The IEC 61850 standard suite provides the digital communications foundation that utilities need for DA applications such as fault location, isolation and service restoration (FLISR), which can play a pivotal role in improving standard reliability metrics.

To deploy FLISR and other IEC 61850 applications, utilities need a field area network (FAN) with extensive cellular wireless coverage across the feeder domain in the distribution grid. The FAN must also be resilient and highly reliable so that it can support uninterrupted FLISR in the midst of a storm.

IEC 61850: Standards-based communication for grid automation

The trajectory of IEC 61850 can be traced back 20 years. In 2003, IEC Technical Committee 57 published the first edition of the IEC 61850 standard, which aimed to enable the open and interoperable digital information exchanges required for substation automation applications.

As the needs of power utilities evolved and demand for automation grew, IEC TC 57 expanded its scope beyond substations to enable automation across the grid. Today, utilities can use IEC 61850 for automation between substations, for automation between substations, control centres and data centres, and for DA in the feeder domain. 

This is a significant development for utilities. For example, having the ability to automate protection, monitoring and operations in the feeder domain of distribution grids allows utilities to improve service reliability, operational efficiency and sustainability. 

IEC TR 61850-90-6:2018 defines use cases for typical DA applications in the feeder domain that require information exchanges between two or more systems, including FLISR, fault indication and reporting, centralised voltage and var control, anti-islanding protection, automatic transfer switch, energy flow monitoring and intelligent electronic device (IED) configuration. It also provides guidelines for the communication architecture and services required to support these use cases.

Using FLISR to improve distribution grid reliability

FLISR is one of the more interesting DA applications. When a fault occurs in the feeder domain, FLISR aims to quickly locate and isolate it in the feeder domain to maintain safety, minimise the duration and impact of power interruptions, and improve the reliability of the grid.

The benefits of FLISR have been well recognised. Back in 2016, a US Department of Energy study on DA revealed that FLISR can reduce the number of customers interrupted (CI) by up to 55% and the number of customer minutes of interruption (CMI) by up to 53%. However, with severe weather events causing widespread disruption on an increasingly frequent basis, FLISR has quickly attracted more attention from utilities and government regulators seeking to keep the lights on.

The beauty of FLISR is that it is a smart, self-healing application that restores power without human intervention.

For example, when a tree branch falls on a feeder circuit and causes a fault, the FLISR application detects it and identifies its location, then uses smart self-healing logic in the FLISR controller to safely bring power back to customers. The FLISR controller, which is typically integrated with the advanced distribution management system (ADMS), geographic information system (GIS) and outage management system (OMS), restores power by reconfiguring the line switches to connect homes outside the affected circuit section to another substation.

FLISR deployment comes in different flavours, as explained in IEC TR 61850-90-6:

• Based on centralised control: When a fault occurs, the main breaker trips, recloses one or more times, and then remains open. Information transmitted to the control centre helps the system or operator locate the fault and then send commands to isolate it, reclose the feeder breaker and restore power to the healthy upstream feeder section.

• Based on distributed control: The feeder equipment controller locates and isolates faults and restores service to healthy sections based on information exchanges among the IEDs that control the main breaker in the substation and the sectionaliser switches in the feeders.

• Based on local control: When a fault occurs on a feeder, the sectionalisers react to it by autonomously opening or closing according to local overcurrent or voltage measurements. The decisions are made locally, although there are communications with the master station.

Regardless of which flavour is adopted, communication over the FAN is critical. If the FAN communication paths are broken or disrupted, FLISR will fail to restore power. To take full advantage of FLISR and other DA applications, power utilities need a FAN that can extend resilient, multiservice connectivity across the feeder domain.

Converged FAN: The foundation for a reliable grid

Utilities cannot feasibly connect all sectionalisers, controllers and switches along feeder circuits using traditional transmission assets such as fibre and microwave. Therefore, cellular wireless is the transmission medium of choice for supporting IEC 61850 communications in the distribution grid. However, utilities that rely on multiple DA applications need service convergence capabilities in the FAN.

An ideal FAN architecture is one that combines IP/MPLS services and cellular wireless connectivity to extend ultra-reliable wireless connectivity to the grid edge. This approach allows utilities to bring IP/MPLS services to utility poles and low-voltage substations that lack network reachability.

With a converged FAN, a utility gains the ability to connect IEDs, feeder circuits or DA subsystems to FLISR and other DA applications in the substation or operations centre. The converged FAN capitalises on IP/MPLS services to support IEC 61850 communications and carry data from FLISR and all other DA applications with the necessary quality of service.

The following figure shows a FAN blueprint that supports FLISR by enabling IEC 61850 communications between feeders and substations.

To provide the strong resiliency required to ensure that FLISR can continue to operate when accidents or weather events disrupt electricity services, the FAN must have a fully redundant end-to-end communication path. It must also have scalable, feature-rich IP/MPLS wireless routers that can capitalise on these capabilities.

Find out more

Explore our IEC 61850 resources to learn more about how the Nokia converged FAN can provide the resilient multiservice connectivity you need to support FLISR and other DA applications and use them to make your distribution grid more reliable, efficient and agile.

Join us at the 2023 UTC Telecom & Technology Conference in Fort Lauderdale, Florida, to learn more about taking IEC 61850 wireless. I will be speaking on this topic with my colleague, Rob Wright. We hope to see you there! 

About the author

Hansen Chan is an IP Product Marketing Manager with a special focus on digital industries and government. He has worked with telecom service providers and critical infrastructure network operators worldwide for more than 25 years on protocol testing, network design and consulting, and product management. When he’s not talking networks, he’s reading up on history and religion, and listening to Baroque and 20th century classical music.

Tweet him @hchan888

The smart meters are intended for Hidrandina itself as well as for the other members of the Distriluz group, Electronoroeste, Electronorte and Electrocentro, which together distribute electricity to more than 12 million people in the north and central regions of Peru.

The contract is expected to be awarded in mid-July and to extend over 2.5 years.

Smart metering in Peru has lagged some other countries in the Latin American region, notably Costa Rica and Uruguay, but has been gathering momentum as part of a broader digitalisation of the energy sector.

Have you read?
Latin America smart meter penetration to triple by 2028
Smart grid drivers in Latin America

In June 2022 Hidrandina announced the intention to pilot 10,650 smart meters in Trujillo, Huanchaco and Virú.

“A detail of the project is that smart metering is not only the meter – it is the communication, the platform and the management software, these three go hand in hand,” said Hidrandina Commercial Manager, Saúl Ayaypoma.

“The objective is to improve the management of energy losses, with these meters we will have information in real time.”

In the first part of the project, which has been completed, smart meters have been installed by Electrocentro in the transformation centres and distribution substations as well as in large customers.

Electrocentro, which also is pioneering the smart grid in Peru, in May reported completing the rollout of its distribution automation project.

Approximately 750,000 people are expected to benefit from a reduction in the time of outages due to more rapid detection of failures

Among other smart metering projects in Peru, Enel Distribución Perú has undertaken two pilots, the first of 8,500 meters and the second of 10,000 meters in its concession zone in the capital Lima and Callao.

Berg Insight has estimated a total of about 50,000 smart meters in Peru and the market to grow to around 650,000 by 2028. They expect an increase after 2024 when technical standards and a cost-benefit methodology for deployment are anticipated.

Most recently the regulator Osinerg has approved the implementation of a new time-of-use tariff plan for smart meter users with effect from September 1.

Three tariff blocks are envisaged, the base from 11pm to 8am, medium from 8am to 6pm and peak from 6pm to 11pm, with potential savings for users estimated between 5% and 19%.

This feature article was originally published in The Global Power & Energy Elites 2022

Located in Victoria, United Energy’s distribution automation initiative has marked a major milestone in the energy transformation of the southeastern Australian state.

The project, innovative in both scope and approach, was launched in 2018 and has well-positioned the utility to enable electrification and support the low carbon future that is the state’s ambition.

United Energy’s distribution automation was initiated in 2016 as an operational initiative to deliver a sustained improvement in system reliability through distribution management technology, analytics and integration with Advanced Meter Infrastructure (AMI) and other system data.

Innovation, Strategy, Design

The initiative was born out of a corporate drive for utilising technology in innovative ways to support operational excellence, higher customer satisfaction and superior financial performance. With a sophisticated approach to smart grid technology, network reliability and performance-based incentives and with the support of regulators, system-wide deployment has been undertaken across United Energy’s service territory, which encompasses east and southeast Melbourne and the Mornington Peninsula.

The programme was undertaken by the utility’s internal network analytics and information technology teams in partnership with Oracle Utilities.

Activities included upgrading the distribution management system, building a full low voltage (LV) network model, developing a mobility solution for field switching (integrated with the DMS) and implementing Oracle’s Operations Mobile Application (OMA) for fault response.

United Energy also developed a forecasting tool that utilises weather forecasts to predict the field labour requirements for fault response; as well as a fault prioritisation engine that draws on real-time travel data and customer outage numbers and locations to indicate where crews should be directed to optimise network safety and reliability.

United Energy considers that from a technology perspective, the most notable aspect of the initiative was a methodical, disciplined approach to developing and proving out
distribution automation use cases, starting with fault location, isolation and system restoration (FLISR).

This technology automatically executes high voltage (HV) fault switching where safe to do so and has restored over 300,000 customers in approximately 45 seconds since it was implemented. With FLISR, the utility was able to achieve the maximum possible performance bonus for system reliability from the Australian Energy Regulator in 2020.

Funding for the project was on a ‘pay as you go’ basis, drawing on its emerging economic benefits. “We are funding the journey with the benefits we recognise from each iteration,” explains Adam Gellie, General Manager for Service Delivery at United Energy.

“We don’t strive for ‘perfect’ – just ‘better’. We then bank the benefits and reinvest in the next best use case. That’s how we achieve excellence over time, redesigning inefficient processes and giving our control room valuable information to make great decisions.”

Gellie adds that the utility’s investment decisions are on track both to exceed the projected two-year payback and to return between five and seven times the cost over a five-year period. We don’t strive for ‘perfect’ – just ‘better’. We then bank benefits and reinvest in the next best use case.

Read the full project feature here

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After what seemed like decades of stability and predictability, utilities have entered a new era of change and uncertainty. Security threats are growing, regulations are tightening, and new technologies — from smart meters to microgrids — are disrupting long-standing
business models.

Meanwhile, consumers are demanding more from their power company, including flexible pricing and sustainable energy options. These trends have changed the game for utilities, forcing them to evolve or face diminishing growth and profitability.

Recent security incidents — both cyber and physical — have sent shock waves through the industry, spurring new regulations to avert crippling attacks on critical energy infrastructure. Yet most utilities have a long way to go to protect their grids. Isolating the network is no longer an option. The reality is that utilities need to be connected to increase grid efficiencies, improve resilience and — ultimately — deliver the next generation of services to an increasingly digitised and mobile customer base.

The growing adoption of solar, wind and other renewables has also challenged utilities to adapt by integrating these distributed energy resources into the grid. This is not a simple integration, given the challenges of implementing bi-directional flows. Meanwhile, consumers themselves are driving change by demanding more choice and flexibility from their energy providers.

To thrive in the new era, utilities will need to invest in more efficient, automated, and resilient energy grids. The industry’s infamous aging infrastructure, and graying workforce, complicates the task. Strategy-minded utilities are increasingly planning for a future based on IT and smart grid applications that require advanced telecommunications systems.

IP-based, packet-switched networks will form the backbone of these new systems, providing system interoperability and enabling a spectrum of new applications that improve grid security, control, and automation. For instance, by harnessing connected-grid technologies, utilities can continuously monitor traffic anomalies and neutralise cyber threats before they occur.

Secure wireless connectivity can help workers troubleshoot outages faster. Distribution automation — enabled by IP networks — can curb power losses. New multiservice networks can rein in costs by consolidating a mix of legacy services and protocols on a single highly efficient communications network.

These are just a few examples of what’s possible for the new digital utility.

Substation operations: Dive into substation operations and address how utility operators can improve grid reliability, meet security and compliance requirements while reducing costs in the Cisco webinar: New Deployment Options for Substation Utility Networks.
Register for the on-demand session here

Perhaps most promising (and exciting)

Connected-grid technologies will offer utilities a broad platform for innovation, helping unlock the power in the latest iterations of the Internet of Things (IoT), artificial intelligence, and predictive analytics.

Considering that utilities are estimated to have the largest collection of intelligent devices in operation, the potential for capitalising on this built-in IoT network — and the terabytes of data it holds — is enormous. The logic of the new era is clear: If utilities are going to reverse flat or declining revenues, cope with an aging infrastructure, improve workforce efficiency, and address new customer expectations, then they must place digital transformation at the top of their business agenda.

More news from Cisco

Modernising the grid with Cisco

The challenges for utilities are huge but so are the opportunities. More and more utilities are partnering with Cisco and harnessing new technologies to enable a range of modern capabilities that accelerate business transformation. Cisco Connected GridTM solutions address every aspect of the modern utility’s network operations. From the control centers and wide area networks (WANs) that provide oversight and management of the entire grid; to the increasingly complex and automated substations that form the backbone of energy distribution, and the field area networks (FAN) that link the “last mile” of the network to residential and business consumers.

Utilities are facing unprecedented challenges to growth and profitability and in order to thrive in the new era, utilities need to connect and modernise end-to-end grid operations.

Leading utilities are turning to Cisco for a full range of solutions, including grid security, WAN modernisation, substation and distribution automation, smart meters, mobile workforce collaboration, and more.

Read how the full-stack networking and cyber security solutions that Cisco has to offer can help ensure you have the digital architecture you need to deliver reliable, efficient, and safe electricity – and power continued growth and innovation.

In increasing numbers, advanced metering infrastructure (AMI), grid sensors, and distributed energy resources are being installed across the networks. Distribution automation enabled by these edge devices, is key for the system operator to maintain the grid’s integrity.

The challenge for grid modernisation is that it is a long term phased implementation utilising the technologies of the day. Commonly, technologies are based on a plethora of different standards – DLMS, G3-PLC, LTE, Wi-SUN to name a few – and backed by a slew of different types of communications networks from private to public and fibre to PLC to wireless.

Distribution automation

Multiple-use cases offer wide-ranging potential benefits for operational reliability, efficiency and system performance, as well as customer engagement and the enablement of prosumer participation in the market.

To increase safety, reliability, customer satisfaction and profitability, utilities are automating meter reads, power quality sensing and customer load profiles through automated two-way communication with the AMI.

Management of power quality throughout distribution systems is being automated with volt/var optimisation. Power restoration is automated with fault, location, isolation and service restoration (FLISR) technologies.

To integrate grids with other energy resources, distribution automation and the Internet of Things (IoT) is used to connect to distributed energy resources such as solar power generators, wind farms and microgrids.

Each of these energy resources has its own set of sensors and specialised substations, which are bringing growing volumes of data to manage and process both from their number and the read frequency as the grid management requirements have moved closer to real-time.

Utility Field Area Networking

This grid modernisation is driving intense focus in wireless Field Area Networking (FAN). Despite the aim for a single FAN, no one technology can support all of the use cases and utilities will have a variety of grid modernisation FANs, adding costs and complexities to their operations.

To simplify operations and to drive convergence within the FAN, new technologies pioneered by connectivity provider Cisco enable all of these technologies to be consolidated onto a single multi-service platform for monitoring and control of distribution networks.

The Cisco FAN solution includes technologies, products and architectures that provide new advantages in security, manageability, edge intelligence, scalability and high availability. This multi-service FAN includes a secure scalable network architecture leveraging LTE, Wi-SUN 900MHz mesh, LoRaWAN and wireline technologies all terminating in the same secure headend infrastructure.

The solution reduces complexity with unified management through the Cisco Field Network Director, which provides enhanced automation and serviceability via a zero-touch deployment and plug-and-play functionality.

With support for 10 million endpoints and a scalable headend architecture, the solution is designed to enable utility deployment of distribution automation assets at volume, speed and accuracy.

Jeffrey Tufts, Director of Global Energy Solutions at Cisco, says that there is the desire to consolidate on to one FAN technology and many projects start with this goal in mind. However, there is no silver bullet and often a FAN that was intended to be a single technology eventually grows to encompass several.

“Often a technology that supports line or pole sensors is not appropriate for real-time fault isolation use cases,” he points out.

“Cisco has worked to develop a utility FAN platform that can consolidate multiple FAN technologies into one architecture with a consistent operational model and security posture, allowing the utility to choose the right technology for the use case, geography or density while not taking on the burdensome task of supporting multiple disparate networks.”

FAN strategy

Tufts advises that a FAN strategy should support the widest array of use-cases across the utility’s operating territory with the fewest technology variations.

No single FAN technology choice can support all field use cases and utilities should converge as many use cases on as few FAN technologies as feasible. Reducing the number of unique FAN networks reduces the long term associated OpEx from support contracts, software licensing, frequency leasing and employee support costs.

A successful FAN strategy also should consider the immediate OpEx in addition to the long-term, he adds.

In the deployment phase for large-scale FANs, the onboarding of end-user equipment, FAN gateways and their corresponding power system devices is a major cost due to a large number of devices to be deployed.

Network automation has become the most adopted resolution to not only reduce deployment costs but also to eliminate human error and the OpEx associated with field remediation during Cisco’s installations.

Cybersecurity is increasingly becoming one of the most important business imperatives for utilities. Limiting the number of different FANs and architectures and their corresponding security postures reduces the cybersecurity complexity and further supports a reduction in the long-term OpEx.

Cisco’s FAN security architecture includes hardware and software certification management, firewall and malware protection and intrusion monitoring as well as robust encryption to help ensure secure network communications and edge applications.

Utility use cases

Public LTE and private mesh

In a lengthy proof of concept, one of the largest utilities in North America tested all 15 of its grid modernisation use cases and decided these could be best supported with a mix of public LTE, fibre and Wi-SUN mesh technologies from Cisco.

The utility’s architecture uses public LTE where it is available and where there is no public LTE service, it extends a private wireless network by using Cisco’s Wi-SUN standard mesh. Its entire grid modernisation architecture uses Cisco’s Distribution Automation platform to enable a single secure architecture that supports rapid technology deployment and a single management platform.

“We are seeing this scenario play out across the globe, where utilities begin their design and engineering phases with a preferred FAN technology but need to eventually adapt their FAN to encompass niche use cases that cannot be served by their primary FAN choice. It’s this adaptability to encompass multiple technologies in a single FAN that has been well received by our clients in the utility sector,” Tufts says.

Public and private LTE

Another leading large US utility has chosen Cisco to support its grid modernisation efforts via a combination of fibre, private LTE (pLTE) and public LTE. Similarly, the desire to be able to use the best technology for the use case, while consolidating on a single architecture and operational model, was the driver to this FAN architecture.

Tufts comments: “The adaptability of the Cisco FAN serves our pLTE FAN clients really well. Private LTE is growing in popularity, but it will take time to acquire frequency and build the pLTE network. Having a FAN that can be flexible to migrate from public LTE infrastructure, including frequency and SIM, to pLTE without truck rolls is an important project consideration allowing our clients to support grid modernisations with a platform that can be switched over to pLTE when desired.”

New edge technology

The emerging 5G with its high capacity, low latency characteristics is opening up a new world of connectivity of the Internet of Things. Capabilities such as network slicing are paving the way for innovative multi-service offerings via connected edge devices.

Utilities have started piloting 5G in distribution automation use cases such as substation monitoring and distributed energy resource optimisation and the technology is expected to be key to support the next wave of smart grid growth at the medium voltage level.

In anticipation of these and other advances including the emergence of Wi-Fi 6, Cisco has recently launched a new portfolio of industrial gateways and routers to unify these technologies into the FAN.

Read more on: Connecting the modern grid: Agility is more important than ever

These ‘Unite your edge’ devices, which were conceived with flexibility and scalability in mind, are intended for fixed and mobile installation in locations such as substations, poles and maintenance trucks. They are modular in design for easy installation with a rugged build to withstand the harshest environments and include built-in edge compute resources along with advanced security features such as hardware encryption.

“With the latest releases of our industrial platforms, we have introduced a level of performance, security, modularity and future adaptability unseen before in the industry,” Tufts concludes.

“We hope that this continues to serve our utility clients well as it protects their investments from obsolescence and enables a platform approach that can be adapted as new technologies such as 5G emerge.”

Visit the Cisco IoT website and discover all Cisco IoT products and solutions.

The guidelines developed for Europe’s distribution system operators (DSOs) are aimed to provide a defined set of practical considerations for procuring secure RTUs for automation of the medium voltage grid.

Grid operators are increasingly automating their MV substations and lines with distribution automation to reliably integrate renewables and electric vehicles and to remotely control the grid to recover from power outages more quickly.

This automation increases the possible impact of cyber attacks. Many grid operators already have thousands of substations and lines automated. If attackers succeed in switching off power in a large part of those, it can take a lot of time to recover.

Related articles:
ENCS and E.DSO – cybersecurity baseline requirements
Cybersecurity incident response – best practices from the US

Making sure the distribution automation system is secure is hence critical.

The requirements from the European Network for Cyber Security (ENCS) and the European Distribution System Operators’ Association (E.DSO) comprise three parts, a security architecture for distribution automation systems (for members only), security requirements for procuring RTUs and a security test plan.

The scope includes RTUs for use in medium to low voltage transformer substations, medium voltage transport substations and automatic circuit recloser controllers applied to overhead distribution lines.

The security requirements for procurement address issues including access rights and authentication, measures for effective function cryptography, operational and communications security, system acquisition and maintenance, supplier relationships and fail-secure design.

The security test plan offers a standardised plan to evaluate RTUs against the security requirements. Three phases are envisaged, functional tests and a vulnerability assessment by the vendor, usually performed during development; a review of development processes and security design by the grid operator, usually performed during selection; and a penetration test by an external lab, usually performed after the RTU has been selected.

Network security guidelines

With these requirements grid operators can use them directly in their procurement documents. By standardising the test plan, grid operators may more easily share the test reports between them. RTU vendors also can use the test reports to show compliance in tenders.

“These requirements lay a strong foundation for an industry-wide set of recommendations,” says Roberto Zangrandi, secretary general of E.DSO. “This would be a huge step forward to ensuring security of critical European energy grids and infrastructure, which can only really be achieved through a collaborative effort between DSOs and cybersecurity experts.”

Anjos Nijk, managing director of ENCS, says that up until now, Europe has had disparate security requirements due to a scattered approach. “However, this work we are doing with E.DSO has allowed for a harmonised and synchronised set of requirements, which will enable manufacturers to implement security cost effectively.”

These new requirements are the third in a series of security guidelines for Europe’s energy networks from ENCS and E.DSO. Previous releases cover electric vehicle charging points and smart meters.

Reza shares highlights like fault location, isolation and restoration, new technology streams, and industry trends towards artificial intelligence (AI), machine learning (ML) and virtual reality (VR).

These technologies are all presented on the floor, and during the event’s summits, knowledge hub sessions and round-table events.

With thunderstorms, a polar vortex and a 133-degree temperature swing between high and low temperatures, Chicago-area weather in 2019 was challenging. Yet, thanks to smart grid investments and the work of ComEd’s 6,000 people, customers enjoyed the best-ever electric reliability.

Families and businesses across northern Illinois experienced record-low frequency and duration of outages and overall reliability that improved more than 70% since 2012, when the company began investing in a smart grid. Since then, ComEd has reduced the average frequency of outages by 47% and the average duration by 52%.

Related news:
Read more news about ComEd here
Watch our interview with Terence Donnelly, President and CEO, ComEd at DISTRIBUTECH 2019

In 2019 customers also saw record reliability in the city of Chicago, where overall reliability has improved 80% since 2012.

“From greater reliability and customer options to job creation and growing businesses, our smart grid investments are delivering great value for our customers and state,” said Joe Dominguez, CEO of ComEd. “ComEd leads the nation in the delivery of clean and renewable power, with 92% of the energy provided to families and businesses coming from power sources that do not produce air pollution. With continued smart grid investments to efficiently integrate solar power and to improve reliability, we are poised to help our customers and our communities reduce local air pollution through electric transportation and other processes while producing billions of dollars in savings.”

Illinois has made significant progress toward reducing harmful air pollution and already has met 85% of the Paris Accord climate action targets.

Since 2012, ComEd customers have been spared more than 13 million service interruptions due in part to smart grid and system improvements, including distribution automation or digital “smart switches” that automatically reroute power around potential problem areas. The avoided outages have resulted in $2.4 billion in societal savings.

“ComEd employees, from line workers to engineers to customer service reps, have made it their mission to improve service for the people who depend on us. The investments we’re making and partnerships we’ve established have laid a strong foundation for the future and are meeting our customers’ evolving needs,” said Terry Donnelly, ComEd president and chief operating officer.

All of these reliability improvements have come while monthly bills remained flat. The average monthly bill for a residential customer is under $83. In 2012, the average monthly bill was $84 per month. If ComEd were a state, its electricity cost as a per cent of median household income would be lower than anywhere but Utah. At 1.4%, the percentage of household income that the average ComEd bill represents compares to a U.S. average of 2.3%.

In addition to producing record customer satisfaction levels, strong power reliability and Illinois’ competitive electricity supply market help attract businesses to ComEd’s northern Illinois service territory. Last year, the GridWise Alliance recognized Illinois as the No. 2 state in the nation for grid modernization.

“ComEd’s track record of providing strong reliability along with Illinois’ competitive energy prices are important components of a thriving regional economy,” said Jack Lavin, president and CEO of the Chicagoland Chamber of Commerce. “We are pleased to see year-over-year improvements in the performance of a critical piece of Chicago and northern Illinois’ infrastructure.”

Itron will provide the utility with an advanced metering infrastructure network, 40,000 smart meters and energy prepayment management platform.

Read more about Itron here

The AMI will be deployed in the city of Cotonou to help SBEE reduce energy losses and billing errors.

Related articles
Rocky Mountain Power selects Itron for grid modernisation
Benin installs its first advanced distribution management system

Itron will provide project management, training and support to the utility as well as integrate IPMP as a Software-as-a-Service (SaaS).

AM Afrique, a user of the SaaS jointly with the SBEE, will operate the system and will assure the data exchanges with other internal systems of SBEE (e.g., billing and customer management systems).

SBEE provides energy to more than 600,000 customers and is confident its partnership with Itron will help improve its cash flow.

Customers will be able to pay their bills through a self-service internet portal, Android-based point-of-sale terminals and smartphone applications.

The project is the foundation for the Benin utility to deploy distribution automation applications to strengthen the resilience of its grid in future.

Smart meters is a hot topic set for discussion at African Utility Week and POWERGEN Africa conference. Click here to register to attend or for more information about the event.

 “We have a growing number of customers who utilise prepayment for electricity, and we are excited to implement Itron’s network technology and prepayment solution to equip more customers to take advantage of prepayment in order to improve delivery, efficiency and reliability,” said Adjamassouhon Wilfrid, project leader at SBEE.

“By collaborating with SBEE, Itron will make prepaid electricity accessible to all of the utility’s users, while enabling them to reduce losses and gain greater awareness of its distribution system,” said Babacar Diba, area vice president, Africa at Itron. “By harnessing our software and hardware, SBEE will be able to realize outcomes that help modernize its electricity infrastructure enabling greater end-customer satisfaction.”

With over 1 GW of DER capacity now part of the regional electricity grid, including over 1,100MW of private rooftop solar (owned by over 160,000 residential and commercial customers), hundreds of utility-scale DERs are now interconnected. As more customers install solar and other distributed resources, it has become increasingly critical for SDG&E to understand its customer load on a more granular scale, both current and forecasted, so operational decisions can be made to ensure reliability and safety.

SDG&E distribution system operators needed to know where the DER was connected and how they impact the demand curve. To provide full operational visibility for each generation resource on the distribution grid, the utility developed real-time and proactive forecast models for each DER asset and customer load. The multidimensional profiles account for the location, weather, solar incidence, condition of use, and other attributes unique to the load and DER asset.

These DER models work with real-time distribution power flow to provide a current outlook and future look-ahead into SDG&E’s distribution operations as part of our Advanced Distribution Management System. The implementation of these models were inspired by the underlying problems associated with distributed energy resources, which by nature are intermittent and often not visible to grid operators because they are
owned by third parties.

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

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

As the second in a series of security guidelines for smart grid components, these mark an important stimulus in improving and harmonising the security of smart grid devices across Europe, helping to build a more resilient ‘grid of grids’.

The requirements provide European distribution network operators (DNOs) and distribution system operators (DSOs) with a practical set of considerations that can be used totally or partially when procuring and testing SMs and DCs.

• Read more about cybersecurity
• Read more about smart meters

ENCS has been active in smart meter security since it was established in 2012. Having started by analysing vulnerabilities in the smart metering protocols and effectiveness of certification approaches, ENCS publicly launched its first set of SM security requirements for Oesterreichs Energy, guiding the whole of Austria towards a secure smart meter roll-out. 

Building on this approach for various countries across Europe, ENCS developed its unique requirements-based security testing method. Unlike traditional testing based on attempted tampering, the ENCS testing approach evaluates the actual security level of components against the requirements, and provides objective feedback to the manufacturers, helping them to improve the security level of the devices. 

Over four years of testing and improvement, ENCS has witnessed a considerable increase in the security level of the current generation of SMs and DCs. 

Nuno Medeiros, Chair of E.DSO Cyber-Security Task Force, stated: “Utilities can use the requirements as a baseline tool for risk mitigation, supporting their risk management strategies.”

Integrating the expertise of key industry stakeholders, the new guidelines are already being applied by Austrian, Bulgarian, Czech, Dutch, Estonian, Portuguese and Swedish DSOs for procurement and security testing purposes. 

Anjos Nijk, Managing Director of ENCS, stated: “With harmonisation of smart meter requirements we have moved away from the scattered approach that saw disparate security requirements spring up across Europe.”

“As more grid operators across Europe use this same requirement set, it incentivises manufacturers to improve security. This then helps raise security standards across the industry. We aim to replicate this approach in other areas where the industry needs to structurally increase and harmonise security levels, such as in electric vehicle charging and distribution automation”.

Speaking on the development of security measures for smart grid devices, Joachim Schneider, Chairman of the Technology Committee of E.DSO commented: “Traditionally, grid operators have looked to manufacturers to implement security measures in components, but manufacturers have waited for the operators to tell them what they needed rather than invest in the wrong technology. With these requirements, ENCS and E.DSO break the impasse, and we can all move forward as a more secure industry.”

The new requirements build on ENCS and E.DSO’s recent leadership pledge on smart grid cybersecurity, and on their memorandum of understanding signed in 2016.

Hancock-Wood Electric Cooperative has selected Sensus to deploy an AMI solution and distribution automation capabilities to cut down grid operation and consumer energy costs.

The project is expected to increase the utility’s grid reliability and efficiency in addition to reducing outages.

Andy Wiles, SCADA technician at Hancock-Wood Electric Cooperative, said: “With 13,000 meters and 1,800 miles of line to manage, we knew there had to be a way to improve reliability and streamline the process.

“With DA, we can monitor and maintain the voltage at a pre-determined threshold. This can allow us to save money by optimising our costs related to purchasing energy.”

Ryan Goolsby, senior engineer at the utility, added: “We went from getting one meter read per month to 3,000 per month with the Sensus AMI system.

“It instantly removed so much guesswork for our technicians as they monitored and managed meters.”

The research firm forecast up to $27.8 billion in investments will be directed towards advanced metering infrastructure in the emerging markets between 2019 and 2023.

A further $33.1 billion will be invested in additional smart grid infrastructure including distribution automation and battery storage, during the forecast period.

Half of the emerging countries investigated in the report have already started large-scale rollout of advanced metering infrastructure projects.

Other key findings of the report include:

1. At the start of 2019, there were 54.7 million smart meters installed across the 50 countries
2. The total base of installed units will reach 323.6 million over the next five years
3. The majority of instalments will be in China and India
4. Excluding China and India, the remaining economies are expected to deploy 109 million units by 2023
5. There is a growing frequency of vendor and third-party financing within the market
6. Chinese vendors are moving into new markets
7. Supply chain shortages could hinder growth
8. Continued decline of per-endpoint costs across all markets

Steve Chakerian, senior research analyst at Northeast Group, said:  “Emerging markets are building on growth from recent years.

“Large-scale rollouts are now underway in Malaysia and Mexico, major tenders are expected in Egypt and Saudi Arabia, and deployments have been steady in Central & Eastern Europe, among other regions.”

 The study explores market trends in Latin America, the Middle East, Africa, Central & Eastern Europe, South Asia and Southeast Asia.

For more information about the report, visit www.northeast-group.com

The solution will provide the utility with conservation voltage reduction and phase detection capabilities to improve customer services, the reliability of grid network and its management.

The rollout follows a successful pilot which began in 2016 in partnership with Sensus.

The pilot included the deployment of 10 base stations which use intelligent electronic devices to collect and analyse data regarding the operations of grid assets.

Data acquired can be used to save money and lower rates for customers by allowing the utility to operate devices in real time to improve reliability and efficiency.

Dan Zaccagnino, senior engineer, NV Energy, said: “We put together a business case and after reviewing power quality before and after the Distribution Capacitor Automation Project (DCAP), we determined that we could deliver an average saving of $1.75 million per year, which we transfer to our customers through a reduction in fuel and purchased power.”

NV Energy had since 2009 started an advanced metering infrastructure project to improve its energy billing through automation of meter reading and data processing.

The project included the deployment of the FlexNet Communication Network to provide connectivity to some 1.3 million smart electric meters.

“With a coverage area that includes mountains, deserts and cities like Las Vegas, we needed a versatile network that could communicate with meters across varied terrain.

“We believed the Sensus FlexNet system would provide us with a secure and reliable network to give us a clearer view of our customers’ usage, and that’s proven to be the case.

“We’re always trying to do things to improve the lives of our customers. That means proactively undertaking initiatives that will result in lower rates and more efficient service.”

Conelectricas, comprising of four utility cooperatives, will deploy Itron’s OpenWay Riva IoT solution.

The solution will include the installation of 250,000 smart meters over the next five years.

Itron is partnering with ITECNA to implement the project.

The Software-as-a-service offering, which includes back-office and edge analytics applications will help the utility cooperatives improve services to 980,000 customers.

The smart meters are expected to help operational costs and non-revenue electricity.

The project will provide Conelectricas with the ability to remotely connect and disconnect devices to improve processes, avoid truck rolls and enhance the quality of service for electricity customers.

Consumers will be able to improve their energy efficiency through access to real-time energy usage data via an online portal.

The cooperatives will also be able to add smart city applications such as distribution automation, electric vehicle charging and smart water metering.

Erick Rojas Salazar, general manager, Conelectricas R.L. “With this solution, Conelectricas R.L. will be able to meet regulation requirements and uncover new revenue streams, such as EV stations, streetlight management, network services, energy and water usage management etc in the smart city and IoT space.”

The report defines grid edge as the segment between distribution substation and a network of distributed energy resources, including assets on both the utility supply and customer demand side of the meter.

An increase in rollout of distributed energy resources is expected to escalate the need for intelligence, control and flexibility in the distribution grid.

Grid edge computing technologies expected to lead the market include advanced metering infrastructure, distribution automation, Volt/VAR optimisation, smart inverters, and DER integration.

To date, the market has been characterised by utility efforts to address challenges caused by distribution grid asset failures, renewables intermittency, shifting loads, capacity constraints, and bidirectional power flows.

Michael Hartnack, research analyst with Navigant, said: “Digitisation technologies and strategies are pervasive in the grid and distributed intelligence is being pushed further out on the grid than ever before.

“In the long term, grid edge intelligence and automation will enable the proactive development of markets for aggregated clean resources and services; reliable, efficient, and self-healing power delivery networks; and end-to-end integrated grid management strategies.”