Pimagazine Asia

ASIA’S LEADING POWER REPORT

VOLUME 3, ISSUE 4

ORIGIN

Excusiv : Capacit e Reviewy

Wastewater Projects in Australia

Ahead of the Curve: The Asian Gas Turbine Market

Wonthaggi Desalination Plant: Insurance or White Elephant? SEE PAGE 18

AUSTRALIA DROWNING IN DEBATE RT

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PEC I AL R

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• P. I . S P

• POWER IN MINING • NUCLEAR ROADMAPS IN SOUTHEAST ASIA • AUSTRALIA AND ATTITUDES TO RENEWABLES

P.I

INCLUDING:

IAL REPO

Fuel Cells and the Asian Market:

Hydrogenics, Indonesia, and More

A Big Thank You from PI Magazine

The Australian people are deeply invested in their country’s energy choices

I’d like to begin the July-August edition of Power Insider Asia by saying a big thank you to everyone who has given us such great feedback on our new look. Reading all your comments has been a very positive experience, as well as seeing the interaction on our social media platforms. If you want to get involved, what are you waiting for? Search for Power Insider Asia Magazine on LinkedIn, Twitter and Facebook to get involved in the debate.

Debate is a word that sums this issue’s feature nation: Australia is constantly debating about energy. The energy market in Australia is different to most of the countries we profile; for a start, there is no requirement to add capacity, with the energy demand actually dropping in Australia. The energy market drivers in Australia revolve around keeping tariffs low, reducing carbon emissions, and investing in renewables to phase out fossil fuels. All noble goals, but one of Australia’s key economies is the mining and export of coal, gas and oil, and with such an abundance of natural resources, hydrocarbon fuel generation is cheap in Australia. This is the main focus of Australia’s energy debate: have a greener, more expensive energy market, or maintain the bottom line?

Another aspect that differentiates Australia is the participation of the public in this debate. This isn’t a conversation going on in industry boardrooms with a few angry environmentalists outside; the Australian people are deeply invested in their country’s energy choices. This is partly to do with the environment; most would like a stable energy future and less carbon, but mostly it’s to do with cost.

Energy prices have tripled recently in Australia, and many are blaming increased investment in renewables and the infamous carbon tax. People’s interest in energy is no bad thing, but the result is that energy is now a political issue.

This leaves decisions about where energy should come from and what it should cost in the hands of policy makers, and

has become such a vote splitter that discussions on power are plagued with political in-fighting, often at the cost of clear and reasonable information.

All of this has presented PI Magazine with a complex power scenario we don’t normally face – one that is intimately linked with the consumer. It is this melee of voices that we are seeking to contextualise and explore with this issue. Our first country focus looks at how renewable energy is perceived in Australia, which is accompanied by a fascinating interview with MWH on Australia’s energy attitudes. Our second country focus looks at desalination; an essential infrastructure feature in arid Australia, and a victim of the same discussion: expense versus sustainability.

A feature on power use in mining discusses the negative effect of the carbon tax, and we asked South Australia Water to tell us more about Australia’s desalinated and recycled water use.

Other fantastic features in this issue of PI Magazine include a focus on the gas turbine market, with a useful overview of market drivers in Asia from Alstom, an exploration into Origin Energy’s fleet of gas powered plants, and Vokes Air and Sulzer talk to us about maintenance and servicing. We talk about fuel cells with Hydrogenics, and look at applications in the Indonesian telecommunications industry, and our Technology Focus looks at solar PV. Other great contributions come from Hibbard, Woodside, Cummins, and A2WIND. So, put your feet up and enjoy the July-August edition of Power Insider Asia!

RACHAEL G. STEPHENS, EDITOR Rachael@sksglobal.com

PI THE TEAM Accounts & Customer Service Manager

Katherine Stinchcombe kathy@sks-global.com Financial Director

Jacob Gold info@sks-global.com Staff Writer

Robin Samuels info@sks-global.com Contributing Writer

Managing Director & Publisher

Sean Stinchcombe sean@sks-global.com

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Sam Thomas sam@sks-global.com

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Daniel Rogers daniel@sks-global.com

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Tradena Hunt info@sks-global.com

Chris Hefferan

Magazine Design

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SKS Global Limited, Kingswood House, South Road, Kingswood, Bristol, UK, BS15 8JF T: +44 (0) 1179 606452 F: +44 (0) 1179 608126 E: info@sks-global.com W: www.sks-global.com SKS Global Power Insider Asia magazine is published bi-monthly and is distributed to senior decision makers throughout Asia and the Pacific. The publishers do not sponsor or otherwise support any substance or service advertised or mentioned in this book; nor is the publisher responsible for the accuracy of any statement in this publication.

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Contents

Jul / Aug 2013

10

38 46

55 FEATURES 28

Playing the Gas Game with Australian Coal Mining Robin Samuels looks at how the mining industry is cutting down on pollution.

38

The Origin of Gas Turbines An exploration into Origin Energy’s fleet of operational gas turbines.

46

Australia’s Appetite for LNG Woodside discusses their latest success as Australia’s largest independent gas company.

55

Cummins Power Generation and Christmas Creek How Cummins is satisfying the appetite for iron ore.

4 POWER INSIDER JUL / AUG 2013

64

Network Fuel Cells for the Indonesian Telecommunications Industry A look into one of the many markets with a growing space for fuel cells.

74

How Effective Air Filtration Systems can Enhance Gas Turbine Efficiency Carlo Coltri from Vokes Air explains why air filtration systems are so important to gas turbine efficiency.

66

Today’s Design for Tomorrow’s Products Wolfgang Kurz tells us about A2WIND’s unique approach to turbine design.

78

Ahead of the Curve: The Asian Gas Turbine Market and Alstom PI Magazine looks at the market drivers for the gas turbine market, and at Alstom’s solutions.

70

To Build or Not to Build: The Billion Dollar Radioactive Question With so many plans but few firm contracts, where is the nuclear industry in Asia headed?

86

Will Smart Grid Deliver as Promised?

Insights from a Utility Survey in Australia from Frost and Sullivan.

INSIDE THIS ISSUE

REGULARS 06

News July and Augusts biggest headlines from the Asian power market.

57

Technology Focus This issue, solar photovoltaics take the spotlight.

10

Australia, Climate Change and the Role of Renewables PI Magazine examines why renewables are so controversial in Australia.

90

Country Directory: Australia An overview of the Australian power industry and significant projects.

18

What Would You Pay for Piece of Mind? Australia and Desalination The success and challenges of the Wonthaggi Desalination Plant in Victoria.

94

Event Directory and Advertiser’s Index

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INTERVIEWS & OPINION 14

24

Australia: How Important is Energy to You? Peter Fagan of MWH helps us explore research into Australia’s attitude towards energy use.

Inspecting the Best: Hibbard, ROV and the Asian Market We ask Hibbard’s President and Chief Applications Engineer about unmanned ROV units.

34

Two Fuels, Limitless Potential: The Growth of Bi-Fuel Technology Lukas Novak of ComAp talks about bi-fuel applications in Asia.

43

How Sulzer Keeps Asia Up and Running Ken Mackenzie, the new Regional Director of Sulzer Asia Pacific, answers our questions.

50

Ensuring Quality, Supporting Life Daniel Rogers talks to SA Water about water management in South Australia.

60 88

Examining Potential for Fuel Cell and Electrolysis Deployment in Asia An interview with Alan Kneisz of Hydrogenics.

The Right Choice for the Best Fix Critical questions about choosing between an OEM and an independent contractor.

34

Advertise www.pimagazine-asia.com/advertise sam@sks-global.com Editorial team If you have a story you think we might want to feature in a forthcoming issue email rachael@sks-global.com

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REGULARS

News from around Asia Holiday season hasn’t affected activity in the Asian power sector, with a number of exciting deals and controversies. The two most contentious are both long, rumbling crises: Fukushima and solar dumping. Officials at TEPCO have had to admit that radioactive material is in the groundwater around Fukushima, and has been leaking into the Pacific Ocean as well. The Japanese Government will assist in the clean up in another blow to the current administration’s attempts to phase nuclear power back in. At least the Chinese and EU negotiators came to an accord, agreeing to remove the strict import tax in return for a minimum price on solar products.

Other stories from the region include Australia’s decision to make an early move to a floating carbon price in 2014, as well as Coal India and Petratherm both seeking to diversify into fossil fuel power generation. Thailand has announced a new solar power feed-in tariff, and South Korea may restart nuclear facilities to ease power fears.

GE announced in July that they will be investing in the Sikkim project in India, whilst the Chameliya project faced the prospect of their Korean contractors pulling out. The wind industry has been plagued with scandal, as Vestas sues Indian companies over unauthorised deals made by their former CEO, Sinovel shuts down four subsidiaries, GE pulls out of a JV with Harbin Electric and AGL decides to delay the Silverton Wind Project. On the other hand, world wind capacity is set to pass 300 GW. In more positive news, Acta Power has started a hydrogen fuel cell test in the Philippines, and Japan has developed a testbed for hydrogen storage. Additionally, the T&D industry in India got a boost with approved loans from ADB to improve transmission.

FOR MORE INFORMATION ON THESE NEWS STORIES USE THE QR CODES TO VISIT OUR ONLINE NEWS PAGE 1 Visit an app store and download a free QR reader.

2 Look for the QR codes on the pages of Power Insider.

3 Scan the code by holding your smartphone over it and enjoy the extra Power Insider content.

6 POWER INSIDER JUL / AUG 2013

SAUDI ARABIA

South Korea’s Hyundai Heavy Industries won a $3.3 billion order to build a steam power plant in Saudi Arabia. Hyundai will complete the massive facility with a production capacity of 2,640 MW by 2017.

MYANMAR

The Myanmar Ministry of Electrical Power opened a tender in July to buy natural gas to meet growing domestic energy demands.

The ministry aims to buy 150-200 million cubic feet daily before March 2014.

NEWSDESK

INDIA

NTPC awarded Tata Power with a 50 MW solar PV project. The flagship project is located in Madhya Pradesh and will double NTPC’s solar capacity.

CHINA

CTG’s 6.4 GW Xiangjiaba Hydro Projects starts four of its eight units.

Supplied by Alstom, each of the 800 MW units were manufactured in Tianjin are the most powerful hydro units in the world.

JAPAN

TEPCO admitted that not only was radioactive tritium present in the groundwater around Fukushima, but that it was also leaking into the Pacific Ocean, with an estimated 2040 trillion becquerels deposited since 2011.

VIETNAM

Vietnam’s central city of Da Neng was warned that they could face water shortages of up to one billion cubic meters during the dry season.

SOUTH KOREA

The Korea Smart Grid Association signed a MoU with the OpenADR Alliance after a successful interoperability test event, to introduce OpenADR technology to Korea and help facilitate its adoption.

AUSTRALIA

EnergyAustralia entered a Sale and Purchase agreement with New South Wale and Delta Electricity to buy the 1,400 MW Mt Piper and 1,000 MW Wallerawang power stations for AUD 160 million.

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REGULARS

Timeline

There’s always plenty going on in the Asian market and the Summer of 2013 has been no exception! Here is PI Magazine Asia’s timeline of top picks to guide you through the most significant developments in July and August.

JUN

TATA POWER BEGINS 1 MW GEOTHERMAL PILOT PLANT IN AUSTRALIA

>

Tata Power has commissioned a 1 MW geothermal pilot plant in the Cooper Basin in Australia.

The Australian geothermal project will be under Geodynamics Ltd., of which Tata Power is an associate participant.

JUL

28

11

>

EVN BORROWS VND14.5 TRILLION FOR LAI CHAU HYDROPOWER PLANT

JUL

A consortium of Vietnamese banks approved a loan for the 1,200 MW Lai Chau hydro project.

The three turbine plant will start generating electricity in 2016 and reach completion in 2017.

12

Scientists from American and German universities have developed an innovative chip that separates salt from water, offering an alternative to membrane technology.

> JUL

17

SEAWATER DESALINATION CHIP SHOWS GREAT POTENTIAL

>

WORLD BANK APPROVES POWER TRANSMISSION PROGRAM TO BOOST INDONESIA’S GRID

JUL

The World Bank approved a $325 million loan for the Second Power Transmission Development Project. This project will assist four project areas – Java-Bali islands, Sumatra, Kalimantan and Sulawesi – by increasing access to the national grid.

18

SIEMENS WILL DELIVER 81MW IN PHILIPPINES

JUL

24

Siemens is to supply hardware for the 81MW Caparispisan wind farm after securing its first order in the Philippines. The German giant will deliver 27 of its 3MW 101 turbines in Pagudpud, Illocos Norte.

COAL INDIA SIGNS SUPPLY PACTS WITH NTPC FOR 16 PLANTS

Coal India Ltd signed fuel supply pacts with NTPC’s 16 power plants and joint ventures, while 11 more agreements with the power major and its JVs are being processed.

> JUL

27

THE EU AND CHINA REACH AMICABLE AGREEMENT IN ANTI-DUMPING ROW

European Union and Chinese negotiators reached an agreement to curb EU imports of solar panels from China in exchange for exempting the shipments from punitive tariffs. The accord would set a minimum price of 56 euro cents a watt for annual imports from China.

> JUL

31

SUMITOMO ELECTRIC TO SUPPLY ENERGY STORAGE SYSTEM FOR HOKKAIDO

> AU G

Sumitomo Electric Industries Ltd announced plans to supply a large size storage battery system to stabilize the flow of wind and solar power on the northern island of Hokkaido, adding 60 MWh of storage capacity.

01

Siemens will supply two H-Class gas turbines for the TNB Prai combined cycle power plant in Malaysia. The company will also supply two generators and two steam turbines.

> AU G

02

STATE GOVERNMENT APPROVES DRINKING WATER AT PERTH SEWAGE PLANT

Up to seven billion liters of treated sewage water will be added to Perth’s drinking water supply every year with the sign off of an AUD 116 million wastewater project.

> AU G

04

TOYO INK GROUP TO DEVELOP 2,000 MW COAL PLANT IN VIETNAM

Malaysia’s Toyo Ink Group signed a MoU with Vietnam’s industry ministry to develop the 2,000 MW Song Hau-2 coal fired power plant in Vietnam. The plant will use imported coal from Australia and Indonesia.

8 POWER INSIDER JUL / AUG 2013

SIEMENS TO SUPPLY PRAI POWER PLANT WITH H-CLASS TURBINES

> AU G

09

GE AND FIRST SOLAR SWAP STOCK FOR TECHNOLOGY

GE and First Solar have signed an agreement to swap 1.75 million shares of First Solar stock for GE’s thin film panel technology. The deal is worth $82 million.

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REGULARS

Australia, Climate Change and the Role of Renewables Rachael G. Stephens looks at why investment in renewable power in Australia is considered expensive, controversial and unpopular.

A

ustralia is one of the world’s worst polluters.

Generating about 1.5% of global greenhouse gas emissions, Australia emits about 24.4 tons of carbon dioxide equivalent per person per capita. Only a few countries in the world rank higher – Bahrain, Bolivia, Brunei, Kuwait and Qatar. At more than four times the world average, Australia is ranked the 17th most carbon competitive economy in the G20.

The energy sector accounts for approximately 76.9% of Australia’s net emissions. Australia generates 60% of its energy from coal, 13% produced by renewables, with the remainder made up by oil and gas. Fossil fuels are a huge part of Australia’s export industry too. As the world’s second largest coal exporter by weight, and with the fourth largest coal reserve in the world, coal is Australia’s second largest export commodity in terms of revenue.

As a result of Australia’s economic and social dependence on fossil fuels, the issues of climate change, carbon emissions and renewable energy are highly politicized. Big businesses want to protect their interests, environmentalists

10 POWER INSIDER JUL / AUG 2013

want to reduce emissions, the government needs to keep the economy afloat and the population want access to sustainable energy at reasonable tariffs.

The dialogue of this complicated cocktail is well documented in the media, who keep the issues very present in the Australian political psyche.

As a result of Australia’s economic and social dependence on fossil fuels, the issues of climate change, carbon emissions and renewable energy are highly politicized Australia’s Energy Revolution The Australian Government wants to move to a more carbon neutral energy industry, and they’re doing this in two major ways. The first is to set a renewable energy target (RET), and

encourage investment in renewable energy projects. The second is to implement a carbon price. Australia’s RET is to reach a 20% share from renewable energy sources in power generation by 2020, or 41,000 GWh. A number of organizations and funding boards, such as the Australian Renewable Energy Agency and the Clean Energy Finance Corporation, have been formed to help distribute funding. The Australian Government’s targets are equivalent to a reduction in every Australian’s carbon footprint of one third to a half.

In July 2012, Australia introduced a price on carbon. Nicknamed the ‘carbon tax’ by its numerous critics, the legislation is an incentive for big polluters to reduce emissions. These polluters will be required to pay AUD 24.15 per ton of carbon emitted until 2014, when the government will introduce a ‘floating price’, based on current EU carbon futures and expected to be cheaper for big business. Originally scheduled for 2015, the early move to a floating price was been promised by Prime Minister Kevin Rudd in July this year. The money raised from the carbon tax will go towards funding renewable projects.

REGULARS: CLIMATE CHANGE AND THE ROLE OF RENEWABLES

Renewable Potential Australia has a huge amount of renewable energy potential, which is seriously underdeveloped. Hydropower is the most mature source of renewable energy, despite Australia being the driest inhabited continent on earth. Australia has more than 100 operating hydroelectric power stations with total installed capacity of 8 GW. Most projects are located in New South Wales and Tasmania, with the Snowy Mountains Hydroelectric Scheme being Australia’s largest project. With a capacity of 3.8 GW, the scheme comprises of sixteen major dams, seven power stations, and 145 km of interconnected trans-mountain tunnels. However, because of the lack of surface water in Australia, the opportunities for large scale hydro projects have dried up.

Australia has the highest solar radiation per square meter of any continent

Solar Of the growth sectors, solar power is the most popular. Australia has the highest solar radiation per square meter of any continent, receiving an average of 58 million PJ of solar radiation per year, approximately 10,000 times more than Australia’s total energy consumption. There has been a huge uptake on the installation of solar panels, with over 1 GW of PV added in 2012.

Utility scale solar projects are also being funded, with the government’s Clean Energy Initiative Solar Flagships Program committing AUD 1.5 billion to support the construction of up to four large scale solar power plants using solar thermal and PV technologies. The program hopes to establish up to 1 GW of solar power.

Two projects that will benefit significantly from this scheme are AGL’s Broken Hill and Nyngan projects. Together with First Solar, AGL will build a 100 MW plant at Nyngan and a 50 MW plant at Broken Hill. Total capital required for the projects will come to AUD 450 million, and the two sites will occupy over 450 hectares of land, requiring

the installation of nearly two millions solar PV modules. Construction on both plants is scheduled to start in 2014, with completion in 2015.

Wind Wind power has seen the most progressive large scale development in Australia.

Australia has some of the best wind resources in the world, located mainly in the south. Key projects include: • The Boco Rock Wind Farm in New South Wales: Owned by Continental Wind Farm Operators, the 113 MW project will use 58 GE ‘Brilliant’ turbines, and will displace some 300,000 metric tons of carbon emissions. Power delivery is expected to start in the fourth quarter of 2014.

• The Taralga Wind Farm in New South Wales: A joint venture between Banco Santander S.A. and CBD Energy Limited, the 107 MW project will utilize 51 Vestas turbines and is expected to be operational by November 2014.

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• The Gullen Range Wind Farm in New South Wales: the Australian Government’s Large Scale Renewable Energy Target has financed this 165 MW project. Utilizing 56 Goldwind turbines, the project will be operational in 2014.

Other under-utilized but high potential renewable energy sources include biomass, tidal and wave energy, and geothermal power.

With the exception of biomass, most of these applications are in the demonstration stage.

Policy Success These two policies and the resulting investment from utilities and the Australian people have produced some positive results.

Firstly, pollution from electricity generation has fallen by 12 million tons in the past year alone, which is the equivalent of removing 2.6 million cars from the roads, with Australia using 13% less brown coal. This has accompanied a 5.5% drop in over all power demand from 2008-12. This can be attributed to a drop off in manufacturing in Australia, solar panel schemes, and a rise in electricity prices encouraging energy efficiency.

Additionally, the share of renewable energy in the National Electricity Market (NEM)

12 POWER INSIDER JUL / AUG 2013

has soared to 13%, growing far quicker than originally forecast. Studies now estimate that Australia could be using up to 51% renewables by 2050, and that by 2020 Australia could be using 25% renewables, surpassing the 20% RET. Political Upheaval This decline in emissions and lessening reliance on fossil fuels should be celebrated, but Australia still hasn’t committed to climate change and renewable energy. The success of the RET is a politically contentious issue, with many industry players calling for renewable funding schemes to be wound back to cut the costs of electricity to consumers, whilst climate campaigners demand the opposite.

Politicians from all parties are vocal about changing the RET without making any specific election promises. Any legislation couldn’t even take place until after the election, which will take place in September.

This political upheaval is causing the industry to stutter. AGL Energy has even delayed an AUD 550 million wind farm because of uncertainty. AGL aren’t the only ones, with a capital strike reported by renewable energy developers, wary about losing favor with the federal government.

Carbon Tax Described by commentators as ‘politically toxic’, the carbon tax is extremely unpopular in Australia. Viewed as excessively high, Australians are unwilling to shoulder the burden of increased prices passed down from businesses compensating for their extra costs.

Businesses complain that they’ve had to cut jobs or move country in order to improve their bottom line without passing on costs to the consumer, and estimates suggest that the carbon tax costs an extra AUD 500 per person a year.

Many were keen to see the carbon tax moved to a floating price sooner than the 2015 schedule. The current government has pledged to do so next year, which could see the carbon price drop to as little as AUD 6 a ton. The Conservative opposition has promised to scrap the carbon price if it wins office. Rudd plans to mitigate the expected revenue loss by ending an energy security fund program two years early, and cutting the funding to the government’s carbon capture and storage program (AUD 200 million), the biodiversity fund (AUD 213 million) and a clean technology program (AUD 200 million).

It has been argued that Kevin Rudd, who famously described the onset of climate

REGULARS: CLIMATE CHANGE AND THE ROLE OF RENEWABLES change as “the greatest moral, economic and environmental challenge of our generation”, is bowing to the pressure from energy industry and from the public who dislike the policy.

This is supported by the fact that his Energy Minister, Gary Gray, is a founding member of the Lavoisier Institute, a group that has famously spread misinformation about climate change. Gray has also described climate change as ‘pop science’. This suggests that the Labor Government is developing popularist policies in order to get through the election.

Cultural Disparity However, it is difficult to predict where votes will go, as the Australian public’s view on renewable energy is complicated at best. In mid 2012, The Climate Institute released the “Climate of the Nation” report, which revealed that Australians are “sick of the politics and scared about rising costs of living, are uncertain about the science, and unconvinced by carbon pricing solutions”. The report, amongst others such as the CSIRO 2011 report and MWH’s ‘Future Cities’, claims that the Australian public are concerned about climate change, but there is a disparity between what they are willing to do in principle, and what they are willing to pay for.

The MWH report states that renewable energy is the second most important living concern for the future – with ‘in the future’ being the indicative clause (for more on this study, see our interview with MWH’s Peter Fagan). Australian people don’t want to see their bills go up, despite up to 91,600 people paying extra for renewable energy and others investing in solar panels, and want to see the government shouldering most of the cost.

More information on the carbon tax may be required to get people on board; in the

CSIRO 2011 report, the percentage of people supporting the carbon tax rose from 28% to 47% after it was explained to them.

Peter Fagan suggests that the Australian public won’t actively engage in climate change until it is essential. After the Millennium Drought, MWH’s “Global Water Gauge 2010” report found that because people had to cut back and be more efficient, an attitude change was instigated that resulted in longterm behavioral changes. Because of the power glut, Australians don’t need to do this with energy, and more significantly they can opt out of doing anything at all. This is compounded by the politician’s manipulation of the public’s reluctance and skepticism to win votes.

To make real progress on Australia’s carbon emissions, a culture change is required in every tier of the energy industry Culture Change ACF climate change manager Tony Mohr said that “the three year fixed carbon price is helping Australia catch up to other countries that have been cleaning up their economies for years.” That is most certainly true; there is quantifiable and irrevocable evidence to support it. However, the constant ongoing debate about the cost of such policies is coloring what should be a straightforward drive towards a greener economy and energy industry.

To make real progress on Australia’s carbon emissions, a culture change is required in every tier of the energy industry. This culture change has to have one major driver; that moving to green power is not a choice. Power plant operators and mining companies will soon run out of resources, and therefore have to diversify to survive. Politicians have a responsibility to protect the wellbeing of the nation; not the nation’s business bigwigs, and the Australian public need to stop behaving as though climate change is not their problem. Climate change is an issue for now, not the future, and the energy industry is changing to accommodate that.

Australia needs to catch up. PI

GET INVOLVED IN THE DEBATE! Do you think the carbon tax is a positive policy for Australia’s energy industry? Was it a good idea to bring forward the floating price?

Do you think Australian politicians care more about winning votes than long term, sustainable energy policies?

Join the debate and tell us what you think on Twitter, LinkedIn and on our website: www.pimagazine-asia.com Alternatively, email the editor: rachael@sks-global.com

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INTERVIEW

Australia: How important is Energy to you?

AN INTERVIEW WITH: PETER FAGAN, MWH GLOBAL

We asked Peter Fagan of MWH Global to tell us a little more about the company’s recent findings from a study into what Australians consider important about their cities.

The MWH ‘Your Life, Your Home, Your City – the future of Australia’s livable cities’ report certainly makes for interesting reading. As recognized leaders in strategic consulting and technical engineering, MWH recently commissioned a piece of independent research of Australians to explore attitudes and priorities with regard to liveable cities. In particular, MWH set out to explore infrastructure priorities, and attitudes towards water, transport and energy.

At PI Magazine Asia, we were particularly interested in attitudes towards energy. The research shows that 78% of Australians believe that coal powered plants will soon be obsolete, with two in three agreeing that businesses should be required to undertake an energy audit to minimize waste. Additionally, 40% of Australians are prepared to pay more to ensure a reliable

14 POWER INSIDER JUL / AUG 2013

supply of electricity with minimal power outages, and 39% are willing to pay higher rates to have access to renewable energy.

We asked MWH General Manager of Sustainability and Environment, Peter Fagan, to unpick some of these energy issues.

How and on whom was this research conducted?

We commissioned a piece of independent research of Australians to explore attitudes and priorities with regard to what makes cities ‘liveable’ – from the perspective of those who live and work in them.

The research is based on the results of a survey conducted on over 1,000 Australians located in both capital cities, regional and remote areas. Questions asked in the survey ranged from opinions on components of

liveable cities and infrastructure priorities, drivers to live in cities versus regional areas, attitudes towards water, transport and energy consumption, lifestyle influences, and opinions of future infrastructure and spend.

Lonergan Research conducted the survey online and results were weighted to the population estimates according to the Australian Bureau of Statistics.

How important is it to Australians to have a steady supply of electricity?

Is a reliable supply a concern for Australians?

Having access to a steady supply of electricity is clearly an important concern for Australians. Overall, electricity was ranked as the fourth most important infrastructure element influencing

INTERVIEW: AUSTRALIA: HOW IMPORTANT IS ENERGY TO YOU? Australians when they choose where to live, and second for the future after water as the highest priority. However, those living in regional areas were more likely to rank electricity as the most important infrastructure element than those living in cities and remote areas.

This goes back to one of the central findings of the research, which suggested that even though we have a very sophisticated society in lots of ways, getting the basics right – water, electricity, healthcare and emergency services, for example – is still an overwhelming factor in Australians’ decision making processes when choosing where to locate. 40 per cent of Australians indicated that are prepared to pay more to ensure a good supply of electricity and minimal power outages, suggesting that reliability and consistency of supply are highly valued.

Spending Priorities

What do Australians want out of their utilities and power producers?

A dual preference emerged for both reliability and sustainability – Australians want to ensure a consistent and reliable electricity supply but do not want this at the expense of the environment, with a demand for access to renewable power options.

Do Australians want to manage their own energy use? Or do they just want the best tariffs and no fuss?

There are two takes on this question. When asked generally I think everyone wants to be efficient and know that they are not wasting energy. For example, our research found that two in three Australians would like it to be mandatory to have an energy audit of business and households annually to ensure that there is no wasting of electricity. This suggests that people want to understand how best they can manage their own energy use to lessen wastage and increase efficiency, and to control their energy in accordance with this.

However, when asked specifically about their own behaviours, people often fail to see the link between being efficient and when they use energy. The experience in some Australian states around “smart metering” has been a bad one, as it was pitched around people being able

Did you know?

40% Australians are prepared to pay more to ensure a good supply of electricity and minimal power outages, and 39% are willing to pay higher rates to have access to renewable energy.

Note: Mean percentage calculated for each budget item

to be more efficient without the necessary understanding of the sting around when they used energy. Consequently when their bills went up they complained. I think with businesses there are better incentives and better understanding of what efficiency actually means and that they are in a better position to manage the complexity around this.

What would an ‘energy audit’ entail?

And how would the consumer, utilities and power producers use the data?

Two in three Australians stated that it should be mandatory to have an energy audit of business and households annually to ensure that there is no wasting of electricity.

Voluntary audits are available now. They generally look at the usage patterns of a household and then look at the energy efficiency profile of the household appliances. Things like the number of appliances on standby are taken into account and there are tools that are then used to display what that costs individual households. There are groups of users though that while they say they won’t waste power they want to be able to use it to meet their lifestyle choices and are willing to pay for the option. Others may call that waste because they make different lifestyle choices.

Do Australians care where their power comes from?

Source: MWH Global

We are a highly environmentally aware population, with 39% of Australians willing to pay higher electricity rates to have access to renewable energy, be it wind or solar. This is an encouraging trend, given the imperative we have as a nation to lesson our impact on the climate and improve our resources efficiency over the coming decades.

Australians will not only pay more for renewable energy; they will also move for it.

Looking to the future, Australians named having renewable energy as the main source of electricity as the second most important aspect influencing where they will choose to live in 30 years’ time.

40% of Australians are willing to pay more for renewables – do the remaining 60% present a significant obstacle for the development of renewables in Australia?

What needs to be done to bring the remaining 60% around?

Again this is a question with two answers. As a general principle Australians are saying yes to renewables and that they recognise they will cost more. On the other hand there is no overwhelming uptake of the renewable energy options available from existing retailers across the country. Businesses on the other hand have a mandated target of 20% renewable energy usage as do generators who have the same mandated target that 20% of their supply has to come from renewable sources.

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INTERVIEW: AUSTRALIA: HOW IMPORTANT IS ENERGY TO YOU? The real issue here is the speed of uptake and the availability of supply. Matching the two is a difficult trick to carry off but I am confident that it will happen as the carbon tax/trade schemes become more imbedded and roll down to the everyday users.

In general, there is a dichotomy between what people are conceptually willing to agree and commit to, and what their real time actions are. When questioned, most people assert that they need to reduce energy consumption, but in reality they are willing to simply pay more in order use whatever they like, when they like. Additionally, when questioned people would agree to pay more for renewable energy, but few have taken up the opportunity to do so.

The research states that renewable energy is the second biggest concern for the future: Do you think this is because the energy crisis is considered a problem for tomorrow instead of right now?

This is a capacity issue linked to climate change understanding more than anything.

In Australia there is a large public debate around the cost of renewables being waged by the Anti-Climate Change groups and media. The general population, though, is concerned about the climate future and wants more sustainable energy supplies available to them, but is concerned about the cost and the availability of enough supply as the existing infrastructure ages. By way of example, the subsidy on household solar installations is calculated to add about AUD 102 to the average household bill across all users whether they have the installations or not.

Components of Liveable Cities (Ranked) 1st

Healthcare (Hospital, Doctors, Health Practitioners etc)

2nd

Employment/Work

3rd

Essential Services (Police, Ambulance, Fire etc)

4th

Infrastructure (Roads, Electricity, Water, Sewage)

5th

Environment (Public Spaces, Air Quality)

6th

Aesthetics (How the place looks)

7th

Education (Schools, Universities)

8th

Culture (eg. Theatre, Cinema, Sports Venues, libraries

9th

Food (Restaurants, Cafes, Fresh Produce)

Source: MWH Global

16 POWER INSIDER JUL / AUG 2013

When asked specifically about their own behaviours, people often fail to see the link between being efficient and when they use energy Are the unused land and government buildings suitable for power generation purposes? If so, what is holding the government back?

Nine in 10 Australians responded that they want to see unused crown land and government-owned buildings being used to generate electricity using solar and wind power, suggesting an expectation that government should be doing more to take on the task of transitioning to renewable energy provision.

This is a question of economics around the supply/demand equation and the return on investment. Some may also say that it is a cop out to have government take the running on this. The reality is that increasingly power generation and supply is being handed to the private sector to deliver and that it is no longer a business that government should be in, providing the right safety nets for the lower socio-economic groups are in place.

I think that response to this is more a commentary on perceived government wastage and inefficiency as opposed to saying they want direct intervention by government in the supply frameworks for renewable energy.

Philippa Charlton in the research claims that developing a green and stable supply of electricity “will require a diverse range of innovative policy, planning and technical solutions that support the uptake of renewable energy generation, encourage energy efficiency and facilitate development of low energy and low carbon urban forms.” Does Australia have a plan in place to develop this way? Is this a realistic expectation?

I do not think that Australia does have a plan to do all of this at this stage. It cannot be dealt with separately to a much wider range of economic reform initiatives that are under active consideration. By way of example, demand for electricity has come off by about 20% in Victoria in the last 5 years.

This happens to coincide with a considerable downsizing of the state’s manufacturing sector.

The consequential drop in demand has meant that there is now spare supply capacity within the existing infrastructure.

Couple this with the cost and reliability questions around renewables and the issue becomes even more complex. The supply of baseload power is the key and matching the supply demand equation is difficult. So if renewables are to be a more significant part of the future we will need to be innovative in the technology that is used, the location of the infrastructure and balancing the supply risk across those things such that there is security to the system.

There has been a strong theme throughout this interview of people not making the connection between the conceptual idea of energy conservation and real time action, due to a lack of understanding or knowledge. How do we educate people to make them aware of the importance of this issue, and who is responsible for that education?

That’s a good question, and in my own view, it isn’t education that makes the difference. A few years ago in Australia we suffered a very significant drought, and as a result a number of water restrictions were put in place. During this time, we saw an attitude and behaviour change toward water usage, as people tried to reduce wastage.

The problem with power is that there is no similar restrictions on use and capacity: due to a 20% drop in power requirements because of the movement of industry out of Australia, there is plenty of electricity capacity. Until there is a similar shortage on electricity as there was on water, people’s behaviour towards energy use is unlikely to change.

Peter Fagan has more than 35 years’ of experience and is MWH General Manager for Sustainability and Environment.

His extensive experience spans the technical and organizational aspects of sustainability through public and private sector roles, including more than 30 years with New South Wales’ largest water provider. Mr. Fagan currently serves as a member of the Technology and Sustainability Standing Committee of the University of Sydney’s Warren Centre for Advanced Engineering.

For more information, go to the MWH website: www.mwhglobal.com If you would like the read the research in full the report is available at www.mwhglobal.com/blog/the-secretsbehind-australias-liveable-cities/

REGULARS

What Would You Pay for Piece of Mind?

Rachael G. Stephens tells the story of Wonthaggi Desalination Plant, and argues why, despite the controversy, it’s the best kind of insurance money can buy.

Relying on your climate for water is risky: especially if you live on Earth’s driest inhabited continent. Australia’s dependence on rainfall and groundwater presents a significant chink in its infrastructure armor, as the climate oscillates dramatically between long periods of dry weather and short periods of wet. Just emerging from the deepest dry period in 100 years, the 15 year ‘Millennium Drought’ exposed substantial weaknesses in Australia’s water supply chain.

18 POWER INSIDER JUL / AUG 2013

Facing the ravages of climate change that will further heighten temperatures and reduce rainfall, and a population boom of 50% by 2050, Australia’s vulnerable urban water supply is under enormous pressure. Melbourne’s water storage levels fell to 25.6% in 2006, with only a year of water left. Adelaide was under pressure to reduce reliance on the drought stricken Murray River, and Sydney struggled to maintain supply as the rain refused to fall. In 2001, Perth’s reservoirs saw the poorest inflow

of water since 1914, gripping the region in the worst drought on record.

The State Governments managed these crises through rigid conservation and demand management policies, but eventually acknowledged that they needed an alternative to the dams and reservoirs that fill and deplete in ever more extreme cycles.

In order to continue to grow socially and economically, Australia needed a sustainable, long-term water security policy.

The Desalination Policy By supplying gigaliters of fresh water, desalination plants can provide great insurance against drought. With 240 small scale plants already in operation in Australia, various state governments decided to use this mature technology to undertake an enormous infrastructure project. Australia’s largest cities are spending AUD 13.2 billion on new desalination plants in order to secure water for the most densely populated areas. Upon completion, Australia’s major cities will draw up to 30% of their water from the sea (see Figure 1).

Despite the potential they have to alleviate considerable pressure from Australian society, desalination plants have drawn fierce criticism from the public. This is largely due to the considerable cost of desalination plants, which has been passed down to the consumer.

As a result, desalination has become a highly politicized issue. In this article, we’ll take a look at the controversial Wonthaggi plant in Victoria, to identify what the public’s objections are, to separate the facts from the political mudslinging, and to provide some perspective on Australia’s water insurance program.

The Wonthaggi Plant: Built Under a Cloud The Wonthaggi Plant in Victoria was proposed by then Labour leader Steve Bracks in 2007. As a public private ownership project, a build-ownoperate contract was awarded to the AquaSure Consortium. This consortium consists of joint ventures between Thiess and Suez’s Degremont.

The plant is capable of delivering 150 gigaliters of water per year, equivalent to a third of Melbourne’s water demand, and had a price tag of AUD 3.5 billion.

Figure 1: The Australian Government’s Desalination Program Project

Capacity (GL pa)

Operator

Association

Operational

The Perth Sea Water Plant

45

Degrémont

WA Water

Operational

The Southern Seawater Plant

100

Southern SeaWater Alliance

WA Water

2011 - 2014

Sydney Plant

90

Sydney Desalination Plant Pty Ltd

NSW Government

2010

Victoria Plant Wonthaggi

150

AquaSure Consortium

Melbourne Water

2012

Port Stanvac, Adelaide

100

AdelaideAqua

SA Water

2013

The scale and price of the Wonthaggi desalination plant drew early criticism in 2007. Public rallies and protests took place, culminating in a petition submitted to the Victorian Parliament in 2009.

Public negativity was validated by a series of labour strikes, lawsuits, construction issues and rather ironically, periods of wet weather that caused plant to run nearly a year behind schedule. The ‘cyclonic’ conditions even prompted AquaSure to sue the state government, claiming that the weather conditions were misrepresented, and that it was unfair to fine the consortium for late completion as a result.

Under this cloud of scandal and litigation, the Australian public began to fixate on what the desalination plant would cost them as consumers.

The Essential Services Commission announced that Melbourne households will see their water bills rise by as much as AUD 220 by the end of 2013. In a political jibe at the former Labour

government who approved the plans, Water Minister Peter Walsh claimed that the government were ‘‘doing everything possible to manage the price increases’’ for Melbourne households “shackled” to a desalination plant that is “far too big and far too expensive’.

The plant is capable of delivering 150 gigaliters of water per year, equivalent to ⅓ of Melbourne’s water demand, and had a price tag of AUD 3.5 billion

PI

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The Perth Seawater Desalination Plant is a successful plant in Australia. According to Australian Water Association Chief Executive Tom Mollenkopf, because Perth experienced such a low rainfall, there was a “high degree of public acceptance” of the technology.

The total project cost was AUD 387 million, with annual running costs of under AUD 20 million – less than one dollar per week per household.

Perhaps it is the plant’s size and more reasonable costs that have made it more acceptable to the public, but despite the plant’s success it isn’t big enough – Perth have had to build another plant.

plant will sit idle until required. This is a trend with the desalination plants. In Adelaide, flooding rains have restored the local river system to health and at the end of the plant’s testing period in 2014, the Port Stanvac plant will be mothballed and remain an ‘essential insurance policy’, according to Jay Weatherill, South Australia’s Premier. Sydney’s dams are also full, and the desalination plant has completed its testing period. It will now lay idle until Sydney’s dams fall below 70%, according to Finance Minister Greg Pearce.

The Melbourne State Government won’t order from the plant until the water storage falls below 65%; currently, Melbourne has around 74%. Peter Walsh claims that this is actually an ideal situation, not wanting to ever have to order water from the plant. This is partly because he doesn’t want drought to return to Melbourne, but also because the Wonthaggi plant would remain a powerful political weapon against the opposition.

Mothballed Adding additional pressure to the scheme is the fact that the plant is unlikely to be used anytime soon. Unless Melbourne suffers a drought in the next two years, the Wonthaggi

Willing to Bet? In Melbourne, Adelaide and Sydney, the main question that’s being asked is: Did we need to spend so much money on something so big that we aren’t using? This question can be answered with another, one posed by Suez Environment Chief Executive Jean-Louis

DESAL SUCCESS STORY

20 POWER INSIDER JUL / AUG 2013

Are you sure that in the coming 30 or 50 years you will not have a drought? Are you willing to bet on that?

Chaussade to the Victorian public in a recent media visit to the Wonthaggi plant: “Are you sure that in the coming 30 or 50 years you will not have a drought? Are you willing to bet on that?”

It’s an excellent question, but unfortunately not the one central to the dialogue surrounding the Wonthaggi plant. Instead, the dialogue is political, with politicians like Peter Walsh presenting arguments that seek to assert that the plant is a magnificent waste of money bought about by the incompetent Labour administration. Instead of straightening out problems and representing the positives in the project, public figures have focussed their time on infighting, litigation and politics, forgetting about their responsibility to the Australian public

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RENEWABLE ENERGIES

WATER

INFRASTRUCTURE

to present the facts. Perhaps Wonthaggi’s formative years are best forgotten, by what do the community in Melbourne need to remember about their desalination facility?

Fantastic Capabilities What cannot be over stated is that desalination plants are rainfall independent water sources.

Whilst rain is plentiful and the dams are full, it is a cutting edge, flexible plant that allows the state government to order water once a year in increments from 0-150 gigaliters.

The psychological impact of these water shortages cannot be underestimated; MHW’s 2010 research into attitudes towards water consumption showed a dramatic change in behaviour when it came to water conservation during the height of the Millennium Drought.

The Wonthaggi desalination plant is capable of providing Melbourne with 150 billion litres of water a year, which can be expanded to 200 billion litres if required. It is a cutting edge, flexible plant that allows water distributors to order what they need throughout the year. Such a strong insurance policy is never a waste of money, especially when that money has been invested in the very best cutting edge technology.

Intake and Outlet Tunnels The Wonthaggi plant is located on the Bass Strait, with easy access to the open ocean. A 1.2 km inlet tunnel draws the seawater to the desalination plant at extremely slow speeds, so that even the smallest fish can swim against the current. To protect the larger sea life, a protective grill is in place over the entrance of the inlet tunnel, and the underground tunnel has no impact on the beach and dune system. The outlet tunnel releases seawater concentrate into circulating water, which helps to water efficiently and quickly back to standard concentrations within a short distance.

22 POWER INSIDER JUL / AUG 2013

Reverse Osmosis Reverse Osmosis (RO) is the process where water molecules are moved across a semipermeable membrane under high pressure to reduce the salt concentration. At Wonthaggi, fine particles are removed during an initial screening before going through the two stage RO process. Degremont of Suez supplied the technology, and the plant has three streams with 51 reverse osmosis racks, utilizing 55,000 reverse osmosis membranes.

The plant has three streams with 51 reverse osmosis racks, utilizing 55,000 reverse osmosis membranes Ecological Restoration The Wonthaggi plant has the largest living green roof ever created in Australia, which is covered with indigenous vegetation. This protects the plant from corrosion and reduces noise and maintenance. As the plant only takes up 38 of the 263 hectare site, a coastal park complete with wetlands, coastal and swampy woodlands and new habitat for local fauna has been created, as well as a network of public paths on the plant site that link with existing trails. The roof and reconstruction of the coastal dunes used soil excavated from the plant site, making it barely visible from public viewing points.

Vital Pipeline The 84 km underground transfer pipeline connects the plant to the Melbourne network

through a delivery point at Berwick and transfer main to Cardinia Reservoir, where water from the plant can be shared with areas in South Gippsland and Western Port if necessary. The pipe is 1.93 m in diameter and is designed to deliver 200 billion litres of water a year.

A booster pump station maintains pumping pressure between Cardinia Reservoir and Wonthaggi. Air vents and scour valves along the pipeline allow air into the pipe when draining and filling up, and two surge tanks at Kilcunda Ridge and St Heliers Gurdies Road control the rate of pressure changes in the pumping system.

Powered by Green A key criticism of desalination technology is that it is extremely energy intensive, and as a result, not very green. The Wonthaggi plant will require 90 MW per year from the grid to operate at full capacity. To put that in perspective, the desalination plant uses about the same amount of energy as a standard 4-star fridge per household per day. A hot water service uses almost eight times as much energy.

Research showed that renewable energy was not reliable enough to provide direct and continuous power to the desalination plant, so the choice was made to offset the plant’s energy use by buying renewable energy certificates (RECs) from AGL. RECs are

REGULARS: WHAT WOULD YOU PAY FOR PIECE OF MIND? AUSTRALIA AND DESALINATION

tradeable, non-tangible energy commodities that represent 1 MWh of electricity generated from a renewable energy source.

The Wonthaggi plant purchases the amount of renewable energy certificates to match the electricity used in any year by the plant and transfer pipeline operations. This ensures the equivalent amount of renewable energy is injected into the electricity grid. Over a 12 month period, this is equivalent to powering the plant entirely by renewable power. The plant is also very flexible, so production can be adjusted to minimise energy use from the grid if necessary.

Saving Energy Not only is Wonthaggi’s energy use offset, but AquaSure were determined to design the plant to be as energy efficient as possible. Over the past 15 years, the advancement in desalination processes has coincided with the development of processes and equipment, which drastically reduces electricity consumption, such as advances in the performance of reverse osmosis membranes, pumping, and the implementation of new energy recovery systems.

The Wonthaggi desalination plant employs the latest equipment and best available technologies. For the RO process, the main choices were related to membrane characteristics and performances: low energy membranes were selected as well as high operating recovery.

The system to recover the energy of the brine was selected based on Degremont’s experience gained in Perth in 2006. The pressure exchanger system first appeared on the scene in the 80s, but was not truly implemented in facilities with a large production capacity until after 2000.

Desalination became a political issue. It was used in the last state election as a weapon by the new government to attack the former government This system has raised efficiency to 94% 97% in the direct transfer of residual pressure of the brine to a part of seawater, without passing through the high pressure pump.

These systems enable a reduction in energy consumption from 0.4 to 0.7kWh/m3 of desalinated water. In terms of the desalination plant’s energy use, this saves 100 GWh/year.

During the concession period a key focus for the Wonthaggi operations team is monitoring energy use and fine tuning the plant’s power consumption, through a systematic regime including flexible operations and production, membrane monitoring and replacement, and regular maintenance activity to ensure the large energy consumption components are in peak operating condition.

Conclusion It cannot be understated just how much Australia needed to review their water supply

strategy. It is the opinion of some that investing in large desalination plants was a panicked, knee-jerk reaction to a water crisis that is now past. But what about the future? The Bureau of Meteorology reckons some part of Australia experiences a drought on average every 18 years, although the time between severe droughts can vary from four to 38 years. Desalination plants can mitigate any drought caused by the climate, and without having to impose the severe water restrictions that characterised the Millennium Drought. They are the ultimate insurance policy, but insurance costs money.

It is this issue that politicians have used and abused in order to win elections. Australian Water Association Chief Executive Tom Mollenkopf states that in Victoria, hostility to the Wonthaggi plant had been exacerbated because “desalination became a political issue. It was used in the last state election as a weapon by the new government to attack the former government.” Whether you think desalination is the answer or not, it is obvious to state that this kind of attitude towards essential urban infrastructure is not useful, nor helps give voters the correct information about what needs achieving in their cities.

Perspective is what is required; whilst it is understandable that consumers don’t want to bear the cost of drought proofing their cities, what must be considered is what they are protecting themselves from. What will a lack of water in the future cost the Australian public? Isn’t it worth paying a little more to future proof your homes and lifestyle? PI PI Magazine would like to thank AquaSure for supplying the images for this article.

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INTERVIEW

Inspecting the Best: Hibbard, ROV and the Asian Market BRADLEY L. HIBBARD TALKS TO PI MAGAZINE ABOUT HIBBARD’S INNOVATIVE REMOTE OPERATING VEHICLES

Operating and maintaining water assets like hydro plants or wastewater treatment facilities can be a difficult task for one simple reason: a large percentage of the components are under water. Additionally, scheduling maintenance or finding the right time to repair a leak can made even more problematic by the cost of shutting down even part of a plant for a few hours. Bradley L. Hibbard, President and Chief Applications Engineer at Hibbard, answers some of our questions about how unmanned Remote Operating Vehicles, or ROV, can be used to mitigate some of these potentially crippling issues.

Firstly, could you please explain how your Remote Operating Vehicles ensure quality service and project specific needs for each of your client requirements?

Hibbard Inshore crew and ROVs (LBV and Long Range Navajo) in Bhutan with Client.

24 POWER INSIDER JUL / AUG 2013

Our inspection services provide detailed data about structures such as tunnels, shafts and penstocks of hydroelectric projects.

This data can be used to determine remaining life, the value of an asset during transfer of ownership, failure identification and construction and maintenance. There are three parts to providing our inspection services. The first part is selecting the sensors required to gather the necessary data. The second part is selecting an ROV, crawler, or Hybrid ROV/AUV to deploy

the sensors into the client’s structure.

The last part is the inspection and data collection method. The method must provide quality data that is useful to the client, so that the client can make informed decisions regarding maintenance, repair and operations. Whether we use one of our standard configurations of vehicle and sensors or a custom setup, we provide our clients with the information they need to make informed decisions.

Can you highlight examples from your Asian projects where your vehicle and inspection methods were uniquely equipped to out perform other techniques?

INTERVIEW: HIBBARD, ROV & THE ASIAN MARKET

Hibbard Inshore packer plug used in construction phase of plugging holes.

Asia has seen a significant increase in hydroelectric capacity built with long or deep tunnels. Older power plants and tunnels benefit from inspections to help determine the condition of the tunnel with respect to the remaining life of the asset, as well as predicting required maintenance. These inspection services help to plan asset maintenance rather than having no inspection or maintenance, which could result in emergency unplanned shutdowns. New power plant builds benefit from inspections to verify that tunnels are free of faults after they have been put into service but before the construction warranty expires.

Customers use our services for warranty inspections, remaining life inspections, catastrophic failure identification and due diligence for change of ownership. In each of these cases, the information our inspections provide can save the client time and money from more costly alternatives or consequences.

We recently performed a general condition survey of a long intake tunnel, surge shaft and penstocks of a hydroelectric power plant located in a mountainous region in Asia. The inspection required making runs approximately 3.5 kilometers in length through a small access point. Our 5.0-kilometer system was configured to fit through the small access point. The tunnel had been in service for a few years but had not been inspected since construction. Our

The information our inspections provide can save the client time and money from more costly alternatives or consequences

inspection revealed several small holes in the surge shaft that were leaking water. This water leak was traced to water flowing out of the side of the mountain. Based on our findings, we designed ROV based repair solution that would not require the plant to be dewatered or taken out of service. All of the holes where repaired by installing packer style plugs during short daily shut downs scheduled allowing the plant to generate on its normal schedule. In addition, the problem was identified while the construction warranty was still in effect which eliminated any cost to the client.

This repair required innovation not only in equipment, but also method because it had to be done, at approximately 100 meters of pressure depth where diving would not have been practical. In addition, the repair had to be accomplished during short shut downs each day so there was no loss of generation revenue.

We constructed a custom tool skid for one of our ROVs to install custom packer plugs into the holes. These packers were installed while the water was flowing through the holes but the headrace tunnel was shut down. The alternative repair method would have required a long shut down and completely dewatering the tunnel and a manned entry. Our method saved time, kept the plant in service and generating, and didn’t require any confined entry.

As well as the hydro and dam sectors, can you give an overview of other infrastructure projects where Hibbard’s services are currently being utilized?

Another key sector for our services is the Water and Wastewater Sector. We inspect large aqueduct tunnels, large sewer tunnels, and ocean and river outfalls. Many of the methods used in the hydro and dam sectors apply to water and wastewater. In the power generation sector, we inspect cooling intakes and outlets for fossil fuel and nuclear power plants.

Many of your inspections can be performed ‘in-flow’, ensuring continued generation and of course minimize outage times. Can you provide an instance of how this can be the case and describe the process itself?

There are economic, environmental and other factors, which can make it important to keep the water flowing in a power plant or aqueduct tunnel. We have developed methods and equipment to inspect long tunnels to 20 km or more in length with or without the water flowing. Hibbard Inshore is the only company that can inspect tunnels this long using our unique Hybrid AUV/ROV (Autonomous Underwater Vehicle / Remotely Operated Vehicle) technology.

One of the best applications of our technology operating in flow is in power plants that directly power metal refineries or similar types of manufacturing plants. While the electricity cost of shutting down a power plant is significant, adding the cost of shutting down a

manufacturing facility is much larger. Recently, we used our Hybrid AUV/ROV vehicle to inspect a long tunnel of a power plant while it operated at partial flow. The tunnel overall length was 18km. This partial water flow allowed the metal refinery to “coast” its kilns so that they wouldn’t have to shut down the refinery. This was a large cost benefit to the client.

Another application of our new technology is in large city aqueduct tunnels. Often, cities only have one water supply and a limited amount of storage at the downstream end of the tunnel.

Our technology can inspect while the tunnel is at partial flow rate during a low water demand time to keep water service to the city. While an aqueduct doesn’t directly produce revenue it is very important to keep water service for fire protection, health and disruption to local business.

Hibbard Inshore using underwater drill to prepare hole for packer installation.

Can you give a breakdown of the latest AUV/ROV Hybrid technology, which is now fully operational by Hibbard?

Our latest long tunnel inspection capability comes from a Saab Seaeye Sabertooth AUV/ ROV. The system has been customized with a suite of tunnel inspection sensors and autonomous navigation software. The unique autonomous tunnel navigation software allows the Sabertooth to navigate complex tunnel structures when the tether isn’t connected.

Based upon tunnel conditions, we can choose to operate the vehicle with or without the tether connected. When the tether is connected, it operates like a standard ROV. Without the tether, the Sabertooth will behave as an AUV. The vehicle also has the ability to change its orientation and fly in a full 6 degrees of freedom. This is most important for getting access into the tunnel as it allows the vehicle to fit through small access shafts, gate slots, surge shafts and other structures.

We have outfitted the vehicle with the sensors specifically for tunnel work. The vehicle has both color and low light black and white video cameras for visual inspection work. The vehicle also has multiple sonar heads that create an image of the tunnel walls ahead of the ROV. These sensors can show concrete joints, debris, large cracks, spalls and many other types of features required for structural inspections. An additional sonar

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INTERVIEW: HIBBARD, ROV & THE ASIAN MARKET

Hybrid AUV/ROV being lowered into water to preform long tunnel inspection.

system on the Sabertooth creates a 3D map of the inside of the tunnel. The 3D map is geo-referenced, providing exact locations of problem areas, such as cross-section loss, cave-ins and debris accumulation. Common software such as CAD can then be utilized to evaluate the data for lifespan assessment or possible repairs.

the plant can continue to generate during peak hours saving the client from a total shut down and revenue loss. We have performed these types of repairs at depths from 100 to 300 meters in the last year. There is no difference to the ROV if we perform these tasks at deeper depths.

Some examples of repairs made with ROVs include in-tunnel trash rack repair, rock trap cleaning, concrete placement and temporary or permanent hole plugging. The hole plugging can range from small diameter (50 mm) plugs installed by an ROV to bulkheads (3m +) for turbine shut off valve replacement. The temporary bulkheads are engineered specifically for each application to facilitate the changing of one valve while leaving the rest of the plant in service.

How can power plant operators benefit from an unmanned ROV repair techniques?

We have developed equipment and techniques to repair tunnels, shafts and other structures underwater. By performing these tasks underwater, we can avoid dewatering the tunnel. This eliminates the risk of cave in from dewatering and the loss of revenue from long shut downs. Often, our repairs can be performed at night during off peak hours so

Damaged Trash rack section being lifted out of a surge shaft after our ROV cut through steel beams at a depth of 120 meters to free it.

3D Tunnel Map and ROV track

New trash rack being replaced through surge shaft

Can you provide an overview of your services toward the water and wastewater sectors?

The hydroelectric and water and wastewater industries are relatively similar in terms of inspecting long tunnels. While some criteria are different, they still require an ROV or Hybrid AUV/ROV to inspect the long tunnels. Our video and sonar inspection methods apply equally as well in any of these types of tunnels. It is important to inspect aqueducts to keep water flowing continuously to major cities. Our technology helps municipalities make capital improvement and risk decisions about their water and waste water supplies to keep their communities healthy and government within budgets. Many cities only have one water supply tunnel and therefore a preventative maintenance program to prevent a catastrophic shut down is very important. Because we can perform inspections at longer ranges without dewatering, we can inspect tunnels, aqueducts and sewers that were previously unable to be inspected because they were fully flooded or too far from available access points.

Finally, what further developments can you see becoming available in the years to come that can continue to assist toward the underwater inspection field?

Hibbard Inshore has been providing inspection services and developing long tunnel inspection technology since 1984. We have seen the resolution of video cameras, sonar heads and other sensors increase steadily since this time. The cost of these components has also been improving. Looking forward, the most important technology for long tunnel inspection is battery technology. While our Hybrid AUV/ ROV represents a large leap in technology to inspect longer tunnels with higher resolutions sensors, this range will increase as battery and other technologies continue to improve.

Bradley L. Hibbard President and Chief Applications Engineer

Brad Hibbard has been working with ROV’s for 23 years and president of Hibbard Inshore for the last 11 years. Prior to this, he had been a lead ROV pilot and project engineer. His ROV experience includes inland structural inspection and construction in hydroelectric plants, nuclear plants, large water intake systems, large sewers, treatment plants, and ocean outfalls. He is a graduate of the College of Engineering, Dept. of Naval Architecture and Marine Engineering at the University of Michigan (B.S.E., N.A.M.E.)

26 POWER INSIDER JUL / AUG 2013

ROV Inspection and Maintenance of Underwater Structures Managing and maintaining the condition of critical structures and assets for functionality, lifespan assessment, and regulatory on the underwater portions of structures allowing for planning and performance of necessary maintenance.

STRUCTURES INSPECTED Trash Racks Lower Outlets Face of Dam Intakes Head Gates and Seals Stoplogs Reservoir Bathymetry Toe of Dam Penstocks (Flooded & Dry) Turbines & Turbine Shut Off Valves Diversion Tunnels Long Conveyance Tunnels

INSPECTION EQUIPMENT Monochrome & Color Video Imaging Sonar 3D Sonar Ultrasonic Thickness Sensing Ground Penetrating Radar Navigation & Tracking Systems ROV penetrations to +20 kilometers and 2,000 meters of pressure/depth Swimming, Floating & Crawling Vehicles

ROV UNDERWATER INSPECTION SERVICES Dredging in Front of Units Bulkheading Deep Water Trash Rack Removal/Replacement Underwater Cleaning Cutting Lifting

Hibbard Inshore LLC. | tel: +1.248.745.8456 | www.hibbardinshore.com | info@hibbardinshore.com

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Playing the Gas Game with Australian Coal Mining

Robin Samuels examines how the Australian coal mining industry has handled the impact of the carbon tax, made efforts to improve environmental compliance, and their increasing utilization of gas.

Photo: BHP Billiton’s Illawarra Coal

T

he Australian coal mining sector is facing a tremendous amount of pressure, in what can only be described as a testing period for an industry that has experienced stratospheric growth since the mid 2000’s.

This article will look at some key Anglo American, Glencore Xstrata and BHP Billiton assets to understand the impact of the carbon ‘tax’, and efforts that these companies are making to improve their own environmental compliance in the diesel fleet, and in turn that of the power industry, through a growing utilization of gas.

The slump in commodity prices associated with China’s economic slowdown has had a dramatic knock on effect for the industry at a time when the government

28 POWER INSIDER JUL / AUG 2013

should have done more to support one of the country’s most important economic contributors. In an ideal world this would have been the case, but the past two years have unfortunately told a very different story, costing the industry billions in lost revenue and job cuts.

Australia’s political rollercoaster has been strategically spearheading energy in their campaign for a long time, pledging allegiance to either the green or natural resources argument. The mining and oil and gas sectors contain some politically influential figures, which will have been lost during campaigns for greener energy and after Julia Gillards hallmark carbon price legislation. Kevin Rudd’s revision on this legislation is undoubtedly part of an intricate plot to win back support from these quarters. However, is the early move to a floating carbon price too little, too late?

The political agenda has put greenhouse gases (GHG) produced in the mining sector under the microscope, including carbon dioxide, methane, nitrous oxide and perfluorocarbon from aluminium smelting. Despite the undeniable contributions this industry has on the environment, some have been offset with commendable investment into initiatives that increase energy efficiency and reduce emissions, with encouraging results. These investments have been ongoing long before the carbon tax and warrant plaudits for efforts in diesel displacement in favour of gas for power generation, going above and beyond in diesel fleet maintenance practises, commercialising carbon capture and storage methods, and deploying coal conversion technologies that produce liquid fuels and synthetic gas.

feature

Dealing with Diesel The use of diesel powered plant in underground mining has steadily increased in the last 30 years. During this time, diesel driven mechanised machinery has replaced physical labour or pneumatically driven machines. Today there is a mechanised diesel unit for most aspects of a typical underground mining operation. The fuel source has become an essential component in catering for the daily operations of a mine, whether that be a haulage system, loader, dumper, minecruiser or diesel generator set to provide high specific power to conveyors and longwall shearers of remote mines in the Pilbara or emergency backup for the grid connected mines in New South Wales.

Australia has generally benefited from the importation of engines compliant with United States (EPA Tier 1 to 4), European Union (Stage I to IV) and other emission standards,

which has contributed to significantly reduced emissions of the above in comparison to China and Indonesia. To maintain these performance and strict emission levels, mine operators have to be extremely aware of engine conditions and vigilant in maintenance strategy.

Tier 1 and 2 engines are less sophisticated than more modern engines and produce low torque compared with typical surface machinery. It was noted that the likes of Glencore, Anglo and BHP took exception when these engines are overhauled, to install new components supplied by the original equipment manufacturer (OEM) and taking advantage of low sulphur fuels and improving fuel efficiency. Such components include more advanced fuel injector systems and electronic control unit functionality, which allow the operating life of older engines to be extended with reduced emissions. With the right configurations, refurbished engines and

In the modern era, growth in innovative lean burn gas combustion technology is opening a new value proposition to the mining industry

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Power supply for the coal conveyor needs to be reliable, ensuring maximum mine profitability

their supporting components can closely emulate the emission characteristics of Tier 3 and 4 engines. This is in accordance with regular checks on air intake condition, optimal engine temperatures and engine oil behaviour.

The miners are vigilant in regular general engine body gas testing and the use of disposable components such as particulate filters. Glencore Xstrata, in particular, have shown considerable investment into this area. In 2012 alone they went through a phenomenal 16,500 filters on the Bulga mine through 83,000 operational machine hours, a significant additional overhead in emission reduction efforts. This is despite the logistical challenges with replacing old filters and the consensus that more emissions are created when the filters are blocked, changing engine burn characteristics.

The efforts of these companies indicates that successful diesel emissions management programs are those taking a holistic approach to deal with a broad range of risk factors.

Successful strategies are those that eliminate or reduce diesel engine emissions at their source and at the transmission of diesel particulate matter through the underground environment and personal exposure. These are challenging operational practises, which have been overlooked in the damaging carbon tax. What should have been implemented is

30 POWER INSIDER JUL / AUG 2013

perhaps a more progressive scheme offering incentives when operational expenditure like this is outlaid to the diesel engine maintenance program, not forgetting that these engines are manufactured to meet strict international emission legislation and purchased on this basis.

The Impact of Methane Methane accounts for a significant portion of the GHG emissions produced in mining.

Each tonne has a global warming potential 21 times greater than that of CO2 over a one hundred year horizon. The methane content in coal seams generally increase further down the seam, and also with age. As the depth of the coal seam increases, so does the pressure level. This in turn reduces the level of permeability, causing the methane to be much more tightly bound to the coal and surrounding rock strata. Underground mining can therefore produce substantially greater levels of methane than surface mining. In fact, underground mines account for the overwhelming majority (up to 90%) of all methane emissions from the coal sector.

In addition to its potency as a GHG, methane is also a major safety concern for underground coal mining. To ensure mine safety, fresh air is circulated through underground coal mines using elaborate ventilation systems, diluting mine

concentrations of methane to levels well below explosive levels. These systems then vent the low concentrations of methane to the atmosphere. Flaring has been the other traditional disposal method, which has ramifications of its own, for what is proving to be a valuable commodity.

For years methane had been seen as an operational hazard coming hand in hand with an expensive, yet mandatory, dispersion process. In the modern era, growth in innovative lean burn gas combustion technology is opening a new value proposition to the mining industry, offering the potential to increase the financial benefits from abating a given volume of gas, derived from the sale of carbon credits and electricity, but also by offsetting diesel use and catering for onsite power requirements.

The concept is being adopted across the mining industry globally, but Australia has been one of the most forward thinking nations with some of the first installations in 1996. The introduction of schemes such as the New South Wales Greenhouse Gas Abatement Scheme (GGAS) and the federal government’s Greenhouse Friendly program helped a number of utilization projects to commence. The next part of the article will look at some of the most successful installations to date.

FEATURE: PLAYING THE GAS GAME WITH AUSTRALIAN COAL MINING BHP Billiton’s Benchmark with the Appin and Tower Mines Illawarra Coal is BHP Billiton’s wholly owned subsidiary, that owns and operates three high volume underground longwall mines – Appin, West Cliff and Tower Mines.

The mines operate in the Wongawilli and Bulli Seams at depths ranging from 180 metres to over 500 metres.

The Appin and Tower sites constitute what is arguably the largest coal seam gas energy project in the world, and one of the world’s largest reciprocating engine-generator installations of any kind. Consuming 600,000 m3 of coal seam gas per day (supplemented when necessary by natural gas from Moomba, Australia), the generating equipment delivers a combined 97 MW of continuous capacity to the local utility grid.

The most common engine utilising methane gas for minesite power generation are the 1.0MW units such as the Caterpillar 3516 and GE Jenbacher 320 In the early days when potential was being realised, gas turbines were first used to generate electricity from coal mine’s methane.

The increasing maintenance costs and inefficiencies associated with variable drainage gas concentration led to the decommissioning of these units.

Despite some concern that multiple reciprocating generator sets would pose challenges with service, parts and consumable supplies, analysis found that the engine based system was the most attractive solution based on both capital and long-term operating costs. After the unsuccessful attempt with gas turbines, BHP Illawarra were not content with giving up and wanted to realise the potential of harnessing this waste gas. In 1995, prominent operator Energy Developments Ltd undertook the installation of a phenomenal 94 x 1.03 MW Cat®G3516 generator sets that utilised methane gas as the primary fuel. 54 of the G3516 generator sets were delivered and installed at the Appin site, with the remaining 40 going to the Tower site.

The G3516 generator sets are driven by 16 cylinder, lean burn engines operating at 1,500 rpm, coupled to SR4 brushless generators.

The engines’ lean fuel mixture is controlled by an electronic system that regulates the air/ fuel ratio for maximum performance and

minimum emissions under varying load, fuel and temperature conditions. Of the total 97 MW capacity, 4 - 10 MW is generally delivered for mine use, significantly offsetting diesel use from traditional stationary power units.

Anglo American: Dealing with Scale Anglo American is a leading supplier of metallurgical and steaming coal to hungry buyers in Asia. They have significant interests in Australia, and as part of their operations they mine two major underground sites rich in coal seam methane; Moranbah North and Capcoal. In recognition of the resources available, they undertook an investigation of delivering this gas to fire two power stations as part of an intricate and environmentally conscious abatement scheme.

Moranbah North is an underground longwall mining operation which began in 1998. In 2008 GE Jenbacher distributor Clarke Energy and Energy Developments Ltd delivered 15 x 3 MW GE Jenbacher gas engines with electrical efficiencies higher than 43%. The engines were installed in purpose built individual enclosures, each with their own engine control compartment located at one end of the enclosure. Gas pre-treatment and conditioning ensures that gas is delivered to engines in the right conditions for combustion. The properties of this gas deliver a methane level, which varies from 50 – 90%.

Despite the recent mining slump, Anglo American are engineering a AUD 1.7 billion growth project currently under development in the Moranbah region of Queensland’s northern Bowen Basin. It involves developing a greenfield underground coal mine called Grosvener, with an anticipated mine life in excess of 30 years. Energy Developments Limited are responsible for the operation of the power station, and they have entered into a new agreement for Anglo American’s metallurgical coal business to continue its supply of waste coal mine gas to the

Moranbah North power station, providing an opportunity to develop an 18 MW expansion of the current 45 MW plant.

German Creek Power Station is the second power plant utilizing the Anglo American waste coal mine gas from the Capcoal project.

The supply of methane for this initiative is delivered from the Grasstree Mine. The power plant stands at an impressive 45 MW, after a recent expansion in the beginning of 2013.

It consists of 16 x 2 MW power generation modules using Caterpillar 3520C generator sets and 4 x 3.3 MW GE Jenbacher J620 generator sets.

Glencore Xstrata: A Leading Example Glencore’s recent takeover of Xstrata coal has not prevented them from investing into intensive energy efficiency and GHG abatement schemes, leading to self sufficiency in power generation across a number of sites. The biggest coal miners in Australia have a huge asset base across open cut and underground operations, looking to displace diesel and grid dependence wherever possible with gas resources.

The first installations took place at the Tahmoor and Teralba mines. The Tahmoor mine employs 7 x 1 MW GE Jenbacher 320 gas engines, catering for its own power needs through the low grade gas directly fed from the existing coal mine’s extraction plant, which receives only minimal treatment before reaching the generators. The Teralba mine is now closed, but still powers the grid using a 4 MW plant of GE Jenbacher 320s. It was a larger plant with 8 generator sets, but gas output declined along with mining operations.

The Bulga complex is the latest development undertaken and also the biggest, after receiving approval to construct and operate 41 MW of generating capacity. The first stage, delivered in the middle of 2012, consists of 3 x 3.3 MW GE Jenbacher J620 gas engines catering for continuous and reliable power supply needed to ensure maximum production of the

Anglo American haul trucks ready for a day of production

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FEATURE: PLAYING THE GAS GAME WITH AUSTRALIAN COAL MINING

Underground coal mining operations

underground mine, but also independence from the grid.

Oaky Creek is arguably Xstrata Coal’s most successful foray into waste coal mine gas use in terms of gas consistency. Commissioned in 2006, the power station was initially designed with 10 x 1 MW GE Jenbacher 320 gas engines operating exclusively on stock supplied from Oaky 1 and Oaky North Coal Mines.

During the latter stages of construction it was decided to relocate a further four generators from Teralba Power Station, bringing capacity to 14 MW. In mid 2009 the Oaky power station was further expanded to take advantage of increased waste gas extraction and greater consistency in quality of gas. Two new GE Jenbacher 620 gas engines with a nominal output of 3.3 MW each were installed and commissioned in 4 months, bringing total capacity of the power station to 20 MW. Waste mine gas is transferred from the mine’s existing gas drainage wells by gas extraction pumps located within the power station compound. Surface laid polyethylene pipelines directly connect the power station to Oaky North and Oaky 1 Mine’s operating surface to both in seam and goaf gas drainage wells. The connection points of the

Regular maintenance duties on a haul truck

32 POWER INSIDER JUL / AUG 2013

A balance is key and increased support from the government needs to be delivered constructively, to secure and safeguard a major component of Australia’s economic future pipelines to the surface well heads are designed to move from time to time as a result of advancing mining operations. The connection points will generally be located in advance of (in seam) and behind (goaf ) the current longwall mining operations in both mines.

LNG - Not Just for Export The LNG industry in Australia is about to become the world’s biggest, but despite the huge investment going into the export market, the mining industry is excitingly emerging as a huge destination for domestic use. Shell in particular are looking to introduce LNG powered fleets at Australian mines as part of a push to increase natural gas use beyond export.

Gas can be introduced by modifying engines and tanks, but it will require a huge amount of cooperation from the engine OEMs, fuel suppliers, and governments to ensure that barriers surrounding gas supply, transport, storage and truck conversion can be passed.

Westport Resources Australia and Caterpillar have recently joined forces to

develop natural gas fuel systems for mine trucks and EMD locomotives, a positive move and indication that maybe gas will one day become the predominant fuel in mining.

These changes cannot be made overnight and consideration has to be made towards the steps that miners are making to invest in implementation. One factor in particular has to be apparent for success of these transitional efforts; leniency in the carbon tax to allow a clear price signal and a predictable and gradual system that allows aggregate revenues to be returned into helping with capital investment into areas such as the LNG network, a dual fuel conversion, or a methane fired power plant. A balance is key and increased support from the government needs to be delivered constructively, to secure and safeguard a major component of Australia’s economic future. PI

GET INVOLVED IN THE DEBATE! Is the Australian Government doing enough to protect such a key industry?

Is their quest for green energy crippling the economy? Is it fair to impose a carbon price on an industry that is already regulating itself in terms of emissions and waste reduction?

Join the debate and tell us what you think on Twitter, LinkedIn and on our website: www.pimagazine-asia.com Alternatively, email the editor: rachael@sks-global.com

InteliBifuel The safe way to save money

AVOID THE COSTS OF DIESEL DEPENDENCY WITH COMAP INTELIBIFUEL CONTROLLERS InteliBifuel system, allowing engines to run on both diesel and gas at the same time.

This proven and economic solution can reduce fuel operating costs up to 75%.

ComAp InteliBifuel system – advanced PLC controller, anti-knocking unit and a dual fuel module Standard and proprietary CAN J1939 protocols for a wide range of EFI engines Remote communication and event logging Safe proven solution with a excellent “return on investment” benefits Optimised operational efficiency

Visit the ComAp website:

www.comap.cz/savemoney

Two Fuels, Limitless Potential:

The Growth of Bi-Fuel Technology

WE ASKED LUKAS NOVAK ABOUT BI-FUEL APPLICATIONS IN ASIA

PI Magazine spoke to Lukas Novak, the Business Development Manager of ComAp’s Bi-Fuel Division, about the application of an exciting technology. ComAp’s Bi-fuel system enables diesel engines to not only use two fuels, but also transition smoothly between each with no interruption to performance. We asked Mr. Novak to tell us about bi-fuel’s potential applications, and about ComAp’s activities in Asia.

Can you tell us about what work ComAp is currently undertaking within the Asian power sector?

Thank you for inviting me to discuss ComAp’ s progress. As you may recall from last year’s ComAp feature on remote communications, we are committed to being a market leader in all aspects of engine control systems, and to deliver innovative solutions for our customers worldwide. I am personally responsible for the bi-fuel product range, which is a clever configuration that enables diesel engines to use two fuels (gas and diesel) at the same time. ComAp has a very strong network in Asia with leading distributors in Indonesia, Thailand, Vietnam, Malaysia and Australia all offering on demand support to engine operators and OEMs. This network is supplemented by our regional office in Singapore.

When and how did ComAp become involved in bi-fuel conversions?

34 POWER INSIDER JUL / AUG 2013

The first bi-fuel conversions for ComAp started way back in 1995 on slow speed ŠKODA (CKD) diesel engines, so we’ve got a lot of experience and knowledge on the subject. Since then, we have grown to become one of leading suppliers of bi-fuel solutions and bi-fuel conversion components through satisfying a phenomenal demand for cost savings on fuel in industries that are dependent on continuous, prime and standby diesel engines. We now offer a range of ComAp InteliBiFuel controllers suitable

Our extensive experience and knowledge of control allows us to carefully monitor and automate the essential engine parameters

for any high speed four stroke engines with fully integrated control panel, comprehensive knocking detection and diesel monitoring system.

The range also boasts complete gas feed and air manifold vacuum feedback hoses, fully certified gas trains, gas actuators and gas/ air blenders. Our extensive experience and knowledge of control allows us to carefully monitor and automate the essential engine parameters to always stay within the engine specifications. We have learnt to consider every case individually regardless of how many times we have applied our product to a specific engine type or industry: This is not a sector to be complacent in.

Dual fuel consideration is a big talking point at the moment for a number of reasons, but is main driver the rising cost of diesel?

Yes, the cost of diesel is a major concern for operators all across Asia, and some markets are also facing the pressure of stringent carbon tax

INTERVIEW

penalties: These changes are certainly leading more companies to consider bi-fuel conversion, not only the end user customer, but business to business oriented customers like O.E.M.’s, packagers, engine dealers etc. In particular, industries such as mining and oil and gas are facing a transitional period with increasing environmental challenges, but they or their customers are also in a fortunate position with access to associated gas resources from wells and underground mines, that are commonly just vented and flared. This gas can in fact be directed to the diesel engine and used for power generation, when fed through a bi-fuel conversion. This can reduce operating costs substantially, as depending on the type of engine, typical gas/diesel ratios after conversion are up to 70% gas/30% diesel, which means in most cases customers will enjoy a very short return on their investment. In fact, we’ve calculated that the typical return of investment is around two - four months, and for oil and gas industries it’s even shorter.

Are there limitations on the types of gas that can be used for bi-fuel engine operation?

Generally, the most suitable gas types are methane based with very low traces of propane - similar to what is typically found in natural gas. We will always undertake an in depth consultation on gas type after receiving the specification from the customer to ensure compatibility. Bi-fuel conversion can also be possible with biogas, provided that we know the composition and calorific value so are able to evaluate if the specific properties are suitable.

Calorific value can sometimes be an issue as biogas is derived from different sources, with low calorific value in many cases. You can imagine we have to inject a sufficient volume of gas into the cylinder to substitute diesel oil: If the calorific value of the biogas is very low, we would need to inject a larger volume of biogas into the cylinder, which could be technically impossible. We always want to advise on the best possible practise from an operational standpoint, which is why we are happy to work hard at evaluating the gas sample.

protect the engine against knocking. As an example, we have generally calculated that if the LPG consists of 50% propane and 50% butane. The so called sweet spot of the bi-fuel operation will be around 60% of the engine’s nominal power, and the LPG/diesel ratio would be expected around 60/40%. As the engine power increases, our system has to automatically decrease LPG/diesel ratio to keep engine operating in safe parameters below the O.E.M’s limits. Therefore operation on higher loads is possible and just the LPG/ diesel ratio is affected. Of course, exact calculations would have to be done for the specific engine type.

Is it necessary to stop the engine for the required transition between bi-fuel and pure diesel operation modes?

No, transitions between the two modes (from bi-fuel to diesel and vice versa) can be achieved while the engine is running (i.e. without interruption of the load supply) and is a very smooth process. The engine will always start on diesel and the operation mode is switched to bi-fuel upon a predefined output level (around 20%). In case of gas shortage, the transition is immediate and seamless at the actual engine load, gas valves are shut off automatically and the engine continues on pure diesel operation.

Once the gas supply has returned the engine is switched back to bi-fuel operation, offering genuine fuel flexibility.

So what are the standout features of the ComAp system?

Our system is mainly concerned with engine safety and the modulation of gas quantity through the whole engine operational range.

Knocking and proper detonation in combustion chamber is one of the major challenges concerned with bi-fuel and it is the most important factor for long-term safe engine operation on Bi-Fuel. ComAp solution is

equipped with comprehensive anti-knocking protection system InteliBifuel DENOX 2 / 20, and offer same level of safety and control as is used on gas engines. Therefore proper detonation principle without knocking is ensured.

This phenomenon exists with standard methane based gas and is getting more and more sensitive in case a different type of gas is used (wellhead gas on drilling rigs with transient load, etc.). Wellhead gas contains hydrocarbons such as propane, butane, pentane, and hexane. The introduction of these gases to compression ignition engines often leads to engine knock, but to counteract this, as standard, we install our anti-knocking detector/ controller ‘InteliBifuel DENOX’. This unit also ensures that engine operation is always with the most efficient gas/diesel ratio possible and always in safe limits for the engine. The ComAp Bi-fuel system is a fully independent and standalone control system ensuring that, if needed, 100% diesel operation is possible at any time in order to avoid knocking.

Is there not a risk of exceeding engine parameters when trying to maximise diesel substitution?

The integrated ComAp Bi-Fuel solution independently monitors the vital engine

When engines are in remote locations with zero access to main gas infrastructure, can LPG be used?

In the case of LPG, the bi-fuel conversion is also generally possible, but the situation is different. The LPG has acceptable calorific values; the composition is also ok considering there are no aggressive elements (sulfur, hydrogen etc.). However LPG is more explosive than natural gas and therefore it has a tendency for “knocking”. Thus, we expect that ideal LPG/diesel ratio will be achieved on slightly lower load compare to standard natural gas bi-fuel operation to

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INTERVIEW: THE GROWTH OF BI-FUEL TECHNOLOGY parameters automatically whilst operating in bi-fuel mode and does not interfere with operation of the original equipment manufacturers’ existing safety shutdown protections or control of the engine/generator.

Our system is a fully automatic (modulating/ dynamic) solution fitted with a gas throttle actuator. This allows increase and decrease of the gas amount across the engine loading range automatically without any manual or regular adjustment required from the operator.

This maximizes the gas usage safely, whilst achieving the maximum fuel savings.

The oil and gas industry offers the most potential for bi-fuel conversion; can you explain why?

Gas is often considered as a by-product of oil drilling, and therefore it’s still being flared in the majority of installations. However in many countries there are new regulations that prohibit atmospheric wastage of gas into the air and are lobbying for companies to use it in any way that’s feasible. In many cases the gas is of poor quality and transient load meaning it’s unsuitable for use in gas engines.

Bi-fuel conversion is often the logical and effective solution. Furthermore, with the rise in popularity of shale gas and oil operations, the use of the gas ‘by-product’ will only grow more relevant, and bi-fuel can have a prominent role in finding the solution.

The standby generator sets used in industries like data centres, financing and healthcare are also very good candidates, can you explain why this is?

An engine is with ComAp Bi-Fuel technology can operate up to 60-70% longer with same size of fuel storage

Although there is an initial cost involved with conversion, and considering conversion of their standby generators, those industries will still enjoy significant benefits.

Many companies are trying to be more environmentally friendly and bi-fuel can lead to lower emissions, in tandem with applying a catalytic converter. Bi-fuel engines often have longer life spans and require less servicing, which are attractive reasons for customers. A further example are the customers who have limited space for fuel storage, and an engine is with ComAp Bi-Fuel technology can operate for a much longer time (up to 60-70% longer) with same size of fuel storage.

Can you tell us about some of your key successes so far in Asia? And which countries do you feel will experience the strongest adoption of bi-fuel conversions in Asia in the next 5 years?

ComAp offers the most comprehensive solution and, thankfully, our customers and distributors agree. The ComAp combination of operational effectiveness and safety is widely used and recommended by the key players in the engine industry. We work globally with major engine brands and provide the ideal products and service for their customers.

Our products, market position and industry reputation means I’m confident regarding future success. I wouldn’t want to predict outcomes for particular countries, but I think it’s fair to say that due to gas availability in the Asia region, along with costs and environmental reasons, bi-fuel conversions will continue to increase in popularity and become widely used in Asia. We are heading towards a very interesting few years. PI

36 POWER INSIDER JUL / AUG 2013

POWER GENERATION Repair : Refurb : Rewind Australian Winders can offer complete inspection, testing, cleaning and overhaul of all your power generation equipment from hydro through conventional cooled to high voltage liquid cooled units.

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We offer project management, self sufficient winding teams, or just supplemental project labour at cost effective rates.

Australian Winders can provide inexpensive solutions for your power generation equipment service allowing you to get back in service quickly saving considerable lost revenue.

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feature

The Origin of Gas Turbines

GE LM6000 PH is expected to see fast growth in Australia

The Australian energy sector is cleaning up. A significant component in its transformation is gas, and Origin Energy is the largest owner and developer of gas fired power generation in Australia. Robin Samuels explored Origin’s vast fleet of gas turbines under their operation.

E

nsuring that Australia has well functioning gas markets, that deliver reliable, efficient and competitively priced energy is vital to Australia’s economy. The nation’s gas markets are projected to undergo major changes in the period to 2030, with the development of new conventional and unconventional resources expected to triple domestic gas production over the period in response to strong international and domestic demand growth.

The growth in the use of natural gas for electricity generation is also resulting in closer links between the gas and electricity markets, which is where the strengths of a company like Origin Energy really come into play, offering capability and experience to both sectors.

38 POWER INSIDER JUL / AUG 2013

Catering for Peak Demand Origin is currently operating seven gas fired power stations across New South Wales, Queensland, South Australia and Victoria.

I was interested in the differing gas turbines installed for these plants, understanding the cyclic duties, performance and procurement drivers behind Australia’s most impressive largest portfolio of gas generation.

In line with Australia’s effort to reduce the carbon footprint, gas turbines are the popular choice for new capacity, owing to their flexibility and fast compensation for the grid fluctuation as renewables are integrated. Origin have been considerate in gas turbine selection, operating at least a model from each of the big four in GE, Siemens, Alstom and MHI. At present the bulk of operational activity for Origin’s expansive gas fired portfolio takes places during peak hours.

The plants have the ability to start up at very short notice, ramping up production in response to rising demand. For example, when the hot Australian summer relies on the heavy energy consumption of air conditioning to keep cool.

The Importance of Quality Maintenance Maintenance costs and part availability are two of the most important concerns for a heavy duty gas turbine equipment owner. With peaking plants this is no exception, and perhaps of even more significance because of this, they are relied upon to supplement the grid when it most needs additional capacity. Maintenance programs can be challenging given that gas turbines wear in different ways for different service duties, and with peaking machines, thermal mechanical fatigue is the dominant limiter of life.

Significant operation at peak load, because of the higher operating temperatures, will require more frequent maintenance and replacement of hot gas path components. However it is vital to understand and account for the impact that starting cycle (hours per start), power setting, fuel, level of steam or water injection, and site environmental conditions can all have in the life of replaceable gas turbine parts and the subsequent planning of a maintenance interval programme.

Last year alone, Origin’s generation, operating and maintenance costs increased

by AUD 2 per MWh to AUD 6 per MWh, owing in part to a full year of costs for the Eraring acquisition. As a consequence, the generation portfolio was able to achieve very high levels of availability and reliability during the period, with availability of 95% versus 90% in the prior year, unplanned outages of 2.0% down from 3.3% in the prior year, and

an equivalent reliability factor of at least 97% achieved for all peaking sites for the year.

Ladbroke Grove Power Station Ladbroke Grove Power Station is one of Origin’s oldest natural gas fired power stations, located in South Australia. When it became operational in 2000, it was Australia’s first integrated gas fired power station. Ladbroke Grove operates two open cycle GE LM6000 gas turbines to generate 86 MW of electricity.

The machines were manufactured by GE IAD at its Evendale facility in Ohio, but then placed into a power generation package delivered by Alstom Gas Turbines.

This was one of the first GE LM6000 models to have modified fuel nozzles enabling it to burn the medium BTU fuel available at the Ladbroke Grove site. This fuel has relatively high CO2 content, resulting in a lower heating value of about 500 Btu/scf.

Maintenance programs can be challenging given that gas turbines wear in different ways for different service duties, and with peaking machines, thermal mechanical fatigue is the dominant limiter of life

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FEATURE: THE ORIGIN OF GAS TURBINES

Siemens SGT5-4000F installed on the Mortlake Power Station

The Ladbroke Grove Power Station

GE’s turbine had also incorporated an option for combustor water injection for emissions reduction. This important innovation provides reliable start up capabilities as well as NOx control, and has been adopted heavily in newer models of the aeroderivitive range. The first gas turbine generator was commissioned in January 2000 and the second began commercial operation in June 2000.

40 POWER INSIDER JUL / AUG 2013

The power plant experienced a major failed generator stator in 2004, where the stator end windings overheated and failed catastrophically requiring a complete rewind, leaving the unit in forced outage for around six months. It was found that the surface temperature of the stator end windings was running in excess of 110°C. These excessive temperatures were thought to be due to poor design of the cooling air through the stator.

Quarantine Power Station The Quarantine power station is Origin’s other major peaking facility in South Australia.

It first went into operation during 2001 following the installation of four GT10B Alstom gas turbines and was originally rated at 95 MW. In 2009, Origin spent AUD 80 million on expanding the Quarantine Power Station from 95 MW to 216 MW. The addition of a new GE Frame 9E gas turbine generator set was installed adjacent to the existing plant, in order to meet the growing demand for peak electricity in South Australia, catering for the significant wind farm growth taking place throughout the state.

Mt Stuart Mt Stuart is a peaking power station with a total capacity of 414 MW, making it one of

the largest power plants in North Queensland.

Origin acquired Mt Stuart in January 2003 from AES Corporation, at which time it had a capacity of 288 MW. The plant originally featured two 114 MW M701D Mitsubishi gas turbines which had been in operation since the plant’s inception in January 1999. The primary fuel source was originally kerosene (Jet-A1) liquid fuel, however the plant was eventually converted to gas.

In 2008, Origin undertook an expansion of Mt Stuart, installing a 126 MW GE Frame 9E turbine generator. The turbine featured evaporative inlet air cooling and NOx reducing demineralised water injection, with an intricate control system, including an Allen Bradley BOP PLC interfacing with GE Mk6 controller.

Mortlake Mortlake power station is the newest addition to the Origin’s gas turbine family, and is also home to Australia’s first Siemens SGT5-4000F installation. The plant consists of two open cycle units of the very large gas turbines, each capable of delivering 275 MW. This gas turbine is at the top of its class, and consists of an annular, walk in combustion chamber with 24 hybrid burners, ceramic combustion chamber tiles, a 15 stage axial flow compressor

Maintenance tailored to your needs Reduced downtime for your rotating equipment To keep your equipment running, Sulzer Turbo Services provides technical support, plant upgrades, refurbishment, long-term maintenance and service contracts for your steam and gas turbines, compressors, motors and generators.

With our tailored solutions you have more time to concentrate on your core business.

Scan the code for more information

www.sulzer.com

Download the TS Solutions App from the App store

Sulzer Turbo Services Asia 7500A Beach Rd #16-324 The Plaza Singapore, 199591 Tel: +65 6391 0628 Fax: +65 6391 0631

FEATURE: THE ORIGIN OF GAS TURBINES with optimized flow distribution (controlled diffusion airfoils), single crystal turbine blades with thermal barrier coating and film cooling, a low NOx combustion system and advanced cooling technology.

The first unit of the plant became operational in 2012 after four years of challenging construction conditions.

Provisions have made so that Origin have the option of developing the plant further to incorporate a 450 MW Stage 2 expansion.

Conversion of Mortlake power station to a combined cycle plant could allow it to be run on either an intermediate or baseload basis, depending on market conditions and future energy demand in Victoria. Given the plants proximity to major loads in western Victoria and beyond, it also reduces the need to transmit power from the Latrobe Valley, which in turn will reduce system losses, improve efficiency and add to the appeal of regulators when they consider approving the alteration to baseload in the future.

Mortlake power station is the newest addition to the Origin’s gas turbine family, and is also home to Australia’s first Siemens SGT5-4000F installation Uranquinty Uranquinty Power Station is a 640 MW gas fired peaking power station, Origin’s largest peaking station and one of the largest open cycle gas turbine power stations in Australia.

The plant consists of four units of Siemens SGT5-2000E turbines, with a rated output of each unit standing at 166 MW. The SGT-2000E is characterized by extremely consistent yet rapid start up properties, in tandem with high reliability and availability as well as lenient fuel quality requirements. The machine features a single shaft, single casing design and two laterally flanged, large volume, and silo-type combustion chambers. Convective air cooling of the first three stationary and first two moving turbine blade rows protects the blade material against high inlet temperatures.

The first three stages of the turbine blades are all protected with a special coating.

Spreading the Net with Baseload Capacity Whilst peaking capacity offers the opportunity for high revenue bursts through heightened tariffs, the past three years have shown a considerable drop in peak demand in comparison to a decade ago. This is in line

42 POWER INSIDER JUL / AUG 2013

with an overall reduction in annual energy use from the Australian gird owing largely to residential solar PV installations.

To ensure that projected revenue streams can be guaranteed consistently, Origin are making efforts to capitalize on baseload plants to compliment their impressive fleet of peak plants. The Darling Downs station, operational since July 2010, is Australia’s largest combined cycle facility. It produces an impressive 630 MW for the grid, enough to power 400,000 Queensland homes.

It operates at intermediate to full baseload capacity and is also one of Australia’s most efficient baseload power stations. GE supplied three Frame 9E gas turbine generators each with a capacity of 120 MW, a C7 steam turbine generator with a capacity of 270 MW and the plant control system, whilst Holland’s NEM delivered the three heat recovery steam generators. The gas turbines include advanced aero stage three buckets and stage three nozzles, and a dry low NOx combustor system to help maintain emission compliance by extending fuel flexibility.

Darling Downs Power Station is powered by a rich source of coal seam gas (CSG) reserves, held by Origin in southwest Queensland. As part of the power station’s development, Origin constructed a 205 km domestic gas pipeline linking Darling Downs to the CSG fields.

Continued Growth for Gas The efforts to increase the role of gas in the Australian energy mix are being principally led by Origin. With an impressive fleet of gas turbines installed, the company is constantly reviewing new sites to develop additional gas fired power plants, capitalizing on their own resources and enviable position as a fuel integrated generator. The proposed 1 GW Spring Gully power plant has been undergoing

Mt Stuart expansion featuring a GE frame 9E gas turbine

environmental consideration from the Queensland government as part of Origin’s bid to develop the project adjacent to the existing coal seam gas extraction plant. Origin has also been attempting to develop a 1 GW combined cycle project in New South Wales, near Big Hill. Unfortunately owing to unpredictable market conditions it had been decided to put consideration of the development on hold for the time being.

The existing gas turbine fleet is a blend of mostly GE and Siemens models across E and F classes, both offering advantages in their respective operational duties. With so much importance placed on dependable start up times and reliability, effective maintenance regimes are vital to ensure that maximum revenue can be obtained from electricity ‘spikes’. Origin is a company that is extremely considerate in this respect and whilst the renewable portfolio grows and new large scale baseload developments face evaluation, the mainstay of Origin Energy’s generation portfolio will continue to be gas led. PI

Siemens SGT-2000E installed at the Uranquinty Plant

INTERVIEW

How Sulzer Keeps Asia Up and Running INTERVIEW WITH: KENNY MACKENZIE, REGIONAL DIRECTOR, SULZER TURBO SERVICES ASIA PACIFIC

Robin Samuels interviewed Kenny MacKenzie, the new Regional Director of Sulzer Turbo Services Asia Pacific, about their turbomachinery and electromechanic repair activities in Asia.

Sulzer Turbo Services is the leading, independent, technically advanced and innovative service provider for all brands of mechanical and electromechanical rotating equipment. The company provides customers with high quality services at competitive prices and delivery times. Downtimes are expensive, but the customized solutions can reduce maintenance time. The company also manufactures and sells replacement parts for gas turbines, steam turbines, compressors, motors and generators.

With rapid response, innovative solutions and quick turnarounds, they help their customers to reduce maintenance costs and increase availability of machinery.

The substantial range of services offered is available on site or in their own workshops.

Sulzer Turbo Services supports customers in a variety of markets such as oil and gas, power

generation, both renewable and conventional, transport, petrochemical and general industries. With more than 40 locations on five continents they are close to the customer with high quality local services. PI Magazine asked Kenny MacKenzie, Regional Director of Sulzer Turbo Services Asia Pacific, to tell us about Sulzer’s recent activities.

It is an exciting period for you personally with relocation to Asia Pacific from Switzerland to take over the reins of the former Region Head, Nathan Self. Can you tell us about some of your new responsibilities and your strategy for the region?

I am in the lucky position of having a dual role, since I will continue to be responsible for the development of our contractual business on a global basis; this makes my

move into Asia Pacific even more exciting.

I hope to do as good a job as Nathan did in the region. He is taking on a new challenge for Sulzer in the UK, but has left me a strong team running vibrant businesses. In terms of the regional strategy, I will be building on what has already been achieved and growing our position in each key market.

In terms of key markets, our Australian and Indonesian businesses have a long history of providing service

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Sulzer is at the forefront of independent turbomachinery services for APAC. Which are your strongest markets here and why?

It’s correct, we have a good position in turbomachinery services, but we have strong positions in electromechanical repairs as well.

In terms of key markets, our Australian and Indonesian businesses have a long history of providing service in a range of segments, such as Oil and Gas, Power, Marine, Mining and General Industry. However, Power and Oil and Gas are key since they require most, if not all, of the service products we have to offer.

Countries like Thailand are seeing huge growth for new gas capacity, which is putting strain on specialist gas turbine repair shops in the region. How are servicing practises developing so that more maintenance work can be carried out in the field?

Field repairs are becoming an increasingly important feature of our capabilities, as we have seen in our recent successes in Russia.

People skills are critical and we have been very successful in transferring our skills to local partners, one example being combustion component repairs that can now be effectively managed on-site during an outage.

Sulzer provides solutions to customers

44 POWER INSIDER JUL / AUG 2013

Owners are increasingly focused on uptime and they have to contract with a partner they can trust to deliver How does the modern long-term service agreements from an independent service provider typically differ to that from the turbine OEM? I am asked this question quite often and my answer would have been different a few years ago, but now things have changed and the differences have shifted. In the past, ISP’s may have been seen as being more flexible in the type and structure of the solutions they provided, both technically and commercially, but today the main differentiator is service quality. Owners are increasingly focused on uptime and they have to contract with a partner they can trust to deliver. In our case this means that we focus on gas turbines, steam turbines or driven equipment where we have an

established capability. But we always tailor our agreements to match the needs of the customer.

What advantages can a condition based maintenance agreement bring to the end user? Are these transactional?

Condition based agreements can give a real benefit in reducing the cost of ownership by reducing the volume of new parts needed, however they work best when the owner and service provider make life extension decisions together. It can work on a transactional basis and Asia Pacific is an area where we have had the greatest success with transactional clients. Often the customer and supplier had history and built a level of mutual trust. In a contractual relationship this can be further developed by risk and reward structures!

Maintenance budgets are continuously being thrust under the radar with ever rising fuel cost, is this also forcing you to adapt your own approach in consideration?

Fuel cost increases can dwarf any savings resulting from an improved maintenance regime. Often the impact of fuel pricing is on the operating regime of the station; running hours rather than maintenance cost. We try to

INTERVIEW: HOW SULZER KEEPS ASIA UP AND RUNNING Sulzer provides electromechanical services

help through reducing the costs of ownership by providing flexibility in the contract, allowing the owner to match his spend to the usage of the unit.

What are the most common failure patterns being experienced on gas turbines in Asia presently?

The most common failure patterns encountered in Asia are corrosion and alloy degradation damages related to high temperature exposure. In Asia, these damages are somewhat more pronounced than in other markets, which is likely to be related to deviations in generic operation profiles, as compared to operation profiles in other regions.

Some turbine types seem to be vulnerable to compressor crashes, but also here the difference with other markets is not remarkable.

Instances of creep and thermo mechanical creep are undesirable for any operator on a gas turbine, how can you help to identify these problems before it’s too late, so to ensure that rehabilitation not replacement can be undertaken?

These problems can be detected at an early stage by visual inspections. At this stage, only a change to a milder operating regime, and/or an advanced parts repair regime, which includes a lifetime extension program, can increase expected parts lifetime. A thorough inspection of disassembled components can be used for a reliable quantification. Centrifugal stresses cannot be avoided, but transient thermal stresses and metal temperature can be reduced by insulation. Thermal Barrier Coatings can be applied and, in exceptional cases, cooling efficiency of components can be increased by modifications of the cooling air distribution.

Can you tell us an interesting fact about Sulzer in Asia that our readers may not know?

Asia is a region where we have been active for many years: Asia and Australia account for

nearly a quarter of the group’s sales. Some call them “emerging markets”, but we have been in India, China and Indonesia for many years, so for us the region includes some of our key “home” territories! For example, Sulzer has been in China since the early 1900’s, and we will be building two additional Turbo Services businesses in the next 18 months! PI

Some call them ‘emerging markets’, but we have been in India, China and Indonesia for many years

Creep based deterioration of components is related to the combination of alloy temperature and mechanical stress level.

In Asia, these damages are somewhat more pronounced than in other markets

Steam Turbine Rotor

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feature

Australia’s Appetite for LNG PI Magazine Asia talks to Woodside, Australia’s largest independent oil and gas company, about their recent activity in the liquefied natural gas sector.

W Photo: The loading Jetty at the Pluto LNG Onshore gas plant

oodside is Australia’s largest independent oil and gas company, with a proud history of safe and reliable operations spanning decades. Woodside produces around 900,000 barrels of oil equivalent each day from a portfolio

46 POWER INSIDER JUL / AUG 2013

of facilities, which operate on behalf of some of the world’s major oil and gas companies. The company has operated their landmark Australian project, the North West Shelf, for 29 years and it remains one of the world’s premier liquefied natural gas facilities.

With the successful start-up of the Pluto LNG Plant in 2012, Woodside now operates six of the seven LNG processing

trains in Australia, helping to meet the demand for cleaner energy from their pipeline customers in Australia, the Asia Pacific region and beyond. PI Magazine Asia talked to Woodside to find out a bit more about their benchmark projects in operation, their efforts to reduce flaring and emissions, and about their upcoming projects in Australia and Myanmar.

FEATURE: AUSTRALIA’S APPETITIE FOR LNG

The North West Shelf: Global Benchmark Firstly, Woodside filled us in on their premier facility. The North West Shelf (NWS) has been the benchmark of the Australian oil and gas industry, operating at exemplary availability and productivity.

Operated by Woodside, the NWS Project is one of the world’s largest liquefied natural gas producers, supplying oil and gas to Australian and international markets from huge offshore gas and condensate fields in the Carnarvon Basin, approximately 125 km off the northwest coast of Australia. Other participants in the NWS project include BHP Billiton, BP, Chevron, Japan Australia (MIMI), and Shell.

Representing an investment of more than AUD 27 billion, the NWS Project currently accounts for around 40% of Australia’s oil and gas production and the majority of Western Australia’s total domestic gas production. The project’s offshore facilities include the North Rankin A, Goodwyn A, and Angel platforms and the Okha floating production, storage and offloading facility (FPSO). A new project at the site is currently under development, and the North Rankin B platform is scheduled to begin operations sometime in 2013.

Hydrocarbons from the NWS offshore facilities are transported to the Karratha Gas Plant for processing by two 130 km subsea trunklines. The Karratha Gas Plant, located 1,260 km north of Perth, is one of the most advanced integrated gas production systems in the world producing LNG, domestic gas, condensate and LPG. Covering an area of approximately 200 hectares, the Karratha Gas Plant facilities include five LNG processing trains, two domestic gas trains, six condensate stabilisation units, three LPG fractionation units as well as storage and loading facilities for LNG, LPG and condensate. More than 1,000 people are employed on the project, and are located in Karratha, offshore and in Perth.

During 2012, the North West Shelf Project achieved two major cargo milestones with the 3,500th cargo loaded from the Karratha Gas Plant and the 3,000th LNG cargo delivered to Japan. These achievements reinforce the project’s fundamental commitment to safety, reliability and strong performance. In 2014, the NWS Project will celebrate 30 years of domestic gas production and 25 years of LNG exports to the Asia Pacific region and other parts of the world.

Deep Sea Drilling Expertise Woodside are also globally renowned for their deep sea drilling expertise, and has been developing their skill set in this area in a number of ways. A leader in deepwater exploration and development for many years, Woodside have a strong knowledge of advanced facility design, production risers, flow assurance, moorings and a range of associated expertise.

To excel in this area, a company must have a broad range of capabilities; expertise in one area is not enough. In one sense, Woodside has developed expertise through the range of projects they’re involved with.

On the other hand, they also target strategic expertise. Woodside’s Technology Division is looking at leading edge facility design and overcoming some of the geologic challenges in deepwater.

Additionally, Woodside has developed expertise because of the culture of excellence they are fostering through the company. Most of their capability comes from functions working together to solve difficult challenges.

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FEATURE: AUSTRALIA’S APPETITIE FOR LNG

The Pluto LNG Onshore gas plant

North Rankin Redevelopment Project The North Rankin Redevelopment Project has been a major undertaking on a global scale, with a number of challenges associated with an open water installation. The North Rankin Redevelopment Project is one of the most complex developments Woodside has ever executed. The project will recover approximately 5 Tcf of low pressure gas from the North Rankin and Perseus gas fields, and represents an investment of approximately AUD 5 billion.

Located 135 km northwest of Karratha, the project involves the installation of a second gas processing facility, North Rankin B, alongside the existing North Rankin A platform. Upon completion both platforms will operate as a single facility.

Representing an investment of more than AUD 27 billion, the NWS Project currently accounts for around 40% of Australia’s oil and gas production 48 POWER INSIDER JUL / AUG 2013

A major challenge was the installation of the North Rankin B topsides onto the platform’s jacket. Weighing more than 24,000 tonnes, the topsides were installed in 2012 using the float-over method, which involves setting an installation record for both height and weight in open water. A 260 meter barge, the largest of its kind in the world, was used to transport and install the topsides from the construction yard in Ulsan, Korea, to the North West Shelf.

The float-over involved carefully steering the barge in between the jacket and lowering the topsides into position with the barge ballasting down. Following the installation the barge further ballasted down and slowly reversed out of the jacket slot, completing the six hour float-over process. The challenges overcome by the North Rankin Redevelopment Project team in safely and successfully achieving this significant milestone cannot be overstated.

James Price Point: Potential for Excellence Woodside recently announced that the company would not be proceeding with the development of an onshore facility designed to process the Browse resources. There were a number of reasons behind this decision. Having completed the technical and commercial evaluation for the proposed Browse LNG Development based on locating onshore facilities at the Western Australian Government’s LNG Precinct at James Price Point, Woodside determined that the concept did not meet the company’s commercial

requirements needed for a positive final investment decision.

However, Woodside is currently engaging with the Browse Joint Venture to evaluate other development concepts to commercialise the Browse resources, which could include floating technologies, a pipeline to existing LNG facilities in the Pilbara, or a smaller onshore option at the proposed Browse LNG Precinct near James Price Point.

Woodside has also recently entered into an agreement with Shell that sets out the key principles that would apply if the Browse resources were developed using Shell’s Floating LNG (FLNG) technology.

Woodside believes that FLNG has the potential to commercialise the Browse resources in the earliest possible time frame, and potentially provides the opportunity for Western Australia to become an industrial, operational and technical centre for excellence for floating FLNG. The Pluto LNG Facility and Emissions Pluto has been one of the great success stories of the modern LNG industry with an incredible delivery period from inception of the project and impressive outperformance on production since 2012. Unfortunately, Woodside suffered a slight setback with a recent unplanned shutdown of the LNG processing train in late June. However, Woodside have rallied, and managed to get the facility back online.

This isn’t the only success of the Pluto facility. Woodside has implemented a number of initiatives at Pluto LNG to make it the most emissions efficient LNG plant currently operating in Australia.

Initiatives included in the design of the Pluto facility include: • The installation of waste heat recovery units on power generation turbines to generate steam for meeting process heat requirements, which eliminates the need to independently burn gas in order to generate steam.

• The installation of a Regenerative Thermal Oxidiser, which incinerates the trace volumes of methane that would otherwise be vented through the acid gas removal process.

A number of other technical improvements have been made to the facility and are summarised in Table 5.1 of the Pluto Greenhouse Gas Abatement Plan, available on Woodside’s website.

Woodside has implemented a number of initiatives at Pluto LNG to make it the most emissions efficient LNG plant currently operating in Australia

A wide view of the Pluto LNG Onshore gas plant

Flaring and Maintenance at Woodside Facilities Woodside’s efforts to reduce flaring activities have been a great example for others to follow. For example, the Okha FPSO incorporated a range of measures.

PI Magazine Asia asked Woodside if they had considered using flare and wellhead gas for their own power generation needs on other platforms and FPSOs, but Woodside already has intrinsic commercial drivers to reduce their use of flared gas. Generally, all of Woodside’s operated facilities are run on natural gas, sourced from their production reservoirs.

Woodside has considered a number of opportunities to minimise flaring and each facility has a flaring reduction target which is closely monitored. This reduction in flaring is then diverted for use as fuel or turned into a saleable product.

Woodside are as committed to managing maintenance activities as they are to reducing emissions and flaring. Maintenance duties are vital

LNG Tanker carrying a cargo from the North West Shelf Project, Western Australia

on compressor drives and other key components in the processing train to maintain maximum productivity. Critical process equipment is monitored on a continuous basis and maintained on a fixed cycle. Major equipment, such as gas turbines, is inspected and overhauled on three and six year cycles in line with vendor recommendations. These maintenance activities are carried out during planned shutdowns of the LNG facility.

Woodside’s Exciting Future Plans Always interested in any LNG projects taking place in Asia, we asked Woodside to tell us more about recently announced plans to establish two new partnerships in Myanmar, which is an exciting prospective area for new oil and gas discoveries, and about any other work or plans in this region and in other parts of Asia.

Woodside confirmed that earlier this year, their offers to acquire interests in two blocks offshore of Myanmar were accepted. Since then, seismic work has started and will continue into 2014, with options to drill exploration wells in subsequent exploration periods.

Woodside has opened the aperture in terms of locations they are willing to consider exploring and operating in. The company is focused on moving early to secure new opportunities in emerging and frontier basins. Woodside is looking to diversify, to spread the risk and extend the company’s business interests further along the value chain where appropriate.

However, the company is also being disciplined when it comes to selecting the opportunities to pursue, to ensure that they have a clear line of sight between their existing capabilities and future value. PI All photographs ©Woodside

For more informationplease visit: http://www.woodside.com.au

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INTERVIEW

Ensuring Quality, Supporting Life: Water management in South Australia

Ensuring a stable supply of water is a complicated and expensive undertaking in any urban area, let alone in the driest inhabited state on earth. Daniel Rogers asked SA Water’s Chief Executive John Ringham to tell PI Magazine about their water management schemes; from the hugely successful Adelaide Desalination Plant, to wastewater treatment facilities, to their Asset Management Strategy.

INTERVIEW WITH: JOHN RINGHAM, CHIEF EXECUTIVE, SA WATER

50 POWER INSIDER JUL / AUG 2013

INTERVIEW: ENSURING QUALITY, SUPPORTING LIFE: WATER MANAGEMENT IN SOUTH AUSTRALIA

Can you tell us about the desalinated and recycled water in SA Water’s supply?

Over the past decade there has been a substantial focus on water conservation due to environmental pressures on the River Murray, which is a key source of raw water for South Australia. The Adelaide Desalination Plant (ADP) is a strategic Government initiative to reduce reliance on this natural water source, and provide a climate independent source of water.

Desalinated water was first produced in October 2011, and since then over 42 gigaliters has been distributed and reduced our pumping from the River Murray. We have also invested in storm water harvesting, use of rainwater tanks, recycling, and in water efficient technologies that have made our irrigators some of the most efficient in the nation.

The collection and treatment of recycled water plays a significant role in reducing the amount of nutrients discharged to sea, as well as making maximum productive use of South Australia’s wastewater. Adelaide is already at the forefront of recycling urban water.

Depending on demand, typically 40 to 60% of suitable treated wastewater is reused during the peak month demand in summer.

There are a number of water reuse schemes operational in the Adelaide area, including Virginia Pipeline Scheme, Mawson Lakes, Glenelg-Adelaide Recycled Water Scheme, Willunga Basin Pipeline Scheme and Southern Urban Reuse Scheme. These schemes deliver higher quality reclaimed water to irrigate a number of locations, from market gardens to the bamboo plantation in Adelaide Zoo.

Adelaide is already at the forefront of recycling urban water Not all treated wastewater is destined for irrigation, with SA Water supplying a number of residential suburbs with recycled water suitable for dual reticulation (i.e. toilet flushing, watering the garden and washing the car).

Several buildings in Adelaide’s CBD also utilize recycled water, and there is the potential for the water to be used in upcoming developments.

Can you highlight some of the Adelaide Desalination Plant’s successes?

The plant has been recognized as the most capital efficient desalination plant in Australia, with the lowest operating cost per megaliter of desalinated drinking water. It also delivers one of the lowest carbon footprints of any desalination plant in the world through the utilization of energy efficient

An aerial view of Adelaide Desalination Plant

water treatment processes. This includes: • Running on 100% renewable energy • Producing 200 kW of onsite solar energy • Harvesting rainwater for non potable reuse • Storm water capturing • Utilization of a wetlands treatment scheme The ADP was awarded the Australian Project of the Year Award at PMI Australia Conference, in Sydney in May 2013. The ADP is now placed on the Global Project Management Achievement List for 2013. This year the ADP was also announced as a finalist for the Mega-Sized Projects by International Project Management Association (IPMA).

The ADP was announced as a finalist in Project Excellence in Mega-Sized Projects along with six other businesses and projects from Iran, India and China. The IPMA Project Excellence Assessment is the highest recognition for Project Management in Europe and globally, particularly for largescale projects. The winners for this will be announced on at the 27th IPMA World Congress in Dubrovnik this year.

In April, at the 2013 Global Water Summit held in Spain the ADP, was further recognized, receiving an Award of Distinction. This award acknowledges desalination plants, commissioned during 2012, and focuses on the most impressive technical, financial or ecologically sustainable projects in the industry. The ADP won a further five project management and design awards in 2012 alone. These awards are a testament to the project management and designers behind the ADP, as well as SA Water’s initiative in paving the way on a sustainable water supply.

These awards are a testament to the project management and the designers behind the ADP Can you provide an overview of your wastewater treatment procedures, and how these result in the safe release of unusable water and biosolids?

Wastewater treatment is a complex and expensive operation, but South Australia has led the nation in installing wastewater treatment systems, and was the first Australian capital to achieve secondary treatment of all wastewater. All of the metropolitan Waste Water Treatment Plants (WWTP) produce treated waste suitable for some form of reuse.

Wastewater from homes and businesses is generally 99.9% water, with the remaining 0.1% made up of dissolved or suspended waste material, and SA Water collects and treats over 100,000 megaliters statewide every year.

Since the mid 1990s, SA Water has spent and committed approximately AUD 700 million on metropolitan WWTP Environment Improvement Programs, Plant Upgrades and Reuse Schemes.

Since that time, the total nitrogen load to coastal marine waters has reduced from 2,776 tons in 1998 to 911 tons of nitrogen in 2012. This represents a 67% reduction in nitrogen load from SA Water since 1998.

Further upgrades of wastewater treatment plant processes and/or expanding reuse will contribute

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Reverse Osmosis at work in the Adelaide Desalination Plant

towards the 2030 target reduction to 300 tonnes of nitrogen discharged to coastal waters from the metropolitan WWTP sites per year. Strategies are currently being developed for the WWTP improvements and will take into account: • Optimization of wastewater collection and treatment processes (and possibly further treatment plant upgrades in the future), • Increased recycling of wastewater, • Receiving monitoring and research..

Each year reuse through the schemes increase.

For example the Glenelg-Adelaide Recycled Water Scheme increased 691 ML from the previous year to 2,374 ML in 2012/13.

SA Water has been actively looking for opportunities to increase reuse, and increased recycling is embedded in SA Water’s Strategic Plan and the Governments Strategic Plan.

Increasing the annual recycled water use from the scheme is dictated by customer demand, which is influenced by climatic conditions and the economic environment.

The organic material from all metro WWTP is collected, treated, and virtually all isused by farmers as soil conditioner (see Figure 1). This soil is high in nitrogen, phosphorus and micronutrient, and

Figure 1: GAP Recycled Water Process.

52 POWER INSIDER JUL / AUG 2013

provides not only environmental benefits in its reuse, but economic benefits based on grain yield and protein content.

Managing more than AUD 13 Billion worth of assets and serving more than 1.5 million customers, what procedures do you have in place to ensure all round satisfaction?

Originally known as the Engineering and Water Supply Department (E&WS), SA Water is today wholly owned by the Government of South Australia. With a history going back over 150 years, SA Water remains a leader in the provision and delivery of clean water to residents of South Australia. SA Water continues to innovate and invest in upgrades of existing systems and new treatment plants and remains firmly committed to meeting the water and service needs of our customers today, and long into the future.

SA Water’s call centre operates 24 hours a day, seven days a week. Our Customer Service Centre received more than 480,000 calls from customers last year. Our staff are fully informed and well trained to meet customer enquiries, ensuring

optimum customer service. A new Standard Customer Contract also came in to effect on 1st July 2013, which outlines how to meet our customer’s service requirements, highlighting our commitment to customers.

SA Water has a stakeholder engagement team that assist in keeping the community informed of project works. As with all major works, some level of disruption is unavoidable, but SA Water continues to work closely with the community to ensure high levels of understanding on each phase of the project, including how residents and business owners need to prepare and how other possible impacts, such as dust, can be minimized.

Recently, as part of the North South Interconnection Project, community engagement was taken to a new level. The overall project design, construction and operation were undertaken in collaboration with the community. The team was challenged by the community to minimize building envelopes to reduce the impact on the surroundings. The Clapham Pump Station, a success of the project, is the largest pump station in urban Adelaide, yet it is small for the role it performs.

The station houses five 1 MW high voltage pumps capable of transferring up to the equivalent of 40 Olympic size swimming pools a day from the Happy Valley clear water storage to the northern suburbs. The project’s acoustic engineers met the challenge of making pump and valve stations as quiet as possible. The resulting levels of acoustic attenuation assisted with the high level of community satisfaction.

Are there any specific trends that are being implemented or that you feel are required in order to assist the development of the Australian water sector as a whole?

Many states experience droughts, yet South Australia remains the driest. Located at the end of the river system, South Australia depends on considerable flows of water from the River Murray to sustain the lives of people, animals, and the environment. In recent years, prolonged

INTERVIEW: ENSURING QUALITY, SUPPORTING LIFE: WATER MANAGEMENT IN SOUTH AUSTRALIA A panoramic view of the Reverse Osmosis B. Racks

droughts have forced limited irrigation, which caused hardship for those using the River Murray for their crops and livestock.

Many South Australians supported plans to reduce water consumption during the drought of 2008, which saw a 30% reduction in water consumption compared to the severe drought of 2002. Additional initiatives were undertaken, such as rebates for water efficient washing machines, showerheads, dual flush toilets, rainwater tanks and more, which helped to reinforce just how precious water is in our daily lives.

Our message today is to use water wisely.

And, although no longer in drought, South Australia remains on WaterWise measures and the South Australian population is probably the most water conscious in the nation.

Going forward it is important to continue to innovate and focus on improving efficiency.

Collaborating with other partners, nationally and worldwide, is also important for the industry.

The current and future research strategy for SA Water is dependent upon alliances, partnerships and knowledge sharing. Accessing a wide range of technology and expertise via these avenues is the most cost effective, efficient and beneficial way.

We are able to exchange information with other water treatment professionals on the challenges and most up-to-date solutions being applied to deal with water quality management issues.

Within Australia, SA Water is involved in an ongoing research program with the Water Services Association of Australia (WSAA), working with other utilities to improve approaches in a number of different areas of water and wastewater service delivery. Internationally SA Water attends a number of study tours and conferences, and has recently joined a new international water research centre developed by the National Cheng Kung University. SA Water is the only international partner in this new venture and we were invited to join based upon our global reputation in water quality research.

In this new partnership a number of projects will be undertaken, and one includes an assessment of the impacts of climate change on reservoir water quality in a range of climatic regions. This project will explore the potential impacts of the climate change on the raw water quality available for portable water production in two of SA Water’s reservoirs. The Myponga Reservoir is one of three international research sites chosen for this 2.5 year project. The other

two sites include the US Occoquan Reservoir and Taiwan’s Hsin-Shan reservoir, each representing a different climate zone.

What specific techniques have SA Water implemented to ensure success and longevity of all of your water networks?

SA Water has a comprehensive Asset Management Strategy. This strategy takes into account costs, risks, and opportunity and performance benefits. Asset Management is a vital part of ensuring service delivery to our customers, however Asset Management can be challenging given that the majority of SA Water’s assets are below ground. SA Water’s key water network assets are: • Water main length 26,591km • Wastewater main length approximately 8,000km • 34 Earth Bank Storages • 514 Water Storage Tanks • 252 Water Pump Stations • 41 Water Treatment Plants • 18 Large Dams • 145 Bores • 78 Dosing Stations The biggest thing affecting our network specifically in metro areas is the reactive clay soils coupled with low rainfall, resulting in soil shrinkage and hardening, which makes pipes more prone to failure.

Due to SA Water’s comprehensive, sustainable, and proactive strategy for water mains we have one of the lowest burst rates per 100km in

Australia. Seventy three per cent of the pipes in the metropolitan Adelaide are less than 50 years old, which makes Adelaide’s pipe network relatively young by urban water industry standards.

Condition assessments are often logistically difficult and costly. Therefore, tracking the location of water main failures is critical for ensuring we focus the budget in the right areas in order to maintain service for our customers.

Taking this into account, SA Water’s Asset Management strategy involves a number of things: • There are individual approaches adopted for each major sub-set of mains (i.e. above ground pipelines, trunk mains & reticulation mains).

• Above ground pipelines and trunk mains are assessed on a risk management methodology with periodic inspections.

• For buried reticulation mains, opportunistic condition assessments are undertaken whenever possible and planned condition assessments are undertaken on targeted trunk mains.

• We have an in-house Materials Science Department, and have the longest testing running program for coatings and materials (particularly in the sewer environment).

SA Water is one of the only water utilities in Australia who have one of these departments.

• Many tests are undertaken annually on various materials and our accredited materials set the standard for materials used nationally and worldwide.

• Modeling tools are used to determine the long-term expenditure required for water main renewals over a set planning period.

The Reverse Osmosis racks at Adelaide Desalination Plant

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INTERVIEW: ENSURING QUALITY, SUPPORTING LIFE: WATER MANAGEMENT IN SOUTH AUSTRALIA

Clapham Pump Station

• A Water Main Prioritisation Tool has been developed to determine a scoring methodology to enable water mains to be ranked in terms of priority for replacement in the short-term.

• SA Water has proposed in excess of AUD 100 million for investment in water main replacements across the state over the period 2013/14 to 2015/16, with over half of this proposed on the small diameter (<375mm diameter) reticulation main replacement program.

• This will continue to target the poorly performing water mains and maintain SA Water’s infrastructure in good condition.

• SA Water has also purchased CCTV equipment and ultrasonic thickness testers to undertake opportunistic condition assessments to increase our knowledge of the buried water pipe assets to assist with future planning.

Can you give us a basic break down of the water quality monitoring programs you have in place?

The drinkingwater delivered to our customers is regarded by SA Health as safe to drink.

Water safety is verified through comprehensive monitoring and testing programs that have included nearly 700,000 tests over the past 12 years. Of these, SA Water has achieved an overall 99.7% compliance within the Australian Drinking Water Guidelines (ADWG) health parameters.

This is above the minimum requirements of the guidelines, which require an overall result of 95%.

The raw water that enters one of our 30 water treatment plants undergoes an extensive multiple stage treatment process. There are 24 water treatment plants in country regions and six in the metropolitan area. Conventional water treatment processes are widely used to improve the quality of water in South Australia. However, treatment methods such as Magnetic Ion Exchange (MIEX®), membrane filtration, desalination, iron removal plants and ultraviolet disinfection are also used.

We have appropriate barriers, preventative measures and management objectives in place to ensure the quality of our drinking water is up to

54 POWER INSIDER JUL / AUG 2013

National standards. Our catchment systems and reservoirs help to minimize the introduction of hazards and remove them. The treatment process helps to remove hazards such as iron, algal byproducts and pathogens. Disinfection then ensures that all microbiological hazards and algal byproducts are eliminated.

SA Water also has the added benefit of the Australian Water Quality Centre (AWQC), a business unit of the South Australian Water Corporation (SA Water), which has been operating since the early 1930s when a statewide monitoring program for drinking water was introduced in South Australia. Since its inception, the AWQC has built an international reputation for water quality analysis and research.

It provides high quality analytical services, leading edge research and professional advice on a comprehensive range of water quality issues.

Today, with over 100 staff members, the AWQC’s state-of-the–art laboratories are located in SA Water’s six green star building in Adelaide’s CBD. With a specific water industry focus, the AWQC’s comprehensive services are tailored to cover all aspects of the water cycle from catchment, source, treatment, distribution, wastewater, trade waste, reuse and alternative sources such as desalination.

Since its inception, the AWQC has built an international reputation for water quality analysis and research The AWQC prides itself on responding to emerging water quality challenges and is backed by a team that can assess the effectiveness of various treatment options. It is often engaged to provide testing and advice during major water quality incidents and on major infrastructure and environmental projects across Australia

and internationally. The laboratory’s focus on innovation and advanced technology enables it to be at the forefront of water testing services.

A key area of the AWQC is monitoring drinking waters for compliance with national and international quality guidelines. The AWQC’s Field Laboratory Services Team visits approximately 3,150 locations, collects 5,100 samples and undertakes 2,080 field tests per month. Routine sampling collections include wastewater, source water, drinking water supplies, metropolitan beaches, cooling towers, customer taps, storage facilities, process factories and even extends to water used for kidney dialysis machines.

Frequent out of hours work is also carried out in response to various water quality events.

The AWQC is responsible for the testing of products in contact with drinking water for compliance with AS/NZS 4020 and BS 6920 recognized by Standards Australia and Water Authorities. In 1992, AWQC was the first laboratory in Australia to carry out testing to AS/NZS 4020, and since then the laboratory has tested thousands of products for national and international companies.

Finally, can you indicate how and where your Environmental Protection Programs are being utilized?

At SA Water, we take our responsibility to protect the environment seriously. We are committed to ensuring that we reduce the environmental impact of our business activities for the benefit of the community. SA Water continuously strives to improve its water and wastewater operations, as well as improving our performance in protecting water supplies, oceans, rivers and other resources.

SA Water completed an AUD 240 million Environment Improvement Program in 2004.

The aims of the program were to: • Increase the effectiveness of our metropolitan wastewater treatment plants, • Reduce the amount of treated wastewater entering Gulf St Vincent, • Recycle high quality treated wastewater for irrigation purposes.

Improvement and efficiency assessments are ongoing, and a further four detailed energy assessments are planned between 2012-16 on activities that have high energy usage: • Water transmission in 2013, • Wastewater treatment plants in 2014, • Water distribution in 2015, • Transport fuels in 2016.

SA Water is an active member of the Federal Government’s Energy Efficiency Opportunities Program (EEO). This program encourages large energy using organizations to increase energy productivity. By being a part of this Federal program, we are required to identify, evaluate and implement cost effective energy saving opportunities. Our Energy Efficiency Opportunities Program is a key strategic initiative for achieving energy and emission reduction targets. PI

feature

Cummins Power Generation & Christmas Creek: Satisfying The Appetite For Iron Ore

The Pilbara region of Western Australia is known as iron ore country, where the generation of electrical power is critical for the biggest mines in the world as they ramp up record production.

The powerful hum from the power station competes with background noise from the mine’s massive infrastructure – a towering crusher and feeder system loading hundreds of thousands of tonnes of ore into rail wagons.

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FEATURE: SATISFYING THE APPETITE FOR IRON ORE

Power station designed, built and operated by Contract Power Group Western Australia.

Behind the walls of this new power station are 27 Cummins Power Generation C3000D5 diesel generator sets powered by QSK78 engines. This is because Fortescue Metal Group’s Christmas Creek mine needs to ramp up production to meet China’s seemingly insatiable appetite for the key steel-making raw material.

This is the biggest diesel power station in Australia, another milestone for Leon Hodges’ Contract Power group of companies. The Christmas Creek is also currently the largest installation in the world of prime power Cummins Power Generation C3000D5 gensets powered by QSK78 engines.

Perth-based Contract Power designed and built the power station and continues to operate and maintain it providing the power requirements for FMG. The fact that it marks the first major installation of C3000D5 gensets powered by QSK78 engines in the world doesn’t concern Hodges and his team.

“We like trying new equipment…we’re certainly not afraid of it. We believe it gives us a leading edge over our competitors,” says Contract Power general manager Marc Grosser, who headed up construction of the Christmas Creek power station.

However, Cummins technology, and in particular their generator sets, are nothing new to Contract Power. The company’s first big milestone was winning the contract in 1998 to build, own and operate the power station at Central Norseman Gold, Australia’s longest continuously running gold mine.

Contract Power still has that contract today, utilizing gensets powered by the Cummins KTA50 engine – an engine Leon Hodges greatly admires for its reliability and longevity.

“What I like about Cummins is their support.

They don’t run away from a problem. They turn to the problem to fix it,” says Hodges.

Contract Power boasts an ability to do business ‘anywhere in the world’ having built, owned and operated power stations across three continents. It is noted for its dynamic approach to the power generation business.

“After-sales service is a key factor for Cummins Power Generation… in fact, our experience is that

56 POWER INSIDER JUL / AUG 2013

What I like about Cummins is their support.

They don’t run away from a problem. They turn to the problem to fix it Cummins Power Generation is the leader in this area,” stated Marc Grosser.

The gensets in the new power station are C3000D5 units powered by the QSK78, Cummins’ biggest diesel engine with its 78-litre, V18 configuration. In mining’s ultraclass dump trucks, the QSK78 pumps out 3,500 hp hauling payloads up to 400 tonnes.

“Contract Power wanted reliability at the 2.2 MW prime rating, and they wanted serviceability and service support,” says Bhavani Sambhara, who headed up the power station project for Cummins

Power Generation.

“We were prepared to guarantee that those key requirements would be met and will be working closely with Contract Power to ensure reliable power supply which will be critical as the mine production ramps up.”

Contract Power’s maintenance regime at Christmas Creek is understandably fine-tuned to the nth degree. There are certainly no compromises.

“It’s a harsh environment in the Pilbara,” says Grosser, adding that “the dust is highly abrasive and ruthless on everything… oil filter integrity needs to be spot on.”

Routine servicing is at 250-hour intervals while oil sampling is carried out every 500 hours. To ensure best possible oil filtration, Cummins’ Eliminator system is used, replacing the traditional disposable spin-on ‘paper’ element filters. Eliminator is a combination of an automatic, self-cleaning full-flow filter and an integral centrifugal bypass unit.

The ability of the power station to operate at maximum capacity in very high ambient temperatures is another critical factor, so cooling system efficiency rated highly in the design criteria.

“Our cooling system at Christmas Creek is designed for 50 degrees Celsius temperatures,” Marc Grosser points out, as “Marble Bar is reputedly the hottest place in Australia and it’s only 150 kilometres north-west of Christmas Creek.”Marble Bar holds the world record for the longest sequence of days –160 days – where the temperature has reached or exceeded 100°Fahrenheit (or 37.8° on the Celsius scale).

Contract Power has high expectations for the QSK78-powered gensets which utilise 11 kV Stamford alternators. “We believe the QSK78 will outrun the competition in terms of service life and also provide good fuel efficiency,” says Marc Grosser. Operating 6,000 to 7,000 hours a year, they will certainly be relied on for dependable power as the iron ore riches of the Pilbara continue to provide Australia with its biggest export earnings. PI

Power station designed, built and operated by Contract Power Group Western Australia.

REGULARS

Technology Focus:

The Cutting Edge Of Photovoltaics Power Insider Asia Magazine looks the research and development breakthroughs in the solar photovoltaic panel manufacturing industry.

T

he solar PV industry is booming globally. Millions are installing solar panels on their homes and businesses, with utilities and power producers spending billions to set up multi-megawatt solar farms. The market is extremely healthy, with opportunities for profitable investment in every part of the supply chain: from mining polysilicon to maintaining the panels on site.

Despite the conceived maturity of photovoltaics, scientifically it is in its infancy. Valuable research is being conducted to improve solar PV, as there are a number of key issues that are restricting its potential. These restrictions include the expense of materials, manufacturing, and installation; land acquisition for utility scale projects; locality of solar farms far away from base loads; intermittent power generation, and low energy to electricity efficiency at 20%. Whilst these issues aren’t preventing the proliferation of solar projects, mitigating these restrictions would improve their competitiveness.

In this edition of PI Magazine’s Technology Focus, we’ll look at three of the most recent breakthroughs in solar research and development that, when commercialized, could assist in making photovoltaic power an even more viable clean technology.

Continuous Solar Power… From Space?

The first of our trio may sound like a gadget in a science fiction film, but governments and research bodies have taken the possibility of putting solar panels in space very seriously. The simplicity of the theory is quite beguiling: use traditional PV panel arrays to cover existing satellite technology that can orbit Earth, collecting huge amounts of solar energy without the interruption of the atmosphere, cloud cover, or nighttime.

Peter Glaser proposed the idea of Space Based Solar Power, or SBSP, in 1968, and suggested that microwaves could be used to transmit the energy. Placed in geosynchronous Earth orbit (GEO) and transmitting to receiving antennas 24 hours a day, these solar satellites could provide an estimated 6-8 times more power than a solar cell on Earth, and delivering a quantity of power similar to a traditional nuclear or coal-fired plant.

Governments and research bodies have taken the possibility of putting solar panels in space very seriously

Global interest This theory has received global interest. In June 2013, a government funded India body joined forces with an American organization to

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develop SBSP. Abdul Kalam, India’s former President and eminent scientist, and Mark Hopkins, the executive committee chairman of the National Space Society, head the project up. In a statement, the two men announced a strategy to market SBSP to G8 or G20 nations next year.

Japans Ministry of Economy, Trade and Industry unveiled a document in 2009 detailing plans to launch a SBSP plant by 2040. The 1 GW solar station will be fitted with four square kilometers of solar panels.

Mitsubishi are part of the consortium committed to the project, which is estimated to cost JPY 2 trillion. Mitsubishi have developed a prototype named ‘Solarbird’.

A number of these ‘small’ solar satellites (which are a few hundred meters each) will be launched into GEO to form a constellation system. The Solarbird is very simple, with a primary mirror that follows the sun and reflects light onto the secondary mirror, which focuses the light onto the solar cells, mounted onto a transmission antenna that sends the energy to earth via microwaves.

Not to be outdone, China announced plans for SBSP in 2011. China’s Academy of Sciences has laid out timelines and policies for development. The organization aims to complete analysis of space solar applications, detailed design of system solutions and key technologies by 2020. Under the plan, a space solar station for commercial use will be completed by 2040, with a 100 kW prototype launched into low Earth orbit by 2025.

The Central Scientific Research Institute for Engineering in Russia is also researching SBSP. They even have a working 100 kW prototype, but haven’t announced launch plans. This is potentially because although the organization plans to use satellites to capture the energy, they have proposed an alternative way to send it back. Instead of using microwaves, the Russians want to develop a highly powerful laser, making the transmission of energy easier to focus. With a laser, the receiving antenna could be ten times smaller.

SBSP feasibility Whilst a lot of technology does exist to make SBSP possible, these projects are arguably not feasible. This is because of the wealth of

58 POWER INSIDER JUL / AUG 2013

essential technology that doesn’t yet exist, and will cost billions to develop. Huge advances are required in power transmission, space structures and transportation, and the solar panels themselves have to improve in efficiency and reduce in weight and cost. Launch vehicles need to be cheaper and cleaner, and the satellites will have to be vast: much bigger than the Space Station and extremely heavy.

And then there’s maintenance; space debris cannot be controlled and will wreak havoc with satellite constellations. And if a satellite breaks, how can it be repaired? It is not quick to send a repairman to space, and would cost millions. After all, money, or the lack thereof, is SBSP’s greatest obstacle, and will probably remain so beyond the 2030-40 period of predicted development.

Researchers have even developed a way to spray paint a photovoltaic layer onto any surface Spray-on Solar Panels Space solar claims to remove the obstacle of intermittent supply, but this next technological breakthrough aims to dramatically reduce the cost of producing the solar panels themselves.

Photovoltaic panels are expensive because they are made of silicon and coated with a layer of silicon nitrate. The panels are made in a vacuum and utilize hydrogen plasma to collect the sunlight. Even thin-film PV cells that use cheaper materials accrue costs through complex manufacturing processes.

Spray-on systems simplify the manufacturing process, by spraying layers of hydrogen and anti-reflective onto the panels as they roll down a conveyor belt. The solar panels themselves would be made from semiconducting nanoparticles called quantum dots, which are mixed with a conducting polymer to make a plastic. Plastic solar panels would be

cheaper to produce, and lighter, stronger and cleaner than traditional solar panels.

Energy in a can Researchers have even developed a way to spray paint a photovoltaic layer onto any surface. Universities at Sheffield and Cambridge claim that their sprayon PV layer demonstrates the same performance as traditional solar cells. The main restriction they’ve found is that the surface used has to very smooth. Mitsubishi Chemical Corporation has also developed a PV ‘spray paint’, utilizing carbon compounds which, when dried and solidified, act as semiconductors and generate electricity in reaction to being exposed to light. Mitsubishi is the first company to make a prototype spray-on solar cell, which has demonstrated a practical conversion rate of 10.1%. Mitsubishi aim to improve that efficiency to 15% by 2015, and aim to eventually match traditional solar cell conversion levels. The sprayed-on solar cells are less than 1 millimeter thick and weigh less than one-tenth of crystalline solar panels of the same size.

Applications for this technology include spraying solar panels on homes and cars, charging lightweight batteries on soldier’s backpacks, and spraying onto textiles. Such technology would allow costs in transportation and installation to reduce significantly, and make solar power more accessible for remote locations. However, both the University of Sheffield and Mitsubishi admit that spray-on technology isn’t efficient enough to compete commercially.

Paper Solar Cells In order to utilize as much sunlight as possible, solar panels need to become more lightweight, flexible and robust. Plastic panels have had limited success in this area, primarily because the anode has a tendency to come away from the surface of the panel when bent. In 2011, researchers at MIT developed a remarkably flexible PV panel that could be printed onto materials as thin as tissue paper. Karen K. Gleason and her team invented the process that made this breakthrough possible. Called oxidative chemical vapor deposition, or oCVD, the method is particularly useful for making thin films of organic polymers, which are carbon-containing molecules that are composed of repeating structural units and are low cost, have high conductivity and can be flexed, stretched, and even folded.

TECHNOLOGY FOCUS: THE CUTTING EDGE OF PHOTOVOLTAICS The oCVD process Gleason based her work on conventional CVD, a well-known method of depositing a thin coating of one material on the surface of another (the “substrate”). But Gleason wanted a method that operated under less heat, and by adding an oxidant and carefully selecting the correct starting materials, she created the oCVD process that operates at gentler conditions inside a vacuum chamber.

To make their anodes using oCVD, Gleason and her research group start with two reactants: iron chloride, the oxidizing agent, and ethylenedioxythiophene (EDOT), the monomer. The EDOT molecules are the basic building blocks that link together to form long chains of the polymer known as PEDOT. The researchers first prepare the selected substrate by placing a physical mask that can be pulled off to leave the desired pattern. They then spray their two reactants, both in vapor form, onto the surface of the substrate.

As a result, three things happen at once.

When the iron chloride and EDOT meet on the surface, they react to form PEDOT. At the same time, they form a thin film. And because of the presence of the mask, the film is deposited in the pattern needed to act as an anode. These three steps occur all at the same time in a dry process called vapor printing. The remaining components are deposited on the substrate using evaporation, another dry process but with no chemical reactions involved. The researchers take a material in solid form, heat it until it becomes a gas, and then allow it to condense on the selected surface. Using that approach, they coat the PEDOT anode with several “photoactive” nanostructured thin films, the layers that absorb light and cause electrons to flow, and then attach the cathode.

The complete cells are extremely durable. They can be bent, stretched or even submerged in water and still produce electricity

Here is what experts fro Notice that the idea has been around since 1968, and no projects have been built. The cost of lifting all the necessary equipment is astronomical (sorry!).

It’s hard to make the economics work versus a ground based system.

Kevin F Swartz It is a difficult proposition if not impossible. But what Want your say? Get in tou ch

m LinkedIn think of SB

SP:

about the cost even if the energy could be available 24 x 7? Would it be even worth trying at exorbitant costs?

Hiro Chandwani Since the scientific research institute suggests using lasers instead of microwaves, it means that they have, or about to have, more effective lasers, and might be an economical ly on Twitter, Facebook and

Project advantages The oCVD process creates an anode that is extremely robust; the process doesn’t degrade the material it’s printed on, or create defects or restrict its original flexibility. Better still, the deposited film is stuck very firmly and flexibly to the substrate, as the process grafts the two materials together. The complete cells are extremely durable. They can be bent, stretched or even submerged in water and still produce electricity. Unfortunately, it isn’t very much electricity. The panels only have a conversion efficiency of about 1%. MIT hope’s to achieve 4% soon, and suggest that the sheer cheapness of the materials could mitigate its poorer performance.

Other paper projects Other paper projects include a panel made from wood pulp, developed at Osaka University in Japan. The light, flexible and eco-friendly panel has conversion rate of 3%, and is less than one millimeter thick. The panel is comprised of transparent cellulose fibers just 15 nanometer thick and a thin film of silver wiring. Researchers hope to commercialize the design within three years. Paper solar cells were also utilized in a clever advertising campaign

feasible project. Besides, if the US, Japan and China plan to build solar power stations between 2030 and 2040, it is not unimaginable for Russia to race for such a project , taking into account that these countries are racing for energy and space technology. Moreover, lifting the necessary equipment is done cheaply by the Russians...

Hayel Msherbash

LinkedIn, or go to our web site!

for Nivea sun cream this year. In Veja Rio Magazine, the Nivea advert was a paper-thin solar panel with a slim USB port that could be used to charge a Smartphone.

In Sum These projects offer some excellent solutions to the obstacles discussed. Space based solar power makes an intermittent power reliable and continuous. Spray-on solar panels supply an alternative to land hungry solar parks by allowing users to spray solar panels potentially anywhere, and could be produced at a far cheaper price to traditional PV panels. Paper PV panels have similar advantages, as well as being lightweight and robust.

However, all three applications have the same disadvantage; none are particularly efficient. Space based solar would cost billions to maintain, and spray-on and paper cells only have a conversion rate of up to 10%. This is frustrating, because surely efficiency is the most important factor. Though any breakthrough that makes manufacturing and installation cheaper is positive, it’s perhaps time to go back to the drawing board and work on those pesky efficiency rates. PI

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INTERVIEW

Examining Potential:

Fuel Cell & Electrolysis Deployment in Asia AN INTERVIEW WITH: ALAN KNEISZ, HYDROGENICS

PI Magazine has really taken an interest in the fuel cell industry in the last six months.

Fuel cells have great potential in a number of power generation applications, and advancements in the technology are breaking barriers regularly to make fuel cells more viable and competitive. We asked Alan Kneisz, Business Development Director at Hydrogenics, to tell us more about the electrolysis market and fuel cell growth in Asia.

Can you give us a brief background of Hydrogenics role and experience in the fuel cell market?

Hydrogenics has over 60 years of experience designing, manufacturing, building and installing industrial and commercial Hydrogen Systems around the globe, in most major verticals like backup power, mobility, industrial and large stationary systems. Our extensive field experience together with innovative approaches to offer our customers the best solution in the industrial, energy storage or fuelling industry are available through our technology breakthroughs and extensive patent portfolio. We have deployed over 2,000 systems in over 100 countries worldwide.

60 POWER INSIDER JUL / AUG 2013

Japan has arguably been the pioneers for the fuel cell business so far, but which other countries offer good potential and for what reasons?

Depending on the market, we have seen extensive deployment in large systems in Korea with POSCO using DFC technology in the multi-megawatt range. Also, Indonesia has seen extensive growth in backup power PEM fuel cells in their Telecom networks with close to 1,000 sites already using fuel cells. In Europe, Germany has been a trailblazer where Hydrogenics has commissioned megawatt hydrogen generators that can be used for fuel cell or other applications like mobility and fuelling stations.

In terms of potential, I see the market for backup power being primarily focused in developing countries where power stability (e.g. Indonesia, India and the Philippines) is an issue, and also in those countries with extensive natural disasters (e.g. Japan). There could also be extensive growth in data centres as prices come down in countries like Malaysia and India. For large-scale power, the markets are mostly focused on countries that have limited natural resources and are looking to create some energy security like Korea and Japan.

Some of the major challenges with fuel cell growth lie in hydrogen availability; can you tell us about how unconventional hydrogen resources can be potentially realized?

As the world’s leader in electrolysis, Hydrogenics is in a unique position to understand the fuelling challenges better than other suppliers. Access to hydrogen has been a challenge, which is why ‘onsite generation’ has been growing in some markets using small electrolyzers and methanol reformers primarily for backup applications in telecom and remote power. Hydrogenics is supporting these two fuelling options. Also, we have seen interest where companies deploy a large electrolyzer, and generate their own hydrogen for a regional requirement for backup power, allowing them to get access to their own cost effective hydrogen.

Access to by-product hydrogen has been mixed as chemical or textile companies do not see this as a core business and thus have shown mixed interest in selling their vented hydrogen.

Fuel cell companies continue to explore this option as we hope more by-product hydrogen can be captured instead of vented.

Hydrogen can also be generated cost effectively in a process called “Power to Gas” where we use excess renewable such as solar, wind, and hydro to generate hydrogen at a reduced cost. Once generated, the hydrogen can be: • Stored as energy for use at a later date, • Used in the natural gas grid, • Used in industrial applications such as food, glass or other applications,

• Used in fuel cells to produce backup power, • Used in fuelling stations to supply fuel for cars and buses.

At Hydrogenics, we see a large growth in the backup power market in Asia and in developing countries due to all the power challenges they are facing because of natural disasters Possibly one of the most exciting sectors for fuel cell deployment lies in telecommunications backup power. Why is this industry attracting so much interest?

Fuel cells have been an exciting area in backup power as telecommunications is probably the largest user of diesel generators globally, as telecom sites are often remote or in developing

countries. For instance in India, telecom companies are the largest single users of diesel.

Telecom companies do not want the sites to go down as they lose revenue, hence their need for reliable backup power. With the proliferation of generators and large battery banks, telecom companies need a reliable and cost effective solution to ensure 100% uptime. Fuel cells now in the range of 2-10 kw offer a cost effective option to generators, with a payback normally under three years and greatly reduced operating expenses.

Fuel cells are quiet, easier to deploy, require limited maintenance and are zero-emission which is a clear advantage over generators.

Telecom companies also see far reduced theft once fuel cells are deployed, further decreasing their operating expenses versus traditional solutions.

With the growth of an onsite solution or regional electrolyzers, the ability to have or get hydrogen to remote areas is becoming more viable. More companies are considering fuel cells in the developing world where hydrogen access used to be an issue.

Also in countries with extensive natural disasters, fuel cells are smaller and offer a better solution to generators. In Japan and the east coast of the USA, extensive deployments of fuel cells are ongoing to ensure power during unfortunate weather conditions.

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INTERVIEW: FUEL CELL AND ELECTROLYSIS DEPLOYMENT IN ASIA be then discharged where and when it is needed most. It enhances the flexibility of the power system while providing a new source of renewable gas. If there is no natural gas pipeline, the stored gas can be used for many commercial applications or to support fuel cell deployments.

One of the major problems with the PEMFC has undoubtedly been the MEA life expectancy. What efforts has Hydrogenics made to improve this in consideration of the unforgiving start-stop configuration?

We have a patented mitigation strategy to prevent damage from start-stop cycling.

All our Power Modules include this feature and we offer unlimited start-stop cycling.

Our closed cathode architecture and liquid cooling gives us an industry leading 10,000 hours of stack life, which allows for reduced replacements of stacks and longer lifetime for the systems especially in places where the power is intermittent.

Thus, the ability for companies to reduce theft and also plan forward knowing their fuel costs is a clear advantage for any company. Knowing that they have a far more reliable solution that is far easier to deploy and maintain.

We understand that Hydrogenics are working on a number of innovative off grid, community power supply schemes offering electrolyzers in ‘regional centres’. Can you tell us more about your activity here?

We have deployed a combined solution using our electrolyzer and fuel cells in many remote locations such Greenland, Argentina (Patagonia) and remote Canadian communities, where we use excess solar or wind to power the electrolyzers.

Beyond this concept, we see ‘regional centres’ that generate hydrogen in countries with power challenges to have a reliable source of hydrogen close to them. Then, we deploy smaller distributed fuel cell systems in the range of 2-10kw for rural power or telecommunication applications. This would give an area the ability to have clean reliable power and grow the hydrogen economy. In simulations we have found that if they generate the hydrogen themselves, the end user could be at par or sometimes cheaper than diesel fuel per kw/hr. We are discussing this concept with some parties and are looking for additional companies and/or partners.

Power to Gas is a very interesting concept to significantly improve the compatibility of renewables. Can you tell us about some of the main conditions required to undertake such a process and also the key benefits?

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Renewable sources of generation, such as wind power, provide a viable pathway to reducing our carbon footprint while increasing our energy supply security. Since these resources are intermittent, other generating sources such as gas fired generating plants, must be dispatched by the independent grid operator to balance the aggregate supply with the load consumed throughout the day. However, at certain times during the day or seasons when demand is lower, there may be a surplus of renewable electricity.

Access to hydrogen has been a challenge, which is why “onsite generation” has been growing in some markets using small electrolyzers and methanol reformers Power to Gas is a hybrid solution that converts surplus renewable generation into hydrogen using electrolysis. The hydrogen can be used for fuelling FCEVs; it can be injected into the existing natural gas infrastructure or used with fuel cells in backup power applications. The natural gas pipeline and underground facilities provide TWh of storage capacity which can

How do you see the use of fuel cells growing in Asia for the future? What are the major milestones that Hydrogenics have reached so far? Do you have plans to upscale, and can PEMFC have a role to play for large base load power applications?

At Hydrogenics, we see a large growth in the backup power market in Asia and in developing countries due to all the power challenges they are facing because of natural disasters. There is also a great opportunity for large systems in remote locations where hydrogen access is needed. Our Power to Gas solution has a great potential, as there is an extensive solar and wind production in the region.

Hydrogenics have installed hydrogen generators all over Asia. We have deployed a 30 kw system in Hong Kong and soon we will be installing a 60 kw system with our electrolyzer in Australia for a zero carbon building. In Japan we have completed some initial phase development in Fukouka Hydrogen town and look forward to expand our initiatives there with our partner Iwatani.

In the rest of Asia we see a strong potential for backup power and we are talking to other potential partners for large-scale power where there is vented hydrogen for instance. For PEMFC we see potential in areas to generate other cheap sources of hydrogen in the future such as biomass (with gas clean up technology) to fuel cell in remote locations and integration of fuel cells with other technology like absorption chillers to allow for greater technical efficiency. PI For more information, visit the Hydrogenics website: www.hydrogenics.com

Onsite hydrogen generator cooling for Power plants

Hydrogen fuel cells for electric vehicles, such as urban transit buses, commercial fleets, utility vehicles and electric lift trucks

Solutions

Stations

Fuel cell installations to lower TCO costs for data centers and telecom back up

Stationary Power

Hydrogenics is pioneering “Power-to-Gas” the world’s most innovative grid-scale energy storage

Talk to us to understand how we help you Shit Power and Energize Your World. +6016 217 0877 akneisz@hydrogenics.com

Sustainable Energy storage

feature

Network Fuel Cells for the Indonesian Telecommunication Industry Robin Samuels examines the potential for fuel cell installation in the telecommunications industry in Indonesia

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For many years, successive Indonesian governments have subsidised hydrocarbon fuels with sale prices fixed by the state.

However due to declining production and rising demand, the country became a net importer of oil in 2004. This alarming reliance on fuel imports and rising prices have led to calls for revision on the subsidies after an increasing impact on state expenditure, with the government attempting to eradicate the support mechanism.

In 2008, it was estimated that combined fuel and electricity subsidies amounted to $20.5 billion or 20% of total government spending for the year. The disparity between the subsidised price and the market price has made lifting these subsidies politically challenging, resulting in significant public pressure. One industry being affected in particular is telecommunications.

Indonesia is the worldâ&#x20AC;&#x2122;s 18th biggest economy, and South East Asiaâ&#x20AC;&#x2122;s largest. It has areas with very high population densities and ability to pay for mobile telecommunication services, leading to a competitive business environment for service providers.

Powering Telecoms However, the geographical distance that separates one island from the other brings its own challenges in powering telecom networks. The task of extending the network coverage in remote areas is plagued by reoccurring issues surrounding the overloaded electricity grid and the low availability of electricity in rural areas or small populated islands; in some cases less than 12 hours a day.

Base transceiver stations (BTS) are the nervous system of any telecommunications network, facilitating wireless communication between subscriber device and operator network. The equipment is traditionally supplemented with back up diesel generator in the 11-13 kva range that will cut into immediate action during frequent grid supply interruption. Whilst designated for emergency operation, the diesel generator sets generally operate for an extended period on a daily basis, having a huge impact on cost and emissions.

The relatively low price of diesel by international standards suggests that this would be a difficult market for technologies competing with diesel, but political drivers are forcing the industry away from oil dependency.

When planning back up power for this industry several factors and scenarios have

The task of extending the network coverage in remote areas is plagued by reoccurring issues

64 POWER INSIDER JUL / AUG 2013

FEATURE: NETWORK FUEL CELLS FOR THE INDONESIAN TELECOMMUNICATIONS INDUSTRY

to be considered for operation in extended periods. Logistical challenges with network maintenance can vary greatly depending on location. The more densely populated islands such as Java have good road infrastructure yet serious traffic problems, while remote parts of islands such as Sumatra, Kalimantan and Sulawesi may take days to reach. The archipelago nature of the country also means that boat access is commonly required between islands. Finally, Indonesia is prone to natural disasters, with high profile volcanic eruptions, earthquakes and tsunamis in recent years.

Although infrequent, the ability to maintain mobile network coverage during these events and rescue efforts is important to operators and is also a key factor when planning backup power for telecoms sites, echoing the significance of reliability in power output and prolonged operation.

At present approximately 90,699 towers serve more than 90.29 million unique subscribers with coverage of about 87% of the population. Out of the total 90,699 deployed sites, GSMA identified 874 sites that rely completely on 24x7 Diesel based energy resource and 3,300 sites that are configured with optimized DG battery hybrid solutions.

By 2015, GSMA estimates the number of telecom towers will reach 134,426, offering phenomenal potential to renewable energy The Alternative Solution With such vast capacity operators are looking for ways to eliminate diesel generators not only to reduce CO2, but to escape being held hostage to the ever fluctuating price of oil.

In light of this, the telecoms sector in Indonesia has to be commended for a collective charge in implementing green technology in response to the barriers above.

Looking at renewable energy deployments, it is estimated that 4,590 green sites have been installed in the network. Of these green sites, 87% are solar based, and Telksomel are responsible for deploying the most, with 3,908 BTS solar sites. More interesting is that Indonesia are one of the leading nations when it comes to fuel cell deployments in telecoms, with an impressive 556 sites in operation.

Hutchinson has deployed most of these with 518 fuel cell sites across the country using both hydrogen and methanol fuel cell technology. The hydrogen and methanol stocks present no difficulty with regards to the production but distribution remains a challenge as MNOs need to have a solid supply chain and maintenance contracts to ensure supplies at the sites.

In Indonesia, both CAPEX and OPEX model based solutions are used to power telecom networks. The CAPEX model is the most common practice to acquire green technology solutions. However recently there has been a transition toward the OPEX model, where MNOs will pay the energy consumption on a pay-per-use basis, without spending capital to buy the green technology solutions. The power purchase agreement model is implemented for energy efficiency but still needs to be developed for green energy solutions.

Support and feed stock Unlike some of the other countries that have significant fuel cell deployments, such as the USA, there has been no real policy support or subsidy in Indonesia. Another challenge is the price of hydrogen, where prices are currently artificially high, due to a limited number of suppliers and not much consumer power due to small purchase volumes. Lowering of hydrogen supply prices could improve the business case further.

The technology is rapidly emerging as a vital component for back up power in a host of fast growing South East Asian nations A significant factor is the Indonesian gas production industry; it is the eighth largest gas producing country in the world, and until the Australian LNG industry ramps up production at the major projects ongoing it remains the biggest in Asia.

The Indonesian gas industry presents a wealth of fuels including hydrogen, LPG and methanol.

The country is a significant methanol producer, generating around 1 million tonnes a year, around 2.5% of world methanol consumption.

Education Telecom companies need to be informed of the features and possible benefits of using fuel cells as backup power systems, against the backdrop of rising diesel prices. The hydrogen systems have been deployed impressively in unreliable grid situations replacing diesel

generators, where typically power outages average between one and four hours per day.

The deployments have generally been deemed a success, the logistics of fuel supply, particularly in a relatively small scale system that may need to respond to significant fluctuations in usage, has been the industries greatest challenge. This is highlighted by the interest in unconventional feedstocks, and the investment that certain network operators have undertaken in deploying electrolysers to sites where it was felt to be more economical than delivering hydrogen.

This also offers potential for rural community power schemes that will be discussed as part of an electrification mission in the upcoming Indonesia focus of Power Insider Asia Magazine.

The opposing agreement to electrolyser use is that the cost of a grid connection and associated equipment is based on the maximum electrical supply rate, and therefore any equipment that requires additional power above that of the BTS, may incur significant financial penalty.

This has ultimately prevented the adoption of more electrolysers at some sites, where the additional load of the electrolyser would require an upgrade of the grid supply.

The problems lie with convincing network operators that first of all, the capital cost and life expectancy of the fuel cell can compete with that of the of the proven diesel generator, and secondly that hydrogen (or similar) supply logistics can be secure and hydrogen cost can be reduced, especially when you compare to markets likes India where hydrogen price is up to 50% less than Indonesia.

In the last year alone, Telkomsel made bold steps towards city broadband, building over 11,000 new BTS, averaging 1000 new units per month: of which a 50% composition are 3G. The ambition in developing this advanced infrastructure is clear, but it also dictates mission critical power supply and zero outage in times when the grid fails to be successful.

Whilst the more developed markets of the world may be getting most of the attention when it comes to fuel cells, the technology is rapidly emerging as a vital component for back up power in a host of fast growing South East Asian nations. However what remains to be seen is whether feedstock security, supply chain and price match the technology. My opinion is that if the example of Indonesia is anything to go by, this time next year could see almost double the capacity installed with untold potential for further installation. PI

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feature

Today’s Design for Tomorrow’s Products

A2WIND’s Fresh Approach to Wind Turbine Design Wolfgang Kurz, Technical Manager of Aerospace & Renewable Energy at A2WIND, tells PI Magazine Asia about A2Wind’s turbine design processes, showing how they are responding to current market drivers whilst future-proofing their technology.

66 POWER INSIDER JUL / AUG 2013

TODAY’S DESIGN FOR TOMORROW’S PRODUCTS: A2WIND

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In the past, wind turbine development has experienced fast progress, with the main focus on increasing the efficiency of the rotor performance and maximization of annual energy production. This was the fundamental task of engineering offices during the design phase of a turbine. Today, there is high competition on a worldwide market, especially in China and Asia.

Large turbines and bigger rotor blades present a challenge to designers Now, the focus has shifted to the costs of the wind turbine and its subcomponents, as well as the costs during operation. There is a growing demand for large size turbines, so that investors can reduce the costs for the funding and operating of a wind turbine project. The key values are price/kW installed and per price/MWh produced. Large turbines and bigger rotor blades present a challenge to designers as on the one hand, they have to deliver a quality product with high reliability and on the other is of economic value to the manufacturer and operator. Classic approaches involve scaling up major components, which leads to less cost effective products and processes, as very large turbines have their own rules and specific challenges.

Aerospace Synergy A2WIND has developed methods that can cater to these new and advanced requirements.

Our engineering experts have gained in depth knowledge in the field of aerospace technology for a variety of applications. Now synergy effects are used to transfer procedures from aerospace technologies and combine them with well known optimization tools in order to work on a multi disciplinary optimization approach in designing components. In particular, rotor blades are predesignated for this kind of application.

The new processes are not limited to rotor blades, but can easily be adapted to any other structure of the wind turbine, or even the whole turbine itself. In general terms it could also be adapted to any structure. The main goal for wind energy is efficiency and best economic costs, which can be achieved with a reliable design and a maximized annual energy yield (AEP). These techniques are very similar to approaches used in aerospace, where a safe design and mission performance is usually the most important design goal. In wind energy it is robustness and economical value.

Fig 1: Key factors for optimization goals

Optimizing Components When optimizing a component, the economic considerations and manufacturing constraints for some engineering tasks can be implemented and used as input parameters.

For example, sizing and layout for the rotor can use the turbine as the parameters. For the economic considerations a cost model can be included and used as a benchmark and target objective to reduce costs during manufacturing and supply.

Finally, manufacturing constraints can also be defined in order to adapt the product to your specific manufacturing environment. For companies in the market who want to be longterm players, they need to think immediately about reducing their costs for future products.

The manufacturer and the operator will benefit from such approach. Wind energy is proving very successful in many countries, so the cost must be reduced further.

Fig 2: Finite element model of a rotor blade

To ensure a lightweight and economical design of the rotor blade, A2WIND is using numerical optimization methods to balance the different constraints like: • Static stiffness (maximum tip deflection), • Static strength (maximum strain in the fibers), • Minimum modal frequencies to avoid resonance with the system, • Static stability (large enough resistance against buckling), • Fatigue strength (to ensure long life), • Against the objective of the optimization targets weight, performance and costs.

Beside these mechanical constraints, the manufacturing constraints have to be regarded as well. A2WIND has created an automated process to assist the design using Altair OptiStruct for the definition of the size and thickness of the

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TODAY’S DESIGN FOR TOMORROW’S PRODUCTS: A2WIND different plies in the flanges and the thickness of the sandwich at the skins and webs. For all considerations mentioned before, a hybrid material mix could be treated as well.

This process starts from the aerodynamic design of the blade with an automated creation of a finite element model for the detailed analysis of the rotor blade. Loads can be extracted from the loads module (FOCUS6) to be directly used for the finite element analysis. Manufacturing constraints are implemented in the finite element and optimization model for the desired layup manufacturing method used mainly by the blade manufacturers.

Fig 3: Key factors for optimization goals

Minimizing Cost Beside an objective to minimize the weight, a cost function has successfully been applied on a rotor blade to balance the usage of glass fibers and carbon fibers to minimal costs. With this sort of optimization the locations where carbon fibers are more cost efficient than pure glass fibers can be detected. All this is done in an automated way within a newly developed software tool: • Start with loads calculations, • Provide the loads data to the optimization tool, • Carry out the optimization loop, • Analyze the results of the structural optimization loop, • Extract the necessary cross section properties of the rotor blade directly from FEM model, • Feed back updated properties to the loads module, • Restart the whole process again until the target objectives are achieved.

The expertise of A2WIND ensures they are able to support the field of aerodynamics. It covers the full spectrum needed to design a rotor for wind turbines, from basic layout of blade and its rotor characteristics through special topics like performance prediction, aerodynamic optimal design, airfoil and shape optimization during development phase.

Introducing WARP A2WIND developed their own in house aerodynamic code for the complete Wind Blade Aerodynamic Design and Performance Prediction (WARP). WARP originally created as Excel calculation sheet, and with incorporated VBA macro, is going to be converted into a standalone executable program developed with Python and a

68 POWER INSIDER JUL / AUG 2013

user friendly and graphical input /output interface.

It will include the following main capabilities: • Extrapolation of airfoil polar data to 360° AoA, • Blade design and optimization, including 3D visualization, • Turbine definition (rotor blade, turbine control, generator type, losses), • Computation of rotor performance over lambda (tip speed ratio) range, • Computation of turbine performance over wind speed range, • Annual yield computation with WEIBULL distribution, • Manual selection of all simulation parameters, • Data browsing and visualization as post processing, • Export functionality for all created simulation data, • Blade geometry export functionality (FOCUS and CATIA V5).

WARP, originally created for performance analysis of Horizontal Axis Wind Turbine, now includes the design and simulation of Vertical Axis Wind Turbines (VAWT), by means of Double-Multiple Stream Tube Model developed by Ion Paraschivoiu.

Fig 4: A2WIND full scale static test in China

Tailoring Your Design A2WIND can help you in creating your own blade tailored for your turbine. It will guide you through the whole process of certification and testing, and can also assist you with setting up your manufacturing processes with modern techniques like VAP (vacuum assisted process) for resin infusion. A2WIND has certified with DEWI-OCC for international customers according to the latest standard GL-2010. All tasks and steps will be performed under ISO 9000 procedures to ensure high quality products for you.

Once a wind turbine is in service it is useful to monitor specific functions and parameters to get a complete picture of the status of the important components and be able to make a risk analysis.

A completely new approach, developed by A2WIND, is to predict future behavior. This approach is called Model-based Prognostics and Health Management (MPHM) in Wind Energy.

Operation and Maintenance Preventive maintenance is the simplest strategy for servicing equipment in regular predefined intervals, with the aim of avoiding component and system failures. This is an expensive approach because the predefined time intervals between

maintenance tasks are suboptimal. A better strategy is on-condition based maintenance. This is the starting point to optimize maintenance costs. On-condition monitoring systems collect and analyze data for vibration and other system parameters, to detect component failures and anomalies in performance. Because the condition of components and systems is monitored and not just conservatively estimated, the time intervals between maintenance may be extended based on the real field data.

The next generation of prognostic maintenance tools from A2WIND provides a richer set of features than current on-condition monitoring systems The next generation of prognostic maintenance tools from A2WIND provides a richer set of features than current on-condition monitoring systems. One of the key building blocks of the A2WIND toolset is the underlying software model of turbine system architecture. Even though existing condition based systems can use sensors to detect damage and sometimes provide a failure prognosis before ultimate failure of a component, it is not an ideal solution. Significant component damage may have accumulated already by the time the damage is detectable by on-condition sensors, and the A2WIND toolset enables the quantification of this damage. On-condition data is used as input in real time to link energy and structural interactions between subsystems to deliver prognoses both for remaining useful life and for advanced discovery of system failures.

The second major feature of the A2WIND tool is that it provides a real-time basis for energy output optimization. Energy losses due to suboptimal performance are quantified in real time, providing an advanced basis for maintenance task decisions. For example, if the energy lost due to a system malfunction (and therefore suboptimal performance) is small but also carries a prognosis of a complete system failure, the operator may decide to continue running the turbine at reduced load until the next scheduled maintenance period is reached. If the prognosis indicates that a complete system failure is imminent, the operator is able to shut down the turbine to minimize damage and concurrently arrange a specific maintenance task to solve the problem. PI For more information about all topics, please visit http://www.a2wind.net

tailored

Project Management

manpower capacity energy yield aerospace Acentiss

wind

turbine movement electricity

energy magnets aerodynamic

calculation fatigue load

azimuth angle cost of electricity

wings

lowest cost

condition-based wind industry

Germany

one to three bladed rotors

R&D oriented wind farm

serial production

cooling system

generator onshore

offshore

strength

A W nd

optimization energy balance rotor

development concepts

gearbox

performance

hub

maintenance

tower

inverter

power curve

lightweight

composites

economics

engineering

global winds induction safety

Italy

testing

corrosion

life time

wind map

Blade development porosity

development

In-Service

technology transfer

renewable

concept density of air

airworks

technology transfer

Established as an international business company, the area of A2WIND GmbH activity is mainly rotor blade development, a discipline in which we are empowering the traditional rotor blade design process by extensive use of aerospace technology in lightweight design.

The vision of A2Wind is to develop lighter and customer inputs for performance and total cost.

Another activity is the development of methods and strategies for cost-optimised maintenance and maximization of energy optimization of wind turbines.

A new software is used to create and implement accurate condition-based maintenance activities.

feature

To Build or Not to Build:

The Billion Dollar Radioactive Question Rachael G. Stephens takes a look at Asian nuclear power roadmaps.

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uclear power is set to boom in Asia.

This is down to two market drivers; the need for electricity and the need to diversify the energy mix. With increasing urbanisation and growing economies, Asian nations require a stable supply of base load electricity. These nations, concerned by carbon emissions and a volatile import-export market, also seek to reduce their reliance on traditional fossil fuels. For many, nuclear power is

70 POWER INSIDER JUL / AUG 2013

a solution to these issues. Despite the 2011 Fukushima disaster, nuclear power generation is set to rise from 331,720 GWh in 2012 to 901,380 GWh in 2020.

In Asia, there are currently 117 nuclear plants, with 44 under construction and firm plans to build 92 more. China, South Korea and India will lead the way with nuclear power generation, due to their existing nuclear infrastructure (figure 1).

In this article, weâ&#x20AC;&#x2122;ll focus on less advanced nuclear programs; from Vietnam, whose first reactor will come online in 2020, to Malaysiaâ&#x20AC;&#x2122;s nuclear proposals.

In Asia, there are currently 117 nuclear plants, with 44 under construction and firm plans to build 92 more

FEATURE: NUCLEAR TO BUILD OR NOT TO BUILD

Fig. 1 Major Nuclear Asian Nations Japan

50 operable units (44 GW, though many are shut down temporarily), 3 under construction, 10 planned (16 GW)

Pakistan

3 reactors in operation, 2 under construction

China

15 operable units (11.9 GW), 26 under construction (27.6 GW), 51 planned (57.5 GW), 120 proposed

South Korea

23 operable units (20.8 GW), 4 under construction, 5 planned (total 12 GW)

India

20 operable units (4.4 GW), 7 under construction, 18 planned, 39 proposed

Vietnam Vietnam has been toying with the notion of nuclear since the 1980s. The 88 million strong population have suffered power rationing and blackouts, and electricity demand growth is expected to reach 15% per year until 2015.

In 2006, the first firm plans for nuclear power were made, and by 2007 an ambitious target of 8 GW by 2025 was set.

The 2 GW Phuoc Dinh and Vinh Hai power projects were announced in 2011, together with a plan for 10 further 1 GW reactors coming online between 2020-29. Since Vietnamâ&#x20AC;&#x2122;s Atomic Energy Law was passed in 2008, a number of organisations have sprung

up to support the development of a nuclear infrastructure, emphasising the importance of safety and utilising foreign knowledge.

The Ministry of Industry & Trade (MOIT) is responsible for the projects, while the Ministry of Science & Technology (MOST) supports the nuclear program. The Vietnam Atomic Energy Institute (VINATOM) is responsible for R&D, technical support and training. The Vietnam Agency for Radiation and Nuclear Safety & Control (VARANS) is the nuclear power regulator. The National Council for Atomic Energy Development & Application coordinates ministries, agencies, governmental bodies and localities in developing nuclear energy. State owned energy goliath EVN will build and operate the plants.

Ninh Thuan 1 The 2 GW Phuoc Dinh plant will become operable in 2020. The plant will be built with Russian technology, with Russiaâ&#x20AC;&#x2122;s Ministry of Finance providing $9.5 billion in funding; 85% of the total equity required.

AtomStroyExport will build the two AES-91 reactors and construction will start in 2014.

Russia will also be responsible for all the fuel supply and repatriation of waste for the life of the plant. Though the project is a turnkey contract, Vietnam and Russia will work together to train hundreds of engineers and workmen to build nuclear plants, with many working on projects in Russia.

Ninh Thuan 2 Vietnam has a similar agreement with Japan for the Vinh Hai project. With two reactors, the plant in scheduled to come online between 2024-5, and will be built and part financed

by Japan Atomic Power Co. (JAPC) and the JINED Consortium, which includes Chubu, Kansai, TEPCO, Mitsubishi, Toshiba and Hitachi. JINED and EVN signed a MoU in 2011 to collaborate on the design, construction and operation of the plant.

A decision on the technology has not yet been made, but the Vinh Hai plant could be extended to four reactors.

With an installed capacity of 8.5 GW and the eighth largest population in the world, around 45% of Bangladesh is without power

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plan to develop enough nuclear power to triple Indonesia’s power output by 2025, and to use nuclear to meet 2% of Indonesia’s electricity needs by 2017.

The government has earmarked $8 billion for four plants totalling 6 GW. Three key locations were suggested; Muria in Central Java, Bangka Island and Madura, which was set to receive a South Korean SMART Reactor. However, many of these plans have been suspended indefinitely, or have shown no signs of realistic development because of the economic climate and public opposition.

As such, there are no firm plans or contracts to construct these proposed plants.

Nuclear power remains a political issue, with a large percentage of Indonesians opposed to development and a number of influential industry players attempting to promote nuclear power. As it stands, Indonesia is unlikely to meet any of the targets set by the government in 2011.

Fig. 2 IAEA - Milestone Approach The IAEA sets out a three phase ‘milestone’ approach to establish nuclear power in new countries:

1

Pre-Project Phase (1-3 years), leading to knowledgeable commitment to a nuclear power program, resulting in set up of a Nuclear Power Program Implementing Organization (NEPIO).

2

Project Decision-Making Phase (3-7 years), involving preparatory work after the decision is made and up to inviting bids. In Phase 2 the government role progressively gives way to that of the regulatory body and the owner-operator.

3

Construction Phase (7-10 years), with a regulatory body operational, up to commissioning and operation.

Bangladesh With an installed capacity of 8.5 GW and the eighth largest population in the world, around 45% of Bangladesh is without power. Those that do have power experience frequent power cuts with energy supplied from outdated gas fired plants. The Prime Minister, Sheikh Hasina, aims to have an installed capacity of 20 GW by 2021, primarily utilising coal and gas. Hasina also stated that nuclear power is an integral part of Bangladesh’s medium - long term electricity plans.

Bangladesh has two reactors planned and a target of 5 GW of nuclear capacity by 2030.

Groundwork began in August this year on the first project in Roopur. Planning has been underway for a plant in this location since 1961, and the 2 GW project will have two 1 GW reactors. Set to cost approximately $2 billion, the plant will come online between 2017-18.

AtomStroyExport, Rosatom and the Bangladesh Atomic Energy Commission (BAEC) will develop the project together.

The deal was confirmed in 2009, after which Bangladesh developed a nuclear power safety infrastructure. This intergovernmental agreement is similar to Vietnam. Rosatom and AtomStroyExport will build, test and operate the plant, as well as supply the fuel

72 POWER INSIDER JUL / AUG 2013

and manage the waste throughout the life of the plant. Rosatom will supply two VVE reactors. They will be assisted by BAEC, and will provide training in and out of Russia to engineers, scientists and workers. Russia will assist in the financing, providing 85% of the $1.5 billion required for the first unit.

Indonesia In Indonesia a debate surrounding the adoption of nuclear power has been raging for thirty years, and culminated in lots of plans but little commitment. Indonesia is experiencing a disparity in electricity generation and population growth. Indonesia’s 242 million inhabitants are served by a capacity of only 30 GW, and only 65% of Indonesian’s have access to electricity. This has resulted in a low reserve margin and numerous blackouts.

Additionally, Indonesia relies heavily on fossil fuels for its existing capacity, with 45% of electricity coming from oil and gas.

Indonesia actually has abundant fossil fuel resources, but instead of securing Indonesia’s energy future, the economical emphasis is on export. Nuclear power has been touted as a way to alleviate Indonesia’s chronic power shortage and free up fossil fuels for profitable export. In 2011, the government unveiled a

Thailand Thailand’s interest in nuclear power comes primarily from the desire to diversify the energy mix. Around 70% of Thailand’s electricity is provided by natural gas, leaving them unhealthily reliant on imports as natural resources are depleted. Additionally, this reliance hit the nation hard this year when routine maintenance on a gas platform in Myanmar led to a 1.1 billion cubic feet drop in gas supply.

In 2007, the Energy Ministry announced a Power Development Plan from 2007-21 that would include the construction of 4 GW of nuclear power. This target was revised in 2010 to include five 1 GW nuclear plants commercialised between 2020 and 2028.

However, after the Fukushima disaster, the commission date for the first plant was extended to 2023.

The proposed plants would be owned and operated by EGAT, who have signed agreements with China General Nuclear Power Corporation and Japan Atomic Power Company to collaborate on nuclear power development.

Feasibility reports were carried out by EGAT between 2007-11. The report identified five different locations for the first plant, though no sites have been confirmed. Plans for nuclear power in Thailand are still very tentative, with no firm information on the 2023 project.

The Westinghouse 621 MW PWR cost the Philippine government $460 million, but was never loaded with fuel; and has never been operated

FEATURE: NUCLEAR TO BUILD OR NOT TO BUILD Philippines The Philippines is one step ahead of the game in Asian nuclear power development; they have already built a reactor. The Bataan 1 Nuclear Power Plant was built in response to the 1973 oil crisis and completed in 1984.

The Westinghouse 621 MW PWR cost the Philippine government $460 million, but was never loaded with fuel; and has never been operated. This is because of accusations of corruption and bribery, and doubts over safety.

Having lain dormant for over twenty years and costing $800,000 a year to maintain, in 2008 the IAEA advised the government that the plant could be refurbished and safely operated for 30 years. This refurbishment, which would involve upgrading 25% of the plant’s equipment, could cost $1 billion. Also in 2008, the Philippines’ National Power Corporation commissioned Korea’s KEPCO to conduct an 18 month feasibility study, and Toshiba have also shown interest in its rehabilitation. In 2011, the plant was opened up as a tourist attraction in order to generate funds and drum up support for its potential commissioning. However, it is still unclear whether the government is likely to reopen the plant.

The Philippines is still interested in the development of nuclear power in general, and in 2008, the government updated their national energy plan to include 600 MW of nuclear power by 2025, with a further boost to 2.4 GW by 2034. Additionally, the government is considering two further 1 GW Korean Standard Nuclear Plant units, using equipment from the aborted North Korean KEDO project. KEPCO is reportedly offering this equipment for $1.1 billion. However, Energy Secretary Carlos Jericho L. Petilla has stated that public suspicion of nuclear power is holding back the government’s program, and the 2025 target is likely to be pushed back as the country is not technologically ready for nuclear power.

Malaysia Malaysia nuclear enthusiasm is motivated by high fossil fuel prices, and the government stated in 2008 that Malaysia had ‘no option’ but to commission nuclear plants. A provisional start up date was set at 2023, and the Nuclear Power Development Steering Committee will present the government with a Nuclear Power Infrastructure Development Plan (NPIDP) later this year to assist in decision making.

The Malaysia Nuclear Power Corporation was commissioned in 2011 to spearhead the eventual deployment of nuclear plants.

A timeline has been conceived, with construction set to start in 2016, with the commissioning of the first plant in 2021.

The Malaysian Government aim to have three or four reactors providing 10-15% of Malaysia’s electricity by 2030. The Malaysian Government already have a $7 billion budget set aside, and have been investigating potential sites. However, winning public support has been difficult, and has set the project back by 6 months.

Much work is required to disseminate information and improve nuclear power’s public image In Sum For the majority of these countries, nuclear power is not just around the corner. Vietnam and Bangladesh are the only countries to have made firm plans, with Indonesia, Malaysia, Thailand and the Philippines just embarking on the road to nuclear power, and are facing significant obstacles. Firstly, there is a technical

deficiency: not enough talent to build, operate and maintain nuclear facilities. This issue is mitigated by the agreements with Russian and Japanese organisations, with technical training for domestic personnel a huge part of the contract.

Secondly, the advantage of nuclear power is that it provides a large amount of energy to the grid. This may present an issue for nations whose grid isn’t stable enough to accept such power or to distribute it. In many cases, as much investment in the grid may be needed as in the nuclear plants. Thirdly, and potentially the most important, public opposition after the Fukushima disaster is at an all time high. Much work is required to disseminate information and improve nuclear power’s public image.

Despite this, a large proportion of Asia is committed to the development of nuclear power, and it will be interesting to watch the plans of Vietnam, Indonesia, Thailand, Bangladesh, Philippines and Malaysia unfold over the next two decades. PI

GET INVOLVED IN THE DEBATE! Do you think South East Asia is serious about their nuclear ambitions?

Are Vietnam and Bangladesh developing their programs in the safest way? Will public opposition ever ease against nuclear power?

Join the debate and tell us what you think on Twitter, LinkedIn and on our website: www.pimagazine-asia.com Alternatively, email the editor: rachael@sks-global.com

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feature

Improving Performance, Reducing Emissions:

How Effective Air Filtration Systems can Enhance Gas Turbine Efficiency Carlo Coltri, Product Marketing Manager for Vokes Air, talks to PI Magazine about innovative technologies for gas turbine air filtration.

74 POWER INSIDER JUL / AUG 2013

FEATURE: HOW EFFECTIVE AIR FILTRATION SYSTEMS CAN ENHANCE GAS TURBINE EFFICIENCY This study will explain how the correct use of air filters can significantly improve the efficiency of gas turbines. Whilst the main focus will be filtration’s role in the defense against contaminants that blunt performance, this paper will also examine the most effective methods of water removal and outline the key considerations when scheduling filter replacement.

Introduction In the field of large power generation plants, even a small improvement in efficiency can have a dramatic effect on overall performance.

Increasing the efficiency of the world’s installed capacity of 2,500 GW by as little as 1% would lead to a reduction of around 300 million tons of CO2 per year, and save 100 million tons of fossil fuels (EU Turbines). A considerable portion of the world’s capacity utilizes gas turbine (GT) technology, so it is clear that even a small improvement in GT efficiency can yield big benefits. According to a study of EU turbines in 2010 within large central electricity production, it is estimated that in 2030, 60% of global emissions will come from power plants currently in service.

According to the same study: • An optimization of the system would lead to a reduction of 5% in CO2, • Retrofit of turbines would lead to a reduction in CO2 of 5%, • Retrofit of boilers would bring a further CO2 reduction of 3%, • Europe’s combined cycle plants are currently working with an average efficiency of approximately 52%. Existing best available technology (BAT) makes it possible to achieve a value greater than 58%.

Improving the efficiency of energy production through retrofitting of existing plants would therefore generate substantial savings in emissions to the environment. Figure 1 illustrates the average life of gas turbines across the globe using average data from various sizes of turbines.

As can be seen, many turbines installed around the world have been operating for a number of decades, often with low efficiency due to outdated technology and worn machinery. The opportunity for improvements in gas turbine efficiency is therefore extensive. This study examines possible performance improvements to existing installations via the air filtration system.

Typical Parameters of Air Filtration Performance – EN 779:2012 The benchmark standard for defining an air filter’s performance is the recently updated EN 779:2012, which now considers minimum efficiency when awarding filter class. The parameters that characterize an air filters are: • Average Arrestance (Am): The ratio between the total amount of synthetic test dust retained by a filter and the amount injected. This parameter is used to classify coarse dust filters of class G.

Fig. 1 Powergen Base (by region and age) as found in Gas Turbine World, 2009

• Average Efficiency (Em): The ratio of the number of particles (average diameter of 0.4 µm) retained by the filter to the number entering it expressed in a percentage. This parameter is used to classify M and F class filters.

• Dust Holding Capacity: The amount of dust that a filter can retain until the final pressure (in grams).

• Initial Pressure Drop: the pressure drop (Pa) of a new filter operating at test air flow.

• Minimum Efficiency: the lowest value recorded during testing from the initial, discharged and loaded efficiencies.

as a function of time due to the effect of fouling.

To get these results, Timot Veer, Klaus Haglerod, and Olav Bolland of the Norwegian University of Science and Technology “measured data correction for improved fouling and degradation analysis of offshore gas turbine”.

Moving from two to three stages has significantly increased system pressure drop but simultaneously reduced the quantity of dust reaching the turbine by approximately 98%, lowering the chance of engine damage, such as

According to the new EN 779:2012 standard, filters are classified into the following coarse, medium and fine categories: Improving Efficiency Through EPA Filtration Normally a gas turbine intake filtration system consists of a first stage of glass fiber coalescer pads, followed by G4 or M5 bag filters and a final stage of F8 or F9 filters. Now, high efficiency EPA filters are offering an alternative.

The coalescer stage will remain the same so will be ignored from this example. Against external environmental condition of 50µg / m 3 of dust concentrations in a turbine of 250 MW come on average 13.1 kg / year of dust that cause the phenomena of fouling, corrosion and erosion. This system has an initial pressure drop of 145 Pa. The alternative to be analyzed is a pre-filter G4, a filter F9 and a final E11. In this case 26.8 gr / year dust will enter in the gas turbine with an initial pressure drop of 360 Pa, considerably higher than the previous case.

Moving from two to three stages, there is the negative factor of the increase in pressure drop but a significant reduction of dust that reaches the turbine. To quantify this additional pressure drop, it is agreed within the power generation industry that an increase in pressure drop of 50 Pa causes a fall in efficiency of 0.1%. Figure 2 shows the trend of the efficiency of the turbine

Figure 2: The efficiency of a turbine over time due to the effect of fouling[4].

fouling, corrosion and erosion.

For the maintenance of gas turbines, to bring the efficiency of the turbine to an optimal value, are used offline washing, washing with water and detergents of the turbine’s vane (considered hazardous waste once used). In Figure 3 are reported respectively developments due to fouling with the classical filtration and the one with the absolute filters, confirmed by study on Mitsubishi heavy duty gas turbines (Koji Watanabe et al, 5).

As is illustrated above, with EPA filtration off line washing is not necessary for 9000 hours.

Overlaying the two curves (see Figure 4) provides further demonstration that a turbine with EPA filtration has less fouling and less deterioration of the efficiency than a traditional two-stage system.

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FEATURE: HOW EFFECTIVE AIR FILTRATION SYSTEMS CAN ENHANCE GAS TURBINE EFFICIENCY

Fig 5: Water first coalesces then drains away from the downstream air flow.

Fig 3: Traditional two-stage intake (top) vs EPA filtration

Quantifying the benefit is a balance between reduced fouling and increased pressure drop. The increased pressure drop can be estimated to restrict performance by approximately 0.4%, while cutting fouling provides a 1.2% improvement in output (empirical average). Therefore, the overall result is a potential efficiency improvement of 0.8%. Other costs must also be considered in addition to the above. Investment is required in the retrofit of filter chambers; upgrades to the system housing (metal frames) to accommodate three stages of filters, for example. However, empirical research has shown that a 37 MW turbine operating continuously saved 2300 MWh in a year by changing from a two to a three-stage system incorporating EPA filters.

Improving Efficiency with Hydrophobic Pre-filters In the past, the simplest way to eliminate water at the first stage of the air intake was through the use of glass fiber coalescer panels or finned louvers. However, these systems come with an inherent pressure loss, which is particularly high in coalescer panels as they become dirty.

Hundreds of Pascal of pressure is wasted in order to capture the water and prevent it from reaching the final filters or the turbine itself.

The introduction of filters that combine the dual function of pre-filter and coalescer has therefore brought considerable benefits to gas turbine operators. Utilizing a hydrophobic media,

Fig 4: Compressor washing and EPA filtration compared

76 POWER INSIDER JUL / AUG 2013

these elements provide a low pressure drop whilst maintaining the ability to stop water and increase the performance of filtration overall (Figure 5). In old filter chambers with coalescer panels and/or rain louvers as the first stage, the new combined filters simply replace the coalescers without the need for structural work to the existing. Figure 6 demonstrates how a 250 MW gas turbine experienced a dramatic pressure drop enhancement by adopting Macrogen GT DuoTM combined filters unit and removing a separate coalescer stage: 250 MW gas turbine operating 4000 hrs/p.a Initial Configuration

Replacement

Stage 1

Coalescer G3

None

Pre-Filter

Bag Filter G4

Macrogen GT Duo M5

Final Stage

Compact F9

Compact F9

275 Pa

162 Pa

Total PD

Modifying the filter house to accommodate a new filter configuration requires both capital investment in new frames and significant downtime to conduct the work. To avoid this disruption and cost, Macrogen GT Duo™ can be easily integrated with Compatex TMP (see Figure 7) compact filters using Velcro strips to provide an all-in-one solution that is incredibly simple to deploy.

Improve Efficiency Through Timely Filter Replacement Quite often the policy of changing filters for each stage is driven not by the prescribed final pressure drop, but by other considerations such as scheduled shutdowns of the plant for maintenance. Bearing in mind the impact that just 50 Pa of additional pressure drop has on overall system efficiency, this should clearly not be the case. Even if the cost of the replacement filter is a factor in delaying, the purchase price of the new element is likely to be much less than the cost incurred through the loss of efficiency from an old, dirty filter.

With this in mind, there are clear areas for potential improvement through the management of filter changes and ensuring that these are completed at exactly the right time.

Figure 8 shows the pressure drop of a pre-filter in an air intake of a turbine of 250 MW. This type of product has an average cost of €20, with this size turbine typically requiring an average of 500 filters. Therefore, a set of pre-filters for this turbine would cost in the region of €10,000.

In November 2008 the new filter had an initial pressure drop of 50 Pa. By mid-May 2009 this figure had increased to 200 Pa and was begin to rise at a greater rate. The filter was finally replaced at 450 Pa in mid-June 2009.

In that month of operation with a high load loss (mid-May to mid-June), the increased pressure drop had reduced the efficiency of the turbine by 0.5%. This equated to an economic loss estimated around €60,000 (assuming continuous operation and a price of 70 €/ MWh). It is therefore clear how the timely changing of pre-filters would have resulted in a considerable economic advantage.

Fig 8: Pressure drop of pre-filters over time

Conclusion

Fig 7: Macrogen GT DuoTM integrated with Compatex TMP compact filters

Air filters are often neglected in the definition of a project in the field of power – filters are considered commodities or simply generators of pressure drop. This study has shown that proper selection and management of filters that considers environmental conditions and new technologies can lead to significant improvements in efficiency of the turbines themselves.

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feature

Ahead of the Curve: The Asian Gas Turbine Market and Alstom Rachael G. Stephens explores the factors that are driving the gas turbine market in Asia, and how Alstom are striving to respond.

T

he natural gas market in Asia is an exciting industry. For a number of reasons, countries in the Asia Pacific are choosing natural gas, supplied either via pipeline or in liquefied form via LNG, as their source of energy, and there is further growth in usage expected for the future. This is primarily because of the demand for more flexible power generation with fewer emissions.

In this article, PI Magazine Asia will take a look at the factors that are driving the gas market in Asia, and at how one power generation giant in particular is responding with state-of-the-art technology and worldclass services – Alstom.

The Asian Power Market and its Drivers Power Demand In Asia, there is an enormous demand for power. As Asian nations grow socioeconomically, their GDP rises in tandem with electricity consumption and the demand for reliable and efficient supply.

This trend can be traced by any regular reader of PI Magazine Asia’s country overviews: almost every country that we have profiled has seen an increase in power demand and projected installed capacity alongside a year-on-year growth in GDP. For example, in three decades, South Korea has enjoyed an annual GDP rise of 8.6%, and rose their energy generation by 373 billion kWh. Particularly in countries where there is a growth in the manufacturing sector, such as India and China, a nation’s GDP is intrinsically linked with power demand. Not only is demand present, but the means for development are too.

78 POWER INSIDER JUL / AUG 2013

Evolving Power Market The structure of the Asian power market is evolving. In the last decade, many Asian nations have deregulated their markets, liberalizing and privatizing energy production. Primarily, this was motivated by demand: governments seeking to electrify the population and provide a stable supply for industry. Additionally, governments recognized that privatizing energy production helped to reduce budgets, vital to some nations after the global financial crisis.

Asian nations are opening their markets to foreign investment and more efficient operation. Theoretically, deregulating the energy market and creating competition increases capacity and decreases costs. This has largely occurred; the Asian power market has seen the establishment of new trading markets, growth in trade volume and an expansion of product offerings. As a result, there are opportunities for IPP’s, EPC’s and OEM’s to invest in power projects.

Flexible Response It isn’t enough to open up the market and throw money at power projects; plant investors and operators have a variety of requirements. One of these requirements is flexibility; plants have to be responsive to demand and fuel type. Plant operators are under pressure to respond to the needs of the population or industries that they are supplying. A plant operating at stable load most of the time will supply satisfactory power, but it is the fluctuation in power demand that present a challenge, such as first thing in the morning when kettles switch on, or for less frequent incidents, such as halftime of a big football match.

This requirement is a huge market driver for gas turbines and combined cycle power plants (CCPP). Combined cycle plants use

Power plants need to be able to start up quickly and efficiently to produce the additional supply

AHEAD OF THE CURVE: THE ASIAN GAS TURBINE MARKET AND ALSTOM

the exhaust energy or waste heat of the gas turbine for producing steam in heat recovery steam generators (HRSGs), which is then provided to the steam turbine generators (STGs) for increasing the thermal efficiency.

As such CCPP are modular, flexible, and have much quicker start up times and a higher overall efficiency compared with coal plants.

Flexible Fuel The capability of handling various compositions of natural gas, so called fuel flexibility, is a key requirement for gas turbines and combined cycle power plants.

This becomes even more important as Asian markets are seeking to rapidly develop their gas infrastructure and supply line. According to the IEA, the Asian natural gas market is expected to become the worldâ&#x20AC;&#x2122;s second largest gas market by 2015.

However, maintaining supply in the Asian market is complex. Some nations, like Indonesia and Malaysia, have indigenous supplies, but Asia lacks gas infrastructure, so other markets supply a large percentage of natural gas. This leaves importers at the

mercy of fluctuating prices and export policies.

Additionally resources are not distributed equally. Therefore the number of LNG facilities has increased, with nations in Asia receiving natural gas from multiple sources around the world. These numerous sources result in significant variation in the fuel composition.

Gas turbines need to be able to accommodate these variations without a hiccup.

Nations such as India and Indonesia have a history of blackouts and poor rural electrification, stunting socio-economic growth

Environmental Pressures Growing pressure from governments to reduce CO2 and NOx emissions is another major gas market driver in Asia. Many fossil fuel operators are opting for retrofits of clean technology, upgrades, and unit retirement and replacement, with new power plants being built to the highest standards of clean technology to meet environmental standards.

In China, for example, stringent air pollution controls dictate that all new coal power plants built have to be fitted with FGD systems while for gas fired technology, emission standards are becoming increasingly strict. Asian nations that are part of the Kyoto Protocol, such as Japan, India, Malaysia and Thailand, have stringent individual targets for CO2 and NOx reduction. Combined with efficient technology designed to emit as little waste as possible, and gas plant operators are able to reduce pollution whilst still producing multi-megawatts of power.

Did y knowou ?

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te fossi l fuel being a , emit s hal natural g f of CO the amo as u 2 tha n coa nt l.

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AHEAD OF THE CURVE: THE ASIAN GAS TURBINE MARKET AND ALSTOM Service Demands Finally, the service expectation of the customer is a significant market driver for new gas turbine technologies. EPC’s and OEM’s need to be able to provide products that will satisfy the diverse service demands of power producers and utilities with different levels of experience and skills. EPC’s and OEM’s need to provide adaptable service solutions, from supplying spare parts to full operation and maintenance support, upgrades and retrofits to increase efficiency or output of the gas turbines, local service for planned and unplanned overhauls, and providing advisory services to improve the competitive position of power producers.

Plant owners and operators also expect prudent asset management. This implies optimizing plant lifecycle economics and minimizing the total cost of ownership of the plant. The best solution to improve the performance and extend the lifetime of a power plant is to invest in turbine upgrades that will improve efficiency and/or output of the plant. Lifecycle costs can further be optimized through upgrades that will allow for longer operation between turbine overhauls and by selective reconditioning of key turbine components. In addition, changes in emission regulations in the developing Asian market also require close cooperation between plant owners and OEMs who can provide upgrades to gas turbines that meet the latest regulations.

The decision to upgrade or retrofit a plant must be made in both economic and technical contexts, so operators will benefit from long term contracts with an OEM that continuously works on R&D programs to meet customers technical needs, provides rapid local service support, has the expertise for operations and maintenance, and worldwide presence to ensure availability of parts and services.

Built with the future in mind, owners and operators will be able to retrofit carbon capture and storage (CCS) technology to Alstom installations at a later stage Alstom: Responding to Demand Alstom, as an EPC and OEM, is already responding to these market drivers with success. Alstom offers a portfolio of gas turbines for simple and combined cycle power plants. Alstom’s advanced or F-class

80 POWER INSIDER JUL / AUG 2013

• Rotor design: All Alstom gas turbines are equipped with the unique welded rotor design. This technology has been used for more than 80 years on all of Alstom’s gas turbine and steam turbine rotors. A major advantage is that the rotor has a stiff and rugged one-piece design avoiding the need for de- and restacking (which is required for stacked rotors), resulting in lower maintenance efforts. gas turbine GT24/GT26 and the respective CCPP KA24/KA26 offers the best all round performance. The conventional or E-class gas turbine GT13E2 has the highest performance, i.e. output and efficiency, within its class.

Although the economic drivers are not in place to justify the expense of fitting CCS technology currently, as soon as it is economically viable Alstom customers can implement CCS technology without replacing their existing installation.

Technology aside, Alstom also delivers the service that owners and operators expect to keep them competitive in the Asian power market. Alstom offers services ranging from long term operation and maintenance, supply of spare parts for overhauls, reconditioning of select turbine components, upgrades to gas turbines for improved performance, specialist services for onsite monitoring & diagnostics, and rapid mobilization of onsite personnel to deal with unplanned outages.

All of these services are backed up by plant support centers with experienced 24/7 technical support. Alstom boasts of “global competence, local presence”, and fully understands the customer’s local market, whilst connecting to a global network of specialist problem solvers. Alstom’s reputation in the gas turbine market is prolific, with more than 19 GW of gas fired power plant capacity awarded to Alstom in the last 3 years alone.

This article will focus in more detail on how Alstom continues to respond to Asian market drivers in order to deliver the best gas turbine technology and service.

Alstom Gas Turbines: Technologically Advanced Alstom’s gas turbines differentiate from other technologies in the market in a number of ways. Alstom gas turbine’s key technology differentiators are: • Combustor design: Alstom turbines are equipped with annular combustors with a simple and robust burner design. A key advantage of this design is that it does not require part replacement or combustor tuning until the hot gas path inspection takes place. Emission levels are at very low levels (15 ppm NOx and below) whilst a high operational flexibility is achieved.

Furthermore, Alstom gas turbines achieve unrivaled fuel flexibility.

• Sequential combustion: Alstom’s advanced class gas turbines GT24 and GT26 use sequential combustion. This is a consecutive combustion in the first EnVironmental (EV) combustor followed by the second Sequential EnVironmental (SEV) combustor. A characteristic of this design is a decoupling of emissions from the load: the emissions are generated in the first combustor while the load is mainly done in the second combustor. A key advantage is that emissions are low over a wide load range.

All Alstom gas turbines are capable and have proven in commercial operation to operate on natural gas and fuel oil. The GT26, for example, has achieved switch over times of 10 minutes from natural gas to fuel oil in the field.

In case of falling gas pressure due limitations in supply, Alstom gas turbines can quickly switch over from gas to fuel oil at high loads The GT13E2 In the twenty years that the 50 Hz GT13E2 has been operating, Alstom has successfully delivered more than 160 units with an accumulated operational experience of over 8 million operational hours. The GT13E2 has always been its superior performance: the turbine offers the highest output and efficiency within the conventional or E-class.

Recently upgraded, the turbine can produce over 200 MW while reaching efficiency levels of over 38%. Whilst doing so, the GT13E2 achieves excellent levels of reliability (99.5% over the last 5 years) and availability. Further technology highlights in the GT13E2 include: • Quick start up times of 15 minutes from push button.

• Low NOx emissions of 15 ppm and below and a turn down capability to 50%

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The perfect combination for GT air intakes Macrogen GT Duo & Compatex TMPC When it comes to gas turbine air filtration, there are three elements vital to overall system performance. The pressure drop, burst resistance and dust holding capacity regulate both the quantity and quality of air delivered to the turbine. Fortunately, two products work in unison to deliver best-in-class performance for each of these aspects.

At the first stage, Macrogen GT Duo combines the prefilter and water removal functions to allow the elimination of a dedicated coalescer phase. Of course, this also removes an entire stage-worth of pressure drop too, yielding an instant boost to turbine performance with no retrofitting required.

Following this is Compatex TMPC, which combines industry-leading pressure drop performance with the highest available dust holding capacity (now up to 30m2 of filter area) and unrivalled burst resistance. It's also available in filter grades from F7 to E12 for EPA levels of defence.

Installing Macrogen GT Duo and Compatex TMPC will boost your turbine's performance; lower filter spend and operating costs; and provide assured safety to downstream components. The perfect combination.

AHEAD OF THE CURVE: THE ASIAN GAS TURBINE MARKET AND ALSTOM

The Alstom GT13E2

The GT13E2 is the ideal gas turbine for a wide range of applications like peak power supply, district heating and cogeneration applications, aluminium smelters or pure power generation GT relative load for both gas and fuel oil while being emission compliant. During oil operation, the GT13E2 requires reduced water consumption for achieving the low emissions.

• The Maintenance Cost Optimized operation mode gives the operator the choice to run the plant (switchable online) either at maximum performance or with maximized intervals between hot gas path inspections. In this mode inspections are taking place up to every 6 years, lowering maintenance spending and boosting availability significantly.

• Robust frequency response capability make this gas turbine a preferred solution in either small grids with high load demand changes or in industrial applications like aluminium smelters.

82 POWER INSIDER JUL / AUG 2013

• The turbine’s superior fuel flexibility is able to burn a wide range of natural gas compositions (higher hydrocarbons content up to 23% in volume, Wobbe Index variation ±10%).

The GT24 and GT26 with Sequential Combustion In the 15 years that the GT24 (60Hz) and the GT26 (50Hz) has been operating, Alstom has successfully delivered more than 140 units with an accumulated operational experience of over 5 million operational hours. Of the same design, confirm GT26 (326MW) is a scaled-up version of the GT24 (230.7MW). Since the market introduction of this technology in the mid-90s, this platform has been consistently upgraded with regard to today’s most important parameters: performance and operational flexibility.

The GT24/GT26 offers high baseload and superior part load performance. With the latest upgrade, the GT26 can produce now over 320 MW while reaching efficiency levels of over 40%. Both models achieve excellent levels of reliability and availability. Further technology highlights of these gas turbines include: • Start up times below thirty minutes.

• The Maintenance Cost Optimized operation mode is also available. In this mode inspections take place up to every 4.5 years, which is the longest interval within the class.

• A unique low load operation capability: In this mode the gas turbine delivers sufficient exhaust energy to keep the steam turbine in operation. The CCPP can be used as online spinning reserve delivering

for the GT26/KA26 350 MW (1on1 configuration) or 700 MW (2on1 configuration) in only 15 minutes. With the GT24/KA24, 450 MW can be provided within this timeframe.

• Low NOx emissions: Below 15 ppm are achieved at baseload and, thanks to sequential combustion, as loads decrease, NOx emissions decrease as well – a characteristic not available with single combustor gas turbines. A turn down capability to 40% plant load and below is also possible.

• These turbines are able to burn a wide range of natural gas compositions. Fuel with a hydrocarbon content of up to 18% can be used. The GT24 and GT26 provide a unique flexibility regarding the variation of the Wobbe Index allowing a variation of up to 21MJ/m3.

By switching off the second combustor the CCPP can be unloaded to around 20% plant load, delivering emissions close to baseload level

The Chiba Mill plant has a daily start stop facility with a start up reliability of 99% Alstom’s Service Network Global Competence, Local Knowledge Alstom can provide local service and support for customers whilst still utilizing the company’s many years of global experience.

Alstom is able to support customers worldwide with a network of over 60 Local Service Centers in 70 countries, staffed by dedicated service managers. For the gas market, Alstom has two GT/CC product centers, seven GT reconditioning centers, and one global field service network. Alstom has five global Gas Turbine Execution Centers, one of which is located in Kuala Lumpur. The Execution Centers are staffed with experienced engineers who are fully equipped to perform planned overhauls, unplanned outages, and other repair and reconditioning work. Alstom also has a 24/7 Plant Support Centre that provides technical customer support to customers globally. Alstom has a mobile workshop in Malaysia in order to meet customer’s onsite needs and is in the process of setting up a reconditioning workshop in Vietnam to enable quick and cost effective reconditioning of gas turbine parts for the Asian market.

Maximizing Performance Because of Alstom’s comprehensive knowledge of product and component integration, the company

is able to offer extensive service solutions in gas power generation. From spare parts to full plant operation, Alstom offers effective solutions for gas turbines and combined cycle plants. Services from Alstom include upgrade solutions to improve the competitiveness of a power plant over its entire lifecycle, state-of-the-art technology, life cycle cost optimization, lifetime extensions and emission reduction packages. Alstom also offers reconditioning packages, extending the operating life of a gas plant whilst minimizing running costs as well as tailored module packages to increase a power plant’s profitability.

The success of the Chiba Mill in Japan demonstrates Alstom’s reputation for reliability.

Alstom supplied the GT26 400 MW combined cycle power plant for steel production and the turbo generator has demonstrated exceptional reliability, accumulating more than 1,300 starts and over 18,000 operating hours over 5 years.

Other project highlights include Kaeng Khoi, which boast 99% reliability; Cartagena in Spain, with a 96% availability, and Hai Fu, Republic of China, also has a start up reliability of 99%.

• Integrated Lifecycle Plant Management Improving the efficiency of a power plant depends on fine tuning complex interactions between diverse sub-systems. Building on decades of operations and maintenance expertise, Alstom helps operators to maximize their total plant performance while fully complying with environmental, regulatory and commercial constraints. Since building and maintaining a profitable gas power plant goes beyond selecting the best components, it is vital that a plant developer builds an integrated plant with an experienced OEM such as Alstom to provide full operations and maintenance support to enhance flexibility and performance.

• Long-term Partnerships One of the major market drivers in the Asian gas power generation industry is the customer’s need to develop a long-term relationship with the OEM in order to maintain efficient and profitable performance throughout the life of the plant. During the course of a long-term agreement (LTA), Alstom can offer a range of services including the provision of new and improved parts, reconditioning services, advice and operational support, field service, performance improvements, service contracts and services on other OEM gas turbines. Like so much of Alstom’s services, the customer is able to customize their contract to best fit the needs of their plant.

Other advantages of an LTA include frameworks that define prices and conditions in advance. Besides offering preferential conditions for high quality parts and services the LTA reduces administrative efforts and simplifies planning and the customer can leverage Alstom’s extensive experience in plant asset management. Service contracts can be customized to meet all customers’ operational, maintenance and support needs and are designed to be a cost effective way to share risk.

Alstom’s LTA O&M contracts are fee based, so that many risks are mitigated

The Keppel Block I gas fired power plant in Singapore

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AHEAD OF THE CURVE: THE ASIAN GAS TURBINE MARKET AND ALSTOM SUCCESS STORIES IN ASIA • Senoko In 2002, the GT26 fleet record for continuous operation was set by the GT26 unit in the Senoko plant at 244 days. The Singapore plant is a success story for a number of reasons, such as the fast delivery; the second phase of the plant was handed over way before the contractual date of September 2004.

Another achievement is that this was not a new project, but a repowering project.

Originally consisting of three 120 MW oil fired units, Alstom were able to convert the plant into three 360 MW combined cycle units.

The resulting 1,080 MW has an efficiency of 50% (HCV) compared with 36% for the oil fired units. The units utilize a GT26B gas turbine with a CMI vertical heat recovery steam generator. Steam from the HRSG drives an extensively upgraded steam turbine retained from the original plant. New rows of blades were skillfully added to accommodate the greater steam flow, with no increase in length.

The benefits of the repowering include a substantial saving relative to a new build; reduced NOx, faster start up (from standstill to full load in 3 hours instead of the 9), greater automation and increased fuel flexibility. The turbine can use gas from either Malaysia (Petronas) or Indonesia (South Sumatra). The prudence of this dual gas supply strategy was amply demonstrated

Alstom also has a 20 year operation and maintenance contract for Keppel I; the first independent power project in the Singapore electricity market

during the Singapore blackout, when Senoko was unruffled by loss of the West Natuna gas supply, and was in fact able to respond by increasing its generation to 50.5% of Singapore’s total load.

• Kaeng Khoi II The Kaeng Khoi II plant was ordered by Japan’s Mitsui & Co. Ltd. to help meet the burgeoning power needs of Thailand’s rapidly developing economy. Alstom was the turnkey EPC for the Kaeng Khoi II plant, and the design was based on two KA26-2 advanced multi-shaft blocks. Each block consists of two GT26 gas turbines with sequential combustion, each coupled to a TOPAIR air cooled turbo generator.

The blocks also utilized two Alstom HRSG systems with triple pressure reheat water/ steam cycle, and a floor mounted three casing steam turbine, coupled to a STF-30C hydrogen cooled TOPGAS turbo generator.

In addition to the EPC contract, Alstom will provide the major spare parts for the first 12 years of operation. The Kaeng Khoi II plant operates with over 99% reliability.

• Keppel II Alstom is the EPC for a new 2 x 400 MW power plant in Singapore for Keppel Merlimau Cogen (KMC) Pte Ltd. Keppel II is being built next to the existing KA13E2-2 Keppel I power plant on Jurong Island, which was also built by Alstom following the implementation of the National Electricity Market of Singapore policy in January 2003.

When completed in August 2013, Keppel II will add around 10% to the country’s capacity, and the contract underlines Alstom’s competitiveness in Asia. Alstom have signed an 18 year service contract for major maintenance for Keppel II, which consists of two GT26 gas turbines equipped with the sequential dry low NOx combustion systems, two horizontal, triple pressure reheat, drum type heat recovery steam generators, two compact, state-of-the-art STF15C steam turbines with axial exhaust, two high efficiency TOPGAS turbo generators, and the ALSPA Series 6 integrated control system.

The Alstom GT24/GT26

84 POWER INSIDER JUL / AUG 2013

Gas will remain a priority power generation fuel in Asia Pacific as it is the cleanest fossil fuel which delivers high efficiency and reliability • EGAT North Bangkok Block 2 EGAT awarded an EPC contract to Alstom to build an 850 MW combined cycle power plant at the North Bangkok Block 2, in consortium with Sumitomo Corporation of Japan. This is Alstom’s first combined cycle power plant contract with EGAT and the first in the world to feature Alstom’s upgraded GT26 gas turbine. Alstom will supply two GT26 gas turbines, the turbo generators, HRSG units, steam turbines and distribution control system.

This contract further strengthens Alstom’s position as a key player in power generation infrastructure in Thailand, having built over 7 GW of the installed capacity of the country. This includes the EPC contract for several gas-fired plants, including the 730 MW Bowin and 350 MW Bang Bo projects. Alstom also supplied equipment to Rayong, Thailand’s first CCPP. In Summary “Alstom’s gas fired technology produces clean, flexible and efficient power, which combined with our extensive experience, will serve Asia Pacific’s growing power requirements well. Alstom’s commitment to our customers and market is to ensure continued improvement – in terms of competitiveness, reliability, flexibility and sustainable environmental footprint as well as adapting our offering that best fits our customers’ and local market needs from Plant Integrator™ to components and services”, advised Pascal Radue, Vice President of Alstom’s Gas Business Asia Pacific.

In Asia, gas power stations and combined cycle power plants will continue to be a major source of power generation. Because of the technology’s strengths in efficiency, flexibility in load and fuel type, and minimal emissions, gas turbines are ideal for responding to Asia’s growing generation needs. Asia Pacific in particular is a key region for the development of natural gas and LNG infrastructure as governments place their confidence in this reliable energy supply.

Asia Pacific is also a key region for Alstom, where the company has a strong customer base, and where Alstom’s gas turbines and combined cycle portfolio perfectly matches the market requirement for the Asia Pacific region, catering for today’s and tomorrows’ power generation. PI

feature

Will Smart Grid Deliver As Promised?

Insights from a Utility Survey in Australia from Frost and Sullivan Introduction ‘Smart grid’ is a concept that is frequently discussed as a solution to most current constraints in electricity distribution. The high profile smart grid projects ‘Australia: Smart Grid Smart City’ in New South Wales and smart metre rollout in Victoria have achieved significant milestones in 2013. Smart Grid Smart City is expected to complete in September 2013. The AMI rollout in Victoria is expected to complete in December 2013.

Meanwhile the project had a successful trial of electric vehicle charging in early 2013.

The sector has long been troubled by the critical demand for power stability, increasing peak demand, and more recently the need for smooth integration of distributed power generation systems.

Nevertheless, is the expectation realistic?

What have utilities been doing in terms of smart grid deployment? What have been the major challenges in deployment? And what are the key areas of interest? To answer these questions, we interviewed about 10 power distribution utilities in Australia aiming to understand how they look at these issues.

What are the drivers and obstacles?

The drivers for smart grid deployment, ranked by impact, are:

86 POWER INSIDER JUL / AUG 2013

• Increasing demand for energy efficiency and the need for capital investment deferral: The electricity price in Australia nearly doubled over the past five years, and is expected to double in the next five years. The price increase in the recent five years was largely due to increased power transmission and distribution costs, and investment in infrastructure. Statistics show that with the increasing adoption of distributed power generation and the promotion of energy efficiency, base load has been stable, whereas peak load has been increasing greatly. This has prompted enormous investment towards meeting peak load. In light of the growingly stringent capital investment project review from Australian Energy Regulator (AER), demand management has been publically encouraged as a way to reduce capital expenditure at power transmission and distribution utilities. The smart grid is seen as one way of reducing (and so managing) peak loads, without adding new generation and distribution capacity.

• Successful trials: Successful business cases have been established by some utilities on an individual technology basis; based on trials. Encouraged by these results, utilities have stepped

forward to increase investment levels.

• Growing adoption of embedded power generation: The power grid control and monitoring offered by smart grids is important to effectively and safely integrate renewable energy sources that tend to be highly volatile in terms of supply.

• The replacement of dated analogue power meters: When traditional analogue meters reach the end of their life expectancy, the utilities will most likely replace them with the modern technology meters – smart meters. This would result in another wave of large scale smart meter rollout.

• Preparing for potential regulatory change: A number of utilities are aware of the contingency of regulatory scheme changes that might affect their future financial returns. In this context, investing in smart grids can potentially reduce the need for new capital assets.

• The search for improved customer experience: With smart grids and in-home displays conveying real time information on energy consumption, consumers can increase their visibility of energy consumption, monitor load pattern, and consequently change energy use behavior to considerably reduce peak load.

FEATURE: WILL SMART GRID DELIVER AS PROMISED?

The restraints, ranked by impact, are: • Asset based capital expenditure allowance scheme a disincentive: Based on the current asset based incentive scheme for the distributors, compared to the amount of revenue they can receive by investing in capital infrastructure, investment on smartening up the existing network apparently offers less immediate and certain returns.

• Disaggregation of the power supply chain in Australia: With distributors owning the smart grid technologies that have direct access to consumers, retailers could potentially be denied energy sales. Also, while distributors are actively encouraging consumers to reduce peaks in demand, retailers’ peaking generators were built to supply this demand; thus increasing the risk of having their assets stranded.

• Inertia among customers in adopting new metering method: The fact that the smart meter would allow people to remotely read the consumers’ meters and potentially even control the meters is creating some level of discomfort among some consumers.

• Negative experiences from previous projects: The still ongoing roll out of smart meters in each household in Victoria was budgeted to cost AUD 800 million. 18 months into the rollout, as of the end of 2011, the total project cost was estimated to reach AUD 2.3 billion, nearly three times the original budget. This has created a strong negative perception in relation to the smart grid concept and has led to some reconsideration of smart grid projects.

• Financing difficulty: The high cost nature of smart grid projects, unclear business case in some instances, and the challenges encountered during previous rollouts have resulted in increasing regulators’ hesitation in approving proposed projects. This has led to significant funding difficulties despite no interviewed distribution utility is willing to acknowledge the funding challenge.

• Untested technologies: With emerging technologies, it is a lengthy process to full deployment, with pilots, trialing, elimination, and confirmation.

Major Challenges Smart Grid Utility Survey: Major Challenges Encountered by Utilities, Australia, 2012 Source: Frost & Sullivan analysis.

The biggest challenge facing utilities is the integration of various technological initiatives (and consequently, technological uncertainty).

It is expected that only by 2015 there will be more consensus on which definitive technologies deliver the desired smart grid results. There is today, no single off-shelf solution for smart grid.

Another notable challenge is the potential conflict of interest between distribution network service providers (DNSPs) and retailers. In the National Electricity Market Australian, the retailers need the access to the smart meters, whereas they are owned by the distributors. In

Smart Grid Utility Survey: Major Challenges encountered by Utilities, Australia, 2012

Smart Grid Utility Survey: Key Areas of Interests, Australia, 2012

Source: Frost & Sullivan Analysis

the case of the smart meter installed at end user sites, the meter and information generated from it are owned by the distributors. The installation and utilization of the meter in turn impacts prices. While retailers need to access the data and deliver services, the current model might lead to disputes and conflicts of interest. The degree of the challenge varies amongst distributors and in some instances the distributors also operate electricity retailing in the region or (in the case of Western Australia) collaboration is necessitated by the structure of that particular market.

Overall, utilities are expecting potential reforms initiated by the regulators to facilitate structural changes to enable a clearer cost-benefit analysis in the assessing smart grid projects for all stakeholders.

Areas of Interest Smart Grid Utility Survey: Key Area of Interests, Australia, 2012 In relation to smart grid projects, demand management is the most mentioned area of interest by utilities. Ultimately, the fundamental function of smart grid is to achieve network management and demand-supply two way interaction. This can be realized with various approaches involving multilayered technologies.

The shift from an AMI-focused approach to result-driven conventional power network technology replacement reflects this sentiment.

Conclusion More stakeholders are of the view today that smart meter focused projects alone cannot deliver desired outcomes. There is no planned large scale smart meter rollout across each state.

The successful experiment of electric vehicle

charging is an encouraging case demonstrating the technological viability to achieve economic values. It takes more compelling case studies and time for public to dissolve the negative perception of AMI based smart grid solution. A results driven network automation strategy that involves direct load control, distributed generation management, proactive consumer education, incident preparedness, while maximizing the existing ICT and T&D infrastructure, and incorporating AMI technology has higher chance of creating a positive cost-benefit result. Also a more inclusive effort of distributors involving retailers in smart grid project rollout is expected to provide greater synergy. PI For more information For more information on smart grid development in Australia, please refer to the studies published

by Frost & Sullivan: The Australian Smart Grid Market - Utility Survey (Moving from Smart Meter focused Deployments to Holistic Solutions) Analysis of Utility Transmission and Distribution Spend in Australia (A More Stringent Regulatory Review Leads to More Discrete CAPEX).

ABOUT FROST & SULLIVAN Frost & Sullivan, the Growth Partnership Company, works in collaboration with clients to leverage visionary innovation that addresses the global challenges and related growth opportunities that will make or break today’s market participants. For more than 50 years, they have been developing growth strategies for the global 1000, emerging businesses, the public sector and the investment community. Contact Frost and Sullivan through their website: www.frost.com

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INTERVIEW

The Right Choice for the Best Fix TONY O’BRIEN, MANAGING DIRECTOR OF AUSTRALIAN WINDERS, ASKS CRITICAL QUESTIONS ABOUT CHOOSING THE RIGHT CONTRACTOR TO WORK ON YOUR ELECTRICAL MACHINE.

Whether your asset is down due to a forced outage or has been scheduled for maintenance or repair, choosing the ‘right man for the job’ can be difficult. How do you pre-qualify the vendors? Is price the main factor, or is quality? Is an Original Equipment Manufacturer (OEM) the best choice or is there an alternative better suited to perform the work? Can the work be done onsite or must the asset be sent offsite? If it’s a forced outage, who can mobilise and help you immediately?

These are just some of the critical questions that customers have to ask themselves when selecting a contractor to work on their equipment. In this article, I give my opinion on what choices are available in the repair and rewinding market.

Lets look at the worst case scenario: a forced outage to either a generator or critical HV motor. It is justifiable to state that help, any help, from specialists would be gladly accepted. To have an expert onsite the very next day would be even better. Normally the only people that can or are willing to achieve this are the non-OEM’s; the smaller owner operator companies who see helping a customer in need as paramount. OEM

80 88 POWER POWERINSIDER INSIDER JUL JUL//AUG AUG2013 2013

companies can take weeks to mobilise to site due to internal requests and procedures, and even longer to schedule any repair works.

Small owner operator companies with the correct skills can make decisions on the spot and want to assist the customer to get back to producing ASAP. Onsite or Off?

Another critical question is: Does a repair or rewind need to be sent offsite? After all, larger generators must be rewound onsite due to their size, so why can’t all machines?

They can, in particular the formed coil type machines. All that is necessary is floor space, preferably overhead cranage and utilities like power, water, and compressed air delivered to the site. If it is necessary to have the machine heated in an oven, portable elements, heating controls and insulation will turn the machine into its own oven! Another important point is that the customer can keep control of their machine, ensure that the instructions are being adhered to, and monitor the progress of the project more closely.

Where do You Find an Expert?

The customer, thinking that they are the only people that know about their generator, will call their OEM company out of respect,

Does a repair or rewind need to be sent offsite? or even fear. The critical question is: Are they the sole expert on your machine? Can the OEM support you fast enough? And is the first person contact at the OEM experienced enough to repair your machine? The synergy that comes with experience from working on all brands of generators can be very beneficial, as they may have unique methods of treating a breakdown that aren’t in the OEM handbook.

An obvious customer concern when using a non-OEM company is whether or not that company has the correct equipment and trained personnel. However, in Australia and New Zealand, it is a well known fact that even OEM companies don’t employ winders and technicians fulltime; they accept the project first and then subcontract the work out to other companies or contractors.

In the USA it is a different story, but there is a much higher volume of generators. Owner operators normally have their own winding crew who work and create that

INTERVIEW: AUSTRALIAN WINDERS

The synergy that comes with experience from working on all brands of generators can be very beneficial synergy together. Additionally, they invest in specific industry tooling and new technology, such as induction welding equipment, digital insulation measuring equipment, and dry ice cleaning tools. They know what resources are necessary for a quality repair or rewind.

Prequalifying Vendors

To prequalify vendors is easy for the customer, especially for a scheduled project.

Large multinational OEM companies have commercial strength that means they have the upper hand in securing contracts. This commercial strength is sometimes stronger than their technical capabilities, so they rely on their subcontractors for technical expertise.

Small owner operator companies who have the technical expertise are usually unable to take on the commercial responsibility unless backed by a large firm.

This qualifying process is sometimes waivered when an urgent repair is required.

Small companies, such as Australian Winders, can respond the very next day in most cases.

They have the expertise and the synergy discussed here that can help in an urgent case.

This commercial strength is sometimes stronger than their technical capabilities The Advantage of Partnerships

These advantages can be accentuated when two owner operator companies come together to form a strategic alliance, and the larger of the companies has the commercial strength to compete with the OEM. This means that the technical evaluation can

match the commercial evaluation for the customer.

Australian Winders and National Electric Coil (USA) has had this type of alliance. This team have worked together to provide potential customers with a reliable, fast, and capable team to assist in forced or scheduled outages. More information on these two companies can be found by visiting their websites, as advertised below. PI FOR MORE INFORMATION For more information, please see the Australian Winders & National Electrical Coil websites: www.australianwinders.com.au www.national-electric-coil.com

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REGULARS

Country Directory:

Australia Australia & Energy: Fast Facts Australia is the

world’s 17th largest consumer of fossil fuels

Coal is one of Australia’s largest commodity exports

with earnings of around $48 billion in 2011–12, and Australia accounts for 27% of world black coal exports

Australia has the highest average solar radiation

per square meter of any continent with approximately 15,000 times more solar energy than Australia’s current energy consumption

54 GW

Australia ‘s installed capacity

Did you Know?

The electricity generation, transport, and manufacturing and construction sectors account for 75% of Australia’s energy consumption

90 POWER INSIDER JUL / AUG 2013

Coal, gas, oil and uranium non-renewable resources available to Australia

Renewable energy is abundant in Australia, with plenty of

wind, solar, wave, bioenergy and geothermal energy

Did you Know?

From 2012, there were 20 projects at an advanced stage of development with a combined capacity of 3,017 MW and a capital cost of around AUD 6.5 billion. 65% of these projects are wind powered

21% by 2050 Projected Total energy consumption growth

Wind resources along the Southern coasts of Australia are amongst

the best in the world

51% Renewable by 2050 BREE projects that by 2050, Australia’s energy mix will contain 51% renewables

Australia’s Energy Mix

Rooftop Solar 1% BioEnergy

1%

Wind

3%

Hydropower

6%

Natural Gas

15%

Coal

74%

Australia’s Power Industry National Energy Market

The NEM facilitates power flow across Capital Territory, New South Wales, Queensland, South Australia, Victoria and Tasmania. The NEM operates as a wholesale spot market in which generators and retailers trade electricity through a gross pool managed by the Australian Energy Market Operator (AEMO). The AEMO works with the Australian Energy Market Commission (AEMC) and Australian Energy Regulator (AER) to allow a consistent near- national approach to regulating Australia’s energy markets.

Western Australia

The energy infrastructure is organized into districts; The South West Interconnected System (SWIS), the North West Interconnected System (NWIS), and a number of regional power systems. The SWIS is a wholesale market and the Independent Market Operator (IMO) is responsible its operation. Other systems operate as retail markets. Electricity regulation is state-based, and is the responsibility of the local Economic Regulation Authority.

Northern Territory

The Utilities Commission of the Northern Territory is responsible for the regulation of the market. The Power and Water Corporation providing most of the electricity. New entrants into this market use the existing infrastructure and pay a network charge.

Generation & Distribution

In Australia, the electricity market is deregulated across all regions. Electricity is generated by a number of IPP and state owned enterprises, and is distributed by 16 local transmission companies. EnergyAustralia, Origin and AGL dominate the industry, controlling 80% of the installed capacity.

COUNTRY DIRECTORY: AUSTRALIA

Top 5 Proposed Coal Projects State

Capacity (MW)

Operator

Status

Investment (AUD Bn.)

Complete

Dual Gas Demo Project

Vic.

600

Dual Gas Pty Ltd

Planning

1.1

Planning Stage

Galilee Power Project

Qld.

400

Waratah Coal

Planning

1.25

2017

Coolimba Power Plant

WA

400 coal

Aviva Corporation

Proposed

1.6

2014

Arckaringa CTL and Power Phase I/II

SA

560/280

Altona Energy and CNOOC

Pre-feasibility

3.5

Planning Stage

Bluewaters Stage 3 & 4

WA

208

Griffin Power 3 Pty Ltd

Expansion: Government approved

-

2016 / 2018

Project Name

State

Capacity (MW)

Operator

Status

Investment (AUD Mn.)

Complete

Diamantina Power Station

Qld.

242

APA Group / AGL Energy

Under construction, EPC’s: CTEC and Siemens

570

2014

Ichthys CCPP

NT

500

JKC Australia LNG Pty Ltd

Under construction, EPC’s: CH2m HILL / UGL / GE

929

2016

Tarrone Power Plant

Vic.

920

AGL

Advanced planning

600

Planning Stage

Aldoga Power Plant

Qld.

500 - 1,500

EnergyAustralia

Seeking permissions

1.8 billion

2013-14

Blackstone Power Station

Qld.

500 (1,500)

EnergyAustralia

Planning tender

1.8 billion

2013-14

Braemar 3

Qld.

550

ERM Power

Advanced planning

550

2015

SA

1000

Investec

Awaiting power sale contract

750

2016-23

NSW

500 - 1,000

AGL Energy

Approved

350 - 700

2017

WA

190

BHP Billiton

Under Construction: Siemens EPC

597

2014

NSW

550-660

ERM Power

Approved

680

2016

Project Name

Top 10 Gas Projects

Cherokee Gas-Fired Station Dalton Power Station Yarnima Power Station Wellington I

Top 5 LNG Production Facilities Project Name

State

Capacity (Mt/pa)

Operator

Other Owners

Complete

Australia Pacific LNG

Qld.

9

Origin Energy

ConocoPhillips, Sinopec

2015

Gladstone LNG

Qld.

7.8

Santos

Petronas, Total, Kogas

2015

Gorgon LNG

WA

15.6

Chevron

Shell, ExxonMobil, Osaka Gas, Tokyo Gas, Chubu Electric

2015

Ichthys LNG

NT

8.4

INPEX

Total

2017

Wheatstone LNG

WA

8.9

Chevron

Apache, KUFPEK, Shell

2016

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COUNTRY DIRECTORY: AUSTRALIA

Top 5 Solar Projects Project Name

State

Capacity (MW)

Operator

Equipment Supplier

Investment (AUD Mn.)

Complete

Kogan Creek Solar Boost Project

Qld.

44

CS Energy

Areva Solar

105

2013

Broken Hill Solar Plant

NSW

50

AGL

First Solar

450 (inc. Nyngan)

2015

Nyngan Solar Plant

NSW

100

AGL

First Solar

450 (inc. Broken Hill)

2015

Whyalla SolarOasis

SA

40

Solar Oasis Consortium

Wizard Power

230

Planning Stage

Chapman Solar Power

WA

50

Investec Limited

Planning

200

2014

State

Capacity (MW)

Operator

Turbine Supplier / Status

Investment (AUD Mn.)

Complete

Vic.

225

RES Australia

Advanced planning

450

Planning Stage

Boco Rock Wind Farm

NSW

113

EGCO

GE, Downer EDI

350

2014

Gullen Range Wind Farm

NSW

165.5

Goldwind Australia

Goldwind

118

2014

Mount Gellibrand Wind Farm

Vic.

189

Acciona Energy

Acciona Windpower

696

2015

Snowtown Stage 2

SA

270

TrustPower Limited

Siemens

439

2013

Darlington Wind Farm

Vic.

350

Union Fenosa Wind Australia

Planning approval process

700

2016

Liverpool Range Wind Farm

NSW

1000

Epuron

Environmental assessment

1.8 bn

2015

Vic.

300 - 450

Origin Energy

Planning network connection

1-1.4 bn

2016

NSW

622.5

Wind Prospect CWP

Advanced planning

1.3 bn

2015

Top Wind Projects Project Name Ararat Wind Farm

Stockyard Hill Wind Farm Uungula Wind Farm

Top 5 Small / Hydro / Ocean and Wave Projects Project Name

State

Capacity (MW)

Operator

Complete

Upper Tamut Expansion

NSW

40

Snowy Hydro

2013

Burdekin Hydro Power Station

Qld.

37

Stanwell Corporation

Planning Stage

Tasmania

302

Tenax Energy

2015

Clarence Strait Tidal Energy Project

NT

450

Tenax Energy

2013

Port Phillip Heads Tidal Energy Project

Vic.

34

Tenax Energy

2014

Banks Strait Tidal Energy Facility

92 POWER INSIDER JUL / AUG 2013

COUNTRY DIRECTORY: AUSTRALIA

Top 3 Bioenergy Projects Project Name

State

Capacity (MW)

Operator

Investment (AUD Bn.)

Complete

North Queensland Bio-Energy Plant

Qld.

80.5

North Queensland Bio-Energy Corporation Limited

450

2015

Woodlawn Bioreactor

NSW

6.4

Veolia

Project proposed

2015-20

WA

40

Western Australia Biomass Pty / Aurecon

110

Planning Stage

State

Capacity (MW)

Operator

Investment (AUD Bn.)

Complete

854

2015 (2020 commercialization)

Diamond Mill Biomass Plant

Top 4 Geothermal Projects Project Name Geelong Geothermal Power Project (HSA)

Vic.

12 (up to 140)

Greenearth Energy Limited

Koroit HAS

Vic.

50

Hot Rocks Limited

-

2014

Paralana

SA

30

Petratherm & Beach Petroleum

230

2018

Innaminka Pilot Plant

SA

1

Geodynamics

-

2013

Top 5 Proposed Water Treatment Projects State

Capacity

Operator

Investment (AUD Mn.)

Complete

Point Paterson Desalination Plant

SA

45 GL

Acquasol

370

Planning Stage

Hawker Desalination Plant

SA

Proposed

SA Water

8

2014

Perth Sewage Plant

WA

28 GL

Water Corporation

116

2016-20

Christies Beach Wastewater Treatment Plant Upgrade

SA

-

SA Water

272

2015

Whitsunday Water Treatment Infrastructure Project

Qld.

14.5 MG

Abigroup / Regional Council

45

2013

Project Name

*NB: PI Magazine would like to credit the Australian Governmentâ&#x20AC;&#x2122;s Bureau of Resources and Energy Economics for their contribution to the facts and figures collated in the Country Directory.

WE WANT TO KNOW WHAT YOU THINK! PI Magazine Asia wants to know what you think of our Country Directory. Did you find it useful and interesting? What did you think about the other articles featured in the July/August edition? If you have any opinions or suggestions on this or any of our other articles, or want to recommend a project to profile, contact us through Twitter and LinkedIn, or through our website: www.pimagazine-asia.com/contact-us Alternatively, email the editor: rachael@sks-global.com

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Upcoming Events: for the Energy Business in Asia September 2013

October 2013

November 2013

3RD MYANMAR OIL, GAS AND POWER WEEK Organized by CMT Events 23 – 27 September 2013 Sedona Yangon Yangon, Myanmar

POWER-GEN ASIA 2013 Organized by Penwell 2-4th October 2013 Mobil Industrial Lubricants MWM

10TH ASIA GAS CONGRESS Organized by CDMC 14-15 November 2013 Osaka, Japan

CARBON FORUM ASIA Organized by Koelnmesse 24 -25 September 2013 Centara Grand Convention Centre Bangkok, Thailand CLEAN ENERGY FORUM ASIA Organized by Koelnmesse 25-27 September 2013 Centara Grand Convention Centre Bangkok, Thailand POWERTRENDS 2013 Organized by Leverage International 25 – 27 September 2013 SMX Convention Centre, Manila, Philippines

IGEM 2013 Organized by Expomal Int 10 – 13 October 2013 Kuala Lumpur Convention Centre KL, Malaysia 22ND WORLD ENERGY CONGRESS Organized by W.E.C 13-17 October 2013 EXCO Centre Daegu, South Korea

December 2013 12TH CLEAN COAL FORUM INDONESIA Organized by CDMC 5-6 December 2013 Jakarta, Indonesia

2014

SINGAPORE INTERNATIONAL ENERGY WEEK Organized by the EMA 28 Oct – 1 Nov 2013 Sands Expo & Convention Centre Marina Bay Sands, Singapore

5TH ANNUAL NUCLEAR POWER ASIA Organized by Clarion Events 21-22 January 2014 Hanoi, Vietnam

GAS TURBINE WORLD CHINA SUMMIT Organized by Oppland Corp 30 – 31 October 2012 Crowne Plaza Shanghai Fudan Shanghai, China

SINGAPORE INTERNATIONAL WATER WEEK Organized by Experia 1-5 June 2014 Singapore

Advertisers Index Mobil Industrial Lubricants Clyde Bergemann IGEM Exhibition Acciona Agua Hibbard ComAp Australian Winders Sulzer Turbo Services

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Hydrogenics A2 Wind Alstom Vokes Air Taiwan Green Trade Show Power Insider Asia MWM

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COUNTRY DIRECTORY: AUSTRALIA

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