Operations personnel at many energy companies feel the pressure of achieving compliance with the NERC CIP standards. Some worry that they are not aware of the problems and security incidents that...
IT systems ease the pain of power plant restarts.
It also depends on the load, reserves, and the type of plant.”
An outage typically begins, Vono says, with a meeting of the minds to outline the project’s timing and scope. “We bring the customer, our field teams and the craft labor together to develop a strategy on how best to manage the outage,” he says. “We apply best practices and lessons learned from past outages and develop a plan specific to that site.”
At this point, customers often want and need recommendations. Athanasia points to a customer with two identical combined-cycle natural gas-turbine power plants, one in Texas, the other in the Northeast. The Texas plant is used exclusively for cycling duty, while the other operates in a baseload—spinning reserve—mode. Both have identical configurations and both are owned by the same electric utility. Yet due to the way the units are dispatched, each is on a different outage timetable and each will have different technical requirements once it’s shut down for maintenance.
“Most utilities are like this—they have multiple generating assets and they operate them differently,” Athanasia explains. “They may ask us, ‘Normally we run this gas turbine for 24,000 hours; are there hardware options that could extend it to 32,000? How might that affect our O&M costs versus the revenue the unit will generate?’” Customers also ask about cycling flexibility or O&M savings—upgrades to increase the plant’s value. “It’s become a much more customized approach. It’s no longer a routine ‘change the oil and give it the once over,’” Athanasia says.
Once the scope is addressed, the more traditional outage service processes begin. The goal, especially these days, is to keep the outage well within its allotted time-frame. How that’s done varies by vendor and—most notably—the type of project. The two biggest market areas are environmental retrofits and nuclear refueling and uprates.
Clean Air Retrofits
Many utilities already have invested billions of dollars in environmental equipment, partly in anticipation of EPA regulations. This spending is expected to continue—and increase into the $10s of billions during the next three to five years. Much of that capital will be invested in air emissions control equipment to comply with the U.S. Environmental Protection Agency’s (EPA) Mercury and Air Toxics Standards, or MATS, which aim to reduce emissions of mercury, acid gases, and other air pollutants.
Such retrofits can be especially dicey because in many instances there’s little if any physical space available to install the equipment. Pre-outage planning is required to orchestrate the delivery of cranes, ductwork, scaffolding and other equipment, and space limitations can affect engineering and design. More ductwork, for example, might require greater throughput supplied by a larger fan design, says Wane Goss, a project manager with Babcock and Wilcox (B&W) power generation group. “Today, it’s more important than ever that design engineering and construction work closely, especially when it comes to back-end retrofits. Otherwise you could end up increasing the outage time and, possibly, equipment costs.”
In certain instances pre-outage planning, combined with pre-outage equipment testing, can pay dividends. A number of utilities have employed plant simulator software during