The WinACC/FoE Fracking Open Meeting on 8 October 2013 raised a lot of audience questions - so many that some could not be answered at the event and were collected afterwards. All the questions and answers follow. See more about the meeting with links to the presentations.

Questions and answers
1. The current licences in Hampshire are one sites where oil is already extracted. Will this affect the process at all? Also, oil at these sites is extracted by pumping in water. How does the resultant waste water differ from the fracking water? Since the oil drilling happens without any apparent local disruption, does this provide evidence that there is no environmental impact?

WinACC Science and Technology Advisory Panel (STAP):

Answer to Question 1.1: Do areas currently licenced for oil extraction allow for the exploration, testing and production of shale gas and, if not, will this affect any eventual application for shale gas exploration?

Petroleum Exploration and Development Licences (PEDL) are issued by the Department of Energy and Climate Change (DECC) along with consents for particular activities and controls can be imposed accordingly. So, for example, a licence may cover exploration, development (drilling) or production. Licences specific to hydraulic fracturing or directional drilling are not awarded per se. PEDL licences grant exclusivity to operators in the licence area. They do not give immediate consent for drilling an exploration well or any other operation.

To begin drilling, an operator must negotiate access with landowners and be granted local planning permission from the Minerals Planning Authority (MPA). In England, Wales and Scotland, the MPA involves local authorities, including representatives from districts and county councils. DECC must also give its consent (Well Consent).

So, in answer to the question, an operator may only conduct operations (whether exploration, development or production) according to the licence held, and subject to permission from the MPA, but the targets could include shale gas as well as oil or conventional gas.

Answer to Question 1.2: Does waste water, used to enhance oil recovery in Hampshire, have to be treated and is this different from treating waste fracking water?

Enhanced Oil Recovery (EOR) is a technique used for increasing the amount of crude oil that can be extracted from an oil field. On average only 30% of the oil is otherwise recovered. In the EOR process, water or steam is used to heat the crude oil in the formation to reduce its viscosity. EOR wells typically produce large quantities of brine at the surface i.e. flowback. The brine may contain toxic metals and radioactive substances. This water by-product must be treated before discharge or reinjection ( A large proportion of the water appears to be re-used over and over again.

Residual oil recovery (ROR) is another method to enhance oil recovery using hydraulic fracturing and horizontal drilling (

No figures on the use of water per well for EOR/ROR in the onshore UK could be found in the public domain. Any waste water associated with this process will differ from water used for shale gas fracking in that fracking water will always be rich in the greenhouse gas methane which must be safely separated from the water and stored or flared off.

So, in answer to the question, so-called produced water used in EOR does have to be treated after use although it may first be re-used. But the treatment will differ from that applied to shale gas fracking waters in that the latter will be rich in methane.

2. Is there the technology available to correct [maintain] groundwater levels, & who would cover the costs of supplying an alternative water source? Is this a factor in County Council decisions?

STAP: Ground water levels are normally determined by the balance between natural precipitation, water used by vegetation (including crops) and water extraction.  In the summer water levels drop, e.g. in wells and surface chalk streams, but normally rise again during the winter. Normally there is no practical technological solution to ‘topping up’ ground water levels or freshwater aquifers.

The Environment Agency (EA) has a Groundwater Protection Policy for England and Wales which, along with national and European regulations, ensures that the regulators and users address and monitor potential risks associated with environmental degradation of groundwater. Various official bodies use numerical models of projected river flows and groundwater levels to assist policymakers, river basin management planners and water companies to consider the implications of licensing abstraction and groundwater recharge.

The EA determines the available water resources in each catchment area in England and Wales. They implement a strategy which considers the impact of abstraction and allows them to grant local conditional abstraction licences suitable for a proposed operation and thereby control the risk of over abstraction of groundwater.

A water abstraction licence from the EA is required if an operator wishes to extract more than 20 cubic metres of ground water per day. It is unlikely that this will be granted if the extraction will significantly impact the environment or water supplies to other users. Obviously, in the first instance, any cost of importing water from another area would have to borne by the operator.

If Hampshire County Council, as the Minerals Planning Authority, receives a Planning Application for hydraulic fracturing then, by law, it will consult the Environment Agency.

3. When accounting for methane leakage, shale gas causes more global warming than oil – 1.2 to 2.1 times more – leakage must be less than 2% to be cleaner (Howarth et al, 2011). Is this correct?

STAP: It is not easy to decide whether shale gas causes more global warming than oil; for example, when used to produce one kilowatt of electricity or to drive one kilometre. To do this, requires accurate figures for how much of each greenhouse gas is emitted at every stage in the life cycle from the ground to a power station’s chimneys or to a motor vehicle’s tail pipe. To do this properly it would be necessary to take into consideration emissions of carbon dioxide, methane, nitrous oxide, black carbon (soot), all of which have a warming effect and sulphur dioxide which has a net cooling effect. No study to date has fully taken this on board.

A very recently published study using an aircraft to estimate methane emissions from a natural gas and oil field in Utah concluded that 6.2 -11.7% of average hourly gas production was lost to the atmosphere,(Karion et al, 2013) significantly larger than the average figures supplied by the gas industry for US natural gas production.

To extend the argument, even if shale gas does produce fewer greenhouse gas emissions per tonne of coal, its use would only lead to a reduction in total global emissions if the gas actually replaced the coal and the latter remained in the ground. There is no evidence that these conditions are being met. For example in the USA the shale gas boom has not resulted in a decline in coal production. The coal that was not burnt in US power stations as a consequence of increased gas production has been exported to Europe and burnt there instead. So on a global climate scale, the emissions from burning the exported coal in Europe instead of in the USA are added to those from burning gas in America. The overall result will be more, not less, CO2 and methane emissions.

4. The first speaker said that c. 50% of the water comes back to the surface. What happens to the rest and how much of a contamination risk is it?

STAP: The speaker quoted 10-50% of the injected water coming back to the surface as flowback. This happens over a period of months after fracking has taken place. In the first instance the remainder stays in the rock formations exposed to the injected water, i.e. the target shales that contain gas. The injected fluids occupy spaces created by the fracturing process and any pre-existing voids. However in practice the actual formations exposed to injected water will depend on the design and integrity of the well. In the ideal case the well (hole) will be lined continuously with steel production casing cemented into place from the surface down into the target formation but the final well design will depend on circumstances including the nature of the rock being drilled.

The greatest risk of contamination after fracking arises from fluids and gases percolating up near vertical cracks towards the surface. However fracked formations typically lie 1000m or more below near-surface freshwater aquifers which might supply drinking water. At present in the UK fracking is not allowed beneath such aquifers.  Further, studies in the USA suggest that there is only a 1% chance of such a fracked crack extending more than 350m although natural hydraulic fracture pipes have been seen offshore West Africa and Norway which extend over 1100m.

On a timescale of decades and centuries the risk of slowly acting geological and other processes leading to pollution are greater but are harder to quantify. They will include corrosion and failure of casing and cement as well as the slow percolation of fluids through the rocks.

In summary, given strict application of regulations to well design and procedures, the risk in the UK that fracking fluids that are ‘left behind’ will lead to contamination of aquifers and the surface environment is low.

5. Long term risks, and the viability of politicians requiring far more research on the problematic issues rather than issuing licences now?

STAP: There are a number of long term risks associated with fracking, both “local” and “worldwide”.

Taking local first. The major risk is leakage into a freshwater aquifer of either the gas itself (principally methane) or the water and chemicals used in the fracking process. The shale that would be fracked is generally many hundreds, or even two or three thousand metres below a freshwater aquifer which, in the Hampshire/ Sussex area, is usually within 100-200 metres of the surface. Vertical cracks in the shale formed by the fracking process are rarely more than three hundred metres long. It is generally considered by geologists that the risk of such pollution arising in this way from either the methane gas, the water or the chemicals is remote. Further, currently the UK does not allow fracking below freshwater aquifers.

There are one or two instances in the USA of methane and possibly chemicals being found in drinking water. There is some controversy surrounding the sources of these. However, if they do turn out to be from the fracking process, the stronger likelihood is that they have leaked out from the well casing itself, where it passes through a freshwater aquifer. This would be due to a badly constructed or damaged, e.g. by an earthquake, well. This is more likely to be a risk if contractors are not strictly regulated in the way that construction and then production is carried out.

As regards “worldwide” risks, there appears to be an increasing body of evidence that there is leakage of methane during the production process of both conventional and unconventional gas of up to 12% of the gas being extracted. Should this be the case, then, because methane is a greenhouse gas much more powerful than carbon dioxide, this escaped gas will have an effect on global warming far greater than previously supposed.

6. How can we influence MPs to get sufficient money to the Environment Agency to deal with fracking? (Currently 40 people, nowhere near enough!)

WinACC: This is a national issue. There are quite a few campaigning groups nationally on fracking which you might be interested in following. They each often invite comments, or ask people to support their campaigns. Among those we know about are:

Friends of the Earth – their fracking ap is useful, at


38 degrees

Frack off

7. How long is the life of a well?

STAP: The productive life of a well drilled for extracting shale gas will depend on the geology and ‘frackability’ of the shale producing the gas.  It is impossible at present to predict how long such a well drilled in Hampshire, for example, would last because there are no data to go on. In the USA , where thousands of wells have already been drilled to extract shale gas, there is information from the five fields that produce 80% of the gas. Here the output of a typical well drops by 80–95% in its first three years (Hughes, 2013). This implies that production from a gas field can only be maintained by drilling more wells or possibly by re-fracking an existing well.

Once it has become uneconomic a well may be abandoned by the company that drilled it but the well, and associated components such as its casing, remains in place! The UK’s Energy and Climate Change Committee (2011) ( has recommended that ‘In the crowded UK we cannot afford to risk the creation of contaminated and abandoned sites where shale gas production has stopped. The prospect of such a risk must be carefully considered when licences and other permissions are granted. We recommend that DECC should require that a fund be established to ensure that if wells are abandoned they can be "plugged". Such a fund could be established through a levy on shale gas well drilling or an upfront bond.’ Whether this recommendation will be followed only time will tell.

8. What experience is there of remediation [after fracking]?

STAP: This answer relates to the experience of fracking for shale gas in the USA.

Remediation after hydraulic fracturing for gas entails reclamation of the site (plugging the well with cement, removing all unnecessary structures from the well pad and replanting).  In addition, country roads and bridges will need to be repaired if damaged by the heavy vehicles used to transport the large quantities of water, sand, chemicals and hardware used in the drilling and fracking processes. In some instances failure of the well plug or even the casing may result in contamination of freshwater aquifers with fracking chemicals or brine from deeper saline aquifers which will, at very least, involve re-plugging the well. The cost of this is likely to be high. One company claims to have spent $730,000 per well to cap three shale gas wells in Pennsylvania (Anon, 2013) while a 2011 study (Hefley et al, 2011) put the cost at $500,000 to $800,000 per well site for the Marcellus Shale, a formation rich in shale gas.

The US experience of remediation does not appear to be good. The problems stem largely from a lack of regulation (  In most states, the cost of remediation is much higher than the bond the company must pay to the state in advance to cover remediation expenses. A further problem is that, in some states, the bonds are released one year after a well is plugged, leaving the tax payer to pick up the cost of plugging wells that fail later.  Further, legislation does not prevent drillers from indefinitely delaying well plugging and reclamation by maintaining wells in an “inactive” state. Finally, a combination of high depletion rates of gas fields, high costs and low gas prices is currently resulting in the liquidation of drilling corporations, leaving the state and the landowner no means of recompense for the damages they are left with.

While UK legislation and regulations are probably tighter than in the USA the considerable influence of shale gas companies on the UK government ( means that it will be necessary to keep a close watch on enforcing legislation on remediation if the despoliation caused by fracking in the USA is to be avoided in the UK.  Ideally, companies that employ fracking for shale gas should be required by law to provide financial assurance to cover well plugging and reclamation, restoration of damage to the environment and natural resources including the top soil, compensation to victims for damage to property and health, provision of alternative sources of potable water in case of water contamination, and full restoration of damage to public infrastructure.

9. Will the Government be offering subsidies for this as they do for renewable energy production?

WinACC: The short answer to this question is Yes, as explained below.

A subsidy in this context could be defined as ”A sum of money granted by the state to an industry or business to increase its profitability or lower the price of a commodity.” Tax breaks are sometimes included as subsidies as they are used to increase profitability or lower the price of a commodity.

A recent report by the Overseas Development Institute showed that gas production already receives tax breaks and other subsidies in the UK despite a government return showing no energy subsidies for 2012. The ODI report valued oil and gas production tax concessions at £280 million in 2011 while the OECD figure for UK budgetary support and tax expenditures for all fossil fuels in the same year was $6.8bn (2011).

George Osborne’s 2013 budget introduced a package of financial support aimed at stimulating a UK shale gas industry. This included a new shale gas “pad” allowance, ring fenced for up to 10 years thus halving the tax the shale gas industry will have to pay. In addition shale gas producers will be able to offset their exploration and development costs against tax for a decade. The budget report also stated that the government will consult on whether these measures should also apply to other forms of onshore unconventional gas including coal bed methane and the highly controversial gasification of underground coal.

The 2013 budget also “committed the government to develop proposals to ensure that local communities will benefit from shale gas projects in their area”. These would be likely to include the use of treasury funds to incentivise communities to accept fracking and partially compensate them for any loss of amenity and inconvenience caused by it. This amounts to a further subsidy to the shale gas industry as it relieves them of these costs. It is likely, or at very least possible, that this proposal originated in a letter describing a similar proposal from Cuadrilla’s CEO to the Energy Minister Peter Hayes and copied to Lord Browne. The latter is a cabinet officer and the chair of Cuadrilla and so stood to profit from the proposal. The letter was published by the Guardian after a freedom of information request.

The “Capacity Market” scheme is a further planned subsidy to the UK gas industry but could be used for other sorts of electricity generators.  It aims to encourage companies to build new generating plants to ensure electrical supply security. The Guardian on-line (20th November 2013) claims that the scheme will pay millions of pounds to energy companies whether the new plants are generating electricity or not. The Guardian also presented evidence that the scheme is being designed by an employee currently on secondment to the DECC from ESB.  This company builds gas-fired power stations and stands to benefit from the subsidy.

Allowing gas exploration and exploitation companies to avoid paying the full cost of site reclamation could also be considered to be a subsidy. In this connection it is not yet clear whether a shale gas industry in the UK will be obliged to provide bonds made over to the government or take out liability insurance to cover the full costs of site reclamation and putting right any environmental damage resulting from the industry’s activities. In the US, the size of the bond is sometimes insufficient to pay for the damage or may be paid back to the company before environmental damage becomes evident. In addition, US companies can delay paying reclamation costs by claiming that the well is still “active” and hence may be liquidated before paying the full reclamation costs. In all these cases part of the clean up costs must be paid from the public purse.

In addition, globally fossil fuel companies currently avoid paying their share of the enormous costs resulting from climate change and marine acidification as a result of their products producing greenhouse gases when burnt. This is sometimes reckoned as a subsidy although conventional economics considers it to be an externality and disregards it.

Between 19 July and 13 September 2013, the UK Government consulted on a proposed tax regime for shale gas ( The proposals include a new shale gas "pad" allowance which would reduce the tax on a portion of a company’s production income from 62% to 30% at current rates. When the consultation was launched, the Chancellor George Osbourne said that he wanted to make the UK tax regime "the most generous for shale in the world" ( The Government is due to publish a summary of responses to the consultation later in 2013 and, where appropriate, bring forward legislation in the Finance Bill 2014.

10. What are the realistic alternatives given the amount of electrical power we need to run our services?

STAP: At present it seems sensible to consider the medium term, say up to 2030, in answer to this question. If we are to reduce the impacts of climate change, that are being caused by the amount of man-produced greenhouse gases (primarily carbon dioxide) in the atmosphere, then the production of these gases needs to be reduced as quickly as possible. In the short to medium term there are a number of ways that this can be done in the UK.

We could reduce the amount of electrical energy that we use, by reducing demand, by efficiency measures and by reducing our dependency on electrical devices. This is unlikely to be hugely significant, from our experience over the last decade or so. In addition, many predict that electricity demand for heating and transport will increase in future as the UK moves to a lower carbon society.

We could reduce emissions from baseload power production by replacing coal power by nuclear or, to a lesser extent, natural gas. However, unless the UK is very quick off the mark with nuclear power station construction, in the 2020s there will be less electricity produced from nuclear than now, because of the closure of old power stations and the time required to build and commission new nuclear power stations. So, unless baseload production is replaced by a much lower carbon system, emissions may increase.

Ideally, perhaps, in the medium term (by 2040?), it would be sensible to use our own resources of coal, in conjunction with a carbon capture and storage system at power stations, which would reduce carbon dioxide emissions from the coal by some 70-80%. Unfortunately this attractive scenario is still little more than theoretical as carbon capture has not been tested at a large scale although there are examples of underground carbon dioxide storage (or sequestration) that have operated over many years.

We could accelerate construction of, and research into, renewable energy methods of generating electricity. Of these, at present only wind power and solar power are at a stage that they can be deployed commercially in significant quantities. However tidal and wave energy have potential too. All renewable schemes rely on intermittent, but often predictable, sources of energy and require energy storage systems (‘batteries’) and/or back up generation systems. In the UK back-up is generally provided today by gas power stations. So gas is likely to be required in significant quantities for some time. However, it seems likely that emissions from conventionally produced gas are somewhat lower than those from gas that might be produced in the UK by fracking unless the conventional gas is piped from outside the EU or supplied in liquefied form (LNG). In addition conventionally produced gas is generally produced in locations that are remote from population centres (very often offshore), and thus does not result in the disturbance that fracking would give rise to in most of the UK. While gas is still required, conventionally produced gas appears a preferable option.

However with more interconnectors (electrical cables) between the UK and continental Europe, ideally Scandinavia because of the hydro, geothermal and wind power available from there, the intermittency problems associated with wind power in particular, will be greatly reduced, as the likelihood of all of Europe being windless is far smaller than for the UK alone.

There are proposals for some form of smart grid. This will enable power to be supplied and used more efficiently. For instance in the home, new appliances which do not need continuous power, such as fridges, freezers, washing machines or laptop computers with batteries, could be set automatically to stop drawing electricity from the mains (for varying lengths of time – perhaps only a minute or so) according to the demand and supply across the electricity system.

The problem of the UK’s future electricity generation is complicated. There is no simple solution and the eventual arrangement is likely to be very different from today’s highly centralised system.

Questions and answers at the meeting
11. Papers say less money made than the actual cost of bringing it out

Juerg Matters (JM): In the US there’s a flooded market which makes Fracking less financially viable.

12. What happens to the subsidence of the ground?

JM: Fracking produces a lot of ground subsidence; no surveys have been carried out in the US.

13. When is the earliest around here?

Richard Bale (RB): If you are in a licensed area you will not see it immediately. Planning permission will take a while. One planning visit will be to find out how much, then one for an appraisal. Three visits at least. Quite a while, literally months before areas will see fracking. Five years minimum I would think.

14. Where in the process will water be taken into account?

RB: Environment agency has responsibilities. There is a severe shortage of water anyway. Real risk the water, which can become radioactive, will go out to the sea.

15. What evidence is there of action from the county council?

RB: They’re not ignorant in this area. There is a collective wisdom there.

16. What provisions are taken for the long term environmental effects?

RB: Most problems take place straight after fracking itself begins. I’m not sure how long these problems last for. I don’t see there being a huge risk of uncollected methane.

JM: Every human activity will have a huge impact on the environment. We need these protocols. It’s the balance of risk of environmental impact and the need for the results.

17.  I spent the last three weeks at Balcombe. Hydrocarbons are in the past, now that age has gone.

RB: It’s not something is safe or unsafe. What’s the risk of any particular in the change to go wrong? How many wells does the Chancellor of the Exchequer want to be drilled? Then you can work out the dangers on the average.




Anon. Cabot Oil & Gas Corporation, Summary of Cabot’s Good Faith Efforts,, downloaded 01.11.2013

Hefley , W.E. and Katz , J.M 2011. The Economic Impact of the Value Chain of a Marcellus Shale Well

Howarth, R.W., R. Santoro, and A. Ingraffea. “Methane and the Greenhouse-gas Footprint of Natural Gas from Shale Formations: A Letter.” Climatic Change 106, no. DOI 10.1007/s10584–011–0061–5 (2011): 679–690.

Hughes, J.D. “Energy: A Reality Check on the Shale Revolution.” Nature 494, no. doi:10.1038/494307a (2013): 307–308.

Karion, A., and and_18_others. “Methane Emissions Estimate from Airborne Measurements over a Western United States Natural Gas Field.” Geophysical Research Letters 40, no. 16 (2013): 4393–4397.