Volt/VAR Control Options and How to Leverage AMI Data

by Tom Helmer and Joseph Sottnik, Black & Veatch

Energy efficiency and operational optimization remain strong drivers for utilities implementing advanced metering infrastructure (AMI). Utilities looking to leverage their AMI technology for operational improvements are increasingly interested in voltage conservation programs. Such programs can achieve 1 to 3 percent energy savings without requiring customers to change their energy consumption behavior. This killer app provides utilities the opportunity to bolster green goals and improve financial performance without impacting customer lifestyles.

Voltage regulation is a core function of utility operations, but the widespread deployment of AMI programs has created a new technology enabler that can improve volt/VAR control effectiveness significantly. Smart grid and AMI systems have laid the foundation for improved voltage management by providing reliable, two-way communications between numerous field devices. Intelligent electronic devices (IEDs) in combination with new distribution system control centers with distribution management systems (DMS) can measure voltage from every grid endpoint and provide improved voltage controls.


Three competing approaches to implementing voltage conservation are:

1. Power system model-based centralized volt/VAR optimization (VVO);
2. Substation-based coordinated volt/VAR control (CVVC); and
3. Point solution for conservation voltage reduction (CVR).

All three approaches require the same investments in power system infrastructure, including controllable load tap changers (LTCs) for power transformers, controllable capacitor banks, controllable voltage regulators and circuit bellwether meters. A substantial difference exists, however, in information technology systems and field-level data change management commitment among the three approaches. Table 1 identifies differences and similarities.


Utilities that implement a centralized DMS (that is driven from a network model based on the daily changes to the power system network) can take advantage of their DMS vendors’ functionality. Turning on the core DMS functionality represents substantial work that might take 18-24 months to complete. The magnitude of this effort depends on the selected vendor solution and the quality of a utility’s power system network connectivity information residing in its geographic information system (GIS) and enterprise asset management (EAM) systems. The additional effort to enable VVO once the core DMS is running is typically six to nine months.

This involves tuning the DMS vendor’s VVO algorithm to meet the utility’s specific needs. Some available VVO solutions allow a utility to set multiple parameters-goals-for the VVO module to optimize. These might include one or more of the following operating objectives:

  • Reducing electric demand;
  • Reducing energy consumption;
  • Improving feeder voltage profile;
  • Maximizing revenue; and
  • Minimizing energy loss, improving power factor or both.

Other available VVO solutions allow a utility to minimize device operations to conserve set point changes and avoid wear on voltage regulators and LTCs.

Required system components. DMS core functionality is required to implement this approach. The following modules must be implemented to affect this solution (see Figure 1):

  • Distribution supervisory control and data acquisition (SCADA);
  • Online power flow;
  • Switch order management;
  • Short-term load forecasting;
  • State estimation;
  • Circuit bellwether meters: leverage investments in AMI infrastructure;
  • Circuit-level wireless telecommunications: could leverage investment in AMI infrastructure;
  • GIS: proposed and scheduled work and all as-built changes;
  • EAM: power system characteristic information;
  • Mobile work management (MWM): proposed and scheduled work and as-built field changes; and
  • OMS: abnormal conditions: device operations, line cuts and jumpers.

Benefits. The DMS with VVO approach requires a large investment. Experience, however, shows that a utility often must implement VVO at only 15 to 25 percent of its substations to justify the DMS investment.

Utilities that have investigated a substation-by-substation approach find that a centralized DMS allows them to deploy VVO on three to five more substations a year because DMS provides enhanced visibility into operations.

This approach provides many benefits in addition to VVO. These are enabled through a DMS suite of advanced applications:

  • Improved visibility and safety to manage the utility’s smart grid IED investments;
  • Improved reliability and customer service: automated switching, automated fault-location prediction, automated fault detection, automated isolation and automated restoration;
  • Improved asset management: optimal network reconfiguration (ONR), historical peak-usage durations;
  • Improved serviceability: takes into account weather forecasting, load forecasting and distributed energy resources (DER) forecasting to maximize heterogeneous DER resources, including distributed generation, electric vehicles and storage. This includes handling resource dispatching, initiating demand response programs, verifying and validating active demand response programs, and managing a networked power system grid (bidirectional flows); and
  • Enhanced sustainability: integration of GIS, EAM and MWM means VVO decisions are based on the most up-to-date version of the power system network.


Many IED manufacturers support coordinated volt/VAR control at the substation level. This approach to CVVC leverages the network’s current state for each substation.

Required system components. Beyond the power system components, this approach requires only an intelligent controller in the substation and wireless communications for the circuit in-line devices that will receive the set point commands. The required components (see Figure 2) are:

  • Substation CVVC IEDs;
  • Controllable LTCs;
  • Controllable capacitor banks;
  • Controllable voltage regulators; and
  • Circuit-level wireless telecommunications.

Benefits. This CVVC approach allows a utility to achieve conservation voltage reduction benefits soon after investing in power system infrastructure (LTCs, capacitor banks, voltage regulators). Because this approach can be implemented one substation at a time, it is relatively easy to initiate and allows a utility to realize the potential incremental energy savings.

This approach’s drawback is that as the system changes significantly or is operated in abnormal configurations for long periods, the logic on which the substation IED will be making decisions will be based on a stale network model configuration. In some instances, control center operators might turn off CVVC at the substation because many power quality issues might be generated when CVVC is working within an old or stale network model. To alleviate this problem, some IED providers offer a model build update process to try to keep the model at the substation up-to-date. This, however, requires a utility to implement business processes to ensure the model update is reliable.


Another commercially available approach to improve system voltage management is CVR. This approach takes advantage of data collected by AMI meters in a closed-loop control of system voltages. This approach requires all the power system investments of the previous two approaches but simplifies the information technology infrastructure requirements by taking more of a power system engineering approach. This scheme controls voltage through two closed-control loops. One uses substation values and in-line values; the other uses AMI metering information to provide a supervisory set point adjustment to the LTCs, capacitor banks and voltage regulators.

Required system components. The following components (see Figure 3) are required to support closed-loop CVR:

  • Distribution feeder SCADA (DSCADA);
  • LTC;
  • Controllable capacitor banks;
  • Controllable voltage regulators;
  • AMI network communications and voltage-equipped smart meters; and
  • Centralized CVR master integrated with distribution planning, DSCADA and AMI.

Benefits. The CVR approach can be deployed substation by substation. Because it uses AMI information, it adapts over time as smart meters deploy and as circuits might operate in abnormal configurations. This approach does not require a network power system model that is maintained with zero latency as the centralized DMS approach does. No model is needed because smart meters provide direct feedback of endpoint voltage. The connectivity model from a utility’s system planning tool is needed to predict voltage at an endpoint when direct measurement is not available.


Voltage conservation allows a utility to become as efficient as possible without requiring its customers to change their usage behavior. Two approaches described may be implemented one substation at a time and allow a utility to incrementally validate voltage conservation’s value. The VVO approach is a much larger smart grid investment but allows a utility to take advantage of all other extended DMS benefits. Whichever approach is taken, the results will improve system reliability, reduce power costs and potentially delay the need to procure power at peak prices.

Tom Helmer is an executive consultant with Black & Veatch. He has 30 years’ experience in solution architecture and systems integration and specializes in smart grid and pipeline integrity. Reach him at helmert@bv.com.

Joseph Sottnik is a project manager with Black & Veatch. A registered professional engineer, Sottnik has more than 30 years of engineering and information technology experience in energy and utilities with focus on AMI and smart metering. Reach him at sottnikj@bv.com.

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