The recent blog “UK failing to learn U.S. lessons on fracking waste water” by O’Donnell, Gilfillan and Haszeldine (ODGH hereafter) is misleading, both in the way it describes events associated with fluid re-injection in the United States, and how it characterises the Environment Agency’s position with regards to the practice.

In their blog, ODGH describe at length the difference between produced water from conventional operations, and flowback fluid from shale gas hydraulic fracturing, and are correct to do so. However, under the terms of their own descriptions, the statements they then make using these definitions are false.

The authors claim that the increases in seismicity observed in Oklahoma are “linked to the subsurface re-injection of vast quantities of waste water from shale gas operations” (my emphasis). This is not correct, and the USGS have been very clear in stating that this is a myth, propagated in the main by anti-fracking activists. In reality, over 90% of the wastewater being disposed of by deep injection in Oklahoma (to be clear: for disposal, not fracking) is produced water from conventional oilfields, and not from hydraulic fracturing flowback fluids [1].

The same is true in California, where ODGH make claims of “environmental contamination due to leaks caused by poor borehole construction.” Firstly, it is important once again to point out that, as is the case in Oklahoma, the vast majority of such wells are disposing produced water from conventional oilfield operations, not flowback water from hydraulic fracturing of shale rocks. It is equally important to note that the concerns raised regarding these wells were of an administrative nature, regarding how licenses were awarded and which formations did or did not qualify as protected aquifers. No actual environmental contamination is thought to have occurred: the State Water Resources Control Board found that “the injection wells have not degraded groundwater quality”[2], while CalEPA stated that: “To date, preliminary water sampling of select, high-risk groundwater supply wells has not detected any contamination from oil production wastewater.”[3]

More importantly, I believe that ODGH have seriously misrepresented the position of the UK’s Environment Agency. Their full position on re-injection of flowback water is quoted below [4]:

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.

By neglecting to provide the full EA position, the ODGF give the impression that the EA are considering allowing “large volumes” of flowback re-injection in the UK. In fact, such disposal is very unlikely. However, the EA take the eminently sensible position that there may be exceptional circumstances under which disposal by re-injection does really present the optimum solution with respect to minimizing the risk of environmental contamination. Personally, I can’t think of any such conditions at present, but I think that it’s a wise position for a regulator to consider every individual case on its merits, and to then take the best available route to ensure environmental protection, rather than imposing an arbitrary blanket ban. Regardless, disposal of flowback at treatment facilities is considered BAT under usual circumstances, and subsurface re-injection is not, and therefore it is very unlikely to be allowed.

Importantly, even given the above position, the EA statement suggests that flowback is to be “injected back into formations from which hydrocarbons have been extracted” (my emphasis). ODGH appear to have missed the significance of this statement, because it renders most of their remaining arguments invalid. If re-injection is limited to formations from which hydrocarbons have already been extracted, then formation pressures will have been reduced. While their analogy with a clay-covered balloon is an interesting metaphor, it is not relevant to the situation at hand, if, as stated, flowback disposal were only allowed into formations that had already seen hydrocarbon production and pressure drawdown (if re-injection is ever allowed, which as discussed above, is very unlikely).

It is also worth considering the volumes involved. The existing onshore conventional industry in the UK disposes of approximately 12 million cubic metres of produced water every year. The Institute of Directors forecasts a UK shale industry developing, between now and 2030, 100 pads with 40 multilateral wells each, with each pad using 0.5 million cubic metres of water[5]. Assuming that 50% of this fracturing fluid flows back, a total of 27 million cubic metres of flowback will need to be disposed of during this period. In contrast, as stated above, the conventional industry will dispose of as much produced water in only two-and-a-bit years.

ODGH have mischaracterized hazard with risk. Hazard is the potential impact of a pollutant, while risk is the hazard posed multiplied by the probability of exposure. It may be true that flowback fluids have different chemical signatures to conventional produced waters that may make them more hazardous (although in reality the chemical signature of every fluid, whether flowback or conventional, will be specific to its geographic locality and rock formation, so the comparison provided by the authors is likely to be an oversimplification).

However, no evidence is provided to suggest that groundwater contamination is more probable during flowback disposal (nor have they provided evidence of such contamination from the USA). In fact, given that the volumes of flowback disposal are likely to be far lower, the likelihood of contamination from conventional produced water might be considered higher simply from a volumetric argument. With or without NORM, produced water is usually hypersaline, and its spillage into freshwater sources would represent, I would expect, a significant environmental incident.

The public can and should take reassurance from the fact that the existing onshore industry has been able to dispose of very large volumes of produced water without causing environmental impacts. The risk of contamination, by either produced water or flowback fluid, would appear therefore to be low.

James Verdon is a Senior Research Fellow at the School of Earth Sciences, University of Bristol

[1] Rubinstein et al., 2015. Myths and facts on Wastewater Injection, Hydraulic Fracturing, Enhanced Oil Recovery, and Induced Seismicity. Seis. Res. Letts..

[2] State Water Resources Control Board September 23, 2014, Item 13 – Executive Director’s Report.

[3] CalEPA Memorandum, 2015. CalEPA Review of UIC Program.

[4] Environment Agency, 2015. Onshore Oil & Gas Sector Guidance Consultation Draft, November 2015.

[5] Institute of Directors, 2013. Getting shale gas working.

[6] Verdon et al., 2014. Significance for secure CO2 storage of earthquakes induced by fluid injection: Env. Res. Letts.

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  1. 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

    Overview

    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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