German Success...?

A big week for Germany in the news. And no, I'm not talking about 7 - 1!

New rules for hydraulic fracturing have been announced in Germany. This has been widely reported as "Germany bans fracking", but the devil may be in the detail - indeed some groups opposed to fracking have referred to it as a "fracking enabling law". This is because it appears that fracking will be allowed at depths below 3,000m, and "where drinking water is not in danger". It is not clear whether this means in areas where no potable groundwater is present, and/or "if the liquid being used cannot contaminate water".

The laws are due to be further discussed in the Autumn, where hopefully some of these ambiguities will be addressed.

Fracking is not new to Germany. Most of Germany's existing natural gas production, from Lower Saxony in the north of the country, requires hydraulic stimulation to be economic. These are not shale rocks, but "tight sandstones", with low permeability requiring fracturing to improve flow rates. The figure below shows the number of frack-jobs performed in Germany over the last few decades.

It's not clear whether the proposed ban would include these existing reservoirs.

ReFINED well integrity

This week's big news was the release of the latest paper from Durham University's ReFINE Group (Research on Fracking IN Europe - academics love a dodgy acronym!). In it, they compile statistics on well integrity from a range of sources, as well as looking at well abandonment and orphaned wells (where the company owning a well goes bust, leaving a well with no-one to look after it).

This follows ReFINE papers on induced seismicity, and on hydraulic fracture height growth. Their approach in each of these cases is to use as much data as they can possibly get their hands on, with little thought for quality control, or on whether they are comparing apples with apples. In their own words:

This paper draws on a variety of datasets, mostly published, but in some instances sourced from online repositories or national databases, and follows the approach of Davies et al. (2013). In that study, the risk of induced seismicity due to hydraulic fracturing was reviewed, and intentionally included all datasets in the public domain that were considered to be reliable, rather than de-selecting any data (Davies et al., 2013). This inclusive approach has a drawback because well barrier and well integrity failure frequencies are probably specific to the geology, age of wells, and era of well construction (King and King, 2013). A wide range of failure statistics is therefore reported, and although they are presented on a single graph to show the spread of results, this is not intended to imply that direct comparisons between very different datasets (i.e. size, age of wells, geology) can be made.

This means that data from recent drilling in the Marcellus (which is probably relevant) is presented alongside less relevant data from offshore wells (drilling offshore is always a more challenging prospect, with hundreds of meters of water between your platform and the well-head), from China, or even from the 1920s in California.

Statements from US State regulators on hydraulic fracturing

This post highlights a statement, made in 2009, from numerous state regulatory bodies pertaining to water contamination and hydraulic fracturing.

http://www.iogcc.state.ok.us/Websites/iogcc/Images/2009StateRegulatoryStatementsonHydraulic%20Fracturing.pdf

These various organisations quoted here represent the state regulatory bodies for oil and gas development. In the US it is the states, rather than federal organisations, that play the main role in regulation of this sector.

You'll note that in every case, no contamination is reported from hydraulic fracturing. How does this square with the numbers I reviewed a few weeks ago, where there are cases reported, albeit very rare ones?

The answer lies in how one defines hydraulic fracturing. To a well engineer, hydraulic fracturing refers to the process of pumping fluid down the well and into the reservoir, in order to fracture the rock. No more, no less. However, to the public, "fracking" has come to mean all stages of shale gas extraction, from drilling and casing a well, to the actual fracturing of the rocks, to the storage, transport and disposal of waste fluids.

Where we have seen contamination issues (and again, if you look at the AP numbers, rather than the headlines, these are rare) they are not due to the hydraulic fracturing process itself, but other aspects of the drilling process. For instance, we have seen issues with well casing leading to buildup of stray methane in shallow aquifers. We have seen examples where storage of waste fluids in open pits has lead to leakage at the surface, and we have seen examples of illegal dumping of untreated waste.

I think this distinction is important, which is why I usually talk about "shale gas development" or "extraction" when referring to the whole process chain, saving "hydraulic stimulation" or "fracking" to use them as they are defined from an engineering perspective.

The distinction matters when it comes to look at the risks that shale development might pose in the UK. We can see in the reports from the various regulatory bodies that the fracking process itself does not pose a risk. The issues appear to be: how the well is drilled and the casing is cemented; and how waste fluids are stored, treated and disposed of.

This is crucial, because it removes the major unknown in the process as an issue - that while wells in the UK have been hydraulically stimulated, current shale proposals represent a scaling up of the existing process. We have abundant experience in the UK of handling, treating, transporting and disposing of all sorts of chemicals, and the existing industry handles plenty of produced water every year.

Similarly, we've drilled thousands of wells both onshore and offshore, and we know how to address casing and integrity issues, which are rare to non-existent. It matters not to the near surface casing integrity whether a well is being used for "high volume" hydraulic fracturing, "traditional" hydraulic fracturing, acidization, or any other completion activity.

Part of the public's fear over shale gas is that it seems like a novel process, and we are scared by what we don't know or understand. In fact, the statements from the US regulators show that the unknown part (the "fracking") does not pose much of a risk - the riskier parts are in fact the parts that we know most about, and that we have the most experience in mitigating, regulating and minimising.

Population density in Total's new PEDLS

In the news this week I am sure you won't have missed the entry of Total into the UK shale gas market. They follow Centrica and GDF Suez as major players in the European gas to invest in UK shale gas by buying into licence areas. 

Rather than bore you with details of their business arrangements, I thought I'd take this opportunity to examine another commonly held myth about shale gas development - that the UK simply does not have enough space.

Total have bought into PEDL (Petroleum Exploration and Development Licence) blocks 139 and 140, which are in Lincolnshire. You can download a large map of all PEDLS from DECC here. I have added the approximate locations of the two adjacent licence blocks to the Google Earth image below.

The first thing you'll notice is the abundance of yellow and pink pins, these represent existing oil and/or gas wells, as per this post. Gainsborough sits atop the Beckingham Marsh oil field, which has been in operation since 1963. The field has numerous wells, and doesn't seem to cause the locals much bother. It will be interesting to see whether a similar level of opposition to shale gas develops here as we have seen at Balcombe and Barton Moss. As they have more experience than most of how the onshore industry is able to operate without causing undue disturbance, this will be an interesting one to watch.

The second thing to notice from the satellite image above is the relative sparsity of population outside of Gainsborough. We are often told that shale gas development in the UK will be too challenging due to the high population density. I think this image tells a different story.

I won't rely on a picture to prove this point, however. Instead, I will compare Lincolnshire with counties in Texas where shale gas is being extracted. I've looked to shale developments in Texas before when addressing shale development footprints, of course.

Extraction of gas from the Barnett shale in Texas is focussed on 5 counties: Denton, Johnson, Parker, Tarrant, and Wise. The following tables show population densities (people per square mile) and the number of wells in each county (pop densities from wiki, well counts from the RRC).

	Density (ppl/sq mile)	No of wells
Denton	754	2,935
Johnson	205	3,386
Parker	129	1,856
Tarrant	2,000	3,844
Wise	21	4,437
Lincolnshire	390	342

I have added Lincolnshire, which has a population density of 390 ppl/sq mile (and 342 existing oil and gas wells). Note the comparable densities between these Barnett shale counties and Lincolnshire, which sits somewhere in the middle. Only Wise County has a density that is substantially lower, while Tarrant County's population density is substantially higher. All five counties have thousands of Barnett shale wells, an indication of how the industry is capable of operating in all settings, preferring unpopulated areas where possible, but perfectly capable of operating in areas of dense population where it is required to.

I'm sure this post won't stop the endless stream of articles in the media telling us that Britain is too crowded for shale gas development to be possible. At least you, dear reader, will now be a little better informed. 

   

Extended reach drilling

There are two key technologies that have enabled gas to be extracted economically from shales. Hydraulic fracturing is the technique that has garnered all of the attention. However, of equal importance is extended reach lateral drilling: turning the drill bit horizontally to drill sideways for several kilometers.

This technology was developed in the 1980/1990s - this graph shows the number of horizontal wells drilled in the US through the late 1980s to mid 1990s.

The number of horizontal wells has subsequently boomed, as the shale revolution has spread across the US - as the next figure shows for the Barnett:

  
Typical shale wells extend between 2 - 4 km in length. However, it is possible to go much further than this. Some of the longest "extended reach" laterals were drilled in the UK in the 1990s, allowing the operators of the Wytch Farm oil field to access reservoir compartments under Poole Harbour and the English Channel from their onshore drilling site.

The scale of these extended reach wells can be difficult to contextualise, but I'm going to try, using an image taken from Dr Ian West's incredibly comprehensive website (warning - for real geo-geeks only).

Dominating this cross-section is a profile of a Wytch Farm extended reach well. Staying topical (as ever), I will use the recent drilling at Barton Moss as a comparison. The extended reach well is over 10km long. If this well were being drilled at Barton Moss, outside of Manchester, then the toe of the well could reach Albert Square in the city centre. To represent this, I have added images of the Barton Moss drilling site and Albert Square to Ian West's image.

The well targets layers over 1.5km deep. This is equivalent to over 5 Shards, stood end on end. So I've also added a Shard, to scale, to the image.

Ian's image also compares the depths of various shale wells, including the rather shallow layer targeted at Balcombe, and deeper wells targeting the Bowland shale in the UK, and the Haynesville in the US. The Barton Moss well will also extend to 3km.

I don't have a particular point to make with this post, I just came across Ian's image while preparing an exam for Bristol's undergrads, and wanted to share how spectacular it is, when you consider the scales involved. Most shale wells in the UK will not extend to 10km. However, the Wytch Farm extended reach wells show what can be done, should the need arise in particular, difficult to reach areas.

Associated Press report on shale gas and pollution - what do the numbers really show?

The twittersphere has been alight in recent days with an Associated Press story examining records held by state regulatory agencies regarding complaints of water contamination related to drilling. This story has been widely reported across the media, generally with negative headlines, and extensively re-tweeted amongst anti-drilling campaign groups.

However, it pays to look beyond the headlines, to the actual numbers listed in the report, which is what this post will do. What does the AP report actually tell us about shale gas drilling and water contamination in 4 key US states?


The Question(s):

Firstly, however, it is important to state what we know, and do not know, and what we would like to find out. In scientifc terms, we must state our hypothesis. We already know that contamination can and has been caused at the surface by leakage of fluids from open waste storage pits (not allowed in the UK) and by illegal dumping of waste fluids into streams and rivers without treatment. We also know that contamination of groundwater by fugitive methane can and has been caused by faulty well cement and casing that allows deep sources of methane to move towards the surface.

The question we want to know is - are these types of incidents common or rare; and secondly, are they inevitable, or could they be prevented by better operating practice? If incidents are common and/or inevitable, shale development might be considered an inherently dangerous and therefore unacceptable process. If they are rare and can be mitigated by improved practices, shale gas development should be considered an acceptable technology.


The Data:

The AP report covers 4 states: Pennsylvania, Ohio, West Virginia and Texas. It does not specify in detail the nature of the complaints it discusses, which clouds the issue somewhat. However, from the report they appear to range from short term diminished water flow rates (not particularly serious), to contamination by stray methane migration (the most common complaint, apparently), to contamination by fracking fluid itself (the most serious allegation, I'd contend). Regardless, any incident or complaint is one too many, so for the purposes of this post they will all get lumped together.

If we are to determine whether these events are common or rare, we need to have data on the number of wells in the states considered by the report. The NRDC provides some figures for the number of oil and/or gas wells in each state, though these figures are from 2009, and don't say when the various wells would have been drilled, nor whether they are active or abandoned. However, the AP report doesn't specify whether complaints have originated from abandoned wells, old but still active conventional wells, or newly drilled shale wells, so perhaps the NRDC figures are the best to use. Regardless, I did a little more searching on various state regulator websites, finding the following:

• The NRDC list 47,000 wells in West Virgina in 2009. The West Virginia DEP website search function indicates a total of 2095 active gas wells, 96 oil wells and 33 CBM wells active from 2009 onwards (the 47,000 figure does seem high to me).
• The NRDC list 70,000 wells in Pennsylvania in 2009. From the Pennsylvania DEP website, a total of 32,625 new gas, oil and CMB wells were drilled (to "spud" in drilling parlance is to begin drilling) since 2005 (note the AP report incorrectly states there are only 5,000).
• The NRDC list 64,000 wells in Ohio in 2009. The Ohio DNR website lists over 50,000 active producing wells in 2011, although it appears that only 1,000 of these are target the Utica shale.
• The NRDC list 250,000 wells in Texas in 2009. The Texas Railroad Commission (who regulate oil and gas, obviously) count 17,000 wells in the Barnett shale in 2013, approximately 4,000 wells in the Eagle Ford shale (going by permits issued), and 800 in the Haynesville shale.

Before comparing numbers of pollution incidents with the number of wells, I first want to mention one striking feature of the numbers in the AP report - the difference between the numbers of complaints received, and the number of incidents actually substantiated though tests carried out by the various agencies. For Pennsylvania, in 2012 the DEP received 499 complaints, but substantiated only 5, meaning only 1% were considered valid. In West Virginia, the DEP received 112 complaints, of which 4 were substantiated (just under 4%). For Ohio, 113 complaints in 2011-2012, with 4 substantiated (just under 4% again), while in Texas none of the 62 complaints relating to water quality have been substantiated (so 0%). 

Why is the the percentage of substantiated claims so low? I'm sure some readers might be tempted to drag out the litigious American stereotype, ready to complain and sue anything and anyone at the drop of a hat. However, perhaps the most relevant data comes from Pennsylvania, where a Penn State study revealed that 40% of private drinking water wells are failing at least one environmental standard anyway. Furthermore, there are over 1 million drinking water wells in Pennsylvania, and approximately 20,000 new ones are drilled every year. 

The scale of these numbers shows why it is not surprising that many people might have complaints about their water quality. If there happens to be a hydrocarbon well near by, then with all the media coverage of fracking, it is inevitable that drillers get the blame. However, the 40% figure shows that there are in fact there are many other potential sources of contamination, and rigorous testing is required to determine where the blame should properly be apportioned. The AP figures suggest that in over 95% of cases, gas drilling is not to blame.  

Are contamination incidents common?

Lets move on now and consider the numbers of substantiated complaints with the number of wells drilled. For Pennsylvania, 106 cases out of 70,000 existing (NRDC) and 32,000 new (PA DEP) wells = 0.1%. For West Virgina, 4 cases, out of (using the low end DEP figures) 2224 wells = 0.1%. For Ohio, 6 cases out of 50,000 wells = 0.01%. For Texas, 0 cases out of 22,000 shale wells = 0%. For what it's worth, these figures are in line with other reports that have looked into this, such are this report by the Groundwater Protection Council, which reported incident rates per well of 0.01 to 0.03%. Our initial question was: are incidents common or rare? The AP numbers show that incidents of drilling-induced contamination are rare. 

Can better regulations reduce the impacts?

The second question was: is contamination due to drilling inevitable or can it be mitigated by better practice? The rarity of these events alone suggest that they represent aberrations rather than an inherent problem with the drilling and hydraulic fracturing processes. We can go further than this, however. During the Marcellus drilling boom in Pennsylvania, a number of new regulations regarding drilling safety and safe disposal of waste fluids have been enforced from 2010 onwards. Fortunately, for Pennsylvania the AP report breaks down the number of complaints by year, allowing us to judge the effects of these regulations.

The numbers of wells spudded in 2010, 2011, 2012 and 2013, respectively, was 3,340, 3,238, 2,374, and 2,175. In addition to the new wells, remember that opponents of drilling like to remind us that "all wells fail through time", so with all these wells coming in you'd expect to see the number of issues increasing through time, as problems emerge from both new wells and old. 

In fact, the numbers of substantiated issues (and the % of new wells this represents) are, from 2010 to 2013: 29 (0.86%), 18 (0.55%), 5 (0.2%) and 2 (0.1%). This represents a clear decrease in the number of contamination incidents as new regulations have come in to force. The AP numbers show that better regulation can reduce the impacts of shale gas drilling.

In Conclusion

To conclude, just as you should never judge a book by its cover, so you should be careful about judging a newspaper story by its headline. The numbers themselves in the AP report tell a very different story from the headlines it generated.

FOI information from DECC - Well integrity in the UK

A recent FOI response from DECC regarding historic drilling in the UK makes for interesting reading. I've often mentioned the thousands of existing wells in the UK, both onshore and offshore, which have been drilled, operated and abandoned without incident, and the implications these have for future shale gas drilling in the UK. I've taken the liberty of doing a wholesale copy-and-paste, because this is fairly fundamental stuff:

(Questions in italics, DECC responses in bold)

The first question discusses offshore wells:
In relation to offshore gas/oil wells which fall under UK Government jurisdiction:
a. How many wells are currently in operation (wells not rigs)?

• There are about 25 offshore wells currently drilling
• Some 3360 offshore wells have been completed for production (ie are either producing oil and /or gas or are shut-in)

b. How many abandoned wells are there?

• Approximately 6500

c. How many operating wells with cementation integrity issues have been reported within the last 5 years?

• DECC does not hold this data

d. How many abandoned wells with cementation integrity issues have been reported within the last 5 years?

• DECC does not hold this data

e. How many leaks from operating wells have been reported within the last 5 years?

• Any release of oil and/or chemicals from offshore installations, including wells and pipelines, must be reported to DECC Offshore Oil and Gas Environment and Decommissioning (OGED) using a Petroleum Operations Notice No.1 (PON1). Details of PON1s received by the Department are published on our website at the following link https://www.gov.uk/oil-and-gas-environmental-data#pon-1-data. As far as DECC OGED is aware, no leaks have been reported for operating wells during the last five years, but a leak was reported from a suspended well in the Elgin field that attracted media attention (further details can be found at https://www.gov.uk/government/news/elgin-gas-release-government-interest-group) and a recent review of all suspended wells on the UKCS confirmed that there were minor gas leaks from four shut-in production wells.

f. How many leaks from abandoned wells have been reported within the last 5 years?

• As far as DECC OGED is aware, there have been no reports of leaks from abandoned wells in the last 5 years.

g. Does the UK Government keep records of abandoned wells with leaks / cementation integrity issues?

• Information in relation to leaks from abandoned wells is held by DECC.

The second question discusses onshore wells
In relation to onshore gas/oil wells in the UK:
a. How many wells are currently in operation?

• DECC requires monthly production reporting on a field basis, not a well basis. Reporting individual well operations is not required on licences issued before 1965, but we estimate there are currently about 300 onshore wells in production.

b. How many abandoned wells are there?

• Records for wells drilled before the 1960’s are not reliable so we can only estimate that there are about 1500 abandoned wells.

c. How many operating wells with cementation integrity issues have been reported within the last 5 years?

• None

d. Where are these wells?

• Not Applicable

e. How many abandoned wells with cementation integrity issues have been reported within the last 5 years?

• One

f. Where are these wells?

• This was a well in Stafforshire and the integrity issues have subsequently been dealt with.

g. How many leaks from operating wells have been reported within the last 5 years?

• None

h. How many leaks from abandoned wells have been reported within the last 5 years?

• None

i. Does the UK Government keep records of abandoned wells with leaks / cementation integrity issues?

• DECC does not keep such records – but regularly liaises with the Health & Safety Executive in relation to such issues.

The final questions relate to hydraulic fracturing:
3. During gas / oil exploration for conventional targets, are wells hydraulically fractured?

• Yes, some are.

4. During gas / oil exploration for unconventional targets (e.g. shale, coal bed methane), are wells hydraulically fractured using exactly the same technique for conventional targets?

• The volume of injected fluid is significantly bigger for shale gas, but similar and small volume for conventional and coalbed methane.

5. During gas / oil exploration for unconventional targets (e.g. shale, coal bed methane), does high pressure, high volume slick water hydraulic fracturing (often referred to as fracking) take place?

• Yes, for shales.

6. If yes, please provide evidence to state at what point of the process this occurs (e.g. initial drilling, pressure testing, sampling etc).

• After drilling, as part of an extended well test, see PREESE HALL information on our website, the only shale well that has been fracked so far. https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/15745/5075-preese-hall- shale-gas-fracturing-review.pdf

Update: Map of existing UK oil and gas wells

In a previous post I discussed the 2000 or so pre-existing onshore oil and gas wells in the UK that rarely seem to get a mention when people talk about shale gas extraction despoiling our wonderful countryside. Well, in a quiet moment at work I made a map showing where they are (click to enlarge). Each red pin is an oil or gas well drilled between 1902 to the present day.

Update: I have modified the map to colour-code the wells by the date they were drillied. Pre-1949 are cyan, 1950 - 1979 are yellow, 1980 - 1999 are (light) pink, and 2000 - 2013 are (dark) purple. 

Update 2: You can download the original data from the DECC website at: 
https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/224856/Landwells22July2013.xlsx. Lat/long data is in Deg/Min/Sec.

I created .kml files to plot the data in Google earth. You can download the 4 files at:
http://www1.gly.bris.ac.uk/~JamesVerdon/Downloads/uk_wells_1900-1949.kml
http://www1.gly.bris.ac.uk/~JamesVerdon/Downloads/uk_wells_1950-1979.kml
http://www1.gly.bris.ac.uk/~JamesVerdon/Downloads/uk_wells_1950-1999.kml
http://www1.gly.bris.ac.uk/~JamesVerdon/Downloads/uk_wells_2000-present.kml

 

Radio 4 You and Yours Interview

On the radio again, this time Radio 4 (does this count as a promotion from 5Live?):

Talking about Balcombe on 5Live, and is the UK oil industry a victim of its own success?

With the protest ongoing outside Cuadrilla's drill site near Balcombe, it's somewhat inevitable that I'd end up on the radio again - 5Live Drive once again. I've included the whole segment, including Bianca Jagger, a man from Blackpool who finds the whole shale gas thing a little boring, Vanessa Vine from Frack-Free-Sussex who finds the whole thing very exciting, and finally I get squeezed in at the end.

Beyond giving you the chance to enjoy my honey-ed tones once more, there are a couple of points that arose from this interview that I'd like to expand on.

The first thing that came to mind while listening to the anti-fracking interviewee was the issue of geological dread in public perception of risk. The concept of 'dread' in public risk perception is well established. From Wikipedia, a dread risk elicits visceral feeling of terror, uncontrollable, and catastrophe. It was coined in an attempt to understand why public perception of risk is often very different to expert assessment of risk. It is often that sense of an unknown danger that provokes feelings of dread. It was initially used to describe feelings towards nuclear power, but I think it applies equally to things like flying (for some people), but especially GM food, and now fracking.

Quoting the interviewee, fracking is 'messing with subterranean geology', and 'we cannot legislate for the vagaries of subterranean geology, it's such a human arrogance'. It seems that the public has this idea that the subsurface is unknowable and uncontrollable, leading to feelings of dread. I would argue that while the subsurface can no doubt be a challenging environment, there are hundreds of thousands, if not millions of people, geologists/geophysicists/hydrologists/geochemists etc., for whom understanding and making use of the subsurface is the bread and butter of their day to day life.

Geologists (Iain Stewart aside, perhaps) don't talk enough to the general public. We saw this in the furore over Iain Duncan Smith's comments about shelf-stackers being more important than geologists, where geologists finally had the gumption to point out to the rest of the world how important they actually are. And we are incredibly important.

Take a look at all the objects around you and in your life. If it's not made of animal (wool, leather) or plant (wood, cotton) then chances are it's made of something extracted from this apparently unknowable subterranean geology, that apparently we shouldn't be messing with.

It might be stone, which has to be quarried, cement and concrete products made from quarried aggregates and limestone. If it's plastic or synthetic then it's made from oil. If it's metal then that metal had to be mined somewhere. Moreover, all of the energy we use involves the subsurface as well. Hydrocarbons are the most obvious example. But where does the uranium come from that we put in our nuclear power plants? What about renewable sources, surely these will take us away from that dreadful subterranean geology with which thou shalt not mess? Well, a typical wind turbine needs something close to 100kg of neodymium, which can only be found in a few places, and mining it is not exactly a pleasant process. And hydroelectric? Well, it's well established that reservoir impoundment for hydroelectric can produce large earthquakes - for example the 2008 magnitude 7.9 Sichuan earthquake, which killed 80,000 people, has been linked with the impoundment of the Zipingpu Dam. Slightly more dramatic than the Blackpool tremor I feel.

Much of human endeavor has been based on 'messing with subterranean geology'. During fracking, we can use geophysical methods to monitor exactly where the induced fractures have gone, and to ensure that they are wholly contained within the targeted shale beds. As geologists, we have to accept that the public are unlikely to fully understand what we do. However, shale gas extraction is not an uncontrolled, poorly understood process. To claim that it is is to do insult to the thousands, or millions, of geologists around the world who do this kind of thing, successfully, every day.

Speaking of success, the events in Balcombe raise a second point. I am wondering whether the current UK onshore oil and gas activities have been a victim of their own success in hiding their operations from the public for the last 50 years.

Protestors talk about thousands of well sites despoiling our beautiful countryside. Which is strange, because we already have thousands of onshore wells across our countryside. Literally, 2000 wells - you can download a spreadsheet listing them all here. 10% of these, so about 200, have been hydraulically stimulated. Yet no-one seems to even know that they are there, and certainly no-one seems to be claiming that 50% of them are leaking hydrocarbons and/or carcinogens to contaminate groundwater.

Our onshore industry has been very effective at (a) making sure that they don't cause environmental problems and (b) doing everything that they can to stay out of the public view. I grew up a few miles down the road from the Humbly Grove Field, which is here (as per my Fort Worth post, go to StreetView and see if you can even see it), yet until I went to university I didn't even know it was there.

Now, when a new well is proposed, because people don't know anything about the onshore industry, the thought of drilling in the rural UK countryside seems crazy, (indeed it even induces dread), even though there are 2000 wells already there.

It's understandable that when we seek to understand shale gas impacts we look to the US, and we try to understand the issues they have faced, and what the development has ended up looking like. However, we should also look to our own industry. If we want to know whether it is possible to conceal well pads without despoiling the countryside, we should look at our own ability to do so, not what American regulators and planning rules allow. If we want to know whether wells are likely to leak, we should look at whether our own 2,000 wells are leaking, not whether wells drilled under American regulatory and inspection regimes are leaking.

There's one major aspect of the media attention at Balcombe that has surprised me. There is ALREADY an oil well on the Balcombe site, drilled in the 1980s by Conoco. They abandoned it because the price of oil dropped to $10 per barrel, while now it is over $100. I've not seen this well mentioned in many reports from Balcombe. Has the old well has been causing problems for Balcombe for the last 25 years? I doubt it. I would love to know what it is about the new well that people see problems? Why will it be different, or more likely to cause problems, than the one that is already there? 

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.

Induced Earthquakes in the USA, and some implications for CCS

Here's a recent BBC report on earthquakes induced by oil and gas activities in the USA. As can be expected, the twitter/blogo-sphere has been lighting up over this in the last few days. For me the biggest surprise is that this has only come up in the wider media in last few days: induced earthquakes have been a key topic of discussion among geophysicists for a couple of years now. The USGS has noted an increase in medium-sized earthquakes in the last decade:

The black line shows the total number of earthquakes in the midcontinent USA (excluding the very active San Andreas fault and other active parts on the west coast) greater than M3 since 1970: you can see the increases as the line gets steeper.

The oil industry likes to dispose of waste-water by injecting it into deep-lying saline aquifers. However, it has been well known since the Rocky Mountain Arsenal in the 1960s that deep fluid injection can trigger earthquakes. It is argued that the increase in oil industry injection activities in the last decade has been the cause of the increase in the numbers of earthquakes.

This remains under debate - could the increase be simply that, as more (and better) seismic monitoring networks are installed, we are detecting more earthquakes than we did in the past. The latest news story is a case in point. The paper in Geology attributes an M5.7 earthquake in Oklahoma to injection of waste-water. The Oklahoma Geological Survey has subsequently released a rebuttal stating that as far as it is concerned, there is not enough evidence to tie the quake to injection activities (strangely enough, the OGS rebuttal hasn't been given much of a look-in from the media).

Nevertheless, I think that it inarguable that, in certain cases at least, fluid injection has triggered earthquakes with magnitudes from about M3 to M6.

This brings me to a couple of asides. Firstly, following on from my last post about bad media reporting of these issues, many reports attributed the quake to injection of waste-water from fracking. This is not the case - the waste water in this case came from conventional oil production. This harks back to an older post I made about the relative risk profiles from fracking in comparison to conventional oil and gas. The need to dispose of large quantities of contaminated waste water is not a new, fracking-related problem in the oil industry. If you are opposed to fracking, you must presumably be opposed to all oil and gas related activity.

Secondly, M5.7 is a large earthquake. It is about 100,000 times larger than the quake induced in Blackpool by fracking. It is larger than any earthquake ever recorded in the UK. Perhaps only a few historical earthquakes in the UK have been of a similar size. An M5.7 triggered earthquake here would be serious news.

So, can we get an estimate of what earthquake magnitude might be triggered by our various activities? Art McGarr, a venerable (and venerated) and highly experienced geophysicist with the USGS has made an effort to do this. McGarr cut his teeth in the 1970s looking at mining induced seismicity, where he noticed a correlation between the total energy released during rock extraction and the volume of rock extracted. He developed the so-called McGarr equation:

Sum(Moment) = G dV

The sum of the released seismic moment equals the volume change (dV) multiplied by the shear modulus (G). It should be noted that this equation is based on empirical observation only. It has subsequently been applied to fluid injection (or mis-applied, some would say, as there is no obvious basis for arguing that physical processes during fluid injection should match those during rock removal (mining)), where dV becomes the volume of fluid injected.

More recently, McGarr has been looking at earthquakes attributed to fluid injection. This includes waste-water injection as discussed above, as well as geothermal activities and, of course, fracking. He has developed the following plot:

Each + represents an injection-induced seismic event. Unfortunately for any non-geophysicist readers, McGarr has given the earthquake sizes in moment, rather than magnitude, but 10^12 is about M2, 10^15 is about M4, 10^18 is M6. I've not found out what all of McGarr's abbreviations are, but

• BUK is the Blackpool earthquake
• RMA is the quake induced by fluid disposal at the Rocky Mountain Arsenal
• BAS is the Basel (Switzerland) earthquake caused by geothermal activity
• STZ is an earthquake caused by geothermal activity at Soultz, France
• RAT (several of them) are earthquakes in the Raton Basin (Colorado) associated with waste water injection
• POK is the Oklahoma earthquake discussed in this blog

You can see a general correlation between the maximum magnitude and the injection volume, following a McGarr-esque equation, replacing the sum of the moment by a maximum magnitude: Mmax = GdV. It should be remembered that this line appears to be describing the MAXIMUM POSSIBLE magnitude. There are over 150,000 waste-water injection wells in the USA, only a tiny fraction of them have caused detectable earthquakes.

So how does this apply to the UK? The first thing to note is that deep injection of waste fluids is not allowed in this country, so we can strike this risk off immediately. What about fracking? A typical frack stimulation uses about 1000 - 5000 metres cubed of water - that's ~10^3. This leaves us with a maximum induce-able moment of ~10^13 (or a magnitude of about M3). We get 30 or so M3 events in the UK every year, so inducing a few more due to fracking isn't going to make much difference.

What about CCS? Carbon capture and storage is a key plank in the UK's CO2 emissions reductions plan. All well and good, but CCS involves the injection of very large volumes of fluid into subsurface aquifers. Could this trigger earthquakes?

I've modified McGarr's plot to add the injection volumes of Sleipner and In Salah, two of the foremost CCS projects currently in operation (as well as changing the scale from moment to magnitude to make life a little easier for non-geophysicists):

You can see that, following the McGarr plot, Sleipner and In Salah have the potential to trigger earthquakes of M5 or larger! Of course, they haven't: Sleipner has barely done anything, while In Salah has triggered at most an M1 event (so small you can't feel it without the aid of sensitive seismometers). The McGarr plot tells you the maximum possible magnitude, not what magnitude you will get. Hence why I have shaded in the area under the line: you could get an event on the line, or anywhere under the line.

Still, I find the potential for induced earthquakes from CCS to be worrying. I think this has been under-appreciated by the UK CCS community. There is a clear need for further study on why most injection sites do not produce seismicity, but a few do? What is it that is different about these sites, and how can we identify this in advance, and only select sites that won't trigger events during CO2 injection. At the same time, we can quickly see that the earthquake risk from fracking has been hugely overplayed in comparison to the risks posed by other activites (geothermal, CCS, waste-water injection, mining, and even hydroelectric energy).

Conventional vs shale: what's the difference?

Oil and gas production is a complicated business. To get those molecules of hydrocarbon from the microscopic sandstone pores kilometers underground all the way to your car's petrol tank or your home's central heating system takes a huge amount of engineering. Shale gas extraction is no different in this respect - in fact it requires additional stages of engineering on top of what is required for normal gas and oil extraction. So I figured it would be of interest to look at what is different in shale gas compared to conventional, and what is the same.

Drilling
Wells drilled to extract conventional HCs are pretty much identical to shale gas wells. They are drilled in the same way, cemented in the same way. Horizontal wells are now common in conventional production, just like they are in shale gas. Check out the map of the Weyburn oilfield (Canda) below - each line is a horizontal well bore, some of which produce oil, some of which inject CO2 to help force the oil out. Conventional and shale wells have pretty similar risks in terms of wellbore integrity and gas leakage.

(click to enlarge)

Hydraulic Fracturing
This is one of the big differences between conventional and shale gas. Although HF is often used in conventional gas fields, it is not usually on the same scale as for shale gas. So, what extra risks does the HF process itself entail? Evidence is pretty clear that the fractures that are created are not providing contamination pathways for gas or nasties to get back to the surface: the fractures created are simply too small and too deep - not even the most ardent anti-frackers are arguing this I don't think. Of course, hydraulic fracturing uses water, some of which comes back up to the surface - I'll talk about this a little more below.

Number of wells
Usually, you would expect to have fewer wells in a conventional field than for a shale gas field. This isn't always the case - look at the number of wells at Weyburn, above, or the Jonah gasfield (below). However, as a general rule, expect more wells for a shale field.

Water Usage
Firstly, water usage. Some water is required to drill a well. I'm not sure how much, but it rarely seems to be an issue for conventional wells. On top of that, hydraulic fracturing also requires 1-5 million gallons (about 10,000-20,000m3, or 4-8 Olympic swimming pools) of water. 5 million gallons sounds like a lot, but it's all about the context. In the UK, 2,559 megaliters of water are lost through leaks in our water system every day. That's 676 million gallons (or 2.5 million m3, or 1000 Olympic swimming pools), enough to frack more than hundred wells every day! If we improve leakage rates in our water system by 1%, we'd have enough water to spare to frack a well every day. So water usage isn't really an issue - if you're worried about the next hosepipe ban, get on to your water supplier to fix their leaks.

Produced water
One of the issues with fracking is that the injected water comes back up the well. Even if the latest CleanSTIM fluids are used (using only ingredients available for use in the food industry), the returning fluids are contaminated by their time in the reservoir, picking up NORM, heavy metals and organic compounds. When the water is returned up the well, it has to be dealt with.

But what about conventional HC production? Most conventional reservoirs have what is called residual water saturation - the part of the rock's pore space that is filled with water rather than hydrocarbon. When the reservoir is produced, the water comes up along with the oil and gas. This water has been in contact with the oil, gas and rock for millions of years, so like the fracking water it may be contaminated with NORM, heavy metals and organic compounds, and it must be dealt with. It's not actually an issue I'd given much thought to until now - having a blog is sometimes great for making you research something you otherwise hadn't considered. As far as I can gather from this page, it appears that in the North Sea this produced water is treated on site and then dumped into the sea. This was quite surprising to me - that it was easy enough to clean the water on-rig to a standard where it can be put back into the sea! Onshore (at Humbly Grove for example) it would appear that this water is re-injected into a deep lying aquifer (I couldn't find out anything about whether it was treated first or not).

So dealing with produced water would appear to be as much an issue for conventional production as it is for shale gas. The main difference is that for shale gas all the water is produced immediately in the days after the frack, while for a conventional field it is produced continuously through the life of the field.

Seismicity
Shale gas extraction has generated a couple of small earthquakes near Blackpool. However, induced seismicity occurs in conventional reservoirs too (read the abstract of this scientific paper, or the whole thing if you have access). So again, as much an issue for conventional production as for shale gas.

Surface Impact
I'm sure many of you enjoyed the good debate between myself, 'John' and 'Anonymous' on my previous post about the surface impact of shale gas extraction. In as much as shale gas fields will probably have more wells than conventional fields, there will be a bigger surface impact. Conversely, however, shale gas wells will be capped with Christmas trees, which are fairly low impact in comparison with a nodding donkey which might be needed for a conventional oilfield. Examples of both are below.

Oilfield nodding donkeys (above) and gas production 'Christmas Tree' (below):

As for other 'excrescences' of the oil and gas processing chain, as John so eloquently described them - pipelines, compressor stations, processing facilities - these are pretty much the same whether it's shale or conventional gas (obviously, oil requires different processing facilities).

All of this leads me to a question that I'd like to ask those who are opposed to shale gas development. Would your opposition be as fervent if new conventional gas fields had been found under Blackpool, rather than shale gas?

Shale gas, and fracking, sounds scary in comparison with the conventional production that we've had for a hundred years. However, when you break things down and look at the major objections to shale gas, are they much different to conventional operations? Wellbore integrity (and the risk of gas leakage from wells) is as much an issue for conventional gas as it is for shale. Dealing with contaminated produced water is always an issue for conventional reservoirs, much as it will be for shale. Induced seismicity happens for both conventional and shale. Shale gas will likely have more wells, and so a greater surface impact, than conventional gas, but this is an incremental increase, not a game changer, while much of the related infrastructure - pipelines, processing facilities etc - will be similar. Intellectual honesty would dictate that if you are opposed to shale gas extraction for these reasons, you should be equally opposed to conventional onshore gas extraction.

Given this, would a better description for those opposed to shale gas development in the UK be 'anti-onshore gas development', rather than 'anti-fracking' or 'anti-shale-gas'?