. 

3.4.1 

Tight Gas and Tight Oil 

Table 3.2 presents the risk assessment for tight gas and tight oil on those items carried forward from the screening 
stage.  The general approach to, and technical options for, hydraulic fracturing for tight gas and oil are largely 
similar to those used in shale gas.  Whilst different surface operations are required for tight oil due to the different 
physical nature of the hydrocarbon (e.g. storage, processing, handling, transportation), such operations are 
transferable from the conventional oil industry and will be addressed by existing conventional oil industry practice 
and regulations; the focus for this study is on the aspects specific to tight oil.  No identified risks from stages 1, 2 or 
6 (preparation, design and drilling and well abandonment respectively) were deemed to be non-comparable to shale 
gas operations and so the risk assessment and evaluation phase concentrated on stages 3-5 only (hydraulic 
fracturing, well completion and the production stage). 

The key operational difference that influences associated risks between hydraulic fracturing for both tight gas and 
tight oil and hydraulic fracturing for shale gas are the quantities of water required for hydraulic fracturing.  ICF 
(2013) suggests that tight gas uses between 200 and 7,100 m3/well and tight oil between 5,700 and 25,600 m3/well 
compared to 7,600 to 34,100 m3/well for shale gas during fracturing (the variations partly influenced by formation 
depth and horizontal distance of the well, with the latter noted as being longer than for shale gas in the Bakken tight 
oil play).  While these ranges have some overlap and the authors recognise that the actual volume required will be 
depth and formation specific, potentially the water demand requirements for tight oil and particularly tight gas may 
be lower.  The AEA (2012) report for shale gas ranked the water depletion risk during fracturing as Moderate.  
With the application of BAU and likely to be applied measures as set out in AMEC (2014)30 the risk rating is 
judged to be Low. 

Impacts on air quality are possible due to the potential for greater vehicle movements associated with transporting 
of tight oil during the production stage (pipeline transportation is not assumed).  Risks and impacts associated with 
traffic are potentially less significant for tight gas than for shale gas in both the well completion and production 
stages due to fewer vehicle movements related to water and flowback transportation.  As noted above, traffic 
associated with produced water management for tight gas is assumed to have a similar range of activity as that for 
shale gas traffic (produced water generation being highly variable from UFF formations.  Also noted above, for 

30 Refer to Appendix B for likely to be applied measures for water depletion. 

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47 

tight oil, production stage traffic may be potentially more significant for tight oil than for shale gas due to vehicle 
movements associated with oil transportation. 

Other aspects were evaluated as having broadly similar risk ratings as for shale gas. 

3.4.2 

Coalbed Methane 

Table 3.3 presents a breakdown of the risk assessment for CBM on those items carried forward from the screening 
stage.  The activities and risks associated with CBM will be different to those seen within tight oil, tight gas and 
shale gas, due to the nature of the geology and extraction process.  A summary of key risks and issues is provided 
below: 

•  Stage 1. Preparation – The well pad size for CBM is expected to be smaller for CBM compared to 

shale gas (Dart Energy 2012); although the overall concession size could potentially be similar. The 
smaller well pad size has consequences when preparing ground for well development.  This includes 
smaller equipment or the same size equipment (as shale gas operations) but for shorter durations.  The 
reduced use of heavy machinery means that the risks regarding releases to air, visual impact and traffic 
will likely be lower than shale gas. However the activities within this stage are broadly similar across 
all UFF types including shale gas and therefore as a result the risk rating is deemed similar.  

•  Stage 2. Design, drilling, casing and cementing – As CBM operations generally work at shallower 

depths than shale gas, the required effort for drilling, casing and cementing will be reduced.  This has 
a consequence for the size of the equipment required to carry out the drilling and associated air 
emissions.  Equally the reduction in the quantity of materials required (such as casings) means the 
volume of traffic to and from site will be lower.   

•  Stage 3. Technical Hydraulic Fracturing – The more brittle nature of coal seams and shallower depth 

means that water demand for fracturing is likely to be lower compared to shale gas.  This is turn means 
the equipment required to carry out the operation is smaller as will be the volume of traffic required to 
transport water to the site.  Conversely the shallower depth and increased potential proximity to 
groundwater could potentially present increased risks to groundwater contamination.  The AEA (2012) 
report for shale gas ranked groundwater contamination risk at this stage as High.  With the application 
of specific measures as set out in AMEC (2014) the risk rating is judged to be moderate31.  It is 
possible that groundwater contamination risks differ for shallow and deep wells (where the source of 
contamination is the target formation), with deep wells exhibiting lower risk due to the further 
geological barriers between groundwater resources and gas producing formations. 

•  Stage 4. Well completion – The reduction in water demand during the fracturing stage will also mean 
that there will be a reduction in the quantity of flowback compared to shale gas operations.  This in 
turn means the volume of traffic required to transport the flowback created will be lower than seen in 
shale gas operations. 

•  Stage 5. Production – Similarly to the hydraulic fracturing stage the issue of water demand is key for 
this part of the process also.  CBM production will likely use less water than shale gas operations at 
the same stage while shallower depths increase the risk to groundwater contamination from injected 

31 Refer to Appendix B for information on likely to be applied measures for groundwater. 

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48 

fracture fluid.  As with the hydraulic fracturing stage, it is possible that groundwater contamination 
risks differ for shallow and deep wells (where the source of contamination is the target formation), 
with deep wells exhibiting lower risk due to the further geological barriers between groundwater 
resources and gas producing formations. 

The risk assessment process for CBM also identified new risks which are unique to CBM and were not covered in 
the AEA (2012) review of shale gas or the above assessment of tight gas or tight oil.  Table 3.4 provides a 
breakdown of these risks which relate to the production stage of the process.  The nature of CBM means that the 
gas is adsorbed to the surface of the coal and to promote a flow of gas excess water from the coal seam must be 
pumped out to lower pressure and allow gas to desorb.  This leads to greater quantities of produced water than seen 
within shale gas, tight oil or tight gas.  Furthermore where a negative pressure is created to allow gas to flow it can 
inadvertently draw away fresh water from groundwater sources into the coal seam where it can become 
contaminated.  
The new risks identified are: 

•  Risks of surface water contamination from greater quantities of actively pumped produced water at the 
surface which must be managed and treated to the standard required by permits32.  Increased volumes 
requiring more frequent transport, treatment and discharge may result in an increased risk of surface 
water contamination (e.g. through spillage during transfer, treatment plant failure); 

•  Risks of increased water resource depletion from groundwater supplies being drawn down towards the 

target formation; and 

•  Potential risk of methane seeping through geological strata and being released as fugitive emissions.  
This risk may increase compared to shale gas and tight gas due to the shallower depth and lack of 
barrier rock strata to prevent such gas reaching the surface. 

Measures to address the risks identified in the following tables are discussed in Section 4. 

32 Produced water has variable quality (e.g. USEPA (2013) and Umweltbundesamt (2013)) indicate a range from 7 to 128,000 mg/l total dissolved solids in produced 
water from CBM formations. 

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49 

Table 3.2 

Risk Assessment of Screened Tight Oil (TO) and Tight Gas (TG) Aspects 

Stage 

Aspect 

AEA risk rating 
(shale gas focus) 

Amec Foster 
Wheeler risk rating 
after application of 
measures1 (shale 
gas focus) 

TO and TG 
risks and 
impacts 
relative to 
shale gas 

Risk assessment 

Consequence 

Frequency 

Risk rating 

Reasoning 1 

3. Technical 
hydraulic 
fracturing 

Water 
Resource 
Depletion 

Moderate 

Low 

Potentially less 
significant 

Minor 

Rare 

Low 

Traffic 

Moderate 

Moderate 

Potentially less 
significant 

Minor 

Occasional 

Moderate 

Potentially less significant and likely will be less than 
shale gas due to lower water consumption. 

Application of 'likely to be applied' measures for 
shale gas is judged to reduce frequency from 
occasional to rare on the AEA risk matrix resulting in 
the risk rating reducing from Moderate to Low. 

TO and particularly TG have generally lower water 
consumption than shale gas potentially further 
reducing the potential risk.  Risk rating including 
application of likely to be applied measures is judged 
to be Low. 

Potentially less significant and likely will be less than 
shale gas due to likely fewer vehicle movements. 

Application of ‘likely to be applied' measures for 
shale gas is unlikely to affect the level of activity and 
hence consequence and frequency.  No change 
results in the AEA risk rating. 

TO and particularly TG have generally lower water 
consumption than shale gas potentially reducing 
traffic related aspects.  Measures to mitigate risk for 
shale gas when applied to similar activities for TO 
and TG will have the same effect.  Overall risk rating 
is judged to remain at Moderate. 

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50 

Stage 

Aspect 

AEA risk rating 
(shale gas focus) 

Amec Foster 
Wheeler risk rating 
after application of 
measures1 (shale 
gas focus) 

TO and TG 
risks and 
impacts 
relative to 
shale gas 

Risk assessment 

Consequence 

Frequency 

Risk rating 

Reasoning 1 

4. Well 
completion 

Traffic 

Low 

Low 

Potentially less 
significant 

Slight 

Likely 

Low 

5. Production 

Water 
Resource 
Depletion 

Moderate 

Low 

Potentially less 
significant 

Minor 

Rare 

Low 

Potentially less significant and likely will be less than 
shale gas due to likely fewer vehicle movements. 

Application of ‘likely to be applied' measures for 
shale gas is unlikely to affect the level of activity and 
hence consequence and frequency.  No change 
results in the AEA risk rating. 

TO and particularly TG have generally lower water 
consumption and corresponding flowback than shale 
gas potentially reducing traffic related aspects.  
Measures to mitigate risk for shale gas when applied 
to similar activities for TO and TG will have the same 
effect.  Overall risk rating is judged to remain at 
Moderate. 

Potentially less significant and likely will be less than 
shale gas due to lower water consumption. 

Application of 'likely to be applied' measures for 
shale gas is judged to reduce frequency from 
occasional to rare on the AEA risk matrix resulting in 
the risk rating reducing from Moderate to Low. 

TO and particularly TG have generally lower water 
consumption than shale gas potentially further 
reducing the potential risk.  Risk rating including 
application of likely to be applied measures is judged 
to be Low.  

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51 

Stage 

Aspect 

AEA risk rating 
(shale gas focus) 

Amec Foster 
Wheeler risk rating 
after application of 
measures1 (shale 
gas focus) 

TO and TG 
risks and 
impacts 
relative to 
shale gas 

Risk assessment 

Consequence 

Frequency 

Risk rating 

Reasoning 1 

Traffic 

(TG only) 

Low 

Low 

Potentially less 
significant 

Slight 

Likely 

Low 

TG only 

Potentially less significant and likely will be less than 
shale gas due to likely fewer vehicle movements. 

Application of ‘likely to be applied' measures for 
shale gas is unlikely to affect the level of activity and 
hence consequence and frequency.  No change 
results in the AEA risk rating. 

Produced water volume generation rate is formation 
specific and so assumed to be in a similar range to 
that for shale gas, hence associated traffic is 
assumed to be comparable; however, TG has 
generally lower water consumption and 
corresponding flowback than shale gas associated 
with the fracturing which potentially reduces traffic 
related aspects overall. 

Measures to mitigate risk for shale gas when applied 
to similar activities for TG will have the same effect.  
Overall risk rating is judged to remain at Low. 

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52 

Stage 

Aspect 

AEA risk rating 
(shale gas focus) 

Amec Foster 
Wheeler risk rating 
after application of 
measures1 (shale 
gas focus) 

TO and TG 
risks and 
impacts 
relative to 
shale gas 

Risk assessment 

Traffic 

(TO only) 

Low 

Low 

Potentially 
more 
significant 

Consequence 

Frequency 

Risk rating 

Reasoning 1 

Slight 

Highly likely 

Moderate 

TO only 

Potentially more significant and likely will be more 
than shale gas due to vehicle movements 
associated with transport of oil (pipelines not 
assumed). 

Application of ‘likely to be applied' measures for 
shale gas is unlikely to affect the level of activity and 
hence consequence and frequency.  No change 
results in the AEA risk rating. 

Whilst TO has generally lower water consumption 
and corresponding flowback than shale gas 
potentially reducing traffic related aspects, additional 
vehicle movements are associated with transporting 
TO.  Measures to mitigate risk for shale gas when 
applied to similar activities for TO will have the same 
effect.  Overall risk rating is judged to remain at 
Moderate. 

1. For measures see Appendix B. 

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53 

Table 3.3 

Risk Assessment of Screened CBM Aspects 

Stage 

Aspect 

AEA risk rating 
(shale gas focus) 

Amec Foster 
Wheeler risk rating 
after application of 
measures1 (shale 
gas focus) 

CBM risks 
and impacts 
relative to 
shale gas 

Risk assessment 

Consequence 

Frequency 

Risk rating 

Reasoning 

1. Well pad site 
identification and 
preparation 

Releases to 
air 

Low 

Low 

Potentially less 
significant 

Slight 

Likely 

Low 

Land take 

Moderate 

Moderate 

Not classifiable  Minor 

Likely 

Moderate 

Potentially less significant and likely will be less than 
shale gas due to likely smaller scale operations. 

Application of ‘likely to be applied' measures for 
shale gas is unlikely to affect the level of activity and 
hence consequence and frequency.  No change 
results in the AEA risk rating. 

In comparison to shale gas operations, the 
preparation of and excavation of land for CBM will 
likely either utilise smaller equipment or the same 
equipment for a shorter time period.  This may 
reduce the effects of releases to air from heavy 
machinery.  However this reduction in scale is not 
expected to be sufficient to reduce the overall risk for 
this activity compared to similar activities within 
shale gas.  Therefore the risk level is judged to 
remain the same.  

The land take issue for CBM is not clear.  Existing 
work at Falkirk (Scotland) has significantly smaller 
land take demand with 0.4 hectares per pad 
compared to shale gas which can be up to 2.24 
hectares per pad (AMEC (2014)).  However it is 
possible depending on the well configuration and 
geological resource that concessions could 
potentially be at the same scale as shale gas 
operations.  Therefore overall risk rating is judged to 
match that for shale gas in lieu of further evidence. 

Visual impact 

Low 

Low 

Not classifiable  Slight 

Likely 

Low 

Judgement is Low risk rating. 

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54 

Stage 

Aspect 

AEA risk rating 
(shale gas focus) 

Amec Foster 
Wheeler risk rating 
after application of 
measures1 (shale 
gas focus) 

CBM risks 
and impacts 
relative to 
shale gas 

Risk assessment 

Consequence 

Frequency 

Risk rating 

Reasoning 

Traffic 

Low 

Low 

Potentially less 
significant 

Slight 

Likely 

Low 

2. Well design, 
drilling, casing 
and cementing 

Releases to 
air 

Moderate 

Moderate 

Potentially less 
significant 

Minor 

Occasional 

Moderate 

Traffic 

Low 

Low 

Potentially less 
significant 

Slight 

Likely 

Low 

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Potentially less significant and likely will be less than 
shale gas due to likely fewer vehicle movements. 

Application of ‘likely to be applied' measures for 
shale gas is unlikely to affect the level of activity and 
hence consequence and frequency.  No change 
results in the AEA risk rating. 

The smaller scale of the operation and equipment 
required means that the burden on traffic will be 
potentially less significant than for shale gas 
operations.  This may potentially reduce impacts 
from traffic but not negate them.  Risk rating is 
judged Low. 

Potentially less significant and likely will be less than 
shale gas due to likely smaller scale operations. 

Application of ‘likely to be applied' measures for 
shale gas is unlikely to affect the level of activity and 
hence impacts consequence and frequency.  No 
change results in the AEA risk rating. 

Shorter drilling period and smaller equipment will 
mean the potential risks and impacts for releases to 
air would be potentially less significant than seen in 
shale gas, however it is unclear whether this 
difference is significant enough to impact the overall 
risk rating.  Risk rating is judged Moderate. 

Potentially less significant and likely will be less than 
shale gas due to likely fewer vehicle movements. 

Application of ‘likely to be applied' measures for 
shale gas is unlikely to affect the level of activity and 

 
 
 
 
 
 
 
 
 
 
55 

Stage 

Aspect 

AEA risk rating 
(shale gas focus) 

Amec Foster 
Wheeler risk rating 
after application of 
measures1 (shale 
gas focus) 

CBM risks 
and impacts 
relative to 
shale gas 

Risk assessment 

Consequence 

Frequency 

Risk rating 

Reasoning 

3. Technical 
hydraulic 
fracturing 

Groundwater 
contamination 

High 

Moderate 

Potentially 
more 
significant 

Moderate 

Rare 

Moderate 

Water 
resource 
depletion 

Moderate 

Low 

Potentially less 
significant 

Minor 

Rare 

Low 

© Amec Foster Wheeler Environment & Infrastructure UK Limited 

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hence impacts consequence and frequency.  No 
change results in the AEA risk rating. 

Reduced need for materials and equipment 
compared to shale could reduce the volume of traffic 
and result in a potentially less significant risk.  Risk 
rating is Low and comparable to shale gas. 

Application of 'likely to be applied' measures for 
shale gas is judged to reduce frequency from 
occasional to rare on the AEA risk matrix resulting in 
the risk rating reducing from High to Moderate. 

Potentially more significant due to greater proximity 
to drinking water aquifers due to shallower depth of 
the target formation could result in risks being 
potentially more significant due to the hazard of 
formation fluids and gas migrating through pathways 
in the coal seam.  However, application of the likely 
to be applied measures assumed for shale gas (see 
footnote 31) is judged to mitigate this risk.  For CBM, 
risk rating is therefore judged to be Moderate. 

For CBM target formations at greater depth (e.g. 
>1,500m) it is possible that likelihood will reduce to 
Extremely Rare due the depth and further geological 
barriers between groundwater resources and the 
gas producing formation.  In this case, for deeper 
formations, risk rating may reduce to Low. 

Potentially less significant and likely will be less than 
shale gas due to lower water consumption. 

Application of 'likely to be applied' measures for 
shale gas is judged to reduce frequency from 

 
 
 
 
 
 
 
 
 
 
56 

Stage 

Aspect 

AEA risk rating 
(shale gas focus) 

Amec Foster 
Wheeler risk rating 
after application of 
measures1 (shale 
gas focus) 

CBM risks 
and impacts 
relative to 
shale gas 

Risk assessment 

Consequence 

Frequency 

Risk rating 

Reasoning 

Releases to 
air 

Low 

Low 

Potentially 
more 
significant 

Slight 

Likely 

Low 

Traffic 

Moderate 

Moderate 

Potentially less 
significant 

Minor 

Occasional 

Moderate 

© Amec Foster Wheeler Environment & Infrastructure UK Limited 

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occasional to rare on the AEA risk matrix resulting in 
the risk rating reducing from Moderate to Low. 

CBM has lower water consumption than shale gas 
potentially reducing the potential risk.  Risk rating 
including application of likely to be applied measures 
is judged to be Low 

Potentially more significant due to potential for 
fugitive releases reflecting typically shallower depth 
of fracturing and a potential for more significant risk 
of fugitive gas seepage through rock strata. 

Potentially offset by comparatively smaller scale 
operations than shale gas, hence the equipment 
used during fracturing for CBM will likely either utilise 
smaller equipment or the same equipment for a 
shorter time period.  However this reduction in scale 
is not expected to be sufficient to reduce the overall 
risk for this activity compared to similar activities 
within shale gas. 

Application of ‘likely to be applied' measures for 
shale gas is unlikely change overall risks 
characteristics significantly.  No change results in the 
AEA risk rating. 

The risk rating is judged to be Low. 

Potentially less significant and likely will be less than 
shale gas due to likely fewer vehicle movements 
associated with lower flowback volume. 

Application of ‘likely to be applied' measures for 
shale gas is unlikely to affect the level of activity and 

 
 
 
 
 
 
 
 
 
 
57 

Stage 

Aspect 

AEA risk rating 
(shale gas focus) 

Amec Foster 
Wheeler risk rating 
after application of 
measures1 (shale 
gas focus) 

CBM risks 
and impacts 
relative to 
shale gas 

Risk assessment 

Consequence 

Frequency 

Risk rating 

Reasoning 

4. Well 
completion 

Traffic 

Low 

Low 

Potentially less 
significant 

Slight 

Likely 

Low 

5. Production 

Groundwater 
contamination 

High 

Moderate 

Potentially 
more 
significant 

Moderate 

Rare 

Moderate 

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hence consequence and frequency.  No change 
results in the AEA risk rating. 

CBM has potentially less water consumption and 
linked traffic movements than shale gas.  Measures 
identified to mitigate risk for shale gas when applied 
to similar activities for CBM will have the same level 
of effect.  On this basis the measures identified will 
not further reduce risk for CBM. The risk rating is 
judged to be Moderate. 

Potentially less significant and likely will be less than 
shale gas due to likely fewer vehicle movements. 

Application of ‘likely to be applied' measures for 
shale gas is unlikely to affect the level of activity and 
hence consequence and frequency.  No change 
results in the AEA risk rating. 

CBM has lower potential for flowback volumes 
requiring transportation linked to lower water 
consumption.  Measures identified to mitigate risk for 
shale gas when applied to similar activities for CBM 
will have the same level of effect.  On this basis the 
measures identified will not further reduce risk for 
CBM. The risk rating is judged to be Low. 

Application of 'likely to be applied' measures for 
shale gas is judged to reduce frequency from 
occasional to rare on the AEA risk matrix resulting in 
the risk rating reducing from High to Moderate. 

Potentially more significant due greater proximity to 
drinking water aquifers due to shallower depth of the 
target formation could result in risks being potentially 

 
 
 
 
 
 
 
 
 
 
58 

Stage 

Aspect 

AEA risk rating 
(shale gas focus) 

Amec Foster 
Wheeler risk rating 
after application of 
measures1 (shale 
gas focus) 

CBM risks 
and impacts 
relative to 
shale gas 

Risk assessment 

Consequence 

Frequency 

Risk rating 

Reasoning 

Water 
resource 
depletion 

Moderate 

Low 

Potentially less 
significant 

Minor 

Rare 

Low 

Land take 

Moderate 

Moderate 

Not classifiable  Minor 

Likely 

Moderate 

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more significant due to the hazard of formation fluids 
and gas migrating through pathways in the coal 
seam.  Application of the likely to be applied 
measures assumed for shale gas (see footnote 31) 
is judged to mitigate this risk.  For CBM, risk rating is 
therefore judged to be Moderate. 

For CBM target formations at greater depth (e.g. 
>1,500m) it is possible that likelihood will reduce to 
Extremely Rare due the depth and further geological 
barriers between groundwater resources and the 
gas producing formation.  In this case, for deeper 
formations, risk rating may reduce to Low. 

Potentially less significant and likely will be less than 
shale gas due to lower water consumption. 

Application of  'likely to be applied' measures for 
shale gas is judged to reduce frequency from 
occasional to rare on the AEA risk matrix resulting in 
the risk rating reducing from Moderate to Low. 

CBM has lower water consumption than shale gas 
potentially further reducing the potential risk.  Risk 
rating including application of likely to be applied 
measures is judged to be Low. 

The land take issue for CBM is not clear.  Existing 
work at Falkirk (Scotland) has significantly smaller 
land take demand with 0.4 hectares per pad 
compared to shale gas which can be up to 2.24 
hectares per pad (AMEC (2014)).  However it is 
possible depending on the well configuration and 
geological resource that concessions could 
potentially be at the same scale as shale gas 

 
 
 
 
 
 
 
 
 
 
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Stage 

Aspect 

AEA risk rating 
(shale gas focus) 

Amec Foster 
Wheeler risk rating 
after application of 
measures1 (shale 
gas focus) 

CBM risks 
and impacts 
relative to 
shale gas 

Risk assessment 

Consequence 

Frequency 

Risk rating 

Reasoning 

Traffic 

Low 

Low 

Potentially 
more 
significant 

Slight 

Likely 

Low 

operations.  Therefore overall risk rating is judged to 
match that for shale gas in lieu of further evidence. 

Potentially more significant due to higher volumes of 
produced water requiring management and 
potentially movement by road. 

Application of ‘likely to be applied' measures for 
shale gas is unlikely to affect the level of activity and 
hence consequence and frequency.  No change 
results in the AEA risk rating. 

Measures identified to mitigate risk for shale gas 
when applied to similar activities for CBM will have 
the same level of effect.  On this basis the measures 
identified will not further reduce risk for CBM. The 
risk rating is judged to be Low. 

1. For measures see Appendix B. 

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Table 3.4 

Risk Assessment of Further Risks for CBM 

Stage 

Aspect 

Risk assessment 

Consequence  Frequency 

Risk rating 

Reasoning 

5. Production 

Groundwater 
contamination 

No data 

No data 

Low1 

Releases to 
air 

No data 

No data 

Low1 

Surface water 
contamination 

Water 
resource 
depletion 

Minor 

Occasional 

Moderate 

Minor 

Occasional 

Moderate 

CBM operates at shallower depths than shale gas hence there is potentially an increased risk of impacts on near-
surface groundwater resources and quality, particularly linked to groundwater pumping required in CBM production.  
Incidences arising from CBM operations are not well documented and therefore it is difficult to predict the frequency 
and magnitude, but overall risk is expected to be low (due to minor consequence and rare occurrence).  This risk would 
reduce for deeper CBM target formations due to increased distance from near surface groundwater resources. 

As CBM operations work at shallower depths than shale gas there is potentially a greater risk of gas seepage through 
rock strata and being emitted as fugitive emissions.  The prevalence of this phenomenon from CBM operations is not 
well documented and therefore it is difficult to predict the frequency and magnitude, but overall risk is expected to be 
low (due to minor consequence and rare occurrence).  This risk would reduce for deeper CBM target formations due to 
increased distance from near surface groundwater resources. 

Greater volumes of produced water from CBM operations (compared to shale gas) mean that careful management and 
handling is required.  Potentially greater volumes of wastewater would present a tangible risk for spillages/releases 
resulting in surface water contamination. 

Unlike other types of UFF, gas is adsorbed to the surface of coal structures and is released for flow into the well by 
pumping water from the well and reducing pressure.  This operation potentially presents a risk that during pumping a 
negative pressure gradient can draw fresh water away from overlying groundwater.  Therefore pumping operations for 
CBM could potentially adversely affect water resources during pumping. 

1. Risk rating classified as low on the basis of expert judgement (due to probable minor consequence and rare occurrence), in the absence of referenced information. 

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4.  Measures 

4.1 

Introduction 

This section provides an assessment of whether the measures identified for shale gas are appropriate and 
proportionate to the risks and impacts for other UFF where these have been identified as not comparable in 
Section 3.  For risks and impacts that are concluded to be comparable, it is assumed that the measures appropriate 
for shale gas will also be appropriate for the other UFF (and so these are not considered here). 

Before the assessment of the measures, a summary of the approach to measure development is presented. 

4.2 

Development of Measures 

The approach to development of measures is described in detail in AMEC (2014).  A brief summary of the 
approach is provided here. 

Measure Development 

Measures to address risks and their impacts were developed based on: (a) the analyses of key risks and mitigation 
measures, (b) an analysis of the acquis communautaire and whether it requires the identified measures to be 
implemented; and (c) subsequent discussion with the Commission and peer review.  The measures were organised 
to identify the following aspects: 

•  Whether the measure is business as usual (BAU) or non-BAU; 

•  Project stage: stage(s) of the unconventional gas extraction process that the measure would be applied 

to; 

•  Level of ambition: potential to reduce both the likelihood of the risks being addressed and the 

consequences; and 

•  Grouping according to a number of different themes agreed with the Commission. 

This allowed comparison of similar and alternative measures e.g. more or less prescriptive approaches to 
addressing risks, or higher/lower levels of ambition. 

Business as Usual vs. Non-Business as Usual 

Those measures identified as already required by EU legislation were classified as BAU.  If measures only may be 
required (i.e. there is uncertainty), then they were classified as non-BAU.  However, many ‘non-BAU’ measures 
(i.e. not definitely required by EU legislation) might be normal practice by the industry. To address this, non-BAU 

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measures that were likely to be applied by industry regardless of legislative requirements were considered.  The 
degree of uptake of the measures by operators was then considered and (assumed, illustrative) uptake rates were 
integrated into the analysis33.  This enabled the costs of those ‘non-BAU’ measures that were likely to be applied 
by industry as a result of normal practice to be taken into account in analysis of policy options. 

The following are significant activities for UFF that are BAU under the existing EU acquis and hence additional 
measures to address risks and impacts are not considered further: 

•  Drilling mud waste management and disposal: regulation of drilling mud waste is addressed through 

the existing legislation (Mining Waste Directive).  Whilst drilling mud composition and contamination 
may vary, the requirement to meet waste management and disposal regulatory requirements is already 
established.  Furthermore, management practices, and treatment and disposal methods are already 
established in the oil and gas industry. 

•  Wastewater treatment and discharge: requirements for wastewater treatment and discharge are 
established through implementation of existing legislation (e.g. Mining Waste Directive, Water 
Framework Directive).  Whilst wastewater compositions may differ (e.g. levels of salinity, mineral oil, 
metals, NORM), the requirement to treat wastewater and requirements on discharges are part of 
existing legislation.  Treated wastewater risks and impacts would be comparable to those for shale gas 
and CFF as the same discharge requirements would apply.  A best available techniques reference 
document (BREF) is currently being reviewed and should encompass the management of waste from 
oil and gas activities. 

Level of Ambition 

Level of ambition of the measures was determined by considering two aspects: (1) potential to reduce the 
likelihood of the identified risks being realised and (2) potential to reduce the magnitude/consequence of damage. 
For each aspect, the team assigned three levels of ambition: High (H), Medium (M) and Low (L). 

With regard to potential to reduce likelihood, H referred to likelihood reduced to zero or a negligible level, M 
referred to significant reduction in likelihood but still potentially foreseeable and L referred low to moderate 
reduction in likelihood.  With regard to damage/consequence reduction, H referred to damage reduced to negligible 
level (no ascertainable damage to health/environment/property), M referred to damage reduced to a broadly 
acceptable level (e.g. compliance with expected standards in other fields) and L referred to low to moderate 
reduction in (potential) damage.  Level of ambition of each measure was then assigned by combining the different 
level of ambition from these two aspects (e.g. HH, ML, etc.).  

33 Measures considered likely to be applied had a 90% uptake level and measures considered possible to be applied had 40% uptake level.  For complete list see 
section 3 and Table E2 in Appendix E of AMEC (2014). 

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Grouping by Theme 

Measures were grouped into the following themes: 

•  Zoning; 

•  Underground; 

•  Chemicals usage; 

•  Water depletion; 

•  Surface water quality; 

•  Air quality; 

•  Waste; 

•  Post-closure; 

•  Public acceptance; and 

•  Other measures (not falling into the above). 

The aim of grouping by theme (and categorisation by relevant process stage) was to create coherent groups of 
measures and to identify at which stage of the process each measure may apply.  This allowed comparison between 
similar or alternative measures as well as understanding possible risks they may be addressed at any stage.  The 
approach also allowed comparison between measures at differing levels of ambition. 

Measures within each theme were presented describing: 

•  Risks of concern within the theme; 

•  Overview of possible measures – the characteristics, costs, description of measure combinations 

(complementary/redundancy), comparative levels of ambition; 

•  Economic impacts – compliance and administrative costs; 

•  Environmental benefits; and 

•  Social impacts. 

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4.3 

Review of Measures 

4.3.1 

Approach 

For the risks that were found to be not comparable to shale gas, a review of the ‘appropriateness’ and 
‘proportionality’ of the measures has been carried out taking account of information presented in Section 3. 

For these risks, the approach considered the measures identified for shale gas in the context of the other UFF for 
their appropriateness, i.e., whether or not the measure is suitable to address the risk for that form of UFF.  
Proportionality was then judged as being ‘over-specified’, ‘proportionate’ or ‘under-specified’.  Further measures 
were also developed to address risks that were found to be additional for the other UFFs when compared to shale 
gas. 

4.3.2 

Outcome of the Review of Existing Measures 

Measures (see Appendix B) were assessed for the following types of impacts: 

•  Water resource depletion measures: for tight oil, tight gas and CBM; 

•  Traffic: for tight oil, tight gas and CBM; 

•  Releases to air: for tight oil and CBM; 

•  Land take: for CBM; 

•  Visual impact: for CBM; and 

•  Groundwater contamination risks: for CBM. 

Water Resource Depletion Measures 

•  All measure are judged appropriate for tight oil, tight gas and CBM; 

•  All measures are judged proportionate for tight oil and tight gas; 

•  The following measures are judged to be over-specified for CBM due to lower water demand 

requirements for CBM: 
3a vi  Site baseline, establish water source availability and test for suitability34 
3b vi  Monitoring, water resources availability 
3b ix  Monitoring, water volumes and origin 
38b  Demand profile for water 
N49  Strategic planning and staged approach of play development to avoid peaks in water demand 

34 Establishment of baseline for water source availability and tests for suitability only.  Baseline establishment for other parameters (e.g. surface water and 
groundwater quality) remain relevant. 

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Traffic Measures 

•  All measure are judged appropriate for tight oil, tight gas and CBM; 

•  A number of measures are judged to be over-specified for tight oil, tight gas and CBM due to fewer 
vehicle movements associated with water and flowback management but may not necessarily be 
overspecified for the management of produced water, for example: 
60a  Use of temporary surface pipes for distribution of water supply 
60b  Use of temporary surface pipes for collection of flowback 
60c  Site selection close to water sources to minimise haulage requirements 
61c  Site selection close to flowback treatment/disposal facilities to minimise haulage requirements 
(judged over-specified for tight oil and tight gas only.  Judged proportionate for CBM due to high 
volume of pumped groundwater during the production stage) 

Releases to Air 

•  Assessed for CBM due to potentially smaller scale activities and pad size and also shallower wells 

resulting in shorter duration of diesel powered mobile plant and drilling rigs required; 

•  Measures are judged to be both appropriate and proportionate for tight oil and CBM. 

Land take 

•  Assessed for CBM only and related to potentially smaller scale activities and pad size; 

•  Relevant measures relate to optimisation (e.g. pad spacing, density), cumulative effects and 
undertaking Strategic Environment Assessment.  The measures are judged appropriate and 
proportionate for CBM. 

Visual Impact 

•  Assessed for CBM only and related to potentially smaller scale activities and pad size; 

•  Relevant measures relate to the requirement for Environment Impact Assessment, including an 

assessment of cumulative impacts.  The measures are judged to be appropriate and proportionate for 
CBM. 

Groundwater Contamination 

•  Assessed for CBM only and related to potentially more significant risks and impacts arising from the 

shallower depths of formations, potential increased proximity to potable water resources and a 
potential for affecting overlying groundwater resources due to the need for groundwater pumping in 
the target formation; 

•  Measures are judged to be both appropriate and proportionate for CBM. 

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4.3.3 

Assessment of Potential Additional Measure Requirements 

Further risks were identified for CBM (see Table 3.4) related to the production stage.  Observations and assessment 
of the requirement for additional measures are provided below regarding these risks.  In reviewing potential 
additional risk mitigation measures, the measures presented in recent studies on CBM by BRGM (2013) and the 
Environment Agency (for England) (2014b) were examined. 

Releases to Air 

As CBM operations are typically at shallower depths than shale gas there is potential for an increased risk of gas 
seepage through rock strata (due to the lack of geological barriers) and being emitted as fugitive emissions.  The 
prevalence of this phenomenon from CBM operations is not well documented and therefore it is difficult to predict 
the frequency and magnitude hence risk is rated ‘Not classifiable’ but overall risk would be expected to be Low.  

Assessment: measures addressing groundwater contamination include measures aimed at developing conceptual 
models, searching for and documenting potential leakage pathways, modelling fracture programmes and both 
baseline and ongoing monitoring of methane in groundwater.  Measures identified for shale gas (in AMEC, 2014) 
are likely to be adequate to also manage this risk. 

Surface Water Contamination 

CBM generates greater volumes of produced water than shale gas, tight oil and tight gas.  Levels of salinity vary 
greatly depending on the formation (ranging from 1-128,000 mg/l chloride).  Consequently, careful management 
and handling is required.  The greater volumes may present a greater risk of spillage and release resulting in surface 
water contamination.  Risk has been assessed as Moderate.35 

Assessment: existing measures identified for shale gas (in AMEC, 2014) are likely to be adequate to manage the 
risk of surface water contamination, for example, existing measures include: good site practice to prevent of leaks 
and spills, undertaking sampling of surface water bodies in wet and dry periods (baseline and ongoing), 
construction of a berm around the site boundary, the use of tank level alarms and double-skinned closed storage 
tanks and installation of an impervious site liner under the well pad with puncture proof underlay. 

Groundwater Contamination and Water Resource Depletion 

CBM requires groundwater pumping.  This operation potentially presents a risk that during pumping a negative 
pressure gradient can draw fresh water away from overlying potable groundwater resources resulting in potential 
risks and impacts to groundwater resources and quality (i.e. contamination). 

Assessment: whilst existing measures (focussed on addressing groundwater contamination risks) include aspects 
such as modelling groundwater flows, additional measures are considered necessary.  These measures are proposed 
to be developed through higher ambition variants of existing measures, in particular: 

35 Note treatment of wastewater to prevent surface water contamination is BAU.  Refer to Section 4.2 for further discussion. 

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•  26d development of conceptual model.  The shale gas measure focused on establishing the 

hydrogeological aspects prior to drilling.  A further HIGH ambition option of the measure was 
included that extends work to model the impact of groundwater pumping on linked groundwater and 
surface water flows and quality; 

•  3b vi monitoring and reporting of water resources availability.  The shale gas measure focuses on 
water resource availability for operations.  A further HIGH ambition option of the measure was 
included to enable extension of monitoring and reporting to include active groundwater resource / 
level management of the concession area; and 

•  38a notification of water demand from fracturing operations to relevant water utilities and competent 
authorities.  The shale gas measure focussed on the provision of information on water demand from 
fracturing and did not focus on actively managing the impact arising from the pumping of 
groundwater from areas also used as groundwater resources as may be required for CBM.  A further 
HIGH ambition option for 38a was included to address this additional requirement. 

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5.  Policy Options Assessment 

5.1 

Introduction 

This section builds on the AMEC (2014) report and this report as a whole should be read in conjunction with the 
AMEC (2014) report.  This section presents a summary of the approach used to assess the impacts of different 
policy options, noting variations to the AMEC (2014) approach.  Policy options are summarised, AMEC (2014) 
provides a fuller discussion of the policy options characteristics. 

5.2 

Approach 

5.2.1 

Illustrative Concessions 

Consistent with AMEC (2014), the concept of an ‘illustrative gas concession’ has been used as a basis upon which 
to assess potential costs and benefits.  This approach has been used due to the uncertainties around the scale of 
future unconventional gas extraction in the EU and how this would develop over time.  This allows the potential 
impacts to be assessed without the need for a mature industry to be developed.  Clearly future developments may 
vary substantially in size and the related impacts would therefore vary significantly. 

The illustrative concessions are based on a number of variables such as a typical assumed number of well pads per 
concession and wells per pad, water consumption, on-site power requirements, vehicle movements, etc.  The 
illustrative concessions include not only technical aspects (i.e. number of pads/wells) but also the types and scale of 
parameters that are directly related to environmental impacts (e.g. volume of wastewater produced).  The 
illustrative concessions information is presented in Appendix A and this has been used to inform the derivation of 
quantitative estimates of the impacts of measures.  It should be noted that due to the degree of uncertainty in the 
selection of the reference values, the illustrative concession data are intended for demonstration purposes and 
parameters will vary significantly depending on site specific characteristics of specific projects. 

The general framework of parameters developed for shale gas formed a starting point for the other UFF; however 
certain parameter values differ.  The study has collated information focussing on the European situation wherever 
possible.  This includes integrating responses to a questionnaire forwarded to Member States requesting the 
provision of information regarding tight gas, tight oil and CBM.  Responses were received from Denmark, 
Germany, Portugal, Romania and the UK.  The UK provided data for a limited number of parameters for 
exploratory CBM operations and Germany provided data for parameters regarding tight gas operations (the other 
responding Member States indicated that there are currently no relevant operations in their respective territories).  

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5.2.2 

Assessment of Measure Impacts 

The economic, environmental and social impacts of full implementation of each measure are considered (treated 
individually, not in a group) in AMEC (2014) and are not repeated here.  In summary, for economic impacts, both 
compliance costs and administrative costs (for operators and authorities) were considered.  Where there was a 
sufficient level of information, these economic impacts were quantitatively estimated, with assumptions drawn 
from existing literature and inputs from Amec Foster Wheeler experts.  The experts included those with practical 
experience of large scale UFF projects in North America and Australia, as well as experience of implementing 
conventional hydrocarbon specific measures in the EU (e.g. surface water modelling, environmental impact 
assessment).  When drawing from practical experience of UFF projects from outside Europe, the project team took 
into consideration the EU context in estimating the costs by using EU-specific assumptions such as the hourly wage 
for operators and external consultancy.  Furthermore, the project team used a set of assumptions in an ‘illustrative 
concession’ (see Section 5.2.1), which provided a unit in describing the potential scale of unconventional gas 
development in the EU.  Where there was an insufficient level of quantitative information or levels of uncertainty 
were too high, the impacts were discussed qualitatively. 

5.3 

Selected Policy Options 

5.3.1 

Introduction 

This section presents a description and comparison of four selected policy options based on the initial analysis set 
out in Section 4 of AMEC (2014).  The four options were: 

•  Option A:  to take forward guidance and a recommendation under existing legislation, voluntary 

industry agreement and best practice; 

•  Option B:  to amend several existing EU laws and accompany this with guidance; 

•  Option C:  to adopt a new dedicated legal instrument in the form of a directive (setting overall 

goals/principles) and accompany this with guidance; and 

•  Option D:  to adopt a new dedicated legal instrument in the form of a regulation, to set specific 

detailed obligations and accompany this with guidance.36 

It should be noted that since the AMEC (2014) work focussed on shale gas, the Commission has partially taken 
forward Option A with the adoption of Recommendation 2014/70/EU in January 2014.  This section begins with a 
brief description of each of the policy options summarised from AMEC (2014).  It then compares these options in 
terms of the measures that are expected to be implemented under each, and a comparative analysis in relation to the 
costs of the options is subsequently presented.  This is presented for tight gas, tight oil and CBM. 

36 In practice, Option D could also be implemented through a directive with more specific obligations than those included under Option C. 

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5.3.2 

Policy Option A: Guidance and Recommendation 

Option A is to take forward a recommendation, voluntary industry agreements and best practice plus guidance in 
relation to existing legislation.  This option is for the Commission, working with stakeholders where relevant, to 
support the protection of health and the environment through the full range of non-legislative approaches available.  

Interpretative guidance is the formal production of non-binding material setting out best practice in the application 
of specific aspects of EU legislation.  A recommendation to Member States may be used to complement existing 
EU legislation.  Such a recommendation provides non-binding actions with no obligatory power that may provide 
preparation for legislation in Member States (if deemed necessary by the latter).  With regard to shale gas, AMEC 
(2014) identified a wide range of issues arising in the interpretation and application of individual Directives that 
could be elaborated through guidance.  Such material would reduce uncertainty for operators and provide assistance 
to regulators who may be uncertain whether they are correctly implementing EU law in this evolving area.  The 
issues apply also to other UFF.  Guidance can examine specific issues with respect to different types of UFF in a 
flexible way.  Further, it can readily be adapted as different UFF sources are developed, as best practice evolves 
and as environmental interactions are better understood.  It is however to be noted that it is the European Court of 
Justice which is ultimately responsible for providing an authoritative interpretation of EU law. 

Non-legislative approaches can be taken further with the development of voluntary approaches with industry and 
sharing of best practice.  The opportunities and limitations of these approaches are explored in Section 4 of AMEC 
(2014). 

5.3.3 

Policy Option B: Amendment to the Acquis plus Guidance 

Option B is to amend several existing EU laws and accompany this with guidance.  

The basis for addressing the regulatory gaps in the existing acquis by amending the existing legislation are 
described in Section 4.5 of AMEC (2014) in which it was noted that the nature of the potential amendments would 
vary significantly.  In some cases such amendments would be relatively minor, ensuring that a particular aspect of 
the operation of an unconventional gas facility or a specific activity is included in the scope of a Directive.  In other 
cases the amendment could be significant aiming to encompass much of the operation or the facility.  Option B 
would further support the implementation of the existing legislation through the adoption of guidance, voluntary 
agreements and sharing of best practice (i.e. Option A).  Examples of possible amendments to the existing acquis 
which could be used to address gaps in the regulation of unconventional gas facilities are provided in the following 
table (from AMEC (2014).  

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Table 5.1 

Examples of Possible Amendments to the Existing Acquis to Address Gaps in the Regulation of 
Unconventional Gas 

Existing EU Instrument 

Possible Amendments  

EIA Directive 

Clarity on the scope of application of EIA particularly for exploration stage. 

Water Framework Directive (and daughter 
Groundwater Directive) 

Clarity on the obligations with regard to protection of groundwater (quantity and quality).  The 
GWD might require additional EQS to be included in the Annex. 

Environmental Liability Directive 

Seveso III 

IED 

Amendment might be possible to include unconventional gas extraction as a category.  
However, this would depend on other amendments, e.g. if IED is amended to fully include 
unconventional gas extraction, the existing reference to IED in ELD would probably be 
sufficient. 

To clarify inclusion of unconventional gas extraction activities, including exploration stage – it 
is unlikely a new instrument would include the full range of accident prevention and 
management requirements. 

IED could be amended to ensure full capture (or at least partial additional capture) of 
unconventional gas exploration and production in its scope. 

The above amendments would all need to be taken forward fully to address unconventional gas extraction.  Each 
contributes to improving regulatory capture in particular ways and, in some cases (e.g. ELD and Seveso), increases 
intra-acquis coherence.  The most potentially far-reaching amendment would be that to IED.   

The development of guidance, would be on the same basis as Option A, except that the amendment of existing 
legislation might require additional guidance to be developed and best practice to be shared on additional elements 
adopted in the amended legislation.  Furthermore, amendment of the Industrial Emission Directive (IED) and 
Mining Waste Directive (MWD) would potentially require the adoption of new BREFs (or strengthening of 
existing ones), which would have the character of guidance, but which also have a legal standing in the 
implementation of those Directives. This option can readily take account of any specificities concerning UFF 
alongside those for shale gas. 

Option B can, therefore, encompass all of the issues for which guidance and sharing best practice could be 
addressed within Option A, as well as filling some of the identified regulatory gaps through legal amendment and 
supporting these new obligations with additional (or expanded) guidance providing more assured uptake of 
measures to address the risks. 

5.3.4 

Policy Option C: Dedicated Directive plus Guidance 

Option C is to adopt a new dedicated legal instrument in the form of a directive (setting over-arching 
goals/principles) and accompany this with guidance. 

The basis and potential scope of a new dedicated instrument is described in Section 4.6 of AMEC (2014), and is not 
repeated here.  The scope of such an instrument would be able to be wider than that of amending the existing 
acquis as covered in Option B.  In principle, all issues associated with the exploration and production of UFF could 
be included.  

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Furthermore, such an instrument could be supported with the adoption of guidance, voluntary agreements and 
sharing of best practice where appropriate.  Such guidance could be dedicated to helping regulators and operators 
interpret and implement the new instrument.  Where aspects of the existing acquis remain appropriate (this would 
depend on the scope of a new instrument), guidance can be developed to help interpret this (as with Option A) 
and/or explore the interaction between that aspect of the existing acquis and the new instrument. 

Option C, therefore, encompasses all of the issues for which guidance and sharing of best practice could be 
addressed within Option A, as well as addressing all of the regulatory gaps encompassed by Option B, as well as 
addressing further regulatory gaps that amendment of the existing acquis might not be able to address. 

5.3.5 

Policy Option D: Dedicated Regulation plus Guidance 

Option D is a step further than Option C in that it also involves a dedicated new legal instrument, but in this case 
setting more specific and detailed obligations.  In this report, it was assumed that this would be in the form of a 
regulation (so ‘regulation’ is referred to below), but such an instrument could equally be achieved through a more 
prescriptive directive. 

As a regulation is directly applicable, its provisions need to be clear and precise as to what is required by whom.  If 
there are provisions which are too vague or general, it is likely that these would require interpretation in law at 
national level and the benefit of directly applicable law would be lost. 

This approach could specify precisely the actions required of operators during exploration and production.  It could 
also include general objectives for operators to follow if these are clearly established in law and potentially linked 
to wider processes. For example, a requirement to apply BAT is clear and reference to dedicated BREFs would also 
be appropriate in a regulation.  

5.3.6 

Comparison of the Options 

A comparison of the Options for shale gas is presented in Section 4.8.6 of AMEC (2014) where a discussion of 
efficiency, effectiveness and coherence is provided.  The general nature of the options under consideration for other 
UFF is the same (albeit with adjustments to the precise measures applied under the options; see below for details of 
measure adjustments) and hence a general comparison of the options is not repeated here.  The principal points of 
comparison of the options presented here is the range of measures that could be addressed by each option (cost 
issues are addressed in subsequent sections). 

The measures that have been determined as appropriate to address the range of environmental and health risks 
associated with unconventional gas extraction under each of the policy options are presented in Appendix D for 
each other UFF (where for each of the four policy options, the table highlights those measures that would be 
potentially addressed by that option for each other UFF).  All four options can take forward many measures for the 
other UFF as summarised in the following table (including shale gas for information from AMEC (2014). 

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Table 5.2 

Number of Measures in Options 

Option 

Shale Gas 

Tight Gas 

Tight Oil 

CBM 

A 

B 

C 

D 

160 

172 

196 

196 

158 

170 

193 

193 

158 

170 

193 

193 

159 

171 

194 

194 

The initial comparison of the options is the division between legislative and non-legislative options, i.e. Option A 
compared to Options B, C and D.  It is generally assumed that binding legislation will be more effective across the 
EU as a whole than non-binding instruments.  Note that Option D does not address further measures than are 
possible through option C, but sets measures in a different legal context of a regulation. 

The changes in measures selected under the options due to differences in risk and the appropriateness and 
proportionality of measures, when compared to the measures selected for shale gas (see AMEC (2014)), can be 
summarised as follows (see Section 4.3 for further discussion): 

•  Tight gas and tight oil.  The following measures were not selected for any policy options: 

-  60c Site selection close to water sources to minimise haulage requirements 

-  60a Use of temporary surface pipes for distribution of water supply 

-  60b Use of temporary surface pipes for collection of flowback 

•  CBM.  The following adjustments to measures were made: 

-  38a Notification of water demand from fracturing operations to relevant water utilities and 

competent authorities (impact of groundwater pumping).  A high ambition measure added to all 
options 

-  38b Demand profile for water.  Remained in option A only 

-  38c Water management plan.  Removed from all options 

-  N49 Strategic planning and staged approach of play development to avoid peaks in water demand.  

Remained in option A only 

-  3a vi Site baseline. Establish water source availability and test for suitability.  Remained in option 

A only 

-  3b vi Monitoring. Water resources availability.  A high ambition measure (focussed on active 
groundwater and surface water level and flow management to address impacts of groundwater 
pumping) added to all options 

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-  3b ix Monitoring. Undertake monitoring of water volumes and origin.  Remained in option A only 

-  60c Site selection close to water sources to minimise haulage requirements.  Not selected for any 

options 

-  60a Use of temporary surface pipes for distribution of water supply.  Not selected for any options 

-  60b Use of temporary surface pipes for collection of flowback.  Not selected for any options 

-  26d Development of a conceptual model of the zone before work commences covering geology, 

groundwater flows, pathways, microseismicity and subsequent updating of the model as 
information becomes available.  A high ambition measure added to all options. 

5.4 

Policy Option Costs 

5.4.1 

Introduction 

For some 230 non-BAU measures (including sub-measures) identified to address (partially or fully) specific 
environmental risks, costs and benefits were assessed quantitatively or qualitatively.   

Quantitative assessment included identification of capital costs (i.e. one-off) as well as annual operating costs, all 
expressed per well pad, based on the available literature and expert judgement based on practical experience of 
implementing similar measures in the EU and North America, and also in Australia for CBM.  The cost estimates 
were based on the key assumptions made in the illustrative concession (see Appendix A) and labour costs for 
operators, external technical experts and competent authorities37.  All costs were adjusted to 2012 Euro prices using 
historical exchange rates (annual average) and Eurostat annual average index of Harmonised Index of Consumer 
Prices (HICP).  This approach was consistent with that used for assessment of shale gas (see AMEC (2014)). 

Once capital and annual operating costs were identified (for those measures that it was possible and appropriate to 
quantify), annualised compliance costs were estimated for each measure.  Capital cost was assumed to be amortised 
over 20 years for tight gas and tight oil and 7 years for CBM (i.e. the assumed typical lifetime of the well facilities).  
For measures where different amortisation periods were applied, this was noted in the key assumptions.  Measures 
and associated costs are based on the illustrative concessions and will vary with concession size and pad lifetimes 
achieved, potentially leading to economies of scale (or vice versa).  A discount rate of 4% was applied.  

Based on the annualised compliance cost of individual measures, total annualised compliance costs for different 
policy options were estimated for tight gas, tight oil and CBM.  For Option A, the high end costs assume that the 

37 Labour cost included average hourly wage, non-wage labour cost and overhead of 25%.  Mean hourly earnings in 2010, % total wages and salaries and % social 
security and other labour costs paid for different NACE categories from Eurostat were used to estimate the non-wage labour costs and overhead.  The “industry 
construction and services” category was assumed for operators; “professional, scientific and technical activities” was assumed for technical experts; and “public 
administration and defence, compulsory social security” was assumed for authorities.  Where Member-State-specific statistics were collected, a weighted average of 
the EU was used for the calculation of labour-based cost components for relevant measures. Labour cost, adjusted to 2012 prices, was assumed to be €39 per hour 
for operators; €41 for Member State competent authorities; €76 per hour for European Commission (based on labour cost in Belgium) and €59 per hour for external 
technical experts.  The labour cost of external technical experts (i.e. contractor that operators would hire to carry out specific services) is adjusted to reflect 18.7% 
EU average gross operating rate for architectural and engineering services – technical testing and analysis sector in 2009, as the hourly fee quoted by these experts 
would likely to include a fee margin on top of the actual labour cost. 

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level of ambition and thus related cost would not exceed that of Option B.  For Option D measures selected as 
guidance only in Option C were assumed to be compulsory; in addition, High ambition measures were selected 
rather than a Low ambition measure where previously in Option C a Low ambition measure was selected and a 
High option was available. 

5.4.2 

Cost of Measures under Each Policy Option 

Annualised Compliance Costs 

Table 5.3, Table 5.4 and Table 5.5 present the annualised compliance costs for tight gas, tight oil and CBM 
respectively for different policy options, showing the split between costs borne by operators and authorities.  These 
costs have been derived by adding the costs of all of the measures that have been quantified and which have been 
assumed to apply under each option.  A detailed list of all measures included in each policy option and their 
annualised compliance cost is available in Appendix D.  By way of comparison, Table 5.6 presents the total 
annualised compliance costs for shale gas for the policy options from AMEC (2014). 

Table 5.3 

Tight Gas Annualised Compliance Costs for Policy Options (€ per pad) 

Policy Option 

Total annualised 
compliance costs  

Operators 

Authorities 

Option A1 
Recommendation 
plus Guidance 

Option B 
Amendment to the 
Acquis plus 
Guidance 

Option C2 
Dedicated Legislation 
(Directive) 
+ Guidance 

Option D 
Dedicated Legislation 
(Regulation) 
+ Guidance 

0 to 968,000 

968,000 

1,019,000 

1,109,000 

0 to 966,000 

0 to 2,000 

966,000 

2,000 

1,012,000 

7,000 

1,102,000 

7,000 

Table 5.4 

Tight Oil Annualised Compliance Costs for Policy Options (€ per pad) 

Policy Option 

Total annualised 
compliance costs  

Operators 

Authorities 

Option A1 
Recommendation 
plus Guidance 

Option B 
Amendment to the 
Acquis plus 
Guidance 

Option C2 
Dedicated Legislation 
(Directive) 
+ Guidance 

Option D 
Dedicated Legislation 
(Regulation) 
+ Guidance 

0 to 970,000 

970,000 

1,022,000 

1,112,000 

0 to 968,000 

0 to 2,000 

968,000 

2,000 

1,015,000 

7,000 

1,105,000 

7,000 

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Table 5.5 

CBM Annualised Compliance Costs for Policy Options (€ per pad) 

Policy Option 

Total annualised 
compliance costs  

Operators 

Authorities 

Option A1 
Recommendation 
plus Guidance 

Option B 
Amendment to the 
Acquis plus 
Guidance 

Option C2 
Dedicated Legislation 
(Directive) 
+ Guidance 

Option D 
Dedicated Legislation 
(Regulation) 
+ Guidance 

0 to 818,000 

818,000 

894,000 

0 to 817,000 

0 to 1,000 

817,000 

1,000 

880,000 

14,000 

984,000 

970,000 

14,000 

Table 5.6 

Shale Gas Annualised Compliance Costs for Policy Options (€ per pad) 

Policy Option 

Total annualised 
compliance costs  

Option A1 
Recommendation 
plus Guidance 

Option B 
Amendment to the 
Acquis plus 
Guidance 

Option C2 
Dedicated Legislation 
(Directive) 
+ Guidance 

Option D 
Dedicated Legislation 
(Regulation) 
+ Guidance 

0 to 1,514,000 

1,514,000 

1,590,000 

1,686,000 

Note: Costs have been rounded to the nearest thousand. 
1. The cost of Option A will be determined by the level of ambition adopted by Member States.  The high end costs for Option A 
assume that the level ambition and thus related cost would not exceed that of Option B. 
2. Costs for Option C may lie between those calculated for Option B and Option C depending on the level of ambition of a 
Directive, the nature of measures applied and the process of application in Member States. 

Compared to annualised compliance costs for shale gas, tight gas and tight oil costs are lower due to a combination 
of an adjustment to measures selected and the assumed well lifetime, principally the latter (20 year lifetime for tight 
gas and tight oil vs. 10 year lifetime for shale gas).  For CBM, annualised compliance costs are lower than shale 
gas, tight gas and tight oil due to a combination of an adjustment to measures selected, the smaller number of wells 
per pad and in the case of (in particular) measure 22a on key elements to maintain well safety38, a scaling of the 
measure cost to account for the shallower depth and shorter horizontal length of the well compared to the other 
unconventional hydrocarbons39. 

The measures included in the policy options are considered as strictly non-BAU as they are not specifically 
required by existing legislation.  However, as discussed in section 4.2, some measures are likely to be normal 
practice by operators.  For instance, measure 22a on key elements to maintain well safety comprises many elements 
that are normal industry practice, but are not necessarily specified requirements under existing regulation.  
Similarly, measure 33b use of tank level alarms (so that operators are notified when the volume of chemicals and/or 

38 Full description of the measure is: ‘Key elements to maintain well safety such as: blowout preventers, pressure & temperature monitoring and shutdown systems, 
fire and gas detection, continuous monitoring for leaks and release of gas and liquids, modelling to aid well/HF design, isolate underground source of drinking water 
prior to drilling, ensure micro-annulus is not formed, casing centralizers to centre casing in hole, select corrosive resistant alloys and high strength steel, fish back 
casing, maintain appropriate bending radius, triple casing, casing and cementing designed to sustain high pressure and low magnitude seismicity, isolation of the 
well from aquifers, casings: minimum distance the surface casing extends below aquifer (e.g. 30m below the deepest underground source of drinking water 
encountered while drilling the well, ref. Environment Agency 2012) and surface casing cemented before reaching depth of e.g. 75m below underground drinking 
water (ref. AEA 2012). Production casing cemented up to at least 150 metres above the formation where hydraulic fracturing will be carried out (ref. AEA 2012).’ 
39 Note that well lifetimes are reported to vary significantly.  USEPA (2013) indicates 5-15 years, Amec Foster Wheeler experience in Australia indicates 2-5 years 
and personal communication with European Gas Ltd (2015) has suggested 15-25 years.  Adjusting well lifetime for CBM from 7 to 15 years would result in total 
annualised compliance costs per pad of Option A of €0 to 506,000, Option B €506,000, Option C €553,000 and Option D €619,000. 

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fracturing fluid stored in tanks is closed to the tanks’ capacity so corrective actions can be implemented) is 
considered to be likely to be applied.  The cost of Option A will be determined by the level of ambition and degree 
of application of measures adopted by Member States.  Hence this option could theoretically incur no costs if a 
recommendation and guidance are not followed for other UFF and the level of ambition is to maintain the extant 
interpretation and application of legislation. 

Since some of the measures considered in the different policy options are likely to be applied in reality, as per the 
approach used for shale gas (see AMEC (2014)) to avoid overestimating the annualised compliance costs of policy 
options , costs of these measures were adjusted downward to reflect a (purely hypothetical) average level of uptake.  
Specifically, 10% of compliance costs was assumed for the measures that were considered to be likely to be applied 
(i.e. 90% uptake level) and 60% of costs for the measures considered to be possible to be applied (i.e. 40% uptake 
level).  Annual compliance costs of policy options, with these adjustments, are shown below in Table 5.7, Table 5.8 
and Table 5.9 for tight gas, tight oil and CBM respectively.  The percentage uptake figures, suggested by the 
Commission, are only illustrative and are not intended to be predictors of actual uptake of any individual measure 
by operators. 

It is noted that costs for CBM do not reduce to the same degree as those for tight gas and tight oil.  This is primarily 
due to the cost of the high ambition baseline groundwater monitoring measure and aspects of the geological, 
hydrogeological and seismic conceptual model measure (in particular, obtaining geomechanical information on 
fractures, stress, rock strength, in situ fluid pressures, and a 3D seismic survey to identify faults and fractures)40.  
These measures are one-off costs that are not proportional to the scale of the gas produced from well.  The measure 
is assumed not to be ‘likely to be applied’ or ‘possible to be applied’ in normal practice hence measure costs are not 
adjusted down for the policy options.  The measure has a significant, €0.2m annualised cost for CBM over the 
seven year well lifetime (compared to a lower annualised cost for tight gas and tight oil where the same fixed cost 
is annualised over a 20 year well lifetime).  In addition, the number of wells assumed for CBM per pad is lower and 
the production phase is shorter than for other UFFs41.  The combination of high initial fixed costs of measures per 
well, a shorter production period and lower revenue potential of CBM wells results in the proportion of the costs of 
policy options to expected revenues being greater for CBM (see Section 5.5) although it should be noted that 
revenues and production periods will vary between sites.   

40 High ambition baseline groundwater monitoring measure, €200k per pad; obtaining geomechanical information on fractures, stress, rock strength, in situ fluid 
pressures, €48k per pad, and a 3D seismic survey to identify faults and fractures, €60k per pad in all policy options. 
41 As noted above (see footnote 39), well lifetimes are reported to vary significantly (from 2-25 years).  In addition, the number of wells per pad are reported to vary 
due to various well configurations, 1, between 2 and 8, and up to 16 wells per pad have been reported (Amec Foster Wheeler experience in the US and Australia, 
and personal communication with European Gas Ltd (2015) respectively). 

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Table 5.7 

Tight Gas Annualised Compliance Costs for Policy Options, with Adjustments for Non-BAU Measures 
that are Likely to be Applied in Practice (€ per pad), and Difference to Annualised Compliance Costs with 
No Adjustments (€ per pad) 

Policy Option 

Option A1 
Recommendation 
plus Guidance  

Option B 
Amendment to 
the Acquis plus 
Guidance 

Option C2 
Dedicated Legislation 
(Directive) 
+ Guidance 

Option D 
Dedicated Legislation 
(Regulation) 
+ Guidance 

Total annualised 
compliance costs , with 
adjustment for non-BAU 
measures likely to be 
applied in practice 

Operators 

Authorities 

Difference compared to 
pre-adjustment 

Total annualised 
compliance costs , with 
adjustment for non-BAU 
measures likely to be 
applied and possible to be 
applied in practice  

Operators 

Authorities 

Difference compared to 
pre-adjustment 

0 to 462,000 

462,000 

505,000 

595,000 

0 to 461,000 

461,000 

499,000 

0 to 1,000 

Up to 48% 

1,000 

48% 

6,000 

50% 

589,000 

6,000 

54% 

0 to 409,000 

409,000 

449,000 

530,000 

0 to 408,000 

408,000 

443,000 

0 to 1,000 

Up to 42% 

1,000 

42% 

6,000 

44% 

524,000 

6,000 

48% 

Note: Costs have been rounded to the nearest thousand. 
1. The cost of Option A will be determined by the level of ambition adopted by Member States.  The high end costs for Option A assume that the 
level ambition and thus related costs would not exceed the level of Option B. 
2. Costs for Option C may lie between those calculated for Option B and Option C depending on the level of ambition of a Directive, the nature 
of measures applied and the process of application in Member States. 

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Table 5.8 

Tight Oil Annualised Compliance Costs for Policy Options, with Adjustments for Non-BAU Measures that 
are Likely to be Applied in Practice (€ per pad), and Difference to Annualised Compliance Costs with No 
Adjustments (€ per pad) 

Policy Option 

Option A1 
Recommendation 
plus Guidance  

Option B 
Amendment to 
the Acquis plus 
Guidance 

Option C2 
Dedicated Legislation 
(Directive) 
+ Guidance 

Option D 
Dedicated Legislation 
(Regulation) 
+ Guidance 

Total annualised 
compliance costs , with 
adjustment for non-BAU 
measures likely to be 
applied in practice 

Operators 

Authorities 

Difference compared to 
pre-adjustment 

Total annualised 
compliance costs , with 
adjustment for non-BAU 
measures likely to be 
applied and possible to be 
applied in practice  

Operators 

Authorities 

Difference compared to 
pre-adjustment 

0 to 464,000 

464,000 

507,000 

597,000 

0 to 463,000 

463,000 

501,000 

0 to 1,000 

Up to 48% 

1,000 

48% 

6,000 

50% 

591,000 

6,000 

54% 

0 to 412,000 

412,000 

451,000 

533,000 

0 to 411,000 

411,000 

445,000 

0 to 1,000 

Up to 42% 

1,000 

42% 

6,000 

44% 

527,000 

6,000 

48% 

Note: Costs have been rounded to the nearest thousand. 
1. The cost of Option A will be determined by the level of ambition adopted by Member States.  The high end costs for Option A assume that the 
level ambition and thus related costs would not exceed the level of Option B. 
2. Costs for Option C may lie between those calculated for Option B and Option C depending on the level of ambition of a Directive, the nature 
of measures applied and the process of application in Member States. 

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Table 5.9 

CBM Annualised Compliance Costs for Policy Options, with Adjustments for Non-BAU Measures that are 
Likely to be Applied in Practice (€ per pad), and Difference to Annualised Compliance Costs with No 
Adjustments (€ per pad) 

Policy Option 

Option A1 
Recommendation 
plus Guidance  

Option B 
Amendment to 
the Acquis plus 
Guidance 

Option C2 
Dedicated Legislation 
(Directive) 
+ Guidance 

Option D 
Dedicated Legislation 
(Regulation) 
+ Guidance 

Total annualised 
compliance costs , with 
adjustment for non-BAU 
measures likely to be 
applied in practice 

Operators 

Authorities 

Difference compared to 
pre-adjustment 

Total annualised 
compliance costs , with 
adjustment for non-BAU 
measures likely to be 
applied and possible to be 
applied in practice  

Operators 

Authorities 

Difference compared to 
pre-adjustment 

0 to 634,000 

634,000 

707,000 

797,000 

0 to 633,000 

633,000 

0 to 1,000 

Up to 77% 

1,000 

78% 

693,000 

14,000 

79% 

783,000 

14,000 

81% 

0 to 574,000 

574,000 

644,000 

722,000 

0 to 573,000 

573,000 

0 to 1,000 

Up to 70% 

1,000 

70% 

630,000 

14,000 

72% 

708,000 

14,000 

73% 

Note: Costs have been rounded to the nearest thousand. 
1. The cost of Option A will be determined by the level of ambition adopted by Member States.  The high end costs for Option A assume that the 
level ambition and thus related costs would not exceed the level of Option B. 
2. Costs for Option C may lie between those calculated for Option B and Option C depending on the level of ambition of a Directive, the nature 
of measures applied and the process of application in Member States. 

Administrative Costs of Policy Options 

Together with costs to operators and authorities associated with risk mitigation measures as set out above, there 
would also be costs to both operators and authorities associated with the policy option(s) used to implement the 
various measures.  Section 4.8.7 of AMEC (2014) presents a discussion of the types of costs to operators and 
authorities that would be likely to arise for each of the policy options together with the baseline option and should 
be referred to for further detail.  Such costs are equally relevant to the administration of the policy options for tight 
gas, tight oil and CBM. 

AMEC (2014) estimates the costs of permitting of unconventional gas installations drawing upon experience of the 
costs of other similar regimes, in particular, those of carbon capture and storage (CCS) and Industrial Emissions.  
In summary, costs identified per pad which are equally relevant to tight gas, tight oil and CBM were: 

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•  Total start-up administrative costs associated with administrative costs of a risk management 

framework for exploration and production: around €22,600 for an operator and €11,000 for the 
administration; 

•  Assuming that inspection and compliance checking would need to be undertaken annually , the annual 

recurring costs for monitoring, reporting and compliance checking would be around €6,100 for 
operators and €1,600 for the administrations. 

These figures are based on individual pads however, an unconventional gas concession would have many pads 
developed over many years hence efficiencies would be present in permit development as operators and 
administrators develop related approaches and experience.  It is, therefore, not possible to provide a reliable 
cumulative figure for administrative costs at EU level.  

Benefits of Policy Options 

Finally it is important to note that it was not possible to provide a monetary estimate of the potential environment 
benefits of the application of the analysed measures for the different policy options and the evaluation did not 
directly assess human health risks from incidents as this was specifically excluded from the study terms of 
reference.  However, in any future consideration of which options should be pursued, it will be important to 
consider the extent of these wider benefits alongside the potential costs to operators and administrations to ensure 
that the full and correct perspective is taken into account in making policy decisions. 

5.5 

Policy Option Affordability 

For tight gas, tight oil and CBM, it is important to understand the likely financial burden that application of the 
various risk management measures under each of the policy options would place upon operators.  In line with the 
approach used in AMEC (2014), the estimates of total annualised costs derived in the previous section have been 
compared to an indicative estimate of the likely revenues that would be gained through a typical unconventional 
gas facility.  It is acknowledged that following the time at which the AMEC (2014) work was carried out, oil and 
gas prices reduced considerably.  To enable direct comparison of affordability with the AMEC (2014) work on 
shale gas, the same gas prices have been used together with an equivalent (in terms of year) oil price.  However, 
commentary on the potential impact on affordability of a lower oil and gas price is made to account for intervening 
price fluctuation. 

For tight gas, assuming an annual gas production rate of 6-19 mcm (as per shale gas42) over a 20 year well 
lifetime43, gas production per pad, per year (assuming eight wells per pad) would be in the order of 45-148 mcm.  

42 Production rates of shale and tight gas formations are variable, however, judgement informed by experience in North America indicates that gas production rate is 
not different due to it being from a tight or shale formation by definition.  The same production rate range as used for shale gas in AMEC (2014) is hence used for 
tight gas. 
43 European Commission data (personal communication based on JRC IET study) suggest 56-185mcm per well based on 30 year lifetime.  Taking into account the 
significant drop-off in production rates for both shale and tight gas seen in the US after c.10 years and typical 10-year gas production rates in the US of around 4-
6bcf (120-160mcm), the JRC figures for shale gas have been divided by 10 to provide an estimated annual production value. 

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The price of natural gas used in AMEC (2014) is used for consistency and was estimated44 at €0.43 per m3.  The 
revenues from natural gas sales are therefore estimated as €19-64 million per pad per year (midpoint of €42 
million). 

For tight oil, assuming an annual oil production rate of 890 m3 over a 20 year well lifetime, oil production per pad, 
per year (assuming eight wells per pad) would be in the order of 7,125 m3.  The price of oil in 2012 was 
approximately €720/m3 ($100 per barrel) (European Commission (2014)).  A 2012 price point has been used to 
enable an even comparison with the AMEC (2014) shale gas study (and, tight gas and CBM in this study).  The 
revenues from oil sales are therefore estimated as €5.1 million per pad per year. 

For CBM, assuming an annual gas production rate of 14 mcm over a seven year well lifetime, gas production per 
pad, per year (assuming four wells per pad) would be in the order of 8 mcm.  A price of natural gas of €0.43 per m3 
is used again for consistency (see above).  The revenues from natural gas sales are therefore estimated as €3.5 
million per pad per year. 

The tables below present the quantified costs under each of the policy options to the potential estimated revenues 
under different scenarios for the expected uptake of measures in the absence of further EU risk management 
policies.  The estimated compliance costs as a percentage of expected revenues for tight gas are similar in 
magnitude to those calculated for shale gas (see Section 4.9 of AMEC (2014)).  The percentage of expected 
revenues for CBM and tight oil are higher than for tight gas and shale gas.  This is due to the assumed lifetime 
production volumes and associated revenues and in addition for CBM, the smaller reduction in compliance costs 
when taking account of ‘likely to be applied’ or ‘possible to be applied’ measures (see Section 5.4.2 for further 
details on this point). 

44 Gas prices per member state in €/kWh (www.energy.eu, November 2012) were used to derive this value based on final natural gas consumption in 2011 by 
member state from Eurostat.  The figure above was derived by estimating an EU average price, weighted according to consumption by member state.  Prices 
include market price, transport, administrative charges, non-recoverable taxes and duties but exclude recoverable taxes and duties (e.g. VAT). 

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Table 5.10  Tight Gas Comparison of Costs of Policy Options to Expected Revenues from Natural Gas Sales 

Measures Included/Excluded 

A 
Recommendation 
plus Guidance 

B 
Amendment + 
Guidance 

C 
Dedicated 
Legislation 
(Directive) 
+ Guidance 

D 
Dedicated 
Legislation 
(Regulation) 
+ Guidance 

Total Annualised Costs of Measures (per pad 

All strictly non-BAU measures 

Non-BAU measures except those likely to be 
applied already 1 

Non-BAU measures except those possibly 
applied already 2 

€ 0 - 258,000 

€ 966,000 

€ 1,012,000 

€ 1,102,000 

€ 0 - 250,000 

€ 461,000 

€ 499,000 

€ 589,000 

€ 0 - 218,000 

€ 408,000 

€ 443,000 

€ 524,000 

Annualised Costs as a Percentage of Expected Annual Revenues 

All strictly non-BAU measures 

Non-BAU measures except those likely to be 
applied already 1 

Non-BAU measures except those possibly 
applied already 2 

Notes 

0.0 - 0.6% 

0.0 - 0.6% 

0.0 - 0.5% 

2.3% 

1.1% 

1.0% 

2.4% 

1.2% 

1.1% 

2.7% 

1.4% 

1.3% 

1  Takes account of uptake of measures categorised as ‘yes’ in terms of whether likely to be applied in any case. 

2  As [1] plus takes account of uptake of measures categorised as ‘possible – high’ in terms of whether likely to be applied in any case. 

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Table 5.11  Tight Oil Comparison of Costs of Policy Options to Expected Revenues from Natural Gas Sales 

Measures Included/Excluded 

A 
Recommendation 
plus Guidance 

B 
Amendment + 
Guidance 

C 
Dedicated 
Legislation 
(Directive) 
+ Guidance 

D 
Dedicated 
Legislation 
(Regulation) 
+ Guidance 

Total Annualised Costs of Measures (per pad) 

All strictly non-BAU measures 

Non-BAU measures except those likely to be 
applied already 1 

Non-BAU measures except those possibly 
applied already 2 

€ 0 - 259,000 

€ 968,000 

€ 1,015,000 

€ 1,105,000 

€ 0 - 251,000 

€ 463,000 

€ 501,000 

€ 591,000 

€ 0 - 219,000 

€ 411,000 

€ 445,000 

€ 527,000 

Annualised Costs as a Percentage of Expected Annual Revenues 

All strictly non-BAU measures 

0.0 – 5.1% 

18.90% 

19.80% 

21.60% 

Non-BAU measures except those likely to be 
applied already 1 

0.0 – 4.9% 

9.10% 

Non-BAU measures except those possibly 
applied already 2 

0.0 – 4.3% 

8.00% 

9.80% 

8.70% 

11.60% 

10.30% 

Notes: 

1  Takes account of uptake of measures categorised as ‘yes’ in terms of whether likely to be applied in any case. 

2  As [1] plus takes account of uptake of measures categorised as ‘possible – high’ in terms of whether likely to be applied in any case. 

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Table 5.12  CBM Comparison of Costs of Policy Options to Expected Revenues from Natural Gas Sales 

Measures Included/Excluded 

A 
Recommendation 
plus Guidance 

B 
Amendment + 
Guidance 

C 
Dedicated 
Legislation 
(Directive) 
+ Guidance 

D 
Dedicated 
Legislation 
(Regulation) 
+ Guidance 

Total Annualised Costs of Measures (per pad 

All strictly non-BAU measures 

Non-BAU measures except those likely to be 
applied already 1 

Non-BAU measures except those possibly 
applied already 2 

€ 0 - 356,000 

€ 817,000 

€ 880,000 

€ 970,000 

€ 0 - 352,000 

€ 633,000 

€ 693,000 

€ 783,000 

€ 0 - 315,000 

€ 573,000 

€ 630,000 

€ 708,000 

Annualised Costs as a Percentage of Expected Annual Revenues 

All strictly non-BAU measures 

0.0 – 10.2% 

23.4% 

Non-BAU measures except those likely to be 
applied already 1 

0.0 – 10.1% 

18.1% 

Non-BAU measures except those possibly 
applied already 2 

0.0 – 9.0% 

16.4% 

Notes 

25.2% 

19.8% 

18.0% 

27.8% 

22.4% 

20.3% 

1  Takes account of uptake of measures categorised as ‘yes’ in terms of whether likely to be applied in any case. 

2  As [1] plus takes account of uptake of measures categorised as ‘possible – high’ in terms of whether likely to be applied in any case. 

A number of important considerations should be taken into account in interpreting these data: 

•  The cost of Option A will be determined by the level of ambition adopted, hence cost could 

theoretically be zero for operators and will increase with higher ambition.  Consequently impact on 
revenues could be nil. 

•  Indications from the unconventional gas industry suggest that many of the measures considered in the 
analysis are likely to be adopted (at least in some Member States), regardless of any additional EU risk 
management framework.  This will tend to reduce the overall costs of measures proposed at an EU 
level. 

•  There are a number of measures under each policy option that it has not been possible to quantify 
within the present analysis.  This will tend to increase the overall costs provided that they do not 
qualify as BAU or are otherwise required by Member States. 

•  The estimates above are highly dependent on a number of assumptions, including: 

-  Estimates of gas production volumes per well and the assumed lifetime over which those volumes 
are realised.  For CBM, as noted above, well lifetimes greater than the seven years assumed have 
been suggested by stakeholders consulted for this report.  In addition potential gas production rates 
of approximately 40-110 mcm per well over the well lifetime have been indicated (European Gas 
Ltd (2015)) for CBM.  Increasing well lifetime from 7 to 15 years and increasing gas production 

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rate from 14 to 50 mcm over the well lifetime would reduce the annualised costs as a percentage of 
expected annual revenues for CBM considerably to approximately the following (with non-BAU 
measures ‘likely to be applied’ and ‘possibly applied’ in place): 

(cid:1)  Option A from 0.0 – 9.0% to 0.0 – 2.9% 

(cid:1)  Option B from 16.4% to 2.9% 

(cid:1)  Option C from 18.0% to 3.2% 

(cid:1)  Option D from 20.3% to 3.7% 

-  The estimates are based on best estimates for measure costs using single point values for option 
cost calculation.  Costs may vary and there are uncertainties regarding costs across the large 
number of measures; 

-  Variations in oil and gas prices which have seen fluctuation in the period 2012-2015.  Oil prices 
have fallen since 201245 whilst gas prices have been broadly stable46.  The fall in oil price since 
2012 will have influenced costs and revenue in the industry.  For tight oil using 2015 prices, 
compared to 2012 prices, this would increase the annualised costs as a percentage of expected 
annual revenues (with non-BAU measures ‘likely to be applied’ and ‘possibly applied’ in place) for 
the policy options approximately as follows: 

(cid:1)  Option A from 0.0 – 4.3% to 0.0 – 7.2% 

(cid:1)  Option B 8.0% to 13.4% 

(cid:1)  Option from C 8.7% to 14.5% 

(cid:1)  Option D from 10.3 to 17.2%:  

-  The gas prices used in the analysis, which include some non-recoverable taxes/duties and 

administrative charges (though they exclude recoverable taxes such as VAT); and 

-  Assumptions and uncertainties regarding the costs of the individual measures of which each policy 

option is comprised. 

45 As noted above, oil price in 2012 was approximately €720/m3 ($100 per barrel) (European Commission (2014)).  Oil price in May 2015 is approximately €430/m3 
($60/barrel) (source nasdaq.com, accessed 19th May 2015).   
46 Energy Prices Report, EU BCN, May 2015 (www.energy.eu) indicates gas price of €0.44/m3 based on natural gas consumption in Europe January to April 2015 
compared to €0.43/m3 used in AMEC (2014). 

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6.  Conclusions 

This section presents conclusions based on the preceding sections of the report. 

Differentiating Conventional Fossil Fuels and Unconventional Fossil Fuels 

Regarding the categorisation of UFF: 

•  There is no universally recognised definition of the distinction between CFF and UFF.  What is 

considered to be UFF may vary over time depending on a combination of resource characteristics, the 
exploration and production technology used, the economic environment, and the scale, frequency and 
duration of production from the resource; 

•  The term ‘unconventional’ is typically used to identify the use of previously rarely used techniques 
such as horizontal drilling and hydraulic fracturing.  However, these techniques are now applied to 
many CFF resources and sufficiently frequently that they no longer represent unconventional 
techniques.  An alternative definition refers to hydrocarbons present in the source rock in which the 
resource was originally formed rather than techniques used; this definition includes shale gas and 
CBM but excludes tight oil and tight gas where hydrocarbons have migrated from a source rock to a 
reservoir; 

•  Potential differentiators between CFF and UFF are: 

-  The permeability of the reservoir rock.  Shale gas, tight oil and tight gas are found in formations 
with lower permeability than CFF.  However, the permeability of rocks holding CBM is more 
variable and therefore cannot be readily distinguished from CFF on this basis.  There is no clear 
distinction between CFF and UFF when considering permeability.  There is a continuum from 
highly productive fields characterised by high permeability, through less productive fields, then 
tight gas and finally to very low permeability shale gas; 

-  The geological environment in which CFF and UFF are found.  CFF are typically found in discrete 
accumulations related to a localised geological structural feature and/or stratigraphic conditions 
(e.g. where a cap rock overlies and contains, a reservoir).  In contrast, UFF may be found in much 
more extensive bodies with more gradational boundaries from the play; 

-  The techniques used to exploit CFF versus UFF and in particular the scale of drilling, the extensive 
use of horizontal wells, and the extent of stimulation required at the production stage for UFF. 

•  Shale gas, tight gas and tight oil resource may be grouped together as they share many characteristics 
including: depth; the scale of operations at a well pad; the use of multi-well pads / potential land take; 
and a requirement for the use of hydraulic fracturing to enable production; 

•  CBM resources form a separate group due to the shallower depth of operations; the reduced scale of 
operations at well pads; the use of hydraulic fracturing which is not always required; the smaller 
volume of fracturing fluid used for fracturing; and the use of chemical additives (not always used).  In 

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addition, CBM requires groundwater pumping to reduce pressure, whereas the other forms of UFF do 
not; 

•  Stimulation of reservoirs by hydraulic fracturing can be used in both CFF and UFF.  The main 

differences are the pressure and the volume of water used in the process, i.e. whether it is high volume 
or not and the number of stages of hydraulic fracturing (whether it is a multi-stage process or not); 

Categorisation Options 

Clear categorisation between CFF and UFF and also between different UFF may enable definition of those 
hydrocarbons falling under a given policy instrument.  There is no single categorisation ‘option’ that captures all 
forms of UFF whilst avoiding capturing CFF; however, potential options for categorisation could be based on the 
following (or combinations thereof): 

•  Permeability of the reservoir formation (e.g. 0.6mD is used by Germany to determine the point at 

which a different level of royalty is payable on hydrocarbon production); 

•  Volume of water used in hydraulic fracturing (for shale gas, tight oil and tight gas).  An appropriate 
value is likely to be in the range 1,000 to 10,000 m3 per well.  A water volume-based option has the 
advantage of avoiding most CFF and capturing the principal activity that distinguishes UFF from CFF 
(i.e. high volume hydraulic fracturing) whilst being linked to the risks and impacts of UFF.  However, 
if the volume is set at too high a level it will capture only larger-scale operations. 

•  Pressure applied during hydraulic fracturing (for shale gas, tight oil and tight gas) e.g. more than 700 

bar.  Specifying a particular (high) pressure  applied during hydraulic fracturing would enable 
capturing of UFF but may also capture some CFF and may not capture shallower (lower pressure) 
UFF operations as pressure is related to depth of the target formation, even although risks and impacts  
are potentially similar.  Categorisation using pressure may be somewhat arbitrary. 

•  Depth, due to additional risks presented by shallower operations (proximity to aquifers above wells) 
and deeper operations (greater pressures required for fracturing and the associated well integrity 
requirements).  However, the use of depth may not capture CBM if the depth is set too deep and there 
is not a direct link between risk and impacts and therefore this may be viewed as arbitrary. 

•  Depth for CBM (e.g. operations less than e.g. 1,000 m below ground level) as such operations are 
more likely to be near aquifers used for drinking water or contributing to surface water flow. 

•  Volume of pumped groundwater for CBM (operations producing more than e.g. 20 m3/day / well). 

Comparison of Risks and Impacts 

Regarding a comparison of risks and impacts with those of shale gas: 

•  Differences are predominantly within the technical hydraulic fracturing, well completion and 

production stages; 

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•  CBM is more markedly different than the other UFF types.  This is due to the different properties of 
the reservoir rock (coal), the typically shallower depth, the lower pressures for hydraulic fracturing, 
and the higher quantity and different characteristics of produced waters associated with the 
requirement to lower hydrostatic pressure; 

•  Tight gas and tight oil: 

-  Risks and impacts at well pad identification and preparation; well design, drilling, casing and 

cementing; and well abandonment stages are comparable to shale gas due to the similar nature and 
potential scale of activities. 

-  Risks and impacts associated with the hydraulic fracturing; well completion; and production stages 
linked to water resource depletion are potentially less significant than for shale gas (in particular 
for tight gas) due to less water required for the fracturing process. 

-  For tight oil, it is possible that risks and impacts at the hydraulic fracturing and production stages 
regarding groundwater contamination by hydrocarbons (arising from migration of hydrocarbons 
underground) could be potentially less significant than for shale gas as the heavier hydrocarbon 
will be less mobile in the underground environment than is the case for gas.  Regarding 
groundwater contamination arising from surface operations, although potentially more significant 
than for shale gas due to the liquid rather than gaseous nature of the hydrocarbon, once account is 
taken of BAU risk mitigation measures, risks and impacts for tight oil are judged comparable to 
tight gas. 

•  CBM: 

-  At the well pad, site identification and preparation, and well design drilling, casing and cementing 
stages, traffic and air pollution could potentially have lower risks due to the smaller scale and 
duration of operations and shallower well depths and distances resulting in shorter drilling times; 

-  At the technical hydraulic fracturing stage risks and impacts associated with groundwater 

contamination are potentially more significant for CBM compared to shale gas due to the shallow 
depth of the target formation compared to shale gas.  Equally the risk of fugitive emissions from 
CBM finding their way through rock strata to the surface is potentially more significant for CBM 
compared to shale gas operations; 

-  Risks and impacts associated with hydraulic fracturing; well completion; and production stages 

linked to water resource depletion and traffic are potentially less significant than for shale gas due 
to less water required for the fracturing process and less flowback requiring management and 
associated transportation;  

-  CBM requires pumping of groundwater at the production stage.  The abstraction of groundwater 
presents a risk to water resources in overlying or lateral formations where a hydrogeological 
connection exists.  There is a potentially more significant impact from CBM on water resources 
compared to shale gas during production due to its greater potential proximity to potable resources.  
The traffic burden (linked to transportation of produced water) and associated risks and impacts for 
CBM may potentially be more significant compared to shale gas. 

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•  Risks and impacts at the well abandonment stage are comparable to shale gas due to the similar nature 

of activities; 

•  New risks identified for CBM compared to shale gas are: 

-  Risks of surface water contamination from greater quantities of actively pumped produced water at 
the surface which must be managed and treated to the standard required by permits47.  Increased 
volumes requiring more frequent transport, treatment and discharge may result in an increased risk 
of surface water contamination (e.g. through spillage during transfer, treatment plant failure); 

-  Risks of increased water resource depletion from groundwater supplies being drawn down towards 

the target formation; 

-  Potential risk of groundwater contamination due to the need for groundwater pumping and 

associated potential impacts on groundwater resources and quality; and 

-  Potential risk of gases seeping through geological strata and being released as fugitive emissions 

due to the shallower depth and lack of barrier rock strata above the target formation. 

Measures Appropriateness and Proportionality 

Regarding the appropriateness and proportionality of measures developed for shale gas for other UFF: 

•  Water resource depletion measures: all measures are judged appropriate for tight oil, tight gas and 
CBM and all measures are judged proportionate for tight oil and tight gas.  Due to lower water 
demand requirements for CBM, there are a number of measures that are judged to be over-specified 
for CBM; 

•  Traffic measures: all measures are considered appropriate for tight oil, tight gas and CBM.  Due to 

fewer vehicle movements associated with water and flowback management, a number of measures are 
judged to be over-specified for tight oil, tight gas and CBM but may not necessarily be overspecified 
for the management of produced water (with the exception for CBM of a measure to reduce vehicle 
movements associated with managing pumped groundwater through site selection close to waste water 
treatment/disposal facilities to minimise haulage requirements); 

•  Releases to air: assessed for CBM due to potentially smaller scale activities and pad size and also 

shallower wells, resulting in shorter duration of diesel powered mobile plant and drilling rigs required.  
Measures for shale gas are judged appropriate and proportionate for tight oil and CBM; 

•  Land take: assessed for CBM only and related to potentially smaller scale activities and pad size 
(relevant measures relate to optimisation (e.g. pad spacing, density), cumulative effects and 
undertaking Strategic Environment Assessment).  Measures are judged appropriate and proportionate 
for CBM; 

47 Produced water has variable quality (e.g. USEPA (2013) and Umweltbundesamt (2013)) indicate a range from 7 to 128,000 mg/l total dissolved solids in produced 
water from CBM formations. 

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•  Visual Impact: assessed for CBM only and related to potentially smaller scale activities and pad size 
(relevant measures relate to the requirement for Environment Impact Assessment and cumulative 
impacts).  Measures are judged to be appropriate and proportionate for CBM; 

•  Groundwater contamination: assessed for CBM only and related to potentially more significant risks 
and impacts arising from the shallower depths of formations, potential proximity to potable water 
resources and potential for affecting overlying groundwater resources due to the need for groundwater 
pumping in the target formation.  All measures are judged appropriate and proportionate to CBM; 

•  New risks of CBM regarding water resource depletion due to the groundwater pumping required: 

whilst existing available measures (focussed on addressing groundwater contamination risks) include 
aspects such as modelling groundwater flows, additional measures may be required to: 

-  Model the impact of groundwater pumping on linked groundwater flows and quality; 

-  Extend groundwater monitoring requirements; and 

-  Require active groundwater level management where potable resources are impacted. 

Policy Options Assessment 

Sections 5.4 of AMEC (2014) sets out conclusions of the overall effectiveness and efficiency of the general policy 
options considered, which is not repeated here. 

Regarding the costs associated with the selected policy options, the total annualised compliance costs of the 
selected policy options for operators per pad are estimated at48: 

Table 6.1 

Total Annualised Compliance Costs for Operators of the Selected Policy Options for Operators (€ per 
pad) 

Policy Option 

Tight gas 

Tight oil 

CBM 

Option A1 
Recommendation 
plus Guidance 

Option B 
Amendment to the 
Acquis plus 
Guidance 

Option C2 
Dedicated Legislation 
(Directive) 
+ Guidance 

Option D 
Dedicated Legislation 
(Regulation) 
+ Guidance 

0 to 966,000 

0 to 968,000 

0 to 817,000 

966,000 

968,000 

817,000 

1,012,000 

1,015,000 

880,000 

1,102,000 

1,105,000 

970,000 

Compared to the option costs for shale gas,49 annualised costs are lower for tight gas and tight oil due to the greater 
assumed well lifetime of 20 years compared to that assumed for shale gas of 10 years.  For CBM, although the 

48 Refer to notes in tables in Section 5 regarding notes on option cost ranges. 
49 Option A: €0 to €1,512,000; Option B: €1,512,000; Option C: €1,578,000; Option D: €1,674,000. 

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assumed well lifetime is seven years compared to ten for shale gas, a combination of fewer measures selected and a 
reduction of the capital cost associated with well safety due to shallower well depth (1,000 m vs. 3,000 m for shale 
gas) and well horizontal length (250 m vs. 1,350 m for shale gas) combined with fewer wells per pad (four per pad 
vs. eight per pad for shale gas) reduces costs per pad compliance50. 

The cost of Option A will be determined by the level of ambition adopted and hence could incur no cost for 
operators and authorities if a low level of ambition is embraced.  Taking account of measures that are likely to be 
applied as normal practice by operators is important so as not to overstate potential compliance costs.  The effect of 
factoring uptake of measures due to the application of normal practice is to reduce the estimated total compliance 
costs from pre-adjusted estimates.  The total annualised compliance costs of the selected policy options per pad 
taking account of measures that are ‘likely’ to be applied and those that will ‘possibly’ be applied are estimated 
at51: 

Table 6.2 

Total Annualised Compliance Costs, with Adjustment for non-BAU measures likely to be applied and 
possible to be applied (€ per pad) 

Policy Option 

Tight gas 

Tight oil 

CBM 

Option A1 
Recommendation 
plus Guidance  

Option B 
Amendment to 
the Acquis plus 
Guidance 

Option C2 
Dedicated Legislation 
(Directive) 
+ Guidance 

Option D 
Dedicated Legislation 
(Regulation) 
+ Guidance 

0 to 409,000 

0 to 412,000 

0 to 574,000 

409,000 

412,000 

574,000 

449,000 

451,000 

644,000 

530,000 

533,000 

722,000 

It should be noted that the cost estimates exclusively address preventive measures and do not include costs for 
remediation of accidental events. 

The estimated compliance costs as a percentage of expected revenues for tight gas are similar in magnitude to those 
calculated for shale gas (see AMEC (2014)).  The percentage of expected revenues for CBM and tight oil are 
higher than for tight gas and shale gas.  This is due to the assumed lifetime production volumes and associated 
revenues and in addition for CBM, the smaller reduction in compliance costs when taking account of measures that 
may be applied already by operators (see Section 5.4.2 for further details on this point).  However, for CBM longer 
well lifetimes and higher gas production rates have been reported than those assumed here, hence compliance costs 
as a percentage of expected revenues may be lower (see Section 5.5. for further detail on this point). 

50 Note that well lifetimes are reported to vary significantly.  USEPA (2013) indicates 5-15 years, Amec Foster Wheeler experience in Australia indicates 2-5 years 
and personal communication with European Gas Ltd (2015) has suggested 15-25 years.  Adjusting well lifetime for CBM from 7 to 15 years would result in total 
annualised compliance costs per pad of Option A of €0 to 506,000, Option B €506,000, Option C €553,000 and Option D €619,000. 
51 Refer to notes in tables in Section 5 regarding notes on option cost ranges. 

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Administrative costs associated with the options for tight gas, tight oil and CBM will be analogous to those 
determined in AMEC (2014) as the general nature of the options remains consistent.   

Regarding benefits of the options, the measures in policy options are principally aimed at prevention of possible 
environmental risks (e.g. technical measures to avoid well failure resulting in groundwater pollution, or effective 
management of wastewaters at surface level to avoid spills and accidental discharges to surface water and/or land). 

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Reserves Conference 

Shemeta, J E, Eide, E A, Hitzman, M W, Clarke, D D, Detournay, E, Dieterich, J H, and Gibbs, C R, 2012.  The 
potential for induced seismicity in energy technologies. The Leading Edge, 31(12) 

Tzimas, E. 2005.  Enhanced Oil Recovery using Carbon Dioxide in the European Energy System. European 
Commission Joint Research Centre 

UK Department of Energy and Climate Change, 2010.  The unconventional hydrocarbon resources of Britain’s 
onshore basins- shale gas 

UK Department of Energy and Climate Change 2013a. The Carboniferous Bowland Shale gas study: geology and 
resource estimation 

UK Department of Energy and Climate Change, 2013b.  Onshore oil and gas exploration in the UK: regulation and 
best practice: England 

UK Department of Energy and Climate Change, 2014.  Wall map showing current fields and licensing.  (at 
https://www.gov.uk/oil-and-gas-onshore-maps-and-gis-shapefiles) 

UK Water Industries Research, 2014.  Understanding the potential impacts of the extraction of unconventional 
gases on the UK water industry: stage 2 report. Report Ref. No. WR09C301 

Umweltbundesamt [UB], 2013.  Environmental Impacts of Fracking Related to Exploration and Exploitation of 
Unconventional Natural gas Deposits.  Risk Assessment, Recommendations for Action and Evaluation of Relevant 
Existing Legal Provisions and Administrative Structures 

US Department of the Interior, Bureau of Reclamation, 2011.  Oil and Gas Produced Water Management and 
Beneficial Use in the Western United States.  Science and Technology Program Report No. 157 

US Energy Information Administration (USEIA), 2013.  World Shale Gas and Shale Oil Resource Assessment 
Technically Recoverable Shale Gas and Shale Oil Resources: An Assessment of 137 Shale Formations in 41 
Countries outside the United States. Prepared by Advanced Resources International Inc. 

US Energy Information Administration (USEIA), 2014.  Annual Energy Outlook 2014.  With projections to 2040 

US Environmental Protection Agency, undated.  Enhanced CBM/ CMM Recovery 

US Environmental Protection Agency, 2004.  Evaluation of Impacts to Underground Sources of Drinking Water by 
Hydraulic Fracturing of Coalbed Methane Reservoirs Study 

© Amec Foster Wheeler Environment & Infrastructure UK Limited 
August 2015 
Doc Reg No. 

 
 
 
 
 
 
101 

US Environmental Protection Agency, 2010.  Coalbed Methane Extraction: Detailed Study Report 

US Environmental Protection Agency, 2011.  Plan to Study the Potential Impacts of Hydraulic Fracturing on 
Drinking Water Resources 

US Environmental Protection Agency, 2013.  Technical Development Document for the Coalbed Methane (CBM) 
Extraction Industry 

US Geological Survey, undated.  Water Produced with Coal-Bed Methane 

US Geological Survey, 2002.  Produced Waters Database. U.S. Department of the Interior 

US Geological Survey, 2012.  Variability of Distributions of Well-Scale Estimated Ultimate Recovery for 
Continuous (Unconventional) Oil and Gas Resources in the United States. Open-File Report 2012–1118 

© Amec Foster Wheeler Environment & Infrastructure UK Limited 
August 2015 
Doc Reg No. 

 
 
 
 
 
 
 
 
102 

© Amec Foster Wheeler Environment & Infrastructure UK Limited 
August 2015 
Doc Reg No. 

 
 
 
 
 
 
 
 
Appendix A 
Illustrative Concession Information 

© Amec Foster Wheeler Environment & Infrastructure UK Limited 
August 2015 
Doc Reg No. 

 
 
 
 
 
 
 
 
 
 
 
© Amec Foster Wheeler Environment & Infrastructure UK Limited 
August 2015 
Doc Reg No. 

 
 
 
 
 
 
 
 
 
Background 

Development of a baseline scenario of ‘no policy action’ is a critical first step for policy option development to 
address a risk management framework for unconventional gas extraction in the EU.  Considering the uncertainty of 
future development of unconventional hydrocarbons in Europe, the context of an illustrative unconventional 
hydrocarbon concession is used as a unit concept for evaluation of potential environmental, economic and/or social 
impacts for both baseline and policy options scenarios.   

Methodology 

An illustrative unconventional hydrocarbon concession has been developed by first selecting a number of 
parameters that are required in relation to calculations of per measure costs, including physical aspects (e.g. number 
of pads/wells), the types and scale of resources required (e.g. fuel/electricity use, water and chemicals used in 
hydraulic fracturing) and outputs generated (e.g. flowback).  For each parameter, either a point estimate or a range 
of values was assigned, based on available literature. 

It should be noted that the characteristics of European other UFF developments are limited and the available 
literature also refers to conditions of other UFF activities, mainly in North America.  Expert judgement from 
project team members was used to adjust values from outside Europe to better reflect the European context. 

Purpose 

This appendix has been produced for the purpose of summarising the key parameters and assumptions used to 
define illustrative unconventional hydrocarbon concessions for other UFF.  It is possible that more than one 
concession is granted per play – total play size would vary extensively from country to country.   

The details, including source references, of further parameters and units/unit ranges are provided in the following 
tables.  Some of the parameters (e.g. well depth, volume of water used, flowback and produced, etc.) have been 
used in estimating compliance and administrative costs in Section 5. 

Monitoring 

In addition to the parameters set out in this appendix, it was assumed that the following is carried out for the 
illustrative concessions: 

•  Baseline monitoring: establishment of the presence of methane in groundwater, including drinking 

water; 

•  Baseline monitoring: undertaking the sampling of groundwater; 

•  Baseline monitoring: Development of a geological, hydrogeological and seismic conceptual model 
including obtaining geomechanical information on fractures, stress, rock strength, in situ fluid 
pressures; and 

•  Monitoring during exploration and production: monitoring of groundwater. 

© Amec Foster Wheeler Environment & Infrastructure UK Limited 
August 2015 
Doc Reg No. 

 
 
 
 
 
 
 
References 

Refer to Section 7 for full references. 

© Amec Foster Wheeler Environment & Infrastructure UK Limited 
August 2015 
Doc Reg No. 

 
 
 
 
 
 
 
 
 
Illustrative concession: tight gas

#

Parameter

Length of horizontal well

Type

Physical

Value

1,350

Min

30

Max

3000

Unit Notes

m ICF (2013) horizontal = 900 - 1500 - 3000 m.

Ewen et al (2012). 1300 m.
LBEG (2014) 30-2150m, suggest 800m (based on tight gas wells of 2 fields).
Suggest 1350 as per shale gas.  Rock type is not the determining factor.

Reference

AMEC expert judgement

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

51

52

53

Depth of vertical well

Physical

3,000

1800

5750

m ICF (2013) depth of injection = 1800 - 3000 - 4200 m.

AMEC expert judgement

Area (overground) covered by well pad during 
construction

Physical

Area (overground) covered by well pad during 
operation

Physical

Area (underground = gas formation) covered 
by well pad

Physical

6

2.24

320

LBEG (2014) 4400-5750 m, suggest 5,000 (based on tight gas wells of 2 fields).
Ewen et al (2012) 3500-5000 m.
Suggest 3000m as per shale gas.  Rock type is not he determining factor.

hectares Based on historical data.  There is no reason why future developments may not be similar size to shale gas 

AMEC expert judgement

however.
Assume same area as shale gas.
hectares LBEG (2014) estimates 30 x 30m.

AMEC expert judgement

Based on historical data.  There is no reason why future developments may not be similar size to shale gas.  
Assume same as shale gas.

hectares LBEG (2014) comment that one can assume nearly the horizontal range of the well path for one direction (s. 

AMEC expert judgement

question 1) multiplied by frac dimension in horizontal range.
Ewen et al (2012) estimate 900 hectares for a 14 well pad.
Assume same as shale gas as assuming same horizontal well length.

Area per concession

Physical

800

7.5

75

km2 LBEG (2014) information indicates average concession size for hydrocarbons (not only limited to tight gas) of 

AMEC expert judgement

# of well pad sites per concession

Distance between well pad sites

Area occupied by well installations

# of well heads per well pad

Vertical drilling per day

Horizontal drilling per day

Days required for vertical drilling

Days required for horizontal drilling

Duration of the drilling stage

Rate of mud generation from drilling

Mud generated from drilling

Physical

Physical

Physical

Physical

Physical

Physical

Time

Time

Time

Waste

Waste

250

1.5

0.7%

8

110

55

27

25

52

697km2.  LBEG (2014) range 1 to 170 km2 for hydrocarbons. Production licences of tight gas specifically range 7.5 
to 75 km2.  However no reason for difference to shale gas in future if fully developed.  Production Licences are 
depending on sizes of gas fields.  On balance, assume same as shale gas for future sceanrio.

units Calculated

0.2

2.5

km LBEG (2014) indicates 200-2500m. Suggest 1500m which is consistent with Ewen et al (2012).

% of the land area 
(concession)

Calculated

Calculated

Ewen et al (2012)
LBEG (2014)
Calculated

1

14

units per well pad LBEG (2014) indicates 1 well per pad based on historic data.

AMEC expert judgement

Ewen et al (2012) indicate well pads with up to 14 wells.
Assume same as shale gas. 

metres / day LBEG (2014) - indicates 15 - 65 days, 35 days proposed.  No differentiation between vertical and horizontal drilling 

AMEC expert judgement

however.  LBEG (2014) no. appears low.  No reason for difference with shale gas.

15

65

metres / day LBEG (2014) - indicates 15 - 65 days, 35 days proposed.  No differentiation between vertical and horizontal drilling 

AMEC expert judgement

however.  No reason for difference with shale gas.

days / well Calculated: depth of well divided by drilling length per day

days / well Calculated: depth of well divided by drilling length per day

100

200

days / well LBEG (2014) indicates 100-200 days, 120 days proposed.

Calculated

Calculated

Calculated

            0.47              0.63 

m^3 per metre 
drilled

Calculated based on assumptions.
Original assumptions for shale gas: 0.9 to 1.2 barrels of mud generated per foot drilled. Converted to metric units. 
Assume as per shale gas.
Calculated from depth of well drilled and rate of mud generation (average is used)

AMEC expert judgement

AMEC expert judgement

                      1,650            1,410            1,890 

m^3

Expected # of wells developed in the EU

Physical

Expected # of well pads developed in the EU

Physical

Required vol. of fracturing fluid in hydraulic 
fracturing

Resource

No data

No data

6,000

100

12000 m^3 per fracturing LBEG (2014) 100-1000m3.

Ewen et al (2012) 1600 per frack for 10 fracks.
ICF (2013) 200--1400-7100 m3.
UB (2013) 12000 m3.
Danish Energy Ministry (2012), Communication to European Commission (in AEA 2012): 7,000-8,000m3 from .

Number of fractures per well during lifetime

Physical

2

1

9

times LBEG (2014) indicates all wells are still in use, and wells may be refracturing in future.  Newer wells have more (up 

% Flowback, out of total vol. of fracture fluid 
used per fracture
Flowback from fracture fluid (volume) per 
fracture
Flowback from fracturing fluid (volume) per 
well lifetime
% Flowback recycle rate

Volume of recycled fracture fluid, to be used 
for further fracturing (volume)
Fracturing fluid - water content

Volume of water (fresh or recycled) in fracture 
fluid per fracturing
Not used

Waste

Waste

Waste

Waste

Waste

Resource

Resource

25%

17%

35%

% Data from 3 wells = 17% - UB (2013)

to 9) fracs well, older wells have only 1-2 fracs per well.  Assume 2 fracs per well over lifetime.

70 - 430 - 2100 m^3 ICF (2013) = approximately 30-35%.
Calculated based on volume of fracture fluid used and % flowback

1,500

3,000

35%

2100

90%

m^3 per fracturing

m^3 per well

%

m^3 per fracturing

Calculated based on volume of fracturing fluid used and % recycling

% of total volume Calculated from % additives and proppant

                      5,400 

m^3 per fracturing

Calculated based on volume of fracture fluid and proportion of water in fracture fluid

Calculated based on volume of flowback and number of fractures per well lifetime

Calculated

Assumption based on 
ranges identified

Assumption based on 
LBEG (2014) data.
Assumption based on UB 
(2013) and ICF (2013) 
Calculated

AMEC expert judgement

Calculated

Calculated

Calculated

Calculated

Water use in fracturing per well lifetime

Resource

m^3 per well Calculated

                    10,950 

Proppant content in fracturing fluid

Resource

9.50%

2.0%

25%

% Larger % related to small volumes.

AMEC expert judgement

Density of proppant

Quantity of proppant in fracture fluid per 
fracturing
Quantity of proppant in fracture fluid per well 
lifetime
Fracturing fluid - additives

Volume of additives in fracture fluid per 
fracturing
Volume of additives in fracture fluid per well 
lifetime

38 Required water storage availability

39 Required proppant storage availability

40 Required additive storage availability

41

42

43

44

45

46

47

48

Storage capacity per truck

# of truck movements to manage freshwater in 
2 hydraulic fracturing
# of truck movements to manage flowback in 2 
hydraulic fracturing
# of site construction truck movements

# drilling stage truck movements

Cuttings additional volume from a horizontal 
well compared to a vertical well
Salinity of produced water

Types and levels of contaminants in flowback 
water

Gas production (URR)

                        1.95 

                      1,112 

                      2,223 

ICF (2013) = 0 - 0.1 - 0.7 million kg/well.
UB (2013) 2%.
Ewen et al (2012) 2%.
LBEG (2014) indicates 60-250t in 100-1000m3.
Assume as per shale gas.
Assumed to be equal to density of wet sand

tonnes/m^3

EC

tonnes Calculated based on volume of fracture fluid,  proportion of proppant in fracture fluid and density of proppant

Calculated

Calculated based on volume of proppant and number of fractures during well lifetime

Calculated

tonnes

0.50%

0.001%

13.00%

% Large amounts relate to older activity.

AMEC expert judgement

                           30 

                           60 

                      6,000 

                      1,112 

                           30 

40

274

49

135

515

40%

Assume similar to more recent shale gas operations (0.5%)
Calculated based on volume of fracture fluid and proportion of additives in fracture fluid

Calculated based on volume of additives and number of fractures during well lifetime

m^3

m^3

m^3 Calculated based on volume of fracture fluid.

tonnes Equivalent to required volume for one fracture

m^3 Equivalent to required volume for one fracture

m^3

trucks

trucks

Calculated: required water divided by storage capacity per truck

Calculated

trucks Assume same pad size as shale gas.
Ewen et al (2012) indicates 70.

trucks Estimated value

Calculated

Calculated

Calculated

Calculated

Calculated

AEAT (2012)

Calculated

Calculated

AMEC expert judgement

AMEC expert judgement

greater compared to 
a vertical well

Horizontal drilling penetrates a greater linear distance of rock and therefore produces a larger volume of drill cuttings 
than does a well drilled vertically to the same depth below the ground surface

NYSDES (2011)

5,000

200,000

ppm Formation specific.  Assume as per shale gas.

See Table in source reference for information on contaminants.
Formation specific.  Assume as per shale gas.
UB (2013) notes NORM, mercury, BTEX toxic metals.

AMEC expert judgement

Table 2 of AEAT (2012) 

56

185

mcm per well URR is assumed to be comparable with shale gas.  Indications from experience in N America is that their shale gas 
and tight gas wells are comparable with some more or less productive - but this not dependent on whethr shale gas 
or tight gas specifically. JRC IET study indicate 56-185 mcm over 30 year lifetime.

JRC IET study

Resource

Resource

Resource

Resource

Resource

Resource

Resource

Resource

Resource

Resource

Resource

Resource

Resource

Resource

Resource

Waste

Waste

Output

49
50 Re-fracturing (occurrence)

Well lifetime

Time

Time

1

20

0

0

30

(Note: USGS 2012 indicates a estimated ultimate recovery range of 0.044-1.657 bcf (1.2 to 46.9 mcm) with an 
average of 17.2 mcm.  Note that lifetime of well is not stated.).

over a well lifetime

years LBEG (2014) indicates wells remain open with oldest from early 1980s and latest from 2008.

Suggest possible 30+ year lifetime although could be similar to shale gas.
Assume 20 years - could be an argument to set at 10 years as per shale gas.

Fuel/energy demand

Resource

1500

3000

kW As shale gas

Volume of produced water

Waste

0.62

0.01

1.72

m3/well/day Low = <200 gallon 

(0.75m3) per MMCF. Medium = 200-1000 gallon 
(0.75 - 3.78m3) per MMCF. High = >1000 gallon (>3.78m3) per MMCF.
Figures here are calculated based on ranges and URR over 10 years.
Value based on average of overall ranges calculated - see produced water sheet.

LBEG (2014)

Assumption based on 
LBEG (2014) data.

AMEC expert judgement

Mantle (2011)

H:\Projects\35229 EC risk man of unconventional hydrocarbons\D Data\Reports\Final\Appendix A.xlsx

Tight gas

1 of 3

Illustrative concession: tight oil

#

Parameter

Length of horizontal well

Type

Physical

Value

1,350

Min

800

Max

4500

Depth of vertical well

Physical

3,000

600

3600

m ICF (2013) depth of injection = 1200 - 2400 - 3600 m.

Unit Notes

m ICF (2013) horizontal = 1200 - 2400 - 4500 m

Suggest 1350 as per shale gas.
CSUR (undated)/Halliburton (2008) 800 m.
Rock type is not the determining factor.

Suggest 3000 as per shale gas.  Rock type is not the determining factor.
All Consulting (2012) = 600 to 2,900 m in Canada

hectares Assume as per shale & tight gas.

hectares Assume as per shale & tight gas.

hectares Assume as per shale & tight gas.

km2 Assume as per shale & tight gas.

units Calculated

0.5

2

km Assume as per shale & tight gas.

% of the land area 
(concession)

Calculated

1

15

15

14

units per well pad Assume as per shale & tight gas.

110

65

metres / day Assume as per shale & tight gas.

metres / day Assume as per shale & tight gas.

days / well Calculated: depth of well divided by drilling length per day

days / well Calculated: depth of well divided by drilling length per day

100

200

days / well Calculated

6

2.24

320

800

250

1.5

0.7%

8

110

55

27

25

52

Area (overground) covered by well pad during 
construction

Physical

Area (overground) covered by well pad during 
operation
Area (underground = oil formation) covered by 
well pad
Area per concession

# of well pad sites per concession

Distance between well pad sites

Area occupied by well installations

# of well heads per well pad

Vertical drilling per day

Horizontal drilling per day

Days required for vertical drilling

Days required for horizontal drilling

Duration of the drilling stage

Rate of mud generation from drilling

Mud generated from drilling

Physical

Physical

Physical

Physical

Physical

Physical

Physical

Physical

Physical

Time

Time

Time

Waste

Waste

            0.47              0.63 

m^3 per metre 
drilled

Original assumptions for shale gas 0.9 to 1.2 barrels of mud generated per foot drilled. Converted to metric units. 
Assume as per shale gas.
Calculated from depth of well drilled and rate of mud generation (average is used)

AMEC expert judgement

Calculated

                      1,650            1,410            1,890 

m^3

Expected # of wells developed in the EU

Physical

Expected # of well pads developed in the EU

Physical

Required vol. of fracturing fluid in hydraulic 
fracturing
Number of fractures per well during lifetime

Resource

Physical

No data

No data

11,400

2

500

25600 m^3 per fracturing ICF (2013) 5700-11400-25600 m3

All Consulting (2012) 500m3

times For tight gas, LBEG (2014) indicates all wells are still in use, and wells may be refracturing in future.  Newer wells 

have more (up to 9) fracs well, older wells have only 1-2 fracs per well.  Assume 2 fracs per well over lifetime.  
Assume as per tight gas.

35%

10%

60%

% 3400 - 6800 - 15300 m^3  ICF (2013)

m^3 per fracturing

m^3 per well

Calculated based on volume of fracture fluid used and % flowback

Calculated based on volume of flowback and number of fractures per well lifetime

% Assum as per tight and shale gas.

AMEC expert judgement

Calculated based on volume of fracturing fluid used and % recycling

Calculated

                    10,260 

m^3 per fracturing

m^3 per fracturing

% of total volume 0.5 - 1.1 - 2.5 kg/well  ICF (2013)

Assume as per shale and tight gas.
Calculated based on volume of fracture fluid and proportion of water in fracture fluid

Water use in fracturing per well lifetime

Resource

m^3 per well Calculated

Proppant content in fracturing fluid

Resource

9.50%

                    20,007 

% ICF (2013) = 0.5 - 1.1 - 2.5 million kg/well

Assume as per shale and tight gas.
Assumed to be equal to density of wet sand

tonnes/m^3

Reference

AMEC expert judgement

Assumption based on 
ranges identified

AMEC expert judgement

AMEC expert judgement

AMEC expert judgement

AMEC expert judgement

Calculated

AMEC expert judgement

Calculated

AMEC expert judgement

AMEC expert judgement

AMEC expert judgement

Calculated

Calculated

Calculated

All Consulting (2012)
ICF (2013)
Assumption based on 
LBEG (2014) data.

ICF (2013)

Calculated

Calculated

AMEC expert judgement

Calculated

Calculated

AMEC expert judgement

EC

tonnes Calculated based on volume of fracture fluid,  proportion of proppant in fracture fluid and density of proppant

Calculated

Calculated based on volume of proppant and number of fractures during well lifetime

Calculated

tonnes

% Assume as per shale and tight gas.

Calculated based on volume of fracture fluid and proportion of additives in fracture fluid

Calculated based on volume of additives and number of fractures during well lifetime

m^3

m^3

m^3 Calculated based on volume of fracture fluid.

tonnes Equivalent to required volume for one fracture

m^3 Equivalent to required volume for one fracture

m^3

trucks

trucks

Calculated: required water divided by storage capacity per truck

Calculated

trucks Assume same pad size as shale & tight gas.

Ewen et al (2012) indicates 70.

trucks Assume as per shale and tight gas.

AMEC expert judgement

Calculated

Calculated

Calculated

Calculated

Calculated

AEAT (2012)

Calculated

Calculated

AMEC expert judgement

AMEC expert judgement

211

200,000

greater compared to 
a vertical well

Horizontal drilling penetrates a greater linear distance of rock and therefore produces a larger volume of drill cuttings 
than does a well drilled vertically to the same depth below the ground surface

NYSDES (2011)

ppm All Consulting (2012) 211 to 107,000 mg/l as chloride.
AEAT (2012) for shale gas indicates upto 200,000.
Salinity if highly formation specific.  Assume as per shale gas.
Formation specific.  Assume as per shale gas but with the addition of heavier hydrocarbons associated with oil also 
present.
UB (2013) notes NORM, mercury, BTEX toxic metals.

All Consulting (2012)
AEAT (2012)

Table 2 of AEAT (2012) 

Oil production (URR)

Output

17,807

m3 per well Based on 168,000 US petroleum barrels estimated ultimate recovery per well for a 30 year lifetime (26,710m3), 

US EAI 2014

50 Re-fracturing (occurrence)
51 Well lifetime

Fuel/energy demand

Time

Time

Resource

52
53

Volume of produced water

Waste

1

20

n/a

adjusted to the assumed well lifetime. 
These are not used in calculation of costs for individual measures

1

9

30

over a well lifetime Assume as per shale and tight gas.

years Assume as per tight gas.

1500

3000

kW Assume as per tight gas.

Water is miixed with oil

AMEC expert judgement

AMEC expert judgement

AMEC expert judgement

AMEC expert judgement

% Flowback, out of total vol. of fracture fluid 
used per fracture
Flowback from fracture fluid (volume) per 
fracture
Flowback from fracturing fluid (volume) per 
well lifetime
% Flowback recycle rate

Volume of recycled fracture fluid, to be used 
for further fracturing (volume)
Fracturing fluid - water content

Volume of water (fresh or recycled) in fracture 
fluid per fracturing
Not used

Waste

Waste

Waste

Waste

Waste

Resource

Resource

3,990

7,980

35%

3990

90%

Density of proppant

Quantity of proppant in fracture fluid per 
fracturing
Quantity of proppant in fracture fluid per well 
lifetime
Fracturing fluid - additives

Volume of additives in fracture fluid per 
fracturing
Volume of additives in fracture fluid per well 
lifetime

38 Required water storage availability

39 Required proppant storage availability

40 Required additive storage availability

Storage capacity per truck

# of truck movements to manage freshwater in 
2 hydraulic fracturing
# of truck movements to manage flowback in 2 
hydraulic fracturing
# of site construction truck movements

# drilling stage truck movements

Cuttings additional volume from a horizontal 
well compared to a vertical well
Salinity of produced water

Types and levels of contaminants in flowback 
water

                        1.95 

                      2,112 

                      4,224 

0.50%

                           57 

                         114 

                    11,400 

                      2,112 

                           57 

40

500

130

135

515

40%

Resource

Resource

Resource

Resource

Resource

Resource

Resource

Resource

Resource

Resource

Resource

Resource

Resource

Resource

Resource

Waste

Waste

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

41

42

43

44

45

46

47

48

49

H:\Projects\35229 EC risk man of unconventional hydrocarbons\D Data\Reports\Final\Appendix A.xlsx

Tight oil

2 of 3

Illustrative concession: coal bed methane

#

Parameter

Length of horizontal well

Type

Physical

Value

250

Min

50

Max

1200

Unit Notes

m ICF (2013): 300-1200

Depth of vertical well

Physical

1,000

200

1500

m Dart Energy (2012) 850m.

AMEC AU view: 50-100m
AMEC US view: horizontal not used in CBM.

Area (overground) covered by well pad during 
construction

Physical

Area (overground) covered by well pad during 
operation

Physical

Area (underground =  gas formation) covered 
by well pad
Area per concession

Physical

Physical

# of well pad sites per concession

Distance between well pad sites

Area occupied by well installations

# of well heads per well pad

Vertical drilling per day

Horizontal drilling per day

Days required for vertical drilling

Days required for horizontal drilling

Duration of the drilling stage

Physical

Physical

Physical

Physical

Physical

Physical

Time

Time

Time

Rate of mud generation from drilling

Waste

ICF (2013) depth of injection = 500 - 900 - 1500 m.
EA (2014) 600 to 1100m (target at 850m).
All Consulting (2012) 1,000 m in Munsterlander-Becker Region, Germany
AMEC AU expert: 200-1200m

1.1

hectares per pad Assumption based on factor between construction (6 hec) and production (2.24 hec) pad size for shale gas 

multiplied by known pad size.

0.4

0.02

1

hectares per pad Dart Energy (2012), 0.4 hectares and 14 x pad arrangement (combination of water pumping and gas extraction 

0.5

100

20

1860

0.5

4

20

800

250

1.5

0.13%

wells)
EA (2014), 1.0 hectares.
AMEC AU expert suggests 0.02-0,04 hectares.

hectares AMEC AU expert: 5,000-10,000 m2

AMEC US: 40-60 acres/well.  Assume 50 acres = 20 hectares

km2 Data from CBM concession (permitted area) sizes in France (2014).  EGL, Bleue Lorraine Sud 264 km², EGL, Lons 

le saunier 1860 km², Gazonor, Valenciennois, 432 km², Gazonor, Sud midi, 929 km².  Average = 871 km2. 
Ministère de l'écologie, du développement durable et de l'énergie 2014.
AMEC AU expert: 100-400km2.
Assume as per other UFFs.

number Assumed whole concession is not in production.  Assume same number of well pads as per shale gas.

km Ewen et al (2012): 1.5 km.
AMEC AU expert: 1-4km.
AMEC US: 0.5km
Note. Spacing unlikely to be consistent due to geological conditions, i.e. clusters may exist.
Calculated

% of the land area 
(concession)

4

1

8

units per well pad EA (2014) indicates 4 wells on pilot site.

110

55

9

5

14

0.11

15

9

5

14

65

21

14

35

Dart Energy (2012) indicates single.
AMEC AU expert: 2-8 wells per pad.
AMEC US view: one well per pad.
Dependant on well configuration.

metres / day Assume as per tight gas.

metres / day Assume as per tight gas.

days / well Calculated: depth of well divided by drilling length per day

Dart (2012) suggests 21 days for 850m

days / well Calculated: depth of well divided by drilling length per day

Dart suggests 14 days

days / well Calculated

m^3 per metre 
drilled

Equivalent to 0.11m^3 per m drilled (180m^3 / 1600m well length + depth)

Mud generated from drilling

Waste

                         110 

m^3 Calculated

Expected # of wells developed in the EU

Physical

Expected # of well pads developed in the EU

Physical

No data

No data

Required vol. of fracturing fluid in hydraulic 
fracturing

Resource

500

0

4700 m^3 per fracturing ICF (2013)= 0 - 100 - 4700m3

Number of fractures per well during lifetime

Physical

2

USEPA (2004) 220-570m3/well
USEPA (2011) = 200 - 1500m3/well

times USEPA (2004) suggests refracturing is typical.

Assume 2 fractures over lifetime (i.e. 1 refracture)

Waste

Waste

Waste

Waste

Waste

% Flowback, out of total vol. of fracture fluid 
used per fracture
Flowback from fracture fluid (volume) per 
fracture
Flowback from fracturing fluid (volume) per 
well lifetime
% Flowback recycle rate

Volume of recycled fracture fluid, to be used 
for further fracturing (volume)
Fracturing fluid - water content

Volume of water (fresh or recycled) in fracture 
fluid per fracturing
Not used

350

700

35%

175

70%

61%

82%

% CBM dewaters well - so flowback and production are different to other UFF.

Assume mid point at approx 70%.

m^3 per fracturing Calculated based on volume of fracture fluid used and % flowback

m^3 per well Calculated based on volume of flowback and number of fractures per well lifetime

% Assum as per tight and shale gas.

AMEC expert judgement.

Resource

91.5%

% of total volume Calculated

Resource

                         458 

m^3 per fracturing Calculated based on volume of fracture fluid and proportion of water in fracture fluid

m^3 per fracturing Calculated based on volume of fracturing fluid used and % recycling

Water use in fracturing per well lifetime

Resource

                         755 

m^3 per well Calculated

Proppant content in fracturing fluid

Resource

8.00%

0.0%

8%

% ICF (2013) = 0.0 - 0.0 - 0.5 million kg/well.  CBM may not use proppant

Density of proppant

Resource

                        1.95 

Halliburton (2008) indicates 8%
tonnes/m^3 Assumed to be equal to density of wet sand

Quantity of proppant in fracture fluid per 
fracturing
Quantity of proppant in fracture fluid per well 
lifetime
Fracturing fluid - additives

Volume of additives in fracture fluid per 
fracturing
Volume of additives in fracture fluid per well 
lifetime

Resource

                           78 

tonnes Calculated based on volume of fracture fluid,  proportion of proppant in fracture fluid and density of proppant

Calculated

Resource

                         156 

tonnes Calculated based on volume of proppant and number of fractures during well lifetime

Calculated

Resource

Resource

0.50%

2.5 

% CBM may not use additives/proppant.

AMEC expert judgement.

m^3 Calculated based on volume of fracture fluid and proportion of additives in fracture fluid

Resource

                             5 

m^3 Calculated based on volume of additives and number of fractures during well lifetime

38 Required water storage availability

Resource

                         500 

39 Required proppant storage availability

Resource

                           78 

40 Required additive storage availability

Storage capacity per truck

# of truck movements to manage freshwater in 
2 hydraulic fracturing
# of truck movements to manage flowback in 2 
hydraulic fracturing
# of site construction truck movements

# drilling stage truck movements

Cuttings additional volume from a horizontal 
well compared to a vertical well
Salinity of produced water

Resource

Resource

Resource

Resource

Resource

Resource

Resource

Waste

2.5 

40

19

11

120

280

40%

Types and levels of contaminants in flowback 
water
Gas production (URR)

Waste

Output

m^3 Calculated based on volume of fracture fluid.

tonnes Equivalent to required volume for one fracture

m^3 Equivalent to required volume for one fracture

m^3

trucks Calculated: required water divided by storage capacity per truck

trucks Calculated

trucks

trucks Based on site with multiple laterals operating for 90 days (could be on the high side).

greater compared to 
a vertical well

Horizontal drilling penetrates a greater linear distance of rock and therefore produces a larger volume of drill cuttings 
than does a well drilled vertically to the same depth below the ground surface

7

128,000

ppm Formation specific.

Chloride.  USEPA (2013): 7 to 34290 mg/l TDS.
UB (2013): 1730-128000mg/l.
Dart Energy (2012): 4500 mg/l.
AMEC Aus: 3,000-12,000 TDS mg/l
Highly variable, freshwater to brine - salinity as per produced water.

14

0.9

258

mcm per well USEPA (2004) present production rates for a number fields.  Indicates Ave annual production rate per well of 0.3-

8.6 mcm, average 2.1 mcm (2.1-60.1 mcm over 7 year liftime, average 14.4 mcm).
USGS (2012) indicates a estimated ultimate recovery range of 0.032-9.128 bcf (0.9 to 258 mcm) with an average of 
14.2 mcm.  Assume 14.3 mcm over lifetime.

(Alternatively: USEPA (2010) indicates 60-500 Mcf/day per basin (1.7 - 14.1 million m^3).  Potential to roughly 
estimate m^3 per day based on well numbers = approx 0.025 million m^3 per day, or 0.025 x 365 days x 7 years = 
63 million m^3 over lifetime of well).

Re-fracturing (occurrence)

Well lifetime

Time

Time

1

7

over a well lifetime USEPA (2004) suggests refracturing is typical.

Assume 2 fractures over lifetime (i.e. 1 refracture)

2

15

years USEPA (2013): 5-15 years
AMEC AU expert: 2-5 years

Fuel/energy demand

Resource

No data

kW

Volume of produced water

Waste

35

1.00

65.00

m3/day/well Dart Energy (2012) and EA (2014) indicate between 1 and 40 m3/day/well.

IEA (2012) indicates up to 65m3/day/well

Reference

Based on:
ICF (2013)
AMEC AU expert

Based on:
ICF (2013)
EA (2014)
All Consulting (2012)
AMEC AU expert
Assumption. Calculated

Based on:
Dart Energy (2012)
EA (2014)
AMEC AU expert
AMEC US expert 
(example well layout)
Based on:
Ministère de l'écologie, du 
développement durable et 
de l'énergie
AMEC AU expert (2014)
Assumption

Based on:
Ewen et al (2012)
AMEC AU expert

Calculated

Based on:
Dart Energy (2012)
EA (2014)
AMEC AU expert

As shale gas.  AMEC 
expert judgement.
AMEC expert judgement.

Calculated

Calculated

Calculated

EA (2014)

Calculated

Assumption based on 
ranges identified

USEPA (2004)

USEPA (2004)

Calculated

Calculated

Calculated

Calculated

Calculated

Halliburton (2008)

EC

Calculated

Calculated

Calculated

Calculated

Calculated

AEAT (2012)

Calculated

Calculated

Dart Energy (2012)

Dart Energy (2012)

NYSDES (2011)

USEPA (2013) & UB 
(2013)

USEPA (2004)
USEPA (2013)
AMEC expert judgement.

USEPA (2004)

Based on:
USEPA (2013)
AMEC AU expert

Dart Energy (2012)
EA (2014)
IEA (2012)

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

41

42

43

44

45

46

47

48

49

50

51

52

53

H:\Projects\35229 EC risk man of unconventional hydrocarbons\D Data\Reports\Final\Appendix A.xlsx

CBM

3 of 3

 
Appendix B 
Measures 

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August 2015 
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Measures assumed ‘likely to be applied’52 are in blue text (based on expert judgment).  Only ‘Aspects’ deemed not 
comparable to shale gas following screening are presented (see Section 3.3). 

Aspect 

Measure 
ref.  

Description 

Sub-measure description 

Water resource 
depletion 

Traffic 

38a 

38b 

N49 

38c 

3a vi 

3b vi 

3b ix 

38d 

38e 

59a 

59b 

60c 

61b i 

61b ii 

61c 

3a vii 

Notification of water demand from fracturing operations to 
relevant water utilities and competent authorities 

Demand profile for water (tight gas and tight oil only) 

Strategic planning and staged approach of play 
development to avoid peaks in water demand 

Water management plan 

Site baseline 
Establish water source availability and test for suitability 
(tight gas and tight oil only) 

Monitoring 
Water resources availability 

Monitoring 
Undertake monitoring of water volumes and origin 

Reuse of flowback and produced water for fracturing 

Use of lower quality water for fracturing (e.g. non-potable 
ground / surface water, rainwater harvesting, saline 
aquifers, sea water, treated industrial waterwaters) 

Traffic impact assessment including consideration of 
noise, emissions and other relevant impacts 

Transport management plan (including consideration of 
available road, rail, waterway infrastructure) 

Site selection close to water sources to minimise haulage 
requirements 

Minimise resources demands and hence traffic 
movements through (i) water management plans and (ii) 
wastewater management plans 

i) water management plans to 
minimise water demands and hence 
traffic movements.  

Minimise resources demands and hence traffic 
movements through (i) water management plans and (ii) 
wastewater management plans 

ii) wastewater management plans to 
minimise water demands and hence 
traffic movements.  

Site selection close to flowback treatment / disposal 
facilities to minimise haulage requirements 

Site baseline 
Undertake transport and traffic study. 

LOW AMBITION 
Undertake transport and traffic study.  
Liaise with highway authority and 
identify relevant routes to/from well 
pad 

HIGH AMBITION 
Undertake transport and traffic study.  
As per LOW plus traffic survey and 
traffic modelling 

3a vii 

Site baseline 
Undertake transport and traffic study. 

52 For complete list relevant to shale gas see section 3 of and Table E2 in Appendix E of AMEC (2014). 

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Aspect 

Measure 
ref.  

Description 

Sub-measure description 

3b vii 

60a 

60b 

61a 

Releases to air 

59d 

N54 

16b i 

16b ii 

16d 

17c 

17c 

3a i 

3b i 

16a 

17b 

Monitoring 
Undertake monitoring of traffic numbers and patterns 

Use of temporary surface pipes for distribution of water 
supply 

Use of temporary surface pipes for collection of flowback 

Use of temporary surface pipes for collection of produced 
water 

Use of vehicles (water, chemicals, waste trucking) that 
meet minimum air emission standards e.g. EURO 
standards 

Encourage industry voluntary approach to reduce air 
pollutants and greenhouse gases 

Low emission power supply (i) LPG or (ii) grid electricity 
rather than diesel 

Low emission power supply 
(switching to LPG) 

Low emission power supply (i) LPG or (ii) grid electricity 
rather than diesel 

Low emission power supply 
(switching to grid electricity) 

Application of abatement techniques to minimise 
emissions (assumed SCR for NOx and Diesel Particulate 
Filter (DPF) for PM). 

Flares or incinerators to reduce emissions from fracturing 
fluid at exploration stage (where not connected to gas 
network) 

LOW AMBITION 
Flares or incinerators to reduce 
emissions from fracturing fluid at 
exploration stage 

Flares or incinerators to reduce emissions from fracturing 
fluid at exploration stage (where not connected to gas 
network) 

HIGH AMBITION 
As LOW AMBITION with no audible 
or visible flaring 

Site baseline 
Undertake sampling of air quality 

Monitoring 
Undertake monitoring of air quality 

Preparation of an emissions reduction plan (reduced 
emission completions) including an assessment of 
potential local air quality impacts including implications for 
compliance with ambient air quality limit values 

Reduced emission completions (REC) to eliminate gas 
venting: prohibit venting of gas; capture and cleaning for 
use of gas released from fracture fluid and produced 
water 

Landtake 

40a 

Optimisation from an environmental perspective, i.e. the 
number of wells, pad density and pad spacing 

7 

N13 

Cumulative effects (e.g. air pollution, traffic impacts, water 
resource requirements) of gas play development 
assessed in planning and permitting taking into account 
other (non-unconventional gas) developments and plans 

Member States carry out SEA to set up 
plans/programmes setting the framework for 
unconventional gas projects before granting concessions 
for unconventional gas exploration and production and 
assess environmental effects of such plans. Assessment 

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Aspect 

Measure 
ref.  

Description 

Sub-measure description 

to address surface aspects such as water abstraction, 
waste treatment and disposal, transport, air quality, 
landtake, species diversity as well as known underground 
risks. Assessment to be reviewed before production 
commences on the basis of information obtained during 
the exploration phase. Those MS that have already 
granted concessions to perform such an assessment 
without undue delay. 

Visual impact 

N15 

Mandatory EIA for all projects expected to involve 
hydraulic fracturing, before exploration starts 

N16 i 

Mandatory EIA (i) after initial phase of well exploration and 
before first test fracturing 

N16 ii 

Mandatory EIA (ii) before production commences 

Mandatory EIA according to Directive 
2011/92/EU after well exploration and 
before first test fracturing 

Mandatory EIA according to Directive 
2011/92/EU before production 
commences 

N17 

N44 

N55 

28d 

N45 

55g 

22d 

26d 

26e 

26g 

55c 

N09 

Assessment of whether full project is likely to have 
significant effects on the environment during prospecting 
phase (i.e. extending the existing requirement in relation 
to deep drillings under the EIA Directive to include 
screening prior to development of exploration plans and 
taking account of the entire project) 

Competent authorities compile regional maps of 
underground resources 

Conduct 2D seismic survey to identify faults and fractures. 

Sharing of information to ensure that all operators in a gas 
play are aware of risks and can therefore plan 

Members States establish a capability to address 
groundwater contamination arising from unconventional 
gas operations. In the case of transboundary aquifers, 
joint capability established 

Engagement with third parties (e.g. regulators, other 
operators, researchers) to ensure fully aware of any 
issues / proximity (e.g. to other underground activities) 

Search for and document potential leakage pathways (e.g. 
other wells, faults, mines) 

Development of a conceptual model of the zone before 
work commences covering geology, groundwater flows, 
pathways, microseismicity and subsequent updating of the 
model as information becomes available 

Modelling of fracturing programme to predict extent of 
fracture growth based on best information 

Implementation of remedial measures if well failure occurs 

Ground motion prediction models to assess the potential 
impact of induced earthquakes 

Operator to develop and maintain a contingency plan to 
address foreseeable impacts of operating conditions on 
environmental risk management (e.g. degradation of well 
barriers, casing/cementing as per measure 22) 

N05 

Initiate immediate flowback post fracturing 

Groundwater 
contamination 

August 2015 
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Related to 3a x-a4 (which is Low 
Ambition) 

 
 
 
 
 
 
 
 
  
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Aspect 

Measure 
ref.  

Description 

Sub-measure description 

N46 

N07 

55h 

22a 

22b i 

22b ii 

22b iii 

The European Commission develops criteria/guidance for 
underground risk assessment (such as criteria to assess 
potential risks of groundwater contamination and induced 
seismicity) related to unconventional gas 

Operator to use alternative fracturing fluids to water (e.g. 
nitrogen, CO2, propane) 

Smaller preinjection prior to main operations to enable 
induced seismicity response to be assessed 

Key elements to maintain well safety such as: 
• blowout preventers 
• pressure & temperature monitoring and shutdown 
systems 
• fire and gas detection 
• continuous monitoring for leaks and release of gas and 
liquids 
• modelling to aid well/HF design 
• isolate underground source of drinking water prior to 
drilling 
• ensure micro-annulus is not formed 
• casing centralizers to centre casing in hole 
• select corrosive resistant alloys and high strength steel 
• fish back casing 
• maintain appropriate bending radius 
• triple casing 
• casing and cementing designed to sustain high pressure 
and low magnitude seismicity 
• isolation of the well from aquifers 
• casings: minimum distance the surface casing extends 
below aquifer (e.g. 30m below the deepest underground 
source of drinking water encountered while drilling the 
well, ref. Environment Agency 2012) and surface casing 
cemented before reaching depth of e.g. 75m below 
underground drinking water (ref. AEA 2012). Production 
casing cemented up to at least 150 metres above the 
formation where hydraulic fracturing will be carried out 
(ref. AEA 2012) 

Integrity testing at key stages in well development e.g. 
before/during/after all HF events, including: 
i) wireline logging (calliper, cement bond, variable density) 
ii) pressure (between 2.1 and 8.3 MPa based on setting 
times between 4 and 72 hours)/hydrostatic testing 
iii) mechanical integrity testing of equipment (MIT) 
iv) casing inspection test and log 

Integrity testing at key stages in well development e.g. 
before/during/after all HF events, including: 
i) wireline logging (calliper, cement bond, variable density) 
ii) pressure (between 2.1 and 8.3 MPa based on setting 
times between 4 and 72 hours)/hydrostatic testing 
iii) mechanical integrity testing of equipment (MIT) 
iv) casing inspection test and log 

Integrity testing at key stages in well development e.g. 
before/during/after all HF events, including: 
i) wireline logging (calliper, cement bond, variable density) 
ii) pressure (between 2.1 and 8.3 MPa based on setting 
times between 4 and 72 hours)/hydrostatic testing 
iii) mechanical integrity testing of equipment (MIT) 
iv) casing inspection test and log 

i) wireline logging (calliper, cement 
bond, variable density) 

ii) pressure (between 2.1 and 8.3 
MPa based on setting times between 
4 and 72 hours)/hydrostatic testing 

iii) mechanical integrity testing of 
equipment (MIT) 

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Integrity testing at key stages in well development e.g. 
before/during/after all HF events, including: 
i) wireline logging (calliper, cement bond, variable density) 
ii) pressure (between 2.1 and 8.3 MPa based on setting 
times between 4 and 72 hours)/hydrostatic testing 
iii) mechanical integrity testing of equipment (MIT) 
iv) casing inspection test and log 

Multiple barriers between the target formation and 
people/the environment, including minimum vertical 
distance between target formation and aquifers 

Monitoring and control during operations to ensure 
hydraulic fractures / pollutants do not extend beyond the 
gas-producing formations and does not result in seismic 
events or damage to buildings/installations that could be 
the result of fracturing 

Site baseline 
Establish the presence of methane in groundwater, 
including drinking water 

Microseismicity monitoring and management 
requirements during operations 

Microseismicity monitoring and management 
requirements during operations 

Site baseline 
Undertake sampling of groundwater 

Site baseline 
Undertake sampling of groundwater 

Site baseline 
Geological, hydrogeological and seismic conceptual 
model 
[1] Obtain and analyse seismic (earthquake) history. 

Site baseline 
Geological, hydrogeological and seismic conceptual 
model 
[2] Obtain geomechanical information on fractures, stress, 
rock strength, in situ fluid pressures 

Sub-measure description 

iv) casing inspection test and log 

LOW AMBITION 
Real time monitoring of 
microseismicity during all operations 

HIGH AMBITION 
AS LOW plus cessation of fracturing 
if specified induced seismic activity is 
detected (using traffic light system) 

HIGH AMBITION 
Sampling of shallow groundwater 
during wet and dry periods 

VERY HIGH AMIBITION 
Borehole to sample deep 
groundwater and characterise the 
hydrological series 

LOW AMBITION. Undertake desk 
study based on existing data and 
literature 

Site baseline 
Geological, hydrogeological and seismic conceptual 
model 
[2] Obtain geomechanical information on fractures, stress, 
rock strength, in situ fluid pressures 

HIGH AMBITION. In addition LOW 
obtain geomechanical information on 
fractures, stress, rock strength, in situ 
fluid pressures through new cores 
and stratigraphic tests. 

Site baseline 
Geological, hydrogeological and seismic conceptual 
model 
[3] Undertake surface microseismic survey 

Aspect 

Measure 
ref.  

Description 

22b iv 

22c 

26f 

3a xi 

55d 

55d 

3a iii 

3a iii 

3a x-a1 

3a x-a2 

3a x-a2 

3a x-a3 

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Aspect 

Measure 
ref.  

3a x-a4 

3a x-a4 

3a x-a5 

3a x-a6 

3a x-a7 

3a xiii 

3a xiii 

3b iii 

3b iii 

3b xvii 

3b xviii 

Description 

Sub-measure description 

LOW AMBITION. Modelling over 100 
years 

HIGH AMBITION. Modelling is done 
over 10,000 years 

Site baseline 
Geological, hydrogeological and seismic conceptual 
model 
[4] Undertake complex modelling of fluid flows and 
migration (reservoir simulations)  

Site baseline 
Geological, hydrogeological and seismic conceptual 
model 
[4] Undertake complex modelling of fluid flows and 
migration (reservoir simulations)  

Site baseline 
Geological, hydrogeological and seismic conceptual 
model 
[5] Develop maps and cross sections of local geologic 
structure 

Site baseline 
Geological, hydrogeological and seismic conceptual 
model 
[6] Conduct 3D seismic survey to identify faults and 
fractures 

Site baseline 
Geological, hydrogeological and seismic conceptual 
model 
[7] Obtain data on area, thickness, capacity, porosity and 
permeability of formations. 

Site baseline 
Undertake assessment of existing underground wells and 
structures 

LOW AMBITION.  Undertake 
assessment of underground wells 
and structures 

Site baseline 
Undertake assessment of existing underground wells and 
structures 

Monitoring 
Undertake monitoring of groundwater 

Monitoring 
Undertake monitoring of groundwater 

Monitoring 
Undertake monitoring of induced seismicity from fracturing 

Monitoring 
Undertake monitoring for presence of methane seepages 
in groundwater, including drinking water. 

HIGH AMBITION.  As LOW 
AMBITION plus undertake 
assessment of underground wells 
and structures desk study to evaluate 
integrity of construction and record of 
completion and/or plugging of 
existing shallow wells 

LOW AMBITION 
Sampling of shallow groundwater 
during wet and dry periods 

HIGH AMBITION 
Deep groundwater sampling network 
to determine the characteristics of 
deep groundwater and formation 
water and piezometric levels 

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Appendix C 
Potential Criteria for Categorisation of CFF and UFF 

© Amec Foster Wheeler Environment & Infrastructure UK Limited 
August 2015 
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© Amec Foster Wheeler Environment & Infrastructure UK Limited 
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For detailed illustrative concession parameter values, refer to Appendix A. 

Criteria 

Possible options for 
legislative provision 

Principal Relevant 
Risks and Impacts 

UFF Criteria Characteristics 

Comment 

Depth 

Depth 

Set a minimum depth 
below which regulation 
applies e.g. 2,000 m 

Pressure applied 
during hydraulic 
fracturing (HF) 

Set a pressure used in 
HF above which 
regulation applies 

Set a minimum depth 
above which regulation 
applies e.g. 1,000 m 

Shallower activities may 
pose greater risk of 
groundwater pollution 

Typically deep  Typically deep  Typically deep  Shallower 
than other 
UFFs 

Will capture CBM but unlikely to capture other UFF 

Shale Gas 

Tight Gas 

Tight Oil 

CBM 

Deeper activities may 
pose greater risk to well 
integrity and associated 
impacts such as 
groundwater pollution 

Higher pressure = 
increased potential for 
compromising well 
integrity, risk of leaks 
and induced seismic 
activity 

Typically deep  Typically deep  Typically deep  Shallower 
than other 
UFFs 

Unlikely to capture CBM May capture tight oil / tight gas and 
CFF 

700 to 1400 
bar 

Around 690 
bar 

Around 550 
bar 

Around 200 
bar 

Pressure is a function of depth and extent of fracturing 
required.  May capture CFF (typically 500-650 bar) particularly 
if deep.  Unlikely to capture CBM 

Need for 
horizontal drilling 

Regulate all activities 
requiring horizontal 
drilling 

None specific to the 
technique 

Required for 
shale gas 

Required for 
tight  gas 

Required for 
tight oil 

Not always 
used 

Horizontal drilling increasingly used in CFF 

Use of proppant 

Regulate all activities 
that use proppant 

None – proppants are 
inert 

Required for 
shale gas 

Required for 
tight gas 

Required for 
tight oil 

Not always 
required for 
CBM 

Proppants used for all UFF but not always for CBM.  Proppants 
are inert and not a risk driver 

Required for 
shale gas 

Required for 
tight  gas 

Required for 
tight oil 

Not always 
used 

Will capture CFF where HF used.  May not capture CBM 

Use of hydraulic 
fracturing (HF) 

Regulate all HF activities  Groundwater pollution, 
induced seismic, water 
resource depletion, 
wastewater 
management and 
treatment 

© Amec Foster Wheeler Environment & Infrastructure UK Limited 

August 2015 

Doc Reg No. 

 
 
 
 
 
 
 
 
 
 
 
Criteria 

Possible options for 
legislative provision 

Principal Relevant 
Risks and Impacts 

UFF Criteria Characteristics 

Comment 

Shale Gas 

Tight Gas 

Tight Oil 

CBM 

Volume of water 
used in HF 

Regulate all HF using 
more than a particular 
volume of water 

Volume of 
flowback 

Regulate all HF 
generating more than a 
particular volume of 
flowback 

Increased risk of leaks, 
contamination and 
induced seismicity, 
water resources 
depletion 

Increased wastewater 
treatment requirements 

Volume of 
produced water 

Regulate all HF 
generating more than a 
particular volume of 
produced water 

Increased wastewater 
treatment requirements, 
water resources 
depletion 

Proximity to 
groundwater 
resource 

Regulate all HF activities 
that take place in or in 
proximity to a 
groundwater resource 

Groundwater resource 
pollution 

Large 
volumes 
(1,000s m3) 
typically used 

Large 
volumes 
(1,000s m3) 
typically 
generated 

Small 
volumes 
generated per 
well but large 
volumes 
across a field 

Takes place 
in low 
permeability 
deposits, not 
in proximity to 
groundwater 
resources 

Lower than 
shale gas 

Lower than 
shale gas 

Lower than 
shale gas 

Lower than 
shale gas 

HF not always 
used.  
Volumes used 
less than 
other UFFs 

HF not always 
used.  
Flowback 
volumes less 
than other 
UFF 

May not capture tight gas or CBM.  Should avoid CFF if set at a 
sufficiently high volume 

% flowback is a factor of volume injected and formation 
characteristics.  May not capture all operations, particularly 
CBM.  Should avoid CFF 

Similar to 
shale gas 

Similar to 
shale gas 

Higher than 
shale gas per 
well 

Rate of water production is a function of the formation and is 
variable.  CBM involves active pumping.  Produced water 
quality is variable 

Typically 
more water 
(groundwater) 
present in 
reservoir than 
shale gas.  
Takes place 
not in 
proximity to 
groundwater 
resources 

Typically 
more water 
(groundwater) 
present in 
reservoir than 
shale gas.  
Takes place 
not in 
proximity to 
groundwater 
resources 

Typically 
more 
groundwater 
present in 
CBM and is in 
greater 
proximity to 
ground water 
resources 
than other 
UFFs 

Groundwater as per Directive 2000/60/EC, ‘all water which is 
below the surface of the ground in the saturation zone and in 
direct contact with the ground or subsoil’. 

No differentiation between groundwater that is potable vs deep 
saline groundwater 

Number / density 
of wells 

Regulate developments 
above a particular scale 
(where size is 

Cumulative impacts 
(groundwater pollution / 
emissions to air / 

Development 
size may vary 
considerably 

Development 
size may vary 
considerably 

Development 
size may vary 
considerably.  

Potentially 
lower 
(generally 

May capture CFF using Enhanced Oil Recovery. 

© Amec Foster Wheeler Environment & Infrastructure UK Limited 

August 2015 

Doc Reg No. 

 
 
 
 
 
 
 
 
 
 
Criteria 

Possible options for 
legislative provision 

Principal Relevant 
Risks and Impacts 

UFF Criteria Characteristics 

Comment 

determined by number / 
density of wells) 

surface water pollution / 
traffic)  

Shale Gas 

Tight Gas 

Tight Oil 

CBM 

smaller 
schemes) 

Potentially 
lower 
(generally 
smaller 
schemes) 

© Amec Foster Wheeler Environment & Infrastructure UK Limited 

August 2015 

Doc Reg No. 

 
 
 
 
 
 
 
 
 
 
 
Amec Foster Wheeler Environment & Infrastructure UK Ltd 
August 2015 
Doc Reg No. 

 
 
 
 
 
 
 
Appendix D 
Measures Included in Policy Options 

© Amec Foster Wheeler Environment & Infrastructure UK Limited 
August 2015 
Doc Reg No. 

 
 
 
 
 
 
 
 
 
 
 
 
© Amec Foster Wheeler Environment & Infrastructure UK Limited 
August 2015 
Doc Reg No. 

 
 
 
 
 
 
 
 
Non-BAU Measures in Policy Options

Categorisation

Measure info

Tight Gas

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Zoning

N/A

42b

42b

Zoning

N/A

N48

N48

Zoning

Zoning

N/A

N/A

26c

40c

26c

40c

Zoning

N/A

2f

Zoning

N/A

2f

Zoning

N/A

2f

Zoning

N/A

2f

Zoning

N/A

2f

2f

2f

2f

2f

2f

1

2

3

4

5

6

7

8

9

vs. 
HIGH
        -    Location of sites close to existing pipeline infrastructure

        -    Minimum distance between hydraulic fracture pipes and geological 

strata containing aquifers and the surface to be determined based on 
risk assessment

        -    Fracturing to be a minimum distance from water resources

        -    High land, agricultural and ecological value locations avoided

0

0

0

0

        -    Buffer zones from abstraction points, aquifers, residential areas, 

schools, hospitals, abandoned wells, active & abandoned mines and 
other potential pathways for fluid migration, and other sensitive areas

        -    Buffer zones from abstraction points, aquifers, residential areas, 

schools, hospitals, abandoned wells, active & abandoned mines and 
other potential pathways for fluid migration, and other sensitive areas

        -    Buffer zones from abstraction points, aquifers, residential areas, 

schools, hospitals, abandoned wells, active & abandoned mines and 
other potential pathways for fluid migration, and other sensitive areas

        -    Buffer zones from abstraction points, aquifers, residential areas, 

schools, hospitals, abandoned wells, active & abandoned mines and 
other potential pathways for fluid migration, and other sensitive areas

        -    Buffer zones from abstraction points, aquifers, residential areas, 

schools, hospitals, abandoned wells, active & abandoned mines and 
other potential pathways for fluid migration, and other sensitive areas

Buffer zone from abstraction points and aquifers 
of 1,000m for drinking water related abstraction

Buffer zone from residential areas, schools 
hospitals and other sensitive areas of 1,600m

Buffer zone within which detailed noise 
assessment is required of 305m

Buffer zone from abandoned wells and other 
potential pathways for fluid migration (distance 
specified on risk basis)
Additional containment for sites near surface 
water supply locations

Zoning

N/A

40a

40a

10

        -    Optimisation from an environmental perspective, i.e. the number of 

0

wells, pad density and pad spacing

Zoning

N/A

40b

40b

11

        -    Compatibility with current and future potential landuse (Natura 2000 

0

sites, conservation sites, human use, industrial use, appropriate zoning, 
CCS, geothermal, water abstraction)

Zoning

N/A

1b

1b

12

        -    Restrict operations within and underneath specified sites (e.g. Natura 

0

2000, protected sites, coal mining areas, drinking water protection areas, 
water extraction areas for public drinking water supply, mineral spa 
protection zones karstic aquifers, flood prone zones and mineral water 
reserves, reforestation areas and areas known to be unfavourable - with 
regard to potential environmental impacts) or within certain distances to 
specified sites

        -    Avoid high seismicity risk areas

0

        -    Minimum distance between hydraulic fracture pipes and geological 

strata containing aquifers (e.g. 600m) and the surface (e.g. 600m depth 
requires special permit)

Zoning

Zoning

N/A

N/A

55e

55i

55e

55i

13

14

Zoning

N/A

55i

55i

15

        -    Minimum distance between hydraulic fracture pipes and geological 

strata containing aquifers (e.g. 600m) and the surface (e.g. 600m depth 
requires special permit)

Minimum distance between hydraulic fracture 
pipes and geological strata containing aquifers of, 
e.g. 600m
Special permit conditions where hydraulic fracture 
pipes are less than, e.g. 600m depth from surface

0

0

Site selection takes into consideration existing 
gas pipeline infrastructure to enable 
minimisation of the need for additional pipeline 
infrastructure and associated development 
impacts.
0

0

Assessment of and avoidance of high land, 
agricultural and ecological value locations (e.g.  
Natura 2000 sites, conservation sites).
Applicable regardless of area type (i.e. not 
limited to Natura 2000 site and other specified 
sites).  Hence applicability is broader.
0

0

0

This is required for sites within 800m of water 
supply locations in Colorado.  The definition of 
additional containment is not provided - 
assume bunded tanks/site - see other 
measures re. this in surface water
Optimise the number of wells per pad, pad 
density and pad spacing to minimise 
cumulative environmental impacts (e.g. one 
pad per 2.6 km2 proposed by New York State).  
This will include consideration of siting with 
consideration of conflicts with nearby or 
adjacent sensitive land uses such as 
residences, schools, hospitals, available 
transport infrastructure, access to water supply, 
access to wastewater treatment, etc.

Note: the acquis communautaire requires this 
measure, but it is uncertain whether it is 
adequately implemented by Member States. 
Assessment of compatibility with current and 
future landuse plans (e.g. Natura 2000 sites, 
conservation sites, human use, industrial use, 
appropriate zoning.

Note: the acquis communautaire requires this 
measure, notably as a mitigation measure 
under the SEAD/the EIAD, but without 
guarantee of the result, Natura2000 Directives 
excepted. 
Operations would be restricted (i.e. greater 
controls as required by discretion of MS 
authorities) within specified areas. 

Areas known to be unfavourable - with regard 
to potential environmental impacts - geological 
and hydrogeological conditions (groundwater 
potentials and pathways, tectonically fractured 
rocks, artesian confined aquifers, suspected 
pathways introduced by abandoned boreholes 
or mining activities)
0

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

Qual

LL

 No 

1. Guidance

3. 
Amendment + 
Guidance
                   1                    -                       1                    -                       1 

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

Qual

MM

 No 

                   1                    -                       1                    -                       1 

Qual

Qual

MM

MM

 No 

 No 

                   1                    -                       1                    -                       1 

                   1                    -                       1                    -                       1 

Qual

MM

 No 

                   1                    -                       1                    -                       1 

Qual

MM

 No 

                   1                    -                       1                    -                       1 

Qual

MM

 No 

                   1                    -                       1                    -                       1 

Qual

MM

 No 

                   1                    -                       1                    -                       1 

Qual

MM

 No 

                   1                    -                       1                    -                       1 

Qual

HM

 No 

                   1                    -                       1                    -                       1 

Qual

HM

 No 

                   1                    -                       1                    -                       1 

Qual

HM

 Yes 

                   1                    -                       1                    -                       1 

Qual

Qual

HH

HH

 No 

 No 

                   1                    -                       1                    -                       1 

                   1                    -                       1                    -                       1 

Qual

HH

 No 

                   1                    -                       1                    -                       1 

35229 MASTER Measures (20150127) TGAS 20150206.xlsx

Measures in Policy Options

1 of  13

Categorisation

Measure info

Tight Gas

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Zoning

N/A

1a

1a

16

vs. 
HIGH
        -    Prohibit operations within and underneath specified sites (e.g. Natura 

0

2000, protected sites, coal mining areas, drinking water protection areas, 
water extraction areas for public drinking water supply, mineral spa 
protection zones karstic aquifers, flood prone zones and mineral water 
reserves, reforestation areas and areas known to be unfavourable - with 
regard to potential environmental impacts) or within certain distances to 
specified sites

        -    Competent authorities compile regional maps of underground resources 0

Areas known to be unfavourable - with regard 
to potential environmental impacts - geological 
and hydrogeological conditions (groundwater 
potentials and pathways, tectonically fractured 
rocks, artesian confined aquifers, suspected 
pathways introduced by abandoned boreholes 
or mining activities)
0

Underground 
Risks
Underground 
Risks

Underground 
Risks
Underground 
Risks

Underground 
Risks

Underground 
Risks
Underground 
Risks

N/A

N44

N44

N/A

N55

N55

N/A

28d

28d

N/A

N45

N45

17

18

19

20

        -    Conduct 2D seismic survey to identify faults and fractures.

        -    Sharing of information to ensure that all operators in a gas play are 

aware of risks and can therefore plan

        -    Members States establish a capability to address groundwater 

contamination arising from unconventional gas operations. In the case of 
transboundary aquifers, joint capability established

0

0

0

0

0

0

0

0

N/A

55g

55g

21

        -    Engagement with third parties (e.g. regulators, other operators, 

N/A

22d

22d

N/A

26d

26d i

22

23

 L 

researchers) to ensure fully aware of any issues / proximity (e.g. to other 
underground activities)

        -    Search for and document potential leakage pathways (e.g. other wells, 

0

Through delivery of 3 a x detail

Related to 3a x-a4 (which is Low Ambition)

Through delivery of 3 a x detail

faults, mines)
i) Development of a conceptual model of the zone before work 
commences covering geology, groundwater flows, pathways, 
microseismicity and subsequent updating of the model as information 
becomes available ii) as above plus Modelling of the impact of 
groundwater pumping on linked groundwater and surface water flows 
and quality

        -    Modelling of fracturing programme to predict extent of fracture growth 

Underground 
Risks

N/A

26e

26e

25

based on best information

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

Qual

HH

 Yes 

1. Guidance

3. 
Amendment + 
Guidance
                   1                    -                       1                    -                       1 

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

Qual

Quant

Qual

Qual

LL

LM

LM

LM

 No 

 Yes 

                   1                    -                       1                    -                       1 

                   1                     1                     1                     1                     1 

 Possible - low 

                   1                     1                     1                     1                     1 

 No 

                   1                    -                       1                    -                       1 

Qual

ML

 Possible - low 

                   1                    -                       1                    -                       1 

Quant

Quant

MM

MM

 Possible - high                     1                     1                     1                     1                     1 

 No 

                   1                     1                     1                     1                     1 

Quant

MM

 No 

                   1                    -                       1                     1                     1 

Underground 
Risks
Underground 
Risks
Underground 
Risks

Underground 
Risks
Underground 
Risks

Underground 
Risks
Underground 
Risks

N/A

26g

26g

N/A

55c

55c

N/A

N09

N09

N/A

N05

N05

N/A

N46

N46

N/A

N07

N07

N/A

55h

55h

26

27

28

29

30

31

32

        -    Implementation of remedial measures if well failure occurs

        -    Ground motion prediction models to assess the potential impact of 

induced earthquakes

        -    Operator to develop and maintain a contingency plan to address 

foreseeable impacts of operating conditions on environmental risk 
management (e.g. degradation of well barriers, casing/cementing as per 
measure 22)

        -    Initiate immediate flowback post fracturing

        -    The European Commission develops criteria/guidance for underground 

risk assessment (such as criteria to assess potential risks of 
groundwater contamination and induced seismicity) related to 
unconventional gas

        -    Operator to use alternative fracturing fluids to water (e.g. nitrogen, CO2, 

propane)

        -    Smaller preinjection prior to main operations to enable induced 

seismicity response to be assessed

0

0

0

0

0

0

0

0

Application of Discrete Fracture Network (DFN) 
approach including dynamic response (e.g. 
hydro-shearing), Finite Element Analysis (FEA) 
or Discrete Element Method (DEM). 3D fracture 
modelling integrated with geomechanics 
modelling.
0

0

0

0

0

0

Qual

Quant

Quant

Qual

Qual

Qual

Qual

Mini-fractures area carried out prior to full scale 
fracturing.  Monitoring of the seismic response 
to the mini-fractures is carried out and 
assessment of the location's actual response 
compared with the modelled response is made.  
Analysis of results and conclusion drawn 
regarding suitability of and approach to full 
scale operations.  Enables model predictions to 
be verified and the actual response of 
geological formations to be assessed.

MM

MM

MM

MM

MH

MH

MH

 Yes 

 No 

 No 

 No 

 No 

 No 

 No 

                   1                     1                     1                     1                     1 

                  -                      -                      -                      -                      -   

                  -                      -                      -                       1                     1 

                   1                     1                     1                    -                       1 

                  -                      -                      -                      -                      -   

                  -                      -                      -                      -                      -   

                   1                    -                       1                    -                       1 

35229 MASTER Measures (20150127) TGAS 20150206.xlsx

Measures in Policy Options

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Categorisation

Measure info

Tight Gas

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

0

Measures to be split out for cost purposes

Quant

HH

 Yes 

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

1. Guidance

3. 
Amendment + 
Guidance
                  -                       1                     1                     1                     1 

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

Underground 
Risks

N/A

22a

22a

33

Underground 
Risks

N/A

22b

22b i

34

vs. 
HIGH
        -    Key elements to maintain well safety such as:

• blowout preventers
• pressure & temperature monitoring and shutdown systems
• fire and gas detection
• continuous monitoring for leaks and release of gas and liquids
• modelling to aid well/HF design
• isolate underground source of drinking water prior to drilling
• ensure micro-annulus is not formed
• casing centralizers to centre casing in hole
• select corrosive resistant alloys and high strength steel
• fish back casing
• maintain appropriate bending radius
• triple casing
• casing and cementing designed to sustain high pressure and low 
magnitude seismicity
• isolation of the well from aquifers
• casings: minimum distance the surface casing extends below aquifer 
(e.g. 30m below the deepest underground source of drinking water 
encountered while drilling the well, ref. Environment Agency 2012) and 
surface casing cemented before reaching depth of e.g. 75m below 
underground drinking water (ref. AEA 2012). Production casing 
cemented up to at least 150 metres above the formation where hydraulic 

        -    Integrity testing at key stages in well development e.g. 

before/during/after all HF events, including:
i) wireline logging (calliper, cement bond, variable density)
ii) pressure (between 2.1 and 8.3 MPa based on setting times between 4 
and 72 hours)/hydrostatic testing
iii) mechanical integrity testing of equipment (MIT)
iv) casing inspection test and log

i) wireline logging (calliper, cement bond, variable 
density)

0

Quant

HH

 Yes 

                  -                       1                     1                     1                     1 

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

N/A

22b

22b ii

35

        -    Integrity testing at key stages in well development e.g. 

before/during/after all HF events, including:
i) wireline logging (calliper, cement bond, variable density)
ii) pressure (between 2.1 and 8.3 MPa based on setting times between 4 
and 72 hours)/hydrostatic testing
iii) mechanical integrity testing of equipment (MIT)
iv) casing inspection test and log

ii) pressure (between 2.1 and 8.3 MPa based on 
setting times between 4 and 72 hours)/hydrostatic 
testing

0

Quant

HH

 Yes 

                  -                       1                     1                     1                     1 

N/A

22b

22b iii

36

        -    Integrity testing at key stages in well development e.g. 

iii) mechanical integrity testing of equipment (MIT) 0

Quant

HH

 Yes 

                  -                       1                     1                     1                     1 

before/during/after all HF events, including:
i) wireline logging (calliper, cement bond, variable density)
ii) pressure (between 2.1 and 8.3 MPa based on setting times between 4 
and 72 hours)/hydrostatic testing
iii) mechanical integrity testing of equipment (MIT)
iv) casing inspection test and log

N/A

22b

22b iv

37

        -    Integrity testing at key stages in well development e.g. 

iv) casing inspection test and log

before/during/after all HF events, including:
i) wireline logging (calliper, cement bond, variable density)
ii) pressure (between 2.1 and 8.3 MPa based on setting times between 4 
and 72 hours)/hydrostatic testing
iii) mechanical integrity testing of equipment (MIT)
iv) casing inspection test and log

N/A

22c

22c

38

        -    Multiple barriers between the target formation and people/the 

N/A

26f

26f

39

N/A

3a

3a xi

40

environment, including minimum vertical distance between target 
formation and aquifers

        -    Monitoring and control during operations to ensure hydraulic fractures / 
pollutants do not extend beyond the gas-producing formations and does 
not result in seismic events or damage to buildings/installations that 
could be the result of fracturing

        -    Site baseline

0

0

0

N/A

55d

55d

41

L

Establish the presence of methane in groundwater, including drinking 
water
Microseismicity monitoring and management requirements during 
operations

N/A

55d

55d

42

        -    Microseismicity monitoring and management requirements during 

operations

LOW AMBITION
Real time monitoring of microseismicity during all 
operations
HIGH AMBITION
AS LOW plus cessation of fracturing if specified 
induced seismic activity is detected (using traffic 
light system)

0

0

Quant

HH

 Yes 

                  -                       1                     1                     1                     1 

Qual

HH

 No 

                   1                     1                     1                    -                       1 

Linked to 3 b xvii

Quant

HH

 No 

                   1                     1                     1                     1                     1 

0

Quant

MM

 Yes 

                   1                     1                     1                     1                     1 

Linked to 3 b xvii

Quant

MM

 No 

                  -                       1                     1                     1                     1 

0

Qual

HH

 No 

                   1                     1                     1                     1                     1 

35229 MASTER Measures (20150127) TGAS 20150206.xlsx

Measures in Policy Options

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Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

Quant

MM

 Yes 

1. Guidance

3. 
Amendment + 
Guidance
                  -                      -                      -                      -                      -   

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

Quant

HH

 Possible - low 

                   1                     1                     1                     1                     1 

Quant

HH

 No 

                   1                     1                     1                     1                     1 

Quant

MH

 Yes 

                  -                      -                      -                      -                      -   

Quant

HH

 No 

                   1                     1                     1                     1                     1 

Quant

HH

 No 

                   1                     1                     1                     1                     1 

Quant

MH

 No 

                   1                     1                     1                     1                     1 

Quant

HH

 No 

                  -                      -                      -                      -                      -   

Quant

HH

 Possible - low 

                   1                     1                     1                     1                     1 

Quant

HH

 Possible - low 

                   1                     1                     1                     1                     1 

Quant

HH

 Possible - high                     1                     1                     1                     1                     1 

Categorisation

Measure info

Tight Gas

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Underground 
Risks

N/A

3a

3a iii

43

vs. 
HIGH
L

Site baseline
Undertake sampling of groundwater

Underground 
Risks

N/A

3a

3a iii

44

H

Site baseline
Undertake sampling of groundwater

MEDIUM AMBITION
Sampling of shallow groundwater during wet and 
dry periods (cost is shown in Middle Ambition 
column)

HIGH AMIBITION
Borehole to sample deep groundwater and 
characterise the hydrological series (cost is 
shown in High Ambition column)

Concentrate boreholes near pad (as on 
impacts on groundwater due to surface spills 
greatest near pad).  Boreholes, at 15m depth at 
each corner.  Analyse for dissolved oxygen, pH, 
ammonia, chloride, total petroleum 
hydrocarbons and polyaromatic hydrocarbons, 
fracturing additive chemicals, isotopic 
fingerprinting (include methane, ethane, 
propane), radioactivity and heavy metals.

Deep boreholes in area.  Analyse for dissolved 
oxygen, pH, ammonia, chloride, total petroleum 
hydrocarbons and polyaromatic hydrocarbons, 
fracturing additive chemicals, isotopic 
fingerprinting (include methane, ethane, 
propane), radioactivity and heavy metals.

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

N/A

3a

3a x-a1

45

        -    Site baseline

0

N/A

3a

3a x-a2

46

L

N/A

3a

3a x-a2

47

H

Geological, hydrogeological and seismic conceptual model
[1] Obtain and analyze seismic (earthquake) history.
Site baseline
Geological, hydrogeological and seismic conceptual model
[2] Obtain geomechanical information on fractures, stress, rock strength, 
in situ fluid pressures
Site baseline
Geological, hydrogeological and seismic conceptual model
[2] Obtain geomechanical information on fractures, stress, rock strength, 
in situ fluid pressures

N/A

3a

3a x-a3

48

N/A

3a

3a x-a4

49

N/A

3a

3a x-a4

50

N/A

3a

3a x-a5

51

        -    Site baseline

L

Geological, hydrogeological and seismic conceptual model
[3] Undertake surface microseismic survey
Site baseline
Geological, hydrogeological and seismic conceptual model
[4] Undertake complex modelling of fluid flows and migration (reservoir 
simulations) 
Site baseline
Geological, hydrogeological and seismic conceptual model
[4] Undertake complex modelling of fluid flows and migration (reservoir 
simulations) 
        -    Site baseline

H

N/A

3a

3a x-a6

52

 H 

Geological, hydrogeological and seismic conceptual model
[5] Develop maps and cross sections of local geologic structure
Site baseline
Geological, hydrogeological and seismic conceptual model
[6] Conduct 3D seismic survey to identify faults and fractures

N/A

3a

3a x-a7

53

        -    Site baseline

N/A

3a

3a xiii

54

N/A

3a

3a xiii

55

L

H

Geological, hydrogeological and seismic conceptual model
[7] Obtain data on area, thickness, capacity, porosity and permeability of 
formations.
Site baseline
Undertake assessment of existing underground wells and structures

Site baseline
Undertake assessment of existing underground wells and structures

Underground 
Risks

N/A

3b

3b iii

56

L

Monitoring
Undertake monitoring of groundwater

LOW AMBITION. Undertake desk study based on 
existing data and literature

HIGH AMBITION. In addition LOW obtain 
geomechanical information on fractures, stress, 
rock strength, in situ fluid pressures through new 
cores and stratigraphic tests.
0

LOW AMBITION. Modelling over 100 years

HIGH AMBITION. Modelling is done over 10,000 
years

0

0

0

0

0

0

0

0

0

0

0

0

HIGH AMBITION.  As LOW AMBITION plus 
undertake assessment of underground wells and 
structures desk study to evaluate integrity of 
construction and record of completion and/or 
plugging of existing shallow wells
MEDIUM AMBITION
Sampling of shallow groundwater during wet and 
dry periods

Underground 
Risks

N/A

3b

3b iii

57

H

Monitoring
Undertake monitoring of groundwater

HIGH AMBITION
Deep groundwater sampling network to determine 
the characteristics of deep groundwater and 
formation water and piezometric levels

Underground 
Risks
Underground 
Risks

N/A

N/A

3b

3b

3b xvii

58

        -    Monitoring

3b xviii

59

        -    Monitoring

Undertake monitoring of induced seismicity from fracturing

0

0

Undertake monitoring for presence of methane seepages in 
groundwater, including drinking water.

LOW AMBITION.  Undertake assessment of 
underground wells and structures

Develop list of penetrations into zone within 
area (from well history databases).

Quant

MH

 Possible - high                    -                      -                      -                      -                      -   

0

Quant

HH

 No 

                   1                     1                     1                     1                     1 

Concentrate boreholes near pad (as on 
impacts on groundwater due to surface spills 
greatest near pad).  Boreholes, at 15m depth at 
each corner.  Analyse for dissolved oxygen, pH, 
ammonia, chloride, total petroleum 
hydrocarbons and polyaromatic hydrocarbons, 
fracturing additive chemicals, isotopic 
fingerprinting (include methane, ethane, 
propane), radioactivity and heavy metals.

Deep boreholes network in area. Analyse for 
dissolved oxygen, pH, ammonia, chloride, total 
petroleum hydrocarbons and polyaromatic 
hydrocarbons, fracturing additive chemicals, 
isotopic fingerprinting (include methane, 
ethane, propane), radioactivity and heavy 
metals.
0

0

Quant

MM

 Yes 

                  -                      -                      -                      -                      -   

Quant

HH

 No 

                   1                     1                     1                     1                     1 

Quant

Quant

HH

HH

 No 

                   1                     1                     1                     1                     1 

 Possible - low 

                  -                      -                      -                      -                      -   

35229 MASTER Measures (20150127) TGAS 20150206.xlsx

Measures in Policy Options

4 of  13

Categorisation

Measure info

Tight Gas

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Chemical Use N/A

CSL5 CSL5

60

Chemical Use N/A

N24

N24

Chemical Use N/A

CAL1 CAL1

Chemical Use N/A

CAL2 CAL2

61

62

63

vs. 
HIGH
        -    Authorities to organise an exchange of views/information on 

environmentally safer technologies and alternatives to the use of 
chemicals in hydraulic fracturing

        -    Traceability of chemicals used by an operator

0

0

        -    CSA/risk assessment explicitly specific to hydraulic fracturing in the EU 

Chemicals - assessment

to be included in REACH Registration

        -    Develop a peer-reviewed EU-level exposure scenario / SpERC for HF for 

Chemicals - assessment

different chemical types

Chemical Use N/A

CAL3 CAL3

64

        -    CAL2 to be implemented in CSAs for chemicals used in HF and any 

Chemicals - assessment

deviations explained

Chemical Use N/A

CDL1 CDL1

65

        -    Disclosure of information to Competent Authority: declaration of 
substance name and CAS number for the chemical substances 
potentially to be used in hydraulic fracturing. Per concession/play

Chemicals - disclosure

Chemical Use N/A

CDL2 CDL2

66

        -    Disclosure of information to the public: list of chemicals potentially to be 

Chemicals - disclosure

used in hydraulic fracturing by UG company to be made available (e.g. 
via company website or centralised data dissemination portal). Per 
concession/play

Chemical Use N/A

CSL1a CSL1a

67

        -    Non-use of any (non-biocidal) substances with [harmonised or notified] 

Chemicals - selection

Chemical Use N/A

CSL1b CSL1b

68

Chemical Use N/A

CSL1c CSL1c

69

Chemical Use N/A

CSL1d CSL1d

70

classification as CMR (carcinogenic, mutagenic or toxic for reproduction) 
category 1A or 1B

        -    Non-use in biocidal products of any substances with [harmonised or 
notified] classification as CMR (carcinogenic, mutagenic or toxic for 
reproduction) category 1A or 1B

        -    Non-use of any (non-biocidal) substances with [harmonised or notified] 
classification as aquatic acute category 1 or aquatic chronic category 1

        -    Non-use in biocidal products of any substances with [harmonised or 
notified] classification as aquatic acute category 1 or aquatic chronic 
category 1

Chemicals - selection

Chemicals - selection

Chemicals - selection

Chemical Use N/A

CSL2 CSL2

71

        -    Non-use of any substances on REACH Candidate List for authorisation 

Chemicals - selection

(substances of very high concern)

Chemical Use N/A

CSL3 CSL3

72

        -    Negative list of named substances that must not be used in UG 
extraction (alternative to two measures CSL1 and CSL2)

Chemicals - selection

Chemical Use N/A

CSL4 CSL4

73

        -    Demonstration that all steps practicable have been taken to reduce 

Chemicals - selection

number, concentration and volume of chemicals used in hydraulic 
fracturing

0

0

Cost to be estimated based on existing data in 
#11.
Estimated cost of developing SpERC to similar 
level of detail to those that already exist for e.g. 
additives used in petroleum products 
(CONCAWE/ESIG)  
http://www.cefic.org/Industry-
support/Implementing-reach/Guidances-and-
Tools1/
Should be feasible to estimate additional cost 
of UG company doing their own CSA for this 
specific use for typical number of chemicals 
used.
Is in principle possible to quantify but not 
considered proportionate to do this given costs 
of this are likely to be small and main costs are 
likely to arise due to other implications (e.g. 
Reduced options for chemical use due to 
greater scrutiny potentially leading to reduced 
productivity).
Is in principle possible to quantify but not 
considered proportionate to do this given costs 
of this are likely to be small and main costs are 
likely to arise due to other implications (e.g. 
Reduced options for chemical use due to 
greater scrutiny potentially leading to reduced 
productivity).
0

0

0

0

Too many substances potentially used in HF to 
robustly estimate differences in costs.  Impacts 
on well productivity will far outweigh differences 
in prices of fluid additives.
Partially quantitative.  Potential to cost actually 
developing the list but costs of not using 
substances on that list not quantifiable as per 
measures above.  
Not considered feasible to quantify costs as too 
site-specific.

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

Qual

LL

 No 

Qual

Quant

Quant

LL

ML

ML

 No 

 No 

 No 

1. Guidance

3. 
Amendment + 
Guidance
                   1                    -                       1                    -                       1 

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

                  -                      -                      -                      -                      -   

                  -                      -                      -                      -                      -   

                   1                    -                       1                    -                       1 

Quant

ML

 No 

                   1                    -                       1                    -                       1 

Qual

ML

 No 

                   1                    -                       1                     1                     1 

Qual

ML

 Possible - high                     1                    -                       1                     1                     1 

Qual

LM

 No 

                   1                     1                     1                     1                     1 

Qual

LM

 No 

                   1                     1                     1                     1                     1 

Qual

LM

 No 

                   1                     1                     1                     1                     1 

Qual

LM

 No 

                   1                     1                     1                     1                     1 

Qual

LM

 No 

                   1                     1                     1                     1                     1 

Quant

LM

 No 

                   1                     1                     1                     1                     1 

Qual

ML

 No 

                   1                     1                     1                     1                     1 

Chemical Use N/A

CSM4 CSM4

74

        -    Establish general principles for the use of chemicals (minimise use, 

Chemicals - selection

0

Qual

LM

 No 

                   1                     1                     1                     1                     1 

Chemical Use N/A

CAM1 CAM1

75

Chemical Use N/A

CSM2 CSM2

76

substitution by less hazardous substances), oblige operator to present 
and discuss alternative substances and establish third party verification. 

        -    Chemical safety assessment / biocide risk assessment includes 
assessment of risks of potential transformation products in HF / 
underground context, as part of permit/licence, with risk management 
measures implemented accordingly

        -    Positive list of substances expected to be safe under EU UG extraction 
conditions and require operators to only use substances on this positive 
list

Chemicals - selection

Chemical Use N/A

CSM3 CSM3

77

        -    Selection of substances (chemicals and proppants) that minimise the 

Chemicals - selection

need for treatment when present in flowback water

Chemical Use N/A

3b

3b x

78

        -    Monitoring

0

Chemical Use N/A

CSM1
a

CSM1a

79

        -    Non-use of any (non-biocidal) substances with [harmonised or notified] 

Chemicals - selection

Undertake monitoring of chemicals type and volume used including 
record keeping

classification as CMR (carcinogenic, mutagenic or toxic for reproduction) 
category 1A, 1B or 2

Chemicals - assessment

Could be e.g. 2-3 times cost for standard CSA / 
risk assessment?

Quant

MM

 No 

                  -                      -                      -                      -                      -   

Partially quantitative.  Potential to cost actually 
developing the list but costs of only using 
substances on that list not quantifiable as per 
measures above.
Not considered feasible to quantify costs as 
insufficient data on which substances (from a 
very large list) require more/less treatment 
under different circumstances.
0

Non-use of any (non-biocidal) substances with 
[harmonised or notified] classification as CMR 
(carcinogenic, mutagenic or toxic for 
reproduction) category 1A, 1B or 2

Quant

MM

 No 

                   1                     1                     1                     1                     1 

Qual

MM

 No 

                   1                     1                     1                     1                     1 

Quant

MM

 Possible - low 

                   1                    -                       1                     1                     1 

Qual

LH

 No 

                   1                     1                     1                     1                     1 

35229 MASTER Measures (20150127) TGAS 20150206.xlsx

Measures in Policy Options

5 of  13

Categorisation

Measure info

Tight Gas

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Chemical Use N/A

CSM1b

80

CSM1
b

vs. 
HIGH
        -    Non-use in biocidal products of any substances with [harmonised or 
notified] classification as CMR (carcinogenic, mutagenic or toxic for 
reproduction) category 1A, 1B or 2

Chemicals - selection

Chemical Use N/A

Chemical Use N/A

CSM1
c

CSM1
d

CSM1c

81

        -    Non-use of any (non-biocidal) substances with [harmonised or notified] 
classification as aquatic acute category 1 or 2 or aquatic chronic 
category 1 or 2

Chemicals - selection

CSM1d

82

        -    Non-use in biocidal products of any substances with [harmonised or 

Chemicals - selection

notified] classification as aquatic acute category 1 or 2 or aquatic chronic 
category 1 or 2

Chemical Use N/A

CDM1 CDM1

83

        -    Disclosure of information to Competent Authority: declaration of 

Chemicals - disclosure

Chemical Use N/A

CDM2 CDM2

84

substance name, CAS number, precise concentrations, quantities and 
all physicochemical and (eco)toxicological data for the substances 
potentially to be used in hydraulic fracturing. Also potentially e.g. date of 
fracturing, total volume of fluids, type and amount of proppant; 
description of the precise additive purpose; concentration in the total 
volume. Per well. Prior to and after operations

        -    Disclosure of information to public: list of chemicals and CAS numbers 

used to be made available (e.g. via company website and centralised 
data dissemination portal) for the chemicals potentially to be used in 
hydraulic fracturing. Per concession/play. Prior to and after operations

Chemicals - disclosure

Chemical Use N/A

N26

N26

Chemical Use N/A

CAH1 CAH1

85

86

        -    Select proppants which minimise the HVHF treatment required

0

        -    Chemical safety assessment / biocide risk assessment includes 

Chemicals - assessment

Chemical Use N/A

CDH1 CDH1

87

assessment of risks of mixtures of chemicals used in HF as part of 
permit/licence, with risk management measures implemented 
accordingly. To include potential additive or synergistic impacts

        -    Disclosure of information to public: details of substance name, CAS 

Chemicals - disclosure

number, concentrations, and all physicochemical and (eco)toxicological 
data for the substances potentially to be used in hydraulic fracturing. 
This is to be made available (e.g. via company website and centralised 
data dissemination portal). Also potentially e.g. date of fracturing, total 
volume of fluids, type and amount of proppant; description of the overall 
purpose of the additives; concentration in the total volume. Per well. 
Prior to and after operations

88

89

90

        -    Non-use of any (non-biocidal) substances with [harmonised or notified] 

Chemicals - selection

classification for any health or environmental effects

        -    Non-use in biocidal products of any substances with [harmonised or 
notified] classification for any health or environmental effects

Chemicals - selection

        -    Use of water or inert materials only in hydraulic fracturing

Chemicals - selection

Chemical Use N/A

Chemical Use N/A

Chemical Use N/A

CSH2a

CSH2
a
CSH2
b
CSH1 CSH1

CSH2b

Water 
Depletion

Water 
Depletion

Water 
Depletion
Water 
Depletion
Water 
Depletion

Water 
Depletion
Water 
Depletion
Water 
Depletion
Water 
Depletion

N/A

38a

38a i

91

        -    i) Notification of water demand from fracturing operations to relevant 

water utilities and competent authorities

N/A

38b

38b

93

        -    Demand profile for water

N/A

N49

N49

N/A

38c

38c

N/A

3a

3a vi

N/A

N/A

3b

3b

3b vi

3b ix

N/A

38d

38d

94

95

96

97

98

99

        -    Strategic planning and staged approach of play development to avoid 

peaks in water demand

        -    Water management plan

        -    Site baseline

Establish water source availability and test for suitability

        -    Monitoring

Water resources availability

        -    Monitoring

Undertake monitoring of water volumes and origin

        -    Reuse of flowback and produced water for fracturing

N/A

38e

38e

100

        -    Use of lower quality water for fracturing (e.g. non-potable ground / 

surface water, rainwater harvesting, saline aquifers, sea water, treated 
industrial waterwaters)

0

0

0

0

0

0

0

0

0

Non-use in biocidal products of any substances 
with [harmonised or notified] classification as 
CMR (carcinogenic, mutagenic or toxic for 
reproduction) category 1A, 1B or 2

Non-use of any (non-biocidal) substances with 
[harmonised or notified] classification as 
aquatic acute category 1 or 2 or aquatic chronic 
category 1 or 2
Non-use in biocidal products of any substances 
with [harmonised or notified] classification as 
aquatic acute category 1 or 2 or aquatic chronic 
category 1 or 2
Is in principle possible to quantify but not 
considered proportionate to do this given costs 
of this are likely to be small and main costs are 
likely to arise due to other implications (e.g. 
Reduced options for chemical use due to 
greater scrutiny potentially leading to reduced 
productivity).
Is in principle possible to quantify but not 
considered proportionate to do this given costs 
of this are likely to be small and main costs are 
likely to arise due to other implications (e.g. 
Reduced options for chemical use due to 
greater scrutiny potentially leading to reduced 
productivity).
0

Scientifically challenging and not likely to be 
possible to quantify with any degree of 
certainty.

Is in principle possible to quantify but not 
considered proportionate to do this given costs 
of this are likely to be small and main costs are 
likely to arise due to other implications (e.g. 
Reduced options for chemical use due to 
greater scrutiny potentially leading to reduced 
productivity).

0

0

 Not thought to be practicable and likely to 
have significant impact on viability and 
productivity of UG extraction. Not considered 
practical to quantify costs - main impact will be 
on well productivity, maintenance frequency, 
etc.
Inform relevant authorities (i.e. water utilities, 
environmental regulators, planning authorities) 
of water demand for the lifetime of the project.
Establish the water demand pattern taking 
account of number of wells, pad locations, 
drilling sequence, water consumption per unit 
operation.  Establish flow patterns including 
peak and average flow volumes under a variety 
of scenarios.
0

Develop a water management plan to cover 
water supply and efficient use on site.
Locate water sources and identifying 
availability, water rights. Test water sources for 
suitability
0

0

Reuse flowback and/or produced water to 
make up fracture fluid.
Use lower quality water (non-potable) to make 
up fracture fluid.

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

Qual

LH

 No 

1. Guidance

3. 
Amendment + 
Guidance
                   1                     1                     1                     1                     1 

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

Qual

LH

 No 

                   1                     1                     1                     1                     1 

Qual

LH

 No 

                   1                     1                     1                     1                     1 

Qual

HL

 Possible - high                     1                    -                       1                     1                     1 

Qual

HL

 No 

                   1                    -                       1                     1                     1 

Qual

Qual

MH

HM

 No 

 No 

                   1                     1                     1                     1                     1 

                  -                      -                      -                      -                      -   

Qual

HM

 Possible - low 

                   1                    -                       1                     1                     1 

Qual

Qual

Qual

MH

MH

HH

 No 

 No 

 No 

                   1                     1                     1                     1                     1 

                   1                     1                     1                     1                     1 

                   1                     1                     1                     1                     1 

Qual

LM

 No 

                   1                     1                     1                     1                     1 

Quant

LM

 Possible - high                     1                    -                       1                     1                     1 

Qual

Qual

Quant

Quant

Quant

Quant

Qual

MM

MM

MM

MM

MM

MM

MM

 No 

                   1                    -                       1                    -                       1 

 Possible - high                     1                     1                     1                     1                     1 

 Possible - high                     1                    -                       1                     1                     1 

 No 

 No 

 No 

 No 

                   1                    -                       1                     1                     1 

                   1                    -                       1                     1                     1 

                   1                    -                       1                     1                     1 

                   1                     1                     1                    -                       1 

35229 MASTER Measures (20150127) TGAS 20150206.xlsx

Measures in Policy Options

6 of  13

Categorisation

Measure info

Tight Gas

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Surface Water N/A

33i

33i

101

vs. 
HIGH
        -    Good site security

0

Surface Water N/A

29a

29a

102

        -    Good practice construction / deconstruction practices, including design 

0

for well abandonment

Surface Water N/A

Surface Water N/A

33a

33d

33a

33d

103

104

        -    Good site practice to prevention of leaks and spills

        -    Spill kits available for use

0

0

Surface Water N/A

3a

3a ii

105

 H 

Site baseline
Undertake sampling of surface water bodies in wet and dry periods

High Ambition 

Surface Water N/A

3b

3b ii

106

L

Monitoring
Undertake monitoring of surface water bodies in wet and dry periods

LOW AMBITION
Monitoring
Undertake monitoring of surface water bodies in 
wet and dry periods

Operators would be required to ensure that the 
site is protected properly to prevent vandalism 
that may lead to pollution from damaged 
equipment/infrastructure.
Note - also included in post closure ref. 
demolition.

Operators should apply construction industry 
good practice to prevent pollution of surface 
water through operator training and approach 
to construction practice.
0

0

Analyse for suspended solids, BOD, dissolved 
oxygen, pH, ammonia, chloride also total 
petroleum hydrocarbons and polyaromatic 
hydrocarbons, radioactivity, fracturing 
chemicals and heavy metals  for assurance.

Analyse for suspended solids, BOD, dissolved 
oxygen, pH, ammonia, chloride also total 
petroleum hydrocarbons and polyaromatic 
hydrocarbons, radioactivity, fracturing 
chemicals and heavy metals  for assurance.

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

Quant

ML

 Yes 

1. Guidance

3. 
Amendment + 
Guidance
                  -                      -                      -                      -                      -   

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

Qual

MM

 Possible - high                     1                     1                     1                     1                     1 

Qual

Quant

MM

MM

 Yes 

 Yes 

                   1                     1                     1                     1                     1 

                   1                     1                     1                     1                     1 

Quant

MM

 Possible - low 

                   1                     1                     1                     1                     1 

Quant

MM

 Possible - high                    -                       1                     1                     1                     1 

Surface Water N/A

3b

3b ii

107

H

Monitoring
Undertake monitoring of surface water bodies in wet and dry periods

Surface Water N/A

33e

33e

108

        -    Berm around site boundary

HIGH AMBITION
AS LOW AMBITION with alert system promoting 
corrective action
0

0

0

Quant

MH

 No 

                   1                    -                       1                    -                       1 

Quant

HM

 No 

                   1                     1                     1                    -                       1 

Surface Water N/A

33g

33g

109

        -    Collection and control of surface runoff

Surface Water N/A

29c

29c

110

        -    Bunding of fuel tanks

Surface Water N/A

30d

30d

111

        -    Use of closed tanks for mud storage

Surface Water N/A

33b

33b

112

        -    Use of tank level alarms

0

0

0

0

Surface Water N/A

33c

33c

113

 H 

Use of double skinned closed storage tanks

High Ambition 

Surface Water N/A

33f

33f

114

        -    Impervious site liner under pad with puncture proof underlay

Air Quality

N/A

59d

59d

115

        -    Use of vehicles (water, chemicals, waste trucking) that meet minimum 

Air Quality

N/A

N54

N54

116

        -    Encourage industry voluntary approach to reduce air pollutants and 

air emission standards e.g. EURO standards

greenhouse gases

0

0

0

Air Quality

N/A

16b

16b i

117

        -    Low emission power supply (i) LPG or (ii) grid electricity rather than 

Low emission power supply (switching to LPG)

Air Quality

N/A

16b

16b ii

118

        -    Low emission power supply (i) LPG or (ii) grid electricity rather than 

diesel

Air Quality

N/A

16d

16d

119

        -    Application of abatement techniques to minimise emissions (assumed 

diesel

Air Quality

N/A

17c

17c

120

L

SCR for NOx and Diesel Particulate Filter (DPF) for PM).
Flares or incinerators to reduce emissions from fracturing fluid at 
exploration stage (where not connected to gas network)

Air Quality

N/A

17c

17c

121

H

Flares or incinerators to reduce emissions from fracturing fluid at 
exploration stage (where not connected to gas network)

Air Quality

N/A

3a

3a i

122

        -    Site baseline

Undertake sampling of air quality

Low emission power supply (switching to grid 
electricity)
0

LOW AMBITION
Flares or incinerators to reduce emissions from 
fracturing fluid at exploration stage
HIGH AMBITION
As LOW AMBITION with no audible or visible 
flaring
0

Air Quality

N/A

3b

3b i

123

        -    Monitoring

0

Undertake monitoring of air quality

Operators construct sites to effectively collect 
and control stormwater, e.g. draining to a single 
collection point, to enable effective control and 
management of any spills and leaks.

0

0

For chemicals, fracturing fluid, muds and 
wastewaters.  Activation triggers corrective 
action/contingency plan implementation.
For chemicals, fracturing fluid, muds and 
wastewaters

0

0

0

0

0

SCR for NOx
Diesel Particulate Filter (DPF) for PM
Capture gas from fracture fluid at exploration 
stage and flare or incinerate 

Quant

MH

 Possible - high                     1                    -                       1                     1                     1 

Quant

HH

 No 

                   1                    -                       1                    -                       1 

Quant

HH

 Possible - low 

                  -                      -                      -                      -                      -   

Quant

HH

 Possible - high                     1                     1                     1                     1                     1 

Quant

HH

 No 

                   1                     1                     1                     1                     1 

Quant

HH

 Yes 

                   1                    -                       1                     1                     1 

Qual

Qual

Quant

Quant

Quant

LL

LM

LM

LM

LM

 No 

 No 

 No 

 No 

 No 

                  -                      -                      -                      -                      -   

                   1                    -                       1                    -                       1 

                   1                    -                       1                    -                       1 

                   1                    -                       1                    -                       1 

                   1                    -                       1                    -                       1 

Quant

MM

 Yes 

                  -                      -                      -                      -                      -   

0

Quant

MM

 No 

                  -                      -                      -                      -                      -   

Three month monitoring period to establish 
baseline using passive monitoring techniques 
at circa six points in the vicinity of a pad.  
Monitoring for combustion gasses (NOx, NO2, 
PM10 and also SO2, CO and VOCs).
On-going monitoring in the vicinity of a pad.  
Monitoring for combustion gasses (NOx, NO2, 
PM10 and also SO2, CO and VOCs).

Quant

MM

 Possible - high                     1                     1                     1                     1                     1 

Quant

MM

 Possible - low 

                   1                     1                     1                     1                     1 

35229 MASTER Measures (20150127) TGAS 20150206.xlsx

Measures in Policy Options

7 of  13

Categorisation

Measure info

Tight Gas

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Air Quality

N/A

16a

16a

124

vs. 
HIGH
        -    Preparation of an emissions reduction plan (reduced emission 

0

completions) including an assessment of potential local air quality 
impacts including implications for compliance with ambient air quality 
limit values

Air Quality

N/A

17b

17b

125

        -    Reduced emission completions (REC) to eliminate gas venting: prohibit 

0

venting of gas; capture and cleaning for use of gas released from 
fracture fluid and produced water

Waste

Waste

Waste

Waste

Waste

N/A

N47

N47

126

        -    Operator demonstrates availability of appropriate wastewater treatment 

N/A

36c

36c

127

        -    Treatment requirements for wastewater and capability of treatment 

works to treat wastewater established

facilities

0

0

N/A

27c

27cii

128

        -    Injection of flowback and produced water into designated formations for 

Untreated wastewater

N/A

N/A

N50

27c

N50

27c i

129

130

disposal, provided specific conditions are in place:
i) treated waste water and
ii) untreated wastewater

        -    Lined open ponds with safety net protecting biodiversity

0

        -    Injection of flowback and produced water into designated formations for 

Treated wastewater

Waste

N/A

3b

3b xiii

131

disposal, provided specific conditions are in place:
i) treated waste water and
ii) untreated wastewater

        -    Monitoring

Undertake monitoring of drilling mud volumes and treatment

Waste

N/A

3b

3b xiv

132

        -    Monitoring

Undertake monitoring of flowback water return rate and characterise

Waste

N/A

3b

3b xv

133

        -    Monitoring

Undertake monitoring (volume and characterisation) of produced water 
volume and treatment solution

0

0

0

Waste

Waste

Waste

Waste

Waste

N/A

N53

N53

134

        -    Consider wastewaters from unconventional gas operations as hazardous 

0

N/A

27f

27f

135

waste

        -    Operators keep records of all waste management operations and make 
them available for inspection (e.g. of flowback, produced water 
management)

N/A

N51

N51

136

        -    Consider wastewaters hazardous unless operator demonstrates 

N/A

N/A

N52

30c

N52

30c

137

138

        -    Ban injection of wastewaters into geological formations for disposal

        -    Use of closed loop system to contain drilling mud

otherwise

Post Closure

Post Closure

N/A

N/A

N22

N11

N22

N11

141

142

        -    Maintain records of well location and depth indefinitely

        -    Operator to provide financial guarantee to competent authority to cover 
costs of any remedial action following transfer of responsibility

Post Closure

N/A

N12

N12

143

        -    Operator to provide a financial contribution to the competent authority 

Post Closure

N/A

26g

26g

144

following closure and abandonment. This contribution should be 
sufficient to cover ongoing monitoring and related activities over a 
sufficient period [assume minimum of 20 years)

        -    Implementation of remedial measures if well failure occurs

Post Closure

N/A

29a

29a

145

        -    Good practice construction / deconstruction practices, including design 

for well abandonment

Post Closure

N/A

N10

N10

146

        -    Operator remain responsible for monitoring, reporting and corrective 

0

measures following well closure (or temporary well abandonment) and 
prior to transfer of responsibility to competent authority [assume 
minimum of 20 years]

0

0

0

0

0

0

0

0

0

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

Quant

MH

 No 

1. Guidance

3. 
Amendment + 
Guidance
                   1                     1                     1                     1                     1 

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

Quant

HH

 No 

                   1                     1                     1                     1                     1 

Qual

Qual

Qual

Qual

Qual

LL

LL

LL

ML

MM

 No 

                   1                    -                       1                     1                     1 

 Possible - high                     1                     1                     1                     1                     1 

 Possible - high                    -                       1                     1                     1                     1 

 No 

                   1                     1                     1                     1                     1 

 Possible - high                    -                       1                     1                     1                     1 

Quant

MM

 No 

                   1                     1                     1                     1                     1 

Quant

MM

 Possible - high                     1                     1                     1                     1                     1 

Quant

MM

 Possible - high                     1                     1                     1                     1                     1 

Qual

Qual

Qual

Qual

Quant

MM

LH

MH

MH

HH

 No 

 No 

 No 

 No 

                  -                      -                      -                      -                      -   

                   1                     1                     1                     1                     1 

                   1                    -                       1                    -                       1 

                  -                      -                      -                      -                      -   

 Possible - high                     1                     1                     1                    -                       1 

Qual

Qual

LL

LM

 Yes 

 No 

                   1                     1                     1                     1                     1 

                  -                      -                      -                       1                     1 

Qual

ML

 No 

                  -                      -                      -                       1                     1 

Plan preparation only
Develop emissions inventory for the site
Undertake dispersion modelling of inventory to 
estimate concentrations within site boundaries 
and surrounding areas
Undertake additional modelling of potential 
impacts of emissions from site on nearby 
population and/or sensitive habitats
Identify and assess options for reducing 
emissions
Capture and cleaning for use of gas released 
from fracture fluid and produced water

0

0

0

0

0

Analyse for VOCs, metals, total petroleum 
hydrocarbons, NORM.

Analyse for oil & grease, BTEX, VOCs, SVOCs, 
TDS, pH, sulphates, H2S, heavy metals, 
NORM, biocides, emulsion breakers, corrosion 
inhibitors. 
Analyse for oil & grease, BTEX, VOCs, SVOCs, 
TDS, pH, sulphates, H2S, heavy metals, 
NORM, biocides, emulsion breakers, corrosion 
inhibitors. 
0

0

0

0

Closed-loop systems employ a suite of solids 
control equipment to minimise drilling fluid 
dilution and provide the economic handling of 
the drilling wastes. The closed loop system can 
include a series of linear-motion shakers, mud 
cleaners and centrifuges followed by a 
dewatering system. The combination of 
equipment typically results in a "dry" location 
where a reserve pit is not required, used fluids 
are recycled, and solid wastes can be land 
farmed, hauled off or injected down-hole.
0

Required following transfer of responsibility as 
prior to that point in time, the operator remains 
responsible for remedial action.
0

Note - measure also listed under 'Underground 
risks'
Note - also included in surface water ref. 
construction.

Qual

Qual

MM

MM

 Possible - high                     1                     1                     1                     1                     1 

 Possible - high                    -                       1                     1                     1                     1 

Operators should apply construction industry 
good practice to prevent pollution of surface 
water through operator training and approach 
to construction practice.
Transfer of responsibility to occur 

Qual

MM

 No 

                  -                      -                      -                       1                     1 

35229 MASTER Measures (20150127) TGAS 20150206.xlsx

Measures in Policy Options

8 of  13

Categorisation

Measure info

Tight Gas

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Post Closure

N/A

13d

13d ii

147

vs. 
HIGH
        -    Abandonment survey

0

Undertake sampling of surface water bodies near the pad

Post Closure

N/A

13d

13d iii

148

 H 

Abandonment survey
Undertake sampling of groundwater near the pad

High Ambition

Post Closure

N/A

13d

13d iv

149

        -    Abandonment survey

Obtain data on drinking water abstraction points (wells, boreholes, 
springs, surface water abstraction points

Post Closure

N/A

13d

13d v

150

        -    Abandonment survey

Undertake land condition (soil) survey around pad

0

0

Post Closure

N/A

13d

13d vi

151

        -    Abandonment survey

Assumed to be Middle Ambition

Undertake survey of biodiversity, ecology and invasive species survey

Post Closure

N/A

13d

13d vii

152

        -    Abandonment survey

0

Surface water
Sampling of surface water courses near the 
pad and analyse for suspended solids, BOD, 
dissolved oxygen, pH, ammonia, chloride also 
total petroleum hydrocarbons and polyaromatic 
hydrocarbons, radioactivity, fracturing 
chemicals and heavy metals  for assurance.

Groundwater
Sampling of monitoring boreholes and analyse 
for dissolved oxygen, pH, ammonia, chloride, 
total petroleum hydrocarbons and polyaromatic 
hydrocarbons, fracturing additive chemicals, 
isotopic fingerprinting (include methane, 
ethane, propane), radioactivity and heavy 
metals.
Drinking water abstraction points
Obtain water quality data and water gas content 
from water abstraction points in the operational 
area (e.g. regarding dissolved oxygen, pH, 
ammonia, chloride, total petroleum 
hydrocarbons and polyaromatic hydrocarbons, 
fracturing additive chemicals, isotopic 
fingerprinting (include methane, ethane, 
propane), radioactivity and heavy metals)

Land condition (soil)
Establish land condition in immediate are of the 
pad and analyse for analyse for total petroleum 
hydrocarbons, polyaromatic hydrocarbon, 
metals suite, pH, sulphate, asbestos, chloride

Scope will vary depending on presence of 
protected species and notable habitats and 
whether a designated site.
0

Post Closure

N/A

13d

13d viii

153

L

Undertake sampling for methane near surface in the pad location
Abandonment survey
Undertake assessment of landuse, infrastructure and buildings

Post Closure

N/A

13d

13d viii

154

H

Abandonment survey
Undertake assessment of landuse, infrastructure and buildings

Post Closure

N/A

13d

13d ix

155

L

Abandonment survey
Undertake assessment of ex-anti underground wells and structures 

Post Closure

N/A

13d

13d ix

156

H

Abandonment survey
Undertake assessment of ex-anti underground wells and structures 

LOW
Undertake assessment of landuse, infrastructure 
and buildings through desk study

LOW AMBITION. Desk study and mapping of 
landuse, infrastructure and buildings.  Objective 
is to enable comparison with baseline 
assessment and consequently any impacts.

HIGH
Undertake assessment of landuse, infrastructure 
and buildings survey through desk study and 
aerial survey

HIGH AMBITION. As above plus remote (aerial) 
survey of land, land uses, structures etc.   
Objective is to enable comparison with baseline 
assessment and consequently any impacts.

LOW
Undertake assessment of underground wells and 
structures through desk study

HIGH
Undertake assessment of underground wells and 
structures desk study to evaluate integrity of 
construction and record of completion and/or 
plugging of existing shallow wells

LOW AMBITION.  Check baseline list of 
penetrations into zone within area (from well 
history databases).  Relates to wells and 
structures in place prior to UG activities.
HIGH AMBITION. As per LOW above plus: 
desk study to evaluate integrity of construction 
and record of completion and/or plugging of 
existing shallow wells.  Relates to wells and 
structures in place prior to UG activities.

Post Closure

N/A

12

12

157

        -    Specific post closure risk assessment, well plugging, inspection and 

0

monitoring requirements (e.g. for releases to air, well integrity, periodicity 
of inspections, wellhead monitoring every 90 days)

Post Closure

N/A

13b

13b i

158

        -    Specific post closure well inspection, maintenance and 

monitoring/reporting programme (i) following detection of possible 
pollution (low ambition); (ii) periodic inspection and monitoring (high 
ambition)

Post closure well inspection, maintenance and 
monitoring/reporting programme - following 
detection of possible pollution (low ambition)

Measure includes:
Flush wells with a buffer fluid before plugging
Plug wells. Use two cement plugs: one in 
producing formation and one for surface to 
bottom of drinking water level, fill the remainder 
with mud.
Perform a mechanical integrity test prior to 
plugging to evaluate integrity of casing and 
cement to remain in ground.
Following detection of possible pollution and 
after well closure.  Well inspection, 
maintenance and monitoring to ensure 
integrity.  Reports would be prepared and 
submitted to competent authority by operators.  
Duration will be until licence surrender.  
Programme would include:
- mechanical integrity testing (MIT)
- determination of any necessary maintenance
- submission of reports
- implementation of remedial actions as 
necessary

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

1. Guidance

2. 
Amendment

3. 
Amendment + 
Guidance

4. Legislation

5. Legislation 
+ Guidance

Quant

MM

 Possible - high                     1                    -                       1                     1                     1 

Quant

MM

 Possible - high                     1                    -                       1                     1                     1 

Quant

MM

 Possible - high                     1                    -                       1                     1                     1 

Quant

MM

 Possible - high                     1                    -                       1                     1                     1 

Quant

LL

 No 

                   1                    -                       1                    -                       1 

Quant

MM

Quant

LL

 No 

 No 

                   1                    -                       1                     1                     1 

                  -                      -                      -                      -                      -   

Quant

MM

 No 

                   1                    -                       1                    -                       1 

Quant

LL

 Possible - high                    -                      -                      -                       1                     1 

Quant

MM

 No 

                  -                      -                      -                      -                      -   

Quant

HH

 Possible - high                     1                     1                     1                     1                     1 

Qual

LH

 Possible - high                    -                      -                      -                       1                     1 

35229 MASTER Measures (20150127) TGAS 20150206.xlsx

Measures in Policy Options

9 of  13

Categorisation

Measure info

Tight Gas

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Post Closure

N/A

13b

13b ii

159

vs. 
HIGH
        -    Specific post closure well inspection, maintenance and 

monitoring/reporting programme (i) following detection of possible 
pollution (low ambition); (ii) periodic inspection and monitoring (high 
ambition)

Post closure well inspection, maintenance and 
monitoring/reporting programme - periodic 
inspection and monitoring (high ambition)

Post Closure

N/A

13c

13c

160

        -    Ownership and liability of wells transferred to a competent authority on 

0

surrender of the site licence following a period of monitoring

Public 
Acceptance

N/A

N23

N23

161

        -    Public disclosure by operators of environmental monitoring (baseline, 

0

operational and post closure), resource use (water use and chemicals), 
production, incidents (e.g. pollution events, well failure) and well integrity 
information 

Public 
Acceptance

N/A

15

15i

162

L

Public consultation and engagement by operators: (i) at all stages (pre-
permitting, permitting, exploration, testing, production and 
abandonment); (ii) for permitting

LOW AMBITION.
Engagement at permitting (website, information, 
public meetings) and abandonment and 
relinquishing of permits.  (website and 
information).  

N/A

N41

N41

163

        -    Member State Competent Authorities provide information on the licences 
and permits of operators involved in unconventional gas exploration and 
production

N/A

N42

N42

164

        -    Prohibit non-disclosure agreements between local residents and/or 

N/A

N40

N40

N/A

15

15i

165

166

landowners and unconventional gas operators

 H 

        -    Member State Competent Authorities provide a map of planned and 
existing exploration, production and abandoned well locations
Public consultation and engagement by operators: (i) at all stages (pre-
permitting, permitting, exploration, testing, production and 
abandonment); (ii) for permitting

N/A

N03

N03

167

        -    All permits/authorisations/licences relating to environmental risk 

0

0

0

HIGH AMBITION.
As per low ambition PLUS the following:
Early stage consultation (initial exploration, pre-
site development and pre-permitting) consultation 
(website, information preparation, public 
meetings).  
Production stage ongoing consultation (ongoing 
website and information provision).
0

N/A

N04

N04

168

sea

N34

N34

169

management to be made available to the public and included on a 
central data repository for all unconventional gas operations in the 
Member State / EU

        -    EU institutions and/or Member States provide peer reviewed information 

to the public on a regular basis on the current state of knowledge of 
potential environmental risks and benefits from unconventional gas and 
available measures to manage those risks

        -    Public authorities produce an underground regional impact assessment 

to optimise resource allocation between unconventional gas and other 
underground resources (e.g. geothermal energy)

permit N35

N35

170

        -    Member States implement integrated permitting for unconventional gas

N/A

N25

N25

171

        -    Reversal of the burden of proof for unconventional gas operators in the 

0

0

0

0

N/A

N38

N38

172

        -    Maintain operator liability for any pollution arising from wells for a period 

0

context of liability in case of environmental damage

N/A

N39

N39

173

        -    Maintain operator liability for any pollution arising from wells indefinitely

of 100 years

N28

N28

174

        -    Assessment by the Competent Authority of the technical and financial 

59a

59a

175

        -    Traffic impact assessment including consideration of noise, emissions 

N29

N29

176

        -    Financial guarantees by operators for environmental and civil liability 

and other relevant impacts

capacity of an operator

operat
or
trans

operat
or

covering any accidents or unintended negative impacts caused by their 
own activities or those outsourced to others (to cover incidents and 
accidents during and after operations, restoration of site)

        -    Operators work together to ensure efficient provision of gas collection 

and wastewater treatment infrastructure

Other 
Measures

efficien
cy

N36

N36

177

0

0

0

0

0

Public 
Acceptance

Public 
Acceptance
Public 
Acceptance
Public 
Acceptance

Public 
Acceptance

Public 
Acceptance

Other 
Measures

Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

1. Guidance

2. 
Amendment

3. 
Amendment + 
Guidance

4. Legislation

5. Legislation 
+ Guidance

Qual

MH

 Possible - high                    -                      -                      -                       1                     1 

Qual

HH

 No 

                  -                      -                      -                       1                     1 

Qual

LL

 Possible - low 

                   1                    -                       1                     1                     1 

Quant

LL

 Possible - high                     1                     1                     1                     1                     1 

Quant

LL

 No 

                  -                      -                      -                       1                     1 

Qual

LL

MM

MM

 No 

 No 

                  -                      -                      -                       1                     1 

                   1                    -                       1                    -                       1 

 Possible - low 

                  -                      -                      -                       1                     1 

Well inspection, maintenance and monitoring to 
ensure integrity on a regular basis (e.g. 3 
yearly).  Reports would be prepared and 
submitted to competent authority by operators.  
Duration will be until licence surrender.  
Programme would include:
- mechanical integrity testing (MIT)
- determination of any necessary maintenance
- submission of reports
- implementation of remedial actions as 
necessary

Following a period of monitoring [minimum 20 
years] after well/pad closure and subsequent 
site reinstatement, the site licence is 
surrendered and the ownership and liability of 
the wells is transferred to the appropriate 
competent authority in MSs.

Following transfer, the competent authority 
takes on responsibility and liability for any 
resultant environmental damage linked to the 
well.
Operators would be required to publicly 
disclose baseline, ongoing monitoring and well 
integrity information through  website 
establishment and maintenance and collation 
of information.  Applies to baseline information 
through to transfer of responsibility to 
Competent Authority.
Note aspects of public acceptance linked to 
chemicals are on the chemicals tab.  The focus 
here is on wider public engagement.

0

0

Also relevant to underground potentially

Quant

Note aspects of public acceptance linked to 
chemicals are on the chemicals tab.  The focus 
here is on wider public engagement.

Quant

0

0

0

0

0

0

0

0

0

0

0

Qual

MM

 No 

                   1                    -                       1                     1                     1 

Qual

MM

 No 

                  -                      -                      -                      -                      -   

Quant

LL

 No 

                   1                    -                       1                     1                     1 

Qual

Qual

Qual

Qual

Qual

Quant

Qual

LL

LL

LM

LM

LM

LM

LM

 No 

 No 

 No 

 No 

 No 

                  -                       1                     1                     1                     1 

                  -                      -                      -                      -                      -   

                   1                    -                       1                    -                       1 

                   1                    -                       1                    -                       1 

                  -                      -                      -                       1                     1 

 Possible - high                     1                    -                       1                     1                     1 

 No 

                  -                      -                      -                       1                     1 

Qual

LM

 No 

                  -                      -                      -                      -                      -   

35229 MASTER Measures (20150127) TGAS 20150206.xlsx

Measures in Policy Options

10 of  13

Categorisation

Measure info

Tight Gas

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

N21

ecolog
y
permit N15

N21

N15

vs. 
HIGH
        -    Implement precautions to prevent invasive species by cleaning vehicles 0

178

179

        -    Mandatory EIA for all projects expected to involve hydraulic fracturing, 

0

before exploration starts

permit N16

N16 i

180

        -    Mandatory EIA (i) after initial phase of well exploration and before first 

test fracturing, and (ii) before production commences

permit N16

N16 ii

181

        -    Mandatory EIA (i) after initial phase of well exploration and before first 

test fracturing, and (ii) before production commences

Mandatory EIA according to Directive 2011/92/EU 
after well exploration and before first test 
fracturing
Mandatory EIA according to Directive 2011/92/EU 
before production commences

permit N17

N17

182

        -    Assessment of whether full project is likely to have significant effects on 

0

Other 
Measures

inciden
t

N08

N08a

183

Other 
Measures

inciden
t

N08

N08b

184

the environment during prospecting phase (i.e. extending the existing 
requirement in relation to deep drillings under the EIA Directive to 
include screening prior to development of exploration plans/prospecting 
and taking account of the entire project)

        -    In the case of an incident/accident significantly affecting the 

environment: (a) operator informs competent authority immediately; (b) 
competent authority provides details of the circumstances of the incident 
and effects on the environment to a designated body at EU level who will 
make non-confidential information available to the public

        -    In the case of an incident/accident significantly affecting the 

environment: (a) operator informs competent authority immediately; (b) 
competent authority provides details of the circumstances of the incident 
and effects on the environment to a designated body at EU level who will 
make non-confidential information available to the public

In the case of an incident/accident significantly 
affecting the environment, operator to inform 
competent authority immediately.

In the case of an incident/accident significantly 
affecting the environment, competent authority to 
provide details of the circumstances of the 
incident and effects on the environment to a 
designated body at EU level who will make non-
confidential information available to the public.
0

trans

59b

59b

185

        -    Transport management plan (including consideration of available road, 

trans

60c

60c

186

        -    Site selection close to water sources to minimise haulage requirements 0

rail, waterway infrastructure)

trans

61b

61b i

187

        -    Minimise resources demands and hence traffic movements through (i) 

trans

61b

61b ii

188

        -    Minimise resources demands and hence traffic movements through (i) 

trans

61c

61c

189

        -    Site selection close to wastewater treatment / disposal facilities to 

water management plans and (ii) wastewater management plans

water management plans and (ii) wastewater management plans

i) water management plans to minimise water 
demands and hence traffic movements. 
ii) wastewater management plans to minimise 
water demands and hence traffic movements. 
0

inciden
t

noi

noi

noi

noi

noi

noi

N09

N09

190

        -    Operator to develop and maintain a contingency plan to address 

minimise haulage requirements

51a

51a

191

foreseeable impacts of operating conditions on environmental risk 
management (e.g. degradation of well barriers, casing/cementing as per 
measure 22)

        -    Maximum noise levels specified

51c

51c

192

        -    Noise screening installation: (i) screen drilling and fracturing rigs with 

noise barrier / enclosure; (ii) acoustic fencing around the site perimeter.

51d

51d

193

        -    Operational hours specified

51e

51e

194

        -    Vehicle routes specified

51f

51f

195

        -    Machinery orientation and selection to minimise noise

3a

3a viii

196

        -    Site baseline

Undertake noise study

noi

3b

3b viii

197

        -    Monitoring

Undertake monitoring of noise

monito
r

guidan
ce
inspect
ion

N27

N27

198

        -    Member States carry out strategic monitoring of unconventional gas 

activities at the level of the gas play to assess overall impacts and 
reaction as necessary

N30

N30

N31

N31

199

200

        -    The European Commission to develop further criteria/guidance for the 
assessment of environmental impacts from unconventional gas
        -    Inspections by Competent Authorities during all stages of development 

(e.g. of well completion reports and environmental risk management and 
controls)

0

0

0

0

0

0

0

0

0

0

0

skills N32

N32

201

        -    Competent Authorities have available sufficient inspection capacity and 

0

inspect
ion
ecolog
y

N33

N33

202

        -    Independent inspection during all stages of development of well integrity 0

appropriately skilled inspectors

N37

N37

203

        -    Pad construction activities staged to reduce soil erosion and to coincide 

0

with low rainfall periods

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

Qual

Quant

Quant

ML

ML

ML

 No 

 No 

 No 

1. Guidance

3. 
Amendment + 
Guidance
                  -                      -                      -                      -                      -   

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

                   1                     1                     1                    -                       1 

                  -                      -                      -                       1                     1 

Quant

ML

 No 

                  -                      -                      -                       1                     1 

Quant

ML

 No 

                  -                      -                      -                      -                      -   

Qual

ML

 Possible - high                    -                      -                      -                       1                     1 

Qual

ML

 No 

                  -                      -                      -                      -                      -   

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

 Possible - high                     1                    -                       1                    -                       1 

 No 

 No 

 No 

 No 

                  -                      -                      -                      -                      -   

                   1                    -                       1                     1                     1 

                   1                    -                       1                     1                     1 

                  -                      -                      -                      -                      -   

 Possible - low 

                   1                    -                       1                     1                     1 

 Possible - high                    -                      -                      -                      -                      -   

 Possible - high                     1                    -                       1                    -                       1 

 Possible - low 

                   1                    -                       1                    -                       1 

 Possible - high                     1                    -                       1                    -                       1 

 Possible - low 

                   1                    -                       1                    -                       1 

 Possible - low 

                   1                    -                       1                    -                       1 

 Possible - low 

                   1                    -                       1                    -                       1 

 No 

 No 

                   1                    -                       1                     1                     1 

                  -                      -                      -                      -                      -   

 Possible - high                     1                    -                       1                     1                     1 

 No 

 No 

 No 

                  -                      -                      -                       1                     1 

                  -                      -                      -                       1                     1 

                  -                      -                      -                       1                     1 

0

0

0

0

0

0

0

0

0

0

0

0

0

0

Screen drilling and fracturing rigs with noise 
barrier/enclosure.

Acoustic fencing around the site perimeter.
(Noise abatement)

(Noise abatement)

(Noise abatement)

Quant

Qual

Qual

Qual

Qual

Quant

Qual

Quant

Qual

Qual

Qual

Consult with relevant regulatory authority and 
carry out baseline noise monitoring

Quant

0

0

0

0

0

0

0

Quant

Quant

Quant

Quant

Qual

Qual

Qual

Other 
Measures
Other 
Measures
Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures

Other 
Measures
Other 
Measures

Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures

Other 
Measures
Other 
Measures

Other 
Measures
Other 
Measures

Other 
Measures
Other 
Measures
Other 
Measures

35229 MASTER Measures (20150127) TGAS 20150206.xlsx

Measures in Policy Options

11 of  13

Categorisation

Measure info

Tight Gas

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Other 
Measures

3a

baselin
e

3a iv

204

vs. 
HIGH
        -    Site baseline

Obtain data on drinking water abstraction points (wells, boreholes and 
springs)

Other 
Measures

monito
r

3a

3a v

205

        -    Site baseline

Undertake land condition (soil) survey around pad

0

0

trans

3a

3a vii

206

L

Site baseline
Undertake transport and traffic study.

trans

3a

3a vii

207

H

Site baseline
Undertake transport and traffic study.

ecolog
y

3a

3a ix

208

        -    Site baseline

Undertake survey of biodiversity and ecology survey

LOW AMBITION
Undertake transport and traffic study.  Liaise with 
highway authority and identify relevant routes 
to/from well pad
HIGH AMBITION
Undertake transport and traffic study.  As per 
LOW plus traffic survey and traffic modelling
Assumed to be Middle Ambition

3a

baselin
e

3a

baselin
e

3a xii

209

L

Site baseline
Undertake assessment of landuse, infrastructure and buildings

3a xii

210

H

Site baseline
Undertake assessment of landuse, infrastructure and buildings

LOW AMBITION. Undertake assessment of 
landuse, infrastructure and buildings through desk 
study
HIGH AMBITION.  As LOW plus remote (aerial) 
survey of land, land uses, structures etc.

3b

3b iv

211

        -    Monitoring 

Undertake monitoring of drinking water abstraction points (wells, 
boreholes, springs, surface water)

3b

3b v

212

        -    Monitoring

trans

3b

3b vii

213

Undertake land condition (soil) tests every five years outside site 
boundary
        -    Monitoring

Undertake monitoring of traffic numbers and patterns

3b xi

214

        -    Monitoring

3b xii

215

        -    Monitoring

Undertake monitoring of energy source and use

Undertake monitoring of greenhouse gas emissions

3b xvi

216

        -    Monitoring

Assumed to be Middle Ambition

Undertake periodic surveys of biodiversity, ecology and invasive species

0

0

0

0

0

0

0

0

0

0

0

0

0

3b xix

217

        -    Monitoring

7

218

        -    Cumulative effects (e.g. air pollution, traffic impacts, water resource 

Undertake monitoring of spills volume, nature, location and clean-up 
(including reporting)

permit N02

N02

219

permit N06

N06

220

sea

N13

N13

221

equip N18

N18

222

requirements) of gas play development assessed in planning and 
permitting taking into account other (non-unconventional gas) 
developments and plans

        -    Operator, as part of permit conditions, obtains independent evaluation of 

environmental risk management measures for gas concession before 
fracturing commences and at regular intervals thereafter
        -    Operations to be subject to an integrated permit from the national 

authority, setting measures to manage environmental impacts for all 
environmental media (air surface/ground water, land). Combined 
monitoring and inspection regimes where separate competent 
authorities exist

        -    Member States carry out SEA to set up plans/programmes setting the 

framework for unconventional gas projects before granting concessions 
for unconventional gas exploration and production and assess 
environmental effects of such plans. Assessment to address surface 
aspects such as water abstraction, waste treatment and disposal, 
transport, air quality, landtake, species diversity as well as known 
underground risks. Assessment to be reviewed before production 
commences on the basis of information obtained during the exploration 
phase. Those MS that have already granted concessions to perform 
such an assessment without undue delay.

        -    Ensure equipment is compatible with composition of fracturing 

chemicals

equip N19

N19

223

        -    Carry out thorough planning and testing of equipment prior to hydraulic 

manag
ement

N20

N20

224

        -    Environmental management system accreditation for unconventional 

fracturing operations

gas installation operators

monito
r

monito
r

3b

3b

3b

monito
r
monito
r
ecolog
y

3b

inciden
t

7

cumul
ative

Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures
Other 
Measures
Other 
Measures

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

1. Guidance

2. 
Amendment

3. 
Amendment + 
Guidance

4. Legislation

5. Legislation 
+ Guidance

Quant

MM

 Possible - high                     1                    -                       1                     1                     1 

Quant

MM

 Possible - high                     1                    -                       1                     1                     1 

Quant

MM

 Possible - high                     1                    -                       1                    -                       1 

Quant

MM

 Possible - low 

                   1                    -                       1                    -                       1 

Quant

MM

 Possible - low 

                   1                    -                       1                     1                     1 

Quant

MM

 Possible - high                     1                    -                       1                    -                       1 

Develop list of wells, boreholes, springs, 
surface water abstraction points within area 
(from public data).
List names and depth of all potentially affected 
(by UG) underground sources of drinking water
Provide geochemical information and 
maps/cross section on subsurface aquifers.
Obtain water quality data and water gas content 
from existing available data.

Trial pits and analyse for total petroleum 
hydrocarbons, polyaromatic hydrocarbon, 
metals suite, pH, sulphate, asbestos, chloride.

0

0

Scope will vary depending on presence of 
protected species and notable habitats and 
whether a designated site.
Desk study

0

Quant

MM

 No 

                   1                    -                       1                    -                       1 

Obtain water quality data and water gas content 
from existing available data.  Ongoing 
monitoring. Annual desk study using data from 
abstraction points.
Analyse for total petroleum hydrocarbons, 
polyaromatic hydrocarbon, metals suite, pH, 
sulphate, chloride).
Traffic count site/system to provide weekly or 
monthly counts.
0

0

Scope and frequency will vary depending on 
presence of protected species and notable 
habitats and whether a designated site.  
Invasive species mitigation plan if required.
0

Quant

MM

 Possible - high                     1                    -                       1                     1                     1 

Quant

MM

 No 

                   1                    -                       1                    -                       1 

Quant

Quant

Quant

Quant

MM

MM

MM

MM

 Possible - low 

                   1                    -                       1                    -                       1 

 No 

 No 

                   1                    -                       1                    -                       1 

                  -                      -                      -                       1                     1 

 Possible - low 

                   1                    -                       1                    -                       1 

Quant

MM

 Possible - high                     1                    -                       1                     1                     1 

Complimentary with other measures associated 
with planning.

Qual

MM

 No 

                  -                      -                      -                       1                     1 

Linked to SEA
0

Qual

MM

 No 

                  -                      -                      -                       1                     1 

0

0

0

0

0

Quant

MM

 No 

                   1                     1                     1                     1                     1 

Quant

MM

 No 

                  -                      -                      -                       1                     1 

Qual

Qual

Quant

MM

MM

MM

 Possible - high                     1                    -                       1                    -                       1 

 Possible - high                     1                    -                       1                    -                       1 

 No 

                   1                    -                       1                    -                       1 

35229 MASTER Measures (20150127) TGAS 20150206.xlsx

Measures in Policy Options

12 of  13

Categorisation

Measure info

Tight Gas

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Other 
Measures

materi
als

30e

30e

225

vs. 
HIGH
        -    Muds restricted to approved list with known properties/safety data or non-

Restrict muds to approved list

toxic drilling muds

30e

30e

226

        -    Muds restricted to approved list with known properties/safety data or non-

Restrict muds to non-toxic drilling muds

29e

29e

227

        -    Site reinstatement plan

toxic drilling muds

Other 
Measures
Other 
Measures

Other 
Measures

materi
als
manag
ement

9b

inciden
t

Other 
Measures

9a

inciden
t

9a

229

trans

60a

60a

230

Other 
Measures
Other 
Measures

Other 
Measures

9b

228

        -    Emergency response plan developed and put in place covering:

- leaks from the well to groundwater or surface water
- releases of flammable gases from the well or pipelines
- fires and floods
- leaks and spillage of chemicals, flowback or produced water
- releases during transportation

        -    Consideration of major hazards for all stages in the life cycle of the 

development (early design, through operations to post abandonment) 
and development of HSE case or similar demonstrating adequacy of the 
design, operations and HSE management (including emergency 
response) for both safety and environmental major impacts

        -    Use of temporary surface pipes for distribution of water supply

trans

60b

60b

231

        -    Use of temporary surface pipes for collection of flowback

trans

61a

61a

232

        -    Use of temporary surface pipes for collection of produced water

0

0

0

0

0

0

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

Qual

MH

 No 

1. Guidance

3. 
Amendment + 
Guidance
                  -                      -                      -                      -                      -   

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

Qual

Quant

HH

MH

 No 

 Yes 

                   1                     1                     1                    -                       1 

                   1                    -                       1                     1                     1 

Qual

HM

 Yes 

                  -                       1                     1                     1                     1 

Specify the use of muds from an approved list 
to minimise the risk of harmful (polluting) mud 
production which could result in polluting spills

Specify the use of water-based muds/non-toxic 
chemical additives
Purpose of measure is to develop a 
reinstatement plan for the site following well 
closure and abandonment.
0

0

Qual

HH

 Possible - high                     1                     1                     1                     1                     1 

Temporary pipes laid above ground to supply 
water to pads.

Qual

Qual

HH

HH

 No 

 No 

                  -                      -                      -                      -                      -   

                  -                      -                      -                      -                      -   

Temporary pipes laid above ground to collect 
flowback and transport to treatment plant.
Temporary pipes  laid above ground to collect 
produced water and transport to treatment 
plant.

Qual

HH

 No 

                  -                      -                      -                      -                      -   

35229 MASTER Measures (20150127) TGAS 20150206.xlsx

Measures in Policy Options

13 of  13

Non-BAU Measures in Policy Options

Categorisation

Measure info

Tight Oil

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Zoning

N/A

42b

42b

Zoning

N/A

N48

N48

Zoning

Zoning

N/A

N/A

26c

40c

26c

40c

Zoning

N/A

2f

Zoning

N/A

2f

Zoning

N/A

2f

Zoning

N/A

2f

Zoning

N/A

2f

2f

2f

2f

2f

2f

1

2

3

4

5

6

7

8

9

vs. 
HIGH
        -    Location of sites close to existing pipeline infrastructure

        -    Minimum distance between hydraulic fracture pipes and geological 

strata containing aquifers and the surface to be determined based on 
risk assessment

        -    Fracturing to be a minimum distance from water resources

        -    High land, agricultural and ecological value locations avoided

0

0

0

0

        -    Buffer zones from abstraction points, aquifers, residential areas, 

schools, hospitals, abandoned wells, active & abandoned mines and 
other potential pathways for fluid migration, and other sensitive areas

        -    Buffer zones from abstraction points, aquifers, residential areas, 

schools, hospitals, abandoned wells, active & abandoned mines and 
other potential pathways for fluid migration, and other sensitive areas

        -    Buffer zones from abstraction points, aquifers, residential areas, 

schools, hospitals, abandoned wells, active & abandoned mines and 
other potential pathways for fluid migration, and other sensitive areas

        -    Buffer zones from abstraction points, aquifers, residential areas, 

schools, hospitals, abandoned wells, active & abandoned mines and 
other potential pathways for fluid migration, and other sensitive areas

        -    Buffer zones from abstraction points, aquifers, residential areas, 

schools, hospitals, abandoned wells, active & abandoned mines and 
other potential pathways for fluid migration, and other sensitive areas

Buffer zone from abstraction points and aquifers 
of 1,000m for drinking water related abstraction

Buffer zone from residential areas, schools 
hospitals and other sensitive areas of 1,600m

Buffer zone within which detailed noise 
assessment is required of 305m

Buffer zone from abandoned wells and other 
potential pathways for fluid migration (distance 
specified on risk basis)
Additional containment for sites near surface 
water supply locations

Zoning

N/A

40a

40a

10

        -    Optimisation from an environmental perspective, i.e. the number of 

0

wells, pad density and pad spacing

Zoning

N/A

40b

40b

11

        -    Compatibility with current and future potential landuse (Natura 2000 

0

sites, conservation sites, human use, industrial use, appropriate zoning, 
CCS, geothermal, water abstraction)

Zoning

N/A

1b

1b

12

        -    Restrict operations within and underneath specified sites (e.g. Natura 

0

2000, protected sites, coal mining areas, drinking water protection areas, 
water extraction areas for public drinking water supply, mineral spa 
protection zones karstic aquifers, flood prone zones and mineral water 
reserves, reforestation areas and areas known to be unfavourable - with 
regard to potential environmental impacts) or within certain distances to 
specified sites

        -    Avoid high seismicity risk areas

0

        -    Minimum distance between hydraulic fracture pipes and geological 

strata containing aquifers (e.g. 600m) and the surface (e.g. 600m depth 
requires special permit)

Zoning

Zoning

N/A

N/A

55e

55i

55e

55i

13

14

Zoning

N/A

55i

55i

15

        -    Minimum distance between hydraulic fracture pipes and geological 

strata containing aquifers (e.g. 600m) and the surface (e.g. 600m depth 
requires special permit)

Minimum distance between hydraulic fracture 
pipes and geological strata containing aquifers of, 
e.g. 600m
Special permit conditions where hydraulic fracture 
pipes are less than, e.g. 600m depth from surface

0

0

Site selection takes into consideration existing 
gas pipeline infrastructure to enable 
minimisation of the need for additional pipeline 
infrastructure and associated development 
impacts.
0

0

Assessment of and avoidance of high land, 
agricultural and ecological value locations (e.g.  
Natura 2000 sites, conservation sites).
Applicable regardless of area type (i.e. not 
limited to Natura 2000 site and other specified 
sites).  Hence applicability is broader.
0

0

0

This is required for sites within 800m of water 
supply locations in Colorado.  The definition of 
additional containment is not provided - 
assume bunded tanks/site - see other 
measures re. this in surface water
Optimise the number of wells per pad, pad 
density and pad spacing to minimise 
cumulative environmental impacts (e.g. one 
pad per 2.6 km2 proposed by New York State).  
This will include consideration of siting with 
consideration of conflicts with nearby or 
adjacent sensitive land uses such as 
residences, schools, hospitals, available 
transport infrastructure, access to water supply, 
access to wastewater treatment, etc.

Note: the acquis communautaire requires this 
measure, but it is uncertain whether it is 
adequately implemented by Member States. 
Assessment of compatibility with current and 
future landuse plans (e.g. Natura 2000 sites, 
conservation sites, human use, industrial use, 
appropriate zoning.

Note: the acquis communautaire requires this 
measure, notably as a mitigation measure 
under the SEAD/the EIAD, but without 
guarantee of the result, Natura2000 Directives 
excepted. 
Operations would be restricted (i.e. greater 
controls as required by discretion of MS 
authorities) within specified areas. 

Areas known to be unfavourable - with regard 
to potential environmental impacts - geological 
and hydrogeological conditions (groundwater 
potentials and pathways, tectonically fractured 
rocks, artesian confined aquifers, suspected 
pathways introduced by abandoned boreholes 
or mining activities)
0

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

Qual

LL

 No 

1. Guidance

3. 
Amendment + 
Guidance
                   1                    -                       1                    -                       1 

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

Qual

MM

 No 

                   1                    -                       1                    -                       1 

Qual

Qual

MM

MM

 No 

 No 

                   1                    -                       1                    -                       1 

                   1                    -                       1                    -                       1 

Qual

MM

 No 

                   1                    -                       1                    -                       1 

Qual

MM

 No 

                   1                    -                       1                    -                       1 

Qual

MM

 No 

                   1                    -                       1                    -                       1 

Qual

MM

 No 

                   1                    -                       1                    -                       1 

Qual

MM

 No 

                   1                    -                       1                    -                       1 

Qual

HM

 No 

                   1                    -                       1                    -                       1 

Qual

HM

 No 

                   1                    -                       1                    -                       1 

Qual

HM

 Yes 

                   1                    -                       1                    -                       1 

Qual

Qual

HH

HH

 No 

 No 

                   1                    -                       1                    -                       1 

                   1                    -                       1                    -                       1 

Qual

HH

 No 

                   1                    -                       1                    -                       1 

35229 MASTER Measures (20150127) TOIL 20150206.xlsx

Measures in Policy Options

1 of  13

Categorisation

Measure info

Tight Oil

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Zoning

N/A

1a

1a

16

vs. 
HIGH
        -    Prohibit operations within and underneath specified sites (e.g. Natura 

0

2000, protected sites, coal mining areas, drinking water protection areas, 
water extraction areas for public drinking water supply, mineral spa 
protection zones karstic aquifers, flood prone zones and mineral water 
reserves, reforestation areas and areas known to be unfavourable - with 
regard to potential environmental impacts) or within certain distances to 
specified sites

        -    Competent authorities compile regional maps of underground resources 0

Areas known to be unfavourable - with regard 
to potential environmental impacts - geological 
and hydrogeological conditions (groundwater 
potentials and pathways, tectonically fractured 
rocks, artesian confined aquifers, suspected 
pathways introduced by abandoned boreholes 
or mining activities)
0

Underground 
Risks
Underground 
Risks

Underground 
Risks
Underground 
Risks

Underground 
Risks

Underground 
Risks
Underground 
Risks

N/A

N44

N44

N/A

N55

N55

N/A

28d

28d

N/A

N45

N45

17

18

19

20

        -    Conduct 2D seismic survey to identify faults and fractures.

        -    Sharing of information to ensure that all operators in a gas play are 

aware of risks and can therefore plan

        -    Members States establish a capability to address groundwater 

contamination arising from unconventional gas operations. In the case of 
transboundary aquifers, joint capability established

0

0

0

0

0

0

0

0

N/A

55g

55g

21

        -    Engagement with third parties (e.g. regulators, other operators, 

N/A

22d

22d

N/A

26d

26d i

22

23

 L 

researchers) to ensure fully aware of any issues / proximity (e.g. to other 
underground activities)

        -    Search for and document potential leakage pathways (e.g. other wells, 

0

Through delivery of 3 a x detail

Related to 3a x-a4 (which is Low Ambition)

Through delivery of 3 a x detail

faults, mines)
i) Development of a conceptual model of the zone before work 
commences covering geology, groundwater flows, pathways, 
microseismicity and subsequent updating of the model as information 
becomes available ii) as above plus Modelling of the impact of 
groundwater pumping on linked groundwater and surface water flows 
and quality

        -    Modelling of fracturing programme to predict extent of fracture growth 

Underground 
Risks

N/A

26e

26e

25

based on best information

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

Qual

HH

 Yes 

1. Guidance

3. 
Amendment + 
Guidance
                   1                    -                       1                    -                       1 

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

Qual

Quant

Qual

Qual

LL

LM

LM

LM

 No 

 Yes 

                   1                    -                       1                    -                       1 

                   1                     1                     1                     1                     1 

 Possible - low 

                   1                     1                     1                     1                     1 

 No 

                   1                    -                       1                    -                       1 

Qual

ML

 Possible - low 

                   1                    -                       1                    -                       1 

Quant

Quant

MM

MM

 Possible - high                     1                     1                     1                     1                     1 

 No 

                   1                     1                     1                     1                     1 

Quant

MM

 No 

                   1                    -                       1                     1                     1 

Underground 
Risks
Underground 
Risks
Underground 
Risks

Underground 
Risks
Underground 
Risks

Underground 
Risks
Underground 
Risks

N/A

26g

26g

N/A

55c

55c

N/A

N09

N09

N/A

N05

N05

N/A

N46

N46

N/A

N07

N07

N/A

55h

55h

26

27

28

29

30

31

32

        -    Implementation of remedial measures if well failure occurs

        -    Ground motion prediction models to assess the potential impact of 

induced earthquakes

        -    Operator to develop and maintain a contingency plan to address 

foreseeable impacts of operating conditions on environmental risk 
management (e.g. degradation of well barriers, casing/cementing as per 
measure 22)

        -    Initiate immediate flowback post fracturing

        -    The European Commission develops criteria/guidance for underground 

risk assessment (such as criteria to assess potential risks of 
groundwater contamination and induced seismicity) related to 
unconventional gas

        -    Operator to use alternative fracturing fluids to water (e.g. nitrogen, CO2, 

propane)

        -    Smaller preinjection prior to main operations to enable induced 

seismicity response to be assessed

0

0

0

0

0

0

0

0

Application of Discrete Fracture Network (DFN) 
approach including dynamic response (e.g. 
hydro-shearing), Finite Element Analysis (FEA) 
or Discrete Element Method (DEM). 3D fracture 
modelling integrated with geomechanics 
modelling.
0

0

0

0

0

0

Qual

Quant

Quant

Qual

Qual

Qual

Qual

Mini-fractures area carried out prior to full scale 
fracturing.  Monitoring of the seismic response 
to the mini-fractures is carried out and 
assessment of the location's actual response 
compared with the modelled response is made.  
Analysis of results and conclusion drawn 
regarding suitability of and approach to full 
scale operations.  Enables model predictions to 
be verified and the actual response of 
geological formations to be assessed.

MM

MM

MM

MM

MH

MH

MH

 Yes 

 No 

 No 

 No 

 No 

 No 

 No 

                   1                     1                     1                     1                     1 

                  -                      -                      -                      -                      -   

                  -                      -                      -                       1                     1 

                   1                     1                     1                    -                       1 

                  -                      -                      -                      -                      -   

                  -                      -                      -                      -                      -   

                   1                    -                       1                    -                       1 

35229 MASTER Measures (20150127) TOIL 20150206.xlsx

Measures in Policy Options

2 of  13

Categorisation

Measure info

Tight Oil

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

0

Measures to be split out for cost purposes

Quant

HH

 Yes 

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

1. Guidance

3. 
Amendment + 
Guidance
                  -                       1                     1                     1                     1 

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

Underground 
Risks

N/A

22a

22a

33

Underground 
Risks

N/A

22b

22b i

34

vs. 
HIGH
        -    Key elements to maintain well safety such as:

• blowout preventers
• pressure & temperature monitoring and shutdown systems
• fire and gas detection
• continuous monitoring for leaks and release of gas and liquids
• modelling to aid well/HF design
• isolate underground source of drinking water prior to drilling
• ensure micro-annulus is not formed
• casing centralizers to centre casing in hole
• select corrosive resistant alloys and high strength steel
• fish back casing
• maintain appropriate bending radius
• triple casing
• casing and cementing designed to sustain high pressure and low 
magnitude seismicity
• isolation of the well from aquifers
• casings: minimum distance the surface casing extends below aquifer 
(e.g. 30m below the deepest underground source of drinking water 
encountered while drilling the well, ref. Environment Agency 2012) and 
surface casing cemented before reaching depth of e.g. 75m below 
underground drinking water (ref. AEA 2012). Production casing 
cemented up to at least 150 metres above the formation where hydraulic 

        -    Integrity testing at key stages in well development e.g. 

before/during/after all HF events, including:
i) wireline logging (calliper, cement bond, variable density)
ii) pressure (between 2.1 and 8.3 MPa based on setting times between 4 
and 72 hours)/hydrostatic testing
iii) mechanical integrity testing of equipment (MIT)
iv) casing inspection test and log

i) wireline logging (calliper, cement bond, variable 
density)

0

Quant

HH

 Yes 

                  -                       1                     1                     1                     1 

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

N/A

22b

22b ii

35

        -    Integrity testing at key stages in well development e.g. 

before/during/after all HF events, including:
i) wireline logging (calliper, cement bond, variable density)
ii) pressure (between 2.1 and 8.3 MPa based on setting times between 4 
and 72 hours)/hydrostatic testing
iii) mechanical integrity testing of equipment (MIT)
iv) casing inspection test and log

ii) pressure (between 2.1 and 8.3 MPa based on 
setting times between 4 and 72 hours)/hydrostatic 
testing

0

Quant

HH

 Yes 

                  -                       1                     1                     1                     1 

N/A

22b

22b iii

36

        -    Integrity testing at key stages in well development e.g. 

iii) mechanical integrity testing of equipment (MIT) 0

Quant

HH

 Yes 

                  -                       1                     1                     1                     1 

before/during/after all HF events, including:
i) wireline logging (calliper, cement bond, variable density)
ii) pressure (between 2.1 and 8.3 MPa based on setting times between 4 
and 72 hours)/hydrostatic testing
iii) mechanical integrity testing of equipment (MIT)
iv) casing inspection test and log

N/A

22b

22b iv

37

        -    Integrity testing at key stages in well development e.g. 

iv) casing inspection test and log

before/during/after all HF events, including:
i) wireline logging (calliper, cement bond, variable density)
ii) pressure (between 2.1 and 8.3 MPa based on setting times between 4 
and 72 hours)/hydrostatic testing
iii) mechanical integrity testing of equipment (MIT)
iv) casing inspection test and log

N/A

22c

22c

38

        -    Multiple barriers between the target formation and people/the 

N/A

26f

26f

39

N/A

3a

3a xi

40

environment, including minimum vertical distance between target 
formation and aquifers

        -    Monitoring and control during operations to ensure hydraulic fractures / 
pollutants do not extend beyond the gas-producing formations and does 
not result in seismic events or damage to buildings/installations that 
could be the result of fracturing

        -    Site baseline

0

0

0

N/A

55d

55d

41

L

Establish the presence of methane in groundwater, including drinking 
water
Microseismicity monitoring and management requirements during 
operations

N/A

55d

55d

42

        -    Microseismicity monitoring and management requirements during 

operations

LOW AMBITION
Real time monitoring of microseismicity during all 
operations
HIGH AMBITION
AS LOW plus cessation of fracturing if specified 
induced seismic activity is detected (using traffic 
light system)

0

0

Quant

HH

 Yes 

                  -                       1                     1                     1                     1 

Qual

HH

 No 

                   1                     1                     1                    -                       1 

Linked to 3 b xvii

Quant

HH

 No 

                   1                     1                     1                     1                     1 

0

Quant

MM

 Yes 

                   1                     1                     1                     1                     1 

Linked to 3 b xvii

Quant

MM

 No 

                  -                       1                     1                     1                     1 

0

Qual

HH

 No 

                   1                     1                     1                     1                     1 

35229 MASTER Measures (20150127) TOIL 20150206.xlsx

Measures in Policy Options

3 of  13

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

Quant

MM

 Yes 

1. Guidance

3. 
Amendment + 
Guidance
                  -                      -                      -                      -                      -   

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

Quant

HH

 Possible - low 

                   1                     1                     1                     1                     1 

Quant

HH

 No 

                   1                     1                     1                     1                     1 

Quant

MH

 Yes 

                  -                      -                      -                      -                      -   

Quant

HH

 No 

                   1                     1                     1                     1                     1 

Quant

HH

 No 

                   1                     1                     1                     1                     1 

Quant

MH

 No 

                   1                     1                     1                     1                     1 

Quant

HH

 No 

                  -                      -                      -                      -                      -   

Quant

HH

 Possible - low 

                   1                     1                     1                     1                     1 

Quant

HH

 Possible - low 

                   1                     1                     1                     1                     1 

Quant

HH

 Possible - high                     1                     1                     1                     1                     1 

Categorisation

Measure info

Tight Oil

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Underground 
Risks

N/A

3a

3a iii

43

vs. 
HIGH
L

Site baseline
Undertake sampling of groundwater

Underground 
Risks

N/A

3a

3a iii

44

H

Site baseline
Undertake sampling of groundwater

MEDIUM AMBITION
Sampling of shallow groundwater during wet and 
dry periods (cost is shown in Middle Ambition 
column)

HIGH AMIBITION
Borehole to sample deep groundwater and 
characterise the hydrological series (cost is 
shown in High Ambition column)

Concentrate boreholes near pad (as on 
impacts on groundwater due to surface spills 
greatest near pad).  Boreholes, at 15m depth at 
each corner.  Analyse for dissolved oxygen, pH, 
ammonia, chloride, total petroleum 
hydrocarbons and polyaromatic hydrocarbons, 
fracturing additive chemicals, isotopic 
fingerprinting (include methane, ethane, 
propane), radioactivity and heavy metals.

Deep boreholes in area.  Analyse for dissolved 
oxygen, pH, ammonia, chloride, total petroleum 
hydrocarbons and polyaromatic hydrocarbons, 
fracturing additive chemicals, isotopic 
fingerprinting (include methane, ethane, 
propane), radioactivity and heavy metals.

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

N/A

3a

3a x-a1

45

        -    Site baseline

0

N/A

3a

3a x-a2

46

L

N/A

3a

3a x-a2

47

H

Geological, hydrogeological and seismic conceptual model
[1] Obtain and analyze seismic (earthquake) history.
Site baseline
Geological, hydrogeological and seismic conceptual model
[2] Obtain geomechanical information on fractures, stress, rock strength, 
in situ fluid pressures
Site baseline
Geological, hydrogeological and seismic conceptual model
[2] Obtain geomechanical information on fractures, stress, rock strength, 
in situ fluid pressures

N/A

3a

3a x-a3

48

N/A

3a

3a x-a4

49

N/A

3a

3a x-a4

50

N/A

3a

3a x-a5

51

        -    Site baseline

L

Geological, hydrogeological and seismic conceptual model
[3] Undertake surface microseismic survey
Site baseline
Geological, hydrogeological and seismic conceptual model
[4] Undertake complex modelling of fluid flows and migration (reservoir 
simulations) 
Site baseline
Geological, hydrogeological and seismic conceptual model
[4] Undertake complex modelling of fluid flows and migration (reservoir 
simulations) 
        -    Site baseline

H

N/A

3a

3a x-a6

52

 H 

Geological, hydrogeological and seismic conceptual model
[5] Develop maps and cross sections of local geologic structure
Site baseline
Geological, hydrogeological and seismic conceptual model
[6] Conduct 3D seismic survey to identify faults and fractures

N/A

3a

3a x-a7

53

        -    Site baseline

N/A

3a

3a xiii

54

N/A

3a

3a xiii

55

L

H

Geological, hydrogeological and seismic conceptual model
[7] Obtain data on area, thickness, capacity, porosity and permeability of 
formations.
Site baseline
Undertake assessment of existing underground wells and structures

Site baseline
Undertake assessment of existing underground wells and structures

Underground 
Risks

N/A

3b

3b iii

56

L

Monitoring
Undertake monitoring of groundwater

LOW AMBITION. Undertake desk study based on 
existing data and literature

HIGH AMBITION. In addition LOW obtain 
geomechanical information on fractures, stress, 
rock strength, in situ fluid pressures through new 
cores and stratigraphic tests.
0

LOW AMBITION. Modelling over 100 years

HIGH AMBITION. Modelling is done over 10,000 
years

0

0

0

0

0

0

0

0

0

0

0

0

HIGH AMBITION.  As LOW AMBITION plus 
undertake assessment of underground wells and 
structures desk study to evaluate integrity of 
construction and record of completion and/or 
plugging of existing shallow wells
MEDIUM AMBITION
Sampling of shallow groundwater during wet and 
dry periods

Underground 
Risks

N/A

3b

3b iii

57

H

Monitoring
Undertake monitoring of groundwater

HIGH AMBITION
Deep groundwater sampling network to determine 
the characteristics of deep groundwater and 
formation water and piezometric levels

Underground 
Risks
Underground 
Risks

N/A

N/A

3b

3b

3b xvii

58

        -    Monitoring

3b xviii

59

        -    Monitoring

Undertake monitoring of induced seismicity from fracturing

0

0

Undertake monitoring for presence of methane seepages in 
groundwater, including drinking water.

LOW AMBITION.  Undertake assessment of 
underground wells and structures

Develop list of penetrations into zone within 
area (from well history databases).

Quant

MH

 Possible - high                    -                      -                      -                      -                      -   

0

Quant

HH

 No 

                   1                     1                     1                     1                     1 

Concentrate boreholes near pad (as on 
impacts on groundwater due to surface spills 
greatest near pad).  Boreholes, at 15m depth at 
each corner.  Analyse for dissolved oxygen, pH, 
ammonia, chloride, total petroleum 
hydrocarbons and polyaromatic hydrocarbons, 
fracturing additive chemicals, isotopic 
fingerprinting (include methane, ethane, 
propane), radioactivity and heavy metals.

Deep boreholes network in area. Analyse for 
dissolved oxygen, pH, ammonia, chloride, total 
petroleum hydrocarbons and polyaromatic 
hydrocarbons, fracturing additive chemicals, 
isotopic fingerprinting (include methane, 
ethane, propane), radioactivity and heavy 
metals.
0

0

Quant

MM

 Yes 

                  -                      -                      -                      -                      -   

Quant

HH

 No 

                   1                     1                     1                     1                     1 

Quant

Quant

HH

HH

 No 

                   1                     1                     1                     1                     1 

 Possible - low 

                  -                      -                      -                      -                      -   

35229 MASTER Measures (20150127) TOIL 20150206.xlsx

Measures in Policy Options

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Categorisation

Measure info

Tight Oil

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Chemical Use N/A

CSL5 CSL5

60

Chemical Use N/A

N24

N24

Chemical Use N/A

CAL1 CAL1

Chemical Use N/A

CAL2 CAL2

61

62

63

vs. 
HIGH
        -    Authorities to organise an exchange of views/information on 

environmentally safer technologies and alternatives to the use of 
chemicals in hydraulic fracturing

        -    Traceability of chemicals used by an operator

0

0

        -    CSA/risk assessment explicitly specific to hydraulic fracturing in the EU 

Chemicals - assessment

to be included in REACH Registration

        -    Develop a peer-reviewed EU-level exposure scenario / SpERC for HF for 

Chemicals - assessment

different chemical types

Chemical Use N/A

CAL3 CAL3

64

        -    CAL2 to be implemented in CSAs for chemicals used in HF and any 

Chemicals - assessment

deviations explained

Chemical Use N/A

CDL1 CDL1

65

        -    Disclosure of information to Competent Authority: declaration of 
substance name and CAS number for the chemical substances 
potentially to be used in hydraulic fracturing. Per concession/play

Chemicals - disclosure

Chemical Use N/A

CDL2 CDL2

66

        -    Disclosure of information to the public: list of chemicals potentially to be 

Chemicals - disclosure

used in hydraulic fracturing by UG company to be made available (e.g. 
via company website or centralised data dissemination portal). Per 
concession/play

Chemical Use N/A

CSL1a CSL1a

67

        -    Non-use of any (non-biocidal) substances with [harmonised or notified] 

Chemicals - selection

Chemical Use N/A

CSL1b CSL1b

68

Chemical Use N/A

CSL1c CSL1c

69

Chemical Use N/A

CSL1d CSL1d

70

classification as CMR (carcinogenic, mutagenic or toxic for reproduction) 
category 1A or 1B

        -    Non-use in biocidal products of any substances with [harmonised or 
notified] classification as CMR (carcinogenic, mutagenic or toxic for 
reproduction) category 1A or 1B

        -    Non-use of any (non-biocidal) substances with [harmonised or notified] 
classification as aquatic acute category 1 or aquatic chronic category 1

        -    Non-use in biocidal products of any substances with [harmonised or 
notified] classification as aquatic acute category 1 or aquatic chronic 
category 1

Chemicals - selection

Chemicals - selection

Chemicals - selection

Chemical Use N/A

CSL2 CSL2

71

        -    Non-use of any substances on REACH Candidate List for authorisation 

Chemicals - selection

(substances of very high concern)

Chemical Use N/A

CSL3 CSL3

72

        -    Negative list of named substances that must not be used in UG 
extraction (alternative to two measures CSL1 and CSL2)

Chemicals - selection

Chemical Use N/A

CSL4 CSL4

73

        -    Demonstration that all steps practicable have been taken to reduce 

Chemicals - selection

number, concentration and volume of chemicals used in hydraulic 
fracturing

0

0

Cost to be estimated based on existing data in 
#11.
Estimated cost of developing SpERC to similar 
level of detail to those that already exist for e.g. 
additives used in petroleum products 
(CONCAWE/ESIG)  
http://www.cefic.org/Industry-
support/Implementing-reach/Guidances-and-
Tools1/
Should be feasible to estimate additional cost 
of UG company doing their own CSA for this 
specific use for typical number of chemicals 
used.
Is in principle possible to quantify but not 
considered proportionate to do this given costs 
of this are likely to be small and main costs are 
likely to arise due to other implications (e.g. 
Reduced options for chemical use due to 
greater scrutiny potentially leading to reduced 
productivity).
Is in principle possible to quantify but not 
considered proportionate to do this given costs 
of this are likely to be small and main costs are 
likely to arise due to other implications (e.g. 
Reduced options for chemical use due to 
greater scrutiny potentially leading to reduced 
productivity).
0

0

0

0

Too many substances potentially used in HF to 
robustly estimate differences in costs.  Impacts 
on well productivity will far outweigh differences 
in prices of fluid additives.
Partially quantitative.  Potential to cost actually 
developing the list but costs of not using 
substances on that list not quantifiable as per 
measures above.  
Not considered feasible to quantify costs as too 
site-specific.

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

Qual

LL

 No 

Qual

Quant

Quant

LL

ML

ML

 No 

 No 

 No 

1. Guidance

3. 
Amendment + 
Guidance
                   1                    -                       1                    -                       1 

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

                  -                      -                      -                      -                      -   

                  -                      -                      -                      -                      -   

                   1                    -                       1                    -                       1 

Quant

ML

 No 

                   1                    -                       1                    -                       1 

Qual

ML

 No 

                   1                    -                       1                     1                     1 

Qual

ML

 Possible - high                     1                    -                       1                     1                     1 

Qual

LM

 No 

                   1                     1                     1                     1                     1 

Qual

LM

 No 

                   1                     1                     1                     1                     1 

Qual

LM

 No 

                   1                     1                     1                     1                     1 

Qual

LM

 No 

                   1                     1                     1                     1                     1 

Qual

LM

 No 

                   1                     1                     1                     1                     1 

Quant

LM

 No 

                   1                     1                     1                     1                     1 

Qual

ML

 No 

                   1                     1                     1                     1                     1 

Chemical Use N/A

CSM4 CSM4

74

        -    Establish general principles for the use of chemicals (minimise use, 

Chemicals - selection

0

Qual

LM

 No 

                   1                     1                     1                     1                     1 

Chemical Use N/A

CAM1 CAM1

75

Chemical Use N/A

CSM2 CSM2

76

substitution by less hazardous substances), oblige operator to present 
and discuss alternative substances and establish third party verification. 

        -    Chemical safety assessment / biocide risk assessment includes 
assessment of risks of potential transformation products in HF / 
underground context, as part of permit/licence, with risk management 
measures implemented accordingly

        -    Positive list of substances expected to be safe under EU UG extraction 
conditions and require operators to only use substances on this positive 
list

Chemicals - selection

Chemical Use N/A

CSM3 CSM3

77

        -    Selection of substances (chemicals and proppants) that minimise the 

Chemicals - selection

need for treatment when present in flowback water

Chemical Use N/A

3b

3b x

78

        -    Monitoring

0

Chemical Use N/A

CSM1
a

CSM1a

79

        -    Non-use of any (non-biocidal) substances with [harmonised or notified] 

Chemicals - selection

Undertake monitoring of chemicals type and volume used including 
record keeping

classification as CMR (carcinogenic, mutagenic or toxic for reproduction) 
category 1A, 1B or 2

Chemicals - assessment

Could be e.g. 2-3 times cost for standard CSA / 
risk assessment?

Quant

MM

 No 

                  -                      -                      -                      -                      -   

Partially quantitative.  Potential to cost actually 
developing the list but costs of only using 
substances on that list not quantifiable as per 
measures above.
Not considered feasible to quantify costs as 
insufficient data on which substances (from a 
very large list) require more/less treatment 
under different circumstances.
0

Non-use of any (non-biocidal) substances with 
[harmonised or notified] classification as CMR 
(carcinogenic, mutagenic or toxic for 
reproduction) category 1A, 1B or 2

Quant

MM

 No 

                   1                     1                     1                     1                     1 

Qual

MM

 No 

                   1                     1                     1                     1                     1 

Quant

MM

 Possible - low 

                   1                    -                       1                     1                     1 

Qual

LH

 No 

                   1                     1                     1                     1                     1 

35229 MASTER Measures (20150127) TOIL 20150206.xlsx

Measures in Policy Options

5 of  13

Categorisation

Measure info

Tight Oil

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Chemical Use N/A

CSM1b

80

CSM1
b

vs. 
HIGH
        -    Non-use in biocidal products of any substances with [harmonised or 
notified] classification as CMR (carcinogenic, mutagenic or toxic for 
reproduction) category 1A, 1B or 2

Chemicals - selection

Chemical Use N/A

Chemical Use N/A

CSM1
c

CSM1
d

CSM1c

81

        -    Non-use of any (non-biocidal) substances with [harmonised or notified] 
classification as aquatic acute category 1 or 2 or aquatic chronic 
category 1 or 2

Chemicals - selection

CSM1d

82

        -    Non-use in biocidal products of any substances with [harmonised or 

Chemicals - selection

notified] classification as aquatic acute category 1 or 2 or aquatic chronic 
category 1 or 2

Chemical Use N/A

CDM1 CDM1

83

        -    Disclosure of information to Competent Authority: declaration of 

Chemicals - disclosure

Chemical Use N/A

CDM2 CDM2

84

substance name, CAS number, precise concentrations, quantities and 
all physicochemical and (eco)toxicological data for the substances 
potentially to be used in hydraulic fracturing. Also potentially e.g. date of 
fracturing, total volume of fluids, type and amount of proppant; 
description of the precise additive purpose; concentration in the total 
volume. Per well. Prior to and after operations

        -    Disclosure of information to public: list of chemicals and CAS numbers 

used to be made available (e.g. via company website and centralised 
data dissemination portal) for the chemicals potentially to be used in 
hydraulic fracturing. Per concession/play. Prior to and after operations

Chemicals - disclosure

Chemical Use N/A

N26

N26

Chemical Use N/A

CAH1 CAH1

85

86

        -    Select proppants which minimise the HVHF treatment required

0

        -    Chemical safety assessment / biocide risk assessment includes 

Chemicals - assessment

Chemical Use N/A

CDH1 CDH1

87

assessment of risks of mixtures of chemicals used in HF as part of 
permit/licence, with risk management measures implemented 
accordingly. To include potential additive or synergistic impacts

        -    Disclosure of information to public: details of substance name, CAS 

Chemicals - disclosure

number, concentrations, and all physicochemical and (eco)toxicological 
data for the substances potentially to be used in hydraulic fracturing. 
This is to be made available (e.g. via company website and centralised 
data dissemination portal). Also potentially e.g. date of fracturing, total 
volume of fluids, type and amount of proppant; description of the overall 
purpose of the additives; concentration in the total volume. Per well. 
Prior to and after operations

88

89

90

        -    Non-use of any (non-biocidal) substances with [harmonised or notified] 

Chemicals - selection

classification for any health or environmental effects

        -    Non-use in biocidal products of any substances with [harmonised or 
notified] classification for any health or environmental effects

Chemicals - selection

        -    Use of water or inert materials only in hydraulic fracturing

Chemicals - selection

Chemical Use N/A

Chemical Use N/A

Chemical Use N/A

CSH2a

CSH2
a
CSH2
b
CSH1 CSH1

CSH2b

Water 
Depletion

Water 
Depletion

Water 
Depletion
Water 
Depletion
Water 
Depletion

Water 
Depletion
Water 
Depletion
Water 
Depletion
Water 
Depletion

N/A

38a

38a i

91

        -    i) Notification of water demand from fracturing operations to relevant 

water utilities and competent authorities

N/A

38b

38b

93

        -    Demand profile for water

N/A

N49

N49

N/A

38c

38c

N/A

3a

3a vi

N/A

N/A

3b

3b

3b vi

3b ix

N/A

38d

38d

94

95

96

97

98

99

        -    Strategic planning and staged approach of play development to avoid 

peaks in water demand

        -    Water management plan

        -    Site baseline

Establish water source availability and test for suitability

        -    Monitoring

Water resources availability

        -    Monitoring

Undertake monitoring of water volumes and origin

        -    Reuse of flowback and produced water for fracturing

N/A

38e

38e

100

        -    Use of lower quality water for fracturing (e.g. non-potable ground / 

surface water, rainwater harvesting, saline aquifers, sea water, treated 
industrial waterwaters)

0

0

0

0

0

0

0

0

0

Non-use in biocidal products of any substances 
with [harmonised or notified] classification as 
CMR (carcinogenic, mutagenic or toxic for 
reproduction) category 1A, 1B or 2

Non-use of any (non-biocidal) substances with 
[harmonised or notified] classification as 
aquatic acute category 1 or 2 or aquatic chronic 
category 1 or 2
Non-use in biocidal products of any substances 
with [harmonised or notified] classification as 
aquatic acute category 1 or 2 or aquatic chronic 
category 1 or 2
Is in principle possible to quantify but not 
considered proportionate to do this given costs 
of this are likely to be small and main costs are 
likely to arise due to other implications (e.g. 
Reduced options for chemical use due to 
greater scrutiny potentially leading to reduced 
productivity).
Is in principle possible to quantify but not 
considered proportionate to do this given costs 
of this are likely to be small and main costs are 
likely to arise due to other implications (e.g. 
Reduced options for chemical use due to 
greater scrutiny potentially leading to reduced 
productivity).
0

Scientifically challenging and not likely to be 
possible to quantify with any degree of 
certainty.

Is in principle possible to quantify but not 
considered proportionate to do this given costs 
of this are likely to be small and main costs are 
likely to arise due to other implications (e.g. 
Reduced options for chemical use due to 
greater scrutiny potentially leading to reduced 
productivity).

0

0

 Not thought to be practicable and likely to 
have significant impact on viability and 
productivity of UG extraction. Not considered 
practical to quantify costs - main impact will be 
on well productivity, maintenance frequency, 
etc.
Inform relevant authorities (i.e. water utilities, 
environmental regulators, planning authorities) 
of water demand for the lifetime of the project.
Establish the water demand pattern taking 
account of number of wells, pad locations, 
drilling sequence, water consumption per unit 
operation.  Establish flow patterns including 
peak and average flow volumes under a variety 
of scenarios.
0

Develop a water management plan to cover 
water supply and efficient use on site.
Locate water sources and identifying 
availability, water rights. Test water sources for 
suitability
0

0

Reuse flowback and/or produced water to 
make up fracture fluid.
Use lower quality water (non-potable) to make 
up fracture fluid.

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

Qual

LH

 No 

1. Guidance

3. 
Amendment + 
Guidance
                   1                     1                     1                     1                     1 

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

Qual

LH

 No 

                   1                     1                     1                     1                     1 

Qual

LH

 No 

                   1                     1                     1                     1                     1 

Qual

HL

 Possible - high                     1                    -                       1                     1                     1 

Qual

HL

 No 

                   1                    -                       1                     1                     1 

Qual

Qual

MH

HM

 No 

 No 

                   1                     1                     1                     1                     1 

                  -                      -                      -                      -                      -   

Qual

HM

 Possible - low 

                   1                    -                       1                     1                     1 

Qual

Qual

Qual

MH

MH

HH

 No 

 No 

 No 

                   1                     1                     1                     1                     1 

                   1                     1                     1                     1                     1 

                   1                     1                     1                     1                     1 

Qual

LM

 No 

                   1                     1                     1                     1                     1 

Quant

LM

 Possible - high                     1                    -                       1                     1                     1 

Qual

Qual

Quant

Quant

Quant

Quant

Qual

MM

MM

MM

MM

MM

MM

MM

 No 

                   1                    -                       1                    -                       1 

 Possible - high                     1                     1                     1                     1                     1 

 Possible - high                     1                    -                       1                     1                     1 

 No 

 No 

 No 

 No 

                   1                    -                       1                     1                     1 

                   1                    -                       1                     1                     1 

                   1                    -                       1                     1                     1 

                   1                     1                     1                    -                       1 

35229 MASTER Measures (20150127) TOIL 20150206.xlsx

Measures in Policy Options

6 of  13

Categorisation

Measure info

Tight Oil

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Surface Water N/A

33i

33i

101

vs. 
HIGH
        -    Good site security

0

Surface Water N/A

29a

29a

102

        -    Good practice construction / deconstruction practices, including design 

0

for well abandonment

Surface Water N/A

Surface Water N/A

33a

33d

33a

33d

103

104

        -    Good site practice to prevention of leaks and spills

        -    Spill kits available for use

0

0

Surface Water N/A

3a

3a ii

105

 H 

Site baseline
Undertake sampling of surface water bodies in wet and dry periods

High Ambition 

Surface Water N/A

3b

3b ii

106

L

Monitoring
Undertake monitoring of surface water bodies in wet and dry periods

LOW AMBITION
Monitoring
Undertake monitoring of surface water bodies in 
wet and dry periods

Operators would be required to ensure that the 
site is protected properly to prevent vandalism 
that may lead to pollution from damaged 
equipment/infrastructure.
Note - also included in post closure ref. 
demolition.

Operators should apply construction industry 
good practice to prevent pollution of surface 
water through operator training and approach 
to construction practice.
0

0

Analyse for suspended solids, BOD, dissolved 
oxygen, pH, ammonia, chloride also total 
petroleum hydrocarbons and polyaromatic 
hydrocarbons, radioactivity, fracturing 
chemicals and heavy metals  for assurance.

Analyse for suspended solids, BOD, dissolved 
oxygen, pH, ammonia, chloride also total 
petroleum hydrocarbons and polyaromatic 
hydrocarbons, radioactivity, fracturing 
chemicals and heavy metals  for assurance.

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

Quant

ML

 Yes 

1. Guidance

3. 
Amendment + 
Guidance
                  -                      -                      -                      -                      -   

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

Qual

MM

 Possible - high                     1                     1                     1                     1                     1 

Qual

Quant

MM

MM

 Yes 

 Yes 

                   1                     1                     1                     1                     1 

                   1                     1                     1                     1                     1 

Quant

MM

 Possible - low 

                   1                     1                     1                     1                     1 

Quant

MM

 Possible - high                    -                       1                     1                     1                     1 

Surface Water N/A

3b

3b ii

107

H

Monitoring
Undertake monitoring of surface water bodies in wet and dry periods

Surface Water N/A

33e

33e

108

        -    Berm around site boundary

HIGH AMBITION
AS LOW AMBITION with alert system promoting 
corrective action
0

0

0

Quant

MH

 No 

                   1                    -                       1                    -                       1 

Quant

HM

 No 

                   1                     1                     1                    -                       1 

Surface Water N/A

33g

33g

109

        -    Collection and control of surface runoff

Surface Water N/A

29c

29c

110

        -    Bunding of fuel tanks

Surface Water N/A

30d

30d

111

        -    Use of closed tanks for mud storage

Surface Water N/A

33b

33b

112

        -    Use of tank level alarms

0

0

0

0

Surface Water N/A

33c

33c

113

 H 

Use of double skinned closed storage tanks

High Ambition 

Surface Water N/A

33f

33f

114

        -    Impervious site liner under pad with puncture proof underlay

Air Quality

N/A

59d

59d

115

        -    Use of vehicles (water, chemicals, waste trucking) that meet minimum 

Air Quality

N/A

N54

N54

116

        -    Encourage industry voluntary approach to reduce air pollutants and 

air emission standards e.g. EURO standards

greenhouse gases

0

0

0

Air Quality

N/A

16b

16b i

117

        -    Low emission power supply (i) LPG or (ii) grid electricity rather than 

Low emission power supply (switching to LPG)

Air Quality

N/A

16b

16b ii

118

        -    Low emission power supply (i) LPG or (ii) grid electricity rather than 

diesel

Air Quality

N/A

16d

16d

119

        -    Application of abatement techniques to minimise emissions (assumed 

diesel

Air Quality

N/A

17c

17c

120

L

SCR for NOx and Diesel Particulate Filter (DPF) for PM).
Flares or incinerators to reduce emissions from fracturing fluid at 
exploration stage (where not connected to gas network)

Air Quality

N/A

17c

17c

121

H

Flares or incinerators to reduce emissions from fracturing fluid at 
exploration stage (where not connected to gas network)

Air Quality

N/A

3a

3a i

122

        -    Site baseline

Undertake sampling of air quality

Low emission power supply (switching to grid 
electricity)
0

LOW AMBITION
Flares or incinerators to reduce emissions from 
fracturing fluid at exploration stage
HIGH AMBITION
As LOW AMBITION with no audible or visible 
flaring
0

Air Quality

N/A

3b

3b i

123

        -    Monitoring

0

Undertake monitoring of air quality

Operators construct sites to effectively collect 
and control stormwater, e.g. draining to a single 
collection point, to enable effective control and 
management of any spills and leaks.

0

0

For chemicals, fracturing fluid, muds and 
wastewaters.  Activation triggers corrective 
action/contingency plan implementation.
For chemicals, fracturing fluid, muds and 
wastewaters

0

0

0

0

0

SCR for NOx
Diesel Particulate Filter (DPF) for PM
Capture gas from fracture fluid at exploration 
stage and flare or incinerate 

Quant

MH

 Possible - high                     1                    -                       1                     1                     1 

Quant

HH

 No 

                   1                    -                       1                    -                       1 

Quant

HH

 Possible - low 

                  -                      -                      -                      -                      -   

Quant

HH

 Possible - high                     1                     1                     1                     1                     1 

Quant

HH

 No 

                   1                     1                     1                     1                     1 

Quant

HH

 Yes 

                   1                    -                       1                     1                     1 

Qual

Qual

Quant

Quant

Quant

LL

LM

LM

LM

LM

 No 

 No 

 No 

 No 

 No 

                  -                      -                      -                      -                      -   

                   1                    -                       1                    -                       1 

                   1                    -                       1                    -                       1 

                   1                    -                       1                    -                       1 

                   1                    -                       1                    -                       1 

Quant

MM

 Yes 

                  -                      -                      -                      -                      -   

0

Quant

MM

 No 

                  -                      -                      -                      -                      -   

Three month monitoring period to establish 
baseline using passive monitoring techniques 
at circa six points in the vicinity of a pad.  
Monitoring for combustion gasses (NOx, NO2, 
PM10 and also SO2, CO and VOCs).
On-going monitoring in the vicinity of a pad.  
Monitoring for combustion gasses (NOx, NO2, 
PM10 and also SO2, CO and VOCs).

Quant

MM

 Possible - high                     1                     1                     1                     1                     1 

Quant

MM

 Possible - low 

                   1                     1                     1                     1                     1 

35229 MASTER Measures (20150127) TOIL 20150206.xlsx

Measures in Policy Options

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Categorisation

Measure info

Tight Oil

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Air Quality

N/A

16a

16a

124

vs. 
HIGH
        -    Preparation of an emissions reduction plan (reduced emission 

0

completions) including an assessment of potential local air quality 
impacts including implications for compliance with ambient air quality 
limit values

Air Quality

N/A

17b

17b

125

        -    Reduced emission completions (REC) to eliminate gas venting: prohibit 

0

venting of gas; capture and cleaning for use of gas released from 
fracture fluid and produced water

Waste

Waste

Waste

Waste

Waste

N/A

N47

N47

126

        -    Operator demonstrates availability of appropriate wastewater treatment 

N/A

36c

36c

127

        -    Treatment requirements for wastewater and capability of treatment 

works to treat wastewater established

facilities

0

0

N/A

27c

27cii

128

        -    Injection of flowback and produced water into designated formations for 

Untreated wastewater

N/A

N/A

N50

27c

N50

27c i

129

130

disposal, provided specific conditions are in place:
i) treated waste water and
ii) untreated wastewater

        -    Lined open ponds with safety net protecting biodiversity

0

        -    Injection of flowback and produced water into designated formations for 

Treated wastewater

Waste

N/A

3b

3b xiii

131

disposal, provided specific conditions are in place:
i) treated waste water and
ii) untreated wastewater

        -    Monitoring

Undertake monitoring of drilling mud volumes and treatment

Waste

N/A

3b

3b xiv

132

        -    Monitoring

Undertake monitoring of flowback water return rate and characterise

Waste

N/A

3b

3b xv

133

        -    Monitoring

Undertake monitoring (volume and characterisation) of produced water 
volume and treatment solution

0

0

0

Waste

Waste

Waste

Waste

Waste

N/A

N53

N53

134

        -    Consider wastewaters from unconventional gas operations as hazardous 

0

N/A

27f

27f

135

waste

        -    Operators keep records of all waste management operations and make 
them available for inspection (e.g. of flowback, produced water 
management)

N/A

N51

N51

136

        -    Consider wastewaters hazardous unless operator demonstrates 

N/A

N/A

N52

30c

N52

30c

137

138

        -    Ban injection of wastewaters into geological formations for disposal

        -    Use of closed loop system to contain drilling mud

otherwise

Post Closure

Post Closure

N/A

N/A

N22

N11

N22

N11

141

142

        -    Maintain records of well location and depth indefinitely

        -    Operator to provide financial guarantee to competent authority to cover 
costs of any remedial action following transfer of responsibility

Post Closure

N/A

N12

N12

143

        -    Operator to provide a financial contribution to the competent authority 

Post Closure

N/A

26g

26g

144

following closure and abandonment. This contribution should be 
sufficient to cover ongoing monitoring and related activities over a 
sufficient period [assume minimum of 20 years)

        -    Implementation of remedial measures if well failure occurs

Post Closure

N/A

29a

29a

145

        -    Good practice construction / deconstruction practices, including design 

for well abandonment

Post Closure

N/A

N10

N10

146

        -    Operator remain responsible for monitoring, reporting and corrective 

0

measures following well closure (or temporary well abandonment) and 
prior to transfer of responsibility to competent authority [assume 
minimum of 20 years]

0

0

0

0

0

0

0

0

0

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

Quant

MH

 No 

1. Guidance

3. 
Amendment + 
Guidance
                   1                     1                     1                     1                     1 

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

Quant

HH

 No 

                   1                     1                     1                     1                     1 

Qual

Qual

Qual

Qual

Qual

LL

LL

LL

ML

MM

 No 

                   1                    -                       1                     1                     1 

 Possible - high                     1                     1                     1                     1                     1 

 Possible - high                    -                       1                     1                     1                     1 

 No 

                   1                     1                     1                     1                     1 

 Possible - high                    -                       1                     1                     1                     1 

Quant

MM

 No 

                   1                     1                     1                     1                     1 

Quant

MM

 Possible - high                     1                     1                     1                     1                     1 

Quant

MM

 Possible - high                     1                     1                     1                     1                     1 

Qual

Qual

Qual

Qual

Quant

MM

LH

MH

MH

HH

 No 

 No 

 No 

 No 

                  -                      -                      -                      -                      -   

                   1                     1                     1                     1                     1 

                   1                    -                       1                    -                       1 

                  -                      -                      -                      -                      -   

 Possible - high                     1                     1                     1                    -                       1 

Qual

Qual

LL

LM

 Yes 

 No 

                   1                     1                     1                     1                     1 

                  -                      -                      -                       1                     1 

Qual

ML

 No 

                  -                      -                      -                       1                     1 

Plan preparation only
Develop emissions inventory for the site
Undertake dispersion modelling of inventory to 
estimate concentrations within site boundaries 
and surrounding areas
Undertake additional modelling of potential 
impacts of emissions from site on nearby 
population and/or sensitive habitats
Identify and assess options for reducing 
emissions
Capture and cleaning for use of gas released 
from fracture fluid and produced water

0

0

0

0

0

Analyse for VOCs, metals, total petroleum 
hydrocarbons, NORM.

Analyse for oil & grease, BTEX, VOCs, SVOCs, 
TDS, pH, sulphates, H2S, heavy metals, 
NORM, biocides, emulsion breakers, corrosion 
inhibitors. 
Analyse for oil & grease, BTEX, VOCs, SVOCs, 
TDS, pH, sulphates, H2S, heavy metals, 
NORM, biocides, emulsion breakers, corrosion 
inhibitors. 
0

0

0

0

Closed-loop systems employ a suite of solids 
control equipment to minimise drilling fluid 
dilution and provide the economic handling of 
the drilling wastes. The closed loop system can 
include a series of linear-motion shakers, mud 
cleaners and centrifuges followed by a 
dewatering system. The combination of 
equipment typically results in a "dry" location 
where a reserve pit is not required, used fluids 
are recycled, and solid wastes can be land 
farmed, hauled off or injected down-hole.
0

Required following transfer of responsibility as 
prior to that point in time, the operator remains 
responsible for remedial action.
0

Note - measure also listed under 'Underground 
risks'
Note - also included in surface water ref. 
construction.

Qual

Qual

MM

MM

 Possible - high                     1                     1                     1                     1                     1 

 Possible - high                    -                       1                     1                     1                     1 

Operators should apply construction industry 
good practice to prevent pollution of surface 
water through operator training and approach 
to construction practice.
Transfer of responsibility to occur 

Qual

MM

 No 

                  -                      -                      -                       1                     1 

35229 MASTER Measures (20150127) TOIL 20150206.xlsx

Measures in Policy Options

8 of  13

Categorisation

Measure info

Tight Oil

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Post Closure

N/A

13d

13d ii

147

vs. 
HIGH
        -    Abandonment survey

0

Undertake sampling of surface water bodies near the pad

Post Closure

N/A

13d

13d iii

148

 H 

Abandonment survey
Undertake sampling of groundwater near the pad

High Ambition

Post Closure

N/A

13d

13d iv

149

        -    Abandonment survey

Obtain data on drinking water abstraction points (wells, boreholes, 
springs, surface water abstraction points

Post Closure

N/A

13d

13d v

150

        -    Abandonment survey

Undertake land condition (soil) survey around pad

0

0

Post Closure

N/A

13d

13d vi

151

        -    Abandonment survey

Assumed to be Middle Ambition

Undertake survey of biodiversity, ecology and invasive species survey

Post Closure

N/A

13d

13d vii

152

        -    Abandonment survey

0

Surface water
Sampling of surface water courses near the 
pad and analyse for suspended solids, BOD, 
dissolved oxygen, pH, ammonia, chloride also 
total petroleum hydrocarbons and polyaromatic 
hydrocarbons, radioactivity, fracturing 
chemicals and heavy metals  for assurance.

Groundwater
Sampling of monitoring boreholes and analyse 
for dissolved oxygen, pH, ammonia, chloride, 
total petroleum hydrocarbons and polyaromatic 
hydrocarbons, fracturing additive chemicals, 
isotopic fingerprinting (include methane, 
ethane, propane), radioactivity and heavy 
metals.
Drinking water abstraction points
Obtain water quality data and water gas content 
from water abstraction points in the operational 
area (e.g. regarding dissolved oxygen, pH, 
ammonia, chloride, total petroleum 
hydrocarbons and polyaromatic hydrocarbons, 
fracturing additive chemicals, isotopic 
fingerprinting (include methane, ethane, 
propane), radioactivity and heavy metals)

Land condition (soil)
Establish land condition in immediate are of the 
pad and analyse for analyse for total petroleum 
hydrocarbons, polyaromatic hydrocarbon, 
metals suite, pH, sulphate, asbestos, chloride

Scope will vary depending on presence of 
protected species and notable habitats and 
whether a designated site.
0

Post Closure

N/A

13d

13d viii

153

L

Undertake sampling for methane near surface in the pad location
Abandonment survey
Undertake assessment of landuse, infrastructure and buildings

Post Closure

N/A

13d

13d viii

154

H

Abandonment survey
Undertake assessment of landuse, infrastructure and buildings

Post Closure

N/A

13d

13d ix

155

L

Abandonment survey
Undertake assessment of ex-anti underground wells and structures 

Post Closure

N/A

13d

13d ix

156

H

Abandonment survey
Undertake assessment of ex-anti underground wells and structures 

LOW
Undertake assessment of landuse, infrastructure 
and buildings through desk study

LOW AMBITION. Desk study and mapping of 
landuse, infrastructure and buildings.  Objective 
is to enable comparison with baseline 
assessment and consequently any impacts.

HIGH
Undertake assessment of landuse, infrastructure 
and buildings survey through desk study and 
aerial survey

HIGH AMBITION. As above plus remote (aerial) 
survey of land, land uses, structures etc.   
Objective is to enable comparison with baseline 
assessment and consequently any impacts.

LOW
Undertake assessment of underground wells and 
structures through desk study

HIGH
Undertake assessment of underground wells and 
structures desk study to evaluate integrity of 
construction and record of completion and/or 
plugging of existing shallow wells

LOW AMBITION.  Check baseline list of 
penetrations into zone within area (from well 
history databases).  Relates to wells and 
structures in place prior to UG activities.
HIGH AMBITION. As per LOW above plus: 
desk study to evaluate integrity of construction 
and record of completion and/or plugging of 
existing shallow wells.  Relates to wells and 
structures in place prior to UG activities.

Post Closure

N/A

12

12

157

        -    Specific post closure risk assessment, well plugging, inspection and 

0

monitoring requirements (e.g. for releases to air, well integrity, periodicity 
of inspections, wellhead monitoring every 90 days)

Post Closure

N/A

13b

13b i

158

        -    Specific post closure well inspection, maintenance and 

monitoring/reporting programme (i) following detection of possible 
pollution (low ambition); (ii) periodic inspection and monitoring (high 
ambition)

Post closure well inspection, maintenance and 
monitoring/reporting programme - following 
detection of possible pollution (low ambition)

Measure includes:
Flush wells with a buffer fluid before plugging
Plug wells. Use two cement plugs: one in 
producing formation and one for surface to 
bottom of drinking water level, fill the remainder 
with mud.
Perform a mechanical integrity test prior to 
plugging to evaluate integrity of casing and 
cement to remain in ground.
Following detection of possible pollution and 
after well closure.  Well inspection, 
maintenance and monitoring to ensure 
integrity.  Reports would be prepared and 
submitted to competent authority by operators.  
Duration will be until licence surrender.  
Programme would include:
- mechanical integrity testing (MIT)
- determination of any necessary maintenance
- submission of reports
- implementation of remedial actions as 
necessary

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

1. Guidance

2. 
Amendment

3. 
Amendment + 
Guidance

4. Legislation

5. Legislation 
+ Guidance

Quant

MM

 Possible - high                     1                    -                       1                     1                     1 

Quant

MM

 Possible - high                     1                    -                       1                     1                     1 

Quant

MM

 Possible - high                     1                    -                       1                     1                     1 

Quant

MM

 Possible - high                     1                    -                       1                     1                     1 

Quant

LL

 No 

                   1                    -                       1                    -                       1 

Quant

MM

Quant

LL

 No 

 No 

                   1                    -                       1                     1                     1 

                  -                      -                      -                      -                      -   

Quant

MM

 No 

                   1                    -                       1                    -                       1 

Quant

LL

 Possible - high                    -                      -                      -                       1                     1 

Quant

MM

 No 

                  -                      -                      -                      -                      -   

Quant

HH

 Possible - high                     1                     1                     1                     1                     1 

Qual

LH

 Possible - high                    -                      -                      -                       1                     1 

35229 MASTER Measures (20150127) TOIL 20150206.xlsx

Measures in Policy Options

9 of  13

Categorisation

Measure info

Tight Oil

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Post Closure

N/A

13b

13b ii

159

vs. 
HIGH
        -    Specific post closure well inspection, maintenance and 

monitoring/reporting programme (i) following detection of possible 
pollution (low ambition); (ii) periodic inspection and monitoring (high 
ambition)

Post closure well inspection, maintenance and 
monitoring/reporting programme - periodic 
inspection and monitoring (high ambition)

Post Closure

N/A

13c

13c

160

        -    Ownership and liability of wells transferred to a competent authority on 

0

surrender of the site licence following a period of monitoring

Public 
Acceptance

N/A

N23

N23

161

        -    Public disclosure by operators of environmental monitoring (baseline, 

0

operational and post closure), resource use (water use and chemicals), 
production, incidents (e.g. pollution events, well failure) and well integrity 
information 

Public 
Acceptance

N/A

15

15i

162

L

Public consultation and engagement by operators: (i) at all stages (pre-
permitting, permitting, exploration, testing, production and 
abandonment); (ii) for permitting

LOW AMBITION.
Engagement at permitting (website, information, 
public meetings) and abandonment and 
relinquishing of permits.  (website and 
information).  

N/A

N41

N41

163

        -    Member State Competent Authorities provide information on the licences 
and permits of operators involved in unconventional gas exploration and 
production

N/A

N42

N42

164

        -    Prohibit non-disclosure agreements between local residents and/or 

N/A

N40

N40

N/A

15

15i

165

166

landowners and unconventional gas operators

 H 

        -    Member State Competent Authorities provide a map of planned and 
existing exploration, production and abandoned well locations
Public consultation and engagement by operators: (i) at all stages (pre-
permitting, permitting, exploration, testing, production and 
abandonment); (ii) for permitting

N/A

N03

N03

167

        -    All permits/authorisations/licences relating to environmental risk 

0

0

0

HIGH AMBITION.
As per low ambition PLUS the following:
Early stage consultation (initial exploration, pre-
site development and pre-permitting) consultation 
(website, information preparation, public 
meetings).  
Production stage ongoing consultation (ongoing 
website and information provision).
0

N/A

N04

N04

168

sea

N34

N34

169

management to be made available to the public and included on a 
central data repository for all unconventional gas operations in the 
Member State / EU

        -    EU institutions and/or Member States provide peer reviewed information 

to the public on a regular basis on the current state of knowledge of 
potential environmental risks and benefits from unconventional gas and 
available measures to manage those risks

        -    Public authorities produce an underground regional impact assessment 

to optimise resource allocation between unconventional gas and other 
underground resources (e.g. geothermal energy)

permit N35

N35

170

        -    Member States implement integrated permitting for unconventional gas

N/A

N25

N25

171

        -    Reversal of the burden of proof for unconventional gas operators in the 

0

0

0

0

N/A

N38

N38

172

        -    Maintain operator liability for any pollution arising from wells for a period 

0

context of liability in case of environmental damage

N/A

N39

N39

173

        -    Maintain operator liability for any pollution arising from wells indefinitely

of 100 years

N28

N28

174

        -    Assessment by the Competent Authority of the technical and financial 

59a

59a

175

        -    Traffic impact assessment including consideration of noise, emissions 

N29

N29

176

        -    Financial guarantees by operators for environmental and civil liability 

and other relevant impacts

capacity of an operator

operat
or
trans

operat
or

covering any accidents or unintended negative impacts caused by their 
own activities or those outsourced to others (to cover incidents and 
accidents during and after operations, restoration of site)

        -    Operators work together to ensure efficient provision of gas collection 

and wastewater treatment infrastructure

Other 
Measures

efficien
cy

N36

N36

177

0

0

0

0

0

Public 
Acceptance

Public 
Acceptance
Public 
Acceptance
Public 
Acceptance

Public 
Acceptance

Public 
Acceptance

Other 
Measures

Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

1. Guidance

2. 
Amendment

3. 
Amendment + 
Guidance

4. Legislation

5. Legislation 
+ Guidance

Qual

MH

 Possible - high                    -                      -                      -                       1                     1 

Qual

HH

 No 

                  -                      -                      -                       1                     1 

Qual

LL

 Possible - low 

                   1                    -                       1                     1                     1 

Quant

LL

 Possible - high                     1                     1                     1                     1                     1 

Quant

LL

 No 

                  -                      -                      -                       1                     1 

Qual

LL

MM

MM

 No 

 No 

                  -                      -                      -                       1                     1 

                   1                    -                       1                    -                       1 

 Possible - low 

                  -                      -                      -                       1                     1 

Well inspection, maintenance and monitoring to 
ensure integrity on a regular basis (e.g. 3 
yearly).  Reports would be prepared and 
submitted to competent authority by operators.  
Duration will be until licence surrender.  
Programme would include:
- mechanical integrity testing (MIT)
- determination of any necessary maintenance
- submission of reports
- implementation of remedial actions as 
necessary

Following a period of monitoring [minimum 20 
years] after well/pad closure and subsequent 
site reinstatement, the site licence is 
surrendered and the ownership and liability of 
the wells is transferred to the appropriate 
competent authority in MSs.

Following transfer, the competent authority 
takes on responsibility and liability for any 
resultant environmental damage linked to the 
well.
Operators would be required to publicly 
disclose baseline, ongoing monitoring and well 
integrity information through  website 
establishment and maintenance and collation 
of information.  Applies to baseline information 
through to transfer of responsibility to 
Competent Authority.
Note aspects of public acceptance linked to 
chemicals are on the chemicals tab.  The focus 
here is on wider public engagement.

0

0

Also relevant to underground potentially

Quant

Note aspects of public acceptance linked to 
chemicals are on the chemicals tab.  The focus 
here is on wider public engagement.

Quant

0

0

0

0

0

0

0

0

0

0

0

Qual

MM

 No 

                   1                    -                       1                     1                     1 

Qual

MM

 No 

                  -                      -                      -                      -                      -   

Quant

LL

 No 

                   1                    -                       1                     1                     1 

Qual

Qual

Qual

Qual

Qual

Quant

Qual

LL

LL

LM

LM

LM

LM

LM

 No 

 No 

 No 

 No 

 No 

                  -                       1                     1                     1                     1 

                  -                      -                      -                      -                      -   

                   1                    -                       1                    -                       1 

                   1                    -                       1                    -                       1 

                  -                      -                      -                       1                     1 

 Possible - high                     1                    -                       1                     1                     1 

 No 

                  -                      -                      -                       1                     1 

Qual

LM

 No 

                  -                      -                      -                      -                      -   

35229 MASTER Measures (20150127) TOIL 20150206.xlsx

Measures in Policy Options

10 of  13

Categorisation

Measure info

Tight Oil

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

N21

ecolog
y
permit N15

N21

N15

vs. 
HIGH
        -    Implement precautions to prevent invasive species by cleaning vehicles 0

178

179

        -    Mandatory EIA for all projects expected to involve hydraulic fracturing, 

0

before exploration starts

permit N16

N16 i

180

        -    Mandatory EIA (i) after initial phase of well exploration and before first 

test fracturing, and (ii) before production commences

permit N16

N16 ii

181

        -    Mandatory EIA (i) after initial phase of well exploration and before first 

test fracturing, and (ii) before production commences

Mandatory EIA according to Directive 2011/92/EU 
after well exploration and before first test 
fracturing
Mandatory EIA according to Directive 2011/92/EU 
before production commences

permit N17

N17

182

        -    Assessment of whether full project is likely to have significant effects on 

0

Other 
Measures

inciden
t

N08

N08a

183

Other 
Measures

inciden
t

N08

N08b

184

the environment during prospecting phase (i.e. extending the existing 
requirement in relation to deep drillings under the EIA Directive to 
include screening prior to development of exploration plans/prospecting 
and taking account of the entire project)

        -    In the case of an incident/accident significantly affecting the 

environment: (a) operator informs competent authority immediately; (b) 
competent authority provides details of the circumstances of the incident 
and effects on the environment to a designated body at EU level who will 
make non-confidential information available to the public

        -    In the case of an incident/accident significantly affecting the 

environment: (a) operator informs competent authority immediately; (b) 
competent authority provides details of the circumstances of the incident 
and effects on the environment to a designated body at EU level who will 
make non-confidential information available to the public

In the case of an incident/accident significantly 
affecting the environment, operator to inform 
competent authority immediately.

In the case of an incident/accident significantly 
affecting the environment, competent authority to 
provide details of the circumstances of the 
incident and effects on the environment to a 
designated body at EU level who will make non-
confidential information available to the public.
0

trans

59b

59b

185

        -    Transport management plan (including consideration of available road, 

trans

60c

60c

186

        -    Site selection close to water sources to minimise haulage requirements 0

rail, waterway infrastructure)

trans

61b

61b i

187

        -    Minimise resources demands and hence traffic movements through (i) 

trans

61b

61b ii

188

        -    Minimise resources demands and hence traffic movements through (i) 

trans

61c

61c

189

        -    Site selection close to wastewater treatment / disposal facilities to 

water management plans and (ii) wastewater management plans

water management plans and (ii) wastewater management plans

i) water management plans to minimise water 
demands and hence traffic movements. 
ii) wastewater management plans to minimise 
water demands and hence traffic movements. 
0

inciden
t

noi

noi

noi

noi

noi

noi

N09

N09

190

        -    Operator to develop and maintain a contingency plan to address 

minimise haulage requirements

51a

51a

191

foreseeable impacts of operating conditions on environmental risk 
management (e.g. degradation of well barriers, casing/cementing as per 
measure 22)

        -    Maximum noise levels specified

51c

51c

192

        -    Noise screening installation: (i) screen drilling and fracturing rigs with 

noise barrier / enclosure; (ii) acoustic fencing around the site perimeter.

51d

51d

193

        -    Operational hours specified

51e

51e

194

        -    Vehicle routes specified

51f

51f

195

        -    Machinery orientation and selection to minimise noise

3a

3a viii

196

        -    Site baseline

Undertake noise study

noi

3b

3b viii

197

        -    Monitoring

Undertake monitoring of noise

monito
r

guidan
ce
inspect
ion

N27

N27

198

        -    Member States carry out strategic monitoring of unconventional gas 

activities at the level of the gas play to assess overall impacts and 
reaction as necessary

N30

N30

N31

N31

199

200

        -    The European Commission to develop further criteria/guidance for the 
assessment of environmental impacts from unconventional gas
        -    Inspections by Competent Authorities during all stages of development 

(e.g. of well completion reports and environmental risk management and 
controls)

0

0

0

0

0

0

0

0

0

0

0

skills N32

N32

201

        -    Competent Authorities have available sufficient inspection capacity and 

0

inspect
ion
ecolog
y

N33

N33

202

        -    Independent inspection during all stages of development of well integrity 0

appropriately skilled inspectors

N37

N37

203

        -    Pad construction activities staged to reduce soil erosion and to coincide 

0

with low rainfall periods

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

Qual

Quant

Quant

ML

ML

ML

 No 

 No 

 No 

1. Guidance

3. 
Amendment + 
Guidance
                  -                      -                      -                      -                      -   

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

                   1                     1                     1                    -                       1 

                  -                      -                      -                       1                     1 

Quant

ML

 No 

                  -                      -                      -                       1                     1 

Quant

ML

 No 

                  -                      -                      -                      -                      -   

Qual

ML

 Possible - high                    -                      -                      -                       1                     1 

Qual

ML

 No 

                  -                      -                      -                      -                      -   

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

 Possible - high                     1                    -                       1                    -                       1 

 No 

 No 

 No 

 No 

                  -                      -                      -                      -                      -   

                   1                    -                       1                     1                     1 

                   1                    -                       1                     1                     1 

                  -                      -                      -                      -                      -   

 Possible - low 

                   1                    -                       1                     1                     1 

 Possible - high                    -                      -                      -                      -                      -   

 Possible - high                     1                    -                       1                    -                       1 

 Possible - low 

                   1                    -                       1                    -                       1 

 Possible - high                     1                    -                       1                    -                       1 

 Possible - low 

                   1                    -                       1                    -                       1 

 Possible - low 

                   1                    -                       1                    -                       1 

 Possible - low 

                   1                    -                       1                    -                       1 

 No 

 No 

                   1                    -                       1                     1                     1 

                  -                      -                      -                      -                      -   

 Possible - high                     1                    -                       1                     1                     1 

 No 

 No 

 No 

                  -                      -                      -                       1                     1 

                  -                      -                      -                       1                     1 

                  -                      -                      -                       1                     1 

0

0

0

0

0

0

0

0

0

0

0

0

0

0

Screen drilling and fracturing rigs with noise 
barrier/enclosure.

Acoustic fencing around the site perimeter.
(Noise abatement)

(Noise abatement)

(Noise abatement)

Quant

Qual

Qual

Qual

Qual

Quant

Qual

Quant

Qual

Qual

Qual

Consult with relevant regulatory authority and 
carry out baseline noise monitoring

Quant

0

0

0

0

0

0

0

Quant

Quant

Quant

Quant

Qual

Qual

Qual

Other 
Measures
Other 
Measures
Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures

Other 
Measures
Other 
Measures

Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures

Other 
Measures
Other 
Measures

Other 
Measures
Other 
Measures

Other 
Measures
Other 
Measures
Other 
Measures

35229 MASTER Measures (20150127) TOIL 20150206.xlsx

Measures in Policy Options

11 of  13

Categorisation

Measure info

Tight Oil

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Other 
Measures

3a

baselin
e

3a iv

204

vs. 
HIGH
        -    Site baseline

Obtain data on drinking water abstraction points (wells, boreholes and 
springs)

Other 
Measures

monito
r

3a

3a v

205

        -    Site baseline

Undertake land condition (soil) survey around pad

0

0

trans

3a

3a vii

206

L

Site baseline
Undertake transport and traffic study.

trans

3a

3a vii

207

H

Site baseline
Undertake transport and traffic study.

ecolog
y

3a

3a ix

208

        -    Site baseline

Undertake survey of biodiversity and ecology survey

LOW AMBITION
Undertake transport and traffic study.  Liaise with 
highway authority and identify relevant routes 
to/from well pad
HIGH AMBITION
Undertake transport and traffic study.  As per 
LOW plus traffic survey and traffic modelling
Assumed to be Middle Ambition

3a

baselin
e

3a

baselin
e

3a xii

209

L

Site baseline
Undertake assessment of landuse, infrastructure and buildings

3a xii

210

H

Site baseline
Undertake assessment of landuse, infrastructure and buildings

LOW AMBITION. Undertake assessment of 
landuse, infrastructure and buildings through desk 
study
HIGH AMBITION.  As LOW plus remote (aerial) 
survey of land, land uses, structures etc.

3b

3b iv

211

        -    Monitoring 

Undertake monitoring of drinking water abstraction points (wells, 
boreholes, springs, surface water)

3b

3b v

212

        -    Monitoring

trans

3b

3b vii

213

Undertake land condition (soil) tests every five years outside site 
boundary
        -    Monitoring

Undertake monitoring of traffic numbers and patterns

3b xi

214

        -    Monitoring

3b xii

215

        -    Monitoring

Undertake monitoring of energy source and use

Undertake monitoring of greenhouse gas emissions

3b xvi

216

        -    Monitoring

Assumed to be Middle Ambition

Undertake periodic surveys of biodiversity, ecology and invasive species

0

0

0

0

0

0

0

0

0

0

0

0

0

3b xix

217

        -    Monitoring

7

218

        -    Cumulative effects (e.g. air pollution, traffic impacts, water resource 

Undertake monitoring of spills volume, nature, location and clean-up 
(including reporting)

permit N02

N02

219

permit N06

N06

220

sea

N13

N13

221

equip N18

N18

222

requirements) of gas play development assessed in planning and 
permitting taking into account other (non-unconventional gas) 
developments and plans

        -    Operator, as part of permit conditions, obtains independent evaluation of 

environmental risk management measures for gas concession before 
fracturing commences and at regular intervals thereafter
        -    Operations to be subject to an integrated permit from the national 

authority, setting measures to manage environmental impacts for all 
environmental media (air surface/ground water, land). Combined 
monitoring and inspection regimes where separate competent 
authorities exist

        -    Member States carry out SEA to set up plans/programmes setting the 

framework for unconventional gas projects before granting concessions 
for unconventional gas exploration and production and assess 
environmental effects of such plans. Assessment to address surface 
aspects such as water abstraction, waste treatment and disposal, 
transport, air quality, landtake, species diversity as well as known 
underground risks. Assessment to be reviewed before production 
commences on the basis of information obtained during the exploration 
phase. Those MS that have already granted concessions to perform 
such an assessment without undue delay.

        -    Ensure equipment is compatible with composition of fracturing 

chemicals

equip N19

N19

223

        -    Carry out thorough planning and testing of equipment prior to hydraulic 

manag
ement

N20

N20

224

        -    Environmental management system accreditation for unconventional 

fracturing operations

gas installation operators

monito
r

monito
r

3b

3b

3b

monito
r
monito
r
ecolog
y

3b

inciden
t

7

cumul
ative

Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures
Other 
Measures
Other 
Measures

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

1. Guidance

2. 
Amendment

3. 
Amendment + 
Guidance

4. Legislation

5. Legislation 
+ Guidance

Quant

MM

 Possible - high                     1                    -                       1                     1                     1 

Quant

MM

 Possible - high                     1                    -                       1                     1                     1 

Quant

MM

 Possible - high                     1                    -                       1                    -                       1 

Quant

MM

 Possible - low 

                   1                    -                       1                    -                       1 

Quant

MM

 Possible - low 

                   1                    -                       1                     1                     1 

Quant

MM

 Possible - high                     1                    -                       1                    -                       1 

Develop list of wells, boreholes, springs, 
surface water abstraction points within area 
(from public data).
List names and depth of all potentially affected 
(by UG) underground sources of drinking water
Provide geochemical information and 
maps/cross section on subsurface aquifers.
Obtain water quality data and water gas content 
from existing available data.

Trial pits and analyse for total petroleum 
hydrocarbons, polyaromatic hydrocarbon, 
metals suite, pH, sulphate, asbestos, chloride.

0

0

Scope will vary depending on presence of 
protected species and notable habitats and 
whether a designated site.
Desk study

0

Quant

MM

 No 

                   1                    -                       1                    -                       1 

Obtain water quality data and water gas content 
from existing available data.  Ongoing 
monitoring. Annual desk study using data from 
abstraction points.
Analyse for total petroleum hydrocarbons, 
polyaromatic hydrocarbon, metals suite, pH, 
sulphate, chloride).
Traffic count site/system to provide weekly or 
monthly counts.
0

0

Scope and frequency will vary depending on 
presence of protected species and notable 
habitats and whether a designated site.  
Invasive species mitigation plan if required.
0

Quant

MM

 Possible - high                     1                    -                       1                     1                     1 

Quant

MM

 No 

                   1                    -                       1                    -                       1 

Quant

Quant

Quant

Quant

MM

MM

MM

MM

 Possible - low 

                   1                    -                       1                    -                       1 

 No 

 No 

                   1                    -                       1                    -                       1 

                  -                      -                      -                       1                     1 

 Possible - low 

                   1                    -                       1                    -                       1 

Quant

MM

 Possible - high                     1                    -                       1                     1                     1 

Complimentary with other measures associated 
with planning.

Qual

MM

 No 

                  -                      -                      -                       1                     1 

Linked to SEA
0

Qual

MM

 No 

                  -                      -                      -                       1                     1 

0

0

0

0

0

Quant

MM

 No 

                   1                     1                     1                     1                     1 

Quant

MM

 No 

                  -                      -                      -                       1                     1 

Qual

Qual

Quant

MM

MM

MM

 Possible - high                     1                    -                       1                    -                       1 

 Possible - high                     1                    -                       1                    -                       1 

 No 

                   1                    -                       1                    -                       1 

35229 MASTER Measures (20150127) TOIL 20150206.xlsx

Measures in Policy Options

12 of  13

Categorisation

Measure info

Tight Oil

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Other 
Measures

materi
als

30e

30e

225

vs. 
HIGH
        -    Muds restricted to approved list with known properties/safety data or non-

Restrict muds to approved list

toxic drilling muds

30e

30e

226

        -    Muds restricted to approved list with known properties/safety data or non-

Restrict muds to non-toxic drilling muds

29e

29e

227

        -    Site reinstatement plan

toxic drilling muds

Other 
Measures
Other 
Measures

Other 
Measures

materi
als
manag
ement

9b

inciden
t

Other 
Measures

9a

inciden
t

9a

229

trans

60a

60a

230

Other 
Measures
Other 
Measures

Other 
Measures

9b

228

        -    Emergency response plan developed and put in place covering:

- leaks from the well to groundwater or surface water
- releases of flammable gases from the well or pipelines
- fires and floods
- leaks and spillage of chemicals, flowback or produced water
- releases during transportation

        -    Consideration of major hazards for all stages in the life cycle of the 

development (early design, through operations to post abandonment) 
and development of HSE case or similar demonstrating adequacy of the 
design, operations and HSE management (including emergency 
response) for both safety and environmental major impacts

        -    Use of temporary surface pipes for distribution of water supply

trans

60b

60b

231

        -    Use of temporary surface pipes for collection of flowback

trans

61a

61a

232

        -    Use of temporary surface pipes for collection of produced water

0

0

0

0

0

0

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

Qual

MH

 No 

1. Guidance

3. 
Amendment + 
Guidance
                  -                      -                      -                      -                      -   

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

Qual

Quant

HH

MH

 No 

 Yes 

                   1                     1                     1                    -                       1 

                   1                    -                       1                     1                     1 

Qual

HM

 Yes 

                  -                       1                     1                     1                     1 

Specify the use of muds from an approved list 
to minimise the risk of harmful (polluting) mud 
production which could result in polluting spills

Specify the use of water-based muds/non-toxic 
chemical additives
Purpose of measure is to develop a 
reinstatement plan for the site following well 
closure and abandonment.
0

0

Qual

HH

 Possible - high                     1                     1                     1                     1                     1 

Temporary pipes laid above ground to supply 
water to pads.

Qual

Qual

HH

HH

 No 

 No 

                  -                      -                      -                      -                      -   

                  -                      -                      -                      -                      -   

Temporary pipes laid above ground to collect 
flowback and transport to treatment plant.
Temporary pipes  laid above ground to collect 
produced water and transport to treatment 
plant.

Qual

HH

 No 

                  -                      -                      -                      -                      -   

35229 MASTER Measures (20150127) TOIL 20150206.xlsx

Measures in Policy Options

13 of  13

Non-BAU Measures in Policy Options

Categorisation

Measure info

Coalbed Methane

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Zoning

N/A

42b

42b

Zoning

N/A

N48

N48

Zoning

Zoning

N/A

N/A

26c

40c

26c

40c

Zoning

N/A

2f

Zoning

N/A

2f

Zoning

N/A

2f

Zoning

N/A

2f

Zoning

N/A

2f

2f

2f

2f

2f

2f

1

2

3

4

5

6

7

8

9

vs. 
HIGH
        -    Location of sites close to existing pipeline infrastructure

        -    Minimum distance between hydraulic fracture pipes and geological 

strata containing aquifers and the surface to be determined based on 
risk assessment

        -    Fracturing to be a minimum distance from water resources

        -    High land, agricultural and ecological value locations avoided

0

0

0

0

        -    Buffer zones from abstraction points, aquifers, residential areas, 

schools, hospitals, abandoned wells, active & abandoned mines and 
other potential pathways for fluid migration, and other sensitive areas

        -    Buffer zones from abstraction points, aquifers, residential areas, 

schools, hospitals, abandoned wells, active & abandoned mines and 
other potential pathways for fluid migration, and other sensitive areas

        -    Buffer zones from abstraction points, aquifers, residential areas, 

schools, hospitals, abandoned wells, active & abandoned mines and 
other potential pathways for fluid migration, and other sensitive areas

        -    Buffer zones from abstraction points, aquifers, residential areas, 

schools, hospitals, abandoned wells, active & abandoned mines and 
other potential pathways for fluid migration, and other sensitive areas

        -    Buffer zones from abstraction points, aquifers, residential areas, 

schools, hospitals, abandoned wells, active & abandoned mines and 
other potential pathways for fluid migration, and other sensitive areas

Buffer zone from abstraction points and aquifers 
of 1,000m for drinking water related abstraction

Buffer zone from residential areas, schools 
hospitals and other sensitive areas of 1,600m

Buffer zone within which detailed noise 
assessment is required of 305m

Buffer zone from abandoned wells and other 
potential pathways for fluid migration (distance 
specified on risk basis)
Additional containment for sites near surface 
water supply locations

Zoning

N/A

40a

40a

10

        -    Optimisation from an environmental perspective, i.e. the number of 

0

wells, pad density and pad spacing

Zoning

N/A

40b

40b

11

        -    Compatibility with current and future potential landuse (Natura 2000 

0

sites, conservation sites, human use, industrial use, appropriate zoning, 
CCS, geothermal, water abstraction)

Zoning

N/A

1b

1b

12

        -    Restrict operations within and underneath specified sites (e.g. Natura 

0

2000, protected sites, coal mining areas, drinking water protection areas, 
water extraction areas for public drinking water supply, mineral spa 
protection zones karstic aquifers, flood prone zones and mineral water 
reserves, reforestation areas and areas known to be unfavourable - with 
regard to potential environmental impacts) or within certain distances to 
specified sites

        -    Avoid high seismicity risk areas

0

        -    Minimum distance between hydraulic fracture pipes and geological 

strata containing aquifers (e.g. 600m) and the surface (e.g. 600m depth 
requires special permit)

Zoning

Zoning

N/A

N/A

55e

55i

55e

55i

13

14

Zoning

N/A

55i

55i

15

        -    Minimum distance between hydraulic fracture pipes and geological 

strata containing aquifers (e.g. 600m) and the surface (e.g. 600m depth 
requires special permit)

Minimum distance between hydraulic fracture 
pipes and geological strata containing aquifers of, 
e.g. 600m
Special permit conditions where hydraulic fracture 
pipes are less than, e.g. 600m depth from surface

0

0

Site selection takes into consideration existing 
gas pipeline infrastructure to enable 
minimisation of the need for additional pipeline 
infrastructure and associated development 
impacts.
0

0

Assessment of and avoidance of high land, 
agricultural and ecological value locations (e.g.  
Natura 2000 sites, conservation sites).
Applicable regardless of area type (i.e. not 
limited to Natura 2000 site and other specified 
sites).  Hence applicability is broader.
0

0

0

This is required for sites within 800m of water 
supply locations in Colorado.  The definition of 
additional containment is not provided - 
assume bunded tanks/site - see other 
measures re. this in surface water
Optimise the number of wells per pad, pad 
density and pad spacing to minimise 
cumulative environmental impacts (e.g. one 
pad per 2.6 km2 proposed by New York State).  
This will include consideration of siting with 
consideration of conflicts with nearby or 
adjacent sensitive land uses such as 
residences, schools, hospitals, available 
transport infrastructure, access to water supply, 
access to wastewater treatment, etc.

Note: the acquis communautaire requires this 
measure, but it is uncertain whether it is 
adequately implemented by Member States. 
Assessment of compatibility with current and 
future landuse plans (e.g. Natura 2000 sites, 
conservation sites, human use, industrial use, 
appropriate zoning.

Note: the acquis communautaire requires this 
measure, notably as a mitigation measure 
under the SEAD/the EIAD, but without 
guarantee of the result, Natura2000 Directives 
excepted. 
Operations would be restricted (i.e. greater 
controls as required by discretion of MS 
authorities) within specified areas. 

Areas known to be unfavourable - with regard 
to potential environmental impacts - geological 
and hydrogeological conditions (groundwater 
potentials and pathways, tectonically fractured 
rocks, artesian confined aquifers, suspected 
pathways introduced by abandoned boreholes 
or mining activities)
0

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

Qual

LL

 No 

1. Guidance

3. 
Amendment + 
Guidance
                   1                    -                       1                    -                       1 

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

Qual

MM

 No 

                   1                    -                       1                    -                       1 

Qual

Qual

MM

MM

 No 

 No 

                   1                    -                       1                    -                       1 

                   1                    -                       1                    -                       1 

Qual

MM

 No 

                   1                    -                       1                    -                       1 

Qual

MM

 No 

                   1                    -                       1                    -                       1 

Qual

MM

 No 

                   1                    -                       1                    -                       1 

Qual

MM

 No 

                   1                    -                       1                    -                       1 

Qual

MM

 No 

                   1                    -                       1                    -                       1 

Qual

HM

 No 

                   1                    -                       1                    -                       1 

Qual

HM

 No 

                   1                    -                       1                    -                       1 

Qual

HM

 Yes 

                   1                    -                       1                    -                       1 

Qual

Qual

HH

HH

 No 

 No 

                   1                    -                       1                    -                       1 

                   1                    -                       1                    -                       1 

Qual

HH

 No 

                   1                    -                       1                    -                       1 

35229 MASTER Measures (20150127) CBM 20150206.xlsx

Measures in Policy Options

1 of  13

Categorisation

Measure info

Coalbed Methane

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Zoning

N/A

1a

1a

16

vs. 
HIGH
        -    Prohibit operations within and underneath specified sites (e.g. Natura 

0

2000, protected sites, coal mining areas, drinking water protection areas, 
water extraction areas for public drinking water supply, mineral spa 
protection zones karstic aquifers, flood prone zones and mineral water 
reserves, reforestation areas and areas known to be unfavourable - with 
regard to potential environmental impacts) or within certain distances to 
specified sites

        -    Competent authorities compile regional maps of underground resources 0

Areas known to be unfavourable - with regard 
to potential environmental impacts - geological 
and hydrogeological conditions (groundwater 
potentials and pathways, tectonically fractured 
rocks, artesian confined aquifers, suspected 
pathways introduced by abandoned boreholes 
or mining activities)
0

Underground 
Risks
Underground 
Risks

Underground 
Risks
Underground 
Risks

Underground 
Risks

Underground 
Risks
Underground 
Risks

N/A

N44

N44

N/A

N55

N55

N/A

28d

28d

N/A

N45

N45

17

18

19

20

        -    Conduct 2D seismic survey to identify faults and fractures.

        -    Sharing of information to ensure that all operators in a gas play are 

aware of risks and can therefore plan

        -    Members States establish a capability to address groundwater 

contamination arising from unconventional gas operations. In the case of 
transboundary aquifers, joint capability established

0

0

0

0

0

0

0

0

N/A

55g

55g

21

        -    Engagement with third parties (e.g. regulators, other operators, 

N/A

22d

22d

N/A

26d

26d i

22

23

 L 

researchers) to ensure fully aware of any issues / proximity (e.g. to other 
underground activities)

        -    Search for and document potential leakage pathways (e.g. other wells, 

0

Through delivery of 3 a x detail

Related to 3a x-a4 (which is Low Ambition)

Through delivery of 3 a x detail

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

Qual

HH

 Yes 

1. Guidance

3. 
Amendment + 
Guidance
                   1                    -                       1                    -                       1 

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

Qual

Quant

Qual

Qual

LL

LM

LM

LM

 No 

 Yes 

                   1                    -                       1                    -                       1 

                   1                     1                     1                     1                     1 

 Possible - low 

                   1                     1                     1                     1                     1 

 No 

                   1                    -                       1                    -                       1 

Qual

ML

 Possible - low 

                   1                    -                       1                    -                       1 

Quant

Quant

MM

MM

 Possible - high                     1                     1                     1                     1                     1 

 No 

                  -                      -                      -                      -                      -   

faults, mines)
i) Development of a conceptual model of the zone before work 
commences covering geology, groundwater flows, pathways, 
microseismicity and subsequent updating of the model as information 
becomes available ii) as above plus Modelling of the impact of 
groundwater pumping on linked groundwater and surface water flows 
and quality

        -    i) Development of a conceptual model of the zone before work 

commences covering geology, groundwater flows, pathways, 
microseismicity and subsequent updating of the model as information 
becomes available ii) as above plus Modelling of the impact of 
groundwater pumping on linked groundwater and surface water flows 
and quality

Underground 
Risks

N/A

26d

26d ii

24

As 26d I +
Modelling of the impact of groundwater pumping 
on linked groundwater and surface water flows 
and quality

Through delivery of 3 a x detail

Quant

MM

 No 

                   1                     1                     1                     1                     1 

Underground 
Risks

Underground 
Risks
Underground 
Risks
Underground 
Risks

Underground 
Risks
Underground 
Risks

Underground 
Risks
Underground 
Risks

N/A

26e

26e

25

        -    Modelling of fracturing programme to predict extent of fracture growth 

0

based on best information

N/A

26g

26g

N/A

55c

55c

N/A

N09

N09

N/A

N05

N05

N/A

N46

N46

N/A

N07

N07

N/A

55h

55h

26

27

28

29

30

31

32

        -    Implementation of remedial measures if well failure occurs

        -    Ground motion prediction models to assess the potential impact of 

induced earthquakes

        -    Operator to develop and maintain a contingency plan to address 

foreseeable impacts of operating conditions on environmental risk 
management (e.g. degradation of well barriers, casing/cementing as per 
measure 22)

        -    Initiate immediate flowback post fracturing

        -    The European Commission develops criteria/guidance for underground 

risk assessment (such as criteria to assess potential risks of 
groundwater contamination and induced seismicity) related to 
unconventional gas

        -    Operator to use alternative fracturing fluids to water (e.g. nitrogen, CO2, 

propane)

        -    Smaller preinjection prior to main operations to enable induced 

seismicity response to be assessed

0

0

0

0

0

0

0

Quant

MM

 No 

                   1                    -                       1                     1                     1 

MM

MM

MM

MM

MH

MH

MH

 Yes 

 No 

 No 

 No 

 No 

 No 

 No 

                   1                     1                     1                     1                     1 

                  -                      -                      -                      -                      -   

                  -                      -                      -                       1                     1 

                   1                     1                     1                    -                       1 

                  -                      -                      -                      -                      -   

                  -                      -                      -                      -                      -   

                   1                    -                       1                    -                       1 

Application of Discrete Fracture Network (DFN) 
approach including dynamic response (e.g. 
hydro-shearing), Finite Element Analysis (FEA) 
or Discrete Element Method (DEM). 3D fracture 
modelling integrated with geomechanics 
modelling.
0

0

0

0

0

0

Qual

Quant

Quant

Qual

Qual

Qual

Qual

Mini-fractures area carried out prior to full scale 
fracturing.  Monitoring of the seismic response 
to the mini-fractures is carried out and 
assessment of the location's actual response 
compared with the modelled response is made.  
Analysis of results and conclusion drawn 
regarding suitability of and approach to full 
scale operations.  Enables model predictions to 
be verified and the actual response of 
geological formations to be assessed.

35229 MASTER Measures (20150127) CBM 20150206.xlsx

Measures in Policy Options

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Categorisation

Measure info

Coalbed Methane

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

0

Measures to be split out for cost purposes

Quant

HH

 Yes 

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

1. Guidance

3. 
Amendment + 
Guidance
                  -                       1                     1                     1                     1 

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

Underground 
Risks

N/A

22a

22a

33

Underground 
Risks

N/A

22b

22b i

34

vs. 
HIGH
        -    Key elements to maintain well safety such as:

• blowout preventers
• pressure & temperature monitoring and shutdown systems
• fire and gas detection
• continuous monitoring for leaks and release of gas and liquids
• modelling to aid well/HF design
• isolate underground source of drinking water prior to drilling
• ensure micro-annulus is not formed
• casing centralizers to centre casing in hole
• select corrosive resistant alloys and high strength steel
• fish back casing
• maintain appropriate bending radius
• triple casing
• casing and cementing designed to sustain high pressure and low 
magnitude seismicity
• isolation of the well from aquifers
• casings: minimum distance the surface casing extends below aquifer 
(e.g. 30m below the deepest underground source of drinking water 
encountered while drilling the well, ref. Environment Agency 2012) and 
surface casing cemented before reaching depth of e.g. 75m below 
underground drinking water (ref. AEA 2012). Production casing 
cemented up to at least 150 metres above the formation where hydraulic 

        -    Integrity testing at key stages in well development e.g. 

before/during/after all HF events, including:
i) wireline logging (calliper, cement bond, variable density)
ii) pressure (between 2.1 and 8.3 MPa based on setting times between 4 
and 72 hours)/hydrostatic testing
iii) mechanical integrity testing of equipment (MIT)
iv) casing inspection test and log

i) wireline logging (calliper, cement bond, variable 
density)

0

Quant

HH

 Yes 

                  -                       1                     1                     1                     1 

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

N/A

22b

22b ii

35

        -    Integrity testing at key stages in well development e.g. 

before/during/after all HF events, including:
i) wireline logging (calliper, cement bond, variable density)
ii) pressure (between 2.1 and 8.3 MPa based on setting times between 4 
and 72 hours)/hydrostatic testing
iii) mechanical integrity testing of equipment (MIT)
iv) casing inspection test and log

ii) pressure (between 2.1 and 8.3 MPa based on 
setting times between 4 and 72 hours)/hydrostatic 
testing

0

Quant

HH

 Yes 

                  -                       1                     1                     1                     1 

N/A

22b

22b iii

36

        -    Integrity testing at key stages in well development e.g. 

iii) mechanical integrity testing of equipment (MIT) 0

Quant

HH

 Yes 

                  -                       1                     1                     1                     1 

before/during/after all HF events, including:
i) wireline logging (calliper, cement bond, variable density)
ii) pressure (between 2.1 and 8.3 MPa based on setting times between 4 
and 72 hours)/hydrostatic testing
iii) mechanical integrity testing of equipment (MIT)
iv) casing inspection test and log

N/A

22b

22b iv

37

        -    Integrity testing at key stages in well development e.g. 

iv) casing inspection test and log

before/during/after all HF events, including:
i) wireline logging (calliper, cement bond, variable density)
ii) pressure (between 2.1 and 8.3 MPa based on setting times between 4 
and 72 hours)/hydrostatic testing
iii) mechanical integrity testing of equipment (MIT)
iv) casing inspection test and log

N/A

22c

22c

38

        -    Multiple barriers between the target formation and people/the 

N/A

26f

26f

39

N/A

3a

3a xi

40

environment, including minimum vertical distance between target 
formation and aquifers

        -    Monitoring and control during operations to ensure hydraulic fractures / 
pollutants do not extend beyond the gas-producing formations and does 
not result in seismic events or damage to buildings/installations that 
could be the result of fracturing

        -    Site baseline

0

0

0

N/A

55d

55d

41

L

Establish the presence of methane in groundwater, including drinking 
water
Microseismicity monitoring and management requirements during 
operations

N/A

55d

55d

42

        -    Microseismicity monitoring and management requirements during 

operations

LOW AMBITION
Real time monitoring of microseismicity during all 
operations
HIGH AMBITION
AS LOW plus cessation of fracturing if specified 
induced seismic activity is detected (using traffic 
light system)

0

0

Quant

HH

 Yes 

                  -                       1                     1                     1                     1 

Qual

HH

 No 

                   1                     1                     1                    -                       1 

Linked to 3 b xvii

Quant

HH

 No 

                   1                     1                     1                     1                     1 

0

Quant

MM

 Yes 

                   1                     1                     1                     1                     1 

Linked to 3 b xvii

Quant

MM

 No 

                  -                       1                     1                     1                     1 

0

Qual

HH

 No 

                   1                     1                     1                     1                     1 

35229 MASTER Measures (20150127) CBM 20150206.xlsx

Measures in Policy Options

3 of  13

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

Quant

MM

 Yes 

1. Guidance

3. 
Amendment + 
Guidance
                  -                      -                      -                      -                      -   

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

Quant

HH

 Possible - low 

                   1                     1                     1                     1                     1 

Quant

HH

 No 

                   1                     1                     1                     1                     1 

Quant

MH

 Yes 

                  -                      -                      -                      -                      -   

Quant

HH

 No 

                   1                     1                     1                     1                     1 

Quant

HH

 No 

                   1                     1                     1                     1                     1 

Quant

MH

 No 

                   1                     1                     1                     1                     1 

Quant

HH

 No 

                  -                      -                      -                      -                      -   

Quant

HH

 Possible - low 

                   1                     1                     1                     1                     1 

Quant

HH

 Possible - low 

                   1                     1                     1                     1                     1 

Quant

HH

 Possible - high                     1                     1                     1                     1                     1 

Categorisation

Measure info

Coalbed Methane

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Underground 
Risks

N/A

3a

3a iii

43

vs. 
HIGH
L

Site baseline
Undertake sampling of groundwater

Underground 
Risks

N/A

3a

3a iii

44

H

Site baseline
Undertake sampling of groundwater

MEDIUM AMBITION
Sampling of shallow groundwater during wet and 
dry periods (cost is shown in Middle Ambition 
column)

HIGH AMIBITION
Borehole to sample deep groundwater and 
characterise the hydrological series (cost is 
shown in High Ambition column)

Concentrate boreholes near pad (as on 
impacts on groundwater due to surface spills 
greatest near pad).  Boreholes, at 15m depth at 
each corner.  Analyse for dissolved oxygen, pH, 
ammonia, chloride, total petroleum 
hydrocarbons and polyaromatic hydrocarbons, 
fracturing additive chemicals, isotopic 
fingerprinting (include methane, ethane, 
propane), radioactivity and heavy metals.

Deep boreholes in area.  Analyse for dissolved 
oxygen, pH, ammonia, chloride, total petroleum 
hydrocarbons and polyaromatic hydrocarbons, 
fracturing additive chemicals, isotopic 
fingerprinting (include methane, ethane, 
propane), radioactivity and heavy metals.

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

Underground 
Risks

N/A

3a

3a x-a1

45

        -    Site baseline

0

N/A

3a

3a x-a2

46

L

N/A

3a

3a x-a2

47

H

Geological, hydrogeological and seismic conceptual model
[1] Obtain and analyze seismic (earthquake) history.
Site baseline
Geological, hydrogeological and seismic conceptual model
[2] Obtain geomechanical information on fractures, stress, rock strength, 
in situ fluid pressures
Site baseline
Geological, hydrogeological and seismic conceptual model
[2] Obtain geomechanical information on fractures, stress, rock strength, 
in situ fluid pressures

N/A

3a

3a x-a3

48

N/A

3a

3a x-a4

49

N/A

3a

3a x-a4

50

N/A

3a

3a x-a5

51

        -    Site baseline

L

Geological, hydrogeological and seismic conceptual model
[3] Undertake surface microseismic survey
Site baseline
Geological, hydrogeological and seismic conceptual model
[4] Undertake complex modelling of fluid flows and migration (reservoir 
simulations) 
Site baseline
Geological, hydrogeological and seismic conceptual model
[4] Undertake complex modelling of fluid flows and migration (reservoir 
simulations) 
        -    Site baseline

H

N/A

3a

3a x-a6

52

 H 

Geological, hydrogeological and seismic conceptual model
[5] Develop maps and cross sections of local geologic structure
Site baseline
Geological, hydrogeological and seismic conceptual model
[6] Conduct 3D seismic survey to identify faults and fractures

N/A

3a

3a x-a7

53

        -    Site baseline

N/A

3a

3a xiii

54

N/A

3a

3a xiii

55

L

H

Geological, hydrogeological and seismic conceptual model
[7] Obtain data on area, thickness, capacity, porosity and permeability of 
formations.
Site baseline
Undertake assessment of existing underground wells and structures

Site baseline
Undertake assessment of existing underground wells and structures

Underground 
Risks

N/A

3b

3b iii

56

L

Monitoring
Undertake monitoring of groundwater

LOW AMBITION. Undertake desk study based on 
existing data and literature

HIGH AMBITION. In addition LOW obtain 
geomechanical information on fractures, stress, 
rock strength, in situ fluid pressures through new 
cores and stratigraphic tests.
0

LOW AMBITION. Modelling over 100 years

HIGH AMBITION. Modelling is done over 10,000 
years

0

0

0

0

0

0

0

0

0

0

0

0

HIGH AMBITION.  As LOW AMBITION plus 
undertake assessment of underground wells and 
structures desk study to evaluate integrity of 
construction and record of completion and/or 
plugging of existing shallow wells
MEDIUM AMBITION
Sampling of shallow groundwater during wet and 
dry periods

Underground 
Risks

N/A

3b

3b iii

57

H

Monitoring
Undertake monitoring of groundwater

HIGH AMBITION
Deep groundwater sampling network to determine 
the characteristics of deep groundwater and 
formation water and piezometric levels

Underground 
Risks
Underground 
Risks

N/A

N/A

3b

3b

3b xvii

58

        -    Monitoring

3b xviii

59

        -    Monitoring

Undertake monitoring of induced seismicity from fracturing

0

0

Undertake monitoring for presence of methane seepages in 
groundwater, including drinking water.

LOW AMBITION.  Undertake assessment of 
underground wells and structures

Develop list of penetrations into zone within 
area (from well history databases).

Quant

MH

 Possible - high                    -                      -                      -                      -                      -   

0

Quant

HH

 No 

                   1                     1                     1                     1                     1 

Concentrate boreholes near pad (as on 
impacts on groundwater due to surface spills 
greatest near pad).  Boreholes, at 15m depth at 
each corner.  Analyse for dissolved oxygen, pH, 
ammonia, chloride, total petroleum 
hydrocarbons and polyaromatic hydrocarbons, 
fracturing additive chemicals, isotopic 
fingerprinting (include methane, ethane, 
propane), radioactivity and heavy metals.

Deep boreholes network in area. Analyse for 
dissolved oxygen, pH, ammonia, chloride, total 
petroleum hydrocarbons and polyaromatic 
hydrocarbons, fracturing additive chemicals, 
isotopic fingerprinting (include methane, 
ethane, propane), radioactivity and heavy 
metals.
0

0

Quant

MM

 Yes 

                  -                      -                      -                      -                      -   

Quant

HH

 No 

                   1                     1                     1                     1                     1 

Quant

Quant

HH

HH

 No 

                   1                     1                     1                     1                     1 

 Possible - low 

                  -                      -                      -                      -                      -   

35229 MASTER Measures (20150127) CBM 20150206.xlsx

Measures in Policy Options

4 of  13

Categorisation

Measure info

Coalbed Methane

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Chemical Use N/A

CSL5 CSL5

60

Chemical Use N/A

N24

N24

Chemical Use N/A

CAL1 CAL1

Chemical Use N/A

CAL2 CAL2

61

62

63

vs. 
HIGH
        -    Authorities to organise an exchange of views/information on 

environmentally safer technologies and alternatives to the use of 
chemicals in hydraulic fracturing

        -    Traceability of chemicals used by an operator

0

0

        -    CSA/risk assessment explicitly specific to hydraulic fracturing in the EU 

Chemicals - assessment

to be included in REACH Registration

        -    Develop a peer-reviewed EU-level exposure scenario / SpERC for HF for 

Chemicals - assessment

different chemical types

Chemical Use N/A

CAL3 CAL3

64

        -    CAL2 to be implemented in CSAs for chemicals used in HF and any 

Chemicals - assessment

deviations explained

Chemical Use N/A

CDL1 CDL1

65

        -    Disclosure of information to Competent Authority: declaration of 
substance name and CAS number for the chemical substances 
potentially to be used in hydraulic fracturing. Per concession/play

Chemicals - disclosure

Chemical Use N/A

CDL2 CDL2

66

        -    Disclosure of information to the public: list of chemicals potentially to be 

Chemicals - disclosure

used in hydraulic fracturing by UG company to be made available (e.g. 
via company website or centralised data dissemination portal). Per 
concession/play

Chemical Use N/A

CSL1a CSL1a

67

        -    Non-use of any (non-biocidal) substances with [harmonised or notified] 

Chemicals - selection

Chemical Use N/A

CSL1b CSL1b

68

Chemical Use N/A

CSL1c CSL1c

69

Chemical Use N/A

CSL1d CSL1d

70

classification as CMR (carcinogenic, mutagenic or toxic for reproduction) 
category 1A or 1B

        -    Non-use in biocidal products of any substances with [harmonised or 
notified] classification as CMR (carcinogenic, mutagenic or toxic for 
reproduction) category 1A or 1B

        -    Non-use of any (non-biocidal) substances with [harmonised or notified] 
classification as aquatic acute category 1 or aquatic chronic category 1

        -    Non-use in biocidal products of any substances with [harmonised or 
notified] classification as aquatic acute category 1 or aquatic chronic 
category 1

Chemicals - selection

Chemicals - selection

Chemicals - selection

Chemical Use N/A

CSL2 CSL2

71

        -    Non-use of any substances on REACH Candidate List for authorisation 

Chemicals - selection

(substances of very high concern)

Chemical Use N/A

CSL3 CSL3

72

        -    Negative list of named substances that must not be used in UG 
extraction (alternative to two measures CSL1 and CSL2)

Chemicals - selection

Chemical Use N/A

CSL4 CSL4

73

        -    Demonstration that all steps practicable have been taken to reduce 

Chemicals - selection

number, concentration and volume of chemicals used in hydraulic 
fracturing

0

0

Cost to be estimated based on existing data in 
#11.
Estimated cost of developing SpERC to similar 
level of detail to those that already exist for e.g. 
additives used in petroleum products 
(CONCAWE/ESIG)  
http://www.cefic.org/Industry-
support/Implementing-reach/Guidances-and-
Tools1/
Should be feasible to estimate additional cost 
of UG company doing their own CSA for this 
specific use for typical number of chemicals 
used.
Is in principle possible to quantify but not 
considered proportionate to do this given costs 
of this are likely to be small and main costs are 
likely to arise due to other implications (e.g. 
Reduced options for chemical use due to 
greater scrutiny potentially leading to reduced 
productivity).
Is in principle possible to quantify but not 
considered proportionate to do this given costs 
of this are likely to be small and main costs are 
likely to arise due to other implications (e.g. 
Reduced options for chemical use due to 
greater scrutiny potentially leading to reduced 
productivity).
0

0

0

0

Too many substances potentially used in HF to 
robustly estimate differences in costs.  Impacts 
on well productivity will far outweigh differences 
in prices of fluid additives.
Partially quantitative.  Potential to cost actually 
developing the list but costs of not using 
substances on that list not quantifiable as per 
measures above.  
Not considered feasible to quantify costs as too 
site-specific.

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

Qual

LL

 No 

Qual

Quant

Quant

LL

ML

ML

 No 

 No 

 No 

1. Guidance

3. 
Amendment + 
Guidance
                   1                    -                       1                    -                       1 

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

                  -                      -                      -                      -                      -   

                  -                      -                      -                      -                      -   

                   1                    -                       1                    -                       1 

Quant

ML

 No 

                   1                    -                       1                    -                       1 

Qual

ML

 No 

                   1                    -                       1                     1                     1 

Qual

ML

 Possible - high                     1                    -                       1                     1                     1 

Qual

LM

 No 

                   1                     1                     1                     1                     1 

Qual

LM

 No 

                   1                     1                     1                     1                     1 

Qual

LM

 No 

                   1                     1                     1                     1                     1 

Qual

LM

 No 

                   1                     1                     1                     1                     1 

Qual

LM

 No 

                   1                     1                     1                     1                     1 

Quant

LM

 No 

                   1                     1                     1                     1                     1 

Qual

ML

 No 

                   1                     1                     1                     1                     1 

Chemical Use N/A

CSM4 CSM4

74

        -    Establish general principles for the use of chemicals (minimise use, 

Chemicals - selection

0

Qual

LM

 No 

                   1                     1                     1                     1                     1 

Chemical Use N/A

CAM1 CAM1

75

Chemical Use N/A

CSM2 CSM2

76

substitution by less hazardous substances), oblige operator to present 
and discuss alternative substances and establish third party verification. 

        -    Chemical safety assessment / biocide risk assessment includes 
assessment of risks of potential transformation products in HF / 
underground context, as part of permit/licence, with risk management 
measures implemented accordingly

        -    Positive list of substances expected to be safe under EU UG extraction 
conditions and require operators to only use substances on this positive 
list

Chemicals - selection

Chemical Use N/A

CSM3 CSM3

77

        -    Selection of substances (chemicals and proppants) that minimise the 

Chemicals - selection

need for treatment when present in flowback water

Chemical Use N/A

3b

3b x

78

        -    Monitoring

0

Chemical Use N/A

CSM1
a

CSM1a

79

        -    Non-use of any (non-biocidal) substances with [harmonised or notified] 

Chemicals - selection

Undertake monitoring of chemicals type and volume used including 
record keeping

classification as CMR (carcinogenic, mutagenic or toxic for reproduction) 
category 1A, 1B or 2

Chemicals - assessment

Could be e.g. 2-3 times cost for standard CSA / 
risk assessment?

Quant

MM

 No 

                  -                      -                      -                      -                      -   

Partially quantitative.  Potential to cost actually 
developing the list but costs of only using 
substances on that list not quantifiable as per 
measures above.
Not considered feasible to quantify costs as 
insufficient data on which substances (from a 
very large list) require more/less treatment 
under different circumstances.
0

Non-use of any (non-biocidal) substances with 
[harmonised or notified] classification as CMR 
(carcinogenic, mutagenic or toxic for 
reproduction) category 1A, 1B or 2

Quant

MM

 No 

                   1                     1                     1                     1                     1 

Qual

MM

 No 

                   1                     1                     1                     1                     1 

Quant

MM

 Possible - low 

                   1                    -                       1                     1                     1 

Qual

LH

 No 

                   1                     1                     1                     1                     1 

35229 MASTER Measures (20150127) CBM 20150206.xlsx

Measures in Policy Options

5 of  13

Categorisation

Measure info

Coalbed Methane

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Chemical Use N/A

CSM1b

80

CSM1
b

vs. 
HIGH
        -    Non-use in biocidal products of any substances with [harmonised or 
notified] classification as CMR (carcinogenic, mutagenic or toxic for 
reproduction) category 1A, 1B or 2

Chemicals - selection

Chemical Use N/A

Chemical Use N/A

CSM1
c

CSM1
d

CSM1c

81

        -    Non-use of any (non-biocidal) substances with [harmonised or notified] 
classification as aquatic acute category 1 or 2 or aquatic chronic 
category 1 or 2

Chemicals - selection

CSM1d

82

        -    Non-use in biocidal products of any substances with [harmonised or 

Chemicals - selection

notified] classification as aquatic acute category 1 or 2 or aquatic chronic 
category 1 or 2

Chemical Use N/A

CDM1 CDM1

83

        -    Disclosure of information to Competent Authority: declaration of 

Chemicals - disclosure

Chemical Use N/A

CDM2 CDM2

84

substance name, CAS number, precise concentrations, quantities and 
all physicochemical and (eco)toxicological data for the substances 
potentially to be used in hydraulic fracturing. Also potentially e.g. date of 
fracturing, total volume of fluids, type and amount of proppant; 
description of the precise additive purpose; concentration in the total 
volume. Per well. Prior to and after operations

        -    Disclosure of information to public: list of chemicals and CAS numbers 

used to be made available (e.g. via company website and centralised 
data dissemination portal) for the chemicals potentially to be used in 
hydraulic fracturing. Per concession/play. Prior to and after operations

Chemicals - disclosure

Chemical Use N/A

N26

N26

Chemical Use N/A

CAH1 CAH1

85

86

        -    Select proppants which minimise the HVHF treatment required

0

        -    Chemical safety assessment / biocide risk assessment includes 

Chemicals - assessment

Chemical Use N/A

CDH1 CDH1

87

assessment of risks of mixtures of chemicals used in HF as part of 
permit/licence, with risk management measures implemented 
accordingly. To include potential additive or synergistic impacts

        -    Disclosure of information to public: details of substance name, CAS 

Chemicals - disclosure

number, concentrations, and all physicochemical and (eco)toxicological 
data for the substances potentially to be used in hydraulic fracturing. 
This is to be made available (e.g. via company website and centralised 
data dissemination portal). Also potentially e.g. date of fracturing, total 
volume of fluids, type and amount of proppant; description of the overall 
purpose of the additives; concentration in the total volume. Per well. 
Prior to and after operations

88

89

90

        -    Non-use of any (non-biocidal) substances with [harmonised or notified] 

Chemicals - selection

classification for any health or environmental effects

        -    Non-use in biocidal products of any substances with [harmonised or 
notified] classification for any health or environmental effects

Chemicals - selection

        -    Use of water or inert materials only in hydraulic fracturing

Chemicals - selection

Chemical Use N/A

Chemical Use N/A

Chemical Use N/A

CSH2a

CSH2
a
CSH2
b
CSH1 CSH1

CSH2b

Water 
Depletion

Water 
Depletion

Water 
Depletion

Water 
Depletion
Water 
Depletion
Water 
Depletion

N/A

38a

38a i

91

        -    i) Notification of water demand from fracturing operations to relevant 

water utilities and competent authorities

N/A

38a

38a ii

92

        -    ii) Notification of water demand from fracturing operations to relevant 

water utilities and competent authorities - high ambition (CBM only)

N/A

38b

38b

93

        -    Demand profile for water

N/A

N49

N49

N/A

38c

38c

N/A

3a

3a vi

94

95

96

        -    Strategic planning and staged approach of play development to avoid 

peaks in water demand

        -    Water management plan

        -    Site baseline

Establish water source availability and test for suitability

0

0

0

0

0

0

Non-use in biocidal products of any substances 
with [harmonised or notified] classification as 
CMR (carcinogenic, mutagenic or toxic for 
reproduction) category 1A, 1B or 2

Non-use of any (non-biocidal) substances with 
[harmonised or notified] classification as 
aquatic acute category 1 or 2 or aquatic chronic 
category 1 or 2
Non-use in biocidal products of any substances 
with [harmonised or notified] classification as 
aquatic acute category 1 or 2 or aquatic chronic 
category 1 or 2
Is in principle possible to quantify but not 
considered proportionate to do this given costs 
of this are likely to be small and main costs are 
likely to arise due to other implications (e.g. 
Reduced options for chemical use due to 
greater scrutiny potentially leading to reduced 
productivity).
Is in principle possible to quantify but not 
considered proportionate to do this given costs 
of this are likely to be small and main costs are 
likely to arise due to other implications (e.g. 
Reduced options for chemical use due to 
greater scrutiny potentially leading to reduced 
productivity).
0

Scientifically challenging and not likely to be 
possible to quantify with any degree of 
certainty.

Is in principle possible to quantify but not 
considered proportionate to do this given costs 
of this are likely to be small and main costs are 
likely to arise due to other implications (e.g. 
Reduced options for chemical use due to 
greater scrutiny potentially leading to reduced 
productivity).

0

0

 Not thought to be practicable and likely to 
have significant impact on viability and 
productivity of UG extraction. Not considered 
practical to quantify costs - main impact will be 
on well productivity, maintenance frequency, 
etc.
Inform relevant authorities (i.e. water utilities, 
environmental regulators, planning authorities) 
of water demand for the lifetime of the project.
Inform relevant authorities (i.e. water utilities, 
environmental regulators, planning authorities) 
of water demand for the lifetime of the project 
(linked to fracturing) and submit groundwater 
pumping plans to relevant authorities to enable 
impacts of groundwater pumping to be 
understood on areas that are also used for 
groundwater resources.

Establish the water demand pattern taking 
account of number of wells, pad locations, 
drilling sequence, water consumption per unit 
operation.  Establish flow patterns including 
peak and average flow volumes under a variety 
of scenarios.
0

Develop a water management plan to cover 
water supply and efficient use on site.
Locate water sources and identifying 
availability, water rights. Test water sources for 
suitability

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

Qual

LH

 No 

1. Guidance

3. 
Amendment + 
Guidance
                   1                     1                     1                     1                     1 

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

Qual

LH

 No 

                   1                     1                     1                     1                     1 

Qual

LH

 No 

                   1                     1                     1                     1                     1 

Qual

HL

 Possible - high                     1                    -                       1                     1                     1 

Qual

HL

 No 

                   1                    -                       1                     1                     1 

Qual

Qual

MH

HM

 No 

 No 

                   1                     1                     1                     1                     1 

                  -                      -                      -                      -                      -   

Qual

HM

 Possible - low 

                   1                    -                       1                     1                     1 

Qual

Qual

Qual

MH

MH

HH

 No 

 No 

 No 

                   1                     1                     1                     1                     1 

                   1                     1                     1                     1                     1 

                   1                     1                     1                     1                     1 

Qual

LM

 No 

                   1                     1                     1                     1                     1 

Qual

LM

 No 

                   1                     1                     1                     1                     1 

Quant

LM

 Possible - high                     1                    -                       1                    -                       1 

Qual

Qual

Quant

MM

MM

MM

 No 

                   1                    -                       1                    -                       1 

 Possible - high                     1                    -                       1                    -                       1 

 Possible - high                     1                    -                       1                    -                       1 

35229 MASTER Measures (20150127) CBM 20150206.xlsx

Measures in Policy Options

6 of  13

Categorisation

Measure info

Coalbed Methane

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Water 
Depletion
Water 
Depletion
Water 
Depletion
Water 
Depletion

N/A

N/A

3b

3b

3b vi

3b ix

N/A

38d

38d

97

98

99

vs. 
HIGH
        -    Monitoring

Water resources availability

        -    Monitoring

Undertake monitoring of water volumes and origin

        -    Reuse of flowback and produced water for fracturing

N/A

38e

38e

100

        -    Use of lower quality water for fracturing (e.g. non-potable ground / 

surface water, rainwater harvesting, saline aquifers, sea water, treated 
industrial waterwaters)

Surface Water N/A

33i

33i

101

        -    Good site security

0

0

0

0

0

Surface Water N/A

29a

29a

102

        -    Good practice construction / deconstruction practices, including design 

0

for well abandonment

Surface Water N/A

Surface Water N/A

33a

33d

33a

33d

103

104

        -    Good site practice to prevention of leaks and spills

        -    Spill kits available for use

0

0

Surface Water N/A

3a

3a ii

105

 H 

Site baseline
Undertake sampling of surface water bodies in wet and dry periods

High Ambition 

Surface Water N/A

3b

3b ii

106

L

Monitoring
Undertake monitoring of surface water bodies in wet and dry periods

LOW AMBITION
Monitoring
Undertake monitoring of surface water bodies in 
wet and dry periods

0

0

Reuse flowback and/or produced water to 
make up fracture fluid.
Use lower quality water (non-potable) to make 
up fracture fluid.

Operators would be required to ensure that the 
site is protected properly to prevent vandalism 
that may lead to pollution from damaged 
equipment/infrastructure.
Note - also included in post closure ref. 
demolition.

Operators should apply construction industry 
good practice to prevent pollution of surface 
water through operator training and approach 
to construction practice.
0

0

Analyse for suspended solids, BOD, dissolved 
oxygen, pH, ammonia, chloride also total 
petroleum hydrocarbons and polyaromatic 
hydrocarbons, radioactivity, fracturing 
chemicals and heavy metals  for assurance.

Analyse for suspended solids, BOD, dissolved 
oxygen, pH, ammonia, chloride also total 
petroleum hydrocarbons and polyaromatic 
hydrocarbons, radioactivity, fracturing 
chemicals and heavy metals  for assurance.

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

Quant

Quant

Quant

Qual

MM

MM

MM

MM

 No 

 No 

 No 

 No 

1. Guidance

3. 
Amendment + 
Guidance
                   1                     1                     1                     1                     1 

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

                   1                    -                       1                    -                       1 

                   1                    -                       1                     1                     1 

                   1                     1                     1                    -                       1 

Quant

ML

 Yes 

                  -                      -                      -                      -                      -   

Qual

MM

 Possible - high                     1                     1                     1                     1                     1 

Qual

Quant

MM

MM

 Yes 

 Yes 

                   1                     1                     1                     1                     1 

                   1                     1                     1                     1                     1 

Quant

MM

 Possible - low 

                   1                     1                     1                     1                     1 

Quant

MM

 Possible - high                    -                       1                     1                     1                     1 

Surface Water N/A

3b

3b ii

107

H

Monitoring
Undertake monitoring of surface water bodies in wet and dry periods

Surface Water N/A

33e

33e

108

        -    Berm around site boundary

HIGH AMBITION
AS LOW AMBITION with alert system promoting 
corrective action
0

0

0

Quant

MH

 No 

                   1                    -                       1                    -                       1 

Quant

HM

 No 

                   1                     1                     1                    -                       1 

Surface Water N/A

33g

33g

109

        -    Collection and control of surface runoff

Surface Water N/A

29c

29c

110

        -    Bunding of fuel tanks

Surface Water N/A

30d

30d

111

        -    Use of closed tanks for mud storage

Surface Water N/A

33b

33b

112

        -    Use of tank level alarms

0

0

0

0

Surface Water N/A

33c

33c

113

 H 

Use of double skinned closed storage tanks

High Ambition 

Surface Water N/A

33f

33f

114

        -    Impervious site liner under pad with puncture proof underlay

Air Quality

N/A

59d

59d

115

        -    Use of vehicles (water, chemicals, waste trucking) that meet minimum 

Air Quality

N/A

N54

N54

116

        -    Encourage industry voluntary approach to reduce air pollutants and 

air emission standards e.g. EURO standards

greenhouse gases

0

0

0

Air Quality

N/A

16b

16b i

117

        -    Low emission power supply (i) LPG or (ii) grid electricity rather than 

Low emission power supply (switching to LPG)

Air Quality

N/A

16b

16b ii

118

        -    Low emission power supply (i) LPG or (ii) grid electricity rather than 

diesel

Air Quality

N/A

16d

16d

119

        -    Application of abatement techniques to minimise emissions (assumed 

diesel

Air Quality

N/A

17c

17c

120

L

SCR for NOx and Diesel Particulate Filter (DPF) for PM).
Flares or incinerators to reduce emissions from fracturing fluid at 
exploration stage (where not connected to gas network)

Air Quality

N/A

17c

17c

121

H

Flares or incinerators to reduce emissions from fracturing fluid at 
exploration stage (where not connected to gas network)

Low emission power supply (switching to grid 
electricity)
0

LOW AMBITION
Flares or incinerators to reduce emissions from 
fracturing fluid at exploration stage
HIGH AMBITION
As LOW AMBITION with no audible or visible 
flaring

Operators construct sites to effectively collect 
and control stormwater, e.g. draining to a single 
collection point, to enable effective control and 
management of any spills and leaks.

0

0

For chemicals, fracturing fluid, muds and 
wastewaters.  Activation triggers corrective 
action/contingency plan implementation.
For chemicals, fracturing fluid, muds and 
wastewaters

0

0

0

0

0

SCR for NOx
Diesel Particulate Filter (DPF) for PM
Capture gas from fracture fluid at exploration 
stage and flare or incinerate 

Quant

MH

 Possible - high                     1                    -                       1                     1                     1 

Quant

HH

 No 

                   1                    -                       1                    -                       1 

Quant

HH

 Possible - low 

                  -                      -                      -                      -                      -   

Quant

HH

 Possible - high                     1                     1                     1                     1                     1 

Quant

HH

 No 

                   1                     1                     1                     1                     1 

Quant

HH

 Yes 

                   1                    -                       1                     1                     1 

Qual

Qual

Quant

Quant

Quant

LL

LM

LM

LM

LM

 No 

 No 

 No 

 No 

 No 

                  -                      -                      -                      -                      -   

                   1                    -                       1                    -                       1 

                   1                    -                       1                    -                       1 

                   1                    -                       1                    -                       1 

                   1                    -                       1                    -                       1 

Quant

MM

 Yes 

                  -                      -                      -                      -                      -   

0

Quant

MM

 No 

                  -                      -                      -                      -                      -   

35229 MASTER Measures (20150127) CBM 20150206.xlsx

Measures in Policy Options

7 of  13

Categorisation

Measure info

Coalbed Methane

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Air Quality

N/A

3a

3a i

122

vs. 
HIGH
        -    Site baseline

Undertake sampling of air quality

Air Quality

N/A

3b

3b i

123

        -    Monitoring

Undertake monitoring of air quality

Air Quality

N/A

16a

16a

124

        -    Preparation of an emissions reduction plan (reduced emission 

completions) including an assessment of potential local air quality 
impacts including implications for compliance with ambient air quality 
limit values

0

0

0

Air Quality

N/A

17b

17b

125

        -    Reduced emission completions (REC) to eliminate gas venting: prohibit 

0

venting of gas; capture and cleaning for use of gas released from 
fracture fluid and produced water

Waste

Waste

Waste

Waste

Waste

N/A

N47

N47

126

        -    Operator demonstrates availability of appropriate wastewater treatment 

N/A

36c

36c

127

        -    Treatment requirements for wastewater and capability of treatment 

works to treat wastewater established

facilities

0

0

N/A

27c

27cii

128

        -    Injection of flowback and produced water into designated formations for 

Untreated wastewater

N/A

N/A

N50

27c

N50

27c i

129

130

disposal, provided specific conditions are in place:
i) treated waste water and
ii) untreated wastewater

        -    Lined open ponds with safety net protecting biodiversity

0

        -    Injection of flowback and produced water into designated formations for 

Treated wastewater

Waste

N/A

3b

3b xiii

131

disposal, provided specific conditions are in place:
i) treated waste water and
ii) untreated wastewater

        -    Monitoring

Undertake monitoring of drilling mud volumes and treatment

Waste

N/A

3b

3b xiv

132

        -    Monitoring

Undertake monitoring of flowback water return rate and characterise

Waste

N/A

3b

3b xv

133

        -    Monitoring

Undertake monitoring (volume and characterisation) of produced water 
volume and treatment solution

0

0

0

Waste

Waste

Waste

Waste

Waste

N/A

N53

N53

134

        -    Consider wastewaters from unconventional gas operations as hazardous 

0

N/A

27f

27f

135

waste

        -    Operators keep records of all waste management operations and make 
them available for inspection (e.g. of flowback, produced water 
management)

N/A

N51

N51

136

        -    Consider wastewaters hazardous unless operator demonstrates 

N/A

N/A

N52

30c

N52

30c

137

138

        -    Ban injection of wastewaters into geological formations for disposal

        -    Use of closed loop system to contain drilling mud

otherwise

Post Closure

Post Closure

N/A

N/A

N22

N11

N22

N11

141

142

        -    Maintain records of well location and depth indefinitely

        -    Operator to provide financial guarantee to competent authority to cover 
costs of any remedial action following transfer of responsibility

Post Closure

N/A

N12

N12

143

        -    Operator to provide a financial contribution to the competent authority 

Post Closure

N/A

26g

26g

144

following closure and abandonment. This contribution should be 
sufficient to cover ongoing monitoring and related activities over a 
sufficient period [assume minimum of 20 years)

        -    Implementation of remedial measures if well failure occurs

0

0

0

0

0

0

0

0

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

1. Guidance

2. 
Amendment

3. 
Amendment + 
Guidance

4. Legislation

5. Legislation 
+ Guidance

Quant

MM

 Possible - high                     1                     1                     1                     1                     1 

Quant

MM

 Possible - low 

                   1                     1                     1                     1                     1 

Quant

MH

 No 

                   1                     1                     1                     1                     1 

Quant

HH

 No 

                   1                     1                     1                     1                     1 

Qual

Qual

Qual

Qual

Qual

LL

LL

LL

ML

MM

 No 

                   1                    -                       1                     1                     1 

 Possible - high                     1                     1                     1                     1                     1 

 Possible - high                    -                       1                     1                     1                     1 

 No 

                   1                     1                     1                     1                     1 

 Possible - high                    -                       1                     1                     1                     1 

Quant

MM

 No 

                   1                     1                     1                     1                     1 

Quant

MM

 Possible - high                     1                     1                     1                     1                     1 

Quant

MM

 Possible - high                     1                     1                     1                     1                     1 

Qual

Qual

Qual

Qual

Quant

MM

LH

MH

MH

HH

 No 

 No 

 No 

 No 

                  -                      -                      -                      -                      -   

                   1                     1                     1                     1                     1 

                   1                    -                       1                    -                       1 

                  -                      -                      -                      -                      -   

 Possible - high                     1                     1                     1                    -                       1 

Qual

Qual

LL

LM

 Yes 

 No 

                   1                     1                     1                     1                     1 

                  -                      -                      -                       1                     1 

Qual

ML

 No 

                  -                      -                      -                       1                     1 

Three month monitoring period to establish 
baseline using passive monitoring techniques 
at circa six points in the vicinity of a pad.  
Monitoring for combustion gasses (NOx, NO2, 
PM10 and also SO2, CO and VOCs).
On-going monitoring in the vicinity of a pad.  
Monitoring for combustion gasses (NOx, NO2, 
PM10 and also SO2, CO and VOCs).
Plan preparation only
Develop emissions inventory for the site
Undertake dispersion modelling of inventory to 
estimate concentrations within site boundaries 
and surrounding areas
Undertake additional modelling of potential 
impacts of emissions from site on nearby 
population and/or sensitive habitats
Identify and assess options for reducing 
emissions
Capture and cleaning for use of gas released 
from fracture fluid and produced water

0

0

0

0

0

Analyse for VOCs, metals, total petroleum 
hydrocarbons, NORM.

Analyse for oil & grease, BTEX, VOCs, SVOCs, 
TDS, pH, sulphates, H2S, heavy metals, 
NORM, biocides, emulsion breakers, corrosion 
inhibitors. 
Analyse for oil & grease, BTEX, VOCs, SVOCs, 
TDS, pH, sulphates, H2S, heavy metals, 
NORM, biocides, emulsion breakers, corrosion 
inhibitors. 
0

0

0

0

Closed-loop systems employ a suite of solids 
control equipment to minimise drilling fluid 
dilution and provide the economic handling of 
the drilling wastes. The closed loop system can 
include a series of linear-motion shakers, mud 
cleaners and centrifuges followed by a 
dewatering system. The combination of 
equipment typically results in a "dry" location 
where a reserve pit is not required, used fluids 
are recycled, and solid wastes can be land 
farmed, hauled off or injected down-hole.
0

Required following transfer of responsibility as 
prior to that point in time, the operator remains 
responsible for remedial action.
0

Note - measure also listed under 'Underground 
risks'

Qual

MM

 Possible - high                     1                     1                     1                     1                     1 

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Categorisation

Measure info

Coalbed Methane

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Post Closure

N/A

29a

29a

145

vs. 
HIGH
        -    Good practice construction / deconstruction practices, including design 

for well abandonment

Post Closure

N/A

N10

N10

146

        -    Operator remain responsible for monitoring, reporting and corrective 

Post Closure

N/A

13d

13d ii

147

measures following well closure (or temporary well abandonment) and 
prior to transfer of responsibility to competent authority [assume 
minimum of 20 years]
        -    Abandonment survey

Undertake sampling of surface water bodies near the pad

0

0

0

Post Closure

N/A

13d

13d iii

148

 H 

Abandonment survey
Undertake sampling of groundwater near the pad

High Ambition

Post Closure

N/A

13d

13d iv

149

        -    Abandonment survey

Obtain data on drinking water abstraction points (wells, boreholes, 
springs, surface water abstraction points

Post Closure

N/A

13d

13d v

150

        -    Abandonment survey

Undertake land condition (soil) survey around pad

0

0

Post Closure

N/A

13d

13d vi

151

        -    Abandonment survey

Assumed to be Middle Ambition

Undertake survey of biodiversity, ecology and invasive species survey

Post Closure

N/A

13d

13d vii

152

        -    Abandonment survey

0

Note - also included in surface water ref. 
construction.

Operators should apply construction industry 
good practice to prevent pollution of surface 
water through operator training and approach 
to construction practice.
Transfer of responsibility to occur 

Surface water
Sampling of surface water courses near the 
pad and analyse for suspended solids, BOD, 
dissolved oxygen, pH, ammonia, chloride also 
total petroleum hydrocarbons and polyaromatic 
hydrocarbons, radioactivity, fracturing 
chemicals and heavy metals  for assurance.

Groundwater
Sampling of monitoring boreholes and analyse 
for dissolved oxygen, pH, ammonia, chloride, 
total petroleum hydrocarbons and polyaromatic 
hydrocarbons, fracturing additive chemicals, 
isotopic fingerprinting (include methane, 
ethane, propane), radioactivity and heavy 
metals.
Drinking water abstraction points
Obtain water quality data and water gas content 
from water abstraction points in the operational 
area (e.g. regarding dissolved oxygen, pH, 
ammonia, chloride, total petroleum 
hydrocarbons and polyaromatic hydrocarbons, 
fracturing additive chemicals, isotopic 
fingerprinting (include methane, ethane, 
propane), radioactivity and heavy metals)

Land condition (soil)
Establish land condition in immediate are of the 
pad and analyse for analyse for total petroleum 
hydrocarbons, polyaromatic hydrocarbon, 
metals suite, pH, sulphate, asbestos, chloride

Scope will vary depending on presence of 
protected species and notable habitats and 
whether a designated site.
0

Post Closure

N/A

13d

13d viii

153

L

Undertake sampling for methane near surface in the pad location
Abandonment survey
Undertake assessment of landuse, infrastructure and buildings

Post Closure

N/A

13d

13d viii

154

H

Abandonment survey
Undertake assessment of landuse, infrastructure and buildings

Post Closure

N/A

13d

13d ix

155

L

Abandonment survey
Undertake assessment of ex-anti underground wells and structures 

Post Closure

N/A

13d

13d ix

156

H

Abandonment survey
Undertake assessment of ex-anti underground wells and structures 

LOW
Undertake assessment of landuse, infrastructure 
and buildings through desk study

LOW AMBITION. Desk study and mapping of 
landuse, infrastructure and buildings.  Objective 
is to enable comparison with baseline 
assessment and consequently any impacts.

HIGH
Undertake assessment of landuse, infrastructure 
and buildings survey through desk study and 
aerial survey

HIGH AMBITION. As above plus remote (aerial) 
survey of land, land uses, structures etc.   
Objective is to enable comparison with baseline 
assessment and consequently any impacts.

LOW
Undertake assessment of underground wells and 
structures through desk study

HIGH
Undertake assessment of underground wells and 
structures desk study to evaluate integrity of 
construction and record of completion and/or 
plugging of existing shallow wells

LOW AMBITION.  Check baseline list of 
penetrations into zone within area (from well 
history databases).  Relates to wells and 
structures in place prior to UG activities.
HIGH AMBITION. As per LOW above plus: 
desk study to evaluate integrity of construction 
and record of completion and/or plugging of 
existing shallow wells.  Relates to wells and 
structures in place prior to UG activities.

Post Closure

N/A

12

12

157

        -    Specific post closure risk assessment, well plugging, inspection and 

0

monitoring requirements (e.g. for releases to air, well integrity, periodicity 
of inspections, wellhead monitoring every 90 days)

Measure includes:
Flush wells with a buffer fluid before plugging
Plug wells. Use two cement plugs: one in 
producing formation and one for surface to 
bottom of drinking water level, fill the remainder 
with mud.
Perform a mechanical integrity test prior to 
plugging to evaluate integrity of casing and 
cement to remain in ground.

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

1. Guidance

2. 
Amendment

3. 
Amendment + 
Guidance

4. Legislation

5. Legislation 
+ Guidance

Qual

MM

 Possible - high                    -                       1                     1                     1                     1 

Qual

MM

 No 

                  -                      -                      -                       1                     1 

Quant

MM

 Possible - high                     1                    -                       1                     1                     1 

Quant

MM

 Possible - high                     1                    -                       1                     1                     1 

Quant

MM

 Possible - high                     1                    -                       1                     1                     1 

Quant

MM

 Possible - high                     1                    -                       1                     1                     1 

Quant

LL

 No 

                   1                    -                       1                    -                       1 

Quant

MM

Quant

LL

 No 

 No 

                   1                    -                       1                     1                     1 

                  -                      -                      -                      -                      -   

Quant

MM

 No 

                   1                    -                       1                    -                       1 

Quant

LL

 Possible - high                    -                      -                      -                       1                     1 

Quant

MM

 No 

                  -                      -                      -                      -                      -   

Quant

HH

 Possible - high                     1                     1                     1                     1                     1 

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Categorisation

Measure info

Coalbed Methane

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Post Closure

N/A

13b

13b i

158

vs. 
HIGH
        -    Specific post closure well inspection, maintenance and 

monitoring/reporting programme (i) following detection of possible 
pollution (low ambition); (ii) periodic inspection and monitoring (high 
ambition)

Post closure well inspection, maintenance and 
monitoring/reporting programme - following 
detection of possible pollution (low ambition)

Post Closure

N/A

13b

13b ii

159

        -    Specific post closure well inspection, maintenance and 

monitoring/reporting programme (i) following detection of possible 
pollution (low ambition); (ii) periodic inspection and monitoring (high 
ambition)

Post closure well inspection, maintenance and 
monitoring/reporting programme - periodic 
inspection and monitoring (high ambition)

Post Closure

N/A

13c

13c

160

        -    Ownership and liability of wells transferred to a competent authority on 

0

surrender of the site licence following a period of monitoring

Public 
Acceptance

N/A

N23

N23

161

        -    Public disclosure by operators of environmental monitoring (baseline, 

0

operational and post closure), resource use (water use and chemicals), 
production, incidents (e.g. pollution events, well failure) and well integrity 
information 

Public 
Acceptance

N/A

15

15i

162

L

Public consultation and engagement by operators: (i) at all stages (pre-
permitting, permitting, exploration, testing, production and 
abandonment); (ii) for permitting

LOW AMBITION.
Engagement at permitting (website, information, 
public meetings) and abandonment and 
relinquishing of permits.  (website and 
information).  

Public 
Acceptance

Public 
Acceptance
Public 
Acceptance
Public 
Acceptance

Public 
Acceptance

Public 
Acceptance

Other 
Measures

Other 
Measures
Other 
Measures

N/A

N41

N41

163

        -    Member State Competent Authorities provide information on the licences 
and permits of operators involved in unconventional gas exploration and 
production

N/A

N42

N42

164

        -    Prohibit non-disclosure agreements between local residents and/or 

N/A

N40

N40

N/A

15

15i

165

166

landowners and unconventional gas operators

 H 

        -    Member State Competent Authorities provide a map of planned and 
existing exploration, production and abandoned well locations
Public consultation and engagement by operators: (i) at all stages (pre-
permitting, permitting, exploration, testing, production and 
abandonment); (ii) for permitting

N/A

N03

N03

167

        -    All permits/authorisations/licences relating to environmental risk 

0

0

0

HIGH AMBITION.
As per low ambition PLUS the following:
Early stage consultation (initial exploration, pre-
site development and pre-permitting) consultation 
(website, information preparation, public 
meetings).  
Production stage ongoing consultation (ongoing 
website and information provision).
0

N/A

N04

N04

168

sea

N34

N34

169

management to be made available to the public and included on a 
central data repository for all unconventional gas operations in the 
Member State / EU

        -    EU institutions and/or Member States provide peer reviewed information 

to the public on a regular basis on the current state of knowledge of 
potential environmental risks and benefits from unconventional gas and 
available measures to manage those risks

        -    Public authorities produce an underground regional impact assessment 

to optimise resource allocation between unconventional gas and other 
underground resources (e.g. geothermal energy)

permit N35

N35

170

        -    Member States implement integrated permitting for unconventional gas

N/A

N25

N25

171

        -    Reversal of the burden of proof for unconventional gas operators in the 

context of liability in case of environmental damage

0

0

0

0

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

Quant/
qual

LoA 
rating

1. Guidance

2. 
Amendment

3. 
Amendment + 
Guidance

4. Legislation

5. Legislation 
+ Guidance

Qual

LH

 Possible - high                    -                      -                      -                       1                     1 

Qual

MH

 Possible - high                    -                      -                      -                       1                     1 

Qual

HH

 No 

                  -                      -                      -                       1                     1 

Qual

LL

 Possible - low 

                   1                    -                       1                     1                     1 

Quant

LL

 Possible - high                     1                     1                     1                     1                     1 

Quant

LL

 No 

                  -                      -                      -                       1                     1 

Qual

LL

MM

MM

 No 

 No 

                  -                      -                      -                       1                     1 

                   1                    -                       1                    -                       1 

 Possible - low 

                  -                      -                      -                       1                     1 

Following detection of possible pollution and 
after well closure.  Well inspection, 
maintenance and monitoring to ensure 
integrity.  Reports would be prepared and 
submitted to competent authority by operators.  
Duration will be until licence surrender.  
Programme would include:
- mechanical integrity testing (MIT)
- determination of any necessary maintenance
- submission of reports
- implementation of remedial actions as 
necessary

Well inspection, maintenance and monitoring to 
ensure integrity on a regular basis (e.g. 3 
yearly).  Reports would be prepared and 
submitted to competent authority by operators.  
Duration will be until licence surrender.  
Programme would include:
- mechanical integrity testing (MIT)
- determination of any necessary maintenance
- submission of reports
- implementation of remedial actions as 
necessary

Following a period of monitoring [minimum 20 
years] after well/pad closure and subsequent 
site reinstatement, the site licence is 
surrendered and the ownership and liability of 
the wells is transferred to the appropriate 
competent authority in MSs.

Following transfer, the competent authority 
takes on responsibility and liability for any 
resultant environmental damage linked to the 
well.
Operators would be required to publicly 
disclose baseline, ongoing monitoring and well 
integrity information through  website 
establishment and maintenance and collation 
of information.  Applies to baseline information 
through to transfer of responsibility to 
Competent Authority.
Note aspects of public acceptance linked to 
chemicals are on the chemicals tab.  The focus 
here is on wider public engagement.

0

0

Also relevant to underground potentially

Quant

Note aspects of public acceptance linked to 
chemicals are on the chemicals tab.  The focus 
here is on wider public engagement.

Quant

0

0

0

0

0

Qual

MM

 No 

                   1                    -                       1                     1                     1 

Qual

MM

 No 

                  -                      -                      -                      -                      -   

Quant

LL

 No 

                   1                    -                       1                     1                     1 

Qual

Qual

LL

LL

 No 

 No 

                  -                       1                     1                     1                     1 

                  -                      -                      -                      -                      -   

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Categorisation

Measure info

Coalbed Methane

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

N/A

N38

N38

172

vs. 
HIGH
        -    Maintain operator liability for any pollution arising from wells for a period 

N/A

N39

N39

173

        -    Maintain operator liability for any pollution arising from wells indefinitely

of 100 years

N28

N28

174

        -    Assessment by the Competent Authority of the technical and financial 

59a

59a

175

        -    Traffic impact assessment including consideration of noise, emissions 

N29

N29

176

        -    Financial guarantees by operators for environmental and civil liability 

and other relevant impacts

capacity of an operator

covering any accidents or unintended negative impacts caused by their 
own activities or those outsourced to others (to cover incidents and 
accidents during and after operations, restoration of site)

        -    Operators work together to ensure efficient provision of gas collection 

177

178

        -    Implement precautions to prevent invasive species by cleaning vehicles 0

and wastewater treatment infrastructure

179

        -    Mandatory EIA for all projects expected to involve hydraulic fracturing, 

0

before exploration starts

operat
or
trans

operat
or

N36

efficien
cy
ecolog
y
permit N15

N21

N36

N21

N15

0

0

0

0

0

0

permit N16

N16 i

180

        -    Mandatory EIA (i) after initial phase of well exploration and before first 

test fracturing, and (ii) before production commences

permit N16

N16 ii

181

        -    Mandatory EIA (i) after initial phase of well exploration and before first 

test fracturing, and (ii) before production commences

Mandatory EIA according to Directive 2011/92/EU 
after well exploration and before first test 
fracturing
Mandatory EIA according to Directive 2011/92/EU 
before production commences

permit N17

N17

182

        -    Assessment of whether full project is likely to have significant effects on 

0

Other 
Measures

inciden
t

N08

N08a

183

Other 
Measures

inciden
t

N08

N08b

184

the environment during prospecting phase (i.e. extending the existing 
requirement in relation to deep drillings under the EIA Directive to 
include screening prior to development of exploration plans/prospecting 
and taking account of the entire project)

        -    In the case of an incident/accident significantly affecting the 

environment: (a) operator informs competent authority immediately; (b) 
competent authority provides details of the circumstances of the incident 
and effects on the environment to a designated body at EU level who will 
make non-confidential information available to the public

        -    In the case of an incident/accident significantly affecting the 

environment: (a) operator informs competent authority immediately; (b) 
competent authority provides details of the circumstances of the incident 
and effects on the environment to a designated body at EU level who will 
make non-confidential information available to the public

In the case of an incident/accident significantly 
affecting the environment, operator to inform 
competent authority immediately.

In the case of an incident/accident significantly 
affecting the environment, competent authority to 
provide details of the circumstances of the 
incident and effects on the environment to a 
designated body at EU level who will make non-
confidential information available to the public.
0

trans

59b

59b

185

        -    Transport management plan (including consideration of available road, 

trans

60c

60c

186

        -    Site selection close to water sources to minimise haulage requirements 0

rail, waterway infrastructure)

trans

61b

61b i

187

        -    Minimise resources demands and hence traffic movements through (i) 

trans

61b

61b ii

188

        -    Minimise resources demands and hence traffic movements through (i) 

trans

61c

61c

189

        -    Site selection close to wastewater treatment / disposal facilities to 

water management plans and (ii) wastewater management plans

water management plans and (ii) wastewater management plans

i) water management plans to minimise water 
demands and hence traffic movements. 
ii) wastewater management plans to minimise 
water demands and hence traffic movements. 
0

inciden
t

noi

noi

noi

noi

noi

noi

N09

N09

190

        -    Operator to develop and maintain a contingency plan to address 

minimise haulage requirements

51a

51a

191

foreseeable impacts of operating conditions on environmental risk 
management (e.g. degradation of well barriers, casing/cementing as per 
measure 22)

        -    Maximum noise levels specified

51c

51c

192

        -    Noise screening installation: (i) screen drilling and fracturing rigs with 

noise barrier / enclosure; (ii) acoustic fencing around the site perimeter.

51d

51d

193

        -    Operational hours specified

51e

51e

194

        -    Vehicle routes specified

51f

51f

195

        -    Machinery orientation and selection to minimise noise

3a

3a viii

196

        -    Site baseline

Undertake noise study

noi

3b

3b viii

197

        -    Monitoring

Undertake monitoring of noise

monito
r

guidan
ce
inspect
ion

N27

N27

198

        -    Member States carry out strategic monitoring of unconventional gas 

activities at the level of the gas play to assess overall impacts and 
reaction as necessary

N30

N30

N31

N31

199

200

        -    The European Commission to develop further criteria/guidance for the 
assessment of environmental impacts from unconventional gas
        -    Inspections by Competent Authorities during all stages of development 

(e.g. of well completion reports and environmental risk management and 
controls)

0

0

0

0

0

0

0

0

0

0

0

Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures

Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures

Other 
Measures
Other 
Measures

Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures

Other 
Measures
Other 
Measures

Other 
Measures
Other 
Measures

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

1. Guidance

3. 
Amendment + 
Guidance
                   1                    -                       1                    -                       1 

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

                   1                    -                       1                    -                       1 

                  -                      -                      -                       1                     1 

 No 

 No 

 No 

 Possible - high                     1                    -                       1                     1                     1 

 No 

                  -                      -                      -                       1                     1 

 No 

 No 

 No 

 No 

                  -                      -                      -                      -                      -   

                  -                      -                      -                      -                      -   

                   1                     1                     1                    -                       1 

                  -                      -                      -                       1                     1 

Quant/
qual

LoA 
rating

Qual

Qual

Qual

Quant

Qual

Qual

Qual

Quant

Quant

LM

LM

LM

LM

LM

LM

ML

ML

ML

Quant

ML

 No 

                  -                      -                      -                       1                     1 

Quant

ML

 No 

                  -                      -                      -                      -                      -   

Qual

ML

 Possible - high                    -                      -                      -                       1                     1 

Qual

ML

 No 

                  -                      -                      -                      -                      -   

Quant

Qual

Qual

Qual

Qual

Quant

Qual

Quant

Qual

Qual

Qual

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

MM

 Possible - high                     1                    -                       1                    -                       1 

 No 

 No 

 No 

 No 

                  -                      -                      -                      -                      -   

                   1                    -                       1                     1                     1 

                   1                    -                       1                     1                     1 

                  -                      -                      -                      -                      -   

 Possible - low 

                   1                    -                       1                     1                     1 

 Possible - high                    -                      -                      -                      -                      -   

 Possible - high                     1                    -                       1                    -                       1 

 Possible - low 

                   1                    -                       1                    -                       1 

 Possible - high                     1                    -                       1                    -                       1 

 Possible - low 

                   1                    -                       1                    -                       1 

 Possible - low 

                   1                    -                       1                    -                       1 

 Possible - low 

                   1                    -                       1                    -                       1 

 No 

 No 

                   1                    -                       1                     1                     1 

                  -                      -                      -                      -                      -   

 Possible - high                     1                    -                       1                     1                     1 

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

Screen drilling and fracturing rigs with noise 
barrier/enclosure.

Acoustic fencing around the site perimeter.
(Noise abatement)

(Noise abatement)

(Noise abatement)

Consult with relevant regulatory authority and 
carry out baseline noise monitoring

Quant

0

0

0

0

Quant

Quant

Quant

Quant

35229 MASTER Measures (20150127) CBM 20150206.xlsx

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Categorisation

Measure info

Coalbed Methane

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures

inspect
ion
ecolog
y
baselin
e

skills N32

N32

201

vs. 
HIGH
        -    Competent Authorities have available sufficient inspection capacity and 

0

appropriately skilled inspectors

N33

N33

202

        -    Independent inspection during all stages of development of well integrity 0

N37

N37

203

        -    Pad construction activities staged to reduce soil erosion and to coincide 

0

3a

3a iv

204

        -    Site baseline

with low rainfall periods

Obtain data on drinking water abstraction points (wells, boreholes and 
springs)

Other 
Measures

monito
r

3a

3a v

205

        -    Site baseline

Undertake land condition (soil) survey around pad

trans

3a

3a vii

206

L

Site baseline
Undertake transport and traffic study.

trans

3a

3a vii

207

H

Site baseline
Undertake transport and traffic study.

ecolog
y

3a

3a ix

208

        -    Site baseline

Undertake survey of biodiversity and ecology survey

LOW AMBITION
Undertake transport and traffic study.  Liaise with 
highway authority and identify relevant routes 
to/from well pad
HIGH AMBITION
Undertake transport and traffic study.  As per 
LOW plus traffic survey and traffic modelling
Assumed to be Middle Ambition

3a

baselin
e

3a

baselin
e

3a xii

209

L

Site baseline
Undertake assessment of landuse, infrastructure and buildings

3a xii

210

H

Site baseline
Undertake assessment of landuse, infrastructure and buildings

LOW AMBITION. Undertake assessment of 
landuse, infrastructure and buildings through desk 
study
HIGH AMBITION.  As LOW plus remote (aerial) 
survey of land, land uses, structures etc.

3b

3b iv

211

        -    Monitoring 

Undertake monitoring of drinking water abstraction points (wells, 
boreholes, springs, surface water)

3b

3b v

212

        -    Monitoring

trans

3b

3b vii

213

Undertake land condition (soil) tests every five years outside site 
boundary
        -    Monitoring

Undertake monitoring of traffic numbers and patterns

3b xi

214

        -    Monitoring

3b xii

215

        -    Monitoring

Undertake monitoring of energy source and use

Undertake monitoring of greenhouse gas emissions

3b xvi

216

        -    Monitoring

Assumed to be Middle Ambition

Undertake periodic surveys of biodiversity, ecology and invasive species

3b xix

217

        -    Monitoring

7

218

        -    Cumulative effects (e.g. air pollution, traffic impacts, water resource 

Undertake monitoring of spills volume, nature, location and clean-up 
(including reporting)

Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures
Other 
Measures
Other 
Measures
Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures

Other 
Measures

monito
r

monito
r

3b

3b

3b

monito
r
monito
r
ecolog
y

3b

inciden
t

7

cumul
ative

permit N02

N02

219

permit N06

N06

220

sea

N13

N13

221

Other 
Measures

equip N18

N18

222

requirements) of gas play development assessed in planning and 
permitting taking into account other (non-unconventional gas) 
developments and plans

        -    Operator, as part of permit conditions, obtains independent evaluation of 

environmental risk management measures for gas concession before 
fracturing commences and at regular intervals thereafter
        -    Operations to be subject to an integrated permit from the national 

authority, setting measures to manage environmental impacts for all 
environmental media (air surface/ground water, land). Combined 
monitoring and inspection regimes where separate competent 
authorities exist

        -    Member States carry out SEA to set up plans/programmes setting the 

framework for unconventional gas projects before granting concessions 
for unconventional gas exploration and production and assess 
environmental effects of such plans. Assessment to address surface 
aspects such as water abstraction, waste treatment and disposal, 
transport, air quality, landtake, species diversity as well as known 
underground risks. Assessment to be reviewed before production 
commences on the basis of information obtained during the exploration 
phase. Those MS that have already granted concessions to perform 
such an assessment without undue delay.

        -    Ensure equipment is compatible with composition of fracturing 

chemicals

0

0

0

0

0

0

0

0

0

0

0

0

0

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

1. Guidance

3. 
Amendment + 
Guidance
                  -                      -                      -                       1                     1 

5. Legislation 
+ Guidance

2. 
Amendment

4. Legislation

                  -                      -                      -                       1                     1 

                  -                      -                      -                       1                     1 

 No 

 No 

 No 

 Possible - high                     1                    -                       1                     1                     1 

Quant/
qual

LoA 
rating

Qual

Qual

Qual

Quant

MM

MM

MM

MM

Quant

MM

 Possible - high                     1                    -                       1                     1                     1 

Quant

MM

 Possible - high                     1                    -                       1                    -                       1 

Quant

MM

 Possible - low 

                   1                    -                       1                    -                       1 

Quant

MM

 Possible - low 

                   1                    -                       1                     1                     1 

Quant

MM

 Possible - high                     1                    -                       1                    -                       1 

0

0

0

Develop list of wells, boreholes, springs, 
surface water abstraction points within area 
(from public data).
List names and depth of all potentially affected 
(by UG) underground sources of drinking water
Provide geochemical information and 
maps/cross section on subsurface aquifers.
Obtain water quality data and water gas content 
from existing available data.

Trial pits and analyse for total petroleum 
hydrocarbons, polyaromatic hydrocarbon, 
metals suite, pH, sulphate, asbestos, chloride.

0

0

Scope will vary depending on presence of 
protected species and notable habitats and 
whether a designated site.
Desk study

0

Quant

MM

 No 

                   1                    -                       1                    -                       1 

Obtain water quality data and water gas content 
from existing available data.  Ongoing 
monitoring. Annual desk study using data from 
abstraction points.
Analyse for total petroleum hydrocarbons, 
polyaromatic hydrocarbon, metals suite, pH, 
sulphate, chloride).
Traffic count site/system to provide weekly or 
monthly counts.
0

0

Scope and frequency will vary depending on 
presence of protected species and notable 
habitats and whether a designated site.  
Invasive species mitigation plan if required.
0

Quant

MM

 Possible - high                     1                    -                       1                     1                     1 

Quant

MM

 No 

                   1                    -                       1                    -                       1 

Quant

Quant

Quant

Quant

MM

MM

MM

MM

 Possible - low 

                   1                    -                       1                    -                       1 

 No 

 No 

                   1                    -                       1                    -                       1 

                  -                      -                      -                       1                     1 

 Possible - low 

                   1                    -                       1                    -                       1 

Quant

MM

 Possible - high                     1                    -                       1                     1                     1 

Complimentary with other measures associated 
with planning.

Qual

MM

 No 

                  -                      -                      -                       1                     1 

Linked to SEA
0

Qual

MM

 No 

                  -                      -                      -                       1                     1 

0

0

0

Quant

MM

 No 

                   1                     1                     1                     1                     1 

Quant

MM

 No 

                  -                      -                      -                       1                     1 

Qual

MM

 Possible - high                     1                    -                       1                    -                       1 

35229 MASTER Measures (20150127) CBM 20150206.xlsx

Measures in Policy Options

12 of  13

Categorisation

Measure info

Coalbed Methane

Main

Sub

Measure ref. 

Order  LOW 

Measure

Sub-measure description

Further definition

equip N19

N19

223

vs. 
HIGH
        -    Carry out thorough planning and testing of equipment prior to hydraulic 

fracturing operations

N20

N20

224

        -    Environmental management system accreditation for unconventional 

gas installation operators

0

0

0

0

30e

30e

225

        -    Muds restricted to approved list with known properties/safety data or non-

Restrict muds to approved list

toxic drilling muds

30e

30e

226

        -    Muds restricted to approved list with known properties/safety data or non-

Restrict muds to non-toxic drilling muds

29e

29e

227

        -    Site reinstatement plan

toxic drilling muds

manag
ement
materi
als

materi
als
manag
ement

9b

inciden
t

Other 
Measures
Other 
Measures
Other 
Measures

Other 
Measures
Other 
Measures

Other 
Measures

Other 
Measures
Other 
Measures

Other 
Measures

9b

228

        -    Emergency response plan developed and put in place covering:

- leaks from the well to groundwater or surface water
- releases of flammable gases from the well or pipelines
- fires and floods
- leaks and spillage of chemicals, flowback or produced water
- releases during transportation

        -    Consideration of major hazards for all stages in the life cycle of the 

development (early design, through operations to post abandonment) 
and development of HSE case or similar demonstrating adequacy of the 
design, operations and HSE management (including emergency 
response) for both safety and environmental major impacts

        -    Use of temporary surface pipes for distribution of water supply

Other 
Measures

9a

inciden
t

9a

229

trans

60a

60a

230

trans

60b

60b

231

        -    Use of temporary surface pipes for collection of flowback

trans

61a

61a

232

        -    Use of temporary surface pipes for collection of produced water

0

0

0

0

0

0

Non-BAU, but 
Likely to be 
applied?

Policy Options:
  Option A Guidance = 1
  Option B Amendment to the Acquis plus Guidance = 3
  Option C Dedicated Legislation (Directive) plus Guidance = 5
  Option D Dedicated Legisalation (Regulation) plus Guidance = 5

1. Guidance

2. 
Amendment

3. 
Amendment + 
Guidance

4. Legislation

5. Legislation 
+ Guidance

 Possible - high                     1                    -                       1                    -                       1 

 No 

 No 

 No 

 Yes 

                   1                    -                       1                    -                       1 

                  -                      -                      -                      -                      -   

                   1                     1                     1                    -                       1 

                   1                    -                       1                     1                     1 

Quant/
qual

LoA 
rating

Qual

Quant

Qual

Qual

Quant

MM

MM

MH

HH

MH

Qual

HM

 Yes 

                  -                       1                     1                     1                     1 

Specify the use of muds from an approved list 
to minimise the risk of harmful (polluting) mud 
production which could result in polluting spills

Specify the use of water-based muds/non-toxic 
chemical additives
Purpose of measure is to develop a 
reinstatement plan for the site following well 
closure and abandonment.
0

0

Qual

HH

 Possible - high                     1                     1                     1                     1                     1 

Temporary pipes laid above ground to supply 
water to pads.

Qual

Qual

HH

HH

 No 

 No 

                  -                      -                      -                      -                      -   

                  -                      -                      -                      -                      -   

Temporary pipes laid above ground to collect 
flowback and transport to treatment plant.
Temporary pipes  laid above ground to collect 
produced water and transport to treatment 
plant.

Qual

HH

 No 

                   1                     1                     1                    -                       1 

35229 MASTER Measures (20150127) CBM 20150206.xlsx

Measures in Policy Options

13 of  13

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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doi:10.2779/001875