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 Kone ship unloaders, as the existing ones 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.

Around 250 attended the Balcombe Village Hall fracking meeting on 11 January

Last night I enjoyed the spectacle of a shale gas public relations car crash in the charming West Sussex village of Balcombe.

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. Since then, 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.

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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 http://millicentmedia.com/2011/12/08/drilling-through-the-spin-uk-shale-gas-exploration/ http://millicentmedia.com/2011/12/08/drilling-through-the-spin-uk-shale-gas-exploration/#comments Thu, 08 Dec 2011 16:20:12 +0000 timprobert http://millicentmedia.com/?p=742 Continue reading »]]>

Shale gas pad drilling. Courtesy Statoil

Cuadrilla Resources, Britain’s first shale gas exploration license holder, claims a 500 square mile area around Blackpool, Preston and Southport contains enough methane to meet national gas demand for at least 50 years and create thousands of jobs. Proponents say Cuadrilla’s resource is revolutionary, opponents say shale gas is unnecessary. Who’s right? Tim Probert digs deep for the answer. This article first appeared in the December 2011 issue of Materials World.

2011 will go down in history as a year of revolution. Tunisia. Egypt. Libya. Blackpool… Blackpool? If Cuadrilla Resources is to be believed, this may not seem so brash.

On 21 September, Lichfield-based Cuadrilla, a joint venture between Australian drilling firm AJ Lucas and American private equity firm Riverstone, announced a 500m2 area of the Bowland sedimentary rock basin in West Lancashire, for which it holds shale gas exploration licenses, holds a total potential resource of 5.66 trillion m3 of gas, or more than 10 times existing UK natural gas reserves.

This figure came as a shock to the British Geological Survey (BGS), which officially estimates shale gas resources for the entire nation at 150 billion cubic metres. Cuadrilla said this volume of methane would meet UK natural gas demand for 56 years, lead to £120m in business rates being paid to local councils over 30 years, £5-6bln in tax revenues for the government, and up to 5,600 new jobs created with an average salary of £55,000.

This shale gas El Dorado is found predominantly to the west of the M6 motorway and includes the towns of Southport, Preston and Blackpool, some of the most economically deprived areas of the UK. Since Cuadrilla’s announcement, there has been a plethora of media reports focusing on how shale gas is a potential ‘game-changer’, a lifeline in hard economic times similar to North Sea oil in the 1970s and 1980s.

Bowland Shale Exploration License Area 1. Preese Hall. 2. Grange Hill Farm. Courtesy Cuadrilla Resources.

Much like nuclear power, the shale gas industry has more than its fair share of supporters and opponents. Prominent former Chancellor and energy minister, Nigel Lawson, calls shale gas ‘the most exciting technological development I can recall’. Others, particularly environmental non-governmental organisations (NGOs), are less keen. Concerned about environment degradation and the impact on renewables investment, WWF has called for an outright ban.

The Bowland shale dates from the Carboniferous Period 363-290 million years ago. In contrast to conventional gas extracted from porous rock, shale is relatively impermeable, meaning gas cannot easily move through the shale the well is drilled in.

Getting down to it
In order to release the methane, drillers use a method called hydraulic fracturing, also known as fracking, which essentially involves pumping a large amount of water, sand and chemicals at high pressure. Cuadrilla intends to use a technique called pad drilling, with up to 10 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.

It must be stressed that Cuadrilla’s figure of 5.66 trillion cubic metres is for ‘gas in place’ in the Bowland basin and not proven reserves. It is very much an estimate, 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 consultancy Palladian Energy, says the most that could be realistically extracted is 20%.

That would be roughly equivalent to the Troll gas field in the North Sea, which holds 60% of Norway’s gas reserves. ‘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.’

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

Standing in the way of development

Despite the huge potential reserves of shale gas in the Bowland basin and elsewhere in the UK, there are many factors that may hamper development – firstly, the huge controversy over fracking. Cuadrilla was forced to halt drilling in May when the BGS suggested fracks at depths of 2.0 and 2.7 kilometres caused two small earth tremors with magnitudes of 2.3 and 1.5 on 1 April and 27 May respectively.

Cuadrilla met with the UK’s Department of Energy and Climate Change (DECC) on 13 October to discuss how the developer intends to mitigate the risk of earthquakes. DECC is currently evaluating the report in tandem with the BGS before it will allow fracking to resume.

There is also considerable concern over the impact on water supplies. Cuadrilla expects to use 13,000m3 (1,000 for the drilling process, 12,000 for fracturing) per well in a six-well pad. Of this volume, equivalent to five Olympic swimming pools, approximately one-third returns to the surface.  Cuadrilla’s fracking fluid consists of 99.75% water and sand, with the remaining 0.25% comprised of three additional ingredients: a friction reducer called polyacrylamide, a biocide to purify water and a weak hydrochloric acid to help open the perforations to initiate frack fluid injection.

As the fracking process takes place several thousand feet below the layers of aquifers, DECC believes it is highly unlikely they will be polluted. However, the USA’s Environment Protection Agency has found there is a serious risk of groundwater pollution from improperly constructed wells, for example where boreholes have not been cased with a steel pipe cemented in place. Cuadrilla says its boreholes will be triple-cased between the drill shaft and the aquifer, while the site will be protected by an impermeable membrane to guard against surface spills – see diagram:

Bowland shale well schematic. Courtesy Cuadrilla Resources

Due to UK ownership rights, where mineral rights belong to the Government and not the landowner, DECC expects shale gas development to be relatively limited. Shale gas drillers have to obtain an exploration license from DECC, but it is up to local councils to allow developers to exploit the shale. This may limit shale gas development in less economically deprived areas such as the Weald Basin, which covers Kent, Sussex and Surrey.

Energy minister Charles Hendry MP says, ‘Getting permission from property owners and landowners will be challenging. Visually, however, these are not intrusive facilities and are of a short-term nature. I think people can be persuaded about shale gas for the wider national good and local benefits in terms of job and wealth creation.’

Spot the difference
The Bowland basin is often compared to the vast Barnett shale in the USA, which provides five per cent of US gas supply, as they are both Carboniferous rock. As Abhen Panther, Senior Geologist with Henley-on-Thames’ RGS Energy, explains, there are some very important differences.

‘The Barnett shale has flat, plane-like deposits. The drilling can go on for miles, flat, in one direction with a good chance of intersecting the shale gas. The Bowland shale is a narrow shoestring rift basin characterised by typical rift scale tectonics. This geology needs complex multi-lateral wells with fancy footwork in order to hit the target.

‘Bowland shale is thicker than anything in the US, where gas reservoirs are typically 100 metres thick. Rift basins are very thick, with gas reservoirs up to around 1,000 metres. That’s why Cuadrilla is quoting 200 trillion cubic feet, but whether they can get it out is a challenge.’

Shale gas wells decline rapidly – Cuadrilla says the typical decline rate is 40% 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 £10.5m each.

The lack of suitable drilling rigs, however, is the most important issue impairing shale gas production, according to Joseph Dutton, Unconventional Gas Analyst at Canterbury-based energy researchers Douglas-Westwood. Deep, multiple-stage fracking ideally requires a drilling rig with at least 2,000 brake horsepower (BHP), says Dutton.  ‘We’ve identified only 78 rigs in western Europe, 49 of those have a rated torque of less than 1,500 BHP, 17 have 1,500-2,000 BHP and only 12 with greater than 2,000 BHP. There are big bucks to be made from companies able to step in and address drilling rig issues.’

Bowland shale full-time jobs generated by three test wells. Source: Regeneris Consulting.

Those who assume shale gas production will suddenly explode, as in the USA where it accounts for around a quarter of natural gas supply, may be disappointed. The UK may not become a significant producer of shale gas until 2020, says Dutton, as costs of production are around four times more than pipeline natural gas and twice that of imported LNG.

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, it is not quite the cheap and abundant source some proponents say. The shale gas ‘revolution’ appears not to be quite so revolutionary. At least, not yet.

Vattenfall was to retrofit a 250 MW coal unit with post-combustion CCS and build a new 250 MW Oxyfuel unit at a cost of €1.5 billion. Courtesy Vattenfall

Swedish power utility Vattenfall has abandoned a planned 500 MW carbon capture and storage (CCS) plant at Jaenschwalde, Germany, expected to cost €1.5 billion, after the German federal government rejected a bill allowing underground carbon storage.

The 500 MW CCS demonstration project was to utilize a new 250 MW Oxyfuel boiler and see another 250 MW boiler retrofitted with a post-combustion capture unit. The EU-supported project would have been operational by 2015/16.

In July, Germany’s lower house approved a bill allowing the underground storage of carbon dioxide but it was rejected by the upper house on September 23. Following the rejection of the bill by the Bundesrat, a mediation committee was formed, which adjourned twice in November without result.

In a statement, Tuomo Hatakka, Vattenfall´s country manager for Germany, said: “We must unfortunately accept that there is currently insufficient will in German federal politics to implement the European directive so that a CCS demonstration project in Germany could be possible.”

Hatakka said that a clear legal framework was needed and the existing draft for the CCS law is, without substantial improvement, insufficient for multi-billion investments in further development of carbon capture technology.

The Swedish state-owned utility said it would continue to further development of CCS. Vattenfall is a main partner in UK’s largest CCS pilot plant at Ferrybridge Power Station in West Yorkshire, which opened 30 November.

The company said it will also continue the test operation of the CCS pilot plant at Schwarze Pumpe, Germany, and work for the development of a European storage infrastructure.

Map of the Caprivi Link Interconnector between Zambia and Namibia. Copyright ABB.

The Caprivi Link ensures reliable power transfer capability between the east and west of the Southern African Power Pool. Tim Probert takes a first-hand look at the link, which is ABB’s first HVDC Light installation built with overhead lines and is also the highest rated and longest system of its type currently in operation. This article was first published in the December 2011 issue of The Energy Industry Times.

Seven out of the world’s top ten fastest-growing economies are in sub-Saharan Africa. Much of the economic growth is being driven by mining, which needs power.

The high rate of economic growth means state utilities are constantly playing catch-up. The vast, sparsely populated nation of Namibia, where demand for power is expected to nearly double by 2014 as new mining operations come on stream, is a prime example.

NamPower is a tightly-run ship, which notched up a steady profit of $45 million in 2010 and it does not have to instigate load-shedding, as suffered in so many African nations.

Yet the 100 per cent state-owned power generation and distribution monopoly suffers a significant power generation shortfall. NamPower is only 46 per cent self-sufficient in power generation, with imports accounting for the remaining 54 per cent, of which 22 per cent is supplied by South African state utility Eskom.

Maximum demand is 511 MW, but capacity totals just 415.5 MW, including the 249 MW Ruacana hydro plant, the 120 MW Von Eck coal plant and two diesel-powered plants of a combined 66.5 MW. Furthermore, low water flow in the Kunene River at the Angolan border has impaired generation at Ruacana, while outages at Eskom’s Koeberg nuclear plant near Cape Town have left Namibia on the brink of blackouts.

NamPower is desperate to build a baseload, fossil fuel power plant, but plans for a 300 MW coal plant in Walvis Bay have been rejected, while an ambitious plan to build the integrated Kudu gas-to-power project, involving a floating gas platform 170 km offshore and an 800 MW combined cycle gas turbine plant in Oranjemund, requires some $2 billion, equivalent to 15 per cent of GDP.

So, in need of a quick fix, NamPower turned to ABB to construct the Caprivi Link, a 950 km overhead high voltage direct current (HVDC) line which runs along the narrow, tropical Caprivi Strip in extreme northeast Namibia.

While technically not an interconnector due to the converter stations being located solely in Namibia, the +300 MW, 350 kV Caprivi Link connects the Zambezi substation near Katima Mulilo, close to the Zambian border, with the Gerus substation near Otjiwarongo, around 300 km north of the Namibian capital Windhoek. The link, for which construction began in March 2007, also connects to the 220 kV HVAC transmission line from the Victoria Falls in Zambia inaugurated in 2008.

Bird's-eye view of the Zambezi substation of the Caprivi Link. Copyright ABB.

The aim of the Caprivi Link is to ensure reliable power transfer capability between the east and west of the Southern African Power Pool (SAPP). It is also the first electrical connection between the Caprivi region of Namibia and the rest of the country, and is able to supply power to the region if normal supplies from Zambia are disrupted.

Larger islanded parts of the Namibian and Zambian grids can also be supplied by the link, which maintains frequency control and thereby avoids power outages.

The Caprivi Link is somewhat of a curate’s egg. Rather than opting for cheaper HVAC or traditional HVDC, NamPower opted to utilise ABB’s HDVC Light, the Swiss firm’s brand name for HVDC with voltage source correction (VSC). HVDC Light is usually the reserve of underground or subsea links of far shorter distances, and as such it is ABB’s first installation built with overhead lines.

At 350 kV, it has the highest operating voltage for an HVDC Light system and at 950 km, is also the longest system currently in operation. Commissioned in June 2010, the Caprivi Link was jointly funded by NamPower, the European Investment Bank, the French Development Bank and the German Development Agency (KwF). Of the total N$3.2bn ($391m) cost, $180 million was booked by ABB.

The decision to use HVDC Light was made because the AC networks connecting with the HVDC Light converter stations are extremely weak at both ends, with short-circuit power levels of around 300 MVA and long AC lines connecting to remote generation stations. As a result, the AC networks are exposed to a risk of 50 Hz resonance.

Manfred Manchen, NamPower’s director of power system studies, says these factors made the design of the Caprivi Link extremely challenging. The key to achieving the desired performance under different AC network configurations, says Manchen, was robust voltage and frequency stabilising control for the connected AC network in conjunction with sufficient damping of DC resonance.

Instead of using traditional feedback active power control, frequency control, and power runback systems as installed in other HVDC Light projects such as the Gotland project in Sweden and the Finland-Estonia Estlink project, a determined direct voltage and frequency control is deployed via ABB’s turn-on/turn-off insulated gate bipolar transistors (IGBT) power semiconductors.

The basic insulation levels at 350 kV DC compare quite closely with those at 400 kV AC, resulting in the assembly configuration and insulators being identical to those specified for standard 400 kV AC line designs. Without any feedback control loop, the HVDC Light system automatically changes the active power needed to keep power balance within the islanded grid so the frequency is stabilised, automatically changing the reactive power needed to keep the AC voltage at the desired level.

The VSC functionality has proved to be an effective tool in maintaining grid stability. During commissioning of the link, an AC breaker failure occurred in the Zambian grid at a time when 50 MW was being exported from Zambia to Namibia, resulting in a frequency drop in the Zambia grid of 4 Hz.

The HVDC Light system identified the critical situation and quickly changed power flow from exporting 50 MW from the Zambezi substation to importing 60 MW from Gerus.This enabled the Zambian grid frequency to recover immediately to 50 Hz, thus avoiding a blackout.

On an occasion when 80 MW was being exported from Namibia to Zambia, an overload protection tripped a 220 kV line in NamPower’s 220 kV bus-zone, which led to a sudden island condition in the Namibian grid. The sudden outage of the line led to a large frequency dip in the Namibian grid.

The Gerus substation immediately reduced the power exporting from 80 MW to almost zero and automatically switched from DC voltage control mode to voltage and frequency stabilisation control. The Zambezi substation then switched from tracking the power order to DC voltage control. About one second after the contingency, says Manchen, the Namibian grid had restored stable AC voltage in both frequency and magnitude.

Gerus HVDC Light station surge arrester columns in AC hall. Photo: Roger Bull

At present, the Caprivi Link has proved more useful as a grid stabilisation tool than as an interconnector to boost power capacity. As Manchen said: “In the worst case of disturbances when all generators are tripped in the island grid, the link can function as a super UPS (Uninterruptible Power Supply) to feed the passive loads.”

The link has not been without problems. It has been plagued by rats, for which dozens of traps have been laid at both the Gerus and Zambezi substations. “They’ve taken a liking to the fibre-optic cable insulation,” explained Manchen. “They ate so much of it that we’ve had to use a different, less tasty type of cable. There are some things that you just can’t plan ahead for!”

Rodent issues aside, the link is not used to its full potential. Power flow is only one-way and the link significantly under-utilised. Due to the weakness of the AC grid in Zambia, only 50 MW is being transmitted, mostly hydropower from the Victoria Falls, representing just one-sixth of the link’s 300 MW capacity.

Zambian hydro plants continue to break down and cause the link to fail. However, the link’s VSC system means that generators at Zambia’s Victoria Falls hydropower plant are able to run through fault conditions for the first time, according to Reiner Jagau, chief officer of NamPower’s power system development.

The link is marketed as a key southern African interconnector, but that will only be true once Phase II is commissioned. Phase I, commissioned in 2010, is a +300 MW monopole link operated with parallel DC lines and earth return to reduce line losses. Phase II would consist of upgrading the converter stations at Zambezi and Gerus substations to a ±600 MW bipole link with zero ground current.

NamPower would also have to strengthen its AC grid, as Gerus is currently connected to the Auas substation near Windhoek only indirectly via 220 kV lines to the Omburu substation in western Nambia, from where it spurs southeast to the capital.

This would mean building a 280 km, 400 kV line from Gerus to Auas. NamPower is in negotiations with Eskom and Zambia to build Phase II, but the project has an indefinite timeline, and estimates put the commission date at 2016 at the earliest.

Another key element of Phase II is the need for a 320 kV link between Zambia’s Victoria Falls and the Hwange coal plant in Zimbabwe, for which NamPower has invested in a $40 million repowering in return for 150 MW of power capacity for five years. This line is a key part of the regional interconnection programme known as ZIZABONA (ZImbabwe, ZAmbia, BOtswana and NAmibia), but again progress is slow due to a lack of available funds in Zimbabwe.

The Caprivi Link will thus remain a useful tool to maintain grid stability and import some Zambian power but, until Phase II is commissioned, its designated function as a two-way interconnector to facilitate power trading with the rest of southern Africa will remain limited.

]]> http://millicentmedia.com/2011/12/02/shedding-some-light-on-namibia/feed/ 0 Map of the Caprivi Link Interconnector between Zambia and Namibia. Copyright ABB. timprobert Map of the Caprivi Link Interconnector between Zambia and Namibia. Copyright ABB. Bird's-eye view of the Zambezi substation of the Caprivi Link. Copyright ABB. Gerus HVDC Light station, situated in central Namibia. Surge arrester columns in AC hall. Copyright ABB. http://millicentmedia.com/2011/12/02/point-carbon-slashes-phase-iii-eu-ets-carbon-price-prediction-by-e10tonne-on-eurozone-woes/ http://millicentmedia.com/2011/12/02/point-carbon-slashes-phase-iii-eu-ets-carbon-price-prediction-by-e10tonne-on-eurozone-woes/#comments Fri, 02 Dec 2011 12:57:00 +0000 timprobert http://millicentmedia.com/?p=719 Continue reading »]]>  

Point Carbon predicts an average EU ETS carbon price of just €12/tonne for Phase III

The average EU Allowance (EUA) price in the third phase of the EU’s Emissions Trading Scheme (EU ETS) will be €12/tonne, predicts Thomson Reuters Point Carbon.

The most depressed price levels will probably be seen in the 2013-2015 period when the average price of EUAs could drop to as little as €10/tonne before rising again in the 2018-2020 period, reaching €16/tonne in 2020 on the basis of a tightening supply-demand balance.

The €12/tonne figure is €10/tonne less than Thomson Reuters Point Carbon’s July 2011 forecast and barely more than a third of the forecast issued this time last year.

“The main reason for this drastic change is the global economic crisis which has multiple impacts on the global carbon market”, explains Anne Kat Brevik, Commercial Manager at Thomson Reuters Point Carbon.

“Not only do we see industrial output and associated emissions down – we predict by some 700 Mt for the period up to 2020 – but also we see governments recoiling from taking tougher climate action in the wake of domestic economic hardship”. Just four months ago it seemed likely that the EU would adopt a 25% emissions reduction target for 2020, “however, the new forecast is now based on a 20% emissions reduction scenario, which we consider a more realistic outcome given today’s severe sovereign debt crisis in the EU, resulting in the market being long in EUAs in the third phase”, she said.

However, any final decision on the overall emissions reduction target will likely not be taken before the start of phase 3, and the option to agree on a 25% target will most likely remain on the table for the next few years.

According to Marcus Ferdinand, Senior Carbon Analyst at Thomson Reuters Point Carbon, “despite these very gloomy predictions, we do not expect prices to deteriorate further in the short term, partly because the power and heat sector still needs to buy credits on a continuous basis in order to back-up their future power sales and partly because as long as a possible move beyond a 20% target still exists, we assume that this inherent uncertainty will deter the industry sector from selling off their entire length.

“As the emissions trading scheme continues beyond 2020, with a steadily decreasing allocation, operators can also bank allowances to meet future compliance needs instead of selling off the surplus at low prices in the short term”.

That said, if the current debt crisis does lead to financial markets drying up, pronounced industrial selling would likely ensue as industrial installations attempt to monetize their EUA length in order to boost cash flow. “If such a situation should materialize, we could see a further substantial drop in EUA prices”, Ferdinand conceded.

Paulinus Shilamba, managing director of Namibia's state power utility NamPower

Namibia will tender in January a $1 billion, 800 MW combined-cycle gas turbine (CCGT) power plant project as part of a novel gas-to-power project which will be the southern African nation’s largest ever engineering project, according to head of state utility NamPower.

The integrated $2 billion gas-to-power Kudu project, equivalent to 15 per cent of national GDP, will be located in Oranjemund, south-western Namibia, on the South African border. Gas would be sourced from a $1 billion floating gas platform 170km offshore in the Atlantic Ocean, from where the fuel would be extracted at a depth of 4500 metres under the seabed.

Paulinus Shilamba, managing director of Nambia’s power generation and transmission monopoly, said the 800 MW Kudu CCGT, which would virtually double NamPower’s existing power plant portfolio, will serve as a regional power plant. “We expect 400 MW to be consumed in Namibia, 100 MW in Zambia with the remaining 300 MW in South Africa,” he told Millicent Media.

NamPower is close to finalizing the government strategic support paper for the project, with submission due by the end of November. The tenders for the engineering, procurement and construction (EPC), operations & maintenance (O&M) and strategic equity partners (SEP) contracts will then be put out in January. Shilamba said the project would be formalized in June 2012.

Reiner Jagau, chief officer of NamPower’s power system development, said: “800 MW would virtually double the current capacity of NamPower, which brings huge risks. It will be a challenging project and we need government support.”

Shilamba said the Kudu plant, which could be online by 2016, would be built on a public-private partnership basis, with NamPower taking a 51 per cent stake and the remaining 49 per cent farmed out to the private sector. The head of NamPower added that there is strong interest in the project from Eskom, South Africa’s power utility, and Zambia’s Copperbelt Energy Corporation.

Namibia is only 46 per cent self-sufficient in power generation, with imports accounting for the remaining 54 per cent, of which 22 per cent is supplied by South African state utility Eskom.

Namibia’s current grid-connected power capacity currently totals 415.5 MW, including the 249 MW Ruacana hydro plant, the 120 MW coal plant and two diesel-powered plants of a combined 66.5 MW. A 90 MW expansion of the Ruacana hydro plant is due to be commissioned in March 2012.

A government White Paper stipulates that Namibia must eventually become 100 per cent self-sufficient in power generation and 75 per cent for all energy needs.