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    Digitalization

       

    Blockchain: from disruption to new business models

       

    Three blockchain experts from Pöyry explore the potential for blockchain in the energy industry and examine how the blockchain vision translates into the world of energy, utilities and renewables  

                     


     


    Blockchain has the potential to change the business world as we know it today. Entire value chains can be shortened by it – including in the energy industry.

    In the field of renewables, this shift can lead to new business models from peer-to-peer trading to flexibility schemes or investment incentives, to name just a few. Although startups and even classical utilities are increasing their efforts in developing blockchain-based applications and processes, nevertheless the number of scalable case studies is marginal right now and developers have difficulties realizing their promising ideas.

    As a digital transaction system that allows for secure data storage and execution of smart contracts in peer-to-peer networks, blockchain can eliminate the need for intermediaries in transactions. Instead, they are performed peer-to-peer in near real time, as integrity and security are guaranteed by the blockchain.

    From an IT perspective blockchains solve the double spending problem – a phenomenon of the current state of the internet where a copy of each set of data is sent from server to server when information is transferred. For any transaction system this issue needs to be eliminated, which so far has been the job of trusted institutions.

    By taking over this task, blockchains make any intermediary superfluous and are therefore referred to as the Internet of Value – an evolution of the current Internet of Information. A next step might be the application of blockchains in the energy sector as the Internet of Energy, which leads us to the ever-growing startup scene around the technology.

    Blockchain technology gained relevance for the energy sector at the beginning of 2016 with an experiment in Brooklyn, New York, when owners of solar PV systems sold their power in the neighbourhood using the Ethereum blockchain without a utility.

    A recent survey indicates that today, around two years after the launch of of a major blockchain microgrid research project, there are 122 organizations involved in blockchain technology and 40 deployed projects.

    Between Q2 2017 and Q1 2018, over $300 million was invested in blockchain in the energy industry. While it is still much too soon to speak of a triumph as blockchains must continue to evolve, the technology has the potential to radically change the energy industry. It provides the opportunity for new or more efficient business models and thus the opportunity for entirely new companies entering the market.

    The years 2015 and 2016 were starting points for blockchain in the energy sector. The last month was marked with relevant infrastructure layers like the Tobalaba test network of the Energy Web Foundation or IOTA – a blockless distributed ledger, so in the coming years we will see numerous rollouts of new, relevant application layer and business models.

    There are at present many new players who are currently developing entirely new areas of value creation, with a variety of startups and established utilities working hard to test blockchain technology.


     


    These possible platforms and distributed database systems are striving for acceptance in order to become the leading player in the decentralized world. Following the example of over 70 banks and financial institutions and their R3 consortium, utilities could also attempt to enable a decentralized power grid and compensate for lost revenues by providing the business platform as a service via such community chains — a kind of consortium.

    Since the consortium’s participants are known and thus have a particular level of trust to each other, the integrated governance of these kind of blockchains is much easier than for free accessible public blockchains. This, in turn, also leads to the advantage of a less energy intensive performance.

    There are many indications that blockchains will gain a foothold in the energy sector — an efficient decentralized energy world requires appropriate decentralized technologies. Blockchains could represent and execute various business processes of the energy world, and would be an ideal instrument for IoT devices to manage their transactions.

    Blockchains are also useful as a trustbuilding element to provide transaction logs for energy to manage power flows and the accounting of cellular systems, automate proof of origin, enable P2P trading and the administration of asset registers. Companies and foundations are currently developing the next generation of blockchains for the energy industry, which protect privacy, are fast enough, and have the usual interfaces.

    For a wide implementation, developers still struggle to identify the specific business model for the different use cases and simultaneously comply with regulatory requirements. A tremendous regulatory hurdle is the European General Data Protection Regulation (GDPR) and the right to be forgotten. Blockchain is actually not designed for meeting the current state of regulation since one of its major features is immutability. Another hurdle is the handling of personal data. With peer-to-peer deliveries one can draw many conclusions on personal behaviour. From this aspect, a way to aggregate and de-personalize data has to be found. In addition, energy law varies from country to country, which means that the application must be adapted to national law or national law has to assimilate to the principles of blockchain.

    Euphoria and reality  

    In truth, blockchain technology can barely justify the current hype around it. Blockchains are not a panacea, but should rather be seen as one of many technologies that could form the basis for next-generation service infrastructure in the energy sector.

    Many digital services are already possible today without blockchains. While many ideas are being developed around the technology, a clear direction of where and with what economic benefits blockchain-based applications could be used is still far from apparent. Most of the current applications are attempting to solve fractional parts of energy market problems, being far away from the oftennamed vision of a blockchain of everything.

    We are currently experiencing a phase where the blockchain energy pilots from a few years ago are under pressure to deliver concrete results and pathways for commercialization. The blockchain euphoria alone is not sufficient to maintain the funding for projects in eternal proof-of-concept stage.

    Therefore, the priority at the moment should be to prove the existence of a viable business model by focusing on a real, existing problem that consumers or energy actors are facing.

    Although utilities should actively engage with blockchain technology, there is no reason to be alarmed as the technology is still young for use in the energy sector. Blockchain technologies work wherever transaction costs exceed the transaction value – for energy trading, processes in high temporal resolution (real-time energy economy) become necessary.

    However, both the related opportunities and risks are already apparent. They should be examined with respect to each company’s own position and strategy in order to derive strategic options. For the majority of companies, the fast-follower strategy is possibly the most appropriate one, but future-proofing the business is even more important.

    As with any new technology, the existing market players should invest time and resources to understand the potential and develop use cases. The incumbents can be disrupted if they stop innovating and adapting to new business models. A number of European utilities have understood this and are actively researching this area: the digital solution for a real-time energy industry to regulate supply and demand and realize real-time physical power flows with minimal transfer costs even in the smallest neighbourhood markets.

    Another relevant question that remains unanswered is "Will blockchain enable a renewable future?" Interestingly enough, most existing projects, especially crowdfundingfocused startups, are somewhat exaggerating the greenness in their communication. Despite this, the reduction in market friction by the future blockchain application will have a positive impact on the future of renewables.

    The current electricity market is still struggling to integrate a high share of intermittent generation and operate the grid in a smarter way.

    The blockchain applications that we are seeing today could create the basis for a more digitalized and automated market where it will be easier to trade flexibility, cheaper to balance intermittent generation, or perhaps even remove the need for balancing by implementing real time nodal pricing.

    Although the technology is not yet sufficiently scalable and regulatory hurdles have to be overcome, these examples set the vision for a number of passionate players to develop the market of the future.

    Thomas Steinberger, Robert Schwarz and Sergiu Maznic are from Pöyry’s European Blockchain Team

    District Cooling Q&A

       

    Why plus points stack up for district cooling

       

    Around the globe there is active investment, acquisition and expansion in district energy, especially cooling as a means to support economic and environmental objectives  

                     


     


    Rob Thornton, president of the International District Energy Association, has been working in the sector since 1987 and has never seen it so active and vibrant. He tells Diarmaid Williams why there is growing recognition of the merits and advantages of district cooling.

    PEi: There is a perception that district cooling is the preserve of cities in warmer regions of the world, and often a failure to note its relevance in colder climes. Is the stereotype indeed the rule or has it evolved?

    Rob Thornton (RT): The commercial district cooling industry started in the US. Hartford, Connecticut was the first downtown district cooling system initiated in 1962, and I worked at that company for five years in the late ’80s. While we were there we doubled the size of its district energy system.

    At the time the buildings we connected were mostly commercial office developments, some special events spaces, some residential and hotel space. In the buildings that we connected, the ratio of cooling BTUs to heating was 3:1 – three times as much cooling energy per building than heating.

    What’s happening now even in northern climates, is that with clustered buildings, there is an aggregation opportunity where there is high density. Buildings are not unlike human bodies. Heat is generated internally by lights, computers, human bodies, even on a mild Spring or cold day, so that heat has to be either rejected and released or utilized.

    Of course district cooling is growing as an industry in warmer climates. Certainly, in the Middle East we’ve seen tremendous progress. In the last decade, the UAE has been the most significant market, with Abu Dhabi and Dubai dramatically shifting to district cooling as an environmental strategy. Saudi Arabia is now coming quickly behind. District cooling as an industry has been steadily growing for 40 or 50 years and particularly where there is density. Cities like Houston, Texas or Phoenix, Arizona would simply not exist without air conditioning.

    But it’s not all driven by outside temperature and climate. Of course, district cooling makes sense where there is a volumetric or even a base cooling load year-round, but It’s not just comfort air conditioning in the summer time. Buildings have a cooling load year-round involving more workplace density, computers, fixed windows and generally more heat being generated internally in buildings. Of course lighting and plug loads have been reduced, and building HVAC and control systems are definitely more efficient than 50 years ago, but the appetite for cooling has been growing.

    PEi: There is a great drive over the last decade to produce smarter cities. Surely cooling should be a key ingredient in any city that wants to be described as smart?

    RT: The development cycle of district cooling means you can’t cover a whole city immediately. You have to build a node and cooling plant in phases, whether that entails a segment of the central business district, a healthcare cluster, a pharma facility or data centres. District cooling often starts with an anchor load.

    In Dubai, one of our (IDEA) members, Empower, has constructed 73 district cooling plants in the last 12 years and now has an aggregated cooling capacity of 1.4 million tonnes of refrigeration and they’ve done that really by effective planning, building these assets to support anchor loads.

    In Dubai there are areas of the city such as the Emirates Mall, or Palm Jumeirah for instance, which have multiple district cooling plants that are interconnected, supporting virtually all of the buildings on that man-made island. That’s a reflection of effective planning and timely investment. In these places, there are demands from the extreme climate not unlike in Houston or Austin or Phoenix here in the US. Cooling is obviously more critical in these locations.

    What’s driving the Investment more generally is efficiency. A district cooling plant can operate at significant efficiency advantage over traditional in-building equipment or air-cooled or terminal units, or air conditioning units you might see in a hotel. In Dubai they don’t want to have the AC load solely supported by electricity, by the wires. In that region about 70 per cent of electricity is used for AC.

    By aggregating the cooling loads of a few dozen buildings you can apply technologies at scale like thermal storage, which allows you to make cooling during periods of low prices or lower demand on the grid and then displace the most expensive electricity demand during peak hours.

    With scale, you can also invest in industrial-grade refrigeration equipment that is functionally more efficient. A key to district cooling is also the diversity factor among connected customers. Let’s say, for instance, you serve 12 buildings in part of the city. The cluster could include a convention centre, three hotels, five office buildings and one residential retail complex.

    With that mixed use, the respective peak demands vary over different times of the day and will not all occur at the same time. Especially with event-space like a convention center, stadium or arena, the loads and uses are intermittent and occur as event occupancy happens, not as part of a regular daily or weekly schedule. This provides some additional flexibility to meet those demands and operate your plant optimally.

    PEi: What other advantages does district cooling offer over the traditional means of cooling?

    RT: Instead of every building investing in cooling equipment which is designed for their worst day or peak day, the customer can contract for what they actually need, so there is a whole capital efficiency gain that the customers capture and the district cooling provider really leverages.

    When buildings don’t have access to district cooling they have to purchase equipment designed for a 25-year life, with declining performance and efficiency loss over time. Engineers will often factor those in, adding in initial capacity coverage for uncertainty. It’s like buying an oversized vehicle that you need for a two-week family vacation road trip, but having to drive that vehicle all year. In my experience connecting dozens of buildings to district cooling networks, installed chiller capacity is often twice or 2.5 times the actual requirement on a design day. District cooling corrects for over-investing and sunk capital costs.

    Energy storage

       

    Earthquake-proof battery backup

       

    A set of new batteries have been installed at the Megalopolis B power station in Greece. George Charalampous explains how the backup battery system will withstand severe earthquakes and operate reliably in the heat of the Grecian summer  

                     


     


    Replacing time-served assets can be challenging. New equipment is rarely a like-for-like substitute for the original and many factors may have changed since the original installation – including building codes and minimum technical requirements.

    This was the case when the Public Power Corporation (PPC) of Greece wanted to renew the backup batteries at Megalopolis B, a 300 MW coal-fired thermal generating unit in the Peloponnese.

    PPC is the largest electricity producer and supplier in Greece with approximately 7.4 million customers. It operates conventional thermal, hydroelectric and renewable generators that together account for 85 per cent of Greek generating capacity. Unit B is part of a facility that has a total of 1140 MW thermal generation.

    When selecting a backup battery system, the operator’s priority was to ensure safe, reliable and long-lasting backup power in a hot and seismically active environment.

    Battery selection  

    The battery system is required to provide more than eight hours of backup time for mission critical equipment, including switchgear, oil pumps and lighting, as well as safe shutdown of equipment and a controlled transition to backup power generation.

    PPC selected a battery system comprising a total of 680 cells in two identical arrays of Alcad MB765P batteries. The MB batteries are designed to provide backup power for a mix of high power and low power sustained loads at industrial sites such as power plants, substations and oil and gas facilities. The installation has been designed to closely match PPC’s requirements for power, voltage and duration.

    While there are many different options for power output and energy storage capacity across Alcad’s range of backup batteries, Alcad identified the optimum size for Megalopolis B with the help of its BaSics (Battery Sizing and Configuration System) software tool.

    This tool is designed to help engineers in optimizing their sizing calculations. It also helps to select the correct battery for the specified application, create the optimum battery layout for the available battery room, and calculate the heat generated by the batteries and the ventilation required.

    The batteries were selected for their proven high quality, reliability and high resistance to the shock and vibration that may be needed to withstand an earthquake.

    Another advantage of the MB cells is high chargeability, which enables faster recharge time.


     


    Following a full discharge, the cells can recover at least 80 per cent of their capacity in 15 hours under float charge conditions of 1.4 to 1.7 Volts per cell.

    Long lifetime in a hot climate  

    An additional factor considered for the battery selection was the battery’s ability to withstand extreme temperatures over a long lifetime. The temperature at Megalopolis varies from 15 to 30°C and although the battery room has ventilation, it does not have air conditioning. As a result, it’s vital that the batteries will perform reliably at +30°C.

    It is well known that elevated temperatures have an impact on battery lifetime. Heat accelerates the electrochemical reactions in all battery types, leading to premature aging. However, some batteries are able to withstand high temperatures for a longer time.

    Comparing the design lifetimes of nickel technology and lead-acid batteries at 20°C, nickel will last 20 to 30 years and lead-acid will last up to ten years.

    However, if the heat rises to a constant 35°C, nickel batteries will last 16 years, versus only up to five years for lead-acid. The gap will widen further as the heat rises.

    As a result, adopting a nickel technology battery system makes financial and technological sense when operated in a hot climate.

    The system will operate reliably for longer, need less maintenance and require longer intervals between asset replacement – meaning a lower Total Cost of Ownership.

    Being located at the intersection of several tectonic plates, earthquakes are common in Greece.

    As a result, it is essential that the battery system operates reliably in the aftermath of the worst-case earthquake for the region.

    Shaking and rupture of the ground can damage structures, cause tidal waves and harm power generation, transmission and distribution assets – potentially leading to fire and electrical surges.

    As a consequence, backup batteries have an important role at power stations in earthquake zones. They ensure availability of control and monitoring equipment, safe shutdown of equipment and clearing of faults.

    In terms of frequency and severity, Greece typically experiences one earthquake every decade which is rated at seven or higher on the Richter scale.

    While the Richter scale is commonly used to compare severity of earthquakes, it is a measure of the total energy released in an earthquake.

    However, duration of earthquakes can vary – with the result being that the Richter scale is not a suitable measure for engineers to use as the basis of designing structures to withstand earthquake conditions.

    Instead, the engineering community uses Peak Ground Acceleration (PGA) as the basis of anti-seismic designs.

    At Megalopolis, the Greek government has published a guideline that buildings and structures in and around the town should be able to withstand at least 0.16 g (a maximum acceleration equivalent to 0.16 times the Earth’s gravity).

    Anti-seismic installation  

    Alcad’s authorized agent in Greece, Semicom GP Hellas, supplied a battery installation that can withstand an earthquake with a PGA of 0.2 g. Its scope of works included designing a new floor plan arrangement for the new batteries, racks and power cables, as well as supplying, installing, commissioning and testing the new battery system.

    The project called for complete decommissioning and dismantling of the existing battery system and battery racks and replacement with the new battery solution.

    The Alcad MB batteries have high mechanical strength and robustness, with an internal steel plate structure and polypropylene outer casing.

    These features mean that the cells themselves are tough and robust and can withstand vibrations, shock loads and mechanical impacts, especially when they are installed on earthquake proof racks as in this application.

    The key difference between standard and earthquake-proof battery racks is that the seismic version has larger support components and additional cross-bracing. The design is modular and can be scaled up to meet the demands of different batteries and higher earthquake intensity, as measured by PGA.


     


    Accessibility challenge  

    The replacement project itself posed an unusual challenge as the battery room was located on the top floor of a high building which was not served by elevators.

    However, each of the 680 new cells weighs around 40 kg and could only be moved in once the existing battery system had been removed. As a result, Semicom used a phased approach. The first preparatory phase was to establish access by breaking through the external wall of the battery room and installing a temporary lift to serve the project. It then rearranged the power cables before installing, connecting and commissioning the new batteries.

    Once the installation was completed, the lift was dismantled and Semicom replaced the outer wall with new brickwork.

    Limited timeframe  

    A further challenge was posed by the limited timeframe available. PPC needed the batteries to be replaced within a two-week planned outage period while the power station was powered down for other service and maintenance activities.

    To avoid extending the outage further, Semicom scheduled a team of six technicians to work ten-hour shifts every day throughout the outage period to complete the job on time.

    As well as supplying and installing the new battery system, Semicom also provided on-site training to PPC’s technicians.

    This was designed to help them develop a full understanding of operation and maintenance techniques and therefore ensure long and reliable lifetime operation of the system.

    One reason for PPC’s selection of Alcad as a manufacturer was the firm’s track record in supplying backup power battery systems for industrial facilities in Greece. These include other sites operated by PPC as well as private power and infrastructure sites.

    Ultimately, PPC needed backup batteries to demonstrate long-term reliability to give the confidence that emergency systems will work faultlessly when required. Alcad has a lot of installations in Greece where batteries have successfully served for more than 25 years.

    Following the installation, Semicom received an excellent appraisal from the PPC for its professionalism, quality of work, ability to cope with the challenges of the project and for keeping to the challenging timeframe.

    With the new battery system being completed in spring 2017, it has now been proven in operation for more than a year.

    In operation, the MB cells have low maintenance requirements, requiring a straightforward annual maintenance inspection to check that the charging system, battery and auxiliary electronics are functioning as expected.

    George Charalampous is Sales Manager for the Middle East at Alcad

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    Hazardous Materials

       

    Don’t let your business go up in smoke

       

    Full disclosure up front is a necessary step toward mitigating or eliminating explosion risks

       

    writes Andrew Parker

                 

     

    It should come as no surprise that fires and explosions cost companies billions of dollars each year.

    Lost productivity, the cost of repairing or replacing damaged or destroyed equipment, settling lawsuits originating from employee injuries or deaths – it all contributes to the total. Industrial operations are particularly familiar with the dangers of explosions, especially those that handle materials such as biomass, wood pellets, sulphur, oil and gas.

    Countless incidents that occur within industries that are susceptible to explosions can be mitigated or eliminated entirely in a variety of ways. Perhaps the most effective method of minimizing the risk of explosion involves a simple conversation or consultation at the beginning of the equipment selection process.

    It’s true that any reputable equipment manufacturer will know that the potential for explosion exists within all of the aforementioned industries, as well as others. That knowledge will (or should) prompt them to ask certain questions in order to collect the required data for proper equipment selection.

    A conveyor manufacturer, for example, will ask if the equipment needs to be gas- or vapourtight due to the nature of the product being handled. The customer’s answer will determine if the conveyor needs to be inert.

    However, those who are responsible for the procurement of equipment in any industrial application must remember that it is their responsibility to inform their suppliers about the material they’re dealing with – and do so in a way that makes it clear they need a plan for mitigating the potential for explosion.

    This stresses the importance of establishing a true partnership between customer and supplier, instead of treating the relationship as a simple business transaction. There needs to be a high level of trust and an open exchange of information in order to avoid catastrophic consequences.

    Often the most important information regarding the explosive properties of a particular material – or, more accurately, the dust it creates – is revealed through third-party testing, which must be commissioned by the equipment purchaser. This testing will eliminate any guessing or doubt as to any potential dangers that could occur during the material handling process.

    Once this information has been obtained and shared with everyone involved in the design and implementation of the equipment, the supplier can pick up the proverbial ball and run with it.

    In the case of conveyors, manufacturers are able to plan for several safeguards that can help prevent explosions from occurring in the first place, or at least minimize the damage if they do happen.

    Explosion venting is a relatively economical way to account for the potential for explosions. In fact, in the US there are National Fire Protection Association (NFPA) standards in place that mandate the implementation of this safeguard when handling various materials.

     

    In the event of a fire or explosion, vents will blow open beyond a certain psi level to provide relief for the internal pressure caused by the incident. This provides a termination point that contains the damage to the conveyor. Without proper venting, equipment acts as a plenum or chimney and moves the volatility downstream, where a more catastrophic explosion could occur.

    Nitrogen purging a conveyor will make it inert by limiting the amount of oxygen within the equipment so it doesn’t react with hydrocarbons and create explosive mixtures.

    Adding lifting/grounding lugs to conveyors can mitigate the potential for static electricity to create a spark or start an arc.

    Using plastic or synthetic UHMW paddles to move material through the conveyor is another way to reduce the possibility of sparks by eliminating steel-to-steel contact within the equipment.

    Sparks are among the most common causes of industrial explosions, and it only takes one to detonate volatile material dust.

    Ultimately, none of these options can deliver the necessary benefit without open communication between customer and manufacturer.

    Experienced suppliers will understand that handling grain or sulphur automatically goes hand in hand with potential explosion issues, and they will ask if it’s necessary to plan for certain safeguards when manufacturing the customer’s conveyors.

    Drag conveyors and bucket elevators, which are typically used in these applications, can be manufactured with a closed design to control dusting. But in most cases, that’s not enough to cover all the bases related to avoiding explosions.

    With other materials, the explosion risk isn’t as obvious. That’s when full disclosure about material properties is absolutely essential. Equipment suppliers can only create a solution based on the information they receive from a customer.

    If that information is lacking for any reason, an explosion occurs and an inspection by the NFPA reveals that the proper equipment wasn’t installed, insurance won’t cover those losses. A single situation like that could be enough to shut down an operation forever, not to mention the human cost of injury or loss of life.

    There are many challenges associated with conveying bulk materials.

    At the very top of the list is understanding the properties of those materials and how they interact with each other, as well as how they interact with all of the environmental factors in a given operation.

    Equipment is one of those factors, and suppliers all must adhere to a strict set of industry-standard guidelines for fire prevention and explosion mitigation when designing a proposed solution.

    But even those guidelines can’t account for everything a conveyor might encounter in a specific application.

    When customers provide results from thirdparty material testing and suppliers offer extensive knowledge about material characteristics and behaviour acquired from years in the field, the likelihood of an explosion is minimized significantly – as is the potential for unimaginable losses.

             

    writes Andrew Parker

    Andrew Parker is vice-president for CDM Systems, Inc. He has more than 20 years of experience in the bulk material handling industry and overseas operations including conveyor design and development. For more information visit www.cdmsys.com

    Coal power

       

    Sealing the deal

       

    Alignite-fired power plant in Germany upgraded the performance of its boiler feed and FGD slurry pump seals, in turn eliminating unplanned pump shutdowns and improving mean time between repair from 20 to 40 months,  

       

    writes Jim McMahon

                 

     

    The lignite-fired power plant is one of the largest coal-fired power plants in operation for power generation in Germany. The power plant has different pumps installed, which are sealed with mechanical seals that keep the pumps in operation.

    Mechanical seals are found, for example, in the main heat cycle – pumping raw feed water, boiler feed water, condensate and the cooling water that supports the condensate system. They are also found in secondary pumps, fire suppression systems, and service and wastewater applications. Mechanical seals are also in limestone slurry for the flue gas desulphurization (FGD) scrubber system.

    A mechanical seal comprises a stationary primary element which is fixed within the pump housing, and a rotating mating element fixed to the shaft. Precisely machined, these two components are pressed together, meeting at a wear face, while the extreme tolerances between the two elements minimizes leakage. The seals, however, rely on a certain amount of leakage to lubricate the moving surfaces. The rotating element is supported on an extremely thin lubricating film, typically 0.25 microns in thickness.

    Mechanical seals are influenced by a number of factors, including temperature, pressure, vibration from pump shaft misalignment and quality of the pumped fluids. Coal-fired plants have many processes that contain abrasives and solids within the fluids being pumped. These insoluble liquids are hard on mechanical seals because they create added abrasion and erosion of the components. The particles can get into the mechanical seals’ O-rings and springs and cause them to go rigid, where the seal is no longer able to move with the shaft movements and pressure deflections.

    As with all rotating equipment, seal wear is a constant factor requiring continual monitoring, maintenance, repair and replacement to keep the equipment operating as required. This lignite-fired power plant, however, experienced premature pump seal wear and excessive seal corrosion, as a result of adverse reactions to feed water treatments and inadequate maintenance coupled with part stocking issues.

    The plant’s boiler feed circuit pump seals and FGD slurry pump seals were negatively impacted, experiencing a significant reduction in mean time between repair (MTBR), ultimately resulting in unplanned pump shutdowns.

    To remedy the condition, John Crane, whose seals were originally installed in the plant’s boiler feed water pumps, implemented a comprehensive programme to isolate the cause of the premature pump seal degradation; engineer a mechanical solution to extend longevity for the seals; implement a system to monitor the ongoing condition of the feed water; and establish a structured maintenance, repair and part stocking regimen.

    Boiler feed circuit pump seals  

    The boiler feed circuits, being the core of a thermal power generating plant, rely on highspeed, high-performance pumps to keep the water moving through the systems. Each boiler feed circuit has two high-speed, high-performance pumps feeding the boiler, and approximately 100 secondary pumps along the feed circuit.

    Plant-wide, the boiler circuits, combined, have 12 high-performance pumps and approximately 600 secondary pumps. Each of these pumps has mechanical seals, and the high-performance boiler pumps have two mechanical seals for each pump.

    In this plant, as in many power stations using high-purity boiler feed water/COT processes, with high-speed, heavy-duty pump applications in boiler feed circuits, minute electrical potentials develop which cause electrostatic corrosion on the mechanical seals. The material of the mechanical seal itself becomes degraded, resulting in a shortened lifespan. This condition is due to chemical reactions from combined oxygen treatment procedures of the feed water initiated to reduce corrosion in the boiler, resulting in the creation of electrical voltage.

    "Failure of the mechanical seal is the primary cause of pump failure," said Wolfram Enders, Senior Application Engineer with John Crane. "The high-performance boiler feed circuit pumps are integral to the operation of any thermal power generating plant. If just one of these pumps fails, that boiler feed circuit would be running on 50 per cent operation, or could be potentially shut down."

    This is just what occurred at this plant, where boiler feed seal integrity was lacking, causing unplanned pump shutdowns. John Crane thoroughly investigated the condition of the pump seals, and developed a strategy to mitigate the problem. This included: a) specifying and installing specific components for the boiler feed seals of this plant; b) implementing an ammonia dosing system which feeds an ammonia solution around the mechanical seal to increase electrical conductivity of the feed water; and c) putting into place a control system to monitor the electrical conductivity of the feed water, integrated into the pump PLCs.

    "We are changing the conductivity of the water around the seals, and changing seal face materials," continued Enders. "This is giving them more reliability and longevity. It has been a project underway for some time, and we are seeing the results in 100 per cent longer life of the seals."

    The feed pump seals in place are heavy-duty John Crane Type 270F O-ring pusher cartridge seals, for boiler feed circuit applications. They are designed for critical high-pressure, high-temperature and high-shaft speed applications. The face and seat are computer-engineered for optimum distortion control leading to high reliability and long operating life.

    The seals can handle temperature limits from -40°F to 500°F (-40°C to 260°C); pressure limits up to 1000 psi(g) (69 bar)(g); and speed limits up to 4000 fps (60 m/s). Advanced computer-designed faces maintain optimum performance under all temperatures and pressures.

    FGD slurry pump seals  

    Flue-gas desulphurization, a set of wet-scrubber technologies used to remove sulfur dioxide (SO2) from exhaust flue gases of fossil-fuel power plants, typically uses a wet limestone (CaSO3, calcium sulfite) slurry through which flue gas containing SO2 is passed in absorber spray towers. The abrasive and corrosive wet limestone slurry puts high corrosive demands on both pumps and seals.

    "Flue gas desulphurization feed pump seals at the plant failed due to metal erosion and corrosion issues, resulting in a lack of seal component flexibility," added Enders. "The corrosion came from the calcium sulfite, and the erosion from the fluid velocity in close to the mechanical seals."

     

    The plant has 60 main feed pumps in the FGD circuit, and an additional 250 – 300 secondary pumps, for a total of 310 – 360 pumps involved in plant-wide flue-gas desulphurization.

    "Together with the local pump service companies of the pump OEMs, we conducted considerable testing, then engineered a mechanical seal solution that mitigated both the erosion and corrosion problems," said Enders.

    "The net result is: we were able to measurably extend the running life of the seals."

    The corrosion/erosion problem, which concerned the 60 main FGD feed pumps, was solved by installing heavy-duty John Crane Type 5860 cartridge slurry seals. These seals are specially designed to operate in the harshest abrasive slurry environments, including exposure to process fluids such as limestone. These seals can handle slurries with solids contents up to 50 per cent by weight, without the need for water flush support.

    The seals can handle temperature limits up to 180°F (80°C); pressure limits up to 360 psi(g), (25 bar)(g); and speed limits up to 65 fps (20 m/s). The seal face provides maximum stability and minimum heat generation under adverse conditions, optimizing performance with maximum seal face life and lubrication.

    Reliability programmes  

    A critical component necessary to restoring and maintaining the integrity of the plant’s pump seals was the establishment of a programme for ongoing seal inspection, maintenance, repair and part stock management. It was insufficient management of these areas which premediated the premature degradation of the plant’s pump seals, and resultant pump failures.

    The plant required a reliable way to manage and repair seals to improve MTBR. Stocking problems and tracking difficulties created confusion and frustration among operations technicians as well as procurement. And it needed a 24/7 stocking programme that would integrate with its existing enterprise resource planning (ERP) system.

    To facilitate organization and structure into this area, John Crane implemented its Performance Plus Reliability Programme, called Interface, for management of the plant’s mechanical seals.

    Programme development for reliability support began with a comprehensive feasibility study to establish the full scope of the plant’s needs. It measured equipment performance, calculated total cost of ownership and identified opportunities for improvement and cost savings.

    Once the data was collected, John Crane used the Interface reliability management software to benchmark asset performance against industry averages and perform a cost/benefit analysis. "The program initially inspected the existing seal installments and stocking procedures," continued Enders.

    "Then it made recommendations to bring order to existing repair and stocking systems, so to deliver high pump reliability. The stock standardization program ensures correct quotes and orders ultimately find their way to the right equipment. It is linked to the plant’s ERP system, streamlining seal repair, stocking and tracking."

    All failures from existing seals are now immediately sent to a nearby John Crane Service Centre for 24/7 repair. Dedicated spare parts are available 24/7 as part of the product/stock standardization program.

    The mechanical seal service delivers new John Crane seals and seal components to the plant, eliminating delays and inefficient and faulty repairs.

    And, importantly, training is provided to field engineer and operations personnel to reduce the risk of unplanned downtime and recurring issues in the future.

    "The Performance Plus Reliability Programme ensures high pump reliability and reduced maintenance costs for the plant’s rotating pump mechanical seals," added Enders. "MTBR, a key driver for the industry, was increased 100 percent, from 20 months to more than 40 months, because of improved seal maintenance, repair and stocking initiatives, including replacing existing seals with new John Crane components."

             

    writes Jim McMahon

    Jim McMahon writes on industrial technology for John Crane, a global leader in rotating equipment solutions

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    Decommissioning

       

    Better asbestos management in coal plant decommissioning

       

    Stuart Goodman considers the strategic management of asbestos in the decommissioning of fossil fuel power plant programmes

                     

     
     
     
     

    The UK government has made it clear that all remaining coal power stations will be forced to close by 2025.

    Indeed, one of the country’s eight remaining coal power stations is expected to cease generating electricity this year as part of plans to phase out coal under the Conservative Party’s flagship green policies.

    While three plants shut in 2016, and most are expected to halt operations by 2022, the last ones standing will be forced to finally close in October 2025 because of new pollution standards.

    These include Drax and Eggborough in Yorkshire and Aberthaw in south Wales. Ferrybridge is in the process of going through demolition internally but is not demolished yet.

    The decommissioning of fossil fuel power plants represents a wider shift by governments and operating companies across the world in their strategic ambitions for reduced harmful emissions and securing future domestic energy requirements.

    Many countries are already, or considering, replacing aging and end-of-life coal-fired plants with renewable energy sources. Indeed, throughout Europe, our experience reveals that the focus is on a planned transition from carbon-intensive power generation to meet the long-term aim of creating a low-carbon society.

    Driven by legislation to reduce emissions, commercial reasons, and moves to rely more heavily on renewable energy sources, power plant decommissioning is required to shut down these sites safely with minimal harm to the surrounding environment.

    However, a significant proportion of the UK’s stock of fossil fuel powers stations are over 40 years old – some even older, having been constructed in the late 1950s and early 1960s. So, this can pose a significant challenge for those with responsibility for site decommissioning, notably around engineering and environmental considerations.

    Hazardous materials  

    Historical information about any potentially hazardous materials a power plant contains is often scant, incomplete or simply missing. Building products containing asbestos are considered to have been extensively used in the construction of coal-fired, oil-fired and even nuclear power stations due to the material’s capacity to insulate against extraordinary heat – it was used widely as a thermal insulating material to assist in reaching the high temperatures necessary to run the boilers and generate electricity.

     

    Power plants required generators, turbines and boilers, among other equipment which was likely to be insulated with asbestos. Given the associated extreme temperature application, steam pipes, turbines, boilers, tanks and other vessels were also often insulated with asbestos-containing attachments, including pipe covering, block insulation, gaskets and heat-resistant (refractory) cement.

    Under the Control of Asbestos Regulations 2012 (CAR2012), the duty holder, usually the site owner, has a ‘Duty to Manage’ any asbestos and asbestos-containing materials on-site. This may appear straightforward, but it does shine a light on the environmental and safety issues associated with the decommissioning of power plants, and the phasing out of fossil fuel generation assets and advancing the demolition process.

    It also signals the significant challenges faced in identifying potential contaminants of concern, wider environmental worries, and the most effective approaches to the management and disposal of any hazardous materials for those across the power generation, EPC, demolition and environmental remediation sectors.

    The duty to manage asbestos is directed at those with responsibility for protecting others who work in industrial premises, or use them in other ways, from the risks to ill health that exposure to asbestos causes. It requires the duty holder to take ‘reasonable steps’ to find out if there are materials containing asbestos in the power plant and, if so, the amount, location and what condition it is in.

    It also stipulates that a record of the location and condition of the asbestos, or any materials that might be presumed to contain asbestos, is provided. A plan is then drawn up laying out in detail how the risks from these materials will be managed, before any steps to put the plan into action are taken.

    Important factors  

    Completion of a survey is a necessary first step in identifying and establishing the location of any asbestos hazard within a decommissioned site. But in preparing the survey, careful consideration must be given from the outset to some important factors: who should carry out the survey, how many people will be involved in the survey team, how long will it take to complete the work, how many samples should be taken, and will the whole process be difficult to complete?

    A completed survey will then provide the basis for moving forward to the next stage: the creation of an asbestos removal management specification.

    The purpose of this document, which should always be tailored to individual site requirements, will be to ensure that each remedial contractor receives a clear and precise set of instructions covering what needs to be completed and by when. A typical specification would include guidance on which regulated practice is to be adopted and a location-specific detailed methodology. Guidance on the adjacent plant, cables and ducting should also be provided.

    Insight into the planning, preparation and execution involved in the safe management and removal of asbestos across a declining fossil fuel-powered energy sector can be seen in the work Lucion is undertaking at Ferrybridge Power Station in Yorkshire.

    The power plant was decommissioned in 2016. Along with its cooling towers and ancillary equipment, it is currently being demolished and removed in a process that’s expected to take three years.

    The work reflects some of the best practices undertaken by utilities and contractors, who have experience in demolishing and dismantling power plants while overcoming some tough on-site conditions.

    The scope of work saw Lucion undertake a comprehensive survey to identify a range of hazardous materials within the insulating materials (asbestos, refractory ceramic fibres, cristobalite and ozone-depleting substances) contained on-site.

    Further challenges around site access have seen Lucion’s team deploy mobile elevating work platforms (MEWPs) and ropes to survey external ducting and piping, while access inside the boilers required hatches to be cut to allow surveyors to be lowered in to collect samples of the inner walls for laboratory analysis.

    More than 13,000 samples were collected, providing a detailed picture of where hazardous materials were located and assisting in the planning for safe demolition.

    Contaminated land  

    While contaminated land is generally well understood, asbestos issues around soil disturbance and excavation are perhaps less well known. In the UK, asbestos as a manufactured product wouldn’t occur naturally in the ground where a power station is located. So why would it be an issue?

    Extensive experience has shown that buildings previously demolished without removing the asbestos can generate long-term contamination issues – building waste was traditionally reused for hardcore or simply buried in an uncontrolled and unrecorded manner.

    This can all have a significant impact on health and safety – and the risk of exposure to asbestos to ground workers – as well as the removal methods of waste soil, its destination, and the associated transportation and disposal costs.

    This all needs to be considered, and there is guidance that determines whether waste soil can be disposed of as hazardous or nonhazardous waste following qualitative and quantitative analysis by experts.

    There are clearly significant challenges around the decommissioning of the UK’s fossil fuel power plant portfolio, and those involved need to consider the role of effective asbestos management and follow best practice as part of a wider strategic approach.

    Investing in the right resources and employing contractors with the requisite ‘big project’ experience and capacity can only contribute to delivering success.

    Stuart Goodman is a safety consultant at Lucion Environmental. Lucion Services brings together a group of multidisciplinary risk management companies to help clients achieve full compliance with occupational and environmental safety regulations. www.lucionservices.com


    
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