A recent U.S. DOE press release stated that the technology revolution has bypassed the wood stove industry. The first round of U.S. EPA regulations in 1988 required all manufacturers to adopt innovations, or go belly up. Most agree that those regulations were a good thing for industry, which was facing public backlash, and potentially far more strict regulations from various states. Can the second round of EPA regulations, coming into effect in 2020, bring about the next big wave of innovation? Many insiders say no, that wood stoves have advanced as much as they can, and there is no reliable way to further drive down emission standards. To us, that is short-sighted.&nbsp; We need positive, forward-thinking leadership. The narrative around wood stoves needs changing, and industry leaders need to be part of that. It&rsquo;s not enough to say smoky stoves are the result of poor operation, and all we need to do is better educate operators. This is almost an admission that stoves will continue to be polluting, and aren&rsquo;t up to the task. It&rsquo;s not enough to say that the problem is just the old stoves, and we shouldn&rsquo;t worry about how clean new stoves should be. We all know that even new stoves can be problematic. A key issue is that wood stove sales volumes aren&rsquo;t enough for major R&amp;D programs. And there is not as much creative pressure on the stove industry as there is on industries making common consumer appliances, such as mobile phones, watches and cars. Those industries are selling millions or tens of millions of units a year, whereas usually, fewer than 200,000 wood stoves are sold per year.&nbsp; In addition, the volume of wood stoves sales is declining, leaving manufacturers with less resources and incentives to innovate. And, many consumers do not have higher expectations for wood stoves&mdash;but they should. If the 2020 deadline comes and goes without much fanfare, and results only in fewer stove models, smaller fireboxes and slightly higher price tags, we think the industry will have missed a big opportunity. It needs to embrace innovation and change, and think more broadly about how a stove operates under 2 grams an hour not just in the lab, but in homes.&nbsp; For example, an Idaho company is coming out with a stove designed to burn pressed logs, and could occupy a small, exciting niche in the marketplace that could grow. But if they or another company combines the pressed log concept with automated controls, the result would be a stove manually loaded with oversized pellets that could have PM and CO emissions and efficiencies closer to pellet stoves than wood stoves. This is just one concept, and there are lots more to explore. The point is that this industry needs leaders who can play even a little bit of the role that Tesla&rsquo;s CEO Elon Musk plays: Give the public a vision for how your product is perfectly suited for the future, whether it&rsquo;s an automobile or a wood stove. We think the next logical step is to finish the job that the bimetallic coil started.&nbsp; We need to automate air controls through cheap sensors and electronics, taking that job away from operators. This is the way of the future, which virtually all modern combustion appliances have embraced. The longer it takes to catch on in the stove industry, the harder it will be to recapture market share and change the narrative around wood stoves. Automation of wood stoves simply involves bringing technologies that have long been used in advanced wood boilers in the basement up to the living room.&nbsp; It opens the possibility of stoves performing in the real world much closer to how they performed in the lab. The challenge is doing this without raising the price too much, and being able to market these stoves to a wide population of wood-heated households. Without such innovation, wood stoves may be on a long-term trajectory of losing market share to gas stoves, heat pumps, pellet stoves and other options. In many communities that experience frequent inversions, the number of wood stoves needs to shrink, and slowly, jurisdictions appear to be more willing to adopt regulations that are less friendly toward wood stoves.&nbsp; The Wood Stove Design Challenge we launched in 2013 will be back on the National Mall in Washington, D.C., in mid-November. The focus is on automated stoves, stoves that make electricity, pairing stoves with solar panels and testing with cordwood. It&rsquo;s a place to share ideas, introduce and test prototypes and showcase strategies that could herald a cleaner future for wood stoves. Up to 20 teams will compete to prove that their stove design should be part of a cleaner, more modern wood heating future.&nbsp; It&rsquo;s free and open to the public, and we hope to see you there. Author: John Ackerly President, Alliance for Green Heat <a href="mailto:jackerly@forgreenheat.org" target="_blank">jackerly@forgreenheat.org</a> 301-204-9562

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Without innovation, wood stoves may be on a long-term trajectory of losing market share to gas stoves, heat pumps, pellet stoves and other options. 

Will EPA Regulations Drive More Wood Stove Innovation?

Wikipedia defines three-dimensional chess as &ldquo;a complex, dynamic system with many competing entities and interests.&rdquo; Sounds a lot like following the biomass industry, right? As we know, our industry transcends wholesale power markets by calling upon policymakers&mdash;and the public&mdash;to recognize the many benefits of generating power from organic materials. So as 2017 draws to a close, it begs the question: Are we winning? If not, what will it take to ensure the long-term stability and growth of biomass power? Our industry looks at the demise of baseload power (nuclear and coal) and rightly wonders, what does the future hold for everyone but solar, wind and natural gas? Recent statistics as reported by the Wall Street Journal paint a challenging, sober picture. Power in ERCOT (Electric Reliability Council of Texas) is currently trading at $25 per megawatt-hour&mdash;a decade ago, that price was $55. In PJM, part of the eastern connection grid, recent trades settled at $29.23 last year, the lowest trades since 1993. At the same time, demand for electricity is, at best, flat, as more consumers are using smart systems that drive down demand. The beneficiaries of falling prices are intermittent sources like wind and solar that continue to drive down costs, and also the sourcing of ever-cheapening shale gas. To give you a sense of these trends, it&rsquo;s notable that in 2016, all new generation in the Southwest Power Pool came from wind, solar and natural gas. So where does this leave biomass, along with other baseload renewable sources? Energy Secretary Rick Perry&rsquo;s recent suggestion, now before the Federal Energy Regulatory Commission, is to award baseload power like biomass&mdash;with reliable, on-site supplies of fuel&mdash;an additional pricing benefit. Some say this is too little too late, given market forces. A trend that folks in Washington, including us, didn&rsquo;t see coming is &ldquo;transport as a service.&rdquo; Tony Seba, the well-respected thought leader on technology, recently predicted that by 2030, 95 percent of vehicles on the road will be on-demand, autonomous electric vehicles. Many in the automobile industry believe that newborns in America today are never likely to take driver&rsquo;s education. Imagine Uber and Lyft on steroids. Where will all this power come from, and what role can we play? Well, for starters, our power qualifies for the federal Renewable Fuel Standard. The RFS promotes biofuels, including renewable electricity from biomass, by awarding tradeable credits. Already, the program has transformed the renewable gas industry, allowing landfills and wastewater treatment plants to get above-market pricing for gas supplied to LNG and CNG fleets. Biomass may be your grandfather&rsquo;s energy, but with your help and support, we can also be your granddaughter&rsquo;s vehicle fuel. We are learning three-dimensional chess, and with any luck, we will win at this game. Onward! Author: Bob Cleaves President, Biomass Power Association <a href="mailto:bob@usabiomass.org" target="_blank">bob@usabiomass.org</a> <a href="http://www.usabiomass.org" target="_blank">www.usabiomass.org</a>

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Biomass may be your grandfather's energy, but with your help and support, we can also be your granddaughter's vehicle fuel. 

Biomass's Opportunity in Future Power Trend

One of the most common deterrents to investment in equipment and technology that will ultimately save bioenergy plants money is exactly that&mdash;money. Steep up-front capital investments can, and often do, deter adaptation of the most efficient, reliable and environmentally sound options. If a developer can find a way to make them pencil out, however, the benefits often have positive multiplier effects, and result in much quicker paybacks. That&rsquo;s exactly what is about to ensue at Dalhousie University Agricultural Campus, which is in the midst of a full replacement of its thermal plant. The components of this month&rsquo;s theme&mdash;operations, maintenance and efficiency&mdash;all go hand-in-hand. For Dalhousie, the story of which is featured in this quarter&rsquo;s Biomass Construction Update, operating and maintaining the decades-old heating system was cumbersome, increasingly inefficient and, at the brink of failure, it needed a major overhaul. On a mission to ensure the system was as efficient as possible, Dalhousie first downsized the system that was initially planned, and discovered that changing from steam to hot water&mdash;again straying from the initial plan&mdash;would make the system more efficient in the long run.&nbsp; One example of the multiplier effects I mentioned above is the fact that Dalhousie is going out of its way to source willow as a portion of its feedstock. It is doing this, said Dalhousie&rsquo;s Rochelle Owen, simply because the university wants to try to help the grower bring down the cost, and potentially expand the market. Therefore, the university is paying more for the willow than the sawmill waste it&rsquo;s using, even it could easily use sawmill waste alone. Finally, adding an electrical component&mdash;an Organic Rankine Cycle turbine&mdash;will allow the university to enjoy an extra revenue stream from the waste heat that is captured and turned into power, a component that without, Owen told me, the project as it is would not have been financially feasible for the school. Due to their ability to maximize process efficiency, ORCs seem to be trending at a variety of bioenergy installations, whether a university like Dalhousie, a small-scale cogeneration project, or even a wood pellet plant. Ron Kotrba&rsquo;s page-16 feature explores the functionality of ORCs, as well as the challenges and opportunities they have to offer bioenergy developers who seek to squeeze every last drop of efficiency out of their operation. Other stories in this issue include a piece on the resounding benefits that switching out aging transformers had on a Kettle Falls, Washington, biomass power plant, and how a new method of boiler component laser cladding could prove worthy of the investment in not only MSW plants, but wood-using plants as well. Smart operations, strategic maintenance and maximum efficiency are the cornerstones of every successful bioenergy installation, but, on top of a lot of determination and heart, it&rsquo;s continued innovation that is truly the pulse of this industry.

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One of the most common deterrents to investment in equipment and technology that will ultimately save bioenergy plants money is exactly that—money.

Every Last Drop

A fundamental principle of distillation, whether for beverage alcohol production or petroleum refining, is that most liquids have different boiling points. Alcohol boils at 173 degrees Fahrenheit, and water at 212 degrees, so to make alcohol, distillers employ temperatures between those two points in order to evaporate the alcohol, and then condense it back into liquid form&mdash;sans water. Now, imagine standing outside on a cool autumn day with a cold, closed jar of unknown liquid. It&rsquo;s 58 degrees outside, and the jar is much colder than that. When you open the jar and expose the liquid to the 58-degree air, it starts to boil.&nbsp; This is the basis of the organic Rankine cycle (ORC)&mdash;a thermodynamic cycle using an organic, high-molecular mass fluid instead of water to produce power from low-grade heat. &ldquo;ORC is literally a refrigeration cycle in reverse,&rdquo; says John Fox, managing director of ElectraTherm. Fox is former CEO of ElectraTherm, a small Reno, Nevada-based startup that experienced significant growth from 2010-&rsquo;16. The company was acquired one year ago by Bitzer SE, a privately held German compressor manufacturer, and Fox was asked to stay on as managing director after the acquisition. Fox says ElectraTherm now has 65 systems worldwide in 11 countries with 750,000 fleet hours. In explaining how ORCs work, Fox says, &ldquo;In refrigeration systems, you buy kilowatts and transfer heat. It&rsquo;s just the opposite for ORCs. Here you transfer heat and make kilowatts&mdash;you do the cycle in reverse.&rdquo; In an ORC system, the heat contained in the gases from combustion or gasification of fuel is transferred via a closed thermal oil loop. &ldquo;The heart of the system is the ORC turbine, which feeds with mechanical power a generator for the production of electric power,&rdquo; says Filippo Vescovo, deputy manager for Turboden Turkey. Turboden, an Italian firm owned by Mitsubishi Heavy Industries, has installed 355 turbogenerators in 38 countries, according to Vescovo. In the Rankine cycle, water is heated in a boiler to create steam or high-pressure vapor that, as Fox explains, is released across an expansion device&mdash;turbines or screw expanders. &ldquo;It spins something and out comes kilowatts,&rdquo; he says. High-grade heat&mdash;400 to 600 degrees&mdash;is needed to drive the steam cycle. But ORC systems make use of low-grade heat due to the low boiling point of the organic fluid. ElectraTherm uses a refrigerant in its ORC systems that boils at 58 degrees. &ldquo;If it wants to boil at 58 degrees, then it really wants to boil at 250 degrees,&rdquo; he says. There are many applications for 500-degree heat, but far fewer for 200-degree waste heat.
At the heart of ElectraTherm&rsquo;s ORC systems are twin screw expanders. &ldquo;It&rsquo;s a male and a female screw, like a piston, rotating against each other,&rdquo; Fox says. High pressure goes through the screws and, as it moves from high to low pressure, the screws spin. &ldquo;That&rsquo;s the expansion device,&rdquo; he says. &ldquo;We like the twin screw expanders because we can run dual phase flow&mdash;liquid and vapor at the same time. You could never do this through a turbine as it would damage the blades&mdash;you never want impingement of liquid on the turbine blades.&rdquo; Antonio Mendes Nazare, vice president of sales and marketing for Paris-based ORC designer and manufacturer Aqylon, says to generate power from heat sources, either technology&mdash;traditional steam turbines or ORCs&mdash;could be used. &ldquo;Depending on the features of the project, however, one of these technologies would certainly fit better than the other,&rdquo; Nazare says. &ldquo;For high powers above 10 or 15 megawatts of electricity, the steam turbines make a lot of sense. But for lower capacities, the ORCs are bringing better economics and technical figures.&rdquo; Advantages Over Steam Beyond their ability to operate with much lower heat sources, Nazare notes several advantages ORCs have compared to steam turbines. One is that ORCs have a high efficiency at partial loads. &ldquo;Even if the heat input decreases by more than 50 percent, or increases by 20 percent, the ORC follows the heat and remains in a close range of efficiency while steam turbine efficiency drops dramatically, or even stops, with slight load variations,&rdquo; he says. A big problem for steam turbines is their loss of efficiency over time as a result of water&rsquo;s long-term effect on metal equipment. &ldquo;For ORCs, there is no erosion of the metallic parts and blades caused by water,&rdquo; Nazare says. &ldquo;Therefore, the first-day efficiency of ORCs remains for their lifetime, while the efficiency of steam turbines gets significantly degraded with time.&rdquo; Furthermore, the water used in a steam turbine must be demineralized using a costly water treatment system. &ldquo;Moreover,&rdquo; Nazare says, &ldquo;steam turbines imply large quantities of water consumption. Depending on the site or country, this can become a heavy economic issue. ORC modules don&rsquo;t have any fluid consumption, as all the required fluids circulate inside a closed loop.&rdquo; Another advantage of ORC systems is that fewer, or in many cases no, operators are required to run them thanks to their automatic, continuous operation&mdash;not the case for steam turbines. &ldquo;Because of its high turbine rotation rate and high pressure, the steam turbine requires permanent presence of operators to ensure the safety of the site,&rdquo; Nazare adds. Vescovo says ORC turbines work at lower pressure levels and turbine speeds, implying lower mechanical stress in moving parts. This, he says, equates to lower maintenance costs and requires less effort and skill for operation. There is a big difference in the restart time between the two types of systems as well. Nazare says it can take days to restart a steam turbine whereas an ORC system restarts in minutes. &ldquo;At a site where the grid stops regularly or frequently, this makes a real impact on the revenues,&rdquo; he says. Last, over five to 10 years, ORC efficiencies and related costs are more attractive for small-capacity power generation systems. &ldquo;We can say that the capex for an ORC solution is slightly higher than for a steam turbine solution,&rdquo; Nazare says. &ldquo;However, it is largely compensated by the difference in the opex, as the opex of an ORC solution is two to three times lower than for a steam turbine solution. Over a project lifetime, the internal rate of return is in favor of the ORC solution.&rdquo; Ideal Applications &ldquo;We always like solving problems,&rdquo; Fox says, adding that the value proposition of his ORC units goes up when an ElectraTherm system can fix a situation. &ldquo;For instance, like with what we did in Maryland with chicken manure.&rdquo; Last June, ElectraTherm announced the sale and shipment of one of its ORC systems to a farm in Maryland that will combust chicken litter and use the heat to produce electricity for on-site consumption. Due to environmental regulations concerning run-off into the Chesapeake Bay, spreading the manure was no longer a viable option. Tipping fees to get rid of the waste were eating away at the bottom line. &ldquo;We put all that into a return on investment for the client,&rdquo; Fox says. &ldquo;We&rsquo;re solving the tipping fees and transportation problems by taking in a waste on the frontend, and getting Btu out of the backend.&rdquo;&nbsp; Nazare says there are thousands of ORCs installed all over the world and hundreds of them in biomass installations. &ldquo;There are a few manufacturers of ORCs, and most of them are addressing different specific sizes, temperatures, applications or markets,&rdquo; he says. &ldquo;The main difference Aqylon has&mdash;apart from the fact that we are addressing all markets, temperatures and applications&mdash;is probably its unique technology.&rdquo; He says not only does Aqylon&rsquo;s patents address the price/efficiency ratio, but also containerizing all its high-temperature ORCs. &ldquo;This brings not only easier transportation and faster on-site installation, but mainly significant savings on the civil work,&rdquo; Nazare says, &ldquo;as we just need a concrete base or even some concrete plots.&rdquo; ORC systems are a great fit for small-scale, localized, distributed power generation, particularly for companies whose processes create a waste stream&mdash;either waste fuel like sawdust or chicken manure, or waste heat from existing combustion practices&mdash;in order to reduce &ldquo;behind-the-fence&rdquo; expenditures on retail power or, in some circumstances, sell power back to the grid. &ldquo;We&rsquo;re the low-temperature, smaller guys,&rdquo; Fox says. &ldquo;We manufacture 35, 65, 110-kw systems that provide the benefits of combined heat and power (CHP). Besides making electricity, with an ORC system you can heat water for barns, chicken coops, office buildings, and dry wood chips or other biomass materials, thereby raising your efficiency. The more bites to the apple you get, the more valuable your waste heat is.&rdquo; Fox says sometimes it doesn&rsquo;t make economic sense for companies to buy an ORC system for the purpose of selling power to the grid as a money-making venture, unless there are biomass power incentives at play. &ldquo;For us, we sell kilowatts,&rdquo; he says. &ldquo;So the value proposition is, the higher the kilowatt price, the better the return&mdash;and in places like Japan, Alaska or Europe, it works. But if you go into Oregon, it might only be 5 cents a kilowatt. The economics are challenged in the U.S. Our major biomass pull has been from the U.K. and its renewable heat incentives.&rdquo; In 2015, ElectraTherm had zero units sold in the U.K. In 2016, the company sent a dozen systems over. &ldquo;In one year, 0 to 80 percent of my business was in the U.K., and it&rsquo;s all incentive-driven,&rdquo; Fox says. &ldquo;But that&rsquo;s where the market is. Incentives work.&rdquo; Author: Ron Kotrba Senior Editor, Biomass Magazine 218-745-8347 <a href="mailto:rkotrba@bbiinternational.com" target="_blank">rkotrba@bbiinternational.com</a>

Power plants using organic Rankine cycle (ORC) systems, such as this 8-megawatt biomass plant in Maine using Turboden ORC technology, feature many advantages over steam turbine power generation. 

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Paris-based Aqylonâ€™s patents address the price/efficiency ratio and containerizing its high-temperature ORCs. 

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ORC systems work much like steam turbine systems except they use an organic, high-molecular mass fluid instead of water, which creates numerous benefits. 

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Turboden, an Italian firm owned by Mitsubishi Heavy Industries, has installed 355 turbogenerators in 38 countries.  

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ElectraTherm ORC units feature twin screw expanders and an organic fluid that boils at 58 degrees Fahrenheit. 

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ORC systems are ideal for distributed power generation where waste biomass can be combusted and the gases used to produce heat and power. 

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Organic Rankine cycle systems are a good fit for companies with 
biomass waste streams to produce combined heat and power, 
and, in some cases, sell power to the grid. 

The ABCs of ORCs

Somewhere within a 10-mile radius of the Calgren Renewable Fuels facility near Pixley, California, a crew is busy excavating dirt&mdash;perhaps along the edge of a field, or across the road of a dairy farm&mdash;laying pipeline at a minimum depth of four feet, carefully and methodically forging its way to the ethanol plant. Eventually, around 20 miles of pipeline will connect 10 anaerobic digesters installed at 11 local dairy farms, serving as the gateway for biogas that will be upgraded and used for process energy and more. As of early December, several miles of pipeline were already placed. General contractor Maas Energy Works chose local R&amp;B Co. as its supplier. The company prides itself on sourcing equipment and services from the nearby community, and, on every job for which it is hired, Maas is putting people to work. Now a staff of 15, all are working on the Calgren project, and at any given time, upward of 40 are working on different aspects&mdash;the pipeline, the dairy digesters, the gas clean-up equipment at the ethanol plant. &ldquo;Work is only being done at two of the locations now, so once we get into six [digesters] at one time, there will be lot more contractors,&rdquo; says Doug Bryant, Maas Energy development manager. Maas has made a name for itself in the Pacific Northwest&mdash;they are the dairy digester guys, and they have the portfolio to prove it. With 13 digesters online and 17 more in development, Maas has built the majority of the West Coast digesters constructed over the past decade. A major key to the company&rsquo;s success has been not only its growing track record, but that they handle everything from grid interconnection to permits, financial management and construction, so busy dairy farmers take on little to no burden. For the Calgren project, it was a matter of explaining to local farmers what the possibilities were. &ldquo;Working with the ethanol plant, we went out and proposed to all of the local dairymen that Calgren would build digesters for them, and use that gas off the digesters to fuel the ethanol facility, which has a high appetite for natural gas,&rdquo; Bryant says. &ldquo;To be able to get some renewable natural gas (RNG) was very appealing to them.&rdquo; The Circle A and Robert Vander Eyk dairy digesters are underway, and anticipated to come online in the second quarter of the year, with two more to follow by the year&rsquo;s end. Notably, the project is what Maas Energy Works believes is the first of its kind in the U.S. &ldquo;There&rsquo;s an Indiana dairy that injects some dairy biogas into the pipeline, but other than that, nobody has been able to do this across a large area,&rdquo; Bryant says. For Calgren Dairy Fuels, the cluster project is a demonstration just how far the ethanol producer has evolved in its renewable biofuel efforts in the past several years. Pixley Biogas, a two-stage, mixed plug-flow digester, was built at the site of Calgren and came online in early 2015. Waste from nearby dairy operation Four J Farms is piped to the digester, and the resulting biogas is used to create power on-site. &ldquo;That was our first introduction to digesters,&rdquo; says Lyle Schlyer, president of Calgren Dairy Fuels. &ldquo;This new project is quite a bit bigger&mdash;I would call it a bit of a phase two, though we didn&rsquo;t have it mind when we did the other one. But we did have a couple of other things that we wanted to do&mdash;we&rsquo;re also doing a biodiesel project.&rdquo; Calgren is building the pipeline big enough to handle about two and a half times what it originally contracted for, according to Schlyer, and not only will the gas be used on-site, but sold to local utility SoCalGas. &ldquo;We think it will be a little bit of, &lsquo;once you build it, they will come,&rsquo; but we think there are advantages for more dairies in the area,&rdquo; he says. &ldquo;If we don&rsquo;t help them do this, eventually, they will probably have to do it themselves, on their own dime. California is pushing pretty hard to see this done, so we see it as an ultimate benefit for the dairies as well.&rdquo; While Calgren could use all of the RNG at its ethanol plant, Schlyer says, by plugging some into the pipeline, it is taking advantage of some incentives offered in California, that encourage the capture of dairy methane. &ldquo;It's backing up our gas-fired turbine generators, and part of the plan is to get that interconnection of our biomethane into the local pipeline, so we'll be able to get some to CNG fueling stations,&rdquo; Schlyer says. &ldquo;It's part of the same project.&rdquo; Work is also well underway at the ethanol plant, and is being headed up by primary design engineers SCS, Schlyer says. &ldquo;The pipeline is in, and we&rsquo;ve broken ground on the process equipment to clean up the biogas to pipeline quality, which is tough in California&mdash;very high standards.&rdquo; The cleanup equipment&mdash;designed by SCS, with sulfur removal by DMT Clear Gas Solutions, and CO2 removal via an Air Liquide membrane system&mdash;should be operational in February, Schlyer adds. The plant should be getting gas from the first digester in March. &ldquo;The rest will follow,&rdquo; he says. &ldquo;We&rsquo;re currently projecting our interconnection to the gas pipeline around September. These projects are all about team work, and we have a great team.&rdquo; As for the most challenging aspect of the project, Bryant says it&rsquo;s simply the newness of the concept. &ldquo;We&rsquo;re venturing down paths that nobody has been, coming up with new rules, figuring out things with the county, the irrigation district, the dairymen&mdash;for many of them it&rsquo;s a new concept&mdash;building all of the monitoring equipment, and everything else,&rdquo; he adds. &ldquo;Those are the challenging parts, but also the most exciting parts. We have broken ground on something that nobody&rsquo;s been able to do yet, and we&rsquo;re excited about it. We have really fun huddles figuring out how to solve certain problems, and we&rsquo;re coming up with neat solutions to certain situations.&rdquo;
Dalhousie University Thermal Plant Upgrade
Whether to replace the nearly 30-year-old heating plant at Dalhousie University&rsquo;s Agricultural Campus in Halifax, Nova Scotia, wasn&rsquo;t the question on the table when the project ball started rolling years ago&mdash;it was how the university could balance the facility&rsquo;s renewal costs while supporting the community, connecting research and operations, and helping achieve Dalhousie&rsquo;s carbon reduction goals. What came together was a master plan that includes replacing the aging steam lines with hot water lines, switching out the wood boiler, installing necessary air quality controls, and, an add-on that will accelerate the payback for the university&mdash;a turbine to create electricity.&nbsp; Right now, the biomass cogeneration plant construction site is bustling, says Rochelle Owen, executive director at Dalhousie University Office of Sustainability. &ldquo;We have already converted our steam system to hot water, that part is done. The biomass boiler and turbine are also there, and work is being done to get those set up and connected. At the same time, work is being done on the fuel bin, so there is a lot going on on-site right now.&rdquo;
Planning for Dalhousie Agricultural Campus replacement system began when the provincial government was running the Nova Scotia Community Feed-in Tariff Program, which was designed to encourage community-based, local renewable energy projects by guaranteeing a rate per kilowatt-hour for the energy the project feeds into the province&rsquo;s distribution electrical grid. The project received COMFIT approval in 2014, and the university plans to sell its excess power, expecting to generate around $1.36 million annually. &ldquo;In our case, we were kind of lucky, because the community feed-in tariff rate has provided revenue stability for us to do this project,&rdquo; Owen says. &ldquo;If we didn&rsquo;t have it, we probably would be doing a biomass boiler. It also secured our power purchase agreement that if wasn&rsquo;t there, this project would be hard to do.&rdquo; Owen says the Organic Rankine Cycle turbine addition will add even more value to the system. &ldquo;Our thought process there was that we wanted to make this whole system as efficient as possible&mdash;it is electrically led&mdash;so we actually reduced the size of the initial project. Our feasibility study was based on a high-pressure steam turbine that would create new revenue, but it would use more energy. So, we decided to take another look and make it energy efficient in the long-term. That&rsquo;s when we went from steam to hot water, and actually changed out the whole distribution system.&rdquo; Now, the university is looking at innovative ways to use the waste heat it will have during shoulder seasons and summer, and plans to move forward with a study to explore options. For fuel, the facility will annually use around 20,000 metric tons of biomass, which will be provided by local sources, and mostly consist of sawmill waste. &ldquo;We have all of the contracts in place with our suppliers, and we did some innovation in that arena,&rdquo; Owen added.&nbsp; &ldquo;Our fuel will be primarily saw mill residue, but we also created a category that we&rsquo;re calling research fuels, so up to a maximum of 5,000 tons can be under that umbrella. It gives us the ability to pay a little more for that fuel, and help support innovation in that area. We have a contract with someone trying to grow willow for bioenergy, and we also have an agreement with three co-ops to do selective harvesting for product. Our goal there is to support their cause, to see if we can help get the cost down, and build more of a market for that supply. So we are paying more for that&mdash;we could have just used all sawmill residue, but this was another way to contribute to this sector.&rdquo; Owen said the goal was to finish construction by June, but the project is a bit ahead of schedule. &ldquo;We&rsquo;re hopeful it may be as early as May,&rdquo; she said. &ldquo;We&rsquo;ve always had an aggressive target, and we're doing our best to move along.&rdquo; Author: Anna Simet Editor, Biomass Magazine <a href="mailto:asimet@bbiinternational.com" target="_blank">asimet@bbiinternational.com</a> 701-738-4961

The roughly 20 miles of pipeline that will send dairy digester gas to Calgrenâ€™s 57 MMgy ethanol plant will be placed underground at a minimum depth of four feet.

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In early November, an official groundbreaking ceremony was held for the Calgren Dairy Fuels project, which will send the gas of nearly a dozen California dairy farms to a nearby ethanol plant.

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Equipment has arrived at the site of the Dalhousie University Agricultural Campus biomass thermal plant ugprade, and multiple crews are busy working on different aspects. 

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The Dalhousie thermal system replacement was taking shape in in early November. Work will continue through winter, with estimated completion in late spring.

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All major system components are on-site, and work is ongoing to place and connect equipment.  

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This quarter's Biomass Construction Update profiles a novel pipeline dairy digester cluster in central California, and a biomass thermal plant upgrade in Halifax, Nova Scotia. 

A First of Their Kind

Bogers named B&amp;W V&oslash;lund managing director Effective Jan. 2, Babcock &amp; Wilcox Enterprises Inc. appointed Koen W. Bogers as managing director of its Denmark-based renewable energy subsidiary, Babcock &amp; Wilcox V&oslash;lund. Bogers most recently served as senior executive vice president of Siemens Building Technologies&rsquo; Middle East division, in Dubai. Before assuming his current role in 2015, he joined Siemens in 1996, serving in positions including project management in the power generation and oil and gas divisions, and&nbsp; managing director positions in the industry solutions and building technologies divisions of Siemens Netherlands. Bogers holds master&rsquo;s degrees in business economics from Erasmus University Rotterdam, and electrical engineering from the Technical University Delft. He will be based in B&amp;W V&oslash;lund&rsquo;s Glostrup, Denmark, office, near Copenhagen.&nbsp; RNG Coalition adds four staff members&nbsp;&nbsp;&nbsp; The Coalition for Renewable Natural Gas has added four senior government affairs and biofuels policy experts to run its Washington, D.C., operations. Manning Feraci joins the RNG Coalition as director of federal government affairs, bringing more than 20 years of experience navigating a myriad of tax, energy, trade and agriculture issues through the federal legislative and regulatory process. He has an extensive background in biofuels policy, and previously led the federal affairs operation for the Solar Energy Industries Association. Feraci served over a decade on Capitol Hill as a legislative director and chief of staff for a member of the U.S. House Ways and Means Committee. Anne Steckel joins the RNG Coalition as director of federal legislative affairs. She has over 20 years of Washington, D.C., experience, working on legislative, regulatory, advocacy, policy and political issues on and off Capitol Hill. Most recently, she was the vice president of federal affairs for the National Biodiesel Board. She previously held senior government relations positions with the American Farm Bureau Federation and Growth Energy, and was a chief of staff for a member of the U.S. House of Representatives. Larry Schafer joins the RNG Coalition as director of federal policy. He is one of the nation&rsquo;s preeminent experts on federal biofuels policy, and has extensive experience providing clients and trade associations with guidance on technical, legislative and regulatory matters relating to renewable fuels, energy, agriculture, tax and trade. He previously served as vice president of federal affairs for the Renewable Fuels Association, and vice president of legal, tax and accounting policy with the National Council of Farmer Cooperatives. Schafer also served as legislative counsel to a member of the U.S. House of Representatives. Sandra Franco joins the RNG Coalition as director of federal regulatory affairs. She has advised clients on administrative, regulatory and litigation matters under several federal environmental laws, including numerous U.S. EPA and federal agency rule-making proceedings. She has worked on Renewable Fuel Standard matters since the program&rsquo;s inception, including successfully defending full implementation of the RFS before the D.C. Circuit. She was director of regulatory affairs and general counsel for the National Biodiesel Board, and spent time as a partner at a major international law firm. Renou joins FPInnovations as CEO FPInnovations has appointed St&eacute;phane Renou as president and CEO. A native of Montr&eacute;al, Renou has a number of degrees from Universit&eacute; de Sherbrooke, as well as Polytechnique Montr&eacute;al, where he went on to complete a master's degree in electrical engineering and a doctorate in chemical engineering. In 2015, he earned an MBA in innovation management from the University of Colorado.&nbsp; In 2000, Renou moved to the U.S. to join General Electric's research center, where he headed a number of divisions at various locations. Within his various responsibilities, he led teams in both the GE Aviation and Oil &amp; Gas divisions. Most recently, he was the leader of industrial outcomes optimization at GE Global Research. Renou assumed his new role on Dec. 14, successor to Pierre Lapointe, who held the position since December 2008.

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Business Briefs

Last year was among the most active and interesting years we&rsquo;ve seen in the biofuels space. The industry has confronted multiple challenges over the past 12 months, culminating in meetings between senators supportive of the oil industry, and President Trump to discuss the future of the RFS program. In the end, we managed to preserve the status quo with the 2018 renewable volume obligations (RVOs) set at 19.29 billion gallons, essentially the same level as 2017. This summer, the D.C. Circuit Court of Appeals determined that EPA erred in its interpretation of &ldquo;adequate domestic supply&rdquo; and required EPA to grant the corn ethanol industry the full congressional statutory mandate of 15 billion gallons for 2016 and beyond. The dispute between big oil and corn has intensified over the year, resulting in this month&rsquo;s meeting between the president, several cabinet secretaries, and 11 Republican senators. In the meeting, the senators asked the White House to encourage senators representing corn ethanol states to come to the table to address the rising cost of conventional RINs. The cost of compliance for both small and merchant refineries continues to be the central friction point between big oil and big corn.&nbsp; On the RFS front, both the Senate and House of Representatives took steps to discuss legislative RFS reform. Though neither chamber produced a comprehensive bill this year, we expect significant progress in early 2018 to find a solution to the RVO process, and address the cost of the ethanol RINs. I believe stakeholders are increasingly coming to a consensus on the priorities for RFS reform, and we expect 2018 to be a busy year on this front. Our real victories this year were scored on the defensive line. First and foremost, we finally put to bed the effort to shift the RFS&rsquo;s point of obligation from the refiners to the blenders. On Nov. 22, EPA published its formal denial of the petition in the Federal Register. This year-long saga&mdash;thrust into the D.C. limelight with the controversy about Trump&rsquo;s advisor Carl Icahn and his ownership stake in CVR refining&mdash;created significant volatility in the RIN market this year, particularly in the conventional D-6 pool. In the end, EPA reported the following: &ldquo;In evaluating this matter, EPA&rsquo;s primary consideration was whether or not a change in the point of obligation would improve the effectiveness of the program to achieve Congress&rsquo;s goals.&nbsp; EPA does not believe the petitioners or commenters on the matter have demonstrated that this would be the case.&rdquo; Our second victory was in beating back the proposals outlined in EPA&rsquo;s Oct. 4 Notice of Data Availability pertaining to the volumes proposed by the agency in July for the 2018 RVOs.&nbsp; This document asked for comment on reducing the proposed RVOs generally, and in particular, the biomass-based diesel pool. The industry quickly unified and mobilized to beat back this proposal with help from five Midwest senators, numerous representatives, several governors, and various biofuels trade associations. Our industry&rsquo;s swift and definitive response to the NODA led to U.S. EPA Administrator Scott Pruitt releasing a letter in which he pledged his support for the RFS, and pulled back on the suggestions outlined in the NODA. In the end, EPA set the 2018 RVOs in line with the original July proposals. Furthermore, although the cellulosic volume for 2018 was reduced compared to last year&rsquo;s number, it was increased from the agency&rsquo;s July proposal, rewarding additional cellulosic production that has come online in 2017. This year&rsquo;s focus on tax reform has left Congress with little time to work on its tax extenders. Our industry&rsquo;s four primary tax credits&mdash;the biodiesel and renewable diesel, second-generation, and alternative fuels mixtures credits&mdash;are a part of the package of provisions that expired in 2016. As I write this, the entire biofuels industry is again coming together to push for the tax extenders package to be included in a year-end, must-pass budget or appropriations bill. Our differences of opinion on the blenders credit have all but evaporated as we collectively work to ensure the retroactive renewal of the biodiesel and renewable diesel tax credits. The good news is that if we are unsuccessful before year&rsquo;s end, we will most likely have another opportunity in late January. To sum up, we&rsquo;ve managed to preserve the status quo in 2017 for the RFS, and hopefully, for our tax provisions, which is a significant accomplishment given the change in administration. In early 2018, we must be ready for an intensified effort to address unresolved concerns about the costs associated with RFS compliance. Thank you for your comments and feedback over the year. I wish you and your families a happy holiday season, and look forward to hearing from you all in 2018. Author: Michael McAdams President, Advanced Biofuels Association <a href="mailto:michael.mcadams@hklaw.com" target="_blank">michael.mcadams@hklaw.com</a> <a href="http://www.advancedbiofuelsassociation.com" target="_blank">www.advancedbiofuelsassociation.com</a>

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Last year was among the most active and interesting years yet for the biofuels industry, which has confronted multiple challenges over the past 12 months,

2017 Wrap-Up: Maintaining the Status Quo

As power transformers at generation facilities near end-of-life cycles, a number of potentially dangerous events can come into play, in addition to untimely power outages and costly repairs. Because many transformers are exposed to dust and high operating temperatures, over time, they incur problems such as clogged air inlets, clogged cooling ducts, and deterioration of winding insulation, all of which can degrade capacity. If a transformer is operating under such conditions, particularly operating at or above its rated load, unexpected outages can occur. Among the more catastrophic of those events are explosions, fires and meltdowns that result in immediate outages, plus risk of worker safety, fines, security lapses and community ire. Occasionally, such events occur because of failure of the transformer lightning arrester, or an inadequate fire protection system. More often, problems due to end-of-life cycles for high-voltage transformers stem from transient overvoltage switching surges, or surges due to degraded insulation of coil windings. &ldquo;Insulation breakdown often results due to high heat, which is one of the biggest enemies of power transformers, as well as over voltage and high current loads above the rated values,&rdquo; says Alan Ober, vice president of engineering and manufacturing at transformer manufacturer and service provider ELSCO. &ldquo;Over a 20-year period, insulation can deteriorate to the point where the coil windings are exposed to moisture and dust, which leads to tracking, flashover to ground of the winding turns, and resulting short circuits.&rdquo; Such was the case at Avista Corp.'s Kettle Falls Generating Station in northeastern Washington. Built in 1983, the Kettle Falls plant was the first utility-owned electric generating station of its kind in the U.S. constructed for the sole purpose of producing electricity from wood waste, or biomass, making it a major contributor to Avista becoming one of the greenest utilities in the country. The 60-MW Kettle Falls station utilizes a variety of wet-type transformers for its power transmission functions, but also uses four dry-type transformers inside their plants to run motors for pumps, evaporators, pollution control systems, and clean air filtration systems. It is these four transformers, enclosed in a dedicated room with switchgear, which came into question in 2015 during the station&rsquo;s annual preventive maintenance outage. The insulation of the four transformers, each of them 35 years old, had already deteriorated to a concerning degree. The power station decided to replace two of the units immediately, and replace the other two in the next year. Yet, there were concerns about being able to find a replacement manufacturer who could provide the Kettle Falls facility with units that were essentially identical with their aging ones, that would drop right into the same footprint and also hook up to the switchgear via the same connections, without requiring significant modifications. After researching several prominent manufacturers, the utility&rsquo;s team decided on ELSCO to design and build the replacement units, as well as provide any modifications that could enhance service life or performance. Founded in 1912 by former Westinghouse engineers, ELSCO specializes in providing new, repaired and rebuilt transformers ratings range from 500 through 3750 kVA in 2.5, 5 and 15kV primary voltages, including both liquid-filled and dry-type models. Tailoring a Neat Fit The Kettle Falls Station team chose ELSCO mainly because of its abilities to design and build replacement transformers for older or outdated units, which often require a certain amount of customization to fit the space available. &ldquo;Tailoring the new transformer to fit the existing space not only facilitates successful installation, but also ensures that the new transformer will integrate directly with existing switchgear,&rdquo; Ober explains. Nathan Sarber, general forman of the Kettle Falls facility, says that not only was matching a tight transformer footprint a challenge, but also getting the replacement units in place was a strenuous task. &ldquo;These are 10,000-pound transformers that are located in a room inside a building, so we had to make sure we dealt with a transformer manufacturer who would be able to help us with the footprint, installation and connection requirements,&rdquo; he says. Sarber worked directly with ELSCO&rsquo;s Ober to ensure that the dimensions of the new units would not only meet the existing transformer specs, but would also facilitate the installation requirements of fitting through the transformer room and having compatibility with the existing switchgear connections. Although Ober's engineers often travel to a customer&rsquo;s site to evaluate the need for transformer service or replacement, much of the validation of replacement unit dimensions is performed with drawings and photographs. A site visit is particularly valuable when there are no references available for the original equipment. &ldquo;Using this process, he was also able to match up exactly the measurements for the dimensions of where our bus connects onto our low-voltage control center, so we were able to basically replicate the original connections from the new transformer,&rdquo; Sarber says. &ldquo;As a result, the footprint stayed exactly the same as it was with the original equipment. This was important, because we didn&rsquo;t have any room to spare.&rdquo; Although the new units were dimensionally identical to the original ones, ELSCO recommended and provided some upgrades for all four replacements. Instead of installing aluminum windings and connections, the manufacturer suggested that copper be used. &ldquo;Copper provides greater conductivity and longevity, with fewer chances of poor electrical connections,&rdquo; Sarber says. &ldquo;Also, in the old days, they used to manufacture transformers that were somewhat overdesigned in terms of capacity and durability. Today, with tighter profit margins, if you want a 1500 kVA transformer, that&rsquo;s exactly what you will get. You won&rsquo;t have the ability to overload it without the risk of a breakdown. So, now the quality of transformers is especially important, including windings and connections.&rdquo; Upgrading the solution The Kettle Falls station engineers also accepted ELSCO&rsquo;s recommendation to upgrade the new transformer enclosures. &ldquo;The old enclosures had inlets and outlets that were basically wide open near the top and bottom of each unit, except for arc-flash screening,&rdquo; Ober explains. &ldquo;There was the potential that, if a transformer would fail and go through a meltdown, the aluminum or copper of the windings could be thrown or splatter onto nearby equipment or personnel.&rdquo; The enclosures were upgraded to NEMA Type-2 indoor specifications that feature drip-proof ventilation louvers instead of slots, which would prevent any dripping water from entering the transformer. If an arc flash or meltdown were to occur, any molten aluminum or copper would be directed downward, providing a measure of added safety for personnel and surrounding equipment. Sarber adds that this project of replacing four aging transformers with new, drop-in units was a first for the plant. However, due to the lower cost and overall ease of the process, he intends to continue replacing aging transformers at the Kettle Falls Power Generation Station in this manner. Contact: ELSCO<a href="Mailto:info@electricservice.com" target="_blank"></a>
<a href="Mailto:info@electricservice.com" target="_blank">info@electricservice.com</a> 800-232-9002 www.elscotransformers.com

A Kettle Falls, Washington, biomass power facility recently avoided lengthy downtime and escalating expenses by upgrading four of its 35-year-old transformers. 

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Much of the validation of the transformer replacement unitsâ€™ dimensions were performed with drawings and photographs. Using this process, engineers were able to match the dimension measurements of where the bus connects onto the low-voltage control

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New-generation power transformers at Avista Corp.'s Kettle Falls, Washington, plant demonstrate the benefits of acquiring replacement units that fit existing footprints and connections.

Transformer Overhaul

In the power generation industry, one of the most inhospitable operational environments occurs within the boilers operating at waste-to-energy (WTE) facilities. There are many categories, but the most common WTE facilities use a fuel source that ranges from wood or construction debris to municipal solid waste (MSW). Within these boilers, pressurized boiler components are subjected to high temperatures (1,600 to 2000 degrees Fahrenheit), high pressures (850 to 1,200 psig) and fuel that is both highly corrosive and erosive. The principle corrosive component is the high-chlorine flue gas created by incinerating the fuel source. Erosion is accelerated due to fly ash impingement, and cleaning cycles performed by soot blowers within the operational boiler. To compound this corrosion/erosion effect, as the fly ash debris builds up onto the boiler components, it begins to block flu gas pathways. This buildup reduces the heat transfer across the boiler components, resulting in thermal hot spots within the boiler. As more surface area of the flu gas pathway is choked off, the remaining open pathways experience high-velocity fly ash impingement to nearby boiler component surfaces. Pressure components such as super heater tubes, super heater platens and water wall panels are all subjected to this hostile environment, and must be replaced at regular intervals, at a significant cost to the energy producer. Mitigation of Wear, Corrosion In an effort to extend component life and reduce replacement costs, the WTE industry has turned to overlaying their boiler pressure components with materials that help minimize wear rates associated with corrosion and erosion. Currently, the typical MSW boiler will process 1 percent (by weight) of chlorine through the boiler. In some of the larger facilities, this can equal 1,000 tons of chlorine burned per month. The most common overlaying alloy used in the power generation industry is Inconel 625. Known as a nickel-based alloy due to its high nickel content, Inconel 625 also contains, elevated amounts of chromium and molybdenum, providing a high level of pitting and crevice corrosion resistance caused by chloride contamination. This alloy can be found in generating plants that include coal-fired, biomass, nuclear and WTE. In this industry, a typical overlay thickness is 0.070- to 0.100-inch thick for pressurized boiler components. A common term for overlaying a metal component with a dissimilar alloy is known as cladding. The advantages of cladding are principally economic. The cost of using a less expensive alloy, (common example: SA213-T22) as the primary boiler component material, and cladding a layer of Inconel 625 over the surface, will cost much less than buying the entire component made from a solid piece of Inconel 625.&nbsp; Another advantage of using an overlay is that material properties might be such that complete components are impossible to fabricate, making cladding the only choice. Laser Overlay Development In February of 2011, American Cladding Technologies began working with a North American WTE power producer in an effort to create and apply a laser coating that would outperform Inconel 625 on pressurized boiler components. Though Inconel 625 was shown to be effective, it still fell short of component lifetime performance goals. Working with ACT, the power producer determined that laser cladding offered benefits that could not be realized with the more traditional methods of applying weld overlays. The development process was a collaborative effort between the WTE power producer&rsquo;s boiler reliability engineers, ACT laser process engineers, a producer of metal powdered alloys, and various university material testing facilities. Once a powdered alloy composition was selected, testing trials began with 10-foot, individual segments installed in various boiler pathways, on primary and secondary super heater pendants. Periodic boiler inspections were performed on the test samples to track performance. The project goals were to extend boiler pressure component lifetime by a minimum of two times, eliminate or reduce the use of shielding on super heater tubes, and optimize the laser cladding process to be cost competitive with existing overlay methods. By the end of 2011, the performance data on the test samples showed results encouraging enough to warrant moving ahead with continued laser metal deposition of super heater tubes. ACT accepted its first purchase order to laser clad a set of 2.5&rdquo;&Oslash;, SA213-T22 super heater tubes for delivery in January 2012. As of November, more than 38 WTE boilers across the U.S. are now operating with coatings developed by ACT. The principle components that show the largest benefit include primary/secondary super-heater tubes and platens. Another boiler component benefiting from this process is the soot blower lance. With encouraging performance data, ACT has now begun testing in both the biomass and pulp and paper industries. Findings, Results In order to maintain customer confidentiality, ACT will not release or discuss specific values regarding the realized cost savings, power plant operating values or any other data that might be considered sensitive to our customers. However, a general overview of the performance results is as follows: Improved thermal efficiencies compared to the preexisting Inconel overlays. a) Elimination or reduction of shielding has reduced ash buildup in the low-flow areas between the shield and tube face, and therefore improved heat transfer. b) Reduced heat input of the laser cladding process results in a very low dilution of the cladding material. This allows for a reduced coating thickness which aids in thermal efficiency. Reduced costs. a) Reduced or eliminated costs associated with shielding procurement and installation.&nbsp; Shielding the lead tubes for most super heaters has been eliminated. b) Reduced the need for (and costs of) unplanned outages by extending boiler component life. c) Boiler life has more than doubled for most facilities. Prior to coating development, the typical Inconel-coated super heater lifespan was 16 to 24 months. At the time of this writing, some super heater components have now been in service for over five years. Other advantages of laser hard-facing over preexisting Inconel overlays. a) Reduced fly ash erosion due to the increased wear resistance of the coating. The typical laser applied overlay is 66 to 70 Rc and very wear resistant. b) By eliminating or reducing super heater tube shielding, hot spot formation has been reduced, thereby reducing localized failure points. c) Less debris buildup onto super heater tubing. Soot blower cleaning cycles have been reduced. Some facilities have reported a 79 percent reduction in cleaning cycle frequency. d) For continuous inline soot blower lances, component life of the lance has been extended by up to six times their preexisting lifespan due to the laser coating. Production cost per linear foot of the laser hard-facing can be equal to or less than the linear foot cost of traditional Inconel 625 overlays. Cost reductions of 40 percent have been realized. These cost swings are largely dependent on total production quantity; required coating thickness, which is significantly less than typical Inconel wire overlays and therefore leads to reduced filler material costs and cladding cycle times; laser deposition rates, which continue to increase as the development effort continues; and the geographic region within the U.S., as overlaying costs vary per region. In summary, due to the low heat input and rapid solidification of the weld pool, the microstructure of the laser overlay is typically superior to traditional overlay methods, and coating thickness can be reduced while maintaining full material properties. All three project goals were achieved through the laser clad development.&nbsp; SH life has doubled or tripled, most, if not all, tube shielding has been removed, and the overall cost of application is now competitive with the traditional, wire-fed Inconel overlay methods. Author: Scott Poeppel Vice President, American Cladding Technologies 860-784-1962 <a href="Mailto:spoeppel@americancladding.com" target="_blank">spoeppel@americancladding.com</a>

Through work with a North American waste-to-energy power producer, American Cladding Technologies has developed a laser coating that may outperform Inconel 625 on pressurized boiler components.

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Pictured is a leading super heater tube from a test sample inspection. Boiler inspection was performed after approximately 14 months of operation. No shielding was installed on test samples. This image was taken after a water wash cleaning of the sup

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Energy plants that use wood, construction debris and municipal 
solid waste can benefit from recent advances in laser metal deposition.

January/February 2018

Columns

Will EPA Regulations Drive More Wood Stove Innovation?

Biomass's Opportunity in Future Power Trend

Every Last Drop

2017 Wrap-Up: Maintaining the Status Quo

Featured

The ABCs of ORCs

Contributions

Transformer Overhaul

Laser Cladding Advancements for Pressurized Boiler Components

Departments

A First of Their Kind

January/February 2018 .css-7jxktu{position:absolute;bottom:0px;left:0px;right:0px;height:3px;border-radius:3px;background-color:var(--chakra-colors-brandBlack);}

Columns

Will EPA Regulations Drive More Wood Stove Innovation?

Biomass's Opportunity in Future Power Trend

Every Last Drop

2017 Wrap-Up: Maintaining the Status Quo

Featured

The ABCs of ORCs

Contributions

Transformer Overhaul

Laser Cladding Advancements for Pressurized Boiler Components

Departments

A First of Their Kind

January/February 2018