What’s Up With Lean-Burn Natural-Gas Gensets

March 1, 2004

Convinced that reciprocating engines fired by natural gas will play a major role in the future of distributed energy but that key technology challenges remain to be addressed, the United States Department of Energy has set the goal of a more efficient and cost-effective lean-burn gas engine within the next five to seven years. The goal for this new era is a fuel-to-electricity conversion efficiency of at least 50% (30% higher than what’s currently available), NOx emissions of 0.1 g/bhp/hr. (a 95% reduction, which still will need aftertreatment to meet tough air-quality standards in such places as California’s South Coast Air Quality Management District), installed capital costs of $400-$540/kWe and significant reduction in maintenance costs. The program is called Advanced Reciprocating Energy Systems (ARES) and so far has the support of the major engine manufacturers working in concert with the national laboratories and selected universities to expand the use of reciprocating engines for distributed-generation (DG) applications.

According to former ARES Program Manager Joe Mavec, the project was launched in September 2001 and will proceed over three phases with research on advanced materials, fuel- and air-handling systems, advanced ignition and combustion systems, catalysts, and lubricants. Phase I is scheduled for completion during 2004-2005, while the deadline for final Phase III is 2009-2010. Cummins Power Generation, Caterpillar Inc., and Waukesha Engine Dresser Inc. have received Phase I grants and are “following individual research paths,” as John Hoeft, director of marketing for Waukesha, puts it, based on each company’s marketing target. “At Waukesha we’re working on the 1-megawatt-size product,” says Hoeft, “and we’re looking at a redesign of our VGF [engine], our V16 platform to get there.”

A non-nonsense, long-established, and extensively used power-generating technology that requires fuel, air, compression, and a combustion source, reciprocating engines fall into two categories: spark-ignited engines fueled by natural gas and compression-ignited engines that run on diesel fuel. Gas engines are currently available in two versions: rich-burn and lean-burn, the latter made commercially viable when microprocessors made it possible to efficiently control critical fuel flow and fuel-air gas mixture plus ignition timing. In a lean-burn engine, excess air is introduced into the engine with the fuel, which reduces the temperature of the combustion process, which in turn reduces by almost half the amount of nitrogen oxide produced compared to rich-burn engines. And because excess oxygen is available, combustion is more efficient, producing more power with the same amount of fuel.

“Distributed-power applications favor natural-gas technologies first and foremost because they deliver low air emissions,” says Caterpillar’s Gas Product Marketing Manager Michael Devine. “Diesel-fueled systems still dominate in standby and short-run installations, but right now gas is better at combining availability, price, and environmental compliance. Gas-fueled generator sets can be on-line and producing power within three to six months of when they’re ordered at a cost that varies from about $350 to $600 per kilowatt.”

Devine says Caterpillar has already hit the market with ARES-style improvements. “The G3500C engine program and its advanced gas-engine control module is an offshoot of ARES. The new control system solves some of the challenges that have typically affected the efficiency of lean-burn engines, including maintaining air-fuel ratio and constant emissions control.”

Technological advances aside, choosing a natural-gas learn-burn generator set from what’s now available requires a thorough assessment of the amount and duration of power to be generated, which must in turn be balanced against installed cost, engine efficiency, and emissions control. While large-scale DG applications have sometimes favored 24/7 cogeneration systems, Devine reports that smaller industrial users and some utilities are opting for selective usage, sometimes running as few as 500 hr./yr.

But Stan Price, project manager for Northern Power Systems Inc. in San Francisco, CA, wonders about such short-hour applications. “We try to select equipment so that it runs at least 4,000 to 4,500 hours a year as close to its full rating as possible. If the capacity factor is below 60%, I begin to wonder whether the economics are going to make sense for the customer. What’s got to drive the decision to put in a genset for, say, 1,200 hours a year is the fact that loss of power during an interruptible period is very expensive in terms of lost product. The company is not just saving money on electricity, they’re saving on product costs.”

At Waukesha, Hoeft thinks the choice of an engine begins with emissions requirements. “Once you look at kilowatt size, you make your decisions based on the product mix and meeting the emissions requirements, then on how much efficiency you want. It’s a tradeoff between emissions and efficiency and first [installation] costs.” 

Chach Curtis, vice president of onsite generation for Waitsfield, VT-based Northern Power Systems, notes that while lean-burn engines have become the industry standard – particularly in Europe because they are typically anywhere from 3 to as much as 10% more efficient in converting fuel to electricity – there also is a market for rich-burn engines. “In states like California and New Jersey and New York and now Massachusetts, both systems are going to need some kind of aftertreatment. For the rich-burn engines, it’s a cheaper, simpler process. So, in these states, you have to look at the higher cost of aftertreatment to meet emissions standards on a lean-burn engine versus how much additional savings you’re going to generate from the higher electrical efficiency a lean-burn system is going to give you. Then you have to determine if that’s going to pay for itself in a reasonable timeframe. If not, the customer might be better off with a rich-burn engine and saving some money up-front on the emissions equipment.

“A year ago you could install a lean-burn engine in Massachusetts without the tougher area-based SCR [selective catalytic reduction]. And, in California, although they’ve extended the incentive program to the end of 2007, they’ve lowered the emission requirements in order to qualify.”

As Curtis points out, the only aftertreatment technology currently on the market to bring lean-burn engines into compliance where NOx standards are tight is SCR, which some end users are uncomfortable about utilizing for cost and safety reasons. But because the major manufacturers are solidly behind lean-burn technology, they are quick to play down states where higher emission standards can make compliance costly, and the industry itself is looking for new aftertreatment technologies to come on-line that will eliminate the perceived risk of storing and using the ammonia that’s added to a lean-burn engine exhaust stream. “Within the next two or three years, you’re going to see exhaust gas-circulation technologies emerging for lean-burn [engines] that will bring them down into compliance,” says John Kelly, director of distributed energy for the Gas Technology Institute (GTI) in Chicago, IL. But Ritchie Priddy of Attainment Technologies LLC in New Iberia, LA, says that time is already here (see sidebar).

At Caterpillar, Devine agrees that meeting local emissions standards is one of the factors that needs to be considered in what he calls “the economic equation” to determine whether generating your own electricity is competitive against purchasing power from a utility. “When a user is trying to determine the cost of operation for a gas engine, they usually think of the installed first cost of the system, the fuel and maintenance costs, but they also need to figure the cost of meeting the local emissions regulations, which can be met either inside the engine or outside the engine. With rich-burn engines, there is just enough air to mix with the right amount of required fuel to make the power required. Given that nitrous oxide is created in the exhaust stream in the presence of heat, the higher the temperature and the longer the exposure to that heat, the more NOx will be created. To minimize exhaust emissions, a three-way catalyst is then used to convert the exhaust gas into essentially water and nitrogen. This type of system is similar to automotive systems used today – you end up with very high exhaust-gas temperatures, and because of the way this type of engine consumes fuel, your efficiency is typically in the 33% to 35% range. A lean-burn engine deals with most emissions in the engine. You still have the same amount of fuel introduced into the cylinder to make the required power, but you’re putting excess air into the cylinder with the fuel. You’re distributing the same amount of heat over a larger volume, so your exhaust-gas temperatures are lower, greatly reducing the formation of NOx. In areas where very low exhaust emissions are required, a simple oxidation catalyst or SCR may be used to meet the local standards. An added benefit of lean-burn engines is that the lower exhaust-gas temperatures translate into higher power density, longer maintenance intervals, and lower owning and operating costs.”

After installation, a 1.75-MW cogeneration system at the Chicago Museum of Science and Industry will provide up to 80% of the museum’s heat, hot water, and electricity.

The Cummins lean-burn generator set produces up to 1.75 MW/hr. of electricity and 4,000 lb./hr. of steam.

Herman Van Niekerk, vice president of engineering at Cummins, agrees that a fundamental difference between rich-burn and lean-burn engines is that the lean-burn is more fuel-efficient, but he adds a qualifier. “As the engine gets bigger, the gap in performance and efficiency gets wider. The newer lean-burns are 39% efficient or better, while the rich-burns are about 32%. With that sort of efficiency gap, you can afford to do all sorts of aftertreatments to meet emissions requirements. But if you get down to 300 kilowatts or less, then the advantage of having lean-burn over rich-burn is not that great. You may [gain] two percentage points of efficiency with lean-burn, but you have the cost of the aftertreatment. I’ve done several feasibility studies on lean-burn projects in which a small unit just doesn’t cut it.

“Otherwise it’s a purely economical situation. We run a feasibility study with the data we get from the utility company – every 15 minutes of use – and from the customer about his site, including his thermal load profile and if it’s a cogeneration project. Then we’ll model an engine on the resulting load curve and simulate real-life conditions for an entire year so we will know exactly what will happen if we try to generate power on the customer’s site. This makes it easy for us to then compare rich-burn and lean-burn engines of different sizes and from different manufacturers.

“This process also gives me a financial model, which allows me to give the customer a full financial-impact study on what it will take to do the job. Some customers want a simple payback in two to three years. Others want to borrow the money. Our program will take the cash flow from construction to ten years and calculate the return on investment. Customers must be clear on these questions before any of the modeling work can be done.”

A case in point is a large automobile manufacturer headquartered in Torrance, CA, that elected a simple payback, Van Neikerk says. The company installed a combined heat and power system that uses a Cummins 1.2-MW natural gas-fired generator with a 250-ton Trane absorption chiller. Modeling convinced decision-makers that a CHP unit was environmentally and economically responsible, says Garth Sellers, manager of national facilities services. “We knew that we wanted to generate power, especially with the cost of energy in California. We also knew we wanted to use the byproduct of heat. Eventually we determined that we could use the heat in an absorption chiller to produce air conditioning, which we needed. We generate enough electricity to fully supply our central plant in Torrance during the summer months. During the winter months and in the evenings and on weekends, we supply several other buildings on campus. Our goal is to run the generator at 100% load, 98% of the time.”

At Northern Power, Pace points out that there are advantages to cogeneration besides what’s obvious. “Being an official cogenerator based on the Public Utility Code [means] that you can apply for incentives, and most utilities have a special gas tariff rate for cogeneration, which in some cases is significantly less than the tariff for normal boiler heating gas. But one thing you have to be careful of is the quality of waste heat you need. Some processes use 150 psi of steam, and recip engines are not good matches for waste heat at 150-pound steam because they don’t have the required amount of waste heat at a high enough temperature. Some manufacturers are more restrictive than others as to how hot they allow certain waste heat streams to be. Some will limit water-jacket heat to 185¡, others will let it go up to 210¡, and some [will let it go] as high as 240¡. So understanding the basic energy balance of the engine and the quality of the heat is important in understanding how you match that specific engine to the process.”

“From our perspective at GTI,” says Kelly, “although heat recovery helps, the really big impact on decision-making is the electricity cost in the region. That’s the number-one driver. With utilities having peak and off-peak rates, if you manage the situation correctly, you can be very economical. At GTI, for example, we run 9 a.m. to 6 p.m. every day, and the payback on our system is maybe four and a half years. We believe this is the optimum solution because it also takes care of the electrical utility. When we’re not running at night, they get to sell their base, but we’re shaving their peak.”

“Whether you’re only going to run at peak periods depends on what your nighttime rates are and what your fuel costs are,” says Van Niekerk. “If you can generate cheaper than what you would otherwise pay for electricity – if you compare both thermal and electric – you always run the genset 24/7, and it pays every time. Because even if you only save a penny per kilowatt-hour, on a megawatt unit, that’s almost $100,000 a year. Because deciding when to run or not is a really tight calculation, at Cummins we also provide a real-time monitoring and analysis system that will actually look at fuel costs and at electrical rates and then advise the customer during off periods to stop the generator until fuel prices come down.”

Except for waste heat, all of these factors were figured into decision-making when the research and development operation of a major global manufacturing company based outside of Chicago decided on self-generation. According to its facilities manager, the company was experiencing major problems with quality and reliability in the power it received from its local utility. During summer hot spells, the load could be down by as much as 15%. The company already had installed its own internal distribution network for power it bought off the grid and its own double-redundant diesel-powered system for backup at its corporate data center. Once the decision was made to generate power on-site, the company brought in Nicor Solutions, which helped develop the onsite power plant, eventually built the facility, and then leased it to the client, who runs it on a typical peak-shaving profile, 9 a.m. to 6 p.m. The company chose two Waukesha VHP 5904-LTD 1- to 25-kW gensets but left enough room in the building that houses them to add a third unit. “We chose Waukesha,” says the facilities manager, “primarily because of their availability in the market, because of their operating history, and [because of] the fact that they’re a relatively simple and straightforward engine. In my mind, other new technology being offered hadn’t been proven. We also liked the fact that the company is relatively close in case anything happens.” Keeping track of fuel costs is critical to efficient operation. “I’m always looking two years ahead, and when I see that the price of gas in 2006 is reasonable, I buy a contract and lock in the price. A lot of people do this, but they don’t constantly monitor the market. We have settled into a procedure, which takes me a minute each morning to look at where our electricity prices are and then at what our natural-gas prices are, and then we make a determination: Does it make sense for me to buy energy, leave my plant idle, and sell my natural gas, or does it make sense to generate electricity on-site?”

Devine agrees that equipment and operating costs have to be balanced against what he calls “power reliability and power quality,” and any bottom-line economic assessment must consider added costs, such as standby charges, exit fees, and additional incremental costs, for interconnection. He points to industrial operations, such as Kuntz Electroplating Inc. in Kitchener, ON, where seconds-long interruptions in utility-supplied power stopped production for as long as an hour. The company also was experiencing voltage disruptions during periods when high-demand equipment came on-line, and the resulting damage in solid state processing control could cause repairs that could shut down production lines for as long as 45 minutes. To solve these problems, Kuntz installed five Cat G3516 generator sets for a 4.075-MW capacity. When the system is operating at the rated load, it carries roughly 65% of the plant’s total electrical load; control switchgear sheds noncritical loads in case of utility power interruptions. The company also recovers heat from engine exhaust and jacket water/oil cooler circuits to help satisfy a process heat load of 18 million Btu /hr. for parts cleaning and electroplating tanks.

Caterpillar also is working with utilities, such as Herber Light and Power (HL&P), a municipal electric utility in Herber City, UT, to install its own DG systems rather than rely on customers to pick up peak-time power demands. Devine explains, “When power shortages hit California in the summer of 2000, HL&P was prepared. By increasing run time on its distributed-generation resources, which consisted of natural-gas- and diesel-engine-driven generator sets, HL&P avoided purchasing wholesale power at prices that rose from the typical $20 per megawatt-hour to as high as $200 per megawatt-hour at peak-demand hours. After the crisis passed, HL&P took further steps to protect reliability and stabilize prices, investing in three new advanced gas-fueled generator sets rated at a combined 5.52 megawatts. With those new units on-line as of July 2002, the distributed-generation facility has nine gas and two diesel units delivering 11.97 megawatts of capacity. It provides economical load following year-round and shields HL&P customers against future swings in wholesale power prices. In case of a major wholesale supply interruption, the facility could carry a substantial share of HL&P’s load, keeping the majority of its customers in service.”

Houston, TX-based Atmos Power Systems (APS) designs and installs plants for peak shaving, shoulder, and interruptible load applications. “Historically,” says APS Vice President Larry Moore, “utility-provided power during peak- and shoulder-load operations has always been the most expensive due to demand charges. APS builds the power-generating facility and offers its customers long-term leases that allow them to build an equity position in the generation plant during the term of the contract.” One of APS’s clients is a food-processing operation in the Southeast where a large portion of the facility’s electricity portfolio was on an interruptible basis, which meant that the utility had the right, given notice, to reduce power demand by a certain amount. In the face of increasing demands on the utility that supplied its power, the company wanted to firm up its power delivery and reduce high demand charges.

“The decision we had to make,” says the company’s energy manager, “was [this]: Do we continue to take interruptible power, or do we take the interruptible part of our portfolio and make it firm? But under most utilities, the real benefit of interruptible power versus firm power is that you don’t pay the high demand charges. So in effect the demand portion is much cheaper. So we weighed the increased cost of firming up our interruptible service against the cost of turning those generators. In effect we were firming up our power because we had generation on-site.”

APS installed a 20-MW plant using 12 Cummins QSV lean-burn generator sets, which environmentally were permitted to operate 1,200 hr./yr., and then leased the plant to the customer. Power is generated at 13,800 V and is connected directly to the customer’s substation. The company’s energy manager acknowledges that leasing the facility rather than bearing the capital cost of building the plant was attractive but that the company hasn’t completely ruled out buying the lease.

With these kinds of numbers, Moore says APS is enthusiastic about the DG market, which he also predicts will include a combination of utilities and end users. “Utilities benefit from DG power plants installed in areas of system weakness,” says Moore, “by being able to defer capital budget items to upgrade their transmission infrastructure.”

Besides emissions, Moore thinks that noise management and equipment maintenance are two factors that have to be considered from the get-go. “In these kinds of lightly loaded applications, the life expectancy of a system like we put in with the 12 Cummins gensets is 40 years, after which the engines will be overhauled and allowed to operate for another 40 years. The key is proper maintenance, which Cummins supplies. The only thing we require of our customers is that someone walk through and do a periodic check once a day to make sure everything is running smoothly, that there’s no oil on the floor, no antifreeze. This has the added benefit that, if five years down the road the customer decides they want to purchase the power plant, they have people who are qualified and know how it works and are familiar with its operating history.”

GTI recommends that anyone considering distributed energy develop maintenance specifications and put them out to bid at the same time they bid the project. Van Niekerk describes Cummins’s “bumper-to-bumper” guarantee as “a fixed feed per kilowatt-hour. The customer knows exactly what it’s costing him to generate electricity. For a penny or a quarter of whatever that number is per kilowatt-hour, we provide full warranted maintenance and a monitoring system, which automatically calls out so everybody knows what’s going on and if there are any problems.”

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