Georgia Power is a good example of a utility that has made great strides in integrating its distribution management system and other components as it moves to being a part of a bigger smart grid. T&D World's Online Editor Nikki Chandler asks industry expert Ed Carlsen what advice Georgia Power, a Southern company, can give to other utilities based on its own extensive experience.
Using the Southern Company definition of "smart grid," Carlsen describes how Georgia Power has made its own internal smart grid and continues to improve and upgrade as needs arise and technology evolves. He explains how Georgia Power is handling the data, using mobile computing and communicating benefits to customers.
Carlsen is manager of distribution management systems and has 33 years of management and engineering experience in Distribution, Transmission and Generation with Georgia Power. In his current role he oversees the development and implementation of wide-ranging technology solutions for Georgia Power’s distribution organization. He is also a member of the Southern Company Distribution Technology Leadership Team and has system sponsorship responsibilities for these areas.
What general initiatives does your utility have in place to become a smart utility?
Georgia Power is using the Southern Company Smart Grid definition as a guide to initiatives. A Smart Grid, to Southern Company, is a two-way telecommunication-enabled power delivery system that uses electronic data and other technologies, such as intelligent devices, integrated systems, and advanced metering, to:
- Optimize grid performance and reliability.
- Provide the customer enhanced options to improve the efficient use of our product.
I would say the Georgia power distribution system is already a rather “smart grid,” as we have a significant penetration of SCADA, Distribution Automation (Intelligent Electronic Devices both inside and outside the substation), a mature OMS (Outage Management System), and a CVR (Conservation Voltage Reduction) program. We continue to expand existing systems more broadly such as adding additional self-healing distribution circuits, expanding CVR systems, growing various communication systems, and replacing electromechanical relays with microprocessor-based equipment.
We are also adding new technologies such as a multi-year Smart Meter/AMI installation effort that is approximately 60% complete; enhanced OMS/DMS functionality; and incorporation of AMI outage data with the OMS.
What components make up your distribution management program and how long have you had them in place?
The primary components of our distribution management program are:
- GIS (Geographical Information System) – the foundation and data source for all facilities, connected OMS model, etc. In place for four years, replacing an earlier CAD-based mapping system.
- OMS (Outage Management System) – a geospatial and tabular system that utilizes a dynamic electrical model that is a near real-time representation of the distribution system near real time. In place for over 10 years.
- SCADA – virtually all the more than 2000 distribution breakers are SCADA enabled. This system has been in place in various forms for over 30 years.
- Distribution Automation – SCADA controlled or autonomous field devices on the distribution circuits. Early equipment was in place more than 15 years ago, however significant deployment efforts have been under way for the last 10 years.
- AMI – Evolving use of AMI data to help operate the distribution system. AMI meter/system deployment of 2.3 million meters began in 2008 and will complete in 2012.
- Ancillary systems include our CIS (Customer Information System), IVR (Interactive Voice Response), Mobile Work Management systems, and Operations
- Business Intelligence systems.
Are they integrated?
These systems are significantly integrated, and the integration continues to evolve. Examples of this integration are: OMS electrical models are updated daily as changes occur in the GIS. The OMS has an ICCP link to the SCADA system and gets real time breaker status. A planned expansion of this interface will include SCADA-monitored field devices and analog data. The IVR/CIS system has 2-way interface with the OMS. AMI outage data will soon flow directly to the OMS system, and coordinate with Work Management Systems to avoid false outage reporting associated with scheduled work. Business Intelligence Systems gather the data from OMS and Work Management systems to present the volumes of data in a meaningful, concise, actionable format. Distribution Automation devices are managed through traditional SCADA, and are also configured as autonomous, self-healing networks.
How have you integrated them?
The integration of the systems is done in a variety of ways… through vendor provided interfaces, third-party integration software, and via in-house developed solutions.
Our sister operating company, Alabama Power is helping develop a comprehensive integrated distribution management system in one vendor package that incorporates SCADA, OMS, and advanced DMS functionality. Georgia Power is providing input and may consider this in the future if it provides operational and financial value.
What is Georgia Power's primary goal/benefit for integrating its distribution management system and has that been met from what you have done so far?
Customer satisfaction is one of our most important drivers at Georgia Power. Providing safe, reliable service while minimizing costs is a goal, and an integrated distribution management system helps us achieve this goal. We have seen improvements in outage restoration times and overall reliability betterment from the many years of DMS system deployment. Customer expectations for timely, accurate information are ever increasing, and the DMS systems allow operators, customer service representatives, and employees provide this to our customers.
Have you solved any prior problems with distribution management?
In general, we continue to grow the DMS solutions to provide better reliability and service to all customers. These solutions may target specific “problems,” but are generally deployed to make business processes and overall system performance more effective. This is accomplished by taking advantage of improved technologies and applications. We have resolved problems in specific locations/areas with reliability challenges through various DA and DMS solutions. We implemented CVR several years ago to avoid construction of additional generation, and continue to expand this capability.
What vendors and programs are you using currently for distribution management?
- GIS – esri ArcGIS, Telvent Arc FM and Designer
- OMS – Oracle NMS (Network Management System)
- Distribution SCADA – AREVA T&D (now Alstom/Schneider) master station application, various field RTU providers
- Distribution Automation – numerous and various providers of equipment
- AMI – Sensus FlexNet system, various meter manufacturers
- Communication Systems: various systems including: SouthernLinc iDEN, commercial cellular carriers, MAS radio system, Southern Company owned and maintained fiber optics rings Business Intelligence: Obvient Strategies Focal Point
Do you have plans to add any new systems?
The following new technologies are being implemented within the next 12 months:
- Various IEDs by several different manufacturers
- Fault location technologies utilizing field devices, substation data collection devices, and applications to analyze the data and present it to users in a meaningful and useful way
- A CVR capacitor health monitoring device/system
- A centralized gateway to manage small areas of self-healing grids is being investigated with two different vendors
How are you "selling" or communicating the benefits of smart grid to customers?
In general, we communicate our commitment to providing safe, reliable power at a cost which is below the national average. Our primary “Smart Grid” communication to customers is related to our Smart Meter / AMI deployment. We have intentionally focused on the near term benefits of the AMI system, and provided some insights into the future benefits Smart Meters can provide. We are careful not to “oversell” the capabilities and benefits until we see these systems can perform as expected, and provide the value desired for both the customer and Georgia Power.
How will your utility handle the volumes of data that smart grid can generate?
There is no doubt that data volume is increasing exponentially. The base systems are evolving or are being upgraded to handle these increases… for example our SCADA system data point threshold has been reached and a planned 2011 upgrade will relieve this bottleneck. We are utilizing Business Intelligence system capabilities to both store and “pre-process” data so it can deliver necessary information as quickly, and efficiently as possible. AMI data volumes are staggering… in many cases having the capability to provide hundreds of times the data than in the past. We are also investigating a data historian and the role it will play in various aspects of the business.
Are you investing in a communications system so you can securely transport data with the proper latency and bandwidth?
We continue to invest in, develop and select communication solutions that meet the technical and needs in the most cost effective and reliable way. Clearly these systems must meet the Cyber Security requirements that continue to evolve. We currently use and are expanding a variety of communication systems. These include company-owned and maintained systems such as fiber optics rings, licensed frequency MAS radio, and SouthernLinc iDEN-based cellular. Other solutions include local phone provider Frame relay, commercial cellular carrier systems, unlicensed frequency mesh network radio systems, and the Sensus FlexNet licensed frequency wireless of the AMI system.
How much are you using mobile field computing functions?
Historically we have used mobile field computing where there was measureable, proven value. This included short cycle work (meter work), outage/trouble first responders, underground cable locating workforce, and some maintenance crews. As the cost of computing, and as importantly wireless communication, has come down and capabilities have become more robust, we are expanding mobile computing to include crew supervisors and field engineers to allow more traditional office-based work to be done in the field. This deployment will continue to expand as the value is proven. We have not deployed to construction crews at this time, and have no immediate plans to do so.
How are you funding any upgrades in your distribution automation?
Distribution Automation and DMS upgrades are an integral part of our base budgets. Georgia Power was awarded funding through the SGIG (Smart Grid Investment Grants) stimulus program and has been able to accelerate the implementation of many planned initiatives.
What are your future plans for your distribution management system?
We plan to continue to evolve the various components of our DMS as described earlier, as well as other advance functionalities such as Fault Location Analysis, centralized control of self healing networks, advanced power flow tools, and other areas. Technology and systems are evolving rapidly, and funding through the SGIG is available for only two more years. We have had challenges with some of the vendors not responding quickly enough to our needs and desires to incorporate these new systems and technologies. I encourage the vendors and utilities to work as partners, abandon unnecessary and wasteful bureaucracy, streamline outdated and slow paradigms, and find ways to implement effective solutions quickly and cost effectively. All will benefit by this approach.
Any advice for other utilities wanting to integrate their systems as they move to smart grid?
First, get a grasp on the quality of your existing data, and determine how it can support the wide ranging functionalities of the Smart Grid. Good, quality data is the key to making the various systems function as desired, and when integrating these systems, data consistency is essential. Be prepared to see that your data may not be as good as you think (or as needed) and plan for the effort and costs to improve, and then maintain this data.
Second, develop an organizational structure, or at least well defined responsibilities, to support a large scale implementation and integration effort. As an example, Steve Pigford, Manager of Georgia Power’s Distribution Design and Performance organization was named overseer of all Southern Company Smart Grid activities, and Van Holsomback, Manager of Distribution Reliability and Automation coordinates all Georgia Power Distribution Smart Grid efforts… in addition to regular job responsibilities. A strong, well functioning relationship between the operational side of business and the IT (Information Technologies) organization is also essential for success.
Third, take a close look at business processes and how they will utilize new or increased use of technology. Change management will be required, and training is an essential part of deploying new systems or processes. Both of these can often get overlooked, or underfunded.
Lastly, develop good working relationships with your key vendors and suppliers.
For a more graphical representation, see Integrating Devices and Applications in an Evolving Distribution Smart Grid for Maximum Effectiveness, Presentation by Ed Carlsen at the 3rd Annual Grid Evolution for Utilities conference, Sept. 30-Oct. 1, 2010.
