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Let’s talk about gas

If the future of energy is decarbonised and largely electrified, where does that leave gas?

Isolated and yesterday’s fuel source? Or the bridging fuel that enables a green future?

The answer is the latter, of course, and it’s a reality that the energy sector has come to accept and adopt in recent years as it takes a holistic, collaborative approach to achieving climate goals.

This issue of PEi examines various aspects of the gas sector. We look at renewable natural gas: what it means, how we get it and what we do with it. Its potential is significant, particularly for sectors such as industrial and manufacturing which are a major contributor to carbon emissions. Yet there are barriers concerning both innovation and investment. We highlight how these can be overcome.

The buzz around hydrogen has created a lifeline for the power generation assets of gas turbine and engine manufacturers. How are they responding? We check out some of the prime movers in this space, including those that are future-proofing themselves via acquisitions of fuel cell companies.

Yet let’s not forget that gas turbine plants remain the backbone of today’s energy sector in countries around the world, and their operators are still striving for even the smallest percentage efficiency increase. So in this issue we also examine the ever-important issue that filtration plays in delivering optimal performance.

Elsewhere, we take a deep dive into an innovative technology that presents the possibility of repurposing coal-fired plants for energy storage; delve into some of the projects that are bringing solar power to emerging markets; and profile a company delivering electricity ship-to-shore by utilising floating power plant vessels.

I, and the rest of the PEi editorial team, hope you enjoy this issue.

Kelvin Ross
Editor, Power Engineering International

The post Power Engineering International Issue 2 2021 appeared first on Power Engineering International.

We started Karpowership because we believe in universal access to energy ” we believe that everyone in the world should have electricity.

Thisà‚ articleà‚ wasà‚ originallyà‚ publishedà‚ inà‚ Power Engineering International Issue 2-2021.

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“A family should never have to wonder if they will have enough money for diesel. The cost of electricity should not be a consideration in a family’s budget ” it’s a basic human right.”

So says Zeynep Harezi, managing director of Turkish firm Karpowership, which offers ship-based power generation on a rental basis.

Powerships are ship or barge-mounted, fully-integrated floating power plants. With wide ranges of installed capacities for utility size operations and no completion or construction risk, the powerships are ready for generation within a short period of time.

Power is fed directly into the transmission network from an onboard high-voltage substation, and therefore requires no land acquisition.

Powerships were initially developed by General Electric during World War II as a transportable large-scale power generation resource. Floating power has come a long way since ” and so too has the ever-increasing need for energy access.

Governments around the world are committing to electrification programmes that enable economic development and improve the lives of their citizens. One company answering the call for energy supply is Karpowership.

The company provides up to 4300MW of electricity internationally by burning liquid natural gas in on-board power generators. Its ships have been deployed to Lebanon, Iraq, Cuba, Sierra Leone, Senegal, Sudan, Gambia, Ghana, Guinea-Bissau, Indonesia, Zambia and Mozambique.

The ships dock in the harbour, crank up their turbines and start generating electricity for customers on land. “And of course, the more electricity, the more jobs, education and foreign direct investment opportunities will come, and increase social and economic welfare and gender rights,” says Harezi. “Electricity impacts everything about well-being and happiness. We are passionate about this.”

How it works

In order for the powership to function, a floating storage regasification unit (FSRU) is moored and connected to the ship via a floating gas pipeline.

The mooring solution allows for ship to ship transfer through cryogenic hoses at -163 degrees Celcius. The FSRU gas cargo tanker, with a capacity of up to 150,000m3, receives gas from an LNG carrier.

The FSRU contains a Regas vapouriser with a capacity of 21-168MMSCFD, an LNG feed pump 50-200m3/h and a 6000kg/h bog compressor. The gas send-out pressure from the FSRU ship is up to 40barg.

The gas is moved through the regasification system and passed to the powership where it generates electricity. The transformers send the power the ships generate over wires to local transmission grids, and from there it goes out to end users.

A variety of powerships meet differing power requirements. The classes range from the smallest, Mermaid, which has a maximum capacity of 80MW and is 90m long and 25m wide, to the Khan class which has a capacity of 470MW and is 300m long and 50m wide.

Karpowership’s vessels only require a depth of five meters (16 feet) to operate at ports, which makes them suitable for multi-island countries that have long coastlines.

The ships can be installed at a coastal site where there is an available substation for electrical connection and suitable marine conditions for berthing or mooring.

Host locations require minimal onshore infrastructure and are ready to commence once Karpowership receives the go-ahead to deliver the powerships. The ship is literally turnkey, with construction works including a transmission interconnection point, a small site office and stores adjacent to the powership.

One example of a project location is Indonesia. In 2015 and 2016, Karpowership signed five contracts with the state utility PT PLN (Persero) to deploy five powerships of 1000MW in total for a period of five years. The ships have been in operation since 2016, with one operating on indigenous gas since 2018.

Unfortunately, powerships are not always seen as the holy grail of power solutions.

Many argue that use local independent power producers would likely reduce the cost of power generation and would develop the local power market. Localisation is an important factor when considering any infrastructure development plan. However, the countries that opt for this solution simply do not have the capacity to build and operate this type and scale of technology.

In many instances, Karpowership has worked with the local utilities to help stabilise the grid, for example through helping finance transmission lines.

But who carries the additional cost of the power? This would surely be carried over to the utility customers, ultimately impacting economic development negatively, which runs contrary to Karpowerships goals. This would only be the case if the ship’s power was more expensive, which is seldom the case when comparing the cost of gas and diesel.

Harezi says: “On a 25-year PPA, we are cheaper than any other land-based power plant. It’s cheaper for us to build and operate the ships. We standardise design, purchase parts in bulk and build several ships at a time. We build in a controlled environment without unforeseen costs. It’s actually extremely economical.”

Another question is whether a long-term PPA is really necessary, when a short-term contract to provide emergency power is all that’s needed.

There is no doubt powerships can play a vital role for countries that are war-torn or going through economic struggles. The question is, do you rely on outside sources of power, or develop your own to become self-sufficient?

You can’t have both, as at some point supply will outweigh demand and asset will be stranded and will stand idle.

The problem seems to be systemic in nature, occurring within the country itself. The countries being supplied seem to be unable to develop the infrastructure required to supply demand. Therefore, powerships answer the need for delivering power where it’s needed and quickly.

Assessments of cumulative air pollution impacts have raised concerns, and climate and environmental justice groups are concerned that the use of gas locks a country into continued use of fossil fuels and rising greenhouse gas emissions.

Harezi explains: “In 2010, the first round of ships that went to Iraq operated on liquid fuel. Then we realised the world was moving in an environmentally friendly direction and we wanted to be a part of this. All ships after this were therefore built with dual fuel engines to allow for cleaner fuel options.

“The modularity of the powership really helps us to reduce emissions. For example, in the case of a Ghana project, we were able to take the ship to the gas source ” as opposed to the Ghanaians pumping the gas 300km to the ship ” thus reducing the carbon footprint of the project. Flexibility also supports the immediate switch to gas and our aim to convert the whole fleet to LNG in the next 3-5 years.”

She adds that the company wants to “improve our renewable portfolio. Currently we have solar projects in Turkey and Ukraine but we want to build more global coverage of solar and battery storage applications as well.”

One of the main challenges to Karpowership is that of third party risk, especially as countries which need the power most are often those struggling the most financially.

Also, according to Harezi, “there is a psychological barrier that needs to be broken. People tend to think the powerships are temporary and must be more expensive because they’re on ships. On the contrary, the physical and economic lifetime of ship is more than 25 years and we can provide really low cost power.”

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Legislative pushes toward an ambitious green economy and sustainability measures are being supported by cost reductions and technological milestones, unlocking huge decarbonisation opportunities driving the energy transition.

Thisà‚ articleà‚ wasà‚ originallyà‚ publishedà‚ inà‚ Power Engineering International Issue 2-2021.

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Operational small or mid-sized power plants running on high hydrogen content gaseous fuels are not uncommon. These include coke oven gas, byproduct gases from chemical processes, or renewable sources like wood gasification in syngas.

Although some decarbonisation strategies focus on renewable technologies supported by energy storage and demand flexibility, others deploy low carbon resources such as nuclear, hydro, geothermal, bioenergy, and carbon capture to achieve emissions targets.

As customer needs have evolved, so has the adoption of distributed energy resources ” they are set to accelerate at a compound annual growth rate of 10.3% until 2030 ” and clean technology resources across residential, commercial, and industrial consumers, which has blurred the demarcation between producers and consumers.

There continues to be a debate on the role of electrification (from mobility to buildings to industrial production) in the global decarbonisation journey.

Given the diversity of electrification and decarbonisation policies and agendas across global markets, different technology mixes are expected to evolve to support local needs.

On one hand, electrification is likely going to be a critical enabler in decarbonising the global energy ecosystem. But regional fuel prices and capital costs of equipment and installation are particularly strong determinants of economic competitiveness for electrified technologies.

On the other hand, decarbonisation can also be achieved by integrating alternative fuels such as renewable natural gas (RNG) produced from sustainable waste and landfills into existing infrastructure and gas pipelines.

The natural gas system has an important ability to support resiliency power needs through its inherent physical and operational capabilities, which enable it to meet the volatile power profiles resulting from imbalance.

Investors and corporations are setting ambitious targets for emissions reductions and assessing their supply chains’ resiliency and associated infrastructure costs. Resiliency and responsiveness are extremely critical to ensuring that energy providers can meet seasonal and peak customer needs.

Decarbonisation of gas can be achieved by blending RNG into existing infrastructure to support decarbonisation of the value chain.

RNG can be biomethane or biogas produced from biomass or hydrogen produced from renewable energy through the electrolysis processes.

However, the RNG market is still challenged by cost efficiency and availability of feedstocks. Biomethane and hydrogen are still produced in limited quantities across key regions and need to be scaled up to justify the economics.

Supportive policies and subsidy schemes will likely play an important role across electricity and gas decarbonisation.

So what are the main opportunities for the decarbonisation of natural gas? Let me highlight four of them:

Power sector decarbonisation

Burning renewable hydrogen in gas turbines for power generation can unlock decarbonisation opportunities across the energy sector.

Natural gas turbines and renewable energy sources can be substituted across baseload generations that emit higher carbon. As investment in renewable energy generation increases, new grid services are required to ensure that these resources can be integrated effectively and that the overall operation of the grid is as efficient as possible.

Based on Guidehouse Insights estimates, 520GW of centralised and distributed generation technologies are going to be annually installed in 2030, of which 400GW or 75% is expected to come from renewable energy sources.

Excess renewable energy can be used to create renewable hydrogen that can be used in gas turbines and stored for application in the industrial and manufacturing sectors.

Industrial decarbonisation

Natural gas contributes to almost 30% of the energy used in the industry. The industrial sector presents increasing opportunities for transitioning to a low carbon fuel mix.

However, this transition requires active investment and innovations across the usage of alternatives such as hydrogen and electrification in steel, cement, and chemical production; low carbon options across industrial feedstocks; value chain efficiency; and innovations in high temperature heat processes to bring in economies of scale.

Regulatory changes and economic incentives around carbon pricing and infrastructural investments across a sustainable value chain, carbon capture and storage, and electricity grids are anticipated to aid decarbonisation efforts across the industrial sector.

Building efficiency and decarbonisation

The transportation of RNG to buildings requires investments in infrastructure and technology.

Energy providers need to evaluate the economics of electrification and decarbonisation alternatives, such as new efficient heat pumps and variable refrigerant flow systems.

Building electrification technologies are rapidly becoming more cost-effective and reliable than fossil fuel systems in a variety of planning scenarios and climatic conditions.

Regulatory developments also stress decarbonisation and therefore favour full electrification as a low emissions building approach.

Although headwinds prevail, full electrification faces high transaction costs, low consumer awareness, lack of regional stock availability, and other barriers.

Fleet decarbonisation

In the mobility sector, both battery EVs and fuel cell vehicles are ramping up their business cases to achieve net zero emissions.

Although momentum for plug-in EVs is strong, the technology is not yet technically or commercially ready to displace internal combustion engines in all road vehicle classes and geographies.

There are other solutions and strategies that can fill the gap; such as advanced biofuels, hydrogen, drive automation and networking technologies, and mode switching.

The mobility sector is witnessing a strong push towards zero emissions vehicles such as battery EVs or fuel cell trucks and zero or low carbon fuels such as renewable electricity, biomethane, and other biofuels.

Many of these solutions are immature and complicated to deploy, but leading suppliers are finding innovative ways to deploy and use these technologies. Suppliers that are slower to act risk losing business to innovative suppliers or more emissions efficient modes such as rail.

To conclude: Applications of decarbonisation and electrification need to percolate across the mobility, buildings, heating, industrial, and power generation sectors.

Although clean energy plans have begun to take shape across countries and regions, the availability of RNG, energy efficiency measures, and low carbon sources varies considerably around the world. Power generation along with the industrial sector could be a key segment to ramp up decarbonisation plans.

Ramping up carbon accounting, monitoring, and reporting methods will also be essential to assess progress and milestones across the decarbonisation journey.

ABOUT THE AUTHOR
Pritil Gunjan is Associate Director of Energy at Guidehouse
Insights.

Pritil Gunjan also spoke to Nigel Blackaby about flexibility in
all its guises and the role it plays in grid stability. Listen to the
interview on www.enlit-europe.com/365

The post What next for natural gas? appeared first on Power Engineering International.

As the energy sector transitions to a more carbon-neutral and flexible system of interconnected distributed energy solutions, what role will gas play in the future?

Thisà‚ articleà‚ wasà‚ originallyà‚ publishedà‚ inà‚ Power Engineering International Issue 2-2021.

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Indeed, will it have a role? Do technology developers who have built their entire or a significant portion of their generating product portfolio around gas need to weigh their future options carefully, lest they encounter lack of market demand and stranded asset prospects.

Already examples abound of industry players taking steps to hedge against such a reality.

Siemens Energy has announced its roadmap to strengthen the hydrogen capability across its gas turbine models (ranging from 4MW to 500+MW) to at least 20% by 2020, and 100% by 2030.

Like many other gas turbine OEMs, the company has placed its bets on hydrogen as a lifeline for gas-based power generation assets as the world shifts away from fossil fuels and stricter emission regulations come into force.

Wärtsilä, a major reciprocating engine player, is allocating R&D efforts into developing the combustion process in its gas engines to enable them to burn 100% hydrogen fuel, as well as explore other renewable fuels. Wärtsilä engines are already capable of combusting 100% synthetic carbon-neutral methane and methanol.

In 2013, MAN Energy Solutions commissioned a methanation reactor to produce syngas for a power-to-gas plant on a 6MW scale for Audi AG, a car manufacturer. Since then, MAN has offered turnkey offerings around power-to-X technologies.

MAN has also recently acquired H-TEC Systems, an electrolysis technology company, and aims to cover all processing steps of the hydrogen economy under the umbrella of MAN Energy Solutions.

INNIO, a provider of established Jenbacher and Waukesha reciprocating engines, is a new entity ” carved out of GE with the purchase of GE’s distributed power business by Advent International.

INNIO has developed a new 1MW engine which can run with a mix of natural gas and hydrogen, up to 100% hydrogen. The engine has now passed all tests to be commercialised, with its first pilot installation in Hamburg commissioned in 2020.

Cummins, a major player in power, has recently acquired a fuel cell and hydrogen production technologies provider Hydrogenics Corporation.

Cummins has outlined its plans to generate electrolyser revenues of at least $400 million in 2025. Investments have also been poured into developing hydrogenready products. For example, Cummins received $3 million in funding in 2020 from the US Department of Energy for R&D in their C&I scale fuel cells.

Why hydrogen? And what type?

Operational small or mid-sized power plants running on high hydrogen content gaseous fuels is not uncommon. These include coke oven gas, byproduct gases from chemical processes, or renewable sources like wood gasification in syngas.

But it is a specific type of hydrogen that has got industry talking: green hydrogen. ‘Clean’ hydrogen is labelled either blue or green depending on the process used to produce it; green H2 is produced by electrolysis of water using renewable electricity, while blue H2 is natural gas derived and relies on the coupling of steam methane reforming (SMR) and carbon capture and storage (CCS).

There’s also grey H2 which is similar to blue H2, but the CO2 is not captured and is instead released into the atmosphere.

While green H2 represents a means to decouple hydrogen and natural gas, it cannot yet be produced at sufficient scale for widespread use.

Hence, in the short term, we expect hydrogen in various forms to still play a part in establishing large-scale hydrogen production and demonstrate the decarbonisation of several sectors. In the mid- to long-term, green H2 is needed to meet climate goals.

One of the arguments for hydrogen-based flexible power generation assets is based around the recognition that intermittent renewables play a key part in the energy system ” and this will increase, as will battery storage.

However, to de-risk situations where a long-term storage solution is needed during prolonged low wind and solar weather conditions, a seasonal and large gas storage solution is useful once the smaller battery storage is fully drained.

There are several notable case studies of hydrogen-based power generation. HYFLEXPOWER in France is the world’s first industrial-scale integrated Power-to-X-to-Power hydrogen gas turbine demonstrator.

Consortium members include Engie Solutions, Siemens, Centrax, Arttic, German Aerospace Center (DLR) and four European universities.

The aim is to demonstrate that green H2 can be produced and stored from renewable electricity and then added (with up to 100%) to the natural gas currently used within the 12MW CHP plant at the Smurfit Kappa site. During periods of high demand, this stored green H2 will then be used to generate electrical energy to be fed into the grid.

INNIO’s 1MW hydrogen CHP project in Hamburg includes the hydrogen-ready Jenbacher engine system. The heat generated will be fed into HanseWerk AG’s local heating network, while electricity will be used for recharging electric vehicles at the site when required. The intention was to bring the CHP plant online for natural gas operation in 2020; hydrogen-powered generation would then commence in 2021.

Power-to-X-to-Power in Hassfurt, Germany (1.25 MWe) sees Stadtwerke Hassfurt, a German local utility, partnering with 2G, a CHP developer, to use hydrogen converted from wind power with an electrolyser to fuel a CHP plant.

In the plant, the hydrogen is then converted back to electricity or heat with efficiencies of over 85% as needed. The electricity from the CHP plant is fed into the city’s electricity grid. The unit began operation in July 2019.

Australia is home to hydrogen fuel cell projects. In central Queensland, there are now several hydrogen energy projects in the pipeline. The Australian company Northern Oil was set to build the first hydrogen fuel cell of its kind in Queensland at its pilot biofuels refinery in Gladstone in 2019. The state government has also been in talks with Japanese experts about building a solar-to-hydrogen plant in central Queensland that would export hydrogen gas out of Gladstone’s port. Northern Oil will use hydrogen to generate electricity, but in a novel way ” turning waste products such as old tyres and weeds into a renewable version of a traditional fossil fuel. It needs hydrogen to do this, and until now it has been buying it on the open market, but that is expensive.

At Vattenfall’s Magnum power plant in Groningen in the Netherlands, Mitsubishi Hitachi Power Systems is working to turn the owner’s ‘Carbon-Free Gas Power’ project into a reality, starting with operationalising one of the three gas turbines to combust only hydrogen by 2024.

The hydrogen needed will be produced by reforming Norwegian natural gas, and the resulting CO2 from that process will be captured and stored in natural caverns.

The largest industrial hydrogen fuel cell power plant in the world ” and the first to use only hydrogen recycled from petrochemical manufacturing ” has just become operational at the Daesan Industrial Complex in Seosan, South Korea.

The 50MW plant contains 114 fuel cells. This is against a policy backdrop of the South Korean Government’s roadmap to revitalise the hydrogen economy within car and fuel cell sectors.

So, be it gas turbine or engine or fuel cells, there are many demonstrators and projects underway. And we only expect more to come.

ABOUT THE AUTHOR
Dina Darshini is Principal Analyst at research and consulting firm Delta-EE.

The post Future-proofing gas power appeared first on Power Engineering International.

In its World Energy Outlook at the end of 2020, the International Energy Agency said solar PV, driven by continued cost reductions, will become the main driver of renewables growth, setting new records for deployment in each year from 2022 until 2040.

Thisà‚ articleà‚ wasà‚ originallyà‚ publishedà‚ inà‚ Power Engineering International Issue 2-2021.

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IEA executive director Fatih Birol stated that he saw “solar becoming the new king of the world’s electricity markets”, and it’s easy to see why ” the IEA also reported that installed global solar PV capacity had grown 18-fold between 2010 and 2020.

With solar set to become a vital part of the generation mix for governments to meet renewable energy and carbon emissions targets, the growth potential is truly global.

While ‘established’ solar regions such as Europe and North America will continue to lead in terms of technologies, Asia is also a leading force, with countries such as Singapore and South Korea experiencing significant growth.

That said, the drivers for growth are different across established and emerging markets. In established markets, the primary focus is how to use the energy that is generated in the most efficient way possible.

In contrast, in emerging markets, the demand for power is much greater. According to BloombergNEF’s 2020 ‘Climatescope‘ report, emerging markets’ annual generation has spiked 54% over the past decade, while electricity production in developed countries remained nearly flat.

This need for additional energy infrastructure to power economic growth means that renewable sources such as solar are becoming more popular.

As well as providing clean energy, solar also provides greater self-sufficiency, particularly for those countries relying on imports of either power ” for example fossil fuels ” or components. Any solution that maximises local resources is welcome, and solar is often installed to supplement other renewable sources.

For example, Nepal is predominantly dependent on hydropower for its electricity generation and aims to achieve 400MW of renewable energy by 2022.

However, the country also needs an additional 200MW of energy to become selfreliant during the dry season, when its power generation drops due to fall in water levels in the rivers.

In addition, certain areas, including the Province 2 area, cannot develop hydropower projects, but do have abundant sun energy that could be utilised. As such, a number of solar-powered projects are in the pipeline to help bridge the power gap when hydropower is not possible.

Nepal’s largest private solar project was recently commissioned in the Dhalbekar region. This milestone 10MW project will supply renewable power to well-known tourist areas including Janakpuri, as well as help to reduce power cuts thanks to increased stability of supply.

Similarly, in Turkey, the desire for more locally-generated energy is also a key factor in the growth of solar. With Turkey being reliant on imports of natural gas and oil, renewable energy has seen strong growth to increase both stability and security of supply as well as meet carbon reduction targets.

This was the case with a project at the 500MW Aà…Ÿaà„Å¸à„±kalekàƒ¶y hydroelectric plant in southeast Turkey.

Hydropower is one of the primary sources of renewable energy in Turkey; however, during times of drought, generation from hydropower is reduced. Therefore, solar is seen as an important stabiliser for hydropower plants, providing increased capacity during times of low output as it can be easily installed adjacent to hydropower plants to ensure uninterrupted supply.

A major 80MW hybrid solar power plant was commissioned to be located alongside the Aà…Ÿaà„Å¸à„±kalekàƒ¶y plant and this project ” the first and largest of its kind in Turkey ” will provide a total of 127GWh of clean energy per year to Turkey’s national grid and supply renewable energy to approximately one million people.

Growing pains?

However, with growth come challenges. For example, increasing the amount of power generated creates a delicate balancing act ” how to satisfy the demand for energy without compromising grid capacity.

For example, progress in Jordan stalled in January 2019 when the Ministry of Energy and Mineral Resources suspended approvals for large-scale electricity projects, citing the need to conduct studies to assess grid capacity.

At the time, a ministry official acknowledged that the grid had experienced ‘technical challenges’ over its capacity to cope with the increased amount of power being generated.

Similarly, network operators across both established and emerging countries ” including Thailand, Spain, Germany, the Americas, South Africa and Australia ” are setting export power limits to help manage grid stability without compromising on the deployment of renewable technologies like solar.

How can these potential issues be managed to ensure solar is used to its full potential?

Export limitation

Export limitation ” which is mandatory in several countries ” means that any solar plant needs to have an active power control to meet the requirements set by network operators and ensure stability of the local grid.

For example, in Australia, the electricity system consists of several independent synchronous zones, the largest of which ” the North-South path, which runs along the east coast ” is extremely long with a very narrow transverse.

As such, it is unable to provide the same level of contingency reserves as the meshed systems found in most of Europe and the US. Therefore, the Australian grid code requires mandatory export limitation to maintain the stability of the grid.

In countries with mandatory grid codes, an export limitation controller is required to avoid the power output exceeding the export limit. The controller works by reacting to load fluctuations to keep the power below the limit.

Grid simulation studies

In some countries ” such as Jordan, which faced issues when it came to accommodating large-scale solar projects ” having an accurate grid simulation study is now vital to the commissioning of a project.

Grid simulation modelling creates a digital representation of the inverter ” a ‘digital twin’ ” which enables different scenarios including faults, setpoints and operating conditions to be created virtually without the need for laboratory testing, power sources and all other ‘real life’ equipment, which can be cost-prohibitive to carry out.

This allows for a study of plant behavior during faults, voltage dips and frequency disturbances.

In real life, it would be impossible to test how a plant will respond to an incident such as a grid fault, as this could result in significant damage to not only the inverter, but also the plant as a whole. Thus grid simulation studies are a crucial part of the project planning phase.

A bright solar future

Without doubt, the solar PV industry is one of the most exciting sectors to be working in at the moment.

Falling costs and increasing government incentives and subsidies across several regions mean that demand for solar power ” across all market segments, from utilityscale through to commercial & industrial and residential ” is growing in both established and emerging markets.

However, what is clear is that it is vital to have local knowledge of these markets ” and any possible grid code or power limitations ” to ensure the full potential of solar is realised.

ABOUT THE AUTHOR

Leonardo Botti is managing director of Commercial and Industrial Business at Italy-headquartered solar inverter company FIMER.

The post A fine balancing act appeared first on Power Engineering International.

Gas turbines have reached new heights in efficiency, with the most efficient, such as the H-class, giving power plants net efficiencies of more than 60% when run in combined cycle mode.

Thisà‚ articleà‚ wasà‚ originallyà‚ publishedà‚ inà‚ Power Engineering International Issue 2-2021.

Read the mobile-friendly digimagà‚ orà‚ subscribe to receive a print copy.

This is a marked increase from older versions such as the E-class, which offer efficiency levels in the region of 50%, and F-class at 55%.

Indeed, large-scale H-class gas turbines are more efficient and flexible in operation and, as they generate more power at the highest efficiency, can move power plants up in dispatch order.

They offer fast start-up and ramp rate capabilities; greater turn down, and so more cost effective ‘spinning reserve’; better fuel efficiency, and lower operating costs ” but these supreme levels of efficiency need careful protection if they are to be maintained over the lifetime of the turbine.

The lower efficiency of E-class turbines means changes in aerodynamics have limited impact on performance. To this end, more rudimentary filtration solutions that only protect these rugged units from the damage caused by large particles in the inlet air flow will likely give enough protection for most operators.

It is accepted that the higher efficiency and output capacities of F-class turbines require a somewhat more sophisticated filtration solution to protect performance, life, and power output. The increased efficiency and generating capacity of the more recent H-class or equivalent GTs, however, require a new level and approach to protection to maintain their outstanding levels of performance.

The latest, advanced GT technology achieves high levels of efficiency through more refined modelling of heat transfer, higher firing temperatures and precise ‘super finish’ aerodynamic design.

3D printing techniques allow more elaborate and optimized blades with advanced aerodynamics, new placements of cooling passages, and true 3D profiles.

Other design features include enhanced air cooling flow, improved design of hot gas path components to reduce temperature and stress gradients, and upgraded thermal barrier coatings.

The fine tuning of these machines and the ‘super alloys’ they employ require more rigorous protection from the fouling and damage that finer particulates and contaminates in the inlet air flow can cause.

As advanced GTs also generate significantly more power than previous turbines, even a small compromise in filtration effectiveness comes at a high cost. Focusing in on pressure drop alone, this could equate to 0.4% loss in output over the lifetime of a filter within the system.

For a gas turbine rated at 300MW, this is around $150,000 dollars of lost revenue per year and $255,000 for a 510MW turbine.

On top of this, a sub-optimum filtration solution leaves the compressor more likely to be fouled, thereby reducing power output as contaminants in the air flow adhere to turbine blades and altering the aerodynamics of the turbine.

Having the right filtration solution means performance can be better maintained, the frequency of offline washes reduced, maintenance costs lowered, availability improved, and profitability optimized, all of which give a clear return on investment.

Considerations for advanced GTs

For high efficiency gas turbine, inlet health starts at the inlet house. No two plant installations are identical and filtration design should take into consideration all local environmental factors.

Is the installation near to the coast? Are there extreme temperatures? Does the area experience high humidity or regular fog events? What are the levels of dust or sand in the area? Are there other industrial settings nearby or building works that may increase dust levels and introduce a particular type of contaminant?

Large gas turbines consume huge volumes of air; and contaminants such as dust, sand and salt can cause fouling, pitting and corrosion to the blades, stators and buckets, decreasing turbine efficiency. Weather conditions including rain, snow, mist, and fog also need to be considered in the filter house design and filter selection.

Larger dust or sand particles can erode the special super alloys, finishes and coatings inside the compressor and turbine ” and may eventually lead to severe machine damage. They can also plug cooling holes, leading to melting or distortion of hot section components.

Finer dust particles and other types of contaminant stick to blades, affect operating aerodynamics, reduce efficiency and therefore increase operational costs. The hygroscopic nature of salt makes it particularly challenging because it can quickly move between dry, sticky and liquid forms.

As well as adhering to blades and affecting efficiency, chloride in salt can start pitting corrosion in compressor blades. The sodium in salt can combine with sulphur in fuel in the hot section of the turbine to form sodium sulphate, which causes accelerated corrosion and ultimately catastrophic failure of very costly hot section components.

As particles build up on the compressor blades, the reduction in output power and increase in heat rate mean an offline wash is ultimately required. The more frequently this maintenance procedure is carried out, the greater the cost impact through lost power output, reduced availability, and increased rates of fuel usage.

Moisture is a threat to gas turbine performance as it can comprise of high concentrations of small droplets, such as in the form of fog, that become trapped in fine, high efficiency filtration media, creating sudden rises in pressure drop across the filtration system.

In this and other forms such as rain and mist, it can also combine with dust to form mud and also quickly change the physical state of hygroscopic salt particles from solid to sticky liquid form. All these factors need to be considered in the design of the air intake system.

The different threats to GT performance often require multiple stages of filtration. It is vital, that none of these stages are compromised. Each filter needs to fit perfectly, and work in tandem with the other filter stages to maximise performance.

The filtration system is only as good as its weakest part. A simple change in prefiltration can have measurable implications on a final filter and result in decreased turbine performance.

The example in Figure 1 shows the realworld impact of filter selection and the effect it has on pressure drop.

Fitting the wrong filter results in much faster rises in pressure drop, which will reduce GT runtime, and leads to much greater losses in power output. In an operational time of 8,000 hours (typical change-out period) this example highlights hundreds of thousands of dollars lost in treating filters like commodity items.

A sudden change to pressure drop is far from desirable and can result in GT runback, unplanned turbine outage or even damage to the filter house.

To assist with the planning of operations and maintenance activities, increases to the pressure drop should be slow and predictable.

Individual filters react in varying ways to the effects of weather and differing contaminants and the performance of every filtration stage is crucial to the optimisation of maintenance cycles.

Filters will also require cleaning or changing over time and the frequency of this operation will depend on the filter house design and the filter elements installed and, again, every filtration stage will impact the overheads involved.

Measuring filter performance

Although there are standards to gauge the dry particulate efficiency level of a filter, the only real test is how the turbine performs in the real world, monitoring the level of output and heat rate of the turbine and how this varies over time.

The return on investment of a filtration solution will come from protecting gas turbine efficiency levels, prolonging turbine life, increasing availability and reducing maintenance overheads to minimise the total turbine lifecycle costs.

As the efficiency of gas turbiness reach new levels, the importance of an optimised filtration system is increasingly critical to maintain high turbine performance.

Filters specifically designed to protect these advanced performance machines take more than just lab-tested filter media efficiency into consideration. They are designed to fully optimise lifecycle costs, withstand harsh installation conditions, effectively remove all types of contaminant, and work reliably and predictably to ensure high levels of GT efficiency and availability are maintained.

ABOUT THE AUTHOR
Tim Nicholas is PowerGen Market Manager, Gas Turbine Filtration Division, at Parker Hannifin.

The post Why compromised filters mean compromised gas turbines appeared first on Power Engineering International.

Global energy markets are at the onset of one of their most significant transformations since the invention of electricity.

Thisà‚ articleà‚ wasà‚ originallyà‚ publishedà‚ inà‚ Power Engineering International Issue 2-2021.

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Today, still more than two-thirds of all electric power is generated from fossil fuels, most of it by plants running on some sort of coal.

Conventional power stations, however, face a very certain future of retirements.

Estimates about the total capacity of thermal power plants to be retired over the next 10 to 20 years vary, but are well in the range of thousands of gigawatts.

Concurrently, renewables keep growing at an undiminished pace. Due to their intermittent and mostly non-dispatchable nature, on the other hand, wind and solar power need energy storage systems enabling them to cope with short- and long-term load variations.

Consequently, their continued expansion is triggering a rapid growth of storage capacity realised by both greenfield and brownfield projects.

At E2S Power, we’re developing a storage solution which in time can convert existing coal-fired plants into thermal batteries.

This not only allows reusing existing infrastructure ” it also helps to protect local employment, which is a point of major political concern in many regions worldwide.

The extensive installed base of thermal power plants offers an enormous market opportunity for those who develop conversion solutions. The sheer scale of the required ramp-up of storage capacity will necessitate all storage options on the table to contribute to the challenge ” not one technology or solution will be able to shoulder it alone.

In regions where a large number of coal plants are still in operation, converting those can be a key contributor to providing the storage capacity required.

Giving otherwise stranded assets a second life in the renewable energy future not only has financial benefits to the owners or operators: the continued use of valuable infrastructure also helps to minimise future CO2 emissions associated with the massive build-up of energy storage capacity, where green-field projects may come with a significant carbon footprint.

How it works

E2S Power’s solution basically consists of substituting the boiler with a thermal energy storage system while reusing all of the remaining infrastructure (see Figure 1).

During off-peak hours, the thermal battery is charged with surplus electricity from renewable sources, which is taken from the grid using the existing step-up transformers.

One core technology our solution is built on is a novel composite material called MGA, which was developed and is now manufactured by our Australian partner MGA Thermal Pty Ltd.

Figure 2 illustrates the basic architecture of the E2S storage module ” which we call the ‘Hamster’ ” which contains an assembly of slab-like components consisting of the MGA storage blocks, steam generator plates, and electric radiating heaters.

All components are arranged in an enclosure, which is thermally insulated against the environment and filled with nitrogen for oxidation protection.

During charging, electrical energy powers the radiating heaters, which raise the temperature of the MGA storage blocks to the required level (which may be plant specific).

During the discharge process, heat stored in the MGA blocks is then transferred to the water running through the steam generators, which create steam of just the right properties so that existing steam turbines can use it to generate electricity.

The conversion of heat to electricity thus happens in about the same fashion as if the plant was still powered by coal.

For each individual brownfield case, the system can be tailored so that it makes use of all existing plant infrastructure, which minimizes costs.

It can be operated at the same voltage and current levels as already present at the generators to feed the electric heaters, use the same high-voltage switchyard, the existing steam turbine, and the accompanying balance of plant like condensers, cooling towers, heat sinks, generators, or transformers.

The steam generators of the E2S Hamster are made of advanced high temperature resistant alloys, which can operate at 700à‚°C and are mounted in between the MGA storage blocks.

Electrical heaters are also specially designed to resist temperatures higher than 1000à‚°C to facilitate the heat transfer to the MGA blocks using thermal radiation.

The MGA elements used for storing the thermal energy are special composites made of graphite and aluminium. The metallic component, i.e. the aluminium, has a melting point of around 660à‚°C, which is lower than the maximum system temperature during the charge-discharge cycle.

The latent heat associated with phase change of the metal during operation is the main reason for the very high energy density our storage technology can achieve.

On the other hand, the melting point of graphite, which forms the matrix and which contains the embedded and finely dispersed metal particles, is significantly above the maximum temperatures in the enclosure at all times.

The matrix therefore remains solid throughout operation, keeping the whole MGA slabs in solid form. From a practical standpoint, this feature of MGAs is a key advantage.

In a sense, the MGA technology allows the utilisation of a metallic phase-change material for heat storage at the simplicity and robustness of systems using e.g. steel or concrete as storage elements.

At the same time, it uses a lot less valuable space than those storage media. Steel and concrete would be three times and 20 times, respectively, the volume of an MGA system at the same temperature level and energy content.

A final yet important point is the fact that the use of the abundantly available and non-toxic base materials graphite and aluminium can help alleviate some of the criticism often raised concerning environmental impact, tight supply chains, and recyclability of the materials built into energy storage devices today.

Complementary not competitive

The high melting point of aluminium enables to perfectly tailor the E2S Hamster to existing thermal plants’ infrastructure.

An innovative design of the electric heaters ensures that all existing power electronics equipment in the thermal plant can be utilised without any costly modifications.

Converting an existing thermal plant has modest capital requirements, and projects can be executed swiftly thanks to our modular design, which allows prefabrication of components.

First experiments indicate that the system’s storage capacity will experience very little degradation over time, which minimises the need for major outages over the lifetime of the plant.

After a productive supply chain has been built up, adding hundreds of MWh of capacity per month already seems feasible in the mid-term.

It’s worth pointing out that our solution is largely complementary to ” and not in competition with ” Li-ion batteries. The target application for a converted thermal plant is balancing variations in load and supply over the diurnal cycle or a period of several days.

Given the large spinning masses of steamturbine and generator trains, supporting grid stability is possible too, although during the discharge phase only.

Currently, our first technology demonstrator of approximately 500 kWh thermal storage capacity is being tested in Belgrade, Serbia, with one single E2S Hamster cell of MGA coupled with an electric heater and a steam generator.

The system produces steam of up to 700à‚°C, which subsequently is discharged to a condenser. After completion of the test campaign and any design or process refinements it may suggest, we expect the system to be mature for a mid-scale field prototype.

Discussions are under way with power plant operators, who have a need for augmenting their fossil power plant with a thermal storage system for greater flexibility. Commissioning of the prototype could be as early as 2022, preceding the product rollout for the Hamster in 2023.

ABOUT THE AUTHOR

Dr Carlos Hàƒ¤rtel is director of Marketing & Business Development at E2S Power.

The post Turning coal plants into storage assets appeared first on Power Engineering International.