Session 2010-11
Publications on the internet

To be published as HC 795-ii

House of commons



Energy and Climate Change Committee

Shale Gas

Tuesday 1 March 2011

Mark Miller, Dennis Carlton and Andrew Austin

Nick Grealy and Jonathan Craig

Evidence heard in Public Questions 118 - 207



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Oral Evidence

Taken before the Energy and Climate Change Committee

on Tuesday 1 March 2011

Members present:

Mr Tim Yeo (Chair)

Ian Lavery

Albert Owen

Christopher Pincher

Dr Alan Whitehead


Examination of Witnesses

Witnesses: Mark Miller, CEO, Cuadrilla Resources, Dennis Carlton, Executive Director, Cuadrilla and Andrew Austin, CEO, IGas Energy, gave evidence.

Q118 Chair: Good morning and welcome to the Committee. We are embarked on this inquiry into shale gas, an interesting and topical subject, and I think the inquiry is already attracting quite a lot of interest. For the avoidance of doubt, I am happy for it to be known that we are visiting Blackpool tomorrow, so we can discuss that if that is helpful. Could I ask just generally to start off with if you could tell us about-I think it is correct to call it-the unconventional exploration, what you are engaged in currently and what that might lead to by way of production?

Dennis Carlton: Yes, I can address that. At the current time we are in the first phase of exploration. We have drilled one well to total depth, about 9,200 feet. It is called the Preese Hall No 1 well, which you will see tomorrow, and that well is currently being prepared for a fracture stimulation job probably in the next two to three weeks. The second exploration well we are drilling is the Grange Hill No 1, and that well is currently drilling at about 6,000 feet and you will also see that well tomorrow.

Of course, the first part of any successful shale gas play is the exploration part, and that is the part we have taken so far. We have built maps based on all the geologic data, subsurface data, geophysical data, outcrop data and selected drill sites to prepare for drilling. Once we have completed the wells in the exploration phase we will try to test those wells, see how commercial they are, and get some type of established flow rates so we can make a commercial decision whether we want to drill additional wells. If, for instance, those wells are successfully drilled, completed and show a commercial rate then we put those wells into production. We also will be able to look at a well that is in production-it’s not a shale gas well, but you’ll see tomorrow-that will probably either sell the gas through a pipeline system but more likely will sell gas into the electric grid system; sell the gas as electrons versus molecules.

Q119 Chair: How long will this take? Give me a feel for the timetable you expect.

Dennis Carlton: The exploration phase has been going on for-the actual desk work exploration phase has been going on for two to two and a half years. We started drilling the first well in about August 2010. It took about 90 days to drill. The second well we expect to take about 45 to 60 days. The initial wells always take longer than you expect. The fracture stimulation work will be carried out over a two to three-month period. We want to make sure we collect sufficient test data to know if we want to drill additional wells or not. We are talking, from start of drilling a well to completion of the well, anywhere from minimal size about four months and a more realistic time schedule, about six months.

Q120 Chair: If you find this will you go into production yourselves or will you engage someone else to do that?

Mark Miller: Our plan, as Dennis said, is in three parts. It’s explore, evaluate and then decide. We have a number of licence areas outside of the UK as well, and over the next two years we are going to look at those and when we see ones that look like they have potential then we look at putting together a field development plan. But with that said, we do currently have a five-year business plan that includes a provision for production in it.

Q121 Chair: When you are doing this, and if you treat me as a new reader on this subject, do you want to keep the data you find very confidential? Are there competitors breathing down your neck who might try and steal a march on you?

Mark Miller: You do keep it confidential in the early stages, but all that has to be public after a certain amount of time and so we keep confidential what we have right now but, that being said, we have been very open with operations, with the media, the local councils and the public, so it isn’t totally confidential at that level that we don’t invite people by to look at the operations; we do that quite a bit.

Q122 Chair: Do you have a view about how the prospects for shale gas and coal bed methane compare in this country?

Andrew Austin: I can probably speak to coal bed methane a little bit more. We basically have pilot operations ongoing in coal bed methane now, producing gas from our site at Doe Green in Warrington and generating electricity and selling that. We’ve drilled nine wells at eight different locations over the last five years. My view is that coal bed methane can be quite a material input to the energy mix in this country and shale gas, ultimately if that can be demonstrated to be commercial and can be flowed at the right rates, could also be a big important part of the mix. I think the most important part of that is its ability to displace imports of other gas from other places, both in terms of security of supply but also in terms of carbon footprint.

Q123 Chair: Are the steep decline rates an anxiety?

Andrew Austin: In coal bed methane it is a different shape of production curve to shale. For coal bed methane you have quite a flat production curve that drops off over a period of time, so then producing for 15 to 20 years on the basis of US and other Australian analogues. That is not so much of an anxiety, from my perspective, but I am sure that is one of the things these gentlemen are going to be looking at.

Dennis Carlton: Yes, if I can give a little bit of colour on that. For the typical shale gas well that we’re looking for in the UK, we expect the initial potential flowing rate, the IPF, to be in the range of 2.5 to 5 million cubic feet per day. As Andrew mentioned, the production profile is different than a coal bed methane. We will see probably 50% decline from the initial potential over the first year to 18 months, followed by about a 20% to 25% decline-it’s a hyperbolic curve-and then at that point anywhere from 5% to 7%, maybe 8%, decline for the next 25 to 30 years. A lot of flush production, as we say, in the early stages and then a long production life.

Mark Miller: It is not uncommon in some of the North American shales to have shales that have been drilled 50 to 60 years ago and still are producing at commercial rates today. After you undergo your initial decline then you have a pretty stable production for a long, long time.

Q124 Chair: In terms of technology, we are using technology that has been developed principally in the United States , are we, for exploration and production?

Mark Miller: Not solely in the US, but the US has probably developed a lot of the technology used in shale gas, but it is a good point maybe to catch up and talk about this term "unconventional" because we are not using unconventional technology. When people talk shale gas or unconventional gas, the term "unconventional" refers to the type of reservoir that we are in. The techniques are the same as you would use for a "conventional" well, whether it is an oil or gas well, so the technologies that are out there today that weren’t there, say, 20 years ago are related to our ability to locate from surface, using seismic locate, the resource, and then to really understand what is going on down hole. With the ability to do computer modelling, we can model reservoirs, we can do fracture mapping and understanding where hydraulic fractures go. We can do a better job of analysing cores and one of the great advances is just the ability to steer a drill bit, to be able to sit at surface and know the azimuth of your borehole and the location of your drill bit. These are the technologies that are advanced. I guess the other one to mention is just really overall equipment efficiency-more horse power in smaller packages and things like that. But it is technology that is used in the entire industry, not just in shale gas.

Q125 Ian Lavery: Obviously, huge volumes of water are required in the fracturing process, which gives notes for concern. I am reading about some of the millions and millions, perhaps billions, of litres of water required. What measures have you put in place to ensure that the fracturing activities don’t place extreme stress on the water resources in the UK ?

Mark Miller: I will just talk about the volumes we are using and then talk about-because it sort of leads into the answer to your question-what we are doing with our shale, which is probably going to be typical of what is done in a lot of other areas. I will just focus on what we are doing right now. We will probably use about 1,000 cubic metres total for our drilling process and probably another 12,000 metres for the fracturing process. That is a big number, 13,000 cubic metres, but just to put it in perspective, it is about five Olympic swimming pools. Again that is no small volume, but in a year we may use 20 Olympic swimming pools.

We buy our water commercially from United Utilities. They know their availability of water and they curtail us if they feel we would be taking too much. But just in looking at the numbers that they produce, one of the interesting statistics we came across is that each day, every day, United Utilities in the north-west loses about 408 million litres of water just to leakage in lines. When we look at what that means in terms of oil and gas wells, if we were to consume the water equivalent to the leakage, we would have to drill 11,000 of our wells in a year. A different way to look at it is to say that the total amount of water that we are using is about 0.08% of what goes to industry and the public out there every day, and that is if we were to drill four wells per year.

Q126 Ian Lavery: Where does the water come from? It is from the mains or is it delivered from other parts of the UK?

Mark Miller: Right now we are buying from the mains and as often as we can, we will. I think in most of the areas that we have proposed we will be able to buy from the mains. In getting our licence with them and everything they tell us how much we can take on a daily basis so that the line pressure does not drop, and we are just an industrial customer like anybody else.

Q127 Ian Lavery: Are you recycling any of the mains water in the hydraulic fracturing process?

Mark Miller: Our intent is to do that, we have not fractured yet, but normally the rule is that when you can you do, partly because you don’t then have to buy additional water. But you recycle what you can and then if there is any water that you can’t recycle, if the salinity gets too high, you have to take that to a disposal facility.

Q128 Ian Lavery: When you extract huge volumes of water from the shale gas during the process this can often cause subsistence and destabilisation, what are you doing to ensure that that doesn’t happen?

Mark Miller: First of all what we extract from the shale will be mainly water that we are putting in during the frac treatment, with a very small volume of produced water thereafter. As a good rule of thumb-I am only quoting because we have not done a job yet -we expect we will get returns similar to some of the North American shale plays, and that is somewhere around 20% to 30% of the water you put in comes back. That on its own doesn’t result in any subsidence. I have a core here I just brought along to show you what the shale looks like. When you look at this and try to compare it to oil and gas plays around the world where there has been subsidence, you look at the nature of this rock and it’s just not compressible. The other thing to remember is that in order for it to subside, we have to take a large volume of something out of it so that the pore space is collapsed.

But typically in an oil and gas well and typically in shales you may get 20% to 30% of the gas out and the rest stays in place. You never actually collapse the pores. That is not something that occurs in shale; it may occur in some really high porosity oil zones in other places in the world. For example, in Holland you can get subsidence, but it is a different type of reservoir altogether.

Andrew Austin: Just in terms of, again, the coal bed methane produced water and the usage of water. We tend to use our own produced water and then wherever possible use that to inject back into the process. We are seeking not to take water out of the system but, again, the numbers are materially lower.

Q129 Ian Lavery: Is there a problem with the water quality?

Mark Miller: Is there a problem with the water quality?

Ian Lavery: Yes, with the extraction of large volumes of the water, is there a problem. Does it have an impact on the water quality in the well?

Mark Miller: Are you talking about when we pull it out will it be a problem for disposal?

Ian Lavery: Yes.

Mark Miller: We anticipate not, but we will not know until we pull it out. We don’t expect it to be, but we have a programme set up so that when we do start removing water from the well we will test for a number of components in the water. We visited the sites where disposal takes place currently for drill cuttings and any drilling mud will also take place when we go ahead and bring back any frac water that we can’t recycle. One of the natures of the visit is to make sure we understand how it is going to be handled and to look at the permits they have in place with the Environment Agency to ensure that what we are bringing to them fits. Even if they would say, "Well, we’ll take it" we want to make sure that it is in compliance with what the Environment Agency has permitted. We will be monitoring that. We don’t expect it to be a problem, but we will certainly know before we break through.

Q130 Albert Owen: You mentioned the Environment Agency there, which monitors quality and concentrations of the chemicals added as well. Can I ask, again as very much a novice here, why you do not use pure water. Why do you need to add chemicals to it? The concerns are not just about the volume of water; they are about the acidity and the chemicals added.

Mark Miller: We use almost pure water. The first thing, just to put some numbers to it, is that 99.8% of everything that goes into a frac fluid is fresh water bought from United Utilities, plus sand. That makes up the bulk of it. But that still leaves about 0.2% of additives. What do we add-

Albert Owen: On a huge volume of water.

Mark Miller: What’s that?

Albert Owen: It is only 0.2% but it is a big volume of water.

Mark Miller: It is, but as a dilution factor it is relatively small. Now, what do we put in and why? We put in a friction reducer. You can imagine when you are pumping down a steel pipe at high velocity you generate friction, and that friction results and manifests itself at the well head as additional pumping pressure. In accordance with the well design, you cannot exceed your well head pressure so what would happen is you would have to slow the rate down to offset the friction. You put a friction reducer in and it just really makes the water slippery and kind of puts it in laminar flow and enables us to get the injection rate we want without excessive friction.

The other product is really just a biocide and there is any number of them out there. What they are for really is to make sure that when we take water that should pretty fresh and pretty clean from the mains and we put it into a tank, it sometimes can be in the tank for maybe several days before we frac or sometimes potentially a week, you don’t want bacteria growth in it, so it is really just to make sure that what we put down the well is pure. Bacterial growth in a well can basically shut off the permeability of what you have just done with the fracing.

Q131 Albert Owen: So it is an anti-corrosion?

Mark Miller: No, it is an anti-bacterial growth. The water itself coming out of the mains is probably fresh enough on its own, but you put just a little bit of this in, and it is a real small amount. Something like a gallon of this goes into 20,000 gallons of fresh water.

Q132 Albert Owen: You are talking my language a little bit, but the concerns that people have is that here in the UK you are only going to add a couple of chemicals; are you just suggesting that?

Mark Miller: Right.

Albert Owen: But in America they do far more.

Mark Miller: They might.

Q133 Albert Owen: Why?

Mark Miller: I don’t know, I mean I am not an expert on what they are doing over there, but let me talk just a little bit about fracing in general. Somewhere I saw a number of lists, like there are 576 different chemicals. There is nobody, I would venture to guess, uses more than four or five chemicals in any one frac treatment but different formations, different sandstones or limestones require different types of chemicals. The worst on the list are really things you put into conventional oil wells to make sure you prevent paraffin precipitation or you dissolve asphaltenes, but they are not needed in a shale. The one interesting thing about the shale fracs is that they use these simpler chemicals for a particular reason. We don’t want to build viscosity in our fluid like you would typically do in conventional reservoirs because we don’t have the same type of leak-off. What we are really trying to do is we are trying to get our thin low-viscosity water to enter these little tiny natural fractures that we find in our cores and open those things up. They can be two sand grains wide and so shale is intentionally designed to be simple, not just because of the environment but because scientifically it works.

Q134 Albert Owen: The Environment Agency will be monitoring the volumes of water you use, the extraction you use from the mains, yes? The amount.

Mark Miller: Yes.

Q135 Albert Owen: Then the concentration of the acid, and then if you are not recycling it, you are putting it in a disposal tank, that will be monitored before it is disposed.

Mark Miller: Yes. We are doing the testing on it. They make periodic inspections of a well site and one of the things they look at is when they come out they look at our delivery tickets just to ensure that we are always delivering any waste products to the approved sites that are permitted for it.

Q136 Albert Owen: Sorry, you leave them in a settling tank and then the chemicals will be taken-

Mark Miller: No. We are talking about a few different things. Right now we are disposing of drill cuttings, so when the little rock chips come out we have to haul those somewhere, and we have one particular landfill for that. There is another, our drilling mud, and we have to dispose of that. That is a different type of landfill and when we get ready to take our water, that will be one of the same landfills, but in a permitted disposal area.

We have not yet fraced a well and had to haul water away, but that will be monitored, so we will look at all the trace elements coming back in it, we will know what it is and if it exceeds anything on the permit then we will have to do something different-

Q137 Albert Owen: What would that something different be then?

Mark Miller: You have to find a site where you can dispose of that, but the numbers in the permit, the base line, are much higher than what we expect to get back. They are much higher than what you typically get back in a shale well.

Q138 Albert Owen: Because you use less chemicals you are thinking that it is going to be an easier and safer method of disposal than the Americans use, in the main?

Mark Miller: Yes, I guess we didn’t design a system necessarily for easier and safer disposal, that’s a benefit of the system. We designed the system we had on what we think will work in the shale. Simpler is always better. It is simpler for us, it is lower cost, it is simpler to pump the job itself, but a big bonus is that it is a safer system to dispose of. We just won’t be using what some of the companies use over there. We do not have a need to do it here.

Q139 Albert Owen: Would you be permitted in the Environment Agency guidelines? Is it because we have got stronger regulations here?

Mark Miller: I don’t know how to necessarily compare them because over there it is a state by state thing, but my initial reaction is that you would have equally strong or stronger regulations in some areas. We have agreements with the Environment Agency and a regulatory process. We have disclosed to it all of our chemicals that are going into the system and if, for example, we are a third of the way in and we say, "You know what, we need to build 10 centipoise viscosity and we need to put a small gelling agent in," then we have to select something on the approved list. There is any number of products out there, and additives, that we are convinced we could put in. But the one thing we are not doing is giving a short list and telling everybody we are going to do this knowing full well we have something else ready to go. Just from a scientific point of view, until you do a few of these you can’t really say, "We will never change anything".

Q140 Albert Owen: Can I ask Mr Austin about coal bed methane exploration? Are any toxic chemicals added there?

Andrew Austin: No.

Q141 Albert Owen: Not at all?

Andrew Austin: No, not at all. Basically the wells we have got on production right now are literally drilled as laterals in the coal. We have fraced one well at Doe Green, we fraced that simply with pure-with produced water from the well primarily and pure water from the Utilities. We didn’t add any proppant into that in the first instance just to see what the range of the frac would be. We may now look at re-entering that and fracing that with sand as a proppant, but we do not need to add anything extra into the water at all in our cases because we are dealing at shallower depths in more permeable coals with less pressure environments than for shale.

Q142 Albert Owen: But the Environment Agency will be monitoring you in the same way?

Andrew Austin: Yes, we have a licence from the Environment Agency for that site. We are engaged with them in terms of what we were able to take out of the ground and what we put into it. As a natural part of producing CBM you do produce water, which is mildly saline, brackish water. We have to have those permits in place and we found the Environment Agency informed and engaged in dealing with them.

Mark Miller: If I could make just one more point there. You were talking about the dilution of the toxic chemicals. I talked about a friction reducer, and the main compound in that is polyacrylamide, which is used in facial creams and contact lenses and also as a bonding agent to seal soil. It is a product that isn’t toxic. It isn’t in the list with benzene and toluene and those things, it is a common product. The biocide is really a product that is-as I said there is a number of them out there, but we will be selecting one from a list that is used in treating drinking water.

A third additive is one that is not really mixed into the frac fluid but is a diluted weak concentration of hydrochloric acid and muriatic acid. It is put in just in front of the frac fluid in a very small volume, maybe 200 to 300 gallons and it is only for the purpose of initially opening up the perforations that we put through the pipe and allowing us to start a fracture treatment. It is very dilute going in and then it is chased by the 12,000 cubic metres of water and becomes really diluted at that point. It is the same product that is used in the food industry. In fact it is used in the processing of beer so it is-

Chair: We won’t go there.

Mark Miller: Anyway, so I just want to make that point, when we talk about toxic chemicals we are not using anything off the list of the-

Q143 Albert Owen: You would be happy to drink the residue?

Mark Miller: There is a lot of things I wouldn’t drink in my household but that is-

Albert Owen: I asked this of somebody in a sewage plant and they said that the end product is so good that they would be able to drink it.

Mark Miller: Who said that?

Albert Owen: Somebody from a sewage plant.

Mark Miller: Okay, well, I mean and maybe that is true. I probably wouldn’t do it but that is-

Q144 Albert Owen: You would not take up the challenge?

Mark Miller: I probably wouldn’t worry about it, it is so dilute but, you know-

Q145 Christopher Pincher: You might get the chance tomorrow.

Albert Owen: I will have a beer tonight.

Christopher Pincher: To line your stomach. You are pumping swimming pools full of usually treated water down a steel pipe to fracture the shale. You said that you use computer modelling to work out what sort of geological formation you are working with. The US Environmental Protection Agency said that, "Predicted and actual fracture lengths still differ frequently and it is difficult to accurately predict and control the location and lengths of fractures". Do you really have any control over the fractures that you are creating? If you do, what do you do to try and control that?

Mark Miller: Let’s talk about that statement. First of all, you do not ever have control in the sense that you can make a fracture go a certain way. It is always going to go along the path of least resistance. I would disagree with the statement that fractures differ from what is modelled. If your modelling were using micro-seismic data in the process of fracture mapping, you can see with real precision how far the fracture goes, how wide it goes and how high it goes. In our case we can’t use micro-seismic because you have to have a twin well. On our very first well, we can’t do it. As we go forward, if we develop this project, we will get to the point where we can run it. But what you can do through taking cores is look at similar shale formations in the US. It’s like a type analysis where you say, "This type of shale or this Young’s modulus and this Poisson’s ratio and all those mechanical properties of the rock result in fractures that grow in a certain length, width and height". I think we do have a pretty good handle on it. The modelling software today is as good, with any software, as the input data.

Now, if we were to shortcut this and not take these kind of cores and really study them, we would have a difficult time using one of those models with confidence. But we have invested a lot into our core acquisition and core analysis and we have a pretty good handle on what is going to happen. Generally, as a rule of thumb, a fracture grows up the same distance as it grows out. It has no reason to continue growing up or continue growing down in any one direction. The upward growth is usually terminated as soon as it hits some kind of impermeable hard rock. In our case, nothing would grow past the Manchester Marl, which is a formation up the hole that is a normal cap rock for some of the shallower gas-producing sands. We are confident we have a pretty good handle on how this is going to grow.

Q146 Christopher Pincher: If I say to you that you can predict the way the fractures will go, but you can’t control them, is that an accurate summation?

Mark Miller: Yes, it is.

Q147 Christopher Pincher: A lot of water leaks off, as I understand it, stays underground, and I am told that that can exceed 70% of the volume that is injected, so it doesn’t seem to me to be leak-off, that is flood-off. The question is what is the risk of that leaking into aquifers, into water supplies and what kind of effects will it have?

Mark Miller: Okay, so the same thing. In this instance we talk about leak-off, we are generally referring to that which goes into the matrix of the rock. In this case, because there is almost no way to really get water into something this hard, what you are doing is you are water-wetting the face of the fracture. You open thousands, literally thousands, of small micro-fractures and you put sand in there. There is a lot of water stays in that sand pack, then water wets the sand grains and water wets the face of the fractures and maybe penetrates a very small amount of the actual matrix of the rock. That is why we get the easy water back, which is perhaps 30% and would be consistent with what you are saying-that 70% stays in place. Now what happens to what stays in place? Generally over the next 50 years it will be produced back; it will give it up as we produce gas in real small amounts, but as far as being able to get back to the surface, it cannot physically go through 5,000 feet of solid rock and find its way up there. If it could, it would already be doing it, so it can’t do that, so the only pathway is if you have a faulty well bore. That becomes an issue of well design. If you do a proper design and put the right casing strings in, you pretty much eliminate the chance of this finding its way into a shallow zone.

Q148 Christopher Pincher: We know all about faulty well design, don’t we, after Deepwater Horizon, so how confident are you that your well design for any particular geological formation is secure?

Mark Miller: We are very confident. We use industry best practices and we have an independent examiner look at our well design. In our case, we are probably over-designing by running more casing strings than are really needed and running them deeper than needed. So we are very confident that we have put back-up systems in place so it just would be near impossible to breach our well bore and get into the ground. But I would like to point one thing out. When I say "near impossible" it can lead to, say, a small percentage of it. In our case, I would say almost not at all. But the thing that is very important to understand about well leaks is that, if they happen they do not cause permanent damage to an aquifer or a situation out of control. It is very easy to go in with today’s instrumentation, pinpoint the location of a leak and then pump what we call a remedial cement job, where you put cement out through that leak and fill the back side and then there is a way to test it to make sure it worked. It is called the bond log. You run a third instrument and it shows you the actual bond between the cement and the casing and shows you that you have eliminated the channel. If something like that happened from a well bore, it is repairable. Typically, it is a three to five-day process to do it.

Q149 Christopher Pincher: You mentioned the independent reviewer of the well design. Who employs the independent reviewer?

Mark Miller: Excuse me?

Christopher Pincher: The independent reviewer of the well design that you mentioned just now, who employs that group of individuals?

Mark Miller: We pay them a fee to do it, but there is a list of four of them that I know from around the UK that are on the approved list for the HSE. Their role is to look at our well design; they don’t necessarily have the authority to overrule, but they make recommendations to the Health and Safety Executive, which can overrule it and recommendations to us. If we put a well design together and they see any part of the process that doesn’t have dual barriers-just as an example, where we don’t have sufficient isolation in containment in our well bore-they will flag that and say, "Step 13 in your programme says you are going to do this, but at this point in time you don’t have enough barriers". So we have to go back then and re-do our design. They get a very small amount for their hourly work, but basically out of the four of them one always has to look at the design and recommend to the HSE and to us if they see anything they would like to see changed before we proceed.

Q150 Christopher Pincher: One last question. How easy is it to determine the cause and effect? If you do have polluted water in an aquifer, is it possible to determine very easily that the cause of that is leak-off, for example?

Mark Miller: It is. We do a lot of testing on the front end, so we have tested ground water, we have tested water from water wells and ponds, streams and soil samples, and we are even testing for things like radio activity at outcrops. We are just trying to get a baseline of everything that is out there. Then as we bring our fluid back we monitor it, so we say, "Here is the base line, and here’s what is coming out of the well". If there is a change and that change matches something on our list then for sure it is coming from our well and we would run one of those logging tools down and say, "Okay, it is our problem, we’ll go pinpoint the problem and repair it". But, as you can imagine, problems can crop up that have absolutely nothing to do with an oil or gas well. People say, "What’s new in the area? Somebody drilled a gas well so that’s the reason there’s a problem." That is why we at the beginning of our drilling we went around and established a baseline of streams and soils and different things.

Q151 Christopher Pincher: If you spot that something is different from what you expect, do you stop drilling while you investigate or do you continue working?

Mark Miller: The answer is yes. If we spotted it while we were drilling, we would certainly stop drilling and repair the problem, but normally when you hear about contamination found in water it happens in the production phase, so we are a long way from that. As I said, we are going to explore and then evaluate and then decide. We are potentially several years from that. But that is usually when you see it. It’s when you start crushing up the casing and flowing a stream of gas on a day-by-day basis that if there is a leak it will finally work its way into something. But as soon as we saw it we would isolate that well, pull it out of production and repair the problem.

Dennis Carlton: I might add that in the case of potential contamination of a shallow water aquifer by natural gas, somebody has gas in a water well for instance, there are ways of typing the gas molecule that is in that particular well. We can take our gas, type it and compare the two to see if one is a biogenic gas versus thermogenic gas or, indeed, if our molecules of gas are contaminating the shallow water aquifer. In that case, as Mark mentioned, we can make a repair to the well if necessary.

Also we can compare water chemical analyses to determine whether any of our water is leaking into a shallow water aquifer. In other words just a pure chemical analysis; if we have a certain element or chemical compound in our produced water and it shows up in a water well then we will know that there is a potential problem. There are ways to identify the problem.

Q152 Chair: Following on from this, tell us a bit more about the flow-back. How much of the fracturing fluid returns to the surface as a result of the flow-back?

Mark Miller: That would be somewhere between 20% and 30%. That is what we are expecting, and that is consistent with a number of the shale plays around the world and, in particular, North America. When we say 20% to 30%, that is probably what we would get back in the first 60 days, and then for the remainder of the life of a producing well you will always get small amounts back. You might reach a point where there is 50% back, but the next 20% would come over years of production.

Q153 Chair: You treat that when it comes back to the surface, do you?

Mark Miller: What we do is we dispose of it, but we test it first. We test it to make sure it meets the requirements of the disposal area where we are going to take it, but it is tested then disposed of. If it needs treating-for example, if it falls outside the guidelines of what is available at any disposal area-then you do have to treat it. There is various equipment and processes out there available to the industry. They are expensive, but it is not a dead-end street if we come up with something that doesn’t fit within the realm of what is allowable to disposal areas. But right now we think we are well within the guidelines of standard disposal for oil and gas wells.

Q154 Chair: What are the risks of spillage or seepage during this period?

Mark Miller: So we are talking at the surface now?

Chair: Yes, surface.

Mark Miller: There is always risk, but one of the things we do that is different than what a lot of the North American operators do is that we don’t use earthen pits to store flow- back fluids or to store drilling mud or cuttings. Everything we do is in a steel tank so that is the start of it. You don’t have to worry about a plastic liner leaking and leaking into the ground. But even a tank under the right conditions can leak at a valve or something. The much bigger failsafe is that when we build a well site, the first thing we do is put a heavy plastic material; it is one heavy enough that if you try to take a knife and pierce it, it will be very difficult. It is not a thin plastic roll-out layer but they put this under the entire well site and they build a dyke around it. When you come and look at the site tomorrow we will show you that and show you just how hard that is. That is about 18 inches down under the gravel. Let’s say, for example, some fuel spilled from a tank or some hydraulic fluid. It would probably be contained in the gravel, which is to be dug up and removed when we reclaim the site. But let’s say it was so big that the gravel alone couldn’t contain and filter it, it has got nowhere to go but out to the dykes around the location and they feed into a holding tank where you can skim it off.

It would be pretty difficult to see any scenario where something could happen out there where we could have leakage go straight from the surface, straight down to the groundwater.

Q155 Chair: Do you test routinely for the presence of any dangerous substances that might have escaped by some method or other?

Mark Miller: We test all the waste materials and we test our frac flow-back when we get to that point. As I said, we have established a baseline of getting all the fluid compositions around the site and soil samples before we have drilled. We have not yet got to the point where we have set up a programme of routine testing. It certainly would be relatively easy to take periodically some stream water or pond water or something from nearby, or soil samples.

Q156 Chair: Are you already having to treat waste water as it is?

Mark Miller: To date, all we really have is what we call the drilling mud, which is a freshwater-based mud. We call it mud. When you see it tomorrow you will see that it looks like muddy water but it has clay in it; that is the main compound. That has to be tested when we deliver that to the landfill.

Q157 Chair: If we see shale gas production developing in this country, will there be a need for lots of waste treatment centres as a result of that?

Mark Miller: I don’t know; I guess I am not familiar enough yet with how many are out there and where they are at. I have only really looked at what we are using. I suppose it is possible, but the oil and gas industry and a lot of the waste facilities we are using have really been established to handle some of the fluids coming from offshore, and that is a pretty big industry. I don’t think the amount that we would be bringing to it, even if shale gas got pretty active, would really exceed the capacity that was set up to service the North Sea.

Dennis Carlton: If indeed it did, we could drill a disposal well or contract with somebody who has a disposal well to increase the volume capacity.

Q158 Dr Whitehead: Are these procedures identical if you are drilling on land or if you are drilling, say, in shallow water?

Mark Miller: The drilling procedures?

Dr Whitehead: The waste water disposal and the use of water and so on.

Mark Miller: I am not an expert on the offshore, but the actual drilling process is the same other than that the equipment, of course, is different. The process is the same of protecting shallow aquifers and disposing of hazardous fluids. There is always some fluid coming out of wells that can be tested and deemed fit to put right into the North sea. There are other fluids that could be from a stimulation or a fraction treatment, because they frac offshore as well by boats and large vessels, and if there is flow-back water that doesn’t meet that criteria then they bring it to these land-based facilities over on the coast. In Hull there is a large disposal area.

Dennis Carlton: Or in some cases they take the water that may need to be disposed of and reinject it into the formation that they produce from.

Mark Miller: I would have to say in general the procedures would be the same. The drilling procedures, everything, well control, all the issues are identical whether you are onshore or offshore. It is only the type of equipment that you work with.

Q159 Dr Whitehead: If there is production, how will you dispose and transport the waste water away?

Mark Miller: If there is production?

Dr Whitehead: Yes.

Mark Miller: One of the things you will see tomorrow is the producing site that we have up at Ellwood. It has a tank on site and when you get to the disposal part you get to where you have a tank out there that maybe has to be loaded out and disposed of once a year, maybe twice a year at the most. We would truck it away from that location over to the disposal site.

Q160 Ian Lavery: Looking at the permitting procedure, it is not clear under what Act shale gas would be or should be regulated. There is a lot of conflict and a lot of ambiguity, depending on who you believe. Can you explain what the procedures are for companies such as yours to obtain a licence or a permit for unconventional gas exploration or production?

Mark Miller: Sure. I will start off answering that question by going back and saying the reason there is no definition in any of the regulations about unconventional or shale gas is because the process of getting it is no different than any other well, so when you construct a well it doesn’t matter whether we are going to produce from a sandstone or a shale, the process is the same, even right down to hydraulic fracturing.

Let’s talk about the process for a minute. When we decided that we wanted to get a licence over here the process that we had to go through started with DECC. You have to wait for a licensing round to come up and then you look at available licence blocks that are out there. You may decide that you want to make an application for a certain block so you have to, in your application, first demonstrate that you have an understanding and you define the hydrocarbon resource that you are going after. Then you have to put a good work plan in place and demonstrate that you have the ability to explore properly for that and that you have a chance of success in your exploration. Then the third thing you have to do is you have to go ahead and demonstrate that, even though you have a great work plan, you have the technical team in place to execute the work plan and you also have the financial backing. DECC evaluates all applications coming in under a number of criteria, but that is probably the short list to make sure you know what is there, you know how to get it and you have the financial backing and the team in place to do it.

Once the licence is awarded, then you have annual follow-ups to show-you say, "This is what I am going to do in year one, two and three" and you have to go ahead and submit reports and follow up on your obligations to DECC to give them information as it comes in about what you are doing. Typically, from the time that you get a licence you may have, in our case, two years of studying the area just to know where we want to put our first well or our first couple of wells. When we have arrived at that decision, the next thing is to get a planning permit, and we deal with the county councils on that. Part of the planning application for them is to go in and define the project, make sure it is clear what you are going to do and what equipment is going to be involved, and you have to do various studies. We have to do, as a minimum, different environmental studies, including ecology, we have to look at noise, light, traffic issues, and so all that is done before we submit the application. They evaluate the application on that and approve or reject it based on how the studies turned out and how well your plan will work within all the issues of light, noise, traffic.

Then when they finally issue you a planning permit, it typically comes with 15 to 20 conditions and says you can proceed but you have to follow these things. One of the big ones in every planning permit is protection of groundwater. We have to demonstrate to DECC that we have a plan in place to protect groundwater and they work closely with the Environment Agency to ensure that we have identified the groundwater sources and that the plan we are putting in place sufficiently protects it.

Once we have the DECC licence and the planning permit, to carry through and say, "We are ready to start drilling" we have to work with the Health and Safety Executive. They have-I brought one along-a guide to borehole sites and operations regulations. This basically outlines the different publications you have to read, the different directives. In a nutshell, the HSE look at our well plan along with the well examiners and they make sure that we are following industry best practices; they have a whole list of checkpoints. I mentioned earlier double barriers. We can’t have any scenario where we go in and say, "We only have one valve in place when we should have two". They check your entire process against that and they check the type of casing we are running, they check the metallurgy on it. We have to identify all these things in order to go ahead and get approval from them to proceed. Then once we do proceed, they have a very rigorous follow-up procedure. Every Monday we have to give them a detailed list of the operations in the previous week. For instance, we did a blow-out preventer test and we have to show them that everything we have done follows what is required from the work plan that they approved. They follow up on that and, of course, they follow up on routine site visits and they also make sure that the general work environment from a safety standpoint for the employees out there is a safe work environment.

That is a quick overview of how you get the licence, how you get the planning permit and how you get then finally the permission to drill.

Q161 Ian Lavery: Do the permitting procedures deal explicitly with unconventionals?

Mark Miller: It doesn’t mention unconventionals because unconventionals are only a term that we as an industry coined years ago to describe a type of reservoir. It is not the process. There is no such thing as an unconventional well or a conventional well; there is only an unconventional reservoir, and that only means that the gas is stored in the same place that it is generated. That is the short definition of an unconventional reservoir, but there is no distinction in the drilling procedures and the well construction procedures for unconventional and conventional wells. They are done exactly the same way.

Q162 Ian Lavery: Do you think the current procedures for licensing and for permits are fit for purpose or do you think they probably need reviewing?

Mark Miller: My opinion is, in comparing it to how things were done in North America, that they are fit for purpose. When you try to go the other way and say a standard well has to meet all these criteria, you tend to end up checking the boxes and maybe have things pertaining-I will use North America as an example-to a shale well in Pennsylvania that may not pertain to the same shale well in Ohio. What really matters is that you look at every well on an individual basis. So even up there in the Bowland shale there are differences between our first well and our second well and we have to identify them. There is a difference in depth and a difference in some hole conditions, so we have to tailor a programme that meets the satisfaction of both the HSE and the independent examiner for each well we drill. We don’t have a standard Bowland Shale design and say, "This is approved and all wells will look like this". I think it is a better process doing it that way.

Andrew Austin: Can I just add something to that? I do think the system is fit for purpose because it is fit for the techniques and the places in which we are operating whether the gas has come from, as Mark said, an unconventional reservoir or a conventional reservoir. The regulation needs to ensure that the techniques employed and the way in which we deal with the surrounding environment are handled correctly. To that extent, as these techniques have been used elsewhere for many years, both onshore and offshore, with a strong safety and environmental record in the UK, the system is fit for purpose.

Q163 Ian Lavery: The EU water framework directive prohibits the injection of substances containing substances other than those resulting from the operations into geological formations from which hydrocarbons have been extracted. Does this apply to fracing?

Dennis Carlton: Yes, is the answer. Any water or hydrocarbons, which is probably not the case, but water that is produced from an exploration or production well would need to be tested, as Mark mentioned, and can be injected into a certified injection well.

Q164 Ian Lavery: It is interesting to hear that basically there is a lot of ambiguity, a lot of conflicting reports from different organisations regarding the permit, but you feel that there isn’t any ambiguity, it is straightforward?

Mark Miller: I think it is very straightforward. It is the same permitting process used in the North sea and it is based on requiring that we use industry best practices and that we do not short-cut anywhere. I think it is a very good system.

Dennis Carlton: It is a better system than North America in that it is not a cookie- cutter type. It is fit for purpose. Every well has its own drilling plan.

Q165 Christopher Pincher: Can I ask you about community involvement and engagement? These well sites are pretty big. If you are drilling up to 16 wells from one pad, it is quite a large site and whereas in the United States landowners own all the gas beneath their land we are not perhaps quite so far-sighted here. I wonder what you do to try and ensure that the local community is engaged in your work and supports it. How do you help them?

Dennis Carlton: Let me just clarify a point; in North America, not all the surface owners own the mineral state. There is a separation in some places where the mineral rights have been sold off to a different entity and/or the mineral rights are state-owned, so there is not always a good relationship between the surface owner and the mineral rights owner. There can be a conflict, so to speak.

Q166 Christopher Pincher: Do you see any conflict here between local communities and the work you do?

Dennis Carlton: No, it has been pretty refreshing. The locals have been very supportive of our well sites and it is not any different than working in North America. We have to approach the landowner, the surface owner, to see if that particular person would entertain the possibility of having a well site on his land, and negotiate a deal. In fact, in the States it is a one-time payment for access to a surface, whereas in the UK it is an annual payment and it escalates through time, based on a set schedule. It is probably three to four times more expensive to obtain a well site in the UK than in the US.

Q167 Christopher Pincher: But is there anything specific or tangible that you tend to do to ensure that the local communities are interested in engaging?

Andrew Austin: We have now obtained planning permission at, I think, 13 different sites around our various acreage, and a lot of it comes through in the planning process. Through the sheer nature of the planning process you are required to engage with the local community, required to get community feedback on your plans, and that all forms part of that engagement and consultation before making a planning application. It is very important to do that. In our experience a lot of the issues with the community are about perceptions rather than the actual practice of what happens afterwards. I think when someone arrives and says, "We’d like to drill a well in the area" people’s immediate assumption is that the rig will remain there on site. Once people realise that the rig comes and then goes, that helps in terms of their comfort about what is being carried out.

We have conducted site visits for local communities, and engaged with local community groups and community associations to allow them to come to the sites to understand what is happening during a drilling process and afterwards. We have also found it is very important to take elected councillors from different areas where we are applying for planning permission to existing sites and sites that we have abandoned-just assay wells-and show them the before and after. There is quite a lot of apprehension before people physically see what happens, but once people have seen what happens on the ground and the sites in a production phase, a lot of those concerns go away. We also spend a lot of time, as I am sure the gentlemen from Cuadrilla have as well, making sure that our sites are landscaped. We plant a lot of trees around the outside and make the impact as low as possible.

You are entering the area where someone else lives, of someone else’s environment, and you have to go in and engage with that community and you have to work with them, because if you do not, it is a recipe for a lack of success from us and a lack of trust from the community, so it is absolutely imperative.

Mark Miller: We echo that; we have done the same. One of the quickest ways to reach a lot of the local population is through the media, so we have been very open to anybody who wanted to come out, whether they are TV filming crews, or radio, newspaper and magazine interviewers. Also, we engage closely with the local councils. We have an open door invitation within the realms of what we can do safely, but if somebody shows up and is interested in asking questions about the well, we will certainly talk to them, and if somebody from the media wants to take pictures or run a story on it we have been very open and invited people round. We have had some requests from one of the local councils just to engage in some small things; they have a tree planting day every year and they wanted to know if that was something we would participate in. It’s a small investment and we are going to engage in those kinds of things just to, I guess, show our support for local projects. That is important to them and so it is something that we are certainly interested in doing.

Q168 Christopher Pincher: You have a community helpline, I understand?

Mark Miller: We’ve got a what?

Christopher Pincher: A community helpline.

Mark Miller: Our website is just about to be launched. The one that is on there now is temporary, so yes, we do have one and it has not been accessed because the full website should go out probably some time this week. But that is really just set up for people who don’t want to come by the site but say, for example, "Well, how do I know what chemicals you are putting in?" We won’t always have the ability to sit with every resident and explain what we put in, but we will certainly answer those questions by phone or by return email and there will be some sites where we just say, "Here are various aspects of our operation, come on and look and see what we are doing".

Q169 Christopher Pincher: How many calls have you had? Has the phone rung yet?

Mark Miller: There has not been any yet, but it is only because the website is just ready to be released.

Andrew Austin: We have had calls from people during drilling processes and we made sure that mobile numbers were available to people if they had any concerns. Interestingly, the only concerns we have ever heard from people around our areas where we have been operating have been around light and light spill. People are very, very sensitive, even in what you might think are really quite highly lit areas, about changing light in their curtains and things like that, much more so than noise. We have never had any issues around noise, it has always been around light. Where you can deal with that in a safe way by reducing the lighting of a site that operates 24 hours a day, you try and do so, but obviously there are safety issues around that.

Q170 Albert Owen: What do you think are the main challenges for unconventional gas development in the UK?

Mark Miller: I think what are challenges might also manifest themselves as opportunities. I think experienced work force is one. If this was to become a large-scale operation, experienced work force and a large base of service equipment would be needed. In the end, if one or more of these shale plays proves successful that will come, so the challenge might be that we have to wait a little bit. This is one of the reasons why we brought a lot our own service equipment, just so that we could carry out our exploration programme without a lot of delays, but if it was to go to production and more than one operator was in here working more than one base, you would build up the work force fairly quickly.

I mentioned opportunities, and I think it is a really important part to look at. When you look in other active oil and gas areas you build a certain expertise with the local population, and over time the number of people employed in a given area far exceeds what is needed for the rigs.

Q171 Albert Owen: Just on that, we are not seeing an Americanisation of this industry? If it develops, we are going to see UK and Europe expertise used as well?

Mark Miller: Certainly we are actively recruiting EU and UK residents to be trained and work in a work force so we-

Q172 Albert Owen: Sorry to cut across, are you using best practice from Europe as well?

Mark Miller: The industry best practice is not really divided continentally, it is a collection of best practice from around the world that is published through the International Petroleum Council and the American Petroleum Institute. There isn’t necessarily a European best practice; they may differ by requirements, but the best practice everybody is pretty much in agreement with. But going back on the expertise and how that can be a benefit, even though it is in shortage now, we always cite Aberdeen. If you look at the work force in Aberdeen, the oilfield work force far exceeds what is needed to go out and service the rigs. Where do those people work, then? They work in other countries. So you start to export talent of people who live in the UK and can get jobs outside of the country on a rotation basis. I would say that would be the challenge for the initial start-up. That will be overcome early on. If you have some success in unconventional exploration, then the service sector will take care of itself.

Q173 Albert Owen: Mr Austin, from your perspective what are the challenges and is this a UK industry in the future?

Andrew Austin: Yes, I do think it is a UK industry for the future. I think, as Mark was saying, there is a lot of opportunity for jobs. I think we do need to grow a service sector to support it and that will, by definition, have to be UK-based. You cannot bring everything in from overseas, you basically have to develop that here. I think the other challenge is that we still need to see more evidence in different basins of the right sort of commercial flow rates that can make this work financially, and I think our activity and the activity of Cuadrilla and others will hopefully demonstrate that over the next couple of years.

Q174 Albert Owen: A final question to you. You mentioned the finances. Have you had discussions with Government about tax breaks for the industry?

Andrew Austin: We have not had any direct discussions with Government about tax breaks. We do fall within the Small Fields Allowance in terms of the lack of application of supplementary charge, so we are seeking to demonstrate that we can make it economic at the current tax rates and under the current regime. But obviously as the business develops it does have a large contribution to make for UK Plc in terms of jobs, economic activity and security of supply.

Dennis Carlton: Yes, we echo those same sentiments; there is no need at this point in time for incentives to be put in place.

Chair: We are out of time, and we have some more witnesses to talk to as well, so thank you very much for coming in this morning. It was very helpful and interesting from our point of view.

Examination of Witnesses

Witnesses: Nick Grealy, Publisher, No Hot Air (Gas Policy Website) and Jonathan Craig, Fellow of the Geological Society, Chair of Petroleum Specialist Group, gave evidence.

Q175 Chair: Good morning and welcome to the Committee. Perhaps I could start off with a general question. How far do you think unconventional gas production can contribute to the UK’s energy independence and indeed our security of supply?

Nick Grealy: I think one of the main problems that we have in Europe is that right now nobody has any gas to show and it is all relatively academic. We can extrapolate from the US experience and from geology, but it is highly unlikely that there is not at least some shale gas in the UK and certainly in Europe.

Jonathan Craig: I think it is too early to say at this stage. We are in the very early stages of exploration for shale gas in the UK. There is a lot of work that needs to be done. Certainly comparison with international shale gas plays would suggest that there is some potential, and I expect eventually that shale gas will make a contribution, but I believe it will be one part of a mixed scenario that will involve other energy sources in addition to shale gas. I think it will be one element and it will make a contribution, but it is too early to say at this point in time how big that contribution will be.

Q176 Chair: Okay. If there is a contribution will it be on a Europe-wide level or will it just be localised to those countries that have reserves?

Jonathan Craig: I think it is very important that we see the issue as far as the UK is concerned in a global context. The gas market in the world these days is a global issue, so it depends where you look around the world. You really have to take both conventional and unconventional gas together-shale gas is one source of unconventional gas obviously, but tight gas from conventional reservoirs, coal bed methane, plus our conventional gas fields, which have been producing natural gas for some time. If you take the global picture, one of the things we have to take account of in terms of new gas supplies around the world is the fact that most of our old conventional fields are declining very rapidly. On a global scale, it is estimated that by 2020 we need to replace about 70% to 75% of our existing production with new sources of natural gas, both conventional and unconventional.

On a world scale, there is a need for additional gas resources, certainly. In the UK context then, we would be looking at that sitting within a European market, and clearly there are both conventional gas supplies in Europe and additional new gas supplies of conventional gas. There is of course conventional gas that comes to Europe from North Africa, for example, or from Russia. So those are all independent supplies, and a number of European countries in addition to the UK are looking to build their own shale gas resources-Germany, France, Poland, in particular. All of those countries are looking to build their own indigenous gas resources from shale gas, and they could be available both for local domestic consumption or they could go into the European gas network and be supplied more widely across Europe, including to the UK.

Nick Grealy: I do not really have much to add on that.

Q177 Chair: I suppose if we find we have significant shale gas reserves here and we start to exploit them, is there a risk that we are simply perpetuating a situation in which Britain, for an important component of its energy supplies, is dependent on gas, eventually most of which will have to be imported?

Nick Grealy: I certainly feel that the whole thing about energy security is a bit of a red herring. Right now, 88% of our supplies come from the North Sea. You often hear of 50% of imports, but most of the imports come from Norway and the Netherlands. Cuadrilla have mentioned that they hope to supply 10% to 15% of UK demand. That would be in the area of 12 bcm, which is greater than the entire LNG imports of 2009, for example. So we could displace LNG entirely.

Q178 Ian Lavery: Could conventional gas production lead to a global gas war similar to the one that we see for oil?

Nick Grealy: I wouldn’t think so because the amount of gas that is available is really game-changing. I do not think people really quite understand the amounts of gas that are available. For example the United States, from 2007 to 2009, increased their estimates of available resources by 40% over two years and in the next one, which comes out in May, we may even be looking at an increase on that.

India, for example, has recently said that its resources were 40 trillion cubic feet and Schlumberger says that now it probably has in the area of 2,000 to 3,500 trillion cubic feet. This is how things can quickly change overnight. Here in the UK we are very used to an idea that gas is running out, whereas in the United States the problem is no longer one of supply but of creating demand.

Jonathan Craig: It depends where you look in the world. The US story is in some ways quite unique. Based on today’s estimates, the US uses about 22 tcf of gas a year, and if you take their combined conventional and natural gas and unconventional resources today, at current consumption rates that is about 100 years’ worth of supply. The US effectively has a very strong position in terms of its own supply of gas for the future. One of the things that has done is displaced LNG, so LNG then becomes available elsewhere in the world on the stock market so it can be transported around the world. Clearly if you go to, for example, India, India is expected to have a four-fold increase in its energy demand by 2035 and is struggling to find sufficient gas to fulfil its requirements for the future. So it has a very strong urge to develop its indigenous shale gas resources and to bring in spot gas from LNG particularly from the Australian shelf, for example. A global market is developing, but it depends where you are, what your indigenous supply is and what that displaces elsewhere that becomes available on the global market.

Q179 Ian Lavery: What impact does the production of unconventional gas in the US have on the global gas market?

Jonathan Craig: Well, the US in the past has taken LNG shipments from elsewhere in the world to meet its demand for gas. Now that it has developed quite significantly its own unconventional gas resources, it no longer has quite the same need for buying in that gas as LNG, so that then becomes available in a wider market.

Nick Grealy: There are also a number of projects in the United States, and also on the west coast of Canada, to export gas. There is a 3 tonne vault in the Gulf of Mexico and also they are just announcing now that the Cove Point terminal near the Marcellus in Pennsylvania is getting ready to export gas, and we would be the closest customer physically.

Jonathan Craig: One of the things this has done, which I think is important, is that it has allowed us to move away necessarily from the need to look for gas resources in some more difficult environments around the world, particularly in the Arctic. If you went back five years ago, 10 years ago, the Arctic was seen as the place we were going to get our gas resources from in the future, particularly the Russian Arctic, which has huge conventional gas resources. Because now the US has developed its unconventional gas resources, the need to address some of the difficult environmental problems that would occur if we were to try and develop gas resources in some of these high Arctic areas, has gone away to a large degree. We are much less focused on those areas now. It has changed the geography in terms of where we want to look for gas resources around the world.

Q180 Ian Lavery: As the shale gas production increases, conventional gas prices could eventually fall. Is there a risk that the major gas-producing companies might form a cartel to control the production of unconventional gas, similar to OPEC?

Nick Grealy: No, I cannot imagine that happening at all. Number one, the main countries at present are in North America, so I wouldn’t imagine the United States would suddenly gang up on the rest of the world, at least in that respect.

Jonathan Craig: One of the things that is important to note is that the distribution of unconventional resources is much wider than that of conventional resources, so a lot of countries come into play that are not, if you like, the traditional big players in the oil and gas market. Poland is a prime example in Europe; it has a long history of conventional exploration that has declined over the years, and has been able to revitalise its unconventional network and resources in a country that traditionally was not part of that market. That occurs quite widely around the world, so a lot of other countries come into play. The chances of a limited number of countries forming a cartel that would have a real impact is quite slim.

Q181 Christopher Pincher: With respect to the United Kingdom, you said that we were in the early days of exploration here; we do not quite know how much unconventional gas we have. But do you think that it will be competitive with imported conventional gas in the next decade? The Oxford Institute for Energy Studies suggests that it will not be.

Q182 Jonathan Craig: Well, I think all these things at the end of the day come down to price. Now if you look at the independent studies that have been done on unconventional sources of gas around the world, so this would be both shale gas and tight gas and coal bed methane, then the independent assessments by people like Wood Mackenzie-Wood Mackenzie is one of the big analyst companies that we use a lot in the industry to give us independent advice on where the market is going-have looked at all of the major unconventional gas developments that are going on around the world and they come up with a price of about $5 per mcf as being the breakeven point. If your price is below that, then you are struggling to make things economic. Now that clearly varies depending on the type of gas, so, as I think has been mentioned already this morning, coal bed methane tends to have a lower breakeven price because it is much shallower, tight gas in conventional reservoirs does not require quite the same technology, so that tends to have a slightly lower breakeven price. In fact the breakeven price for shale gas in the European countries tends to be a bit higher than that, because drilling costs tend to be rather higher, so I think it is simply a question of economics. What is the price going to be in the market for the different sources of gas? But $5 is around about the breakeven point for unconventional resources around the world. That is traditionally considered to be roughly where it lies today.

Now the interesting thing is that, of course, the gas price in the US at the moment is lower than that. The US gas industry, the unconventional gas industry, has largely kept going on the basis of the fact that it hedged its sales in advance, so it booked to sell its gas at a higher price in the future than the current gas price. Coupled with that is the fact that a lot of the smaller companies in the US have had a big injection of cash from major international gas companies, which have provided them with the money to keep going. But there is a general view that, on US gas prices today, a lot of the shale gas operations in the US are probably marginally economic.

Nick Grealy: I would disagree on that, and I would point out the history of shale gas has been one of continuous improvement in the economics and how much is produced, and so on. For example, recently Cabot Petroleum said that their cost of gas in the Marcellus Shale in Pennsylvania was about $1.30, and we also have interesting things in the United States where we have the development of shale oil-that is to access oil using unconventional techniques, including hydraulic fracturing and horizontal drilling. In that case then, we are going to have a situation in which they have to get rid of the gas so that they can access the oil, and that is the situation that I am told has led to the export potential of the Gulf of Mexico. Basically, they can give that gas away and, in fact, if they do not give that gas away they lose a large amount of $100-a-barrel oil.

Q183 Christopher Pincher: That is the United States. Do you anticipate the need for a subsidy here to encourage UK drilling?

Nick Grealy: No. With respect, from what I see of the activities of your Committee, you are used to a large amount of people coming here and saying, "We need a subsidy for CCS, we need a subsidy for wind, we need a subsidy for nuclear" and so on. The shale gas industry wants to give you money. It wants to participate. Going back to the Cuadrilla example of about 12 bcm, that would be a corporation tax take alone of somewhere in the area of £350 million per year, not to mention all the other benefits. This is where shale is unique, in that nobody is here with their hand out. That is why many of the enemies of shale such as Gazprom, the World Coal Council and the WWF are all united in perhaps being scared of losing their markets or their market share of fear.

Q184 Christopher Pincher: We can leverage the best practice in the United States, and the technology that is being used there, which you seem to suggest is driving down prices, but Mr Craig you mentioned that the drilling costs in Europe tend to be a little higher than they might be here. Why is that?

Jonathan Craig: Yes, that is partly because of the depth of the formations that we are drilling to, so the wells have to be somewhat deeper than they are in a lot of the US shale gas plays, so it is partly to do with that, and it is partly to do with things like the fact that labour costs, and so on, are slightly higher in Europe than they are, for example, in India or China. There tends to be that element to it. I would agree; I don’t really see a need for a subsidy, particularly for unconventional gas in this country. The gas is the same gas whether it is conventional or unconventional, as has been said several times this morning. It is just the reservoir that is different. We use exactly the same technologies as we use for conventional gas. I think it is often perceived that shale gas is a new thing. The first natural gas use in the world was in 1821 in Fredonia in Pennsylvania state in the US, and that came from a shale gas reservoir; it was shale gas that was used. This is not a new business, if you like; it has been around for close on 200 years and the technology that we use is exactly the same technology. The issue for the industry is simply that we have a different type of reservoir to deal with.

Q185 Christopher Pincher: Let’s not call it new, let’s call it an additional resource.

Jonathan Craig: It is additional, it is not a new resource.

Q186 Christopher Pincher: Which is now hopefully coming on stream. Do you see this additional resource could lead to a fall in the wholesale gas price?

Jonathan Craig: Not particularly. As I said, in the UK I can see it will make a contribution but not a big enough contribution that it is going to have a major effect on the price of gas in the UK.

Nick Grealy: This is where I disagree with Jonathan and Wood Mackenzie and Florence Gény and a number of other people. I am quite bullish about gas, but I am realistic. I would say that I have been looking at it for about three years and the number one mistake that I made was to underestimate the impact. It has gotten cheaper, it has been found in myriad locations worldwide and it looks extremely positive. By 2020 in the United States unconventional is going to become the dominant form of production, so therefore perhaps we need a new name.

Jonathan Craig: By 2020 unconventional gas will be 50% of US gas production, so it will be a 50-50 split.

Nick Grealy: I say to people, okay, it is conventional to dig gas out from 4,000 metres below the Barents Sea, freeze it, take it to Norway, then take it to the UK, but it is unconventional to dig it out of a field near Blackpool. It is a bit bizarre.

Q187 Chair: You have referred to the fact that the growth in unconventional production in the US has cut demand for LNG, which presumably therefore means there is more LNG available for the rest of us in Europe. Is that greater availability of LNG here likely to have any disincentive effect on investment in developing unconventional resources here?

Jonathan Craig: No, I would not imagine so. Clearly, there are all sorts of good reasons for wanting to develop indigenous sources of gas, energy security being one of them, employment being another one, development of technologies, and so on. So fundamentally at the end of the day price will determine where you buy your gas.

Q188 Chair: Do you think that the effect on LNG availability will be a long-term one?

Jonathan Craig: Yes, I would say certainly it will be. Again, it depends where you are in the world, so places like China and India are going to need huge quantities of gas, some of which again will come from their indigenous shale gas and conventional gas resources, but they will continue to need to bring in significant quantities of gas from outside, so I think it will be a long-term market, absolutely.

Nick Grealy: What one should understand is that the world LNG market was 243 billion cubic metres in 2009 and the UK used only 10.24 bcm of that, so less than 4%. The major dominant customers are Japan and Korea, which if you combine them consume 121 bcm. Certainly in Japan, as we know, there is no long-term demand growth and it is probably going to shrink. In India and China, I am sure all the LNG bulls have pushed that scenario, but China, for example, is 7.6 bcm. Many people say that it will go up to four times that by 2020, but that would still make their requirements smaller than the LNG import requirements of Spain, for example. One has to understand that China has multiple sources of supply- indigenous, imports from Turkmenistan, Myanmar, and so on. I think that they are not going to suck up all this gas and price us out of the market.

Q189 Christopher Pincher: I was going to ask one question on the international prospects for, particularly, shale gas. Outside the US do you anticipate any significant shale gas production in the next nine or 10 years?

Jonathan Craig: Outside of the US, absolutely. There are a number of places in Europe, for example. Poland is one of those, which is likely to be tested within the next couple of years. The first two wells have already been drilled. The big unknowns again come back to India and China, both of whom are very keen to develop their indigenous resources because of their demand for energy for the future. India has just put in place its first pilot-the second one has just been drilled, so they are currently in the process of testing-as has China. The results in both of those seem to have been, from a technical perspective, quite good. I would not be at all surprised to see both of those come on stream within the next 10 years, yes.

Nick Grealy: The US State Department has something called the World Shale Gas Initiative and there have been presidential level Memorandums of Understanding between China and India, for example, but there are a number of other countries-Chile, Argentina, Uruguay, Colombia, Morocco, Jordan, Turkey, Poland, and I think some other countries in Eastern Europe. Basically, shale is almost ubiquitous. Some people say that if you drill deep enough, you will eventually run into some. I think that is a very good point of Jonathan’s. The history of the hydrocarbon industry has been to go and drill in the Arctic and never mind polar bears or pollution or anything like that. Now, it can be very choosy and I think that certainly people are saying in the United States, where there is a moratorium in New York State, that they are going to shoot themselves in the foot, because they are going to come and say, "Guys, we have got so much gas from Pennsylvania and Alberta and Ohio and Texas and Louisiana that we don’t really need you guys any more". That really shows you how we have gone from fears of supply to a question of demand. We really have to soak up this gas in a number of ways, generation being an obvious one.

Q190 Christopher Pincher: If you can go anywhere and find shale gas, which is what you appear to be suggesting, do you assume that the places where it can be found are really going to go for it? Do you think there is an opportunity for this to be a game-changer in international gas supply?

Nick Grealy: Yes, certainly I would think so. When I first spoke to the US State Department, about 18 months ago, I thought that this would be something for commercial gain, but they are looking at it from a political viewpoint and saying that local energy is sustainable energy and it makes the world a less dangerous place if people are not competing for gas supply. There is plenty of economics in the US Energy Department and the Commerce Department, but the State Department has a completely political viewpoint, and I know that it has engaged with the FCO here.

Jonathan Craig: I think the only word of caution I would put in is that when we look around the world certainly there are vast resources of in-place shale gas, so you are quite right, many places where you go and drill you will eventually come across a shale that contains gas. The real issue is how much of that gas is producible technically and commercially? That is the difficult question for us when we come outside of the US. We have a reasonably good idea in the US because we have been building the industry up over the years. Outside of the US, it is still an open question. There are resources there, absolutely. A significant portion-maybe 20% to 30%-of those are technically producible. You then have an economic overlay on top of that says, "Okay, at what price?"

Q191 Chair: Theoretically, if there is such an abundance-I take your caveat about the price-could it impede a switch to low-carbon electricity generation? If people suddenly get lots and lots of gas, clearly that is significantly lower carbon than coal, but it is nowhere near where we need to be in 20 years’ time if we are going to be able to reduce carbon emissions to the level that people are now suggesting.

Nick Grealy: Gas is low carbon. It is not zero carbon. It is not the only alternative, but I think there are no ideal alternatives anywhere in energy. I think that one has to consider the cost and the availability, and so on. In the UK, for example, if we replaced coal generation and especially replaced it more with a localised generation, with a number of CHP-size plants spread around the country, some people have said that you could save up to 70% of the carbon emissions from a coal plant, and for nothing. Well, as I said, for a contribution from the gas industry to the Government. You could save money. I think it was Voltaire who said that we can’t make the perfect the enemy of the good. The perfect is an 80% reduction by 2050, whereas a number of people are saying, "Look, we can get to a 50% reduction by 2030, by which point perhaps there are going to be other advances in energy storage-solar, and what have you." But we run a risk of choosing winners today that may not be winners and will be made completely irrelevant. I am thinking here of CCS especially and possibly offshore wind.

Q192 Dr Whitehead: You have said that shale gas is relatively low carbon and essentially the same as non-shale gas in terms of its carbon content. That is about a little over half per kilowatt hour, the carbon emissions from efficient coal. In terms of the UK’s road map 2050, you would have to see shale gas as, yes, cheaper but still very much a transitional fuel. But a number of countries in the world such as Poland in Europe and South Africa, are almost wholly coal-dependent. Would you see shale gas, bearing in mind its potential abundance as more an area-specific longer term transitional solution, but not so much in the UK?

Jonathan Craig: I think the 50% figure is the figure that is usually quoted in terms of carbon emissions. Burning natural gases produces 50% less on average than burning coal. I read the other day a quote from Aubrey McClendon who is the CEO of a company called Chesapeake, which is one of the biggest players in the US. He said that natural gas, and he was talking about both conventional and unconventional natural gas, as being, "America’s greatest new opportunity because it will free us from dirty coal and dangerous foreign oil". That, if you like, sets the context from an energy security position and also from a carbon position. The US are very much looking at using natural gas, and shale gas as one of the components of natural gas, to reduce their dependence on coal for coal-fired power stations in order to cut their carbon emissions. It clearly is something that is going to make a contribution and it needs to make a contribution in the UK as well.

Q193 Ian Lavery: Looking at the future investment in shale gas, the shale gas prospects are already impacting on the confidence of energy investors. Is there an appetite for energy investors to invest in shale gas at this point in time?

Jonathan Craig: Are you talking specifically about the UK or generally?

Ian Lavery: The UK and then generally.

Jonathan Craig: Generally, certainly. It is, if you like, the hot topic in the oil and gas industry these days. Most companies have relatively recently set up teams that are exclusively devoted to looking for unconventional resources, shale gas being the prime one, in a number of different areas around the world. So yes, indeed, in the global industry I would say today there is considerable appetite, for looking for shale gas resources around the world. One of the reasons of that is synergies with existing operations, so if you already have a position in a country developing conventional oil and gas resources then it makes a lot of sense, if you like, from an economic and commercial perspective to also invest in shale gas in those regions. It very often tends to be on the back of existing operations around the world.

In terms of the UK, I think it is in its very early stages. I think it is mirroring very much what the US did, in that a small number of very small companies, niche companies, went into the market to test the potential and having established that particular plays looked as if they were going to be productive, the bigger companies came in and provided the funding to develop that. I think that is probably the way that the UK market will develop as well.

Nick Grealy: Certainly in the case of Poland, basically you have a number of small companies there and they are hoping that once they discover some gas all of a sudden Exxon Mobil or one of the big guys will come round calling. 21% of all M&A activity last year was in shale gas and it is a very hot topic in the United States. There have been mega-billion investments by China, Reliance Industries of India and the European ones, Total and Statoil, and so on.

Jonathan Craig: Again, you see China, India, their companies going out into the world because of their energy crisis, their need for energy security, and they are investing around the world in these plays.

Q194 Ian Lavery: Mr Craig, you corrected Mr Pincher, saying that this is not a new fuel-1821 I think it was.

Jonathan Craig: 1821, indeed.

Ian Lavery: It is amazing that it is not a new fuel but it has not come to the fore yet. People like ourselves are very buoyant about it, very upbeat about it. If this hype with regard to shale gas turns out to be wrong in 10 years’ time, is there a distinct possibility that the UK could have under-invested in conventional gas resources?

Jonathan Craig: I do not personally see that at this point in time the unconventional industry is taking away investment from the conventional industry. The company that I work for, for example, is putting about 7% of its total exploration budget into unconventional resources around the world. That gives you a view of the amount of investment that we are putting into the two sides. Again, we are trying to build up an industry and test the market. We need to understand whether some of these shale gas plays will produce or not. I think we need to take a very cautious approach and at this stage it is very much about testing the opportunity, testing the deliverability of some of these plays before we make a decision about putting significant amounts of money into investment and developing things. We are only going to develop them, if you like, if they work.

Nick Grealy: I think at this point, in Europe especially, we have this major issue that everything we are talking about here is academic. We need to have somebody in Europe to say, "Yes, we have made a game change in discovery,", and I feel that over the next year we are going to have game-changing discoveries in at least two areas of Europe. By game-changing I would say places where the combination would be at least twice the size of the resource of the North Sea. That changes a lot. I hope I am right.

Q195 Ian Lavery: That is very interesting. Do you see that in the very near future there will be a change from coal to gas in the UK in the electricity-generating sector, or do you believe that gas will just be subsumed by the continued increase in the demand for electricity?

Nick Grealy: I think people do not understand really that in the developed countries, in the OECD, all energy use-gas, electricity and oil-is moderating. A lot of people are saying, "Oh, that was because of the recession", but the peak for electricity in the UK was, I believe, in 2005. I believe that peak demand for gas was in 2006 and for oil even slightly earlier than that. Basically we are seeing the impact of energy efficiency in many small ways. Anybody who buys a refrigerator, even a bigger refrigerator, will find that it is 40% more efficient than the one it replaced. Over the course of a 20-year lifetime of a major appliance or a central heating boiler we are going to see a decline. National Grid say that themselves; I think they are looking at a drop in UK gas demand by something approaching 1% a year over the next 20 years, which could be taken into electricity.

Ian Lavery: Very briefly, Mr Yeo, it would be very interesting to hear, but I know we are constrained by time, why it has taken nearly 200 years for shale gas to come to the fore. It is an issue for another time.

Q196 Chair: Would you like to say something about that? The same question occurred to me. If this was such a good idea and was first discovered in 1821, what have we done in the meantime?

Jonathan Craig: Well, that comes down very largely to, first of all, gas prices, to some degree, but also to technological advances, clearly, and the biggest technological advance, as has already been pointed out, is the ability to drill horizontal wells. That is something that has only been really possible in the last 20 years or so. The ability to steer drills really accurately within relatively thin shale horizons has been one of the big game changes in terms of technology. If you like, that is why it has taken us so long; the change of technology has allowed us to do that.

Q197 Chair: Do these technology changes also require a change in the legislative framework? Do we need to revise how we regulate oil and gas exploration and production in the UK to reflect what may be some new challenges?

Jonathan Craig: The technology is new but it is not distinctive to unconventional resources. We use horizontal wells in conventional fields, so, if you like, the technology is the technology, irrespective of whether it is conventional or unconventional, whether it is tight gas or shale gas or conventional oil fields. We already have a history in all of those areas of using the same technology, both the technology of horizontal wells and the technology of fracing wells. So I would say, no, not particularly.

Nick Grealy: I would say that the regulation of right now appears to be working. The only other thing that I am slightly concerned about is the treatment of water when it comes back up, the flow-back, but I think you have to understand that in Pennsylvania water is 18 cents a gallon. That gives everybody an 18 cent-a-gallon incentive to use less water. So less water in, less water out. But the Environment Agency in this country is already very well placed to do it. We just have to make sure that if we are in a happy position of having a few hundred shale wells, the amount of regulators is increased.

Q198 Chair: The US EPA is investigating the impact of fracturing on drinking water. I slightly subscribe to the conventional view that they are a bit more cavalier about environment issues over there than we are here. Why would we not want to wait and see what that report produces?

Jonathan Craig: I think again you have to understand here that this is not new technology, so the fracing of wells has been going on traditionally since the 1950s. Interestingly, the first well that was fraced ever in the world was also in Fredonia in the 1820s in the shale gas reservoir, but again it is not new technology. One of the things that happens here is that, as an industry we have been looking very hard to try and understand-it was a question that came up earlier-how confident we are about where the fracs go when we frac the reservoirs.

A body of work has been published very recently, last year, that looked at all of the frac jobs that have been run in two of the main shale gas plays in the US, in the Marcellus and the Barnett, which are two of the big shale gas plays. They use micro-seismicity, which has been talked about earlier today, to measure where the fractures go within the rock-how far up and down they extend from the shale gas horizon that you are looking at. What that work has demonstrated is that there is no connection between the fracs that you make in the shale gas reservoir and the shallow aquifer. There is not a direct connection between the two, there are several thousand feet of rock sitting between the two.

That does not negate the issues that we have been talking about earlier this morning, for example, of having bad cement jobs on your wells that allows them to connect the shale gas reservoir with the near service. But that is exactly the same in conventional hydrocarbon exploration. It is exactly the same, for example, in carbon sequestration, in geothermal energy, so the issue, if you like, is not shale gas being in some way different. It is the same technology and the same issues apply both in conventional and unconventional reservoirs. The cases that are demonstrated of some contamination of the near-surface aquifers is either due to the fact that there has not been a proper cement job across a big fracture in the rock, which has allowed a conduit to go to the surface, or due to the fact that the cement job behind the metal casing that we put inside the well has not been properly secured and the gas has leaked up the inside of the well. But the fracs themselves are not the cause of contamination.

Q199 Dr Whitehead: But there is a difference between conventional and unconventional, obviously, inasmuch as you do require large amounts of reasonably pure water for unconventional?

Jonathan Craig: Absolutely.

Q200 Dr Whitehead: Disregarding the very small amount of chemicals that go in. Do you have an estimate for the amount of water, and this is presumably reasonably purified water, that would be required to produce a cubic metre of unconventional gas?

Jonathan Craig: Well, I can tell you that for an average frac job in a US well today, they use about 100,000 barrels of water. Now a barrel-a difficult conventional measure of volume that we use in the industry-is about 35 imperial gallons. You are looking at around 3.5 million gallons of water to do a conventional frac job. Now you put that water at high pressure into the formation in order to break the formation to create the cracks and, as was mentioned earlier on, you get back about 20% or 30% of that water. The rest of the water stays within the formation.

Q201 Dr Whitehead: Bearing in mind in various parts of the UK there is a substantial water shortage and difficulty of sourcing water, to what extent, if you had a substantial development of unconventional gas across UK land, would that cause any sort of competition for water resources?

Jonathan Craig: Sorry, I will just finish this bit and then come back to you. I mentioned previously that there is an issue about how much you can economically produce from some of these shale gas reservoirs. Globally, water is a big issue, so if we are looking at some of the shale gas plays that exist for example in India, in Rajasthan, there you have an area which is already desperately short of water for agriculture. It is going to be a huge issue to develop shale gas reservoirs in places like that, because you need these large supplies of water. One of the things that the industry is trying to do is to reduce the volume of water that is required to frac some of these wells.

We run what are called production logs-we run a tool through the well that looks at where the gas production is coming from, from which fractures that we have made in the rock. Typically today, the industry works on the basis that something like 30%, only 30%, of the fractures that we make are contributing gas to the well. We need to either use less fluid, so that we only frac the 30% that we need to frac, or get much more efficient about fracing, so that we create more fractures that are contributing. A lot of energy is going in the industry these days into reducing the amount of fluid that is required. Clearly, if you have areas where there is already a shortage of water for domestic use, for agriculture, then that is a big issue, absolutely. It is something that needs to be taken into consideration.

Q202 Dr Whitehead: Sticking with the UK, do you consider that at any stage being an issue for the UK or even parts of the UK in terms of its existing and likely future water resources for population and for agriculture, which may be diverted for gas production?

Nick Grealy: I pick up on a point Mark Miller made about comparative use. If five Olympic swimming pools sounds alarming and 3 million gallons sounds alarming, but it is literally a drop in the ocean. Four million gallons is, and the Chairman would appreciate this, the irrigation for a golf course for 28 days. That would last underground for maybe 10 years. Preece Hall, the well that you will see tomorrow, the first one, was built in a corn field. Now technically if you are worried about water displacement, although shortage of water is obviously not an issue as you will probably see tomorrow in Lancashire, irrigation for a corn field of five acres in one growing season is the same amount of water that would be used in a shale well.

Q203 Dr Whitehead: Is that over a year?

Nick Grealy: Yes. So if you really want to save water, dig up the cornfields and do a shale well.

Jonathan Craig: The only difference, I guess, is the issue of declining rates in wells, as was talked about earlier on. Obviously you need to drill a lot of wells in a shale gas field in order to keep the production levels up, so a typical shale gas field in the US might have 850 wells in it, something of that order. This is different from conventional exploration in that we are not drilling one well here, another well over here; we are drilling a lot of wells.

Q204 Chair: 850 wells for one field?

Jonathan Craig: Is not an untypical number.

Q205 Dr Whitehead: Does each of those take that amount of corn field type of water?

Jonathan Craig: You have to frac each well.

Q206 Dr Whitehead: That is 850 corn fields you use?

Chair: Or golf courses.

Jonathan Craig: It is not per year, you only frac the well at the start to get the production and then you move on to the next well.

Q207 Dr Whitehead: Maybe you need to refrac it?

Jonathan Craig: You might need to refrac it, but it is basically 100,000 barrels of oil per well.

Nick Grealy: Certainly people in the States have said that it is less than one half of 1% of water resources and Talisman in Quebec said that even if they had full production, they would only use one half of 1% of the total, compared to 2% for the car wash industry.

Chair: Okay. I am sorry to say we are running out of time. We might perhaps write to you with two or three more questions that we have not been able to cover this morning, but I think we are going to lose our quorum presently. Thank you very much indeed. Very interesting evidence, and we are very grateful to you for coming in.