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:
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 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.. , the UK’s largest onshore oil field, and the
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.
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.
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.