Make better use of Real-Time Energy Information to improve service reliability
Hahn Tram SchlumbergerSema 6399 South Fiddler’s Green Circle, Suite 600 Greenwood Village, CO 80111 Abstract This paper focuses on how to improve service reliability and take Outage Management Systems (OMS)s to the next plateau by leveraging the real-time energy information and technologies available today. The paper extends OMS beyond existing applications that process circuit lockout events from Supervisory Control and Data Acquisition/Substation Automation/Distribution Automation (SCADA/SA/DA) and outage notifications of automated meter reading systems. It exploits the real-time data network associated with advanced Automated Meter Reading (AMR) systems to confirm service restorations quickly and without unnecessary nuisance to the customers and without increased call center or dispatching resources. It exploits the availability of real-time meter data on customer interruptions, along with the geospatial information of customers, to lessen the effects of missing or erroneous customer and network connectivity data. It exploits the real-time data of customer demand along with circuit loading and distributed generation data for emergency switching analysis to increase the effectiveness of emergency load transfers. These exploitations converge to form key elements of a next-generation OMS that is part of the overall real-time energy information strategy. For completeness, the author also discusses the use of real-time data, and historical records of it, to better plan and manage maintenance outages, to formulate more cost-effective asset maintenance plans, and to improve system planning and engineering for reducing the frequency as well as duration of customer interruptions. The Business Challenge Utility deregulation and competition along with increasing customer demand in the digital economy have forced distribution utilities to improve service quality while reducing costs. Utilities are pressed on all sides: internal business pressure due to competition and expectations from merger and acquisition activities, more stress on the bulk power system due to open energy trading and increasing transmission capacity constraints, higher and quicker customer demands of power and power quality, and greater regulatory and public demands. Utilities have to respond to these pressures in a proactive manner and rethink their overall strategy to improving service reliability (Tram and Engelken, 2000.) Using near real-time energy information that is becoming available with systems such as advanced. AMR is part of this strategy and is the subject of this paper. Improving the ROI of Real-time Energy Information The business case for AMR has changed drastically over the years, generally toward better Return on Investments (ROI) as AMR technologies evolve from monthly energy meter reads to real-time energy information management (Benassi, 2001). In the past, the justification of AMR mainly fell upon labor savings in meter reading for energy billing purposes. Today, the benefits of enhancing customer services and competitive energy trading outweigh savings from labor reduction. In addition to the fundamental energy consumption meter reading function, today’s AMR lets the utility manage energy not only at the system level, but also at the customer level. For example, for these advanced applications, it can provide:
Focus on Service Reliability Improving the energy delivery business requires a holistic view of the utility’s processes and technology utilization, from customer service and dispatch operations to engineering and planning (Tram, 1999). Hence, service reliability improvements involve two main areas: one on remedial efforts of service restoration when outages occur and the other on efforts of planning and engineering to prevent outage occurrences. The first area of improvements relates to using real-time meter data to reduce the durations of customer service interruptions and improve crew efficiency in the outage management process. The improvements are possible by exploiting the metering information through the real-time data network to:
Outage Management The following discussions explore how OMS can analyze the data acquired by AMR and put it to use to improve the customer response and service restoration processes. While few utilities have actually implemented the outage monitoring functions of AMR, many are considering them (Brown, 2000). AMR is not a substitute for OMS, and vice versa. AMR provides valuable input to OMS with automated outage notifications and confirmations of service restoration. OMS supports the management of restoration resources (crews and materials needed and where they are needed), customer communication (why the lights are out, and more important, when the lights will be back on), emergency switching design, and reliability analysis and reporting. Outage Notification AMR can let the utility know if services have been interrupted before customers call. Of particular importance is that the utility is notified without the customer being on the premises. Practical considerations in implementing the outage notification function include the latency and reliability in the transmission of the real-time data and the filtering of momentary service interruptions. Data Latency — Depending on the number of customer interruptions and the bandwidth of the data network, there may be a delay of as much as thirty minutes between the time when a meter detects a service interruption and the time when the utility operation and dispatch center receives the notification. Still, the meter data will most likely help the utility diagnose outage locations faster and more accurately because many customers will not call the utility to report an outage within the thirty-minute window. Moreover, most utility customers would see the automated outage notification as a value-added service — it protects them from spoiled food in the freezer, for example, even when they are not on the premises when the outage occurs. Reliability of Data Transmission — Common AMR meters do not include batteries, so outage notification relies on the last gasp signal sent by the meter when loss of power is detected. Due to the nature of wireless communications, the signal sometimes may not reach the utility operation and dispatch center. With the advanced trouble analysis methods in OMS products today, the percentage of customer interruption messages that actually get through is generally adequate to determine the possible outage locations in the distribution network accurately. On the other hand, the lack of data transmission robustness means that the utility will still need to rely on customer calls to determine secondary service outages to some extent. Momentary Interruptions — To reduce the data network traffic and the workload of outage dispatchers, the utility may want to filter momentary from sustained interruptions by letting the AMR system or the AMR/OMS interface wait one to five minutes to determine whether the service is restored before sending the interruption event to OMS. (The IEEE guideline for defining sustained outages is five minutes.) Outage Confirmation When processing a customer trouble call, before logging the trouble call, the utility should first confirm whether the customer premises is part of a known outage in OMS and if not, query AMR to check if the premises has service, in that order. Checking with the OMS database — When a customer calls to report an outage, he or she mostly wants to know if the utility knows about the outage and when service will be restored. This information is contained in an OMS. OMS not only has possible outages estimated based on other calls and AMR notifications, but also confirmed outages based on operational events from SCADA, the estimated time of restoration and current work status from field crews, etc. Querying the AMR server — If the customer premises is not part of a known or possible outage already determined by OMS, in cases of the customer call coming before AMR notification due to data latency or data communication problems on the AMR network, the utility should combine the call information with other customer calls or AMR outage notifications already received to help determine the more likely outage location. To confirm if the outage is on the distribution system before dispatching a trouble investigator to the premises, the utility should check the AMR system to determine if the meter is still energized during the customer call. If AMR shows a good likelihood of an energized meter, the call agent should then follow a script to direct the customer to check the house circuit breaker before sending the trouble call to OMS. Workflow Recommendation — The author recommends that the trouble call entry process query OMS before querying AMR because (1) OMS contains more information and (2) OMS typically provides faster response than AMR. In fact, when call volume is high, the utility may want to skip AMR verification to speed up the call entry process because it is more likely that the call is already part of a known outage. In the extreme case of very high call volumes during major system events or storms, the utility may want to skip both OMS and AMR verifications as part of the overflow call entry process. Trouble Analysis Another improvement that AMR would enable in outage management is reducing the reliance of the OMS trouble analysis application on complete and accurate data of network and customer connectivity. Trouble analysis involves predicting possible outage locations, or fault clearing devices, and calculating the interrupted customers based on trouble calls received from customers, outage notifications from power monitoring units and AMR, and telemetry data from SCADA and Substation and Feeder Automation systems. The objective of trouble analysis is to help the utility pinpoint the outage locations accurately and quickly, allowing faster crew dispatch and less troubleshooting travel time, thereby reducing overall outage durations and costs. While trouble analysis techniques of commercial OMS products have advanced in recent years, their practical value in operations has been limited in many utilities for lack of quality data, most notably the connectivity of customer service addresses to distribution transformers and the network (Hatfield and Tram, 2000). AMR helps alleviate the data problem to improve the practicality of the trouble analysis engines. Trouble Analysis Based on Network Connectivity — AMR equipped with appropriate real-time data communication and management capabilities can help lessen the impact of inaccurate connectivity data on the trouble analysis results. The basis for this improvement is: the fact that there are no customer trouble calls in an area would not as reliably tell the utility that the outage location must not have affected that area as much as the fact that there are no service interruptions detected from AMR meters in that area would. Furthermore, OMS can improve the confidence level of its predicted outages by querying AMR meters in select locations on the distribution network as part of the trouble analysis process. The select locations include, for example, the customer meters immediately upstream and immediately downstream from the current predicted outage location. This additional step is recommended because of potential latency and loss of last gasp messages as explained above. Trouble Analysis Based on Geospatial Information — Another improvement in trouble analysis made possible by AMR is in areas where the confidence in the quality of customer/network connectivity data is very low. To supplement the trouble analysis method based on customer/network connectivity, which is most common among OMS products today, AMR outage notification adds more data points to customer trouble calls, which can be combined with the geocodes of customer premises and device location addresses to help the utility operator/dispatcher pinpoint possible outage locations and dispatch trouble investigators. Restoration Confirmation Querying the AMR allows the utility to confirm that service has been restored without having to call the customers back. The automated confirmation process can quickly identify power still-out situations, which are common in storms due to cascading outages, and allow the utility to notify the trouble crew before it leaves the area if problems still exist, thereby increasing operational efficiency. Using AMR for the restoration confirmation function avoids the nuisance of calling the customer in the middle of the night and reduces call center, dispatch, or Interactive Voice Response (IVR) resources. Switching Decision Support In addition to outage monitoring as explained above, an OMS can leverage AMR capabilities in near real-time monitoring of customer loads, and distributed generation if available, to help utility operators develop more effective switching procedures and emergency load transfer schemes. Many OMSs today estimate transferred loads by using the connected kVA ratings of distribution transformers. This method often leads to too conservative switching, and sometimes even erroneous switching, for the obvious reason that transformer ratings do not accurately reflect customer demands — some transformers may not have customers connected at the time of switching and some may be overloaded. A few OMSs today use the transformer’s ratings or last month’s customer kWh billing data at various load points to allocate the SCADA kW and kVAR measurements at the substation to load points along the feeder to calculate line loading and voltages for switching planning. While this method is much more accurate than the first one, it does not consider the time-of-day variations of different types of customer loads. The near real-time load data captured by AMR alleviates this deficiency and improves the accuracy of the second method. Summary AMR and OMS systems have complementary but different roles, and integrating the two will elevate the capability and ROI of both systems to new plateaus. Assuming that the real-time data communication network supports AMR with adequate bandwidth, AMR can benefit outage management in many areas: outage notification, outage confirmation, trouble analysis, emergency switching design, restoration confirmation, and post-outage reliability analysis. AMR helps the utility gage the outage extends quickly and ensure that all problems in the area are fixed without having to wait for more calls from customers, often repeated calls hours later. These benefits are particularly important during storm outages when there are often cascade problems on the same circuit. References
| ||
|
|