In my previous blog post I discussed how smart meters will be supplanted by increasingly intelligent electronic devices that will make possible new and better grid monitoring and control. Now I want to discuss the concept of enhanced grid management via distributed smart metering.
While added functionality is a plus, the journey we’re now on – from electro-mechanical devices to rapidly improving digital devices – means that these devices’ useful lives may be radically reduced. That could be a shocker for an industry (and its stakeholders) that has traditionally measured useful life in decades.
If industry standards for interoperability play the role they should, and there’s every indication that this will ultimately happen, then rapid obsolescence of digital meters does not automatically equate to a full rip-and-replace nightmare scenario. Most utilities are presently locked into a full deployment of a single vintage of meters from the same vendor but, in the future, interoperability will allow utilities to mix and match smart meters, both new and old from a single vendor, or devices from multiple vendors.
Getting the advanced functionality of next generation devices doesn’t have to mean total system replacement as has been the case for most utilities that have moved to a new generation of AMI. It may not be necessary to equip every endpoint on a distribution system to greatly improve grid operations. The efficiency and reliability of a distribution grid can be improved by installing newer intelligent electronic devices at bellwether locations that provide the desired monitoring and control.
For example, locate these devices immediately upstream and downstream of all devices that may cause service interruptions – fuses, re-closers, breakers, transformers – or that require monitoring and remote control – breakers, voltage regulators, tap changers, capacitor banks, etc. Many utilities already position more advanced automatic metering at significant commercial and industrial customers. This can also enable much improved Volt/VAR optimization by being able to control voltage regulators and capacitor banks, even load management, based upon the most critical voltage location on the grid rather than the voltage where the voltage regulator or capacitor is located.
In fact, an alternative to an initial full smart meter/advanced metering infrastructure (AMI) deployment could be to create a skeletal network of smart meters at strategic points, rather than at every endpoint. This could reduce the capital cost and allow for much more rapid deployment. This sort of approach would depend on the feasibility of the necessary two-way digital communications. Hopefully, public networks could provide it. Today, especially for sparsely populated areas, public network coverage might be lacking. But we’ll eventually see ubiquitous wired and wireless broadband service to every corner of the country using a variety of technologies appropriate to the location. Again, in the same context as already discussed, even a partial deployment in those areas where public or accessible private networks are available could provide valuable improvements in grid monitoring and control.
The value of smart meters in enhancing the functionality of automated outage management systems is well known. However, they may, in fact, help a utility to prevent rather than just react to outages. The behavior of a re-closer, for instance, may be an indicator of an impending service interruption. For example, if it is operating frequently, that might suggest a need for right-of-way clearing or a bad electrical connection somewhere, or a faulty piece of equipment. If a re-closer is opening more than three times before locking out, it may indicate a problem with the re-closer itself. Now, rather than just recovering from a service interruption, a utility may be able to anticipate and prevent one. Though many smaller utilities probably do not have the resources to purchase and operate distribution SCADA, they could install and monitor smart meters upstream and downstream of the re-closer.
On the customer side, new appliances and add-on devices for existing appliances are steadily increasing capabilities for more granular monitoring and control. As appliances are increasingly equipped with on-board intelligence and Internet capability, every major appliance could eventually be able to provide voltage, current and phase angle as well as other data. And they will have built-in remote control capabilities. This is part of a brave new world known as “The Internet of Things.” It is already allowing utilities and customers to have remote monitoring and control of smart thermostats, for instance. Why not the rest of the appliances in the home or business? Or even all of the electrical appliances in the home or business? Or electric vehicles (EVs) and plug-in hybrid electric vehicles (PHEVs)? I just heard at a conference this week about a consumer endeavoring to match his PHEV charging with the output of his home PV system. Imagine on a utility-wide scale matching premises appliance control with the output of a wind farm or solar garden?
The hub for this new world of distributed metering probably won’t be the meter on the side of the house. After all, it was located there because a utility meter needed to have ready access to it to read the meter or connect/disconnect the customer. Now remote monitoring and control can do all this. Customers, especially in new “smart homes,” may actually have their own whole house and distributed metering systems. The hub will likely be an app in the cloud that provides the desired aggregate and individual monitoring and control.
I’ll leave you with one last thought: When consumers buy their automated, intelligent appliances, energy management systems and apps from non-utility retailers or virtual stores what happens when that retailer offers the customer a retail electricity provider (REP), as we now have here in parts of Texas, where I live? Or a special deal from Solar City to install solar photovoltaic panels on their roof. Or what if aggregators other than utilities (the dreaded “disintermediaries”) aggregate retail consumers’ monitoring and control capabilities and take their “negawatts” to organized power markets for sale? I’ve discussed before how technology enables disruptive forces that challenge the utility business model and distributed metering is yet another example.
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