Once merely a staple of backup and distributed generation, reciprocating engines are now challenging other resources for utility-scale generation—in addition to carving out some new niches.
Grant County is a rural, sparsely populated county in southwestern Kansas. It doesn’t have a lot of people—its population in the 2010 U.S. Census was just 7,829—but what it does have a lot of is wind.
Like the rest of Kansas, Grant County is in the middle of the nation’s best wind resource area, giving the state the second-highest wind potential in the country, according to the American Wind Energy Association. Kansas gets about 20% of its electricity from around 3 GW of installed capacity, with more on the way. One of those new wind farms, the Buffalo Dunes Wind Project, a 250-MW farm being developed by Lenexa, Kan.–based Tradewind Energy, will be partly located in Grant County.
The Mid-Kansas Electric Cooperative is a coalition of five rural electric cooperatives and one wholly owned subsidiary serving customers in central and western Kansas. Mid-Kansas owns 179 MW of wind generation along with about 550 MW of gas- and coal-fired capacity—the newest of which came online in 1978. With the Southwest Power Pool transitioning to an integrated market this year, Mid-Kansas needed quick-responding generation that could meet its future needs while providing badly needed voltage support for the area.
It should come as no surprise that Mid-Kansas opted for gas-fired generation, but not so long ago, it might have raised eyebrows that it opted to use reciprocating engines to power a 110-MW plant. These days though, the combination of cheap natural gas and advancing technology has taken reciprocating engines out of their traditional role as backup and distributed generation into direct competition with gas turbines, coal, and even nuclear.
Fast, Flexible, Efficient
“Reciprocating engines are becoming an increasingly popular choice of prime mover technology for utility-class generation assets,” Dean Powell, general manager of Power Plants & Key Accounts at Caterpillar told POWER. In many ways, Mid-Kansas’s Rubart Station, under construction in Grant County, with completion scheduled for this month, exemplifies how gas-fired engine plants are carving out a serious niche in utility-scale generation worldwide. The project, being built by Burns & McDonnell, will comprise 12 Caterpillar G20CM34 generator sets (Figure 1). The G20CM34 is a new offering from Caterpillar, and Rubart Station will be the first plant to employ it, as well as the largest power plant Caterpillar has ever built.
|1. Ready to rock. This bank of 12 Caterpillar G20CM34 gas-fired generator sets will power the new 110-MW Rubart Station plant in Kansas. Courtesy: Caterpillar|
What Rubart will offer Mid-Kansas is a plant that can reach full power in less than 8 minutes, ramp up and down continuously with little effect on heat rate, while requiring relatively little maintenance and support compared to more complex gas turbine–based plants. What engine-based plants give up in efficiency compared to combined cycle plants, they more than make up for in flexibility—and those combined cycle efficiency advantages start to ebb away in a rapid-cycling environment.
The advantage comes in the modular nature of the plant. Unlike gas-turbine plants that may have only one or two units to ramp up and down, multishaft engine plants can scale their output by taking individual units offline, while the remaining units can continue running at peak efficiency. And when waste heat recovery systems are added, such as with Wärtsilä’s Flexicycle design, combined cycle gas engine plants can match or beat combined cycle gas turbine plants for efficiency in peaking and load-following modes. That matters for a plant like Rubart, which will be backing up a lot of wind generation.
Additionally, maintenance can be handled with less overall downtime, since each engine can be serviced individually without affecting the others or requiring a plantwide outage. That’s an advantage for remote areas and especially for areas in the developing world where the grid may already be variable enough. (For a review of a similar plant with a similar role, see “LCEC Generation Plant, Lovington, New Mexico” in the September 2012 issue.)
Bigger and Better
When it comes to utility-scale engine-based plants worldwide, Wärtsilä has been a leader for several decades, with 56 GW of global installed capacity. Recently, however, Wärtsilä has made a push toward even bigger plants that dwarf the 50-MW to 200-MW offerings that have thus far been its staple. It recently delivered its first Flexicycle plant in the Dominican Republic, the 430-MW Quisqueya facility in San Pedro de Macorís, which came online at the end of 2013 (Figure 2). Consisting of 24 of Wärtsilä’s 18V50DF dual-fuel engines and two associated steam cycles, Quisqueya feeds both a nearby gold mine and the national grid. The size and flexibility of the plant allows it to supply both baseload demand and voltage support for the grid. (For more on the Quisqueya plant, see the Top Plant article in this issue.)
|2. Big presence. The 430-MW Quisqueya I & II plant in the Dominican Republic is one of the largest gas-fired engine plants in the world. Plants like this are increasingly competing with other options for large-scale generation. Courtesy: Wärtsilä|
But Quisqueya will not be the largest for long. Wärtsilä is supplying an even bigger plant in Jordan, the 573-MW Al Manakher plant outside the capital of Amman. That project is being built by a consortium composed of Wärtsilä, Mitsubishi, Korea Electric Power Co., and Lotte Engineering and Construction, and is projected for final completion this fall. This plant will also employ the 18V50DF engine—a whopping 38 of them. The Al Manakher plant will be followed by another Jordanian project, albeit about half the size, that Wärtsilä is supplying for AES and Mitsui.
Wärtsilä is still developing smaller plants and is aggressively pursuing roles that are ill-suited for gas turbine–based plants. Its new 20V32TS engines are a two-stage turbocharged version of its 32 series designed specifically for extreme ambient conditions. One of the first deliveries is for a 47-MW captive power plant at a cement factory in the mountains of western Saudi Arabia. Temperatures at the site—which is at an elevation of 1,000 meters—can reach 50C in the summer. Such an environment will challenge gas turbines, but turbocharged engines like the 20V32TS can handle them with relative ease.
Combined heat and power (CHP), or cogeneration, has been a familiar niche that reciprocating engines—mostly diesel—have helped fill. But as smaller gas turbines have begun competing with diesel as liquid fuel prices have skyrocketed, gas-fired engines are not giving up their turf.
General Electric’s (GE’s) Jenbacher line from its Distributed Power division has long been a cogeneration workhorse, but recent advances have made it more competitive than ever. The new J920 FleXtra, a 9.5-MW two-stage turbocharged engine, can achieve electrical efficiencies up to 48.7% at 50 hertz. The first one was delivered in July to E.ON Hanse Wärme GmbH’s Stapelfeld CHP plant in Germany, which will be E.ON’s largest engine-powered CHP plant in the country (Figure 3). GE and E.ON have developed an innovative CHP system for this engine that achieves total system efficiency of approximately 95%. The 60-Hz version of the J920 FleXtra, with a capacity of 8.6 MW, became available in North America this summer.
|3. Heating up. General Electric’s new J920 FleXtra engine is one of its newest, most efficient offerings. This one will power a combined heat and power plant in Germany. Courtesy: GE|
Smaller Jenbacher engines are powering other CHP projects in the U.S. and elsewhere. GE announced in July that it would be supplying a 13.125-MW CHP plant in Merida, Mexico, employing three turbocharged J624 gensets. The plant will supply power to the grid and process steam to an adjacent manufacturing plant.
GE has also been pursuing a new niche for engine-based CHP systems, one that employs a form of carbon dioxide (CO2) capture. But while larger carbon capture projects are looking for ways of sequestering CO2, such as via enhanced oil recovery, GE’s solution employs it for a more basic function: growing plants. The first such system is in operation at a tomato farm in California, supplying electricity for farm operations, and heat and CO2 for the greenhouses. (For more on this innovative project, see “Tomato or To-mah-to? GE Gas Engines Do Triple Duty in California Hothouse” in the October 2012 issue of GAS POWER.)
It’s not just natural gas seeing increased use in reciprocating engines. As biogas and landfill gas are being increasingly captured and used, gas engines are often the first choice for power generation because of their flexibility and tolerance for a wide range of fuel qualities.
GE recently supplied 10 Jenbacher engines to power the largest landfill gas plant in France, the 17.3-MW Electr’od cogeneration plant in Plessis-Gassot, outside Paris, which was built by Clarke Energy. The new plant replaced an old, inefficient steam boiler and turbine system, and supplies district heating to buildings in the town center. Power output was increased by 5 MW, and overall efficiency was nearly doubled. GE and Clarke Energy also recently partnered on a project in the UK to upgrade several landfill gas plants operated by waste management company Biffa.
Though it has made a major—and highly successful—push to introduce its gas-fired vehicle engines for fleet use in the U.S., Cummins is also focusing on power generation. It recently supplied the prime mover for an anaerobic digestion plant in the UK. The project at the Nocton Fen Farm in Lincolnshire employs a 2-MW C2000 N5C genset that burns biogas from a mixed biowaste digester (Figure 4). The system can export power to the national grid and also has a waste heat recovery system.
|4. Down on the farm. This 2-MW Cummins C2000 N5C genset runs on biogas produced from an anaerobic digester at a farm in the eastern UK. Courtesy: Cummins|
The growing market for gas-fired engines and engine plants is leading to some new alliances. MAN Diesel & Turbo, though a traditional force in diesel generation, also offers gas-fired engine options, some of which have been converted from its diesel-fueled models. In July, MAN and Fairbanks Morse announced a strategic alliance to supply the U.S. power sector with gas-fired and dual-fuel engines. Fairbanks Morse offers dual-fuel engines up to 4 MW, but partnering with MAN will give it access to MAN’s portfolio of larger engines, up to 17.6 MW (Figure 5). MAN has already supplied a number of gas engine plants outside the U.S.
|5. Gas workhorse. The four-stroke, gas-fired 51/60G is MAN Diesel & Turbo’s largest gas-fired engine. The unit has an output of 18.9 MW. Courtesy: MAN Diesel & Turbo|
A sector as mature as the internal combustion engine might not seem ripe for major technological innovations. But that’s just what may be coming if GE has its way.
Last year, GE disclosed that it was working on a hybrid fuel cell–gas engine system that would leverage advances in solid oxide fuel cells (SOFCs) it has been developing. Natural gas would be passed through the fuel cell, and the mostly syngas output would then be burned in an attached engine. However, no details were released at the time.
Then, this July, GE announced what it called a “game changer” in SOFC design that uses stainless steel in place of far more expensive platinum. That makes it potentially much more economical than previous designs. GE says that when paired with a Jenbacher engine, the prototype system, which is scalable from 1 MW to 10 MW, has an electrical efficiency of 65%–substantially higher than simple cycle gas turbines, and comparable to proposed fuel cell–gas turbine hybrids (see “Major Developments for Solid Oxide Fuel Cells” in the August 2012 issue). When waste heat recovery is added, a total system efficiency of at least 95% is achievable. Though an actual product is still years away, this development promises to further expand the reach of gas-fired reciprocating engines.
Meanwhile, back in Kansas, the folks at Rubart are looking forward to getting under way.
“Rubart Station demonstrates that even larger-capacity facilities can benefit from the operational flexibility and comparably higher efficiency that this technology provides,” Powell said. ■
— Thomas W. Overton, JD is a POWER associate editor (@thomas_overton, @POWERmagazine).
[This article has been updated to correct the image used in Figure 5.]