AEP shares lessons learned from its smart grid deployment to help others avoid similar issues.
Utilities around the world are changing the way they do business to meet the ever-increasing expectations of their customers, regulators, legislatures and environmental groups. The evolution of the smart grid addresses multiple scenarios, including enhancing electrical service reliability, rebuilding or upgrading the electrical infrastructure, increasing energy efficiency, reducing peak demand, increasing renewable energy resource application in utility generation portfolios and the private sector, and reducing greenhouse gas emissions.
American Electric Power (AEP) has deployed advanced technologies, collectively referred to as gridSMART, to operate the grid more efficiently by integrating a broad range of advanced technologies on the distribution grid, utility back-office systems and consumer programs. In the development of gridSMART, the utility has worked through designs, deployment plans and challenges, and learned some valuable lessons along the way.
AEP's distribution grid management vision is to transform single-source distribution circuits into an interconnected grid with multiple sources, real-time visualization, optimization, automation and control. Where multiple circuit ties are not practical, real-time sensing, visualization and control needs to be employed. Following are details of the utility's vision:
The distribution management system (DMS) or distribution supervisory control and data acquisition (SCADA) would be deployed to provide distribution energy management, and monitoring and control of the smart system components (capacitor banks, voltage regulators, reclosers, switches, circuit breakers and sensors). The DMS or distribution SCADA would continue to evolve over time.
Distribution automation volt/VAR control (DAVVC) would be included to provide utility-controlled energy efficiency and peak demand-reduction programs from the customer to the generator.
Distribution automation circuit reconfiguration (DACR) schemes would be installed to improve customer reliability experience and optimize circuit performance.
Accommodations in monitoring and control also would be made to take full advantage of distributed energy sources, including solar, wind, storage, fuel cells, customer generation and demand response.
Advanced metering infrastructure (AMI) and customer-facing programs would be used to improve energy efficiency, improve demand response and improve meter operations efficiency:
AMI meters would be installed to allow for automated meter reading and reading on demand.
Automated connect and disconnect would be available with AMI meters.
Home area network, in-home displays, programmable communicating thermostats and direct load control, and other appropriate systems would be used.
Plug-in electric hybrid vehicles and plug-in electric vehicles would be addressed.
Customers would be able to take advantage of time-of-use rates and real-time pricing to reduce their energy use and energy costs on a voluntary basis.
Cyber secure communications infrastructure would be installed for AMI, distribution automation (DA) and DMS deployments. These systems would be continuously monitored and the security updated as needed. The DMS, outage management system (OMS) and AMI would be integrated to improve outage restoration, distribution operations and customer experience. Software integration from various vendors would be completed using the common information model and coordinated with the Electric Power Research Institute (EPRI), National Institute of Standards and Technology (NIST) and other pertinent authorities.
Based on the number of new technology installations across its service territory, AEP has developed a comprehensive library of lessons learned. Utilities and vendors planning to head down the smart grid path from engineering, technology and operations perspectives could gain valuable insight from this knowledge. Here are some to-do items based on lessons AEP has learned:
- Implementation requires team efforts
The effort utility and vendor teams put in to implement smart grid technology on the utility system is very large. It is easy to underestimate the amount of time required. Smart grid technologies require a much higher level of team coordination when commissioning the systems. Coordination includes engineering, system planning, circuit engineers, telecommunications, protection and control, dispatch centers, distribution control engineers, DMS support group, cyber security, multiple vendors and teams that have not been set up or contemplated yet.
- Modernize existing infrastructure
Utilities must be able to modernize their existing infrastructure without being required to rebuild their system from the ground up. The new technologies must be able to work with legacy and older equipment. Experience has shown that interfacing new controls with aging equipment may not be straightforward, may be troublesome and, at times, may not produce optimal performance of the distribution system.
- Communication is key
The communication network is one of the most important components in developing the smart grid. Near-real-time operation of systems similar to DAVVC and community energy storage (CES) requires highly stable and reliable networks. Communications networks that optimize systems in one geographic area may not work or be available in other areas of the service territory. AMI meters and DA can use shared communications networks, or separate networks can be employed in the same area. There is much industry debate concerning the proper design of communications for the smart grid systems.
- Cyber security is evolving
Security needs to be considered in an ever-evolving role with the developing smart grid. Cyber security has always been important to the utility infrastructure and SCADA systems that were mainly connected to secured fenced-in station locations. The new technologies being introduced to the distribution system require cyber security to address issues associated with communications equipment installed on utility poles throughout the public domain. These same cyber security resources are now being called on to provide security for numerous controller operating system platforms being installed in stations. This is a new challenge for cyber security, as these platforms were previously installed in secured buildings behind firewalls.
- Volt/VAR is gaining momentum
DAVVC solutions are relatively new to the distribution industry, including the vendors. The technology continues to gain significant attention in the utility industry and regulatory arena as being a method for improving energy efficiency and reducing peak demand. This increased emphasis has vendors continuously improving their existing programs or scrambling to develop their own DAVVC system. DAVVC systems can cause more frequent operation of capacitors, regulators and transformer load tap changers (LTCs) and will need to be optimized further in this respect to minimize operations and maintenance expenses. It is important for the industry to strive for integration of less costly end-of-line voltage monitoring systems and develop AMI meter interfaces, where practical.
- Volt/VAR provides benefits
The benefits associated with DAVVC systems are mainly reductions in energy use and peak demand with minimal reduction in distribution system losses. AEP Ohio's pilot project is showing average energy efficiency and peak demand reduction is approximately 3%, per Battelle's third-party evaluation. As the full benefits of DAVVC are being determined, it will be important to investigate the right balance between automation technology and circuit/equipment upgrade investment.
- Improve products
In early DACR installations, utilities were required to install three poles to provide voltage sensing on both sides of a recloser or switch. Utilities need to work with vendors to ensure all the voltage-sensing equipment can be installed on a single pole and meet all applicable codes. The DACR technologies must be able to take into account customers who have alternate feed sources, multiple-station transformers and associated switching configurations. Smart grid distribution line devices need equipment door alarms added for communication security purposes.
- Dealing with rapid changes is challenging
With all of the new smart grid equipment being introduced to the distribution industry, it is a challenge for distribution standards groups and work management systems to keep up. It is difficult to standardize with one vendor, as all vendors are developing and optimizing their new platforms. The vendors' technologies seem to evolve with each new scheme installed, based on utility feedback. This makes it difficult to fix problems with older schemes, as they become obsolete quickly. Risks need to be mitigated by working with vendors to ensure their systems are designed with interchangeable equipment and backward compatibility in mind.
- Evolution of personnel is a must
Smart grid technologies and deployments have created a shortage of technically savvy personnel, as the technical workload has increased. Existing utility personnel have to learn new systems and take on new responsibilities and roles. Incremental technical support staff are needed to install and maintain grid management systems. Colleges and universities need to redirect some of their course offerings to take into account the new smart grid work associated with their power and telecommunications courses.
- Use monitored and controlled devices to operate the smart grid
The new DMS or distribution SCADA system becomes the real-time distribution network management tool for the utility distribution dispatch centers. The new DMS expands the SCADA systems of yesteryear from breakers and devices within the station fence to all smart devices on the distribution system. Monitored and controlled devices on the grid could easily be increased tenfold. The new DMS not only provides the high-level view and control, but also advanced analytics for the distribution system. When developing the DMS system, the requirements and capabilities need to be clearly understood by all utility and vendor teams. When commissioning the DMS systems, point-to-point and system-acceptance testing are greatly enhanced through remote network access to field devices and the use of simulators.
- Gain efficiency by integrating systems
As smart devices are rolled out onto the distribution circuits, efficiency is gained through highly integrating the geographic information system, OMS and DMS. The DMS network modeling must match field conditions as closely as possible through near-real-time updates to safely and efficiently dispatch crews. It is important all distribution SCADA and non-SCADA switching devices be included in the DMS modeling so automatic and manual switching operations can be monitored and captured in the records. Tools need to be automated to manage network changes as they are constructed in the field.
- Turn data into action
The introduction of all the new electronic smart grid devices and the ability to communicate information back to the DMS and back-office systems has created an enormous amount of data and log files. This includes system operation and equipment performance data. IT reporting and data mining applications need to be developed to turn the large amount of data into knowledge and identify which items the utility needs to take proactive action on.
- Work with vendors to ensure equipment interoperability
As smart grid installations expanded rapidly and equipment vendors began to create their own individual smart devices, utilities were caught in a world where vendor devices were not necessarily interoperable. It is important for utilities and vendors to work together to enhance smart equipment so multiple devices become interoperable and vendor agnostic. This is important because continuous updates to vendor equipment and specifications create challenges, and it is critical to ensure proper integration with existing systems going forward.
The Exciting Journey
AEP and the rest of the utility industry have just begun the exciting journey into the smart grid world. There is much to do to proceed with a full implementation across AEP, the United States and around the world. The information in this article is provided to help define some main building blocks and the lessons learned to help steer utilities around the potential issues associated with future smart grid deployments.
Paul Thomas (email@example.com) is the American Electric Power grid management deployment supervisor. He was previously the AEP Ohio project manager for integrated volt/VAR control, distribution automation and community energy storage. Thomas helped co-author the AEP Ohio gridSMART demonstration project in 2009, which was awarded US$75 million in funding from the Department of Energy for the highest-scoring Midwest proposal. He holds a BSEE degree from the University of Toledo, and is a member of the National Society of Professional Engineers, a member of the Ohio Society of Professional Engineers and a member of IEEE. He is a licensed professional engineer in the state of Ohio.
Editor's note: This material is based upon work supported by the U.S. Department of Energy under award number DE-OE0000193. Disclaimer: This report was prepared as an account of work sponsored by an agency of the United States government. Neither the United States government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States government or any agency thereof.
AEP's gridSMART Deployment Summary
American Electric Power has been developing and deploying smart grid technologies for the past several years. In 2007, the company began a major systemwide effort to develop AEP's gridSMART vision and deployment strategies.
Several distribution projects involved innovative sodium-sulfur battery-storage projects, including one 1-MW unit, three 2-MW units and one 4-MW unit, totaling 11 MW of battery storage in service. Throughout the system, there are approximately 40 distribution automation (DA)/circuit reconfiguration (DACR) schemes in various stages of planning, design and construction.
Major multifaceted deployment projects on the AEP system include Indiana Michigan Power (in service), AEP Ohio (in progress), AEP Texas (in progress) and Public Service Company of Oklahoma (in progress). The following technologies were included in the deployments:
Advanced metering infrastructure - 1,157,000 meters
DACR - 88 circuits
DA Volt/VAR control - 28 circuits
Community energy storage - 80 25-kW batteries
Plug-in hybrid electric vehicles and plug-in vehicles (10 cars and 15 charging stations)
Enhanced time-of-use rates
Programmable communicating thermostats
Direct load control
Home area networks
Customer Web portals for monitoring and management
In-home displays for monitoring and management
Simulation of technologies with GridLAB-D and Open DSS open source modeling and simulation software
American Electric Power www.aep.com
Electric Power Research Institute www.epri.com
Indiana Michigan Power
National Institute of Standards and Technology