New study on methane emission from shale wells, and a comment on the role of environmental NGOs

A new paper released in PNAS, using measurements from 500 shale wells, shows very low methane leakage rates (~0.43% of total produced volume). This is significant because it has been suggested that high methane leakage rates could counter the greenhouse benefits of the 50% CO2 reduction you get from switching from coal to gas.

Those who have been following this debate for a while will know that this issue has been put to bed a while ago, with numerous studies contradicting the infamous, and oft-cited, Howarth study (which, to re-iterate, was based purely on estimates and models, and no actual measurements). I've covered this before here, and NoHotAir has covered the issue quite succinctly here. Nevertheless, this new study is probably the most comprehensive yet, with numerous measurements from each stage of the well completion process, and it is reassuring to see that it has come to similar conclusions to prior studies that also show the significant climate benefits of switching from coal to gas.

The details of the study has been widely reported, so I won't waste too much ink on it here, instead I'll let you read some links here and here.

The study was funded by a collaboration between 9 drilling companies and the Environmental Defence Fund, and it is on this aspect that I'd like to dwell for the remainder of this post.

The EDF's policy towards natural gas is outlined here. Like any environmental organisation, they're not wildly in favour of gas production, and would prefer to see an increase in renewable energy capacity. However, they appreciate the role of natural gas in a diverse energy portfolio. That is, of course, so long as it is extracted safely, and so long as fugitive methane emissions do not impact the benefits of burning gas over coal.

To ensure that this is the case, they are working in collaboration with drilling companies. Through this collaboration, they gain direct access to drill sites in order to take the kind of measurements necessary for the kind of studies described above. I would describe this as a mature, practical approach, bringing industry, scientists and environmentalists to the same table to talk about what can be done to protect the environment.

This can be contrasted with the efforts made thus far by UK environmental organisations such as Greenpeace, FOE and the Green Party, which could be described as like a child having a tantrum, screaming "No No No", No attempt to discuss how shale gas extraction could be made as safe as possible, no attempt to explore the potential to displace coal generation. Just say no.

I simply cannot see how chaining yourself to a fence outside a drilling site and getting arrested is a more productive use of time than getting around the table with some scientists. Indeed, why not use a small part of Greenpeace's £200 million annual turnover to fund a few UK academics to do some studies? If you believe, as these groups do, that shale gas extraction is fundamentally unsafe, why would you not be rushing to put some funding together to find the scientific proof that this is so.

I'll leave you with some similar comments from a blogger from Scientific American, who puts across similar thoughts far more succinctly than I.

Produced water disposal - a comparison with the conventional industry

A typical fracture stimulation stage requires approximately 1 million gallons of water. Depending on the specific site, you would expect between 25 - 75% of this fluid to return to the surface in the days following the frack. The fluid that comes back is called "flowback".

The injected fluid may contain about 1% chemical additive. The two principal additives tend to be friction reducers (which reduce the energy needed to pump the water) like polyacrimide (found in many cosmetic products) and thickeners (to help the fluid carry proppant) like guar gum (found in many food products). Cuadrilla have listed their ingredients here.

In addition, during its brief sojourn underground, the injected fluid can pick up additional material from the shale rock, including naturally occurring radioactive material (so-called NORM) and other minerals. Therefore, these fluids need to be treated before they can be safely returned to the water system.

The need to dispose of produced water is not a new problem for the oil industry. In most conventional hydrocarbon reservoirs, there is a certain amount of water trapped along with the oil. As the oil is produced, so is the water. As the field gets older, and most of the oil is gone, more and more water is produced alongside the remaining oil, and the "water cut" (the percentage of water produced alongside the oil) can be as high as 90% (i.e. 90% of the fluid produced from the reservoir is water, not oil).

As is the case with water injected for fracking, this water will have been in contact with the hydrocarbon reservoir, in this case for millions of years, rather than a few days. Therefore it may be highly saline, and it may contain NORM. This water, when produced, has to be dealt with.

A recurring theme in many of my posts is that what is proposed for UK shale extraction does not differ hugely from conventional operations, and also that we have a successful onshore industry with an excellent track record of minimising its environmental impact.

To make this point again, this time with respect to dealing with water produced from oil and gas wells, the table below lists the volumes of water (in barrels) produced from onshore UK oil and gas fields in 2012.

In total, over 73 million barrels of water are produced from onshore UK wells every year. The majority of this comes from the Wytch Farm oil field. Some of this water is re-injected into the reservoir to help force out more oil (approx 5 million barrels at Wytch Farm) but typically it is treated, and then, once clean it's discharged into the sea.

The larger UK offshore industry has to deal with an eye-watering (excuse the pun) 1.5 billion barrels of produced water every year!

A typical hydraulic fracture stimulation will use approximately 1 - 5,000 cubic meters (200,000 - 1,000,000 gallons) of water, or 6,000 - 30,000 barrels. Assuming that 50% returns to surface, that's 3,000 - 15,000 barrels of water to be processed for each frack stage.

This, again, is where comparisons with the conventional industry become pertinent - the current UK onshore industry has to deal with 73,000,000 barrels of produced water every year. It would take thousands of frack stages every year just to to match that rate. As an unnamed onshore operator commented to me recently (my emphases): "most people don't realise that all oil and gas wells produce water, more water than oil, and we have been dealing with it since way before shale gas. It is a lot of water. Can't blame the UK water on fracs!".

I'm not a chemist, so I'm not really up to speed with the details of how produced water is processed. I had an anonymous commenter on this post who seemed to really know his stuff. However, the best place to find out would be from the guys who are doing it, such as Lee Petts from Remsol, who has blogged about the issue here.  

Shale and renewable energy

In a recent post I pointed out the role that domestic shale gas production can play in moving towards a greener energy system, and suggested that the exchequer should ring-fence a portion of the taxes resulting from shale development to be spent on alternative energy research and development (improved renewable tech, next gen nuclear, and energy efficiency). I'm not the only UK geoscientist to come to this conclusion - if you enjoy FrackLand then I highly recommend that you also follow http://gasandgaiters.blogspot.co.uk, a new blog by Paul Glover, a Professor of Petrophsics at Leeds Uni.

My hope is that more UK academics start to realise the vital role they need to play in the current shale gas debate. Gasandgaiters has come to a very similar conclusion about the implications for shale development and renewables for the UK.

I think this point is made most succinctly, however, by those involved in the renewable energy business themselves - do they see shale gas as a help or a hindrance? The remainder of this post is borrowed from Energy in Depth (this post in particular). This is an gas-industry-sponsored website, so is unsurprisingly pro-gas-industry. As such, I try to avoid linking to it too much. In this case, however, the pertinent quotes are from leaders in the renewables industry, collated by EID.

Focusing on Texas, a renewables boom as gone hand-in-hand with the shale gas boom, as reported in the Scientific American. Quoting EID:

A report released today by the Texas Clean Energy Coalition has reconfirmed that natural gas and renewables “are complementary, not competing, resources.” The study, compiled by economists with the Brattle Group, analyzed the short and long term relationship between natural gas and renewable resources in the Texas electricity market – and what they found was a “win-win for Texas and the environment.” Texas provided 28 percent of all U.S. marketed natural gas production in 2011, while leading the nation in installed wind generation capacity.  Combined, these resources are providing clean, reliable, and affordable power for Texas consumers. Yet while wind energy provides 96 percent of renewable generation in the state, the overall output is not controllable and at times is ill-matched with electricity market demand. The ability of natural gas to quickly ramp up and down and to provide intermittent output makes it an ideal, complementary match to wind output.

Rhone Resch is the chief of the US Solar Energy Industries Association. ClimateDesk reports:

'Natural gas and renewables complement each other very nicely,' Rhone Resch, CEO of the Solar Energy Industries Association, said this morning at a press conference for the release of Bloomberg New Energy Finance’s 2013 Factbook, an exhaustive analysis of the state of clean energy in America.

The report, based on a blend of original and existing government research, is unequivocal in placing natural gas in the same ‘clean energy’ boat as renewables, a new arrangement Resch and Dave McCurdy, head of the American Gas Association, agreed they were happy to see. 'Natural gas can fill the gap when renewables go intermittant,' he said, 'ramping up when the wind stops or the sun goes down.'

Studies from MIT have shown how shale gas development can free up resources to invest in renewables. This is the view taken by US Energy Secretary Ernest Moniz. Meanwhile, Bloomberg reports the director-general of the International Renewable Energy Agency (IRENA) as stating:

Shale gas at low cost can help to create a hybrid system,’ whereby more gas-fired power is fed to the grid, supplanting coal, and augmented by wind and solar.

The success or otherwise of renewables in the UK will depend principally whether the political willpower is there to continue to support them. I hope the government continues to show that it will develop renewable energy systems. The extraction of domestic shale gas will support, not hinder, this development. 

Update (10/09/2013): It seems that I timed this blog rather nicely. Yesterday, in a speech to the Royal Society, DECC Minister Ed Davey, outlined the future role of UK shale development. This is backed up by a new government report describing how shale gas development fits in with the UK's plans to develop renewable energy and reduce greenhouse gas emissions.




 

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.

Shale must be careful who its friends are

Wherever you read a media report on shale gas these days, it will inevitably be described as 'controversial'. While Nick Grealy at nohotair.co.uk pulls out his hair over what is media hype rather than sound science, there can be little doubt that shale has a public image (or at least a media image) problem.

This cuts deeper than the deep greens camped outside Balcombe making outrageous claims that the water there is already poisoned, or that 2 recent earthquakes in the Irish Sea were due to fracking. A wider, more rational concern is that shale "is just another fossil fuel, locking us into a fossil fuel future". I work in a geology department: most of my colleagues are geoscientists, while some study climate change. In general, when they ask me about shale gas, their questions are not about water or earthquake risks, but about climate change.

This concern arises, in part, because of who the public sees as the main cheerleaders for shale gas. In recent weeks, we have seen the case for shale gas being made by the likes of Lord Lawson, Lord Howell (he of the "desolate north-east" comment), George Osborne and the like. Whatever actual views they might hold, the public do not see them as people who can be trusted to put environmental issues before financial gain.

Is it a surprise then, that with protagonists such as these it is difficult to convince the public that shale gas extraction could actually be a good thing in terms of greenhouse gas emissions? Shale should be careful who its friends are.

Instead of hearing from Messrs Lawson, Howell and Osborne, perhaps we should hear more from the Environmental Defense Fund, who have realised that rather than getting themselves arrested for protesting about shale gas outside an limestone-oil-drilling operation, which is a bit silly, the productive thing to do is to work with the industry to ensure that the benefits of shale are maximised, and any negative impacts are minimised.

Perhaps we should hear more from the likes of Transition Dorking, an environmental group prepared to consider the benefits of shale.

Will shale gas extraction lock us into a fossil fuel future? Perhaps we should hear more from the State of Texas, the undisputed home of shale gas. Texas is also one of the leading states for renewable energy generation (mainly from wind), trailing only the rainy and mountainous (and therefore ideal for hydroelectric) Pacific Coast states. Texas is the wind capital of the US (perhaps it's all the fantastic BBQ food).

This boom in renewable energy development occurred simultaneously with the shale gas boom. It may just be coincidence. However, in the current absence of efficient and large scale energy storage options, the ability of gas turbine power plants to provide quickly-dispatchable power has been crucial in coping with wind intermittency.

The economic benefits provided by shale development are no doubt helpful as well - a state with decent finances is surely more likely to be prepared to spend more in developing renewable energy. We like to say that we should be investing more in renewable energy. Well, to invest, you need to have money to spend.

Texas shows us that shale gas development need not crowd out renewable developments (and in fact may be beneficial). However, our current government is seen to be very pro-shale, and somewhat ambivalent to renewables, hence the public concern in this regard. I think the government is missing the chance to show that it is committed to both, and that they can work together.

Despite recent announcements of tax cuts to stimulate early development, the exchequer can still expect to take a lot of tax from shale gas extraction. Why not declare that a certain portion of that tax take will be ring-fenced, to be spent only on research, development and demonstration of alternative energy options (be they renewable, next-gen nuclear or fusion)?

That, in my view, would be the ideal path to take - showing that the government doesn't view shale as the be-all and end-all, but a necessary step on the path to a better future, and that there's more to shale development than is presented by Howell, Lawson et al.