By Rod Walton, Senior Editor
AMI is here to stay FYI. Without context sometimes it’s TMI and certainly no LOL matter for the utilities trying to make sense of it.
Nearly half of the world’s utilities have rolled out smart meters to their customers, promising greater ability to craft tailor-made energy use solutions, save money via efficiencies and plug the once analog and basic HVAC and appliance worlds into the digital array of the Internet of Things. Advanced metering infrastructure (AMI) is linking utilities and their customers to a real-time data revolution.
The future is wide open, but this wide-eyed optimism doesn’t really convey the stone-cold complexities that AMI systems pose for their owners. No matter how advanced things are they still malfunction or they (rarely) might be calibrated just a click or two off. Sometimes they simply cost more to operate than expected.
Utilities must deal with it all. How do utilities and their AMI vendors best go about maintaining and operating their systems once they are installed and in long-term operation?
“Yes, it can be done better,” said David Kreiss, managing director for San Diego-based AMI Operations Consulting LLC. “Most utilities do not have a centralized AMI operations center staffed with folks that maintain high levels of reliability. Without the center security risks are higher and addressing non-responding meters is much slower.”
Six of One, Half-Dozen of the Other: Pros and Cons of AMI
• Eliminating manual meter reading
• Better system monitoring
• Reducing peak usage
• Real-time data
• Delaying or cutting need for new generation
• Managing appliances
• Potentially negative customer response
• Challenge to manage and store all that data
• Cybersecurity issues
• Long-term financial and maintenance commitment
• Lack of software integration across business units
• Potential inaccuracy
Global penetration of smart meters is expected to be 800 million installations by 2020 and could approach or exceed 1 billion within the next 10 years. Truthfully, smart meter technology has been around since the 1970s in the form of automatic meter reading (AMR) and shifting to AMI.
Ken Polarek, marketing director with global power management firm Eaton, noted that the large saturation of programmable logic control AMR systems are now being replaced by AMI. The latest and greatest smart meters pulsate with a number of potential benefits in addition to billing and meter reading savings. For example, Polarek said, AMI systems are enabling integrated volt/VAR management, feeder reconfiguration, transformer loading analysis and targeted demand response.
“Today’s AMI systems include better radio sensitivity, higher power to provide coverage to less densely populated areas, continued increased data throughput for higher densely populated areas and distribution automation applications,” he said.
The pluses from AMI rollouts are universally championed by both utilities and vendors. The challenges also are multi-faceted, considering the need to manage the smart meter lifecycle. Keeping track of and coordinating so many moving parts-including meters, the communication networks, routers and collectors, data collection engines and a data management system-necessitates the need for utilities to develop technology/service roadmaps for those networks.
“More Complex Than Expected”
French consulting firm Capgemini released a report two years ago studying the various cost factors of AMI rollout, maintenance and operations. It found several unique components to those challenges, such as exceptions and error handling, logistics, meter migration and scarcity of skilled resources (Figure 1).
“The quality of the workforce, level of automation and the strength of the business processes are all important elements that will contribute to the overall total cost of ownership of the smart meter network,” Nilabja Guha, lead solution architect for smart grid solutions for Capgemini Utilities Practice in North America, said.
“The identification and analysis of AMI meter and communications issues are more complex than expected,” Guha’s colleague Peter Jansen, senior delivery executive for Capgemini, added. “Operating and analysis tools beyond those supplied by the metering system vendor are needed. These tools include GIS (geographic information system), WMS (work management system) and robust analytical applications. Utilities have found that the meter data alone is not sufficient and must be correlated and processed with a broad array of disparate data sources to provide actionable information.”
|courtesy of Capgemini|
Field workers, of course, are crucial to making sure that smart meters are installed correctly, operate smoothly and respond to disruptions in the field.
“Leading utilities have ensured that their field workers are running mobile work software tools on tablets and smartphones to help them be as efficient and safe as possible in completing critical field work every day,” Robin Cairns, smart grid product manager for Clevest, said.
The connected Internet of Things, he added, “amplifies this impact by an order of magnitude because it increases the number of integrated devices in the field from thousands or millions to tens and hundreds of millions.”
Eaton’s Polarek said most systems are designed to be low-maintenance from a field perspective. Of course, many of these were rolled out fairly recently and haven’t lived a life-cycle, yet.
“Utilities looking to proactively address issues before they become significant problems, can expand monitoring of their network and look to communication connectivity trends to improve access to real-time information,” Polarek pointed out.
Scaling Up Smartly
Commercial and industrial customers (C&I), a segment which accounts for most of utilities’ revenues, are ahead of the game in using smart meters. C&I meters provide more detailed data at more frequent intervals and capture more channels such as kilowatt hours, kilovolt amperes reactive hours (kVarh) and voltage, said Wendy Lohkamp, senior director of solutions marketing for software and services at Liberty Lake, Washington-based firm Itron.
Given the criticality of accurate C&I data capture and billing, utilities often dedicate a full-time staff and separate systems to manage those needs, Lohkamp added. Meanwhile, they are rolling out AMI for residential customers that essentially adopt the tried yet sophisticated C&I meter model.
“This increase in scale requires that many processes be automated and only exceptions are managed,” she said. “Utilities will not have time or staff to examine every meter data stream before billing. They must set up a system that allows for the capture of quality data for all meters and manage only those exceptions that prevent its use in critical processes like billing.”
Echoing Capgemini’s concerns on workforce challenges, Lohkamp warned that utilities must learn how an AMI solution will change their daily operations so they can be prepared from a staffing perspective.
“In many cases, there may be business processes that go away with an AMI solution,” she said. “However, they typically are replaced with a new and potentially different one…By going through the change management process, in advance of the solution implementation, they will be more prepared.”
The 2014 Capgemini report on the total cost of smart meters operations put it this way: “The value chain to realize the expected benefits of a smart meter program is not aligned to how a utility is organized.”
According to Capgemini, the smart meter value chain involves numerous business units, such as customer service, billing, network engineering, information technology, supply chain, and meter and field services, trying to integrate with newly developed teams.
“This siloed approach creates deferred decision-making and redundant costs across multiple budgets,” the report reads. “Like a domino effect, decisions made within one unit have immediate financial/operational impacts on another, pushing the need for greater collaboration between the business units.”
Some think the silo approach has produced disappointing cost recovery mechanisms from the “advanced” levels of the smart meter lifespan. AMI Consulting’s Kreiss, for example, is helping Southern California Edison (SCE) improve those bottom-line benefits beyond the “meters to cash” phase of the AMI.
In Kreiss’ terminology, deployment is step one and step two is “meters to cash,” in which the meter infrastructure is fine-tuned through the billing process. Step three is when the transmission and distribution (T&D) units are keyed in and connected to make sense of it all, he noted. Sometimes they’ve been left out of the pre-deployment process altogether.
“Meters to cash is easy,” Kreiss said. “Finally, T&D jumps in…they’ve got millions of (data) notes…How do we use the data for volt/VAR, distributed energy resource management, public safety?”
Those first two steps produce tangible revenue because they save money on the front end. Yet the third stage is often an afterthought.
“AMI was developed out of the customer service business unit,” he said. “Sometimes T&D is not that aware of it.”
Kreiss previously worked with Southern California Edison on its AMI deployment. Now he is helping them develop what he called their “GridMod” or grid modernization program. The idea is to take all the databases and align them with a singular engine.
“How do we bring all this together?” Kreiss asked.
Clevest’s Cairns said that AMI gives utilities a great opportunity to break those silos down and better integrate the information across business units. Yet most efforts are focused first on getting meters installed and working within the network. Using single software systems used by several or all of the business units can reduce capital and operational costs.
“In our experience, there is widespread recognition of the importance of this integration,” Cairns said. “Some utilities have been faster than others to integrate software systems and information across various business units.”
|courtesy of Capgemini|
Capgemini’s Guha and Jansen said their company thinks of “meter operations” as a group which can be organized into seven services or towers (Figure 2). Utilities, they say, need to think about these towers and find efficiencies within them.
The project phase of AMI deployment often involves subcontractors filling temporary roles. This is a valid approach meeting both experience and deadline challenges. They say, however, that once the smart meter program is in the “sustainment” mode, utilities still find themselves dependent on higher-cost subcontracted resources.
“It is important for utilities to have a long-term sustainment strategy in place early on,” Jansen pointed out. “Due to the high demand of skilled resources, utilities look toward an outsourced model to manage the smart meter network in order to control costs.”
And who’s controlling the future direction of AMI maintenance and operations? The American National Standards Institute (ANSI) and the International Electrotechnical Commission (IEC) oversee metering specifications for North America and globally, respectively. Both ANSI C12.18 and IEC 62056 were derived as the metering standards after extensive working group participation and ramifications.
Itron’s Lohkamp believes both standards are moving in the right direction to keep up with the changes wrought by AMI.
“It’s not a matter of improving the standards but rather ensuring that the standards offer more flexibility in innovations, interoperability, security and certification,” Lohkamp said.
How to make smart meters pay off smartly in the long run, and making sense of the data load, will be the challenge for many years to come. And they also have to improve safety and outage response. Otherwise, what’s the point?
“One surprise might be how well the technology works,” Cairns said. “Despite some overblown media coverage of newly deployed smart meters catching fire, AMI technology is high-performing, robust and safe.
“If data is captured and time-stamped at every step of the process, it puts informational power in the hands of operational staff to drive performance from their teams and the technology they have invested in.”