Support to the identification of potential risks for the environment and

Support to the identification of potential risks for the environment and
Support to the identification of
potential risks for the environment and
human health arising from
hydrocarbons operations involving
hydraulic fracturing in Europe
Report for
European Commission
DG Environment
AEA/R/ED57281
Issue Number 17c
11
Date 10/08/2012
28/05/2012
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Customer:
Contact:
European Commission DG Environment
Dr Mark Broomfield
AEA Technology plc
Gemini Building, Harwell, Didcot, OX11 0QR
t: 0870 190 6389
e: [email protected]
AEA is a business name of AEA Technology plc
AEA is certificated to ISO9001 and ISO14001
Customer reference:
07.0307/ENV.C.1/2011/604781/ENV.F1
Confidentiality, copyright & reproduction:
This report is the Copyright of the European
Commission DG Environment and has been
prepared by AEA Technology plc under
contract to the European Commission DG
Environment ref
07.0307/ENV.C.1/2011/604781/ENV.F1.
The contents of this report may not be
reproduced in whole or in part, nor passed to
any organisation or person without the
specific prior written permission of the
European Commission DG Environment.
AEA Technology plc accepts no liability
whatsoever to any third party for any loss or
damage arising from any interpretation or
use of the information contained in this
report, or reliance on any views expressed
therein. This document does not represent
the views of the European Commission. The
interpretations and opinions contained in it
are solely those of the authors.
Author:
Dr Mark Broomfield
Approved By:
Andrew Lelland
Date:
10 August 2012
Re-issued with minor corrections 11 February
2013)
Signed:
AEA reference:
Ref: ED57281- Issue Number 17c
(Re-issued with minor corrections)
Ref: AEA/ED57281/Issue Number 17
ii
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Executive summary
Introduction
Exploration and production of natural gas and oil within Europe has in the past been mainly
focused on conventional resources that are readily available and relatively easy to develop.
This type of fuel is typically found in sandstone, siltstone and limestone reservoirs.
Conventional extraction enables oil or gas to flow readily into boreholes.
As opportunities for this type of domestic extraction are becoming increasingly limited to
meet demand, EU countries are now turning to exploring unconventional natural gas
resources, such as coalbed methane, tight gas and in particular shale gas. These are
termed ‘unconventional’ resources because the porosity, permeability, fluid trapping
mechanism, or other characteristics of the reservoir or rock formation from which the gas is
extracted differ greatly from conventional sandstone and carbonate reservoirs.
In order to extract these unconventional gases, the characteristics of the reservoir need to be
altered using techniques such as hydraulic fracturing. In particular high volume hydraulic
fracturing has not been used to any great extent within Europe for hydrocarbon extraction.
Its use has been limited to lower volume fracturing of some tight gas and conventional
reservoirs in the southern part of the North Sea and in onshore Germany, the Netherlands,
Denmark and the UK.
Preliminary indications are that extensive shale gas resources are present in Europe
(although this would need to be confirmed by exploratory drilling). To date, it appears that
only Poland and the UK have performed high-volume hydraulic fracturing for shale gas
extraction (at one well in the UK and six wells in Poland); however, a considerable number of
Member States have expressed interest in developing shale gas resources. Those already
active in this area include Poland, Germany, the Netherlands, the UK, Spain, Romania,
Lithuania, Denmark, Sweden and Hungary.
The North American context
Technological advancements and the integration of horizontal wells with hydraulic fracturing
practices have enabled the rapid development of shale gas resources in the United States –
at present the only country globally with significant commercial shale gas extraction. There,
rapid developments have also given rise to widespread public concern about improper
operational practices and health and environmental risks related to deployed practices. A
2011 report from the US Secretary of Energy Advisory Board (SEAB) put forward a set of
recommendations aiming at "reducing the environmental impact "and "helping to ensure the
safety of shale gas production."
Almost half of all states have recently enacted, or have pending legislation that regulates
hydraulic fracturing. In 2012, the US Environmental Protection Agency (EPA) has issued
Final Oil and Natural Gas Air Pollution Standards including for natural gas wells that are
hydraulically fractured as well as Draft Permitting Guidance for Oil and Gas Hydraulic
Fracturing Activities Using Diesel Fuels. The EPA is also developing standards for waste
water discharges and is updating chloride water quality criteria, with a draft document
expected in 2012. In addition, it is implementing an Energy Extraction Enforcement Initiative,
and is involved in voluntary partnerships, such as the Natural Gas STAR program. The US
Department of the Interior proposed in April 2012 a rule to require companies to publicly
disclose the chemicals used in hydraulic fracturing operations, to make sure that wells used
in fracturing operations meet appropriate construction standards, and to ensure that
operators put in place appropriate plans for managing flowback waters from fracturing
operations).
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
The general European context
In February 2011, the European Council concluded that Europe should assess its potential
for sustainable extraction and use of both conventional and unconventional fossil fuel
resources.1 A 2011 report commissioned by the European Parliament drew attention to the
potential health and environmental risks associated with shale gas extraction.
At present, close to half of all EU Member States are interested in developing shale gas
resources, if possible. Member States active in this area include Poland, Germany,
Netherlands, UK, Spain, Romania, Lithuania and Denmark. Sweden, Hungary and other EU
Member States may also be interested in developing activity in this area. However, in
response to concerns raised by the general public and stakeholders, several European
Member States have prohibited, or are considering the possibility to prohibit the use of
hydraulic fracturing. Concurrently, several EU Member States are about to initiate
discussions on the appropriateness of their national legislation, and contemplate the
possibility to introduce specific national requirements for hydraulic fracturing.
The recent evolution of the European context suggests a growing need for a clear,
predictable and coherent approach to unconventional fossil fuels and in particular shale gas
developments to allow optimal decisions to be made in an area where economics, finances,
environment and in particular public trust are essential.
Against this background, the Commission is investigating the impact of unconventional gas,
primarily shale gas, on EU energy markets and has requested this initial, specific
assessment of the environmental and health risks and impacts associated with the use of
hydraulic fracturing, in particular for shale gas.
Study focus and scope
This report sets out the key environmental and health risk issues associated with the
potential development and growth of high volume hydraulic fracturing in Europe. The study
focused on the net incremental impacts and risks that could result from the possible growth
in use of these techniques. This addresses the impacts and risks over and above those
already addressed in regulation of conventional gas exploration and extraction. The study
distinguishes shale gas associated practices and activities from conventional ones that
already take place in Europe, and identifies the potential environmental issues which have
not previously been encountered, or which could be expected to present more significant
challenges.
The study reviewed available information on a range of potential risks and impacts of high
volume hydraulic fracturing. The study concentrated on the direct impacts of hydraulic
fracturing and associated activities such as transportation and wastewater management.
The study did not address secondary or indirect impacts such as those associated with
materials extraction (stone, gravel etc.) and energy use related to road, infrastructure and
well pad construction.
The study has drawn mainly on experience from North America, where hydraulic fracturing
has been increasingly widely practised since early in the 2000s. The views of regulators,
geological surveys and academics in Europe and North America were sought. Where
possible, the results have been set in the European regulatory and technical context.
The study includes a review of the efficiency and effectiveness of current EU legislation
relating to shale gas exploration and production and the degree to which the current EU
framework adequately covers the impacts and risks identified. It also includes a review of
risk management measures.
1
European Council, Conclusions on Energy, 4 February 2011
(http://www.consilium.europa.eu/uedocs/cms_Data/docs/pressdata/en/ec/119141.pdf)
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Preliminary risk assessment
The main risks were assessed at each stage of a project (well-pad) development, and also
covered the cumulative environmental effects of multiple installations. The stages are:
1. Well pad site identification and preparation
2. Well design, drilling, casing and cementing
3. Technical hydraulic fracturing stage
4. Well completion
5. Well production
6. Well abandonment.
The study adopted a risk prioritisation approach to enable objective evaluation. The
magnitude of potential hazards and the expected frequency or probability of the hazards
were categorised on the basis of expert judgement and from analysis of hydraulic fracturing
in the field where this evidence was available to allow risks to be evaluated. Where the
uncertainty associated with the lack of information about environmental risks was significant,
this has been duly acknowledged. This approach enabled a prioritisation of overall risks.
The study authors duly acknowledge the limits of this risk screening exercise, considering
notably the absence of systematic baseline monitoring in the US (from where most of the
literature sources come), the lack of comprehensive and centralised data on well failure and
incident rates, and the need for further research on a number of possible effects including
long term ones. Because of the inherent uncertainty associated with environmental risk
assessment studies, expert judgement was used to characterise these effects.
The study identified a number of issues as presenting a high risk for people and the
environment. These issues and their significance are summarised in the following table.
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Table ES1: Summary of preliminary risk assessment
Project phase
Site
Environmental
identification
aspect
and
preparation
Well
Well
Overall
design
Well
abandonment
Production
drilling, Fracturing
rating across
completion
and postall phases
casing,
abandonment
cementing
Individual site
Groundwater
contamination
Not
applicable
Low
ModerateHigh
High
ModerateHigh
Not
classifiable
High
Surface water
contamination
Low
Moderate
ModerateHigh
High
Low
Not applicable
High
Not
applicable
Not
applicable
Moderate
Not
applicable
Moderate
Not applicable
Moderate
Low
Moderate
Moderate
Moderate
Moderate
Low
Moderate
Moderate
Not
applicable
Not
applicable
Not
applicable
Moderate
Not
classifiable
Moderate
Not
classifiable
Low
Low
Low
Moderate
Not
classifiable
Moderate
Noise impacts
Low
Moderate
Moderate
Not
classifiable
Low
Not applicable
Moderate –
High
Visual impact
Low
Low
Low
Not
applicable
Low
Low-moderate
Low Moderate
Not
applicable
Not
applicable
Low
Low
Not
applicable
Not applicable
Low
Low
Low
Moderate
Low
Low
Not applicable
Moderate
Water
resources
Release to air
Land take
Risk to
biodiversity
Seismicity
Traffic
Cumulative
Groundwater
contamination
Not
applicable
Low
ModerateHigh
High
High
Not
classifiable
High
Surface water
contamination
Moderate
Moderate
ModerateHigh
High
Moderate
Not
applicable
High
Water
resources
Not
applicable
Not
applicable
High
Not
applicable
High
Not
applicable
High
Low
High
High
High
High
Moderate
High
Land take
Very high
Not
applicable
Not
applicable
Not
applicable
High
Not
classifiable
High
Risk to
biodiversity
Not
classifiable
Low
Moderate
Moderate
High
Not
classifiable
High
Noise impacts
Low
High
Moderate
Not
classifiable
Low
Not
applicable
High
Visual impact
Moderate
Moderate
Moderate
Not
applicable
Low
Low-moderate
Moderate
Seismicity
Not
applicable
Not
applicable
Low
Low
Not
applicable
Not
applicable
Low
High
High
High
Moderate
Low
Not
applicable
High
Release to air
Traffic
Not applicable: Impact not relevant to this stage of development
Not classifiable: Insufficient information available for the significance of this impact to be assessed
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
General risk causes
In general, the main causes of risks and impacts from high-volume hydraulic fracturing
identified in the course of this study are as follows:





The use of more significant volumes of water and chemicals compared to
conventional gas extraction
The lower yield of unconventional gas wells compared to conventional gas wells
means that the impacts of HVHF processes can be greater than the impacts of
conventional gas exploration and production processes per unit of gas extracted.
The challenge of ensuring the integrity of wells and other equipment throughout the
development, operational and post-abandonment lifetime of the plant (well pad) so as
to avoid the risk of surface and/or groundwater contamination
The challenge of ensuring that spillages of chemicals and waste waters with potential
environmental consequences are avoided during the development and operational
lifetime of the plant (well pad)
The challenge of ensuring a correct identification and selection of geological sites,
based on a risk assessment of specific geological features and of potential
uncertainties associated with the long-term presence of hydraulic fracturing fluid in
the underground

The potential toxicity of chemical additives and the challenge to develop greener
alternatives
 The unavoidable requirement for transportation of equipment, materials and wastes to
and from the site, resulting in traffic impacts that can be mitigated but not entirely
avoided.
 The potential for development over a wider area than is typical of conventional gas
fields
 The unavoidable requirement for use of plant and equipment during well construction
and hydraulic fracturing, leading to emissions to air and noise impacts.
Environmental pressures
Land-take
The American experience shows there is a significant risk of impacts due to the amount of
land used in shale gas extraction. The land use requirement is greatest during the actual
hydraulic fracturing stage (i.e. stage 3), and lower during the production stage (stage 5).
Surface installations require an area of approximately 3.6 hectares per pad for high volume
hydraulic fracturing during the fracturing and completion phases, compared to 1.9 hectares
per pad for conventional drilling. Land-take by shale gas developments would be higher if
the comparison is made per unit of energy extracted. Although this cannot be quantified, it is
estimated that approximately 50 shale gas wells might be needed to give a similar gas yield
as one North Sea gas well. Additional land is also required during re-fracturing operations
(each well can typically be re-fractured up to four times during a 40 years well lifetime).
Consequently, approximately 1.4% of the land above a productive shale gas well may need
to be used to exploit the reservoir fully. This compares to 4% of land in Europe currently
occupied by uses such as housing, industry and transportation. This is considered to be of
potentially major significance for shale gas development over a wide area and/or in the case
of densely populated European regions.
The evidence suggests that it may not be possible fully to restore sites in sensitive areas
following well completion or abandonment, particularly in areas of high agricultural, natural or
cultural value. Over a wider area, with multiple installations, this could result in a significant
loss or fragmentation of amenities or recreational facilities, valuable farmland or natural
habitats.
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Releases to air
Emissions from numerous well developments in a local area or wider region could have a
potentially significant effect on air quality. Emissions from wide scale development of a shale
gas reservoir could have a significant effect on ozone levels. Exposure to ozone could have
an adverse effect on respiratory health and this is considered to be a risk of potentially high
significance.
The technical hydraulic fracturing stage also raises concerns about potential air quality
effects. These typically include diesel fumes from fracturing liquid pumps and emissions of
hazardous pollutants, ozone precursors and odours due to gas leakage during completion
(e.g. from pumps, valves, pressure relief valves, flanges, agitators, and compressors).
There is also concern about the risk posed by emissions of hazardous pollutants from gases
and hydraulic fracturing fluids dissolved in waste water during well completion or
recompletion.
Fugitive emissions of methane (which is linked to the formation of
photochemical ozone as well as climate impacts) and potentially hazardous trace gases may
take place during routeing gas via small diameter pipelines to the main pipeline or gas
treatment plant.
On-going fugitive losses of methane and other trace hydrocarbons are also likely to occur
during the production phase. These may contribute to local and regional air pollution with the
potential for adverse impacts on health. With multiple installations the risk could potentially
be high, especially if re-fracturing operations are carried out.
Well or site abandonment may also have some impacts on air quality if the well is
inadequately sealed, therefore allowing fugitive emissions of pollutants. This could be the
case in older wells, but the risk is considered low in those appropriately designed and
constructed. Little evidence exists of the risks posed by movements of airborne pollutants to
the surface in the long-term, but experience in dealing with these can be drawn from the
management of conventional wells.
Noise pollution
Noise from excavation, earth moving, plant and vehicle transport during site preparation has
a potential impact on both residents and local wildlife, particularly in sensitive areas. The site
preparation phase would typically last up to four weeks but is not considered to differ greatly
in nature from other comparable large-scale construction activity.
Noise levels vary during the different stages in the preparation and production cycle. Well
drilling and the hydraulic fracturing process itself are the most significant sources of noise.
Flaring of gas can also be noisy. For an individual well the time span of the drilling phase will
be quite short (around four weeks in duration) but will be continuous 24 hours a day. The
effect of noise on local residents and wildlife will be significantly higher where multiple wells
are drilled in a single pad, which typically lasts over a five-month period. Noise during
hydraulic fracturing also has the potential to temporarily disrupt and disturb local residents
and wildlife. Effective noise abatement measures will reduce the impact in most cases,
although the risk is considered moderate in locations where proximity to residential areas or
wildlife habitats is a consideration.
It is estimated that each well-pad (assuming 10 wells per pad) would require 800 to 2,500
days of noisy activity during pre-production, covering ground works and road construction as
well as the hydraulic fracturing process. These noise levels would need to be carefully
controlled to avoid risks to health for members of the public.
Surface and groundwater contamination
The study found that there is a high risk of surface and groundwater contamination at various
stages of the well-pad construction, hydraulic fracturing and gas production processes, and
during well abandonment. Cumulative developments could further increase this risk.
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Runoff and erosion during early site construction, particularly from storm water, may lead to
silt accumulation in surface waters and contaminants entering water bodies, streams and
groundwater. This is a problem common to all large-scale mining and extraction activities.
However, unconventional gas extraction carries a higher risk because it requires high-volume
processes per installation and the risks increase with multiple installations. Shale gas
installations are likely to generate greater storm water runoff, which could affect natural
habitats through stream erosion, sediment build-up, water degradation and flooding.
Mitigation measures, such as managed drainage and controls on certain contaminants, are
well understood. Therefore the hazard is considered minor for individual installations with a
low risk ranking and moderate hazard for cumulative effects with a moderate risk ranking.
Road accidents involving vehicles carrying hazardous materials could also result in impacts
on surface water.
The study considered the water contamination risks of sequential as well as simultaneous
(i) well-drilling and (ii) hydraulic fracturing.
i.
ii.
Poor well design or construction can lead to subsurface groundwater contamination
arising from aquifer penetration by the well, the flow of fluids into, or from rock
formations, or the migration of combustible natural gas to water supplies. In a
properly constructed well, where there is a large distance between drinking water
sources and the gas producing zone and geological conditions are adequate, the
risks are considered low for both single and multiple installations. Natural gas well
drilling operations use compressed air or muds as the drilling fluid. During the drilling
stage, contamination can arise as a result of a failure to maintain storm water
controls, ineffective site management, inadequate surface and subsurface
containment, poor casing construction, well blowout or component failure. If
engineering controls are insufficient, the risk of accidental release increases with
multiple shale gas wells. Cuttings produced from wells also need to be properly
handled to avoid for instance the risk of radioactive contamination. Exposure to these
could pose a small risk to health, but the study concluded that this would only happen
in the event of a major failure of established control systems. No evidence was found
that spillage of drilling muds could have a significant effect on surface waters.
However, in view of the potential significance of spillages on sensitive water
resources, the risks for surface waters were considered to be of moderate
significance.
The risks of surface water and groundwater contamination during the technical
hydraulic fracturing stage are considered moderate to high. The likelihood of properly
injected fracturing liquid reaching underground sources of drinking water through
fractures is remote where there is more than 600 metres separation between the
drinking water sources and the producing zone. However, the potential of natural and
manmade geological features to increase hydraulic connectivity between deep strata
and more shallow formations and to constitute a risk of migration or seepage needs
to be duly considered. Where there is no such large depth separation, the risks are
greater. If wastewater is used to make up fracturing fluid, this would reduce the water
requirement, but increase the risk of introducing naturally occurring chemical
contaminants and radioactive materials into aquifers in the event of well failure or of
fractures extending out of the production zone. The potential wearing effects of
repeated fracturing on well construction components such as casings and cement are
not sufficiently understood and more research is needed.
In the production phase, there are a number of potential effects on groundwater associated
however with the inadequate design or failure of well casing, leading to potential aquifer
contamination. Substances of potential concern include naturally occurring heavy metals,
natural gas, naturally occurring radioactive material and technologically enhanced radioactive
material from drilling operations. The risks to groundwater are considered to be moderatehigh for individual sites, and high for development of multiple sites.
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Inadequate sealing of a well after abandonment could potentially lead to both groundwater
and surface water contamination, although there is currently insufficient information available
on the risks posed by the movement of hydraulic fracturing fluid to the surface over the long
term to allow these risks to be characterised. The presence of high-salinity fluids in shale
gas formations indicates that there is usually no pathway for release of fluids to other
formations under the geological conditions typically prevailing in these formations, although
recently published research indicates that pathways may potentially exist in certain
geological areas such as those encountered in parts of Pennsylvania, emphasising the need
for a high standard of characterisation of these conditions.
Water resources
The hydraulic fracturing process is water-intensive and therefore the risk of significant effects
due to water abstraction could be high where there are multiple installations. A proportion of
the water used is not recovered. If water usage is excessive, this can result in a decrease in
the availability of public water supply; adverse effects on aquatic habitats and ecosystems
from water degradation, reduced water quantity and quality; changes to water temperature;
and erosion. Areas already experiencing water scarcity may be affected especially if the
longer term climate change impacts of water supply and demand are taken into account.
Reduced water levels may also lead to chemical changes in the water aquifer resulting in
bacterial growth causing taste and odour problems with drinking water. The underlying
geology may also become destabilised due to upwelling of lower quality water or other
substances.
Water withdrawal licences for hydraulic fracturing have recently been
suspended in some areas of the United States.
Biodiversity impacts
Unconventional gas extraction can affect biodiversity in a number of ways. It may result in
the degradation or complete removal of a natural habitat through excessive water
abstraction, or the splitting up of a habitat as a result of road construction or fencing being
erected, or for the construction of the well-pad itself. New, invasive species such as plants,
animals or micro-organisms may be introduced during the development and operation of the
well, affecting both land and water ecosystems. This is an area of plausible concern but
there is as yet no clear evidence base to enable the significance to be assessed.
Well drilling could potentially affect biodiversity through noise, vehicle movements and site
operations. The treatment and disposal of well drilling fluids also need to be adequately
handled to avoid damaging natural habitats. However, these risks are lower than during
other stages of shale drilling.
During hydraulic fracturing, the impacts on ecosystems and wildlife will depend on the
location of the well-pad and its proximity to endangered or threatened species. Sediment
runoff into streams, reductions in stream flow, contamination through accidental spills and
inadequate treatment of recovered waste-waters are all seen as realistic threats as is water
depletion. However, the study found that the occurrence of such effects was rare and
cumulatively the risks could be classified as moderate.
Effects on natural ecosystems during the gas production phase may arise due to human
activity, traffic, land-take, habitat degradation and fragmentation, and the introduction of
invasive species. Pipeline construction could affect sensitive ecosystems and re-fracturing
would also cause continuing impacts on biodiversity. The possibility of land not being
suitable for return to its former use after well abandonment is another factor potentially
affecting local ecosystems. Biodiversity risks during the production phase were considered
to be potentially high for multiple installations.
Traffic
Total truck movements during the construction and development phases of a well are
estimated at between 7,000 and 11,000 for a single ten-well pad. These movements are
temporary in duration but would adversely affect both local and national roads and may have
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
a significant effect in densely populated areas. These movements can be reduced by the
use of temporary pipelines for transportation of water.
During the most intensive phases of development, it is estimated that there could be around
250 truck trips per day onto an individual site – noticeable by local residents but sustained at
these levels for a few days. The effects may include increased traffic on public roadways
(affecting traffic flows and causing congestion), road safety issues, damage to roads, bridges
and other infrastructure, and increased risk of spillages and accidents involving hazardous
materials. The risk is considered to be moderate for an individual installation, and high for
multiple installations.
Visual impact
The risk of significant visual effects during well-pad site identification and preparation are
considered to be low given that the new landscape features introduced during the well pad
construction stage are temporary and common to many other construction projects. The use
of large well drilling rigs could potentially be unsightly during the four-week construction
period, especially in sensitive high-value agricultural or residential areas. Local people are
not likely to be familiar with the size and scale of these drills, and the risk of significant effects
was considered to be moderate in situations where multiple pads are developed in a given
area.
The risk of visual effects associated with hydraulic fracturing itself is less significant, with the
main changes to the landscape consisting of less visually intrusive features. For multiple
installations, the risk is considered to be moderate from the site preparation to the fracturing
phases. During the post-abandonment phase, it may not be possible to remove all wellhead
equipment from the site; however, this is considered to pose a low risk of significant visual
intrusion, in view of the small scale of equipment remaining on site.
Seismicity
There are two types of induced seismic events associated with hydraulic fracturing. The
hydraulic fracturing process itself can under some circumstances give rise to minor earth
tremors up to a magnitude of 3 on the Richter Scale, which would not be detectable by the
public. An effective monitoring programme can be used to manage the potential for these
events and identify any damage to the wellbore itself. The risk of significant induced seismic
activity was considered to be low.
The second type of event results from the injection of waste water reaching existing
geological faults. This could lead to more significant underground movements, which can
potentially be felt by humans at ground level. This would not take place at the shale gas
extraction site.
European Legislation
The objectives of the review of the current EU environmental framework were threefold:

To identify potential uncertainties regarding the extent to which shale gas exploration
and production risks are covered under current EU legislation

To identify those risks not covered by EU legislation

To draw conclusions relating to the risk to the environment and human health of such
operations in the EU.
An analysis of all EU 27 Member States’ legislation and standards was outside the scope of
this study, as was the consistency of Member States’ implementation of the EU legislation
reviewed.
In all, 19 pieces of legislation relevant to all or some of the stages of shale gas resource
development were identified and reviewed.
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
A number of gaps or possible inadequacies in EU legislation were identified. These were
classified as follows:

Inadequacies in EU legislation that could lead to risks to the environment or human
health not being sufficiently addressed.

Potential inadequacies –uncertainties in the applicability of EU legislation: the
potential for risks to be insufficiently addressed by EU legislation, where uncertainty
arises because a lack of information regarding the characteristics of high volume
hydraulic fracturing (HVHF) projects.

Potential inadequacies –uncertainties in the existence of appropriate requirements at
national level: aspects relying on a high degree of Member State decision-making for
which it is not possible to conclude under this study whether or not at EU level the
risks are adequately addressed.
The legislative review identified the following gaps or potential gaps in European legislation
(please see the discussion of limitations of the analysis in Section 3.1):
Table ES2: Summary of gaps and potential gaps in European legislation
Gap or potential gap
Impact
Risk associated with gap/potential gap
Gaps in legislation
Environmental Impact
Assessment Directive
(2011/92/EU)
Annex I threshold for gas
production is above HVHF
project production levels.
Result: no compulsory EIA.
Environmental Impact
Assessment Directive
(2011/92/EU)
Annex II no definition of
deep drilling; exploration
phase would not be covered
under Annex II classification
“Surface industrial
installations for the
extraction of coal,
petroleum, natural gas and
ores, as well as bituminous
shale”. Result: no
compulsory EIA
Environmental Impact
Assessment Directive
(2011/92/EU)
No explicit coverage of
geomorphological and
hydrogeological aspects, no
obligation to assess
geological features as part
of the impact assessment
Water Framework
Directive (2000/60/EC)
WFD programmes of
measures are not required
to be enforced until
All, especially relevant
to key impacts from
landtake during
preparation, noise
during drilling, release
to air during fracturing,
traffic during fracturing
and groundwater
contamination
A decision on the exploration and production may
not be based on an impact assessment. Public
participation may not be guaranteed, permits may
not be tailor-made to the situation
Impacts may not be known and assessed.
Measures to mitigate possible impacts may not be
applied through consent process or permitting
regime.
All, especially relevant
to key impacts from
landtake during
preparation, noise
during drilling, release
to air during fracturing,
traffic during fracturing
and groundwater
contamination
A decision on the exploration and production may
not be based on an impact assessment. Public
participation may not be guaranteed, permits may
not be tailor-made to the situation
HVHF project involving shallow drillings not
covered by EIA. For these projects, impacts may
not be known and assessed. Measures to
mitigate possible impacts may not be applied
through consent process or permitting regime.
Preventative measures may not be undertaken.
Aquifers in surroundings not known, leading to
unanticipated pollution.
Especially relevant for
groundwater
contamination,
seismicity, land
impacts, release to air
No assessment of geological and hydrogeological
conditions (e.g. natural and manmade faults,
fissures, hydraulic connectivity, distance to
aquifers, etc) in the frame of the impact
assessment or screening, resulting in sub-optimal
site selection and risks of subsequent pollution
Monitoring of groundwater quality of aquifers in
surrounding of the site may not be done and
preventative measures not undertaken.
Aquifers in surroundings not known, leading to
unanticipated pollution.
Abstraction of water
and impacts due to
water contamination
Inadequate monitoring and measures to prevent
these impacts
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Gap or potential gap
Impact
Risk associated with gap/potential gap
Pollution of
groundwater
“Pollutants” are defined as “any substance liable
to cause pollution, in particular those listed in
Annex VIII.”
Permit conditions may not require monitoring or
measures to prevent hydraulic fracturing leading
to impacts on aquifers
Waste management
as covered by MWD –
treatment of hydraulic
fracturing fluids during
and after fracturing
No shared opinion on Best Available Techniques
nor enforcement of those techniques
Higher levels of pollution arising from the
management of mining waste
Air pollution especially
during drilling and
fracturing
Measures may not be taken to prevent high
emissions to air, leading to localised increased air
pollution, although purpose of legislation is to
regulate machine standards not emissions during
use.
Air pollution especially
during drilling and
fracturing
Measures may not be taken to prevent high
emissions to air, leading to localised increased air
pollution. This potential gap arises because of
uncertainty over the hazardous character of
fracturing fluids which would determine the
applicability of the IPPC Directive (2008/1/EC) to
hydraulic fracturing installations
Noise during drilling
Drilling equipment used in HVHF processes
however is not included in the equipment cited in
this directive. Compressors used for drilling have
a power capacity over 350 kW, which is the limit
for this directive
Air pollution during
drilling and fracturing
and traffic impacts
No measures to reduce emissions to air. Levels
of air pollution may be above impact levels or air
quality standards.
Landtake, air impacts
during drilling and
fracturing and traffic
Some environmental impacts may not be covered.
22.12.2012
Water Framework
Directive (2000/60/EC)
For substances which are
not pollutants, the WFD
does not prevent direct
fracturing into groundwater
that may ultimately impact
aquifers
Mining Waste Directive
(2006/21/EC)
No reference document on
Best Available Techniques
(BREFs)
Directives on Emissions
from Non-Road Mobile
Machinery (Directive
97/68/EC as amended)
Lack of emission limits for
off-road combustion plant
above 560 kW
IPPC Directive (2008/1/EC)
and IED (2010/75/EC)
No BREF for drilling
equipment
The Outdoor Machinery
Noise Directive2000/14/EC
Gaps in limits to prevent
noise for specific equipment
Air Quality Directive
(2008/50/EC)
Not specific about remedial
measures or prohibition of
polluting activities
Environmental Liability
Directive (2004/35/EC)
Damage caused by non
Annex III activities not
covered unless it is damage
to protected species and
natural habitats resulting
from a fault or negligence
on part of operator.
Impacts caused by diffuse
pollution are not covered,
unless a causal link can be
established
Uncertainties in application
IPPC Directive (2008/1/EC)
and IED (2010/75/EC)
Emissions to air, water
and soil
Activity not mentioned or
may not be covered under
hazardous waste or
combustion capacity
Ref: AEA/ED57281/Issue Number 17
No permit obligation under IPPC and no BREF
under IPPC or IED .This potential gap arises
because of uncertainty over the hazardous
character of fracturing fluids which would
determine the applicability of the IPPC Directive
(2008/1/EC) to hydraulic fracturing installations
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Gap or potential gap
Impact
Risk associated with gap/potential gap
The monitoring requirements as mentioned in
IPPC directive may not be applied. Integrated
measures designed to prevent or to reduce
emissions in the air, water and land, including
measures concerning waste, in order to achieve a
high level of protection of the environment may
not be taken. Monitoring of emissions to air might
not take place.
Mining Waste Directive
(2006/21/EC)
Uncertainty over
classification of Category A
waste facility
Seveso II Directive
(96/82/EC)
Uncertainty over whether
the Directive covers high
volume hydraulic fracturing
(HVHF), subject to storage
of natural gas or of specific
chemical additives on-site.
Major accidents,
groundwater and
surface water
pollution, air impacts
The classification may be inadequately performed
Major accidents might occur without proper
prevention and emergency plans.
Major accidents
involving dangerous
substances (e.g. water
pollution events)
Major accidents might occur without proper
prevention and emergency plans.
Issues currently at the discretion of Member States
The Strategic
Environmental
Assessment Directive
(2001/42/EC)
All
No SEA would be made
Information on possible environmental effects
would not be available and therefore would not be
used in an authorisation/consent process or
permits
All
No EIA would be made. The environmental
impacts would not be assessed and properly
described. The measures that can prevent or
mitigate the impacts will not be presented
All
Member States may not take account of
environmental impacts during the authorisation
process
Waste management as
covered by MWD –
treatment of hydraulic
fracturing fluids during
and after fracturing
There may be inadequate measures for the
monitoring and control of impacts related to
management of mining waste
Emissions to air,
especially during drilling
and fracturing, and
releases to water during
fracturing
There may be inadequate measures for the
monitoring and control of impacts related to air
and water emissions
Emissions to air,
especially during
drilling, fracturing and
traffic, and releases to
No specific measures for emission abatement
may be required.
Air pollution may not be prevented or mitigated
Remains up to Member
States to decide whether
or not a plan or
programme might have
significant effects
Environmental Impact
Assessment Directive
(2011/92/EU)
Member States must
decide whether an EIA is
required (Article 4(2)) for
activities covered by
Annex II.
Hydrocarbons
Authorization Directive
(94/22/EC)
No compulsory account of
environmental aspects
Mining Waste Directive
(2006/21/EC)
Member States decide on
the permit and the control
measures
IPPC Directive
(2008/1/EC)
Member State decisions
on monitoring and
inspection
Air Quality
Directive(2008/50/EC)
Member States
responsible for making
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Gap or potential gap
Impact
Risk associated with gap/potential gap
plans to meet the AQ
standards
water during fracturing
Water Framework
Directive (2000/60/EC)
Water use during
fracturing
There may be unmitigated or poorly controlled
impacts arising from water use during abstraction
Noise during drilling
and fracturing and
traffic during fracturing
No specific measures for noise abatement may be
required.
Noise may not be prevented or mitigated
Member State
determination of control
measures related to
abstraction
Noise Directive
(2002/49/EC)
Up to Member States to
set noise levels and to
make plans to meet these
levels
Study recommendations
As highlighted above, the risks posed by high volume hydraulic fracturing for unconventional
hydrocarbon extraction are greater than those of conventional extraction. A number of
recent reports have looked at opportunities and challenges of unconventional fossil fuels and
shale gas developments, and found that developing unconventional fossil fuel resources
generally poses greater environmental challenges than conventional developments. Robust
regulatory regimes would be required to mitigate risks and to improve general public
confidence (e.g. the "Golden Rules for a Golden Age of Gas" special report from the
International Energy Agency, or an independent German study on shale gas entitled
“Empfehlungen des Neutralen Expertenkreis” (“Recommendations of the neutral expert
group”).
Measures for mitigation of these risks were identified from existing and proposed legislation
in the US and Canada where shale gas extraction is currently carried out. Measures set out
in industry guidance and other publications were also reviewed and included where
appropriate.
A number of the recommendations made by the US Department of Energy (SEAB 2011a
NPR) are relevant for regulatory authorities in Europe. In particular, it is recommended that
the European Commission should take a strategic overview of potential risks. This will
require consideration of aspects such as:

Undertaking science-based characterisation of important landscapes, habitats and
corridors to inform planning, prevention, mitigation and reclamation of surface effects.

Establishing effective field monitoring and enforcement to inform on-going assessment
of cumulative community and land use effects

Restricting or preventing development in areas of high value or sensitivity with regard
to biodiversity, water resources, community effects etc.
As set out in Section 3.17 and in the table above, it is recommended that the European
Commission considers the gaps, possible inadequacies and uncertainties identified in the
current EU legislative framework. It is also recommended that Member States’ interpretation
of EU legislation in respect of hydraulic fracturing should be evaluated.
This study has identified and made recommendations on specific risk management
measures for a number of aspects of hydrocarbon developments involving HVHF, and in
particular:

The appropriate siting of developments, to reduce above and below-ground risks for
specified projects
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe

Measures and approaches to reduce land disturbance and land-take

Measures to address releases to air and to effectively reduce noise during drilling,
fracturing and completion

Measures to address water resource depletion

Measures to reduce the negative effects caused by increased traffic movements

Measures to improve well integrity and to reduce the risk of ground and surface water
contamination

Measures to reduce the pressure on biodiversity
A number of recommendations for further consideration and research are made with regard
to current areas of uncertainty. These include:

Consideration and further research over relevant provisions of the Carbon Capture
and Storage Directive (2009/31/EC) covering aspects such as: site characterisation
and risk assessment, permitting arrangements, monitoring provisions, transboundary
co-operation, and liability.

The use of micro-seismic monitoring in relation to hydraulic fracturing

Determination of chemical interactions between fracturing fluids and different shale
rocks, and displacement of formation fluids

Induced seismicity triggered by hydraulic fracturing

Development of less environmentally hazardous drilling and fracturing fluids

Methods to improve well integrity through development of better casing and
cementing methods and practices

Development of a searchable European database of hydraulic fracturing fluid
composition

Research into the risks and causes of methane migration to groundwater from shale
gas extraction

The development of a system of voluntary ecological initiatives within sensitive
habitats to generate mitigation credits which could be used for offsetting future
development.
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
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Table of contents
1
Overview of hydraulic fracturing in Europe ............................................................. 1
1.1 Introduction ........................................................................................................ 1
1.2 Objective of the study ......................................................................................... 1
1.3 EU Context......................................................................................................... 2
1.4 Shale gas extraction........................................................................................... 9
1.5 Short chronological summary of use of hydraulic fracturing and horizontal drilling
21
2
Impacts and risks potentially associated with shale gas development ................23
2.1 Introduction .......................................................................................................23
2.2 Risk prioritisation ...............................................................................................26
2.3 Stages in shale gas development ......................................................................28
2.4 Stage 1: Well pad site identification and preparation .........................................29
2.5 Stage 2: Well Design, drilling, casing and cementing ........................................35
2.6 Stage 3: Technical Hydraulic Fracturing ............................................................43
2.7 Stage 4: Well Completion ..................................................................................56
2.8 Stage 5: Well Production ...................................................................................61
2.9 Stage 6: Well / Site Abandonment .....................................................................67
2.10 Summary of key issues .....................................................................................70
3
The efficiency and effectiveness of current EU legislation ....................................75
3.1 Introduction to the legal review ..........................................................................75
3.2 Objectives and approach...................................................................................75
3.3 Study Overview .................................................................................................76
3.4 General provisions ............................................................................................78
3.5 Land-take during site preparation and production (cumulative, project stage 1) 97
3.6 Release to air during drilling (project stage 2) .................................................100
3.7 Noise during drilling (cumulative, project stage 2) ...........................................102
3.8 Water resource depletion during fracturing (project stage 3) ...........................103
3.9 Release to air during fracturing (project stage 3) .............................................104
3.10 Traffic during fracturing (cumulative, project stage 3) ......................................106
3.11 Groundwater contamination during fracturing and completion (project stages 3
and 4) 108
3.12 Surface water contamination risks during fracturing and completion (project
stages 3 and 4) .........................................................................................................115
3.13 Groundwater contamination during production (project stage 5)......................118
3.14 Release to air during production (project stage 5) ...........................................118
3.15 Biodiversity impacts (all project stages) ...........................................................118
3.16 Lower priority impacts .....................................................................................119
3.17 Conclusions ....................................................................................................119
4
Review of risk management measures ..................................................................127
4.1 Methodology ...................................................................................................127
4.2 Summary of risk management measures ........................................................129
5
Recommendations ..................................................................................................139
5.1 Introduction .....................................................................................................139
5.2 General recommendations ..............................................................................139
5.3 Traffic during site preparation and fracturing ...................................................140
5.4 Land take during site preparation ....................................................................143
5.5 Releases to air during drilling ..........................................................................148
5.6 Noise during drilling.........................................................................................151
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
5.7
5.8
5.9
5.10
5.11
5.12
5.13
5.14
5.15
5.16
6
Water resource depletion during fracturing ......................................................152
Releases to air during completion ...................................................................156
Groundwater contamination during fracturing and completion .........................158
Surface water contamination during fracturing and completion........................163
Groundwater contamination during production ................................................169
Releases to air during production ....................................................................169
Biodiversity impacts during production ............................................................173
Lower priority impacts .....................................................................................174
Summary table ................................................................................................175
Recommendations for further consideration and research ..............................175
References ...............................................................................................................179
Appendices
Appendix 1: Glossary and Abbreviations
Appendix 2: Types of artificial stimulation treatments
Appendix 3: Hydraulic fracturing additives used in high volume hydraulic fracturing in the UK,
2011
Appendix 4: Hydrocarbon extraction in Europe
Appendix 5: Shale gas exploration in Europe
Appendix 6: Matrix of potential impacts
Appendix 7: Evaluation of potential risk management measures
Appendix 8: List of relevant ISO standards applicable in the hydrocarbons industry
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
1 Overview of hydraulic fracturing in
Europe
1.1 Introduction
This report for the European Commission sets out the key environmental and health risk
issues associated with the potential development and growth of high volume hydraulic
fracturing in Europe. The study focuses on the net incremental risks which could result from
the possible growth in use of high volume hydraulic fracturing in Europe, over and above
those risks which are already addressed in regulation of conventional gas practices.
In order to do this, the study identifies activities involving high volume hydraulic fracturing
and their potential environmental issues which have not previously been encountered in
Europe, or which could be expected to present more significant environmental challenges.
This chapter includes the following components:

Section 1.2: a description of the study objectives

Section 1.3: a description of the EU context for shale gas extraction and hydraulic
fracturing

Section 1.4: a discussion of unconventional gas extraction techniques
In chapter 2, the key environmental risks and potential impacts are described. Drawing on
the risks identified in chapter 2, chapter 3 describes the identification and appropriateness of
applicable EU legislation, providing insights into likely and potential gaps, inadequacies and
further uncertainties.
Chapter 4 presents an overview of risk management measures summarised mainly on the
basis of the North-American experience. Key risk management measures are discussed in
chapter 5 in relation to regulatory gaps, inadequacies and uncertainties identified in chapter
2. A glossary of some relevant terms is provided in Appendix 1.
In this report, peer reviewed references are denoted “ PR ” and non-peer reviewed
references are denoted “ NPR ”.
1.2 Objective of the study
At present, a considerable number of EU Member States are interested in developing shale
gas resources, if possible. Member States active in this area include Poland, Germany,
Netherlands, UK, Spain, Romania, Lithuania and Denmark. Sweden, Hungary and other EU
Member States may also be interested in developing activity in this area. However, in
response to concerns raised by the general public and stakeholders, several European
Member States have prohibited, or are considering the possibility to prohibit the use of
hydraulic fracturing. Concurrently, several EU Member States are about to initiate
discussions on the appropriateness of their national legislation, and are considering the
possibility of introducing specific national requirements for hydraulic fracturing.
In its meeting of 4 February 2011, the European Council concluded that Europe should
assess its potential for sustainable extraction and use of conventional and unconventional
fossil fuel resources.2 A 2011 report commissioned by the European Parliament drew
2
European Council, Conclusions on Energy, 4 February 2011 (http://www.consilium.europa.eu/uedocs/cms_Data/docs/pressdata/en/ec/
119141.pdf)
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
attention to environmental risks associated with shale gas extraction (Lechtenböhmer et al.
2011, NPR). More recently, a number of reports that looked at opportunities and challenges
of unconventional fossil fuels and shale gas developments have found that producing
unconventional fossil fuel resources generally imposes a larger environmental footprint than
conventional developments. These studies indicate that robust regulatory regimes would be
required to mitigate risks and to improve general public confidence (e.g. International Energy
Agency 2012 NPR ; Exxon Mobil 2012a NPR).
Against this background, the Commission requested a specific assessment of the
environmental and health risks associated with the use of hydraulic fracturing for
hydrocarbon extraction, and in particular, shale gas extraction.
Throughout this report, the term “risk” refers to an adverse outcome which may possibly
occur as a result of the use of hydraulic fracturing for hydrocarbon extraction in Europe.
Risks may be mitigated by taking steps to reduce the likelihood and/or significance of the
adverse outcome. The term “impact” refers to all adverse outcomes – that is, those which
will definitely occur to a greater or lesser extent, as well as those which may possibly occur.
For example, the use of high volume hydraulic fracturing will definitely result in traffic
movements, and this can be described as an “impact.” High volume hydraulic fracturing may
result in spillage of chemicals, and this can be described as a “risk”.
This study focuses on environmental and health risks. The potential climate impacts of shale
gas exploration and production are not addressed in this study, but will be addressed in a
separate study commissioned by DG CLIMA.
1.3 EU Context
1.3.1 Conventional and unconventional fossil fuels
Conventional and unconventional hydrocarbons can be considered on the basis of the
resource triangle provided below (see Figure 1). Conventional resources (illustrated at the
apex of the triangle) represent a small proportion of the total hydrocarbons but are less
expensive to develop and produce. In contrast, unconventional hydrocarbons depicted by
the lower part of the triangle tend to occur in substantially higher volumes but require more
costly technologies to develop and produce.
Exploration and production in Europe has in the past mainly been focused on the apex of the
triangle. However, opportunities at the top of the triangle are becoming increasingly
inadequate to meet demand. As well as importing natural gas from outside Europe, the
industry is thus pursuing opportunities lower in the triangle as long as market conditions are
such that the opportunities are considered to be economically viable, and can attract
investment.
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Figure 1: The hydrocarbon resource triangle
"Conventional" gas is trapped in reservoirs in which buoyant forces keep hydrocarbons in
place below a sealing caprock. The combination of good permeability and high gas content
typically permits natural gas (and oil) to flow readily into wellbores through conventional
methods that do not require artificial stimulation. Conventional reservoirs are typically
sandstone, siltstone and carbonate (limestone) reservoirs (British Geological Survey, 2011
NPR). In contrast, releasing natural gas from unconventional formations and bearing rocks
requires typically a system of natural and/or artificial fractures.
Shale gas, along with tight gas and coalbed methane, is an example of unconventional
natural gas (see Figure 1). The term “unconventional” does not refer to the characteristics or
composition of the gas itself, which are the same as “conventional” natural gas, but to the
porosity, permeability, fluid trapping mechanism, or other characteristics of the reservoir or
bearing rock formation from which the gas is extracted, which differ from conventional
sandstone and carbonate reservoirs. These characteristics result in the need to alter the
geological features of the reservoir or bearing rock formation using artificial stimulation
techniques such as hydraulic fracturing in order to extract the gas.
Oil could potentially also be extracted from unconventional reservoirs such as oil shales
using hydraulic fracturing techniques. However, there is at present no indication of a
significant increase in shale oil production in Europe or the US. This study therefore focuses
on unconventional gas extraction.
Shale gas
Gas shales are geologic formations of organic-rich shale, a sedimentary rock formed from
deposits of mud, silt, clay, and organic matter, in which substantial quantities of natural gas
could be present. As described above, the shales are continuous deposits typically
extending over areas of thousands of square kilometres, (US EIA 2011 NPR Sections V, VI
and VII), have very low permeabilities and low natural production capacities. The extremely
low permeability of the rock means that shales must be artificially stimulated (fractured) to
enable the extraction of natural gas.
Gas generation in a shale formation occurs by two main processes. Both require the
presence of organic rich material in the shale:
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hydrocarbons operations involving hydraulic fracturing in Europe
1. Biogenic production related to the action of anaerobic micro-organisms at low
temperatures and,
2. Thermogenic production associated with higher temperatures and pressures and,
greater burial depths
Biogenic processes tend to produce less gas per unit volume of sediment than thermogenic
processes (New Mexico Bureau of Geology and Mineral Resources, undated NPR).
Consequently, wells used for extraction of biogenic shale gas tend to be low volume and at
shallower depths (<600 m), although this is not necessarily the case (Clayton, 2009 NPR).
The main differences between conventional reservoirs and unconventional shale gas
reservoirs are:

In conventional reservoirs the hydrocarbons have migrated (upward) from a source
rock (e.g. coal or shale). In contrast, in a shale gas reservoir, the natural gas is held
within the source rock. Because of the large areas of clay deposition in tidal flats and
deep water, shale gas reserves can cover wider areas extending to tens of thousands
of square km(US EIA 2011 NPR Sections V, VI and VII) and typically have low gas
content per rock volume;

In conventional reservoirs a stratigraphic trap or cap rock is always present (e.g. salt
or shale). With unconventional reservoirs in Europe, a cap rock is not always
present. When used in conventional reservoirs, fracturing fluids are thus always
contained by the stratigraphic trap. In unconventional reservoirs such as shale gas,
this is not always the case.

The permeability in unconventional reservoirs is significantly lower than the
permeability in unconventional (shale gas) reservoirs. Unconventional reservoirs have
a very low permeability, which ranges typically from 10-4 to 10-1millidarcy (md)3 in the
case of tight gas, or 10-5 to 5.0x10-4 md in the case of shale gas. By contrast, the
permeability of a conventional reservoir ranges from 10-1 to 104 md (Holditch 2006 PR
Figure 1; Reinicke 2011 NPR p4). The higher permeability of conventional reservoirs
means that hydrocarbons are able to flow freely to the bored well casing. USEIA
(2012 NPR) defines conventional gas production as "natural gas that is produced by
a well drilled into a geologic formation in which the reservoir and fluid characteristics
permit the oil and natural gas to readily flow to the wellbore").

In Europe, the majority of conventional oil and gas extraction has taken place
offshore. In contrast, the majority of shale gas exploration and potential is onshore.
This results in a different range of risks, potential environmental and human
exposure, and consequences to those which need to be addressed for offshore
extraction.
Considerable potential for expansion in shale gas exploration and production has been
identified in industry forecasts (PGNiG (2011 NPR) quoting Douglas-Westwood, 2011 NPR).
The United States Department of Energy (2011 NPR) estimated technically recoverable
shale gas reserves to amount to approximately 13 trillion cubic metres, approximately
equivalent to 35 years of natural gas consumption in Europe. However, questions remain
regarding the long-term viability of the industry in the light of ongoing availability of
conventional resources, questions about the lifetime of unconventional wells and preliminary
results from exploratory drilling in Poland (e.g. New York Times, June 2011 NPR ; Exxon
Mobil 2012b NPR). Only exploratory drilling can confirm the economic potential of
unconventional gas in Europe.
The low permeability of shale gas plays means that horizontal wells paired with hydraulic
fracturing are required in order for natural gas recovery to be viable. The typically extensive
3
Darcy (or darcy unit) and Millidarcy (md, or one thousandth of a darcy), are units of fluid permeability used by geologists to
characterise geological formations, in particular oil and gas reservoirs.
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hydrocarbons operations involving hydraulic fracturing in Europe
area of shale gas formations opens the possibility of extensive development of large gas
fields. This is in contrast to conventional gas extraction, which has been localised in nature
within the European gas fields (see USGS, 1997 NPR).
The majority of prospective shale gas formations in Europe can be expected to be deep – for
example, shale gas formation plays in Poland and the Baltic states are at a depth of below
2km. However, the situation is more complex in relation to the Alum Shale in the Baltic area,
and the extremely complex geology in Romania and Bulgaria. In particular, Alum Shale
reaches the near surface (<10m) in the Baltic area. In complex, folded and fractured geology
where the target formation might be close to the surface, the likelihood of any near surface
formation retaining sufficient gas to be exploitable is much lower. This is because of the
need for the formation to have been previously buried deep enough to reach the
temperatures required for gas generation, and the need for the formation to retain
impermeable rock of high integrity. Consequently, near-surface shale gas deposits are
possible in Europe, although they are not likely to be widespread. Recent industry reports
indicate that shale gas has been confirmed at shallow depths of 75 – 85 metres in the Ekeby
area, onshore Sweden (Natural Gas Europe, 2012 NPR).
Appendix 4 provides further information on conventional and unconventional hydrocarbon
extraction and resources in Europe.
1.3.2 Energy sources in Europe
Primary energy consumption in Europe between 1990 and 2008 is summarised in Figure 2.
Figure 2: Sources of primary energy consumption in Europe
Source: European Environment Agency, 2012 NPR
(http://www.eea.europa.eu/data-and-maps/figures/primary-energy-consumption-by-fuel-1)
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Natural gas accounted for approximately 25% of primary energy consumption in Europe in
2008. The vast majority of this gas production was from conventional reservoirs. No specific
figures are available for unconventional gas or oil production in Europe, most likely because
the contribution of unconventional sources is an extremely small proportion of total gas
production.
1.3.3 Definition of high volume hydraulic fracturing
From a technical viewpoint, hydraulic fracturing is the process by which a liquid under
pressure causes a geological formation to crack open. The main use of interest for the
purpose of this project is the use of hydraulic fracturing for extraction of hydrocarbons
(natural gas or oil). The process is also known as “HF”, “fracking,” “fraccing” or “fracing,” but
is referred to as “hydraulic fracturing” or “fracturing” in this report.
Within the scope of this study, hydraulic fracturing is to be understood as the cycle of
operations from the upstream acquisition of water, to chemical mixing of the fracturing fluid,
injection of the fluid into the formation, the production and management of flowback and
produced water, and the ultimate treatment and disposal of hydraulic fracturing wastewater.
Hydraulic fracturing is used for vertical wells in conventional oil and gas formations to a
limited extent in Europe and to a considerable extent in the US. Hydraulic fracturing is used
in vertical and directional wells in unconventional formations.
Use of horizontal wells
It had long been recognized that substantial supplies of natural gas were embedded in shale
rock. Horizontal drilling techniques were developed at the Wytch Farm shale oil and gas site
in the UK during the 1980s. In 2002/2003, hydraulic fracturing and horizontal drilling enabled
commercial shale gas extraction to commence in the US (SEAB, 2011a NPR ; New York
State 2011 PR Section 1). Directional/horizontal drilling techniques and hydraulic fracturing
techniques developed in the US allow the well to penetrate along the hydrocarbon bearing
rock seam. This maximises the rock area that, once fractured, is in contact with the well bore
and so maximises well production in terms of the flow and volume of gas that may be
collected from the well.
To drill and fracture a shale gas well, operators first drill down vertically until they reach the
shale formation. Within the target shale formation, the operators then drill horizontally or at
an angle to the vertical to create a lateral or angled well through the shale rock. The US EPA
(2012a NPR) indicates that horizontal well length may be up to 2000 metres. New York
State DEC (2011 PR p5-22) suggests that well lengths are normally greater than 1200
metres. In the Marcellus Shale formation in Pennsylvania, a typical horizontal well may
extend from 600 to 2,000 metres and sometimes approaches 3,000 metres (Arthur et al.,
2008 NPR). The USEPA (2011a PR) reports that horizontal wells used for unconventional
gas extraction can extend more than 1.5 km below the ground surface (Chesapeake Energy,
2010 NPR), while the “toe” of the horizontal leg can be up to 3 km from the vertical leg
(Zoback et al., 2010 NPR). This suggests that a typical horizontal section can be expected
to be 1200 to 3000 metres in length
Directional drilling is also used in coalbed methane recovery. In this case, the drilling follows
the coal seam, and is not necessarily horizontal. The term “horizontal” drilling is normally
used in respect of shale gas, and is used to represent both horizontal and directional drilling
in this report.
Definition of high volume horizontal fracturing
Because of the longer well lengths, higher pressures and higher volumes of water are
required for horizontal hydraulic fracturing compared to conventional fracturing. The
quantities of water used depend on well characteristics (depth, horizontal distance) and the
number of fracturing stages within the well. Vertical shale gas wells typically use
approximately 2,000 cubic metres water (US Department of Energy 2009 NPR pp 74-77). In
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contrast, horizontal shale gas wells typically use 10,000 to 25,000 m3 water per well, based
on the following assessments:

New York State DEC (2011 PR p3-6) indicates that a single multi-stage well would
typically use 10,800 to 35,000 m3 fluid per well.

DOE (2009 NPR p64) reports that shale gas wells typically use 10,000 – 17,000 m3
water per well, with typically 4-5 stages per well. This information is referenced by
US EPA (2011a PR p22)

BRGM suggests that horizontal wells typically use 10,000 to 20,000 m3 fluid per well
(BRGM 2011 NPR , p59).

The SEAB (2011a NPR) suggests that a shale gas well requires 4,500 to 22,500 m3
fluid per well.
The use of higher volumes of water in this way is known as high volume horizontal (or
directional) fracturing. This differentiates the use of hydraulic fracturing for unconventional
gas extraction from current hydraulic fracturing activities in Europe. High volume hydraulic
fracturing requires significantly more water than current hydrocarbon extraction techniques,
and could potentially enable the development of extensive shale gas plays in Europe which
would not otherwise be commercially or technically viable. Consequently, attention has been
focused in this study on high volume hydraulic fracturing.
In this context, the term “high volume” has been interpreted following the definition in the
New York SGEIS (State of New York, 2011 PR Glossary and section 3.2.2.1): “The
stimulation of a well using 300,000 gallons or more of water as the base fluid in fracturing
fluid.” This figure corresponds to 1,350 m3 cumulatively in the hydraulic fracturing phase.
An appropriate definition for the European context was identified by comparing the fluid
volumes used in recent test drillings against the volumes used in past hydraulic fracturing
activities. This enabled a definition to be identified which differentiates the use of hydraulic
fracturing for unconventional gas extraction from the past use of hydraulic fracturing in
conventional oil and gas wells. In the European context, it appears that a definition of 1,000
m3 per stage would be a more appropriate working definition, based on the following
observations:

For the test drillings carried out by Cuadrilla in Boxtel, the Netherlands, a hydraulic
fracturing volume of 1000m3/hour is estimated for 1 to 2 hours, per stage. No specific
information on the number of stages or actual fluid volumes are available as
exploration is currently on hold in the Netherlands, but it is expected that the total
amount of water used will be about the same as in the UK (9000 - 29000 m3/well)
(Broderick et al 2011 NPR).

For the hydraulic fracturing carried out by Halliburton at Lubocino-1 well in Poland,
1600 m3fluid was used in a single stage.

The Danish Energy Agency (2012 NPR) provided information on two examples of
hydraulic fracturing processes using some 7,000 m3 fluid to fracture 11 zones in the
first example, and 8,000 m3 fluid to fracture 11 zones in the second example. The
fracturing was carried out for tight gas extraction and involved somewhat lower
pressures, of 580 bar.
The volumes of fluid used for coal-bed methane fracturing are typically 200 m3 to 1500 m3
per well (USEPA 2011a PR p22). As coal-bed methane fracturing typically takes place
across multiple stages in a directional well, this amounts to less than 1,000 m3 per stage
(USEPA 2011a PR p22). The volumes of fluid used for fracturing of tight gas reservoirs are
also typically less than 1,000 m3 per stage (Chambers et al, 1995 NPR ; Danish Energy
Agency 2012 NPR). Consequently, these activities lie outside the scope of this project.
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1.3.4 Hydraulic fracturing practices
The US EPA describes hydraulic fracturing as:
“a well stimulation process used to maximize the extraction of underground
resources, including oil, natural gas, geothermal energy, and even water. The oil and
gas industry uses hydraulic fracturing to enhance subsurface fracture systems to
allow oil or natural gas to move more freely from the rock pores to production wells
that bring the oil or gas to the surface.
The process of hydraulic fracturing begins with building the necessary site
infrastructure including well construction. Production wells may be drilled in the
vertical direction only or paired with horizontal or directional sections. Vertical well
sections may be drilled hundreds to thousands of feet below the land surface and
lateral sections may extend 1000 to 6000 feet [300 to 2000 metres] away from the
well.
Fluids, commonly made up of water and chemical additives, are pumped into a
geologic formation at high pressure during hydraulic fracturing. When the pressure
exceeds the rock strength, the fluids open or enlarge fractures that can extend
several hundred feet away from the well.
After the fractures are created, a propping agent is pumped into the fractures to keep
them from closing when the pumping pressure is released. After fracturing is
completed, the internal pressure of the geologic formation cause the injected
fracturing fluids to rise to the surface where it may be stored in tanks or pits prior to
disposal or recycling. Recovered fracturing fluids are referred to as flowback.
Disposal options for flowback include discharge into surface water or underground
injection.”
(Taken from “Hydraulic fracturing background information,”
http://water.epa.gov/type/groundwater/uic/class2/hydraulicfracturing/wells_hydrowhat.cfm)
Typical and maximum fracture lengths are discussed in Section 1.4.2.
Hydraulic fracturing has been used in the United States for over 60 years. By the end of the
1970s, hydraulic fracturing of tight gas wells had become a proven technique for developing
commercial wells in low-permeability or tight gas formations. Hydraulic fracturing is also
widely used for conventional gas extraction in North America (CAPP, 2011 NPR) The
combination of multi-stage hydraulic fracturing and horizontal drilling for hydrocarbon
extraction has been in use for commercial extraction of shale gas in North America since
2002/2003 (SEAB, 2011a NPR p8). In Europe, the use of hydraulic fracturing for recovery of
conventional gas (that is, reservoirs with an average permeability of more than 1 milliDarcy
(mD)) is not common. This is principally because it has not in the past been economic or
necessary for field development.
The gas extraction sector has developed a number of different oil- and water-based fluids for
use in hydraulic fracturing and related treatments (US EPA 2004 NPR page 4-2). For ideal
performance, fracturing fluids should possess the following four qualities:

Be viscous enough to create a fracture of adequate width.

Maximize fluid travel distance to extend fracture length.

Be able to transport large amounts of proppant into the fracture.

Require minimal gelling agent to allow for easier degradation or “breaking” and
reduced cost.
Due to the high costs involved, horizontal drilling and hydraulic fracturing have in the past not
routinely been used for conventional hydrocarbon extraction in Europe. The use of hydraulic
fracturing for hydrocarbon extraction in Europe has been limited to lower volume fracturing of
some tight gas and conventional reservoirs in the southern part of the North Sea and in
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onshore Germany, Netherlands, Denmark and the UK. These activities did not in general
constitute High Volume hydraulic fracturing as defined in Section 1.3.3 above.
1.4
Shale gas extraction
This section provides a description of the shale gas extraction process, based directly or
indirectly on experience from North America.
1.4.1 Stages in shale gas field development
Philippe and Partners (2011 NPR p7-8) describe five stages of development of a shale gas
project covering exploration (stages 1 to 4) and commercial production (stage 5):
1. Identification of the gas reservoir. During this stage the interested company performs
initial geophysical and geochemical surveys in a number of regions. Seismic and
drilling location permits are secured.
2. Early evaluation drilling. At this stage, the extent of gas bearing formation(s) is/are
measured via seismic surveys. Geological features such as faults or discontinuities
which may impact the potential reservoir are investigated. Initial vertical drilling starts
to evaluate shale gas reservoir properties. Core samples are often collected.
3. Pilot project drilling. Initial horizontal well(s) are drilled to determine reservoir
properties and completion techniques. This includes some multi-stage hydraulic
fracturing, which may comprise high volume hydraulic fracturing. The drilling of
vertical wells continues in additional regions of shale gas potential. The interested
company executes initial production tests.
4. Pilot production testing. Multiple horizontal wells from a single pad are drilled, as part
of a full size pilot project. Well completion techniques are optimised, including drilling
and multistage hydraulic fracturing and micro seismic surveys. Pilot production
testing starts. The company initiates the planning and acquisition of rights of way for
pipeline developments.
5. Commercial development. Provided the results of pilot drilling and testing are
favourable, the company takes the commercial decision to proceed with the
development of the field. The developer carries out design of well pads, wells,
pipelines, roads, storage facilities and other infrastructure. The well pads and
infrastructure are developed and constructed, leading to the production of natural gas
over a period of years or decades. As gas wells reach the point where they are no
longer commercially viable, they are sealed and abandoned. During this process,
well pad sites are restored and returned to other uses.
1.4.2 Stages in well development
This section sets out the process of well development for an individual unconventional gas
well during the pilot drilling, pilot production testing and commercial development phases,
based on the following six stages (adapted from New York State DEC 2011 PR p5-91 to 5137):
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Figure 3: Stages in well development
Stage 1:
Site
identification
& preparation
Stage 4:
Well completion,
management of
wastewater
Stage 2:
Well design,
drilling, casing &
cementing
Stage 5:
Well production
(refracturing may
be carried out)
Stage 3:
Technical
hydraulic
fracturing
Stage 6:
Well
abandonment
Figure 4 provides an illustration of the two key stages in the hydraulic fracturing process.
Figure 4: Illustration of Well Development Stage 2
Stage 2: Well design, drilling, casing and cementing
Note: Different combinations of well casings may be used depending
on the geological and hydrogeological conditions
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Stage 3: Technical hydraulic fracturing
Source: ERG. These drawings are illustrative only, and based on US practices
These stages are described in more detail below.
Stage 1: Site identification and preparation
Site identification
The operator identifies sites to be used as well pads. An individual well pad may typically
have 6 to 10 well heads, each of which extends in a different direction from the site, covering
underground an area of up to 250 hectares (New York State 2011 PR p 5-17). Further land
would be needed at the surface for supporting infrastructure such as roads, pipelines and
storage facilities. SEAB (2011a NPR p33) reports that up to 20 wells have been constructed
on a single pad, and King (2012 PR) reports that a single 2.4 hectare well pad is used to
collect shale gas from a 2,400 hectare area, although the construction of well pads with only
1 to 2 wells is still a widespread practice at present in some states in the USA. The planned
shale gas development in the UK is intended to operate with 10 well heads per pad
(Broderick et al 2011 NPR p19). The site selection stage can have an important influence on
the potential environmental and health impacts, as discussed in Chapter 2. During the first
four stages of gas field development set out in Section1.4.1, a small number of sites will be
identified. During the commercial production stage, a much greater number of sites may be
identified (potentially up to 2,400 well pad sites within a single concession with a typical
separation of approximately 1.5 km, as discussed in Chapter 2).
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Site 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 (New York State DEC
2011 PR p5-10). Site access routes need to be designed and constructed. The well pad site
area is typically up to 3.0 hectares (New York State DEC 2011 PR p5-6), with further land
requirements needed for site access routes, pipelines and other infrastructure. Ground
surface preparation typically involves staking, grading, stripping and stockpiling of topsoil
reserves, then placing a layer of crushed stone, gravel, or cobbles over geotextile fabric.
Site preparation also includes establishing erosion and sediment control structures around
the site, and constructing pits as needed for retention of drilling fluid and, possibly,
freshwater.
Stage 2: Well design; drilling; casing; cementing; perforation
Well design; drilling; casing; cementing
Except for the use of specialized downhole tools, horizontal drilling is performed using similar
equipment and technology as vertical drilling (New York State DEC 2011 PR p5-25 to 5-17).
Wells for shale gas development using high-volume hydraulic fracturing will be drilled with
rotary rigs. Operators may use one rig to drill an entire wellbore from the surface to toe of
the horizontal bore, or may use two or three different rigs in sequence. At a multi-well site,
two rigs may be present on the pad at once, but more than two are unlikely because of
logistical and space considerations. New York State DEC (2011 PR p6-191 to 6-192)
estimates that a maximum of four wells could be drilled at a single pad in any 12 month
period.
The first drilling stage is to drill, case, and cement the conductor hole at the ground surface.
This process takes approximately 1 day, with the depth and size of the hole depending on
the ground conditions.
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. This can take up to 2 weeks or longer if drilling is slow or
problems occur. A surface casing is constructed which extends below the lowest aquifer and
is sealed to the surface. Additional casing should be provided for the surface layers (USEPA
2011 NPR p14; New York State DEC 2011 PR p5-91 to 5-92). A further intermediate casing
extends to the top of the hydrocarbon-bearing formation. Cement is pumped between the
intermediate casing and the intervening formations to isolate the well bore from the
surrounding rock, act as a barrier to upward migration through this space, and provide
support to the intermediate casing. The third drilling stage is to drill the horizontal bore.
Again, this stage would take up to 2 weeks or longer if delays occur. This gives a total
duration of the drilling stage of up to 4 weeks (Broderick et al 2011 NPR p29). The
production casing extends into the shale gas formation itself and along the horizontal bore.
In other cases, “open hole” completions are carried out, in which the production casing
penetrates the top of the producing zone only. No casing is provided for the horizontal
section of the wellbore within the production zone. This approach can be adopted in
formations capable of withstanding production conditions. The environmental risks of open
hole completions are not significantly different to those posed by standard well designs,
because the only differences are within the producing measure.
Perforation
Once the cement hardens, shaped charges are pushed down the pipe to perforate the
pipework and cement layer at the required locations. In some cases, pre-perforated liners
are used (University of North Dakota EERC, accessed 2012 NPR ; Surjaatmadja et al., 2007
PR). Surjaatmadja et al. indicate that there are limitations for using pre-perforated liners with
hydraulic fracturing, and pre-perforated liners are not widely used in the US on-shore.
Anecdotal evidence suggests that in-place perforation provides more accuracy for placing
the perforations. Perforation is not required for open hole completions.
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Installation of wellhead
The last steps prior to fracturing are the installation of a wellhead which is designed and
pressure-rated for the fracturing operation. The system is then pressure tested (New York
State DEC 2011 PR p5-92).
Stage 3: Technical hydraulic fracturing
Hydraulic fracturing fluid
Fracturing fluid is produced by mixing proppant and other additives into the substrate. Water
is the most widely used substrate. Propane gel based fluids are also available, but these are
not widely used at present (Inside Climate News 2011 NPR). This requires the
transportation of water, additives and proppant to the site. Transportation is normally by
truck, although transportation of water by pipeline is becoming increasingly common in the
USA (New York State DEC 2011 PR p5-84; Auman 2012 NPR). Appropriate transportation
is needed for all materials, and in particular, potentially hazardous additives.
The sources of water used during hydraulic fracturing activities include surface water and
ground water, which can be supplemented by recycled water from previous hydraulic
fracturing. Water, proppant and additives must be stored securely at the site, and then
mixed in the appropriate proportions, while avoiding spillage of any materials (US EPA 2011a
PR p28). The additives are designed primarily to modify the fluid characteristics to improve
the performance of the fracturing fluid. King (2012 PR) indicates that a slick water fracturing
fluid typically includes:
i. Water – About 98% to 99% of total volume
ii. Proppant – about 1% to 1.9% of total volume, usually sand or ceramic particles
iii. Friction reducer – about 0.025% of total volume, often polyacrylamide
iv. Disinfectant (biocide) – about 0.005% to 0.05% of total volume. Common biocides
include glutaraldehyde, quaternary amine or tetrakis hydroxymethyl phosphonium sulphate
(THPS) These chemicals are giving way to the use of UV light, ozone and chlorine dioxide.
v. Surfactants used to modify surface or interfacial tension, break or prevent emulsions –
about 0.05% - 0.2% of total volume
vi. Gelation chemicals (thickeners) such as guar gum and cellulose polymers are not
commonly used, but may be used in hybrid fractures which use both ungelled and gelled
water
vii. Scale inhibitors – typically phosphate esters or phosphonates
viii. Hydrochloric acid may be used in some cases to reduce fracture initiation pressure
ix. Corrosion inhibitor, used at 0.2% to 0.5% of acid volumes, and only used if acid is used.
New York State DEC (2011 PR) confirms that fracturing fluids typically consist of about 98%
to 99% water and proppant, together with 0.5% to 2% additives (New York State, 2011 PR
p5-40 and Table 5.6), as set out in Table 1.
Table 1: Fracture fluid additives (taken from New York State, 2011 PR , table 5.6)
Additive Type
Description of Purpose
Examples of chemicals
Proppant
“Props” open fractures and allows gas /
fluids to flow more freely to the well bore.
Sand [Sintered bauxite; zirconium oxide;
ceramic beads]
Acid
Removes cement and drilling mud from
Hydrochloric acid (HCl, 3% to 28%) or
casing perforations prior to fracturing fluid muriatic acid
injection, and provides accessible path to
formation.
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Additive Type
Description of Purpose
Examples of chemicals
Breaker
Reduces the viscosity of the fluid in order Peroxydisulphates
to release proppant into fractures and
enhance the recovery of the fracturing
fluid.
Bactericide / Biocide / Antibacterial Agent Inhibits growth of organisms that could
Glutaraldehyde; 2,2-dibromo-3produce gases (particularly hydrogen
nitrilopropionamide
sulphide) that could contaminate
methane gas. Also prevents the growth
of bacteria which can reduce the ability of
the fluid to carry proppant into the
fractures.
Buffer / pH Adjusting Agent
Adjusts and controls the pH of the fluid in Sodium or potassium carbonate; acetic
order to maximize the effectiveness of
acid
other additives such as crosslinkers.
Clay Stabilizer / Control / KCl
Prevents swelling and migration of
formation clays which could block pore
spaces thereby reducing permeability.
Salts (e.g., tetramethyl ammonium
chloride), Potassium chloride (KCl)
Corrosion Inhibitor (including Oxygen
Scavengers)
Reduces rust formation on steel tubing,
well casings, tools, and tanks (used only
in fracturing fluids that contain acid).
Methanol; ammonium bisulphate for
Oxygen Scavengers
Crosslinker
Increases fluid viscosity using phosphate Potassium hydroxide; borate salts
esters combined with metals. The metals
are referred to as crosslinking agents.
The increased fracturing fluid viscosity
allows the fluid to carry more proppant
into the fractures.
Friction Reducer
Allows fracture fluids to be injected at
optimum rates and pressures by
minimizing friction.
Sodium acrylate-acrylamide copolymer;
polyacrylamide (PAM); petroleum
distillates
Gelling Agent
Increases fracturing fluid viscosity,
allowing the fluid to carry more proppant
into the fractures.
Guar gum; petroleum distillates
Iron Control
Prevents the precipitation of metal oxides Citric acid
which could plug off the formation.
Scale Inhibitor
Prevents the precipitation of carbonates
Ammonium chloride; ethylene glycol
and sulphates (calcium carbonate,
calcium sulphate, barium sulphate) which
could plug off the formation.
Solvent
Additive which is soluble in oil, water &
Various aromatic hydrocarbons
acid-based treatment fluids which is used
to control the wettability of contact
surfaces or to prevent or break
emulsions.
Surfactant
Reduces fracturing fluid surface tension
thereby aiding fluid recovery.
Methanol; isopropanol; ethoxylated
alcohol
The US House of Representatives (2011 NPR page 7) found that the following chemicals
were most frequently encountered in fracturing fluids used between 2005 and 2009. A full
list of 750 chemicals is provided in Appendix A to the US House of Representatives report.
This list of chemicals does not distinguish in terms of the quantities of chemicals or their
potential hazards:

Methanol (Methyl alcohol) (as surfactant)

Isopropanol (Isopropyl alcohol, Propan-2-ol) (as surfactant)

Crystalline silica - quartz (SiO2) (as proppant)

Ethylene glycol monobutyl ether (2-butoxyethanol) (as surfactant)

Ethylene glycol (1,2-ethanediol) (as scale inhibitor)
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
Hydrotreated light petroleum distillates (as friction reducer)

Sodium hydroxide (Caustic soda) (as pH adjusting agent)
The chemicals reported as being used by Cuadrilla Resources at its Preese Hall-1 well in the
UK are provided in Appendix 3.
Based on discussions held at the Society of Petroleum Engineers (SPE) Workshop
“Reducing Environmental Impact of Unconventional Resource Development”, April 2012 (
NPR), operators are developing methods of reducing the number and quantity of chemicals
in hydraulic fracturing fluids, and improving the environmental performance of fluid additives.
Hydraulic fracturing service providers and chemical suppliers are developing schemes to
evaluate the potential human health and environmental impacts of hydraulic fracturing
chemicals. These schemes follow the UN Globally Harmonized System of Chemical
Classification and Labelling. These systems allow operators to select chemicals based on
their hazard as well as cost and effectiveness. The risks posed by flowback waters from
shale gas wells are linked to the constituents of fracturing fluids, but are also driven by the
presence of naturally occurring substances in flowback water.
Injection of fracturing fluid
When perforations are present at the appropriate point, fracturing fluid is pumped into the
well at high pressure.
The proppant is forced into the fractures by the pressured water, and holds the fractures
open once the water pressure is released. For conventional fracturing, the fracture pressure
gradient is typically 0.4-1.2 psi/foot (0.09 – 0.27 bar/metre) (derived from project team
experience). For instance, for a typical conventional well, this would correspond to
approximately500 bar, and pressures would generally be below 650 bar. The range of fluid
pressures used in high volume hydraulic fracturing is typically 10,000 to 15,000 psi (700 –
1000 bar),and exceptionally up to 20,000 psi (1400 bar). This compares to a pressure of up
to 10,000 psi (700 bar) for a conventional well. In the tight gas example from the Danish
authorities, pressures of up to 8,400 psi (580 bar) were applied.
Fracture lengths can be expected to vary depending on the geological properties of the rock
matrix and the fracture treatment. Operators have a commercial incentive to restrict the
extent of fractures to the gas-bearing formation (NETL, 2012a NPR). Davies et al. (2012 PR)
reported a maximum fracture length from several thousand shale gas fracturing operations in
the US of 588 metres. The majority of fractures were less than 100 m in length. It is not
known how many of these operations were high volume hydraulic fracturing operations, or
whether these findings would be applicable in the European setting. Similar data are
reported by Fisher and Warpinski (2012 PR Figure 2), indicating a maximum vertical fracture
extent of approximately 600 metres. The analysis carried out by Fisher and Warpinski
indicated that fracturing carried out close to the surface tended towards the formation of
horizontal fracturing, which would reduce (although not eliminate) the risk of fractures
interacting with water resources in shallower shale gas formations.
The fractures allow natural gas and oil to flow from the rock into the well.
Stage 4: Well completion and management of wastewater
Well completion and flowback handling
Following the release of pressure, injected fracturing fluids are returned to the surface as
flowback. Hydraulic fracturing fluid is typically returned to the surface over a period of
several days (Broderick et al. (2011) NPR p26) to two weeks or more (USEPA 2011a PR
page 23; SEAB 2001a NPR). Recovered fracturing fluid and produced waters from wet
shale formations are collected and sent for treatment and disposal or re-use where possible.
The latter can contain substances that are found in the formation, and may include dissolved
solids, gases (e.g. methane, ethane), trace metals, naturally occurring radioactive elements
(e.g. radium, uranium), and organic compounds.
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Wastewater – a term used to designate collectively fracturing fluids returned to the surface
as flowback and produced water – continues in many cases to flow to the surface from shale
gas wells during the well completion phase and during the production phase of the well.
After the initial recovery of hydraulic fracturing fluid, waste water usually consists of fluids
displaced from within the shale play (referred to as “produced water”) with decreasing
quantities of hydraulic fracturing fluid. Experience in the US is that between 0% and 75% of
the injected fracturing fluid is recovered as flowback (DOE 2009 NPR p66; EPA 2011 p42
NPR ; Webb 2012 PR ; a similar range was suggested by consultees).
As shale formations were originally laid down in marine environments, produced water tends
to be of high salinity. API (2010 NPR) reports that “water salinity can range from brackish
(5,000 parts per million (ppm) to 35,000 ppm TDS), to saline (35,000 ppm to 50,000 ppm
TDS), to supersaturated brine (50,000 ppm to >200,000 ppm TDS.” Hydraulic fracturing
wastewaters in Europe are expected to generally have a high salinity due to their
predominant marine origin, which may result in issues for disposal and re-use. Preliminary
data from test drilling in the north-west of England suggests total sodium chloride levels in
the range 23,000 ppm to 103,000 ppm (Broderick et al. 2011 NPR Table A.2). This covers a
wide range of salt contents, but at the upper level is of high salinity.
Hydraulic fracturing wastewater may be stored in tanks or pits prior to disposal or recycling.
In the US, hydraulic fracturing wastewater is frequently disposed to well injection facilities, or
following treatment to surface waters. A proportion of these waters can be re-used in some
cases, with operators citing goals of up to 100% recycling (New York State DEC 2011 PR
p.1-2). Techniques for recycling hydraulic fracturing wastewater are subject to rapid
development. DOE (2009 NPR p70) reported that, “With further development, such
specialized treatment systems may prove beneficial, particularly in more mature plays such
as the Barnett; however, their practicality may be limited in emerging shale gas plays.
Current levels of interest in recycling and reuse are high, but new approaches and more
efficient technologies are needed to make treatment and re-use a wide-spread reality.”
However, because recovery of fracturing fluid is incomplete (typically below 75%), fresh
water was reported as comprising 80-90% of the water used at each well for high-volume
hydraulic fracturing (New York State DEC 2011 PR p.1-2 and p5-122). The limiting factors
on re-use are the salinity and presence of other contaminants (North American regulator
consultation response 2012 NPR), the volume of flowback water recovered, and the timing of
upcoming fracture treatments (New York State DEC 2011 PR p5-122).
Friction reducers are now available which can be used in highly saline waters. A
combination of technical developments and commercial factors has resulted in increased
wastewater recycling. Yoxtheimer (2012 PR) reported that 67% of wastewater generated
from the Pennsylvania Marcellus Shale was recycled in the first half of 2011, increasing to
77% in the second half of 2011, although there is uncertainty over the typical rate of recycling
in the US, which may be significantly lower.
Typical levels of contaminants found in flowback water from shale gas extraction are set out
in Table 2 (Alley et al. 2011 PR).
Table 2: Levels of contaminants in flowback water from shale gas extraction
Parameter
Minimum(mg/L)
Maximum(mg/L)
pH
1.21
8.36
Alkalinity
160
188
Nitrate
nd
2670
Phosphate
nd
5.3
Sulphate
nd
3663
0.65pCi/g
1.031pCi/g
Radium 226 (pCi/g)
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Parameter
Minimum(mg/L)
Maximum(mg/L)
Hydrogen carbonate
nd
4000
Aluminium
nd
5290
Boron
0.12
24
Barium
nd
4370
Bromine
nd
10600
Calcium
0.65
83950
Chloride
48.9
212700
Copper
nd
15
Fluoride
nd
33
Iron
nd
2838
0.21
5490
nd
611
Magnesium
1.08
25340
Manganese
nd
96.5
Sodium
10.04
204302
Strontium
0.03
1310
nd
20
Potassium
Lithium
Zinc
As well as these contaminants, flowback waters may also contain sand, heavy metals, oils,
grease fracturing fluid additives, and naturally occurring radioactive materials (DOE 2011
NPR p21, New York State (2011 PR) p5-101, US EPA 2011a PR p43).
During the production phase, the well is connected to the gas network. During the
exploratory phases, the gas is collected and flared, although the preference is for flaring to
be minimised by connecting the well to the gas main as soon as this can be done.
The pre-production stages may last 500 to 1500 days at an individual well pad (Tyndall
Centre 2011 NPR p28).
Stage 5: Production
Before gas production can commence, pipeline infrastructure must be developed to collect
natural gas for transfer to the existing natural gas pipeline infrastructure.
Once the well is connected to the gas main, gas can be dehydrated, and then passed to the
collection system. Ongoing maintenance and monitoring is required to confirm that the gas
production process is proceeding satisfactorily without adverse environmental or health
effects.
The flow to the well can be expected to decrease rapidly following the initial phase. New
York State DEC (2011 PR p5-139) quotes operator estimates suggesting the following gas
production rates from a new well in the Marcellus shale:

Year 1: initial rate of 92,000 to 250,000 m3/day declining to 32,000 to 100,000 m3/day

Years 2 to 4: 32,000 to 100,000 m3/day declining to 14,000 to 35,000 m3/day

Years 5 to 10: 14,000 to 35,000 m3/day declining to 8,000 to 16,000 m3/day

Years 11 and after: 8,000 to 16,000 m3/day declining at 5% per annum.
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
An operator may choose to re-fracture a well in order to increase the rate of gas production,
if this is considered worthwhile from a commercial perspective (ICF, 2009 NPR p20).
Experience in the US suggests that wells are likely to be re-fractured infrequently – either
once every 5 to 10 years, or not at all. The situation in the US regarding re-fracturing is not
clear at present (New York State DEC 2011 PR p5-98), and it is not clear whether this
experience is transferrable to the European context. For the present study, it has been
assumed that re-fracturing may be carried out once over a 10 year period, while recognising
that this is an area of uncertainty. Well lifetime may be between 10 years and 30 years (New
York State DEC 2011 PR p6-276) or 40 years (US National Parks Service 2009 NPR). This
is also subject to considerable uncertainty at present, with indications that well lifetime may
be shorter than anticipated. A lifetime of up to 40 years suggests that wells may be
refractured between zero and four times during their operational lifetime.
Stage 6: Abandonment
When the well is no longer economic to operate, it is taken out of service temporarily or
permanently. Abandonment takes place in accordance with established procedures in the oil
and gas production industry. Abandonment procedures for use in the conventional oil and
gas industry in Europe have been specified by national regulators (e.g. Norsok Standard D010 is applied in Norway; see also Oil and Gas UK 2012 NPR). Abandonment procedures
include the installation of a surface plug to stop surface water seepage into wellbore. A
cement plug is installed at the base of the lowest underground source of drinking water to
isolate water resources from potential contamination by hydrocarbons or other substances
migrating via the well bore. A cement plug is also installed at the top of the shale gas
formation.
1.4.3 Comparison of high volume hydraulic fracturing and conventional
hydrocarbon extraction practices
Table 3 below sets out the stages of a high volume hydraulic fracturing activity, and
summarises the differences between this and conventional hydrocarbon production (adapted
from USEPA 2011a PR and New York State DEC 2011 PR).
Early evaluation drilling referred to in Section 1.4.1 would not require hydraulic fracturing.
Drilling carried out at the pilot testing stage would require hydraulic fracturing. As of 2012 in
Europe, pilot testing only has been carried out for shale gas. As discussed previously, the
majority of drilling and hydraulic fracturing activity would be carried out during the production
stage.
Table 3: High Volume Hydraulic Fracturing: Stages, Steps, and Differences from
Conventional Hydrocarbon practices
Development
& Production
Stage
Site Selection
and
Preparation
Step
Site identification
Site selection
Decision factors
Production yield versus
development cost
Number of wells required
Proximity to buildings / other
infrastructure
Geologic considerations
Proximity to natural gas pipelines
Feasibility of installing new
pipelines
Site area (around 3 hectares/well
needed during fracturing)
Ref: AEA/ED57281/Issue Number 17
Differences from Conventional Hydrocarbon
practices
None
Many more shale gas wells are required for
recovery of a given volume of gas than for
recovery of the same volume of gas from
conventional reservoirs. Of the order of 50 shale
gas wells might be needed to recover the same
volume of gas as a typical North Sea well (see
Section 2.1.2).
None
None
None
None
More space required during hydraulic fracturing
for tanks / pits for water / other materials required
for fracturing process (New York State 2011 PR
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hydrocarbons operations involving hydraulic fracturing in Europe
Development
& Production
Stage
Step
Decision factors
Differences from Conventional Hydrocarbon
practices
p5-6)
More lorry movements during hydraulic fracturing
than conventional production sites due to need to
transport additional water, fracturing material
(including sand/ceramic beads) and wastes
Availability and cost of water
Obtaining large volumes of water (10,000 to
supply and wastewater disposal
25,000 m3 per well) (see1.3.3)
Disposing of large volumes of contaminated water
(up to19,000 m3flowback water per well assuming
up to 75% recovery, together with produced
water) (Derived from Broderick et al 2011 NPR)
Availability of space to store make Storage of large volumes of water (10,000 to
up water and wastewater
25,000 m3 per well) (see 1.3.3)
Will require sufficient trucks / tanks onsite to
manage flowback (e.g. 250 – 625 trucks at 40 m3
per truck) (derived from New York State DEC
2011 PR p6-302)
Number of wellheads per pad and Installation of additional tanks / pits sufficient to
per hectare
accommodate up to 25,000 m3 of make-up water
Well pad design to control run off 6-10 wells/pad (New York State 2011 PR p3-3)
and spills and contain leaks
whereas 1 well/pad has been more common for
conventional production
Amount of water / proppant
needed for production activities
Fewer wellpads/hectare: 1 multi-well horizontal
well pad can access c. 250 hectares, compared
to c.15 hectares for a vertical well pad (New York
State 2011 PR p5-17)
Separation of aquifer from
Both conventional and unconventional wells may
hydrocarbon bearing formation by be drilled through water bearing strata and need
impermeable layers
to achieve the same performance standards. The
Existence of fault / fracture zones hydraulic fracturing process places additional
stresses on the well casing, which may require
Maximising access to
changes to the well design and/or additional
hydrocarbon in strata
monitoring
Depth to target formation (vertical Horizontal drilling produces longer well bore
or horizontal)
(vertical depth plus horizontal leg) requires more
mud and produces more cuttings/well. Typically
40% more mud and cuttings for horizontal well
compared to a vertical well, depending on depth
and lateral extent ( New York State 2011 PR p534). However, horizontal wells allow access to a
greater extent of shale gas formation, and are
more effective for exploitation of a given shale gas
formation.
Horizontal drilling requires specialist equipment:
larger diesel engine for the drill rig uses more fuel
and produces more emissions. Equipment is on
site for a longer time (typically 25days for
horizontal well compared to 13days for vertical
well; New York State DEC 2011 PR p6-192).
However, horizontal wells have a smaller land
surface footprint than conventional vertical
wells(USEPA 2011a PR 3.2.1). Consequently,
horizontal drilling from a limited number of well
heads would in principle be preferable to vertical
drilling from a larger number of well heads. In
practice, horizontal drilling techniques are
normally used to open up reservoirs which would
not otherwise be viable with vertical drilling
techniques, and so this comparison is not directly
relevant.
Access roads / requirement
improvements
Site preparation
Well Design,
drilling, casing
and cementing
Selection of
horizontal vs vertical
well
Well drilling
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Development
& Production
Stage
Step
Decision factors
Casing
Well
Completion
Casing required or open hole
construction (competent
conditions only):casing would
normally be required
Conductor (for wellhead)
Surface (to isolate near-surface
aquifer from production)
Intermediate (to provide further
isolation)
Production (in target formation)
Centred casing to enable
cementing
Cementing
Correct cement for conditions in
well (e.g. geology and
groundwater) and fracturing
pressure
Hydraulic Fracturing: Quantity of water required for
Water sourcing
hydraulic fracturing
Quality of water required for
hydraulic fracturing
Source and availability of water
Impact on water resources and
surface water flows
Intensity of activity in watersheds /
geologic basins
Hydraulic Fracturing: Tailoring of fracturing fluid to
Chemical Selection
properties of the formation /
project needs
Tailoring chemicals to make up
water quality (e.g., highly saline
flowback, acid mine drainage)
Chemical
Transportation
Chemical storage
Size, type, and material of tanks
or other containers
Chemical Mixing
Quality control on site to ensure
correct mixture and avoidance of
potentially harmful spills
Hydraulic Fracturing: Use and type of explosive (not
Perforating casing
required if open-hole drilling is
carried out)
Differences from Conventional Hydrocarbon
practices
Casing material must be compatible with
fracturing chemicals (e.g., acids)
Casing material must also withstand the higher
pressure from fracturing multiple stages
Hydraulic fracturing has the potential to damage
cement: may pose a higher risk during refracturing, although unclear at present (EPA 2011
NPR p82)
Requirement to abstract and transport water to
wellhead for storage prior to hydraulic fracturing
operations
Current information indicates that the composition
of chemicals used in high volume fracturing is
similar to that used in conventional fracturing
(New York State DEC 2011 PR p5-54). Less
harmful additives are being developed and used
at lower concentrations in both conventional and
unconventional applications (King 2011 PR p39).
Record-keeping and disclosure of chemicals is
also improving (e.g. see www.fracfocus.org).
Transport of large volumes of water, chemicals
and proppant to well pad (up to 25,000 m 3 water
per well, together with a further 8-15% proppant
and 0.5-2% chemical additives; New York State
DEC 2011 PR p5-51)
More chemical storage required for high volume
hydraulic fracturing (as for transportation above)
Mixing of water with chemicals and propping
agent (proppant)
Conventional wells are hydraulically fractured in
North America, although this is uncommon in
Europe. The amount and extent of perforations
may be greater for high volume HF
Hydraulic Fracturing: Number of stages required
Monitoring requirements and interaction of
Well injection of
fracturing fluid with formation also occur in
Need to inject small amount of
hydraulic fracturing
conventional wells but more extensive in high
fluid before fracturing occurs to
fluid
determine reservoir properties and volume fracturing due to longer well length in
contact with formation (up to 2,000 metres for
enable better fracture design
HVHF compared to up to a few hundred metres
Pressure required to initiate
for conventional well depending on formation
fracturing with fracturing fluid
thickness)
without proppant dependent on
depth and mechanical properties More equipment required: series of pump trucks,
fracturing fluid tanks, much greater intensity of
of formation
Monitoring and control of hydraulic activity.
fracturing process.
Number, size, timing and
concentration of delivery slugs of
fracturing fluid and proppant
Hydraulic Fracturing: Chemical additions to break
“Flowback” of fracturing fluid and produced water
Pressure reduction in fracturing gels (if used)
containing residual fracturing chemicals, together
well / to reverse fluid Planning for storage and
with materials of natural origin: brine (e.g., sodium
flow recovering
chloride), gases (e.g., methane, ethane, carbon
management of flowback
flowback and
dioxide, hydrogen sulphide, nitrogen, helium),
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Development
& Production
Stage
Step
produced water
Well completion
(continued)
Connection of well
pipe to production
pipeline
Reduced Emission
Completion
Well pad removal
Well Production
Well Site
Abandonment
Postabandonment
Construction of
pipeline
Decision factors
recovered before the well starts
gassing (varies from 0%-75% but
strongly formation dependent).
Planning for storage and
management of smaller volumes
of wastewater generated during
production (decreasing flow rates
and increasing salt
concentrations)
During exploration phase, natural
gas is likely to be flared
Wells should be connected to
production pipeline immediately in
production phase.
Capture gas produced during
completion and route to
production pipeline or flare it if
pipeline is not available
Amount of wastewater storage
equipment to keep on site
Remove unneeded equipment
and storage ponds
Regrade and re-vegetate well pad
May need to construct a pipeline
to link new wells to gas network
Differences from Conventional Hydrocarbon
practices
trace elements (e.g. mercury, lead, arsenic),
naturally occurring radioactive material (e.g.
radium, thorium, uranium), and organic material
(e.g. acids, polycyclic aromatic hydrocarbons,
volatile and semi-volatile organic compounds)
(USEPA 2011a PR Table 5)
In principle, no difference to conventional wells.
However, potential for impacts in areas which
would not otherwise be commercially viable
Larger volume of flowback and sand to manage
than conventional wells (10,000 to 25,000 m 3 per
well) (Derived from Broderick et al 2011 NPR)
Larger well pad (with more wells/pad) with more
ponds and infrastructure to be removed, as
described above
Exploitation of unconventional resources may
result in a requirement for gas pipelines in areas
where this infrastructure was not previously
needed
Production
May need to refracture the well to Produced water will contain decreasing levels of
increase recovery. This could
fracturing fluid as well as hydrocarbons
take place up to four times over a Conventional wells are often in wet formations that
40 years well lifetime.
require dewatering to maintain production. In
Wastewater management (e.g.
these wells, produced water flow rates increase
discharge to surface water bodies, with time. In shale and other unconventional
reuse or disposal via underground formations, produced water flow rates tend to
injection including transport to
decrease with time.
disposal site)
Remove pumps and Need to install surface plug to
Abandonment of unconventional wells is similar to
downhole equipment stop surface water seepage into
abandonment of conventional wells.
Plugging to seal well wellbore and migrating into
ground water resources
Need to install cement plug at
base of lowermost underground
source of drinking water
Need to install cement plugs to
isolate hydrocarbon,
injection/disposal intervals
Potential for methane Proper design and construction of Abandonment of unconventional wells is similar to
seepage to occur in well plugs and liners.
abandonment of conventional wells.
the long-term if seals Long-term monitoring programme
or liners break down of abandoned wells
1.5 Short chronological summary of use of hydraulic
fracturing and horizontal drilling
Shale gas was first extracted in the 1920s in the US. Horizontal well drilling was first carried
out in 1929. The first use of hydraulic fracturing for hydrocarbon extraction was in 1947 in a
short vertical well. The process rapidly developed to commercial use in the US during the
1950s and 1960s. High volume hydraulic fracturing was first used in the Barnett Shale in
Texas, U.S. in 1986. The first economical horizontal well in the Marcellus Shale,
Pennsylvania was drilled in 2003 (Harper 2008 PR ; Montgomery 2010 PR ; Givens 2005
NPR).
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Hydraulic fracturing appears to have been introduced in Europe in the early 1980s. Multistage hydraulic fracturing in tight gas reservoirs has been carried out in horizontal wells in
the Soehlingen field in Germany, and in the South Arne field in Denmark (Rodrigues and
Neumann, 2007 NPR ; Danish Energy Ministry 2012 NPR). Hydraulic fracturing has been
carried out elsewhere in Germany (Reinicke 2011 NPR p11), as well as the Netherlands
(NOGEPA, 2012 NPR) and the United Kingdom (UK Department of Energy and Climate
Change, 2012 NPR). These fracturing operations did not use sufficient fluid to be classified
as HVHF.
Exploratory drilling for shale gas with hydraulic fracturing in Germany, Poland and the UK
commenced in 2010. Appendix 5 provides further information on shale gas development in
Europe.
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
2 Impacts and risks potentially
associated with shale gas
development
2.1 Introduction
2.1.1 Background
The US Department of Energy identified four major areas of concern for potential human and
ecosystem impacts with regard to the use of hydraulic fracturing for shale gas production
(SEAB, 2011a NPR):

Possible pollution of drinking water from methane and chemicals used in fracturing
fluids;

Air pollution;

Community disruption during shale gas production; and

Cumulative adverse impacts
The potential significance of local effects, together with cumulative and regional effects of
multiple drilling, hydraulic fracturing, production and delivery activities on the environment
was also highlighted by the International Energy Agency (2012 NPR p14), which noted in
particular the potential cumulative effects on water use and quality, land use, air quality,
traffic and noise as well as the issue of waste water management
New York State DEC (2011 PR p11-2 to 11-9) identified impacts associated with the
following resources:

Potential effects on people (e.g. via noise, radioactive materials, air emissions)

Water resources

Sensitive ecosystems and species

Air quality

Visual quality of the landscape

Transportation
The USEPA (2011a PR p viii) focused specifically on the relationship between hydraulic
fracturing and drinking water resources.
The range of potential hazards identified in these key references were considered
systematically at each stage of the HVHF process, to enable the risks associated with each
aspect of HVHF to be characterised in a preliminary manner, considering the limits of the
exercise, as indicated below.
When considering environmental risks and impacts, it is important to consider the probability
and severity of a possible event. King (2012 PR) suggests categorising events according to
the significance of impacts on people and the environment, and according to experience of
the frequency of their occurrence, consistent with more general guidance on environmental
risk assessment (e.g. UK Department for Environment, Transport and the Regions, 2000
NPR). The activities identified by King (2012 PR) as potentially significant are:
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe

transport of fracturing materials to the well

the specific act of fracturing

recovery of hydraulic fracturing wastewater from the well ; and

the transport of wastewater from the well
A wider range of impacts was considered in the present study, in accordance with the project
specification.
2.1.2 Study approach and limitations
The study uses a preliminary risk screening approach to identify the most significant risks
which require consideration in the study. This is described in Section 2.2. This review
considered all potential issues identified during the literature review, discussion with
consultees, and from the knowledge of the project team. The review focused in particular on
the issues which differ for HVHF compared to conventional oil and gas extraction.
The preliminary risk screening approach was applied by developing criteria for evaluating the
potential significance and likelihood of impacts occurring. Each potential issue was
considered against these criteria to the extent permitted by the available information. The
study authors duly acknowledge the limits of this risk screening exercise, considering notably
the absence of systematic baseline monitoring in the US (from which most of the examined
literature sources come from), the lack of comprehensive and centralised data on well failure
and incident rates, and the need for further research on a number of possible effects
including long term ones. Greater weight was given to information available in peer reviewed
publications, the number of which is limited. In carrying out this analysis, it was assumed
that controls normally applied in the oil and gas extraction industry in Europe would be
applied to shale gas extraction.
Ideally, a comparison of risks and impacts with conventional gas extraction would be made
on the basis of the impacts per unit of energy extracted. Within the constraints of this
project, it was not possible to develop this analysis, and furthermore the data on the scale of
impacts and their frequency are not available or sufficiently robust to enable this analysis to
be carried out for the majority of potential impacts under consideration. In particular, there is
no clear indication of the volume of gas likely to be recoverable from shale gas wells in
Europe (the “Estimated Ultimate Recovery” or EUR”). New York State DEC (2011, p5-139)
quotes a range of 60 to 280 million m3 EUR per well for the US. Lechtenböhmer et al. (2011
NPR) and US EIA (2010 NPR) indicate that the figure of 60 million m3 is more likely to
represent an upper limit for EUR from the Marcellus shale, and lower recoveries would be
applicable from other US formations. These gas volumes may not be economically
recoverable in practice. It is not possible to state whether this wide range would be
representative of EURs in Europe. For comparison with conventional gas extraction, a
conventional North Sea gas well might result in recovery of up to 2,800 million m3 of natural
gas based on unconfirmed information – that is, it is likely that many more wells would be
needed to extract unconventional gas compared to conventional gas.
2.1.3 Cumulative impacts
The development of shale gas plays opens the possibility of development of gas extraction
infrastructure over a wide area. Consequently, cumulative risks need to be taken into
account in the risk assessment. This was carried out by separately evaluating the risks
posed by development of individual installations, and the risks posed by development of an
entire shale gas play. Shale gas infrastructure may cover an area of several tens of
thousands of square kilometres. For example, in Poland, concessions may extend up to
1,200 km2, and there is no limit to the number of concessions that an individual company
may hold (Baginski, 2010 NPR p150). Chevron reports the acquisition of a 6,100 km2
concession in Romania (Chevron, 2012a NPR).
Ref: AEA/ED57281/Issue Number 17
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hydrocarbons operations involving hydraulic fracturing in Europe
The current trend towards the use of multi-well pads, in which up to 10 wells may be placed
on a single pad mitigates these impacts to some extent. New York State (2011 PR p5-17)
indicates that one well pad may allow approximately 250 hectares of shale formation to be
accessed (a similar value of 259 hectares was derived from DOE, 2009 NPR). This would
correspond to a typical separation between well pads of approximately 1.5 km. Over an area
of 6,000 km2, this would correspond to up to 2,400 multi-well installations, occupying
approximately 1.4% of the land area. The potential for cumulative effects was assessed on
the basis of development of this scale. The rate of well pad development is likely to be
limited by the availability of plant and equipment. For the purposes of this assessment, it
was assumed that development of an individual shale gas concession could proceed at up to
5% of the rate of well development in the US as a whole (PGNiG 2011 NPR quoting
Douglas-Westwood 2011 NPR) – that is, approximately 850 wells per year with development
of up to 85 well pads per year.
This is comparable to the highest number of wells forecast to be drilled in any EU state for
the period up to 2020 (1090 wells for Poland) (PGNiG 2011 NPR quoting Douglas-Westwood
2011 NPR). This is also comparable to the total of approximately 710 shale gas wells drilled
in Pennsylvania during 2009 (Cuadrilla Resources Ltd 2011 NPR p12). The area of
Marcellus Shale formation in Pennsylvania is approximately 250,000 square kilometres, of
which only a fraction has been developed (Cuadrilla Resources Ltd 2011 NPR p40). This
suggests that the assumed rate of intensive development of a shale gas play in Europe is
likely to be an over-estimate of the rate of development that would arise in practice.
This assessment allowed risks to be preliminary screened to identify those of greater
significance. Potentially significant risks were then considered in the context of the
legislative analysis described in Chapter 3.
2.1.4 Study scope and boundaries
Following the description of the hydraulic fracturing process in Chapter 1, the following
aspects fall under the scope of the assessment:

water withdrawal

transport of fracturing materials to the well

mixing of chemicals and use in the specific act of fracturing

recovery, treatment and disposal of wastewater

well abandonment and post-abandonment,

cumulative effects associated with development over a wide area
The study considers the direct environmental and health issues associated with these
aspects of shale gas extraction. The study is not a “life-cycle” assessment, and
consequently the risks associated with secondary processes are outside the scope of the
study (e.g. the specific risks/impacts, resources and energy consumed in order to
manufacture sand and other proppants, gravel, stone and chemical additives for well pad
construction; or to construct and maintain road and pipeline infrastructure; or to produce
fracturing fluids).
The potential impacts associated with traffic have been highlighted as a distinct issue from
the impacts associated with the gas extraction process itself and associated infrastructure.
Some of the impacts associated with traffic (such as emissions of air pollution, noise impacts
and land take) can be expected to be similar in nature to those of the gas extraction process,
whereas others (such as impacts on community severance or accident risks) differ in nature.
The nature of the sources and the relevant control measures are sufficiently different for it to
be useful to consider traffic-related impacts as a distinct but related issue.
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
The study inevitably draws on experience from the US, but where possible the findings from
the US have been set in the European regulatory and technical context.
This study is not designed to draw conclusions on the potential significance of hazards posed
by specific installations in Europe or the US. The approach taken is to draw on published
information in relation to environmental and health risks, and make a preliminary judgment in
terms of the potential significance of the hazards under consideration for the use of HVHF in
Europe. The basis for reaching each preliminary judgment is set out in the text following
each classification in the sections below.
2.1.5 Summary of impacts
Tables A5.1, A5.2 and A5.3 in Appendix 6 summarise the potential environmental impacts of
hydrocarbons operations involving high-volume hydraulic fracturing (adapted from USEPA
2011a PR and other references).
These tables classify potential impacts as follows:

Impacts which are unique to hydraulic fracturing, but which are likely to be more
significant for high-volume hydraulic fracturing than for other hydraulic fracturing
activities;

Impacts which are common to hydraulic fracturing and conventional exploration /
extraction practices in Europe, but which are more significant with hydraulic
fracturing;

Impacts which are common to both hydraulic fracturing and to conventional practices
in Europe.
2.2 Risk prioritisation
2.2.1 Risk prioritisation framework
A preliminary risk prioritisation approach has been adopted to enable potential impacts to be
evaluated.
King (2012 PR) sets out a useful basis for risk prioritisation in the context of shale gas
development. This follows established principles of screening and prioritisation for
environmental risk and impact assessment and management (e.g. UK Department for
Environment, Transport and the Regions, 2000 NPR).
The risk prioritisation was carried out by classifying environmental hazards and hazards for
people on the following basis:

Slight: Slight environmental effect– e.g. a planned or unplanned discharge which
does not result in exceedances of an environmental quality standard

Minor: Minor environmental effect – e.g. a planned or unplanned discharge which
could result in exceedances of an environmental quality guideline in the immediate
vicinity of the release point, but which would not be expected to have significant
environmental or health effects

Moderate: Localised environmental effect – e.g. a discharge or incident resulting in
potential effects on natural ecosystems in the vicinity of the release point or incident;
ongoing effects on people in the vicinity of a site due to impacts such as noise, odour
or traffic

Major: Major environmental effect – e.g. an ongoing discharge resulting in persistent
exceedances of European environmental quality standard; permanent degradation of
a protected habitat
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe

Catastrophic: Massive environmental effect – e.g. a pollution incident resulting in
harm to the health of members of the public over a wide area due to contamination of
drinking water supplies; accident resulting in death or serious injury to workers and/or
members of the public.

No data: Insufficient data to allow a preliminary judgment to be reached
The frequencies or probabilities of hazards occurring were classified on the following basis
(adapted from King, 2012 PR):

Rare: Encountered rarely or never in the history of the industry; not forecast to be
encountered under foreseeable future circumstances in view of current knowledge
and existing controls on oil and gas extraction.

Occasional: Encountered several times in this industry; could potentially occur under
foreseeable future circumstances if management or regulatory controls fall below best
practice standards

Periodic: Occurs several times a year in this industry; a short-term impact would be
expected to occur with the use of hydraulic fracturing for hydrocarbon operations

Frequent/definite: Occurs several times a year at a specific site; a long-term impact
would be expected to occur with the use of hydraulic fracturing for hydrocarbon
operations

No data: Insufficient data to allow a preliminary judgment to be reached
In environmental risk assessment studies of hazard significance and probability, it is often
necessary to use some judgment because of uncertainty associated with the evidence base.
This was the case for the present study. The frequency or probability of hazards occurring
was estimated from reported analysis of hydraulic fracturing activities in the field where this
was available. As indicated above, independent and comprehensive information for instance
on well failures and incident rates is limited, which makes this risk prioritisation exercise a
preliminary one, pending additional data. Indeed the absence of evidence of hazards does
not necessarily mean evidence of the absence of hazards. Where expert judgment needed
to be used, this was noted in the text.
Considering the hazard significance and associated probability enables risks to be prioritised
and screened, as set out in Table 4 (adapted from King 2012 PR , after DeMong et al., 2010
PR).
Table 4: Risk ranking table
Probability
classification
Hazard classification
Slight
Minor
Moderate
Major
Catastrophic
Rare
Low
Low
Moderate
Moderate
High
Occasional
Low
Moderate
High
High
Very high
Periodic/short
term definite
Low
Moderate
High
Very high
Very high
Frequent/longterm definite
Moderate
High
Very high
Very high
Very high
No data
No data
Not
classifiable
Not classifiable
Where more than one scenario is envisaged, the combination giving rise to the highest
ranking is presented. Risks can then be screened and prioritised as follows:

Green: Low risk

Yellow: Moderate risk
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Support to the identification of potential risks for the environment and human health arising from
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
Orange: High risk

Red: Very high risk
This approach is useful for evaluating individual risks, and has been applied in the following
sections to characterise the potential risks which could occur if specific mitigation in relation
to the risks posed by shale gas extraction is not carried out.
2.2.2 Well lifetime and re-fracturing
Conventional and unconventional gas well production rates tend to drop after a period of
time. An operator may choose to re-fracture the well, in order to increase the gas flow rate.
As discussed in Chapter 1, this may take place approximately once every 10 years, or
between 0 and 4 times over a well lifetime of up to 40 years while recognising that this is an
area of uncertainty.
In practice, the evaluation in this chapter is not sensitive to the assumed frequency of refracturing, because the study is designed to be applicable to a wide range of circumstances
involving the potential for development of multiple well pads in a local area such as a
municipality, and across a wider area of thousands of square kilometres.
2.3 Stages in shale gas development
A shale gas development project is carried out in five main stages (Philippe and Partners,
2011 NPR p7-8; see Section 1.4) covering exploration (stages 1-4) and production (stage 5):
1. Identification of the gas resource.
2. Early evaluation drilling.
3. Pilot project drilling.
4. Pilot production testing.
5. Commercial development.
The exploration phase initially consists of drilling and fracturing a small number of vertical
wells (typically only two or three wells) to determine if shale gas is present and can be
extracted. A ‘plug and perforate completion’ technique tends to be used in the exploration
phase. The well is lined and then perforated at certain points. Sections with the perforations
are isolated with cement plugs before being fractured. The plugs are drilled through to allow
the gas to flow to the surface where the potential for further development can be appraised.
If the initial indications are favourable, more wells (typically 10 to 15 wells) are drilled and
fractured to characterise the shale, examine how fractures will tend to propagate and
establish if the play could produce gas economically. Further wells (typically up to 30 wells)
may be drilled to ascertain the long-term economic viability of the play (Royal Society and
Royal Academy of Engineering (UK) 2012 PR).
The exploration phase is important in relation to the impacts of these pilot drilling and
fracturing activities themselves, as well as in influencing the areas where full-scale shale gas
extraction will take place.
For an individual unconventional gas well, the process of well development is as follows
(again as described in Chapter 1.4.2):
1. Well pad site identification and preparation
2. Well Design, Drilling, Casing and Cementing
3. Technical Hydraulic Fracturing Stage
4. Well Completion (flowback)
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hydrocarbons operations involving hydraulic fracturing in Europe
5. Well Production
6. Well Abandonment
The remaining part of this chapter focus on the above six stages of well development and the
key risks associated with each individual stage and for the total project.
2.4 Stage 1: Well pad site identification and preparation
Stage 1
Stage 2
Stage 3
Stage 4
Stage 5
Stage 6
2.4.1 Surface water contamination risks
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
minor
moderate
Probability
classification
rare
rare
Risk ranking
low
moderate
Peer reviewed research
Runoff and erosion during early site construction may lead to silt accumulation in surface
waters (This has a greater potential risk in HVHF because of larger well pads and storage
impoundment construction). New York State DEC 2011 PR (page 6-14) highlights the
particular risk of stormwater runoff leading to contaminants such as nutrient phosphorus and
nitrogen, hydraulic oil, fuel and lubricating fluids entering water bodies, streams and
groundwater. Common to industrial activity and construction sites generally, this impact
relates to the extent of groundworks and the nature of surface construction (roads, concrete
areas etc). The larger footprint of high volume multi-well pad installations (up to 3.0
hectares/pad; New York State 2011 PR p5-6) compared with those for conventional gas
(c.1.9 hectares/pad) as well as larger storage impoundments make this an elevated risk of
the former when assessed on a “per site” basis.
For similar reasons, shale gas installations have greater scope for habitat impacts directly
associated with stormwater runoff, through the impact this has on the erosion of streams,
sediment build-up, water quality degradation and potentially flooding. These stormwater
impacts can be mitigated to an extent through managed drainage and controls on potential
groundwater contaminants.
Other research
Other research was not used in this evaluation.
Preliminary judgment
As the risks to habitat sites are well understood for similar installations resulting in minimal
impacts, the potential significance was considered to be “low”.
The potential cumulative effects on water quality due to development of multiple sites over an
area of hundreds or thousands of square kilometres are a potential concern. As potential
impacts could be additive, the potential significance of cumulative effects was considered to
be “moderate”.
2.4.2 Release to air
Risk Characterisation
Individual installation
Ref: AEA/ED57281/Issue Number 17
Hazard
classification
slight
Probability
classification
short-term definite
Risk ranking
low
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Cumulative effects of multiple installations
slight
short-term definite
low
Peer reviewed research
Heavy machinery/installations used for site preparation and construction give rise to exhaust
emissions. At the site construction stage, these are not significantly different to emissions
from any other similar construction activity, although the larger well pad site area in the case
of HVHF means that emissions would be greater for HVHF than for conventional gas
extraction. Adopting the findings of New York State (2011 PR p5-6) that the well pad may be
approximately 60% larger for HVHF than for conventional gas, releases to air may be also
expected to be approximately 60% higher. Attention is normally focused on diesel engine
emissions during the drilling and fracturing stages (Howarth and Ingraffea, 2011 NPR) rather
than the site preparation phase, and are of less concern during site preparation. In this
context, diesel engine emissions do not pose a significant environmental or health risk, and
were assessed as a hazard of “slight” significance.
Similarly, there is a risk of fugitive emissions to air in the event of an equipment fuel or oil
spillage, but this risk would be common to any similar activity and controlled via normal
procedures for the oil and gas industry.
The well pad construction phase may be expected to last up to 4 weeks per well pad (New
York State 2011 PR p5-135).
Other research
Lechtenböhmer et al. (2011 NPR) concur that diesel engine emissions during the drilling and
fracturing stages are an area of concern, and hence are not of significance at the site
preparation stage.
Broderick et al (2011 NPR , p28) concur that the well pad construction phase may be
expected to last up to 4 weeks per well pad.
Preliminary judgment
A consistent view was identified that emissions to air during site preparation are of less
concern than emissions during later stages in the project. In this context, diesel engine
emissions would not pose a significant environmental or health risk, and were assessed as a
hazard of “slight” significance.
Although no specific information was available with regard to the risks posed by fugitive
emissions to air following a fuel or oil spillage, because these risks would be common to any
similar activity, it was judged that this potential impact would be of “slight” significance.
Although no specific information was available in relation to cumulative impacts, in view of
the limited significance of emissions to air during well pad site preparation, and with a typical
well pad separation of approximately 1.5 km, it is judged unlikely that the cumulative effect of
emissions to air during this phase could pose a significant risk to air quality in the context of
wider sources of emissions to air such as road traffic. This was therefore assessed as a
hazard of “slight” significance.
2.4.3 Land take
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Ref: AEA/ED57281/Issue Number 17
Hazard
classification
minor
major
Probability
classification
short-term definite
short-term definite
Risk ranking
moderate
very high
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Peer-reviewed research
According to New York State DEC (2011 PR p5-6) land disturbance directly associated with
high-volume hydraulic fracturing will consist primarily of constructed gravel access roads,
well pads and utility corridors. It explains how well numbers and pattern layouts contribute to
the overall pad size. Well pad equipment includes pits, impoundments, tanks, hydraulic
fracturing equipment, reduced emission completion equipment, dehydrators and production
equipment such as separators, brine tanks. Additionally, construction of pipelines would
require land-take during the construction and operational phases. Pipelines may be buried
which could enable this land to be returned to the previous use, or other beneficial use such
as agriculture or road verges.
In the present study, the potential risks and impacts associated with the production of
materials needed for road construction, such as minerals (gravel, stone, etc) and energy
inputs associated with the production of these materials, are not assessed (see
Section2.2.1).
Surface installations require an area of approximately 3.0 hectares per pad for high volume
hydraulic fracturing during the fracturing and completion phases, compared to 1.9 hectares
per pad for conventional drilling (New York State DEC 2011 PR Table 5.1) The additional
area for HVHF well pads is needed to accommodate the equipment and storage tanks/pits
required for up to 30,000 m3 of make-up water, together with chemical additives and waste
water.
Multi-well pads are now in widespread use for shale gas extraction. This enables a single
pad to accommodate 6-10 wells (New York State 2011 PR p3-3), resulting in a lower land
take impact compared to 1 well/pad for conventional production. This enables a single multistage horizontal well pad to access approximately 250 hectares of shale gas play, compared
to approximately 15 hectares for a vertical well pad (adapted from New York State 2011 PR
p 5-17). Assuming 3.6 hectares per multi-well pad (see below), this suggests that
approximately 1.4% of the land above a productive shale gas reservoir may need to be used
to fully exploit the reservoir, or more if other indirect land-uses (e.g. central storage facilities
and pipelines) are taken into account.
It may not be possible to fully restore a site in a sensitive area following well completion or
well abandonment. For example, sites in areas of high agricultural, natural or cultural value
could potentially not be fully restorable following use.
As well as the well pads themselves, the associated infrastructure (access roads and
pipelines) also results in land take and habitat fragmentation. For example, Sutherland et al.
(2011 PR) highlight that over 30% of the 8,900 km2 forests of the State of Pennsylvania have
been made available for natural gas extraction, although only around 1.4% of this area (or
less than 0.5% of the total forest area) would be taken for use in well pad development.
The use of land for gas development could be viewed as incurring an “opportunity cost” due
to its unavailability for other, potentially more beneficial, uses. These opportunity costs have
not been taken into account in this study.
Other research
The New York State DEC estimate of well pad area is consistent with a study carried out by
the Nature Conservancy (2011 NPR p18) who estimate that 3.6 hectares of forest land would
be taken per well pad, including roads and other infrastructure.
US DOE (2009 NPR) confirms the land requirements for conventional installations and
installations using HVHF.
Lechtenböhmer et al.(2011 NPR page 21)highlight the potential significance of land take and
habitat fragmentation due to associated infrastructure (access roads and pipelines).
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hydrocarbons operations involving hydraulic fracturing in Europe
Preliminary judgment
Land-take associated with an individual site is within the normal range of commercial and
infrastructure developments in Europe, and it was judged that this can be considered as a
minor impact. The cumulative land-take impact of 1.4% for full development of a gas
reservoir compares to 4% of land in Europe currently occupied by “artificial areas” such as
housing, industry and transportation. This is judged to be of potentially major significance,
and would be a short-term impact likely to be associated with the full development of any
large shale gas concession and therefore classified as “short term definite” likelihood.
2.4.4 Biodiversity impacts
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
minor
not classifiable
Probability
classification
not classifiable
not classifiable
Risk ranking
not classifiable
not classifiable
Peer-reviewed research
The term "biodiversity” refers to the variability among living organisms from all sources; …
this includes diversity within species, between species and of ecosystems (adapted from the
Convention on Biological Diversity). For the purposes of this project, “biodiversity” refers to
the range of species supported by the ecosystem(s) surrounding a shale gas development or
area of shale gas development, and the evaluation considers the risks to these species and
ecosystems which could potentially result in a loss of biodiversity.
Gas extraction can affect biodiversity via a number of routes (New York State DEC 2011
Section 6.4; Entrekin et al. PR 2011). These include:

removal of habitat (addressed in Section 2.4.3 above) or degradation of habitat (e.g.
as a result of excessive water abstraction); or fragmentation (e.g. as a result of
fencing, road construction)

introduction of invasive species;

noise and other disturbance

water and land pollution
An invasive species is a species that is not native to the ecosystem under consideration and
whose introduction causes or is likely to cause economic or environmental harm or harm to
human health. Invasive species can be plants, animals, and other organisms such as microorganisms, and can impact both terrestrial and aquatic ecosystems (New York State DEC
2011 PR p 6.4.2). New York State DEC highlights the potential effects on biodiversity due to
invasive species as a potential concern.
The main impacts at the site preparation stage would be associated with habitat loss or
fragmentation, following land take as described in Section 2.4.3. At this stage, the risks
posed by sediment runoff into streams and potential contamination of streams from
accidental spills should be considered, in order to minimise the risk of impacts at a later
stage in the process (Entrekin et al., 2011 PR p8). Entrekin et al. conclude that there are
preliminary indications of detectable effects of sedimentation of watercourses due to shale
gas development, and consider that scientific data are needed to ensure protection of water
resources.
Other research
Lechtenböhmer et al.(2011 NPR page 19) found that there were no documented effects of
shale gas extraction on biodiversity. The EPA (2012 NPR p9) highlighted a local issue linked
to the introduction of algae into local water courses, resulting in major fish kills. Locally-
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
gathered evidence indicates that gas extraction can affect biodiversity via the introduction of
invasive species and via habitat loss (e.g. Heatley, 2011 NPR) but this evidence has not
been published for external verification.
The Nature Conservancy (2011 NPR page 18) confirmed that development of well pads in
forest areas in Pennsylvania affects a wider area than the site area itself. It was estimated
that the area indirectly affected would be approximately an additional 2.4 hectares for every
hectare of well pad area, or an additional 9 hectares per well pad.
Preliminary judgment
The risks to biodiversity arise due to accidental releases and habitat loss (up to 1.4% of
habitat may be lost, with a further 3.4% of habitat indirectly affected). In view of the absence
of published peer-reviewed research in this area, the risks to biodiversity posed by these
impacts remains an area of plausible concern, but without a clear evidence base.
It was judged that the impacts on biodiversity associated with individual sites are likely to be
limited to the vicinity of the site, supported by the conclusions of Entrekin et al. (2011 PR
p8)and Nature Conservancy (2011 NPR). It was judged that cumulative effects of
development of multiple sites could be more widespread, but it was not possible to classify
the potential significance of these impacts.
It was judged that impacts associated with disturbance and potential for introduction of
invasive species would be less than at other stages in the process. No information on the
likelihood of impacts occurring during this stage of shale gas development was identified.
2.4.5 Noise
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
slight
minor
Probability
classification
periodic
rare
Risk ranking
low
low
Peer-reviewed research
Noise from excavation, earth moving, other plant and vehicle transport could affect
residential amenity and wildlife, particularly in sensitive areas during the period of site
preparation – typically up to four weeks (see Section 2.4.2).
The levels of noise during site preparation were estimated by New York State DEC (2011 PR
p6-289 to 6-300).
Other research
None referenced
Preliminary judgment
The levels of noise identified by New York State DEC (2011 PR) could be controlled to avoid
risks to health for members of the public. Site operatives and visitors may need additional
controls to ensure that no adverse effects on health occur due to noise during this stage.
The issues associated with site preparation would be typical of the scale of impacts
associated with any comparable construction activity and are therefore judged to be of
“slight” significance for individual development. The separation of approximately 1.5 km
between multi-well pads would result in significant attenuation for receptors potentially
affected by multiple developments, and there is judged to be a low risk of cumulative impacts
due to noise during site development.
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
2.4.6 Visual impact
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
slight
minor
Probability
classification
periodic
occasional
Risk ranking
low
moderate
Peer-reviewed research
Visual impacts are described by New York State DEC (2011 PR p6-263) as impacts that
“would typically result from the introduction of new landscape features into the existing
settings surrounding well pad locations that are inconsistent with (i.e., different from) existing
landscape features in material, form, and function." New York State DEC reviewed a number
of field studies of visual impacts of shale gas production facilities, and concluded that, in the
context of development in New York state, “the visibility of new landscape features
associated with well sites tends to be minimal from distances beyond 1 mile” (p6-283). New
York State DEC went on to summarise the range of features which may result in a visual
impact over the lifetime of a shale gas development.
Other research
None referenced
Preliminary judgment
The use of heavy plant, stockpiles, fencing, site buildings etc could potentially result in
adverse visual intrusion during site preparation, particularly in sensitive areas of high
landscape value, or in close proximity to residential areas.
The new features introduced as a result of well pad construction would be temporary in
nature, and in general familiar to local populations, even if they may represent a new feature
in a particular landscape, and are therefore judged to represent a “slight” impact. These
features are likely to proceed sequentially as a shale gas play is developed. The sequential
development of well pads would reduce the potential for cumulative effects which could result
from simultaneous development of a number of pads in a given area, but would equally tend
to make the impacts a longer-term feature in the landscape. Cumulative effects are therefore
judged to represent a “minor” hazard.
2.4.7 Traffic
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
slight
minor
Probability
classification
short term definite
long term definite
Risk ranking
low
high
Peer-reviewed research
New York State DEC (2011 PR) summarises the potential effects of road traffic as follows:
“The introduction of high-volume hydraulic fracturing has the potential to generate significant
truck traffic during the construction and development phases of the well. These impacts
would be temporary, but the cumulative impact of this truck traffic has the potential to result
in significant adverse impacts on local roads and, to a lesser extent, state roads where truck
traffic from this activity is concentrated.”
The New York State DEC (2011 PR Table 6.60) indicates that the total number of truck
movements during drill pad construction is likely to be approximately 135 one-way trips per
well, or about 7% of the total truck movements. This suggests approximately 500 – 800 truck
movements for the development of a 10 well pad. This number of movements over a pad
construction period of approximately 4 weeks (see Section 2.4.2) would not be
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
environmentally significant in itself, although it would be noticeable in a rural or residential
area (New York State DEC 2011 PR p6-308).
Other research
Broderick et al (2011 NPR) state that the data for New York combined with data in relation to
exploratory drilling in the UK “…suggests a total number of truck visits of 7,000-11,000 for
the construction of a single ten well pad ... Local traffic impacts for construction of multiple
pads in a locality are, clearly, likely to be significant, particularly in a densely populated
nation…”
Preliminary judgment
The maximum permitted vehicle weight in the US is 80,000 pounds (67 CFR 658.17),
equivalent to 36 tonnes, although heavier longer combination vehicles are also permitted. In
the EU, the maximum permitted vehicle weight is 44 tonnes gross (Directive 96/53/EC).
Hence, the number of heavy vehicle movements in an EU context may be approximately
83% of those set out in New York State DEC (2011 PR), equivalent to 20 to 30 movements
per day.
It is judged that this number of vehicle movements associated with site preparation would be
a small proportion of the numbers of vehicles likely to give rise to significant environmental or
health impacts. On this basis, it is judged to represent a “slight” impact. The impacts include
air emissions, noise and visual impact, as well as transport system effects such as
infrastructure damage, congestion and effects on road safety during the period of site
preparation.
If a number of well pads are developed in a given area, the potential for adverse effects
would be more significant, as there would potentially be a sustained increase in numbers of
goods vehicle movements in a local area. The cumulative impacts may be considered on the
basis of the estimated site separation of approximately 1.5 km. The most sensitive situation
is likely to be a route located through a town centre leading to a shale gas development area.
A single route could plausibly be needed for the development of the order of 100 well pads,
covering an area of 15 km × 15 km. This could result in a combination of increased vehicle
numbers, or an extension of the period of site development by a factor of up to 100,
equivalent to approximately 8 years. This is considered to be a “minor” potential impact in
view of the longer development period. Any impact is likely to be more severe on unsuitable
roads and for longer haulage distances.
2.5 Stage 2: Well Design, drilling, casing and cementing
Stage 1
Stage 2
Stage 3
Stage 4
Stage 5
Stage 6
In this section, the options of sequential well drilling and simultaneous well drilling have been
considered. Each well is likely to take up to two weeks to drill, and one or two wells may be
drilled at a time at an individual well pad (Broderick et al 2011 NPR p28). If wells are drilled
sequentially, it may take three to five months to complete drilling at a single well pad with six
to ten well bores. If two wells are drilled simultaneously, the drilling process would take six to
ten weeks to complete, but activity would be more intense during this period.
2.5.1 Groundwater contamination and other risks
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Ref: AEA/ED57281/Issue Number 17
Hazard
classification
minor
minor
Probability
classification
rare
rare
Risk ranking
low
low
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Peer-reviewed research
During the well construction and development phase there is a risk of subsurface
groundwater contamination due to drilling muds, additives and naturally-occurring chemicals
in well cuttings. New York State DEC (2011 PR p6-40) identifies these risks as:

Turbidity (suspension of solids within the water supply) arising from aquifer
penetration, which it notes is short term in nature. The report (p2-24) highlights an
incident in which an operator caused turbidity in drinking water supplies during well
construction as a result of a “non-routine incident” in which a drill bit became stuck in
a partially drilled well;

Flow of fluids into or from rock formations – discussed below for hydraulic fracturing

Natural gas migration. New York State DEC 2011 PR cites the preceding GEIS (New
York State 1992 PR) which observes that natural gas migration to water supplies
poses a hazard because it is combustible and an asphyxiant. It notes that whilst the
impact may manifest itself during the production phase, the root cause lies in well
construction integrity. Good construction practices can help to mitigate this risk.
Other research
The EPA (2012 NPR p8) noted a potentially higher risk of methane migration with air drilling
compared to drilling using liquid muds, and recommended further research in this area.
SEAB (2011a NPR page 19) noted that where there is a large depth separation between
drinking water sources and the producing zone the chances of contamination reaching
drinking water is remote in a properly constructed well.
A surfactant additive used in well drilling was found to be emerging from a spring and
contaminating a watercourse in Pennsylvania in 2010 (PFBC 2011). The source was
identified as a shale gas well site situated above the spring discharge, at a distance of
approximately 600 metres The surfactant was pumped into the well during the drilling
process and was then flushed laterally through the underground rock strata by heavy rain
runoff.
Preliminary judgment
Poor well construction can have important environmental consequences due to the effect
that inadequate design or execution can have on the risks associated with hydraulic
fracturing. These risks are described in more detail in section 2.6.1. The risk rating here is
provided for risks occurring during the well construction and development phase.
The causes of groundwater contamination associated with the well design, drilling, casing
and cementing stage generally relate to the quality of the well structure. The risk of
contamination would increase in situations where casings are of inadequate depth. As
discussed in section 2.6.1, wellbore casings provide the primary line of defence against
contamination of groundwater, and any loss of integrity from catastrophic failure of well
casing to poor cement seals can lead to a contamination event. Poor casing quality can thus
lead to pollution of groundwater during subsequent well development stages, such as
hydraulic fracturing, flowback or gas production activities. Furthermore, the risks due to
surface spills, discussed in section 2.5.2would also apply for drilling wastes.
The risks from these activities would increase linearly with the number of wells and the time
period over which the risk exposure arises. Any significant increase in groundwater pollution
during this phase could potentially affect health in the event that members of the public were
exposed to pollution in drinking water.
The risks to groundwater posed by well construction for HVHF during the well construction
stage are similar to those posed by well construction for conventional natural gas extraction.
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
In view of the limited extent of potential effects and the established issues under
consideration, impacts are considered to be of “minor” potential significance. In view of the
limited number of incidents associated with the drilling and casing stage of the process in the
peer reviewed and other literature, the frequency was considered to be “rare” for both
individual facilities and cumulative impacts. It is also important to achieve a high standard of
well integrity to ensure impacts are properly controlled during subsequent stages in the
process, as discussed in Sections 2.6, 2.7 and 2.8 below.
2.5.2 Surface water contamination risks
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
moderate
moderate
Probability
classification
rare
rare
Risk ranking
moderate
moderate
Peer-reviewed research
Natural gas well drilling operations use compressed air or muds during the drilling process as
the drilling fluid. Compressed air may be used for vertical wells, and horizontal wells are
normally drilled with muds (New York State DEC 2011 PR p5-32). The quantities of muds
involved are likely to be greater for a horizontal shale gas well than for a conventional vertical
well of similar depth, although the quantities would not be unusual in the context of wells
encountered in the oil and gas extraction industry. A well with a 1,200 metre horizontal
section would give rise to approximately 47 m3 of mud and cuttings from the horizontal
section (adapted from New York State 2011 PR p5-34). A multi-well pad would give rise to
this quantity of material from each well.
Wells also produce cuttings which need to be properly handled. For example, a vertical well
with surface, intermediate and production casing drilled to a total depth of 2,100 metres
produces approximately 120 cubic metres of cuttings, while a horizontally drilled well with the
same casing program to the same target depth with an example 1,200 metre lateral section
produces a total volume of approximately 170 cubic metres of cuttings (i.e., about 40%
more). A multi-well site would produce approximately that volume of cuttings from each well
(adapted from New York DEC 2011 PR p5-34).
During the drilling stage, contamination can arise as a result of failure to maintain stormwater
controls (potentially leading to site-contaminated runoff), ineffective site management,
inadequate surface and subsurface containment, poor casing construction or more generally
well blowout or component failure events (New York State 2011 PR page 6-15). The greater
intensity and duration of well pad activities for multiple shale gas wells increases the potential
for accidental release if engineering controls are not sufficient. As well as management and
engineering practices, these risks can be reduced by avoiding locating drilling fluids in
primary or principal aquifer areas.
Measurement of radioactivity of cuttings from the Marcellus Shale and Barnett Shale found
that levels were not significantly elevated above background (New York State 2011 PR p534).
Other research
USEPA (2011a PR) states that “drilling muds are known to contain a wide variety of
chemicals that might impact drinking water resources. This concern is not unique to
hydraulic fracturing and may be important for oil and gas drilling in general.”
The US EPA (2012a NPR p4) highlights that horizontal wells would overall result in a lower
volume of cuttings than vertical wells for development of a given area.
The Paleontological Research Institute (2011 NPR p5) also found that levels of radioactivity
in cuttings were not significantly elevated above background, although the US EPA (2012a
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
NPR p4 and p5) reports other data sets from the Marcellus Shale with higher levels of
Naturally-Occurring Radioactive Material (NORM).
Preliminary judgment
Exposure to materials with elevated radiological activity could potentially be of concern with
regards to health, but this would only take place in the event of failure of established control
systems. There is insufficient information on the potential for radiological impacts in gasbearing shales in Europe to enable a judgment to be made on the potential significance of
this issue in Europe, although established procedures are in place to address radiological
risks.
It is important to ensure proper storage and disposal of cuttings. Established procedures are
in place for management of waste from hydrocarbon extraction activity, for example, under
the Mining Waste Directive (see Chapter 3). The introduction of wide scale shale gas
extraction would result in a significant increase in the quantities of potentially contaminated
material requiring storage, handling, treatment and disposal. Depending on the nature of
shales in Europe, this material may have elevated levels of radioactivity.
There is no centralised database of information on spillages of muds during shale gas drilling
activities, although it may be expected that any potentially significant incidents would be
reported. No evidence was found that a spillage of muds has caused a significant impact on
surface waters – for example, this was described by Lechtenböhmer et al.(2011 NPR p27) as
a “possible” source of water contamination. Bearing in mind that absence of evidence of
impacts is not the same as evidence of absence of impacts, the frequency was classified as
“rare” albeit subject to some uncertainty. In view of the potential significance of impacts of
spillages on sensitive water resources, the risks were considered to be of “moderate”
significance.
2.5.3 Release to air
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
minor
major
Probability
classification
occasional
occasional
Risk ranking
moderate
high
Peer-reviewed research
As described in New York State DEC 2011 PR (page 6-114), drilling operations can lead to
air emission from 1) combustion from diesel-powered plant on site; and 2) truck activities
near the well pad. The overall impact of these is affected by the period over which the
activities take place.
New York State DEC 2011 PR (page 6-105) identifies the primary pollutants as particulate
matter (PM), NOx, CO, VOCs and SO2, and estimates, based on industry data, emissions for
drilling, completion and production under flaring and venting scenarios. While there is a
complex picture of diverse impacts and stages, the overall assessment of hazardous air
pollutants shows greatest impacts associated with flaring of wet gas, production of wet gas
and drilling in all scenarios. Wet gases from some fields have relatively high levels of higher
molecular weight VOCs (Academic sector consultation response 2012 NPR). In dry gas
scenarios, drilling is the largest single emitting activity when pollutants are aggregated.
These figures are indicative and New York State DEC 2011 PR should be examined for
further details and also regarding the extensive modelling performed to calculate expected
air quality impacts from potential developments.
The main issue of potential concern with regard to emissions to air during well drilling is the
risk of emissions of diesel exhaust fumes from well drilling equipment (Howarth and
Ingraffea, 2011 NPR ; Academic sector consultation response 2012 NPR).
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Other research
The period of well drilling is typically four weeks per well(Broderick et al 2011 NPR).
Lechtenböhmer et al. (2011 NPR)concur that the main issue of potential concern with regard
to emissions to air during well drilling is the risk of emissions of diesel exhaust fumes from
well drilling equipment.
Emissions from numerous well developments in a local area or wider region could potentially
have a significant effect on air quality. For example, diesel emissions are considered likely to
be a contributory factor to winter ozone episodes in rural Wyoming and Ohio (Argetsinger,
2011 NPR ; University of Wyoming, 2012 NPR ; Academic sector consultation response
2012 NPR).
Preliminary judgment
The potential effects of emissions from diesel-powered plant would in principle be greater for
HVHF than for conventional gas extraction because of the larger well volumes, as described
in Section2.5.2. Emissions from diesel-engined plant are well understood and emissions
from plant up to 560 kW are controlled in Europe. In view of this, the emissions from
individual installations are judged to be of “minor” significance. No significant adverse effects
on health would be expected to arise from a properly designed and operated individual
installation.
In view of the evidence from non-peer reviewed but independent sources of the cumulative
effects of emissions to air from hydrocarbon facilities on environmental levels of ozone, the
potential significance of these impacts was described as “major.” The atmospheric chemistry
environment in Europe differs from that in continental North America, in that ozone is
typically associated with summertime photochemical activity rather than calm winter
conditions (Derwent et al. 2003 PR). Nevertheless, it is considered in principle possible for
emissions to air to have a comparable indirect effect on summer ozone levels in Europe,
although it is not possible to quantify the scale of this potential effect on air quality and hence
on health. Exposure to elevated levels of ozone can have an adverse effect on respiratory
health, and this impact was also considered to be potentially “major”.
Additionally, there is a risk of fugitive emissions to air in the event of an equipment fuel or oil
spillage, but this risk would be common to any similar activity. There is no centralised
database of information on such spillages during shale gas drilling activities. No evidence
was found that fuel spillages pose a significant risk to air quality. It was judged that the
potential effects of any intermittent spillage would not be significant in the overall context of
gas extraction processes.
2.5.4 Biodiversity impacts
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
minor
minor
Probability
classification
rare
rare
Risk ranking
low
low
Peer-reviewed research
Gas well drilling could potentially affect biodiversity primarily via noise and disturbance
caused by the drilling process itself, together with associated vehicle movements and site
operations. However, the evidence in relation to biodiversity impacts is that any impacts are
associated with other stages of the well development process – e.g. via land-take at well pad
construction stage (New York State 2011 PR p6-67). Consequently, the impacts at this
stage are considered to be of “minor” significance.
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Adequate handling, treatment and disposal of well drilling fluids as described in Section 2.5.2
is needed to avoid potentially significant impacts on biodiversity, and more data is needed to
fully understand these effects (Entrekin et al., 2011 PR).
Other research
As discussed above, drilling at a multi-well pad could take place for up to 5 months
(Broderick et al 2011 NPR p28) assuming wells are drilled sequentially.
Preliminary judgment
As noted in Section 2.4.4, there is no evidence in the peer-reviewed literature for effects of
shale gas extraction on biodiversity, although informal publications and presentations provide
plausible indications that adverse effects on biodiversity could occur due to activities other
than well drilling. Well drilling could potentially cause local disturbance as described in
Section 2.5.5 below, but would not give rise to concerns related to wider scale effects
associated with other aspects of shale gas extraction. On this basis, it is judged that there is
a minor potential for cumulative impacts on biodiversity associated with well drilling at
multiple well pad installations.
2.5.5 Noise
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
minor
moderate
Probability
classification
occasional
occasional
Risk ranking
moderate
high
Peer reviewed research
New York State DEC (2011 PR p6-289 to 6-297) indicates that well drilling is one of the more
significant sources of noise, other than during the fracturing process itself. This would also
need to be seen in the context of ongoing noise from sources including well pad construction,
hydraulic fracturing and road traffic.
Other research
The process lasts up to 4 weeks per well (Broderick et al 2011 NPR table 2.5), but drilling is
continuous for 24 hours per day over this time. Broderick et al consider that drilling is the
stage of greatest continuous noise pollution. Furthermore, if a number of wells are
developed on a single pad, this would extend the period that this impact takes place to up to
five months.
Preliminary judgment
If two wells are drilled simultaneously at a well pad, this could result in a doubling of the
noise source, with a resultant increase in noise level experienced in the local area by up to 3
dB(A). Because of the sensitivity of the human ear to sound, an increase of 3 dB(A) would
be detectable, but would not be perceived as a doubling of sound level. With this increase,
the noise levels would continue to be less significant although longer lived than those
associated with the hydraulic fracturing process. Effective noise abatement controls are well
established in the oil and gas industry (New York State DEC 2011 PR p6-289 to 6-297). It is
expected that established noise controls would be applied during drilling, and consequently
this impact was judged to be of “minor” significance.
Noise from well drilling could potentially affect residential amenity and wildlife, particularly in
sensitive areas. Noise impacts over the shale gas pre-production stages are discussed in
section 2.6.7 and highlight that whilst construction and drilling noise levels can be significant,
they are lower than for the hydraulic fracturing stage itself.
The levels of noise during drilling forecast by New York State DEC (2011 PR p6-289 to 6300) could be controlled to avoid risks to health for members of the public. Site operatives
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
and visitors may need additional controls to ensure that no adverse effects on health occur
due to noise during this stage.
If a number of well pads are developed in a given area close to sensitive residential areas or
habitats, the potential for adverse effects would be more significant, as there would
potentially be a sustained increase in noise levels for an extended period. A typical
separation of 1.5 km between well pads would provide significant attenuation of cumulative
noise impacts. These cumulative impacts were judged to be of potentially “moderate”
significance.
2.5.6 Visual impact
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
slight
minor
Probability
classification
periodic
occasional
Risk ranking
low
moderate
Peer-reviewed research
The use of well drilling rigs could potentially result in adverse visual intrusion over the
approximately 4 week period of well drilling, particularly in sensitive areas of high landscape
value, or in close proximity to residential areas (New York State DEC (2011) PR section
6.9.2.2).
Other research
An example drilling rig is shown as the highest vertical feature in Figure 5.
Figure 5: Drilling rig used in well excavation, Eagle Ford Shale, Texas
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Preliminary judgment
The new features introduced as a result of well pad construction would be temporary in
nature, but would typically be unfamiliar to local populations, and would represent a new
industrial feature in a particular landscape. Individual wellpads would be separated by
approximately 1.5 km. Furthermore, the development of a number of wells on a single pad
would extend the period that this impact takes place. In view of the limited duration
associated with drilling at individual well pads, this impact is judged to be of “slight”
significance.
These features are likely to proceed sequentially as a shale gas play is developed. The
sequential development of well pads would reduce the potential for cumulative effects which
could result from simultaneous development of a number of pads in a given area, but would
equally tend to make the impacts a longer-term feature in the landscape. Consequently,
development of a shale gas play could affect a landscape over a longer period. Cumulative
impacts were therefore judged to be potentially of “minor” significance.
2.5.7 Traffic
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
slight
minor
Probability
classification
short term definite
long term definite
Risk ranking
low
high
Peer-reviewed research
New York State DEC (2011 PR Table 6.60) indicates that the total number of truck
movements during well drilling is likely to be approximately 515 one-way trips per well, or
about 26% of the total truck movements. This suggests approximately 5,000 truck
movements for the development of a 10 well pad. This number of movements over a pad
construction period of approximately three to five months would not be environmentally
significant in itself, although it would be noticeable in a rural or residential area (New York
State DEC 2011 PR p6-308).
Other research
Broderick et al (2011 NPR) state that the data for New York combined with data in relation to
exploratory drilling in the UK “…suggests a total number of truck visits of 7,000-11,000 for
the construction of a single ten well pad ... Local traffic impacts for construction of multiple
pads in a locality are, clearly, likely to be significant, particularly in a densely populated
nation…”
Preliminary judgment
The number of heavy vehicle movements in an EU context may be approximately 83% of
those set out in New York State DEC (2011 PR), equivalent to approximately 50 movements
per day.
It is judged that this number of vehicle movements associated with site preparation would be
a small proportion of the numbers of vehicles likely to give rise to significant environmental or
health impacts. On this basis, it is judged to represent a “slight” impact. The impacts include
air emissions, noise and visual impact, as well as transport system effects such as
infrastructure damage, congestion and effects on road safety during the period of site
preparation.
If a number of well pads are developed in a given area, the potential for adverse effects
would be more significant, as there would potentially be a sustained increase in numbers of
goods vehicle movements in a local area. Following the approach adopted in Section 2.4.7,
it is judged that the cumulative traffic impacts may be considered a “minor” potential impact.
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
2.6 Stage 3: Technical Hydraulic Fracturing
Stage 1
Stage 2
Stage 3
Stage 4
Stage 5
Stage 6
Constituents of fracturing fluid
Peer reviewed research
Many chemicals have been used across the hydraulic fracturing industry. However, only a
small number of chemicals are used in an individual fracturing operation – typically 6 – 12
chemicals, depending on the nature of the fluid used (King, 2012 PR).
Other research
The constituents of hydraulic fracturing fluids are examined in USEPA (2011a PR page 30),
although it states this list to be incomplete given the lack of information regarding the
frequency, quantity and concentration of chemicals used. It identifies a research activity to
gather additional data on hydraulic fracturing fluid composition, although acknowledges that
this information may be seen as commercially confidential by the companies using the fluids.
USEPA (2011a PR page 31) sets out a programme to examine the chemical, physical and
toxicological properties of these chemicals, citing the US House of Representatives
Committee on Energy and Commerce (2011 NPR) which identified 2,500 hydraulic fracturing
products containing 750 chemicals in use between 2005 and 2009 in the US. These
included 29 chemicals that were known human carcinogens, regulated under safe drinking
water legislation or listed as hazardous air pollutants under clean air legislation.
SEAB (2011a NPR page 23) examines the issue of composition of fracturing liquids and
notes that some US States have adopted disclosure regulations for chemicals added to
fracturing liquids, as well as there being (as of August 2011) Federal interest in this issue.
2.6.1 Risks of groundwater contamination
Leakage via wellbore or induced fractures
Risk Characterisation
Individual installations
(more than 600 m separation between
fracturing zone and groundwater)
Individual installation
(less than 600 m separation between
fracturing zone and groundwater)
Cumulative effects of multiple installations
Hazard
classification
Probability
classification
Risk ranking
moderate
rare
moderate
moderate
occasional
high
major
rare
moderate
Peer-reviewed research
Considerable measures are taken during hydraulic fracturing to prevent leakage of the
fracturing liquid into the groundwater due to inadequacies in the well casing or due to the
extension of induced fractures into zones which could potentially result in movement of
contaminants to groundwater. Hydraulic fracturing can also affect the mobility of naturally
occurring substances in the subsurface, particularly in the hydrocarbon-containing formation
(EPA 2011a PR). The substances of potential concern include the chemical additives in
hydraulic fracturing fluid, produced water, gases, trace-elements, naturally occurring
radioactive material and organic material. Some of these substances may be liberated from
the formation via complex biogeochemical reactions with chemical additives found in
fracturing fluid (Falk et al., 2006 PR ; Long and Angino, 1982 PR quoted in EPA 2011a PR).
If fractures extend beyond the target formation and reach aquifers, or if the casing around a
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
wellbore is inadequate in extent or fails under the pressure exerted during hydraulic
fracturing, contaminants could potentially migrate into drinking water supplies.
Recent evidence indicates that a separation of the order of 600 m would result in a remote
risk of properly injected fluid resulting in contamination of potable groundwater (Davies et al.,
2012 PR). Similar data are reported by Fisher and Warpinski (2012 PR Figure 2), indicating
a maximum vertical fracture extent of approximately 600 metres. Another recent study finds
evidence however that in particular locations methane and fugitive gases from deep
geological layers can migrate upwards into shallow strata through natural pathways (Warner
et al. (2012) PR). This indicates a need for systematic processes to characterise the geology
to enable any such migration risks to be understood and taken into account in the site
selection and design process. This study followed on from a study of methane contamination
in aquifers overlying the Marcellus and Utica shale formations of north-eastern Pennsylvania
and upstate New York (Osborn et al. 2011 PR) which is discussed in Section 2.8.1. No
evidence for contamination of drinking-water samples with deep saline brines or fracturing
fluids was found by Osborn et al.
The analysis carried out by Fisher and Warpinski indicated that fracturing carried out close to
the surface tended towards the formation of horizontal fracturing, which would reduce
(although not eliminate) the risk of fractures interacting with water resources in shallower
shale gas formations.
The lack of baseline monitoring carried out in the US prior to shale gas development may
partly explain why the evidence of contamination associated with shale gas extraction is
complex and uncertain.
Other research
SEAB (2011a NPR page 28) states, in the context of the potential effects of methane
contamination, “leakage to water reservoirs is widely believed to be due to poor well
completion, especially poor casing and cementing.…. there need to be multiple engineered
barriers to prevent communication between hydrocarbons and potable aquifers. In addition,
the casing program needs to be designed to optimize the potential success of cementing
operations. Poorly cemented cased wells offer pathways for leakage; properly cemented
and cased wells do not." In this context, the term “reservoirs” refers to underground aquifers.
SEAB (2011a NPR , p19) highlights that regulators and geophysical experts agree that the
likelihood of properly injected fracturing liquid or naturally occurring contaminants reaching
underground sources of drinking water through fractures is remote where there is a large
depth separation between drinking water sources and the producing zone. According to
SEAB, this view is confirmed by the existence of few, if any, documented examples of such
migration. The SEAB does not specify what a “large depth” would constitute.
Preliminary indications are that most but not all shale gas reservoirs in Europe exhibit a
separation of more than 600 metres between the depth of shale gas formations and aquifer
resources (US Department of Energy EIA, 2011 NPR).
In contrast, where there is no such large depth separation, nor cap rock between the aquifer
and the gas play, the risks are greater. At one such site setting (Pavillion, Wyoming),
hydraulic fracturing occurred in gas production wells at a depth as shallow as 372 metres
below ground surface (EPA, 2011c NPR (draft)). Overlying the gas field, there is an aquifer
in a formation where water wells are excavated to depths of 15m to 230m or more. These
wells are the principal source of domestic, municipal and agricultural water in the area of
Pavillion. Groundwater contamination has been found in this area. The US EPA (2011c
NPR) draft report concluded that the data indicate likely impact to ground water which can be
explained by hydraulic fracturing. The USEPA’s draft report concluded that the observed
contamination was linked to inadequate vertical well casing lengths and a lack of well
integrity (USEPA 2011c NPR p37, p38). However, the initial sampling will need to be
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
completed in a next phase of testing. (Wyoming State Governor; the Northern Arapaho and
Eastern Shoshone Tribes, and US EPA Administrator, 3 March 2012 NPR).
The geological setting at Pavillion is unique in the US, and fracturing was carried out directly
from vertical wells, whereas fracturing which is the focus of this study is carried out from the
horizontal section of wells.
Broderick et al (2011 NPR page 81) notes that once installed, wellbore casings provide the
primary line of defence against contamination of groundwater, and states that any loss of
integrity from catastrophic failure of well casing to poor cement seals can lead to a
contamination event. It notes, however, that loss of casing integrity events would require
physical failure of both steel casing and cement. In this respect Broderick et al (2011 NPR
pages 81 and 82) emphasise the role of high quality cementing as protection against
contamination.
The US EPA (2011a PR p35) highlights the potential impacts on well integrity of multiplestage fracturing processes and of repeated fracturing of a well over its lifetime. As discussed
in Section 2.2, it is assumed that hydraulic fracturing may be repeated up to four times during
the operational lifetime of a well to maintain the flow of hydrocarbons to the well. The EPA
indicates that the potential effects of repeated hydraulic fracturing treatments on well
construction components (e.g., casing and cement) are not well understood. This is an area
where additional information is needed to draw firm conclusions with regard to potential
impacts, and is highlighted as an issue of high potential significance.
Preliminary judgment
The issue of groundwater contamination as a result of the technical hydraulic fracturing stage
will be highly site specific and can be to a degree mitigated through site selection processes
as mentioned above. Measures may include limiting extraction to shale gas formations at
significant depth and ensuring the presence of low permeable geological strata between the
producing zone and aquifers in use as a source of drinking water. Furthermore, there is little
information on the potential impacts on well integrity of repeated fracturing of a well over its
lifetime.
In view of the currently available evidence that there have been few past incidents of
contamination which were associated with practices which would not be carried out under
HVHF and the controls which are now well established in the industry, it is judged that the
frequency of incidents of groundwater contamination during hydraulic fracturing due to
wellbore leakage is rare. The frequency would increase when considering drilling across an
entire shale gas concession with approximately 24,000 wells.
It is judged that the magnitude of a contamination event is no more than “moderate,” defined
as “a localised environmental effect." Because of the low likelihood of contamination events
taking place on adjacent wells, it is judged that the magnitude of cumulative impacts would
be unchanged compared to the magnitude for individual events with more than 600 m
separation between the fracturing zone and groundwater. For individual sites with less than
600 m separation between the fracturing zone and groundwater, the risk was judged "high".
Migration through faults and pre-existing manmade structures
Risk Characterisation
Individual installations
(more than 600 m separation between
fracturing zone and groundwater)
Individual installation
(less than 600 m separation between
fracturing zone and groundwater)
Cumulative effects of multiple installations
Ref: AEA/ED57281/Issue Number 17
Hazard
classification
Probability
classification
Risk ranking
moderate
rare
moderate
moderate
occasional
high
major
rare
moderate
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Peer-reviewed research
As discussed above, the potential exists in principle for the fugitive gases, chemical additives
in the fracturing liquid or the liberated, naturally occurring substances to reach underground
sources of drinking water raises concerns over the risks to human health. This could
potentially occur, for example, if extended fractures are linked to aquifers via faults or preexisting manmade structures.
Recent evidence discussed above indicates that in most cases a separation of the order of
600 m would result in a remote risk of properly injected fluid resulting in contamination of
potable groundwater, though site-specific geological circumstances would need to be
considered. Besides leakage through artificial pathways, Warner et al (2012 PR) show that
there is also a possibility of leakage of fluids or gases through natural geological structures,
cracks, fissures or interconnected pore spaces.
Other research
Research indicated that predicted and actual fracture lengths often differ (Daneshy, 2003
NPR ; Warpinski et al. 1998 NPR , quoted in EPA 2011a PR ; Damjanac et al, 2010 NPR).
Due to this uncertainty in fracture location, fracturing may lead to fractures intersecting local
geologic or man-made features, potentially creating subsurface pathways that allow fluids or
gases to contaminate drinking water resources.
Broderick et al (2011 NPR page 81) identified common subsurface pathways as the outside
of the wellbore itself, incomplete or plugged wellbores from abandoned wells, fractures and
other natural cracks, fissures and interconnected pore spaces. As described above,
Broderick et al (2011 NPR pages 81 and 82) emphasise the role of high quality cementing as
protection against contamination.
Preliminary judgment
Control measures may include preliminary surveys to ensure the absence of natural
pathways in the geological strata). The potential also exists for pre-existing manmade
structures (e.g. abandoned oil and gas wells) in the vicinity of injection zones or wells to
serve as conduits increasing the reach of contaminated groundwater. The existence of
abandoned wells is a significant issue in the US, where oil and gas extraction has proceeded
for decades. The existence and location of many of these wells is not recorded. Abandoned
gas wells also exist in Europe, although indications are that there are fewer such wells in
Europe than in the US. It is considered likely that unrecorded abandoned wells may be a
more significant issue in Eastern Europe than in Western Europe, but no evidence to
substantiate this view could be identified.
Based on the examined literature, there appears to be no identified records of incidents of
contamination due to hydraulic fracturing linked to faults and pre-existing manmade
structures. It is judged that the frequency of incidents of groundwater contamination during
hydraulic fracturing via this pathway would be rare when there is more than 600 metres of
separation between the fracturing zone and groundwater, and could be reduced further by
the specification of appropriate minimum separation distances (see Chapter 4).
The evidence from other stages in the process and via other pathways is that contamination
is likely to be limited to the immediate vicinity of the relevant wells. In view of this, it is judged
that the magnitude of a contamination event is no more than “moderate,” defined as “a
localised environmental effect.” Because of the low likelihood of contamination events taking
place on adjacent wells, it is judged that the magnitude of cumulative impacts would be
unchanged compared to the magnitude for individual events. For individual installations with
less than 600 m separation between the fracturing zone and groundwater, the risk was
judged to be "high".
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Accidental surface spills
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
moderate
major
Probability
classification
not classifiable
not classifiable
Risk ranking
not classifiable
not classifiable
A further aspect of groundwater contamination during hydraulic fracturing is that related to
accidental spills and leakages. Section 2.6.2 sets out the potential sources of spillages
during hydraulic fracturing.
Peer-reviewed research
New York State DEC (2011 PR p6-15) highlights the risks to subsurface soils and aquifers
via this pathway.
Other research
Broderick et al (2011 NPR page 81) highlight the key factors affecting the potential severity
of groundwater contamination, citing the significance of the aquifer for abstraction; the extent
and nature of contamination; the concentration of hazardous substances; and connection
between groundwater and surface waters. US EPA (2011a PR p28) highlights the risk of
contamination of soil and near-surface aquifer via this pathway, and has focused further
research in this area. The Department of Energy SEAB (2011a NPR p19-20) also highlights
the risks to subsurface soils and aquifers via this pathway.
Preliminary judgment
The potential significance of impacts posed by a single well pad is considered likely to be
localised in nature but with potential for transport away from the site. Taking the issues
outlined above into consideration, this impact is judged to be potentially of “moderate”
significance.
Multiple development would pose risks of more widespread contamination if not properly
managed, which is considered to be potentially of “major” significance.
No information was identified on the frequency of liquid spillage, and it was therefore not
possible to classify the frequency of risks to groundwater posed by spillages.
2.6.2 Risks of surface water contamination
The relevant issues are:

Accidental spillage of fracturing fluid and other fluids at the surface;

Wellbore leakage; and
Accidental surface spills and vehicle accidents (see Section 2.6.10)
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
moderate
major
Probability
classification
occasional
rare
Risk ranking
high
moderate
Peer-reviewed research
New York State DEC 2011 PR (page 6-15) identifies that the amount of fracturing liquid used
is considerably greater for horizontal drilling compared with more conventional vertical
drilling. As discussed in Chapter 1, typically 10,000 to 20,000 m3 fracturing fluid may be
used per well (New York State 2011 PR p3-6), compared with 1,350 to 2,700 m3 for a vertical
well (New York State 2011 PR p3-6). New York State 2011 PR p6-15 quotes an analysis
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
carried out by the state which indicates that the proposed additives for high volume
horizontal drilling are similar to those used for vertical drilling. It therefore concludes that the
risks (from spillage) are proportionally higher for horizontal drilling, although notes previous
work (New York State 1992 GEIS PR) that there are no qualitatively different exposure
situations for horizontal drilling.
New York State DEC 2011 PR (page 6-15) highlights that other spillage events could arise
from tank ruptures, piping failures, equipment or surface impoundment failures, overfills,
vandalism, accidents, fires, drilling and production equipment defects or improper operations.
It expands on the causes and management practices related to these:

The causes and modes of release events are similar for hydraulic fracturing additives
as for drilling fluids. Contamination can arise as a result of failure to maintain
stormwater controls, ineffective site management, inadequate surface and subsurface
containment, poor casing construction or more generally well blowout or component
failure events. Risks can be reduced by siting hydraulic fracturing fluids away from
primary or principal aquifer areas. The risk is increased under high-volume hydraulic
fracturing because of the larger fluid volumes.

Leaks and spills of flowback water could also pose environmental or human health
risks. The potential causes of releases are similar to those for the primary injection
fluid, with the added risks associated with flowback water containment and
processing equipment, including hoses or pipes to convey flowback water to tanks
and trucks or leakage from those vessels. Flowback water will include fracking liquid
additives as well as constituents from the local environment and well equipment.
Produced water from wet shales could include dissolved solids, metals, biocides,
lubricants, organics and naturally occurring radioactive materials and degradation
products.
New York State DEC (2011 PR) also refers to the risks posed by truck accidents, although
these risks are not quantified.
Other research
DOE (2009 NPR p64) and BRGM (2011 NPR p59) confirm that typically 10,000 to 20,000 m3
fracturing fluid may be used per well.
The frequency of spillage events is not well known. USEPA (2011a PR page 29) cites
numerous media reports of spills but also points to a lack of robust data on the frequency or
causes of such events. A key concern for accidental fluid release is the potential impact on
surface waters as well as public water supplies. The risks of drinking water contamination
from spills are affected by the processes for managing contaminated water and the actions
taken to mitigate the effects of any spills or leakages. SEAB (2011a NPR page 20) states
that additional measures are being taken by some operators and regulators to manage this
risk, including the use of mats, catchments and groundwater monitors associated with the
hydraulic fracturing installation, together with buffers around surface water resources. Whilst
the specific measures may be considered site specific the principles and approaches to
managing these risks may be treated as generic best practice.
Preliminary judgment
A spillage at a single well pad or a vehicle accident could potentially affect surface water at
some distance away from the site. Taking the issues outlined above into consideration, this
impact is judged to be potentially of “moderate” significance.
Multiple development of wellpads at approximately 1.5 km separation would pose more
significant risks due to the number of activities being undertaken, which is considered to be
potentially of “major” significance.
The existence of reported spillages indicates that the frequency of occurrence should be
considered “occasional” although improved data would be useful in this regard. The
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
likelihood of cumulative impacts is judged to be “rare” because it is less likely that multiple
events would affect one surface water body: reported incidents refer to single events only.
Wellbore leakage
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
moderate
major
Probability
classification
rare
rare
Risk ranking
moderate
moderate
Peer-reviewed research
A common concern with hydraulic fracturing is leakage of the fracturing liquid through
fractures into the groundwater (as discussed in Section 2.6.1 above) and ultimately into
drinking water. The key control measures for this are set out in Section 2.6.1.
Other research
None reviewed
Preliminary judgment
Wellbore leakage at a single well pad could potentially affect surface water at some distance
away from the site. This impact is judged to be potentially of “moderate” significance.
Multiple development of wellpads at approximately 1.5 km separation could pose a more
significant and widespread risk to surface waters, which is considered to be potentially of
“major” significance.
The absence of reports of surface water contamination due to wellbore leakage during
technical hydraulic fracturing indicates that the frequency of occurrence should be
considered “rare” although improved data would be useful in this regard. The likelihood of
cumulative impacts is also judged to be “rare” because it is unlikely that multiple events
would affect one surface water body.
2.6.3 Water resource depletion
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
minor
moderate
Probability
classification
occasional
occasional
Risk ranking
moderate
high
Peer-reviewed research
The hydraulic fracturing process is water intensive and abstraction impacts can be
significant. In the broader context, however, New York State DEC 2011 PR (page 6-9) notes
that water abstraction from conventional oil and gas drilling is a very small percentage of
overall water withdrawal, and the contribution of gas extraction with hydraulic fracturing
would be expected to be low (less than 0.25% of the total water resource use in New York
State based on the peak forecast usage rate for the oil and gas industry in the state; New
York State DEC 2011 PR p6-12). In view of the wide range of other water uses, a similar
pattern would expect to prevail in Europe. However, New York State DEC also points out
that there is potential for adverse effects when water withdrawals occur on low flow or
drought conditions or in unsustainable locations New York State DEC 2011 PR (page 6-10).
A proportion (25% to 100%) of the water used in hydraulic fracturing is not recovered, and
consequently this water is lost permanently to re-use, which differs from some other water
uses in which water can be recovered and processed for re-use. The potential impacts
described cover:
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe

Reduced stream flow affecting the availability of resources for downstream use, such
as for public water supply.

Adverse impacts on aquatic habitats and ecosystems from affects such as degradation
of water quality, reduced water quantity, changes to water temperature, oxygenation
and flow characteristics, including the effects of sediment and erosion under altered
responses to stormwater runoff.

An interplay with downstream dischargers, affecting their ability to discharge where
limits are related to stream flow rate, or the overall concentration of pollutants where
discharge rates remain unaffected.

Impacts on water quality, affecting the use which can be made of surface waters
New York State DEC 2011 PR (page 6-9) considers the potential volume of abstraction in
New York and states this to be unknown due to uncertainty in the number of wells that could
be operated. This highlights that the overall cumulative impact from hydraulic fracturing is as
much determined by the local density of well sites as the characteristics of the fracking
process itself. As an example of the figures involved, New York State DEC 2011 PR (page
6-10) reports that between July 2008 and February 2011, average water usage for highvolume hydraulic fracturing within the Susquehanna River Basin in Pennsylvania was 19,000
m3per well based on data for 553 wells.
The quantity of water withdrawn is influenced by the re-use of flowback water from previous
fracturing operations, which New York State DEC 2011 PR (page 6-10) estimated to typically
account for 10%-20% of the injected fracturing fluids. Recent estimates indicate recycling of
approximately 77% of wastewater in the second half of 2011 in Pennsylvania, compared to
10% two years previously (Yoxtheimer, 2012 PR), although there is uncertainty over the
typical rate of recycling in the US, which may be significantly lower.
Yoxtheimer (2012 PR) described how many of the challenges associated with processing the
flowback for re-use have been overcome, in particular by the introduction of friction reducers
which permit the re-use of high salinity water.
Other research
The evaluation of potential impacts is supported by Broderick et al (2011 NPR page 90).
This study highlighted that local effects could be much more significant and areas already
under the strain of water scarcity may be affected especially as longer term climate change
impacts of water supply and demand are taken into account.
USEPA (2011a PR pages 25 and 27) cites similar impacts. In highlighting the potential of
diversion of drinking water supplies, it references stakeholder concerns regarding high volume
withdrawals from small streams in the headwaters of watersheds supplying drinking water in
the Marcellus Shale area. This impact on the drinking water system can lead to the need for
engineering solutions for reduced aquifer levels – for example lowering of pumps or
deepening of wells as required in the area of the Haynesville Shale. Further consequences of
reduced water levels mentioned include:

The potential for chemical changes to aquifer water, including altered salinity, as a
result of the exposure of naturally occurring minerals to an oxygen rich environment.

stimulated bacterial growth, causing taste and odour problems in drinking water.

upwelling of lower quality water or other substances (e.g. methane – shallow deposits)
from deeper and subsidence or destabilization of geology
Following recent low rainfall, water withdrawal permits for shale gas well development in the
Susquehanna River Basin in Pennsylvania have been temporarily suspended (SRBC, 2012b
NPR). This substantiates the concerns expressed by New York State DEC (2011 PR).
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
The water abstraction volumes identified by New York State DEC (2011 PR) are consistent
with the range of 4,500 to 22,500 m3per well cited in SEAB (2011a NPR p19). USEPA
(2011a PR pages 22 and 25) cites similar figures.
USEPA (2011a PR page 23) estimates that 25-75% of the original fluid injected in the first
two weeks after a fracture is recovered. North American regulator consultation response,
(2012 NPR) confirmed that processing and re-use of flowback has improved substantially in
recent years. Because of the incomplete fluid recovery, re-used fluid is typically blended with
a similar volume of fresh water.
Preliminary judgment
In view of the above discussion, the potential impact of a single site on water resources is
judged to be “minor.” The potential exists for development of multiple sites within a single
water catchment. This would require careful management to ensure that development takes
place at an appropriate pace. If this management is not in place, development of multiple
sites could pose a “moderate” risk to water resources in some areas. The frequency of these
potential effects are judged to be “occasional,” defined as “could potentially occur … if
management or regulatory controls fall below best practice standards.”
2.6.4 Release to air
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
minor
moderate
Probability
classification
occasional
occasional
Risk ranking
moderate
high
Peer-reviewed research
As discussed in section2.5.3, New York State DEC 2011 PR (page 6-114) identifies the main
sources of air emissions from drilling, completion and production activities and examines
their relative significance. Sources of emissions include diesel fumes and truck activities
near the well pad. Emitted substances include PM, NOx, CO, VOCs and SO2. Emissions of
diesel fumes from fracturing fluid pumps were highlighted by Howarth and Ingraffea (2011
NPR).
Other research
The issues of potential concern with regard to emissions to air during hydraulic fracturing
comprise the following:

Emissions of diesel fumes from fracturing fluid pumps (Lechtenböhmer et al. 2011
NPR)

On-site handling (by conveyor and blender) of proppant (sand) which can emit
significant quantities of dust. Kellam (2012 NPR) reported that 0.25% (by weight) of
proppant sand was emitted to the air as fine dust during fracturing fluid make up
operations.
Preliminary judgment
As discussed in Section 2.5.3, impacts during hydraulic fracturing from individual sites are
considered to be of “minor” significance, but the cumulative impact from multiple sites could
potentially be of greater significance. The major contributor to regional air quality issues is
likely to be the completion and production stages, and the cumulative impact from the
technical hydraulic fracturing stage was judged to be “moderate”.
Additionally, there is a risk of fugitive emissions to air in the event of an equipment fuel or oil
spillage, but this risk would be common to any similar activity and not significant in the overall
context of gas extraction processes. There is no centralised database of information on such
spillages during shale gas drilling activities. No evidence was found that fuel spillages pose
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
a significant risk to air quality in the context of other sources of emissions to air. On this
basis, the risks of fugitive emissions following a spillage were judged to be of minor
significance.
2.6.5 Land take
Land is required for storage of hydraulic fracturing fluids and waste water, together with
vehicle access, pipelines and associated plant and equipment. This is addressed in Section
2.4.3.
2.6.6 Biodiversity impacts
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
minor
moderate
Probability
classification
rare
rare
Risk ranking
low
moderate
On-site storage and transportation of water can affect biodiversity due to land take,
disturbance and/or by the introduction of non-native invasive species. This is discussed in
Section 2.4.4.
Peer-reviewed research
New York State DEC (2011 PR p6-3) cites the effect of shale gas exploitation activities on
ecosystems and wildlife. The impacts will be strongly location dependent but general effects
can be defined. These include fragmentation of habitat, potential transfer of invasive species
and impacts on endangered or threatened species. Entrekin et al (2011 PR p8) describe the
risks to wildlife posed by sediment runoff into streams, reductions in streamflow,
contamination of streams from accidental spills, and inadequate treatment practices for
recovered wastewaters as “realistic threats”.
Other research
The EPA (2012 NPR p9) highlighted a local issue linked to the introduction of algae into local
water courses, resulting in major fish kills.
Three examples of uncontrolled release of fluids with actual or potential effects on
biodiversity and agriculture are quoted by Michaels et al. (2011 NPR).
Preliminary judgment
The impact will be related to the footprint of the development sites, including the effects of
access roads and utility services. These are discussed in section 2.4.3. In addition,
contamination of local water sources and the effects of water depletion can all harm local
ecosystems. The potential causes of these effects are described in sections 2.6.1 and 2.6.3.
In view of the existence of limited evidence of effects of hydraulic fracturing on biodiversity,
the frequency is considered to be “rare.” The biodiversity impacts of potential concern (e.g.
Michaels et al. 2011 NPR ; New York State DEC 2011 PR p6-3) are associated with
cumulative development over a wider area, and are judged to be of “moderate” significance.
2.6.7 Noise
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
minor
minor
Probability
classification
short-term definite
short-term definite
Risk ranking
moderate
moderate
Peer-reviewed research
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Noise emissions associated with operation of well and associated equipment could affect
residential amenity and wildlife, particularly in sensitive areas. New York State DEC 2011
PR (pages 6-289 to 6-300) describes the noise impacts from hydraulic fracturing. The noise
level differs with the stages in the preparation and production cycle. At 75 metres, for
example, the maximum calculated composite noise level for construction equipment is
70dBA. For horizontal drilling the corresponding maximum noise level is 64dBA. The
hydraulic fracturing process, however, can produce noise levels of 90dBA at that distance.
This is calculated on the basis that up to 20 diesel pumper trucks are required to operate
simultaneously to inject the required water volume to achieve the necessary pressure. The
operation takes place over a period of several days for each well and would be repeated at a
site for multiple wells and pads. This noise has the potential to temporarily disrupt and
disturb local residents and wildlife.
Other research
Broderick et al (2011 NPR , p92) examined noise pollution, with a focus on the extent of
activities rather than their noise levels, focusing on Cuadrilla Resources’ Preese Hall
exploratory site in the UK. It states that each well pad (assuming 10 wells per pad) would
require 800 to 2,500 days of noisy activity during pre-production. This covers ground works
and road construction as well as the hydraulic fracturing process. Drilling, which it states as
the stage of greatest continuous noise pollution, is required for 24 hours per day for four to
five weeks at each well.
Preliminary judgment
The levels of noise during fracturing forecast by New York State DEC (2011 PR p6-289 to 6300) would need to be carefully controlled to avoid risks to health for members of the public.
Site operatives and visitors may need additional controls to ensure that no adverse effects on
health occur due to noise during this stage. Because controls on noise are widely used in
the oil and gas industry, it is judged that the potential significance of noise issues with these
controls in place is “minor”.
2.6.8 Seismicity
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
slight
minor
Probability
classification
rare
rare
Risk ranking
low
low
Peer-reviewed research
New York State DEC 2011 PR (page 6-319) describes two types of induced seismic events
associated with hydraulic fracturing. One is micro-seismic events resulting from the physical
fracturing process. These are sufficiently small to require very sensitive monitoring
equipment to be detected. This is an inherent part of the fracturing process and data on
these events is used to guide the fracturing process. Indeed SEAB (2011a NPR page 21)
recommends micro seismic surveys as a means to understand fracture growth and limit
methane leakage (as opposed to the management of seismic risks). For hydraulic fracturing,
New York State DEC 2011 PR (page 6-321) notes that seismic activity is only detectable at
the surface by very sensitive equipment, and that the magnitude can be minimised by
avoiding pre-existing faults. It also describes the potential for sheer slip, in which slippage
occurs on bedding planes, which it states to be several orders of magnitude less than that
which would be felt by humans. It reviews operating experience and reports on consultations
with experts to conclude that the possibility of fluids injected during hydraulic fracturing the
Marcellus or Utica Shales reaching a nearby fault and triggering a seismic event is remote.
A recent peer reviewed European report nevertheless provides recommendations on the
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
need to introduce traffic light monitoring systems to mitigate induced seismicity (Royal
Society and Royal Academy of Engineering PR 2012, p.6).
The second type of event results from injection fluids reaching existing geological faults,
leading to more significant ground accelerations, potentially felt by humans at the ground
surface. These types of events can arise in any process involving the injection of
pressurised liquids underground. For example, New York State DEC 2011 PR (page 6-321)
notes that carbon sequestration can cause such events, with magnitudes typically less than
3, and the events connected to circumstances that could be avoided through site selection
and injection design.
Well integrity could potentially be affected by seismic activity – either activity induced by the
hydraulic fracturing process, or other seismic events. This is managed by the normal
processes for monitoring and maintaining well integrity. Induced seismicity from hydraulic
fracturing is of very small magnitude and would not be expected to adversely affect wellbore
integrity.
Other research
Broderick et al (2011 NPR page 93) reviewed the discussion in the previous draft New York
State DEC study (2009 PR) but went on to describe experiences at the Cuadrilla Resources’
Preese Hall exploratory site in the UK. At that location hydraulic fracturing was halted in May
2011 following instrumental detection of seismic events of magnitude 1.5 and 2.3 in the
vicinity. Subsequent studies suggested a link between the fracturing activities and the
seismic events (de Pater and Baisch 2011 NPR). As reported by Broderick et al (2011
NPR), one study indicated a maximum induced magnitude of around 3, for that location,
which was considered insufficient to cause surface structural damage but to potentially
damage the wellbore itself. The UK Government has published research which sets out a
proposed monitoring and control approach (DECC 2012 NPR) and anticipates lifting the
temporary embargo on hydraulic fracturing operations in the UK with this system in place.
Seismic activity was also recorded in Oklahoma in January 2011 (Holland 2011 NPR). It was
concluded that the recorded earth tremors could possibly be linked to hydraulic fracturing
activity in a nearby water disposal well. The study reported two previous events in
Oklahoma, in which a link to hydraulic fracturing had been suggested over the period 1977 to
2011.
Preliminary judgment
In view of these evaluations and the low frequency of reported incidents, it is judged that the
frequency of significant seismic events is “rare” and the potential significance of this impact is
“slight.” Multiple development could increase the risk of seismic events due to one operation
affecting the well integrity of a separate operation, although in view of the low frequency of
the reported events and the established measures for monitoring well integrity, the risks are
judged to remain low.
2.6.9 Visual impact
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
slight
slight
Probability
classification
short-term definite
long-term definite
Risk ranking
low
moderate
Peer-reviewed research
New York State DEC 2011 PR (page 6-275) reviewed visual impacts associated with
hydraulic fracturing activities at well sites. It identifies landscape features as access roads,
pipelines, water impoundment areas, storage vessels and other hydraulic fracturing
equipment, vehicles and buildings. It notes that these impacts would be short-term, but
could repeat periodically over the life of a multi-well location. The visual impact is of more
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
consequence in developments at more rural locations. A more comprehensive summary of
visual impacts is presented in New York State DEC 2011 PR (page 6-285) for Horizontal
Drilling and Hydraulic Fracturing in the Marcellus and Utica Shale Area of New York,
although many of the impacts have more general applicability.
Other research
Broderick et al (2011 NPR page 92) also identifies visual impacts, citing the UK Cuadrilla
development at Blackpool as involving a footprint of 1ha per well pad for up to 80 pads.
Broderick et al. concur that the visual impact is of more consequence in rural locations.
Preliminary judgment
In view of the perception-based nature of these impacts, and lower visual impact compared
with the drilling stage, they are judged to be “slight”. Impacts can be expected to occur with
an individual site over a short period, and for multiple development over an extended period.
On this basis, the likelihood of impacts was judged to be “short-term definite” for individual
sites and “long-term definite” for multiple sites.
2.6.10 Traffic
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
minor
moderate
Probability
classification
occasional
occasional
Risk ranking
moderate
high
Peer-reviewed research
The traffic impacts of shale gas pre-production are examined in New York State DEC 2011
PR (pages 6-300 to 6-316). It estimates the number of loaded truck trips per horizontal well
during construction. Two scenarios are considered, one in which all water (fracking fluid and
backflow) are transported by truck, and one in which pipelines are used in part of that
activity. In the former, a total of heavy 1,148 truck trips are envisaged, with the largest single
activities associated with hydraulic fracturing (175 for the transportation of equipment and
500 for transport of water to site). This figure reduces to 625 where pipelines are assumed
to be available for water and waste transport. Furthermore, the temporal distribution of these
activities is uneven, so the total number of trips during the heaviest period could be as high
as 250 per day (including lighter trucks). The maximum permitted weight of articulated
vehicles is slightly greater in Europe than in the US, and so the number of vehicle
movements may be slightly less. .
New York State DEC 2011 PR goes on to examine some of the potential impacts of this level
of transport. These include:

Increased traffic on public roadways. This could affect traffic flows and congestion.

Road safety impacts.

Damage to roads, bridges and other infrastructure. This could lead to decreased road
quality and increased costs associated with maintenance for roads not designed to
sustain the level of traffic experienced.

Risks of spillages and accidents involving hazardous materials.
In addition to the above, the road vehicles would cause air emissions with the potential for
localised air quality impacts, as well as increasing the potential for community severance
(reduction in community interaction due to roads with high traffic volumes) and potentially
affecting residents’ quality of life. The noise impacts are described above.
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Other research
For more widespread development, EPA (2012 NPR p14) suggests that there may be a
sustained impact at this level.
Road traffic accident statistics in Europe focus on fatalities rather than on the number of
vehicle accidents (see http://epp.eurostat.ec.europa.eu/portal/page/portal/statistics). These
statistics indicate an ongoing decline in the rate of fatal accidents associated with truck
transportation in Europe.
Preliminary judgment
Even at the levels described above, the impact in traffic terms associated with an individual
site would be no more than “minor” in view of the short duration, although it would potentially
be noticeable by local residents.
An increase in road transportation of potentially hazardous chemicals and waste materials
would result in an increased risk of environmental pollution due to accidents, although these
risks cannot be quantified at present. The established controls on transportation of
dangerous goods such as Directive 2008/68/EC on the inland transport of dangerous goods
would reduce the risks posed by vehicle accidents.
Following the views of the EPA (2012 NPR p14), the impact of traffic associated with more
widespread development, including the risks posed by traffic accidents, could be considered
of “moderate” significance.
2.7 Stage 4: Well Completion
Stage 1
Stage 2
Stage 3
Stage 4
Stage 5
Stage 6
2.7.1 Groundwater contamination and other risks
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
moderate
major
Probability
classification
occasional
occasional
Risk ranking
high
high
During the well completion phase, operators need to handle flowback and produced water to
ensure that accidents, runoff and surface spillages do not occur, which would pose risks of
groundwater contamination. If flowback water is used to make up fracturing fluid, this would
increase the risk of introducing naturally occurring chemical contaminants and radioactive
materials to groundwater. Relevant naturally occurring substances could include:

Salt

Trace elements (mercury, lead, arsenic)

NORM (radium, thorium and uranium)

Organic material (organic acids, polycyclic aromatic hydrocarbons)
Peer-reviewed research
New York State DEC (2011 PR Table 6.1) lists a large number of chemicals recorded in
flowback water, or present in fracturing fluid which may be present in flowback waters, and
concludes that “… high-volume hydraulic fracturing operations, although temporary in nature,
may pose risks to Primary and Principal Aquifers…”
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Other research
As noted in Section 2.6.6, three examples of uncontrolled release of fluids with actual or
potential effects on biodiversity and agriculture are quoted by Michaels et al. (2011 NPR).
Preliminary judgment
These risks are similar to those discussed during the hydraulic fracturing phase in Section
2.6.1.
In view of the risks posed by metals and NORM in flowback fluid and the findings of New
York State DEC quoted above, the potential impacts are judged to be of “moderate”
significance for individual installations, and “major” significance in relation to cumulative
impacts. On the basis of reported instances of uncontrolled releases in non-peer reviewed
research, it is judged that the likelihood of impacts from individual sites and for cumulative
impacts should be considered as “occasional” – defined as “could potentially occur … if
management or regulatory controls fall below best practice standards.”
2.7.2 Surface water contamination risks
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
moderate
moderate
Probability
classification
occasional
occasional
Risk ranking
high
high
Peer-reviewed research
Treatment in municipal sewage treatment plant can affect the plant due to the salt content of
the water. If not properly handled, this can reduce the overall effectiveness of the sewage
works. New York State (2011 PR p6-62) highlights the scale of water treatment resources
that would be needed to maintain adequate treatment capacity. Also, some parameters
which are likely to be present in flowback water may not be properly treated in a standard
sewage treatment facility. New York State DEC highlights the potential for accumulation of
NORM in sewage sludges.
Howarth and Ingraffea (2011 NPR) cite examples of water contamination of tributaries of the
Ohio River with barium, strontium and bromides from municipal wastewater treatment plants
receiving wastewater from hydraulic fracturing processes.
Other research
As described in Chapter 1, flowback waters are collected and recycled in the hydraulic
fracturing process, or sent for treatment and disposal. The options for recycling are limited to
some extent because of a build-up of salts and contaminants in flowback fluid which
ultimately makes the fluid unsuitable for use without dilution (North American regulator
consultation response, 2012 NPR). Arthur (2008 NPR p19-20) highlights the development of
research and pilot-scale projects for flowback water recycling. This work has accelerated in
recent years, with 77% of wastewater estimated to have been recycled in Pennsylvania in
the second half of 2011 (Yoxtheimer, 2012 NPR). However, there is uncertainty over the
typical rate of recycling in the US, which may be significantly lower.
A number of options are available for disposal of flowback water:

Direct discharge to surface rivers and streams can affect water quality, particularly in
the light of the high salt content. This practice is banned in the U.S. and would not be
permitted in Europe under the terms of the Mining Waste Directive.

Waste water may be injected into disposal wells if such facilities are available and if it
is not prohibited by law (see discussion in Chapter 3)
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe

Waste water may be treated in on-site facilities or in separate sewage works including
commercial facilities designed for treatment of produced water from wet shale
formations. Extensive desalination treatment, such as evaporation/distillation, allows
discharge of the treated water to surface waters. Less extensive chemical
precipitation treatment is used to remove suspended solids and divalent cations
(magnesium, calcium, strontium, barium and radium) to facilitate wastewater reuse
(Yoxtheimer, 2012 NPR).
Arthur (2008 NPR p19) refers to the need for development of new waste water treatment
technologies.
Lechtenböhmer et al. (2011 NPR section 5.4.2) refers to the treatment of waste water as an
issue that “may also complicate projects” and cites an example in which the rate of disposal
of gas drilling wastewaters had to be reduced by 95% as a result of non-compliance with
water quality standards. Lechtenböhmer et al. highlighted in particular the risks potentially
posed by metals and NORM in waste waters.
Examples of spillages and accidental discharges are cited by Michaels et al. (2011 NPR) –
for example, 109 spillages were reported in Colorado during a three year period.
Preliminary judgment
In view of the risks posed by metals and NORM in waste waters, the potential impacts are
judged to be of “moderate” significance.
In view of the reported incidents of discharges to water in peer reviewed and non-peer
reviewed research, it is judged that the likelihood of impacts from individual sites and for
cumulative impacts should be considered as “occasional” – defined as “could potentially
occur … if management or regulatory controls fall below best practice standards.”
2.7.3 Release to air
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
minor
major
Probability
classification
occasional
occasional
Risk ranking
moderate
high
Individual installation:
Hazard classification: minor Probability classification: occasional Risk ranking: moderate
Cumulative effects of multiple installations:
Hazard classification: major Probability classification: occasional Risk ranking: high
Peer-reviewed research
As discussed in section 2.5.3, New York State DEC 2011 PR (page 6-114) identifies the
main sources of air emissions from drilling, completion and production activities and
examines their relative significance. Sources of emissions include combustion from engines
and flares; venting; and truck activities near the well pad. Emitted substances include PM,
NOx, CO, VOCs and SO2. Flowback gas would normally be dry although wet gas, requiring
removal of condensable hydrocarbons, could be encountered.
Other research
The issues of potential concern with regard to emissions to air during hydraulic fracturing
comprise the following:

Emissions of hazardous air pollutants, ozone precursors and/or odours due to gas
leakage during completion (Lechtenböhmer et al., 2011 section 2.3.1; Michaels et al.
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
2011 NPR p19). Leakage may take place from pumps, valves, pressure relief valves,
flanges, agitators, and compressors (EPA 2011b NPR Sections 4.2 and 8.1).

Emissions of hazardous air pollutants, ozone precursors and/or odours from gases
dissolved in flowback water during well completion or recompletion (EPA 2011b NPR
Section 4). The short-term storage of flowback water on site can lead to considerable
emissions of VOCs (Academic sector consultation response 2012 NPR). The amount
of VOCs and methane released varies over the flow back period. Reduced
Emissions Completions can use open tank storage, which may result in flashing and
evaporative emissions.

Fugitive emissions of methane and other trace gases may take place from routeing
gas generated during completion via small diameter pipeline to the main pipeline or
gas treatment plant. This is likely to be more severe from wells developed during the
pilot stages than from production stage wells, by which stage robust pipeline
infrastructure should be in place (EPA 2011b NPR Section 4.4.2.1). Emissions to air
could also occur from flaring of methane during exploratory phases prior to the
construction of gas collection infrastructure (British Columbia OGC 2011 NPR).
Preliminary judgment
Relevant naturally occurring substances could include:

Gases (natural gas (methane, ethane), carbon dioxide, hydrogen sulphide, nitrogen
and helium)

Organic material (volatile and semi-volatile organic compounds)

Naturally-occurring radioactive material (NORM)
The potential effects of emissions during well completion can be expected to be greater for
HVHF than for conventional gas extraction because of the wider range of potential sources of
process and fugitive emissions. Emissions to air from a properly designed and operated
individual facility would not be expected to have a significant adverse effect on health,
although a residual risk does remain.
As discussed in Section 2.5.3, impacts from individual sites are therefore considered to be of
“minor” significance, but based on non-peer reviewed evidence from the US, the cumulative
impact from multiple sites could potentially be of “major” significance. Exposure to elevated
levels of ozone can have an adverse effect on respiratory health, and this potential
cumulative impact on health was also considered to be potentially “major”.
2.7.4 Land take
Following completion, some of the land used for a well pad and associated infrastructure can
be returned to the prior use, or to other uses. However, well established natural habitats
cannot necessarily be fully restored following use of the land for shale gas extraction.
Consequently, it may not be possible to fully restore a site, or to return the land to its
previous status resulting in habitat loss (New York State DEC (2011) p6-68), resulting in a
long-term impact as described in previous sections and in Section 2.8.5.
2.7.5 Biodiversity impacts
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Ref: AEA/ED57281/Issue Number 17
Hazard
classification
minor
moderate
Probability
classification
rare
rare
Risk ranking
low
moderate
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Contamination of local water sources due to spillages or inadequate treatment of waste
waters can potentially harm local ecosystems, similarly to the impacts described in 2.6.6.
The potential causes of these effects are described in sections 2.6.1, 2.6.2 and 2.7.2.
2.7.6 Noise
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
not classifiable
not classifiable
Probability
classification
short-term definite
short-term definite
Risk ranking
not classifiable
not classifiable
Peer-reviewed research
Noise from the well completion process could arise from on-site plant and machinery, but is
likely to be lower than at other stages in the gas extraction process, and of limited duration
(New York State DEC 2011 PR p 6-289 to 6-300).
Preliminary judgment
No peer-reviewed evidence was found in relation to noise from gas flaring. Noise from flares
can be minimised using appropriate flare design. Residual noise from flares could not be
controlled using engineering measures in the same way that plant and equipment noise can
be controlled because of the nature of the source.
No adverse effects on public health would be expected to arise due to noise from plant and
equipment provided established controls used in the oil and gas industry are applied.
However, because of the uncertainty associated with flaring noise, it is judged that noise
impacts are not classifiable.
2.7.7 Seismicity
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
minor
minor
Probability
classification
rare
rare
Risk ranking
low
low
Peer-reviewed research
None reviewed
Other research
Recent evidence indicates that injection of waste water into disposal wells may have been
associated with minor earth tremors of magnitude 2.7 to 4.0 on the Richter scale (Ohio
Department of Natural Resources, 2012 NPR ; Arkansas Sun Times, 2011 NPR).
Preliminary judgment
Injection of waste water into aquifers is not permitted in Europe, although disposal into
geological formations with no connection to aquifers may be permitted as discussed in
Chapter 3.
If injection of waste water from hydraulic fracturing into disposal wells were permitted, earth
tremors of the magnitude recorded in Ohio would not normally have significant
consequences at the surface, and are judged to be of minor significance. On the basis of
some reported occurrences of minor earth tremors, the frequency of seismic impacts is
judged to be rare.
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
2.7.8 Traffic
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
slight
minor
Probability
classification
short-term definite
short-term definite
Risk ranking
low
moderate
Peer-reviewed research
The traffic impacts of shale gas pre-production are examined in New York State DEC 2011
PR (pages 6-300 to 6-316). It estimates the number of loaded truck trips per horizontal well
during completion. 100 truck movements per well are estimated to be needed for waste
water disposal. This figure reduces to 17 movements where pipelines are assumed to be
available for water and waste transport. This represents a small proportion of overall truck
movements, but would contribute to the net impacts of traffic associated with a well
development.
Other research
None reviewed
Preliminary judgment
In view of the low number of traffic movements associated with well completion phase, the
impacts associated with an individual well pad are judged to be slight, and those associated
with wider area development are judged to be minor.
2.8 Stage 5: Well Production
Stage 1
Stage 2
Stage 3
Stage 4
Stage 5
Stage 6
2.8.1 Groundwater contamination and other risks
Risk Characterisation
Individual installations
(more than 600 m separation between
fracturing zone and groundwater)
Individual installation
(less than 600 m separation between
fracturing zone and groundwater)
Cumulative effects of multiple installations
Hazard
classification
Probability
classification
Risk ranking
moderate
rare
moderate
moderate
occasional
high
moderate
occasional
high
Risks to groundwater are principally those posed by failure or inadequate design of well
casing leading to potential aquifer contamination. The substances of potential concern
comprise naturally occurring substances such as heavy metals, together with natural gas,
naturally occurring radioactive material (NORM), and technologically enhanced NORM
(TENORM) from drilling operations.
Peer-reviewed research
Osborn et al (2011 PR) investigated methane in shallow groundwater used as a drinking
water resource in aquifers overlaying the Marcellus and Utica shales of NE Pennsylvania.
Samples taken close to active gas extraction sites were compared with samples distant from
any active gas extraction. Higher levels of methane were identified in samples taken near
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
active wells than at more distant sites. The isotopic signature of the methane samples taken
near active wells was found to be characteristic of deeper deposits. Whilst this suggests a
link between the elevated methane levels and the gas extraction process, there was no
evidence of mixing of aquifer water with either fracturing fluids or shale formation waters and
thus it was concluded that the water chemistry was consistent with historical baseline data.
Osborn et al. considered the possible mechanisms for elevated concentrations of
thermogenic gas to be found in the aquifers. The three mechanisms they propose are: first,
physical movement of gas rich fluids from the shale, but this would have to be rapid, and they
therefore rule this out based on their negative results from chemical analysis to identify
evidence of mixing of aquifer water with deep formation water. Second, the fracturing
process could create new fracture pathways from the shale to the aquifer and methane gas
being released to solution due to pressure reduction during extraction. This could then allow
gas phase methane to migrate through the fissure network. Indeed there is evidence that
rapid vertical gas migration is possible, particularly where there are old unused gas wells that
are uncased and abandoned in the neighbourhood, and where the overlying formations are
naturally highly fractured, and faulted. Third, the authors conclude that a more likely
explanation would be that the methane may have leaked from leaky gas casings at depths of
up to hundreds of metres below ground, followed by migration of the methane both laterally
and vertically towards the water wells. This finding has been challenged by Molofsky et al.
(2011 PR), who found that the isotopic signatures of thermogenic methane identified by
Osborn et al. (2011 PR) were more consistent with shallow deposits overlying the Marcellus
shale. Molofsky et al interpreted these results to mean that the methane detected in the
Duke study could have originated entirely from shallower sources above the Marcellus which
are entirely unrelated to hydraulic fracturing. Osborn et al. reported methane present at
lower levels at locations distant from active gas extraction wells, and concluded that this was
likely to have resulted from natural release of methane from source rocks in view of its more
biogenic signature. The Duke University team is continuing its research, sampling
approximately 150 water wells in Northeast Pennsylvania (see Warner et al. (2012 PR)
discussed in Section 2.6.1).
Considine et al. (2012 PR) reviewed all the Notices issued by the Pennsylvania Department
for Environmental Protection between 2008 and 2011 in relation to incidents at shale gas
extraction sites. The 2,988 notices issued related to 845 environmental events, of which 25
were considered to be major events. Six events were not fully mitigated, of which two related
to contamination of groundwater. The causes of these events were linked to inadequate well
casing.
Other research
A number of studies have highlighted potential links between shale gas extraction and
groundwater contamination. However, reliable examples of contamination are limited, partly
because of the difficulty of distinguishing between naturally or previously occurring
contamination, and contamination associated with shale gas extraction operations. The US
EPA (2011c NPR , in draft) found that hydraulic fracturing of tight and conventional gas fields
may have resulted in contamination of a drinking water aquifer at Pavillion in Wyoming. This
incident was linked in the EPA draft report to inadequate vertical well casing lengths and a
lack of well integrity (USEPA 2011c NPR p37, p38). However, the findings of this study are
preliminary and will be followed by further ongoing research (see Section 2.6.1).
It is well established that methane can be present in shallow aquifers independent of shale
gas extraction activity (e.g. Breen et al., 2007). SEAB (2011a NPR) found that the research
carried out by Osborn et al. (2011 PR) provided credible evidence of elevated levels of
methane originating in shale gas deposits in wells surrounding a shale production site and
recommended further investigation of this issue.
Re-fracturing may be needed during the production phase. It is estimated that re-fracturing
may take place up to four times from an individual well, as described in Section 2.2. The
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
USEPA (2011a PR p82) highlights concerns that the potential effects of repeated pressure
treatments on well construction components (e.g., casing and cement) are not well
understood.
Preliminary judgment
It is anticipated that any potential failure of the well would be monitored during the refracturing process, and remedial measures implemented to address any issues identified
using established industry processes (e.g. API 2009 NPR is used as a reference standard for
shale gas production operations in the US). Nevertheless, in view of the possible evidence
for methane migration into potable groundwater (Osborn et al. 2011) and uncertainty around
the risks associated with re-fracturing, the potential for increased risk due to re-fracturing
remains an area of uncertainty, and hence has been assigned a risk ranking of “high” for
installations with less than 600 m distance between fracturing zone and groundwater and
"moderate" for installations with more than 600 m distance. In other respects, the risks and
impacts associated with re-fracturing would be similar to those described in Section 2.6.
Because potential emissions to groundwater would only occur in the event of a failure of
control systems, it is judged highly unlikely that multiple incidents would affect the same
location. On this basis, cumulative impacts are not judged likely to be significantly different
to the impacts associated with individual installations.
2.8.2 Surface water contamination risks
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
minor
minor
Probability
classification
rare
occasional
Risk ranking
low
moderate
Peer-reviewed research
Production water is the fluid returning from the borehole during the production phase (US
EPA 2011a PR page 1; New York State DEC 2011 PR p6-17). This brine requires interim
storage, transport, processing and disposal or re-use. Accidental releases can arise as a
result of tank ruptures, equipment or surface impoundment failures, overfills, vandalism, fires
and improper operations. The production brine can have elevated levels of naturally
occurring radioactive materials (higher than for flowback liquid) such as radium, thorium and
uranium.
Well blowout has been reported as giving rise to four major environmental incidents in
Pennsylvania between 2008 and 2012. When blowout or uncontrolled venting occurs, fluids
and gases may be released from the wells(Considine et al. 2012 PR). The quantities of fluid
cannot be quantified, but discharges identified by Considine et al were sufficient to result in
significant pollution of surface waters, requiring remedial action.
Re-fracturing may be needed during the production phase on up to four occasions, as
described in Section2.2. This could potentially pose additional risks to surface waters in the
event that repeated pressure treatment affects the integrity of the well(US EPA 2011a PR).
In this case, the integrity and capacity of the well would need to be assessed, to enable a
site-specific assessment of risks and impacts to be carried out (King 2012 PR , p2).
Other research
None reviewed
Preliminary judgment
The risks posed by the handling and treatment of production water are similar to those
described in Section 2.7.2 above.
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Because of the risks potentially associated with re-fracturing, it is judged that there would
remain a higher risk of impacts compared to the risks described in Section 2.6.2.
2.8.3 Water resource depletion
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
minor
moderate
Probability
classification
occasional
occasional
Risk ranking
moderate
high
Re-fracturing may be needed during the production phase on up to four occasions, as
described in Section2.2. In this case, the impacts would be similar to those described in
Section 2.6.
2.8.4 Release to air
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
minor
major
Probability
classification
periodic
occasional
Risk ranking
moderate
high
Peer-reviewed research
Flaring has been carried out during the first 24 hours of flowback operations while a well
produces a high ratio of flowback water to gas (New York State DEC 2011 PR p5-134).
Flaring may result in emission to air of combustion gases, and of some unburnt
hydrocarbons, depending on the efficiency of the flaring process.
Well blowout has been reported as giving rise to four major environmental incidents in
Pennsylvania between 2008 and 2012 resulting in the release of fluids and gases (Considine
et al. 2012 PR). The quantities of fluid cannot be quantified, but discharges identified by
Considine et al were sufficient to result in significant pollution of surface waters, requiring
remedial action.
Other research
Flaring or venting of gas may also be required during the pilot testing phases, before a
gathering line is in place (British Columbia OGC 2011 NPR).
Ongoing fugitive losses of methane and other trace hydrocarbons are likely to occur during
production phase via leakages from valves, flanges, compressors etc (US EPA 2011b NPR ;
Lechtenböhmer et al. 2011 NPR). These fugitive losses may contribute to local and regional
air pollution, with potential for adverse effects on health, as described in the above sections.
Emissions from numerous well developments in a local area or wider region could potentially
have a significant effect on air quality. For example, emissions from regional shale gas
development are considered likely to be a contributory factor to ozone episodes in Texas,
Wyoming and Ohio (Michaels et al. 2011 NPR ; Argetsinger, 2011 NPR ; University of
Wyoming, 2011 NPR).
Preliminary judgment
As discussed in Section 2.5.3, impacts from individual sites are considered to be of “minor”
significance, but the cumulative impact from multiple sites could potentially be of “major”
significance. The potential effect of elevated levels of ozone on respiratory health was also
considered to be potentially “major”.
Emissions to air during blow-outs would contribute to fugitive emissions from shale gas
extraction more widely. The risk of direct environmental or health effects due to emissions
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
under blowout conditions cannot be ruled out, although there are no specific reports
associated with these incidents.
Re-fracturing may be needed during the production phase on up to four occasions, as
described in Section2.2. In this case, the impacts would be similar to those described in
Section 2.6. The potential climate impacts of fugitive methane emissions are not addressed
in this study, but will be addressed in a separate study commissioned by DG CLIMA.
2.8.5 Land take
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
slight
minor
Probability
classification
long-term definite
long-term definite
Risk ranking
moderate
high
Peer-reviewed research
Following completion, some of the land used for a well pad and associated infrastructure can
be returned to the prior use, or to other uses. However, well established natural habitats
cannot necessarily be fully restored following use of the land for shale gas extraction.
Consequently, it may not be possible to fully restore a site, or to return the land to its
previous status resulting in habitat loss (New York State DEC (2011) p6-68), resulting in a
long-term impact as described in previous sections.
Other research
None reviewed
Preliminary judgment
It is judged that land take during the production phase would be ongoing, but at a lower level
than during earlier phases. This is judged to be of potentially minor significance, and would
be a long-term impact likely to be associated with the full development of any large shale gas
formation.
Re-fracturing may be needed during the production phase on up to four occasions, as
described in Section2.2. In this case, the impacts would be similar to those described in
Section 2.6.
2.8.6 Biodiversity impacts
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
minor
moderate
Probability
classification
occasional
occasional
Risk ranking
moderate
high
Peer-reviewed research
There would be a slight potential for disturbance to natural ecosystems during production
phase due to human activity, traffic, land-take, habitat degradation and fragmentation, and
introduction of invasive species (New York State 2011 PR Section 6.4).
Pipelines constructed for use during the production phase would constitute new linear
features, which could adversely affect biodiversity, particularly in sensitive ecosystems.
Other research
None reviewed
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Preliminary judgment
The discussion in New York State 2011 PR Section 6.4 was used to assess the risks to
biodiversity during the production stage.
Re-fracturing may be needed during the production phase on up to four occasions, as
described in Section2.2. In this case, the impacts would be similar to those described in
Section 2.6.
2.8.7 Noise
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
slight
slight
Probability
classification
occasional
occasional
Risk ranking
low
low
Peer-reviewed research
Once completed, there is expected to be minimal ongoing noise from wellhead installations
(New York State 2011 PR p6-300) although no specific information is available on noise
levels.
Other research
Noise may be associated with new gas compressor stations and treatment facilities which
may be needed to handle gas extracted from new well infrastructure (Lechtenböhmer et al.
2011 NPR).
Preliminary judgment
Noise from pipeline construction could affect residential amenity and wildlife, particularly in
sensitive areas. However, this is likely to be lower intensity than other phases in shale gas
development, and not to be correlated with other sources of noise associated with shale gas
extraction.
Re-fracturing may be needed during the production phase on up to four occasions, as
described in Section2.2. In this case, the impacts would be similar to those described in
Section 2.6.
2.8.8 Seismicity
Re-fracturing may be needed during the production phase, as described in Chapter 1. In this
case, the impacts would be similar to those described in Section 2.6, although improved
knowledge gained during the initial fracturing may enable these risks to be reduced.
2.8.9 Visual impact
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
minor
minor
Probability
classification
rare
rare
Risk ranking
low
low
Peer-reviewed research
None reviewed
Other research
None reviewed
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Preliminary judgment
Well head plant and equipment could have a visual impact, particularly in residential areas or
high landscape value areas, but this would be minimal compared to the impacts during the
drilling and fracturing stages.
Pipelines could have a significant visual impact, particularly in residential areas or high
landscape value areas
Re-fracturing may be needed during the production phase on up to four occasions, as
described in Section2.2. In this case, the impacts would be similar to those described in
Section 2.6
2.8.10 Traffic
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
slight
slight
Probability
classification
periodic
periodic
Risk ranking
low
low
Peer-reviewed research
None reviewed
Other research
None reviewed
Preliminary judgment
Transportation of materials and equipment for maintenance could have minor adverse effects
due to noise, community severance etc during the operational phase. These impacts are
judged to be minimal compared to impacts during the drilling, fracturing and completion
stages.
Re-fracturing may be needed during the production phase on up to four occasions, as
described in Section2.2. In this case, the impacts would be similar to those described in
Section 2.6.
2.9 Stage 6: Well / Site Abandonment
Stage 1
Stage 2
Stage 3
Stage 4
Stage 5
Stage 6
The assessment of post-abandonment impacts considers potential impacts over shortmedium timescales and long timescales. Over short-medium timescales of decades, it is
assumed that management and maintenance regimes will be in place. Over long timescales
of hundreds of years, potentially management and maintenance regimes will no longer be in
place.
There is generally little difference between conventional and unconventional wells in the
post-abandonment phase, with the exception of the presence of unrecovered hydraulic
fracturing fluids in the shale formations in the case of hydraulically fractured wells. The
presence of high salinity fluids in shale gas formations indicates that there is normally no
pathway for release of fluids to other formations (New York State 2011 PR p11). Hence, the
issue of potential concern would be the risk of movement of fracturing fluids to aquifers or
surface waters via the well and/or via fractures introduced during the operational phase.
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2.9.1 Groundwater contamination and other risks
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
not classifiable
not classifiable
Probability
classification
not classifiable
not classifiable
Risk ranking
not classifiable
not classifiable
At present, there is little information to enable a judgment to be made regarding the risks
posed by movement of hydraulic fracturing fluid to the surface in the long term. The
presence of high salinity fluids in shale gas formations indicates that there is normally no
pathway for release of fluids to other formations (New York State 2011 PR p11).
Furthermore, some of the chemicals used in fracturing fluids will be adsorbed to the rocks
(e.g. surfactants and friction reducers) and some will be biodegraded in situ (e.g. guar gums
used for gels). For shale gas measures at significant depths, the volume of the rock between
the producing formation and the groundwater is substantially greater than the volume of
fracturing fluid used
Other research
None reviewed
Preliminary judgment
Inadequate sealing of a well could potentially result in subsurface pathways for contaminant
migration leading to groundwater pollution, and potentially surface water pollution.
Experience in the US to date is that the risks posed by poorly controlled and logged historical
wells far outweigh the risks posed by wells designed and constructed to current standards.
However, this experience does not yet extend into the long term (considered to represent
periods of hundreds of years following abandonment).
It is considered likely that unrecorded abandoned wells may be a more significant issue in
Eastern Europe than in Western Europe, but no evidence to substantiate this view could be
identified.
The chemical constituents of hydraulic fracturing fluids remain an area of uncertainty pending
the development of a more extensive database of behaviour of fluids in shale formations over
time.
2.9.2 Release to air
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
minor
moderate
Probability
classification
rare
rare
Risk ranking
low
moderate
Peer-reviewed research
None reviewed
Other research
None reviewed
Preliminary judgment
Inadequate sealing of wells could result in fugitive emissions to air. Experience in the US to
date is that the risks posed by poorly controlled and logged historical wells far outweigh the
risks posed by wells designed and constructed to current standards. However, this
experience does not yet extend into the long term (considered to represent periods of
hundreds of years following abandonment). It is considered likely that unrecorded
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abandoned wells may be a more significant issue in Eastern Europe than in Western Europe,
but no evidence to substantiate this view could be identified.
At present, there is little information to enable a judgment to be made regarding the risks
posed by movement of airborne pollutants to the surface in the long term. It is judged that
any risks are likely to be similar to those posed by conventional wells..
2.9.3 Land take
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
minor
moderate
Probability
classification
not classifiable
not classifiable
Risk ranking
not classifiable
not classifiable
Peer-reviewed research
It may not be possible to return the entire site to beneficial use following abandonment e.g.
due to concerns regarding public safety (New York State DEC 2011, PR Section 6.4).
Other research
None reviewed
Preliminary judgment
It is judged that the consequences for land take at an individual site in the post-abandonment
phase would be comparable with many other industrial and commercial land-uses, and are of
no more than minor significance. It may not be possible to return the entire site to beneficial
use following abandonment, e.g. due to concerns regarding public safety. Over a wider area,
this could result in a significant loss of land, and/or fragmentation of land area such as an
amenity or recreational facility, valuable farmland, or valuable natural habitat. There is no
evidence available to enable the likelihood of permanent effects on land-use to be evaluated.
2.9.4 Biodiversity impacts
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
minor
moderate
Probability
classification
not classifiable
not classifiable
Risk ranking
not classifiable
not classifiable
Peer-reviewed research
It may not be possible to return the entire site to its previous state following abandonment,
which could be particularly significant for sites located in sensitive areas. Over a wider area,
this could potentially result in a significant loss or fragmentation of a sensitive natural habitat
(New York State DEC 2011 PR Section 6.4).
Other research
None reviewed
Preliminary judgment
It is judged that the consequences for biodiversity at an individual site in the postabandonment phase would be comparable with many other industrial and commercial landuses, and are of no more than minor significance. Over a wider area, this could potentially
result in a significant loss of natural habitat. There is no evidence available to enable the
likelihood of effects on biodiversity during the post-abandonment phase to be evaluated.
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2.9.5 Visual impact
Risk Characterisation
Individual installation
Cumulative effects of multiple installations
Hazard
classification
slight
slight
Probability
classification
not classifiable
not classifiable
Risk ranking
moderate or low
moderate or low
Peer-reviewed research
None reviewed
Other research
None reviewed
Preliminary judgment
It may not be possible to remove all wellhead equipment from site. This is not considered
likely to pose a significant impact in view of the small scale of equipment potentially
remaining on site.
2.10 Summary of key issues
The preliminary risk assessment is summarised in Table 5. This table also sets out an
overall risk rating across all project phases. This is identified as the highest rating of any
individual phase as a minimum. A higher risk rating was considered in any cases where the
ongoing nature of shale gas development could potentially warrant a higher risk rating than
was applied to individual phases.
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Table 5: Summary of preliminary risk assessment
Project phase
Site
Environmental
identification
aspect
and
preparation
Well
Well
Overall
design
Well
abandonment
Production
drilling, Fracturing
rating across
completion
and postall phases
casing,
abandonment
cementing
Individual site
Groundwater
contamination
Not
applicable
Low
ModerateHigh
High
ModerateHigh
Not
classifiable
High
Surface water
contamination
Low
Moderate
ModerateHigh
High
Low
Not applicable
High
Not
applicable
Not
applicable
Moderate
Not
applicable
Moderate
Not applicable
Moderate
Low
Moderate
Moderate
Moderate
Moderate
Low
Moderate
Moderate
Not
applicable
Not
applicable
Not
applicable
Moderate
Not
classifiable
Moderate
Not
classifiable
Low
Low
Low
Moderate
Not
classifiable
Moderate
Noise impacts
Low
Moderate
Moderate
Not
classifiable
Low
Not applicable
Moderate –
High
Visual impact
Low
Low
Low
Not
applicable
Low
Low-moderate
Low Moderate
Not
applicable
Not
applicable
Low
Low
Not
applicable
Not applicable
Low
Low
Low
Moderate
Low
Low
Not applicable
Moderate
Water
resources
Release to air
Land take
Risk to
biodiversity
Seismicity
Traffic
Cumulative
Groundwater
contamination
Not
applicable
Low
ModerateHigh
High
High
Not
classifiable
High
Surface water
contamination
Moderate
Moderate
ModerateHigh
High
Moderate
Not
applicable
High
Water
resources
Not
applicable
Not
applicable
High
Not
applicable
High
Not
applicable
High
Low
High
High
High
High
Moderate
High
Land take
Very high
Not
applicable
Not
applicable
Not
applicable
High
Not
classifiable
High
Risk to
biodiversity
Not
classifiable
Low
Moderate
Moderate
High
Not
classifiable
High
Noise impacts
Low
High
Moderate
Not
classifiable
Low
Not
applicable
High
Visual impact
Moderate
Moderate
Moderate
Not
applicable
Low
Low-moderate
Moderate
Seismicity
Not
applicable
Not
applicable
Low
Low
Not
applicable
Not
applicable
Low
High
High
High
Moderate
Low
Not
applicable
High
Release to air
Traffic
Not applicable: Impact not relevant to this stage of development
Not classifiable: Insufficient information available for the significance of this impact to be assessed
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Table 5 highlights the issues potentially associated with road traffic and emissions to air
throughout the project lifetime. These issues are addressed in the following sections of the
report.
Visual impacts would also be ongoing throughout the lifetime of a project to a varying degree.
Based on the findings of New York State DEC (2011 PR p6-283) that visual impacts of
individual facilities are minimal over a distance of 1.5 km, it is judged that the overall risk of
visual impact of cumulative shale gas development can be considered as “moderate.” The
risks posed by noise would continue throughout the initial stages of an unconventional gas
project. In view of this, and reliance on effective abatement to manage the potential impacts
on noise, the overall risk of noise associated with an individual well-pad was considered to
be “moderate to high.”
Table 5 also highlights the uncertainties associated with the post-abandonment phase.
Further research in this area is recommended in Chapter 5.
One issue was identified as “very high” in the European context using this approach:

Land-take during site preparation (cumulative)
This analysis has identified the following “high” significance issues:

Traffic during site preparation (cumulative)

Releases to air during drilling (cumulative)

Noise during drilling (cumulative and due to overall impact across all phases)

Surface water contamination during fracturing (individual installation)

Water resource depletion during fracturing (cumulative)

Traffic during fracturing (cumulative)

Groundwater contamination during completion (individual installation and cumulative)

Surface water contamination during completion (individual installation and cumulative)

Releases to air during completion (cumulative)

Groundwater contamination during production (individual installation)

Releases to air during production (cumulative)

Land take during production (cumulative)

Biodiversity impacts during production (cumulative)
The following issues were identified as being “not classifiable” due to a lack of relevant data:

Potential impacts on biodiversity due to cumulative development in the European
context

Frequency of surface spillages during hydraulic fracturing

Potential frequency and significance of road accidents involving trucks carrying
hazardous substances in support of HVHF operations

Noise impacts due to flaring, and associated controls

Risks of groundwater contamination following abandonment

Land take following abandonment

Risks to biodiversity following abandonment
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The issues identified during the preparation, drilling, fracturing and completion phases are
more significant for high volume hydraulic fracturing than for conventional installations, or are
unique to HVHF. A further set of “moderate” significance issues was identified:

Surface water contamination risks during site identification and preparation
(cumulative)

Land take during site identification and preparation (individual installation)

Visual impact during site identification and preparation (cumulative)

Traffic during site identification and preparation (cumulative)

Surface water contamination risks during well design, drilling, casing and
cementing(individual installation and cumulative)

Release to air during well design, drilling, casing and cementing(individual
installation)

Noise during well design, drilling, casing and cementing (individual installation)

Visual impact during well design, drilling, casing and cementing (cumulative)

Risks of groundwater contamination during hydraulic fracturing preparation (individual
installation and cumulative)

Risks of surface water contamination during hydraulic fracturing (individual installation
and cumulative)

Water resource depletion during hydraulic fracturing (individual installation)

Release to air during hydraulic fracturing (individual installation)

Biodiversity impacts during hydraulic fracturing (cumulative)

Noise during hydraulic fracturing (individual installation and cumulative)

Visual impact during hydraulic fracturing (cumulative)

Traffic during hydraulic fracturing (individual installation)

Release to air during well completion (individual installation)

Biodiversity impacts during well completion (cumulative)

Traffic during well completion (cumulative)

Groundwater contamination and other risks during production (individual installation)

Surface water contamination risks during production (cumulative)

Water resource depletion during production (individual installation)

Release to air during production (individual installation)

Biodiversity impacts during production (individual installation)

Release to air following well abandonment (cumulative)

Visual impact following well abandonment (cumulative)
Particular attention was paid to the “very high” and “high” significance issues in the
subsequent phases of this project. Consideration was also given to the “moderate”
significance issues at the conclusion of the analysis of high/very high significance issues.
The main causes of impacts and risks were as follows:

The use of more significant volumes of water and chemicals compared to
conventional gas extraction
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






The challenge of ensuring the integrity of wells and other equipment throughout the
development, operational and post-abandonment lifetime of the plant (well pad) so as
to avoid the risk of surface and/or groundwater contamination
The challenge of ensuring that spillages of chemicals and waste waters with potential
environmental consequences are avoided during the development and operational
lifetime of the plant (well pad)
The challenge of ensuring a correct identification and selection of geological sites,
based on a risk assessment of specific geological features and of potential
uncertainties associated with the long-term presence of hydraulic fracturing fluid in
the underground
The potential toxicity of chemical additives and the challenge to develop greener
alternatives
The unavoidable requirement for transportation of equipment, materials and wastes to
and from the site, resulting in traffic impacts that can be mitigated but not entirely
avoided.
The potential for development over a wider area than is typical of conventional gas
fields
The unavoidable requirements for use of plant and equipment during well
construction and hydraulic fracturing. This equipment necessarily requires space to
be sited and operated, and results in unavoidable emissions to air and noise impacts.
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3 The efficiency and effectiveness of
current EU legislation
3.1 Introduction to the legal review
Chapter 2 provides an overview of the environmental and health risks of hydrocarbons
operations involving hydraulic fracturing, in particular HVHF in each project phase. In
Chapter 3, the appropriateness of the EU legal environmental framework is analysed and
conclusions are drawn regarding the degree to which the current EU framework adequately
covers these risks. Developing an understanding of EU legislation applying to in particular
high-volume hydraulic fracturing is the key basis for understanding the need for control
against any eventual gaps in the EU regulatory framework in relation to possible net
incremental risks of these techniques identified in Chapter 2, and summarised in section
2.10.
Potentially relevant regulatory risk management measures considered, proposed or adopted
for hydrocarbons operations using hydraulic fracturing techniques are set out in Appendix 7
and summarised in Chapter 4.
3.2 Objectives and approach
The objectives of the review of relevant legislation within this study are:

Identifying potential uncertainties with regard to the degree to which shale gas
exploration and production specific risks and impacts are covered under current EU
legislation applicable to such operations in the EU

Identifying risks and impacts which are not covered by existing EU legislation

Drawing conclusions with regard to the key risks to the environment and human
health of such operations in the EU
The study was designed to provide an appreciation of the appropriateness of the legislation
in place for ensuring an adequate level of protection to the environment and to humans. The
study identifies whether this legislation is appropriate to address risks of operations involving
hydraulic fracturing and in particular high-volume hydraulic fracturing. It identifies which
European laws apply; whether the provisions are adequate; what (if anything) is missing; and
whether there are relevant areas where no EU provisions exist. The study uses definitions
from the legislative documents where appropriate. In some instances, these differ from one
legislative instrument to another.
Pieces of EU legislation described below are essentially Directives (with the exception of the
REACH Regulation), which naturally do not result in a full harmonisation of rules and
practices among Member States as they allow for a degree of Member State autonomy in
their implementation. This clearly leads to the possibility of different approaches being
adopted, with potential differential treatment of environmental or human health impacts.
Limitations of the analysis
Given the breadth of the scope as well as time and resource limitations, this report does not
elaborate on international conventions, standards and industry guidelines. This study does
not aim to assess the extent to which existent jurisprudence by the European Court of
Justice would provide sufficient clarity on relevant issues identified by this study (concerning
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for example the Environmental Impact Assessment Directive (2011/92/EU), EU waste and
water legislation, etc.) This could potentially have a bearing on the study findings regarding
the EIA Directive and possibly other pieces of EU legislation. Relevant International
Standards Organisation (ISO) standards for the hydrocarbon extraction industry are listed in
Appendix 8.
Likewise, we do not consider the extent to which health and safety legislation could influence
or reduce risks to the environment from HVHF. The most applicable legislation in respect of
health and safety is the Directive concerning minimum requirements for improving health and
safety of workers in the mineral-extracting industries through drilling (Directive 92/91/EEC).
It is also beyond the scope of this study to examine the consistency of Member States’
transposition and implementation of EU legislation, but this is a factor in the ultimate level of
environmental protection or remediation required for developments involving hydraulic
fracturing, in particular HVHF. Within the present project we therefore highlight below
instances where, in line with applicable rules, the extent of environmental protection is
governed by Member State decision-making. In these cases it cannot be concluded that the
associated risks are sufficiently or adequately addressed at EU level. It is beyond the scope
of this study to assess the sufficiency or adequacy of Member State measures.
Summary
Summarising the above, including the acknowledged limitations of this study, this section
draws three categories of conclusion with regard to the potential for inadequacy in the way
risks are dealt with in the EU legislation;

Inadequacies in EU legislation that could lead to risks to the environment or human
health not being sufficiently addressed.

Potential inadequacies - uncertainties in the applicability of EU legislation: the
potential for risks to be insufficiently addressed by EU legislation, where uncertainty
arises because of lack of information regarding the characteristics of HVHF projects.

Potential inadequacies - uncertainties in the existence of appropriate requirements at
national level: for aspects relying on a high degree of Member State decision-making
it is not possible to conclude whether or not at EU level the risks are adequately
addressed.
3.3 Study Overview
The assessment starts by analysing the EU environmental acquis, using the Commission's
legal assessment of the applicable framework (EC, 2011) as the starting point. Given more
in-depth information about the type and nature of risks related to hydraulic fracturing and in
particular HVHF, a number of conclusions in this report may go further than the
Commission's interpretation providing better insights with regard to particular legal aspects.
For instance, this appears to be the case with regard to the Environmental Impact
Assessment (EIA) Directive 2011/92/EU, under which an EIA is not (always) mandatory with
regard to shale gas extraction activities due to the fact that:
o
o
o
activities are expected not to fall within the scope of Annex I of the Environmental
Impact Assessment Directive (2011/92/EU).
it is questionable whether shallow drillings are covered when looking at Annex II
of the same Directive.
approaches between Member States could differ regarding the way in which risk
and impacts are weighted and whether or not an EIA is required. In that sense
the Environmental Impact Assessment Directive (2011/92/EU) in itself does not
prescribe that an EIA, addressing the risks and impacts identified in Chapter 2, is
mandatory.
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This analysis and other regulatory aspects are identified and discussed below. In Table 6,
the pieces of legislation falling within the scope of the analysis are listed to provide an
enhanced overview.
Table 6: Overview of relevant EU legislation
Number Legislative measure
1.
Strategic Environmental Impact Assessment Directive (2001/42/EC)
(relating to plans and programmes only)
2.
Environmental Impact Assessment Directive (2011/92/EU)
3.
Integrated Pollution and Prevention Control - Directive (2008/1/EC), if applicable
4.
Industrial Emissions Directive (2010/75/EC), if applicable
5.
Mining Waste Directive(2006/21/EC)
6.
Environmental Liability Directive (2004/35/EC)
7.
Waste Framework Directive (2008/98/EC)
8.
Water Framework Directive (2000/60/EC)
9.
Groundwater Directive (2006/118/EC)
10.
Noise Directive (2002/49/EC)
11.
Air Quality Directive (2008/50/EC)
12.
Habitats Directive (1992/43/EEC)
13.
Birds Directive(2009/147/EC)
14.
REACH (Regulation 1907/2006/ EC)
15.
Biocidal Products Directive (98/8/EC)
16.
Authorization (for the prospection, exploration and production) of hydrocarbons Directive (94/22/EC)
17.
SEVESO II Directive (1996/82/EC)
18.
1992/29/Euratom Directive
19.
Urban wastewater Directive (97/271/EEC)
Some pieces of legislation are relevant for all of the project phases and some only come into
play at certain stages (e.g. when actual shale gas extraction activities take place). However,
the impacts tackled by the different pieces of legislation might differ. In the following
sections, the impacts identified per well development stage are considered, and the
legislation relevant for tackling these impacts is discussed.
In section 3.4, an analysis is provided of directives which are not specific to individual risks or
stages of the shale gas production process.
In sections 3.5 to 3.15, the impacts identified in section 2.10 as potentially being of “very
high” or “high” significance are discussed in the context of legislation which is relevant for
these impacts. Where appropriate, reference is made to the general provisions described in
section 3.4. These more severe impacts are treated as bounding cases and it can be
expected that less severe impacts would be either covered by the legislation in a similar
manner or be considered insufficiently significant to be addressed by the legislation.
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This analysis covers the impacts of most significant potential concern with regard to the use
of high volume hydraulic fracturing techniques in Europe. The provisions and analysis set
out in section 3.4 to 3.15 also addresses the majority of potential impacts of lower (moderate)
priority identified in Chapter 2. In section 3.16, a brief discussion is provided of “moderate”
priority issues. The overall conclusions of the regulatory analysis are provided in section
3.17.
3.4 General provisions
There are several steps that a competent authority should take prior to granting development
consent - see Strategic Environmental Assessment Directive (2001/42/EC) and
Environmental Impact Assessment Directive (2011/92/EC). These steps give the competent
authorities the legal framework for impact assessments, permits and other decisions.
Among these steps are:

Deciding which area is to be permitted for exploration;

Identifying where environmental assessments have to be undertaken; and

Identifying which permits can or should be granted.
In this section we cover these more general directives and the extent to which they are
relevant to the use of High Volume Hydraulic Fracturing (HVHF) for hydrocarbons
operations. The final subsection of section 3.4 presents a consolidated review of the
monitoring and inspection requirements specified by the IPPC Directive (2008/1/EC), the
Mining Waste Directive (2006/21/EC) and the Water Framework Directive (2000/60/EC).
The section starts with the level of planning and decision making. In this case it is the
decision of a national competent authority to dedicate a certain area for prospecting,
exploration or production of hydrocarbons. Subsequently it is decided whether or not to
grant permits to entities who apply for the authorisation of prospecting, exploring or
producing. An important distinction to make, therefore, is that some Directives relate to
plans/programmes and others to developments/projects. This is explained in the discussion
of each Directive below.
At the start of the actual prospecting, any necessary environmental assessments have to be
carried out, and any required environmental permits have to be applied for.
3.4.1 Strategic Environmental Assessment Directive (2001/42/EC)
The Strategic Environmental Assessment Directive (2001/42/EC) obliges Member States to
provide strategic environmental assessments (SEA) of all governmental programmes and
plans that might have significant environmental impacts. The SEA is aimed at providing the
necessary information for the authorities to decide on their plan taking into account the
environmental risks and impacts associated with, in this case, high volume hydraulic
fracturing processes.
Article 2 of Strategic Environmental Assessment Directive (2001/42/EC) defines ‘plans and
programmes’ as plans and programmes, including those co-financed by the European
Community, as well as any modifications to them:
— which are subject to preparation and/or adoption by an authority at national, regional or
local level or which are prepared by an authority for adoption, through a legislative procedure
by Parliament or Government, and
— which are required by legislative, regulatory or administrative provisions.
Article 3(2) of the Strategic Environmental Assessment Directive (2001/42/EC) sets out that
an environmental assessment (EA) shall be carried out for all plans and programmes which
are prepared for, inter alia, energy, industry, waste management, water management and
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country planning or land use which set the framework for future development consent of
projects listed in Annexes I and II of the Environmental Impact Assessment Directive
(2011/92/EU). Additionally, an environmental assessment is mandatory for plans and
programmes which require an assessment related to the Habitats Directive (1992/43/EEC).
With regard to the Strategic Environmental Assessment Directive (2001/42/EC), and its
relation to the impact of shale gas activities, a key consideration is whether there exist or
could exist relevant overlying programmes/plans subject to an SEA obligation. Country
planning programmes fall within this category. Annex II of the Environmental Impact
Assessment Directive (2011/92/EU) mentions, in the section Extractive Industry, d) deep
drillings and e) Surface industrial installations for the extraction of coal, petroleum, natural
gas and ores, as well as bituminous shale. Because shale gas is natural gas, an SEA is
required for plans and programmes concerning the country planning of shale gas activities.
Decisions on granting and using authorisations for prospection, exploration and production of
hydrocarbons concern the use of areas of land and are therefore considered country
planning. Only in the case of the use of small areas at local level a SEA is not mandatory
according to article 3(3) of the Strategic Environmental Assessment Directive (2001/42/EC).
Member States can require a SEA in those cases if they determine that there are likely
significant environmental effects.
The first step that a competent authority has to undertake, when considering opening the
possibility of granting permits or authorisations for prospecting, exploring or producing
hydrocarbons is to carry out a strategic environmental assessment.
Annex I provides guidance related to the information that should be reported in the strategic
environmental assessment. Impacts that should be covered are stated in Annex I (f): the
likely significant effects (1) on the environment, including on issues such as biodiversity,
population, human health, fauna, flora, soil, water, air, climatic factors, material assets,
cultural heritage including architectural and archaeological heritage, landscape and the
interrelationship between the above factors.
When looking at other hydraulic fracturing impacts, there is no explicit reference to resource
(e.g. water) use, impacts on the underground environment and noise (human health) and
nuisance factors (such as from traffic). However, Annex I(f) states that “the likely significant
effects on the environment should be taken into account.” We therefore consider these to be
covered.
Conclusions on applicability of the Strategic Environmental Assessment Directive
(2001/42/EC)

The Strategic Environmental Assessment Directive (2001/42/EC) is applicable since
shale gas extraction activities fall within the scope defined in Article 3(2). This means
that a strategic environmental assessment is obligatory in as far as Member States
develop public plans and programmes related to shale gas extraction activities.

The Strategic Environmental Assessment Directive (2001/42/EC) is aimed at
targeting all the relevant significant environmental aspects (Annex I). We therefore
consider these to also be covered, perhaps with the exception of certain specific
aspects, including geological aspects, for which there is no explicit reference.
3.4.2 Environmental Impact Assessment Directive (2011/92/EU)
As indicated in the Commission’s legal interpretation of the environmental acquis (EC,
2011a), the Environmental Impact Assessment Directive (2011/92/EU) is relevant to HVHF
activities.
Article 2(1) of the Environmental Impact Assessment Directive (2011/92/EU) requires that
“Member States shall adopt all measures necessary to ensure that, before consent is given,
projects likely to have significant effects on the environment by virtue, inter alia, of their
nature, size or location are made subject to a requirement for development consent and an
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assessment with regard to their effects.” The projects to which these provisions are
applicable are defined in Article 4 of the Environmental Impact Assessment Directive
(2011/92/EU). The aspects covered by the Environmental Impact Assessment therefore play
an important role in the development consent of the project and through this route the
competent authority has the powers to impose measures to protect and preserve the
environment potentially impacted by the development. However, it is uncertain if an EIA will
automatically be mandatory for shale gas extraction activities. The reason for this is
discussed in the paragraphs below.
Obligation to carry out an EIA for projects concerning high volume hydraulic
fracturing processes
According to Article 4(1) of the Environmental Impact Assessment Directive (2011/92/EU), an
assessment is obligatory for certain projects mentioned in Annex I. This annex lists:
“Extraction of petroleum and natural gas for commercial purposes where the amount
extracted exceeds 500 tonnes/day in the case of petroleum and 500,000 cubic metres/day in
the case of gas.” Operator information quoted by New York State DEC (2011 PR p5-139)
indicates that the maximum foreseeable production rate in the initial phases of a well in the
Marcellus Shale would be 250,000 m3 per day, rapidly declining to less than 100,000 m3 per
day (see section 1.4.2). Preliminary indications from exploratory drilling in Europe suggest
that production rates are likely if anything to be lower than in the US (Bloomberg, 2012 NPR).
Consequently, it is unlikely that the threshold of 500,000 cubic metres/day will be met in case
of shale gas production at a single well. However, for multiple well sites, the total production
rate could exceed the 500,000 cubic metres/day threshold. The Environmental Impact
Assessment Directive (2011/92/EU) is clear that cumulative impacts need to be taken into
account (as discussed below) when Member States apply discretion in the requirement for
an EIA, but it is not explicit in stating whether or not the production rates from multiple
projects need to be taken into account in determining the need for an EIA under Annex I.
The obligation for conducting an EIA is derived from the general notion that environmental
impacts that might be significant must be known before a decision on project is made. The
assessment must have a role in the decision making process. One of the reasons for this
lies in the precautionary principle. Given this principle, and the fact that the impacts related
to HVHF processes are higher than those of conventional gas production and the chance of
occurrence of the impacts is greater (as discussed in Chapter 2), it would make sense to
have a lower threshold. This threshold is applicable for the expected maximum production
capacity within the project and should be used at the outset of the approval process for the
project.
However, Article 4(2) provides discretionary powers for Member States to require an
environmental impact assessment (EIA) for projects listed in Annex II of the Environmental
Impact Assessment Directive (2011/92/EU). These include projects in the extractive
industries, with specific reference to underground mining, deep drillings and surface
industrial installations for the extraction of natural gas (among others) and surface storage of
natural gas.
Under Article 4(2) Member States themselves shall determine whether the project shall be
made subject to an EIA through either a case-by-case examination or setting thresholds or
criteria (or both). In doing so they are obliged to take into account the relevant selection
criteria given in Annex III of the Environmental Impact Assessment Directive (2011/92/EU).
These criteria involve:

Characteristics of projects, in particular: size, cumulation with other projects, use of
natural resources, production of waste, pollution, nuisances and risks of accidents;

Location of projects, in the sense that the environmental sensitivity of geographical
areas likely to be affected by projects must be considered;
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
Characteristics of the potential impact, including: the extent of the impact, the
transfrontier nature of the impact, the magnitude and complexity of the impact, the
probability of the impact and the duration, frequency and reversibility of the impact.
Furthermore, according to the EC’s “guidance note on the application of Directive
85/337/EEC to projects related to the exploration and exploitation of unconventional
hydrocarbon” (EC, 2011 NPR), the overall objective (to apply to projects with significant
effects on the environment) should be taken into account. That guidance also makes clear
that the examples under the Annex IId reference to deep drillings should be treated as
indicative and to be taken as including unconventional hydrocarbon projects that use deep
drillings.
However, uncertainty may remain in relation to a shallow well by virtue of lack of precision
over the definition of “deep drilling”, which would not cover shallow drilling activities (not
defined). Based on Annex II (2) (e) though “Surface industrial installations for the extraction
of coal, petroleum, natural gas and ores, as well as bituminous shale,” Member States are
obliged to determine whether or not a project shall be made subject to an EIA for installations
related to the extraction of natural gas.
Scope of EIA
The Environmental Impact Assessment Directive (2011/92/EU) requires an assessment of
projects likely to have significant effects on the environment. It is not specific as to what
those measures are but arguably can be considered adequate in that there are no limitations
regarding impacts that could be excluded (i.e. true goal-based approach). If hydraulic
fracturing were to result in unforeseen impacts then they may not be addressed through EIA,
but this would be a weakness in the understanding of the technology, and not the
construction of the EIA legislation which is a horizontal instrument by nature. In relation to
this aspect, the EC guidance regarding application of Environmental Impact Assessment
Directive (2011/92/EU) to unconventional hydrocarbon projects (EC, 2011 NPR) stated that
unconventional hydrocarbon projects would be subject to an EIA if it cannot be excluded, on
the basis of objective information, that the project will have significant environmental effects.
The precautionary and prevention principles also imply that in case of doubts as to the
absence of significant effects, an EIA must be carried out.
The EIA Directive (2011/92/EC) has no explicit coverage of geomorphological and
hydrogeological aspects, and there is a lack of clarity as to whether there is an obligation to
assess impacts related to geological features as part of the impact assessment. This might
lead to a knowledge gap and could potentially result in significant impacts to groundwater.
Also of significance is the list of specific selection criteria contained in Annex III of the
Environmental Impact Assessment Directive (2011/92/EU), which guides Member States in
the decision on whether an EIA is required under Article4(3). If significant impacts from
hydraulic fracturing were not covered by Annex III then this would be an inadequacy of the
legislation. In the table below we list the Annex III criteria alongside the relevant aspects of
hydraulic fracturing.
Table 7: Relevance of criteria in Environmental Impact Assessment Directive
(2011/92/EU) Annex III to hydrocarbons activities involving the use of HVHF
Annex III aspect
CHARACTERISTICS OF PR OJECTS
The characteristics of projects must be
considered having regard, in particular, to:
 the size of the project

the cumulation with other projects
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Relevance to hydrocarbons activities
involving the use of high volume hydraulic
fracturing
This recognises the potential scale of the project
including its expansion
Covers cumulative effects including those with
other technologies/activities
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Annex III aspect


the use of natural resources
the production of waste

pollution and nuisances

the risk of accidents, having regard in
particular to substances or technologies
used
LOCATION OF PR OJECTS
The environmental sensitivity of geographical
areas likely to be affected by projects must be
considered, having regard, in particular, to:
 the existing land use
 the relative abundance, quality and
regenerative capacity of natural resources in
the area
 the absorption capacity of the natural
environment, paying particular attention to
the following areas
o wetlands
o
coastal zones
o
mountain and forest areas
o
nature reserves and parks
o
[protected areas listed under point 2(v)
of Annex III]
areas in which the environmental
quality standards laid down in Union
legislation have already been exceeded
densely populated areas
o
o
o
landscapes of historical, cultural or
archaeological significance
CHARACTERISTICS OF THE POTENTIAL
IMPACT
The potential significant effects of projects must
be considered in relation to criteria set out in
points 1 and 2, and having regard in particular to:
 the extent of the impact (geographical area
and size of the affected population)

the transboundary nature of the impact

the magnitude and complexity of the impact
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Relevance to hydrocarbons activities
involving the use of high volume hydraulic
fracturing
Particularly relevant to water abstraction
Covers mining waste and waste hydraulic
fracturing fluids including constituents
Recognises noise, traffic and visual impacts as
well as surface water and groundwater
contamination and gaseous emissions
Recognises risks, especially relevant to those
posed by accidental release of hydraulic
fracturing fluids, fluid additives, waste waters, or
gaseous emissions
Acknowledges land take and usage
Recognises local context to land use
Considers impacts on water bodies from
additives, fracturing liquids, treated and untreated
waste water
Considers impacts on water bodies from
additives, fracturing liquids, treated and untreated
waste water
Covers deforestation from land clearance and for
road construction
Recognises impacts on reserves and local
amenities from all impacts
Covers potential impacts on protected
ecosystems
Covers cumulative and additional effects for all
pollution types
Recognises elevated risks to higher density local
populations, covering effects of groundwater and
drinking water contamination, air pollution, noise,
visual impact
Addresses the significance of land take and land
usage in the context of local landscape
importance
Covers the scale of hydraulic fracturing zones. It
is unclear whether this point is intended to cover
the underground environment
Covers impacts crossing boundaries and with
potentially great extent
Covers the size of the impact and recognising
complexities such as those related to risks of
contamination of water bodies with highly toxic
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Annex III aspect

the probability of the impact

the duration, frequency and reversibility of
the impact
Relevance to hydrocarbons activities
involving the use of high volume hydraulic
fracturing
hydraulic fracturing substances, at low and high
concentrations
Will require consideration of the likelihood of
accidental releases of hydraulic fracturing fluids,
additives, waste waters, air pollutants, invasive
species etc
Acknowledges temporal extent of impacts, the
reversibility and residual environmental impact
An environmental impact assessment must address the whole project, since impacts that
might occur in any one of the project stages might be significant enough to deny the approval
for the project as a whole.
With regard to the assessment of impacts in Chapter 2, the following are clearly covered by
the above list (the Environmental Impact Assessment Directive (2011/92/EU) covers the
whole life of the project and therefore the covered impacts are not identified against project
stage):

Surface water contamination risks

Release to air

Land take

Noise

Visual impact

Traffic

Groundwater contamination

Water resource depletion
Nevertheless, under the EIA Directive there is less clarity on the treatment of impacts from
underground activities. This is implicitly covered by the inclusion of pollution (which can be
underground) under project characteristics, but underground environments are not explicitly
mentioned. There is no reference to seismicity within the Annex, although again implicitly
environmental impacts related to induced seismic activity would be covered.
Impacts on biodiversity are not explicitly listed but would be accounted for insofar as
important species reside within protected areas listed under point 2(v) of Annex III, or in
relation to impacts on biodiversity caused by releases of pollution, noise or other impacts
which are covered. Impacts on flora and fauna at other areas of nature conservation value
are to be assessed in an EIA. It is up to Member States to indicate the nature conservation
value of the area(s) concerned in the vicinity of the proposed production site(s).
The EIA must, according to Article 5 and Annex IV, provide information on the project itself,
the location, size, time of operation, etc. It must also provide information on the possible
impacts of the project and the measures foreseen to prevent or mitigate the impacts. This
information should cover the direct effects and any indirect, secondary, cumulative, short,
medium and long-term, permanent and temporary, positive and negative effects of the
project. For the projects concerning hydrocarbons operations involving hydraulic fracturing
this means that at least the impacts addressed in chapter 2 of this report will be taken into
account in an EIA. The estimated or calculated impacts will be decisive for the competent
authorities for their decision on for instance granting a permit for exploration or extraction.
This also includes providing information on the use of chemicals and its properties.
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Disclosure of the information on these chemicals is also regulated through the REACH
regulation (1907/2006/EC), Articles 117 and 118.
The EIA must take into account other projects that cumulatively might result in larger impacts
on the environment. This means that an EIA on a shale gas project must also describe other
projects in the same area and the effects of multiple wells. This is done in order to prevent
the slicing of projects into smaller parts just to reduce the environmental impacts.
Projects concerning hydrocarbons operations involving hydraulic fracturing usually start with
a few wells to be expanded with more wells in due time. This expansion is to be foreseen in
the EIA and is to be taken into account. A thorough assessment of the impacts of also future
wells must be part of the EIA. A multiple well site should be assessed with the same
methods as a single or double well site. The location of the (future) wells must be known in
order to address and assess the impacts. In addition, this means that the output of a multiple
well site must be taken into account when determining whether the Annex I threshold of
500,000 cubic metres/day is exceeded.
The size of a project that could be the subject of an EIA is not limited by law, nor in practice,
by the feasibility of assessing the impacts. All activities in the project at all locations must be
described and assessed.
An EIA can be conducted in a very large area and for projects that have several phases in
process. In general one should start with a survey of the main impacts that can occur and at
least should be addressed in the EIA. This is a scoping phase in the assessment project. In
this scoping phase the area of study for the assessment is also part of this first step. With
the use of the SEA, the most important impacts and areas of concern may already be known,
provided there are national public plans or programmes encompassing shale gas activities.
This would make it possible to conduct a meaningful EIA even if there is a large number of
well sites. Each of these sites has its own characteristics, but they also have many common
features.
The public shall be informed, whether by public notices or by other appropriate means such
as electronic media where available, of the matters set out in Article 6 early in the
environmental decision-making procedures. The information collected under Article 5 on the
project itself, its impacts and the foreseen measures to prevent or to mitigate the impacts
shall also be made available to the public. The public concerned shall be given early and
effective opportunities to participate in the environmental decision- making procedures
referred to in Article 2(2) and shall, for that purpose, be entitled to express comments and
opinions.
In this way the public has the opportunity to participate in the decision making process by
giving comments and opinions. According to Article 8 the results of consultations and the
information gathered pursuant to Articles 5, 6 and 7 shall be taken into consideration in the
development consent procedure.
Article 11 of the EIA directive (2011/92/EC) regulates the public’s right to have access to a
review procedure before a court of law or another independent and impartial body
established by law to challenge the substantive or procedural legality of decisions, acts or
omissions subject to the public participation provisions of this Directive.
Conclusions on applicability of Environmental Impact Assessment Directive
(2011/92/EU)

According to Article 4(1) of the Environmental Impact Assessment Directive
(2011/92/EU), an assessment is mandatory for certain projects mentioned in Annex I.
Shale gas extraction activities are expected not to fall under the activities listed in Annex I
due to the fact that they will not likely reach the 500,000m3/day gas extraction threshold
stated in that Annex.
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
The impacts of HVHF processes can be greater than the impacts of conventional gas
exploration and production processes per unit of gas extracted. The use of a single
volume threshold for all gas extraction activities in Annex I could lead to more severe
impacts from HVHF not being assessed in an impact assessment under this Directive.
This is an inadequacy in the EU legislation that could lead to risks not being sufficiently
addressed. It is beyond the scope of this work to examine alternative thresholds or
approaches for HVHF.

Member States must decide whether an EIA is required (Article 4(2)) for activities
covered by Annex II. Guidance on making this decision is given in the Directive but
approaches between Member States could differ regarding the way in which risk and
impacts are weighed and whether or not an EIA is required. It is not possible to conclude
that risks are adequately addressed at EU level and it is beyond the scope of this project
to assess the adequacy of Member State decision-making for activities in Annex II. We
consider it appropriate though that the requirement for EIA for HVHF projects falling
outside of Annex I be assessed on the basis of project specific characteristics, as is the
approach taken in the Directive.

Based on the characteristics of shale gas extraction activities they fall within the scope of
Annex II of the Environmental Impact Assessment Directive (2011/92/EU) with regards
Annex II (2) (e) for “Surface industrial installations for the extraction of coal, petroleum,
natural gas and ores, as well as bituminous shale” (which however would not cover
exploration activities) and, insofar as they constitute “deep drillings” as specified in Annex
II (2)(d) (which would cover both exploration and extraction activities).

However, uncertainty may remain in relation to a shallow well by virtue of lack of
precision over the definition of “deep drilling”, which would not cover shallow drilling
activities (not defined). This is an inadequacy of legislation at EU level. In addition,
geological/underground aspects are not explicitly mentioned.

If an EIA is deemed appropriate by a national authority, cumulative impacts are covered
by the Environmental Impact Assessment Directive (2011/92/EU). This is specified in
Article 5(1) and Annex IV of the Directive.
3.4.3 Hydrocarbons Authorization Directive (94/22/EC)
The Hydrocarbons Authorization Directive (94/22/EC) sets a common framework aimed at
guaranteeing non-discriminatory access to the activities of prospection, exploration and
production of hydrocarbons. It stipulates that the limits of the geographical areas covered by
an authorisation and the duration of that authorisation must be determined in proportion to
what is justified in terms of the best possible exercise of the activities from an economic and
technical point of view.
The Hydrocarbons Authorization Directive (94/22/EC) prescribes that Member States shall
take the necessary measures to ensure that authorizations are granted on the basis of
certain criteria, concerning in all cases the way in which applicants propose to prospect,
explore and/or bring into production the geographical area in question (Article 5(1b)). It is not
specifically aimed at addressing the risks and impacts identified in Chapter 2, as it focuses
on ensuring fair competition in the internal market. At most, this directive allows Member
States to provide in authorization conditions imposed on concession holders if this is justified
from, e.g., the perspective of environmental protection and protection of biological resources
(amongst others Article 6(2)). This provision makes it possible for Member States to draft
authorization conditions aimed at preventing or mitigating environmental impacts it deems
necessary. In this respect there is arguably a potential overlap with the Mining Waste
Directive (2006/21/EC), which puts in place specific conditions associated with managing the
environmental aspects of mining waste management. However, as such measures are not a
requirement under the Hydrocarbons Authorization Directive (94/22/EC), Member States
themselves determine if and how to implement the option in practice. This is not a gap in the
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EU legislation per se and it is beyond the scope of this study to go into the degree to which
Member States make use of the option under the Hydrocarbons Directive to draft
authorization conditions aimed at preventing or mitigating environmental impacts.
In accordance with the Convention on Access to Information, Public Participation in Decisionmaking and Access to Justice in Environmental Matters (Aarhus Convention) public
participation is required in respect of permitting decisions for activities listed in Annex I to the
convention (Article 6). These include, inter alia, installations for the treatment and disposal of
waste and hazardous waste (point 5), extraction of natural gas exceeding 500,000 m3/day
(point 12) and other activities for which national environmental impact assessment legislation
requires public participation (point 20). These provisions potentially therefore require public
participation in the procedure for authorisations granted under the Hydrocarbons
Authorization Directive (94/22/EC).
3.4.4 Integrated Pollution Prevention and Control Directive (2008/1/EC)
The IPPC Directive (2008/1/EC) has the objective of achieving integrated prevention and
control of pollution arising from the activities that cause significant pollution. It lays down
measures designed to prevent or, where that is not practicable, to reduce emissions in the
air, water and land from these activities, including measures concerning waste, in order to
achieve a high level of protection of the environment taken as a whole.
In order to achieve this objective, the directive consists of a system of permitting, setting
emission standards, monitoring and documents for best available technology.
Activities covered by the Directive
Annex I of the IPPC Directive (2008/1/EC) states the activities that fall under the jurisdiction
of the directive. This covers energy industries, production and processing of metals, mineral
industry, chemical industry and waste management.
Annex I includes combustion emissions from combustion installations in energy industries
which have a rated thermal input of over 50MW. New York DEC 2011 PR (p6-100) identifies
drilling rig power of 5400Hp, implying at a thermal input at 50% efficiency (illustrative) a
thermal input of 8MW; well below the IPPC threshold. This means that combustion
emissions from single drilling rigs are not covered by the IPPC Directive (2008/1/EC).
However, Annex I also states that if there are multiple installations on the site, the total
thermal input of all installations should be used as the value to meet the threshold, leading to
the potential for large multiple well operations to be covered.
A further area of potential relevance to shale gas lies in the hazardous waste treatment
installations, principally for hazardous waste. The used hydraulic fracturing fluids that return
from the well or stay underground and will not be reused are considered waste.
Annex I section 5.1 includes:
Installations for the disposal or recovery of hazardous waste as defined in:

the list referred to in Article 1(4) of Directive 91/689/EEC (Council Directive on
hazardous waste, amended by Directive 2008/98/EC)

Annexes II A and II B to Directive 2006/12/EC (Council Directive on hazardous waste)

Council Directive 75/439/EEC on the disposal of waste oils (2),
with a capacity exceeding 10 tonnes per day.
In this case hazardous waste’ means hazardous waste as defined in point 2 of Article 3 of
the Waste Framework Directive (2008/98/EC). “‘hazardous waste’ means waste which
displays one or more of the hazardous properties listed in Annex III;” That directive cites the
following (with descriptions):

‘Explosive’
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
‘Oxidizing’

‘Highly flammable’

‘Flammable’

‘Irritant’

‘Harmful’

‘Toxic’

‘Carcinogenic’

‘Corrosive’

‘Infectious’

‘Toxic for reproduction’

‘Mutagenic’

Waste which releases toxic or very toxic gases in contact with water, air or an acid.
‘Sensitizing’

‘Ecotoxic’

Waste capable by any means, after disposal, of yielding another substance, e.g. a
leachate, which possesses any of the characteristics listed above.
To clarify these points the Waste Framework Directive (2008/98/EC) notes:
1. Attribution of the hazardous properties ‘toxic’ (and ‘very toxic’), ‘harmful’, ‘corrosive’,
‘irritant’, ‘carcinogenic’, ‘toxic to reproduction’, ‘mutagenic’ and ‘eco-toxic’ is made on the
basis of the criteria laid down by Annex VI, to Council Directive 67/548/EEC of 27 June 1967
on the approximation of laws, regulations and administrative provisions relating to the
classification, packaging and labelling of dangerous substances.
2. Where relevant the limit values listed in Annex II and III to Directive 1999/45/EC of the
European Parliament and of the Council of 31 May 1999 concerning the approximation of the
laws, regulations and administrative provisions of the Member States relating to the
classification, packaging and labelling of dangerous preparations shall apply.
The US House of Representatives Committee on Energy and Commerce inquiry into the
practice of hydraulic fracturing in the US examined the constituents of hydraulic fracturing
fluids (US House of Representatives, 2011 NPR). It noted (page 1) that additive products
included 29 chemicals that are: (1) known or possible human carcinogens; (2) regulated
under the Safe Drinking Water Act for their risks to human health; or (3) listed as hazardous
air pollutants under the Clean Air Act. This would suggest that the disposal of hydraulic
fracturing fluids would be covered by the IPPC Directive (2008/1/EC) due to the potentially
hazardous constituent compounds. New York State DEC (2011 PR p5-54 onwards),
examines the potential constituents of hydraulic fracturing fluids and concludes that
“Chemicals in products proposed for use in high-volume hydraulic fracturing include some
that, based mainly on occupational studies or high-level exposures in laboratory animals,
have been shown to cause effects such as carcinogenicity, mutagenicity, reproductive
toxicity, neurotoxicity or organ damage.” However the effect that these could have on human
health depend on exposure routes.
This suggests that hydraulic fracturing fluids could constitute hazardous waste: however
further detailed examination of hydraulic fracturing additives would be required to confirm
their classification as hazardous under the Waste Framework Directive (2008/98/EC).
Thresholds for the constituents of liquids to determine classification as hazardous wastes
require specific values to be calculated, under the terms of the Classification, Packaging and
Labelling Directive (1999/45/EC). Furthermore, In order to harmonise the approach of
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declaring waste as hazardous, the European Commission issued a decision 2000/532/EC
which gives thresholds on substances in waste. Wastes with characteristics above these
thresholds are classified as hazardous. The assessment of whether hydraulic fracturing
fluids could be hazardous would need to be carried out on a case by case basis, in view of
the variability in constituents of fracturing fluids.
Annex I of the IPPC Directive (2008/1/EC) also identified non-hazardous waste disposal as
requiring an IPPC permit under certain circumstances. It includes (point 5.3): “Installations
for the disposal of non-hazardous waste as defined in Annex II A to Directive 2006/12/EC
under headings D8 and D9, with a capacity exceeding 50 tonnes per day,” where headings
D8 and D9 specify biological and physico-chemical treatment respectively. Whilst hydraulic
fracturing injection rates could exceed this threshold, the fluids would not necessarily be
seen to be treated in this way for the purposes of disposal.
Pollution covered by the Directive
It is important to consider the extent to which the IPPC Directive (2008/1/EC) covers the
impacts from activities such as drilling and hydraulic fracturing. One could consider the
interpretation of Art 1 to cover Annex I activities irrespective of whether or not they are the
main activities of the site.
The rationale for this is that the approach of IPPC is to regulate activities, and not sites, or
main activities. An installation is defined by Art 2 as a technical unit where annex I activities
take place, including directly associated activities with a technical connection to the activities.
This is reflected in the boundary of the installation from a permit perspective, Arts 6 and 9,
which require that permits and their conditions apply to installations, and hence the activities
taking place there.
In summary, there is no definition of an installation separate from the activities in Annex I, so
one can conclude that IPPC would apply to all Annex I activities irrespective of the main
purpose of a site or the boundaries drawn for that site for other purposes (EIA-Directive,
Mining Waste Directive etc). This means that the IPPC Directive (2008/1/EC) could apply to
hydraulic fracturing installations that meet Annex I criteria for waste management, even
though the primary purpose of the installations is not the management of waste.
A further consideration is whether the permit covers only the polluting substances resulting
from Annex I activities, or more widely all pollution from the installation. For example,
consider a hydraulic fracturing site involved the disposal of hazardous waste with a capacity
of >10 tonnes per day (Annex I 5.1) and at the same time its combustion capacity is below
50MW, therefore it does not meet any Annex I requirements in relation to air emissions from
that drilling equipment. According to Art 2(3) the “installation” means: “a stationary technical
unit where one or more activities listed in Annex I are carried out, and any other directly
associated activities which have a technical connection with the activities carried out on that
site and which could have an effect on emissions and pollution;”. Therefore one needs to
determine if air emissions would be covered by an IPPC permit for the installation in the
above example. Two considerations apply:

Whether the drilling equipment has a technical connection with the activity of waste
disposal (the hydraulic fracturing process).If it is a general and broad definition of
connection, then it could be interpreted that the Directive covers any activity
associated with shale gas exploitation at the site and drilling pollution would be
covered. A narrow definition, however, would be that the technical connection means
the connected activities would need to influence the pollution of the Annex I activity.
In other words, in the example above drilling would only be connected if it influenced
the pollution due to waste disposal. However, technical connection is not defined in
the directive, and Art 2(3) does not limit this connection as being associated with
Annex I activities. Therefore the broad interpretation appears reasonable.
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
The drilling equipment could have an effect on emissions and pollution. Critical to this
interpretation, though, is that Art 2(3) does not limit the directly associated activities to
those which have an effect on the pollution associated with the Annex I activity; it
refers to emissions and pollution in a more general sense. In other words, there is no
need to demonstrate that the operation of the drilling equipment (and for example the
technology used) has an effect on the pollution associated with waste disposal. It is
enough that it has some impact on pollution (where pollution is defined in Art 2(2)).
Taken together, the above analysis suggests that the undertaking of any Annex I activity at a
shale gas exploitation site would include under IPPC any pollution from any equipment
directly connected with the shale gas exploration work. This is the approach taken in the
report. If this broad definition is not supported then the coverage of IPPC would be limited to
a subset of activities or pollution at the site.
Relationship to Industrial Emissions Directive (2010/75/EC).
The IPPC directive will be replaced by the Industrial Emissions Directive (2010/75/EC).
Under that directive the potential permit requirements for HVHF processes would be similar.
Operators of industrial activities listed in Annex I to the Directive must obtain an integrated
permit from relevant national authorities prior operation. As with IPPC, Annex I to this
Directive does not explicitly refer to unconventional hydrocarbon exploration and exploitation
activities, but covers activities related to combustion capacity (thermal input over 50MW) and
waste (for which the thresholds relating to hazardous and non-hazardous waste are the
same as IPPC, albeit the definitions within the annex differ). Also , the exemption of
research, development and testing activities in annex I of IPPC is not included in the
corresponding annex of IED.
Under the permit, operators will be subject to the compliance with certain conditions which
include measures on emission limit values for polluting substances listed in Annex II to the
Directive and for other polluting substances that are likely to be emitted from the installation
concerned in significant quantities.
One of the extra requirements is a baseline report which contains at least the following
information:

Information on the present use and, where available, on past uses of the site;

Where available, existing information on soil and groundwater measurements that
reflect the state at the time the report is drawn up or, alternatively, new soil and
groundwater measurements having regard to the possibility of soil and groundwater
contamination by those hazardous substances to be used, produced or released by
the installation concerned.
These baseline reports are of importance to establish a good reference of environmental
quality of the site at the start and in case of site closure.
The inspection regime is also strengthened under the Industrial Emissions Directive
(2010/75/EC) compared to the IPPC directive (2008/1/EC).
The Industrial Emissions Directive (2010/75/EC) will be effective for new installations as of
January 7, 2013 and as of July 7, 2015 for existing installations.
Conclusions on applicability of IPPC Directive (2008/1/EC) and IED Directive
(2010/75/EC)
Based on the analysis in this section we conclude that it is uncertain whether or not a permit
according to the IPPC Directive (2008/1/EC) and respectively the IED Directive (2010/75/EC)
is required. Under the IPPC Directive and IED Directive, the permit would be required if (part
of) the installation is defined as an installation for the disposal or recovery of hazardous
waste, where ‘hazardous waste’ is defined in the Waste Framework Directive (2008/98/EC).
The chemical composition of the hydraulic fracturing fluids used is commercially sensitive
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and can differ between production sites, therefore whilst they could be defined as hazardous
(Reins, 2011 PR), it is not possible to form a conclusive and generalised view at this stage.
This is not necessarily an inadequacy of EU legislation, but because of the uncertainty over
HVHF technology characteristics it is not possible to confirm that related environmental risks
would be adequately addressed.
If an IPPC (or IED) permit were required, then the permit conditions would include measures
that are related with the best available techniques (BAT). However, documents to confirm
BAT for this sector are not yet available (Lechtenböhmer et al., 2011 NPR).
Article 6 of the IPPC directive (article 12 IED) states the information required for application
for a permit. This information can be derived from a performed EIA, but will also be more
specific on the techniques and management measures that will be taken.
The permit shall include emission limit values for polluting substances likely to be emitted
from the installation concerned in significant quantities, having regard to their nature and
their potential to transfer pollution from one medium to another (water, air and land). If
necessary, the permit shall include appropriate requirements ensuring protection of the soil
and ground water and measures concerning the management of waste generated by the
installation.
The permit must also include the suitable release monitoring requirements, specifying
measurement methodology and frequency, evaluation procedure and an obligation to supply
the competent authority with data required for checking compliance with the permit.
If the IPPC Directive (2008/1/EC) or IED (2010/75/EC) does not apply, this means that
(extra) safeguards regarding possible pollutant activities laid down in these Directives and
highlighted above do not apply to hydraulic fracturing.
Since there is no obligation for a permit that covers the complete process on the site and its
impacts, this might be considered as a gap.
3.4.5 Mining Waste Directive (2006/21/EC)
The Mining Waste Directive (2006/21/EC) places specific obligations on operators of facilities
that pose a potential risk to public health or the environment. The wastewater that is the
result of the activities during the HVHF process falls within the scope of the Mining Waste
Directive. This is because the Mining Waste Directive (2006/21/EC), Article 3 (1), refers to
the definition of waste as given in the Waste Directive (Directive 75/442/EEC, subsequently
repealed by Directive 2008/98/EC). In the Waste Directive (2008/98/EC) waste is defined as
“any substance or object which the holder discards or intends or is required to discard”
(Article 3(1)). Commission Decision 2000/532/EC gives a further definition of the waste. The
annex of this decision identifies “01 05 Drilling muds and other drilling wastes” as a category.
The water resulting from HVHF processes is to be considered a drilling waste. This enables
us to conclude that wastewater constitutes waste under the Mining Waste Directive
(2006/21/EC).
The scope of such operations is defined in Article 2 as the management of waste resulting
from the prospecting, extraction, treatment and storage of mineral resources and the working
of quarries. However, it makes exclusions for waste which is generated by prospecting,
extraction and treatment of mineral resources not directly resulting from those operations and
waste from offshore prospecting extraction and treatment of mineral resources. Recognising
these definitions it can be concluded that the directive applies to shale gas extraction.
Due to the fact that, after the hydraulic fracturing, wastewater not only comes out of the well,
but also partly remains underground, the well must be considered as an underground
storage facility for wastewater.
HVHF processes also need a permit under the Mining Waste Directive (2006/21/EC) as
stated in Article 7(1):
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“No waste facility shall be allowed to operate without a permit granted by the
competent authority”.
The permit must contain the waste management plan and adequate arrangements by way of
a financial guarantee or equivalent (Article 7(2)). In fact the combination of the permit and
the waste management plan ensure the necessary measures to prevent accidents and
environmental impacts due to the waste facility. The permit does not cover the activities on
the site that are not related to the waste management. On the other hand the permit under
2006/21/EC can be combined with a permit that might be required under the Water
Framework Directive (2000/60/EC) since discharge of wastewater to surface water must be
regulated with a permit.
The waste management plan must also include measures that the operator takes in the after
abandonment phase, such as monitoring and control. This is most relevant for the waste
water remaining in the wells. It also means that measures must be taken in order to ensure
the construction of the borehole and the well is safe enough to prevent leakage of
wastewater outside the well.
Part of the waste management plan is the characterisation of the waste facility. The operator
must give the information to classify the waste facility as either Category A or non-Category
A according to the criteria laid down in Annex III of the Mining Waste Directive (2006/21/EC).
Category A classification is carried out on the basis of the following criteria (Commission
Decision 2009/337/EC also gives more detailed criteria for this categorisation):

a failure or incorrect operation, e.g. if the collapse of a heap or the bursting of a dam,
could give rise to a major accident, on the basis of a risk assessment taking into
account factors such as the present or future size, the location and the environmental
impact of the waste facility; or

it contains waste classified as hazardous under Directive 91/689/EEC above a certain
threshold; or

it contains substances or preparations classified as dangerous under Directives
67/548/EEC or 1999/45/EC above a certain threshold.
As for these criteria and their application to the hydraulic fracturing process:

the amounts of stored waste water are estimated to stay below 30,000 m3 (see Table
3). Any collapse of a storage facility would not cause a major accident as referred to
in the first criteria; or

the concentrations of hazardous waste or dangerous substances above certain
thresholds could occur, but there is a knowledge gap in relation to these
concentrations, and this would need to be assessed on a case-by-case basis. This
uncertainty over whether HVHF liquids would constitute hazardous waste is
discussed in section 3.4.4.
If the concentrations mentioned are exceeded, the waste facility must be characterised as a
Category A Facility and is subject to a stringent regime including major accident prevention
measures and external emergency plan. If a facility is not characterised as a Category A
facility the operator still has to draw up a waste management plan. However, in that case the
operator does not have to have a major accident prevention policy and external emergency
plan.
A major accident as defined in the Mining Waste Directive (2006/21/EC) means: an
occurrence on site in the course of an operation involving the management of extractive
waste in any establishment covered by this Directive, leading to a serious danger to human
health and/or the environment, whether immediately or over time, on-site or off-site.
Migration of fracturing fluids and/or displaced formation fluids into an aquifer is one of the
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potential risks of HVHF processes, but is not considered a major accident under the Mining
Waste Directive (2006/21/EC).
Waste classification
One of the questions that has to be answered, in order to determine the application of the
IPPC directive for HVHF sites and whether to classify the waste treatment installation as a
Category A installation under the Mining Waste Directive (2006/21/EC), is whether or not the
waste coming from the well or remaining in the underground is hazardous. This issue is
described in section 3.4.4.
It is concluded that, in order to classify hydraulic fracturing wastewaters as hazardous or
non-hazardous, the chemical composition of the waste must be known. Waste chemical
composition will vary from site to site, depending on the nature of the hydraulic fracturing
fluids used, and the levels of naturally occurring potentially hazardous substances present in
wastewater.
This makes it impossible at this stage to classify the waste coming from the well, or the
waste remaining in the well, other than to indicate the possibility that waste waters may
potentially be classified as hazardous. Nevertheless, as noted above, any waste facility shall
require a permit granted by the competent authority and which will contain the waste
management plan (Articles 5 and 7(1) Mining Waste Directive (2006/21/EC)).
Conclusions on applicability of the Mining Waste Directive (2006/21/EC)
The (contaminated) wastewaters related to activities during the HVHF process are
considered to fall under the definition of waste from extractive industries. This conclusion is
in line with the Commission’s legal interpretation on this issue (EC, 2011). Based on the
provisions in the Mining Waste Directive (2006/21/EC) it is not clear whether or not the waste
facility is classified as a Category A waste facility, for which additional safeguards are
mandatory (major accident prevention policy and external emergency plan). This uncertainty
is brought about by the fact that it is unclear whether or not the waste coming from the well or
remaining in the underground is considered ‘hazardous’. The chemical composition of the
hydraulic fracturing fluids used is commercially sensitive and can differ between production
sites. This is not necessarily an inadequacy of EU legislation, but because of the uncertainty
over HVHF technology characteristics it is not possible to confirm that environmental risks in
relation to accidents would be adequately addressed.
If a facility is not characterised as a Category A facility the operator still has to draw up a
waste management plan addressing how he will deal with waste issues and the risks of
chemicals remaining in the underground (which should also be assessed in any
environmental impact assessment before the start of the project). However, in that case the
operator is not required to have a major accident prevention policy and external emergency
plan.
In each case the provisions of the Mining Waste Directive (2006/21/EC) should provide
guidance to Member States in addressing the risks arising from HVHF. The Directive
requires Member States to ensure the operator takes all measures necessary to prevent as
far as possible any adverse effects on the environment or human health, including following
its abandonment (Article (4(2)), implemented through the permit and management plan
(Article 7). However, at present there is no Best Available Technology Reference Document
(BREF) at EU level for shale gas waste management. Whilst reliance on Member State
permitting regimes and associated decision-making is not a gap in the EU legislation per se,
it is beyond the scope of this project to determine whether the Member States’
implementation for this aspect adequately addresses all environmental risks.
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3.4.6 Seveso II Directive (96/82/EC)
The Seveso II Directive (96/82/EC) aims to prevent major accidents involving dangerous
substances, limit their consequences and ensure high levels of protection in a consistent and
effective manner.
Article 4 states the exclusions of the Directive, especially 4(e) [the exploitation (exploration,
extraction and processing) of minerals in mines, quarries, or by means of boreholes, with the
exception of chemical and thermal processing operations and storage related to those
operations which involve dangerous substances, as defined in Annex I] and ‘(g) [waste landfill sites, with the exception of operational tailings disposal facilities, including tailing ponds or
dams, containing dangerous substances as defined in Annex I, in particular when used in
connection with the chemical and thermal processing of minerals].
In both (e) and (g) there must be chemical and thermal processing operations and storage
which involves dangerous substances, although the terms “chemical and thermal processing”
are not defined in the directive. Chemical and thermal processing operations are common in
the ore mining industry. HVHF processes do not use chemical and thermal processing
operations, but do involve mechanical processes, i.e. the mixing of substances. The Seveso
II Directive (96/82/EC) is not applicable to waste storage of HVHF processes. The risks
involving the management of waste are covered by the Mining Waste Directive
(2006/21/EC).
There may be another reason for applicability of Seveso II Directive (96/82/EC), which is the
presence of natural gas in the ground or on land. Under Article 2 it applies to dangerous
substances that are present in quantities equal to or in excess of the quantities listed in
Annex I, Part 1, or substances with the characteristics mentioned in Annex I Part 2.
The storage of natural gas above 50 tonnes is one of the thresholds (Annex I, part 1) related
to HVHF processes. In general the gas produced at a HVHF site is, after dehydrating,
delivered to the main gas infrastructure. The presence of gas in the underground is not
considered to be storage as meant in the Seveso II Directive (96/82/EC). The gas is well
preserved underground and has no possibility of causing risks as addressed by the directive.
Storage of gas on site is not a common procedure, since storage in fact takes place in the
well itself. As discussed above, the constituents of hydraulic fracturing fluids, and therefore
the chemicals held or mixed on site, are complex, often subject to commercial sensitivity and
may vary between sites. It is therefore not possible to conclude whether the requirements of
the Seveso II Directive (96/82/EC) apply. Given the amounts that must be on site to meet
the characteristics of Annex I, part 2, it is however very unlikely that they will be exceeded,
even if the addition rule of Annex I, part 2, Notes (4) was applied. The addition rule uses the
sum of the amount of the substances relative to the thresholds set out in the Annex. If the
sum is larger than 1, then the threshold is met due to the combined presence of the
substances. This would be the case if toxic substances exceed the amount of 50 tonnes,
very toxic substances 5 tonnes or substances dangerous to the environment 200 or 500
tonnes (depending on their impact).
Should the substances involved fall under the Directive then Member States shall ensure that
the operator is obliged to take all measures necessary to prevent major accidents and to limit
their consequences and to notify the competent authority of these measures (Article 5). The
Operator must also draw up major accident prevention policies (Article 7). A safety report
must be carried out and made public under Article 13 and a regime of competent authority
inspections must be applied (Article 18) to assess whether the operator has implemented the
measures and to confirm the accuracy of the safety report. Regarding information
disclosure, certain information must be exchanged between member States and the
European Commission with regard major accidents and their prevention (Article 19) and
make the information publicly available, although subject to commercial or industrial
sensitivity restrictions specified in Article 20.
Conclusions on applicability of the Seveso II Directive (96/82/EC).
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Whilst the authors judge it unlikely that the Seveso II Directive is applicable to HVHF process
sites, it is not possible to say definitively that this is the case.
The risks of major accidents are related to the mining waste and for Category A installations
they are addressed in the Mining Waste Directive (2006/21/EC).
3.4.7 The Environmental Liability Directive (2004/35/EC)
As described in the document with legal interpretation of the environmental acquis drafted by
the Commission (EC, 2011) the Environmental Liability Directive (2004/35/EC) provides the
framework for Member States to require:

preventive measures in case of an imminent threat of environmental damage; or

necessary restorative measures where environmental damage has occurred.
The Directive applies to (Article 3):

environmental damage caused by any of the occupational activities listed in Annex III,
and to any imminent threat of such damage occurring by reason of any of those
activities; or

damage or threat of damage to protected species and natural habitats caused by any
occupational activities other than those listed in Annex III, whenever the operator has
been at fault or negligent.
Environmental damage (Article 2(1)) means damage to protected species and natural
habitats, water or land with significant adverse effects.
The activities listed in Annex III include those subject to a permit concerning IPPC Directive
(2008/1/EC), Water Framework Directive (2000/60/EC) and waste management in relation to
hazardous wastes or handling of dangerous substances, which would be required to hold a
permit under the Mining Waste Directive (2006/21/EC). In addition to this, Article 15 of the
Mining Waste Directive (2006/21/EC) amends the Environmental Liability Directive
(2004/35/EC) adding the following to Annex III:

The management of extractive waste pursuant to Directive 2006/21/EC of the
European Parliament and of the Council of 15 March 2006 on the management of
waste from extractive industries.
It is also important to note that Article 4(5) of the Environmental Liability Directive
(2004/35/EC) which states the directive to only apply to environmental damage or to an
imminent threat of such damage caused by pollution of a diffuse character, where it is
possible to establish a causal link between the damage and the activities of individual
operators. This will limit the applicability of the directive to diffuse impacts such as from air
pollution.
In conclusion, all damage from activities covered by directives referred to in Annex III of the
Environmental Liability Directive (2004/35/EC) would be covered under the strict liability
scope of Directive 2004/35/EC. However, activities not covered by the Annex III directives
would not be included in this way. For example, emissions to air during fracturing are not
covered by the Mining Waste Directive (2006/21/EC), therefore it follows that these impacts
are not automatically covered by the Environmental Liability Directive (2004/35/EC) by virtue
of the inclusion of the Mining Waste Directive (2006/21/EC) in Annex III. Nevertheless, these
impacts could be covered by the Environmental Liability Directive where the IPPC Directive
is applicable to these projects.
In order for other impacts to fall within the scope of the Directive they have to involve
damages to protected species and natural habitats with significant adverse effects for which
the operator has been at fault or negligent.
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3.4.8 Monitoring and Inspection
The legal interpretation of the Commission (EC, 2011) briefly describes relevant monitoring
and inspection provisions following form the EU regulatory framework. This section presents
a consolidated review of the monitoring and inspection requirements specified by the IPPC
Directive (2008/1/EC), the Mining Waste Directive (2006/21/EC) and the Water Framework
Directive (2000/60/EC) as directly relevant to hydraulic fracturing. The Directives related to
environmental quality (air, noise and water) all have their own monitoring schemes that allow
the Member States to follow and report on changes in the environmental quality. Since these
are general monitoring schemes and not directly related to specific sites, they are not
discussed further in this report.
For Hydraulic fracturing processes, monitoring would need to be related to the chemical and
physical characteristics of the wastewater, as well as to emissions to water, groundwater and
air. Monitoring of induced seismicity could be of relevance to reduce public concerns.
Under the Mining Waste Directive (2006/21/EC) Article 11.2 (c) the operator must have
suitable plans and arrangements for regular monitoring and inspection of the waste facility by
competent persons and for taking action in the event of results indicating instability or water
or soil contamination. Article 11.3 obliges the operator to, without undue delay and in any
event not later than 48 hours thereafter, notify the competent authority of any events likely to
affect the stability of the waste facility and any significant adverse environmental effects
revealed by the control and monitoring procedures of the waste facility. The operator shall
implement the internal emergency plan, where applicable, and follow any other instruction
from the competent authority as to the corrective measures to be taken. Also, the operator
remains responsible for the maintenance, monitoring and corrective measures in the afterabandonment phase as long as it is required by the competent authority (Article 12.4;
Directive 2006/21/EC).
Article 17 of the Mining Waste Directive (2006/21/EC) deals with inspections by the
competent authority in the following manner:
1. Prior to the commencement of deposit operations and at regular intervals thereafter,
including the after-abandonment phase, to be decided by the Member State
concerned, the competent authority shall inspect any waste facility covered by Article
7 in order to ensure that it complies with the relevant conditions of the permit. An
affirmative finding shall in no way reduce the responsibility of the operator under the
conditions of the permit.
2. Member States shall require the operator to keep up-to-date records of all waste
management operations and make them available for inspection by the competent
authority and to ensure that, in the event of a change of operator during the
management of a waste facility, there is an appropriate transfer of relevant up-to-date
information and records relating to the waste facility
Both monitoring and inspection of the waste are regulated through the Mining Waste
Directive (2006/21/EC).
Emissions to surface water have their monitoring requirements in the Water Framework
Directive (2000/60/EC). Article 11 (g) for point source discharges liable to cause pollution, a
requirement for prior regulation, such as a prohibition on the entry of pollutants into water, or
for prior authorisation, or registration based on general binding rules, laying down emission
controls for the pollutants concerned, including controls in accordance with Articles10
and 16. These controls shall be periodically reviewed and, where necessary, updated. The
monitoring requirements are to be part of the permit under the Water Framework Directive
(2000/60/EC).In fact the regulation of emissions to surface water is done by permit which can
be combined with the permit under the Mining Waste Directive (2006/21/EC).
The monitoring of underground stored wastewater is also part of the monitoring requirements
in the permit under the Mining Waste Directive (2006/21/EC). Article 5 of the waste
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management plan is the legal basis for these requirements. This means that the groundwater
in the direct vicinity of the well must be monitored in order to detect possible leakage from
the well.
Within river basins districts, the monitoring of the quality of groundwater in general is dealt
with in the Water Framework Directive (2000/60/EC) Annex V, 2.4, which gives the directions
on the monitoring of groundwater. Annex V, 2.4.3 of the Water Framework Directive gives
the requirements for operational monitoring to be carried out by Member States, at least
once a year for all those groundwater bodies […] which on the basis of both the impact
assessment carried out [by Member States] in accordance with Annex II and surveillance
monitoring are identified as being at risk of failing to meet the objectives under Article 4. This
"identification process" is drawing on the initial characterisation performed by Member States
at the latest 13 years after the date of entry into force of this Directive and every six years
thereafter. Therefore, no operational monitoring is required for groundwater bodies that, in a
time frame of six years, were not identified as being at risk of failing to meet the objectives
under Article 4 of the Water Framework Directive (2000/60/EC). As monitoring of aquifers in
the surrounding of HVHF process activities should always be required, this indicates a
possible gap in legislation.
There are no requirements on the frequency of the monitoring of both discharge to surface
waters and the quality of groundwater in the vicinity of the site. It is up to the competent
authority to establish these requirements and regulate them through the permit under the
Mining Waste Directive (2006/21/EC).
Monitoring of emissions to air is only required under EU legislation if the installation needs a
permit under the IPPC Directive (2008/1/EC). Article 9 (5) states the monitoring aspects that
should be in the permit. Article 14 (3) deals with the inspection by the competent authority in
order to verify the compliance with the permit. There are no requirements on the frequency
of monitoring and inspections. This is not necessarily an inadequacy of EU legislation, but
because of the uncertainty over HVHF technology characteristics (i.e. where it would fall
under the IPPC Directive (2008/1/EC) it is not possible to confirm that related environmental
risks would be adequately addressed.
Under the IPPC Directive (2008/1/EC) it is up to the competent authorities to decide on the
frequency of monitoring and inspections. In the case the permit under IPPC is not required,
the complete monitoring and inspection is the jurisdiction of the competent authority.
If the IED (2010/75/EC is applicable, the monitoring and inspection requirements in Articles
14 and 16 of that directive apply. Article 14 sets out the provisions that must be included in
permits for regulated installations, including provisions relating to emissions monitoring.
Article 16 lays down the principles for monitoring regimes, with specific provisions for soil and
groundwater monitoring.
3.4.9 Conclusions regarding general provisions
The Strategic Environmental Assessment Directive (2001/42/EC) applies to programmes and
plans and gives the competent authorities the obligation to conduct an environmental
assessment before starting the concession processes. This assessment provides the
information on the possible environmental impacts in the area where the concessions are to
be granted.
The Environmental Impact Assessment Directive (2011/92/EC) is the basis for environmental
impact assessments to be included as part of the development consent process and is
applicable for hydraulic fracturing projects. These assessments however are not always
mandatory since the Environmental Impact Assessment Directive (2011/92/EC) gives the
Member States the possibility for defining the kind of projects that need an assessment.
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Inadequacies in the EU legislation have been identified with regards the use of a single
threshold in Annex I for all gas extraction technologies requiring mandatory EIA, and the
absence of a clear definition of deep drilling in Annex II. It is beyond the scope of this project
to assess the adequacy of Member State application of optional EIA for activities in Annex II.
Permits are required under the Mining Waste Directive (2006/21/EC) and the Water
Framework Directive (2000/60/EC). It is beyond the scope of this project to determine
whether the Member States’ implementation for this aspect adequately addresses all
associated environmental risks. Permits might be required under the IPPC Directive
(2008/1/EC) or IED (2010/75/EC) depending on whether the installation in question is
deemed to be handling hazardous waste or has combustion capacity over the threshold in
those directives. This is not necessarily an inadequacy of EU legislation, but because of the
uncertainty over HVHF technology characteristics it is not possible to confirm that related
environmental risks would be adequately addressed.
The Hydrocarbons Authorization Directive (94/22/EC) prescribes that Member States shall
take the necessary measures to ensure that authorizations are granted on the basis of
certain criteria. This directive allows Member States to provide in authorization conditions
imposed on concession holders if this is justified, however, such measures are not a
mandatory requirement.
Whilst the authors judge it unlikely that the Seveso II Directive (96/82/EC) is applicable to
HVHF process sites, it is not possible to say definitively that this is the case. However, to the
extent that a HVHF process site constitutes a Category A installation under the Mining Waste
Directive (subject to whether fracturing fluids are deemed to be hazardous or not), the risks
of major accidents related to the mining waste are addressed in the Mining Waste Directive
(2006/21/EC).
All damage from activities covered by the Mining Waste Directive (2006/21/EC) would be
covered under the strict liability scope of the Environmental Liability Directive (2004/35/EC).
In order for other impacts to fall within the scope of the Environmental Liability Directive
(2004/35/EC) they have to involve damages to protected species and natural habitats with
significant adverse effects for which the operator has been at fault or negligent.
3.5 Land-take during site preparation and production
(cumulative, project stage 1)
3.5.1 Impacts and applicable legislation
The key issue with regard to land take impacts deals with the fact that surface installations
for high-volume hydraulic fracturing, without mitigating measures, could take up
approximately 60% more space per well pad than conventional drilling (see Chapter 2). This
additional area is needed to accommodate the plant and storage tanks/pits required for up to
30,000 m3 of make-up water, together with chemical additives and waste water. Additionally,
shale gas formations cover areas of tens of thousands of square kilometres, with
concessions being granted for areas of up to 6,000 km2. The analysis in Chapter 2 (section
2.4.3) indicates that approximately 1.4% of the land above a productive shale gas reservoir
may need to be used to fully exploit the gas reservoir, or more if other indirect land-uses are
taken into account.
As already indicated in Chapter 2 multi-well pads are in increasing use for shale gas
extraction in the US. This enables a single pad to accommodate 6-10 wells instead of just 1
in the case of conventional gas extraction activities or earlier shale gas developments,
resulting in a lower land-take impact per well. This partly compensates up for the extra
space needed for surface installations if no mitigating measures are in place. Therefore,
land-take associated with an individual site is expected to be within the normal range of
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commercial and infrastructure developments in Europe, and can be considered as a minor
impact.
However, the cumulative land-take impact of multiple installations is considered to be of
potentially major significance. It may not be possible to fully restore a site in a sensitive area
following well completion or well abandonment. For example, sites in areas of high
agricultural, natural or cultural value could potentially not be fully restorable following use.
Also, the associated infrastructure (access roads and pipelines) result in land-take and
habitat fragmentation.
The following legislation is applicable:

The Environmental Impact Assessment Directive (2011/92/EU)

The Strategic Environmental Assessment Directive (2001/42/EC)

The Environmental Liability Directive (2004/35/EC)

The Habitats Directive (1992/43/EEC)

The Birds Directive (2009/147/EC)

The Hydrocarbons Authorization Directive (94/22/EC)
The relevance of these Directives with regard to sufficient coverage of (cumulative) land-take
impacts in the site preparation phase of the project is discussed below.
3.5.2 Applicability of the legislation
EIA obligation in relation to land take impacts
In sections 3.4.1 and 3.4.2 the question whether shale gas extraction activities are always
subject to an EIA obligation was discussed. It was concluded that shale gas extraction
activities fall within the scope of Annex II of the Environmental Impact Assessment Directive
(2011/92/EU). With regard to these activities it is up to the Member States to decide whether
an EIA is appropriate (Article 4(2) of the Environmental Impact Assessment Directive
(2011/92/EU)). Therefore, as already mentioned, the Environmental Impact Assessment
Directive (2011/92/EC) in itself does not prescribe that an EIA, addressing the (cumulative)
land-take impacts during site preparation, is mandatory. It is beyond the scope of this study
to determine the adequacy of implementation of the Environmental Impact Assessment
Directive (2011/92/EC) at Member State level.
In the remainder of this section, it is assumed that an EIA obligation is deemed appropriate
by the Member State. The next question is whether land-take impacts are expected to be
sufficiently covered in this EIA.
Article 3 of the Environmental Impact Assessment Directive (2011/92/EU) sets out what
should be assessed in an EIA. In particular it states: “The environmental impact assessment
shall identify, describe and assess in an appropriate manner, …. the direct and indirect
effects of a project on the following factors:
(a) human beings, fauna and flora;
(b) soil, water, air, climate and the landscape;
(c) material assets and the cultural heritage;
(d) the interaction between the factors referred to in points (a), (b) and (c).”
The expected land take impacts are covered by the obligation to pay attention to the effects
of a project on the fauna and flora and the landscape (Article 3(a) and 3(b) Environmental
Impact Assessment Directive (2011/92/EU)). Also, the Member State has to ensure that the
developer provides the authority responsible for approving the project with the information
listed in Annex IV insofar as the Member State deems it to be relevant for the case
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concerned (Article 5(1) of the Environmental Impact Assessment Directive (2011/92/EU)).
This information should consist of a description of the expected environmental impacts
related to land-take and information with regard to the land-use requirements during the
construction and operational phases of the whole project (Point 1a of Annex IV of the
Environmental Impact Assessment Directive (2011/92/EU). One approach that could be
adopted would be to split the EIA according to the phases in the exploration and exploitation
process. The impacts that occur during the exploration phase (Stages 1 and 2 in Figure 3)
are likely to be smaller than those of the exploitation phase where larger areas of land are
involved; there would be less opportunity for collection and utilisation of fugitive gases during
the exploration phase. The systematic approach of the EIA however requires an integrated
impact analysis over the whole period of the project.
For the projects concerning hydrocarbons operations involving hydraulic fracturing this
means that the land-take impacts described in Chapter 2 of this report will have to be dealt
with in an EIA. This also holds for cumulative land-take effects of shale gas extraction
activities (footnote 1 in Annex IV of the Environmental Impact Assessment Directive
(2011/92/EU), which states that information must cover, inter alia, cumulative effects of the
project), in order to prevent the slicing of projects into smaller parts to reduce the reported
environmental impacts. Projects usually start with a limited amount of wells to be expanded
with more wells in due time. This expansion, increasing land-take impacts, is to be foreseen
in the EIA and is to be taken into account. The full (future) size of the project plant, and
associated land-take impacts, is brought under the scope of the EIA carried out, as was
already clarified in section 3.4.2 .
3.5.3 The Environmental Liability Directive (2004/35/EC)
As described in section 3.4.7, the Environmental Liability Directive (2004/35/EC) covers
environmental damage from activities regulated by directives cited in Annex III. The
presence and use of waste facilities on site are part of the activities cited in Annex III.
Environmental damage caused by these activities fall under the Environmental Liability
Directive (2004/35/EC).Next to that, damages to protected species and natural habitats with
significant adverse effects under the 1992/43/EEC Habitats Directive and the 2009/147/EC
Birds Directive would also be included if caused by non-Annex III occupational activities,
provided that the operator has been at fault or negligent. Impacts from land take not caused
by waste facilities would therefore only be covered by the directive insofar as they cause
damage to these protected species and habitats. This is an inadequacy of the legislation.
3.5.4 Conclusions
In cases where shale gas extraction activities as such are subject to an EIA obligation, a
Member State is obliged to indicate in its EIA what the estimated land-take impacts are, now
and in the future, and how these are dealt with (Article 3 and 5 of the Environmental Impact
Assessment Directive (2011/92/EU)). However, the Environmental Impact Assessment
Directive (2011/92/EU) leaves at the discretion of competent authorities the way in which
land-take impacts are analysed, assessed and weighted. Whilst this is not a gap in the EU
legislation per se considering the horizontal nature of the EIA Directive (2011/92/EU), further
examination beyond the scope of this project is needed to determine whether the Member
States’ implementation for this aspect adequately addresses land take risks.
The 2004/35/EC Environmental Liability Directive only covers land-take impacts which qualify
as ‘environmental damage’, for which the operator is at fault or negligent. The usual landtake impacts are economic issues which are dealt with using economic instruments such as
payment.
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3.6 Release to air during drilling (project stage 2)
3.6.1 Impact and applicable legislation
The release to air of polluting substances during drilling is described in section 2.5.3. The
main issue of potential concern with regard to emissions to air during well drilling is the risk of
emissions of diesel exhaust fumes from well drilling equipment. While less-polluting
processes do exist, this section builds on findings from section 2.5.3, which looks at shale
gas developments known in the USA.
The directive that in principle covers the emissions to air from equipment at drilling sites,
such as diesel engine equipment, is the IPPC Directive (2008/1/EC) or the IED
(2020/75/EC). As indicated in section 3.4.4 the question whether or not the IPPC Directive
(2008/1/EC) or IED (2010/75/EC) is applicable is uncertain, due to uncertainties over the
likely combustion capacity and classification of waste at the site.
With regards combustion capacity the IPPC Directive (2008/1/EC) and IED (2010/75/EC)
Annex I includes combustion emissions from combustion installations in energy industries
which have a rated thermal input of over 50MW. New York DEC 2011 PR (p6-100) identifies
drilling rig power of 5400Hp, implying at a thermal input at 50% efficiency (illustrative) a
thermal input of 8MW; well below the IPPC threshold. At this level single drilling rigs are not
covered by the IPPC Directive (2008/1/EC) or IED (2010/75/EC). However, Annex I also
states that if there are multiple installations on the site, the total thermal input of all
installations should be used as the value to meet the threshold, leading to the potential for
large multiple well operations to be covered.
The Air Quality Directive (2008/50/EC) sets limit values of air polluting substances in ambient
air, however it does not regulate specific site emissions and monitoring under that directive
will not necessarily be local to sources of hydraulic fracturing air emissions.
If the project is subject to an environmental impact assessment obligation (see section 3.4.2)
the developer/operator has to provide information on emissions to air and their impacts
(Article 3b, Article 5(1) and Annex IV point 1(c) of the Environmental Impact Assessment
Directive (2011/92/EU).
Emission limits for off-road combustion plant are specified via the Directives on Emissions
from Non-Road Mobile Machinery (Directive 97/68/EC as amended by 2010/26/EC). These
directives specify limits on emissions of carbon monoxide, oxides of nitrogen, hydrocarbons
and particulate matter from engines up to 560 kW and are aligned with the equivalent US
emissions standards. It’s important to note, however, that this legislation applies only to
type-approval and new off-road machines; it does not limit their emissions during the use.
Therefore the effect on emissions is indirect and therefore possibly of marginal effectiveness
in mitigating these emissions. Emissions limits applicable to engines rated above 560 kW
were proposed in the review of amending Directive 2004/26/EC, either by extending the
limits for engines below 560 kW, or by creating an additional class of engines above 560 kW
(Joint Research Centre, 2008 PR p78). Plant used for drilling in advance of HVHF
operations is likely to be rated above 560 kW (e.g. see New York DEC 2011 PR p6-100).
Hence, the existing European emissions limits may not apply to larger drilling plant if the
scope of the directive is not extended to plant rated above 560 kW. This is an inadequacy of
legislation at EU level.
3.6.2 Applicability of the legislation
The preceding section mentions that air emission would be covered by any assessment
under the Environmental Impact Assessment Directive (2011/92/EU) and subject to a permit
regime under the IPPC Directive (2008/1/EC), if that directive applies. In the absence of
these directives applying then air emissions would not be regulated. The inadequacies
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concerning the EIA directive and the role of Member State decision-making are discussed in
section 3.4.2.
The remainder of this section examines the legislative requirements for installations where
emissions from drilling and hydraulic fracturing equipment for a shale gas development were
to be covered by the IPPC Directive (2008/1/EC). The IPPC permit application should
describe the nature and quantities of foreseeable emissions from the installation into each
medium as well as identification of significant effects of the emissions on the environment. It
should also describe the proposed technology and other techniques for preventing or, where
this not possible, reducing emissions from the installation (Article 6 IPPC). These techniques
should meet the general criteria of the IPPC Directive or IED on best available technology.
However, there are no Best Available Technology Reference documents (BREF, IPPC or
IED) for drilling and hydraulic fracturing equipment. This potential gap arises because of
uncertainty over the applicability of the IPPC Directive (2008/1/EC) or IED (2010/75/EC) to
hydraulic fracturing installations.
In the case of emissions to air from diesel engines used during the drilling process, the
possible technology includes: particle filters, selective catalytic reduction filters, low sulphur
fuels, adequate stack height and others. However, Article 10 of IPPC specifies that where an
environmental quality standard requires stricter conditions than those achievable by the use
of the best available techniques, additional measures shall in particular be required in the
permit, without prejudice to other measures which might be taken to comply with
environmental quality standards.
Emissions from numerous well developments in a local area or wider region could potentially
have a significant effect on air quality. The IPPC directive article 9(4) covers such situations
in stating that emission limit values, based on Best Available Techniques, should take
account of geographical location and local environmental conditions. In the case of many
emission sources in the vicinity of a drilling site, the combination of Article 6 (1)e and Article
10 of the IPPC directive mean that the cumulative impact of these sources on air quality must
be taken into account in the permit application.
The Air Quality Directive(2008/50/EC) Article 13 and Annex XI, provides the limit values and
alert thresholds for the protection of human health, in general referred to as air quality
standards. These standards are to be met for all ambient air in the troposphere, with the
exemption of workplaces. Article 10 of the IPPC Directive (2008/1/EC) gives a direct link to
the environmental quality directives such as the Air Quality Directive 2008/50/EC. Where an
environmental quality standard requires stricter conditions than those achievable by the use
of the best available techniques, additional measures shall in particular be required in the
permit, without prejudice to other measures which might be taken to comply with
environmental quality standards.
With the monitored data the competent authorities are able to judge whether the emissions to
air are within the emission limits set in the permit or not. If the air quality limit values are
exceeded, extra emission abatement techniques must be used in order to meet the required
levels. The permit should also contain measures planned to monitor emissions into the
environment. This should be part of the permit application as mentioned in Article 6 of the
IPPC Directive (2008/1/EC).
3.6.3 Conclusions
The legislative framework that consists of the IPPC Directive (2008/1/EC) – if applicable –
and Air Quality Directives could provide the appropriate structure to manage the impacts
from emissions to air during drilling. As discussed in section 3.4.4, it is uncertain whether the
IPPC Directive (2008/1/EC) would apply to shale gas projects. Hydraulic fracturing activities
would be covered by the directive if hydraulic fracturing fluids were classified as a hazardous
waste. They would also be covered if the combustion capacity were over 50MW. However,
if the combustion equipment at the hydraulic fracturing site were to be below the 50MW
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capacity threshold for energy industries, then this would suggest that the air emission
impacts are at a threshold below which would be regulated under the IPPC Directive
(2008/1/EC). The absence of a BREF under IPPC on diesel-engined drilling processes is a
potential gap at EU level, arising from the uncertainty over the applicability of the IPPC
Directive (2008/1/EC). Knowledge of emissions abatement techniques by both competent
authorities and operators is well established in Europe, but it is not possible to say whether
standards are applied in a consistent way. It is beyond the scope of this project to determine
whether the Member States’ implementation for this aspect adequately addresses all
environmental risks.
Compliance with the emissions standards for off road mobile machinery (Directive 97/68/EC,
as amended) would influence emissions of potential concern from on-site plant through
design limits, but would not by itself control emissions during use of these devices or deliver
compliance with standards and guidelines for air quality. This would need to be implemented
via national provisions specified by Member States under the Air Quality Framework
Directive. The member states have a resultant obligation on this subject. This is not a gap in
the EU legislation per se, but it is beyond the scope of this project to determine whether the
Member States’ implementation for this aspect adequately addresses all environmental risks.
3.7 Noise during drilling (cumulative, project stage 2)
With regard to the impact of ‘noise’ in particular, the Environmental Impact Assessment
Directive (2011/92/EU), the Strategic Environmental Impact Assessment Directive
(2001/42/EC), the Noise Directive (2002/49/EC)the Outdoor machinery noise directive
(2000/14/EC) and the IPPC Directive (2008/1/EC) are relevant.
In sections 3.4.1 and 3.4.2 the requirements for an EIA for hydraulic fracturing were
discussed. It was concluded that shale gas extraction activities fall within the scope of Annex
II of the Environmental Impact Assessment Directive (2011/92/EU). With regard to these
activities it is up to the Member States to decide whether an EIA is appropriate (Article 4(2) of
the Environmental Impact Assessment Directive (2011/92/EU)). Therefore, as already
mentioned, the Environmental Impact Assessment Directive (2011/92/EC) in itself does not
prescribe that an EIA, addressing impacts associated with noise during drilling, is mandatory.
It is beyond the scope of this study to determine the adequacy of implementation of the
Environmental Impact Assessment Directive (2011/92/EC) at Member State level.
Under the Environmental Impact Assessment Directive (2011/92/EU) the Member State has
to ensure that the developer provides the authority responsible for approving the project with
the information listed in Annex IV insofar as the Member State deems it to be relevant for the
case concerned (Article 5(1)). This information should consist of a description of the
expected environmental impacts, including noise impacts (point 1c of Annex IV of the
Environmental Impact Assessment Directive (2011/92/EU)), resulting from the operation of
the proposed project. For the projects concerning hydrocarbons operations involving
hydraulic fracturing, this means that noise during drilling will have to be dealt with in an EIA
and taken into account before the competent authority grants development consent.
If the IPPC Directive is applicable, noise is a part of the permit under the IPPC, similar to air
pollution discussed in section 3.6. The discussion and conclusion for noise would be similar
and is therefore not further elaborated.
3.7.1 The 2002/49/EC Noise Directive
The Noise Directive 2002/49/EC sets a general framework with regard to environmental
noise to which humans are exposed, particularly in built-up areas, public parks or other quiet
areas. It does not set noise limits for specific kind of activities. Under the Noise Directive,
Member States are required to develop strategic noise maps for noise sensitive locations
and implement measures to tackle problem areas where maximum noise levels are violated.
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Strategic noise mapping is obligatory for all agglomerations with more than 250,000
inhabitants and for all major roads which have more than six million vehicle movements, and
major railways with more than 60,000 train movements per year and major airports within
their territory. Action plans must include measures to manage noise levels, however the
measures within the plans are at the discretion of the competent authorities and do not
automatically prohibit noise creating activities.
3.7.2 The Outdoor Machinery Noise Directive 2000/14/EC
The Outdoor Machinery Noise Directive(2000/14/EC) and its amendments have been
reviewed for applicability. This directive covers much of the equipment that is likely to be
used on the hydraulic fracturing site. For that equipment maximum produced noise levels are
defined in the directive. These levels must be met when the equipment is put on the market
or taken into use.
Drilling equipment used in HVHF processes however is not included in the equipment cited in
this directive. Compressors used for drilling have a power capacity over 350 kW, which is the
limit for this directive (Article 12).
3.7.3 Conclusions
In cases where shale gas extraction activities are subject to an EIA obligation, a Member
State is obliged to indicate in its EIA what the estimated noise impacts are and how these are
dealt with (point 1c of Annex IV of the Environmental Impact Assessment Directive
(2011/92/EU)). However, the Environmental Impact Assessment Directive (2011/92/EU)
leaves at the discretion of competent authorities the way in which noise impacts are
analysed, assessed and weighted. Whilst this is not a gap in the EU legislation per se,
further examination, beyond the scope of this project, is needed to determine whether the
Member States’ implementation for this aspect adequately addresses the noise related risks.
The Noise Directive does not provide noise limits for specific kind of activities, such as drilling
activities for shale gas production purposes and does not mandate specific actions to reduce
noise or prohibit noise creating activities. We do not consider this to be an inadequacy,
because the Outdoor Machinery Noise Directive(2000/14/EC) does specify such limits.
However we have identified that drilling and compressors with a capacity over 350 kW would
not be covered by this Directive, which is an inadequacy of legislation at EU level.
3.8 Water resource depletion during fracturing (project
stage 3)
3.8.1 Impact and applicable legislation
The Water Framework Directive (2000/60/EC) is applicable to the water resource depletion.
This directive sets a framework on all water related impacts. The Framework should
promote sustainable water use based on a long-term protection of available water resources
as stated in Article 1 of the directive.
3.8.2 Applicability of the legislation
The degradation of resources due to emissions of pollutants is dealt with in sections 3.11,
3.12 and 3.13. The current section examines the measures to control the abstraction of
water and to manage the effects of abstraction.
Article 11 of the Water Framework Directive (2000/60/EC) requires Member States to
establish a programme of measures that ensures the achieving of the objectives of the Water
Framework Directive (2000/60/EC). The basic measures that must be in the programmes of
measures are stated in that article.
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According to Article 11(3)(e) the programme of measures should inter alia contain controls
over the abstraction of fresh surface water and groundwater, and impoundment of fresh
surface water, including a register or registers of water abstractions and a requirement of
prior authorisation for abstraction and impoundment. In other words, the abstraction of water
from surface waters or groundwater sources should need prior authorisation. The only
potential exemption is that Member States can exclude abstractions that have no significant
impact on water status.
This authorisation would be required to ensure that the objectives of Article 4 of 2000/60/EC
are met and take account of the assessment in Article 5 of the directive

Article 4 sets out objectives to protect, enhance and restore surface waters,
groundwater and projected areas.

Article 5 specifies that analysis be undertaken for the river basin that takes into
account its characteristics, the impact of human activity on the status of water bodies
and the economics of water use.
The competent authority must take into account the impacts that arise from the intake and
use of water. If the impacts do not interfere with the achieving of the objectives for the river
basin area involved, the authorisation can be granted. If they do interfere, mitigating
measures must be taken, and if these measures are not sufficient, the intake must be
prohibited. This is not a gap in the EU legislation per se, but it is beyond the scope of this
project to determine whether the Member States’ implementation for this aspect adequately
addresses all environmental risks.
The programmes of measures are due to be in operation at the latest 12 years after the
directive’s entry into force. The directive came into force on 22.12.2000 which means there
is a gap in legislation for Member States that have not yet made the measures operational,
although this should not exist beyond 22.12.2012.
Environmental damage under the Environmental Liability Directive (2004/35/EC) would be
covered insofar as it relates to activities regulated under the Water Framework Directive
(2000/60/EC).
3.8.3 Conclusions
The Water Framework Directive (2000/60/EC) gives the instruments to address the risk of
water resource depletion. There is a requirement for authorisation of water intake and
adequate measures for reducing the water intake need or for mitigation. This means that
environmental damage should be limited. Further examination, beyond the scope of this
project, is necessary to determine whether the Member States’ implementation for this
aspect adequately addresses water resource depletion risks.
There is a gap due to the timeframe of a full implementation of the Water Framework
Directive (2000/60/EC). This should not exist after 22.12.2012.
3.9 Release to air during fracturing (project stage 3)
3.9.1 Impact and applicable legislation
The release to air of polluting substances during fracturing is described in 2.6.4.
The IPPC Directive (2008/1/EC) is relevant with regard to the emissions to air at the
fracturing site. The Air Quality Directive 2008/50/EC concerns the limit values of air polluting
substances in ambient air. The applicability of IPPC is discussed in section 3.4.4 and in
relation to gaseous emissions in section3.6.
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Information on emissions to air and its impacts on the environment would be considered as
part of the development consent granted in accordance with the Environmental Impact
Assessment Directive (2011/92/EU).
3.9.2 Applicability of the legislation
In instances where a hydraulic fracturing development is covered by IPPC or IED, the permit
application should describe the nature and quantities of foreseeable emissions from the
installation into each medium as well as identification of significant effects of the emissions
on the environment. It should also describe the proposed technology and other techniques
for preventing or, where this not possible, reducing emissions from the installation (Article 6
IPPC). These techniques should meet the general criteria of the IPPC on best available
technology.
In the case of emissions to air from diesel engines used during the process, the possible
technology includes: particle filters, selective catalytic reduction filters, low sulphur fuels,
adequate stack height and others. The emission due to leakage from pumps, valves etc is
not different than in other industrial settings. General abatement techniques and good
maintenance procedures prevent or minimise these emissions. The permit for the site
should contain provisions for this.
Emissions from numerous well developments in a local area or wider region could potentially
have a significant effect on air quality. The IPPC directive (2008/1/EC) article 9(4) or IED
(2010/75/EC) article covers such situations in stating that emission limit values should take
account of geographical location and local environmental conditions. Where an
environmental quality standard requires stricter conditions than those achievable by the use
of the best available techniques, additional measures shall in particular be required in the
permit, without prejudice to other measures which might be taken to comply with
environmental quality standards.
The Air Quality Directive, (2008/50/EC), article 13 and Annex XI, provides the limit values
and alert thresholds for the protection of human health, in general referred to as air quality
standards. The member states have a resultant obligation on this subject.
In the case of many emission sources in the vicinity of a HVHF process site, the cumulative
impact of these sources to the air quality must be taken into account in the permit
application. If the air quality standards are exceeded, extra emission abatement techniques
must be used in order to meet the air quality standards.
The IPPC permit should also contain measures planned to monitor emissions into the
environment, Article 6 2008/1/EC. With the monitored data, the competent authorities are
able to judge whether the emissions to air are within the emission limits set in the permit or
not. In the case of exceeding the limit values, extra abatement techniques are required.
The Environmental Impact Assessment Directive (2011/92/EU) requires an assessment of
projects likely to have significant effects on the environment and includes the effects of air
emissions (point 1c of Annex IV of the Environmental Impact Assessment Directive
(2011/92/EU)). The requirement for an EIA to be carried out is discussed in section 3.4.2.
Aspects covered by the Environmental Impact Assessment affect the development consent
of the project and through this route the competent authority has the powers to impose
measures to protect and preserve the environment potentially impacted by the development.
Should releases to air have a significant effect on the environment, these would be covered
by an EIA.
3.9.3 Conclusions
The legislative framework that consists of the IPPC Directive (2008/1/EC) (or IED
2010/75/EC) – if applicable – and Air Quality Directive (2008/50/EC) could provide the
appropriate structure to manage the impacts from emissions to air during drilling. As
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discussed in section 3.4.4, it is uncertain whether IPPC or IED would apply to shale gas
projects. Hydraulic fracturing activities would be covered by IPPC if hydraulic fracturing
fluids were classified as a hazardous waste. They would also be covered if the combustion
capacity were over 50MW. However, if the combustion equipment at the hydraulic fracturing
site were to be below the 50MW capacity threshold for energy industries, then this would
suggest that the air emission impacts are at a threshold below which would be regulated
under IPPC. This is not necessarily an inadequacy of EU legislation, but because of the
uncertainty over HVHF technology characteristics it is not possible to confirm that related
environmental risks would be adequately addressed.
Significant air impacts would be covered by any assessment carried out under the
Environmental Impact Assessment Directive (2011/92/EU) and taken into account when the
local authority grants development consent. The inadequacies concerning the EIA directive
and the role of Member State decision-making are discussed in section 3.4.2.
3.10 Traffic during fracturing (cumulative, project stage 3)
Traffic impacts during the fracturing phase of the project are described in section 2.5.9.
Traffic impacts during fracturing involve air pollution due to emissions from exhaust fumes
(localised air quality impacts), noise impacts and land take, but also impacts on community
severance and accident risks. The severity of traffic impacts will depend on whether liquids
(hydraulic fracturing fluid and wastewater) are transported by truck or by pipelines instead.
When looking at relevant legislation applicable to traffic impacts the Environmental Impact
Assessment Directive (2011/92/EU), the Strategic Environmental Impact Assessment
Directive (2001/42/EC), the Noise Directive (2002/49/EC) and the Air Quality Directive
(2008/50/EC) are relevant.
Regulation (EC) No 595/2009 on type-approval of motor vehicles and engines with respect to
emissions from heavy duty vehicles places obligations on manufacturers of such vehicles to
obtain type approval (Article 4) to ensure compliance with emission limit values set out in
Annex I. This will have an indirect effect on emissions associated with traffic during
fracturing, but is not intended to directly regulate emissions during use.
3.10.1 The Environmental Impact Assessment Directive (2011/92/EU) and the
Strategic Environmental Impact Assessment Directive (2001/42/EC)
Noise impacts and land-take impacts, including those related to traffic, are discussed
elsewhere in the report. The way in which these impacts are covered in the fracturing stage
of gas shale extraction activities is the same. According to the Environmental Impact
Assessment Directive (2011/92/EU estimated noise impacts and land-take impacts over the
whole of the project have to be addressed, including measures how to prevent and mitigate
these impacts (Article 3 and 5 of the Environmental Impact Assessment Directive
(2011/92/EU)). However, as already mentioned in sections 3.4.1 and 3.4.2, Member States
decide whether or not an EIA is appropriate (Article 4(2) of the Environmental Impact
Assessment Directive (2011/92/EU)). Guidance on making this decision is given in the
Directive but approaches between Member States may differ. Also, if an EIA obligation is
applied, the way in which noise and land-take impacts are weighed when deciding whether
or not to grant a permit is the competence of national authorities. Therefore, as already
mentioned, the Environmental Impact Assessment Directive (2011/92/EC) in itself does not
prescribe that an EIA, addressing (cumulative) impacts related to traffic during fracturing, is
mandatory. Further examination, beyond the scope of this study, is needed to determine the
adequacy of implementation of the Environmental Impact Assessment Directive
(2011/92/EC) at Member State level.
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3.10.2 The 2002/49/EC Noise Directive
As already mentioned in section 3.7.2,the Noise Directive (2002/49/EC) itself does not set
noise limits for specific kind of activities. Under the Noise Directive (2002/49/EC) Member
States are required to develop strategic noise maps for noise sensitive locations and
implement measures to tackle problem areas where maximum noise levels are violated.
Furthermore action plans under the Noise Directive (2002/49/EC)must include measures to
manage noise levels, however the measures within the plans are at the discretion of the
competent authorities and do not automatically prohibit noise creating activities. Whilst this
is not a gap in the EU legislation per se, further examination beyond the scope of this project
is needed to determine whether the Member States’ implementation for this aspect
adequately addresses all environmental risks.
Noise emissions of four-wheel motor vehicles are addressed by Council Directive
70/157/EEC of 6 February 1970 on the approximation of the laws of the Member States
relating to the permissible sound level and the exhaust system of motor vehicles , as
modified by Directives 73/350/EEC, 77/212/EEC, 81/334/EEC, 84/372/EEC, 84/424/EEC,
87/354/EEC, 89/491/EEC, 92/97/EEC, 96/20/EC, 99/101/EC, 2006/96/EC, 2007/34/EC.
The proposed4 Regulation on the sound level of motor vehicles would repeal these
Directives. The proposal aims at updating the requirements for the type-approval system as
regards the sound level of motor vehicles and of their exhaust systems. In particular, if
adopted it would introduce a new test method for noise emissions measurement, lower noise
limit values and introduce additional sound emission provisions in the EU type-approval
procedure. The proposed Regulation would have effect on new vehicles put on the market or
taken into use. Eventually it would reduce the noise levels in the vicinity of roads. It would
have no direct relation with HVHF processes and related traffic.
With regard to noise impacts associated with shale gas extraction activities, these are dealt
with in the EIA, if these projects are subject to an EIA obligation. In those cases noise
impacts are expected to be fully/sufficiently covered. This is due to the fact that a Member
State is obliged to indicate in its EIA what the estimated noise impacts are and how these are
dealt with (point 1c of Annex IV of the Environmental Impact Assessment Directive
(2011/92/EU)). However, the Environmental Impact Assessment Directive (2011/92/EU)
leaves at the discretion of competent authorities the way in which noise impacts are
analysed, assessed and weighted. Therefore, as already mentioned, the Environmental
Impact Assessment Directive (2011/92/EC) in itself does not prescribe that an EIA,
addressing (cumulative) impacts related to traffic during fracturing, is mandatory. Further
examination, beyond the scope of this study, is needed to determine the adequacy of
implementation of the Environmental Impact Assessment Directive (2011/92/EC) at Member
State level.
3.10.3 The Air Quality Directive (2008/50/EC)
Article 13 and Annex XI of the Air Quality Directive (2008/50/EC) provide the limit values and
alert thresholds for the protection of human health, in general referred to as air quality
standards which Member States have to respect. The Directive includes standards for
sulphur dioxide, nitrogen dioxide, benzene, carbon monoxide, lead and PM10. .The Member
States have a resultant obligation on this subject. With regard to air quality impacts
associated with shale gas extraction activities, including associated (cumulative) traffic
impacts, are dealt with in the EIA covering the whole project, if these projects are subject to
an EIA obligation. In those cases impacts are expected to be fully/sufficiently covered. This
is due to the fact that a Member State is obliged to indicate in its EIA what the estimated air
quality impacts are and how these are dealt with (point 1c of Annex IV of the Environmental
Impact Assessment Directive (2011/92/EU)). However, the Environmental Impact
4
COM(2011) 0856
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Assessment Directive (2011/92/EU) leaves at the discretion of competent authorities the way
in which the impacts are analysed, assessed and weighted.
Under Article 19 of Air Quality Directive (2008/50/EC), Member States are required to act in
the event of thresholds (in Annex XII) being exceeded. However, these actions need only
extend to communication with the public and the European Commission. The requirements
for remedial actions are described in Chapter IV of the directive, which relates to the
production of air quality plans, including short term plans. That chapter is not specific about
what measures should be taken and there is no requirement for the prohibition of specific
polluting activities in the event that limits are exceeded. Furthermore, it is the Member
States that decide on the sources to be regulated and the actions to be taken to prevent
limits being exceeded, which arguably could introduce the possibility of inconsistent
approaches to the regulation of hydraulic fracturing emissions. Further examination, beyond
the scope of this study, is needed to determine the adequacy of implementation of the Air
Quality Directive (2008/50/EC) at Member State level. The Air Quality Directive
(2008/50/EC) in itself does not prescribe how to deal with (cumulative) impacts related to
traffic during fracturing.
3.10.4 Conclusion
There is no EU legislation that deals specifically with the impact of traffic during fracturing
and this could represent an inadequacy where potential significant risks arise from
cumulative project developments.
3.11 Groundwater contamination during fracturing and
completion (project stages 3 and 4)
3.11.1 Impact and applicable legislation
Groundwater contamination during hydraulic fracturing and well completion can be caused
through several routes as explained in sections 2.6.1 and 2.7.1. The relevant legislation on
the impacts for groundwater contamination is: 2006/118/EC Groundwater Directive;
2000/60/EC Water Framework Directive, and; the REACH regulation, 1907/2006.
3.11.2 Applicability of the legislation
Water Framework Directive (2000/60/EC) and Groundwater Directive (2006/118/EC)
The Water Framework Directive (2000/60/EC) contains general provisions for the protection
and conservation of groundwater and the Groundwater Directive (2006/118/EC) establishes
specific measures to prevent and control groundwater pollution
The Groundwater Directive (2006/118/EC) in particular puts forward criteria for the
assessment of groundwater quality (including monitoring schemes (Article 4)). Article 6 also
contains provisions preventing or limiting inputs of pollutants into groundwater. The
monitoring of the groundwater quality by competent authorities has the purpose of identifying
the change in groundwater quality in an early stage and enabling action to be taken
accordingly. The directive places obligations on Member States in relation to monitoring and
measures to protect groundwater; it does not regulate directly potentially polluting
installations. It is therefore only indirectly applicable to the impacts of hydraulic fracturing
installations, although Article 6(3) excludes measures related to, inter alia, the consequences
of accidents or exceptional circumstances of natural cause that could not reasonably have
been foreseen, avoided or mitigated. Noting the exceptions, under Article 6 of the
Groundwater directive, Member States must ensure that the programme of measures
includes all measures necessary to prevent or limit inputs into groundwater of pollutants, and
thus could in principle involve the prevention of hydraulic fracturing operations, should the
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latter involve the injection underground of pollutants. Overall, we do not consider there to be
inadequacies in relation to the Groundwater Directive.
The Water Framework Directive (2000/60/EC) Annex V, 2.4 gives the directions on the
monitoring of groundwater. Annex V, 2.4.3 of the Water Framework Directive gives the
requirements for operational monitoring to be carried out by Member States, at least once a
year for all those groundwater bodies […] which on the basis of both the impact assessment
carried out [by Member States] in accordance with Annex II and surveillance monitoring are
identified as being at risk of failing to meet the objectives under Article 4. This "identification
process" is drawing on the initial characterisation performed by Member States at the latest
13 years after the date of entry into force of this Directive and every six years thereafter.
Therefore, no operational monitoring is required for groundwater bodies that, in a time frame
of six years, were not identified as being at risk of failing to meet the objectives under Article
4 of the Water Framework Directive (2000/60/EC). As monitoring of aquifers in the
surrounding of HVHF process activities should always be required, which this indicates a
possible gap in legislation.
Well bore leakage
The well bore is constructed by using steel piping combined with a cement casing. The risk
of leakage is one of the aspects that could cause environmental impacts and therefore
should be addressed in the EIA, the permit application under the IPPC Directive (2008/1/EC)
if required, and the waste management plan required under the Mining Waste Directive
(2006/21/EC) as applicable.
The coverage of well integrity issues under Directive 1992/91/EEC, concerning minimum
requirements for improving the safety and health protection of workers in the mineralextracting industries through drilling, is limited to well control (i.e. blowout prevention) rather
than well integrity for the whole life cycle of the well (e.g. design, construction, operation,
maintenance and abandonment). This directive's scope is also health and safety of workers,
and not the environment.
The construction of the well is subject to a number of ISO standards for use in the oil and gas
industry. Amongst these standards are ISO 10426-1 on well cementing; ISO 10405
Care/use of casing/tubing; ISO 11961 Drill pipe. These and other technical standards give
the framework of the technical lay out and construction of the wells and the bore holes.
Amongst these standards are testing and control standards. The content and effectiveness
of the standards were not assessed in the framework of this study.
Migration of wastewater from the production zone into aquifers
In 2.6.1 and 2.7.1 the risk of migration of wastewater from the production zone to aquifers is
considered remote in suitable geological settings and where there is at least a separating
impermeable layer of 600 metres between them. In cases where the layer is smaller or
where specific geological features may constitute natural or manmade migration pathways,
the risk will be higher.
The measures aiming at preventing the risk of the possible migration of wastewater from the
production zone to an aquifer are generally part of an EIA. It is nevertheless acknowledged
that the EIA Directive (2011/92/EU) does not include explicitly geological aspects. The
Environmental Impact Assessment Directive (2011/92/EU) leaves at the discretion of
competent authorities the way in which generic and specific geologic risks are analysed,
assessed and weighted. Whilst this is not a gap in the EU legislation per se, further
examination beyond the scope of this project is needed to determine whether the Member
States' implementation for this aspect adequately addresses all environmental risks.
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Accidental surface spills
The risk of accidental surface spills has been identified in several stages of the HVHF
process. Within the permit for the whole site and the waste management plan, preventive
measures can be taken to avoid or diminish the impacts of these spills. The main issue of
the impacts at this stage for groundwater, but also for surface waters, is the runoff of
pollutants due to spillage or stormwater takings from the working area.
The runoff of pollutants is to be seen as a diffuse emission of contaminated water. Measures
can be prescribed in permits to prevent the runoff of pollutants. The construction of tanks,
containers or other means of storage of chemicals or other used substances should be
properly designed for their use.
The measures aiming at preventing surface spills or avoiding impacts of surface spills are
dealt with under the permit for the Mining Waste Directive (2006/21/EC). Further
examination, beyond the scope of this project, is needed to determine whether the Member
States’ implementation for this aspect adequately addresses all environmental risks.
Reuse of wastewater
The reuse of wastewater (flowback and produced water) is one of the possibilities to reduce
the amount of water that needs to be taken in from either groundwater or surface water
sources (or alternative sources). There are however some constraints on the reuse of
wastewater.
Under the Water Framework Directive (2000/60/EC) programmes of measures must be
made including a number of basic measures, as listed in Article 11(3) of that directive.
Article 11 (3)(j) prohibits the direct discharge of pollutants into groundwater, subject to
specific provisions (exclusions to this general prohibition).
The second one of these provisions is that Member States may authorise re-injection,
specifying conditions for “injection of water containing substances resulting from the
operations for exploration and extraction of hydrocarbons or mining activities, and
injection of water for technical reasons, into geological formations from which
hydrocarbons or other substances have been extracted or into geological formations
which for natural reasons are permanently unsuitable for other purposes. Such
injections shall not contain substances other than those resulting from the above
operations”
The Commission considers that Article 11(3)(j) of the Water Framework Directive does not
allow the injection of flowback water (containing hazardous chemicals) for disposal into
geological formations. As such, the exception clause under Article 11(3)(j) first indent does
not apply to shale gas activities. The Commission sees this approach as being consistent
with the objective of the Water Framework Directive (i.e. ensuring a good status of water
resources) and as being supported by the negotiation history of the Directive, since the
exception clause in Article 11(3)(j) was devised for conventional hydrocarbon operations.
Article 2.2 of the Water Framework Directive (2006/60/EC) defines groundwater as:
“(…) all water which is below the surface of the ground in the saturation zone and
in direct contact with the ground or subsoil"
According to this definition, 'groundwater' encompasses all water, including 'aquifers' and
'bodies of groundwater'.
Article 2.11: 'Aquifer' means a subsurface layer or layers of rock or other
geological strata of sufficient porosity and permeability to allow either a significant
flow of groundwater or the abstraction of significant quantities of groundwater.
Article 2.12: 'Body of groundwater' means a distinct volume of groundwater within
an aquifer or aquifers.
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Article 11(3)(j) prohibits the discharge of pollutants into groundwater. Pollutants are defined
in the Water Framework Directive (2006/60/EC), Annex VIII and Annex X as “any substance
liable to cause pollution”. According to the above, the chemicals that are used in hydraulic
fracturing must therefore not be pollutants, otherwise their use is prohibited.
As mentioned above, Article 11 (3)(j) of the Water Framework Directive (2006/60/EC)
provides as follows (emphasis added by authors):
“(j) a prohibition of direct discharges of pollutants into groundwater subject to
the following provisions: (…)
(Member States) may also authorise, specifying the conditions for:
injection of water containing substances resulting from the operations for
exploration and extraction of hydrocarbons or mining activities, and injection
of water for technical reasons, into geological formations from which
hydrocarbons or other substances have been extracted or into geological
formations which for natural reasons are permanently unsuitable for other
purposes. Such injections shall not contain substances other than those
resulting from the above operations,”
The fracturing fluid does not qualify as "water containing substances resulting from the
operations" as
(i)
employed fracturing fluids are designed to maximise the flow of hydrocarbons
from the geological formation to the wellhead – they serve a purpose and are
not a consequence of the operations, and
(ii)
the flowback water contains the initial fracturing fluid that was 'prepared' for
the fracturing process itself, plus substances liberated by the fracturing
process itself and which were originally present in the geological formation.
In neither case does the flowback water only contain substances resulting from the extraction
process itself – that is, only substances that were originally present in the geological
formation and which have been removed from the formation by the respective practice.
Accordingly, used fracturing fluid is to be considered as extractive waste and flowback water
must be treated according to the requirements of Directive 2006/6621/EC. The classification
of substances as hazardous does not play a role in this respect. A closed-loop use of
flowback water however may avoid the classification as waste.
There are possible impacts in the case that the underground fracturing area is or may be in
connection with aquifers. The EIA and permit application should make these possibilities
clear and migration of polluting substances in the wastewaters must be prevented. Further
examination, beyond the scope of this project, is needed to assess Member State
implementation of the Directives
Waste water that has been (pre)treated up to a level that is not hazardous waste according
to 2008/98/EC, can be used as a product in other industrial sites or at other hydraulic
fracturing jobs provided it does not contain substances identified as pollutants under the
Water Framework Directive.
3.11.3 Naturally occurring radioactive material
The wastewaters contain substances from the geological structure where the fracturing took
place. These substances can also be radioactive substances. The Council Directive
96/29/EURATOM addresses the approach in Article 17 on operational protection of exposed
workers be based in particular on the following principles, inter alia:
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
Article 11 (a) prior evaluation to identify the nature and magnitude of the radiological
risk to exposed workers and implementation of the optimization of radiation protection
in all working conditions;

Article 11 (d) implementation of control measures and monitoring relating to the
different areas and working conditions, including, where necessary, individual
monitoring;
In addition, the general provisions in Article 6 require Member States to ensure that the sum
of doses for members of the public shall not exceed prescribed limits. This means that the
operator has the responsibility to evaluate the possible risks from the wastewaters for the
health of the workers and the general public.
The wastewater must be already monitored on its content according to the Mining Waste
Directive (2006/21/EC) Article 11 (2). The combination of the above mentioned also means
that naturally occurring radioactive materials (NORM) must be taken into account, since it is
possible that these substances can occur in wastewater.
Article 5 of Council Directive 96/29/EURATOM gives the obligation for prior authorisation of
activities concerning radioactive materials, like wastewaters containing NORM. This gives
the competent authorities the means to require measures that prevent impacts due to
radiation. The measures are not generally addressed in the Council Directive
96/29/EURATOM, but can be specified in a case by case approach.
3.11.4 Chemicals used and the management of their impacts
Drilling muds and hydraulic fracturing fluids contain a wide variety of chemicals. These
chemicals fall under the REACH regulation, (1907/2006/EC). Within the REACH system
manufacturers and importers of substances are obliged to register each substance
manufactured or imported in quantities of 1 tonne or above per year.
The registration dossier' for a substance is the set of information submitted electronically (in
IUCLID 5 format) by a registrant to the European Chemicals Agency. It consists of two main
components:
(i) a technical dossier, always required for all substances subject to the registration
obligations,
(ii) a chemical safety report, required if the registrant manufactures or imports a substance in
quantities of 10 tonnes or more per year. Substances present in low concentrations in
preparations (see Article 14(2)), and intermediates under strictly controlled conditions do not
need a chemicals safety report.
The registration must contain information on the substances, which must be used to assess
the risks arising from their use and to ensure that the risks which they may present are
properly managed. This should be done through guidance on safe use for the substance or
preparation. Annex VI of the REACH regulation cites the information required for a
registration.
Downstream users of chemicals must make sure that the chemicals they use are properly
registered for their intended use. They must consider the safety of their use of substances
based primarily on information from the suppliers. They must take the risk management
measures that are appropriate for their intended use Regulation (EC) on REACH
(1907/2006),Article 37(5).This information must be available to the operator of the HVHF
process.
Hence, the operator of a hydraulic fracturing installation must be aware of the risks and
impacts of the use of chemical substances and act according to the risk management
measures. The enforcement of this principle is by Member States. This means that a
Member State can and must act if chemical substances are used outside their intended use
or without registration.
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There are two possibilities for the operator of a shale gas facility to acquire the relevant
information to meet this obligation. They have the right to make their uses known to their
suppliers or they can choose to keep the use confidential. In the first case the supplier can
include the use in the chemical safety assessments. In the second case the user must
perform a chemical safety assessment. This is also the case if the user wants to use a
chemical outside the exposure scenarios communicated by the supplier.
This obligation does not apply if the operator uses less than 1 tonne of the substance per
year. However, an operator always needs to consider the use(s) of the substance and
identify, apply and recommend appropriate risk management measures, REACH
(1907/2006) Article 37.
Provisions for the disclosure of information are contained in Article 118 of REACH
(1907/2006), which states that disclosure of certain information shall normally be deemed to
undermine the protection of commercial interests of the concerned person. This information
includes details of the full composition of a preparation, its use and the quantities
manufactured or placed on the market. Article 119 prescribes arrangements for public
access to information, but also allows for certain information to be withheld for reasons of
commercial sensitivity (Article 119 (2)).
Directive 98/8/EC on biocidal products also has a strict regime on authorisation. Under
Article 3(1) Member States may not permit biocidal products to be placed on the market
unless they are low risk products subject to authorisation (Article 3(2)(i)) or have been
entered into Annex IB of the directive (Article 3(2)(ii)). This directive is also applicable for
fracturing fluids insofar as they may contain biocides. Only biocides that are registered for
this intended use via the above routes are allowed in hydraulic fracturing fluids. This directive
will be replaced by Regulation 528/2012/EU which lays down rules for:
(a) the establishment at Union level of a list of active substances which may be used in
biocidal products;
(b) the authorisation of biocidal products; EN 27.6.2012 Official Journal of the European
Union L 167/7
(c) the mutual recognition of authorisations within the Union;
(d) the making available on the market and the use of biocidal products within one or more
Member States or the Union;
(e) the placing on the market of treated articles.
The Regulation 528/2012 will be applicable as of 1 September 2013. It retains the
authorisation regime of the Directive 98/8/EC on biocidal products. In practice there are no
major changes related to HVHF processes.
The Biocidal Directive 98/8/EC prescribes the exchange of information between Member
States and the European Commission regarding authorisation and registration of products
(Article 18), including those for which authorisation or registration is refused. Under that
directive, the information must include, inter alia, specific details of applicants, the biocidal
product, quantities to be used and conditions imposed on use. Article 19(1) of 98/8/EC
allows for Member States to take necessary steps to ensure the confidentiality of information
which is industrially or commercially sensitive. Applicants may indicate information which
they consider industrially or commercially sensitive, although it is for the Member State to
decide which information must be treated as such. Sensitive information must be exchanged
with other Member States and the European Commission as does non-sensitive information
under Article 18, but sensitive information bust be treated as confidential by these receiving
parties under Article 19.
These provisions allow for the exchange of hydraulic fracturing related biocidal information
between Member States and the European Commission but also for this to be treated as
commercially sensitive.
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The Aarhus Convention (on access to information, public participation in decision-making
and access to justice in environmental matters 25 June 1998) sets requirements that have
relevance to disclosure of chemicals. The objective of the Convention is to contribute to the
protection health and the environment by guaranteeing access to information and decision
making in environmental matters and under Article 6 of the convention public participation in
decision-making is required for activities falling under Annex I. In particular, Annex 1 (12)
confirms the Convention to apply to Extraction of petroleum and natural gas for commercial
purposes where the amount extracted exceeds 500 tons/day in the case of petroleum and
500 000 cubic metres/day in the case of gas. This aligns with the Annex I threshold in the
Environmental Impact Assessment Directive (2011/92/EU). Also, Annex I (5) lists
installations for the treatment of hazardous waste or disposal of non-hazardous waste
exceeding 50 tons per day, which could in principle relate to the waste management
activities under the Mining Waste Directive (2006/21/EC).
The Aarhus Convention also sets out requirements for access to environmental information,
defined as follows:
“Environmental information” means any information in written, visual, aural, electronic
or any other material form on:
(a) The state of elements of the environment, such as air and atmosphere, water, soil,
land, landscape and natural sites, biological diversity and its components, including
genetically modified organisms, and the interaction among these elements;
(b) Factors, such as substances, energy, noise and radiation, and activities or
measures, including administrative measures, environmental agreements, policies,
legislation, plans and programmes, affecting or likely to affect the elements of the
environment within the scope of subparagraph (a) above, and cost-benefit and other
economic analyses and assumptions used in environmental decision-making;
(c) The state of human health and safety, conditions of human life, cultural sites and
built structures, inasmuch as they are or may be affected by the state of the elements
of the environment or, through these elements, by the factors, activities or measures
referred to in subparagraph (b) above;
Article 4(4) allows for requests for information to be refused on the grounds of, inter alia,
confidentiality of commercial and industrial information, although information on emissions
which is relevant for the protection of the environment must be disclosed. Article 5,
describes how information provided must be collected and disseminated. These
requirements align with those contained in the REACH Regulation(1907/2006/EC) and the
Biocidal Products Directive (98/8/EC).
3.11.5 Conclusions
The risks from contamination of groundwater could be regulated through the permit under
IPPC (if required) and Mining Waste Directive (2006/21/EC). The Water Framework
Directive (2000/60/EC) prohibits the direct discharge of pollutants in groundwater, but gives
way for reuse of wastewater if the latter does not contain pollutants. Activities under Water
Framework Directive (2000/60/EC) that cause environmental damage under the
Environmental Liability Directive (2004/35/EC) would then be covered.
Risks would be possible in the case that the underground fracturing area is or can be in
connection with aquifers. The EIA and permit application must have made these possibilities
clear and migration of polluting substances in the wastewaters must be prevented. However,
the Environmental Impact Assessment Directive (2011/92/EU) does not address explicitly
geological conditions and leaves at the discretion of competent authorities the way in which
such risks and impacts are analysed, assessed and weighted. Whilst this is not a gap in the
EU legislation per se (given the horizontal nature of the EIA Directive), further examination
beyond the scope of this project is needed to determine whether the Member States'
implementation for this aspect adequately addresses all environmental risks.
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The use of chemicals is regulated through REACH (1907/2006) and the directive on biocidal
products (98/8/EC). We conclude that this legislation adequately gives the controlling
mechanism for the use of chemicals and biocides associated with HVHF, due to the
authorisation and registration requirements they impose. The legislation does, however,
allow for commercially sensitive information to be withheld from the public under certain
conditions. The legal interpretation of the Commission (EC, 2011) does not provide
additional guidance on this matter.
Council Directive 96/29/EURATOM provides adequate protection for naturally occurring
radioactive materials to workers and the public.
3.12 Surface water contamination risks during fracturing
and completion (project stages 3 and 4)
3.12.1 Impacts and applicable legislation
Wastewaters are collected and recycled in the hydraulic fracturing process, or sent for
disposal. The wastewaters consist not only of the chemicals used in the hydraulic fracturing
process but also salts, metals and other substances dissolved or migrated from the well.
The wastewater is contaminated and needs special attention.
A number of options are available for management of wastewater:

Wastewater may be injected into disposal wells if such facilities are available
according to the contractor's interpretation

Wastewater may be treated in on-site facilities or in separate sewage works

Re-use
3.12.2 Applicability of the legislation
Discharging wastewater to surface water
The handling of impacts on surface water is addressed in the Water Framework Directive,
2000/60/EC (Water Framework Directive (2000/60/EC)). Under this directive (Article 4(1)(a)
Member States shall implement the necessary measures to prevent deterioration of the
status of all bodies of surface water; and protect, enhance and restore all bodies of surface
water, with the aim of achieving good surface water status. For this purpose Member States
shall implement the necessary measures to prevent deterioration of the status of all bodies of
surface water.
This means that any deterioration of the status of surface waters that can be foreseen by the
competent authorities must be prevented. There is no exemption for specific installations
therefore the provisions will apply to hydraulic fracturing installations. Article 11 of
2000/60/EC, specifies, inter alia, basic measures to be undertaken by Member States to
meet the objectives in Article 4. It contains (Article 11(3)(g)) a requirement for prior
regulation, authorisation or registration of point sources liable to cause pollution. The
Directive is not prescriptive regarding the regulatory regime implemented by Member States
and it may be that that a combined permitting approach incorporating permits required under
the IPPC Directive (2008/1/EC) – if applicable – or Mining Waste Directive (2006/21/EC)
would be applied. In fact the permit under the Mining Waste Directive (2006/21/EC) can
contain measures concerning the discharging of wastewater to surface water, provided the
wastewater is generated from the mining process.
The Water Framework Directive (2000/60/EC) ensures that all discharges into surface waters
are controlled according to the combined approach set out in Article 10 of that directive.
Accordingly, Member States must establish/implement emission controls based on best
available techniques, relevant emission limit values, or in the case of diffuse impacts the
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controls including, as appropriate, best environmental practices. These measures are to be
enforced through the prior regulation, authorisation or registration arrangements required
under Article 11.
Discharge of wastewater is to be seen as an emission of contaminated water. The water
must be treated in order to satisfy the control measures applicable for discharges to surface
water as referred to in Article 10 of the Water Framework Directive (2000/60/EC).
Priority substances in the field of water policy under the Environmental Quality Standards
Directive (2008/105/EC) are specified in Annex II to that directive. A total of 33 specific
substances of families of substances are listed. For comparison, House of Representatives
(2011 NPR) Annex A identified all chemical components of hydraulic fracturing products
used between 2005 and 2009. In the table below we provide an analysis of which
Environmental Quality Standards Directive (2008/105/EC) appear within the House of
Representatives (2011) report. There are some important caveats to this assessment:

Chemical names may be represented differently between the two sources. The
approach was to investigate any positive identifications between the two lists. No
substances listed in the Environmental Quality Standards Directive (2008/105/EC)
were categorically discounted from those listed in House of Representatives (2011).

Even if substances in House of Representatives (2011) match those in Environmental
Quality Standards Directive (2008/105/EC) this does not necessarily mean they would
be used or be intended to be used in future HVHF operations in the EU.
For ease of reference positive matches are highlighted in bold.
Table 8: Review of chemicals listed in Environmental Quality Standards Directive
Environmental Quality
Standards Directive
(2008/105/EC) priority
substances
Included in House
of Representatives
(2011) Annex A?
Environmental Quality
Standards Directive
(2008/105/EC) priority
substances
Included in House
of Representatives
(2011) Annex A?
Alachlor
Not found
Mercury and its compounds
Not found
Anthracene
Not found
Naphthalene
Included
Atrazine
Not found
Nickel and its compounds
Included
Benzene
Included
Nonylphenol
As below
Brominated diphenylether
Not found
Pentabromodiphenylether
Not found
Octylphenol
As below
Cadmium and its compounds
Not found
(4-(1,1′,3,3′tetramethylbutyl)-phenol)
Not found
Chloroalkanes, C10-13
Included
Pentachlorobenzene
Not found
Chlorfenvinphos
Not found
Pentachlorophenol
Not found
Chlorpyrifos (Chlorpyrifosethyl)
Not found
Polyaromatic hydrocarbons
As below
1,2-dichloroethane
Not found
(Benzo(a)pyrene)
Not found
Dichloromethane
Not found
(Benzo(b)fluoranthene)
Not found
Di(2-ethylhexyl)phthalate
(DEHP)
Not found
(Benzo(g,h,i)perylene)
Not found
Diuron
Not found
(Benzo(k)fluoranthene)
Not found
Endosulfan
Not found
(Indeno(1,2,3-cd)pyrene)
Not found
Fluoranthene
Not found
Simazine
Not found
Hexachlorobenzene
Not found
Tributyltin compounds
As below
Hexachlorobutadiene
Not found
(Tributyltin-cation)
Not found
Hexachlorocyclohexane
Not found
Trichlorobenzenes
Not found
Isoproturon
Not found
Trichloromethane (chloroform)
Not found
Lead and its compounds
Included
Trifluralin
Not found
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(4-nonylphenol)
(Nonyl phenol
ethoxylate included)
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On the basis of this limited assessment, it is concluded that it is possible that the constituents
of hydraulic fracturing fluids would include substances identified as priority substances under
the Environmental Quality Standards Directive (2008/105/EC).
Since wastewater could contain harmful substances the Environmental Quality Standards
(EQS) as set in Directive 2008/105/EC are to be taken into account in the process of granting
the prior regulation, authorisation or registration under the Water Framework Directive
(2000/60/EC) Article 11(3)(g). If the EQS are exceeded this might require extra treatment of
the wastewater or even result in prohibiting discharge to surface water.
The permit discharging water to surface waters under the Water Framework Directive
(2000/60/EC) will also have specific monitoring requirements based on article 11(4) in order
to control the emissions of water to surface waters..
Environmental damage under the Environmental Liability Directive (2004/35/EC) would be
covered insofar as it relates to activities regulated under the Water Framework Directive
(2000/60/EC).
Injection of wastewater into (disposal) wells
Another way of disposing flowback water and other wastewater is to re-inject it in (disposal)
wells. This is however prohibited by Article 11(3)(j) of the Water Framework Directive
(2000/60/EC). See also Section 3.11.
Flowback water disposal to a waste water treatment plant
The urban waste water directive, 97/271/EEC, Article 11, regulates the discharge of industrial
waste water into the collecting systems and urban waste water treatment plants. Under this
article and Annex I.C, discharge of waste water is only permitted if the waste water has been
pre-treated in order to prevent malfunction of the urban waste water treatment facility, to
protect the health of the workers at the plant, to ensure that discharges from treatment plants
do not adversely affect the environment and to ensure the sludge of the treatment plant can
be disposed of safely in an environmentally acceptable manner.
In the case of flowback water, which is contaminated with chemicals from hydraulic fracturing
fluids, as well with salts and other residues that dissolved from the geological formations
during the hydraulic fracturing process, pre-treatment would be required before discharging it
to a municipal waste water treatment plant. These salts and residues should be examined,
and pre-treated, before the water can be presented to the waste water treatment plant.
3.12.3 Chemicals used and the management of their impacts
The use of chemicals is discussed in section 3.12.3. The impacts of potential concern and
regulatory mechanisms are similar in relation to groundwater and surface waters.
3.12.4 Conclusions
Discharges of waste water, mainly flowback waters are regulated through the permit under
the Water Framework Directive (2000/60/EC) taking in to account the environmental quality
standards for the substances in the water and through the obligations under the Mining
Waste Directive (2006/21/EC). Activities under Water Framework Directive (2000/60/EC)
that cause environmental damage under the Environmental Liability Directive (2004/35/EC)
would then be covered. The potential applicability of IPPC to HVHF is discussed in section
3.4.4.
Waste water cannot be sent to waste water treatment plants without pre-treatment.
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3.13 Groundwater contamination during production
(project stage 5)
Risks to groundwater are principally those posed by failure or inadequate design of well
casing, and possibly – in rare circumstances – by the migration of wastewater from the
production zone into aquifers, leading to potential aquifer contamination.
These risks and legislation are discussed in Section 3.11.
3.14 Release to air during production (project stage 5)
3.14.1 Impact and applicable legislation
The impacts related to the release to air during production are addressed in sections
2.8.4and3.9.
3.14.2 Applicability of the legislation
There are no additional aspects over and above those mentioned in 3.9.2.
3.14.3 Conclusions
The legislative framework that could consist of the IPPC Directive (2008/1/EC; provided it
applies) and the Air Quality Directives (2008/50/EC) could give the appropriate structure to
manage the impacts from emissions to air during production. However, Member States
themselves set requirements deemed necessary when implementing the Air Quality Directive
(2008/50/EC). It is beyond the scope of this study to determine the adequacy of
implementation of the Air Quality Directive (2008/50/EC) at Member State level. The Air
Quality Directive (2008/50/EC) in itself does not prescribe how to deal with (cumulative)
impacts related to traffic during fracturing.
3.15 Biodiversity impacts (all project stages)
3.15.1 Impacts and applicable legislation
Impacts on biodiversity may occur during all phases of the HVHF process. They are partly
related to other impacts already covered in the previous sections (e.g. potential effects on
water resources).
The most important legislation that addresses the impacts on biodiversity are: The Habitats
Directive (1992/43/EEC) and the Birds Directive (2009/147/EC). Next to this the
Commission’s legal interpretation of the environmental acquis (EC, 2011) describes that due
to the large number of wells needed to exploit a shale gas play, the appropriate assessment
of cumulative impacts, as required by Article 6(3) of the Habitats Directive (1992/43/EEC)
and the Environmental Impact Assessment Directive (2011/92/EU) is of importance.
The Habitats Directive (1992/43/EEC) aims to help maintain biodiversity in the Member
States. Under the Habitats Directive the "Natura 2000" network has been established. This
network consists of special areas of conservation designated by Member States. It also
includes special protection areas classified pursuant to the Birds Directive (2009/147/EC).
The areas within the Natura 2000 network get special attention under this directive. If
activities or projects are planned in those areas or their impacts might affect these areas, an
EIA must be carried out. Any negative impact on these areas must be prevented and, if not
possible, must be compensated (Article 6 (4)) and will be taken into account in the granting
of a development consent in accordance with the Environmental Impact Assessment
Directive (2011/92/EU).
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3.15.2 Applicability of the legislation
When a Member State is considering the granting of authorisation of prospecting, exploring
or production of hydrocarbons, the possible impacts on designated areas under the Habitats
Directive (1992/43/EEC) and Birds Directive (2009/147/EC) must be taken into account.
During the decision process the competent authority has to carry out an assessment of a
proposed project against the requirements of the Habitats Directive, with the aim of
demonstrating that there would be no harm to the integrity of a Natura 2000 site. The results
of this assessment must be taken into account in the decision. This also applies for the
following decisions on granting a permit. In those cases where significant impacts on the
Habitats are expected, mitigating measures must be taken. This is the case during all
phases of the HVHF process.
The EIA Directive (2011/92/EC) Annex IV 3 and national legislation can be used to address
impacts at sites which are not protected at an EU level. This approach is appropriate for
sites which do not receive protection at an EU level.
3.15.3 Conclusions
Where the EIA Directive applies, the legal framework would cover the potential adverse
impacts on biodiversity.
3.16 Lower priority impacts
This assessment has addressed directly the impacts identified as above moderate risk in
Chapter 2. The application of legislation discussed for these more severe risks is directly
relevant to those of lesser significance described in Chapter 2. This will be the case for
issues related to different stages of the gas exploration and production process, and/or in
relation to cumulative effects in some cases where the effects of individual installations are
considered to be of moderate significance.
It is concluded that the discussion set out above addresses all the issues identified as being
of “low” or “medium” significance, in addition to the “high” and “very high” significance issues.
3.17 Conclusions
In this chapter we have examined the applicability of EU legislation with regard to HVHF and
determined the extent to which key environmental risks are adequately covered. In doing so
we have drawn three types of conclusion:



Inadequacies in EU legislation that could lead to risks to the environment or human
health not being sufficiently addressed.
Potential inadequacies - uncertainties in the applicability of EU legislation: the
potential for risks to be insufficiently addressed by EU legislation, where uncertainty
arises because a lack of information regarding the characteristics of HVHF projects.
Potential inadequacies - uncertainties in the existence of appropriate requirements at
national level: for aspects relying on a high degree of Member State decision-making
for which it is not possible to conclude under this study whether or not at EU level the
risks are adequately addressed.
Each of these types of conclusion are summarised below
3.17.1 Inadequacies in EU legislation
Impact Assessment Directive (2011/92/EU)
The impacts of HVHF processes can be greater than the impacts of conventional gas
exploration and production processes per unit of gas extracted. The use of a single volume
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threshold for all gas extraction activities in Annex I could lead to more severe impacts from
HVHF not being assessed in an impact assessment under this Directive. It is beyond the
scope of this work to examine alternative thresholds or approaches for HVHF. This
inadequacy affects all environmental impacts for which an EIA would involve a more detailed
assessment than would otherwise occur. In our report we have identified it to be particularly
relevant to the key risk stages of landtake during preparation, noise during drilling, release to
air during fracturing, traffic during fracturing and groundwater contamination.
Based on the characteristics of shale gas extraction activities, the latter fall within the scope
of Annex II of the Environmental Impact Assessment Directive (2011/92/EU),(2) (e) [“Surface
industrial installations for the extraction of coal, petroleum, natural gas and ores, as well as
bituminous shale”] and insofar as they constitute “deep drillings” as specified in Annex IId.
However, uncertainty may remain in relation to a shallow well by virtue of lack of precision
over the definition of “deep drilling”, which would not cover shallow drilling activities (not
defined)
The EIA Directive (2011/92/EC) has no explicit coverage of geomorphological and
hydrogeological aspects, and there is a lack of clarity as to whether there is an obligation to
assess impacts related to geological features as part of the impact assessment. This is
considered a potential inadequacy in EU legislation.
Water Framework Directive (2000/60/EC)
The monitoring of the quality of groundwater in general is dealt with in the Water Framework
Directive (2000/60/EC). Annex V, 2.4 gives the directions on the monitoring of groundwater.
Annex V, 2.4.3 of the Water Framework Directive gives the requirements for operational
monitoring to be carried out by Member States, at least once a year for all those groundwater
bodies […] which on the basis of both the impact assessment carried out [by Member States]
in accordance with Annex II and surveillance monitoring are identified as being at risk of
failing to meet the objectives under Article 4. This "identification process" is drawing on the
initial characterisation performed by Member States at the latest 13 years after the date of
entry into force of this Directive and every six years thereafter. Therefore, no operational
monitoring is required for groundwater bodies that, in a time frame of six years, were not
identified as being at risk of failing to meet the objectives under Article 4 of the Water
Framework Directive (2000/60/EC). Monitoring of aquifers in the surrounding of HVHF
process activities should always be required, which indicates a possible gap in legislation.
The monitoring of the groundwater can, and must, be regulated through the permit under the
Mining Waste Directive (2006/21/EC).It affects impacts associated with groundwater
contamination.
The programmes of measures are due to be in operation at the latest 12 years after the
directive’s entry into force. The directive came into force on 22.12.2000 which means there
is a gap in the legislation for Member States that have not yet made the measures
operational, although this should not exist beyond 22.12.2012. This could affect water
abstraction and water contamination impacts prior to that date.
Mining Waste Directive (2006/21/EC)
At present there is no Best Available Technology Reference Document (BREF) at EU level
for shale gas waste management. This could affect the adequacy of measures to manage
impacts related to mining waste. The key mining waste from HVHF is the fracturing fluid and
therefore this inadequacy most directly relates to groundwater and surface water
contamination.
Directives on Emissions from Non-Road Mobile Machinery (Directive 97/68/EC as
amended)
These directives specify limits on emissions of carbon monoxide, oxides of nitrogen,
hydrocarbons and particulate matter from engines up to 560 kW and are aligned with the
equivalent US emissions standards. Emissions limits applicable to engines rated above
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560 kW were recommended in the review of amending Directive 2004/26/EC, either by
extending the limits for engines below 560 kW, or by creating an additional class of engines
above 560 kW. It’s important to note, however, that this legislation applies only to typeapproval and new off-road machines; it does not limit their emissions during the use.
Therefore the effect on emissions is indirect. Plant used for drilling in advance of HVHF
operations is likely to be rated above 560 kW (e.g. see New York DEC 2011 p6-100).
Hence, the existing European emissions limits may not apply to larger drilling plant if the
scope of the directive is not extended to plant rated above 560 kW. This inadequacy affects
air emissions during drilling and fracturing.
IPPC Directive (2008/1/EC) and IED (2010/75/EC)
The IPPC or IED permit application should describe the proposed technology and other
techniques for preventing or, where this not possible, reducing emissions from the installation
(Article 6 IPPC, Article 12 IED)). These techniques should meet the general criteria of the
IPPC on best available technology. However, there are no Best Available Technology
Reference documents (BREF, IPPC or IED) for drilling equipment. This potential gap arises
because of uncertainty over the applicability of the IPPC Directive (2008/1/EC) or IED
2010/75/EC) to hydraulic fracturing related installations, it is not a gap in the IPPC or IED
legislation per se. A similar shortfall would be expected under the Industrial Emissions
Directive (2010/75/EC) regime. It in practice affects air emissions during drilling and
fracturing. It also affects discharges to water bodies since the Water Framework Directive
(2000/60/EC) requires that emission prevention measures under IPPC are taken into
account.
Noise Directive (2002/49/EC) and the Outdoor Machinery Noise Directive(2000/14/EC)
The Noise Directive does not provide noise limits for specific kind of activities, such as drilling
activities for shale gas production purposes and does not mandate specific actions to reduce
noise or prohibit noise creating activities. 2000/14/EC Outdoor Machinery Noise
Directive(2000/14/EC) does specify noise limits, however we have identified that drilling and
compressors with a capacity over 350 kW would not be covered by (2000/14/EC), which is
an inadequacy of legislation at EU level.
Environmental Liability Directive (2004/35/EC)
In conclusion, all environmental damage from activities covered by directives referred to in
Annex III of the Environmental Liability Directive (2004/35/EC) would be covered by
2004/35/EC. However, activities not covered by the Annex III directives would not be
included in this way. In order for other impacts to fall within the scope of the Directive they
have to involve damages to protected species and natural habitats with significant adverse
effects for which the operator has been at fault or negligent. Also, damage caused by
pollution of a diffuse character where it is not possible to establish a causal link between the
damage and the activities of individual operators would be excluded. Impacts potentially not
covered would therefore relate to land-take, release to air during drilling and fracturing (if not
covered by IPPC Directive (2008/1/EC)) and traffic impacts.
3.17.2 Potential inadequacies – uncertainties in the applicability of EU
legislation
There is the potential for risks to be insufficiently addressed by EU legislation, where
uncertainty arises because a lack of information regarding the characteristics of HVHF
projects. The conclusions regarding potential gaps are as follows:
IPPC Directive (2008/1/EC) and IED (2010/75/EC)
It is uncertain whether or not a permit according to the IPPC Directive (2008/1/EC) or IED
(2010/75/EC) is required. This is due to uncertainties in whether fracturing fluids would be
classified as hazardous, since chemical composition of the hydraulic fracturing fluids used is
commercially sensitive and can differ between production sites, and whether combustion
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capacity thresholds in the directive would be met (considered unlikely). This is not
necessarily an inadequacy of EU legislation, but because of the uncertainty over HVHF
technology characteristics it is not possible to confirm that related environmental risks would
be adequately addressed. This impacts releases to air during drilling and fracturing and
releases to water during fracturing, since it is not clear if monitoring and control measures
under that directive would apply.
Mining Waste Directive (2006/21/EC)
It is not clear whether or not a waste facility under this Directive would be classified as a
Category A waste facility, for which additional safeguards are mandatory (major accident
prevention policy and external emergency plan). This uncertainty is brought about by the
fact that it is unclear whether or not the waste coming from the well or remaining in the
underground is considered hazardous. As mentioned above the chemical composition of the
hydraulic fracturing fluids used could be commercially sensitive and can differ between
production sites. It is not possible to confirm that environmental risks in relation to major
accidents would be adequately addressed.
Seveso II Directive (96/82/EC)
Whilst the authors judge it unlikely that the Seveso II Directive is applicable to HVHF process
sites, it is not possible to say definitively that this is the case. This uncertainty affects the
measures that would be required to prevent major accidents involving dangerous
substances, limit their consequences and ensure high levels of protection.
3.17.3 Potential inadequacies - uncertainties in the existence of appropriate
requirements at national level
The following aspects rely on a high degree of Member State decision-making for which it is
not possible to conclude in the scope of this project whether or not at EU level the risks are
adequately addressed. In particular, there is potential for differing interpretations of
directives or the application of conditions within national authorisation and permitting
regimes. It is beyond the scope of this project to examine Member State implementation of
EU Directives or other Member State national legislation.
Strategic Environmental Assessment Directive (2001/42/EC)
This Directive is applicable since shale gas extraction activities fall within the scope defined
in Article 3(2). This means that a strategic environmental assessment is obligatory for public
plans and programmes related to shale gas projects which might have significant
environmental impacts.
Environmental Impact Assessment Directive (2011/92/EU)
Member States must decide whether an EIA is required (Article 4(2)) for activities covered by
Annex II. Guidance on making this decision is given in the Directive but approaches
between Member States could differ regarding the way in which risk and impacts are
weighted and whether or not an EIA is required. The Directive also leaves at the discretion
of competent authorities the way in which land-take impacts are analysed, assessed and
weighted. Any shortfalls could affect all significant environmental impacts since measures in
relation to these would be part of the consenting process were they to be covered by this
directive.
Hydrocarbons Authorization Directive (94/22/EC)
This Directive, which focused on ensuring non-discriminatory access to licences for the
prospection, exploration and production of hydrocarbons, allows Member States to provide in
authorization conditions imposed on concession holders if this is justified from, e.g., the
perspective of environmental protection and protection of biological resources (amongst
others Article 6(2)). This provision makes it possible for Member States to draft authorization
conditions aimed at preventing or mitigating environmental impacts it deems necessary.
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However, this is not a requirement and Member States themselves determine if and how to
implement this in practice.
Mining Waste Directive (2006/21/EC)
The Directive requires Member States to ensure the operator takes all measures necessary
to prevent as far as possible any adverse effects on the environment or human health,
including following abandonment of the well (Article (4(2)), implemented through the permit
and waste management plan (Article 7). Any shortfalls would affect the management of
mining waste and in particular hydraulic fracturing fluids.
IPPC Directive (2008/1/EC) and IED (2010/75/EC)
If applicable, under this directive it is up to the competent authorities to decide on the
frequency of monitoring and inspections. In the case the permit under IPPC or IED is not
required, the complete monitoring and inspection is the jurisdiction of the competent authority
as far as the permit required under the Mining Waste Directive (2006/21/EC) does not
provide the necessary monitoring. Any shortfalls could affect the prevention and
minimisation of emissions to air, especially during drilling and fracturing, and releases to
water during fracturing.
Air Quality Directive (2008/50/EC) and Emissions Standards for Off Road Machinery
Directive 97/68/EC
Compliance with the emissions standards for off road machinery Directive 97/68/EC as
amended would influence emissions of potential concern from on-site plant through design
limits, but would not of itself control emissions during use or deliver compliance with
standards and guidelines for air quality This would need to be implemented via national
provisions specified by Member States under the Air Quality Directive. This could affect
regulation of emissions to air during drilling and hydraulic fracturing.
Under Article 19 of Air Quality Directive (2008/50/EC), Member States are required to act in
the event of thresholds (in Annex XII) being exceeded. Furthermore, it is the Member States
that decide on the sources to be regulated and the actions to be taken to prevent limits being
exceeded, which introduces the possibility of inconsistent approaches to the regulation of
hydraulic fracturing emissions. This could affect regulation of emissions to air during drilling
and hydraulic fracturing and traffic emission during fracturing. Note however, that the Air
Quality Directive (2008/50/EC) is concerned with ambient air quality rather than installation
air emissions.
Water Framework Directive (2000/60/EC)
The competent authority must take into account the impacts that arise from the intake and
use of water. If the impacts do not interfere with the achieving of the objectives for the river
basin area involved, the authorisation can be granted. If they do interfere, mitigating
measures must be taken, and if these measures are not sufficient, the intake must be
prohibited. Any potential shortfalls here would affect the management of impacts from water
usage during hydraulic fracturing.
Noise Directive (2002/49/EC)
Action plans under the Noise Directive (2002/49/EC) must include measures to manage
noise levels, however the measures within the plans are at the discretion of the competent
authorities and do not automatically prohibit noise creating activities. This would particularly
affect management of noise during drilling, fracturing and traffic during fracturing.
3.17.4 Risk assessment
In this section we describe the main risks arising from the gaps identified in the legislation
review. The purpose is to summarise the gaps and uncertainties in the legislation, highlight
the potential consequences of these and indicate their significance. The findings from all
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three categories of conclusion in the preceding subsections are included. The limitations of
this analysis are set out in Section 3.1.
Table 9: Summary of risks arising from gaps or potential gaps in European legislation
Gap or potential gap
Impact
Risk associated with gap/potential gap
Gaps in legislation
Environmental Impact
Assessment Directive
(2011/92/EU)
Annex I threshold for gas
production is above HVHF
project production levels.
Result: no compulsory EIA.
Environmental Impact
Assessment Directive
(2011/92/EU)
Annex II no definition of deep
drilling; exploration phase
would not be covered under
Annex II classification
“Surface industrial installations
for the extraction of coal,
petroleum, natural gas and
ores, as well as bituminous
shale”. Result: no compulsory
EIA
Environmental Impact
Assessment Directive
(2011/92/EU)
No explicit coverage of
geomorphological and
hydrogeological aspects, no
obligation to assess geological
features as part of the impact
assessment
Water Framework Directive
(2000/60/EC)
WFD programmes of
measures are not required to
be enforced until 22.12.2012
Water Framework Directive
(2000/60/EC)
All, especially relevant
to key impacts from
landtake during
preparation, noise
during drilling, release
to air during fracturing,
traffic during fracturing
and groundwater
contamination
A decision on the exploration and production may not
be based on an impact assessment. Public
participation may not be guaranteed, permits may
not be tailor-made to the situation
Impacts may not be known and assessed. Measures
to mitigate possible impacts may not be applied
through consent process or permitting regime.
All, especially relevant
to key impacts from
landtake during
preparation, noise
during drilling, release
to air during fracturing,
traffic during fracturing
and groundwater
contamination
A decision on the exploration and production may not
be based on an impact assessment. Public
participation may not be guaranteed, permits may not
be tailor-made to the situation
HVHF project involving shallow drillings not covered
by EIA. For these projects, impacts may not be
known and assessed. Measures to mitigate possible
impacts may not be applied through consent process
or permitting regime.
Preventative measures may not be undertaken.
Aquifers in surroundings not known, leading to
unanticipated pollution.
Especially relevant for
groundwater
contamination,
seismicity, land
impacts, release to air
No assessment of geological and hydrogeological
conditions (e.g. natural and manmade faults, fissures,
hydraulic connectivity, distance to aquifers, etc) in the
frame of the impact assessment or screening,
resulting in sub-optimal site selection and risks of
subsequent pollution
Monitoring of groundwater quality of aquifers in
surrounding of the site may not be done and
preventative measures not undertaken.
Aquifers in surroundings not known, leading to
unanticipated pollution.
Abstraction of water
and impacts due to
water contamination
Inadequate monitoring and measures to prevent
these impacts
Pollution of
groundwater
“Pollutants” are defined as “any substance liable to
cause pollution, in particular those listed in Annex
VIII.”
Permit conditions may not require monitoring or
measures to prevent hydraulic fracturing leading to
impacts on aquifers
Waste management as
covered by MWD –
treatment of hydraulic
fracturing fluids during
and after fracturing
No shared opinion on Best Available Techniques nor
enforcement of those techniques
Higher levels of pollution arising from the
management of mining waste
Air pollution especially
during drilling and
fracturing
Measures may not be taken to prevent high emissions
to air, leading to localised increased air pollution,
although purpose of legislation is to regulate machine
standards not emissions during use.
For substances which are not
pollutants, the WFD does not
prevent direct fracturing into
groundwater that may
ultimately impact aquifers
Mining Waste Directive
(2006/21/EC)
No reference document on
Best Available Techniques
(BREFs)
Directives on Emissions
from Non-Road Mobile
Machinery (Directive
97/68/EC as amended)
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Gap or potential gap
Impact
Risk associated with gap/potential gap
Air pollution especially
during drilling and
fracturing
Measures may not be taken to prevent high emissions
to air, leading to localised increased air pollution. This
potential gap arises because of uncertainty over the
hazardous character of fracturing fluids which would
determine the applicability of the IPPC Directive
(2008/1/EC) to hydraulic fracturing installations
Noise during drilling
Drilling equipment used in HVHF processes however
is not included in the equipment cited in this directive.
Compressors used for drilling have a power capacity
over 350 kW, which is the limit for this directive
Air pollution during
drilling and fracturing
and traffic impacts
No measures to reduce emissions to air. Levels of air
pollution may be above impact levels or air quality
standards.
Landtake, air impacts
during drilling and
fracturing and traffic
Some environmental impacts may not be covered.
Lack of emission limits for offroad combustion plant above
560 kW
IPPC Directive (2008/1/EC)
and IED (2010/75/EC)
No BREF for drilling
equipment
The Outdoor Machinery
Noise Directive2000/14/EC
Gaps in limits to prevent noise
for specific equipment
Air Quality Directive
(2008/50/EC)
Not specific about remedial
measures or prohibition of
polluting activities
Environmental Liability
Directive (2004/35/EC)
Damage caused by non
Annex III activities not covered
unless it is a damage to
protected species and natural
habitats resulting from a fault
or negligence on part of
operator. Impacts caused by
diffuse pollution are not
covered, unless a causal link
can be established
Uncertainties in application
IPPC Directive (2008/1/EC)
and IED (2010/75/EC)
Emissions to air, water
and soil
No permit obligation under IPPC and no BREF under
IPPC or IED .This potential gap arises because of
uncertainty over the hazardous character of fracturing
fluids which would determine the applicability of the
IPPC Directive (2008/1/EC) to hydraulic fracturing
installations
The monitoring requirements as mentioned in IPPC
directive may not be applied. Integrated measures
designed to prevent or to reduce emissions in the air,
water and land, including measures concerning
waste, in order to achieve a high level of protection of
the environment may not be taken. Monitoring of
emissions to air might not take place.
Major accidents,
groundwater and
surface water pollution,
air impacts
The classification may be inadequately performed
Major accidents might occur without proper
prevention and emergency plans.
Major accidents
involving dangerous
substances (e.g. water
pollution events)
Major accidents might occur without proper
prevention and emergency plans.
Activity not mentioned or may
not be covered under
hazardous waste or
combustion capacity
Mining Waste Directive
(2006/21/EC)
Uncertainty over classification
of Category A waste facility
Seveso II Directive
(96/82/EC)
Uncertainty over whether the
Directive covers high volume
hydraulic fracturing (HVHF),
subject to storage of natural
gas or of specific chemical
additives on-site.
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Gap or potential gap
Impact
Risk associated with gap/potential gap
Issues currently at the discretion of Member States
The Strategic Environmental
Assessment Directive
(2001/42/EC)
All
No SEA would be made
Information on possible environmental effects would
not be available and therefore would not be used in
an authorisation/consent process or permits
All
No EIA would be made. The environmental impacts
would not be assessed and properly described. The
measures that can prevent or mitigate the impacts will
not be presented
All
Member States may not take account of
environmental impacts during the authorisation
process
Waste management as
covered by MWD –
treatment of hydraulic
fracturing fluids during
and after fracturing
There may be inadequate measures for the
monitoring and control of impacts related to
management of mining waste
Emissions to air,
especially during
drilling and fracturing,
and releases to water
during fracturing
There may be inadequate measures for the
monitoring and control of impacts related to air and
water emissions
Member States responsible
for making plans to meet the
AQ standards
Emissions to air,
especially during
drilling, fracturing and
traffic, and releases to
water during fracturing
No specific measures for emission abatement may be
required.
Air pollution may not be prevented or mitigated
Water Framework Directive
(2000/60/EC)
Water use during
fracturing
There may be unmitigated or poorly controlled
impacts arising from water use during abstraction
Noise during drilling
and fracturing and
traffic during fracturing
No specific measures for noise abatement may be
required.
Noise may not be prevented or mitigated
Remains up to Member States
to decide whether or not a
plan or programme might
have significant effects
Environmental Impact
Assessment Directive
(2011/92/EU)
Member States must decide
whether an EIA is required
(Article 4(2)) for activities
covered by Annex II.
Hydrocarbons Authorization
Directive (94/22/EC)
No compulsory account of
environmental aspects
Mining Waste Directive
(2006/21/EC)
Member States decide on the
permit and the control
measures
IPPC Directive (2008/1/EC)
Member State decisions on
monitoring and inspection
Air Quality
Directive(2008/50/EC)
Member State determination
of control measures related to
abstraction
Noise Directive (2002/49/EC)
Up to Member States to set
noise levels and to make
plans to meet these levels
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
4 Review of risk management
measures
This chapter provides a review of the practices, legislation, and standards which can be used
to manage hydraulic fracturing risks.
4.1 Methodology
Information was derived from the literature review, supplemented by additional information
necessary to identify state-of-the-art technologies for control of environmental risks and
impacts associated with high volume hydraulic fracturing, and the expected evolution of
these controls. The following resources were consulted:

Existing technology-based environmental regulations (e.g., the Industrial Emissions
Directive (2010/75/EU); the Control of Major Accidents Hazards (COMAH) Directive
(96/82/EC, also referred to as the Seveso II Directive); and the US EPA’s Oil and Gas
New Source Performance Standards published in April 2012);

The collaborative initiative between industry and regulatory authorities in the US
known as STRONGER (State Review of Oil and Natural Gas Environmental
Regulations). The STRONGER website summarises US state regulations. Relevant
information was also reviewed from US EPA, Delaware River Basin Commission,
Susquehanna River Basin Commission, British Columbia, and US States where
hydraulic fracturing is under way (Colorado, Delaware, Ohio, Oklahoma,
Pennsylvania, Texas, Wyoming).

Government-drafted “best management practices,” for example, those issued by the
state of Pennsylvania, proposals from the State of New York, and recommendations
from the US Secretary of Energy Advisory Board (SEAB) Natural Gas Subcommittee.

Industry guidance materials, principally the American Petroleum Institute series of
Guidance Documents:
o
“Hydraulic Fracturing Operations - Well Construction and Integrity Guidelines
(HF1),” October 2009 NPR ;
o
“Water Management Associated with Hydraulic Fracturing (HF2),” June 2010
NPR
o
“Practices for Mitigating Surface Impacts Associated with Hydraulic Fracturing
(HF3),” January 2011 NPR

Academic research

Recommendations from local interest groups in relation to shale gas activities in their
local area (referred to as “community group recommendations”

Discussions with consultees

Presentations at industry technical conferences; and

Vendor literature, particularly case studies.
The focus of this evaluation was to address the potential impacts set out in Chapter 2.
Where necessary, the review of best practice technologies and regulatory requirements from
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
hydraulic fracturing used during oil and gas production was expanded to risk management
measures and frameworks used for similar/comparable contexts.
The review of control measures from non-European territories focused on regulatory
controls, permitting requirements, and financial assurance (bonding) requirements targeted
to hydrocarbon extraction using high volume hydraulic fracturing – that is, HVHF used for
shale gas extraction, as discussed in Chapter 1.
Where available, information characterising the potential cost and affordability of control
measures was provided
This chapter sets out measures available to government and regulatory authorities, such as
regulations, permitting and bonding requirements. Risk management measures for shale
gas developments which have been recommended for use in Europe, and/or proposed or
implemented by non-European governments are discussed.
The chapter also describes best management practices for environmental control used by
the shale gas industry, largely based on US experience. These are defined by the US
Environmental Protection Agency as: “A practice used to reduce impacts from a particular
land use,” and this section provides a description of measures which are currently required
by regulatory authorities, or recommended by regulators, industry, academics or other
bodies. No single body, EPA or otherwise, has made an ultimate decision about what
constitutes best practice, but there is a consensus between US industry and regulators that
best management practices can be used to reduce impacts or risks of environmental
pollution, based on experience in the US.
The wider oil and gas industry does not always have a positive reputation in terms of
environmental responsibility. Incidents such as the Deepwater Horizon incident or
environmental pollution in the Niger delta have had an adverse effect on the industry’s
reputation. However, HSE awareness is deeply integrated in the oil and gas industry and the
large oil and gas companies are particularly concerned about their reputation in terms of
environmental responsibility. The environmental risk and control measures which are in
place in the oil and gas industry are relevant to hydraulic fracturing, particularly since the
industries active in the exploration and production of unconventional resources in the US are
already part of the established oil and gas industry or are an offshoot of the industry. A
similar situation appears likely to develop in Europe, with established businesses taking a
leading role in the emerging shale gas industry (e.g. see www.europeunconventionalgas.org;
Chevron 2012b NPR). The businesses highlighted in Table A6.1 are established operators
in the oil and gas industry, or are joint ventures with significant input from established
operators.
Industry groups, such as the American Petroleum Institute (API) and government research
organizations, such as the National Energy Technology Laboratory (NETL) have developed
and compiled guidance for best management practices currently used in the oil and natural
gas industry to address potential environmental impacts. This guidance was taken as
representing the industry’s view of robust operating practices, and was not separately
reviewed or evaluated. Industry best management practices (BMPs) do not account for sitespecific conditions. In implementing these best practices, operators must consider local,
state, and federal regulations as well as the setting and geology of each oil and gas
extraction project.
Industry BMPs can address potential impacts that are not feasible (or legal) for government
regulators to address.
The remainder of this section presents information on regulatory and industry-led initiatives.
Some sources identified similar or identical BMPs.
In the wider oil and gas industry, numerous documents, guidelines and standards address
and define environmental control and risk management measures. These focus on the risks
which are common to conventional gas extraction, and do not address the risks which are
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
specific to HVHF. E&P Forum/UNEP (1997 NPR) is a document developed by the oil and
gas industry jointly with the public sector. This report provides an overview of the
environmental issues and the technical and management approaches to achieving high
environmental performance in the activities necessary for oil and gas exploration and
production. Management systems and practices, technologies and procedures that prevent
and minimize impact are described.
The chapter text provides a summary of identified risk management measures. The detailed
analysis of measures is provided in Appendix 7. Following discussion of overarching risk
management measures, Appendix 7 is organised by the stages in shale gas facility
development set out in Chapter 2.
4.2 Summary of risk management measures
Risk management measures and controls are summarised in Table 10, with details provided
in Appendix 7. Some of these measures are already established in Europe, and other
measures may already form part of controls applied under a permitting regime such as those
laid down by the IPPC Directive, the Industrial Emissions Directive, or the Mining Waste
Directive, but an analysis of national permitting requirements was out of the scope of this
study.
Table 10: Summary of risk management measures and controls
Aspect
Database
Peer review
Zoning
(general)
Description of measure
Status
Creation of a national database of public sources
of information
Expert panel recommendation
to US Government
Develop database of baseline water quality and
quantity, and geologic information across a shale
gas formation, prior to the commencement of
HVHF
Recommended best practice
from geological survey
consultee
Funding to enable peer review of regulatory
activity
Expert panel recommendation
to US Government
Identifying zones which are off-limits to hydraulic
fracturing if required for environmental protection
Independent report
recommendation to European
Parliament; expert panel
recommendation to US
Government
Prevent HVHF in reforestation areas, wildlife
management areas and high quality aquifers
Proposed regulatory measure
by New York State
Prevent HVHF in areas specified for protection of
groundwater
Recommendation from
academic sector
Minimum distance to private water well: 150 m
Buffer zones
Recommendation to
Pennsylvania state authorities
Delaware River Basin
Commission proposal
Recommendation to
Minimum distance to public water well or reservoir: Pennsylvania state authorities
300 m
Delaware River Basin
Commission proposal
Minimum distance from well to surface
watercourse: 90 m
Recommendation to
Pennsylvania state authorities
Delaware River Basin
Ref: AEA/ED57281/Issue Number 17
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hydrocarbons operations involving hydraulic fracturing in Europe
Aspect
Description of measure
Status
Commission proposal
Minimum distance from disturbance to surface
watercourse: 90 m
Recommendation to
Pennsylvania state authorities
Delaware River Basin
Commission proposal
Minimum distance to watersheds used for drinking Proposed regulatory measure
water supply: 1,200 m
by New York State
Minimum distance to residential areas: 1,600 m
(where possible)
Recommended industry best
practice measure
Distance within which detailed investigation of
noise mitigation is needed: 305 m
Proposed regulatory measure
by New York State
Require site-specific separation from abandoned
wells and other potential pathways for fluid
migration
Regulatory measure adopted by
State of Michigan. Proposed
regulatory measure by New
York State
Require additional containment to prevent surface
water impacts for sites within 800 m of surface
water supply locations
Regulatory measure adopted by
State of Colorado
Notification to local communities when drilling is
planned
Recommendation to
Pennsylvania state authorities.
Public involvement in decisionmaking is an important part of
existing permitting processes
(e.g. Article 15(1) of the IPPC
Directive 2008/1/EC)
Notification to water suppliers in the event of spills
or leaks
Recommended industry best
practice measure
Voluntary ecological initiatives within critical
habitats that would generate mitigation credits
which can be used to offset future development
Recommendation to
Pennsylvania state authorities
Notification
Mitigation
credit system
Environmental Encourage or require accreditation for shale gas
management
installation operators to secure ongoing
systems
environmental improvements
Surface and
water quality
monitoring
Surveys of water quality and levels to be carried
out before, during and after HVHF operations
Air quality
monitoring
Surveys of air quality to be carried out before and
during HVHF operations
Pit liners
Require pit liners to be installed
Secondary
containment
Require secondary containment for storage of
specified hazardous fluids
Ref: AEA/ED57281/Issue Number 17
Measure used voluntarily in
conventional oil and gas
industry
Recommended best practice by
geological surveys and
academics
Established measure in US
shale gas industry
Established measure in US
shale gas industry
Established measure in US
shale gas industry
Regulatory measure, e.g. State
of Louisiana
US Federal regulatory measure
Recommended industry best
practice measure
130
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Aspect
Description of measure
Status
Spill control
plans
Require spill control plans to be produced and
maintained
US Federal regulatory measure
Proposed regulatory measure
by New York State
Well spacing
Minimum spacing of well pads of one per 2.6
square km, with all the horizontal wells in the unit
drilled from a common well pad
Specify minimum well spacing
Expert panel recommendation
to US Government
Minimise
habitat
fragmentation
Implement mitigation measures to minimise
ecological impacts.
Proposed practice by New York
State
Minimise
impacts on
sensitive
habitats
Develop and implement a specific mitigation plan
and monitor in sensitive wildlife areas
Proposed practice by New York
State
Invasive
species plan
Develop and implement an invasive species
mitigation plan
Proposed practice by New York
State
Locate sites away from occupied structures and
places of assembly
Proposed practice by New York
State
Implement management measures to minimise
noise
Noise
mitigation
Implement barrier methods to minimise noise
Carry out noisy operations during the day
Seismicity
monitoring
Visual impact
mitigation
Minimise
impacts of
traffic
Monitoring of seismic activity with intervention in
the event of events occurring
Standard measures to minimise visual impacts
with regard to site location, lighting and paintwork
Road use agreement/transportation plan covering
vehicle routeing and timing
Proposed practice by New York
State.
Established practice in US
shale gas industry
Proposed practice by New York
State.
Established practice in US
shale gas industry
Proposed practice by New York
State
Established practice in US
shale gas industry
Proposed practice by UK
government
European regulator and
geological survey consultee
recommended best practice
Proposed practice by New York
State
Established practice in
conventional gas extraction
Proposed practice by New York
State
Recommended industry best
practice measure
Use existing roads where possible
Recommended industry best
practice measure
Locate access roads away from residential areas
Recommended industry best
Ref: AEA/ED57281/Issue Number 17
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hydrocarbons operations involving hydraulic fracturing in Europe
Aspect
Description of measure
Status
practice measure
Centralise gathering facilities to reduce truck traffic
Proposed practice by State of
Wyoming
Minimise impacts of new road construction via
design and use of appropriate standards; build in
mitigation at design stage
Recommended industry best
practice measure
Limit truck weights
Proposed practice by New York
State
Vehicles to conform with highest emissions
standards
Established best practice for US
shale gas industry. Vehicle
emissions standards are
already applied in Europe.
Unnecessary idling to be prevented
Established best practice for US
shale gas industry
Carry out effective maintenance
Recommended industry best
practice measure
Repair road damage, or make payments to allow
damage to be repaired
Proposed practice by New York
State
Use temporary pipeline for water transportation
Recommended industry best
practice measure
Site selection
Comprehensive assessment to identify optimum
site
Established measure in US
shale gas industry
Management
Staff selection, training and supervision in
environmental protection
Established measure in US
shale gas industry
Maintain land used for gas extraction to a suitable
standard to enable restoration so far as possible
Proposed practice by New York
State
Stockpile surface soils for use in restoration
Recommended industry best
practice measure
Loose soil should be covered with geotextiles or
other materials
Recommended industry best
practice measure
Land
restoration
Pace of
development
Limiting the pace of development could reduce
some acute effects associated with shale gas
development
Site layout
Use cut areas for surface impoundment
construction to avoid unnecessary increases in
facility footprint
Avoid the use of surface impoundments and
reserve pits where possible
Minimise risks
Avoid the use of surface impoundments and
from liquid
reserve pits in flood zones or other sensitive areas
storage and
handling
Silt fences, sediment traps or basins, hay bales,
mulch, earth bunds, filter strips or grassed swales
can be used to slow runoff and trap sediment from
Ref: AEA/ED57281/Issue Number 17
Suggested measure by New
York State
Suggested measure by State of
Wyoming
Recommended industry best
practice measure
Suggested community group
measure
Suggested community group
measure
Suggested community group
measure
Established best practice for US
shale gas industry
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Aspect
Description of measure
Status
leaving the site.
Where possible, activities should be staged to
reduce soil exposure and coincide with a season
of low rainfall
Recommended industry best
practice measure
Contingency planning and training to address
spillage risks
Established best practice for US
shale gas industry
Visual inspection of primary containment before
hydraulic fracturing is carried out
Established best practice for US
shale gas industry
Use conductance monitors for rapid detection and
assessment of spillages
Geological survey
recommended measure
Minimise risks
from
Pipelines should not be located on steep hillsides
temporary
or within watercourses
pipelines
Surface casing to extend to at least 30 m below
aquifers
Surface casing to extend to at least 15 m below
aquifers
Extent of
surface casing
Extent of
production
casing
Well integrity
Recommended industry best
practice measure
Regulatory measure, State of
Michigan
Regulatory measure, States of
Colorado, Illinois, Pennsylvania,
Oklahoma and Ohio
Established industry best
practice
Surface casing to extend below aquifers
Regulatory measure, State of
Montana
Surface casing to extend to at least 30 m below
ground level
Established best practice for US
shale gas industry
Surface casings should be cemented before
reaching a depth of 75 metres below underground
sources of drinking water.
Established best practice for US
shale gas industry
Production casing should be cemented up to at
least 150 metres above the formation where
hydraulic fracturing will be carried out
Established best practice for US
shale gas industry
Pressure tests of the casing and state-of-the-art
cement bond logs should be carried out
Expert panel recommendation
to US Government
Regulation and inspection regime needed to
confirm effective repair of defective cementing
Expert panel recommendation
to US Government
Measure compressive strength with benchmarks
between 2.1 and 8.3 MPa, based on setting times
between 4 and 72 hours
Include well integrity measures in permit specified
under Mining Waste Directive
Regulatory measure, States of
Colorado, Illinois, Texas,
Pennsylvania, Montana, Ohio
Established industry best
practice
Independent recommendation
to European Parliament
Complete cementing and isolation of underground
Established industry best
sources of drinking water must be carried out prior
practice
to further drilling
Casing centralizers should be used to centre the
Ref: AEA/ED57281/Issue Number 17
Established industry best
133
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hydrocarbons operations involving hydraulic fracturing in Europe
Aspect
Description of measure
Status
casing in the hole
practice
Testing of well integrity should take place at
Established industry best
construction, and throughout the lifetime of the well practice
Minimum
depth for
hydraulic
fracturing
Multi-stage
fracturing
Fracturing at depths of less than 600 m requires a
specific permit
Regulatory measure, British
Columbia
Fracturing not permitted with a separation of less
than 46 m between fracture zone and aquifer
Regulatory measure, State of
Michigan
Fracturing at depths of less than 600 m or with
Proposed practice by New York
less than 300 m separation between fracture zone
State
and aquifer requires a specific analysis and review
Fracturing with a separation of less than 600 m
between horizontal section of well and aquifer
should not be permitted
Academic sector
recommendation
Maintain hydraulic isolation between porous zones
Regulatory measure, British
Columbia
Regulatory measure in five US
states
Disclosure
Operators should disclose publicly the chemical
constituents of hydraulic fracturing fluid, including
product name and purpose/type; proposed
composition of fracturing fluid by weight; and
proposed volume of each additive
Proposed measure by US
federal authority, EPA and
Bureau of Land Management
Proposed measure by New
York State and State of British
Columbia
Expert panel recommendation
to US Government
Operators should disclose publicly the results of
well integrity tests
Proposed practice by US
federal authority
Emissions from diesel engines to conform with
highest applicable standards
Established industry best
practice
Use natural gas powered engines and
compressors where feasible
Drilling
engines
Use electrically driven engines and compressors
where feasible
Waste
handling
Drilling fluids
Emerging industry best practice
Expert panel recommendation
to US Government
Emerging industry best practice
Expert panel recommendation
to US Government
Use selective catalytic reduction to reduce
emissions from drilling rig engines
Emerging industry best practice
Use established procedures and regulatory
frameworks in Europe to manage waste
European regulator
recommendation
Drillers should select fluids to minimise the
environmental hazard posed by drilling wastes
Proposed practice by New York
State
Separation of drilling fluids and processing to
facilitate re-use
Recommended industry best
practice
Use closed-loop systems to reduce drilling time,
drilling fluid use and surface disturbance
Suggested community group
measure
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Aspect
Composition
of HVHF fluid
Description of measure
Status
Develop guidance for use of diesel fuel in HVHF
fluid
Proposed measure by US EPA
Prohibit use of diesel fuel in HVHF fluid
Expert panel recommendation
to US Government
Prohibit use of specified volatile organic
compounds in groundwater zone
Regulatory measure in State of
Wyoming
Use of specified volatile organic compounds in
HVHF fluid requires prior authorisation
Regulatory measure in State of
Wyoming
Select appropriate additives to minimise
environmental impacts
Established measure in US
shale gas industry
Minimise biocide use, e.g. via use of UV
disinfection techniques in place of chemical
biocides
Industry best practice measure
under consideration
Select proppants which minimise the HVHF
treatment required
Industry best practice measure
under consideration
Expert panel recommendation
to US Government
Established practice in State of
British Columbia
Water
resource
management
Develop and use an integrated water management
Established practice by
system
Susquehanna River Basin
Commission
Proposed practice by Delaware
River Basin Commission
Require use of alternative sources of water
Avoid sensitive areas for water withdrawals
Control of
invasive
species
Control of
HVHF process
Proposed practice by Delaware
River Basin Commission
Industry best practice measure
under consideration
Recommended industry best
practice measure
Proposed practice by New York
Implement precautions to prevent invasive species State
from water storage by cleaning vehicles and
Recommended industry best
appropriate disposal of surplus water
practice measure
Predictive modelling to optimise fracturing
strategies
Established measure in US
shale gas industry
Share data from nearby fracturing operations
Established measure in US
shale gas industry
Ensure equipment compatible with composition of
fracturing fluid
Established measure in US
shale gas industry
Use all available techniques to minimise risk of
fracturing taking place outside the target reservoir
Established measure in US
shale gas industry
Thorough planning and testing of equipment prior
to fracturing operations
Established measure in US
shale gas industry
Development of contingency plan prior to
Established measure in US
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Aspect
Description of measure
Status
fracturing operations
shale gas industry
Detailed monitoring of process during fracturing
operations
Established measure in US
shale gas industry
Develop pre-treatment standards for discharges of
Proposed regulatory measure
shale gas extraction wastewater to municipal
by US EPA
wastewater treatment plants
Establish treatment requirements/discharge limits
for treatment and final discharge of wastewater
Wastewater
management
Re-use waste water where possible
Regulatory measure adopted by
the State of Pennsylvania. A
framework for emission controls
and emission limit values for
discharges into surface waters
in Europe is already set out in
Article 10 of the Water
Framework Directive
(2000/60/EC), although the
establishment and/or
enforcement of such emission
control and limit values is at the
discretion of Member States
Recommended industry best
practice measure
Academic sector
recommendation
Store waste water in storage tanks, or in double
lined lagoons constructed with regard to local
topography
Recommended industry best
practice measure
Ensure receiving treatment works is capable of
handling wastewaters
Established measure in US
shale gas industry
Install on-site wastewater treatment if appropriate
Industry best practice measure
under consideration
Measure the composition of the stored return
water
Expert panel recommendation
to US Government
Use closed-loop systems manage and reprocess
waste waters
Suggested community group
measure
Develop and adopt air emission standards for
methane, air toxics, ozone-forming pollutants, and
other airborne contaminants
Expert panel recommendation
to US Government
Regulatory measure adopted by
the US EPA
Emissions to
air from well
completion
Require Reduced Emissions Completions to be
carried out
Expert panel recommendation
to US Government
Recommended industry best
practice measure, where
applicable
Prohibit venting of gases, and minimise use of
flaring
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Regulatory measure adopted by
the State of British Columbia
Recommended community
group measure
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Aspect
Leakage to air
during
operation
Temporarily
abandoned
wells
Description of measure
Status
Control of VOC emissions by combustion for any
tank emitting more than 6 tons VOCs per year
Regulatory measure adopted by
the US EPA
Prohibit use of open-top or blow down tanks
Regulatory measure adopted by
the State of Wyoming
Specify required reductions in uncontrolled VOC
emissions
Regulatory measure adopted by
the States of Colorado and
Wyoming
Use low-bleed or no-bleed pneumatic controllers
Regulatory measure adopted by
the State of Colorado
Replace glycol systems with alternatives
Industry measure under
consideration
Survey well head equipment to identify and
address leakage
Recommended industry best
practice measure
Use equipment with low potential for leakage
Recommended industry best
practice measure
Automatic fail-safe equipment on pipelines
Recommended industry best
practice measure
Reduce the number of storage tanks on site
Recommended industry best
practice measure
Set requirements for plugging and inspection of
shut-in wells
Regulatory measure adopted by
the States of Colorado, Illinois,
Oklahoma, Pennsylvania Texas
and Wyoming
Inspect and maintain wellheads every 90 days
Established industry best
practice measure
Plug with 30 m of cement every 760 m and at least
Regulatory measure adopted by
30 m cement at the surface, with 30 m of cement
the State of Wyoming
in horizontal section
Permanent
well
abandonment
Plug with 15 m of cement above every zone to be
protected
Regulatory measure adopted by
the State of Colorado
Plug at least 15 m below the deepest perforation
and 15 m above the shallowest perforation
Regulatory measure adopted by
the State of Illinois
Plug at least 15 m above and below the base of
the deepest usable aquifer
Regulatory measure adopted by
the State of Texas
Plug at least 30 m above and 15 m below each
fluid-bearing stratum
Regulatory measure adopted by
the State of Pennsylvania
Plug from 15 m below to 15 m above the base of
the treatable water zone
Regulatory measure adopted by
the State of Oklahoma
Set requirements for inspection of abandoned
wells
Regulatory measure adopted by
the States of Colorado,
Pennsylvania and Wyoming
Ensure a micro-annulus is not formed at temporary Recommended industry best
plugs
practice measure
Carry out ongoing monitoring programme
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Aspect
Well pad
restoration
Bonding
Wider area
development
Description of measure
Status
Maintain records of well location and depth
indefinitely
Established industry best
practice measure
Transfer ownership and liability to competent
authority on surrender of permit to ensure longterm management
Established practice in other
industries e.g. mineral
extraction
Remove surface impoundments as soon as
possible when no longer needed
Recommended industry best
practice measure
Remediate well pads on an ongoing basis to
facilitate return to original conditions
Recommended community
group measure
Well sites must be restored as soon as possible
after the end of extraction operations
Regulatory measure adopted by
the State of British Columbia
All operators are required to have financial security Regulatory measure adopted by
for the wells through performance bonds on an
US states or other regulatory
individual well or a field of wells
bodies
Operators should work cooperatively with
regulatory agencies and other stakeholders to
promote best practices, and improve
communication with local communities.
Recommended industry best
practice measure
Neighbouring operators work together to ensure
efficient provision of gas collection and water
treatment infrastructure
Regulatory measure adopted by
the State of British Columbia
Transboundary Competent authorities should co-operate in jointly
co-operation
meeting regulatory requirements
Established practice in other
industries e.g. minerals
extraction industry
Tables A7.1, A7.2 and A7.3 in Appendix 7 summarise the potentially effective controls
available to address the potential environmental impacts and risks of shale gas extraction
using high-volume hydraulic fracturing compared to conventional practices currently in use.
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5 Recommendations
5.1 Introduction
This section of the report provides recommendations on justified, feasible and effective risk
management measures applicable in the EU for hydrocarbons operations which involve high
volume hydraulic fracturing. The measures listed below include possible technical and
regulatory measures and are presented as options for consideration by the Commission.
Some measures are established within comparable industries in Europe and/or the USA. At
this stage, it is not possible to be confident that the implementation of some or all of these
measures will be effective in avoiding all risks of environmental and health impacts. In
particular, some impacts such as those resulting from land-take can be minimised but not
fully eliminated. Similarly, risks such as those posed by traffic accidents can be minimised
with the implementation of measures such as those set out below, but cannot be completely
eliminated.
The discussion focuses on the risks identified in Section 2.10 as being of “very high” or “high”
significance for individual well pads or multiple developments in Sections 0 to 5.13.
Consideration is given in overall terms to the risks identified as being of “moderate”
significance in Section 5.14. Recommendations for further consideration and research are
provided in Section 5.16. As in chapter 2, the term “impact” refers to all adverse outcomes –
that is, those which will definitely occur to a greater or lesser extent, as well as those which
may possibly occur. The term “risk” refers to an adverse outcome which may possibly occur
as a result of shale gas operations.
The recommendations set out in this chapter draw on the findings of Chapters 2, 3 and 4.
Potential control measures are drawn largely from experience of application of such
measures to hydraulic fracturing operations in the US. Information on these measures is
taken from New York State DEC (2011 PR), EPA (2011a PR), SEAB (2011a NPR) and IEA
(2012). Information has also been taken from publications from within the gas production
industry, in particular from the Natural Gas Star website hosted by the EPA, and from recent
industry-focused conferences. As the study focuses mainly on issues linked specifically to
HVHF, standards and guidance from the European natural gas extraction industry were not
evaluated.
Where possible, information on costs was provided, and its relevance for the European
context considered where appropriate. Measures which are widely implemented in the US
were considered likely in principle to be practicable and cost-effective for application in
Europe, unless there were specific indications to the contrary. In practice, the costs of HVHF
in Europe, including the costs associated with risk management measures, are likely to be
greater than those associated with similar activities in the US in the early years of
establishment of a shale gas extraction industry.
5.2 General recommendations
A number of the recommendations made by the US Department of Energy (SEAB, 2011a
NPR) are relevant for regulatory authorities in Europe. It is recommended that the European
Commission should take a strategic overview of potential impacts and risks. This will require
consideration of relevant issues for Europe, such as:

Undertaking science-based characterisation of important landscapes, habitats and
corridors to inform planning, prevention, mitigation and reclamation of surface impacts.
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
Establishing effective field monitoring and enforcement to inform on-going assessment
of cumulative community and land use impacts

Restricting or preventing development in areas of high value or sensitivity with regard
to biodiversity, water resources, community effects etc.
As set out in Section 3.17 and in the table above, it is recommended that the European
Commission considers the gaps, possible inadequacies and uncertainties identified in the
current EU legislative framework. It is also recommended that Member States’ interpretation
of EU legislation in respect of hydraulic fracturing should be evaluated.
5.3 Traffic during site preparation and fracturing
The traffic impacts of shale gas pre-production are principally associated with the need for
road delivery of hydraulic fracturing fluid, together with a significant contribution from other
project requirements such as movement of equipment and waste water.
5.3.1 Site selection and design
Taking traffic considerations into account at the site selection stage is likely to enable
efficiencies to be built into the process and thereby deliver reduced traffic impacts.
Description of measure
The impact of transportation and other impacts can be minimised by selecting an appropriate
location, which is close to the main highway network and minimises the use of inappropriate
roads or the need to construct site roads (see also Section5.4.2. Locating sites close to
sources of materials can also be effective in reducing overall vehicle mileage. Developers
should also consider the impacts of potential access road locations at the planning stage,
and preferably, locate access road away from homes and businesses. API (2011a NPR p17)
recommends that existing roads that meet transportation needs should be utilized, where
feasible. When it is necessary to build new roadways, they should be developed with
potential impacts and purpose in mind. Mitigation options should be considered prior to
construction and landowner recommendations should be part of the planning process.
Effectiveness
Appropriate site selection can be effective in reducing the impact of road traffic. However,
site selection and design measures would not significantly affect the number of vehicle
movements required, and further measures may still be necessary.
Feasibility
The feasibility of locating a site close to the existing highway network, and the benefits of
other site design measures on traffic impacts, will vary from one site to another.
Consideration of traffic-related impacts at the project design stage is established practice for
development projects in Europe. An EIA must show the potential impacts and the possible
mitigating measures used to manage these impacts. Site location choice is one of the
aspects considered within an EIA. This instrument should be used in the assessment of
shale gas developments.
Recommendation
This measure should be considered in view of the potential effectiveness of appropriate site
selection and design in mitigating road traffic impacts. The exploration phase is likely to
influence site selection for the production phase, and this measure is therefore relevant for
both exploration and production phases.
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5.3.2 Using alternatives to road transportation
Alternatives to road traffic can be effective in reducing vehicle movements associated with
high volume hydraulic fracturing operations.
Description of measure
Operators can adopt alternatives for reducing truck traffic. These could include:

Use of waterless (or reduced water) fracturing

Use of temporary surface pipes to transport water to the well pad and to transport
flowback and produced water to storage, treatment, or injection points.

Use of well pads that act as a hub to serve multiple well pads through a temporary
piping system

Use of central facilities for storage of other materials and equipment to reduce vehicle
mileage

Onsite treatment and reuse of produced water
Implementation of measures such as these requires a strategic approach to the development
of a site, or (more typically) development of multiple sites in a wider area. It may require
investment in planning and development of additional infrastructure such as local storage
facilities and temporary pipelines.
Reducing road transportation is likely to be attractive in principle to operators because of the
opportunity to reduce costs associated with transport of materials and equipment.
Implementation of some options may have associated impacts – e.g. the use of temporary
pipelines or local storage facilities may require short-term land take.
Effectiveness
Measures such as those set out above can be effective in reducing road transportation
associated with high volume hydraulic fracturing schemes. However, further measures may
still be necessary depending on local circumstances.
Feasibility
The feasibility of implementing alternatives to road transportation will vary from one site and
local area to another. It would be important to consider and minimise the potential impacts of
these alternatives. This would require consideration throughout the development of
individual sites and wider scale projects. Implementing this requirement would be complex
because of the balance between diverse impacts which are potentially covered by more than
one regulatory framework. For example, road traffic and temporary pipework may be
addressed by the EIA Directive; water treatment, re-use and disposal may be covered under
the Water Framework Directive, Mining Waste Directive, IPPC Directive and/or Industrial
Emissions Directive. More sustainable use of water would have positive consequences for
other impacts.
Recommendation
This measure should be considered in view of the potential effectiveness of measures to
reduce road transportation.
5.3.3 Development of transportation plans
Developing a transportation plan for development of an individual site, or at a strategic level
for a number of sites in a wider area, can be effective in reducing the impact of unavoidable
road traffic.
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Description of measure
Developing a transportation plan can be an effective means to reduce truck traffic (e.g. by
sharing loads), designate appropriate parking and storage areas, and identify transportation
routes. Further guidance is provided by API (2011a NPR p17):

Where appropriate, operators should obtain road use agreements with local
authorities.

Whether agreements are in place or not, in areas with traffic concerns, operators
should develop a trucking plan that includes an estimated amount of trucking, hours
of operations, appropriate off-road parking/staging areas and routes. Examples of
possible measures in a road use agreement or trucking plan include:
o
Route selection to maximize efficient driving and public safety;
o
Avoidance of peak traffic hours, school bus hours, community events and
overnight quiet periods;
o
Coordination with local emergency management agencies and highway
departments;
o
Upgrades and improvements to roads that will be travelled frequently;
o
Advance public notice of any necessary detours or road/lane closures; and
o
Adequate off-road parking and delivery areas at the site to avoid lane/road
blockage.
o
Limiting truck weights
Effectiveness
A transportation plan can be effective in reducing the impact of road traffic. However, further
measures may still be necessary depending on local circumstances.
Feasibility
The benefits to be gained from developing a transportation plan will vary from one site and
local area to another. The development of transportation plans for individual developments
or wider scale projects and plans is established practice for development projects in Europe.
Recommendation
This measure should be considered, in view of the potential effectiveness of a transportation
plan in mitigating road traffic impacts
5.3.4 Measures to minimise vehicle emissions
Applying higher standards of emissions control could potentially be effective in reducing the
impact of vehicle emissions on air quality in sensitive areas such as those where baseline air
quality already approaches or exceeds the relevant standards. However, road transport
associated with the development of unconventional gas is likely to have no more than a
minor and localised effect on air quality.
Description of measure
There is an extensive programme of regulation of vehicle emissions in Europe. Road
vehicles used in relation to any development, including unconventional gas projects, would
need to comply with these regulations.
Emissions from truck traffic can be further minimised by using vehicles which conform to the
highest currently applicable standards for vehicle emissions. Trucks should be prevented
from idling over extended periods, with a presumption that engines will be switched off.
Truckload contents should be covered as appropriate to reduce dust and particulate matter
emissions. Consideration should be given to the use of low emissions vehicles.
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Effectiveness
These measures can be effective in reducing the impact of road traffic on air quality to a
limited extent in the vicinity of transportation routes. However, further measures may still be
necessary depending on local circumstances.
Feasibility
Emissions from road transportation can be readily reduced by adopting the measures set out
above. The use of low emissions vehicles would depend on the development and availability
of appropriate technology. The implementation of management measures in relation to
vehicle idling and covering of dusty loads is established practice in Europe. The use of low
emissions vehicles for individual developments is not widely established practice, but could
potentially be implemented as part of a transportation plan (see Section5.3.3), or by the
instrument of environmental zoning.
Recommendation
Such measures should be considered, in view of the potential effectiveness of these
measures in reducing air quality impacts.
5.3.5 Road maintenance
Intensive use of roads by heavy vehicles can cause damage to roads, particularly where
inappropriate roads need to be used for site access. Carrying out road maintenance and
repair can be effective in reducing road vehicle noise and dust, as well as protecting
sensitive area and improving the experience of other road users.
Description of measure
Proper road maintenance is critical for the performance of roads, to manage erosion and to
protect environmentally sensitive areas (API 2011a NPR p17). Operators may be asked to
contribute to road maintenance either by carrying out works themselves, or by making
payments for repair and maintenance of the road network used by operator vehicles.
Effectiveness
These measures can be effective in reducing the environmental impact of roads and road
traffic in general (not just traffic associated with the development), by reducing noise and
dust and avoiding impacts due to erosion.
Feasibility
Highway repairs and maintenance can be readily carried out. Placing requirements on
operators for highway and site road repair and maintenance is established practice in
Europe.
Recommendation
This measure should be considered, in view of its potential effectiveness in mitigating the
wider environmental effects of road traffic.
5.4 Land take during site preparation
Surface installations require an area of approximately 3.0 hectares per pad during the
fracturing and completion phases (New York State DEC 2011 PR Table 5.1; US DOE 2009
NPR). In addition to the well pads, the associated infrastructure (access roads and
pipelines) also results in land take and habitat fragmentation (Lechtenböhmer et al. 2011
NPR page 21; The Nature Conservancy 2011 NPR). The required land-take for
development of a shale gas play could amount to approximately 1.4% of the total land area.
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5.4.1 Maximize required spacing between wells (Install multiple wells/pad)
Increasing well spacing and using multiple wells per pad reduces the total land disturbed for
well pad construction. Fewer pads require fewer roads, pipelines, and other rights of way. A
minimum number of wells per pad could be required, but it may be preferable to impose a
minimum well spacing. For example, New York State anticipates requiring “spacing units of
up to 640 acres [2.6 sq km] with all the horizontal wells in the unit drilled from a common well
pad” (New York State DEC 2011 PR page 5-22).
The pros of this measure are:

reduces the land take compared to single-well pads

reduces construction costs (e.g. SEAB 2011a NPR ; US DOE 2009 NPR).

reduces community impacts
The cons of this measure are:

requires a developer to acquire rights to larger parcels of land

may reduce the gas recovered from the formation

may increase localized impacts during construction, drilling, fracturing, well
completion and production operations (API 2011 NPR p15).
Description of measure
Use larger drilling pads for multiple wells, increasing the spacing between wells.
Justification
Increasing well spacing and using multiple wells per pad reduces the total land disturbed for
well pad construction. Fewer pads require fewer roads, pipelines, and other rights of way.
Effectiveness
Increasing well pad spacing from one pad per 2.5 sq.km to 1 pad per 5 sq km would reduce
the total land disturbance in the drilling phase from 30 hectare to 22.5 hectare per 2,500
hectare area, as set out in the table below. This calculation assumes 6 to 8 horizontal wells
per pad at the 2.5 sq km spacing (New York State DEC 2011 PR p 5-23).
Feasibility
Drilling long horizontal legs from a central vertical well is an essential component of
economic exploitation of unconventional oil and gas resources. Increased well spacing
would be feasible in Europe.
Recommendation
This measure should be considered in relation to the key issues for land-use, in view of the
potential significance of land-take by hydraulic fracturing installations. The exploration phase
is likely to influence land use for the production phase, and this measure would therefore be
effective for both exploration and production phases.
5.4.2 Require Environmental Site Assessment for Optimal Site Selection
Appropriate siting can reduce the amount of land disturbed for constructing roads, pipelines,
and other infrastructure. Appropriate siting can also be an important means of avoiding or
minimising adverse impacts on sensitive receptors such as residential areas or ecosystems.
Description
This measure would require operators to take environmental and health concerns into
account when selecting sites for shale gas extraction facilities. To reduce land take and
facilitate ultimate site reclamation, HVHF operations should be located near existing roads,
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rights of way, and pipelines, so far as practicable. Developers should also select sites which
minimize the amount of surface terrain alteration, avoiding sites requiring cut and fill
construction (API 2011 NPR page 16). Developers should select sites with the minimum
impact on sensitive locations such as residential areas or habitat sites, by virtue of distance,
screening or other means.
There are no specific legislative or regulatory initiatives in place regarding proximity to
existing gas pipelines, although gas developers in close proximity in British Columbia are
obliged to work together to reduce environmental impacts (State of British Columbia, 2011
NPR).
As well as securing environmental benefits, reduced construction and transportation
requirements would reduce costs for well installation and site reclamation, although this may
be offset by the additional cost and difficulty of acquiring land near roads and rights of way.
Effectiveness and Feasibility
Siting flexibility depends on topography and other site-specific considerations.
The feasibility of this remedy requires a mechanism for implementation, e.g. designation of
zones which are off-limits for shale gas development; or enforcement requirement for
individual operators to demonstrate optimum selection for each well pad. This would
normally be implemented via national spatial planning legislation. If an environmental impact
assessment is needed for a specific development, this needs to include an assessment of
alternative locations. The outcome of that assessment would give the competent authority
the possibility of prohibiting non-optimal site selections. Ensuring that shale gas extraction
facilities are included in the scope of the EIA directive as discussed in Chapter 3 would
enable the EIA system to deliver protection for sensitive sites.
Recommendation
In view of the potential significance of land-take by hydraulic fracturing installations this
measure should be considered. The exploration phase is likely to influence site selection for
the production phase, and would therefore be effective for both exploration and production
phases.
5.4.3 Limit the use of impoundments
Construction of storage ponds requires excavation and building berms. Temporary tanks
can be placed on levelled ground, which requires less land disturbance and is therefore
easier to restore during the well production phase. The use of tanks has other benefits as
outlined by New York State DEC (2011 PR). However, the tanks may present more of a
visual impact.
The land used for infrastructure such as storage ponds should be minimized so that land
used for HVHF can be restored to its original form. New York State DEC (2011 PR p7-61)
states: “Tanks, while initially more expensive, experience fewer operational issues
associated with liner system leakage… In addition, tanks can be easily covered to control
odours and air emissions from the liquids being stored. Precipitation loading in a surface
impoundment with a large surface area can, over time, increase the volumes of liquid
needing treatment. Lastly above ground tanks also can be dismantled and reused.”
Effectiveness and Feasibility
The feasibility would depend on the availability of temporary tanks. Temporary tanks are
likely to incur an additional cost to operators. This could be taken into account via e.g. the
economic evaluation procedures for individual sites.
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Recommendation
This measure should be considered in view of the potential significance of land-take by
hydraulic fracturing installations and the potential effectiveness of this measure in mitigating
the impact.
5.4.4 Use temporary surface pipes to transport water to the well pad
Using temporary surface piping to transport make up water to the well pad reduces the
required onsite storage and associated land requirements. This approach can also reduce
transportation requirements. If temporary surface pipes can be installed adjacent to the
access road or gas collection piping, no additional land disturbance is required.
The pros of this measure are:

Avoids potential adverse impacts/risks due to trucking and water storage
The cons of this measure are:

This approach may require additional permitting to cover the pipeline at a national
level, for example via national spatial planning regulations.

The pipeline route may not be available due to land ownership issues or practical
constraints.

The pipeline would need to be maintained during its operational lifetime.

This measure could result in additional land-take and potential impacts on
biodiversity.
Additionally, this approach would typically incur a lower cost than trucking (Auman 2012)
Feasibility
Several operators in the Pennsylvania portion of the Marcellus Shale formation are currently
piping make up water over severe terrain (Auman 2012 NPR , Peloquin 2012 NPR , Kepler
2012 NPR ; DiGennaro, 2012 NPR). The use of this technique is evidently feasible in a
range of situations.
Recommendation
This measure should be considered, in view of the potential significance of land-take by
hydraulic fracturing installations and the potential effectiveness of this measure in mitigating
the impact.
5.4.5 Ensure land disturbed during well construction and development is
reclaimed
This measure minimises the land taken long term or permanently from alternative uses (e.g.,
agriculture, wildlife habitat). As soon as practicable, require the removal of temporary
equipment and reclamation and restoration of excess areas. This will reduce the location
size and overall footprint during the production phase (API 2011 NPR , p15).
During site preparation, require stockpiling of surface soils for all cut and fill areas so that
they can be reused during interim and final reclamation. Topsoil should be segregated from
subsurface materials to improve the effectiveness of reclamation activities. Require
reclamation of non-productive, plugged, and abandoned wells, well pads, roads and other
infrastructure areas. Reclamation should be conducted as soon as practicable and should
include interim steps to establish appropriate vegetation during substantial periods of
inactivity. Native tree, shrub, and grass species should be used in appropriate habitats.
(New York State DEC 2011 PR , p7-77)
The pros of this measure are:
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
Minimizes the duration of surface disruptions
The cons of this measure are:

Reclamation may not effectively restore some original uses (e.g., archaeological
sites, some sensitive wildlife habitats).
Effectiveness
Reclamation can effectively restore many original land uses, e.g., agriculture. Not all impacts
of land taken for construction activities can be remedied. For example, the restored area is
not likely to be appropriate for residential use.
Feasibility
Reclamation of the drilling and completion site during the production phase is common
industry practice. The regulatory challenge is to ensure that this takes place at the earliest
point possible in the lifetime of the site, and to the highest appropriate standard.
Recommendation
The implementation of this measure should be further considered.
5.4.6 Restrict hydraulic fracturing and well pad installation from sensitive
areas
This measure could be appropriate to protect sensitive sites from inappropriate development.
European sites already benefit from protection under Directive 92/43/EEC, as discussed in
Section 3.15. This measure would potentially be used to protect other sensitive features,
such as nature conservation resources which are not covered under Directive 92/43/EEC,
water catchments, or areas of high agricultural or cultural value.
The measure could prevent or restrict the recovery of shale gas reservoirs beneath the
protected areas (other than in areas accessible via horizontal drilling from outside the
protected areas).
Description
It may not be possible to fully restore a site in a sensitive area following well completion or
well abandonment. For example, sites in areas of high agricultural, natural or cultural value
could potentially not be fully restorable following use. Authorities may wish to restrict
development in such areas, for instance in the vicinity of sensitive surface water or
groundwater resources. For example, New York State DEC recommended that high-volume
hydraulic fracturing operations not be permitted in the Syracuse and New York City
watersheds or in a protective 1,200 metre buffer area around those watersheds (New York
DEC (2011 PR) p1-17).
For this reason, it may be appropriate to prevent HVHF operations from being carried out in
identified sensitive areas (see Section 3.4). Depending on the sensitivity of the area and the
depth of the shale formation, the ban could be limited to the installation of well pads and
supporting structures and drilling, allowing horizontal legs to be installed under the sensitive
area.
Effectiveness
This measure would potentially be effective in mitigating impacts and risks in identified
sensitive areas.
Feasibility
Measures of this nature are under consideration by New York State DEC:
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
“Well pads for high-volume hydraulic fracturing would be prohibited in the NYC and
Syracuse watersheds, and within a 4,000-foot [1,200 metre]buffer around those
watersheds;

Well pads for high-volume hydraulic fracturing would be prohibited within 500 feet of
primary aquifers (subject to reconsideration 2 years after issuance of the first permit
for high-volume hydraulic fracturing);

Well pads for high-volume hydraulic fracturing would be prohibited within 2,000 feet of
public water supply wells, river or stream intakes and reservoirs (subject to
reconsideration 3 years after issuance of the first permit for high-volume hydraulic
fracturing);
…

The Department would not issue permits for proposed high-volume hydraulic
fracturing at any proposed well pad within 500 feet [150 metres]of a private water well
or domestic use spring, unless waived by the owner.”
No comparable zonal restrictions on drilling beneath sensitive areas are envisaged by the
New York State DEC.
Recommendation
This measure should be considered in view of the potential significance of land-take by
hydraulic fracturing installations and the potential effectiveness of this measure in mitigating
the impact. The exploration phase is likely to influence site selection for the production
phase, and this measure is therefore relevant for both exploration and production phases.
5.5 Releases to air during drilling
Drilling operations can lead to air emissions from: 1) diesel exhaust fumes from drill rig
engines and site electricity generation; 2) fuel storage tanks; and 3) truck activities near the
well pad (New York State DEC 2011 PR page 6-114, Howarth and Ingraffea, 2011 NPR ;
Lechtenböhmer et al. 2011 NPR). These emissions could potentially pose significant risks to
the environment in the case of development over a wide area.
5.5.1 Require natural gas-fired or electric grid drilling rig engines
Emissions from natural gas combustion are lower than from diesel combustion. Tests with
natural gas-fired drilling rigs reduced emissions by over 4,000 tons of VOC and 600 tons of
NOX per year compared with the diesel drilling rigs (Hill, 2011 NPR). It would be expected
that emissions of fine particulate matter would also be reduced.
Use of grid-connected electric drilling rig engines effectively transfers emissions from the
drilling location to the point of electricity generation. The electricity generating plant may or
may not give rise to emissions to air, and would be subject to its own permitting requirements
and environmental controls. Moving the emission location in this way may be beneficial in
circumstances when drilling occurs in an area that does not meet air quality standards or is
of particular sensitivity to air pollution.
Description of measure
Drilling rig engines are typically powered by transportable diesel engines (New York State
DEC 2011 PR p6-99). Using natural gas-fired drilling rig engines reduces the visible exhaust
typical of diesel engines and emit less than 1.3 gram NOX/kWhr (Wright, 2011 NPR), which
will significantly reduce emissions compared to diesel drilling rig engines.
Natural gas-fired drilling rig engines are only feasible in areas with existing natural gas
infrastructure. In the remote Jonah Play in Wyoming, US, an operator replaced diesel
powered drilling with natural gas-fired rig engines to make use of excess natural gas
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production which would otherwise have been wasted. The natural gas extracted throughout
the field is sent to a centralized processing facility. Some of the processed natural gas is
returned to the drilling rig sites for use in the natural gas powered drilling engines (Wright,
2011 NPR). The quality of the natural gas in other areas may be such that processing is not
necessary before use (Hill, 2011 NPR). For drilling rigs in areas without natural gas
infrastructure, rigs can run on liquefied natural gas (LNG) (Hill, 2011 NPR).
Using electric grid drilling rig engines, where a grid connection is available, reduces
emissions to air by reducing the need for diesel-powered plant at the well pad (WRAP Oil
and Gas Scope p42).
Effectiveness

Reduces truck traffic for hauling diesel fuel to drilling sites

Reduces emissions and visible haze significantly (Hill, 2011 NPR)

Runs more quietly (Hill, 2011 NPR)

If electrically powered plant is less efficient than diesel-fuelled plant, this could result
in a net increase in carbon emissions.
Feasibility
Natural gas infrastructure may not exist in new development areas, which would limit the
applicability of this measure to the use of liquefied natural gas. This measure may result in
higher net costs, depending on the price of natural gas versus diesel fuel and whether the
gas used could otherwise have been sold to the collection network. The low availability of
natural gas-fired drilling rigs may limit the practical feasibility of this remedy at present,
although the market is likely to respond if there is a need for more gas-fired drilling rigs.
Engines fired on natural gas respond more slowly under variable loads than diesel fuelled
engines, so technically it would seem more appropriate to use natural gas fired plant for
constant load operations (Hill, 2011 NPR).
This measure is only appropriate if the electricity grid is accessible from the site. This
measure could potentially result in higher drilling costs depending on the price of electricity
versus diesel and plant efficiency. Electrically powered motors are straightforward to retrofit,
and can be used interchangeably with diesel or diesel-powered generating plant (Shipley,
2009 NPR). However, there may be difficulties related to the installation of power lines, the
use of mobile transformers, and coordination with electric utility company (Shipley, 2009
NPR)
Cost issues are specific to each individual case.
Recommendation
This measure could be considered in view of the potential effectiveness of this measure in
mitigating the impact of emissions to air from site infrastructure.
5.5.2 Require emission controls on lean burn and rich burn drilling rig engines
This measure would reduce emissions of NOX, CO and VOCs (including formaldehyde)
Description of measure
Selective catalytic reduction (SCR) installation on lean-burn drilling rig engines reduces NOX
emissions, while the oxidization catalysts reduce CO, VOCs, and formaldehyde emissions.
The SCR systems require industrial grade urea, anhydrous ammonia, or aqueous ammonia
injected into the engine exhaust prior to flow through a catalyst. The oxidization catalyst is a
dry system (Four Corners AQTF Mitigation Options, 2007 NPR p18; NYSDEC, 2011 NPR
p7-102).
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Non-selective catalytic reduction (NSCR) or 3-way catalyst installation on rich-burn drilling rig
engines reduces NOX, CO, VOCs, and formaldehyde emissions. The 3-way catalyst includes
reduction and oxidation materials to convert NOX, CO, and hydrocarbons to N2, H2O, and
CO2 (Four Corners AQTF Mitigation Options, 2007 NPR p20; NYSDEC, 2011 NPR p7-103).
Effectiveness

Reduce emissions and visible haze

Could potentially be installed on natural gas drilling rig engines for additional emission
reductions
Feasibility
Selective catalytic reduction has the following characteristics:

Limited to lean burn engines

Requires chemical storage, possibly heated depending on chemical and environment

Possible side effects with ammonia slip (increased efficiency results in increased
ammonia slip), which can lead to airborne nitrate formation if there is a NOX plume,
even if NOX emissions are reduced (Four Corners AQTF 2007 NPR p 18)

Requires electrical supply or generation to run the SCR system and instrumentation

Incremental cost is likely to be very high because of the small incremental emission
reductions on lean burn engines (Four Corners AQTF 2007 NPR p18). 5-year cost
for an SCR on a 3-engine rig in the Wyoming, US was estimated at 5 million US
dollars (Four Corners AQTF, 2007 NPR p 18)
Non-selective catalytic reduction and 3-Way Catalytic convertors have the following
characteristics:

Limited to rich burn engines within a narrow air/fuel ratio to maintain catalyst
efficiency (Four Corners AQTF Mitigation Options, 2007 NPR p20)

Limited temperature window for emissions control (Four Corners AQTF Mitigation
Options, 2007 NPR p20)

Possible to retrofit existing engines

Catalysts lose efficiency through lifespan (lifespan up to 5 years)
Emission limits for off-road combustion plant are already specified via a series of European
directives (Directives 97/68/EC, 2002/88/EC, 2004/26/EC and 2010/26/EU. These directives
specify limits on emissions of carbon monoxide, oxides of nitrogen, hydrocarbons and
particulate matter from engines up to 560 kW and are aligned with the equivalent US
emissions standards. As discussed in Section 3.6.1, the position with regard to engines
above 560 kW is subject to review.
Compliance with these EU limits would provide control on relevant emissions of potential
concern from on-site plant, but would not of itself deliver compliance with standards and
guidelines for air quality.
Recommendation
This measure should be considered in view of the potential effectiveness of this measure in
mitigating the impact of emissions to air from site infrastructure. It is recommended that
careful consideration is given to the interactions with existing European directives relating to
emissions from off-road combustion plant, to ensure that any measures are robust and
proportionate.
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5.6 Noise during drilling
Noise from well drilling could potentially affect residential amenity and wildlife, particularly in
sensitive areas (New York State DEC 2011 PR p6-289 to 6-297)
5.6.1 Specification of maximum noise levels at sensitive locations
This measure could be used to deliver effective control on noise impacts at sensitive
locations. This would be particularly important in areas of intensive shale gas development,
where noise impacts could be almost continuous over a period of months.
Description of measure
Setting limits on maximum permissible noise levels is a potentially appropriate means of
protecting local amenity and sensitive ecosystems from noise impacts.
Appropriate noise emissions data, baseline monitoring data, and impact assessment tools
would need to be used to demonstrate compliance with specified noise limits.
Effectiveness
Specifying limits in this way allows the operator to deliver the required performance in the
most effective and appropriate means taking account of the local context (e.g. background
noise levels; topographical influences on noise emissions). It also allows the specific
characteristics of drilling noise to be taken into account when setting limits. Experience in
other industries is that this approach can be effective in controlling impacts due to noise. An
appropriate level of analysis, review, inspection and monitoring would be needed to ensure
ongoing compliance with the specified standards.
However, the use of a limits-based approach would not support the philosophy of reducing
environmental impacts to the minimum level, as operators would tend to work towards
compliance with the limits rather than impact minimisation.
Feasibility
This measure enables operators to select the most appropriate measure for achieving
acceptable performance in terms of noise.
Recommendation
This measure should be considered in view of the potential effectiveness of this measure in
mitigating the impact of noise during drilling and other stages of shale gas exploration and
production. Consideration should be given to the interactions with existing European
directives in relation to noise impacts of minerals extraction and industrial installations. .
5.6.2 Separation between drilling operation and sensitive location
This measure could be used to deliver control on noise impacts at sensitive locations. This
would be particularly important in areas of intensive shale gas development, where noise
impacts could be almost continuous over a period of months.
Description of measure
Noise is mitigated with increasing distance between the source and receptor (New York
State DEC 2011 PR p7-128). New York State uses a distance of 305 metres as indicative of
the zone within which noise impacts may be significant and detailed investigation is needed.
Mitigation can be provided by setting minimum separation distances between wells and
sensitive locations, including residential properties, public amenities, and sensitive habitat
sites. These separation distances would ideally take account of the planned drilling
activities, other mitigation to be provided, and forecast noise levels.
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Effectiveness
This approach could be effective in controlling impacts due to noise, as part of a wider
programme of noise control measures. Setting specific minimum separation distances would
be more straightforward to implement and regulate than a measure based on noise
performance (Section 5.6.1).
Feasibility
This measure provides a simple basis for regulation. However, it would be more complex to
specify appropriate generic separation distances which take account of site-specific
circumstances.
It would be important for this measure to be consistent with existing regulations in relation to
noise impacts of minerals extraction and industrial installations.
Recommendation
This measure should be considered, alongside other measures to mitigate the impact of
noise during drilling. It is recommended that consideration is given to the interactions with
existing European directives such as the Environmental Noise Directive (2002/49/EC) and
plans developed under Article 8 of this Directive.
5.6.3 Management and barrier methods to reduce noise impacts
Noise management measures are an important aspect of noise control at any oil and gas,
mineral extraction or industrial installation or construction site. This measure would comprise
the specification of appropriate controls, which could significantly improve the performance of
a site in relation to noise impacts. This would be particularly important in areas of intensive
shale gas development, where noise impacts could be almost continuous over a period of
months.
A range of potentially applicable management measures is set out in Appendix 7. These
measures could be applied to reduce noise impacts as applicable at individual sites
Effectiveness
The use of management and barrier measures is effective in controlling impacts due to
noise, as part of a wider programme of noise control measures.
Feasibility
The design and implementation of noise management measures is established practice for
oil and gas facility operators. It would be important for this measure to be consistent with
existing regulations in relation to noise impacts of minerals extraction and industrial
installations.
Effectiveness
The use of management measures is effective in controlling impacts due to noise, as part of
a wider programme of noise control measures.
Recommendation
It is recommended that the introduction of management measures is considered, alongside
other measures to mitigate the impact of noise during drilling. It is recommended that
consideration is given to the interactions with existing European directives. .
5.7 Water resource depletion during fracturing
Significant quantities of water are required for HVHF operations. This section considers
measures for management of water resources.
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5.7.1 Regional water resource management
Regional management of water resources will be important to ensure that the effects of
intensive implementation of high volume hydraulic fracturing can be managed in the context
of competing demands on water resources and climatic changes.
Description of measure
As recommended by the US Department of Energy (SEAB, 2011a NPR), under this
measure, authorities would evaluate water use at the scale of affected watersheds, and
consider declaring unique and/or sensitive areas off-limits to drilling and support
infrastructure as determined through an appropriate science-based process.
Effectiveness
Regional water resource management is likely to be effective in balancing competing
demands for limited or scarce water resources. The development and use of an integrated
water management system has the potential for greatly reducing the environmental footprint
and risk of water use in shale gas production.
Feasibility
A North American regulator (consultation response 2012 NPR) considers that it is able to
manage watershed impacts on an integrated basis, using modelling techniques and
information provided by operators.
Recommendation
It is recommended that the introduction of this measure is considered in view of the potential
effectiveness of this measure in mitigating the impact.
5.7.2 Reuse wastewater
Reuse of produced water will reduce the amount of make-up water required for hydraulic
fracturing and thus the potential impacts from water resource depletion.
Description of measure
Recovered wastewater (consisting of fracturing fluid and produced water) can replace some
or all of fracturing fluid make up water (Yoxtheimer, 2012 NPR).
The pros of this measure are:

reduces the quantity of fresh water required from water resources

reduces or eliminates the need for disposal of produced water
The cons of this measure are:

required treatment may be costly and may generate treatment residuals (sludges and
brines) requiring management and disposal

flowback and produced water must be stored and/or transported prior to reuse

reuse may require additional transport of produced water
Effectiveness
Less than 100% of fracturing fluid is recovered. Typically, between 30% and 75% of the
injected fluid is recovered as flowback (DOE 2009 NPR p66; EPA 2011 NPR p42; Webb
2012 NPR). This means that even if all recovered fracturing fluid is reused, additional make
up water is still required.
Feasibility
Technical feasibility depends on the amount and type of salts dissolved in the produced
water and the required fracturing fluid chemistry. Reuse is becoming standard practice for
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shale gas exploitation in the US. Moving wastewater between watersheds and/or political
jurisdictions may require additional approvals under jurisdictions such as Regulation (EC) No
1013/2006 on transfrontier waste shipments (depending on the methods used for transferring
waste and the nature of the waste materials). It would be important to establish an
appropriate regulatory basis for the imposition of requirements with regard to re-use of
wastewater which takes account of the technical and site-specific issues.
Recommendation
It is recommended that the introduction of this measure is considered, in view of the potential
effectiveness of this measure in mitigating the impact. It will be important for any regulatory
regime to be sufficiently flexible to accommodate the range of circumstances and technical
issues likely to be encountered in practice. An alternative regulatory regime may need to be
adapted or introduced to ensure that water recycling is carried out to the maximum
appropriate extent. .
5.7.3 Use of alternative sources of water
Use of lower quality water (e.g. seawater, brackish water) for fracturing fluid make up will
reduce the depletion of drinking water sources (fresh groundwater and surface water).
Description of measure
In place of freshwater of drinking water quality, operators can use alternative water supplies,
such as non-contact cooling water from power plants and industrial boilers, mine drainage
water, and treated wastewater (that is, water which has been treated but is not of sufficient
quality to be discharged to the environment) (Alleman, 2012 NPR ; Vidic 2012 NPR). Use of
alternative supplies may require transport of the water across watersheds and require
adjustment of chemicals used for fracturing as well as treatment to adjust pH and to reduce
concentrations of scale-forming cations (e.g., calcium, magnesium). For example, operators
can use brackish groundwater (500 – 30,000 mg/L TDS) as fracturing fluid make up water.
In coastal locations, operators can use seawater (35,000 mg/L TDS). Use of lower quality
water for make up may require adjustment of chemicals used for fracturing as well as
treatment to reduce concentrations of scale-forming cations (e.g., calcium, magnesium,
barium). Desalination using reverse osmosis has been employed to facilitate use of brackish
water for fracturing fluid make up for the Bakken oil shale, North Dakota, U.S. (Kurz 2011
NPR)
The pros of this measure are:

Reduces the quantity of fresh water required from water resources

May reduce makeup water transportation impacts if the lower quality water is closer to
the well installation than an alternate fresh water supply

May reduce treatment requirements for other waste water producers

May reduce costs for shale gas installation operators where it results in reduced
transportation needs, and may also reduce costs for other waste water producers.
The cons of this measure are:

Any required treatment (particularly reverse osmosis) may be costly

Any required treatment may generate treatment residuals (brine, sludges) requiring
management and disposal

May require additional transport of alternative water supplies, and may involve
additional regulatory approval, inspection, and recordkeeping as well as crossjurisdiction cooperation in watersheds that cross political boundaries
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Effectiveness
In appropriate locations, low quality water could completely replace the use of freshwater and
eliminate the potential impacts from water resource depletion.
Feasibility
The feasibility of use of alternative water supplies depends on their availability and
compatibility with well conditions (Auman 2012 NPR). This may include consideration of
access to reduced water quality water source; the amount and type of salts dissolved in the
water, and the required fracturing fluid chemistry. For example, acid mine water was used to
fracture a well in Tioga County, Pennsylvania (Palone 2010 NPR). Use of seawater at inland
locations may not be feasible because of transportation costs, and other sources may not be
feasible because of transportation costs and liability concerns (Auman 2012 NPR). Onsite
storage in tanks, rather than impoundments, may be required to reduce risk of contamination
from impoundment leaks and spills.
It would be important to establish an appropriate regulatory basis for the imposition of
requirements with regard to use of alternative sources of water which takes account of the
technical and site-specific issues.
Effectiveness
In appropriate locations, alternative sources of water could completely replace the use of
freshwater and eliminate the potential impacts from water resource depletion.
Recommendation
It is recommended that the introduction of this measure is considered in view of the potential
effectiveness of this measure in mitigating the impact. It will be important for any regulatory
regime to be sufficiently flexible to accommodate the range of circumstances and technical
issues likely to be encountered in practice. An alternative regulatory regime may need to be
adapted or introduced to ensure that water recycling is carried out to the maximum
appropriate extent.
5.7.4 Manage water abstraction
Hydraulic fracturing requires large volumes of water, up to 25,000 m3 per well over a short
period of time (see Chapter 1). Withdrawals are intermittent, impermanent, and consumptive
(abstractive water is typically not returned to the water source). In addition to protecting the
interest of various water users, management of water withdrawal from small surface streams
will protect fish and other wildlife habitat.
Description
Manage allocation of surface and groundwater through a regulatory approval process that
considers the conditions of the water source and current and future uses. Use hydrologic
computer models to manage watershed impacts, including reduction in the assimilative
capacity resulting from temporary reduced water flow. For small streams, ensure that the
approval requires a minimum pass by flow (i.e., that water withdrawal must be interrupted if
stream flow falls to a minimum value). Require screens and filters on intake structures to
prevent entrainment of fish and other aquatic organisms, as appropriate for local conditions.
Water withdrawals should be metered, recorded, and reported to the appropriate authority.
The pros of this measure are:

reduces potential impacts on freshwater sources

may reduce disputes between water users
The cons of this measure are:

requires active government approval, inspection, and recordkeeping
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
may require cross-jurisdiction cooperation in watersheds that cross political
boundaries
Effectiveness
Management of freshwater use will maximise its availability to all users.
Feasibility
There are no technical considerations limiting the feasibility of this remedy. Operators may
need to schedule fracturing activities around pass by conditions and water can be stockpiled
in storage impoundments during wet conditions (Auman, 2011 NPR). Water use should be
evaluated on a watershed (or catchment) basis, which may require cross-jurisdictional
cooperation.
Effectiveness
Management of freshwater use will maximise its availability to all users.
Recommendation
It is recommended that the introduction of this measure is considered, in view of the potential
effectiveness of this measure in mitigating the impact. It will be important for this measure to
be sufficiently flexible to accommodate the range of circumstances and issues likely to be
encountered in practice. .
5.8 Releases to air during completion
As discussed in Section 2.6.3, relevant emission sources include engines, flares, venting,
and truck activities near the well pad. Emitted substances include methane, PM, NOX, CO,
VOCs, SO2, and HAPs.
5.8.1 Require reduced emission completions to eliminate natural gas venting
during fracturing from flowback and wastewater
This method can deliver significant reductions in emissions to air, combined with an
unusually short payback period because captured natural gas can be sold.
Description of measure
Reduced emission completions (RECs), or green completions, reduce natural gas venting
during fracturing. The wastewater, natural gas, and condensate produced from the wellhead
are collected so the solids (e.g., proppant) and liquids are separated from the natural gas.
The natural gas is delivered to the sales pipeline rather than venting or flaring, reducing
methane, VOC, and HAP emissions (US EPA Natural Gas Star Lessons Learned website,
accessed 2012 NPR). British Columbia Oil and Gas Commission requires connection to a
sales pipeline if the pipeline is within 1.5 km from the well (BCOGC, 2011 NPR). RECs may
include a dehydrator depending on the natural gas quality from the well and in the sales
pipeline (US EPA Natural Gas Star Lessons Learned website). The dehydrator is also a
source of air emissions, see Sections 5.11.5 and 5.11.6 for recommendations on emission
reductions for dehydrators.
Effectiveness

Estimated produced gas savings 14,000-57,000 m3/day/well (US EPA Gas Star
Lessons Learned)

US EPA Natural Gas STAR partner companies reported capturing for sale over 6.2
million m3 natural gas using RECs in 2009
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Feasibility
The feasibility of Reduced Emissions Completion is enhanced because it results in the
production of saleable natural gas. This results in a short payback period. The estimated
payback periods when using REC on 25 wells/year are as follows (US EPA Gas Star
Lessons Learned):

Natural gas at $0.11/m3 = 7 months

Natural gas at $0.18/m3 = 5 months

Natural gas at $0.25/m3 = 4 months

Natural Gas at $0.35/m3 = 3 months
RECs cannot be used in areas without sales pipelines in close proximity (e.g., exploratory
and delineation wells) (US EPA Gas Star Lessons Learned; Smith 2011 NPR). The use of
green completion in low pressure fields requires a compressor to boost the gas to the sales
pipeline pressure (US EPA Gas Star Lessons Learned). This approach is still under
development and may not be cost effective in every situation.
Hydraulic fracturing with inert gases requires specialized RECs to separate the inert gas from
sales natural gas (US EPA Gas Star Lessons Learned). Portable acid gas removal
membranes can be used, if carbon dioxide is used as the fracturing fluid (US EPA Gas Star
Lessons Learned)
The US EPA has proposed a rule which requires flaring or RECs for all new wells and
recompletions up to the end of 2014. From 2015, operators must capture the gas generated
during the completion period and make it available for use or sale. Exceptions exist for
exploratory or delineation wells and low pressure wells. Operators must use combustion,
unless combustion is a safety hazard or is prohibited by state or local laws.
Recommendation
It is recommended that the introduction of this measure is considered, in view of the potential
effectiveness of this measure in mitigating the impact. It will be important for any regulatory
regime to be sufficiently flexible to accommodate the range of circumstances and technical
issues likely to be encountered in practice.
5.8.2 Require flares or incinerators to control emissions from fracturing
wastewater storage tank vents
Reduced fugitive emissions of methane and other VOCs from fracturing wastewater
Description of measure
Traditionally, fracturing wastewater that flows back from the wellhead is sent to a surface
impoundment (pit) or tank, where the water, hydrocarbon liquids, and sand are separated
and natural gas is vented to the atmosphere or combusted by a flare or incinerator. A flare
combusts natural gas at the end of an elevated flare stack, resulting in a characteristic flame.
An incinerator mixes the natural gas with oxygen in an enclosed chamber, and does not
result in a visible flame (EnerFAQ Flaring p1). British Columbia Oil and Gas Commission
does not permit venting from fracturing wastewater storage tank vents (BCOGC, 2011 NPR).
Requiring flares or incinerators where gas cannot be collected and transferred to the
collection network would reduce methane, VOC, and HAP emissions (US EPA Gas Star
Lessons Learned).
Effectiveness

Open flaring can create visible impacts (US EPA Gas Star Lessons Learned)

Flaring may not be an appropriate option in populated areas
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
There would potentially be an increased risk of grass or forest fires (US EPA Gas
Star Lessons Learned)

It is typically assumed that flares have the potential to be highly efficient (98-99%),
but studies on oil and gas field flares have found lower efficiencies (62-84%) (Four
Corners AQTF Mitigation Options, 2007 NPR p94)

Flares reduce emissions of methane and volatile organic compounds, but result in
increased emissions of CO2, SOX, NOX, PM, and CO (US EPA Gas Star Lessons
Learned)

Flares used during hydraulic fracturing could remain in place to control emissions
from produced water and condensate tanks during production

Flares minimise the risk of explosion by providing a controlled burn of surplus natural
gas
Feasibility
The US EPA has proposed regulations requiring flaring emissions from wastewater storage
tank for hydraulically fractured exploratory and delineation wells unless there is a safety
hazard (US EPA Proposed NSPS Fact Sheet, 2011d NPR).
Proposed permit conditions set out in the New York State Draft Supplemental Generic
Environmental Impact Statement would prohibit flaring during completion operations if a
gathering line is in place (New York State DEC 2011 PR p5-135). British Columbia OGC
requires gas collection and transfer to pipeline where appropriate, or flaring in situations
where a pipeline connection is not available in the vicinity of the site. Operators are required
to co-operate to deliver the most effective solution for control of fugitive gas (British Columbia
OGC, 2011 NPR).
Recommendation
It is recommended that the introduction of this measure is considered, in view of the potential
effectiveness of this measure in mitigating the impact. .
5.9 Groundwater contamination during fracturing and
completion
There are three mechanisms that could potentially result in contact between fluids from
drilling and fracturing, and sensitive groundwater. Firstly, the down hole flow and flowback of
the fracturing fluids, drilling fluids, produced water and gases in the well could result in
contact with groundwater if the wells are not properly constructed. Secondly, subsurface
drinking water supplies could also be contaminated during surface events, such as
accidental spills and leakage from surface impoundment used to store fracturing fluid and
flow back. Thirdly, groundwater could potentially be contaminated in the event that fractures
extend beyond the production zone. The likelihood of aquifer contamination through
fractures is remote where there is more than 600 metres separation between the drinking
water sources and the producing zone. However, where there is no such large depth
separation, the risks are greater.
5.9.1 Monitoring of groundwater quality
Requirements for systematic groundwater quality monitoring will not prevent pollution by
themselves, but will be an important element in identifying any contamination issues which
arise, and enabling remedial actions to be taken, should pollution occur.
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Description
Issues have been identified in the US whereby groundwater contamination has been
tentatively identified (US EPA, 2011c NPR ; Osborn et al., 2011 PR), but establishing the
source of contamination is highly complex because of the absence of baseline monitoring
data. It would therefore be important to carry out regular monitoring of baseline groundwater
quality throughout the stages of a shale gas extraction programme:

Prior to exploration, in vicinity of exploration wells (to identify potential receptors)

During exploration, in vicinity of exploration wells (to identify potential receptors)

Prior to production phase, throughout area of planned production focusing in particular on
potentially sensitive groundwaters and over a period sufficient to identify baseline
conditions

During production phase, throughout area of production focusing in particular on
potentially sensitive groundwaters

Following production phase, throughout area of production focusing in particular on
potentially sensitive groundwaters until surrender of site (analogous to monitoring carried
out in relation to landfill sites under the terms of operating permits issued under the
IPPCD)

Regular monitoring of pressure heads in sensitive aquifers, during all stages, at locations
in the vicinity of exploration wells and in the vicinity of drinking water wells, to provide
information about ground water flow direction and velocity.
The monitoring programme would need to have regard to the pollutants of potential concern,
including methane, fracturing fluid constituents, and contaminants likely to be present in
produced waters as determinants to indicate any unacceptable discharges to controlled
water.
Effectiveness
Requirements for systematic groundwater quality monitoring will be effective as part of a
wider set of measures of prevention of groundwater pollution and ongoing assessment and
monitoring of shale gas extraction installations.
Feasibility
Groundwater monitoring is an established feature of hydrocarbons, mineral extraction and
industrial process operations in Europe at present, but is often carried out only in the event of
a pollution event occurring or being suspected. For other installations such as landfill sites,
groundwater monitoring takes place routinely. Some drinking water wells may be private
wells which do not meet relevant construction standards. This may compromise the ability to
take representative samples.
Recommendation
It is recommended that the introduction of this measure is considered, in view of the potential
effectiveness of this measure in mitigating the impact. It will be important for any regulatory
regime to be sufficiently flexible to accommodate the range of circumstances likely to be
encountered in practice. This impact was identified as potentially of concern with regard to
individual site impacts, and a monitoring programme may also need to be carried out before
and during the exploration phases to establish a baseline. Consequently it is relevant for
both the exploration and production phases.
5.9.2 Restrict hydraulic fracturing in areas with potentially significant
groundwater risks
Many shale gas developments are insulated from potential effects on groundwater
contamination due to the depth of the producing zone, occurrence of low permeable
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geological strata between the producing zone and aquifers, and absence of natural or manmade pathways in the geological strata. However, these conditions are not uniform (US
Department of Energy, 2011 NPR). Impacts could potentially occur in the event of fracturing
extending outside the target formation, potentially providing pathways to near-surface
groundwater.
Description
This measure would comprise a restriction on or prevention of the use of HVHF in zones at
greater risk of groundwater contamination by virtue of the geological features. The use of
HVHF would be limited to formations at a significant depth with low permeability strata above
the formation, and the absence of pathways to near-surface groundwater. This measure
would comprise the specification of criteria that must be met before HVHF can be permitted
for use for shale gas exploration or extraction. For example, based on Davies et al. (2012
PR), an appropriate vertical separation between shale gas extraction and aquifer may be
considered to be 600 metres, slightly longer than the maximum recorded vertical fracture
length of 588 m. A minimum vertical separation was recommended by the International
Energy Agency (2012 NPR p13), and restriction of hydraulic fracturing in sensitive areas
(aquifers and mineral resources) was proposed by the German Environment Ministry
(Umweltbundesamt 2011 NPR p23).
Effectiveness
This measure would potentially be effective in mitigating risks of groundwater contamination
in areas potentially at higher risk.
Feasibility
Criteria of this nature are under consideration with respect to the protection of surface waters
(see Section5.4.6).
Recommendation
It is recommended that the introduction of this measure is considered, in view of the potential
uncertainties associated with the control of the hydraulic fracturing process (e.g. USEPA
2011a PR , p30), and additional uncertainties that may be introduced by transferring
techniques developed for use in the US to the European context. This impact was identified
as potentially of concern with regard to individual site impacts, and consequently it is relevant
for both the exploration and production phases.
5.9.3 Appropriate standard and quality assurance of well casing
Proper installation and quality assurance of well casings is essential for long-term protection
of groundwater and surface water resources, and indirectly for ensuring ongoing protection of
drinking water quality and natural ecosystems.
Description
The following sequence of casing is a minimum requirement:

Conductor (for wellhead)

Surface casing (to isolate near-surface aquifer from production)

Intermediate casing (to provide isolation of deeper aquifers from production)

Production casing (in target formation)
With regards to casing quality the following recommendations are made:

Casing material must be compatible with fracking chemicals (e.g., acids)

Casing material must also withstand the higher pressure from fracturing multiple stages,
and from re-fracturing on up to four occasions
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The casing shall be properly centred to enable complete cementing of the annulus (space
between casing and borehole wall)
With regards to cement quality the following recommendations are made:

Sufficient time shall be allowed for the cement to harden

Tests shall be carried out to determine in situ cement quality

Regulations and inspections are needed to confirm that operators have taken prompt
action to repair defective cementing
Effectiveness
An adequately installed casing throughout the entire well, together with ongoing inspection,
monitoring and maintenance, provides sufficient protection against groundwater pollution.
Feasibility
The full installation and cementation of casings in this way is already standard practice in
European conventional hydrocarbon operations, particularly onshore. However, the use of
hydraulic fracturing may require a higher standard of installation and quality assurance.
Installation and cementation of well casings are routine for well-established oil and gas
contracting companies and operators. Additional design, verification and monitoring
measures may be needed for high volume hydraulic fracturing operations. These measures
are established practice in this industry in the US and could be adapted for use in Europe.
Recommendation
It is recommended that the introduction of this measure is considered in view of the potential
effectiveness of this measure in mitigating the impact. It will be important for any regulatory
regime to be sufficiently flexible to accommodate the range of circumstances and technical
issues likely to be encountered in practice. Because of the limited experience of relation to
HVHF in Europe and absence of relevant standards specific to HVHF, this measure may
require the development of new safeguards for application in Europe as described in
Section5.2. This impact was identified as potentially of concern with regard to individual site
impacts, and consequently it is relevant for both the exploration and production phases.
5.9.4 Surface impoundment construction standards
Proper liner construction will prevent infiltration of stored fluids to the subsurface. Proper
impoundment design and construction will prevent a failure or unintended discharge off site.
Description of measure
To prevent migration of fluid stored in surface impoundments to groundwater, requirements
or a programme to review and approve surface impoundment construction and operation
could be established. Elements may include [API HF3 2011 NPR , page 11]

Initial review of site topography, geology, and hydrogeology

Identification of the distance between the proposed impoundment and ground water
features such as public or private water wells and domestic supply springs and
surface water features (wetland, lake, pond, etc.)

Requirements for impermeable liners, either compacted clay or synthetic materials
such as polyethylene, to prevent groundwater contamination

Design and construction requirements for structural integrity

Documentation of materials placed in the impoundment
The pros of this measure are:
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Requirements are similar to existing programmes for wastewater impoundment
construction and operation, and use established techniques
The cons of this measure are:

Short term storage in clay soils may not justify the cost of impermeable liners. This
would need to be taken into account via the appropriate permitting process.
Effectiveness
Lined impoundments can reduce potential for groundwater contamination from stored
fracturing fluids. A similarly effective alternative would be storage in above ground storage
tanks with secondary containment. Tanks used in this way should also meet relevant
established standards.
Feasibility
Requirements are similar to existing programs for wastewater impoundment construction and
operation.
Recommendation
This measure should be further considered. It will be important for the regulatory regime to
be operated in a sufficiently flexible way to accommodate the range of circumstances and
technical issues likely to be encountered in practice. This impact was identified as potentially
of concern with regard to individual site impacts, and consequently it is relevant for both the
exploration and production phases.
5.9.5 Leak and spill prevention, detection, and control
Description of measure
Establish requirements or a program to review and approve operator plans for spill incident
prevention, detection, and containment. Such requirements may be patterned on oil spill
prevention control and countermeasure requirements. This measure is discussed in detail in
Section 5.10.4.
5.9.6 Control of fracturing process
During fracturing, leakage of fracturing liquid through fractures into the ground water could be
possible. Furthermore hydraulic fracturing can affect the mobility of naturally occurring fluids,
gases, trace-elements, radio-active and organic material. Since there is an uncertainty in
fracture location, fracture may lead to local geologic or man-made features potentially
creating pathways that allow fluids of gases to contaminate drinking water resources.
Besides leakage through artificial pathways there is also a possibility of leakage through
natural pathways, such as cracks, fissures or interconnected pore spaces.
Control of the hydraulic fracturing process is important to ensure that leakage via extended
fractures into the groundwater zone does not take place.
Description
Appropriate technical measures for control of hydraulic fracturing are set out in Section
A6.3.2, in the section headed “Control of fracturing operation”.
Effectiveness
There is little evidence of failures in the hydraulic fracturing operations in the US resulting in
contamination of groundwater. If substantiated, the examples which may exist (US EPA
2011c NPR , Osborn et al. 2011 PR) relate to poor practice which would be identified and
addressed via the implementation of appropriate controls on the well design, fracturing and
gas extraction processes. However, groundwater contamination remains a potential risk and
an area of uncertainty in view of the risk of fractures extending beyond the planned zone.
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Feasibility
Appropriate standards and controls for the hydraulic fracturing process could be
implemented, drawing on sources such as API methodologies (API, 2009 NPR and API,
2011 NPR). These measures are established practice in this industry in the US and could be
adapted for use in Europe.
Recommendation
It is recommended that the introduction of this measure is considered, in view of the potential
effectiveness of this measure in mitigating the impact. It will be important for any regulatory
regime to be sufficiently flexible to accommodate the range of circumstances and technical
issues likely to be encountered in practice. This impact was identified as potentially of
concern with regard to individual site impacts, and consequently it is relevant for both the
exploration and production phases.
5.10 Surface water contamination during fracturing and
completion
Surface water may be contaminated during high volume hydraulic fracturing by

discharges of well site wastewater to surface streams
o
directly from the fracturing operation, or
o
via discharge to wastewater treatment plants

accidental leaks and spills of well site wastewater (returned fracturing fluid (flowback)
and produced water)

site-contaminated runoff
5.10.1 Monitoring of surface water quality
Requirements for surface water quality monitoring will not of themselves prevent pollution,
but will be an important element in identifying any contamination issues which arise, and
assisting in identifying and mitigating the sources of any contamination. Targeted monitoring
focused on the substances and areas of potential concern with regard to proposed or
ongoing unconventional hydrocarbon extraction will add significant value to established
surface water monitoring programmes at river basin level.
Description
It would be helpful to carry out monitoring of baseline surface water quality throughout the
stages of a shale gas extraction development:

Prior to exploration, in vicinity of exploration wells

During exploration, in vicinity of exploration wells

Prior to production phase, throughout area of planned production focusing in particular on
potentially sensitive surface waters

During production phase, throughout area of production focusing in particular on
potentially sensitive surface waters

Following production phase, throughout area of production focusing in particular on
potentially sensitive surface waters
Monitoring would need to have regard to the pollutants of potential concern, including
methane, fracturing fluid constituents, and contaminants likely to be present in produced
waters.
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Effectiveness
Requirements for surface water quality monitoring will be effective as part of a wider set of
measures for prevention of water pollution and ongoing assessment and monitoring of shale
gas extraction installations.
Feasibility
Surface water monitoring requirements are an established feature of hydrocarbons, mineral
extraction and industrial process operations in Europe at present under the terms of site
operating permits.
Recommendation
It is recommended that the introduction of this measure is considered, in view of the potential
effectiveness of this measure in mitigating the impact. It will be important for any regulatory
regime to be sufficiently flexible to accommodate the range of circumstances likely to be
encountered in practice. Monitoring may need to be carried out before and during the
exploration phases to establish a baseline, and consequently it is relevant for both the
exploration and production phases.
5.10.2 Limit pollutant concentrations in wastewater discharges
Limiting discharged pollutant concentrations will protect receiving stream ecosystems and
also protect municipal sewage treatment plants. Sewage treatment plants are designed to
remove dissolved organic constituents, nitrogen compounds, and phosphates, but not the
dissolved salts contained in untreated HVHF wastewater. As a result, the dissolved salts will
pass through the municipal plant untreated and may also reduce the overall effectiveness of
the sewage works. Limits already exist on a range of substances under the Water
Framework Directive and can be applied to individual installations under permitting regimes
such as IPPC, but it may be beneficial to extend the range of wastewater discharge
concentration limits to include the substances of potential concern with regard to wastewater
from unconventional gas operations.
Description of measure
Contamination can be controlled by limiting the mass and/or concentrations of pollutants of
concern in wastewaters discharged to surface waters. (Alternatively, discharges may be
prohibited, as discussed in 5.2.3.) Allowable discharge concentrations may be determined
based on existing water quality criteria or the capacity of the receiving water to assimilate the
pollutants. Another approach is to base allowable discharge concentrations on feasible
treatment technology, i.e., “best available treatment.” Either approach requires detailed
understanding of the identity and concentrations of pollutants present in the wastewater.
Following SEAB (2011a NPR), it is recommended that measurement of the chemical
composition of produced water should be a routine industry practice
The pros of this measure are:

Properly designed limitations will protect water quality

Pollutant discharge limitations, rather than discharge prohibition, provides operators
with flexibility in managing wastewater

If pollutant discharge limitations allow the operator to discharge near the well site, this
alternative could reduce impacts of transporting HVHF wastewater.
The cons of this measure are:

Development of limitations requires detailed knowledge of wastewater pollutants,
their impacts on receiving streams, and effective treatment. Industry heterogeneity
increases the required information

Development of limitations can be a lengthy (and expensive) process
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
Wastewater treatment generates residuals, such as brines and sludges, that require
further disposal

Implementation of discharge limitations requires industry self-monitoring and active
government approval (permitting), inspection, and recordkeeping.
Any controls introduced in this way would need to conform with existing requirements for
water treatment and discharge.
Effectiveness
Limitations on TDS and other specific pollutants will prevent surface water contamination
from known pollutants. However, a wide range of other constituents are used in fracturing
fluids in low concentrations. The toxicity and environmental effects of many constituents are
not known and also there may be no methods to monitor their presence in wastewater.
Limitations for TDS and other pollutants may not be protective if they do not also control
concentrations of these unidentified fracturing fluid constituents.
Feasibility
Sodium chloride (salt) is the pollutant present in highest concentration in HVHF wastewater.
Depending on the geologic formation, concentrations of total dissolved solids (TDS) average
60,000 to 110,000 mg/L (Acharya 2011 NPR , Hayes 2011 NPR , Mantell 2011 NPR). For
comparison, seawater salinity is approximately 35,000 mg/L. Technologies available to
reduce TDS concentration include reverse osmosis (for TDS <50,000 mg/L) and evaporation
plus crystallization. These technologies are expensive, energy intensive, and generate
treatment residuals (brine and salt crystals) that require disposal. Attention would also need
to be given to the treatment and disposal of water and sludges containing NORM.
Development of limitations requires detailed knowledge of wastewater pollutants, their
impacts on receiving streams, and identification of effective and affordable treatment.
Industry heterogeneity increases the required information. Development of limitations can be
a lengthy (and expensive) process. Enforcement requires active government approval
(permitting), inspection, and recordkeeping.
Recommendation
It is recommended that the introduction of this measure is considered, in view of the potential
effectiveness of this measure in mitigating the impact. It will be important for any controls to
be consistent with existing measures for control of discharges to water, and to be sufficiently
flexible to accommodate the range of circumstances and technical issues likely to be
encountered in practice. This impact was identified as potentially of concern with regard to
cumulative impacts, and consequently it is primarily relevant for the production phase.
5.10.3 Prohibit wastewater discharges
Prohibiting discharges protects surface water and sewage treatment plants while providing
an incentive for wastewater reuse, which will reduce demands on water resources.
Description of measure
The Mining Waste Directive (2006/21/EC) specifies that a permit and waste management
plan are required for any relevant facility. These together ensure that the necessary
measures are in place to prevent environmental impacts due to the waste facility. This would
require avoidance of discharge of untreated or treated effluent, if the effluent posed a
significant environmental hazard. Article 10 of the WFD advises that BAT should be used for
control of discharges to water, or emissions standards should be applied.
The risk of contamination could theoretically also be controlled by prohibiting HVHF
wastewater discharges to surface waters (Kline 2012 NPR , p 23 – 32). Operators would
then need to manage wastewater by other means such as:
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Reuse as fracturing fluid make up

Injection in disposal well (would only be permitted in non-aquifers in Europe)

Other use (e.g., recovery of useful dissolved salts)
The pros of this measure are:

Wastewater reuse will reduce required freshwater and reduce demands on water
resources

Discharge prohibition is more straightforward to implement than pollutant limitations
The cons of this measure are:

Reuse of wastewater may require changes to fracturing fluid chemistry

Prohibition of discharge may require wastewater disposal by alternative means, which
would have associated environmental impacts if wastewater must be hauled longer
distances to disposal facilities

Underground injection requires regulatory management, including control of well
locations and the amount of fluid injected, in order to protect groundwater quality and
prevent induced seismicity. The European Commission's legal interpretation of the
EU environmental framework applicable to HVHF, of December 2011, concluded that
disposal of wastewater through underground injection into geological formations is
prohibited under the Water Framework Directive.

Feasible uses for HVHF wastewater salts have not yet been developed (Silva et al.
2011 NPR , p3)
Effectiveness
Prohibiting discharges protects surface water from impacts of all pollutants present in the
wastewater, those known and measurable as well as pollutants that may be present but not
measureable.
Feasibility
Reuse of fracturing fluid flowback and high salt produced water is dependent on fracturing
chemistry requirements. Some jurisdictions do not allow (or are phasing out) underground
injection (see discussion in Section 4.2.8). If there is a lack of alternative disposal or re-use
options, prevention of discharge of treated HVHF waste waters to surface water could
effectively prevent the development of hydraulic fracturing in Europe.
Recommendation
This measure would go beyond the provisions of the Mining Waste Directive and Water
Framework Directive, and the discussion in Chapter 2 suggests that it is not likely to be
required. It is recommended that implementation of this measure is not pursued.
5.10.4 Leak and spill prevention, detection, and control
US EPA (2011a PR page 29) cites numerous media reports of spills, though robust data on
their frequency is not available. Spill prevention is much more cost-effective and preferable
in principle to clean-up following spillages
Description of measure
Establish requirements to review and approve operator plans for spill incident prevention,
detection, and containment. Such measures may be patterned on oil spill prevention control
and countermeasure requirements. The principles and approaches to managing leak and
spill risks are established generic good practice in the oil and gas industry.
Elements may include [API HF3 2011 NPR , p11]
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


Spill prevention practices
o
Equipment maintenance and corrosion abatement programs
o
Tests and inspections of lines, vessels, valves, and hoses
o
Proper storage of fracturing chemicals
o
Inspection of fracturing chemical containers before and during the fracturing
operation
Spill detection practices
o
Routine visual inspection
o
Tank level indicators
o
Groundwater monitoring
Spill containment practices
o
Sloping the well pad away from surface water
o
Positioning absorbent mats between active sites and surface water
o
Perimeter trenching and catchments
o
Enclosing tanks in secondary containment adequate to hold tank volume
o
Positioning of buffers around potentially sensitive surface water resources
Spill response procedures
o
Notification requirements
o
Clean up kits and practices
The pros of this measure are:

Elements of a spill prevention plan will be familiar to operators who have developed
oil spill prevention and control plans

Spill prevention measures are effective at avoiding impacts which arise from spillage
of potentially hazardous materials.
The cons of this measure are:

Spill prevention measures cannot fully eliminate the risk of spillage

A high standard of management and operation is required, which could not be the
subject of frequent inspection at every site in the event of intensive development.
Effectiveness
Preventing spills is a cost effective means of protecting surface water from HVHF
contamination.
Feasibility
Spill prevention and containment is standard practice for chemical and oil storage.
Recommendation
It is recommended that the introduction of this measure is considered. This impact was
identified as potentially of concern with regard to cumulative impacts, and consequently it is
primarily relevant for the production phase.
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5.10.5 Erosion and run on/run off control
Minimizing the storm water or precipitation that flows across the well site will minimize the
potential to transport contaminants to surface water.
Description of measure
Establish a program to review and approve operator plans for stormwater management and
control. Plan elements may include (API HF3, 2011 NPR , p 13; Polzella 2011 NPR , p 5-6).

Installation of systems to control stormwater coming on to the location (run-on) and
escaping from the location (runoff)

Location of equipment, pads, and impoundments away from natural drainage so
stormwater runoff does not erode base material (which could lead to failure of
impoundments and release of wastewater to local surface waters)

Use erosion control devices, such as


o Straw mulching
o Hydromulch/hydroseeding
o Geotextiles
o Straw erosion blankets
o Terracing, Soil Roughening
o Chemical Stabilization/Soil Binders
o Rock armouring
o Compost filter socks
o Silt fence
o Sediment traps and sediment basins
o Inlet protection
o Hay bale dikes
Inspection of site control devices both on a regular bases and following each
significant storm event, to identify needed repairs to stormwater control systems
Prompt completion of any necessary repairs
The pros of this measure are:

Stormwater management practices are widely known and applied in the oil and gas
exploration and production industry.
The cons of this measure are:

In the event of intensive shale gas development, a formal review program may
overextend the resources of regulatory authorities.
Effectiveness
Preventing run on, run off, and erosion is a cost effective means of protecting surface water
from HVHF contamination.
Feasibility
Stormwater management practices are widely known and applied in the oil and gas
exploration and production industry.
Recommendation
It is recommended that the introduction of this measure is considered, in view of the potential
effectiveness of this measure in mitigating the impact. This impact was identified as
potentially of concern with regard to cumulative impacts, and consequently it is relevant for
the production phase.
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5.11 Groundwater contamination during production
Measures for protection of groundwater contamination during production are similar to those
described in relation to the fracturing and completion stages in Section5.9.
Additionally, it is recommended that consideration is given to adapting the relevant provisions
of the Carbon Capture and Storage directive (2009/31/EC), and the recommendations of the
World Resources Institute (2010 NPR), with regard to hydraulic fracturing fluid remaining in
the shale gas formation, as described in Section 5.2.
5.12 Releases to air during production
Production emission sources include tank vents, pneumatic controllers, and glycol
dehydrators. Emissions of methane, volatile organic compounds and hazardous air
pollutants during production are of most significant concern, together with the potential for
contributing to the formation of low-level ozone.
5.12.1 Monitoring of air quality
A programme of air quality monitoring will not itself prevent pollution, but will be an important
element in identifying any air quality issues which arise, and assisting in identifying and
mitigating the sources of any significant levels of air pollutants. Targeted monitoring focused
on the substances and areas of potential concern with regard to proposed or ongoing
unconventional hydrocarbon extraction will add significant value to established air quality
monitoring programmes.
While it would be difficult to establish the effect of an individual site on air quality, the overall
influence of multiple sites on air quality has become apparent in some areas, and an
appropriate monitoring programme would be able to identify any significant effects on air
quality of extensive shale gas development.
Description
It would be helpful to design and carry out monitoring of air quality throughout the stages of a
shale gas extraction programme:

Prior to exploration, in the vicinity of exploration wells

During exploration, in the vicinity of exploration wells

Prior to production phase, throughout area of planned production focusing in particular on
potentially sensitive areas (e.g. residential areas downwind of intensive production
zones)

During production phase, throughout area of production focusing in particular on
potentially sensitive areas

Following production phase, throughout area of production focusing in particular on
potentially sensitive areas
The monitoring programme would need to have regard to the pollutants of potential concern
and associated indicator substances, including methane, volatile organic compounds, oxides
of nitrogen, particulate matter, and ozone.
Effectiveness
Requirements for air quality monitoring will be effective as part of a wider set of measures, or
a programme of minimisation of emissions to air and ongoing assessment and monitoring of
shale gas extraction installations.
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Feasibility
Air quality monitoring requirements are an established feature of hydrocarbons, mineral
extraction and industrial process operations in Europe at present under the relevant
permitting regimes.
Recommendation
It is recommended that the introduction of this measure is considered as a precautionary
step in the event of intensive development of shale gas installations. Monitoring may need to
be carried out before and during the exploration phases to establish a baseline, and
consequently it is relevant for both the exploration and production phases.
5.12.2 Require vapour recovery units for tank emissions
This measure would result in reduced methane and VOC emissions, with potential benefits
for formation of secondary pollutants such as ozone and visible haze. There are no specific
requirements for such measures in Europe at present.
Description of measure
Install vapour recovery units on produced water and condensate tanks to capture the flash
emissions that occur because of the pressure drop between the separator and atmospheric
storage tanks (Four Corners AQTF p80). The recovered gas can be compressed and sold,
used as fuel gas for equipment at the site, or piped to a stripper unit to separate out natural
gas liquids and methane (US EPA Gas STAR Program VRU; Richards 2011 NPR).
Effectiveness
VRUs can recover 95% of the vapours (US EPA (2012c NPR) Gas STAR Program VRU)
Feasibility

Requires steady source of tank vapours and information on vapour quantity for sizing
(US EPA Gas STAR Program VRU)

Installation depends on availability of a use for the vapours (US EPA Gas STAR
Program VRU; Richards 2011 NPR)

When gas gathering systems operate at a high pressure, VRU requires additional gas
compression
This method may incur additional costs.
Recommendation
It is recommended that the introduction of this measure is proposed, in view of the potential
effectiveness of this measure in mitigating the impact, having regard to potential site-specific
issues relevant to the applicability of this measure. This impact was identified as potentially
of concern with regard to cumulative impacts, and consequently it is relevant for the
production phase.
5.12.3 Require low-bleed or no-bleed pneumatic controllers
Reduced emissions of methane and VOCs
Description of measure
Hydraulically fractured wells are typically located at remote sites that do not have access to a
compressed air supply (“plant air”). As a result, operators typically use natural gas
pneumatic controllers, which can come in “high-bleed,” “low-bleed,” or “no-bleed” options.
US EPA Natural Gas STAR Program defines “high-bleed” as devices that bleed over 0.17 m3
per hour (1500 m3/year) (US EPA Gas Star Pneumatics). The constant bleed of natural gas
Ref: AEA/ED57281/Issue Number 17
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Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
is one of the largest sources of methane emissions from HVHF installations (Four Corners
AQTF p118).
Feasibility

Low-bleed controllers are readily available and commonly used by the natural gas
production industry (Four Corners AQTF p111)

No-bleed controllers are only available in locations that can use plant air or have
electricity (Four Corners AQTF p111)
Effectiveness

EPA reported payback for retrofitting high-bleed to low-bleed units is 5-21 months
(Four Corners AQTF p112)

EPA reported emissions reductions of 1400 - 7400 m3 per year per controller (Four
Corners AQTF p112)

Field testing of low-bleed pneumatic controllers by CETAC-WEST at six sites in
Western Canada resulted in 70% reduction in natural gas consumption (CETACWEST, 2005 NPR)
Recommendation
It is recommended that the introduction of this measure is proposed, in view of the potential
effectiveness of this measure in mitigating the impact, having regard to potential site-specific
issues relevant to the applicability of this measure. This impact was identified as potentially
of concern with regard to cumulative impacts, and consequently it is relevant for the
production phase.
5.12.4 Require desiccant rather than glycol dehydrators
Reduced methane, VOC, and hazardous air pollutant emissions as compared to glycol
dehydrators
Description of measure
Dehydration removes water from the natural gas prior to sale. Some natural gas does not
require dehydration. Desiccant dehydration uses moisture-absorbing salts (e.g., calcium,
potassium, or lithium chlorides) to remove the water. The wet natural gas passes through a
bed of desiccant tablets that remove moisture and form a brine solution. The brine solution
must be drained when required and the bed must be refilled. Operators typically operate two
desiccant dehydrators in parallel so maintenance can be performed on one without shutting
down production. Emissions from desiccant dehydrators may occur when the vessel is
depressurized and re-filled (Four Corners AQTF p85).
Effectiveness

Conventional glycol dehydrators continuously release methane, VOCs, and HAPs.
Some operators found 99% decrease in emissions of these gasses when they
converted to a desiccant dehydrator (Four Corners AQTF p85)

US EPA Natural Gas STAR Program estimated 280 m3/year total emissions from a
desiccant dehydrator compared to 30,000 m3/year total emissions from a glycol
dehydrator with a flow rate of 28,000 m3/day natural gas operating at 31 bar and 8°C
(US EPA Gas Star Desiccant Dehydrator p9)

Additional beneficial impacts: reduced ground contamination because no glycol,
reduced fire hazard, lower maintenance (no moveable parts), no need for external
power (Four Corners AQTF p85)
Ref: AEA/ED57281/Issue Number 17
171
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Feasibility


Desiccant dehydrators work best when operating at higher pressure, lower
temperature, and comparably low flow rates (US EPA Gas Star Zero Emissions
Dehydrators p2):
o
Gas to be dried is 140,000 m3/day or less (Four Corners AQTF p85)
o
Wellhead gas temperature is low (<15°C for calcium chloride and <21°C for
lithium chloride) to avoid forming hydrates that can precipice in the brine
solution and cause problems. If the gas is too hot, it can be cooled or
compressed, but this increases the system cost (Four Corners AQTF p85)
o
Wellhead gas pressure is high (>17 bar for calcium chloride and >7 bar for
lithium chloride) (Four Corners AQTF p85)
Estimated capital cost for one 50 cm vessel with 28,000 m3/day gas flow is
approximately $8,100 with operating costs approximately $4,700/year ; estimated
payback 21 months (US EPA Gas STAR Dehydration 2007 NPR , slides 19, 22). The
global market in gas production equipment indicates that equipment capital costs are
likely to be similar in Europe. Operating costs may differ due to differences in gas
production expertise and methods in Europe compared to the US.
Recommendation
It is recommended that the introduction of this measure is considered, in view of the potential
effectiveness of this measure in mitigating the impact, having regard to potential site-specific
issues relevant to the applicability of this measure. This impact was identified as potentially
of concern with regard to cumulative impacts, and consequently it is relevant for the
production phase.
5.12.5 Require zero emission glycol dehydrators
Reduced methane, VOC, and HAP emissions as compared to standard glycol dehydrators.
Existing glycol dehydrators can be retrofitted with zero emissions technology through
modifications of the gas stream piping, valves, pumps, and controllers, as well as
modification of the fuel used, and/or the dehydrating media. (Natural Gas Star PR O Fact
Sheet No. 206).
Description of measure
Glycol dehydrator technology can be adapted to eliminate emissions by combining emission
reduction technologies into one system. The glycol still vapours include water and
condensable and non-condensable hydrocarbons. In a standard glycol dehydrator these
vapours are directly vented. In a zero emissions dehydrator, the vapours are condensed and
separated. The water is disposed of with other wastewater; the condensable hydrocarbons
are sold as condensate; and the non-condensable hydrocarbons (e.g., methane and ethane)
are used as fuel in the glycol reboiler. The only emissions source for the zero emissions
dehydrator is the glycol reboiler.
Feasibility

Require electric utilities or an engine-generator set

More appropriate than desiccant dehydrators for lower pressure, higher temperature,
and higher flow rates

Can reduce emissions more using an electric glycol circulation pump, but requires
electrical source (Four Corners AQTF p91)

Results in condensate collection, which can be sold (Four Corners AQTF p91)
Ref: AEA/ED57281/Issue Number 17
172
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe

Cost of zero emissions dehydrators are comparable to glycol dehydrators; EPA
estimates 1 year payback (Four Corners AQTF p91). Payback times may be longer
in Europe because of potentially higher purchase and operational costs, particularly in
the early stages of development of the shale gas market.
Effectiveness

HAP destruction efficiency of 98% (Four Corners AQTF p91)

Data from the U.S. Environmental Technology Verification Program (ETV Zero
Emissions Dehydrator p4-5):

o
Average NOX emissions: 65 ppm; 0.037 kg/hr
o
Average CO emissions: 0.6 ppm; 0.00023 kg/hr
o
Average VOC emissions: 0.6 ppm; 0.00014 kg/hr
o
Average emissions of hazardous air pollutants: below detection limit of 0.1
ppm
o
No methane detected
US EPA Natural Gas STAR Program estimated 890,000 m3 annual methane
emissions reduction from zero emission dehydrators compared to conventional glycol
dehydrators (US EPA Gas STAR Zero Emission Dehydrators p1-2)
Recommendation
It is recommended that the introduction of this measure is considered, in view of the potential
effectiveness of this measure in mitigating the impact, having regard to potential site-specific
issues relevant to the applicability of this measure. This impact was identified as potentially
of concern with regard to cumulative impacts, and consequently it is relevant for the
production phase.
5.13 Biodiversity impacts during production
Risks are posed to biodiversity by potential impacts such as surface water pollution and
water resource depletion. These are addressed in the appropriate sections of this chapter
(see Sections 5.4.2, 5.4.5, 5.6.2, 5.7.1and 5.7.4.)
Other than these pollution-related issues, the key issue for biodiversity impacts is the risk
posed by habitat degradation and fragmentation, and introduction of invasive species (New
York State DEC 2011 PR Section 6.4). Habitat fragmentation can be minimised during the
design stage, as described in Section 5.4.
5.13.1 Minimise risks posed by invasive species
Invasive species can present risk of adverse impacts on sensitive habitat sites (Heatley 2011
NPR ; Brittingham 2011 NPR). It is appropriate for operators to take all feasible measures to
reduce the risk of such impacts.
Description of measure
New York State DEC (2011 PR p7-88 to 7-94) sets out a range of measures to minimise the
introduction and spread of invasive species, and to encourage restoration of native
vegetation. These measures would be set out in an agreed site specific invasive species
mitigation plan, and may include the following:

All machinery and equipment to be washed with high pressure hoses and hot water
prior to delivery to the project site;
Ref: AEA/ED57281/Issue Number 17
173
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe

All trucks, machinery and equipment to be checked prior to entry and exit of the
project site;

All fill and/or construction material from offsite locations should be inspected for
invasive species and should only be utilized if no invasive species are found growing
in or adjacent to the fill/material source; and

Only certified weed-free straw should be utilized for erosion control.

Native vegetation should be re-established and weed-free mulch should be used on
bare surfaces to minimize weed germination;

Only native (non-invasive) seeds or plant material should be used for re-vegetation

All seed should be from local sources to the extent possible;

Re-vegetation should occur as quickly as possible at each project site;

Any top soil brought to the site for reclamation activities should be obtained from a
source known to be free of invasive species;

The site should be monitored for new occurrences of invasive plant species following
partial reclamation.

Any new invasive species occurrences found at the project location should be
removed and disposed of appropriately.

Prior to any ground disturbance, any invasive plant species encountered at the site
should be stripped and removed.

Run-off resulting from washing operations should not be allowed to directly enter any
water bodies or wetlands.

Loose plant and soil material that has been removed from clothing, boots and
equipment, or generated from cleaning operations would be destroyed or
appropriately disposed of off-site.

Water should not be transferred from one water body to another.
Effectiveness
Measures such as those set out above are effective in reducing the risk and extent of spread
of invasive species. Close attention and management would need to be paid to ensure that
impacts have been reduced to the maximum extent possible. However, measures such as
these could not fully eliminate the risk of spreading of invasive species. This risk would be
more acute for development of numerous sites in a sensitive habitat area.
Feasibility
Measures to reduce the spread of invasive species are established for use in the US in
relation to unconventional gas extraction, and in Europe for a wide range of developments.
Recommendation
It is recommended that the introduction of controls on invasive species via a site-specific
mitigation plan should be considered. This impact was identified as potentially of concern
with regard to cumulative impacts, and consequently it is primarily relevant for the production
phase.
5.14 Lower priority impacts
The impacts identified as being of moderate significance are listed in Section 2.10.
Ref: AEA/ED57281/Issue Number 17
174
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Similar impacts to all these “moderate” significance issues are addressed in the sections
above, in relation to different stages of the gas exploration and production process, and/or in
relation to cumulative effects in some cases where the effects of individual installations are
considered to be of moderate significance. The recommendations in the discussion set out
above addresses all the issues identified as being of “medium” significance, in addition to the
“high” and “very high” significance issues.
5.15 Summary table
Table 11 below provides a summary of the identified measures, and highlights measures
which would bring synergistic effects in addressing multiple potential impacts. The table
highlights that a wide range of measures would potentially have a beneficial impact on
protection of biodiversity.
Measures which envisage the construction of additional pipework infrastructure to transfer
water to and from shale gas extraction sites bring a potential negative impact on biodiversity
and land take associated with the additional pipeline infrastructure. Hence, the use of
alternative means of transportation of water could result in beneficial effects on biodiversity
due to reduced traffic impacts, but also adverse effects due to the construction of new
pipelines.
5.16 Recommendations for further consideration and
research
It is recommended that consideration is given to research recommendations made by SEAB
(2011a NPR) which would be relevant to hydraulic fracturing in Europe:

The use of micro-seismic monitoring in relation to hydraulic fracturing

Determination of the chemical interactions between fracturing fluids and different
shale rocks

Induced seismicity triggered by hydraulic fracturing

Development of less environmentally hazardous drilling and fracturing fluids

Development of improved casing and cementing methods.
It is recommended that a readily accessible database on hydraulic fracturing fluid
composition is developed for European high volume hydraulic fracturing projects (developing
a recommendation presented to the European Parliament, Lechtenböhmer et al., 2011 NPR
p61). To be valuable, completion of the database would need to be a requirement for all high
volume hydraulic fracturing activities, and it should be fully searchable by geographic location
and by chemical species/additive name. This would be useful for regulators and would also
be of interest to researchers and local communities.
The SEAB (2011a NPR p20) recommends that research should be carried out into the risks
and causes of methane migration into groundwater from shale gas extraction. This was
supported by an academic consultee, who also recommended research into the potential
health effects of chronic exposure to methane via ingestion (Academic sector consultation
response 2012 NPR).
Further consideration and research pertain to the long-term fate of hydraulic fracturing fluid
remaining in the shale gas formation during the production and post-closure phases, for
instance in relation to provisions of the Carbon Capture and Storage Directive (2009/31/EC).
Based on the discussion of potential impacts of high volume hydraulic fracturing in Chapter
2, further research is recommended into the potential for increased risk of methane migration
to groundwater with air drilling compared to drilling using liquid muds. It is recommended
Ref: AEA/ED57281/Issue Number 17
175
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
that further research is carried out into well cementing methods and practices for HVHF. It is
recommended that further research is carried out into the risks which could not be classified
based on the available information:

Potential impacts on biodiversity due to cumulative development in the European
context

Frequency of surface spillages during hydraulic fracturing

Potential frequency and significance of road accidents involving trucks carrying
hazardous substances in support of HVHF operations

Noise impacts due to flaring, and associated controls

Risks of groundwater contamination following abandonment

Land take following abandonment

Risks to biodiversity following abandonment
It is recommended that further research is carried out to improve the viability of techniques
for recycling of wastewater, to ensure that wastewater recycling can be applied in Europe,
and to enable a higher proportion of wastewater to be recycled in this way.
The Pennsylvania Governor’s Marcellus Shale Advisory Commission recommended the
development of voluntary ecological initiatives within critical habitats that would generate
mitigation credits which are eligible for use to offset future development. It is recommended
that the applicability of similar initiatives in Europe should be investigated.
Ref: AEA/ED57281/Issue Number 17
176
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Table 11: Summary of identified measures
Land take
during site
preparation
Measure
Releases
to air
during
drilling
Noise
during
drilling
Water
resource
depletion
during
fracturing
Releases to
air during
fracturing
and
completion
Traffic
during
fracturing
Groundwater
contamination
during fracturing,
completion and
production
Surface water
contamination
during
fracturing and
completion
Releases
to air
during
production
Biodiversity
impacts
during
production
5.3.1
Maximize required spacing between wells (Install
multiple wells/pad)
M
+
+
+
5.3.2
Require Environmental Site Assessment for Optimal
Site Selection
M
+
+
+
5.3.3
Limit the use of impoundments
M
5.3.4
Use temporary surface pipes to transport water to the
well pad
M
5.3.5
Ensure land disturbed during well construction and
development is reclaimed
M
5.3.6
Restrict hydraulic fracturing and well pad installation
from sensitive areas
M
5.4.1
Require natural gas-fired, or electric-grid drilling rig
engines
M
5.4.2
Require emission controls on lean burn and rich burn
drilling rig engines
M
5.5.1
Specification of maximum noise levels at sensitive
locations
M
+
5.5.2
Separation between drilling operation and sensitive
location
M
+
5.5.3
5.5.4
5.6.1
5.6.2
Management methods to reduce noise impacts
Screening of noise-generating equipment
Regional water resource management
Reuse wastewater
M
M
+
+
5.6.3
Use lower quality water (seawater, brackish water) for
fracturing fluid make up
M
5.6.4
5.6.5
Manage water abstraction
Use alternative water resources
M
M
5.7.1
Require reduced emission completions to eliminate
natural gas venting during fracturing from flowback
M
5.7.2
Require flares or incinerators to control emissions
from fracturing wastewater storage tank vents
M
Ref: AEA/ED57281/Issue Number 17
+
+
+
+/+
+
+
+
+
+
M
M
+
177
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Land take
during site
preparation
Measure
5.8.1
5.8.2
5.8.3
5.8.4
5.8.5
5.9.1
Site selection and design
Using alternatives to road transportation
Development of transportation plan
Measures to minimise vehicle emissions
Road maintenance
Monitoring of groundwater quality
5.9.2
Appropriate standard and quality assurance of well
casing
5.9.3
5.9.4
5.9.5
5.10.1
Surface impoundment construction standards
Leak and spill prevention, detection, and control
Monitoring and control of fracturing process
Monitoring of surface water quality
5.10.2
Limit pollutant concentrations in wastewater
discharges
5.10.3
5.10.4
5.10.5
5.12.1
5.12.2
5.12.3
5.12.4
5.12.5
5.13.1
Prohibit wastewater discharges (not recommended)
Leak and spill prevention, detection, and control
Erosion and run on/run off control
Monitoring of air quality
Require vapour recovery units for tank emissions
Require low-bleed or no-bleed pneumatic controllers
Require desiccant rather than glycol dehydrators
Require zero emission glycol dehydrators
Minimise risks posed by invasive species
Key
Releases
to air
during
drilling
Noise
during
drilling
+
Water
resource
depletion
during
fracturing
Releases to
air during
fracturing
and
completion
+
+
+
Groundwater
contamination
during fracturing,
completion and
production
Surface water
contamination
during
fracturing and
completion
Releases
to air
during
production
M
M
M
M
M
Biodiversity
impacts
during
production
+
+/-
M
M
+
+
M
M
M
+
+
+
M
+
+
+
M
+
+
M
M
+
+
M
M
M
M
M
M
M: Main reason for proposal of measure
+: Potential synergistic effect
-: Potential counter-productive effect
+ / -: Potential for both synergistic and counter-productive effects
Ref: AEA/ED57281/Issue Number 17
Traffic
during
fracturing
178
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
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hydrocarbons operations involving hydraulic fracturing in Europe
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hydrocarbons operations involving hydraulic fracturing in Europe
Appendices
Appendix 1: Glossary and Abbreviations
Appendix 2: Types of artificial stimulation treatments
Appendix 3: Hydraulic fracturing additives used in high volume hydraulic fracturing in the UK,
2011
Appendix 4: Hydrocarbon extraction in Europe
Appendix 5: Shale gas exploration in Europe and worldwide
Appendix 6: Matrix of potential impacts
Appendix 7: Evaluation of potential risk management measures
Appendix 8: List of relevant ISO standards applicable in the hydrocarbons industry
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Appendix 1: Glossary and Abbreviations
Glossary adapted in part from New York DEC (2011 PR). The majority of terms in this
glossary are referred to in the report. Some additional terms are included to assist in wider
discussion of unconventional gas operations.
Abandonment: To permanently close a well, usually after determining that there is insufficient
hydrocarbon potential to complete the well, or after production operations have drained the
reservoir. An abandoned well is plugged with cement to prevent the escape of methane to
the surface or nearby aquifers
Annular Space or Annulus: Space between casing and the wellbore, or between the tubing
and casing or wellbore, or between two strings of casing.
Anticline: A fold with strata sloping downward on both sides from a common crest.
Aquifer: A zone of permeable, water saturated rock material below the surface of the earth
capable of producing significant quantities of water.
Bactericides: Also known as a "Biocide." An additive that kills bacteria.
Barrel: A volumetric unit of measurement equivalent to 42 U.S. gallons or 0.159 m3
bbl/yr: Barrels per year.
bbl: Barrel.
Bcf: Billion cubic feet. A unit of measurement for large volumes of gas. 1 bcf is equivalent to
28.3 million cubic metres
BCOGC: British Columbia Oil and Gas Commission.
Best Management Practice: Current state-of-the-art mitigation measures applied to oil and
natural gas drilling and production to help ensure that development is conducted in an
environmentally responsible manner
Biocides: See "Bactericides".
Black shale: shale that was laid down in especially anoxic conditions on the floors of
stagnant seas and is rich in organic compounds derived from bacterial, plant and animal
matter.
BLM: United States Federal Bureau of Land Management
Blowout: An uncontrolled flow of gas, oil or water from a well, during drilling when high
formation pressure is encountered.
BMP: Best Management Practice
Breaker: A chemical used to reduce the viscosity of a fluid (break it down) after the thickened
fluid has finished the job it was designed for.
Brine: Water displaced from the geological formation which contains elevated levels of
dissolved solids;
Buffer agent: A weak acid or base used to maintain the pH of a solution at or close to a
chosen value.
CAS Number: Chemicals Abstract Service number, assigned by Chemical Abstracts Service.
Casing: Steel pipe placed in a well.
CBM: Coal bed methane
CFR: Code of Federal Regulations.
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Chemical Additive: A product composed of one or more chemical constituents that is added
to a primary carrier fluid to modify its properties in order to form hydraulic fracturing fluid.
Chemical Constituent: A discrete chemical with its own specific name or identity, such as a
CAS Number, which is contained within an additive product.
Coal-bed methane: natural gas trapped in coal seams that can be extracted by similar
methods to those used for shale gas. The term refers to methane adsorbed onto the solid
matrix of the coal. (Coal bed methane requires less fracturing fluid and so extraction of this
gas falls outside the definition of “high volume hydraulic fracturing”)
Completion: the activities and methods of preparing a well for production after it has been
drilled to the objective formation. This principally involves preparing the well to the required
specifications; running in production tubing and its associated down hole tools, as well as
perforating and stimulating the well by the use of hydraulic fracturing, as required.
Compressor: A facility which increases the pressure of natural gas to move it in pipelines or
into storage.
Condensate: Liquid hydrocarbons that were originally in the reservoir gas and are recovered
by surface separation.
Conventional reservoir: a high permeability (greater than 1 milliDarcy) formation, usually
sandstone, containing oil and/or gas, which can be more readily extracted than hydrocarbons
from unconventional reservoirs.
Corrosion Inhibitor: A chemical substance that minimizes or prevents corrosion in metal
equipment.
Crosslinker: A compound, typically a metallic salt, mixed with a base-gel fluid, such as a
guar-gel system, to create a viscous gel used in some stimulation or pipeline cleaning
treatments. The crosslinker reacts with the multiplestrand polymer to couple the molecules,
creating a fluid of high viscosity.
Darcy: A unit of permeability. A medium with a permeability of 1 darcy permits a flow of 1
cm³/s of a fluid with viscosity 1 cP (1 mPa·s) under a pressure gradient of 1 atm/cm acting
across an area of 1 cm2.
DEC: New York State Department of Environmental Conservation.
Directional drilling: Deviation of the borehole from vertical so that the borehole penetrates a
productive formation in a manner parallel to the formation, although not necessarily
horizontally.
Disposal Well: A well into which waste fluids can be injected deep underground for safe
disposal.
Drilling Fluid: Mud, water, or air pumped down the drill string which acts as a lubricant for the
bit and is used to carry rock cuttings back up the wellbore. It is also used for pressure
control in the wellbore.
Economically recoverable reserves: technically recoverable petroleum for which the costs of
discovery, development, production, and transport, including a return to capital, can be
recovered at a given market price.
Ecosystem: The system composed of interacting organisms and their environments.
EIS: Environmental Impact Statement.
EPA: The (U.S.) Environmental Protection Agency.
Fault: A fracture or fracture zone along which there has been displacement of the sides
relative to each other.
Field: The general area underlain by one or more pools.
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Flare: The burning of unwanted gas through a pipe.
Flashing: evaporation of volatile substances due to a reduction in pressure
Flowback Fluids: fluid returned to the surface after hydraulic fracturing has occurred, but
before the well is placed into production. It typically consists of returned fracturing fluids in
the first few days following hydraulic fracturing which are progressively replaced by produced
water.
Fold: A bend in rock strata.
Footwall: The mass of rock beneath a fault plane.
Formation: A rock body distinguishable from other rock bodies and useful for mapping or
description. Formations may be combined into groups or subdivided into members.
Fossil methane / fossil fuel: A natural fuel such as coal or gas, formed in the geological past
from the remains of living organisms.
Fracking or Fracing (pronounced “fracking”): informal abbreviation for "Hydraulic Fracturing".
Friction Reducer/Friction Reducing Agent: A chemical additive which alters the hydraulic
fracturing fluid allowing it to be pumped into the target formation at a higher rate & reduced
pressure.
GEIS: Generic Environmental Impact Statement.
Gelling Agents: Polymers used to thicken fluid so that it can carry a significant amount of
proppants into the formation.
Geothermal Well: A well drilled to explore for or produce heat from the subsurface.
gpd: Gallons per day.
gpm: Gallons per minute.
Green Completion: see Reduced Emissions Completion
Groundwater: Water in the subsurface below the water table. Groundwater is held in the
pores of rocks, and can be connate (that is, trapped in the rocks at the time of formation),
from meteorological sources, or associated with igneous intrusions.
HAPS: Hazardous Air Pollutants as defined under the Clean Air Act (see
http://www.epa.gov/ttn/atw/188polls.html)
High Volume Hydraulic Fracturing: The stimulation of a well (normally a shale gas well using
horizontal drilling techniques with multiple fracturing stages) with high volumes of fracturing
fluid. Defined as fracturing using 1,000 m3 or more of water per stage as the base fluid in
fracturing fluid.
Horizontal Drilling: Deviation of the borehole from vertical so that the borehole penetrates a
productive formation with horizontally aligned strata, and runs approximately horizontally.
Horizontal Leg: The part of the wellbore that deviates significantly from the vertical; it may or
may not be perfectly parallel with formational layering.
Hydraulic Fracturing Fluid: Fluid used to perform hydraulic fracturing; includes the primary
carrier fluid, proppant material, and all applicable additives.
Hydraulic Fracturing: The act of pumping hydraulic fracturing fluid into a formation to
increase its permeability. Hydraulic fracturing is understood within the scope of this study as
the full lifecycle of operations, from the upstream acquisition of water, to chemical mixing of
the fracturing fluid, injection of the fluid into the formation, the production and management of
flowback and produced water, and the ultimate treatment and disposal of hydraulic fracturing
wastewater.
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Iron Inhibitors: Chemicals used to bind the metal ions and prevent a number of different
types of problems that iron can cause (for example, scaling problems in pipe).
Limestone: A sedimentary rock consisting chiefly of calcium carbonate (CaCO3).
Make-up water: water in which proppant and chemical additives are mixed to make fracturing
fluids for use in hydraulic fracturing
Mcf: Thousand cubic feet (equivalent to 28.3 cubic metres).
md: Millidarcy.
Millidarcy: A unit of permeability, equivalent to one thousandth of a Darcy
MMcf: Million cubic feet (equivalent to 28,300 cubic metres).
NORM: Naturally Occurring Radioactive Materials. Low-level radioactivity that can exist
naturally in native materials, like some shales and may be present in drill cuttings and other
wastes from a well.
Operator: Any person or organization in charge of the development of a lease or drilling and
operation of a producing well.
Perforate: To make holes through the casing to allow the oil or gas to flow into the well or to
squeeze cement behind the casing.
Perforation: A hole created in the casing to achieve efficient communication between the
reservoir and the wellbore.
Permeability: A measure of a material’s ability to allow passage of gas or liquid through
pores, fractures, or other openings. The unit of measurement is the Darcy or millidarcy.
Polymer: Chemical compound of unusually high molecular weight composed of numerous
repeated, linked molecular units.
Pool: An underground reservoir containing a common accumulation of oil and/or gas. Each
zone of a structure which is completely separated from any other zone in the same structure
is a pool.
Porosity: Volume of pore space expressed as a percent of the total bulk volume of the rock.
Primary Carrier Fluid: The base fluid, such as water, into which additives are mixed to form
the hydraulic fracturing fluid which transports proppant.
Primary Production: Production of a reservoir by natural energy in the reservoir.
Product: A hydraulic fracturing fluid additive that is manufactured using precise amounts of
specific chemical constituents and is assigned a commercial name under which the
substance is sold or utilized.
Production Casing: Casing set above or through the producing zone through which the well
produces.
Produced water: fluids displaced from the geological formation, which can contain
substances that are found in the formation, and may include dissolved solids (e.g. salt),
gases (e.g. methane, ethane), trace metals, naturally occurring radioactive elements (e.g.
radium, uranium), and organic compounds,
Proppant or Propping Agent: A granular substance (sand grains, aluminium pellets, or other
material) that is carried in suspension by the fracturing fluid and that serves to keep the
cracks open when fracturing fluid is withdrawn after a fracture treatment.
Proved reserves: The quantity of energy sources estimated with reasonable certainty, from
the analysis of geologic and engineering data, to be recoverable from well-established or
known reservoirs with the existing equipment and under the existing operating conditions
REC: Reduced Emissions Completion.
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hydrocarbons operations involving hydraulic fracturing in Europe
Reduced Emissions Completion (also known as green completion): a term used to describe
a practice that captures gas produced during well completions and well workovers following
hydraulic fracturing. Portable equipment is brought on site to separate the gas from the
solids and liquids produced during the high-rate flowback, and produce gas that can be
delivered into the sales pipeline. RECs help to reduce methane, VOC, and HAP emissions
during well cleanup and can eliminate or significantly reduce the need for flaring.
Reservoir (oil or gas): A subsurface, porous, permeable or naturally fractured rock body in
which oil or gas has accumulated. A gas reservoir consists only of gas plus fresh water that
condenses from the flow stream reservoir. In a gas condensate reservoir, the hydrocarbons
may exist as a gas, but, when brought to the surface, some of the heavier hydrocarbons
condense and become a liquid.
Reservoir Rock: A rock that may contain oil or gas in appreciable quantity and through which
petroleum may migrate.
Sandstone: A variously coloured sedimentary rock composed chiefly of sandlike quartz
grains cemented by lime, silica or other materials.
Scale Inhibitor: A chemical substance which prevents the accumulation of a mineral deposit
(for example, calcium carbonate) that precipitates out of water and adheres to the inside of
pipes, heaters, and other equipment.
Sedimentary rock: A rock formed from sediment transported from its source and deposited in
water or by precipitation from solution or from secretions of organisms.
SEIS: Supplemental Environmental Impact Statement.
Seismic: Related to earth vibrations produced naturally or artificially.
SGEIS: Supplemental Generic Environmental Impact Statement.
Shale oil: Oil shale, also known as kerogen shale, is an organic-rich fine-grained sedimentary
rock containing kerogen (a solid mixture of organic chemical compounds) from which liquid
hydrocarbons called shale oil can be produced. Crude oil which occurs naturally in shales is
referred to as “tight oil”.
Shale: A sedimentary rock consisting of thinly laminated claystone, siltstone or mud stone.
Shale is formed from deposits of mud, silt, clay, and organic matter laid down in calm seas or
lakes.
Shale gas: natural gas that remains tightly trapped in shale and consists chiefly of methane,
but with ethane, propane, butane and other organic compounds mixed in. It forms when
black shale has been subjected to heat and pressure over millions of years, usually at depths
of 1,500 to 4,500 metres
Show: Small quantity of oil or gas, not enough for commercial production.
Siltstone: Rock in which the constituent particles are predominantly silt size.
Slickwater Fracturing (or slick-water): A type of hydraulic fracturing which utilizes waterbased fracturing fluid mixed with a friction reducing agent and other chemical additives.
Spudding: The breaking of the earth’s surface in the initial stage of drilling a well.
Squeeze: Technique where cement is forced under pressure into the annular space between
casing and the wellbore, between two strings of pipe, or into the casing-hole annulus.
Stage Plug: A device used to mechanically isolate a specific interval of the wellbore and the
formation for the purpose of maintaining sufficient fracturing pressure.
Stage: Isolation of a specific interval of the wellbore and the associated interval of the
formation for the purpose of maintaining sufficient fracturing pressure.
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Stimulation: The act of increasing a well’s productivity by artificial means such as hydraulic
fracturing or acidizing.
Stratum (plural strata): Sedimentary rock layer, typically referred to as a formation, member,
or bed.
Surface Casing: Casing extending from the surface through the potable fresh water zone.
Surfactants: Chemical additives that reduce surface tension; or a surface active substance.
Detergent added to hydraulic fracturing fluid is a surfactant.
Target Formation: The reservoir that the driller is trying to reach when drilling the well.
Tcf: Trillion cubic feet, equivalent to 28.3 billion cubic metres
Technically recoverable reserves: The proportion of assessed in-place petroleum that may
be recoverable using current recovery technology, without regard to cost.
Tight Formation: Formation with very low (less than 1 milliDarcy) permeability.
Tight gas: natural gas held in sandstone reservoirs that are unusually impermeable; it can be
extracted by fracturing the rock (tight gas is typically extracted using vertical wells which
require less fracturing fluid and so extraction of this gas falls outside the definition of “high
volume hydraulic fracturing”).
tpy: Tonnes per year
Unconventional gas: Gas contained in rocks (which may or may not contain natural fractures)
which exhibit in-situ gas permeability of less than 1 millidarcy.
USDW - Underground Source of Drinking Water: An aquifer or portion of an aquifer that
supplies any public water system or that contains a sufficient quantity of ground water to
supply a public water system, and currently supplies drinking water for human consumption,
or that contains fewer than 10,000 mg/L total dissolved solids and is not an exempted
aquifer.
USEPA: United States Environmental Protection Agency.
USGS: United States Geological Survey.
Viscosity: A measure of the degree to which a fluid resists flow under an applied force.
VOC: Volatile Organic Compound.
Wastewaters: term used to designate collectively returned fracturing fluids and produced
water which are sent for disposal or treatment and re-use.
Water Well: Any residential well used to supply potable water.
Watershed: The region drained by, or contributing water to, a stream, lake, or other body of
water.
Well pad: A site constructed, prepared, levelled and/or cleared in order to perform the
activities and stage the equipment and other infrastructure necessary to drill one or more
natural gas exploratory or production wells.
Well site: Includes the well pad and access roads, equipment storage and staging areas,
vehicle turnarounds, and any other areas directly or indirectly impacted by activities involving
a well.
Wellbore: A borehole; the hole drilled by the bit. A wellbore may have casing in it or it may
be open (uncased); or part of it may be cased, and part of it may be open.
Wellhead: The equipment installed at the surface of the wellbore. A wellhead includes such
equipment as the casinghead and tubing head.
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Workover: Repair operations on a producing well to restore or increase production. This may
involve repeat hydraulic fracturing to re-stimulate gas flow from the well
Zone: A rock stratum of different character or fluid content from other strata.
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hydrocarbons operations involving hydraulic fracturing in Europe
Appendix 2: Types of artificial stimulation
treatments
High volume hydraulic fracturing (known also as “slickwater” fracturing)
In the late 1990s, operators developed a technology known as “slickwater fracturing” to
develop shale formations, primarily by increasing the amount and proportion of water used,
reducing the use of gelling agents and adding friction reducers (New York State DEC 2011
PR p5-39). The additives typically used in hydraulic fracturing fluids are of the following
types (King, 2012 PR):

Scale inhibitor

Acid (usually hydrochloric acid)

Biocide

Friction reducer, typically polyacrylamide.
Multi-stage horizontal drilling techniques were developed, which enabled shale gas
reservoirs to be developed in a more cost-effective way. The quantity of fracturing fluid used
in these treatments is more than 1,000 m3 of water per stage.
The following sections describe other hydraulic fracturing treatments for reference.
Acidising
Acid treatments are used to dissolve carbonate materials in the reservoir host rock and to
widen a flow path, either natural or artificially created. Acid is also used to clean up scale
build-up, rust and cement that may occur from the drilling or production of the well. Acidising
can be carried out as a fracture treatment, as a pre-treatment prior to a fracture and/or as
general maintenance to clean up a well. Acidising may use the chemical action of the acid
alone (described as “matrix fracturing”), or the acid may act under pressure to physically
fracture the rock matrix.
Water gel hydraulic fracturing
Hydraulic fracturing has been carried out on conventional oil and gas wells using a mixture of
diesel fuel or water, together with sand and chemical additives since the 1940s (New York
State DEC 2011 PR p6-289). Typically, these processes involved the use of 90 to 360 m3 of
water per well, and are now used mainly for shale oil and tight sands. These higher viscosity
fluids use gellants or thickeners to create viscous gelled fluids with a high carrying capacity.
Gellant selection is based on formation characteristics such as pressure, temperature,
permeability, porosity, and zone thickness, with guar gum a widely used additive in current
operations. Linear and cross-linked gels are available: borate additives are used to create
the cross-linkages. Breaker additives are mixed in with the fluid which break these linkages
after hydraulic fracturing to reduce viscosity and facilitate the return of fluid to the surface.
Propane gel
The use of propane gel as a hydraulic fracturing fluid has been trialled at over 1,000 sites in
North America. The gel is typically made up of 90% propane and a phosphoric acid diester
gelling agent together with proppant and other additives. After the fracturing stage, the gel is
broken, and propane is returned to the surface as a gas. Consequently, the fluid additives
tend to remain in the formation rather than being returned to the surface. This approach
removes the need to dispose of water-based fracturing fluids, and the propane can be
collected and transferred to production pipeline or flared.
Little data on the application of this technology has been made publicly available. The initial
costs can be 20-40% more than water-based fracking, but this could potentially be offset by
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increased gas production efficiency and reduced costs associated with the disposal of water
(Royal Society of Chemistry, 2011).
Foamed gels
Nitrogen or carbon dioxide gas is blended with fluid to create a foam (approximately 70-75%
nitrogen or carbon dioxide) to transport and place proppant into fractures (EPA 2004 NPR
p4-5). Nitrogen fracture operations require higher surface pressures due to the lower
hydrostatic weight of the foam, but use much less water (only 25-30% of injected fluid) to
fracture the rock and then pump in the foam/sand mixture. Operators have successfully
used nitrogen foam fractures in the UK in CBM reservoirs, to improve proppant-carrying
capabilities and to minimize the amount of liquid placed in the formation which improves the
clean-up and flow back (UK Department for Energy and Climate Change, 2012 NPR). It is
unlikely that this technique could be used for shale gas, because of the viscosity of the fluid.
High Rate Nitrogen
High Rate Nitrogen involves the pumping of nitrogen gas into a formation at high rates and
pressures. High Rate Nitrogen treatments are used for shallow applications, typically
coalbed methane (CBM) where reservoir pressures may be low and the flowback of fracture
fluids may be difficult. The purpose of this treatment is to open cleats or natural fractures in
the coal and to remove damage in order for natural gas to be able to flow more easily into the
well.
Occasionally a proppant is added to the nitrogen. The amounts added are typically much
lower than used in liquid treatments (CSUR, 2012 NPR). No further additives are added
during the fracturing process. During the flowback period, the nitrogen is vented to the
atmosphere while any produced water encountered is captured in on site tank storage for
later disposal.
Thermal fracturing
Water injection wells for enhanced oil recovery are commonly hydraulically fractured by a
combination of pressure and temperature. Typically, seawater at ambient temperature or
produced water at around 50oC is injected into warmer rocks in the subsurface, resulting in
cracking of the buried rocks when they are flushed with the colder water.
Liquid carbon dioxide
Liquid carbon dioxide fracture treatments involve pumping liquid carbon dioxide into the
formation without any added chemicals. Most liquid carbon dioxide fracture treatments are
carried out for research and development on a well, because this method is considered to
have a low risk of damaging the formation.
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Appendix 3: Hydraulic fracturing additives
used in high volume hydraulic fracturing in the
UK, 2011
Hydraulic fracturing additives used in the UK (see table below)
Data for Preese Hall-1 well, obtained from
http://www.cuadrillaresources.com/what-we-do/hydraulic-fracturing/fracturing-fluid/
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Appendix 4: Hydrocarbon extraction in Europe
Hydrocarbon extraction has taken place in Europe since the 19th century. The industry
developed rapidly in the 1960s following the discovery of oil and gas in the southern North
Sea, and in the 1980s following the discovery of reserves in the northern North Sea and
Russia. The industry focused mainly on “conventional” reserves – that is, oil and gas from
high permeability formations, which could be more readily extracted.
Proven gas reserves in the Europe Union have started to decline since around 2002 (see
Figures A4.1a and A4.1b).
Figure A4.1a: Worldwide proven natural gas reserves 1980 – 2010
200
Proven natural gas reserves (trillion cubic metres)
Asia Pacific
180
Africa
Middle East
160
140
S. & Cent. America
North America
Other Europe & Eurasia
European Union
120
100
80
60
40
20
0
(Source: Data taken from BP (2011 NPR))
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Figure A4.1b: European Union proven natural gas reserves 1980 - 2010
Proven natural gas reserves (trillion cubic metres)
6
5
4
3
2
1
0
(Source: Data taken from BP (2011 NPR))
This change coincided with the development and application of techniques in the United
States for extraction of gas from reserves which were previously uneconomic or impractical.
In this context, gas producers in Europe have begun to investigate unconventional oil and
gas resources. In Europe, preliminary indications are that these resources comprise
extensive shale gas reserves, although this will not be confirmed until further exploratory
drilling has been carried out. Preliminary estimates of shale gas reserves in Europe are
summarised in Table A4.1.
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Table A4.1. Estimated shale gas recoverable resources for select basins in Europe
(1)
2009 Natural Gas Market (trillion cubic
metres, dry basis)
State
Production Consumption
Imports
(exports)
Proved Natural
(2)
Gas Reserves
(trillion cubic
metres)
Technically
Recoverable Shale
Gas Resources
(trillion cubic
metres)
France
0.00085
0.049
98%
0.006
5.10
Germany
0.0144
0.093
84%
0.18
0.23
Netherlands
0.0790
0.049
(62%)
1.39
0.48
Norway
0.103
0.0045
(2156%)
2.04
2.4
U.K.
0.059
0.088
33%
0.255
0.57
Denmark
0.0085
0.0045
(91%)
0.059
0.65
Sweden
-
0.0011
100%
Poland
0.0059
0.016
64%
0.164
5.30
Turkey
0.00085
0.035
98%
0.006
0.42
Ukraine
0.020
0.044
54%
1.10
1.19
Lithuania
-
0.0028
100%
0.014
0.027
50%
0.305
0.365
Others
(2)
Total
(1)
Dry production and consumption (EIA, 2011 NPR).
(2)
Romania, Hungary, Bulgaria.
1.16
0.113
0.077
0.54
5.27
13.0
Coal bed methane
Coal bed methane (CBM) is present in varying quantities in all coal measures. As in shale
gas formations, the natural gas is trapped with the strata, in this case within the coal itself,
with only 5-9% present as free gas. Because relatively low volumes of fluid are required for
extraction of CBM, this lies outside the scope of this project (see Section 1.3.3).
Estimated global coal-bed methane reserves are summarised in Table A4.2 (IFP, 2007
NPR). This indicates that in the European context, coal-bed methane could also comprise a
significant proportion of unconventional gas resources. However, there is at present no
significant forecast expansion in extraction of CBM in Europe.
Table A4.2: Estimated world CBM reserves
Area
Estimated recoverable
reserves (Tm3) Low end
Estimated recoverable
reserves (Tm3) High end
Asia
18.3
95.1
North America
26.9
124.1
South America
0.4
0.9
113.3
456.3
4.6
7.6
Commonwealth of
Independent States5
Europe other than CIS
5
Armenia, Azerbaijan, Belarus, Kazakhstan, Kyrgyzstan, Moldova, Russia, Tajikistan, Turkmenistan, Ukraine,
Uzbekistan
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Africa
0.8
1.6
World
164.2
685.7
Tight gas
“Tight gas” refers to gas which is produced from a very low permeability and porosity
reservoir rock with a permeability of less than 1 milliDarcy (Veeken et al., 2007 NPR).
Hydrocarbon production from tight reservoirs can be difficult without stimulation operations.
The term is generally used for reservoirs other than shales.
Tight gas is typically at depths greater than 3,500 metres below the surface (BP, 2012c
NPR). In a conventional sandstone the pores are interconnected so gas is able to flow easily
from the rock. In tight sandstones there are smaller pores, which are poorly connected by
very narrow capillaries, resulting in very low permeability (see Figure 2).
Figure 6: Microscopic sandstone sections
Conventional sandstone (left) has well- connected pores (dark blue). The pores of tight gas sandstone (right) are irregularly
distributed and poorly connected by very narrow capillaries (NETL, 2011b NPR).
Tight gas is currently being produced in Europe, most notably in Germany (Europe
Unconventional Gas website accessed 2012 NPR). Data published by the German
regulators LBEG and BRG do not distinguish between tight gas extraction and conventional
natural gas extraction, and so it has not been possible to quantify the quantities of tight gas
produced in Europe. Because relatively low volumes of fluid are required for extraction of
tight gas, this lies outside the scope of this project (see Section1.3.3).
Unconventional gas production in Europe
Having searched the documents assembled for this project and carried out a search of
scientific literature via www.sciencedirect.com as well as a more general internet search, no
specific figures could be identified for unconventional gas production in Europe. Indications
from regulators or industry indicates that some hydraulic fracturing (though not high volume
hydraulic fracturing) has been carried out on a total of approximately 800 conventional and
unconventional wells in Europe. This compares to approximately 400,000 producing gas
wells in the US (no figures are available for the number of wells in Europe). Currently, CBM
and tight gas make an insignificant contribution to EU natural gas production and
consumption with some potential for an increased contribution in future years (BP, 2011 NPR
; BGR, 2009 NPR).
Table A4.3 provides a preliminary evaluation of shale gas formations in Europe
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Table A4.3: Preliminary summary of European shale gas plays
Region
Basin
Formation
Poland
Baltic Basin
Lublin Basin
Podlasie Depression
Silurian Shales
Silurian Shales
Silurian Shales
Sub-total
Other
Eastern
Europe
Baltic Basin
Lithuania, Latvia,
Estonia
Dnieper-Donets Basin
Ukraine
Lublin Basin
Ukraine
PannonianTransylvanian Basin
Slovenia, Hungary,
Slovakia and Romania
14.6
6.3
1.6
22.4
3.7
1.2
0.4
5.3
2.6
0.7
1.4
0.3
4.2
0.8
Silurian Shales
Silurian Shales
Silurian Shales
"Neogene age"
Not assessed
Carpathian-Balkanian
Basin
Romania and Bulgaria
Jurassic
Dogger Balls /
Lias Etropole
formations
Not assessed
Carpathian-Balkanian
Basin
Romania and Bulgaria
Silurian
Tandarei
Not assessed
North Sea-German
Basin
Belgium, Netherlands,
Germany
Western
Europe
Technically
Risked Gas InRecoverable
place (Tcm)
Resource (Tcm)
Paris Basin
France
Scandinavia Region
Sweden and Denmark
South-East French
Basin
France
North UK Petroleum
System
UK
South UK Petroleum
System
UK
Sub-total
Posidonia
Shale
Namurian
Shale
Wealden Shale
PermoCarboniferous
Alum Shale
Terres Niores
Liassic Shale
Depth
(average)
(m)
2500
2000
1750
5000
4100
3450
3750
3050
2605
1800
2299
2049
Ukraine – outside EU
Ukraine – outside EU
Limited information -very complex
geology - recent deposits on
multiple upfaulted rocks but shale
gas potential
Limited information - complex
geology with nappe structures example cross-section show
potential target areas <1km deep
but other cross-section could
show deposits closer to surface
Limited information - complex
geology with nappe structures
8.2
1.8
0.7
0.2
1.8
0.3
0.5
0.1
8.6
2.2
16.7
3.2
4.2
0.8
8.6
2.2
2.7
0.5
0.1
42.6
73.3
0.0
10.5
17.7
Bowland Shale
Liassic Shale
Sub-total
Total
Depth interval (m)
1000
5000
3000
2500
5000
3750
1000
3000
2000
2600
4000
3300
<100
Not stated 1000
1000
1999
1500
2499
4999
3749
1000
1920
1460
3500
4720
4110
Source: US Energy Administration Information, 2011 NPR
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Appendix 5: Shale gas exploration in Europe
The limited history of exploration for shale gas in Europe is summarised in Table A5.1 below,
together with information on planned future developments. This is based on data collected
between November 2011 and April 2012.
Due to the high costs involved, horizontal drilling and hydraulic fracturing have in the past not
routinely been used for conventional hydrocarbon extraction in Europe. The use of hydraulic
fracturing for hydrocarbon extraction in Europe has been limited to lower volume fracturing of
some tight gas and conventional reservoirs in the southern part of the North Sea and in
onshore Germany, Netherlands, Denmark and the UK. These activities did not in general
constitute High Volume hydraulic fracturing as defined in Section 1.3.3below.

The Soehlingen field, in onshore Northwest Germany has several tight gas reservoirs
which, after discovery in 1980, were developed using hydraulic fracturing. The
development started in the early 1980s with hydraulic fracturing in vertical wells. In
1999 and 2000 multi-stage hydraulic fracturing in horizontal wells was performed,
resulting in increased and economic production (Rodrigues and Neumann, 2007
NPR). A fracturing test was carried out on coal-bed methane field in North-Rhine
Westphalia in 1994, but this was not pursued as it was not commercially successful
(European regulator consultation response, 2012 NPR). It is estimated that a total of
approximately 300 wells have been fractured in Germany between 1977 and 2010
(Reinicke 2011 NPR p11).

In the Danish sector of the North Sea, it is estimated that stimulation using hydraulic
fracturing has been carried out at approximately 130 wells (Danish energy ministry,
2012 NPR). Most of these wells have 10 to 20 fracture stages each. Approximately
twice as many wells have been stimulated using acid fracturing or matrix acidizing,
which lies outside the scope of this study. The wells are drilled in a tight gas chalk
reservoir with a grain size in the clay fraction.

In the Netherlands, over 200 unconventional gas wells have been fractured since the
1950s, of which about half are onshore and half offshore (NOGEPA, 2012 NPR).
Fracturing has been used at depths of between 1,600 and 4,000 metres. Between
2007 and 2011, 9 onshore wells and 13 offshore wells were fractured. NOGEPA
(2012 NPR) quotes an example fracturing operation which used 250 m3 of fracturing
fluid, suggesting that these operations were low volume, below the threshold adopted
for HVHF.

In the UK, approximately 200 onshore wells have so far been hydraulically fractured
(UK Department of Energy and Climate Change, 2012 NPR). These are mainly
conventional wells with a few coal-bed methane wells and one exploratory shale gas
well (Preese Hall, Lancashire). No fracturing of tight gas wells has been carried out
in the UK, and the majority of treatments were acidisation. High volume fracturing
was only carried out at the Preese Hall-1 well. The programme at this site was cut
short following minor earth tremors. It is estimated that at least 3,000 offshore wells
have been fractured. Although specific data on fluid volumes are not available, the
majority of these are likely to have been below the threshold of high volume fracturing
(see Section1.3.3). These are likely to have been almost entirely conventional oil or
gas formations, although some sandstone formations would be regarded as "tight" by
European standards.
No information was identified from the literature search in relation to the environmental
impacts of these hydraulic fracturing activities. The use of hydraulic fracturing in Europe has
been the subject of technical and scientific publications, but this has not extended to an
analysis of potential environmental or health effects. The environmental impacts of natural
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
gas extraction in Europe have been studied, but the contribution to these impacts from
hydraulic fracturing have not been separately analysed.
At the time of preparation of this report (March 2012), the following high volume hydraulic
fracturing operations for shale gas had taken place:

UK (Cuadrilla Resources Ltd): Preese Hall Lancashire: 8,600 m3 over 6 stages
(Broderick et al 2011 NPR Table 2.4)

Poland: Siekierki Blocks 207 & 208 (Multi Fractured Horizontal Wells T-2 and T-3)
(Ref. Aurelian company website, accessed 2012 NPR); no information on fluid
volumes.

Poland: Łebień LE-1 single-stage horizontal well (2010). Łebień LE-2H and Warblino
LE-1H2 multi-stage horizontal wells (2011). (Ref. 3 Legs Resources company
website, accessed 2012 NPR); no information on fluid volumes

Poland: Horizontal fracturing of Lubocino-1 well near Wejherowo: 1600 m3 fluid (Ref.
PGNiG company website, accessed 2012 NPR)

Poland: Incomplete fracture stimulations performed on the Cambrian & Ordovician
intervals in the Lebork S-1 well in 2011 (insufficient proppant) (Ref. BNK company
website, accessed 2012 NPR); no information on fluid volumes

Poland: Hydraulic fracturing procedures carried out by PGNiG SA in July 2010 in the
Markowola-1 well in Zwola (Volumes and directionality not known but likely to have
been high volume horizontal fracturing) (PGNiG company website, accessed 2012
NPR)
Table A5.1: Overview of shale gas exploration involving high volume hydraulic
fracturing in Europe (as of February 2012)
Date
Location
Description
Company
Status (based on
information from
company websites)
Reference
Broderick et al
2011 NPR
United Kingdom
Nov 2009
Preese Hall Farm,
Weeton, Preston
Lancashire
Exploratory well
Cuadrilla resources
Completed on 8 Dec
2010
Jan 2011
Grange Hill
Exploratory well
Cuadrilla resources
Not known
-
Anna’s Road
Exploratory well
Cuadrilla resources
Planning approved
-
Balcombe well
site (drilled by
Conoco in 1986)
West Sussex licence
area held by its
investment partner AJ
Lucas.
Cuadrilla resources
No plans
Cuadrilla
Resources,
2012 NPR
-
Point of Ayr
Potential shale
resource
IGL
review of hydrocarbon
potential
Island Gas
Limited
company
website, 2012
NPR
Poland (2011: over 100 licences have been granted, rapid developments)
-
Milejow
Milejow is adjacent to
several blocks held by
ExxonMobil, shale
strategy and work
programme pending
the outcome of shale
drilling on nearby
blocks
Dart Energy
Direct award licence
issued to Composite in
November 2010
Dart intends to
undertake an
independent resource
certification exercise
during 2011.
Composite
Energy - Dart
Energy
company
website, 2012
NPR
Sept 2011
Siennica
In the Lublin Basin,
Exxon is operating in
partnership with French
oil major Total, which
ExxonMobil
(ExxonMobil has six
licenses to explore for
shale gas in Poland.)
Initial drilling and
hydraulic fracturing
carried out at Krupe 1
and Siennica 1 wells.
Natural Gas
Europe
website, 2012
NPR
Ref: AEA/ED57281/Issue Number 17
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Date
Location
Description
Company
Status (based on
information from
company websites)
Reported to be not
commercially viable.
Reference
Company website
indicates that initial
drilling is expected
Q2/Q3 2011, but press
release suggests that
drilling has been
carried out at Rogity-1
well in February 2012.
San Leon
Energy
company
website, 2012
NPR
holds a 49% stake in
the licenses.
In the Podlasie Basin,
Exxon has partnered
with Hutton Energy.
Q2/Q3
2011.
Baltic Basin
including Gdansk-W,
Braniewo-S, Szczawno
- with a pending
application on the
Czersk concession.
San Leon Energy (The
company has shale
gas concessions in the
Baltic Basin) - in jointventure with Talisman
energy
2011
South-East
Poland
Chevron conducted
seismic programs and
drilled an exploration
well
Chevron Corp
2011
Poland
Research of
hydrocarbons in tight
sands and shale
Cuadrilla Poland
Licences for research
of hydrocarbons in tight
sands and shale have
been awarded
Polish
Exploration
and Production
Industry
Organisation,
2011 NPR
2011
Siekierki Project
(Block 207 &
Block 208)
Testing Multi-stage
fractured horizontal
Wells T-2 and T-3
Aurelian Oil and Gas
PLC
Final results were
anticipated at the end
of January 2012.
Aurelian Oil
company
website, 2012
NPR
2010/2011
Baltic Basin
Łebień LE-2H
horizontal well drilled
Warblino LE-1H2
horizontal well drilled
3legresources (9
licenses) / Lane
Energy Poland/
ConocoPhilllips
A seven stage
hydraulic fracture
stimulation programme
was successfully
executed across the
500 metre horizontal
section in the deeper
lower Palaeozoic
shales.
Further testing in 2012.
3 leg resources
company
website, 2012
NPR
2010
Baltic Basin
fracture stimulations
were performed on
both the Cambrian and
Ordovician intervals in
the Lebork S-1 well
BNK Petroleum (6
licenses)
Company plans to
restimulate Lebork S-1
well and stimulate
Starogard and
Wytowno wells
2010-2011
Zwola
hydraulic fracturing
procedures is carried
out by PGNiG SA in
July 2010 in the
Markowola-1 well in
Zwola
PGNiG (15 licenses)
Company studies have
highlighted no
environmental issues
(not independently
verified)
PGNiG
company
website, 2012
NPR
2011
Wejherowo
Lubocino-1 well near
Wejherowo
Tests carried out after
completion of the
fracturing operation
indicate that there are
potentially significant
amounts of shale gas
in the Wejherowo
licence area
PGNiG
PGNiG SA is the first
Polish company to
have commenced
works towards
commercial production
of shale gas in Europe,
aiming to commence
production in 2014.
Further horizontal
drilling and further
fracturing treatments
are planned for 2012.
PGNiG
company
website, 2012
NPR
2011
Baltic Depression
The Company began
drilling operations in
the Łeczna and Siedlce
districts in the fourth
quarter of 2011,
Marathon Oil (11
concessions)
Plans to drill seven to
eight wells by the end
of 2012. Early stages
of exploring and
evaluating the full
potential of these
holdings.
Marathon Oil
company
website, 2012
NPR
Chevron
company
website, 2012b
NPR
Ref: AEA/ED57281/Issue Number 17
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hydrocarbons operations involving hydraulic fracturing in Europe
Date
Location
Description
Company
Status (based on
information from
company websites)
Reference
2008-2011
Damme 3 Shale
well
Testing Hydraulic
Fracturing
ExxonMobil
Hydraulic Fracturing
has been carried out;
no environmental
impacts reported by
operator (not
independently verified).
Evaluating gas
potential
ExxonMobil
Deutschland
company
website, 2012
NPR
2009-2010
- 2 concessions in
North RhineWestphalia
- concession in
Lower Saxony
- 2 concessions in
Thuringia
geological survey /
seismic survey
BNK Petroleum
Horizontal wells to be
drilled not earlier than
2015
2010
concessions
"Rhineland" and
"Ruhr"
received permission
Wintershall
conduct geological
investigations in two
license areas
Wintershall
company
website, 2012
NPR
Schuepbach
France has banned
hydraulic fracturing for
shale gas exploration
and exploitation (June
2011) (research
projects under public
supervision may
however be allowed);
three exploration
permits granted
previously to
Schuepbach, Total &
Devon for shale gas
exploration were
abrogated
Company
websites
Germany
France
2010/11
Nant
(Aveyron)and
Villeneuve-deBerg (Ardèche)
Montélimar
4,328 km2 concession
awarded in 2010
Total/Devon
Boxtel
Planned exploratory
well
Cuadrilla Resources
Drill activities
suspended by court
order
Shale gas deposit
in a large section
of Dobrudzha in
the north east of
the country,
Planned two
exploratory drillings in
2015 and two more in
2016.
Chevron Corp
Bulgarian government
has imposed a ban on
the use of hydraulic
fracturing for oil and
gas exploration and/or
extraction on the
Bulgarian territory (24th
January 2012) and
cancelled an
exploration permit for
shale gas exploration
granted June 2011 to
Chevron Corp (Jan
2012). Chevron can
proceed with
operations on the Novi
Pazar concession in
northeastern Bulgaria,
but only by using
conventional drilling
techniques and not
hydraulic fracturing
Skane
Drilling three test wells
Royal Dutch Shell (two
exploration licenses)
Limited resources of
gas in the Alum shale.
Netherlands
Bulgaria
2015/2016
Sweden
2008-2010
Shell company
website, 2012
Ref: AEA/ED57281/Issue Number 17
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hydrocarbons operations involving hydraulic fracturing in Europe
Date
Location
Description
Company
Status (based on
information from
company websites)
No further
developments.
Reference
NPR
2012
Östergötland and
Öland
Biogenic gas (shallow
formations)
Gripen Gas
Four wells drilled and
tested.
Gripen
website
2012
Motala project
planned test drilling in
Alum shale
Aura Energy
Company plans to start
drilling at the Motala
site (3 - 5 wells)
Aura
Energy
company
website, 2012
NPR
Gas
Norway
2010
Alum Shale
2010: The Norwegian
Petroleum Directorate
(NPD) confirms the
existence of shale gas
on the Norwegian shelf
and onshore, but no
plans for extraction.
Denmark
2010
Bornholm
Scientific drilling to
investigate natural gas
in the Alum shale,
seismic research
GEUS (Geological
Survey Denmark and
Greenland),
cooperation with GASH
2010
Nordjylland
Nordsjælland
Two onshore licences
to explore for
subsurface oil and gas
in Denmark were
granted in 2010
Total E&P Denmark
B.V., an affiliate of
Total, and the Danish
state-owned oil and
gas company
Nordsøfonden (2
exploration licenses)
Geological
Survey
Denmark and
Greenland,
2010 NPR
The exploration
licenses run from 2010
to 2016. Total E&P
Denmark B.V. and
Nordsøfonden are
currently working on
the first of three
exploration phases.
The full exploration
process is due for
completion in 2016.
Skifergas
company
website
Ref: AEA/ED57281/Issue Number 17
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Appendix 6: Matrix of potential impacts
Tables A6.1, A6.2 and A6.3 summarise the potential environmental impacts and risks of
shale gas extraction using high-volume hydraulic fracturing (adapted from USEPA 2011a PR
and other sources identified in chapter 2).
Table A6.1: Matrix of impacts (groundwater, surface water and water resources)
Impacts specific to HVHF/Unconventional gas extraction are underlined
Development & Step
Groundwater contamination
Surface water contamination
Production
and other risks and impacts
risks and impacts
Stage
Site Selection
Site identificand Preparation ation
Site selection
Site
Runoff and erosion during site
preparation
construction may lead to silt
accumulation in surface waters
(greater potential risk in HVHF
because of larger well pads and
storage impoundment
construction)
Well Design
Deep well
Inadequate design could result
(directional)
in aquifer pollution. Risk of
pollution via casing of
Shallow
inadequate depth and/or quality
vertical
Well drilling,
casing and
cementing
Drilling
Casing
Cementing
Hydraulic
Fracturing
Water
sourcing:
surface water
and ground
water
withdrawals
Inadequate control of drilling
process and associated wastes
could result in groundwater or
surface water pollution.
Inadequate casing quality or
depth could result in pollution of
groundwater during hydraulic
fracturing, flowback, and gas
production
Inadequate quality of
cementation could result in
pollution of groundwater during
hydraulic fracturing, flowback,
and gas production
Surface water abstraction could
affect groundwater flow
pathways, or quantity or quality
Water resource
depletion
Leaks/spills of drilling mud and
cuttings could result in SW
pollution
Temporary structures (hoses and
pipes) used to remove source
water from surface stream could
cause bank erosion, potential for
silt contamination of the stream. 







Withdrawal from
ground water resources
may have the following
impacts:
Lowering of water table
Dewatering drinking
water aquifers
Changes in water
quality resultant from
water use:
Changes to salinity of
water
Chemical
contamination resulting
from mineral exposure
to aerobic environment
Lowering of water table
may result in bacterial
growth, taste or odour
problems
Lowering of water table
may lead to release of
biogenic methane into
superficial aquifers
Aquifer depletion may
lead to upwelling of
lower quality water or
other substances (e.g.
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
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Development & Step
Production
Stage
Groundwater contamination
and other risks and impacts
Surface water contamination
risks and impacts
Water resource
depletion
methane – shallow
deposits) from deeper
and subsidence or
destabilization of
geology

 Withdrawal from
surface water
resources (streams ,
ponds and lakes) can
affect hydrology and
hydrodynamics altering
flow regime (depth,
velocity and
temperature), can
reduce dilution and
increase contaminants
Water
sourcing:
Reuse of
flowback and
produced
water
Flowback stored in surface
impoundments prior to reuse
can leak and cause GW
contamination.
Risk of indirect effects following
spillage and contamination of
surface waters
Chemical
additive
transportation
and storage;
mixing of
chemicals with
water and
proppant
Accidents and spillages on site
can result in surface and/or
ground water contamination,
e.g. as a result of:
 Tank ruptures
 Equipment / surface
impoundment failures
 Overfills
 Vandalism
 Accidents
 Fires
 Improper operations
If storage arrangements are
inappropriate, rainfall can
transfer materials offsite in runoff
Inappropriate charge used to
perforate casing could affect
well integrity (e.g., crack cement
and casing)
Fluid contaminants could be
transferred to aquifers:
via induced fractures extending
beyond target formation to
aquifer as a result of hydraulic
fracturing operations and/or
through complex
biogeochemical reactions with
chemical additives in fracturing
fluid and/or
via pre-existing fracture or fault
zones and/or
via pre-existing man-made
structures where these intersect
an injection zone or in vicinity of
hydraulically fractured well
serving as conduits
Sites close to, or hydraulically
linked to water resources pose a
greater risk
Risk of pollution due to spillage
Perforating
casing
Well injection
of hydraulic
fracturing fluid 



Pressure
Surface impoundments that store
flowback prior to reuse can fail
and cause SW contamination.
Flowback transported to another
location: Accidents and spillages
in transit can result in surface
and/or ground water
contamination.
Risk of indirect impacts via
groundwater contamination.
Risks may result from HF fluid
chemicals, contaminants in
produced water, and/or gas
migration. Sites close to, or
hydraulically linked to water
resources pose a greater risk
Risk of direct impacts via spillage
Ref: AEA/ED57281/Issue Number 17
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Development & Step
Groundwater contamination
Production
and other risks and impacts
Stage
reduction in
of flowback and produced water
well to reverse via
fluid flow,
 Tank ruptures
recovering
 Equipment or surface
flowback and
impoundment failures
produced
 Overfills
water
 Improper operations
These waters contain HF fluid,
naturally occurring materials, as
well as potentially reaction and
degradation products including
radioactive materials.
Risk of disruption to
groundwater flows
Well Completion Handling of
waste water
during
completion
(planned
management)
Handling of
waste water
during
completion
(accident
risks)
Connection of
well pipe to
production
pipeline
Well pad
removal
Surface water contamination
risks and impacts
Water resource
depletion
of flowback water; indirect impacts
via groundwater contamination.
Risks may result from HF fluid
chemicals, contaminants in
produced water, and/or gas
migration. Sites close to, or
hydraulically linked to water
resources pose a greater risk
If permitted, direct discharge to
surface streams can affect water
quality, particularly from the high
salt content (this practice is
banned in the U.S.)
Treatment in municipal sewage
treatment plant can affect the
plant due to slugs of saline
wastewater which can pass
through the plant untreated.
Treatment in Centralized Waste
Treatment facility: risks depend on
the treatment process.
Risk of pollution due to spillage of
flowback and produced water via
 Tank ruptures
 Equipment or surface
impoundment failures
 Overfills
 Vandalism
 Fires
 Improper operations
Risk of pollution if wastewater is
re-used or disposed
inappropriately
If flowback water is used to make
up fracturing fluid, this would
increase the risk of introducing
naturally occurring chemical
contaminants and radioactive
materials to groundwater.
Relevant naturally occurring
substances could include:
 Salt
 Trace elements (mercury, lead,
arsenic)
 NORM (radium, thorium and
uranium)
 Organic material (organic acids,
polycyclic aromatic
hydrocarbons)
Improper grading may cause
runoff and erosion and lead to silt
accumulation in surface waters.
Drainage and removal of
impoundment facilities could
potentially result in accidental
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Development & Step
Production
Stage
Well Production
Production
(including
produced
water
management)
Pipeline
construction
and operation
Re-fracturing
Well / Site
Abandonment
Well / Site
Abandonment
Remove
pumps and
downhole
equipment
Plugging to
seal well
Groundwater contamination
and other risks and impacts
Surface water contamination
risks and impacts
discharge to surface waters.
Risks posed by failure or
inadequate design of well casing
leading to potential aquifer
contamination
Surface spills or release of
produced water during storage
on site could affect groundwater
and surface waters, as for
“Hydraulic Fracturing” above. At
the beginning of the production
phase, flowback will comprise
mainly fracturing fluid, changing
to produced water after a few
days, with increased salt
concentration.
Risk of pollution if wastewater is
re-used or disposed
inappropriately, as for “Hydraulic
Fracturing” above
Risks due to spillage of
materials during construction of
pipeline
Similar to “Hydraulic Fracturing” Similar to “Hydraulic Fracturing”
above
above
Water resource
depletion
Similar to “Hydraulic
Fracturing” above
Inadequate sealing of well could
result in subsurface pathways
for contaminant migration
leading to groundwater pollution,
and potentially surface water
pollution
Existence of well could result in
increased risks of pollution
associated with future
subsurface activity.
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Table A6.2: Matrix of impacts (air emissions, land take and biodiversity)
Impacts specific to HVHF/Unconventional gas extraction are underlined
Development & Step
Release to air of HAPs/ O3
Production
precursors/ odours
Stage
Site Selection
Site identification
and Preparation
Site selection
Site preparation
Diesel emissions from site
construction equipment.
Minor risk due to fugitive
emissions in the event of
equipment fuel or oil
spillage
Well Design
Deep well (directional)
Shallow vertical
Well drilling,
casing and
cementing
Drilling
Hydraulic
Fracturing
Chemical additive
transportation and
storage; mixing of
chemicals with water
and proppant
Perforating casing
(where present)
Well injection of
hydraulic fracturing
fluid
Biodiversity risks and
impacts
Typical well head would
remove an area of
approx. 3ha from other
uses (eg agriculture,
natural habitat) for the
duration of exploration
and production (US
Department of Energy
2009 NPR). It may not
be possible to restore a
sensitive habitat following
operational phase
Risk of impacts on sensitive
species during site
preparation due to removal
of habitat, introduction of
invasive species; noise,
disturbance, particularly in
sensitive areas
Emissions, noise, human
activity, traffic, land-take,
habitat degradation,
introduction of invasive
species etc. could result in
disturbance to natural
ecosystems, particularly in
sensitive areas
Diesel emissions from well
drilling equipment. Minor
risk due to fugitive
emissions in the event of
equipment fuel or oil
spillage
Casing
Cementing
Water sourcing:
surface water and
ground water
withdrawals
Reuse of flowback
and produced water
Land take
Noise or plant movement
during drilling could affect
wildlife, particularly in
sensitive areas
On-site storage of water
for hydraulic fracturing
requires land-take
On-site storage and
transportation of water can
affect biodiversity due to
land take, disturbance
and/or by the introduction of
non-native invasive species
Risk of emissions to air of
HAPs/ozone precursors/
odours, from inadequate
control of gas leakage
during completion, or from
release of gases dissolved
in liquids Possible fugitive
emissions of methane or
HAPs from flowback or
produced water. Direct
effects more severe in the
vicinity of residential
locations. Indirect effects
may be more severe in rural
areas
Accidents and spillages can
result in harmful effects on
natural ecosystems
Diesel emissions from
fracturing fluid pumps.
Risks posed by movement
of naturally occurring
substances to groundwater
as described for
groundwater contamination.
Relevant naturally occurring
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
substances could include:
 Gases (natural gas
(methane, ethane), carbon
dioxide, hydrogen sulphide,
nitrogen and helium)
 Organic material (volatile
and semi-volatile organic
compounds)
Pressure reduction in
well to reverse fluid
flow, recovering
flowback and
produced water
Well Completion
Volatile and semi-volatile
Storage of flowback
chemicals may be released water and produced
from flowback and produced water requires land take
waters during recovery
(EPA, 2011b NPR). Direct
effects more severe in the
vicinity of residential
locations. Indirect effects
may be more severe in rural
areas
Fugitive emissions may take
place from routeing gas
generated during
completion to the sales
pipeline. This is likely to be
more severe from
exploratory pre-pipeline
wells than from
developmental wells
(pipeline in place)
Handling of waste
water during
completion (planned
management)
Handling of waste
water during
completion (accident
risks)
Spillages of waste water
could result in pollution or
other disruption to habitats
Connection of well
pipe to production
pipeline
Well pad removal
Well Production
Well / Site
Abandonment
(Return of land used for
well pad to prior use or
other uses)
(After fracturing, the well
pad may be removed or
made smaller, reducing
the footprint.)
Production (including
produced water
management)
Fugitive losses could occur
during production phase via
valve leakage etc
Collect and treat gases
dissolved in produced water
along with methane
Pipeline construction
and operation
Risk of fugitive losses
during production phase via
valve or flange leakage
Pipeline requires landtake during construction
and operation
Re-fracturing
Re-fracturing
Similar to “Hydraulic
Fracturing” above, but
should be possible to route
emissions to the pipeline
Inadequate sealing of well
could result in fugitive
emissions following site
abandonment
Similar to “Hydraulic
Fracturing” above
Plugging to seal well
It may not be possible to
return the entire site to
beneficial use following
abandonment, e.g. due to
concerns regarding
public safety
Slight potential for
disturbance to natural
ecosystems during
production phase due to
human activity, traffic, landtake, habitat degradation,
introduction of invasive
species etc., particularly in
sensitive areas
Construction of new linear
feature could adversely
affect biodiversity,
particularly in sensitive
ecosystems
Similar to “Hydraulic
Fracturing” above
It may not be possible to
return the site and any other
affected areas to its
previous state, which could
be particularly significant for
sites located in sensitive
areas
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Table A6.3: Matrix of impacts (noise, seismicity, visual impacts and traffic)
Impacts specific to HVHF/Unconventional gas extraction are underlined
Development & Step
Noise
Seismicity
Production
Stage
Site Selection and Site identificPreparation
ation
Site selection
Site
Noise from excavation,
preparation
earth moving, other
plant and vehicle
transport could affect
residential amenity
and wildlife,
particularly in sensitive
areas
Well Design
Deep well
Noise emissions from
(directional)
wellhead could affect
Shallow vertical residential amenity
and wildlife,
particularly in sensitive
areas
Well drilling,
Drilling
Noise emissions from
casing and
drilling or associated
cementing
activity could affect
residential amenity
and wildlife,
particularly in sensitive
areas
Casing
Cementing
Hydraulic
Water
Noise from use of
Fracturing
sourcing:
pumps to handle water
surface water
for hydraulic fracturing
Reuse of
and ground
could affect residential
flowback and
water
amenity and wildlife,
produced water
particularly in sensitive
Chemical additive withdrawals
areas
transportation and
storage; mixing of
chemicals with
water and
proppant
Perforating casing
(where present)
Reuse of
Noise from use of
Well injection of
flowback and
pumps to handle water
hydraulic
produced water for hydraulic fracturing
fracturing fluid
could affect residential
Pressure
amenity and wildlife,
reduction in well
particularly in sensitive
to reverse fluid
areas
flow, recovering
Chemical
flowback and
additive
produced water
transportation
and storage;
mixing of
chemicals with
water and
proppant
Perforating
casing (where
present)
Well injection
of hydraulic
fracturing fluid
Visual impacts
Traffic
Heavy plant,
stockpiles, fencing,
site buildings etc
could result in
adverse visual
intrusion during site
preparation
Transportation to/from
well heads during site
preparation can have
significant adverse
effects as above.
Impact likely to be
more severe on
unsuitable roads and
for longer haulage
distances
Well heads constitute
a potentially
significant visual
intrusion, particularly
in non-industrial
settings as above
Drilling activity and
associated plant could
constitute a potentially
significant visual
intrusion, particularly
in non-industrial
settings as above
Transportation of
water to the site can
have significant
adverse effects due to
noise, community
severance, air
emissions,
accident/spillage risk
etc. Impact likely to be
more severe on
unsuitable roads and
for longer haulage
distances
Chemicals storage
tanks and related
plant could constitute
a potentially
significant visual
intrusion, particularly
in non-industrial
settings as above
Hydraulic
fracturing could
be associated
Transportation of
chemicals to the site
can have significant
adverse effects due to
noise, community
severance, air
emissions,
accident/spillage risk
etc. Impact likely to be
more severe on
unsuitable roads and
for longer haulage
distances
Hydraulic fracturing
plant could constitute
a potentially
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Development &
Production
Stage
Step
Pressure
reduction in
well to reverse
fluid flow,
recovering
flowback and
produced water
Well Completion
Noise
Seismicity
Visual impacts
with minor earth
tremors up to 4.0
on Richter scale
significant visual
intrusion, particularly
in non-industrial
settings as above
Injection of waste
water could
potentially be
associated with
minor earth
tremors
Waste water tanks
and related plant
could constitute a
potentially significant
visual intrusion,
particularly in nonindustrial settings as
above
Noise emissions
associated with
operation of well and
associated equipment
could affect residential
amenity and wildlife,
particularly in sensitive
areas
Handling of
waste water
during
completion
(planned
management)
Handling of
waste water
during
completion
(accident
risks)
Connection of
well pipe to
production
pipeline
Well pad
removal
Well Production
Well / Site
Abandonment
Noise from
construction/demolition
machinery
Production
Pipeline
construction
and operation
Noise from pipeline
construction could
affect residential
amenity and wildlife,
particularly in sensitive
areas
Re-fracturing
Similar to “Hydraulic
Fracturing” above
Plugging to
seal well
Traffic
Transportation of
waste water to
treatment/disposal
facility can have
significant adverse
effects due to noise,
community severance,
air emissions etc.
Impact likely to be
more severe on
unsuitable roads and
for longer haulage
distances
Transportation of
waste water to
treatment/disposal
facility can have
significant adverse
effects due to
accident/spillage risk.
Impact likely to be
more severe on
unsuitable roads and
for longer haulage
distances
(Benefit from removal
of site infrastructure)
Site plant and
equipment could have
a visual impact,
particularly in
residential areas or
high landscape value
areas, but much less
than during fracturing
Pipeline could have a
significant visual
impact, particularly in
residential areas or
high landscape value
areas
Similar to
Similar to “Hydraulic
“Hydraulic
Fracturing” above
Fracturing” above
It may not be possible
to remove all
wellhead equipment
from site
Transportation of
materials and
equipment could have
adverse effects due to
noise, community
severance etc during
construction phase
Similar to “Hydraulic
Fracturing” above
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Appendix 7: Evaluation of risk control
measures
This section presents risk control measures broken down by the stages in the hydraulic
fracturing process identified in Chapter 2. Within these stages, regulatory control measures
are presented first, covering both measures currently implemented, those which are
proposed for implementation, and those recommended to regulatory authorities. Industry
control measures are then presented, with attention focused firstly on those which are
established practice (e.g. those which are laid down in guidelines published by the oil and
gas industry), and then on measures which are recommended or proposed for
implementation by industry.
A7.1 Overarching risk management measures
A7.1.1 Regulatory measures
The US Department of Energy (SEAB, 2011a NPR) recommended that regulatory authorities
should take a strategic overview of potential impacts. SEAB recommended the creation of a
national database of public sources of information relating to shale gas. This database
would contain information on industry trends (production, well numbers and location etc),
geological records, chemical usage, regulatory activity, and historical records of
environmental quality, protection and safety. The cost for the US was estimated as
approximately $20 million to create the database, with an annual maintenance cost of about
$5 million. A geological survey consultee concurred that the primary need for the US is to
have a database of baseline water quality and quantity, and geologic information across the
entire shale gas formation, prior to the commencement of HVHF (North American geological
survey consultation response 2012 NPR). Such a database would have similar advantages
for the UK. Rahm (2011 p2980 PR) emphasises the need for a strong regulatory approach,
and highlights difficulties caused due to differences of approach between state and federal
regulatory authorities in the US.
It was also recommended that funding should be provided for the existing STRONGER
initiative to provide peer review of regulatory activities, and for information resources to assist
in consistent regulation and evaluation (total cost estimated to be $5 million per year).
Academic consultees confirmed that well cementing methods and practices needs further
research (Consultation response from Professor R Vidic, University of Pittsburgh 2012 NPR).
European regulators emphasised the importance of research focusing on unknown features
of shale gas geology in Europe (European regulator consultation responses 2012 NPR):

Amount and distribution of gas in the different target horizons

Permeabilities of source rocks and barriers for fluids and gases; estimate of fracture
patterns

Localisation of faults and estimation of their hydraulic effects

Origin and risk of migration of methane in the overburden of the gas shales
Depending on the circumstances, a regulatory authority may choose to take a wider or a
narrower view of the impacts of a new shale gas development industry. For example, New
York State's Supplemental Generic Environmental Impact Statement (SGEIS) (2011 PR)
addresses not just the potential impacts from HVHF, but the potential impacts for state-wide
exploitation of the Marcellus Shale. There is a wide range of impacts which are potentially
associated with the industry (e.g. habitat fragmentation) which are not directly the result of
HVHF, but result from the industry that HVHF enables.
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
A report to the European Parliament (Lechtenböhmer et al., 2011 NPR) suggested that
authorities should consider identifying zones which are off-limits to hydraulic fracturing if
required to protect drinking water supplies, prevent groundwater contamination and protect
ecosystems and wildlife from endangerment and invasive species.
In March 2011, the Governor of Pennsylvania established the “Governor’s Marcellus Shale
Advisory Commission.” The purpose of the Advisory Commission was to develop a
comprehensive, strategic proposal for the responsible and environmentally sound
development of Marcellus Shale. The Commission issued its report in July 2011
(Pennsylvania State, 2011 NPR). The report provides extensive information on the history of
hydraulic fracturing and drilling in the Marcellus Shale formation including the role of all state
and local agencies. It also provides an overview of the Pennsylvania state regulatory
changes prompted by Marcellus Shale activity, case studies on the potential for impacts to
ground water and surface water, and a detailed discussion on the economic impacts of
hydraulic fracturing in Pennsylvania.
The Advisory Commission reviewed and developed recommendations to mitigate
environmental impacts; enhance emergency response; identify and mitigate uncompensated
local and community impacts; and provide for appropriate public health monitoring and
analysis. Their recommendations included:

increased permitting,

pre-drilling notification

operator liability requirements.

additional conditions for locating wells and storing hazardous chemicals. These
recommendations included:
o
9.2.11 - Increase the minimum setback distance from a private water well from
60 m to 150 m (200 feet to 500 feet) and establish a minimum setback
distance from a public water supply (water well, surface water intake or
reservoir) of 300 m(1,000 feet) unless waived in writing by the owner or public
water supply operator.
o
9.2.12 - Provide regulator with additional authority to establish further
protective measures for the storage of hazardous chemicals or materials on a
well site located within a floodplain.
o
9.2.13 - Impose additional conditions for locating well sites in floodplains,
including prohibiting where appropriate.
o
9.2.24 -The setback standard for an unconventional well shall be increased to
90 metres (300 feet) from the wellbore to a stream or water body as provided
in section 205(b) of the Oil and Gas Act. A 30 m (100 foot) setback from the
stream or water body to the edge of disturbance shall also be implemented.
… For High Quality and Exceptional Value streams, however, additional
setbacks or BMPs may be required by the regulator.

additional well stimulation and completion reporting requirements

voluntary ecological initiatives within critical habitats that would generate mitigation
credits which are eligible for use to offset future development.
The current international standard for environmental management systems (ISO 14000
series, 2004) is widely adopted by operators in the oil and gas industry on a voluntary basis
(ISO, accessed 2011). This standard is also applicable for the management of HVHF
operations. ISO 14001:2004 and ISO 14004:2004 deal with environmental management
systems. The ISO 14000 series of standards are designed to enable organisations to
minimise the adverse effects of their operations on the environment, and to deliver ongoing
improvements in environmental performance. Accreditation to ISO 14000 provides a
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
framework for an organisation to assess, monitor and improve its environmental
performance. Accreditation should be encouraged for shale gas installation operators as a
means of ensuring ongoing improvements in all aspects of environmental performance.
The SEAB (2011a NPR p27) recommended the creation of a shale gas industry production
organization dedicated to continuous improvement of best practice in the industry through
development and promulgation of appropriate standards, and assessment of compliance
among its members. It recommended that this work should initially focus on five priority
areas:

Measurement and disclosure of air emissions including VOCs, methane and air toxics

Reduction of methane emissions to air from all shale gas operations

Integrated water management systems

Well completion – casing and cementing

Characterization and disclosure of flow back and other produced water
Disclosure of hydraulic fracturing fluid additives and flowback composition was also
recommended by the German environment ministry (Umweltbundesamt 2011 NPR p23)
Consultees recommended that further research into the control of cumulative impacts
associated with shale gas development is needed (North American geological survey
consultation response; European regulator consultation response 2012 NPR).
A7.2 Well pad site identification and preparation
A7.2.1 Regulatory measures
Baseline surveys
The SEAB (2011a NPR p23) recommended that systems for measurement and reporting of
background surface and ground water quality should be implemented in advance of shale
gas production activity. Indicator species such as bromides may be useful components of a
baseline survey (Consultation response from Professor R Vidic University of Pittsburgh 2012
NPR). The need for systematic and independent data on baseline groundwater quality was
supported by Osborn et al. (2011 PR p5). The SEAB went on to recommend monitoring for
wider community and cumulative impact issues (SEAB (2011a NPR p26), and further
recommended a “science-based characterization of important landscapes, habitats and
corridors to inform planning, prevention, mitigation and reclamation of surface impacts.”
Similarly, two European regulators and one North American geological survey consultee
recommended groundwater monitoring before, during and after shale gas exploration works
(consultation responses 2012 NPR). Osborn et al. (2011 PR p4) recommended long-term,
coordinated sampling and monitoring of the quality of water provided to industry and private
homeowners.
Groundwater level monitoring networks are being used in the US to monitor groundwater
depletion in areas where groundwater is used as water supply for drilling and hydraulic
fracturing purposes. GIS and remote sensing technologies linked to ground-truth studies of
targeted species and existing studies of land-use alteration can be used to evaluate land
cover changes due to concentrated development and its possible effects on flora and fauna.
This is particularly useful in remote or heavily forested areas (North American geological
survey consultation response 2012 NPR).
Prohibit high volume hydraulic fracturing in drinking watersheds
New York: New York State DEC (2011 PR) concluded that high-volume hydraulic fracturing
activity is not consistent with the preservation of unique unfiltered water supplies that depend
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
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on strict land use and development controls to ensure that water quality is protected. It was
concluded that high-volume hydraulic fracturing activities could result in a degradation of
drinking water supplies from accidents and surface spills and that large scale industrial
activity is not compatible with the use of this area as a drinking watershed. Accordingly, NY
DEC recommended that high-volume hydraulic fracturing operations not be permitted in the
Syracuse and New York City watersheds or in a protective 4,000 foot (1,200 metre) buffer
area around those watersheds (New York DEC (2011 PR) p1-17)
The SEAB (2011 NPR p26) supported the declaration of unique and/or sensitive areas offlimits to drilling and support infrastructure, based on an appropriate science-based process.
Ensure new wells are installed away from abandoned wells and other potential
conduits for fluid migration (site selection and permitting)
Michigan: The Michigan Department of Environmental Quality, Office of Geological Survey,
Permits and Bonding Unit reviews applications for “Permits to Drill and Operate” oil and gas
wells that may be hydraulically fractured. During this review, staff are required to “identify
recorded existing or permitted well bores within [specified] radii of the proposed
well…determine whether the [identified] well may provide a conduit for movement of
hydraulic fracturing fluids or produced fluids into a stratum containing fresh water. The
determination shall take into account the anticipated radius of influence of the potential
hydraulic fracturing….[if such wells are identified, require the applicant to] [r]elocate the
proposed well to a location such that all potential conduits are outside the area of review.”
(Michigan Office of Geological Survey, 2011a NPR)
New York: “To ensure that abandoned wells do not provide a conduit for contamination of
fresh water aquifers, the Department proposes to require that the operator consult the
Department’s Oil and Gas database as well as property owners and tenants in the proposed
spacing unit to determine whether any abandoned wells are present. If
1. the operator has property access rights,
2. the well is accessible, and
3. it is reasonable to believe based on available records and history of drilling in the
area that the well’s total depth may be as deep or deeper than the target formation for
high-volume hydraulic fracturing,
then the Department would require the operator to enter and evaluate the well, and properly
plug it prior to high-volume hydraulic fracturing if the evaluation shows the well is open to the
target formation or is otherwise an immediate threat to the environment.” (New York State
DEC 2011 PR , p7-58)
Requirement for pit liners (construction specifications)
As an example, pit specification requirements are set out in the State of Louisiana
Administrative Code Title 43 Part XIX §307.A.1.a:
“For natural liners: A liner along the bottom and sides of pits which has the equivalent of
3 continuous feet [0.9 m] of recompacted or natural clay having a hydraulic conductivity
no greater than 1 x 10-7 cm/sec.
For synthetic liners: Pits constructed with a manufactured liner must have side slopes of
3:1 and the liner at the top of the pit must be buried in a 1-inch wide and 1-inch deep
trench.
Freeboard Requirement: Liquid levels in pits shall not be permitted to rise within 2 feet
[0.6 m] of top of pit levees or walls.
Additional Requirements: Pits shall be protected from surface waters by levees or walls
and by drainage ditches, where needed, and no siphon or openings will be placed in or
over levees or walls that would permit escaping of contents so as to cause pollution or
contamination.”
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
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Requirement for secondary containment for storage tanks and spill control plans
These measures will also reduce risk of surface water contamination.
US EPA, Office of Emergency Management: For fuel oils, diesel, produced oil, and certain
produced water containers: The Federal Spill Prevention, Control, and Countermeasure
(SPCC) rule includes requirements for oil spill prevention, preparedness, and response to
prevent oil discharges to navigable waters and adjoining shorelines. The rule requires
specific facilities to prepare, amend, and implement SPCC Plans. The SPCC rule is part of
the Oil Pollution Prevention regulation (EPA, 2012c NPR), which also includes the Facility
Response Plan (FRP) rule (EPA, 2012d NPR).
Colorado: New oil and gas locations within 2640 feet [800 m] of surface water supply
locations shall use pitless drilling systems; berms or other containment around crude oil,
condensate, and produced water storage tanks; and conduct surface water sampling predrilling and three months after drilling immediately downgradient of the oil and gas location
(COGCC 317B(c), (d), (e)).
Restrict hydraulic fracturing and well pad installation from sensitive areas
New York: NYDEC proposes that certain sensitive areas of New York State should be offlimits to surface drilling for natural gas using high-volume hydraulic fracturing
technology…these areas include

watersheds associated with unfiltered water supplied to the New York City and
Syracuse areas (because these are unfiltered water supplies that depend on strict
land use and development controls to ensure that water quality is protected)

reforestation areas

wildlife management areas

“primary” aquifers (which are highly productive aquifers presently used municipal
water supplies) and

additional setback and buffer areas.
Delaware River Basin Commission: In order to protect high value water resource landscapes
and special protection waters, the Delaware River Basin Commission proposed to require
that any natural gas development project sponsor with natural gas leaseholds in the basin
encompassing a total of over 3,200 acres (1300 hectares) or who intends to construct more
than five natural gas wellpads must prepare a plan (Natural Gas Development Plan) for siting
and accessing its natural gas development projects. The goal of the requirement is to
protect the natural character of the watershed and the project area by encouraging facility
siting that minimizes land disturbance, including forest clearing and fragmentation (Section
7.5). Among other requirements, the commission proposed to restrict development from
flood plains, steep slopes, the river corridor itself, and proposed that development meet the
following set-backs (7.5(d)):

Stream, waterbody or wetland – the greater of 300 ft. (90 m) from the wellbore or 100
ft. (30 m) from the nearest disturbance.

Surface water supply intake – 1,000 ft. (300 m) from nearest disturbance

Water supply reservoir – 1,000 ft. (300 m) from nearest disturbance

Public water systems – 1,000 ft. (300 m) from nearest disturbance

Private water supply well – 500 ft. (150 m) from nearest disturbance
Set minimum well spacing
New York: As described in New York State DEC (2011 PR) Section 5, developing a shale
formation using horizontal wells drilled from a multi-well pad will result in a reduced number
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
of well pads within a given area and the need for only a single access road and gas
gathering system to service multiple wells on a single pad. Consequently, a smaller total
area of land disturbance is associated with horizontal wells for shale gas development than
that for vertical wells. Land take can be minimized by setting a larger minimum well spacing.
For vertical wells, well spacing is typically 40 acres (16 hectares). New York State
anticipates requiring “spacing units of up to 640 acres (260 hectares or 2.6 sq km) with all the
horizontal wells in the unit drilled from a common well pad” (New York State DEC (2011 PR)
page 5-22). Installing 16 vertical wells to develop a 260 hectare site would disturb 31.1
hectare. The same site could be developed using a well pad with four horizontal wells,
requiring 3.2 hectare of land disturbance. Installing more wells per pad would further reduce
the required land area. The use of higher numbers of wells could enable up to 5 square
kilometres to be developed per pad, as set out in Table 12.
Table 12: Land take for a 25 square km development
Spacing Option
Multi-Well 2.5 sq km
Number of pads
10
Total Disturbance –
30 hectare
Drilling/fracturing Phase
(3 hectare per pad)
% Disturbance – Drilling/fracturing 1.2%
Phase
(30 hectare /2,500 hectare
area)
Total Disturbance – Production
5 hectare
Phase
(0.5 hectare per pad)
% Disturbance Production Phase
0.2%
(Adapted from New York State DEC 2011 PR Table 5.1)
Multi-Well 5 sq km
5
22.5 hectare
(4.5 hectare per pad)
0.89%
(22.5 hectare/2,500
hectare area)
4 hectare
(0.8 hectare per pad)
0.16%
The SEAB (2011 NPR p26) also recommends the use of multi-well pads to reduce
community impacts such as traffic and new road construction.
Require strategies to minimize onsite water storage (produced water reuse, use of
temporary pipe networks)
No specific legislative or regulatory initiatives discouraging onsite water storage could be
identified in the course of this study.
Locate sites close to existing gas pipelines
No specific legislative or regulatory initiatives regarding proximity to existing gas pipelines
could be identified in the course of this study.
Minimisation of habitat fragmentation and destruction
New York: The NY SGEIS (Section 7.4.1) includes proposed practices to mitigate harm from
fragmentation of existing habitats:

Require multiple wells on single pads wherever possible

Design well pads to fit the available landscape and minimize tree removal

Require soft edges around forest clearings by either maintaining existing shrubs or
planting shrubs, or allowing shrub areas to grow

Require lighting used at wellpads to shine downward during bird migration periods

Limit the total area of disturbed ground, number of well pads, and especially, the
linear distance of roads, where practicable

Require roads, water lines, and well pads to follow existing road networks and be
located as close as possible to existing road networks to minimize disturbance
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe

Require reclamation of non-productive, plugged, and abandoned wells, well pads,
roads and other infrastructure areas.
The NYSGEIS proposes additional strategies for controlling habitat fragmentation that are
specific to habitats of concern in the Marcellus Shale area of New York State. For example,
where operators request permits to conduct HVHF operations in areas where there are
contiguous habitats of 30 acres (12.1 hectares) or more of grassland or 150 acres (60.7
hectares) or more of forest, the applicant must conduct a site-specific ecological assessment,
develop a site-specific mitigation plan, and monitor the effects of disturbance during activities
and for two years following well completion.
Practices to reduce risk of introduction of non-native species.
New York: The NY SGEIS (Section 7.4.2) includes proposed practices to mitigate harm from
invasive species caused by HVHF activities. The SGEIS called for a site- specific and
species-specific invasive species mitigation plan. The plan would include practices for
mitigating harm from terrestrial (plant) and aquatic invasive species. Recommended
practices include, among others:

Preventing the Spread of Invasive Species: Machinery and equipment - pressurewash and clean with water (no soaps or chemicals) prior to leaving the invasive
species affected area to prevent the spread of seeds, roots or other viable plant parts.
This includes all machinery, equipment, and tools used in the stripping, removal, and
disposal of invasive plant species.

Preventing New Invasive Species Introductions: Fill and/or construction material (e.g.
gravel, crushed stone, top soil, etc.) from offsite locations - only use material after
inspection if no invasive species are found growing in or adjacent to the fill/material
source.

Restoration and Preservation of Native Vegetation: Use only native (non-invasive)
seeds or plant material for re-vegetation during site reclamation.
Site selection to minimise noise
New York: NYSGEIS identified noise mitigation measures for HVHF operations (New York
State DEC 2011 PR p7-130). These measures are not required in regulations but could be
added to specific permits and enforced through binding permit conditions. With regard to site
selection, it was recommended that the well site and access road should be located as far as
practical from occupied structures and places of assembly.
Minimisation and control of potential seismic impacts
European regulators recommended carrying out monitoring with respect to potential seismic
events (European regulator consultation response 2012 NPR). A North American geological
survey regulator suggested that it would be helpful for data held by the industry to be
available to regulators. A method for monitoring and management of potentially significant
seismic events was proposed by the UK Government (UK DECC, 2012 NPR)
The state of Arkansas does not have regulations addressing potential seismic risks from
hydraulically fracturing shale gas and oil wells. However, Arkansas experienced a series of
very small earthquakes in 2010 (Guy-Greenbrier earthquake swarm) (Arkansas Sun Times,
2011 NPR). The Arkansas Oil and Gas Commission, Arkansas Geological Survey, and the
Center for Earthquake Research and Information (CERI) concluded the earthquakes
correlated with underground injection of wastewater from Fayetteville shale gas wells. In
response, the Arkansas Oil and Gas commission initiated a moratorium on Class II disposal
wells (Arkansas State, 2012 NPR).Unless otherwise approved by the Arkansas Oil and Gas
Commission after notice and a hearing, no permit to drill or re-enter, a new Class II Disposal
or Class II Commercial Disposal Well may be granted within one (1) mile of a Regional Fault
or within five (5) miles of a known or identified Moratorium Zone Deep Fault.
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
The State of Ohio is proposing to introduce reforms with regard to management of potential
seismic impacts associated with wastewater injection wells (Ohio Department of Natural
Resources, 2012 NPR):

Review of existing geologic data to identify known faulted areas within the state and
avoid the locating of new disposal wells within these areas;

Require a complete suite of geophysical logs to be run on newly drilled disposal wells.

Evaluate the potential for conducting seismic surveys;

Require the submission, at time of permit application, of any information available
concerning the existence of known geological faults, and submission of a plan for
monitoring any seismic activity that may occur;

Require a measurement or calculation of original downhole reservoir pressure;

Require conducting a step-rate injection test;

Require the installation of a continuous pressure monitoring system;

Require the installation of an automatic shut-off system;
Injection of waste water into aquifers would not be permitted in Europe (European
Commission, 2011a NPR ; see Section 3.17).
Minimisation of visual impacts
New York: From New York State DEC (2011 PR):

Siting: Use multi-well pads; avoid ridgelines or other areas where aboveground
equipment and facilities break the skyline;

Lighting: should be the minimum necessary for safe working conditions and public
safety, and should be sited and directed to minimize off-site light migration, glare, and
“sky glow” light pollution.

Camouflage: Use forms and colours to mimic surroundings (e.g., paint fracturing fluid
tanks so as to blend with surroundings)
Site-specific remedies for traffic issues
Other site-specific remedies for traffic issues could include

limiting truck weights,

road use agreements,

payments by industry to repair damaged roads.
A7.2.2 Industry measures
Established measures
For sites developed in accordance with the API guidelines, a comprehensive pre-site
assessment must be carried out to ensure that the most appropriate sites are developed
(ALL Consulting, 2010a NPR p12; API 2011a NPR p15). Site selection should take into
account aspects such as the following:

Geological considerations

Potential presence of other wells which could affect the integrity of the proposed well

Water sourcing

Locate equipment and well pads to use existing features (e.g., hillsides, trees) to
contain noise and preserve views.
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe

Locate site so it is accessible by existing roads and other infrastructure (e.g.,
pipelines) to minimize construction impacts.

Potential environmental constraints such as floodplains, wetlands, fluid makeup,
depth to the quality of groundwater, surface topography, proximity to drinking water
supplies and wells, proximity to surface water, proximity to geological hazards,
proximity to residential or commercial buildings, and proximity to other
environmentally sensitive areas.
Developers should incorporate best design and management practices and train employees
in why good management is important, including the need to prevent or minimise risks to
health and the environment (STRONGER, 2010 NPR ; API 2011a NPR p9, p10). Providing
a sufficient number of on-site staff throughout drilling, completions, and production
operations is important to ensure that environmental management and safety procedures
can be properly implemented.
Before and during exploration and production, it is important to design and implement an
appropriate baseline environmental survey. This is likely to include consideration of baseline
testing of ambient air before well pad construction commences, and baseline testing of water
wells and boreholes before commencing drilling. A plan for air and water well monitoring
should be developed and implemented during the construction, drilling, and production
phases. For sites developed in accordance with the API guidance, water samples from any
nearby source of water (rivers, creeks, lakes, ponds, and water wells) should be obtained
and tested (API, 2009 NPR). The area of sampling should be based on the anticipated
fracture length plus a safety factor. This procedure will establish the baseline conditions in
the surface and groundwater prior to any drilling or hydraulic fracturing operations. If
subsequent testing reveals changes, this baseline data will allow the operator to determine
the potential sources causing any changes. Because the constituents of the hydraulic
fracturing fluid are known to the operator and can be made available to the regulatory
authorities via the permitting processes described in Chapter 2, a determination can be made
regarding the source of the changes in the groundwater composition.
Guidance on impoundment construction is provided in API (2011a NPR p11).
Recommended measures
The International Energy Agency (2012 NPR p13) emphasised the importance of site
selection to minimise environmental impacts and community disturbance.
ALL Consulting (2009b NPR) suggest a separation of 1 mile (1.6 km) between well pads and
sensitive residential areas where possible.
The impact of transportation and other impacts can be minimised by selecting an appropriate
location, and by managing traffic routeing to and from the site. Developers should also
consider the impacts of potential access road locations at the planning stage, and preferably,
locate access roads away from homes and businesses.
Risks to groundwater can be minimised by limiting development to appropriate zones
specified to protect groundwater (Pochon et al., 2008 PR).
Limiting the pace of development may be effective in reducing the more acute impacts of
HVHF activities (New York State DEC 2011 PR p6-317). This needs to be balanced against
the longer development period that would result from slower development.
In the past, shale gas development in the US has taken place via single-well pads. More
recently, there has been a trend towards the use of multi-well pads with typically 6 to 10 wells
per pad (New York State DEC 2011 PR p3-3) and up to 20 wells per pad in some instances
(SEAB 2011a NPR p33). The use of multi-well pads is effective in reducing a wide range of
potential impacts compared to the use of single-well pads. This measure also reduces
construction costs (e.g. SEAB 2011a NPR p33; ALL Consulting 2009 NPR). For example,
land-take and habitat fragmentation can be minimised in this way. ALL Consulting (2009b
Ref: AEA/ED57281/Issue Number 17
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NPR) estimates that surface disturbance can be reduced by 85% in this way compared to
single well pads. Similarly, New York State DEC (2011 PR p5-23) suggests that the use of
multi-well pads can reduce surface disturbance compared to single well pads by 90% during
the drilling/fracturing phase, and by 80% during the production phase.
The land used for infrastructure such as storage ponds should be minimised. It is important
that land used for gas extraction is maintained to a suitable standard so that it can be
restored to its original form, so far as possible. However, as noted in Chapter 2, it may not
be possible to fully restore a site in a sensitive area. For example, sites in areas of high
agricultural, natural or cultural value could potentially not be fully restorable following use.
During the planning stage, it will be helpful to investigate and review the history of nearby
wells to determine if any unusual problems were encountered (e.g., significant flowback or
lost cementing returns). These can then be addressed in future well development.
Proper supply chain and transportation management can mitigate equipment, chemicals, and
storage tank availability. Measures include:

Develop a transportation plan to reduce truck traffic, designate parking and storage
areas, and identify transportation routes. If possible, use temporary surface pipes to
transport water to the well pad and flowback and produced water to storage,
treatment, or injection points.

Centralise gathering facilities to reduce truck traffic, including the liquids gathering
system.
At the planning stage, preliminary lighting surveys should be carried out to enable site
lighting to be arranged in order to minimize or eliminate any visual disturbance for local
residents or wildlife, while still providing sufficient light to provide a safe workplace for on-site
employees (ALL Consulting 2009b NPR p15).
During site preparation, surface soils should be stockpiled for all cut and fill areas so that
they can be reused during interim and final reclamation. Topsoil should be segregated from
subsurface materials to improve the effectiveness of reclamation activities. By using cut
areas for surface impoundment construction, unnecessary increases in facility footprint can
be avoided. Fill slopes should be compacted to reduce the risk of subsidence and slope
failure.
Primary and secondary containment of chemical, water and waste storage facilities can be
utilised at the well site to ensure the surface environment is not exposed to materials that
could pose harm to the surrounding area. Barriers can be implemented as needed to ensure
surface disruptions such as potential erosion at the drill site do not affect the surrounding
environment. Buffer zones can also be used around surface water resources to provide
further protection against water pollution risks (see example buffer zones in Section A7.1).
Surface impoundments and reserve pits should be avoided where possible (Oil and Gas
Accountability Project, 2012 NPR). If unavoidable, surface impoundments should not be
constructed in sensitive areas such as natural water courses, karst topography, source water
protection areas used for public water supplies, areas with shallow groundwater, and in
porous soils. These should be located in cut areas when possible. Impoundments and pits
should not be constructed in areas within a flood risk zone, to reduce the risk of overtopping
due to external flood events. Synthetic liners and/or compacted clay can be used to reduce
the risk of groundwater impacts. Before installing synthetic liners, operators should consider
using sand, clay or felt liners to protect the synthetic liner from being punctured by rock
material. It is important that surface impoundments and storage tanks are managed so as to
provide sufficient freeboard to avoid overtopping. Secondary containment and liners should
be used as appropriate around storage tanks to avoid potential soil and groundwater
contamination due to storage tank leaks or spills.
The key control measures during the design of site access roads include the following
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe

Construct roads along natural contours or in flatter terrain where possible.

Avoid constructing roads to a higher standard than the necessary to minimize
environmental impacts. For example, basic two-track roads can be used where
appropriate to avoid the impacts associated with tarmac road construction.

Avoid construction of shorter roads on steep slopes: these can create greater
environmental impacts at higher cost than longer roads with lower gradients.
When work is being carried out near residential areas, it is important to provide residents in
local communities sufficient information on the site layout and potential hazards. This can be
a useful means of reducing the perceived impacts associated with drilling activities
(International Energy Agency 2012 NPR p13). Emergency response policies and procedures
should be developed to enable any community risks when incidents occur to be properly
handled and managed.
During site selection, developers should consider opportunities to avoid water quality impacts
by locating facilities where pollutant transport into surface and groundwater will be limited. It
is important to consider spill pathways, erosion and sedimentation issues, and stormwater
runoff when selecting well pad and auxiliary facility locations.
Where possible, facilities should not be located adjacent to or near surface water bodies or
within source water protection areas for public water supplies, in order to reduce pollutant
transport pathways. Similarly, facilities should not be located in or near sensitive
environments (e.g., riparian areas, wetlands, sensitive species habitats, karst areas) (see
example buffer zones in Section A7.1).
Silt fences, sediment traps or basins, hay bales, mulch, earth bunds, filter strips or grassed
swales can be used to slow runoff and trap sediment from leaving the site. Loose soil should
be covered with geotextiles or other materials. Where possible, activities should be staged
to reduce soil exposure and coincide with a season of low rainfall.
The risk of impacts on water quality can be mitigated by:

Periodically monitoring down-gradient of surface impoundments.

Immediate notification of public water suppliers in the event of spills or leaks.

Use of near real-time water quality monitors for specific conductance which can be
used to provide an initial assessment of water quality impacts from spills (North
American geological survey consultation response 2012 NPR)

Installation and use of groundwater monitoring wells up-gradient and down-gradient
of the well pad to ensure that drilling, hydraulic fracturing, and other operations do not
compromise ground water.

Installation of a liner and secondary containment around the well pad to minimize the
potential for surface water and shallow ground water contamination.
Pipelines should not be located on steep hillsides or within watercourses. Pipelines
constructed across watercourses should be built high enough to provide clearance for highflow events. Pipelines can be located along road corridors to minimize surface disturbance
and promote leak detection. Secondary containment may be appropriate for pipelines and
valves conveying potentially toxic substances.
Sites should be located to maximise the benefit of natural noise attenuation features such as
land-form and vegetation. As described in Section A7.1, sites should be located as far away
from sensitive residential or habitat areas as possible. New York State DEC (2011 PR p7128) uses a distance of 305 metres as indicative of the zone within which noise impacts may
be significant and detailed investigation is needed.
Baseline monitoring for key environmental indicators, such as groundwater quality, was
recommended by the International Energy Agency (2012 NPR p13).
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
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Site selection is an important factor in minimising road traffic impacts. Further guidance is
provided by API (2011a NPR p17):

Existing roads that meet transportation needs should be utilized, where feasible

When it is necessary to build new roadways, they should be developed with potential
impacts and purpose in mind. Mitigation options should be considered prior to
construction and landowner recommendations should be part of the planning
process.

Proper road maintenance is critical for the performance of roads, to manage erosion
and to protect environmentally sensitive areas.

Where appropriate, operators should obtain road use agreements with local
authorities.

Whether agreements are in place or not, in areas with traffic concerns, operators
should develop a trucking plan that includes an estimated amount of trucking, hours
of operations, appropriate off-road parking/staging areas and routes. Examples of
possible measures in a road use agreement or trucking plan include:
o
route selection to maximize efficient driving and public safety;
o
avoidance of peak traffic hours, school bus hours, community events and
overnight quiet periods;
o
coordination with local emergency management agencies and highway
departments;
o
upgrades and improvements to roads that will be travelled frequently;
o
advance public notice of any necessary detours or road/lane closures; and
o
adequate off-road parking and delivery areas at the site to avoid lane/road
blockage.
A7.2.3 Summary
The site identification and preparation stage provides the opportunity to implement many of
the key preventive controls on potential environmental and health risks. As described in
Section 2, the key issue associated with site preparation is that of cumulative land take.
There may also be less significant issues associated with surface water contamination risks;
biodiversity impacts; visual impact; and traffic during this stage. However, the decisions
taken and actions carried out at this stage are likely to be beneficial in mitigating risks
throughout the lifetime of the site.
A wide range of regulatory measures can be applied at the site identification and preparation
stage. Similar measures are planned to be implemented in Québec (North American
regulator consultation response 2012 NPR). The key measures identified for implementation
in Québec include:

Specifying appropriate buffer distances to sensitive locations such as surface waters,
groundwater, residential locations or protected habitats

Specifying a minimum separation or maximum development density to minimise
impacts on biodiversity and visual impacts

Setting appropriate emissions or environmental performance standards – e.g. with
regard to contaminants in waste water, noise or air pollution

Setting appropriate environmental monitoring programmes in place to ensure that any
impacts can be tracked
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
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Operators will be subject to a number of potentially conflicting constraints with regard to site
selection. In some cases, commercial considerations will align with good environmental
performance – e.g. minimising vehicle mileage will typically be beneficial both to the operator
and for the environment. In other cases, good environmental performance may need to be
enforced via appropriate regulatory measures.
The issues with regard to site preparation and levelling are common to many development
projects and do not require special consideration with regard to hydrocarbons operations
involving HVHF.
The control measures set out in this section are implemented by regulators and the industry
in areas where HVHF is established – that is, North America. Under these conditions, they
are considered to be affordable. The cost and affordability of such measures in a European
context cannot be evaluated at this stage, and will depend on the forecast revenues from
shale gas extraction in Europe.
The control measures set out in this chapter are considered likely to be effective in delivering
control of the impacts under consideration. For example, noise impacts can be effectively
controlled by appropriate siting and design. Containment of water can be designed to reduce
the risk of significant impacts in the event of a spillage to an insignificant level.
However, some impacts cannot be fully mitigated. For example:

It may not be possible to return land used for shale gas development to its former use
in some locations – e.g. if the land was a valuable habitat site or historical/cultural
resource.

Good site selection and design can reduce traffic impacts, but a significant number of
traffic movements is inevitable.
A7.3 Well design, drilling, casing and cementing
A7.3.1 Regulatory measures
Isolate well from underground source of drinking water
Surface casing and cementing requirements (well construction and development, field
inspection)
Examples of State Requirements for casing placement to ensure aquifer protection are as
follows.
Colorado: In areas where subsurface conditions are unknown, the surface casing shall be set
in or through an impervious formation and cemented in place (COGCC 317(e)). In areas
where subsurface conditions are known through drilling experience, the surface casing shall
be set and cemented to protect all fresh water (COGCC 317(f)). In areas where fresh water
aquifers are of such depths as to make it impractical or uneconomical to set the surface
casing the total depth, the intermediate and/or production string shall be cemented from a
minimum of 50 feet [15 m] above to 50 feet [15 m] below any freshwater aquifer (COGCC
317(g)).
Illinois: Surface casings shall be set to a depth of at least 100 feet [30 m], or 50 feet [15 m]
below the base of a freshwater aquifer (whichever is deeper). Alternative casing methods
are available in the regulations; however, all methods require a minimum of 50 feet [15 m]
below the freshwater aquifer. (62 Illinois Administrative Code Section 240.710)
Pennsylvania: The operator shall drill to approximately 50 feet [15 m] below the deepest
fresh groundwater or at least 50 feet [15 m] into consolidated rock (whichever is deeper), and
immediately set and permanently cement a string of surface casing to that depth. (25 PA
Code §78.83)
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Oklahoma: Suitable and sufficient surface casing shall be run and cemented from bottom to
top with a minimum setting depth which is the greater of 90 feet [27 m] below the surface, or
50 feet [15 m] below the base of treatable water. The operator must run and cement the
surface casing string before reaching a depth of 250 feet [76 m] below treatable water. (OK
Reg 165:10-3-4(c)).
Montana: Suitable and safe surface casing must be used in all wells. Sufficient surface
casing must be run to reach a depth below all fresh water located at levels reasonably
accessible for agricultural and domestic use (Administrative Rules of Montana
36.22.1001(1)).
Ohio: Surface casings must be set at least 50 feet [15 m] below Underground Source of
Drinking Water (USDW)s(Draft Ohio Oil and Gas Well Construction Rules 1501:9-108(M)(4)(a), dated 2/8/2012. The Ohio Department of Natural Resources drafted the rules
pursuant to Senate Bill 165, effective 6/30/2010. The comment period was extended to
3/5/2012).
US Department of Energy (SEAB 2011a NPR) indicates that pressure tests of the casing and
state-of-the-art cement bond logs should be performed to confirm that the methods being
used achieve the desired degree of formation isolation. Regulations and inspections are
needed to confirm that operators have taken prompt action to repair defective
cementing(referred to as “squeeze jobs”).
State requirements for cement testing are designed to measure compressive strength with
benchmarks between 2.1 and 8.3 MPa, and specify setting times between 4 hours and 72
hours for different tests:
Example state requirements for cement testing are as follows:
Colorado: Cement placed behind the surface and intermediate casing shall be allowed to set
a minimum of 8 hours before resuming drilling, or until it has developed a minimum
calculated compressive strength of 300 psi [2.1 MPa] (COGCC 317(h). Cement placed
behind the production casing shall be allowed to set a minimum of 72 hours before resuming
drilling, or until it has developed a minimum calculated compressive strength of 800 psi [5.5
MPa](COGCC 317(i). Surface, intermediate, and production casing cement shall achieve a
minimum compressive strength of 300 psi [2.1 MPa] after 24 hours and 800 psi [5.5
MPa](after 72 hours (when measured at 95°F [35°C]) (COGCC 317(h)).
Illinois: Surface casing cement shall be allowed to set in place until it has developed
sufficient strength to allow drilling to resume, but no less than 4 hours. (62 Illinois
Administrative Code Section 240.710)
Texas: Surface casing strings must be allowed to stand under pressure until the cement has
reached a compressive strength of at least 500 psi [3.4 MPa] in the zone of critical cement
before drilling plug or initiating a test. The cement mixture in the zone of critical cement shall
have a 72-hour compressive strength of at least 1,200 psi [8.3 MPa]. (16 TAC §3.13(b)(C)).
Pennsylvania: Cement should set to a minimum compressive strength of 350 psi [2.4 MPa]in
accordance with American Petroleum Institute (API) Specification 10. Cement should be
allowed to set for at least 8 hours before the operator resumes drilling activities. (25 PA
Code §78.85)
Montana: All casing strings must be cemented and properly tested by the pressure method
before cement plugs are drilled and shall stand under pressure until the cement has reached
a compressive strength of 300 pounds per square inch; provided, however, that no tests shall
be commenced until the cement has been in place for at least 8 hours (Administrative Rules
of Montana 36.22.1001(2)).
Ohio: Cement must be allowed to set undisturbed until an initial compressive strength of 500
psi [3.4 MPa] has been achieved (Draft Ohio Oil and Gas Well Construction Rules 1501:9-108(J)(2)).
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Well casing and cementing programmes can be included in site permits (ALL Consulting,
2010a NPR p13). As discussed in Chapter 3, the mining framework directive is a potential
means of specifying standards for drilling and well construction in Europe.
Minimum permitted depth between underground source of drinking water and hydraulic
fracture
Groundwater could potentially be protected by preventing hydraulic fracturing from taking
place in zones where the shale gas formation does not have adequate separation from the
aquifers. The following criteria have been adopted regarding the zones which are and are
not acceptable for gas extraction via high-volume hydraulic fracturing. An alternative
approach would be for member states to prohibit shale gas extraction in specified areas
where there is a risk that the separation between fracturing operations and aquifers may not
be acceptable.
British Columbia: “A well permit holder must not conduct a fracturing operation at a depth
less than 600 m below ground level unless the operations are permitted by the well permit.”
B.C.Reg. 282/2010, Drilling and Production Regulation, Part 3 — Well Position, Spacing and
Target Areas, Division 4 — Procedures, 21. Fracturing operations.
New York: In its draft SGEIS, New York proposes that where the assumptions about vertical
separation used in the SGEIS are not met, additional site-specific SEQRA (State
Environmental Quality Review Act) review would be required for the state to respond to a
permit application. Depending on the outcome of that review, the state could require a sitespecific SEIS (supplemental environmental impact statement).
“As explained in Section 6.1.5.2, the conclusion that harm from fracturing fluid migration
up from the horizontal wellbore is not reasonably anticipated is contingent upon the
presence of certain natural conditions, including 1,000 feet [300 m] of vertical separation
between the bottom of a potential aquifer and the top of the target fracture zone. The
presence of 1,000 feet [300 m]of low-permeability rocks between the fracture zone and a
drinking water source serves as a natural or inherent mitigation measure that protects
against groundwater contamination from hydraulic fracturing. As stated in Section
8.4.1.1, GWPC recommended a higher level of scrutiny and protection for shallow
hydraulic fracturing or when the target formation is in close proximity to underground
sources of drinking water. Therefore, the Department proposes that site-specific
SEQRA review be required for the following projects:
1) any proposed high-volume hydraulic fracturing where the top of the target fracture
zone at any point along any part of the proposed length of the wellbore is shallower
than 2,000 feet [600 m] below the ground surface; and
2) any proposed high-volume hydraulic fracturing where the top of the target fracture
zone at any point along any part of the proposed length of the wellbore is less than
1,000 feet [300m] below the base of a known freshwater supply.”
Review would focus on local topographic, geologic, and hydrogeological conditions, along
with proposed fracturing procedures to determine the potential for a significant adverse
impact to fresh groundwater. The need for a site-specific SEIS would be determined based
upon the outcome of the review.” (New York State DEC 2011 PR p7-58). Recent research
suggests a potentially significant risk of fractures extending 350 m or more in a vertical
direction, suggesting that the second criterion may not be fully protective of groundwater
resources.
Michigan: In Michigan, since the 1960s, more than 12,000 wells have been hydraulically
fractured. Most of these are Antrim Shale Formation gas wells in the northern Lower
Peninsula (Michigan Office of Geological Survey, 2011b NPR). Existing wells are shallow
and typically use only 50,000 gallons [190 m3] of water in the fracturing process (Nicholson
and Fair, 2011 NPR).
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Michigan has developed new regulations for hydraulic fracturing, in anticipation of
development of the Utica shale formation that underlies the Antrim shale. These new
regulations require that the surface casing must extend a minimum of 100 feet [30 m] below
any freshwater zones, and fracturing is not permitted within 50 feet [15 m] of the surface
casing, so the spacing between freshwater and fracturing must be at least 150 feet [46 m]:
“The installation of steel pipe (“casing”), encased in cement, is key to preventing
migration of gas or fluids. Michigan regulations require that each oil and gas well have a
casing and cementing plan that will effectively contain gas and other fluids within the
wellbore, whether related to fracturing or not. Surface casing must be set a minimum of
100 feet [30 m] into the bedrock and 100 feet [30 m] below any fresh water zones and
cemented from the base of the casing to the ground surface. Before fracturing or other
operations can take place to complete a well for production, an additional string of
production casing must be set to the depth of the reservoir and cemented in place.
Depending on depth, additional protective casing may be required. To provide additional
protection for aquifers and well integrity, the DEQ imposes a permit condition for wells in
shallow reservoirs prohibiting hydraulic fracturing within 50 feet [15 m] of the base of the
surface casing.” (Michigan Office of Geological Survey, 2011b NPR)
General requirements
US Department of Interior, Bureau of Land Management (BLM): manages the use of natural
resources on Federal Lands, including mining and oil and gas extraction. In spring 2012,
BLM plans to propose rules to require oil and gas operators to submit (US BLM, 2012a
NPR):

well integrity information prior to well stimulation (e.g., hydraulic fracturing)

disclosure of the chemical constituents of hydraulic fracturing fluids.
The draft BLM regulations are not yet available, although press articles have been published
based on leaked information. At this stage, it appears that companies will have to report the
trade names, additive purposes with specific chemicals in each additive, and volumes used.
The draft regulation includes a trade-secret exemption, but it is not clear whether companies
will have to report trade-secret information. There is no confirmation regarding when BLM
will propose the regulation.
British Columbia:B.C.Reg. 282/2010, Drilling and Production Regulation, Part 3 — Well
Position, Spacing and Target Areas, Division 4 — Procedures, 22. Hydraulic isolation states
that a well permit holder must establish and maintain hydraulic isolation between all porous
zones in a well, except for zones in which commingled production is permitted or authorized
as described in section 23.
Plant operation to minimise noise
New York: NYSGEIS identified noise mitigation measures for HVHF operations (New York
State DEC 2011 PR p7-130). These measures are not required in regulations but could be
added to specific permits and enforced through binding permit conditions.

Direction - Noise-generating equipment, such as high-pressure discharge pipes,
should be directed away from occupied structures and places of assembly.

Timing - Significant noise-generating operations should occur during daylight hours.
A7.3.2 Industry measures
Established measures
Because of the importance of well integrity, the majority of relevant industry measures are
laid down in established guidance such as API guidance Document HF1 (2009 NPR).
Air emissions
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Emissions from truck traffic can be minimised by using vehicles which conform with the
highest currently applicable standards for vehicle emissions. Trucks should be prevented
from idling over extended periods, with a presumption that engines will be switched off.
Truckload contents should be covered as appropriate to reduce dust and PM emissions.
For conventional diesel-powered plant, drilling rig engines should conform with the highest
currently applicable emissions standards (Tier 2 (or better) standards are used in the US).
Well integrity
Detailed guidance for well construction is provided by the American Petroleum Institute (2009
NPR) Guidance Document HF1, “Hydraulic Fracturing Operations—Well Construction and
Integrity Guidelines.” This sets out general principles for groundwater protection, well design
and construction, drilling and completion.
Complete cementing and isolation of underground sources of drinking water must be carried
out prior to further drilling. API Standards for casing include:

API Spec 5CT for casing design, manufacturing, testing, and transportation

API Spec 5B for casing and coupling threads

API Spec 10A and API RP 10B-2 for selection and use of cementing products
Casing centralizers should be used to centre the casing in the hole, which will allow for good
mud removal and cement placement.
Testing of well integrity should take place at construction, and throughout the lifetime of the
well (API 2009 NPR p22).
Surface, intermediate and production casings should extend at least 30 metres deep or 15
metres below all underground sources of drinking water (whichever is deeper). Surface
casings should be cemented before reaching a depth of 75 metres below underground
sources of drinking water. Production casing should be cemented up to at least 150 metres
above the formation where hydraulic fracturing will be carried out (API 2009 NPR p11-12).
A minimum of 8 hours is needed for cement to set prior to resuming drilling operations.
Testing should then be carried out to ensure that the cement exceeds a minimum
compressive strength prior to resuming drilling operations. For production casing, the
cement should exceed the anticipated hydraulic fracturing pressure. API RP 10B-2 includes
cement testing specifications that recommends testing for slurry density, thickening time,
fluid loss control, free fluid, compressive strength development, and fluid compatibility.
Drilling fluids and cuttings
Drillers should carefully consider fluid choices to minimize the environmental hazard posed
by drilling wastes. Aspects to consider include (New York State DEC 2011 PR):

Use water-based muds with additives (e.g., mineral oil) rather than diesel-based
muds.

Prioritize reusing brine base fluid from flowback and produced waters for drilling
fluids.

Prioritize using less hazardous biocides (e.g., isothiazoline, amines).

Conserve water by using low-solids, nondispersed drilling fluid systems instead of
dispersed systems.

Return unused additives to suppliers or use at other wells.

Use air rotary drilling through surface casing zones to avoid drilling mud contacting
fresh water aquifers. Air rotary drilling can be used as much as possible to reduce
drilling waste
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe

Separated solids must be transported off-site for disposal.
Noise control
Noise control measures are outlined by ALL Consulting (2009b NPR p14), New York State
DEC (2011 PR p7-130 to 7-132) and the API (2011a NPR p17):

Limiting operations to certain hours (e.g. perform noisier activities, when practicable,
after 7 pm and before 7 pm);

Limiting drill pipe cleaning (“hammering”) to certain hours;

Running of casing during certain hours to minimize noise from elevator operation;

Using higher or larger-diameter stacks for flare testing operations;

Placing redundant permanent ignition devices at the terminus of the flow line to
minimize noise events of flare re-ignition;

Providing advance notification of the drilling schedule to nearby receptors;

Placing conditions on air rotary drilling discharge pipe noise, including:
o
orienting high-pressure discharge pipes away from noise receptors;
o
having the air connection blowdown manifolded into the flow line. This would
provide the air with a larger-diameter aperture at the discharge point;
o
having a 2-inch connection air blowdown line connected to a larger-diameter
line near the discharge point or manifolded into multiple 2-inch discharges;
o
shrouding the discharge point by sliding open-ended pieces of larger-diameter
pipe over them; or
o
rerouting piping so that unusually large compressed air releases (such as
connection blowdown on air drilling) would be routed into the larger-diameter
pit flow line to muffle the noise of any release.

Using rubber hammer covers on the sledges when clearing drill pipe;

Laying down pipe during daylight hours;

Scheduling drilling operations to avoid simultaneous effects of multiple rigs on
common receptors;

The use of sound barriers, blankets and walls to supplement attenuation from natural
features. Encasing compressor stations with specifically-designed walls to minimize
or even eliminate noise in the area has reduced the level of sound pollution
associated with compressor stations.

Limiting hydraulic fracturing operations to a single well at a time; and

Employing electric pumps.
Recommended measures
Drilling fluids and cuttings
Drilling fluids need to be carefully managed. Speciality muds which might only be used over
short intervals can be segregated into separate tanks so that they can be reused in other
wells. Where pits must be used, liner systems can be installed to an appropriate standard of
quality assurance. Monitoring using piezometers can be carried out to verify the liner’s
efficacy. Drilling fluids can be processed to separate liquids and solids in order to generate
recycled drilling fluid.
Measures under consideration
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Drilling fluids and cuttings
Closed-loop systems with storage tanks can be used instead of open pits. Closed loop
systems reduce drilling time, drill bit and water usage, and total surface disturbance (Oil and
Gas Accountability Project, 2007 NPR ; Smith-Heavenrich 2008 NPR).
Air emissions
Consideration should be given to the use of natural gas powered engines.
Pilot studies are expected to commence in 2012 to investigate the use of natural gas in
drilling rig engines in the US (Uintah Basin, Utah) (Kerr-McGee Oil & Gas, 2012 NPR). This
would be appropriate in established fields where there is an abundant local supply of natural
gas. Alternatively, electric drilling rigs can be used. Similarly, electric compressors or gas
turbines can be used rather than internal combustion engines for compression.
Selective catalytic reduction (SCR) and/or fuel additives can be used to reduce emissions
from drilling rig engines.
Wyoming Federal Lands (Managed by US Department of Interior, Bureau of Land
Management): This project is working towards achieving zero days of modelled visibility
impairment from drilling operations using mitigation controls on engines (US BLM 2008
NPR), including:

Require centralisation of production facilities to reduce truck traffic,

Reduce the pace of development
A7.3.3 Summary
The well design, drilling, casing and cementing stage provides the opportunity to implement
the key preventive controls on emissions to groundwater during hydraulic fracturing and
operation. As described in Section 2, the potentially significant issues associated with this
stage itself are noise and air quality impacts associated with drilling. There may also be less
significant issues associated with surface water contamination risks and visual impact during
this stage.
There is a well-defined set of industry standards that can be referenced by regulators during
the well design, drilling, casing and cementing stage. These standards set out the design
parameters for new well construction, and specify the testing that needs to be carried out to
verify well integrity. These standards could potentially be adapted by an individual regulator
if it was considered that site-specific issues warranted a different (typically higher) standard
of control.
The issues with regard to well design and construction contain some features which are
specific to hydrocarbons operations involving HVHF.
The control measures set out in this section are implemented by regulators and the industry
in areas where HVHF is established. Under these conditions, they are considered to be
affordable. Such measures are considered on balance likely to be affordable in a European
context, but the potential influence of these costs on shale gas project viability cannot be
evaluated at this stage, and will depend on the forecast revenues from shale gas extraction
in Europe.
Under specific geological conditions and fracturing techniques, there is a risk that HVHF
could potentially cause contamination of shallow ground water, due to the chemical additives
in hydraulic fracturing fluid, or due to the release of naturally occurring substances. There is
only a material risk of this taking place for extraction from shallow shale gas formations. In
the event that this occurs, remediation measures such as the use of Permeable Reactive
Barriers or interception wells can be used.
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
If contamination is suspected, tracer studies can be used to evaluate migration of hydraulic
fracturing fluids from the target hydrocarbon zone along fractures/faults and possibly into
freshwater aquifers for any processes which take place at shallower depths (North American
geological survey consultation response 2012 NPR). A geological survey consultee
recommended further research into potential impacts associated with shale gas extraction in
shallower shale gas formations (North American geological survey consultation response
2012 NPR).
These measures have not been addressed further in this report, which focuses on the
specification of appropriate measures to prevent pollution occurring.
A7.4 Technical hydraulic fracturing stage
A7.4.1 Regulatory measures
Controls on chemicals used for hydraulic fracturing
Disclosure of fluid composition is beneficial for regulatory authorities and to assist emergency
response in the event of a spillage (API 2011a NPR p8). The US EPA is currently
developing requirements under the Toxic Substances Control Act for hydraulic fracturing
chemical manufacturers to report data on environmental or health effects and exposures,
and health and safety studies. The US EPA’s action in this area is currently under review by
the Office of Management and Budget. Publication of an Advanced Notice of Proposed
Rulemaking was planned for May - June 2012.
The US Bureau of Land Management has developed a proposed rule which would require oil
and gas operators to disclose hydraulic fracturing fluids used in their operations and to
submit well integrity information prior to well stimulation (e.g. hydraulic fracturing) (Bureau of
Land Management, 2012b NPR). The proposed rule was published in May 2012, with the
final rule to be published following the close of the public comment period in September
2012.
New York State DEC (2011 PR p8-30) proposes to require operators to identify additive
products, by product name and purpose/type; proposed composition of fracturing fluid by
weight; and proposed volume of each additive. This requirement matches the requirements
used in the five US states with the most demanding requirements (New York State DEC
2011 PR p1-9). Similarly, British Columbia Oil and Gas Commission is planning on moving
to complete disclosure (North American regulator consultation response 2012 NPR). A
similar recommendation was made to the US Department of Energy (SEAB 2011a NPR
p24).
US EPA, Office of Groundwater and Drinking Water: under the authority of the Safe Drinking
Water Act, EPA’s Underground Injection Control Program is considering guidance for
additional permit conditions for oil and gas hydraulic fracturing using diesel fuels. EPA
planned to publish guidance for public comment in 2012. The guidance may:

define diesel fuels for this application

address siting consideration including ensuring there are no conduits for fluid
migration

provide well construction, operation, mechanical integrity, monitoring, and reporting
requirements

detail plugging and abandonment provisions.
USEPA’s authority to regulate materials used for hydraulic fracturing is limited to diesel fuels.
A state has the option of requesting primacy for Class II wells under either section 1422 or
1425 of the Safe Drinking Water Act:
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe

Section 1422 requires states to meet EPA’s minimum requirements for UIC
programs. Programs authorized under section 1422 must include construction,
operating, monitoring and testing, reporting, and abandonment requirements for well
owners or operators. Enhanced oil and gas recovery wells may either be issued
permits or be authorized by rule. Disposal wells are issued permits. The owners or
operators of the wells must meet all applicable requirements, including strict
construction and conversion standards and regular testing and inspection.

Section 1425 allows states to demonstrate that their existing standards are effective
in preventing endangerment of USDWs. These programs must include permitting,
inspection, monitoring, and record-keeping and reporting that demonstrates the
effectiveness of their requirements.
The following Federal UIC Regulations describes the minimum federal requirements for
injection operations:
 Part 144: Underground Injection Control Program, provides minimum
requirements for the UIC Program promulgated under the SDWA.
 Part 145: State UIC Program Requirements, outlines the procedures for EPA to
approve, revise, and withdraw UIC Programs that have been delegated to the states.
 Part 146: Underground Injection Control Program: Criteria and Standards,
includes technical standards for various classes of injection wells.
 Part 147: State Underground Injection Control Programs, outlines the applicable
UIC Programs for each state.
 Part 148: Hazardous Waste Injection Restrictions, describes the requirements for
Class I hazardous waste injection wells.
EPA is currently developing Underground Injection Control (UIC) permitting guidance under
the Safe Drinking Water Act for hydraulic fracturing activities that use diesel fuels in
fracturing fluids (USEPA 2012b NPR). Draft guidance for additional permit conditions for oil
and gas hydraulic fracturing using diesel fuels has been published for comment. The EPA
sets out a definition of diesel fuels for this application based on six CAS numbers for Diesel
fuels. This guidance is to be implemented by EPA permit writers for 11 states (the remaining
39 states have their own UIC permit programs). The guidance addresses how regulations
may be tailored to address the risks of diesel fuels injection during hydraulic fracturing. Draft
guidance was published in May 2012, with final guidance to be issued after the close of the
public comment period in August 2012.
The SEAB (2011a NPR p25) recommended that the use of diesel as an additive to hydraulic
fracturing fluid should be eliminated.
In the absence of authority to regulate materials used for hydraulic fracturing, EPA, other
federal agencies, and some states have developed requirements for operators to disclose
the chemicals used for hydraulic fracture. It should be noted that the mere disclosure of the
use of toxic chemicals does nothing to manage the potential risks posed by their use.
Examples of state disclosure requirements are as follows:
Texas: 16 Texas Administrative Code §3.16 Hydraulic Fracturing Chemical Disclosure
Requirements: This section applies to a hydraulic fracturing treatment performed on a well in
the State of Texas for which the Commission has issued an initial drilling permit on or after
February 1, 2012. Operators are currently allowed to report to www.FracFocus.org. This
resource enables oil and gas companies to upload information about the chemicals used on
each hydraulic fracturing job conducted on or after January 1, 2011. The website is
managed by the Ground Water Protection Council (GWPC) and Interstate Oil and Gas
Compact Commission (IOGCC). The GWPC is a non-profit national association of state
ground water and underground injection control agencies, while the IOGCC is a multi-state
government agency of governors and appointed representatives. The registry is voluntary
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
and does not include reporting proprietary or trade secret chemicals. It includes the well
location, total water volume, and additive information (trade name, supplier, purpose,
ingredients, maximum chemical concentrations in the additive and fracturing fluid). Although
the registry is voluntary, it has 234 participant companies.
Colorado: COGCC 205A: Hydraulic Fracturing Chemical Disclosure: Rule 205a applies to
hydraulic fracturing treatments performed on or after April 1, 2012. Within 60 days following
the conclusion of a hydraulic fracturing treatment, and in no case later than 120 days after
the commencement of such hydraulic fracturing treatment, the operator of the well must
complete the chemical disclosure registry form and post the form on the chemical disclosure
registry. Some exclusions are specified. Operators are currently allowed to report to
www.FracFocus.org.
Wyoming: WYOGCC Section 45. Well Stimulation requires that The Owner or Operator shall
provide detailed information to the Supervisor as to the base stimulation fluid source. The
Owner or Operator or service company shall provide to the Supervisor, for each stage of the
well stimulation program, the chemical additives, compounds and concentrations or rates
proposed to be mixed and injected, including:
(i)
Stimulation fluid identified by additive type (such as but not limited to acid, biocide,
breaker, brine, corrosion inhibitor, crosslinker, de-emulsifier, friction reducer, gel, iron
control, oxygen scavenger, pH adjusting agent, proppant, scale inhibitor, surfactant);
(ii)
The chemical compound name and Chemical Abstracts Service (CAS) number shall
be identified (such as the additive biocide is glutaraldehyde, or the additive breaker is
aluminium persulphate, or the proppant is silica or quartz sand, and so on for each
additive used);
(iii)
The proposed rate or concentration for each additive shall be provided (such as gel
as pounds per thousand gallons, or biocide at gallons per thousand gallons, or
proppant at pounds per gallon, or expressed as percent by weight or percent by
volume, or parts per million, or parts per billion);
(iv)
The Owner or Operator or service company may also provide a copy of the
contractor’s proposed well stimulation program design including the above detail;
(v)
The Supervisor may request additional information under this subsection prior to the
approval of the Application for Permit to Drill (Form 1) or of the Sundry Notice (Form
4);
(vi)
The Supervisor retains discretion to request from the Owner or Operator and/or the
service company, the formulary disclosure for the chemical compounds used in the
well stimulation(s).
The injection of volatile organic compounds, such as benzene, toluene, ethylbenzene and
xylene, also known as BTEX compounds or any petroleum distillates, into groundwater is
prohibited. The proposed use of volatile organic compounds, such as benzene, toluene,
ethylbenzene and xylene, also known as BTEX compounds or any petroleum distillates for
well stimulation into hydrocarbon bearing zones is authorized with prior approval of the
Supervisor. It is accepted practice to use produced water that may contain small amounts of
naturally occurring petroleum distillates as well stimulation fluid in hydrocarbon bearing
zones.
WYOGCC is not using www.FracFocus.org because trade secret information is required to
be submitted.
US Department of Energy SEAB (2011a NPR p25) recommends that regulatory entities
develop rules to require disclosure of all chemicals used in hydraulic fracturing fluids on both
public and private lands.
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The study commissioned by the Environment Committee of the European Parliament
recommended that requirements should be placed on operators to declare publicly the
chemicals used in hydraulic fracturing fluids (Lechtenböhmer et al., 2011 NPR p61).
Manage water abstraction
The SEAB (2011a NPR p22) considered that “the development and use of an integrated
water management system has the potential for greatly reducing the environmental footprint
and risk of water use in shale gas production and recommends that regulators begin working
with industry and other stakeholders to develop and implement such systems.” The SEAB
recommended that authorities evaluate water use at the scale of affected watersheds, and
consider declaring unique and/or sensitive areas off-limits to drilling and support
infrastructure as determined through an appropriate science-based process.
A North American geological survey consultee expressed concern that water used during
hydraulic fracturing is ‘consumptive’: that is, the water is not returned to the hydrologic
system (North American geological survey consultation response 2012 NPR). This aspect of
HVHF requires further research.
British Columbia: The British Columbia Oil and Gas Activities Act was implemented in
October, 2010, in response to anticipated increased production of natural gas from shale,
tight sands, and coal beds. This act consolidated existing regulations, but also increased
protection of surface and ground water quality and fish and wildlife habitat. In BC, water is a
Crown resource, and the use of water for oil and gas activity requires approval from the BC
Oil and Gas Commission (Commission) which administers short term use of water by the oil
and gas industry through section 8 of the Water Act. Any oil and gas operator wishing to
withdraw water from a lake, stream, dugout or other water source for the purposes of oil and
gas activity is required to apply for and obtain a Section 8 approval. Applicants must provide
the proposed volume (m3) of water per day, total volume (m3) of water being applied for, and
the length of time for which the water withdrawal is being requested. Applicants must also
consult with First Nations. Water withdrawal data must be reported for each approved
withdrawal location. The provisions of this Act enable the British Columbia Oil and Gas
Commission to manage ground water and surface water withdrawals used for hydraulic
fracturing fluid make up. The commission ensures that the water drawdown does not affect
shoreline or aquatic habitat. A north American regulator considers that it is able to manage
watershed impacts on an integrated basis, using modelling techniques and information
provided by operators (Consultation Response 2012 NPR).
Susquehanna River Basin Commission (Pennsylvania, Maryland, New York, U.S. Army
Corps of Engineers) (SRBC) :SRBC regulates water withdrawals and consumptive water
uses. Natural gas companies need SRBC approval for surface water and groundwater
withdrawals and consumptive water uses. Many approvals require the withdrawal to be
interrupted at a prescribed low flow (called a passby flow condition). SRBC also assesses
the potential for adverse cumulative impacts from multiple withdrawals and could cap
quantities approved within a watershed to protect the water resources and downstream uses
(SRBC, 2012a NPR)
Delaware River Basin Commission (Delaware, New Jersey, New York, Pennsylvania, U.S.
Army Corps of Engineers) (DRBC) : DRBC developed draft regulations for natural gas
development in the Delaware River Basin to mitigate depletion and degradation of surface
and groundwater resources. The draft regulations were proposed in December 2010 and
revised in November 2011, but promulgation was postponed to allow additional time for
review by the DRBC organisations.
To reduce the risk of potential water source depletion, the draft regulations would require the
Commission to approve the use of basin water sources for natural gas development
activities. Approval would require that the proposed withdrawal
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
Not reduce the stream flow to less than the Q7-10 flow (an indicator of flow conditions
during a drought) or a more stringent value recommended by the appropriate host
state agency.

Not create short-term swings in surface flow volumes.

Not have a significant adverse effect on upstream or downstream dischargers (due to
loss of assimilative capacity), downstream withdrawers, wetlands, or aquatic life. Nor
may it adversely affect groundwater levels in the vicinity of the withdrawal or
diversion.
The draft regulations also required that water withdrawals be metered and recorded by
means of an automatic continuous recording device, or flow meter, and measured to within
5% of actual flow (DRBC, 2011 NPR).
Texas - Surface water is owned and managed by the State. Operators using surface water
must obtain a water rights permit from the Texas Commission on Environmental Quality. An
applicant may apply for a Temporary Water Right permit for short-term use of surface water.
Temporary Water Rights permits authorizing use of 10 acre feet [1,200 m3] or less and for
one year or less may be issued by a TCEQ Regional Office. In times of drought, the TCEQ
may suspend all temporary water rights permits. Water Rights permits for more water
quantity or longer time periods must be obtained through TCEQ Headquarters (Texas
Railroad Commission, 2012 NPR).
In Texas, groundwater is managed by landowners or groundwater conservation districts.
The groundwater wells are grouped into the following categories, each with different
permitting requirements:

Rig supply wells that do not penetrate the base of useable quality water;

Rig supply wells that penetrate the base of useable quality water;

Injection water supply wells that do not penetrate the base of useable quality water;
and

Injection water supply wells that penetrate the base of useable quality water.

Rig supply well: a water well drilled to supply water for a drilling rig

Injection water supply well: a water well drilled to produce water for hydrocarbon
recovery
Minimize water use (e.g. reuse produced water) and encourage use of lower quality
water
DRBC: In order to encourage the use of sources other than fresh water for hydraulic
fracturing of natural gas wells, the revised draft regulations provide for approvals for the
diversion into the basin (importation) of non-contact cooling water, treated wastewater that
meets certain criteria, mine drainage water, and recovered flowback and production water (if
within the same state) to be used in hydraulic fracturing. (DRBC, 2011 NPR)
US Department of Energy (SEAB 2011a NPR): Development and use of an integrated water
management system has the potential for greatly reducing the environmental footprint and
risk of water use in shale gas production and recommends that regulators begin working with
industry and other stakeholders to develop and implement such systems in their jurisdictions
and regionally.
Minimise impacts on biodiversity due to water use
When water is stored in surface impoundments, implement precautions to preclude the
transfer of invasive species into new habitats or watersheds.
For moving fresh water between sites and/or discharges, transport unused fresh water via
truck or pipeline to other drilling locations where it can be discharged into tanks or for
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subsequent use; if fresh water cannot be used at another drilling location, dispose of unused
fresh water over land (not in surface water or in manner that drains directly to surface water),
preferably in same drainage area as collected, and using appropriate erosion control
measures.
For vehicles and equipment used to withdraw and transport fresh water - Drain all hoses and
equipment at collection site after use; clean all mud, vegetation, organisms and debris and
dispose on site if the contaminants originated at site and dispose of properly. Before moving
to another water body, decontaminate equipment that has come in contact with surface water
using appropriate protocols (Pressure wash with hot water at contact point for 3 minutes or
disinfect with 200 ppm chlorine for 10 minutes; keep disinfection solution from entering
surface waters; and dry) (New York State DEC 2011 PR p7-97).
Control impacts due to disposal of treated waste water
Existing US guidelines under the Clean Water Act prohibit the discharge of oil and gas
extraction wastewater directly to surface waters. The US EPA is developing pretreatment
standards for discharges of shale gas extraction wastewater (flowback and produced water)
to municipal wastewater treatment plants (US EPA 2012g). The US EPA is also developing
effluent limitation guidelines for discharges of wastewater from coalbed methane extraction.
A proposal for unconventional gas extraction wastewater pretreatment standards is planned
for 2014.
Minimise truck traffic
Alternative approaches for reducing truck traffic could include:

waterless (or reduced water) fracturing

well pads that act as a hub to serve multiple well pads through a temporary piping
system

onsite treatment and reuse of produced water
A7.4.2 Industry measures
Established measures
Because of the importance of control of the hydraulic fracturing process, the majority of
relevant industry measures are laid down in established industry guidance such as API
guidance Document HF3 (2011 NPR).
Water source selection
The authority responsible for management of water resources should be able to advise on
acceptable levels of water abstraction on the basis of water resource modelling and
management techniques.
Fluid additives
Appropriate selection of hydraulic fracturing fluid is important to minimise risks of
environmental impacts (API 2011a NPR p7).
Spill prevention and mitigation
Prevention of spillage of waste waters is important. Spillage prevention and mitigation
measures are specified by API (2011a NPR p11). These include:

Planning and training. Contingency plan elements might include the following.
o
Modification of site layout or installation of new equipment or instrumentation,
as needed, including the use of alarms, automatic shutdown, fail-safe
equipment to prevent, control or minimize potential spills resulting from
equipment failure or human error.
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o
Maintenance and/or corrosion abatement programs to provide for continued
sound operation of all equipment.
o
Tests and inspections of lines, vessels, dump valves, hoses and other
pollution prevention equipment where failure(s) and/or malfunction(s) could
result in a potential spill incident.
o
Operating procedures that minimize potential spills.
o
Examination of field drainage patterns and installation of containment, barriers
or response equipment

Fracturing materials should be stored in such a way to prevent any accidental release
to the environment. Primary containment methods commonly used include tanks,
hoppers, blenders, sand separators, lines and impoundments. It is recommended
these primary containers be visually inspected before and during the fracturing
operation to ensure integrity.

The use of techniques such as sloping the well location away from surface water
locations, positioning absorbent pads between sites and surface waters, and
perimeter trenching systems and catchments may be used to contain and collect any
spilled fluids.

Operators should evaluate the potential for spills and damages and use this
information to determine the type and size of primary and secondary containment
necessary. Contingency elements might include the location of emergency
equipment, the type(s) of materials and products that can be used effectively for
clean-up, and sources and procedures for using these chemicals. Spill response
drills/simulations should include participation of relevant contractor personnel.

In the event a spill occurs, the source of the spill should be controlled, or reduced to
the extent possible, in a safe manner. The release should be confined or contained
to minimize potentially adverse effects. Methods to control and contain spilled
substances include:
o
retaining walls or dikes around tanks;
o
sluice gates;
o
secondary catchment basins designed to prevent the spread of fluids that
escape the primary wall or dike;
o
absorbent pads;
o
booms in water basins adjoining the facility;
o
use of chemicals to gel or bio-degrade the spilled fluids.
Control of fracturing operation
Predictive modelling is used in conjunction with drillers’ logs and available geological data to
optimize fracture strategies (e.g. Yang, 2011 PR). Planning activities can be limited by a lack
of detailed geologic data. Useful data can often be obtained from previous well completions
in nearby areas. Operators should plan the hydraulic fracturing process to ensure that
fracturing takes place only in the target reservoir using techniques such as the following (ALL
Consulting 2009b NPR p17). This has both commercial/technical and environmental
benefits:

Geology & lithology studies

Coring and core analysis

Geophysical logging

3D Seismic surveys
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
Correlation Analysis

Fracture gradient analysis
Well integrity should be tested prior to perforation. Testing assures that all equipment is
operating properly and is providing accurate reporting. Pressure testing should be
conducted on mechanical pumps and piping to the fracturing pressure before fracturing
commences (API 2011a NPR p9). Chemical additive pump assurance tests should be
carried out before fracturing.
A pumping schedule should be designed which specifies the quantity of fluid and each
chemical being pumped into the perforations and below the packer. Pre-job safety meetings
with on-site staff should be carried out, to cover issues such as maximum pumping rates,
downhole pressure, annulus pressure, safety precautions, and the order of operations.
Contingency planning should be carried out to address equipment failures and unexpected
fracture progression. Specific responsibilities should be allocated to on-site staff to ensure
that corrective actions are taken immediately and effectively to address problems that arise
during fracturing. The quantity of fluid required for a fracturing process can usually be
accurately forecast, but unforeseen circumstances can occur which result in unpredictable
changes in the quantity of required fluid during the middle of an operation (API 2011a NPR
p10). Spillage prevention measures are described by API (2011a NPR p11).
Downhole pressure and acid storage tank pressure should be monitored when applying an
acidizing matrix before pumping fracturing fluid. The wellhead, annulus, and downhole
pressures, pumping rates, fracturing fluid density, and additive/proppant volumes and rates
should be monitored during fracturing to identify potential issues.
Geophysical methods (e.g., microseismic fracture mapping, tilt-meter analysis) should be
used to track fracturing progress and identify potential issues (SEAB, 2011a NPR).
Action levels for monitored parameters should be specified and agreed prior to initiating
fracturing process. It is important to develop action levels for monitored parameters before
fracturing activities begin, so that on-site personnel can identify problems and take action
immediately. For example, field personnel should be aware of maximum allowable downhole
pressures during each stage of fracturing, so that corrective action can be taken immediately
if necessary. Based on the designated action levels for monitored parameters, ensure action
is taken when appropriate.
Piping, equipment and liner materials must be compatible with the injectate and produced
water. Chemical treatments and cathodic protection can be used to minimize scale and
corrosion. Chemical corrosion inhibitors are potentially harmful, so it is important to use
these treatments conservatively. Lead-free pipe dope materials should be used where
possible. The quantity used should be minimised. If excess dope material is used, it must
be chemically treated and eliminated to prevent the possibility of this material reaching the
wellbore.
Treatment of waste waters
For any re-use/treatment/disposal option, it is important to verify that the approach is able to
handle the waters produced to a satisfactory standard of treatment. Any treatment method
must take account of the potential presence of naturally occurring radioactive material
(NORM).
Waste waters can be discharged to existing industrial or municipal sewage works. This
introduces a requirement to transport waste waters to the disposal facility. Again, it is
important to verify that the receiving works is able to handle the waters produced to a
satisfactory standard of treatment. The availability of capacity and adequacy of treatment
methods has been raised as a matter of concern by the EPA in relation to areas of intensive
shale gas development in the US (EPA 2011a PR p49-53).
Ref: AEA/ED57281/Issue Number 17
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Finally, if disposal by reinjection is required, appropriate practices for reinjection are set out
in the US EPA’s Underground Injection Control (UIC) Program (USEPA 2012b NPR ; ALL
Consulting, 2010a NPR). The UIC Program is responsible for regulating the construction,
operation, permitting, and abandonment of injection wells that place fluids underground for
storage or disposal. However, injection into aquifers would not be permitted in Europe
(European Commission 2011a NPR ; see Section 3.17).
Recommended measures
Control of hydraulic fracturing
The International Energy Agency (2012 NPR p13) recommended that monitoring should be
carried out to ensure that fractures do not extend beyond the target formation.
Water source selection
The following approaches can be used to manage environmental impacts at the water source
selection stage:

Working with local water resource planners to optimize source selection. Some well
sites may be close enough to one another to justify reuse of produced water in
nearby wells.

Avoiding sensitive areas for water withdrawals (e.g., headwater tributaries, small
surface water bodies, sensitive ecosystems).

Developing strategies to eliminate or reduce the potential for transferring invasive
species between sources.
Use of temporary pipeline
Water can in some cases be transported by pipeline rather than by road to reduce
environmental impacts (API 2011a NPR p8; Peloquin, 2012 NPR). When temporary surface
pipes are installed adjacent to the access road or gas collection piping, no additional land
disturbance is required.
Hydraulic fracturing can require up to 25,000 cubic meters of make-up water per well. At 90
m3 per storage tank, 280 tanks would be required to store this volume. Assuming tank
footprint of 13.6 m × 2.4 m (Adler Tank Rentals, 2012 NPR), make up water tanks would
require at least 9,200 square metres (0.92 hectares) of cleared, levelled land. Assuming 7
wells per pad, development of 70 wells would require 9.2 hectares for water storage. Piped
water can be stored in a central location and piped to each well site during the hydraulic
fracturing stage (Kepler 2012 NPR). For example, a US operator developed a single
impoundment with a footprint of approximately 4 hectares, to serve a 70-well development
project. Thus, piping water reduced land take for storage from 9.2 hectares (or more) to 4
hectares. The main motivation from an operator perspective for piping water is to eliminate
hauling water by truck (Kepler 2012 NPR).
Water storage
Water storage should be carefully planned to consider land use, impacts on invasive and
endangered species, and mosquito control.
Treatment of waste waters
SEAB (2011a NPR) recommends that measurement of the composition of the stored return
water should be a routine industry practice. The International Energy Agency (2012 NPR
p14) recommended that water should be reused or recycled wherever possible.
The ability to treat water on-site and reuse in later fracturing operations is becoming more
widespread. Techniques used to treat water at the well site include thermal evaporation,
crystallization and destabilization technology. Using these systems, some companies in the
Marcellus Shale are able to recycle more than 90% of their return water, although not all the
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fracturing fluids are returned to the surface. The elevated salinity of recycled waters can
adversely affect the performance of friction reducers (ALL Consulting 2011 NPR p21), but
recent innovations have addressed this problem (Consultation response Prof. R Vidic,
University of Pittsburgh, 2012 NPR). Other beneficial uses may also be available for
produced water, to minimize treatment requirements (e.g. biofuels production).
If storage tanks are not available and surface impoundments/pits are required for produced
water, run-on/runoff control should be used. Pond locations should take account of the local
topography, in order to minimise surface drainage into ponds. Purpose built lagoons with
double liners should be used to hold fracturing waters prior to treatment and reuse
(Rassenfoss, 2011 NPR).
Dust control
Mobile bag houses can be used to control dust emissions from potentially dust-generating
proppants such as sand (Kellam, 2012 NPR).
Measures under consideration
Water source selection
The following approaches can be used to manage environmental impacts at the water source
selection stage:

Identifying opportunities for reusing produced water, industrial wastewater, or other
impacted, low-quality water sources.

Considering the location and timing of water withdrawals to minimize resource
impacts. For example, withdrawals could be made during high-flow seasons and
stored in surface impoundments.

Abstract water from saline aquifers, if the salt content can be managed via pretreatment, as has been carried out at Marcellus Shale gas wells in
Pennsylvania(Rassenfoss 2011 NPR p49).

Abstract water from seawater (North American regulator consultation response 2012
NPR), if appropriate to the location. Research is currently being carried out in
Canada and Europe into the use of seawater for hydraulic fracturing (Bukovac et al,
2009 NPR).

Use acid mine drainage (AMD) as make-up water (Consultation response Professor
R Vidic, University of Pittsburgh 2012 NPR). This is problematic because of the low
pH; sulphate levels potentially leading to the formation of hydrogen sulphide or
barium sulphates; and risks associated with storage of AMD. Research is being
carried out into treatment processes for blending AMD and flowback water to produce
a liquid suitable for fracturing.
Fracturing fluid additives
A number of suppliers have begun developing hydraulic fracturing fluids that could exclude
the use of toxic chemicals. For example, hydraulic fracturing fluids utilizing additives sourced
from the food industry are being developed by the industry. The chemical composition of
these fluids has not been published by the manufacturers.
Many biocides used in fracturing fluids are potentially harmful to aquatic life, even at low
concentrations. It is preferable to avoid these additives if possible, and generally minimize
biocide usage. Alternative non-chemical treatments are available such as UV disinfection.
UV light can be used to control bacteria growth in the wellbore, reducing the need for
biocides in hydraulic fracturing fluid.
Viscoelastic based fluids can be used in place of polymer based fluids in order to reduce the
wellbore damage and the elimination of subsurface leakage.
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Selection of proppants which increase porosity inside the fracture can be beneficial in
reducing the extent of treatment required. A sieve analysis can be carried out to assist in
identifying the most appropriate proppant for use in a specific application.
Operators should continue to research and evaluate new fracturing fluid products which
provide improved environmental protection opportunities (API 2011a NPR p7).
One option for disposal of produced waters is to install a treatment system to reduce the
chlorides and total dissolved solids in produced water (ALL Consulting 2011 NPR p30).
Treatment options include: distillation, ion exchange, membrane treatment such as reverse
osmosis, and drying technologies such as vapour compression and evaporation (ALL
Consulting 2009b NPR p25; ALL Consulting 2011 NPR p26). By allowing local re-use or
disposal, this approach can reduce the requirement for off-site transportation of produced
water. It is important to be confident that any on-site treatment facilities deliver an
appropriate standard of treatment for the waters produced, and the intended end-use.
The International Energy Agency (2012 NPR p13) recommended that operational data on
fracturing fluid additives and volumes, water usage, and the quantity and nature of waste
water should be published.
Treatment of waste waters
Where possible, produced waters should be considered for re-use in future drilling and
fracturing operations (Howarth and Ingraffea, 2011 NPR ; Lior, 2011 PR ; Rassenfoss, 2011
NPR). Produced water that is unsuitable for reuse may be treated using a variety of
technologies. Treating a portion of produced water and blending it with fresh water may lead
to a suitable option for reuse.
Closed loop management systems significantly reduce the footprint of a well pad by
removing the need for storage pits on location as all drilling and water wastes are channelled
through mechanical systems and stored in steel containers on-site (Oil and Gas
Accountability Project, 2012 NPR). This process not only reduces land needed but also
removes any opportunity for drill cuttings and produced water to come into contact with the
natural environment.
The availability of capacity and adequacy of treatment methods has been raised as a matter
of concern by the EPA in relation to areas of intensive shale gas development in the US, and
future EPA research will be focused in this area (EPA 2011a PR p49-53).
A7.4.3 Summary
As described in Section 2, the potentially significant issues associated with Technical
Hydraulic Fracturing stage are water resource depletion, emissions to air, groundwater
contamination risks, and road traffic. There may also be less significant issues associated
with surface water contamination risks, biodiversity, noise and visual impacts during this
stage.
Sourcing of water for hydraulic fracturing is a potentially significant feature of HVHF
operations. Measures can be taken to reduce the impact of water sourcing, including water
resource management by regulators, use of water from saline aquifers or seawater if
practicable, the use of temporary pipelines to transport water; and the recycling of flowback
waters for use in hydraulic fracturing. However, there will remain a potentially significant
need for water during the hydraulic fracturing stage which cannot be completely eliminated.
For this reason, there is likely to be an ongoing requirement for road transportation which
cannot be fully eliminated. Plant and equipment at the site will give rise to emissions to air,
which could potentially be mitigated by the use of gas-powered plant if appropriate plant and
fuels are available, but cannot be completely eliminated.
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Established procedures are available for regulators to be notified of and agree the chemicals
to be used during hydraulic fracturing and the control to be applied during the fracturing
stage (e.g. via permitting arrangements).
Experience in the US is that hydraulic fracturing operations can normally be carried out
without significant environmental or health impacts, provided appropriate measures are taken
to control impacts. Unforeseen events can occur which result in unexpected impacts, such
as a gas blowout. Contingency measures should be in place to deal with events such as
this. Also, where design, operation or monitoring falls below the appropriate standard, the
risk of impacts could increase.
The control measures set out in this section are implemented by regulators and the industry
in areas where HVHF is established. Under these conditions, they are considered to be
affordable. Such measures are considered on balance likely to be affordable in a European
context, but the potential influence of these costs on shale gas project viability cannot be
evaluated at this stage, and will depend on the forecast revenues from shale gas extraction
in Europe.
A7.5 Well Completion
A7.5.1 Regulatory measures
Control of emissions to air
The SEAB (2011a NPR p16-18) recommends the development and adoption of air emission
standards for methane, air toxics, ozone-forming pollutants, and other airborne
contaminants. It was recommended that regulators should support projects to design and
rapidly implement measurement systems to collect comprehensive methane and other air
emissions data. Industry and regulators should expand efforts to reduce air emissions using
proven technologies and practices. It was recommended that the emissions rules adopted in
the state of Wyoming represent a good starting point for establishing regulatory frameworks
and for encouraging industry best practices.
Reduced Emission completion
US EPA Office of Air and Radiation, Office of Air Quality Planning and Standards: under the
authority of the Clean Air Act, the EPA issued New Source Performance Standards (NSPS)
and Amendments to National Emission Standards for Hazardous Air Pollutants (NESHAPs)
for the Oil and Natural Gas industry on 17 April 2012 (see USEPA 2011b NPR). This will
become effective 60 days after publication in the Federal Register, which is expected in the
near future. The NSPS include standards for volatile organic compounds from gas well
completions, based on “reduced emission completion” where gas flowback that is otherwise
vented is captured, cleaned, and routed to the sales line. This would potentially be effective
in:

Reducing emissions of VOCs

When gas cannot be collected, VOCs would be reduced through pit flaring, unless it
is a safety hazard.

Methane, a potent greenhouse gas, also would be significantly reduced as a cobenefit of reducing VOCs.
Industry consultation responses to EPA’s draft NESHAPs document suggest that the EPA
has overestimated the methane reductions that can be expected to arise from these
measures.
The green completion requirements would not apply to exploratory wells or delineation wells
(used to define the borders of a natural gas reservoir), because they are not near a sales
line. Those wells must use pit flaring to burn off their emissions, unless it is a safety hazard
Ref: AEA/ED57281/Issue Number 17
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(US EPA 2012c NPR) or on the case of low pressure wells where gas cannot be routed to
the gathering line. Howarth and Ingraffea (2011 NPR) suggest that minimisation of fugitive
emissions to air requires the application of strict regulatory controls to ensure a high standard
of control and maintenance.
US Department of Energy SEAB (2011a NPR) supports this approach: Methane leakage and
uncontrolled venting of methane and other air contaminants in the shale gas production
should be eliminated except in cases where operators demonstrate capture is technically
infeasible, or where venting is necessary for safety reasons and where there is no alternative
for capturing emissions. When methane emissions cannot be captured, they should be
flared whenever volumes are sufficient to do so.
British Columbia: Venting is generally prohibited and flaring must be minimized: B.C. Reg.
282/2010, Drilling and Production Regulation, Part 7 — Safety, Security and Pollution
Prevention, 41. “Venting and fugitive emissions” states that a permit holder must not vent
gas unless the gas heating value, volume or flow rate is insufficient to support stable
combustion. Section 42 “Flaring limits” states that a permit holder must ensure that the
duration of flaring and the quantity of gas that is flared is minimized (British Columbia State,
2010 NPR). There is a further commitment to eliminate routine flaring at oil and gas wells
and production facilities in British Columbia by 2016 (British Columbia OGC 2009 NPR).
Degas produced water prior to reuse
No government requirements to degas produced water prior to reuse were identified.
Limit use of open tanks and pits for produced water storage
US EPA: combustion controls must be applied to any tank emitting more than 6 tons VOCs
per year.
Wyoming – Limits are applied for concentrated development areas (that is, seven specified
counties in Wyoming) and the Jonah Pinedale Anticline Development Area (defined as
specific sections of Sublette County, Wyoming). Open-top or blow down tanks shall not be
used as active produced water tanks but may be used for blow down or for temporary
storage during emergency or upset conditions, such as spare tanks at facilities connected to
liquids gathering systems, and do not have to be tied into 98% control systems. (Wyoming
State, 2010 NPR)
Controls on produced water storage tank vents
Colorado: Colorado Department of Public Health and Environment requires 90% reduction in
uncontrolled VOC emissions during the ozone season (May 1 to September 30) and 70%
reduction in uncontrolled VOC emissions during non-ozone season in non-attainment areas.
Operators are required to meet the reductions system-wide (i.e., not every tank must be
controlled). Tank batteries (i.e., groups of tanks) with combustion devices for VOC control
must have auto-igniters. Tank batteries with uncontrolled VOC emissions greater than 100
tons per year [91 metric ton/year] shall have electronic or manual surveillance systems to
monitor the combustion device daily. Statewide, condensate storage tanks with >20 tpy [18
metric ton/year] uncontrolled VOC emissions must control emissions by 95% (CODPHE,
2011 NPR).
Wyoming: In concentrated development areas and the Jonah Pinedale Anticline
Development Area, new and modified facilities shall control VOC and HAP emissions from all
active produced water tanks by at least 98%. (Wyoming State, 2010 NPR)
Replacement of diesel-powered engines
Natural gas powered engines and electric motors can be used in place of diesel engines in
some applications.
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
US Department of Energy, Secretary of Energy Advisory Board: recommends reducing the
use of diesel engines for surface power in favour of natural gas engines or electricity where
available (SEAB, 2011a NPR p24).
Wyoming Federal Lands (Managed by US Department of Interior, Bureau of Land
Management): This project is working towards achieving zero days of modelled visibility
impairment from drilling operations using mitigation controls on engines, including (BLM,
2008 NPR):

Replacing diesel-fired drilling rig engines with natural gas-fired drilling rig engines,

Requiring Tier 2 equivalent (or better) emissions on drilling rig engines,

Installing selective catalytic reduction on drilling rig engines,

Using electric drilling rigs.
Use low-bleed or no-bleed pneumatic controllers
US EPA: A New Source Performance Standard (NSPS) now applies to pneumatic controllers
in the US, requiring emissions to be limited to 0.17 m3/hour.
Colorado: CODPHE requires pneumatic controllers installed in non-attainment areas after
2/1/2009 shall emit ≤6 scfh[0.17 m3 per hour] of natural gas (low bleed definition). Existing
pneumatic controllers shall be retrofit to meet the low bleed definition by 5/1/2009.
(CODPHE 2011 NPR)
Prohibit discharge of untreated produced water to surface water and to POTWs
US EPA Office of Water, Office of Science and Technology establishes regulations to control
wastewater discharges to surface water, under the authority of the Clean Water Act. Existing
guidelines prohibit discharge of oil and gas extraction wastewater directly to receiving
streams. The EPA is (US EPA 2012d NPR):

Developing pre-treatment standards for discharges of shale gas extraction
wastewater (flowback and produced water) to municipal wastewater treatment plants,
including evaluating economic impacts. Draft standards are scheduled for proposal in
2014.

Developing effluent limitations guidelines for discharges of coalbed methane
wastewater, including evaluating economic impacts. Draft regulations are scheduled
for proposal in 2013.
British Columbia: prohibits discharges of oil and gas wastewaters to surface waters: B.C.
Reg. 282/2010, Drilling and Production Regulation, Part 3 — Well Position, Spacing and
Target Areas, Division 4 – Procedures, 51. Storage and disposal of wastes (1) A well permit
holder must ensure that produced water, oil, drilling fluid, completion fluid, waste, chemical
substances or refuse from a well, tank or other facility do not do any of the
following:….(b) run into or contaminate any water supply well, usable aquifer or water body
or remain in a place from which it might contaminate any water supply well, usable aquifer or
water body; (British Columbia State, 2010 NPR).
Rassenfoss (2011 NPR) suggests that authorities could prohibit discharge of produced water
to treatment works if necessary. Because of the lack of proven alternatives to treatment and
disposal, this could present a significant barrier to the development of shale gas resources in
Europe. Re-use remains an option for produced water, but it may not be possible to re-use
all the water produced because of its chemical characteristics, and/or if there are insufficient
new wells being development to accommodate the produced water from existing wells
(Consultation response Professor R Vidic, University of Pittsburgh 2012 NPR).
Ref: AEA/ED57281/Issue Number 17
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Establish treatment requirements/discharge limitations for produced water
Pennsylvania: In August 2010, Pennsylvania finalized regulations limiting discharges of total
dissolved solids, total chlorides, barium, and strontium to surface waters in the state. These
regulations are codified at PA Code §95.10. The regulations apply to discharges from
commercial waste treatment (CWT) plants to municipal wastewater treatment plants as well
as from CWT plants directly to receiving streams. The PA limits are (Pennsylvania State,
2010 NPR):
Table 13: Pennsylvania Regulations for Unconventional Gas Production Wastewaters
Parameter
Maximum monthly average (mg/L)
Total Dissolved Solids
500
Total Chlorides
250
Barium
10
Strontium
10
A7.5.2 Industry measures
Established measures
No specific required industry measures for completion were identified.
Recommended measures
Reduced Emission Completions (see USEPA, 2012c NPR) can be used to minimise
emissions to air from flowback and produced water. The flowback, natural gas, and
condensate are collected, and dissolved gas is separated from the waters. Gas collected in
this way is routed to the sales line. If a sales line is unavailable, emissions should be routed
through a flare. VOC and HAP emissions from produced water can be minimised by the use
of equipment such as closed tanks, hydrocyclones and water tank blankets. Hydrocyclones
separate gas from water below the surface, reinjecting the water into a lower lying disposal
aquifer and sending the methane to the surface. CO2-rich produced gas is ideal for water
tank blankets. Reduced Emission Completions are not always applicable, and can be
particularly problematic and even counter-productive for low-pressure wells (BP, 2012b
NPR).
Flash losses can be minimised by reducing the operating pressure of low-pressure
separators that dump to storage tanks. The use of pressure tanks for storage should be
minimised. Vapour recovery technology should be used when available; alternatively,
emissions can be discharged to a flare with an auto-igniter.
Flaring is likely to be necessary for sites where exploratory drilling is being carried out in
advance of the availability of gas collection infrastructure. Flaring may be required in
response to plant failure, or if back-pressure from gas compressor plant and pipeline
infrastructure causes problems with the flow of gas and waters from the well. This can be a
particular issue at wells with lower gas pressures than expected (BP 2012b NPR), and hence
the EPA excluded low pressure wells from the requirement to use reduced emission
completion or flaring to eliminate VOC venting in the April 2012 NSPS. Flaring should be
minimised and, where possible, eliminated (Dogwood Initiative, undated; British Columbia
OGC, 2009 NPR ; International Energy Agency 2012 NPR p14). British Columbia OGC
prohibits flaring of gas during completion at wells within 1.5 km of a collection pipeline (North
American regulator consultation response 2012 NPR).
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Measures under consideration
Emissions to air
Emissions from dehydrators can be minimised by replacing glycol systems with desiccant
dehydrators, low/zero emissions dehydrators (ZED) or solar methanol injection systems. If
possible, it is preferable to avoid using a glycol dehydration system, which continuously vents
methane, VOCs, and HAPs. Operators can choose Zero Emissions Dehydrators or solar
methanol injection systems. ZEDs have several advantages:

By using a desiccant dehydrator, operators also save on costs: desiccant dehydrators
require less capital investment and less operations and maintenance.

In a desiccant dehydrator, wet gas passes through a drying bed of desiccant tablets.
The tablets pull moisture from the gas and gradually dissolve in the process. Since
the unit is fully enclosed, gas emissions occur only when the vessel is opened, such
as when new desiccant tablets are added.

ZED collect condensable components from the still column vapour and use noncondensable still vapour (methane and ethane) as fuel for the glycol re-boiler. A
water exhauster is used to yield high glycol concentrations without the use of a gas
stripper.
In contrast, glycol dehydrators have several disadvantages (USEPA, 2006 NPR ; Natural
Gas Star 2011 NPR):

Methane absorbed and vented is directly proportional to the glycol circulation rate.
Many wells produce gas below design capacity and circulate glycol at rates higher
than necessary. This results in marginally lower gas moisture but much higher
methane emissions and fuel use.

Maintenance of glycol dehydrators often requires a complete shutdown. During
maintenance, production wells are shut in or vented. Low pressure wells are often
vented because it can be difficult to resume flow once they are shut in.

Gas-assisted glycol pumps increase emissions from dehydrator systems by passing
the pneumatic driver gas to the reboiler.
Flash tank separators can be installed on glycol dehydrators to reduce methane, volatile
organic compound (VOC), and hazardous air pollutant (HAP) emissions. Recovered gas can
be recycled to the compressor suction and/or used as a fuel for the glycol reboiler and
compressor engine. Non-condensable still vent and glycol flash separator vapours can be
routed to a combustion unit, or can be used as fuel for process equipment burners. Portable
desiccant dehydrators can be used during glycol dehydrator maintenance.
Cyclone separators and in-line heaters can be used in place of glycol recirculation units. The
separators use refrigeration to enhance water condensation and separation, and the gas is
then reheated so that it will be below dew point anywhere in the system.
It was recommended that monitoring for verification of emissions inventories should be
carried out by independent regulatory authorities (Academic sector consultation response
2012 NPR).
A7.5.3 Summary
As described in Section 2, the potentially significant issues associated with this stage are
risks of groundwater and surface water pollution. There may also be less significant issues
associated with biodiversity and traffic-related impacts during this stage.
The key issues during this stage are the handling and disposal of flowback water. The
control of spillages and other accidental discharges is important. Risks posed by spillages
can be minimised by measures taken during the site identification and development stage.
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Emissions to air from pollutants entrained in the flowback water can be controlled by using
reduced emission completions. Other air emissions are also controlled via measures which
are common to conventional oil and gas production facilities. However, the nature of shale
gas formations is that the use of hydraulic fracturing techniques could potentially open up
developments over a wide area. This could potentially give rise to cumulative effects on air
quality during the production phase. Measures to assess and reduce emissions to air are
available, but intensive development in some areas could potentially mean that it may not be
possible to reduce emissions sufficiently to avoid air quality issues. In Europe, air quality
issues such as this may be managed via the permitting and strategic planning process,
deriving standards for air quality from the relevant Air Quality Framework and Daughter
Directives, although this would require further analysis as the examination of national
requirements was not in the scope of this study.
The control measures set out in this section are implemented by regulators and the industry
in areas where HVHF is established (i.e. North America). Under these conditions, they are
considered to be affordable. Such measures are considered on balance likely to be
affordable in a European context, but the potential influence of these costs on shale gas
project viability cannot be evaluated at this stage, and will depend on the forecast revenues
from shale gas extraction in Europe.
A7.6 Well Production
A7.6.2 Industry measures
Fugitive emissions controls
Detailed methods for fugitive emissions controls are provided via EPA’s Natural Gas Star
Program (Natural Gas Star, 2012 NPR). These methods include:

Survey for leaking components in the first year of a directed inspection and
maintenance program. In subsequent years, focus inspection and repair on
components that are the most likely to leak and that represent cost-effective
emissions reduction.

Use of enhanced sensing to locate leaks where appropriate. Enhanced sensing
includes technologies such as Infrared, Differential Absorption Lidar, Tunable Diode
Laser Absorption Spectroscopy, and ultrasound

Replace equipment with low-leak components (e.g., low or no-bleed pneumatic
controllers, electronic valve systems, compressed air).

Construct pipelines with automatic cutoff valves that isolate sections when pressure
drops. Trip‐wires laid on top of the pipelines will break and activate cutoff valves
when severed

Spray gravel roads near populated areas with dust suppressant during dry periods.

Reduce the number of storage tanks containing VOCs.
Automatic control systems (e.g., programmable compressor ignition systems) can be used to
reduce startups and shutdowns. Programmable Logic Controllers (PLCs) are used to
increase the operational efficiency and reliability of the compressor and also reduce methane
emissions. PLCs incorporate features such as unit performance, process calculations, unit
load management, independent safety shutdown, and automated backup control.
A7.6.3 Summary
As described in Section 2, the potentially significant issues associated with the production
stage are groundwater contamination risks and emissions to air. There may also be less
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
significant issues associated with surface water contamination risks and land take during this
stage.
The risks to groundwater are associated with ongoing well integrity. This may be a
particularly significant issue if re-fracturing is carried out: it is estimated that this may take
place up to four times during a 40 years well lifetime. Well integrity needs to be maintained
and monitored on an ongoing basis. Measures for ongoing well maintenance are not specific
to HVHF processes, and have not been addressed specifically in this report.
Land take impacts can be mitigated by the measures described in Section A7.1.
Additionally, regulators can require the rapid restoration of land which is no longer needed
during the production stage. However, as noted in Section A7.1, it may not be possible to
fully restore some sites to their previous use, resulting in a potentially significant ongoing
impact.
The control measures set out in this section are implemented by regulators and the industry
in areas where HVHF is established. Under these conditions, they are considered to be
affordable. Such measures are considered on balance likely to be affordable in a European
context, but the potential influence of these costs on shale gas project viability cannot be
evaluated at this stage, and will depend on the forecast revenues from shale gas extraction
in Europe.
A7.7 Well / Site abandonment
A7.7.1 Regulatory measures
A geological survey consultee commented that the current information base extends over
approximately 10 years only, and recommended that ongoing research would be required in
the post-abandonment phase to ensure that any long-term impacts associated with HVHF
can be identified and addressed (North American geological survey consultation response
2012 NPR).
Procedures for well pad removal (site restoration)
British Columbia: B.C. Reg. 282/2010, Drilling and Production Regulation, Part 3 — Well
Position, Spacing and Target Areas, Division 4 — Procedures, 28,“Surface restoration of
wells and associated sites.” This state that immediately after ceasing drilling or workover
operations, or as soon after cessation as weather and ground conditions permit, a well permit
holder must restore the ground surface of those areas of the well site and associated remote
sumps and camp sites that will not be required for future operations to a state that eliminates
hazards, enables control of weeds and runoff and prevents erosion.
Plugging of abandoned wells, with permitting and inspection requirements.
Operators in the US may stop production from a well either temporarily or permanently.
States have developed different requirements for temporary shut-in and permanently
abandoned wells; shut-in wells have monitoring requirements, while abandoned wells are
completely reclaimed. States limit the length of time an operator can shut-in a well. Of the
state regulations reviewed, most did not distinguish between conventional and
horizontal/directional or hydraulically fractured wells. Only Wyoming had specific provisions
for plugging horizontal wells.
Shut-In (Temporary) wells: This is defined as a well which is capable of production, but
which is not being produced for various reasons (e.g., lack of production facilities, lack of
market, maintenance) (16 TAC §9.31(b)(9); COGCC §100(G)).
Plugging Requirements:
Colorado: Close the well to the atmosphere with a swedge and valve or packer (COGCC
§319(b)(1))
Ref: AEA/ED57281/Issue Number 17
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hydrocarbons operations involving hydraulic fracturing in Europe
Post-Shut-In Monitoring Requirements:
Colorado: Requires shut-in wells pass a mechanical integrity test within 2 years of initial shutin and every 5 years thereafter (COGCC §326(b)).
Pennsylvania: Requires good well construction; monitoring of liquid in the well for TDS to
determine if surface casing is deep enough and not leaking; every 90 days, monitor flow of
gas from annulus (25 PA Code §78.102); annual mechanical integrity monitoring (25 PA
Code §78.103).
Wyoming: May require shut-in wells requesting extension of temporary status to pass a
mechanical integrity test (WYOGCC 16(c)).
Abandonment (Permanent):This is defined as a well which has been cemented in,
associated production facilities (e.g., tanks, flare, gas pipelines) have been removed, and the
well pad has been reclaimed (COGCC §100(F)).
Examples of State Requirements for Abandonment are as follows:
Wyoming: Wells without production casing must be filled with fluid consistent to what was
used to drill the well and plugged with at least 100 feet [30 m] of cement over the open hole
porous and permeable formations, at least every 2500 feet [760 m] if nonporous and
impermeable, base of the surface casing. Wells with production casing must be plugged with
at least 100 feet [30 m] of cement every 2500 feet [760 m] in the base of the surface casing
and at least 100 feet [30 m] in the casing at the surface, and cement isolating the perforated
zones, with drilling fluid between all plugs. Horizontal wells shall have a continuous
cement plug 100 feet[30 m] into the lateral and 100 feet [30 m] into the vertical portion
of the wellbore; remaining vertical wellbore shall be plugged in accordance with the
preceding requirements. (WYOGCC 18)
Colorado: Cement plugs should be at least 50 feet [15 m] in length and extend a minimum of
50 feet [15m] above each zone to be protected. Plugs should be made of neat cement slurry
mixed to API standards with at least 300 psi [2.1 MPa] compressive strength after 24 hours
and 800 psi [5.5 MPa](after 72 hours measured at 95 °F [35°C] and at 800 psi[5.5 MPa].
Abandonment must be completed within six months. (COGC §319(a))
Illinois: Cement plugs must extend 50 feet [15 m] below the deepest perforation, and extend
to 50 feet[15 m] above the shallowest perforation. The plug should extend 50 feet [15 m]
above and below the exposed zone in uncased wells. (62 Illinois Administrative Code
Section 240.1150)
Texas: Cement plugs in surface and production casings shall extend at least 50 feet [15 m]
above and below the base of the deepest usable aquifer. Plugs in intermediate casings must
be placed extend no less than 50 feet [15 m] above and below the base of the deepest
usable aquifer. (16 Texas Administrative Code §3.14)
Pennsylvania: Cement plugs shall be set in the cemented portion of the production casing
extending at least 50 feet [15 m] below and 100 feet [30 m] above each fluid-bearing stratum.
(25 PA Code §78.91 through 97)
Oklahoma: Before or after running a plug, the operator shall remove all fluid from the
wellbore, and fill the wellbore and/or casing with plug mud. The minimum mud weight shall
be nine pounds per gallon with a minimum viscosity of 36 using the API Full Funnel Method.
The wellbore shall be filled with cement from 50 feet [15 m] below to 50 feet [15 m] above the
base of the treatable water zone (or to three feet [0.9 m]below surface). (OK Reg 165:10-116(e))
Bonding
All operators are required to have financial security for the wells through performance bonds
on an individual well or a field of wells.
Ref: AEA/ED57281/Issue Number 17
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hydrocarbons operations involving hydraulic fracturing in Europe
In the US, bonding requirements are laid down by the permitting authority –in most instances
this is the State, but may be tribal or federal authority depending on whether the federal
program was delegated to the states or tribes. Each state has different bonding
requirements (e.g., bond structure (well, lease, statewide), what types of bonds they can
receive, the amount required, what they cover, when they are released). No bond
requirements were identified which are specific to hydraulically fractured wells. Federal
requirements are laid down in 43 CFR §3104. These requirements were most recently
updated in 1988, prior to the boom in hydraulic fracturing in the US. Sections 3104.2 and
3104.3 describe the bond structure and include minimum bond amounts of up to USD
$150,000.
Bonds cover issues related to pit construction, seismic operations, inactive wells, plugging
and abandonment. Bonds are normally linked to plugging liability (ALL Consulting, 2010a
NPR p24). The bond period is normally specified to end when the well is permanently
plugged and abandoned, and would therefore not cover post-abandonment issues under US
arrangements.
Financial arrangements in relation to Carbon Capture and Storage projects are discussed in
Section A7.9.
A7.7.2 Industry measures
Established measures
The following measures are adopted by industry in relation to idle wells

Maintain wellheads during layup.

Conduct site inspections every 90 days where possible to identify any visual signs of
damage to the wellhead or pad area. Idle wells may be located in remote areas,
making regular inspections of the well site difficult.

Idle wells should be constantly re-evaluated to ensure that they are closed as soon as
necessary.
A combination of cement plugs and mud is placed in the wellbore prior to abandonment. It is
important that the plugs are designed to prevent a micro-annulus from forming. Materials
used should be appropriate for the local hydrogeology. Typically, natural bentonite mud is
ideal for abandonment because it has good gel-shear strength and is less likely to separate
with time. As well as achieving a high standard of sealing, it is important that an ongoing
monitoring programme is carried out, and clear records of well location and depth are
maintained indefinitely.
Recommended measures
Any surface impoundments can be closed in a timely and effective manner after a well has
ceased to be active in producing gas.
Well pads can be remediated on an ongoing basis so that when operations cease the land
and water resources can be successfully returned to their original condition (Dogwood
Initiative, undated).
A7.7.3 Summary
As described in Section 2, the potentially significant issues associated with this stage are
those associated with land take and biodiversity during this stage (moderate significance
only).
Land take and biodiversity impacts can be mitigated by the measures described in Section
A7.1. Additionally, regulators can require the rapid restoration of land which is no longer
needed during the production stage. However, as noted in Section A7.1, it may not be
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
possible to fully restore some sites to their previous use, resulting in a potentially significant
ongoing impact.
The control measures set out in this section are considered on balance likely to be affordable
in a European context, but the potential influence of these costs on shale gas project viability
cannot be evaluated at this stage, and will depend on the forecast revenues from shale gas
extraction in Europe.
A7.8 Wider area development
API (2011a NPR p6) highlights the potential significance of cumulative effects of
development over a wider area. Examples are provided of collaborative initiatives
undertaken by the oil and natural gas industry to inform its members on best practices,
working cooperatively with regulatory agencies and other stakeholders to promote best
practices, and improve communication with local communities. Neighbouring operators in
British Columbia are required to work together to ensure efficient provision of gas collection
and water treatment infrastructure (British Columbia OGC, 2011 NPR).
A7.9 Measures derived from other regulatory contexts
Potentially relevant best practice technologies and regulatory requirements have been laid
down in relation to the use of hydraulic fracturing in similar/comparable contexts.
A7.9.1 Carbon capture and storage
Carbon capture and storage differs significantly from high-volume hydraulic fracturing.
However, both operations involve the injection of large volumes of potentially harmful
substances in the subsurface.
The Carbon Capture and Storage Directive (2009/31/EC) includes the following potentially
relevant provisions:

Requirements for site characterisation following a 3-dimensional approach (Directive
Annex I)

Requirement for permits to cover both exploration and storage phases. The storage
permit would cover the operational and post-abandonment phases

Requirements for a monitoring plan as part of the storage permit (Article 13)

Requirement for proof of financial security as part of the storage permit (article 19)

Requirement to assess potential displacement of produced water and seismicity risks
(Annex 1 Step 3)

After satisfactory abandonment, an installation can be transferred to the competent
authority (Article 18). This provides long-term assurance of management of facilities

For transboundary installations, competent authorities are required to co-operate in
jointly meeting the directive requirements (Article 24)
This directive does not cover hydraulic fracturing specifically, and requires operators to
assess the risk of fracturing the storage formation. However, the measures set out in this
Directive could potentially inform the Commission’s approach in relation to high volume
hydraulic fracturing facilities.
Some of the issues and recommendations in World Resources Institute (2010 NPR) are also
relevant for consideration in relation to hydraulic fracturing processes. The relevant issues
and recommendations have been summarised below:
1. Non-permanence, including long-term permanence
Ref: AEA/ED57281/Issue Number 17
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2. Measuring, reporting and verification (MRV): It is recommended to have an
environmental regulatory framework established that:

Covers the area of injected CO2 and any displaced fluids

Requires operators to monitor and report key data and information

Establish criteria for determining when monitoring can end
3. Environmental impacts - the following recommendations are given:

Ensure that an environmental regulatory frameworks provides for a compositional
analysis of the CO2 stream, which is then used in the site-specific risk assessment

Conduct a comprehensive EIS analysis for any CCS effort, which includes a risk
analysis and public participation.
4. Project activity boundaries -The following recommendations are given:

Ensure an environmental regulatory framework for CCS that requires a monitoring
area and project footprint be established based on site specific data, simulations,
and risk assessment.

Establish national methodologies for MMV of CCS projects.
5. International law - it is recommended for national governments to follow the rules and
best practices of the London Protocol and OSPAR, where applicable.
6. Liability - The lack of established procedures for addressing short- and long-term liability
for CCS has been raised as a concern. It is recommended to:

Develop and agree to clear rules and procedures for managing liability in a CCS
project.

Develop and agree to criteria for proving that the CCS project does not endanger
human health or the environment, and use these as the basis for transfer of
liability and stewardship responsibilities.
7. Safety - For national governments it is recommended to:

Apply to CCS projects laws that protect worker safety.

Ensure a regulatory framework that prioritizes human and ecosystem safety.
8. Insurance coverage and compensation for damages caused due to seepage or leakage The recommendations are to:

Require operators to have insurance during operational project phases.

Develop a national trust fund or other mechanism for long term stewardship.
A7.9.2 Artificial recharge
Procedures for well construction are specified in relation to Artificial Recharge (AR) of
aquifers. AR is a process by which liquid is introduced into the sub-surface by anthropogenic
means (McAlistar and Arunakumaren, 2001 NPR). Practices for reinjection are set out in the
US EPA’s Underground Injection Control (UIC) Program (USEPA 2012b NPR ; ALL
Consulting, 2010a NPR). However, because AR takes place in shallow, moderate to high
permeable aquifers, there are limited parallels to the use of HVHF in highly impermeable
formations.
However, guidance produced under the UIC program could potentially be useful for the
development of regulatory measures and statutory guidance in relation to high volume
hydraulic fracturing.
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
In the Netherlands, desalinated brackish groundwater is used for agricultural purposes in
low-lying areas below sea level. Residual brines have been injected into deep (saline)
aquifers under strict conditions including monitoring of quality and quantity of the brinedischarge and well-design and well-abandonment (Provincie Zuid-Holland, 2009 NPR). This
activity will be banned from 2013 in view of concerns regarding sustainability and the
potential for environmental harm. This further highlights the potential for environmental
impacts if hydraulic fracturing were to take place in zones which could potentially affect
aquifers.
A7.9.3 Coal bed methane
Alternative methods for treating produced waters are described in the US National Research
Council’s 2010 publication on “Management and Effects of Coalbed Methane Produced
Water in the United States” (http://www.nap.edu/catalog.php?record_id=12915) (academic
sector consultation response, 2012 NPR). However, substantial developments have been
made in treatment and re-use of produced waters from HVHF activities related to shale gas
in the US which are more relevant to the use of HVHF in Europe (see Sections 2.6.3 and
2.7.2; see Yoxtheimer, 2012 NPR).
A7.9 Measures effective for multiple impacts
The following measures have been identified as effective in addressing more than one
potential environmental or health risk.
1. Hydraulic fracturing chemicals – use of lower toxicity fracturing chemicals, and
minimizing the required quantities of chemicals
a. Reduces impacts of any spills, leaks, or other releases
b. Reduces transportation costs and risks
c. Can also reduce costs to the operator
2. Reuse produced water
a. Reduces potential water resource depletion (at lower cost for well operator)
b. Reduces truck traffic, if the produced water is reused close to the point of
generation,
i.
for transporting make up water to well site
ii. for transporting wastewater to disposal site
c. Reduces risks from wastewater disposal (surface water and underground
injection)
3. Increase the required well spacing (i.e., install fewer well pads with more wells per
pad)
a. Reduces land take, biodiversity impacts
b. Reduces visual impact
c. Reduces truck traffic (including community impacts, noise, air pollution)
d. Consolidates noise to fewer locations, reducing community impacts
4. Transport make-up water to site via (temporary) pipeline
a. Reduces truck traffic (including community impacts, noise, air pollution)
5. Transport produced water to centralized collection point via (temporary) pipeline
a. Reduces truck traffic (including community impacts, noise, air pollution)
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
A7.10
Matrix of potentially effective controls
Tables A7.1, A7.2 and A7.3 summarise the potentially effective controls available to address
the potential environmental impacts of shale gas extraction using high-volume hydraulic
fracturing.
Table A7.1: Matrix of controls (groundwater, surface water and water resources)
Impacts specific to HVHF/Unconventional gas extraction are underlined
Development & Step
Groundwater contamination
Surface water contamination
Production
and other risks
risks
Stage
Site Selection
Site identificIdentify sites away from aquifers Identify sites away from sensitive
and Preparation ation
and/or with impervious cap
surface waters
Site selection Select sites away from aquifers Select sites away from sensitive
surface waters
Site
Normal good practice measures
preparation
to control run-off and erosion
during site preparation
Well Design
Deep well
Ensure well design appropriate
(directional)
and adequate to protect any
aquifers
Shallow
vertical
Well drilling,
Drilling
Procedures to prevent spillage
Normal good practice measures
casing and
of water or oil-based drilling
to prevent discharge and ensure
cementing
fluids leading to contamination
proper disposal of drilling mud
of surface water body or nearand cuttings
surface aquifer
Casing
QA/QC on well design to ensure
proper well construction and
avoid risk of subsurface
contaminant migration pathways
for groundwater pollution
Design of well casings to
withstand potentially repeated
hydraulic fracturing
Cementing
Ensure complete cement
delivery to isolate aquifers from
target formation
Hydraulic
Water
Assess potential for changes in Assess potential for changes in
Fracturing
sourcing:
groundwater quantity or quality
surface water quality due to
surface water due to surface water abstraction, surface water abstraction, and
and ground
and manage abstraction
manage abstraction accordingly
water
accordingly
withdrawals
Water resource
depletion
Design well and HF
process to minimise
use of HF fluids
Minimise HF water
volumes by monitoring
and control of operation
and manage water
abstraction to avoid
potentially significant
impacts.
Water
Proper design, construction and Proper design, construction and
Re-use of fracturing
sourcing:
inspection/maintenance of
inspection/maintenance of surface fluids where
surface impoundments.
impoundments.
appropriate
Reuse of
flowback and High operating standards to
High operating standards to
Use of lower quality
produced
minimise risk of spillages with
minimise risk of spillages with
waters where
water
consequent risk of indirect
consequent risk of effects on
appropriate
effects
surface water quality
Ensure appropriate road vehicle
design and operational standards
to minimise accident risk during
transportation of flowback waters
for re-use offsite
Chemical
Minimise risk of spillages as
Minimise risk of chemical
additive
described for surface water
transportation accidents
transportation impacts.
Procedures and bunding to
and storage;
minimise risk of surface spill
mixing of
contaminating aquifer via infiltration
chemicals with
into soil or surface water from:
water and
 Tank ruptures
proppant
 Equipment / surface impoundment
failures
 Overfills
 Vandalism
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Development & Step
Production
Stage
Groundwater contamination
and other risks
Surface water contamination
risks
Water resource
depletion
 Accidents
 Fires
 Improper operations
Provision of adequate toxicological
information on hydraulic fracturing
fluid
Appropriate storage to avoid
surface water run-off
Perforating
casing (where
present)
Ensure appropriate charge used
to perforate casing to avoid
impacts on well integrity
Ensure additional chemicals
from introduction of explosives
into geologic environment do not
have significant environmental
effects
Well injection Prevent movement of naturally
Avoid pollution risk to surface water
of hydraulic
occurring substances to aquifers as described for groundwater
fracturing fluid  via induced fractures extending Ensure proper treatment and
disposal of flowback containing
beyond target formation to
these substances in solution
aquifer
Proper disposal of water treatment
 through biogeochemical
reactions with chemical additives residues (potentially containing
 via pre-existing fracture or fault NORM)
zones and/or
 via pre-existing man-made
structures
Ensure potential effects of
reusing flowback containing
dissolved elements for further
hydraulic fracturing operations
are properly addressed
Pressure
Avoidance of surface spill or
Avoid pollution risk to surface
reduction in
releases of flowback and
water as described for
well to reverse produced water via
groundwater
fluid flow,
 Tank ruptures
recovering
 Equipment or surface
flowback and
impoundment failures
produced

Overfills
water
 Vandalism
 Fires
 Improper operations
Wastewaters contain HF fluid,
naturally occurring materials as
well as potentially reaction and
degradation products including
radioactive materials.
Ensure no disruption to
groundwater flows
Avoid wastewater uses which
pose risks due to inappropriate
use or disposal of produced water
Well Completion Handling of
Implementation of measures to
Prevention of direct discharge to
waste water prevent inappropriate re-use of
surface streams
during
waste water, having regard to
Management of discharges to
completion
risks posed by:
municipal sewage treatment plant
(planned
or centralised waste treatment.
 Salinity
management)
 Trace elements (mercury, lead,
arsenic)
 NORM
 Organic material (organic acids,
polycyclic aromatic
hydrocarbons)
Handling of
Implementation of measures to
waste water
avoid surface spill or releases of
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Development & Step
Production
Stage
during
completion
(accident
risks)
Groundwater contamination
and other risks
Production
(including
produced
water
management)
Inspect and maintain well to
avoid failure of mechanical
integrity of well leading to
potential aquifer contamination
Pipeline
construction
and operation
Re-fracturing
Well / Site
Abandonment
Well / Site
Abandonment
Remove
pumps and
downhole
equipment
Plugging to
seal well
Water resource
depletion
flowback and produced water via
 Tank ruptures
 Equipment or surface
impoundment failures
 Overfills
 Vandalism
 Fires
 Improper operations
Connection to
production
pipeline
Well pad
removal
Well Production
Surface water contamination
risks
Similar to “Hydraulic Fracturing”
above
Ensure proper well
abandonment (e.g. adequate
and properly installed cement
plugs) to avoid subsurface
pathways for contaminant
migration leading to
groundwater pollution
Normal good practice measures
to prevent runoff, erosion and silt
accumulation in surface waters
from well pad and impoundment
facilities.
Prevent surface spill or release of
produced water during storage on
site
Avoid uses which pose risks due
to inappropriate use or disposal of
produced water
Implement procedures and
controls to minimise risk of
spillage of materials during
construction of pipeline
Similar to “Hydraulic Fracturing”
Similar to “Hydraulic
above
Fracturing” above
Ensure no contamination of
surface water resources as
described in relation to
groundwater
Table A7.2: Matrix of controls (air emissions, land take and biodiversity)
Impacts specific to HVHF/Unconventional gas extraction are underlined
Development &
Step
Release to air of HAPs/ O3
Production Stage
precursors/ odours
Site Selection and
Site identification Identify sites away from
Preparation
sensitive locations such as
residential areas
Site selection
Select sites away from
sensitive locations such as
residential areas
Site preparation
Minimise number of
wellheads to facilitate
capture of fugitive emissions
Well Design
Deep well
(directional)
Shallow vertical
Well drilling, casing
and cementing
Drilling
Normal good practice
procedures to prevent oil
spillage
Land take
Biodiversity impacts
Identify sites of low
agricultural/ ecological
value
Select sites of low
agricultural/ ecological
value
Design site layout to
minimise area of land take
Identify sites away from
protected/ sensitive areas
Select sites away from
protected/ sensitive areas
Minimise disturbance to
wildlife during site
preparation e.g. due to
traffic, noise, heavy plant
Take care not to introduce
new/invasive species
Minimise disturbance to
wildlife during drilling e.g.
due to excessive noise
Casing
Cementing
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Development &
Step
Release to air of HAPs/ O3
Production Stage
precursors/ odours
Hydraulic Fracturing Water sourcing:
surface water and
ground water
withdrawals
Reuse of
flowback and
produced water
Well Completion
Well Production
Pipeline
construction and
operation
Biodiversity impacts
Minimise water volumes
used to minimise
requirement for on-site
water storage
Minimise distances to
surface water resources to
minimise traffic movements
Avoid introduction of
invasive species to water
bodies from use of make-up
water from a different
catchment
Ensure flowback/produced
water fully degassed and
trace contaminants collected
prior to re-use
Chemical additive
transportation
and storage;
mixing of
chemicals with
water and
proppant
Perforating
casing (where
present)
Well injection of
Prevent movement of
hydraulic
naturally occurring
fracturing fluid
substances to aquifers
Affected naturally occurring
substances could include:
 Gases (natural gas
(methane, ethane), carbon
dioxide, hydrogen sulphide,
nitrogen and helium)
 Organic material (volatile
and semi-volatile organic
compounds)
 helium
Ensure proper treatment and
disposal of flowback
containing these substances
in solution
Pressure
Capture and treatment of
reduction in well organic vapours from
to reverse fluid
flowback and produced
flow, recovering
waters
flowback and
produced water
Handling of
Use of green completion
waste water
techniques to minimise
during
emissions to air
completion
(planned
management)
Handling of
waste water
during
completion
(accident risks)
Production
(including
produced water
management)
Land take
Minimise fugitive losses
during production phase via
program of leak checking
etc.
Collect and treat gases
dissolved in produced water
along with methane
Minimise fugitive losses from
pipeline via program of leak
checking etc.
Minimise risks to natural
ecosystems from spillages
etc
Minimise requirements for
storage of flowback water
and produced water
Minimise flowback water
storage requirement
Implementation of measures
to avoid surface spill or
releases of flowback and
produced water as for surface
water
Ensure no encroachment
from site during
operational lifetime
Operate facility to minimise
disturbance to natural
ecosystems. End operations
at the earliest opportunity
Locate sites close to
existing pipeline
infrastructure
Design and construct
pipelines to minimise
impacts on sensitive habitats
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Development &
Production Stage
Step
Re-fracturing
Re-fracturing
Well / Site
Abandonment
Plugging to seal
well
Release to air of HAPs/ O3
precursors/ odours
Similar to “Hydraulic
Fracturing” above, but
should be possible to route
emissions to the pipeline
Ensure integrity of seals to
minimise vapour losses
Land take
Biodiversity impacts
Similar to “Hydraulic
Fracturing” above
Similar to “Hydraulic
Fracturing” above
Return maximum
proportion of site to state
prior to development or
other beneficial use
Return maximum proportion
of site to state prior to
development or other
beneficial use
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Table A7.3: Matrix of controls (noise, seismicity, visual impacts and traffic)
Impacts specific to HVHF/Unconventional gas extraction are underlined
Development & Step
Noise
Seismicity
Production
Stage
Site Selection and Site identificIdentify sites away
Avoid high
Preparation
ation
from sensitive
seismicity risk
locations
areas
Site selection
Select sites away from Avoid high
sensitive locations
seismicity risk
areas
Site
Minimise plant noise
preparation
during site preparation
using established
techniques.
Visual impact
Traffic
Identify sites with low
visual impact
Identify sites close to
transportation routes
and sources of water
Select sites close to
transportation routes
and sources of water
Minimise traffic
impacts during site
preparation using
established
techniques.
Minimise length and
properly design access
roads
Select sites with low
visual impact
Minimise visual
intrusion during site
preparation using
established
techniques.
Well Design
Deep well
Design well to
(directional)
minimise operational
Shallow vertical noise via location/
screening etc
Design well to
minimise visual
impacts via location/
screening etc
Well drilling,
casing and
cementing
Drilling
Minimise visual
impacts via location/
screening etc
Hydraulic
Fracturing
Reuse of
flowback and
produced water
Chemical additive
transportation and
storage; mixing of
chemicals with
water and
proppant
Perforating casing
(where present)
Well injection of
hydraulic
fracturing fluid
Pressure
reduction in well
to reverse fluid
flow, recovering
flowback and
produced water
Casing
Cementing
Water
sourcing:
surface water
and ground
water
withdrawals
Minimise operational
noise via location/
screening/ use of lownoise plant etc
Design and operate
plant to minimise noise
levels
Reuse of
flowback and
produced water
Chemical
additive
transportation
and storage;
mixing of
chemicals with
water and
proppant
Perforating
casing (where
present)
Well injection
of hydraulic
fracturing fluid
Well Completion
Ensure road design
and vehicle
operational standards
to minimise emissions,
noise and accident risk
during transportation
to site
(Potential benefit in
reduced water usage)
Pressure
Operate well so as to
reduction in
minimise noise
well to reverse
fluid flow,
recovering
flowback and
produced water
Handling of
waste water
Minimise visual impact
of chemical additive
storage infrastructure
via location/sizing/
screening
Monitor well to
detect any
potentially
significant events
and halt
operations if any
detected.
Monitor well to
detect any
potentially
significant events
and halt
operations if any
detected.
Ensure road design
and vehicle
operational standards
to minimise risks of
spillage of chemicals
during transportation
to site
Minimise visual impact
of hydraulic fracturing
fluid injection plant via
location/sizing/
screening
Waste water tanks and Minimise distance to
related plant could
water disposal facilities
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Development &
Production
Stage
Step
Noise
Seismicity
during
completion
(planned
management)
Production
Operate facility to
minimise noise
Pipeline
construction
and operation
Design pipelines to
avoid sensitive
residential areas.
Carry out construction
programme to
minimise noise
Similar to “Hydraulic
Fracturing” above
Re-fracturing
Well / Site
Abandonment
Plugging to
seal well
Traffic
constitute a potentially
significant visual
intrusion, particularly in
non-industrial settings
as above
Handling of
waste water
during
completion
(accident
risks)
Well Production
Visual impact
Monitor well to
detect any
potentially
significant events
and halt
operations if any
detected.
Ensure road design
and vehicle
operational standards
to minimise risks of
spillage of produced
water during offsite
transportation
Minimise distance to
water disposal facilities
Ensure road design
and vehicle
operational standards
to minimise risks of
spillage of produced
water during offsite
transportation
Ensure visual
Ensure road design
screening maintained and vehicle
to a high standard
operational standards
during operational
to minimise risks of
lifetime
spillage of produced
water during offsite
transportation
Design route to avoid Ensure road design
sensitive areas. Bury and vehicle
pipelines where
operational standards
appropriate to
to minimise noise,
minimise visual impact accident risk etc
Similar to
Similar to “Hydraulic
Similar to “Hydraulic
“Hydraulic
Fracturing” above
Fracturing” above
Fracturing” above
Ensure site restored to
a high standard to
avoid residual visual
impacts
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
Appendix 8: List of relevant ISO standards
applicable in the hydrocarbons industry
General
ISO 13879 Content and drafting of a functional specification
ISO 13880 Content and drafting of a technical specification
ISO 13881 Classification and conformity assessment of products, processes and services
ISO/TS 29001 Sector-specific quality management systems – requirements for product and
service supply organizations
ISO 14224 Collection and exchange of reliability and maintenance data for equipment
ISO 15156 series: Materials for use in H2S-containing environments in oil and gas
production:
ISO 15156-1: General principles for selection of cracking-resistant material
ISO 15156-2: Cracking-resistant carbon and low alloy steels, and the use of cast irons
ISO 15156-3: Cracking-resistant CRAs (corrosion-resistant alloys) and other alloys
ISO 15663 series: Life cycle costing:
ISO 15663-1: Methodology
ISO 15663-2: Guidance on application of methodology and calculation methods
ISO 15663-3: Implementation guidelines
Pipeline transportation systems
ISO 13623 Pipeline transportation systems
ISO 13847 Welding of pipelines
ISO 14313 Pipeline valves
ISO 14723 Subsea pipeline valves
ISO 16708 Reliability-based limit state methods
ISO 15590 series: Induction bends, fittings & flanges for pipeline transportation systems:
ISO 15590-1 Induction bends
ISO 15590-2 Fittings
ISO 15590-3 Flanges
ISO 15589 series: Cathodic protection of pipeline transportation systems:
ISO 15589-1 On-land pipelines
ISO 15589-2 Offshore pipelines
ISO 3183 Steel pipe for pipeline – Transportation systems
ISO 21329 Pipelines Repairs – Test procedures for mechanical connectors
Fluids
ISO 10414 series: Field testing of drilling fluids:
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
ISO 10414-1 Water-based fluids
ISO 10414-2 Oil-based fluids
ISO 10416 Drilling fluids laboratory testing
ISO 13500 Drilling fluid materials – Specifications and tests
ISO 13501 Drilling fluids
ISO 10426 series: Cements & materials for well cementing:
ISO 10426-1 Specification
ISO 10426-2 Testing of well cements
ISO 10426-3 Testing of deep-water well cement formulations
ISO 10426-4 Preparation and testing of atmospheric foam cement slurries at atmospheric
pressure
ISO 10426-5 Shrinkage & expansion of well cement
ISO 10427 series: Equipment for well cementing:
ISO 10427-1 Bow-spring casing centralizers
ISO 10427-2 Centralizer placement & stop collar testing
ISO 10427-3 Performance testing of cementing float equipment
ISO 13503 series: Completion fluids & materials:
ISO 13503-1 Measurement of viscous properties of completion fluids
ISO 13503-2 Measurement of properties of proppants used in hydraulic fracturing & gravelpacking operations
ISO 13503-3 Testing of heavy brines
ISO 13503-4 Measuring stimulation & gravelpack fluid leakoff
ISO 13503-5 Measuring long-term conductivity of proppants
Drilling and production equipment
ISO 10423 Wellhead & christmas tree equipment
ISO 10424-1 Rotary drilling equipment
ISO 10424-2 Threading, gauging & testing of rotary connections
ISO 13533 Drill through equipment
ISO 13534 Inspection, maintenance repair & remanufacture of hoisting equipment
ISO 13535 Hoisting equipment
ISO 13625 Marine drilling riser couplings
ISO 13626 Drilling & well-servicing structures
ISO 14693 Drilling & well-servicing equipment
Subsurface safety valve systems:
ISO 10417 Design, installation, operation & repair
Downhole equipment:
ISO 10432 Subsurface safety valve equipment
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
ISO 14310 Packers & bridge plugs
ISO 16070 Lock mandrels & landing nipples
ISO 17078-1 Slide-pocket mandrels
Progressing cavity pump systems for artificial lift:
ISO 15136-1 Pumps
ISO 15136-2 Drive heads
Casing, tubing & drill pipes for wells
ISO 10405 Care and use of casing & tubing
ISO 11960 Steel pipes for use as casing or tubing for wells
ISO 11961 Steel pipes for use as drill pipe – Specification
ISO 15463 Field inspection of new casing, tubing & plain end drill pipe
ISO 13679 Procedures for testing casing & tubing connections
ISO 13680 Corrosion resistant alloy seamless tubes for use as casing, tubing, & coupling
stock
ISO 13678 Evaluation & testing of thread compounds for use with casing, tubing & line pipe
ISO 15546 Aluminium alloy drill pipe
Rotating equipment
ISO 10437 Steam turbines – Special purpose applications
ISO 10438 series: Lubrication, shaft-sealing & control-oil systems & auxiliaries:
ISO 10438-1 General requirements
ISO 10438-2 Special purpose oil systems
ISO 10438-3 General purpose oil systems
ISO 10438-4 Self-acting gas seal support systems
Flexible couplings for mechanical power transmission:
ISO 10441 Special purpose applications
ISO 14691 General purpose applications
ISO 13691 Gears – High-speed special purpose gear units
ISO 13709 Centrifugal pumps for petroleum, petrochemical & natural gas industries
ISO 13710 Reciprocating positive displacement pumps
ISO 21049 Shaft sealing systems for centrifugal & rotary pumps
Petroleum, chemical & gas service industries:
ISO 10439 Centrifugal compressors
ISO 10442 Packaged, integrally geared centrifugal air compressors
ISO 13631 Packaged reciprocating gas compressors
ISO 13707 Reciprocating compressors
ISO 10440-1 series: Rotary-type positive-displacement compressors:
Ref: AEA/ED57281/Issue Number 17
Support to the identification of potential risks for the environment and human health arising from
hydrocarbons operations involving hydraulic fracturing in Europe
ISO 10440-1 Process compressors
ISO 10440-2 Packaged air compressors (oil-free)
Gas turbines – Procurement:
ISO 3977-5 Applications for petroleum & natural gas industries
Static equipment
ISO 13703 Design & installation of piping systems on offshore production platforms
ISO 14692 series: Glass-reinforced plastic (GRP) piping:
ISO 14692-1 Vocabulary, symbols, applications & materials
ISO 14692-2 Qualification & manufacture
ISO 14692-3 System design
ISO 14692-4 Fabrication, installation & operation
ISO 15649 Piping
ISO 13704 Calculation of heater-tube thickness in petroleum refineries
ISO 13705 Fired heaters for general refinery service
ISO 13706 Air-cooled heat exchangers
ISO 15547-1 Plate heat exchangers
ISO 15547-2 Brazed aluminium platefin type heat exchangers
ISO 16812 Shell-and-tube heat exchangers
ISO 10434 Bolted bonnet steel gate valves for petroleum & natural gas industries
ISO 15761 Steel gate, globe & check valves for sizes DN 100 & smaller, for petroleum &
natural gas industries
ISO 17292 Metal Gall Valves
Ref: AEA/ED57281/Issue Number 17
The Gemini Building
Fermi Avenue
Harwell
Didcot
Oxfordshire
OX11 0QR
Tel:
Fax:
0870 190 1900
0870 190 6318
www.aeat.co.uk
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