I draw attention to my entry in the Register, especially my interests in energy industry.
In doing so I emphasise, as I have done before, that my views on climate change, on the need for Britain to move more swiftly to a low carbon economy and to cut its dependence on fossil fuels, were formed two decades ago when I had ministerial responsibility for this area of policy.
I’ve not changed these views at any time since then. I’ve repeated them publicly and privately on many occasions throughout the last 20 years. My views have never been influenced at any time or in any way by my financial interests.
All those interests were acquired after I left the Shadow Cabinet in 2005. That was 12 years after I accepted the overwhelming scientific consensus on this subject and began campaigning for a more urgent response to the challenge of climate change.
Various bloggers, columnists and others, including one or two Honourable Friends, who insinuate otherwise, and who ignore this scientific consensus, invariably overlook my strong and consistent support for nuclear power, a low carbon technology which should be part of Britain’s energy mix.
I’m grateful for this opportunity to debate the amendment in the name of honourable members from all parties and myself.
The amendment is based on a unanimous recommendation made in July last year in the Report of the Energy and Climate Change Committee on the draft Energy Bill.
The Govt accepted many of the Committee’s recommendations, and by doing so materially improved the Bill.
I congratulate my RHF the Secretary of State and his team on their response to our Report and on the outcome of their negotiations with the Treasury on a range of issues, including the LCF.
However for a variety of reasons the need for the amendment we are debating is even greater now than it was when my Committee’s Report was published.
Firstly, despite some positive signs about the Govt’s support for low carbon electricity generation, the publication on the day of the Autumn Statement of the Gas Strategy confused many investors.
The possibility that the Govt might sanction 37 GW of new gas fired generation capacity rests uneasily with its acceptance two years ago of the 4th Carbon Budget which covers the period 2023 to 2027. It suggests that the purpose of next year’s review of the 4th Carbon Budget is to water it down and weaken incentives for low carbon investment.
The understandably envious glances cast across the Atlantic by the Treasury at the transformation of the US gas market in the wake of the exploitation of shale gas have not passed unnoticed.
Not surprisingly there are now doubts in the minds of many prospective investors about the depth of the Govt’s commitment to decarbonising electricity generation.
On the issue of shale gas incidentally the ECC Committee was one of the first bodies to urge the Government, more than two years ago, to approve more exploration and testing to establish the scale of Britain’s shale gas reserves.
If our dependence on imported gas can be cut and if consumers can be protected against the fluctuations in international gas prices which have been the main cause of the rise in domestic energy prices in the last few years then that is wholly to be welcomed.
However my Committee also warned in our more recent Report on Shale Gas that it would be rash to base energy policy on the assumption that Britain will soon be a major shale gas producer.
The opposition to exploring for shale gas in Sussex which is already emerging is a foretaste of the battle for public opinion which must be won before domestic production of shale gas on even a modest scale can occur.
The case for a diversified energy mix is therefore as strong as ever.
Secondly, although we hear regular warnings about a looming capacity crisis in electricity generation, and the consequent risk of power cuts, there is a curious complacency about the Government’s attitude.
Investment in new generating capacity is now at a low level.
The nuclear talks between Government and EDF remain unfinished. Even if, as I now expect, they are brought to a successful though belated conclusion it will be 2020 at the earliest before a single KW of electricity is generated by a new nuclear power station in Britain.
New investment in coal is unlikely to occur until an economically viable form of Carbon Capture and Storage is available. Despite the huge potential market for CCS there is no sign anywhere in the world of this happening.
I am an enormous fan of CCS. It is the single technology the world most urgently needs to address Climate Change but we may have to wait another decade or even longer for a breakthrough on this front.
Meanwhile coal can currently be imported cheaply from America so our remaining coal fired power stations are running flat out.
Gas generation, the great white hope of many people, is currently so unprofitable that, far from large scale new investment taking place, some plant is currently mothballed.
Critically, potential investors in gas generation are holding back until the details of the Government’s proposed capacity mechanism are known. I urge my Right Honourable Friend to publish these details as soon as possible.
With a decision on nuclear still awaited and fossil fuel generating investment at a standstill it might be thought that money would pour into low carbon renewables. Even here the picture is unclear. For example, according to new figures from Bloomberg, the flow of funds is actually slowing down.
Doubts about whether a future Govt will stay committed to supporting low carbon technologies after 2020, fears that instead it will bet the farm on another dash for gas, and a lack of clarity about the level of strike prices to be proposed for the new Contracts for Difference regime have all unsettled investors.
The only certain consequence of this is that investment will be slower and the risk of a capacity crisis greater.
The element of perceived political risk will lead investors to seek higher returns for investment in the UK energy market.
Higher returns to investors mean higher prices for consumers.
My amendment directly addresses these issues.
By itself it will not immediately alter the low carbon pathway on which the Govt has already embarked, most notably by its acceptance of the 4th Carbon Budget.
But the prospect of the 4th Carbon Budget being watered down in next year’s review is simply another unwelcome uncertainty.
The amendment removes that uncertainty. It requires the Secretary of State to set, no later than 1April 2014, a decarbonisation target for 2030 for electricity generation.
As currently drafted the Bill merely gives the Secretary of State a power to set such a target without compelling him to do so. It also prevents him from exercising this power before 2016.
Suggestions that this amendment would force him to set the target at 50 grams per Kwh in 2030 are mistaken. The amendment requires him to set the target in accordance with advice from the Committee on Climate Change. If he does not follow the advice of the Committee on Climate Change he would have to explain why.
The CCC would not have a free hand in advising the Government. It would still have to take account of all the matters already referred to in the Bill in Clause 2 section 2. These include READ OUT (a) to (e).
In truth therefore this amendment is not very revolutionary. It seeks to bring forward by a couple of years something which the Government is contemplating doing anyway.
If it is indeed true, as the Secretary of State asserted yesterday, that we are heading for substantial decarbonisation of electricity anyway, what objection to this amendment can there possibly be?
There is now very widespread support for it. Only two weeks ago the CCC published a report recommending that a target for reducing carbon emissions from electricity generation by 2030 to 50 grams per Kwh should be set in legislation, with flexibility to adjust this in the light of new information as the amendment provides.
A wide range of businesses and trade bodies have backed it. The Aldersgate Group for example, whose members include Microsoft, Marks & Spencer, Aviva, Sky, PepsiCo, British American Tobacco and others, are strong supporters.
Many companies with interests in the supply chain and with potential to create jobs in Britain want to see it passed.
A wide range of voluntary bodies are campaigning for it, including the Women’s Institutes,
Even among HMs there are signs of enthusiasm. At the Lib Dem Party Conference last September the Chief Secretary to the Treasury proposed a motion to establish, and I quote, “a target range of 50-100g of CO2 per Kwh for the decarbonisation of power sector in addition to existing carbon reductions.”
If every Lib Dem MP who supported the Chief Secretary that day joins me in the Aye Lobby at 4 o’clock the amendment will be carried. I am sure that all my Honourable Friends on the Lib Dem benches are keen to take this opportunity to strengthen their well known reputation for consistency.
Even the Government itself seeks powers in the Bill as it stands to introduce such a target. But for some reason they don’t want to do so until 2016 at the earliest.
The problem with this St Augustinian coyness, this promise of possible future chastity in the matter of greenhouse gas emissions but please God, not just yet, is that by 2016 many investment decisions will have been made.
If these lock Britain into a high greenhouse gas emission future they will either prevent us from meeting our climate change commitments or else will lead to the construction of fossil fuelled generating capacity which has to be subsequently scrapped.
2016 is also after the next General Election. Delaying a decision until then creates another needless but harmful element of doubt about the Government’s true intentions.
I therefore urge HMs on all sides to support this amendment. Doing so will remove an element of uncertainty whose presence hampers investment, increases the risk of a capacity crisis and raises electricity prices unnecessarily.
This amendment will not impose on the Government today any commitments it does not already claim to embrace.
Furthermore it will not remove the need for even greater priority to be given to demand side measures and to energy efficiency, issues which I wholly support.
By itself it will not raise electricity prices in the next seven years by a single penny because the total sums spent on subsidising low carbon electricity in the period up to 2020 has already been capped by the LCF.
By contrast the Treasury’s own cherished floor price for carbon does raise prices and add to consumer and business bills making British industry less competitive relative to the rest of the EU but does so in a way which does not cut emissions by a single kg.
Without the amendment this Bill, whose early passage through Parliament is desperately needed for economic and security reasons as much as for environmental ones, will be needlessly weakened.
I commend the amendment to the House.
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To the great surprise of the established nuclear industry, thorium and molten salt reactors could be on the verge of making a comeback. Tim Probert cuts through the growing hype to explore whether good ideas can ever become good business. This article was first published in the May 2013 edition of Energy World.
Thorium has enjoyed a remarkably high profile of late given its chequered history. Despite the fact most development programmes by commercial entities (though not research institutes) were canned in the 1970s and 1980s, an increasing amount of hyperbolic articles are being published in serious and not-so-serious outlets extolling the virtues of thorium.
In reading these articles, the reader may be led to believe thorium is something of an energy panacea. Thorium is a ‘green’ source of nuclear energy, they say, abundant, cheap, safe, without the drawbacks of core meltdowns and copious amounts of radioactive waste.
The truth, of course, is far more complex. While thorium does offer highly attractive potential advantages as a source of atomic power, there are also several considerable barriers to the development of thorium-based nuclear reactors.
Uranium’s head start
Some view thorium as the Wankel rotary versus four-stroke piston engine or Betamax versus VHS battles of the energy industry: despite its significant technical advantages over its rivals, the ‘lesser’ product won. There is a great deal of truth in this, and a short history lesson is required to explain why.
It is essential to point out Thorium-232 (T232), like Uranium-238 (U238), is a fertile isotope, not a fissile isotope. Both these isotopes have to be first irradiated in a reactor to produce their derivative respective fissile isotopes U233 and Plutonium-239 (Pu239) resulting from neutron capture decay chains, neither of which exist in nature.
To begin its nuclear weapons programmes in the 1940s, the United States decided to produce both enriched uranium in U235, the only naturally occurring fissile isotope in nature, and Pu239, produced from neutron irradiation of fertile U238 in a reactor.
The United States recognised but declined the third option to produce U233 from irradiation of Th232 in U235-enriched reactors for two main reasons. Firstly, it was known that U233 was a hard gamma emitter which would be both difficult to reprocess and to machine and handle from a personnel protection standpoint.
Secondly, and more importantly, it was demonstrated that the 0.7% level of fissile U235 in natural uranium was sufficient to be the basis for a nuclear reactor system, with the 99.3% U238 content in natural uranium hence being partially converted to produce around 0.8% of the new fissile element plutonium – unknown in nature – which could then be chemically separated through reprocessing.
Had the United States gone down the thorium route, there would have been a significant weapons programme delay in producing sufficient quantities of the required enriched uranium driver. Unlike uranium, thorium cannot be driven by a natural uranium reactor (since neutrons are absorbed by the U 238), only by an enriched uranium reactor.
Uranium, therefore, got a head start for civil nuclear power from which thorium has never recovered. Thorium research became a side show as a means to an end to produce U-233, the only other fissionable feed isotope.
The light water nuclear reactors (LWR) deployed in nuclear power stations developed simply as scaled-up versions of nuclear submarine reactors, again driven by military impetus. As a result, virtually the entire nuclear energy industry has been optimised around the uranium and, to a lesser extent, plutonium fuel cycles.
While thorium is three to four times more abundant than natural uranium, there is no shortage of the latter. At current usage of 68,000 tonnes/year, global proven resources of 5.3 million tonnes mean there is enough natural uranium for at least 80 years, notwithstanding spent fuel.
While there are many good arguments in favour of thorium, energy security is one of the weaker ones and governments may only turn to thorium if uranium economics or its geopolitical abundance becomes problematic, says P.K. Doshi, Director of International Business Development at nuclear consultancy Excel in Maryland, USA.
Doshi, who has 45 years of nuclear industry experience and also thorium fuel manager when Westinghouse Electric operated the world’s first pressurized water reactor with thorium cores (at Shippingport, near Pittsburgh) in the 1970s, is highly sceptical about thorium’s chances.
“The infrastructure is in place to support LWRs on the uranium cycle,” says the Indian. “It’s expensive to compete with an established infrastructure, particularly when the timeframe to develop an alternate is so long. In this sense, thorium is kept down by ‘the system’. But I don’t see it as a conspiracy, rather as an economic fact of life.”
It is the job of the Weinberg Foundation to challenge ‘the system’. Founded in 2011 to promote thorium energy, the Foundation is named after thorium advocate Alvin Weinberg, research director of Oak Ridge National Laboratory (ORNL), which produced plutonium for the Manhattan Project.
Weinberg Foundation’s headquarters are at Somerset House on London’s Strand. In keeping with thorium’s image as a ‘green’ nuclear energy source, its patron is Baroness Bryony Worthington, founder of emissions trading lobby group Sandbag and a key architect of the 2008 Climate Change Act.
The Foundation’s CEO Laurence O’Hagan is under no illusions about the scale of the challenge of taking on a uranium fuel cycle industry worth an estimated £200bn a year. “The argument is it will take too long,” he says. “That the established nuclear industry doesn’t want to change. But if we don’t start now, we’ll never get there. The potential advantages are so significant that we believe they are worth pursuing.”
O’Hagan sees considerable promise in molten salt reactors (MSR). Indeed, one of Alvin Weinberg’s major projects at Oak Ridge was the Molten Salt Reactor Experiment of 1965-1969, a 7.4 MW thorium-based demonstration reactor using U-233 as the main fissile driver.
Unlike conventional nuclear reactors which use solid fuel, usually rods or pellets, MSRs use a mixture of fluoride salts in a molten state. The salt mixture includes fissile material, i.e. fissile isotopes of uranium and/or plutonium, together with fertile material, such as T232 or U238.
The front-running thorium-based MSR is the liquid fluoride thorium reactor (LFSR). In this design, the molten salt also serves as the primary coolant, carrying heat away from the reactor, and delivering it to a secondary cooling circuit and ultimately to the steam turbines that generate electricity.
One of the main advantages is the reactor and its cooling circuits operate at near atmospheric pressure, reducing the chance of any explosion. As fuel in a LFTR is already in liquid form, it cannot melt down, as can solid fuel rods in a LWR.
Furthermore, the LFTR’s large negative temperature coefficient means that regulation of the reactor’s temperature is passive, so there is no need for control rods. The molten salt expands as a result of the heat generated by fission, which slows the rate of fission.
The reduction in fission heat cools the salt, which in turn leads to an increase in the rate of fission. In other words, as the reactor temperature rises, the reactivity decreases. The reactor thus automatically reduces its activity if it overheats.
In the event of a reactor overheating, the fuel and salt drains into a holding tank, where the fuel spreads out enough for the reactions to stop. The salt then cools and solidifies, encapsulating the radioactive materials.
Another major advantage over uranium is fuel efficiency. Due to the degrading effect of neutron bombardment on solid fuel rod metal cladding in LWRs, between only 2-4% of the energy contained within can be used before they have to be removed. An LFTR reactor, however, would continuously recirculate nuclear fuel, thus greatly improving efficiency and radically diminishing the produced volume of nuclear waste and proliferation risk.
Corrosion: The killer blow?
On paper at least, LFTRs are highly attractive and it is easy to see why they have a growing number of proponents. In practice, however, there are major drawbacks yet to be overcome.
While Weinberg’s work at Oak Ridge’s relatively short-lived Molten Salt Reactor Experiment successfully demonstrated the potential for thorium molten salt reactors, a number of serious problems were highlighted, particularly pertinent for power generation reactors with an operational lifetime of several decades.
Researchers at Oak Ridge found that the Hastelloy-N metal used for the containing molten salts cracked and corroded under intense radiation. The development of corrosion-resistant materials capable of surviving exposure to neutron bombardment and fluoride salts at high temperatures for decades is essential if LFTRs are ever to be a commercial proposition.
“Corrosion was one of the problems at Oak Ridge but since then material science has considerably progressed,” says O’Hagan. “We are now two generations beyond Hastelloy.
“MIT is researching using salt as a coolant and they are about to patent a corrosion-resistant material. We are not claiming all the engineering problems have been solved and there has to be work done to resolve them, but all the signs are pointing in the right direction.”
The main stumbling block, though, is economics. “LFTRs are theoretically beautiful but making it work in practice is a different matter,” says Johann Lindner, who heads up Excel’s European division. “In the end, they will not get off the ground because building a full-size unit will prove to be economically unviable,” he says.
“Building an LFTR requires more than just a reactor design. It requires a new fuel cycle with fuel fabrication facilities, remote handling equipment, and new back-end spent fuel management methods and technologies.
“It’s a non-starter; Darwinian selection has chosen LWRs. There may be some prototypes built but you’ll never convince utilities to buy them for commercial power generation. The first 50-100 will be too expensive compared to LWRs.”
Thorium fuel has so far been used in about 30 operational reactors. Most of these were located in the USA, Germany, Netherlands and India. A single example operated in the UK, from 1965 to 1976: the Dragon Reactor at Winfrith, a helium-cooled test reactor.
Aside from Oak Ridge, perhaps the most significant use of thorium was the German THTR-300 (Thorium High Temperature Reactor), a 300 MW pebble bed modular reactor, which used a mixture of thorium and highly enriched uranium, between 1983 and 1989. The plant, constructed in the North Rhine Westphalia town of Hamm-Uentrop by Hochtemperatur-Kernkraftwerk, was not a success.
On 4 May 1986, within just six months of generating grid-connected power and days after the Chernobyl accident, the THTR-300, which had no containment building, was found to have released radioactive dust into the environment due to an erroneously open valve. It was later found that pebble friction had generated so much dust that several pebbles became jammed, and the attempts to unclog the blockage merely aggravated the release.
Thorium in the UK
Keith Perron, a former nuclear submarine reactor specialist at Rolls-Royce, believes the only viable usage of thorium in the UK is its use in existing LWRs rectors or to incinerate plutonium as a final disposal route as an alternative to the type of MOX reprocessing plants as developed at Sellafield.
“Uranium MOX fuel designs, whereby plutonium is mixed with uranium oxide, do not remove plutonium, they just recycle it,” he says. “Such fuel actually produces more plutonium than it started with. Judged as a means to incinerate separated plutonium and to rid it from the world, MOX is a dismal failure.”
The traditional problem with uranium MOX is chemical changes within the fuel rod result in a positive feedback coefficient, i.e. radioactivity increases over time. By mixing thorium with plutonium oxide, so-called ‘THROX’ would not react that way, it stays negative, which means in theory you could continuously recycle and reprocess the fuel rods until the actinides have been burnt up, says Perron.
Again, however, the medium-term prospect for thorium usage in conventional reactors is extremely poor, although a company called Thor Energy, a division of Scatec, has made an experimental thorium fuel rod to be loaded into a test reactor in Norway this year.
Current development of molten salt reactors
The only operational reactors using thorium currently are in India, which possesses abundant thorium reserves but little uranium. These are conventional, solid fuel LWR reactors.
It is expected China will be the first nation to develop a new MSR. The China Academy of Sciences in January 2011 launched a $350 million R&D programme on LFTR, known locally as the thorium-breeding molten-salt reactor (TMSR).
The 2 MW test unit, developed by the Shanghai Institute of Nuclear Applied Physics, is currently expected to be operational by 2020. However, the programme has been delayed by two years as it is taking longer than expected to train the 700 scientists required, says O’Hagan.
India is also slowly developing a thorium programme at its Bhabha Atomic Research Centre in Mumbai, although primarily for usage in an advanced heavy water reactor rather than MSRs. Meanwhile, Russia is believed to be developing thorium as part of a generic nuclear research programme.
Reborn in the USA?
The USA does not have a concerted thorium programme at present, although there are interesting developments in Cambridge, Massachusetts, home to Transatomic Power. An offshoot of MIT, Transatomic Power is developing the WAMSR (Waste-Annihilating Molten Salt Reactor) designed to run not on thorium, but on the United States’ considerable stockpile of radioactive waste.
The company’s ultimate aim is to produce a 500 MW unit. It estimates that it can build such a plant for $1.7 billion, roughly half the cost per megawatt of current LWRs.
Transatomic Power, backed by the founder of E Ink, Russ Wilcox, appears to be serious. It has recruited highly experienced nuclear engineers from Westinghouse and MIT scientists and it recently scooped the top award at the Department of Energy’s 2013 Energy Innovation Summit.
So far, it has raised a fraction of the $200 million needed to build a small prototype. Aside from materials science, the lack of funding – from both the private and public sectors – is likely to continue to thwart ambition for thorium.
Steve Kidd, Deputy Director General of the World Nuclear Association, cannot foresee a bright future for thorium. “It’s only when the likes of Westinghouse, GE Hitachi and Areva come into the frame will thorium get going,” he says.
“Most of the current development is by physicists and other scientists at government research centres and they are not too fussed about commercial development. It may be so that the thorium cycle is superior to uranium and using thorium in reactors is perfectly technically feasible but nobody is going to commercialise it because in the 1950s we decided to go down the uranium route.”
The Weinberg Foundation refuses to be downhearted in the face of cynics in the conventional nuclear industry. “In my opinion, a commercial MSR is quite likely within 20 years,” says researcher David Martin. “There are many reasons for this, firstly the economics of the current nuclear industry. They don’t have a product they can build on time and to budget.
“An MSR is basically a chemical set with some surrounding concrete, and it operates at atmospheric pressure so there’s no need for multiple redundant safety systems and high-pressure vessels. In theory, the key components of MSRs could be constructed in a modular fashion, rather than built in situ on a bespoke basis.
“Furthermore, fuel fabrication is more chemistry than physics. It’s far easier to manufacture the few cubic metres of fluoride or chloride salts than fabricate fuel rods. Given the safety of operation I just can’t see how it could be more expensive than light water reactors.”
Martin thinks it is high time the Government put its hand in its pocket to fund more research. “There should be a vigorous programme in order to recapture some of the optimism that characterised the first wave of nuclear reactors. In the UK, nuclear R&D is a mess. The fragmentation of the industry was an act of vandalism which has left us without a nuclear research base.”
Had there been 60 years of development of molten salt reactors, the nuclear industry may have been in a very different position. Given the prevalence of the uranium fuel cycle, however, only an optimist could believe that the world will give thorium a second chance.
After an 18-month hiatus, the Department of Energy and Climate Change has given the green light to resume shale gas exploratory ‘fracking’. Tim Probert explores the next steps towards the UK’s ambition to create a shale gas revolution. This article was first published in the February 2013 issue of Materials World.
There has been no end of hyperbole about shale gas in the UK over the past two years. But for all the wildly varying talk about the potential riches or environmental damage from shale gas, hydraulic fracturing (fracking) has been on ice since Lichfield-based Cuadrilla Resources was found to have caused two relatively large earth tremors in Lancashire of 1.5 and 2.3 magnitude in April and May 2011 respectively.
After an 18-month hiatus, the Department of Energy and Climate Change (DECC) finally gave the green light to resume exploratory fracking last December. Given the large gas-in-place resource estimates in UK shale basins and the potential for Her Majesty’s Treasury to accrue many billions of pounds in tax revenue the decision was never really in doubt.
DECC has laid down some tough new regulations for exploration, primarily aimed at mitigating induced seismicity. Analysis carried out by Cuadrilla, and confirmed by DECC, concluded the cause of the tremors was the movement of the frack fluid into and along a fault which was already under stress. The additional pressure of the fluid caused the fault to move, resulting in the tremors.
DECC says many other faults in the Lancashire area have similarly unrelieved stresses, and could in a similar scenario likewise resulting in tremors. Shale gas drillers must, therefore, take a more cautious approach to the duration and volumes of fluid used. Fracking will also be subject to a “traffic-light” regime, so that operations can be quickly paused and data reviewed if an unusual level of seismic activity is observed.
DECC took a dim view of Cuadrilla’s response to the tremors, saying the company “demonstrated some weaknesses in its management of environmental risks”. In other words, the drilling team did not tell the Cuadrilla board about the incidents quite as swiftly as it should have done.
So DECC has imposed a strict regime for Cuadrilla’s exploration programme in Lancashire, setting the remedial action level for the traffic light system will be set at magnitude 0.5. This is seen as a conservative level as it far below a perceptible surface event, although larger than the expected level generated by fracking.
In order to simplify and streamline the regulatory process and to provide single point of contact for investors, DECC will create the Office for Unconventional Gas and Oil, working with the Department of the Environment and Rural Affairs (Defra) and other government departments.
Regulation of activities associated with shale gas exploration, such as groundwater protection and well integrity, will remain the relevant responsibilities of the Environment Agency and the HSE. Meanwhile, HM Treasury will announce a targeted tax regime for the shale gas industry at Budget 2013 on 20 March.
Cuadrilla activities to date
So far Cuadrilla has drilled three shale gas wells in Lancashire and has completed a 3D seismic survey of over 100 square kilometres of its 1,200 square kilometres license area known as PEDL165 in West Lancashire. As is well known, Cuadrilla has announced an extremely large gas-in-place resource estimate for PEDL165: 200 trillion cubic feet, equal to more than 60 years of supply.
Cuadrilla is understandably keen to establish gas flowback rates and recoverability factors as soon as possible. The company says it expects to restart fracking in the first half of 2013 upon receiving planning approval from Lancashire County Council.
If all goes to plan then Cuadrilla will seek to frack at least three wells in the initial exploratory stage. While the Preese Hall site in Wheeton near Blackpool has been plugged to avoid a repeat of the unfortunate earth tremors incidents in 2011, Cuadrilla will conduct intensive fracking at the Anna’s Road site in Westby near Lytham St. Annes, the Grange Hill site in Singleton near Poulton-le-Fylde and the Becconsall site in Banks near Southport.
The Anna’s Road site is seen as a crucial well for Cuadrilla. Starting from a vertical well, at over a mile beneath the surface, an extension will gradually ‘arc’ into a horizontal path. The well will be 8.5 inches in diameter and the 12-stage horizontal frack will extend 1,400 metres from the site to the west.
From this and Cuadrilla’s other exploratory wells, the company intends to produce gas, to be burned in an on-site generator to produce electricity, for one year to determine how much gas can be produced and how fast gas production declines. At this point, Cuadrilla would approach DECC, if flow rates are sufficiently promising, notifying its intention to proceed to production stage.
As a pre-cursor to full-blown production, Cuadrilla is expected to drill approximately 20 wells from single-site ‘pads’, from which operators can move a drilling rig in order to drill several wells from the same site without the disruption of dismantling and re-erecting the rig each time. These wells, roughly two miles vertically and three miles horizontally, would be drilled over a larger area across Cuadrilla’s PEDL165 license area.
Again, these wells would be operated for a year to ascertain flow rate and recoverability. At this stage, end-2014 or 2015, Cuadrilla would enter full-blown production. This would entail the development of a further 800-1,200 wells from around 100-120 pads spread over a 50 square miles area between Cleavleys to the north of Blackpool, Kirkham towards Preston and Lytham St Annes.
Exploring and developing shale gas plays will not come cheaply. Cuadrilla says well drilling costs are £20,000 per half-day, with an exploration well costing £10.5 million each, falling to £9 million in commercial extraction. At the time of writing, Cuadrilla was reportedly in negotiations with Centrica (owners of British Gas), ExxonMobil, BP and Shell to sell a stake in their shale gas assets.
Cuadrilla not the only show in town
UK shale gas exploration does not start and finish with Cuadrilla Resources. UK firm IGas Energy says test results indicate more than 9 trillion cubic feet of shale gas in place at its sites in Ince Marshes near Chester and Doe Green in Warrington and is evaluating possible drilling.
Eden Energy is a 50% partner of Bridgend-based Coastal Oil and Gas Limited with exploration licenses across South Wales from Cowbridge to Pontypridd, Neath, Port Talbot and Swansea. Eden Energy reports its seven licences in South Wales have gas-in-place resources of 34 trillion cubic feet.
In Scotland, Dart Energy intends to develop its Airth sites, estimated to contain 0.7 trillion cubic feet, near Stirling in Clackmannanshire. Dart Energy also holds several exploratory licenses for the Cheshire Basin and Gainsborough Trough in northwest England. Several more companies are expected to prospect for shale gas when DECC finally completes its 14th licensing round for onshore oil and gas exploration.
Developing shale gas plays
In general, UK shale basins tend to be very different from the United States, they are much smaller and the geology is more complicated. Many of the US basins are intra-cratonic, which tends to form in geologically stable regions with relatively small amounts of faulting and deformation of the Earth’s crust.
By contrast, as in the geological past the UK was situated close to the boundary of several tectonic plates, many of the UK shale basins have undergone much more deformation. That means buried faults are contained within the basins that cut through and offset the shale deposits.
The good news is that the sequences of shale are very thick, and that is undoubtedly beneficial in a country like the UK with a high population density sensitive to developments. Yet the thickness of the shale could be a doubled-edged sword. The gas ‘pay zone’ is much deeper than the United States shale plays and therefore it may be more dispersed and more difficult to extract.
What is certain is that there will be ‘good’ shales and ‘bad’ shales with a huge amount of variability within them, as Dr. Nick Riley, the British Geological Survey’s (BGS) Team Leader for Unconventional Gas explains. “There’s a lot of single depositional tectonics going on,” he says.
“So not only do you have over-printing of faults between the late-Carboniferous and post-Carboniferous periods, you’ve got active faulting during the Carboniferous period and that is controlling a lot of the quality of the shale, the thickness of the shale. Plus at certain times of the Carboniferous period the sea level goes up and down as polar ice caps waxed and waned, which changes the organic nature of the shale.”
As yet there is no exploration data in the public domain appraising whether the ‘good’ shales have ‘sweetspots’ of shale gas all the way through. Geologists can, however, conduct burial history analysis to determine how quickly and steeply sediments were buried at the time they were originally deposited in order to make pressure estimates ahead of drilling any wells.
Dr Jonny Imber, a Durham Energy Institute structural geologist, says brittle layers of rock are preferable for extracting hydrocarbons from shale. “The hydraulic fractures will propagate more easily, and will remain open easily, within very brittle layers,” he says. “They tend to be layers which contain quartz and calcites.”
Shale gas companies look at the stratigraphy by extracting cores of rock to analyse the layers. “But the well is like putting a pinprick in a very large cushion, you don’t know what’s going on laterally. The key challenge is to try and work out how the geology varies as you move around the compass positions away from the well.
“Shale gas production often relies on natural fracture systems within the shales and a well is essentially a one-dimensional sample through a three-dimensional rock volume. It can be difficult to understand the geometry of the natural fractures just by looking at a single well.
“They can use seismic reflection data to produce a seismic survey over an area of interest, but the resolution of the seismic data is probably only around 30 metres vertically. It will give you a broad overview of the structure and the different layers but it won’t to get you anywhere near enough information,” adds Imber.
Even when ‘sweetspots’ are located, extracting hydrocarbons from shale is not straightforward, says the BGS’s Riley. “In places producing shale gas they can drill wells very close to each other in the same layer where one well will flow and the other will not. Also, one horizontal leg may not flow and they don’t know why. There is still a lot to learn.”
In the end, it will be case of suck it and see. Graham Tiley, Shell’s general manager for an unconventional venture in Ukraine, expects disappointments. “That is why it is called exploration,” he says. “We drilled three shale gas wells in southern Sweden and did not find the gas content in the shale and exited that project.
“At the end of the day, if you have drilled your 1,000 wells, the question is does the average recovery per well exceed your economic threshold. Some wells will come in lower. A few wells will hopefully come in much higher. But the absolute critical factor is your average recovery per well.”
Gaining public confidence in shale gas
Almost all energy developments attract controversy but shale gas has proven particularly hyperbolic. Much of the screeching from opponents to shale gas is overblown, yet there is no doubt that poorly-constructed wells could result in extensive groundwater pollution as has occurred in the United States.
In its report, ‘Shale gas extraction in the UK: A review of hydraulic fracturing’, the Royal Society said well integrity is the highest priority to practice safe fracking. Dougal Goodman, Chief Executive of The Foundation for Science and Technology and member of the Royal Society’s shale gas extraction working group, says monitoring should be carried out before, during and after shale gas operations to detect methane and other contaminants in groundwater and potential leakages of methane and other gases into the atmosphere.
“In the US there have been casing failures and with a very large number of wells drilled this is perhaps to be expected,” he says. “ In the UK the well design has to be reviewed by a third-party independent examiner, but we recommend that this independent examiner should also make on-site visits rather than merely review the paperwork for the design, drilling and completion stages.”
The HSE appears to have heeded the Royal Society’s advice. Steve Walker, Head of HSE’s Offshore Division says it will engage with the onshore drilling industry in order to gain public trust in shale gas. “One of the issues raised by the Royal Society was not so much concern about well integrity but public confidence in well integrity.
“The industry is also concerned about ‘cowboy frackers’ cutting corners to cut costs. So the industry is saying it will go above statutory requirements. [Shale gas developers] say ‘We not need to the well examiner to do ‘x’ but we will make sure they do it in order to get that extra public assurance’”.
Cuadrilla operates an ‘open house’ policy on its activities, says Chief Operating Officer Eric Vaughan. “We have given hundreds of residents, MPs and councillors tours of our fracking sites and we have a full-time visitor cabin when we are drilling so people can come and see what we do,” he says.
Yet the company has not covered itself in glory in recent years. Aside from the earth tremors, hugely damaging in a public relations sense, Cuadrilla was forced to abandon last November a borehole at the Anna’s Road site after a ‘packer’ – testing equipment used to investigate a cement failure – was lost and became jammed 2000 feet below the surface.
Incidents such as these do nothing to assuage fears that shale gas is not safe. “There is no love for shale gas in the UK”, says Simon Whitehead, managing director of energy PR firm Hill and Knowlton. “There needs to be an industry-wide, offensive campaign with a fresh new narrative giving more of a brand feel to shale gas developments. Fracking needs a re-brand, perhaps with a ‘kitemark’ for safe developers.”
Developing community benefits from shale gas
Yet this may still not be enough to ensure shale gas operations go ahead. The industry recognizes that it may be rational for communities to oppose developments because they could come in for all the downside of fracking – road traffic, noise and potential groundwater pollution – without any of the upside.
Ultimately the social licence to operate resides within the communities and no amount of exploration licenses guarantee access to hydrocarbons without it. Public acceptance may require some tangible benefits and shale gas companies are talking with local and national government to explore ways to transfer some of the revenues back to the communities affected by drilling activities.
In Poland, Hutton Energy has set up a community advisory board comprised of key stakeholders: local residents, the local mayor, the landowner, company representatives and, in some cases, the local priest. Another developer in Poland, San Leon, even goes as far as working with priests to spread the good word about shale gas, attending Sunday worship and making donations towards church maintenance.
A similar approach may work in the UK, says Andrew Austin, CEO of IGas Energy, which operates 30 oil and gas fields with production in the East Midland and the Weald. “Around 10% of our operational expenditure, or 3% of our revenue, is on business rates, which remain in the local community,” he says. “Those rates may mean a weekly bin collection, or two more bobbies on the beat.
“In addition, we also make annual contributions to a voluntary community fund run by independent trustees. The local parish councils are able to bid for projects such as music festivals, village hall restorations, bus shelters and so on.”
Austin says shale gas developers will have a much higher probability of getting community approval if they build on the similarities to conventional oil and gas rather than highlighting the differences. “One of the biggest obstacles is to get over the impression that the drilling rig will stay forever like a mobile phone mast or a wind turbine. The rig is there for 90 to 120 days and then it goes; all that remains is a wellhead.”
The time for talk is over. Shale gas developers like Cuadrilla and IGas now need to get on with the business of exploration to ascertain the rates at which gas flows out of the shale. Then, and only then, will we know whether shale gas can make a meaningful difference in the UK.
THE EUROPEAN UNION’S (EU’s) AMBITIOUS plan to rollout smart meters to 80 percent of its 500 million population by 2020 is not going as well as hoped. This article was first published in the January/February 2013 edition of Intelligent Utility magazine.
Europe has enjoyed notable success with smart meters. In 2006, Italy became the first country in Europe to complete a national smart meter program after utility Enel conducted a five-year, $2.6 billion (US) scheme – mainly to reduce non-technical losses – for its 30 million customers.
Elsewhere, Scandinavia leads the way. Sweden also achieved full-scale penetration in 2010, while Finland, Norway, and Denmark are likely to achieve their targets by 2016. Yet for many EU nations who did not take it upon themselves to be early adopters, smart meter programs have struggled.
The European Union’s 2009 Third Energy Package, which sets out measures to liberalize Europe’s power sector, required each of the 27 member states to publish a cost-benefit analysis by end-September 2012. If the analysis found a positive business case, member states are compelled to install smart meters to 80 percent of consumers by 2020.
Most nations have reported a positive cost-benefit analysis, although there were some exceptions. The Czech Republic’s analysis was negative and has recommended its rollout start in 2018, while Germany has delayed the publication of its report until February 2013.
The three basic lessons
While utility benefits of smart meters are not in doubt, for the average European the case for consumers has not been well established. Significant tactical errors have been made, not least in the Netherlands, which proposed all 7 million households of the country should have a smart meter by 2013.
Faced with a growing moral panic over data privacy concerns, the Dutch government pushed for compulsory installation of smart meters, with refusal punished by a fine or six months in prison. After vigorous campaigning by consumer organizations it eventually relented and the Dutch Parliament moved to make installation voluntary.
The Dutch example is a salutary lesson in the dangers of putting the cart before the horse. Dr Philip Lewis, CEO of Finland-based utility analyst Vaasa ETT, says rollouts cannot be successful without consumer trust.
“There are three basic stages of consumer motivation,” said Dr. Lewis, a psychologist who now specializes in utility customer behavior. “First, there are reasons to be positive about overall smart meter developments at a national level. The second is to be positive about reasons to get involved with smart meters. The third is eliminating reasons not to get involved.”
Preaching the first lesson
Promoting them at a national level in Britain is the job of Maxine Frerk, deputy director and head of consumer engagement of the UK Department of Energy’s smart meter program.
Engaging consumers is proving tough in Britain, which is very much its own beast. Rather than regulated distribution network operators, deregulated energy retailers have the responsibility to procure and install 53 million gas and electricity meters, involving visits to 30 million homes and small businesses, by 2019.
It is an interesting policy choice and, in that respect, Britain is in a minority of one worldwide. The rationale is simple: Energy retailers have a relationship with their customers, and customer behavior change is a major element of their business case. So it was decided that it made sense for suppliers to be the primary interface for the rollout.
After years of inflation-busting price increases, tariff mis-selling and poor customer service at a time of stagnant wages and rising unemployment, however, British energy retailers are among the least popular organizations in the nation, barely more popular than banks, estate agents and even parking attendants.
So the energy companies will have assistance from the UK Department of Energy’s new smart meter `Central Delivery Body’ that will conduct a public awareness campaign about the benefits, which are estimated at a total £16 billion ($26 billion) in return for £11 billion in costs. Frerk believes a strong push from the center is needed because smart meter awareness and public trust in utilities is very low.
“Our latest survey of consumer awareness showed only 49 percent of respondents had heard of smart meters and from some of the other questions we asked, it’s not clear that even all of those did,” she said. “Getting consumers to just open their front door is the first challenge. If suppliers are faced with a lot of apathy, and find it hard to get access, it will increase costs.”
Putting the second lesson into practice
The British division of German utility E.ON aims to install 1 million smart meters by the third quarter of 2014, around the time the national rollout officially begins. The program started in 2011 and the company is close to 300,000 installations. By the designated end of the national rollout in 2019 it expects to install 8 million electricity and gas meters to 5 million homes.
The stakes are high for E.ON UK. Up for grabs are hundreds of millions of pounds in efficiency savings, the potential to offer critical peak period and other time-of-use tariffs and even the possibility of harnessing data for third-party marketing purposes.
“We’re investing £1 billion in this,” said Chris Lovatt, head of field operations, E.ON UK. “Our head office in Germany regularly asks me why they should spend it on smart meters when we could invest that money in, say, Brazil and see a much greater return. So we owe it to our customers and shareholders that this is done efficiently.”
E.ON has created two “centres of excellence,” essentially customer service contact centres to hold their customers’ hands through the end-to-end experience of smart meters. “We’re also creating a field centre of excellence to ensure all our meter technicians are technically skilled,” said Lovatt.
“They will also go through comprehensive customer service training so they’re able to have softer conversations with our customers to explain how the smart meter benefits them.”
E.ON is working with charities such as Age UK to ensure smart meters do not leave elderly consumers out on a limb. “Age UK was particularly concerned about the support that customers got post-installation, so we’re actually training some of their staff in five different regions across the UK to handle queries.”
Initial feedback shows that E.ON’s efforts are paying off. “The levels of NPS (Net Promoter Score) are in the high 20s, higher than anywhere else across our portfolio,” said Lovatt. “We’re feeding some of the knowledge gained from smart meters into our classic environment.”
Lessons learned the hard way
The message is clear: Consumer engagement should be done prior to the rollout with the technology coming at a later stage, and not the other way round. This was a lesson learned the hard way by Californian utility Pacific Gas and Electric (PG&E), which since 2007 has installed 9.5 million power and gas meters in 6 million households, taking 90 billion meter reading intervals per year.
At peak, it installed 18,700 meters a day with contractors and its internal workforce, equivalent to one every 2.5 seconds. Yet the path of smart metering did not run smoothly. “If we were to start again we would have done things differently,” said Jim Meadows, director of PG&E’s smart meter program.
“The more you separate out the installation from customer engagement, the more customers are suspicious about the motives behind smart meters. You need to make customers feel part of the bargain from the start. And in order to use the data efficiently you also need to have your operations center completely functional from the day the first meter is installed,” Meadows said.
Ogi Kavazovic, vice-president of marketing and strategy at Opower, says utilities should be thinking about their customer strategy at least a year before the smart meters are installed.
“The cost is probably less than 1 percent of the overall smart grid program costs yet many utilities don’t do it because they think consumers will change anyway,” he said.
The third lesson: Don’t be afraid of opt-outs
Despite their mandatory nature, European law may mean rollouts are subject to opt-outs.
PG&E believes opt-outs are to be welcomed. “If we learned one thing it’s that customers don’t like strictly mandatory programs,” said Meadows. “They like to know there’s an opt-out. In hindsight, we would have offered an opt-out from the start.”
E.ON UK says the carrot of energy savings should be sufficient to gain public acceptance, but U.S. utilities also know that wielding a big stick is useful. PG&E has an opt-out rate of just 0.5 percent, helped in part by the imposition of a $75 up-front fee and a further monthly charge of $10 per month to cover the expense of manual meter reading.
Opt-out rates in Europe are so far reassuringly small, said Lonneke Driessen-Mutters, head of smart meter operations at Dutch firm Enexis. “We have installed 220,000 smart meters and less than 1 percent has refused. It seems that just having the option to opt out is enough, but we are very vigilant that things will stay that way.”
The endgame: smart pricing
Post-installation, some European utilities may not be able to offer smart pricing but even without it there is much to be done with smart meter data, said Opower’s Kavazovic.
“Home energy reports give insights on consumption data and when customers call they can be given new insights, targeted discounts and coupons based on their data. As well as giving insight into their consumption, we also show the potential savings that could be made on the report,” he added.
Opower says its monthly mail energy report is the most effective method to engage consumers, but it also uses e-mail and web portals.
“Engage customers where they are not where you wish they are,” said Kavazovic. “In Europe, mobile phone channels look very promising.”
For most utilities, the endgame of smart metering is smart pricing. VaasaETT’s Lewis says consumers must feel part of the deal for time-of-use tariffs to be successful.
“Customers need to feel they are in control. When they introduced time-of-use pricing in Australia without consumer permission the backlash was so bad they had to stop it. There was a perception that some people were suffering from smart meters. We don’t want that to happen in Europe,” he said.
PG&E has a peak summer load of 16 GW. Its SmartRate tariff dictates that for 15 days a year a surcharge of $0.50/kWh is imposed between 14:00-19:00. In exchange, participants get credit for off-peak hours.
“You have some unintended consequences such as at 19:00 demand for air conditioning is higher than usual because of the higher heat of homes,” said Meadows, “But 80 percent of the customers find a way to save money. And we’ve had a 13 percent critical peak period load reduction.”
Dr. Lewis warns that customers must become accustomed to smart pricing. “You can’t suddenly shove it upon them and sit on them. There needs to be a fair and transparent link between the sacrifice and the reward, and customers have to explore what those benefits are for themselves directly.”
The psychologist sees best practice in Scandinavia where the Finnish utility Fortum has launched a product whereby customers can automatically control their hot water heating linked to the spot power market, Nordic. The heating system is timed throughout the day and is switched on or turned off depending on market prices.
“From the customer point of view it’s a profit-sharing scheme”, said Lewis. “The utility benefits by getting the customer engaged in sharing market volatility and the customers save by taking advantage of that volatility, rather than suffering from it.”
The EU is a big place and there can be no one-size-fits-all solution for a continent of 27 nations and 500 million people but, says Lewis, follow the three golden rules and progress will be less problematic, and less costly.