The Drakenstein Municipality project is an ongoing collaboration with clean tech developer Schneider Electric and system integrator partner, Altek.

Located 30 minutes outside of Cape Town, the Municipality has installed Schneider Electric’s RM AirSeT switchgear with pure air technology and digital connectivity.

Installed in February 2023 at the Dalwes substation, the new technology is free from SF₆ gas (Sulphur hexafluoride) and its associated greenhouse gas (GHG) emissions.

Shifting away from SF₆

The municipality’s choice to install the switchgear, forms part of their drive for clean growth and electricity distribution.

Vladimir Milovanovic, vice president of power systems for Schneider Electric Anglophone Africa: “Drakenstein Municipality is undoubtedly leading the way in establishing a modern, digitised infrastructure that enables it to remotely monitor equipment like the RM AirSeT switchgear which in turn allows for expanded network visibility, as well as preventative and proactive maintenance and problem solving.”

Added Alderman Conrad Poole, executive mayor of Drakenstein Municipality: “This project comes at a time when South Africa faces immense energy challenges. Being an early adopter of this pioneering technology will enable us to share lessons learnt with our peers.”

Mayor Poole here is referring to rolling blackouts in the country, known as loadshedding, due to the breakdown of TSO Eskom’s generating units.

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Identified by the Kyoto Protocol as one of six GHGs needed to be reduced, SF₆, a regulated fluorinated gas, is typically found in traditional gas-insulated switchgear and is 23,500 times more potent than CO2.

The gas currently has a special exemption for use in electrical distribution across geographies. However, as alternatives become more readily available, countries and territories are considering measures to restrict its use. For example, earlier this year in March, the European Parliament voted to accelerate the phase down of SF₆ and other fluorinated gases (F-gases) on the EU market.

Digital connectivity – SCADA update

Aside from the move to greener distribution, the switchgear is also being touted by the project partners as providing the municipality with heightened digital connectivity.

The municipality, serving a population of 305,281, will gradually replace its current 25-year-old SCADA (supervisory control and data acquisition) monitoring system with Schneider Electric’s ETAP system, which they describe as a model-driven electrical SCADA software solution.

Three of the municipality’s 36 substations are already online in the system. In the 2023/24 financial year, eight more substations will be brought online.

Explaining the system during the launch event was Altek managing director Alvin Naidoo, who stated the necessity of using SCADA: “We once looked at SCADA as a ‘nice to have’ but now it’s a way of life… [Through SCADA] we improve the efficiency of our network, reduce fault finding times and improve response times.”

According to Naidoo, the importance of the system comes in when looking at the use of data for consumption management:

“Based on simulation data, the system has features for load forecasting. We take simulation data, data that’s available in the repositories on the SQL (structured query language) and essentially amalgamate them and create load forecasting potential.”

Additionally, Schneider Electric states that the switchgear includes condition-based maintenance features, feeding data from its sensors to local field tools/apps and analytics tools, which can be hosted in the cloud or on premise, depending on requirements.

It also provides continuous condition monitoring and controls to check the quality of power connections, identify and isolate faults, as well as self-healing capabilities for reduced downtime.

This is according to a report released by Allied Market Research, Utility Communications Market, which analysed the systems and processes that utilities use to manage and organise their operations.

Utility companies rely on communication networks to monitor infrastructure, respond to service outages and guarantee service delivery to customers.

According to the report, the increase in adoption of distributed energy resources (DERs) has been a factor in the growth of the utility communications market. Utility communications play an important role because communication links need to be established among DERs, grid operators and control centres. Communication networks enable monitoring, control and coordination of DERs to ensure that they are integrated and effective grid performance.

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Asia-Pacific dominated the market in 2022. Many countries in Asia-Pacific have experienced rapid urbanization. As urban populations grow, there is a higher demand for reliable electricity, gas, and water supply, as well as effective communication systems to manage and monitor utility networks.

Asia-Pacific countries have also invested heavily in infrastructure development, including energy generation, transmission, and distribution systems. This includes the construction of new power plants, expansion of grid networks, and implementation of smart grids. Utility communications play a crucial role in connecting these infrastructure components and enabling efficient management of energy resources.

The report showed that the wired segment was the highest revenue contributor to the market in 2022. Wired utility communications offer high bandwidth and capacity, allowing the transmission of large volumes of data. This capacity is essential for handling real-time monitoring and control data, as well as supporting advanced utility applications such as smart grid technologies, AMI (Advanced Metering Infrastructure), and SCADA (Supervisory Control and Data Acquisition) systems.

According to the opinions of various CXOs of leading companies, the utility communications market is expected to witness increased demand during the forecast period due to a surge in demand for smart grid infrastructure.

Smart grid infrastructure will however require robust cybersecurity measures to protect against cyber threats and ensure the privacy of customer data.

Utility communications play a vital role in establishing secure communication networks, implementing encryption protocols, and monitoring network security to safeguard critical infrastructure and customer information.

The project, which has been awarded $300 million by the World Bank, will see the prepaid gas meters installed in the capital Dhaka and the Rajshahi Division in the west of the country.

Among these, 1.1 million prepaid meters will be deployed in Greater Dhaka covering just over half of the residential customers of Titas Gas Transmission and Distribution Company Limited.

The balance of 128,000 prepaid meters will be deployed in the Rajshahi division, covering the entire residential customer base of Pashchimanchal Gas Company Limited (PGCL).

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In addition, a pilot with up to about 60 larger industrial users in the two companies’ service areas will be implemented to demonstrate the viability of smart meters to better monitor and manage gas use in the industrial sector.

A Supervisory Control and Data Acquisition (SCADA) and Geographic Information System also will be installed on PGCL’s network to improve gas flow monitoring and help reduce methane leaks and ultimately contribute to a reduction of greenhouse gas emissions.

With all its customers having gas meters, the company will have better visibility on the flows of gas in its networks and report gas losses more accurately and thus be able to better target leakage reduction.

“Bangladesh’s biggest source of greenhouse gas emission comes from the oil and gas sector,” comments Sameh I. Mobarek, World Bank Senior Energy Specialist and Team Leader for the project.

“Prepaid gas meters and advanced monitoring systems will help optimise natural gas end-use, mitigate methane leakages and lead to lower gas bills for the households and industrial users.”

Natural gas accounted for two-thirds of primary energy consumption in Bangladesh in 2021 and over half of the power generation capacity.

Methane leakages in the oil and gas value chain amount to an estimated 257kt, which is roughly equivalent to 7.7Mt of CO2.

The decision to implement prepaid metering follows an earlier pilot of 200,000 prepaid meters conducted by Titas Gas, which was launched in 2015 and found that the system seemed to have successfully increased consumer awareness in combating waste of natural gas, thus creating the potential for savings in residential consumption.

The project will finance technical assistance to detect CO2 and methane emission sources along the natural gas value chain and identify and prioritise opportunities to abate emissions in existing facilities and infrastructure.

It will also help develop emissions monitoring, reporting and verification protocols and regulatory frameworks for sustained carbon abatement in the energy value chain that can then be implemented through investment with public and private climate financing.

The Sembcorp energy storage system (ESS) spans two hectares of land in the Banyan and Sakra region on Jurong Island, southwest of the main island of Singapore.

Commissioned in only six months, the utility-scale ESS has a maximum storage capacity of 285MWh that can meet the electricity needs of around approximately 24,000 households for one day in a single discharge.

Its rapid response time helps mitigate the intermittency caused by increasing amounts of solar power in Singapore. It can also provide reserves to the power grid, which frees up power generation plants to generate more electricity to meet demand when needed.

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The Sembcorp ESS is an integrated system comprising more than 800 large-scale lithium iron phosphate battery units.

It uses a Supervisory Control and Data Acquisition (SCADA) platform by Envision which offers monitoring and control of the ESS from the site level down to each battery unit and auxiliary equipment.

Live monitoring through the use of intelligent sensors, security cameras and dashboards tracks operational performance.

A decentralised temperature control system by Huawei was deployed to maintain the batteries’ temperature difference within a narrow range. This increases the battery lifespan and ensures a stable power output, according to Sembcorp.

Ngiam Shih Chun, chief executive of the Energy Market Authority, said: “This large-scale ESS marks the achievement of Singapore’s 200MWh energy storage target ahead of time. It will complement our efforts to maximise solar adoption by storing and delivering energy given the intermittent nature of solar power. The ESS will also enhance our power grid stability and resilience by managing mismatches between electricity demand and supply.”

China Energy Engineering Group Shanxi Electric Power Engineering Co., Ltd. (SEPEC) oversaw the engineering, procurement, construction, infrastructure works, installation and commissioning of the Sembcorp ESS.

The Energy Market Authority (EMA), a statutory board under the Singapore Ministry of Trade and Industry, is taking proactive steps to encourage the deployment of energy storage systems across the island. Various statutory papers have been published to provide clarity on the deployment of ESS in Singapore and the current regulatory framework.

The EMA and SP PowerAssets (SPPA) are also collaborating on a regulatory sandbox to test SPPA’s ability to use ESS to smooth out electricity supply during times of high electricity usage in residential areas.

The latest generation of cellular technology, 5G is still emerging with its full potential yet to be determined with the performance improvements and other benefits it brings over its predecessors.

A ten-fold performance improvement over 4G is the one benefit most likely to be apparent to the average user. But there are others that are of value for businesses, such as the improved capability of cloud services and edge computing and network slicing, which offers among other use cases one of the options for establishing a private network.

(Note the widespread application of the immersive reality-based metaverse will need to await 6G).

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With these benefits there also may appear added security concerns but unlike the earlier cellular generations, 5G was designed with ‘secure by design’ principles with security measures built in. Indeed the security flaws that have been found have been attributed to the mobile operator implementation.

Nevertheless as with any communications system the security architecture needs to be end-to-end with external applications secured independently.

5G has been trialled extensively in distribution networks, e.g. in Sweden, Ireland and China, and for individual use cases, such as smart substation monitoring, but so far there have been no or possibly few trials at the transmission network level.

5G transmission system use cases

The study, ‘5G – Art of the Possible’, was undertaken by the Digital Catapult, the government digital innovation agency, in collaboration with National Grid Electricity Transmission (ET) to explore the potential of 5G as an enabling platform for the digitalisation of the electricity and gas transmissions networks as a means of delivering on the UK’s net zero targets.

The study identifies “a long list” of use cases that 5G could bring, focussing in on those with high value based on a digital workflow offering additional data insights, greater efficiencies and opportunities to accelerate the deployment of innovative technologies.

These, with respective trials, are proposed in four main categories. One of these, which pertains to 5G service deployment, is communications resilience with the need for fast restoration in order to maintain communications service during power outages or other disruptions.

The trial would utilise a pop-up 5G network on wheels, which can be moved between sites to provide a temporary service.

The other categories, which pertain to how 5G services can be used, are asset monitoring and management, workforce management digitalisation including field worker support and training and SCADA.

In these cases the trial assets are still to be defined. For the asset management use case, the selected asset(s) would ideally already have a communication capability, while in that of the SCADA use case the detail of the equipment at the test site is unknown.

The workforce management digitalisation trial is proposed to focus on maintenance and inspection, potentially in two phases, one with mobile device video streaming and a second with a virtual reality headset.

The study reports that of these use cases, the most significant continuous benefit comes from workforce management digitalisation with an estimated £14.4 million (US$17.2 million) annually.

With a significant capital plan, construction is a critical workstream, particularly across the gas network, and with better workforce management at these sites there could be a £10 million ($12.2 million) saving.

Further, fines could be up to £10 million lower by being able to provide better asset management data.

Overall £103 million ($125.4 million) savings are estimated over five years. And more savings could be quantified if the baseline costs of different workflows and processes become available in the future.

Long term destination

The study concludes that the development of 5G capabilities would open up a wide range of benefits across the electricity and gas transmission networks and that it can provide the long term future-proof communication foundation required across them.

However, beyond trials there are several longer term directions that National Grid could take, based on the level of direct involvement in operating its networked services.

For example, National Grid could operate the services using its own infrastructure and resources.

Alternatively, National Grid could turn over provision of 5G to a 3rd party provider and continues to use its own infrastructure and resources, or it could contract with an organisation that is dedicated to providing services to the energy sector.

Together with Delta automation solutions, VTScada allows manufacturers to implement redundant and complex infrastructures across industries, including that of the energy industry.

With over 100 drivers already integrated, Delta has stated how operators will gain fast and direct access to the control environment.

According to Delta, VTScada was designed to allow developers to create applications of any size. Users reportedly gain access to across-the-board monitoring and its core SCADA features include alarms and notifications, trend reports, mapping, reporting, mobile connectivity, version control, graphic development, security and enterprise connectivity.

“At Delta, we’re pursuing growth across all industrial domains,” stated Delta product manager Nick Sobols. “Boosting our process automation portfolio with VTScada is a purposeful step in that direction.”

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Users can also connect to any combination of Delta or other hardware, aiming to provide a high degree of flexibility. System-wide redundancy features include server failover, load sharing, redundant networks and synchronised historians and alarm databases. Optional components include remote access and alarm notifications.

Ad-hoc or scheduled reports are included as standard in addition to a continuous real-time historical data viewer.

SCADA (supervisory control and data acquisition) is recognised for its ability to augment efficiency in the energy industry.

A category of software applications for controlling industrial processes, its importance lies in its capability to improve access to data and control. With big data providing platforms for more effective decision-making, SCADA is touted as enabling smarter decisions, especially in an industry that is becoming more digitalised by the day.

VTScada was developed as an open architecture with the aim of enabling far-reaching integrations across devices. The software is based on a C++ engine with cross-platform compatibility.

The front-of-the-meter residential project is an alternative to traditional distribution-level grid hardening solutions, said Sunverge in a press release.

Martin Milani, CEO of Sunverge Energy, said the platform works with upstream and midstream utility grid management systems, “which allows for the smooth integration of feeder-tied energy storage systems into core distribution grid planning and operations.”

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This project is designed to place the energy storage systems in front of the residential meter, where it can be integrated with utility distribution SCADA, said the company. The company said it is hopeful that the front-of-the-meter application will showcase how its platform can be used in direct distribution grid management.

The learnings and standards developed from the project could be scaled for large-scale utility-owned front-of-the-meter assets to enhance residential feeder reliability and resiliency, added Sunverge.

The project is expected to be completed later this year.

FERC order 2222 and PJM

Sunverge earlier announced that its Elk Neck Battery Storage Pilot Program would participate in the PJM wholesale market for ancillary services. At the time of the announcement in late 2021, the project, a virtual power plant (VPP) with a planned capacity of 0.55 MW / 2.2 MWh was set to be fully operational during the first quarter of 2022.

As designed, the Elk Neck Battery Storage Pilot Project is expected to allow aggregated DER to test markets under real-world market conditions in alignment with FERC Order 2222, PJM said in a statement.

Originally published on power-grid.com

Built on an area of 1.5 hectares, the digital substation is the first and largest of its kind in East Java, according to Hitachi Energy, and connects the 200-hectare Sidoarjo Industrial Estate to PLN’s grid, ensuring the many large manufacturing companies have access to stable power.

The substation will facilitate decarbonisation by allowing for the integration of renewable energy into the electricity network and will positively influence economic growth in the East Java Province by ensuring a reliable source of electricity, according to Hitachi.

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Djarot Hutabri, General Manager of the East Java and Bali Development Central Unit, said: “Thanks to Hitachi Energy, with this digital substation, operators can retrieve real-time data about electricity flowing in the network so they can anticipate and make decisions faster.

“This is important for the resilience and stability of the electricity network, especially to support this very strategic industrial area in East Java.

“In addition, this digital substation also allows for improved reliability, integration of new, cleaner forms of energy, and delivery of energy services in a smarter and safer way”.

The digitalisation of PLN’s Sidoarjo substation aims to lower O&M costs and will limit electrical risk with the use of fiber optic cable rather than copper for operational data exchange.

According to Hitachi Energy, the new substation at KIS is based on the latest communication protocols and will use a process bus communication network to enable the continuous bidirectional exchange of digital data between primary equipment, protection equipment, the SCADA system, and the regional control centre.

Station-level control is achieved through Hitachi Energy’s MicroSCADA power automation solution, from which PLN can get intelligent and automated results, thereby enhancing the availability and resilience of its power infrastructure.

MicroSCADA, along with the latest generation of remote terminal units (RTU), protection devices, and merging units, will enable PLN to improve the efficiency of its operations.

Furthermore, centralized monitoring enables disturbances to be identified and addressed quickly, minimising network disruption. This is particularly important to ensure the stable supply of electricity to the industrial estate and to increase reliability by sharing the energy load and distribution between the regions of Bangil and New Porong.

The 40MW solar PV is located in the district of Almaraz in Extremadura and comprises a 3MW/9MWh battery energy storage.

The project is part of Iberdrola’s Arañuelo 1, 11 and 111 solar systems with a total capacity of 143MW.

Technology firm Ingeteam was selected by Iberdrola for the supply and installation of the lithium-ion battery systems, solar PV inverters, transformer stations, power plant controllers and SCADA monitoring system.

The digital control and SCADA systems enable the system to be monitored and controlled in near real-time to optimise energy generation and storage.

Digital protection and control systems which include 30/132KV step-up transformers and collector and connection circuits were installed to develop a renewable energy control center with real-time information and access to various aspects of the system. The system also enables protection and control of the line that delivers capacity to the grid, according to Ingeteam.

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The project offers a novel feature with the inclusion of the battery storage system within the solar PV plant as a distributed system with a DC-Coupling configuration. In this mode, the batteries are installed within the solar array and the battery converters share the DC connection with the PV inverters, offering advantages including:

• Possibility of utilizing the extra power from the solar panels that is not used in the peak production hours (Clipping Recapture).
• This makes it possible to minimize the losses by charging the batteries from the PV array, given that the connection between the panels and the batteries only passes through the DC/DC converter. The discharge is also more efficient, due to the fact that no power transformer is required, in contrast to the AC connected solution.

The Campo Arañuelo complex is part of Iberdrola’s strategy to expand its portfolio of renewable energy for decarbonisation and use of energy storage to optimise renewables projects.

By coupling renewables with storage, the utility will be able to shift capacity to when it is most required, as well as leverage use cases such as energy flexibility for grid reliability.

The project is already producing clean energy to supply a population equivalent to 65,000 homes a year and avoiding the emissions of 41,000 tons of carbon dioxide per year.

The programme aims to upgrade and expand the country’s distribution infrastructure for grid efficiency and reliability for some 40 million people in Dhaka and Mymensingh.

Over 31,000km of lines, 157 substations, a Supervisory Control and Data Acquisition System and Advanced Metering Infrastructure will be installed to ensure grid resilience against climate change and cyber threats and to ensure that modern services are provided to consumers.

The project is expected to help improve access to modern and reliable electricity for consumers served by 25 rural electric cooperatives in the Bangladesh Rural Electrification Board as well as enable the integration of renewable energy for decarbonisation purposes.

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Bipul Singh, World Bank senior energy specialist and task team leader said: “Since 2009, Bangladesh Rural Electrification Board (BREB) has implemented one of the largest rural electrification programmes in the World, delivering access to more than 90 million people.

“With the access agenda nearing completion, this programme will strengthen BREB’s ability to deliver reliable electricity supply and support the energy transition in Bangladesh.”

The upgrades will enable energy storage systems to be integrated with the grid, a move that will help allow the introduction of energy flexibility for grid reliability, according to the statement.

Dandan Chen, acting country director of the World Bank in Bangladesh added: “In the last decade, Bangladesh achieved a more than fourfold increase in electricity generation capacity and delivered electricity connections to more than 99 percent of its population. But the electricity distribution network could not keep pace with the remarkable increase in electricity generation.

“This programme will help modernise and ensure climate resilience of the distribution network, which is the backbone of a secure and reliable power system.”

Today, more and more energy-intensive industries – such as mining, steel, or chemical industries – turn to using renewable energy for their power needs.

Leading the pack, though, are the giants of the digital age such as Google, Amazon and Facebook. They are being compelled both by their massive and rising energy needs, as well as their commitment (and their regulatory obligations) to decarbonization through renewable energy – mainly wind and solar – for their daily, globe-spanning operations.

By and large, they get their megawatt-hours through power purchase agreements. But it’s not just these major players that have a huge appetite for clean energy.

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At the beginning of 2021, a market analysis by S&P Global identified 400 projects with PPAs with 120 US-based companies totaling 46,000 MW alone. Still, PPAs are not the only solution. Many companies – including those mentioned above – also turn to on-site renewable power production with their own data centers. And for good reason.

As every millisecond counts for data traffic, they need to be close to internet exchange points, usually situated in urban areas. At the same time, these digital nerve centers store and process more data every day, resulting in increasing energy consumption.

The consequence is that the local utility may not be able to guarantee the capacity needed for such a center, especially if several data centers compete for the local energy supply. The solution: on-site power plants.

However, with the continuous drive towards decarbonization, they also have to use intermittent renewable energy. And that means hybrid power plants comprising renewable power generation, energy storage, back-up solutions, and possibly thermal storage for district heating, heat pumps, electrolysers producing hydrogen, and, last but not least, a smart flexible control system.

A new energy world
Many companies face this situation today, be it their pulp and paper plants, mines, or steel mills.

Even whole municipalities might be keen on ensuring a steady energy supply in the face of increasing demand, their desire to shrink their carbon footprint or to simply have more control over their electricity bill. And today, with continuous innovation in the energy sector and decreasing prices for renewable energy, this is no longer a pipe dream, but a realistic option of how to drive decarbonization.

Let’s take a quick look at some of the innovations and major changes that have happened over the last two decades that enable us to build these hybrid power plants today, as well as laying the basis for a new energy world.

For one, solar and wind energy are not just more efficient than ever before, but they have become affordable. They increasingly often have a lower levelized cost of energy (LCOE) over the lifetime of a renewable plant compared to a solely fossil fired one.

Second, as their power supply is fluctuating, energy storage solutions such as batteries, pumped hydro, or rotating grid stabilizers ensuring grid stability not only have become increasingly important, but tailored to the needs of renewables, making a steady increase in the share of fluctuating renewables feasible.

Third, digitalization. With renewable energy generation having become decentralized, the linear chain from a centralized power plant run based on demand changed to a complex as well as dynamic network of distributed power generators.

What keeps them connected and controlled are not just power lines, but digitalization – with an ever-increasing number of sensors, IoT-technology, 5G-networks, cloud and edge computing, advanced analytics, and intelligent cybersecurity.

The brain of the power plant in this context are digital management systems that flexibly as well as automatically manage fluctuating power supply and a plant’s energy needs.

So, just as our energy future is hybrid, on a small scale this future is already being realized today – on-site at industrial power plants. For sure, it’s not one-size-fits-all. Every plant needs its own customized solution.

At Siemens Energy, we achieve this via detailed Energy System Design studies, leading to optimal site-specific configurations, all enabled by Siemens Energy’s diverse portfolio.

That portfolio means you don’t have to rely on solutions solely based on single products but allows a much more technology-agnostic approach. But no matter which company a client ultimately chooses, it’s important to have the right competencies and specific know-how in order to find the optimal hybrid configuration for each customer, for which local conditions (e.g., wind speeds and solar irradiation), as well as customer requirements (e.g., percentage of decarbonization, minimising LCOE) need to be considered.

What does such a customized intelligent solution look like for electricity generation? Its key functional elements are renewables (wind, solar), which help to achieve a high level of decarbonization. It is storage systems, such as batteries bridging fluctuations and enabling optimal use of available energy.

And it’s efficient gas turbines, ensuring availability during longer doldrums, which later may be increasingly co-fired with green hydrogen. Its brain, though, is the ever-important smart control system, without which running hybrid power plants that rely heavily on renewables would be impossible.

Maximizing productivity and efficiency
Siemens Energy’s digital control system for hybrid plants is called ‘Omnivise Hybrid Control’, based on the SPPA-T3000 technology with more than 3.000 installations worldwide.

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It makes it possible to flexibly manage the unique setups that hybrid power plants consist of – with renewables, energy storage, gas turbines, and other assets – with one single operating system that’s easy to handle.

It comes with a remote or central control center based on a SCADA application server that allows the operator to monitor and control all plant processes. It stores all the relevant data concerning the plant’s performance. And it can be augmented with predictive modeling for early failure identification.

One module for the Omnivise Hybrid Control-System should be highlighted, though, and that’s the ‘Dispatch Optimizer’ providing economic dispatch optimization based on weather forecasts, technical and financial measurements, and other parameters.

Let’s look at how it works by taking the weather as an example. The ‘Dispatch Optimizer’ calculates the optimal economic dispatch for all assets in a microgrid over the next 24 hours based on the weather and load forecast. This calculation is done every 15 minutes, and the setpoints are sent to the hybrid controller.

The controller in turn manages the microgrid in real-time by constantly monitoring the measurements and sending control signals to the generation assets on a sub-second timeframe. This maximizes the productivity and efficiency of the plant.

Revenue-optimized generation
In the same way, the ‘Dispatch Optimizer’ can also optimize production schedules, e.g. prepare to ramp up production when electricity demand is rising, or slow it down, when it is scarce.

Likewise, it can recommend revenue-optimized power generation and storage schedules. How? For example, by participating in arbitrage: storing energy when it’s cheap and selling when it’s expensive. And if – next to supplying one’s own plant – there is an agreement to deliver clean energy to another client, the Dispatch Optimizer helps to avoid PPA penalties by ensuring obligations are met. In short, this module is an important part of the ‘brain’ of the ‘Omnivise Hybrid Control’ management system, as it allows for optimal economic management of hybrid power plants.

A precursor of the ‘Omnivise Hybrid Control’ was already piloted at the Isabela Hybrid Power Plant on the environmentally sensitive Galapagos Islands.

This hybrid power plant pilot included multiple energy sources, such as a photovoltaic plant; an array of biofuel generators; and an electrical energy storage system.

It started operations in 2019 and continues to smartly manage the requirements of the island’s power demands, which are mainly resilience, availability, and quality of supply. A key function is using weather forecasts and energy demand cycles, so it knows how to manage energy generation and storage. This successful first implementation showed that this smart solution can successfully integrate various components of a hybrid power plant.

Currently, Siemens Energy has several other hybrid power plants under development. There are basically two types. One is ‘Low Carbon Hybrid Power Plants’ that include photovoltaic and/or wind, gas turbines for residual power, and battery storage.

One step further, you have ‘Zero Carbon Hybrid Power Plants’ highlighting the increasing importance of long-term (hydrogen) storage. Such solutions may include an H2 electrolyzer, H2 fuel-cells, and H2 storage, next to photovoltaic and/or wind. Obviously, both types are monitored and controlled by the ‘Omnivise Hybrid Control’ operating system.

An attainable goal
It’s clear that to change the world we need to do it one step at a time. And when it comes to trying to realize a decarbonized energy world by 2050, we have to recognize that it’s not just a tall order, but that it’s also complex.

And for this complexity – fluctuating renewables, decentralization, various storage systems, etc. – to be manageable, we need intelligent tools that allow us to simplify it again.

With hybrid power plants and its intelligent controls, Siemens Energy is doing just that. It shows today how important it is to create tailored hybrid solutions for industry or municipalities for optimized energy production, decarbonization, and economics. And it’s not just for their benefit.

As we do this, we also show that our goal of a decarbonized energy system is absolutely attainable.

Hans Koopman is Business Owner Decentral Hybrid Solutions, Siemens Energy

The utility industry is transforming with new opportunities that are improving operational efficiency, productivity and resiliency across the electricity value chain.

The attack surface for utility infrastructure continues to expand as intelligent distribution systems, sensors and IoT devices aid in the visibility of the electrical system and assist with ensuring power delivery in the most efficient and reliable manner.

This article was originally published in the DISTRIBUTECH supplement of Smart Energy International Issue 1-2021.

Read the full supplement, the full digital magazine or subscribe to receive a print copy.

With this expansion comes a greater need to ensure that security is properly implemented end-to-end. According to an ESG survey, 74% of respondents say their organisation has been impacted by shortages of security skills. The security landscape is getting more complicated and the stakes are rising. As we connect everything, anything can be disrupted and everything from the cloud to the edge needs to be considered and protected.

Cloud computing represents a major shift from traditional computing, one that enables users – whether businesses or government agencies – to do more, faster. In part, this shift is due to the way in which cloud services are provisioned and maintained, allowing customers to tap into the power of cloud data centres and services without having to build, manage or maintain them.

Data hosted on premise is not free from cybersecurity risks. It is subject to many of the same cyberattacks as cloud solutions, but with the disadvantage of lacking the immediate access to cloud providers’ multinational resources and security measures, which are a major focus for these providers.

Cloud providers recognise that trust is a fundamental part of their business model and do their utmost to keep it. Moreover, cloud providers also use security to differentiate themselves, hiring the best talent in the space and dedicating significant resources to its development. For example, Microsoft invests more than $1 billion in security annually.

Additionally, a large pool of clients can work to the benefit of security, as it allows cloud providers to look for security intelligence across the whole environment, which is generally much larger than an average corporation’s traditional on-premise infrastructure.

The very process of migrating data and services to the cloud can increase the security and resilience of an organisation’s computing infrastructure. This is because migration can act as a forcing function for robust data governance, making organisations not only more aware of the data they retain, but also more purposeful about how they treat it.

And finally, it’s important to acknowledge that most technology providers have adopted a cloud-first approach. As a result, most of their innovation is delivered in the cloud and only later translated into on-premise solutions.

So, given the comparative speed of updates in the two environments that represent a significant advantage for cloud over traditional implementations, many of these developments are in security. Cloud security can not only compete with security delivered on-premise, but has several distinct advantages.

Speaking in a webinar during the DISTRIBUTECH+ series, Dr John Lemmon, global power and utilities leader at Microsoft’s Azure Energy Engineering, said that as the landscape of power and utilities – and indeed the grid in general – becomes more digitised, decarbonised and decentralised, the value proposition for cloud starts to increase.

This, he said, brings about scalability and the capability to add high-powered computing, provide more insights into what’s going on on the distribution side and coordinate with the overall transmission and utility side. Part of the transition for this digital transformation is being able to secure utility data in the cloud.

“Cybersecurity is needed across the full value chain of a utility,” Lemmon says. “And at multi-scale across different data platforms.

Lemmon explains: “it’s a case of edge security – to IoT security – to cloud security.”

“If we think about edge security, in my mind it’s one of these emerging technologies for things like SCADA listening, anomaly detection, data stream analysis, and signal analysis. Intelligence actually gives us the benefit of being able to create self-detect and self-healing algorithms for security reasons,” he says.

On the IoT side, there is automated asset discovery, vulnerability, management and integration. On the cloud side, you can collect data, process infrastructure, and detect threats through analytics and threat intelligence, and also investigate and hunt down suspicious activities and respond in an orchestrated and automated manner.

Lemmon points to responsibility as a key reason to shift to cloud computing, saying that “as you migrate from an infrastructure platform as a service and software service, the actual responsibilities for the security starts to migrate over to the cloud provider”.

He continues that many cloud providers are independently audited by a variety of organisations, including FedRAMP, the federal risk and authorisation management programme that is enabled by NIST standards and guidelines.

Joining him in the DISTRIBUTECH+ debate was Carl Imhoff, electricity market sector manager at Battelle Pacific Northwest National Laboratory. Imhoff chairs the grid modernisation lab consortium where a key focus is cyber and physical security. Imhoff notes: “There are two big transitions I wanted to highlight. The first from five years ago. A lot of the utilities were very uncomfortable getting into the cloud environment. Now, however, there’s been quite a bit of uptake and transformation in terms of their interest in engagement. Since then, we as a laboratory have been very involved in both commercial cloud activities and government cloud activities.

“The second big transition we’re seeing is one towards an acceptance of open platforms for some of the new innovation analytics that need to be delivered to the industry. We’re seeing it across the Department of Energy’s North American Energy System Resilience Modelling effort, where they’re partnering with NERC to put in place some new tools to help build resilience at a national scale.

“This is leveraging some of the big open-source platforms that we’ve developed as part of the Federal agenda there. Utilities like Avista and Duke and others are starting to look at open-source platforms for advanced distribution management systems and other things.”

About three years ago P&L worked with the Midwest ISO to develop a next generation tool to predict what the load is going to be going forward and match the generation to meet that load. It’s called the security constraint unit commitment and it’s a way they can predict supply and demand forecasts and create very large, complex computational challenges. “And then the world changes, they move the goal posts, and we have to add a lot of distributed resources and other sources of complexity into the power system markets,” says Imhoff.

“We worked with GE grid solutions, University of Florida, Cognitive Analytics and others to put together a next generation security constraint optimiser that can handle the complexity and scale of distributed resources like energy storage, etc. going forward.

“It will include both high performance computing to better segment the problem, and some advanced optimisation algorithms to improve that ability. What used to take us about three hours to calculate now is down to about 20 minutes, and it’s able to handle much more complexity in terms of the types of assets on the power system.”

Imhoff moves on to a topic he says is at the core of grid security: “The whole notion of the protection system, when the grid is close to a blackout. In the Western Interconnection, they call it Remedial Action Schemes and it can take a phenomenal amount of preplanning and design. And typically, they’re mostly manual.

“They can handle up to about 500 scenarios, but it can sometimes take months or years to go through all the analytics to set up these remedial action schemes. We started our journey a couple of years ago to see if we could leverage the emerging phasor measurement data coming off the grid – in this case, the Western System.

“And we teamed with Idaho Power and Pacificore to see if we couldn’t use high performance computing and machine learning, all benefiting from a cloud environment to do what’s called a remedial action scheme. In other words, it’s looking at real-time conditions on the system. In real time, lookups on the past performance to identify similar situations enables more precise optimisation on the real action schemes. This makes them more precise, protects more equipment more effectively, reduces the scope of a blackout and makes it easier for the operating entities to bring back online.

“I mentioned it was a manual appr oach; typically you can handle up to about 500 scenarios with this approach. But if the planners are able to use up to say 10,000 scenarios, they can look at much more complex attack planes or risk scenarios that they need to deal with to help protect the system. And they can perform at about 10 extra speeds. So instead of months to years to do the setups, it can be done in days.

“It can transform our ability to protect the system.”

Wolfgang Loew has been an active part of the European Network for Cybersecurity (ENCS) network since his company, Austrian utility EVN, joined as one of ENCS’ early members in 2014. Since then, Loew has become CISO at EVN, joined the Assembly Committee at ENCS and worked with E.DSO and various EU bodies – a man who w orks tirelessly to improve cybersecurity in the energy sector. We caught up with him in December 2020.

“We joined ENCS in 2014,” says Loew. “We weren’t founding members, but we were early to join the network as even back then, we could see the need for partnership on cybersecurity and a secure environment where we could work together with others. In particular, we wanted to work with specialists for testing and implementing network components, and we needed to do so in a trusted environment.”

EVN has worked with ENCS on a multitude of projects over the past six year, specifically on the utility’s smar t meter rollout, setting the security requirements for the components and then testing them.

“Of course, this is probably one of the most important projects we’ve undertaken with ENCS. Obviously, the smart meter rollout is happening. However, it’s essential that the whole system is designed, specified and procured with utmost care to prevent the introduction of avoidable security flaws. No cybersecurity is perfect, but when thinking about such a far-reaching initiative, anything less is unacceptable.

“So, we worked with ENCS to shape the cybersecurity requirements that we issued to potential vendors – which is helpful to the vendors too, as it gives them direction. Then we worked with ENCS specialists to conduct rigorous on-site penetration testing before any orders were placed.

“We take this approach with other components too, of course, such as RTUs. It may sound onerous for the vendors, but actually it is very collaborative. We can even involve them in the testing process so that issues can be fixed and, ultimately, we are all working towards the same outcome: a secure grid.

“Designing the specifications across both meters, network and components has meant that EVN can purchase smart meters and other components with confidence.

“EVN has always been good at prioritising security and we take the topic seriously – we have to in order to provide services our customers are expecting. Take smart meters – the project most visible to end-customers. There is a breaker unit involved, meaning a threat to security of supply, and GDPR relevant data, meaning privacy concerns. That’s two hugely important cyber threats in one component, so we see no choice but to take that seriously.

“Like a lot of industries, ours has had to cope with the abrupt shift to working from home. At EVN, we were fortunately already more or less prepared for that, but obviously needed to scale up the infrastructure to allow for everybody doing it at once.

“In terms of materially new threats, there has been a noticeable rise in phishing attacks across the sector, taking advantage of people working from home and communicating 100% digitally. In a way this has underlined a message we have been repeating for years: that security is a mindset, not a function, and the responsibility of everyone at the company, not just a few of us in infosec and IT. This will only become truer as companies move more infrastructure into the cloud. It’s a problem for COVID-19, but also for the future.”

The project will allow the control of almost the entire high and medium voltage distribution network in the country (315 substations and 165,000 secondary substations), covering around 7.5 million customers and generating a positive impact on a population of around 10 million people.

The project appears in the context of two successful works developed by Efacec over the last few years, namely in the Attica region and in the Greek islands’ region.

The implementation of these command and control centers is based on the ScateX platform

With modern cyber security-oriented architecture, in the configuration directed to electric power distribution networks, Scatex advanced distribution management software combines in single platform functionality of real-time operation, analytics based on advanced electrical calculation algorithms and management of incidents and planned tasks.

Incidents, though often unfortunate, represent incredible opportunities. With the right data strategy, a utility can not only respond to and correct the situation, but also compile and analyse data that can play a critical role in the success of a future digital transformation strategy. This effort has evolved over time with the adoption of real-time series data technology and infrastructure.

Join Bill McEvoy, Industry Principal for Transmission and Distribution at OSIsoft, as he explains how utilities can leverage real-time data to:

• Avoid redundant incidents and improve team-wide communication and collaboration
• Measure incident response effort and demonstrate incident management value
• Track continuous improvement and manage Security Risk within their critical control systems
• Minimize and optimize load balancing on SCADA and System Security Modeling Systems

The new SCADA system, Optime, will be used in the RWE Supply & Trading Dispatch Centre in Essen, Germany, to optimise monitoring of wind and solar energy farms.

RWE had two separate systems to monitor renewable assets in Germany, in the Netherlands, and Belgium. The two systems will be integrated into a single platform using the new SCADA.

Related articles:
RWE sets up new regional renewables control center in Coventry
RWE pilot maps the future of floating offshore wind energy market

Optime can also be used to integrate distributed energy resources such as battery storage and diesel-powered backup generators.

The development is part of efforts by RWE to invest in new technologies and business models that would accelerate and simplify the energy transition.

The new SCADA consist of a wall of monitors several metres high and wide showing in real time which RWE power stations are feeding power into the grid, the feed-in levels, and which plants are being ramped up or down.

The new system will enable RWE to create a new virtual power plant and allow the utility to control its distributed assets in real time.

The RWE control team keeps constant watch over developments as they unfold because power supply and demand can deviate from projections, for example in the event of unusual weather conditions or major events. In such cases, the engineers working in the Dispatch Centre must respond quickly.

Up to 500 optimisation runs are performed every day using the power plant dispatch optimisation programme developed specifically for this purpose by experts at RWE. This program determines the most economical use of all power plant units and machines and uses that data to create current target schedules. These are then transmitted via Optime as a target figure to the corresponding unit or machine control system of each power plant location.

Guido Hommelsheim, Head of Dispatch at RWE Supply & Trading, is pleased: “Optime gives us automatic control in real time as well as improved control performance. In addition, it allows us to better coordinate our portfolio, which consists of renewable energy plants, the existing flexibilities of our industrial customers, and conventional power stations. In view of the expansion of renewable energy, this is becoming increasingly important.”

Sabine Erlinghagen, CEO of Siemens Digital Grid, says: “The success of this project hinged on the close cooperation between RWE and Siemens. The new control technology for Europe’s largest trading floor enables Siemens to combine state-of-the-art control software and SCADA tools on a single platform. This helps RWE to better coordinate generation capacities in Germany, the Netherlands and Belgium. At the same time, high-quality, virtually disruption-free system services can be provided. In the future, it will be possible to optimise the integration of fluctuating levels of renewables-based energy. This holistic approach to power plant management will make a contribution to accelerating the energy transition in Europe and the world.”

UK renewable energy infrastructure development firm Solarcentury is partnering with Gantner Instrument Environment Solutions for the construction, operation and maintenance of the 110MW Vlagtwedde solar energy project.

The two have won a tender for the project from renewable energy fund manager Impax Asset Management.

The solar project will be built on 100 hectares of land. Gantner will provide 54 power plant controllers, a central 19’’ data logger and PPC rack for the construction of the project and control of the two grid connection points.

The PPC receives control commands from the Automatic Network Management leveraging IEC 60870 communication protocol. With the integrated touch screen of the local SCADA/HMI the power plant can be operated on-site.

The control and monitoring functions are provided with a sample rate of 1Hz. One-minute measurement values will be sent to the Gantner.webportal for daily O&M and for comprehensive power plant analytics with the latest big data technologies. The total number of acquired and calculated channels adds up to about 500 million per day and a lifetime data volume of 12 TB.

Thanks to the restful API which comes with Gantner.webportal it is easy to integrate plant data into company-wide data warehouses for unified storage and further applications. To effectively support onsite O&M, Gantner will setup an industrial Wi-Fi mesh network for smooth working processes for the service technicians. Gantner is also supplying six weather stations.

Today, that problem is solved without paper—through an entirely automated digital system dashboard that allows operators to do everything they had done manually faster and without the layering, shuffling, searching and by-hand and eye comparison.

KCP&L has crafted a unique extension to the standard Supervisory Control and Data Acquisition (SCADA) system for distribution automation (including fault location analysis) using Oracle Utilities Network Management System (NMS)—and some creative thinking and strategy. This extension enables the utility to increase visibility without increasing complexity for the operators, expand efficiency efforts into new urban and rural settings and boost operational performance.

In 2018, KCP&L merged with Westar Energy to bring their customers more savings, sustainable energy and solutions to meet every need.

The companies are combining operations, resulting in a stronger regional energy provider.

Originally, KCP&L had multiple software systems to help this local Midwestern US utility keep the lights on. In 2014, the utility took an opportunity to upgrade their systems which combined all those systems into one underneath the Oracle NMS umbrella. Now, realtime information is feeding into the outage management system and the operators have one dashboard to work from, which allows the operators to respond quicker and more efficiently to any detected faults or customer queries. “We’re talking about outages that impact thousands of customers restored in a couple of minutes,” said Dan Munkers, KCP&L Senior Manager of DSO.

This article was originally published in The Global Power & Energy Elites 2020. Read the full article here

When gas pipelines are ruptured by entities involved in excavation or similar activities, it leads to quite the scare. Buildings are evacuated, city blocks are temporarily closed and precautionary measures are taken which all contribute to a disruption of life and economic activity. Enter the heroes: utility emergency crews with their excellent training and tools move in quickly, isolate the problem and restore normalcy.

However, there are also instances where no one has been excavating, or there is no one to report a problem when natural land movements cause backfilling or padding to deteriorate. Gradually deteriorating pipes or consistently overloaded sections of a system are prone to catastrophic failure. Occasionally, incorrect operation goes undetected until it is too late. In most cases these are only discovered when there is an explosion. In some parts of the world, metallic gas pipelines are corroded to a point where the pipeline is no more than a semi-porous clay conduit. In times like these, there is not much sympathy for the utility, and they may even be held liable for losses.

The pain of unforced errors

The United States has over 2.35 million miles of gas distribution networks. Data from the Pipeline and Hazardous Materials Safety Administration (PHMSA) in the US shows that over 38% of incidents reported by gas distribution pipeline operators since january 2010 were caused due to reasons other than ‘excavation’ and ‘other outside force damage’. Every two or three years, when it appears that these seem to be brought under control, we see a spike that reverses the gains made by the industry. This indicates that factors like age of construction, methods of cyclic inspection, successful technology pilots, and changes in perception of risk might be at play.

Trends aside, these incidents also trigger greater media attention and generally incur a high cost in terms of restoration efforts, compensations, and regulatory costs. Regulators and other stakeholders are asking distribution companies to modernize their systems and processes by enhancing cyclic inspection methods with more real time monitoring and incident prevention. Technology like SCADA has always been at the disposal of pipeline operators, and being able to make actionable sense of all the data and prioritize maintenance dollars to the right cases is the current challenge.

If it could speak what would the network tell you

Even among the utilities that have SCADA systems, there are a few shortcomings in the use of the SCADA information, such as trends and alarms to detect and prevent problems. Firstly, SCADA systems may not extend to all levels of the network. The primary reasons being cost, and limited availability of power and communications. Secondly, there is either too much data or too little useful data returned to operators to allow them to take actionable decisions.

What happens today?

Telemetry data that is captured by the SCADA system has preset alarm levels (set manually) and any breach attracts the attention of the control room staff. An operator calls a technician to visit the site and determine if the repair requires a work order or if the alarm was caused by an acceptable deviation from the normal operating state. While communicating with the technician the control room has to relay all related information about the site and the field device so that the technician is able to proceed directly without needing additional assistance. This is also true for additional findings that the technician needs to relay back from the field. Logs are manually maintained and actions are based on the experience and judgement of the parties involved. Actions include combinations of resetting the alarm, emergency fixes on site, scheduling a larger piece of work, or modifying alarm setting.

Combining the strengths of digital technologies

Low power IoT (Internet of Things) sensors are now very economical, and these are available with batteries or solar power packs additionally, the cost of communication devices, services and overall maintenance of devices and sensors makes IoT an efficient extension of telemetry systems like SCADA. These devices can capture a variety of parameters and can also be remotely configured to change the measured parameters or the rate of sampling.

In the same manner as a data scientist works with a sample data pack, strategically placed devices coupled with an intelligent IoT management system can enhance the picture that the SCADA system provides. Enabling temporary verbose logging under critical conditions allows for a more detailed picture of the behavior of a part of the network.

IoT on its own brings in several benefits that include access to cost-effective monitoring feeds and ability to measure a variety of parameters. But combined with other modern technologies such as big data analytics and artificial intelligence (with machine learning), it forms the basis of intelligent network monitoring. These technologies are mature, accessible, easy to implement and affordable. Big data analytics allows the utility to combine data from IoT, SCADA, other OT systems, asset maintenance, engineering and planning, weather, and geology to produce meaningful insights. Artificial intelligence works its way through problem scenarios making increasingly accurate decisions and triggering the next course of action.

“One of the key challenges of our distribution business is to be able to identify and locate our facilities after they are installed. As a part of track and trace ability proof of concept, our team utilized the beta version of collector app with the help of Wipro which was tested for the first time in the industry.” – Rick Dion, Manager Construction, Avangrid

The future with intelligent pipeline monitoring

• Trend based predictions and anomaly detection

An intelligent pipeline monitoring system would continuously look for patterns and be able to trigger an action as soon as it sees a known set of events that are likely to lead to a failure in the pipeline network. It would be self-learning, adding new patterns and improving its ability to detect matching conditions. Anomaly detection systems would look for uncharacteristic deviations that might help identify a different type of problem.

• Intelligent decision making and automated action

Using artificial intelligence, problem resolution evolves to automated action that includes opening and closing of valves, triggering fire suppression systems, scrambling crews, triggering public alarm systems, notifying government agencies and emergency services and diverting resources such as tools, spares, and vehicles from non-critical work. These decisions would be instantaneous and dependable.

• Intelligent network optimization

While to some extent self-healing is covered above, intelligent pipeline monitoring allows the utility to go even further by allowing the network to optimize itself. This occurs in two stages. In the first stage automated feeds would update engineering and planning systems for design parameters such as constraints and tolerances. In the second stage the network would operate like a fully autonomous robot, actively operating control systems and dynamically modifying settings, in response to supply and demand, market trends and weather forecasts. A robot that has the intelligence to deliver the perfect outcome in every situation. A robot that serves aces.

About the author:

Dinesh works at Wipro in Texas, with a specific focus on utilities in North America. He helps clients evolve and modernize their businesses through digitalization and through leveraging new capabilities of the smart grid. Dinesh has almost two decades of experience spanning across consulting, engineering and sales in the utilities, renewables, and sustainability sectors.

He can be reached at: dinesh.rajan@wipro.com

Ameren Illinois will use ABB Ability Ellipse Asset Performance Management to optimise asset management and increase power reliability for one million customers.

The software solution will allow the energy company to better predict and prevent the failure of mission-critical equipment under the firm’s multi-million dollar grid modernisation project.

The solution will eliminate manual regularly scheduled “check-ups” to maintain grid infrastructure.

The technology uses sensors, data and advanced analytics to constantly assess the real-time condition of assets, determine when they might need repair or replacement and alert the stakeholders. This allows utilities to prioritise short- and long-term maintenance needs and drive productivity, safety and return on investment from critical grid assets.

“We are investing significant resources to modernise the grid, improve reliability and deliver value for our customers,” said Ron Pate, senior vice president, operations and technical services, Ameren Illinois.

The solution will be complemented by existing ABB transformers, Ability Network Manager, Supervisory Control and Data Acquisition/Advanced Distribution Management System, Ability Velocity Suite, ABB Ability PROMOD and ABB Ability distributed control systems, deployed by Ameren Illinois.

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Product Category: Electronics equipment EMD Amount (INR): 11,000 Tender Type: Open tender Bid Validity(Days): 180 Period Of Work(Days): 60 Location: Cwprs pune Document Download Start Date: 07-aug-2018 05:30 pm Document Download End Date: 04-sep-2018 11:00 am Bid Submission Start Date: 08-aug-2018 09:00 am Bid Submission End Date: 04-sep-2018 11:00 am Bid Opening Date: 07-sep-2018 11:00 am Pre Qualification: Please refer tender documents. Eligibility Criteria : Please refer Tender documents. EMD value : INR 11000 Document Purchase Start date : 07 Aug 2018 Document Purchase End date : 04 Sep 2018 Opening date : 07 Sep 2018

Deadline: 4 Sept 2018, 11.00 AM

Tender notice no: 51/2018-19 ID:2018_CWPRS_369867_1

Contact details:

Central Water and Power Research Station
Khadakwasla, Pune-411024
Maharashtra, India

Telephone: +91(20)24103200/ 24380511/ 24380825
E-mail: director@cwprs.gov.in

http://cwprs.gov.in/ 

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The report, SCADA Market – Global Industry Analysis, Size, Share, Growth, Trends and Forecast 2014 – 2020, states that within the electrical power sector market growth will result from increasing numbers of SCADA systems which are being deployed in countries like India and China to reduce power transmission and distribution losses.

Within emerging markets, process automation amongst industry verticals like water and wastewater management have been a big driving factor of the SCADA market.

SCADA markets are also being stimulated by the renewed interest in shale gas extraction.The existing supply and demand gap in the oil and gas sector has increased the need for efficient search and extraction of oil and gas.

Demand for SCADA systems is set to rise during the forecast period, as rising numbers of industries aim to acquire data from remote devices such as pumps, transmitters; valves etc. and provide overall remote control from a host software platform.

This competitive landscape is stimulated by the various business strategies adopted by major industry players and their recent developments in the field of SCADA.

Further, the report includes the market attractiveness analysis of different components and architecture of SCADA systems and insight into the major end use area of the systems.

Some of the leading players in the market include ABB Ltd (Switzerland), Honeywell International, Inc. (The US), Schneider Electric SE (France) and Afcon Holdings Group (Israel) among others.

The report provides assessment of different trends, drivers, restraints and opportunities that are impacting the global market for the forecast period of 2016 – 2024.

Based on components, the market report has been segmented into human machine interface (HMI), programmable logic controller (PLC), SCADA communication systems, remote terminal unit (RTU) among others. By architecture, the market has been segmented into hardware, software and services.

The global SCADA market, by end use industry, is segmented into electrical power, water & wastewater, oil & gas, manufacturing, transportation, telecommunication, chemicals, food & beverages, pharmaceuticals and others.

By geography, the market is segmented into North America, Europe, Asia Pacific, Middle East & Africa (MEA) and South America.

Both sample and complete reports are available for upon request.