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2016 02 Power Engineering

Magazine Power Engineering

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2016 02 Power Engineering

  1. 1. HARNESS THE POWER OF ADVANCED HRSG TECHNOLOGY The industry leader in Heat Recovery Steam Generators for gas turbines up to 30 MW, RENTECH offers a full range of HRSG systems to meet your toughest project requirements. We custom engineer our crossflow two-drum and waterwall designs to perform superbly in the most demanding applications and operating conditions. We master every detail to deliver elemental power for clients worldwide. HARNESS THE POWER WITH RENTECH. HEAT RECOVERY STEAM GENERATORS WASTE HEAT BOILERS FIRED PACKAGED WATERTUBE BOILERS SPECIALTY BOILERS WWW.RENTECHBOILERS.COM
  3. 3. © 2016 General Electric Company. All rights reserved. At GE’s Gas Power Systems, we bring together advanced gas-fired technologies, experienced plant engineers, and predictive industrial software. Designing, building, and working as one fast moving system. Meeting the unique needs of today’s power-hungry planet. We’re always ready to run. #ReadytoRun @ge_gaspower For info. RS#1
  4. 4. SENIOR VICE PRESIDENT, NORTH AMERICAN POWER GENERATION GROUP — Richard Baker (918) 831-9187 NATIONAL BRAND MANAGER — Rick Huntzicker (770) 578-2688 CHIEF EDITOR — Russell Ray (918) 832-9368 ASSOCIATE EDITOR — Sharryn Dotson (918) 832-9339 ASSOCIATE EDITOR — Tim Miser (918) 831-9492 CONTRIBUTING EDITOR—Brad Buecker (913) 928-7311 CONTRIBUTING EDITOR—Brian Schimmoller (704) 595-2076 CONTRIBUTING EDITOR—Robynn Andracsek (816)-822-3596 CONTRIBUTING EDITOR—Wayne Barber (540) 252-2137 CONTRIBUTING EDITOR—Barry Cassell (804) 815-9186 GRAPHIC DESIGNER — Deanna Priddy Taylor (918) 832-9378 MARKETING MANAGER — Rachel Campbell (918) 831-9576 CIRCULATION MANAGER — Linda Thomas AUDIENCE DEVELOPMENT MANAGER I — Jesse Fyler PRODUCTION MANAGER — Katie Noftsger CORPORATE HEADQUARTERS—PennWell Corp. 1421 South Sheridan Road • Tulsa, OK 74112 P.O. Box 1260, Tulsa, OK 74101 Telephone: (918) 835-3161 • Fax: (918) 831-9834 E-mail: World Wide Web: For assistance with marketing strategy or ad creation, please contact PennWell Marketing Solutions VICE PRESIDENT — Paul Andrews (240) 595-2352 CHAIRMAN — Robert F. Biolchini VICE CHAIRMAN — Frank T. Lauinger PRESIDENT AND CHIEF EXECUTIVE OFFICER — Mark C. Wilmoth EXECUTIVE VICE PRESIDENT, CORPORATE DEVELOPMENT AND STRATEGY — Jayne A. Gilsinger SENIOR VICE PRESIDENT, FINANCE AND CHIEF FINANCIAL OFFICER — Brian Conway SUBSCRIBER SERVICE P.O. Box 3264, Northbrook, IL 60065 Phone: (847) 763-9540 E-mail: REPRINT SALES — Rhonda Brown Tel: 866.879.9144 ext 194 • Fax: 219.561.2023 POWER ENGINEERING® (ISSN 0032-5961) USPS 440-980, POWER ENGINEERING is published 12 times a year, monthly by PennWell® Corporation, 1421 S. Sheridan,Tul- sa, OK 74112. Periodicals postage paid at Tulsa, OK 74112 and at additional mailing offices. SUBSCRIPTION PRICES: U.S.A. and possessions $111 per year; Canada and Mexico, $124 per year; international airmail, $300 per year. Single copies: U.S., $18, Outside U.S. $29. Back Issues of POWER ENGINEERING may be purchased at a cost of $18 each in the United States and $29 elsewhere. POSTMASTER: Send address corrections to POWER ENGINEERING,P.O.Box 3271,Northbrook,IL 60065-3271.POW- ER ENGINEERING is a registered trademark. © PennWell Corporation 2016. All rights reserved.Reproduction in whole or in part without permission is prohibited.Permission, however, is granted for employees of corporations licensed under the Annual Autho- rization Service offered by the Copyright Clearance Center Inc. (CCC), 222 Rosewood Drive, Danvers, Mass. 01923, or by calling CCC’s Customer Relations Department at 978-750-8400 prior to copying. We make portions of our subscriber list available to carefully screened companies that offer products and services that may be important for your work. If you do not want to receive those offers and/or information via direct mail, please let us know by contacting us at List Services POWER ENGINEERING, 1421 South Sheridan Road,Tulsa, OK 74112. Printed in the USA. GST No. 126813153. Pub- lications Mail Agreement no. 40612608. Member American Business Press BPA International PRINTED IN THE U.S.A. GST NO. 126813153 Publications Mail Agreement No. 40052420 Power Engineering® Power Engineering is the flagship media sponsor for POWER ENGINEERING ONLINE : Newsletter: Stay current on industry news, events, features and more. Newscast: A concise, weekly update of all the top power generation news Industry News: Global updates throughout the day FEATURES DEPARTMENTS No.2,February 2016 120YEARS 20 Dry Ash Conversions With the final version of the Environmental Protection Agency’s Coal Combustion Residuals (CCR) rule now on the books,utilities have the regulatory clarity they need to move forward with compliance strategies.What should you consider when developing and executing a plan to meet the new CCR mandates. 33 Leak Detection “Ins” and “Outs” When condensers experience air inleakage and water leakage,the results can be costly. Proactive routine cleaning and leak detection can maximize output while minimizing outages. 30 Combating Boiler Slag The tools used to combat the buildup of boiler slag at power plants are wide ranging.Common tools include soot blowers,sound waves,hydro blasters,CO2 blasters, jackhammers,picks,and carefully-aimed shotguns.In some severe cases,plant operators will turn to dynamite to deal with ceaseless slagging. 36 Natural Gas Gensets: Poised for Growth As a source of emergency standby,prime,peaking,or continuous power,natural gas-fired generator sets are poised for significant growth,especially in the U.S., where low-priced natural gas is widely available. 16 Analyzing the Potential of CHP in North America Combined heat and power has the potential to provide a quarter of U.S.power needs.This time-tested form of power generation is poised for vigorous growth. Our analysis of this emerging market will explain why. 2 Opinion 4 Industry News 6 Clearing the Air 8 Industry Watch 10 View on Renewables 12 Energy Matters 14 Nuclear Reactions 40 What Works 41 Generating Buzz 56 Ad Index
  5. 5. 2 OPINION said Chip Bottone, chief executive offi- cer of FuelCell Energy. Bottone’s company has fuel cell pow- er plants up and running in more than 50 locations worldwide. Fuel cells have several advantages over other more common forms of on- site power. They are significantly clean- er, quiet, less expensive to operate, and require little real-estate. Dominion Resources owns the largest fuel cell power plant in North America, a 15-MW project in Bridge- port, Connecticut, capable of produc- ing enough electricity for about 15,000 homes. Dominion sells the power to Connecticut Light & Power under a 15- year power purchase agreement. Fuel cells are not a new technology. They have long been associated with the NASA space program and transpor- tation vehicles. In recent years, though, the applications and markets for fuel cells have expanded. Fuel cells are be- ing used for primary power, backup power, emergency power, and auxilia- ry power. They are used to power ho- tels, hospitals, universities, and data centers for Apple and eBay. As the cost of centralized power rises, the cost of decentralized power contin- ues to fall. Some power professionals believe the days of centralized power are numbered. That point of view is a bit extreme, but fuel cells are without question going to play a starring role in what is sure to be a significant transi- tion to distributed generation. If you have a question or a comment, contact me at Follow me on Twitter @RussellRay1. I magine a source of power that is virtually emission-free, highly re- liable, occupies small spaces and can generate enough electricity to pow- er thousands of homes. It’s not a pipe dream. The technology has been around for a while and it is increasingly being deployed in the U.S. and abroad to meet public demand for clean, reliable electricity. More homes, businesses and utilities are turning to fuel cells to meet their pow- er generation needs. Installing groups of modular fuel-cell systems to create small power plants ranging from 5 MW to 63 MW in size is a growing market. Several large scale fuel-cell power plants have been built in Connecticut, Delaware and California. Just last month, state officials in Connecticut approved plans to build what will be the largest fuel cell power plant in the world. Equipped with 21 fuel cells, the 63.3-MW Beacon Falls fuel cell power plant will surpass the 59.9-MW fuel cell plant in South Korea. The Beacon Falls project will be capa- ble of generating enough electricity to power 60,000 Connecticut homes and is expected to be completed in 2019. The power plant and substation will be built on about eight acres. A solar plant would require about 10 times more land to achieve the same amount of output. In addition, fuel cells, which use hydrogen and oxygen to generate elec- tricity, have no moving parts, making them inherently quiet and ideal for use in urban settings where the power is actually consumed. This limits the need for transmission and distribution lines, thus reducing the risk of power outages caused by ice storms and heavy winds. The hydrogen used in fuel cells can be produced by a variety of fuels, in- cluding natural gas. A fuel cell splits hydrogen into electrons and protons. As protons pass through the cell’s thin plastic membrane, the electrons are forced into a circuit, creating an elec- tric current. Although the universe is 80 percent hydrogen, it is almost never found nat- urally by itself because it’s locked up in other compounds like water and cellu- lose. That’s why the source of hydrogen is typically natural gas or methane. The electrochemical reaction in fuel cells creates water vapor, eliminating the harmful emissions of a combustion engine.  What’s more, the cost of fuel cells is falling thanks to increasing demand, or better economies of scale, making the technology even more attractive. Leading fuel cell manufacturer Fu- elCell Energy Inc. will supply the fuel cells for the Beacon Falls project. Since power from fuel cells have been deemed renewable in 13 states, including Connecticut, the power from these systems can be used to comply with new standards for renewable pow- er, also known as renewable portfolio standards (RPS). “This one project meets about 10 percent of the State of Connecticut’s RPS requirements for 2016, and no state funds are needed as private capi- tal will be used to finance the project,” Fuel Cells to Play Important Role in Power Generation BY RUSSELL RAY, CHIEF EDITOR
  6. 6. US Corporate Office | 660.829.5100 Whether it’s a planned project or an urgent need, ProEnergy has a solution for every aspect of your plant’s operation. From a full inventory of equipment to a complete team of experienced engineers, you can rest assured we’ve got all the pieces you need when you need them most. THE RIGHT PIECES AT THE RIGHT TIME For info. RS#2
  7. 7. 4 INDUSTRY NEWS connection expected between April and December. NRC Begins Inspection at Arkansas Nuclear One The U.S. Nuclear Regulatory Com- mission (NRC) began a comprehensive inspection at Entergy’s Arkansas Nuclear One power plant. A team of 25 inspectors will devote about 3,600 hours of effort to inde- pendently assess and document the ade- quacy of Entergy programs and process- es used to identify, evaluate, and correct performance issues; provide insights into the causes of performance deficiencies; and evaluate the adequacy of a third-par- ty safety culture assessment conducted at the site. The NRC placed ANO under special inspections after a 2013 incident during a planned outage where heavy equipment fell and  killed a worker. In June 2014, the NRC issued yellow findings for how the equipment was handled. In January 2015, the NRC issued additional yellow findings associated with flood protection at the plant. The findings moved ANO into Column 4 of the plant performance matrix, the second-highest level of the matrix, which also means the plant is un- der the highest level of NRC oversight of operating power plants. Column 5 would mean the plant could not operate. Supreme Court Rules FERC Can Issue Demand Response Rule The U.S. Supreme Court overturned a lower court ruling against the Federal En- ergy Regulatory Commission (FERC) Or- der 745, which pays consumers for using less power during high-demand periods. In  Electric Power Supply Association v. FERC, the high court voted 6-2 that FERC hadauthorityundertheFederalPowerAct to issue the so-called demand response rule. The justices said FERC is not directly regulating retail electricity sales with the rule. Justice Samuel Alito recused himself Court Denies Stay of Clean Power Plan The D.C. Circuit Court of Appeals denied petitions to stay the Obama administration’s  Clean Power Plan, preserving the landmark rule’s author- ity to regulate carbon emissions from power plants, even as the rule prepares to defend against subsequent litigation designed to erode its legality. The Clean Power Plan calls for sweeping new requirements to cut car- bon dioxide emissions 32 percent be- low 2005 levels by 2030. States have until 2018 to submit their compliance plans. Stating that petitioners “have not satisfied the stringent standards that apply to petitions for extraordinary writs that seek to stay agency action,” the court declined to uphold action brought by West Virginia and Peabody Energy Corporation, which would have rendered the law powerless, even as it defended its constitutionality in future legal cases. The American Coalition for Clean Coal Electricity (ACCCE) says efforts to overturn the Clean Power Plan will continue. sPower Plans 700 MW of Utility-Scale Solar in 2016 Sustainable Power Group (sPower) has entered a contract with Rosendin Electric Inc. (REI) to develop nearly 700 MW of  utility-scale solar  photovoltaic (PV) projects in 2016. Construction of the new projects be- gan in January, with completion and grid from the case because of a stock holding. The demand response rule was adopt- ed in March 2011 and was intended to compensate large, individual consumers such as utilities, large groups of electric- ity consumers, and factories for using less electricity during peak demand peri- ods. A U.S. Court of Appeals for the D.C. Circuit panel ruled in May 2014 that the states have jurisdiction over demand re- sponse because it affects retail customers and how much electricity they buy, even though it affects the wholesale markets. EIA: Fossil-Fueled Power to Lose Share to Renewables Fossil-fueled power generation will lose share to renewable resources across the nation’s generation portfolios, ac- cording to the U.S. Energy Information Administration’s (EIA) Short-Term Ener- gy Outlook. Published last month, the current edition of the report is the first to include energy forecasts for 2017. “A decline in power generation from fossil fuels in the forecast period is offset by an increase from renewable resources,” the report says. The share of natural gas-fired power generation is expected to fall from 33 percent in 2015 to 31 percent in 2017. Likewise, the share of coal-fired power generation will fall from 34 percent to 33 percent in the reporting period. Renewables are expected to increase their share of the country’s power gener- ation portfolio, with hydropower rising from 6 percent in 2015 to 7 percent in 2017, and the share of all other renew- ables rising from 7 percent to 9 percent in the same period. The report sees continued growth in utility-scale solar power, forecasting a production average of 129 gigawat- thours per day in 2017, which represents a 45-percent increase over 2016 levels. Levels in 2016 will themselves amount to a 126-percent increase over 2014 levels. All told, utility-scale solar is forecasted to
  8. 8. For info. RS#3 account for 1.1 percent of total U.S. power generation in 2017. North Carolina, Ne- vada and California will together account for about two-thirds of capacity additions in 2015 and 2016. With its larger installed capacity base, wind energy grew by 13 percent in 2015, says the report. It is forecasted to increase by 14 percent in 2016 and 3 percent in 2017. MHPSA Ships First Domestically-Manufactured M501J from Georgia Mitsubishi Hitachi Power Systems Americas (MHPSA) has shipped the first U.S.-manufactured M501J gas tur- bine from its Savanah Machinery Works (SMW) facility in Georgia. The new tur- bine is now on its way to Grand River Dam Authority’s (GRDA) Grand River Energy Center in Oklahoma. The J-series gas turbine will replace the facility’s older coal-fired unit. Once oper- ational, the 300-ton turbine will generate 495 MW of electricity, supplying power to GRDA customers in all but two of Okla- homa’s counties. “What makes the J-series gas turbine so unique is that it is the first and only turbine in commercial operation today capable of achieving 2,912°F turbine inlet temperatures while delivering efficiencies approaching 62 percent in combined-cy- cle mode,” said David Brozek, senior vice president at MHPSA. Scheduled for completion in the sec- ond quarter of 2017, GRDA’s turbine will be the 28th J-series turbine to go into commercial operation. In addition to the GRDA Unit, SMW has a backlog of J-Se- ries turbines that will be shipped over the next several years. MHPSA’s SMW manufacturing facility opened in 2011, fulfilling a commitment by the company to be closer to its North American customer base and provide fast- er support. Hurst Boiler Commissions 1st US Poultry Litter-Fueled Boiler Hurst Boiler is commissioning the first poultry litter-fueled boiler in the U.S. – the world’s third such system – at a Clin- ton, North Carolina cogeneration facility. Commissioning is expected in mid- 2016, at which time the system will sup- port Prestage Farm’s turkey operations. The 1600 HP is the first Hurst Boiler system in the country designed specifical- ly to be fueled by poultry litter. “While we have been carefully evaluat- ing the potential to use litter in our boilers in the U.S. market, one of our solid fuel boilers in Guatemala began running al- most three years ago on 100-percent litter, simply because it was the most cost effec- tive and reliable fuel,” said Tommy Hurst, of Hurst Boiler Inc. “Since then, two more systems have been installed and are pro- viding steam to poultry facilities using only chicken litter.” “We are well aware of the many chal- lenges and problems of litter as a fuel, which is why we spent an inordinate amount of time and resources making sure that we had measures in place to ensure success in the U.S. market,” said Charlie Coffee, solid fuel boiler sales for Hurst Boiler. Coffee says there are many benefits to using poultry litter. The ash from litter is rich in potassium and phosphorous. “By concentrating these nutrients in ash, these systems can transform the po- tential risk of phosphorous regulation into an economic asset for companies,” said Coffee.
  9. 9. 6 CLEARING THE AIR W hile admitting the final version of the Clean Power Plan (CPP) is better than the proposed version, Jeff Holmstead, an environmental attorney with Brace- well & Giuliani, said the CPP is very clever, but ultimately illegal. Holmstead’s comments were made in a mega-session at POWER-GEN In- ternational 2015. Holmstead said short of a stay, the CPP will carry the force of law during litigation, but will likely be struck down by the Supreme Court in late 2017 or early 2018. Under the law, he said, a single Supreme Court justice—John Roberts—could stay the rule unilaterally, though there is no precedent for such an action, and it will likely not happen. The Clean Power Plan calls for sweeping new requirements to cut car- bon dioxide (CO2 ) emissions 32 per- cent below 2005 levels by 2030. States have until 2018 to submit their compli- ance plans. On Jan. 21, the D.C. Circuit Court of Appeals did indeed deny petition to stay the rule, preserving the land- mark legislation’s authority to regulate carbon emissions from power plants, even as the rule prepares to defend against subsequent litigation designed to erode its legality. Stating that petitioners “have not satisfied the stringent standards that apply to petitions for extraordinary writs that seek to stay agency action,” the Court declined to uphold action brought by West Virginia and Peabody HOLMSTEAD: CPP is Very Clever, but Ultimately Illegal BY TIM MISER, ASSOCIATE EDITOR Energy Corporation, which would have rendered the law powerless as it defended its constitutionality in future legal cases. The final rule, Holmstead said, took a much more national approach and was designed to incentivize states to imple- ment a mass-based cap and trade pro- gram, instead of a rate-based program. Still, he said, states are all watching one another to see what the others will do. The session, attended by more than 100 power professionals, also includ- ed panelists Ben Machol with the EPA, Steve Corneli with NRG Energy, and John Lawhorn with the Midwest Inde- pendent System Operator (MISO.) Machol said the CPP was designed to mitigate climate change and the asso- ciated warming trend of the last many years. He then highlighted key differ- ences between the proposed version and the final version of the CPP. NRG Energy’s Corneli said there is no longer a question about climate change. The science is in, he said, and as a large carbon emitter, NRG is in the process of working toward a solution. Corneli ad- vocated for a strategy that would “pick the low-hanging fruit first”. States can approach owners of coal plants and ask them to commit to voluntarily retire high-emission coal plants, he said. Many states are already very close to CPP compliance, he continued, and emissions reductions will essential- ly come from coal plants, not com- bined-cycle gas-fired plants. Lawhorn, whose work has modelled the impact of the CPP, said the inter- connected nature of the grid creates an environment in which conditions that affect one system operator may also af- fect neighboring system operators. MISO is talking with its neighbors about collective efforts to analyze the CPP, he said, adding the impacts of the CPP “will be national in scope, reach- ing beyond the border of any single sys- tem operator.” Addressing the question of whether the CPP delivered what it was expected to deliver, Lawhorn said there was no way to know, since state implementation plans are not yet final- ized. The default backstop for the CPP is the federal implementation plan, he noted, adding that states “need the flexibility to implement the CPP on the most economical basis possible.” Jeff Holmstead
  10. 10. We fit 15 patents and 23 engineers into As an engineer at a power-gen company, you know there’s no margin for error. At VSP Technologies, we make fluid-sealing products built for reliability and safety. But don’t take our word for it. Our customers have reported over $100 million in cost savings – thanks to less downtime, process improvements and 24/7 expert service from a team of engineers and technicians. We’re doing big things for the power-gen industry. Download your free white papers at 1/16” t en company, r error. uid-sealing ety. But don’ ve reported ks to less 24/7 ’t d s Engineering Service and Support Product Design and Development 1-800-334-6013 “Last night, I was involved in an emergent event that required parts to be shipped for next-day a.m. delivery to one of our nuclear sites. VSP Technologies came through with exemplary performance during this event. It was late, we were tired, and the VSP team provided a solution that met customer expectations, with smiles on their faces. Thank you!” – Supply Chain Manager Power Utility For info. RS#4
  11. 11. 8 INDUSTRY WATCH networks of key DER stakeholders. DER project orchestrators uncover op- portunities for smart cities and cam- puses as well as individual energy con- sumers large and small to save money, increase resiliency, security and sus- tainability, and promote economic development. At the same time, they help utilities find, size, and develop opportunities to defer capital, improve operations, and generate new revenue sources, resulting in net savings for ratepayers. They help wholesale mar- kets maintain balance by creating new DER-enabled energy, capacity and an- cillary service resources. They develop securitizable DER project investment structures such that private investors have opportunities to realize attractive and portfolio-diversified risk-adjusted returns. Finally, DER project orchestra- tors engage project developers, service providers, and technology vendors at deeper levels of commitment, thereby creating significant cross-project syner- gies while driving down team integra- tion risks and soft costs. The emergence of new players and partnerships in this space is evidence of a shift to complex DER project or- chestration over simple generation as- set development. Though DER growth is forecasted to rise, development barri- ers abound, creating the need for a new kind of player in the market.  As such, DER investments will be increasing- ly specified, procured, and deployed through the influence or direct con- trol of project orchestrators. Wise DER asset vendors and project developers will find ways to partner with this new breed of DER project orchestrator . D istributed Energy Resource (DER) deployments are rap- idly growing. While DER drivers vary by technology, region, and customer, “the overarching goal of DER deployments is to make the electricity grid more efficient, resilient, cost-effective, and sustainable.” Navigant Research forecasts the world-wide capacity of DER to increase four fold from 136 GW in 2015 to 531 GW in 2024. Of that increase, North America is projected to be the second largest market (after Asia Pacific) with installed capacity increasing 46 GW to 134 GW—a compound annual growth rate of 12.6 percent. In light of these trends, players are acting. Utilities are increasingly consid- ering DER as tools for planning, such as ConEd’s Brooklyn/Queens Demand Management (BQDM) program that seeks to use DER to defer $1 billion in substation and related infrastructure upgrades. Similarly, unregulated util- ity businesses are pursuing new DER business lines, such as Duke Energy Renewables’ majority stake in REC So- lar and subsequent partnership with Green Charge Networks. Meanwhile, leading DER firms are continuing to make investments in North American, such as Tesla’s factories in Sparks, NV. As DER grid penetration accelerates, feeder DG absorption constraints, in- terconnect complexity, and cost and op- erational concerns all rise accordingly. While direct interconnection costs are often regulated to be borne by the DER project, broader issues of legacy fixed investment and obligation-to-serve operational readiness cost shifting to non-participants is sparking debate across the U.S. and beyond. The crux of the matter is that although custom- ers want to control their own destiny and reduce costs, distribution utilities remain obligated to maintain the grid’s safety and reliability at the lowest cost possible and with equitable cost ap- portionment across rate classes. As this DER growth tension plays out, private investors are lining up, eagerly seeking returns through ownership of a piece of the growing DER pie, but also frustrat- ed in their struggle to identify attrac- tive risk-adjusted return opportunities within this complex DER ecosystem. A DER project orchestrator, much like a network orchestrator, provides proactive coordination of stakehold- ers to achieve value creation benefits for all. These benefits reach beyond the typical project finance and gener- ation asset metrics of interest to tradi- tional project developers, and include value propositions attractive to a wide range of stakeholders. In pursuing this broader basket of benefits, DER project orchestrators unlock value by uncover- ing and addressing hidden opportuni- ties and risks among and between utili- ties, investors, communities, wholesale markets, and large or aggregated loads. Finally, DER project orchestrators operate at scale by leveraging broad Holders of the Hidden Keys to DER Integration BY KEN HORNE, ASSOCIATE DIRECTOR, DAN BRADLEY, MANAGING DIRECTOR, AND MICHELLE BEBRIN, SENIOR CONSULTANT, NAVIGANT Ken Horne Dan Bradley Michelle Bebrin
  12. 12. Industrial Insulation Shaped by Experts We share our knowledge to your advantage. The key to ROXUL Technical Insulation’s success is the combination of high-grade products and dedicated people. Thanks to our expertise and 75+ years of experience our customers can count on sustainable ProRox stone wool solutions that offers great protection against fire, heat, noise and energy loss. Like us to share our knowledge with you? Call (800) 265-6878 or visit for the latest in a series of expert tools that help your business shape up. 1.800.265.6878 Order your ProRox Process manual at Order your ProRox Industrial insulation Process Manual Technical guidelines for the insulation of industrial installations EXPERT TOOL For info. RS#5
  13. 13. 10 VIEW ON RENEWABLES facility, but also requires that the custom- er enter a contract with the utility and pay distribution, delivery, and daily demand charges to the utility. These green tariffs can help utilities remain relevant and vi- able among corporate customers seeking new options. Another option for corporations in reg- ulated states are contracts in which the corporation does not purchase the power to serve its own retail load. Instead, while the specific terms generally vary, in a con- tract for differences, the renewable energy seller sells its energy into the market for the available market price (floating) and the corporate customer agrees to fixed price for the same power. The buyer then settles monthly with the seller on the dif- ference between the fixed and floating prices with a payment going from buyer to seller if the fixed price is above the mar- ket price and in reverse where the floating price is above the fixed price. This ar- rangement provides a benefit to the seller in terms of a fixed revenue stream and to the buyer in the form of a hedge against its retail supply arrangement. That said, these arrangements can implicate regu- latory and accounting obligations about which corporations and sellers must be aware. Corporations’ ever-increasing demand for renewables is driving new and inno- vative options for procuring them. While corporations in regulated states have been limitedintheirabilitytodirectlypurchase renewables and take advantage of their lower costs, virtual PPAs and green tariffs are beginning to offer those benefits. Cor- porations can thus look forward to better access to renewables going forward. B usinesses across the country are seeing the green in renewable energy. They recognize that in ad- dition to helping meet corporate sustain- ability goals, renewables are a desirable option from a profitability standpoint be- cause electricity generated by renewables is increasingly cost-competitive with fos- sil-fuel generation without the same price volatility and risk. This is good news for renewable developers as it increases de- mand for renewable energy and presents potential customers. Businesses target- ing opportunities to purchase renewable energy have several options: they can install renewables (usually solar) on site, purchase renewables directly from a spe- cific project, or participate in a program through their designated public utility. However, the options available to the company usually depends on the reg- ulatory scheme applicable to the load the company wishes to serve. States like Illinois, Oregon, Texas, California, and much of the Northeast have deregulated their electricity markets, meaning that the traditional system of public utility monopolies has been replaced with a sys- tem in which independent electricity sell- ers can compete with the utility to serve certain loads. In deregulated states, cor- porations generally can enter into power purchase agreements (PPAs) directly with renewable energy projects; provided that the customer qualifies for and has opted into the applicable direct access program and the seller is eligible to sell. Renewable energy developers often have the option to consider serving the load directly or contracting with the qualified entity that serves the rest of the corporation’s load. Tying together the various pieces of the service obligation and multiple contracts is complex. In addition, with a pivot from utility to commercial and industrial off-takers comes new discussions about traditional allocations or risks in renew- able PPAs. In states that have maintained their traditional regulatory scheme for public utilities, renewable developers cannot en- ter into PPAs directly with corporations. States long ago granted public utilities the exclusive right to sell electricity in the utility’s service territory in order to avoid duplication of service. This restriction is a central tenet of traditional public utility regulation, and is one of the primary dif- ferences between regulated and deregu- lated states. Corporations wishing to pur- chase renewable energy to power facilities in regulated states depend on public utili- ties to procure that renewable energy. For over 20 years, utilities have met requests for renewables from corporate customers by offering “green tariffs” to large custom- ers, charging these customers a premium for the renewable energy and providing them with renewable energy certificates (RECs) so that the corporations can prove their commitment to renewables. Corporations are beginning to find ways to work around restrictions in regu- lated states. Utilities have begun offering new green tariffs that are more appealing to corporate buyers. In Utah, the Legisla- ture has created an option that blends a green tariff with a corporate PPA. The En- ergy Resource Procurement Act, passed in 2012, allows the customer to select the renewable energy facility and negoti- ate the price and RECs directly with the Regulatory Tips for Companies Seeking Green Energy Opportunities BY JENNIFER MARTIN AND EMMA FAZIO, STOEL RIVES Jennifer Martin Emma Fazio
  14. 14. CLEAN SOLUTIONS FOR THE POWER INDUSTRY Power generation has many unique monitoring requirements, from combustion optimization, air pollution control and continuous emissions monitoring. The more complex the process, the greater the demands on analyzer solutions, system engineering and services. When it comes to meeting these measurement ᣝᣞᣟᣠᣠᣡᣢᣣᣡᣤᣥᣦᣧᣨᣩᣪᣦᣫᣤᣦᣟᣦᣤᣬᣡᣭᣦᣟᣞᣡᣟᣮᣦᣯᣫᣬᣞᣦᣝᣰᣱᣭᣠᣡᣬᣡᣦᣤᣰᣠᣲᣬᣫᣰᣢᣤᣦᣳᣰᣴᣦᣣᣟᣤᣦᣟᣢᣟᣠᣵᣤᣫᣤᣥᣦᣮᣲᣤᣬᣦᣟᣢᣮᣦ᣶ᣰᣯᣦᣱᣡᣟᣤᣲᣴᣡᣱᣡᣢᣬ᣷ᣦᣧᣨᣩᣪᣦ offers rugged technologies that are perfectly tailored for each measurement environment, with superior ᣡ᣸ᣲᣫᣭᣱᣡᣢᣬᣦᣟ᣹ᣟᣫᣠᣟ᣺ᣫᣠᣫᣬᣵᣦᣟᣢᣮᣦᣡᣟᣤᣵᣦᣰᣭᣡᣴᣟᣬᣫᣰᣢ᣷ᣦ᣻ᣞᣡᣢᣦᣫᣬᣦᣝᣰᣱᣡᣤᣦᣬᣰᣦ᣼ᣢᣮᣫᣢᣣᣦᣟᣦᣝᣠᣡᣟᣢᣦᣤᣰᣠᣲᣬᣫᣰᣢᣥᣦᣬᣞᣡᣦᣯᣞᣰᣠᣡᣦᣯᣰᣴᣠᣮᣦᣬᣟ᣽ᣡᣦᣫᣬᣤᣦ ᣱᣡᣟᣤᣲᣴᣡᣱᣡᣢᣬᣤᣦᣳᣴᣰᣱᣦᣧᣨᣩᣪᣦ᣾ᣦᣯᣡᣦᣬᣞᣫᣢ᣽ᣦᣬᣞᣟᣬ᣿ᣤᣦᣫᣢᣬᣡᣠᣠᣫᣣᣡᣢᣬ᣷ᣦᣩᣟᣠᣠᣦᤀᤁᤂ᣾ᤃᤄᤅ᣾ᤆᤂᤇᤇᣦᣰᣴᣦ᣹ᣫᣤᣫᣬᣦᣯᣯᣯ᣷ᣤᣫᣝ᣽ᣲᣤᣟ᣷ᣝᣰᣱ᣷ For info. RS#6
  15. 15. 12 ENERGY MATTERS A fine line separates propaganda from effective public relations. For the last several years, EPA has adopted a markedly different tone in press releases and has employed a more sophisticated social media strat- egy. To ignore social media would be foolish in today’s tweet-obsessed cul- ture; however, EPA may have gone too far. The Government Accountability Office (GAO) concluded in a Decem- ber 14, 2015 decision that EPA “vi- olated publicity or propaganda and anti-lobbying provisions…with its use of certain social media platforms in as- sociation with its Waters of the United States (WOTUS) rulemaking…” At issue is EPA’s use of Thunder- clap, a “crowd-speaking platform” that allows a single message to be shared across multiple Facebook, Twitter and Tumblr accounts at the same time. When people join a Thunderclap, they authorize the app to post a canned message on their behalf to their so- cial accounts. Think of Thunderclap like a digital telephone tree. One per- son calls three friends who then each call three friends, who then each call three friends, and so on. Except with Thunderclap, social media replaces the old-fashioned telephone and the elec- tronic message goes out simultaneous- ly to thousands of people. The use of viral content sharing sites is becoming more common as adver- tisers, activists and companies aim to recreate the social buzz that comes nat- urally to funny cat memes. EPA created a “campaign” which stated “Clean wa- ter is important to me. I support EPA’s EPA’s Thunderclap: Propaganda or Publicity? BY ROBYNN ANDRACSEK, P.E., BURNS & MCDONNELL AND CONTRIBUTING EDITOR efforts to protect it for my health, my family, and my community.” When the campaign reached its goal of 500 supporters, Thunderclap promoted this message, reaching an estimated 1.8 million people. GAO describes covert propaganda as communications that fail to disclose the agency’s role as the source of infor- mation. The Thunder- clap message did not identify EPA as the au- thor to the multitudes of people who received the Thunderclap and that was EPA’s error. By using the first per- son (“I” and “me”) in the message, EPA “de- liberately disassociates itself as the writer, when the message was in fact written, and its posting so- licited, by EPA.” By contrast, GAO de- termined that EPA’s #CleanWaterRules and #DitchtheMyth Twitter campaigns were not propaganda or self-aggran- dizement since references were made to “our rule” and the EPA logo was in- cluded in associated graphics. Keeping to the theme of modern communications, EPA responded to the GAO decision in a strongly worded blog. In EPA’s perspective, Thunderclap was a General Services Administration (GSA) approved platform appropriate- ly used to catalyze the public engage- ment process. EPA asserts that they did not encourage the public to contact Congress or any state legislature about the Clean Water Rule. EPA insists they “won’t back down from our mission” and resents these “empty attacks.” Social media is a developing com- munication avenue that, by design, evolves quickly. President Obama’s administration is the first to imple- ment (and the first to need) an Office of Digital Strategy, but subsequent ad- ministrations will surely continue this department. The laws regulating pro- paganda were written for more traditional avenues of reaching an audience and are quickly becoming outdated. EPA’s own public outreach began to expand from dry press releases as early as summer 2011 when EPA issued a press re- lease entitled “Here’s what they’re say- ing about the cross-state air pollution rule.” Instead of news, the content was a series of quotes from activist groups such as the American Lung Associa- tion, Environmental Defense Fund and the Sierra Club. EPA followed this up with similar “press releases” about the Mercury and Air Toxics Standards rule, Clean Water Act Proposed rule and Motor Vehicle Emission and Fuel Standards. EPA is right that one of the most ef- fective ways to share information today is via the Internet and social media; however, federal law prohibits gov- ernmental agencies from engaging in propaganda. This cautionary tale pro- vides initial guidance for governmen- tal agencies on where the line is drawn between publicity and lobbying. “To ignore social media would be foolish in today’s tweet-obsessed culture; however, EPA may have gone too far.”
  16. 16. Hydrolox™ engineered polymer chainless traveling water screens provide you with longer lasting, cost- effective, and virtually maintenance-free performance. These 316(b) compliant, easy to install solutions are built to withstand extreme debris events and eliminate uneven wear and mistracking. Backed by expert project management and industry-leading warranties, Hydrolox™ intake screens address the needs of water- extracting facilities across all industries. ce. e ate es, er- Built to last. Designed to comply. Tough. Reliable. Guaranteed. To learn more visit, call 866.586.2825 or email For info. RS#7
  17. 17. 14 NUCLEAR REACTIONS investments need to be well thought out and planned. “We cannot risk creating a situation in which we want clean, reliable and affordable electricity, but we are not able to provide it because we failed to plan, invest and build when we could,” Roderick said. “New energy infrastruc- ture that will last for 50 years or more cannot be built overnight. We need careful, long-term planning of invest- ments and construc- tion.” Both plans have one major goal in mind: bring down the amount of emis- sions generated by power plants around the world. Where nu- clear fits into these plans is where ques- tions arise, though common sense would say nuclear power is one of the best zero-emission and reliable gener- ating sources to build. However, nei- ther plan gives any financial help to offset the high upfront costs to build a plant, nor do they supply answers to the issue of market prices not fairly compensating nuclear. Plant operators say the increase in installed renewables on the grid and low natural gas prices have led to artificially low electricity prices that do not cover the benefits of nuclear power, much less normal oper- ating costs. When those issues are re- solved, then we can see nuclear power’s true benefits. T wo plans were released in 2015 aimed at cutting emissions around the world. The plans have different requirements and meth- ods of reducing pollutants resulting from power generation, and they also have different impacts on the future development of nuclear power. While one may be a boon for nuclear new builds, the other may be a hindrance, according to some in the industry. President Obama and the U.S. En- vironmental Protection Agency in Au- gust revealed the Clean Power Plan, which seeks to cut carbon emissions 32 percent below 2005 levels by 2030, and allows states to create and imple- ment their own plans to cut carbon emissions. A federal appeals court in January denied a stay against the rule, which means states must move for- ward with compliance requirements and deadlines. However, several state lawsuits challenging the plan are still pending. Some say the plan does not boost the U.S. nuclear industry because it does not recognize the value of nuclear’s zero-carbon power generation. Accord- ing to the Nuclear Energy Institute, the rule also does not give credit for license extensions. The rule does say, however, that more premature shut downs of nu- clear plants are expected in the future, which would actually increase emis- sions if the lost capacity is replaced with natural gas. The final rule does not consider the five reactors currently under construction in the U.S. – Watts Bar 2 in Tennessee, Vogtle 3 & 4 in Georgia and Summer 2 & 3 in South Carolina – in the goal setting calcula- tion. When they are operational, they will count toward compliance. The second plan was reached at the COP21 climate change talks in Par- is, in which 196 countries agreed to reduce greenhouse gas emissions to a level that will limit the rise of the global average temperature to well be- low 2 degrees C (3.6 F) of pre-indus- trial levels by 2030. The reductions mean nations will have to lower their use of fossil-fueled generat- ing sources like coal, oil and gas, and rely more on low-car- bon emitters, such as renewables and nuclear. The agree- ment also calls for developed countries to fund $100 billion a year to developing countries starting in 2020 that is ex- pected to increase over time. Every five years, the nations will be required to assess and report on their progress. Westinghouse said in a release that it believed the COP21 agreement would be the shot in the arm that the nuclear industry needs. “The message from COP21 is clear: it’s time to redirect investment and fi- nancing from carbon-intensive fossil fuels to building a new generation of nuclear power plants for security of fu- ture energy supply,” said Westinghouse President and CEO Danny Roderick. Roderick pointed out that these COP21 vs. Clean Power Plan: Which Benefits Nuclear More? BY SHARRYN DOTSON, EDITOR New energy infrastructure that will last for 50 years or more cannot be built overnight.We need careful, long- term planning... - Westinghouse President & CEO Danny Roderick
  18. 18. For info. RS#8
  19. 19. 16 ONSITE POWER BY ANNE HAMPSON Packaged CHP systems are pre-engineered and assembled at the factory for optimal operation, and they can be placed into service at a host facility in a short amount of time because they require little on-site as- sembly. Photo courtesy: ICF International emerged that are shifting the economics and value proposition for CHP in the US. This is already leading to increasing levels of CHP deployment, and a shift in its achievable potential ahead. So how big is this potential, and what does it look like? Determining the true market for CHP can be a challenge. It requires estimates of the technical, eco- nomic, and likely achievable potential for additional CHP installations—no small task in some areas, and with many variables to consider. The current state of the market and starting point for any analysis can be seen in the U.S. Department of Energy CHP Installa- tion Database (managed by ICF, and available at: https://doe.icfwebservices. com/chpdb/), which tracks CHP instal- lations throughout the country, provid- ing data on market trends and growth. Traditionally, large industrial facilities have been the primary CHP adopters, accounting for 86 percent of currently installed capacity (71GW). Commer- cial and institutional facilities make up the remaining 14 percent (about 12 GW). However, a shift may be coming. Looking forward at the re- maining technical potential for CHP, we see a much different split, with in- dustrial facilities accounting for about 45 percent and commercial/institution- al facilities accounting for 55%. This means that the future is smaller: the av- erage system size of the remaining CHP potential is significantly lower than the average size of currently installed systems. The total of this technical potential in the United States ranges in estimates between 110 – 160 GW for systems that use all of their energy out- put onsite. However, even beyond that impressive figure, for some facilities that use more thermal energy (typically in the form of steam compared to elec- tricity) a CHP system can be sized to allow export of excess electricity to the T here’s a hot new technol- ogy in energy. It’s driv- en by rapidly improving economics, better prod- uct offerings that are far easier to use, and innovative new business models that can bring turn- key solutions right to customers. It has the potential to provide a quarter of our power generation. It’s been making waves in the market, and signs point to more vigorous growth ahead. Except this technology is not new. And it’s not what you’re thinking. Combined heat and power (CHP) gets fewer headlines and has a lot less sizzle than some other distributed en- ergy technologies, but when you break down the numbers, it delivers. The basic concept goes all the way back to Thomas Edison, who employed it himself in his first commercial power station. Over the ensuing years, CHP has made serious inroads into our na- tion’s power and heat supply, providing electricity and thermal energy for over 4,400 commercial and industrial facili- ties around the country. In fact, there is currently over 82 GW of CHP capacity installed in the US, accounting for 12 percent of electricity production and 8 percent of power generation capacity. And while this is a lot more than most people realize, it’s not anywhere near the technology’s full potential. In fact, a variety of game-changing factors have Analyzing the Potential of CHP in North America
  20. 20. The Potential for Additional CHP is Nationwide CHP Technical Potential (MW) 1,000–3,000 MW >5,000 MW <1,000 MW 3,000–5,000 MW Author Anne Hampson is senior manager at ICF International. The spark spread is a metric used to evaluate the cost effectiveness of a CHP system based on the difference between fuel and electricity prices. The larg- er the spread, the more cost savings a CHP system will provide. California and the Northeastern states have tra- ditionally been the primary targets for CHP due to their high electricity prices and moderate fuel prices. As natural gas prices have decreased and electric- ity prices have either remained stable or continued to increase, more regions of the country are showing favorable spark spreads for CHP. The Midwest in particular is a region where high levels of technical potential are meeting in- creasingly favorable economics, which is leading to more projects under devel- opment. Packaged CHP Systems As with any asset investment, one of the primary barriers to CHP develop- ment has been the high upfront capi- tal cost of the system, especially when considering that they are installed at facilities whose core business is some- thing other than power generation. Traditionally, CHP systems have been local utility. When accounting for this excess electrical capacity, the potential for CHP could increase by another 75 – 125 GW. In sum then, there is a very substantial 185 – 285 GW of deploy- able CHP in a country that has just over 1,000 GW of current electric generating capacity. These estimates will be further refined in an upcoming study to be re- leased by the U.S. Department of Ener- gy on the current amount of technical potential for CHP in the United States on a state-by-state basis. Furthermore, unlike other clean ener- gy technologies that are confined by the availabilityoftheresourceitself(i.e.hours of sunlight, or presence of wind), CHP can use any combustible fuel. Therefore, the technical potential for CHP is con- strained only by the amount of energy consuming facilities that can use both its electric and thermal outputs. Of course, estimating the technical potential for additional CHP is only the first step in analyzing the CHP market, as it provides the universe for what is capable of being served by the technol- ogy. It’s an estimation of market size constrained only by technological lim- its—the ability of CHP technologies to meet existing customer energy needs. The technical potential does not consid- er other factors such as economics, abil- ity to retrofit, owner interest in applying CHP, capital availability, and variation of energy consumption within custom- er application/size classes. All of these factors affect the feasibility, cost and ultimate acceptance of CHP at a site, which are evaluated in the later stages of economic and likely achievable poten- tial analysis. But when we look at those areas, we see the scales tipping quickly and significantly in CHP’s favor. ECONOMIC GAME-CHANGERS The evaluation of economic poten- tial for CHP is not as straightforward as the technical potential. The outcomes depend a lot on the assumptions that are used in its calculation (which can also vary significantly from region to region). Economic potential is also hard to char- acterize because the term “economic” means different things to different peo- ple. Some companies would not consider a CHP system to be economic unless it had a payback period of less than 2 years, whereas other companies would consider a system to be economic at a 5-7 year pay- back — which, when considered against other energy technologies, is very compa- rable and quite competitive. All of the economic trends are point- ing in the right direction for robust growth in CHP’s economic potential and actual deployment: systems are be- coming more affordable due to low nat- ural gas prices, new packaging options, innovative business models, and the potential for additional revenue streams for their environmental attributes and/ or electric system benefits. Natural Gas Prices Natural gas, the preferred fuel for CHP, has been selling at record low prices, which is creating favorable spark spreads in many regions of the country.
  21. 21. 18 ONSITE POWER from distributed CHP installations – not only from reduced congestion on transmission and distribution lines, but from demand response and ancillary services such as voltage and frequency regulation. These services can poten- tially be monetized and utilized as a source of revenue for CHP customers, with regional transmission organiza- tions like PJM offering market-based compensation for customer-generators that can provide demand response and ancillary services for the system. States like New York and California are work- ing hard on developing distribution level markets for such services. These markets are still a work in progress, however, they show strong promise to provide additional revenue streams to CHP systems, further enhancing project economics. EXPECTED ACHIEVABLE POTENTIAL The expected achievable potential for CHP is the final step to creating a forecast of how much CHP will be de- ployed. After the economic potential is calculated (shown by grouping the technical potential capacity into rang- es based on their expected payback) the results are multiplied by typical customer acceptance factors to esti- mate the amount of CHP capacity that would actually be installed. Customer acceptance of a clean energy technol- ogy can be highly variable and takes into account the fact that even at very low paybacks (and high rates of re- turn), some customers would still not move forward with an installation. In a recent analysis for the Pew Charita- ble Trusts, ICF concluded that 18 GW of CHP could be expected to enter the market by 2030, based on current eco- nomic conditions. As the economics for CHP continue to improve and cus- tomers become more comfortable with new business models, the potential re- mains for deployment at an even great- er level. custom-engineered for each installa- tion, a process that involves ordering all the components separately and then assembling it onsite. This process can be slow and expensive, and has been described by Dana Levy at the New York State Energy Research and Devel- opment Authority (NYSERDA) as akin to purchasing all the parts at an auto supply store and going home to assem- ble your car. Packaged systems are dramatically changing that story for smaller CHP sys- tems. Most CHP technologies are fairly mature, so rather than seeing reductions in cost coming from the prime mover technology itself, they are coming from innovative ways of packaging the tech- nology with the heat recovery system, generator, and controls all in one package so that the unit can be installed at a lower cost. These packaged systems are pre-en- gineered and assembled at the factory for optimaloperation,andtheycanbeplaced into service at a host facility in a short amount of time because they require little on-site assembly. Packaged units can also be stacked together to make larger capac- ity systems which increase the operation- al flexibility and reliability of the overall system. These attributes, coupled with standardized controls and monitoring software are making pre-packaged CHP systems less expensive to install, operate and maintain. While there are many US companies pursing the packaged CHP market, there has been a notable increase in European companies that are entering the US mar- ket and utilizing their experience from Europe, where small packaged CHP sys- tems are a much more common practice. Packaged system developers are also tak- ing advantage of the replicability of these systems to attract hotel, supermarket, and assisted living community chains that can deploy a portfolio of systems at mul- tiple facilities. Innovative Business Models As distributed generation systems like CHP have received higher levels of recognition, many developers have started offering leased system options or “build, own, and operate” business models for their customers. With these offerings, the developer pays for all of the up-front costs of a CHP installation, and the customer only pays for the de- livered energy, typically at a guaranteed discount compared to local utility costs. Think of it as SolarCity for CHP. The de- veloper owns and operates the CHP sys- tem, providing remote monitoring and all system maintenance at no additional cost to the customer. While this busi- ness model has been around for a while it has become more prominent given its relative recent success in the solar pho- tovoltaic market. Innovative business models can make CHP systems a much more attractive proposition for small to medium-sized businesses that are hesi- tant to commit to a large capital invest- ment or to what can be a complicated process of working out the technical is- sues for their site. The transfer of own- ership and operational risk from the end-user to the developer is also bring- ing in customers that would not other- wise consider generating on-site power. Additional Revenue Streams CHP systems reduce greenhouse gas emissions by producing power and heat more efficiently than central utility sys- tems that may still rely on coal for power generation. The avoided consumption of utility electricity from CHP custom- ers can add up to significant amounts of prevented emissions over time. While markets for greenhouse gas emissions have been slow to develop in the U.S., they could potentially provide a valu- able source of revenue for customers with CHP systems. And now, as states are confronted with designing pro- grams to bring them into compliance with EPA’s Clean Power Plan, CHP, like many other clean energy technologies, may be able to sell its positive environ- mental attributes, delivering additional value to system owners. Additionally, utilities can benefit
  22. 22. 19 Boilers – Critical Process ComponentBY SCOTT LYNCH, PRESIDENT AND CEO, ABMA major injuries. This risk far outweighs the cost of proper maintenance as down time can cost companies millions in lost productivity. UPGRADING A BOILER In many cases, the boiler shell will outlast many of the component parts. With technological advances and ever changing environmental regulations, it is important to explore boiler upgrades on a regular basis. There are times when an upgrade can pay for itself in just a few years, maybe even months with energy and fuel savings. There is also an op- portunity to explore additional upgrades whengoingthroughacompliancereview. PURCHASING A NEW BOILER Whetheraboilerneedstobepurchased to replace on old unit or expansion is on the horizon, there are great opportunities to purchase the ideal boiler system for an end-user’s needs. An end-user may know best what it needs from a boiler, but a boiler manu- facturer understands today’s technol- ogy and how to create a boiler that offers the best value while addressing unique challenges. Collaboration is important early in the process to ensure high perfor- mance and cost-effective decision. Large boilers for industrial, commer- cial and institutional use are not widgets, they are highly engineered, extremely customized complex systems. The design and build process does not take days, it takes months and boiler manufacturers investment significant time and resourc- es to create each system. Purchasing the proper boiler and instituting a textbook maintenance schedule, will enable this investment to serve the needs of an end- user for decades to come. ABMA and its members cannot change perceptions overnight and we don’t plan to create Super Bowl commercials any- time soon. Our goal is to move the needle and personalize our message to the needs of various audiences, and we are confi- dent that this educational campaign will lead to a more successful industry and ad- vance the safety of our products. As an association, ABMA is partner- ing with marketing firm Larnish Larsen to create awareness and highlight the critical nature of the boiler industry and ensure that there is an understanding of why boilers are so important, what is needed to properly maintain a boiler and how investing in a boiler room can offer many benefits and potential long-term cost savings to an end-user. T hink about a hospital that isn’t able to sterilize its medical equipment, the college campus with no hot water for their thou- sands of students or the food processing plant that cannot make steam and pro- duction comes to halt. These are all re- alities without fully operational boilers. In many cases, the boiler is thought of as that room in the basement that does what we need it to do. But our industry knows that there is much more to this story and ABMA has decided it is time to focus our efforts on moving percep- tions toward reality. So why is the boiler room “that room in the basement”? In many cases, the boiler room is not seen as a critical com- ponent of the business. A hospital is wor- ried about saving lives, a college campus is investing in educating future leaders, and a food processing facility is focused on its product development. MAINTAINING A BOILER I hear all the time that lack of regular maintenance is a top reason for the break down and replacement of boilers. With proper care and maintenance, a boiler can run efficiently for years and years. But in many cases, the dollars to properly maintain a boiler room are not allocated and operators are not properly trained. Over time, the boiler goes into disrepair or in the worst cases, explodes, costing companies significantly more dollars and ABM A SpecialSection Scott Lynch
  23. 23. 20 ABM A SpecialSection industry commentary, utilities now have the regulatory clarity necessary for compliance strategy development, technology selection, budgeting, per- mitting, scheduling and ultimately project implementation. As a result, numerous utilities are now moving forward with project planning and ex- ecution in accordance with the compli- ance requirements and deadlines. Proj- ect activity presently includes existing CCR impoundment stabilization, dry landfill expansion/construction, W ith the final is- sue of the Envi- ronmental Pro- tection Agency (EPA) Coal Combustion Residual (CCR) rules on April 17, 2015 and the Steam Electric Power Effluent Limitations Guidelines (ELG) on Nov. 3, 2015, utilities now have defined compliance requirements for post-combustion solid waste man- agement, groundwater and surface wa- ter and wastewater management. After nearly five years of data collec- tion, technology and cost evaluations, draft rulemaking, public comment and Dry Ash Conversions Implications, Options and Technical Considerations for CCR & ELG Compliance BY KEVIN L. MCDONOUGH
  24. 24. groundwater monitoring, fly ash and/ or bottom ash wet-to-dry conversions, gypsum dewatering, wastewater treat- ment and overall plant water balance management. This activity is expected to continue in earnest for the immedi- ate three to five years and largely con- clude in 2023 at the close of the ELG compliance window. The CCR rules target benefits such as ground water protection and the prevention of CCR impoundment catastrophic failures. As opposed to the initial draft rule, which was more focused on the closure of surface im- poundments, the final rule was issued with a more defined set of criteria by which coal unit operators could contin- ue to utilize surface impoundments as an alternative to complete wet-to-dry conversions. Its focus is based on the following implementation timeframes from the publication of the rule: a) lo- cation restrictions (aquifer, wetlands, fault zones, seismic zones and unstable areas): 42 months; b) design criteria (lined/unlined, leaking/not leaking, structural integrity): 18 months; c) op- erating criteria (flood control, fugitive dust control, inspections): six to 18 months; d) groundwater monitoring and corrective action: 30 months; e) closure requirements and post-closure care: 36 to 162 months; and f) record- keeping, notification and internet posting: 6 months. The ELG rule seeks to strengthen the controls on discharges from steam electric power plants by revising tech- nology-based effluent limitations guidelines and standards for the steam electric power generation industry. It also seeks to reduce the amount of potentially harmful metals and other pollutants discharged to surface wa- ter (direct discharges) and publicly owned treatment works (indirect dis- charges to POTWs). Targeted waste- water streams include Flue Gas Desul- furization (FGD) Wastewater, Fly Ash and Bottom Ash Wastewater, Flue Gas Mercury Control (FGMC) Wastewater, Combustion Residual Leachate from Landfills and Surface Impoundments, Nonchemical Metal Cleaning Wastes and Coal and Pet Coke Gasification Wastewater. According to the EPA, Best Available Technology (BAT) compli- ance technologies include chemical precipitation, biological treatment, evaporation, dry handling and prop- erly designed surface impoundments for the differing waste streams. For fly ash and bottom ash, however, the technology basis for compliance is dry handling or closed-loop zero liquid discharge (ZLD) systems for all units >50MW, with the exception that fly ash and bottom ash transport waters can be used as a source of FGD process wa- ter. For generating units <50MW, the ash systems must meet Best Practicable Technology (BPT) requirements that include Total Suspended Solid and Oil/ Grease limitations in the ash effluent wastewater streams. The rule mandates This Continuous Dewatering and Recirculation (CDR™) from United Conveyor Corp was recently commissioned at a plant in the Southeast region of the US. The technology combines the benefits of a recirculation system and the proven technology of a submerged flight conveyor.Photo courtesy: United Conveyor. Author Kevin L. McDonough is Vice President of Sales & Marketing for United Conveyor
  25. 25. Our boiler manufacturing experience and passion for customer service has made a significant difference to our customers, who include the largest independent power producers, refining, petrochemical, and industrial companies in North America. At RENTECH, we aren’t resting on our reputation – we are continually building one! MARKET LEADER IN LARGE FIRED PACKAGED BOILERS Over the past four years, we have supplied more large fired packaged boilers than any other manufacturer in the North American market for units > 100,000 lb/hr in size. Our Packaged Boiler design has been specified time and again for critical industrial processes, turbine warm-up and auxiliary boiler applications because of its rugged design and proven reliability. 100% Membrane Wall construction eliminates the need for refractory and enables quick start-up to achieve full steam capacity of the boiler in a fraction of the time that it takes with older designs. In addition to significantly reducing maintenance and operating costs, a water-cooled membrane wall furnace offers further benefits in reducing emissions. INTEGRATED SOLUTIONS FOR ACHIEVING LOWER EMISSIONS Our approach to achieving lower emissions starts with optimization of the boiler design. Coupled with RENTECH’s knowledge of low emissions burner and catalytic reduction technologies, we are capable of supplying a system that fully complies with all performance criteria and is backed by a single-source guarantee. HRSGS FOR SMALL- AND MEDIUM-SIZED GAS TURBINES We specialize in, and are the largest supplier of, HRSGs for today’s high-efficiency gas turbines that operate in the 3-40 MW size range. Our expertise in high- fired applications incorporates full optimization of the duct-burner performance while utilizing Catalytic Oxidation and SCR for control of emissions from the entire system. RENTECH BOILER SYSTEMS CONTINUES TO LEAD THE INDUSTRY IN PRODUCING NEW, INNOVATIVE BOILER DESIGNS. Design Features: 100% headered membrane water wall construction No refractory walls or seals Fully drainable Convective Super-heater that eliminates the problems associated with radiant designs Customized designs for applications requiring lowest emissions Standard 5-year warranty on front and rear furnace walls Turnkey Capabilities: Integrated Low NOx Burner and SCR/CO catalyst systems guaranteed to achieve less than 5 ppmvd Installation and start-up services Comprehensive engineering and design evaluation of other boiler systems Rebuilds, upgrades and major modifications of existing boilers FIRED BOILERS HRSGs WASTEHEAT BOILERS SCR AND CO SYSTEMS INDUSTRIAL WATERTUBE BOILERS WASTE HEAT BOILERS SCR SYSTEMS For info. RS#9
  26. 26. HARNESS THE POWER OF ADVANCED HRSG TECHNOLOGY The industry leader in Heat Recovery Steam Generators for gas turbines up to 30 MW, RENTECH offers a full range of HRSG systems to meet your toughest project requirements. We custom engineer our crossflow two-drum and waterwall designs to perform superbly in the most demanding applications and operating conditions. We master every detail to deliver elemental power for clients worldwide. HARNESS THE POWER WITH RENTECH. HEAT RECOVERY STEAM GENERATORS WASTE HEAT BOILERS FIRED PACKAGED WATERTUBE BOILERS SPECIALTY BOILERS WWW.RENTECHBOILERS.COM
  27. 27. 24 ABM A SpecialSection handling systems, along with the de- commissioning of existing wet back-up systems. Utility operators may elect to install additional redundancy for pri- mary dry systems that currently utilize wet back-up systems. In contrast to fly ash, many installa- tions presently utilize wet sluicing sys- tems to transport bottom ash from the operating units to surface impound- ments. Due to the traditional coal unit boiler and associated bottom ash hop- per designs, wet-to-dry conversions pose numerous unique design consid- erations, such as boiler operating seal requirements, spatial limitations both under the boiler and beyond the walls of the powerhouse, water balance re- quirements, as well as unit outage con- siderations. Although the technical and eco- nomic criteria is unique to a given plant, consideration must be given to flexibility to account for typical plant operating conditions and maintenance activities. Specifically, the ELG notes that “transport water does not include low volume, short duration discharges of wastewater from minor leaks (e.g. leaks from valve packing, pipe flang- es, or piping) or minor maintenance events (e.g., replacement of valves or pipe sections).” The overwhelming majority of util- ity installations currently utilize dry handling systems for fly ash (>85%). These positive and negative pressure pneumatic systems in various dilute and dense phase conveying regimes, have been proven to be highly reliable systems if properly designed, operat- ed and maintained consistent with fuel/ash characteristics and plant op- erating conditions. The new ELG re- quirements will likely result in dry ash conversions for any remaining wet a compliance timeframe that is “as soon as possible beginning November 1, 2018, but no later than December 31, 2023”. Under the implementation ap- proach, each state (permitting author- ity) shall confirm the required compli- ance date within the defined window with particular consideration for ex- isting National Pollutant Discharge Elimination System (NPDES) permit validity dates and sufficient timelines for implementation. The combination of the CCR and ELG requirements will likely drive dozens of wet-to-dry con- versions, pond closures, along with dry landfill and wastewater treatment projects. In fact, numerous projects are currently underway. While the ELG does mandate ZLD requirements for both Fly Ash and Bot- tom Ash transport water, it is worth noting that the EPA has attempt- ed to incorporate some operational This Continuous Dewatering and Recirculation (CDR™) system from United Conveyor Corpora- tion is installed at a plant in South Carolina. The technology was the preferred wet-to-dry conver- sion option due to physical limitations underneath the boiler. Photo courtesy:United Conveyor.
  28. 28. Available Technologies (BAT) noted in the ELG, UCC has implemented vari- ous technologies throughout the U.S. utility coal fleet, which are summa- rized below. UNDER BOILER SUBMERGED FLIGHT CONVEYOR (SFC) SYSTEM System Overview: The SFC collects bottom ash from the boiler into a water-filled trough where it quenches and cools the ash. Horizontal flights move the ash con- tinuously through the trough and up a dewatering ramp where it is then discharged into a load-out bunker or secondary transfer conveyor. Bottom ash is typically allowed to dewater in the bunker to 15 percent or 20 percent moisture, which is ideal for fugitive dust emission control and landfill com- paction. In addition, the SFC produces a dewatered product with a consistent particle size distribution suitable for beneficial reuse. Overflow water from the SFC trough is commonly captured, cooled and recirculated to complete a zero liquid discharge system, although the final ELG allows some flexibility for the management of cooling water overflows. The under boiler SFC has been the industry standard on new units for the past few decades. In ad- dition, numerous utilities have suc- cessfully retrofitted SFCs on existing units. The SFC is a proven bottom ash system and a cost-effective solution when long-term life cycle costs are a major decision factor and when ex- isting bottom ash hoppers may be in need of repair. Feedback from existing reference installations has indicated that maintenance costs for an SFC Sys- tem are only 1/3 that of a conventional water-impounded bottom ash hopper and sluice conveying system. System Design Considerations: The key variables that determine viability for an SFC retrofit include available physical space and planned and distance, ash marketability/bene- ficiation, unburned carbon concerns, ash characteristics, physical param- eters, multiple unit synergies, plant water balance and maintenance re- quirements. Due to the extent and complexity of the project variables, it is also critical to select a technology provider with sufficient experience, proven reference installations and ex- ecution capacity to meet the needs of the plant within a defined timeframe. Relative to the survey of Best a multitude of variables in order to de- termine the optimal solution for com- pliance. Accordingly, a single technical solution does not necessarily translate to all bottom ash applications (i.e. “one size does not fit all”). Therefore, select- ing the most appropriate technical al- ternative requires careful evaluation of a combination of factors including: schedule requirements, site impacts, spatial constraints, budget, outage re- quirements, site environmental con- siderations, ash conveying capacities The patented 100% Dry Pneumatic Ash Extractor (PAX™) from United Conveyor is installed at a plant in the Eastern US,as they preferred a conversion solution that removed water as a conveying medium. Photo courtesy:United Conveyor.
  29. 29. ABMA Special Section For info. RS#10 enhancements, including improved dewatering elements, valves and op- erational sequencing, have addressed many of the performance concerns. If designed, operated and maintained properly, this technology still rep- resents a viable wet-to-dry conversion solution, and particularly if a plant currently has existing dewatering bins installed as a means of coarse particu- late separation with overflows directed to an operating surface impoundment. In this scenario, the system can be ret- rofitted to a closed-loop system with the addition of settling and surge tanks and associated return water pumps, valves and piping. Several units have recently been converted using this approach and are in compliance with the ELG zero liquid discharge require- ments. System Design Considerations: Due to the scope of the system – in- cluding multiple tanks, overflow pip- ing, underflow piping, valves, pumps, etc. – system controls and associated operation can be complex. Redundan- cies must also be balanced with added complexity. In addition, these systems can retain ash in solution for extend- ed periods of time, often numerous days and even longer in certain cir- cumstances. In these cases, additional consideration has to be given for the water quality/chemistry in a closed- loop system, particularly relative to the zero liquid discharge requirements outage schedules. Many existing boil- ers do not possess the physical space to accommodate an SFC retrofit due to limited headroom between the boil- er throat and grade, deep bottom ash hopper pits, structural steel interfer- ences, equipment/ductwork interfer- ences around the bottom ash hopper or limited space outside the powerhouse wall for storage, truck traffic or ash transfer. In addition, this retrofit will require removal of the existing bottom ash hopper and associated equipment. As such, the retrofit typically requires a 6-8 week outage for successful proj- ect execution. If the SFC cooling water overflows are captured in a closed-loop system, the system must be designed to ensure that the water temperatures are maintained at appropriate levels, often requiring some form of heat exchanger in the hydraulic system. DEWATERING BIN SYSTEM System Overview: Conventional dewatering bin sys- tems, often with associated settling and surge tanks, have been implement- ed throughout the U.S fleet since the 1960s and represent the traditional approach to bottom ash closed-loop design. Dozens of these systems are currently in operation, although performance issues related to main- tainability and operability have been noted for these prior generation de- watering solutions. Recent design This under-the-boiler Submerged Flight Conveyor (SFC™) by United Conveyor is installed at a plant in Midwest. Numerous utilities have successfully implemented the SFC technology which has been the industry standard on new units for the past few decades.Photo courtesy: United Conveyor.
  30. 30. For info. RS#11 Fuel Oil Pump Sets Pressurized Deaerators ï Diesel Supply to Emergency Generators ï Oil Supply to Boilers for Primary or Backup Fuel Supply Fuel Oil Pump Sets surized erators Pump Sets cy Generatorsï Diesel Supply to Emergenc ï Oil Supply to Boilers for Primary or Backup Fuel Supply INDUSTRIALSTEAM.COM 1403 SW 7th Street, Atlantic, Iowa 50022 (712) 243-5300 INDUSTRIAL Mission Critical Fuel Oil Systems FUEL SYSTEMS, LLC erators Tray-Type .005 cc/l performance Counter-flow design Stainless steel internals Steam Flow (Recycling) .005 cc/l GUARANTEED under ALL CONDITIONS Pressurized Recycling Design Stainless steel internals Spray Type .005 cc/l performance Stainless steel internals Schaub Engineering (Atmospheric) Direct replacements for all Schaub designs Oi Pres Deaeae TT .0 C S S ( .0 u P S S .0 S S E ( D ff of ELG. Plants must determine and specify their desired approach for wa- ter sampling and analysis for ongoing water quality management, which can be accomplished via additional system instrumentation and continuous mon- itoring or intermittent sampling and analysis. To manage unanticipated excursions in water quality, the system can also be designed with blowdown provisions; in particular, bottom ash sluice water can be used as a FGD sys- tem makeup water source or as a dry fly ash conditioning water source. CONTINUOUS DEWATERING AND RECIRCULATION (CDR) SYSTEM System Overview: The Continuous Dewatering and Re- circulation (CDR) system with Remote Submerged Flight Conveyors (R-SFC) is a preferred wet-to-dry conversion option for installations that have phys- ical limitations underneath the boilers and seek to minimize costly outage-re- lated activity, while also realizing the benefits of the SFC, which produces a highly consistent dewatered bottom ash product. The CDR system is designed to re- ceive existing sluice conveying lines and divert the bottom ash slurry to a remote dewatering conveyor located outside of the powerhouse. Materi- al is collected, dewatered and then discharged into a load-out bunker or secondary transfer conveyor to a con- dition that is favorable for transport to and compaction in a dry landfill. In addition, the CDR system can be read- ily designed to ensure that beneficial reuse products can be separated. After completing a fine particulate settling phase, the sluice water is then pumped back to the boiler house to complete a closed-loop, zero-liquid discharge system. The CDR system has been designed to address the com- plexities of a bottom ash water balance, considering multiple flow sources, in- termittent conveying cycles and vari- able flow rates. The conversion option is highly favorable when considering physical space limitations underneath the boiler and maintaining plant avail- ability, as this can be implemented with little to no outage requirements if commissioning is planned and execut- ed properly. System Design Considerations: For CDR systems, R-SFC location, conveying distance and hydraulic profile are key variables in the proper design of the closed-loop system. Ac- cordingly, pump selection, sizing and quantity are key factors in the system design. Experience is essential to prop- erly select pumps that balance the flow and pressure requirements with the an- ticipated water quality. As with the dewatering bin system, additional consideration has to be given for the water quality/chemistry in a closed-loop system, particularly relative to the zero liquid discharge requirements of ELG. Plants will need to monitor water quality in the closed- loop system. Should an installation have a par- ticle size distribution that has an in- creased concentration of fines in the bottom ash water recirculation system (e.g. finer bottom ash, economizer ash, etc.), the CDR system can also be scaled to provide for additional settling area, additional mechanical particu- late separation and/or polymer addi- tion to reduce TSS concentrations in the recirculating water. CDR SYSTEM WITH CLARIFIER System Overview: The CDR System with clarifier matches the system described above, but with an additional clarification phase that reduces the Total Suspended Solids (TSS) concentration in the bot- tom ash transport water. The addition- al clarification phase is provided by
  31. 31. ABM A SpecialSection 28 most appropriate relative to key vari- ables including existing system oper- ation, fly ash and bottom ash benefi- cial reuse and cost. In any case, econ- omizer ash can be incorporated into the dry fly ash or dry bottom ash sys- tems with proper consideration for generation rates, particle size distribution and unique material characteristics. MILL REJECTS (PYRITES) IMPLICATIONS The CCR and ELG rules made no new distinctions for mill rejects, as these are not included in the definition of coal combustion residuals.. The majority of existing Mill Reject (Pyrites) removal systems currently use sluice conveying systems for removal and most are con- nected in some manner to the existing bottom ash sluice conveying systems and discharged to surface impoundments. In any case, the Mill Reject systems can be readily tied into SFC, CDR or Dewatering Bin Systems or can be segregated via inde- pendent systems to allow for bottom ash separation and beneficial reuse. CONCLUSION While the final Coal Combustion Residual and Effluent Limitations Guidelines present challenging regu- latory requirements for new and exist- ing coal unit installations, numerous options are available to achieve com- pliance, and in many cases improve system operations with newer technol- ogies. A careful evaluation of multiple alternatives, with consideration for each unique set of plant operating and design criteria can result in an optimal selection of a safe, reliable and cost-ef- fective compliance solution for fly and bottom ash handling. means of a thickener/clarifier located downstream of the remote submerged flight conveyor (R-SFC) with polymer addition. This technology selection is suitable for installations that anticipate a higher concentration of fines in the ash particulate or require lower TSS levels suitable for certain types of recir- culation pumps. System Design Considerations: If the plant desires to keep exist- ing high pressure “clean water” slurry pumps in operation, the CDR System with clarifier is highly effective in pro- ducing water quality (TSS) suitable for these types of pumps. In addition, this system, while likely higher in both capital and operating cost, will provide greater control in water quality should the bottom ash sluice water be needed as a source for FGD makeup or dry fly ash conditioning water. PNEUMATIC ASH EXTRACTOR (PAX) SYSTEM System Overview: The patented UCC PAX Pneumatic Ash Extractor is a preferred wet-to-dry conversion alternative when a plant desires to convert from the traditional water-impounded hopper design and eliminate water usage for the bottom ash systems. As a 100% dry solution, the PAX system is particularly ideal for in- stallations that have physical limitations under the boiler. For this technical alter- native, bottom ash is collected dry in a refractory-lined hopper under the boiler. Percolating air cools the ash to help com- plete combustion of unburned material and protection of ancillary equipment. As the ash cools, it is crushed then fed into a pneumatic vacuum conveying line and transported to a storage silo or trans- fer station for dry bottom ash unloading. System Design Considerations: One of the important design features of the PAX system is the design of the dry, refractory-lined hopper. Simi- lar to traditional systems, this multi-V hopper provides for system redundancy and operational flexibility during upset conditions. The system can also be designed with ad- ditional boiler iso- lation features that provide improved reliability. For PAX sys- tems, vacuum con- veying distance and Dry Bottom Ash Silo location are key variables in the proper design of the conveying system. In addition, ash characteristics (specific gravity, density, chemical constituents, etc.) and generation rates are also of es- sential importance in system sizing and equipment selection. Several utility clients have recently se- lected PAX as their preferred bottom ash compliance technology and several oth- ers are actively investigating its potential application. Utility feedback indicates that the condition of the existing bottom ash hoppers, long-term life cycle cost analysis and environmental risk analysis are key factors in the PAX system evalua- tion. Based on favorable field data from operating references on O&M costs, the PAX option may be ideal if existing bot- tom ash hoppers need to be significant- ly repaired/replaced and/or an owner wants to remove bottom ash sluice water from their environmental risk profile to address current ELG requirement and longer term regulatory exposure. ECONOMIZER ASH IMPLICATIONS The new rules made no new distinc- tion for economizer ash. As presently defined, economizer ash is considered fly ash when “it is collected with the fly ash systems” and bottom ash when “it is collected with the bottom ash sys- tems.” With this apparent regulatory flexibility, plants will have the option to manage economizer ash as is deemed “Economizer ash can be incorporated into the dry fly ash or dry bottom ash systems with proper consideration for generation rates, particle size distribution and unique material characteristics.”
  33. 33. 30 ABM A SpecialSection How to Deal with Ceaseless Slagging BY RUSSELL RAY, CHIEF EDITOR I t’s no secret that excessive boiler deposits can lead to serious reli- ability and performance issues for power plants. Regular boiler maintenance that includes thor- ough boiler cleaning will lead to lower operating costs, reduced fuel con- sumption, greater effi- ciency, and a longer lifespan of the boiler. Over time, the burning of coal, bio- mass and other solid fuels creates molten ash. The ash accumulates to create a stony ABM A SpecialSection
  34. 34. compressed air. But these soot blower sys- tems are powerful and can cause erosion if they are used on a slag-free section of tubing. Power producers have been using soot blowers to clear their boilers of slag for decades. But modern-day soot blowing systems are more sophisticated than tra- ditional systems. The goal is to provide just enough pressure to clean the tube and avoid causing damage. Intelligent soot blowing systems func- tion only when the furnace walls and boiler tubes need to be cleaned. This technology prevents boiler tube erosion caused by unnecessary soot blowing. Traditional systems operate on a specif- ic sequence and are blind to the actual conditions inside the boiler. Blowing high-pressure steam on a bare tube can damage the tube. On the flip side, some areas of the boiler accumulate slag more quickly and require more frequent clean- ing. Without an intelligent system, slag can accumulate to excessive levels and severely restrict heat transfer. This could lead to unplanned downtime. But soot blowing systems only temper slag deposits. More effective methods for slag removal are typically used during the next planned outage. WATER LANCES Ajetofhigh-pressurewaterisonemeth- od used to break down the buildup of slag during a planned outage. The use of hydro-blasting systems equipped with pumps capable of sending up to 1,200 gallons per minute through their hoses can strip away the toughest slag deposits. The problem with using high-pressure water lances is the risk of introducing moisture into the boiler. Water lances cover about a 20-foot generation and equipment maintenance. According to the Electric Power Research Institute, slagging and problems associat- ed with excessive slagging cost coal-fired power plants more than $2 billion a year. The cofiring of other fuels with coal, es- pecially biomass, has created big slagging problems for power plant boilers not de- signed to handle ash from these alterna- tivefuels.Muchthoughtneedstobegiven to selecting a biofuel and the appropriate replacement levels for cocombustion. But the industry has demonstrated that these problems can be overcome. Boiler service companies say routine slag removal can boost boiler efficiency by as much as 4 percent, in addition to extending the life of the boiler. The tools used to combat the buildup of boiler slag at power plants are wide rang- ing. Common tools include soot blowers, soundwaves,hydroblasters,CO2 blasters, jackhammers, picks, and carefully-aimed shotguns. In some severe cases, power plant operators will turn to dynamite to deal with ceaseless slagging. SOOT BLOWERS To clean a boiler while it’s online and producing power, most power plants use soot blowers driven by steam or buildup on the furnace walls of the boiler known as slag. Slag may also fuse to the fire side of the boiler tube, preventing suf- ficient heat transfer. A reduction in heat transfer from the flue gas to the steam tubes can cause lower boiler efficiency, hotter flue gas temperatures and, in some instances, a boiler shutdown. What’s more, slag causes boiler corrosion, which can lead to unexpected failures. It has been estimated that slagging inci- dents cost the global power sector several billion dollars each year in reduced power If slag is allowed to build up inside a boiler, it can lead not only to efficiency problems but can also cause damage because of the weight.Photo courtesy:N.B.Harty Retractable sootblower. Photo courtesy:Diamond Power
  35. 35. 32 ABM A SpecialSection Most acoustic systems have a fre- quency range of 60 Hz to 420 Hz. They create a series of very rapid and pow- erful sound waves that are transmitted into the dry deposits. This causes the ash to move at differing speeds, allow- ing the ash to break away from adjoin- ing particles and the surface they are surface they are fused with. EXPLOSIVES Using explosives to clean slag from boilers isn’t a new process, but it’s one that many plant operators prefer. The industry began using dynamite to clean boilers in the 1960s. Dynamite is still used today, but most operators prefer to use binary explosives, which are safer to handle because they require two different ingredients that will not explode until they are mixed together. Explosives are very effective at clear- ing out large, thick volumes of slag. However, if the explosives are not charged properly, the damage it could do to the boiler can be great and very expensive to repair. Using a qualified, licensed and experienced contractor is crucial. Norm Harty of N.B. Harty General Contractor Inc. has been using dyna- mite to clean boilers for years. He and his staff have developed the procedure into a state-of-the art technique that can quickly clean the slag from a boiler. To clean a boiler using explosives, Harty said his company will use prim- er cord around tubes that are close to avoid damage. The cord has connectors to delay the chargers, which he said is important to avoid destroying the wall or insulation of the boiler. Harty said using explosives has sev- eral advantages, including speed and convenience. “With dynamite,” he said, “you can put all of it in a pickup truck and clean any boiler.” cause significant damage to the boiler. What’s more, handling and disposing the chemical waste is costly and risky. The risk of a spill and environmental damage should be considered. ACOUSTIC CLEANING To dislodge large volumes of dry de- posits, power producers will use built-in horns or speakers to unleash powerful sound waves. The waves loosen the build- up without risking damage or fatigue to the boiler. While this can be done by using acous- tic horns, other acoustic technologies can be engineered specifically for a power plant. They are part of an engineered, in- tegrated system in which the frequency is determined by 3D modeling. Deposits are dislodged amid a change in pressure that breaks the bond of the particles from themselves and the struc- ture. Acoustic cleaning systems typically remove deposits more effectively at lower frequencies. Lower frequencies produce higher levels of displacement in larger ar- eas, but extremely low frequencies could cause structural damage to the boiler. diameter area. They have a small nozzle area and require high purity water. Some companies provide hands-free hydro- blasters, which are operated remotely and safely outside the boiler. CHEMICAL CLEANING Using chemical solutions is an effec- tive method for cleaning boilers because it ensures that all of the treated surfaces will be clean, allowing operators to see the true condition of the metal inside the boiler. Previously unnoticed pits or goug- es will become clearly visible, allowing for a more effective inspection. The advantages of chemical cleaning include: • The quality of steam can be main- tained at the turbine inlet • Corrosion of the metal surface of the boiler can be minimized • Under deposit corrosion of the metal can be avoided • Better heat transfer • Minimizing downtime due to boiler tube failures But chemical cleaning is expensive and dangerous. The chemical solutions can Norm Harty has been using explosives to clean boilers for nearly 50 years.Photo courtesy:N.B.Harty
  36. 36. Technician Checking For Air In-Leakage Around Valves 1 Photo courtesy:Conco Leak Detection “Ins”and“Outs”BY BARRY VAN NAME you an indication that there is a problem that could be traced to a leak. You might also experience a need for more frequent maintenance of equipment that could lead to increased risk to turbine compo- nents. Also, high levels of dissolved O2 in the feedwater will cause increased corro- sion and deterioration of your boiler and feed systems. All plants need to test for leaks, but the test can be either reactive or proactive. When it’s reactive, the condenser is telling you when to test. Emergency inspections are performed as a result of catastrophic failure or because inleakage has exceeded the capability of your air removal system. Waiting for an emergency situation can be very costly and result in damage to an- cillary equipment. With proactive testing, W hen considering the damaging and costly effects resulting from condenser air in- leakage and water leakage, we must also consider methods to avoid these condi- tions and maintain condenser reliability. Effective cleaning and testing strategies will maximize megawatt output while minimizing condenser-related outages during normal operating cycles. Properly performed, your results can be quanti- fied, permitting an accurate calculation of return-on-investment. To achieve maximum condenser per- formance,wemustconsiderthecombined efforts of cleaning, leak detection and testing. Many plants have an established cleaning regimen, usually annually, as well as an eddy current testing regimen that could take place up to every few years, depending on the age and condi- tion of the condenser. However, many of the leak detection programs occur on an as-needed basis. By combining proactive cleaning, leak detection and eddy current testing, the result will be improved total performance of your condenser and con- denser components. Condensers are designed with air removal systems to handle a certain amount of air inleakage and keep the unit runningatpeakefficiency. Wheneveryou have a leak that exceeds the capability of the air removal system, the efficiency of the condenser is adversely affected. An in- creased plant heat rate will certainly give ABM A SpecialSection