Shale gas water management schematic. Courtesy Schlumberger

Water and energy have always had a close relationship, but shale gas and water are particularly intimate. Water is integral to shale gas drilling and there is a growing market, estimated to be worth up to $100 billion in the United States, for wastewater treatment. Tim Probert explores the opportunities and challenges in Europe. This article was first published in the April/May 2012 edition of Water and Wastewater International.

There is no question that shale gas has been a ‘game-changer’ in the US. From virtually nothing ten years ago, shale gas now accounts for around a quarter of domestic natural gas production.

Can the same happen in Europe? According to the US Energy Industry Administration, Europe has up to 480 trillion cubic feet (tcf) of “technically recoverable shale gas resources”, compared with 862 tcf in the US. This would be enough to meet current consumption levels for approximately 25 years, but getting the gas out of the Earth’s crust is a heavily industrial process and will be more tightly regulated in the European Union than in the US.

In contrast to conventional gas extracted from porous rock, shale is relatively impermeable, meaning gas cannot easily move through the shale in which the well is drilled. In order to release the gas, drillers use a method called hydraulic fracturing, also known as fracking, essentially pumping water, sand and chemicals at high pressure. Shale gas developers use a technique called pad drilling, with up to ten drill wells radiating horizontally for distances of up to six miles from a single site, or pad.

This technique has been used for decades, but the improved ability to steer drill bits using off-the-shelf technology has made horizontal fracking cost-effective. The facility to perform surface data acquisition to locate gas in the rock, rather than drill right through the shale as previously, has also brought down costs.

A controversial practice

Fracking, however, is highly controversial and there are moratoria in France, Bulgaria and in some regions of the US, Australia, South Africa and Canada. Most of the opposition to fracking centres on the use of water.

Numerous scare stories emanating from the US, of inflammable water supplies, polluted ponds and exploding houses, not to mention seismic activity in the UK, have added fuel to the environmentalists’ fire.  However, there is growing, robust evidence of ground- and surface water pollution due to poor practice and slack regulation; fracking is exempted from federal Clean Water and Safe Drinking Water Acts.

Cuadrilla Resources, which last year announced that a 500 square mile area in northwest England contains enough shale gas for more than 50 years consumption, is operating a number of exploratory wells in the UK. It claims to use ten fracking methods “fundamentally different” from the US.

These include the use of steel tanks to store flowback water rather than in a bare pit dug out of the earth; an impermeable plastic sheath 18 inches below the top gravel layer onsite to prevent leakage of flowback water and facilitate easy capture of spills; and monitoring wells to detect methane leaks in shallow water supplies used by farmers.

Cuadrilla will also use surface and intermediate cement casing of boreholes to a depth of up to 1000 feet to protect contamination of aquifers.  Regulations in New York State, for example, require casing to a depth of just 50 feet to preventing contamination of gas in water supplies.

Draft to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water, US EPA, February 2011.

Water goes in

It is estimated that a shale gas well requires between 9-29 million litres per well. A report by the UK’s Tyndall Centre for Climate Change estimates 2580-3000 wells would be required to produce 9 billion cubic metres per year of shale gas, equivalent to 10 per cent of national annual consumption.

This volume of gas implies a total annual water requirement of up to 87 billion litres. To the uninitiated this sounds an awful lot of water, but the figure is dwarfed by the 1.2 trillion litres lost in the UK in 2011 from pipe leakage.

Added to the water, equivalent to around 0.25 per cent of total fracking fluid used, are three additional ingredients: a friction reducer called polyacrylamide; a biocide to purify water; and a weak hydrochloric acid (E507) to help open the perforations to initiate frack fluid injection. The use of these chemicals are another source of controversy, but the European Commission and the Environment Agency (EA), which regulates water usage in England & Wales, have declared these chemicals safe.

Water comes out

With respect to water usage, pumping fracking fluid into the well is the easy part.  Approximately 10-40 per cent of the fluid returns to the surface.   This flowback fluid is lucrative yet pretty nasty stuff, and yet another source of controversy.

As well as the target natural gas (mostly methane plus propane, butane, and ethane), the flowback water contains other gases such as carbon dioxide, hydrogen sulphide, nitrogen and helium; naturally-occurring brine, trace elements of mercury, arsenic and lead; naturally occurring radioactive material (radium, thorium, uranium); and volatile organic compounds that easily vaporise into the air, such as benzene. Herein lay the challenges and opportunities for water and wastewater companies.

Flowback rates during first two weeks of fracking average 3,000-5,000 barrels/day (bpd) (357,000 to 595,000 litres), declining rapidly to a few 100 bpd. Further decline is gradual, estimated at 10-20 bpd after a few months.

There are four primary options for dealing with flowback.  The first option is the also easiest and cheapest: reuse it without treatment.  Reusing untreated water is frequently performed in the US, but continued reuse will lead to problems as the high level of contaminants may plug the gas wells with residual chemicals, precipitates or shale fines.

The second option is deep well injection. Simply drilling another well to store the water, however, is not without problems: in March, Ohio state regulators said a dozen earthquakes in the state’s northeast were almost certainly induced by injection of gas-drilling wastewater into the earth and analysts say this option will be almost impossible in Europe due to stricter legislation.

The third option is on-site treatment for reuse. This option is used to remove most TSS (total suspended solids), acid-producing bacteria and scaling materials like barium, calcium, iron, magnesium and strontium, which are likely to clog the well if returned to the gas reservoir.

Typical capacity for this option is 2,400-14,000 bpd.  Having removed most TSS, typically from 500-1000 mg/l to 50/mg/l, this treated water is then mixed with fresh water and re-used for fracking. As everything is done on site, this option has negligible transport costs.

The fourth option is on- or off-site treatment for discharge as fresh water, which can, of course, be used for fracking. The main objective is to remove TDS (total dissolved solids) in flowback, which can reach extremely high levels of both concentration and variability. Flowback from fracking operations in the Haynesville shale, which covers southwestern Arkansas, northwest Louisiana and East Texas, can contain between 500-250,000 mg/l.

TDS removal, which must be down to 500 mg/l to meet US Environmental Protection Agency standards, is done on-site by using or mobile units or off-site at central treatment plants. Typical capacity of off-site treatment would be 12,000 to 48,000 bpd. Due to the large volume of water, transportation costs become a cost factor.

Karim Essemiani, business & marketing manager for Veolia Water S&T Oil and Gas, estimates the costs of TSS removal in the US at between $3-6/bbl, rising to $20/bbl for TDS removal including equipment, operation, labour, chemicals, sludge handling etc.

GE mobile fracking water evaporator

Flowback treatment technologies

For on-site TSS treatment, the process typically involves a five-step process. The first is chlorine dioxide oxidation, which breaks oil/grease emulsions; destroys friction reducers and other chemical additives; and kills bacteria.

Step two is dissolved air flotation which floats oil, grease and TSS to the top of the chamber. Liquid-phase activated carbon then removes most hydrocarbons and other organics, before chemical precipitation removes the aforementioned scale‐forming compounds. Finally, a conventional sand filter removes the TSS.

There are two viable options for TDS removal from shale gas flowback: thermal distillation and membrane filtration.  A commonly-deployed method for flowback water desalination uses an integrated three-stage mobile RO system.  The first phase is pre-treatment using chemical flocculation, clarification and oil removal; phase two is cold lime softening; and the third stage uses micro-, ultra- and nano-filtration, as well as reverse osmosis.

Energy costs of RO are one-tenth of mechanical evaporation, but inadequate pre-treatment can result in significant fouling and scaling leading to costly membrane replacement. Furthermore, RO is unsuitable for treating flowback with TDS greater than 50,000 mg/l.

The most common method to remove TDS is thermal distillation via a mobile vapour recompression (MVR) evaporator unit, offered by a number of leader water technology companies such as GE Water, Veolia and Aquatech.  Here, the incoming flowback water is boiled to produce steam, while all dissolved solids remain in the concentrate. The resulting steam is then condensed into pure water.  While energy costs are higher than RO, MVR units are able to cope with high TDS concentrations of 50,000-250,000 mg/l.

Once RO or thermal distillation is complete the brine concentrate has to be treated, usually through an off-site crystallizer.  A 1 million gallon a day crystallization plant will generate approximately 400 tons a day of salt waste, which will require disposal in a solid waste landfill.

Opportunities for the water industry

Michael Coffey, managing director of water consultants Aquastrat, says shale gas offers several revenue streams for the water and wastewater industry, not only from treating flowback water, but also flowback water data management and laboratory analysis, while treated brine could be sold for road de-icing.

Coffey is confident water utilities can cope from waste materials in flowback water, but it may not want to, despite the opportunities. “At the moment, they don’t see anything that differs from other industrial activities, but they are slightly concerned about the concentrations of chemicals.

The consultant notes the US state of Pennsylvania has issued a decree preventing any flowback water from being treated at wastewater treatment plants because of high levels of bromide, which when disinfected creates a compound called brominated trihalomethanes linked to several types of cancer and birth defects.

“There are issues over the interplay of bromides used in fracking fluids and chlorine in water treatment plants,” he says. “I’m not saying it can’t be dealt with but the shale gas industry needs to be upfront as part of its water strategy.”

Another pressing concern is radiation. Analysis by the EA of Cuadrilla Resources’ Preese Hall exploratory well found significant levels of radium-226 above legal limits. Although the concentration of radioactivity is low, the total volume of return fluids is large, large enough to require a permit for disposal at its intended destination, United Utilities’ Davyhulme plant in Greater Manchester.

Nearly a year on from the EA’s visits, however, Cuadrilla has still yet to attain a permit, which requires a full radiological impact assessment, and the flowback water remains in steel tanks on the fracking site.

South East Water has expressed concern over fracking and is working with Water UK for water companies to be included as statutory consultees on planning applications. A spokesperson said: “We accept the risks to water supplies do exist. In particular, the risks to drinking water supplies need to be addressed to ensure the safety of our customers’ water quality is maintained.”

Stricter regulation means higher costs

Lucy Field, of energy consultants Poyry, who has authored a report for the UK Department of Energy and Climate Change about unconventional gas, says water usage and disposal is the single biggest most prohibitive factor in shale gas development. “The UK is in the middle of a drought and supplying water to fracking sites could be difficult in certain regions. We have enough trouble supplying water for our everyday needs.

“But the main issue is water disposal: the flowback water can only be recycled at most three times before it has to be disposed. In US they truck the water in and out, but in the UK they may have to build pipelines, which costs.

Field says if best practice is followed fracking can be done safely, but following the UK’s strict water regulations correctly will be expensive. “Due to the population density and relative shortage of land, plus the cost of meeting more stringent regulations, we expect the costs of production will be at the very least 50 per cent higher than in the US,” she says.

Europe has the advantage of learning from good practice and the mistakes made by first-movers in the US. Shale gas offers tremendous benefits in terms of wealth and job creation, but if it is to be a game-changer in Europe as in the US, it is fundamentally important that the water industry is fully engaged with any shale gas drilling activity.

UK’s Bowland shale well schematic. Source: Cuadrilla Resources

Vanessa Vine front left and Green MEP Keith Taylor front right at Ardingly Reservoir in Sussex with supporters of No Fracking In Sussex.

To some, shale gas is potentially the best thing energy development in Britain since North Sea oil. To others, shale gas is a potential environmental catastrophe. Will the growing environmental opposition to hydraulic fracturing, or ‘fracking’, stop shale gas in Sussex in its tracks? Tim Probert digs deep. This article was first published in the May 2012 issue of Sussex Life.

Last September, US oil company Cuadrilla Resources announced a 500 square miles area of the Bowland sedimentary rock basin in West Lancashire held  ten times existing UK natural gas reserves, enough for more than 50 years’ consumption at current rates.  Cuadrilla now believes there could be a sizeable quantity of unconventional oil and gas in the Weald and Wessex basins.

While no shale gas drilling has yet taken place in Sussex, Cuadrilla has permission to test drill for oil and gas at Lower Stumble, a mile south of Balcombe in West Sussex. Cuadrilla intends to drill at the same site on the 3,000-acre Balcombe Estate where oil major Conoco started, and later abandoned, an exploratory well in 1986.

Mark Miller, CEO of Cuadrilla Resources, is using the undoubted success story of Wytch Farm in Dorset – which BP developed to be Western Europe’s largest onshore oilfield – as a role model. However, in contrast to this ‘conventional’ oil and gas, extracted from porous rock, shale is relatively impermeable, meaning gas cannot easily move through the shale in which a well is drilled.

In order to break open the shale and release the methane, shale gas drillers use a method called hydraulic fracturing, also known as ‘fracking’, essentially pumping large amounts of water, sand and chemicals at high pressure.  Therein lies the rub. Fracking is highly controversial and has been banned in France, Bulgaria and in some regions of Germany, the United States, Australia, South Africa and Canada.

Most of the opposition centres on the use of water.  Shale gas requires approximately 30 million gallons of water per drilling site. Approximately one-third of this water is returned to the surface and this ‘flowback’ fluid typically contains methane, naturally occurring radioactive substances, metals and volatile compounds such as benzene.

Numerous scare stories emanating from the United States, of inflammable water supplies, polluted ponds and exploding houses, have added fuel to the environmentalists’ fire. Closer to home, an independent study concluded two small earthquakes near Blackpool on 1 April and 27 May 2011 were directly attributable to Cuadrilla’s fracking activities.

Cuadrilla Resources’ oil and gas borehole at Lower Stumble on the Balcombe Estate. Cuadrilla has planning permission to commence exploratory fracking at the West Sussex site. Alec Smart Fotos.

Fracking is safe, say authorities

Miller says Cuadrilla will use ten fracking methods in the UK “fundamentally different” from the United States. These include the use of steel tanks to store flowback water rather than in a bare pit dug out of the earth; impermeable plastic sheaths to prevent leakage; and monitoring wells to detect methane leaks in shallow water supplies used by farmers.

Meanwhile, the Environment Agency has concluded there is no risk to groundwater if regulations are adhered to, while the British Geological Survey says groundwater pollution is extremely unlikely. Lucy Field, of Oxford-based energy consultants Pöyry, author of a shale gas report for the Department of Energy and Climate Change, says the environmental opposition to shale gas is overblown.

“Quite a lot of the scare stories are inaccurate,” she says. “Clearly there have been instances of pollution which can’t be ignored, but these are mostly due to poor practice.  If best practice is followed, such as proper cementing of wells, fracking can be done safely.”

Opposition to fracking by local residents could be viewed as perfectly rational, as there are no immediate benefits to the community but plenty of drawbacks should an accident occur. However, Simon Greenwood, owner of the Balcombe Estate, which earns thousands of pounds in annual rent from Cuadrilla, says he has more to lose than anyone.

“There has been some measured concern expressed locally but also a lot that is ill-informed,” he says. “If there was a problem I would have as much to lose or more to lose than anyone else; if it is detrimental to Balcombe, it is detrimental to me.”

Anti-shale gas group Frack Off unveil their banner at Brighton station. Alec Smart Fotos.

Fracking is unsafe, say campaigners

Whatever the realities, the negative public publicity for fracking has galvanized increasing numbers of people to protest against shale gas development. Vanessa Vine, co-ordinator of the No Fracking in Sussex protest group, believes fracking could irreversibly pollute the region’s drinking water supplies.

Vine notes the Lower Stumble site is located 100 yards from the London to Brighton mainline, and less than a mile from both Ardingly Reservoir and 170-year old Balcombe Viaduct.  “There are too many unknowns Cuadrilla won’t answer, like whether or not the fracking water would come from the Ardingly Reservoir, which is already at very low levels due to drought,” she says. “And can we be sure that even a small earthquake would not cause damage to an ancient Grade II viaduct?’

In response to a statement released by Cuadrilla last December signalling its intentions at Lower Stumble, Vine organized a meeting at Balcombe Victory Hall on January 11, inviting Cuadrilla’s Miller to speak. Miller agreed, with the express intention of winning round the local population with arguments based in fact, not emotion.

The meeting attracted more than 250 attendees and a passionate debate ensued. The meeting was covered by BBC radio and independent television news, while prominent features appeared in The Daily Telegraph and The Guardian.

Public awareness of fracking in Sussex – and opposition – is growing. In February, a nationwide protest group, Frack Off, unveiled a 22 m2 anti-fracking banner, for which a local property developer has given permission to display for four months in full view of trains from London and the South East, on a billboard at Brighton station.

Does Vine think the protest movement can put a stop to shale oil and gas fracking in Sussex? “I do not see it as a foregone conclusion that there will be fracking all over the place. We are not the United States and people aren’t used to seeing nodding donkeys on fields in Britain. They can’t get away with it in such densely populated land as Sussex.”

Whether the Balcombe site will ever be developed is still very much yet to be decided, says Miller. “We have no immediate plans in Balcombe but we have a deadline of 2014 to decide whether to drill or lose the licence,” he says.

“Exploration is a high risk venture and the percentage of exploration wells that go into production is very small. We have a number of these licence areas that we may never go forward with. Lower Stumble is one on our list that we’re debating.”

Whether or not shale gas goes into production in Sussex remains to be seen, but the Battle of Balcombe continues to rumble on.

Shale gas drilling rig operated by Cuadrilla Resources

An independent report published today by the UK’s Department of Energy and Climate Change (DECC) recommends shale gas hydraulic fracturing (fracking) should be immediately halted if seismic activity is recorded of a magnitude (M) of 0.5 or above, far below Cuadrilla Resources’ proposed level of 1.7M.

Shale gas developer Cuadrilla Resources, which last September claimed that a 500 square miles area of the Bowland sedimentary rock basin in West Lancashire holds 200 trillion cubic feet of gas, was forced to halt exploratory fracking last year after the British Geological Survey suggested its operations were causing earth tremors.

A series of studies were commissioned by Cuadrilla Resources to examine the possible relationship between hydraulic fracture operations at its Preese Hall site, near Blackpool, and a total of 50 seismic events up to 2.3M detected between 31 March to 27 May 2011. After admitting that fracking had caused seismic events, Cuadrilla proposed a maximum magnitude threshold of 1.7M before it would halt operations.

Today’s report, co-authored by the British Geological Survey, says this level could be too high to prevent potential structural damage. The report states: “We consider that the maximum magnitude threshold of 1.7M initially proposed is undesirably high from the viewpoint of prudent conduct of future operations.

“This was based on the critical magnitude 2.6 M and a maximum post-injection magnitude increase of 0.9 M. However, we note that, based on this limit, no action would have been taken before the magnitude 2.3 M event on 1 April 2011. We recommend a threshold of 0.5 M for cessation of operations, to minimise the probability of further felt earthquakes.

“We consider that this would be a prudent threshold value, to reduce the likelihood of events perceptible to local residents, and to offer a higher margin of safety against any possibility of damage to property.”

The report effectively gives the go-ahead to Cuadrilla to continue shale gas exploration at Preese Hall, but there will be questions as to whether the low magnitude limit and other recommendations are workable. Others may take a view that the limit has been set low to mitigate potential for any more negative publicity regarding fracking and seismic activity.

The report also sets out a number of best practice methods recommended for any hydraulic fracture developments:

1. Formal risk assessment of potential well drilling and completion operation impacts, prior to spudding the well;

2. Geophysical logging, to delineate the base of freshwater aquifers and determine reservoir parameters;

3. Surface casing and packers/cement deep enough to protect freshwater aquifers;

4. Production completion (casing/cement packers) designed to prevent upward migration of reservoir and injected fluids (e.g. intermediate string inclusion, if necessary);

5. Cement bond logging and pressure testing of each completion string to ensure good seals;

6. Drilling and frac fluid storage in tanks and offsite burial of drill cuttings;

7. Fracture diagnostics, especially microseismic and tiltmeter monitoring of hydraulic fracture growth;

8. Avoidance of fracturing near faults/subsurface structures;

9. Reuse of frac fluid to reduce freshwater resource impacts and potential disposal issues;

10. Water sampling before and after drilling/HF operations to ensure no aquifer contamination;

11. Regular updates and frequent engagement with stakeholders, about ongoing operations.

The full report can be read here: 5055-preese-hall-shale-gas-fracturing-review-and-recomm

The Fukushima Daiichi nuclear plant accident has accelerated a trend towards a two-speed nuclear world. Photo: Reuters/Kim Kyung-Hoon

There is a general consensus that new nuclear build has been delayed rather than derailed by the Fukushima crisis in Japan. But Fukushima may have accelerated a trend already present before the accident – a two-speed nuclear world split into liberalised and state-directed power markets.

This year is shaping up to be an annus horribilis for the nuclear power industry. The accident at the Fukushima Daiichi plant in eastern Japan, the second worst in history, is still yet to be under full control, leaving plant owner Tokyo Electric Power teetering on the edge of bankruptcy.

Since the massive tsunami struck the crippled Fukushima facility on March 11, the United States, Italy, Switzerland, Egypt and Thailand have postponed or cancelled new build projects, while Germany has seemingly abandoned nuclear power forever. In total, 37 reactors have been axed or put on hold since the crisis.

In Europe, the nuclear industry has taken a succession of blows. Germany will close all 17 of her nuclear plants by 2022. Switzerland has banned the construction of new reactors, while Italians overwhelmingly voted against a return to nuclear power in a national referendum. Of the 55 per cent of citizens who participated in the plebiscite, a crushing 94 per cent voted against the construction of new plants.

Most European nations, however, are still pursuing nuclear power. There is particularly strong interest in Central and Eastern Europe, with Poland, the Czech Republic and Lithuania keen to reduce their dependence on Russian natural gas, while the UK and France are pressing on with renewing their aging fleets.

Crucially, the European Commission has stood by nuclear power, despite recent actions by certain national governments. Marc Deffrennes, nuclear officer at the European Commission DG RTD, told The Energy Industry Times: “The Commission has not become more anti-nuclear since Fukushima. The Commission’s 2050 Low Carbon Roadmap envisages a very high penetration of renewables, but that will require a ‘super-smart grid’ and a high level of energy storage capacity, and this will have an impact on affordability. It is important to keep open the nuclear option in order to stabilize costs, as well as provide security of supply.”

The Commission’s initiative to check the safety of nuclear power plants in extreme circumstances, the so-called stress tests, are well underway. The tests are being conducted on 196 reactors in the EU plus Switzerland, Armenia, Belarus, Croatia, Russia, Turkey and Ukraine. The tests focus on the aspects of plant safety highlighted by Fukushima: natural events like earthquakes and floods, as well as loss of safety functions and severe accident management following any kind of initiating event. The operators have to explain their means to maintain control of reactivity, fuel cooling, and confinement of radioactivity after such an event.

Plant operators will file final reports to national regulators by 31 October, with the regulators updating the Commission by 15 September before making their final reports by 31 December. It seems certain that some reactors will close following the stress tests; Belgium’s energy minister Paul Magnette, for example, said that any unit which fails the tests will be shut down. According to Greenpeace, the older units at Belgium’s Doel nuclear plant, just five miles from Antwerp, are at risk of failing the tests.

Public opinion may take another dip when the results of the stress tests are announced, but Malcolm Grimston, Associate Fellow (energy policy) at British think-tank Chatham House believes that the importance of public perception about nuclear has been overblown. “Nuclear doesn’t have to be popular to get on,” he said. “It hasn’t stopped bankers! Fukushima, rightly, should change people’s views about nuclear because we should learn lessons from it, but I don’t see a massive swell of public opinion against it.”

Financing nuclear is a headache

What matters more to the development of new build nuclear is finance. Allan Baker, global head of power at French banking group Societe Generale, says Fukushima has made an already difficult job even tougher for the financial community, and expects a number of new build projects to be delayed. “Even before Fukushima it was clear that there isn’t enough liquidity to finance these projects,” said Baker.

“We have found it incredibly difficult to mobilize capital for an industry which is seen as very expensive and, to be blunt, non-competitive in a competitive electricity market. No financial institution is willing to take the risk on cash flows over 20-25 years without visible government support for the nuclear industry.

“Banks are also not keen on the construction, completion and cost over-run risks. Sponsors will need certainty over completion and cost over-run guarantees and European utilities don’t necessarily have the balance sheets to take on those risks without the credit rating agencies downgrading them.

“It’s not the costs of nuclear per se, but the uncertainty of costs, which is the killer for financial institutions. If you’re building something which costs $10 billion and there is a 20 per cent cost over-run, then there’s another $2 billion to find. Where does that come from? Does it come from the sponsors or additional debt? And will it be recovered soon, or over the entire lifetime of the plant?”

Professor Stephen Thomas, Director of Research at the UK’s University of Greenwich’s Business School, believes the writing is on the wall for nuclear power in Europe. “Fukushima could be the final straw for light water reactors (LWRs),” he told The Energy Industry Times. “After 60 years of development, real costs have only ever gone one way. Has any other technology had similar experience and still been pursued? Economic LWRs that can survive loss-of-coolant and loss-of-power accidents are an impossible dream.

“The promise of simpler, safer and cheap nuclear power at $1000/kW was either self-delusion or deception. Most recent cost estimates are more than $6000/kW. The future for nuclear power is going to be outside Europe. There will be very few orders in Western Europe and the US. Financing will be geared along national lines; Team Russia, Team Korea, Team Japan, Team France, perhaps Team China in the future. They will sell reactors as a package with financing included.”

Growth in state-run power sectors

In its recent report entitled, ‘The future of nuclear energy: One step back, two steps forward’, the Economist Intelligence Unit (EIU) says the overriding global trend for nuclear power over the next decade will be one of growth, despite recent events.

The EIU has revised down its forecasts for capacity additions in the top ten nuclear nations – USA, France, Japan, Russia, Germany, South Korea, Ukraine, Canada, UK and China – but by 2020 it still expects a 27 per cent rise in these nations to 405 GW, compared to 2010. However, the bulk of this new capacity will be built in state-directed economies like China and Russia where financing of nuclear is of much less of an issue. China’s nuclear capacity will rise by a staggering 527 per cent to 53 GW by 2020; while Russia will see an 81 per cent increase to 18.3 GW.

In the USA, France, Japan, Germany, Canada and the UK, new nuclear capacity will be profoundly slower, reports the EIU. Japan’s nuclear output is expected to fall by 5 per cent, Germany’s by 56 per cent, while the USA and France will witness modest growth of 8 per cent and 5 per cent respectively.

In liberalised power markets, where quick-to-build, relatively low cost CCGTs make far more financial sense, gas will be the clear winner from any slowdown in nuclear build-out, not least because the recent shale gas boom in the US has eased geopolitical concerns about the future sources of natural gas. Plenty of new build coal is the pipeline, not least in Germany, but plant investment decisions made in the medium term are less likely to include coal since Fukushima, according to Point Carbon.

The carbon market analysts say that the German nuclear phase-out will push up the price of carbon permits within the European Union’s emissions trading scheme by about €5 a tonne, leading to a greater switch to gas from coal, particularly in the UK, Italy and Spain. Renewables will also accelerate due to the phase-out, it said.

According to the International Energy Agency (IEA), nuclear power currently accounts for 14 per cent of global power generation. Prior to Fukushima, the IEA forecast 360 GW of nuclear new build, in addition to the existing installed base 390 GW. Following the accident, the IEA has halved the projection for new capacity to 180 GW and expects nuclear power to account for just 10 per cent of the global mix by 2035.

Most of the new capacity will come outside Europe, like in the Middle East where Abu Dhabi is pressing on with its new build programme. Paige Crewson, Special Counsel for Global Projects at Baker Botts LLP’s Abu Dhabi office, said: “Progress in the Middle East hasn’t even really slowed.  The UAE programme is still on schedule for first operation in 2017 and Saudi Arabia has just entered into preliminary arrangements.

“The biggest impact of Fukushima is likely to be international changes to safety standards which will be a design (and licensing of design) issue, rather than a project management one.  If new standards come online before Middle Eastern reactors, they will be expected to comply. The key drivers behind new build – diversifying local economies, carbon reduction, profitability of fossil fuel exports, and increased energy demands from a booming population – haven’t changed.”

Alstom built the 30 MW oxycombustion steam generator system for the Schwarze Pumpe plant Brandenburg, Germany. Source: Vattenfall

The UK’s Department of Energy and Climate Change (DECC) places a mandatory requirement on gas-fired power plants to be built ‘carbon capture ready’ so they can be retrofitted at a later stage. Tim Probert speaks to plant developer Intergen, carbon capture OEM Alstom, engineering group Foster Wheeler and the Crown Estate to find what CCR entails, and whether ‘ready’ will ever become ‘retrofit’. This article was published in the November/December 2011 issue of Gas Turbine World magazine.

The UK likes to think it is a world leader in carbon capture technology. To demonstrate its credentials the Department of Energy and Climate Change (DECC) launched in May 2007 a £1 billion ($1.6 billion) carbon capture and storage (CCS) competition to build a utility-scale, full-chain demonstration project, with the winner expected to be announced a year later. Nearly five years on, the competition remains open and the money remains unspent.

On 19 October, DECC pulled the plug on Scottish Power’s project to retrofit a 300 MW unit at the 2400 MW Longannet coal-fired plant in Fife. The official reason for the withdrawal of support for the project was a technical problem with the plan to transport CO2 from the flue at Longannet via a 280km converted natural gas pipeline to the St Fergus gas terminal in Aberdeenshire and then a further 100km to Royal Dutch Shell’s Goldeneye gas platform in the North Sea.

The competition rumbles on and the new favourite is not a coal-fired plant, but a gas-fired plant. British Energy Secretary Chris Huhne MP says SSE’s proposal to retrofit a 385 MW CCGT unit with post-combustion CCS at its 1180 MW Peterhead power plant would be achievable within the £1billion budget and a decision is expected in 2012.

UK gas-fired plants must be carbon capture ready

The UK is pinning its hopes on CCS because it is a vital cog in DECC’s plans to “largely decarbonize” the power sector by 2030 as part of the 2008 Climate Change Act’s legally binding target of an overall 80 per cent national cut in carbon emissions by 2050. As of 23 April 2009, all combustion plants with an electrical generating capacity at or over 300 MW must be ‘carbon capture ready’ (CCR).

Gas plants are no exception. In order to satisfy DECC and gain Section 36 planning consent, developers must ensure sufficient space is available on or near the site to accommodate carbon capture equipment in the future; demonstrate the technical feasibility of retrofitting their chosen carbon capture technology; identify a suitable area of deep geological storage offshore (onshore CO2 storage is currently prohibited) and demonstrate the technical feasibility of transporting the captured CO2 to the proposed storage site.

One such developer is InterGen, which gained Section 36 consent for the 900 MW Spalding Energy Centre in Lincolnshire in November 2010 and the 900 MW Gateway Energy Centre in Essex in August 2011. Is CCR merely an inconvenient box-ticking exercise to gain planning consent?

“Absolutely not,” says Peter Lo, Gateway Energy Centre project manager. “InterGen supports fully the aim of achieving a low-carbon economy and a technically proven and economically viable carbon capture solution is an important part of the low-carbon future of the UK.”

Lo says the feasibility studies for the Spalding and Gateway projects are based on post-combustion carbon capture technology using a chemical absorption method using amine solvents as it believes this is the best currently available technology suitable for scaling up to a size suitable for CCGTs. However, it does not expect to retrofit its CCGT plants until well into the next decade.

“Given the status of the technology and the demonstration projects and the advancements in such still needed, we consider that CCS could be retrofitted after 2025,” he says. In the meantime, new gas-fired plants like Spalding and Gateway will continue to be built ready for the day when the plant owners deem CCS to be economically viable.

What exactly is carbon capture ready?

There is a public perception that CCR is merely having a few spare acres of land. Not so, says Michael Ladwig, French carbon capture equipment OEM Alstom’s director of gas turbine product management.

“CCR is not just a patch of grass,” he says. “It’s a product we offer with all new gas turbine-based power plants, devised as a result of technical and economic research on potential problems arising from retrofits.

“It makes economic sense to make some technical changes to the CCGT plant to make it capture ready. One of the changes needed for CCR is a flue gas stack opening for the connection of the capture plant, covered initially with a cover plate. It might be wise to include that at the beginning.

“A carbon capture retrofit would generate some hot steam back into the condenser and this has to be fed into the water-steam cycle of the CCGT. Our analysis has shown that it would be highly cost-effective to install a baffle plate on the condenser from day one rather than be installed during the retrofit.

“The baffle plate would comprise less than 1 per cent of the cost of a combined cycle power plant and would not affect the performance of the power plant.” Upon completion of a new Alstom CCR gas-fired plant the plant owner receives a report to be sent to the authorities verifying that all components have been checked and that the plant is CCR.

Retrofitting gas-fired plants with CCS

A CCS retrofit requires the installation significant equipment such as CO2 absorption vessels, CO2 stripper column and a CO2 compressor. “We do not yet know how long it will take to construct the capture units and the associated building, as we have not yet built a full-scale capture unit, but I would expect it to take anywhere between 12 to 24 months from start to finish,” says Philippe Paelinck, Alstom’s director of CO2 business development.

“We would also have to tie in a connection to bring steam to the stripper column, and that’s where we might have to shut down the plant. I believe that this can be done during a scheduled maintenance period, probably a two-to-three week regular maintenance timeframe. We have not yet tested that but we think it’s realistic.

“As well as the space for the capture plant, there is also space reserved in the switchyard for additional transformers. There will be some downtime when you make those connections.”

While there are no changes necessary to the heat recovery steam generator (HRSG) itself, a CCS unit will cause an increase in the back pressure of the water-steam cycle. Alstom will return the steam from the plant and extract the steam from the steam turbine crossover pipe, which connects the CCS plant to the combined-cycle plant. This would need around 35 days of plant downtime to install, but the company says it could be done as part of a regular hot gas parts inspection process as not to further increase downtime.

Post-combustion CCS courtesy Vattenfall

Mitigating CCS efficiency penalties

It is well known that there is a heavy energy penalty imposed from the carbon capture process. Most of the penalty arises from supplying steam supplied to the CO2 stripper column and from the extra electricity needed to power the CO2 compressor, which pressurizes it to 100 bar.

“On a gas plant we expect a 10 to 15 per cent efficiency penalty in absolute terms, translating to an overall efficiency loss of 6-8 points for a 60 per cent efficient CCGT,” says Paelinck. To reduce the efficiency penalty Alstom is contemplating recycling parts of the flue gas to the inlet of the turbine to enrich the CO2 in the flue gas.

“We think it could have an impact on the capex to reduce the size of the required equipment, but maybe not so much the efficiency. The efficiency depends on the quantity of CO2 per megawatt needed to be removed and so there is little we can do to reduce that. The only option is to use better quality solvents, which could improve efficiency by a percentage point or two. It will be very difficult to reduce the efficiency penalty further with first-generation carbon capture technologies.”

Foster Wheeler trying to find efficiency mitigation solutions

Foster Wheeler has conducted a number of early project phase exercises looking at the impact of carbon capture on CCGT plant efficiency. A typical amine solvent carbon capture plant with CO2 dehydration and compression units may have more of an impact on efficiency than Alstom’s research suggests, according to Tim Bullen, Foster Wheeler’s CCS manager.

“We see a nine percentage point drop to around 51 per cent efficiency for a 60 per cent efficient CCGT operating at full load, depending on the CO2 capture rate and the discharge pressure for compression,” he says.

Foster Wheeler’s findings are based on performance simulations using in-house and public domain gas turbine performance and a generic MEA-based amine system, not on a particular proprietary licensed technology. “Whether you take Alstom’s solvent, Aker’s solvent or Mitsubishi’s KS1 solvent, they all have some slight differences in performance, but from what we’ve seen there is not a dramatic change.”

Bullen says the main contributor to the net reduction in power output results from the loss of steam turbine output, which is due to the steam extraction for the reboiler within the capture unit and the power required for CO2 compression, either from direct electric power or from steam. There are also further demands from smaller units like the gas blower, additional cooling loads and pumping the solvent.

Improved solvent formulation will help mitigate efficiency, says Bullen, but there are certain engineering solutions like improvements to CO2 compression techniques that will also reduce efficiency losses. However, these are likely to be relatively small on the overall impact on efficiency.

“We’ve looked at heat recovery to improve efficiency,” explains Bullen. “We’ve looked at waste heat that’s currently thrown away to cooling water to the CO2 compressor and using that heat within the CCGT to heat boiler feed water. These all help but they won’t achieve massive changes in efficiency in themselves.

Another problem to overcome is the additional pressure drop on the flue gas. “The general consensus is that you need a flue gas blower downstream at the HRSG, otherwise you end up back pressuring the gas turbine, which would impact its performance,” Bullen says. How the CCGT and the capture plant are laid out and their locations relative to each other will have an impact on the power required for the flue gas blower, he adds.

The challenges of CCS under part-load CCGT operation

A more pressing problem concerns the steam turbine and the need to extract low-pressure stream to regenerate the amine in the reboiler under part-load operations. Foster Wheeler is currently conducting research for an unnamed client into CCS operation at part-load for CCGTs.

“There are some challenges and considerations that need to be looked regarding the steam between the outlet of the medium-pressure turbine and the inlet of the low-pressure turbine sections,” Bullen says. “Under part-load, the pressure within the steam turbine will tend to fall while you still want to maintain pressure conditions to the amine system. This is a challenge.”

The challenges of part-load, CCGT flexibility and meeting grid code requirements are not a CCS-killer, but they do present a significant problem. “There are things you could do with the CCS system so that the grid code can be met. For example, you could shut down the CO2 compressor and export to the grid the auxiliary load saved, but there is an impact on doing that because then you’re not exporting CO2 to the pipeline.

“What’s the priority? Is it exporting CO2 or is it maintaining power supply to the grid? There needs to be some understanding of the overriding requirements of the plant and then design a system to work within those stipulations. We’ve done a lot of desktop studies and some early FEED work but no-one has taken the next step of putting kit on the ground.”

How much does CCS cost?

Unofficial reports suggested Scottish Power’s Longannet project fell through at the eleventh hour because it was asking for an additional £500m to complete the project, and the UK Treasury was not willing to spend more than the original £1 billion allocated. Alstom says CCS, whether on coal or gas plants, is competitive with alternative low-carbon technologies.

Paelinck says its reference plant puts the levelized cost of electricity for a state-of-the-art 600 MW CCGT power plant commissioned in 2015, integrated with CCS and operating in baseload, at €65/MWh ($86). Without CCS, the levelized cost of electricity for the reference plant is €43 per MWh, meaning the cost of CCS adds another 50 per cent.

Alstom cannot put a price on retrofitting CCGTs with CCS. “It would be highly dependent on location at whether the plant is capture ready or not,” says Paelinck. “Given our experience of retrofitting the water-steam cycle to open-cycle gas turbines, I would expect capex costs to be 15-20 per cent higher compared to a plant designed for CCS from scratch.”

Adding 15-20 per cent on the capex will translate to 10 per cent additional overall cost, says Ladwig, or approximately €70/MWh for a retrofitted CCGT with CCS.

Advanced amine carbon capture process

Making CCS pay

Alstom calculates that the cost of saving a tonne of CO2 emitted from CCS at €75 per tonne in 2015. The current carbon price is barely €9 per tonne and Paelinck admits that the chance of the carbon price rising to this level is extremely slim.

“Unless we have dramatic changes in European policy regarding the EU ETS, a utility’s decision to build a CCS plant won’t be based on the carbon price alone for the foreseeable future,” he says. “If you want CCS to start in 2015 on the back of a carbon price you need it to be €80-€90 per tonne to trigger investment, but on cost grounds it needs to be above €75 per tonne.”

Paelinck says the carbon saving costs of wind and solar are more like €150-€200, but thanks to feed-in tariffs these technologies are being deployed. “The UK’s Electricity Market Reforms, which will convert the Renewables Obligation subsidy scheme to a feed-in tariff with contracts for difference is a good option that will kick-off CCS on a competitive basis. Our customers will then look at CCS versus wind, solar or hydro.”

Even with dedicated government subsidies, the investment scenario for CCS is tough. The increasing penetration of renewables has dented the operational hours of fossil fuel power plants and utilities wishing to invest in new plant have a headache.

“Decision-makers will, slowly but surely, realise what’s going on and realise we need a price for decarbonized electricity that includes the costs of dispatch,” says Paelinck. “What we are proposing with CCS is to augment the capex of power plant in order to decarbonize, therefore exposing those plants to even more sensitivity to the number of operating hours.

“We’re probably going to see capacity payments made for fossil fuel backup plants. I can’t see any other way for our customers to invest in new plant.”

The problems of storing CO2

Once governments and industry have cracked how to monetize carbon capture, the other crucial element of CCS – storage – needs to be fixed. There is general impression that captured carbon dioxide can be easily transported across the existing natural gas pipeline infrastructure, swapping CH4 for CO2. That could be highly dangerous due to corrosive ‘dense phase’, pressurized CO2.

The problem is that CO2 captured from power plants always contains moisture. Wet CO2 is very acidic and the potential for corrosion, leakage and even explosions is such that dedicated CO2 pipelines made from expensive corrosion-resistant steel may have to be used.

Dr. Ward Goldthorpe, who heads up the UK Crown Estate’s CCS programme, says a huge amount of technical work needs to be done for regulating CO2 with impurities, i.e. water. “The regulatory framework is essentially adapted from the US petroleum industry, but a lot of CO2 transport in the US is pure CO2. Devising standards for the CCS industry that can cope with CO2 plus impurities is still a work in progress.”

Goldthorpe says the major stumbling block for CO2 storage from power plants is the lack of a viable business model. “Unlike the enhanced oil recovery (EOR) projects in the US, we are trying to implement in one fell swoop integrated CCS projects with no associated value proposition at all. The public funding is not prepared to underwrite the awkward risk-sharing and liability issues which pop out of the integrated model.”

Paelinck agrees. “We don’t have a business model for CCS in Europe because the carbon price is too low and the opportunities for EOR are quite scarce. We have some in the North Sea but it won’t be enough to supply the big market everybody dreams of. In the US the price for EOR is $20-$40 per tonne of CO2 but that’s not enough to justify CCS with gas.”

DECC says developing CCS is an “uncertain, potentially time-consuming, costly and risky business opportunity”. That is putting it mildly. If CCS is to become a viable commercial proposition then the various technical, regulatory and financial hurdles must be overcome. Just don’t expect CCS to be ready any time soon.

Potential scenarios of methane pollution from shale. Source: Nature, September 2011.

The British Geological Survey’s (BGS) study to establish levels of methane in groundwater in the UK will not include sites ‘fracked’ by Cuadrilla Resources in Lancashire.

These sites operated by Cuadrilla, which last year claimed that a 500 square mile area around Blackpool, Preston and Southport contains enough methane to meet national gas demand for at least 50 years, are the only current fracking sites in the UK. The firm halted drilling last May, however, after the BGS concluded fracking at Cuadrilla’s Preese Hall 1 shale gas well had likely caused two small earthquakes off the Fylde coast.

According to the BGS, evidence from the USA has shown very high methane concentrations in groundwater in areas of shale gas exploitation, which has been directly related to shale gas operations. Yet there is considerable uncertainty as to the source of methane and there is no baseline data on methane concentrations in groundwater before the onset of shale gas exploitation.

Last December the BGS commenced a year-long project to establish the baseline of methane levels in groundwater in seven areas: Northern Ireland; South Wales; the East Pennines (Cleveland Basin); the Wessex and Weald Basin in Southern England; the East Midlands, the Northumberland Trough; and Lancashire.

Cuadrilla Resources’ capped gas well in Cowden, Kent

However, according to Dr. Rob Ward, head of groundwater science at the BGS, the study will not include Cuadrilla’s existing sites despite its use of fracking to determine its estimate of 200 trillion cubic feet for gas in place in the Bowland Shale.

“We are not testing those specific areas,” he told Millicent Media. ”At the moment [Cuadrilla] is not exploiting shale gas, it has only drilled exploratory wells. This is a strategic survey to build up a national baseline against which environmental impacts can be assessed and appropriate management decisions taken if large-scale exploitation goes ahead.”

At each region, the BGS will identify 20-25 monitoring sites, such as boreholes, to take samples of groundwater. Once sampled, the BGS will test for concentrations of dissolved methane.

Dr. Rob Ward, head of groundwater science at the British Geological Survey. Source: BGS

If the BGS finds elevated levels, says Dr. Ward, it will conduct a more rigorous (isotopic) analysis to determine whether the methane is biogenic, which is usually produced from organic material in peatbogs, landfill etc., or thermogenic methane, which is produced from material buried at depth like shale.

“At the 2-4 km depths I anticipate shale gas will be explored and potentially exploited in the UK the methane will be of thermogenic origin, so it would have an isotopic signature which would enable us to disassociate it from, for example, landfill gas.”

Dr. Ward said the BGS started the study in South Wales in December.  Due to scarce resources, he says, the study is “limited” and has no official budget, with funds being reallocated from other projects. Just “five or six” people are working on the study, Dr. Ward added.

The study is, however, self-funded and independent. Dr. Ward expects sampling to be completed by the end of 2012, with a report due to be published in 2013.

Tilbury’s jetty on the river Thames, which can accommodate Panamax class vessels of up to 60,000 tonnes, saves an estimated £30 million ($47 million) per year in rail freight costs. Photo courtesy RWE npower

With legislation increasingly tough on coal-burning plants, many are switching to renewable fuels to ensure longevity. But supply chain issues may prevent some plants from undertaking the conversion process. Tim Probert profiles the UK’s Tilbury power station, a 1960s coal plant which has become the world’s largest biomass plant, and talks to Drax about the potential to convert its 4 GW coal plant. This article was first published in the January-February edition of Renewable Energy World magazine.

To describe the British town of Tilbury as a green beacon would require a stretch of the imagination. Home to London’s main container port and an unsightly 1960s concrete-slab power plant, with a curious smell emanating from the nearby sewage works, Tilbury epitomises twentieth century grit, smoke, soot and clank.

Yet a beacon of green energy is exactly what Tilbury power station has become. In December 2011, Tilbury B, a 1062 MW coal-fired plant opened in 1967, was successfully converted to a 742 MW biomass plant. Tilbury thus became the largest biomass burning power generation facility in the world, beating the previous coal-to-biomass record holder, GDF Suez’s 180 MW Rodenhuize plant in Belgium, by some distance.

Rather than invest in flue gas desulphurization and other emissions reduction measures, plant owner RWE npower opted Tilbury out of the European Commission’s Large Combustion Plant Directive (LCPD) in 2007, thus restricting the plant to a further 20,000 operating hours between 1 January 2008 and 31 December 2015.

Having conducted trials in September 2010 to prove the technical feasibility of burning biomass exclusively in a coal unit, RWE npower took the decision to convert the plant to biomass two months later.

Tilbury B generated its last kilowatt-hour from coal on 4 March 2011. In the nine months between coal and biomass generation, Tilbury’s engineering manager Dave Dyson worked frantically to ensure the plant can burn 2.3 million tonnes of wood pellets, enough for the remaining 8,000 hours, by 31 March 2013, when the number of Renewable Obligation Certificates (ROCs) allocated to biomass conversion plants reduces from 1.5 to 1.

A bold decision to convert to biomass

Dyson says the decision to convert Tilbury B to biomass was brave. “It was a bold decision by the board,” he says. “The cost of the conversion is in the tens of millions, but the value at risk is in the hundreds of millions.

“We had fixed price coal contracts and forward power prices set. Virtually all the power produced from coal was sold forward. We had to unwind all those contracts and the secure income. Instead we’ve taken on contracts for 2.3 million tonnes of wood without having proven we can use it.”

Burning coal, Tilbury would operate near baseload in the winter months of December, January and February, two-shifting in spring and autumn, with often no units running for weeks at a time in summer. Over the course of a year, this would amount to around 4,500 hours. In order to use up the 8,000 hours by 31 March next year and avoid a financial hit of around £20/MWh, however, Tilbury will run at sub-optimal periods, i.e. when the price of electricity is low.

“Dark spreads could be vastly lower than under a purely commercially driven aspect, but we need to burn the hours up,” says Dyson. “Our revenues from the power price may be barely above the ROC price.”

The Thames – Tilbury’s major advantage

The ‘design life’ of the plant may be only 8,000 hours, but surprisingly little has been spent on converting Tilbury from coal to biomass. The UK’s Drax coal power plant, for example, spent £80 million on new biomass burners, fuel conveying and filtering equipment plus a railway upgrade to co-fire up to 10 per cent biomass, or around 1 million tonnes a year.

Tilbury has one distinct advantage for biomass conversion: its own jetty on the River Thames, which can accommodate Panamax class vessels of up to 60,000 tonnes and saves an estimated £30 million a year in rail freight costs. Dyson’s biggest challenge is dust and most of the investment was spent on equipment that mitigates dustiness, including two new vacuum ship unloaders made by Vigan Engineering, as the existing Kone ship unloaders were too abrasive, an elutriator, and a dedicated pipeline which pneumatically conveys dust to the furnace.

“As with all biomass dusts,” says Dyson, “in the right concentration it is explosive and a sensitizer if inhaled. As far as possible, we derisk the transportation of the fuel by removing the dust at source rather than cleaning up afterwards.”

While coal is typically stored outdoors in huge heaps, biomass needs to be kept dry. Unlike Drax and other biomass co-firing coal plants, there is no virtually no biomass stored on site at Tilbury. The wood pellets arrive on a vessel and are unloaded and burned during the course of a week. Once the ship’s payload is empty and departs, another vessel arrives within hours and the process starts again.

Dyson explains: “We only store enough biomass onsite to see through the few hours where there is no ship on the jetty, around six hours’ margin, so we have to have a slick, just-in-time shipping turnaround. I suspect the fuel handling team will have significantly less hair by April 2013!”

Most of RWE npower's investment in converting Tilbury was spent on fuel handling. Photo courtesy RWE npower

Impact on efficiency and emissions

Due to the lower calorific content and bulk density of biomass versus coal, Tilbury’s generation capacity will be reduced by around 30 per cent to 742 MW, which in turn has reduced the thermal efficiency of the plant to 35.3 per cent from 37 per cent.

Physical changes to the combustion system are more tweaks than transformation; small modifications have been made to the fuel mills, feeders and burners. When biomass is put through the grinder, it splinters and chips, and does not break down into a standard size unlike coal, which is pulverized into fine dust. Combined with the lower calorific value of biomass, this causes the burners to respond differently.

Therefore, the plant’s low NOx burners have been modified to ensure a more stable flame and to minimize the required amount of support fuel, tall oil. This is achieved by creating a fuel mixing zone (and therefore the flame) nearer to the front of the burner.

Corrosion is also a potential engineering challenge. The high chlorine content in biomass will corrode and diminish the existing boiler fuel pipes.  As operation is limited to 8,000 hours, however, this is not expected to present a major problem.

Based on the results of the biomass trial in September 2010, Dyson expects NOx emissions to fall from 480 mg/m3 to 220 mg/m3, SOx to fall from 800 mg/m3 to 200 mg/m3, and the volume of ash produced from 40 kt/TWh to 4 kt/TWh. Lifecycle carbon dioxide emissions are predicted fall from 0.81 mt/TWh to 0.11-0.18mt/TWh, a 78-87 per cent reduction.

Tilbury & biomass – A one-off?

As things stand, Tilbury B will close once the 8,000 hours have been used up. In July 2010, RWE Npower submitted an environmental assessment scoping report to the UK Infrastructure Planning Commission for Tilbury C, a 2000 MW combined cycle gas turbine and 400 MW open cycle gas turbine plant.  This replaced RWE’s previous proposal to build a 1600 MW supercritical coal plant with carbon capture and storage (CCS).

RWE, however, is also considering the possibility of re-permitting and re-consenting Tilbury B to enable it to continue to operate as a dedicated biomass plant beyond the LCPD limit. “Phase II would be a completely different proposition and we won’t make a decision until well into the second quarter of 2012,” explains Dyson.

“Tilbury B would require a vast upgrade to meet more stringent NOx and SOx emissions standards and we will have to work out if biomass is commercially viable with just 1 ROC. It depends on plant and environmental performance.”

Dyson says the critical aspect of whether other coal plants in the UK and elsewhere can convert to biomass is fuel supply. “In theory there is no technical reason why other coal plants couldn’t replicate Tilbury but whether they could be as much of a commercial success is doubtful. The big question concerns fuel supply logistics.  Biomass is more expensive than coal and trying to get enough of it to an inland power station is a challenge. Most European plants will have the same problem.”

Getting wood

Around 30 per cent of Tilbury B’s biomass is sourced from RWE’s own 750,000 tonnes/year wood pelletization plant in Waycross, Georgia; a further 50 per cent will come from the USA and Canada. The remaining 20 per cent come from Europe, either the Baltic States or southern Europe. All fuel is debarked softwood pellets.

Dyson believes it is unlikely RWE will develop a similar biomass facility in Europe, much less the UK. “Sustainability is an issue in Europe. It doesn’t have the scale as the US. If we could source biomass sustainably in the UK we would do so, but there are no obvious opportunities to develop that at present.”

According to McKinsey, however, there is no shortage of sustainable biomass. In its World Biomass Energy Report 2009, McKinsey concluded there is enough land available for biomass to exceed currently mandated consumption levels by a factor of two by 2020, even after all other needs were met, i.e. food and feed crops; domestic firewood, projected demand from the forest products industry; no deforestation, and only environmentally sustainable use of virgin land.

And the market is beginning to respond to demand for biomass. In November 2011, the Dutch energy exchange APX-ENDEX launched the world’s first exchange for biomass. At present the Amsterdam-based exchange trades only non-cleared products where the physical settlement is arranged bilaterally by the counterparties. Phase two, however, scheduled to take place during the course of 2012, will include clearing services for wood pellet contracts, providing financial security to market participants.

The exchange has been developed in co-operation with the Port of Rotterdam, which is expecting a boom in biomass handling due to the Dutch Government’s Energy Report 2011 that will make biomass co-firing at coal plants mandatory. According to Koen Overtoom, commercial director of the Port of Amsterdam, the Netherlands, Germany, Scandinavia and the UK will require 15 million tonnes/year of biomass by 2020. Of that figure, Dutch ports will handle 13.5 million tonnes, up from 1.5 million tonnes at present, with the Port of Amsterdam alone accounting for 6 million tonnes.

Drax – a totally different conversion proposition

At 3960 MW, Drax is the second largest power plant in Europe. Unlike Tilbury, Drax complied with the LCPD, thus allowing it to run without restriction. In 2016, however, another European regulation, the Industrial Emissions Directive (IED), will force coal plants like to install selective catalytic reduction (SCR), which removes NOx from flue gases.

The cost of IED compliance for each of the plant’s six 660 MW coal units would probably run into the hundreds of millions of pounds. Throw in the UK Treasury’s carbon floor price/tax and full auctioning of Phase III European Union Emissions Trading Scheme (EU ETS) carbon permits and one can see why production director Peter Emery is considering other fuel options..

Drax currently co-fires up to 8 per cent biomass, burning approximately 1.2 million tonnes in 2011, mostly wood chips, straw pellets, oat and sunflower seed husks. Drax is now considering converting the entire plant to biomass. “When it became clear that UK government policy was not just pricing carbon into power production via the EU ETS but also the carbon floor price, we felt we had to do something radical,” says Emery.

“If we can’t compete in a world post-2016 with a very high carbon price we would opt out of the IED. Plants like Tilbury which opted out of the LCPD may just close rather than convert to biomass. Plants that opted in may find that the economics stack up. So biomass is a big deal for us, it will enable us to be competitive and enable us to develop the business.”

Drax is converting one of its 660 MW units to burn biomass. If it was to convert fully, says Emery, the capacity of each unit would be reduced to around 500 MW, each burning 2.5-3 million tonnes a year.

Sourcing this volume of biomass would be a major challenge. Drax is unable to source enough biomass at the right price in order to co-fire the permitted 12.5 per cent limit, let alone a 100 per cent conversion. “The biomass market isn’t there, and sourcing it is not as simple as having a group of traders with telephones,” Emery explains. “We’re having to negotiate deals to build pellet plants and set up shipping contracts, or encourage British farmers to grow miscanthus, willow or eucalyptus.

“Could we get hold of 15-18 million tonnes of biomass tomorrow? Yes, but biomass that has been harvested, pelleted and processed for power plants? Clearly not. Our challenge is to develop the supply chain, which may take 20-30 years.”

Drax wants the UK government to think again about reducing the amount of ROCs allocated to biomass conversions from 1.5 to 1. “There’s a massive potential for biomass to be industrialized in Britain and the ROCs would help us to develop the infrastructure. If the British government commits to a firm biomass policy over the 15-20 years, the rest will follow.

“For example, tree plantations use white wood pulp for paper and building materials but a lot of the offcuts aren’t used. There’s also an awful lot of land that is not agricultural grade not being used that would be ideal for biomass.”

Biomass silos at Drax power station, UK. Photo courtesy Drax

Conversion = Addiction to subsidy?

Based on 2010 generation of 26.4 TWh at an average power price of £51.60/MWh and burning 15m tonnes of biomass at £80/tonne, Drax could expect revenues (including 1 ROC) to comfortably outstrip the higher fuel costs by more than £500 million, even with a 25 per cent drop in output. Add in exemptions from buying EU ETS permits for carbon, of which Drax emits 22.8 million tonnes/year, and the carbon floor price, and biomass conversion looks attractive.

But converting to 100 per cent biomass would mean Drax would be reliant on subsidy to be commercially viable. Is it fair to ask British taxpayers to keep Drax alive this way? “This is about starting a brand new industry,” says Emery. “The idea is not to generate super profits versus coal, but to give an adequate return on investment for burning biomass.

“The government has got renewables targets to hit, it wants to reduce CO2 and the beauty of co-firing and unit conversion is that it’s cheap. It’s broadly half the cost of offshore wind and broadly in parity with onshore wind, but biomass is also fully dispatchable. The taxpayer would think that’s very fair.”

Is Drax doomed without biomass? “We are not doomed, but the direction of government policy means that coal-fired generation in its current guise is doomed. Biomass gives us a route to market with cost-effective low-carbon generation. So, yes, it is helping to save Drax, but would you rather spend double the money to build more wind farms and shut Drax?”

Keeping its options open, Drax is also exploring CCS and considering a combined cycle gas turbine plant on the site of the current facility. In the meantime, one would hope Emery’s prediction of 20-30 years to develop the biomass supply chain will prove to be a little pessimistic.

As REW goes to press, German utility E.ON has announced that it plans to convert one of two 500 MW at its coal-fired Ironbridge coal plant in the UK to biomass, with the option to convert the second unit at a later date. The utility has applied for planning permission to build a fuel store on-site. The plant chose to opt out of the LCPD, and will open in 2013.

Last year shale oil and gas firm Cuadrilla Resources obtained a license to commence exploratory drilling at Lower Stumble, 1 mile south of the village. A hardcover surface has been prepared, and a shallow hole has been drilled on the site.

Under the planning permission granted by West Sussex County Council, Cuadrilla has provision to use hydraulic fracturing at this test borehole. As part of the planning application the company states: “There may be a need to stimulate … by pumping water under pressure into the natural fractures in the shale formations to open them up to allow the gas to flow more freely.” In other words, fracking.

At the request of the ‘No Fracking in Sussex’ group, CEO of Cuadrilla Resources Mark Miller and his right-hand man, COO Eric Vaughan, agreed to speak at Balcombe village hall to answer questions about exploratory shale oil and gas drilling.

The meeting was not a formal consultation, but a voluntary public meeting. The village hall was absolutely packed. All 100 seats were filled, leaving standing room only for another 100-150 more in attendance. A Balcombe resident told me no more than half of the attendees actually lived in the village, with the rest seemingly environmentalists, ecologists and others of an ‘anti-fracking’ persuasion.

It was obvious from the start that most attendees were not overly enamoured with the prospect of their village becoming a fracking site and it didn’t take long before the meeting swiftly descended into an almost out-of-control verbal melee, an oratorical riot against fracking.

Difficult as it may be for Cuadrilla Resources to put across their point of view in such circumstances, they made a total hash of it. Although Cuadrilla stressed it had no firm plans to put its option to commence fracking in Balcombe into practice, very few believed them.

I came away thinking Cuadrilla’s plans to exploit the Weald Basin shale rock of Kent, Sussex and Surrey for oil and gas will be very tough and the meeting had only made an already stiff challenge more difficult.

I cannot imagine for a moment that a major oil firm would have engaged with the local population about so sensitive a subject in this fashion. Decent chaps they may be, but Cuadrilla came across as amateurs.

Should Cuadrilla ever decide to attend a similar public meeting in future, here are my top ten tips for not ‘fracking’ it up.

1. Don’t attend a public meeting about fracking when 99% of the local population had only heard about your plans a few days beforehand

Apart from the crack troupe of anti-fracking campaigners, barely anyone had a clue about what is planned in Balcombe. Such a melting pot of ignorance, confusion and anger does not make for rational, informed debate.

2. Don’t appear too American

The Chief Executive Officer and Chief Operating Officer of Cuadrilla Resources are American. Fair enough; the vast majority of global shale gas expertise is to be found in America. But Cuadrilla does have a British senior manager in Peter Turner, head of exploration, from Lancashire. There were a number of comments along the lines of ‘The Americans are taking over our village’. Doesn’t create a good impression in a deeply conservative West Sussex village.

3. Don’t bring along your PR guy who also happens to be a district councillor specialising in planning applications

Nick Sutcliffe, who represents Cuadrilla’s lobbying firm PPS Group, has lobbied the Department of Energy and Climate Change to garner political support for fracking. Mr Sutcliffe is also a councillor who serves on the planning committee at Guildford District Council. Again, doesn’t look good chaps.

4. Don’t allow the chairman to lose control of the floor

Poor Charles Metcalfe, a Balcombe resident of ten years, was unable to cope with the constant interruptions and interjections from an angry audience.

Miller couldn’t get through his highly informative and quite impressive PowerPoint presentation and during the tiresome Q&A, he was endlessly prevented from answering questions in full. Having to deal with all the questions flying around made the Cuadrilla representatives appear shifty, defensive and nervous.

5. Don’t forget to espouse the benefits to the local population

Unfortunately there was no straw poll to ascertain public support for Cuadrilla’s plans, but if there had the number of supporters would have been counted on one hand.

I can’t blame the villagers for their total lack of support for fracking. At no point did Cuadrilla make any mention of potential benefits to the community. No mention of jobs and other economic benefits. It seemed to be all take and no give. With no incentives, why on earth should residents be anything but vehemently opposed?

Mark Miller, CEO of Cuadrilla Resources, addresses a packed Balcombe village hall

6. Don’t come ill-prepared

Mark Miller repeatedly tried to assure the meeting that Cuadrilla had no firm plans to frack for oil and gas in Balcombe. But this very lack of a plan only aroused suspicion. If they had no plans, what were they doing there?

7. Don’t suddenly announce that you might have to build a power plant in the village if you find shale gas

Half-way through the meeting Miller said that, actually, Cuadrilla wants to frack for oil, not gas, using the undoubted success story of Wytch Farm in Dorset – which BP developed to be Western Europe’s largest onshore oilfield – as a role model. Great. What happens to the gas? “We may have to build a power plant onsite,” came the reply. Again, this does not impress an increasingly befuddled audience.

8. Don’t allow one-sided, polemic films about the “evils” of fracking to be shown immediately before you make your presentation

Bad move. Made the audience bay for Miller’s blood.

9. Don’t talk like a politician

The good folk of Balcombe became increasingly aggrieved when Miller qualified his virtually every statement with words like ‘possibly’, ‘probably’ and ‘potentially’.  Miller particularly got their goat when he began to start his sentences with ‘Typically…’.

10. Be prepared when the vice-chairman of the Parish Council admits it didn’t have a clue what it was doing when it approved the planning application for oil and gas exploratory drilling in its village without telling anybody

And also when the County Council senses that approving a shale oil and gas production license would be unpopular in the extreme and reassures the audience with promises that it now understands the full environmental implications of fracking and has powers to stop shale oil and gas production in the village.

The Balcombe Village Association says they plan to hold another meeting in the coming months. At this stage, I should not expect a return appearance from the CEO of Cuadrilla.

With financial backing from retailer Marks & Spencer and distribution by energy efficiency pressure group 10:10, the new book is being distributed for free to encourage Britons to launch carbon-cutting and renewable-energy projects in their local communities.

The Rough Guide to Community Energy is a ’how-to’ guide for community energy projects, covering everything from setting up a group to picking a renewable technology, as well as providing advice on finances and governance. The book features many case studies of community energy projects, including wind, solar PV, solar thermal, heat pumps, biomass, hydro, CHP and energy efficiency.

The book can be downloaded here: The Rough Guide to Community Energy (2.74 MB PDF; right click and select ‘Save target as…’ to download)

Printed copies are also available for the price of two first-class stamps and an A5 envelope. To receive a printed copy, simply send a self-addressed A5 envelope with two first-class stamps to the following address:

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Cuadrilla Resources claims there is enough methane in a 500 square mile area to fuel British natural gas demand for 50 years.

Shale gas has been called a game changer in the US but Europe will have a tough job emulating the US’ success, writes Tim Probert. This article first appeared in the December issue of The Energy Industry Times.

There is no question that shale gas has been a ‘game-changer’ in the United States. From virtually nothing ten years ago, shale gas now accounts for one-third of domestic natural gas production.

US energy policy has been turned completely upside down by shale gas. Having built a number of LNG terminals in recent years to cope with anticipated demand for natural gas, the US is set to be an exporter. LNG cargoes destined for the US have been redirected to Europe, while LNG terminal operators are considering converting regasification terminals into liquefaction terminals.

With enough shale gas to meet domestic needs for up to 90 years, gas-fired power plants have become the obvious choice to replace aging coal plants, which have been beset by a host of environmental issues. Furthermore, a plunge in the price of natural gas has made coal power even less attractive.

According to the US Energy Industry Administration (EIA), Europe has a shale gas resource of 2587 trillion cubic feet (tcf), enough to meet current consumption for 140 years. Will the same happen in Europe? Well, the short answer is possibly, but it will take some time for the industry to get up to speed. Here’s why. In contrast to ‘conventional’ gas extracted from porous rock, shale is relatively impermeable, meaning gas cannot easily move through the shale in which the well is drilled.

In order to release the methane, drillers use a method called hydraulic fracturing, also known as fracking, essentially pumping a large amount of water, sand and chemicals at high pressure. Shale gas developers use a technique called ‘pad drilling’, with up to ten drill wells radiating horizontally for distances of up to six miles from a single site, or ‘pad’.

This technique has been used for decades, but the improved ability to steer drillbits using off-the-shelf technology has made horizontal fracking cost-effective. The facility to perform surface data acquisition to locate gas in the rock, rather than drill right through the shale as previously, has also brought down costs.

Environmental concerns

However, fracking is not without problems. To some, the US shale gas industry has been reminiscent of the Wild West, a free-for-all where developers frack first and ask questions later. This is partly due to slack regulation – fracking is exempted from federal Clean Water and Safe Drinking Water Acts – and there is growing evidence that rivers and other water sources have been polluted.

As the fracking process takes place several thousand feet below the layers of aquifers, it is highly unlikely they will be polluted. However, the USA’s Environment Protection Agency has found that there is a serious risk of groundwater pollution from improperly constructed wells, i.e. where boreholes have not been cased with a steel pipe cemented in place. In Europe, stricter regulations should ensure boreholes are tripled-cased between the drill shaft and the acquifer, while the site will be protected by an impermeable membrane to guard against surface spills.

However, shale gas requires approximately 5 million gallons of water per frack and approximately one-third of this water is returned to the surface. This ‘flowback’ water typically contains the released gases from fracking; naturally occurring radioactive substances; metals; and volatile organic compounds like benzene, which easily vaporise into the air.

According to Veolia Water’s Karim Essimiani, the costs of treating the flowback water in the US ranges from up to $6/bbl for reuse or up to $24/bbl for discharge. This would translate to a water treatment cost of up to $3 million per frack, but Essimiani warns that due to deeper European wells up to three times more water may be required.

Tessa Davis, a London-based senior energy attorney at Linklaters LLP, says, “Regulation may affect the ability to economically recover shale gas. Water costs for shale gas fracking in Europe could be ten times higher than in the US, due to greater volumes and higher input costs.”

Image of a completed well pad with 10 wells (computer generated). Courtesy Cuadrilla Resources

How much is really down there?

In September Cuadrilla Resources, a UK joint venture between Australian drilling firm AJ Lucas and American private equity firm Riverstone, announced the Bowland sedimentary rock basin in Northwest England, for which it holds shale gas exploration licenses, holds a total potential resource of 200 tcf, or more than ten times existing UK natural gas reserves.

It must be stressed that the estimate by Cuadrilla, which is not a listed company and therefore not subject to usual Stock Exchange reporting criteria, is for ‘gas in place’ and not proven reserves. It is very much a ‘guesstimate’, more than 40 times the official estimate for the whole of the UK, calculated by multiplying the area of shale rock by an average figure of how much gas may be extractable from this particular type of shale.

James Elston, CEO of London-based shale gas developer Palladian Energy, says the most that could be realistically extracted from the Bowland shale is 20 per cent. That would be roughly equivalent to the Troll gas field in the North Sea, which holds 60 per cent of Norway’s gas reserves alone. “But they’ve only drilled two wells,” notes Elston. “Only when they’ve done seven or eight fracks over a wider area will we get a true idea of how much shale gas is down there and how much can be got out.”

The EIA estimates Poland as having an enormous shale gas resource of 187 tcf. Initial frack results, however, have been mixed. 3Legs Resources, which partners oil major ConocoPhillips in developing Polish shale gas, has lost two-thirds of its share price since floating in June 2011 due to disappointing flow rates.

The main problem appears to be a lack of suitable drilling equipment. Shale gas wells decline rapidly; Cuadrilla says the typical decline rate is 40 per cent within two years. To exploit the Bowland basin successfully, Cuadrilla may need to drill six to eight boreholes per square mile and up to 50 wells a year, at a cost of £10.5 million each.

According to Joseph Dutton, an unconventional gas analyst with Douglas-Westwood, the lack of suitable drilling rigs is the most important issue impairing shale gas production in Europe today. The UK-based consultancy forecasts European shale gas production to hit 1.2 tcf a year by 2020. This is based on a figure of 3,500 new wells drilled a year by 2020 from a total well stock of 15,000 wells.

Due to the very high decline rates of shale gas wells, however, the industry will need to spend a $1 billion on drilling to hit this production rate. Money which, says Douglas-Westwood unconventional gas analyst Joseph Dutton, is simply not currently available unless investors are “firmly convinced” of the business case.

“Despite the hype, shale gas financing is on a knife-edge,” he said. “For it to really take off there needs to be a great deal of capex and opex to invest in drilling and drill rig, but a lot of companies are sitting on their hands. There are big bucks to be made from addressing drilling rig issues.

“Deep, multiple-stage fracking ideally requires a drilling rig with at least 2000 brake horsepower (BHP), but we’ve identified only 78 rigs in Western Europe, 49 of those have a rated torque of less than 1,500 BHP, 17 have between 1,500-2,000 BHP and only 12 with greater than 2,000 BHP.”

Palladian Energy’s Elston is optimistic the drilling issues will be overcome. “Unlike pressure pumping which is dominated by Halliburton, Schlumberger and Weatherford, shale gas drilling companies can be formed by anyone as long as they can demonstrate competency. Onshore drilling is not all that different from offshore drilling and Europe has a tremendous human resource base of competent drilling engineers working in the North Sea. There will be no capital restraints, as there will be plenty of US private equity and European public market equity available for the right projects.”

The Oxford Institute for Energy Studies cost estimates for natural gas production in 2020.

Impact on gas prices

There is fear among environmentalists that shale gas will derail plans to decarbonize the power sector by choking investment in renewables and nuclear. The argument goes that shale gas, and therefore gas-fired power generation, is ‘cheap’, so there is no need to build expensive wind farms, solar panels or nuclear reactors.

European shale gas production costs, however, will remain far above conventional natural gas resources. According to the Oxford Institute for Energy Studies, Polish shale gas production costs in 2020 will be four times more than pipeline natural gas from Algeria and twice that of imported LNG from Qatar.

While in the US shale gas recovery has driven gas prices below their traditional oil-linked levels, the complex nature of European gas markets mean that oil indexation in gas contracts will remain for the foreseeable future.  Elston says, “Rabid proponents who say shale gas will lead to lower natural gas prices are being disingenuous. What it does is offer a subsidy-free energy source with security of supply, jobs in depressed areas and government revenue, but it won’t change the need for zero-carbon sources of energy.”

Shale gas is not the environmental catastrophe some NGOs would like us to believe. Equally, shale gas is not quite the “cheap and abundant” source some proponents say. The shale gas ‘revolution’ appears to be not quite so revolutionary. At least, not yet.

]]> http://millicentmedia.com/2011/12/23/europe-will-have-to-dig-deep-for-the-shale-gas-dream/feed/ 0 shale gas well drilling timprobert shale gas well drilling Image of a Completed Well Pad with 10 wells Shale Gas Costs