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Smart grid technology is being rolled out around the world, with the United States nearing completion of a particularly significant 4 plus billion-dollar Federal program funded under the American Recovery and Reconstruction Act (2009). Under the Climate Change Working Group Implementation Plan, Smart Grid activity comparative analyses are being conducted of benefits estimation methods with example applications to 4 case study smart grid projects, 2 in each country. In this first study, three of eight Southern California Edison’s Irvine Smart Grid Demonstration Project sub-project benefits have been analysed over the period 2010-2035. The analysis uses the Smart Grid Computational Tool (SGCT) developed by Navigant Consulting Inc. for the U.S. Department of Energy based on Electric Power Research Institute methods. Results show significant benefits potential for technologies such as distribution voltage and VAR control and utility-scale batteries, while a 22-residence zero net energy home demonstration inspired by California’s 2020 residential energy efficiency standard falls far short of economic breakeven at the current stage of costs and technology performance. The experience gathered indicates the SGCT being intended for widespread U.S. smart grid evaluation use is necessarily simple, and consequently has limited applicability for international applications or comparisons.

One of the main objectives of this DOE-sponsored project was to reduce customer outage time. Fault location, prediction, and protection are the most important aspects of fault management for the reduction of outage time. In the past most of the research and development on power system faults in these areas has focused on transmission systems, and it is not until recently with deregulation and competition that research on power system faults has begun to focus on the unique aspects of distribution systems. This project was planned with three Phases, approximately one year per phase. The first phase of the project involved an assessment of the state-of-the-art in fault location, prediction, and detection as well as the design, lab testing, and field installation of the advanced protection system on the SCE Circuit of the Future located north of San Bernardino, CA. The new feeder automation scheme, with vacuum fault interrupters, will limit the number of customers affected by the fault. Depending on the fault location, the substation breaker might not even trip. Through the use of fast communications (fiber) the fault locations can be determined and the proper fault interrupting switches opened automatically. With knowledge of circuit loadings at the timemore » of the fault, ties to other circuits can be closed automatically to restore all customers except the faulted section. This new automation scheme limits outage time and increases reliability for customers. The second phase of the project involved the selection, modeling, testing and installation of a fault current limiter on the Circuit of the Future. While this project did not pay for the installation and testing of the fault current limiter, it did perform the evaluation of the fault current limiter and its impacts on the protection system of the Circuit of the Future. After investigation of several fault current limiters, the Zenergy superconducting, saturable core fault current limiter was selected for installation. Because of some testing problems with the Zenergy fault current limiter, installation was delayed until early 2009 with it being put into operation on March 6, 2009. A malfunction of the FCL controller caused the DC power supply to the superconducting magnet to be turned off. This inserted the FCL impedance into the circuit while it was in normal operation causing a voltage resonance condition. While these voltages never reached a point where damage would occur on customer equipment, steps were taken to insure this would not happen again. The FCL was reenergized with load on December 18, 2009. A fault was experienced on the circuit with the FCL in operation on January 14, 2010. The FCL operated properly and reduced the fault current by about 8%, what was expected from tests and modeling. As of the end of the project, the FCL was still in operation on the circuit. The third phase of the project involved the exploration of several advanced protection ideas that might be at a state where they could be applied to the Circuit of the Future and elsewhere in the SCE electrical system. Based on the work done as part of the literature review and survey, as well as a number of internal meetings with engineering staff at SCE, a number of ideas were compiled. These ideas were then evaluated for applicability and ability to be applied on the Circuit of the Future in the time remaining for the project. Some of these basic ideas were implemented on the circuit including measurement of power quality before and after the FCL. It was also decided that we would take what was learned as part of the Circuit of the Future work and extend it to the next generation circuit protection for SCE. Also at this time, SCE put in a proposal to the DOE for the Irvine Smart Grid Demonstration using ARRA funding. SCE was successful in obtaining funding for this proposal, so it was felt that exploration of new protection schemes for this Irvine Smart Grid Demonstration would be a good use of the project resources. With this in mind, a protection system that uses fault interrupting switches, high speed communications, and looping two radial distribution circuits would have the potential for significant reductions in interruption time and number of interruptions for customers.« less

This report articulates and justifies the preliminary selection of diagnostic applications for data from micro-synchrophasors (µPMUs) in electric power distribution systems that will be further studied and developed within the scope of the three-year ARPA-e award titled Micro-synchrophasors for Distribution Systems.

This report describes the tests conducted to determine the behavior of two Capstone 30 kW microturbines connected in parallel with some impedance between them. This test was meant to simulate the operation of two microturbines at nearby customer facilities. This arrangement also constitutes a simple microgrid. The goal of this test was to investigate if any voltage and power instabilities exist between the two microturbines. Two test sequences were conducted. The first test sequence operated two microturbine/load bank pairs using manual control of the microturbine and load bank setpoints. The second test sequence used the Capstone Load Following mode of operation to control generation levels of one of the microturbines. The two microturbine/load bank sets were connected together through a 300 foot long, four conductor, #12 cable so th at the impedance between them would cause up to a 5 percent voltage drop (depending on the load balance between the two sets). Data was collected from both Capstone microturbines, two power quality instruments and a power monitor. The tests showed there were no instabilities in the microturbines' voltage or power output as long as care was taken not to overload either unit. A voltage drop of almost 5 percent was observed between the two microturbines at the highest loadings. This "soft" connection between the two microturbines did not cause problems. Basic protective functions of the microturbines avoided unintentional islanded operation, but probably would not be sufficient or desirable for normal microgrid operations. Some simple automatic load sharing could be accomplished by using the Load Following mode of operation of the microturbine. This ability was demonstrated during the second set of tests. Load sharing works as long as all loads are kept within operating limits of the two microturbines. Use of the load following mode of the microturbine seemed to work fairly well. To improve the responsiveness of the load following, a faster pulse rate would need to be obtained from the kilowatt-hour meter for the expected loads. The faster pulse rate would allow a shorter averaging period in the microturbine which would make it respond more quickly. Revision of the microturbine operating software would be desirable so that both microturbines could share load and voltage regulation duties in the microgrid. Once these abilities were integrated into the microturbines, the functions would need to be verified in a set of lab tests and then checked in actual field operations. Additional protection functions would also need to be integrated into the microgrid so that a fault on the microgrid would not drop all load and generation.

This report describes test measurements of the behavior of two microturbine generators (MTGs) under transient conditions. The tests were conducted under three different operating conditions: grid-connect; stand-alone single MTG with load banks; and two MTGs running in parallel with load banks. Tests were conducted with both the Capstone 30-kW and Honeywell Parallon 75-kW MTGs. All tests were conducted at the Southern California Edison /University of California, Irvine (UCI) test facility. In the grid-connected mode, several test runs were conducted with different set-point changes both up and down and a start up and shutdown were recorded for each MTG. For the stand-alone mode, load changes were initiated by changing load-bank values (both watts and VARs). For the parallel mode, tests involved changes in the load-bank settings as well as changes in the power set point of the MTG running in grid-connect mode. Detailed graphs of the test results are presented. It should be noted that these tests were done using a specific hardware and software configuration. Use of different software and hardware could result in different performance characteristics for the same units.