Activating the Human Grid through Telemetry

Activating the Human Grid Through Telemetry
Tapping your crew and utility customer as a powerful source of network information

The involvement of the crew and the utility customer is a powerful untapped source of telemetry, control and general network information, not available by any other means. Furthermore, it is effective over the entire network. This human grid must be integrated into the control center ADMS systems to receive the input data and to push better visualization of the operation of the network to both crews and customers, for their benefit. Finally a smart grid technology will provide a value proposition. Not only does the human grid enable more informed decisions on the part of the consumer regarding energy usage, but also allows the utility to leverage grid-edge information to further enhance the overall efficiency of the network for all stakeholders impacted by the grid.

Challenges in Maintaining a Real-Time Model

Most smart grid solutions are centralized so application network solutions readily provide an up-to-date view of the entire state of the network. The synergistic integration of various applications relies on a common model, which is usually maintained by the utility control center.
Utilities of different sizes face different complications with respect to managing network changes. Often, smaller utilities either do not operate a control center or they do not have 24/7 support. Their crews are often small, but very experienced, so they can envision their entire network and its normal operations from a crew truck. However, without a centralized model of the network, even minor automation applications, such as peer-to-peer self-healing repair solutions, cannot recover if the feeder’s “normally open” point moves.

Large utilities face a different challenge. The network is so large that their crews cannot possibly assimilate it in real-time. Since widespread down-line automation is rare, it is difficult to maintain an accurate operating model of a large complex network. Multiple crews, working from static maps, are challenged in performing switching changes to repair outages.

In either case, the smart grid requires that an accurate model  be maintained to reflect the true operational state. All automa­tion, analysis and restoration depend on knowing the real-time operating state of all feeders. Smart grid applications often perform network changes in order to meet their objective func­tion. The optimum topology changes may not leave the feeder in its normal configuration, but rather in a non-standard topology. Non-standard configurations neutralize the crew’s experience and operational knowledge of the network while rendering the static maps as inaccurate.

The advantage of automation is that it reflects all network changes immediately in the model with a topology processor. However, the cost and time involved make widespread network automation impractical, particularly in very large networks. Manually switched portions of the network require an alternate method of maintaining an accurate real-time network state. An example of this approach is implemented on a very large utility in India with over three thousand feeders. This beneficial “human grid” application accomplishes near real-time network manage­ment cost-effectively on non-automated networks.

Analysis Tool Sets Replace Automation

Although a smart grid implementation generally automates a small area of the network, utilities who “go-live” can leverage their technology to apply to non-automated feeders. If applied properly, the quality of the switching solutions are the same for automated or non-automated feeders. The only advantage automation offers is the speed of implementation.

A tool set of analysis and switching applications can be applied through an operator’s ad hoc query evoked by selecting any feeder element. The tool set includes solutions to accomplish switching objectives, to generate:

  • restoration plans
  • isolation plans
  • “return to normal” topology plans
  • fault location plans
  •  voltage reduction plans
  • loss minimization plans

Even when applied to self-healing situations, the tool set substitutes the automatic fault location process. Once the fault is located using non-automated methods, such as with an outage management system (OMS) or distribution management system (DMS) allows a fault location (short circuit) analysis to identify the location so the utility operator can request isolation switching with load transfer quickly in a single click.

Mobile Switch Plan Generation

Without supervisory control and data acquisition (SCADA), an alternate method of switch plan execution is vital. In this case a mobile integrated switch plan manager will eliminate extra maintenance and avoid network errors.
Most control centers still manually write switch plans on a paper pad. Few control centers use a centralized switch plan application. A centralized, load flow-capable switch plan manager administers, validates, assigns and archives all switch transac­tions, whether they are manually or automatically generated and executed. The proposed solution extends the centralized switch plan manager further by adopting a tight integration with the crew’s mobile platform. The Switch Plan communicates directly with the crew just as a SCADA system communicates with front-end processors and remote terminal units (RTUs).

Using the switch plan manager, switch steps assigned to crews are sent automatically to each crew’s mobile device. The crew’s execution of each step is recorded with validation of information related to the operation, such as the device state and time of execution. The information uploaded to the DMS updates the centralized network model in a process that is analogous to auto­mated systems. This approach replaces the traditional telemetry.

Due to the inherent delay between creation and execution, the plan may no longer be accurate due to subsequent switching, placement of tags, subsequent faults, etc. The switch plan manager must include a verification feature. Verification enables the opera­tor to validate and confirm the feasibility of a new best practices plan. Any and all changes in this plan should immediately be sent to the utility crew’s mobile device.

Crew Empowerment

Two important crew mobile functions include: the ability to view a dynamic, interactive mobile task list of operational work assign­ments; and the ability for the crew to visualize the real-time state of the network. Previously only the control center operators had access to this detailed information. Displaying it to the crews enables them to validate the information and to immediately correct errors. The improved visualization increases their situational awareness during switching in normal and non-standard configurations.

Mobile visualization displays the real-time colorized network topology overlaid on a Google map. Among other features, the crew is able to view the placement of clearance tags placed by the operator in the control center. The crew can visualize the location of all active switch plans and the extent of the switching steps. Crews also have visibility of the other crew locations, network devices and fault locations. If they have the security authorization, the crews can view DMS displays, reports, or one-line diagrams.

This innovative technology provides several benefits, namely increased real-time information improves crew safety and network reliability, and confirms the network state for the DMS. These advantages benefit all feeders, even those without automation.

Customer Empowerment Improves Utility Customer Satisfaction

The purpose fulfilling the other half of the human grid is to leverage the consumer to provide outage and restoration telemetry, and in some cases, a degree of load control, since the consumer ultimately controls the load.

The recent J.D. Power’s 2016 Electric Utility Business Cus­tomer Satisfaction Study reports an important public perception: “Power quality and reliability satisfaction among business custom­ers…is highest among customers who receive outage information proactively from their utility and lowest among those who did not receive any outage information proactively from their utility.”

The astonishing conclusion is that power quality and reliability satisfaction is perceived to improve, without actu­ally installing automation improvements. When it comes to customers, for all practical purposes, their perception of a utility is in the reality of a power outage. How quickly and efficiently can a utility restore power? Furthermore, the J.D. Power report concludes that compounding “proactive communication, includ­ing using digital and social media, is key to improved business customer satisfaction with electric utility companies” resulting in an approximate thirty-three percent (33%) improvement in customer satisfaction.

The main implication is that utilities must invest in the customer experience to surpass customer satisfaction and create customer cooperation. In order to develop a deeper relationship, the utility must engage the customer with useful information on non-outage days, using the same application. For this purpose, utilities could provide information on a mobile device such as:

  • billing predictions to month end
  • budget alerts
  • bill pay
  • complex billing options
  • energy usage: green footprint reporting
  • outage visualization and updates
  • outage subscription services for special alerts on specific outages
  • street light outage reporting
  • crew scheduling

If the customer’s satisfaction and their perceived reliability of the grid can be greatly improved, with little investment in automation, the utility can transform a satisfied customer into a cooperative and participating consumer. Using direct dynamic and personal communication with the customer’s smart phone, such a consumer will be willing to enroll in new utility programs, such as Passive Load Curtailment, with little to no utility automa­tion investment in the grid.