“One of the things I’ve been thinking about in the last couple of years is this: Where is the big growth and the big impact in digital?”

Laura Anderson certainly isn’t the only one in the energy sector mulling this digital dilemma – however, she’s far better placed than most to be able to identify a ‘next big thing’.

As Senior Vice-President of Controls and Digitalisation at Siemens Energy, she describes herself as “a geek for linking long-term market trends and the strategies needed to capitalize on them”.

She says she does this by “wearing a lot of hats”, including researcher, data detective, idea-generator and storyteller. And she adds that what makes her unique “is my ability to navigate grey areas and uncomplicate the complex”.

Which is good news: because I want her to uncomplicate the digital transformation of the energy sector up until now and then peer into that often greyest of grey areas – the future.

However, before she looks to the future, she wants to set what comes next in the context of what’s gone before, particularly in terms of digital innovations in technologies such as gas turbines.

Solving old problems with new solutions

She says digitalisation on the traditional power plant “is relatively straight-forward – we know those use cases and we’ve known them for 40 years”.

“When I think about it from a digital perspective, we can see where the path is going for conventional power plants.

“Traditionally, we have had a lot of fantastic data on the rotating equipment, and through controls and automation we have been expanding that. We can optimize it so that you have better outcomes and better efficiencies by looking at the whole system.

“Before digitalisation, we were perhaps suboptimizing a little bit. Now we can use AI and machine learning to re-optimize to get more out of where we’re going. We are using these digital tools to help us answer old problems.”

However, she states “that’s not necessarily where the big innovation is”.

“I think a bit of a game-changer is going to be on remote operation.” To illustrate her point, she highlights a successful pilot Siemens Energy carried out with Florida Power & Light to enable remote start-up on one of their plants.

“And starting up a power plant with no-one on site is not a trivial matter – yet it was like a push-button remote start that we managed to achieve.

“So what we are starting to see is this idea of the power plant moving from being a fully-manned operation to more of a ‘smart machine’ – it will do what it needs to do and if it needs a person on site, it will let you know.”

This, says Anderson, “is a reflection of the energy transition, where you are starting to see power plants as one further set of resources: as a commodity to be deployed on a ‘right power, right place, right emissions’ basis”.

Remote operating proves its worth

Remote operating is something we have all had to do in our work over the past 18 months during the pandemic, and lockdown conditions presented significant challenges for power plant operators.

“Our customers are reluctant to allow more people inside a plant than are absolutely needed. And in some cases you had lockdown on sites, with people sleeping there.”

She says suddenly there was a demand for Siemens Energy’s already established remote-worker concept, which would see a field worker don wearable technology to talk to an expert who may often be on another continent.

“We would be able to outfit them to be able to see what was going on and accompany someone while they were doing some of the more advanced checks.”

She says that with international travel at a standstill, “customers appreciated that we had a solution that we could deploy around the world – remotely”.

And some customers certainly needed that solution: “We had a few who really had a crisis. One on the industrial side had a plant explosion: his experts were in Europe and the plant was in Asia. So we got a call: ‘Can you help?’

“We had the right equipment not too far away, we got it over, and we were able to digitally connect with their experts to be able to triage – that was incredibly helpful.

“We were not necessarily the experts in providing the underlying information technology, but we were able to put together a packet of technologies for that particular situation.”

Did she learn anything from those experiences of live video engineering from afar? She laughs: “We found out that having a camera on the head is much like watching The Blair Witch Project: you get dizzy. So we started using chest-mounted cameras, which are much easier to follow. Also using Google glasses gave field workers the opportunity to see illustrations that would point them directly to what they needed to do.”

Lasting impact of the pandemic

She says that as we come out of the pandemic, “we’ll probably go back to sometimes putting experts on the ground for longer periods of time, but I think a lot of pandemic practices will most likely be here to stay”.

“COVID-19 has accelerated certain patterns of adoption. I think the pace of change is now being dictated by both the virus and governments and companies coming up with green goals – the pace is not being dictated by technology or its limitations.”

So, with that in mind, I ask her if she believes the pandemic will accelerate a green energy transition.

“I think the pandemic has forced us to get comfortable with certain technologies in a much more immediate way than otherwise. And I think it engineered big changes to be able to work from home. But in terms of the bigger context of the industry – no, I don’t think so.

“Why? Because I have a feeling that we will be back to our usual consumption patterns relatively quickly – I think we will be a bit back to where we were.”

She adds that the pandemic “has presented people with an opportunity to realise that they can get along with less, so there may be some longer-term consumption trends – but I wouldn’t see it as being a huge thing”.

“I think the remote trend on generation assets will be an interesting one to watch and see to what extent it picks up in the more price-competitive markets – especially as they move more to becoming peakers.”

Drilling down to things specifically digital, she says there will be “a lot more momentum” around the use of microgrids, AI and blockchain in relation to green energy.

“I also think we’ll start to see more AI on trading models and we’ll be able to better balance the demand-supply equation.”

And that, she says, “will start to make the decentralized concept really ‘live’ more, because while there are current initiatives, there seems to me to be too little clarity on which way they are really going and which approach will be a good one.”

More AI, machine learning and blockchain means more data – and that means an increased security risk around that data.

“There are going to be some big cybersecurity challenges that we need to get our arms around,” says Anderson.

“We have a lot of remote assets: how do we keep them protected to the best of our ability? The speed of cybersecurity is turning up, as well as the sophistication of actors in terms of getting in and then making money by stopping production.”

Talking about the broader digital transformation of energy, Anderson believes the sector has come a long way.

“A lot of companies have matured their digital thinking around their digital stack. If you think back five years when the early software platforms were starting to come out, nobody really knew what to do in terms of digital.

“Now they have done enough trial and error to get an understanding of their stack. The maturity of customers and their thinking has significantly changed over the last five years.”

She believes the digital front-runners will have a philosophy that will dictate the pace and direction of change, and that philosophy is one of co-operation, adaptation and evolution.

“The time of monolithic solutions is probably over: it’s going towards customers’ individual needs and the skills going forward will be the ability to listen and understand what is actually needed.”

The potential of AI and blockchain

Professor Monika Sturm is Siemens Energy’s Principal Key Expert in Digitalization – Laura Anderson sums her up as “our blockchain expert”.

And while Professor Sturm will use the term blockchain, she prefers distributed ledger technology – it’s more precise.

“Blockchain is a young technology and it’s been very hyped in past years,” she says. “At Siemens Energy, we are not concentrating on developing a new kind of blockchain concept: our focus is on using the existing technology to enable us to offer new digital services to the energy market.”

She talks about the digital sustainability of blockchain and of the need for ‘correct’ data – or ‘good enough’ data.

She explains: “For me, the important part in the blockchain arena is that we keep control over the data. We can distribute the data in a trusted way so that everybody who is offering the data keeps a form of control.

“And here, the management between AI and blockchain has a very important role. Because an AI algorithm or machine learning algorithm runs on data, and if that data is manipulated, then the AI or ML output will not be correct.

“So I think the combination between AI and a distributed ledger technology layer is where the potential lies to enable services running on correct data in a way where everybody keeps a level of control – it really is secure data sharing.”

She finds the changes – and the speed of change – in the energy sector fascinating. “Up to now, we all get our energy through a utility – a retailer. How do we know we will have these retailers in five years? Or will there simply be a platform where I log on and receive my contract?

“This is what we are really working on: to understand this change and manage it. It is so interesting to me: we can define it and design it.”

And she stresses: “It’s not an area where only start-ups should be active. We team up with our customers. Because if they don’t move, they may be out of the market in five to ten years.”

The democratisation of digital

Laura Anderson introduces Stefan Lichtenburger as “all things AI”.

He says what has changed over the last five years is “the democratisation of digital technologies and their methods and means: that has exposed many people to digital technologies”.

He adds: “What is going on now is more like a consolidation – not in terms of technology, but in terms of how to use it: how to make it applicable; how you foster business cases and make best use of digital technologies for people and for business.

“And that runs into the trend of decarbonisation. Together, they will provide us with new ideas, new business models and cases that will be normal in five years – and yet we have not even thought of them now.”

The post Digital transformation – Big data, big thinking appeared first on Power Engineering International.

Electrostatic Precipitator (ESP) is one of the most common and important pollution control devices that removes suspended particulates (dust) from the flue gas in coal-fired power stations. For many old power stations built in the 1980s ~ 1990s, their ESPs were designed with dust collection efficiency of 98% ~ 99.5% and outlet emission at 25mg/ Nm³ ~ 200mg/Nm³, in compliance with emission regulation at the time.

Nevertheless, after more than three decades, air pollution regulations have become more stringent while ESP internal parts have also deteriorated over decades of long operation. The existing ESP dust collection efficiency is no longer sufficient and so major upgrade improvement is required.

Upgrade Strategy

There are 2 common strategies in upgrading ESP dust collection efficiency; one is to increase the dust collecting area, the other is to increase the strength of electrical fields inside the ESP.

While the former requires either additional fields or ESP structure modification that demand space availability, long outage time and are cost consuming, the latter can be achieved by retrofitting Discharge Electrode (DE) to Rigid Discharge Electrodes (RDE) and upgrading a conventional transformer rectifier (T/R) unit to a Switch Mode Power Supply (SMPS) unit, which is more cost effective and can be completed within the time-constraint annual shutdown period.

By optimising the strength of electrical field to the most extent, ESP outlet emission can be reduced to as low as under 10mg/Nm3.

Case Study: Coal-Fired Power Plant, Taichung, Taiwan

Taichung Power Plant is one of the largest power stations in the world, built for a generation capacity of 5,500 MW, accounting for 15% of total power generation in Taiwan. There is a total of 10 ESP units, with unit 1 through unit 8 of identical design. Commissioned in the 1990s, ESP units were designed for outlet emission of 28mg/Nm³ with 99.29% dust collection efficiency.

Being the largest among the state-owned power stations, it serves as a paradigm of dedication to continuous improvement in environmental protection. Thus, the objective led to the launch of the ESP efficiency upgrade project to reduce emission and respond to more stringent emission regulation.

Each ESP consists of 4 chambers with 6 fields per chamber, forming a 4*6 matrix. Based on the theory that the first and second fields collect 90% of the particulate matter and an actual series of performance test carried out beforehand, full operating conditions were established including but not limited to electrical readings, fuel type, gas volume and temperature.

The ESP upgrade project had then been concluded to retrofit the original serrated type DE (also called saw band type) in the first and second fields (phase I) to RDE (total 8 fields) and replace conventional T/R unit by SMPS unit.

The pilot project was first executed on unit 6, followed by unit 5, 7, and 8, respectively during successive scheduled shutdown periods. Each unit took around 52 days with 2 cranes working in parallel in both chambers to complete. The results of the performance test showed the project was a success, meeting not only environmental standards but also customer expectations.

Benefits of an Upgrade

RDEs are break-resistant and much more durable than serrated type DE. Its spikes and main body are integrally fabricated from a single piece of steel plate (jointless); therefore, after an operation covering an appreciable time, the RDEs are usually found with spikes intact and deformation-free. The aggressive spike design also generates a higher corona current with a lower onset voltage.

SMPS, a 3-phase power source, produces an almost DC waveform, giving a higher field voltage, while its modern electronics precisely detect and respond to any spark/ arc more rapidly and thus minimize the setback time, providing a significant improvement in electrical operating conditions. The combination of RDE retrofit and SMPS upgrade largely enhances the ESP dust collection efficiency in comparison with its original design.

ESP Improvement

The expectations from the upgrade project were to have ESP outlet emission below 15mg/Nm3 at 6% O2 and emission reduction rate of not less than 10%. Before the upgrade, ESP outlet emissions were measured at each unit and the results were: unit 5 at 10.98 mg/Nm³, unit 6 at 19.38 mg/Nm³, unit 7 at 10.4 mg/Nm³, and unit 8 at 10.86 mg/Nm³ at 6% O₂, respectively.

After the upgrade, performance tests were conducted under similar operating conditions i.e. boiler loading at 500MW±10%, while using mixed coal with calorific value and ash content less than ±10% deviation. The results were: unit 5 at 9.77 mg/Nm³, unit 6 at 10.98 mg/Nm³, unit 7 at 9.27 mg/Nm³, and unit 8 at 9.55 mg/Nm³ at 6% O₂, respectively.

In summary, the implementation RDE retrofit and SMPS upgrade combined has been proven to be a preferable technology for ageing ESPs that require dust collection efficiency improvement in terms of cost and time saving and unavailability of space in order to achieve single-digit emission under certain conditions.

Further Challenges

Upon the completion of the above upgrade project, Taichung Power Plant was further stressed by the public and government to reduce the usage of coal. The current coal blending ratio of Australian coal to Indonesian coal was then adjusted from 2:3 to 3:2 in order to maintain the same calorific value needed for the same amount of electricity generation.

Unfortunately, the new formula of coal mixture contains higher ash content and thus inevitably caused higher ESP inlet dust loading. As a consequence, ESP outlet emission on unit 8 increased from 9.55 mg/Nm³ to 11.56 mg/Nm³ from the baseline test results. Therefore, applying the same method of ESP upgrade as abovementioned to the 3rd and 4th fields (phase II) was carried out on unit 8 as a trial project.

Phase II trial project was executed 2 years after phase I upgrade project. The ESP outlet emission was expected to be under 11.5 mg/Nm³ at 6% O_² and an emission reduction rate of not less than 8%. The performance test results showed that the emission had again been successfully reduced from 11.56 mg/Nm³ to 9.47 mg/Nm³ with 18.1% reduction. Since phase II upgrade was done in the 3^rd and 4^th fields where finer dust particles were more difficult to collect, SMPS played a vital role in increasing dust collection efficiency while still achieving this remarkable reduction percentage.

Maximising dust collection efficiency of aging ESPs by RDE retrofit and SMPS upgrade has once again been proven to be a feasible and economical approach that ultimately allows power plants to minimise their negative impacts on the environment.

About the authors

Thompson Tsai and Wendy Hsu – Vice President and Project Coordinator of Tai & Chyun Associates Industries, Inc., a provider of optimized solutions of parts and services for Electrostatic Precipitator (ESP) to ensure emission compliance with standard regulations.

Alex Tsai – Maintenance Manager of Taichung Power Station, one of the largest coalfired power plants under a state-owned Taiwan Power Company (Taipower), providing electricity to Taiwan and its off-shore islands.

The post Achieving single-digit emissions in coal-fired power plants appeared first on Power Engineering International.

Many parties consider hydrogen as an important energy carrier for replacing the direct use of coal, oil and natural gas.

Commercial parties such as fuel cell manufacturers see hydrogen as a means to substantially expand their business.

Pipeline operators cherish hydrogen for a future ‘green’ use of their assets. Scientific establishments use the interest for hydrogen as a way to receive grants in research on the matter.

Consequently, many marketeers are strongly lobbying for hydrogen. However, at the same time there are many voices that proclaim a maximum electrification of energy over the use of hydrogen.

Policymakers and citizens hear all these different opinions and it is not easy to distil the facts and ascertain the best way forward.

One might wonder if the moment is already here to use precious renewable electricity for producing hydrogen for a dedicated use or for blending natural gas with it.

Currently, only about 20% of all primary energy supply in Europe is renewable and not even half of that is renewable electricity.

It is true that in Germany renewable electricity production recently exceeded 40% of the total electricity production in that country. However, if the intention is to electrify road and rail transport as much as possible while also moving away from heating of buildings with gas towards using electric heat pumps, much more renewable electric energy is needed.

Renewable electricity is a valuable commodity and it should be used in an optimum way. That is to decrease the greenhouse gas emissions as effectively as possible.

Direct or indirect renewables?

For the heating of buildings, it is possible to use electric energy directly with an electric heat pump or indirectly via the hydrogen route.

For a moderate ambient temperature, an air-to-air electric heat pump needs 1 kWh of electricity to produce 3.5 kWh of heat. One might argue that this does not apply to very low ambient temperatures, but such a situation occurs only a small fraction of the time in the moderate climates of the EU.

Via the hydrogen-based heating route, where electrolysis has to produce the hydrogen and a boiler has to burn the hydrogen, the effectiveness of the renewable electricity is a factor of almost six lower than a direct use.

Hydrogen supporters claim that a coefficient of performance (COP) of 3.5 is only possible in cases of well insulated homes with low temperature heating.

However, equipping newly built homes and well insulated buildings with heat pumps will already substantially increase the demand for electricity. Consequently, in the short and mid term, there is no real ‘excess’ renewable electricity available for producing high amounts of hydrogen for home heating.

A direct use of electricity with heating coils is even more efficient than heating via the hydrogen route. Natural gas and biomethane can be used for heating homes that still require high-temperature heating.

It is nevertheless a fact that the consumption of natural gas for heating will gradually decrease because of the application of heat pumps and improved insulation.

For road transport, the direct use of electricity is also much more effective in combating greenhouse gas emissions than via the hydrogen route.

If a train receives the electricity for its motors from a catenary system, the effectiveness of the electric energy is more than a factor three higher than via the hydrogen route.

In case of the hydrogen route, the electric energy has to be used for producing hydrogen and then a fuel cell has to convert the hydrogen back into electric energy for driving the motors.

The same comparison can be made for road transport, although the use of batteries slightly reduces the total efficiency. This would result in a factor 2.5 better effectiveness when avoiding the hydrogen route.

If natural gas has to be replaced by hydrogen as a major energy carrier in the near future, an option is to produce it by steam reforming of fossil fuels and capturing the resulting CO2.

The big question is if the required CO2 storage can be realised considering the available space, the security of storage and the opposition of citizens. Pyrolysis is another option, where black carbon is a by-product instead of CO2.

The resulting so-called blue hydrogen might be somewhat cheaper than hydrogen produced by electrolysis. Fossil fuel producers as well as major pipeline companies see reforming and pyrolysis as a possibility for a continuation of using their assets.

Hydrogen blending

Manufacturers of gas turbines, reciprocating engines and boilers can certainly modify their products for running on ‘pure’ hydrogen.

However, one should not ignore the issues arising from the fact that hydrogen is a completely different fuel from natural gas. Its high flame speed and the factor 10 lower minimum required ignition energy compared with natural gas and the tendency to produce more NOx require special attention.

Its volumetric calorific value is about a factor three lower than that of natural gas so that much higher flows are required. The flammability limits of hydrogen are about a factor five wider for hydrogen than for natural gas. Nevertheless, the manufacturers are already exploring and testing the techniques.

A number of gas pipeline operators advocate the blending of natural gas with hydrogen. A main argument is greening of an otherwise fossil fuel.

However, because the volumetric calorific value of hydrogen is about a third of that of natural gas, high fractions of hydrogen are needed in order to be effective for decreasing the specific CO2 production.

Currently, many stake-holders consider 20% of hydrogen in natural gas as a limit for avoiding substantial changes in performance, safety and emissions for the end use.

However, the exact allowed fraction also depends on the base gas in which it is injected. Natural gas with a high content of hydrocarbons higher than methane has a higher reactivity than methane and can therefore accept less hydrogen.

The gas sector cannot guarantee that with hydrogen blending the fraction of hydrogen will stay constant. This tends to substantially widen the range in calorific value and Wobbe Index value of the resulting gas while gas applications can in general only accept a limited variation in gas quality.

Figure 1 shows that in order to reduce the specific CO2 emissions from electricity production by adding hydrogen to natural gas, one needs high volume fractions in order to be effective.

If natural gas contains 10% of hydrogen by volume, the energy contribution of the hydrogen in the gas is only slightly higher than 3% and consequently the specific CO2 emission is only reduced by about 3% provided the fuel efficiency remains the same.

The ‘Taxonomy’ process that is under development in Europe requires a maximum CO2 production of 100 g/kWh for new power generators, with a gradual decrease towards the year 2050.

For such a low specific CO2 emission, one needs to have more than 90% of hydrogen in the gas. Such quantities are not available today, so the only possibility to reach such a low level is by using biomethane. However, that is currently also not available in large quantities.

The fraction of renewable electricity in the total energy supply of Europe is currently, and most probably also in the coming decade, not sufficient for producing hydrogen at a scale required to replace a direct use of natural gas.

Yet, in the longer run, there will certainly be a role for hydrogen in the energy supply.

For the time being, by far the best application of renewable electricity with respect to the reduction of greenhouse gases emissions is by replacing electricity produced with fossil fuel and by providing energy for electric heat pumps and electric vehicles.

Any temporary excess of electricity caused by the volatile character of solar and wind based generation can be used for producing hydrogen for dedicated users, such as the fertiliser industry, blast furnaces and refineries.

The ‘learning process’ for electrolyser development can be done at those dedicated locations. As soon as a dedicated hydrogen ‘backbone’ is functioning in Europe, that system can be used for storing and transporting hydrogen resulting from temporary excess in electricity during sunny and windy days with low electricity demand.

Blending natural gas with variable fractions of hydrogen causes too much uncertainty in the gas quality and would be a temporary solution anyway.

Developing inherently complicated gas supply systems for that and adapting the gas applications for blending destroys the intrinsical robustness of the gas supply system.

A reliable and secure energy supply system is of crucial importance for the economy.

About the author

Dr Jacob Klimstra is a senior researcher and engineer with over 50 years of experience in energy, cogeneration and engine technology.

The post Diving into the hydrogen debate appeared first on Power Engineering International.

Why should we prefer to run engines on hydrogen and its derivates in the future?

The answer is simple and, at the same time, terrifying. The earth has become warmer and warmer than in the past: The average temperature of the last three decades has always been higher than that of all other decades since records began in 1850. This is alarming, and the negative consequences of global warming can already be felt almost everywhere.

Climate protection is hence the central challenge of our time. It is essential to counteract global warming and its consequences now. The focus is on rapidly reducing emissions of greenhouse gases such as carbon dioxide (CO2).

CO2 is released, among others, when fossil fuels such as coal, oil, gas or their derivatives are burned: in industry, in transportation and traffic, for heating and cooling or for power generation. To drastically reduce greenhouse gas emissions, various solutions can and must be pursued.

Renewable energy sources, especially solar and wind energy, will play an increasingly important role in the future. With their help, electricity can be generated.

But regenerative energy sources do not always actually supply energy. For example, when it is dark and there is no wind. Thus, to ensure security of supply, alternatives must be available that do fill the gaps.

This is where internal combustion engines come into play. They can be started quickly and therefore react flexibly to the fluctuating electricity yield from renewables. The combustion engine has proven its robustness and reliability over decades and does not produce any CO2 emissions during the utilization phase itself – it is the traditional fossil fuels that are responsible for CO2 emissions during the use phase.

And this is where renewable energy sources come into play again. There is another reason why they are so important: ‘Green’ hydrogen can be produced by electrolysis of water with electricity from these renewable sources.

Today there is no doubt about green hydrogen being the heart of the energy system of the future because it is CO2-free. It can either be used directly or converted further; for example into eFuels, synthetic fuels that can already power combustion engines in a climate-neutral way.

Thanks to Power-to-X (or P2X, PtX), green electricity in the form of chemical energy carriers can be stored efficiently and for a long time.

In many countries – such as China, Japan, and Korea, but also in France and Germany – governments have long since set the course for future hydrogen use. There is also an ambitious hydrogen strategy at EU level. The hydrogen economy in the US is also likely to grow rapidly, especially now that it appears to have political support. And the US has extensive, low-cost solar and wind energy resources, and plenty of space. For emerging economies that have few energy systems and are just building them, hydrogen will also be important.

The World Energy Council predicts that in the future hydrogen will come primarily from countries such as Saudi Arabia, Chile, or Australia – from regions where wind or sun, and thus potentially renewable energy, are abundant. Countries like Germany, however, will continue to import energy in the future because they consume more energy than they can generate themselves from renewable sources.

The question of transportation has not been conclusively resolved since hydrogen as a gas is best transported by pipeline. For regions like Patagonia for instance, one must also consider conversion steps from hydrogen to, for example, ammonia or hydrocarbons. This is one more good reason to consider the use of eFuels as well. In any case, innovative technologies based on hydrogen offer enormous potential everywhere to successfully defossilize industries.

There are engines already being successfully powered by hydrogen today, but when will engines generally be ready for hydrogen? After all, stationary internal combustion engines are very longlived assets that require high levels of investment from their operators.

Those engines that go into operation today or in the near future will most probably still be powered by conventional fossil fuels. But they must be adaptable to the requirements of a climate-friendly energy supply. This creates investment security and thus a willingness to invest. Moreover, this future security is an important contribution to sustainability. If the engines can be further used without any problems, they do not have to be replaced by new units. This also helps to save valuable resources.

It has to be said that, overall, a hydrogen engine works no differently from any other internal combustion engine. It follows well-known, tried-and-tested principles of energy conversion. Nevertheless, engineers have faced and continue to face countless challenges that must be overcome in order to guarantee outstanding reliability and efficiency when an engine is powered by hydrogen.

Facing these different challenges is ultimately a purely conventional and solvable – but non-trivial – development task. To give a concrete example, all the engine’s components must meet particularly stringent leak-tightness requirements. This is because the molecules of hydrogen are very small. That’s why they can diffuse more easily. In addition, H2 has very poor lubricating properties. A specific solution has to be found for this as well. The constant exchange between developers and designers on the one hand and with users on the other is therefore particularly important and necessary – a fact that directly brings us to the CIMAC Congress where every three years, the large engine industry meets.

CIMAC is the voice of the large engine industry, a leading global non-profit association consisting of members in 27 countries in America, Asia and Europe. The CIMAC Congress is a unique opportunity to keep up to date with what is happening in the internal combustion engine industry. This is where experts from all over the world meet, gather information, discuss with each other, look for solutions and define standards.

Next year in Busan, from 13 to 17 June 2022, the Congress will be held for the 30th time. The overarching theme of climate protection plays a very prominent role at the congress as well as in its Technical Program, where technical, environmental, and regulatory trends, developments, opportunities and challenges are discussed.

There is simply no better place to learn about the latest developments and encouraging results in the large engine industry, including the hydrogen-ready engine. By 2025, the industry believes that – possibly after updates or specific retrofits – newly purchased stationary combustion engines for power and heat generation will be able to burn up to 100% hydrogen. Powered with green hydrogen, they will work without producing CO2.

The post Internal combustion engines go for hydrogen readiness appeared first on Power Engineering International.

At the end of April 2021, the UK government reset its own climate goalposts and pledged to enshrine in law the most ambitious climate change targets in the world, committing to reducing greenhouse gas emissions by 78%.

However, as the UK commits to leading the way on systemic decarbonisation, this ambition is not currently matched by adequate sources of a renewable energy and heat.

Geothermal energy has the potential to significantly contribute to the country’s net-zero goals alongside, of course, a variety of other energy solutions – but currently, its potential as source of both heat and baseload electricity is not being taken advantage of.

It is highly dispatchable, renewable, and capable of sustaining projects for lifespans of over 50 years. With November’s COP26 calling the attention of the world to the UK’s climate action, the country cannot be seen to be wasting, undervaluing, or ignoring the natural resources that can accelerate its plans.

The UK is home to a number of locations suitable for deep geothermal energy drilling, as well as several hundred defunct oil and gas wells that could be modified and converted.

As well as electricity, geothermal energy can provide large quantities of renewable heat from underground to the surface. The heating of homes and district heating is a challenge for decarbonisation, but geothermal heat provides a viable zero-carbon alternative to gas.

Agriculture and other industries can benefit too; for example, the United Downs Deep Geothermal Power Plant in Cornwall is to deliver a rum distillery with zero-carbon heat and power.

Jobs and carbon savings

A recent report from engineering consultants Arup states that by delivering up to 12 deep geothermal projects per year over the next 30 years, the UK could host 360 plants that together would be able to generate between 200 and 400GWh of electricity per year, and up to 15,000GWh of heat.

The benefits of investing in geothermal energy are not restricted to renewable electricity and heat: it is estimated that enough projects would create 10,000 direct jobs and 25,000 indirect jobs, generating £1.5 billion ($2bn) of investment.

These jobs would clearly be concentrated in areas with promising geological conditions such as Northumberland, Durham, Cumbria. Newcastle upon Tyne, Staffordshire, and Cornwall – several of which are areas that the government has pledged to ‘level up’.

The development of 10 to 12 projects over the next five years in these areas would lead to 500 to 500GWh of heat per year, which would supply the equivalent of up to 50,000 homes with investment in the order of £10 million to £15 million ($13.9 – $20.9 million) for each project.

At the same time, the development of these types of projects would lead to a carbon savings of up to 80,000 – 100,000 tonnes, purely through the decarbonisation of district heating.

With or without the government

But growth in UK geothermal projects is expected to continue to proceed too slowly without intervention from the government, such as those that have been used in the Netherlands, Germany, and France to stimulate deep geothermal projects.

In the Netherlands, the number of deep geothermal projects increased from one to 18 over a decade, and now at least 21 exist. Presently, the Dutch government aims to deliver 10 new deep geothermal projects each year by 2025, then 20 per year by 2030, and 25 per year by 2050. This strategy will result in 700 projects over the next 30 years, and the UK has enough resources to deliver projects at a similar rate.

Assistance from the government should take the form of a dedicated deep Geothermal Development Incentive. A heat production incentive dedicated to deep geothermal projects could be structured in a way that it provides assurance to the geothermal market, while providing funding only for projects which successfully generate heat or electricity.

To control the cost of an incentive scheme, the government could limit the use of a Geothermal Development Incentive to the first 30 projects which meet application conditions.

At the same time, the government could review the planning permission requirements for projects and make some minor changes to the Contracts for Difference for geothermal power in the next auction round.

UK market development

Arup’s report into the potential for deep geothermal power in the UK identifies that setting the minima of 50MWe for geothermal projects would improve investor confidence and I agree with that.

If such improvements to the system were made, following an initial ramp-up, the UK could deliver 10 or more projects each year, with a production system consisting of surface heat exchanger with production and reinjection wells connected to the same aquifer.

This growth rate would be expected only to increase over time as markets develop and supply chains mature.

Indeed, once the UK’s geothermal market and sector expertise is developed, there is nothing to stop the country from exporting it and supporting the uptake of the energy resource around the world.

The UK has a long history of innovation in the field of deep geology, and investing in geothermal energy could lead to the UK becoming both a climate action leader and a specialist in the energy resources that lie beneath our feet.

British projects in Cornwall have already pioneered the co-production of lithium from geothermal brine, and other areas of the geothermal supply chain such as specialist equipment and component manufacturing, digital engineering and consulting, financial expertise, and deep geothermal training are fields in which the UK could lead.

The UK has experimented with, and benefitted from, geothermal heat for thousands of years, from the construction of the Roman thermae in Bath around 75AD to the first deep geothermal wells in Cornwall.

But as well as celebrating a rich heritage in ‘hot rocks’, the UK government should be investing in the future of an energy resource that has yet to fulfil its potential.

Decarbonisation is a mission of such scale and urgency that we cannot afford to leave such a rich resource unused.

About the author

Dr Ryan Law is Managing Director of Geothermal Engineering, a team of specialised geologists and engineers who have developed several projects, including the £30 million ($41.7 million) United Downs initiative in Cornwall.

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With high insolation levels, favourable conditions for wind farms and immense availability of land, Australia offers an attractive environment for large utility-scale renewable developments.

Recently, developers have proposed projects to leverage this renewable energy potential to generate and export clean electricity to Southeast Asia, and Singapore in particular, through a subsea High Voltage Direct Current (HVDC) interconnector.

This prospective project requires a unique integrated contracting strategy involving multiple HVDC cable suppliers, marine heavy transport companies and cable installation contractors to be delivered within a sensible timeframe effectively, safely and sustainably.

Although relatively ambitious, a study by global energy consultancy Xodus demonstrated the technical feasibility and quantified the environmental benefits.

It is one of the few credible options to help move the region towards a net zero future and, in the meantime, strengthen its energy security. The tri-party power link model is currently being implemented by the EuroAsia interconnector project 1 between Israel, Cyprus and Greece.

External hazards

To connect Australia to Singapore, Aberdeen-headquartered Xodus identified a potentially suitable marine route estimated to be 3,200km long with three main distinct sections.

The first 400km and last 1,600km, sections A and C respectively in Figure 1, lie in relatively shallow waters, typically 100m to 200m deep, with a flat profile.

Over these sections, the cable would need to be trenched to protect them from external hazards in addition to wave actions and sediment movements.

Conversely, the water depth along section B varies significantly with alternate deep and shallow sections and high gradients. The deepest section is at the Timor Trough and reaches water depths of 1,900m and high slopes.

The structure of the proposed cable includes a central conductor surrounded by an insulation, armouring and external sheath.

Adopting the current technology, the interconnector will most likely be configured in a bipolar mode to offer 2 to 3GW power capacity, using two individual and identical HVDC underwater cables.

In the event of one cable failure, this arrangement allows using the intact cable into monopolar mode with earth return over the repair duration, enabling half of the electricity capacity to be transmitted.

Typical linear weights of these subsea HVDC cables range from 40 kg/m to 60 kg/m with diameters in the order of 150 mm and a capacity exceeding 1GW. It is estimated that the total cable weight of this interconnector (two off 3,200km cables) would reach 300,000 to 400,000 tonnes.

The cable will be transported into basket carousels using heavylift vessels (HLVs) or barges with cable lengths split into manageable sections of about 100-120km long.

Given the route length and variability, it is anticipated that various cable designs will be adopted to meet the diverse requirements.

The cable design features include different conductor materials, insulation technologies and armouring arrangements to account for constraints related to water depth, laying operations, seabed on-bottom stability, and protection against external damage.

The electrical loss through HVDC cable is approximately 3% per 1,000km resulting in a 10% total electrical loss along this interconnector.

Supply, transportation and installation

HVDC cable manufacturing requires specific know-how and capital-intensive power plants with facilities located in areas with well-established logistical infrastructures and marine access facilities.

The location of the HVDC cable suppliers is illustrated in Figure 2 (Surabaya being the midpoint along the marine route).

Most long subsea HVDC interconnector projects executed to date were located within 500 to 1,000km from the HVDC cable manufacturing facilities. This enables the cable lay vessel (CLV) to act as the transport and installation vessel, transiting back and forth from the offshore cable route to the plant for reloading each cable section.

Typical CLV transit durations from Indonesia to Northern Europe, Southern Europe and Northeast Asia were estimated at 37 days, 26 days and 11 days, respectively (one way).

Based on a CLV capacity of 10,000 tonnes (equivalent to approximately 200km of cable), a total of 32 vessel trips will be required to complete the entire interconnector offshore installation scope.

Depending on the number of simultaneous CLVs used for both transportation and installation (assumed one to three vessels) and the various plant locations, the overall cable installation campaign would last between two years (three CLVs and plants in Northeast Asia) and 11 years (one CLV and plants in Northern Europe), continuously.

It was concluded that an integrated approach combining CLVs and a fleet of transport vessels, fitted with high-capacity basket carousels, will most likely be required to achieve an acceptable project delivery duration.

In this situation, the CLVs would remain along the cable route vicinity during the entire installation campaign, whilst transport vessels journey back and forth from manufacturing plants to CLVs to ensure operational continuity and avoid excessive stand-by durations.

Carbon tax and emissions

To fairly estimate the actual net greenhouse gas emissions of this type of project, a carbon lifecycle analysis of the embodied carbon of HVDC cables as well as the carbon emissions related to transportation, installation, operations and decommissioning, were undertaken.

Assuming an interconnector capacity of 2.4GW associated with a 70% factor of charge (with adequate storage capacity, excluded from this assessment), approximately 15TWh per annum of power generated by Singapore-based gas-fired plants can by replaced by clean Australian electricity, which corresponds to about 30% of Singapore’s annual electricity consumption.

The avoided emissions from Singapore’s gas-fired plants were estimated to reach 320 MteCO2e over 50 years – the typical design life of interconnectors. The carbon emissions of a 10GW solar plant coupled with an interconnector were evaluated to 40 MteCO2e, resulting in a net saving of approximately 280 MteCO2e over the course of its service life as described in Table 1.

The cost of utility PV solar has decreased significantly over the past decade and this trend is expected to continue in the short and medium terms.

As of today, the capital expenditure of a 10GW solar farm with an intercontinental power link is estimated at $20 billion with one third of the cost allocated to the subsea interconnector.

It is difficult to predict the carbon tax evolution over the next 50 years and a more refined cost model would be required to estimate the present value of this complex development.

However, if the carbon tax in Singapore, currently set at approximately $4 per tonne of CO2e, is expected to reach $10–20 per tonne of CO2e by 2030, this could result in $3–6 billion savings if 280 MteCO2e are not emitted from gas-fired plants.

This simplistic calculation illustrates that carbon tax savings could, at least partially if not entirely, offset the cost of an intercontinental power link over its design life.

Although relatively ambitious, interconnector projects such as an Australia-Singapore power link are technically feasible and can potentially offer valuable benefits, not only to both exporting and receiving countries, but also to the entire region collectively in the long term.

Most notably, over its 50-year design life, the link can reduce the carbon footprint of a country’s power generation system, traditionally dominated by fossil-fuel, by a few hundred million tonnes of CO2.

Further, projects of this nature will foster renewable energy integration at a continent level and enhance country energy security. Ultimately, increasing climate concerns and carbon tax are likely to create credible business cases for intercontinental power links soon.

ABOUT THE AUTHORS

Jeremy Gordonnat is a Consultant Engineer with Xodus Group. He graduated with a BSc in Mechanical Engineering and MSc in Ocean Engineering, is a Chartered Engineer, member of RINA and Project Management Professional (PMP) certified.

James Hunt is Interconnectors & Cables Lead at Xodus Group. He has a BEng in Mechanical Engineering, an MSc in Physical Oceanography and an MBA. He has 33 years of offshore experience and, in the past 17 years, has been involved in significant projects in the HV power and renewable energy sectors from early-stage feasibility through development, planning, construction and O&M.

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Distribution utility Baltimore Gas and Electric (BG&E) partnered with the Smart Electric Power Alliance plus other stakeholders to develop and execute a microgrid feasibility pilot scheme that would advance carbon reduction and optimise grid management.

The Maryland Energy Administration (MEA) awarded grant funding to the Smart Electric Power Alliance (SEPA), which took the lead in conducting and developing the study, as well as stakeholder engagement.

Jared Leader, Manager of Industry Strategy at the SEPA, explained that utilities are increasingly exploring microgrid solutions because the rising cost and frequency of weather disasters have emphasized resilience as a key driver for evaluating planning processes.

In order to roll out microgrids successfully, Leader said: “We want to get under the hood of microgrid planning processes, by building out a template that can be used in future project planning.”

Learning in the field

The Newtowne Twenty affordable housing complex in the city of Annapolis in Maryland is a 78-unit development currently undergoing revitalization and is considered vulnerable.

Local stakeholders and the utility were interested in assessing the feasibility of adding a microgrid to the development, which would introduce locally-generated solar energy and increase resilience.

Jennifer Adams, director of development and modernization at Housing Authority of the City of Annapolis (HACA), explained: “At the Newtowne Twenty property, we shape the services and appliances that use the energy and administer a utility allowance process to ensure utility costs remain affordable.

“We wanted to explore ways to provide reliable and affordable energy to our customers and frankly, it was exciting to be an innovator in a space where the public housing authority is often the last to come to the table.”

After the conceptual phase, the housing authority, SEPA and BG&E conducted an engineering analysis to understand the site in detail and determine what was next.

Leader said: “SEPA had the opportunity to pull together all the stakeholders, leverage grant funding, and come up with an idea of what success looks like for a project like this. We engaged stakeholders, agreed on best practices and developed scenarios to aid planning.”

Practical working groups were developed to allow the team to understand community needs and consider innovative approaches to meet them.

Justin Felt, manager of strategic planning at BG&E, highlighted that the important first step was to reach a consensus on how to tackle the project site, by looking at physical constraints in terms of size and location.

Engaging stakeholders

Even though there is no single template for microgrid projects, there can be a boilerplate process, standardised to increase success.

Throughout the Newtowne Twenty development planning process, lessons were learned on how to go about engaging the community to encourage buy-in and ensure the project meets core needs.

Felt said that BG&E’s role in the project was to provide engineering and data analysis. “BG&E, as a local distribution utility, saw this as an opportunity to build internal competency beyond the buckets we typically find ourselves involved in. This was a learning and listening opportunity.

“BGE learned that the stakeholder engagement process is important. You want people to support the process. It’s one thing for an analyst to come up with something in a basement but it’s another thing to see what the people involved actually want.”

A stakeholder engagement questionnaire was vital to get to the root community needs and prioritize them, and the questionnaire also proved to be the ultimate tool to form the microgrid design.

Engaging with stakeholders through the questionnaire allowed the team to learn that customers wanted as much bang for their buck as possible. “So looking at a natural gas generator was more feasible than a renewables-only microgrid,” said Felt.

“Also, backup power for the community centre was not necessarily a priority at first. We had preconceptions, but we wanted to hear from them. It taught us more about learning to listen.”

The residents and stakeholders were given details about the various design scenarios and the potential impact. “We surveyed the stakeholders through a working group to understand their preferences. Based on these preferences, we chose a final scenario,” explained Leader.

And Felt added: “You have to boil it down to the most important information when communicating with stakeholders. We tried to find ways to ensure easy decision-making. We also included outside companies to advise on the engineering nitty-gritty, allowing the key stakeholders to make decisions with ease.”

All scenarios were considered from the perspective of the physical landscape and from a wiring perspective.

The scenario that seemed the best fit for Newtowne was rooftop solar PV, energy storage and natural gas backup standby generation connected to the BG&E grid.

However, in terms of natural gas generation, the generators had to be kept away from pedestrian areas, minimising noise and maximising visual shielding.

As for solar, the team considered carports but eventually decided on rooftop PV for the best insulation, maximising the balance between cost and benefit.

According to Adams, the final microgrid design considered cost, but the most important factor was resilience. Historically, the older buildings experienced frequent power outages which made the ability to island favourable to the community.

“The final design scenario reflects the diversity of the stakeholders involved. When considering cost, having 100% renewable wasn’t the primary consideration. Why wouldn’t you want that kind of resiliency in your house or community centre?”

Blueprint material

However, the project presented some key challenges: the planning process had to adjust to the conditions on the ground, especially as it was a re-build housing project. Adams also feels the planning process would have been less challenging if it had been started earlier.

However, the lessons learned have given rise to a blueprint that can be used in future projects, ensuring every voice is incorporated and every customer is served in the most energy-efficient, resilient way.

According to Leader, this is a perfect example of an energy project that can really advance the equity, environmental and social justice goals within communities, as well as resiliency needs and sustainable energy to populations that have historically been left out.

It’s still nascent, and utilities are still grappling with what microgrids are and what their role should be. This was an interesting pilot to demonstrate BGE and HACA’s role and their strategy in working together on projects like this in the future.

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Read the full, mobile-friendly digimag

The human touch of digitalisation

Digitalisation has changed the face of power generation engineering – and will continue to do so for the foreseeable future.

Science fiction has become engineering for many now widely adopted practices and the next decade will offer more game-changing breakthroughs. And all of this requires energy companies to adapt and evolve with these changes, reskilling existing workforces and developing training modules for the next generation.

Of course, there are aspects of engineering that are instinctive and based on human senses: an engineer can know something is right or wrong with a piece of machinery simply by the hum of its engine. How do you build a piece of artificial intelligence that could do the same?

That’s one of the big questions facing the people developing energy’s digital highway – people like Laura Anderson of Siemens Energy. Which is why I sat down with her to explore the past, present and future of the power sector’s digital transformation.

She highlights how automation came to the fore during the pandemic and how AI and blockchain are offering innovative solutions to pressing climate issues.

Elsewhere in this issue, Dr Jacob Klimstra gets behind the hype to examine what is realistically the optimum use of hydrogen in conjunction with renewables.

We also explore the untapped potential of geothermal energy that is, literally, beneath our feet; and we discover what it would take to build a subsea link that would transport Australia’s considerable renewable energy electricity resources to Singapore. And we spotlight an affordable housing project in the US that is proving to be a blueprint for success for microgrid deployment.

I hope you enjoy this issue.

Kelvin Ross
Editor, Power Engineering International

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