Conferência: Metering, Billing/CRM Latin America
Local: Rio de Janeiro, Brazil
Palestrante: John O’Farrell
Artigo: Apresentado por John O’Farrell na Metering, Billing/CRM Latin America
Like their counterparts in other countries, most Latin American utilities have not yet implemented significant amounts of automation in their local distribution networks. Such key tasks as meter-reading or service connection and disconnection require a visit to the customer location; local distribution network elements such as capacitor banks, switches or reclosers typically do not have any communications capability, meaning that they cannot be monitored or controlled remotely. This lack of automation creates many problems, for example: Theft of electricity cannot be easily detected or prevented; Outage detection and restoration is a labor-intensive, time-consuming process; The grid cannot be proactively managed to reduce technical power losses; Energy efficiency programs such as time-of-use pricing cannot easily be implemented.
Driven by the need to increase energy efficiency, reduce theft and improve service, some utilities have tackled various aspects of this problem. For example, metering departments have initiated Automated Meter Reading (AMR ) or even Advanced Metering Infrastructure (AMI) projects. Separately, transmission and distribution departments have initiated Distribution Automation (DA) programs. Another initiative may be Demand Response (DR) programs to try to reduce peak demand. While these approaches are constructive, they suffer from a number of problems: Because they are implemented by separate departments using separate dedicated networks, they lack economies of scale and scope and can be difficult to cost-justify. They often depend on a single vendor’s proprietary technology that has been developed solely to address the specific problem (e.g. meter-reading) and lacks the flexibility or performance to be used for other purposes or even with other vendors’ equipment. Even for a specific application, many of these proprietary technologies suffer from a lack of bandwidth, or are cost-prohibitive to deploy on a ubiquitous basis, or are not reliable or secure enough to justify wide deployment.
This paper describes how several leading North American utilities are taking advantage of a powerful combination of high-performance wireless mesh technology and open Internet Protocol (IP)-based networking to implement multi-service Smart Grid networks today. These networks offer a very compelling set of characteristics relative to traditional proprietary single application approaches:
- Single high-performance network that supports AMI, DA, DR, Home networking and other applications
- Ample bandwidth, enabling hundreds of thousands of transactions daily (scalable to millions) with very low latency
- Very high availability and accuracy — 99.99% or better
- Openness to any IP-enabled device or application — enabling the utility to choose from many vendors
- Costs comparable to or lower than dedicated proprietary AMI approaches
- Extremely high security
The paper includes many real examples and performance data from these deployments to illustrate the impressive results achieved by these networks. The lessons learned and implications for Latin American utilities are discussed, along with a potential roadmap for implementation.