Money may be difficult to come by for Wall Street financiers in these dark days, but apparently not for electric transmission construction—at least so far. A rash of recent orders from FERC shows...
T&D investments prioritize reliability and load growth.
How, we asked, did they prioritize their requirements? How did they address smart grid, reliability and capacity issues when deciding where to invest? And are growing environmental concerns impacting those decisions?
At NU, four projects are at or near completion. A new 20-mile length of 345-kilovolt (kV) electric-transmission line in southwestern Connecticut went live in 2006. Two projects—a new underground 115-kV line in the Stamford-Norwalk area and three new underwater solid-core (non-fluid filled) cables that replaced seven fluid-filled transmission cables that ran between Connecticut and Long Island, New York—will be completed by the end of 2008. A 69-mile project involving new overhead and underground lines and reconstructed existing lines cutting through 18 cities and towns in southwestern Connecticut is scheduled to be completed in early 2009.
Additionally, three more 345-kV transmission projects are in the development stage at NU, including new lines for central and eastern Connecticut and a new line in Springfield, Mass., a major distribution hub for southern New England. The three projects, which are scheduled to be completed by 2013, will improve reliability and save the region hundreds of millions of dollars in congestion charges.
“We’re in the middle of the most dramatic reliability improvement in New England in 25 years,” says Aylsworth. “We’re maximizing the existing transmission-system operations, either by building new infrastructure, or introducing new technologies that make the existing system more efficient.”
As is the case with other utilities, measuring network operations is a combination of the old and the new. In-house planners still provide system-wide oversight. However, they now rely on computer and software technologies to analyze system performance, monitor load growth within certain parts of the service territory, and plan transmission-system improvements.
“Data collection is one area of utility operations that’s really changed. You can collect information from any number of grid components,” says Fred Trice, senior manager in the global utilities practice at Mclean, Va.-based BearingPoint, a management and technology consulting firm. “For example, data from voltage regulators in your system’s switching stations can tell you both the value of the load going through that system, as well as the operating condition of the regulator itself.”
NU begins its planning process by using computer modeling programs to put existing T&D system through a series of “what if” scenarios that help determine the current state of operations; identify weak points within the grid; and test the impact of hypothetical upgrades.
“First, we identify problem areas. Planners can take the existing power flows and conduct what-if scenarios to determine what would happen if, for example, we lost a major generating unit, or two major lines due to lightning,” Aylsworth explains.
Load-growth projections then are added to the mix. How will further growth within a region impact the existing system? Will the voltage levels be less than acceptable and if so, what upgrades will be needed and when? And, perhaps most important, how will those upgrades impact other parts of the transmission system?
That’s where Aylsworth’s Whack-a-Mole metaphor comes in. To overcome that, NU works closely with ISO New England, which operates