Rick Owen, combustion turbine specialist for the City of Burbank, CA, received shipment of the first production version of Ingersoll Rand’s new 250-kW recuperated-exhaust microturbine early in 2005. Year-end verdict: “It’s been running exceptionally well,” he says, with only a single equipment-related shutdown.
It has also neatly solved a problem the city had in finding right-sized equipment for this relatively small landfill. Until the 250 kW came along—which is now the largest microturbine on the market—earlier turbines in the 30-70–kW range, as well as reciprocating engines of larger sizes, weren’t quite right for the modest methane output. But 250 kW of power (220-225 net) is achievable with extremely low operational and maintenance overhead. Gas that was being flared is no longer wasted. The 250 “puts out good power,” he says, “and the parasitic load is not very high,” i.e., the 30 kW or so on hot days, needed to run the integrated fuel conditioner which cleans and compresses the gas. All the remaining power goes to the city grid. Owen sums up: “If you’re interested in burning landfill gas, this is a nice, easy, cheap way to do it.”
A similar situation existed at the Los Angeles County Sanitation Districts—consisting of 16 landfills and wastewater treatment sites of assorted sizes scattered among a population of about five and a half million. Most of these sites, as LACSD’s Ed Wheless notes, yield enough landfill gas (LFG) to power multi-megawatt generators. Total output comes to 127 MW, of which 29 MW supports plant operations The balance— about 98 MW —gets sold to Southern California Edison In this market, and at a sizeable scale, “it’s very easy” for him to cost-justify onsite power plants. But it’s quite a different story at smaller LFG sites where assorted problems make power extraction less viable.
Fuel-Conditioning Challenges
On this score, one major issue is gas quality. Pipeline gas is typically clean, dry and ready to burn. However, as Ingersoll Rand’s Jim Watts explains, “with what we call ‘environmental fuels’—i.e., digester gases, LFG, and fuels recovered in industrial processes— these typically enter the extraction system saturated with moisture and usually contaminated with silicon-based organic compound like siloxane— “a nasty little fluid,” he says, which precipitates as solid silica (SiO2) sand-like particles. Watts is Ingersoll’s product manager for the 250 kW.
Naturally, siloxanes and precipitates must be removed to prevent fouling. This is done with solid filtering media—a methodology originally developed some years ago, and more recently packaged with compressors to work with microturbines. Field research on this fuel-prep innovation was largely conducted at LACSD and implemented locally a half-dozen years ago. Owen’s department, for one, had installed an array of ten Capstones 60kW microturbines, but the dirty LFG in Burbank, he recalls, “tore those up.”
Subsequently, fuel-filtering was developed across town at the LACSD site, then implemented in Burbank and elsewhere by SCS Energy, an engineering firm based in nearby Long Beach. SCS had installed the very first commercial LFG-fired microturbine power plant anywhere; in 2001, and went on to design or build 14 more plants, employing a total of forty microturbines. From such field experience SCS developed a fuel preparation and compressor skid (costing in the neighborhood of $200,000). It delivers up to 400 scfm of dehydrated LFG at 70 to 110 psig pressure.
For the sake of backup redundancy, three parallel compressors (rather than a single one) were installed in order to accommodate the maximum anticipated gas volume. In addition, apart from the skid there are two polishing vessels in series, containing 2,000 lbs of activated carbon. (SCS selects filtering media to be site-specific, an SCS report on the project notes.). Both polishing vessels are dedicated to the Capstone microturbines, which require complete siloxane removal.
Owen reports: “The Capstones are now doing fine.”
Likewise, when Ingersoll installed the 250 kW last year, Burbank opted to have an identical SCS Energy fuel conditioning skid service it. Skid components include an inlet moisture separator; rotary vane compressor; a chilled water heat exchanger to reduces LFG to 40 degrees F; a gas reheat heat exchanger to add 20-40 degrees F above dew point; and optional polishing vessels charged with activated carbon and/or other media. SCS engineer David Penoyer, who is now with SCS’ Tampa office, states that, “One of the purposes of the 250-kW microturbine demonstration project was to evaluate its siloxane sensitivity,” in a report he recently presented to waste industry managers in Florida.
All told, about a dozen SCS fuel-prep skids are in operation to date, and are also being used to service a fuel cell and reciprocating engine.
According to data reported by SCS Energy, the overall project costs using LFG, microturbines and SCS Energy fuel skids price-out to about $2,500 to $3,000 per kW. Inasmuch as the gas supply itself is sort of “free,” the investment usually pays off nicely, especially in California, which has high power rates.
Fueling Improvements...
A Chilling Thought
However, the current technology for filtration-based fuel-preparation carries some drawbacks, as Wheless points out. First, the volume of filtering medium that will be needed amounts to thousands of pounds. Second, the precise amount that will be needed is hard to predict and varies with the amount of siloxanes in each landfill. As a result, says Wheless—who is LACSD’s division engineer in the solid waste management department—time-consuming inspections of filters are required. “If you have a break-through” or filtration system failure, he says, “how do you know it? You have to test, on a regular basis—and you don’t know if you’re doing it frequently enough,” he says. Testing is also expensive.
Problems aren’t so bad, though, where siloxane volumes are low; there’s one site, for instance, he says, “so low so low that we can put in a couple of thousand pounds of media and then just change it out every year, for a couple of thousand dollars.” Capstone microturbines have been “working great” there for three-plus years, he adds.
Unfortunately, most sites have higher siloxanes than this—sometimes much higher. Wastewater digester biogas also usually comes out laced with siloxanes, he notes, albeit at more predictable quantities.
Bottom line: Gas treatment typically adds many thousands of dollars in first cost and lifetime system cost to these systems.
Again, in smaller-volume sites, this has historically been a deal-killer.
However, Wheless happily reports that, along with the arrival of Ingersoll’s 250 kW has come an entirely new, very different and apparently better, lower-cost method for integrated fuel-preparation. Speaking of the thorny fuel-conditioning problem, he says, “I think we’ve found the solution.”
IR and LACSD have collaboratively devised a gas-cleaning method suitable for even very moisture-and-contaminate-laden gas, which produces reliably clean and steady supply—with virtually unattended operation and without reliance on solid filtration. The system takes raw, newly extracted LFG or biogas, then runs it through a chiller that takes the temperature down to -20 degrees F—and presto, in so doing, about 95% of moisture and contaminants are frozen out. After removal, the cleaned gas is then reheated for use.
Moreover, field trials and initial results show that the chilling-and-purifying performance remain consistent, as long as a frigid -20 degrees F is maintained. Here, adds Wheless, “a thermocouple is telling you that your system is meeting the temperature requirement”—making it easy to remote-monitor.
Only nominal maintenance is needed; there’s no laborious inspection or change-out of media, nor of hazardous or non-hazardous desiccants. Full remote operation for both the fuel-conditioner and microturbine is provided by microprocessor controllers; start-stop, data retrieval, and monitoring, are Internet-based. Compensation for fuel Btu variances is automatic, and so on.
Wheless observers: “It’s an elegant solution which makes more sense” than the predecessor.
Right-Sizing at LACSD’s Lancaster, CA, Plant
Despite a dozen-plus booming power plants in the Sanitation Districts, one lone facility had remained stubbornly untapped. The plant does multi-stage treatment of 16 million gallons, serving about 160,000 people. Its digesters were already generating about 140 cubic feet per minute (cfm) of gas containing 55% methane—90% of which had historically been flared. The other 10% was being burned as process-heat for the digesters.
Thus, Wheless’ department set its sights on turning the unused fuel at Lancaster into electric power (as well as equipping one other remaining small landfill with a reciprocating engine).
Ingersoll Rand shipped a prototype of the 250 kW and its innovative fuel chiller-conditioner to LACSD in June 2004—then promptly asked for it back, in order to do further refinements.
A year later the system was re-delivered, ready for work.
Commissioning came, as Wheless recalls, right at the peak of the 2005 summer desert’s heat. For a chilling-based system, this severity would provide the ultimate challenge. Commissioning coincided with the perhaps toughest possible conditions. Day-to-nighttime temperature swings initially played havoc with the “gas-freezer,” Wheless candidly remembers. A duplex heat exchanger was experiencing recurring ice buildup on the active exchanger, necessitating melting, alternately “shifting back and forth” between chilling the gas and thawing the resulting ice. “It’s been tricky getting it right,” he says.
As of late 2005, corrective adjustments were still being made. By year-end, Wheless expected remedies to be working smoothly so that the system should being operating year-round as designed. With its maturity, he adds, “It’ll open the door to all kinds of applications for Ingersoll Rand, because they’ve gone through the growing pains to marriage these two systems together.... They took the time and effort to do the QA/QC, to oversee the manufacturing, and to put in the kinds of controls you need in order to build a whole lot of units. They’re really committed to this market.”
On that score, Ingersoll’s manager of energy systems, Holly Emerson, notes that the company has identified upwards of 50 wastewater treatment plants and 80 small-to-medium sized landfills, primarily in California and New York, as prime candidates for the 250 kW package.
Power, Performance, Payback ...
With the Lancaster system’s chiller and compressor absorbing 25 kW, net output comes to 225 kW of electricity—or enough, says Wheless, to cover about a quarter of the plant’s 841 kW total demand.
Along with this comes cogenerated hot water coming off the turbines’ exhaust heat exchangers; it circulates back into the digesters, keeping the bugs warm and hungry so that they’ll optimize gas output. About 60% of this fuels the turbine—leaving enough surplus to warrant envisioning a second engine at some future date. Net electrical/thermal efficiency currently comes to 51%.
Engine output, he notes, can run independent of the grid. So, if the latter goes down, the Ingersoll provides backup. Conversely, when the turbine goes offline, the utility power steps up, and a boiler ignites to warm the digesters.
One of the best parts of the deal, from LACSD’s standpoint: Running the power plant is left entirely to Ingersoll. The Sanitation Districts “doesn’t even have to think about” operation or maintenance, says Wheless, and he and his colleagues can devote themselves entirely to the treatment plant operations.
LACSD’s total installed cost at Lancaster came in at $720,000. Forty percent was offset almost immediately by a grant from the California Public Utilities Commission under its Self Generation Incentive Program. Somewhat more typical installations elsewhere might cost a future buyer, as Ingersoll’s Watts suggests, “somewhere between $1,500 to $2,000 per kilowatt.” This puts the microturbine plant in the same price range as recip engines.
Wheless’ department calculates that power production at Lancaster now costs only 4.3 cents/kW-hr (1.6 of that being for O&M, and 2.7 for capital recovery). This sum offsets a very high local utility rate, currently about 13 cents/kw-hr. Thus, the LACSD Lancaster power plant will save the Sanitation Districts some $225,000 yearly on electric bills. Payback is expected within about two-and-one-half years.
What also makes it ‘go,’ financially, is the combination of good power output and little or no maintenance. Prior to installing the big microturbine, Wheless says, “we actually had tried [an internal combustion engines]—and it didn’t work at all, because IC engines take a lot of attention. You have to change the oil, and filters, and the sparkplugs, and it just takes a lot of time and effort to do that.” Ultimately, the ICs “hardly ever ran, because, clearly, the operators have more important things to do.”
Finally, though, California’s high spark spread “makes this kind of a no-brainer for us.” Other markets with much cheaper utility rates may not benefit so dramatically, of course.
The Lancaster demo has been sort of a high-profile project for the wastewater and solid waste industries, Wheless notes. The results have been eagerly awaited. When Wheless speaks about it to industry groups, he summarizes the reasons favoring installation of the 250 kW in place where, formerly, the numbers didn’t work:
- Saving money on power purchases;
- Improving power reliability by having a primary or backup heat source for the digesters during grid power loss; the 250 kW “can synchronize with backup diesel generators,” thereby enabling “much longer running;”
- Lower net emissions;
- Relatively low maintenance and unattended operation, which is easily outsourced.
The 250: Building a Bigger, Cleaner Microturbine
Ingersoll’s Watts notes that the new 250 design benefits from a predecessor model, the KG 2MW Dresser Rand which has a lot of similarities. Designers also gained from their experience with Ingersoll’s 70-kW microturbine, particularly regarding the handling of gases. Both can use btu values ranging from the very-low-end at 350 Btus per cubic foot; “environmental fuels” derived from wastewater, agricultural digesters, and some landfills producing about 600 to 700 Btus per standard cubic foot, he notes.
Mid-range pipeline gas at about 1,000 Btus is of course usable, as is high-energy propane at about 2,300 Btu, Watts says. The full range can be accommodated by means of assorted combustor configurations, which a customer may pre-specify.
Watts describes a rugged fuel compressor which employs, he says, “two intermeshing screw-shaped rotors,” which squeeze the gas volume in a single direction. Because they’re completely sealed, the microturbine and fuel compressor system qualifies under the National Fire Protection Association for indoor usage, and so too under the electrical codes. For outdoors, the system can be packaged in a standard IR enclosure.
Waste heat from the 250, available at nominally 500 degrees F, can be captured by a state-of-the-art recuperator. Heat recovery is completely packaged within the engine enclosure and requires no dump radiator for times when a thermal load is absent. Hot water output is rated for potable service. Hence, it can be used directly for cooking, washing, hydronic space heating, or other domestic service. The turbine’s exhaust heat can also directly regenerate a dehumidifier’s desiccant wheel.
The 250 is available in both 60-Hz and 50-Hz configurations and designed for a life of 80,000 hours with overhauls
Low Emissions: First to Win “.07/’07” Certification
As stated above, the 250-kW microturbine holds the distinction as the first gas-fueled engine to receive a passing grade under the California Air Resources Board’s (CARB) tough .07 NOx standard. This is scheduled to become effective Jan. 1, 2007.
Before this, in 2003, Ingersoll had also gained certification for its 70-kW microturbine, at the .49 NOx standard (i.e., seven times higher than the forthcoming limit). Watt’s notes: “With the 250 we knew we wanted to sell it in California. In some air-quality control districts, permits are required for a 250 kW, but in others, where the engine size limits are higher, there’s a need for engine certification.” Thus, he made CARB certification a priority.
Ingersoll hired a testing firm to perform the CARB emissions measurements, and the engine passed, with the help of an additional credit received for combined heating and power (CHP) efficiency. Watts is proud that, even without the credit, the low emissions very nearly passed. The 250 microturbine outputs less than 9 ppm NOx & CO at 15% O2.
Too, it will continue to comply while load-following, although typical turbine operation involves continuous running during the load period. Shutoff entails cooling down of the engine’s exhaust recuperator, requiring several hours to do. Hence, frequent on-off cycling is undesirable.
The recuperator acts as a thermal mass, capturing heat for the cogeneration.
The recuperator design also enables the engine to reach 29 or 30% efficiency (which varies depending on the fuel-conditioner usage), and helps minimize NOx levels in the exhaust.
“The combustion process is very conservative and non-aggressive,” Watts explains, “which is important because NOx output is determined by how long your gases are at high temperatures.”
Conservative combustion takes place because the intake air “is coming in with a lot of heat already, from the recuperator,” he says. “By not burning as much fuel, gases spend less time experiencing the hottest portion of the combustion process. That definitely helps in NOx reduction.”
Besides gaining this green benefit, the engine eliminates the need for flaring of LFG or surplus digester gas, which is also, of course, “environmentally correct.”
In sum, the Lancaster application, notes Wheless, “eliminates its weight in CO2 every day.”
La Mesa, CA-based writer DAVID ENGLE specializes in construction-related topics.
DE - May/June 2006
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