As an ever-changing power mix and growing renewable contributions challenge grid stability, flexible gas generation looks to be more important than ever, panelists at ELECTRIC POWER 2014 reported.
With the gas-fired power sector in continual flux, blessed by plentiful gas supplies but faced with uncertain fuel costs and competition from intermittent renewable generation, plant owners must make flexibility and responsiveness a priority. That was the message from the natural gas track at the ELECTRIC POWER Conference held in New Orleans, April 1–4.
Rob James, product manager for Neuco, discussed a project optimizing heat rate and ramp rate at Dynegy’s Independence combined cycle plant in Osewgo, N.Y. The 1,042-MW dual 2 x 1 facility began bidding into the New York Independent System Operator frequency regulation market about four years ago. Dynegy later retained Neuco to help maximize the plant’s capability for high–ramp rate ancillary services. This meant finding ways to optimize the dynamics of the combined cycle process and enhancing day-ahead capability prediction.
By using sophisticated modeling software to predict demand trends, the plant is able to deploy its duct burners ahead of time to increase steam turbine output and preserve high–ramp rate gas turbine capacity. The model then turns the duct burners off as soon as they are no longer needed in order to maintain plant efficiency. Timing the duct burners is important when selling into the regulation market because the gas turbines can reach maximum output below total plant output well before the heat recovery steam generator (HRSG) heats up, which can compromise the plant’s committed ramp rate. If the duct burners are timed properly, the plant can sell all its power into the regulation market while still bidding at gas turbine ramp rate.
Nikhil Kumar, director of energy and utility analytics, Intertek Asset Integrity Management, reviewed a study of combined cycle and simple cycle gas turbine operating performance from 2002 through 2012. The study was intended to characterize trends and effects of cycling operation. Not surprisingly, the data showed substantial increases in average capacity factors at these plants, but also increased number of starts and ramping episodes. This places greater stress on a plant, meaning steps must be taken to increase equipment resiliency. Among the countermeasures that can help deal with increased cycling are installing additional thermocouples in the HRSG to better monitor temperature changes and better monitoring and control of HRSG chemistry. More effective steps can be taken if planning begins at the design stage.
Increased penetration from intermittent renewable generation is challenging combined cycle plant profitability as increased cycling (see related article, “Managing the Changing Profile of a Combined Cycle Plant” in this issue) sends maintenance costs up while lucrative baseload roles are taken by wind and solar. However, renewable generation rarely follows forecasts precisely, leaving plenty of gaps needing to be filled. Properly designed plants can ramp quickly and stay profitable by pursuing opportunities in ancillary markets, as several speakers explained.
Omar Rubio of Siemens Energy described two major ramping episodes in Germany and California last year, when multiple gigawatts of renewable generation came off the grid over a short period of time, and grid operators had to ramp up major amounts of conventional generation to replace it. Such episodes will only become more common, and that means a big opportunity for fast-starting combined cycle plants that can meet the need.
Gordon Smith, chief consulting engineer with GE Power & Water, discussed two of the main challenges of fast starts: stresses on the HRSG and managing NOx emissions. Relatively minor HRSG design changes can minimize thermal stresses and increase steam turbine responsiveness. Meanwhile, predictive modeling to better manage NH3 additions to the selective catalytic reduction system can help keep emissions under control even when turbine output is erratic.
Flexibility takes other forms than combined cycle gas turbines, of course, as several presenters reviewing the performance of reciprocating engines alongside renewable generation reported.
Chris Marks, mechanical engineer with Burns & McDonnell, described the development and construction of Mid-Kansas Electric Co.’s 110-MW Rubart Station gas engine plant in western Kansas, which is coming online this year. The area is a major producer of wind energy, and Mid-Kansas’s cooperative profile includes 179 MW of wind capacity out of a total of 733 MW. That’s created a need for balancing from highly flexible but efficient generation. Mid-Kansas ultimately chose a 10-unit plant powered by Caterpillar G20CM34 gas engines. The plant can ramp from 0% to 100% load in only 8 minutes, with flat efficiency across a wide operating range.
Dennis Finn, business development manager for Wärtsilä North America, reviewed a similar gas engine project in Alaska, the Matanuska Electric Association’s (MEA’s) 170-MW Eklutna Generating Station in Palmer, northeast of Anchorage (Figure 1). In Alaska, the highest loads are in the winter, while summer demand can be very light. The area is also seismically active. MEA chose a Wärtsilä-supplied gas engine plant (powered by 10 18V50DF dual-fuel engines) because of their high reliability, rapid dispatch, and low maintenance requirements. The plant will be able to continue operating down to –40F and remain online (by switching to fuel oil) even in the event of an earthquake. Construction began in early 2013 and the plant is expected to come online by January 2015.
|1. Gas projects roll on. Dennis Finn of Wärtsilä gives a report on a gas engine plant in Alaska during the ELECRIC POWER natural gas track as panelists Udo Zirn, Chris Marks, and Joe Ferrari look on. Source: POWER/Tom Overton|
Advances in turbine technology are also increasing generation options. Udo Zirn, manager, turbine systems for Mitsubishi Hitachi Power Systems Americas (MHPS), presented a new technology that MHPS is preparing to roll out. Called AHAT, or advanced humid air turbine, it involves feeding humidified compressed air into a simple cycle turbine to increase efficiency. Combustion air is cooled by wet evaporative cooling and is then passed through a humidification tower and heated in a heat exchanger using turbine exhaust before entering the combustor. The water vapor in the exhaust is then recovered and returned to the humidifier.
MHPS has been developing the technology since 2000. A pilot project using an H-50 turbine was launched in 2010, and MHPS plans to commercialize it this year. The H-50 turbine with AHAT outperformed the same turbine in combined cycle mode, achieving 70 MW output at 50.6% efficiency. Zirn said MHPS believes efficiencies above 60% are achievable with larger turbines.
MHPS is also developing a related retrofit product called Smart AHAT, which involves adding significant steam injection to a combined cycle arrangement, with AHAT’s water recovery system added to the exhaust. (For more on AHAT, see “Recent Innovations from Gas Turbine and HRSG OEMs” in this issue.) ■
— Thomas W. Overton, JD is a POWER associate editor (@thomas_overton, @POWERmagazine).