Sensors and Remote Monitoring Enable Smarter Renewables

by John T A Miller and Doug Young

A growing investment in renewable energy and distributed energy resources (DER) is creating opportunities also for ongoing modernization of the grid – and the effort shows no signs of letting up. System upgrades are pressing on worldwide to support the increase in renewable energy while making infrastructure smarter and more resilient.

This move from centralized to distributed power generation is spurring utilities to digitize, reinforcing the need for data collection and analysis to ensure proper operation and maintenance of these often unmanned assets. Along the way, it is increasing the opportunity for intelligent operations and planning.

According to survey results from Black & Veatch’s 2018 Strategic Directions: Smart Cities & Utilities Report, utilities rank improving reliability, integrating DER, and improving both efficiencies and analytics (tied) as the top three challenges facing distribution systems today, underscoring the need for upgrades that will address those issues and more (Figure 1).

To assimilate DERs into the generation mix, utilities are turning to the Internet of Things (IoT), using advanced communications networks, sensors and remote monitoring capabilities to see what’s happening in real time, and respond quicker. Through the integration of communications, technology and data analytics, utilities can make intelligent decisions and use automation to become more efficient. Overall, lessening disruption while enhancing optimization, reliability, security and safety.

UNLOCKING EFFICIENCY WITH DATA

Today, the plummeting costs of embedded sensors encourage increased use. Placing signal devices in a myriad of things — electric meters, field equipment including capacitor bank and recloser controls, and solar and wind controls — directly informs when repair and replacement is needed by allowing operations and maintenance personnel to collect data such as vibrational anomalies or spikes in energy usage or changes in voltage. Sensors also allow vendors to remotely update equipment with warranty data or recall information, allowing for greater control and accessibility.

This proliferation of sensors have advanced to enable utilities to collect massive amounts of data from their renewable installations, gracing operators with a far wider understanding of their systems and chunks of information to create actionable insights. It also opportunistically guards against disruption.

Operators of wind turbines, for instance, have been able to leverage data from those towering machines to prevent component failures and make minor design tweaks that make them more efficient, often at no additional expense. Such departures from traditional applications hold the promise of paring operational costs and furthering sustainability by using data analytics to better understand our environment and drive greater decisions about costs, materials and the amount of energy used – or more importantly, wasted.

Utilities are interested in improving grid reliability and efficiency through the use of automation and a deeper understanding of grid operations. To achieve that, according to the Black & Veatch’s report, one-third of utilities plan to implement advanced metering infrastructure. Thirty percent expect to put in place a distributed energy resources management system, with an equal percentage looking at outage management systems. Twenty-eight percent are considering new modeling tools for distribution planning (Figure 2).

Survey results show that the majority of utilities (80 percent) are planning to add smart assets as a critical component of their repair/replacement programs. Of that number, 41 percent plan to add smart assets in critical areas guided by cost/benefit analysis; 25 percent are looking at deploying smart assets as part of a coordinated data monitoring strategy, linked to asset life cycle plans; and 22 percent say they will implement smart infrastructure projects as existing assets are retired. Some 17 percent are planning for wholesale replacement of existing assets with smart assets.

Twenty percent of respondents are not including smart infrastructure implementation as part of their repair/replacement programs or capital plans.

PUTTING STRATEGY INTO PRACTICE

An emerging trend among utilities operating in the DER space is the narrowing focus on determining the appropriate level of monitoring and the corresponding economic investment. The question becomes: What is the right level of monitoring from a cost and production standpoint?

Let’s look at an example of solar. Typically, plants monitor at the inverter level because inverters are the most common point of on-site failure, and it’s the first level of observation. Inverter data can provide critical performance metrics such as power lost during DC to AC conversion, or fault code information for remote troubleshooting.

At the utility scale, the growing trend is to build large plants using smaller inverters (string inverters). For example, instead of using one 2MW inverter, a plant would use multiple 100kW inverters. Building large plants using smaller inverters offers the ability to communicate on a much smaller level while also delivering operations and maintenance (O&M) and production benefits. Failure on smaller inverters also means smaller losses. However, from the financial perspective, it does not always make sense to repair each individual inverter — rather, it is more economical to repair inverters in batches. The fix has to pay for itself.

Other levels of monitoring take an even closer look. Subarray monitoring on larger systems takes it one step deeper, providing greater visibility to identify issues at the string or module level. Specific subarray or zone monitoring breaks apart an inverter’s array into smaller metered arrays, allowing for easier identification of strings and areas of the array without investing in costly site visits and/or analysis.

String level monitoring offers even more granularity. Used by utility-scale PV plants to detect low production and potential energy loss, string monitoring combines 20 to 30 modules per string. These groups of strings then are combined in “smart combiners,” which monitor each string or pair of strings independently to collect data and send it to the monitoring system for software analysis. This level offers the most detailed level of surveillance and can identify underperforming strings.

Although these levels of monitoring offer minute details, large-scale plants might not need that level of information. A large solar PV plant, for instance, could have 300,000 modules. One individual module is 1/300,000th of the system. So, does it make sense to monitor each individual module? By comparison, small DER installations such as a residential solar system rely on micro inverters that provide input on every single module in the system.

ASSET MANAGEMENT CRITICAL TO INTEGRATION

While more utilities are looking into comprehensive programs that outfit equipment with sensors and remote monitoring systems, this year’s survey results reflect an industry still determining how technology and networks will work together in the modern grid. Many survey respondents were unsure of how all the elements will play together. Many utilities, for example, already have enhanced monitoring in place but are not using it to its full potential.

Data from enhanced monitoring can be used to make informed business decisions; today, only a meager 17 percent of utilities are not using smart monitoring to track asset condition or performance in any capacity (Figure 3).

Planning and preparation will be critical before starting any type of integration. Enhanced or “smart” monitoring still is relatively new to the utility industry, and it will require a firm commitment to asset management efforts.

Asset management programs are designed to align people, processes and technology to improve operations and create cost efficiencies, enhance service levels and extend asset life. Formal asset management efforts use data to inform business decisions on the basis of risk, or the likelihood and impact of potential asset failure. However, data is only useful if it provides the right information to the right people. Data must be actively used to monitor current operations and identify trends.

Although integration is specific to the utility’s needs and generating source, utilities across the board need to ensure that all assets speak the same language and are on a common, compatible platform. For example, when one system uses fiber optics, another goes with Ethernet, and a third RS 485, integration can cost more than the value of the information received. Furthermore, the method and reliability of data communication requires careful consideration.

Before integration, utilities will need to thoroughly understand their assets, and ask themselves some critical questions:

– What is the configuration of the DER system?

– Where is this DER asset located, relative to the electrical distribution and communications systems?

– What are the critical assets?

– How old are the assets?

– What is the condition of the assets?

– How are budgets for these assets best spent?

Once asset management is in place, utilities will need to understand how to analyze the data. Today, new combinations of innovative and traditional technologies such as Black & Veatch’s ASSET360® data analytics platform are giving utilities the ability to manage data with greater planning and operational complexity.

The cloud-based ASSET360® platform captures, integrates and analyzes data from infrastructure systems, assets and devices. By providing this type of analysis, platforms such as this allow utilities to make quick, actionable insights to improve operations and support future planning.

ADDRESSING CHALLENGES

The path to grid modernization is no doubt challenging. The ability to support a high penetration of ubiquitous sensors, automated controls and DER within the current distribution system requires focus on many levels. Survey results show that 49 percent of respondents report system stability as the biggest obstacle, followed by troubles with analyzing DER load flows, business modeling and standardizing interconnections.

A Data Tsunami

It’s well recognized that IoT can drive efficiencies and optimize processes. That said, IoT’s ability to capture huge blasts of data through sensors leads to one major challenge — how does an organization structure that data, and more importantly, distill something usable from what is effectively a “Data Tsunami”?

This is a significant, even daunting proposition, and utilities vary with their level of data integration abilities. Some have developed detailed plans to direct data to specific areas within the utility; others struggle with the concept of using operational data for something other than where it is coming from. For example, data can bring about a turf battle between IT and OT. Operational data (e.g., percent of energy remaining) is collected by battery sensors through SCADA systems. This data must then pass to those responsible for making energy purchase decisions, and then to billing in the IT systems department.

Utilities are in various stages of interconnecting these technologies, but those that master this union and nimbly collect and process vast amounts of data hold the edge. This challenge demands a strategy for structuring information, applying analytics and extracting knowledge to harness data’s value.

The Communications Gap

As these data collection systems evolve and become more efficient, they require reliable, robust communications systems to send information back to the central office or SCADA system. Unfortunately, the move to more advanced grid technologies can be hampered by the capacity and capabilities of current communications systems.

The equipment may have aged and become outdated, making renewable integration, distribution automation or network convergence difficult to implement without more.

Survey results show that more than 58 percent of utilities believe their current communications network is inadequate, while nearly 5 percent of that group admitted not knowing where to start (Figure 4).

Protecting Against Cyber Threats

Utility leaders clearly understand the importance of maintaining security across IT and OT networks. Survey results show that 70 percent of utilities see cybersecurity and physical security as a growing “must have” to protect the influx of wireless technology and other communication devices.

But the rapid evolution of electric grids and communications networks can make it difficult to plan safeguards. As efficiency efforts drive IT and OT systems to converge, hackers can gain access to the OT infrastructure via an IT route, fueling a need for utility leaders to assess, plan and implement protection strategies for critical assets.

This position represents a fundamental shift in approach to security; where security was once set up under IT only or as a separate shop, it is now being integrated into a broader IT/OT function. Asset managers must assess their risks and adopt responsible security measures that are flexible and scalable.

Committing Human and Capital Investments

When looking to upgrade, utilities appear ready to invest the needed capital. While most utilities say they plan to invest less than $50 million in their electric distribution systems over the next three years, a quarter of respondents will spend more than $100 million (Figure 5). In stark contrast, 70 percent of the previous year’s respondents reported they were planning to invest less than $20 million.

A major challenge for utilities is that these new data analytics systems are mandating a new set of skills, requiring a different type of staffing than what was needed in the past. Two-thirds of utilities anticipate a shortage in skilled professional, technical and/or labor resources within the next 10 years.

To combat this, the majority of utilities are working to attract, retain and train new staff (78 percent), use advanced technology to automate operations and processes (54 percent), outsource specific job functions (47 percent), process and/or organizational re-engineering (46 percent), and implement knowledge management systems (42 percent).

PLANNING FOR THE FUTURE

Increasing connectivity and a growing embrace of renewable energy are driving deep change in the utility industry. While there is a growing understanding that “smart” monitoring systems deliver unparalleled levels of scrutiny and increased awareness, utilities must be aware that these networks are best served with a holistic and integrated systems approach, rather than focusing on the separate components of the generation and distribution process.

Although system reliability and efficiency remain the top priorities, utility managers in the U.S. are planning accordingly and reimagining these priorities in a much more distributed paradigm.

Authors

John T A Miller is the solar technology manager for Black & Veatch. He has spent the last 15 years focused on sustainable technology, energy and infrastructure. Doug Young is a project manager and lead engineer with Black & Veatch. His specialties are in SCADA design, automation, protective relaying and electric metering.