The electricity system in the United States received renewed attention after the August 2003 blackout that affected more than 50 million customers across the Northeast United States and caused billions of dollars of damage to the U.S. economy. This blackout became a call to action as the event exposed the United States’ dependency on a vulnerable infrastructure. The state of the grid was unacceptable and a change was needed to ensure safety and reliability across the system. The intelligent network is one of the results of that call to action.
“Intelligent” electric networks involve increased awareness in a network and its ability to respond in real time, leading to better operational effectiveness for the utility and an improved experience for the customer. It represents a complete transformation of today’s electric grid. Key aspects are:
(1) A combination of centralized and locally distributed generation models that can economically provide energy;
(2) Higher-quality materials that can transmit more power with fewer losses and failures;
(3) Improved sensors that can instantly observe the state of the grid and transmit the information to different locations;
(4) An advanced network of integrated systems, both centralized and distributed, which can make intelligent decisions; and
(5) More automated processes supported by trained people.
All of these components need to be considered to ensure proper delivery of benefits.
But four key myths about intelligent networks must be recognized and debunked:
Myth #1: Intelligent networks and the “smart grid” are 10 to 15 years away.
Myth #2: Intelligent networks are all about sensors, self-healing equipment, and new materials.
Myth #3: The majority of grid investments are focused on transmission. Intelligent network efforts therefore should start with transmission.
Myth #4: There is no financial business case for a utility to start implementing intelligent networks.
There are enough aspects of intelligent networks available today for viable investment. Several products appearing in the marketplace greatly support the intelligent network arena. Many of these products are mature and have had extensive field experience. This leads us to believe that there are areas of opportunity available even now to get started right away. Some of these key areas include:
• Remote power factor/voltage control;
• Demand-response controller;
• Modular protection automation and control for transmission and distribution (T&D);
• Substation automation/monitoring controllers;
• Smart meters that can perform multiple functions;
• FACTS and other Thyristor-based devices;
• Phasor Measurement Units (PMUs);
Advanced information systems exist to enable the smart grid components listed above.
A combination of wired/wireless systems is available to be the communications backbone. Each of these components tend to be business-case justifiable on its own, depending on the circumstances.
Utilities need to invest in certain key foundational capabilities that will position them well to handle future changes. Key enabling technologies are required to realize the benefits of the intelligent network. An accurate representation of the T&D system along with connectivity and geo-spatial renderings are critical. This information will be used by the distributed/centralized self- healing/self-configuration systems to understand the connectivity in real-time based on the as-built model. The renderings will allow the operator to track the changes as they occur, allowing the systems to update the operational diagrams as the system state changes.
A stable outage management system (OMS) and data management system need to be in place. This is where the applications that perform self-healing/ self-configuration reside. The power system connectivity analysis and the associated real-time add-ons can assist the operator in making the right decisions.
Currently, this analysis is based on manual input by an operator. In the future, the analysis will be made based on real-time or near-real-time data provided by the sensors in the field. In addition, several other benefits will be made available to the operator, including intelligent alarming, electronic operating map, remote SCADA-based controls (as available), restoration switching analysis, planned switching, and clearance management.
These systems set the framework for the model, ensure the accuracy of the model is in place, and drive increased integration between T&D as well as facilitate the convergence of these two areas. An illustrative application architecture is shown in Fig. 1. Once the base applications are in place, the utility will be better positioned to handle the extra visibility and controllability afforded by the sensors.
While transmission is getting all the attention, the short- to mid-term focus should be on distribution. Most of the articles on intelligent networks have focused on transmission: high-temperature superconductors, predictive monitoring, self-healing grid, and new types of cable materials. Much of this is 10 to 15 years away.
Distribution tends to get overlooked. In fact, distribution has lagged much in terms of investment in almost all categories. It is not uncommon to have limited SCADA-based visibility or remote-control capability. Many utilities still rely on manual field-crew-based operations, and they depend on customer calls to locate outages. In addition, paper-based operations are quite common in many distribution operations control centers.
Many of the answers used in debunking Myths #1 and #2 show the steps that can be taken to get started on distribution and get the utility on a path to achieving benefits.
Maintaining the status quo can become quite expensive. Some of the benefit areas that need to be thought through follow.
Demand Growth. As demand grows, there will be an increased need to make additional T&D investments, followed by the need for new sources of power (either constructed or purchase from external sources).
Power Quality. As more power electronics-based devices get connected to the grid, they will affect the quality of power being delivered adversely, including voltage fluctuations and more harmonics in the system.
Reliability. Continued lack of sensors in the network will lead to a continued dependency on customer calls to identify outage locations. As customers get savvier, they will demand better power stability, leading to more potential fines for the utility by the PUC.
Aging Assets. Almost all the utilities in North America are saddled with large quantities of aging assets that will need to be replaced within the next 5 to 10 years. Replacing them with today’s designs would not position them well for the future.
Distributed Generation Growth. More states will follow California’s lead and will require a greater percentage of their supply to be met by renewable sources. As this happens, there will be an increased need to analyze the distribution grid’s ability to support bi-directional power, and the need to spend significant money to redesign the grid in a reactive manner, instead of doing it proactively.
The cost of the overall implementation of the smart grid is high by today’s standards and will be difficult to justify under most utility scenarios. Any initiative of this magnitude would need to be viewed as a journey with changing objectives based on signposts.
The risk in the implementation is high. The characteristics of the components (sensors, systems, communications, etc.) will change with time and could move the intelligent network implementation in different directions.
There is significant regulatory skepticism. The key issue to regulatory acceptance is an acceptance/belief in the intelligent network vision. There is significant work to do in proving to regulators that this significant level of investment will in turn provide the benefits proposed, while at the same time minimize overall risk. The shift from time-based maintenance to condition-based maintenance also will be difficult to implement.
Large changes almost always face a high degree of skepticism within a utility, halting many of them at the pilot stage. Any change in this area will require intense education of the key players. But change is happening rapidly. Many vendors are working on distributed generation, embedding sensors in the new generation of equipment, developing new materials, and so on. These developments have the potential to alter the dynamics of the changes and how quickly they can be implemented. The key to managing risk is to develop an overall roadmap and follow the roadmap in manageable chunks. This process should begin now, with a strong focus on condition-based maintenance.
Utilities cannot afford to ignore the coming transformation of their networks. Doing so will lead only to greater costs. The key is to develop a strategy and to stay abreast of the leading best practices. The following steps are crucial:
• Create appropriate signposts and make changes to the strategy as the timing becomes right;
• Get started early. There are enough value-driven options available now;
• Do not forget the foundation. Ensure the basic capabilities are implemented to support the future options; and
• Develop an overall roadmap, to be followed in manageable chunks.
Intelligent networks represent the next wave of utility transformation, driving significant benefits in almost all facets of utility operations, ranging from customer service to field operations to T&D (see Figure 1). Several industry efforts already are underway in this area.