The authors make the following clarification regarding the original blog:

  • The earlier version incorrectly implied that Third Energy’s ongoing planning application at Ebberston Moor included the drilling of a wastewater injection well related to shale gas operations. It  is corrected to state clearly that this planned waste water injection well relates to their conventional production activities, and not shale gas operations.
  • The text clarifies that earthquakes triggered in Oklahoma are the result of injection of waste waters produced from both conventional and unconventional hydrocarbon production.

The amended blog follows –

The UK Environment Agency has recently released new draft guidelines contradicting its former total prohibition of underground waste water disposal following fracking. Allowing large volumes of chemically contaminated waste water to be disposed of by injection underground has, in the USA, led to groundwater contamination and to hundreds of significant earthquakes, not minor tremors. There is currently no evidence that large volumes of fracking wastewater can be effectively treated for subsurface disposal in the UK. We have found that almost all of the waste water produced by existing UK onshore oil and gas activities is disposed of through underground injection. There are no records available to determine if any treatment, except for the separation of oil and gas, was carried out on these waters before they were re-injected. This shows that the existing onshore oil and gas industry is not an appropriate example of the UK’s ability to safely treat waste water produced from fracking.

Why does this matter?

One of the most controversial aspects of the potential exploitation of the UK’s shale gas resources is how the waste water produced during the fracking process will be treated and disposed of. Reports of Cuadrilla legally disposing of such waste water flowing from their initial shale gas operations in Lancashire caused widespread concern in 2014. Wastewater disposal has recently been brought to the forefront of the debate over fracking in the US, as a result of more than 100 significant earthquakes per year in Oklahoma. These have been linked to the increased rate of subsurface re-injection of vast quantities of waste water mainly from traditional oil and gas activities but also recent shale gas operations. Separately, in Ohio and Arkansas, recent earthquake swarms have been directly linked to the injection of wastewater from shale gas production. Re-injection is the most common and economically viable solution to deal with flowback waste waters in the US but, in addition to induced earthquakes, the practice has also resulted in environmental contamination through surface spills and leaky wells. These issues have raised concerns over the suitability of this disposal method for the UK. However, contrary to the claims of several proponents of the UK shale gas industry that the practice will not happen in the UK, our research into the latest Environment Agency guidelines has found that subsurface injection for disposal of waste waters from fracking operations could be permitted in England and Wales.

How are waste waters generated from fracking?

Shale gas is obtained from sedimentary rocks containing high amounts of organic matter. Heat and pressure during burial of these rocks generates hydrocarbons from the organic matter, which can migrate out of shale rocks to be trapped in porous rocks forming conventional oil and gas fields. However, due to the tightly packed structure of shale, oil migration is more difficult, and much of the oil and gas remains trapped within the rock. To extract this oil and gas from shale rocks they can be high-volume hydraulically fractured; a process that involves pressurising a drilled well with fracking fluids, typically consisting of 98% fresh water, 2% sand and 0.05% chemical additives. This creates artificial cracks in the rock, allowing the gas to be released.

Here we make an important distinction between the different fluids involved in high-volume fracking (Fig. 1). Before fracking, the pore spaces in the rock contain pre-existing “formation water” in geochemical equilibrium with exposed mineral surfaces. During conventional oil production, “produced water” is collected at the surface along with oil, gas and formation water. During the fracking process, fresh cracks in the shale expose chemically reactive rock faces to the “fracturing fluids”. This permits rapid chemical exchange between the fracturing fluids, the rock minerals, and any natural formation water present. Once fracking operations have ceased, the well is depressurised, allowing the gas and these fluids to be produced from the well, named “flowback fluids”. Flowback fluids typically contain high levels of dissolved and suspended solids, heavy metals, dissolved hydrocarbons, and naturally occurring radioactive material (NORM) leached from the shale and formation waters, making them chemically distinct from produced waters. This flowback water is the main waste product of shale gas operations, and its management presents a significant environmental and economic challenge to the development of the shale gas industry in the UK.

For clarity within this article, we outline these terms in Fig. 1 below:

Figure 1 – Fluids and the hydraulic fracturing process. Produced Water Image from Flowback Fluids Image from

Haszeldine Fig 1

How is waste water from UK onshore oil and gas currently managed?

Management of contaminated waste water is not unique to shale gas operations, as conventional onshore oil and gas wells have been producing waste water and disposing of it since the oil industry began to exploit the onshore reserves of the UK over a century ago. This has been cited by several shale gas proponents as evidence that the disposal of flowback water from future UK shale gas activities will not be a problem. However, produced water from conventional oil and gas fields comprises of only the formation water from the reservoir, and is chemically very different from the flowback water which is produced from fracking for shale gas.

In an important analogue, publicly available data from the Government Department of Energy and Climate Change (DECC) shows that 99.9% of produced water from UK onshore oil and gas fields was re-injected into the subsurface in 2014/15. Wytch Farm, the UK’s largest onshore oil field, and the Welton and Gainsborough fields in the East Midlands publicly cite that they dispose of their waste produced water by re-injection. The purpose of this re-injection is for waste disposal, enhanced hydrocarbon recovery and to maintain high fluid pressures in the reservoir which aid oil and gas production. There is no evidence available to determine if any treatment, except for the separation of oil and gas, was carried out on these waters before they were re-injected. Hence, there is no established track record in the safe treatment of such waste water in the UK.

What are the rules for waste water disposal from shale gas in the UK?

In their recently published draft guidelines for the onshore oil and gas sector (including shale hydrocarbons), the Environment Agency outline their current position on waste water management for this sector in England and Wales. These guidelines state that waste water should be managed in a way that reduces the risk posed to public health and the environment. This includes aiming to reduce the amount of waste generated, and to encourage the reuse of waste fluids wherever possible, to reduce the need for fresh water and water treatment facilities. The Agency’s preferred method of disposal for produced water from conventional onshore oil and gas production is through regulated re-injection into the subsurface.

For contaminated flowback fluids from shale gas activities, the Environment Agency guidance states that re-use is preferred for subsequent fracturing operations, because “until the flowback fluid no longer serves a useful purpose it is not considered a waste”. The draft guidance also states that “The Environment Agency will generally not permit the re-injection of flowback fluid for disposal into any formation”. However, the document goes on to create a loophole, by stating that “re-injection of flowback fluid for disposal is not necessarily prohibited and may be permissible where, for example, it is injected back into formations from which hydrocarbons have been extracted and will have no impact on the status of water bodies or pose any risk to groundwater.” The Agency intends to review this position in light of increased evidence from hydraulic fracturing operations and from the monitoring of underground waste facilities.

This new position is a distinct contrast, and softening of position, compared to a draft Technical Guidance document previously published by the Agency in 2013 which stated that “Disposal of flowback fluid simply by re-injecting it into the shale strata is not permissible under groundwater protection legislation and isn’t considered further here”. This stance was confirmed by an interview by the Agency given to Greenpeace’s Energydesk in 2014. Hence, the new draft guidelines issued in November 2015 show a significant shift towards the potential permitting and operational use of re-injection wells for the disposal of large volumes of contaminated flowback fluids in England and Wales.

Why is this a problem and should we care?

If disposal of used water by re-injection is within the established environmental regulations and is the current convention for onshore hydrocarbon operations, why should we be concerned by its possible application in shale gas operations in the UK? Two key risks are posed: firstly, the potential for seismic activity as a result of the pressure increase within the geological formation due to fluid injection and secondly, that the chemical makeup of flowback fluids from fracking are very different to that of produced waters associated with conventional hydrocarbon extraction, and so have a greater potential to contaminate groundwater should any leakage of them to the environment occur.

For conventional hydrocarbon operations, produced waters are almost entirely formation waters, and re-injection usually occurs into the same formation from which the hydrocarbons and waters were originally extracted. This means that the waters are close to geochemical equilibrium with the rock-forming minerals they have contacted for millennia. Additionally, the volume of produced water re-injected from traditional oil and gas is overall less than, or similar to, the volumes of pore space underground – as the oil and gas have been removed from the same reservoir into which re-injection occurs. In contrast, during shale gas operations, the flowback fluids will have to be re-injected into differing geological formations.

Potential for Earthquakes

The additional volume of injected flowback fluid into the subsurface can cause an increase of pressure, and this will be more pronounced in geological formations where hydrocarbons have not been previously extracted. This produces an effect much like a child’s balloon being inflated inside a coating of plasticine clay: the balloon expands slightly, then fractures the enclosing clay. Geologically, this behaviour can release built-up stresses underground and produces an earthquake. In the US, many of these earthquakes have been felt at the surface (Magnitude 3), with a few up to magnitude 5.6 causing minor damage to buildings. Larger earthquakes have been tens of kilometres from the site of water injection, and have not occurred until several days after fluid injection has stopped.

Chemical Reactions

Flowback fluids produced from shale gas production will be more chemically complex than conventional produced water due to the freshly fractured shale rock surfaces geochemically reacting with fracturing fluids and mixing with formation water. This rapid interaction encourages mineral leaching from the shale, meaning the flowback fluids will contain higher amounts of heavy metals and potentially Naturally Occurring Radioactive Materials (NORMs). A recent study of produced waters from the Marcellus shale in Pennsylvania shows that the chemistry of flowback waters from unconventional gas fracking activity cannot be explained by a mixing into formation waters by injection fluids. It is likely that more complex chemical reactions are occurring and further research is required to understand the implications of these reactions.

The potential permitting of injection for flowback fluids in England and Wales is particularly concerning as there is a complete lack of research on the compositions of the waste water and potential chemical reactions in the subsurface. There has been only one high-volume hydraulic fracturing operation, performed on the Bowland Shale in Lancashire by Cuadrilla, from which we can analyse the chemistry of the associated flowback water. As part of Third Energy’s planning application for a non-shale gas related produced water disposal well into the Sherwood Sandstone at Ebberston Moor (formerly the Lockton gas field) in Yorkshire, they provide compositional data for the produced water arising from their conventional gas operations in the area.

Figure 2 – Geochemistry of produced water from conventional hydrocarbon extraction by Third Energy at Ebbertson Moor, and unconventional hydraulic fracturing of shale by Cuadrilla at Preese Hall.

Flowback water data is from unconventional operations in the Bowland shale, produced water data is from conventional operations in the Kirkham Abbey, deep Permian sands.

Haszeldine Fig 2

A simple comparison, as shown in Figure 2, shows that there is a considerable difference between the chemistry of two waters, with Cuadrilla’s flowback fluids being significantly higher in heavy metals, lower in dissolved salts and reduced in sulphate and nitrate. Unfortunately levels of NORMs in Third Energy’s produced waters are not available so a comparison with those in Cuadrilla’s flowback fluids cannot be made. It is essential that the chemistry of the flowback fluids from shale gas operations is better known to understand how they will react in the subsurface if re-injected for disposal, or how they can be safely treated for surface disposal instead.

Actions and legislation needed

If the UK is to dispose of high-volume flowback fluids from shale gas by using re-injection into geological formations, much further research into the potential risks of the process and how to reduce them is required. Lessons from the US, where the process has been linked to induced local seismicity and environmental contamination due to poor well construction, have to be learned and not repeated.

We have not been able to discover any research into the potential seismic hazard posed by existing or future injection of wastewater in the UK. Should high volume re-injection activity of flowback fluid be carried out in the UK, it must be carefully monitored to comply with the established traffic light scheme which will be used to measure for induced seismicity from future fracking operations. We also strongly recommend that a research based, industry accepted code of best practice, from which the regulators can adapt the legislation to reduce the risk of environmental contamination must be established before any flowback fluid re-injection permits are granted.    Send article as PDF   
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  1. “Produced water from conventional oil and gas fields comprises only the formation water from the reservoir, and is chemically very different from the flowback water which is produced from fracking for shale gas”. What about the wastewater from coal bed methane extraction if fracking is not used? Is this closer chemically to formation water or to fracking flowback water, bearing in mind that some of the same drilling fluids might be used?

  2. Response to Dr. James Verdon’s article on ‘UK failing to learn U.S. fracking lessons?’

    Dr. Stuart Gilfillan, Megan O’Donnell and Prof. Stuart Haszeldine, University of Edinburgh


    We thank Dr James Verdon for his thorough response to our article ‘UK failing to learn U.S. fracking lessons?’. It is satisfying to see that disposal of flowback fluids from UK shale gas operations is starting to receive the attention that it deserves, having so far been absent from the debate surrounding the potential future production of shale gas in the UK. However, whilst Dr Verdon’s response is high on specific detail, it fails to understand the two key points that we make in our original article.

    Firstly, as we clearly outline, and has since been confirmed to The Ferret Scotland, the new draft guidelines released by the Environment Agency in November of 2015 show that the organisation has rolled back on their total prohibition of re-injection of flowback fluids from fracking. This is a clear and significant shift from their 2013 position, confirmed in an interview given to Greenpeace’s Energydesk in 2014, that any injection of flowback fluid from fracking would not be permitted under the EU water framework directive. This change in policy opens the door to UK shale gas operators applying to the Agency for a permit for flowback reinjection in the future, as we highlight.

    Secondly, Dr. Verdon appears to have missed the significance of our finding that almost all (99.9%) of the currently produced water from onshore oil and gas activities in the UK is disposed of through reinjection. Several proponents of the UK shale gas industry, including Dr. Verdon himself, have made the case that the management of future flowback waters from shale gas will not be a problem, as we currently manage large volumes of similarly contaminated wastewater from conventional production. However, if flowback fluids from shale gas wells will not be reinjected, as Dr. Verdon and the UK Onshore Operators Group have claimed following our article, then the existing onshore oil and gas industry is not an appropriate example of the UK’s ability to safely treat waste water produced from fracking. Following this finding we believe it is imperative that the ability of the UK to treat flowback fluids from shale gas operation is investigated urgently. To date, there has been no credible review of either the chemistry of the fluids that will be produced by UK fracking operations or how they can be safely treated prior to surface discharge, the only viable alternative to reinjection.

    Response to specific points raised by Dr. Verdon:

    (i) U.S. issues surrounding wastewater injection

    Following Dr. Verdon’s comments that a significant proportion of wastewater injected in Oklahoma is from conventional oil and gas activities we have posted an updated version of our article which clarifies this fact. However, we would like to highlight that triggered earthquakes in both Arkansas and Ohio have been directly linked to the reinjection of flowback fluids from fracking activities. Additionally, in Oklahoma, the triggered seismicity is still linked to the injection of wastewater, and we are confident that the residents of the region suffering from these events take no comfort that fracking flowback fluids are not a large proportion of the wastewater injected.

    We have made a similar update to the article to reflect that the situation surrounding wastewater disposal in California. Further research on this topic has unearthed multiple cases of wastewater injection wells causing environmental contamination in the US, particularly in the state of Texas. Whilst we admit that the case we originally cited in California was not an appropriate example, it is clear that poor borehole construction has led to groundwater contamination incidents in the USA, and our point that wastewater injection wells pose a potential environmental contamination risk is entirely valid.

    (ii) Environment Agency position

    Dr. Verdon’s claim that we have misrepresented the Environment Agency’s position is questionable. For the avoidance of doubt in this reply we outline below the full position on reinjection of flowback fluids, in which we highlight in bold the key words and phrase which clearly show that the Agency is open to the idea of permitting flowback fluid reinjection.

    Flowback fluid that cannot feasibly be re-used, is considered by us to be an extractive waste and may contain a concentration of NORM waste above the out of scope values. It will then require a radioactive substances activity permit for its disposal. You must send this to an appropriate permitted waste facility for treatment or disposal.

    The Environment Agency will generally not permit the re-injection of flowback fluid for disposal into any formation, whether or not it contains a concentration of NORM waste above the out of scope values. The re-injection of flowback fluid for disposal is not necessarily prohibited and may be permissible where, for example, it is injected back into formations from which hydrocarbons have been extracted and will have no impact on the status of water bodies or pose any risk to groundwater.

    The Environment Agency takes a precautionary approach to this activity and we do not consider it has been demonstrated that re-injection in these circumstances is BAT.

    At present and in the absence of BAT being demonstrated we have determined that overall the long-term objective of ensuring good status of water bodies takes precedence over arguments in favour of the disposal of flowback fluid to underground formations.

    This is reinforced by our view that there are available and viable alternatives, namely disposal at permitted waste disposal facilities or by using onsite waste water treatment facilities. We consider that these techniques are a better environmental option.

    We will review this position in light of increased evidence from hydraulic fracturing operations and from the monitoring of underground waste facilities.

    Note that the word ‘generally’, and the term ‘for example’ are not definitive legal language and provide no reassurance that reinjection of flowback fluids will not be considered in the future, or will be confined to formations from which hydrocarbons have been extracted. Our research into this area has found that, in 2014, Third Energy were granted a permit to inject wastewater from their conventional gas production activities at the Ebberston Moor ‘A’ site into the Sherwood Sandstone saline aquifer, which is located above their producing hydrocarbon reservoir (in the Kirkham Abbey Formation). No hydrocarbons have been produced from the Sherwood sandstone in that area and this clearly shows that the Environment Agency are open to permitting reinjection of produced waters from conventional production activities into such horizons. The company is currently using this successful application as a precedent to seek planning permission for a second produced water disposal well (again related solely to their conventional activities) into the Sherwood sandstone at their Ebberston Moor ‘B’ site.

    The shift in position of the Environment Agency from a total ban on reinjection of flowback fluids from fracking in 2013, to the current position, shows a clear direction towards permitting reinjection, and that these guidelines are evolving rapidly. The last sentence shows that the Agency will review their position in light of future evidence from hydraulic fracturing operations, and again opens the door to evidence from operators that treatment of flowback fluids is difficult and expensive and reinjection is a more financially agreeable solution. An important technical point is that evidence from transient preliminary fracking activity is unlikely to be informative about the stress states and subsurface pressures induced by cumulative localised injection of large fluid volumes, as these are very different operations.

    (iii) Use of Risk and Hazard terminology

    On Dr. Verdon’s point on risk and hazard terminology, our article is aimed at a general audience, and hence we use the general definition of risk, which is ‘the possibility of incurring misfortune or loss; hazard’ according to the Collins English dictionary. The issue we highlight in our article that there has been no detailed investigation into the risk management surrounding the disposal of flowback fluids from fracking operations in the UK. This is particularly surprising given that the much publicised Joint Royal Society and Royal Academy of Engineering Review of Hydraulic Fracturing in 2012 stated that ‘Options for disposing of wastes should be planned from the outset. Should any onshore disposal wells be necessary in the UK, their construction, regulation and siting would need further consideration’. We are simply restating this point having seen no evidence that further research into large scale wastewater management strategies has been undertaken since.

    The recent Task Force on Shale Gas report on ‘Assessing the impact of shale gas on the local environment and health’ outlines the risk of seismicity associated with wastewater reinjection in the US. The report also cites to the now out of date statement that ‘It is understood that the [Environment] agency will not grant a permit for the disposal of waste water by deep injection under its interpretation of the European Union’s Water Framework Directive’ and goes onto outline wastewater reuse and treatment strategies, without any assessment of the current capability of such treatment facilities in the UK. Given this evidence, we strongly believe that the potential permitting of flowback fluid reinjection in the UK without a review of the seismic hazard posed and the regulations surrounding disposal well construction shows that lessons from the U.S. have not been learned.

    (iv) Comparison of UK flowback reinjection with CCS

    On Dr. Verdon’s final point about seismicity related to CO2 storage operations, the simple answer is that there are no proposals for onshore CCS in the UK, with all of the potential storage sites located offshore in the North Sea. We would certainly expect some induced seismic activity, along with chemical reactions related to the injection of the CO2. However, given the offshore location this is not going to pose a risk to the general population. Additionally, any CO2 storage site would be carefully monitored from the outset to measure any induced seismic activity, something Dr. Verdon has an international reputation in being an expert in, and downhole pressure build up within the injection formation. Should an unexplained pressure increase or large seismic event occur injection would be shut down immediately and the cause investigated.

    Lastly, we would like to ask Dr. Verdon that ‘given his dismay at recent government decisions to shelve the proposed [CCS] demonstration projects’, and his opinion that the ‘UK will be not be able to meet its emissions targets [without CCS]’, if he would like to reconsider his support for the development of a new UK hydrocarbon industry as other previous supporters of the industry, such as Prof. Paul Younger have recently done, now that CCS is no longer a near-term option in the UK? Whatever Dr Verdon thinks about fracking, he may be able to reflect that cumulative production of fossil hydrocarbon from the subsurface, without abatement of emissions by CCS, is agreed by an overwhelming majority of geoscientists to be the primary driver of global climate change. How can these two positions be reconciled?

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