Pursuing a carefully charted course has led to higher emissions standards for genset exhaust.
By David Engle
“Diesel” conjures to mind the rumble of high-power-density engines that can do the job. Unfortunately, until a few years ago, you probably also winced your nostrils at soot-puffing truck tailpipes, toxic with the scent of that black hydrocarbon combustion.
But, beginning back in 1998, these unpleasant connotations began slowly to change; that was the year EPA presented the nation with its roadmap to a fresh and airy environment, relatively cleansed of the nitrogen oxide (NOx) and oily particulate matter (PM) that we all knew from those earlier days.
The laudable goal, to be attained progressively over the ensuing 16 years, was this: Annual NOx and several other emissions to be cut by nearly a million tons a year (equivalent of removing 35 million cars) by 2010; and, this at a reasonable cost, estimated at a very modest 1–3% tacked on to the price of typical new non-road diesels: net, about $600 per ton of NOx eliminated.
Pursuing that carefully charted course, standards have been ratcheting slowly higher ever since, year-by-year. We’re now at Tier 4, for non-road diesels. When the entire engine replacement cycle is completed, including both roadway and off-road or non-road diesels, the resulting hazardous emissions curtailment works out to an estimated 738,000 tons of NOx and 129,000 tons of PM, those being the two primary hazards (source: http://dieselnet.com).
|Photo: MTU Onsite Energy and Pacific Power Products
Each MTU Onsite Energy generator set has its radiator mounted outside of the enclosure and powered by a 100-hp electric fan.
|Photo: MTU Onsite Energy and Pacific Power Products
Generator sets at the Kensington mine site
feature sound-attenuated enclosures and SCR after-treatment systems.
And the third, being sulfur in the fuel: so, along with EPA mandating cleaner-burning engines, we also got a plan for low-sulfur diesel fuel (less than 15 ppm) to complete the clean-air effort. Although this element adds seven cents per gallon to fuel cost, it nets out to just three cents; four cents are saved in cheaper engine maintenance.
Any way you look at it (or breath it in), that’s a staggering improvement in the composition of our air. In human terms it means sparing 12,000 people from premature deaths by 2030.
The current Tier 4 standard, being phased-in over 2008 to 2015, now requires major reductions in NOx for engines bigger than 56 kW, and PM reductions for those above 19 kW.
Through the past decade, as EPA has applied these rules to genset projects, the onsite power industry sometimes bellyached about bureaucratic rigidity. (Why, for instance, should rules intended for urban areas be applied in remote, unpopulated ones?) But, generally speaking, the agency has also shown due regard for cushioning economic impact and grandfathering. Example: With an existing power project, the new standard would not usually be applied until the engine requires significant overhaul, “at which point you have to meet it,” notes Paul Johnson, marketing communications director for Woodward Control Solutions, a leading developer of emissions monitoring and control devices for the major original equipment manufacturers (OEMs).
Even better, from a project development standpoint, EPA’s approach has put the compliance burden on standardized engine designs: Once the quality goal is achieved by a manufacturer, the result is a pre-certified genset. In general it will automatically meet clean-running requirements, and reduce the onsite customizing tweaks.
Too, the technology for emission-scrubbing is now fully mature. It consists mainly of selective catalytic reduction (SCR), accomplished by injecting a urea solution into exhaust streams. Equipment for doing this was first developed years ago for diesel-powered vehicles, notes Johnson, “then migrated over to stationary generators;” that collaboration thereby save the power-generation industry from duplicative effort.
Also, a few anecdotes told off-the-record for this article reflect occasions when air-quality districts were even “generous” in granting unexpected leeway to project developers—without which, deals might not have been done. Typical statement of this type: “The project hinged on getting a permit without SCRs,” meaning, it that SCRs were technically either required or “borderline,” but the project got approved without them.
As one grateful engine dealer put it, “Just call it a business-friendly environment for local air-quality management districts.” Conversely, though, another onsite power developer complained that his competitors seemed to benefit from such favor, but he didn’t. Another commenter observed that, over the course of the several presidential administrations, EPA permitting standards seemed to become noticeably easier over time—then, after a change in government, “uncertainty” ruled again.
Also, in stride with tighter diesel combustion standards, natural gas has gone through ever-tighter NOx controls as well. Engine owners have been facing, says Johnson, “the need to take a look at upgrading control systems to meet those standards. Some older engines are either getting upfitted or retired—retrofitted, decommissioned, or replaced with new compliant engines.” Decisions on which course to take often hinge on whether the local Air Quality Management District faces EPA enforcement pressure applied to “non-attainment areas.”
Another influence steering these “exhausting” compliance issues is the shifting federal fuel support policy. It, too, moves around with successive government administrations. Subsidies for biofuels and the cleanest renewables perhaps represent a more emphatic shift away from hydrocarbon fuels of past years. Looking ahead, the current batch of federal and state tax and credit incentives seem to be pushing the country to favoring domestic natural gas. One of many examples: In September 2008, California enacted AB 811, an important DE-friendly bill enabling home and business owners to finance onsite energy “with a low-interest loans repayable through property tax assessment,” notes Mike Upp, of ClearEdge Power, which recently began introducing a consumer-level 500-kW “micro”cogen plant.
How are genset developers coping with the latest diesel and NOx standards? Of late, compliance dynamics have changed, compared to a few years ago, due to the downturn, followed by the Obama government and its stimulus and regulatory policies. To illustrate, here are a few developers’ challenges-and-solutions—at least, the ones they’re willing to talk about here!
A 1-MW Caterpillar C-32 plant for onsite cogen heat, cooling, and diesel-fueled primary power operates at a resort hotel on the Hawaiian island of Lana’i.
Kensington Gold Mine, Coeur, Alaska
Mission: Not-so-impossible, but really expensive. Suppose your assignment—should you choose to accept it—is to run a 1,200-hp, 4,160-V diesel genset that will crush rock and provide prime power for a $230 million gold mining investment, deep in Alaska’s interior.
Barely accessible, even on logging roads, there’s, obviously, no power grid or gas pipeline, and solar photovoltaic is sort of out, too. You need to energize an industrial site; your only practical choice is diesel.
You’re remote from much two-legged population—and yet, EPA standards demand the engine be equipped with SCRs, like gensets practically anywhere. That means, besides tanking-in fuel, you’ll be buying thousands of gallons of urea-based diesel emissions fluid (DEF) to dose and clean the exhaust.
But after checking with vendors, you discover DEF isn’t even made in Alaska. Historically, it’s shipped from the Lower 48. You’re not exactly on a regular UPS or FEDEX route here, so the rates for everything—fuel, urea, whatever—look like deal-breakers. As project manager Rick Elder, of Pacific Power in Tacoma, WA, recalls, “The quoted cost of cement chokes you”—over $1,000 dollars a square yard. Delivery access comes by helicopter or water and dock.
After seeing bids, what comes next? Answer: The idea of doing-it-yourself, i.e., making DEF in your own mixing plant. One hurdle here is freezing temperatures: You will need to warm hundreds of gallons of inflowing water from local streams, up to about 100°F. Then, after the DEF is mixed, it might freeze, so your ambient storage temperatures must always keep this in mind.
Even the question of which engine to buy had to be subjected to extra-rigorous scrutiny, in light of special site factors like higher hauling costs, the emissions profile, and fuel-efficiency hair-splitting. Example: Exceeding a contractual fuel spec imposes penalty of $75,000 per gram. So, this necessitated precise testing and verification, to ensue avoiding a huge hit. The gold mine owner, notes Elder, was naturally “very concerned about operating costs.”
Engine modules weighed close to 70,000 pounds and required extra trainage to get them up the mountainside to the mine shaft; switch gear had be specially designed in disassemble clamshell halves, so that each half could make it up the tight logging road.
Concrete bases for the machines were sort of pricey—again, at $1,000 per square yard; so gravel would have to do.
As for the engine selection: After scrutinizing WarZillas and CATs, the developer determined that EPA monitoring requirements in this case were driven more by the fact that the engine runs almost continuously, rather than by other engine quirks. Elder explains: “Once you start talking about primer power apps, up in Alaska, they're going [to look] into a total site emissions [in tonnage] for the year” as the determining variable in permitting. So, assuming the engine is Tier 4 compliant, the allowable emissions tonnage can be calculated from manufacturer specs. Permits were granted accordingly.
As for the engine itself: Thanks to that Tier 4 pre-certification, continuous monitoring turns out not mandated; however, costly annual performance validations are. So, factor-in a yearly visit from a third-party expert flying to the 49th state from half a world away. In the end, Pac Power happened to have on hand some suitable 2-MW Detroit Diesel D-Deck 4 engines; using open-loop exhaust dosing, these would do nicely and affordably.
For mixing DEF on the site, Elder’s crew designed and installed customized tanks and heating elements. Urea is now being stored handily in super sacks and kept super dry: urea is hydroscopic, and if exposed, hardens like cement.
Commissioned in mid-2009, the D-Decks were at first derated to 1,535 kW on the hope “that maybe they could get 30,000 hours out of them” in longer service, Elder says. But, once put to work, this output proved deficient, so re-rating will occur, and perhaps even more power added, by the time full-scale rock-crushing starts in mid-2010.
Though the site is often surrounded by snow and harsh conditions, a recent mineral assayer has reconfirmed the good news in this story: indeed, a major gold strike exists here. Along with crushing ore, Elder observers: “they’ll be doing a lot of snow plowing.” And, for himself, he says, the labor has proved interesting and challenging—“a once in a lifetime project.”
Four Seasons Resort, Lana’i, at Manele Bay
This genset project, at a luxury five-star hotel, delivers not only clean prime power, but the efficiencies of captured waste heat, and much-needed emergency power generation.
What’s a bit unusual here, though: the hotel which benefits is not the engine owner; rather, the tiny local utility company Maui Electric Company Ltd. (MECO, a subsidiary of Hawaiian Electric Company Inc., HECO), owns and operates it, to mutual advantage.
MECO recently partnered with Castle & Cooke Resorts LLC and the Four Seasons chain to install a 1-MW Caterpillar C-32 plant for onsite cogen heat, cooling, and power. Dan Suehiro, a project manager for the utility, gives some of the context: Lana’i Island’s modest peak demand reaches only 5 MW; this load is served by two, 2.2-MW Caterpillar units at a central station, along with some vintage backup engines and peakers. “So adding one megawatt is very significant,” he says, and MECO was happy to collaborate with a local commercial customer to share it.
For its part in the deal, HECO gains the dispatchable capacity, plus metered revenues from both the genset and the utility’s regular 12-kV feeder. In this configuration the two power resources backup each other—something very desirable for both the hotel and Lana’i’s “microgrid” reliability. A nominal charge to the customer for engine waste heat helps recoup the cost of the Cain heat recovery system.
For the hotel’s part, captured exhaust heat adds BTUs to a domestic hot water loop and also activates a York absorption chiller loop, delivering 115 tons of air-conditioning.
A San Diego, CA-based Caterpillar dealer, Hawthorne Power Systems, provided the genset, switchgear, sound-attenuated enclosure and controls for the CHP unit, notes HPS’ Neal Johnson.
Emission compliance on the project was, relatively speaking, “a breeze.” This case illustrates how EPA’s strategy of emphasizing higher manufacturing standards, and pre-certifying them, benefits the cogen marketplace by making small engines easier to permit. As Suehiro adds, there is also a regulatory proviso for local flexibility. In this case, Hawaii lacks an infrastructure for the usually preferable fuel, pipeline gas; thus, diesel is the only practical fuel. The state’s air permit rule, therefore, does provide Islanders the option of imposing, says Suehiro, “a fuel limit on small projects such as this one, rather than requiring installation of an expensive continuous emissions monitoring system or performing periodic emissions testing.” Simply capping fuel consumption this way “is a much more practical way to manage emissions,” he finds. And it enabled the much-needed project to go forward.
New Belgium Brewing, Fort Collins, Colorado
This isn’t a diesel story, but it tells of the implications in converting an engine from pipeline gas to digester methane. Given the fervor these days for refueling with things like renewable biowaste, this kind of engine unfitting may as well have become commonplace (as federal priorities increasingly tend to push it).
Johnson explains the tech issue in using a retrofit kit to convert from pipeline gas to a locally produced landfill or digester methane. The latter, he says, “is tricky because the heat content of the fuel changes over time. It’s inconsistent, and its burn characteristics fluctuate.” When BTU content is high, overheating can result, and rapid burning may cause damage. Likewise, ignition inconsistency causes engine knock. These are common (though not insurmountable) difficulties in using digester methanes.
Such was the concern and occasional experience at New Belgium Brewing Company (NBB), in Fort Collins, CO. In 2000, the brewery wanted to fuel its 292-kW Gauscor engine (a Spanish import) with biogas from the anaerobic digester that helps process brewery wastewater. In this somewhat ingeniously efficient operating cycle, the production of gas neatly coincides with engine fuel demand. Typically the Gauscor runs “eight to 12 hours daily,” notes NBB sustainability director Jennifer V. Orgolini. Digester methane inflates large storage balloons over the tanks; the methane is thus prevented from adding to the planetary greenhouse effect. Each day, the balloon swells ever larger, then shrinks again as it feeds its fuel to the genset. Imagine a sort of giant energy respirator. “We harvest the methane and use it to shave our peak loads” (hitting about 1.3 MW), explains Orgolini. Coincidental peak pricing from the utility grid hits $14 a kilowatt then, though, at other times, the community enjoys very low base rates of just four cents per kilowatt-hour (5.5 cents with taxes and surcharges). Grid power is thus so cheap that an onsite system doesn’t really pay, on strictly business terms, she concedes. In fact, even with the self-manufactured digester gas, the cost of power self-generation comes out at about eight cents per kilowatt-hour. However, the cogen plant also warms the brewing vats, and the company affirms it commitment to sustainable renewable energy and also onsite water treatment efficiency. So, the investment is considered well spent.
Technically, the only glitch here, she says, is “dealing with the richness of the gas,” necessitating help from Woodard Control Solutions. The latter’s ignition gadget has now solved the problem, while curtailing NOx and remaining in EPA compliance.
As Woodward’s, Johnson explains, the retrofit kit is called “the comprehensive E3, for ‘all encompassing engine emissions,’” and it enables the blending of multiple fuels. “You can mix either this biomethane or pipeline quality natural gas, or any combination of the two, on the fly,” he says. The main element is a precision fuel-metering valve, which gauges the incoming gas; then, a high-energy ignition system follows on, “making sure the fuel-air mixture ignites properly.” It’s a detonation system, “so that if you get into engine knock situation it will back off appropriately to keep you out of knock,” he adds, and controls are handled at an interface panel.
Coming up in 2010, NBB will commission another engine, this a 260-kW Cummins, also for peak shaving. Woodward is donating the engine, as part of a demonstration project under the Smart Grid program, for which Fort Collins has received federal funding. Although the Cummins was designed for diesel fueling, another Woodward conversion kit will enable burning of digester and/or pipeline gas in combination. Thus, assuming that both this and the Gauscor conversions work well over time, these projects will be trail-blazers for other engine-owners seeking to keep their engines but switch to renewable fuels, which will likely be incentivized.
Meanwhile, the Gauscor will also be up-rated this year to 320 kW, enabling the two engines to take care of most of the brewery’s daily peak load spike.
NBB is also a collaborator with the city and DOE on the Smart Grid, and will soon be exploring load shedding and power management. To follow Smart Grid progress in the community, dubbed “FortZED” for Zero Energy District, visit the Web site at http://fortzed.com.
Coming Just Ahead…
More target dates for EPA’s cleaner engines and emissions campaign come due soon: In June 2010, roadway diesels must hit their next compliance benchmark, and in 2011, non-road engines face another “not-to-exceed” emissions limit for engines above 130 kW.
In 2012, comes a plateau for 56- to 130-kW engines to meet, and in 2013, for engines below 56 kW.
Finally, by 2014 … we should be done. And we’ll all breath easier about compliance, too.
Author's bio: Writer David Engle specializes in energy-related topics.