Simulating induced seismicity using geomechanics

The best possible words in the life of an academic are undoubtably "paper accepted". Since I've recently had a paper accepted in EPSL. I thought I would add a layman's summary of it here. 

The paper is available here, and is "open access", so you shouldn't need a subscription to read it. 

Our motivation is to try to understand and model why subsurface processes cause induced earthquakes. Induced seismicity has become a controversial issue in relation to fracking, but in fact the risk of inducing an earthquake during fracking are much lower than the risk of inducing an earthquake by other subsurface activities, such as geothermal energy, waste water injection and carbon capture and storage. 

The main reason for this is simply a matter of volume - the more volume you inject, the more likely you are to trigger an earthquake. While much has been made of the water volumes used for fracking, they are actually quite small in the grand scheme of things. The volumes injected for waste-water disposal and for CCS are much larger than the volumes used for fracking. This is why we've seen such increases in seismicity in places like Oklahoma in recent years (it's got very little to do with fracking). 

We've also seen induced seismicity - albeit of small magnitude, less than mag 3 - at two pilot CCS projects, the Decatur project in Illinois, and at the In Salah project in Algeria, which is the subject of our study. 

Firstly, a brief introduction to the In Salah site. It's a gas field in the middle of the Sahara desert. 

Due to natural geological processes, the natural gas that is produced contains a relatively high percentage of CO2. This must be stripped off before the gas can be sold - there are minimum CO2 content requirements. Usually, the CO2 would just be vented to the atmosphere. However, the operators of the site, BP, Statoil and Sonatrach, decided to use the site as a pilot project for CO2. So they instead re-injected the CO2 into the water-leg of the reservoir (part of the reservoir unit that is filled with water rather than gas). The image below shows the basic principles in cartoon form.  

In total nearly 4 million tonnes of CO2 were injected between 2004 - 2011. The average car emits about 4 tonnes of CO2 per year, so that's the equivalent of the annual emissions of 1 million cars.

The site was monitored using a number of methods, but it was clear from relatively early on than the CO2 injection was producing geomechanical deformation. As a result, microseismic monitoring was used to image any small earthquakes. You can read more about the results of the microseismic monitoring here, but the main conclusions were that thousands of small-magnitude (mostly around magnitude 0.0) events had been induced. The largest event was magnitude 1.7, which is probably too small to be felt by humans at the surface (we can detect them with seismometers though of course), and definitely too small to cause damage. Fortunately, all the events were confined to the reservoir unit, so there was no evidence that the seismicity was providing a pathway for CO2 to escape.  

So, what's this latest paper all about?

The basic premise of our study was that induced events occur on pre-existing fractures. They occur because industrial activities change the state of stress in the subsurface, moving a fault from a stable to an unstable state, which allows it to move, triggering an earthquake. So in theory, if we can predict or model where the faults and fractures are, and we can predict or model the changes in stress generated by our activities, we can resolve the stress changes onto the faults, and work out when and where faults might trigger seismicity. The purpose of our paper was to assess how well this approach works in practice. 

To model the size, orientation and positions of faults and fractures I am indebted to my colleague Dr. Clare Bond at Aberdeen, who build a structural model of the reservoir, which simulates how the reservoir geometry we observe today could have formed from the originally-flat sedimentary layers. This produces a strain map, which is then converted into a discrete fracture network to account for how fractures would have accommodated the modelled strain. The resulting fracture map is shown below: you can see that fractures are not uniformly distributed across the reservoir, but there are bands of intense fracturing running through the reservoir, and zones with much fewer fractures. 

In order to simulate the stress changes induced by injection, I am indebted to another colleague, Rob Bissell, from Carbon Fluids Ltd., who built a geomechanical simulation of the injection process. More details about this model are available here. The model provides a map of stress and pore-pressure changes at monthly intervals through the injection period. 

In order to work out whether the modelled stress changes would be sufficient to induce seismicity, for each modelled fracture we resolved the modelled stress from the nearest node of the geomechanical model into normal and shear stresses on the fracture face. If the shear stress exceeded the Mohr-Couloumb criteria, then an event will occur. The size of the event will be determined by the stress drop generated by the event, which will be a function of the shear stress, and the size of the fracture, which is pre-determined in the model provided by Dr Bond. 

Therefore we have a method to simulate when and where an earthquake may occur, and how big it will be. We tested our model simulation results against the microseismic observations made by my colleague Dr. Anna Stork in this paper. 

The figure below shows that the relative rates of seismicity predicted by the model matches that observed at In Salah. CO2 injection re-starts in late 2009. However, only a small amount of seismicity is observed. Injection rates increase in summer 2010, and for 4 months the rate of induced seismicity also increases. Once injection rates are reduced, the number of events decays away as well. This behaviour is well captured by our model. 

In terms of magnitudes, our modelled largest event matched very well the observed largest magnitude of M=1.7. Magnitudes are determined by the size of the fault and the stress drop, so this indicates that Dr Bond's model did a good job of simulating the fault/fracture sizes, and that Rob Bissell's model did a good job of simulating the stress changes induced by injection. 

Overall, our model does a good job of simulating induced events at In Salah, which is encouraging in terms of our future ability to mitigate induced seismicity at future projects. We have outlined a workflow that can be followed at sensitive sites where induced seismicity may be an issue. For example, the modelling approach can be used to assess whether alternative injection strategies may lower the risk of inducing an event. 

Landmark shale gas study shows no groundwater problems

One of the difficulties in the current shale gas debate is that good data is hard to come by. Operators collect lots of data from around their sites, including water sampling to test for pollution, and geophysical monitoring to track where the fractures went during stimulation. However, this data is often considered commercially sensitive, so it rarely sees the light of day.

A government-sponsored project would be very useful, because it would provide a test-bed for an extensive monitoring program. All data could then be made public, and the claims of all those involved in the shale gas debate openly tested.

This is exactly what has been happened in the USA, with the final report released this week. The US National Energy Technology Lab (NETL) sponsored a monitoring program at a hydraulic fracking operation in Greene County, Pennsylvania. The monitoring program consisted of 2 parts: microseismic monitoring to track the fractures created by the stimulation, and geochemical sampling in overlying layers to test whether any contamination has occurred. Most importantly, because the data is publicly available, it's a great opportunity to talk through the anatomy of hydraulic stimulation.

The first stage of shale gas extraction is to drill horizontal wells through which the fracking will be done. The figure below shows a map of the lateral wells drilled. Those in the yellow box were the 6 wells that made up the NETL study.

Image (video) of the Day: How near-surface microseismic monitoring works

As part of the monitoring requirements for their new wells in Lancashire, Cuadrilla are installing near-surface microseismic monitoring arrays. Geophones are buried to depths of 50 - 100m. They are capable of detecting the small "pops" and "cracks" as the shale is fractured, allowing the operator to map where the fractures are going as the stimulation progresses.

This video explains how the technique works, and how it is used both to allow operators to maximise the efficiency of their operations, and to minimise any environmental risks.

The video is made for an American audience, and I think to UK eyes it comes across as a little slick and "corporate", but it's well worth a watch.

New paper: Estimates of error in micro-earthquake magnitude estimation

With excellent timing, on the same day as the new BGS report into the shale oil potential of the Weald Basin, a new paper, written by two co-workers at Bristol Uni and myself, has been released in Geophysical Prospecting. In it, we examine the uncertainties in estimates of event magnitude made on small earthquakes.

This paper is significant for shale gas extraction in the wake of DECC's traffic light system (TLS) proposal for fracking operations. Under the TLS, operational decisions during the fracking process must be taken on events as small as magnitude 0.0 (the amber level), with complete cessation of activities for events larger than magnitude 0.5.

As most people are aware, a magnitude 0 event is very small, at the limit of what can be detected using conventional seismographs (see our efforts at Balcombe, for example). Expensive downhole microseismic monitoring systems are required to robustly detect smaller magnitudes.

The TLS pre-supposes that earthquake magnitudes at this low level can be accurately determined. The purpose of the TLS was to provide a simple-to-understand system to re-assure the public. Uncertainties in event magnitude estimation could undermine this, generating more controversy, not less.

We show in our paper that event magnitude estimations at these low levels can be very uncertain: you can get different answers depending on what methods you use and assumptions you make. It doesn't take too much imagination to think of a scenario where one group reporting on a fracking operation concludes that an induced earthquake was just below the TLS threshold, but another group using a different method finds that the earthquake did exceed it. The current debate over shale gas extraction is febrile enough as it is, can you imagine the recrimination and the confusion that such an eventuality would generate?

Image of the day: Hydraulic stimulation at Cotton Valley

Microseismic monitoring technology allows geophysicists to map the fractures as they are created during the stimulation process. This image shows a map of the fractures created during stimulation at Cotton Valley (an early East-Texas tight gas play). This shows the extent of a typical stimulation zone - a few hundred meters either side of the injection point, and no more than 50m above the injection depth. The black triangles show the geophones used to collect this data.

Seismometer Deployments at Balcombe: Final Report

Cuadrilla's drilling at Balcombe attracted a lot of headlines. In a previous post I described (mainly by way of lots of holiday snaps) the deployment of seismometers by Bristol colleagues and I.

We have now completed our data analysis, and our results are available for you to read!

Hydraulic stimulation was not planned for this phase of Cuadrilla's operations. Therefore, we did not expect to see any induced seismic events. Nevertheless, we saw this as a good opportunity to attempt several objectives:

The first objective was simply about public perception. The average member of the public does not know much about earthquakes or about seismometers. They don't really understand magnitude scales, and they are not aware of the detection capabilities of modern seismometers. We hoped that the high levels of publicity surrounding Balcombe would give us a chance to help educate the public in these regards.

However, we had two main technical objectives as well. These relate to DECC's proposed traffic light scheme, whereby operators are required to stop if they trigger events above magnitude 0.0. Traffic light schemes are common for such operations - the Swiss in particular seem to like them. However, the minimum threshold here is far lower than anything used by the Swiss. Our aim is not to say whether this is appropriate or not, but its operation does pose some additional challenges, which our work seeks to address.

The first issue stems from the Gutenberg-Richter law, which states that the number of earthquakes (N) that occur which are larger than a given magnitude (M) is given by
                             log(N) = a - bM.
where a and b are measurable constants. The BGS gives values for a and b in the UK of 3.82 and 1.03, respectively. Using a magnitude of 0.0 (the lowest cutoff for the traffic lights), this relationship tells us that over 5,000 such events occur every year. The existing BGS seismic network is not capable of detecting these low magnitude events.

In order for the traffic light scheme to work effectively, we need to be able to distinguish between the 5,000 naturally occurring magnitude 0.0 and greater quakes that occur each year, and those induced by hydraulic stimulation. This requires us to have data about the naturally occurring events, which we do not currently have. Therefore, one purpose of our array was to begin to establish baseline measurements around a potential drilling site so that we can characterise any pre-existing, natural seismicity. This is but a small start, with only 1 month of background data. In an ideal scenario we'd want to have at least a year of baseline data.

The second purpose of our array was to measure typical levels of seismic noise and detectability thresholds for small, temporary arrays such as ours. The traffic light threshold of magnitude 0.0 is often at the threshold of detectability for surface seismometers. The detectability is controlled in part by the levels of noise on the seismometers. Although you might think the British countryside is a quiet place, there are many potential sources of noise, such as trains, roads, farm machinery, rivers. We wanted to see whether a small, relatively cheap array like ours would be helpful in administering the traffic light scheme, or whether more expensive microseismic monitoring methods are likely to be needed.

So, what did we find?
Well, the most obvious thing we saw was the train, made famous by local concerns about seismic impacts on the viaduct. We saw the train on all 4 seismic stations that we deployed. Here is an example:

You can see that the train is coming from the north. It is seen on station BA02 first, which is the northernmost, and on BA04 last, which is the southernmost. BA04 is only 150m from the rail line, so you can see the biggest signal on this station.

We wanted to compare the vibration from the train with typical earthquake magnitudes. To do this we used the UK magnitude scale, which is defined as
                             Ml = log(A) + 0.95log(R) + 0.00183R - 1.76,
where A is the amplitude of the signal at the station, and R is the distance between earthquake and seismometer. We modelled earthquakes occurring directly below the drilling site, and found that a quake with magnitude of 1.5 (the same as the 2nd Preese Hall quake) produced a similar amount of vibration to the train going past at 150m.

We used an automated trigger algorithm to search our data for potential local seismic events. Sadly, we didn't see anything that looked like a local earthquake, either before or during drilling.

The seismometers that we used are actually designed to detect earthquakes from around the globe. We did spot a number of such events (called "teleseismic arrivals"). Here's an example from a magnitude 7.7 event in Pakistan:

This map shows all 25 such events that we spotted:

One of our stations was only 300m from the drilling site. We did notice that things got slightly noisier on this station when drilling started. This figure compares the background noise before and during drilling. A simulated M0.5 event is shown - this shows up above the noise for both cases.

We didn't see any events during our monitoring period. However, we wanted to work out what we could have seen, had something happened. We simulated earthquakes occurring below the drill site, with a variety of magnitudes, and ran the simulated data through our automated detection algorithm, to see what was the smallest that could be reliably identified, given our recorded noise levels

We found that magnitude -0.2 was the smallest we could see. This simulated event is shown below:

As you can see, it just peaks up above the noise. This is the smallest event we can expect to see. This is just below what is required for the traffic light scheme, so a small array like this could work. However, I'd want to see a larger number of stations to really push the detection limits below the magnitude 0.0 cutoff.

Discussion - Accurate event magnitudes?
We finish with a number of recommendations for the implementation of the traffic light scheme (TLS). A fact unbeknownst to most non-seismologists is that there are in fact a number of different magnitude scales, depending on how magnitude is measured. They are all designed to be close to each other, however they are not always exactly the same.

The most common magnitude scale is known as "local magnitude", or ML. This is basically the good ol'fashioned Richter scale, and is fairly simple to compute. You simply measure the maximum amplitude of the seismic trace, you take the distance from source to receiver, and you put it into a local magnitude equation as I outlined above.

An alternative magnitude scale is the "Moment magnitude", or Mw. This directly relates to the moment (read 'force' or 'energy' in layman's terms) released by the earthquake, and in turn to both the size of the fault and the amount that the fault slipped. Mw is slightly harder to compute - you have to look at the frequency content of the earthquake signals - but probably a better representation of the physical process occurring in an earthquake (as opposed to an empirical approximation, as provided by ML).

Small, local arrays such as ours will typically report ML. However, the dense coverage provided by microseismic arrays (as now installed at Preese Hall) often report Mw. It needs to be made absolutely clear how these different types of measurements will be factored into the TLS, because they may not be exactly the same - indeed at small magnitudes they can be different by half a magnitude unit or more. So, for example, what happens if a quake is measured with ML = -0.1 but Mw = +0.1?

Similarly, all measurements of magnitude are subject to an error. This is rarely reported for the large earthquakes you see on TV - the relative signal to noise ratios for a large event are so large that you can be sure that it is magnitude 6.5 (or whatever) ± a very small amount. However, as you enter the world of micro-seismic events, the signal to noise ratio deteriorates (as you can see in image #6 above). As this happens, the error in the calculation gets larger. Again, the incorporation of errors into the TLS needs to be clarified - what happens if an event has magnitude -0.1 ± 0.2?

These issues do not invalidate the traffic light scheme. However, given that operational decisions, and therefore potentially millions of pounds, hang on the accurate characterisation of event magnitudes, it would be helpful to iron out any potential inconsistencies now, rather than in the wake of another induced event.




In closing, I would like to thank the co-authors of this work, who don't yet have blogs of their own.

Professor David Smythe's critique of Cuadrilla's drilling plans: A comment

Update (1.8.2014): It seems that the Geological Society are very unhappy about Prof. Smythe claiming to be a chartered geologist. The Geol Soc state that this title requires "proof of continuous professional development", with the clear implication that they do not believe Prof. Smythe meets this requirement.

Glasgow University are also unhappy about being associated with the professor. Paul Younger, Professor of Energy Engineering at Glasgow stated:

"He has published nothing on [shale gas] in any proper scientific forum — no doubt because he knows he would never get past peer review with his pseudo-scientific scaremongering. He falsely claims to be a chartered geologist. That’s fraudulent. It’s wilful untruth. I am concerned about the damage to the reputation of the university by someone who never fails to use his university affiliation.”

Original Article:
This post is a comment on the critique of Cuadrilla's Balcombe drilling plans made by David Smythe, Emeritus Professor of Geophysics at Glasgow University. The key points of this critique are as follows:

• Cuadrilla's interpretation of faults in the Weald basin differs from a potentially more parsimonious interpretation.
• Cuadrilla's interpretation omits smaller faults near to the well site, some of which might intersect a horizontal well.
• Seismic data is restricted to 2D seismic profiles of 1990s vintage, making it challenging to keep the horizontal well within the target micrite layer.
• If the well does stray out of zone, it may contact Kimmeridge Clay an important potential shale resource. It is suggested that the proposed micrite target is in fact a "cover story" for the targeting of Kimmeridge shales.
• Concerns are raised that if faults are intersected, they may act as "fast-track conduits" for surface water contamination, and/or lead to the triggering of seismic activity.

My comments are as follows:

There are indeed differences between the fault interpretations made by Cuadrilla and by Prof. Smythe. Without access to more data it is probably difficult to determine whose interpretation is the more accurate. This is a fact appreciated by all geology students who have ever done a mapping project: with limited data multiple interpretations are always possible. However, disagreements between fault locations are limited to the areas south of the Bolney well, which are not in Cuadrilla's license area. Within Cuadrilla's license area, the principal area of interest, both sets of fault interpretations are closely matched.

It is argued that the lack of 3D seismic data means that it will not be possible to keep the horizontal drill within the target micrite formation, and that it will not be possible to identify if/when small faults are intersected. This criticism ignores one of the key technological developments of the last 20 years, which is closely associated with the development of horizontal drilling. That technology is called "Geosteering" (also known as "Logging While Drilling"). For more detailed info on these techniques I'll have to hand you over to google for now, but this article provides a decent explanation.

Essentially, geophysical measurements are taken continuously at the drill tip. This data tells drilling engineers what rocks they are in. They use this to guide where the drill goes, allowing them to stay within the target formation. If you read the linked article, you'll note that it even allows engineers to see when they've intersected faults. Geosteering is common practice when drilling horizontal wells in the Barnett and the Marcellus, the two most significant shale plays in the US.

I'll include here some comments on a couple of issues raised on Prof. Smythe's website, which don't appear in the linked slides but form a key part of the conclusions outlined above. In the comments on faulting in US and European basins, he argues that "faulting is almost non-existent in the US basins". This isn't the first time I've heard this suggestion, and I don't know where this meme has come from. The eagle-eyed among you will have spotted this comment in the linked Geosteering article:

"In some areas in Pennsylvania, the geology is very complex across some of our leases," Collins noted. "There are very large thrust faults"

I've even had the pleasure of seeing them myself - they tend to show up in microseismic data. You can see an example in this paper, and below is another microseismic dataset clearly showing the interaction of the stimulated stages with a fault:

(image courtesy of Microseismic Inc)

Faults are clearly not "almost non-existent in the US basins". Prof. Smythe criticises the well-known Warpinski-Fisher paper that looked at hydraulic fracture height growth for its failure to include fault data. However, the Warpinski-Fisher paper explicitly includes data from examples when hydraulic fractures have intersected faults (see slides 7 and 11 in this presentation, for example), providing clear evidence that stimulation does not create pathways from deep-lying reservoirs to shallow potable aquifers, even when faults are present.

I would also like to address the comment that "faults do not normally act as seals". This is a misleading comment. It is true that when risking a potential reservoir trap identified on seismic data, the observation of faulting on the top of an anticline would present a risk, because with seismic surveys alone it is difficult to tell whether a fault might be sealing or not, and so whether there might be hydrocarbons present, of if they might have all leaked away over geological time.

However, it is not true to claim that "faults do not normally act as seals". Fault traps - where the geometry of faults and reservoir units serve to form a trap, instead of the traditional anticline domes - are a common method of trapping oil and gas. If that last sentence didn't make sense, there are plenty of pictures on google. Fault compartmentalisation - where sealing faults break up a reservoir and prevent fluids from flowing to the well - is a common problem in conventional reservoirs. You can read about a case example here. A particularly pertinent quote is "clay-rich lithologies (i.e. shales) are likely to reduce fault zone permeability (i.e. provide better fault sealing) more than clay-poor lithologies". We know from Conoco's drilling in the 1980s that oil is present in the micrite beds underneath Balcombe. This oil has been trapped there for hundreds of millions of years. This would suggest that, even if the Paddockhurst Park Fault does intersect the target micrite formation, it is not providing a transmissive pathway to flow.

Finally on the issue of induced seismicity. It is a misconception that if a hydraulic stimulation intersects a fault, it will inevitably create a "larger" earthquake (i.e. one that might be felt by humans at the surface, such as at Blackpool). Again, this is not the case, as documented in the microseismic examples above. It is not uncommon for stimulations to intersect small faults, yet incidences of felt seismic events are extremely rare amongst hundreds of thousands of stimulations. Although in some cases event magnitudes have increased slightly upon intersection with a fault, they remain well below the threshold that could be felt at surface. For hydraulic stimulation to trigger detectable seismic events, the stress state on the triggered fault must already have optimal orientation and magnitude - that is to say the fault must already be close to it's failure state. The majority of faults likely to be intersected during stimulation will not meet these criteria, hence the lack of detected seismicity during operations in the USA, and hence the conclusion by the expert report into the Blackpool earthquakes that they represent "exceptional" circumstances.

That said, as with pretty much any subsurface activity, there is a small risk of triggering small seismic events that should be considered. DECC have already put into place strict seismic monitoring guidelines to ensure that there is no repeat of events near Blackpool. Bristol University already has seismic monitoring stations deployed around Balcombe.

I agree with some of the more general suggestions made by Prof. Smythe: more geophysical surveys will enable us to better understand the subsurface geology. This is beneficial all around - enabling operators to maximise their production efficiency while regulators can minimise any environmental risk. I expect that as potential shale gas developments move through exploration into preliminary production phases, we will see more and more geophysical data being collected (as we have already seen a new 3D seismic survey collected on the Fylde). However, I strongly disagree with Prof. Smythe with respect to current operations at Balcombe - they are not likely to pose a significant risk in terms of fluid migration from depth or from induced seismicity.

Update (04/09/2013): Another example of hydraulic stimulation interacting with faults without adverse impact is the NETL hydraulic fracturing study, which received a lot of coverage last month. In this study, researchers injected tracer chemicals along with the fracking fluid. The shale layers were at 8,000ft depth, and an overlying layer at 5,000ft depth was monitored, looking to see if the tracers appeared in this overlying formation. The microseismic data from this operation has not yet been published, but reports seem to indicate that the stimulation intersected a fault. Even so, there was no evidence for the tracers in the overlying formation, nor were any larger-magnitude seismic events triggered.

Update (05/09/2013): Of course, I've missed perhaps the best example of stimulation intersecting a fault, in fact probably the best known one: the operations near Blackpool that triggered seismic events in 2011. This is the worst-case scenario - a stimulation intersecting a fault that is optimally oriented in the present day stress field, and close enough to failure that the stimulation is capable of triggering some of the largest seismic events ever seen during hydraulic fracturing in shales. Yet even for this worst-case example, the operators were able to produce gas from the reservoir, without any suggestion of shallow groundwater contamination from this fault.

Seismometer deployment to monitor drilling at Balcombe

If you follow me on twitter as well as reading my blog will know that I go by the name @TheFracDoctor. This choice of name was influenced in part by the fact that I had recently finished my PhD, and as anyone who has experienced the flush of post-viva success, there is the temptation to put the word ‘Doctor’ in front of everything. 

But also it is the role of the doctor to monitor the health of his patient, and that is how I see seismic and micro-seismic monitoring – a tool to monitor the health of a fracture stimulation.

In the last few weeks I’ve had the opportunity to do this for real in the UK for the first time: deploying seismometers around Cuadrilla’s planned Balcombe well. I’ll note right now that the current Cuadrilla plan is to drill into limestone for conventional oil, with no intention of hydraulic fracturing at this stage, but we wanted to get some experience deploying seismometers for this sort of situation.

However, Balcombe is the site of the now-infamous ‘Battle of Balcombe’ and has been at the center of much debate of unconventional gas extraction (these stations were put in a month ago, well before the events of last week). Of particular focus has been the risk of seismic activity to the Balcombe Viaduct.

This spectacular bridge, built in 1841, still carries the main London-to-Brighton rail line:

After the seismic events during stimulation at the Preese Hall well, Blackpool, concerns were raised about the possibility of similar seismic activity affecting this bridge. So we decided to deploy seismometers while they drill their Balcombe well. There are no plans for fracking at the moment, so we’re not expecting any seismic activity. Our main aims were (1) to get some experience deploying seismic stations in rural England, and (2) to record baseline activity prior to drilling.

Baseline data will help us understand the noise levels in the area, which will determine the size of the smallest earthquake we can detect – obviously the lower the noise level, the smaller event you can detect. The current traffic light scheme for seismicity proposed by DECC requires events as small as M0.0 to be detected. We want to see if this will be possible with a small array of 4 surface seismometers (we will compute the expected shaking from an M0.0 event, and see if it emerges above the noise).

Baseline data will also enable to see what changes (if any) drilling activities produce.

I will post updates as and when we collect and analyse the data. For now, this seems like a good time to share some holiday snaps, so you get to learn about what we do when we deploy seismometer arrays, and what they look like.

Firstly, here’s the piece of kit that we use: a Trillium 120 seismometer:

This is a fairly standard piece of kit in earthquake seismology, capable of measuring the vibration of the earth across a wide frequency, from long periods (up to 60 seconds) up to the sampling rate of 250Hz.

To reduce the noise from things like wind and rain, they need to be buried 50cm or so under ground. Which means you have to dig a hole. I used to work on building sites during my A-levels, and I was delighted when I got my degree, knowing that my days of manual labour were over (because digging holes all day is TOUGH work). Yet, a masters degree and PhD later, and here I am digging holes all day!

Once the pit is ready, the seismometer is carefully placed into the hole:

The batteries and data logger go in the steel box next to the pit. We run cables, insulated inside fire hose, from the instrument into the box:

 

Initial covering for the instrument, to further minimise surface noise, is provided by its ‘lid’, the black dome you can see below:

Once we are happy that the instrument is working properly, we fill the hole (being careful not to dislodge the insulating cover from the instrument. We lay a waterproof sheet just below the surface, and pile turf on top as a final covering:

Finally, we put a small chicken-wire fence around the station. This is more of a deterrent than anything else: it’s not likely to stop a marauding cow, nor is it really capable of keeping out a determined rodent (animals chewing on loose cables is a real problem in many seismic deployments):

And after all that (a couple of hours work at least), you have your seismic station:

We placed 4 stations in total, including one a few hundred yards from the viaduct:

As we set this station up, we could see the vibrations from the trains going past every 5 minutes recorded on our seismometer. It will be interesting to see what caused more vibration – the Preese Hall earthquakes or the train going past at a distance of a couple of hundred yards. After all, the initial concern at Balcombe was that seismicity would trouble the bridge – even though this is a bridge that is being shaken by an express train every 5 minutes.

We enjoyed our two days in the picturesque British countryside, and we were very glad we missed all the protestors. Fortunately, the stations are all a couple of km at least from the London Road protest site, and accessible from other roads, so that’s a gauntlet we won’t have to run. The only disturbance we saw was from these guys:

So there’s our seismic deployment in Balcombe. More to follow once we’ve analysed the data.

Permeability estimates from microseismic data

Those who've followed this blog for a while will know that my attitude to open access publishing is luke-warm at best. However, today I can claim that I'm doing my bit for OA, because a colleague has had a paper published in the 'International Scholarly Research Network' Geophysics Journal. Which means you can read it free of charge here.

Personally, I would have preferred to submit to a more established journal. ISRN Geophysics has published a total of 9 papers ever in its history. Geophysics (published by the SEG) has published about 30 papers a month since 1936. I doubt this paper will ever win me any points in a REF submission. However, it'll be interesting to see whether the fact that it is open access leads to a higher number of citations down the line.

What I will say is that I was very impressed by the speed at which Hindawi Publishing turned the article around. I have an article still awaiting publishing in Geophysical Prospecting that has taken more than a year and is still not yet available. This article was submitted in mid December, and is now available online with DOI number by mid-February, which is frankly pretty damn good.

Anyway, since it is openly available to you, I thought I might try to explain what we have done in the paper. So here goes:

One of the crucial things that reservoir engineers always want to find out about a reservoir is the permeability, because this controls how fast the gas and/or oil will flow to the well. There are a number of ways permeability can be estimated, but my colleague Doug Angus at Leeds University has been coming up with a way to estimate it using microseismic events.

During hydraulic fracturing (fracking), microseismic events are triggered by the pulse of fluid pressure moving out from the wellbore. Much as the speed of the gas going into the well during production will be controlled by permeability, so the speed of the pressure pulse moving away from the wellbore during fracking will be controlled by permeability. So by tracking the distance of the microseismic events from the well through time, we can estimate the permeability.

Much of the work on this has been done by Serge Shapiro of Freie Universitat Berlin. The Shapiro method assumes that microseismic events are triggered by small pore pressure perturbations, and solves the diffusion equation to determine how quickly events should move out from the injection well. However, what this doesn't take into account is the deformation of the rock itself. The increases in pressure will be causing poro-elastic deformation as well. An alternative model developed by Alexander Rozhko of Schlumberger incorporates the triggering of microseismic events through stress changes produced by poro-elastic deformation.

In this paper, Doug compares the two models, using them to predict the microseismicity induced during a multistage fracking operation, where in one stage water was used as the fluid, and in the other CO2 was used. Despite the different fluid properties, both methods should in theory recover the same permeabilities.

The following figures show how the two different models fit the data (first the Shapiro diffusion model, then the Rozhko poroelastic model):
Note that while both models fit the data reasonably well, both make very different predictions for what would happen to the microseismicity though time had the injection continued. With the diffusion model, event-injection point distance keeps increasing, with the poro-elastic model it becomes capped.

The permeability estimates for both models are broadly consistent - approximately 50-100 milliDarcies (no, not a small Colin Firth). However, the estimates from the poro-elastic method are more consistent and more stable. Therefore, based on this dataset at least, this method is Doug's preferred choice for permeability estimation using microseismic event locations.

So there you are - my first OA paper, and an attempt to explain it in layman's terms. I hope you made it to the end.

BGS shale gas estimates: an update, and other London meetings

I've just got back to Bristol from a very interesting few days in London, first at an AAPG conference on induced seismicity, followed by a BGA conference on geophysics and new energy challenges.

The first item of note was a talk given by Mike Stephenson of the BGS on UK shale gas. He didn't mention any numbers from the upcoming BGS resource estimate, so I took the trouble of asking him for a comment on the numbers published by the Times last weekend. In his words: 'they've simply made those numbers up'.

Fair enough, I guess that'll teach the likes of me to go jumping on every number you see in the press. Of course, he'd have to say that, as it would be embarrassing for the BGS to have had a leak, but either way hopefully the BGS will get around to giving us some figures in the very near future (it was originally supposed to be released in January, and we're still waiting).

I also got to have a good long chat with Huw Clarke, who is Cuadrilla's chief microseismic guy. One thing that noone has really talked about much is the flow rates from Cuadrilla's fracked well.

We've all talked plenty about the earthquake they produced, but we've all forgotten that they successfully completed 6 stages of fracking, and have tested the flow rates they got back after the frack. Whether or not the flow rates are sufficient to be economical will be a key part of whether shale gas extraction will happen in the UK.

Of course, Cuadrilla's flow rates are highly highly highly commercially sensitive, and there's no way Cuadrilla are going to tell anyone what they are. But it's interesting to note that, after having measured the flow rates, Cuadrilla have been happy to pay for a 3D seismic survey, the installation of a dense array of permanent geophone sensors, and a whole heap of PR on the side (as well as leaving the drilling rig parked in Lancashire when it could be drilling holes anywhere in Europe).

These aren't the kind of things you'd do if you have concerns about the economic viability of the gas flow rates from the shale formation, which of course implies that Cuadrilla probably think they're sitting on some pretty significant resources.


Other things that came up in these conferences? One of the major themes can be summarised as 'Induced seismicity, friend or foe', or 'Induced seismicity, the good, the bad and the ugly'. Of course, if you've met many geophysicists, you'll know what the 'ugly' is describing.

Whenever you inject fluids into, or take fluids out of, a reservoir, you change the stress state. This will almost inevitably induce earthquakes. The majority of these are so small (M-3 to M-1) that they can only be detected with sensitive seismometers placed right next to the target of interest. We geophysicists locate the microearthquakes, using them to learn about the stress state and fractures in the reservoir, enabling operators to improve the safety and economic viability of their operations. This is the good, or friend, part of induced seismicity.

However, every so often, as at Blackpool, operations create a larger event, which can be felt by the public. This tends to cause a lot of alarm, and the operators start to feel the regulators breathing down their neck. This is induced seismicity the bad, or the foe.

The big problem is that we're still not really very good at predicting when we'll just get small events, and when we'll get larger ones. Clearly the presence of a pre-existing fault is needed for a larger event. But many operations occur right next to faults without triggering any seismicity.

So it seems we still don't know why 99% of our activities don't trigger felt seismicity, but some do. There are probably about 150,000 waste-water injection wells in the US, and only about 10-20 have induced felt seismicity. There have been hundreds of thousands of fracking stages completed in the US, yet only one in Oklahoma, one in Blackpool, and a few in British Columbia, have triggered felt earthquakes.

So this was probably one of the key aspects emerging from these two meetings: the need to develop improved geomechanical modelling of reservoir activities (whether it be fracking, carbon dioxide injection for CCS, or waste-water injection), so we can predict whether we're likely to trigger a larger earthquake on a fault. So if you are a budding geoscientist or engineer deciding what direction to pursue, I'd recommend looking in to this, because improvements in this area will be really significant for a lot of industries.

Ed Davey's Written Statement on Shale Gas: Highlights

Well done if you got to the end of my previous post, Ed Davey's full statement on shale gas extraction. In case you didn't, I've selected the highlights with respect to induced seismicity:

I have concluded that appropriate controls are available to mitigate the risks of undesirable seismic activity. Those new controls will be required by my Department for all future shale gas wells.

 So any new regulations will be applied to all wells.

the amount of energy likely to be stored in these faults is not large, and the largest earthquake likely in this area from such a cause is assessed at magnitude 3.

Seems reasonable that the maximum likely quake is the same as those typically seen in background rates.

Operators will first be required to review the available information on faults in the area of the proposed well to minimise the risk of activating any fault by fracking, and required to monitor background seismicity before operations commence. Real time seismic monitoring will also continue during operations, with these subject to a “traffic-light” regime, so that operations can be quickly paused and data reviewed if unusual levels of seismic activity is observed.

Very interesting, and good news for service companies. The 'available information' on faults in the area must surely imply 3D seismic surveys prior to any fracking. Good news if you are WesternGeco et al. Also, real time (micro)seismic monitoring is required. Good news for microseismic companies (and researchers like me).

Real-time recording of earthquakes during and for 24 hours after each stage of the frac will be analysed to look for abnormal induced events amidst the normal background seismicity.

Again, more good news on real time monitoring. I'm not sure how we'd classify an 'abnormal' event though.

Operators will also be required to monitor the growth in height of the frac away from the borehole. This will allow the operator to evaluate the effectiveness of the frac, but also ensure that the actual fracture is conforming to its design, and that it remains contained and far away from any aquifers.

To monitor the growth in height of the fracture will require accurate microseismic monitoring, with depths in particular being well constrained. This means deployments of significant arrays. Chucking a couple of broadband seismometers nearby will not be sufficient - large dense surface arrays or downhole arrays will be required.

the remedial action level for the traffic light system (that is, the “red light”) will be set at magnitude 0.5 (far below a perceptible surface event, but larger than the expected level generated by the fracturing of the rock).

Cuadrilla's 'traffic light' system will remain in place. This states that fracking must stop if an event larger than M0.5 is induced. In principle this is a sensible limit. However, it throws up questions of it's own, because in science there are such things as error bars. There's no such thing as an M0.5 event. There's M0.5 ± some value. There are also several different ways of computing magnitude, which don't always produce the same value. The question is then: do you take the highest possible value, the lowest possible value, or some mean (most probable) value as the point at which the traffic light red is exceeded?

And who gets to decide? Industry themselves? Probably not the wisest move. DECC themselves? Do they have the expertise - not really? <begins shameless self promotion> how about independent academic experts?< /ends shameless self promotion>

All told, good news for shale gas companies looking at the UK, but even better news for service companies (and researchers) with experience in microseismic monitoring!  

Ed Davey's Written Statement on Shale Gas: In Full

The news this week has been buzzing with the recent decision by DECC to allow hydraulic fracturing in the UK to continue. Here's the Energy Minister's statement in full:

Shale gas development has been of increasing importance in the US for some years, but exploration has only just begun in the UK. The potential of producing shale gas from a suitable formation can only be established by fracturing the rock, and it happens that the fracturing of the first shale gas well in the UK, at Preese Hall near Blackpool last year, resulted in noticeable seismic tremors. These were not at a level which could cause any damage, but seismic activity at this level was not an expected consequence of the fracking activity, and DECC therefore suspended all fracking operations for shale gas pending a thorough investigation of the causes of these tremors and the scope for mitigation of seismic risks in any future operations of this type. I am announcing today the outcome of that investigation and the way forward on exploration for shale gas in the UK.

Having carefully reviewed the evidence with the aid of independent experts, and with the aid of an authoritative review of the scientific and engineering evidence on shale gas extraction conducted by the Royal Academy of Engineering and the Royal Society, I have concluded that appropriate controls are available to mitigate the risks of undesirable seismic activity. Those new controls will be required by my Department for all future shale gas wells. On that basis, I am in principle prepared to consent to new fracking proposals for shale gas, where all other necessary permissions and consents are in place.

This opens the way to a resumption of work on exploration for shale gas, though I stress the importance of the other regulatory consents, and planning permission, which are also necessary for these activities, and which must be in place before my Department will consider consent to individual operations. In practice, it will be well into next year before any new exploration work has all the necessary consents to proceed. Whether any production operations may be proposed will depend on the success of the exploration work, but, in any event, this is likely to be some years away yet.

The background is that, in most oil and gas fields worldwide, the oil or gas is extracted from a relatively porous rock, usually a sandstone or calcareous rock, in which it has been accumulated or trapped. The original source of the petroleum however lies elsewhere, in deeper formations of non-porous rocks classed as shales. These shale source rocks are widely distributed around the world, and exist in many areas of the UK.
It has long been recognised that very substantial quantities of oil and gas were trapped in these shales, but the scope for its economic extraction seemed small - largely because the rock in its natural state allows the oil and gas to flow into a well only at very low rates. In the last twenty years, however, further development of oilfield technology, first in the Barnett Shale in Texas, has enabled economic large-scale extraction of gas, and oil, from these source rocks.

One of the key technologies involved is hydraulic fracturing, or fracking. This is carried out by pumping water at high pressure into the shale formation, which forms blade-like fractures, a few millimetres wide and extending several hundred feet away from the well bore. Once the fractures have started to form, sand or a similar material is pumped in, to hold the fractures open once the pressure is released. The fractures can continue to grow only so long as pressure is maintained. When the fractures have sufficiently developed, the pressure is released and the frac fluid, followed by the released gas, can flow into the well. The process is not novel and is also widely used in conventional oil and gas production, It is however, more intensively used in the production of shale gas.

It has been recognised for some time that injection of large quantities of water into the subsurface can cause seismic tremors. This has happened, for example, in those areas of the US in which disposal of waste water into deep injection wells is permitted. However, the quantities of water used in fracking are substantially smaller, and up until the time of the Preese Hall tremors, no association had been recognised between injection of these smaller volumes and any seismic activity. The analysis carried out by Cuadrilla’s advisers, and confirmed by our independent panel of experts, has however concluded that the most likely cause of the tremors is the movement of the frac fluid into and along a fault which was already under stress. The additional pressure of the fluid allowed the fault to move, releasing the energy stored in the fault and resulting in the perceived tremors at the surface.

Our experts advise that there are many other faults in the Lancashire area which similarly have unrelieved stresses, and could in a similar scenario likewise result in tremors. Because of the relatively weak nature of these rocks, the amount of energy likely to be stored in these faults is not large, and the largest earthquake likely in this area from such a cause is assessed at magnitude 3. While this is not large enough to cause significant material damage, it would be perceptible and disturbing. I consider that new controls to minimise disturbance to those living and working nearby, and to prevent the risk of any damage, are now a prerequisite for further exploration.

I am therefore announcing new controls to mitigate these risks, which will be applied to all future fracking operations for shale gas. As this is a developing area of knowledge, I stress that we will be moving forward with appropriate caution. The controls are not at this stage to be regarded as definitive, but as appropriate precautionary measures for our present state of knowledge. Initial operations under these controls will be subject to careful scrutiny to ensure the effectiveness of the controls. And they will be reviewed, as experience develops, to ensure that they are proportionate to the risks. The controls will be enforced by my Department, though the data obtained will of course be shared with other regulators.

Operators will first be required to review the available information on faults in the area of the proposed well to minimise the risk of activating any fault by fracking, and required to monitor background seismicity before operations commence. Real time seismic monitoring will also continue during operations, with these subject to a “traffic-light” regime, so that operations can be quickly paused and data reviewed if unusual levels of seismic activity is observed.

We will also be requiring operators to take a more cautious approach to the duration and volumes of fluid used in the fracking itself. A fracking plan will be required to be submitted to my Department before consent is given to any fracking. The fracking plan should be progressive, starting with the injection of small volumes of fluid and analysing the resulting data carefully before the full stage. Each stage of the frac will be carefully designed to use just enough fluid to create a fracture sufficient to enable gas to flow. A flow-back period will be required immediately after each stage to re-balance the pressures. Real-time recording of earthquakes during and for 24 hours after each stage of the frac will be analysed to look for abnormal induced events amidst the normal background seismicity.

Operators will also be required to monitor the growth in height of the frac away from the borehole. This will allow the operator to evaluate the effectiveness of the frac, but also ensure that the actual fracture is conforming to its design, and that it remains contained and far away from any aquifers.

So far as Cuadrilla’s current exploration programme in Lancashire is concerned, the remedial action level for the traffic light system (that is, the “red light”) will be set at magnitude 0.5 (far below a perceptible surface event, but larger than the expected level generated by the fracturing of the rock). I consider that this is an appropriately precautionary approach. We received representations in our consultation that this is too cautious, by comparison with the control protocols established for geothermal energy, construction and quarrying projects. I emphasise that this level is adopted only for fracking operations for shale gas, and the reasons for setting it at this level are entirely specific to the context. And it may well prove to be the case that, as our experience of applying this type of control to fracking operations develops, it can be confirmed that trigger levels can be adjusted upwards without compromising the effectiveness of the controls.

For the first few operations, DECC will have an independent expert on site to observe the operator’s conformance to the protocols we have established and to monitor the operator’s interpretation of data. We will therefore be able to learn as much as possible from these first operations and to put the lessons promptly into effect. But it would clearly not be right, in our present state of knowledge, to attempt to establish definitive standards, and I have preferred to start on an explicitly cautious basis.

At the present time, no applications for consent to fracking operations for shale gas are outstanding, and it is too soon to say exactly how the new protocols will be applied to any such proposals which may come forward in other basins. I can say that we will apply the same principles, of careful prior analysis of the risk of seismic activity, progressive design of the fracking process and feedback from the emerging data, and systematic monitoring by the operators before, during and after the operations. We will also expect operators to make monitoring data promptly available to the public.

As I have noted, fracking is not exclusively associated with shale gas extraction, and fracking operations using smaller volumes of fluid have been carried out both onshore and offshore the UK for many years. These have not to date been associated with any seismic risk, nor is there any evidence for such risks from elsewhere. However, DECC will apply proportionate scrutiny to the possibility. Oil and gas operators proposing fracking will be required to submit an analysis of the risks of any seismic activity being caused by the proposed operations, to conduct appropriate monitoring, and to inform planning authorities and local residents. Appropriate levels of control will be imposed by DECC where the assessed risk is not negligible.

These new controls on seismic risks do not remove any of the existing regulatory controls and requirements. Consistent with previous practice, my Department will not give consent to specific fracking operations until all other consents are in place, including in particular planning permission, the obtaining of environmental permits from the Environment Agency or the Scottish Environment Protection Agency (SEPA) as the case may be, and scrutiny by the Health and Safety Executive (HSE. Separate guidance is available from local planning authorities and regulators on how to acquire the relevant permissions and permits. Both the Environment Agency and SEPA have published sector-specific guidance for the shale gas industry.

However, I am well aware, in particular from the responses to our consultation on the report of our independent experts, that many people, including residents of Lancashire and other areas where shale gas exploration may be contemplated, have many other concerns besides the seismic risks, and it is only right that I should say how these other concerns are being addressed.

The development of shale gas in the US has been accompanied by an increasing level of debate on its environmental impacts. Many of the incidents reported have, on investigation, not been shown to be connected with oil and gas activity. However, they have given rise to concerns which in themselves are entirely reasonable. Residents in those areas want to be assured that their water will not be contaminated with gas or toxic chemicals, and the air will not be contaminated with noxious gases; that there will be no threat of damage from earthquakes; and that other kinds of disturbance such as traffic, lights and noise will be kept under control. In considering these concerns, I have had the benefit of the earlier report on shale gas by the Energy and Climate Change Committee, and many authoritative reports from the US, including two from the Secretary of Energy’s Advisory Board.

I have also had the benefit of the comprehensive and authoritative review of the risks of fracking by the Royal Society and Royal Academy of Engineering which I have already mentioned. I can announce that the Government accepts all the recommendations of the academies’ report addressed to it. Work is already in hand to implement these recommendations, so far as the current phase of exploration activity is concerned. One further recommendation is being considered by the Research Councils to whom it was addressed.

The reports from US regulators and review bodies do confirm that gas developments there have, on occasion, led to water contamination. There are relatively few confirmed instances of this – most complaints on investigation have proved to be attributable to causes other than gas production. And no case has yet come to light in which it has been confirmed that fracking has contaminated an aquifer. But the instances of contamination which have occurred confirm the need for the industry to consistently apply good practice, and the need for proper scrutiny and oversight of the industry to ensure that this is in fact done.

So far as the UK is concerned, I believe that the industry has a good record, and that there are already in place robust regulatory controls on all oil and gas activities. On water contamination, first, all such operations are subject to scrutiny by the appropriate environment agency (the Environment Agency in respect of England and for the time being of Wales; and the Scottish Environment Protection Agency in respect of Scotland). It is an offence to cause or knowingly permit poisonous noxious or polluting matter to enter controlled waters, which include ground waters. The environment agencies are statutory consultees in the planning process, and have to be consulted on all proposed borehole operations. A permit from the Environment Agency is required where fluids containing pollutants are injected into rock formations that contain groundwater. A permit may also be needed if the activity poses an unacceptable risk of mobilising natural substances that could then cause pollution. The permit will specify any necessary limits on the activity, any requirements for monitoring, the chemicals which may be used, and any appropriate limits on permissible concentrations. Regulators will take a risk based approach, and if the activity poses an unacceptable risk to the environment, it will not be allowed.

The academies’ report, and that of the Select Committee, also emphasise the importance in this context of the integrity of the well. This issue is central to the regulation of the safety of well operations by the HSE. The Executive have to be notified of all drilling operations for oil or gas, and will scrutinise the well design and operational plan. Additionally, the regulations require a full review of the proposed and actual well operations by an independent competent person, the “well examiner”. The academies in their report commented that this independent review is highly valuable, and made recommendations for strengthening it, which we of course accept and are already working on.

So far as the use of chemicals is concerned, the environment agencies take a risk-based approach to the regulation of the use of chemicals in shale gas fracking activities. The hazard potential of all substances proposed to be injected into the ground will be assessed and the use of substances hazardous to groundwater will not be permitted. The identity of all substances proposed for injection, and the agency’s conclusions on their hazard potential, will be publicly available.

Concern has also been expressed about the quantities of water used in fracking, or the disposal of waste water from the process. The water used may of course be obtained from licensed suppliers, but if directly abstracted by the operators, requires a licence from the environment agency. Licences will only be given where the agency is satisfied that a sustainable supply is obtainable.

Equally, disposal of waste water is subject to scrutiny by the agencies and will require a permit. The waste water from the operations in Lancashire has been found to contain low levels of radioactivity. A case-specific radiological assessment is required in support of any application for a permit for the disposal of radioactive waste. The agency will critically review any such assessment, and will only issue a permit if satisfied.
Concern has also been raised about the possibility of fracking leading to subsidence, but this is not considered a risk because of the strength and load-bearing characteristics of these rocks. And this is borne out by practical experience, because there is no report from the US of subsidence attributable to fracking, although the number of wells which have been fracked for shale gas is now in the hundreds of thousands.

A further major area of concerns was with the impacts of normal operations in terms of noise, traffic, impacts on health, etc. All proposals for oil and gas exploration require planning permission from the relevant minerals planning authority. The National Planning Policy Framework requires planning authorities to assess applications for all minerals developments so as to ensure that permitted operations do not have unacceptable adverse impacts on the natural or historical environment or on human health, including from noise, dust, visual intrusion, or migration of contamination from the site. In doing so, they should take into account the cumulative effects of multiple impacts from individual sites and/or a number of sites in a locality. Conditions can be placed on working hours at the site, numbers of traffic movements, etc., to ensure that any such impacts on local residents remain within acceptable bounds.

Other concerns which have been expressed are not to do with the current phase of exploration work but with the implications of a possible future move to production operations, if the exploration is successful. It is by no means certain that any such operations will ever be proposed, but if they were, a different set of considerations would arise, which I address further below. But as regards the concerns which have very reasonably been expressed about the current phase of exploration operations, I consider that the consistent application of good practice by the industry, supplemented by the additional action to control seismic hazards which I am announcing today, will ensure that there will be no unacceptable damage to the environment, or threat to the health of local residents, or interference with their lives.

I also consider that the existing regulatory framework already provides the means to ensure that the industry does apply good practice throughout its operations; and that it will do so consistently. But we are taking further steps to reinforce the regime. We have already set up a Strategy Group on Shale Gas at senior official level, with representation from the main Departments engaged in shale gas regulation, the Environment Agency and the HSE, to ensure that the work of the various bodies is well-coordinated. That group can already point to some successes in improving the coordination of regulation, for example, planned joint inspections of fracking operations by the HSE and the EA. And in the Gas Generation Strategy published last week, I announced that a new Office of Unconventional Gas and Oil will be set up in DECC to support this work as well as providing a single point of contact for investors and ensuring a streamlined regulatory process.

Accordingly, I am satisfied that fracking for shale gas can now in principle resume, and I will be prepared to consent to new proposals, subject to case-by-case scrutiny by my Department, to the new requirements to mitigate seismic hazards, and to confirmation that all other necessary permissions and consents are in place.

I should also mention one further outcome of the investigation of the tremors at Preese Hall. DECC has come to the conclusion that Cuadrilla’s response to the occurrence of the tremors demonstrated some weaknesses in its management of environmental risks. This conclusion has been discussed with the company, and they have in consequence reinforced their overall management structure, including by assigning to one board member specific responsibility for health and safety measures, and by reinforcing technical skills within the operational team. The effectiveness of these changes, and the resulting revised structure, is at present being reviewed for Cuadrilla by external consultants. Further fracking operations by Cuadrilla are in any case dependent upon the obtaining of new planning permissions and Environment Agency permits: but my final consent to new fracking operations will not be given until the conclusions of the external consultants have been discussed with the company, and any remaining points of concern addressed to the Department’s satisfaction.

As regards the implications of any future move to large-scale production, the concerns are principally of two kinds: on the one hand, concerns about the local or regional impacts on questions such as traffic movements, noise, night-time lighting, etc., or on the health of people living in the vicinity, or on regional water resources, or on tourism and other aspects of the local economy; on the other, concerns about wider issues including the implications of large scale shale gas production for climate change, for the UK’s climate change policies or for renewables investment.

As regards the local or regional impacts, it should be noted that the planning system requires permission to be obtained separately for exploration and production activities (and for any appraisal phase where distinguishable). There will therefore be a full opportunity to consider the local and regional impacts, including cumulative impacts, of any proposals to initiate production activities, before any such development takes place.

Planning procedures of course already provide for full consultation with communities who may be affected, and the planning authorities may require an Environmental Impact Assessment to be carried out. However, the academies have in addition recommended that an Environmental Risk Assessment should be mandatory for all shale gas operations, involving the participation of local communities at the earliest possible opportunity, and that this assessment should address risks across the entire lifecycle of shale gas extraction.

DECC will therefore take steps to enhance the existing frameworks for consultation and consenting to these activities, in line with these recommendations. Licensees will be required to carry out a comprehensive high-level assessment of environmental risks, including risks to human health, and covering the full cycle of the proposed operations, including well abandonment; and to consult with stakeholders including local communities, as early as practicable in the development of their proposals. The scope of these assessments would naturally be framed by the operations proposed, so that prospective future production operations would not be in scope for an assessment drawn up for exploration activities. Cuadrilla has been asked to conduct such an assessment in relation to their proposals for further exploration work in Lancashire.

This high-level assessment may inform the work entailed by risk assessments already required, for example under the Environmental Permitting Regulations, and which are consulted on separately by the Environment Agency, as well as work entailed by any Environmental Impact Assessment which may be required by the local planning authority. And together, these assessments will provide a full picture of the risks and impacts to inform effective engagement with local communities.

On health impacts, the Health Protection Agency is currently reviewing the evidence base on the health impacts of shale gas, with a particular focus on the health impacts of emissions to air, land and water. This review will identify any potential health risks, and inform both future regulation and any future health impact assessments that may be carried out.

As regards the wider concerns about the implications of large scale shale gas production for the UK’s climate change policies, etc., it is in general too early as yet to make any meaningful estimate of what these might be in the absence of any convincing estimate of what future production might be. But as there has been particular concern about the carbon footprint of shale gas operations, and in particular the possible impacts of fugitive emissions of methane, I should note that all shale gas operations will be subject to my Department’s long-standing policy on flaring and venting of methane. Venting of methane, which has been widely unregulated in the US prior to the recent proposals from the Environmental Protection Agency (EPA) for a new controls, is already required in the UK to be reduced to the minimum technically possible. Flaring of methane will also be required to be reduced to the economic minimum, so that where cost-effective routes for economic use of the gas are available, these must be used. These controls mean that UK oil and gas operations already meet the standards which the EPA is introducing, but the new Office will ensure that these work consistently with new controls which may be introduced by the Environment Agency in applying their legislation, and that methane emissions will continue to be minimised.

At the present time, methane emissions from oil and gas operations onshore are a very small part of our GHG emissions. The current estimate is that they contribute less than 1% to the total. And the relatively small number of wells which might be drilled in the current exploration phase will not in any case substantially increase that contribution. I therefore intend to commission a study into the possible impacts of shale gas extraction on greenhouse gas emissions. This will consider the available evidence on the lifecycle greenhouse gas emissions from shale gas exploitation, and the need for further research. I have invited Professor David Mackay, my Department’s Chief Scientific Adviser and Dr Tim Stone, the Expert Chair of the Office of Nuclear Development to undertake this work.

We are also taking steps to prepare the way for any future production phase, though this is likely to be some years away. We have commissioned more detailed work on the shale gas resources of Great Britain from the British Geological Survey (BGS) and this will be published early next year. I emphasise that this will provide only an estimate of the resource, the gas in the ground, and not the reserves, the amount of gas which can in practice be produced economically from that resource. Until more exploration work has been done, a significant number of wells fracked and production patterns established over time, it will not be possible to make any meaningful estimate of likely economically recoverable resources of shale gas in the United Kingdom.

Also, we will be acting on the academies’ recommendations that the regulatory bodies should assess the requirements for effective regulation of a significant future production phase, and that existing coordination should be maintained and strengthened. The new Office of Unconventional Gas and Oil will be taking this forward in collaboration with the other departments and agencies concerned. And the Environment Agency is already conducting a review of the implications of shale gas for its regulatory responsibilities, including the question of whether further controls and monitoring requirements are appropriate in respect of methane emissions. To facilitate future development, further consideration is being given to ensuring a streamlined and transparent regulatory process for environmental permitting.

We will also be taking steps to open the way to new onshore licensing. DECC had already commenced a Strategic Environmental Assessment in 2010, with a view to further onshore licensing, and conducted a public consultation in the latter part of that year. Work on the SEA has however been in abeyance following the seismic tremors in 2011. DECC will now commission further work on the environmental implications of further licensing, taking account of all new knowledge arising since the earlier assessment was compiled, and will conduct a full public consultation on the extended assessment. The results of this consultation will be fully considered before any decisions are taken on new licensing.

Many more questions of detail have been raised over the last year or so, particularly in the course of our consultation, and in this statement I have sought only to cover the principal issues of interest to the greatest number of respondents. I have today placed in the Libraries of both Houses and placed on my Department’s website a full synopsis of the questions raised and of the Government’s responses to them as well as a response on all of the recommendations of the academies’ study group.

Did you get to the end? Well done! I'll pick out my highlights in a subsequent post....